RFCC-DQ

VIETNAM OIL AND GAS CORPORATION (PETROVIETNAM) DUNG QUAT REFINERY

OPERATING MANUAL VOLUME 5

RESIDUE FLUIDISED CATALYTIC CRACKING UNIT UNIT 015 BOOK

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Project n° - Unit Doc. type Mat. code Serial n° Rev.

8474L 015

ML

001

Page

A

OP Center Job No. 0-3952-20 OP Center Doc. No. S-015-1283-001 VIETNAM OIL AND GAS CORPORATION ( PETROVIETNAM ) DUNG QUAT REFINERY (DQR) PROJECT OPERATING MANUAL UNIT RFCC (015)

OPERATING MANUAL UNIT 015

RESIDUE FLUIDAISED CATALYTIC CRACKING UNIT (RFCC)

Document Class: Z

Pages modified under this revision:

A Rev

02-MAR-07 Date DD/MM/YY

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ISSUE FOR APPROVAL

T. Tsuchiya

M. Okada

M. Okada

STATUS

WRITTEN BY (name & visa)

CHECKED BY (name & visa)

APPROVED BY (name & visa)

DOCUMENT REVISIONS Sections changed in last revision are identified by a vertical line in the margin

VIETNAM OIL AND GAS CORPORATION (PETROVIETNAM) DUNG QUAT REFINERY OPERATING MANUAL UNIT RFCC (015)

February 2007 Rev. :A Chapter : 1 Page : 1/230

CONTENTS 1 DESIGN BASIS

14

1.1

Introduction and Purpose of Process

14

1.2

Basis of design

16

1.2.1 Unit objectives and capacity

16

1.2.2 Feedstock properties

17

1.2.3 Product specifications

20

1.2.4 Operating conditions

25

1.2.5 Battery limit conditions

28

1.2.6 Utility operating / Design conditions

29

1.3

30

Material balances

1.3.1 Reaction - Regeneration – Catalyst handling and flue gas treatment

30

2 UNIT DESCRIPTION

33

2.1

33

Reaction – Regeneration – Catalyst handling – Flue gas treatment

2.1.1 Reaction system

33

2.1.2 Regeneration system

35

2.2

37

Technology features

2.2.1 Cold wall design

37

2.2.2 Feed injection system

38

2.2.3 MTC system

38

2.2.4 Riser Outlet Separation System

39

2.2.5 Two stage regeneration

39

2.2.6 Special valves

40

2.2.7 Riser wye steam ring

40

2.2.8 Aeration and fluidization systems

40

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2.2.9 Stripper bottom ring

41

2.2.10 First stage regenerator fluffing ring

41

2.2.11 Regenerated catalyst withdrawal well ring

41

2.2.12 Combustion air rings

41

2.3

Catalyst

42

2.4

Flue gas treatment

43

2.5

Feed fractionation

43

2.5.1 Feed section

43

2.5.2 Mixed crude feed

43

2.5.3 Fractionator bottom section

44

2.5.4 HCO section

44

2.5.5 LCO section

44

2.5.6 MTC and heavy naphtha section

45

2.5.7 Top section

45

2.5.8 Fractionator overhead section

45

2.6

46

Gas Recovery section

2.6.1 Wet gas compressor and HP condenser

46

2.6.2 Stripper condenser and high pressure separator drum

46

2.6.3 Primary absorber

46

2.6.4 Stripper

46

2.6.5 Secondary absorber

46

2.6.6 Fuel gas absorber

47

2.6.7 Debutanizer

47

2.6.8 LPG amine absorber

47

2.7

47

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Theory of the Process

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2.7.1 Chemical reactions and catalysts

47

2.7.2 Types of reactions

49

2.7.3 Desired reactions

53

2.7.4 Reactions to be limited (but not eliminated)

54

2.7.5 Undesirable reactions to be reduced to the minimum

54

2.7.6 Conversion selectivity of various hydrocarbon families

54

2.7.7 Catalyst

56

2.7.8 Catalyst regeneration

60

3 UNIT CONTROL DESCRIPTION

62

3.1

Control philosophy of the process

62

3.2

Process variables of Reactor / Regeneration Section

64

3.2.1 General

64

3.2.2 Riser Outlet Temperature

64

3.2.3 Disengager pressure

65

3.2.4 Catalyst activity

65

3.2.5 Regenerators air balance

65

3.2.6 Regenerators temperature

66

3.2.7 Regenerators residence time

66

3.2.8 Regenerators velocities

67

3.2.9 Stripper operation

67

3.2.10 Heat balance

67

3.2.11 Feedstock quality

67

3.2.12 Feed temperature

68

3.2.13 Coke yield / delta coke / catalyst to oil ratio

68

3.2.14 Catalyst circulation / pressure balance

69

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3.3

Process Operation variables

70

3.3.2 RFCC reaction variables

70

3.3.3 Feed temperature effects

71

3.3.4 Riser / Outlet Temperature effects

72

3.3.5 Effects of contact time

74

3.3.6 Effects of catalyst activity

75

3.3.7 Effects of recycle rate

76

3.3.8 Effects of fresh feed quality

76

3.3.9 Metals and Carbon residue effects

77

3.4

78

Uninterruptible Power Supply (UPS)

4 CHEMICAL, CATALYST AND UTILITY

79

4.1

79

Specifications of catalysts

4.1.1 Catalyst inventory and addition rate

79

4.1.2 Fresh catalyst selection

79

4.2

Antimony (Nickel passivator)

79

4.3

Corrosion inhibitor

80

4.4

Amine antifoaming agent

80

4.5

Amine (outside battery limit)

80

4.6

Phosphate for Steam Generation

80

4.7

Estimated utilities

81

5 PREPARATION FOR INITIAL START-UP

82

5.1

Chronology of operations

82

5.2

Equipment and unit inspection

83

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3.3.1 Introduction

5.2.1 Equipment inspection

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83


5.2.2 Unit inspection

85

5.2.3 Line Flushing Outline

88

5.2.4 Rotating Equipment Run-in

89

5.3

90

Preliminary operations

5.3.1 Definitions

90

5.3.2 Utility systems commissioning

90

5.3.3 Unit commissioning

91

5.3.4 Initial leak tests

91

5.3.5 Catalyst hoppers loading

92

5.4

92

First start-up

5.4.1 General

92

5.4.2 Status of the unit

93

5.4.3 Chronology of start-up operation

93

5.4.4 Blower start-up and checks

94

5.4.5 Dry-out of refractory

97

5.4.6 Refractory inspection

99

5.4.7 Drying out and Chemical Boiling-out of CO Boiler/Waste Heat Boiler

102

5.4.8 Soda Boiling of WHB BFW Circuit

102

5.4.9 Soda Boiling of Main Column Bottoms Generator

102

5.4.10 Degreasing of Amine Circuit

102

6 INITIAL AND NORMAL START-UP

103

6.1

103

Start-up Summary

6.1.1 Reactor and Regeneration Section

103

6.1.2 Fractionation and Gas Concentration Section

106

6.2

108

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Final Preparation

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6.2.1 Preparation Confirmation

108

6.2.2 Off-site and relating units preparation

109

6.3

110

Reactor Regenerator Start-up Procedure

6.3.1 Unit warm-up

110

6.3.2 Main fractionator MOV-001 Opening

111

6.3.3 Catalyst loading

112

6.3.4 Establishing catalyst circulation

114

6.3.5 Oil-in into Rizers

116

6.3.6 MTC system commissioning

119

6.4

123

Start-up for the Fractionator Section

6.4.1 Objective

123

6.4.2 Status

123

6.4.3 Steam-out (or nitrogen purge)

123

6.4.4 Main fractionator cold circulation

125

6.4.5 Cold Oil Circulation of Gas-Concentration Section

126

6.4.6 Main fractionator hot circulation

127

6.4.7 Main fractionator MOV-001 Opening

127

6.4.8 Wet gas compressor start-up

128

6.4.9 Start up Procedure of Wet Gas Compressor

128

6.4.10 Inventory Gas Concentration Section and Naphtha Circulation

129

6.4.11 Heat Up the Stripper and Debutanizer

130

6.4.12 Introduction of feed

130

7 NORMAL OPERATION OF THE UNIT

132

7.1

Summary of operating conditions

132

7.2

Control philosophy of the process

133

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7.3

Operating parameters

135

7.3.2 Riser Outlet Temperature

135

7.3.3 Disengager pressure

136

7.3.4 Catalyst activity

136

7.3.5 Regenerators air balance

137

7.3.6 Regenerator temperatures

138

7.3.7 Regenerators residence time

138

7.3.8 Regenerators velocities

138

7.3.9 Stripper operation

138

7.3.10 Heat balance

139

7.3.11 Feedstock quality

140

7.3.12 Feed temperature

141

7.3.13 Coke yield / delta coke / catalyst to oil ratio

141

7.4

143

Adjustment of operating conditions

7.4.1 Feedstock properties

143

7.4.2 Mass balance

144

7.4.3 Product properties

144

7.4.4 Heat balance

144

7.4.5 Pressure balance

150

7.5

153

Catalyst management

7.5.1 Catalyst analyses

153

7.5.2 Catalyst replacement

156

7.5.3 Catalyst addition

156

7.5.4 Catalyst draw-off

157

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7.3.1 Capacity

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7.6

Operation of Fractionation and Gas Concentration Section

160

7.6.2 Gas Concentration section

163

7.7

164

Supporting Facility Operation

7.7.1 Steam Generation Blow-down Operation

164

7.7.2 Slurry Separator Operation

165

7.7.3 Slurry Pump Operation Note

165

7.7.4 Corrosion Monitoring

166

7.7.5 Fuel Gas and Pilot Gas Supply System

166

7.7.6 Slop Oil Injection Operation

166

7.7.7 Pump Minimum Flow Operation

167

7.7.8 Flue Gas Onstream Analyzers Operation

167

7.8

168

Troubleshooting

7.8.1 Troubleshooting situations

168

7.8.2 Catalyst circulation problems

168

7.8.3 Excessive catalyst losses

169

7.8.4 Poor quality of regeneration

170

7.8.5 Spent catalyst stripping

170

7.8.6 Product quantity and quality

170

7.8.7 Partial Shutdown of Electrostatic Precipitator

171

7.9

172

Operation Notes, Relating Hazop Follow-up Action

7.9.1 Feed Injection Atomising Steam supply failure

172

7.9.2 Temporary Strainer in Feed Line at downstream of M-1501

172

7.9.3 MOV-001 Operation and Isolation Valve of PSV-002

172

7.9.4 Avoid Solidification of Feed Oil

173

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7.6.1 Fractionation section

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7.9.5 Reactor Temperature Control for Coke Formation

173

7.9.6 MTC Atomizing Steam Injection

173

7.9.7 Avoid Vacuum Condition of Reactor Vessel

173

7.9.8 Metal Passivator Filling Operation to D-1508

174

7.9.9 PDT-103 Commisioning Note for Slide Valve SV-1502

174

7.9.10 Catalyst sampling method

174

7.9.11 Operation of Vaiable Orifice down stream of Flue Gas Slide Valve

175

7.9.12 Combustion Air Control to the First Regenerator

175

7.9.13 Combustion Air Control to the Second Regenerator

175

7.9.14 Flue Gas Operating Temperature at Economizer Outlet

175

7.9.15 Slurry Service Heat Exchanger Flush out when Idling Operation

176

7.9.16 Switch Over Operation of E-1506AB Stand-by to Operation

176

7.9.17 Operation of HP-BFW Preheating by E-1516 and E-1511

176

7.9.18 WGC Compressor Suction KO Drum Pump Out operation

176

7.9.19 Depressuring operation of T-1556 LPG Extractor

177

7.9.20 First Regenerator High High Temperature

177

7.9.21 Split Range Control of Surge Drum

177

7.9.22 Untreated Gas to F/G System during Upset Situation of F/G Absorber T-1555

178

7.10 Unit monitoring check list

179

8 NORMAL SHUT-DOWN

180

8.1

180

Normal Shut-down

8.1.1 Shutdown and restart of the unit

180

8.2

180

Normal shutdown General and Summary

8.2.1 General

180

8.2.2 Summary of Shutdown of Reactor and Regenerator

180

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8.2.3 Summary of Shutdown on Fractionator and Gas Recovery Section

182

8.3

Shut Down Procedure

183

8.3.1 Catalyst inventory reduction

183

8.3.2 Feed reduction

183

8.3.3 Oil out of riser

184

8.3.4 Coke burn-off

184

8.3.5 Stop catalyst circulation

184

8.3.6 Closing of MOV-001 at main fractionator inlet

185

8.3.7 Catalyst removal

185

8.3.8 Unit cooldown

186

8.4

Short period shutdown

189

8.5

Automatic emergency shutdown (ES)

189

8.6

Injectors Inspection and Maintenance

189

8.6.1 Inspection

189

8.6.2 Maintenance

190

8.7

191

Shutdown of the Fractionator Section

8.7.1 Normal shutdown

191

8.7.2 Feed reduction and removal

191

8.7.3 Main Fractionator MOV-001 closing

192

8.7.4 Fractionation section hydrocarbon removal

192

8.8

192

Gas recovery section shutdown

8.8.1 Shut-down Procedure of gas Recovery Section

192

8.8.2 Gas recovery section hydrocarbon removal

193

9 EMERGENCY SHUTDOWN PROCEDURE

194

9.1

194

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Emergency sequences Summary

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9.2

Detail Description of Emergency Trip System

194

9.2.2 Inventory Isolation and Equipment Protection

199

9.3

200

Emergency shutdown by operators

9.3.1 General

200

9.3.2 Power failure

200

9.3.3 Instrument air failure

201

9.3.4 Fluidization / Aeration / Purge Air and FG failure

202

9.3.5 Steam failure

203

9.3.6 Boiler feed water failure

204

9.3.7 Cooling water failure

204

9.3.8 Sea water failure

205

9.3.9 Air blower failure

205

9.3.10 Feed pump failure as loss of feed

206

9.3.11 Other pump failure

206

9.3.12 Fuel gas failure

206

9.3.13 Wet gas compressor failure

207

9.3.14 Catalyst slide valve / plug valve failure

208

9.3.15 Loss of regenerators pressure control (flue gas slide valve failure)

208

9.3.16 Control system failure

209

9.3.17 Oil reversal

209

9.3.18 Low riser outlet temperature

209

9.3.19 Plugged catalyst circulation

209

9.3.20 Downstream unit failure

210

9.3.21 Fire emergency

210

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9.2.1 Emergency Shut-down System

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9.4

Emergency shutdown of Fractionator and Gas Concentration Section

210

9.4.2 Utility failure

210

9.4.3 Wet gas compressor failure

212

10 SAFETY EQUIPMENT AND PROCEDURES

213

10.1 Pressure Safety Devices

213

10.2 Alarm Setting

213

10.3 Trip Setting

213

10.4 Trip System Chart

213

10.5 Hazardous and Toxic Materials

213

10.5.1 General considerations

213

10.5.2 Vessel entry

213

10.5.3 Hazardous and Toxic Materials

214

10.5.4 Material Safety Data Sheet (MSDS)

215

10.6 HAZOP Recommendation for Operation Instruction

215

11 INSTRUEMNT DATA

219

11.1 Control Valves and Instruments

219

11.2 Orifice Plates

219

12 SUMMARY OF MAJOR EQUIPMENT

220

12.1 Equipment List

220

12.2 Large Rotating Equipment

220

12.2.1 Air Blower, C-1501

220

12.2.2 Wet Gas Compressor, C-1551

220

12.3 Major Special Packages

221

12.3.1 Electrostatic Precipitator, X-1507

221

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9.4.1 General

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12.3.2 COB/WHB Package, H-1503

221

12.3.3 Slurry Separator, X-1504

221

13 ANALYSIS

222

13.1 Sampling and Testing Method Schedule

222

13.2 Catalyst sampling method

224

13.3 On-Line Analyzer

227

14 PROCESS CONTROL

228

14.1 Distributed System Control (DCS)

228

15 DRAWINGS

229

15.1 Plot Plans

229

15.2 Process Flow Diagram

229

15.3 Piping and Instrumentation Diagram

229

15.4 Other Drawings

229

16 ATTACHMENT

230

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1


DESIGN BASIS

1.1 Introduction and Purpose of Process This document covers operation manual of RFCC Unit (Unit 15) of Dung Quat Refinery Project of Vietnam Oil and Gas Corporation. The RFCC unit design Capacity is 69,700 BPSD of Atmospheric Residue of the following crude: - Bach Ho crude - Mixed Crude of Bach Ho and Dubai Crude The main purpose of the Residue Fluid Catalytic Cracking Process R2R process is to convert various reduced crudes to lower boiling, high value products, primarily C3-C4 LPG, gasoline, and light cycle oil. Using vapor phase chemical reactions in the presence of specialized FCC cracking catalyst, the long molecular chain FCC feedstock is cracked to shorter chain molecules. Heat for the cracking process is supplied by the hot regenerated catalyst which vaporizes the finely atomized oil feed and sets the stage for the rapid but selective cracking process. The vaporization and cracking reactions occur in the “reactor-riser” in roughly two seconds. As by-products of the reaction, fuel gas, slurry oil, and coke are also generated in the “reactor-riser”. The majority of the FCC equipment handles catalyst / vapor product separation and removal of the coke from the catalyst, while only a small portion of the system is directly used for the cracking reaction. The IFP Residue Fluid Catalytic Cracking Process (RFCC) incorporates two-stage catalyst regeneration, a unique feed injection system, mixed temperature control, an efficient riser termination system, and effective air / steam distribution devices. This proven IFP RFCC process offers maximum flexibility for converting reduced crudes into valuable products. The Fractionation section fractionates the vapor product from the Reaction section. The products from this section are clarified oil, LCO and heavy naphtha. For Maximum Gasoline operation the heavy naphtha is combined with the light gasoline from the Gas Recovery section. For Maximum Distillate operation the heavy naphtha is combined with the LCO product. The fractionator overhead vapor and liquid streams are further processed in the Gas Recovery section. The products from this section are light gasoline, amine treated fuel gas and amine treated LPG.

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List of ABBREVIATIONS ABD AI API ASTM atm CCR CF CRC C/O E-cat EP FG HC HCO HDS HF HT HVGO IBP LCO LOI LPG MAT molwt MON MR MTBE PSD RCSV RE REUSY REY RGT RON RVP ROT SA SCSV VAC VGO TBP TC UCS USY

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Apparent Bulk Density Attrition Index American Petroleum Institute American Standard for Testing Metals atmospheric Conradson Carbon Residue Coke Factor Carbon on Regenerated Catalyst Catalyst to Oil ratio Equilibrium catalyst End Point Fuel Gas HydroCarbon Heavy Cycle Oil Hydro DeSulfurization Hydrogen Factor Hydrogen Transfer Heavy Vacuum Gas Oil Initial Boiling Point Light Cycle Oil Loss On Ignition Liquefied Petroleum Gas Micro Activity Test molecular weight Motor Octane Number Metal Resistance Methyl Tertiary Butyl Ether Particle Size Distribution Regenerated Catalyst Slide Valve Rare Earth Rare Earth exchange Ultra Stable zeolite Y Rare Earth exchange zeolite Y Regenerator Temperature Research Octane Number Reid Vapor Pressure Riser Outlet Temperature Surface Area Spent Catalyst Slide Valve Vacuum Vacuum Gas Oil True Boiling Point Thermal Cracking Unit Cell Size Ultra Stable zeolite Y




1.2 Basis of design 1.2.1

Unit objectives and capacity

The Residue Fluid Catalytic Cracking (RFCC) is designed for two atmospheric residues from Bach Ho and Bach Ho/Dubai crudes mixture. The RFCC design capacity is 3 256 000 tones per annum of Bach Ho 370+°C crude distillation residue, which is equivalent to a volumetric flowrate of 69 700 BPSD, based on the RFCC operation of 8 000 hours operation per year. The RFCC is also designed to process a residue based on the CDU processing a sour crude blend in the ratio of 1.0 million tones of Dubai crude to 5.5 million tones of Bach Ho crude. The sour residue blend capacity is also 3 256 000 tones per annum, which is equivalent to a volumetric flowrate of 69 700 BPSD, based on 8 000 hours operation per year. The RFCC is also designed to process both the Bach Ho and sour crude mix residues on the following two modes of operation: - Maximize RFCC Naphtha (Max Gasoline) - Maximize LCO (Max Distillate) The product guarantees are based on RFCC operating in the maximum distillate mode of operation. The RFCC is designed to process 100% hot feed direct from the Crude Distillation Unit and is capable of processing up to 100% cold feed from storage. In addition to the above, the RFCC Gas Plant can process the following streams : - CDU Stabilizer Off-gas - CDU LPG rich stream The RFCC shall also treat the off-gas stream from the Naphtha hydrotreater (NHT).

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1.2.2


Feedstock properties

1.2.2.1 Atmospheric residue properties

Cut range, TBP Vol% on Crude Wt% on Crude API Gravity SG at 15/4°C Nitrogen Sulphur Conradson Carbon Vanadium Nickel Sodium

°C

wt ppm wt% wt% wt ppm wt ppm wt ppm cSt

Viscosity @ 50°C Viscosity @ 100°C cSt Pour point °C Asphaltenes wt% Wax content wt% Hydrogen wt% Neutralization No. mg KOH/gm Characterization "K" factor ASTM distillation, °C (D1160 @ 760 mmHg) IBP 10% 30% 50% vol% above @ 550°C

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Crude (Sour) Blend 370+ 46.6 50.0 26.95 0.893 1800 0.55 2.66 10.5 5 1.6 43.4

100% (Sweet) Bach Ho 370+ 47.3 50.1 28.9 0.882 1300 0.05 1.57 0 1 1.6 43.4

8.8 50 2.0 N/A 12.7 0.05 12.58

9 52 1.0 41 12.84 0.05 12.78

263 379

262 379

435 475 32.4

437 480 32.5

ASTM Test method

D1266 D189 D2787 D2788 D445 D97 D128 D1018 D3242



1.2.2.2 CDU stabilizer off-gas The following gas stream is fed from the CDU Stabilizer, directly to the suction of the wet-gas compressor in the RFCC Gas Plant:

Flowrate Composition N2 H2S C1 C2 C3 iC4 nC4 iC5 nC5 C6+ H2O Total Molecular weight

kg/h mol% mol% mol% mol% mol% mol% mol% mol% mol% mol% mol% mol%

Crude (Sour) Blend 339.0 ---

---

-6.3 37.0 14.3 40.6 0.4 --1.4 100.0

0.7 4.8 22.7 16.0 53.5 0.4 --1.9 100.0

50.6

52.6

Note: Sour Crude Blend data is based on 100% Dubai crude.

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100% (Sweet) Bach Ho 291.0


1.2.2.3 NHT stripper off-gas to RFCC H2O H2S

kg mol/h kg mol/h kg mol/h

NH3 H2

kg mol/h kg mol/h

C1 C2

kg mol/h kg mol/h kg mol/h kg mol/h

C3 iC4 nC4 iC5 nC5 C6+ Total

kg mol/h kg mol/h kg mol/h kg mol/h (kg/h)

0.13 0.32 trace 13.17 1.69 1.37 0.83 0.06 0.40 0.14 0.10 0.63 18.84 (243)

1.2.2.4 CDU LPG rich steam The following LPG rich stream is fed from the CDU :

Flowrate SG at 15°C Composition C2= C2 C3= C3 C4= iC4 nC4 iC5+ Total

kg/h

mol% mol% mol% mol% mol% mol% mol% mol% mol%

Crude (Sour) Blend 6206 0.565 -1.2 -19.3 -16.5 61.7 1.3 100.0

Note: Sour Crude Blend data is based on 100% Dubai crude.

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100% (Sweet) Bach Ho 2071 0.572 -0.8 -10.7 -16.1 71.0 1.4 100.0




1.2.2.5 Slops feed to RFCC Provision is made to allow the re-running of slops through the RFCC main fractionator. Heavy slops: 5000 BPSD

Light slops: 1.2.3

5000 BPSD

Product specifications

1.2.3.1 Distillation specifications Gasoline LCO Slurry

TBP cut points RVP (kPa) TBP cut points Flash point TBP cut point Flash point

Max Gasoline C5 - 205°C

Max Distillate C5 - 165°C 60 max

205 - 360°C

165 - 390°C 65°C mini

360+°C

390+°C 100°C mini

1.2.3.2 Gas recovery targets C3 overall recovery C4 overall recovery C5+ content in LPG H2S content in LPG

: : : :

95% mini. 96% mini. 0.7% wt max. 25 ppm wt max.

1.2.3.3 Flue gas specifications (after Electrostatic Precipitator and DeSOx unit) NOx SOx

: 1000 mg/Nm3 max : 500 mg/Nm3 max

Catalyst fines CO content

: :

50 mg/Nm3 max 300 mg/Nm3 max

Note that DeSOx unit will be provide in future, since the Project is executed that Bach Ho crude operation is initially intended, and thus SOx in flue gas could be less than 500 mg/Nm3. 1.2.3.4 Fuel gas specification H2S content

:

50 ppm wt max

1.2.3.5 Decant oil specification (after slurry separation) Catalyst content

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:

100 ppm wt max



1.2.3.6 Estimated product properties Case LPG Sp. Gr 15/15 Mercaptans COS Total sulphur Butadiene

wt ppm wt ppm wt ppm wt ppm

GASOLINE (C5 - 165°C) Sulphur wt ppm RON clear MON clear TVP g/cm² kPa RVP Sp. Gr 15/15 D-86 IP 5 10 30 50 70 90 95 EP Olefins

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wt%

Mixed MG

Bach Ho MG

Mixed MD

Bach Ho MD

0.565 78 5.0 3786 3012

0.566 7.1 5.0 332 1647

0.565 78 5.0 4260 1358

0.565 7.1 5.0 383 1063

230 92.0 79.5 498 48

10 91.7 79.2 531 51

0.719

0.715

35 43 47 60 72 91 129 144 159

34 42 46 58 70 89 129 143 156

43

45


Case GASOLINE (C5 - 205°C) Sulphur RON clear MON clear TVP RVP

wt ppm

g/cm² kPa

Sp. Gr 15/15 D-86 IP 5 10 30 50 70 90 95 EP Olefins

wt%

LIGHT CYCLE OIL (165 - 390°C) wt% Sulphur Cetane number Cloud point °C Viscosity @ 100°C cSt Viscosity @ 50°C cSt Pour point °C °C Flash point Sp. Gr 15/15 D-86 IP 5 10 30 50 70 90 95 EP

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Mixed MG

Bach Ho MG

340

10

92.1 79.9 337 32

91.8 79.6 363 34

0.736

0.732

39 50 55 71 90 116 160 176 197

39 49 54 70 87 113 159 175 197

34

35


Mixed MD

Bach Ho MD

0.45

0.04

33.9 -1.8 1.02 2.05 -17.3 67

38.4 -0.9 1.02 2.04 -18.9 67

0.881

0.864

189 203 212 239 263 291 333 349 373

189 204 212 239 264 292 334 350 374


Case LIGHT CYCLE OIL (205 - 360°C) Sulphur wt% Cetane number Cloud point °C Viscosity @ 100°C cSt Viscosity @ 50°C cSt Pour point °C °C Flash point Sp. Gr 15/15 D-86 IP 5 10 30 50 70 90 95 EP SLURRY (390+ °C) Sp. Gr 15/15 Sulphur Conradson carbon Viscosity @ 100°C Viscosity @ 50°C Pour point

wt% wt% cSt cSt °C

SLURRY (360+ °C) Sp. Gr 15/15 Sulphur Conradson carbon Viscosity @ 100°C Viscosity @ 50°C Pour point

wt% wt% cSt cSt °C

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Mixed MG

Bach Ho MG

0.619 24.4 -6.1 0.99 1.92 -12.8 76

0.055 28.1 -5.3 0.97 1.88 -14.0 74

0.926

0.911

188 221 230 245 263 287 323 336 353

180 220 230 245 262 286 322 335 353

1.092 1.03 15.7 14.5 160 15-20

1.043 0.10 12.7 11.1 140 15-20


Mixed MD

Bach Ho MD

0.994 0.835 12.5 8.94 110 15-20

0.960 0.07 9.5 6.09 45 15-20



1.2.3.7 LPG composition

Component H2S H2 C1 C2 ETLN C3 PRLN IC4 NC4 IBTE 1BUTENE C2BUTENE T2BUTENE BD 20-50 TOTAL : Component H2S H2 C1 C2 ETLN C3 PRLN IC4 NC4 IBTE 1BUTENE C2BUTENE T2BUTENE BD 20-50 TOTAL : Mercaptan (wt ppm) COS (wt ppm) T (°C) P (kg/cm2 g) Density (P ; T) Density (15°C)

Note: Dry liquid.

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BACH HO BLEND MAX GASOLINE MAX MAX GASOLINE MAX DISTILLATE DISTILLATE LPG RATE (kg/h) LPG RATE (kg/h) LPG RATE (kg/h) LPG RATE (kg/h) 1 1 1 2 0 0 0 0 0 0 0 0 449 333 444 349 9 6 9 7 6 124 5 179 6 627 5 793 20 251 14 145 19 625 14 621 14 681 11 273 13 689 10 839 5 801 4 221 7 858 6 560 6 579 4 679 6 758 5 170 6 317 4 706 5 922 4 653 6 482 4 751 5 909 4 592 9 862 7 245 8 964 6 975 106 50 184 64 541 399 540 424 77203 56988 76530 60049 LPG (kmol/h) 0.04 0.00 0.00 14.94 0.31 138.87 481.23 252.58 99.81 117.26 112.59 115.53 175.76 1.96 8.07 1518.96

LPG (kmol/h) 0.03 0.00 0.00 11.07 0.21 117.44 336.14 193.94 72.63 83.39 83.88 84.68 129.12 0.93 6.10 1119.56

LPG (kmol/h) 0.04 0.00 0.00 14.77 0.32 150.28 466.37 235.51 135.20 120.45 105.54 105.32 159.76 3.41 8.00 1504.96

LPG (kmol/h) 0.06 0.00 0.00 11.62 0.24 131.37 347.44 186.49 112.86 92.15 82.93 81.84 124.31 1.18 6.47 1178.96

7 5

7 5

78 5

78 5

40 18 530.2 563.3

40 18 530.1 563.0

40 18 529.8 562.8

40 18 529.8 562.7


1.2.4


Operating conditions

1.2.4.1 Reaction / Regeneration section Mixed MG

Bach Ho MG

Mixed MD

Bach Ho MD

°C kg/h °C kg/h kg/h

520 407000 170 76400 0

518 407000 290 0 0

kg/h kg/h °C °C °C kg/h °C

5000 81400 183 170

5000 5000

511 407000 170 0 117100 HCO 5000 122100

505 407000 290 0 117100 HCO 5000 122100

wt%

20350 250 6.34 1.22

20350 250 5.57 0.94

170 290 20350 250 6.43 0.99

170 290 20350 250 5.27 0.91

°C kg/cm²g kg/h °C kg/h

517 1.43 14300 250 491906

515 1.43 14300 250 425858

508 1.43 14300 250 538339

502 1.43 14300 250 544695

Mixed MG

Bach Ho MG

Mixed MD

Bach Ho MD

°C °C kg/cm²g % kg/h kg/h °C t/day

678 683 2.28 70 282084 261840 210 15.2

646 651 2.28 70 194650 181520 232 5.5

641 646 2.28 70 231506 215357 223 15.2

631 636 2.28 70 178544 166575 238 5.5

°C

772

734

733

720

Case RISER Outlet temperature Feed flowrate Feed temperature MTC Heavy naphtha Feed recycle flow Feed recycle quality HCO back flush Total riser recycles MTC recycle temperature HCO back flush temperature Recycle to feed temperature Riser steam flow Riser steam temperature C/O Delta coke

170

DISENGAGER / STRIPPER Outlet temperature Pressure Stripping steam flow Stripping steam temperature Effluent flowrate

Case FIRST REGENERATOR Dilute temperature Dense temperature Dilute pressure Coke burnt Flue gas flow Air flow Air blower temperature (*1) Catalyst dry make-up SECOND REGENERATOR Dilute temperature

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Dense temperature Dilute pressure Flue gas flow Air flow Air blower temperature (*1)

°C kg/cm²g kg/h kg/h °C


762 1.3 138674 127775 210

713 1.3 94603 86942 232

712 1.3 114689 105427 223

695 1.3 86941 79856 238

79.94 6748/ 3213 68 42.97

80.76 0 / 1776 75 37.77

62.60 6748 /3213 55 43.61

61.88 0 / 1776 60 35.72

MISCELLANEOUS Standard conversion V/Ni on EQ-CAT MAT activity Catalyst circulation

wt% ppm wt% t/min

(*1): As per air blower vendor’s data.

1.2.4.2 Main fractionator Bach Ho Case Max Max Gasoline Distillate

Mixed Case Max Max Gasoline Distillate

OVERHEAD RECEIVER Temperature Pressure COLUMN Top Temperature Pressure Draw-off temperature Heavy naphtha LCO HCO pumparound Bottom Temperature Pressure

°C kg/cm²g

42 0.4

42 0.4

42 0.4

42 0.4

°C kg/cm²g

102 0.85

96 0.85

103 0.85

100 0.85

152 210 306

161 230 337

156 216 305

162 227 337

340 1.15

340 1.15

340 1.15

340 1.15

°C °C °C °C kg/cm²g

1.2.4.3 Gas recovery Bach Ho Case Max Max Gasoline Distillate


HIGH PRESSURE SEPARATOR Temperature Pressure

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°C kg/cm²g

40 15.1

40 15.1

40 15.1

40 15.1


Bach Ho Case Max Max Gasoline Distillate



PRIMARY ABSORBER Top Temperature Pressure Bottom Temperature Pressure STRIPPER

°C kg/cm²g

49 14.8

48 14.8

51 14.8

50 14.8

°C kg/cm²g

58 15.1

58 15.1

59 15.1

58 15.1

59 15.7

60 15.7

59 15.7

60 15.7

122 16

126 16

120 16

122 16

°C kg/cm²g

47 14.4

45 14.4

50 14.4

47 14.4

°C kg/cm²g

58 14.7

59 14.7

60 14.7

59 14.7

°C kg/cm²g

68 11.7 0.59

68 11.7 0.66

68 11.7 0.57

68 11.7 0.62

°C kg/cm²g

178 12.1

171 12.1

180 12.1

172 12.1

Top Temperature °C Pressure kg/cm²g Bottom Temperature °C Pressure kg/cm²g SECONDARY ABSORBER Top Temperature Pressure Bottom Temperature Pressure DEBUTANIZER Top Temperature Pressure Molar reflux ratio R/F Bottom Temperature Pressure

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FUEL GAS ABSORBER Top Temperature Pressure Bottom Temperature Pressure LPG AMINE ABSORBER Top Temperature Pressure Bottom Temperature Pressure

°C kg/cm²g

56 13.7

°C kg/cm²g

61 14

°C kg/cm²g

40 17.9

°C kg/cm²g

42 19.7

1.2.5 Battery limit conditions When the unit is operating at design throughput the temperature and pressure of the feed and products shall be as follows: Feed Stream

Temperature °C 115 70 46-52 50 40 55 50 max 70 max

Pressure (min at grade) kg/cm² g 4.5 4.5 17.5- 20.0 (1) 0.7 0.6 22.6 3.5 3.5

Temperature °C 54 40 40 50 50 90 40-42

Pressure (min at grade) kg/cm² g 4.5 18.0 8.5 6.0 6.0 8.0 3.5

Atmospheric residue from Crude Distillation Unit Atmospheric residue from storage LPG rich stream ex CDU Off-gas from CDU to fractionator OVHD drum NHT off-gas Lean amine from ARU Light slops from off-site Heavy slops from off-site Note (1) B.L pressure of CDU LPG is normally 17.5 kg/cm2g, while maximum 20.0 kg/cm2g when CDU LPG is fed to LPG Amine Absorber when Gas Recovery Section shut-down. Products Stream Unsaturated off-gas C3/C4 to LPG treater RFCC naphtha to naphtha treater LCO to blending LCO to LCO hydrotreater CLO to blending Sour water to SWS

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Rich amine to ARU 1.2.6

64/50


7.0

Utility operating / Design conditions Service

Pressure (kg/cm² g)

Temperature (°C)

Normal

Max.

Min.

Design

Normal

Max.

Min.

Design

HHP steam HP steam MP steam LP steam Power station LP steam

105.5 42.3 14.1 3.6 4.1

107.5 44.3 15.1 4.6 4.6

103.5 40.3 13.1 3.6 3.6

118.2 48.3 16.8 6.3 6.3

500 380 250 160 160

510 400 270 180 180

490 360 230 140 148

535 450 320 230 230

Service water Potable water Demineralized water HHP BFW HP BFW LP BFW Fresh CW supply Fresh CW return Sea CW supply Sea CW return Refinery fire water Salt fire water

5.0 2.5 5.0 142.0 60.0 22.0 5.2 2.2 3.3 1.3 7.0 10.0

9.5 4.0 7.5 149.0 66.0 24.0 3.5 2.5 4.0 1.4 15.0 15.0

1.5 0.5 1.5 138.0 58.0 20.0 5.0 2.1 3.3 1.3 3.0 6.0

14.2 5.5 11.0 180.0 72.6 26.4 9.2 9.2 7.4 7.4 19.3 19.3

30 30 30 112 112 112 32 47 30 38 30 30

35 35 35 131 131 131 34 60 30 40 35 30

15 15 15 105 105 105 25 25 20 20 15 20

60 60 60 160 160 160 70 70 70 70 60 70

HP condensate MP condensate LP condensate Vacuum condensate(1)

7.5 7.5 3.0 2.5

3.0

2.0

48.3 16.8 6.3 4.7

170 170 133 50

80

50

450 320 230 110

Inst. air / Plant air Refinery nitrogen CCR nitrogen

7.5 7.0 8.5

8.0 9.0 9.0

7.0 6.5 8.5

10.5 11.7 11.7

35 30 30

40 40 40

10 10 10

65 65 65

Fuel gas collection Fuel gas supply LPG Fuel gas (2) Refinery fuel oil

3.8 3.3 6.0 13

4.0 3.5

3.5 3.0

38 38

13.0

46 40 40 90

53 53

14.0

6.7 6.7 34.0 20

100

50

75 75 140 125

(1)

Applies to the condensate from both Refinery and Power Station.

(2)

Start-up fuel gas from LPG vaporizer, and also used for pilot gas to COB.

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1.3 Material balances 1.3.1

Reaction - Regeneration – Catalyst handling and flue gas treatment

1.3.1.1 Yields

Case Standard cut points H2S H2 C1 C2 C2= Dry gas C3 C3= iC4 nC4 iC4= 1C4= 2C4= C4= = LPG C5 – 220 LCO – 220-360 Slurry – 360+ Coke Total

Case Operating cut points C5 – 205 C5 – 165 205 – 360 165 – 390 360+ 390+

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Mixed MG wt% 0.2988 0.1053 0.7996 0.7043 0.6922 2.3015 1.4020 5.0248 3.1474 0.9963 1.7001 1.4927 3.9369 0.0535 17.7536 51.8277 12.5270 7.5358 7.7555 100.00

vol%

wt%

vol%

Mixed MD wt%

vol%

Bach Ho MD wt%

vol%

0.0274 0.2554 0.0231 0.1000 0.1000 0.1000 0.5810 0.5452 0.5097 0.5139 0.4888 0.4624 0.5008 0.4634 0.4279 1.6957 1.5974 1.5000 2.4646 1.4673 2.5476 1.1771 2.0692 1.2262 2.1289 8.5796 5.0861 8.5774 3.6927 6.3051 3.5423 5.9739 4.9923 3.5602 5.5775 2.4172 3.8340 2.7052 4.2380 1.5208 1.0834 1.6334 0.6507 0.9933 0.6706 1.0111 2.5260 1.6477 2.4181 1.2930 1.9212 1.1700 1.7170 2.2179 1.5859 2.3274 1.1661 1.7327 1.1797 1.7313 5.6873 4.3295 6.1775 3.0373 4.3879 3.1645 4.5154 0.0762 0.0310 0.0435 0.0183 0.0260 0.0145 0.0204 28.0647 18.7912 29.3026 13.4525 21.2695 13.6732 21.3362 62.4783 55.0125 65.9308 40.9122 49.2568 41.8821 50.1389 11.9554 11.9778 11.4824 28.5098 28.5307 28.5567 28.8560 6.1589 7.2655 6.1373 8.8941 8.1376 9.5657 8.9264 5.2299 6.3787 4.7993 108.66 100.00 112.85 100.00 107.19 100.00 109.26

Mixed MG wt%

Bach Ho MG

vol%

Bach Ho MG wt%

vol%

49.8000

60.3964 53.0129 63.8818

14.5547

14.0373 13.9774 13.5315

7.5358

6.1589

Mixed MD wt%

vol%

Bach Ho MD wt%

vol%

31.6707 39.3370 32.6035 40.1844 40.3576 40.9428 40.5390 41.4420 7.2655

6.1373 6.2878

5.6454

6.8619

6.2949



1.3.1.2 Detailed material balances

INLET, t/h Catalyst Fresh feed Riser steam Stripping steam Recycles Carry-off from reg#2 Coke Total

OUTLET, t/h Catalyst H.C. effluent & carry-off Net injection steam Total feed to Main Fract. Carry-off to reg#1 Coke Total

INLET, t/h Catalyst Coke Air Carry-off from stripper Total

OUTLET, t/h Catalyst Coke Flue gas Carry-off to lift Total

INLET, t/h Catalyst Coke Carry-off from lift Air

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Mixed MG

Bach Ho MG

Mixed MD

Bach Ho MD

2578.423 407.000 20.350 14.300 81.400 3.050 1.289 3105.812

2266.452 407.000 20.350 14.300 5.000 2.812 1.133 2717.047

2616.685 407.000 20.350 14.300 122.100 3.250 1.308 3184.993

2143.488 407.000 20.350 14.300 122.100 2.706 1.072 2711.016

Mixed MG

Bach Ho MG

Mixed MD

Bach Ho MD

2578.423 491.606 0.300 491.906 2.629 32.854 3105.812

2266.452 425.558 0.300 425.858 2.318 22.419 2717.047

2616.685 538.039 0.300 538.339 2.699 27.270 3184.993

2143.488 544.395 0.300 544.695 2.228 20.605 2711.016

Mixed MG

Bach Ho MG

Mixed MD

Bach Ho MD

2578.423 32.854 261.840 2.629 2875.746

2266.452 22.419 181.520 2.318 2472.709

2616.685 27.270 215.357 2.699 2862.011

2143.488 20.605 166.575 2.228 2332.896

Mixed MG

Bach Ho MG

Mixed MD

Bach Ho MD

2578.423 10.759 282.084 4.480 2875.745

2266.452 7.519 194.650 4.087 2472.708

2616.685 9.097 231.506 4.723 2862.011

2143.488 6.932 178.544 3.932 2332.896

Mixed MG

Bach Ho MG

Mixed MD

Bach Ho MD

2578.423 10.759 4.480 127.775

2266.452 7.519 4.087 86.942

2616.685 9.097 4.723 105.427

2143.488 6.932 3.932 79.856


Total

OUTLET, t/h Catalyst to WW Coke Flue gas Carry-off to WW Total

REGENERATOR 1 CO CO2 H2O N2 NOx + NH3 SOx + H2S Total M.W., kg/kmol Catalyst fines, mg/Nm3

REGENERATOR 2 CO CO2 H2O N2 O2 NOx + NH3 SOx + H2S Total M.W., kg/kmol Catalyst fines, mg/Nm3

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2721.437

2365.000

2735.932

2234.208

Mixed MG

Bach Ho MG

Mixed MD

Bach Ho MD

2578.423 1.289 138.674 3.050 2721.436

2266.452 1.133 94.603 2.812 2365.000

2616.685 1.308 114.689 3.250 2735.932

2143.488 1.072 86.941 2.706 2234.207

Mixed MG mole %

Bach Ho MG mole %

Mixed MD mole %

Bach Ho MD mole %

6.2598 9.9362 16.2236 67.4775 0.0286 0.0742 100.0 28.00 400

5.3138 10.6274 16.3897 67.6317 0.0259 0.0115 100.0 28.08 400

6.2377 9.9011 16.5193 67.2390 0.0286 0.0743 100.0 27.97 400

5.3092 10.6182 16.4622 67.5731 0.0259 0.0115 100.0 28.07 400

Mixed MG mole %

Bach Ho MG mole %

Mixed MD mole %

Bach Ho MD mole %

0 16.9843 7.1866 73.8779 1.8561 0.0255 0.0696 100.0 30.11 900

0 16.9958 7.2909 73.8239 1.8539 0.0248 0.0108 100.0 30.08 900

0 16.9369 7.2845 73.8298 1.8541 0.0255 0.0692 100.0 30.09 900

0 16.9850 7.3139 73.8121 1.8534 0.0248 0.0108 100.0 30.08 900


2

January 2007 Rev. :A Chapter : 2 Page : 33/230

UNIT DESCRIPTION

2.1 Reaction – Regeneration – Catalyst handling – Flue gas treatment The R2R Process is a fluid catalytic cracking process incorporating a two-stage regeneration system, a unique feed injection system, a proprietary catalyst disengager and catalyst cooler (optional). This proven process eliminates or greatly reduces many of the constraints of previous FCC configurations and offers maximum flexibility for converting reduced crudes and mixtures of gas oils and vacuum residues. The process unit consists in feed injection system, riser, riser outlet separator system, disengager/stripper, first stage regenerator, second stage regenerator, catalyst cooler (optional), catalyst withdrawal well, catalyst transfer lines and control systems. The following is a description of the full technology included in the R2R process. 2.1.1

Reaction system

2.1.1.1 General The feed mixture is pumped to the base of the riser and divided into equal flows, to each of the feed nozzles. The feed, which has been preheated, is finely atomized and mixed with dispersion steam in the feed nozzles and injected into the riser. The small droplets of feed contact hot regenerated catalyst in a counter current way and vaporize immediately. The vaporized oil intimately mixes with the catalyst particles and cracks into lighter, more valuable products along with slurry oil, coke and gas. The product vapors travel up the riser while carrying the catalyst. Residence time in the riser is approximately 2 seconds at design conditions. The specially designed feed injection system insures the reaction is carried out efficiently to minimize the production of coke, gas and slurry oil. 2.1.1.2 Feed injection zone Oil feed to the riser is preheated before entering the reaction system. Preheat temperature along with regenerated catalyst temperature is controlled to result in an optimum catalyst to oil ratio. Passivator injection into the fresh feed just ahead of the feed nozzles acts to inhibit the undesirable effects of nickel in the feed. Shutdown valves will stop the flow of feed to the riser and divert it back to the feed surge drum in case of certain emergencies. Flow controllers regulate the flow to each of the feed nozzles. The feed should be split evenly between the feed nozzles as observed by individual flow indicators. Pressures on each feed nozzle should be monitored as a verification of flow and indication of nozzle condition. Depending upon the operating case, a different quality of recycle to feed is used. In Mixed Crude MG operation, an heavy naphtha recycle is used in order to adjust the feed viscosity and further improve the feed atomization. An additional effect is to decrease the heavy oil partial pressure leading to a better vaporization. In MD operation, a HCO recycle is used in order to improve the bottom conversion. Dispersion steam is supplied to each of the feed nozzles to promote atomization and vaporization of the feed. The flow to each of the feed nozzles is adjusted by flow controllers. Upstream the feed injection, stabilization steam is injected in the riser, through the stabilization steam injectors, in order to promote a smooth and homogeneous catalyst flow at the feed injection point. The flow to each of the injectors is adjusted by flow controllers. MTC (Mix Temperature Control) injectors are provided above the feed injection zone to inject recycled heavy FCC naphtha. MTC plays an important role in the heat balance control and heavy feed vaporization. The key is to achieve a higher temperature in the fresh feed mixing zone. As for the feed injectors, MTC flow and dispersion steam flow to each injector are adjusted by flow controllers.

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Upon emergency shutdown the steam flow control valves on all injectors automatically open to clear the riser of oil and catalyst with steam. 2.1.1.3 Riser/Reactor The sensible heat, heat of vaporization and heat of reaction required by the feed is supplied by the hot regenerated catalyst. The riser outlet temperature is controlled by the amount of regenerated catalyst admitted to the riser through the regenerated catalyst slide valve. In the wye section at the base of the riser, steam is injected via a steam ring to keep the regenerated catalyst in a fluid state at all times. The cracking reactions take place during the two second residence time in the riser as the reaction mixture accelerates toward the Riser Outlet Separator System (ROSS). The catalyst is quickly separated from the hydrocarbon/steam vapors in the ROSS separator located at the end of the riser. This separation is necessary to discourage the undesirable continuation of reactions which produce gas at the expense of gasoline. This system drastically reduces the post riser catalyst/vapors contact time. After exiting the ROSS separator, the vapors pass through high efficiency single stage cyclones to complete the separation of catalyst from vapors, thus minimizing the amount of catalyst lost into the product. The reactor product vapors, containing a small amount of inerts and steam, flow to the quench zone of the main fractionator. The small amount of catalyst contained in the product vapors is carried away from the fractionator in the bottom slurry product. The reactor pressure "floats on" the main fractionator pressure and as such is not directly controlled at the converter section. A pressure control at the main column overhead receiver allows to achieve a steady operating pressure in the reaction system. The ROSS separator and disengager cyclones separate the product vapors from spent catalyst and return the catalyst to the stripper bed. The cyclone diplegs are equipped with trickle-valves to prevent reverse flow of gas up the diplegs. Also, the ROSS separator is equipped with diplegs fitted on its pre-stripping chambers. These diplegs are sealed into the stripper catalyst bed in order to avoid any possibility of vapors back mixing. 2.1.1.4 Stripper Catalyst exiting the ROSS separator is pre-stripped with steam from a steam ring located immediately at the exit of the separator diplegs. This is an important feature for reducing coke yield. The catalyst is further stripped by steam from the main steam ring as the catalyst flows down the stripper. Two additional rings (upper and lower rings) are also provided in addition to the main ring. The upper ring achieves a second stage of pre-stripping of the catalyst before it enters the stripper. The lower ring is located in the bottom head of the stripper to achieve a stable fluidization at the inlet of the spent catalyst standpipe. The total steam flow is designed to provide about 6 kg of steam per ton of catalyst circulated. The contact between catalyst and steam is enhance by the presence of fluidized bed packing allowing for cross and counter current flow of steam and catalyst. This highly efficient contacting displaces the volatile hydrocarbons contained on and in the catalyst particles before they enter the first stage regenerator. Coke remaining on the catalyst is burned off in the regenerators. The catalyst is aerated in the spent catalyst standpipe to the proper density for stable head gain. 2.1.1.5 Spent catalyst transfer The stripped spent catalyst flows down the spent catalyst standpipe and through the spent catalyst slide valve. Aeration by fuel gas (or nitrogen) is added to the standpipe at several elevations to maintain proper density and fluid characteristics of the spent catalyst emulsion. The spent catalyst slide valve controls the level in the stripper by regulating the flow of spent catalyst from the stripper. The spent catalyst flows into the first stage regenerator through a distributor which ensures that the entering coke-laden catalyst is spread across the regenerator bed.

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2.1.2


Regeneration system

2.1.2.1 General The first stage regenerator burns 50 to 80% of the coke and the remainder is burned in the second stage regenerator. This two stage approach to regeneration adds considerable flexibility to the process as potential heat is rejected in the first stage regenerator in the form of CO. When running heavy feeds, the need for heat rejection is higher, the amount of coke burned in the first stage regenerator is increased, thereby lowering the final temperature of the regenerated catalyst. When running lighter feeds the amount of coke burned in the first stage regenerator is reduced, thus increasing the regenerated catalyst temperature. The amount of coke burned in the first stage can be varied by adjusting the air flowrate in order to achieve operating flexibility on the unit for different feedstocks. For the very heavy feeds (Conradson Carbon higher than 7% wt), additional heat removal is required and a (catalyst cooler) must be provided to limit the regenerated catalyst temperature. The heat of combustion released by the combustion of coke is transferred to the catalyst which will later supply the heat required to the reactor. The heat balance of the unit is much more flexible than in single stage regeneration systems because potential energy in the form of carbon monoxide from the first stage regenerator can be adjusted while complete regeneration of the catalyst is accomplished in the second stage. 2.1.2.2 Air blower and air heaters The combustion air required is supplied by an air blower, commonly driven by a steam turbine. The steam supply to the turbine is throttled on cascade air flow trim control/compressor speed. Atmospheric air is introduced to the air blower through an intake filter and silencer. The blower air is distributed to a header system providing combustion air to first regenerator rings, second regenerator ring, lift air (and catalyst cooler fluffing air in case it is installed). Power assisted check valves at the blower discharge prevent back-flow of catalyst in the event of blower shutdown. Blower surging is prevented by venting air using a sophisticated anti-surge controller. Combustion air to each regenerator is flow controlled. Low air flow to either regenerator will trigger the emergency shutdown circuit in the case of blower failure. Combustion air to the first stage regenerator is split between two air rings. The outer air ring and inner air ring are designed to handle about 70% and 30% of the combustion air to the first stage regenerator respectively. Direct fired air heaters are located in the combustion air lines to the first regenerator combustion air rings and second regenerator combustion air ring. The air heaters are used during start-up to heat-up the equipment including dry out of refractory. Instrumentation is provided to prevent overheating the equipment during air heater operation and a flame safety package is included to prevent unsafe conditions during burner operation. 2.1.2.3 First stage regenerator Spent catalyst containing roughly 1 to 1.5 wt % coke flows from the spent catalyst distributor and is spread across the bed in the first stage regenerator. Part of the coke is burned by combustion air from the air rings. This regenerator operates in a counter current (air in at bottom and spent catalyst in at top) mode which helps prevent catalyst overheating. The regeneration conditions are mild to limit hydrothermal deactivation of the catalyst. First stage regenerator total combustion air is controlled to limit the temperature in the first stage to maximum 730°C. The partially regenerated catalyst flows down through the first stage regenerator bed to the entrance of the air lift. Aeration is supplied in this area to ensure smooth flow of catalyst to the lift. A hollow stem plug valve regulates the flow of catalyst to the lift line and is controlled by the level in the first stage regenerator. Air injected through the hollow stem of the plug valve into the air lift is flow controlled at a rate sufficient to lift the catalyst in a dilute phase up to the second stage regenerator. Emergency air is provided through blast connections to clear the lift in the event of plugging.

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Two stage cyclones separate entrained catalyst from the flue gas exiting the first stage regenerator. At the exit of the regenerator, the flue gas pressure is reduced through a double disc flue gas slide valve controlling the regenerator pressure. Incineration of the CO in the flue gas is then accomplished at the CO incinerator. A continuous catalyst withdrawal is necessary to maintain the unit catalyst inventory in the normal operating region. Torch oil is used to heat the process to its operating temperature during start-up. Oil and steam on flow control are directed to two nozzles which spray into the bed of air preheated catalyst. 2.1.2.4 Second stage regenerator The partially regenerated catalyst flows up the lift and enters the second stage regenerator below the air ring. A distributor at the end of the lift provides for efficient distribution of catalyst and air from the lift. Catalyst is then completely regenerated to less than about 0.05% carbon at more severe conditions than in the first stage regenerator. Very little carbon monoxide is produced in the second stage and excess oxygen is controlled by flow control of the second regenerator combustion air for efficient and complete combustion. Because most of the hydrogen in coke was removed in the first stage, very little water vapor is produced in the second stage. This limits hydrothermal deactivation of the catalyst as higher regeneration temperatures are experienced. External refractory lined cyclones are used on the second stage flue gas to remove entrained catalyst. This design expands the operating envelope for regenerator temperatures which tend to be higher for residue type feed. The cyclone dip legs are external to the regenerator. Catalyst recovered in the cyclone are returned to the regenerator bed below the normal operating level by way of the diplegs. Aeration is supplied to the diplegs to provide for smooth fluidized catalyst flow and the diplegs outlets are equipped with flapper valves to prevent catalyst and gas backflow into the cyclones. The second stage regenerator pressure is controlled by a flue gas double disc slide valve, through differential pressure between the first and second stage regenerators. 2.1.2.5 Regenerated catalyst transfer The hot regenerated catalyst flows from the second stage regenerator through a lateral into the withdrawal well. In the withdrawal well a quiescent bed is established at proper standpipe density by introduction of a controlled amount of fluidizing air from the withdrawal well ring. A smooth stable flow of catalyst down the standpipe is provided by injection of aeration air at several elevations on the regenerated catalyst standpipe. As the head pressure increases down the standpipe and the catalyst emulsion is compressed, these aeration points are used to replace the "lost" volume, thereby to ensure a continuity of fluid catalyst flow properties. At the bottom of the regenerated catalyst standpipe the regenerated catalyst slide valve controls the flow of hot catalyst. The Riser Outlet Temperature sets the position of the slide valve which regulates the flow of catalyst. The regenerated catalyst passes to the wye section at the base of the riser where a steam ring fluidizes the catalyst. The wye steam and fluidization points in the wye section ensure that the catalyst flow to the feed injection point is stable and smooth in order for the feed injection system to perform at its optimum. 2.1.2.6 Catalyst handling The catalyst handling system includes hoppers for storage of fresh catalyst and spent catalyst, loading devices for catalyst addition and a draw-off device for continuous equilibrium catalyst withdrawal. Three hoppers are installed: the fresh catalyst hopper, the spent catalyst hopper and the auxiliary catalyst hopper. The auxiliary catalyst hopper provides flexibility in the operation for different options: storage of imported equilibrium catalyst reused as part of the make-up catalyst, storage of excess spent catalyst, storage of a second grade of fresh catalyst for make-up.

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The spent and fresh catalyst hoppers are sized to contain the entire unit inventory. Each hopper is provided with one cyclone and with aerations in the bottom cone to assist the catalyst circulation to the transfer lines. a) Hoppers loading and unloading Fresh catalyst or equilibrium catalyst, delivered in trucks, are loaded into the fresh catalyst hopper for fresh catalyst, and spent catalyst hopper for equilibrium catalyst, using either the truck compressor or the steam ejector supplied for reducing the hopper pressure. Spent catalyst is unloaded from the spent catalyst hopper to the flexible bag by hopper pressurizing with plant air. b) Unit loading and unloading Before start-up, equilibrium catalyst is loaded into the spent catalyst hopper as described above. When the unit warm-up is completed, the catalyst is loaded into the unit through the first regenerator. The hopper is pressurized with plant air. Air from the blower used as motive fluid to transport the catalyst. After shutdown, the spent catalyst is unloaded from the unit into the spent catalyst hopper by reducing the pressure in the hopper using the steam ejector. The catalyst air mixture should not exceed 400°C when entering the spent catalyst hopper. c) Catalyst addition and withdrawal During normal operation, a batch feeder is used to automatically add fresh catalyst at the desired rate. It can be adjusted for batch size and frequency of additions. As most of the time, catalyst addition is higher than the catalyst losses from the unit, catalyst must be withdrawn in order to keep the unit inventory. This operation is achieved by a specific continuous drawoff device provided on the first regenerator. Hot catalyst is withdrawn, cooled down through a finned tube and sent to the spent catalyst hopper at a temperature below 400°C. 2.2 Technology features The R2R technology possesses many design features to achieve flexibility of operation on a wide range of feedstocks. It is intended to provide high yields of gasoline and distillate while minimizing the production of coke and gas. These features such as two stage regeneration, feed injection, riser outlet separation system, (catalyst cooler), aeration and fluidization... are described hereafter. 2.2.1 Cold wall design When possible and practical, IFP chooses to use cold wall design for major vessels and lines. In this case, vessels and lines are lined with internal refractory lining which isolates sufficiently from the process side to have the metal operating at a temperature usually between 150 and 200°C with high air ambient temperature and no wind. This concept has several advantages : • By varying refractory material and thickness it is possible to hold the metal temperature within the specified range. • The second regenerator and its external cyclones are exposed to high temperatures. Only the refractory is exposed to these high temperatures and the rated service temperature of the refractory (around 1250°C) is far above the maximum process design temperature (around 900°C) limited, now only, by the catalyst stability. • Thermal expansion is limited. It has been possible to limit the use of expansion joints to one located on the spent catalyst line and another small one at the junction of the two regenerators. • Conventional carbon steel can be used for all vessels and major lines reducing greatly cost and maintenance problems. • In the transfer line to the main fractionator, the coke deposit is minimized, due to higher velocity, higher internal temperature and less cold spots and also shorter lay out.

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In order to use cold wall design it is essential to have a good refractory design. Which implies: • A well designed anchors system, • Judicious selection of material, • Experienced refractory Vendors and refractory installation sub-Contractors. IFP relied upon many years of cracking operations to use proven materials and design technique for a good refractory materials selection and proven anchors design. 2.2.2 Feed injection system The principle of the feed injection system is to atomize the oil feed into very small droplets with a high surface area for rapid heat transfer with the hot regenerated catalyst. Vaporization of the feed is then rapidly promoted. This enhances vapor phase cracking reactions and minimizes liquid phase coking reactions. In catalytic cracking, the reaction takes place in the vapor phase, the importance of maximizing the vaporization in the quickest possible time is then critical. A larger oil droplet stays in liquid phase longer and can surround the catalyst particle, effectively blocking the active surface area. Slow vaporization of the feed promotes the formation of coke, gas and slurry oil. The relative direction of oil injection towards catalyst is also essential. IFP technology is to inject the oil downwards counter current of the accelerated catalyst. This injection pattern promotes the contact between oil droplets and hot regenerated catalyst. The heat transfer is drastically enhanced. Uniform feed distribution and rapid vaporization also has other benefits. In the bottom of the riser the catalyst turns upward with aid of the bottom steam, then the catalyst flow is stabilized by means of stabilization steam and meets the oil/steam mist at the feed injection point. A well distributed, rapidly vaporizing, feed helps accelerate the reaction mixture to its final velocity in a smooth manner. Catalyst slippage and back mixing will promote undesirable side reactions. In this last situation, some feed vapor sees too much catalyst and some not enough. The venturi like effected of the high energy feed injection system associated to the counter current injection results is a faster, more uniform acceleration of the catalyst in its upward path and more uniform catalyst densities along the cross section of the riser. The R2R feed injection nozzle atomize the oil feed by a high energy shearing action on a specially designed venturi type injector. High velocity steam jet shears the oil, further into a fine mist. The injector tip is designed to discharge a wedge shaped spray that fans out from the tip in a carefully determined angle. The action of the feed nozzles together provide uniform coverage of the riser cross section without impingement on the riser walls. The injectors have no moving parts and can be installed outside the riser for easier maintenance and can be replaced during planned downtime. 2.2.3 MTC system The MTC (Mix feed Temperature Control) has been developed to further improve the R2R process capabilities and performances with respect to the cracking of increasingly heavier and more refractory feedstocks. It is designed to face the two main challenges encountered when processing very heavy, highly contaminated feeds, namely: • Achieve a satisfactory vaporization of the feed so as to eliminate the unnecessary coke production resulting from an incomplete vaporization. •

To keep the desired heat balance while maintaining the conversion at the optimum level.

The MTC system basically consists of the injection of an appropriate stream into the riser, downstream of the feed injection point, at a location and under conditions selected to obtain the desired quenching effect and the best yield selectivity.

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In this case, the stream used is a special MTC stream located in the heavy naphtha cut recycled from the main fractionator. The optimum MTC flowrate depends on the feed quality (the heavier the feed the higher the recycle flowrate) and on the desired yields structure: to switch from a maximum gasoline to a maximum distillate mode of operation for instance, operating conditions will have to be modified directionally towards a decrease of the conversion per pass, which will result mainly in : • A lower Riser Outlet Temperature and subsequently a lower mix temperature in the fresh feed injection zone which will tend to increase the coke make if the mix temperature becomes lower than the feed dew point. • A higher slurry yield with a lower aromatic content and therefore a superior potential of this product for an additional conversion through recycle. • A lower gas make leading to an increased margin on fractionation and wet gas compressor section. According to these observations, the MTC system is specifically useful in this situation for maximizing the distillate yield while keeping the coke production under control. MTC flowrate should be limited to 20% maximum of fresh feed. 2.2.4 Riser Outlet Separation System The principle of the patented IFP Riser Outlet Separation System (ROSS) is a symmetrical structure of separation chambers and collecting chambers alternatively arranged around the top of the riser. The separation chambers are connected in their upper section to the riser and the vapor + catalyst mixture follows a 45° turn downwards around an inlet baffle. The vapor outlets to the collecting chambers are located underneath the inlet baffle in the perpendicular direction of the incoming stream. This geometry provides simultaneously both the centrifugal effect and the inertial effect which are key factors for catalyst separation. The catalyst separated is collected in a hopper prorogated by a dipleg which achieves the necessary seal between the riser and the stripper vessel. The vapor exiting the separation chamber is then mixed in the collecting chamber with the steam evolved from the stripper vessel. The collecting chambers are then connected to a center pipe collector which distributes the vapor to the disengager cyclones for final catalyst separation. This system achieves in a single device an extra-short time of vapor disengagement of about 1 second (45° turn, no vortex) and an efficient catalyst separation in two chambers arranged in series. The main chamber which is the separation chamber itself and the secondary chamber which is the vapor collecting chamber providing an additional safety buffer volume for further catalyst disengagement in case of catalyst carry-over. 2.2.5 Two stage regeneration Residue cracking differs from gas oil cracking in that the feed contains more asphaltenes, and is more hydrogen deficient. Coke make, which is usually dictated by heat balance requirements, can become a critical factor in the operability of the process. Coke make increases as residual oil is added to the feed and regenerator temperatures rise as more heat of combustion from the coke is released. A conventional single stage regenerator is limited in regard to cracking residues because of metallurgical limits within the regenerator vessel. The R2R technology splits the regeneration into two stages. The first stage burns part of the coke from the catalyst at mild conditions and completes the regeneration in the second stage. Several benefits are realized as a result of this configuration. Most of the hydrogen in coke is removed in the first stage at mild conditions, i.e. a maximum operating temperature limited at 730°C (usually 670 to 690°C). The resulting water vapor is in contact with catalyst at lower temperatures than those necessary for complete regeneration, leading to much less catalyst deactivation. The relatively dry atmosphere of the second regenerator allows to raise the temperature while the regeneration is completed. Thus the R2R two stage regeneration results in less hydrothermal deactivation of the catalyst.

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As the residue content of the feed increases to higher levels, the coke make increases and the heat balance of the unit must be adjusted to maintain catalyst circulation rates and conversion. In the two stage regenerator configuration, potential energy, in the form of carbon monoxide, is rejected from the regenerator system by increasing the amount of total coke burned in the first stage regenerator. Complete regeneration of the catalyst is accomplished in the second stage regenerator. Excess oxygen is maintained to ensure complete regeneration to essentially carbon free catalyst. Since the second stage regenerator cyclones are external to the vessel and lined with refractory, the metallurgical limitations previously encountered with residue feeds are circumvented (the maximum operating temperature can reach 810°C relatively to the catalyst while the mechanical design is 840°C). 2.2.6 Special valves Two types of valves are used in the R2R process : catalyst slide valves and plug valve. Slide valves are carefully designed with abrasion resistant protection for improving the valves reliability. Internal insulation allows to use carbon steel for the body of the valves. The valves are provided with appropriate purges, on the stem and body, to clear the valves from any catalyst particles. Internal inlet shapes are designed to provide smooth operation. The plug valve design includes a stuffing box, an insulation sleeve and an air purge which provides efficient protection against catalyst blockage. Thrust limiter and seat and plug angles have been optimized to overcome the thermal expansion of the air lift. All valves are provided with independent hydraulic oil system to ensure a reliable and stable operation. 2.2.7 Riser wye steam ring Its function is to straighten out the catalyst flow pattern as it makes the transition at the "wye" from its downward flowing, partially deaerated state, to an upward flowing, evenly aerated state. In aerating the catalyst, this ring also provides the reverse seal needed to protect against oil flow reversals. The vertical column of catalyst below the feed nozzles provides a seal against such upsets. This ring is designed for a normal flowrate that should be maintained at all times when the catalyst is circulating. 2.2.8 Aeration and fluidization systems The catalyst fluidization and aeration systems play a vital role in the stability of catalyst circulation. Proper attention should be given to all fluidization and aeration flows to make sure that they are properly set at their specified rates. All the aeration and fluidization services in the catalyst system are discussed below. The standpipe aeration systems on the unit are designed to handle a wide range of conditions and still provide smooth, stable, catalyst flow required for proper operation. This is essential for stable and adequate catalyst slide valve differentials. The system includes aeration points located along the vertical portions of the standpipes with a rotor meter or flow orifice provided for each tap. The flows to the taps are initially set equally to replace the volume of interstitial gas compressed by head pressure. New operating conditions, if they vary widely, may require that these flows be adjusted slightly, but this should only be done after a pressure profile is taken along the standpipe to measure variations in density. It is important to note the difference between aeration and fluidization systems. Aeration is the process of replacing, with the injection of gas, the volume lost to compression by head pressure in a column of fluidized catalyst. Aeration medium is necessary to keep the catalyst from becoming non fluidized and developing unstable flow characteristics. The taps on standpipes are located such that there are twice the number required for an adequate aeration. If one becomes plugged the neighboring tap will continue to ensure stable operation. Fluidization taps are employed when the direction of catalyst flow changes. In the R2R unit, 45° angle changes are used to redirect catalyst flow whenever possible. As the catalyst flows into a 45° line the fluidization media is injected to assist in the turn. On the other hand, when catalyst flows from a 45° line, the fluidization media is added to smooth the turn and to penetrate the denser catalyst layer at the wall to

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allow easier entrance. A smooth, stable flow of catalyst into vertical standpipes is very important. Therefore, fluidization taps are either doublets or triplets. The flowrate on each fluidization service is a function of the geometry and catalyst flow pattern at that location. Two locations merit special notice. The regenerated catalyst standpipe handles catalyst without any coke residue and is at high temperatures. Catalyst at this condition is inherently more difficult to maintain fluidized. Therefore it is important to be certain that the aeration rates and instruments purges are kept at specified settings. The second location to note is the second stage cyclone dipleg aeration. Instrument purges provide a large part of the required aeration and these purges should be set as specified. The fluidization in the slanted portions of the diplegs is very important. The penetration of the dense catalyst layer near the regenerator wall is necessary to ensure smooth flow of fines returning to the regenerator. Without proper aeration in the diplegs the cyclones may flood and catalyst losses will increase. 2.2.9 Stripper bottom ring This ring is located in the bottom head of the stripper. The steam rate for this ring is part of the total steam required for good stripping but its prime function is to aerate the catalyst entering the spent catalyst standpipe. This is important for adequate head build-up to maintain an adequate slide valve differential pressure for controlling the stripper level. 2.2.10 First stage regenerator fluffing ring This air ring is located below the main combustion air rings and aerates the catalyst in the vicinity of the plug valve which controls the regenerator level. It ensures free travel of plug valve and smooth entry of catalyst into the lift line. 2.2.11 Regenerated catalyst withdrawal well ring This air ring is located in the bottom portion of the regenerated catalyst withdrawal well. The withdrawal well serves as a vessel to condition the catalyst for smooth quiescent flow, at proper density into the regenerated catalyst standpipe. It controls the catalyst aeration before it enters the standpipe. The regenerated catalyst is inherently more difficult to keep in fluidized flow state and therefore it is important to set the fluidization ring at the specified level. The ring is designed to fluidize the bed in the withdrawal well if it has become deaerated. Setting the flowrate on the ring must be done carefully as it may create upsets in the operation of the regenerated catalyst slide valve differential. 2.2.12 Combustion air rings The combustion air rings distribute the combustion air evenly across the bed in the regenerators. A well distributed source of combustion air is essential for good, evenly distributed catalyst regeneration without after burn. The rings are designed to operate satisfactorily at the minimum turndown design for the unit. The pressure drop across the ring is kept above 0.07 bar at reduced rate to maintain adequate distribution and prevent intrusion of catalyst into the ring and avoid associated erosion. The catalyst air lift transports the catalyst from the first stage regenerator to the second stage regenerator in a dilute phase. The operation of this lift should be kept as steady as possible but however it can be changed to adjust the pressure balance on the unit. The pressure drop across the lift is mainly a function of the lift air rate. More air creates a less dense flow regime and, hence, a lower pressure drop due to static head. The lower limit of air flow is the choke velocity at which the air ceases to lift the catalyst. The minimum air rate for acceptable lift is about 5 m/s. Normal air velocity in the pick-up zone is 8 to 12 m/s.

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2.3 Catalyst The proper selection of catalyst is very important to successful residue cracking operations. The importance magnifies as the percentage of residual oil increases in the feedstock. Several properties of the catalyst should be examined for a particular feed. The properties are: • Zeolite content •

Micro-activity

•

Rare earths content,

•

Unit cell size

•

Coke selectivity

•

Particle size distribution

•

Bulk density

•

Thermal stability

•

Surface area

•

Pore volume and pore distribution (strippability)

•

Attrition resistance

•

Metals resistance

•

Gasoline octane properties

The IFP recommendation for use in R2R residue cracking unit is low sodium, Ultra-Stable Hydrogen Y type (USHY) zeolite. A USHY catalyst has a high ratio of silica to alumina. The zeolite structure has relatively large three dimensional pores which allow more surface area available for cracking. Unit cell size can be an indicator of coke selectivity as coke precursor molecules may be rejected from the zeolite cage. The USHY catalyst with low rare earths content also provides a lower hydrogen transfer rate resulting in preservation of olefins and better coke selectivity. IFP recommends a low rare earths content for residue cracking operations. Rare earths are exchanged onto the USHY structure to enhance activity and stability. Unfortunately rare earths also promote hydrogen transfer reactions which increases coke selectivity. Also the matrix activity and structure plays a key role in the cracking selectivity. The matrix achieves the pre-cracking of heavy molecules and feeds the zeolite. Therefore the balance between matrix and zeolite is essential. On an other hand, the matrix porosity controls the catalyst activity and strippability. A catalyst must be hard enough to survive interparticle and wall collisions induced by various turbulent zones in the process. Attrition of the catalyst particles into very small particle sizes will result in increased losses through the cyclones. Metals contamination of the catalyst is a result of contaminants in the feed. The catalyst should be tolerant to metals levels up to about 10,000 ppm. Nickel in the feed deposits on the catalyst and promotes undesirable dehydrogenation reactions, high gas make and increased coke yield. Antimony is used as an effective passivator of nickel at a dosage to maintain an equilibrium level of about 25 to 40% of the nickel loading. Vanadium in the feed and deposited on the catalyst will promote collapse of the zeolite structure and loss of active surface area at the elevated regenerator temperatures. Sodium is also detrimental to the catalyst activity. Feed sodium should be kept below 1 ppm through efficient desalting in the crude unit. Caustic injection used in the crude train is not recommended without effective removal of the sodium neutralization salts. Caustic injection, if used, should be achieved before the desalters. The Na2O content of the equilibrium catalyst should not exceed the Na2O content of the fresh catalyst by more than 0.10 wt %. The effect of metals on the catalyst can be controlled through passivation and dilution. That is, catalyst addition in residue cracking operations is governed by catalyst metals loading. There are many

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commercial units operating with metals loading from 7 000 to 10 000 ppm. To reduce operating cost a mixture of fresh and outside equilibrium catalyst can be used to control metals loading and activity. Catalyst used in residue cracking operations should be double calcined to enhance thermal stability. Particle size distribution should be examined on the fresh catalyst. The zero to 20 micron fraction should be low to minimize the direct losses through the cyclones. The cyclone system is designed to retain enough of the equilibrium zero to 40 micron fraction to maintain good fluidization properties. 2.4 Flue gas treatment The flue gas coming from the first regenerator contains CO and some unburned products. It is sent to the CO boiler for combustion completion. The flue gas is routed to the Waste Heat Boiler for HP steam regeneration. The flue gas coming from the second regenerator is sent to the waste heat boiler, directly. Heat released is used for HP steam generation. The flue gas coming from the waste heat boiler is sent to an electrostatic precipitator, an economizer, and DeSOx unit (for future), and then to a stack. The Waste Heat boiler is equipped with a boiling steam water drum. The CO boiler is equipped with FD fans, burners for fuel gas and also fuel oil in order to obtain a complete combustion of CO. 2.5 Feed fractionation 2.5.1 Feed section Long residue is normally fed directly to the unit from the Crude Unit (CDU) at 115°C. Alternatively part, or all, of the feed can be fed from storage at 70°C. The preheat of the feed is designed to process 100% cold feed. The hot feed and cold feed flow to Feed Surge Drum D-1513. The feed rate is on level control, with a split range level control signal to the controller inside the CDU or to the flow controller on the cold feed from storage. In the Bach Ho case preheating of feed is by the LCO pumparound, MP and HP steam and finally by slurry to obtain the feed temperature of 290°C. In the case of Mixed Crude feed, the feed is preheated to the required temperature of 170°C by the LCO pumparound when 100% of the feed to the surge drum is hot. Additionally, MP steam heating is required when the feed is all or partly cold. The following description is based on Bach Ho feed, hot or cold; the feed is pumped from D-1513 by feed pumps P-1501A/B to LCO Pumparound Feed Heater E-1512A/B/C/D. The preheat duty in this exchanger is set by flow control of the LCO pumparound. The feed is further preheated in MPS Feed Heater E-1522 and HPS Feed Heater E-1524. The MP steam to E-1522 is on flow control and the HP steam to E-1524 is on flow control reset by the feed side outlet temperature. Final preheating takes place in Slurry Preheat Exchangers E-1502A/B/C and E-1501A/B. The final feed temperature is controlled by by-passing feed around E-1502A/B/C and E-1501A/B. The temperatures controller is located after the point where feed is mixed with HCO recycle. A constant pressure is maintained on the feed to the reactor feed control valves by the pressure control valve upstream of E-1502A/B/C. This pressure control ensures that the HCO recycle can enter the feed line. The location of the pressure control valve also facilitates the by-pass temperature control. 2.5.2 Mixed crude feed When processing mixed crude feed, the slurry preheat exchangers are not required. These exchangers should have the slurry flushed out of them to avoid settling of catalyst fines and because of the high viscosity and high pour point of the slurry. The feed is preheated in the LCO Pumparound Feed Heater E-1512 A/B/C/D for hot feed and for cold feeds also in MP Steam Feed Heater E-1522. The final temperature is controlled either by controlling LCO Pumparound to E-1512A/B/C/D or by controlling MP steam flowrate to E-1522.

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2.5.3 Fractionator bottom section The reactor effluent from the disengager of the reaction section is sent to the main fractionator T-1501. The bottom slurry pumparound is circulated by Slurry Pumparound Pumps P-1519A/B/C. In the case of Bach Ho feed, a large proportion of the bottom pumparound duty is used to preheat the feed in E-1501A/B and E-1502 A/B/C. The remaining duty is used to generate HP steam in HP steam generators E-1504A/B and MP steam in MP steam generators E-1505A/B. For the Mixed Crude feed case, E1501A/B and E-1502 A/B/C are not in service. In this case HP steam is generated in HP steam generators E-1503 A/B/C. The main part of this cooled slurry pumparound is returned to the grid section (Bed 5) where the reactor effluent is desuperheated and the bottom slurry product is condensed. The cooled stream flowrate is reset by the temperature controller below the HCO draw-off tray. A constant total flowrate to the grid is maintained by by-passing hot slurry from the discharge of the slurry pumps. Part of the cooled slurry is returned to the bottom of the column to quench the bottoms temperature to around 340°C to minimize coking. Part of this quench is taken on flow control from either the discharge of E-1502A/B/C or E-1503A/B/C, depending on operating case. The remaining quench is taken from the outlet of E-1505A/B on flow control reset by T-1501 bottom outlet temperature controller. The slurry product is taken from the discharge of the MP steam generators E-1505 A/B under bottoms level control and flows to slurry draw-off drum D-1515. The slurry product is pumped by P-1504 A/B and is cooled in LPS generator E-1506 A/B and then flows to slurry separator X-1504 to remove catalyst fines. The clarified oil leaving the slurry separator is finally cooled in tempered water coolers E-1507 A/B/C/D before going to storage. The slurry separator X-1504 consists of 10 modules. These are sequentially taken out of service for backflushing while the others remain in service. The modules are back-flushed by P-1505 A/B with HCO from D-1516. The flush oil from the separator, containing a high concentration of catalyst fines, goes to back-flush oil receiver D-1517. The back-flush oil is returned to the reactor riser at constant rate by P1506 A/B. 2.5.4 HCO section Heat is removed at high level in the HCO pumparound section. HCO flushing oil and HCO recycle are also taken from this section. Heat is removed in Bed 3 and internal reflux from the draw tray flows to wash section, Bed 4. HCO pumparound is circulated by P-1508 A/B and is cooled in the debutanizer reboiler E-1560A/B, heavy naphtha stripper reboiler E-1509 and MPS generator E-1523. Total flow is maintained constant by by-pass control and heat removal is controlled by temperature control of flow through E-1523. HCO for flushing oil is stripped in HCO stripper T-1504 and the stripper vapor is returned to T-1501 above the pumparound, Bed 3. The stripped HCO is pumped by P-1509 A/B and is cooled under temperature control in HCO LPS generator E-1510. Part of the HCO goes to Backflush Oil Receiver D-1516 on flow control, reset by D-1516 level. The remaining part goes to the HCO flushing oil system for flushing of slurry pump seals and for instrument flushing. For maximum distillate mode operation, HCO is recycled to the reactor feed. The HCO recycle is pumped by P-1507 A/B, and after cooling on temperature control by generating steam in HCO Recycle MPS Generator E-1508, it is mixed with the feed upstream of the feed temperature control point. 2.5.5 LCO section This section of T-1501 consists of six fractionating trays, trays 25 to 30, and a packed pumparound bed, Bed 2. LCO pumparound is circulated by P-1510 A/B and is cooled in stripper and reboiler E-1557, LCO pumparound feed preheat exchangers E-1512 A/B/C/D and LCO pumparound BFW Heater E-1511. Total flow is maintained constant by by-pass control and heat removal is controlled by temperature control of flow through E-1511.

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LCO is drawn off the pumparound draw tray and is fed to LCO Stripper T-1503 on T-1503 bottoms level control. The stripper vapor is returned to T-1501 above the pumparound, Bed 2. Stripped LCO is pumped by P-1511 A/B and is cooled on temperature control in LCO Product LPS Generator E-1513 and the air cooler E-1514 before going to the LCO Hydrotreater unit. For maximum gasoline operation this is the total LCO product. For maximum LCO operation (maximum distillate operation), heavy naphtha is mixed with this stream before going to the LCO Hydrotreater unit. In case of LCO Hydrotreater shut down, the LCO is sent directly to the storage.

2.5.6 MTC and heavy naphtha section This section consists of 14 fractionating trays, trays 11 to 24, and heavy naphtha pumparound bed, Bed 1. MTC is drawn off from tray 19. The MTC (Mix Temperature Control) has a composition between the light end of the LCO and the heavy end of the heavy naphtha. This cut is recycled to the riser in the Mixed Crude Maximum Gasoline case. The MTC is pumped by P-1512 A/B to the riser injection nozzle on flow control. Heavy naphtha pumparound is circulated by P-1514 A/B and is cooled by Stripper Feed Preheater E-1555, Heavy Naphtha Pumparound air cooler E-1521 and is used for reboiling in the Propylene Recovery Unit (PRU). The air cooler E-1521 is designed for the case when the PRU is not in operation. Total flow is maintained by by-pass control and heat removal is controlled by temperature control of the flow through E-1521. Heavy naphtha is drawn off the pumparound tray and is fed to Heavy Naphtha Stripper T-1502 on T-1502 bottoms level control. The stripper is reboiled by reboiler E-1509, which is heated by the HCO pumparound. The stripper vapor is returned to T-1501 above the pumparound bed. Stripped heavy naphtha is pumped by P-1515 A/B. It is first cooled by preheating HP boiler feed water in E-1516 and is then cooled in air cooler E-1517 and trim cooler E-1518. For maximum LCO case, the heavy naphtha is mixed with LCO and for maximum gasoline case it is mixed with debutanized gasoline in the Gas Recovery Section. Heavy naphtha is also drawn off as lean oil for the secondary absorber in the Gas recovery Section. The lean oil is pumped by P-1513 A/B on flow control in the Gas Recovery Section where it is first cooled in Lean Oil / Rich Oil Exchanger E-1563 before cooling in Lean Oil Cooler E-1564. 2.5.7 Top section This section of T-1501 consists of 10 fractionation trays, trays 1 to 10. Rich oil from the secondary absorber in the Gas Recovery Section is fed to tray 9. A partial draw-off accumulator tray is provided below the top tray. The accumulator tray is designed to separate water and hydrocarbon. Any water is drawn-off under interface level control and flows by gravity to the inlet of overhead condenser E-1519. 2.5.8 Fractionator overhead section The overhead naphtha cut point is controlled by the overhead temperature controller resetting the external reflux rate. Wash water is recycled from the fractionator reflux drum D-1514 to the inlet of the overhead condenser E-1519 to minimize corrosion in the condenser. Corrosion inhibitor is also injected to the overhead line of T-1501. The overhead vapor from T-1501 is partially condensed in E-1519 and E-1520A-H and the liquid hydrocarbon, water and vapor phases are separated in D-1514. Off-gas streams from CDU and NHT Units are fed to D-1514. Part of the liquid hydrocarbon is refluxed to T-1501 by P-1516 A/B. The net overhead liquid product is pumped by P-1518 A/B, under flow control reset by level control, to the primary absorber in the Gas Recovery Section. The overhead wet vapor flows to the wet gas compressor suction drum.

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Sour water is pumped from D-1514 boot by P-1517 A/B. Part of the water is recycled on flow control to the inlet of E-1519 and part is sent on flow control as wash water to the wet gas compressor intercooler. The remaining sour water is sent to the sour water stripping unit on boot interface level control. 2.6 Gas Recovery section 2.6.1 Wet gas compressor and HP condenser Wet gas from the Fractionation Section flows to the wet gas compressor first stage knock-out drum D1551. The gas is compressed in the first stage of the compressor C-1551 and is then cooled in air intercooler E-1551 and trim cooler E-1552 A/B. Sour water from the Fractionation Section is injected at the inlet of E-1551 to minimize corrosion. The cooled vapor and condensed liquid from E-1552 are separated in interstage drum D-1552. The vapor from D-1552 is compressed in the second stage of compressor C-1551. The liquid phase in D-1552, hydrocarbon and water, is pumped by P-1551 A/B and is re-contacted with the compressor discharge vapor. This combined stream is partially condensed in HP condenser E-1553. 2.6.2 Stripper condenser and high pressure separator drum The outlet from E-1553, the primary absorber bottom liquid and the stripper overhead vapor are combined before entering stripper condensers E-1554A/B. An LPG stream from the CDU is also fed to the inlet of E-1554 A/B. The mixed phase outlet from E-1554A/B is separated into water and hydrocarbon liquid phases and a vapor phase in HP separator drum D-1553. The sour water is sent on D1553 boot interface level control to the sour water stripper. The hydrocarbon liquid phase is pumped by P-1553 A/B and after preheating in E-1555 is fed to the top of stripper T-1552. The vapor phase from D-1553 is fed below the bottom tray of primary absorber T-1551. 2.6.3 Primary absorber The primary absorber T-1551 recovers most of the C3 and C4 from D-1553 vapor. The overhead liquid from the Fractionation Section is fed to the top tray of T-1551. For other than Bach Ho Max Gasoline case, gasoline is also recycled from the bottom of the debutanizer in order to obtain the required recovery of C3 and C4. The absorber bottom rich oil flows to the inlet of E-1554 under level control. 2.6.4 Stripper The stripper strips H2S and C2 and lighter from the LPG and gasoline mixture which is fed to the top tray from HP separator drum D-1553. Reboiler heat is supplied by two reboilers in series. The first reboiler E1556 is heated by debutanizer bottoms. The second reboiler E-1557 is heated by the LCO pumparound from the Fractionation Section. The heat input to E-1557 is controlled by the overhead vapor rate from the stripper. This rate, and hence the reboiler duty, is set to meet the C2 specification in the debutanizer overheads. The overhead vapor is condensed in E-1554. The bottom liquid is fed to the debutanizer T-1554 on flow control reset by level control. 2.6.5 Secondary absorber The secondary absorber T-1553 recovers gasoline light fractions from the overhead gas from primary absorber T-1551. The lean oil is a heavy naphtha stream from the Fractionation Section. The lean oil is cooled by exchange with the bottoms of T-1553 in E-1563 and then in lean oil cooler E-1564. The cooled liquid flows through lean oil coalescer D-1556 to remove entrained water before being fed to the top tray of T-1553. The bottom rich oil flows under level control, and after recovering heat by exchange with the lean oil in E-1563, it is recycled to the main fractionator in the Fractionation Section.

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The overhead gas is cooled in fuel gas cooler E-1565 and flows to fuel gas absorber K.O. drum D-1557. 2.6.6 Fuel gas absorber The fuel gas absorber T-1555 removes H2S and CO2 from the gas from the secondary absorber by contact with DEA. The small amount of liquid in the effluent from E-1565 is separated in K.O. drum D-1557. The liquid is sent to the inlet of E-1563 on level control. The overhead gas is fed to the bottom of T-1555 and the lean amine is fed to the top tray. The temperature of the lean amine is controlled to maintain the lean amine at a fixed temperature difference above the inlet gas, to avoid hydrocarbon condensation. The overhead gas is sent to K.O. drum D-1559 before going to the fuel gas system. The rich amine goes to the amine unit under T-1555 level control. Any amine accumulated in K.O. drum D–1559 also goes to the amine unit on level control. 2.6.7 Debutanizer The debutanizer separates LPG from gasoline. The bottom of the stripper is fed to debutanizer T-1554. The overhead vapor is totally condensed in condenser E-1561 A/B. The pressure in D-1554 is controlled by by-passing part of the overhead vapor to the reflux drum D-1554. The condensed liquid is pumped from D-1554 by P-1556 A/B. Part of the liquid is refluxed on flow control reset by the temperature controller on the sensitive tray in the top section of the column. This controls the C5 specification in the overhead product. The remaining overhead liquid, LPG product, goes under flow control reset by D-1554 level control to the LPG amine absorber T-1556 after cooling in E-1562. The column is reboiled by reboiler E-1560 A/B. The heat input to the reboiler is from the HCO pumparound in the Fractionation Section. The reboiler duty is set to ensure that the C4 specification in the gasoline is met. The gasoline from the bottom of the column is first cooled in stripper reboiler E-1556 and then in air cooler E-1558 and finally in gasoline cooler E-1559. Part of the cooled gasoline is pumped on flow control by P-1554 A/B to the primary absorber as supplementary lean oil when required. The net gasoline product is sent on flow control, reset by debutanizer level control, to the Gasoline Treating Unit. For maximum Gasoline operation the heavy naphtha from the Fractionation section is combined with this stream. 2.6.8 LPG amine absorber The LPG amine absorber T-1556 removes H2S by contact with DEA. T-1556 is a packed column. The LPG enters at the bottom and flows up through the amine. The LPGamine interface level control above the top packed section is maintained by controlling rich amine flow leaving the bottom of the absorber. The overhead LPG liquid flows to the LPG amine coalescer D-1555, where amine carry-over is separated. The amine is sent to the rich amine stream from the absorber bottom on boot interface level control. The overhead LPG from the drum goes to the LPG Treating Unit. 2.7 Theory of the Process 2.7.1

Chemical reactions and catalysts

2.7.1.1 Introduction and Objective of this chapter The aim of the information given in this chapter is to provide enough theoretical background, in the simplest possible way, to the instructions given in the chapters that follow, i.e. Start-up of unit, Operation of the unit, Shutdown of the unit.

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It is expected that this theoretical support will help the operators to better understand the reasons of the operating instructions and enable them to make wise decisions, should the circumstances deviate from what is covered in the Operating Instructions. 2.7.1.2 Thermodynamics and kinetics. For any chemical reaction the thermodynamics dictates the possibility of its occurrence and the amount of products and unconverted reactants. In fact, some reactions are 100% completed i.e. all the reactants are converted into products. Others are in equilibrium i.e. part of the reactants only are converted. The amount of products and reactants at equilibrium depends upon the operating conditions and is dictated by the thermodynamics. Note that the thermodynamics does not mention the time required to reach the equilibrium or the full completion of a reaction. Kinetics dictates the rate of a chemical reaction (i.e. the amount of feed that disappears in, say, one second). Kinetics (rate of reaction) is dependent upon operating conditions but can also be widely modified through the use of properly selected catalysts. One reaction (or a family of reactions) is generally enhanced by a specific catalyst. In other words, thermodynamics dictates the ultimate equilibrium composition assuming the time is infinite. Kinetics enables to forecast the composition after a finite time. Since time is always limited, when reactions are concurrent, kinetics is generally predominant. A catalyst generally consists of a support (earth oxide, alumina, silica, magnesia,...) on which (a) finely divided metal(s) is (are) deposited. The metal is always responsible for the catalytic action. Very often, the support has also a catalytic action linked to its chemical nature. A catalyst is not consumed but can be deactivated either by impurities in the feed or by some of the products of the chemical reactions involved, resulting in coke deposit on the catalyst. The different chapters of section 5-3 describe: ♦

The various chemical reactions involved in the process as well as the effect of the operating conditions.

♦

The catalyst characteristics.

♦

The catalysis mechanism.

♦

The catalyst contaminants.

♦

The process variables.

2.7.1.3 Catalyst activity, selectivity, stability The main characteristics of a catalyst other than its physical and mechanical properties are: • The activity which is the catalyst ability to increase the rate of the reactions involved. It is

measured by the temperature at which the catalyst must be operated to produce a product onspecification, for a given feed, all other operating conditions being equal. • The selectivity expresses the catalyst ability to favour desirable reactions rather than others. • The stability characterizes the change with time of the catalyst performance (i. e., activity,

selectivity) when operating conditions and feed are stable. It is chiefly the polymers or coke

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deposit which affects stability, because it decreases the metal contact area. Traces of metal in the feed also adversely affect stability. 2.7.2

Types of reactions

The reactions involved in RFCC process are of two types: thermal cracking and catalytic cracking. A Thermal cracking Chemical cracking reactions are characterized by the breaking of chemical bonds within the molecules of hydrocarbons or other compounds contained in petroleum fractions. They mainly involve the breaking of carbon-carbon bonds (- C - C -), carbon-sulfur bond (- C - S -) and also, although to a lesser extent, carbon-hydrogen bonds (- C - H). These reactions are the result of the heating effect, whether or not in the presence of a catalyst. However, cracking of a petroleum cut is not confined to these breakages of bonds, since both shorter and longer molecules than those originally present in the treated cut are simultaneously obtained. This can be explained by a rather complex mechanism, which occurs after the first cracking reactions. To simplify matters, one can distinguish primary cracking reactions and progress reactions. a)

Primary cracking reactions

This type of reaction concerns various molecules in the feed. In the case of the main groups of hydrocarbons, paraffins, naphthenes and aromatics, the following conversions are mainly to be observed: Paraffin

Æ

Olefin

+

Lighter paraffin

C30H62

Æ

C22H44

+

C8H18

Naphthene

Æ

Olefin (by cycle cracking)

example

R

example

C=C Æ

Aromatic with side chain CH - R 1

example

Æ

Æ

C- C- C

C-R

+ Olefin Aromatic (by cracking at side chain) + CH = R 2

In every case, the absence of hydrogen supply is found to result in the regeneration of olefinic unsaturated products. b)

Progress reactions

It concerns intermediate compounds produced by primary cracking.

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These include: Secondary cracking of paraffins producing, like primary cracking, an olefin and a paraffin. C8H18

example

Æ

C5H10

+

C3H8

Conversion of highly reactive olefins. Either into smaller olefins by cracking. Olefin C8H16

example

Æ Æ

two smaller olefins C3H6

+

C5H10

or into diolefins by hydrogen loss, such dehydrogenation being the result of breaking of carbonhydrogen bonds.

Olefin C10H20

example

Æ

diolefin

+

hydrogen

Æ

C10H18

+

H2

Conversion of olefins into paraffins and diolefins or aromatics; this hydrogen transfer reaction plays a considerable role in the case of catalytic cracking. olefin 1 + olefin 2

Æ

Paraffin

+

diolefin

olefins

Æ

Paraffins

+

aromatic

Starting with olefins gives a product with higher hydrogen content (paraffin) and another with lower hydrogen content (diolefin, aromatic). Additional reactions between certain intermediate products, mainly involve progressive attachment of diolefins to aromatics, resulting in condensed and highly aromatic polycyclic heavy products; this is how heavy fuel oils and coke appear. This kind of reaction is called Diels Alder cycloaddition (or condensation). B

Catalyst cracking

The use of a catalyst in chemical reactions during hydrocarbon cracking makes a significant change in the chemical conversions, affecting reaction mechanisms and selectively speeding up some of them. Catalytic cracking differs from thermal cracking in the following main ways: • Lower yields of C2 gases, since catalysts theoretically do not allow the formation of short molecules with fewer than 3 carbon atoms. • Higher yields of gasoline, which also have better stability and a higher octane number. • Smaller coke production for the same feed processing, thereby indicating better catalyst selectivity. • Products of different chemical composition: few olefins, many isomerized structures, high aromatic contents, etc..

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Since their discovery, catalytic cracking catalysts have changed a great deal, and now consist mainly of mixtures of amorphous silica-alumina and crystallised silica-alumina, the latter better known as zeolite or molecular sieves. They take the form of a solid in powder form, the catalyst activity of which during cracking is related to the acid properties of their surface. They are treated during manufacture to endow them with proper acidity, quite comparable with that existing for conventional liquid acids such as sulfuric, hydrochloric and nitric acids.

This acidity function in cracking reactions appears in the following two main mechanisms: • Appearance of a particular reaction mechanism, involving the intermediate presence of ionic reaction compounds. • Major impact on the hydrogen transfer reactions already described. These two specific mechanisms, which largely explain the catalytic cracking efficiency, are discussed below. Catalytic cracking is a reaction characterized by its endothermicity and an increase in the number of molecules. It is therefore favored at high temperature and at low pressure. a) Acid catalyst cracking The cracking mechanism involving catalyst acidity is related to the appearance of intermediate ionic compounds, which possess very specific properties governing the progress of the cracking process. Such compounds usually appear during adsorption of an olefin produced by primary cracking on the acid catalyst. Whereas thermal cracking of a heavy petroleum cut involves a fairly complex mechanism, which rather unselectively generates unsaturated lighter products, and heavier products, than the original feed (in particular producing a great deal of gas, rather unstable gasolines and a high proportion of coke), cracking reactions can be improved to move product yields and qualities in the desired direction, by using a catalyst. This explains the great benefit of catalytic cracking. Structural change in the hydrocarbon chain in the direction of branched-chain isomerised structures. These new forms represent greater stability for the O+ cation. This stage explains the high presence of such molecules in catalytic cracking products. The structural change takes place spontaneously and leads to this more stable carbocation: this is isomerization. Secondary cracking resulting in the formation of a smaller olefin and new O+ cation with a shorter chain, which may then undergo the same process as the previous one. This corresponds to the standard progression of cracking, resulting in the formation of light products. O+ cations, however, very strongly discourage the formation of short chains with fewer than 3 carbon atoms, explaining the lower yields of C2- gases obtained by catalytic cracking. b)

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Hydrogen transfer reactions

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As already mentioned, hydrogen transfer reactions from olefins, which are highly encouraged by zeolite catalysts, result in the parallel formation of: • Hydrocarbons with more hydrogen, benefiting from the transfer; these are therefore mainly paraffins; • Compounds with less hydrogen, such as aromatics. The reaction shown below demonstrates the typical change of olefins into C6 through this type of reaction:

4C6 olefins

3C6 paraffins

+

1C6 aromatic

3 (C6H14)

+

C6H6

hydrogen transfer 4 (C6H12)

It involves four C6 olefins converted into three paraffins by hydrogen gain and one aromatic by hydrogen loss. This reaction is extremely important for overall results of cracking, since it has two main consequences: It preserves the gasoline yield by preventing, through the very fact of its rapidity, concomitant conversion of olefins in the gasoline carbon range into light gases by cracking. It produces paraffin-richer products, particularly gasolines, which would have a very bad effect on the octane number, if a large proportion of the paraffins thereby obtained did not have an isomerised structure. All this goes to show that the effect of the catalyst acidity and hydrogen transfer reactions are largely responsible for the yields and qualities obtained by catalytic cracking. An other example concerns the hydrogen transfer reaction between a naphteno-aromatic compound (tetraline) and an ∝-olefin (isobutene). 3CnH2n-2

Æ

2CnH2n

+

CnH2n-6

cyclo-olefins

Æ

naphtenes

+

aromatic

Hydrogen transfer is influenced by: ♦ Feed quality. ♦ Riser Outlet Temperature. ♦ Cat to oil ratio. ♦ RE2O3 on catalyst. ♦ Catalyst composition. ♦ More hydrogen transfer means: ♦ More coke.

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♦ Less LPG. ♦ More gasoline. ♦ Less product olefins. ♦ Lower RON. A glance at the general scheme of the parallel and consecutive cracking reactions shows that all the products (gas, gasoline, LCO and coke) are primary. The LCO usually results from a single cracking operation of the large molecules in the feed. Most of the gasoline and part of the gas also result from primary cracking. However, a large share of the gases, especially C3 and C4, result from the secondary cracking of gasoline and LCO. A small part of the coke appears to form instantaneously by thermal dehydrogenation of large probably naphteno-aromatic molecules. C1 and C2 hydrocarbons are essentially produced by thermal cracking. This set of reactions involved can be divided into three categories. 2.7.3

Desired reactions

These reactions include cracking and isomerization. A Cracking reactions • Hydrocarbon reactivities A very rough order of reactivity of the main hydrocarbon categories is: olefins > alkylaromatics > alkylnaphtenes and isoparaffins > n-paraffins and naphtenic cycle >> aromatic ring (very stable) In all cases, cracking results from the scission of a carbocation (or carbenium ion) located in the neighborhood of an acid site on the catalyst. The more easily the carbocation is formed and occupies the catalyst surface, the more it undergoes scission. This helps to define an additional reactivity rule valid within the first four categories above: Crackability increases with size (or number of carbon atoms) and the degree of branching of the hydrocarbon category. How are hydrocarbons cracked? A few simple rules can be set forth. Heavy linear alkanes and linear alkenes are always isomerised before cracking. The cracking products of the molecules hence contain a majority of 1 to 2 methyl branches (or, to a lesser degree, ethyl). Cracking by scission at β of these molecules mainly occurs in mid-chain and practically never at less than three carbon atoms from the end. C1 and C2 are formed by a thermal homolytic mechanism different from β-scission. The alkyl chains fixed to a cycle are cut at the edge of the ring if the cycle is aromatic, and at any point located at three or more carbon atoms from its end if the cycle is naphthenic. B Isomerization reaction

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Given the short residence times employed in cracking, this reaction only affects the olefins with roughly more than four or five carbon atoms and the heavy paraffins of the feed. The light paraffins produced by a first cracking subsequently do not have the time to isomerize. The C4 paraffins are thus present in proportions quite different from those of thermodynamic equilibrium. C4 olefins are much closer to equilibrium but never reach it. 2.7.4

Reactions to be limited (but not eliminated) A Hydrogen transfer

This bimolecular reaction consists in the transfer of a hydrogen molecule from one naphthene or olefin to another olefin, by a heterolytic acid mechanism. It leads essentially to the formation of saturated hydrocarbons, mainly paraffins, as well as aromatic compounds (mono and essentially polyaromatics). Polynaphthenoaromatics and other heavy coke precursors are very reactive molecules with respect to hydrogen transfer. This reaction plays a very important role in the quality of the gasoline obtained and the formation of coke. Hence considerable hydrogen transfer decreases the olefinicity of the gasoline and increases the coke production in the installation. It simultaneously improves the stability of the gasoline (i.e. its ability to withstand overcracking) by lowering the reactive molecule content. B Condensation reactions The Diels-Alder cyclo-addition is the main reaction. It consists in combining a linear or cyclic olefin with a linear or cyclic diolefin, leading to more condensed and partly unsaturated cyclic structures. These are transformed into aromatics (mono or poly) by hydrogen transfer, or continue to undergo cycloaddition. The final stage of the successive cyclo-addition and hydrogen transfer reactions is the deposition of very heavy condensed polyaromatics constituting coke on the catalyst. 2.7.5

Undesirable reactions to be reduced to the minimum A Hydrogen formation

The dehydrogenation of condensed and partly unsaturated cyclic molecules by metallic contaminants, in particular Ni and V, is responsible for most of the production of hydrogen (Ni and V) and a substantial share of coke (mainly Ni). The production of methane is virtually unaffected by the metal content, therefore this effect is monitored through the H2/methane ratio. B C1 and C2 hydrocarbons These are mainly due to non-selective thermal cracking. Hence their production is highly sensitive to the riser temperature. 2.7.6

Conversion selectivity of various hydrocarbon families

The two families most selectively converted to gasoline are alkylmonoaromatics and condensed polynaphthenes (mainly with two cycles). Among the simple saturated hydrocarbons, the order of gasoline selectivities is: naphthene > isoparaffins > normal paraffins. Polyaromatics, especially with four and five rings, are not converted to gasoline but are excellent coke precursors. • Definitions of conversion

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A


Conversion

The conversion rate is defined by the following ratio:

Conversion =

Flow rate of converted products x 100 Flow rate of fresh feed

Depending on whether flow rates are expressed by weight or volume, the conversion rate is a weight percentage or a volume percentage. Converted and non-converted products are designated as follows: • Converted products: Dry gas C3 cut C4 cut Light gasoline Heavy gasoline Coke • Unconverted products: LCO HCO Slurry B

Industrial conversion rate

It is not easy to measure the flow rates of converted products. The flow rate of coke is not directly measurable, and volume flow rates of dry gas are meaningless. In contrast, it is possible to measure flow rates of non-converted products. The flow rate of converted product is obtained by subtracting the flow rate of non-converted products from the flow rate of fresh feed: Converted products flow rate = fresh feed flow rate - non-converted products flow rates. and therefore:

Industrial conversion rate = C

Fresh feed flow rate - non - converted products flow rates x 100 Fresh feed flow rate

Adjusted conversion rate

It can be understood that the flow rate of converted products depends on the cutpoint between gasoline and LCO. This cutpoint is conventionally defined by the ASTM FBP of the gasoline at a constant cutpoint of 221°C (430°F).

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If the initial point of the fresh feed is less than 221°C, the flow rate of fresh feed is adjusted as follows: Adjusted fresh feed flow rate = fresh feed flow rate - fraction boiling before 221°C. 2.7.7

Catalyst

2.7.7.1 Catalyst characteristics The performance of the reaction system and the regenerations is highly dependent on the kinetic properties of the catalyst. Performance of the catalyst circulation system is also dependent on the physical properties of the catalyst. The FCC catalyst is a solid complex composite acid. Modern FCC catalysts consist of several ingredients, such as: ♦

Zeolites (Y-type Faujasites, ZSM-5).

♦

Active matrices (Silica-Aluminas,).

♦

Binder, Kaolin, Metal traps,...

Zeolites are microporous crystalline aluminium silicates. Procedures exist for the synthesis of zeolites with a structure similar to known minerals as well as zeolites without a natural counterpart, such as for example the ZSM-5 that is used in octane boosting additives. For FCC catalysts mainly the Y-type (Faujasite) zeolite is of interest, with a silica to alumina ratio of about 5. The framework of the zeolite is composed of silicon, aluminium and oxygen atoms, forming a rigid structure of tetrahedra, linked together in cubo-octahedra. The silicon atoms in the SiO4 tetrahedra are partly replaced with aluminium atoms and a corresponding number of charge-compensating sodium ion. These sodium ions are rather mobile and can be exchanged with NH4+ or rare earth (RE3+). This ion exchange is essential for zeolites used as cracking catalysts, because it generates active sites for cracking. RE-exchanged zeolites (REY and REUSY) are favored in cracking catalysts because they show an excellent stability and activity. However, as the rare earth enhances hydrogen transfer reactions, the product olefinicity and research octanes are depressed. During the eighties the rare earth contents were reduced somewhat, while other techniques were developed to compensate for the loss in zeolite stability and activity. The openings of the zeolite pores (0.8 nm) are too narrow for the average feedstock molecules, so that precracking is required. Active « matrices » are applied to give the catalyst a proper pore size and activity distribution, and a good accessibility to the highly active zeolite sites. These matrices also protect the zeolite from catalyst poisons, such as vanadium and sodium. The pore size and activity distribution of the catalyst should be tailored to the feedstock quality and the required product yields. The kaolin serves as a filter and does not directly contribute to the catalyst activity. The binder gives the catalyst the required strength. Today’s spray-dried FCC catalysts consist of microspheres that have excellent fluidization properties and are attrition resistant. The average particle size is around 70 microns in the fresh catalyst and slightly higher in the equilibrium, depending on the efficiency of the cyclones in the reactor and regenerator vessel. The performance of FCC catalysts is the result of the concentration and catalytic activity of the functional ingredients and the intraparticle accessibility of the catalyst. The catalytic activity is determined by e.g.,

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the type of zeolite, the rare earth concentration, the type of matrix and the stability of the active components. The accessibility depends not only on the matrix and the zeolite but also on the non-active components in the catalyst. A. Fresh catalyst Refer to Chapter 4.1, “Specifications of catalysts” B.

Equilibrium catalyst

Equilibrium catalyst (E-cat) withdrawn from the FCC unit can be re-used or disposed of as spent catalyst. a) Re-useable equilibrium catalyst Good quality E-cat can be re-used in the RFCC unit as start-up catalyst, to compensate for losses or as flushing catalyst. In general such catalyst is characterized by: ♦

Unpromoted catalyst is required.

♦

A total metals content (Ni + V) 3000 and 5000 ppm maximum.

♦

An activity level above approximately 67 wt % MAT.

♦

An average particle size of around 70 microns.

♦

Fine content 40 microns minus: above 10%.

♦

Surface area:

above 125 m2g.

♦

CRC:

below 0.1 wt %.

♦

Rare Earths content:

below 1 wt %.

The value of re-useable E-cat depends on the market demand. At least six months prior to start-up, a representative equilibrium fluid cracking catalyst analysis will be submitted to IFP for approval prior to purchase. b) Disposal of equilibrium catalyst In case the metals content (Ni + V) of the equilibrium catalyst exceeds 15000 ppm the E-cat is in general considered as spent catalyst, not suitable anymore for re-use in a low metals RFCC operation. Consequently the material will have to be disposed of in an environmentally safe way. c) FCC catalyst fines FCC catalyst fines are in general not suitable for re-use in the RFCC unit and should therefore be disposed of as spent catalyst. However certain qualities of fines are suitable as flow improver for units with circulation problems. 2.7.7.2 Catalyst mechanism It is the selection of the right catalyst together with the operating conditions (mainly the temperature) which determines the rate of the various reactions and enables to meet the required selectivity. The performance of RFCC catalysts is the result of the concentration and catalytic activity of the functional ingredients and the intraparticle accessibility of the catalyst. The catalytic activity is determined by e.g., the type of zeolite, the rare earth concentration, the type of matrix and the stability of the active components.

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The accessibility depends not only on the matrix and the zeolite but also on the non-active components in the catalyst. ♦

The catalyst support must meet the following criteria:

♦

improve the metal dispersion within its structure as well as the reactants diffusion to the active sites,

♦

be mechanically resistant.

♦

withstand steam, air treatments at temperatures higher than 750°C,

♦

and keep an excellent behaviour towards thermal shocks and steam during the course of regenerations.

Catalyst used in residue cracking operations should be double calcined to enhance thermal stability. Particle size distribution should be examined on the fresh catalyst. The zero to 20 micron fraction should be low to minimize losses through the cyclones. The cyclone system is designed to retain enough of the equilibrium 0-40 micron fraction to maintain good fluidization properties. 2.7.7.3 Catalyst contaminants Definition Three different types of contaminants are considered: inhibitors or activity moderators, temporary poisons, permanent poisons. General remarks The list of contaminants, their effects, their origin and means of removal are presented in the following pages. This presents a non-exhaustive list of the most commonly encountered impurities in the given type of application. Impurities not listed here, and related to other feeds, may have a detrimental effect on catalyst performance. A Inhibitors or activity moderators Inhibitors are compounds which compete with the reactants for the catalyst active surface resulting in a reduction of the available active surface. They adsorb strongly on the catalyst metal but this adsorption is perfectly reversible. • Carbon on catalysts is a typical inhibitor In order to monitor the regenerator efficiency of RFCC unit, the remaining carbon on regenerated catalyst is measured. The carbon on catalyst flowing from the stripper into the regenerator (spent catalyst) can be measured as well, allowing direct analysis of the delta coke level. The carbon is converted to carbon dioxide, which is analyzed using an infrared detector. Apart from measuring the carbon on regenerated catalyst (CRC), the carbon content can be estimated by the refiner by comparing the color of the equilibrium catalyst with the color of reference samples taken from the same unit. A high carbon content does not affect the measured activity but results in a loss of effective activity of the catalyst flowing into the reactor riser (typically 1-2 wt % MAT per 0.1 wt % CRC). As a consequence the unit conversion and selectivities may change. An improved air and/or catalyst

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distribution results in a reduced carbon content. The efficiency of carbon removal also benefits from increasing the dense bed temperature for units operating in a partial combustion mode. B Temporary poisons Temporary poisons are contaminants which are so strongly adsorbed that they accumulate over the active surface. Removal of poisons and activity recovery are obtained only by using specific procedures. • Antimony (Sb) Antimony is only present on equilibrium catalyst if an antimony passivator is used to reduce nickel activity. Approximately 30-50% of the value of the nickel content is sufficient to reduce hydrogen yields to an acceptable level. • Miscellaneous Other metals may also affect catalyst performance. For example, iron and copper can increase the hydrogen make while calcium and magnesium may affect catalyst activity or stability. Usually these metals are not present in such a concentration that a significant impact on the performance is noticed. The equilibrium catalyst may also contain minor amounts of non-metallic oxides from e.g., S, P, Cl and elements like Ti, originating from the kaolin or a metal trap. The balance usually is silica. C Permanent poisons Permanent poisons are not removable by procedures available on site, i.e. usually steam-and- air decoking. The catalyst must be dumped and replaced by a fresh load. Nickel, vanadium and sodium are typical permanent poisons. ♦

Nickel (Ni)

Nickel is introduced with the feed and deposited on the equilibrium catalyst. Nickel is not mobile under normal regeneration conditions and acts as a dehydrogenation catalyst. In FCC nickel enhances nonselective cracking reactions, particularly those producing more hydrogen and coke. ♦

Vanadium (V)

Vanadium is introduced with the feed and is deposited on the equilibrium catalyst. Under regenerator conditions, vanadium migrates and is able to enter the fresh catalyst and destroy the zeolite. As a consequence, catalyst activity and conversion suffer. For conventional catalysts (a typical rule is that 2 points catalyst activity are lost per 1000 ppm vanadium at constant unit conditions and catalyst consumption). As with sodium, the deactivation rate strongly depends on the highest temperature and the vapor pressure of water in the regenerator. By limiting the burn of coke in the first regenerator and thereby the temperature to less than about 700°C in an oxygen deficient environment, the migration of vanadium on the catalyst is inhibited and zeolite damage limited. The damaging form of vanadium is the fully oxidized V2O5 form which requires water to form a vanadium acid, destroying the zeolite and hence catalyst activity. Without an oxidizing atmosphere, vanadium oxidation, mobility, and acid formation can be controlled even in the presence of water/steam. Vanadium in the feed and deposited on the catalyst will promote collapse of the zeolite structure and loss of active surface area at the elevated regenerator temperatures. ♦

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0

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Small amounts of sodium (typically 0.1-0.4 wt %) are present in the fresh catalyst. Sodium can also be introduced by the feed, especially if resid is processed. In case of high sodium levels on equilibrium catalyst, the feed quality should be checked. Malfunctioning of crude desalters or processing of imported feeds contaminated with seawater are the typical causes of high sodium levels in most cases. Sodium is a catalyst poison which neutralizes acid sites and destroys the zeolite. Approximately 6 points MAT activity are lost per wt % sodium originating from the FCC feed. At high sodium levels the catalyst is more sensitive to high temperatures, due to increased rates of sintering, and surface destruction. Feed sodium should be kept imperatively below 2 wt ppm. Note: Caustic injection used in the crude train is not recommended without effective removal of the sodium neutralization salts. Caustic injection, if used, should be before the desalters. The Na2O content of the equilibrium catalyst should not exceed the Na2O content of the fresh catalyst by more than 0.10 wt %. 2.7.8

Catalyst regeneration

The catalyst that leaves the stripper usually contains up to 1 wt % coke with a C/H ratio of about unity. The main objectives of regeneration are to burn off the coke from the catalyst in order to restore its activity and to maintain the heat balance of the unit. The heat generated by the major combustion reactions is shown in table.

Heat released kcal/kg carbon

Reaction H2

+

½ O2

Æ

H2O

28700

C

+

O2

Æ

CO2

7830

C

+

½ O2

Æ

CO

2200

CO

+

½ O2

Æ

CO2

5630

The total heat generated largely depends on the hydrogen content of the coke, the level of CO combustion and the coke yield. Depending on the stripper conditions and the strippability of the catalyst, the H content of the coke can vary from 6 to 8 wt %. It should also be noted that, in addition to carbon and hydrogen, coke contains sulphur and nitrogen. These two impurities originate from sulphur and nitrogen compounds in the feed which combine with the coke during the cracking process. During combustion in the regenerators, the sulphur and nitrogen produce sulphur oxides (SO2 and SO3), ammonia (NH3) and nitrogen oxides (Nox) in amounts that vary with the regenerators operating conditions. All these compounds present in the regenerator flue gases are atmospheric pollutants and the allowable amounts released are governed by statutory regulations. In the R2R process, catalyst regeneration is achieved in two independent regenerators. objectives are:

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The main



-

Handling, when required, high coke laden catalyst without exceeding any catalyst or metallurgical constraints,

-

Regenerating the catalyst with a complete coke removal < 0.05 wt %,

-

Favoring CO formation over CO2 to minimize the heat of coke combustion. The heat released from the combustion of CO (carbon monoxide) to CO2 (carbon dioxide) is about 2.5 times greater per kilogram of carbon than that from the combustion of carbon to CO.

-

Letting the regeneration temperature free to float and to equilibrate to the level corresponding to the coke deposition on spent catalyst.

-

Minimizing catalyst deactivation mainly with vanadium by preventing the vanadium acid destruction of the zeolite embedded in the catalyst.

-

Obtaining a hot catalyst in short contact time designs to favour rapid heat transfer to feed by radiation. This is particularly advantageous in high conversion operations.

In the first stage regenerator production of CO is encouraged, which limits the heat release and thereby rejecting potential heat from the process to the flue gases. The increase of the CO combustion not only results in a higher heat of combustion, but also in a higher consumption of air per ton of coke.

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3


UNIT CONTROL DESCRIPTION

3.1 Control philosophy of the process Refer to chapter 1. “Process specification section”. The most critical control loop on the converter is the Riser Outlet Temperature. The temperature should be controlled within ± 1°C of the set point. A thermocouple located near the outlet of the riser measures the reaction temperature. The temperature is a function of the amount of catalyst admitted to the riser by the regenerated catalyst slide valve. Reaction temperature is basic to the conversion of RFCC feedstocks. To enhance fresh feed vaporization and ultimately the product yields, mixed temperature control (MTC) technology is used. MTC flowrate is set to maintain the desired temperature at the fresh feed injection point. A thermocouple located upstream of the MTC injectors measure the catalyst / vapor mixture temperature. NOTE: It is designed that MTC injection is required for Maximum Gasoline of Mixed Crude. The spent catalyst slide valve controls the catalyst stripper level by modulating the flow of spent catalyst from the catalyst stripper to the first stage regenerator. The catalyst level in the stripper is measured by differential pressure instruments and sends a signal to the controller which sets the position of the slide valve. A minimum level is required in the catalyst stripper to ensure good stripping of hydrocarbons from the catalyst and a seal at the diplegs outlet of the Riser Outlet Separation System. The level in the first stage regenerator is measured by a differential pressure instrument and signals a level controller which resets the position of the plug valve. The plug valve modulates the flow of catalyst from the first stage regenerator into the lift to the second stage regenerator. A minimum level must be maintained in the first stage regenerator to ensure good regeneration and to seal the cyclone diplegs. A low level in the regenerator may unseal the diplegs which could result in backflow of flue gas up the diplegs and loss of catalyst fines with the flue gas. A high level in the first stage regenerator can also result in catalyst carryover from the cyclones because of higher entrainment from the bed and reentrainment from the cyclone dust bowls. During normal operation, the second stage regenerator level is not controlled, but follows the unit inventory. This level is monitored and adjusted by continuous withdrawal as the level builds through catalyst addition. The level in the second stage regenerator must be held within certain limits for the same reasons as stated above for the first stage regenerator. The total daily amount of catalyst withdrawal is adjusted by timer setting taking into account the operation requirements for the overall catalyst balance. In case a (catalyst cooler) is used, the level in the catalyst cooler is not controlled and depends on the second regenerator level. Temperatures of the regenerators are adjusted by varying the catalyst rate through the catalyst cooler and/or adjusting the heat transfer coefficient with the amount of fluidization air. The regenerators pressures are controlled by flue gas slide valves which throttle the flow of flue gas from the vessels. The pressure of the first stage regenerator is directly controlled by the first regenerator flue gas slide valve. The differential pressure between the first stage and second stage regenerators is controlled by the second regenerator flue gas slide valve. This differential pressure is set to provide

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adequate pressure drop across the plug valve for stable control of the regenerators levels. The disengager pressure rides on the main fractionator pressure which is controlled at the main fractionator overhead receiver. The objective in operation is usually to set the main fractionator pressure to a base level for efficient operation and the regenerator vessel pressures to result in approximately equal differentials across the catalyst slide valves. As a general rule any change in the vessels should be done slowly in gradual increments to allow slide valves to reposition properly for stable catalyst circulation. The unit is designed to provide adequate slide valve pressure differential for safe operation. Override controls are provided for action in low slide valve differential upsets which close slide valves to prevent dangerous reverse flow. Normal catalyst slide valve differential is around 0.3 to 0.5 bar to provide stable control. Slide valve differentials above 0.7 bar are to be avoided because they may cause valve erosion. Negative differentials should never be permitted and the PDIC controls should be set to override the main controllers at 0.1 bar. Smooth catalyst circulation is paramount for successful operation of R2R and is achieved by proper catalyst aeration and fluidization in the transfer lines, as well as control of the unit pressure balance. An emergency shutdown circuit will close the catalyst slide valves automatically upon loss of feed and loss of combustion air. ♦

MTC control

Control of the feed and catalyst mix temperature is critical in order to vaporize all hydrocarbons that can be converted to lighter products. This can be achieved independently of the riser outlet temperature which is the primary reaction control parameter. Riser Outlet Temperature is maintained conventionally by regenerated catalyst circulation through the hot regenerated catalyst slide valve. The mix temperature, which can be measured in an appropriate location downstream from the feed injection point, is controlled by an additional liquid hydrocarbon injection point, provided a few meters above the feed injection. With MTC, it is therefore possible to raise the mix temperature while maintaining the Riser Outlet Temperature or even lowering it. Thus the optimum catalyst temperature, the target catalyst circulation, and the desired catalytic cracking reactions can be adjusted separately. The MTC technology offers the possibility of operating the feed injection zone at a higher temperature thereby promoting vaporization without reaching over-cracking conditions in the riser whose outlet is maintained at a lower temperature. Like the (catalyst cooler coil), MTC provides additional heat removal, but in this case heat removal takes place on the disengager side. Cooling is carried out by vaporization of the liquid hydrocarbons introduced at the MTC level. The heat absorbed by MTC vaporization is then used downstream in the fractionation section for steam production, preheating or reboiling. The nature of the recycle depends upon each situation. If heavy naphtha is used as MTC fluid, then MTC acts essentially as a heat sink. The aromaticity of heavy naphtha renders it essentially inert. As a result, LPG and light gasoline yields will be promoted and higher conversion levels will be achieved. When using heavy naphtha, the additional coke formed in the riser (delta-coke) will be minimized and the C/O ratio will therefore be increased. To avoid over-cracking, the Riser Outlet Temperature can be reduced by about 10°C when the recycle is 20% of feed. If the heat balance of the unit is not critical, heavier fractions such as Light Cycle Oil (LCO) or Heavy Cycle Oil (HCO) can be used.

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3.2 Process variables of Reactor / Regeneration Section 3.2.1 General The R2R unit will operate in a stable manner over a wide range of conditions. The operating mode chosen will affect the distribution and quality of products produced. The unit operator chooses a mode of operation to maximize desirable products for different feedstocks or to conform to the demands and limitations of the refining complex. Careful attention to unit performance and process variables will result in an operation of maximum profitability with few problems and upsets. The quality of the reaction which determines the products quality and quantity depends on the: riser outlet temperature, reactor pressure, catalyst activity. The quality of the regeneration depends on the: regenerators air balance, regenerators temperatures, regenerators residence time, regenerators fluidization velocities. The quality of stripping will affect the yields pattern through the delta-coke which controls the regeneration conditions and further the catalyst circulation. Reaction and regeneration are interdependent through the overall heat balance. The heat balance depends on the following variables: feedstock properties, feed temperature, coke production / delta-coke / catalyst to oil ratio. Heat is carried from the regeneration zone to the reaction zone by the catalyst circulation. A proper pressure balance is required to ensure a smooth catalyst circulation. 3.2.2 Riser Outlet Temperature The operating temperature of the riser outlet will normally be set to achieve the desired degree of conversion. Typically, a temperature of 510°C will correspond to a maximum distillate operation and a temperature of 525 to 530°C will correspond to a maximum gasoline operation. This temperature is controlled by the regenerated catalyst slide valve position allowing more or less hot regenerated catalyst to contact and mix with the incoming feed. When the hot catalyst contacts the feed in the bottom of the riser the oil vaporizes almost instantaneously. The homogeneous mixture of oil and catalyst reaches a temperature approximately 30 to 40°C higher than the top of the riser. The initial temperature shock causes thermal cracking, while catalytic cracking begins after the oil is converted to vapor, and the molecules contact the active catalyst sites. As the catalytic cracking progresses and the catalyst/oil mixture flows up the riser, the temperature drops since the heat of cracking is endothermic. At the top of riser the moles of products are 3.5 - 5.0 times more than the moles of fresh feed. The riser temperature has a complex interrelation with the other parameters in cracking. An increase in the riser temperature is generally accompanied by: an increase in conversion, an increase in dry gas yield, an increase in LPG production, an increase or a decrease (over cracking) in gasoline production depending on the reaction severity, an increase in gasoline octane,

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-


a decrease in LCO and slurry yield, a slight increase in coke production.

These are only trends. A quantitative definition of the changes requires heat and material balances as well as yield correlations. The catalyst quality also affects the extent of the changes. 3.2.3 Disengager pressure A lower pressure in the reaction zone thermodynamically improves product yields. However the choice of the disengager pressure must take into account the equipment size and the minimum acceptable pressure considering the wet gas compressor. A pressure of around 0.8 barg can be considered as an optimum value for very heavy feedstocks. 3.2.4 Catalyst activity In conventional gas oil cracking the catalyst activity is measured in two different ways, from actual operation and in the laboratory. In the current practice, an equilibrium catalyst sample is forwarded each week to the catalyst supplier laboratory. There, a standard test (feedstock and operating conditions) is performed to check catalyst activity. Other analyses such as surface area, density, pore volume, particle size distribution, metal content, are as well reported. The catalyst activity, thus measured, relates to the conversion that the actual operating unit may experience with a different feedstock. The correlation of the laboratory measurement is somewhat loose on account of the difficulty in properly quantifying the differences not only in the feedstock, but also the relationship of the method to unit operation. This leads more to a directional relationship in the sense that higher activity catalyst in gas oil cracking leads to greater conversion. In residue cracking the catalyst activity does not necessarily hold the directional relationship between laboratory measurement and unit operation. The complexity of evaluation increases which necessitates the use of other parameters for relating to conversion. The catalyst surface area and the concentration of the deposited heavy an alkali metals provide a more meaningful basis to predict unit performance. This is in addition to a detailed knowledge of the specific characteristics of the catalysts. While catalyst properties and predicted product slate are originally derived at the catalyst development stage, the true performance of the catalyst can only be ascertained from unit operations. The catalyst activity is best measured by the unit operation. The conversion is calculated from unit yields, which include gas and coke productions. Close monitoring of the yields, changes in metal deposition and catalyst surface area are the best methods for maintaining the desirable level of activity. Catalyst activity should be interpreted to mean not only the level of conversion, but also the ability of the catalyst to yield the maximum amount of valuable products and high octane gasoline, while at the same time coke and dry gas productions must be minimized. Catalyst activity is maintained by the addition of fresh catalyst on a continuous basis. The required rate of addition varies depending on feedstock quality, desired level of conversion, operating conditions, and type of catalyst. Normally, addition at a rate of around 1 to 4 kg of catalyst per 1000 kg of feed are necessary to maintain desired conversion. Frequent monitoring of the equilibrium catalyst properties and level of metal contamination (i.e. Ni, V, Na, etc...) are required to provide optimum adjustment of the addition rate. 3.2.5 Regenerators air balance The reduction of the coke on the catalyst to less than 0.05 wt % requires a predetermined amount of air regardless of how the air is distributed between the two regenerators. In a unit with one regenerator the required air rate would be the sum of what the two regenerators require as long as coke yield and the average flue gas composition are the same. Having two regenerators provides a flexibility of how to split the total air required. When certain constraints, such as the maximum regenerator bed temperature and desirable flue gas composition are imposed, the freedom to arbitrarily split the required air decreases. However, there is a great advantage in assigning a specific air rate to each regenerator.

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The first stage regenerator design temperature is 770°C, therefore the coke that should be burned must be controlled so that this temperature limits is not exceeded. The combustion of carbon monoxide is more rapid as the temperature increases over 650°C. This results in lower carbon monoxide concentration and greater air requirement as the regenerator bed temperature rises. When coke burns to form carbon monoxide and steam the heat generated is about half as much as when the same amount of coke burns to form carbon dioxide and steam. The higher temperature generated by greater carbon dioxide production further facilitates the burning of carbon monoxide. If the air rate is limited, then the conversion of CO to CO2 is controlled and the regenerator bed temperature is kept lower. But at the same time more coke remains on the catalyst. The objective is to determine an air rate to the first stage regenerator that will limit the bed temperature and yields carbon monoxide in the flue gas. The objective in the second stage regenerator is to burn all the remaining coke completely to carbon dioxide. The bed temperature is allowed to rise around 810°C (mechanical design : 840°C). The air rate is adjusted to give 2 - 3 mole % of free oxygen in the flue gas which ensures that the carbon monoxide concentration in the flue gas is less than 0.05 mole %. The above split of the required air also has the advantage of minimizing catalyst deactivation. Most of the hydrogen contained in the coke burns in the first stage regenerator. The steam thus generated is at a lower temperature and causes less catalyst deactivation. Since only a small part of the total hydrogen contained in the coke is burnt in the second stage regenerator, the steam concentration is reduced in the higher temperature environment. The flue gas from each regenerator is routed separately which segregates the flue gases according to their carbon monoxide concentration. 3.2.6 Regenerators temperature a) Dense phase temperatures First stage The first stage regenerator dense phase temperature is a function of the riser temperature, the amount of coke burned, and the catalyst circulation rate. The temperature is controlled by varying the air flow to the vessel. The air rate should be adjusted so as not to exceed a temperature of 730°C. Second stage The second stage regenerator dense bed temperature is also a function of the amount of coke burned and the catalyst circulation rate. The normal operating temperature is around 100°C higher than the first stage regenerator dense bed. Control of this temperature is not independent because the air rate to the second stage regenerator is adjusted to achieve complete CO combustion (i.e. 2 - 3 % mole O2 in flue gas) under normal operation. In any case, it is important to keep a minimum temperature in the catalyst dense bed, which is required for a proper combustion (around 680°C). b) Dilute phase temperatures The dilute phase temperature will normally run within 10°C of its corresponding dense phase temperature. The catalyst used, while not promoted, has properties which enhance combustion in the dense bed. These properties, together with proper inventory of catalyst in the dense phase, ensure that all oxygen required for combustion will be burnt away in the dense bed, removing the possibility of after burning. 3.2.7 Regenerators residence time The catalyst residence time in the regenerators is a key parameter for the regeneration quality. The catalyst levels in the two regenerators are optimized depending on the regeneration temperatures to achieve the required inventories. Typically, a total residence time around 6 minutes for the two regenerators is sufficient to achieve a carbon on regenerated catalyst leaving the second regenerator of less than 0.05 wt %, which is considered as a target value for a good regeneration.

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During normal operation, care must be taken to keep the catalyst levels at their normal levels. Low catalyst levels will affect the regeneration quality, whereas high catalyst levels will affect the catalyst entrainment to the cyclones and consequently will increase the catalyst losses. 3.2.8 Regenerators velocities The quality of the combustion depends on the catalyst fluidization. A good mixing between catalyst and air is required for the combustion and therefore turbulent flow is desired in the regenerators dense bed. The corresponding superficial velocities are in the range of 1 - 1.3 m/s. A minimum velocity of 0.5 m/s should be kept in any case (especially for reduced capacity operation). 3.2.9 Stripper operation The removal of any light hydrocarbons which may remain with the catalyst after disengagement in the reactor is accomplished by steam injection into the stripper dense bed via different steam rings. The amount of steam is adjusted depending on the catalyst circulation rate and feed rate. The flowrate is adjusted on the main steam ring, keeping the flowrates on the lower ring and upper ring constant. Stripping efficiency is measured by the hydrogen content on coke. Stripping is considered as efficient when the hydrogen on coke is around 6 wt %. 3.2.10 Heat balance The reaction/regeneration section can be viewed as a closed heat exchange loop where catalyst is recirculated between a heater (regenerator) and a cooler (riser). Hot catalyst is cooled in the riser through vaporization and cracking of feed and is reheated in the regenerator by burning the coke produced during the cracking reaction. The Riser Outlet Temperature controls the regenerated catalyst slide valve to provide sufficient flow of hot catalyst to maintain the riser at the desired temperature. Sensible heats represented by normal variations in riser and regenerator temperatures are very small when compared to the heat of combustion of coke (heating medium), the heat of vaporization of feed and the heat of cracking (cooling medium). The unit is heat balanced in the sense that the heat for vaporizing and cracking the feed is furnished by the combustion of the produced coke in the regenerator. An overall energy balance shows that the energy released by the combustion of coke (carbon and hydrogen) becomes: the sensible and latent heat of the fluid gases, the sensible and latent heat of the reactor effluent, the heat of cracking. Expressed another way, the coke yield in this adiabatic process is essentially that required to satisfy the heat load. The dependent operating variable will automatically achieve conditions where enough coke is made to produce the required heat of combustion to heat and vaporize the feed, supply the heat of chemical reaction, and cover the various heat losses from the process. 3.2.11 Feedstock quality In catalytic cracking a hydrogen deficiency develops as the hydrocarbon molecule split and requires that hydrogen joins a cracked molecule. The higher molecular weight hydrocarbons have lower concentration of hydrogen than the lower molecular weight hydrocarbons. When the cracking process produces lighter hydrocarbons than the feed, the hydrogen is made available from the hydrogen of hydrocarbons with higher molecular weight. The molecule that gives up hydrogen can become deficient in hydrogen to the point that it turns into coke. Hence, it is easy to see that the yield of lighter hydrocarbons or the conversion depends on the total amount of hydrogen contained in the feed. API gravity and distillation determine the hydrogen availability to yield lighter products. Even when the distillation is not properly defined, the API gravity

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gives an indication of feed quality, since lower API gravity feedstock generally has a higher boiling range and less hydrogen. The metals, which are part of the FCC feed, adversely affect performance. Nickel, vanadium, copper and iron carried by the feed will deposit on the catalyst sites and through a complex mechanism, lead to catalyst deactivation. The process is gradual up to a certain metal level on the catalyst, but above about 10 000 ppm of metals, deactivation becomes more rapid. If the metal concentration of the feed cannot be reduced to control this, then fresh catalyst addition replacing catalyst in the unit must be at a rate high enough to keep the metal concentration on the catalyst at the required level. Sodium and other alkali metals also act as catalyst poisons. Exceeding 1 ppm of sodium in the feed should be avoided. Also sodium decreases catalyst melting point making it more sensible to high temperatures. The nitrogen and the sulphur in the feed adversely affect cracking, but are less harmful. Both the nitrogen and the sulphur tie up hydrogen that could be used in the formation of valuable hydrocarbons. In addition to this, the ammonia that is formed is basic, and has a neutralizing effect on the acidic catalyst sites. The Conradson carbon in the feed was in the past believed to convert fully to coke. The coke on the catalyst surface must be burned off in the regenerator, and more coke produces higher regenerator temperatures. Hence, increasing Conradson carbon in the feed was expected to lead to inoperable conditions. In the development of the R2R process, the temperature limitation was raised to be able to handle higher coke burning rate. At the same time, it was noted that previous beliefs stating that 100% of the Conradson carbon converts to coke were false. Only about 50% of the Conradson carbon converts to coke, while the rest turns into gaseous products. As the Conradson carbon concentration increases, the second stage regenerator temperature has a tendency to increase. Adjusting certain operating parameters such as feed temperature, disengager pressure, atomization steam flow, stripping steam flow, may compensate for this up to a point. Note: Do not put slops in the unit feedstock. Additives like copper, manganese, sodium, potassium, organic chlorides, lead from gasoline... will at least increase gas production and could damage catalyst. Nitrogen will also neutralize catalyst acid sites and will decrease conversion. 3.2.12 Feed temperature The preheat temperature of the feed must be adjustable: to ensure a proper oil viscosity (around 10 to 15 cSt maximum at the injector inlet) for proper atomization of the feed ; to ensure a minimum temperature to avoid steam condensation in the feed injectors. The feed temperature must also be optimized depending on the heat balance. The feed temperature affects significantly the coke production and the second regenerator temperature (refer to the next section concerning the coke production). Note that an increase of the feed temperature will result in: a decrease of coke production, an increase of the second regenerator temperature. 3.2.13 Coke yield / delta coke / catalyst to oil ratio The catalyst to oil ratio (C/O) is defined as the rate of catalyst divided by the rate of fresh feed. The delta coke is defined as the difference between the coke percentage on spent catalyst and the coke percentage on the regenerated catalyst. The coke yield corresponds to the percentage of feed transformed into coke. These three parameters are correlated by the following equations: Coke yield = C/O x ΔCoke

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T reg 2

=


T reactor + coeff x ΔCoke

These relations reflect the heat balance between the reaction section and regeneration section. The three process variables will automatically achieve the conditions where the heat balance is satisfied. For a given feed quality and catalyst type, the coke production depends upon nothing except riser temperature and feed temperature. The unit will be optimized with the highest possible C/O and the lowest possible delta coke for the following reasons: • a higher C/O will provide : - more active catalyst sites for the reaction, - a better contact between catalyst and oil, - a higher heat transfer efficiency. This leads to higher conversion, i.e. larger total liquid, LPG, gasoline yields while slurry yield declines. • a lower delta coke will provide : - lower regeneration temperature. C/O is increased by : • raising the riser temperature, • decreasing the feed temperature. But the adjustment of the feed and riser temperatures is limited : • the feed temperature cannot be lowered below a limit value in order to maintain an acceptable feed viscosity for proper atomization and to maintain a minimum temperature for good vaporization, • the riser temperature is fixed by the operation mode (maxi gasoline or distillate mode). IFP has developed the MTC concept which allows to disconnect the heat balance between the reaction section and the regeneration section, providing supplementary flexibility for the unit operation. If the operation mode requires do decrease the Riser Outlet Temperature, the injection of a "cold" fluid, acting as a quench, helps keeping the feed mix temperature at a desired high value for seek of vaporization and heat transfer. 3.2.14 Catalyst circulation / pressure balance Catalyst circulation results from different vessels elevations and from differential pressure created by various catalyst densities. Fluidized catalyst behaves very similarly to normal liquid fluids. Smooth catalyst circulation requires precise control of the unit pressure balance, through the precise control of the pressure in the vessels and the proper control of the densities in the catalyst dense beds and standpipes. The pressure in the disengager is controlled by the main column overhead receiver. The pressure in the disengager is higher than the receiver pressure by the amount of pressure drop through the main column, the condenser and the lines between top of the disengager and the receiver. The pressure in the disengager is normally kept as low as possible within the limits of the wet gas compressor. The first stage regenerator pressure is controlled by a double disc slide valve followed by a variable orifice and a differential pressure controller holds a constant differential pressure (around 0.7bar) between the first and the second regenerator. The differential pressure between the two regenerators should be maintained constant for a smooth operation of the air lift. Pressure of the first regenerator must be controlled so that the differential pressures on the regenerated and spent catalyst slide valves are balanced satisfactorily, i.e. to obtain similar pressure drops through the two slide valves. The minimum required pressure drop through the slide valves for steady control of the valve is around 0.3bar. Maximum pressure drop should be limited to 0.7bar for avoiding erosion problems.

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It is obviously essential for steady circulation that the pressure difference between the vessels be as consistent as possible. Toward this end, it should be noted that the stripper and first stage regenerator levels are kept steady. The second stage regenerator is allowed to float between its minimum and maximum levels. Catalyst circulation is controlled by the opening of the regenerated catalyst slide valve. The circulation rate cannot be measured directly; it must be calculated from the heat balance or estimated from the openings and pressure drops of the regenerated and spent catalyst slide valves.

3.3 Process Operation variables 3.3.1

Introduction

The performance of the RFCC unit is determined by the relationship between the feedstock, the process variables, the catalyst, process design and unit control. Proper control of the FCCU requires careful balancing of the many process variables. The unit can then be optimized within certain limitations to provide the best possible performance. These restrictions include available feedstock, mechanical and operational equipment limitations, and environmental constraints. The following instructions are general and intended as a guide. The operating costs and product values for a given yield distribution will be the major factors in any optimization effort. The process variables are interrelated, so many of the effects may not be immediately obvious. The effects of key process variables will be reviewed. Examples will be given illustrating the role of adjusting these variables to achieve a particular process objective. 3.3.2

RFCC reaction variables

Process variables can be classified in two categories: ¾ Independent variables, ¾ Dependent variables. Table 1 lists some of the key independent variables in the FCC process. Of these, the most critical are the feed temperature, the Riser Outlet Temperature, the catalyst activity, the contact time, and the feed quality. The dependent variables are presented in Table 2 and include the conversion (and yields selectivities), the regenerator temperature and the catalyst to oil ratio.

TABLE 1 INDEPENDENT FCC VARIABLES • • • • • • • •

•

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Riser Outlet Temperature Feed temperature Feed rate Catalyst activity Feed quality Contact time Recycle rate Catalyst circulation rate Air rate



TABLE 2 DEPENDENT FCC VARIABLES • • • •

Regenerator temperature Conversion Carbon on catalyst (spent and regenerated) Catalyst to oil ratio • CO2 to CO ratio Reaction and regeneration are interdependent through the overall heat balance. Independent variables that affect the heat balance can be classified depending on whether they affect the coke production or the delta coke on catalyst. Independent variables that influence the heat balance

EFFECT ON COKE YIELD

EFFECT ON DELTA COKE

Feed flowrate Feed temperature Catalyst cooling Air temperature/humidity

Feed properties Reactor pressure Catalyst activity Catalyst selectivity

EFFECT ON COKE YIELD AND DELTA COKE Recycle flowrate Riser Outlet Temperature Steam rates (atomization, stripping) The coke yield and delta coke are examples of dependent variables that can only be changed indirectly, i.e. by manipulation of independent variables. 3.3.3

Feed temperature effects

Table 3 summarizes the effects of increasing the feed preheat temperature at a constant Riser Outlet Temperature. If the feed temperature is increased, and no change is made to the catalyst circulation rate, the riser temperature would rise along with the feed temperature. This is because the catalyst is supplying the heat needed to heat the feed from the feed preheat temperature to the riser temperature. So if the feed temperature is increased, the catalyst circulation rate will have to decrease to prevent the riser temperature from getting too high. Since the riser temperature is automatically set and is controlled by the action of the regenerated catalyst slide valve, the slide valve should close slightly as the feed temperature is increased. This reduction in catalyst circulation rate (Cat/Oil) causes a number of other changes to occur. First, conversion is usually reduced, while delta coke tends to increase, because the feed coke is spread over less catalyst particles. As delta coke increases, the regenerator temperature tends to increase, making it easier to burn the coke off the catalyst. As a result, the concentration of coke on the regenerated catalyst tends to decrease, while the concentration of coke on the spent catalyst will increase slightly. It is important to remember the equation: Coke Yield = (Cat/Oil) * Delta Coke As the feed temperature increases, delta coke increases slightly, but (Cat/Oil) is significantly reduced, so that the coke yield drops significantly as the feed temperature is increased. Probably the most important

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effect of increasing feed temperature is that it reduces the coke yield. Conversely, lowering the feed temperature increases the coke yield. Thus, the required air rate drops as the feed temperature is increased. For a given air rate, more barrels of feed can be processed as the feed temperature is increased. Following are reasons why feed temperature might be increased: 1. If more feed needs to be processed at a constant air rate. 2. If regenerator temperature needs to be increased. 3. If more feed needs to be processed at a constant catalyst circulation rate. 4. If regenerator gas velocities need to be decreased to reduce catalyst losses from the regenerator. 5. If catalyst circulation rate or air rate need to be reduced at a constant feed rate. 6. If conversion needs to be lowered. Following are reasons why feed temperature might be reduced: 1. If conversion needs to be increased. 2. If dry gas or wet gas rates need to be reduced. 3. If regenerator temperature needs to be lowered. 4. If catalyst circulation rate needs to be increased

TABLE 3 EFFECTS OF FEED PREHEAT Action: Increased feed temperature at constant Riser Outlet Temperature Reactions:

3.3.4

•

Catalyst circulation must decrease

•

Regenerator temperature increases

•

Carbon on regenerated catalyst decreases

•

Coke yield decreases

•

Conversion and octane usually decrease

Riser / Outlet Temperature effects

Table 4 summarizes the effects of increasing Riser Outlet Temperature at constant feed temperature. The automatic controls on the regenerated catalyst slide valve is set to control the disengager temperature. Usually, the disengager temperature is a few degrees lower than the Riser Outlet Temperature due to heat loss and the continuation of endothermic cracking reactions. In most cases, the Riser Outlet Temperature is changed by changing the catalyst circulation rate. If a ROT increase is called for, the regenerated catalyst slide valve is opened slightly to allow more hot catalyst to mix with the feed.

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The FCC conversion will increase for two reasons, the higher temperature and the higher catalyst-to-oil ratio. The coke yields must increase to generate the extra heat required to heat the oil to the higher reactor temperature. The delta coke declines slightly because the coke is spread over more catalyst particles. The regenerator temperature increases, but by less than the reactor temperature is increased. The carbon on the regenerated catalyst declines because the coke is easier to burn as the regenerator temperature rises. However, since the coke yield increases, more air is required to burn the coke. The gasoline octanes will increase, as will the fuel gas and wet gas rates. Gasoline yields will increase until the overcracking point, which usually occurs at ROT between about 525°C and 535°C. Above the overcracking point, the gasoline yields will decline as ROT is increased, while LPG and dry gas (fuel gas) yields will increase rapidly. In summary, Riser Outlet Temperature is the fastest and simplest method of changing conversion in the FCCU. Raising reaction temperature is appropriate when conversion and/or gasoline octanes must be increased and: ¾

Wet gas and dry gas rates are not at their maximum.

¾

Catalyst circulation rate can be increased.

¾

Slide valve pressure differentials are above minimum.

¾

Air rate can be increased.

¾

Regenerator temperatures are not at maximum limits.

Other methods of increasing conversion (such as increasing catalyst activity) may be more appropriate if: ¾

Gas compressor capacity is at a maximum.

¾

Catalyst circulation rate is limited.

¾

Air blower capacity is limited.

¾

Feed rate must be increased.

The choice of the Riser Outlet Temperature will depend on many factors, and optimizing the reaction temperature is often a difficult and complicated procedure that requires a computer model to simulate many variable effects. The above guidelines, however, can be used to at least indicate the proper direction in which the reaction temperature should be moved.

TABLE 4 EFFECTS OF RISER OUTLET TEMPERATURE Action: Increase Riser Outlet Temperature at constant feed temperature Reactions:

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•

Catalyst circulation increases

•

Conversion increases



TABLE 4 EFFECTS OF RISER OUTLET TEMPERATURE

3.3.5

•

Coke yield increases

•

Delta coke declines

•

Regenerator temperature increases

•

Carbon on decreases

•

Required air rate increases

•

Octane increases

•

Fuel gas increases

•

LPG yields increase, iso/olefin decreases

•

Gasoline yields increase

regenerated

catalyst

usually

Effects of contact time

Table 5 summarize the effects of contact time. Contact time is defined as the amount of time that the catalyst and the oil vapor are together in the riser. This depends on the feed rate, the steam rate and both the length and the diameter of the riser. Contact time can be changed by: 1. Changing the feed rate. 2. Changing the dispersion steam rate. 3. Changing the length and/or the diameter of the risers (in case of revamp). 4. Changing the location of the feed injectors (in case of revamp). 5. Changing the riser/disengager pressure. The first four methods of changing contact time are obvious. Disengager pressure affects contact time because it affects the volume that is occupied by a given amount of vapor. Increasing the pressure by 0.1 bar will reduce the vapor volume (and will increase the contact time by approximately 4.0%). Reducing contact time will lower conversion because the oil molecules simply have less time to react. The major benefit of reducing contact time, however, is that the tendency to make coke, or the delta coke, is substantially reduced. As a result, the regenerator temperature drops significantly and the amount of catalyst required to heat the oil increases. Conversion becomes more selective to gasoline, with less production of dry gas and coke. Because refiners do not generally like to see conversion decreases, when contact time is reduced, some other adjustment is usually made to recover any conversion that may be lost. The adjustment may be an increase in Riser Outlet Temperature or an increase in catalyst activity, depending on the other unit limitations.

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An important point is that the volume of vapor changes as conversion takes place. The volume of vaporized products is about 3.5 to 5 times as great as the volume of vaporized feed. As molecules crack, the volume is proportional to the number of moles. As the volume increases, the velocity of flow up the riser also increases. This is why the velocity at the end of the riser is about 20 m/second. For reasons of simplicity, contact time may be calculated based on the volume of vaporized products. In summary, shortening contact time will improve product selectivity by reducing the time available for undesirable coking and thermal reactions. The result is lower delta coke, a lower regenerator temperature and a higher catalyst circulation rate, with less production of dry gas. These benefits are offset somewhat by a lower conversion, which must be regained by other means, such as higher catalyst activity or higher Riser Outlet Temperature.

TABLE 5 EFFECTS OF CONTACT TIME Action: Decrease time by shortening riser Reactions:

3.3.6

•

Conversion decreases

•

Fuel gas and LPG decrease slightly

•

Iso/olefin ratio decreases

•

Regenerator temperature drops

•

Cat/oil increases

•

Coke yield decreases slightly

•

Octane increases slightly

Effects of catalyst activity

Table 6 summarizes the effects of FCC catalyst activity. The activity of the FCCU equilibrium catalyst is measured by the catalyst manufacturers in a laboratory microactivity (MAT) test. The test indicates how active the catalyst is for cracking a standard feed at standard conditions. Changes in the MAT activity will reliably predict the activity of the catalyst in the refinery FCCU. The equilibrium catalyst activity is controlled by how much fresh catalyst is added to the unit each day. As the fresh catalyst addition rate is increased, the equilibrium catalyst activity will rise. Changes in the equilibrium catalyst activity usually do not happen quickly. It may take several days to see noticeable changes in activity after a change in catalyst addition rate is made. If, however, a unit upset occurs and the regenerator temperature or steam concentration increases significantly, for even one or two hours, the activity of the entire catalyst inventory can be reduced very rapidly. Most importantly, as catalyst activity increases, conversion rises by about 0.5 to 0.7 vol. % on fresh feed for each 1 number increase in MAT activity. The conversion increases by less than the activity because the delta coke increases as the catalyst gets more active. This causes the regenerator temperature to increase, which, in turn, causes the Cat/oil to be reduced, offsetting some of the conversion gain.

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Increasing catalyst activity also increases the yields of coke, wet gas and dry gas, but these yields increase by smaller amounts than they would if the same conversion increases were achieved by increasing riser temperature. Gasoline octanes are not greatly affected by catalyst activity.

TABLE 6 EFFECTS OF CATALYST ACTIVITY Action:

Raise catalyst make up rate

Reactions: • Equilibrium MAT activity increases • Delta coke increases • Regenerator temperature increases • Cat/Oil decreases

• Conversion increases by less than MAT activity increase 3.3.7

Effects of recycle rate

Many different streams can be recycled to the FCCU, for a variety of reasons. The most common recycle streams are HCO and slurry oil, because these streams have the lowest value and the refiner has the most incentive to convert these streams to more useful products. The problem with recycle, however, is that a barrel of recycle uses close to the same amount of air as a barrel of fresh feed, and slurry recycle makes more coke and gas than fresh feed. Often, the refiner has to decide between running more barrels of fresh feed or adding recycle. Usually, the economics favor adding more fresh feed. For this reason, many units do not recycle any material. For most units, as slurry recycle rate increases, conversion will increase slightly. The effective conversion on the slurry oil will be between 20 and 40 vol.%, depending on the recycle quality. This compares with conversions of 60 to 80 vol.% on fresh feed. Since slurry oil is very aromatic, it tends to make higher delta coke than fresh feed and is very difficult to convert. The high delta coke causes the regenerator temperature to increase and the catalyst-to-oil ratio (based on fresh feed) to decline. The slurry oil also tends to make high yields of C1 and C2, increasing both the dry and wet gas rates. 3.3.8

Effects of fresh feed quality

Table 7 shows the most important FCC feed characteristics. The quality of the FCC feed is probably the single most important factor in determining the yields that can be obtained from the FCCU. The structure of the feed molecules is critical not only in defining the reactions that can take place, but also in determining the quality of the FCC products. The following paragraphs discuss the key effects of the key feed properties.

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TABLE 7 FEEDSTOCK QUALITY THE MOST SIGNIFICANT VARIABLE Important feed characteristics: •

API gravity

•

Hydrocarbon type (Aniline PT, K Factor)

•

Boiling range

•

Sulfur, nitrogen

•

Metals

•

Carbon residue

API gravity, hydrocarbon type and boiling range These properties are discussed as a group, because they are inter-related. For a given boiling range feed (for example, 320°C to 540°C), the API gravity will increase as the feed becomes more paraffinic, and will decrease as the feed becomes more aromatic. Also, for a constant feed composition, the API will increase as the feed becomes lighter (lower boiling points) and will decrease as the feed gets heavier. Two key properties indicate how aromatic the feed will be. High values of the K Factor and the Aniline Point indicate high paraffin concentrations, with lower levels of aromatics. Low K Factors and Aniline Points indicate high levels of aromatics. Feeds with K Factors above 12.0 and Aniline Points above 90°C are considered very paraffinic. Feeds with K Factors below 11.7 and Aniline Points below 77°C are considered very aromatic. The more aromatic feeds give lower conversions and lower yields of gasoline, C3 and C4, with higher yields of LCO, slurry oil, coke and dry gas. Gasoline octanes generally increase as the feed becomes more aromatic. Feed sulfur and nitrogen contents The sulfur content of the feed has only minor effects on the conversion and other FCC yields, except that as sulfur increases, the yield of H2S will increase. In addition, the SOx emissions from the regenerator will rise, as will the levels of sulfur in all of the liquid products. This may significantly affect the ability of the refiner to make environmentally acceptable products. This is one reason that the refiner may consider feed hydrotreating, since it will remove up to 99% of the FCC feed sulfur. Nitrogen can significantly reduce FCC conversion. Usually, nitrogen levels are highest in aromatic feeds. These feeds tend to make high octane gasoline, which is high in olefins (as indicated by a high bromine number). High activity catalysts are usually needed to overcome the effects of the high feed nitrogen. 3.3.9

Metals and Carbon residue effects

The major problems for the RFCC unit are the nickel, vanadium and Conradson Carbon Residue. The nickel and vanadium will deposit on the catalyst and will cause undesirable dehydrogenation and coking reactions. In addition, the vanadium will react with the zeolite, destroying the crystal structure and

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causing a large activity loss. Of course, these effects increase as the levels on nickel and vanadium on the catalyst rise. The carbon residue consists of large molecules that are impossible to vaporize at FCC conditions. A high percentage of this material (roughly 80%) just lays on the surface of the catalyst and degrades to coke, blocking the active sites. This adds to delta coke, causing a rise in the regenerator temperature and a drop in the catalyst to oil ratio. The first thing an operator will observe to the FCCU is the rise in regenerator temperature due to the increase in delta coke. Then, if attempts are made to cool the regenerator by removing heat (for example, by lowering the feed temperature), more air will be required, as the coke yields rises. As more the metals levels on the catalyst increase, catalyst activity will decline, dry gas yields will increase, and conversion will drop.

3.4 Uninterruptible Power Supply (UPS) LATER.

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4


CHEMICAL, CATALYST AND UTILITY

4.1 Specifications of catalysts 4.1.1 Catalyst inventory and addition rate • Catalyst inventory: 675 tons • Fresh catalyst addition rate: Feed Mixed Addition rate ton/day (*) 15.2 (*): dry basis.

Bach Ho 5.5

4.1.2 Fresh catalyst selection The fresh catalyst will be specifically designed to maximize middle distillate (LCO) and metal resistance. The target for the MAT activity associated with the corresponding delta coke is given hereafter and linked to the metal concentration to be sustained. Mixed Maxi Gasoline Ni content (ppm) V content (ppm) Equilibrium catalyst MAT activity (wt %) Delta coke (wt %)

68

Mixed Maxi Distillate 3213 6748 55

1.22

0.99

Bach Ho Maxi Gasoline

75 0.94

Bach Ho Maxi Distillate 1776 60 0.91

Two catalyst lines fit appropriately with the operation objectives: ¾ AKZO NOBEL COBRA RMR or CENTURION or ¾ GRACE Davison Z14USY associated with LCM matrix. The final guarantee catalyst will be selected by IFP after evaluation of the best candidates proposed by Vendors. 4.2 Antimony (Nickel passivator)

Used in:

RFCC Feed Section

Type : Antimony content: Injection rate:

NALCO EC9192A or equivalent 23% ratio Sb/Ni in feed: 0.5

Normal consumption:

109 kg/day

Mixed Case

0 kg/day Bach Ho Case Maximum consumption:

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15 kg/h



4.3 Corrosion inhibitor Used in:

Fractionator overhead

Type: Normal consumption:

CHIMEC 1430 60 kg/day

Maximum consumption:

120 kg/day

4.4 Amine antifoaming agent Used in:

Gas recovery Section in LPG/Fuel gas amine absorber

Type: Normal consumption: Maximum consumption:

CHIMEC 8045 10 kg/day (1) 20 kg/day

(1) Antifoaming agent is injected batch wise in either the following tower when foaming is experienced. Once foaming is settled, stop injection to avoid over-dosing of chemical. It should be noted that injection of antifoaming agent is the last resolution. During amine absorber operation, lean amine temperature should be always 10 deg C higher than feed gas to avoid condensation of hydrocarbon inside of the fuel gas absorber -

T-1555 Fuel Gas Absorber

-

T-1556 LPG Amine Absorber.

4.5 Amine (outside battery limit) Type DEA:

20% wt di-ethanolamine

H2S content:

0.022 mole/mole DEA

Lean Amine Flowrate

kg/hr :

Rich Amine Flowrate

kg/hr :

50382 77623 50926 78145

Bach Ho Mixed Crude Bach Ho Mixed Crude

4.6 Phosphate for Steam Generation The following phosphate will be used for steam generation: RFCC HPS and MPS Generation 7.0 kg/day RFCC Waste Heat Boiler 24.0 kg/day Total 31.0 kg/day Note:

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(1) Phosphate injection rate is depended on blow down flow rate and phosphate level in the steam drum or generator. The above rate is based on 1.0 % of blow down from the steam generation system, and marinating 30 wt ppm of phosphate concentration. (2) For LPS steam generation, it is not required to operate blow down operation, and thus phosphate injection is also not required.

4.7 Estimated utilities Refer to the attached utility summary: Spec No. 8474L-015-CN-0003-511

Estimated Utility Consumption Bach Ho MG – Normal

8474L-015-CN-0003-512

Estimated Utility Consumption Bach Ho MD – Normal

8474L-015-CN-0003-513

Estimated Utility Consumption Mixed Crude MG – Normal

8474L-015-CN-0003-514

Estimated Utility Consumption Mixed Crude MD – Normal

8474L-015-CN-0003-521

Estimated Utility Consumption Bach Ho MG – Design

8474L-015-CN-0003-522

Estimated Utility Consumption Bach Ho MD – Design

8474L-015-CN-0003-523

Estimated Utility Consumption Mixed Crude MG – Design

8474L-015-CN-0003-524

Estimated Utility Consumption Mixed Crude MD – Design

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0

Description


5


PREPARATION FOR INITIAL START-UP

5.1 Chronology of operations A typical bar chart sequence of events for the first start-up is attached. No time scale has been given since the completion of these tasks depends on site manpower, local facilities and contractual provisions between the Unit Owner and its Contractors. The following section will discuss the various aspects associated with the pre-commissioning of the facilities in the refinery. The pre-commissioning operations ensure that the unit is safe, operable, and constructed as specified. Each start-up preparation operations shall be performed in unit by unit. In addition to the procedures, the operator of one area (or unit) shall coordinate with the operator of the other area (or unit) to perform the pre-commissioning operation. A systematic program of start-up preparations must be drawn up and carried out to ensure that the startup operation proceeds properly. This is particularly important when the unit has to be brought on-stream together with other units within a limited time. As the construction of the unit nears completion, a large amount of work must begin in order to prepare it for start-up. These pre-commissioning activities have three main purposes:

To ensure, by thorough inspection and testing, that the unit is safe, operable, and constructed as specified; To operate equipment for by flushing, running in, etc., and To acquaint the operators with the unit.

The importance of these activities cannot be overemphasized. No matter how well a unit is designed, if the equipment is not as specified, not properly brought on stream, or not understood by operators, it will not perform as expected. The following activities are major Pre-commissioning activities. However, an exact order of presentation need not be strictly obeyed. Depending on the progress of construction, certain procedures may be required earlier or later that suggested here. A through knowledge of the entire pre-commissioning operation will allow the plant personnel to schedule activities in the most time-saving and labour efficient way. These are the necessary pre-commissioning activities: 1. 2. 3. 4. 5. 6. 7. 8. 9. 10. 11.

Vessel and other Major Equipment Inspection Line Cleaning Servicing and Calibration of Instruments Run-in of Rotary machineries Chemical Cleaning Refractory Drying System Drying Loading of Chemicals, Catalysts, and Other Materials Operational Tightness Test Air Freeing Commissioning of Additional Plant Services

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5.2 Equipment and unit inspection 5.2.1

Equipment inspection

The pieces of equipment to be inspected are the following ones: ¾

Vessels with internals and refractory materials: riser, disengager, stripper, regenerators, withdrawal well, cyclones, catalyst standpipe.

¾

Catalyst hoppers,

¾

Injectors,

¾

Slide valves and plug valve,

¾

Expansion joints.

Equipment is inspected for compliance with Licensor (Axens) specifications and drawings, of the Process book. A typical, but not exhaustive list of items to be checked is given below. The list needs to be adapted according to the specific requirements of the unit as expressed in section 2 of the process book. Vessels ¾

All refractory material should be inspected for proper installation and proper type.

¾

All cyclones and specifically the cyclones diplegs must be inspected to ensure they are free from foreign material. Trickle valves should be inspected for freedom of movement and proper seating.

¾

Air rings and steam rings should be inspected, for proper nozzles size and orientation. All nozzles should be free of refractory or pluggage by debris. Note:

Once the rings are installed and unit construction is finished. Each air and steam ring must be protected from falling debris. Either completely wrap the ring in a protecting material on place removable plugs into each upward directed nozzle.

¾

If installed, all baffles should be inspected for proper installation.

¾

Supports of the air and steam rings should be inspected for proper movement. Wells around air rings supports should be fitted with kaowool or equivalent material to minimize binding that could occur from catalyst packing.

¾

Internal guides on the riser and air lift must be inspected for proper movement.

¾

All distributors (spent catalyst inlet in first regenerator, lift outlet, riser outlet) must be inspected for proper construction and protection against erosion.

¾

All instrumentation, fluidization and aeration taps must be checked for proper orientation and penetration. The nozzles should be free of refractory or other material.

¾

Torch oil nozzles should be inspected for proper orientation and penetration.

¾

Thermowells should be checked for proper location and length.

¾

Catalyst hopper vessels must be inspected, and free of foreign material.

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Injectors Feed, MTC, steam, back flush oil injectors should be inspected for proper orientation and penetration. The annulus around the injectors must be packed with kaowool or equivalent. Note:

The injector Vendor installation procedure must be used, for proper orientation and penetration of the injector using the installation tool (see Vendor inspection book) and for field welding of the flanges on the injectors.

Slide valves/plug valve Slide valves and the plug valve should be inspected for proper calibration movement and operation. The valve should be operable from the primary control instrument on both manual and automatic control, from the field mounted controller and from the hand wheel if so equipped. The valve should be tested for proper operation upon loss of signal (typically fail lock). If the valve is equipped with low differential pressure override control, this function should be verified to be operational. The action of the valve upon emergency trip conditions should be tested. If the flue gas slide valves are equipped with limit stops these should be verified for proper installation. While observing the position of the disks or plug, all slide valves should be calibrated. External etching can be used to mark critical valve positions. The readings for valve travel should be kept for future reference. The plug valve should be calibrated while it is cold and again when the unit is hot during refractory curing (or unit heat-up) due to the thermal growth of the lift line. The closed position for the plug valve will be different between hot and cold condition. These should be marked on the valve and recorded for future reference. Expansion joints Expansion joints should to be inspected for proper installation and freedom of movement. Any shipping supports/stays should be removed and limit rods should be properly adjusted. Depending upon specific application, the expansion joint may require areas to be packed with Kaowool or equivalent. Direct Fired Air Preheater ¾ ¾ ¾ ¾ ¾ ¾ ¾

Check that targets, air dampers, and lining are sound Check the bottom of the heater for trash. Dismantle, clean, and air-blow all burners. Check the relative orientation of the ignitor, pilot burner, and main burner per installation drawings. Check the freedom of movement of air dampers, and repack glands, if necessary. Remove and clean the sight glasses. Check that the spark plug is dry and that a good spark is obtained.

Reactor Regenerator Structure ¾ ¾ ¾

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Check that all the catalyst lines and expansion joints are free to move in all directions. Be sure shipping stops are removed from the expansion joints. Check that the platforms and other structures will not interfere with the free expansion of the equipment in any direction. Check that instrument piping, electrical conduit, hydraulic piping, and other equipment is in no danger of binding.

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5.2.2 Unit inspection It shall take place prior to the mechanical completion of the unit. A. PID's check This check is primarily for piping, instrument and fittings. Location of instruments, valves, fittings (including drip rings, special shut off valves, tie-ins, etc.). A check is made against the latest revision of the P&ID to ensure plant completion and the correct installation of all items of equipment. Particular attention should be paid to the following: a) b)

The correct routing of pipework. The installation of all valves with special attention paid to the direction of flow for control valves (Note), globe and non-return valves. c) All instrumentation is installed. (Note) d) Safety valves are correctly installed. (Note) e) Pump cooling water, lube and seal systems are complete and correctly installed. f) Vendor's packages should be thoroughly checked against P&ID and where possible, items of equipment run in the presence of the Vendor's representative. g) The installation of fire fighting equipment and personnel safety showers. Note: Safety valves and instrumentation such as orifice plate, control valves, etc. are installed after line flushing is completed. B.

Operability check

This consists of an assessment of the practicability of carrying out all the operations required for commissioning, start-up and shutdown. It focuses mainly on access to instruments and valves (including vents, drains), to manholes, to spectacle blinds… and to parts of equipment that need to be dismantled. The presence of the required start-up and pressurization lines is checked as well as the impact of safety switches on start-up operations. Ensure that all valves using for start-up, shut-down, emergency are easily accessible. C. Instrument check

a) Prior to unit start-up all instruments (flow, level, pressure, temperature) must have been checked with regard to: –

Proper tagging,

–

Proper location in the process,

–

Correctness of assembly,

–

Operating range consistent with the operating conditions prevailing at the location,

–

Calibration,

–

Flow orifice coefficients must be checked and recorded,

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–

b)


Level instruments will be calibrated using the most likely liquid density, and proper installation of Dp taps for catalyst level.

– Differential pressure instrument, check Dp cells for proper installation and connections. Alarm checking

Make sure that the release mechanism on the unit actuates the corresponding light or audible alarm in the control room. c) Control Valves The control valves are removed during washing operations. They will be checked for cleanness of the seats and free movement of the plug or ball. Check the valves motion and their response to the controller signal. When all the single instruments have been individually checked, when all their addresses have been verified in the DCS, then the loop checking can take place for each loop or group of control loops. Each TRIP either linked to the process or to equipment, shall also be individually tested. Hydraulic system for assisted valves (slide, valves, plug valve, assisted check valves) must be carefully checked and tested. d) Safety devices check The process includes quite a few specific control sequences called (UC) multiple variable control, Interlocks (I) and emergency shutdown systems (ES). The tests of these devices must be witnessed by the Licensor (Axens) representative and remedial works be carried out until the operation is fully satisfactory. These devices are designed either to protect the catalyst against misoperation (too high temperature) or to protect equipment (compressor against liquid carry over) or to fulfil certain actions related to the operation of the catalyst regeneration or catalyst circulation. The interlocks are independent hardwired systems which in the case of occurrence of (a) defined potentially harmful event(s) initialize various actions (valve closure, power cut off, etc...) to alleviate the risk. An interlock operates through a solenoid valve and the solenoid valve must be reset either locally or in the control room in accordance with the PID. The control sequences are a short series of simple actions in sequence which are programmed into the DCS and are designed to ensure a trouble free, automatic and safe operation of the catalyst circulation and regeneration. The emergency shutdown systems are called logics, separated from the DCS, perform automatic emergency shutdown actions upon the occurrence of potentially harmful situations. The principles of these checks are as follows: a simulated default signal from the primary sensor will be fed into the system and the resulting signal output to valves or equipment will be checked. Whenever possible, the end result of the signal output (i. e., actual valve closure or machine shutdown) will be observed. Ultimately real tests require equipment to be operating and shall be continued during unit dry out or catalyst circulation. Throughout this exercise, the actual physical position of the valves (or status of machines) will be checked against the indications shown in the control room. The check of the motorized valves is part of the same task. It includes: ♦ A site test of the opening/closing of the valve upon the input signal. ♦ A control room check of the reported indication and a check of the satisfactory actuation from the control room.

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5.2.3 Line Flushing Outline All piping should be thoroughly cleaned of debris and scale. Generally, liquid handling lines are flushed with water and thoroughly drained. Where practical, it is suggested that clean water be used for flushing vessels. Care must be taken not to flush debris into equipment. Water flushed lines which do not drain freely should be blown clear with air. Gas handling lines may be water flushed or air blown. Water should be drained from the gas lines upon completion of flushing. The restriction orifice plates must not be installed prior to cleaning of lines. Steam and air utility piping may be cleaned by blowing with their normal media. Instrument air lines should be thoroughly blown with clean dry air. Utility water lines may be flushed with normal media. Upon completion of line flushing of any system, carefully check that all temporary breaks are reconnected, control valves reinstalled, and pump alignments are normal. Thorough cleaning prior to pump run-in minimizes screen cleaning requirements. The following is a guide for flushing: (1) Orifice plates must not be installed prior to flushing. (2) Prior to flushing, control valves and in-line instruments should be removed. (3) Instrument lines should be closed off or disconnected prior to flushing. (4) Remove burners prior to flushing burner fuel lines. (5) Flush pump suction and discharge piping while disconnected. Do not introduce any fluid into pump casing before cleaning the pump suctions. (6) Supply steam lines to ejectors should be disconnected while being cleaned. (7) Flush through open end lines. Do not restrict flow in principle. (8) Flush through all drains and vents. (9) Where possible, flush downward or horizontally. (10)Flush or blow the main header from source-to-end, each lateral header from the main-to-end, and each branch line from the lateral header-to-end. (11)Always flush through bypasses, where provided, to an open end before flushing through equipment. (12)For steam systems, blow out well through dirt leg drains and steam trap bypasses before placing the traps in service. (13)After placing the steam traps in service, check whether the traps operate properly. (14)After flushing operation, check that all orifice plates are installed and positioned correctly as per list. (15)When necessary vessels or drums are used as water reservoirs for flushing, check vessels for water-filled design. Moreover, a water-filled system must not be drained without adequate venting to avoid a vacuum condition and probable collapse of equipment not designed for a vacuum. (16)Isolation valves of the Water coalescer, Slurry Separator must be closed to avoid sludge entering to internal.

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5.2.4 Rotating Equipment Run-in Proper installation and operation are required for all rotary machines especially. Pumps and drivers should receive careful handling during initial run-in. The initial run-in of pumps is generally executed by circulating water through the related equipment. Temporary fine mesh strainers are installed in the suctions of pumps. When pumping water with centrifugal pumps intended for hydrocarbon service, the suction valve must be wide open and the discharge throttled properly to avoid overloading the motor. During run-in of pumps, operators must be careful to avoid any cavitation which may occur due to large amounts of debris in the strainer, excessive internal slippage generating excessive heat, and/or loss of suction pressure, etc. Also, the bearing must be checked frequently for signs of overheating and vibration. The following is a check list for pumps: (1) Check that overall installation is complete. (2) Verify that pumps and drivers have been aligned for cold operation. There must be no undue strain imposed on pumps or drivers by the piping. (3) Check cooling water piping. Verify that water piping is connected, where required, to bearing jackets, pedestals, stuffing boxes, etc. (4) Check steam piping. Verify that steam piping, where required, is complete. In addition to steam for drivers, in some hot services steam may be used for cooling shaft seal oil. (5) Check seal or gland oil piping. Conventional packed pumps in hot service are generally furnished with gland oil - verify that this installation is correct and complete. When a pump is furnished with mechanical seals, verify that all of the components of the orifices and coolers, when required, have been correctly installed and are clean. (6) Verify that packing or seals are installed. (7) Check that temporary fine mesh strainers in suction piping, where required, have been installed. (8) Verify that bearing and shafts have been cleaned prior to final lubrication. (9) Check that pumps and drivers are lubricated according to the lubrication instructions. (10)Check rotation of electric motor drivers uncoupled from the pump. Run-in uncoupled, verifying operability. (11)Run-in, uncoupled from pump, drivers other than electric motors. During run-in of driver, check over-speed trip, bearings, controls, vibration, etc., to confirm operability. Abnormal conditions must be corrected before coupling to the pump. (12)After coupling driver and pump, check necessary items as mentioned above. (13)Ensure good level of pump suction. Fully open valves installed on pump suction, and vent out from high point vent and/or pump casing vent. Start pump, suitably throttle delivery valves, and make sure of circulation route. (14)As for the spare pumps, the run-in test should be completed in the same manner as described above, and they should be ready for use. (15)Pumps normally handle a material of lighter density than the water circulated during initial run-in. The pump driver is sized for the normal pumping fluid. Consequently, when pumping water, the electric motors are easily overloaded.

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To avoid overloading the motor driving a centrifugal pump, the flow must be limited by throttling the pump discharge valve. 5.3 Preliminary operations 5.3.1 Definitions The following definitions are used throughout this chapter: • Precommissioning is the period when conformity, non-operating checks and verifications

that the installation conforms to plans, specifications, and drawings, are carried out. It includes the calibration of instruments, cold-alignment checks, testing of safety devices, etc. This phase leads to the mechanical completion or ready for commissioning. • Commissioning is the period when the dynamic verification of the functioning equipment,

the simulation of control loops and safety systems, and the operational tests are carried out. Commissioning includes also a variety of activities such as cleaning and drying-out of piping systems, tightness tests, loading of chemicals, dessicants and catalysts, running-in of pumps, turbines, and compressors, with inert fluid (water, nitrogen). These operations are conducted before feed introduction into the plant and end up at a point in time called ready for start-up meaning that the plant is ready to be operated for the first time. Well planned and carefully executed precommissioning and commissioning activities generally result in a quick and successful start-up. 5.3.2 Utility systems commissioning Here is a non restrictive list of these systems and the status under which they are expected to be. Some of the systems may not be applicable, depending on the unit. • In service means the system is operational: main header and users feeder lined up. Each

individual user only is isolated either by block valves, if available, or blinds. • Ready to use means the system (main header, individual users feeder) has been cleaned, dried

if required, leak and pressure tested and left under the appropriate atmosphere. The main header has been subsequently shut off with block valves and blinds. Instrument air : In service Utility air/Plant Air : In service Cooling water system : In service Individual user isolated, drain open Sea Water System : In service Individual user isolated Nitrogen system : In service Checked for proper oxygen content Steam : In service Drains and traps have been checked Condensate water : In service Boiler Feed Water : In service, ready to use Potable water : In service Fire water : In service Flare system : Ready to use The flare main header of the unit is kept open to atmosphere and isolated with blind from the flare collector at the battery limit Hydrocarbon closed drain : Ready to use

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Amine Drain : Ready to use Fuel gas for COB : Ready to use Fuel oil for COB : Ready to use Start-up fuel gas and pilot gas for COB: Ready to use for H-1501 / H-1502 Fuel gas from LPG vaporizer, directly. Propane or LPG gas should be used for start-up operation. Electrical equipment : Ready to use All wiring, junction boxes, breakers, switches have been checked for correctness and compliance with specifications. Electrical motors have been run in for 4 hours (disconnected from the driven machine). 5.3.3 Unit commissioning The following operations related to process unit equipment are completed in accordance with the relevant precommissioning procedures and the equipment manufacturers instructions. • Hydrostatic test of piping, • Equipment washing, • Rotating machine alignment, • Pump running in, • Air blowers running and checking of surge curve. • Refractory or ceramics lined lines will not be cleaned with water. Hand cleaning will be made,

and where it is impossible a vacuum blower will be used. • It is important to clean properly the lines to instrument nozzles and aeration / fluidization

nozzles as flow orifices installed on these lines are small and can plug easily. • Checking of each nozzle must be done and witnessed by an IFP representative. • Before starting the catalyst hoppers loading, all catalyst lines (loading, unloading, make-up, draw-off lines) must be checked for cleanliness. It consists of checking free air circulation along each whole line. It is worth remembering that water wash must be avoided for equipment subject to a forthcoming drying. 5.3.4 Initial leak tests The general instructions hereunder shall only be used as a reminder. The initial leak tests can be performed using air. The test pressure will be the air system pressure or the unit (or section of unit) design pressure, whichever is the lower. The unit is isolated with blinds from adjacent sections containing hydrocarbons (liquid or gaseous), and from utilities systems where pressure is lower than air pressure. The pressure rise must be checked on several manometers and possibly checked on a pressure recorder. Leaks must be carefully located and tightened. Their location must be recorded. The leak test is satisfactory when the pressure decrease is lower than 0.05 kg/cm2/hour over a period of 4 consecutive hours. The air used for leak tests should be purged out of the unit using low points drains to remove free water, if any. For the purpose of leak tests the unit will be divided into sections of approximately the same design pressure, as defined hereunder. Air will be injected at different locations depending upon check valves.

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The initial leak tests apply for the feed preparation section: the feed surge drum and its associated piping from the unit battery limit and to the injectors system. The feed pump suction must be isolated with a blind. The leak tests of the disengager / stripper and of the regenerators are performed during the air blower start-up and refractory dry-out by visual or sound detection. For the catalyst handling section the tests can be followed by a vacuum test at maximum vacuum. Loss of vacuum shall not exceed 25 mm Hg/hour over a period of 4 consecutive hours (Catalyst hoppers and its associated piping).

5.3.5

Catalyst hoppers loading

5.3.5.1 Preliminary checking Before the catalyst is loaded to the hoppers, all catalyst lines between hoppers and regenerators should be inspected. The catalyst lines and vessels must be free of foreign material, especially water or oil. The air lines should be checked by blowing all lines until they are clear and dry. Any water in the catalyst lines and hoppers will form a sticky mud which makes normal handling impossible, and this wet catalyst is extremely difficult to remove. Prolonged blowing with air or cleanout by hand will work, but the best method is prevention by keeping the system dry. If needed, the hoppers will be brushed and vacuum cleaned before catalyst loading start. 5.3.5.2 Recommendations Catalyst can be dispatched to the customer by several means of transportation. Delivery in bulk trucks is usually the most rapid and economic way to get the catalyst to refineries. Trucks are equipped with a tank tilting device, a compressor and flexible discharge lines with several coupling systems. In few hours all the catalyst is transferred from the trucks into the fresh catalyst hopper. Usually the vacuum of the catalyst hopper is sufficient to transfer the catalyst into the hopper. In case the transport line is too long, extra transport air may be required. Fresh catalyst is loaded into the fresh catalyst hopper and Equilibrium catalyst in the Auxiliary catalyst hopper using either the truck compressor or the steam ejector. To dip catalyst hopper in order to estimate quantity of catalyst transferred, it is recommended to aerate the hopper for a period of two hours and to settle the catalyst for one hour before to attempt any accurate measurement of the catalyst level. It is also recommended to leave the catalyst in the hoppers under a constant flow of instrument air sweeping in order to avoid moisture absorption in the catalyst.

5.4 First start-up 5.4.1 General The following describes the very first start-up of the unit (reaction and regeneration section). Any subsequent start-up of the same unit will very likely not include all the following steps but part of them

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only, depending upon the status of the unit after the shutdown. For instance the refractory dry out procedure needs not be performed again, except in the case major turnaround. Reference is made to other sections of the facility as required; however, the start-up of the downstream and associated equipment is not covered in this guideline. This guideline assumes the unit is in the cold, open condition, as would exist after construction or a major turnaround. It presumes that the unit has been thoroughly inspected by refinery personnel, that the safety equipment is available and operational, and that all precommissioning activities have been completed. The following procedure is intended as a general guideline only. It is written without reference to unforeseen difficulties which often occur during start-up. The step by step guide is not intended to replace plant rules or established plant operating procedures and requires the safe and intelligent judgement of experienced operating personnel. 5.4.2

Status of the unit

The status of the unit prior to its initial start-up is as follows: ♦ Tightness test and nitrogen purges have been completed (O2 < 0.2% volume) on the feed preparation section. ♦ Free water trapped has been drained at low points. ♦ All necessary utilities are in service: blinds on the headers have been swing open and valves opened on all users. ♦ All instrumentation has been checked and is in service. ♦ The emergency shutdown systems have been tested and are ready for operation. ♦ On disengager and first regenerator cyclones, set blocks to open the trickle valves on the diplegs (if it not planned to re-enter the vessel use a material that will incinerate or melt at the temperatures expected). ♦ Verify that the disengager and the regenerators man way are closed. ♦ Verify isolation and blinding of the fuel gas system. 5.4.3

Chronology of start-up operation

The chronology of the various start-up tasks is shown on the typical procedures. The durations considered are indicative and are only those required to perform the tasks; no time gap between two consecutive tasks has been taken into account. The chronology of the start-up is as follows: ♦ Blower start-up and checks. ♦ Refractory dry-out (first start-up only). ♦ Catalyst hoppers loading (first start-up only). ♦ Refractory inspection (first start-up only). ♦ Unit warm-up. ♦ Main fractionator MOV open ♦ Catalyst loading.

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♦ Establishing catalyst circulation. ♦ Starting feed to the riser. ♦ Adjustment of operating conditions. Remarks: It is recommended to inspect the refractory after the dry-out operation, especially for the first start-up. The CO Boiler, waste heat boiler (or flue gas cooler), and flue gas lines are generally dried during the reaction / regeneration section dry-out in connection with the overall start-up procedure. 5.4.4

Blower start-up and checks a) Before starting the air blower, purges on instrument, aeration and conveying lines must be put into operation, in order to avoid plugging of these small lines with dust or other material. On the reaction section side (riser, disengager/stripper, spent catalyst line) the purges must be connected to the plant air header. Plant air is also injected by temporary lines into steam rings lines (bottom ring, main, hopper, lower, anticoking rings) and stabilization, atomization and torch oil nozzles to avoid nozzles to be plugged. b) Activate blower lube/seal oil systems according to manufacturer’s procedure. c) Place flue gas slide valves, plug valve, regenerated slide valve and spent catalyst slide valve on manual control and put the purges valves in service according to manufacturer’s procedure. Make sure boiler feed water system is in operation. Make sure bypass emergency systems ES1 and ES2. d) Open flue gas slide valves and plug valve at 100%, open catalyst slide valves at 60%. Close the control valve on air lift to plug valve. e) The disengager vapor line blind plate upstream of MOV-001 at the main fractionator feed line should be in place, isolating the fractionator from the disengager. Be sure the vent is closed at this time. Note that this blind plate should be removed and replace to Ring Spacer, after drying out operation of the reactor and regenerator. Subsequent operation will be carried out by opening of MOV-001. f) Start the air blower as per its detailed start-up procedure. Monitor blower operation closely during first day of operation. g) Set air blower flow to maintain a minimum flow rate 10% above surge point at all times and check surge point of the machine. Stabilize and check blower for vibrations and temperatures. h) Increase the air flow control at normal operation to the first regenerator rings, and place on automatic. i) Increase the air flow control at normal operation to the second regenerator and place on automatic. j) Slowly close second regenerator flue gas slide valve on manual until it is only about 20 % opened by PdIC. Record positions on valve stems (on D.C.S. and locally). k) Slowly throttle first regenerator flue gas slide valve on manual to raise the pressure in the regenerators by 0.200 kg/cm2 increments to about 1.0 kg/cm2g. Check the flanges and manways on the unit for leaks. Adjust opening of the second regenerator flue gas slide valve

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to control smoothly regenerator pressures. Check that the reaction/regeneration section temperature is less than 100°C. Hold for 10 hours minimum. Then increase the regenerators pressure by 0.4 kg/cm2 increments to the maximum blower discharge pressure. Make a second leak test. Then reduce regenerators pressure to 1.0 kg/cm2g. l) Record the first regenerator flue gas slide valve openings when 1.0 kg/cm2g is reached. Then make an air blower check at design capacity; stabilize and check for vibrations and temperatures. Then resume the normal operating flow rate to first regenerator and to second regenerator. m) Set the first regenerator pressure controller (PIC-146) to hold 1.0 kg/cm2 g and place on automatic. n) Set PdIC-172 to hold a 0.0 kg/cm2 differential pressure between the two regenerators and place on automatic. o) Open the regenerated and spent catalyst slide valves 30 % to 40 % on manual to allow air to flow from the regenerators into the disengager stripper vessel. p) Slowly open the vent on the disengager vapor line at the main column inlet to allow some air flow through the disengager stripper vessel. Do not allow both flue gas valves to close below 20%. Adjust air flow rates to correct the situation. Note:

The flue gas treatment section is normally ready to be placed in service, or bypass lines can be used to the stack.

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5.4.5


Dry-out of refractory

Prior to start-up, the refractory must be cured. This can be accomplished utilizing the main air blower, air heaters, and installed instrumentation. Depending upon the configuration, temporary vents / mufflers may be required in the flue gas duct. During refractory dry-out the steam side of the waste heat boiler, CO Boiler and Economizer should be boiled out in accordance with vendor’s procedure. The actual procedure used, depending on the refractory type and thickness, should be developed between the Licensor, the refractory Vendor, the Contractor, the refractory Installer, and the operating Company. Temperature steps and times indicated in the dry-out procedure should be checked, for the initial start-up and for start-up after a major turnaround. A typical procedure may require five days and is listed below. During the dry-out, adjustments to slide valve position might be needed to adjust the warming rates of each vessel. As air lift will have thermal expansion during the warm-up it will have a tendency to push on the plug valve and severe damages to plug valve or air lift can result if the plug valve is not fully open. During dry-out, the plug valve must remain fully open. The catalyst loading and unloading lines will also be dried during this operation. Open the block valves on each catalyst transfer line and the vent on the catalyst hoppers. Have the catalyst feeders by-passed. Keep flapper valves of cyclones diplegs blocked open during the dry-out in order to drain water. For dilatation reasons between the disengager/stripper and the regenerators it is necessary to make sure that the temperature difference between these vessels does not exceed the design of the expansion joint (as indicated in the specification of the expansion joint, maximum differential temperature is 350°C). Preparation of Dry-out Operation -

COB/WHB to be dry-out prior for reactor and regenerator dryout operation.

-

Install blind plate at upstream of MOV-001 at feed line of the main fractionator. Note that this blind plate should be removed after dry-out operation.

-

Use N2 purge to D-1509, if N2 is available at this time.

-

If N2 is not available use Plant Air for purge gas. For line-up Plant Air to fuel gas purge line of the instrument of the reactor. Use 3”-PA-157230 in P&ID 015-PID-0021-138. Close isolation valve of fuel gas side. Note that 3”-PA-157233 connecting to N2 line shall not be used unless PSV-007A outlet to route atmosphere, by temporary piping avoiding Plant Air routing to flare.

-

Isolate PSV-002 at the fractionator feed line by closing inlet valve.

-

Open isolation valves on start-up line of the reactor outlet to the flue gas line (24”-PG150037 on P&ID 015-PID-0021-123).

-

Start-up fuel gas (Propane or LPG) is ready to use from the fuel gas LPG vaporizer.

-

Prepare soda boiling of the BFW system in WHB.

-

Line-up Air Blower discharge air to MPS header (upstream of PV-365) using 6”-A-150072 on P&ID 015-PID-132/138, so that steam line to e purged by Air Blower discharge air. Isolate MPS supply valves.

-

All Injection Nozzles are not removed during dry-out operation.

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Proceed as follows: a)

Plant air purges on instrument, aeration conveying lines, steam rings lines (riser bottom, fluffing, main, upper, pre-stripping, anticoking rings) and stabilization, atomization, torch oil nozzles must be in operation, using temporary lines.

b)

Warm up with blower discharge temperature hold conditions until vessels heat to the blower discharge temperature. Open drain valves at low points, mainly at the bottom of the riser.

c)

Light the air heater pilots according to air heaters Vendor’s start-up procedure. Allow time for the air heaters refractory drying. Consult with air heaters Vendor.

d)

Hold around 120°C to 140°C for 24 hours in the regenerators dense bed at minimum stable pilot firing. During this period of time, heat up the disengager / stripper by alternatively opening and closing spent catalyst and regenerated catalyst slide valves at least once every hour. Check that the withdrawal well and catalyst standpipes warm up evenly. Check the operation of slides valves manually and automatically.

e)

Light the air heaters burner, activate UX-003(ES3) and UX-004(ES4) and rise the temperature 30°C/h at air heater outlet to obtain around 340°C in the regenerators. Continue to heat up disengager / stripper as in “d” of the above. Check thermal expansion of lines and equipment and watch free movement of small lines. Monitor expansion joints and pipe supports.

f)

Hold 340°C for 24 hours in the regenerators. During this period of time proceed to the hot bolting of flanges. Observe piping, supports, and spring hangers during the entire heat-up period to ensure free line movement without binding or deformation. Closely inspect the equipment for leaks while the unit is relatively cold. Any leaks found should be stopped before further heat-up.

g)

Close the block valves on each catalyst transfer line and keep the system dry before the catalyst is loaded to the hoppers.

h)

Raise air heater temperature at 30°C/h to obtain the maximum temperatures: – Adjust catalyst slide valves position and disengager vent line on transfer line to ensure flow of air through all vessels. At least once per hour the slide valve and plug valve positions should be moved to check for binding. – Air heaters outlet

:

maxi

760°C

– Regenerators

:

about 650°C (evenly distributed)

– Disengager

:

mini maxi

480°C 540°C

Hold for 24 hours and hot bolt again. Check skin temperatures. Contact thermometers can be used to ensure heat up of the spent and regenerated catalyst stand pipes. Due to air heaters limitations, it may be necessary to fit the air flow rate to obtain the desired temperature. Note 1:

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Note 2:


In case of a restart, which means with coke deposited on the refractory of the riser / disengager / stripper wall, keep disengager and riser temperature under 340°C to avoid to start coke burning.

When this is completed, cool down at 60°C/h by reducing firing in air heaters gradually. Shut-off air heaters, blind fuel gas and cool with blower discharge air. After Dry-out of the refractory, the line-up to revert to the normal operation. -

Remove blind plate and replace to Ring Spacer at upstream of MOV-001 on feed line of the main fractionator. Note that subsequent isolation operation between the Reactor and Main Fractionator should be made by open / close of MOV-001. Note: During drying out of refractory, blind plate should be inserted upstream of MOV001 for secure isolation between Reactor and Fractionator. This blind plate is only used during refractory drying operation.

-

Remove Plant Air connection for line-up to fuel gas purge line of the instrument of the reactor. Used 3”-PA-157230 in P&ID 015-PID-0021-138. Open isolation valve of fuel gas side.

-

Open isolation valve of PSV-002 at the fractionator feed line, and ready to use during heating-up operation.

-

Close isolation valves on start-up line of the reactor outlet to the flue gas line (24”-PG150037 on P&ID 015-PID-0021-123).

-

Remove line-up Air Blower discharge air to MPS header (upstream of PV-365) using 6”-A150072 on P&ID 015-PID-132/138, so that MPS steam line is ready to use.

5.4.6

Refractory inspection

Open and inspect the vessels and internals of reaction regeneration section and flue gas treatment section. Repair refractory where found necessary. Plant air injection should be stopped where necessay, because this operation is dangerious for personels inside of vessel. Make sure that plant air for all instruments, aeration coveying lines and steam rings should be re-injected after completion of refractory inspection (to be confirmed nobody is in the vessel inside, when plant air valves are opened).

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5.4.7


Drying out and Chemical Boiling-out of CO Boiler/Waste Heat Boiler Dryout of the COB/WHB refractory should be carried out according to the manufacturer's instructions. The source of heat for the dryout of the COB/WHB will be the COB combustion burner. Soda boiling for removal of oil and scale from the steam generation sections will be also simultaneously executed. 1. 2.

3.

4. 5. 6.

Drying out of COB and WHB must be carried out before refractory dry-out of Reactor and Regenerator. Ensure the isolation dampers at COB and WHB inlet are closed. Open the block and globe valves in the vent line on the super-heated steam line located at the WHB outlet. Unblock the steam line battery limit block valve. Open the boiler feed water flow control valve, inventory the WHB water circuit, and establish a level in the steam disengaging drum. Line up boiler feed water to the steam drum. Control the makeup feed water flow manually until steady steam generation begins. When an increasing flow of steam appears from the vent line, raise the steam pressure by gradually closing the venting globe valve. The reason for venting steam is to maintain a flow through the tubes, and to remove air from the system. When the superheater outlet pressure increases the normal pressure level, close the vent line valves and put steam into its normal header. Commission the boiler feed water flow to the desuperheater using the desuperheater outlet temperature controller. Prepare the chemical injection systems for use Commission the continuous and intermittent blowdown systems.

Reference shall be made to the manufacturer's instructions for detailed precommissioning procedures. 5.4.8

Soda Boiling of WHB BFW Circuit During Refractory drying out operation, chemical cleaning of WHB BFW circuit shall be also conducted. For detail procedure, see commissioning procedure

5.4.9

Soda Boiling of Main Column Bottoms Generator Prior to cold/ hot circulation on main column section, Soda Boiling of Main Column Bottoms Steam Generator shall be conducted. For detail procedure, see commissioning procedure.

5.4.10 Degreasing of Amine Circuit In order to remove oil and/or grease from lines or equipment internal surface to prevent foaming trouble, degreasing operation using alkaline is applied for Amine circulation circuit. Details including the scope of degreasing operation procedure.

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6


INITIAL AND NORMAL START-UP

6.1 Start-up Summary 6.1.1 Reactor and Regeneration Section The chronology of the various start-up tasks is as follows • Line-up Flue Gas Ducting • Start Electric Precipitator “Pre Start Mode” for warm-up • Commission COB/WHB with “Fresh Air Operation”, and start HP steam generation • Air Blower start-up and checks, • Reactor & Regenerator warm-up and heating up by air heaters • Main Fractionator inlet open MOV-001 • Catalyst loading to Regenerator • Establishing catalyst circulation, • Starting feed to the reactor riser, • Adjustment of operating conditions. 1. 2. 3. 4. 5. 6.

7. 8. 9. 10. 11. 12. 13.

Before start-up of the blower check that all airlines are free of catalyst upstream of the assisted check valves. Ensure that the check valves CV-1501, CV-1502, CV-1503, CV-1504 are in closed position. Start purges on instrumentation, aeration and conveying lines. Connect plant air purges to the riser, disengager /stripper and spent catalyst lines. Activate the Air Blower lube and seal oil systems according to the VENDOR’s operating procedures. Place the flue gas slide valves, plug valve, regenerated catalyst slide valve and spent catalyst slide valve on manual control. Put the purge valves in service. Put BFW system in operation in COB/WHB and bypass Emergency systems UX-001(ES1) and UX002(ES2). Confirm line-up of flue gas ducting and isolation dampers of Economizer, Electric Precipitator, COB/WHB. Start Electric Precipitator with “Pre-Start” mode and heating and warming up of Ash handling section of Electric Precipitator, as per Vendor’s procedure. Start firing COB package as fresh air operation, as per COB/WHB package operation procedure. Open the flue gas slide valves and plug valves at 100%, open the catalyst slide valves at 60%. Close the control valve on the airlift to the plug valve. Start the Air Blower as per its detailed start-up procedure. Set the air flow and speed of Air Blower to maintain a flow rate 10% above the surge point. Increase the air flow to the First Regenerator rings to the normal operating flow and place it on automatic control. Increase the air flow to the Second Regenerator to the normal operating flow and place it on automatic control. Commission of purge blower air to BV-1501AB and BV-1502AB, if not opened. Warm up the reaction/ regeneration section as follows. •

Warm the UNIT with Air Blower discharge temperature for two hours prior to lighting the Air Heaters. • Light the Air Heaters according to VENDOR’s procedures and maintain at minimum firing for two hours. 14. Heat up the Regenerators at a rate of 60 °C/ hr to 340 °C and start to heat up the Disengager/Stripper. Hold at 340 °C for one hour.

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15. Increase the Air Heaters outlet temperatures at a rate of 60 - 100 °C per hour up to their maximum outlet temperature. However do not exceed 760 °C at the outlets of the Air Heaters. 16. At least every hour during warm-up, pinch and open the spent and regenerated catalyst slide valves and check that the riser and the catalyst standpipes are heating up evenly. 17. Check for leaks and watch closely all the spring hangers and expansion joints. 18. Heat both Regenerators up to 650 °C as measured in the dilute phases and heat the Disengager/Stripper up to 340 °C. Hold at these temperatures for a minimum of two hours. For initial start-up, it is recommended to hold these temperature for four (4) hours minimum to avoid catalyst plugging in the cyclone leg, due to high potential containing moisture in E-catalyst while transporting from outside of Refinery. 19. The instrument purges, aeration and conveying lines to the Disengager section should be switched from air to nitrogen. All steam rings and stabilization, atomisation nozzles should be switched from air to steam. 20. When the UNIT heat up is stable prepare to open MOV-001 at inlet of the main Fractionator in coordination with the RFCC Gas Plant operation. (Note that inlet blind upstream of MOV-001 is already removed and replaced to the ring spacer after refractory drying out operation). 21. The hot oil circulation and dry-out of the Main Fractionator should be complete. 22. Reduce the Main Fractionator bottom level to minimum and stop the hot oil circulation. 23. Close the spent and regenerated catalyst slide valves. 24. Open the Disengager vent line and drain upstream of MOV-001. 25. Reduce the steam flow to a minimum at the Main Fractionator, Stripper and riser. Allow both sides of MOV-001 to depressurise. 26. With the steam still going to the Disengager/Stripper and to the Main Fractionator, open MOV-001. 27. After MOV-001 fully open, slowly close the Disengager vent line and re-establish stripping steam and riser steam flows at the normal operating rates. 28. Commission purge HPS to MOV-001 after MOV-001 fully opened. Refer to Vendor’s operation manual of MOV-001 for more detail. Caustion: Do NOT open pruge HPS under MOV-001 operation (both moving to open and close). 29. The Main Fractionator is pressurised with fuel gas or nitrogen. 30. Set the Disengager pressure to approximately 0.1 kg/cm2 higher than the First Regenerator pressure to avoid air flow into the Main Fractionator until catalyst loading is started. 31. Equilibrium catalyst should now be loaded from the Spent Catalyst Hopper or Auxiliary Catalyst Hopper to the First Regenerator. 32. Close the catalyst slide valves and plug valve. 33. Set the First Regenerator pressure to 1.1 kg/cm2g and the Second Regenerator pressure to 1.0 kg/cm2g. 34. Reduce the combustion air flows to 30 - 40% of normal flow until the diplegs of the Regenerator cyclones are sealed. 35. Start the lift air at 50 % of normal flow. 36. Record the initial catalyst level in the hopper, before catalyst loading. Confirm E-catalyst inventory in the hopper before catalyst loading. 37. Start loading the catalyst by slowly opening the gate valve at the Hopper bottom. Adjust catalyst flow by the gate valve opening and by lift air flow rate. 38. Load catalyst into the First Regenerator while maintaining the dense phase above 370 °C. 39. When the level in the First Regenerator is at least 500 mm above the torch oil nozzles and the dense phase temperature is at least 370 °C, torch oil may be started at a minimum rate. 40. Adjust torch oil flow to achieve 650 °C in the dense phase. 41. Continue loading the catalyst to the First Regenerator until the maximum bed level is achieved.

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42. Increase the differential pressure between the First and Second Regenerators to 0.7 kg/cm2 by PDIC. Adjust air flow rate to the second regenerator to achieve 0.3-0.4 m/sec at dense phase to minimize catalyst loss. Slowly open the plug valve and begin to transfer the catalyst to the Second Regenerator. 43. When the level in the Second Regenerator is at least 500 mm above the torch oil nozzles, the torch oil may be started if the dense phase temperature in the Second Regenerator is above 370 °C. 44. Adjust the torch oil flow to maintain 650 °C in the dense phase of the second regenerator. 45. Record hopper level, time to time to confirm how many catalyst are loaded into the regenerators. Continue loading catalyst and transferring from the First to the Second Regenerator until all the catalyst inventory has been loaded. 46. Hold the regenerator levels and dense phase temperatures near 650 °C while preparing for catalyst circulation. 47. Before establishing the catalyst circulation, achieve the following process conditions • Disengager at 300 °C, under steam, pressure controlled at the Main Fractionator by the Wet Gas Compressor. • First Regenerator at 650 °C, 1.1 kg/cm2g, air rings flow rate at 50%. • Second Regenerator at 650 °C, 0.4 kg/cm2g, air rings flow rate at 50%. 48. Increase air lift flow to the normal flow rate. 49. Set the PDIC on the spent and regenerated slide valve at 0.1 kg/cm2 and place on automatic control. 50. Reduce stripping steam flow rates to minimum, set the stabilisation and dispersion bottom wye steam to normal flow rate. 51. Slowly open the regenerated slide valve on manual to 20% open. Monitor and maintain the regenerated slide valve differential pressure to above 0.2 kg/cm2. 52. Continue batch-wise circulation and transfer until the Stripper temperature is above 370 °C. When it reaches 480 °C, increase the Stripper level to the normal operating level. 53. Adjust the regenerated and spent catalyst slide valves to keep the levels in the vessels, and to maintain an equal differential operating pressure on the two catalyst slide valves. Then the valves may be put on automatic control. 54. Continue to circulate catalyst until a temperature of at least 510 °C is reached at the riser outlet. 55. At this stage oil can be introduced into the system, the fractionation section should be ready to receive products from the reactor section. The feed system to the riser should be circulating through the reaction section bypass to the feed surge drum and ready to be lined up to the feed injectors. 56. Switch the Disengager/Stripper purges from nitrogen to fuel gas. Check flow rates of all purges. 57. Check that emergency systems UX-001(ES1) and UX-002(ES2) are ready for activation. 58. Put the regenerated catalyst slide valve on manual control. 59. Drain water from feed injectors and open the isolation block valves on the feed lines keeping the control valves closed. 60. Feed Cut-in to Riser. Put injectors in operation three by three opening the control valves to give 50% of normal flow. The riser outlet temperature should not fall below 480°C. 61. Raise feed rate to 70% of the normal capacity within 1 hour of feed cut-in. 62. Adjust air flow rates to the Regenerators so that a temperature of 650-700°C is maintained in the First Regenerator and 2% excess oxygen is obtained in the Second Regenerator flue gas. 63. Start the metal passivator injector as required. For initial operation, start metal passivator injection at later stage, after establishing line-up all the operating condition and stable operation. Note: Metal passivator will be used Mixed Crude Case only. 64. After the Main Fractionator has stabilised, increase feed rate to the design capacity in increments of 10%. 65. Adjust air flow rates to the Regenerators accordingly, sample and check the regenerated catalyst. 66. Start to load fresh catalyst and to withdraw spent catalyst, referring sampling data of the all product, and maintain catalyst activities. 67. Sample the Main Fractionator bottoms for signs of catalyst carry-over from the Disengager.

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68. Sample flue gases to adjust combustion air rates. 6.1.2 Fractionation and Gas Concentration Section The following are summary of Start-up of Fractionation and Gas Concentration Section 1 2

3 4 5

6 7 8

9 10 11 12 13

14 15 16 17

18 19

Inform all concerned of the proposed time of the start-up. All precommissioning and commissioning activities have been completed. Sections leak tested and water flushed as necessary. Instruments tested, utility systems have been commissioned. Safety equipment is in place, required blinds removed / installed as appropriate. The UNIT has not been air freed. Purge air from the sections of the UNIT using steam and nitrogen and leave under nitrogen or fuel gas to maintain a positive pressure. Charge the UNIT with light oil (LCO or LGO) into the Feed Surge Drum. Drain free water from the drum and piping before introducing oil. Transfer oil from the Feed Surge Drum into the Fractionator via feed oil pumping and preheating system, using start-up line upstream of XV-002. When a level is established in the bottom of T-1501, start circulation through the slurry circuits. Drain free water from low points in the circulating circuits before hot circulation is started. Continue to add LCO feed to the Fractionator and run oil to slops or to storage via the clarified oil circuit. Stops LCO feed to the Fractionator and continue circulation. The clarified oil circuit can be recirculated via the minimum flow line back to the Fractionator. Hot circulation of the slurry pumparound can commence using medium pressure steam heat input in the slurry steam generators E-1505A/B. In case COB/WHB is already commissioned, and saturated HP steam, generating by WHB, is available, use E-1504A/B for heating-up operation, as well to support heating up operation. Open the blinds in the lines to the condensate traps on the steam generators of E-1505AB. These traps are used only for start-up. Continue circulation through the slurry circuits. Pumps should be switched from time to time so that all three pumps and piping are heated. Allow the system to heat up to the steam condensing temperature of around 200 ° C. Drain off water, which collects in the pumparounds, product draw-off lines and overhead reflux drum. Bring naphtha into the Fractionator Reflux Drum from outside of the unit. Conduct cold naphtha circulation in Gas Concentration Unit, using start-up naphtha. Introduce start-up naphtha into the overhead receiver, then supply naphtha to stripper. Establish cold circulation loop in Gas Concentration and main fractionator receiver, using start-up naphtha. Operate Wet Gas Compressor with fuel gas under closed condition of MOV-001 at Fractionator inlet to pressurize Gas Concentration Unit. Continue hot circulation until it is time to open MOV-001 at the Main Fractionator inlet. Stop hot circulation and depressure the fractionator to flare. Open MOV-001 of the Main Fractionator inlet. Be sure that purge HPS to MOV-001 is closed prior MOV-001 operation. Once MOV-001 is opened, restart circulation and heat the circulating oil to around 200 ° C. Reopen the purge HPS line to MOV-001 after confirmation of MOV-001 full opening. For the initial start-up, fill the LCO pumparound by bringing in LGO via the suction of the LCO Pumparound Pumps. Circulate the LGO in the LCO circuit and drain water from the low points in the circuit. For subsequent start-ups LCO will be available as flushing oil. Fill the HCO pumparound circuit by overflowing the LCO chimney tray. Circulate through the HCO pumparound circuit and drain water from the low points in the circuit. Start hot circulation of HCO pumparound using heating-up by E-1523, introducing MPS. Commission steam trap at bottom of E-1523.

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20 Transfer warmed oil from HCO pumparound to LCO pumparound using start-up line from P1508AB. After sufficient volume of warm oil is available in LCO pumparound, transfer warm oil to Heavy Naphtha pumparound using start-up line from P-1510AB discharge. Maintain hot oil circulation of HCO PA, LCO PA, and Heavy Naphtha PA to eliminate water in the system. Note: Hot oil circulation of Heavy Naphtha PA is option, subject to situation of cold oil circulation of Heavy Naphtha PA using start-up naphtha. 21 Continue to bring naphtha into the Fractionator Reflux Drum from outside of the unit. Start a reflux pump and fill the heavy naphtha pumparound circuit. Circulate through the heavy naphtha pumparound circuit and drain free water from the low points. 22 Continue hot circulation on the slurry pumparound and fill the Fractionator reflux drum to normal liquid level with naphtha until feed is brought into the reactor riser. 23 Start the Wet Gas compressor by opening the suction and discharge valves on each stage and startup following the VENDOR’s procedures. The compressor start-up step is optional at this stage. The consequence of delaying the compressor start-up until feed is brought into the reactor riser is that more gas will be vented to flare. 24 If the molecular weight of the fuel gas is too low it may cause surging of the compressor, increase it by bringing LPG into the fuel gas system in the utility supply system (Unit 37), via LPG vaporizer. 25 Start cooling water to the Main Fractionator Trim Condenser and the Wet Gas Compressor Trim Cooler as required. 26 Establish cooling water flow through all the water cooled exchangers, and start all air coolers. 27 Start steam to the LCO and HCO Strippers 28 Switch the slurry HP steam generators E-1504AB from heating mode to steam generation, and MP steam generator E-1505AB to manual operation by shutting off the medium pressure heating steam and admitting boiler feed water. Isolate the medium pressure steam and then start-up condensate traps. 29 Initially send steam to atmosphere via the start-up silencer. Use both the continuous and intermittent blowdowns to bring the blowdown water within specification. 30 Monitor closely the Main Fractionator bottoms level. Check the slurry for catalyst fines several times per shift until operation has stabilised. 31 If the Wet Gas Compressor was not already started, start now WGC. For initial start-up, it is recommendable that Wet Gas compressor to start operation after feed cut-in so that sufficient gas is available and simpler control of pressure control of the reactor section. 32 As liquid builds up in the Interstage Drum, start liquid flow to the High Pressure Separator. 33 If the HCO, LCO and Heavy naphtha pumparounds have been stopped, they should be restarted. Check the circuits frequently for water at the low points. Start the air coolers if not already started. 34 When the level starts to rise in the Fractionator Reflux Drum, start reflux to control the overhead temperature. Keep this temperature high enough to prevent condensation of steam at the top of the column. 35 Start drawing off LCO to the LCO Stripper and adjust stripping steam rate. Send the LCO to slop header. 36 Start drawing off heavy naphtha to the Heavy Naphtha Stripper and start re-boiling the stripper with the HCO pumparound. Send the heavy naphtha to slops. 37 Start drawing off HCO to the stripper and adjust the stripping steam rate. Prepare to start the LP steam generator. 38 When the level in the HCO Stripper starts to rise switch the flushing oil system to HCO. 39 Start the water wash to the overhead condenser. 40 Open the line to flare at the top of the Fuel Gas Absorber and set the pressure controller at the top of the Secondary Absorber. Pressurise the HP Separator, Primary Absorber, Secondary Absorber, and the Fuel Gas Absorber with gas from the Wet Gas compressor. 41 Start the overhead liquid distillate pump and send liquid to the primary absorber in Gas Con Section. 42 Send HP Separator liquid to feed the Stripper.

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43 When heat is available from the LCO pumparounds, start re-boiling the Stripper. Pressurise liquid to the Debutaniser. 44 Fill start-up LPG to the debutanizer receiver. As level available in the debutanizer receiver, gradually fill LPG to LPG treater using the debutanizer reflux pump. Fill lean Amine to LPG treater. 45 When a level is established in the Debutaniser bottom start re-boiling with the HCO pumparound. Vent light ends to the flare from the debutanizer receiver. 46 Start the lean sponge oil pump and feed lean oil to the Secondary Absorber. When a liquid level is established start sending rich oil back to the Main Fractionator. 47 Send the liquid from the Debutaniser reflux drum to the LPG Treating Unit. 48 When a level is established in the Debutaniser bottom start the Gasoline Recycle Pumps and circulation to the Primary Absorber. 49 Send the liquid from the Debutaniser bottom to the RFCC Naphtha Treating Unit. 50 Start the amine flow to the Fuel Gas Absorber and switch the outlet of the fuel gas absorber to fuel gas. 51 Start the amine flow to the LPG treater, and start routing treated LPG to LTU. 52 Start the water wash to the Wet Gas Compressor Intercooler.

6.2 Final Preparation 6.2.1

Preparation Confirmation The final preparations described here are from the point where the UNIT is cold, air is in the equipment (and piping) and the UNIT remains blinded at all battery limit locations and at the locations in the UNIT for the refinery fuel gas. Prior to the final preparations all preliminary checks will have been carried out for commissioning or a start-up following a turnaround. Other start-ups from ‘cold’ will incorporate preliminary checks as applicable. The preliminary checks are: 1. 2. 3. 4. 5.

6. 7. 8.

9. 10.

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All concerned have been informed of the proposed time of start-up. Tightness test and nitrogen purges have been completed and the oxygen level is less than 0.2 vol% in the feed preparation section. All lines and equipment have been cleaned and all flanges and manways are bolted with the correct gaskets, and equipment blinds removed or swung open. Strainers are installed where required and orientated correctly. Temporary fine mesh strainers are installed for initial operation of the pumps. For initial start-up only, confirm installation of the temporary strainer in the feed line upstream of the feed injectors at down stream of M-1501 of the feed line. (See Note 4 of P&ID 8474L-015-0021-121). This temporary strainer is provided to remove construction debris. Remove this temporary strainer at appropriate timing, soon after initial operation and temporary shut-down chance, when construction debris are considered to removed. All distributors (spent catalyst inlet in First Regenerator, lift outlet, riser outlet) inspected for proper construction and protection against erosion. Air rings and steam rings inspected for proper nozzle size and orientation. Feed, MTC and steam injectors inspected for proper orientation and penetration. The annulus around the injectors packed with kaowool or equivalent. Injector VENDOR installation procedure must be followed. Orifice plates; tab diameters checked against data sheets and orientated properly. All instrumentation, fluidisation and aeration taps including torch oil nozzles checked for proper orientation and penetration. The nozzles are free of refractory or other material.


11. 12. 13. 14. 15. 16.

17.

18.

19. 20. 21. 22. 23. 24. 25. 26. 27.

28.


All control valves have correct flow orientations and have been stroked and left closed on manual. Their bypasses checked as tightly shut off. Slide valves and plug valves inspected for proper calibration, movement, and operation. Expansion joints inspected for proper installation and freedom of movement. All check valve orientations are confirmed, correctly. All instruments and analysers have been calibrated and are ready for use. All rotating machinery has been run, has correct lubrication inventories established, has been aligned, has had rotation direction checked, and guards securely installed. Relief valves (systems) shop certified and installed with seals, chained open / close valves, and interlocking open / close devices checked for correctness per check list. Blinds and restrainers removed per check list. On the Disengager and First Regenerator cyclones, set blocks to open the trickle valves on the diplegs. Verify that the Disengager and the Regenerators manways are closed. UNIT drains and vents not required for start-up purging or draining have been checked as capped, plugged or blinded. Dampers, air registers of the air heaters have been checked for easy movement. All utility services are available at the battery limit. All relief, slops and drainage systems are ready for use and the Main Flare has been commissioned. The UNIT has been checked free of all debris, scaffolding, planking etc., especially at the upper levels. All alarm circuits have been checked and are ready for use. Emergency shut-off valves have been tripped and reset twice and the emergency shutdown systems have been tested and ready for operation. Fire fighting, safety equipment and gas emission analysers checked for operability and completeness. Remove or swing blinds to normal operating positions at battery limit lines. Leave MOV-001 closed at inlet of the Main Fractionator. Make a final check to remove or ‘swing’ out of use any isolating blinds at unit equipment or in lines. Check “distance” spools are made up or disconnected per check list. Recheck all relief systems are in an operable position, any upstream and downstream isolation blinds removed, and where double relief valve arrangements exist that the installed valve in the system has its isolation valves in the locked open position. Commission all utilities.

6.2.2 Off-site and relating units preparation Confirm off-site and relating units are ready to start sending feed, product and off-spec material from RFCC. - CDU is operating to supply feed Atm Residue - LCO tank is filled with LGO from CDU for initial start-up operation - Start-up naphtha is available from CDU - Start-up LPG is available from offsite - LTU (Unit 16) and PRU (Unit 21) are ready to receive RFCC LPG. - NTU (Unit 17) is ready to receive RFCC Gasoline - LCO unit is ready to receive LCO product - Fuel Oil Pipeline is ready to receive Clarified Oil - Amine treating unit is ready to supply lean amine and receive rich amine - Sour water stripper unit is ready to receive sour water

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-


All product rundown system are ready to receive product Slop handling facilities are ready to receive all slop.

6.3 Reactor Regenerator Start-up Procedure 6.3.1

Unit warm-up

The status of the unit prior to warning up of reaction / regeneration section is as follows: ♦ Refractory has been repaired and ready for operation in whole section as well as flue gas treatment section. ♦ Equilibrium catalyst is loaded into the spent catalyst hopper or Auxiliary Hopper ♦ Fractionation and Gas Recovery section has been warmed up, dried out and is ready from oil in. ♦ EP is ready as “Pre-Heat” Mode, and CO Boiler is ready for operator in fresh air mode. ♦ Waste heat boiler is in operation with boiler water filling in the steam drum. ♦ Steam drum of Waste heat boiler is ready for operation. ♦ Electrostatic precipitation is grounded. ♦ Economizer is bypassed, but under BFW filling is available. ♦ In stripper/disengager side, plant air is injected by temporary connection at minimum flow rate to avoid small lines, and rings nozzles to be plugged. ♦ Air is also injected into fuel gas lines (instrument, aeration, conveying lines). ♦ Air is also injected into steam ring lines (bottom ring, main, hopper, lower, anticoking rings, stabilization, atomization, and torch oil nozzles. ♦ Confirm blind plate upstream of MOV-001 is removed and replaced to ring spacer. As for the refractory dry-out operation, during the warm-up operation, it will be necessary to adjust the position of the slide valves and plug valve periodically to control the heat-up rates of each vessel. The objective is to have all three vessels arrive at their final operating temperature at the same time while maintaining heat-up rates at about 60°C to 100°C per hour. At least once per hour the slide valve positions should be moved to check for binding. All spring hangers and expansion joints should be watched closely during this time. Portable contact thermometers can be used to ensure heat-up of the spent catalyst and regenerated catalyst standpipes. The flue gas COB/WHB section must be ready to be placed in service. During the warm-up, the pressure in the three vessels is maintained at 1.0 kg/cm2g. a)

Warm the unit with blower discharge temperature for two hours prior to lighting the air heaters.

b)

Light the air heaters according to Vendor’s procedures and maintain at minimum firing rate for two hours.

c)

Heat up the regenerators at a speed of 60°C/h to 340°C and start to heat-up the disengager/stripper.

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d)


Hold one hour at 340°C. Try to obtain as high temperature as possible in the disengager/stripper around 340°C. Note 1: In case of restart (coked refractory), keep disengager/stripper and riser temperatures about 330°C ± 10°C to avoid starting coke burning.

e)

Increase the air heaters outlet temperatures at a rate of 60°C to 100°C per hour up to their design maximum outlet temperature. Note 2: Do not exceed 760°C at air heaters outlet.

f)

At least every hour during warm-up:

1.

Alternatively pinch and open the spent and regenerated catalyst slide valves and check by contact thermometers or by feeling that the riser and catalyst standpipes are heating up evenly.

2.

Check the unit for any leaks. All spring hangers and expansion joints should be watched closely during this time.

g)

Heat both regenerators up to about 650°C as measured in the dilute phases and heat the disengager up to preferably 340°C. Hold at these temperatures for a minimum of two hours. For initial start-up, hold these temperature as long as practical, preferably more than four hour to keep regenerator hot condition to avoid stick of catalyst in the cyclone leg while catalyst loading to the regenerator, due to possible moisture during catalyst transfer from the outside of the refinery.

h)

Once again check the unit for leaks.

i)

During the final stage of warm-up, instrument purges, aeration and conveying lines to the disengager/stripper section should be switched from air to nitrogen. They will later be switched to fuel gas before introducing oil to the unit. All steam rings and stabilization, atomisation nozzles should be switched from air to steam.

WARNING:

6.3.2

New refractory linings should not be exposed to steam for a long duration prior to catalyst circulation, depending on pressure/temperature conditions in the vessels, in order to avoid steam migration into the refractory and as a result possible condensation between shell and refractory.

Main fractionator MOV-001 Opening

In preparation for opening MOV-001 of the main fractionator, all steam lines to the process should be hot and free of condensate. The hot oil circulation and dry-out of the main fractionator should be completed. Reduce the main fractionator level to minimum, stop the hot oil circulation. a)

Close spent and regenerated catalyst slide valves.

b)

Time to time open the drain at riser bottom and bottom of the stripper, and the drain at spent catalyst sampling connection to check if there is some condensate.

c)

Establish a steam purge at the bottom of the main column. Depressure the main fractionator completely to flare.

d)

Open the disengager/stripper vent line to the Silencer and drain just upstream of MOV-001.

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e)

Assure that a supply of dry steam is available at the stripper and riser steam injection locations and start all steam injections. Set stripping steam and dispersion steam at 50% of normal operating flow.

f)

Observe the disengager/stripper vent line exhaust until a continuous flow of steam has been venting for a minimum of 15 minutes. Watch the disengager pressure instrument and reduce steam flow if necessary to avoid over-pressuring the disengager/stripper.

g)

Reduce the steam flows to a minimum at the main fractionator, stripper and riser. Allow both sides of MOV-001 to depressure.

h)

Be sure that purge HPS line to MOV-001 is closed.

i)

Open MOV-001, slowly. Make sure that steam is still going to stripper / disengager and to fractionator to avoid air entry.

j)

After full opening MOV-001, slowly close the disengager vent line to the Silencer and reestablish stripping steam and riser steam flows at normal operating flow rates. Restart purge HPS to MOV-001. Provide positive Locking that MOV-001 shall never be closed during subsequent operation, including normal operation. The main fractionator may now be pressured with fuel gas (or nitrogen). Use the steam vent to set disengager pressure at approximately 0.1 kg/cm2 higher than the first regenerator pressure. This is to avoid air flowing through the spent catalyst standpipe stripper/disengager until catalyst loading is started and a catalyst seal is established above the spent catalyst slide valve.

k)

6.3.3

Leave the drain at riser bottom slightly open to drain condensates, close the drain on the spent catalyst sampling connection. Catalyst loading 1. Equilibrium catalyst is loaded from the spent catalyst hopper or auxiliary hopper to the first regenerator. Record initial catalyst inventory level in the hoppers by manual dipping scale wire from the manual gauge valve nozzle (4”) at top of the hopper. 2. Before starting the loading, open all fluidization air nozzles to spent hopper bottom at normal flow rate, and pressurize at 3.5 kg/cm2g by plant air. Open all the valves on the catalyst loading line, except the one located at the hopper bottom. 3. Start blower air through the catalyst loading line at the rate of about 1500 to 2000 kg/h enough to create air / catalyst mixture density of 40 to 60 kg/cm3 (catalyst velocity in loading line must not exceed 10 m/s for erosion purpose). The catalyst hopper is ready for loading. Check and record the catalyst level in the hopper. 4. In the regenerators, during the start of loading, take care not to increase blower air flow rate too high in order to avoid losing catalyst through the cyclones dipleg. The air velocity in the first regenerators dense phase must be kept within the range of 0.3 to 0.4 m/s during catalyst loading.

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5. The air flow rate could be as follow to maintain 0.3 to 0.4 m/sec. at dense phase of the first regenerator. -

Diameter of Dense phase (first Regenerator): 8.9 m

-

Center Riser Pipe: 1.8 m

-

Segmental Area excluding center pipe: 59.64 m2

-

First Regenerator Pressure : 1.1 kg/cm2G

-

Temperature: 650 deg C

-

Air density: 0.816 kg/m3

-

Air rate to first Reg to maintain 0.3 – 0.4 m/sec: 52,600 to 70,100 kg/hr (40,700 – 54,200 NM3/hr)

It might be necessary to snort some air at the blower discharge to avoid surging. Refer to performance curve of the main Air Blower. 6. Close the catalyst slide valves and plug valve. Ensure the slide valves cannot be opened accidentally. Note the position of the plug valve in the hot closed position for future reference. Set the first regenerator pressure to about 1.1 kg/cm2g. The disengager pressure is set 0.1 kg/cm2 higher than the first regenerator pressure (on automatic control). The second regenerator pressure is around 1 kg/cm2g. 7. Reduce the combustion air flow rates to the above rate (about 30-40 % of the normal operating flow rates of Bach Ho Gasoline Case) until such time that the regenerators cyclones diplegs are sealed to minimize catalyst losses. 8. Start lift air to the plug valve at 50% of normal flow. (47,832 kg/hr) 9. Start loading the catalyst by slowly opening the gate valve at the hopper bottom. A pressure gage and sight glass located on the catalyst loading line will indicate if the catalyst transfer is established. Adjust the catalyst flow by the gate valve opening and by the carrying air flow rate. During the loading, the amount of loaded catalyst must regularly be checked by measuring the level decrease in the hopper. Record catalyst level in the hopper to check the loading speed. The tentative amount of loaded catalyst should be about 35 t/hour for a 6" loading line. Be careful not to exceed significantly these values in order to limit the catalyst damages. 10. Load the first regenerator while maintaining the dense phase above 370°C. 11. When the level in first regenerator is at least 500 mm above the torch oil nozzles and the dense phase temperature is at least 370°C, torch oil may be started. Start torch oil at minimum rate and observe the dense phase temperature closely. If a substantial increase in dense phase temperature is not registered within about 30 seconds the torch oil flow should be stopped or the catalyst may become saturated with oil and may make run away temperatures later. The dense phase temperature should be raised about 30°C before attempting torch oil again. If the torch oil does not produce a response above 450°C, suspect a flow stoppage.

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12. Adjust the torch oil flow to achieve 650°C in the dense phase. The first regenerator air heater can be reduced to minimum firing but should remain in operation until the unit is onstream, so that it can be used in case a problem develops with the torch oil flow. 13. Continue loading catalyst to first regenerator until the maximum bed level is achieved. The air rate to first regenerator may be increased after the diplegs are sealed. 14. Increase the differential pressure by dPIC between first and second regenerator to 0.7 kg/cm2. Slowly open the plug valve and begin to transfer the catalyst from first to second regenerator. 15. Reduce air flow to the second Regenerator to maintain 0.3 – 0.4 m/sec at dense phase of the Second regenerator (diameter: 8.0 m) to minimize loss of catalyst, until catalyst level is higher than the dip leg of the cyclone. The equivalent total air flow rate is 42,200 – 56,300 kg/hr. Since lift air is already set to 24,000 kg/hr (50 % of normal), air flow rate via H-1502 could be 18,200 – 32,300 kg/hr. Ideally the differential pressure and plug valve opening should be adjusted to transfer catalyst to second regenerator just fast enough to slowly empty first regenerator to the minimum operating level. Do not empty the first regenerator below the cyclones diplegs and torch oil nozzles. Monitor the density readings of the regenerated catalyst standpipe to see when it is filled. 16. When the level in second regenerator is at least 500 mm above the torch oil nozzles, the torch oil may be started if dense phase temperature in second regenerator is above 370°C. After torch oil ignites in the second regenerator, set the torch oil flow to maintain 650°C in the dense phase. Second regenerator air heater firing may be reduced to minimum firing. 17. Continue loading catalyst and transferring from first to second regenerator until all the catalyst inventory has been loaded into first and second regenerator. 18. Hold the regenerator levels and dense phase temperatures near 650°C while preparing for catalyst circulation. 6.3.4

Establishing catalyst circulation

The isolation valve MOV-001 between the main fractionator and the disengager must be opened before starting the catalyst circulation: the liquid level in the main column is reduced to minimum, the main column pressure is set to the disengager pressure, the valve MOV-001 is slowly opened and simultaneously the vent valve is slowly closed. Before establishing the catalyst circulation, the unit must be under following conditions: • Disengager

: Around 300°C, under steam, pressure controlled at main fractionator overhead drum by wet gas compressor if possible (*1) and/or by FG system or nitrogen at 1.2 kg/cm2g. Bottom pumparound is circulating through the MF.

• First regenerator

: Around 650°C, pressure at 1.1 kg/cm2g.

• Second regenerator

: Around 650°C, pressure at 0.4 kg/cm2g.

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• First and second regenerators air rings flow rates at about 50% of the normal operation flow rate. • Prior to beginning catalyst circulation, the drain at the bottom of the stripper, and riser wye should be checked for water, and any water found should be drained. Confirm sufficient catalyst has loaded into the both regenerators, by: - Hopper level reduction - Level in both regenerators at dense phase (*1) For initial start-up, it is recommended that Wet Gas Compressor not to operate until feed cut-in, so that pressure control of the main fractionator is easily made. Subsequent operation, Wet Gas compressor could be commissioned, as gain of operation experience and minimize flaring of hydrocarbon. Start catalyst circulation by the following steps: a) Air lift flow rate is increased up to the normal flow rate. b) Set the PDIC’s on the spent and the regenerated slide valves at 0.1 kg/cm2 and place these controllers on automatic. The Riser Outlet Temperature control (RCSV) and stripper level control (SCSV) controllers should be on manual and in the closed position. During pressure balance modification, always maintain a positive differential of 0.1 kg/cm2 between the disengager and first regenerator. c) Reduce stripping steam flow rates to minimum, set the stabilization, dispersion bottom wye steam to normal flow rate. d) Slowly open the regenerated slide valve on manual to about 20% open. The first indication of catalyst flow will be an increase in riser differential pressure, and then later, an increase in riser temperatures (the first catalyst above the regenerated slide valve may be relatively cold). Monitor the regenerated slide valve differential pressure and try to maintain above 0.2 kg/cm2. e) The first indication of catalyst in the spent catalyst line will be an increase in the slide valve differential pressure. When an increase is noted on the spent slide valve differential pressure, very slowly open the spent catalyst slide valve to initiate the circulation. When the spent catalyst slide valve differential drops, close the valve. The first portion of catalyst may be difficult to circulate because it is cold, and possibly wetted. A batch wise transfer is recommended until the temperatures are higher. It may be necessary to increase the differential pressure between the stripper and the first regenerator, i.e. to decrease the first regenerator pressure to overcome difficulty in the initial catalyst movements. The minimum delta pressure through the lift is 0.3 kg/cm2. f) Continue batch-wise circulation and transfer until the stripper temperature is above 370°C. At this time, start to rise the pressure in the first regenerator to the normal operating pressure and adjust the second regenerator pressure. Put pressure controllers on automatic control. g) When the stripper temperature reaches 480°C, the stripper level can be increased to the normal operating level. During these operations adjust the plug valve opening to keep the level in the second regenerator and put the level in the second regenerator on automatic control.

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h) Manually adjust the opening of the spent catalyst slide valve to keep the level in the stripper. Note :

Do not let the level in the stripper get above high level at any time. If this level is being approached, slow or stop the flow of catalyst from the second regenerator as required by manually pinching the regenerated catalyst slide valve until the stripper level is back to its normal level, in order to avoid catalyst loss through the disengager cyclones.

i) Adjust the regenerated and spent catalyst slide valves to keep the levels in the vessels and to maintain approximately an equal differential opening pressure on the two catalyst slide valves. Then the valves may be put on automatic control. j) Catalyst addition or withdrawal may be necessary in order to adjust the unit inventory. k) Continue to circulate catalyst until a temperature of preferably 530°C and at least 510°C is reached at riser outlet. l) At this point the fractionation system should be ready to receive products from the reaction section. The feed system to the riser should be circulating through the reaction section bypass and ready to be lined up to the feed injectors. m) During catalyst circulation, check that no water is present in Riser Wye section (taking precautions, as a lot of catalyst may go out). Note :

6.3.5

To stop catalyst transfer, always close first the gate valve at the bottom of the hopper, in order to get the transfer line completely rid of catalyst.

Oil-in into Rizers

Prior to oil in, provided all other sections (gas recovery flue gas treatment) are ready to handle disengager effluents. Before oil-in the unit must be in the following conditions: ♦ Pressures: –

Disengager

:

Normal operating conditions on automatic control from PIC. Controlling by WGC or Flaring through pressure control valve.

–

First regenerator

:

Normal operating conditions on automatic control acting on the first regenerator flue gas slide valve.

–

Second regenerator

:

Normal operating conditions on ΔP automatic control acting on the second regenerator flue gas slide valve PdIC.

♦ Levels: –

Disengager

:

On automatic control acting on the spent catalyst slide valve from LIC.

–

First regenerator

:

At normal level on automatic control acting on the plug valve from LIC.

–

Second regenerator

:

Is not controlled directly, but is a function of catalyst inventory.

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♦ Temperatures: –

Riser outlet

:

Preferably 530°C.

–

Regenerators

:

650°C with torch oil and fuel gas firing in the heaters.

♦ Flow rates: ♦ First and second regenerators air flows are at about 50% of the normal operating flow rate. –

Air lift flow is at 100% of the normal operating flow rate.

–

Riser and stripping steams are all in service at normal operating flow rates.

–

Aeration, conveying and instrument purges are all in service at normal operating flow rates.

♦ All injections steams (stabilization, feed, MTC) are all in service at normal operating flow rates. ♦ Catalyst is circulating and catalyst slide valves are opened in order to have a minimum of 0.35 kg/cm2 pressure drop in each slide valve. ♦ Monitor the oxygen in the main fractionator reflux drum (oxygen < 0.2% vol.). ♦ Analysers on flue gas lines (O2, CO, CO2) will be operational. Oil-in will be performed as follows: Caution:

As hydrocarbons will be present in the unit it is important that all vents and drains be closed and opened only with an operator present. Drain condensate from all low points, being careful not to vent fuel gas.

a) Switch the disengager/stripper purges from nitrogen to fuel gas. Check all purges flow rates. Special Note: 1. Since purge gas to “Detail B2 and A2” for instrument tapping of the disengager / stripper is normally supplied from the Gas Con Section, fuel gas should be temporary used until commission of Gas Con Section. Open 3” fuel gas connection at the inlet of D1509 on P&ID 8474L-015-PID-0021-138. Upon treated gas from Gas Con Section is available switch purge gas from fuel gas to treated gas. 2. Since fuel gas pressure is normally 3.0 – 3.3 kg/cm2g, opening of bypass valves of the following control valves are required to maintain pressure at the purge points, when fuel gas is used as purge gas. - PCV-015: Rizer instrument purge “Detail B2” (PID 15-122) - PCV-013: Regnerated catalyst conveying “Detail A2”(PID-15-122) -PCV-044: Disengager instrument purge “Detail B2” (PID-15-124) -PCV-042: Stripper instrument purge “Detail B2” (PID-15-124) 3. In case Wet Gas Compressor is operating and treated gas from Gas con Section is available, the above fuel gas purge operation is not required. b) Check that emergency systems UX-001(ES1) and UX-002(ES2) are activated. c) Put the regenerated catalyst slide valve on manual control.

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d) Drain water from feed injectors and open the block valves on the feed lines, keeping the control valves closed. e) Injectors will be put in operation three by three. First, on three opposite injectors open the control valves at 50% of the normal flow; then proceed with the next three injectors, etc... As soon as feed is injected into the riser, the riser outlet temperature will tend to drop. To compensate the temperature drop, the opening of the regenerated catalyst slide valve can be slowly increased to admit more hot catalyst into the riser. Do not get pressure drop getting less than 0.15 kg/cm2g. The second regenerator temperature can also be increased by increasing the torch oil flow rate. The riser outlet temperature should not drop below 480°C as catalyst stripping will become ineffective. Feed rate should be quickly increased to 70% of the normal capacity as rapidly as possible, within 1 hour of oil-in. Beginning of coke combustion will be noted by an increase of the first regenerator dense phase temperature. Adjust the regenerators temperatures by adjusting the torch-oil flow rates and stop firing in both air heaters. Keep the temperatures below 700°C. f) Adjust air flow rates to regenerators so that a temperature of 650°C-700°C is kept in the first regenerator and an oxygen excess of minimum 2% is obtained in the second regenerator flue gas. g) When catalyst circulation is stabilized, put the Riser Outlet Temperature on automatic control (RCSV). h) Proceed to a pressure survey of each injector (steam and oil) for equal flows and inlet nozzles pressures. i) Start metal passivator injection as required. For initial operation, start metal passivator injection at later stage, after establishing line-up all the operating condition and stable operation. j) Check catalyst levels. After main fractionator stabilization, increase the capacity at design capacity by increaments of 10% of capacity. k) Adjust air flow rates to regenerators, accordingly. l) Check the regenerated catalyst by samples. m) Check the unit inventory of catalyst (add or withdraw catalyst if necessary). n) Start to load fresh catalyst and to withdraw spent catalyst. o) Sample the main fractionator bottoms for signs of catalyst carry-over from the disengager. p) Sample flue gases to adjust combustion air rates. Note:

During the increase of capacity, the two regenerators are running with about 50% of the normal air flow rates and torch oil under complete combustion mode. While the capacity is increased, the torch oil is progressively reduced to balance the coke formation. After a given capacity is reached, the coke make is enough to shift to partial combustion in the first regenerator. At this moment the CO content can increase rather quickly (in 2 to 3 minutes).

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After stabilization, the flue gas from the first regenerator can be sent directly to CO Boiler. CO Boiler can be put on stream progressively when the CO content is high enough and stable in the flue gas at about 5%. It may be necessary to adjust the position of flue gas bypass valves (quench sprayers) to achieve a good control range on CO Boiler or flue gas bypass lines according to the manufacturers procedures. 6.3.6 Notes:

MTC system commissioning 1. Dispersion steam is constant whatever the flow of MTC recycle. 2. The optimum MTC flow rate depends on the feed quality and on the desired yields structures (switch from maxi gasoline to a maxi distillate mode of operation for instance). 3. For design intention MTC injection is only used for the Maximum Gasoline Operation of Mixed Crude.

a)

Drain water from MTC injectors and open block valves on the recycle lines.

b)

Make sure lines from pumps to riser are clean by checking the drains before the control valves. Check that dispersion steam is at the normal operating flow rate.

c)

Put the Riser Outlet Temperature control (RCSV) on manual. Slowly open MTC control valves by steps of about 5%. The cracking severity of the fresh feed will increase. Adjust the set point of the Riser Outlet Temperature controller to obtain the desired conditions for optimized cracking operation: Fresh feed mix temperature, Catalyst to fresh feed ratio (C/O).

d)

Injectors will be put in operation one by one. Confirm that flow rate of MTC injection should be higher than pump minimum flow. Increase again MTC injection by 5% increments and adjust the Riser Outlet Temperature accordingly.

f) Put Riser Outlet Temperature on automatic control (RCSV).

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6.4 Start-up for the Fractionator Section 6.4.1 Objective The following guidelines describe the first start-up of the unit. For subsequent start-ups some procedures will be omitted, depending on the status of the unit. 6.4.2 Status All precommissioning and commissioning activities have been completed:

• Each section has been leak tested • All sections have been water flushed • Instruments have been tested • Utility systems have been commissioned • All safety equipment is in place • Required blinds have been removed/installed as required • The unit has not been air freed 6.4.3 Steam-out (or nitrogen purge) Prior to bringing hydrocarbons into the unit, it is necessary to remove all air from the unit. This is done by steaming out the unit and then admitting nitrogen or fuel gas to prevent vacuum conditions when the steam condenses. Caution : If steam-out is stopped with the vessel vents closed, and gas is not introduced, vacuum conditions will occur. However, most equipment is designed for steam-out conditions of 160°C and full vacuum. Caution: Reactor and Regenerators are not designed “Full vacuum”. Special care shall be taken that vent valve shall never kept to close while steaming into the system, especially under situation of MOV-001 closed condition. For steam-out, the unit can be considered to be divided up into the following sections :

• Feed section • Main fractionation section including side strippers, from main fractionator inlet to the wet gas compressor suction • Flushing oil • Slops • Wet gas compressor interstage • Wet gas compressor (N2 purge) • HP separator drum, absorber-stripper, secondary absorber and fuel gas absorber • Debutanizer section • LPG amine absorber section Before admitting steam into the unit cooling water should be shut-off to exchangers, instruments which could be damaged by steam should be isolated, pumps blocked in and vessel vents opened.

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The 1st and 2nd stages of the wet gas compressor are isolated from the interstage section, so that the compressor stages can be nitrogen purged and the interstage section steamed out. 1) Feed section Steam out via the vent or drain connections on the lines feeding the unit and on the feed surge drum. Continue steaming out until there is a good flow of steam from the feed surge drum vent. The preheat piping and exchangers should be hot with steam coming from the various vents and drains. After steam has been venting for a minimum of one hour, this section can be pressure tested by closing vents and drains to raise the pressure to 1.5 to 2.0 kg/cm²g. After pressure testing is complete, the section is pressurized with fuel gas. Block in the steam and admit fuel gas to maintain a positive pressure on this section. 2) Main fractionator to wet gas compressor This section consists of the main fractionator, reflux drum, wet gas compressor suction drum, product stripping sections, slurry system and pumparounds. This section can be further sub-divided as considered necessary, with the same procedure being carried out for each subsection. Steam-out is carried out with MOV-001 closing position in the reactor vapor line. Steam out connections on the main fractionator, strippers and drums in the section are all used for steam out. Continue steaming out until there is a good flow of steam from all the vessels in the section. All piping and exchangers in the section should be hot, with steam coming from the various vents and drains. After steam has been venting for a minimum of one hour, this section can be pressure tested by closing vents and drains to raise the pressure to 1.5 to 2.0 kg/cm²g. After pressure testing, the sections are pressurized with fuel gas. Block in the steam and admit fuel gas to maintain a positive pressure on the sections. 3) Slops section Steam out via the steam out connections on the light slops drum and the heavy slops drum. Continue steaming out until there is a good flow of steam from the drum vents and piping vents and drains. After steam has been venting for a minimum of one hour, the heavy slops and light slops sections can be pressure tested by closing vents and drains to raise the pressure to 1.5 to 2.0 kg/cm²g. After pressure testing, the two sections are pressurized with fuel gas. Block in the steam and admit fuel gas to maintain a positive pressure on the two sections. 4) Flushing oil Steam out via the steam out connections on the HCO and LCO flushing oil drums. Continue steaming out until there is a good flow of steam from the drum vents and piping vents and drains. After steam has been venting for a minimum of one hour, the HCO and LCO flushing oil sections can be pressure tested by closing vents and drains to raise the pressure to 1.5 to 2.0 kg/cm²g. After pressure testing, the two sections are pressurized with fuel gas. Block in the steam and admit fuel gas to maintain a positive pressure on the two sections. 5) Wet gas compressor interstage Steam out via the steam out connection on the wet gas compressor 2nd stage K.O. drum. Continue steaming out until a good flow of steam is venting from the drum. After steam has been venting for a minimum of one hour, this section is pressure tested by closing vents and drains to raise the pressure to 1.5 to 2.0 kg/cm2 g. After pressure testing is complete the section is pressurized with fuel gas. Block in the steam and admit fuel gas to maintain a positive pressure on this section. Drain condensate from all low points while ensuring that fuel gas is not vented. 6) Wet gas compressor purge

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Each stage is isolated by the suction and discharge valves. Pressurize each stage with nitrogen to 2 to 3 kg/cm2 g (or as specified by vendor), then depressurize to atmosphere. This procedure should be repeated 4-5 times and then leave the compressor stages under a pressure of 1.5 to 2 kg/cm2 g. 7) HP separator drum, absorber-stripper, secondary and fuel gas absorbers Use the steam out connections on the HP separator drum, absorber-stripper, secondary and fuel gas absorbers to steam out this section. Steam out until there is a good flow of steam from the vents on the HP separator drum, stripper-absorber and secondary absorber and fuel gas absorber. After steam has been venting for a minimum of one hour, this section can be pressure tested by closing vents and drains to raise the pressure to 1.5 to 2.0 kg/cm2 g. After pressure testing is complete the section is pressurized with fuel gas. Block in the steam and admit fuel gas via the line to fuel gas from the fuel gas absorber knock-out drum via reverse flow from the refinery fuel gas system opening by-pass valve of the last control valve PV-733, to maintain a positive pressure on this section. Drain condensate from all low points while ensuring that fuel gas is not vented. 8) Debutanizer section Use the steam out connections on the debutanizer and debutanizer reflux drum. Steam out until there is a good flow of steam from the vents on the debutanizer and the reflux drum. After steam has been venting for a minimum of one hour, this section can be pressure tested by closing vents and drains to raise the pressure to 1.5 to 2.0 kg/cm2 g. After pressure testing is complete the section is pressurized with fuel gas. Block in the steam and admit fuel gas to the debutanizer reflux drum, to maintain a positive pressure on this section. Drain condensate from all low points while ensuring that the fuel gas is not vented. 9) LPG amine absorber section Isolate the section from the inlet of the LPG cooler to the outlet of the LPG amine coalescer. Use the steam out connections on the LPG amine absorber and LPG amine coalescer to steam out the section. Steam out until there is a good flow of steam from the vents on the absorber and coalescer. After steam has been venting for a minimum of one hour, this section is pressure tested by closing vents and drains to raise the pressure to 1.5 to 2.0 kg/cm²g. After pressure testing is complete, block in the steam and pressurize with nitrogen. 6.4.4 Main fractionator cold circulation When all sections of the fractionation and gas recovery section are under stable pressure, with fuel gas, nitrogen or LPG as applicable, cold hydrocarbon liquid is introduced to the main fractionator. Prior to bringing in hydrocarbon liquid, check throughout the unit to ensure that all instrumentation and electrical equipment is energized and ready for operation. Place all pumps in the stop position. It is suggested to use a light oil (LCO, LGO) for the initial flush as this does not form an emulsion as stable as that with heavier oils. Normally, residue type feed will not be brought into the unit until the unit is ready for feed to the riser. All vents and drains should be plugged or flanged and blinds should be put in the proper position for operation. LCO is used for pump mechanical flushing during start-up, until HCO is available. Fill LCO to D-1518, HCO flushing Oil Drum and start supply pump mechanical flushing oil to the various pumps. Ensure that external flushing oil system are commissioned prior to start the relevant pump. The purpose of the cold circulation is to remove as much foreign material and water as possible and to establish levels to test pumps. 1.

Drain any water from the boot of the feed surge drum D-1513 and start to bring in LCO from outside of B.L. When there is sufficient level in the feed surge drum, start one of the feed pumps,

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ensuring that the minimum flow line is open. Each pump can be started separately, for testing and running in. 2.

Filling LCO to the preheat heat exchangers from the feed pumps, and establish the following cold oil circulation loop, using start-up line 8”-PL-150024. D-1513Æ P-1501ABÆ E-1512ABCDÆ E-1522Æ E-1524Æ E-1502ABCÆ E-1501ABÆ FCV001Æ 8”-PL-150024Æ D-1513

3.

Start filling the bottom of the main fractionator through the start-up line (6”-PL-150025) from the feed section E-1501AB outlet. Bring LCO into the feed surge drum as required. Line up the slurry pumparound circuits and start two of the three pumps and start circulation through the slurry pumparound circuits, using maximum circulation rates to flush the circuits. Alternate the pumps for testing and running-in. Drain free water from low points.

4.

Fill the HCO and LCO pumparound circuits with LCO. The LCO circuit is filled directly using the LCO start-up connection (3”-PL-150604) to the pumparound pumps P-1510AB suction line. Fill the HCO circuit by flowing LCO down the column.

5.

Start circulation in the two circuits, bringing in LCO as required. Alternate the pumps for testing and running-in. Drain free water from low points.

6.

To help to remove water quickly from the circuits, continue to add feed to the fractionator and run oil to slops via the slurry product, HCO product and LCO product circuits. Open all by-passes to flush these lines. Drain free water from low points in the circulating circuits. It is important to remove all free water before hot circulation is started. When running to slops via the slurry product line, by-pass the slurry separator.

7.

After stopping flushing to slops, stop LCO feed to the fractionator and continue circulation.

8.

Commission level control of D-1518 HCO flushing oil drum as necessary to supply sufficient mechanical seal flushing oil to the various pump, which are used external flushing oil. LCO should be continuously supplied from over filling from main fractionator LCO pumparound to HCO pumparound and HCO stripper.

6.4.5 Cold Oil Circulation of Gas-Concentration Section Proceed cold oil circulation of Gas-Concentration section using start-up naphtha to remove water and any sludge in the system and reedy to receive feed gas from the main fractionator. ¾ Subsequet steam out operation of Gas Concentlation unit, admit fuel gas from the fuel gas system to the outlet of HP Separator, D-1553, using start-up fuel gas line (3 inch). ¾ Maintain pressure of Gas con unit as high as possible by fuel gas. If CDU LPG is available at this moment, introduce CDU LPG to HP Separator, D-1553 for increasing operation pressure, by self vaporization. ¾ Start Wet Gas Compressor to pressurize Gas Con Section, under MOV-001 closed condition to segrigae operation of Reactor/Regeneration and Fractionator/Gas Concentration Section. ¾ Introduce fuel gas to D-1554, and subsequently bring start-up LPG to D-1554, debutanizer Reflux drum to pressurize D-1554 and T-1554, Debutanizer, by self vaporization. Startheating up of Debutanizer Reboiler to boost-up operation pressure of Debutanizer. ¾ Fill start-up naphtha to the main fractionator reflux drum D-1514, and start P-1515AB for transfer start-up naphtha to T-1551, and establish cold oil circulation of Gas Concentration section.

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¾


D-1514Æ P-1515ABÆ T-1551Æ D-1553Æ P-1553ABÆ E-1555Æ T-1552Æ T-1554Æ E-1556Æ E-1558Æ E-1559Æ 6 inch Start-up lineÆ D-1514 Drain water from the low point of piping, and remove water as far as possible, before feed cut in to the reactor.

6.4.6 Main fractionator hot circulation Hot circulation is carried out to check the pumps under hot conditions and thus ensure the availability of pumparound cooling when hot feed is introduced to the fractionator. Hot bolting can be carried out and the circuits checked for any thermal stress problems. Both the slurry pumparound and HCO pumparound can be heated during hot circulation. In the slurry pumparound, circulating LCO is heated by condensing MP steam in the slurry MP steam generators E-1505A/B. The slurry pumparound circuit can be heated up to approximately the MP steam condensing temperature. In the HCO pumparound, the HCO MP steam generator E-1523 can be used for heating. The main requirement of hot oil circulation is to reach around 110 deg C at the top of the main column. Using MPS a temperature in the slurry pumparound and bottom temperature around 200 deg C can be reached. As higher temperature is preferred, if saturated HPS is available from COB/WHB section, admit saturate HPS to E-1504AB utilizing reverse flow, by-passing check valves. In order to assist heating up upper sections of the main column, the following jump over lines are provided to warming/heating-up of LCO pumparound and Heavy Naphtha pumparound. -

Start-up line (6”-PL-151010) from HCO pumparound pump discharge to LCO pumparound circuit return.

-

Start-up line (6”-PL-151009) from LCO pumparound pump discharge to Heavy Naphtha pumparound circuit return. As the fractionator heats up, any remaining water will be vaporized up the column. This will condense and should be drained off from low point of the LCO pumparound, the heavy naphtha section and the reflux drum. Before it is time to open MOV-001 at the column inlet, allow the circulating pumparounds to cool down to around 120°C. 6.4.7 Main fractionator MOV-001 Opening Opening MOV-001 between the main fractionator and the reactor must be carefully co-ordinated between the two sections. Allow the slurry and HCO pumparounds to cool down to 120°C. Reduce the main fractionator level to a minimum (below the steam out connection) and stop slurry circuit circulation. Stop the HCO and LCO pumparounds circulation. Depressurize the main fractionator section to the flare and start steam flow to the bottom of the fractionator, using 3” steam out connection. Follow the procedure for opening MOV-001 as outlined in the Reaction/Regeneration Section. After full opening MOV-001, steam flows to the reactor and main fractionator may be re-started, and fuel gas admitted to pressurize the main fractionator using HCV-434 at the overhead off gas line. The main fractionator pressure is controlled by the pressure control from the reflux drum to flare. A constant pressure is required to allow smooth catalyst circulation. Stop the steam to the bottom of the fractionator and bring oil into the fractionator from the feed section. Re-start slurry and HCO pumparounds circulation and heat the circulating oil to avoid the condensing steam temperature. Start LCO pumparound circulation. Bring in LCO as required. During circulation drain water from the low points in the circuit. To fill the heavy naphtha pumparound circuit, bring start-up naphtha into the fractionator reflux drum. Start a reflux pump and fill the heavy naphtha pumparound circuit. Start heavy naphtha pumparound circulation and during circulation, drain free water from the low points.

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The hot circulation on the slurry pumparound and HCO pumparound should be continued until feed is brought into the riser. Fill the fractionator reflux drum to normal liquid level with start-up naphtha to provide initial top reflux when feed is brought into the riser. 6.4.8 Wet gas compressor start-up Start-up of the wet gas compressor at this stage is optional. The only consequence of delaying the compressor start-up until feed is brought into the riser is that more gas will be vented to flare. It is recommended that Wet gas Compressor to start operation after reactor feed cut-in as enough gas is available, and avoiding surge concerning. If the molecular weight of the fuel gas is too low this may cause surging of the compressor. If this is the case the molecular weight may be increased by bringing LPG into the fuel gas system, using LPG vaporizer E-3701 in the fuel gas system (Unit 37). Communicate operation of Fuel Gas supply system. To start the wet gas compressor introduce fuel gas to the system via HIC-434 at the main fractionator overhead, and 3” fuel gas supply to the interstage KO drum. Open the suction and discharge valves and start the compressor following the vendor’s procedures. If gas is not being produced from the reaction section, it will be necessary to bring in more fuel gas as the fractionator pressure will decrease as the compressor is started. When required, start the fractionator overhead air cooler and compressor intercooler and start cooling water to the fractionator trim condenser and compressor interstage trim cooler. The wet gas compressor is run on full spill-back until gas is available from the fractionator reflux drum. Dry gas seal of the wet gas compressor is normally supplied from the treated off gas. When starting the wet gas compressor, use nitrogen for the source of dry gas seal. Soon after the wet gas compressor is operating and treated gas being available switch over seal gas source from nitrogen to treated gas. 6.4.9 Start up Procedure of Wet Gas Compressor Check instrumentation and commission any instruments not already in operation. Prepare to startup the wet gas compressor (C-1551) in accordance with manufacture’s instructions. The steam turbine driver exhausts to a surface condenser which must be placed in operation prior to the compressor. 1. Nitrogen Purge of Compressor Purge all air from the compressor by Nitrogen prior to unblocking the suction and discharge lines for both stages. 2. Lube Oil and Dry Gas Seal The lube oil and dry seal gas systems should be in operation per manufacturer's recommendations. 3. Open Compressor Isolation MOVs Slowly open the suction MOV and allow the pressure in the compressor to equalize with the connecting piping and vessels. Add fuel gas as necessary to maintain pressure in the unit. 4. Draining Check drain from suction line and the compressor casing to remove any liquid. 5. Line-up Make sure the line-up as follows:

Spillback valves UV-701 and UV-702: Full Open

MOV-703/704/705/706: Full Open 6. Increase Fuel Gas Injection Increase the fuel gas makeup to the Compressor suction KO drum to provide an operating cushion before starting the gas compressor. Maintain the Main Column overhead pressure at 0.7 kg/cm2g 7. Interstage Coolers Make sure operation of inter cooler and trim cooler by opening the cooling water to the interstage trim cooler.

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8. Start Compressor Start the compressor on line according to manufacturer's procedure. Watch the pressures in the Main Fractionation main column receiver (D-1514), the compressor suction drum (D-1551) and the compressor interstage suction drum (D-1552) carefully. Add fuel gas as necessary to maintain pressure. The compressor should be running at the minimum normal operating speed with the spillbacks open and PCV-733 closed condition at outlet of the fuel gas absorber outlet drum D-1559. 9. Pressurize System Watch the pressures in the Main Fractionation main column receiver (D-1514), and the compressor interstage suction drum (D-1552) carefully. Add fuel gas as necessary to maintain pressure. The system pressure may be increased up to approximately 5 kg/cm2g at Stripper to enable gasoline cold circulation. 6.4.10 Inventory Gas Concentration Section and Naphtha Circulation Once the vessels are under pressure with fuel gas, they can be inventoried with start-up naphtha and internal circulation can be established. This will allow smoother control of levels and flows while feed is being started from the Main Fractionation Section. This must be coordinated with the Fractionation Sections as the initial inventory is provided through the normal operating flow schemes. 1) Preparation Prior to introducing start-up naphtha, establish the stripper (T-1552) pressure higher than the debutanizer (T-1554) pressure by 3 kg/cm2 if possible. The stripper (T-1552) bottoms are pressured to the debutanizer (T-1554) and there must be enough pressure available to allow flow between the two vessels if circulation is to be established. 2) Inventory Startup Naphtha to Main Column Receiver Start up naphtha is introduced to the Main Column Receiver Drum (D-1514). Once the Main Column Receiver (D-1514) is inventoried and levels are stabilized, naphtha can be brought into the primary absorber (T-1551) using the overhead liquid pumps (P-1518A/B). 3) Inventory Naphtha to Gas Concentration Section Start the flow slowly and do not lose the level in the Main Column Receiver (D-1514). Continue make-up naphtha flow from storage as necessary. Build a high level in the primary absorber (T1551) bottoms and then start flow to the high pressure separator condenser (E-1554). Continue to establish levels in the high pressure separator (D-1553), the stripper (T-1552) and the debutanizer (T-1554). 4) Establish Naphtha Circulation Once a level is in the bottom of the debutanizer (T-1554), then bottoms liquid to recycle gasoline back to the Main Fractionation column receiver (D-1514), using start-up circulation line (6”-PL-150761). Once all levels are established, the make-up start-up naphtha to the Main Fractionation Receiver can be stopped. Continuous circulation from the main column receiver (D-1514) through the primary absorber (T-1551), the high pressure receiver (D-1553) should now be in operation. Control may be somewhat difficult due to low flow rates so it is important that all levels are carefully monitored. Also the pressure differential between the stripper (T-1552) and the debutanizer (T-1554) must be maintained monitoring compressor operation. At this moment, for the debutanizer overhead pressure control, to maintain stable pressure in the column at approximately 2 kg/cm2 of differences between T-1552 and T-1554. Or, if Stripper pressure is not enough due to lack of compressor head with low molecular weight gas, the Debutanizer pressure may be lowered to enable naphtha transfer from Stripper to Debutanizer.

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6.4.11 Heat Up the Stripper and Debutanizer Heat to the stripper (T-1552) and debutanizer (T-1554) is supplied from the circulated LCO and HCO from/ to Main Fractionation Section. It is desirable to warm up the reboilers on these vessels prior to start up if possible. This is entirely dependent upon available heat from the Main Fractionator and must be closely coordinated with the warm-up activities of Main Fractionator to prevent too much heat removal from the Main Fractionator (T-1501). (1) Heat up Debutanizer Reboiler Begin a small flow of heavy cycle oil (HCO PA) through the debutanizer reboiler (E-1560AB). It may be necessary to use the control valve bypass on the HCO flow to limit heat removal from the Main Fractionator (T-1501). Watch the bottoms level so as to not boil away all the naphtha and monitor the debutanizer (T1554) temperatures. Do not overheat the column. (2) Heat up Stripper Reboiler Begin a small flow of light cycle oil (LCO PA) through the Stripper Reboiler (E-1557). Again this must be closely coordinated with the warm-up activities of Main Fractionator to prevent too much heat removal from the Main Fractionator (T-1501). During this start-up, sampling is needed to frequently check there is no water content in pumparound stream. The bottoms level and the temperatures in the stripper (T-1552) must also be monitored for proper heating up. (3) Inventory Secondary Absorber Begin a small flow of lean oil to the Secondary Absorber (T-1553) from the Lean Sponge Oil Pump (P-1513AB) and establish a level in the bottom of the secondary absorber (T-1553). If possible begin to circulate this hydrocarbon back to the Main Fractionation section. This flow depends upon the sponge absorber pressure, which depends upon the compressor operation with low molecular weight gas, being higher than the LCO return pressure so it may not be possible to establish this flow until normal operating pressure is achieved in the secondary absorber (T1553). 6.4.12 Introduction of feed 1) Fractionation section Prior to introduction of feed, the slurry pumparound and HCO pumparound circuits are on hot circulation. Ensure that there is always a sufficient flowrate to the grid (Bed 5) during start-up and subsequent normal operation. Failure to maintain adequate flow to the grid will result in coking. The LCO pumparound should be checked for water. Cooling water flow should be established through all water cooled exchangers. Steam can be started to the HCO and LCO strippers. Switch the slurry MP steam generators and HCO MP steam generator to normal operation by shutting off the medium pressure heating steam and admitting boiler feed water. Bring in boiler feed water to the HP steam generators. After feed is introduced to the fractionator and as the slurry pumparound temperature increases, initially send steam to atmosphere via start-up silencers. Open the block valves in the lines to the steam headers and pressurize the steam generators by throttling the valves in the lines to the silencers. During start-up both the continuous and intermittent blowdowns can be used to bring the blowdown water within specification. The main fractionator bottoms level should be closely monitored as it may increase when feed is introduced. Shortly after feed has started the slurry should be checked for catalyst. This will indicate if there is excessive catalyst carry-over from the reactor. This should be checked several times per shift until operation has stabilized. If the wet gas compressor was not already started it will now be necessary to do so. Open the isolation valves and start the compressor according to the vendor’s procedures.

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The compressor must be started smoothly to prevent any pressure surge on the main fractionator, which could upset catalyst circulation. As liquid builds up in the interstage drum start liquid flow to the HP separator drum. When the level starts to rise in the fractionator reflux drum, slowly start reflux to control the overhead temperature. The temperature should be kept high enough to prevent condensation of steam at the top of the column. Start the overhead sour water pumps and send the sour water initially to the sour water stripper. Start slowly drawing off LCO to the stripper and adjust the stripping steam rate, and prepare to start the LP steam generator. Send the LCO to slops, before sending LCO to storage. Start drawing off heavy naphtha to the stripper and start reboiling the stripper with the HCO pumparound. Send the heavy naphtha to slops. Start drawing off HCO to the stripper and adjust the stripping steam and prepare to start the LP steam generator. When the level in the stripper starts to rise switch the flushing system to HCO. When stable operation is reached in the fractionation section, start the water wash to the overhead condenser. 2) Stripper, absorbers and debutanizer The HP separator drum, primary absorber, secondary and fuel gas absorber are pressurized with gas coming from the wet gas compressor. Open the line to flare at the outlet of the fuel gas absorber outlet K.O. drum and set the pressure controller at the top of the secondary absorber. When the liquid level rises in the fractionator reflux drum, start the overhead liquid pumps and send liquid to the primary absorber. When the liquid level rises in the HP separator, start the stripper feed pump and begin to feed the stripper. When heat is available from the LCO pumparound, start reboiling the stripper. Liquid from the stripper is pressurized to the debutanizer. When a level is established in the debutanizer start reboiling with the HCO pumparound. When the level in the debutanizer reflux drum starts to rise, start the debutanizer reflux pump. During the start-up period, light ends may be carried over to the debutanizer and it may be necessary to vent the reflux drum to the flare. In the absorber section, start the lean sponge oil pump and feed lean oil to the secondary absorber on flow control. When there is a liquid level in the secondary absorber start sending rich oil back to the main fractionator on level control. When the level rises in the debutanizer reflux drum, start sending LPG to the LPG amine absorber. When a level is established in the debutanizer bottom, flow of gasoline is started to slops, via the stripper first reboiler, air cooler and water cooler. Start the gasoline recycle pumps and slowly start circulation to the primary absorber. Adjust the reboiler duty of the stripper. Start amine flow to the fuel gas absorber and switch the outlet of the fuel gas absorber from flare to fuel gas. When stable operation of the gas plant is reached, start the water wash to the wet gas compressor intercooler. 3) LPG amine absorber Prepare the LPG amine absorber for start-up prior to introduction of feed. The section is under nitrogen pressure. Start slowly the flow of lean amine to the LPG amine absorber and fill up to 50% of the level control range. Vent nitrogen to the flare as necessary. When LPG is available in the debutanizer reflux drum, introduce LPG to the bottom of the absorber and slowly fill the top of the absorber and the coalescer. Vent nitrogen to flare as the system is filled. Set the lean amine at design flowrate and start sending LPG to the LPG treating unit

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7


NORMAL OPERATION OF THE UNIT

7.1 Summary of operating conditions For the sake of easy reference throughout this section, a summary of the operating conditions is given below. For more details refer to the Process flow diagram(s) and Basis of design. The parameters marked * are those which can be set by operators and must be set as indicated in order to achieve the above objective. The other parameters are expected ones and depend upon the conditions (flow rate, feed quality...) at the time. The figures shown are related to the normal operating flow and design feed. Bach Ho Bach Ho Mixed Mixed Reaction-regeneration

Riser • Outlet temperature* • Feed flow rate* • Feed temperature* • Recycle flow rate* • Recycle temperature • MTC flow rate* • MTC temperature • Dispersion steam flow rate* • Riser steam temperature • Backflush oil Disengager/stripper • Dilute phase pressure* • Stripping steam flow rate* Regenerator 1 • Dilute phase temperature • Dense phase temperature • Dilute phase pressure* • Coke burnt • Flue gas composition • CO • CO2 • Air ring flow rate* • Air blower temperature Regenerator 2 • Dilute phase temperature • Dense phase temperature • Dilute phase pressure*

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Maxi Gasoline

Maxi Distillate

crude Maxi Gasoline

crude Maxi Distillate

°C kg/h °C kg/h °C kg/h °C kg/h

518 407 000 290 0 0 20 350

505 407,000 290 117,100 0 20,350

520 407 000 170 0 76 400 181 20 350

511 407 000 170 117,100 0 20 350

°C kg/h

250 7379

250 6875

250 7605

250 7097

kg/cm2g

1.43

1.43

1.43

1.43

14 300

14,300

14 300

14 300

°C °C kg/cm2g

646 651 2.28

631 636 2.28

678 683 2.28

641 646 2.28

% % mole % mole % kg/h °C

70

70

70

70

5.3 10.6 181 520 232

5.3 10.6 166,575 238

6.3 9.9 261 840 210

6.2 9.9 215,357 223

°C °C kg/cm2g

734 713 1.3

720 695 1.3

772 762 1.3

733 712 1.3

kg/h


Maxi Distillate

Mixed crude Maxi Gasoline

Mixed crude Maxi Distillate

0 16.9 1.8 38 773 232 47 832

0 16.9 1.8 31685 238 47832

0 16.9 1.8 79 610 210 47 832

0 16.9 1.8 57261 223 47 832

t/min t/d

0.94 5.57 37.7 5.5

0.91 5.27 35,7 5.5

1.22 6.34 42.9 15.2

0.99 6.43 43.6 15.2

wt ppm wt ppm wt % wt %

0 1 776 75 80.76

0 1776 60

6 748 3 213 68 79.94

6 748 3 213 55

Reaction-regeneration

• Flue gas composition • CO • CO2 • O2 • Air ring flow rate* • Air blower temperature • Air lift flow rate* Catalyst • Delta coke • C/O • Catalyst circulation • Catalyst make-up* (dry basis) • Metals on catalyst V Ni • Catalyst activity MAT • Standard conversion

% mole % mole % mole % kg/h °C kg/h wt %

Bach Ho

Bach Ho

Maxi Gasoline


7.2 Control philosophy of the process The R2R unit will operate in a stable manner over a wide range of conditions. Careful attention to unit performances and process variables will result in an operation of maximum profitability with few problems and upsets. As a general rule any change in the vessels should be done slowly in gradual increments for stable catalyst circulation. In the present chapter we will look at these variables again from more practical standpoints such as MTC control. The most critical control loop on the converter is the Riser Outlet Temperature. The temperature should be controlled within ± 1°C of the set point. A thermocouple located near the outlet of the riser measures the reaction temperature. The temperature is a function of the amount of catalyst admitted to the riser by the regenerated catalyst slide valve. Reaction temperature is basic primary variable to the conversion of RFCC feedstocks. To enhance fresh feed vaporization and ultimately the product yields, mixed temperature control (MTC) technology is used. MTC flow rate is set to maintain the desired temperature at the fresh feed injection point. A thermocouple TI-008 located uptream of the MTC injectors measures the catalyst / vapor mixture temperature. The spent catalyst slide valve controls the catalyst stripper level by modulating the flow of spent catalyst from the catalyst stripper to the first stage regenerator. The catalyst level in the stripper is measured by differential pressure instruments and sends a signal to the controller which sets the position of the slide valve. A minimum level is required in the catalyst stripper to ensure good stripping of hydrocarbons from the catalyst and to provide a seal at the diplegs outlet of the Riser Outlet Separation System.

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The level in the first stage regenerator is measured by a differential pressure instrument that signals a level controller which resets the position of the plug valve. The plug valve modulates the flow of catalyst from the first stage regenerator into the lift to the second stage regenerator. A minimum level must be maintained in the first stage regenerator to ensure good regeneration and to seal the cyclone diplegs. A low level in the regenerator may unseal the diplegs which could result in backflow of flue gas up the diplegs and loss of catalyst fines with the flue gas. A high level in the first stage regenerator can also result in catalyst carryover from the cyclones because of higher entrainment from the bed and reentrainment from the cyclone dust bowls. During normal operation, the second stage regenerator level is not controlled, but follows the unit inventory. This level is monitored and adjusted by continuous withdrawal as the level builds through catalyst addition. The level in the second stage regenerator must be held within certain limits for the same reasons as stated above for the first stage regenerator. The total daily amount of catalyst withdrawal is adjusted by timer setting taking into account the operation requirements for the overall catalyst balance. The regenerators pressures are controlled by flue gas slide valves which throttle the flow of flue gas from the vessels. The pressure of the first stage regenerator is directly controlled by the first regenerator flue gas slide valve. The differential pressure between the first stage and second stage regenerators is controlled by the second regenerator flue gas slide valve. This differential pressure is set to provide adequate pressure drop across the plug valve for stable control of the regenerators levels. The disengager pressure rides on the main fractionator pressure which is controlled at the main fractionator overhead receiver. The objective in operation is usually to set the main fractionator pressure to a base level for efficient operation and the regenerator vessel pressures to result in approximately equal differentials across the catalyst slide valves. As a general rule any change in the vessels should be done slowly in gradual increments to allow slide valves to reposition properly for stable catalyst circulation. The unit is designed to provide adequate slide valve pressure differential for safe operation. Override controls are provided for action in low slide valve differential upsets which close slide valves to prevent dangerous reverse flow. Normal catalyst slide valve differential is around 0.3 to 0.5 kg/cm² to provide stable control. Slide valve differentials above 0.7 kg/cm² are to be avoided because they may cause valve erosion. Negative differentials should never be permitted and the PDIC controls should be set to override the main controllers at 0.1 kg/cm². Smooth catalyst circulation is paramount for successful operation of R2R and is achieved by proper catalyst aeration and conveying in the transfer lines, as well as control of the unit pressure balance. An emergency shutdown circuit will close the catalyst slide valves automatically upon loss of feed and loss of combustion air. ♦

MTC control

Control of the feed and catalyst mix temperature is critical in order to vaporize all hydrocarbons that can be converted to lighter products. This can be achieved independently of the riser outlet temperature which is the primary reaction control parameter. Riser Outlet Temperature is maintained conventionally by regenerated catalyst circulation through the hot regenerated catalyst slide valve. The mix temperature, which can be measured in an appropriate location downstream from the feed injection point, is controlled by an additional liquid hydrocarbon injection point, provided a few meters above the feed injection.

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With MTC, it is therefore possible to raise the mix temperature while maintaining the Riser Outlet Temperature or even lowering it. Thus the optimum catalyst temperature, the target catalyst circulation, and the desired catalytic cracking reactions can be adjusted separately. The MTC technology offers the possibility of operating the feed injection zone at a higher temperature thereby promoting vaporization without reaching over-cracking conditions in the riser whose outlet is maintained at a lower temperature. MTC provides additional heat removal. Cooling is carried out by vaporization of the liquid hydrocarbons introduced at the MTC level. The heat absorbed by MTC vaporization is then used downstream in the fractionation section for steam production, preheating or reboiling. The nature of the recycle depends upon each situation. If heavy naphtha is used as MTC fluid, then MTC acts essentially as a heat sink. The aromaticity of heavy naphtha renders it essentially inert. As a result, LPG and light gasoline yields will be promoted and higher conversion levels will be achieved. When using heavy naphtha, the additional coke formed in the riser (delta-coke) will be minimized and the C/O ratio will therefore be increased. To avoid over-cracking, the Riser Outlet Temperature can be reduced by about 10°C when the recycle is 20% of feed. If the heat balance of the unit is not critical, heavier fractions such as Light Cycle Oil (LCO) or Heavy Cycle Oil (HCO) can be used. 7.3 Operating parameters Chapter 3.3.2 has listed the process variables, i.e. the variables (pressures, temperatures, catalyst activity, regenerators air balance, heat balance, feedstock quality, coke yield, delta coke, catalyst to oil ratio) which according to the thermodynamics and the kinetics have an impact on the reaction involved in the process. This rather theoretical approach did not outline whether the operators could actually change the considered variable. Chapter 3.3.2 has listed the effects of key process variables illustrating the role of adjusting these variables to achieve a particular process objective. In the present chapter we will look at these variables again from a more practical standpoint such as operating parameters and how the operators can actually use them to adjust the performance of the unit. 7.3.1

Capacity

The R2R unit is capable of operating in a stable manner at turndown capacity with some adjustment of the operating parameters. The mass flow of the circulating catalyst and combustion air is nearly proportional to the feed rate. The basic design of the unit has taken into consideration the turndown rates for catalyst velocities and air distribution at turndown rate. Proper air distribution and catalyst flow will be stable at turndown rates. During operation below design capacity, oil feed should be reduce proportionally to each feed injector. The quantity of dispersion steam, stabilization steam, and MTC steam should be maintained as per the design operating conditions. 7.3.2

Riser Outlet Temperature

The operating temperature of the riser outlet will normally be set to achieve the desired degree of conversion. Typically, a temperature of 510°C will correspond to a maximum distillate operation and a temperature of 525 to 530°C will correspond to a maximum gasoline operation. This temperature is controlled by the regenerated catalyst slide valve position allowing more or less hot regenerated catalyst to contact and mix with the incoming feed. When the hot catalyst contacts the feed in the bottom of the riser the oil vaporizes almost instantaneously. The homogeneous mixture of oil and catalyst reaches a

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temperature approximately 30 to 40°C higher than the top of the riser. The initial temperature shock causes thermal cracking, while catalytic cracking begins after the oil is converted to vapor, and the molecules contact the active catalyst sites. As the catalytic cracking progresses and the catalyst/oil mixture flows up the riser, the temperature drops since the heat of cracking is endothermic. At the top of riser the moles of products are 3.5 - 5.0 times more than the moles of fresh feed. The riser temperature has a complex interrelation with the other parameters in cracking. An increase in the riser temperature is generally accompanied by: ♦ an increase in conversion, ♦ an increase in dry gas yield, ♦ an increase in LPG production, ♦ an increase or a decrease (over cracking) in gasoline production depending on the reaction severity, ♦ an increase in gasoline octane, ♦ a decrease in LCO and slurry yield, ♦ a slight increase in coke production. These are only trends. A quantitative definition of the changes requires heat and material balances as well as yield correlations. The catalyst quality also affects the extent of the changes. 7.3.3

Disengager pressure

A lower pressure in the reaction zone thermodynamically improves product yields. However the choice of the pressure must take into account the equipment size and the minimum acceptable pressure considering the wet gas compressor. A pressure of around 0.8 to 1.4 kg/cm² g can be considered as an optimum value for very heavy feedstocks. Typically the pressure is maintained constant and is only changed to adjust disengager pressure during unit start-up or upsets. 7.3.4

Catalyst activity

In conventional gas oil cracking the catalyst activity is measured in two different ways, from actual operation and in the laboratory. In the current practice, an equilibrium catalyst sample is forwarded each week to the catalyst supplier laboratory. There, a standard test (feedstock and operating conditions) is performed to check catalyst activity. Other analyses such as surface area, density, pore volume, particle size distribution, metal content, are also reported. The catalyst activity, thus measured, relates to the conversion that the actual operating unit may experience with a different feedstock. The correlation of the laboratory measurement is somewhat loose on account of the difficulty in properly quantifying the differences not only in the feedstock, but also the relationship of the method to unit operation. This leads more to a directional relationship in the sense that higher activity catalyst in gas oil cracking leads to greater conversion. In residue cracking the catalyst activity does not necessarily hold the directional relationship between laboratory measurement and unit operation. The complexity of evaluation increases which necessitates the use of other parameters for relating to conversion. The catalyst surface area and the concentration of the deposited heavy alkali metals provide a more meaningful basis to predict unit performance. This is in

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addition to a detailed knowledge of the specific characteristics of the catalysts. While catalyst properties and predicted product state are originally derived at the catalyst development stage, the true performance of the catalyst can only be ascertained from unit operations. The catalyst activity is best measured by the unit operation. The conversion is calculated from unit yields, which include gas and coke productions. Close monitoring of the yields, changes in metal deposition and catalyst surface area are the best methods for maintaining the desirable level of activity. Catalyst activity should be interpreted to mean not only the level of conversion, but also the ability of the catalyst to yield the maximum amount of valuable products and high octane gasoline, while at the same time coke and dry gas productions must be minimized. Catalyst activity is maintained by the addition of fresh catalyst on a continuous basis. The required rate of addition varies depending on feedstock quality, desired level of conversion, operating conditions, and type of catalyst. Normally, addition at a rate of around 1 to 4 kg of catalyst per 1000 kg of feed are necessary to maintain desired conversion. Frequent monitoring of the equilibrium catalyst properties and level of metal contamination (i.e. Ni, V, Na, etc...) are required to provide optimum adjustment of the addition rate. 7.3.5

Regenerators air balance

The reduction of the coke on the catalyst to less than 0.05 wt % requires a predetermined amount of air regardless of how the air is distributed between the two regenerators. In a unit with one regenerator the required air rate would be the sum of what the two regenerators require as long as coke yield and the average flue gas composition are the same. Having two regenerators provides a flexibility of how to split the total air required. When certain constraints, such as the maximum regenerator bed temperature and desirable flue gas composition are imposed, the freedom to arbitrarily split the required air decreases. However, there is a great advantage in assigning a specific air rate to each regenerator. The first stage regenerator design temperature is 770°C, therefore the coke that should be burned must be controlled so that this temperature limit is not exceeded. The combustion of carbon monoxide is more rapid as the temperature increases over 650°C. This results in lower carbon monoxide concentration and greater air requirement as the regenerator bed temperature rises. When coke burns to form carbon monoxide and steam the heat generated is about half as much as when the same amount of coke burns to form carbon dioxide and steam. The higher temperature generated by greater carbon dioxide production further facilitates the burning of carbon monoxide. If the air rate is limited, then the conversion of CO to CO2 is controlled and the regenerator bed temperature is kept lower. But at the same time more coke remains on the catalyst. The objective is to determine an air rate to the first stage regenerator that will limit the bed temperature and yields carbon monoxide in the flue gas. The objective in the second stage regenerator is to burn all the remaining coke completely to carbon dioxide. The bed temperature is allowed to rise to around 810°C (mechanical design : 840°C). The air rate is adjusted to give 2 - 3 mole % of free oxygen in the flue gas which ensures that the carbon monoxide concentration in the flue gas is less than 0.05 mole %. The above split of the required air also has the advantage of minimizing catalyst deactivation. Most of the hydrogen contained in the coke burns in the first stage regenerator. The steam thus generated is at a lower temperature and causes less catalyst deactivation. Since only a small part of the total hydrogen contained in the coke is burnt in the second stage regenerator, the steam concentration is reduced in the higher temperature environment. The flue gas from each regenerator is routed separately which segregates the flue gases according to their carbon monoxide concentration.

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7.3.6 a)

Regenerator temperatures Dense phase temperatures

♦

First stage


The first stage regenerator dense phase temperature is a function of the riser temperature, the amount of coke burned, and the catalyst circulation rate. The temperature is controlled by varying the air flow to the vessel. The air rate should be adjusted so as not to exceed a temperature of 730°C. ♦

Second stage

The second stage regenerator dense bed temperature is also a function of the amount of coke burned and the catalyst circulation rate. The normal operating temperature is around 100°C higher than the first stage regenerator dense bed. Control of this temperature is not independent because the air rate to the second stage regenerator is adjusted to achieve complete CO combustion (i.e. 2 - 3 % mole O2 in flue gas) under normal operation. In any case, it is important to keep a minimum temperature in the catalyst dense bed, which is required for a proper combustion (around 680°C). b)

Dilute phase temperatures

The dilute phase temperature will normally run within 10°C of its corresponding dense phase temperature. The catalyst used, while not promoted, has properties which enhance combustion in the dense bed. These properties, together with proper inventory of catalyst in the dense phase, ensure that all oxygen required for combustion will be burnt away in the dense bed, removing the possibility of after burning. 7.3.7

Regenerators residence time

The catalyst residence time in the regenerators is a key parameter for the regeneration quality. The catalyst levels in the two regenerators are optimized depending on the regeneration temperatures to achieve the required inventories. Typically, a total residence time around 6 minutes for the two regenerators is sufficient to achieve a carbon on regenerated catalyst leaving the second regenerator of less than 0.05 wt %, which is considered as a target value for a good regeneration. During normal operation, care must be taken to keep the catalyst levels at their normal levels. Low catalyst levels will affect the regeneration quality, whereas high catalyst levels will affect the catalyst entrainment to the cyclones and consequently will increase the catalyst losses. 7.3.8

Regenerators velocities

The quality of the combustion depends on the catalyst fluidization. A good mixing between catalyst and air is required for the combustion and therefore turbulent flow is desired in the regenerators dense bed. The corresponding superficial velocities are in the range of 1 - 1.3 m/s. A minimum velocity of 0.5 m/s should be kept in any case (especially for reduced capacity operation). 7.3.9

Stripper operation

The removal of any light hydrocarbons which may remain with the catalyst after disengagement in the disengager / stripper is accomplished by steam injection into the stripper dense bed via different steam rings. The amount of steam is adjusted depending on the catalyst circulation rate and feed rate. The flow

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rate is adjusted on the main steam ring, keeping the flow rates on the lower ring and upper ring constant. Stripping efficiency is measured by the hydrogen content on coke. Stripping is considered as efficient when the hydrogen on coke is around 6 wt %. 7.3.10 Heat balance The reaction/regeneration section can be viewed as a closed heat exchange loop where catalyst is recirculated between a heater (regenerator) and a cooler (riser). Hot catalyst is cooled in the riser through vaporization and cracking of feed and is reheated in the regenerator by burning the coke produced during the cracking reaction. The riser outlet temperature controls the regenerated catalyst slide valve to provide sufficient flow of hot catalyst to maintain the riser at the desired temperature. Sensible heats represented by normal variations in riser and regenerator temperatures are very small when compared to the heat of combustion of coke (heating medium), the heat of vaporization of feed and the heat of cracking (cooling medium). The unit is heat balanced in the sense that the heat for vaporizing and cracking the feed is furnished by the combustion of the produced coke in the regenerator. An overall energy balance shows that the energy released by the combustion of coke (carbon and hydrogen) becomes: ♦ the sensible and latent heat of the flue gases, ♦ the sensible and latent heat of the disengager effluent, ♦ the heat of cracking. Expressed another way, the coke yield in this adiabatic process is essentially that required to satisfy the heat load. One of the unique features of the RFCC process is that it will always attempt to reach an equilibrium operating point that is heat balanced. That is, the dependent operating variables will automatically achieve conditions where enough coke is made to produce the required heat of combustion to heat and vaporize the feed, supply the heat of chemical reaction, and cover the various heat losses from the process. The most important independent variable in the RFCC unit is the Riser Outlet Temperature. Two other important independent variables are feed preheat temperature and MTC oil flow rate. A Riser Outlet Temperature is chosen based on the type of feedstock processed and the type of yields distribution desired. The heat of reaction, the coke make, catalyst circulation rate, and the regenerator temperature change as the Riser Outlet Temperature is varied. The feed preheat temperature, MTC oil flow rate, can be manipulated to control these operating parameters within their optimum ranges. The optimum ROT operation varies with feedstock and operational goals. If the feed temperature is reduced, more hot regenerated catalyst will be required to heat the reaction mixture. The regenerated catalyst slide valve will open and the catalyst to oil ratio will increase. Coke make will increase because of the increased catalyst to oil ratio. The lower heat input into the RFCC, from the feed preheat exchangers will be made up by burning the extra coke. As the regenerator temperature increases the catalyst/oil ratio will find a new equilibrium. Thus, feed temperature can be adjusted to affect conversion at the expense of coke make. If the feed quality changes such that coke make begins to increase the regenerator temperature will rise and the regenerated catalyst slide valve will close slightly as it senses the increasing temperature of the

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riser outlet. The catalyst-to-oil ratio then decreases, conversion decreases, and coke make decreases. Although the unit is now in a new, stable, equilibrium operating point, an adjustment of some other operating variable may be necessary to maintain the desired product distribution at the new heat balanced level. If the percentage of residue in the feedstock gets too high there may be no remaining flexibility for the heat balance. In this case, coke make due to the nature of the feed becomes the predominant source of coke and changes in catalyst-to-oil ratio have a smaller effect on overall coke make. In this case, an increase in the feed preheat may cause very high regenerator temperatures as the coke level builds up on the catalyst and significantly reduces the catalyst-to-oil ratio. Unacceptably poor conversion will result. If the MTC oil rate is increased, the Riser Outlet Temperature begins to decrease and the regenerated catalyst slide valve will open slightly as it senses the lower ROT. The catalyst-to-oil ratio then increases, mix zone temperature increases, conversion increases, and coke / slurry oil production decreases. When the set point of the riser outlet temperature is changed, the regenerated catalyst slide valve will immediately vary the catalyst-to-oil ratio to satisfy the new riser heat demand. Before the system reaches steady state and the regenerator equilibrates at a new temperature, the system will go through a transition stage due to the large catalyst inventory. During the transition, operating signals can be confusing. For example, a higher riser outlet temperature demands a higher catalyst circulation rate and a higher coke make. But the catalyst takes time to travel through the riser, disengager, stripper and the spent catalyst transfer line to reach the regenerator. The temperature in the regenerator will decline initially because of the immediate extra heat demand in the riser. Eventually, the unit will heat balance by producing more coke, and the regenerator temperature will rise. This higher temperature will cause the catalyst circulation rate to decrease. The system can eventually be returned to the optimal catalyst-to-oil ratio if the feed preheat temperature is adjusted to offset the additional riser heat demand. 7.3.11 Feedstock quality In catalytic cracking a hydrogen deficiency develops as the hydrocarbon molecule splits and requires that a hydrogen joins a cracked molecule. The higher molecular weight hydrocarbons have lower concentration of hydrogen than the lower molecular weight hydrocarbons. When the cracking process produces lighter hydrocarbons than the feed, the hydrogen is made available from the hydrogen of hydrocarbons with higher molecular weight. The molecule that gives up hydrogen can become deficient in hydrogen to the point that it turns into coke. Hence, it is easy to see that the yield of lighter hydrocarbons or the conversion depends on the total amount of hydrogen contained in the feed. API gravity and distillation determine the hydrogen availability to yield lighter products. Even when the distillation is not properly defined, the API gravity gives an indication of feed quality, since lower API gravity feedstock generally has a higher boiling range and less hydrogen. The metals, which are part of the RFCC feed, adversely affect performance. Nickel, vanadium, copper and iron carried by the feed will deposit on the catalyst sites and through a complex mechanism, lead to catalyst deactivation. The process is gradual up to a certain metal level on the catalyst, but above about 10,000 ppm of metals, deactivation becomes more rapid. If the metal concentration of the feed cannot be reduced to control this, then fresh catalyst addition replacing catalyst in the unit must be at a rate high enough to keep the metal concentration on the catalyst at the required level. Sodium and other alkali metals also act as catalyst poisons. Exceeding 1 ppm of sodium in the feed should be avoided. Also sodium decreases catalyst melting point making it more sensible to high temperatures. The nitrogen and the sulphur in the feed adversely affect cracking, but are less harmful. Both the nitrogen and the sulphur tie up hydrogen that could be used in the formation of valuable hydrocarbons.

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In addition to this, the ammonia that is formed is basic, and has a neutralizing effect on the acidic catalyst sites. The Conradson carbon in the feed was in the past believed to convert fully to coke. The coke on the catalyst surface must be burned off in the regenerator, and more coke produces higher regenerator temperatures. Hence, increasing Conradson carbon in the feed was expected to lead to inoperable conditions. In the development of the R2R process, the temperature limitation was raised to be able to handle higher coke burning rate. At the same time, it was noted that previous beliefs stating that 100% of the Conradson carbon converts to coke were false. Only about 50% of the Conradson carbon converts to coke, while the rest turns into gaseous products. As the Conradson carbon concentration increases, the second stage regenerator temperature has a tendency to increase. Adjusting certain operating parameters such as feed temperature, disengager pressure, atomisation steam flow, stripping steam flow, may compensate for this up to a point. Notes: 1. Do not put slops in the unit feedstock. Additives like copper, manganese, sodium, potassium, organic chlorides, lead from gasoline... will at least increase gas production and could damage catalyst. Nitrogen will also neutralize catalyst acid sites and will decrease conversion. 2. Recycle of the slurry backwash oil to feed injectors is NOT recommended. The recycle slurry will tend to increase both coke and dry gas production and will result in excessive erosion of the feed injectors. As result, this backwash material is directed to a single injector located in the top section of the riser, specifically designed for erosive service. 7.3.12 Feed temperature The preheat temperature of the feed must be adjustable: ♦ to ensure a proper oil viscosity (around 10 to 15 cSt maximum at the injector inlet) for proper atomization of the feed, ♦ to ensure a minimum temperature to avoid steam condensation in the feed injectors. The feed temperature must also be optimized depending on the heat balance. The feed temperature affects significantly the coke production and the second regenerator temperature (refer to the next section concerning the coke production). Note that an increase of the feed temperature will result in: ♦ a decrease of coke production, ♦ an increase of the second regenerator temperature. 7.3.13 Coke yield / delta coke / catalyst to oil ratio The catalyst to oil ratio (C/O) is defined as the rate of catalyst divided by the rate of fresh feed. The delta coke is defined as the difference between the coke percentage on spent catalyst and the coke percentage on the regenerated catalyst. The coke yield corresponds to the percentage of feed transformed into coke. These three parameters are correlated by the following equations: Coke yield = C/O x ΔCoke = T reactor + coeff x ΔCoke T reg 2 These relations reflect the heat balance between the reaction section and regeneration section. The three process variables will automatically achieve the conditions where the heat balance is satisfied. For a given feed quality and catalyst type, the coke production depends upon nothing except Riser Outlet Temperature and feed temperature. The unit will be optimized with the highest possible C/O and the lowest possible delta coke for the following reasons:

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• a higher C/O will provide: –

more active catalyst sites for the reaction,

–

a better contact between catalyst and oil,

– a higher heat transfer efficiency. This leads to higher conversion, i.e. larger total liquid, LPG, gasoline yields while slurry yield declines.

• a lower delta coke will provide: –

lower regeneration temperature.

C/O is increased by maintaining a minimum temperature for good vaporization, • the Riser Outlet Temperature is fixed by the operation mode (maxi gasoline or distillate mode). IFP has developed the MTC concept which allows to disconnect the heat balance between the reaction section and the regeneration section, providing supplementary flexibility for the unit operation. If the operation mode requires to decrease the Riser Outlet Temperature, the injection of a "cold" fluid, acting as a quench, helps to keep the feed mix temperature at a desired high value for sake of vaporization and heat transfer. Catalyst circulation / pressure balance Catalyst circulation results from different vessels elevations and from differential pressure created by various catalyst densities. Fluidized catalyst behaves very similarly to normal liquid fluids. Smooth catalyst circulation requires precise control of the unit pressure balance, through the precise control of the pressure in the vessels and the proper control of the densities in the catalyst dense beds and standpipes. The pressure in the disengager is controlled by the main column overhead receiver. The pressure in the disengager is higher than the receiver pressure by the amount of pressure drop through the main column, the condenser and the lines between top of the disengager and the receiver. The pressure in the disengager is normally kept as low as possible within the limits of the wet gas compressor. The first stage regenerator pressure is controlled by a double disc slide valve followed by a variable orifice and a differential pressure controller holds a constant differential pressure (around 0.7 kg/cm²) between the first and the second regenerator. The differential pressure between the two regenerators should be maintained constant for a smooth operation of the air lift. Flue gas slide valves should operate with a pressure differential between 0.3 to 0.7 kg/cm² for good control and minimal disk erosion. These valves are designed to never fully close by means of a mechanical stop or a slot cut into the disks. Complete closure of these valves could potentially overpressure the disengager / stripper / regenerator system. Pressure of the first regenerator must be controlled so that the differential pressures on the regenerated and spent catalyst slide valves are balanced satisfactorily, i.e. to obtain similar pressure drops through the two slide valves. The minimum required pressure drop through the slide valves for steady control of the valve is around 0.30 kg/cm². Maximum pressure drop should be limited to 0.7 kg/cm² for avoiding erosion problems.

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It is obviously essential for steady circulation that the pressure difference between the vessels be as consistent as possible. Toward this end, it should be noted that the stripper and first stage regenerator levels are kept steady. The second stage regenerator is allowed to float between its minimum and maximum levels. Catalyst circulation is controlled by the opening of the regenerated catalyst slide valve. The circulation rate cannot be measured directly; it must be calculated from the heat balance or estimated from the openings and pressure drops of the regenerated and spent catalyst slide valves. 7.4 Adjustment of operating conditions Monitoring and optimization of the performance of a RFCC can add significantly to the overall refinery margins. It requires careful data collection and validation procedures to ensure that a proper evaluation is made and the right conclusions are drawn with respect of the catalyst effects. The relevant data for this exercise include the unit conditions, feedstock properties, product yields and qualities as well as equilibrium catalyst analyses. Unit monitoring includes data collection, validation and interpretation. The number of available measurements will determine the extent of the evaluation. The required data can be grouped as follows:

• Feedstock properties (density, sulfur, metals etc..), • Mass balance data (product flows, densities), • Essential product properties (distillation, octanes, sulfur, viscosity), • Heat balance data (temperatures, flue gas composition, air rates), • Pressure balance data (vessels pressures, valves ΔP, standpipe operation, catalyst levels), • Equilibrium catalyst analyses (activity, surface area, metals, etc…). In most cases heat and mass balance data are available on a continuous basis from the process computer. Feed and product analyses are made periodically. The equilibrium catalyst analyses are normally available once per week. A careful survey of the operating conditions must be constantly performed. To minimize analyses, a good definition of essential product properties is required for the refinery engineer. Apart from that it is also important that the essential analyses are from samples taken at the same time. All this together allows a proper monitoring of the RFCC unit. The modification of the feedstock properties, operation mode (maxi distillate / maxi gasoline...) and catalyst activity (metals content, new catalyst) requires to adjust the operating variables. For the detailed monitoring of the operating variables, refer to section above. 7.4.1

Feedstock properties

The feed must be analyzed on a daily basis. The metals content must be carefully checked, especially the sodium content which should be limited to 2 wt ppm maximum to avoid catalyst poisoning and deactivation. Malfunctioning of crude desalters or processing of imported feeds contaminated with seawater are the typical causes of high sodium levels in most cases. The nickel introduced with the feed is partially passivated by passivator injection (Sb or Bi solutions). The passivation efficiency can be checked by measuring the ratio H2/C1 in the dry gas. This ratio should not exceed 1.0. Otherwise, the amount of passivator should be increased accordingly.

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Metals contents as high as 10000 ppm (total content) are acceptable on the equilibrium catalyst but sudden increases of metals in the feed, especially sudden changes in vanadium content, should be avoided. 7.4.2

Mass balance

To monitor the product yields, it is very useful to calculate the yields for constant cut points (typically 221°C TBP for gasoline end point and 360°C TBP for LCO end point). A TBP distillation curve of the total disengager effluent must be built based on the ASTM distillation and yield of each product. Product flow measurements must be corrected carefully in order to obtain accurate yields patterns. All the products are measured at the fractionation unit/gas recovery unit outlets except the coke production. For the coke production calculation, see next section, heat balance. 7.4.3

Product properties

Product properties will be checked regularly and the operating conditions will be adjusted to meet the desired properties: operating mode, cut points,... Some specific properties should be watched carefully, such as the slurry fines content in order to check any troubles on the disengager cyclones or such as the slurry viscosity in order to optimize the control of the main fractionator bottom. 7.4.4

Heat balance

In a commercial unit, the coke production will always be such that the energy released by the combustion of coke keeps the unit in heat balance. This energy is used in the regenerator to: • heat the spent catalyst from stripper outlet to regenerators bed temperature, • heat the air from blower discharge to the flue gas temperature, • compensate for regenerator heat losses. The heat transferred by the circulating catalyst provides the energy for: • vaporization of the feed, including the recycles, • heating any riser stabilization/dispersion medium, • the heat of reaction, • compensation of disengager stripper heat losses. The regenerators mass balance gives the coke production whereas the heat balance is used to calculate the catalyst circulation. The accuracy of the calculation depends mainly on the accuracy of the flue gas analyses. A) Coke yield It is possible to estimate the amount of coke burned in each regenerator when one knows the amount of air going to the regenerators and the flue gas analysis (CO, CO2, O2). "A" is flow rate of air to the regenerator expressed in kg/h. CO, CO2, O2 are % moles in the flue gas sample where all the water from combustion and from air humidity is supposed to be condensed (dry sample).

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One can therefore assume that the concentration of nitrogen N2 in % moles in the dry flue gas sample is: N2 = 100 - (CO + CO2 + O2 + H2 + CH4 + C2H6) In the air to the regenerators there are:

A x 0.79 kmoles of nitrogen 29 The amount of nitrogen moles crossing the regenerators does not change and if "NFG" is the amount of dry flue gas moles not including the water, it is possible to write that:

NFG x N 2 A = x 0.79 100 29 Therefore:

NFG =

A 100 x 0.79 x N2 29

The amount of carbon moles burnt in the flue gas is the amount of moles of CO + CO2. That is:

CO + CO 2 x NFG 100 Therefore the weight of burnt carbon is:

12 x A x 0.79 x (CO + CO 2 ) N 2 x 29 The weight of carbon "CB" burnt in the coke is: "CB" =

0.328 x A x (CO + CO 2 ) kg/h N2

The weight of stripped carbon "CS" in kg/h is: "CS" =

0.328 x A x (CH 4 + 2 x C 2 H 6 ) kg/h N2

The number of moles of oxygen in the air to the regenerators is calculated from H2O, O2, CO and CO2 in the flue gas. The number of moles of oxygen in the air is:

A x 0.21 kmoles 29 The number of moles of oxygen in the flue gas calculated from CO, CO2 and O2 is:

NFG ⎛ 1 ⎞ CO⎟ ⎜ O 2 + CO 2 + ⎝ ⎠ 100 2 Therefore the number of moles "O" of oxygen which are found in the flue gas under H2O is:

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"O" =


0.79 (O 2 + (0.5 x CO ) + CO 2 ) A x 0.21 A x 29 N2 29

or: "O" =

A ⎛ 0.79 ⎛ 1 ⎞⎞ x ⎜ 0.21 x ⎜ O 2 + CO 2 + CO⎟ ⎟ ⎝ ⎠⎠ 29 ⎝ N2 2

The weight of water made from the hydrogen of the coke is: "O" x 2 x18 Therefore the weight of hydrogen burnt in the coke "HB" is: "HB" =

"HB" =

2 x "O" x 2 x 18 = 4 x "O" 18

4A ⎛ 0.79 ⎛ 1 ⎞⎞ x ⎜ 0.21 x ⎜ O 2 + CO 2 + CO⎟ ⎟ ⎝ ⎠⎠ 29 ⎝ N2 2

or "HB" =

⎛ A 0.79 ⎛ 1 ⎞⎞ x ⎜ O 2 + CO 2 + CO⎟ ⎟ (kg/h) x ⎜ 0.21 ⎝ ⎠⎠ N2 2 7.25 ⎝

The weight of stripped hydrogen "HS" is:

H 2 + (2 x CH 4 ) + (3 x C 2 H 6 ) x NFG 100 2 x A x 0.79 x (H 2 + (2 x CH 4 ) + (3 x C 2 H 6 ) ) "HS" = 29 x N 2 "HS" = 2 x

The weight of stripped coke is: Stripped coke = "CS" + "HS" The weight of coke burnt is: Coke burnt = "CB" + "HB" The total amount of coke is: Total coke = "CS" + "HS" + "CB" + "HB" B)

Catalyst circulation rate

The catalyst circulation rate can be estimated by two different methods: • By the heat balance around the regenerators. a)

• By calculating the catalyst circulation through the slide valves. Catalyst circulation rate from heat balance

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Likewise previous calculation of coke production, the following formulas apply as well for the first regenerator as for the second regenerator. The goal here is to get a simple but reliable circulation rate calculation. For this purpose, the following approximation have been made: • Sulfur in coke is not taken into account. • Specific heats are kept constant, corresponding to an average temperature.

The general formula is yielded from the heat balance around the regenerator:

CCR =

Hair + Hcoke + Hcombustion - Hdesorption - Hflue gas Losses CpCAT x (Tout - Tin )

with

CCR

= Catalyst Circulation rate

(kg/h)

CpCAT

= Specific heat of catalyst = 0.2862

(kcal/kg/°C)

Tout

= Regenerator dense phase temperature

(°C)

Tin

= Catalyst inlet temperature

(°C)

Hair

= Wet air enthalpy

(kcal/h)

Hcombustion

= Coke combustion enthalpy

(kcal/h)

Hflue gas

= Flue gas enthalpy

(kcal/h)

Losses

= Heat losses

(kcal/h)

Hcoke

= Enthalpy of coke burnt in the vessel

(kcal/h)

Hdesorption

= Coke desorption enthalpy

(kcal/h)

Wet air enthalpy calculation:

Hair = Qair [(1 - m) x [(CpN x WN 2 ) + (CpO x WO 2 ) + (m x CpW )] x (Tair - To) with

Hair

= Wet air enthalpy

(kcal/h)

Qair

= Air rate

(kg/h)

m

= Air water content (weight fraction)

CpN

= Nitrogen specific heat = 0.249 kcal/kg/°C

WN2

= Air nitrogen content = 0.768 wt fraction

CpO

= Oxygen specific heat = 0.223 kcal/kg/°C

WO2

= Air oxygen content = 0.232 wt fraction

CpW

= Water specific heat = 0.453 kcal/kg/°C

Tair

= Air temperature

(°C)

To

= Reference temperature = 0°C

(°C)

Coke enthalpy calculation:

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Hcoke = Qcoke1 x (0.24 x Tstripper + 12.96 x 10-5 x Tstripper2) with

Qcoke1

= “CS” + “HS” + “CB” + “HB”

(kg/h)

Tstripper

= Catalyst inlet temperature average stripper temperature (°C)

Coke combustion enthalpy calculation: Hcombustion = Qcoke2 x AA + BB

⎛⎛

⎞

⎞

⎟ AA = ⎜ ⎜⎜ ⎜ CO + CO ⎟⎟ x [(7.831 x FC O 2 ) + (2198 x FCO)]⎟ 2 ⎝ ⎠ ⎝ ⎠ C

BB = (28869 x FH ) - [((- 57.11 x FH ) + 440.78 ) x C] with

Hcombustion

= Coke combustion enthalpy

(kcal/h)

Qcoke2

= “CB” + “HB”

(kg/h)

C

= Coke carbon weight fraction

(kg/kg)

FCO

= Dry flue gas CO content mole fraction

(mole/mole)

FCO2

= Dry flue gas CO2 content mole fraction

(mole/mole)

FH

= Coke hydrogen weight fraction

(kg/kg)

Coke desorption heat calculation: Hdesorption = 354 x Qcoke3 x C with

Hdesorption

= Coke desorption heat

(kcal/h)

Qcoke3

= “CS” + “HS”

(kg/h)

C

= Coke carbon content weight fraction

(kg/kg)

Losses (including aeration enthalpy variation): Default values are 1.5 x 106 kcal/h Flue gas enthalpy calculation: Hflue gas = Qflue gas x [A + (B x (C + D + E + F + G + H + I ))] x (TFLUEGAS - TO ) with

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A

= y x CpW1

B

=

C

= 28 x CO x CpCO

D

= 44 x CO2 x CpCO2

E

= 32 x O2 x CpO2

0

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⎛ 1− y ⎞ ⎜ ⎟ ⎝ MW ⎠



F

= 2 x H2 x CpH2

G

= 16 x CH4 x CpCH4

H

= 30 x C2H6 x CpC2H6

I

= 28 x N2 x CpN2

Hflue gas

= Flue gas enthalpy

(kcal/h)

Qflue gas

= Total wet flue gas rate

(kg/h)

y

= Flue gas water content water/air wt fraction (kg/kg)

FCO

= Dry flue gas CO content mole fraction

(mole/mole)

FCO2

= Dry flue gas CO2 content mole fraction

(mole/mole)

FO2

= Dry flue gas O2 content mole fraction

(mole/mole)

FN2

= Dry flue gas N2 content mole fraction

(mole/mole)

CpCO2

= CO2 specific heat = 0.261 kcal/kg/°C

CpO2

= O2 specific heat = 0.223 kcal/kg/°C

CpCO

= CO specific heat = 0.262 kcal/kg/°C

CpN2

= N2 specific heat = 0.249 kcal/kg/°C

Tflue gas

= Regenerator temperature

MW

= Molecular weight of dry flue gas

(°C)

= (28 x FCO) + (44 x FCO2) + (32 x FO2) + (28 x FN2) + (2 x FH2) + (16 x FCH4) + (30 x FC2H6) FH2

= Hydrogen content mole fraction

(mole/mole)

FCH4

= Methane content mole fraction

(mole/mole)

FC2H6

= Ethane content mole fraction

(mole/mole)

FCpH2

= H2 specific heat = 3.483 kcal/kg/°C

FCpCH4

= CH4 specific heat = 0.788 kcal/kg/°C

FCpC2H6

= C2H6 specific heat = 0.703 kcal/kg/°C

FCpW1 = Water specific heat = 0.491 kcal/kg/°C Catalyst circulation rate from slide valves

b)

The circulation through a catalyst slide valve can be estimated as follows:

CCR = 0.036 x with

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A x OPEN x K x 2 x G x ρcata x ΔP 60000

CCR

= Catalyst circulation rate

(t/min)

ΔP

= Delta pressure through the slide valve

(kg/cm2)

ρcata

= Catalyst density

(kg/m3)

0

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c)


OPEN

= Percentage of open area if proportional. Usually the valve manufacturer provides the correlation between the open area and the valve stroke.

A

= Slide valve area at 100% opening

cm2

G

= Gravity acceleration

cm/s2

K

= Valve coefficient, typically 0.85, to be confirmed during unit operation.

Delta coke

The delta coke corresponds to the difference between the coke amount deposited on the spent catalyst and the coke amount remaining on the regenerated catalyst. This value can be determined by catalyst analyses. It can also be estimated roughly by the following correlation:

Δcoke =

Tbed regen2- ROT HCOOL + 100 195

with

d)

Δcoke

= Delta coke (wt %)

Tbed regen2

= Second regenerator dense phase average temperature (°C)

ROT

= Riser outlet temperature

(°C)

HCOOL

= Catalyst cooler duty (if applicable)

(106 kcal/h)

Overall heat balance

The achievement of the overall heat balance can be translated into the following equation: ηcoke = C/O x Δcoke with

7.4.5

ηcoke

= Coke yield

(wt %)

C/O

= Catalyst to oil ratio

(massic ratio)

Δcoke

= Delta coke

(wt %)

Pressure balance

An adequate pressure balance will ensure a smooth catalyst circulation in the unit. The key parameters are the catalyst slide valves pressure drops. A good pressure balance will result in equilibrated pressure drops through the regenerated catalyst slide valve and the spent catalyst slide valve (around 0.5 kg/cm2). The pressure drop through the valves should not be lower than 0.3 kg/cm2, to keep a sufficient margin to avoid reverse flow and should not exceed 0.7 kg/cm2 to avoid excessive erosion in the valve. The pressure balance results from the balance between the pressure lost to lift the catalyst (in the air lift and riser) and the pressure gained in the catalyst dense beds and standpipes. The monitoring of the pressure balance requires the checking of the catalyst levels in the vessels and the checking of the regenerated and spent catalyst standpipes behaviour. A) Catalyst levels

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Normal catalyst levels have been defined in the design. These levels must be kept as constant as possible, and in any case in between the operating margin (minimum level-maximum level). The levels should not be too high to avoid excessive catalyst fines carry-over to the cyclones and should not be too low to maintain minimum residence times in the vessels for proper stripping and proper regeneration.

There is no direct measure of the levels. The levels are measured through dP cells located in the dense beds: A first dP cell measures the pressure difference between the dense phase and the dilute phase. The height of catalyst above the lower pressure tap is then:

H =

dP1 x 10 4 d

with H

= Catalyst height above lower dP tap

(in m)

dP1

= Pressure drop

(in kg/cm2)

d

= Catalyst density

(in kg/m3)

L1 x S1 100

dP1 =

with L1 S1

H =

= Reading 0-100% on level recorder = Scale of level transmitter

(in kg/cm2)

L1 x S1 x 100 d

A second dP cell measures the catalyst density in the dense bed. This cell measures the pressure drop in the bed for a given and known distance between two pressure taps (typically 1.5 meters).

d =

dP2 x S2 x 100 L

with d

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= Catalyst density

(in kg/m3)

dP2

= Reading 0-100% on dPI recorder

S2

= Scale of dPI transmitter

(in kg/cm2)

L

= Distance between dPI impulse lines

(in m)



Finally, the catalyst level can be estimated by:

Hcata = Hlow + L x with Hcata

L1 x S1 dP2 x S2

= Catalyst level

(in m)

Hlow

= Elevation of lower level tap

L

= Distance between the two pressure taps of catalyst density measure (in m)

L1

= Reading on level recorder

(in %)

S1

= Scale of level transmitter

(in kg/cm2)

dP2

= Reading on dPI recorder

(in %)

S2

= Scale of dPI transmitter

(in kg/cm2)

The accuracy of the level measurement depends on the accuracy of the catalyst density measure. It is critical that the two pressure taps of the density measure are covered by catalyst. This means that during the catalyst loading, as long as the catalyst level has not reached the upper density tap, the measured density is not correct. It is recommended to use the design density during the loading. In case of failure of the density measurement, the design densities can be used to estimate the levels. Actual densities can also be determined by the fluidization curve which gives for each catalyst, the density versus the superficial fluidization velocity in the vessel. B)

Catalyst standpipes

A significant part of the pressure recovery in the unit takes place in the catalyst standpipes. It is important to check regularly the behaviour of the standpipes, especially the regenerated catalyst standpipe. The monitoring of the regenerated catalyst standpipe should be done in such a way that aerations are adjusted to keep a constant catalyst density along the standpipe. Aerations are located all along the standpipe. The purpose of these aerations is to compensate the air compression effect due to the pressure increase along the standpipe and consequently to maintain a constant density. An easy way to control the standpipe behaviour is to check pressure profile. The profile must be a continuous curve straight line showing the increase of pressure.

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Elevation top


Theoretical pressure recovery chart with correct individual aeration setting flow. Individual aeration rate shall be reset. Pressure decrease due the catalyst acceleration at the slide valve inlet. Pressure

Bottom

The aerations flow rates must be adjusted in order to obtain the smoothest profile. The aeration rate is proportional to the catalyst circulation rate.

7.5 Catalyst management 7.5.1

Catalyst analyses

The equilibrium catalyst analyses are carried out on a frequent basis, in order to monitor the catalyst performance in commercial operation and to optimize product yields and quality. A) Activity and selectivity A standard procedure to determine the activity of equilibrium catalyst by means of the Micro Activity Test (MAT) has been developed and standardized. In the MAT a sample of cracking catalyst is contacted with gas oil in a fixed bed reactor. Gas chromatographic analyses on gas and liquid products are used to determine the yield structure. MAT conversion (wt %) The MAT conversion or catalyst activity is calculated from the mass balance with: % conversion = 100 - LCO - Slurry = gas + LPG + gasoline + coke The equilibrium catalyst activity is measured at a set of standard conditions (constant cat/oil ratio, contact time, reactor temperature, etc,...). It can be related to the commercial unit performance, and allows the refiner to distinguish between catalyst activity effects and the influence of process or feed quality parameters. In general, a higher catalyst activity results in: • improved conversions, • higher regenerators temperatures, • lower cat/oil ratios. A detailed study of the unit performance should be made to find the optimum catalyst activity. Hydrogen factor (HF)

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The hydrogen factor is a relative number and is proportional to the specific hydrogen yield. Specific hydrogen is defined as: spec. H2 = H2 yield x (100 - conversion) / conversion The hydrogen factor depends on the catalyst quality and is affected by the nickel deposited on equilibrium catalyst. Only the trend of the hydrogen factor is of importance and this can be correlated with the H2/CH4 ratio in the unit. Coke factor (CF) The coke factor is a relative number, proportional to the specific coke, which is defined as: spec. coke = coke yield x (100 - conversion) / conversion Like the hydrogen factor, the coke factor is affected by metals deposited on the equilibrium catalyst. Only the trend is of importance, indicating the contribution of the equilibrium catalyst quality to the delta coke in the commercial unit. However the delta coke depends mostly on the feed quality and the catalyst activity. B)

Metal analyses

Usually, the X-ray fluorescence spectrometry is applied to determine the metals content of the catalyst. The metals on equilibrium RFCC include the heavy metals taken up from the feed. Alumina (Al2O3, wt %) Alumina is present in several components of the catalyst, such as zeolite, clay (kaolin) and active matrices. The total alumina content is the result of the contributions of each component. The alumina content of equilibrium catalyst can often be used to calculate the degree of exchange when switching to a catalyst with a different composition. Rare Earth (RE2O3, wt %) The rare earth content of the zeolite indicates its hydrogen transfer activity. A higher rare earth content results in more hydrogen transfer and consequently reduces the product olefinicity and research octane level of the gasoline. Cracking reactions are terminated by hydrogen transfer, thus reducing overcracking from gasoline to LPG. The rare earth content of the catalyst usually depends on both the zeolite type and the zeolite content of the catalyst. The specific activity (per m2/g surface area) increases in general with the rare earth content. Sodium (Na, wt %) Small amounts of sodium (0.1 - 0.4 wt %) are present in the fresh catalyst. Sodium can also be introduced by the feed. In case of high sodium levels on the equilibrium catalyst, the feed quality must be checked. The sodium content in the feed be limited to 2 wt ppm maximum. Vanadium (V, ppm) Vanadium is introduced with the feed and is deposited on the equilibrium catalyst. Under regenerator conditions, vanadium migrates and is able to enter the fresh catalyst and destroy the zeolite. As a consequence catalyst activity and conversion suffer. For conventional catalysts a rule of thumb is that 2 points catalyst activity are lost per 1000 ppm vanadium at constant unit conditions and catalyst consumption. As with sodium, the deactivation rate strongly depends on the highest temperature and the vapor pressure of water in the regenerator. Nickel (Ni, ppm)

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Like vanadium, nickel is introduced with the feed and deposited on the equilibrium catalyst. Nickel is not mobile under normal regeneration conditions and acts as a dehydrogenation catalyst. In RFCC nickel enhances non-selective cracking reactions, particularly those producing more hydrogen and coke. Antimony (Sb, ppm) Antimony is only present on equilibrium catalyst if an antimony passivator is used to reduce nickel activity. Approximately 30-50% of the value of the nickel content is sufficient to reduce hydrogen yields to an acceptable level. C)

Carbon on catalyst

In order to monitor the regenerators efficiency, the remaining carbon on regenerated catalyst is measured. The carbon on catalyst flowing from the stripper into the regenerator (spent catalyst) must be measured as well, allowing direct analysis of the delta coke level. The carbon is converted to carbon dioxide. Apart from measuring the carbon on regenerated catalyst (CRC), the carbon content can be estimated by the refiner by comparing the color of the equilibrium catalyst with the color of reference samples taken from the same unit. A high carbon content does not affect the measured activity but results in a loss of effective activity of the catalyst flowing into the reactor riser (1-2 wt % MAT per 0.1 wt % CRC). As a consequence the unit conversion and selectivities may change. An improved air and/or catalyst distribution results in a reduced carbon content. The efficiency of carbon removal also benefits from increasing the dense bed temperature. D) Physical properties Surface Area (SA, m2/g) RFCC catalysts in general contain micropores smaller than 2 nm (10 Ångstrom radius) that originate mostly from the zeolite, mesopores of 2-60 nm (10-300 Å radius), which provide the area often referred to as matrix surface area and the macropores, that allow penetration of large feedstock molecules into the catalyst particle. The latter have a negligible contribution to the surface area. The surface area in general is a measure of the catalyst activity and has a strong effect on the performance of the RFCC unit. However, when a switch to a different catalyst type is made, the surface area may change while the activity remains constant. As a high surface area also results in increased adsorption of hydrocarbons, a higher steam rate in the stripper may be required to keep the delta coke and regenerator temperature at acceptable levels. Apparent Bulk Density (ABD, g/ml) The apparent bulk density is determined by measuring the mass of a known volume of catalyst, settled freely under its own weight. The apparent bulk density is of importance for the circulation and cyclone efficiency. A higher bulk density in general means a higher particle density, which improves the efficiency of the cyclones. The effect of the apparent bulk density on catalyst circulation depends on the unit design and operation as well as the particle size distribution. Particle Size Distribution (PSD, wt %) The particle size distribution is determined using laser light scattering and is important to monitor the cyclone efficiency and catalyst circulation properties. If catalyst losses and the average particle size (APS) of the equilibrium catalyst both increase at the same time, the cyclone efficiency is reduced and

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damaged cyclones are suspected. This can be confirmed with PSD analyses of fines from the regenerators or disengager cyclones showing increased 40+ micron material. The coarser the equilibrium catalyst, the more difficult it is to circulate catalyst. If catalyst losses increase while the average particle size drops, then the cause may be related to: • soft catalyst usage (poor attrition resistance), • high velocities in the unit damaging the catalyst (hardware attrition source), • increased fresh catalyst and/or fines additions. The PSD of equilibrium catalyst is more affected by the attrition factors and cyclone efficiency than by the fresh particle size distribution. Fresh catalyst analyses Analyses that are only performed on fresh catalyst samples are the loss on ignition and attrition. Loss on Ignition (LOI, w %) The loss on ignition is determined by measuring the loss of weight (mainly water) upon ignition at 815°C for 1 hour. The measurement is required because catalyst is only paid for on a dry basis. In general the LOI has no influence on the performance of the catalyst Attrition Index (AI, w %) A sample of fresh catalyst is subjected to fluidization by high velocity air jets. In this process, wear on the particles occurs as they are blown against each other and against the wall with a high velocity. The fines formed are removed from the attrition zone and weighed. A lower attrition index means a higher attrition resistance. Low catalyst losses can be expected under normal unit conditions with attrition index levels up to 10 wt %. However, in some cases also higher values can be tolerated depending on the catalyst composition and its ageing in the regenerator. 7.5.2

Catalyst replacement

During normal operation, in order to keep a given catalyst activity, fresh catalyst is added on a semicontinuous basis. To keep a constant catalyst inventory in the unit, equilibrium catalyst is automatically withdrawn from the unit. Catalyst addition and withdrawal are done to/from the first regenerator. Three catalyst hoppers are installed in the unit: the spent catalyst hopper, the fresh catalyst hopper and the auxiliary catalyst hopper. The spent catalyst hopper is used for the unit inventory loading and unloading and for the continuous equilibrium catalyst withdrawal. The fresh catalyst and auxiliary catalyst hoppers are used for fresh catalyst addition. 7.5.3

Catalyst addition

Continuous addition of fresh catalyst to the RFCC is essential for at least three reasons: • to maintain an optimum catalyst activity and selectivity, • to keep metals on equilibrium catalyst at an acceptable level, • to make up the inventory of circulating catalyst, compensating for catalyst losses. The primary criterion governing fresh catalyst addition is activity maintenance. The following factors may serve as a guide for the catalyst replacement:

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• the optimum E-cat activity level as determined by feed quality, unit limitations and yield product quality requirements; • the range of metals, primary Ni, V and Na to be tolerated on the equilibrium catalyst, on a temporary or permanent basis; • the response of equilibrium (E-cat) activity to fresh cat addition. The optimum fresh catalyst activity level must be determined for any specific operation. Generally, the cleaner the feed, the higher the E-cat activity that can be applied to boost conversion. As the feed becomes heavier and more contaminated, more moderate catalyst activities are optimum, due primarily to heat balance constraints (i.e. the delta coke).

In principle three alternative catalyst policies exist: 1. Balanced addition: the amount of fresh catalyst added equals the catalyst losses. The optimum catalyst activity and selectivity is often not obtained with balanced addition only. 2. Catalyst withdrawal: the fresh catalyst addition rate is equal to the sum of catalyst losses and withdrawal. This type of operation is practiced to reduce metal poisoning, or to enhance catalyst replacement. 3. Catalyst flushing: the addition of E-cat or low activity flush catalyst is applied to avoid too high equilibrium activity or delta coke and reduce total catalyst costs especially during high losses, or a high metals operation. Two hoppers have been provided for catalyst addition. This allows to add simultaneously two different types of catalyst. It allows also to load one hopper from a truck using the ejector system while the other hopper can remain pressurized for the normal catalyst addition operation. A catalyst feeder is used to automatically add fresh catalyst at the desired rate. The feeder can be adjusted for batch size and frequency of additions. The catalyst feeders are directly located below the catalyst hoppers. The amount of catalyst introduced to the catalyst feeder is controlled by a weight cell and a diaphragm valve at the catalyst feeder inlet. When the desired weight is in the loader, the diaphragm valve closes. A switch is then activated which opens fluidizing and pressuring air to the feeder. The feeder pressures up to about 3.5 kg/cm2 g and another diaphragm valve opens which loads the catalyst into the first stage regenerator. It is possible to bypass the catalyst make-up feeders during operation for repairs. For detailed operation, refer to the Manufacturer’s instructions. 7.5.4 Catalyst draw-off As catalyst addition is higher than the catalyst losses from the unit, catalyst must be withdrawn in order to keep the unit inventory. This operation is achieved by a specific continuous draw-off system provided on the first regenerator. Hot catalyst is withdrawn by a ON/OFF valve actuated by timer, cooled down through a finned tube and sent to the spent catalyst hopper at a temperature below 400°C. The amount of withdrawn catalyst is controlled by a restriction orifice. For catalyst conveying and line cleaning, plant air is injected into the catalyst at line downstream of the restriction orifice by another ON/OFF valve actuated by timer. The plant air is set in order to limit the catalyst velocity in the draw-off line (10 m/s), to limit the erosion.

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The total daily amount of catalyst withdrawal is adjusted by timer setting taking into account the operation requirements for the overall catalyst balance.

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7.6 Operation of Fractionation and Gas Concentration Section 7.6.1 Fractionation section The Fractionation Section fractionates the vapor product from the Reaction Section. The products from this section are clarified oil, LCO, heavy naphtha and overhead liquid distillate and wet gas streams. A heavy naphtha lean oil stream from the fractionator goes to the secondary absorber in the Gas Recovery Section and the absorber rich oil is returned to the fractionator. There are two streams that can be recycled to the reaction section. For Maximum Distillate operation, for both the Bach Ho and Mixed Crude feeds, HCO is combined with the preheated feed to the riser. For Maximum Gasoline operation, only in the case of Mixed Crude feed, a heavy naphtha stream (MTC) is recycled directly to the riser. The main fractionator has a grid section at the bottom where the superheated vapor feed is desuperheated and the bottom product is condensed. Above the grid there is a wash oil structured packing section. Above this there are three heat removal (pumparound) structured packing sections and three trayed fractionation sections. Each section of the column has a relatively independent system for control of the fractionation and product draw-off rates. Product draw-off rates are interrelated ; a change in one product rate must be balanced by a change in one or more other product rates to maintain the material balance on the column. The basic parameters used to establish correct operating conditions in a section of the column are product end point and product separation. End point is corrected by adjusting product draw-off rate. Separation between products is corrected by controlling reflux rates in the column. This is done by adjusting pumparound duties. Product separation efficiency is determined from ASTM distillation curves for adjacent products. The basic criteria used in setting the fractionator operation are related to operating pressure and temperature profile. 7.6.1.1 Pressure control The main fractionator pressure is controlled at the reflux drum by speed control of the wet gas compressor in the gas recovery section. Pressure is not a process variable from an operation point of view and is not adjusted to correct product specifications. The unit has been designed to operate with a pressure of 0.4 kg/cm²g in the fractionator reflux drum. This pressure sets the pressure in the reactor, where low pressure is desirable to achieve good feed vaporization. 7.6.1.2 Temperature profile The major indicator for correct operation of the main fractionator is the column temperature profile. Temperature is the variable most responsive to changes in the operation of the column. For stable feed to the reactor and stable reactor operating conditions, the heat input to the main fractionator remains constant. The heat removal in the pumparounds and the product draw rates are the variables available to the operator in the operation of the column. A column side draw temperature is a good indication of the side draw end point. If draw temperature is recorded against on-specification product end points, the draw temperature can be used as a means of setting product end point. In a column with good fractionation, the relationship between end point and draw temperature will be fairly constant. Product draw rates, and hence product end point, are set based on draw temperature. If a product draw rate is increased, the end point increases. If the rate for one product is changed, the end point of the products below will also change, unless the rate of the product immediately below is changed to compensate for the change in the product rate above. If, for example, the heavy naphtha end point is too low, the draw rate is increased and hence the end point. If the LCO end point is not to increase, the LCO draw must be decreased accordingly.

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Separation requirements are achieved by adjusting the reflux rates in the various sections of the column. This is done by controlling the pumparound duties. If the pumparound duty is increased the vapor rate leaving the pumparound is reduced and hence the liquid reflux in the section above is reduced. A decrease in pumparound increases reflux in the sections above and therefore improves separation. For example, if it is required to improve separation between HCO and LCO, the HCO pumparound is reduced and more vapor leaves the pumparound section, bed 3. This additional vapor is condensed further up the column, resulting in higher reflux in trays 25 to 30. The duty decrease in the HCO pumparound must be compensated for by increasing the duty of the pumparounds above and/or the condenser. Reducing pumparound duties results in better separation at the expense of high level heat recovery. Each pumparound should be set to provide adequate fractionation between products while maximizing heat recovery. In practice, once the pumparound duties have been established to give good fractionation in the column they should not require changing, except for changes in feedstock rate and quality. With stable feed, the main changes carried out in the fraction section will be related to achieving end point and flash point specifications. 7.6.1.3 Bottom section The bottom pumparound flowrates and duty are set to maintain the bottom temperature at or below 340°C and to satisfy reflux and/or heat duty requirements in the sections above. The bottom pumparound duty determines the wash rate in bed 4, above the grid. If the bottom temperature is too high, coking on the grid and in the bottom of the column can occur. Coking is a function of both temperature and residence time. In the design, the column bottom has a reduced diameter to limit residence time and the bottom pumparound and quench are designed to limit temperature. It is essential to have adequate flow to the grid to ensure good distribution. The hot slurry by-pass and the flow control system allows for constant flowrate to the grid whilst allowing for changes in heat removal. For Bach Ho feed, slurry pumparound is required for unit feed preheat whereas it is not required for Mixed Crude feed. For other (non-design) feeds slurry may or may not be required for preheat, depending on the required temperature to the riser. Five HP steam generators (E-1503 A/B/C and E-1504 A/B) and two MP steam generators (E-1505 A/B) are provided. For the Bach Ho feed case the design is based on having two HP (E-1504 A/B) and two MP (E-1505 A/B) steam generators in service, along with the feed preheat slurry exchangers, E-1501A/B and E-1502 A/B/C. For this case, the slurry must be flushed from the non-operating steam generators and associated lines to prevent settling of catalyst fines. For the Mixed Crude feed, the design is based on all five HP and both MP steam generators in service. The preheat exchangers are not required and these must be flushed out. The total heat removal in the slurry pumparound is controlled by the temperature controller above bed 4 by resetting the flowrate of slurry through the HP and MP steam generators E-1504 A/B and E-1505 A/B or resetting the flowrate of slurry through HP steam generators E-1503 A/B/C. The bottom temperature is controlled by resetting quench flow from E-1504 A/B and E-1505 A/B, or by resetting quench flow from E-1503 A/B/C. 7.6.1.4 HCO section The HCO pumparound provides heat to the debutanizer reboiler and heavy naphtha stripper reboiler. Constant heat removal in the pumparound is controlled by controlling total pumparound flow, and by controlling return pumparound temperature by controlling heat removal in the HCO PA MP steam generator. HCO for flushing oil and for slurry separator backflushing is stripped in the HCO stripper. The stripping rate is set to adjust HCO flash point to ensure that there are no problems with pump seal flushing due to flushing oil vaporization. The temperature of the HCO is controlled by pressure control on the steam side of the HCO LPS generator.

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For the Maximum Distillate case for both Bach Ho and Mixed Crude feed HCO is recycled to the reaction section. The flowrate is controlled in the reaction section. The temperature of the recycled HCO is controlled by by-passing the HCO recycle MPS generator. A start-up line for E-1508 is provided from the outlet of E-1508 to the HCO pumparound return. 7.6.1.5 LCO section The LCO pumparound provides heat for the stripper second reboiler and is used to preheat the unit feed. The pumparound rate is on flow control and return temperature is controlled by controlling heat removal in the LCO PA BFW heater. The LCO draw-off rate controls the end point of the LCO product. An increase/decrease in draw rate will increase/decrease the end point. The TBP cut point range for LCO is 205°C – 390°C for Maximum Distillate operation and 205°C – 360°C for Maximum Gasoline operation. The total LCO for Maximum Distillate, 165°C – 390°C, is obtained by combining LCO from this section with the heavy naphtha cut. Adjust LCO flowrate to obtain the required ASTM end point and set stripping steam rate to meet the flash point specification. The initial point will be set by adjusting end point of the heavy naphtha draw. 7.6.1.6 MTC recycle The MTC (Mix Temperature Control) is drawn off the main fractionator at tray 20. The MTC is taken off at this point in the column to provide the appropriate stream composition to minimize cracking in the riser. MTC is used only for the Mixed Crude Maximum Gasoline case. The required flowrate is set in the reaction section. It may also be required for other non-design feed cases. 7.6.1.7 Heavy naphtha section The heavy naphtha pumparound is used to preheat the feed to the stripper and is also used for reboiling in the PRU. The pumparound is on flow control and the return temperature is controlled by controlling flow through the heavy naphtha pumparound air cooler. This air cooler is designed for the case when the PRU is not in operation. The lean oil for the secondary absorber is drawn off along with the pumparound. The flowrate is set in the Gas Recovery Section. Heavy naphtha product is also drawn off with the heavy naphtha pumparound. For Maximum Distillate operation, the heavy naphtha is combined with the LCO. For Maximum Gasoline operation, the heavy naphtha is combined with gasoline from the debutanizer and is sent to the gasoline treating unit. The cut point between LCO and heavy naphtha is controlled by the temperature controller below the heavy naphtha draw tray. This resets the heavy naphtha flowrate. The cut point between heavy naphtha and overhead distillate is controlled by fractionator overhead temperature controller resetting reflux flowrate. Alternatively, the heavy naphtha draw rate can be fixed on flow control and the temperature controller below Bed 1 can be switched to reset reflux flow. This controls total naphtha flowrate. For Maximum Distillate operation the overhead cut point is critical to ensure that the combined LCO flash point specification is met. Even with maximum reboiling of the heavy naphtha stripper, the flash point specification will not be met if the overhead cut point is too low. This temperature should be adjusted based on operating experience, in order to maximize total LCO product while meeting the flash point specification. For Maximum Gasoline operation the cut point between LCO and heavy naphtha is critical to ensure that the specified maximum gasoline ASTM end point (205°C) is not exceeded.

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7.6.1.8 Top section and overhead system As discussed for the heavy naphtha section, the overhead cut point is controlled by the temperature controller resetting reflux flowrate. A water draw-off tray is provided below the top tray. The normal overhead temperature is approximately 15°C to 20°C above the water dew point. If the column is operated at or near the overhead water dew point, water will condense. This can occur during start-up with the unit at turndown as the steam rates are not reduced proportionately to feed rate. Water is drawn off under interface level control to the inlet of the overhead air condenser. The water wash to the overhead condenser should be kept at the design flowrate to minimize corrosion. Overhead water is also sent to the wet gas compressor interstage cooler and some is sent to the sour water stripper to maintain the interface level in the reflux drum boot. Corrosion inhibitor is also injected in the overhead line. The inhibitor injection rate should be set initially at a rate corresponding to 10 wt ppm in the overheads. This rate can be reduced based on operating experience. 7.6.2

Gas Concentration section

7.6.2.1 Gas Concentration Flow Scheme The overhead wet gas and liquid distillate are separated in the gas recovery unit into gasoline, LPG and fuel gas. This is accomplished in a series of absorption steps to maximize LPG and C5+ recovery, a stripper to reduce H2S and C2 in the LPG and a debutanizer to separate LPG from gasoline. Fuel gas is treated in the fuel gas absorber and LPG is treated in the LPG amine absorber. Operating pressures are set by the design of the unit and are not considered as operating variables. 7.6.2.2 Wet gas compressor The wet gas compressor operation is controlled by the pressure controller on the fractionator reflux drum. This pressure sets the operating pressure on the reaction section. The pressure controller is set at the normal value. It is not an operating variable for the gas plant and is not normally adjusted. The primary control on the compressor is speed control of the steam turbine within the operating speed range. Secondary control is spill-back control on the two compressor stages. The compressor is protected from surge by the compressor anti-surge control system. For detailed operation of this compressor follow vendor operating instructions. The water wash to the inlet of the compressor intercooler must be maintained during normal operation to prevent corrosion. The water rate should be adjusted to the normal rate. 7.6.2.3 Primary absorber, secondary absorber and stripper The primary and secondary absorbers recover C3+ components from the fuel gas. In the primary absorber, most of the propane, propylene, butane and butylene is recovered from the gas stream from the high pressure separator drum. The lean oil streams to the primary absorber are the fractionator overhead liquid distillate and recycled light naphtha from the bottom of the debutanizer. The overhead liquid distillate rate and temperature are fixed by the fractionation section operation. The lean oil recycle rate from the debutanizer is set to obtain the specified C3 and C4 recovery. Increasing this rate will increase recovery, as long as the total liquid rate does not flood the column. The secondary absorber recovers practically all of the C5+ from the fuel gas. The lean oil to this absorber is a heavy naphtha stream from the fractionator. The rich oil is returned to the fractionator. As with the primary absorber, increasing lean oil rate will increase absorption as long as the liquid rate does not flood the column. In both absorbers, a decrease in temperature will improve absorption. The absorbers operating temperature is not considered as a variable. The design operating temperature has been set based on the design cooling water temperature, but will vary based on actual cooling water temperature. Correct operation of the stripper is critical to the operation of the gas recovery section. The feed preheat temperature should be set initially at the design value. If this temperature is too low, there may be water

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condensation in the stripper. If it is too high it can reduce C3 recovery. The reboil rate is reset by the stripper overhead flowrate. If the reboil rate is too high, and hence the stripping rate, the primary absorber can be overloaded, resulting in reduced C3/C4 recovery. If the reboil rate is too low, the C2 and H2S rates going to the debutanizer will be too high. The set point of the stripper overhead flowrate should be adjusted to optimize C3 recovery, while maintaining acceptable H2S and C2 concentrations in the debutanizer overheads. As an alternative to controlling reboiler rate by the overhead flowrate, the reboiler duty can be fixed based on operating experience. 7.6.2.4 Fuel gas absorber H2S and CO2 is removed in the fuel gas absorber. Set the lean amine rate at the normal flowrate and adjust as necessary to meet the fuel gas specification. The lean oil rate should also be set to maintain a maximum mole ratio of acid gas (H2S + CO2) to DEA of 0.4 in the rich DEA. The temperature difference between the fuel gas to the absorber and the lean amine is set by controlling the amine temperature, to maintain it approximately 15°C above the gas temperature. This is to minimize condensation of hydrocarbons in the rich amine. If there is a high pressure drop across the absorber, as indicated by the PDIC, this could be due to foaming. Inject anti-foam at a rate of 5 to 10 ppm in lean amine as required to prevent foaming. 7.6.2.5 Debutanizer The debutanizer is designed to separate the gasoline from LPG. The two specifications to be met are the vapor pressure of the gasoline and the C5 content of the LPG. Additionally, there is an overall C4 recovery specification. Generally, if this recovery specification is met, the gasoline RVP specification will also be met. The column operating variables are the reflux rate and the reboiler duty. The overhead C5 specification is controlled by the temperature controller in the top section of the column. Decreasing the temperature controller set point decreases C5 concentration in the LPG. The reboiler duty should be set manually to obtain the gasoline RVP specification and/or the overall C4 recovery. If the C2 content in the debutanizer overheads is too high the reflux drum pressure will rise. An HIC valve is provided to vent to flare. The stripper operating conditions should be adjusted to reduce C2 in the overheads and hence in the LPG product. 7.6.2.6 LPG amine absorber The LPG amine absorber removes H2S from the LPG prior to LPG treatment for the removal of mercaptans. The column operates liquid-filled, with the LPG rate from the column controlled by DEA/LPG interface level control. Set lean amine rate to meet the H2S specification and also to maintain a maximum H2S to DEA mole ratio of 0.4 in the rich DEA. Inject anti-foam at a rate of 5 to 10 ppm in lean amine as required to prevent foaming.

7.7 Supporting Facility Operation 7.7.1 Steam Generation Blow-down Operation The design intention is that the following steam blow down is recommended for MPS and HPS steam generator to maintain the quality of the generated steam, which are used for turbine. -

Continious blow down : 3.0 % of BFW feed

-

Intermittent blow down : 10 % of BFW feed

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For LPS Generator, the facilities are provided to cover continious and intermittent operation, but blow down operation is normaly not required, since LPS is not used for the turbine. Most of LPS is used for stripping steam or heating steam. Phospate chemical injection is required in case steam generators operates blowdown operation. It intended the dosage of phosphate is to maintain 10-20 wtPPM, referring conductivity of BFW in the generator. Therefore inject phosphate at the following flow rate (10 PPM case): Net Inj Rate kg/hr = Blow down BFW (kg/hr) x (10 /1000,000) Actual Inj Rate of solution = Net Inj (kg/hr) / ( Wt % Concent /100) Phosphate solution is prepare by injection package X-1510. For COB/WHB package, the operation concept is as same as steam generation of the process heat exchanger that injection of phosphate should be adjusted, referring sampling data of BFW in the steam drum of WHB, and continious blow down flow rate. 7.7.2 Slurry Separator Operation 1) Back Flushing Frequency Back flsuhing frequency is depended on the catalyst content in feed oil. For the design purpose, the following are considered. Therefore, back flushing frequency should be adjusted as concentration of catalyst (PPM) in feed slurry oil. Catalyst in feed Back flushing Average flushing oil Times/Day M3/hr Wt PPM 1,700 83 4.2 4,300 209 11.8 2) Temperature Control Maintain operating temperature at 170 deg C, by adjusting operating pressure of E-1506A (or B) LP steam side. Operation temperature of back flushing oil (HCO) should be the same level temperature of slurry feed temperature. 3) Back Flushiong Oil to Rizer Minimum Flow Rate Maintain flow rate of back flushing oil return to rizer at 8.0 SM3/hr set by FIC-012 to keep velocity (1.21.5 m/sec) in the 2 inch pipe to avoid accumulation of slurry, even if the back flushing flow rate is less than 8.0 SM3/hr. Level in D-1517 could be maintained by additional HCO supply via FCV-460. 7.7.3 Slurry Pump Operation Note There are operation concerning to avoid accumulation of slurry, especialy during idling service, or standby condition. The following are operation note of the slurry pump P-1519ABC to minimize accumulation of catalyst inside of pump when pump is not in service. -

Isolate AOV at suction and discharge, in case idling service

-

Flush out slurry oil by flushing oil (FLS) to heavy slop header (HSO) soon after stopping of duty pump.

-

Do not retain slurry oil in idling condition to avoid accumulation of catalyst slurry in pump.

-

Open AOVs at suction and discharge just before restarting pump, and proceed warming up operation with certain period prior spare pump start-up.

-

Commission of external flushing and external barriers for spare pump prior start up.

-

Clean-up drain valves soon after stopping of pump, by flushing oil. (FLH).

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7.7.4 Corrosion Monitoring Corrosion Probes (CP) and Corrosion Coupons (CC) are provided on the following points to monitor corrosion situation. Periodical monitoring of corrosion status should be made during normal operation. Location P&ID Tag No. CP/CC-401 E-1519 outlet 015 - 319 CP/CC-402 E-1520 outlet 015 - 319 CP-406, CC-405 D-1514 boot outlet 015 - 320 CP-702,CC-701 E-1551 outlet 015 - 403 CP-704,CC-703 E-1554 outlet 015 - 404 CP-706,CC-705 D-1553 boot outlet 015 - 404 CP-708, CC-707 E-1565 outlet 015 - 408 CP-710, CC-709 E-1561 outlet 015 - 410 CP-712, CC-711 D-1554 boot outlet 015 - 410 7.7.5 Fuel Gas and Pilot Gas Supply System The following provisions are considered for fuel gas and pilot gas supply to RFCC unit. 1) Start-up fuel gas for H-1501 & H-1502 Since operating pressure of H-1501 and H-1502 is 2.3 -2.5 kg/cm2g, normal fuel gas is not sufficient for these operation. LPG vapor from the LPG vaporizer in the fuel gas system is used for firing H-1501 & H1502. LPG vapor from fuel gas system is supplied to D-1525 via PCV-371A (large control valve) during heating up operation using H-1501 & H-1502. 2) Pilot gas for COB (H-1503) Pilot gas is required only for start-up of COB (H-1503). Once main burners of COB (H-1503) are ignited, this pilot gas can be stopped. Pilot gas is supplied from LPG vaporizer in fuel gas to D-1525 via PCV-371B (Small control valve). Selection switch HS-371 is used for selection of duty either the following : -

Pilot gas to COB (H-1503)

-

Main fuel gas to H-1501 & H-1502 during start-up of Regenerator

3) Fuel gas to COB (H-1503) Fuel gas to COB is supplied from the fuel gas net work, via D-1526, dedicately. 7.7.6 Slop Oil Injection Operation There are facilties that heavy slop oil and light the following facility : Drum No. Pump No Slop System Light slop D-1522 P-1526AB Heavy slop D-1523 P-1527AB

slop oil could be reprocessed to the main fractionator by Rated Flow, M3/hr 55.0 at condition 55.0 at condition

In case reprocessing these heavy slop oil to the main fractionator, the following procedures should be followed to minimize upset of the operation. -

Reduce RFCC charge flow rate to provide a room for additional duty of gasoline and LCO draw-off system.

-

Adjust heat balance of the main fractionator, especially shift the duty from the bottom PA to LCO & HCO PA so that additional duty for fractionatoion can be covered.

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-

Reinjection to the fractionator should be conducted very slowly, minimum affect to the heat balance of the main fractionator and gas concentration unit. Monitor temperature profile and flow balance of the all pump around, when reprocessing these slop oils.

-

Monitor water level in the boot of the respective slop drum, and avoid water reprocessing to the main fractionator. Water carry over into the system results in violent boiling and causes pressure swing.

-

Reinjection should be carried out one by one, and not simultanious of heavy and light slop to avoid serious effect to the main fractionator heat balance.

7.7.7 Pump Minimum Flow Operation The pump minimum flow recycle facilities are provided for the following pumps, since the rated pump capacity could not cover turn-down operation for certain operation cases. Operate minimum flow line in case pumping flow rate is closed to the pump minimum flow of the selected pump. Item No. P-1511AB P-1518AB P-1553AB

Service LCO Product Overhead Liquid Stripper Feed

Rated, M3/hr 208.2 225.0 535.3

Minimum Flow, M3/hr 72.0 75.0 260

7.7.8 Flue Gas Onstream Analyzers Operation The following Onstream Analyzers are provided on the flue gas lines : 1) On First Regenerator Flue Gas -

AI-004 : O2 analyzer

-

AI-005 : CO2 analyzer

- AI-006 : CO analyzer 2) On Second Regenerator Flue Gas -

AI-007 : CO analyzer

-


- AI-009 : O2 analyzer 3) On WHB outlet Flue Gas -

AI-011 : CO analyzer

-


- AI-013 : O2 analyzer 4) On Stack Inlet -

AI-018 : O2 analyzer

-

AI-019 : SOx analyzer

- AI-020 : NOx analyzer Since these analizers are provided the condition for dusty and water moisture, it is requires the following handling procedures to operate these analayzers propely. -

Close inlet isolation valve(s) of the sampling filters while start-up of RFCC, especially until line-up catalyst loading. During catalyst loading to the regenerator, it is anticipated high load of catalyst will be blowing to the regenerator outlet line.

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-

These analyzers could be switch-on after stable condition is achieved on the regenerator, to avoid plugging of filters with high dust load.

-

Spare filters are provided for on-stream switch over of the sampling set. During normal operation, check cleanness of the sampling filters, regularly, and replace to the sapred filter, as necessary.

-

Confirm tracing of sampling lines is properly working to prevent condensation of water in flue gas. During precommisioning, ensure that secure tracing is provided.

7.8 Troubleshooting 7.8.1

Troubleshooting situations

The problems often encountered in a RFCC are due mainly to changes in the feedstock, catalyst, operating variables, and mechanical equipment. As stated previously, the solution can take the form of improving yields, avoiding shutdowns or, increasing unit reliability. Troubleshooting consists of investigating and correcting the causes of unsatisfactory operations (typically off-spec products or unexpected operating conditions) before they deteriorate any further. Troubleshooting actions must be undertaken when: • The product is off-specifications, • Unexpected operating conditions are noticed. The main causes of concern, related to process are: • Catalyst circulation problems, • Excessive catalyst losses, • Poor quality of regeneration, • Spent catalyst stripping, • Product quantity and quality. 7.8.2

Catalyst circulation problems

Catalyst circulation problems are mainly correlated with: • Inadequate equilibrium catalyst properties, • Improper catalyst fluidization and aeration. In case of unstable circulation (unstable catalyst valve ΔP, sudden loss of pressure above the slide valve, ragged ROT temperature and/or stripper level control, levels swings in the regenerators), the problem must first be localized by checking the complete pressure balance of the unit. Improper catalyst fluidization and/or aeration will result in erratic pressure profile, i.e. no pressure gain or limited pressure gain in the catalyst standpipes or catalyst dense beds. In that case, the adjustment of the fluidization rates or aeration rates will help to restore the proper circulation. Especially aeration and fluidization nozzles and lines must be checked for cleanness and flow conditions. The catalyst circulation stability depends often on the equilibrium catalyst properties. The following factors appear to improve the fluidization:

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• A lower particle size distribution and lower catalyst density, • A higher fines content (40 microns). Typically, no circulation problems are observed with catalyst containing more than 5 wt % of fines (0-40 microns). In case of too low fines content (< 5 wt %) adding more fresh catalyst and/or using a softer catalyst can help to improve the catalyst properties. Adding fines directly in the unit is inefficient and can overload the cyclones. The circulation can also be improved by increasing the pressure level in the regenerators if pressure margin is available on the catalyst slide valves. Erratic circulation occurs when catalyst is not developing a smooth and uniform static head over the entire length of the stand pipe. When this appears, the catalyst packs and bridges across the stand pipe. 7.8.3

Excessive catalyst losses

Excessive losses can occur through the disengager cyclones or through the regenerators cyclones. In the first case, the fines content in the slurry product will become too high, causing plugging of the slurry circuit equipments: exchangers, pumps. In the second case, flue gas dust emissions will be excessive. Monitoring the catalyst losses requires periodic analyses of fines content in the flue gases and in the slurry product. Excessive losses can be due to: • Catalyst attrition, • High or low catalyst levels in the vessels, A)

• Cyclone performances deterioration. Catalyst attrition

Catalyst attrition mainly occurs in the lift, the riser and around the air rings, where high velocities are achieved. Excessive velocities will dramatically increase the attrition phenomenon. Excessive attrition will result in a high fines content in the equilibrium catalyst (> 15 wt % of 40 microns). In case of high attrition, the lift air flow rate and riser steam flow rates must be checked and adjusted if necessary to keep reasonable velocities in the lines: about 10 m/s in the air lift, 20 m/s in the riser. The cause of tremendous attrition can also be the mechanical weakness of the catalyst. In that case, « harder » catalysts with lower attrition index must be used. B)

High or low catalyst levels

It is critical to keep the catalyst level below the maximum or above the minimum admissible level. In case of high level, the required disengaging height will not be sufficient and the cyclones will be overloaded, causing efficiency decreasing and losses increasing. A low level may unseal the diplegs which could result in backflow of flue gas up to the diplegs and loss of catalyst fines. Specific care must be taken for checking the levels reading, especially during transient operations (start-up, shutdown, catalyst change,...). C)

Cyclone performances deterioration

There are several reasons for deteriorating cyclone performances: • increased load, either solids or vapor,

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• holes in cyclone body, outlet, dipleg, or plenum chamber, • erosion of the internal lining, • lost dipleg seal or blocked trickle valve, • dipleg plugged or partially plugged by foreign material. An increased load can be caused by poor air distribution due to localized high velocity and catalyst entrainment. This also results in higher cyclone outlet temperatures due to after burning and lower air rings back pressure. Increasing the regenerator bed level can help alleviate this problem. Once the cyclones are badly eroded, little can be done to keep the unit on-stream for a long time with losses under control. If the holes are formed in the lower part of the dipleg, increasing the bed level to seal the holes may be successful. 7.8.4

Poor quality of regeneration

A poor quality of regeneration will result in: • High carbon content on the regenerated catalyst, • Non-homogeneous dense bed temperatures distribution in the regenerators, The catalyst regeneration can be improved by: • Improving the mixing between the catalyst and the combustion air. This can be achieved by increasing the air flow rate or by decreasing the operating pressure in the regenerators, • Increasing the catalyst residence time in the regenerators, by increasing catalyst levels, • Increasing the bed temperatures in case of too low temperatures (650°C in the first regenerator, 730°C in the second regenerator). 7.8.5

Spent catalyst stripping

Poor spent catalyst stripping causes an increase in delta coke, which results in a decrease of the catalyst circulation rate at a given heat balance requirement. The regenerators temperatures will then increase and eventually the feed throughput may have to be decreased. A stripping problem is apparent from an increase in hydrogen in coke, as calculated from the flue gas analyses. The optimum steam rate to ensure proper stripping depends on the catalyst circulation rate, the stripper design and the equilibrium catalyst surface area. Good stripping occurs when the delta coke is minimized. For a given design, the stripping steam rate is optimized by adjusting it to a value slightly above the one which minimizes the regenerators temperatures. The catalyst architecture can directly affect the observed stripper performance. Entrainment of hydrocarbons in the catalyst pores and the resulting carry-over to the regenerators will be minimized with the use of a large pore catalyst. 7.8.6

Product quantity and quality

The amount and quality of products obtained from the RFCC unit are influenced largely by feed quality, catalyst properties, operating variables, and mechanical conditions of the unit. The indicators which are often employed to measure the unit’s performance are: • Conversion,

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• Dry gas yield, • Gasoline yield, • Gasoline octane. The conversion is affected by feed quality, catalyst properties, operating variables and mechanical conditions. The common causes that affect the conversion are: • Feedstock quality (increase in reside content, increase in feed impurities such as nickel, vanadium, sodium etc..), increase in the CCR. • Catalyst properties (decrease in micro activity and surface area). • Operating variables (decrease in ROT, in C/O ratio, in fresh catalyst addition rate). • Mechanical conditions (a damaged or plugged feed nozzle and/or damaged stripping steam distribution). Note:

The “apparent” conversion is affected by the distillation cut point and the main fractionator operation.

The dry gas yield gasoline yield and gasoline octane are also affected by feed quality, catalyst properties, operating variables and mechanical conditions. The operating parameters having the most negative impact on dry gas yield are: • Increase in ROT, • Increase in slurry or HCO recycle. The main operating parameters that favor gasoline yield are: • Decrease in the feed preheat temperature and subsequent, • Increase in C/O ratio, • Decrease in carbon content of the E-Cat, • Increase in ROT if overcracking is not occurring. In general, any parameters which increase the gasoline yield will also decrease its octane, one reason is that high octane components in the gasoline tend to be denser than the low octane components. Increase in the naphthene and aromatic fraction of the feedstock enhance the octane. The factors that increase octane are: • Increase in ROT, • Decrease in the C/O ratio, • Increase HCO recycle. Note: Mechanical conditions for critical equipment or system failures (air blower, catalyst circulation, feed outage etc…) which lead to emergency shutdown are covered in Chapter 9.2. 7.8.7

Partial Shutdown of Electrostatic Precipitator

The electrostatic precipitator (X-1507) is located at the downstream of COB/WHB Package (H-1503) in flue gas duct. It removes the catalyst fines in the flue gas from the first and second regenerators to 50mg/Nm3, in order to meet the environmental regulation in Vietnam. The electrostatic precipitator

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consists of two chambers, arranged in parallel. The electrostatic precipitator can be operated with single chamber, in case one of the chambers is under shutdown condition, e.g., mechanical trouble, equipment maintenance. The isolation dampers, which are installed at the inlet and outlet ducts, will isolate the chamber. However, when either of the chambers is not in operation, it is impossible to meet the environmental regulation for particle emission in flue gas under normal RFCC load. Therefore, the operator shall reduce RFCC load to approximately 50% to follow the environmental regulation.

7.9 Operation Notes, Relating Hazop Follow-up Action This section summarizes the operation note, and procedures, relating Hazop Follow-up action. Operation should take note that these actions are highly relating safety and operability review at the design review. 7.9.1

Feed Injection Atomising Steam supply failure

Referring HAZOP Action No. 4003, when fail of steam supply to the feed injectors I-1501A-F are detected by FAL-005A-F, the following actions should be taken to avoid coking-up of feed injectors. -

Loss of atomizing steam to the feed injector causes inadequate vaporizing and mist generation of the feed oil, and cause coke-up of feed inadequate separation in the reactor.

-

At event of atomizing steam low flow of either FI-005 A to F, check the site condition of FV-005 A to F, while manual by-passing of the relevant control valve.

-

Check MPS are properly line-up for atomizing steam.

7.9.2

Temporary Strainer in Feed Line at downstream of M-1501

Referring Hazop Action 4009, a temporary strainer on the feed line at down stream of M-1501 was provided for the initial start up. See Note 4 of P&ID 8474L-015-PID-0021-121. This temporary strainer is provided to remove any debris during construction, and avoid blocking/plugging of the feed injectors. It is recommended to remove this temporary strainer, after appropriate timing of commissioning operation (at least 5-10 days operation), assessing debris are removed, and utilize chance of temporally stopping RFCC feed after feed cut-in to the raiser. 7.9.3

MOV-001 Operation and Isolation Valve of PSV-002

Referring Hazop Action 4015/4040, ensure the following operating procedure of opening and closing of MOV-001 and isolation valve of PSV-002 1) MOV-001 shall be opened as per detail procedure in the start-up procedure. Once open MOV-001, kept open by locking devices that MOV-001 shall never closed during operation. 2) Once MOV-001 closed and during normal operation, isolation valve at inlet of PSV-002 should be locked closed position. Isolation blind at down stream of this valve should be also closed position. These considerations should be strictly followed to avoid hydrocarbon release to atmosphere via PSV-002, as the result of fault popping. During start-up and MOV-001 is closed position and steaming operation is progressing before catalyst circulation, this isolation valve at inlet of PSV-002 shall be kept open so that PSV-002 is protecting the system while steaming the riser and reactors.

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3) It should be noted that there is a high tendency of coke deposit at dead end portion up stream of isolation valves. Therefore, commission HPS purging to the following RO’s and steam rings when isolation valves are closed during normal operation. See P&ID 8474L-015-PID-0021-123. -

RO-027: HPS to upstream of isolation valve of PSV-002

-

RO-025: HPS to upstream of isolation valve of SL-1501

-

RO-028: HPS to upstream of isolation valve of 24” start-up vent line (24”-PG-150037-B1AS)

7.9.4 Avoid Solidification of Feed Oil Referring Hazop Action No.4019 the following appropriate procedure should be taken to avoid solidification of feed oil system. -

Pour point of feed oil (Atmospheric Residue) is 50-52 deg C.

-

Routine checking that steam trace is working properly to maintain piping temperature is higher than pour point.

-

In case equipment isolation for onstream maintenance or idling operation of heat exchangers and pumps, flush out by LCO from FLS header. Do not drain feed oil to the closed drain header, prior flush out by LCO.

-

In case shut-down duration is relatively long, introduce LCO from BL to the feed surge drum, and replace feed oil by LCO.

7.9.5 Reactor Temperature Control for Coke Formation Referring Hazop Action No. 4023, that Reactor Outlet temperature control is the primary operation variable to control coke formation and yield. Refer to Section 7.3.1 for process vaiable control. The following are design intended Reactor Outlet temperature : ¾ Bach Ho Max gasoline : 518 deg C ¾ Bach Ho Max distillate : 505 deg C ¾ Mixed Crude Max gasoline : 520 deg C ¾ Mixed Crude Max gasoline : 511 deg C Adjust riser outlet temperature and other process variables to meet the desired conversion and product specification. Refer to Process variable, Effect of Riser Outlet temperature (Sect 7.3.2) High high temperature of the rizer outlet is caused by the following situation : -

Loss of feed oil to the injectors

- Excessive regenerated catalyt circuration via the slide valve SV-1501 Remedial actions are required to avoid coke-up of the reactor. 7.9.6 MTC Atomizing Steam Injection Referring Hazop Action No. 4026, MTC injection is intended during Mixed Crude Max Gasoline Case only. It is recommended that MPS injection shall be maintained while no MTC injection to avoid catalyst accumulation in the MPS line and injection nozzle of I-1502A-D. 7.9.7 Avoid Vacuum Condition of Reactor Vessel Referring Hazop Action No. 4036, the following procedure should be strictly followed to avoid vacuum condition of the reactor, which are not designed for full vacuum condition.

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-

Steaming of reactor and raiser will be proceeded during start-up, under MOV-001 closing condition.

-

Venting line to SL-1501 shall never be closed while steam out operation to avoid creating vacuum condition, as steaming accidentally stopped, and cool down of the equipment.

-

Once MOV-001 is opened, then venting line to SL-1501 could be closed, since there is fuel gas purging from the main fractionator overhead section.

7.9.8 Metal Passivator Filling Operation to D-1508 Referring Hazop Action No. 4041, the following procedure should be taken when metal passivator filling to D-1508 to avoid releasing chemical vapor to the grade area. -

As shown in the chemical injection setion, NALCO EC9192 or equivalent is used for Nickel passivator. Dosage rate is 109 kg/day for Mixed Crude(Ni in feed is 10.5 PPM), and 0.0 kg/day for Bach Ho Crude case (as Ni in feed is only 1.0 ppm). Since inventory of D-1508 is 2.0 M3, filling operation to D-1508 is required approximate 30 days interval at Mixed Crude Operation. No filling operation is anticipated for Bach Ho Crude case.

-

In case differnt feed oil other than design, check Ni content (PPM) in feed oil and adjust dosage injection, as proportional to Ni content.

-

Filling operation will be carried out using portable air pump from the chemical drum. Prior to refilling operation, confirm the level in D-1508. As progressing of filling, care no over-filling D-1508.

-

A valve of overflow should be opened during filling, and be closed during normal operation.

-

Refer to MSDS of NALCO EC9192

7.9.9 PDT-103 Commisioning Note for Slide Valve SV-1502 Referring Hazop Action No. 4048, PDT-103 for Slide Valve SV-1502 should be commissioned properly that LP side shall never left open condition, opening manual bleed valve at low pressure side. PDT-103 is provided to close SV-1502, when pressure differential is less than 0.1 -0.15 kg/cm2 to ensure catalyst level and seal is available with minimum catalyst level upstream of SV-1502. Hence in case low pressure side kept open to atmosphere, there could be fault measuring of pressure drop across SV-1502. Ensure that pulsation line-up of the low pressure side (down stream of SV-1502) are properly made and confirm manual vent valve should be closed during commissioning of PDT-103. 7.9.10 Catalyst sampling method Referring Hazop Action No. 4050, the following are sampling procedure of hot catalyst. - The following Sampling points are provided for hot catalyst sampling: SP-022: Regenerated catalyst at downstream of SV-1501 SP-001: Spent catalyst upstream of SV-1502 SP-002: First Regenerator Bottom - See sketch on P&ID 8474L-15-PID-0021-122/125/127. Sample buffer pot is used for hot catalyst sampling. - When sampling is not in operation, valve “3” is always opened to purge the nozzles with nitrogen and valves “1”, “2” and “4” are closed. - At the time of catalyst sampling, close valve “3” to get catalyst in the sampling line. Then open valves “1” and “2” to allow the sampling in the buffer pot. When the buffer is full, close “2” and open “4” to back-flush the sampling line. Finally open “3” and close valves “1” and “4”.

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7.9.11 Operation of Vaiable Orifice down stream of Flue Gas Slide Valve Referring Hazop Action No. 4080 and 4092, the following variable orifice are provided to support smooth slide valve operation of the respective flue gas of the regenerator : - SV-1503-VO-01, First Variable Orifice of SV-1503 (First Regenerator Flue gas slide valve) - SV-1503-VO-02, Second Variable Orifice of SV-1503 (First Regenerator Flue gas slide valve) - SV-1504-VO : Variable Orifice of SV-1504 (Second Regenerator Flue gas slide valve) Operation note of variable orifice and slide valve - Opening of Variable Orifice should be adjusted so that smooth operation of the respective slide valve are achieved, depended on the flue gas flow rate. i.e. opening of slide valves SV-1503 & SV-1504 to be the operation and control range. (30-60 % opening, HOLD) - It should be avoided condition that slide valves SV-1503 & SV-1504 operates almost closed position (less than 10% open, HOLD), or full open condition (higher than 90 %, HOLD) to make secure control of the pressure. Adjust opening of variable orifices referring opening of SV-1503 and SV1504 are operation range. Since design intention of the slide valve and variable is that pressure drop are evenly distributed between these facilities, set the respective opening as follows : -

Set flow rate of air to the regenerator, under 50 % opening of SV-1503, VO1, and VO2.

-

Adjust opening VO2 to 1/3 of the desired pressure under full open of SV-003 and VO1.(e.g.in case 2.3 kg/cm2g of pressure in the regenerator is the desired pressure, first set to 2.3/3=0.77 kg/cm2g)

-

Then slowly adjust VO1 opening to achieve 2/3 of the desired pressure. (e.g 1.54 kg/cm2g) under full opening of SV-1503.

-

Finaly adjust SV-1503 to achieve the desired pressure (e.g 2.3 kg/cm2g).

7.9.12 Combustion Air Control to the First Regenerator Referring Hazop Action No.4082, combustion air to the first regenerator should be adjusted to control CO in the flue gas. As stated in the design basis and operation variable sections, it is intended that 70 % of cokes in the spent catalyst is burnt in the first regenerator, by adjusting combution air flow rate, referring CO content in the flue gas is 5 - 6 %. 7.9.13 Combustion Air Control to the Second Regenerator Referring Hazop Action No.4097, combustion air to the second regenerator should be adjusted to attain complete combustion of CO in the flue gas. As stated in the design basis and operation variable sections, it is intended that remaining 30 % of cokes in the spent catalyst is completely burnt in the second regenerator, by adjusting combution air flow rate, referring CO content in the flue gas is 0.0 % with presense of 2-3 % of excess air. 7.9.14 Flue Gas Operating Temperature at Economizer Outlet Referring Hazop Action No. 4144, flue gas temperature should be always 50 deg C higher than its acid dew point. The following are expected acid dew point at design case : -

Bach Ho Crude : 164 deg C

- Mixed Crude : 190 deg C Economizer outlet temperature is the concerning area, since other sections are operating more than 300 deg C. Economizer outlet temperature of the flue gas is controlled by BFW inlet temperature at the inlet of the economizer, controlled by MPS heater. In order to achieve 50 deg C higher than its acid dew point,

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BFW temperature to control properly. For design purpose, the following are recommended BFW temperature down stream of MPS heater. -

Bach Ho Crude : 140 deg C

-

Mixed Crude : 165 deg C

7.9.15 Slurry Service Heat Exchanger Flush out when Idling Operation Referring Hazop Action No.4320, flush-out operation should be carried out when idling of heat exchanger of the slurry service to avoid accumulation of slurry oil and solidification in the heat exchangers, as pour point of slurry oil is 15-20 deg C. The following provisions are provided for flushing operation. -

FLS connection for LCO supply

-

HSO connection to the heavy slop header

-

Closed drain connection

- Steam out connection by Low Pressure Steam Prior to drain out to the closed drain system, the relevant exchanger should be firstly flushing by LCO, opening HSO connection. After sufficient flushing by LCO (confirmed by bleed operation from HSO connection), and confirmed the fluid is completely replaced by LCO, then open the drain to the closed drain. 7.9.16 Switch Over Operation of E-1506AB Stand-by to Operation Referring Hazop Action No. 4345, the following are switch over operation of E-1506AB. -

E-1506AB is designed that one shell is stand-by service during normal operation.

-

Switch over from operation service to idling service, time to time.

-

Fill BFW in the idling shell, opening feed isolation valve.

-

Gradualy open tube side to warm-up the heat exchanger.

-

Operate stand-by exchanger using vent to the Silenser. After sufficient venting steam to atomosphare, open isolation valve of the generated steam line. Then close vent valve to Silensor.

-

After line-up of steam generation, then close hot fluid to the original operating shell. Subsequently, isolate BFW supply to the original operating shell.

-

Change the line-up blow down and chemical injection of the service side.

7.9.17 Operation of HP-BFW Preheating by E-1516 and E-1511 Referring Hazop Action No. 4381, ensure that isolation valves HP-BFW at E-1516 and E-1511 should be always Locked Open to provide secure supply of BFW to the subsequent section. HP-BFW is preheated by E-1516 and E-1511, then supplied to the following HP steam generators : -

E-1504AB : Slurry HPS Generator

-

E-1503ABC : Slurry HPS Generator

-

E-1534 : BFW Preheater (at Economizer inlet)

7.9.18 WGC Compressor Suction KO Drum Pump Out operation Referring Hazop Action No. 4601, the following are specific operation note of liquid pump-out operation from D-1551, WGC Suction KO drum.

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-

Pump out pump P-1552A or B will be operated automatically, when liquid level is detected by LIA701. High level start the pump, and low level stop the pump.

-

Since the drum is normaly empty, operation should be aware that LAL-703 detection of low level is the normal situation.

-

In order to avoid lose suction of these pumps, confirm site sitation that P-1552A or B should never running under sitaution of low liquid level, detected by LAL-703.

7.9.19 Depressuring operation of T-1556 LPG Extractor Referring Hazop Action No. 4697, the following care shall be taken for Depressuring operation of LPG vessel. -

Depressuring facility (UX-717 for activating XV-752) is provided on top of T-1556 for safety provision during external fire.

-

This UX-717 shall be activated during external fire, only.

-

Depressuring of LPG other than external fire situation results in self refrigeration of LPG, since self vaporization temperature is -25 deg C at atmospheric pressure. Self refrigeration will also cause icing and solidification of amine solution.

-

In case operation faulty activates UX-717 (depressuring), immediate remedial action are required to stop depressuring by resetting activation of XV-752 from the local panel, avoiding freezing of T1556 and icing of amine solution. There is a substantial time for operator's intervention to check the realistic situation at the case of operation fault, and to reach complete frozen condition of T-1556.

-

The stroke test procedure for the depressuring valve should be carried out that the downstream locked open isolation valve has to be shut and could only be carried out under permit to work system.

7.9.20 First Regenerator High High Temperature Referring Hazop Action No. 4058, the following are procedure in case high high temperature of the first regenerator. - Reduce Reactor feed rate to reduce coke quantity in the spent catalyst - Reduce catalyst circulation rate from the reactor, if possible. - Reduce combustion air to the first regenerator - Check torch oil is injected or not, if torch oil is used, stop injection. Refer to Process variable section for temperature control of the regenerator. 7.9.21 Split Range Control of Surge Drum Referring Hazop Action No. 4449, 4468, 4482, and 4488, the following surge drums have pressure control that fuel gas is introduced to the drum when pressure is reduced, and purge out to flare when pressure is increased. These controls are made by split range control that both control valves never open, simultaneously. Hazop Action is requested that the relevant PIC and PV to check, time to time, whether both PVs are opened or not, by driven open, in case mal-function of the relevant PIC controller. There are local PGs for back-up of PIC. Time to time, operator should check local PG to confirm PIC is operating properly. PV to Flare Controller No. PV for Fuel Drum No Gas In D-1513 PIC-403 PV-403A PV-403B D-1515 PIC-468 PV-468A PV-468B D-1516 PIC-479 PV-479A PV-479B

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D-1517 D-1518 D-1519 D-1522 D-1523

PIC-475 PIC-483 PIC-489 PIC-505 PIC-510

PV-475A PV-483A PV-489A PV-505A PV-510A


PV-475B PV-483B PV-489B PV-505B PV-510B

7.9.22 Untreated Gas to F/G System during Upset Situation of F/G Absorber T-1555 Referring Hazop Action No. 2070, provide a rapid communication of FG absorber problem to FG customers so that they can initiate appropriate safety measures. This action is highlighted in HAZOP Action of Unit 12 for the failure situation of the fuel gas absorber T-1555 that H2S in fuel gas will be higher than normal, and special attention for handling is required for the relating unit, using treated fuel gas. RFCC off gas is the major source of fuel gas of the whole refinery. The off gas is treated by Fuel Gas Absorber T-1555 to remove H2S by 20 % DEA solution, then routes to the fuel gas mixing drum in the fuel gas system (Unit 37). The maximum H2S content of the treated off gas is controlled to 50 wt PPM. During upset of this fuel gas absorber, such as foaming in the absorber tower, loss of control of lean amine solution, or upset of Amine Regeneration Unit, then untreated off gas with high concentration of H2S will be routed to the fuel gas system of the Refinery. The following are expected H2S concentration in T-1555 feed gas (untreated RFCC off gas): ¾ Bach Ho Max Gasoline: 0.47 wt % (4,700 wt PPM) ¾ Bach Ho Max Distillate: 0.53 wt % (5,300 wt PPM) ¾ Mixed Crude Max Gasoline: 4.55 wt % (45,500 wt PPM) ¾ Mixed Crude Max Distillate: 2.51 wt % (25,100 wt PPM) Referring H2S in treated gas 50 wt PPM, upset condition of Fuel Gas Absorber expects very high concentration of H2S in the treated gas, and spoil fuel gas system seriously. It should be informed to the all concerned section of the refinery that untreated off gas is routing to the fuel gas system, and special attention shall be taken for the all fuel gas users for handling of fuel gas. For RFCC unit, the following procedures should be taken to recover upset of Fuel Gas Absorber: 1) Foaming Prevention of Fuel Gas Absorber -

Operate proper differential temperature between absorber feed gas and lean amine. Lean amine solution should be always 15 deg C higher than feed gas to avoid condensation of hydrocarbon in this Absorber. To achieve this situation, monitor TI-743 at outlet of E-1565, and TDIC-746 which reset temperature control of lean amine solution in ARU (outlet of E-1904).

-

Filtering of lean amine solution properly in ARU (F-1901, F-1902, and F-1903) for clean-up of lean amine solution. Dirty amine solution causes foaming in Absorber or Regenerator.

-

Injection of anti-foam chemical is the final resolution to control foaming, properly. Injection of antifoam chemical should be limited only foaming occurred in Absorber. Over-dosing of anti-foam results in adverse effect.

-

Upon foaming is observed in Absorber, such unsteady pressure drop of the tray, measured by PDI740, or unsteady level indicator of T-1555 bottom, change operating parameters such as reduction of RFCC throughput to cover operation range, or reduce lean amine solution to be operable range. Check whether temperature of feed gas is higher than lean amine solution. Start anti-foam chemical injection, even if various process variable could not recovered foaming operation.

2) Regeneration Section Operation (ARU) The following operation should be made properly, referring the operation manual of Amine Treating Unit.

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-

Remove hydrocarbon from rich amine, properly

-

Filtering of lean amine, regular basis

-

Anti-foam injection properly (only foaming duration)

-

Proper temperature control of lean amine solution

-

Proper regeneration of amine solution (reboiler)


7.10 Unit monitoring check list For smooth operation and to avoid breakdowns of the system, the unit engineer should examine certain information daily. Other operating data should be checked on a weekly basis. Daily checks 1. Yield distribution versus the feed properties and riser outlet temperature. 2. Complete a heat and material balance of the unit, calculate coke yield and catalyst-to-oil ratio. 3. Temperatures and pressures at the suction and the discharge of the blowers. 4. Flue gas flow rate and composition. 5. Disengager and regenerator pressures, and slide/plug valve differential pressures and positions. 6. Regenerator temperatures and temperature gradients. 7. Riser Outlet Temperature. 8. Composition of coke on the spent catalyst (H2 and S). 9. Carbon on regenerated catalyst. 10. Density in the stripper and regenerator catalyst beds. 11. Flow rates of aeration / fluidization air and steam in the standpipes and catalyst cooler (if applicable). 12. Fresh and equilibrium catalyst addition rates. Spent catalyst withdrawal rate. 13. Dispersion and stabilization steam rates. 14. Flow rates of main combustion air, stripping steam, withdrawal well air, and wye stabilization steam. 15. Solids content of slurry oil. 16. Product properties and flow rates. 17. Passivator injection rate. Weekly checks 1. Catalyst properties. 2. Complete catalyst balance to calculate losses. 3. Steam and oil pressures at the fresh feed injectors and MTC oil injectors. 4. Complete utilities balance for steam, air, and fuel. 5. Complete pressure survey. 6. Confirm that instrument tap purges are operational. 7. Perform unit performance test including a complete heat and material balance.

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8


NORMAL SHUT-DOWN

8.1 Normal Shut-down 8.1.1 Shutdown and restart of the unit Important recommendations for shutdown and restart There are three types of shutdown. The normal shutdown scheduled for a turnaround, the shutdown due to short duration problem in part of the unit, and the emergency shutdown. The normal scheduled shutdown requires the catalyst unloading while, for a short time shutdown, one will try to keep the catalyst circulation by all means in order to restart the unit as quickly as possible.

8.2 Normal shutdown General and Summary 8.2.1 General This is a shutdown guideline for the reaction/regeneration section of the RFCC process. Reference is made to other sections of the process as required; however, the shutdown of the other sections of the unit is not covered in this guideline. This guideline relates to a shutdown as it would occur on a planned basis prior to a major turnaround. Prior to shutting down, other operations in the refinery must be properly notified. As equipment temperatures will be rapidly changing during the course of this procedure, operators should be aware of the possibility of equipment binding, flange leaks or other associated process hazards and maintain constant vigilance. Normal scheduled shutdown should be made in orderly sequences because there is no character of emergency. The main points to observe are:

• Keep catalyst circulation during the shutdown as long as possible. • Make sure all circuits are flushed to avoid problems during the inspection and the next start-up. • Keep product quality as long as possible. 8.2.2 Summary of Shutdown of Reactor and Regenerator 1 This guide relates to a planned shutdown where all concerned have been informed of the time of the shutdown. 2 Normal scheduled shutdown should be done in an orderly sequence with the main points to observe as follows: • Keep the catalyst circulating as long as possible during the shutdown. • Flush all circuits to avoid problems during inspection and the next start-up. • Maintain product quality as long as possible. 3 Start reducing the catalyst inventory • Prior to shutdown, check that there is adequate room in the Spent Catalyst Hopper to hold the UNIT catalyst inventory. • Activate Hopper steam ejector and pull a vacuum on the Spent Catalyst Hopper. • About 8 hrs before reducing feed, begin to lower catalyst levels in all three vessels to minimum. • Withdraw catalyst slowly and avoid overheating the Spent Catalyst Hopper ( 400 °C maximum). 4 Start feed reduction • Close recycle to the MTC injectors. Keep the dispersion steam to the MTC injectors in operation at normal flowrate.

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• Reduce the feed by 5% decrements to 60% of normal operating flow. • Reduce air rates and stripping steam rate generally in the same proportion to the feed. Maintain excess oxygen of 1 to 3 vol% in the Second Regenerator flue gas. • Adjust the flows of the steam generation system and watch levels in the steam drums. • Adjust the regenerator pressures as necessary to maintain an adequate differential pressure across the spent catalyst slide valve. • Maintain feed at 60% capacity for one hour, decrease the Disengager temperature to 510 °C. Inject fuel-gas or nitrogen in the Fractionator Reflux Drum to maintain control of the Disengager pressure. • As coke make decreases, Regenerator temperatures will fall, light the Air Heater to keep a minimum of 650 °C in the Regenerators. Maintain catalyst circulation for at least 15 minutes to regenerate the whole batch of catalyst. • Shut off the burners in the CO Boiler, and shutdown the CO Boiler as per VENDOR’s instructions. • Shutdown passivator injection and isolate the chemical injection from the feed line. 5 Start removing oil from the riser as follows: • Reduce the feed rate to 10-20% as quickly as possible. Maintain stabilisation and dispersion steam at operating flow rates to maintain riser lift. • Reduce air rates to 50% of the normal operating flow. • Activate reaction section bypass and block in oil feed to the riser feed injectors. • Flush feed lines and torch oil lines with LCO to HSO header in order to avoid the plugging concern with hiher pour point fluid.. • Reduce Regenerator pressures and increase the Main Fractionator pressure as necessary while maintaining adequate catalyst slide valves differential pressure. • Continue catalyst circulation on steam with dispersion and stabilisation steam. • Switch fuel gas purges to nitrogen purges on the Disengager Stripper section. • Close the isolation valve between the Main Fractionator and the Disengager after opening the Disengager vent line. 6 Using manual control, lower the level in the Catalyst Stripper to minimum without losing the spent catalyst slide valve differential pressure. 7 Continue catalyst circulation until there is no appreciable temperature difference between the Regenerators. 8 Begin unloading the catalyst when dense phases cool down to 400 °C. 9 Close the regenerated slide valve and stop the catalyst circulation. Close the plug valve on manual hydraulic control 10 Lower the Catalyst Stripper level until the pressure differential across the spent catalyst slide valve reaches 0.1 kg/cm2. Close the spent catalyst slide valve and prevent it from opening except to dump any additional catalyst which may collect in the Stripper. 11 Control the pressures on both Regenerators at the same value, between 0.7 and 0.9 kg/cm2g. Continue to unload the catalyst. 12 Close MOV-001 at the Main Fractionator inlet. • Blind the hydrocarbon sources to the feed system and to the riser. • Reduce the dispersion and the stripping steam flow rates to 50% of the normal operating flows. Steam out to atmosphere through the vent for 15 minutes. • Reduce the steam flow in the Main Fractionator, and to the feed, MTC, and stabilisation injectors, and adjust stripping steam to minimum. Open the purge bleeder. • Be sure that purge HPS to MOV-001 is clised prior MOV-001 operation. • Close MOV-001 at the Main Fractionator inlet.

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• The Main Fractionator and RFCC Gas Plant shutdown operation may proceed independently after closing MOV-001 at the Main Fractionator inlet. 13 Re-establish dispersion steam flow at about 50% of the normal flow rate and stripping steam at 30% of the normal flowrate. 14 Continue catalyst removal. • Continue unloading the Regenerators, normally the Second Regenerator empty first. • When the Second Regenerator is empty, open the regenerated catalyst slide valve and empty the withdrawal well and standpipe. • When the regenerated catalyst slide valve differential pressure reaches 0.1 kg/cm2, close the slide valve. • Equalise the pressure on the Disengager and on the Second Regenerator. • Empty the Stripper to the First Regenerator through the spent catalyst slide valve. • Continue unloading the First Regenerator. 15 After all the catalyst has been unloaded, reduce the regenerator pressures to a minimum to reduce the blower discharge temperature for refractory cooling. 16 Block in the dispersion and stabilisation steam. Continue cooling the Disengager/Stripper with stripping steam until a temperature of 200 °C is reached. 17 Stop steam flow on steam rings and admit air via the temporary plant air lines. 18 Replace nitrogen purges by air purges. 19 Continue cooling the regenerators with Blower air until the dilute phase temperatures are within 15 °C of the Air Blower discharge temperature. 20 When the UNIT is cooled , shut down the Air Blower as per VENDOR’s instructions. 21 Check for residual hydrocarbons. 22 Release the plant for maintenance under a Permit to Work 8.2.3 Summary of Shutdown on Fractionator and Gas Recovery Section 1 Inform all concerned of the time of the shutdown. 2 As feed to the reactor is reduced, gradually reduce the HCO, LCO and Heavy Naphtha pumparound duties. 3 Maintain slurry pumparound flow at normal rate to the grid to avoid coking. 4 Bring the Wet Gas compressor speed to minimum, operate on spill back to maintain control. 5 Bring fuel gas or nitrogen into the Main Fractionator Reflux Drum. 6 Stop pumparound pumps, reflux pump and product pumps as levels are lost. 7 Continue slurry oil pumparound to the bottom of the Fractionator. 8 Bring in cold LCO to the Main Fractionator from the feed section to allow flushing of the slurry circuit. Rundown via the clarified oil circuit to the clarified oil storage or to slops. 9 Shutdown and isolate the Wet Gas Compressor when catalyst circulation in the reaction section of the RFCC has stopped. 10 Isolate the compressor stages by closing the suction and discharge valves and the spillback valves. 11 Stop water wash to the inter-cooler and pump out the liquid from the 2nd stage suction drum to the HP separator. Depressurise the compressor stages to fuel gas and then to flare. 12 Close MOV-001 for segregation of the Main Fractionator and the reactor section. 13 The Gas Recovery section shutdown must be closely co-ordinated with the Main Fractionator shut down. 14 Stop the lean oil pump while the Main Fractionator is being shutdown. Pressurise the liquid from the Secondary Absorber back to the Main Fractionator. 15 When there is no longer flow of liquid from the Fractionator reflux drum to the Primary Absorber, drain remaining liquid to the HP separator.

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16 Pump the hydrocarbon liquid from the HP Separator to the Stripper and pressurise water to the Sour Water Stripper. 17 Pressurise hydrocarbon liquid from the Stripper to the Debutaniser. 18 Depressure the Absorbers and Stripper to fuel gas and then to flare. 19 Pressurise liquid from the bottom of the Debutaniser to off-spec storage or slops. Pump LPG from the Debutaniser Reflux Drum to the LPG Treating Unit (Unit 16) and then off-spec LPG storage. Depressure the Debutaniser to flare. 20 Drain remaining liquids in the unit to the closed drain or to the oily water sewer. Purge the Wet Gas Compressor to flare with nitrogen and then to atmosphere. Leave the compressor under a slight nitrogen pressure until it is opened for maintenance.

8.3 Shut Down Procedure 8.3.1

Catalyst inventory reduction

a) Prior to shutdown, the spent catalyst hopper should be checked and provision made for adequate room to hold the unit catalyst inventory. Activate hopper steam ejector and pull vacuum on the spent catalyst hopper. b) Approximately 8 hours prior to reducing feed, begin to lower the catalyst levels in all three vessels to their minimum operating levels. Withdraw catalyst slowly using X-1501, catalyst with-draw package, by resetting draw-off rate, taking acount to avoid upsets and avoid overheating the spent catalyst hopper (400°C maximum). c) Never throttle catalyst withdrawal flow with the valve next to the regenerator vessel. Use the next valve downstream to avoid erosion damage to primary vessel isolating valve. 8.3.2

Feed reduction

a)

Close recycle to the MTC injectors. Keep dispersion steam of MTC injectors in operation at normal flow rate. This will clean MTC injectors.

b)

Reduce the feed by 5% increments to 60% of normal operating flow. Reduce air rates and stripping steam rate, generally in the same proportion to feed, while observing regenerator temperature profiles. Accordingly adjust air rate to the regenerators and keep an excess of oxygen in flue gas of second regenerator in the range of 1 to 3% volume to keep a good regeneration of the catalyst. During the feed rate reduction adjust steam generation system and watch carefully levels in the steam drums.

c) Observe the position of air lift control valve during the changes in air rates and adjust FIC-161 and PV-311 on the first regenerator combustion air lines as necessary to maintain good control above the minimum air lift rate. d) As feed is decreased, the disengager pressure will fall. Adjust the regenerator pressures as necessary to maintain adequate pressure differential across the spent catalyst slide valve. e) Maintain the feed rate at 60% of capacity for one hour, decrease the disengager temperature to 510°C and prepare to inject fuel-gas in the fractionator reflux drum to keep the control of the disengager pressure. f) Reduce the LCO production to make the slurry oil lighter. Maintain products on specifications by keeping drawoff-tray temperatures, adjusting pumparounds and reflux.

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g) As coke make decreases, regenerator temperatures will have a tendency to decrease. Light air heater to keep a minimum of 650°C in the regenerators. Keep catalyst circulation for at least 15 minutes to regenerate the whole batch of catalyst with a temperature in the regenerators of around 600/650°C. Avoid to use torch oil. Watch carefully the main air blower to avoid surging. Stop the burners in CO Boiler or incinerator and apply Manufacturer instructions to stop the boiler. h) Shutdown passivator injection and isolate the chemical injection from the feed line. 8.3.3

Oil out of riser

a)

From 60% feed rate, reduce the feed to 10 to 20% as quickly as possible. Be sure to maintain stabilization and dispersion steam at operating flow rates to keep the riser lift. Reduce the air rates to about 50% of the normal operating flow, while observing regenerator temperature profiles.

b)

At 10 to 20% of capacity, activate the reaction section bypass and block in oil feed to the riser feed injectors. Admit LCO from storage to the feed surge drum, and then flush feed lines and torch oil lines with light feed to dedicated HSO connection. Adjust vessel pressure as necessary to maintain pressure differentials. Reduce regenerator pressures and increase the main fractionator pressure as necessary while maintaining adequate catalyst slide valves differential pressure. Continue catalyst circulation on steam with dispersion and stabilization steam.

c)

Switch fuel gas purges to nitrogen purges on disengager stripper section.

d)

The isolation valve MOV-001 can be closed at this stage, after opening of the disengager vent line.

8.3.4

Coke burn-off

a) Place regenerated and spent catalyst slide valves on manual control as the regenerators begin to cool. Using manual control, lower the level of catalyst stripper as low as possible without losing the spent slide valve differential pressure. b) Continue catalyst circulation until there is no appreciable temperature difference between the first and second regenerator dense phases. c) Begin unloading catalyst when dense phases cool down to 400°C. 8.3.5

Stop catalyst circulation a) When no temperature rise exists between the first and second regenerator dense phases close the regenerated slide valve and stop the catalyst circulation. Close the plug valve on manual hydraulic control. b) Lower the stripper level until the pressure differential across the spent slide valve reaches 0.1 kg/cm2. The first regenerator pressure may be reduced to 0.1 kg/cm2 less than the disengager pressure to facilitate this transfer. At this point the disengager pressure should be maintained 0.1 kg/cm2 higher than the first stage regenerator to prevent air flow through the spent slide valve from the regenerator to the disengager. Close the spent slide valve and prevent from reopening except to dump any additional catalyst that may collect in the stripper. If the first regenerator dilute phase or flue gas temperature increases this could indicate that gas

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is flowing from the disengager to the regenerator. If this occurs, adjust the disengager and first regenerator pressure to the same value. c) Control pressures on both regenerators to the same value, between 0.7 and 0.9 kg/cm2g. Continue to unload the catalyst. 8.3.6 a).

Closing of MOV-001 at main fractionator inlet Blind hydrocarbon sources to the feed system and to the riser. Switch the fuel gas purges on the stripper/disengager to nitrogen.

b). Cool the main fractionator bottom. Stop reflux and pumparound flows. Empty the main fractionator bottom level. Depressure the main fractionator. Start steam injection from the bottom of the main fractionator to purge out hydrocarbon vapors. c).

Reduce the dispersion steam flow rate and stripping steam flow rate to about 50 % of the normal operating flow. Steam out to atmosphere through the vent for 15 minutes.

d). Reduce the steam flow in the main fractionator, feed, MTC, stabilization injectors, and put stripping steam to minimum. Open vent valve to SL-1501 upstream of MOV-001 on the transfer line, to prevent forming a vacuum in the vessels when steam flow is stopped. e).

Following plant safety procedures and using precaution so that employees are not exposed to sour gas and/or super-heated steam, close MOV-001 at the main fractionator inlet.

f).

Be sure that the purge HPS to MOV-001 is closed prior MOV-001 operation.

g). After closing MOV-001 at the main fractionator inlet, the shutdown operation in the main fractionator and gas recovery sections may proceed independently. h). Re-establish dispersion steam flow at about 50 % of the normal flow rate and stripping steam at 30%. If necessary, throttle the disengager vent to equalize the disengager pressure to the same value as the regenerators. 8.3.7

Catalyst removal

a) Continue unloading the regenerators. Normally the second regenerator will empty first. b) When the second regenerator is empty, open slightly the regenerated slide valve and empty the withdrawal well and regenerated catalyst standpipe. Lift this catalyst up through the riser into the stripper with dispersion steam. Dispersion steam rate, second regenerator pressure, and disengager vent may have to be adjusted to accomplish this transfer. c) When the regenerated catalyst slide valve differential reaches 0.1 kg/cm2 close the slide valve. d) Equalize the pressure on the disengager and on the second regenerator. e) Open the spent catalyst slide valve and empty the stripper to the first regenerator. Close the spent catalyst slide valve. f) Continue unloading the first stage regenerator until no more catalyst can be unloaded. g) Be aware of the disengager temperatures during the unloading procedure as an increase in temperature may indicate burning of coke adhered to the vessel dome or walls. If this occurs, increase the disengager pressure to be slightly higher than regenerator pressure.

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8.3.8


Unit cooldown a) After all the catalyst has been unloaded, reduce the regenerator pressures to minimum to reduce the blower discharge temperature for refractory cooling. b) Block in the dispersion and stabilization steam and continue to cool the disengager/stripper with stripping steam. When the disengager temperature has fallen below 200°C, the steam flow can be stopped on steam rings and air admitted via the temporarily plant air line. Nitrogen purges on the reaction section can be replaced by air purges. Caution : When this is done, disengager/stripper temperatures should be monitored very closely to observe any sign of burning. Stop air flow and re-admit steam at any sign of temperatures rise which would indicator coke burning.

c) Continue cooling the regenerators with blower air until the dilute phase temperatures are within 15°C of the blower discharge temperature. d) When the unit is cool, the blower may be shutdown in accordance with the Manufacturer’s instructions. Note: Before any vessel entry or hot work is permitted, the proper safety requirements must be met. Personnel must be aware of the possibility of pockets of hydrocarbon or H2S which may be present.

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8.4 Short period shutdown If the shutdown is foreseen to last a short period it is not necessary to unload the catalyst as long as the catalyst does not cool down too much. If necessary, use torch oil to keep at least 600°C in the regenerators. Cut off the feed by following the above procedure from scheduled shutdown and keep catalyst in circulation with steam in the riser.

8.5 Automatic emergency shutdown (ES) Automatic emergency shutdown can be carried out through the various safety sequences described below. However operators must carefully analyze the initiating events and their possible causes in order to prevent, whenever possible, the emergency shutdown. Anytime an emergency shutdown is necessary, other units affected by the shutdown must be notified as soon as possible. The object of an emergency shutdown procedure is first to make the unit safe for personnel and equipment and second to have the unit in condition for a prompt start-up when the emergency conditions have passed. In most emergency shutdowns, the first action is to take the feed out of the unit and simultaneously increase dispersion steam to clear the riser. The disengager/stripper is then segregated from the regenerators by closing the regenerated catalyst slide valve and the spent catalyst slide valve. After these steps are taken, other variables can be adjusted to prepare the unit for re-start. The first steps in an emergency shutdown should be committed to memory by all operating personnel. No written procedure can encompass all of the possible symptoms and difficulties encountered during an emergency condition. The following scenarios are supplied as representing some of the major reasons in an emergency shutdown of the RFCC. Changes in process conditions can occur rapidly during an emergency condition and require intelligent and safe judgement. This can only be attained through classroom and on-the-job training and operating experience. The emergency shutdown sequences are designed to put the unit in a safe condition for some of the known conditions, such as loss of air blower or loss of feed. The unit operator should verify that the control valves have moved to their fail-safe position when they are activated and must confirm that feed to the riser is shut-off by checking that the riser air operated valve is closed and that the valve on the return to feed surge drum is open. The main fractionator pressure must be watched carefully and fuel gas must be brought in as required to hold the disengager pressure. If feed can be re-established quickly, raise the feed circulation to 60% of capacity and proceed with restart after having at least 510°C in the disengager. Notes: 1. Avoid return of air in the riser and stripper section by adjusting the pressure of the disengager 0.1 kg/cm2 higher than the pressure of the first regenerator. 2. When injecting torch oil to keep the catalyst temperature, always check that there is an excess of oxygen in the flue gas. 8.6 Injectors Inspection and Maintenance Typically the feed, MTC, steam and backwash injectors should be inspected for wear at normal unit turnarounds. They usually require minimal maintenance. If erosion occurs, the concerned part is the injection tip. 8.6.1

Inspection

Injector tips can be inspected visually from inside the riser, it is not necessary to remove the injector for inspection. If erosion and tip damage is noticed it can be necessary to remove the injector for maintenance.

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8.6.2 A)


Maintenance Principle

Injector tip is made of high strength alloy coated with stellite hard facing. Due to the stellite it is not recommended to attempt repair in the field. Consequently, it is recommended to have a complete set(1) of feed, MTC, steam, and backwash injectors as spare in the warehouse. Note: Spare injectors are covered in the 2 years spare list. (1) Complete set: Junction flange, venturi, tip, threated rod, nuts, and gaskets for each type of injector. B)

Replacement operation

In case of damage, remove piping and mixing chamber from riser nozzle flange. Injector should be replaced in the same sleeve from which it was taken by a new complete set of injector, or by the same injector after a tip replacement (injector flanges and riser flanges are matched marked at original installation). C)

Tip replacement

The injector tip should be replaced as a unit with the warehouse spare tip. Remove the injector from the vessel sleeve and take it to the maintenance shop. After confirming the integrity of venturi orifice. 1. Measure the new tip length and mark the injector venturi for cutting at this length. The new tip is sized to place the new weld outside of the present weld zone (about 20 mm). 2. Verify that the overall length of the injector will remain the same when tip assembly is mounted at the marked cut line. 3. Match mark the injector venturi upstream of the cut line to ensure proper injector slot orientation when the new tip assembly is installed. 4. Saw cut the old assembly and remove it from the venturi. 5. Prepare the saw cut end of the feed injector venturi for welding. This bevel should approximate the bevel provided on the new tip assembly. Note: Grinding discs shall be compatible with stainless steel to avoid contamination of the base metal. 6. Align the new tip assembly to the existing feed injector venturi. Tack weld injector tip assembly to the injector venturti using the Gas Tungsten Arc Welding (GTAW) process. Welding procedure and filler material shall be provided by Injector Vendor. 7. Weld the root pass using the GTAW process between the injector tip assembly and the venturi with weld filler metal. Clean the weld upon completion with a stainless steel brush or compatible grinding disc; all slag, scale and impurities must be removed prior to the next weld pass. Note: All welding shall be full penetration. 8. Continue welding the injector tip assembly to the venturi cleaning between weld passes using the GTAW process until the weld thickness equals the injectors venturi thickness.

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9. Remove the purge and visually examine the weld. The root pass visible through the injector tip assembly shall be clean and free of concavity and convexity. The exposed surface shall be free of slag, inclusions, cracks, etc. 10. Perform a dye penetrant examination on the weld and correct any finding. 11. Upon successful completion of inspection, the feed injector is ready for reinstallation. 12. Verify the injectors are clean for operation. D)

Injector reinstallation

The injector is then reinstalled in the riser in the proper orientation. • Pack the annular space between the injector and internal refractory sleeve with kaowool or ceramic paper. • Reconnect piping and mixing chamber for operation.

8.7 Shutdown of the Fractionator Section 8.7.1 Normal shutdown This section describes the normal planned shutdown of the unit, as for scheduled maintenance. The procedure outlines the general philosophy. This procedure must be elaborated in detail by operating personnel for each shutdown circuit at the time of shutdown. 8.7.2 Feed reduction and removal As feed to the reactor is reduced, gradually reduce the HCO, LCO and heavy naphtha pumparound duties, with the aim of keeping products on specification. As the shutdown proceeds, send products to slops. The duty of the slurry pumparound is also reduced. Keep the flowrate to the grid at normal flowrate to avoid coking while feed temperature is still high. Keep the quench rate high to keep the bottom temperature at or below 340°C. By reducing the bottom temperature, flowrates through the slurry exchangers can be maintained high as duties are reduced. As gas production is reduced, reduce compressor speed. Bring the compressor speed to a minimum and operate the compressor on spill-back to maintain control. Bring fuel gas or nitrogen into the line from the fractionator reflux drum as necessary. A. Upper section fractionator (LCO section to overhead section) When feed to the riser has been cut proceed as follows: - Stop corrosion inhibitor injection, if not already stopped. - Pump out sour water to the sour water stripper and stop the overhead sour water pumps. - Stop the reflux pump. - Pump out as much hydrocarbon liquid as possible from the overhead drum to the absorber-stripper and then stop the overhead liquid pump. - Cool down the heavy naphtha and LCO pumparounds and stop the pumps. - Stop reboiling and pump out the heavy naphtha stripper to slops and stop the product pump. - Stop the LCO stripping steam. Pump out the LCO stripper to slops.

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B. Lower section of Fractionator (HCO and slurry sections) When feed to the riser has been cut proceed as follows: - Continue operation of the HCO pumparound. - Continue operation of the slurry circuit to cool down the bottom of the fractionator. - Bring feed in from the feed section to the bottom of the fractionator. Run down via the clarified oil circuit while continuing to circulate the slurry pumparound. - Reduce the level of feed in the feed surge drum to a minimum, then bring in LCO to the drum. - Bring in LCO to the bottom of the fractionator to flush out the slurry product section and slurry pumparound circuits while running LCO to clarified oil storage or to slops. - Bring LCO into the HCO circuit to flush the HCO pumparound and HCO circuits. The LCO can be brought in via the connection on the LCO pumparound and overflowed down the column. - Stop HCO stripping steam and pump out as much hydrocarbon liquid as possible from the HCO stripper to the HCO flushing oil drum. Ensure that LCO is also available for flushing oil to the HCO flushing oil drum. 8.7.3 Main Fractionator MOV-001 closing Closing operation of MOV-001 between the main fractionator and the reactor must be coordinated between the two sections. Stop feed of LCO to the fractionator if this has not already been stopped. Stop circulation of the HCO and slurry pumparounds. Reduce the fractionator level below the steam out connection and depressurize the main fractionator section to flare. Start steaming out the fractionator via the bottom steam out connection. Steam out the main fractionator for a minimum of one hour to remove any hydrocarbon . Reduce steam flows to the main fractionator and the reactor to a minimum, allowing both sides of MOV-001. Close MOV-001, slowly. After closing MOV-001, steam flows to the reactor and main fractionator may be restarted. Shutdown operations in the fractionation and vapor recovery sections can proceed independently of the reaction section. 8.7.4 Fractionation section hydrocarbon removal At this stage, all vessels should have been pumped out to minimum levels. Shut-off all flushing connections to the fractionation section. Drain all remaining liquids to the closed drain system. Steam out all vessels to flare to remove the bulk of the hydrocarbon vapors. After steam out to flare, open vents and drains and steam out to atmosphere. Drain condensate from low points. When steam flow is stopped, ensure that vents are open to prevent vacuum conditions. Following plant safety rules, install blinds and open vessels as required. Personnel must be aware that there may be pockets of hydrocarbon or H2S. 8.8 Gas recovery section shutdown 8.8.1 Shut-down Procedure of gas Recovery Section The shutdown of this section must be closely coordinated with the fractionation section shutdown. As feed to the unit is reduced, the overhead liquid distillate and wet gas from the fractionation section reduces. Reduce the stripper and debutanizer reboiler duties gradually, with the aim of keeping gasoline

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and LPG on specification. As the shutdown proceeds send light gasoline to slops and LPG to offspecification storage. - When gas flow from the fractionator has stopped and catalyst circulation has stopped (and the catalyst slide valves are closed) stop the compressor. - Stop the water wash to the intercooler and isolate the compressor stages by closing suction and discharge valves. -

-

-

Depressurize the compressor sections to fuel gas and then to flare. While the fractionation section is being shutdown stop the lean oil pump. Pressurize the liquid in the secondary absorber back to the fractionator. Also pressurize any liquid in the fuel gas absorber feed knock-out drum back to the fractionator. Pump out as much liquid as possible from the compressor interstage drum to the HP separator drum. When there is no longer a flow of liquid distillate from the fractionation section to the primary absorber, drain remaining liquid from the primary absorber to the HP separator. Pump the hydrocarbon liquid from the HP separator to the stripper and pressurize sour water to the sour water stripper section. Pressurize liquid from the stripper to the debutanizer. Pressurize amine from the fuel gas absorber column and outlet KO drum to the amine unit. Depressurize the stripper, primary and secondary absorbers and fuel gas absorber to fuel gas and then to flare. Pressurize liquid from the bottom of the debutanizer to light slops. Pump out LPG from the debutanizer reflux drum to the LPG amine absorber. As this LPG may be off-specification, it should be sent to off-specification storage after the LPG treating unit. Stop flow of lean amine. Pressurize sour water from the boot of the debutanizer reflux drum. Isolate the debutanizer section and depressurize to flare. The recovery of LPG from the LPG amine absorber and coalescer should be maximized by manually increasing the amine /LPG interface. Pressurize amine to the amine unit from the column and from the coalescer. The vessels should be pressurized with nitrogen to avoid freezing as the pressure decreases. Drain remaining liquid to the amine drain and depressurize the vessels to flare.

8.8.2 Gas recovery section hydrocarbon removal At this stage, all vessels should have been pumped out, or pressurized, to minimum levels and all sections depressurized to flare. Drain any remaining hydrocarbon liquids to the closed drain and any amine to the amine drain. The compressor stages suction and discharge valves are closed and the two compressor stages have been depressurized. Purge the compressor stages with nitrogen to flare and then to atmosphere. Steam out all vessels to flare to remove the bulk of the hydrocarbon vapors. After steam out to the flare, open vents and drains and steam out to atmosphere. Drain condensate from low points. When steam flow is stopped ensure that vents are open to prevent vacuum conditions. Following plant safety rules, install blinds and open vessels as required. Personnel must be aware that there may be pockets of hydrocarbon or H2S.

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9


EMERGENCY SHUTDOWN PROCEDURE

9.1 Emergency sequences Summary Emergency shutdown systems operate automatically upon the occurrence of the undesirable events but can also be activated by operators. This covers the following emergency sequences: • UX-001 (ES1) – Feed Outage • UX-002 (ES2) – Catalyst Circulation Failure • UX-003 (ES3) – First Regenerator Air heater trip • UX-004 (ES4) – Second Regenerator Air heater trip • UX-005 (ES5) – Air Blower Failure • UX-907 (ES7) – COB/WHB Failure (by COB/WHB Vendor) • UX-901- COB Combustion failure (by COB/WHB Vendor) • UX-008 (ES8) – COB/WHB First Regenerator Flue Gas Bypass Valve • UX-009 (ES9) – Electrostatic Precipitator Trip • UX-010 (ES10) – COB/WHB Second Regenerator Flue Gas Bypass Valve • UX-013 (ES13) – Economiser Bypass Operation • (ES14) – DeSOx Unit (Future) Note: ES-XX in ( ) shows original Axens’s ES numbers. Operators must be thoroughly familiar with these sequences and able to perform the emergency sequence step by step, should the automatic system fail. For the right understanding of what follows, operators must refer to the emergency systems Cause and Effect Table and the relevant PID's. Note: Restart of the unit For restarting the unit after a maintenance shutdown or an emergency shutdown, the normal start-up instructions should be followed. In case of air blower shutdown during an emergency shutdown, specific care must be taken to restart the air blower (refer to air blower failure).

9.2 Detail Description of Emergency Trip System 9.2.1

Emergency Shut-down System

Refer to Cause & Effect Chart 8474L-015-DW-1514-602, in detail function. Note: ES-XX in ( ) shows original Axens’s ES numbers. UX-001(ES1): FEED OUTAGE (Reaction Stop) ♦ Initiators: –

Hand switch in control room. (UXHS-001)

–

Signal from UX-002(ES2)

–

Signal from Feed Flow Stop (FALL-405).

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♦ Actions: –

Close valve XV-002 to stop feed to injectors I-1501A - F

–

Open valve FV-001 to send feed oil to surge drum D-1513

–

Close valve XV-003 to stop MTC to injectors I-1502A-D .

–

Close valve XV-004 to backwash recycle oil to injector I-1504.

–

Stops metal passivator injection pump P-1502AB in feed line.

–

Stop MTC injection pump P-1512AB.

–

Stop backflush oil recycle pumps P-1508AB.

–

Stop HCO recycle pumps P-1507AB to riser .

–

Open valves on steam injection FV-005A - F of feed injectors to fully admit dispersion steam to riser.

–

Open valves on stabilization steam injectors FV-007A - D to fully admit stabilization steam to riser. UX-002(ES2): CATALYST CIRCULATION STOP ♦ Initiators: –

Hand switch in control room (UXHS-002)

–

Low low D-1501 Disengager/Stripper level by PDXALL-064

–

Low low pressure drop across the spent catalyst slide valve SV-1502 by PDXALL-104

–

Low low withdrawal well level by LXALL-010

–

Low low pressure drop across the regenerated catalyst slide valve SV-1501 by PDXALL242

–

Low low air flow rate to air lift by FXAL-172, first regenerator by FXAL-170, second regenerator by FXAL-171.

–

Air Blower trip UX-005 (ES5).

–

Signal from low MP steam pressure on MPS supply sub-header to Reactor, by PXAL-363.

♦ Actions: –

Close the spent catalyst slide valve, SV-1502

–

Close the regenerated catalyst slide valve, SV-1501

–

Close the plug valve, PV-1501

–

Activate UX-001(ES1), feed outage

–

Activate UX-008 (ES8) to open First Regenerator Flue Gas by-pass of COB/WHB

– Activate UX-010 (ES10) to open Second Regenerator Flue gas by-pas of COB/WHB. UX-003(ES3): FIRST AIR PREHEATER TRIP ♦ Initiators:

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–

Hand switch in control room, UXHA-003A

–

Pilot flame detector, BXAL-003

–

Main flame detector, BXAL-004

–

Low low air flow rate to heater, FALL-170

–

Low low fuel gas pressure, PXALL-321

–

High high temperature air heater H-1501 outlet, TXAHH-069

–

Air blower trip, UX-801 (ES5)


♦ Actions: –

Close the valve on fuel gas XV-016 and XV-017 to First Regenerator Air Heater, H-1501.

– Open vent valve XV-019 between XV-016 and XV-017 UX-004 (ES4): SECOND AIR PREHEATER TRIP ♦ Initiators: –

Hand switch in control room, UXHA-004A

–

Pilot flame detector, BXAL-001

–

Main flame detector, BXAL-002

–

Low low air flow rate to heater, FALL-171

–

Low low fuel gas pressure, PXALL-321

–

High high temperature air heater H-1501 outlet.TXAHH-072

–

Air blower trip, UX-801 (ES5)

♦ Actions: –

Closes the valve on fuel gas XV-014 and XV-015 to Second Regenerator Air Heater, H1502

– Open vent valve XV-020 between XV-014 and XV-015 UX-005 (ES5): AIR BLOWER TRIP ♦ Initiators: –

Hand Switch for Air Blower Trip, UXHS-005

–

Shut down signals from Air Blower Protection (from UX-801).

♦ Actions: –

Open the blower discharge to atmosphere by UX-802

–

Closes the assisted check valves CV-1501, CV-1502, CV-1503, and CV-1504 on air blower discharge lines.

– Actuates UX-002 (ES2), catalyst circulation UX-907 (ES7): CO BOILER Steam Drum Level FAILURE ♦ Initiators:

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–


–

High high liquid level in steam drum (LXA-901)

–

Low low liquid level in steam drum (LXA-902)


♦ Actions: –

Open the First Regenerator Flue Gas COB/WHB by-pass valves, BV-1501B and Close the valves to COB/WHB, BV-1501A (Interlocking)

–

Open BFW injection valves, XV-058A / XV-058B and Atomizing MPS XV-059

–

Open COB/WHB flue gas bypass valves BV-1502A and close flue gas block valve BV1502A (interlocks)

–

Opens BFW valves XV-056A and XV-056B to bypass sprayers and opens MP steam valve XV-057 to bypass valves sprayers.

–

Shut-down fuel gas and fuel oil to all burners

– Close damper at FD fan and open LP steam purge UX-901: COB Combustion Control Failure ♦ Initiators: –


–

Pilot fuel gas low low pressure (PXA-908)

–

Pilot fuel gas high high pressure (PXA-908)

–

Fuel gas low low pressure (PXA-913)

–

Fuel gas high high pressure (PXA-913)

–

Fuel Oil Pressure low low (PXA-921)

–

Fuel Oil pressure high high (PXA-921)

–

Atomizing steam/Fuel oil diffential pressure low low (PDXA-915)

–

Combustion air flow low flow (FXA-932)

–

Flame failure detector (4 out of 5 burners)

♦ Actions: –

Close pilot gas valves (all burners)

–

Close fuel gas valves (all burners), activates by upset fuel gas pressure

–

Close fuel oil valves (all burners), activated by upset fuel oil pressure

–

Close FD fan discharge valve

– Open LP steam purge at FD fan discharge UX-008 (ES8): First Regenerator flue gas COB/WHB BY-PASS ♦ Initiators: –

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Hand switch in control room, UXHS-008

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–

High high flue gas temperature in CO Boiler bypass line TXAHH-089A/B

–

COB/WHB Trip signal by UX-907

–

Activates by UX-002 (ES2), catalyst circulation.

♦ Actions: – –

Opens MP Steam valve XV-059 to bypass valve sprayers (two signals). Open BFW injection valves, XV-058A / XV-058B

–

Open the First Regenerator Flue Gas COB/WHB by-pass valves, BV-1501B and closes the valves to COB/WHB, BV-1501A (interlocking) UX-009 (ES9): ELECTROSTATIC PRECIPITATOR ♦ Initiators: –


–

by Vendor.

♦ Actions: – by Vendor. UX-010 (ES10): Second Regenerator Flue Gas By-Pass of COB/WHB ♦ Initiators: –


–

High high flue gas temperature in WHB bypass line (two signals), TXAHH-082AB

–

COB/WHB Trip signal by UX-907

–

Activates by UX-002 (ES2), catalyst circulation.

♦ Actions: –

Opens COB/WHB flue gas bypass valves BV-1502B and closes flue gas block valve BV1502A (interlocks).

–

Opens BFW valves XV-056A and XV-056B to bypass sprayers

–

Opens MP steam valve XV-057 to bypass valves sprayers.

UX-013 (ES13): Economizer Bypass ♦ Initiators: –


–

High high flue gas temperature in Economizer outlet line TXAHH-098AB

–

Economizer By-pass signal by UX-906 (by Vendor), activated by low low HPBFW flow to Economizer

♦ Actions: –

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Open ROV-005 (by-pass open)

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–


Open BFW valves XV-060A and XV-060B to bypass sprayers.

– Open MP steam XV-061 to bypass sprayers. (ES14): DESOx Unit Bypass (Future) The following ESD are anticipated, but to be reviewed and develop in future. ♦ Initiators: –

Hand switch in control room.

–

by Vendor.

♦ Actions:

9.2.2

-

Open the DeSOx bypass valve.

-

Close the inlet valve to DeSOx unit.

Inventory Isolation and Equipment Protection

Refer to Cause & Effect Chart 8474L-015-DW-1514-602, in detail function. The following are list of the inventory isolation, equipment protection, and depressuring system. UX-421 D-1513 OVERFILLING PROTECTION UX-422 P-1501A/B PROTECTION UX-423 T-1501 & P-1507A/B INVENTORY ISOLATION UX-424 T-1501 & P-1508A/B INVENTORY ISOLATION UX-425 SLURRY PUMPS P-1519A/B/C PROTECTION UX-426 T-1501 & P-1519A/B/C INVENTORY ISOLATION UX-427 T-1504 & P-1509A/B INVENTORY ISOLATION UX-428 P-1515A/B PROTECTION UX-429 P-1511A/B PROTECTION UX-430 D-1514, P-1516A/B & P-1518A/B INVENTORY ISOLATION UX-431 D-1524, P-1517A/B INVENTORY ISOLATION UX-432 D-1515 OVERFILLING PROTECTION UX-433 P-1504A/B PROTECTION UX-434 P-1506A/B PROTECTION UX-435 D-1517 OVERFILLING PROTECTION UX-436 P-1505A/B PROTECTION UX-437 D-1516 OVERFILLING PROTECTION UX-438 P-1521A/B PROTECTION UX-439 P-1522A/B PROTECTION UX-440 D-1522 OVERFILLING PROTECTION UX-441 P-1526A/B PROTECTION UX-442 D-1523 OVERFILLING PROTECTION UX-443 P-1527A/B PROTECTION UX-444 P-1528A/B PROTECTION UX-705 C-1551 ISOLATION & PROTECTION UX-706 P-1551A/B PROTECTION UX-707 D-1553 INTERFACE ISOLATION UX-708 D-1553 INVENTORY ISOLATION

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UX-709 UX-710 UX-712 UX-713 UX-714 UX-715 UX-716 UX-717 UX-718 UX-719


D-1556 INTERFACE ISOLATION T-1555 INTERFACE ISOLATION T-1554 INVENTORY ISOLATION D-1554 INTERFACE ISOLATION D-1554 INVENTORY ISOLATION T-1556 INTERFACE ISOLATION D-1555 INTERFACE ISOLATION T-1556 DEPRESSURIZATION D-1559 INTERFACE ISOLATION D-1553 DEPRESSURIZATION

9.3 Emergency shutdown by operators 9.3.1

General

The most common causes of emergency shutdowns are described below, together with their effects and the actions to be undertaken. In several cases, a number of actions are carried out by the emergency sequences. But operators must always check the satisfactory completion of the sequence and complement it as described. In addition they must be able to perform the safety sequence in manual mode, if needed. A few actions (through hand-switches) are left to operators judgement, who can anticipate the automatic action. The sequences must be reviewed before start-up In most of failure cases, it is recommended or required to stop the feed to the unit. This can be done by activating the emergency system UX-001 (ES1). Each time the following operations must be achieved: ♦ Check that feed has been bypassed back to the feed surge drum ♦ Check that all recycles to the riser have been stopped. ♦ Check that passivator injection has been stopped. ♦ Close the control valves on feed and recycle lines. ♦ Check that dispersion steams, stabilization steam and riser bottom steam are effective. ♦ If the duration of the failure exceeds a couple of hours, the fuel gas purges on the reaction section should be switched to nitrogen purges. 9.3.2

Power failure

A failure of electrical power will result in an emergency shutdown of the unit. Steam pressure will generally be kept for a short time. However, refinery wide power failure results in steam failure, subsequent to power failure, as sea water and BFW will stop at refinery wide power failure. Instrument indications and controls should not be affected by UPS system. The consequences and emergency sequences to be followed will depend on the localized power failure or refinery wide power failure.

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Note that Air Blower and Wet Gas Compressor will also stopped at power failure, since sea water to the turbine’s surface condensers will be stopped during power failure as sea water pumps are driven by motor. Refer to the corresponding equipment failure described hereafter. The object is to get the unit into a safe condition while battery power or alternate power is available to the instruments. The following will occur: ♦ Feed oil will stop ♦ Disengager will depressurize rapidly ♦ SCSV differential pressure will fall ♦ Cooling water supply temperature will increase as fans are inoperative. The following actions should be taken immediately: a) Activate ES1, block in all oil feed to riser. Place RCSV, SCSV, and plug valve on manual and close. Shutdown passivator injection. b) Adjust fresh feed dispersion steam and all other oil injectors dispersion steam to minimum. c) Adjust pressures as required to control differential pressures. Reduce combustion air rates to 50% operating conditions if possible. d) Due to lack of sufficient cooling in the main fractionator overhead system, any steam usage in the riser should be minimized. e) Stop heating steam to E-1522 and E-1524. f) Stop stripping steam to T-1503 & T-1504 Specific note for steam demand management between RFCC and PRU. Though, PRU is not part of RFCC, but complex of RFCC group. PRU should be also brought into emergency mode operation, during upset of RFCC. Since PRU compressor C-2101 consumes substantial HPS (30-35 ton/hr), stop C-2101 for proper management of HPS demand, during emergency of RFCC. When electrical supply is re-established check operation of pumps and air coolers. Restart the unit following normal start-up procedures. 9.3.3 Instrument air failure Usually instrument air failure is of short duration and the unit can be started-up immediately after return to normal conditions. However, loss of instrument air will require an emergency shutdown of the unit. Supervision should set a standard for minimum instrument air pressure for continued operation. Although control elements will drift toward their fail-safe positions, operator intervention is required to manage the shutdown. If falling air pressure reaches the minimum pressure, the emergency shutdown sequence should be enacted. a) Activate UX-001(ES1) to bypass feed and recycles from the riser, block in oil to the riser, and continue dispersion and stabilization steam to clear the riser. b) Place the regenerated catalyst slide valve on manual and close. c) When the stripper level begins to fall, place the spent catalyst slide valve on manual and close.

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d) Set the dispersion steam to about 50% flow rate and reduce the stripping steam to 50% of the operating conditions. e) Close the plug valve but be careful not to overfill first regenerator. f) Adjust the air rates to about 50% flow rate but be careful not to lose air lift flow. g) When feed is cut out of from the riser, the disengager pressure will fall rapidly. Adjust pressures as required to maintain the spent catalyst slide valve differential. h) Start torch oil and on through bypass valve and keep the temperature near 600°C in the regenerators. Due to loss of purge air or instrument supply air, instruments and level indicators may begin to give false signals. Look for correlating variables, especially temperatures to help understand the status of the process. For this reason, extreme care should be taken in making any moves on the levels when there is no instrument air pressure. Continuous operator attention is required where the process is on hand valve control. i)

Determine the expected duration of the outage. If less than 24 hours the catalyst can be maintained hot with torch oil. The disengager pressure should be maintained at least 0.1 kg/cm2 higher than the regenerator pressure to keep air out of the disengager.

j)

When instrument air is re-established return to control on the various hand valves that are being used. Check all instrument purges to ensure they are not plugged and see that instruments are reading correctly.

k) Check all nozzle points to see that they are not plugged and place them in service. l)

When this has been accomplished the unit may be started using the normal start-up procedure.

Note:

1. The major problem will come from the air blower which can surge or choke during transient operations. Snort valves will fail close and valve controlling air to the air lift will fail in position. This is important to avoid return of catalyst from second regenerator into first regenerator. Possibility to run the air blower in these conditions must be checked with the machine manufacturer.

9.3.4

Fluidization / Aeration / Purge Air and FG failure

Loss of fluidization, aeration, or purge air flow will require the unit to be shutdown. Erroneous instrument readings and or catalyst circulation instability make the unit uncontrollable without operator action. a) Activate UX-001(ES 1) to bypass the riser, block in the oil feed and adjust the dispersion steam at the rate of 50% operating conditions. b) Shutdown passivator injection. c) Put the regenerated catalyst slide valve on manual and close. d) When the stripper level begins to drop out the spent catalyst slide valve on manual and close. Close the plug valve but be careful not to overfill first regenerator. e) When feed is cut out from the riser, the disengager pressure will drop rapidly.

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f) Adjust pressures as required to maintain a positive spent catalyst slide valve differential. g) Be aware that instruments taps on the regeneration and reaction section may plug up and give false readings. Therefore exercise extreme caution in making any moves on the regenerators. By closely monitoring the regenerators temperature profile the unit may be kept hot with torch oil. The tap should be checked for pluggage after aeration is re-established. When assured that all taps are free, the unit may be re-started as for a normal start-up. Note:

1.

9.3.5

In disengager side only, fluidization, aeration and purge are supplied with fuel gas in normal operation, but nitrogen take place for start-up and FG failure.

Steam failure

Loss of steam will require a complete shutdown of the unit due to loss of the Air blower and wet gas compressor, and loss of dispersion, stabilization and stripping steam. a) Actuate UX-001(ES1), bypass the riser, block in all oil feeds to the riser, and shut down the passivator injection system. b) Close the RCSV (SV-1502) on manual control. Maintain dispersion steam as long as possible to clear the riser of catalyst. c) When the stripper catalyst level begins to drop, close the SCSV (SV-1501) on manual control. Close the plug valve being careful not to allow the first stage regenerator to overfill. d) When oil feed is cut out of the riser, the system pressure will drop rapidly. As necessary, adjust system pressure to maintain the adequate differential on the SCSV (SV-1501) e) Transfer as much as possible the catalyst retained in the stripper to the first regenerator by carefully opening the spent catalyst slide valve. Avoid pressure differential to go below 0.1 kg/cm2. f) Since the air blower is steam driven the regenerator catalyst beds will slump. Torch oil cannot be used to maintain regenerator temperatures without proper catalyst fluidization. Ensure that the plug valve does not open as that would cause the catalyst in the second stage regenerator to flow into the first stage regenerator. Block in steam headers to the process before steam header pressure falls below regenerators pressures. g) The wet gas compressor is also steam turbine driven and will shut down. It will be necessary to depressure the main fractionator to prevent the potential of hydrocarbons backing into the regenerators. The depressurizing control valve PIC-458 at the outlet of D-1514 should be set to open at a pressure of around 0.15 kg/cm2 above the normal operating pressure to prevent the converter from slumping. h) The slurry circuit should be flushed to prevent any plugging problems as the slurry system cools down. i)

Determine the expected duration of the outage. If the expected start-up will be within 48 hours, the unit can remain hot on torch oil control after getting the air blower back in operation. If the outage is expected to extend beyond 48 hours the catalyst should be emptied from the unit. When steam supply is re-established, first assure that steam headers are dry all the way up to

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the process and then start stripping, dispersion and stabilization steam. When this is done, the unit may be restarted using the normal start-up procedure. j)

If no operator intervention is taken upon loss of steam pressure, the catalyst circulation will stop due to loss of riser lift. When feed is cut off due the temperature increases, the riser will slump. This can lead to extended shutdown and plugged equipment which is difficult and costly to clear. Exceedingly high temperatures in the regenerator can be experienced upon the loss of dispersion, stabilization, and stripping steam if feed is not cut off immediately.

k) When steam is available begin circulation of the slurry system and, if necessary, use torch oil as in the normal start-up. Confirm that the steam is dry and then establish both stripping and main fractionator steam. Control pressure on the main fractionator as required to maintain differentials between the disengager regenerators. At this point the unit can be restarted following the normal start-up guidelines. 9.3.6

Boiler feed water failure

Loss of boiler feed water (BFW) will require a shutdown of the RFCC unit. Actuate UX-001(ES1). Additionally, the loss of steam production may lead to a steam failure. If this happens, the procedure for steam failure should be followed. A BFW failure will require bypassing the flue gas equipments (CO Boiler and waste heat boiler), and maintain water circulation through the tubes as long as possible to maintain cooling on the tubes. It must be checked that the sprayers have been automatically started. The wet gas compressor and all steam generation equipment should be shut down. As liquid levels require, other pumps should be shut down. When BFW is available establish levels in the steam generators and restart the unit following normal start-up procedures. 9.3.7

Cooling water failure

Loss of cooling to the fractionation and Gas Concentration section will require the shutdown of the RFCC unit. Loss of lube oil cooler of the air blower also require to trip Air Blower. Actuate UX-001(ES1), bypass the riser, block in all oil injectors feeds, and adjust the fresh feed dispersion steam rate for 50% operating condition. Place the RCSV, SCSV, and plug valve on manual and close. Since the lube oil system for the air blower, and wet gas compressor require cooling water for continued operation, shut down the wet gas compressor and air blower. Due to reduced cooling capacity in the main fractionator system, any steam usage in the reaction and regeneration sections should be minimized. Since the air blower is shut down, it will be necessary to depressurize the main fractionator to minimize disengager regenerator differential pressure and prevent to potential flow of hydrocarbons from the disengager into the regenerators. Disengager pressure should be held around 0.15 kg/cm2 above the first stage regenerator pressure. When cooling water is re-established the unit may be restarted following normal start-up procedures. The effect of cooling water loss should be studied by refinery personnel to develop a detailed plan of action.

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9.3.8


Sea water failure

Sea water is used for coolant of the surface condenser of the air blower. Therefore, failure of sea water will automatically trip of air blower, as turbine is not work properly. Follow operation procedure of Air Blower failure. 9.3.9

Air blower failure

In case of air blower failure, the unit will be shut down by UX-005(ES5), which will actuate UX002(ES2) and UX-001(ES1) systems. The pressure in the regenerators will fall rapidly resulting in possible flow reversal at the RCSV if the operator does not act immediately. Reduce the main fractionator pressure to flare to minimize the disengager / regenerator differential pressure. Bypass the fresh oil feed to the feed surge drum, block in all oil feeds to the riser, while reducing all other injector steam and stripping steam to about 50% of operating conditions. Shut down passivator injection. Place the RCSV and SCSV on manual and close. Place the plug valve on manual and close. Disengager pressure should be held at about 0.15 kg/cm2 above regenerator pressure. Catalyst may have backed into air lines so extreme care should be taken when re-establishing air flow. Normally the following actions are required to re-established air flow to the unit when restarting the blower: ♦ Close the control valves on the line to the first stage regenerator air rings. ♦ Open the plant air into the catalyst lift line between the first regenerator and second regenerator. The uppermost blast point should be started first, then open the lower blast points stepwise down the lift line. With all blast points open, slowly begin lift air from the air blower and then reduce plant air to minimum purge rates. ♦ Before to start the blower it must be checked that all air lines are free of catalyst upstream the assisted check valves. Ensure that the check valves are in closed position. ♦ Plant air connections have been provided upstream the regenerators air rings. These connections must be put in operation to clear the air rings from the accumulated catalyst. ♦ The amount of catalyst back flow into the air heaters must be checked by visual inspection. In case of significant catalyst amount in the heaters, the blast connections provided on the air lines must be put in operation to clear the lines. The connections must be put in operation one by one, starting with the connection located close to the regenerator. ♦ After clearing of the air lines, the air blower can be restart following the manufacturer instructions. ♦ Open the control valves on the line to the R-1 rings. This should be done slowly so as not to lose lift air flow. When all air flows are re-established, the unit may be started as in the normal start-up procedure.

Notes:

1.

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The unit can be restarted if the catalyst temperatures are not too low (above 400°C).

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2.


Loss of the blower by serious mechanical failure due to long duration problem, will necessitate the normal shutdown of the RFCC unit with catalyst unloading. The loss of the blower causes the fluidised bed to slump. As a result, not all catalyst is regenerated and more is fully cooled.

The critical items regarding the catalyst unloading without blower are: • To be able to maintain enough pressure in the regenerators to transfer the catalyst to the hopper (a delta pressure about 0.7 kg/cm2 – by plant air injections – should be sufficient). • To cool down the temperature in the regenerators imperatively below 300°C everywhere into the regenerators before starting the unloading, to avoid any coke combustion either in the catalyst transfer lines or in the spent catalyst hopper. During catalyst unloading, a careful survey of the temperatures in the regenerators disengager stripper, and at the top of the spent catalyst hopper should be performed. Before catalyst unloading following plant safety rules, install blinds to allow the final vacuum truck removal of the remaining catalyst as necessary. 9.3.10 Feed pump failure as loss of feed Loss of feed will activate emergency shutdown system, activate UX-001(ES1) to stop feed and recycles to the riser and bypass the riser. If the spare feed pump can be quickly started, the unit may be brought back on line in a short period of time. If unable to start a fresh feed pump, maintain the unit in a hot condition. a)

Adjust the dispersion steam at the maximum rate of operating conditions.

b)

Take the regenerated catalyst slide valve on manual control to monitor the catalyst circulation. Place the feed control on manual and close.

c)

When the feed is taken out of the unit the vessel pressure will fall. Adjust the pressure balance to maintain a positive pressure differential between the disengager and the regenerators.

d)

Start torch oil injection immediately in the regenerators to keep the catalyst about 600°C.

e)

When feed is available, re-establish the operating conditions as required before the normal oil-in (riser outlet temperature around 530°C, pressure balance,...) and restart the unit following normal start-up procedures.

9.3.11 Other pump failure Loss of any other pump will not require a shut down of the RFCC unless the spare pump cannot be started. In cases where the spare pump is unavailable, it may be possible to continue operation by adjusting unit operations. Each system should be studied to determine how to continue operation is case of pump failure. 9.3.12 Fuel gas failure Typically, fuel gas failure will not require a shutdown of the RFCC. Fuel gas is used in the CO Boiler. Switch main fuel source from fuel gas to fuel oil so that COB operation can be continue as far as possible. Loss of the CO Incinerator may require a shutdown of the RFCC since the carbon monoxide rich fuel gas

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from R-1 is released to the atmosphere. Violations of the environmental permits may force reduction of the RFCC feed. Provision is made that fuel oil can be also used for COB combustion burner. Use fuel oil firing, maximum extent at failure of fuel gas, and maintain COB operation as far as possible. If feed is cut off from the unit, the reaction / regeneration sections can be maintained in a hot condition using torch oil for 24 hours. If the outage is expected to extend beyond 24 hours, the catalyst should be emptied as for a normal shutdown. As the CO Incinerator is off-line, the heat load to the Waste Heat Boiler will be reduced and therefore steam production will diminish. Shut-down of COB will seriously affect to the overall steam balance of the refinery, including Air Blower and WGC in RFCC. Steam from the utility boilers will be used for back-up of steam demand. Reduce RFCC throughput, and reduce Air Blower and WGC load to reduce steam demand. If steam availability is critical, then cut-off heating steam of HPS and MPS to E-1522 and E-1524. When fuel gas is available, re-establish the unit following the normal start-up procedures. 9.3.13 Wet gas compressor failure Loss of the WGC will require a reduction in fresh feed rate or possibly a shut down of the RFCC. Follow any emergency procedures from the WGC vendor to safeguard the WGC. If this shutdown is for a short period of time, reduce feed flow rate to about 60% of the operating condition and flare the gas at the overhead receiver. If it not possible to flare the gas or if pressure is uncontrollable: a)

Activate UX-001(ES1) to stop feed and recycles to the riser.

b)

Place slide valves and plug valve on manual control.

c)

Control the disengager pressure higher than the regenerators pressures. Inject fuel gas in the overhead receiver as necessary. The catalyst circulation can be maintained as long as the pressure differential through the spent catalyst slide valve is kept above 0.15 kg/cm2 and as long as the steam flow in riser is sufficient to lift the catalyst (minimum velocity: 5 m/s).

d)

If catalyst circulation is maintained, check the flue gas treatment equipments (steam drum levels), check the main fractionator level and check the temperatures in the regenerators; use torch oil to maintain the catalyst about 600°C. 1. If catalyst circulation is difficult to maintain at adequate conditions unsteady pressure balance, (temperatures in regenerators), actuate UX-002 (ES2) to shut-down the unit. 2. In addition, instrument purge systems on the disengager side use treated gas from the Gas Concentration as the primary media. Automatic back-up by nitrogen will be made when supply of treated off gas is stopped as consequence of the failure of the wet gas compressor. Operations should carefully monitor the back-up nitrogen system is working.

When the WGC is ready for restarting follow vendor’s procedures and restart the unit following normal start-up procedure. Notes:

1.

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Loss of the WGC by serious mechanical failure due to long duration problem, will necessity the normal shutdown of the RFCC unit with catalyst unloading.

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2


Loss of the WGC will reduce production of RFCC off gas to the refinery fuel gas system. Since RFCC off gas is the prim source of fuel gas, proper management of fuel gas and fuel oil is required to avoid loss of fuel gas in the refinery. Maximize fuel oil firing in the major users of fuel gas.

9.3.14 Catalyst slide valve / plug valve failure For a failure of catalyst slide / plug valves, the unit may remain in operation depending upon the type of failure and which valve fails. It may be possible to continue operation with manual local control of the valve position. If this is attempted, it is very important to have continuous monitoring of the control variable and good communications between the control room and the operator at the valve. If the plug valve fails, the unit may continue to operate by controlling R-1 catalyst level with the R-1/R-2 differential pressure. Is stable control cannot be demonstrated quickly, the unit should be shutdown. a) If stable control cannot be achieved activate UX-001(ES1) to stop feed and recycles to the riser, block in all oil feeds, and shutdown passivator injection. b) Close the RCSV on manual or with the handwheel. If the RCSV cannot be closed, reduce the dispersion, stabilization steam and riser bottom ring injection to about 20-30% let the riser slump. c) Adjust pressures to hold a positive SCSV differential. The RCSV differential may go to zero if the riser is slumped. d) Hold the disengager pressure 0.15 kg/cm2 above the regenerator pressure. Notes:

1.

If catalyst valve is blocked in closed position, check that UX-001(ES1) and UX002(ES2) have been activated.

2.

If catalyst slide valve is blocked in open position activate UX-001(ES1) and try to take the other catalyst valves on manual control and adjust the valves opening to obtain a stable and constant catalyst circulation through the unit, circulation which will be dictated by the opening of the failed valve.

3.

Loss of catalyst slide valve by serious mechanical failure due to long duration problem, will necessitate the normal shutdown of the RFCC unit with catalyst unloading.

9.3.15 Loss of regenerators pressure control (flue gas slide valve failure) For a failure of flue gas slide valves, the unit may remain in operation depending upon the type of failure and which valve fails. It may be possible to continue operation with manual local control of the valve position. If this is attempted, it is very important to have continuous monitoring of the control variable and good communications between the control room and the operator at the valve. If stable control cannot be demonstrated quickly, the unit should be shutdown. If stable control cannot be achieved, activate UX-001 (ES1) to stop feed and recycles to the riser, block in all oil feeds, and shutdown passivator injection. Hold the disengager pressure 0.15 kg/cm2 above the regenerator pressure.

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Note:

1.


Loss of flue gas slide valve by serious mechanical failure due to long duration problem, will necessitate the normal shut down of the RFCC unit with catalyst unloading.

9.3.16 Control system failure For a failure of control system, the unit may remain in operation for a short time typically 10 to 15 min. Otherwise, the unit is shut down by activating UX-001(ES1) and UX-002(ES2). 9.3.17 Oil reversal This situation can occur when oil injected in the riser comes back into the second regenerator instead of being lifted up in the riser. This is the consequence of a sudden increase of disengager pressure or sudden decrease of second regenerator pressure. It is detected by a sudden rise of the second regenerator temperatures which can exceed the limit of the design and can be very dangerous. a)

Immediately actuate UX-002(ES2) and UX-001(ES1) and check that catalyst slide valves are all closed. Check that oil is effectively bypassed from riser, block all oil feeds.

b)

Decrease air rates if the temperatures continue to rise.

c)

Establish a pressure higher in the disengager than in the regenerators. Inject fuel gas in the fractionator overhead receiver.

d)

Restart the unit as soon as the reason of oil reversal is explained and corrected.

Note:

1.

In R2R process regenerated catalyst is withdrawn into an external withdrawal stand pipe. This proven system ensures an efficient seal against oil reversal.

9.3.18 Low riser outlet temperature In case of too low Riser Outlet temperature (< 480°C), the feed is not cracked and the catalyst will be socked with hydrocarbons. These hydrocarbons will be carried into the first regenerator where they will burn, causing unacceptable temperature run away. Loss of ROT will require a reduction in fresh feed rate or possibly a shut down of the RFCC by activating UX-001(ES1). The catalyst circulation can continue on automatic control, however, the operator may have to temporarily help the instruments by manually slowing the catalyst circulation rates. Feed-in can be achieved when an acceptable Riser Outlet Temperature for start-up (510-530°C) is obtained. 9.3.19 Plugged catalyst circulation It can happen that the catalyst is plugged in the lift or standpipes, especially during the start-up periods. In that case feed and recycles must be stopped to the riser as actuate UX-001(ES1) before unplugging the catalyst. a) In case of plugging in the air lift, blast connections are provided along the air lift to help to refluidize the catalyst. Put the blast connections in operation one by one, starting with the upper connection. Lift air flow rate and pressure can be increased to help to deplug the air lift. b) In case of catalyst plugging in a standpipe, the circulation can be restored by increasing the differential pressure through the line: decrease the first regenerator pressure in case of spent catalyst line plugging and increase the second regenerator pressure in case of regenerated catalyst

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line plugging (increasing the aeration and fluidization rates is not sufficient). During the deplugging operation, do not maintain the catalyst slide valve continuously fully open; proceed with quick close/open valve operations. 9.3.20 Downstream unit failure Depending upon the nature of the downstream equipment failure, the RFCC may operate at reduced throughput. If unable in a stable, controlled manner the unit should be shutdown following the normal shutdown procedure. Follow as close as possible the normal shutdown procedure. If the outage is expected to be less than about 48 hours, the unit can be kept hot with torch oil. If the outage is expected to extend beyond 48 hours, plan for unloading catalyst as per the normal shutdown procedure. In the case of continued stand-by operation, reduce the disengager pressure to 0.15 kg/cm2 above the first stage regenerator pressure and reduce stripper catalyst level to minimum. Once the downstream failure is repaired, the unit may be restarted following the normal start-up procedure. 9.3.21 Fire emergency In case of a fire emergency, it should be determined what effect the emergency will have on the RFCC. If shut down of the unit is required, the normal shutdown procedure should be followed as closely as possible as activate UX-001(ES1). If the emergency requires immediate action, it may not be possible to completely utilize the normal shutdown procedure. In those cases, oil hydrocarbon feeds should be isolated from the reactional section and the unit should be maintained in a hot condition using torch oil. As required the catalyst circulation may be shut down as activate UX-002(ES2) until the emergency situation is under control. When the fire emergency is over, the unit can be restarted following the normal start-up procedure.

9.4 Emergency shutdown of Fractionator and Gas Concentration Section 9.4.1 General In an emergency, steps must be taken to bring the unit to a safe shutdown condition. An emergency may be caused due to failure of a utility or failure of equipment. Emergency shutdown of the reaction section will also necessitate shutdown of the fractionation and gas recovery sections. Initially, the unit should be shutdown and maintained in a hot condition by switching the slurry steam generators to heating. Admit fuel gas to the main fractionator overheads to maintain the pressure balance in the reactor. It may be necessary to shut down the wet gas compressor because of steam balance requirements or because of compressor surging. If the emergency is anticipated to be for long duration, shutdown should proceed as for a normal shutdown, as far as equipment is available to do so. 9.4.2

Utility failure

A. Steam failure On loss of steam, the air blower in the reaction section and the wet gas compressor will be lost. This will require a shutdown of the unit. The slurry pumparound pumps are steam turbine driven and these also will be lost.

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Depressurize the main fractionator to prevent the possibility of flow of hydrocarbon back to the regenerators. Flush the slurry circuit to prevent plugging problems as the slurry circuits cool down. Shutoff stripping steam to the HCO and LCO strippers. When steam becomes available, start the slurry pumps and start slurry circulation. If necessary, heat the slurry circuits as for normal start-up. Admit fuel gas to the main fractionator overhead and start the wet gas compressor. Continue start-up of the unit following the procedure for normal start-up. B. Instrument air failure Instrument air failure will require shutdown of the unit. The control valves will go to the failure position. The operators should be familiar with these positions. If the wet gas compressor has not shut down on instrument failure, it should be shut down following the normal shutdown procedure. Maintain slurry circulation. It will be necessary to manually control boiler feed water to the slurry pumparound steam generators, using the control valve by-passes. Other pumps should be shut down as liquid levels decrease. Stop stripping steam to the strippers. As steam flow may continue to the reactor, the main fractionator reflux drum water level will require manual control. If necessary, heat the slurry circuit in the steam generators to maintain the main fractionator hot. When instrument air is available, check all control valves for proper operation. Any control valves being by-passed should be placed back in service. Restart the unit following the normal start-up procedure. C. Boiler feed water failure Loss of boiler feed water will require shutdown of the unit. Loss of boiler feed water can lead to loss of steam, depending on the duration. In this case, follow the procedure for steam failure. When boiler feed water is available, establish levels in the steam generators and restart the unit following the normal start-up procedure. D. Fuel gas failure Fuel gas failure will not normally require a shutdown of the fractionator section. Fuel gas is used for pressure control on the feed surge drum. Loss of pressure control should not result in any operating difficulty as any loss of pressure will be gradual. Fuel gas is also used as pressure control on the surge drums associated with the slurry separator. Loss of this control should not result in any operating difficulty. E. Electrical power failure Electrical power failure will require a shutdown of the unit. There is a possibility that steam failure will subsequently anticipated, soon after refinery wide power failure. Wet gas compressor will be shut-down, automatically, as sea water is not available at event of refinery wide power failure. Try to maintain operation of the following pumps at power failure, and subsequent steam failure: -

Main fractionator bottom pump P-1519ABC

-

HCO flushing pump P-1521A for supplying flushing oil to P-1519ABC. In case HCO is not available from the main fractionator, try to introduce LCO from the tankage, if available. In case shut-down duration is to be longer, maintain the main fractionator hot by switching the slurry steam generators to heating. For prolong steam available to the essential part of RFCC, i.e. steam to riser and reactor stripping, cut off the steam to the following users, by manually; -

MP steam to E-1522

-

HP steam to E-1524

-

HPS to COB FD fan CT-1502B, subject to availability of HPBFW and fuel oil and or fuel gas.

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-


LP steam to T-1503

- LP steam to T-1504 As the fractionator overhead air condenser and overhead sour water pumps will be lost, the use of steam to the reactor should be minimized. When power is available, restart the unit following the normal start-up procedure. F. Cooling water failure Cooling water failure will require a shutdown of the unit. Cooling water is used for main fractionator trim condenser, and trim condensers of the wet gas compressor. Cooling water is also used for pump auxiliary coolers, and lube oil cooler of the Wet Gas Compressor. Shut down the wet gas compressor and maintain the main fractionator hot by switching the slurry steam generators to heating. G. Sea water failure Sea water is used for coolant of the surface condenser of the wet gas compressor. Therefore, failure of sea water will automatically trip of WGC, as turbine is not work properly. Follow operation procedure of wet gas compressor failure. 9.4.3 Wet gas compressor failure On loss of the wet gas compressor, divert the fractionator overhead gas to flare and start to reduce feed to the unit. If the wet gas compressor cannot be re-started quickly, this will require shutdown of the unit. Follow any emergency procedures from the vendor to safeguard the compressor. Maintain the main fractionator hot by switching the slurry steam generators to heating. When the wet gas compressor is ready to start, follow the normal start-up procedure to re-start the unit.

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10 SAFETY EQUIPMENT AND PROCEDURES 10.1 Pressure Safety Devices The following is RFCC flare discharge summary as attached: 8474L-015-NM-0006-701: RFCC Flare Discharge Summary Refer to specification of safety relief valves (8474L-400-SP-1545-001). 10.2 Alarm Setting Refer to the attached Alarm Setting List 10.3 Trip Setting Refer to the attached Trip Setting List 10.4 Trip System Chart Refer to Cause and Effect Table (8474L-015-DW-1514-602) as attached. 10.5 Hazardous and Toxic Materials 10.5.1 General considerations Safety is a wide field covering a large variety of subjects including safety during start-up, shutdown, emergencies, normal operation, fire fighting, maintenance, handling or toxic materials, turn-around. It is the responsibility of the refinery staff to make sure that the procedure used during the various operations are in accordance with the government regulations, guidelines from the professional groups and the general safety policy of the refinery. Training of the operators to improve their knowledge of the RFCC process and of the equipment, together with good communication and good coordination between groups involved in the unit operation plus regular safety practice exercises are very important to ensure a good level of safety. It is not in the scope of this operating instructions manual to describe fire fighting nor vessels entry methods. Hereunder will be given some recommendations concerning handling of hazardous materials and vessel entry. Materials in an RFCC unit are not dangerous as long as they are handled according to the normal procedure. Some are dangerous if they are allowed to leak in the atmosphere or if someone attempts to enter a vessel which is not sufficiently purged out. Therefore sampling and vessels entry methods should be adhered to and cautiously elaborated. 10.5.2 Vessel entry Before opening the disengager or the stripper manholes or nozzles, make sure that the vessels are cooled down below 200°C to avoid auto-ignition or coke deposits. Among other precautions make sure that before entering any vessel : • The vessel is isolated by blind flanges from other vessels, steam injections, nitrogen injections, fuel gas injections. • Breathable atmosphere is obtained especially in the low points. Check for O2, CO content, hydrocarbons, explosivity. • Separate air supply independent from electric power system should be available for immediate transfer to people working in the vessels, • Supply fresh air continuously by an air mover.

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10.5.3 Hazardous and Toxic Materials These substances are: • Catalyst and additives, • Flue gases, • Cracked hydrocarbons. Detailed data regarding the hazard and toxicity of these compounds can be found in the following documents: • OSHA Regulated Hazardous Substances published by the Occupational Safety and Health Organization - US Department of labor. • Fiches toxicologiques published by: Institut National de Recherche et de Sécurité 30, rue Olivier Noyer 75680 PARIS CEDEX. The Unit Owner is advised to request the relevant data sheets from the above organizations. Concerning catalysts and additives supplied under a trade mark, the relevant updated Material Safety data sheets must be acquired from the manufacturers. a). Catalyst RFCC catalyst is able to cause eyes and lungs irritations. When working with catalyst (sampling taking, catalyst containers loading and unloading…) face shields or goggles and a dust mask should be worn. Hot catalyst will burn skin. During catalyst sampling the whole body should be protected by adequate clothing. One should be careful with pile of hot catalyst spillage which can be cold externally but very hot inside. b). Flue gas In the RFCC process there are two different flue gases. The flue gas coming from the first regenerator contains CO and is a very dangerous gas. Exposure to a concentration as low as 0.4 % vol. can be fatal in a short period of time. The flue gas contains no or very little oxygen and is a dense gas which can accumulate in low parts of equipments. Therefore it can cause asphyxiation or poisoning if not sufficiently purged off. First aid consists of taking the victim out of the dangerous area and then to use artificial respiration. c). Chemical and hazardous properties of carbon monoxide (CO) Poisonous carbon monoxide has the ability to replace oxygen in the blood; too high concentration in the body may cause death in a short period of time. CO also acts to keep the oxygen in the blood from reaching the tissues causing a type of suffocation. Maximum allowable concentration in the air is 100 ppm. CO burns readily and is dangerous when exposed to heat or flames. Its explosive limits range from 12.5% to 74% volume. Autoignition temperature: 650°C. Mixtures of CO and air in certain proportions are flammable. Detection of CO Should be detected only by a reliable detector such as ORSAT apparatus or DRAEGER tube. Personnel protection Always wear an autonomous oxygen mask when entering in an area or vessel suspected to contain CO. First aid Move victim to fresh air. If recovery is slow, bring resuscitator and give oxygen.

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If the breathing has stopped, practice artificial respiration until the doctor arrives. d). Cracked hydrocarbons Cracked hydrocarbons are skin irritants. Precautions should be taken during maintenance operations or products sampling to avoid contact with skin and eyes. It also contains aromatics which are poisons. In case of exposure, skin should be washed with soap and eyes thoroughly cleaned with water. Contaminated clothes should be removed. 10.5.4 Material Safety Data Sheet (MSDS) MSDS of the following chemical are attached. • Nickel Passivator EC9192 • Corrosion Inhibitor CHIMEC 1430 • Anti foam Chemical CHIMEC 8045 • Phosphate NALCO 7208 10.6 HAZOP Recommendation for Operation Instruction The following are list of HAZOP Follow-up action, relating the operation manual. See the relevant section for the detail procedures to cover the Hazop review requirement during design review. HAZOP Follow-up Action in Operation Manual Action Description Follow-up Description by TPC Action No 4003 Ensure operating manual and Operation manual will cover the following. procedures includes actions to be At event of Atomizing steam low flow of either taken if steam supply fails. FI-005 A to F, check the site condition of FV005 A to F, while manual by-passing of the relevant control valve. 4009 Consider provision of temporary A temporary Strainer on the feed line will be strainer and relevant operating provided for the initial start up, and procedure instruction. will be covered in the operation manual. 4015 Ensure that the operating procedure Operating Manual will cover the detail indicates the opening and closing of Procedures for: valves and blinds of the PSV-002 - opening of AOV-001 - closing isolation valve of PSV-002 - during normal operation, isolation valve of PSV-002 shall keep closing 4019 Ensure operating manual has an Operation manual will instruct appropriate appropriate instruction. procedure to avoid solidification of feed oil system as following. - Routine checking that steam trace is working properly. 4023 Ensure that the operating guideline Operation manual will cover that the reactor should include reference to need for temperature control is the prime concerns to correct process condition. promote coke formation. 4026 4036

See Section 7.9.2 See Section 7.9.3

See Section 7.9.4

See Section 7.9.5 and 7.3.1 Ensure operating procedure cover this Operation manual will cover that MPS injection See aspect. shall be maintained while no MTC injection. Section 7.9.6 Ensure that the operating procedure Operation procedure will cover that venting line See includes reference to possibility of shall never closed while steam out operation to Section creating a vacuum. 7.9.7 create vacuum condition.

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0

Referen ce Sect See Section 7.9.1


Action Description Action No 4040 Confirm arrangements to ensure that isolation valve on the PSV is not blocked before putting the PSV in service. 4041 Operating procedures should describe that overflow vent valve should be open during drum filling and close during normal operation 4048 Ensure procedures provide for positive valve isolation. 4050

4058 4067

4080 4082 4092 4097 4144

4320 4345

4381

Follow-up Description by TPC

Referen ce Sect See Action No. 4015, that operation manual See will cover the procedure for isolation of PSV- Section 002. 7.9.3 Operation manual will cover that valve of See overflow should be opened during filling, and Section be closed during operation. 7.9.8

Operation manual to cover that PDT-103 should be commissioned properly that LP side shall never left open condition Confirm sampling operation can be Operation procedure will be cover sampling of carried out safely with equipment hot catalyst from the reactor. provided and that instructions to operators are appropriate. Confirm operator’s guideline for Operation manual to cover the procedures when action on HH temperature. high high temperature of the regenerator

See Section 7.9.9 See Section 7.9.10

See Section 7.9.20 Confirm sampling operation can be Operation manual to cover sampling procedure See carried out safely with equipment of hot catalyst. Section provided and that instructions to 7.9.10 operators are appropriate. Confirm procedures and arrangements It will be confirmed when vendor’s data is See for setting and operating SV1503-VO- available, and will be described in the operation Section 01/02. manual, if any. 7.9.11 Operating procedure should include Operation manual will cover that combustion See corrective actions. air to the 1st regenerator should be adjusted to Section control CO in the flue gas. 7.9.12 Confirm procedures and arrangements Operation manual by vendor will cover the See for setting and operating SV1504-VO. procedures and arrangements for setting and Section operation. 7.9.11 Operating procedure should include Operation manual to cover that combustion air See corrective actions. to the 2nd regenerator should be properly Section control to attain complete combustion of CO. 7.8.13 Operating procedure to ensure flue gas Operation manual will cover that flue gas See temperature is above the dew point by temperature should be always 50deg C higher Section at 50 degree C (minimum). than its dew point ( 160-190 deg C), i.e.240 deg 7.9.14 C. Confirm operating procedure include Operation procedure will cover flush out is See need to flush out slurry exchangers required while not in service of slurry Section not in service. exchangers. 7.9.15 Investigate arrangement for bringing A check valve will be added on BFW supply, See steam generated back into service downstream of isolation valve, respectively to Section after outage and start up. secure filling BFW operation on the idling 7.9.16 exchanger. Operation manual will cover the switch over operation to the stand-by exchanger. Lock open inlet and outlet valves on It will be covered in the operation manual. See water side of E-1511 and ensure this is Section covered by operating procedure. 7.9.17

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0




Action Description Action Follow-up Description by TPC No 4601 Ensure that adequate operating (Rev.0 on 11-APR-2006) instructions provided for on/off pumps Operation manual will cover that vessel D-1551 P-1552. is normally empty and ensure that pump P-1551 A or B shall never operate while vessel empty. (Rev.1 on 21-JUL-2006) See Action No. 4600, appropriate operation is required when activating low alarm on LA-701 to avoid pump P-1552A or B to operate lose suction condition. 4697 Contractor to identify depressurization Design temperature of T-1556 covers the mode for failure of solenoid or open situation self refrigeration (- 25 deg C). circuit and consider provision of Operation manual will cover, specifically, that upstream isolation valve depressuring operation of LPG vessel shall be activated during external fire, only. There is a substantial time for operator’s intervention to check the realistic situation at the case of operation fault, and to reach complete frozen condition of T-1556. 4449 Contractor to check for this condition (Rev.2 on 11-SEP-2006) 4468 where fuel gas via the following PCVs The split range control with purge gas and 4482 without causing PIC low alarm. 4488 - PIC-483 for PCV-483A & B venting to flare is commonly applied for at D-1518 pressure control of the surge drum. Intelligent - PIC-489 for PCV-489A & B assessment confirms that the frequency of at D-1519 driven open of PCV to flare is quite rare. As the - PIC-505 for PCV-505 A & B relevant drum is designed for full vacuum at D-1522 condition, and even if operation pressure is - PIC-510 for PCV-510 A & B balanced to the flare pressure, there is no at D-1523 concerning of safety and operability. In order to close out this issue, TPC will describe in the operation manual that operation condition of these control valves should be checked, time to time, whether both PCVs are opened or not, and check local PG for confirmation of proper function of PIC. (Rev.3 on 17-NOV-2006 for 4468) Please be informed that PV-489A and PV-489B are close in normal operation and one (not “both”) of them will be open dependent on input signal as split range control. There is no change that both PV-489A and PV-489B are open at a time as shown on the P&ID. With this split range control and the system availability as per project specifications, there is no considerable loss of fuel gas to the flare.

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Referen ce Sect See Section 7.9.18

See Section 7.9.19

See Section 7.9.21


Action Description Action No 2070 Provide operating procedures which require rapid communication of FG treater problem to FG customers so that they can initiate appropriate safety measures.

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Follow-up Description by TPC

Referen ce Sect See YOC will develop this procedure in the Section Operation manual for RFCC Unit. 7.9.22 NOTE: This action is highlighted in HAZOP Action of Unit 12 for the failure situation of the fuel gas absorber T-1555 that H2S in fuel gas will be higher than normal, and special attention for handling is required for the relating unit, using treated fuel gas.



11 INSTRUEMNT DATA 11.1 Control Valves and Instruments Refer to following control valve and flow instrument data sheets: 8474L-015-SP-1541-101: Data Sheets for Control Valves (Unit 15) 8474L-015-SP-1541-102: Data Sheets for Control Valves (Slurry Service) (Unit 15) 8474L-015-SP-1542-103: Data Sheets for Self Actuated Control Valves (Unit 15) 8474L-015-SP-1543-201: Data Sheets for Actuated On-off Valves (Unit 15) 8474L-015-SP-1543-202: Data Sheets for Actuated On-off Valves (Slurry Service) (Unit 15) 8474L-015-SP-1553-101: Data Sheets for “Electronic Diff. Pressure Type Flow” Transmitter (Unit 15) 8474L-015-SP-1547-002: Data Sheets for Rotormeters (Unit 15) 8474L-015-SP-1547-016: Data Sheets for Ultrasonic Flowmeters (Unit 15) 11.2 Orifice Plates Refer to following orifice plates and restriction orifice data sheets: 8474L-015-SP-1546-002: Data Sheets for Orifice Plates (Unit 15) 8474L-400-SP-1546-001: Instrument Specification Restriction Orifice

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12 SUMMARY OF MAJOR EQUIPMENT 12.1 Equipment List Refer to RFCC Equipment List (8474L-410-EL-001) as attached. 12.2 Large Rotating Equipment 12.2.1 Air Blower, C-1501 Air Blower is a centrifugal compressor to supply the necessary amount of air to burn all the coke off the catalyst and some of the resulting CO to CO2. Depending upon the mode of operation and other factors such as feed quality, the required air amounts to the regenerator is supplied from this Air Blower. The design capacity is 340,483 NM3/h, and 25 MW shaft power. The machine type is axial compressors with steam condensing turbine driven. The capacity of air flow rate is mainly controlled by speed of turbine. The major operating conditions are as follows: C-1501 Process Condition Mix MG Mix MD BH MG BH MD Ope Case Unit Design Flowrate NM3/hr 340,432 309,483 254,808 213,247 195,748 Suct Press kg/cm2A 1.008 1.008 1.008 1.008 1.008 Suct Temp Deg C 36 36 36 36 36 Disch Press kg/cm2A 4.66 4.26 4.26 4.26 4.26 Disch Temp Deg C 227 210 223 232 238 The following are design data of turbine of C-1501: - First critical speed of C-1501: 2011 RPM - First critical speed of turbine: 2604 RPM (HOLD) - Normal speed: 4,400 RPM - Rated speed: 4,661RPM (100 %) - Minimum continuous speed: 3,263 RPM (70 %) - Maximum continuous speed: 4,894 RPM (105 %) - Trip speed : 5,383 RPM (115.5 %) Refer to the attached expected Q-H curves for C-1501. 12.2.2 Wet Gas Compressor, C-1551 The Wet Gas Compressor is a multi-stage centrifugal compressor to boost-up the main fractionator overhead gas pressure from atmospheric level to 14-15 kg/cm2g for Gas Concentration Section. The machine consists two stages compressor, with external cooling. The Wet Gas Compressor is driven by condensing steam turbine. The driver capacity is 8,100 KW. The capacity is mainly controlled by turbine speed. Mixed Crude Max Bach Ho Max C-1551 process Condition Gasoline Gasoline Unit Normal Design Normal Design Ope Case First Stage Flowrate NM3/hr 65326 75127 67578 77715 Wt Flow Kg/hr 138964 159809 139263 160152 MW 47.68 47.68 46.19 46.19 Suct Press kg/cm2A 1.33 1.33 1.33 1.33 Suct Temp Deg C 41.9 41.9 41.9 41.9 Disch Press kg/cm2A 5.13 5.09 5.2 5.19 Disch Temp Deg C 96.5 97 98.7 99.5

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C-1551 process Condition

Bach Ho Max Gasoline Normal Design

Unit Ope Case Second Stage Flowrate NM3/hr 43794 Wt Flow Kg/hr 80749 MW 41.33 Suct Press kg/cm2A 4.43 Suct Temp Deg C 41.9 Disch Press kg/cm2A 17.1 Disch Temp Deg C 111.3 The following are design data of turbine of C-1551 - Normal speed: 5,134 RPM - Rated Speed: 5,458 RPM - Maximum continuous speed: 5,731 RPM - Trip Speed: 6,304 RPM - First Critical speed: 2,600 - 2,700 RPM - Second Critical Speed: 11,000 RPM Refer to the attached expected Q-H curves for C-1551.

50363 92861 41.33 4.39 41.9 17.1 112


Mixed Crude Max Gasoline Normal Design 48195 86739 40.34 4.5 41.9 17.1 112

55424 99750 40.34 4.49 41.9 17.1 112.6

12.3 Major Special Packages 12.3.1 Electrostatic Precipitator, X-1507 The Electrostatic Precipitator is provided to decrease catalyst dust from the flue gas from the Regenerator via COB/WHB package, to meet the environmental specification the dust fine content at precipitator outlet shall not exceed 50 mg/NM3 dry basis. The facilities consist of two parallel precipitators and ash handling facilities. The principle of operation is to provide high voltage electric for collection of dust by corona effect. 12.3.2 COB/WHB Package, H-1503 The COB/WHB Package is provided to incinerate CO rich flue gas from the first regenerator, steam generation from COB and flue gas from the second regenerator. The package consists of COB, WHB, and Economizer sections. The auxiliary firing of COB is designed to generate 205 ton/hr of HPS at all operation cases. The imported saturated HPS and MPS are also superheated in WHB. This package contributes a production of major HPS generation for the users in the Refinery. 12.3.3 Slurry Separator, X-1504 The Slurry Separator is provided to decrease catalyst fine in the Fractionator Bottom and produce Clarified Oil for fuel oil production. The design capacity is 30.7 ton/hr of slurry oil. The catalyst fine in the slurry oil is maximum 4,300 PPM at peak, and outlet catalyst fine maximum is targeting to 100 PPM. The Slurry Separator package consist 10 module filters with automatic back-washing facilities by flushing oil.

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February 2007 Rev. :A Chapter : 13 Page :222/230

13 ANALYSIS 13.1 Sampling and Testing Method Schedule For proper control of the unit it is essential to run laboratory tests on a regular basis. The following tests are recommended as a minimum. Feed Oil ANALYSIS

METHOD

FREQUENCY

ASTM D 1298/D 4052

Daily

ASTM Distillation

ASTM D 1160

Daily

Viscosity

ASTM D 445

Daily

Sulfur

ASTM D 4294

Daily

Nitrogen

ASTM D 4629

Daily

Conradson carbon residue (CCR)

ASTM D 189

Daily

D 5863 / D 5708 /D 5185

Weekly

ASTM D 611

Weekly

METHOD

FREQUENCY

Paramagnetic type analyzer

Daily (continuous)

Specific Gravity

Metals Aniline point Flue gas ANALYSIS 1st flue gas

O2

2nd flue gas

CO, O2

Infrared photometry

Daily (continuous)

SOx, NOx

Chemiluminescence

Weekly or at request

Particulates

Isokinetic sampling

At request

METHOD

FREQUENCY

Catalyst ANALYSIS • Spent catalyst

Carbon

Element analyzer

Daily

• 1st regen. catalyst

Carbon

ASTM D 3178 or equiv.

Daily

• 2nd regen. catalyst

Carbon

ASTM D 3178 or equiv.

Daily

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Particle size

by catalyst vendor

MAT Activity

by catalyst vendor

Surface area

by catalyst vendor

Pore volume

by catalyst vendor

Bulk density

by catalyst vendor


ANALYSIS

• Fresh catalyst

METHOD

Metals

by catalyst vendor

Rare earths

by catalyst vendor

MAT activity

by catalyst vendor/ R2R MAT

Particle size

by catalyst vendor

Surface area

by catalyst vendor

Pore volume

by catalyst vendor

Bulk density

by catalyst vendor

Metals

by catalyst vendor

Rare earths

by catalyst vendor

FREQUENCY

Light cycle oil Property Specific gravity Distillation Sulfur Nitrogen Color Flash point Cloud point Water Viscosity at 50°C Pour point

Method ASTM D1298 / D4052 ASTM D86 ASTM D4294 ASTM 4629 ASTM D1500 ASTM D93 ASTM D2500 ASTM D4377 / E0203 ASTM D445 ASTM D97

Frequency Daily Daily Daily Daily Daily Daily Daily Daily Daily Daily

Heavy cycle oil Property Specific gravity Distillation Viscosity Sulfur

Method ASTM D1298 / D4052 ASTM D86 / D1160 ASTM D445 ASTM D4294

Frequency At request At request At request At request

Method ASTM D1298 / D4052 ASTM D1160 ASTM D445 ASTM D97 ASTM D93 ASTM D4294 ASTM D1796 ASTM D482

Frequency Daily At request At request Daily At request Daily Daily Daily

Clarified oil Property Specific gravity Distillation Viscosity at 100°C Pour point Flash point Sulfur Water & sediment Catalyst loading (Ash) Slurry

_ _ _ __ RA| D __| N I ||___ 0

8474L-015-ML-001-A 07 R-20 7-MA



Property Catalyst loading (Ash) Absorber gas Property Composition H2S

Method ASTM D482

Frequency Daily

Method

Frequency Daily

Gas chromatograph Draeger tube

Daily

Method ASTM D1298 / D4052 ASTM D86 ASTM D4294 ASTM D2699 ASTM D2700

Frequency Daily Daily Daily Daily Daily

Debutanizer bottoms / Gasoline product Property Method Specific gravity ASTM D1298 / D4052 Distillation ASTM D86 Sulfur ASTM D4294 RON ASTM D2699 MON ASTM D2700 RVP ASTM D323

Frequency Daily Daily Daily Daily Daily Daily

Heavy Naphtha Property Specific gravity Distillation Sulfur RON MON


LPG Property Composition C5, mol% C2, mol%

Specific gravity

Method

Gas chromatograph

Frequency Daily

ASTM D2163 ASTM D2163 ASTM D1657

Daily Daily As required

Method ASTM D1293 ASTM D1688 ASTM D1068 ASTM D1783 ASTM D4282 ASTM D4658 ASTM D1426 ASTM D3921

Frequency At request At request At request At request At request At request At request At request

Sour water Property pH Copper Iron Phenols Cyanides Sulfides Ammonia Hydrocarbons

13.2 Catalyst sampling method See attached drawing and P&I diagrams of spent catalyst line, regenerated catalyst line and first regenerator. When sampling is not in operation, valve “3” is opened to purge the nozzles with nitrogen and valves “1”, “2” and “4” are closed.

_ _ _ __ RA| D __| N I ||___ 0

8474L-015-ML-001-A 07 R-20 7-MA



At the time of catalyst sampling, close valve “3” to get catalyst in the sampling line. Then open valves “1” and “2” to allow the sampling in the buffer. When the buffer is full, close “2” and open “4” to backflush the sampling line. Finally open “3” and close valves “1” and “4”.

_ _ _ __ RA| D __| N I ||___ 0

8474L-015-ML-001-A 07 R-20 7-MA


_ _ _ __ RA| D __| N I ||___ 0

8474L-015-ML-001-A 07 R-20 7-MA



13.3 On-Line Analyzer Refer to RFCC Analyzer Process Data Sheet (8474L-015-PDS-AE-401).

_ _ _ __ RA| D __| N I ||___ 0

8474L-015-ML-001-A 07 R-20 7-MA



14 PROCESS CONTROL 14.1 Distributed System Control (DCS) LATER.

_ _ _ __ RA| D __| N I ||___ 0

8474L-015-ML-001-A 07 R-20 7-MA




15 DRAWINGS 15.1 Plot Plans Refer to the attached RFCC Plot Plan (8474L-015-DW-0051-001) and Area Classification (8474L-015DW-1920-001). 15.2 Process Flow Diagram Refer to the attached RFCC Process Flow Diagrams and Material Selection Diagram.

15.3 Piping and Instrumentation Diagram Refer to the attached RFCC Piping and Instrumentation Diagrams.

15.4 Other Drawings Refer to the attached following drawings for RFCC unit. - Substation SS8A Single Line Diagram - Civil Installation Works Underground Plan - Fire Fighting Water Distribution Diagram

_ _ _ __ RA| D __| N I ||___ 0

8474L-015-ML-001-A 07 R-20 7-MA



16 ATTACHMENT Description

Spec No. 8474L-015-CN-0003-511

Estimated Utility Consumption Bach Ho MG – Normal

8474L-015-CN-0003-512

Estimated Utility Consumption Bach Ho MD – Normal

8474L-015-CN-0003-513

Estimated Utility Consumption Mixed Crude MG – Normal

8474L-015-CN-0003-514

Estimated Utility Consumption Mixed Crude MD – Normal

8474L-015-CN-0003-521

Estimated Utility Consumption Bach Ho MG – Design

8474L-015-CN-0003-522

Estimated Utility Consumption Bach Ho MD – Design

8474L-015-CN-0003-523

Estimated Utility Consumption Mixed Crude MG – Design

8474L-015-CN-0003-524

Estimated Utility Consumption Mixed Crude MD – Design

8474L-015-NM-0006-701

RFCC Flare Discharge Summary

---

Alarm Setting List

---

Trip Setting List

8474L-015-DW-1514-602 ---

MSDS for Nickel Passivator EC9192

---

MSDS for Corrosion Inhibitor CHIMEC 1430

---

MSDS for Anti foam Chemical CHIMEC 8045

---

MSDS for Phosphate NALCO 7208

8474L-410-EL-001

RFCC Equipment List

8474L-015-A1002-1040-001-035

C-1501 Q-H Curves

8474L-015-A1002-1010-001-009

C-1551 Q-H Curves

8474L-015-DW-0051-001

RFCC Plot Plan

8474L-015-DW-1920-001

RFCC Hazardous Area Classification

8474L-015-PFD-0010-101-117

RFCC Process Flow Diagram

8474L-015-MSD-0011-501-505

RFCC Material Selection Diagram

8474L-015-PID-0021-101-662

RFCC Piping and Instrumentation Diagram

8474L-001-DW-1652-108

Substation SS8A Single Line Diagram

8474L-015-DW-1452-001-019

Civil Installation Works Underground Plan

8474L-015-PID-1931-601-603

RFCC Fire Fighting Water Distribution Diagram

_ _ _ __ RA| D __| N I ||___

8474L-015-ML-001-A 07 R-20 7-MA

0

Cause and Effect Chart

ESTIMATED UTILITY CONSUMPTION

ESTIMATED UTILITY CONSUMPTION DOCUMENT CLASS CLIENT

PETROVIETNAM

LOCATION

DUNG QUAT

PLANT CAPACITY

VIETNAM

SECTION No.

015 RFCC

CASE

UNIT

Pages modified under revision 1 :

REVISION 69,700 BPSD -

7 2-20007 FEABR0273-M

Code

Serial N°

Rev. index

CN

00 03

511

1

Op. Center JOB No.

0-3952-20-0000

Op. Center Doc. No.

S-015-1223-511

FEED Doc. No.

A

0

1

23-MAY-06

01-FEB-07

23-FEB-07

WRITTEN BY

T. Tsuchiya

T. Tsuchiya

T. Tsuchiya

Bach Ho Max Gasoline

CHECKED BY

M. Okada

M. Okada

M. Okada

- Normal Case

APPROVED BY

M. Okada

M. Okada

M. Okada

DESCRIPTION

Issue for Review

For Construction

For Construction

2,4,10

Bach Ho MG - Normal

S-015-1223-511-1.xls

Doc. type

8474L 015

DATE

GENERAL NOTES:

_ _ _ __ RA| D __| N I ||___

X

Project N° - Unit

6960-015-DS-0711

SHEET

1

OF

10


ESTIMATED UTILITY CONSUMPTION CLIENT

PETROVIETNAM

LOCATION

DUNG QUAT

PLANT CAPACITY

VIETNAM

SECTION No.

015 RFCC

CASE

UNIT

ITEM No.

DESCRIPTION

MOTOR LOAD/ RATING

ELECTRIC POWER kW MECH. ELEC. RUNNING OPER LOAD LOAD

-0.3

-0.3

-585.0

-597.0

HP STM

MP STM

219.9

0.5

COB / WHB PACKAGE FORCED DRAFT AIR FAN

C-1502 B

FORCED DRAFT AIR FAN

(-18.0)

C-1502B HOT STAND-BY

-1.4

1230

BFW HEATER AIR BLOWER

3

-3.0

-3.0

P-1529 A

C-1501 TURBINE CONDENSATE PUMP

55

-39.0

-43.3

P-1529 B


55

(-39.0)

(-43.3)

E-1531

SURFACE CONDENSER 37

-18.5

-20.6

15

-15.0

-15.0

C-1501 LUBE OIL PUMP (Main) C-1501 LUBE OIL PUMP (Spare)

-

TURNING GEAR MOTOR

C-1551

WET GAS COMPRESSOR

-1.5

-1.5


18.5

-13.9

-14.8

P-1559 B


18.5

(-13.9)

(-14.8)

E-1567

TURBINE CONDENSER 30

-16.0

-17.8

C-1551 LUBE OIL PUMP (Main)

-

C-1551 LUBE OIL PUMP (Spare)

Serial N°

Rev. index

8474L 015

CN

00 03

511

1

HP COND

DATE

SHEET

WRITTEN BY CHECKED BY

2

OF

-68.7

-30.4

DESCRIPTION CONDENSATE T/h MP LP COLD COND COND COND

BFW T/h HP BFW

LP BFW

-226.1

-0.5

COLD BFW

DW T/h DEMIN. WATER

LOSSES T/h

REMARKS

1

1.4

-0.3

9.0 -0.1

0.1

68.7

0.3

30.4

0.4

(2.6)

-0.4

(-2.1)

(2.1)

-34.7

34.7

DISENGAGER / STRIPPER

-

COB/WHB LP BLOWDOWN DRUM

0.5

-0.5

D-1527

LP BLOWDOWN DRUM

0.1

-0.1

T-1503

LCO STRIPPER

-3.0

3.0

T-1504

HCO STRIPPER

-0.5

0.5

PAGE TOTAL

1462

-692.2

-713.3

119.4

-43.9

-3.0

0.0

9.0

0.1

99.1

-226.1

-0.5

0.0

0.0

45.9

GENERAL TOTAL

1462

-692.2

-713.3

119.4

-43.9

-3.0

0.0

9.0

0.1

99.1

-226.1

-0.5

0.0

0.0

45.9

NOTES

(

S-015-1223-511-1.xls

7 2-20007 FEABR0273-M

) INTERMITTENT PRODUCER/CONSUMER

+ INDICATES QUANTITY PRODUCED

REV

6.2

D-1501

_ _ _ __ RA| D __| N I ||___

10

APPROVED BY

(18.0)

(-2.6)

P-1559 A

-

LP STM

-9.0

E-1534

-

Code

Included in H-1503

C-1501

-

69,700 BPSD Bach Ho Max Gasoline - Normal Case STEAM T/h

H-1503

ECONOMIZER

Doc. type

REVISION

C-1502 A

E-1525

Project N° - Unit

MOTOR/LOAD RATING:

NAMEPLATE RATING OF MOTOR OR LOAD

MECH. RUNNING LOAD:

MOTOR SHAFT POWER

ELEC. OPERATING LOAD:

POWER ABSORBED BY MOTOR (MECH. LOAD/EFFY)

- INDICATES QUANTITY CONSUMED



PETROVIETNAM

LOCATION

DUNG QUAT

PLANT CAPACITY

VIETNAM

SECTION No.

015 RFCC

CASE

UNIT

ITEM No.

DESCRIPTION

Project N° - Unit

Doc. type

Code

Serial N°

Rev. index

8474L 015

CN

00 03

511

1

REVISION

MOTOR LOAD/ RATING


TOTAL PREVIOUS PAGES

1462

-692.2

-713.3

P-1501 A

FEED PUMP

600

-476.0

-500.5

P-1501 B

FEED PUMP

600

(-476.0)

(-500.5)

P-1504 A

SLURRY PRODUCT PUMP

55

-42.7

-45.1

P-1504 B

SLURRY PRODUCT PUMP

55

(-42.7)

(-45.1)

P-1505 A

BACKFLUSH OIL PUMP

22

-15.0

-16.5

P-1505 B

BACKFLUSH OIL PUMP

22

(-15.0)

(-16.5)

P-1506 A

BACKFLUSH OIL RECYCLE PUMP

11

-7.4

-8.4

P-1506 B


11

(-7.4)

(-8.4)

P-1507 A

HCO RECYCLE PUMP

150

0.0

0.0

P-1507 B

HCO RECYCLE PUMP

150

(0.0)

(0.0)


DATE

SHEET

WRITTEN BY 3

CHECKED BY

OF


LP BFW

COLD BFW

DW T/h DEMIN. WATER

LOSSES T/h

HP BFW -226.1

-0.5

0.0

0.0

45.9

HP STM

MP STM

LP STM

HP COND

119.4

-43.9

-3.0

0.0

9.0

0.1

99.1

BFW T/h

P-1508 A

HCO PUMPAROUND PUMP

220

-179.4

-188.4

P-1508 B

HCO PUMPAROUND PUMP

220

(-179.4)

(-188.4)

P-1509 A

HCO PRODUCT PUMP

15

-9.1

-10.1

P-1509 B

HCO PRODUCT PUMP

15

(-9.1)

(-10.1)

P-1510 A

LCO PUMPAROUND PUMP

335

-303.0

-316.0

P-1510 B

LCO PUMPAROUND PUMP

335

(-303.0)

(-316.0)

P-1511 A

LCO STRIPPER PUMP

90

-73.4

-76.9

P-1511 B

LCO STRIPPER PUMP

90

(-73.4)

(-76.9)

P-1512 A

MTC RECYCLE PUMP

75

0.0

0.0

P-1512 B

MTC RECYCLE PUMP

75

(0.0)

(0.0)

P-1513 A

LEAN OIL PUMP

75

-55.0

-58.1

P-1513 B

LEAN OIL PUMP

75

(-55.0)

(-58.1)

P-1514 A

NAPHTHA PUMPAROUND PUMP

225

-203.0

-213.9

P-1514 B


225

(-203.0)

(-213.9)

PAGE TOTAL

3746

-1364.0

-1433.9

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

GENERAL TOTAL

5208

-2056.2

-2147.2

119.4

-43.9

-3.0

0.0

9.0

0.1

99.1

-226.1

-0.5

0.0

0.0

45.9

REMARKS

NOTES

_ _ _ __ RA| D __| N I ||___ (

S-015-1223-511-1.xls

7 2-20007 FEABR0273-M



10

APPROVED BY

MOTOR/LOAD RATING:


MECH. RUNNING LOAD:

MOTOR SHAFT POWER




REV



PETROVIETNAM

LOCATION

DUNG QUAT

PLANT CAPACITY

VIETNAM

SECTION No.

015 RFCC

CASE

UNIT

ITEM No.

DESCRIPTION

Project N° - Unit

Doc. type

Code

Serial N°

Rev. index

8474L 015

CN

00 03

511

1

REVISION

MOTOR LOAD/ RATING



5208

-2056.2

-2147.2

P-1515 A

HEAVY NAPHTHA PRODUCT PUMP

55

-39.4

-41.6

P-1515 B


55

(-39.4)

(-41.6)

P-1516 A

FRACTIONATOR REFLUX PUMP

110

-96.0

-101.3 (-101.3)


HP STM

MP STM

LP STM

HP COND

119.4

-43.9

-3.0

0.0

DATE

SHEET


4

OF

DESCRIPTION CONDENSATE T/h LP MP COLD COND COND COND

LP BFW

COLD BFW

DW T/h DEMIN. WATER

LOSSES T/h

HP BFW

0.1

-226.1

-0.5

0.0

0.0

45.9

9.0

99.1

BFW T/h

P-1516 B


110

(-96.0)

P-1517 A

OVERHEAD SOUR WATER PUMP

30

-25.5

-27.6

P-1517 B


30

(-25.5)

(-27.6)

P-1518 A

OVERHEAD LIQUID PUMP

250

-206.0

-228.9

P-1518 B


250

(-206.0)

(-228.9)

P-1519 A

SLURRY PUMPAROUND PUMP

-10.3

P-1519 B


-10.3

10.3

P-1519 C


(-10.3)

(10.3)

P-1519C HOT STAND-BY

-0.8

P-1521 A

HCO FLUSHING OIL PUMP

-3.7

P-1521 B


110

(-80.9)

P-1522 A

LCO FLUSHING OIL PUMP

30

-18.4

-19.9

P-1522 B


30

(-18.4)

(-19.9)

P-1526 A

LIGHT SLOPS PUMP

37

-26.1

-27.9

P-1526 B

LIGHT SLOPS PUMP

37

(-26.1)

(-27.9)

P-1527 A

HEAVY SLOPS PUMP

37

-27.9

-29.8

P-1527 B

HEAVY SLOPS PUMP

37

(-27.9)

(-29.8)

P-1528 A

TEMPERED WATER PUMP

15

-10.5

-11.7

P-1528 B

TEMPERED WATER PUMP

15

(-10.5)

(-11.7)

PAGE TOTAL

1238

-449.8

-488.7

-25.1

0.0

24.3

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.8

GENERAL TOTAL

6446

-2506.0

-2635.8

94.3

-43.9

21.3

0.0

9.0

0.1

99.1

-226.1

-0.5

0.0

0.0

46.7

REMARKS

(

S-015-1223-511-1.xls

7 2-20007 FEABR0273-M


0.8 3.7

(-84.4)


REV

10.3

NOTES

_ _ _ __ RA| D __| N I ||___

10

APPROVED BY

MOTOR/LOAD RATING:


MECH. RUNNING LOAD:

MOTOR SHAFT POWER




1



PETROVIETNAM

LOCATION

DUNG QUAT

PLANT CAPACITY

VIETNAM

SECTION No.

015 RFCC

CASE

UNIT

ITEM No.

DESCRIPTION

Project N° - Unit

Doc. type

Code

Serial N°

Rev. index

8474L 015

CN

00 03

511

1

REVISION

MOTOR LOAD/ RATING


DATE

CHECKED BY

DESCRIPTION CONDENSATE T/h MP COLD LP COND COND COND

HP STM

MP STM

LP STM

HP COND

94.3

-43.9

21.3

0.0

9.0

0.1


6446

-2506.0

-2635.8

INTERSTAGE DRUM PUMP

150

-134.0

-142.3

P-1551 B


150

(-134.0)

(-142.3)

P-1552 A

KO DRUM LIQUID PUMP

4

-1.2

-1.4

P-1552 B

KO DRUM LIQUID PUMP

4

(-1.2)

(-1.4)

P-1553 A

STRIPPER FEED PUMP

132

-112.0

-117.9

P-1553 B

STRIPPER FEED PUMP

132

(-112.0)

(-117.9)

P-1554 A

GASOLINE RECYCLE PUMP

55

0.0

0.0

P-1554 B


55

(0.0)

(0.0)

5

OF

99.1

LP BFW

COLD BFW

DW T/h DEMIN. WATER

LOSSES T/h

HP BFW

BFW T/h

-226.1

-0.5

0.0

0.0

46.7

P-1556 A

DEBUTANIZER OVERHEAD PUMP

225

-185.0

-194.9

P-1556 B


225

(-185.0)

(-194.9)

P-1560 A

RFCC CLOSED DRAIN PUMP

22

(-16.5)

(-18.1)

P-1560 B


22

(-16.5)

(-18.1)

P-1561

RFCC LIFT STATION NO.1 SUMP PUMP

7.5

(-4.9)

(-5.4)

P-1562


7.5

(-4.9)

(-5.4)

P-1563

OILY WATER LIFT PUMP - COMMON SPARE

7.5

(-4.9)

(-5.4)

P-1564

AMINE CLOSED DRAIN PUMP

15

(-10.8)

(-12.0)

PAGE TOTAL

1214

-432.2

-456.5

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

GENERAL TOTAL

7660

-2938.2

-3092.3

94.3

-43.9

21.3

0.0

9.0

0.1

99.1

-226.1

-0.5

0.0

0.0

46.7

REMARKS

NOTES

_ _ _ __ RA| D __| N I ||___ (

S-015-1223-511-1.xls

7 2-20007 FEABR0273-M



10

APPROVED BY


P-1551 A

SHEET

WRITTEN BY

MOTOR/LOAD RATING:


MECH. RUNNING LOAD:

MOTOR SHAFT POWER




REV



PETROVIETNAM

LOCATION

DUNG QUAT

PLANT CAPACITY

VIETNAM

SECTION No.

015 RFCC

CASE

UNIT

ITEM No.

DESCRIPTION

Project N° - Unit

Doc. type

Code

Serial N°

Rev. index

8474L 015

CN

00 03

511

1

REVISION

MOTOR LOAD/ RATING



7660

-2938.2

-3092.3

E-1514

LCO AIR COOLER

120

-97.6

-106.2

E-1517

HEAVY NAPHTHA AIR COOLER

33

-20.4

-23.1

E-1519

OVERHEAD AIR CONDENSER

960

-736.0

-800.9

E-1521

HEAVY NAPHTHA PUMPAROUND AIR COOLER

120

-99.6

-108.4

E-1530

TEMPERED WATER AIR COOLER

22.5

-15.0

-17.8

E-1551

WET GAS COMPRESSOR INTERCOOLER

240

-190.4

-207.2


HP STM

MP STM

LP STM

HP COND

94.3

-43.9

21.3

0.0

DATE

SHEET


6

OF

DESCRIPTION CONDENSATE T/h MP LP COLD COND COND COND 9.0

0.1

99.1

LP BFW

COLD BFW

DW T/h DEMIN. WATER

LOSSES T/h

HP BFW -226.1

-0.5

0.0

0.0

46.7

BFW T/h

E-1553

HP CONDENSER

180

-134.4

-146.2

E-1558

GASOLINE AIR COOLER

120

-92.8

-101.0

E-1503

SLURRY HP STEAM GENERATOR

0.0

0.0

E-1504


10.3

-10.6

E-1505

SLURRY MP STEAM GENERATOR

E-1506

SLURRY LP STEAM GENERATOR

E-1508

HCO RECYCLE MP STEAM GENERATOR

E-1510

8.0

0.2

1.3

-1.4

0.1

0.0

0.0

HCO LP STEAM GENERATOR

2.1

-2.2

0.1

E-1513

LCO PRODUCT LP STEAM GENERATOR

2.2

-2.2

0.0

E-1518

HEAVY NAPHTHA TRIM COOLER

0.0

REMARKS

0.3

-8.2

PAGE TOTAL

1796

-1386.2

-1510.8

10.3

8.0

5.6

0.0

0.0

0.0

0.0

-10.6

-14.0

0.0

0.0

0.7

GENERAL TOTAL

9455

-4324.4

-4603.1

104.6

-35.9

26.9

0.0

9.0

0.1

99.1

-236.7

-14.5

0.0

0.0

47.4

NOTES

_ _ _ __ RA| D __| N I ||___ (

S-015-1223-511-1.xls

7 2-20007 FEABR0273-M



10

APPROVED BY

MOTOR/LOAD RATING:


MECH. RUNNING LOAD:

MOTOR SHAFT POWER




REV



PETROVIETNAM

LOCATION

DUNG QUAT

PLANT CAPACITY

VIETNAM

SECTION No.

015 RFCC

CASE

UNIT

ITEM No.

DESCRIPTION

TOTAL PREVIOUS PAGES E-1520 A-H

Project N° - Unit

Doc. type

Code

Serial N°

Rev. index

8474L 015

CN

00 03

511

1

REVISION

MOTOR LOAD/ RATING 9455



HP STM

MP STM

LP STM

HP COND

-4603.1

104.6

-35.9

26.9

0.0

-4324.4

DATE

SHEET


7

OF


LP BFW

COLD BFW

DW T/h DEMIN. WATER

LOSSES T/h

HP BFW

0.1

-236.7

-14.5

0.0

0.0

47.4

9.0

99.1

BFW T/h

REMARKS

OVERHEAD TRIM CONDENSER

E-1522

MP STEAM FEED HEATER

-8.7

E-1523

HCO PUMPAROUND MP STEAM GENERATOR

0.7

E-1524

HP STEAM FEED HEATER

E-1532

BLOWDOWN COOLER

E-1552 A/B

WET GAS COMPRESSOR TRIM COOLER

E-1554 A-D

STRIPPER CONDENSER

E-1559

GASOLINE COOLER

E-1561 A/B

DEBUTANIZER CONDENSER

E-1562

LPG COOLER

E-1564

LEAN OIL COOLER

8.7

Cold Feed Case: -18.7 t/h MPS 0.0

-0.7

-13.5

Cold Feed Case: -22.8 t/h HPS

13.5

E-1565

FUEL GAS COOLER

E-1566

LEAN AMINE COOLER

I-1501

FEED INJECTOR

Included in D-1501

I-1502

MTC INJECTOR

Included in D-1501

I-1503

STABILIZATION INJECTOR

Included in D-1501

I-1504

BACK FLUSH OIL INJECTOR

SPR-1501

FIRST REGENERATOR TORCH OIL SPRAYER

(-0.3)

Included in D-1501 (0.3)

SPR-1502

SECOND REGENERATOR TORCH OIL SPRAYER

(-0.3)

SPR-1503

WATER SPRAY FOR D-1502 FLUE GAS BYPASS

(-1.5)

(-25.7)

(-27.2)

SPR-1504


(-1.5)

(-15.8)

(-17.3)

SPR-1505

WATER SPRAY FOR ECONOMIZER BYPASS

(-1.5)

(-18.5)

(-20.0)

(0.3)

PAGE TOTAL

0

0.0

0.0

-13.5

-8.0

0.0

13.5

8.7

0.0

0.0

0.0

-0.7

0.0

0.0

0.0

GENERAL TOTAL

9455

-4324.4

-4603.1

91.1

-43.9

26.9

13.5

17.7

0.1

99.1

-236.7

-15.2

0.0

0.0

47.4

NOTES

_ _ _ __ RA| D __| N I ||___ (

S-015-1223-511-1.xls

7 2-20007 FEABR0273-M



10

APPROVED BY

MOTOR/LOAD RATING:


MECH. RUNNING LOAD:

MOTOR SHAFT POWER




REV



PETROVIETNAM

LOCATION

DUNG QUAT

PLANT CAPACITY

VIETNAM

SECTION No.

015 RFCC

CASE

UNIT

ITEM No.

DESCRIPTION

TOTAL PREVIOUS PAGES X-1504

SLURRY SEPARATOR

X-1505

CORROSION INHIBITOR INJECTION PACKAGE

MOTOR LOAD/ RATING


9455

-4324.4

-4603.1

-230.0

-230.0

CORROSION INHIBITOR PUMP

0.55

-0.40

-0.44

X-1507

ELECTROSTATIC PRECIPITATOR

491

-379.0

-379.0

88

(-53)

(-53)

(-270.0)

(-300.0)

X-1509

Doc. type

Code

Serial N°

Rev. index

8474L 015

CN

00 03

511

1

REVISION

P-1520

X-1508

Project N° - Unit

DESOX UNIT(FUTURE)


HP STM

MP STM

LP STM

HP COND

91.1

-43.9

26.9

13.5

DATE

SHEET


8

OF


LP BFW

COLD BFW

DW T/h DEMIN. WATER

LOSSES T/h

HP BFW

0.1

-236.7

-15.2

0.0

0.0

47.4

17.7

99.1

BFW T/h

-0.3

REMARKS

0.3 Intermittent Users in X-1507

METAL PASSIVATOR INJECTION PACKAGE

P-1502 A

METAL PASSIVATION PUMP

0.55

0.00

0.00

P-1502 B


0.55

(0.00)

(0.00)

X-1510

PHOSPHATE INJECTION PACKAGE

6.05

-4.36

-4.84

X-1551

ANTI-FOAM INJECTION PACKAGE

P-1557

ANTI-FOAMING PUMP

0.55

(-0.40)

(-0.44)

P-1558

ANTI-FOAMING PUMP

0.55

(-0.40)

(-0.44)

-3.3

EJ-1501

CATALYST HOPPERS STEAM EJECTOR

SV-1501

REGENERATED CATALYST SLIDE VALVE

4.0

-3.0

SV-1502

SPENT CATALYST SLIDE VALVE

4.0

-3.0

-3.3

SV-1503

FIRST REGENERATOR FLUE GAS SLIDE VALVE

4.0

-3.0

-3.3

SV-1504

SECOND REGENERATOR FLUE GAS SLIDE VALVE

4.0

-3.0

-3.3

PV-1501

PLUG VALVE

4.0

-3.0

-3.3

---

OIL MIST GENERATOR

3.0

-3.0

-3.0

---

STEAM TRACE

(0.9)

(-0.9)

0.1

-0.1

-2.0

2.0

PAGE TOTAL

611

-631.5

-633.7

0.0

0.0

-2.4

0.0

0.0

2.0

0.0

0.0

0.0

0.0

0.0

0.4

GENERAL TOTAL (excl. Future DeSOx)

10066

-4955.9

-5236.8

91.1

-43.9

24.5

13.5

17.7

2.1

99.1

-236.7

-15.2

0.0

0.0

47.8

GENERAL TOTAL (incl. Future DeSOx)

10066

-5225.9

-5536.8

91.1

-43.9

24.5

13.5

17.7

2.1

99.1

-236.7

-15.2

0.0

0.0

47.8

NOTES

_ _ _ __ RA| D __| N I ||___ (

S-015-1223-511-1.xls

7 2-20007 FEABR0273-M



10

APPROVED BY

MOTOR/LOAD RATING:


MECH. RUNNING LOAD:

MOTOR SHAFT POWER




REV



CLIENT

PETROVIETNAM

LOCATION

DUNG QUAT

PLANT CAPACITY

VIETNAM

SECTION No.

015 RFCC

CASE

UNIT

ITEM No.

Project N° - Unit

Doc. type

Code

Serial N°

Rev. index

8474L 015

CN

00 03

511

1

REVISION

COOLING WATER

DESCRIPTION

ΔT ºC

m3/h

E-1518


6.0

-19

E-1520 A-H


8.0

-1882

E-1531

SURFACE CONDENSER

E-1532

BLOWDOWN COOLER

13.0

-15

E-1533

BLOWDOWN COOLER

15.0

-24

E-1552 A/B


8.0

-255

E-1554 A-D

STRIPPER CONDENSER

6.0

-820

E-1559

GASOLINE COOLER

6.0

-160

E-1561 A/B


12.0

-1353

E-1562

LPG COOLER

6.0

-64

E-1564

LEAN OIL COOLER

6.0

-177

E-1565

FUEL GAS COOLER

6.0

-9

E-1566

LEAN AMINE COOLER

6.0

-72

E-1567

TURBINE CONDENSER

69,700 BPSD Bach Ho Max Gasoline - Normal Case SEA WATER ΔT ºC

m3/h

8.8

-7285

8.8

-2300

FRESH WATER T/h

DATE

SHEET


9

DESCRIPTION PLANT AIR INST. Nm3/h AIR Nm3/h CONTIN INTERMIT

NITROGEN Nm3/h

S-015-1223-511-1.xls

7 2-20007 FEABR0273-M

(

CONTIN

INTERMIT

Efficiency %

FUEL FIRED MW

PUMP / COMP COOLING

-95

PAGE TOTAL

-4945

-9585

0

0

0

0

0

0

0.0

0.0

0.0

GENERAL TOTAL

-4945

-9585

0

0

0

0

0

0

0.0

0.0

0.0



10

FURNACES & BOILERS DUTY MW

NOTES

_ _ _ __ RA| D __| N I ||___

OF

APPROVED BY


REMARKS

REV



CLIENT

PETROVIETNAM

LOCATION

DUNG QUAT

PLANT CAPACITY

VIETNAM

SECTION No.

015 RFCC

CASE

UNIT

ITEM No.

Doc. type

Code

Serial N°

Rev. index

8474L 015

CN

00 03

511

1

REVISION

DESCRIPTION

COOLING WATER ΔT ºC

m3/h -4945


69,700 BPSD Bach Ho Max Gasoline - Normal Case SEA WATER ΔT ºC

m3/h

FRESH WATER T/h

DATE

SHEET

WRITTEN BY 10

CHECKED BY

DESCRIPTION INST. PLANT AIR AIR Nm3/h Nm3/h CONTIN INTERMIT

H-1502

SECOND REGENERATOR HEATER

H-1503

COB/WHB PACKAGE

NITROGEN Nm3/h CONTIN

FURNACES & BOILERS

INTERMIT

DUTY MW

X-1507 X-1504

X-1502

FRESH CATALYST FEEDER

X-1503

AUXILIARY CATALYST FEEDER

C-1501

AIR BLOWER

-22

-3

-50

(-125)


-26

-8

(-85)

SLURRY SEPARATOR

-1

OIL MIST GENERATOR

-165 -3

-60

(-40)

(-3)

(-60)

(-40)

GLAND CONDENSER

-76

OIL COOLER

-32 -6

MAIN OIL COOLER

6.0

-60

GLAND CONDENSER

6.0

-50

PV-1501

PLUG VALVE

SV-1501


SV-1502


SV-1504


-134

PRIMARY PLANT AIR FOR REGEN SECTION

-4230

REV

(-280)

-611 -84 -36

(2)

1

(-2320) -340

-160

(-560)

PAGE TOTAL

-221

0

0

-5658

-118

0

-351

0

0.0

0.0

-113.7

GENERAL TOTAL

-5166

-9585

0

-5658

-118

0

-351

0

0.0

0.0

-113.7

MISCELLANEOUS USERS

-13.7

NOTES 1. FUEL GAS RATES DURING START-UP FOR BOTH REGENERATOR AIR HEATERS (APPROX. 4.5 T/h) 2. PLANT AIR FROM INSTRUMENT AIR HEADER FOR PRIMARY USERS.


REMARKS

-100.0

-71

SECONDARY PLANT AIR FOR REGEN SECTION

7 2-20007 FEABR0273-M

FUEL FIRED MW

(1) 15.0

WET GAS COMPRESSOR

S-015-1223-511-1.xls

Efficiency %

(1)

-120

(

10

-9585

FIRST REGENERATOR AIR HEATER

_ _ _ __ RA| D __| N I ||___

OF

APPROVED BY

H-1501

C-1551

Project N° - Unit



1



PETROVIETNAM

LOCATION

DUNG QUAT

PLANT CAPACITY

VIETNAM

SECTION No.

015 RFCC

CASE

UNIT



7 2-20007 FEABR0273-M

Code

Serial N°

Rev. index

CN

00 03

512

1

Op. Center JOB No.

0-3952-20-0000

Op. Center Doc. No.

S-015-1223-512

FEED Doc. No.

A

0

1

23-MAY-06

01-FEB-07

23-FEB-07

WRITTEN BY

T. Tsuchiya

T. Tsuchiya

T. Tsuchiya

Bach Ho Max Distillate

CHECKED BY

M. Okada

M. Okada

M. Okada

- Normal Case

APPROVED BY

M. Okada

M. Okada

M. Okada

DESCRIPTION

Issue for Review

For Construction

For Construction

2,4,10

Bach Ho MD - Normal

S-015-1223-512-1.xls

Doc. type

8474L 015

DATE

GENERAL NOTES:

_ _ _ __ RA| D __| N I ||___

X

Project N° - Unit

6960-015-DS-0711

SHEET

1

OF

10



PETROVIETNAM

LOCATION

DUNG QUAT

PLANT CAPACITY

VIETNAM

SECTION No.

015 RFCC

CASE

UNIT

ITEM No.

DESCRIPTION

MOTOR LOAD/ RATING


HP STM

MP STM

219.3

0.7


C-1502 B


(-21.0)


-1.7

1230

-0.3

-0.3

-683.0

-697.0

E-1534


3

-3.0

-3.0

P-1529 A


55

-39.0

-43.3

P-1529 B


55

(-39.0)

(-43.3)

E-1531


-18.5

-20.6

15

-15.0

-15.0


-


-

TURNING GEAR MOTOR

WET GAS COMPRESSOR

-1.5

-1.5


18.5

-13.9

-14.8

P-1559 B


18.5

(-13.9)

(-14.8)

E-1567


-16.0

-17.8


Serial N°

Rev. index

8474L 015

CN

00 03

512

1

HP COND

DATE

SHEET


2

OF

-68.7

-30.4


BFW T/h HP BFW

LP BFW

-225.5

-0.7

COLD BFW

DW T/h DEMIN. WATER

LOSSES T/h

REMARKS

1

1.7

-0.3

7.0 -0.1

0.1

68.7

0.3

30.4

0.4

(2.6)

-0.4

(-2.1)

(2.1)


-


0.5

-0.5

D-1527

LP BLOWDOWN DRUM

0.2

-0.2

T-1503

LCO STRIPPER

-3.0

3.0

T-1504

HCO STRIPPER

-0.5

0.5

34.7

-34.7

PAGE TOTAL

1462

-790.2

-813.3

118.5

-41.7

-2.9

0.0

7.0

0.1

99.1

-225.5

-0.7

0.0

0.0

46.1

GENERAL TOTAL

1462

-790.2

-813.3

118.5

-41.7

-2.9

0.0

7.0

0.1

99.1

-225.5

-0.7

0.0

0.0

46.1

NOTES

(

S-015-1223-512-1.xls

7 2-20007 FEABR0273-M



REV

6.2

D-1501

_ _ _ __ RA| D __| N I ||___

10

APPROVED BY

(21.0)

(-2.6)

C-1551

-

LP STM

-7.0

P-1559 A

-

Code

Included in H-1503

C-1501

-

69,700 BPSD Bach Ho Max Distillate - Normal Case STEAM T/h

H-1503

ECONOMIZER

Doc. type

REVISION

C-1502 A

E-1525

Project N° - Unit

MOTOR/LOAD RATING:


MECH. RUNNING LOAD:

MOTOR SHAFT POWER






PETROVIETNAM

LOCATION

DUNG QUAT

PLANT CAPACITY

VIETNAM

SECTION No.

015 RFCC

CASE

UNIT

ITEM No.

DESCRIPTION

Project N° - Unit

Doc. type

Code

Serial N°

Rev. index

8474L 015

CN

00 03

512

1

REVISION

MOTOR LOAD/ RATING



1462

-790.2

-813.3

P-1501 A

FEED PUMP

600

-476.0

-500.5

P-1501 B

FEED PUMP

600

(-476.0)

(-500.5)


DATE

SHEET


3

OF


HP STM

MP STM

LP STM

HP COND

118.5

-41.7

-2.9

0.0

7.0

0.1

99.1

LP BFW

COLD BFW

DW T/h DEMIN. WATER

LOSSES T/h

HP BFW -225.5

-0.7

0.0

0.0

46.1

BFW T/h

P-1504 A

SLURRY PRODUCT PUMP

55

-42.7

-45.1

P-1504 B

SLURRY PRODUCT PUMP

55

(-42.7)

(-45.1)

P-1505 A

BACKFLUSH OIL PUMP

22

-15.0

-16.5

P-1505 B

BACKFLUSH OIL PUMP

22

(-15.0)

(-16.5)

P-1506 A


11

-7.4

-8.4

P-1506 B


11

(-7.4)

(-8.4)

P-1507 A

HCO RECYCLE PUMP

150

-128.0

-142.2

P-1507 B

HCO RECYCLE PUMP

150

(-128.0)

(-142.2)

P-1508 A

HCO PUMPAROUND PUMP

220

-179.4

-188.4

P-1508 B

HCO PUMPAROUND PUMP

220

(-179.4)

(-188.4)

P-1509 A

HCO PRODUCT PUMP

15

-9.1

-10.1

P-1509 B

HCO PRODUCT PUMP

15

(-9.1)

(-10.1)

P-1510 A

LCO PUMPAROUND PUMP

335

-303.0

-316.0

P-1510 B

LCO PUMPAROUND PUMP

335

(-303.0)

(-316.0)

P-1511 A

LCO STRIPPER PUMP

90

-73.4

-76.9

P-1511 B

LCO STRIPPER PUMP

90

(-73.4)

(-76.9)

P-1512 A

MTC RECYCLE PUMP

75

0.0

0.0

P-1512 B

MTC RECYCLE PUMP

75

(0.0)

(0.0)

P-1513 A

LEAN OIL PUMP

75

-55.0

-58.1

P-1513 B

LEAN OIL PUMP

75

(-55.0)

(-58.1)

P-1514 A


225

-203.0

-213.9

P-1514 B


225

(-203.0)

(-213.9)

PAGE TOTAL

3746

-1492.0

-1576.1

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

GENERAL TOTAL

5208

-2282.2

-2389.4

118.5

-41.7

-2.9

0.0

7.0

0.1

99.1

-225.5

-0.7

0.0

0.0

46.1

REMARKS

NOTES

_ _ _ __ RA| D __| N I ||___ (

S-015-1223-512-1.xls

7 2-20007 FEABR0273-M



10

APPROVED BY

MOTOR/LOAD RATING:


MECH. RUNNING LOAD:

MOTOR SHAFT POWER




REV



PETROVIETNAM

LOCATION

DUNG QUAT

PLANT CAPACITY

VIETNAM

SECTION No.

015 RFCC

CASE

UNIT

ITEM No.

DESCRIPTION

Project N° - Unit

Doc. type

Code

Serial N°

Rev. index

8474L 015

CN

00 03

512

1

REVISION

MOTOR LOAD/ RATING



HP STM

MP STM

LP STM

HP COND

118.5

-41.7

-2.9

0.0


5208

-2282.2

-2389.4

P-1515 A


55

-39.4

-41.6

P-1515 B


55

(-39.4)

(-41.6)

P-1516 A


110

-96.0

-101.3

P-1516 B


110

(-96.0)

(-101.3)

P-1517 A


30

-25.5

-27.6

P-1517 B


30

(-25.5)

(-27.6)

P-1518 A


250

-206.0

-228.9

P-1518 B


250

(-206.0)

(-228.9)

P-1519 A


-10.3

P-1519 B


-10.3

10.3

P-1519 C


(-10.3)

(10.3)


-0.8

P-1521 A


-3.7

DATE

SHEET


4

OF

DESCRIPTION CONDENSATE T/h MP COLD LP COND COND COND 7.0

0.1

99.1

LP BFW

COLD BFW

DW T/h DEMIN. WATER

LOSSES T/h

HP BFW

BFW T/h

-225.5

-0.7

0.0

0.0

46.1

REMARKS

0.8 3.7

P-1521 B


110

(-80.9)


30

-18.4

-19.9

P-1522 B


30

(-18.4)

(-19.9)

P-1526 A

LIGHT SLOPS PUMP

37

-26.1

-27.9

P-1526 B

LIGHT SLOPS PUMP

37

(-26.1)

(-27.9)

P-1527 A

HEAVY SLOPS PUMP

37

-27.9

-29.8

P-1527 B

HEAVY SLOPS PUMP

37

(-27.9)

(-29.8)

P-1528 A

TEMPERED WATER PUMP

15

-10.5

-11.7

P-1528 B

TEMPERED WATER PUMP

15

(-10.5)

(-11.7)

PAGE TOTAL

1238

-449.8

-488.7

-25.1

0.0

24.3

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.8

GENERAL TOTAL

6446

-2732.0

-2878.1

93.4

-41.7

21.4

0.0

7.0

0.1

99.1

-225.5

-0.7

0.0

0.0

46.9

(-84.4)

NOTES

(

S-015-1223-512-1.xls

7 2-20007 FEABR0273-M



REV

10.3

P-1522 A

_ _ _ __ RA| D __| N I ||___

10

APPROVED BY

MOTOR/LOAD RATING:


MECH. RUNNING LOAD:

MOTOR SHAFT POWER




1



PETROVIETNAM

LOCATION

DUNG QUAT

PLANT CAPACITY

VIETNAM

SECTION No.

015 RFCC

CASE

UNIT

ITEM No.

DESCRIPTION

Project N° - Unit

Doc. type

Code

Serial N°

Rev. index

8474L 015

CN

00 03

512

1

REVISION

MOTOR LOAD/ RATING



6446

-2732.0

-2878.1

P-1551 A


150

-134.0

-142.3

P-1551 B


150

(-134.0)

(-142.3)

P-1552 A

KO DRUM LIQUID PUMP

4

-1.2

-1.4

P-1552 B

KO DRUM LIQUID PUMP

4

(-1.2)

(-1.4)

P-1553 A

STRIPPER FEED PUMP

132

-112.0

-117.9

P-1553 B

STRIPPER FEED PUMP

132

(-112.0)

(-117.9)

P-1554 A


55

-44.0

-47.7

P-1554 B


55

(-44.0)

(-47.7)

P-1556 A


225

-185.0

-194.9

P-1556 B


225

(-185.0)

(-194.9)


DATE

SHEET


5

OF


LP BFW

COLD BFW

DW T/h DEMIN. WATER

LOSSES T/h

HP BFW -225.5

-0.7

0.0

0.0

46.9

HP STM

MP STM

LP STM

HP COND

93.4

-41.7

21.4

0.0

7.0

0.1

99.1

BFW T/h

P-1560 A


22

(-16.5)

(-18.1)

P-1560 B


22

(-16.5)

(-18.1)

P-1561


7.5

(-4.9)

(-5.4)

P-1562


7.5

(-4.9)

(-5.4)

P-1563


7.5

(-4.9)

(-5.4)

P-1564


15

(-10.8)

(-12.0)

PAGE TOTAL

1214

-476.2

-504.2

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

GENERAL TOTAL

7660

-3208.2

-3382.3

93.4

-41.7

21.4

0.0

7.0

0.1

99.1

-225.5

-0.7

0.0

0.0

46.9

REMARKS

NOTES

_ _ _ __ RA| D __| N I ||___ (

S-015-1223-512-1.xls

7 2-20007 FEABR0273-M



10

APPROVED BY

MOTOR/LOAD RATING:


MECH. RUNNING LOAD:

MOTOR SHAFT POWER




REV



PETROVIETNAM

LOCATION

DUNG QUAT

PLANT CAPACITY

VIETNAM

SECTION No.

015 RFCC

CASE

UNIT

ITEM No.

DESCRIPTION

Project N° - Unit

Doc. type

Code

Serial N°

Rev. index

8474L 015

CN

00 03

512

1

REVISION

MOTOR LOAD/ RATING



HP STM

MP STM

LP STM

HP COND

93.4

-41.7

21.4

0.0


7660

-3208.2

-3382.3

E-1514

LCO AIR COOLER

120

-97.6

-106.2

E-1517


33

-20.4

-23.1

E-1519


960

-736.0

-800.9

E-1521


120

-99.6

-108.4

E-1530


22.5

-15.0

-17.8

E-1551


240

-190.4

-207.2

DATE

SHEET

WRITTEN BY 6

CHECKED BY

OF


0.1

99.1

LP BFW

COLD BFW

DW T/h DEMIN. WATER

LOSSES T/h

HP BFW -225.5

-0.7

0.0

0.0

46.9

BFW T/h

E-1553

HP CONDENSER

180

-134.4

-146.2

E-1558

GASOLINE AIR COOLER

120

-92.8

-101.0

E-1503


0.0

0.0

E-1504


18.0

-18.5

E-1505


E-1506


E-1508


E-1510

0.4

1.3

-1.4

0.1

-6.7

0.2


2.9

-3.0

0.1

E-1513


8.6

-8.9

0.3

E-1518


13.8

6.5

REMARKS

0.5

-14.2

PAGE TOTAL

1796

-1386.2

-1510.8

18.0

20.3

12.8

0.0

0.0

0.0

0.0

-18.5

-34.2

0.0

0.0

1.6

GENERAL TOTAL

9455

-4594.4

-4893.1

111.4

-21.4

34.2

0.0

7.0

0.1

99.1

-244.0

-34.9

0.0

0.0

48.5

NOTES

_ _ _ __ RA| D __| N I ||___ (

S-015-1223-512-1.xls

7 2-20007 FEABR0273-M



10

APPROVED BY

MOTOR/LOAD RATING:


MECH. RUNNING LOAD:

MOTOR SHAFT POWER




REV



PETROVIETNAM

LOCATION

DUNG QUAT

PLANT CAPACITY

VIETNAM

SECTION No.

015 RFCC

CASE

UNIT

ITEM No.

DESCRIPTION


Project N° - Unit

Doc. type

Code

Serial N°

Rev. index

8474L 015

CN

00 03

512

1

REVISION




HP STM

MP STM

LP STM

HP COND

-4893.1

111.4

-21.4

34.2

0.0

-4594.4

DATE

SHEET


7

OF


LP BFW

COLD BFW

DW T/h DEMIN. WATER

LOSSES T/h

HP BFW

0.1

-244.0

-34.9

0.0

0.0

48.5

7.0

99.1

BFW T/h

REMARKS


E-1520 A-H E-1522


-6.5

E-1523


7.3

E-1524


E-1532

BLOWDOWN COOLER

E-1552 A/B


E-1554 A-D

STRIPPER CONDENSER

E-1559

GASOLINE COOLER

E-1561 A/B


E-1562

LPG COOLER

E-1564

LEAN OIL COOLER

6.5

Cold Feed Case: -16.4 t/h MPS -7.5

-11.3

0.2

11.3


E-1565

FUEL GAS COOLER

E-1566

LEAN AMINE COOLER

I-1501

FEED INJECTOR

Included in D-1501

I-1502

MTC INJECTOR

Included in D-1501

I-1503


Included in D-1501

I-1504


SPR-1501


(-0.3)

SPR-1502


(-0.3)

SPR-1503


(-1.5)

(-22.8)

(-24.3)

SPR-1504


(-1.5)

(-14.0)

(-15.5)

SPR-1505


(-1.5)

(-5.2)

(-6.7)

Included in D-1501 (0.3) (0.3)

PAGE TOTAL

0

0.0

0.0

-11.3

0.8

0.0

11.3

6.5

0.0

0.0

0.0

-7.5

0.0

0.0

0.2

GENERAL TOTAL

9455

-4594.4

-4893.1

100.1

-20.6

34.2

11.3

13.5

0.1

99.1

-244.0

-42.4

0.0

0.0

48.7

NOTES

_ _ _ __ RA| D __| N I ||___ (

S-015-1223-512-1.xls

7 2-20007 FEABR0273-M



10

APPROVED BY

MOTOR/LOAD RATING:


MECH. RUNNING LOAD:

MOTOR SHAFT POWER




REV



PETROVIETNAM

LOCATION

DUNG QUAT

PLANT CAPACITY

VIETNAM

SECTION No.

015 RFCC

CASE

UNIT

ITEM No.

DESCRIPTION


SLURRY SEPARATOR

X-1505


Doc. type

Code

Serial N°

Rev. index

8474L 015

CN

00 03

512

1

REVISION

MOTOR LOAD/ RATING


9455

-4594.4

-4893.1

-230.0

-230.0

P-1520


0.55

-0.40

-0.44

X-1507


491

-379.0

-379.0

88

(-53)

(-53)

(-270.0)

(-300.0)

X-1508

Project N° - Unit

DESOX UNIT(FUTURE)

X-1509


P-1502 A


0.55

0.00

0.00

P-1502 B


0.55

(0.00)

(0.00)

X-1510


6.05

-4.36

-4.84

X-1551


P-1557

ANTI-FOAMING PUMP

0.55

(-0.40)

(-0.44)

P-1558

ANTI-FOAMING PUMP

0.55

(-0.40)

(-0.44)

-3.3


HP STM

MP STM

LP STM

HP COND

100.1

-20.6

34.2

11.3

DATE

SHEET

WRITTEN BY 8

CHECKED BY


0.1

99.1

LP BFW

COLD BFW

DW T/h DEMIN. WATER

LOSSES T/h

HP BFW -244.0

-42.4

0.0

0.0

48.7

BFW T/h

-0.3

CATALYST HOPPERS STEAM EJECTOR REGENERATED CATALYST SLIDE VALVE

4.0

-3.0

SV-1502


4.0

-3.0

-3.3

SV-1503


4.0

-3.0

-3.3

SV-1504


4.0

-3.0

-3.3

PV-1501

PLUG VALVE

4.0

-3.0

-3.3

---

OIL MIST GENERATOR

3.0

-3.0

-3.0

---

STEAM TRACE

REMARKS


(-0.9)

EJ-1501 SV-1501

OF

(0.9)

-0.1

0.1

-2.0

2.0

PAGE TOTAL

611

-631.5

-633.7

0.0

0.0

-2.4

0.0

0.0

2.0

0.0

0.0

0.0

0.0

0.0

0.4


10066

-5225.9

-5526.7

100.1

-20.6

31.8

11.3

13.5

2.1

99.1

-244.0

-42.4

0.0

0.0

49.1


10066

-5495.9

-5826.7

100.1

-20.6

31.8

11.3

13.5

2.1

99.1

-244.0

-42.4

0.0

0.0

49.1

NOTES

_ _ _ __ RA| D __| N I ||___ (

S-015-1223-512-1.xls

7 2-20007 FEABR0273-M



10

APPROVED BY

MOTOR/LOAD RATING:


MECH. RUNNING LOAD:

MOTOR SHAFT POWER




REV



CLIENT

PETROVIETNAM

LOCATION

DUNG QUAT

PLANT CAPACITY

VIETNAM

SECTION No.

015 RFCC

CASE

UNIT

ITEM No.

Project N° - Unit

Doc. type

Code

Serial N°

Rev. index

8474L 015

CN

00 03

512

1

REVISION

COOLING WATER

DESCRIPTION

ΔT ºC

m3/h

E-1518


6.0

-20

E-1520 A-H


8.0

-1743

E-1531

SURFACE CONDENSER

E-1532

BLOWDOWN COOLER

13.0

-15

E-1533

BLOWDOWN COOLER

15.0

-24

E-1552 A/B


8.0

-225

E-1554 A-D

STRIPPER CONDENSER

6.0

-650

E-1559

GASOLINE COOLER

6.0

-138

E-1561 A/B


12.0

-1159

E-1562

LPG COOLER

6.0

-49

E-1564

LEAN OIL COOLER

6.0

-196

E-1565

FUEL GAS COOLER

6.0

-6

E-1566

LEAN AMINE COOLER

6.0

-53

E-1567

TURBINE CONDENSER

69,700 BPSD Bach Ho Max Distillate - Normal Case SEA WATER ΔT ºC

m3/h

8.8

-7285

8.8

-2300

FRESH WATER T/h

DATE

SHEET


9


NITROGEN Nm3/h

S-015-1223-512-1.xls

7 2-20007 FEABR0273-M

(

CONTIN

INTERMIT

Efficiency %

FUEL FIRED MW

PUMP / COMP COOLING

-95

PAGE TOTAL

-4373

-9585

0

0

0

0

0

0

0.0

0.0

0.0

GENERAL TOTAL

-4373

-9585

0

0

0

0

0

0

0.0

0.0

0.0



10


NOTES

_ _ _ __ RA| D __| N I ||___

OF

APPROVED BY


REMARKS

REV



CLIENT

PETROVIETNAM

LOCATION

DUNG QUAT

PLANT CAPACITY

VIETNAM

SECTION No.

015 RFCC

CASE

UNIT

ITEM No.

Doc. type

Code

Serial N°

Rev. index

8474L 015

CN

00 03

512

1

REVISION

DESCRIPTION



m3/h -4373

69,700 BPSD Bach Ho Max Distillate - Normal Case SEA WATER ΔT ºC

m3/h

FRESH WATER T/h

DATE

SHEET


10


H-1502


H-1503

COB/WHB PACKAGE


FURNACES & BOILERS

INTERMIT

DUTY MW

X-1507 X-1504

X-1502


X-1503


C-1501

AIR BLOWER

-22

(-125)


-26

-8

(-85)

SLURRY SEPARATOR

-1

OIL MIST GENERATOR

-165 -3

-60

(-40)

(-3)

(-60)

(-40)

-3

GLAND CONDENSER

-76

OIL COOLER

-32 -6

MAIN OIL COOLER

6.0

-60

GLAND CONDENSER

6.0

-50

PV-1501

PLUG VALVE

SV-1501


SV-1502


SV-1504


-134


-4230

REV

(-280)

-611 -84 -36

(2)

1

(-2320) -340

-160

(-560)

PAGE TOTAL

-221

0

0

-5658

-118

0

-351

0

0.0

0.0

-123.7

GENERAL TOTAL

-4594

-9585

0

-5658

-118

0

-351

0

0.0

0.0

-123.7

MISCELLANEOUS USERS

-13.7



REMARKS

-110.0

-71


7 2-20007 FEABR0273-M

FUEL FIRED MW

(1) -50

15.0

WET GAS COMPRESSOR

S-015-1223-512-1.xls

Efficiency %

(1)

-120

(

10

-9585


_ _ _ __ RA| D __| N I ||___

OF

APPROVED BY

H-1501

C-1551

Project N° - Unit



1



PETROVIETNAM

LOCATION

DUNG QUAT

PLANT CAPACITY

VIETNAM

SECTION No.

015 RFCC

CASE

UNIT



7 2-20007 FEABR0273-M

Code

Serial N°

Rev. index

CN

00 03

513

1

Op. Center JOB No.

0-3952-20-0000

Op. Center Doc. No.

S-015-1223-513

FEED Doc. No.

A

0

1

23-MAY-06

01-FEB-07

23-FEB-07

WRITTEN BY

T. Tsuchiya

T. Tsuchiya

T. Tsuchiya

Mixed Crude Max Gasoline

CHECKED BY

M. Okada

M. Okada

M. Okada

- Normal Case

APPROVED BY

M. Okada

M. Okada

M. Okada

DESCRIPTION

Issue for Review

For Construction

For Construction

2,4,10

Mixed Crude MG - Normal

S-015-1223-513-1.xls

Doc. type

8474L 015

DATE

GENERAL NOTES:

_ _ _ __ RA| D __| N I ||___

X

Project N° - Unit

6960-015-DS-0711

SHEET

1

OF

10



PETROVIETNAM

LOCATION

DUNG QUAT

PLANT CAPACITY

VIETNAM

SECTION No.

015 RFCC

CASE

UNIT

ITEM No.

DESCRIPTION

MOTOR LOAD/ RATING


-0.3

-0.3

-352.0

-363.0

HP STM

MP STM

214.0

0.7


C-1502 B


(-11.0)


-0.9

1230


3

-3.0

-3.0

P-1529 A


55

-39.0

-43.3

P-1529 B


55

(-39.0)

(-43.3)

E-1531


-18.5

-20.6

15

-15.0

-15.0


-

TURNING GEAR MOTOR

C-1551

WET GAS COMPRESSOR

-1.5

-1.5


18.5

-13.9

-14.8

P-1559 B


18.5

(-13.9)

(-14.8)

E-1567


-16.0

-17.8


-


Serial N°

Rev. index

8474L 015

CN

00 03

513

1

HP COND

DATE

SHEET


2

OF

-94.0

-32.2


BFW T/h HP BFW

LP BFW

-220.2

-0.7

COLD BFW

DW T/h DEMIN. WATER

LOSSES T/h

REMARKS

0.9

-0.3

1

10.0 -0.1

0.1

94.0

0.3

32.2

0.4

(2.6)

-0.4

(-2.1)

(2.1)


-


0.5

-0.5

D-1527

LP BLOWDOWN DRUM

0.5

-0.5

T-1503

LCO STRIPPER

-3.0

3.0

T-1504

HCO STRIPPER

-0.5

0.5

-34.7

34.7

PAGE TOTAL

1462

-459.2

-479.3

86.9

-44.7

-2.6

0.0

10.0

0.1

126.2

-220.2

-0.7

0.0

0.0

45.0

GENERAL TOTAL

1462

-459.2

-479.3

86.9

-44.7

-2.6

0.0

10.0

0.1

126.2

-220.2

-0.7

0.0

0.0

45.0

NOTES

(

S-015-1223-513-1.xls

7 2-20007 FEABR0273-M



REV

6.2

D-1501

_ _ _ __ RA| D __| N I ||___

10

APPROVED BY

(11.0)

(-2.6)

P-1559 A

-

LP STM

-10.0

E-1534

-

Code

Included in H-1503

C-1501

-

69,700 BPSD Mixed Crude Max Gasoline - Normal Case STEAM T/h

H-1503

ECONOMIZER

Doc. type

REVISION

C-1502 A

E-1525

Project N° - Unit

MOTOR/LOAD RATING:


MECH. RUNNING LOAD:

MOTOR SHAFT POWER






PETROVIETNAM

LOCATION

DUNG QUAT

PLANT CAPACITY

VIETNAM

SECTION No.

015 RFCC

CASE

UNIT

ITEM No.

DESCRIPTION

Project N° - Unit

Doc. type

Code

Serial N°

Rev. index

8474L 015

CN

00 03

513

1

REVISION

MOTOR LOAD/ RATING



1462

-459.2

-479.3

P-1501 A

FEED PUMP

600

-476.0

-500.5

P-1501 B

FEED PUMP

600

(-476.0)

(-500.5)


HP STM

MP STM

LP STM

HP COND

86.9

-44.7

-2.6

0.0

DATE

SHEET

WRITTEN BY 3

CHECKED BY

OF


LP BFW

COLD BFW

DW T/h DEMIN. WATER

LOSSES T/h

HP BFW

10.0

0.1

-220.2

-0.7

0.0

0.0

45.0

126.2

BFW T/h

P-1504 A

SLURRY PRODUCT PUMP

55

-42.7

-45.1

P-1504 B

SLURRY PRODUCT PUMP

55

(-42.7)

(-45.1)

P-1505 A

BACKFLUSH OIL PUMP

22

-15.0

-16.5

P-1505 B

BACKFLUSH OIL PUMP

22

(-15.0)

(-16.5)

P-1506 A


11

-7.4

-8.4

P-1506 B


11

(-7.4)

(-8.4)

P-1507 A

HCO RECYCLE PUMP

150

0.0

0.0

P-1507 B

HCO RECYCLE PUMP

150

(0.0)

(0.0)

P-1508 A

HCO PUMPAROUND PUMP

220

-179.4

-188.4

P-1508 B

HCO PUMPAROUND PUMP

220

(-179.4)

(-188.4)

P-1509 A

HCO PRODUCT PUMP

15

-9.1

-10.1

P-1509 B

HCO PRODUCT PUMP

15

(-9.1)

(-10.1)

P-1510 A

LCO PUMPAROUND PUMP

335

-303.0

-316.0

P-1510 B

LCO PUMPAROUND PUMP

335

(-303.0)

(-316.0)

P-1511 A

LCO STRIPPER PUMP

90

-73.4

-76.9

P-1511 B

LCO STRIPPER PUMP

90

(-73.4)

(-76.9)

P-1512 A

MTC RECYCLE PUMP

75

-67.0

-72.0

P-1512 B

MTC RECYCLE PUMP

75

(-67.0)

(-72.0)

P-1513 A

LEAN OIL PUMP

75

-55.0

-58.1

P-1513 B

LEAN OIL PUMP

75

(-55.0)

(-58.1)

P-1514 A


225

-203.0

-213.9

P-1514 B


225

(-203.0)

(-213.9)

PAGE TOTAL

3746

-1431.0

-1505.9

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

GENERAL TOTAL

5208

-1890.2

-1985.2

86.9

-44.7

-2.6

0.0

10.0

0.1

126.2

-220.2

-0.7

0.0

0.0

45.0

REMARKS

NOTES

_ _ _ __ RA| D __| N I ||___ (

S-015-1223-513-1.xls

7 2-20007 FEABR0273-M



10

APPROVED BY

MOTOR/LOAD RATING:


MECH. RUNNING LOAD:

MOTOR SHAFT POWER




REV



PETROVIETNAM

LOCATION

DUNG QUAT

PLANT CAPACITY

VIETNAM

SECTION No.

015 RFCC

CASE

UNIT

ITEM No.

DESCRIPTION

Project N° - Unit

Doc. type

Code

Serial N°

Rev. index

8474L 015

CN

00 03

513

1

REVISION

MOTOR LOAD/ RATING



5208

-1890.2

-1985.2

P-1515 A


55

-39.4

-41.6

P-1515 B


55

(-39.4)

(-41.6)

P-1516 A


110

-96.0

-101.3 (-101.3)


HP STM

MP STM

LP STM

HP COND

86.9

-44.7

-2.6

0.0

DATE

SHEET


4

OF


LP BFW

COLD BFW

DW T/h DEMIN. WATER

LOSSES T/h

HP BFW

0.1

-220.2

-0.7

0.0

0.0

45.0

10.0

126.2

BFW T/h

P-1516 B


110

(-96.0)

P-1517 A


30

-25.5

-27.6

P-1517 B


30

(-25.5)

(-27.6)

P-1518 A


250

-206.0

-228.9

P-1518 B


250

(-206.0)

(-228.9)

P-1519 A


-10.3

P-1519 B


-10.3

10.3

P-1519 C


(-10.3)

(10.3)


-0.8

P-1521 A


-3.7

P-1521 B


110

(-80.9)

P-1522 A


30

-18.4

-19.9

P-1522 B


30

(-18.4)

(-19.9)

P-1526 A

LIGHT SLOPS PUMP

37

-26.1

-27.9

P-1526 B

LIGHT SLOPS PUMP

37

(-26.1)

(-27.9)

P-1527 A

HEAVY SLOPS PUMP

37

-27.9

-29.8

P-1527 B

HEAVY SLOPS PUMP

37

(-27.9)

(-29.8)

P-1528 A

TEMPERED WATER PUMP

15

-10.5

-11.7

P-1528 B

TEMPERED WATER PUMP

15

(-10.5)

(-11.7)

PAGE TOTAL

1238

-449.8

-488.7

-25.1

0.0

24.3

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.8

GENERAL TOTAL

6446

-2340.0

-2473.8

61.8

-44.7

21.7

0.0

10.0

0.1

126.2

-220.2

-0.7

0.0

0.0

45.8

REMARKS

(

S-015-1223-513-1.xls

7 2-20007 FEABR0273-M


0.8 3.7

(-84.4)


REV

10.3

NOTES

_ _ _ __ RA| D __| N I ||___

10

APPROVED BY

MOTOR/LOAD RATING:


MECH. RUNNING LOAD:

MOTOR SHAFT POWER




1



PETROVIETNAM

LOCATION

DUNG QUAT

PLANT CAPACITY

VIETNAM

SECTION No.

015 RFCC

CASE

UNIT

ITEM No.

DESCRIPTION

Project N° - Unit

Doc. type

Code

Serial N°

Rev. index

8474L 015

CN

00 03

513

1

REVISION

MOTOR LOAD/ RATING



HP STM

MP STM

LP STM

HP COND

61.8

-44.7

21.7

0.0


6446

-2340.0

-2473.8

P-1551 A


150

-134.0

-142.3

P-1551 B


150

(-134.0)

(-142.3)

P-1552 A

KO DRUM LIQUID PUMP

4

-1.2

-1.4

P-1552 B

KO DRUM LIQUID PUMP

4

(-1.2)

(-1.4)

P-1553 A

STRIPPER FEED PUMP

132

-112.0

-117.9

P-1553 B

STRIPPER FEED PUMP

132

(-112.0)

(-117.9)

P-1554 A


55

-44.0

-47.7

P-1554 B


55

(-44.0)

(-47.7)

DATE

SHEET


5

OF


0.1

126.2

LP BFW

COLD BFW

DW T/h DEMIN. WATER

LOSSES T/h

HP BFW

BFW T/h

-220.2

-0.7

0.0

0.0

45.8

P-1556 A


225

-185.0

-194.9

P-1556 B


225

(-185.0)

(-194.9)

P-1560 A


22

(-16.5)

(-18.1)

P-1560 B


22

(-16.5)

(-18.1)

P-1561


7.5

(-4.9)

(-5.4)

P-1562


7.5

(-4.9)

(-5.4)

P-1563


7.5

(-4.9)

(-5.4)

P-1564


15

(-10.8)

(-12.0)

PAGE TOTAL

1214

-476.2

-504.2

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

GENERAL TOTAL

7660

-2816.2

-2978.0

61.8

-44.7

21.7

0.0

10.0

0.1

126.2

-220.2

-0.7

0.0

0.0

45.8

REMARKS

NOTES

_ _ _ __ RA| D __| N I ||___ (

S-015-1223-513-1.xls

7 2-20007 FEABR0273-M



10

APPROVED BY

MOTOR/LOAD RATING:


MECH. RUNNING LOAD:

MOTOR SHAFT POWER




REV



PETROVIETNAM

LOCATION

DUNG QUAT

PLANT CAPACITY

VIETNAM

SECTION No.

015 RFCC

CASE

UNIT

ITEM No.

DESCRIPTION

Project N° - Unit

Doc. type

Code

Serial N°

Rev. index

8474L 015

CN

00 03

513

1

REVISION

MOTOR LOAD/ RATING



7660

-2816.2

-2978.0

E-1514

LCO AIR COOLER

120

-97.6

-106.2

E-1517


33

-20.4

-23.1

E-1519


960

-736.0

-800.9

E-1521


120

-99.6

-108.4

E-1530


22.5

-15.0

-17.8

E-1551


240

-190.4

-207.2


HP STM

MP STM

LP STM

HP COND

61.8

-44.7

21.7

0.0

DATE

SHEET


6

OF


0.1

126.2

LP BFW

COLD BFW

DW T/h DEMIN. WATER

LOSSES T/h

HP BFW -220.2

-0.7

0.0

0.0

45.8

BFW T/h

E-1553

HP CONDENSER

180

-134.4

-146.2

E-1558

GASOLINE AIR COOLER

120

-92.8

-101.0

E-1503


43.1

-44.4

1.3

E-1504


18.5

-19.1

0.6

E-1505


E-1506


E-1508


E-1510

13.8

-14.2

0.4

1.2

-1.2

0.0


1.9

-2.0

0.1

E-1513


2.6

-2.7

0.1

E-1518


REMARKS

0.0

0.0

PAGE TOTAL

1796

-1386.2

-1510.8

61.6

13.8

5.7

0.0

0.0

0.0

0.0

-63.5

-20.1

0.0

0.0

2.5

GENERAL TOTAL

9455

-4202.4

-4488.8

123.4

-30.9

27.4

0.0

10.0

0.1

126.2

-283.7

-20.8

0.0

0.0

48.3

NOTES

_ _ _ __ RA| D __| N I ||___ (

S-015-1223-513-1.xls

7 2-20007 FEABR0273-M



10

APPROVED BY

MOTOR/LOAD RATING:


MECH. RUNNING LOAD:

MOTOR SHAFT POWER




REV



PETROVIETNAM

LOCATION

DUNG QUAT

PLANT CAPACITY

VIETNAM

SECTION No.

015 RFCC

CASE

UNIT

ITEM No.

DESCRIPTION


Project N° - Unit

Doc. type

Code

Serial N°

Rev. index

8474L 015

CN

00 03

513

1

REVISION




HP STM

MP STM

LP STM

HP COND

-4488.8

123.4

-30.9

27.4

0.0

-4202.4

DATE

SHEET


7

OF


LP BFW

COLD BFW

DW T/h DEMIN. WATER

LOSSES T/h

HP BFW

0.1

-283.7

-20.8

0.0

0.0

48.3

10.0

126.2

BFW T/h

REMARKS


E-1522


(-17.2)

E-1523


0.9

E-1524


E-1532

BLOWDOWN COOLER

E-1552 A/B


E-1554 A-D

STRIPPER CONDENSER

E-1559

GASOLINE COOLER

E-1561 A/B


E-1562

LPG COOLER

E-1564

LEAN OIL COOLER

(17.2)

Cold Feed Case Only 0.1

-1.0

0.0

0.0

E-1565

FUEL GAS COOLER

E-1566

LEAN AMINE COOLER

I-1501

FEED INJECTOR

Included in D-1501

I-1502

MTC INJECTOR

Included in D-1501

I-1503


Included in D-1501

I-1504


SPR-1501


(-0.3)


SPR-1502


(-0.3)

SPR-1503


(-1.4)

(-42.0)

(-43.4)

SPR-1504


(-1.4)

(-25.5)

(-26.9)

SPR-1505


(-1.4)

(-10.5)

(-11.9)

(0.3)

PAGE TOTAL

0

0.0

0.0

0.0

0.9

0.0

0.0

0.0

0.0

0.0

0.0

-1.0

0.0

0.0

0.1

GENERAL TOTAL

9455

-4202.4

-4488.8

123.4

-30.0

27.4

0.0

10.0

0.1

126.2

-283.7

-21.8

0.0

0.0

48.4

NOTES

_ _ _ __ RA| D __| N I ||___ (

S-015-1223-513-1.xls

7 2-20007 FEABR0273-M



10

APPROVED BY

MOTOR/LOAD RATING:


MECH. RUNNING LOAD:

MOTOR SHAFT POWER




REV



PETROVIETNAM

LOCATION

DUNG QUAT

PLANT CAPACITY

VIETNAM

SECTION No.

015 RFCC

CASE

UNIT

ITEM No.

DESCRIPTION


SLURRY SEPARATOR

X-1505


MOTOR LOAD/ RATING


9455

-4202.4

-4488.8

-230.0

-230.0


0.55

-0.40

-0.44

X-1507


491

-379.0

-379.0

88

(-53)

(-53)

(-270.0)

(-300.0)

X-1509

Doc. type

Code

Serial N°

Rev. index

8474L 015

CN

00 03

513

1

REVISION

P-1520

X-1508

Project N° - Unit

DESOX UNIT(FUTURE)


HP STM

MP STM

LP STM

HP COND

123.4

-30.0

27.4

0.0

DATE

SHEET


8

OF


LP BFW

COLD BFW

DW T/h DEMIN. WATER

LOSSES T/h

HP BFW

0.1

-283.7

-21.8

0.0

0.0

48.4

10.0

126.2

BFW T/h

-0.3

REMARKS



P-1502 A


0.55

-0.40

-0.44

P-1502 B


0.55

(-0.40)

(-0.44)

X-1510


6.05

-4.36

-4.84

X-1551


P-1557

ANTI-FOAMING PUMP

0.55

(-0.40)

(-0.44)

P-1558

ANTI-FOAMING PUMP

0.55

(-0.40)

(-0.44)

-3.3

EJ-1501


SV-1501


4.0

-3.0

SV-1502


4.0

-3.0

-3.3

SV-1503


4.0

-3.0

-3.3

SV-1504


4.0

-3.0

-3.3

PV-1501

PLUG VALVE

4.0

-3.0

-3.3

---

OIL MIST GENERATOR

3.0

-3.0

-3.0

---

STEAM TRACE

(0.9)

(-0.9)

0.1

-0.1

-2.0

2.0

PAGE TOTAL

611

-631.9

-634.1

0.0

0.0

-2.4

0.0

0.0

2.0

0.0

0.0

0.0

0.0

0.0

0.4


10066

-4834.3

-5123.0

123.4

-30.0

25.0

0.0

10.0

2.1

126.2

-283.7

-21.8

0.0

0.0

48.8


10066

-5104.3

-5423.0

123.4

-30.0

25.0

0.0

10.0

2.1

126.2

-283.7

-21.8

0.0

0.0

48.8

NOTES

_ _ _ __ RA| D __| N I ||___ (

S-015-1223-513-1.xls

7 2-20007 FEABR0273-M



10

APPROVED BY

MOTOR/LOAD RATING:


MECH. RUNNING LOAD:

MOTOR SHAFT POWER




REV



CLIENT

PETROVIETNAM

LOCATION

DUNG QUAT

PLANT CAPACITY

VIETNAM

SECTION No.

015 RFCC

CASE

UNIT

ITEM No.

Project N° - Unit

Doc. type

Code

Serial N°

Rev. index

8474L 015

CN

00 03

513

1

REVISION

COOLING WATER

DESCRIPTION

ΔT ºC

m3/h

E-1518


6.0

-19

E-1520 A-H


8.0

-1786

E-1531

SURFACE CONDENSER

E-1532

BLOWDOWN COOLER

13.0

-15

E-1533

BLOWDOWN COOLER

15.0

-24

E-1552 A/B


8.0

-245

E-1554 A-D

STRIPPER CONDENSER

6.0

-863

E-1559

GASOLINE COOLER

6.0

-156

E-1561 A/B


12.0

-1319

E-1562

LPG COOLER

6.0

-54

E-1564

LEAN OIL COOLER

6.0

-182

E-1565

FUEL GAS COOLER

6.0

-16

E-1566

LEAN AMINE COOLER

6.0

-72

E-1567

TURBINE CONDENSER

69,700 BPSD Mixed Crude Max Gasoline - Normal Case SEA WATER ΔT ºC

m3/h

8.8

-7285

8.8

-2300

FRESH WATER T/h

DATE

SHEET


9


NITROGEN Nm3/h

S-015-1223-513-1.xls

7 2-20007 FEABR0273-M

(

CONTIN

INTERMIT

Efficiency %

FUEL FIRED MW

PUMP / COMP COOLING

-95

PAGE TOTAL

-4846

-9585

0

0

0

0

0

0

0.0

0.0

0.0

GENERAL TOTAL

-4846

-9585

0

0

0

0

0

0

0.0

0.0

0.0



10


NOTES

_ _ _ __ RA| D __| N I ||___

OF

APPROVED BY


REMARKS

REV



CLIENT

PETROVIETNAM

LOCATION

DUNG QUAT

PLANT CAPACITY

VIETNAM

SECTION No.

015 RFCC

CASE

UNIT

ITEM No.

Doc. type

Code

Serial N°

Rev. index

8474L 015

CN

00 03

513

1

REVISION

DESCRIPTION


m3/h -4846


69,700 BPSD Mixed Crude Max Gasoline - Normal Case SEA WATER ΔT ºC

m3/h

FRESH WATER T/h

DATE

SHEET

WRITTEN BY 10

CHECKED BY


H-1502


H-1503

COB/WHB PACKAGE


FURNACES & BOILERS

INTERMIT

DUTY MW

X-1507 X-1504

X-1502


X-1503


C-1501

AIR BLOWER

-22

-3

-50

(-125)


-26

-8

(-85)

SLURRY SEPARATOR

-1

OIL MIST GENERATOR

-165 -3

-60

(-40)

(-3)

(-60)

(-40)

GLAND CONDENSER

-76

OIL COOLER

-32 -6

MAIN OIL COOLER

6.0

-60

GLAND CONDENSER

6.0

-50

PV-1501

PLUG VALVE

SV-1501


SV-1502


SV-1504


-134


-4230

REV

(-280)

-611 -84 -36

(2)

1

(-2320) -340

-160

(-560)

PAGE TOTAL

-221

0

0

-5658

-118

0

-351

0

0.0

0.0

-63.6

GENERAL TOTAL

-5067

-9585

0

-5658

-118

0

-351

0

0.0

0.0

-63.6

MISCELLANEOUS USERS

-13.7



REMARKS

-49.9

-71


7 2-20007 FEABR0273-M

FUEL FIRED MW

(1) 15.0

WET GAS COMPRESSOR

S-015-1223-513-1.xls

Efficiency %

(1)

-120

(

10

-9585


_ _ _ __ RA| D __| N I ||___

OF

APPROVED BY

H-1501

C-1551

Project N° - Unit



1



PETROVIETNAM

LOCATION

DUNG QUAT

PLANT CAPACITY

VIETNAM

SECTION No.

015 RFCC

CASE

UNIT



7 2-20007 FEABR0273-M

Code

Serial N°

Rev. index

CN

00 03

514

1

Op. Center JOB No.

0-3952-20-0000

Op. Center Doc. No.

S-015-1223-514

FEED Doc. No.

A

0

1

23-MAY-06

01-FEB-07

23-FEB-07

WRITTEN BY

T. Tsuchiya

T. Tsuchiya

T. Tsuchiya

Mixed Crude Max Distillate

CHECKED BY

M. Okada

M. Okada

M. Okada

- Normal Case

APPROVED BY

M. Okada

M. Okada

M. Okada

DESCRIPTION

Issue for Review

For Construction

For Construction

2,4,10

Mixed Crude MD - Normal

S-015-1223-514-1.xls

Doc. type

8474L 015

DATE

GENERAL NOTES:

_ _ _ __ RA| D __| N I ||___

X

Project N° - Unit

6960-015-DS-0711

SHEET

1

OF

10



PETROVIETNAM

LOCATION

DUNG QUAT

PLANT CAPACITY

VIETNAM

SECTION No.

015 RFCC

CASE

UNIT

ITEM No.

DESCRIPTION

MOTOR LOAD/ RATING


-0.3

-0.3

-443.0

-457.0

HP STM

MP STM

214.8

0.5


C-1502 B


(-13.8)


-1.1

1230


3

-3.0

-3.0

P-1529 A


55

-39.0

-43.3

P-1529 B


55

(-39.0)

(-43.3)

E-1531


-18.5

-20.6

15

-15.0

-15.0


-

TURNING GEAR MOTOR

C-1551

WET GAS COMPRESSOR

-1.5

-1.5


18.5

-13.9

-14.8

P-1559 B


18.5

(-13.9)

(-14.8)

E-1567


-16.0

-17.8


-


Serial N°

Rev. index

8474L 015

CN

00 03

514

1

HP COND

DATE

SHEET


2

OF

-77.9

-32.2


BFW T/h HP BFW

LP BFW

-221.0

-0.5

COLD BFW

DW T/h DEMIN. WATER

LOSSES T/h

REMARKS

1.1

-0.3

1

10.0 -0.1

0.1

77.9

0.3

32.2

0.4

(2.6)

-0.4

(-2.1)

(2.1)


-


0.5

-0.5

D-1527

LP BLOWDOWN DRUM

0.5

-0.5

T-1503

LCO STRIPPER

-3.0

3.0

T-1504

HCO STRIPPER

-0.5

0.5

-34.7

34.7

PAGE TOTAL

1462

-550.2

-573.3

103.6

-44.9

-2.6

0.0

10.0

0.1

110.1

-221.0

-0.5

0.0

0.0

45.2

GENERAL TOTAL

1462

-550.2

-573.3

103.6

-44.9

-2.6

0.0

10.0

0.1

110.1

-221.0

-0.5

0.0

0.0

45.2

NOTES

(

S-015-1223-514-1.xls

7 2-20007 FEABR0273-M



REV

6.2

D-1501

_ _ _ __ RA| D __| N I ||___

10

APPROVED BY

(13.8)

(-2.6)

P-1559 A

-

LP STM

-10.0

E-1534

-

Code

Included in H-1503

C-1501

-

69,700 BPSD Mixed Crude Max Distillate - Normal Case STEAM T/h

H-1503

ECONOMIZER

Doc. type

REVISION

C-1502 A

E-1525

Project N° - Unit

MOTOR/LOAD RATING:


MECH. RUNNING LOAD:

MOTOR SHAFT POWER






PETROVIETNAM

LOCATION

DUNG QUAT

PLANT CAPACITY

VIETNAM

SECTION No.

015 RFCC

CASE

UNIT

ITEM No.

DESCRIPTION

Project N° - Unit

Doc. type

Code

Serial N°

Rev. index

8474L 015

CN

00 03

514

1

REVISION

MOTOR LOAD/ RATING



1462

-550.2

-573.3

P-1501 A

FEED PUMP

600

-476.0

-500.5

P-1501 B

FEED PUMP

600

(-476.0)

(-500.5)

P-1504 A

SLURRY PRODUCT PUMP

55

-42.7

-45.1

P-1504 B

SLURRY PRODUCT PUMP

55

(-42.7)

(-45.1)

P-1505 A

BACKFLUSH OIL PUMP

22

-15.0

-16.5

P-1505 B

BACKFLUSH OIL PUMP

22

(-15.0)

(-16.5)

P-1506 A


11

-7.4

-8.4

P-1506 B


11

(-7.4)

(-8.4)

P-1507 A

HCO RECYCLE PUMP

150

-128.0

-142.2

P-1507 B

HCO RECYCLE PUMP

150

(-128.0)

(-142.2)


HP STM

MP STM

LP STM

HP COND

103.6

-44.9

-2.6

0.0

DATE

SHEET

WRITTEN BY 3

CHECKED BY

OF


LP BFW

COLD BFW

DW T/h DEMIN. WATER

LOSSES T/h

HP BFW

10.0

0.1

-221.0

-0.5

0.0

0.0

45.2

110.1

BFW T/h

P-1508 A

HCO PUMPAROUND PUMP

220

-179.4

-188.4

P-1508 B

HCO PUMPAROUND PUMP

220

(-179.4)

(-188.4)

P-1509 A

HCO PRODUCT PUMP

15

-9.1

-10.1

P-1509 B

HCO PRODUCT PUMP

15

(-9.1)

(-10.1)

P-1510 A

LCO PUMPAROUND PUMP

335

-303.0

-316.0

P-1510 B

LCO PUMPAROUND PUMP

335

(-303.0)

(-316.0)

P-1511 A

LCO STRIPPER PUMP

90

-73.4

-76.9

P-1511 B

LCO STRIPPER PUMP

90

(-73.4)

(-76.9)

P-1512 A

MTC RECYCLE PUMP

75

0.0

0.0

P-1512 B

MTC RECYCLE PUMP

75

(0.0)

(0.0)

P-1513 A

LEAN OIL PUMP

75

-55.0

-58.1

P-1513 B

LEAN OIL PUMP

75

(-55.0)

(-58.1)

P-1514 A


225

-203.0

-213.9

P-1514 B


225

(-203.0)

(-213.9)

PAGE TOTAL

3746

-1492.0

-1576.1

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

GENERAL TOTAL

5208

-2042.2

-2149.4

103.6

-44.9

-2.6

0.0

10.0

0.1

110.1

-221.0

-0.5

0.0

0.0

45.2

REMARKS

NOTES

_ _ _ __ RA| D __| N I ||___ (

S-015-1223-514-1.xls

7 2-20007 FEABR0273-M



10

APPROVED BY

MOTOR/LOAD RATING:


MECH. RUNNING LOAD:

MOTOR SHAFT POWER




REV



PETROVIETNAM

LOCATION

DUNG QUAT

PLANT CAPACITY

VIETNAM

SECTION No.

015 RFCC

CASE

UNIT

ITEM No.

DESCRIPTION

Project N° - Unit

Doc. type

Code

Serial N°

Rev. index

8474L 015

CN

00 03

514

1

REVISION

MOTOR LOAD/ RATING



5208

-2042.2

-2149.4

P-1515 A


55

-39.4

-41.6

P-1515 B


55

(-39.4)

(-41.6)

P-1516 A


110

-96.0

-101.3 (-101.3)


HP STM

MP STM

LP STM

HP COND

103.6

-44.9

-2.6

0.0

DATE

SHEET


4

OF


LP BFW

COLD BFW

DW T/h DEMIN. WATER

LOSSES T/h

HP BFW

0.1

-221.0

-0.5

0.0

0.0

45.2

10.0

110.1

BFW T/h

P-1516 B


110

(-96.0)

P-1517 A


30

-25.5

-27.6

P-1517 B


30

(-25.5)

(-27.6)

P-1518 A


250

-206.0

-228.9

P-1518 B


250

(-206.0)

(-228.9)

P-1519 A


-10.3

P-1519 B


-10.3

10.3

P-1519 C


(-10.3)

(10.3)


-0.8

P-1521 A


-3.7

P-1521 B


110

(-80.9)

P-1522 A


30

-18.4

-19.9

P-1522 B


30

(-18.4)

(-19.9)

P-1526 A

LIGHT SLOPS PUMP

37

-26.1

-27.9

P-1526 B

LIGHT SLOPS PUMP

37

(-26.1)

(-27.9)

P-1527 A

HEAVY SLOPS PUMP

37

-27.9

-29.8

P-1527 B

HEAVY SLOPS PUMP

37

(-27.9)

(-29.8)

P-1528 A

TEMPERED WATER PUMP

15

-10.5

-11.7

P-1528 B

TEMPERED WATER PUMP

15

(-10.5)

(-11.7)

PAGE TOTAL

1238

-449.8

-488.7

-25.1

0.0

24.3

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.8

GENERAL TOTAL

6446

-2492.0

-2638.1

78.5

-44.9

21.7

0.0

10.0

0.1

110.1

-221.0

-0.5

0.0

0.0

46.0

REMARKS

(

S-015-1223-514-1.xls

7 2-20007 FEABR0273-M


0.8 3.7

(-84.4)


REV

10.3

NOTES

_ _ _ __ RA| D __| N I ||___

10

APPROVED BY

MOTOR/LOAD RATING:


MECH. RUNNING LOAD:

MOTOR SHAFT POWER




1



PETROVIETNAM

LOCATION

DUNG QUAT

PLANT CAPACITY

VIETNAM

SECTION No.

015 RFCC

CASE

UNIT

ITEM No.

DESCRIPTION

Project N° - Unit

Doc. type

Code

Serial N°

Rev. index

8474L 015

CN

00 03

514

1

REVISION

MOTOR LOAD/ RATING



HP STM

MP STM

LP STM

HP COND

78.5

-44.9

21.7

0.0


6446

-2492.0

-2638.1

P-1551 A


150

-134.0

-142.3

P-1551 B


150

(-134.0)

(-142.3)

P-1552 A

KO DRUM LIQUID PUMP

4

-1.2

-1.4

P-1552 B

KO DRUM LIQUID PUMP

4

(-1.2)

(-1.4)

P-1553 A

STRIPPER FEED PUMP

132

-112.0

-117.9

P-1553 B

STRIPPER FEED PUMP

132

(-112.0)

(-117.9)

P-1554 A


55

-44.0

-47.7

P-1554 B


55

(-44.0)

(-47.7)

DATE

SHEET


5

OF


0.1

110.1

LP BFW

COLD BFW

DW T/h DEMIN. WATER

LOSSES T/h

HP BFW

BFW T/h

-221.0

-0.5

0.0

0.0

46.0

P-1556 A


225

-185.0

-194.9

P-1556 B


225

(-185.0)

(-194.9)

P-1560 A


22

(-16.5)

(-18.1)

P-1560 B


22

(-16.5)

(-18.1)

P-1561


7.5

(-4.9)

(-5.4)

P-1562


7.5

(-4.9)

(-5.4)

P-1563


7.5

(-4.9)

(-5.4)

P-1564


15

(-10.8)

(-12.0)

PAGE TOTAL

1214

-476.2

-504.2

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

GENERAL TOTAL

7660

-2968.2

-3142.3

78.5

-44.9

21.7

0.0

10.0

0.1

110.1

-221.0

-0.5

0.0

0.0

46.0

REMARKS

NOTES

_ _ _ __ RA| D __| N I ||___ (

S-015-1223-514-1.xls

7 2-20007 FEABR0273-M



10

APPROVED BY

MOTOR/LOAD RATING:


MECH. RUNNING LOAD:

MOTOR SHAFT POWER




REV



PETROVIETNAM

LOCATION

DUNG QUAT

PLANT CAPACITY

VIETNAM

SECTION No.

015 RFCC

CASE

UNIT

ITEM No.

DESCRIPTION

Project N° - Unit

Doc. type

Code

Serial N°

Rev. index

8474L 015

CN

00 03

514

1

REVISION

MOTOR LOAD/ RATING



7660

-2968.2

-3142.3

E-1514

LCO AIR COOLER

120

-97.6

-106.2

E-1517


33

-20.4

-23.1

E-1519


960

-736.0

-800.9

E-1521


120

-99.6

-108.4

E-1530


22.5

-15.0

-17.8

E-1551


240

-190.4

-207.2


HP STM

MP STM

LP STM

HP COND

78.5

-44.9

21.7

0.0

DATE

SHEET


6

OF


0.1

110.1

LP BFW

COLD BFW

DW T/h DEMIN. WATER

LOSSES T/h

HP BFW -221.0

-0.5

0.0

0.0

46.0

BFW T/h

E-1553

HP CONDENSER

180

-134.4

-146.2

E-1558

GASOLINE AIR COOLER

120

-92.8

-101.0

E-1503


35.0

-36.1

1.1

E-1504


21.4

-22.1

0.7

E-1505


E-1506


E-1508


E-1510


2.8

E-1513


8.5

E-1518


16.1

1.2

14.4

-16.6

0.5

-1.2

0.0

-14.9

0.5

-2.8

0.0

-8.8

0.3

PAGE TOTAL

1796

-1386.2

-1510.8

56.4

30.5

12.5

0.0

0.0

0.0

0.0

-58.2

-44.3

0.0

0.0

3.1

GENERAL TOTAL

9455

-4354.4

-4653.1

134.9

-14.4

34.2

0.0

10.0

0.1

110.1

-279.2

-44.8

0.0

0.0

49.1

REMARKS

NOTES

_ _ _ __ RA| D __| N I ||___ (

S-015-1223-514-1.xls

7 2-20007 FEABR0273-M



10

APPROVED BY

MOTOR/LOAD RATING:


MECH. RUNNING LOAD:

MOTOR SHAFT POWER




REV



PETROVIETNAM

LOCATION

DUNG QUAT

PLANT CAPACITY

VIETNAM

SECTION No.

015 RFCC

CASE

UNIT

ITEM No.

DESCRIPTION


Project N° - Unit

Doc. type

Code

Serial N°

Rev. index

8474L 015

CN

00 03

514

1

REVISION




HP STM

MP STM

LP STM

HP COND

-4653.1

134.9

-14.4

34.2

0.0

-4354.4

DATE

SHEET


7

OF


LP BFW

COLD BFW

DW T/h DEMIN. WATER

LOSSES T/h

HP BFW

0.1

-279.2

-44.8

0.0

0.0

49.1

10.0

110.1

BFW T/h

REMARKS


E-1522


(-17.1)

E-1523


6.8

E-1524


E-1532

BLOWDOWN COOLER

E-1552 A/B


E-1554 A-D

STRIPPER CONDENSER

E-1559

GASOLINE COOLER

E-1561 A/B


E-1562

LPG COOLER

E-1564

LEAN OIL COOLER

(17.1)


-7.0

0.0

0.0

E-1565

FUEL GAS COOLER

E-1566

LEAN AMINE COOLER

I-1501

FEED INJECTOR

Included in D-1501

I-1502

MTC INJECTOR

Included in D-1501

I-1503


Included in D-1501

I-1504


SPR-1501


(-0.3)


SPR-1502


(-0.3)

SPR-1503


(-1.5)

(-31.1)

(-32.6)

SPR-1504


(-1.5)

(-19.2)

(-20.7)

SPR-1505


(-1.5)

(-9.7)

(-11.2)

(0.3)

PAGE TOTAL

0

0.0

0.0

0.0

6.8

0.0

0.0

0.0

0.0

0.0

0.0

-7.0

0.0

0.0

0.2

GENERAL TOTAL

9455

-4354.4

-4653.1

134.9

-7.6

34.2

0.0

10.0

0.1

110.1

-279.2

-51.8

0.0

0.0

49.3

NOTES

_ _ _ __ RA| D __| N I ||___ (

S-015-1223-514-1.xls

7 2-20007 FEABR0273-M



10

APPROVED BY

MOTOR/LOAD RATING:


MECH. RUNNING LOAD:

MOTOR SHAFT POWER




REV



PETROVIETNAM

LOCATION

DUNG QUAT

PLANT CAPACITY

VIETNAM

SECTION No.

015 RFCC

CASE

UNIT

ITEM No.

DESCRIPTION


SLURRY SEPARATOR

X-1505


MOTOR LOAD/ RATING


9455

-4354.4

-4653.1

-230.0

-230.0


0.55

-0.40

-0.44

X-1507


491

-379.0

-379.0

88

(-53)

(-53)

(-270.0)

(-300.0)

X-1509

Doc. type

Code

Serial N°

Rev. index

8474L 015

CN

00 03

514

1

REVISION

P-1520

X-1508

Project N° - Unit

DESOX UNIT(FUTURE)


HP STM

MP STM

LP STM

HP COND

134.9

-7.6

34.2

0.0

DATE

SHEET


8

OF


LP BFW

COLD BFW

DW T/h DEMIN. WATER

LOSSES T/h

HP BFW

0.1

-279.2

-51.8

0.0

0.0

49.3

10.0

110.1

BFW T/h

-0.3

REMARKS



P-1502 A


0.55

0.00

0.00

P-1502 B


0.55

(0.00)

(0.00)

X-1510


6.05

-4.36

-4.84

X-1551


P-1557

ANTI-FOAMING PUMP

0.55

(-0.40)

(-0.44)

P-1558

ANTI-FOAMING PUMP

0.55

(-0.40)

(-0.44)

-3.3

EJ-1501


SV-1501


4.0

-3.0

SV-1502


4.0

-3.0

-3.3

SV-1503


4.0

-3.0

-3.3

SV-1504


4.0

-3.0

-3.3

PV-1501

PLUG VALVE

4.0

-3.0

-3.3

---

OIL MIST GENERATOR

3.0

-3.0

-3.0

---

STEAM TRACE

(0.9)

(-0.9)

0.1

-0.1

-2.0

2.0

PAGE TOTAL

611

-631.5

-633.7

0.0

0.0

-2.4

0.0

0.0

2.0

0.0

0.0

0.0

0.0

0.0

0.4


10066

-4985.9

-5286.7

134.9

-7.6

31.8

0.0

10.0

2.1

110.1

-279.2

-51.8

0.0

0.0

49.7


10066

-5255.9

-5586.7

134.9

-7.6

31.8

0.0

10.0

2.1

110.1

-279.2

-51.8

0.0

0.0

49.7

NOTES

_ _ _ __ RA| D __| N I ||___ (

S-015-1223-514-1.xls

7 2-20007 FEABR0273-M



10

APPROVED BY

MOTOR/LOAD RATING:


MECH. RUNNING LOAD:

MOTOR SHAFT POWER




REV



CLIENT

PETROVIETNAM

LOCATION

DUNG QUAT

PLANT CAPACITY

VIETNAM

SECTION No.

015 RFCC

CASE

UNIT

ITEM No.

Project N° - Unit

Doc. type

Code

Serial N°

Rev. index

8474L 015

CN

00 03

514

1

REVISION

COOLING WATER

DESCRIPTION

ΔT ºC

m3/h

E-1518


6.0

-19

E-1520 A-H


8.0

-1675

E-1531

SURFACE CONDENSER

E-1532

BLOWDOWN COOLER

13.0

-15

E-1533

BLOWDOWN COOLER

15.0

-24

E-1552 A/B


8.0

-219

E-1554 A-D

STRIPPER CONDENSER

6.0

-684

E-1559

GASOLINE COOLER

6.0

-134

E-1561 A/B


12.0

-1154

E-1562

LPG COOLER

6.0

-43

E-1564

LEAN OIL COOLER

6.0

-195

E-1565

FUEL GAS COOLER

6.0

-8

E-1566

LEAN AMINE COOLER

6.0

-56

E-1567

TURBINE CONDENSER

69,700 BPSD Mixed Crude Max Distillate - Normal Case SEA WATER ΔT ºC

m3/h

8.8

-7285

8.8

-2300

FRESH WATER T/h

DATE

SHEET


9


NITROGEN Nm3/h

S-015-1223-514-1.xls

7 2-20007 FEABR0273-M

(

CONTIN

INTERMIT

Efficiency %

FUEL FIRED MW

PUMP / COMP COOLING

-95

PAGE TOTAL

-4321

-9585

0

0

0

0

0

0

0.0

0.0

0.0

GENERAL TOTAL

-4321

-9585

0

0

0

0

0

0

0.0

0.0

0.0



10


NOTES

_ _ _ __ RA| D __| N I ||___

OF

APPROVED BY


REMARKS

REV



CLIENT

PETROVIETNAM

LOCATION

DUNG QUAT

PLANT CAPACITY

VIETNAM

SECTION No.

015 RFCC

CASE

UNIT

ITEM No.

Doc. type

Code

Serial N°

Rev. index

8474L 015

CN

00 03

514

1

REVISION

DESCRIPTION


m3/h -4321


69,700 BPSD Mixed Crude Max Distillate - Normal Case SEA WATER ΔT ºC

m3/h

FRESH WATER T/h

DATE

SHEET

WRITTEN BY 10

CHECKED BY


H-1502


H-1503

COB/WHB PACKAGE


FURNACES & BOILERS

INTERMIT

DUTY MW

X-1507 X-1504

X-1502


X-1503


C-1501

AIR BLOWER

-22

-3

-50

(-125)


-26

-8

(-85)

SLURRY SEPARATOR

-1

OIL MIST GENERATOR

-165 -3

-60

(-40)

(-3)

(-60)

(-40)

GLAND CONDENSER

-76

OIL COOLER

-32 -6

MAIN OIL COOLER

6.0

-60

GLAND CONDENSER

6.0

-50

PV-1501

PLUG VALVE

SV-1501


SV-1502


SV-1504


-134


-4230

REV

(-280)

-611 -84 -36

(2)

1

(-2320) -340

-160

(-560)

PAGE TOTAL

-221

0

0

-5658

-118

0

-351

0

0.0

0.0

-92.6

GENERAL TOTAL

-4542

-9585

0

-5658

-118

0

-351

0

0.0

0.0

-92.6

MISCELLANEOUS USERS

-13.7



REMARKS

-78.9

-71


7 2-20007 FEABR0273-M

FUEL FIRED MW

(1) 15.0

WET GAS COMPRESSOR

S-015-1223-514-1.xls

Efficiency %

(1)

-120

(

10

-9585


_ _ _ __ RA| D __| N I ||___

OF

APPROVED BY

H-1501

C-1551

Project N° - Unit



1



PETROVIETNAM

LOCATION

DUNG QUAT

PLANT CAPACITY

VIETNAM

SECTION No.

015 RFCC

CASE

UNIT



7 2-20007 FEABR0273-M

Code

Serial N°

Rev. index

CN

00 03

521

1

Op. Center JOB No.

0-3952-20-0000

Op. Center Doc. No.

S-015-1223-521

FEED Doc. No.

A

0

1

23-MAY-06

01-FEB-07

23-FEB-07

WRITTEN BY

T. Tsuchiya

T. Tsuchiya

T. Tsuchiya

Bach Ho Max Gasoline

CHECKED BY

M. Okada

M. Okada

M. Okada

- Design Case

APPROVED BY

M. Okada

M. Okada

M. Okada

DESCRIPTION

Issue for Review

For Construction

For Construction

2,4,10

Bach Ho MG - Design

S-015-1223-521-1.xls

Doc. type

8474L 015

DATE

GENERAL NOTES:

_ _ _ __ RA| D __| N I ||___

X

Project N° - Unit

6960-015-DS-0711

SHEET

1

OF

10



PETROVIETNAM

LOCATION

DUNG QUAT

PLANT CAPACITY

VIETNAM

SECTION No.

015 RFCC

CASE

UNIT

ITEM No.

DESCRIPTION

MOTOR LOAD/ RATING


-0.3

-0.3

-585.0

-597.0

HP STM

MP STM

219.9

0.5


C-1502 B


(-18.0)


-1.4

1230


3

-3.0

-3.0

P-1529 A


55

-39.0

-43.3

P-1529 B


55

(-39.0)

(-43.3)

E-1531


-18.5

-20.6

15

-15.0

-15.0


-

TURNING GEAR MOTOR

C-1551

WET GAS COMPRESSOR

-1.5

-1.5


18.5

-13.9

-14.8

P-1559 B


18.5

(-13.9)

(-14.8)

E-1567


-16.0

-17.8


-


Serial N°

Rev. index

8474L 015

CN

00 03

521

1

HP COND

DATE

SHEET


2

OF

-68.7

-30.4


BFW T/h HP BFW

LP BFW

-226.1

-0.5

COLD BFW

DW T/h DEMIN. WATER

LOSSES T/h

REMARKS

1.4

-0.3

1

21.1 -0.1

0.1

68.7

0.3

30.4

0.4

(2.6)

-0.4

(-2.1)

(2.1)


-


0.5

-0.5

D-1527

LP BLOWDOWN DRUM

0.1

-0.1

T-1503

LCO STRIPPER

-3.0

3.0

T-1504

HCO STRIPPER

-0.5

0.5

-34.7

34.7

PAGE TOTAL

1462

-692.2

-713.3

119.4

-56.0

-3.0

0.0

21.1

0.1

99.1

-226.1

-0.5

0.0

0.0

45.9

GENERAL TOTAL

1462

-692.2

-713.3

119.4

-56.0

-3.0

0.0

21.1

0.1

99.1

-226.1

-0.5

0.0

0.0

45.9

NOTES

(

S-015-1223-521-1.xls

7 2-20007 FEABR0273-M



REV

6.2

D-1501

_ _ _ __ RA| D __| N I ||___

10

APPROVED BY

(18.0)

(-2.6)

P-1559 A

-

LP STM

-21.1

E-1534

-

Code

Included in H-1503

C-1501

-

69,700 BPSD Bach Ho Max Gasoline - Design Case STEAM T/h

H-1503

ECONOMIZER

Doc. type

REVISION

C-1502 A

E-1525

Project N° - Unit

MOTOR/LOAD RATING:


MECH. RUNNING LOAD:

MOTOR SHAFT POWER






PETROVIETNAM

LOCATION

DUNG QUAT

PLANT CAPACITY

VIETNAM

SECTION No.

015 RFCC

CASE

UNIT

ITEM No.

DESCRIPTION

Project N° - Unit

Doc. type

Code

Serial N°

Rev. index

8474L 015

CN

00 03

521

1

REVISION

MOTOR LOAD/ RATING



1462

-692.2

-713.3

P-1501 A

FEED PUMP

600

-476.0

-500.5

P-1501 B

FEED PUMP

600

(-476.0)

(-500.5)

P-1504 A

SLURRY PRODUCT PUMP

55

-42.7

-45.1

P-1504 B

SLURRY PRODUCT PUMP

55

(-42.7)

(-45.1)

P-1505 A

BACKFLUSH OIL PUMP

22

-15.0

-16.5

P-1505 B

BACKFLUSH OIL PUMP

22

(-15.0)

(-16.5)

P-1506 A


11

-7.4

-8.4

P-1506 B


11

(-7.4)

(-8.4)

P-1507 A

HCO RECYCLE PUMP

150

0.0

0.0

P-1507 B

HCO RECYCLE PUMP

150

(0.0)

(0.0)


HP STM

MP STM

LP STM

HP COND

119.4

-56.0

-3.0

0.0

DATE

SHEET

WRITTEN BY 3

CHECKED BY

OF


LP BFW

COLD BFW

DW T/h DEMIN. WATER

LOSSES T/h

HP BFW

21.1

0.1

-226.1

-0.5

0.0

0.0

45.9

99.1

BFW T/h

P-1508 A

HCO PUMPAROUND PUMP

220

-179.4

-188.4

P-1508 B

HCO PUMPAROUND PUMP

220

(-179.4)

(-188.4)

P-1509 A

HCO PRODUCT PUMP

15

-9.1

-10.1

P-1509 B

HCO PRODUCT PUMP

15

(-9.1)

(-10.1)

P-1510 A

LCO PUMPAROUND PUMP

335

-303.0

-316.0

P-1510 B

LCO PUMPAROUND PUMP

335

(-303.0)

(-316.0)

P-1511 A

LCO STRIPPER PUMP

90

-73.4

-76.9

P-1511 B

LCO STRIPPER PUMP

90

(-73.4)

(-76.9)

P-1512 A

MTC RECYCLE PUMP

75

0.0

0.0

P-1512 B

MTC RECYCLE PUMP

75

(0.0)

(0.0)

P-1513 A

LEAN OIL PUMP

75

-55.0

-58.1

P-1513 B

LEAN OIL PUMP

75

(-55.0)

(-58.1)

P-1514 A


225

-203.0

-213.9

P-1514 B


225

(-203.0)

(-213.9)

PAGE TOTAL

3746

-1364.0

-1433.9

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

GENERAL TOTAL

5208

-2056.2

-2147.2

119.4

-56.0

-3.0

0.0

21.1

0.1

99.1

-226.1

-0.5

0.0

0.0

45.9

REMARKS

NOTES

_ _ _ __ RA| D __| N I ||___ (

S-015-1223-521-1.xls

7 2-20007 FEABR0273-M



10

APPROVED BY

MOTOR/LOAD RATING:


MECH. RUNNING LOAD:

MOTOR SHAFT POWER




REV



PETROVIETNAM

LOCATION

DUNG QUAT

PLANT CAPACITY

VIETNAM

SECTION No.

015 RFCC

CASE

UNIT

ITEM No.

DESCRIPTION

Project N° - Unit

Doc. type

Code

Serial N°

Rev. index

8474L 015

CN

00 03

521

1

REVISION

MOTOR LOAD/ RATING



5208

-2056.2

-2147.2

P-1515 A


55

-39.4

-41.6

P-1515 B


55

(-39.4)

(-41.6)

P-1516 A


110

-96.0

-101.3 (-101.3)


HP STM

MP STM

LP STM

HP COND

119.4

-56.0

-3.0

0.0

DATE

SHEET


4

OF


LP BFW

COLD BFW

DW T/h DEMIN. WATER

LOSSES T/h

HP BFW

0.1

-226.1

-0.5

0.0

0.0

45.9

21.1

99.1

BFW T/h

P-1516 B


110

(-96.0)

P-1517 A


30

-25.5

-27.6

P-1517 B


30

(-25.5)

(-27.6)

P-1518 A


250

-206.0

-228.9

P-1518 B


250

(-206.0)

(-228.9)

P-1519 A


-10.3

P-1519 B


-10.3

10.3

P-1519 C


(-10.3)

(10.3)


-0.8

P-1521 A


-3.7

P-1521 B


110

(-80.9)

P-1522 A


30

-18.4

-19.9

P-1522 B


30

(-18.4)

(-19.9)

P-1526 A

LIGHT SLOPS PUMP

37

-26.1

-27.9

P-1526 B

LIGHT SLOPS PUMP

37

(-26.1)

(-27.9)

P-1527 A

HEAVY SLOPS PUMP

37

-27.9

-29.8

P-1527 B

HEAVY SLOPS PUMP

37

(-27.9)

(-29.8)

P-1528 A

TEMPERED WATER PUMP

15

-10.5

-11.7

P-1528 B

TEMPERED WATER PUMP

15

(-10.5)

(-11.7)

PAGE TOTAL

1238

-449.8

-488.7

-25.1

0.0

24.3

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.8

GENERAL TOTAL

6446

-2506.0

-2635.8

94.3

-56.0

21.3

0.0

21.1

0.1

99.1

-226.1

-0.5

0.0

0.0

46.7

REMARKS

(

S-015-1223-521-1.xls

7 2-20007 FEABR0273-M


0.8 3.7

(-84.4)


REV

10.3

NOTES

_ _ _ __ RA| D __| N I ||___

10

APPROVED BY

MOTOR/LOAD RATING:


MECH. RUNNING LOAD:

MOTOR SHAFT POWER




1



PETROVIETNAM

LOCATION

DUNG QUAT

PLANT CAPACITY

VIETNAM

SECTION No.

015 RFCC

CASE

UNIT

ITEM No.

DESCRIPTION

Project N° - Unit

Doc. type

Code

Serial N°

Rev. index

8474L 015

CN

00 03

521

1

REVISION

MOTOR LOAD/ RATING



HP STM

MP STM

LP STM

HP COND

94.3

-56.0

21.3

0.0


6446

-2506.0

-2635.8

P-1551 A


150

-134.0

-142.3

P-1551 B


150

(-134.0)

(-142.3)

P-1552 A

KO DRUM LIQUID PUMP

4

-1.2

-1.4

P-1552 B

KO DRUM LIQUID PUMP

4

(-1.2)

(-1.4)

P-1553 A

STRIPPER FEED PUMP

132

-112.0

-117.9

P-1553 B

STRIPPER FEED PUMP

132

(-112.0)

(-117.9)

P-1554 A


55

0.0

0.0

P-1554 B


55

(0.0)

(0.0)

DATE

SHEET


5

OF


0.1

99.1

LP BFW

COLD BFW

DW T/h DEMIN. WATER

LOSSES T/h

HP BFW

BFW T/h

-226.1

-0.5

0.0

0.0

46.7

P-1556 A


225

-185.0

-194.9

P-1556 B


225

(-185.0)

(-194.9)

P-1560 A


22

(-16.5)

(-18.1)

P-1560 B


22

(-16.5)

(-18.1)

P-1561


7.5

(-4.9)

(-5.4)

P-1562


7.5

(-4.9)

(-5.4)

P-1563


7.5

(-4.9)

(-5.4)

P-1564


15

(-10.8)

(-12.0)

PAGE TOTAL

1214

-432.2

-456.5

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

GENERAL TOTAL

7660

-2938.2

-3092.3

94.3

-56.0

21.3

0.0

21.1

0.1

99.1

-226.1

-0.5

0.0

0.0

46.7

REMARKS

NOTES

_ _ _ __ RA| D __| N I ||___ (

S-015-1223-521-1.xls

7 2-20007 FEABR0273-M



10

APPROVED BY

MOTOR/LOAD RATING:


MECH. RUNNING LOAD:

MOTOR SHAFT POWER




REV



PETROVIETNAM

LOCATION

DUNG QUAT

PLANT CAPACITY

VIETNAM

SECTION No.

015 RFCC

CASE

UNIT

ITEM No.

DESCRIPTION

Project N° - Unit

Doc. type

Code

Serial N°

Rev. index

8474L 015

CN

00 03

521

1

REVISION

MOTOR LOAD/ RATING



7660

-2938.2

-3092.3

E-1514

LCO AIR COOLER

120

-97.6

-106.2

E-1517


33

-20.4

-23.1

E-1519


960

-736.0

-800.9

E-1521


120

-99.6

-108.4

E-1530


22.5

-15.0

-17.8

E-1551


240

-190.4

-207.2


HP STM

MP STM

LP STM

HP COND

94.3

-56.0

21.3

0.0

DATE

SHEET


6

OF


0.1

99.1

LP BFW

COLD BFW

DW T/h DEMIN. WATER

LOSSES T/h

HP BFW -226.1

-0.5

0.0

0.0

46.7

BFW T/h

E-1553

HP CONDENSER

180

-134.4

-146.2

E-1558

GASOLINE AIR COOLER

120

-92.8

-101.0

E-1503


0.0

0.0

E-1504


10.3

-10.6

E-1505


E-1506


E-1508


E-1510

8.0

0.2

1.3

-1.4

0.1

0.0

0.0


2.1

-2.2

0.1

E-1513


2.2

-2.2

0.0

E-1518


0.0

REMARKS

0.3

-8.2

PAGE TOTAL

1796

-1386.2

-1510.8

10.3

8.0

5.6

0.0

0.0

0.0

0.0

-10.6

-14.0

0.0

0.0

0.7

GENERAL TOTAL

9455

-4324.4

-4603.1

104.6

-48.0

26.9

0.0

21.1

0.1

99.1

-236.7

-14.5

0.0

0.0

47.4

NOTES

_ _ _ __ RA| D __| N I ||___ (

S-015-1223-521-1.xls

7 2-20007 FEABR0273-M



10

APPROVED BY

MOTOR/LOAD RATING:


MECH. RUNNING LOAD:

MOTOR SHAFT POWER




REV



PETROVIETNAM

LOCATION

DUNG QUAT

PLANT CAPACITY

VIETNAM

SECTION No.

015 RFCC

CASE

UNIT

ITEM No.

DESCRIPTION


Project N° - Unit

Doc. type

Code

Serial N°

Rev. index

8474L 015

CN

00 03

521

1

REVISION




HP STM

MP STM

LP STM

HP COND

-4603.1

104.6

-48.0

26.9

0.0

-4324.4

DATE

SHEET


7

OF


LP BFW

COLD BFW

DW T/h DEMIN. WATER

LOSSES T/h

HP BFW

0.1

-236.7

-14.5

0.0

0.0

47.4

21.1

99.1

BFW T/h

REMARKS


E-1522


-8.7

E-1523


0.7

E-1524


E-1532

BLOWDOWN COOLER

E-1552 A/B


E-1554 A-D

STRIPPER CONDENSER

E-1559

GASOLINE COOLER

E-1561 A/B


E-1562

LPG COOLER

E-1564

LEAN OIL COOLER

8.7


-0.7

-13.5


13.5

E-1565

FUEL GAS COOLER

E-1566

LEAN AMINE COOLER

I-1501

FEED INJECTOR

Included in D-1501

I-1502

MTC INJECTOR

Included in D-1501

I-1503


Included in D-1501

I-1504


SPR-1501


(-0.3)


SPR-1502


(-0.3)

SPR-1503


(-1.5)

(-25.7)

(-27.2)

SPR-1504


(-1.5)

(-15.8)

(-17.3)

SPR-1505


(-1.5)

(-18.5)

(-20.0)

(0.3)

PAGE TOTAL

0

0.0

0.0

-13.5

-8.0

0.0

13.5

8.7

0.0

0.0

0.0

-0.7

0.0

0.0

0.0

GENERAL TOTAL

9455

-4324.4

-4603.1

91.1

-56.0

26.9

13.5

29.8

0.1

99.1

-236.7

-15.2

0.0

0.0

47.4

NOTES

_ _ _ __ RA| D __| N I ||___ (

S-015-1223-521-1.xls

7 2-20007 FEABR0273-M



10

APPROVED BY

MOTOR/LOAD RATING:


MECH. RUNNING LOAD:

MOTOR SHAFT POWER




REV



PETROVIETNAM

LOCATION

DUNG QUAT

PLANT CAPACITY

VIETNAM

SECTION No.

015 RFCC

CASE

UNIT

ITEM No.

DESCRIPTION


SLURRY SEPARATOR

X-1505


MOTOR LOAD/ RATING


9455

-4324.4

-4603.1

-230.0

-230.0


0.55

-0.40

-0.44

X-1507


491

-379.0

-379.0

88

(-53)

(-53)

(-270.0)

(-300.0)

X-1509

Doc. type

Code

Serial N°

Rev. index

8474L 015

CN

00 03

521

1

REVISION

P-1520

X-1508

Project N° - Unit

DESOX UNIT(FUTURE)


HP STM

MP STM

LP STM

HP COND

91.1

-56.0

26.9

13.5

DATE

SHEET


8

OF


LP BFW

COLD BFW

DW T/h DEMIN. WATER

LOSSES T/h

HP BFW

0.1

-236.7

-15.2

0.0

0.0

47.4

29.8

99.1

BFW T/h

-0.3

REMARKS



P-1502 A


0.55

0.00

0.00

P-1502 B


0.55

(0.00)

(0.00)

X-1510


6.05

-4.36

-4.84

X-1551


P-1557

ANTI-FOAMING PUMP

0.55

(-0.40)

(-0.44)

P-1558

ANTI-FOAMING PUMP

0.55

(-0.40)

(-0.44)

-3.3

EJ-1501


SV-1501


4.0

-3.0

SV-1502


4.0

-3.0

-3.3

SV-1503


4.0

-3.0

-3.3

SV-1504


4.0

-3.0

-3.3

PV-1501

PLUG VALVE

4.0

-3.0

-3.3

---

OIL MIST GENERATOR

3.0

-3.0

-3.0

---

STEAM TRACE

(0.9)

(-0.9)

0.1

-0.1

-2.0

2.0

PAGE TOTAL

611

-631.5

-633.7

0.0

0.0

-2.4

0.0

0.0

2.0

0.0

0.0

0.0

0.0

0.0

0.4


10066

-4955.9

-5236.8

91.1

-56.0

24.5

13.5

29.8

2.1

99.1

-236.7

-15.2

0.0

0.0

47.8


10066

-5225.9

-5536.8

91.1

-56.0

24.5

13.5

29.8

2.1

99.1

-236.7

-15.2

0.0

0.0

47.8

NOTES

_ _ _ __ RA| D __| N I ||___ (

S-015-1223-521-1.xls

7 2-20007 FEABR0273-M



10

APPROVED BY

MOTOR/LOAD RATING:


MECH. RUNNING LOAD:

MOTOR SHAFT POWER




REV



CLIENT

PETROVIETNAM

LOCATION

DUNG QUAT

PLANT CAPACITY

VIETNAM

SECTION No.

015 RFCC

CASE

UNIT

ITEM No.

Project N° - Unit

Doc. type

Code

Serial N°

Rev. index

8474L 015

CN

00 03

521

1

REVISION

COOLING WATER

DESCRIPTION

ΔT ºC

m3/h

E-1518


6.0

-19

E-1520 A-H


8.0

-1882

E-1531

SURFACE CONDENSER

E-1532

BLOWDOWN COOLER

13.0

-15

E-1533

BLOWDOWN COOLER

15.0

-24

E-1552 A/B


8.0

-255

E-1554 A-D

STRIPPER CONDENSER

6.0

-820

E-1559

GASOLINE COOLER

6.0

-160

E-1561 A/B


12.0

-1353

E-1562

LPG COOLER

6.0

-64

E-1564

LEAN OIL COOLER

6.0

-177

E-1565

FUEL GAS COOLER

6.0

-9

E-1566

LEAN AMINE COOLER

6.0

-72

E-1567

TURBINE CONDENSER

69,700 BPSD Bach Ho Max Gasoline - Design Case SEA WATER ΔT ºC

m3/h

8.8

-7285

8.8

-2300

FRESH WATER T/h

DATE

SHEET


9


NITROGEN Nm3/h

S-015-1223-521-1.xls

7 2-20007 FEABR0273-M

(

CONTIN

INTERMIT

Efficiency %

FUEL FIRED MW

PUMP / COMP COOLING

-95

PAGE TOTAL

-4945

-9585

0

0

0

0

0

0

0.0

0.0

0.0

GENERAL TOTAL

-4945

-9585

0

0

0

0

0

0

0.0

0.0

0.0



10


NOTES

_ _ _ __ RA| D __| N I ||___

OF

APPROVED BY


REMARKS

REV



CLIENT

PETROVIETNAM

LOCATION

DUNG QUAT

PLANT CAPACITY

VIETNAM

SECTION No.

015 RFCC

CASE

UNIT

ITEM No.

Doc. type

Code

Serial N°

Rev. index

8474L 015

CN

00 03

521

1

REVISION

DESCRIPTION


m3/h -4945


69,700 BPSD Bach Ho Max Gasoline - Design Case SEA WATER ΔT ºC

m3/h

FRESH WATER T/h

DATE

SHEET

WRITTEN BY 10

CHECKED BY


H-1502


H-1503

COB/WHB PACKAGE


FURNACES & BOILERS

INTERMIT

DUTY MW

X-1507 X-1504

X-1502


X-1503


C-1501

AIR BLOWER

-22

-3

-50

(-125)


-26

-8

(-85)

SLURRY SEPARATOR

-1

OIL MIST GENERATOR

-165 -3

-60

(-40)

(-3)

(-60)

(-40)

GLAND CONDENSER

-76

OIL COOLER

-32 -6

MAIN OIL COOLER

6.0

-60

GLAND CONDENSER

6.0

-50

PV-1501

PLUG VALVE

SV-1501


SV-1502


SV-1504


-134


-4230

REV

(-280)

-611 -84 -36

(2)

1

(-2320) -340

-160

(-560)

PAGE TOTAL

-221

0

0

-5658

-118

0

-351

0

0.0

0.0

-113.7

GENERAL TOTAL

-5166

-9585

0

-5658

-118

0

-351

0

0.0

0.0

-113.7

MISCELLANEOUS USERS

-13.7



REMARKS

-100.0

-71


7 2-20007 FEABR0273-M

FUEL FIRED MW

(1) 15.0

WET GAS COMPRESSOR

S-015-1223-521-1.xls

Efficiency %

(1)

-120

(

10

-9585


_ _ _ __ RA| D __| N I ||___

OF

APPROVED BY

H-1501

C-1551

Project N° - Unit



1



PETROVIETNAM

LOCATION

DUNG QUAT

PLANT CAPACITY

VIETNAM

SECTION No.

015 RFCC

CASE

UNIT



7 2-20007 FEABR0273-M

Code

Serial N°

Rev. index

CN

00 03

522

1

Op. Center JOB No.

0-3952-20-0000

Op. Center Doc. No.

S-015-1223-522

FEED Doc. No.

A

0

1

23-MAY-06

01-FEB-07

23-FEB-07

WRITTEN BY

T. Tsuchiya

T. Tsuchiya

T. Tsuchiya

Bach Ho Max Distillate

CHECKED BY

M. Okada

M. Okada

M. Okada

- Design Case

APPROVED BY

M. Okada

M. Okada

M. Okada

DESCRIPTION

Issue for Review

For Construction

For Construction

2,4,10

Bach Ho MD - Design

S-015-1223-522-1.xls

Doc. type

8474L 015

DATE

GENERAL NOTES:

_ _ _ __ RA| D __| N I ||___

X

Project N° - Unit

6960-015-DS-0711

SHEET

1

OF

10



PETROVIETNAM

LOCATION

DUNG QUAT

PLANT CAPACITY

VIETNAM

SECTION No.

015 RFCC

CASE

UNIT

ITEM No.

DESCRIPTION

MOTOR LOAD/ RATING


-0.3

-0.3

-683.0

-697.0

HP STM

MP STM

219.3

0.7


C-1502 B


(-21.0)


-1.7

1230


3

-3.0

-3.0

P-1529 A


55

-39.0

-43.3

P-1529 B


55

(-39.0)

(-43.3)

E-1531


-18.5

-20.6

15

-15.0

-15.0


-

TURNING GEAR MOTOR

C-1551

WET GAS COMPRESSOR

-1.5

-1.5


18.5

-13.9

-14.8

P-1559 B


18.5

(-13.9)

(-14.8)

E-1567


-16.0

-17.8


-


Serial N°

Rev. index

8474L 015

CN

00 03

522

1

HP COND

DATE

SHEET


2

OF

-68.7

-30.4


BFW T/h HP BFW

LP BFW

-225.5

-0.7

COLD BFW

DW T/h DEMIN. WATER

LOSSES T/h

REMARKS

1.7

-0.3

1

18.5 0.1

-0.1

68.7

0.3

30.4

0.4

(2.6)

-0.4

(2.1)

(-2.1)

-34.7

34.7


-


0.5

-0.5

D-1527

LP BLOWDOWN DRUM

0.2

-0.2

T-1503

LCO STRIPPER

-3.0

3.0

T-1504

HCO STRIPPER

-0.5

0.5

PAGE TOTAL

1462

-790.2

-813.3

118.5

-53.2

-2.9

0.0

18.5

0.1

99.1

-225.5

-0.7

0.0

0.0

46.1

GENERAL TOTAL

1462

-790.2

-813.3

118.5

-53.2

-2.9

0.0

18.5

0.1

99.1

-225.5

-0.7

0.0

0.0

46.1

NOTES

(

S-015-1223-522-1.xls

7 2-20007 FEABR0273-M



REV

6.2

D-1501

_ _ _ __ RA| D __| N I ||___

10

APPROVED BY

(21.0)

(-2.6)

P-1559 A

-

LP STM

-18.5

E-1534

-

Code

Included in H-1503

C-1501

-

69,700 BPSD Bach Ho Max Distillate - Design Case STEAM T/h

H-1503

ECONOMIZER

Doc. type

REVISION

C-1502 A

E-1525

Project N° - Unit

MOTOR/LOAD RATING:


MECH. RUNNING LOAD:

MOTOR SHAFT POWER






PETROVIETNAM

LOCATION

DUNG QUAT

PLANT CAPACITY

VIETNAM

SECTION No.

015 RFCC

CASE

UNIT

ITEM No.

DESCRIPTION

Project N° - Unit

Doc. type

Code

Serial N°

Rev. index

8474L 015

CN

00 03

522

1

REVISION

MOTOR LOAD/ RATING



1462

-790.2

-813.3

P-1501 A

FEED PUMP

600

-476.0

-500.5

P-1501 B

FEED PUMP

600

(-476.0)

(-500.5)

P-1504 A

SLURRY PRODUCT PUMP

55

-42.7

-45.1

P-1504 B

SLURRY PRODUCT PUMP

55

(-42.7)

(-45.1)

P-1505 A

BACKFLUSH OIL PUMP

22

-15.0

-16.5

P-1505 B

BACKFLUSH OIL PUMP

22

(-15.0)

(-16.5)

P-1506 A


11

-7.4

-8.4

P-1506 B


11

(-7.4)

(-8.4)

P-1507 A

HCO RECYCLE PUMP

150

-128.0

-142.2

P-1507 B

HCO RECYCLE PUMP

150

(-128.0)

(-142.2)


HP STM

MP STM

LP STM

HP COND

118.5

-53.2

-2.9

0.0

DATE

SHEET

WRITTEN BY 3

CHECKED BY

OF


LP BFW

COLD BFW

DW T/h DEMIN. WATER

LOSSES T/h

HP BFW

18.5

0.1

-225.5

-0.7

0.0

0.0

46.1

99.1

BFW T/h

P-1508 A

HCO PUMPAROUND PUMP

220

-179.4

-188.4

P-1508 B

HCO PUMPAROUND PUMP

220

(-179.4)

(-188.4)

P-1509 A

HCO PRODUCT PUMP

15

-9.1

-10.1

P-1509 B

HCO PRODUCT PUMP

15

(-9.1)

(-10.1)

P-1510 A

LCO PUMPAROUND PUMP

335

-303.0

-316.0

P-1510 B

LCO PUMPAROUND PUMP

335

(-303.0)

(-316.0)

P-1511 A

LCO STRIPPER PUMP

90

-73.4

-76.9

P-1511 B

LCO STRIPPER PUMP

90

(-73.4)

(-76.9)

P-1512 A

MTC RECYCLE PUMP

75

0.0

0.0

P-1512 B

MTC RECYCLE PUMP

75

(0.0)

(0.0)

P-1513 A

LEAN OIL PUMP

75

-55.0

-58.1

P-1513 B

LEAN OIL PUMP

75

(-55.0)

(-58.1)

P-1514 A


225

-203.0

-213.9

P-1514 B


225

(-203.0)

(-213.9)

PAGE TOTAL

3746

-1492.0

-1576.1

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

GENERAL TOTAL

5208

-2282.2

-2389.4

118.5

-53.2

-2.9

0.0

18.5

0.1

99.1

-225.5

-0.7

0.0

0.0

46.1

REMARKS

NOTES

_ _ _ __ RA| D __| N I ||___ (

S-015-1223-522-1.xls

7 2-20007 FEABR0273-M



10

APPROVED BY

MOTOR/LOAD RATING:


MECH. RUNNING LOAD:

MOTOR SHAFT POWER




REV



PETROVIETNAM

LOCATION

DUNG QUAT

PLANT CAPACITY

VIETNAM

SECTION No.

015 RFCC

CASE

UNIT

ITEM No.

DESCRIPTION

Project N° - Unit

Doc. type

Code

Serial N°

Rev. index

8474L 015

CN

00 03

522

1

REVISION

MOTOR LOAD/ RATING



5208

-2282.2

-2389.4

P-1515 A


55

-39.4

-41.6

P-1515 B


55

(-39.4)

(-41.6)

P-1516 A


110

-96.0

-101.3 (-101.3)


HP STM

MP STM

LP STM

HP COND

118.5

-53.2

-2.9

0.0

DATE

SHEET


4

OF


0.1

99.1

LP BFW

COLD BFW

DW T/h DEMIN. WATER

LOSSES T/h

HP BFW

BFW T/h

-225.5

-0.7

0.0

0.0

46.1

P-1516 B


110

(-96.0)

P-1517 A


30

-25.5

-27.6

P-1517 B


30

(-25.5)

(-27.6)

P-1518 A


250

-206.0

-228.9

P-1518 B


250

(-206.0)

(-228.9)

P-1519 A


-10.3

P-1519 B


-10.3

10.3

P-1519 C


(-10.3)

(10.3)


-0.8

P-1521 A


-3.7

P-1521 B


110

(-80.9)

P-1522 A


30

-18.4

-19.9

P-1522 B


30

(-18.4)

(-19.9)

P-1526 A

LIGHT SLOPS PUMP

37

-26.1

-27.9

P-1526 B

LIGHT SLOPS PUMP

37

(-26.1)

(-27.9)

P-1527 A

HEAVY SLOPS PUMP

37

-27.9

-29.8

P-1527 B

HEAVY SLOPS PUMP

37

(-27.9)

(-29.8)

P-1528 A

TEMPERED WATER PUMP

15

-10.5

-11.7

P-1528 B

TEMPERED WATER PUMP

15

(-10.5)

(-11.7)

PAGE TOTAL

1238

-449.8

-488.7

-25.1

0.0

24.3

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.8

GENERAL TOTAL

6446

-2732.0

-2878.1

93.4

-53.2

21.4

0.0

18.5

0.1

99.1

-225.5

-0.7

0.0

0.0

46.9

REMARKS

(

S-015-1223-522-1.xls

7 2-20007 FEABR0273-M


0.8 3.7

(-84.4)


REV

10.3

NOTES

_ _ _ __ RA| D __| N I ||___

10

APPROVED BY

MOTOR/LOAD RATING:


MECH. RUNNING LOAD:

MOTOR SHAFT POWER




1



PETROVIETNAM

LOCATION

DUNG QUAT

PLANT CAPACITY

VIETNAM

SECTION No.

015 RFCC

CASE

UNIT

ITEM No.

DESCRIPTION

Project N° - Unit

Doc. type

Code

Serial N°

Rev. index

8474L 015

CN

00 03

522

1

REVISION

MOTOR LOAD/ RATING



HP STM

MP STM

LP STM

HP COND

93.4

-53.2

21.4

0.0


6446

-2732.0

-2878.1

P-1551 A


150

-134.0

-142.3

P-1551 B


150

(-134.0)

(-142.3)

P-1552 A

KO DRUM LIQUID PUMP

4

-1.2

-1.4

P-1552 B

KO DRUM LIQUID PUMP

4

(-1.2)

(-1.4)

P-1553 A

STRIPPER FEED PUMP

132

-112.0

-117.9

P-1553 B

STRIPPER FEED PUMP

132

(-112.0)

(-117.9)

P-1554 A


55

-44.0

-47.7

P-1554 B


55

(-44.0)

(-47.7)

DATE

SHEET


5

OF


0.1

99.1

LP BFW

COLD BFW

DW T/h DEMIN. WATER

LOSSES T/h

HP BFW

BFW T/h

-225.5

-0.7

0.0

0.0

46.9

P-1556 A


225

-185.0

-194.9

P-1556 B


225

(-185.0)

(-194.9)

P-1560 A


22

(-16.5)

(-18.1)

P-1560 B


22

(-16.5)

(-18.1)

P-1561


7.5

(-4.9)

(-5.4)

P-1562


7.5

(-4.9)

(-5.4)

P-1563


7.5

(-4.9)

(-5.4)

P-1564


15

(-10.8)

(-12.0)

PAGE TOTAL

1214

-476.2

-504.2

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

GENERAL TOTAL

7660

-3208.2

-3382.3

93.4

-53.2

21.4

0.0

18.5

0.1

99.1

-225.5

-0.7

0.0

0.0

46.9

REMARKS

NOTES

_ _ _ __ RA| D __| N I ||___ (

S-015-1223-522-1.xls

7 2-20007 FEABR0273-M



10

APPROVED BY

MOTOR/LOAD RATING:


MECH. RUNNING LOAD:

MOTOR SHAFT POWER




REV



PETROVIETNAM

LOCATION

DUNG QUAT

PLANT CAPACITY

VIETNAM

SECTION No.

015 RFCC

CASE

UNIT

ITEM No.

DESCRIPTION

Project N° - Unit

Doc. type

Code

Serial N°

Rev. index

8474L 015

CN

00 03

522

1

REVISION

MOTOR LOAD/ RATING



7660

-3208.2

-3382.3

E-1514

LCO AIR COOLER

120

-97.6

-106.2

E-1517


33

-20.4

-23.1

E-1519


960

-736.0

-800.9

E-1521


120

-99.6

-108.4

E-1530


22.5

-15.0

-17.8

E-1551


240

-190.4

-207.2


HP STM

MP STM

LP STM

HP COND

93.4

-53.2

21.4

0.0

DATE

SHEET


6

OF


0.1

99.1

LP BFW

COLD BFW

DW T/h DEMIN. WATER

LOSSES T/h

HP BFW -225.5

-0.7

0.0

0.0

46.9

BFW T/h

E-1553

HP CONDENSER

180

-134.4

-146.2

E-1558

GASOLINE AIR COOLER

120

-92.8

-101.0

E-1503


0.0

0.0

E-1504


18.0

-18.5

E-1505


E-1506


E-1508


E-1510


2.9

E-1513


8.6

E-1518


13.8

1.3

6.5

REMARKS

0.5

-14.2

0.4

-1.4

0.1

-6.7

0.2

-3.0

0.1

-8.9

0.3

PAGE TOTAL

1796

-1386.2

-1510.8

18.0

20.3

12.8

0.0

0.0

0.0

0.0

-18.5

-34.2

0.0

0.0

1.6

GENERAL TOTAL

9455

-4594.4

-4893.1

111.4

-32.9

34.2

0.0

18.5

0.1

99.1

-244.0

-34.9

0.0

0.0

48.5

NOTES

_ _ _ __ RA| D __| N I ||___ (

S-015-1223-522-1.xls

7 2-20007 FEABR0273-M



10

APPROVED BY

MOTOR/LOAD RATING:


MECH. RUNNING LOAD:

MOTOR SHAFT POWER




REV



PETROVIETNAM

LOCATION

DUNG QUAT

PLANT CAPACITY

VIETNAM

SECTION No.

015 RFCC

CASE

UNIT

ITEM No.

DESCRIPTION


Project N° - Unit

Doc. type

Code

Serial N°

Rev. index

8474L 015

CN

00 03

522

1

REVISION




HP STM

MP STM

LP STM

HP COND

-4893.1

111.4

-32.9

34.2

0.0

-4594.4

DATE

SHEET


7

OF


LP BFW

COLD BFW

DW T/h DEMIN. WATER

LOSSES T/h

HP BFW

0.1

-244.0

-34.9

0.0

0.0

48.5

18.5

99.1

BFW T/h

REMARKS


E-1522


-6.5

E-1523


7.3

E-1524


E-1532

BLOWDOWN COOLER

E-1552 A/B


E-1554 A-D

STRIPPER CONDENSER

E-1559

GASOLINE COOLER

E-1561 A/B


E-1562

LPG COOLER

E-1564

LEAN OIL COOLER

6.5


-7.5

-11.3


11.3

E-1565

FUEL GAS COOLER

E-1566

LEAN AMINE COOLER

I-1501

FEED INJECTOR

Included in D-1501

I-1502

MTC INJECTOR

Included in D-1501

I-1503


Included in D-1501

I-1504


SPR-1501


(-0.3)


SPR-1502


(-0.3)

SPR-1503


(-1.5)

(-22.8)

(-24.3)

SPR-1504


(-1.5)

(-14.0)

(-15.5)

SPR-1505


(-1.5)

(-5.2)

(-6.7)

(0.3)

PAGE TOTAL

0

0.0

0.0

-11.3

0.8

0.0

11.3

6.5

0.0

0.0

0.0

-7.5

0.0

0.0

0.2

GENERAL TOTAL

9455

-4594.4

-4893.1

100.1

-32.1

34.2

11.3

25.0

0.1

99.1

-244.0

-42.4

0.0

0.0

48.7

NOTES

_ _ _ __ RA| D __| N I ||___ (

S-015-1223-522-1.xls

7 2-20007 FEABR0273-M



10

APPROVED BY

MOTOR/LOAD RATING:


MECH. RUNNING LOAD:

MOTOR SHAFT POWER




REV



PETROVIETNAM

LOCATION

DUNG QUAT

PLANT CAPACITY

VIETNAM

SECTION No.

015 RFCC

CASE

UNIT

ITEM No.

DESCRIPTION


SLURRY SEPARATOR

X-1505


MOTOR LOAD/ RATING


9455

-4594.4

-4893.1

-230.0

-230.0


0.55

-0.40

-0.44

X-1507


491

-379.0

-379.0

88

(-53)

(-53)

(-270.0)

(-300.0)

X-1509

Doc. type

Code

Serial N°

Rev. index

8474L 015

CN

00 03

522

1

REVISION

P-1520

X-1508

Project N° - Unit

DESOX UNIT(FUTURE)


HP STM

MP STM

LP STM

HP COND

100.1

-32.1

34.2

11.3

DATE

SHEET


8

OF


LP BFW

COLD BFW

DW T/h DEMIN. WATER

LOSSES T/h

HP BFW

0.1

-244.0

-42.4

0.0

0.0

48.7

25.0

99.1

BFW T/h

-0.3

REMARKS



P-1502 A


0.55

0.00

0.00

P-1502 B


0.55

(0.00)

(0.00)

X-1510


6.05

-4.36

-4.84

X-1551


P-1557

ANTI-FOAMING PUMP

0.55

(-0.40)

(-0.44)

P-1558

ANTI-FOAMING PUMP

0.55

(-0.40)

(-0.44)

-3.3

EJ-1501


SV-1501


4.0

-3.0

SV-1502


4.0

-3.0

-3.3

SV-1503


4.0

-3.0

-3.3

SV-1504


4.0

-3.0

-3.3

PV-1501

PLUG VALVE

4.0

-3.0

-3.3

---

OIL MIST GENERATOR

3.0

-3.0

-3.0

---

STEAM TRACE

(0.9)

(-0.9)

0.1

-0.1

-2.0

2.0

PAGE TOTAL

611

-631.5

-633.7

0.0

0.0

-2.4

0.0

0.0

2.0

0.0

0.0

0.0

0.0

0.0

0.4


10066

-5225.9

-5526.7

100.1

-32.1

31.8

11.3

25.0

2.1

99.1

-244.0

-42.4

0.0

0.0

49.1


10066

-5495.9

-5826.7

100.1

-32.1

31.8

11.3

25.0

2.1

99.1

-244.0

-42.4

0.0

0.0

49.1

NOTES

_ _ _ __ RA| D __| N I ||___ (

S-015-1223-522-1.xls

7 2-20007 FEABR0273-M



10

APPROVED BY

MOTOR/LOAD RATING:


MECH. RUNNING LOAD:

MOTOR SHAFT POWER




REV



CLIENT

PETROVIETNAM

LOCATION

DUNG QUAT

PLANT CAPACITY

VIETNAM

SECTION No.

015 RFCC

CASE

UNIT

ITEM No.

Project N° - Unit

Doc. type

Code

Serial N°

Rev. index

8474L 015

CN

00 03

522

1

REVISION

COOLING WATER

DESCRIPTION

ΔT ºC

m3/h

E-1518


6.0

-20

E-1520 A-H


8.0

-1743

E-1531

SURFACE CONDENSER

E-1532

BLOWDOWN COOLER

13.0

-15

E-1533

BLOWDOWN COOLER

15.0

-24

E-1552 A/B


8.0

-225

E-1554 A-D

STRIPPER CONDENSER

6.0

-650

E-1559

GASOLINE COOLER

6.0

-138

E-1561 A/B


12.0

-1159

E-1562

LPG COOLER

6.0

-49

E-1564

LEAN OIL COOLER

6.0

-196

E-1565

FUEL GAS COOLER

6.0

-6

E-1566

LEAN AMINE COOLER

6.0

-53

E-1567

TURBINE CONDENSER

69,700 BPSD Bach Ho Max Distillate - Design Case SEA WATER ΔT ºC

m3/h

8.8

-7285

8.8

-2300

FRESH WATER T/h

DATE

SHEET


9


NITROGEN Nm3/h

S-015-1223-522-1.xls

7 2-20007 FEABR0273-M

(

CONTIN

INTERMIT

Efficiency %

FUEL FIRED MW

PUMP / COMP COOLING

-95

PAGE TOTAL

-4373

-9585

0

0

0

0

0

0

0.0

0.0

0.0

GENERAL TOTAL

-4373

-9585

0

0

0

0

0

0

0.0

0.0

0.0



10


NOTES

_ _ _ __ RA| D __| N I ||___

OF

APPROVED BY


REMARKS

REV



CLIENT

PETROVIETNAM

LOCATION

DUNG QUAT

PLANT CAPACITY

VIETNAM

SECTION No.

015 RFCC

CASE

UNIT

ITEM No.

Doc. type

Code

Serial N°

Rev. index

8474L 015

CN

00 03

522

1

REVISION

DESCRIPTION


m3/h -4373


69,700 BPSD Bach Ho Max Distillate - Design Case SEA WATER ΔT ºC

m3/h

FRESH WATER T/h

DATE

SHEET

WRITTEN BY 10

CHECKED BY


H-1502


H-1503

COB/WHB PACKAGE


FURNACES & BOILERS

INTERMIT

DUTY MW

X-1507 X-1504

X-1502


X-1503


C-1501

AIR BLOWER

-22

-3

-50

(-125)


-26

-8

(-85)

SLURRY SEPARATOR

-1

OIL MIST GENERATOR

-165 -3

-60

(-40)

(-3)

(-60)

(-40)

GLAND CONDENSER

-76

OIL COOLER

-32 -6

MAIN OIL COOLER

6.0

-60

GLAND CONDENSER

6.0

-50

PV-1501

PLUG VALVE

SV-1501


SV-1502


SV-1504


-134


-4230

REV

(-280)

-611 -84 -36

(2)

1

(-2320) -340

-160

(-560)

PAGE TOTAL

-221

0

0

-5658

-118

0

-351

0

0.0

0.0

-123.7

GENERAL TOTAL

-4594

-9585

0

-5658

-118

0

-351

0

0.0

0.0

-123.7

MISCELLANEOUS USERS

-13.7



REMARKS

-110.0

-71


7 2-20007 FEABR0273-M

FUEL FIRED MW

(1) 15.0

WET GAS COMPRESSOR

S-015-1223-522-1.xls

Efficiency %

(1)

-120

(

10

-9585


_ _ _ __ RA| D __| N I ||___

OF

APPROVED BY

H-1501

C-1551

Project N° - Unit



1



PETROVIETNAM

LOCATION

DUNG QUAT

PLANT CAPACITY

VIETNAM

SECTION No.

015 RFCC

CASE

UNIT



7 2-20007 FEABR0273-M

Code

Serial N°

Rev. index

CN

00 03

523

1

Op. Center JOB No.

0-3952-20-0000

Op. Center Doc. No.

S-015-1223-523

FEED Doc. No.

A

0

1

23-MAY-06

01-FEB-07

23-FEB-07

WRITTEN BY

T. Tsuchiya

T. Tsuchiya

T. Tsuchiya

Mixed Crude Max Gasoline

CHECKED BY

M. Okada

M. Okada

M. Okada

- Design Case

APPROVED BY

M. Okada

M. Okada

M. Okada

DESCRIPTION

Issue for Review

For Construction

For Construction

2,4,10

Mixed Crude MG - Design

S-015-1223-523-1.xls

Doc. type

8474L 015

DATE

GENERAL NOTES:

_ _ _ __ RA| D __| N I ||___

X

Project N° - Unit

6960-015-DS-0711

SHEET

1

OF

10



PETROVIETNAM

LOCATION

DUNG QUAT

PLANT CAPACITY

VIETNAM

SECTION No.

015 RFCC

CASE

UNIT

ITEM No.

DESCRIPTION

MOTOR LOAD/ RATING


-0.3

-0.3

-352.0

-363.0

HP STM

MP STM

214.0

0.7


C-1502 B


(-11.0)


-0.9

1230


3

-3.0

-3.0

P-1529 A


55

-39.0

-43.3

P-1529 B


55

(-39.0)

(-43.3)

E-1531


-18.5

-20.6

15

-15.0

-15.0


-

TURNING GEAR MOTOR

C-1551

WET GAS COMPRESSOR

-1.5

-1.5


18.5

-13.9

-14.8

P-1559 B


18.5

(-13.9)

(-14.8)

E-1567


-16.0

-17.8


-


Serial N°

Rev. index

8474L 015

CN

00 03

523

1

HP COND

DATE

SHEET


2

OF

-94.0

-32.2


BFW T/h HP BFW

LP BFW

-220.2

-0.7

COLD BFW

DW T/h DEMIN. WATER

LOSSES T/h

REMARKS

0.9

-0.3

1

19.8 -0.1

0.1

94.0

0.3

32.2

0.4

(2.6)

-0.4

(-2.1)

(2.1)


-


0.5

-0.5

D-1527

LP BLOWDOWN DRUM

0.5

-0.5

T-1503

LCO STRIPPER

-3.0

3.0

T-1504

HCO STRIPPER

-0.5

0.5

-34.7

34.7

PAGE TOTAL

1462

-459.2

-479.3

86.9

-54.5

-2.6

0.0

19.8

0.1

126.2

-220.2

-0.7

0.0

0.0

45.0

GENERAL TOTAL

1462

-459.2

-479.3

86.9

-54.5

-2.6

0.0

19.8

0.1

126.2

-220.2

-0.7

0.0

0.0

45.0

NOTES

(

S-015-1223-523-1.xls

7 2-20007 FEABR0273-M



REV

6.2

D-1501

_ _ _ __ RA| D __| N I ||___

10

APPROVED BY

(11.0)

(-2.6)

P-1559 A

-

LP STM

-19.8

E-1534

-

Code

Included in H-1503

C-1501

-

69,700 BPSD Mixed Crude Max Gasoline - Design Case STEAM T/h

H-1503

ECONOMIZER

Doc. type

REVISION

C-1502 A

E-1525

Project N° - Unit

MOTOR/LOAD RATING:


MECH. RUNNING LOAD:

MOTOR SHAFT POWER






PETROVIETNAM

LOCATION

DUNG QUAT

PLANT CAPACITY

VIETNAM

SECTION No.

015 RFCC

CASE

UNIT

ITEM No.

DESCRIPTION

Project N° - Unit

Doc. type

Code

Serial N°

Rev. index

8474L 015

CN

00 03

523

1

REVISION

MOTOR LOAD/ RATING



1462

-459.2

-479.3

P-1501 A

FEED PUMP

600

-476.0

-500.5

P-1501 B

FEED PUMP

600

(-476.0)

(-500.5)


HP STM

MP STM

LP STM

HP COND

86.9

-54.5

-2.6

0.0

DATE

SHEET

WRITTEN BY 3

CHECKED BY

OF


LP BFW

COLD BFW

DW T/h DEMIN. WATER

LOSSES T/h

HP BFW

19.8

0.1

-220.2

-0.7

0.0

0.0

45.0

126.2

BFW T/h

P-1504 A

SLURRY PRODUCT PUMP

55

-42.7

-45.1

P-1504 B

SLURRY PRODUCT PUMP

55

(-42.7)

(-45.1)

P-1505 A

BACKFLUSH OIL PUMP

22

-15.0

-16.5

P-1505 B

BACKFLUSH OIL PUMP

22

(-15.0)

(-16.5)

P-1506 A


11

-7.4

-8.4

P-1506 B


11

(-7.4)

(-8.4)

P-1507 A

HCO RECYCLE PUMP

150

0.0

0.0

P-1507 B

HCO RECYCLE PUMP

150

(0.0)

(0.0)

P-1508 A

HCO PUMPAROUND PUMP

220

-179.4

-188.4

P-1508 B

HCO PUMPAROUND PUMP

220

(-179.4)

(-188.4)

P-1509 A

HCO PRODUCT PUMP

15

-9.1

-10.1

P-1509 B

HCO PRODUCT PUMP

15

(-9.1)

(-10.1)

P-1510 A

LCO PUMPAROUND PUMP

335

-303.0

-316.0

P-1510 B

LCO PUMPAROUND PUMP

335

(-303.0)

(-316.0)

P-1511 A

LCO STRIPPER PUMP

90

-73.4

-76.9

P-1511 B

LCO STRIPPER PUMP

90

(-73.4)

(-76.9)

P-1512 A

MTC RECYCLE PUMP

75

-67.0

-72.0

P-1512 B

MTC RECYCLE PUMP

75

(-67.0)

(-72.0)

P-1513 A

LEAN OIL PUMP

75

-55.0

-58.1

P-1513 B

LEAN OIL PUMP

75

(-55.0)

(-58.1)

P-1514 A


225

-203.0

-213.9

P-1514 B


225

(-203.0)

(-213.9)

PAGE TOTAL

3746

-1431.0

-1505.9

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

GENERAL TOTAL

5208

-1890.2

-1985.2

86.9

-54.5

-2.6

0.0

19.8

0.1

126.2

-220.2

-0.7

0.0

0.0

45.0

REMARKS

NOTES

_ _ _ __ RA| D __| N I ||___ (

S-015-1223-523-1.xls

7 2-20007 FEABR0273-M



10

APPROVED BY

MOTOR/LOAD RATING:


MECH. RUNNING LOAD:

MOTOR SHAFT POWER




REV



PETROVIETNAM

LOCATION

DUNG QUAT

PLANT CAPACITY

VIETNAM

SECTION No.

015 RFCC

CASE

UNIT

ITEM No.

DESCRIPTION

Project N° - Unit

Doc. type

Code

Serial N°

Rev. index

8474L 015

CN

00 03

523

1

REVISION

MOTOR LOAD/ RATING



5208

-1890.2

-1985.2

P-1515 A


55

-39.4

-41.6

P-1515 B


55

(-39.4)

(-41.6)

P-1516 A


110

-96.0

-101.3 (-101.3)


HP STM

MP STM

LP STM

HP COND

86.9

-54.5

-2.6

0.0

DATE

SHEET


4

OF


LP BFW

COLD BFW

DW T/h DEMIN. WATER

LOSSES T/h

HP BFW

0.1

-220.2

-0.7

0.0

0.0

45.0

19.8

126.2

BFW T/h

P-1516 B


110

(-96.0)

P-1517 A


30

-25.5

-27.6

P-1517 B


30

(-25.5)

(-27.6)

P-1518 A


250

-206.0

-228.9

P-1518 B


250

(-206.0)

(-228.9)

P-1519 A


-10.3

P-1519 B


-10.3

10.3

P-1519 C


(-10.3)

(10.3)


-0.8

P-1521 A


-3.7

P-1521 B


110

(-80.9)

P-1522 A


30

-18.4

-19.9

P-1522 B


30

(-18.4)

(-19.9)

P-1526 A

LIGHT SLOPS PUMP

37

-26.1

-27.9

P-1526 B

LIGHT SLOPS PUMP

37

(-26.1)

(-27.9)

P-1527 A

HEAVY SLOPS PUMP

37

-27.9

-29.8

P-1527 B

HEAVY SLOPS PUMP

37

(-27.9)

(-29.8)

P-1528 A

TEMPERED WATER PUMP

15

-10.5

-11.7

P-1528 B

TEMPERED WATER PUMP

15

(-10.5)

(-11.7)

PAGE TOTAL

1238

-449.8

-488.7

-25.1

0.0

24.3

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.8

GENERAL TOTAL

6446

-2340.0

-2473.8

61.8

-54.5

21.7

0.0

19.8

0.1

126.2

-220.2

-0.7

0.0

0.0

45.8

REMARKS

(

S-015-1223-523-1.xls

7 2-20007 FEABR0273-M


0.8 3.7

(-84.4)


REV

10.3

NOTES

_ _ _ __ RA| D __| N I ||___

10

APPROVED BY

MOTOR/LOAD RATING:


MECH. RUNNING LOAD:

MOTOR SHAFT POWER




1



PETROVIETNAM

LOCATION

DUNG QUAT

PLANT CAPACITY

VIETNAM

SECTION No.

015 RFCC

CASE

UNIT

ITEM No.

DESCRIPTION

Project N° - Unit

Doc. type

Code

Serial N°

Rev. index

8474L 015

CN

00 03

523

1

REVISION

MOTOR LOAD/ RATING



HP STM

MP STM

LP STM

HP COND

61.8

-54.5

21.7

0.0


6446

-2340.0

-2473.8

P-1551 A


150

-134.0

-142.3

P-1551 B


150

(-134.0)

(-142.3)

P-1552 A

KO DRUM LIQUID PUMP

4

-1.2

-1.4

P-1552 B

KO DRUM LIQUID PUMP

4

(-1.2)

(-1.4)

P-1553 A

STRIPPER FEED PUMP

132

-112.0

-117.9

P-1553 B

STRIPPER FEED PUMP

132

(-112.0)

(-117.9)

P-1554 A


55

-44.0

-47.7

P-1554 B


55

(-44.0)

(-47.7)

DATE

SHEET


5

OF


0.1

126.2

LP BFW

COLD BFW

DW T/h DEMIN. WATER

LOSSES T/h

HP BFW

BFW T/h

-220.2

-0.7

0.0

0.0

45.8

P-1556 A


225

-185.0

-194.9

P-1556 B


225

(-185.0)

(-194.9)

P-1560 A


22

(-16.5)

(-18.1)

P-1560 B


22

(-16.5)

(-18.1)

P-1561


7.5

(-4.9)

(-5.4)

P-1562


7.5

(-4.9)

(-5.4)

P-1563


7.5

(-4.9)

(-5.4)

P-1564


15

(-10.8)

(-12.0)

PAGE TOTAL

1214

-476.2

-504.2

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

GENERAL TOTAL

7660

-2816.2

-2978.0

61.8

-54.5

21.7

0.0

19.8

0.1

126.2

-220.2

-0.7

0.0

0.0

45.8

REMARKS

NOTES

_ _ _ __ RA| D __| N I ||___ (

S-015-1223-523-1.xls

7 2-20007 FEABR0273-M



10

APPROVED BY

MOTOR/LOAD RATING:


MECH. RUNNING LOAD:

MOTOR SHAFT POWER




REV



PETROVIETNAM

LOCATION

DUNG QUAT

PLANT CAPACITY

VIETNAM

SECTION No.

015 RFCC

CASE

UNIT

ITEM No.

DESCRIPTION

Project N° - Unit

Doc. type

Code

Serial N°

Rev. index

8474L 015

CN

00 03

523

1

REVISION

MOTOR LOAD/ RATING



7660

-2816.2

-2978.0

E-1514

LCO AIR COOLER

120

-97.6

-106.2

E-1517


33

-20.4

-23.1

E-1519


960

-736.0

-800.9

E-1521


120

-99.6

-108.4

E-1530


22.5

-15.0

-17.8

E-1551


240

-190.4

-207.2


HP STM

MP STM

LP STM

HP COND

61.8

-54.5

21.7

0.0

DATE

SHEET


6

OF


0.1

126.2

LP BFW

COLD BFW

DW T/h DEMIN. WATER

LOSSES T/h

HP BFW -220.2

-0.7

0.0

0.0

45.8

BFW T/h

E-1553

HP CONDENSER

180

-134.4

-146.2

E-1558

GASOLINE AIR COOLER

120

-92.8

-101.0

E-1503


43.1

-44.4

1.3

E-1504


18.5

-19.1

0.6

E-1505


E-1506


E-1508


E-1510

13.8

-14.2

0.4

1.2

-1.2

0.0


1.9

-2.0

0.1

E-1513


2.6

-2.7

0.1

E-1518


REMARKS

0.0

0.0

PAGE TOTAL

1796

-1386.2

-1510.8

61.6

13.8

5.7

0.0

0.0

0.0

0.0

-63.5

-20.1

0.0

0.0

2.5

GENERAL TOTAL

9455

-4202.4

-4488.8

123.4

-40.7

27.4

0.0

19.8

0.1

126.2

-283.7

-20.8

0.0

0.0

48.3

NOTES

_ _ _ __ RA| D __| N I ||___ (

S-015-1223-523-1.xls

7 2-20007 FEABR0273-M



10

APPROVED BY

MOTOR/LOAD RATING:


MECH. RUNNING LOAD:

MOTOR SHAFT POWER




REV



PETROVIETNAM

LOCATION

DUNG QUAT

PLANT CAPACITY

VIETNAM

SECTION No.

015 RFCC

CASE

UNIT

ITEM No.

DESCRIPTION


Project N° - Unit

Doc. type

Code

Serial N°

Rev. index

8474L 015

CN

00 03

523

1

REVISION




HP STM

MP STM

LP STM

HP COND

-4488.8

123.4

-40.7

27.4

0.0

-4202.4

DATE

SHEET


7

OF


LP BFW

COLD BFW

DW T/h DEMIN. WATER

LOSSES T/h

HP BFW

0.1

-283.7

-20.8

0.0

0.0

48.3

19.8

126.2

BFW T/h

REMARKS


E-1522


(-17.2)

E-1523


0.9

E-1524


E-1532

BLOWDOWN COOLER

E-1552 A/B


E-1554 A-D

STRIPPER CONDENSER

E-1559

GASOLINE COOLER

E-1561 A/B


E-1562

LPG COOLER

E-1564

LEAN OIL COOLER

(17.2)


-1.0

0.0

0.0

E-1565

FUEL GAS COOLER

E-1566

LEAN AMINE COOLER

I-1501

FEED INJECTOR

Included in D-1501

I-1502

MTC INJECTOR

Included in D-1501

I-1503


Included in D-1501

I-1504


SPR-1501


(-0.3)


SPR-1502


(-0.3)

SPR-1503


(-1.4)

(-42.0)

(-43.4)

SPR-1504


(-1.4)

(-25.5)

(-26.9)

SPR-1505


(-1.4)

(-10.5)

(-11.9)

(0.3)

PAGE TOTAL

0

0.0

0.0

0.0

0.9

0.0

0.0

0.0

0.0

0.0

0.0

-1.0

0.0

0.0

0.1

GENERAL TOTAL

9455

-4202.4

-4488.8

123.4

-39.8

27.4

0.0

19.8

0.1

126.2

-283.7

-21.8

0.0

0.0

48.4

NOTES

_ _ _ __ RA| D __| N I ||___ (

S-015-1223-523-1.xls

7 2-20007 FEABR0273-M



10

APPROVED BY

MOTOR/LOAD RATING:


MECH. RUNNING LOAD:

MOTOR SHAFT POWER




REV



PETROVIETNAM

LOCATION

DUNG QUAT

PLANT CAPACITY

VIETNAM

SECTION No.

015 RFCC

CASE

UNIT

ITEM No.

DESCRIPTION


SLURRY SEPARATOR

X-1505


MOTOR LOAD/ RATING


9455

-4202.4

-4488.8

-230.0

-230.0


0.55

-0.40

-0.44

X-1507


491

-379.0

-379.0

88

(-53)

(-53)

(-270.0)

(-300.0)

X-1509

Doc. type

Code

Serial N°

Rev. index

8474L 015

CN

00 03

523

1

REVISION

P-1520

X-1508

Project N° - Unit

DESOX UNIT(FUTURE)


HP STM

MP STM

LP STM

HP COND

123.4

-39.8

27.4

0.0

DATE

SHEET


8

OF


LP BFW

COLD BFW

DW T/h DEMIN. WATER

LOSSES T/h

HP BFW

0.1

-283.7

-21.8

0.0

0.0

48.4

19.8

126.2

BFW T/h

-0.3

REMARKS



P-1502 A


0.55

-0.40

-0.44

P-1502 B


0.55

(-0.40)

(-0.44)

X-1510


6.05

-4.36

-4.84

X-1551


P-1557

ANTI-FOAMING PUMP

0.55

(-0.40)

(-0.44)

P-1558

ANTI-FOAMING PUMP

0.55

(-0.40)

(-0.44)

-3.3

EJ-1501


SV-1501


4.0

-3.0

SV-1502


4.0

-3.0

-3.3

SV-1503


4.0

-3.0

-3.3

SV-1504


4.0

-3.0

-3.3

PV-1501

PLUG VALVE

4.0

-3.0

-3.3

---

OIL MIST GENERATOR

3.0

-3.0

-3.0

---

STEAM TRACE

(0.9)

(-0.9)

0.1

-0.1

-2.0

2.0

PAGE TOTAL

611

-631.9

-634.1

0.0

0.0

-2.4

0.0

0.0

2.0

0.0

0.0

0.0

0.0

0.0

0.4


10066

-4834.3

-5123.0

123.4

-39.8

25.0

0.0

19.8

2.1

126.2

-283.7

-21.8

0.0

0.0

48.8


10066

-5104.3

-5423.0

123.4

-39.8

25.0

0.0

19.8

2.1

126.2

-283.7

-21.8

0.0

0.0

48.8

NOTES

_ _ _ __ RA| D __| N I ||___ (

S-015-1223-523-1.xls

7 2-20007 FEABR0273-M



10

APPROVED BY

MOTOR/LOAD RATING:


MECH. RUNNING LOAD:

MOTOR SHAFT POWER




REV



CLIENT

PETROVIETNAM

LOCATION

DUNG QUAT

PLANT CAPACITY

VIETNAM

SECTION No.

015 RFCC

CASE

UNIT

ITEM No.

Project N° - Unit

Doc. type

Code

Serial N°

Rev. index

8474L 015

CN

00 03

523

1

REVISION

COOLING WATER

DESCRIPTION

ΔT ºC

m3/h

E-1518


6.0

-19

E-1520 A-H


8.0

-1786

E-1531

SURFACE CONDENSER

E-1532

BLOWDOWN COOLER

13.0

-15

E-1533

BLOWDOWN COOLER

15.0

-24

E-1552 A/B


8.0

-245

E-1554 A-D

STRIPPER CONDENSER

6.0

-863

E-1559

GASOLINE COOLER

6.0

-156

E-1561 A/B


12.0

-1319

E-1562

LPG COOLER

6.0

-54

E-1564

LEAN OIL COOLER

6.0

-182

E-1565

FUEL GAS COOLER

6.0

-16

E-1566

LEAN AMINE COOLER

6.0

-72

E-1567

TURBINE CONDENSER

69,700 BPSD Mixed Crude Max Gasoline - Design Case SEA WATER ΔT ºC

m3/h

8.8

-7285

8.8

-2300

FRESH WATER T/h

DATE

SHEET


9


NITROGEN Nm3/h

S-015-1223-523-1.xls

7 2-20007 FEABR0273-M

(

CONTIN

INTERMIT

Efficiency %

FUEL FIRED MW

PUMP / COMP COOLING

-95

PAGE TOTAL

-4846

-9585

0

0

0

0

0

0

0.0

0.0

0.0

GENERAL TOTAL

-4846

-9585

0

0

0

0

0

0

0.0

0.0

0.0



10


NOTES

_ _ _ __ RA| D __| N I ||___

OF

APPROVED BY


REMARKS

REV



CLIENT

PETROVIETNAM

LOCATION

DUNG QUAT

PLANT CAPACITY

VIETNAM

SECTION No.

015 RFCC

CASE

UNIT

ITEM No.

Doc. type

Code

Serial N°

Rev. index

8474L 015

CN

00 03

523

1

REVISION

DESCRIPTION


m3/h -4846


69,700 BPSD Mixed Crude Max Gasoline - Design Case SEA WATER ΔT ºC

m3/h

FRESH WATER T/h

DATE

SHEET

WRITTEN BY 10

CHECKED BY


H-1502


H-1503

COB/WHB PACKAGE


FURNACES & BOILERS

INTERMIT

DUTY MW

X-1507 X-1504

X-1502


X-1503


C-1501

AIR BLOWER

-22

-3

-50

(-125)


-26

-8

(-85)

SLURRY SEPARATOR

-1

OIL MIST GENERATOR

-165 -3

-60

(-40)

(-3)

(-60)

(-40)

GLAND CONDENSER

-76

OIL COOLER

-32 -6

MAIN OIL COOLER

6.0

-60

GLAND CONDENSER

6.0

-50

PV-1501

PLUG VALVE

SV-1501


SV-1502


SV-1504


-134


-4230

REV

(-280)

-611 -84 -36

(2)

1

(-2320) -340

-160

(-560)

PAGE TOTAL

-221

0

0

-5658

-118

0

-351

0

0.0

0.0

-63.6

GENERAL TOTAL

-5067

-9585

0

-5658

-118

0

-351

0

0.0

0.0

-63.6

MISCELLANEOUS USERS

-13.7



REMARKS

-49.9

-71


7 2-20007 FEABR0273-M

FUEL FIRED MW

(1) 15.0

WET GAS COMPRESSOR

S-015-1223-523-1.xls

Efficiency %

(1)

-120

(

10

-9585


_ _ _ __ RA| D __| N I ||___

OF

APPROVED BY

H-1501

C-1551

Project N° - Unit



1



PETROVIETNAM

LOCATION

DUNG QUAT

PLANT CAPACITY

VIETNAM

SECTION No.

015 RFCC

CASE

UNIT



7 2-20007 FEABR0273-M

Code

Serial N°

Rev. index

CN

00 03

524

1

Op. Center JOB No.

0-3952-20-0000

Op. Center Doc. No.

S-015-1223-524

FEED Doc. No.

A

0

1

23-MAY-06

01-FEB-07

23-FEB-07

WRITTEN BY

T. Tsuchiya

T. Tsuchiya

T. Tsuchiya

Mixed Crude Max Distillate

CHECKED BY

M. Okada

M. Okada

M. Okada

- Design Case

APPROVED BY

M. Okada

M. Okada

M. Okada

DESCRIPTION

Issue for Review

For Construction

For Construction

2,4,10

Mixed Crude MD - Design

S-015-1223-524-1.xls

Doc. type

8474L 015

DATE

GENERAL NOTES:

_ _ _ __ RA| D __| N I ||___

X

Project N° - Unit

6960-015-DS-0711

SHEET

1

OF

10



PETROVIETNAM

LOCATION

DUNG QUAT

PLANT CAPACITY

VIETNAM

SECTION No.

015 RFCC

CASE

UNIT

ITEM No.

DESCRIPTION

MOTOR LOAD/ RATING


-0.3

-0.3

-443.0

-457.0

HP STM

MP STM

214.8

0.5


C-1502 B


(-13.8)


-1.1

1230


3

-3.0

-3.0

P-1529 A


55

-39.0

-43.3

P-1529 B


55

(-39.0)

(-43.3)

E-1531


-18.5

-20.6

15

-15.0

-15.0


-

TURNING GEAR MOTOR

C-1551

WET GAS COMPRESSOR

-1.5

-1.5


18.5

-13.9

-14.8

P-1559 B


18.5

(-13.9)

(-14.8)

E-1567


-16.0

-17.8


-


Serial N°

Rev. index

8474L 015

CN

00 03

524

1

HP COND

DATE

SHEET


2

OF

-77.9

-32.2


BFW T/h HP BFW

LP BFW

-221.0

-0.5

COLD BFW

DW T/h DEMIN. WATER

LOSSES T/h

REMARKS

1.1

-0.3

1

12.2 0.1

-0.1

77.9

0.3

32.2

0.4

(2.6)

-0.4

(2.1)

(-2.1)

-34.7

34.7


-


0.5

-0.5

D-1527

LP BLOWDOWN DRUM

0.5

-0.5

T-1503

LCO STRIPPER

-3.0

3.0

T-1504

HCO STRIPPER

-0.5

0.5

PAGE TOTAL

1462

-550.2

-573.3

103.6

-47.1

-2.6

0.0

12.2

0.1

110.1

-221.0

-0.5

0.0

0.0

45.2

GENERAL TOTAL

1462

-550.2

-573.3

103.6

-47.1

-2.6

0.0

12.2

0.1

110.1

-221.0

-0.5

0.0

0.0

45.2

NOTES

(

S-015-1223-524-1.xls

7 2-20007 FEABR0273-M



REV

6.2

D-1501

_ _ _ __ RA| D __| N I ||___

10

APPROVED BY

(13.8)

(-2.6)

P-1559 A

-

LP STM

-12.2

E-1534

-

Code

Included in H-1503

C-1501

-

69,700 BPSD Mixed Crude Max Distillate - Design Case STEAM T/h

H-1503

ECONOMIZER

Doc. type

REVISION

C-1502 A

E-1525

Project N° - Unit

MOTOR/LOAD RATING:


MECH. RUNNING LOAD:

MOTOR SHAFT POWER






PETROVIETNAM

LOCATION

DUNG QUAT

PLANT CAPACITY

VIETNAM

SECTION No.

015 RFCC

CASE

UNIT

ITEM No.

DESCRIPTION

Project N° - Unit

Doc. type

Code

Serial N°

Rev. index

8474L 015

CN

00 03

524

1

REVISION

MOTOR LOAD/ RATING



1462

-550.2

-573.3

P-1501 A

FEED PUMP

600

-476.0

-500.5

P-1501 B

FEED PUMP

600

(-476.0)

(-500.5)

P-1504 A

SLURRY PRODUCT PUMP

55

-42.7

-45.1

P-1504 B

SLURRY PRODUCT PUMP

55

(-42.7)

(-45.1)

P-1505 A

BACKFLUSH OIL PUMP

22

-15.0

-16.5

P-1505 B

BACKFLUSH OIL PUMP

22

(-15.0)

(-16.5)

P-1506 A


11

-7.4

-8.4

P-1506 B


11

(-7.4)

(-8.4)

P-1507 A

HCO RECYCLE PUMP

150

-128.0

-142.2

P-1507 B

HCO RECYCLE PUMP

150

(-128.0)

(-142.2)


HP STM

MP STM

LP STM

HP COND

103.6

-47.1

-2.6

0.0

DATE

SHEET

WRITTEN BY 3

CHECKED BY

OF


LP BFW

COLD BFW

DW T/h DEMIN. WATER

LOSSES T/h

HP BFW

12.2

0.1

-221.0

-0.5

0.0

0.0

45.2

110.1

BFW T/h

P-1508 A

HCO PUMPAROUND PUMP

220

-179.4

-188.4

P-1508 B

HCO PUMPAROUND PUMP

220

(-179.4)

(-188.4)

P-1509 A

HCO PRODUCT PUMP

15

-9.1

-10.1

P-1509 B

HCO PRODUCT PUMP

15

(-9.1)

(-10.1)

P-1510 A

LCO PUMPAROUND PUMP

335

-303.0

-316.0

P-1510 B

LCO PUMPAROUND PUMP

335

(-303.0)

(-316.0)

P-1511 A

LCO STRIPPER PUMP

90

-73.4

-76.9

P-1511 B

LCO STRIPPER PUMP

90

(-73.4)

(-76.9)

P-1512 A

MTC RECYCLE PUMP

75

0.0

0.0

P-1512 B

MTC RECYCLE PUMP

75

(0.0)

(0.0)

P-1513 A

LEAN OIL PUMP

75

-55.0

-58.1

P-1513 B

LEAN OIL PUMP

75

(-55.0)

(-58.1)

P-1514 A


225

-203.0

-213.9

P-1514 B


225

(-203.0)

(-213.9)

PAGE TOTAL

3746

-1492.0

-1576.1

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

GENERAL TOTAL

5208

-2042.2

-2149.4

103.6

-47.1

-2.6

0.0

12.2

0.1

110.1

-221.0

-0.5

0.0

0.0

45.2

REMARKS

NOTES

_ _ _ __ RA| D __| N I ||___ (

S-015-1223-524-1.xls

7 2-20007 FEABR0273-M



10

APPROVED BY

MOTOR/LOAD RATING:


MECH. RUNNING LOAD:

MOTOR SHAFT POWER




REV



PETROVIETNAM

LOCATION

DUNG QUAT

PLANT CAPACITY

VIETNAM

SECTION No.

015 RFCC

CASE

UNIT

ITEM No.

DESCRIPTION

Project N° - Unit

Doc. type

Code

Serial N°

Rev. index

8474L 015

CN

00 03

524

1

REVISION

MOTOR LOAD/ RATING



5208

-2042.2

-2149.4

P-1515 A


55

-39.4

-41.6

P-1515 B


55

(-39.4)

(-41.6)

P-1516 A


110

-96.0

-101.3 (-101.3)


HP STM

MP STM

LP STM

HP COND

103.6

-47.1

-2.6

0.0

DATE

SHEET


4

OF


LP BFW

COLD BFW

DW T/h DEMIN. WATER

LOSSES T/h

HP BFW

0.1

-221.0

-0.5

0.0

0.0

45.2

12.2

110.1

BFW T/h

P-1516 B


110

(-96.0)

P-1517 A


30

-25.5

-27.6

P-1517 B


30

(-25.5)

(-27.6)

P-1518 A


250

-206.0

-228.9

P-1518 B


250

(-206.0)

(-228.9)

P-1519 A


-10.3

P-1519 B


-10.3

10.3

P-1519 C


(-10.3)

(10.3)


-0.8

P-1521 A


-3.7

P-1521 B


110

(-80.9)

P-1522 A


30

-18.4

-19.9

P-1522 B


30

(-18.4)

(-19.9)

P-1526 A

LIGHT SLOPS PUMP

37

-26.1

-27.9

P-1526 B

LIGHT SLOPS PUMP

37

(-26.1)

(-27.9)

P-1527 A

HEAVY SLOPS PUMP

37

-27.9

-29.8

P-1527 B

HEAVY SLOPS PUMP

37

(-27.9)

(-29.8)

P-1528 A

TEMPERED WATER PUMP

15

-10.5

-11.7

P-1528 B

TEMPERED WATER PUMP

15

(-10.5)

(-11.7)

PAGE TOTAL

1238

-449.8

-488.7

-25.1

0.0

24.3

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.8

GENERAL TOTAL

6446

-2492.0

-2638.1

78.5

-47.1

21.7

0.0

12.2

0.1

110.1

-221.0

-0.5

0.0

0.0

46.0

REMARKS

(

S-015-1223-524-1.xls

7 2-20007 FEABR0273-M


0.8 3.7

(-84.4)


REV

10.3

NOTES

_ _ _ __ RA| D __| N I ||___

10

APPROVED BY

MOTOR/LOAD RATING:


MECH. RUNNING LOAD:

MOTOR SHAFT POWER




1



PETROVIETNAM

LOCATION

DUNG QUAT

PLANT CAPACITY

VIETNAM

SECTION No.

015 RFCC

CASE

UNIT

ITEM No.

DESCRIPTION

Project N° - Unit

Doc. type

Code

Serial N°

Rev. index

8474L 015

CN

00 03

524

1

REVISION

MOTOR LOAD/ RATING



HP STM

MP STM

LP STM

HP COND

78.5

-47.1

21.7

0.0


6446

-2492.0

-2638.1

P-1551 A


150

-134.0

-142.3

P-1551 B


150

(-134.0)

(-142.3)

P-1552 A

KO DRUM LIQUID PUMP

4

-1.2

-1.4

P-1552 B

KO DRUM LIQUID PUMP

4

(-1.2)

(-1.4)

P-1553 A

STRIPPER FEED PUMP

132

-112.0

-117.9

P-1553 B

STRIPPER FEED PUMP

132

(-112.0)

(-117.9)

P-1554 A


55

-44.0

-47.7

P-1554 B


55

(-44.0)

(-47.7)

DATE

SHEET


5

OF


0.1

110.1

LP BFW

COLD BFW

DW T/h DEMIN. WATER

LOSSES T/h

HP BFW

BFW T/h

-221.0

-0.5

0.0

0.0

46.0

P-1556 A


225

-185.0

-194.9

P-1556 B


225

(-185.0)

(-194.9)

P-1560 A


22

(-16.5)

(-18.1)

P-1560 B


22

(-16.5)

(-18.1)

P-1561


7.5

(-4.9)

(-5.4)

P-1562


7.5

(-4.9)

(-5.4)

P-1563


7.5

(-4.9)

(-5.4)

P-1564


15

(-10.8)

(-12.0)

PAGE TOTAL

1214

-476.2

-504.2

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

GENERAL TOTAL

7660

-2968.2

-3142.3

78.5

-47.1

21.7

0.0

12.2

0.1

110.1

-221.0

-0.5

0.0

0.0

46.0

REMARKS

NOTES

_ _ _ __ RA| D __| N I ||___ (

S-015-1223-524-1.xls

7 2-20007 FEABR0273-M



10

APPROVED BY

MOTOR/LOAD RATING:


MECH. RUNNING LOAD:

MOTOR SHAFT POWER




REV



PETROVIETNAM

LOCATION

DUNG QUAT

PLANT CAPACITY

VIETNAM

SECTION No.

015 RFCC

CASE

UNIT

ITEM No.

DESCRIPTION

Project N° - Unit

Doc. type

Code

Serial N°

Rev. index

8474L 015

CN

00 03

524

1

REVISION

MOTOR LOAD/ RATING



7660

-2968.2

-3142.3

E-1514

LCO AIR COOLER

120

-97.6

-106.2

E-1517


33

-20.4

-23.1

E-1519


960

-736.0

-800.9

E-1521


120

-99.6

-108.4

E-1530


22.5

-15.0

-17.8

E-1551


240

-190.4

-207.2


HP STM

MP STM

LP STM

HP COND

78.5

-47.1

21.7

0.0

DATE

SHEET


6

OF


0.1

110.1

LP BFW

COLD BFW

DW T/h DEMIN. WATER

LOSSES T/h

HP BFW -221.0

-0.5

0.0

0.0

46.0

BFW T/h

E-1553

HP CONDENSER

180

-134.4

-146.2

E-1558

GASOLINE AIR COOLER

120

-92.8

-101.0

E-1503


35.0

-36.1

1.1

E-1504


21.4

-22.1

0.7

E-1505


E-1506


E-1508


E-1510


2.8

E-1513


8.5

E-1518


16.1

1.2

14.4

-16.6

0.5

-1.2

0.0

-14.9

0.5

-2.8

0.0

-8.8

0.3

PAGE TOTAL

1796

-1386.2

-1510.8

56.4

30.5

12.5

0.0

0.0

0.0

0.0

-58.2

-44.3

0.0

0.0

3.1

GENERAL TOTAL

9455

-4354.4

-4653.1

134.9

-16.6

34.2

0.0

12.2

0.1

110.1

-279.2

-44.8

0.0

0.0

49.1

REMARKS

NOTES

_ _ _ __ RA| D __| N I ||___ (

S-015-1223-524-1.xls

7 2-20007 FEABR0273-M



10

APPROVED BY

MOTOR/LOAD RATING:


MECH. RUNNING LOAD:

MOTOR SHAFT POWER




REV



PETROVIETNAM

LOCATION

DUNG QUAT

PLANT CAPACITY

VIETNAM

SECTION No.

015 RFCC

CASE

UNIT

ITEM No.

DESCRIPTION


Project N° - Unit

Doc. type

Code

Serial N°

Rev. index

8474L 015

CN

00 03

524

1

REVISION




HP STM

MP STM

LP STM

HP COND

-4653.1

134.9

-16.6

34.2

0.0

-4354.4

DATE

SHEET


7

OF


LP BFW

COLD BFW

DW T/h DEMIN. WATER

LOSSES T/h

HP BFW

0.1

-279.2

-44.8

0.0

0.0

49.1

12.2

110.1

BFW T/h

REMARKS


E-1522


(-17.1)

E-1523


6.8

E-1524


E-1532

BLOWDOWN COOLER

E-1552 A/B


E-1554 A-D

STRIPPER CONDENSER

E-1559

GASOLINE COOLER

E-1561 A/B


E-1562

LPG COOLER

E-1564

LEAN OIL COOLER

(17.1)


-7.0

0.0

0.0

E-1565

FUEL GAS COOLER

E-1566

LEAN AMINE COOLER

I-1501

FEED INJECTOR

Included in D-1501

I-1502

MTC INJECTOR

Included in D-1501

I-1503


Included in D-1501

I-1504


SPR-1501


(-0.3)


SPR-1502


(-0.3)

SPR-1503


(-1.5)

(-31.1)

(-32.6)

SPR-1504


(-1.5)

(-19.2)

(-20.7)

SPR-1505


(-1.5)

(-9.7)

(-11.2)

(0.3)

PAGE TOTAL

0

0.0

0.0

0.0

6.8

0.0

0.0

0.0

0.0

0.0

0.0

-7.0

0.0

0.0

0.2

GENERAL TOTAL

9455

-4354.4

-4653.1

134.9

-9.8

34.2

0.0

12.2

0.1

110.1

-279.2

-51.8

0.0

0.0

49.3

NOTES

_ _ _ __ RA| D __| N I ||___ (

S-015-1223-524-1.xls

7 2-20007 FEABR0273-M



10

APPROVED BY

MOTOR/LOAD RATING:


MECH. RUNNING LOAD:

MOTOR SHAFT POWER




REV



PETROVIETNAM

LOCATION

DUNG QUAT

PLANT CAPACITY

VIETNAM

SECTION No.

015 RFCC

CASE

UNIT

ITEM No.

DESCRIPTION


SLURRY SEPARATOR

X-1505


MOTOR LOAD/ RATING


9455

-4354.4

-4653.1

-230.0

-230.0


0.55

-0.40

-0.44

X-1507


491

-379.0

-379.0

88

(-53)

(-53)

(-270.0)

(-300.0)

X-1509

Doc. type

Code

Serial N°

Rev. index

8474L 015

CN

00 03

524

1

REVISION

P-1520

X-1508

Project N° - Unit

DESOX UNIT(FUTURE)


HP STM

MP STM

LP STM

HP COND

134.9

-9.8

34.2

0.0

DATE

SHEET


8

OF


LP BFW

COLD BFW

DW T/h DEMIN. WATER

LOSSES T/h

HP BFW

0.1

-279.2

-51.8

0.0

0.0

49.3

12.2

110.1

BFW T/h

-0.3

REMARKS



P-1502 A


0.55

0.00

0.00

P-1502 B


0.55

(0.00)

(0.00)

X-1510


6.05

-4.36

-4.84

X-1551


P-1557

ANTI-FOAMING PUMP

0.55

(-0.40)

(-0.44)

P-1558

ANTI-FOAMING PUMP

0.55

(-0.40)

(-0.44)

-3.3

EJ-1501


SV-1501


4.0

-3.0

SV-1502


4.0

-3.0

-3.3

SV-1503


4.0

-3.0

-3.3

SV-1504


4.0

-3.0

-3.3

PV-1501

PLUG VALVE

4.0

-3.0

-3.3

---

OIL MIST GENERATOR

3.0

-3.0

-3.0

---

STEAM TRACE

(0.9)

(-0.9)

0.1

-0.1

-2.0

2.0

PAGE TOTAL

611

-631.5

-633.7

0.0

0.0

-2.4

0.0

0.0

2.0

0.0

0.0

0.0

0.0

0.0

0.4


10066

-4985.9

-5286.7

134.9

-9.8

31.8

0.0

12.2

2.1

110.1

-279.2

-51.8

0.0

0.0

49.7


10066

-5255.9

-5586.7

134.9

-9.8

31.8

0.0

12.2

2.1

110.1

-279.2

-51.8

0.0

0.0

49.7

NOTES

_ _ _ __ RA| D __| N I ||___ (

S-015-1223-524-1.xls

7 2-20007 FEABR0273-M



10

APPROVED BY

MOTOR/LOAD RATING:


MECH. RUNNING LOAD:

MOTOR SHAFT POWER




REV



CLIENT

PETROVIETNAM

LOCATION

DUNG QUAT

PLANT CAPACITY

VIETNAM

SECTION No.

015 RFCC

CASE

UNIT

ITEM No.

Project N° - Unit

Doc. type

Code

Serial N°

Rev. index

8474L 015

CN

00 03

524

1

REVISION

COOLING WATER

DESCRIPTION

ΔT ºC

m3/h

E-1518


6.0

-19

E-1520 A-H


8.0

-1675

E-1531

SURFACE CONDENSER

E-1532

BLOWDOWN COOLER

13.0

-15

E-1533

BLOWDOWN COOLER

15.0

-24

E-1552 A/B


8.0

-219

E-1554 A-D

STRIPPER CONDENSER

6.0

-684

E-1559

GASOLINE COOLER

6.0

-134

E-1561 A/B


12.0

-1154

E-1562

LPG COOLER

6.0

-43

E-1564

LEAN OIL COOLER

6.0

-195

E-1565

FUEL GAS COOLER

6.0

-8

E-1566

LEAN AMINE COOLER

6.0

-56

E-1567

TURBINE CONDENSER

69,700 BPSD Mixed Crude Max Distillate - Design Case SEA WATER ΔT ºC

m3/h

8.8

-7285

8.8

-2300

FRESH WATER T/h

DATE

SHEET


9


NITROGEN Nm3/h

S-015-1223-524-1.xls

7 2-20007 FEABR0273-M

(

CONTIN

INTERMIT

Efficiency %

FUEL FIRED MW

PUMP / COMP COOLING

-95

PAGE TOTAL

-4321

-9585

0

0

0

0

0

0

0.0

0.0

0.0

GENERAL TOTAL

-4321

-9585

0

0

0

0

0

0

0.0

0.0

0.0



10


NOTES

_ _ _ __ RA| D __| N I ||___

OF

APPROVED BY


REMARKS

REV



CLIENT

PETROVIETNAM

LOCATION

DUNG QUAT

PLANT CAPACITY

VIETNAM

SECTION No.

015 RFCC

CASE

UNIT

ITEM No.

Doc. type

Code

Serial N°

Rev. index

8474L 015

CN

00 03

524

1

REVISION

DESCRIPTION


m3/h -4321


69,700 BPSD Mixed Crude Max Distillate - Design Case SEA WATER ΔT ºC

m3/h

FRESH WATER T/h

DATE

SHEET

WRITTEN BY 10

CHECKED BY


H-1502


H-1503

COB/WHB PACKAGE


FURNACES & BOILERS

INTERMIT

DUTY MW

X-1507 X-1504

X-1502


X-1503


C-1501

AIR BLOWER

-22

-3

-50

(-125)


-26

-8

(-85)

SLURRY SEPARATOR

-1

OIL MIST GENERATOR

-165 -3

-60

(-40)

(-3)

(-60)

(-40)

GLAND CONDENSER

-76

OIL COOLER

-32 -6

MAIN OIL COOLER

6.0

-60

GLAND CONDENSER

6.0

-50

PV-1501

PLUG VALVE

SV-1501


SV-1502


SV-1504


-134


-4230

REV

(-280)

-611 -84 -36

(2)

1

(-2320) -340

-160

(-560)

PAGE TOTAL

-221

0

0

-5658

-118

0

-351

0

0.0

0.0

-92.6

GENERAL TOTAL

-4542

-9585

0

-5658

-118

0

-351

0

0.0

0.0

-92.6

MISCELLANEOUS USERS

-13.7



REMARKS

-78.9

-71


7 2-20007 FEABR0273-M

FUEL FIRED MW

(1) 15.0

WET GAS COMPRESSOR

S-015-1223-524-1.xls

Efficiency %

(1)

-120

(

10

-9585


_ _ _ __ RA| D __| N I ||___

OF

APPROVED BY

H-1501

C-1551

Project N° - Unit



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_ _ _ _ _ RA| D __| N I ||___ 0077 BR-2-20 A E F M 0276

匠d山適温首督

_ _ _ __ RA| D __| N I ||___ 7 2-20007 FEABR0276-M

︻H闇m一．−u山

感息首督

_ _ _ __ RA| D __| N I ||___ 7 2-20007 FEABR0276-M

U15 RFCC

015 RFCC Alarm/Trip SP List Tag No. 015-FI -601 015-FI -602 015-FI -603 015-FI -604 015-FI -605 015-FI -606 015-FI -607 015-PI -601 015-PI -604 015-PI -610 015-PI -612 015-PI -614 015-PI -616 015-PI -618 015-PI -645 015-PI -646 015-TI -601 015-TI -603 015-TI -604 015-TI -606 015-TI -608 015-TI -610 015-TI -628 015-FI -608 015-FI -609 015-FI -610 015-FI -611 015-FI -612 015-PI -622 015-PI -624 015-PI -626 015-PI -628 015-PI -630 015-TI -612 015-TI -614 015-TI -616 015-TI -618 015-TI -620

_ _ _ __ RA| D __| N I ||___ 007 AR-2 07-M

Service SEA WATER SUPPLY TO RFCC COOLING WATER SUPPLY TO RFCC SERVICE WATER TO RFCC DEMINERALIZED WATER TO RFCC NITROGEN TO RFCC INSTRUMENT AIR TO RFCC FUEL GAS TO RFCC SEA WATER SUPPLY TO RFCC COOLING WATER SUPPLY TO RFCC NITROGEN TO RFCC INSTRUMENT AIR TO RFCC PLANT AIR TO RFCC FUEL GAS TO RFCC FUEL OIL SUPPLY TO RFCC SERVICE WATER TO RFCC DEMINERALIZED WATER TO RFCC SEA WATER SUPPLY TO RFCC SEA WATER RETURN FROM RFCC COOLING WATER SUPPLY TO RFCC COOLING WATER RETURN FROM RFCC FUEL GAS TO RFCC FUEL OIL SUPPLY TO RFCC NITROGEN TO RFCC HP STEAM FROM/TO RFCC MP STEAM TO RFCC LP STEAM FROM RFCC HP BFW TO RFCC LP BFW TO RFCC HP STEAM FROM/TO RFCC MP STEAM TO RFCC LP STEAM FROM RFCC HP BFW TO RFCC LP BFW TO RFCC HP STEAM FROM/TO RFCC MP STEAM TO RFCC LP STEAM FROM RFCC HP BFW TO RFCC LP BFW TO RFCC

P&ID No 8474L-015-PID-0021-106 8474L-015-PID-0021-106 8474L-015-PID-0021-106 8474L-015-PID-0021-106 8474L-015-PID-0021-106 8474L-015-PID-0021-106 8474L-015-PID-0021-106 8474L-015-PID-0021-106 8474L-015-PID-0021-106 8474L-015-PID-0021-106 8474L-015-PID-0021-106 8474L-015-PID-0021-106 8474L-015-PID-0021-106 8474L-015-PID-0021-106 8474L-015-PID-0021-106 8474L-015-PID-0021-106 8474L-015-PID-0021-106 8474L-015-PID-0021-106 8474L-015-PID-0021-106 8474L-015-PID-0021-106 8474L-015-PID-0021-106 8474L-015-PID-0021-106 8474L-015-PID-0021-106 8474L-015-PID-0021-107 8474L-015-PID-0021-107 8474L-015-PID-0021-107 8474L-015-PID-0021-107 8474L-015-PID-0021-107 8474L-015-PID-0021-107 8474L-015-PID-0021-107 8474L-015-PID-0021-107 8474L-015-PID-0021-107 8474L-015-PID-0021-107 8474L-015-PID-0021-107 8474L-015-PID-0021-107 8474L-015-PID-0021-107 8474L-015-PID-0021-107 8474L-015-PID-0021-107

Page 1

Unit m3/Hr m3/Hr m3/Hr m3/Hr Nm3/Hr Nm3/Hr Nm3/Hr kg/cm2g kg/cm2g kg/cm2g kg/cm2g kg/cm2g kg/cm2g kg/cm2g kg/cm2g kg/cm2g degC degC degC degC degC degC degC kg/Hr kg/Hr kg/Hr m3/Hr m3/Hr kg/cm2g kg/cm2g kg/cm2g kg/cm2g kg/cm2g degC degC degC degC degC

Min 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

Max 14000 11000 60 .15 400 1400 19000 5 8 10 12 12 5 20 8 8 50 60 50 70 70 150 50 150000 42000 65000 350 120 70 25 6 100 40 600 400 250 200 200

LL Alarm L Alarm 5.9 6.3 2.7 11.7 1.3 -

H Alarm HH Alarm -

U15 RFCC

015 RFCC Alarm/Trip SP List Tag No. 015-FI -077-A 015-FI -077-B 015-FI -077-C 015-FI -078-A 015-FI -078-B 015-FI -078-C 015-FIC -003-A 015-FIC -003-B 015-FIC -003-C 015-FIC -003-D 015-FIC -003-E 015-FIC -003-F 015-FIC -005-A 015-FIC -005-B 015-FIC -005-C 015-FIC -005-D 015-FIC -005-E 015-FIC -005-F 015-FIC -007-A 015-FIC -007-B 015-FIC -007-C 015-FIC -007-D 015-FIC -010-A 015-FIC -010-B 015-FIC -010-C 015-FIC -010-D 015-FIC -011-A 015-FIC -011-B 015-FIC -011-C 015-FIC -011-D 015-FIC -077-A 015-FIC -077-B 015-FIC -077-C 015-FIC -078-A 015-FIC -078-B 015-FIC -078-C 015-FI -405 015-FIC -001

_ _ _ __ RA| D __| N I ||___ 007 AR-2 07-M

Service TORCH OIL TO 1ST REGEN D-1502 TORCH OIL TO 1ST REGEN D-1502 TORCH OIL TO 1ST REGEN D-1502 TORCH OIL TO 2ND REGEN(LWR)D-1503 TORCH OIL TO 2ND REGEN(LWR)D-1503 TORCH OIL TO 2ND REGEN(LWR)D-1503 PROCESS LIQ TO FEED INJEC I-1501A PROCESS LIQ TO FEED INJEC I-1501B PROCESS LIQ TO FEED INJEC I-1501C PROCESS LIQ TO FEED INJEC I-1501D PROCESS LIQ TO FEED INJEC I-1501E PROCESS LIQ TO FEED INJEC I-1501F MP STEAM TO FEED INJECTOR I-1501A MP STEAM TO FEED INJECTOR I-1501B MP STEAM TO FEED INJECTOR I-1501C MP STEAM TO FEED INJECTOR I-1501D MP STEAM TO FEED INJECTOR I-1501E MP STEAM TO FEED INJECTOR I-1501F MP STM TO STAB INJECTORS I-1503A MP STM TO STAB INJECTORS I-1503B MP STM TO STAB INJECTORS I-1503C MP STM TO STAB INJECTORS I-1503D PROC LIQ TO MTC INJECTOR I-1502A PROC LIQ TO MTC INJECTOR I-1502B PROC LIQ TO MTC INJECTOR I-1502C PROC LIQ TO MTC INJECTOR I-1502D MP STEAM TO MTC INJECTOR I-1502A MP STEAM TO MTC INJECTOR I-1502B MP STEAM TO MTC INJECTOR I-1502C MP STEAM TO MTC INJECTOR I-1502D TORCH OIL TO 1ST REGEN D-1502 TORCH OIL TO 1ST REGEN D-1502 TORCH OIL TO 1ST REGEN D-1502 TORCH OIL TO 2ND REGEN(LWR)D-1503 TORCH OIL TO 2ND REGEN(LWR)D-1503 TORCH OIL TO 2ND REGEN(LWR)D-1503 PROCESS LIQ TO STATIC MIXER M1501 PL FROM EXCHNG E-1524 & E-1501A/B


Page 2

Unit

Min

Max

m3/Hr m3/Hr m3/Hr m3/Hr m3/Hr m3/Hr kg/Hr kg/Hr kg/Hr kg/Hr kg/Hr kg/Hr kg/Hr kg/Hr kg/Hr kg/Hr m3/Hr m3/Hr m3/Hr m3/Hr kg/Hr kg/Hr kg/Hr kg/Hr kg/Hr kg/Hr kg/Hr kg/Hr kg/Hr kg/Hr

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

150 150 150 150 150 150 3500 3500 3500 3500 3500 3500 1000 1000 1000 1000 35 35 35 35 200 200 200 200 180 180 180 180 180 180

m3/Hr

0

700

LL Alarm L Alarm 58.9 58.9 58.9 58.9 58.9 58.9 2160 2160 2160 2160 2160 2160 558 558 558 558 20.6 20.6 20.6 20.6 132 132 132 132 275.4

H Alarm 2970 2970 2970 2970 2970 2970 -

HH Alarm -

U15 RFCC

015 RFCC Alarm/Trip SP List Tag No. 015-FIC -002 015-FXA -405 015-PI -001 015-PI -004 015-TI -001 015-TI -003 015-TI -004 015-TIC -002 015-FI -006-A 015-FI -006-B 015-FI -009 015-FIC -012 015-FIC -013 015-PDI -035-A 015-PDI -035-B 015-PDI -036-A 015-PDI -036-B 015-PI -008 015-TI -005 015-TI -006 015-TI -007 015-TI -008 015-TI -009 015-TI -010 015-TI -011 015-TI -031 015-TI -039 015-FIC -029 015-FIC -030 015-FIC -031 015-FIC -032 015-FIC -033 015-TI -013 015-TI -014 015-TI -016 015-TI -017 015-TI -018 015-TI -019

_ _ _ __ RA| D __| N I ||___ 007 AR-2 07-M

Service HCO RECYCLE FROM EXCHNG E-1508 PROCESS LIQ TO STATIC MIXER M1501 OUTLET OF STATIC MIXER M1501 SM TO FEED INJECTORS I-1501A-F PL FROM EXCHNG E-1524 & E-1501A/B OUTLET OF STATIC MIXER M1501 SM TO FEED INJECTORS I-1501A-F PL FROM EXCHNG E-1524 & E-1501A/B MP STEAM TO RISER BOTTOM RING MP STEAM TO RISER BOTTOM RING MTC FROM MTC RECY PUMP P-1512A/B OIL TO BACKFLUSH OIL INJEC I-1504 SM TO BACKFLUSH OIL INJEC I-1504 FG FROM FUEL GAS DRUM D-1509 FG FROM FUEL GAS DRUM D-1509 FG FROM FUEL GAS DRUM D-1509 FG FROM FUEL GAS DRUM D-1509 MTC FROM MTC RECY PUMP P-1512A/B STABILIZATION INJECTORS I-1503 SM TO BACKFLUSH OIL INJEC I-1504 SM TO STAB INJECOTRS I-1503A-D MIDLLE OF RISER MIDLLE OF RISER MP STEAM TO MTC INJECTOR I-1502 MP STEAM TO RISER BOTTOM RING MTC FROM MTC RECY PUMP P-1512A/B OIL TO BACKFLUSH OIL INJEC I-1504 MP STEAM TO FLUFFING RING D-1501 SM TO STRIPPER MAIN RING D-1501 SM TO UPPER STRIPPING RING D1501 PRE STRIPPING STM TO STRPR D-1501 ANTIKNOCKING STM TO STRPR D-1501 DISENGAGER/STRIPPER D-1501 DISENGAGER/STRIPPER D-1501 DISENGAGER/STRIPPER D-1501 DISENGAGER/STRIPPER D-1501 DISENGAGER/STRIPPER D-1501 DISENGAGER/STRIPPER D-1501


Page 3

Unit m3/Hr m3/Hr kg/cm2g kg/cm2g degC degC degC degC kg/Hr

0 0 0 0 0 0 0 0 0

Min

Max 200 900 25 25 450 450 400 450 800

m3/Hr m3/Hr kg/Hr kg/cm2

0 0 0 0

130 15 500 1

kg/cm2

0

.3

kg/cm2g degC degC degC degC degC degC degC degC degC kg/Hr kg/Hr kg/Hr kg/Hr kg/Hr degC degC degC degC degC degC

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

25 1000 350 350 900 900 400 350 360 450 3600 11500 5500 1500 1000 800 800 800 800 800 800

LL Alarm 282.9 -

L Alarm 124.4 11.9 12 160 160 250 82.3 6.6 220 11.9 220 160 220 220 173 2160 5600 2720 720 240 -

H Alarm 300 113.1 454 580 580 -

HH Alarm -

U15 RFCC

015 RFCC Alarm/Trip SP List Tag No. 015-TI -021 015-TI -022 015-TIC -015 015-TIC -020 015-LI -002 015-LI -003 015-LIC -002 015-LIC -003 015-PDI -064 015-PDI -065-A 015-PDI -065-B 015-PDI -066 015-PDI -067 015-PDI -070 015-PDI -393-A 015-PDI -393-B 015-PDXA -064 015-PIC -068 015-FI -021 015-PDI -088 015-PDI -103 015-PDI -104 015-PDIC -103 015-PDXA -104 015-FI -069-A 015-FI -069-B 015-FI -069-C 015-FI -073-A 015-FI -073-B 015-FIC -069-A 015-FIC -069-B 015-FIC -069-C 015-LI -004 015-LIC -004 015-PDI -134-A 015-PDI -134-B 015-PDI -135-A 015-PDI -135-B

_ _ _ __ RA| D __| N I ||___ 007 AR-2 07-M

Service DISENGAGER/STRIPPER D-1501 EFFLUENT TO FRACTIONATOR T-1501 DISENGAGER/STRIPPER D-1501 DISENGAGER/STRIPPER D-1501 DISENGAGER/STRIPPER D-1501 DISENGAGER/STRIPPER D-1501 DISENGAGER/STRIPPER D-1501 DISENGAGER/STRIPPER D-1501 FG FROM FUEL GAS DRUM D-1509 FG FROM FUEL GAS DRUM D-1509 FG FROM FUEL GAS DRUM D-1509 FG FROM FUEL GAS DRUM D-1509 FG FROM FUEL GAS DRUM D-1509 FG FROM FUEL GAS DRUM D-1509 GAS FROM FUEL GAS DRUM D-1509 GAS FROM FUEL GAS DRUM D-1509 FG FROM FUEL GAS DRUM D-1509 FG FROM FUEL GAS DRUM D-1509 NITROGEN TO SPENT CATALYST LINE FG FROM FUEL GAS DRUM D-1509 NITROGEN TO SPENT CATALYST LINE NITROGEN TO SPENT CATALYST LINE NITROGEN TO SPENT CATALYST LINE NITROGEN TO SPENT CATALYST LINE TORCH OIL TO 1ST REGEN D-1502 TORCH OIL TO 1ST REGEN D-1502 TORCH OIL TO 1ST REGEN D-1502 PA TO CAT DRAW OFF SYS X-1501 PA TO CAT DRAW OFF SYS X-1501 TORCH OIL TO 1ST REGEN D-1502 TORCH OIL TO 1ST REGEN D-1502 TORCH OIL TO 1ST REGEN D-1502 1ST REGENERATOR D-1502 1ST REGENERATOR D-1502 PA TO 1ST REGENERATOR D-1502 PA TO 1ST REGENERATOR D-1502 PA TO 1ST REGENERATOR D-1502 PA TO 1ST REGENERATOR D-1502


Page 4

Unit degC degC degC degC

0 0 0 0

Min

Max 800 800 800 800

% % kg/cm2 kg/cm2

0 0 0 0

.5

kg/cm2 kg/cm2 kg/cm2 kg/cm2

0 0 0 0

.5 .2 .3 .5

kg/cm2 kg/cm2g m3/Hr kg/cm2

0 0 0 0

.5 2 60 1

kg/cm2 kg/cm2 kg/cm2

0 0 0

1 1

Nm3/Hr

3.5

35

m3/Hr m3/Hr m3/Hr

0 0 0

4.5 4.5 4.5

% kg/cm2

0 0

100 .2

kg/cm2

0

.2

100 100

LL Alarm 0.15 0.07 -

L Alarm 30 40 0.2 0.2 0.06 0.09 0.2 20.8 0.4 0.15 14 40 -

H Alarm 528 70 60 0.3 0.3 0.14 0.21 30.9 60 -

HH Alarm -

U15 RFCC

015 RFCC Alarm/Trip SP List Tag No. 015-TI -025 015-TI -026 015-TI -027 015-TI -028 015-TI -029 015-FI -004 015-FI -070-A 015-FI -070-B 015-FI -071-A 015-FI -071-B 015-PDI -133-A 015-PDI -133-B 015-TI -023 015-TI -024 015-AI -004 015-AI -005 015-AI -006 015-LI -020 015-PDI -069 015-PI -147 015-PIC -146 015-TI -030 015-TI -032 015-TI -033 015-TI -034 015-TI -035 015-TI -036 015-TI -037 015-TI -038 015-AI -007 015-AI -008 015-AI -009 015-LI -005-AA 015-LI -005-AB 015-LI -005-BA 015-LI -005-BB 015-LI -005-CA 015-LI -005-CB

_ _ _ __ RA| D __| N I ||___ 007 AR-2 07-M

Service 1ST REGENERATOR D-1502 1ST REGENERATOR D-1502 1ST REGENERATOR D-1502 1ST REGENERATOR D-1502 CATALYST DRAW OFF SYSTEM X-1501 PA TO PLUG VALVE PV-1501 PA TO 1ST REGEN D-1502 PA TO 1ST REGEN D-1502 AIR FROM AIR BLOWER C-1501 AIR FROM AIR BLOWER C-1501 PA TO PLUG VALVE PV-1501 PA TO PLUG VALVE PV-1501 CAT FROM FRESH CAT FEEDER X-1502 CAT FROM AUX CAT FEEDER X-1503 FLUE GAS TO COB PACKAGE H-1503 FLUE GAS TO COB PACKAGE H-1503 FLUE GAS TO COB PACKAGE H-1503 FG DRUM, LEVEL D-1509 PA TO/FROM 1ST REGEN D-1502 PA TO 1ST REGENERATOR D-1502 PA TO 1ST REGENERATOR D-1502 FLUE GAS TO COB PACKAGE H-1503 FIRST REGENERATOR D-1502 FIRST REGENERATOR D-1502 FIRST REGENERATOR D-1502 FIRST REGENERATOR D-1502 FIRST REGENERATOR D-1502 FIRST REGENERATOR D-1502 1ST REGENERATOR D-1502 AVG TEMP FLUE GAS TO COB PACKAGE H-1503 FLUE GAS TO COB PACKAGE H-1503 FLUE GAS TO COB PACKAGE H-1503 2ND REGEN EXT CYCLONE CY-1504A 2ND REGEN EXT CYCLONE CY-1504A 2ND REGEN EXT CYCLONE CY-1504B 2ND REGEN EXT CYCLONE CY-1504B 2ND REGEN EXT CYCLONE CY-1504C 2ND REGEN EXT CYCLONE CY-1504C


Page 5

Unit degC degC degC degC degC m3/Hr Nm3/Hr

0 0 0 0 0 0 0

Min

Max 1000 1000 1000 1000 300 800 1000

Nm3/Hr

0

900

kg/cm2

0

.7

degC degC

0 0 0 0 0 % 0 kg/cm2 0 kg/cm2g 0 kg/cm2g 0 degC 0 degC 0 degC 0 degC 0 degC 0 degC 0 degC 0 degC 0 0 0 % 0

120 120 5 20 20 100 .3 4 4 1000 1000 1000 1000 1000 1000 1000

%

0

100

%

0

100

.5 30 5 100

LL Alarm L Alarm 620 620 620 620 36 220.1 0.07 630 630 630 630 630 630 -

H Alarm 720 720 720 720 250 880.6 794.8 100 100 16 3 710 710 710 710 710 710 710 0.4 -

HH Alarm 725 725 725 725 725 725 -

U15 RFCC

015 RFCC Alarm/Trip SP List Tag No. 015-LI -005-DA 015-LI -005-DB 015-LI -006-AA 015-LI -006-AB 015-LI -006-BA 015-LI -006-BB 015-LI -006-CA 015-LI -006-CB 015-LI -006-DA 015-LI -006-DB 015-LI -007 015-LIC -007 015-PDI -163-AA 015-PDI -163-AB 015-PDI -163-BA 015-PDI -163-BB 015-PDI -163-CA 015-PDI -163-CB 015-PDI -163-DA 015-PDI -163-DB 015-PDI -165 015-PI -175 015-TI -050 015-TI -052 015-TI -056 015-TI -058 015-TI -063 015-TI -064 015-FI -096-A 015-FI -096-B 015-FI -096-C 015-FI -097-A 015-FI -097-B 015-FIC -096-A 015-FIC -096-B 015-FIC -096-C 015-PDI -170-A 015-PDI -170-B

_ _ _ __ RA| D __| N I ||___ 007 AR-2 07-M

Service 2ND REGEN EXT CYCLONE CY-1504D 2ND REGEN EXT CYCLONE CY-1504D 2ND REGEN EXT CYCLONE CY-1504A 2ND REGEN EXT CYCLONE CY-1504A 2ND REGEN EXT CYCLONE CY-1504B 2ND REGEN EXT CYCLONE CY-1504B 2ND REGEN EXT CYCLONE CY-1504C 2ND REGEN EXT CYCLONE CY-1504C 2ND REGEN EXT CYCLONE CY-1504D 2ND REGEN EXT CYCLONE CY-1504D 2ND REGENERATOR D-1503 2ND REGENERATOR D-1503 2ND REGENERATOR D-1503 2ND REGENERATOR D-1503 2ND REGENERATOR D-1503 2ND REGENERATOR D-1503 2ND REGENERATOR D-1503 2ND REGENERATOR D-1503 2ND REGENERATOR D-1503 2ND REGENERATOR D-1503 2ND REGENERATOR D-1503 PA TO 2ND REGENERATOR D-1503 2ND REGENERATOR (UPPER) D-1503 2ND REGENERATOR (UPPER) D-1503 2ND REGENERATOR (UPPER) D-1503 2ND REGENERATOR (UPPER) D-1503 2ND REGENERATOR D-1503 AVG TEMP OUTLET OF 2ND REGENERATOR D-1503 TORCH OIL FROM MP STM HTR E-1524 TORCH OIL FROM MP STM HTR E-1524 TORCH OIL FROM MP STM HTR E-1524 AIR FROM AIR BLOWER C-1501 AIR FROM AIR BLOWER C-1501 TORCH OIL FROM MP STM HTR E-1524 TORCH OIL FROM MP STM HTR E-1524 TORCH OIL FROM MP STM HTR E-1524 PA TO 2ND REGEN (LOWER) D-1503 PA TO 2ND REGEN (LOWER) D-1503


Page 6

%

Unit 0

Min

Max 100

%

0

100

%

0

100

%

0

100

%

0

100

% kg/cm2

0 0

100 .4

kg/cm2

0

.4

kg/cm2

0

.4

kg/cm2

0

.4

kg/cm2 kg/cm2g degC degC degC degC degC degC

0 0 0 0 0 0

.3 3 1000 1000 1000 1000

0

1000

Nm3/Hr

0

1300

m3/Hr m3/Hr m3/Hr kg/cm2

0 0 0 0

4.5 4.5 4.5 .2

LL Alarm L Alarm 40 650 650 650 650 -

H Alarm 60 0.25 1.8 810 810 810 810 820 -

HH Alarm 830 830 830 830 -

U15 RFCC

015 RFCC Alarm/Trip SP List Tag No. 015-PDI -171-A 015-PDI -171-B 015-PDIC -172 015-PI -173 015-TI -046 015-TI -047 015-TI -048 015-TI -049 015-LI -008-A 015-LI -008-B 015-LI -009-A 015-LI -009-B 015-LI -010 015-LXA -010 015-PDI -241 015-PDI -242 015-PDI -243-A 015-PDI -243-B 015-PDI -247 015-PDIC -247 015-PDXA -242 015-PI -216 015-PI -217 015-PI -218 015-PI -219 015-PI -220 015-PI -221 015-PI -222 015-PI -223 015-PI -224 015-PI -225 015-PI -226 015-PI -227 015-PI -228 015-PI -229 015-PI -230 015-PI -231 015-PI -232

_ _ _ __ RA| D __| N I ||___ 007 AR-2 07-M

Service PA TO 2ND REGEN (LOWER) D-1503 PA TO 2ND REGEN (LOWER) D-1503 PA TO 2ND REGEN (LOWER) D-1503 PA TO 2ND REGEN (LOWER) D-1503 2ND REGENERATOR (LOWER) D-1503 2ND REGENERATOR (LOWER) D-1503 2ND REGENERATOR (LOWER) D-1503 2ND REGENERATOR (LOWER) D-1503 WITHDRAWAL WELL LEVEL WITHDRAWAL WELL LEVEL WITHDRAWAL WELL LEVEL WITHDRAWAL WELL LEVEL WITHDRAWAL WELL LEVEL WITHDRAWAL WELL LEVEL PA TO REGEN CATALYST STAND PIPE N2 TO REGEN CATALYST STAND PIPE PA TO REGEN CATALYST STAND PIPE PA TO REGEN CATALYST STAND PIPE N2 TO REGEN CATALYST STAND PIPE N2 TO REGEN CATALYST STAND PIPE N2 TO REGEN CATALYST STAND PIPE PA TO REGEN CATALYST STAND PIPE PA TO REGEN CATALYST STAND PIPE PA TO REGEN CATALYST STAND PIPE PA TO REGEN CATALYST STAND PIPE PA TO REGEN CATALYST STAND PIPE PA TO REGEN CATALYST STAND PIPE PA TO REGEN CATALYST STAND PIPE PA TO REGEN CATALYST STAND PIPE PA TO REGEN CATALYST STAND PIPE PA TO REGEN CATALYST STAND PIPE PA TO REGEN CATALYST STAND PIPE PA TO REGEN CATALYST STAND PIPE PA TO REGEN CATALYST STAND PIPE PA TO REGEN CATALYST STAND PIPE PA TO REGEN CATALYST STAND PIPE PA TO REGEN CATALYST STAND PIPE PLANT AIR TO WITHDRAWAL WELL


Page 7

Unit kg/cm2

0

Min .2

Max

kg/cm2 kg/cm2g degC degC degC degC %

0 0 0 0 0 0 0

1 3 1000 1000 1000 1000 100

%

0

100

% kg/cm2 kg/cm2 kg/cm2

0 0 0 0

100 .4

kg/cm2 kg/cm2 kg/cm2g kg/cm2g kg/cm2g kg/cm2g kg/cm2g kg/cm2g kg/cm2g kg/cm2g kg/cm2g kg/cm2g kg/cm2g kg/cm2g kg/cm2g kg/cm2g kg/cm2g kg/cm2g kg/cm2g

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

1 1 4 4 4 4 4 4 4 4 4 4 4 4 4 4 3 3 3

2

LL Alarm 10 0.07 -

L Alarm 0.15 650 650 650 650 30 30 0.15 -

H Alarm 810 810 810 810 70 1.8 2.6 -

HH Alarm -

U15 RFCC

015 RFCC Alarm/Trip SP List Tag No. 015-PI -233 015-PI -236 015-PI -238 015-PI -246 015-FI -020 015-FI -170 015-FI -171 015-FI -172 015-FIC -161 015-FIC -164 015-FIC -166 015-FIC -169 015-FXA -170 015-FXA -171 015-FXA -172 015-FYV -161 015-PDI -826 015-PDI -827 015-PDI -829 015-PDI -830 015-PI -800 015-PI -828 015-PI -834 015-PIC -311 015-TI -800 015-TI -819 015-TI -820 015-TI -821 015-FI -214 015-TI -067 015-TI -069 015-TIC -068 015-TXA -069 015-FI -213 015-PI -321 015-PXA -321 015-TI -070 015-TI -072

_ _ _ __ RA| D __| N I ||___ 007 AR-2 07-M

Service PLANT AIR TO WITHDRAWAL WELL PLANT AIR TO WITHDRAWAL WELL PLANT AIR TO WITHDRAWAL WELL N2 TO REGEN CATALYST STAND PIPE SH TO AIR BLOWER STM TURB ST1501 AIR TO 1ST REGEN AIR HTR H-1501 AIR TO 2ND REGEN AIR HTR H-1502 AIR TO 1ST REGEN D-1502 AIR TO 1ST REGEN AIR HTR H-1501 AIR TO 2ND REGEN AIR HTR H-1502 AIR TO 1ST REGEN D-1502 AIR FROM AIR BLOWER C-1501 AIR TO 1ST REGEN AIR HTR H-1501 AIR TO 2ND REGEN AIR HTR H-1502 AIR TO 1ST REGEN D-1502 AIR TO 1ST REGEN AIR HTR H-1501 SIGNAL TO ANTI SURGE CONTROLLER SIGNAL TO ANTI SURGE CONTROLLER AIRBLOWR C-1501 TO SURGE DETECTOR SIGNAL TO ANTI SURGE CONTROLLER SH TO AIR BLOWER STM TURB ST1501 SIGNAL TO ANTI SURGE CONTROLLER SIGNAL TO ANTI SURGE CONTROLLER AIR FROM AIR BLOWER C-1501 SH TO AIR BLOWER STM TURB ST1501 AR BLOWR C-1501 TO SURGE DETECTOR ARBLR C-1501 TO ANTI SURG CONTRLR AIR BLOWER C-1501 DISCHARGE LINE FG TO 1ST REGN AIR HEATER H-1501 COMB AIR TO 1ST REGEN D-1502 COMB AIR TO 1ST REGEN D-1502 COMB AIR TO 1ST REGEN D-1502 COMB AIR TO 1ST REGEN D-1502 FG TO 2ND REGEN AIR HTR H-1502 FG TO 2ND REGEN AIR HTR H-1502 FG TO 2ND REGEN AIR HTR H-1502 COMB AIR TO 2ND REGEN D-1503 COMB AIR TO 2ND REGEN D-1503


Page 8

Unit kg/cm2g kg/cm2g kg/cm2g kg/cm2g kg/Hr

Nm3/Hr Nm3/Hr Nm3/Hr Nm3/Hr Nm3/Hr Nm3/Hr Nm3/Hr m3/Hr kg/cm2 kg/cm2 kg/cm2 kg/cm2 kg/cm2g kg/cm2g kg/cm2g kg/cm2g

m3/Hr degC degC degC Nm3/Hr

Min 0 0 0 0 0

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

kg/cm2g 0 degC 0 0

Max 3 2 3 5 145000

260000 77000 51000 600 260000 77000 51000 11000

2 2 2 5

2200 800 800 800 700 10 800

LL Alarm 103830 31638 19009 3 -

L Alarm 34600 166128 50621 30414 211 2.9 874.2 266 -

H Alarm 2.1 1.8 228426 69603.6 45621.6 792 4 720 720 -

HH Alarm 740 -

U15 RFCC

015 RFCC Alarm/Trip SP List Tag No. 015-TIC -071 015-TXA -072 015-FI -187-A 015-FI -187-B 015-LI -013-A 015-LI -013-B 015-TI -073 015-TI -076 015-TI -083 015-FI -175-A 015-FI -175-B 015-FI -177-A 015-FI -177-B 015-FI -185-A 015-FI -185-B 015-FI -186-A 015-FI -186-B 015-LI -012-A 015-LI -012-B 015-TI -074 015-TI -075 015-TI -087 015-FI -176-A 015-FI -176-B 015-FI -183-A 015-FI -183-B 015-FI -184-A 015-FI -184-B 015-LI -011-A 015-LI -011-B 015-TI -079 015-TI -088 015-FI -025 015-FI -203 015-LI -015 015-PI -363 015-PI -364 015-PIC -365

_ _ _ __ RA| D __| N I ||___ 007 AR-2 07-M

Service COMB AIR TO 2ND REGEN D-1503 COMB AIR TO 2ND REGEN D-1503 PA TO SPENT CAT HOPPER D-1506 PA TO SPENT CAT HOPPER D-1506 SPENT CAT HOPPER D-1506 SPENT CAT HOPPER D-1506 SPENT CATALYST FROM D-1506 SPENT CAT HOPPER D-1506 SPENT CATALYST HOPPER D-1506 AIR FROM AIR BLOWER C-1501 AIR FROM AIR BLOWER C-1501 AIR FROM AIR BLOWER C-1501 AIR FROM AIR BLOWER C-1501 PA TO AUX CATALYST HOPPER D-1507 PA TO AUX CATALYST HOPPER D-1507 PA TO AUX CATALYST FEEDER X-1503 PA TO AUX CATALYST FEEDER X-1503 AUX CATALYST FEEDER D-1507 AUX CATALYST FEEDER D-1507 CATALYST TO AUX CAT FEEDER X-1503 AUX CATALYST FEEDER D-1507 AUXILLIARY CATALYST HOPPER D-1507 AIR FROM AIR BLOWER C-1501 AIR FROM AIR BLOWER C-1501 PA TO FRESH CAT HOPPER D-1505 PA TO FRESH CAT HOPPER D-1505 PA TO FRESH CAT FEEDER X-1502 PA TO FRESH CAT FEEDER X-1502 FRESH CATALYST HOPPER D-1505 FRESH CATALYST HOPPER D-1505 CAT TO FRESH CAT FEEDER X-1502 FRESH CATALYST HOPPER D-1505 NITROGEN TO FUEL GAS DRUM D-1509 FG FROM FUEL GAS DRUM D-1509 FUEL GAS DRUM D-1509 MP STEAM FROM MAIN HEADER MP STEAM FROM MAIN HEADER MP STEAM FROM MAIN HEADER


Page 9

Unit degC degC Nm3/Hr

0 0 0

Min

Max 800 800 2500

%

0

100

degC degC degC Nm3/Hr

0 0 0 0

600 600 1000 2700

Nm3/Hr

0

2700

Nm3/Hr

0

2500

Nm3/Hr

0

110

%

0

100

degC degC degC Nm3/Hr

0 0 0 0

120 600 1000 2700

Nm3/Hr

0

2500

Nm3/Hr

0

110

%

0

100

degC degC Nm3/Hr Nm3/Hr %

0 0 0 0 0

120 1000 850 1400 100

kg/cm2g 0 kg/cm2g 0

25 25

LL Alarm L Alarm 697 12 -

H Alarm 2318.8 80 410 200 80 100 200 80 100 200 1220.2 76.7 -

HH Alarm 740 -

U15 RFCC

015 RFCC Alarm/Trip SP List Tag No. 015-PIC -367 015-PXA -363 015-TI -077 015-FI -208-A 015-FI -208-B 015-PDIC -384 015-PI -380-A 015-PI -380-B 015-TI -084 015-TI -089-A 015-TI -089-B 015-TI -090 015-TIC -091 015-TXA -089-A 015-TXA -089-B 015-FI -204-A 015-FI -204-B 015-PDIC -375 015-PI -372-A 015-PI -372-B 015-TI -078 015-TI -080 015-TI -082-A 015-TI -082-B 015-TIC -081 015-TXA -082-A 015-TXA -082-B 015-AI -011 015-AI -012 015-AI -013 015-PI -386-A 015-PI -386-B 015-PI -389 015-TI -085 015-TI -086 015-TI -092 015-TXA -086 015-AI -018

_ _ _ __ RA| D __| N I ||___ 007 AR-2 07-M

Service FUEL GAS DRUM D-1509 MP STEAM FROM MAIN HEADER MP STEAM FROM MAIN HEADER BFD TO WATER SPRAYERS SPR-1503 BFD TO WATER SPRAYERS SPR-1503 SM TO WATER SPRAYERS SPR-1503 PA TO BLOCK/BYP VALVE BV-1501A/B PA TO BLOCK/BYP VALVE BV-1501A/B PG TO BLOCK/BYP VALVE BV-1501A/B FLUE GAS TO ESTATIC PPTOR X-1507 FLUE GAS TO ESTATIC PPTOR X-1507 FLUE GAS TO ESTATIC PPTOR X-1507 FLUE GAS TO ESTATIC PPTOR X-1507 FLUE GAS TO ESTATIC PPTOR X-1507 FLUE GAS TO ESTATIC PPTOR X-1507 BFD TO WATER SPRAYERS SPR-1504 BFD TO WATER SPRAYERS SPR-1504 SM TO WATER SPRAYERS SPR-1504 PA TO BLOCK/BYP VALVE BV-1502A/B PA TO BLOCK/BYP VALVE BV-1502A/B PG TO BLOCK/BYP VALVE BV-1502A/B FLUE GAS TO ESTATIC PPTOR X-1507 FLUE GAS TO ESTATIC PPTOR X-1507 FLUE GAS TO ESTATIC PPTOR X-1507 FLUE GAS TO ESTATIC PPTOR X-1507 FLUE GAS TO ESTATIC PPTOR X-1507 FLUE GAS TO ESTATIC PPTOR X-1507 FLUE GAS FROM COB PACKAGE H-1503 FLUE GAS FROM COB PACKAGE H-1503 FLUE GAS FROM COB PACKAGE H-1503 PA TO ESTATIC PPTOR X-1507 PA TO ESTATIC PPTOR X-1507 FLUE GAS TO ECONOMIZER E-1525 FLUE GAS FROM COB PACKAGE H-1503 FLUE GAS FROM COB PACKAGE H-1503 PG TO ESTATIC PPTOR X-1507 FLUE GAS FROM COB PACKAGE H-1503 FLUE GAS TO STACK SK-1501


Page 10

Unit kg/cm2g kg/cm2g degC m3/Hr m3/Hr kg/cm2 kg/cm2g

Min 0 0 0 0 0 0 0

degC

Max 10 25 400 60 60 1.5 .25

0 0 0 degC 0 degC 0 degC 0 degC 0 m3/Hr 0 m3/Hr 0 kg/cm2 0 kg/cm2g 0

550 550 550 550 35 35 1.5 .25

degC degC

1000 550

0 0 0 0 degC 0 degC 0 degC 0 0 0 0 kg/cm2g 0 kg/cm2g 0 degC 0 0 degC 0 degC 0 0

1000

550 550 550 .05 30 5 .25 .1 550 550 550 5

LL Alarm L Alarm 6.5/5.0 9 190 304 165 -

H Alarm 8 0.2 700 370 0.2 810 370 0.04 0.2 338 338 -

HH Alarm 390 390 400 400 390 -

U15 RFCC

015 RFCC Alarm/Trip SP List Tag No. 015-AI -019 015-AI -020 015-AI -021 015-FI -211-A 015-FI -211-B 015-PDIC -385 015-TI -093 015-TI -094 015-TI -098 015-TI -099 015-TIC -100 015-TXA -098-A 015-TXA -098-B 015-LI -301 015-LI -303 015-PI -357 015-PIC -371 015-FI -404 015-FIC -402 015-FIC -403 015-LI -403 015-LI -404-A 015-LI -404-B 015-LI -404-C 015-LI -406 015-LIC -402 015-LXA -403 015-LXA -404-A 015-LXA -404-B 015-LXA -404-C 015-PIC -403 015-TI -401 015-TI -402 015-TI -403 015-FIC -409 015-FIC -410 015-FIC -411 015-PI -408

_ _ _ __ RA| D __| N I ||___ 007 AR-2 07-M

Service FLUE GAS TO STACK SK-1501 FLUE GAS TO STACK SK-1501 FLUE GAS TO STACK SK-1501 BFD TO WATER SPRAYERS SPR-1505 BFD TO WATER SPRAYERS SPR-1505 SM TO WATER SPRAYERS SPR-1505 FLUE GAS TO ECONOMIZER E-1525 FLUE GAS FROM ECONOMIZER E-1525 FLUE GAS TO DESOX UNIT X-1508 FLUE GAS TO DESOX UNIT X-1508 FLUE GAS TO DESOX UNIT X-1508 FLUE GAS TO DESOX UNIT X-1508 FLUE GAS TO DESOX UNIT X-1508 CO BLR FUEL GAS KO DRUM D-1526 AIR HTR FUEL GAS KO DRUM D-1525 FUEL GAS TO COB PACKAGE H-1503 FG TO AIR HTR FG KO DRUM D-1525 FEED FROM PUMP P-1501A/B COLD RESIDUE TO FSD D-1513 FEED FROM PUMP P-1501A/B FEED SURGE DRUM D-1513 FEED SURGE DRUM D-1513 FEED SURGE DRUM D-1513 FEED SURGE DRUM D-1513 FEED SURGE DRUM D-1513 FEED SURGE DRUM D-1513 FEED SURGE DRUM D-1513 FEED SURGE DRUM D-1513 FEED SURGE DRUM D-1513 FEED SURGE DRUM D-1513 FREE DRAINING TO FSD D-1513 HOT RESIDUE TO FSD D-1513 COLD RESIDUE TO FSD D-1513 FREE DRAIN TO FEED PUMP P-1501A/B LCO TO MAIN FRACTIONATOR T-1501 SM TO MP STEAM FEED HTR E-1522 SH TO HP STEAM FEED HTR E-1524 PL TO MP STEAM FEED HTR E-1522


Page 11

Unit ppmv ppmv % m3/Hr m3/Hr kg/cm2 degC degC

0 0 0 0 0 0 0 0 0 degC 0 degC 0 degC 0 degC 0 % 0 % 0 kg/cm2g 0 kg/cm2g 0 m3/Hr 0 m3/Hr 0 m3/Hr 0

Min

Max 2000 500 100 35 35 1.5 550 400 400 400 400 400 400 100 100 5 10 600 600 600

% % % % % % kg/cm2g degC degC degC m3/Hr kg/Hr kg/Hr kg/cm2g

100 100 100 100 100 100 2.5 200 100 200 650 24000 28000 30

0 0 0 0 0 0 0 0 0 0 0 0 0 0

LL Alarm 182 76.9 -

L Alarm 294 226 2.7 191.1 28.4 0.5 213.4 -

H Alarm 338 257 257 80 80 81.6 87.5 2 125 -

HH Alarm 390 390 50 50 50 -

U15 RFCC

015 RFCC Alarm/Trip SP List Tag No. 015-TI -408 015-TI -409 015-TI -410 015-TI -420 015-TIC -411 015-FIC -407 015-FIC -408 015-PI -409 015-TI -421 015-TI -423 015-FI -539 015-FIC -406 015-FIC -501 015-PIC -410 015-TI -414 015-TI -422 015-FI -413 015-FIC -412 015-FIC -414 015-TI -427 015-TI -428 015-TI -429 015-TIC -430 015-FI -416 015-FI -490-A 015-FI -490-B 015-FIC -415 015-LI -408 015-LIC -408 015-PDIC -420 015-TI -426 015-TIC -425 015-FIC -417 015-FIC -418 015-TI -432 015-TI -434 015-FI -422 015-FIC -419

_ _ _ __ RA| D __| N I ||___ 007 AR-2 07-M

Service PL TO MP STEAM FEED HTR E-1522 PL TO HP STEAM FEED HTR E-1524 FEED TO EXCHANGER E-1502A/B LCO TO MAIN FRACTIONATOR T-1501 FEED TO EXCHANGER E-1502A/B SLRY TO MAIN FRACTIONATOR T-1501 SLRY TO MAIN FRACTIONATOR T-1501 FEED FROM HP STM FEED HTR E-1524 FEED TO EXCHANGER E-1501A/B SLRY TO MAIN FRACTIONATOR T-1501 FLOW SIGNALS TO UY-405 SLRY TO MAIN FRACTIONATOR T-1501 SLRY TO MAIN FRACTIONATOR T-1501 PROC LIQ TO STATIC MIXER M-1501 PL TO STATIC MIXER M-1501 SLRY TO MAIN FRACTIONATOR T-1501 NAPHTHA FROM PUMP P-1514A/B NAPHTHA FROM PUMP P-1514A/B HVN FROM HVN PUMPAROUND CLR E1521 HVN FROM HVN PUMPAROUND CLR E1521 HVN TO MAIN FRACTIONATOR T-1501 HVN TO MAIN FRACTIONATOR T-1501 HVN TO MAIN FRACTIONATOR T-1501 SM FROM MP STEAM GEN E-1508 HCO TO MAIN FRACTIONATOR T-1501 HCO TO MAIN FRACTIONATOR T-1501 BFD TO MP STEAM GEN E-1508 HCO RECYCLE MP STEAM GEN E-1508 HCO RECYCLE MP STEAM GEN E-1508 HCO TO STATIC MIXER M-1501 HCO TO STATIC MIXER M-1501 HCO TO STATIC MIXER M-1501 LCO TO STRIPPER 2ND REBLR E-1557 LCO FROM LCO PA BFW HTR E-1511 LCO FROM LCO PA BFW HTR E-1511 BFB TO SLRY HP STMGEN E-1503A/B/C SM FROM MP STMGEN E-1523 HCO FROM PUMP P-1508A/B


Page 12

Unit degC degC degC degC degC m3/Hr m3/Hr kg/cm2g degC degC m3/Hr m3/Hr m3/Hr kg/cm2g degC degC m3/Hr m3/Hr m3/Hr degC degC degC degC kg/Hr m3/Hr

Min

0 0 0 0 0 0 0 0 0 0 0 0 0 0

Max 250 300 300 250 300 350 250 30 400 400 230 220 230 25 450 500 400 1000 650 150 200 200 200 21000 80

m3/Hr

0

20

% kg/cm2 degC degC m3/Hr m3/Hr degC degC kg/Hr m3/Hr

0 0 0 0 0 0 0 0 0 0

100 2 350 350 1500 350 250 200 11000 900

0 0 0 0 0 0 0 0 0 0

LL Alarm L Alarm 211.4 167.4 181.2 90.6 90.6 13.6 362.8 20 90 41.6 280 527.9 109 -

H Alarm 290.6 230.1 20 280 199.3 199.3 16.6 300 120 130 58.4 300 -

HH Alarm -

U15 RFCC

015 RFCC Alarm/Trip SP List Tag No. 015-FIC -420 015-FIC -421 015-LI -410 015-LIC -410 015-TI -435 015-FIC -427 015-LIC -416 015-PI -435 015-TI -444 015-TI -445 015-TI -447 015-TI -448 015-TI -449 015-TI -450 015-TI -451 015-TI -453 015-TI -455 015-TI -456 015-TI -457 015-TI -458 015-TI -459 015-TI -460 015-TI -526 015-TI -527 015-TIC -446 015-TIC -452 015-TIC -454 015-TIC -461 015-LI -411-A 015-LI -411-B 015-LI -414 015-LIC -411 015-LXA -414 015-PI -430 015-PI -434 015-TI -436 015-TI -437 015-TI -438

_ _ _ __ RA| D __| N I ||___ 007 AR-2 07-M

Service HCO FROM MP STMGEN E-1523 BFD TO MP STMGEN E-1523 HCO PUMPAROUND MP STMGEN E-1523 HCO PUMPAROUND MP STMGEN E-1523 HCO FROM MP STMGEN E-1523 OVRHD REFLUX FROM PUMP P-1516A/B MAIN FRACTIONATOR TWR T-1501 MAIN FRACTIONATOR TOWER T-1501 HCO FROM MAIN FRACTIONATOR T-1501 HCO FROM MP STMGEN E-1523 MAIN FRACTIONATOR TOWER T-1501 MAIN FRACTIONATOR TOWER T-1501 LCO FROM MAIN FRACTIONATOR T-1501 MAIN FRACTIONATOR TOWER T-1501 LCO FROM LCO PA BFW HTR E-1511 MTC TO PUMPS P-1512A/B MAIN FRACTIONATOR TOWER T-1501 HVN TO HVN PUMPS P-1514 A/B MAIN FRACTIONATOR TOWER T-1501 SOW TO OVRHD AIR CONDNSR E-1519 MAIN FRACTIONATOR TOWER T-1501 OVRHD FRM MAIN FRACTIONATOR T1501 MAIN FRACTIONATOR TOWER T-1501 MAIN FRACTIONATOR TOWER T-1501 HCO FROM MP STMGEN E-1523 LCO FROM LCO PA BFW HTR E-1511 MAIN FRACTIONATOR TOWER T-1501 OVRHD FRM MAIN FRACTIONATOR T1501 SIDE MAIN FRACTIONATOR TWR T-1501 SIDE MAIN FRACTIONATOR TWR T-1501 SIDE MAIN FRACTIONATOR TWR T-1501 SIDE MAIN FRACTIONATOR TWR T-1501 SIDE MAIN FRACTIONATOR TWR T-1501 SIDE MAIN FRACTIONATOR TWR T-1501 MAIN FRACTIONATOR TOWER T-1501 SIDE MAIN FRACTIONATOR TWR T-1501 SIDE MAIN FRACTIONATOR TWR T-1501 SLRY FRM MAIN FRACT TWR T-1501


Page 13

Unit m3/Hr m3/Hr

0 0

Min

Max 100 12

% degC m3/Hr % kg/cm2g degC degC degC degC degC degC degC degC degC degC degC degC degC degC degC degC degC degC degC degC % %

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

100 350 350 100 2 500 350 500 500 350 500 250 60 350 250 250 150 250 150 350 350 350 250 350 150 100 100

% % kg/cm2g kg/cm2g degC degC degC

0 0 0 0 0 0 0

100 100 2 2 800 800 550

LL Alarm 7.89 -

L Alarm 41.6 144.2 0.5 16 95 35 0.9 -

H Alarm 58.4 76 1.4 110 80 1.7 1.3 -

HH Alarm -

U15 RFCC

015 RFCC Alarm/Trip SP List Tag No. 015-TI -440 015-TI -441 015-TI -442 015-TI -528 015-TIC -439 015-TIC -443 015-FI -423 015-FI -432 015-FI -434 015-FIC -428 015-FIC -429 015-FIC -431 015-FIC -433 015-LI -418 015-LI -420 015-LIC -418 015-LIC -420 015-TI -462 015-TI -463 015-FI -436 015-FIC -424 015-FIC -425 015-FIC -430 015-FIC -435 015-LI -422 015-LIC -422 015-TI -464 015-TI -465 015-FI -444 015-FI -448 015-FIC -438 015-FIC -443 015-FIC -447 015-LI -426 015-LI -430 015-LIC -426 015-LIC -430 015-TI -468

_ _ _ __ RA| D __| N I ||___ 007 AR-2 07-M

Service SLRYQUENCHING TO MAIN FRCT T-1501 SLRY PA RETRN TO MAIN FRCT T-1501 MAIN FRACTIONATOR TOWER T-1501 MAIN FRACTIONATOR TOWER T-1501 SLRY FRM MAIN FRACT TWR T-1501 MAIN FRACTIONATOR TOWER T-1501 SLURRY FROM PUMPS P-1519 A/B/C HP STEAM FRM STEAM GEN E-1503A HP STEAM FRM STEAM GEN E-1503B SLURRY RTN FRM STEAM GEN E-1503A SLURRY RTN FRM STEAM GEN E-1503B BFW TO STEAM GENERATOR E-1503A BFW TO STEAM GENERATOR E-1503B SLURRY HP STEAM GEN E-1503A SLURRY HP STEAM GEN E-1503B SLURRY HP STEAM GEN E-1503A SLURRY HP STEAM GEN E-1503B SLURRY RTN FRM STEAM GEN E-1503A SLURRY RTN FRM STEAM GEN E-1503B HP STEAM FROM STMGEN E-1503C SLRY FRM SLRY HP STMGEN E-1503A/B SLRY FRM SLRY HP STMGEN E-1503A/B SLRY RTN FRM HP STMGEN E-1503C BFB TO HP STEAM GENERATOR E-1503C SLURRY HP STEAM GEN E-1503C SLURRY HP STEAM GEN E-1503C SLRY RTN FRM HP STM GEN E-1503C SLRY FRM SLRY MP STMGEN E-1503A/B SAT HP STM FROM HP STMGEN E-1504A SAT MP STM FROM MP STMGEN E-1505A SLURRY FROM MP STMGEN E-1505A BFW TO HP STMGEN E-1504A BFD TO MP STEAM GENERATOR E-1505A HP STEAM GENERATOR E-1504A MP STEAM GENERATOR E-1505A HP STEAM GENERATOR E-1504A MP STEAM GENERATOR E-1505A SH TO SLRY PUMPAROUND PMP P-1519C


Page 14

Unit degC degC degC degC degC degC m3/Hr kg/Hr kg/Hr m3/Hr m3/Hr m3/Hr m3/Hr

0 0 0 0 0 0 0 0 0 0 0 0 0

Min

Max 400 400 500 600 550 500 1700 22000 22000 350 350 25 25

% % degC degC kg/Hr m3/Hr m3/Hr m3/Hr m3/Hr

0 0 0 0 0 0 0 0 0

100 100 400 400 22000 300 750 350 25

% degC degC kg/Hr kg/Hr m3/Hr m3/Hr m3/Hr

0 0 0 0 0 0 0 0

100 400 400 16000 12000 220 18 13

% % degC

0 0 0

100 100 1000

LL Alarm L Alarm 665.6 121.8 121.8 41.6 41.6 70.4 285.3 121.8 41.6 80.6 41.6 41.6 -

H Alarm 380 350 58.4 58.4 58.4 193.5 58.4 58.4 -

HH Alarm -

U15 RFCC

015 RFCC Alarm/Trip SP List Tag No. 015-TI -469 015-FI -442 015-FI -446 015-FIC -426 015-FIC -437 015-FIC -439 015-FIC -440 015-FIC -441 015-FIC -445 015-LI -424 015-LI -428 015-LIC -424 015-LIC -428 015-TI -466 015-TI -467 015-TI -470 015-FI -451 015-FIC -449 015-FIC -450 015-FIC -474 015-LI -432 015-LI -435 015-LIC -431 015-LIC -435 015-LXA -432 015-PIC -447 015-TI -471 015-TI -472 015-TI -473 015-TIC -474 015-FIC -454 015-LI -440 015-LIC -439 015-LXA -440 015-TI -477 015-TI -478 015-TI -482 015-TI -483

_ _ _ __ RA| D __| N I ||___ 007 AR-2 07-M

Service SH TO HCO FLUSH OIL PUMP P-1521A SAT HP STM FROM HP STMGEN E-1504B SAT MP STM FROM MP STMGEN E-1505B SLURRY PA SUPPLY FRM P-1519A/B/C SLURRY FROM MP STMGEN E-1505B SLURRY FROM MP STMGEN E-1505A SLURRY FROM MP STMGEN E-1505A BFW TO SLURRY HP STMGEN E-1504B BFD TO MP STEAM GENERATOR E-1505B SLURRY HP STEAM GENERATOR E-1504B SLURRY MP STEAM GENERATOR E-1505B SLURRY HP STEAM GENERATOR E-1504B SLURRY MP STEAM GENERATOR E-1505B SH TO SLRY PUMPAROUND PMP P-1519A SH TO SLRY PUMPAROUND PMP P-1519B SLURRY FROM MP STMGEN E-1505A SL FROM HCO LP STMGEN E-1510 SL TO HCO STRIPPER T-1504 BFD TO HCO LP STEAM GEN E-1510 HCO FRM HCO PRODUCT PUMP P1509A/B HCO STRIPPER TOWER T-1504 HCO LP STEAM GEN E-1510 HCO STRIPPER TOWER T-1504 HCO LP STEAM GEN E-1510 HCO STRIPPER TOWER T-1504 SL FROM HCO LP STMGEN E-1510 HCO FRM STRIPPER TWR OVHD T-1504 PL FRM HCO STRIPPER BOTTOM T-1504 HCO FRM HCO LP STMGEN E-1510 HCO FRM HCO LP STMGEN E-1510 HCO TO STRIPPER REBLR E-1509 HVY NAPHTHA STRPR TWR T-1502 HVY NAPHTHA STRPR TWR T-1502 HVY NAPHTHA STRPR TWR T-1502 PG OVRHD FROM HVN STRIPPER T-1502 PL FRM STRPR TWR BOTTOM T-1502 PZ FROM HVN STRIPPER T-1502 HCO FRM HVN STRPR REBLR E-1509


Page 15

Unit degC kg/Hr kg/Hr m3/Hr m3/Hr m3/Hr m3/Hr m3/Hr m3/Hr

0 0 0 0 0 0 0 0 0

Min

Max 1000 16000 12000 500 220 350 170 18 13

% % degC degC degC kg/Hr kg/Hr m3/Hr m3/Hr

0 0 0 0 0 0 0 0 0

100 100 1000 1000 350 6500 650 7 50

% % % kg/cm2g degC degC degC degC m3/Hr

0 0 0 0 0 0 0 0 0

100 100 100 8 500 500 250 250 80

% % degC degC degC degC

0 0 0 0 0 0

100 100 300 350 350 400

LL Alarm L Alarm 41.8 80.6 41.6 41.6 37.1 41.6 6.5 32.8 30 5 -

H Alarm 459.7 58.4 58.4 230 80.6 58.4 7 190 190 82.5 -

HH Alarm -

U15 RFCC

015 RFCC Alarm/Trip SP List Tag No. 015-TI -484 015-FI -478-A 015-FI -478-B 015-FIC -452 015-LI -437 015-LIC -436 015-LXA -437 015-TI -475 015-TI -476 015-TI -489 015-TI -536 015-FI -457 015-FI -458 015-FI -477-A 015-FI -477-B 015-FIC -455 015-FIC -456 015-FIC -459 015-LI -444 015-LI -447 015-LIC -443 015-LIC -446 015-LXA -444 015-LXA -447 015-PIC -456 015-PIC -458 015-TI -490 015-TI -491 015-TI -492 015-FIC -462 015-LI -450 015-LI -478 015-LIC -448 015-LXA -450 015-LXA -478 015-PIC -468 015-TI -494 015-FI -466

_ _ _ __ RA| D __| N I ||___ 007 AR-2 07-M

Service BFW FROM HVN BFW HEATER E-1516 LCO STRIPPER T-1503 MIDDLE LCO STRIPPER T-1503 MIDDLE SL FRM LCO STRIPPER TWR T-1503 SIDE LCO STRIPPER TOWER T-1503 SIDE LCO STRIPPER TOWER T-1503 SIDE LCO STRIPPER TOWER T-1503 LCO FROM LCO STRPR OVHD T-1503 LCO FROM LCO STRPR BOTTOM T-1503 PZ FRM TRM CONDNSR E-1520 BAY A-H PZ FRM AIR CONDNSR E-1519 BAY A-P PG TO REFLUX DRUM D-1514 PG TO REFLUX DRUM D-1514 FRACTIONATOR REFLUX DRUM D-1514 FRACTIONATOR REFLUX DRUM D-1514 PL FRM OVHD LIQUID PMP P-1518A/B SOW FROM OVHD SOW PUMP P-1517A/B SOW FROM OVHD SOW PUMPS P-1517A/B SHELL FRCTNTR REFLUX DRUM D-1514 BOOT FRCTNTR REFLUX DRUM D-1514 SHELL FRCTNTR REFLUX DRUM D-1514 BOOT FRCTNTR REFLUX DRUM D-1514 SHELL FRCTNTR REFLUX DRUM D-1514 BOOT FRCTNTR REFLUX DRUM D-1514 FRCTNTR REFLUX DRUM D-1514 FRACTIONATOR REFLUX DRUM D-1514 OFF GAS FROM FRCTNTR DRUM D-1514 PG TO REFLUX DRUM D-1514 PG TO REFLUX DRUM D-1514 SLRY TO DRAWOFF DRUM INLET D-1515 SIDE SLRY DRAWOFF DRUM D-1515 SIDE SLRY DRAWOFF DRUM D-1515 SIDE SLRY DRAWOFF DRUM D-1515 SIDE SLRY DRAWOFF DRUM D-1515 SIDE SLRY DRAWOFF DRUM D-1515 TOP SLRY DRAWOFF DRUM D-1515 SLRY FRM DRAWOFF DRUM BOT D-1515 SL FRM SLRY LP STM GEN E-1506A/B


Page 16

Unit degC Nm3/Hr

0 0

Min

Max 200 1000

kg/Hr

0

3700

% % degC degC degC degC Nm3/Hr Nm3/Hr Nm3/Hr

0 0 0 0 0 0 0 0 0

100 100 350 350 70 100 1800 180 1000

m3/Hr m3/Hr m3/Hr

0 0 0

250 45 40

% % % % kg/cm2g kg/cm2g degC degC degC m3/Hr

0 0 0 0 0 0 0 0 0 0

100 100 100 100 .6 .8 70 60 80 40

% % % kg/cm2g degC kg/Hr

0 0 0 0 0 0

100 100 100 2.5 350 2000

LL Alarm 4.4 14.6 5.6 5.1 -

L Alarm 1500 33.8 102.5 15.1 50.5 39.3 0.2 30.4 0.5 -

H Alarm 83 47 65 86.4 81.5 0.6 36.5 86.8 2 -

HH Alarm 94 96 75 -

U15 RFCC

015 RFCC Alarm/Trip SP List Tag No. 015-FIC -465 015-LI -452-A 015-LI -452-B 015-LI -452-C 015-LIC -452 015-PIC -473 015-TI -495 015-TIC -496 015-FIC -460 015-FIC -463 015-FIC -464 015-PDI -376 015-PDI -398 015-PI -495 015-TI -497 015-TI -498 015-TI -499 015-FIC -491 015-LI -458 015-LI -459 015-LIC -456 015-LXA -458 015-LXA -459 015-PIC -475 015-TI -502 015-FIC -467 015-FIC -468 015-LI -462 015-LI -463 015-LIC -460 015-LXA -462 015-LXA -463 015-PIC -479 015-TI -503 015-FI -470 015-FIC -461 015-FIC -469 015-LI -466

_ _ _ __ RA| D __| N I ||___ 007 AR-2 07-M

Service BFD TO SLRY LP STM GEN E-1506A/B SLRY LP STM GENERATORS E-1506A/B SLRY LP STM GENERATORS E-1506A/B SLRY LP STM GENERATORS E-1506A/B SLRY LP STM GENERATORS E-1506A/B SL FRM SLRY LP STM GEN E-1506A/B SLURRY FROM LP STMGENS E-1506A/B SLURRY FROM LP STMGENS E-1506A/B HCO FROM HCO LP STMGEN E-1510 CLRFD OIL FRM SLRY SPRTR X-1504 PL FRM SLRY CLRD OIL CLR E1507A-D HCO FROM P-1505 A/B SLURRY OIL PRE-FILTERS F-1503A/B PL FRM SLRY CLRD OIL CLR E1507A-D PL FRM SLRY CLRD OIL CLR E1507A-D PL FRM SLRY CLRFD OIL CLR E-1507C PL FRM SLRY CLRD OIL CLR E1507A-D BK FLUSH OIL FRM RECY PMP P-1506A SIDE BK FLUSH OIL RCV DRUM D-1517 SIDE BK FLUSH OIL RCV DRUM D-1517 SIDE BK FLUSH OIL RCV DRUM D-1517 SIDE BK FLUSH OIL RCV DRUM D-1517 SIDE BK FLUSH OIL RCV DRUM D-1517 FG TO FLUSH OIL RCV DRUM D-1517 BK FLUSH OIL FRM RCV DRUM D-1517 HCO TO FLUSH OIL DRAW OFF D-1516 HCO FROM FLUSH OIL PUMP P-1505A FLUSH OIL DRAW OFF DRUM D-1516 FLUSH OIL DRAW OFF DRUM D-1516 FLUSH OIL DRAW OFF DRUM D-1516 FLUSH OIL DRAW OFF DRUM D-1516 FLUSH OIL DRAW OFF DRUM D-1516 FG TO FLUSH OIL DRAW OFF D-1516 HCO FROM OIL DRAW OFF BOT D-1516 HCO FRM FLUSHOIL FILTER F-1502A/B PL TO HCO FLUSHING DRUM D-1518 HCO TO HCO FLUSHING DRUM D-1518 SIDE HCO FLUSHING OIL DRUM D-1518


Page 17

Unit m3/Hr

0

Min 2

Max

% kg/cm2g degC degC m3/Hr m3/Hr m3/Hr kg/cm2 kg/cm2 kg/cm2g degC degC degC m3/Hr

0 0 0 0 0 0 0 0 0 0 0 0 0 0

100 8 250 250 5 45 40 .15 .8 15 150 150 150 15

% % % kg/cm2g degC m3/Hr m3/Hr

0 0 0 0 0 0 0

100 100 100 2 250 13 30

% % % kg/cm2g degC m3/Hr m3/Hr m3/Hr %

0 0 0 0 0 0 0 0 0

100 100 100 2 250 50 50 35 100

LL Alarm L Alarm 41.6 160 15.9 80 80 80 32.9 5 0.5 12 32.1 4.2 0.5 18.7 -

H Alarm 58.4 180 35 0.7 11.7 100 100 100 73.2 1.5 26.4 84.8 1.5 180 -

HH Alarm 75 93 72

U15 RFCC

015 RFCC Alarm/Trip SP List Tag No. 015-LI -467 015-LI -468 015-LIC -464 015-LXA -468 015-PDI -488 015-PI -487 015-PIC -483 015-PIC -496 015-TI -504 015-FIC -471 015-LI -471 015-LI -500 015-LIC -469 015-LXA -471 015-PIC -489 015-TI -486 015-FI -476 015-FIC -453 015-FIC -472 015-FIC -475 015-FIC -479 015-LI -481 015-LIC -481 015-TI -479 015-TI -480 015-TI -481 015-TI -505 015-TI -512 015-TI -513 015-TI -514 015-FIC -481 015-FIC -482 015-LI -485 015-LI -486 015-LI -487 015-LIC -484 015-LXA -485 015-LXA -486

_ _ _ __ RA| D __| N I ||___ 007 AR-2 07-M

Service SIDE HCO FLUSHING OIL DRUM D-1518 SIDE HCO FLUSHING OIL DRUM D-1518 SIDE HCO FLUSHING OIL DRUM D-1518 SIDE HCO FLUSHING OIL DRUM D-1518 HCO FLUSH OIL FILTERS F-1502A/B PL TO FLUSH OIL FILTERS F-1502A/B FLARE FRM OIL DRUM OVRHD D-1518 HCO FRM FLUSHOIL FILTER F-1502A/B HCO FRM FLUSH OIL DRUM BOT D-1518 LCO FRM FLUSH OIL PMP P-1522A/B SIDE LCO FLUSH OIL DRUM D-1519 SIDE LCO FLUSH OIL DRUM D-1519 SIDE LCO FLUSH OIL DRUM D-1519 SIDE LCO FLUSH OIL DRUM D-1519 PG TO/FRM FLSH OIL DRM TOP D-1519 PL FROM LCO FLUSH OIL DRUM D-1519 SL FROM PRODUCT LP STMGEN E-1513 PL FRM HVN TRIM CLR OUTLET E-1518 PL FRM LCO AIR CLR OUTLET E-1514 BFD TO PRODUCT LP STMGEN E-1513 PL FRM LCO AIR COOLER E-1514 LCO PRODUCT LP STEAM GEN E-1513 LCO PRODUCT LP STEAM GEN E-1513 HVN TO HVN AIR CLR INLET E-1517 HVN FRM HVN AIR CLR OUTLET E-1517 PL FRM HVN TRIM CLR OUTLET E-1518 PL FRM LP STEAM GEN TUBE E-1513 PL FRM LCO AIR CLR OUTLET E-1514 PL FRM LCO AIR CLR OUTLET E-1514 PL FRM LCO AIR CLR OUTLET E-1514 LSO FRM LIGHT SLOPS PMP P-1526A/B LSO FRM LIGHT SLOPS PMP P-1526A/B SIDE LIGHT SLOP DRUM SHELL D-1522 SIDE LIGHT SLOP DRUM SHELL D-1522 SIDE LIGHT SLOP DRUM SHELL D-1522 SIDE LIGHT SLOP DRUM SHELL D-1522 SIDE LIGHT SLOP DRUM SHELL D-1522 SIDE LIGHT SLOP DRUM SHELL D-1522


Page 18

%

Unit 0

Min

Max 100

% % kg/cm2 kg/cm2g kg/cm2g kg/cm2g degC m3/Hr

0 0 0 0 0 0 0 0

100 100 .8 40 2.5 5 250 30

% % % kg/cm2g degC kg/Hr m3/Hr m3/Hr m3/Hr m3/Hr

0 0 0 0 0 0 0 0 0 0

100 100 100 2.5 80 11000 40 200 12 250

% degC degC degC degC degC degC degC m3/Hr m3/Hr

0 0 0 0 0 0 0 0 0 0

100 250 80 60 250 80 60 60 60 60

% % % %

0 0 0 0

100 100 100 100

LL Alarm 31 31 38.4

L Alarm 50 24.6 21 0.5 12.5 23.4 0.5 12.9 78.4 41.6 30 15.5 38.4 -

H Alarm 85.9 0.7 2 180 85.3 2 60 58.4 60 45 168 60 45 45 81.6 62 -

HH Alarm 89 80.1 -

U15 RFCC

015 RFCC Alarm/Trip SP List Tag No. 015-PIC -505 015-TI -520 015-TI -521 015-FIC -485 015-FIC -486 015-LI -491 015-LI -492 015-LI -493 015-LIC -490 015-LXA -491 015-LXA -492 015-PIC -510 015-TI -522 015-TI -523 015-FI -488 015-FIC -487 015-LI -496-A 015-LI -496-B 015-LI -498 015-LXA -498 015-PDIC -514 015-PIC -515 015-TI -524 015-TIC -525 015-LI -701 015-LI -703 015-LI -704-A 015-LI -704-B 015-LI -704-C 015-LXA -704-A 015-LXA -704-B 015-LXA -704-C 015-TI -703 015-FI -701 015-FI -702 015-FI -704 015-FI -705 015-FI -706

_ _ _ __ RA| D __| N I ||___ 007 AR-2 07-M

Service PG T/F LIGHT SLOP DRUM D-1522 LSO TO LHT SLOPS DRUM D-1522 PL FRM LIGHT SLOPS DRUM D-1522 PL FRM HEAVY SLOPS PUMP P-1527A/B PL FRM HEAVY SLOPS PUMP P-1527A/B HEAVY SLOPS DRUM SHELL D-1523 HEAVY SLOPS DRUM SHELL D-1523 HEAVY SLOPS DRUM BOOT D-1523 HEAVY SLOPS DRUM SHELL D-1523 HEAVY SLOPS DRUM SHELL D-1523 HEAVY SLOPS DRUM SHELL D-1523 PG TO/FRM HEAVY SLOP DRUM D-1523 HSO TO HVY SLOP DRUM D-1523 PL FROM HEAVY SLOP DRUM D-1523 TPW FRM TEMPERED WATER PMP P-1528 TPW FRM TEMPERED WATER PMP P-1528 TEMPERED WATER SURGE DRUM D-1524 TEMPERED WATER SURGE DRUM D-1524 TEMPERED WATER SURGE DRUM D-1524 TEMPERED WATER SURGE DRUM D-1524 TPW TO AIR COOLER INLET E-1530 N2 TO TMPRD WTR SURGE DRUM D-1524 TPW FROM AIR COOLER OUTLET E-1530 TPW FROM AIR COOLER OUTLET E-1530 SIDE 1ST STAGE K.O DRUM D-1551 SIDE 1ST STAGE K.O DRUM D-1551 SIDE 1ST STAGE K.O DRUM D-1551 SIDE 1ST STAGE K.O DRUM D-1551 SIDE 1ST STAGE K.O DRUM D-1551 SIDE 1ST STAGE K.O DRUM D-1551 SIDE 1ST STAGE K.O DRUM D-1551 SIDE 1ST STAGE K.O DRUM D-1551 WET GAS TO 1ST STG KO DRM D-1551 WG TO WG COMP 1ST STAGE C-1551 WG TO WG COMP 2ND STAGE C-1551 WT GAS FROM COMP 1ST STAGE C-1551 WT GAS FROM COMP 2ND STAGE C-1551 STEAM TURBINE CONDENSATE


Page 19

Unit kg/cm2g degC degC m3/Hr m3/Hr

0 0 0 0 0

2 60 60 60 60

% % % % kg/cm2g degC degC m3/Hr m3/Hr %

0 0 0 0 0 0 0 0 0 0

100 100 100 100 2 150 150 70 70 100

% kg/cm2 kg/cm2g degC degC % %

0 0 0 0 0 0 0

100 2 8 100 100 100 100

% % % degC Nm3/Hr Nm3/Hr Nm3/Hr Nm3/Hr kg/Hr

Min

0 0 0 0 0 0 0 0 0

Max

100 100 100 70 83000 60000 75000 48000 48000

LL Alarm 16.7 17 5 -

L Alarm 0.8 24.2 38.4 0.8 28.9 55 10 32719.5 23537 -

H Alarm 1.8 81.6 62 1.8 82 5.5 70 90 47 -

HH Alarm 80.1 50 50 50 -

U15 RFCC

015 RFCC Alarm/Trip SP List Tag No. 015-PI -703 015-PI -704 015-PI -705 015-PI -709 015-PI -711 015-TI -631 015-TI -632 015-TI -701 015-TI -702 015-TI -710 015-TI -711 015-TI -788 015-FI -727 015-FIC -703 015-LI -707 015-LI -708 015-LI -709-A 015-LI -709-B 015-LI -709-C 015-LIC -705 015-LXA -707 015-LXA -709-A 015-LXA -709-B 015-LXA -709-C 015-PIC -707 015-PYV -707 015-TI -704 015-TI -709 015-FI -708 015-FI -712 015-FI -728-A 015-FI -728-B 015-FI -741 015-FIC -711 015-LI -716 015-LI -719 015-LIC -714 015-LIC -717

_ _ _ __ RA| D __| N I ||___ 007 AR-2 07-M

Service WG TO WG COMP 1ST STAGE C-1551 SH TO WG COMP STM TURB ST-1551 WT GAS FROM COMP 1ST STAGE C-1551 WG TO WG COMP 2ND STAGE C-1551 WT GAS FROM COMP 2ND STAGE C-1551 WT GAS FROM COMP 1ST STAGE C-1551 WT GAS FROM COMP 2ND STAGE C-1551 WG TO WG COMP 1ST STAGE C-1551 WT GAS FROM COMP 1ST STAGE C-1551 WG TO WG COMP 2ND STAGE C-1551 WT GAS FROM COMP 2ND STAGE C-1551 AIR TO WET GAS COMPRESSOR C-1551 INTERSTG DRUM PUMP P-1521A OULET SOUR WATER FROM FRCTNTN SECTION SIDE INTERSTAGE KO DRUM D-1552 SIDE INTERSTAGE KO DRUM D-1552 SIDE INTERSTAGE KO DRUM D-1552 SIDE INTERSTAGE KO DRUM D-1552 SIDE INTERSTAGE KO DRUM D-1552 SIDE INTERSTAGE KO DRUM D-1552 SIDE INTERSTAGE KO DRUM D-1552 SIDE INTERSTAGE KO DRUM D-1552 SIDE INTERSTAGE KO DRUM D-1552 SIDE INTERSTAGE KO DRUM D-1552 WET GAS FROM KO DRUM OVRHD D-1552 WET GAS FROM KO DRUM OVRHD D-1552 PZ TO WG COMP TRIM CLR E-1552A/B PZ TO INTERSTAGE KO DRUM D-1552 PRIMARY ABSORBER BOT FRM T-1551 SOW FRM HP SPRTR DRM BOOT D-1553 PL TO HP SEPARATOR DRUM D-1553 PL TO HP SEPARATOR DRUM D-1553 LPG TO STRIPPER CONDNSR E-1554A-D PL FROM STRPR FEED PUMP P-1553A/B HP SEPERATOR DRUM BOOT D-1553 HP SEPERATOR DRUM SHELL D-1553 HP SEPERATOR DRUM BOOT D-1553 HP SEPERATOR DRUM SHELL D-1553


Page 20

Unit Min kg/cm2g kg/cm2g 0 kg/cm2g kg/cm2g kg/cm2g 0 0 degC 0 degC 0 degC 0 degC 0 degC 0 m3/Hr 0 m3/Hr 0

Max 70

350 350

600 90 35

%

0

100

% % % % % kg/cm2g m3/Hr degC degC m3/Hr m3/Hr m3/Hr m3/Hr m3/Hr

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

100 100 100 100 100 5 11000 80 70 300 40 130 130 15 600

% %

0 0

100 100

LL Alarm L Alarm 59.9 14.1 25.5 4 20 243 38.5 61.9

H Alarm 90.9 74.7 3.7 60 50 534.6 87.7 91.2

HH Alarm 50 50 50 -

U15 RFCC

015 RFCC Alarm/Trip SP List Tag No. 015-LXA -716 015-LXA -719 015-PIC -718 015-PYV -718 015-TI -712 015-TI -713 015-TI -714 015-TI -715 015-TI -720 015-TI -726 015-TI -736 015-FI -707 015-FI -726 015-FIC -709 015-FIC -710 015-FIC -713 015-FIC -714 015-LIC -710 015-LIC -712 015-PI -723 015-TI -721 015-TI -722 015-TI -724 015-TI -725 015-TI -727 015-TI -728 015-TI -729 015-TI -730 015-TI -737 015-TIC -723 015-FIC -715 015-TI -731 015-TI -732 015-TI -734 015-TI -735 015-FI -717 015-FIC -718 015-LI -722

_ _ _ __ RA| D __| N I ||___ 007 AR-2 07-M

Service HP SEPERATOR DRUM BOOT D-1553 HP SEPERATOR DRUM SHELL D-1553 PG FROM HP SEPERATOR DRUM D-1553 PG FROM HP SEPERATOR DRUM D-1553 WG TO HP CONDENSER INLET E-1553 WG FRM HP CONDENSER OUTLET E-1553 LPG TO STRIPPER CONDNSR E-1554A-D PZ TO STRIPPER COND E-1554A/B/C/D PZ TO HP SEPERATOR DRUM D-1553 PL TO STRPR FEED PUMP P-1553A SOW FROM HP SEPARATOR DRUM D-1553 HP VAP TO PRIMARY ABSORBER T-1551 HVN TO STRPR FEED PRE HTR E-1555 PG FROM STRIPPER OVRHD T-1551 LCO TO STRPR 2ND REBOILER E-1557 GASOLINE TO PRIM ABSORBER T-1551 PL FROM STRIPPER BOT T-1552 SIDE PRIMARY ABSORBER TANK T-1551 STRIPPER TOWER T-1552 STRIPPER TOWER T-1552 PL FROM PRIM ABSORBER BOT T-1551 PL FROM STRIPPER OVRHD T-1552 PZ FRM STRPR FEED PRE HTR E-1555 HVN FRM STRPR FEED PRE HTR E-1555 PL FROM STRIPPER BOT T-1552 PL FROM STRIPPER BOT T-1552 PZ TO STRIPPER TANK T-1552 LCO FRM STRPR 2ND REBOILER E-1557 BED9 STRIPPER TANK T-1552 PZ FRM STRPR FEED PRE HTR E-1555 GASOLINE FROM GASOLINE CLR E-1559 PL TO GASOLINE CLR INLET E-1558 PL FRM GASOLINE CLR OUTLET E-1558 GASOLINE FRM COOLER E-1559 GASOLINE FROM GASOLINE CLR E-1559 PG TO SECONDARY ABSR TANK T-1553 LEAN OIL TO SECONDARY ABSR T-1553 SIDE SECONDARY ABSR TANK T-1553


Page 21

Unit % % kg/cm2g m3/Hr degC degC degC degC degC degC degC Nm3/Hr m3/Hr Nm3/Hr m3/Hr m3/Hr m3/Hr % % kg/cm2g degC degC degC degC degC degC degC degC degC degC m3/Hr degC degC degC degC Nm3/Hr m3/Hr %

Min 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

Max 100 100 25 11000 120 80 80 80 60 60 60 37000 90 22000 400 55 600 100 100 25 100 100 80 120 150 200 200 250 100 80 350 200 80 60 60 25000 55 100

LL Alarm L Alarm 5.7 50 20 20 9098.5 248.9 14.4 11.7 45 20 20 21.6 4.3 -

H Alarm 16.1 60 45 81.1 85.8 55 60 45 47.5 -

HH Alarm -

U15 RFCC

015 RFCC Alarm/Trip SP List Tag No. 015-LI -725 015-LIC -720 015-LIC -723 015-LXA -725 015-PDI -735 015-PIC -733 015-TI -738 015-TI -739 015-TI -740 015-TI -741 015-TI -749 015-TI -751 015-TI -787 015-FI -720 015-FI -729 015-FI -742 015-FIC -719 015-LI -728 015-LI -729 015-LI -732 015-LI -735 015-LIC -726 015-LIC -730 015-LIC -733 015-LXA -732 015-LXA -735 015-PDI -740 015-PI -770 015-TDIC -746 015-TI -743 015-TI -744 015-TI -745 015-TI -747 015-TI -748 015-FIC -721 015-FIC -722 015-LI -738 015-LIC -736

_ _ _ __ RA| D __| N I ||___ 007 AR-2 07-M

Service LEAN OIL COALESCER D-1556 SIDE SECONDARY ABSR TANK T-1553 LEAN OIL COALESCER D-1556 LEAN OIL COALESCER D-1556 LEAN OIL TO/FRM COALESCER D-1556 PG FRM FG ABSR OUTLET DRUM D-1559 PG TO SECONDARY ABSR TANK T-1553 PL FRM SECONDARY ABSR TANK T-1553 PZ FRM RICH OIL EXCHANGER E-1563 FG FROM SEC ABSORBER OVRHD T-1553 PL TO RICH OIL CLR INLET E-1564 PL FRM RICH OIL CLR OUTLET E-1564 PZ FRM RICH OIL EXCHANGER E-1563 PG FRM FG ABSR OUTLET DRUM D-1559 FUEL GAS TO WET GAS COMP C-1551 FUEL GAS TO FUEL GAS DRUM D-1509 AM TO FUEL GAS ABSR TANK T-1555 SIDE FG ABSR FEED KO DRUM D-1559 SIDE FG ABSR FEED KO DRUM D-1559 SIDE FUEL GAS ABSORBER TK T-1555 SIDE FG ABSORBER KO DRUM D-1559 SIDE FG ABSR FEED KO DRUM D-1559 SIDE FUEL GAS ABSORBER TK T-1555 SIDE FG ABSORBER KO DRUM D-1559 SIDE FUEL GAS ABSORBER TK T-1555 SIDE FG ABSORBER KO DRUM D-1559 FG ABSR OUTLET KO DRM D-1559 PG FRM FG ABSR OUTLET DRUM D-1559 AM TO FUEL GAS ABSR TANK T-1555 PZ TO FG ABSR FEED KO DRUM D-1557 PG TO FG ABSORBER TANK T-1555 AM TO FUEL GAS ABSR TANK T-1555 PG FRM FG ABSR OUTLET DRUM D-1559 AM FROM FG ABSORBER TK BOT T-1555 REFLUX TO DBTR TANK BED1 T-1554 HCO FRM PUMPAROUND PMP P1508A/B SIDE DEBUTANIZER TANK T-1554 SIDE DEBUTANIZER TANK T-1554


Page 22

Unit

Min

Max

% % % kg/cm2 kg/cm2g degC degC degC degC degC degC degC Nm3/Hr Nm3/Hr Nm3/Hr m3/Hr % %

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

100 100 100 1.2 25 80 100 150 70 150 60 150 17000 450 1500 60 100 100

% % % % % kg/cm2 kg/cm2g degC degC degC degC degC degC m3/Hr m3/Hr

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

100 100 100 100 100 .7 20 25 60 60 80 100 100 270 650

%

0

100

LL Alarm L Alarm 29 17.2 8.6 13.5 22.6 5.5 49 27.2 6 7.6 10 109.1 267.5 35.5

H Alarm 81.3 51.7 1 15.7 45 49.7 65.9 84.9 77.7 0.6 20 45 60 60 240 87.2

HH Alarm 87.9 -

U15 RFCC

015 RFCC Alarm/Trip SP List Tag No. 015-LXA -738 015-PI -751 015-PIC -745 015-TI -752 015-TI -753 015-TI -755 015-TI -758 015-TI -761 015-TI -762 015-TI -770 015-TIC -754 015-LI -741 015-LI -744 015-LIC -739 015-LIC -742 015-LXA -741 015-LXA -744 015-PI -746 015-TI -765 015-FIC -723 015-FIC -724 015-LI -748 015-LI -751 015-LIC -746 015-LIC -749 015-LXA -748 015-LXA -751 015-PDI -758 015-PDI -761 015-PI -759 015-TI -768 015-TI -771 015-TI -772 015-TI -774 015-TI -795 015-LI -601 015-LI -603 015-LIC -601

_ _ _ __ RA| D __| N I ||___ 007 AR-2 07-M

Service SIDE DEBUTANIZER TANK T-1554 SIDE DEBUTANIZER TANK T-1554 PG TO REFLUX DRM OVRHD D-1554 SIDE DEBUTANIZER TANK T-1554 SIDE DEBUTANIZER TANK T-1554 GASOLINE FRM DBTR TANK BOT D-1554 PZ TO DEBUTANIZER TANK T-1554 HCO TO MAIN FRACTIONATOR T-1501 VAPOR FROM DBTR TANK OVRHD T-1554 PZ TO DEBUTANIZER TANK T-1554 SIDE DEBUTANIZER TANK T-1554 SIDE DBTR REFLUX DRUM BOOT D-1554 SIDE DBTR REFLUX DRM SHELL D-1554 SIDE DBTR REFLUX DRUM BOOT D-1554 DEBUTANIZER REFLUX DRUM D-1554 SIDE DBTR REFLUX DRUM BOOT D-1554 SIDE DBTR REFLUX DRM SHELL D-1554 PG FRM REFLUX DRM OVRHD D-1554 PL FRM DBTR CONDENSERS E-1561A/B LPG FROM LPG COOLER E-1562 AMINE TO LPG AMINE ABSR T-1556 LPG AMINE ABSORBER T-1556 LPG AMINE COALESCER D-1555 LPG AMINE ABSORBER T-1556 LPG AMINE COALESCER D-1555 LPG AMINE ABSORBER T-1556 LPG AMINE COALESCER D-1555 LPG AMINE ABSORBER T-1556 LPG AMINE COALESCER D-1555 LPG FROM LPG AMINE COAL D-1555 LPG FROM LPG COOLER E-1562 AMINE FROM LPG AMINE ABSR T-1556 AMINE FROM LEAN AMINE CLR E-1556 LPG FROM LPG AMINE COAL D-1555 AMINE FROM LPG AMINE ABSR T-1556 RFCC CLOSED DRAIN VESSEL D-1560 RFCC CLOSED DRAIN VESSEL D-1560 RFCC CLOSED DRAIN VESSEL D-1560


Page 23

Unit % kg/cm2g kg/cm2g degC degC degC degC degC degC degC degC

0 0 0 0 0 0 0 0 0 0 0

Min

Max 100 20 20 250 150 300 300 350 100 300 150

% % % % kg/cm2g degC m3/Hr m3/Hr

0 0 0 0 0 0 0 0

100 100 100 100 20 70 200 40

% % % % kg/cm2 kg/cm2 kg/cm2g degC degC degC degC degC

0 0 0 0 0 0 0 0 0 0 0 0

100 100 100 100 1.2 1 30 60 100 60 60 75

% %

0 0

100 100

LL Alarm 4.2 12.9 19 5.2 6.2 -

L Alarm 77 43.7 45.5 9.9 72.7 15.7 40 12.3 16.3 -

H Alarm 12.7 87 80.6 83.5 12.1 160 34.5 79.1 36.9 1.1 19.9 45 -

HH Alarm -

U15 RFCC

015 RFCC Alarm/Trip SP List Tag No. 015-TI -625 015-LIC -605 015-TI -629 015-LI -769 015-LI -774 015-LIC -769 015-LI -771 015-LI -773 015-LIC -770 015-LIC -772 015-TI -797 015-TI -798 015-FI -502 015-FI -503 015-FI -504 015-FI -505 015-FI -506 015-FI -507 015-FI -508 015-FI -509 015-FI -510 015-FI -511 015-FI -512 015-FI -513 015-FI -514 015-FI -515 015-FI -516 015-FI -517 015-FI -518 015-FI -519 015-FI -520 015-FI -521 015-FI -522 015-FI -523 015-FI -524 015-FI -743 015-FI -744 015-LI -502

_ _ _ __ RA| D __| N I ||___ 007 AR-2 07-M

Service RFCC CLOSED DRAIN VESSEL D-1560 LP BLOWDOWN DRUM D-1527 ATMOSPHERIC BLOWDOWN DRUM D-1523 AMINE CLOSED DRAIN DRUM D-1561 AMINE CLOSED DRAIN DRUM D-1561 AMINE CLOSED DRAIN DRUM D-1561 RFCC LIFT STATION XP-1501 RFCC LIFT STATION XP-1502 RFCC LIFT STATION XP-1501 RFCC LIFT STATION XP-1502 RFCC LIFT STATION XP-1501 RFCC LIFT STATION XP-1502 FEED PUMP P-1501A FEED PUMP P-1501A FEED PUMP P-1501B FEED PUMP P-1501B SLURRY PRODUCT PUMP P-1504A BACK FLUSH OIL PUMP P-1504B BACK FLUSH OIL PUMP P-1505B BACK FLUSH OIL PUMP P-1505A BACK FLUSH OIL RECY PMP P-1506A BACK FLUSH OIL RECY PMP P-1506B HCO RECYCLE PUMP P-1507A HCO RECYCLE PUMP P-1507A HCO RECYCLE PUMP P-1507B HCO RECYCLE PUMP P-1507B HCO PUMPAROUND PUMP P-1508A HCO PUMPAROUND PUMP P-1508A HCO PUMPAROUND PUMP P-1508B HCO PUMPAROUND PUMP P-1508B HCO PRODUCT PUMP P-1509A HCO PRODUCT PUMP P-1509B SLURRY PUMPARROUND PUMP P-1519A SLURRY PUMPARROUND PUMP P-1519B SLURRY PUMPARROUND PUMP P-1519C RFCC CLOSED DRAIN PUMP P-1560A RFCC CLOSED DRAIN PUMP P-1560B LCO PUMPAROUND PUMP P-1510A


Page 24

Unit degC % degC

0 0 0

Min

Max 150 100 100

% % % % % % degC degC m3/Hr m3/Hr m3/Hr m3/Hr m3/Hr m3/Hr m3/Hr m3/Hr m3/Hr m3/Hr m3/Hr m3/Hr m3/Hr m3/Hr m3/Hr m3/Hr m3/Hr m3/Hr m3/Hr m3/Hr m3/Hr m3/Hr m3/Hr m3/Hr m3/Hr %

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

100 100 100 100 100 100 75 75 1 1 1 1 .8 .8 .8 .8 .7 .7 1 1 1 1 1 1 1 1 .8 .8 1.5 1.5 1.5 .6 .6 100

LL Alarm L Alarm 0.39 0.39 0.39 0.39 0.372 0.372 0.3 0.3 0.276 0.276 0.42 0.42 0.42 0.42 0.42 0.42 0.42 0.42 0.285 0.285 0.738 0.738 0.738 0.24 0.24 62.9

H Alarm 95 80 46 46 0.78 0.78 0.78 0.78 0.624 0.6 0.6 0.468 0.468 0.84 0.84 0.84 0.84 0.84 0.84 0.84 0.84 0.57 0.57 1.248 1.248 1.248 0.48 0.48 95.2

HH Alarm -

U15 RFCC

015 RFCC Alarm/Trip SP List Tag No. 015-LI -503 015-LI -504 015-LI -505 015-LI -506 015-LI -507 015-LI -508 015-LI -509 015-LI -510 015-LI -511 015-LI -512 015-LI -513 015-LI -514 015-LI -515 015-LI -516 015-LI -517 015-LI -518 015-LI -519 015-LI -520 015-LI -521 015-LI -522 015-LI -523 015-LI -524 015-LI -525 015-LI -526 015-LI -527 015-LI -752 015-LI -753 015-LI -754 015-LI -755 015-LI -756 015-LI -757 015-LI -758 015-LI -759 015-LI -760 015-LI -762 015-LI -763 015-LI -764 015-LI -765

_ _ _ __ RA| D __| N I ||___ 007 AR-2 07-M

Service LCO PUMPAROUND PUMP P-1510A LCO PUMPAROUND PUMP P-1510B LCO PUMPAROUND PUMP P-1510B LCO STRIPPER PUMP P-1511A LCO STRIPPER PUMP P-1511B MTC RECYCLE PUMP P-1512A MTC RECYCLE PUMP P-1512B LEAN OIL PUMP P-1513A LEAN OIL PUMP P-1513A LEAN OIL PUMP P-1513B LEAN OIL PUMP P-1513B NAPHTHA PUMPAROUND PUMP P-1514A NAPHTHA PUMPAROUND PUMP P-1514A NAPHTHA PUMPAROUND PUMP P-1514B NAPHTHA PUMPAROUND PUMP P-1514B LEAN OIL PUMP P-1515A LEAN OIL PUMP P-1515B FRCTNTR REFLUX PUMP P-1516A FRCTNTR REFLUX PUMP P-1516B OVHD SOUR WATER PUMP P-1517A OVHD SOUR WATER PUMP P-1517B OVHD LIQUID PUMP P-1518A OVHD LIQUID PUMP P-1518A OVHD LIQUID PUMP P-1518B OVHD LIQUID PUMP P-1518B INTERSTAGE DRUM PUMP P-1551A INTERSTAGE DRUM PUMP P-1551A INTERSTAGE DRUM PUMP P-1551B INTERSTAGE DRUM PUMP P-1551B K.O DRUM LIQUID PUMP P-1552A K.O DRUM LIQUID PUMP P-1552A STRIPPER FEED PUMP P-1553A AMINE CLOSED DRAIN PUMP P-1564 STRIPPER FEED PUMP P-1553B GASOLINE RECYCLE PUMP P-1554A GASOLINE RECYCLE PUMP P-1554B DEBUTANIZER OVERHEAD PUMP P-1556A DEBUTANIZER OVERHEAD PUMP P-1556A


Page 25

Unit % % % % % % % % % % % % % % % % % % % % % % % % % % % % % % % % % % % % % %

Min 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

Max 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100

LL Alarm L Alarm 62.9 62.9 62.9 62.9 62.9 62.9 62.9 62.9 62.9 62.9 62.9 62.9 62.9 62.9 62.9 62.9 62.9 62.9 62.9 62.9 62.9 62.9 62.9 62.9 62.9 62.9 62.9 62.9 62.9 62.9 62.9 62.9 62.9 62.9 62.9 62.9 62.9

H Alarm 95.2 95.2 95.2 95.2 95.2 95.2 95.2 95.2 95.2 95.2 95.2 95.2 95.2 95.2 95.2 95.2 95.2 95.2 95.2 95.2 95.2 95.2 95.2 95.2 95.2 95.2 95.2 95.2 95.2 95.2 95.2 95.2 95.2 95.2 95.2 95.2 95.2 95.2

HH Alarm -

U15 RFCC

015 RFCC Alarm/Trip SP List Tag No. 015-LI -766 015-LI -767 015-PI -540 015-PI -541 015-PI -542 015-PI -543 015-PI -544 015-PI -545 015-PI -546 015-PI -547 015-PI -548 015-PI -549 015-PI -550 015-PI -551 015-PI -552 015-PI -553 015-PI -554 015-PI -555 015-PI -556 015-PI -557 015-PI -558 015-PI -559 015-PI -560 015-PI -561 015-PI -562 015-PI -563 015-PI -564 015-PI -565 015-PI -724 015-PI -725 015-PI -726 015-PI -727 015-PI -728 015-PI -729 015-PI -730 015-PI -731 015-PI -736 015-PI -738

_ _ _ __ RA| D __| N I ||___ 007 AR-2 07-M

Service PUMP NAME P-1521B PUMP NAME P-1521B LCO PUMPAROUND PUMP P-1510A LCO PUMPAROUND PUMP P-1510A LCO PUMPAROUND PUMP P-1510B LCO PUMPAROUND PUMP P-1510B LCO STRIPPER PUMP P-1511A LCO STRIPPER PUMP P-1511B MTC RECYCLE PUMP P-1512A MTC RECYCLE PUMP P-1512B LEAN OIL PUMP P-1513A LEAN OIL PUMP P-1513A LEAN OIL PUMP P-1513B LEAN OIL PUMP P-1513B NAPHTHA PUMPAROUND PUMP P-1514A NAPHTHA PUMPAROUND PUMP P-1514A NAPHTHA PUMPAROUND PUMP P-1514B NAPHTHA PUMPAROUND PUMP P-1514B HVY NAPHTHA PRODUCT PUMP P-1515A HVY NAPHTHA PRODUCT PUMP P-1515B FRCTNTR REFLUX PUMP P-1516A FRCTNTR REFLUX PUMP P-1516B OVHD SOUR WATER PUMP P-1517A OVHD SOUR WATER PUMP P-1517B OVHD LIQUID PUMP P-1518A OVHD LIQUID PUMP P-1518A OVHD LIQUID PUMP P-1518B OVHD LIQUID PUMP P-1518B INTERSTAGE DRUM PUMP P-1551A INTERSTAGE DRUM PUMP P-1551A INTERSTAGE DRUM PUMP P-1551B INTERSTAGE DRUM PUMP P-1551B K.O DRUM LIQUID PUMP P-1552A K.O DRUM LIQUID PUMP P-1552A STRIPPER FEED PUMP P-1553A STRIPPER FEED PUMP P-1553A STRIPPER FEED PUMP P-1553B GASOLINE RECYCLE PUMP P-1554A


Page 26

Unit % % kg/cm2g kg/cm2g kg/cm2g kg/cm2g kg/cm2g kg/cm2g kg/cm2g kg/cm2g kg/cm2g kg/cm2g kg/cm2g kg/cm2g kg/cm2g kg/cm2g kg/cm2g kg/cm2g kg/cm2g kg/cm2g kg/cm2g kg/cm2g kg/cm2g kg/cm2g kg/cm2g kg/cm2g kg/cm2g kg/cm2g kg/cm2g kg/cm2g kg/cm2g kg/cm2g kg/cm2g kg/cm2g kg/cm2g kg/cm2g kg/cm2g kg/cm2g

Min 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

Max 100 100 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20

LL Alarm L Alarm 62.9 62.9 -

H Alarm 95.2 95.2 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 XXX 0.8 0.8

HH Alarm -

U15 RFCC

015 RFCC Alarm/Trip SP List Tag No. 015-PI -739 015-PI -741 015-PI -742 015-PI -743 015-PI -744

_ _ _ __ RA| D __| N I ||___ 007 AR-2 07-M

Service GASOLINE RECYCLE PUMP P-1554B DEBUTANIZER OVERHEAD PUMP P-1556A DEBUTANIZER OVERHEAD PUMP P-1556A DEBUTANIZER OVERHEAD PUMP P-1556B DEBUTANIZER OVERHEAD PUMP P-1556B

P&ID No 8474L-015-PID-0021-637 8474L-015-PID-0021-637 8474L-015-PID-0021-637 8474L-015-PID-0021-637 8474L-015-PID-0021-637

Page 27

Unit kg/cm2g kg/cm2g kg/cm2g kg/cm2g kg/cm2g

Min 0 0 0 0 0

Max 20 20 20 20 20

LL Alarm L Alarm H Alarm 0.8 0.8 0.8 0.8 0.8

HH Alarm -

CAUSE AND EFFECT CHART Project N° - Unit

DOCUMENT CLASS

Z

Doc. type

Code

8474L 015 DW o Op. Center JOB N . o Op. Center Doc. N . o FEED Doc. N .

PETROVIETNAM

CLIENT

UNIT Rev.

A

B

C

CAUSE AND EFFECT CHART D

E

Rev.

Page

E

1/50

A

B

C

D

E

Page

1

X

X

-

-

X

26

X

X

-

-

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2

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27

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28

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48

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50

-

X

X

-

-

E

27 Dec. 06

Y.Yanai

E.Hirano

E.Hirano

Issue for design

D

25 Aug. 06

Y.Yanai

E.Hirano

E.Hirano

Issue for design

C

18 Aug. 06

K. Miyata

J. Lee

M. Okada

Issue for design

B

25-Jul-06

K. Miyata

J. Lee

M. Okada

Issue for design

A

19-Jan-06

K. Miyata

J. Lee

M. Okada

Issue for review

Date

Written by

Checked by

Approved by

Description

Rev.

Rev. index

Page

DUNG QUAT VIETNAM 015 RFCC

LOCATION

Serial N°

15 14 602 0-3952-20-0000 S-015-1223-602

DD-MMM-YY

_ _ _ __ RA| D __| N I ||___

Document revisions

PDS94 - Rev. 4 - ANG - XL97

PD094A14

7 2-20007 JAANR073-M

S-015-1223-602_RevE.XLS

E 121 REACTION STOP (ADP)

B 122

B 122

MP STEAM TO STABILIZATION INJECTORS (I-1503 D)

B 122

MP STEAM TO STABILIZATION INJECTORS (I-1503 C)

B 122

MP STEAM TO STABILIZATION INJECTORS (I-1503 B)

B 121

MP STEAM TO STABILIZATION INJECTORS (I-1503 A)

B 121

MP STEAM TO FEED INJECTORS (I-1501 F)

B 121

MP STEAM TO FEED INJECTORS (I-1501 E)

B 121

MP STEAM TO FEED INJECTORS (I-1501 D)

B 121

MP STEAM TO FEED INJECTORS (I-1501 C)

B 121

MP STEAM TO FEED INJECTORS (I-1501 B)

B 3 324

MP STEAM TO FEED INJECTORS (I-1501 A)

B 3 324

BACK FLUSH OIL RECYCLE PUMP

B 2


HCO RECYCLE PUMP

306

B 2 306

305

305 MTC RECYCLE PUMP

MTC RECYCLE PUMP

121 FEED PASSIVATOR PUMP

121

122

FEED PASSIVATOR PUMP

122

BACKFLUSH OIL TO BACK FLUSH OIL INJECTOR (I-1504)

121

121 FEED RECIRCULATION TO D-1513

FEED TO FEED INJECTORS (I-1501 A TO F)

MTC TO MTC INJECTORS (I-1502 A TO D)

30

29

28

27

26

25

24

23 UXA-001B

ESD

HARDWIRE SWITCH ACTIVE

121

N/A

N/A

UXHS-001A

1

C

O

C

C

T

T

T

T

T

T

T

T

O

O

O

O

O

O

O

O

O

O

A

1

D

6

ESD


121

N/A

N/A

UXHS-001B

2

C

O

C

C

T

T

T

T

T

T

T

T

O

O

O

O

O

O

O

O

O

O

A

2

B

1

I-1501A~F

FEED FLOW LOW LOW

121

FHS-405B

FHS-405A

FXALL-405

3

C

O

C

C

T

T

T

T

T

T

T

T

O

O

O

O

O

O

O

O

O

O

A

3

CATALYST CIRCULATION STOP

121

N/A

N/A

4

C

O

C

C

T

T

T

T

T

T

T

T

O

O

O

O

O

O

O

O

O

O

A

4

D

B

UX-002

A.- UNLESS OTHERWISE SPECIFIED, ALL DRAWING NUMBERS SHALL BE PREFIXED BY 8474L-015-PID-0021 . B.- UNLESS OTHERWISE SPECIFIED, ALL INSTRUMENT TAG NUMBERS SHALL BE PREFIXED BY 015 . C.- PER ESD SYSTEMS STANDARD 8474L-JSS1515-001 CLAUSE 7.1, ALL INPUTS SHALL HAVE A DELAY OF 0.5 SECONDS UNLESS OTHERWISE SPECIFIED. D.- ALL ESD VALVES WILL BE PROVIDED WITH PARTIAL STROKE TEST FACILITY UNLESS OTHERWISE SPECIFIED. E.- ALL INPUTS AND OUTPUTS SHALL BE FAILSAFE UNLESS OTHERWISE SPECIFIED. FIELD INPUT CONTACTS SHALL OPEN TO TRIP. OUTPUT SHALL DE-ENERGIZE TO TRIP. F.- DCS ALARMS SHALL BE PROVIDED IN ACCORDANCE WITH LONG FORMAT SHOWN ON SYMBOLOGY P&ID 8474L-000-PID-0090-010 TO 013 INCLUSIVE. G.- ALL OUTPUT SHALL BE PROVIDED WITH MOS.

FV-007 D 22 FSY-007 D

FV-007 C 21 FSY-007 C

FV-007 B 20 FSY-007 B

FV-007 A 19 FSY-007 A

FV-005 F 18 FSY-005 F

FV-005 E 17 FSY-005 E

FV-005 D 16 FSY-005 D

FV-005 C 15 FSY-005 C

FV-005 B 14 FSY-005 B

FV-005 A 13 FSY-005 A

P-1506B 12 MXS-465

P-1506A 11 MXS-464

P-1507B 10 MXS-482

P-1507A MXS-481 9

P-1512B MXS-440 8

P-1512A MXS-439 7

P-1502B MXS-002 6

P-1502A

XV-004 XSY-004

FV-001

XV-002

XV-003 XSY-003

MXS-001 5

TAG No.

4

MOS

3

OOS

FSY-001

OVERRIDE TAG No. P&ID

DESCRIPTION

1

EQUIPMT

LOGIC

2

SERVICE

OTHER Rev. NOTE

MOS : Maintenance Override Switch OOS : Operation Override Switch

GENERAL NOTES :

XSY-002

CAUSE

HCO RECYCLE PUMP

B

B

B

B

B

B

B

B

Rev. NOTE

P&ID OTHER LOGIC TAG No

EQUIPMT

UX-001 REACTION STOP

DESCRIPTION

UNIT 015 RFCC UNIT

SERVICE

LOGIC IDENTIFICATION

EFFECT

UNIT or EQUIPMENT

ABBREVIATIONS USED IN THE MATRIX : A = Activate C= Close O = Open S = Start T = Trip I = Inhibit P = Permissive R = Reset V = oVerride

E

5

DCS

SOFTWARE SWITCH ACTIVE

121

N/A

N/A

XHSC-002-A

5

C

E

5

DCS


121

N/A

N/A

XHSO-002-A

6

O

E

5

DCS


122

N/A

N/A

XHSC-003-A

7

C

E

5

DCS


122

N/A

N/A

XHSO-003-A

8

O

E

5

DCS


122

N/A

N/A

XHSC-004-A

9

C

9

E

5

DCS


122

N/A

N/A

XHSO-004-A

10

O

10

5 6 7 8

11

11

12

12

13

13

14

14

15

15

16

16

17

17

18

18

19

19

20

20

21

21

22

22

23

23

24

24

25

25

26

26

27

27

28

28

29

29

30

30

NOTES : 1. TIME DELAY OF 10 SECONDS. 2. TRIPPED BY UX-423. 3. TRIPPED BY UX-424. 4. DISCREPANCY ALARM TO BE GENERATED ACCORDING TO 8474L-000JSS-1513-002. 5. DCS OPERATION IS NOT ALLOWED WHEN UX-001 IS TRIPPED. 6. ESD BY-PASS SWITCH

HOLDS :

RESET B

DCS


121

UHSR-001

1

R

B

XV-002


121

XHSR-002

2

R

B

XV-003


121

XHSR-003

3

B

XV-004


121

XHSR-004

4

7 2-20007 JAANR073-M

R

R

R

R

R

R

R

R

R

R

R

R

R

R

R

R

R

R

R

R

1 2

R

3

R 1

_ _ _ __ RA| D __| N I ||___

R

2

3

4

4

5

6

7

8

9

10

11

CAUSE AND EFFECT CHART

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

28

30

UNIT 015 015-UX-001 REACTION STOP Project N° - Unit

Doc. type

Code

Serial N°

Rev. index

SHEET

8474L 015

DW

15 14

602

E

2

E 202

125 CATALYST CIRCULATION STOP (ADP)

E

B 201

COB/WHB 2ND REGE FLUE GAS BYPASS OPERATION

E

B

121

UX-010 COB/WHB 1ST REGE FLUE GAS BYPASS OPERATION

PLUG VALVE TO FIRST REGENERATOR

REACTION STOP

127

UX-001

3

B

B 131 REGENERATED CATALYST SLIDE VALVE

125 SPENT CATALYST SLIDE VALVE

30

29

28

27

26

25

24

23

22

21

20

19

18

17

16

15

14

13

9

12

8

11

7

10

6

UX-008

UXA-002B

PV-1501 USY-016 5

USY-017

SV-1501

A.- UNLESS OTHERWISE SPECIFIED, ALL DRAWING NUMBERS SHALL BE PREFIXED BY 8474L-015-PID-0021.. 8474L-015-PID-0021 B.- UNLESS OTHERWISE SPECIFIED, ALL INSTRUMENT TAG NUMBERS SHALL BE PREFIXED BY 015. 015 . C.- PER ESD SYSTEMS STANDARD 8474L-JSS1515-001 CLAUSE 7.1, ALL INPUTS SHALL HAVE A DELAY OF 0.5 SECONDS UNLESS OTHERWISE SPECIFIED. D.- ALL ESD VALVES WILL BE PROVIDED WITH PARTIAL STROKE TEST FACILITY UNLESS OTHERWISE SPECIFIED. E.- ALL INPUTS AND OUTPUTS SHALL BE FAILSAFE UNLESS OTHERWISE SPECIFIED. FIELD INPUT CONTACTS SHALL OPEN TO TRIP. OUTPUT SHALL DE-ENERGIZE TO TRIP. F.- DCS ALARMS SHALL BE PROVIDED IN ACCORDANCE WITH LONG FORMAT SHOWN ON SYMBOLOGY P&ID 8474L-000-PID-0090-010 TO 013 INCLUSIVE. G.- ALL OUTPUT SHALL BE PROVIDED WITH MOS.

ESD


125

N/A

N/A

UXHS-002A

1

C

C

C

A

A

A

A

1

ESD


125

N/A

N/A

UXHS-002B

2

C

C

C

A

A

A

A

2

124

PDHS-064B

PDHS-064A

PDXLL-064

3

C

C

C

A

A

A

A

3

125

PDHS-104B

PDHS-104A

PDXLL-104

4

C

C

C

A

A

A

A

4

2

STRIPPER DEL P LOW LOW SV1502 WITHDRAWAL WELL LEVEL LL

131

LHS-010B

LHS-010A

LXALL-010

5

C

C

C

A

A

A

A

5

B

2

SV-1501 DEL P LOW LOW

131

PDHS-242B

PDHS-242A

PDXLL-242

6

C

C

C

A

A

A

A

6

E

5

AIR FLOW TO H-1501 LL

132

FHS-170B

FHS-170A

FXALL-170

7

C

C

C

A

A

A

A

7

B


132

FHS-171B

FHS-171A

FXALL-171

8

C

C

C

A

A

A

A

8

B

AIR FLOW TO D-1502 LL

132

FHS-172B

FHS-172A

FXALL-172

9

C

C

C

A

A

A

A

9

E

MP STEAM PRESS LL

138

PHS-363A

PXALL-363

10

C

C

C

A

A

A

A

10

MAB PROTECTION ACTIVE

132

11

C

C

C

A

A

A

A

D D

4

E

1

E

1

B

E

UX-005

N/A

N/A

4

TAG No.

3

MOS

2

OOS

3

3


DESCRIPTION

1

EQUIPMT

LOGIC

USY-015

SERVICE

OTHER Rev. NOTE


GENERAL NOTES : SV-1502

EQUIPMT TAG No

CAUSE

B

B

Rev. NOTE

P&ID OTHER LOGIC DESCRIPTION

UX-002 CATALYST CIRCULATION STOP

UNIT 015 RFCC UNIT

SERVICE


EFFECT

UNIT or EQUIPMENT


11

NOTES :

12

12

13

13

14

14

15

15

16

16

17

17

1. 2 OUT OF 2 VOTING (PDXALL-064 AND 104) 2. 10 SECOND AVERAGE TO BE USED FOR INPUT. 3. DISCREPANCY ALARM TO BE GENERATED ACCORDING TO 8474L-000-JSS-1513-002. 4. ESD BY-PASS SWITCH 5. 10 SECOND OFF-DELAY TIMER TO BE PROVIDED.

18

18

19

19

20

20

21

21

22

22

23

23

24

24

25

25

26

26

27

27

28

28

29

29

30

30

HOLDS :

RESET B

DCS


125

UHSR-002

1

R

R

R

R

R

R

1

2

2

3

3

4

4

1

_ _ _ __ RA| D __| N I ||___ 7 2-20007 JAANR073-M

2

3

4

5

6

7

8

9

10

11


12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

28

30

UNIT 015 015-UX-002 CATALYST CIRCULATION STOP Project N° - Unit

Doc. type

Code

Serial N°

Rev. index

SHEET

8474L 015

DW

15 14

602

E

3

B

B

B

E

133

133

133

133

Rev.

1ST REGENERATOR AIR HEATER TRIP (ADP)

FUEL GAS TO VENT

FUEL GAS TO H-1501

FUEL GAS TO H-1501

30

29

28

27

26

25

24

23

22

21

20

19

18

17

16

15

14

13

12

11

10

9

8

7

6

UXA-003B

XV-017

XSY-019

B

ESD


133

N/A

N/A

UXHS-003A

1

C

C

O

A

1

E

H-1501

H-1501 TEMP HIGH HIGH

133

N/A

THS-069A

TXAHH-069

2

C

C

O

A

2

E

FG HEADER

FUEL GAS PRESS LOW LOW

134

N/A

PHS-321A

PXALL-321

3

C

C

O

A

3


132

FHS-170A

FXALL-170

4

C

C

O

A

4

B

3

E

H-1501

NO PILOT FLAME

133

BHS-003

BXALL-003

5

C

C

O

A

5

E

H-1501

NO MAIN FLAME

133

BHS-004

BXALL-004

6

C

C

O

A

6

MAB TRIP

132

N/A

N/A

XS-801

7

C

C

O

A

7

LOCAL PANEL HARDWIRE SWITCH ACTIVE

133

N/A

N/A

UXHS-003B

8

C

C

O

A

8


133

N/A

N/A

UXHS-003C

9

C

C

O

B

1

UX-801 C-1501

E E

2

LOCAL PANEL


XV-019

5

TAG No.

4

MOS

3

OOS

XSY-017


DESCRIPTION

1

EQUIPMT

LOGIC

2

SERVICE

OTHER Rev. NOTE

XV-016

CAUSE


GENERAL NOTES :

XSY-016

TAG No

EQUIPMT

UX-003 FIRST REGENERATOR AIR HEATER TRIP

DESCRIPTION

UNIT 015 RFCC UNIT

SERVICE


EFFECT

UNIT or EQUIPMENT

P&ID OTHER LOGIC

NOTE


9

10

10

11

11

12

12

13

13

14

14

15

15

16

16

17

17

18

18

19

19

20

20

21

21

22

22

23

23

24

24

25

25

26

26

27

27

28

28

29

29

30

30

NOTES : 1. AIR BLOWER TRIP BY VENDOR. 2. AIR HEATER STOP BY VENDOR. 3. OOS FOR FXALL-170 IS NOT REQUIRED FOR UX003.

HOLDS :

RESET DCS


133

UHSR-003

1

R

E

XV-016


133

XHSR-016

2

R

E

XV-017


133

XHSR-017

3

E

XV-019


133

XHSR-019

4

7 2-20007 JAANR073-M

R

1 2

R

3

R 1

_ _ _ __ RA| D __| N I ||___

R

2

3

4

4

5

6

7

8

9

10

11


12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

28

30

UNIT 015 015-UX-003 FIRST REGENERATOR AIR HEATER TRIP Project N° - Unit

Doc. type

Code

Serial N°

Rev. index

SHEET

8474L 015

DW

15 14

602

E

4

B

B

B

E

134

134

134

134

Rev.

2ND REGENERATOR AIR HEATER TRIP (ADP)

FUEL GAS TO VENT

FUEL GAS TO H-1502

FUEL GAS TO H-1502

30

29

28

27

26

25

24

23

22

21

20

19

18

17

16

15

14

13

12

11

10

9

8

7

6

UXA-004B

XV-015

XSY-020

B

ESD


134

N/A

N/A

UXHS-004A

1

C

C

O

A

1

B

H-1502

H-1502 TEMP HIGH HIGH

134

N/A

THS-072A

TXAHH-072

2

C

C

O

A

2

B

FG HEADER

FUEL GAS PRESS LOW LOW

134

N/A

PHS-321A

PXALL-321

3

C

C

O

A

3


132

FHS-171A

FXALL-171

4

C

C

O

A

4

B

3

E

H-1502

NO PILOT FLAME

134

BHS-001

BXALL-001

5

C

C

O

A

5

E

H-1502

NO MAIN FLAME

134

BHS-002

BXALL-002

6

C

C

O

A

6

MAB TRIP

132

N/A

XHS-801A

XS-801

7

C

C

O

A

7

LOCAL PANEL HARDWIRE SWITCH ACTIVE

134

N/A

N/A

UXHS-004B

8

C

C

O

A

8


134

N/A

N/A

UXHS-004C

9

C

C

O

E

1

UX-801 C-1501

E E

2

LOCAL PANEL


XV-020

5

TAG No.

4

MOS

3

OOS

XSY-015


DESCRIPTION

1

EQUIPMT

LOGIC

2

SERVICE

OTHER Rev. NOTE

XV-014

CAUSE


GENERAL NOTES :

XSY-014

TAG No

EQUIPMT

UX-004 SECOND REGENERATOR AIR HEATER TRIP

DESCRIPTION

UNIT 015 RFCC UNIT

SERVICE


EFFECT

UNIT or EQUIPMENT

P&ID OTHER LOGIC

NOTE


9

10

10

11

11

12

12

13

13

14

14

15

15

16

16

17

17

18

18

19

19

20

20

21

21

22

22

23

23

24

24

25

25

26

26

27

27

28

28

29

29

30

30

NOTES : 1. AIR BLOWER TRIP BY VENDOR 2. AIR HEATER STOP BY VENDOR 3. OOS FOR FXALL-171 IS NOT REQUIRED FOR UX004.

HOLDS :

RESET B

DCS


134

UHSR-004

1

R

B

XV-014


134

XHSR-014

2

R

B

XV-015


134

XHSR-015

3

B

XV-020


134

XHSR-020

4

7 2-20007 JAANR073-M

R

1 2

R

3

R 1

_ _ _ __ RA| D __| N I ||___

R

2

3

4

4

5

6

7

8

9

10

11


12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

28

30

UNIT 015 015-UX-004 SECOND REGENERATOR AIR HEATER TRIP Project N° - Unit

Doc. type

Code

Serial N°

Rev. index

SHEET

8474L 015

DW

15 14

602

E

5

4

E

1

132

N/A

XHS-801A

XS-801

3

B

B 132

132 BLOW-OFFVALVES OPEN


125

UC-802

2

B 3 132

OTHER BLOWER AIR USERS ASSISTED CHECK VALVE

3

E 3 134

AIR LIFT ASSISTED CHECK VALVE

B

2ND REGENERATOR AIR RING ASSISTED CHECK VALVE

B

C

C

C

A

30

29

28

27

26

25

24

23

22

21

20

19

18

17

16

15

14

A

13

A

12

C

11

C

10

C

9

C C


CV-1504

CV-1503

CV-1502

CV-1501

XS-802

MAB TRIP

UX-002

2

8

1

UXHS-005B

7

UXHS-005A

N/A

XSY-168

N/A

N/A

6

N/A

132

XSY-167

132


5


XSY-165

ESD ESD UX-801 C-1501

133

3

TAG No.

4

MOS

1

OOS

2


DESCRIPTION

XSY-163

D D

EQUIPMT

LOGIC

3

SERVICE

OTHER Rev. NOTE

1ST REGENERATOR AIR RING ASSISTED CHECK VALVE

B

Rev. NOTE


CAUSE


GENERAL NOTES :

EQUIPMT

UX-005 AIR BLOWER PROTECTION

DESCRIPTION

UNIT 015 RFCC UNIT

SERVICE


EFFECT

UNIT or EQUIPMENT


1

A

2

A

3

4

4

5

5

6

6

7

7

8

8

9

9

10

10

11

11

12

12

13

13

14

14

15

15

16

16

17

17

18

18

19

19

20

20

21

21

22

22

23

23

24

24

25

25

26

26

27

27

28

28

29

29

30

30

NOTES : 1. AIR BLOWER TRIP BY VENDOR. 2. BLOW-OFF VALVES ,UV-822/823/824, OPEN BY VENDOR. 3. DISCREPANCY ALARM TO BE GENERATED ACCORDING TO 8474L-000-JSS-1513-002. 4. ESD BY-PASS SWITCH

HOLDS :

RESET B

DCS


133

UHSR-005

R

1

R

R

R

R

R

1

2

2

3

3

4

4

1

_ _ _ __ RA| D __| N I ||___ 7 2-20007 JAANR073-M

2

3

4

5

6

7

8

9

10

11


12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

28

30

UNIT 015 015-UX-005 AIR BLOWER PROTECTION Project N° - Unit

Doc. type

Code

Serial N°

Rev. index

SHEET

8474L 015

DW

15 14

602

E

6

ESD 1

KS-XXX H-1503


203

COB/WHB BURNER FLAME OFF FLUE GAS OUTLET TEMP HH

UHS-007

203

TXALL-086

1

-

203

203

FUEL OIL TO COB/WHB (3-WAY VALVE FOR RECIRC)

COB/WHB 1ST REGEN FLUE GAS BYPASS OPERATION

COB/WHB 2ND REGEN FLUE GAS BYPASS OPERATION

1

1

-

1

FUEL GAS TO COB/WHB

FUEL GAS TO COB/WHB

FEUL GAS VENT TO ATM

30

29

28

27

26

25

24

23

22

21

20

19

18

17

16

15

14

13

12

11

10

9

8

7

H-1503 XV-XXX

A.- UNLESS OTHERWISE SPECIFIED, ALL DRAWING NUMBERS SHALL BE PREFIXED BY 8474L-015-PID-0021. B.- UNLESS OTHERWISE SPECIFIED, ALL INSTRUMENT TAG NUMBERS SHALL BE PREFIXED BY 015. C.- PER ESD SYSTEMS STANDARD 8474L-JSS1515-001 CLAUSE 7.1, ALL INPUTS SHALL HAVE A DELAY OF 0.5 SECONDS UNLESS OTHERWISE SPECIFIED. D.- ALL ESD VALVES WILL BE PROVIDED WITH PARTIAL STROKE TEST FACILITY UNLESS OTHERWISE SPECIFIED. E.- ALL INPUTS AND OUTPUTS SHALL BE FAILSAFE UNLESS OTHERWISE SPECIFIED. FIELD INPUT CONTACTS SHALL OPEN TO TRIP. OUTPUT SHALL DE-ENERGIZE TO TRIP. F.- DCS ALARMS SHALL BE PROVIDED IN ACCORDANCE WITH LONG FORMAT SHOWN ON SYMBOLOGY P&ID 8474L-000-PID-0090-010 TO 013 INCLUSIVE.

UX-010 6

H-1503

H-1503

XV-XXX

XV-XXXB

UX-008 5

TAG No.

4

MOS

3

OOS

2


DESCRIPTION

1

EQUIPMT

LOGIC

H-1503

SERVICE

OTHER Rev. NOTE


GENERAL NOTES :

XV-XXXA

CAUSE

-

Rev. NOTE


EQUIPMT

UX-007 CO BOILER / WASTE HEAT BOILER TRIP (BY VENDOR)

DESCRIPTION

UNIT 015 RFCC UNIT

SERVICE


EFFECT

UNIT or EQUIPMENT


1

C

C

O

C

A

A

1

2

C

C

O

C

A

A

2

3

C

C

O

C

A

A

3

1

KS-XXX H-1503

FUEL GAS PRESS LL

-

4

C

C

O

C

A

A

4

1

KS-XXX H-1503

FUEL OIL PRESS LL

-

5

C

C

O

C

A

A

5

1

KS-XXX H-1503

COB/WHB CHAMBER TEMP HH

-

6

C

C

O

C

A

A

6

1

KS-XXX H-1503

STEAM DRUM LEVEL LL

-

7

C

C

O

C

A

A

7

1

KS-XXX H-1503

SHP STEAM TEMP HH

-

8

C

C

O

C

A

A

8

1

KS-XXX H-1503

COMBUSTION AIR FLOW LL

-

9

C

C

O

C

A

A

9

1

KS-XXX H-1503

BFW FLOW LL

-

10

C

C

O

C

A

A

10

1

KS-XXX H-1503

COB/WHB MECH FAILURE

UX-002


-

KS-XXX

11

C

C

O

C

A

A

11

203

UX-002

12

C

C

O

C

A

A

12

13

13

14

14

15

15

16

16

17

17

18

18

19

19

20

20

21

21

22

22

23

23

24

24

25

25

26

26

27

27

28

28

29

29

30

30

NOTES : 1. BY COB/WHB PACKAGE VENDOR

HOLDS :

RESET DCS


203

UHSR-007

1

R

R

R

R

R

R

1

2

2

3

3

4

4

1

_ _ _ __ RA| D __| N I ||___ 7 2-20007 JAANR073-M

2

3

4

5

6

7

8

9

10

11


12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

28

30

UNIT 015 015-UX-007 CO BOILER / WASTE HEAT BOILER TRIP Project N° - Unit

Doc. type

Code

Serial N°

Rev. index

SHEET

8474L 015

DW

15 14

602

A

7

B 201

201 ATOMIZING STEAM INJECTION VALVE IN BY-PASS LINE

B

B

LP BFW INJECTION VALVE IN BYPASS LINE

B

201

201 1ST REGENERATOR FLUE GAS BLOCK VALVE

1 201

XV-059

30

29

28

27

26

25

24

23

22

21

20

19

18

17

16

15

14

13

12

11

10

9

8

7

6


201

N/A

N/A

UXHS-008

1

O

C

O

O

O

1

E

1oo2

1ST REGEN BYPASS TEMP HH

201

N/A

THS-089A

TXAHH-089A/B

2

O

C

O

O

O

2

B

UX-002

CATALYT CIRCULATION STOP

125

N/A

N/A

UX-002

3

O

C

O

O

O

3

UX-907

COB/WHB TRIP

203

N/A

XHS-941A

XS-941

4

O

B

DCS


XSY-059 5

XV-058B

XV-058A

BV-1501 A

XSY-058A

MXSY-023

XSY-058B 4

TAG No.

3

MOS

2

OOS

1ST REGENERATOR FLUE GAS BYPASS VALVE

2


DESCRIPTION

1

EQUIPMT

LOGIC

BV-1501 B

SERVICE

OTHER Rev. NOTE


GENERAL NOTES :

MXSY-024

CAUSE


B

Rev. NOTE


EQUIPMT

UX-008 COB/WHB 1ST REGENERATOR FLUE GAS BYPASS OPERATION

DESCRIPTION

UNIT 015 RFCC UNIT

SERVICE


EFFECT

UNIT or EQUIPMENT


E

3

E

1

BV-1501B

BV-1501B FULLY OPENED

201

N/A

MZHS-024BA

MZSO-024B

5

E

2

BV-1501A

BV-1501A FULLY OPENED

201

N/A

MZHS-023BA

MZSO-023B

6

E

4

DCS


201

N/A

N/A

XHSO-058AA

7

O

E

4

DCS


201

N/A

N/A

XHSC-058AA

8

C

E

4

DCS


201

N/A

N/A

XHSO-058BA

9

O

9

E

4

DCS


201

N/A

N/A

XHSC-058BA

10

C

10

4

P

5

P

6 7 8

11

11

12

12

13

13

14

14

15

15

16

16

17

17

18

18

19

19

20

20

21

21

22

22

23

23

24

24

25

25

26

26

27

27

28

28

29

29

30

30

NOTES : 1. PERMISSIVE TO CLOSE BV-1501A, WHEN BV1501B OPENED FULLY (INTERLOCKED WITH BV1501B) 2. PERMISSIVE TO CLOSE BV-1501B, WHEN BV1501A OPENED FULLY (INTERLOCKED WITH BV1501A) 3. COB/WHB TRIP BY VENDOR 4. DCS OPERATION IS NOT ALLOWED WHEN UX008 IS TRIPPED.

HOLDS :

RESET DCS


201

UHSR-008

1

B

XV-058A


201

XHSR-058A

2

B

XV-058B


201

XHSR-058B

3

B

XV-059


201

XHSR-059

4

R

7 2-20007 JAANR073-M

R

R

R

1

R

2

R

3

R 1

_ _ _ __ RA| D __| N I ||___

R

2

3

4

5

4

6

7

8

9

10

11


12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

28

30

UNIT 015 015-UX-008 COB/WHB 1ST REGEN FLUE GAS BYPASS OPERATION Project N° - Unit

Doc. type

Code

Serial N°

Rev. index

SHEET

8474L 015

DW

15 14

602

E

8

Rev.

1

NOTE

SERVICE

ESD

X-1507



204

UHS-009

1

30

29

28

27

26

25

24

23

22

21

20

19

18

17

16

15

14

13

12

11

10

9

8

7

6

TAG No.

5

MOS

4

OOS

3


DESCRIPTION

2

EQUIPMT

LOGIC

GENERAL NOTES :

1

OTHER


204

P&ID OTHER LOGIC

CAUSE Rev. NOTE


TAG No

EQUIPMT

UX-009 ELECTROSTATIC PRECIPITATOR TRIP (BY VENDOR)

DESCRIPTION

UNIT 015 RFCC UNIT

SERVICE


EFFECT

UNIT or EQUIPMENT


T

1

2

2

3

3

4

4

5

5

6

6

7

7

8

8

9

9

10

10

11

11

12

12

13

13

14

14

15

15

16

16

17

17

18

18

19

19

20

20

21

21

22

22

23

23

24

24

25

25

26

26

27

27

28

28

29

29

30

30

NOTES : 1. BY ELECTROSTATIC PRECIPITATOR VENDOR

HOLDS :

RESET 1

VENDOR PLC


204

UHSR-009

1

R

1

2

2

3

3

4

4

1

_ _ _ __ RA| D __| N I ||___ 7 2-20007 JAANR073-M

2

3

4

5

6

7

8

9

10

11


12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

28

30

UNIT 015 015-UX-009 ELECTROSTATIC PRECIPITATOR TRIP Project N° - Unit

Doc. type

Code

Serial N°

Rev. index

SHEET

8474L 015

DW

15 14

602

A

9

B

DCS

E

1oo2

E

3

E

1

B

UX-907 BV-1502B UX-002

B 202


B

B


D

202

202 2ND REGENERATOR FLUE GAS BLOCK VALVE

1 202

XV-057


30

29

28

27

26

25

24

23

22

21

20

19

18

17

16

15

14

13

12

11

10

9

8

7

6

XSY-057 5

XV-056B

XV-056A

BV-1502 A

XSY-056A

MXSY-025

XSY-056B 4

TAG No.

3

MOS

2

OOS

2ND REGENERATOR FLUE GAS BYPASS VALVE

2


DESCRIPTION

1

EQUIPMT

LOGIC

BV-1502 B

SERVICE

OTHER Rev. NOTE


GENERAL NOTES :

MXSY-026

CAUSE


D

Rev. NOTE


EQUIPMT

UX-010 COB/WHB 2ND REGENERATOR FLUE GAS BYPASS OPERATION

DESCRIPTION

UNIT 015 RFCC UNIT

SERVICE


EFFECT

UNIT or EQUIPMENT



202

N/A

N/A

UXHS-010

1

O

C

O

O

O

1

2ND REGEN BYPASS TEMP HH

202

N/A

THS-082A

TXAHH-082A/B

2

O

C

O

O

O

2

COB/WHB TRIP

203

N/A

XHS-941A

XS-941

3

O

BV-1502B FULLY OPENED

202

N/A

MZHS-026BA

MZSO-026B

4

CATALYT CIRCULATION STOP

125

N/A

N/A

UX-002

5

O P

3

P C

4

O

O

O

5

E

2

BV-1502A

BV-1501A FULLY OPENED

202

N/A

MZHS-025BA

MZSO-025B

6

E

4

DCS


202

N/A

N/A

XHSO-056AA

7

O

E

4

DCS


202

N/A

N/A

XHSC-056AA

8

C

E

4

DCS


202

N/A

N/A

XHSO-056BA

9

O

9

E

4

DCS


202

N/A

N/A

XHSC-056BA

10

C

10

6 7 8

11

11

12

12

13

13

14

14

15

15

16

16

17

17

18

18

19

19

20

20

21

21

22

22

23

23

24

24

25

25

26

26

27

27

28

28

29

29

30

30

NOTES : 1. PERMISSIVE TO CLOSE BV-1502A, WHEN BV1502B OPENED FULLY (INTERLOCKED WITH BV1502B) 2. PERMISSIVE TO CLOSE BV-1502B, WHEN BV1502A OPENED FULLY (INTERLOCKED WITH BV1502A) 3. COB/WHB TRIP BY VENDOR 4. DCS OPERATION IS NOT ALLOWED WHEN UX010 IS TRIPPED.

HOLDS :

RESET DCS


202

UHSR-010

1

B

XV-056A


202

XHSR-056A

2

B

XV-056B


202

XHSR-056B

3

B

XV-057


202

XHSR-057

4

R

7 2-20007 JAANR073-M

R

R

R

1

R

2

R

3

R 1

_ _ _ __ RA| D __| N I ||___

R

2

3

4

5

4

6

7

8

9

10

11


12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

28

30

UNIT 015 015-UX-010 COB/WHB 2ND REGEN FLUE GAS BYPASS OPERATION Project N° - Unit

Doc. type

Code

Serial N°

Rev. index

SHEET

8474L 015

DW

15 14

602

E

10

Rev.

205 EP BYPASS OPERATION


GENERAL NOTES :

ESD


E-1525

HP BFW FLOW LL

205

UHS-009

-

30

29

28

27

26

25

24

23

22

21

20

19

18

17

16

15

14

13

12

11

10

9

8

7

TAG No.

6

MOS

5

OOS

4


DESCRIPTION

1

EQUIPMT

LOGIC

3

SERVICE

OTHER Rev. NOTE

2

CAUSE


UX-013

TAG No

EQUIPMT

UX-012 ECONOMIZER TRIP

DESCRIPTION

UNIT 015 RFCC UNIT

SERVICE


EFFECT

UNIT or EQUIPMENT

P&ID OTHER LOGIC

NOTE


1

A

1

2

A

2

3

3

4

4

5

5

6

6

7

7

8

8

9

9

10

10

11

11

12

12

13

13

14

14

15

15

16

16

17

17

18

18

19

19

20

20

21

21

22

22

23

23

24

24

25

25

26

26

27

27

28

28

29

29

30

30

NOTES : 1. BY ECONOMIZER VENDOR

HOLDS :

RESET 1

DCS


205

UHSR-012

1

R

1

2

2

3

3

4

4

1

_ _ _ __ RA| D __| N I ||___ 7 2-20007 JAANR073-M

2

3

4

5

6

7

8

9

10

11


12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

28

30

UNIT 015 015-UX-012 ECONOMIZER TRIP Project N° - Unit

Doc. type

Code

Serial N°

Rev. index

SHEET

8474L 015

DW

15 14

602

A

11

B 205


B

B


B

205

B

Rev.


XV-061

30

29

28

27

26

25

24

23

22

21

20

19

18

17

16

15

14

13

12

11

10

9

8

XV-060B

E

4

ECONOMIZER BYPASS

205

N/A

XHS-943A

XS-943

1

O

E

4

DCS


205

N/A

N/A

XHSO-060AA

2

O

E

4

DCS


205

N/A

N/A

XHSC-060AA

3

C

E

4

DCS


205

N/A

N/A

XHSO-060BA

4

O

4

E

4

DCS


205

N/A

N/A

XHSC-060BA

5

C

5

UX-906

O


XSY-061

7

TAG No.

6

MOS

5

OOS

XSY-060B

XV-060A


DESCRIPTION

3

EQUIPMT

LOGIC

4

SERVICE

OTHER Rev. NOTE

XSY-060A

TAG No

CAUSE


GENERAL NOTES :

EQUIPMT

UX-013 ECONOMIZER BYPASS COOLING

DESCRIPTION

UNIT 015 RFCC UNIT

SERVICE


EFFECT

UNIT or EQUIPMENT

P&ID OTHER LOGIC

NOTE


O

1 2 3

6

6

7

7

8

8

9

9

10

10

11

11

12

12

13

13

14

14

15

15

16

16

17

17

18

18

19

19

20

20

21

21

22

22

23

23

24

24

25

25

26

26

27

27

28

28

29

29

30

30

NOTES : 1. DELETED 2. DELETED 3. DELETED 4. ECONOMIZER BYPASS OPERATION INTERLOCK BY VENDOR

HOLDS :

RESET SOFTWARE SWITCH ACTIVE

205

UHSR-013

1

R

B

XV-060A


205

XHSR-060A

2

R

B

XV-060B


205

XHSR-060B

3

B

XV-061


205

XHSR-061

4

B

4

UX-906

7 2-20007 JAANR073-M

R

1 2

R

3

R 1

_ _ _ __ RA| D __| N I ||___

R

2

3

4

5

4

6

7

8

9

10

11


12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

28

30

UNIT 015 015-UX-013 ECONOMIZER BYPASS COOLING Project N° - Unit

Doc. type

Code

Serial N°

Rev. index

SHEET

8474L 015

DW

15 14

602

E

12

B

Rev.

E

2oo3 D-1513

FEED SURGE DRUM LEVEL HH

301

N/A

LHS-404A

LXAHH-404 A/B/C

1

301 RESIDUE TO D-1513


XV-404

30

29

28

27

26

25

24

23

22

21

20

19

18

17

16

15

14

13

12

11

10

9

8

7

TAG No.

6

MOS

5

OOS

4


DESCRIPTION

1

EQUIPMT

LOGIC

3

SERVICE

OTHER Rev. NOTE

GENERAL NOTES :

2

CAUSE


XSY-404

TAG No

EQUIPMT

UX-421 D-1513 OVERFILLING PROTECTION

DESCRIPTION

UNIT 015 RFCC UNIT

SERVICE


EFFECT

UNIT or EQUIPMENT

P&ID OTHER LOGIC

NOTE


C

1

2

2

3

3

4

4

5

5

6

6

7

7

8

8

9

9

10

10

11

11

12

12

13

13

14

14

15

15

16

16

17

17

18

18

19

19

20

20

21

21

22

22

23

23

24

24

25

25

26

26

27

27

28

28

29

29

30

30

NOTES :

HOLDS :

RESET DCS


301

UHSR-421

1

R

1

2

2

3

3

4

4

1

_ _ _ __ RA| D __| N I ||___ 7 2-20007 JAANR073-M

2

3

4

5

6

7

8

9

10

11


12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

28

30

UNIT 015 015-UX-421 D-1513 OVERFILLING PROTECTION Project N° - Unit

Doc. type

Code

Serial N°

Rev. index

SHEET

8474L 015

DW

15 14

602

E

13

B

B

301

301

Rev.

B

D-1513

FEED SURGE DRUM LEVEL LL

301

N/A

LHS-403A

LXALL-403

1

FEED PUMP

FEED PUMP


30

29

28

27

26

25

24

23

22

21

20

19

18

17

16

15

14

13

12

11

10

9

8

7

6

P-1501B

T

5

TAG No.

4

MOS

3

OOS

MXS-436


DESCRIPTION

1

EQUIPMT

LOGIC

2

SERVICE

OTHER Rev. NOTE

GENERAL NOTES : P-1501A

CAUSE


MXS-435

TAG No

EQUIPMT

UX-422 P-1501A/B PROTECTION

DESCRIPTION

UNIT 015 RFCC UNIT

SERVICE


EFFECT

UNIT or EQUIPMENT

P&ID OTHER LOGIC

NOTE


T

1

2

2

3

3

4

4

5

5

6

6

7

7

8

8

9

9

10

10

11

11

12

12

13

13

14

14

15

15

16

16

17

17

18

18

19

19

20

20

21

21

22

22

23

23

24

24

25

25

26

26

HOLDS :

27

27

1.-

28

28

29

29

30

30

NOTES : 1.

RESET DCS


301

UHSR-422

1

R

R

1

2

2

3

3

4

4

1

_ _ _ __ RA| D __| N I ||___ 7 2-20007 JAANR073-M

2

3

4

5

6

7

8

9

10

11


12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

28

30

UNIT 015 015-UX-422 P-1501A/B PROTECTION Project N° - Unit

Doc. type

Code

Serial N°

Rev. index

SHEET

8474L 015

DW

15 14

602

A

14

306

306 P-1507A DISCHARGE MOTOR OPERATED VALVE

E

E 306

P-1507B DISCHARGE MOTOR OPERATED VALVE

E

E 306

B 1

P-1507A SUCTION MOTOR OPERATED VALVE

P-1507B SUCTION MOTOR OPERATED VALVE

B 1

306 HCO RECYCLE PUMP

306

XV-405

XV-406

XV-407

XV-408

XSY-405

XSY-406

XSY-407

XSY-408

A.- UNLESS OTHERWISE SPECIFIED, ALL DRAWING NUMBERS SHALL BE PREFIXED BY 8474L-015-PID0021 . B.- UNLESS OTHERWISE SPECIFIED, ALL INSTRUMENT TAG NUMBERS SHALL BE PREFIXED BY 015 . C.- PER ESD SYSTEMS STANDARD 8474L-JSS-1515001 CLAUSE 7.1, ALL INPUTS SHALL HAVE A DELAY OF 0.5 SECONDS UNLESS OTHERWISE SPECIFIED. D.- ALL ESD VALVES WILL BE PROVIDED WITH PARTIAL STROKE TEST FACILITY UNLESS OTHERWISE SPECIFIED. E.- ALL INPUTS AND OUTPUTS SHALL BE FAILSAFE UNLESS OTHERWISE SPECIFIED. FIELD INPUT CONTACTS SHALL OPEN TO TRIP. OUTPUT SHALL DE-ENERGIZE TO TRIP. F.- DCS ALARMS SHALL BE PROVIDED IN ACCORDANCE WITH LONG FORMAT SHOWN ON SYMBOLOGY P&ID 8474L-000-PID-0090-010 TO 013 INCLUSIVE. G.- ALL OUTPUT SHALL BE PROVIDED WITH MOS.

30

29

28

27

26

25

24

23

22

21

20

19

18

17

16

15

14

13

12

11

10

9

8

7

P-1507B

6

P-1507A

5

TAG No.

4

MOS

3

OOS

MXS-482

OVERRIDE TAG No.

P&ID

DESCRIPTION

2

EQUIPMT

LOGIC

1

SERVICE

OTHER Rev. NOTE


GENERAL NOTES :

MXS-481

CAUSE

HCO RECYCLE PUMP

Rev. NOTE


EQUIPMT

UX-423 T-1501 & P-1507A/B INVENTORY ISOLATION

DESCRIPTION

UNIT 015 RFCC UNIT

SERVICE


EFFECT

UNIT or EQUIPMENT


B

ESD


306

N/A

N/A

UXHS-423A

1

T

T

C

C

C

C

1

B

LOCAL


306

N/A

N/A

UXHS-423B

2

T

T

C

C

C

C

2

E

1

XV-406

80% LIMIT SWITCH ACTIVE

306

N/A

XZHS-406-A

XZSM-406

3

T

E

1

XV-406

80% LIMIT SWITCH NOT ACTIVE

306

N/A

XZHS-406-A

XZSM-406

4

P

E

1

XV-405


306

N/A

XZHS-405-A

XZSM-405

5

T

E

1

XV-405


306

N/A

XZHS-405-A

XZSM-405

6

P

C

LOCAL


306

N/A

N/A

UXHS-423C

7

T

T

C

C

C

C

7

C

LOCAL


306

N/A

N/A

UXHS-423D

8

T

T

C

C

C

C

8

C

LOCAL


306

N/A

N/A

UXHS-423E

9

T

T

C

C

C

C

3 4 5 6

9

10

10

11

11

12

12

13

13

14

14

15

15

16

16

17

17

18

18

19

19

20

20

21

21

22

22

23

23

24

24

25

25

26

26

27

27

28

28

29

29

30

30

NOTES : 1. MOTOR OF PUMP SHALL BE AUTOMATICALLY STOPPED WHEN XV IS LESS THAN 80% OPEN AND CANNOT BE RESTARTED UNTIL XV IS OPEN MORE THAN 80%.

HOLDS :

RESET C

DCS


306

UHSR-423

1

C

LOCAL


306

XHSR-405

2

C

LOCAL


306

XHSR-406

3

C

LOCAL


306

XHSR-407

4

C

LOCAL


306

XHSR-408

5

R

7 2-20007 JAANR073-M

R

R

R

R

1

R

2

R

3

R R 1

_ _ _ __ RA| D __| N I ||___

R

2

3

4

5

6

4

7

8

9

10

11


12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

28

30

UNIT 015 015-UX-423 T-1501 & P-1507A/B INVENTORY ISOLATION Project N° - Unit

Doc. type

Code

Serial N°

Rev. index

SHEET

8474L 015

DW

15 14

602

E

15

308

308 P-1508B DISCHARGE MOTOR OPERATED VALVE

E

E 308

P-1508A DISCHARGE MOTOR OPERATED VALVE

E

E 308

B 1



B 1

308 HCO PUMPAROUND PUMP

308

XV-409

XV-410

XV-411

XV-412

XSY-409

XSY-410

XSY-411

XSY-412


30

29

28

27

26

25

24

23

22

21

20

19

18

17

16

15

14

13

12

11

10

9

8

7

P-1508B

6

P-1508A

5

TAG No.

4

MOS

3

OOS

MXS-445

OVERRIDE TAG No.

P&ID

DESCRIPTION

2

EQUIPMT

LOGIC

1

SERVICE

OTHER Rev. NOTE


GENERAL NOTES :

MXS-444

CAUSE

HCO PUMPAROUND PUMP

Rev. NOTE


EQUIPMT


DESCRIPTION

UNIT 015 RFCC UNIT

SERVICE


EFFECT

UNIT or EQUIPMENT


B

ESD


308

N/A

N/A

UXHS-424A

1

T

T

C

C

C

C

1

B

LOCAL


308

N/A

N/A

UXHS-424B

2

T

T

C

C

C

C

2

E

1

XV-409


308

N/A

XZHS-409-A

XZSM-409

3

T

E

1

XV-409


308

N/A

XZHS-409-A

XZSM-409

4

P

E

1

XV-410


308

N/A

XZHS-410-A

XZSM-410

5

T

E

1

XV-410


308

N/A

XZHS-410-A

XZSM-410

6

P

C

LOCAL


308

N/A

N/A

UXHS-424C

7

T

T

C

C

C

C

7

C

LOCAL


308

N/A

N/A

UXHS-424D

8

T

T

C

C

C

C

8

C

LOCAL


308

N/A

N/A

UXHS-424E

9

T

T

C

C

C

C

3 4 5 6

9

10

10

11

11

12

12

13

13

14

14

15

15

16

16

17

17

18

18

19

19

20

20

21

21

22

22

23

23

24

24

25

25

26

26

27

27

28

28

29

29

30

30


HOLDS :

RESET C

DCS


308

UHSR-424

1

C

LOCAL


308

XHSR-409

2

C

LOCAL


308

XHSR-410

3

C

LOCAL


308

XHSR-411

4

C

LOCAL


308

XHSR-412

5

R

7 2-20007 JAANR073-M

R

R

R

R

1

R

2

R

3

R R 1

_ _ _ __ RA| D __| N I ||___

R

2

3

4

5

6

4

7

8

9

10

11


12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

28

30


Doc. type

Code

Serial N°

Rev. index

SHEET

8474L 015

DW

15 14

602

C

16

B

T-1501

1

FRACTIONATOR LEVEL LL

310

N/A

LHS-414A

LXALL-414

1

UX-432 321 SLURRY PRODUCT TO D-1515


XV-451

30

29

28

27

26

25

24

23

22

21

20

19

18

17

16

15

14

13

12

11

10

9

8

7

6

TAG No.

5

MOS

4

OOS

3


DESCRIPTION

1

EQUIPMT

LOGIC

GENERAL NOTES :

2

SERVICE

OTHER Rev. NOTE


XSY-451

CAUSE

B

B

Rev. NOTE


EQUIPMT

UX-425 SLURRY PUMPS P-1519A/B/C PROTECTION

DESCRIPTION

UNIT 015 RFCC UNIT

SERVICE


EFFECT

UNIT or EQUIPMENT


C

1

2

2

3

3

4

4

5

5

6

6

7

7

8

8

9

9

10

10

11

11

12

12

13

13

14

14

15

15

16

16

17

17

18

18

19

19

20

20

21

21

22

22

23

23

24

24

25

25

26

26

27

27

28

28

29

29

30

30

NOTES : 1. XV-451 WILL BE TRIPPED BY UX-432.

HOLDS :

RESET DCS


310

UHSR-425

1

R

1

2

2

3

3

4

4

1

_ _ _ __ RA| D __| N I ||___ 7 2-20007 JAANR073-M

2

3

4

5

6

7

8

9

10

11


12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

28

30

UNIT 015 015-UX-425 SLURRY PUMP P-1519A/B/C PROTECTION Project N° - Unit

Doc. type

Code

Serial N°

Rev. index

SHEET

8474L 015

DW

15 14

602

B

17

311

311

311

P-1519B DISCHARGE MOTOR OPERATED VALVE

P-1519C DISCHARGE MOTOR OPERATED VALVE

E

E 311


E

E 311

P-1519C SUCTION MOTOR OPERATED VALVE

E

E

B


311

1 311

311

SLURRY PUMPAROUND PUMP TURBINE HP STEAM VALVE


B

311


XV-416

XV-417

XV-418

XSY-416

XSY-417

XSY-418


30

29

28

27

26

25

24

23

22

21

20

19

18

17

16

15

14

13

12

11

10

XV-415 XSY-415

9

XV-414 XSY-414

8

XV-413 XSY-413

7

XV-423 XSY-423

6

XV-421 XSY-421

5

TAG No.

4

MOS

3

OOS


1


DESCRIPTION

2

EQUIPMT

1

LOGIC

XV-419

SERVICE

OTHER Rev. NOTE


GENERAL NOTES :

XSY-419

CAUSE

1

B

Rev. NOTE


EQUIPMT

UX-426 T-1501 & P-1519A/B/C INVENTORY ISOLATION

DESCRIPTION

UNIT 015 RFCC UNIT

SERVICE


EFFECT

UNIT or EQUIPMENT


B

ESD


311

N/A

N/A

UXHS-426A

1

C

C

C

C

C

C

C

C

C

1

B

LOCAL


311

N/A

N/A

UXHS-426B

2

C

C

C

C

C

C

C

C

C

2

E

1

XV-413


311

N/A

XZHS-413-A

XZSM-413

3

C

E

1

XV-413


311

N/A

XZHS-413-A

XZSM-413

4

P

E

1

XV-414


311

N/A

XZHS-414-A

XZSM-414

5

C

E

1

XV-414


311

N/A

XZHS-414-A

XZSM-414

6

P

E

1

XV-415


311

N/A

XZHS-415-A

XZSM-415

7

C

7

E

1

XV-415


311

N/A

XZHS-415-A

XZSM-415

8

P

8

B

2

DCS


311

N/A

N/A

HS-419

9

C

9

E

2

LOCAL


311

N/A

N/A

XHSO-419B

10

O

10

E

2

LOCAL


311

N/A

N/A

XHSC-419B

11

C

B

2

DCS


311

N/A

N/A

HS-421

12

C

12

E

2

LOCAL


311

N/A

N/A

XHSO-421B

13

O

13

E

2

LOCAL


311

N/A

N/A

XHSC-421B

14

C

B

2

DCS


311

N/A

N/A

HS-423

15

C

15

E

2

LOCAL


311

N/A

N/A

XHSO-423B

16

O

16

E

2

LOCAL


311

N/A

N/A

XHSC-423B

17

C

C

LOCAL


311

N/A

N/A

UXHS-426C

18

C

C

C

C

C

C

C

C

C

18

C

LOCAL


311

N/A

N/A

UXHS-426D

19

C

C

C

C

C

C

C

C

C

19

C

LOCAL


311

N/A

N/A

UXHS-426E

20

C

C

C

C

C

C

C

C

C

20

C

LOCAL


311

N/A

N/A

UXHS-426F

21

C

C

C

C

C

C

C

C

C

21

C

LOCAL


311

N/A

N/A

UXHS-426G

22

C

C

C

C

C

C

C

C

C

22

3 4 5 6

11

14

17

23

23

24

24

25

25

26

26

27

27

28

28

29

29

30

30

NOTES : 1. TURBINE OF PUMP SHALL BE AUTOMATICALLY STOPPED WHEN XV IS LESS THAN 80% OPEN AND CANNOT BE RESTARTED UNTIL XV IS OPEN MORE THAN 80%. 2. DCS/LOCAL OPERATION IS NOT ALLOWED WHEN UX-013 IS TRIPPED.

HOLDS :

RESET C

DCS


311

UHSR-426

1

E

LOCAL


311

XHSR-413

2

E

LOCAL


311

XHSR-414

3

E

LOCAL


311

XHSR-415

4

E

LOCAL


311

XHSR-416

5

E

LOCAL


311

XHSR-417

6

E

LOCAL


311

XHSR-418

7

R

7 2-20007 JAANR073-M

R

R

R

R

R

R

R

1

R

2

R

3

R

4

R R R 1

_ _ _ __ RA| D __| N I ||___

R

2

3

4

5

6

7

8

9

10

11


12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

28

30

UNIT 015 015-UX-426 T-1501 & P-1519A/B/C INVENTORY ISOLATION Project N° - Unit

Doc. type

Code

Serial N°

Rev. index

SHEET

8474L 015

DW

15 14

602

E

18

316

316 P-1509B DISCHARGE MOTOR OPERATED VALVE

E

E 316


E

E 316

B 1



B 1

316 HCO PRODUCT PUMP

316

XV-430

XV-431

XV-432

XV-433

XSY-430

XSY-431

XSY-432

XSY-433


30

29

28

27

26

25

24

23

22

21

20

19

18

17

16

15

14

13

12

11

10

9

8

7

P-1509B

6

P-1509A

5

TAG No.

4

MOS

3

OOS

MXS-447

OVERRIDE TAG No.

P&ID

DESCRIPTION

2

EQUIPMT

LOGIC

1

SERVICE

OTHER Rev. NOTE


GENERAL NOTES :

MXS-446

CAUSE

HCO PRODUCT PUMP

Rev. NOTE


EQUIPMT


DESCRIPTION

UNIT 015 RFCC UNIT

SERVICE


EFFECT

UNIT or EQUIPMENT


B

ESD


316

N/A

N/A

UXHS-427A

1

T

T

C

C

C

C

1

B

LOCAL


316

N/A

N/A

UXHS-427B

2

T

T

C

C

C

C

2

E

1

XV-430


316

N/A

XZHS-430-A

XZSM-430

3

T

E

1

XV-430


316

N/A

XZHS-430-A

XZSM-430

4

P

E

1

XV-431


316

N/A

XZHS-431-A

XZSM-431

5

T

5

E

1

XV-431


316

N/A

XZHS-431-A

XZSM-431

6

P

6

B

T-1504

HCO STRIPPER LEVEL LL

316

N/A

LHS-432A

LXALL-432

7

T

T

C

LOCAL


316

N/A

N/A

UXHS-427C

8

T

T

C

C

C

C

C

LOCAL


316

N/A

N/A

UXHS-427E

9

T

T

C

C

C

C

9

C

LOCAL


316

N/A

N/A

UXHS-427D

10

T

T

C

C

C

C

10

3 4

7 8

11

11

12

12

13

13

14

14

15

15

16

16

17

17

18

18

19

19

20

20

21

21

22

22

23

23

24

24

25

25

26

26

27

27

28

28

29

29

30

30

NOTES : 1. MOTOR OF PUMP SHALL BE AUTOMATICALLY STOPPED WHEN XV IS LESS THAN 80% OPEN AND CANNOT BE RESTARTED UNTIL XV IS OPEN MORE THAN 80%. 2. DCS/LOCAL OPERATION IS NOT ALLOWED WHEN UX-427 IS TRIPPED.

HOLDS :

RESET C

DCS


316

UHSR-427

1

E

LOCAL


316

XHSR-430

2

E

LOCAL


316

XHSR-431

3

E

LOCAL


316

XHSR-432

4

E

LOCAL


316

XHSR-433

5

R

7 2-20007 JAANR073-M

R

R

R

R

1

R

2

R

3

R R 1

_ _ _ __ RA| D __| N I ||___

R

2

3

4

5

6

4

7

8

9

10

11


12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

28

30


Doc. type

Code

Serial N°

Rev. index

SHEET

8474L 015

DW

15 14

602

C

19

B

B

317

317

Rev.

B

T-1502

HN STRIPPER LEVEL LL

317

N/A

LHS-440A

LXALL-440

1

HEAVY NAPHTHA PRODUCTPUMP

HEAVY NAPHTHA PRODUCTPUMP


30

29

28

27

26

25

24

23

22

21

20

19

18

17

16

15

14

13

12

11

10

9

8

7

6

P-1515B

T

5

TAG No.

4

MOS

3

OOS

MXS-451


DESCRIPTION

1

EQUIPMT

LOGIC

2

SERVICE

OTHER Rev. NOTE


CAUSE


MXS-450

TAG No

EQUIPMT


DESCRIPTION

UNIT 015 RFCC UNIT

SERVICE


EFFECT

UNIT or EQUIPMENT

P&ID OTHER LOGIC

NOTE


T

1

2

2

3

3

4

4

5

5

6

6

7

7

8

8

9

9

10

10

11

11

12

12

13

13

14

14

15

15

16

16

17

17

18

18

19

19

20

20

21

21

22

22

23

23

24

24

25

25

26

26

27

27

28

28

29

29

30

30

NOTES :

HOLDS :

RESET DCS


317

UHSR-428

1

R

R

1

2

2

3

3

4

4

1

_ _ _ __ RA| D __| N I ||___ 7 2-20007 JAANR073-M

2

3

4

5

6

7

8

9

10

11


12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

28

30


Doc. type

Code

Serial N°

Rev. index

SHEET

8474L 015

DW

15 14

602

A

20

B

B

318

318

Rev.

T-1503

LCO STRIPPER LEVEL LL

318

N/A

LHS-437A

LXALL-437

1

LCO STRIPPER PUMP

LCO STRIPPER PUMP


30

29

28

27

26

25

24

23

22

21

20

19

18

17

16

15

14

13

12

11

10

9

8

7

6

P-1511B

T

5

TAG No.

4

MOS

3

OOS

MXS-453


DESCRIPTION

1

EQUIPMT

LOGIC

2

SERVICE

OTHER Rev. NOTE

P-1511A

CAUSE


GENERAL NOTES :

MXS-452

TAG No

EQUIPMT


DESCRIPTION

UNIT 015 RFCC UNIT

SERVICE


EFFECT

UNIT or EQUIPMENT

P&ID OTHER LOGIC

NOTE


T

1

2

2

3

3

4

4

5

5

6

6

7

7

8

8

9

9

10

10

11

11

12

12

13

13

14

14

15

15

16

16

17

17

18

18

19

19

20

20

21

21

22

22

23

23

24

24

25

25

26

26

27

27

28

28

29

29

30

30

NOTES :

HOLDS :

RESET DCS


318

UHSR-429

1

R

R

1

2

2

3

3

4

4

1

_ _ _ __ RA| D __| N I ||___ 7 2-20007 JAANR073-M

2

3

4

5

6

7

8

9

10

11


12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

28

30


Doc. type

Code

Serial N°

Rev. index

SHEET

8474L 015

DW

15 14

602

A

21

B

B 1 320

320 P-1516A/B & P-1518A/B SUCTION SHUT-OFF VALVE

B 1 320


B 1 320


B 1

P-1518B

XV-444

MXS-461

XSY-444


30

29

28

27

26

25

24

23

22

21

20

19

18

17

16

15

14

13

12

11

10

9

8

7

6

P-1518A MXS-460

5

P-1516B MXS-457

4

TAG No.

3

MOS

2

OOS


320


DESCRIPTION

1

EQUIPMT

LOGIC

P-1516A

SERVICE

OTHER Rev. NOTE


GENERAL NOTES :

MXS-456

CAUSE


Rev. NOTE


EQUIPMT

UX-430 D-1514, P-1516A/B & P-1518A/B INVENTORY ISOLATION

DESCRIPTION

UNIT 015 RFCC UNIT

SERVICE


EFFECT

UNIT or EQUIPMENT


B

ESD


320

N/A

N/A

UXHS-430A

1

T

T

T

T

C

1

B

LOCAL


320

N/A

N/A

UXHS-430B

2

T

T

T

T

C

2

E

1

XV-444


320

N/A

XZHS-444-A

XZSM-444

3

T

T

T

T

3

E

1

XV-444


320

N/A

XZHS-444-A

XZSM-444

4

P

P

P

P

4

B

D-1514

D-1514 LEVEL LL

320

N/A

LHS-444A

LXALL-444

5

T

T

T

T

E

LOCAL


320

N/A

N/A

XHSO-444B

6

O

6

E

LOCAL


320

N/A

N/A

XHSC-444B

7

C

7

5

8

8

9

9

10

10

11

11

12

12

13

13

14

14

15

15

16

16

17

17

18

18

19

19

20

20

21

21

22

22

23

23

24

24

25

25

26

26

27

27

28

28

29

29

30

30


HOLDS : 1.

RESET C

DCS


320

UHSR-430

1

B

LOCAL


320

XHSR-444

2

R

R

R

R

R

1

R

2

3

3

4

4

1

_ _ _ __ RA| D __| N I ||___ 7 2-20007 JAANR073-M

2

3

4

5

6

7

8

9

10

11


12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

28

30

UNIT 015 015-UX-430 D-1514, P-1516A/B & P-1518A/B INVENTORY ISOLATION Project N° - Unit

Doc. type

Code

Serial N°

Rev. index

SHEET

8474L 015

DW

15 14

602

C

22

B

B 1 320 OVERHEAD SOUR WATER PUMP

320

B 1 320 OVERHEAD SOUR WATER PUMP

P-1517A/B SUCTION SHUT-OFF VALVE

P-1517B

XV-445 XSY-445


30

29

28

27

26

25

24

23

22

21

20

19

18

17

16

15

14

13

12

11

10

9

8

7

6

5

TAG No.

4

MOS

3

OOS

MXS-459


DESCRIPTION

1

EQUIPMT

LOGIC

2

SERVICE

OTHER Rev. NOTE

P-1517A

CAUSE


GENERAL NOTES :

MXS-458

Rev. NOTE


EQUIPMT

UX-431 D-1524, P-1517A/B INVENTORY ISOLATION

DESCRIPTION

UNIT 015 RFCC UNIT

SERVICE


EFFECT

UNIT or EQUIPMENT


B

D-1514

FRACT REFLUX DRUM BOOT LL

320

N/A

LHS-447A

LXALL-447

1

T

T

B

ESD


320

N/A

N/A

UXHS-431A

2

T

T

C

2

B

LOCAL


320

N/A

N/A

UXHS-431B

3

T

T

C

3

1

E

1

XV-445


320

N/A

XZHS-445-A

XZSM-445

4

T

T

E

1

XV-445


320

N/A

XZHS-445-A

XZSM-445

5

P

P

E

LOCAL


320

N/A

N/A

XHSO-445B

6

O

6

E

LOCAL


320

N/A

N/A

XHSC-445B

7

C

7

4 5

8

8

9

9

10

10

11

11

12

12

13

13

14

14

15

15

16

16

17

17

18

18

19

19

20

20

21

21

22

22

23

23

24

24

25

25

26

26

27

27

28

28

29

29

30

30


HOLDS :

RESET C

DCS


320

UHSR-431

1

B

LOCAL


320

XHSR-445

2

R

R

R

1

R

2

3

3

4

4

1

_ _ _ __ RA| D __| N I ||___ 7 2-20007 JAANR073-M

2

3

4

5

6

7

8

9

10

11


12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

28

30

UNIT 015 015-UX-431 D-1524, P-1517A/B INVENTORY ISOLATION Project N° - Unit

Doc. type

Code

Serial N°

Rev. index

SHEET

8474L 015

DW

15 14

602

C

23

B

Rev.

1

NOTE

B

D-1515

D-1515 LEVEL HH

321

N/A

LHS-478A

LXAHH-478

B

1


XV-451

30

29

28

27

26

25

24

23

22

21

20

19

18

17

16

15

14

13

12

11

10

9

8

7

6

TAG No.

5

MOS

4

OOS

3


DESCRIPTION

1

EQUIPMT

LOGIC

GENERAL NOTES :

2

SERVICE

OTHER Rev. NOTE


XSY-451

CAUSE

SLURRY PRODUCT TO D-1515

321

UX-425


EQUIPMT


DESCRIPTION

UNIT 015 RFCC UNIT

SERVICE


EFFECT

UNIT or EQUIPMENT


C

1

2

2

3

3

4

4

5

5

6

6

7

7

8

8

9

9

10

10

11

11

12

12

13

13

14

14

15

15

16

16

17

17

18

18

19

19

20

20

21

21

22

22

23

23

24

24

25

25

26

26

27

27

28

28

29

29

30

30

NOTES : 1. XV-451 WILL BE TRIPPED BY UX-425 .

HOLDS :

RESET DCS


321

UHSR-432

1

R

1

2

2

3

3

4

4

1

_ _ _ __ RA| D __| N I ||___ 7 2-20007 JAANR073-M

2

3

4

5

6

7

8

9

10

11


12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

28

30


Doc. type

Code

Serial N°

Rev. index

SHEET

8474L 015

DW

15 14

602

B

24

B

B

321

321

Rev.

B

D-1515

D-1515 LEVEL LL

321

N/A

LHS-450A

LXALL-450

1

SLURRY PRODUCT PUMP

SLURRY PRODUCT PUMP


30

29

28

27

26

25

24

23

22

21

20

19

18

17

16

15

14

13

12

11

10

9

8

7

6

P-1504B

T

5

TAG No.

4

MOS

3

OOS

MXS-463


DESCRIPTION

1

EQUIPMT

LOGIC

2

SERVICE

OTHER Rev. NOTE

P-1504A

CAUSE


GENERAL NOTES :

MXS-462

TAG No

EQUIPMT


DESCRIPTION

UNIT 015 RFCC UNIT

SERVICE


EFFECT

UNIT or EQUIPMENT

P&ID OTHER LOGIC

NOTE


T

1

2

2

3

3

4

4

5

5

6

6

7

7

8

8

9

9

10

10

11

11

12

12

13

13

14

14

15

15

16

16

17

17

18

18

19

19

20

20

21

21

22

22

23

23

24

24

25

25

26

26

27

27

28

28

29

29

30

30

NOTES :

HOLDS :

RESET DCS


321

UHSR-433

1

R

R

1

2

2

3

3

4

4

1

_ _ _ __ RA| D __| N I ||___ 7 2-20007 JAANR073-M

2

3

4

5

6

7

8

9

10

11


12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

28

30


Doc. type

Code

Serial N°

Rev. index

SHEET

8474L 015

DW

15 14

602

A

25

B

D-1517

D-1517 LEVEL LL

324

N/A

LHS-458A

LXALL-458

1

1 324

B

1 BACK FLUSH OIL RECYCLE PUMP


30

29

28

27

26

25

24

23

22

21

20

19

18

17

16

15

14

13

12

11

10

9

8

7

6

5

P-1506B MXS-465

T

4

TAG No.

3

MOS

2

OOS

324

B


DESCRIPTION

1

EQUIPMT

LOGIC

P-1506A

SERVICE

OTHER Rev. NOTE

GENERAL NOTES :

MXS-464

CAUSE



Rev. NOTE


EQUIPMT


DESCRIPTION

UNIT 015 RFCC UNIT

SERVICE


EFFECT

UNIT or EQUIPMENT


T

1

2

2

3

3

4

4

5

5

6

6

7

7

8

8

9

9

10

10

11

11

12

12

13

13

14

14

15

15

16

16

17

17

18

18

19

19

20

20

21

21

22

22

23

23

24

24

25

25

26

26

27

27

28

28

29

29

30

30

NOTES : 1. TRIPPED BY UX-001.

HOLDS :

RESET DCS


324

UHSR-434

1

R

R

1

2

2

3

3

4

4

1

_ _ _ __ RA| D __| N I ||___ 7 2-20007 JAANR073-M

2

3

4

5

6

7

8

9

10

11


12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

28

30


Doc. type

Code

Serial N°

Rev. index

SHEET

8474L 015

DW

15 14

602

A

26

B

Rev.

B

D-1517

D-1515 LEVEL HH

324

N/A

LHS-459A

LXAHH-459

1

324 HCO PRODUCT TO D-1517


XV-459

30

29

28

27

26

25

24

23

22

21

20

19

18

17

16

15

14

13

12

11

10

9

8

7

TAG No.

6

MOS

5

OOS

4


DESCRIPTION

1

EQUIPMT

LOGIC

3

SERVICE

OTHER Rev. NOTE

GENERAL NOTES :

2

CAUSE


XSY-459

TAG No

EQUIPMT


DESCRIPTION

UNIT 015 RFCC UNIT

SERVICE


EFFECT

UNIT or EQUIPMENT

P&ID OTHER LOGIC

NOTE


C

1

2

2

3

3

4

4

5

5

6

6

7

7

8

8

9

9

10

10

11

11

12

12

13

13

14

14

15

15

16

16

17

17

18

18

19

19

20

20

21

21

22

22

23

23

24

24

25

25

26

26

27

27

28

28

29

29

30

30

NOTES :

HOLDS :

RESET DCS


324

UHSR-435

1

R

1

2

2

3

3

4

4

1

_ _ _ __ RA| D __| N I ||___ 7 2-20007 JAANR073-M

2

3

4

5

6

7

8

9

10

11


12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

28

30


Doc. type

Code

Serial N°

Rev. index

SHEET

8474L 015

DW

15 14

602

A

27

B

B

325

325

Rev.

B

D-1516

D-1516 LEVEL LL

325

N/A

LHS-462A

LXALL-462

1

BACK FLUSH OIL PUMP

BACK FLUSH OIL PUMP


30

29

28

27

26

25

24

23

22

21

20

19

18

17

16

15

14

13

12

11

10

9

8

7

6

P-1505B

T

5

TAG No.

4

MOS

3

OOS

MXS-467


DESCRIPTION

1

EQUIPMT

LOGIC

2

SERVICE

OTHER Rev. NOTE

P-1505A

CAUSE


GENERAL NOTES :

MXS-466

TAG No

EQUIPMT


DESCRIPTION

UNIT 015 RFCC UNIT

SERVICE


EFFECT

UNIT or EQUIPMENT

P&ID OTHER LOGIC

NOTE


T

1

2

2

3

3

4

4

5

5

6

6

7

7

8

8

9

9

10

10

11

11

12

12

13

13

14

14

15

15

16

16

17

17

18

18

19

19

20

20

21

21

22

22

23

23

24

24

25

25

26

26

27

27

28

28

29

29

30

30

NOTES :

HOLDS :

RESET DCS


325

UHSR-436

1

R

R

1

2

2

3

3

4

4

1

_ _ _ __ RA| D __| N I ||___ 7 2-20007 JAANR073-M

2

3

4

5

6

7

8

9

10

11


12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

28

30


Doc. type

Code

Serial N°

Rev. index

SHEET

8474L 015

DW

15 14

602

A

28

B

Rev.

B

D-1516

D-1516 LEVEL HH

325

N/A

LHS-463A

LXAHH-463

1

325 HCO PRODUCT TO D-1516


FV-467

30

29

28

27

26

25

24

23

22

21

20

19

18

17

16

15

14

13

12

11

10

9

8

7

TAG No.

6

MOS

5

OOS

4


DESCRIPTION

1

EQUIPMT

LOGIC

3

SERVICE

OTHER Rev. NOTE

GENERAL NOTES :

2

CAUSE


FSY-467

TAG No

EQUIPMT


DESCRIPTION

UNIT 015 RFCC UNIT

SERVICE


EFFECT

UNIT or EQUIPMENT

P&ID OTHER LOGIC

NOTE


C

1

2

2

3

3

4

4

5

5

6

6

7

7

8

8

9

9

10

10

11

11

12

12

13

13

14

14

15

15

16

16

17

17

18

18

19

19

20

20

21

21

22

22

23

23

24

24

25

25

26

26

27

27

28

28

29

29

30

30

NOTES :

HOLDS :

RESET DCS


325

UHSR-437

1

R

1

2

2

3

3

4

4

1

_ _ _ __ RA| D __| N I ||___ 7 2-20007 JAANR073-M

2

3

4

5

6

7

8

9

10

11


12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

28

30


Doc. type

Code

Serial N°

Rev. index

SHEET

8474L 015

DW

15 14

602

A

29

B

B

326

326

Rev.

HCO FLUSHING OIL PUMP (P-1512A)


P-1521B

D-1518

D-1518 LEVEL LL

326

N/A

LHS-468A

LXALL-468

1

C

DCS


326

N/A

N/A

HS-468

2

C

2

2,3

LOCAL


326

N/A

N/A

XHSO-468B

3

O

3

E

2,3

LOCAL


326

N/A

N/A

XHSC-468B

4

C

4

B

1

DCS

FLUSHING OIL PRESS LOW

326

N/A

N/A

PAL-487

5

O

5

E

3

LOCAL


326

N/A

N/A

XHSM-468B

6

A

6

B B

2

E


30

29

28

27

26

25

24

23

22

21

20

19

18

17

16

15

14

13

12

11

10

9

8

7

6

5

TAG No.

4

MOS

3

OOS

MXS-468


DESCRIPTION

1

EQUIPMT

LOGIC

2

SERVICE

OTHER Rev. NOTE

XV-468

CAUSE


GENERAL NOTES :

XSY-468

TAG No

EQUIPMT


DESCRIPTION

UNIT 015 RFCC UNIT

SERVICE


EFFECT

UNIT or EQUIPMENT

P&ID OTHER LOGIC

NOTE


T

1

7

7

8

8

9

9

10

10

11

11

12

12

13

13

14

14

15

15

16

16

17

17

18

18

19

19

20

20

21

21

22

22

23

23

24

24

25

25

26

26

27

27

28

28

29

29

30

30

NOTES : 1. DETAIL TO BE REFFERED TO 8474L-015-SP1511-101. 2. DCS/LOCAL OPERATION IS NOT ALLOWED WHEN UX-438 IS TRIPPED. 3. XHSM-468B IS REMOTE/LOCAL SWITCH. XHSO-468B/XHSC-468B/XHSM-468B ARE 3 POSITION SWITCH.

HOLDS :

RESET DCS


326

UHSR-438

1

R

R

1

2

2

3

3

4

4

1

_ _ _ __ RA| D __| N I ||___ 7 2-20007 JAANR073-M

2

3

4

5

6

7

8

9

10

11


12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

28

30


Doc. type

Code

Serial N°

Rev. index

SHEET

8474L 015

DW

15 14

602

E

30

B

B

327

327

Rev.

B

D-1519

D-1519 LEVEL LL

327

N/A

LHS-471A

LXALL-471

1




30

29

28

27

26

25

24

23

22

21

20

19

18

17

16

15

14

13

12

11

10

9

8

7

6

P-1522B

T

5

TAG No.

4

MOS

3

OOS

MXS-470


DESCRIPTION

1

EQUIPMT

LOGIC

2

SERVICE

OTHER Rev. NOTE

P-1522A

CAUSE


GENERAL NOTES :

MXS-469

TAG No

EQUIPMT


DESCRIPTION

UNIT 015 RFCC UNIT

SERVICE


EFFECT

UNIT or EQUIPMENT

P&ID OTHER LOGIC

NOTE


T

1

2

2

3

3

4

4

5

5

6

6

7

7

8

8

9

9

10

10

11

11

12

12

13

13

14

14

15

15

16

16

17

17

18

18

19

19

20

20

21

21

22

22

23

23

24

24

25

25

26

26

27

27

28

28

29

29

30

30

NOTES :

HOLDS :

RESET DCS


327

UHSR-439

1

R

R

1

2

2

3

3

4

4

1

_ _ _ __ RA| D __| N I ||___ 7 2-20007 JAANR073-M

2

3

4

5

6

7

8

9

10

11


12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

28

30


Doc. type

Code

Serial N°

Rev. index

SHEET

8474L 015

DW

15 14

602

A

31

B

Rev.

B

D-1522

D-1522 LEVEL HH

329

N/A

LHS-485A

LXAHH-485

1

329 LIGHT SLOP TO D-1522

A.- UNLESS OTHERWISE SPECIFIED, ALL DRAWING NUMBERS SHALL BE PREFIXED BY 8474L- 015-PID-0021 . B.- UNLESS OTHERWISE SPECIFIED, ALL INSTRUMENT TAG NUMBERS SHALL BE PREFIXED BY 015 . C.- PER ESD SYSTEMS STANDARD 8474L-JSS1515-001 CLAUSE 7.1, ALL INPUTS SHALL HAVE A DELAY OF 0.5 SECONDS UNLESS OTHERWISE SPECIFIED. D.- ALL ESD VALVES WILL BE PROVIDED WITH PARTIAL STROKE TEST FACILITY UNLESS OTHERWISE SPECIFIED. E.- ALL INPUTS AND OUTPUTS SHALL BE FAILSAFE UNLESS OTHERWISE SPECIFIED. FIELD INPUT CONTACTS SHALL OPEN TO TRIP. OUTPUT SHALL DE-ENERGIZE TO TRIP. F.- DCS ALARMS SHALL BE PROVIDED IN ACCORDANCE WITH LONG FORMAT SHOWN ON SYMBOLOGY P&ID 8474L-000-PID-0090-010 TO 013 INCLUSIVE. G.- ALL OUTPUT SHALL BE PROVIDED WITH MOS.

XV-485

30

29

28

27

26

25

24

23

22

21

20

19

18

17

16

15

14

13

12

11

10

9

8

7

TAG No.

6

MOS

5

OOS

4


DESCRIPTION

1

EQUIPMT

LOGIC

3

SERVICE

OTHER Rev. NOTE

GENERAL NOTES :

2

CAUSE


XSY-485

TAG No

EQUIPMT


DESCRIPTION

UNIT 015 RFCC UNIT

SERVICE


EFFECT

UNIT or EQUIPMENT

P&ID OTHER LOGIC

NOTE


C

1

2

2

3

3

4

4

5

5

6

6

7

7

8

8

9

9

10

10

11

11

12

12

13

13

14

14

15

15

16

16

17

17

18

18

19

19

20

20

21

21

22

22

23

23

24

24

25

25

26

26

27

27

28

28

29

29

30

30

NOTES :

HOLDS :

RESET DCS


329

UHSR-440

1

R

1

2

2

3

3

4

4

1

_ _ _ __ RA| D __| N I ||___ 7 2-20007 JAANR073-M

2

3

4

5

6

7

8

9

10

11


12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

28

30


Doc. type

Code

Serial N°

Rev. index

SHEET

8474L 015

DW

15 14

602

A

32

B

B

329

329

Rev.

B

D-1522

D-1522 LEVEL LL

329

N/A

LHS-486A

LXALL-486

1

LIGHT SLOP PUMP

LIGHT SLOP PUMP


30

29

28

27

26

25

24

23

22

21

20

19

18

17

16

15

14

13

12

11

10

9

8

7

6

P-1526B

T

5

TAG No.

4

MOS

3

OOS

MXS-474


DESCRIPTION

1

EQUIPMT

LOGIC

2

SERVICE

OTHER Rev. NOTE


CAUSE


MXS-473

TAG No

EQUIPMT


DESCRIPTION

UNIT 015 RFCC UNIT

SERVICE


EFFECT

UNIT or EQUIPMENT

P&ID OTHER LOGIC

NOTE


T

1

2

2

3

3

4

4

5

5

6

6

7

7

8

8

9

9

10

10

11

11

12

12

13

13

14

14

15

15

16

16

17

17

18

18

19

19

20

20

21

21

22

22

23

23

24

24

25

25

26

26

27

27

28

28

29

29

30

30

NOTES :

HOLDS :

RESET DCS


329

UHSR-441

1

R

R

1

2

2

3

3

4

4

1

_ _ _ __ RA| D __| N I ||___ 7 2-20007 JAANR073-M

2

3

4

5

6

7

8

9

10

11


12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

28

30


Doc. type

Code

Serial N°

Rev. index

SHEET

8474L 015

DW

15 14

602

A

33

B

Rev.

B

D-1523

D-1523 LEVEL HH

330

N/A

LHS-491A

LXAHH-491

1

330 HEAVY SLOP TO D-1523

A.- UNLESS OTHERWISE SPECIFIED, ALL DRAWING NUMBERS SHALL BE PREFIXED BY 8474L- 015-PID-0021 . B.- UNLESS OTHERWISE SPECIFIED, ALL INSTRUMENT TAG NUMBERS SHALL BE PREFIXED BY 015 . C.- PER ESD SYSTEMS STANDARD 8474L-JSS1515-001 CLAUSE 7.1, ALL INPUTS SHALL HAVE A DELAY OF 0.5 SECONDS UNLESS OTHERWISE SPECIFIED. D.- ALL ESD VALVES WILL BE PROVIDED WITH PARTIAL STROKE TEST FACILITY UNLESS OTHERWISE SPECIFIED. E.- ALL INPUTS AND OUTPUTS SHALL BE FAILSAFE UNLESS OTHERWISE SPECIFIED. FIELD INPUT CONTACTS SHALL OPEN TO TRIP. OUTPUT SHALL DE-ENERGIZE TO TRIP. F.- DCS ALARMS SHALL BE PROVIDED IN ACCORDANCE WITH LONG FORMAT SHOWN ON SYMBOLOGY P&ID 8474L-000-PID-0090-010 TO 013 INCLUSIVE. G.- ALL OUTPUT SHALL BE PROVIDED WITH MOS.

XV-491

30

29

28

27

26

25

24

23

22

21

20

19

18

17

16

15

14

13

12

11

10

9

8

7

TAG No.

6

MOS

5

OOS

4


DESCRIPTION

1

EQUIPMT

LOGIC

3

SERVICE

OTHER Rev. NOTE

GENERAL NOTES :

2

CAUSE


XSY-491

TAG No

EQUIPMT


DESCRIPTION

UNIT 015 RFCC UNIT

SERVICE


EFFECT

UNIT or EQUIPMENT

P&ID OTHER LOGIC

NOTE


C

1

2

2

3

3

4

4

5

5

6

6

7

7

8

8

9

9

10

10

11

11

12

12

13

13

14

14

15

15

16

16

17

17

18

18

19

19

20

20

21

21

22

22

23

23

24

24

25

25

26

26

27

27

28

28

29

29

30

30

NOTES :

HOLDS :

RESET DCS


330

UHSR-442

1

R

1

2

2

3

3

4

4

1

_ _ _ __ RA| D __| N I ||___ 7 2-20007 JAANR073-M

2

3

4

5

6

7

8

9

10

11


12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

28

30


Doc. type

Code

Serial N°

Rev. index

SHEET

8474L 015

DW

15 14

602

A

34

B

B

330

300

Rev.

B

D-1523

D-1523 LEVEL LL

330

N/A

LHS-492A

LXALL-492

1

HEAVY SLOP PUMP

HEAVYSLOP PUMP


30

29

28

27

26

25

24

23

22

21

20

19

18

17

16

15

14

13

12

11

10

9

8

7

6

P-1527B

T

5

TAG No.

4

MOS

3

OOS

MXS-476


DESCRIPTION

1

EQUIPMT

LOGIC

2

SERVICE

OTHER Rev. NOTE


CAUSE


MXS-475

TAG No

EQUIPMT


DESCRIPTION

UNIT 015 RFCC UNIT

SERVICE


EFFECT

UNIT or EQUIPMENT

P&ID OTHER LOGIC

NOTE


T

1

2

2

3

3

4

4

5

5

6

6

7

7

8

8

9

9

10

10

11

11

12

12

13

13

14

14

15

15

16

16

17

17

18

18

19

19

20

20

21

21

22

22

23

23

24

24

25

25

26

26

27

27

28

28

29

29

30

30

NOTES :

HOLDS :

RESET DCS


330

UHSR-443

1

R

R

1

2

2

3

3

4

4

1

_ _ _ __ RA| D __| N I ||___ 7 2-20007 JAANR073-M

2

3

4

5

6

7

8

9

10

11


12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

28

30


Doc. type

Code

Serial N°

Rev. index

SHEET

8474L 015

DW

15 14

602

A

35

B

B

330

300

Rev.

B

D-1524

D-1524 LEVEL LL

331

N/A

LHS-498A

LXALL-498

1

TEMPERED WATER PUMP

TEMPERED WATER PUMP


30

29

28

27

26

25

24

23

22

21

20

19

18

17

16

15

14

13

12

11

10

9

8

7

6

P-1528B

T

5

TAG No.

4

MOS

3

OOS

MXS-479


DESCRIPTION

1

EQUIPMT

LOGIC

2

SERVICE

OTHER Rev. NOTE

P-1528A

CAUSE


GENERAL NOTES :

MXS-478

TAG No

EQUIPMT


DESCRIPTION

UNIT 015 RFCC UNIT

SERVICE


EFFECT

UNIT or EQUIPMENT

P&ID OTHER LOGIC

NOTE


T

1

2

2

3

3

4

4

5

5

6

6

7

7

8

8

9

9

10

10

11

11

12

12

13

13

14

14

15

15

16

16

17

17

18

18

19

19

20

20

21

21

22

22

23

23

24

24

25

25

26

26

27

27

28

28

29

29

30

30

NOTES :

HOLDS :

RESET DCS


331

UHSR-444

1

R

R

1

2

2

3

3

4

4

1

_ _ _ __ RA| D __| N I ||___ 7 2-20007 JAANR073-M

2

3

4

5

6

7

8

9

10

11


12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

28

30


Doc. type

Code

Serial N°

Rev. index

SHEET

8474L 015

DW

15 14

602

A

36

D 3

D

D 3

3 402

402 C-1551 SECOND STAGE DISCHARGE VALVE

C-1551 SECOND STAGE SUCTION VALVE

402

402 C-1551 FIRST STAGE DISCHARGE VALVE

C-1551 FIRST STAGE SUCTION VALVE

C-1551 TRIP

402

UX-861

MOV-705

MOV-706

MXSY-705

MXSY-706

E

ESD


402

N/A

N/A

UXHS-705AA

1

A

C

C

C

C

1

B

LOCAL

HAEDWIRE SWITCH ACTIVE

402

N/A

N/A

UXHS-705B

2

A

C

C

C

C

2

E

2

2oo3 D-1551

D-1551 LEVEL HH

401

N/A

LHS-704A

LXAHH-704A/B/C

3

A

E

2

2oo3 D-1552

D-1552 LEVEL HH

403

N/A

LHS-709A

LXAHH-709A/B/C

4

A

E

1,3

UX-861 C-1551

C-1551 TRIPPED (SPEED LL)

403

N/A

XHS-861A

XS-861

5


30

29

28

27

26

25

24

23

22

21

20

19

18

17

16

15

14

13

12

11

10

9

8

7

6

MOV-704 MXSY-704

5

MOV-703 MXSY-703

4

TAG No.

3

MOS

2

OOS

D

C 1


DESCRIPTION

1

EQUIPMT

LOGIC

C-1551

SERVICE

OTHER Rev. NOTE


GENERAL NOTES :

XS-862

CAUSE

3

Rev. NOTE


EQUIPMT

UX-705 C-1551 ISOLATION & PROTECTION

DESCRIPTION

UNIT 015 RFCC UNIT

SERVICE


EFFECT

UNIT or EQUIPMENT


3 4

P

P

P

P

5

D

C-1551

DISCHARGE TEMP MH

402

N/A

THS-631-A

TXAHH-631

6

A

6

D

C-1551

DISCHARGE TEMP MH

402

N/A

THS-632-A

TXAHH-632

7

A

7 8

E

4

MOV-703

OPEN LIMIT SWITCH

402

N/A

MZHS-703BA

MZSO-703B

8

A

E

4

MOV-704

OPEN LIMIT SWITCH

402

N/A

MZHS-704BA

MZSO-704B

9

A

9

E

4

MOV-705

OPEN LIMIT SWITCH

402

N/A

MZHS-705BA

MZSO-705B

10

A

10

E

4

MOV-706

OPEN LIMIT SWITCH

402

N/A

MZHS-706BA

MZSO-706B

11

A

11

12

12

13

13

14

14

15

15

16

16

17

17

18

18

19

19

20

20

21

21

22

22

23

23

24

24

25

25

26

26

27

27

28

28

29

29

30

30

NOTES : 1. C-1551 TRIP BY VENDOR 2. 2 OUT OF 3 VOTING 3. PERMISSIVE TO CLOSE WHEN C-1551 ROTATING SPEED IS LESS THAN 250 RPM. C-1551 CANNOT BE RESTARTED UNTIL MOVs ARE OPENED FULLY. 4. MOV NOT FULLY OPEN TO TRIP C-1551

HOLDS :

RESET B

DCS


402

UHSR-705

1

R

R

R

R

R

1

2

2

3

3

4

4

1

_ _ _ __ RA| D __| N I ||___ 7 2-20007 JAANR073-M

2

3

4

5

6

7

8

9

10

11


12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

28

30

UNIT 015 015-UX-705 C-1551 ISOLATION & PROTECTION Project N° - Unit

Doc. type

Code

Serial N°

Rev. index

SHEET

8474L 015

DW

15 14

602

E

37

B

B

403

403

Rev.

B

D-1552

D-1552 LEVEL LL

403

N/A

LHS-707A

LXALL-707

1




30

29

28

27

26

25

24

23

22

21

20

19

18

17

16

15

14

13

12

11

10

9

8

7

6

P-1551B

T

5

TAG No.

4

MOS

3

OOS

MXS-715


DESCRIPTION

1

EQUIPMT

LOGIC

2

SERVICE

OTHER Rev. NOTE

P-1551A

CAUSE


GENERAL NOTES :

MXS-714

TAG No

EQUIPMT


DESCRIPTION

UNIT 015 RFCC UNIT

SERVICE


EFFECT

UNIT or EQUIPMENT

P&ID OTHER LOGIC

NOTE


T

1

2

2

3

3

4

4

5

5

6

6

7

7

8

8

9

9

10

10

11

11

12

12

13

13

14

14

15

15

16

16

17

17

18

18

19

19

20

20

21

21

22

22

23

23

24

24

25

25

26

26

27

27

28

28

29

29

30

30

NOTES :

HOLDS :

RESET DCS


403

UHSR-706

1

R

R

1

2

2

3

3

4

4

1

_ _ _ __ RA| D __| N I ||___ 7 2-20007 JAANR073-M

2

3

4

5

6

7

8

9

10

11


12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

28

30


Doc. type

Code

Serial N°

Rev. index

SHEET

8474L 015

DW

15 14

602

B

38

B

Rev.

B

D-1553

D-1553 INTERFACE LEVEL LL

404

N/A

LHS-716A

LXALL-716

1

404 D-1553 BOOT SOUR WSTER DRAW-OFF


XV-716

30

29

28

27

26

25

24

23

22

21

20

19

18

17

16

15

14

13

12

11

10

9

8

7

TAG No.

6

MOS

5

OOS

4


DESCRIPTION

1

EQUIPMT

LOGIC

3

SERVICE

OTHER Rev. NOTE

GENERAL NOTES :

2

CAUSE


XSY-716

TAG No

EQUIPMT

UX-707 D-1553 INTERFACE ISOLATION

DESCRIPTION

UNIT 015 RFCC UNIT

SERVICE


EFFECT

UNIT or EQUIPMENT

P&ID OTHER LOGIC

NOTE


C

1

2

2

3

3

4

4

5

5

6

6

7

7

8

8

9

9

10

10

11

11

12

12

13

13

14

14

15

15

16

16

17

17

18

18

19

19

20

20

21

21

22

22

23

23

24

24

25

25

26

26

27

27

28

28

29

29

30

30

NOTES :

HOLDS :

RESET DCS


404

UHSR-707

1

R

1

2

2

3

3

4

4

1

_ _ _ __ RA| D __| N I ||___ 7 2-20007 JAANR073-M

2

3

4

5

6

7

8

9

10

11


12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

28

30

UNIT 015 015-UX-707 D-1553 INTERFACE ISOLATION Project N° - Unit

Doc. type

Code

Serial N°

Rev. index

SHEET

8474L 015

DW

15 14

602

A

39

B

B 1 404

404 P-1553A/B SUCTION LINE

B 1

P-1553B

XV-719

MXS-718

XSY-719


30

29

28

27

26

25

24

23

22

21

20

19

18

17

16

15

14

13

12

11

10

9

8

7

6

5

4

TAG No.

3

MOS

2

OOS

STRIPPER FEED PUMP

404


DESCRIPTION

1

EQUIPMT

LOGIC

P-1553A

SERVICE

OTHER Rev. NOTE


GENERAL NOTES :

MXS-717

CAUSE

STRIPPER FEED PUMP

Rev. NOTE


EQUIPMT

UX-708 D-1553 INVENTORY ISOLATION

DESCRIPTION

UNIT 015 RFCC UNIT

SERVICE


EFFECT

UNIT or EQUIPMENT


B

ESD


404

N/A

N/A

UXHS-708A

1

T

T

C

1

B

LOCAL


404

N/A

N/A

UXHS-708B

2

T

T

C

2

E

1

XV-719


404

N/A

XZHS-719-A

XZSM-719

3

T

T

3

E

1

XV-719


404

N/A

XZHS-719-A

XZSM-719

4

P

P

4

B

D-1553

D-1553 LEVEL LL

404

N/A

LHS-719A

LXALL-719

5

T

T

E

LOCAL


404

N/A

N/A

XHSO-719B

6

O

6

E

LOCAL


404

N/A

N/A

XHSC-719B

7

C

7

5

8

8

9

9

10

10

11

11

12

12

13

13

14

14

15

15

16

16

17

17

18

18

19

19

20

20

21

21

22

22

23

23

24

24

25

25

26

26

27

27

28

28

29

29

30

30

NOTES : 1. MOTOR OF PUMP SHALL BE AUTOMATICALLY STOPPED WHEN MOV IS LESS THAN 80% OPEN AND CANNOT BE RESTARTED UNTIL MOV IS OPEN MORE THAN 80%.

HOLDS :

RESET C

DCS


404

UHSR-708

1

B

LOCAL


404

XHSR-719

2

R

R

R

1

R

2

3

3

4

4

1

_ _ _ __ RA| D __| N I ||___ 7 2-20007 JAANR073-M

2

3

4

5

6

7

8

9

10

11


12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

28

30

UNIT 015 015-UX-708 D-1553 INVENTORY ISOLATION Project N° - Unit

Doc. type

Code

Serial N°

Rev. index

SHEET

8474L 015

DW

15 14

602

C

40

B

Rev.

B

D-1556


407

N/A

LHS-725A

LXALL-725

1

407 D-1556 BOOT SOUR WSTER DRAW-OFF


XV-725

30

29

28

27

26

25

24

23

22

21

20

19

18

17

16

15

14

13

12

11

10

9

8

7

TAG No.

6

MOS

5

OOS

4


DESCRIPTION

1

EQUIPMT

LOGIC

3

SERVICE

OTHER Rev. NOTE

GENERAL NOTES :

2

CAUSE


XSY-725

TAG No

EQUIPMT


DESCRIPTION

UNIT 015 RFCC UNIT

SERVICE


EFFECT

UNIT or EQUIPMENT

P&ID OTHER LOGIC

NOTE


C

1

2

2

3

3

4

4

5

5

6

6

7

7

8

8

9

9

10

10

11

11

12

12

13

13

14

14

15

15

16

16

17

17

18

18

19

19

20

20

21

21

22

22

23

23

24

24

25

25

26

26

27

27

28

28

29

29

30

30

NOTES :

HOLDS :

RESET DCS


407

UHSR-709

1

R

1

2

2

3

3

4

4

1

_ _ _ __ RA| D __| N I ||___ 7 2-20007 JAANR073-M

2

3

4

5

6

7

8

9

10

11


12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

28

30


Doc. type

Code

Serial N°

Rev. index

SHEET

8474L 015

DW

15 14

602

A

41

B

Rev.

B

T-1555

T-1555 INTERFACE LEVEL LL

408

N/A

LHS-732A

LXALL-732

1

408 RICH AMINE FROM T-1555


XV-732

30

29

28

27

26

25

24

23

22

21

20

19

18

17

16

15

14

13

12

11

10

9

8

7

TAG No.

6

MOS

5

OOS

4


DESCRIPTION

1

EQUIPMT

LOGIC

3

SERVICE

OTHER Rev. NOTE

GENERAL NOTES :

2

CAUSE


XSY-732

TAG No

EQUIPMT

UX-710 T-1555 INTERFACE ISOLATION

DESCRIPTION

UNIT 015 RFCC UNIT

SERVICE


EFFECT

UNIT or EQUIPMENT

P&ID OTHER LOGIC

NOTE


C

1

2

2

3

3

4

4

5

5

6

6

7

7

8

8

9

9

10

10

11

11

12

12

13

13

14

14

15

15

16

16

17

17

18

18

19

19

20

20

21

21

22

22

23

23

24

24

25

25

26

26

27

27

28

28

29

29

30

30

NOTES :

HOLDS :

RESET DCS


408

UHSR-710

1

R

1

2

2

3

3

4

4

1

_ _ _ __ RA| D __| N I ||___ 7 2-20007 JAANR073-M

2

3

4

5

6

7

8

9

10

11


12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

28

30

UNIT 015 015-UX-710 T-1555 INTERFACE ISOLATION Project N° - Unit

Doc. type

Code

Serial N°

Rev. index

SHEET

8474L 015

DW

15 14

602

A

42

B

B 1 406

409 T-1554 BOTTOM LINE

B 1

P-1554B

XV-738

MXS-721

XSY-738


30

29

28

27

26

25

24

23

22

21

20

19

18

17

16

15

14

13

12

11

10

9

8

7

6

5

4

TAG No.

3

MOS

2

OOS


406


DESCRIPTION

1

EQUIPMT

LOGIC

P-1554A

SERVICE

OTHER Rev. NOTE


GENERAL NOTES :

MXS-720

CAUSE


Rev. NOTE


EQUIPMT

UX-712 T-1554 INVENTORY ISOLATION

DESCRIPTION

UNIT 015 RFCC UNIT

SERVICE


EFFECT

UNIT or EQUIPMENT


B

ESD


409

N/A

N/A

UXHS-712A

1

T

T

C

1

B

LOCAL


409

N/A

N/A

UXHS-712B

2

T

T

C

2

E

1

XV-738


409

N/A

XZHS-738-A

XZSM-738

3

T

T

3

E

1

XV-738


409

N/A

XZHS-738-A

XZSM-738

4

P

P

4

B

T-1554

T-1554 LEVEL LL

409

N/A

LHS-738A

LXALL-738

5

T

T

E

LOCAL


409

N/A

N/A

XHSO-738B

6

O

6

E

LOCAL


409

N/A

N/A

XHSC-738B

7

C

7

5

8

8

9

9

10

10

11

11

12

12

13

13

14

14

15

15

16

16

17

17

18

18

19

19

20

20

21

21

22

22

23

23

24

24

25

25

26

26

27

27

28

28

29

29

30

30


HOLDS :

RESET E

DCS


404

UHSR-712

1

B

LOCAL


404

XHSR-738

2

R

R

R

1

R

2

3

3

4

4

1

_ _ _ __ RA| D __| N I ||___ 7 2-20007 JAANR073-M

2

3

4

5

6

7

8

9

10

11


12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

28

30

UNIT 015 015-UX-712 T-1554 INVENTORY ISOLATION Project N° - Unit

Doc. type

Code

Serial N°

Rev. index

SHEET

8474L 015

DW

15 14

602

C

43

B

Rev.

B

D-1554


410

N/A

LHS-741A

LXALL-741

1

410 SOUR WATER FROM D-1554 BOOT


XV-741

30

29

28

27

26

25

24

23

22

21

20

19

18

17

16

15

14

13

12

11

10

9

8

7

TAG No.

6

MOS

5

OOS

4


DESCRIPTION

1

EQUIPMT

LOGIC

3

SERVICE

OTHER Rev. NOTE

GENERAL NOTES :

2

CAUSE


XSY-741

TAG No

EQUIPMT


DESCRIPTION

UNIT 015 RFCC UNIT

SERVICE


EFFECT

UNIT or EQUIPMENT

P&ID OTHER LOGIC

NOTE


C

1

2

2

3

3

4

4

5

5

6

6

7

7

8

8

9

9

10

10

11

11

12

12

13

13

14

14

15

15

16

16

17

17

18

18

19

19

20

20

21

21

22

22

23

23

24

24

25

25

26

26

27

27

28

28

29

29

30

30

NOTES :

HOLDS :

RESET DCS


410

UHSR-713

1

R

1

2

2

3

3

4

4

1

_ _ _ __ RA| D __| N I ||___ 7 2-20007 JAANR073-M

2

3

4

5

6

7

8

9

10

11


12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

28

30


Doc. type

Code

Serial N°

Rev. index

SHEET

8474L 015

DW

15 14

602

B

44

B

B 1 410

410 P-1556A/B SUCTION LINE

B 1

P-1556B

XV-744

MXS-723

XSY-744


30

29

28

27

26

25

24

23

22

21

20

19

18

17

16

15

14

13

12

11

10

9

8

7

6

5

4

TAG No.

3

MOS

2

OOS


410


DESCRIPTION

1

EQUIPMT

LOGIC

P-1556A

SERVICE

OTHER Rev. NOTE


GENERAL NOTES :

MXS-722

CAUSE


Rev. NOTE


EQUIPMT

UX-714 D-1554 INVENTORY ISOLATION

DESCRIPTION

UNIT 015 RFCC UNIT

SERVICE


EFFECT

UNIT or EQUIPMENT


B

ESD


410

N/A

N/A

UXHS-714A

1

T

T

C

1

B

LOCAL


410

N/A

N/A

UXHS-714B

2

T

T

C

2

E

1

XV-744


410

N/A

XZHS-744-A

XZSM-744

3

T

T

3

E

1

XV-744


410

N/A

XZHS-744-A

XZSM-744

4

P

P

4

B

D-1554

D-1554 LEVEL LL

410

N/A

LHS-744A

LXALL-744

5

T

T

E

LOCAL


410

N/A

N/A

XHSO-744B

6

O

6

E

LOCAL


410

N/A

N/A

XHSC-744B

7

C

7

5

8

8

9

9

10

10

11

11

12

12

13

13

14

14

15

15

16

16

17

17

18

18

19

19

20

20

21

21

22

22

23

23

24

24

25

25

26

26

27

27

28

28

29

29

30

30


HOLDS :

RESET C

DCS


410

UHSR-714

1

B

LOCAL


410

XHSR-744

2

R

R

R

1

R

2

3

3

4

4

1

_ _ _ __ RA| D __| N I ||___ 7 2-20007 JAANR073-M

2

3

4

5

6

7

8

9

10

11


12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

28

30

UNIT 015 015-UX-714 D-1554 INVENTORY ISOLATION Project N° - Unit

Doc. type

Code

Serial N°

Rev. index

SHEET

8474L 015

DW

15 14

602

C

45

B

Rev.

B

T-1556

T-1556 INTERFACE LEVEL LL

411

N/A

LHS-748A

LXALL-748

1

411 RICH AMINE FROM T-1556 BOTTOM


XV-748

30

29

28

27

26

25

24

23

22

21

20

19

18

17

16

15

14

13

12

11

10

9

8

7

TAG No.

6

MOS

5

OOS

4


DESCRIPTION

1

EQUIPMT

LOGIC

3

SERVICE

OTHER Rev. NOTE

GENERAL NOTES :

2

CAUSE


XSY-748

TAG No

EQUIPMT

UX-715 T-1556 INTERFACE ISOLATION

DESCRIPTION

UNIT 015 RFCC UNIT

SERVICE


EFFECT

UNIT or EQUIPMENT

P&ID OTHER LOGIC

NOTE


C

1

2

2

3

3

4

4

5

5

6

6

7

7

8

8

9

9

10

10

11

11

12

12

13

13

14

14

15

15

16

16

17

17

18

18

19

19

20

20

21

21

22

22

23

23

24

24

25

25

26

26

27

27

28

28

29

29

30

30

NOTES :

HOLDS :

RESET DCS


411

UHSR-715

1

R

1

2

2

3

3

4

4

1

_ _ _ __ RA| D __| N I ||___ 7 2-20007 JAANR073-M

2

3

4

5

6

7

8

9

10

11


12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

28

30

UNIT 015 015-UX-715 T-1556 INTERFACE ISOLATION Project N° - Unit

Doc. type

Code

Serial N°

Rev. index

SHEET

8474L 015

DW

15 14

602

A

46

B

Rev.

B

D-1555


411

N/A

LHS-751A

LXALL-751

1

411 RICH AMINE FROM D-1555


XV-751

30

29

28

27

26

25

24

23

22

21

20

19

18

17

16

15

14

13

12

11

10

9

8

7

TAG No.

6

MOS

5

OOS

4


DESCRIPTION

1

EQUIPMT

LOGIC

3

SERVICE

OTHER Rev. NOTE

GENERAL NOTES :

2

CAUSE


XSY-751

TAG No

EQUIPMT


DESCRIPTION

UNIT 015 RFCC UNIT

SERVICE


EFFECT

UNIT or EQUIPMENT

P&ID OTHER LOGIC

NOTE


C

1

2

2

3

3

4

4

5

5

6

6

7

7

8

8

9

9

10

10

11

11

12

12

13

13

14

14

15

15

16

16

17

17

18

18

19

19

20

20

21

21

22

22

23

23

24

24

25

25

26

26

27

27

28

28

29

29

30

30

NOTES :

HOLDS :

RESET DCS


411

UHSR-716

1

R

1

2

2

3

3

4

4

1

_ _ _ __ RA| D __| N I ||___ 7 2-20007 JAANR073-M

2

3

4

5

6

7

8

9

10

11


12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

28

30


Doc. type

Code

Serial N°

Rev. index

SHEET

8474L 015

DW

15 14

602

A

47

B

B

411

411

Rev.

T-1556 OVERHEAD TO FLARE

FEED TO T-1556

FV-723


30

29

28

27

26

25

24

23

22

21

20

19

18

17

16

15

14

13

12

11

10

9

8

7

6

5

TAG No.

4

MOS

3

OOS

FSY-723


DESCRIPTION

1

EQUIPMT

LOGIC

2

SERVICE

OTHER Rev. NOTE

GENERAL NOTES : XV-752

CAUSE


XSY-752

TAG No

EQUIPMT

UX-717 T-1556 DEPRESSURIZATION

DESCRIPTION

UNIT 015 RFCC UNIT

SERVICE


EFFECT

UNIT or EQUIPMENT

P&ID OTHER LOGIC

NOTE


B

ESD


411

N/A

N/A

UXHS-717A

1

O

C

1

B

LOCAL


411

N/A

N/A

UXHS-717B

2

O

C

2

3

3

4

4

5

5

6

6

7

7

8

8

9

9

10

10

11

11

12

12

13

13

14

14

15

15

16

16

17

17

18

18

19

19

20

20

21

21

22

22

23

23

24

24

25

25

26

26

27

27

28

28

29

29

30

30

NOTES :

HOLDS :

RESET C

DCS


411

UHSR-717

1

R

B

LOCAL


411

XHSR-752

2

R

R

1 2

3

3

4

4

1

_ _ _ __ RA| D __| N I ||___ 7 2-20007 JAANR073-M

2

3

4

5

6

7

8

9

10

11


12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

28

30

UNIT 015 015-UX-717 T-1556 DEPRESSURIZATION Project N° - Unit

Doc. type

Code

Serial N°

Rev. index

SHEET

8474L 015

DW

15 14

602

B

48

B

Rev.

B

D-1559


408

N/A

LHS-735A

LXALL-735

1

408 LEAN AMINE FROM D-1559


XV-735

30

29

28

27

26

25

24

23

22

21

20

19

18

17

16

15

14

13

12

11

10

9

8

7

TAG No.

6

MOS

5

OOS

4


DESCRIPTION

1

EQUIPMT

LOGIC

3

SERVICE

OTHER Rev. NOTE

GENERAL NOTES :

2

CAUSE


XSY-735

TAG No

EQUIPMT


DESCRIPTION

UNIT 015 RFCC UNIT

SERVICE


EFFECT

UNIT or EQUIPMENT

P&ID OTHER LOGIC

NOTE


C

1

2

2

3

3

4

4

5

5

6

6

7

7

8

8

9

9

10

10

11

11

12

12

13

13

14

14

15

15

16

16

17

17

18

18

19

19

20

20

21

21

22

22

23

23

24

24

25

25

26

26

27

27

28

28

29

29

30

30

NOTES :

HOLDS :

RESET B

DCS


408

UHSR-718

1

R

1

2

2

3

3

4

4

1

_ _ _ __ RA| D __| N I ||___ 7 2-20007 JAANR073-M

2

3

4

5

6

7

8

9

10

11


12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

28

30


Doc. type

Code

Serial N°

Rev. index

SHEET

8474L 015

DW

15 14

602

B

49

B

Rev.

408 D-1559 OVERHEAD TO FLARE


XV-733

30

29

28

27

26

25

24

23

22

21

20

19

18

17

16

15

14

13

12

11

10

9

8

7

TAG No.

6

MOS

5

OOS

4


DESCRIPTION

1

EQUIPMT

LOGIC

3

SERVICE

OTHER Rev. NOTE

GENERAL NOTES :

2

CAUSE


XSY-733

TAG No

EQUIPMT

UX-719 D-1553 DEPRESSURIZATION

DESCRIPTION

UNIT 015 RFCC UNIT

SERVICE


EFFECT

UNIT or EQUIPMENT

P&ID OTHER LOGIC

NOTE


B

ESD


408

N/A

N/A

UXHS-719A

1

O

1

B

LOCAL


408

N/A

N/A

UXHS-719B

2

O

2

3

3

4

4

5

5

6

6

7

7

8

8

9

9

10

10

11

11

12

12

13

13

14

14

15

15

16

16

17

17

18

18

19

19

20

20

21

21

22

22

23

23

24

24

25

25

26

26

27

27

28

28

29

29

30

30

NOTES :

HOLDS :

RESET C

DCS


408

UHSR-719

1

R

1

B

LOCAL


408

XHSR-733

2

R

2

3

3

4

4

1

_ _ _ __ RA| D __| N I ||___ 7 2-20007 JAANR073-M

2

3

4

5

6

7

8

9

10

11


12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

28

30

UNIT 015 015-UX-719 D-1553 DEPRESSURIZATION Project N° - Unit

Doc. type

Code

Serial N°

Rev. index

SHEET

8474L 015

DW

15 14

602

B

50

MATERIAL SAFETY DATA SHEET PRODUCT

NICKEL PASSIVATION PLUS EC9192 EMERGENCY TELEPHONE NUMBER(S) See section 16, for Emergency Telephone Numbers.

1.

CHEMICAL PRODUCT AND COMPANY IDENTIFICATION

PRODUCT NAME :

NICKEL PASSIVATION PLUS EC9192

APPLICATION :

METALS PASSIVATOR

COMPANY IDENTIFICATION :

NALCO EUROPE B.V. Postbus 627 2300 AP Leiden, The Netherlands

EMERGENCY TELEPHONE NUMBER(S) :

See section 16, for Emergency Telephone Numbers.

Date issued : Version Number :

17.03.2005 1.10

COMPANY CONTACT TELEPHONE NUMBERS. NALCO EUROPE B.V. NALCO AB (SE) NALCO ANADOLU KIMYA (TR) NALCO APPLIED SERVICES OF EUROPE BV NALCO BELGIUM N.V./S.A. (B) NALCO DANMARK A/S NALCO DEUTSCHLAND GmbH (D)

+32 (0)3-450 69 10 +45-48195800 +49 (0)69-79340

NALCO ESPAÑOLA S.A. (E) NALCO FINLAND OY (FI) NALCO FRANCE SAS

+34 93-4095555 +358 (0)9 2517 4700 +33 (0)3 20 11 70 00

2.

+31 71 5241 100 +46 (0)8-50074000 +90 216 5743464 +31 (0)73 6456980

NALCO ITALIANA S.R.L.(I) NALCO Kft. (HU) NALCO LIMITED

+39 06-542971 +36 (0)1 471 91 81 +44 (0)1606 74488

NALCO NETHERLANDS B.V. NALCO NORGE AS (NO) NALCO ÖSTERREICH Ges.m.b.H. (A) NALCO POLSKA Sp.z.o.o. (PL) NALCO PORTUGUESA LDA. (P) WYSS WASSERTECHNIK AG (CH)

+31 (0)13-5952200 +47 51 96 36 00 + 43(0)1 27026350 +48 (0)32-3262750 +351 214130996 +41 (0)52 235 38 38

COMPOSITION/INFORMATION ON INGREDIENTS

This product is classified as dangerous in accordance with the Preparations Directive 1999/45/EC. Hazardous Substance(s)

EINECS / ELINCS NO Proprietary

SYMBOL

Phosphoric Acid Diethanolamine

231-633-2 203-868-0

C Xn

Methanol

200-659-6

F, T

Triethanolamine

203-049-8

Xi

Antimony compound

Xn, Xi, N

R-PHRASES / NOTAS R20/22, R36/38, R51/53 R34 R22, R38, R41, R48/22 R11, R23/24/25, R39/23/24/25 R36/38

% (w/w) 30 - 60 1- 5 1- 5 5 - 10 5 - 10

Refer to Section 16 for descriptions of relevant risk phrases and Notas.

3.

HAZARDS IDENTIFICATION

HAZARD CLASSIFICATION : This product is classified as dangerous in accordance with the Preparations Directive 1999/45/EC. Flammable. Harmful by inhalation, in contact with skin and if swallowed. Irritating to eyes and skin. Toxic to aquatic organisms, may cause long-term adverse effects in the aquatic environment. Harmful: possible risk of irreversible effects through inhalation, in contact with skin and if swallowed.

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NALCO EUROPE B.V. Postbus 627 • 2300 AP Leiden, , , The Netherlands • 0031 71 5241100

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HUMAN HEALTH HAZARDS - ACUTE : INHALATION : Repeated or prolonged exposure may irritate the respiratory tract. Product mist or vapors may cause headache, nausea, vomiting, drowsiness, stupor or unconsciousness. Methyl alcohol may cause central nervous system effects which may result in permanent visual changes including blindness. SKIN CONTACT : Can cause moderate irritation. Harmful if absorbed through skin. Methanol may be absorbed through the skin and cause central nervous system effects which may result in permanent visual changes including blindness. EYE CONTACT : Can cause moderate irritation. INGESTION : Not a likely route of exposure. There may be irritation to the gastro-intestinal tract. Harmful if swallowed. Can cause blindness. HUMAN HEALTH HAZARDS - CHRONIC : No adverse effects expected other than those mentioned above. ENVIRONMENTAL HAZARDS : Keep out of waterways. Toxic to aquatic organisms. PHYSICAL AND CHEMICAL HAZARDS : Flammable.

4.

FIRST AID MEASURES

INHALATION : Remove to fresh air, treat symptomatically. If symptoms develop, seek medical advice. SKIN CONTACT : Immediately flush with plenty of water for at least 15 minutes. If symptoms develop, seek medical advice. EYE CONTACT : Immediately flush eye with water for at least 15 minutes while holding eyelids open. If symptoms develop, seek medical advice. INGESTION : Do not induce vomiting without medical advice. If conscious, washout mouth and give water to drink. If reflexive vomiting occurs, rinse mouth and repeat administration of water. NOTE TO PHYSICIAN : Based on the individual reactions of the patient, the physician's judgement should be used to control symptoms and clinical condition.

5.

FIRE FIGHTING MEASURES

FLASH POINT :

44 °C PMCC

LOWER EXPLOSION LIMIT :

6 V%

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UPPER EXPLOSION LIMIT :

36.5 V%

AUTOIGNITION TEMPERATURE :

400 °C

EXTINGUISHING MEDIA : Foam, Carbon dioxide, Dry powder, Other extinguishing agent suitable for Class B fires, For large fires, use water spray or fog, thoroughly drenching the burning material. Water mist may be used to cool closed containers. FIRE AND EXPLOSION HAZARD : Flammable Liquid; may release vapors that form flammable mixtures at or above the flash point. Vapors can travel to a source of ignition and flash back. Empty product containers may contain product residue. Do not pressurize, cut, heat, weld, or expose containers to flame or other sources of ignition. May evolve oxides of carbon (COx) under fire conditions. May evolve oxides of nitrogen (NOx) under fire conditions. SPECIAL PROTECTIVE EQUIPMENT FOR FIRE FIGHTING : In case of fire, wear a full face positive-pressure self contained breathing apparatus and protective suit.

6.

ACCIDENTAL RELEASE MEASURES

PERSONAL PRECAUTIONS : Restrict access to area as appropriate until clean-up operations are complete. Use personal protective equipment recommended in Section 8 (Exposure Controls/Personal Protection). Stop or reduce any leaks if it is safe to do so. Ventilate spill area if possible. Remove sources of ignition. Ensure clean-up is conducted by trained personnel only. Do not touch spilled material. Have emergency equipment (for fires, spills, leaks, etc.) readily available. Notify appropriate government, occupational health and safety and environmental authorities. METHODS FOR CLEANING UP : SMALL SPILLS: Soak up spill with absorbent material. Place residues in a suitable, covered, properly labeled container. Wash affected area. LARGE SPILLS: Contain liquid using absorbent material, by digging trenches or by diking. Reclaim into recovery or salvage drums or tank truck for proper disposal. Clean contaminated surfaces with water or aqueous cleaning agents. Contact an approved waste hauler for disposal of contaminated recovered material. Dispose of material in compliance with regulations indicated in Section 13 (Disposal Considerations). ENVIRONMENTAL PRECAUTIONS : Prevent material from entering sewers or waterways. Toxic to aquatic organisms.

7.

HANDLING AND STORAGE

HANDLING : Do not get in eyes, on skin, on clothing. Do not take internally. Use with adequate ventilation. Do not breathe vapors/gases/dust. Keep the containers closed when not in use. Have emergency equipment (for fires, spills, leaks, etc.) readily available. Ensure all containers are labelled. Do not use, store, spill or pour near heat, sparks or open flame. STORAGE CONDITIONS : Store in suitable labelled containers. Store the containers tightly closed. Store away from heat and sources of ignition. Have appropriate fire extinguishers available in and near the storage area. Connections must be grounded to avoid electrical charges. SUITABLE CONSTRUCTION MATERIAL : PVC, Viton, Stainless Steel 304, Stainless Steel 316L, PTFE

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UNSUITABLE CONSTRUCTION MATERIAL : Copper, Brass, Aluminum, Polypropylene, Carbon Steel C1018 SPECIFIC USE(S) : METALS PASSIVATOR For specific dosages and customized applications please contact your Nalco representative.

8.

EXPOSURE CONTROLS/PERSONAL PROTECTION

OCCUPATIONAL EXPOSURE LIMITS Exposure guidelines have not been established for this product. Available exposure limits for the substance(s) are shown below. Country/Source ________BELGIU M

DENMARK

FINLAND

FRANCE

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Substance(s) Antimony compound (Respirable fraction.)

Category: TWA

ppm

Antimony compound (Inhalable fraction.) Antimony compound (Inhalable particles.) Antimony compound as Sb Antimony compound (Inhalable fraction.)

TWA TWA TWA TWA

10 3 0.5 10

Phosphoric Acid

TWA STEL

1 2

Diethanolamine

TWA Skin*

0.46

2

Methanol

TWA STEL Skin*

200 250

266 333

Antimony compound

GV

Phosphoric Acid

TWA

Diethanolamine

GV Skin* GV Skin*

0.5 1 0.46

07

2

0.46

Methanol

GV Skin*

200

Antimony compound Antimony compound as Sb

HTP 8H HTP 8H

Phosphoric Acid

HTP 8H HTP 15MIN

Diethanolamine

HTP 8H Skin*

0.46

2

Methanol

HTP 8H HTP 15MIN Skin*

200 250

270 330

Antimony compound as Sb

VME

Diethanolamine

VME

4 / 13

260

0.5 0.5 1 2

0.5 3


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mg/m3 3

15



GERMANY

IRELAND

ITALY

NETHERLANDS

NORWAY

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Methanol

VLE

1,000

Antimony compound (Inhalable dust) Antimony compound (Respirable dust) Antimony compound (Inhalable fraction.) Antimony compound (Respirable dust) Antimony compound Antimony compound as Sb (Inhalable fraction.)

MAK MAK MAK MAK Ex_Limit MAK

Phosphoric Acid

TWA

1

Diethanolamine (Inhalable fraction.) Diethanolamine

MAK Skin*

15

Methanol

MAK Skin*

Antimony compound as Sb Antimony compound (Respirable dust) Antimony compound (Total inhalable dust.)

TWA TWA TWA

0.5 4 10

Phosphoric Acid

TWA STEL

1 2

Diethanolamine

TWA

3

15

Methanol

TWA STEL Skin*

200 250

260 310

Antimony compound (Inhalable particulate.) Antimony compound (Respirable.) Antimony compound as Sb Antimony compound (Inhalable fraction.) Antimony compound (Respirable particles.) Antimony compound as Sb

TWA TWA TWA TWA TWA TWA

10 3 0.5 10 3 0.5

Phosphoric Acid

TWA STEL

1 2

Diethanolamine

TWA Skin* TWA Skin*

0.46

Methanol

TWA

200

Antimony compound as Sb Antimony compound (Inhalable dust) Antimony compound (Respirable dust)

MAC TGG MAC TGG MAC TGG

Phosphoric Acid

MAC TGG MAC-TGG 15

0.2 0.5

1 2

Diethanolamine

MAC TGG Skin*

0.46

2

Methanol

MAC TGG Skin*

200

260


ADM. NORM

0.5

Phosphoric Acid

ADM. NORM

1

Diethanolamine

ADM. NORM

10 6 0.5 3 0.5

200

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270

2 2

260 0.5 10 5

3


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1,300

15



SPAIN

SWEDEN

SWITZERLAND

UNITED KINGDOM

Methanol

ADM. NORM Skin*

100

130

Antimony compound (Inhalable fraction.) Antimony compound (Respirable fraction.) Antimony compound as Sb

VLA-ED VLA-ED VLA-ED

10 3 0.5

Phosphoric Acid

VLA-ED VLA-EC

1 2

Diethanolamine

VLA-ED Skin*

0.46

2

Methanol

VLA-ED VLA-EC Skin*

200 250

266 333

Antimony compound as Sb (Total dust.) Antimony compound (Respirable dust) Antimony compound (Total dust.)

NGV NGV NGV

0.5 5 10

Phosphoric Acid (Mist.)

NGV KTV

1 3

Diethanolamine

NGV KTV Skin*

3 6

15 30

Methanol

NGV KTV Skin*

200 250

250 350

Antimony compound as Sb (Inhalable dust) Antimony compound (Inhalable dust)

TWA TWA

0.1 0.5

Phosphoric Acid

TWA

1

Diethanolamine

TWA

3

13

Methanol

TWA STEL Skin*

200 800

260 1,040


TWA

0.5

Phosphoric Acid

STEL TWA

2 1

Diethanolamine

TWA

3

13

Methanol

TWA STEL Skin*

200 250

266 333

* A skin notation refers to the potential significant contribution to overall exposure by the cutaneous route, including mucous membranes and the eyes.

MONITORING MEASURES : A small volume of air is drawn through an absorbant or barrier to trap the substance(s) which can then be desorbed or removed and analyzed as referenced below: Substance(s) Method Analysis Absorbant Phosphoric Acid US NIOSH: 7903 Ion chromatography Silica gel

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Diethanolamine

US NIOSH: 3509

Ion chromatography

Impinger containing 2mM Hexane sulphonic acid

Methanol

US NIOSH: 2000

Gas chromatography

Silica gel

BIOLOGICAL EXPOSURE INDICES : Methanol A biological index of exposure to methanol (CAS 67-56-1) is the detection of methanol in the urine post shift (USA, 15mg/l), post shift and at end of the working week (Germany, 30mg/l). ENGINEERING MEASURES : General ventilation is recommended. The use of local exhaust ventilation is recommended to control emissions near the source. Laboratory samples should be handled in a fumehood. Provide mechanical ventilation of confined spaces. PERSONAL PROTECTION GENERAL ADVICE : The use and choice of personal protection equipment is related to the hazard of the product, the workplace and the way the product is handled. In general, we recommend as a minimum precaution that safety glasses with side-shields and workclothes protecting arms, legs and body be used. In addition any person visiting an area where this product is handled should at least wear safety glasses with side-shields. The applicable European standard can be found in EN 166. RESPIRATORY PROTECTION : Where concentrations in air may exceed the limits given in this section, the use of a half face filter mask or air supplied breathing apparatus is recommended. A suitable filter material depends on the amount and type of chemicals being handled. The applicable European standard can be found in EN 141, EN 143 and EN 371. Consider the use of filter type: A-B-E-K-P In event of emergency or planned entry into unknown concentrations a positive pressure, full-facepiece SCBA should be used. If respiratory protection is required, institute a complete respiratory protection program including selection, fit testing, training, maintenance and inspection. HAND PROTECTION : When handling this product, the use of chemical gauntlets is recommended. The choice of work glove depends on work conditions and what chemicals are handled, but we have positive experience under light handling conditions using gloves made from PVC Gloves should be replaced immediately if signs of degradation are observed. Breakthrough time not determined as preparation, consult PPE manufacturers. The applicable European standard can be found in EN 374. SKIN PROTECTION : When handling this product, the use of overalls is recommended. A full slicker suit is recommended if gross exposure is possible. The applicable European standard can be found in EN 345. EYE PROTECTION : Wear chemical splash goggles. The applicable European standard can be found in EN 166. HYGIENE RECOMMENDATIONS : Use good work and personal hygiene practices to avoid exposure. Keep an eye wash fountain available. Keep a safety shower available. If clothing is contaminated, remove clothing and thoroughly wash the affected area.

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Launder contaminated clothing before reuse. Always wash thoroughly after handling chemicals. When handling this product never eat, drink or smoke. ENVIRONMENTAL EXPOSURE CONTROL PRECAUTIONS : Consider the provision of containment around storage vessels.

9.

PHYSICAL AND CHEMICAL PROPERTIES

PHYSICAL STATE

Liquid

APPEARANCE

Clear Light yellow Green

ODOR

None

FLASH POINT :

44 °C PMCC

LOWER EXPLOSION LIMIT :

6 V%

UPPER EXPLOSION LIMIT : SPECIFIC GRAVITY SOLUBILITY IN WATER pH (100 %) MELTING POINT BOILING POINT VAPOR PRESSURE

36.5 V% 1.396 (25 °C) Complete 6.5 -22 °C 65 °C Calculated 13.3 kPa

Note: These physical properties are typical values for this product and are subject to change.

10.

STABILITY AND REACTIVITY

STABILITY : Stable under normal conditions. HAZARDOUS POLYMERIZATION : Hazardous polymerization will not occur. CONDITIONS TO AVOID : Heat and sources of ignition including static discharges. MATERIALS TO AVOID : Contact with strong oxidizers (e.g. chlorine, peroxides, chromates, nitric acid, perchlorate, concentrated oxygen, permanganate) may generate heat, fires, explosions and/or toxic vapors. HAZARDOUS DECOMPOSITION PRODUCTS : Under fire conditions: Oxides of carbon, Oxides of nitrogen, Oxides of phosphorus

11.

TOXICOLOGICAL INFORMATION

No toxicity studies have been conducted on this product. SENSITIZATION : This product is not expected to be a sensitizer.

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CARCINOGENICITY : None of the substances in this product are listed as carcinogens by the International Agency for Research on Cancer (IARC), the National Toxicology Program (NTP) or the American Conference of Governmental Industrial Hygienists (ACGIH). For additional information on the hazard of the preparation, please consult section 3 and 12.

12.

ECOLOGICAL INFORMATION

ECOTOXICOLOGICAL EFFECTS : No toxicity studies have been conducted on this product. The following values are estimated based on known component toxicity. ACUTE FISH RESULTS : Species Exposure Fish 96 hrs

LC50 1,245.3 mg/l

ACUTE INVERTEBRATE RESULTS : Species Exposure LC50 Crustacean 48 hrs 629.7 mg/l

Method

EC50

Test Descriptor Product (estimated)

Method

Test Descriptor Product (estimated)

MOBILITY : The environmental fate was estimated using a level III fugacity model embedded in the EPI (estimation program interface) Suite TM , provided by the US EPA. The model assumes a steady state condition between the total input and output. The level III model does not require equilibrium between the defined media. The information provided is intended to give the user a general estimate of the environmental fate of this product under the defined conditions of the models. If released into the environment this material is expected to distribute to the air, water and soil/sediment in the approximate respective percentages; Air <5%

Water 30 - 50%

Soil/Sediment 30 - 50%

The portion in water is expected to be soluble or dispersible. PERSISTENCY AND DEGRADATION : The organic portion of this preparation is expected to be readily biodegradable. BIOACCUMULATION POTENTIAL This preparation or material is not expected to bioaccumulate.

13.

DISPOSAL CONSIDERATIONS

If this preparation becomes a waste, the final user must define and assign the appropriate European Waste Catalogue code. Use only authorized contractors. Ensure compliance with EC, national and local regulations.

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This product is suitable for disposal in an approved landfill or by controlled incineration. This product will generate an ash if burned. It can be burned directly in appropriate equipment. This product is NOT suitable for disposal via municipal sewers, drains, natural streams or rivers. Empty drums should be taken for recycling, recovery, or disposal through a suitably qualified or licensed contractor. EUROPE WASTE CODE : 16 03 05*- OFF SPECIFICATION BATCHES AND UNUSED PRODUCTS - Organic wastes containing dangerous substances. If this product is used in any further processes, the final user must redefine and assign the most appropriate European Waste Catalogue Code. NATIONAL REGULATIONS FRANCE : Relevant.

14.

TRANSPORT INFORMATION

The information in this section is for reference only and should not take the place of a shipping paper (bill of lading) specific to an order. Please note that the proper Shipping Name / Hazard Class may vary by packaging, properties, and mode of transportation. Typical Proper Shipping Names for this product are as follows. LAND TRANSPORT Proper Shipping Name : Technical Name(s) : UN/ID No : Hazard Class - Primary : Packing Group : ADR/RID H.I.n. : CLASSIFICATION CODE :

FLAMMABLE LIQUID, N.O.S. Methanol UN 1993 3 III 30 F1

AIR TRANSPORT (ICAO/IATA) Proper Shipping Name : Technical Name(s) : UN/ID No : Hazard Class - Primary : Packing Group : IATA Cargo Packing Instructions : IATA Cargo Aircraft Limit : IATA Passenger Packing Instructions : IATA Passenger Aircraft Limit :

FLAMMABLE LIQUID, N.O.S. Methanol UN 1993 3 III 310 220 L (Max net quantity per package) Y309 / 309 10 L / 60 L

MARINE TRANSPORT (IMDG/IMO) Proper Shipping Name : Technical Name(s) : UN/ID No : Hazard Class - Primary : Packing Group :

FLAMMABLE LIQUID, N.O.S. Methanol UN 1993 3 III

OTHER APPLICABLE INFORMATION CEFIC TREMCARD REFERENCE : EMERGENCY ACTION CODE :

30GF1-III 3[Y]

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15.

REGULATORY INFORMATION

CLASSIFICATION AND LABELLING : GOVERNING DIRECTIVE(S): Dangerous Substances Directive 67/548/EEC and Dangerous Preparations Directive 1999/45/EC. HAZARD SYMBOLS

HARMFUL

DANGEROUS FOR THE ENVIRONMENT

Contains:..Methanol Antimony compound RISK PHRASES R10 - Flammable. R20/21/22 - Harmful by inhalation, in contact with skin and if swallowed. R36/38 - Irritating to eyes and skin. R51/53 - Toxic to aquatic organisms, may cause long-term adverse effects in the aquatic environment. R68/20/21/22 - Harmful: possible risk of irreversible effects through inhalation, in contact with skin and if swallowed. SAFETY PHRASES S23C - Do not breathe vapor. S24/25 - Avoid contact with skin and eyes. S26 - In case of contact with eyes, rinse immediately with plenty of water and seek medical advice. S28 - After contact with skin, wash immediately with plenty of water. S36/37 - Wear suitable protective clothing and gloves. S57 - Use appropriate containment to avoid environmental contamination.

NATIONAL REGULATIONS FRANCE Table of occupational diseases, Article L461-4. Social Security Code- Decree 11/2/2003: Relevant, see table(s): Table: 49 Dangerous or Poisonous Substances and Preparations: Relevant. Special medical supervision - Decree of 11 July 1997: Relevant. Work Restrictions: Fair labor standards act, Article R234-9 and 10 (women): Not-applicable. Fair labor standards act, Article R234-16, 20 and 21 (young workers): Relevant. Fair labor standards act, Decree of the 8/10/90 (temporary work and contract last given): Relevant. Classified Industrial Sites (ICPE): Not-applicable. Water Discharge: Relevant.

NATIONAL REGULATIONS GERMANY WGK 2 (Annex 4)

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INTERNATIONAL CHEMICAL CONTROL LAWS UNITED STATES The substances in this preparation are included on or exempted from the TSCA 8(b) Inventory (40 CFR 710) CANADA : The substances in this preparation are listed on the Domestic Substances List (DSL), are exempt, or have been reported in accordance with the New Substances Notification Regulations. EUROPE The substances in this preparation have been reviewed for compliance with the EINECS or ELINCS inventories. JAPAN All substances in this product comply with the Law Regulating the Manufacture and Importation Of Chemical Substances and are listed on the Ministry of International Trade & industry List (MITI).

16.

OTHER INFORMATION

RELEVANT RISK PHRASES AND NOTAS R11 - Highly flammable. R48/22 - Harmful: danger of serious damage to health by prolonged exposure if swallowed. R51/53 - Toxic to aquatic organisms, may cause long-term adverse effects in the aquatic environment. R20/22 - Harmful by inhalation and if swallowed. R22 - Harmful if swallowed. R23/24/25 - Toxic by inhalation, in contact with skin and if swallowed. R34 - Causes burns. R36/38 - Irritating to eyes and skin. R38 - Irritating to skin. R39/23/24/25 - Toxic: danger of very serious irreversible effects through inhalation, in contact with skin and if swallowed. R41 - Risk of serious damage to eyes. This product material safety data sheet provides health and safety information. The product is to be used in applications consistent with our product literature. Individuals handling this product should be informed of the recommended safety precautions and should have access to this information. For any other uses, exposures should be evaluated so that appropriate handling practices and training programs can be established to insure safe workplace operations. Please consult your local sales representative for any further information. EMERGENCY TELEPHONE NUMBER(S) Trans-European Belgium / Luxembourg Czech Republic Denmark Finland France / French Switzerland Germany / Austria / German Switzerland Hungary Italy / Italian Switzerland

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+32-(0)3-575-5555 +32-(0)3-575-0330 +420-602-669421 +47-22-33-69-99 +358-(0)9-4711 +33-(0)6-11-07-32-81 +49-(0)6232-130128 +36-30-9-506-447 +39-333-210-7947


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The Netherlands Norway Poland Portugal Russia / Belarus Slovak Republic Spain Sweden UAE UK and Republic of Ireland Nalfleet International

+32-(0)3-575-0330 +47-22-33-69-99 +48-(0)601-66-2626 +351-91-911-1399 +7-812-449-0474 +421-(0)905-585-938 +34-977-551577 +47-22-33-69-99 +44-(0)7071-223-738 +44-(0)7071-223-738 +32-(0)3-575-5555

POISON CONTROL CENTER TELEPHONE NUMBERS Belgium Czech Republic France Slovak Republic

+32-70-245245 +420 224 91 92 93 +33-(0)145-42-59-59 ORFILA +421 (0)2 5477 4166

Prepared By : SHE Department Date issued : 17.03.2005 Version Number : 1.10

REVISED INFORMATION: Signficant changes to regulatory or health information for this revision is indicated by a bar in the left-hand margin of the MSDS. Numbers quoted in the MSDS are given in the format: 1,000,000 = 1 million and 1,000 = 1 thousand

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MATERIAL SAFETY DATA SHEET

Trade Name Product Code

CHIMEC 1430 993/3

1. Identification of the substance & the company Identification of the substance Trade name

: CHIMEC 1430

Chemical family

: quaternary ammonium compounds : in water solution.

Type of product and use

: corrosion inhibitor.

Company identification Responsible for placing on the market

: CHIMEC S.p.A.

Address and telephone nr

: CHIMEC S.p.A. - Via Ardeatina Km 22,500 00040 S. Palomba - Pomezia (ROMA) Tel. 06.918251 - Fax 06.91825260

2. Composition / information on ingredients : alkyl-imidazolyne / benzyl quat. Hazardous component(s) Corrosive (C). R:34. LD50 oral: > 2000 mg/Kg (rat). CAS Nr.73049-47-5 Conc. : 20 - 30 % : alkyl dimethyl benzyl ammonium chloride. Corrosive(C). R:22,34. LD50 oral: 400 mg/Kg (rat). CAS Nr.68989-00-4 Conc. : 10 - 20 %

3. Hazards identification Important hazards

: a concentrated solution of this product is corrosive: direct contact may produce skin burns and strong eye irritation.

4. First-aid measures First aid - Inhalation

: remove the exposed person from contaminated area; keep warm and in fresh air. : if victim has trouble breathing, transport to medical care and give supplemental oxygen. : in case of loss of consciousness, give artificial respiration.

- Skin contact

: take off immediately all contaminated clothing. : wash thoroughly with soapy water. : if irritation persists, seek medical advice.

Page

1

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CHIMEC S.p.A. Via delle Ande 19 00144 Roma Tel. +39.06.918251

Trade Name

CHIMEC 1430

- Eye contact

: wash with plenty of water,for at least 15 minutes, keeping the lids well open. : seek medical advice.

- Ingestion

: rinse the mouth with clean water; give plenty of water, seek medical advice. : do not give anything by mouth to an unconscious or convulsing person.

5. Fire - fighting measures Extinguishing media - Suitable

: carbon dioxide, dry chemicals, foam, water spray ( or fog).

- Not suitable

: in case of large fire, water may be ineffective

Fire/explosion hazards

: avoid breathing the fumes. : avoid static build up; must be earthed.

Fire-fighting procedures

: fire fighters and others who may be exposed to the products of combustion, should be equipped with NIOSH approved positive pressure self-contained breathing apparatus and full protective clothing. : when exposed to flames or high temperatures encountered during fire conditions, sealed containers may rupture because of the build up of internal pressure: cool containers with water and remove. : the contaminated water used for extinguishing must be disposed of in accordance with local legislation.

6. Accidental release measures After spillage / leakage - on soil

- on water

7. Handling and storage Handling

: isolate the dangerous area, wear protective clothing. Remove all sources of ignition and contain the spill with inert materials. : then collect in suitable containers and dispose of or burn at approved site. : avoid dispersion of large quantities of product in sewers or waterways. : if spilled product is going into water courses or drain and soil or vegetation are contaminated, advise legal authority and take measures to minimize effects on the aquatic environment.

: avoid contact with skin and eyes. : handle this product near emergency showers, emergency eye-wash and with independent breathing protection. : protect eyes from vapour/spray. : do not breathe vapour/spray.

Page

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Trade Name

CHIMEC 1430

: take precautionary measures against static discharge during blending and transfer operations. : wear suitable respiratory equipment. : a localized aspiration is necessary if the warmed product forms vapours. : store in well closed boxes.

Storage

Suitable storage materials Not suitable storage materials

: store in a fresh and well-ventilated place, away from incompatible substances. : keep containers in store rooms with security electric plants and protection from atmospheric discharge. : stainless steel (316 L), teflon and fluorinated polymers, high density polyethylene, polypropylene, epoxy and furanic resins, polyesther, Viton. : carbon steel, polyacetalic and polysulphonic resins, polycarbonates, nylon, polyurethanes and poly-methyl methacrylates.

8. Exposure controls / personal protection : this product is a complex mixture and contains following Occupational exposure limits substances with recommended or approved OEL limits: TLV (mg/m3) : ---TLV

(ppm)

: ----

Personal protection - Respiratory protection

- Eye protection

: a localized aspiration is necessary if the warmed product forms vapours. : protective mask in case of exposure to vapours formed by warmed product. : protective gloves in neoprene or latex, approved for protection against chemical substances (EC seal - Directives 89/686 and 93/68). : goggles or face shield with safety glasses.

- Others

: appropriated protective clothing.

- Skin protection

: eyewash bottle with clean water. Industrial hygiene

: ventilate thoroughly the working place. : do not eat or drink when handling this product. : remove all contaminated clothing and remove protective clothing when the work is completed. : handle in accordance with good industrial hygiene and safety procedures.

9. Physical and chemical properties Appearance Physical state at 20°C Page

3

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: liquid. CHIMEC S.p.A. Via delle Ande 19 00144 Roma Tel. +39.06.918251

Trade Name

CHIMEC 1430

Colour

: yellow.

Odour

: characteristic.

Change in physical state -760 mm Hg - Freezing point (°C)

: -5°C

- Boiling point (°C)

: ca. 100

- Pour point

(ASTM D97)

(°C)

: n.d.

Density at 20°C

(gr/cm3)

: 1.01 ± 0.02

Viscosity at 20°C

(cP)

: 50 - 200

Solubility in water

(% weight)

: complete.

Soluble in

: water.

pH value (concentrated product) Flash point (ASTM D 93) (°C) Auto-ignition temperature

: > 100 (°C)

: n.d.

Explosion limits - Lower

(% vol)

: n.d.

- Upper

(% vol)

: n.d.

Thermal decomposition (°C)

: stable if utilized under normal conditions.

Further information

: The information reported in this Material Safety Data Sheet are not to be considered as a guarantee on any specific properties of the product.

10. Stability and reactivity Conditions to avoid

: hot organic chemical vapours or mists can suddenly and without warning combust when mixed with air: ignition can occur at typical elevated temperature process conditions. : any proposed use in such processes should be evaluated thoroughly to assure safe operating conditions. : none to our knowledge.

Substances to avoid On combustion forms Hazardous decomposition products

: may release oxides of carbon and other toxic gases and vapours. : no hazardous decomposition products.

Hazardous reactions

: may react violently with strong oxidizers.

11. Toxicological information Rat oral LD50 (mg/kg)

: ----

Rabbit dermal LD50

(mg/kg)

: ----

Rat inhalation LC50

(ppm)

: ----

Inhalation

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: vapours or fog inhalation at high temperature may produce irritation of respiratory tract.


Trade Name

CHIMEC 1430

Dermal toxicity

: skin damages caused by prolonged and repeated contact.

Ingestion

: burning effects in mouth, throat and stomach with abdominal cramps.

Corrosivity / Irritating capacity - skin

: corrosive. : may produce dermatitis and burns.

- eyes

: corrosive. : direct contact may cause conjunctivitis and corneal lesions.

Sensitization

: no evidence of this effect is shown.

Carcinogenicity


Mutagenicity


Teragenicity


12. Ecological information Information on ecological effects Mobility 96 Hour-LC50-fish

(mg/l)

: utilize in accordance with good working practice and avoid to disperse the product in the environment. : with a correct disposal in biological treatment system, are not expected problems for the degradation activity of activated sludge. : ----

Persistence and degradability

: readily degradable.

Biodegradation (%)

: the product is not readily biodegradable.

Bioaccumulative potential WGK class (Germany)

: the product has been shown to present no bioaccumulation hazard in aquatic plants or fish. : 2 - hazardous.

AOX

: the product does not contain organic halons.

13. Disposal considerations Disposal

Disposal of packaging

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: dispose in a safe manner in accordance with local/national regulations. : do not dispose in a sink, drain or in the immediate environment. : of the methods of disposal currently available, it is recommended that an alternative be selected according to the following order of preference, based upon environmental acceptability: : 1 - recycle or rework if at all feasible; 2 - incinerate at an authorized facility; 3 - treat at an acceptable waste treatment facility. : dirty containers of product must be recycled or disposed by an authorized facility. : empty containers can retain product residues and may be CHIMEC S.p.A. Via delle Ande 19 00144 Roma Tel. +39.06.918251

Trade Name

CHIMEC 1430

hazardous: do not use heat, sparks, open flames, or cigarettes on near empty container. 14. Transportation information - ADR/RID/IATA Proper shipping name

: Corrosive liquids, n.o.s.

ADR Class

: 8 - Corrosive substances.

Packaging group

: II

Risk Label(s)

: 8 - Corrosive.

Subsidiary Risk Label(s)

: none.

Danger identification number (upper)

: 80

Substance identification number (lower)

: 1760

Tremcard type

: C

UN Number.

: 1760

IMO-IMDG IMO class

: 8 - Corrosive substances.

Risk Label

: 8 - Corrosive.

Subsidiary Risk Label

: none.

Proper shipping name

: Corrosive liquids, n.o.s.

Contains

: alkyl-imidazolyne / benzyl quat : alkyl dimethyl benzyl ammonium chloride

Packaging group

: II

Emergency Schedule (EmS)

: F-A, S-B

15. Regulatory information UE - Symbol(s)

: Corrosive:C

- Contains

: alkyl-imidazolyne / benzyl quat : alkyl dimethyl benzyl ammonium chloride

- R Phrase(s)

: R 34 :Causes burns.

- S Phrase(s)

: S 26 :In case of contact with eyes, rinse immediately with plenty of water and seek medical advice. : S 28 :After contact with skin, wash immediately with plenty of soap and water. : S 36/37/39 :Wear suitable protective clothing, gloves and eye/face protection. : S 45: In case of accident or if you feel unwell, seek medical advice immediately (show the label when possible).

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Trade Name

CHIMEC 1430

16. Other information Further information

: R 34 :Causes burns. : R 22 :Harmful if swallowed.

Sources of key data used

: N.Irving SAX - Dangerous properties of Industrial Materials ( Sixth edition) - Edited by Van Nostrand Reinhold Company 1984 : TLV - Threshold Limit Values for Chemical Substances in Work Environment - Adopted by ACGIH - 2000 : A.D.R. - European Agreement concerning the international carriage of Dangerous Goods by Road - United Nation Publication : Karel VERSCHUEREN - Handbook of Environmental data on organic chemicals - 1977

Information for medical staff Revised chapters

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: The chapters indicated by " ********** " have been modified with the present version of this MSDS. : The chapters indicated by " ********** " have been modified with the present version of this MSDS.


Trade Name

CHIMEC 1430

22/01/2007

Issue Date:

MATERIAL SAFETY DATA SHEET ST1 - 993/3 28/07/2003 - 1

Preparata da: C.SCALAMANDRE This MSDS complies with Directives 91/155/EC, 93/112/EC, 2001/58/EC, 2001/59/EC, 2001/60/EC and their amendments. Laboratorio CHIMEC Via Ardeatina KM.22.500 - Loc. S.Palomba Pomezia(ROMA) Tel.(06)- 918251 - Fax n.(06)-91825260

Le informazioni contenute in questo documento sono date in buona fede, e costituiscono la nostra migliore conoscenza in m Tuttavia non possono costituire in alcun caso responsabilità a nostro carico quando il prodotto è impiegato impropriamente. The information reported on this MSDS results from our present state of knowledge on safety regulations and is not to be co guarantee of any specific product property. CHIMEC cannot be held responsible for any injury or damage deriving from the improper application of the product.

Les informations incluses dans cette fiche de sécurité dérivent de nos connaissances actuelles en matière de sécurité. Elles n en aucun cas une garantie des propriétés spécifiques du produit. Aucun dommage résultant d`une application impropre du produit ne peut être imputé à CHIMEC.

Alle Angaben stützen sich auf den heutigen Stand unserer Kenntnisse. Das Sicherheitsdatenblatt ist dazu bestimmt, die beim chemischen Stoffen und Zubereitungen wesentlichen physikalischen, sicherheitstechnischen, toxikologischen und ökologischen Daten zu vermitteln und Empfehlungen für den sicheren Umgang Verwendung und Transport zu geben.

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MATERIAL SAFETY DATA SHEET

Trade Name Product Code

CHIMEC 8045 874/2

1. Identification of the substance & the company Identification of the substance Trade name

: CHIMEC 8045

Chemical family

: siliconic antifoam : in xylene (mixture of isomers).

Type of product and use

: antifoam product.

Company identification Responsible for placing on the market

: CHIMEC S.p.A.

Address and telephone nr

: CHIMEC S.p.A. - Via Ardeatina Km 22,500 00040 S. Palomba - Pomezia (ROMA) Tel. 06.918251 - Fax 06.91825260

2. Composition / information on ingredients : xylene (isomers mixture). Hazardous component(s) Harmful(Xn).R:10,20/21,38. TLV-TWA (ACGIH): 100 ppm - 435 mg/m3. CAS Nr.1330-20-7 Conc. : > 80 %

3. Hazards identification Important hazards

: the product is harmful if inhalated and in contact with skin: the most important hazard is exposure to high vapour concentration, with resultant central nervous system depression and visual disease.

4. First-aid measures First aid - Inhalation

- Skin contact

: remove the exposed person from contaminated area; keep warm and in fresh air. : if not breathing, give artificial respiration and seek immediate medical attention. : take off immediately all contaminated clothing. : wash thoroughly with soapy water. : if irritation persists, seek medical advice.

- Eye contact

: wash with plenty of water,for at least 15 minutes, keeping the lids well open. : seek medical advice.

- Ingestion

: do not induce vomiting.

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Trade Name

CHIMEC 8045

: rinse the mouth with clean water; give plenty of water, seek medical advice. : do not give anything by mouth to an unconscious or convulsing person. : if aspiration is suspected (during spontaneous vomiting,for instance),seek medical advice urgently. 5. Fire - fighting measures Extinguishing media - Suitable

: carbon dioxide, dry chemicals, foam, water spray ( or fog).

- Not suitable

: water jets.

Fire/explosion hazards

: avoid static build up; must be earthed.

Fire-fighting procedures

: avoid vapours contact with sources of flame (open flames, sparks, very hot surface). : fire fighters and others who may be exposed to the products of combustion, should be equipped with NIOSH approved positive pressure self-contained breathing apparatus and full protective clothing. : when exposed to flames or high temperatures encountered during fire conditions, sealed containers may rupture because of the build up of internal pressure: cool containers with water and remove. : the contaminated water used for extinguishing must be disposed of in accordance with local legislation.

6. Accidental release measures After spillage / leakage - on soil

- on water

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: isolate the dangerous area, wear protective clothing. Remove all sources of ignition and contain the spill with inert materials. : then collect in suitable containers and dispose of or burn at approved site. : avoid dispersion of large quantities of product in sewers or waterways. : vapours heavier than air propagate at ground level and may cause risks of explosion and poisoning in basements and pits. : contain and limit the spill at source; remove the residual product from surface by mechanical means or absorbing material. : if spilled product is going into water courses or drain and soil or vegetation are contaminated, advise legal authority and take measures to minimize effects on the aquatic environment. : advise legal authority (harbour, ecc.) and keep other boats away: only if allowed by authority, may the product be sunk or dispersed with suitable substances.


Trade Name

CHIMEC 8045

7. Handling and storage Handling

: take precautionary measures against static discharge during blending and transfer operations. : avoid contact with skin and eyes. : handle the product near emergency washing and eye wash bottles. : protect eyes from vapour/spray.

Storage

: store in well closed boxes. : store in a fresh and well-ventilated place, away from incompatible substances. : storage at elevated temperatures should be avoided.

Suitable storage materials Not suitable storage materials

: keep containers in store rooms with security electric plants and protection from atmospheric discharge. : carbon and stainless steel, teflon. : natural or butylic rubber, EPDM, polystyrene, polyethylene, polypropylene, PVC, polyvinylalcohols, polyacrylonitryle.

8. Exposure controls / personal protection Occupational exposure limits : this product is a complex mixture and contains following substances with recommended or approved OEL limits: TLV (mg/m3) TLV (ref. to solvent)

(mg/m3)

: 430 - TWA (Xylene) : 540 - STEL (Xylene)

Personal protection - Respiratory protection

: a localized aspiration is necessary if the warmed product forms vapours. : none under normal conditions. : ensure good ventilation.

- Eye protection

: in closed premises or in case of insufficient ventilation, use protective mask with filter for organic vapours. : protective gloves made of nitrile or PVA, approved for protection against chemical substances (EC seal - Directives 89/686 and 93/68). : goggles or face shield with safety glasses.

- Others

: appropriated protective clothing.

- Skin protection

: eyewash bottle with clean water. Industrial hygiene

: keep away from sources of ignition - no smoking. : ventilate thoroughly the working place. : do not eat or drink when handling this product. : remove all contaminated clothing and remove protective clothing when the work is completed.

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Trade Name

CHIMEC 8045

: handle in accordance with good industrial hygiene and safety procedures. 9. Physical and chemical properties Appearance Physical state at 20°C

: liquid.

Colour

: colourless to light yellow. : yellow.

Odour

: characteristic.

Change in physical state -760 mm Hg - Freezing point (°C)

: n.d.

- Boiling point (°C)

: ca. 140 °C

- Pour point

(ASTM D97)

(°C)

: < -20

Density at 20°C

(gr/cm3)

: 0.89 ± 0.01

Viscosity at 20°C

(cP)

: < 100

Solubility in water

(% weight)

Soluble in

: insoluble. : aromatic and aliphatic hydrocarbons. : organic solvents.

pH value in distilled water

: n.d.

Flash point (ASTM D 93) (°C)

: ca.28

Auto-ignition temperature

(°C)

: > 450

Explosion limits - Lower

(% vol)

: 1.1

- Upper

(% vol)

: 14.0

Thermal decomposition (°C)

: stable if utilized under normal conditions.

Further information

: The information reported in this Material Safety Data Sheet are not to be considered as a guarantee on any specific properties of the product.

10. Stability and reactivity Conditions to avoid Substances to avoid

: the product is incompatible with concentrated acids and strong oxidizing agents. : avoid contact with strong oxidizers.

Hazardous decomposition products

: may release oxides of carbon and other toxic gases and vapours. : no hazardous decomposition products.

Hazardous reactions

: none to our knowledge.

On combustion forms

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Trade Name

CHIMEC 8045

11. Toxicological information Rat oral LD50 (mg/kg) Inhalation

Rat inhalation LC50

: 4300 (Xylene) : slight exposure: irritation of eyes and primary respiratory tract, with temporary reduction of smelling capacity. : exposure to high vapour concentration: depressant effect on the central nervous system with headaches, drowsiness, derangement, serious damage to visual faculties, nausea, vomiting, drunkenness. : may cause anesthetic and/or narcotic effects.

(ppm)

Dermal toxicity

: 5000 (Xylene) : the product is harmful when absorbed through the skin in sufficient amounts. : ingestion causes severe irritation of the mouth, throat and stomach, with nausea, vomiting, dizziness, faintness, drowsiness and lack of coordination. : ingestion creates a high risk of aspiration and subsequent chemical pneumonia.

Ingestion

Corrosivity / Irritating capacity - skin

: prolonged and repeated contact may produce dermatitis and irritation. : the vapours may cause irritation.

- eyes

: direct contact may cause strong irritation. Sensitization


Carcinogenicity


Mutagenicity


Teragenicity


12. Ecological information Information on ecological effects Mobility 96 Hour-LC50-fish

(mg/l)

Persistence and degradability

: utilize in accordance with good working practice and avoid to disperse the product in the environment. : with a correct disposal in biological treatment system, are not expected problems for the degradation activity of activated sludge. : n.d.

WGK class (Germany)

: the product is rapidly eliminated from the aquatic medium through irreversible adsorption onto suspended matter and dissolved organics. : this product is not water-soluble and is therefore slowly degraded by micro- organisms. : the product has been shown to present no bioaccumulation hazard in aquatic plants or fish. : 2 - hazardous.

AOX

: the product does not contain organic halons.

Biodegradation (%) Bioaccumulative potential

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Trade Name

CHIMEC 8045

13. Disposal considerations Disposal

Disposal of packaging

: dispose in a safe manner in accordance with local/national regulations. : do not dispose in a sink, drain or in the immediate environment. : of the methods of disposal currently available, it is recommended that an alternative be selected according to the following order of preference, based upon environmental acceptability: : 1 - recycle or rework if at all feasible; 2 - incinerate at an authorized facility; 3 - treat at an acceptable waste treatment facility. : dirty containers of product must be recycled or disposed by an authorized facility. : empty containers can retain product residues and may be hazardous: do not use heat, sparks, open flames, or cigarettes on near empty container.

14. Transportation information - ADR/RID/IATA Proper shipping name

: Flammable liquids, n.o.s.

ADR Class

: 3 - Flammable liquids.

Packaging group

: III

Risk Label(s)

: 3 - Flammable.

Subsidiary Risk Label(s) Danger identification number (upper)

: 30

Substance identification number (lower)

: 1993

Tremcard type

: F1

UN Number.

: 1993

IMO-IMDG IMO class Risk Label

: 3.3 - Flammable liquids. High flashpoint group (up to 23°C and including 61°C). : 3 - Flammable.

Subsidiary Risk Label Proper shipping name

: 1993

Contains

: xylene (isomers mixture).

Packaging group

: III

Emergency Schedule (EmS)

: F-E, S-E

15. Regulatory information Page

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Trade Name

CHIMEC 8045

UE - Symbol(s)

: Harmful:Xn

- Contains

: xylene (isomers mixture).

- R Phrase(s)

: R 10 :Flammable. : R 20/21 :Harmful by inhalation and in contact with skin. : R 38 :Irritating to skin.

- S Phrase(s)

16. Other information Further information

: S 25 :Avoid contact with eyes.

: R 10 :Flammable. : R 20/21 :Harmful by inhalation and in contact with skin. : R 38 :Irritating to skin.

Sources of key data used

: N.Irving SAX - Dangerous properties of Industrial Materials ( Sixth edition) - Edited by Van Nostrand Reinhold Company 1984 : TLV - Threshold Limit Values for Chemical Substances in Work Environment - Adopted by ACGIH - 2000 : A.D.R. - European Agreement concerning the international carriage of Dangerous Goods by Road - United Nation Publication : Karel VERSCHUEREN - Handbook of Environmental data on organic chemicals - 1977

Information for medical staff Revised chapters

Page

7

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: The chapters indicated by " ********** " have been modified with the present version of this MSDS.


Trade Name

CHIMEC 8045

01/02/2005

Issue Date:

MATERIAL SAFETY DATA SHEET ST1 - 874/2 12/06/2003 - 1

Preparata da: C.SCALAMANDRE This MSDS complies with Directives 91/155/EC, 93/112/EC, 2001/58/EC, 2001/59/EC, 2001/60/EC and their amendments. Laboratorio CHIMEC Via Ardeatina KM.22.500 - Loc. S.Palomba Pomezia(ROMA) Tel.(06)- 918251 - Fax n.(06)-91825260

Le informazioni contenute in questo documento sono date in buona fede, e costituiscono la nostra migliore conoscenza in m Tuttavia non possono costituire in alcun caso responsabilità a nostro carico quando il prodotto è impiegato impropriamente. The information reported on this MSDS results from our present state of knowledge on safety regulations and is not to be co guarantee of any specific product property. CHIMEC cannot be held responsible for any injury or damage deriving from the improper application of the product.

Les informations incluses dans cette fiche de sécurité dérivent de nos connaissances actuelles en matière de sécurité. Elles n en aucun cas une garantie des propriétés spécifiques du produit. Aucun dommage résultant d`une application impropre du produit ne peut être imputé à CHIMEC.

Alle Angaben stützen sich auf den heutigen Stand unserer Kenntnisse. Das Sicherheitsdatenblatt ist dazu bestimmt, die beim chemischen Stoffen und Zubereitungen wesentlichen physikalischen, sicherheitstechnischen, toxikologischen und ökologischen Daten zu vermitteln und Empfehlungen für den sicheren Umgang Verwendung und Transport zu geben.

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NALCO 7208 EMERGENCY TELEPHONE NUMBER(S) (800) 424-9300 (24 Hours) CHEMTREC

1.

CHEMICAL PRODUCT AND COMPANY IDENTIFICATION

PRODUCT NAME :

NALCO 7208

APPLICATION :

BOILER WATER TREATMENT

COMPANY IDENTIFICATION :

Ondeo Nalco Energy Services, L.P. P.O. Box 87 Sugar Land, Texas 77487-0087

EMERGENCY TELEPHONE NUMBER(S) :

(800) 424-9300 (24 Hours)

NFPA 704M/HMIS RATING HEALTH : 1/2 FLAMMABILITY : 0/0 INSTABILITY : 0 = Insignificant 1 = Slight 2 = Moderate 3 = High 4 = Extreme

2.

CHEMTREC

0/0

OTHER :

COMPOSITION/INFORMATION ON INGREDIENTS

Our hazard evaluation has identified the following chemical substance(s) as hazardous. Consult Section 15 for the nature of the hazard(s). Hazardous Substance(s) Sodium Hydroxide

3.

CAS NO 1310-73-2

% (w/w) 0.01.0 - 5.0

HAZARDS IDENTIFICATION **EMERGENCY OVERVIEW**

WARNING Irritating to eyes and skin. Do not get in eyes, on skin, on clothing. Do not take internally. Keep container tightly closed. In case of contact with eyes, rinse immediately with plenty of water and seek medical advice. After contact with skin, wash immediately with plenty of water. Protect product from freezing. Wear suitable protective clothing, gloves and eye/face protection. May evolve oxides of phosphorus (POx) under fire conditions. PRIMARY ROUTES OF EXPOSURE : Eye, Skin HUMAN HEALTH HAZARDS - ACUTE : EYE CONTACT : Can cause moderate to severe irritation. SKIN CONTACT : Can cause moderate to severe irritation.

Ondeo Nalco Energy Services, L.P. P.O. Box 87 • Sugar Land, Texas 77487-0087 (281)263-7000 1 / 11

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INGESTION : Not a likely route of exposure. No adverse effects expected. INHALATION : Not a likely route of exposure. Aerosols or product mist may irritate the upper respiratory tract. SYMPTOMS OF EXPOSURE : Acute : A review of available data does not identify any symptoms from exposure not previously mentioned. Chronic : A review of available data does not identify any symptoms from exposure not previously mentioned. AGGRAVATION OF EXISTING CONDITIONS : A review of available data does not identify any worsening of existing conditions.

4.

FIRST AID MEASURES

EYE CONTACT : Immediately flush eye with water for at least 15 minutes while holding eyelids open. If irritation persists, repeat flushing. Get immediate medical attention. SKIN CONTACT : Immediately flush with plenty of water for at least 15 minutes. If symptoms persist, call a physician. INGESTION : Do not induce vomiting without medical advice. If conscious, washout mouth and give water to drink. Get medical attention. INHALATION : Remove to fresh air, treat symptomatically. Get medical attention. NOTE TO PHYSICIAN : Based on the individual reactions of the patient, the physician's judgement should be used to control symptoms and clinical condition.

5.

FIRE FIGHTING MEASURES

FLASH POINT :

> 200 °F / > 93 °C ( PMCC )

EXTINGUISHING MEDIA : This product would not be expected to burn unless all the water is boiled away. The remaining organics may be ignitable. Keep containers cool by spraying with water. Use extinguishing media appropriate for surrounding fire. FIRE AND EXPLOSION HAZARD : May evolve oxides of phosphorus (POx) under fire conditions. SPECIAL PROTECTIVE EQUIPMENT FOR FIRE FIGHTING : In case of fire, wear a full face positive-pressure self contained breathing apparatus and protective suit.


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6.

ACCIDENTAL RELEASE MEASURES

PERSONAL PRECAUTIONS : Restrict access to area as appropriate until clean-up operations are complete. Ensure clean-up is conducted by trained personnel only. Ventilate spill area if possible. Do not touch spilled material. Stop or reduce any leaks if it is safe to do so. Use personal protective equipment recommended in Section 8 (Exposure Controls/Personal Protection). Notify appropriate government, occupational health and safety and environmental authorities. METHODS FOR CLEANING UP : SMALL SPILLS: Soak up spill with absorbent material. Place residues in a suitable, covered, properly labeled container. Wash affected area. LARGE SPILLS: Contain liquid using absorbent material, by digging trenches or by diking. Reclaim into recovery or salvage drums or tank truck for proper disposal. Wash site of spillage thoroughly with water. Contact an approved waste hauler for disposal of contaminated recovered material. Dispose of material in compliance with regulations indicated in Section 13 (Disposal Considerations). ENVIRONMENTAL PRECAUTIONS : Do not contaminate surface water.

7.

HANDLING AND STORAGE

HANDLING : Avoid eye and skin contact. Do not take internally. Do not get in eyes, on skin, on clothing. Have emergency equipment (for fires, spills, leaks, etc.) readily available. Ensure all containers are labelled. Keep the containers closed when not in use. Use with adequate ventilation. STORAGE CONDITIONS : Store the containers tightly closed. Store in suitable labelled containers. SUITABLE CONSTRUCTION MATERIAL : Teflon, HDPE (high density polyethylene), Natural rubber, Viton, Polypropylene, Stainless Steel 304, Stainless Steel 316L, Surface-modified HDPE (high density polyethylene), PTFE UNSUITABLE CONSTRUCTION MATERIAL : Carbon Steel C1018, Epoxy phenolic resin

8.

EXPOSURE CONTROLS/PERSONAL PROTECTION

OCCUPATIONAL EXPOSURE LIMITS : Exposure guidelines have not been established for this product. Available exposure limits for the substance(s) are shown below. ACGIH/TLV : Substance(s) Sodium Hydroxide

CEILING: 2 mg/m3

OSHA/PEL : Substance(s) Ondeo Nalco Energy Services, L.P. P.O. Box 87 • Sugar Land, Texas 77487-0087 (281)263-7000 3 / 11

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Sodium Hydroxide

CEILING: 2 mg/m3

ENGINEERING MEASURES : General ventilation is recommended. RESPIRATORY PROTECTION : Where concentrations in air may exceed the limits given in this section, the use of a half face filter mask or air supplied breathing apparatus is recommended. A suitable filter material depends on the amount and type of chemicals being handled. Consider the use of filter type: Particulate filter - HEPA (Purple) If respiratory protection is required, institute a complete respiratory protection program including selection, fit testing, training, maintenance and inspection. HAND PROTECTION : Neoprene gloves, Nitrile gloves, Butyl gloves, PVC gloves SKIN PROTECTION : Wear standard protective clothing. EYE PROTECTION : Wear chemical splash goggles. HYGIENE RECOMMENDATIONS : If clothing is contaminated, remove clothing and thoroughly wash the affected area. Launder contaminated clothing before reuse. Keep an eye wash fountain available. Keep a safety shower available. HUMAN EXPOSURE CHARACTERIZATION : Based on our recommended product application and personal protective equipment, the potential human e xposure is: Moderate

9.

PHYSICAL AND CHEMICAL PROPERTIES

PHYSICAL STATE

Liquid

APPEARANCE

Hazy Light yellow

ODOR

None

SPECIFIC GRAVITY DENSITY SOLUBILITY IN WATER pH (100 %) pH (1.0 %) VISCOSITY BOILING POINT VAPOR PRESSURE VOC CONTENT

1.04 - 1.08 @ 77 °F / 25 °C 8.7 - 9.0 lb/gal Complete 13.1 11.3 1.3 cps @ 77 °F / 25 °C 212 °F / 100 °C 12 mm Hg @ 68 °F / 20 °C 0.00 %

Note: These physical properties are typical values for this product and are subject to change.


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10.

STABILITY AND REACTIVITY

STABILITY : Stable under normal conditions. HAZARDOUS POLYMERIZATION : Hazardous polymerization will not occur. CONDITIONS TO AVOID : Freezing temperatures. MATERIALS TO AVOID : Contact with strong acids (e.g. sulfuric, phosphoric, nitric, hydrochloric, chromic, sulfonic) may generate heat, splattering or boiling and toxic vapors. HAZARDOUS DECOMPOSITION PRODUCTS : Under fire conditions: Oxides of phosphorus

11.

TOXICOLOGICAL INFORMATION

The following results are for the product. ACUTE ORAL TOXICITY : Species LD50 Rat 4,596 mg/kg Rating : Non-Hazardous

Test Descriptor Product

ACUTE DERMAL TOXICITY : Species LD50 Rabbit > 2,000 mg/kg Rating : Non-Hazardous

Test Descriptor Product

SENSITIZATION : This product is not expected to be a sensitizer. CARCINOGENICITY : None of the substances in this product are listed as carcinogens by the International Agency for Research on Cancer (IARC), the National Toxicology Program (NTP) or the American Conference of Governmental Industrial Hygienists (ACGIH). HUMAN HAZARD CHARACTERIZATION : Based on our hazard characterization, the potential human hazard is: Moderate

12.

ECOLOGICAL INFORMATION

ECOTOXICOLOGICAL EFFECTS : The following values are estimated based on known component toxicity. Ondeo Nalco Energy Services, L.P. P.O. Box 87 • Sugar Land, Texas 77487-0087 (281)263-7000 5 / 11

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ACUTE FISH RESULTS : Species Bluegill Sunfish Rainbow Trout Fathead Minnow Rating : Essentially non-toxic

Exposure 96 hrs 96 hrs 96 hrs

LC50 > 1,000 mg/l > 1,000 mg/l > 1,000 mg/l

ACUTE INVERTEBRATE RESULTS : Species Exposure Daphnia magna 48 hrs Rating : Essentially non-toxic

LC50 > 1,000 mg/l

Test Descriptor Similar Product Similar Product Similar Product

EC50 1,000 mg/l

Test Descriptor Similar Product

MOBILITY : The environmental fate was estimated using a level III fugacity model embedded in the EPI (estimation program interface) Suite TM , provided by the US EPA. The model assumes a steady state condition between the total input and output. The level III model does not require equilibrium between the defined media. The information provided is intended to give the user a general estimate of the environmental fate of this product under the defined conditions of the models. If released into the environment this material is expected to distribute to the air, water and soil/sediment in the approximate respective percentages; Air <5%

Water 30 - 50%

Soil/Sediment 50 - 70%

The portion in water is expected to be soluble or dispersible. BIOACCUMULATION POTENTIAL This preparation or material is not expected to bioaccumulate. ENVIRONMENTAL HAZARD AND EXPOSURE CHARACTERIZATION Based on our hazard characterization, the potential environmental hazard is: Low Based on our recommended product application and the product's characteristics, the potential environmental exposure is: Moderate If released into the environment, see CERCLA/SUPERFUND in Section 15.

13.

DISPOSAL CONSIDERATIONS

If this product becomes a waste, it could meet the criteria of a hazardous waste as defined by the Resource Conservation and Recovery Act (RCRA) 40 CFR 261. Before disposal, it should be determined if the waste meets the criteria of a hazardous waste. Hazardous Waste: D002 Hazardous wastes must be transported by a licensed hazardous waste transporter and disposed of or treated in a properly licensed hazardous waste treatment, storage, disposal or recycling facility. Consult local, state, and federal regulations for specific requirements.


_ _ _ _ _ RA| D __| N I ||___ 07

0 AR-2 07-M



14.

TRANSPORT INFORMATION

The information in this section is for reference only and should not take the place of a shipping paper (bill of lading) specific to an order. Please note that the proper Shipping Name / Hazard Class may vary by packaging, properties, and mode of transportation. Typical Proper Shipping Names for this product are as follows. LAND TRANSPORT : Proper Shipping Name : Technical Name(s) : UN/ID No : Hazard Class - Primary : Packing Group :

SODIUM HYDROXIDE SOLUTION

Flash Point :

> 93 °C / > 200 °F

UN 1824 8 III

AIR TRANSPORT (ICAO/IATA) : Proper Shipping Name : Technical Name(s) : UN/ID No : Hazard Class - Primary : Packing Group : IATA Cargo Packing Instructions : IATA Cargo Aircraft Limit :

SODIUM HYDROXIDE SOLUTION UN 1824 8 III 812 60 L (Max net quantity per package)

MARINE TRANSPORT (IMDG/IMO) : Proper Shipping Name : Technical Name(s) : UN/ID No : Hazard Class - Primary : Packing Group :

15.

SODIUM HYDROXIDE SOLUTION UN 1824 8 III

REGULATORY INFORMATION

NATIONAL REGULATIONS, USA : OSHA HAZARD COMMUNICATION RULE, 29 CFR 1910.1200 : Based on our hazard evaluation, the following substance(s) in this product is/are hazardous and the reason(s) is/are shown below. Sodium Hydroxide : Irritant CERCLA/SUPERFUND, 40 CFR 117, 302 : This product contains the following Reportable Quantity (RQ) Substance. Also listed is the RQ for the product. If a reportable quantity of product is released, it requires notification to the NATIONAL RESPONSE CENTER, WASHINGTON, D.C. (1-800-424-8802).


_ _ _ _ _ RA| D __| N I ||___ 07

0 AR-2 07-M



RQ Substance Sodium Hydroxide

RQ 65,700 lbs

SARA/SUPERFUND AMENDMENTS AND REAUTHORIZATION ACT OF 1986 (TITLE III) - SECTIONS 302, 311, 312, AND 313 : SECTION 302 - EXTREMELY HAZARDOUS SUBSTANCES (40 CFR 355) : This product does not contain substances listed in Appendix A and B as an Extremely Hazardous Substance. SECTIONS 311 AND 312 - MATERIAL SAFETY DATA SHEET REQUIREMENTS (40 CFR 370) : Our hazard evaluation has found this product to be hazardous. The product should be reported under the following indicated EPA hazard categories: X -

Immediate (Acute) Health Hazard Delayed (Chronic) Health Hazard Fire Hazard Sudden Release of Pressure Hazard Reactive Hazard

Under SARA 311 and 312, the EPA has established threshold quantities for the reporting of hazardous chemicals. The current thresholds are: 500 pounds or the threshold planning quantity (TPQ), whichever is lower, for extremely hazardous substances and 10,000 pounds for all other hazardous chemicals. SECTION 313 - LIST OF TOXIC CHEMICALS (40 CFR 372) : This product does not contain substances on the List of Toxic Chemicals. TOXIC SUBSTANCES CONTROL ACT (TSCA) : The substances in this preparation are included on or exempted from the TSCA 8(b) Inventory (40 CFR 710) FOOD AND DRUG ADMINISTRATION (FDA) Federal Food, Drug and Cosmetic Act : When use situations necessitate compliance with FDA regulations, this product is acceptable under : 21 CFR 173.310 Boiler Water Additives Limitations: no more than required to produce intended technical effect. This product has been certified as KOSHER/PAREVE for year-round use INCLUDING THE PASSOVER SEASON by the CHICAGO RABBINICAL COUNCIL. FEDERAL WATER POLLUTION CONTROL ACT, CLEAN WATER ACT, 40 CFR 401.15 / formerly Sec. 307, 40 CFR 116.4 / formerly Sec. 311 : This product contains the following substances listed in the regulation: Substance(s) • Sodium Hydroxide • Sodium Tripolyphosphate

Citations Sec. 311


_ _ _ _ _ RA| D __| N I ||___ 07

0 AR-2 07-M



CLEAN AIR ACT, Sec. 111 (40 CFR 60, Volatile Organic Compounds), Sec. 112 (40 CFR 61, Hazardous Air Pollutants), Sec. 602 (40 CFR 82, Class I and II Ozone Depleting Substances) : None of the substances are specifically listed in the regulation. CALIFORNIA PROPOSITION 65 : This product does not contain substances which require warning under California Proposition 65. MICHIGAN CRITICAL MATERIALS : None of the substances are specifically listed in the regulation. STATE RIGHT TO KNOW LAWS : The following substances are disclosed for compliance with State Right to Know Laws: Sodium Tripolyphosphate Sodium Hydroxide Water

7758-29-4 1310-73-2 7732-18-5

NATIONAL REGULATIONS, CANADA : WORKPLACE HAZARDOUS MATERIALS INFORMATION SYSTEM (WHMIS) : This product has been classified in accordance with the hazard criteria of the Controlled Products Regulations (CPR) and the MSDS contains all the information required by the CPR. WHMIS CLASSIFICATION : E - Corrosive Material CANADIAN ENVIRONMENTAL PROTECTION ACT (CEPA) : The substances in this preparation are listed on the Domestic Substances List (DSL), are exempt, or have been reported in accordance with the New Substances Notification Regulations. INTERNATIONAL CHEMICAL CONTROL LAWS AUSTRALIA All substances in this product comply with the National Industrial Chemicals Notification & Assessment Scheme (NICNAS) and are listed on the Australian Inventory of Chemical Substances (AICS). EUROPE The substances in this preparation have been reviewed for compliance with the EINECS or ELINCS inventories. JAPAN All substances in this product comply with the Law Regulating the Manufacture and Importation Of Chemical Substances and are listed on the Ministry of International Trade & industry List (MITI). KOREA All substances in this product comply with the Toxic Chemical Control Law (TCCL) and are listed on the Existing Chemicals List (ECL)


_ _ _ _ _ RA| D __| N I ||___ 07

0 AR-2 07-M



THE PHILIPPINES All substances in this product comply with the Republic Act 6969 (RA 6969) and are listed on the Philippine Inventory of Chemicals & Chemical Substances (PICCS).

16.

OTHER INFORMATION

Due to our commitment to Product Stewardship, we have evaluated the human and environmental hazards and exposures of this product. Based on our recommended use of this product, we have characterized the product's general risk. This information should provide assistance for your own risk management practices. We have evaluated our product's risk as follows: * The human risk is: Moderate * The environmental risk is: Low Any use inconsistent with our recommendations may affect the risk characterization. Our sales representative will assist you to determine if your product application is consistent with our recommendations. Together we can implement an appropriate risk management process. This product material safety data sheet provides health and safety information. The product is to be used in applications consistent with our product literature. Individuals handling this product should be informed of the recommended safety precautions and should have access to this information. For any other uses, exposures should be evaluated so that appropriate handling practices and training programs can be established to insure safe workplace operations. Please consult your local sales representative for any further information. REFERENCES Threshold Limit Values for Chemical Substances and Physical Agents and Biological Exposure Indices, American Conference of Governmental Industrial Hygienists, OH., (Ariel Insight# CD-ROM Version), Ariel Research Corp., Bethesda, MD. Hazardous Substances Data Bank, National Library of Medicine, Bethesda, Maryland (TOMES CPS# CD-ROM Version), Micromedex, Inc., Englewood, CO. IARC Monographs on the Evaluation of the Carcinogenic Risk of Chem icals to Man, Geneva: World Health Organization, International Agency for Research on Cancer. Integrated Risk Information System, U.S. Environmental Protection Agency, Washington, D.C. (TOMES CPS# CD-ROM Version), Micromedex, Inc., Englewood, CO. Annual Report on Carcinogens, National Toxicology Program, U.S. Department of Health and Human Services, Public Health Service. Title 29 Code of Federal Regulations, Part 1910, Subpart Z, Toxic and Hazardous Substances, Occupational Safety and Health Administration (OSHA), (Ariel Insight# CD-ROM Version), Ariel Research Corp., Bethesda, MD. Registry of Toxic Effects of Chemical Substances, National Institute for Occupational Safety and Health, Cincinnati, OH, (TOMES CPS# CD-ROM Version), Micromedex, Inc., Englewood, CO.


_ _ _ _ _ RA| D __| N I ||___ 07

0 AR-2 07-M



Ariel Insight# (An integrated guide to industrial chemicals covered under major regulatory and advisory programs), North American Module, Western European Module, Chemical Inventories Module and the Generics Module (Ariel Insight# CD-ROM Version), Ariel Research Corp., Bethesda, MD. The Teratogen Information System, University of Washington, Seattle, WA (TOMES CPS# CD-ROM Version), Micromedex, Inc., Englewood, CO.

Prepared By : Product Safety Department Date issued : 02/26/2003 Replaces : 05/16/2002


_ _ _ _ _ RA| D __| N I ||___ 07

0 AR-2 07-M

Project Nr Unit 8474L 410

Serial N° EL 001

OP Center Job No. OP Center Doc. No.

Rev. 0

Page 1 /19

: 0-3952-20 : S-000-1224-001

DOCUMENT CLASS :

X

PROJECT EQUIPMENT LIST DUNG QUAT REFINERY PROJECT Residue Fluidised Catalytic Cracking (RFCC) - Unit 015 LPG Treater (LTU) - Unit 016 RFCC Naphtha Treater (NTU) - Unit 017

Pages modified under this revision : 3～20

0

15-NOV-06 Issue for Construction

Y. Nishimura

S. Nishikawa

M. Kimbara

D

6-JUL-06

Issue for Design

Y. Nishimura

S. Nishikawa

M. Kimbara

C

17-FEB-06 Issue for Design

S. Nishikawa

M. Kimbara

M. Kimbara

B

29-SEP-05 Issue for Review

S. Nishikawa

M. Kimbara

M. Kimbara

A

26-SEP-05 Issue for Review

S. Nishikawa

M. Kimbara

M. Kimbara

WRITTEN BY (Name & visa)

CHECKED BY (Name & visa)

APPROVED BY (Name & visa)

Rev.

Date DD/MM/YY

_ _ _ __ RA| D __| N I ||___ 22000067- rev. 2 ELA1V R---ANG NO 0176-M

STATUS

DOCUMENT REVISIONS Sections changed in last revision are identified by a vertical line in the right margin

Page 2 / 19

PROJECT EQUIPMENT LIST

Project

Nr Unit

8474L 410

Serial N°

Revision

EL 001

0

DUNG QUAT REFINERY PROJECT IDENTIFICATION

REV

(1)

TAG

SERVICE

(2)

(3)

PURCHASING

PARENT TAG NUMBER

(4)

MAT ERIA REQUISITION NUMBERON DE L COD E

(5)

(6)

(7)

LOCALISATION

Criticality Factors VENDOR NAME

F

S

(8)

(9)

(10)

Category (PED)

(11)

Module (PED)

(12)

PID #

(13)

S Y S T E M

(14)

G E O G R .

D E S I G N

U N I T

A R E A

(15)

(16)

DESIGN PARAMETERS

D R I V E R

P O W E R / D U T Y

P O S I T I O N

(kW)

(17)

(18)

SUBCONTRACT PARAMETERS

OVERALL DIMENSIONS

(19)

MATERIAL

(m)

(m)

(m)

(kg/cm²g)

(° C)

(° C)

I N T E R N A L

(20)

(21)

(22)

(23)

(24)

(25)

(26)

DIAMETER / WIDTH

LENGTH

HEIG HT

Design pressure

Design Operating Temperature Temperature

PAINTING

INSULATION

E X T E R N A L

T Y P E

B Y

(27)

(28)

(29)

T H I C K .

(mm) (30)

M A T E R I A L

(31)

S U R F A C E

(m²)

(32)

F I R E P R O O F I N G

(33)

NBER OF DELIVERIES

S Y S T E M

B Y

(34)

(35)

I T E M

N U M S B K E I R D

(36)

(37)

D E L I V E R D

O F

W E I G H T

REMARKS

(Tons)

(38)

(39)

LEGEND 1: 2: 3: 4: 5: 6: 7: 8: 9: 10 : 11 : 12 : 13 : 14 : 15 : 16 : 17 : 18 : 19 : 20 : 21 : 22 : 23 : 24 : 25 : 26 : 27 : 28 : 29 : 30 : 31 : 32 : 33 : 34 : 35 : 36 : 37 : 38 : 39 :

Revision Index relative to the Process Data Sheet Item number Designation of the item Package item number in case equipment is included in a package Requisition number : XXXX Y-UUU-MR-AAAA-BBB where XXXX Y= Contract Number / UUU = Project unit / AAAA=Material Code / BBB= Serial Number Name of the requisition Material code as per Vademecuum relative to the equipment itself and not to the package Fabrication criteria as per PG 1 §3.4 Scheduling criteria as per PG 1 §3.4 Vendor Name responsible of the equipment / package Classification of Pressure vessels : 4 categories (I, II, III and IV) according to ascending level of hazard Conformity assessment procedures applied by Manufacturer : modules A, A1, B, B1, C1, D or D1, Eor E1, F, G , H and H1 PID(s) number where equipment is located Precommissioning system number :UUU-L-YYY where UUU= Unit number / L= P for process units, U for Utilities, E for Electrical / YYY= Serial numbe Geographical unit number where equipment is located Piping design area number where equipment is located Driver : "T" for turbine, "M" for motor, "D" for diesel, "S" for shaft, "P" for pneumatic For motor : power at rated flowrate to be specified, for exchanger : design duty Position for vessels only : enter "V" for (Vertical) or "H" for (Horizontal) Internal diameter Length between tangent lines Height between tangent lines Design Pressure : - For pumps : Casing/Imp - For exchangers : Shell side - For filters : Shell side/ Filtering side Design Temperature, same as point (23) Operating Temperature, same as point (24) - For exchangers : Tube side - For filters : Filtering side Internal Material : CS+CA (Corrosion Allowance) or LTCS, SS, 316L, 304S, Titane, - For pumps : Impeller - For exchangers : Shell side - For filters : Shell side External Material : CS+CA (Corrosion Allowance) or LTCS, SS, 316L, 304S, Titane - For pumps :casing Insulation type : H Hot insulation, C Cold insulation, A Acoustic insulation, PP Personal protection, NI not insulated, ST Steam traced By T (Technip) or V (Vendor) Thickness of insulation Material of insulation Surface of equipment to be insulated Fireproofing for equipment supports: Y (yes) or N (no) Painting system to be specified Painting : by T (Technip) or V (Vendor) Number of item to be delivered Number of package skids Empty Weight Remarks

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV NO 0176-M EL 1 - ANG - rev. 2

- For vessels : internals (such as mesh, distributor, packing, trays,..) or internal lining / cladding - For vessels : shell side

Page 3 /19


Project - Unit

Serial N°

8474L 410

EL 001

Revision 0

DUNG QUAT REFINERY PROJECT, Residue Fluidised Catalytic Cracking (RFCC) - Unit 015, LPG Treater (LTU) - Unit 016, RFCC Naphtha Treater (NTU) - Unit 017 IDENTIFICATION

REV

TAG

(1)

SERVICE

(2)

(3)

PURCHASING

PARENT REQUISITION TAG NUMBER NUMBER

(4)

(5)

REQUISITION MATERIA DESIGNATION L CODE

LOCALISATION

Criticality Factors

VENDOR NAME

F

S

(7)

(8)

(9)

(10)

AIR HEATERS

0110

B

A

I.T.A.S. SpA

AIR HEATERS

0110

B

A

I.T.A.S. SpA

(6)

Category (PED)

(11)

Module (PED)

(12)

PID #

(13)

S Y S T E M

(14)

G E O G R .

D E S I G N

U N I T

A R E A

(15)

(16)

DESIGN PARAMETERS

D R I V E R

P O W E R / D U T Y

P O S I T I O N

(kW)

(17)

(18)

SUBCONTRACT PARAMETERS MATERIAL

OVERALL DIMENSIONS

(19)

(m)

(m)

(m)

(kg/cm² g)

(° C)

(° C)

I N T E R N A L

(20)

(21)

(22)

(23)

(24)

(25)

(26)

DIAMETER / WIDTH

LENGTH

HEIGHT

Design Pressure


INSULATION E X T E R N A L

T Y P E

B Y

(27)

(28)

(29)

T H I C K .

(mm) (30)

M A T E R I A L

(31)

PAINTING S U R F A C E

(m²)

(32)


(33)

NBER OF DELIVERIES

D E L I V E R D

N U M I S B T K E E I R M D

S Y S T E M

B Y

(34)

(35)

(36)

O F

(37)

REMARKS W E I G H T

(Tons)

(38)

(39)

U015 - Residue Fluidised Catalytic Cracking (RFCC)

0100 - FIRED EQUIPMENT 0

H-1501

0

H-1502

0

H-1503

8474L-015MR-0110001 8474L-015SECOND REGENERATOR AIR MR-0110HEATER 001 8474L-015COB/WHB PACKAGE H-1503 MR-0160001


COB/WHB PACKAGE

0

H-1503-H-01

CO COMBUSTOR

8474L-015COB/WHB H-1503 MR-0160PACKAGE 001

0

H-1503-E-01

WASTE HEAT BOILER

H-1503

0

SPR-1501A


0

SPR-1501B


0

SPR-1501C


0

SPR-1502A


0

SPR-1502B


0

SPR-1502C


0

X-1507


C

X-1508

DESOX UNIT (FUTURE)

0

BV-1501A

0

BV-1501B

0

BV-1502A

0

BV-1502B

0

MOV-003

COB OUTLET FLUE GAS BLOCK VALVE

H-1503

0

ROV-001

E-1525 FLUE GAS BLOCK VALVE

H-1503

_ _ _ __ RA| D __| N I ||___ 0

ROV-002

C

ROV-003

C

ROV-004

067 R--22000 AV NO 0176-M 0

ROV-005

EL 1 - ANG - rev. 2

B

A

0160

B

A

8474L-015COB/WHB MR-0160PACKAGE 001

0160

B

A

TORCH OIL SPRAYER

0830

C

C

TORCH OIL SPRAYER

0830

C

C

TORCH OIL SPRAYER

0830

C

C

TORCH OIL SPRAYER

0830

C

C

TORCH OIL SPRAYER

0830

C

C

TORCH OIL SPRAYER

0830

C

C

8474L-015- ELECTROST MR-4240- ATIC 002 PRECIPITAT

4240

C

LODGE C STURTEVAN T LIMITED

8474L-015MR-0830201 8474L-015MR-0830201 8474L-015MR-0830201 8474L-015MR-0830201 8474L-015MR-0830201 8474L-015MR-0830201

SPRAYING SYSTEMS CO. SPRAYING SYSTEMS CO. SPRAYING SYSTEMS CO. SPRAYING SYSTEMS CO. SPRAYING SYSTEMS CO. SPRAYING SYSTEMS CO.

0146

CO BOILER FIRST REGENERATOR FLUE GAS BLOCK VALVE CO BOILER FIRST REGENERATOR FLUE GAS BYPASS VALVE CO BOILER SECOND REGENERATOR FLUE GAS BLOCK VALVE CO BOILER SECOND REGENERATOR FLUE GAS BYPASS VALVE

E-1525 OUTLET FLUE GAS BLOCK VALVE X-1508 FLUE GAS BLOCK VALVE (FUTURE) X-1508 OUTLET FLUE GAS BLOCK VALVE (FUTURE) E-1525 FLUE GAS BYPASS VALVE

0160

FOSTER WHEELER ENERGY FOSTER WHEELER ENERGY LIMITED FOSTER WHEELER ENERGY LIMITED

8474L-015MR-0130201 8474L-015MR-0130201 8474L-015MR-0130201 8474L-015MR-0130201

FUEL GAS BLOCK VALVE FUEL GAS BLOCK VALVE FUEL GAS BLOCK VALVE FUEL GAS BLOCK VALVE

200

15

H

1.772

7.800

2.6

5.2

350

200

SA516 Gr70 +3mm CA

8474L015-PID0021-203

15

H

3.880

29.220

19.75

0.2

350

15

0.250

2.000

770

SS304H + 1.5 mm CA

15

0.250

2.000

770

SS304H + 1.5 mm CA

15

0.250

2.000

770

SS304H + 1.5 mm CA

15

0.250

2.000

840

SS304H + 1.5 mm CA

15

0.250

2.000

840

SS304H + 1.5 mm CA

15

0.250

2.000

840

SS304H + 1.5 mm CA

15

22.830

18.320

8474L015-PID0021-126 8474L015-PID0021-126 8474L015-PID0021-126 8474L015-PID0021-130 8474L015-PID0021-130 8474L015-PID0021-130 8474L015-PID0021-204 8474L015-PID0021-205 8474L015-PID0021-201 8474L015-PID0021-201 8474L015-PID0021-202 8474L015-PID0021-202

0130

C

C

HOKUSHIN SANGYO

0130

C

C

HOKUSHIN SANGYO

0160

C

C

FOSTER WHEELER ENERGY

8474L015-PID0021-204

COB/WHB PACKAGE

0160

C

C

COB/WHB PACKAGE

0160

C

C

FOSTER WHEELER ENERGY FOSTER WHEELER ENERGY

8474L015-PID0021-205 8474L015-PID0021-205 8474L015-PID0021-205 8474L015-PID0021-205 8474L015-PID0021-205

70

85

V

1

29.5

70

65

V

1

21.4

V

1

V

7

15

350

HOKUSHIN SANGYO


350

0.2

C

C

5.2

10

C

C

3.192

15.340

0130

0160

6.950

9.500

HOKUSHIN SANGYO


2.500

H

C

0130 H-1503

H

15

C

0130

15

8474L015-PID0021-203

0130


8474L-015MR-0160001 8474L-015H-1503 MR-0160001

8474L015-PID0021-133 8474L015-PID0021-134 8474L015-PID0021-203

27.73

0.2

400

SA516 Gr70 +3mm CA

347

Inlet design temparature 770℃ Material of tubes for superheater shall be 9Cr 50.0 1Mo. Material of tuves for steam generation section shall be C Si or C Mn Inlet design temparature 840℃ Material of tubes for superheater shall be 9Cr 642.0 1Mo. Material of tuves for steam generation section shal

600.0

15

To be Installed in Future

15

H

2.400

4.700

5.2

770

678

SS400

Refractory Lined 6.5 Max Operating Temp. 730℃

15

H

2.400

4.700

5.2

770

678

SS400


15

H

1.700

3.900

5.2

840

772

SS400


15

H

1.700

3.900

5.2

840

772

SS400


15

0.2

400

LATER

15

0.2

400

LATER

15

0.2

400

LATER

15

To be Installed in Future with X-1508

15 15

To be Installed in Future with X-1508 0.2

400

LATER

Page 4 /19


Project - Unit

Serial N°

8474L 410

EL 001

Revision 0


REV

TAG

(1)

SERVICE

(2)

(3)

C

ROV-006

X-1508 FLUE GAS BYPASS VALVE (FUTURE)

D

SK-1501

STACK

PURCHASING


(4)

(5)


(6)

(7)

LOCALISATION

Criticality Factors

VENDOR NAME

F

S

(8)

(9)

(10)

0130

H-1503


0160

C

Category (PED)

(11)

Module (PED)

(12)

PID #

(13)

S Y S T E M

(14)

G E O G R .

D E S I G N

U N I T

A R E A

(15)

(16)

8474L015-PID0021-205

15

15

DESIGN PARAMETERS

D R I V E R

P O W E R / D U T Y

P O S I T I O N

(kW)

(17)

(18)


OVERALL DIMENSIONS

(19)

(m)

(m)

(m)

(kg/cm² g)

(° C)

(° C)

I N T E R N A L

(20)

(21)

(22)

(23)

(24)

(25)

(26)

DIAMETER / WIDTH

LENGTH

HEIGHT

Design Pressure



T Y P E

B Y

(27)

(28)

(29)

T H I C K .

(mm) (30)

M A T E R I A L

(31)


(m²)

(32)


(33)

S Y S T E M

B Y

(34)

(35)

NBER OF DELIVERIES

D E L I V E R D


(36)

O F

(37)

REMARKS W E I G H T

(Tons)

(38)

(39)

To be Installed in Future with X-1508

C


8474L015-PID0021-205

8474L015-PID0021-123

15

V

8.750

-

3.4/6.5

64.9

3

310.0

Refractory Lined (Because of the application of refractory lining, the design temperature for shell is 350 degC as 525.0 specified in AXENS's data sheet and mechanical flow diagram.) Weight is is shipping shipping weigh weigh Weight

0400 - REACTORS

0

D-1501


0

D-1502

FIRST REGENERATOR

0

D-1503

SECOND REGENERATOR

0

TR-D-1501

PACKING OF DISENGAGER / STRIPPER

D

REFRACTORY

DISENGAGE 8474L-015- R / MR-0410- STRIPPER & 001 REGENERA TORS DISENGAGE 8474L-015- R / MR-0410- STRIPPER & 001 REGENERA TORS DISENGAGE 8474L-015- R / MR-0410- STRIPPER & 001 REGENERA TORS 8474L-015- DISENGAGE MR-0480- R / 001 STRIPPER

8474L-015- REFRACTOR MR-0132- Y 001 MATERIAL SUPPLY

0410

A

A

HITACHI ZOSEN

0410

A

A

HITACHI ZOSEN

8474L015-PID0021-128

15

V

11.150

-

0410

A

A

HITACHI ZOSEN

8474L015-PID0021-129

15

V

10.250

-

0480

B

B

KOCH GLITCH

8474L015-PID0021-123

15

0132

B

A

PLIBRICO JAPAN CO.,LTD

28.665

18.500

13.5

8.750 / 5.325

5.2

350

525

A516 Gr70 + 1.5 mm CA (Each Side)

5.2

350

678

A240-304H + 1.5 mm CA (Each Side)

A516 Gr70 + 1.5 mm CA

NI

Y

V

1

5.2

350

772

A240-304H + 1.5 mm CA (Each Side)

A516 Gr70 + 1.5 mm CA

NI

N

V

1

5.2

560

525

A387 Gr22 Cl2 / A182 F22

A516 Gr70 + 1.5 mm CA

NI

Y

V

1

Refractory Lined 640.0 (Because of the application of refractory lining, the design temperature for shell is 350 degC as specified in AXENS's data sheet and mechanica Weight is shipping weigh Refractory Lined 475.0 (Because of the application of refractory lining, the design temperature for shell is 350 degC as specified in AXENS's data sheet and mechanica (The design temperature for internals is 560 degC 34.0 as specified in AXENS's data sheet and mechanical flow diagram.)

15

0500 - COLUMNS

0

T-1501

MAIN FRACTIONATOR

0

T-1502

HEAVY NAPHTHA STRIPPER

0

T-1503

LCO STRIPPER

0

T-1504

HCO STRIPPER

0

T-1551

PRIMARY ABSORBER

0

T-1552

RFCC STRIPPER

0

T-1553

SECONDARY ABSORBER

0

T-1554

DEBUTANIZER

0

T-1555

FUEL GAS ABSORBER

_ _ _ __ RA| D __| N I ||___ 0

T-1556

LPG AMINE ABSORBER

0

TR-T-1501-01

TRAY OF MAIN FRACTIONATOR

067 R--22000 AV NO 0176-M EL 1 - ANG - rev. 2

8474L-015- MAIN MR-0510- FRACTIONA 001 TOR

8474L-015MR-0510003 8474L-015MR-0510003 8474L-015MR-0510002

CARBON STEEL COLUMNS CARBON STEEL COLUMNS ALLOY & HIC COLUMNS


ALLOY & HIC COLUMNS ALLOY & HIC COLUMNS ALLOY & HIC COLUMNS CARBON STEEL COLUMNS ALLOY & HIC COLUMNS ALLOY & HIC COLUMNS

8474L-015- TRAYS & MR-0580- INTERNAL 001 PACKINGS

0510

A

A

0510

B

B

0510

B

B

0510

B

B

0510

B

B

0510

B

B

0510

B

B

0510

B

B

0510

B

B

0510

B

B

0580

B

B

DOOSAN MECATEC CO.,LTD.

8474L015-PID0021-309

KNM PROCESS SYSTEMS KNM PROCESS SYSTEMS DOOSAN MECATEC CO.,LTD.

8474L015-PID0021-317 8474L015-PID0021-318 8474L015-PID0021-316

DOOSAN MECATEC CO.,LTD. DOOSAN MECATEC CO.,LTD. DOOSAN MECATEC CO.,LTD. KNM PROCESS SYSTEM DOOSAN MECATEC CO.,LTD. DOOSAN MECATEC CO.,LTD.

8474L015-PID0021-405 8474L015-PID0021-405 8474L015-PID0021-407 8474L015-PID0021-409 8474L015-PID0021-408 8474L015-PID0021-411

KOCH GLITCH

8474L015-PID0021-309

545 / 340 / 520 / 315 / 250 / 200 215 / 150

15

V

7.400

-

55.3

3.8

15

V

1.600

-

9.0

3.8

242

217

15

V

1.900

-

9.05

3.8

256

231

15

V

0.950

-

8.400

3.8/-0.25

370

336

15

V

2.400

-

23.100

17.7

87

62

15

V

3.700 / 5.000

-

32.360

17.7

161

126

SS304 / 11/13Cr

CS + 3 mm CA

1.25Cr - 0.5Mo + 3 mm Clad : 405 or 410S / CS + 3 mm Clad : H 405 or 410S / CS + 4.5 mm CA / CS HIC Resistant + 6 mm CA

220 / T 100 / 60 / 30

1542 Y

V

1

CS + 3 mm CA

H

T

60

54

Y

V

1

CS + 3 mm CA

CS + 3 mm CA

H

T

60

66

Y

V

1

CS + 3 mm Clad : TP-410S / 5Cr - 0.5Mo + 4.5 mm CA KCS HIC Resistant + 6 mm CA/ 11/13Cr KCS HIC Resistant + 6 mm CA/ 11/13Cr

CS + 3 mm Clad : TP-410S / 5Cr - 0.5Mo + 4.5 mm CA

H

T

90

28

Y

V

1

SA516-60(HIC) + 6mm CA

NI

N

V

1


H

Y

V

1

SA516-60(HIC) + 6 mm CA

NI

Y

V

1

Y

V

1

T

30

474

15

V

1.400

-

17.950

17.7

87

62

KCS HIC Resistant + 6 mm CA

15

V

3.300 / 4.000

-

34.550

14.8

222

185

KCS + 3 mm CA

SA 516 GR. 60N + 3 mm CA

H

15

V

1.300

-

18.100

17.7

89

64

KCS + 6 mm CA


NI

N

V

1

SS304L


NI

Y

V

1

15

15

V

2.700

7.400

-

14.100

28.6

3.8

75

50

545 / 340 / 520 / 315 / 250 / 200 215 / 150

11/13Cr

T

30/ 40

430

685,5

4.000 mm Skirt To be Designed for 1.5 kg/cm2g @ 160 degC + FV (for Steam Out Condition)

To be Designed for 1.5 kg/cm2g @ 160 degC + 31.0 FV (for Steam Out Condition) Empty Weight : 24.7 ton (w/ T-1503) To be Designed for 1.5 kg/cm2g @ 160 degC + 31.0 FV (for Steam Out Condition) Empty Weight : 24.7 ton (w/ T-1502) 7.24

To be Designed for 1.5 kg/cm2g @ 160 degC + FV (for Steam Out Condition)

To be Designed for 1.5 kg/cm2g @ 160 degC + 288.2 FV (for Steam Out Condition) Empty Weight : 290 ton (w/ T-1552) To be Designed for 1.5 kg/cm2g @ 160 degC + 288.2 FV (for Steam Out Condition) Empty Weight : 290 ton (w/ T-1551) 20.4


To be Designed for 1.5 kg/cm2g @ 160 degC + 190.0 FV (for Steam Out Condition) Desgin Temp : -25 degC @ atm To be Designed for 1.5 kg/cm2g @ 160 degC + 47.0 FV (for Steam Out Condition) Empty Weight : 43 ton (w/ D-1557 & D-1559) To be Designed for 1.5 kg/cm2g @ 160 degC + 60.0 FV (for Steam Out Condition) Desgin Temp : -25 degC @ atm

140.0 Valve Tray

Page 5 /19


Project - Unit

Serial N°

8474L 410

EL 001

Revision 0


REV

(1)

TAG

SERVICE

(2)

(3)

0

TR-T-1501-02

PACKING OF MAIN FRACTIONATOR

0

TR-T-1502

TRAY OF HEAVY NAPHTHA STRIPPER

0

TR-T-1503

TRAY OF LCO STRIPPER

0 0

TR-T-1504

TRAY OF HCO STRIPPER

TR-T-1551

TRAY OF PRIMARY ABSORBER

0

TR-T-1552

TRAY OF RFCC STRIPPER

0

TR-T-1553

TRAY OF SECONDARY ABSORBER

0

TR-T-1554

TRAY OF DEBUTANIZER

TR-T-1555

TRAY OF FUEL GAS ABSORBER

0

TR-T-1556

PACKING OF LPG AMINE ABSORBER

0

E-1501A

SECOND FEED PREHEAT SLURRY EXCHANGER

0

E-1501B

SECOND FEED PREHEAT SLURRY EXCHANGER

E-1502A

FEED PREHEAT SLURRY EXCHANGER

0

E-1502B


0

E-1502C


E-1503A


E-1503B


0

E-1503C


0

E-1504A


0

E-1504B


E-1505A


E-1505B


0

E-1506A


0

E-1506B


0

PURCHASING


(4)


(5)

(6)

8474L-015MR-0580001 8474L-015MR-0570001 8474L-015MR-0570001 8474L-015MR-0570001 8474L-015MR-0570001 8474L-015MR-0570001 8474L-015MR-0570001 8474L-015MR-0570001 8474L-015MR-0570001 8474L-015MR-0570001

MAIN FRACTIONA TOR TRAYS & INTERNAL PACKINGS TRAYS & INTERNAL PACKINGS TRAYS & INTERNAL PACKINGS TRAYS & INTERNAL PACKINGS TRAYS & INTERNAL PACKINGS TRAYS & INTERNAL PACKINGS TRAYS & INTERNAL PACKINGS TRAYS & INTERNAL PACKINGS TRAYS & INTERNAL PACKINGS

8474L-015MR-0610001 8474L-015MR-0610001 8474L-015MR-0610001 8474L-015MR-0610001 8474L-015MR-0610001 8474L-015MR-0610001 8474L-015MR-0610001 8474L-015MR-0610001 8474L-015MR-0610001 8474L-015MR-0610001 8474L-015MR-0610001 8474L-015MR-0610001 8474L-015MR-0610002

ALLOY SHELL & TUBE HEAT ALLOY SHELL & TUBE HEAT ALLOY SHELL & TUBE HEAT ALLOY SHELL & TUBE HEAT ALLOY SHELL & TUBE HEAT ALLOY SHELL & TUBE HEAT ALLOY SHELL & TUBE HEAT ALLOY SHELL & TUBE HEAT ALLOY SHELL & TUBE HEAT ALLOY SHELL & TUBE HEAT ALLOY SHELL & TUBE HEAT ALLOY SHELL & TUBE HEAT CARBON STEEL SHELL & TUBE HEAT CARBON STEEL SHELL & TUBE HEAT CARBON STEEL SHELL & TUBE HEAT CARBON STEEL SHELL & TUBE HEAT

(7)

LOCALISATION

Criticality Factors

VENDOR NAME

F

S

(8)

(9)

(10)

0580

B

B

KOCH GLITCH

0570

B

B

KOCH GLITCH

0570

B

B

KOCH GLITCH

B

KOCH GLITCH

B

KOCH GLITCH

0570 0570

B B

0570

B

B

KOCH GLITCH

0570

B

B

KOCH GLITCH

B

KOCH GLITCH

B

KOCH GLITCH KOCH GLITCH

0570 0570

B B

0570

B

B

0610

B

B

0610

B

B

Category (PED)

(11)

Module (PED)

(12)

PID #

(13)

8474L015-PID0021-309 8474L015-PID0021-317 8474L015-PID0021-318 8474L015-PID0021-316 8474L015-PID0021-405 8474L015-PID0021-405 8474L015-PID0021-407 8474L015-PID0021-409 8474L015-PID0021-408 8474L015-PID0021-411

S Y S T E M

(14)

G E O G R .

D E S I G N

U N I T

A R E A

(15)

(16)

DESIGN PARAMETERS

D R I V E R

P O W E R / D U T Y

P O S I T I O N

(kW)

(17)

(18)


OVERALL DIMENSIONS

(19)

(m)

(m)

(m)

(kg/cm² g)

(° C)

(° C)

I N T E R N A L

(20)

(21)

(22)

(23)

(24)

(25)

(26)

DIAMETER / WIDTH

LENGTH

HEIGHT

Design Pressure


545 / 340 / 520 / 315 / 250 / 200 215 / 150


T Y P E

B Y

(27)

(28)

(29)

T H I C K .

(mm) (30)

M A T E R I A L

(31)


(m²)

(32)


(33)

S Y S T E M

B Y

(34)

(35)

NBER OF DELIVERIES

D E L I V E R D


(36)

O F

(37)

REMARKS W E I G H T

(Tons)

(38)

(39)

15

7.400

3.8

15

1.600

3.8

242

217

11/13Cr

0.6 Valve Tray

15

1.900

3.8

256

231

11/13Cr

1.3 Valve Tray

15

0.950

3.8

370

336

11/13Cr

0.5 Valve Tray

15

2.400

17.7

87

62

11/13Cr

5.7 Valve Tray

15

3.700

17.7

161

126

11/13Cr

17.5 Valve Tray

15

1.400

17.7

87

62

11/13Cr

1.2 Valve Tray

15

3.300 / 4.000

14.8

222

185

11/13Cr

19.5 Valve Tray

15

1.300

17.7

89

64

SS304L

1.1 Valve Tray

15

2.700

28.6

75

50

SS304L

11/13Cr / SS304

60.0 Structured Packing

15.0 Pall Ring

0600 - HEAT EXCHANGERS

0

0 0

0 0

_ _ _ __ RA| D __| N I ||___

8474L-015MR-0610002

0

E-1507A

SLURRY CLARIFIED OIL COOLER

8474L-015MR-0610002

0

E-1507B


8474L-015MR-0610002

067 R--22000 AV NO 0176-M EL 1 - ANG - rev. 2

0610

B

B

0610

B

B

0610

B

B

0610 0610

B B

B B

0610

B

B

0610

B

B

0610

B

B

0610 0610

B B

B B

DOOSAN MECATEC CO.,LTD. DOOSAN MECATEC CO.,LTD. DOOSAN MECATEC CO.,LTD. DOOSAN MECATEC CO.,LTD. DOOSAN MECATEC CO.,LTD. DOOSAN MECATEC CO.,LTD. DOOSAN MECATEC CO.,LTD. DOOSAN MECATEC CO.,LTD. DOOSAN MECATEC CO.,LTD. DOOSAN MECATEC CO.,LTD. DOOSAN MECATEC CO.,LTD. DOOSAN MECATEC CO.,LTD. JMC CORPORATI ON

8474L015-PID0021-304 8474L015-PID0021-304 8474L015-PID0021-303 8474L015-PID0021-303 8474L015-PID0021-303 8474L015-PID0021-312 8474L015-PID0021-312 8474L015-PID0021-313 8474L015-PID0021-314 8474L015-PID0021-315 8474L015-PID0021-314 8474L015-PID0021-315 8474L015-PID0021-322

15

3,865 H

1.150

6.900

32.0 + FV

315 266.3/290

410S + 3 mm CA

1.25Cr - 0.5Mo + 3 mm CA

H

T

80/ 100

35

Y

V

1

15

3,865 H

1.150

6.900

32.0 + FV

315 266.3/290

410S + 3 mm CA

1.25Cr - 0.5Mo + 3 mm CA

H

T

80/ 100

35

Y

V

1

410S + 3 mm CA

1.25Cr - 0.5Mo + 3 mm CA

H

80/ T 100

36

Y

V

1

H

80/ T 100

36

Y

V

1

H

T

80/ 100

36

Y

V

1

H

80/ T 100

61

Y

V

1

H

80/ T 100

61

Y

V

1

15

(*)

H

1.200

6.890

32.0 + FV

315 205.0/269

15

(*)

H

1.200

6.890

32.0 + FV

315 205.0/269

410S + 3 mm CA

1.25Cr - 0.5Mo + 3 mm CA

15

(*)

H

1.200

6.890

32.0 + FV

315 205.0/269

410S + 3 mm CA

1.25Cr - 0.5Mo + 3 mm CA

51.0 + FV

120.6/257. 290 7

51.0 + FV

120.6/257. 290 7

15 15

9,413 H 9,413 H

1.900 1.900

7.580 7.580

410S 410S

CS + 3 mm CA CS + 3 mm CA

Type : AES 26.0 Tubesheet, Channel, Cover : CS + 410S 3 mm Clad Type : AES 26.0 Tubesheet, Channel, Cover : CS + 410S 3 mm Clad Type : AES 28.7 (*) 19,950 kW for E-1502 A, E-1502 B and E1502 C Type : AES 28.7 (*) 19,950 kW for E-1502 A, E-1502 B and E1502 C Type : AES 28.7 (*) 19,950 kW for E-1502 A, E-1502 B and E1502 C Type : AKT 50.2 Tubesheet, Channel, Cover : CS + 410S 3 mm Clad Type : AKT 50.2 Tubesheet, Channel, Cover : CS + 410S 3 mm Clad Type : AKT 50.2 Tubesheet, Channel, Cover : CS + 410S 3 mm Clad Type : AKT 39.5 Tubesheet, Channel, Cover : CS + 410S 3 mm Clad Type : AKT 39.5 Tubesheet, Channel, Cover : CS + 410S 3 mm Clad

15

9,413 H

1.900

7.580

51.0 + FV

120.6/257. 290 7

410S

CS + 3 mm CA

H

80/ T 100

61

Y

V

1

15

6,790 H

1.700

7.560

51.0 + FV

290

137.6/257. 7

410S + 3 mm CA

CS + 3 mm CA

H

T

80/ 100

54

Y

V

1

15

6,790 H

1.700

7.560

51.0 + FV

290

137.6/257. 7

410S + 3 mm CA

CS + 3 mm CA

H

T

80/ 100

54

Y

V

1

17.8 + FV

112.0/200. 320 9

1.25Cr - 0.5Mo + 3 mm CA

H

40/ T 80

45

Y

V

1

23.9 Type : AKT

17.8 + FV

112.0/200. 320 9

1.25Cr - 0.5Mo + 3 mm CA

H

40/ T 80

45

Y

V

1

23.9 Type : AKT

CS + 3 mm CA

CS + 3 mm CA

H

40/ T 60

33

Y

V

1

8.8 Type : AKT

112.0/155. 6

CS + 3 mm CA

CS + 3 mm CA

H

T

40/ 60

33

Y

V

1

8.8 Type : AKT

15 15

5,355 H 5,355 H

1.700 1.700

6.370 6.370

CS + 3 mm CA CS + 3 mm CA

15

879 H

1.150

7.630

18.9 + FV

112.0/155. 230 6

8474L015-PID0021-322

15

879 H

1.150

7.630

18.9 + FV

230

JMC CORPORATI ON

8474L015-PID0021-323

15

(*)

H

0.950

7.000

18.9

114 65.0/89.0

CS + 3 mm CA

CS + 3 mm CA

PP T

30/ 40

42

Y

V

1

14.5

Type : AES (*) 1,320 kW for E-1507 A and E-1507 B

JMC CORPORATI ON

8474L015-PID0021-323

15

(*)

H

0.950

7.000

18.9

114 65.0/89.0

CS + 3 mm CA

CS + 3 mm CA

PP T

30/ 40

42

N

V

1

14.5

Type : AES (*) 1,320 kW for E-1507 A and E-1507 B

0610

B

B

0610

B

B

JMC CORPORATI ON

0610

B

B

0610

B

B

Page 6 /19


Project - Unit

Serial N°

8474L 410

EL 001

Revision 0


TAG

REV

(1)

(2)

SERVICE

(3)

0

E-1507C


0

E-1507D


E-1508


0

E-1509

HEAVY NAPHTHA STRIPPER REBOILER

0

E-1510


0

E-1511

LCO PUMPAROUND BFW HEATER

0

PURCHASING


(4)

(5)


0

E-1512A

LCO PUMPAROUND FEED PREHEAT EXCHANGER

8474L-015MR-0610002

0

E-1512B


8474L-015MR-0610002


8474L-015MR-0610002


8474L-015MR-0610002


8474L-015MR-0610002

HEAVY NAPHTHA BFW HEATER

8474L-015MR-0610002


8474L-015MR-0610002

0

0

0

0

0

E-1512C

E-1512D

E-1513

E-1516

E-1518

0

E-1520A


8474L-015MR-0610002

0

E-1520B


8474L-015MR-0610002

0

E-1520C


8474L-015MR-0610002

0

E-1520D


8474L-015MR-0610002

0

E-1520E


8474L-015MR-0610002

0

E-1520F


8474L-015MR-0610002

0

E-1520G


8474L-015MR-0610002

_ _ _ __ RA| D __| N I ||___ 0

E-1520H


0

E-1522


0

E-1523

HCO PUMPAROUND MP

0176-

STEAM GENERATOR 7 --2200006 R V A O N M EL 1 - ANG - rev. 2

8474L-015MR-0610002 8474L-015MR-0610002 8474L-015MR-0610001


(6)

CARBON STEEL SHELL & TUBE HEAT CARBON STEEL SHELL & TUBE HEAT ALLOY SHELL & TUBE HEAT ALLOY SHELL & TUBE HEAT ALLOY SHELL & TUBE HEAT CARBON STEEL SHELL & TUBE HEAT CARBON STEEL SHELL & TUBE HEAT CARBON STEEL SHELL & TUBE HEAT CARBON STEEL SHELL & TUBE HEAT CARBON STEEL SHELL & TUBE HEAT CARBON STEEL SHELL & TUBE HEAT CARBON STEEL SHELL & TUBE HEAT CARBON STEEL SHELL & TUBE HEAT CARBON STEEL SHELL & TUBE HEAT CARBON STEEL SHELL & TUBE HEAT CARBON STEEL SHELL & TUBE HEAT CARBON STEEL SHELL & TUBE HEAT CARBON STEEL SHELL & TUBE HEAT CARBON STEEL SHELL & TUBE HEAT CARBON STEEL SHELL & TUBE HEAT CARBON STEEL SHELL & TUBE HEAT CARBON STEEL SHELL & TUBE HEAT ALLOY SHELL & TUBE HEAT

LOCALISATION

Criticality Factors

VENDOR NAME

Category (PED)

Module (PED)

PID #

S Y S T E M

G E O G R .

D E S I G N

U N I T

A R E A

(15)

(16)

DESIGN PARAMETERS

D R I V E R

P O W E R / D U T Y

F

S

(7)

(8)

(9)

(10)

0610

B

B

JMC CORPORATI ON

8474L015-PID0021-323

0610

B

B

JMC CORPORATI ON DOOSAN MECATEC CO.,LTD. DOOSAN MECATEC CO.,LTD. DOOSAN MECATEC CO.,LTD. JMC CORPORATI ON


15

(*)

0610

B

B

0610

B

B

0610

B

B

0610

B

B

(11)

(12)

(13)

(14)

P O S I T I O N

(kW)

E X T E R N A L

T Y P E

B Y

(28)

(29)

(m)

(m)

(m)

(kg/cm² g)

(° C)

(° C)

(20)

(21)

(22)

(23)

(24)

(25)

(26)

(27)

114 65.0/89.0

CS + 3 mm CA

CS + 3 mm CA

PP T

114 65.0/89.0

CS + 3 mm CA

CS + 3 mm CA

PP T

DIAMETER / WIDTH

LENGTH

HEIGHT

Design Pressure


(19)

15

(*)

H

0.950

7.000

18.9

15

(*)

H

0.950

7.000

18.9

9,580 H

INSULATION

I N T E R N A L

(18)

15

(17)


OVERALL DIMENSIONS

1.500

7.540

112.0/200. 9

21.2 + FV

320

210.6/212. 242 5

410S + 3 mm CA

CS + 3 mm CA

T H I C K .

(mm) (30)

M A T E R I A L

(31)


(m²)


NBER OF DELIVERIES

D E L I V E R D


S Y S T E M

B Y

(34)

(35)

(36)

O F

(Tons)

(32)

(33)

30/ 40

42

Y

V

1

14.5

Type : AES (*) 1,320 kW for E-1507 C and E-1507 D

30/ 40

42

N

V

1

14.5

Type : AES (*) 1,320 kW for E-1507 C and E-1507 D

H

T

40/ 100

45

Y

V

1

15

2,000 H

0.750

5.770

11.2 /-0.25

410S + 3 mm CA

CS + 3 mm CA

H

60/ T 100

19

Y

V

1

15

1,884 H

1.200

5.090

9.0 + FV

230

112.0/155. 6

410S + 3 mm CA

CS + 3 mm CA

H

T

40/ 100

25

Y

V

1

15

7,350 H

0.650

5.020

68.7 + FV

256

230.6/174. 2

CS + 3 mm CA

CS + 3 mm CA

H

T

60/ 30

14

Y

V

1

H

0.850

7.010

32.0 + FV

195 114.9/170

CS + 3 mm CA

CS + 3 mm CA

H

T

40/ 60

26

Y

V

1

(37)

REMARKS W E I G H T

(38)

(39)

Type : AKT 19.4 Tubesheet, Channel, Cover : CS + 410S 3 mm Clad Type : AJS 8.5 Tubesheet, Channel, Cover : CS + 410S 3 mm Clad Type : AKT 8.5 Tubesheet, Channel, Cover : CS + 410S 3 mm Clad 8.6 Type : CEU Type : AES (*) 7,375 kW for E-1512 A and E-1512 C Short-term Design Temperature 300 degC due to Hot Feed Circulation Type : AES (*) 7,375 kW for E-1512 B and E-1512 D 13.5 Short-term Design Temperature 300 degC due to Hot Feed Circulation Type : AES (*) 7,375 kW for E-1512 A and E-1512 C 13.5 Short-term Design Temperature 300 degC due to Hot Feed Circulation Type : AES (*) 7,375 kW for E-1512 B and E-1512 D 13.5 Short-term Design Temperature 300 degC due to Hot Feed Circulation

0610

B

B

JMC CORPORATI ON

0610

B

B

JMC CORPORATI ON

8474L015-PID0021-302

15

(*)

H

0.850

7.010

32.0 + FV

195 114.9/170

CS + 3 mm CA

CS + 3 mm CA

H

T

40/ 60

26

N

V

1

B

JMC CORPORATI ON

8474L015-PID0021-302

15

(*)

H

0.850

7.010

32.0 + FV

195 114.9/170

CS + 3 mm CA

CS + 3 mm CA

H

T

40/ 60

26

Y

V

1

B

JMC CORPORATI ON

8474L015-PID0021-302

15

(*)

H

0.850

7.010

32.0 + FV

195 114.9/170

CS + 3 mm CA

CS + 3 mm CA

H

T

40/ 60

26

N

V

1

B

JMC CORPORATI ON

8474L015-PID0021-328

15

5,648 H

1.500

6.480

13.1 + FV

230

112.0/148. 2

CS + 3 mm CA

CS + 3 mm CA

H

T

30/ 60

39

Y

V

1

14.5 Type : AKT

B

JMC CORPORATI ON

8474L015-PID0021-317

15

1,027 H

0.600

3.800

68.7 + FV

241

215.9/157. 0

CS + 3 mm CA

CS + 3 mm CA

H

T

60/ 30

11

Y

V

1

5.8 Type : CEU

B

JMC CORPORATI ON

8474L015-PID0021-328

15

135 H

0.400

7.080

19.1

161 50.0/40.0

CS + 3 mm CA

CS + 3 mm CA

NI

Y

V

1

2.7 Type : AES

8474L015-PID0021-319

15

2,176 H

1.400

6.980

7.1/-0.25

105

60/42

CS HIC Resistant + 3 mm CA


NI

Y

V

1

Type : AJS 29.4 Tubesheet : HIC Resistant Carbon Steel Channel and Cover : Carbon Steel

0610

0610

0610

0610

0610

B

B

B

B

B

13.5

0610

B

B

JMC CORPORATI ON

0610

B

B

JMC CORPORATI ON

8474L015-PID0021-319

15

2,176 H

1.400

6.980

7.1/-0.25

105

60/42



NI

Y

V

1


0610

B

B

JMC CORPORATI ON

8474L015-PID0021-319

15

2,176 H

1.400

6.980

7.1/-0.25

105

60/42



NI

Y

V

1


0610

B

B

JMC CORPORATI ON

8474L015-PID0021-319

15

2,176 H

1.400

6.980

7.1/-0.25

105

60/42



NI

Y

V

1


0610

B

B

JMC CORPORATI ON

8474L015-PID0021-319

15

2,176 H

1.400

6.980

7.1 (-0.25) / 9.2

105 / 70



NI

Y

V

1


0610

B

B

JMC CORPORATI ON

8474L015-PID0021-319

15

2,176 H

1.400

6.980

7.1 (-0.25) / 9.2

105 / 70



NI

Y

V

1


0610

B

B

JMC CORPORATI ON

8474L015-PID0021-319

15

2,176 H

1.400

6.980

7.1 (-0.25) / 9.2

105 / 70



NI

Y

V

1


0610

B

B

JMC CORPORATI ON

8474L015-PID0021-319

15

2,176 H

1.400

6.980

7.1 (-0.25) / 9.2

105 / 70



NI

Y

V

1


0610

B

B

1.050

6.940

32.0 + FV

210

118.8/159. 3

CS + 3 mm CA

CS + 3 mm CA

H

T

40/ 60

33

Y

V

1

B

B

8474L015-PID0021-302 8474L015-PID0021-308

H

0610

JMC CORPORATI ON DOOSAN MECATEC CO.,LTD.

4,830 H

1.250

5.110

17.8 + FV

320

112.0/200. 9

410S + 3 mm CA

CS + 3 mm CA

H

T

40/ 100

27

Y

V

1

15

15

#####

Type : AES 19.6 Short-term Design Temperature 300 degC due to Hot Feed Circulation Type : AKT 9.8 Tubesheet, Channel, Cover : CS + 410S 3 mm Clad

Page 7 /19


Project - Unit

Serial N°

8474L 410

EL 001

Revision 0


REV

TAG

(1)

SERVICE

(2)

(3)

0

E-1524


0

E-1525

ECONOMIZER

0

E-1531

SURFACE CONDENSER

0

E-1532

BLOWDOWN COOLER

D

E-1533

BLOWDOWN COOLER

D

E-1534

BFW FEED WATER

0

E-1552A


0

E-1552B


0

E-1554A

STRIPPER CONDENSER

0

E-1554B

STRIPPER CONDENSER

0

E-1554C

STRIPPER CONDENSER

0

E-1554D

STRIPPER CONDENSER

0

E-1555

STRIPPER FEED PREHEATER

0

E-1556

STRIPPER FIRST REBOILER

0

E-1557

STRIPPER SECOND REBOILER

0

E-1559

GASOLINE COOLER

0

E-1560A

DEBUTANIZER REBOILER

0

E-1560B

DEBUTANIZER REBOILER

0

E-1561A


0

E-1561B


0

E-1562

LPG COOLER


PURCHASING


(4)

(5)


(6)

CARBON 8474L-015STEEL MR-0610SHELL & 002 TUBE HEAT 8474L-015COB/WHB H-1503 MR-0160PACKAGE 001 8474L-015AIR C-1501 MR-1040BLOWER 001 CARBON 8474L-015STEEL MR-0610SHELL & 002 TUBE HEAT 8474L-015COB/WHB H-1503 MR-0160PACKAGE 001 H-1503

8474L-015COB/WHB MR-0160PACKAGE 001 CARBON 8474L-015STEEL MR-0610SHELL & 002 TUBE HEAT CARBON 8474L-015STEEL MR-0610SHELL & 002 TUBE HEAT CARBON 8474L-015- STEEL MR-0610- SHELL & 002 TUBE HEAT EXCHANGE CARBON 8474L-015- STEEL MR-0610- SHELL & 002 TUBE HEAT EXCHANGE CARBON 8474L-015- STEEL MR-0610- SHELL & 002 TUBE HEAT EXCHANGE CARBON 8474L-015- STEEL MR-0610- SHELL & 002 TUBE HEAT EXCHANGE CARBON 8474L-015STEEL MR-0610SHELL & 002 TUBE HEAT CARBON 8474L-015STEEL MR-0610SHELL & 002 TUBE HEAT CARBON 8474L-015STEEL MR-0610SHELL & 002 TUBE HEAT CARBON 8474L-015STEEL MR-0610SHELL & 002 TUBE HEAT ALLOY 8474L-015SHELL & MR-0610TUBE HEAT 001 EXCHANGE ALLOY 8474L-015SHELL & MR-0610TUBE HEAT 001 EXCHANGE CARBON 8474L-015STEEL MR-0610SHELL & 002 TUBE HEAT CARBON 8474L-015STEEL MR-0610SHELL & 002 TUBE HEAT CARBON 8474L-015STEEL MR-0610SHELL & 002 TUBE HEAT

LOCALISATION

Criticality Factors

VENDOR NAME

F

S

(7)

(8)

(9)

0610

B

0160

B

1040

B

(10)

JMC CORPORATI ON FOSTER WHEELER B ENERGY LIMITED MAN TURBO B AG B

JMC CORPORATI ON FOSTER WHEELER ENERGY LIMITED FOSTER WHEELER ENERGY LIMITED JMC CORPORATI ON

Category (PED)

(11)

Module (PED)

(12)

PID #

(13)

S Y S T E M

D E S I G N

U N I T

A R E A

(15)

(16)

DESIGN PARAMETERS

D R I V E R

P O W E R / D U T Y

P O S I T I O N

(kW)


T Y P E

B Y

T H I C K .

(m)

(m)

(m)

(kg/cm² g)

(° C)

(° C)

I N T E R N A L

(20)

(21)

(22)

(23)

(24)

(25)

(26)

(27)

(28)

(29)

(30)

H

T

60/ 120

DIAMETER / WIDTH

LENGTH

HEIGHT

Design Pressure


(19)

15

#####

H

0.950

6.770

15

#####

V

3.720

10.700

15

56 H

3.000

9.000

15

224 H

0.254

3.450

8474L015-PID0021-203

15

H

8474L015-PID0021-203

15

H

8474L015-PID0021-403

15

1,181 H

1.300

6.990

7.2

90

50/42

1,181 H

1.300

6.990

7.2

90

50/42

8474L015-PID0021-205 8474L015-PID0021-132 8474L015-PID0021-452

(17)


OVERALL DIMENSIONS

(18)

8474L015-PID0021-302

(14)

G E O G R .

8.16

4.000

37.2 + FV

250

159.3/205. 0

CS + 3 mm CA

CS + 3 mm CA

0.2

400

350

SA179 + 3 mm CA

CS + 3 mm CA

0.49/FV

110

60

Ti

CS

7.1

125

100/50

CS + 3 mm CA

CS + 3 mm CA

3.0

135

0610

B

B

0160

B

B

0160

B

B

0610

B

B

0610

B

B

JMC CORPORATI ON

8474L015-PID0021-403

15

0610

B

B

JMC CORPORATI ON

8474L015-PID0021-404

15

(*)

H

1.050

5.790

18.0

90

57.5/40

0610

B

B

JMC CORPORATI ON

8474L015-PID0021-404

15

(*)

H

1.050

5.790

18.0

90

57.5/40

0610

B

B

JMC CORPORATI ON

8474L015-PID0021-404

15

(*)

H

1.050

5.790

18.0

90

57.5/40

0610

B

B

JMC CORPORATI ON

8474L015-PID0021-404

15

(*)

H

1.050

5.790

18.0

90

57.5/40

0610

B

B

JMC CORPORATI ON

8474L015-PID0021-405

15

2,770 H

0.650

4.630

20.5

90

35/50

0610

B

B

JMC CORPORATI ON

8474L015-PID0021-405

15

6,932 H

1.200

4.570

18.3

161

0610

B

B

JMC CORPORATI ON

8474L015-PID0021-405

15

8,816 H

1.200

4.570

18.3

0610

B

B

JMC CORPORATI ON

8474L015-PID0021-406

15

1,107 H

0.800

7.070

0610

B

B


8474L015-PID0021-409

15

#####

H

1.100

0610

B

B


8474L015-PID0021-409

15

#####

H

0610

B

B

JMC CORPORATI ON

8474L015-PID0021-410

15

0610

B

B

JMC CORPORATI ON

8474L015-PID0021-410

0610

B

B

JMC CORPORATI ON

8474L015-PID0021-411

(mm)

M A T E R I A L

(31)


(m²)


(32)

(33)

49

Y

NBER OF DELIVERIES

D E L I V E R D


S Y S T E M

B Y

(34)

(35)

(36)

V

1

O F

(37)

REMARKS W E I G H T

(Tons)

(38)

(39)

Type : AES 21.6 Short-term Design Temperature 300 degC due to Hot Feed Circulation 121.0 Refractory Lined

28.3 Tubesheet : CS + Ti Clad

PP T

20/ -

3.8

Y

V

1

0.9 Type : AES

LATER

LATER Type : AES Tube : HIC Resistant CS Tubesheet : HIC Resistant CS, 6 mm CA on Shell Side Type : AES Tube : HIC Resistant CS Tubesheet : HIC Resistant CS, 6 mm CA on Shell Side Type : AES (*) 2,995 kW for E-1554 A and E-1554 B Tube : HIC Resistant CS Tubesheet : HIC Resistant CS, 6 mm CA on Shell Side Type : AES (*) 2,995 kW for E-1554 A and E-1554 B Tube : HIC Resistant CS Tubesheet : HIC Resistant CS, 6 mm CA on Shell Side Type : AES (*) 2,995 kW for E-1554 C and E-1554 D Tube : HIC Resistant CS Tubesheet : HIC Resistant CS, 6 mm CA on Shell Side Type : AES (*) 2,995 kW for E-1554 C and E-1554 D Tube : HIC Resistant CS Tubesheet : HIC Resistant CS, 6 mm CA on Shell Side Type : AES Tube & Tubesheet : HIC Resistant CS, 3 mm CA Channel & Cover : CS, 3 mm CA Hot Insulation on Tube Side Only (40 mm THK)

CS HIC Resistant


NI

Y

V

1

22.5

CS HIC Resistant


NI

Y

V

1

22.5

CS HIC Resistant


NI

Y

V

1

16.1

CS HIC Resistant


NI

N

V

1

16.1

CS HIC Resistant


NI

Y

V

1

16.1

CS HIC Resistant


NI

N

V

1

16.1

CS HIC Resistant


H

T

/40

14

Y

V

1

5.3

102.2/110. 6

CS + 3 mm CA

CS + 3 mm CA

H

T

30/ 40

28

Y

V

1

18.3 Type : AJS

161

110.6/121. 5

CS + 3 mm CA

CS + 3 mm CA

H

T

30/ 60

28

N

V

1

18.0 Type : AJS

15.8

134

50/40

CS + 3 mm CA

CS + 3 mm CA

NI

Y

V

1

9.1 Type : AES

5.750

15.8

222

178.4/185. 2

410S

CS + 3 mm CA

H

T

40/ 100

29

Y

V

1

1.100

5.750

15.8

222

178.4/185. 2

410S

CS + 3 mm CA

H

T

40/ 100

29

Y

V

1

9,392 H

1.450

6.980

14.8

93

63.8/47

KCS + 3 mm CA

KCS + 3 mm CA

NI

Y

V

1

15

9,392 H

1.450

6.980

14.8 / 11.4

93

63.8/47

KCS + 3 mm CA

KCS + 3 mm CA

NI

Y

V

1

Type : AES 31.4 Channel & Cover : CS, 3 mm CA Depressurizing Temperature : -25 degC @ atm

15

448 H

0.500

7.060

30.0

74

48/40

KCS + 3 mm CA

KCS + 3 mm CA

NI

Y

V

1

Type : AES 4.6 Channel & Cover : CS, 3 mm CA Depressurizing Temperature : -25 degC @ atm

Type : AJS Tube : 410S Tubesheet : CS + 410S 3 mm Clad on Tube Side Channel & Cover : CS + 410S 3 mm Clad Type : AJS Tube : 410S 16.1 Tubesheet : CS + 410S 3 mm Clad on Tube Side Channel & Cover : CS + 410S 3 mm Clad Type : AES 31.4 Channel & Cover : CS, 3 mm CA Depressurizing Temperature : -25 degC @ atm 16.1

Page 8 /19


Project - Unit

Serial N°

8474L 410

EL 001

Revision 0


REV

TAG

(1)

SERVICE

(2)

(3)

PURCHASING


(4)

(5)

0

E-1563

LEAN OIL / RICH OIL EXCHANGER

8474L-015MR-0610002

0

E-1564

LEAN OIL COOLER

8474L-015MR-0610002

0

E-1565

FUEL GAS COOLER

8474L-015MR-0610002

0

E-1566

LEAN AMINE COOLER

8474L-015MR-0610002

TURBINE CONDENSER

8474L-015C-1551 MR-1010001

0

E-1567

0

E-1514

LCO AIR COOLER

0

E-1517


0

E-1519


0

E-1521


0

E-1530


0

E-1551


0

E-1553

HP CONDENSER


(6)

CARBON STEEL SHELL & TUBE HEAT CARBON STEEL SHELL & TUBE HEAT CARBON STEEL SHELL & TUBE HEAT CARBON STEEL SHELL & TUBE HEAT WET GAS COMPRESS OR

LOCALISATION

Criticality Factors

VENDOR NAME

Category (PED)

Module (PED)

PID #

S Y S T E M

G E O G R .

D E S I G N

U N I T

A R E A

(15)

(16)

DESIGN PARAMETERS

D R I V E R

P O W E R / D U T Y

P O S I T I O N

(m)

(kg/cm² g)

(° C)

(° C)

(21)

(22)

(23)

(24)

(25)

(26)

(27)

(28)

(29)

(30)

133 57.3/106.9



H

T

136 109.9/40

CS + 3 mm CA

CS + 3 mm CA

PP T

50/40



80

55/40

CS + 3 mm CA

121

60

Ti

S (10)

0610

B

B

JMC CORPORATI ON

8474L015-PID0021-407

15

1,141 H

0.500

5.860

22.7

0610

B

B

JMC CORPORATI ON

8474L015-PID0021-407

15

1,363 H

0.700

7.050

29.5

0610

B

B

JMC CORPORATI ON

8474L015-PID0021-408

15

112 H

0.550

3.420

17.7

75

0610

B

B

JMC CORPORATI ON ELLIOTT EBARA TURBOMAC HINERY

8474L015-PID0021-411

15

498 H

0.500

7.070

36.5

8474L015-PID0021-402

15

H

1.320

6.500

2.4

FV+1.05

1010

B

B

AIR COOLERS

0710

B

B

AIR COOLERS

0710

B

B

AIR COOLERS

0710

B

B

AIR COOLERS

0710

B

B

AIR COOLERS

0710

B

B

(kW)

(17)

(18)

#####

(19)

B Y

(m)

HEIGHT


(9)

(14)

T Y P E

T H I C K .

(20)

LENGTH

Design Pressure

F

(13)

E X T E R N A L

(m)

DIAMETER / WIDTH

(8)

(12)

INSULATION

I N T E R N A L

(7)

(11)


OVERALL DIMENSIONS

(mm)

M A T E R I A L

(31)


(m²)


NBER OF DELIVERIES

D E L I V E R D


S Y S T E M

B Y

(34)

(35)

(36)

O F

(37)

REMARKS W E I G H T

(Tons)

(32)

(33)

30/ 40

12

Y

V

1

3.8

20/ -

20

Y

V

1

8.1 Type : AES

NI

Y

V

1

3.2

CS + 3 mm CA

NI

Y

V

1

4.7 Type : AES

CS

NI

N

V

1

(38)

(39)

Type : AES Channel & Cover : CS, 3 mm CA

Type : AES Channel & Cover : CS, 3 mm CA

12.970 Tubesheet : CS + Ti Clad

0700 - AIR COOLERS

0

E-1558

GASOLINE AIR COOLER

0

D-1505

FRESH CATALYST HOPPPER

8474L-015MR-0710001 8474L-015MR-0710001 8474L-015MR-0710001 8474L-015MR-0710001 8474L-015MR-0710001 8474L-015MR-0710001 8474L-015MR-0710001 8474L-015MR-0710001

AIR COOLERS

0710

B

B

AIR COOLERS

0710

B

B

AIR COOLERS

0710

B

B

LARGE DRUMS

0810

C

C

S&T CORPORATI ON S&T CORPORATI ON S&T CORPORATI ON S&T CORPORATI ON S&T CORPORATI ON S&T CORPORATI ON S&T CORPORATI ON S&T CORPORATI ON

8474L015-PID0021-328 8474L015-PID0021-328 8474L015-PID0021-319 8474L015-PID0021-305 8474L015-PID0021-331 8474L015-PID0021-403 8474L015-PID0021-404 8474L015-PID0021-406

DOOSAN MECATEC CO.,LTD. DOOSAN MECATEC CO.,LTD. DOOSAN MECATEC CO.,LTD. SECO BONO EXACTA S.p.A DAECHANG HRSG CORPORATI ON FOSTER


15

M

8,662 H

12.900

9.050

4.45

17.0

220

KCS + 3 mm CA

2

41.7


15

M

1,689 H

12.900

2.930

4.45

20.0

241

KCS + 3 mm CA

1

12.8


15

M #####

H

12.900

36.000

4.45

3.5 (-0.25)

125


16

307.9


15

M #####

H

12.900

11.460

4.45

16.5

187

KCS + 3 mm CA

2

42.5


15

M

1,318 H

12.900

2.620

4.45

14.0

114

KCS + 3 mm CA

1

10.1

4

84.8


15

M

9,023 H

10.900

24.000

4.4

7.5

115


15

M

7,448 H

10.900

17.500

4.4

18.4

125


3

62.9


15

M

9,931 H

12.900

11.100

4.45

15.8

160

KCS + 3 mm CA

2

41.4


V

6.800

5.0 + FV

425

0800 - DRUMS

0

D-1506

SPENT CATALYST HOPPER

0

D-1507

AUXILIARY CATALYST HOPPER

0

D-1508

METAL PASSIVATOR DRUM

0

D-1509

FUEL GAS DRUM

0

D-1512

STEAM DRUM

0

D-1513

FEED SURGE DRUM

0

D-1514

FRACTIONATOR REFLUX DRUM

0

D-1515

SLURRY DRAW OFF DRUM

D-1516

BACKFLUSH OIL DRAW OFF DRUM

_ _ _ __ RA| D __| N I ||___ 0

0

D-1517

BACKFLUSH OIL DRUM

067 R--22000 AV NO 0176-M EL 1 - ANG - rev. 2

8474L-015MR-0810003 8474L-015MR-0810003 8474L-015MR-0810003 8474L-410X-1509 MR-4046001 8474L-410MR-0810002 H-1503

LARGE DRUMS

0810

C

C

0810

C

C

4046

C

C

0810

C

C

0160

C

C

LARGE DRUMS

0810

C

C

LARGE DRUMS

0810

C

C

MEDIUM DRUMS

0810

C

C

LARGE DRUMS CHEMICAL INJECTION PACKAGES MEDIUM DRUMS

8474L-015COB/WHB MR-0160PACKAGE 001 8474L-015MR-0810003 8474L-015MR-0810003 8474L-410MR-0810002 8474L-410MR-0810002 8474L-410MR-0810002

MEDIUM DRUMS

0810

C

C

MEDIUM DRUMS

0810

C

C

WHEELER ENERGY LIMITED DOOSAN MECATEC CO.,LTD. DOOSAN MECATEC CO.,LTD. DAECHANG HRSG CORPORATI DAECHANG HRSG CORPORATI DAECHANG HRSG CORPORATI


15

32.000

amb / 150

SA516 Gr70 + 3 mm CA


NI

Y

V

1

290.0


NI

Y

V

1

290.0


NI

Y

V

1

290.0

SS304

NI

CS + 3 mm CA

NI

N

V

1

15

V

6.800

32.000

5.0 + FV

425

amb / 400


15

V

6.800

32.000

5.0 + FV

425

amb / 400


15

V

atm

65

amb

15

V

0.600

8.7

82

57

15

H

2.136

17.060

15

H

5.000

15.000

15

H

5.000

13.500

15

V

1.400

2.005

CS + 3 mm CA

A516 Gr70 + 3 mm CA

3.5+FV 315/160

4.350

To be Designed for 1.5 kg/cm2g @ 160 degC + 1.0 FV (for Steam Out Condition) Wire Mesh Internal 51.0

115

CS + 3 mm CA

CS + 3 mm CA

H

3.5 (-0.25)

90

42

CS HIC Resistant


NI

3.5

245

220

CS + 3 mm CA

CS + 3 mm CA

H

T

T

30

60

315

26

With Boot Ø600 L1350 mm To be Designed for 1.5 kg/cm2g @ 160 degC + FV (for Steam Out Condition) Boot to be Traced With Boot Ø2500 L2350 mm 84.0 To be Designed for 1.5 kg/cm2g @ 160 degC + FV (for Steam Out Condition)

N

V

1

120.0

N

V

1

Y

V

1

5.5


15

V

1.400

4.050

3.5

195

170

CS + 3 mm CA

CS + 3 mm CA

H

T

40

24

Y

V

1

To be Designed for 1.5 kg/cm2g @ 160 degC + 5.3 FV (for Steam Out Condition)

15

V

1.400

4.050

3.5

195

170

CS + 3 mm CA

CS + 3 mm CA

H

T

40

24

Y

V

1

5.6


Page 9 /19


Project - Unit

Serial N°

8474L 410

EL 001

Revision 0


REV

TAG

(1)

(2)

0

D-1518

0

D-1519

0

D-1522

0

D-1523

0

SERVICE

D-1524

0

D-1525

0

D-1526

0

D-1527

(3)

PURCHASING


(4)

8474L-410HCO FLUSHING OIL DRUM MR-0810002 8474L-410LCO FLUSHING OIL DRUM MR-0810002 8474L-410LIGHT SLOPS DRUM MR-0810002 8474L-410HEAVY SLOPS DRUM MR-0810002 8474L-410TEMPERED WATER SURGE MR-0810DRUM 002 8474L-410AIR HEATER FUEL GAS KO MR-0810DRUM 002 8474L-410CO BOILER FUEL GAS KO MR-0810DRUM 002 8474L-410LP BLOWDOWN DRUM MR-0810002 8474L-410ATMOSPHERIC BLOWDOWN MR-0810DRUM 002 8474L-015CONTINUOUS BLOWDOWN H-1503 MR-0160DRUM 001

0

D-1528

0

D-1531

0

D-1532

INTERMITTENT BLOWDOWN H-1503 DRUM

0

D-1551

FIRST STAGE KNOCK OUT DRUM

0

D-1552

INTERSTAGE KO DRUM

0

D-1553

HP SEPARATOR DRUM

0

D-1554

DEBUTANIZER REFLUX DRUM

0

D-1555

(5)

LPG AMINE COALESCER

8474L-015MR-0160001 8474L-015MR-0810001 8474L-015MR-0810001 8474L-015MR-0810003 8474L-015MR-0810001


(6)

(7)

LOCALISATION

Criticality Factors

VENDOR NAME

F

S

(8)

(9)

MEDIUM DRUMS

0810

C

C

MEDIUM DRUMS

0810

C

C

MEDIUM DRUMS

0810

C

C

MEDIUM DRUMS

0810

C

C

MEDIUM DRUMS

0810

C

C

MEDIUM DRUMS

0810

C

C

MEDIUM DRUMS

0810

C

C

MEDIUM DRUMS

0810

C

C

MEDIUM DRUMS

0810

C

C

COB/WHB PACKAGE

0160

C

C

COB/WHB PACKAGE

0160

C

C

LARGE DRUMS

0810

C

C

LARGE DRUMS

0810

C

C

LARGE DRUMS

0810

C

C

LARGE DRUMS

0810

C

C

8474L-015MR-0840COALESCER 301

0840

C

C

(10)

DAECHANG HRSG CORPORATI DAECHANG HRSG CORPORATI DAECHANG HRSG CORPORATI DAECHANG HRSG CORPORATI ON DAECHANG HRSG CORPORATI DAECHANG HRSG CORPORATI DAECHANG HRSG CORPORATI DAECHANG HRSG CORPORATI DAECHANG HRSG CORPORATI FOSTER WHEELER ENERGY LIMITED FOSTER WHEELER ENERGY LIMITED TEPAT TEKNIK SDN BHD TEPAT TEKNIK SDN BHD DOOSAN MECATEC CO.,LTD. TEPAT TEKNIK SDN BHD

PEERLESS EUROPE LIMITED

Category (PED)

(11)

Module (PED)

(12)

PID #

(13)

8474L015-PID0021-326 8474L015-PID0021-327 8474L015-PID0021-329 8474L015-PID0021-330 8474L015-PID0021-331 8474L015-PID0021-206 8474L015-PID0021-206 8474L015-PID0021-452 8474L015-PID0021-452 8474L015-PID0021-203 8474L015-PID0021-203 8474L015-PID0021-401 8474L015-PID0021-403 8474L015-PID0021-404 8474L015-PID0021-410

8474L015-PID0021-411

S Y S T E M

(14)

G E O G R .

D E S I G N

U N I T

A R E A

(15)

(16)

DESIGN PARAMETERS

D R I V E R

P O W E R / D U T Y

P O S I T I O N

(kW)

(17)

(18)

(19)

(m)

(kg/cm² g)

(° C)

(° C)

(21)

(22)

(23)

(24)

(25)

(26)

(27)

(28)

(29)

(30)

T

40

51

Y

V

1

(38)

8.9 6.4

(39)


1.500

5.250

3.5

157

50

CS + 3 mm CA

CS + 3 mm CA

NI

Y

V

1

15

H

2.200

6.500

3.5

75

50

CS + 3 mm CA

CS + 3 mm CA

NI

N

V

1

15

H

2.200

6.500

3.5

95

70

CS + 3 mm CA

CS + 3 mm CA

H

T

30

61

N

V

1

15

V

0.900

2.500

6.7

112

65

CS + 3 mm CA

CS + 3 mm CA

PP T

30

9.5

N

V

1

15

V

0.650

2.119

7.7

146

40

CS + 3 mm CA

CS + 3 mm CA

H

T

30

5.8

N

V

1

15

V

1.050

2.850

5.7

75

46

CS + 3 mm CA

CS + 3 mm CA

NI

N

V

1

15

V

0.600

2.000

6.3 + FV

185

148

CS + 3 mm CA

CS + 3 mm CA

H

T

30

4.8

N

V

1

0.9

15

V

0.750

2.000

3.5

125

100

CS + 3 mm CA

CS + 3 mm CA

PP T

20

6.2

N

1

1.6

15

V

0.540

2.3

6.3

230

LATER

15

V

1.070

2.5

3.0

175

LATER

15

V

4.400

5.550

3.5 + FV

90

42



15

V

2.800

7.650

7.0 + FV

90

42



NI

Y

V

1

15

H

4.300

13.500

17.7 + FV

90

40



NI

N

V

1

15

H

2.800

8.000

14.4 + FV

94

47

KCS + 3 mm CA

KCS + 3 mm CA

V

1

15

H

0.914

0510

C

C


8474L015-PID0021-408

15

V

1.300

ALLOY & HIC COLUMNS

0510

C

C

15

V

1.300

LARGE DRUMS

0810

C

15

H

2.000

EL 1 - ANG - rev. 2

(Tons)

V

8474L-015- ALLOY & MR-0510- HIC 002 COLUMNS

067 R--22000 AV NO 0176-M

O F

(37)

15

FUEL GAS ABSORBER FEED KO DRUM

0810

(36)

H

D-1557

D-1561

(35)

(33)

CS + 3 mm CA

0

0

(34)

(32)

CS + 3 mm CA

0.508

LARGE DRUMS

B Y

REMARKS W E I G H T

170

H

AMINE CLOSED DRAIN DRUM


200

15

D-1560

(m²)

D E L I V E R D

S Y S T E M

3.5

8474L015-PID0021-407

0

(31)

NBER OF DELIVERIES

7.150

PEERLESS EUROPE LIMITED

_ _ _ __ RA| D __| N I ||___

(mm)


1.800

C

RFCC CLOSED DRAIN VESSEL

HEIGHT



V

C

8474L015-PID0021-408 8474L015-PID0021-451 8474L015-PID0021-453

LENGTH

Design Pressure

M A T E R I A L

15

0840

DOOSAN MECATEC CO.,LTD. TEPAT C TEKNIK SDN BHD TEPAT TEKNIK SDN BHD

B Y

(m)

8474L-015MR-0840COALESCER 301

8474L-015MR-0510002 8474L-015MR-0810001 8474L-015MR-0810001

T Y P E

T H I C K .

(20)

LEAN OIL COALESCER

FUEL GAS ABSORBER OUTLET KO DRUM

E X T E R N A L

(m)

DIAMETER / WIDTH

D-1556

D-1559

INSULATION

I N T E R N A L

0

0


OVERALL DIMENSIONS

15

H

1.500

1.430

30.0

5.690

Y

V

1

To be Designed for 1.5 kg/cm2g @ 160 degC + 39.0 FV (for Steam Out Condition) Wire Mesh Internal To be Designed for 1.5 kg/cm2g @ 160 degC + 26.0 FV (for Steam Out Condition) Wire Mesh Internal With Boot Ø2000 L1950 mm 108.1 To be Designed for 1.5 kg/cm2g @ 160 degC + FV (for Steam Out Condition) With Boot Ø600 L1450 mm To be Designed for 1.5 kg/cm2g @ 160 degC + 22.0 FV (for Steam Out Condition) Boot : KCS HIC Resistant + 6 mm CA

N

40

N

1

3.0

CS + 3 mm CA

NI

N

1

To be Designed for 1.5 kg/cm2g @ 160 degC + 1.4 FV (for Steam Out Condition) Boot : CS HIC Resistant + 6 mm CA

110

40

2.600

17.7

66

40



NI

Y

V

1

2.600

17.4

82

57



NI

N

V

1

3.5

110

85(amb)

N

V

1

CS(HIC) + 6 mm CA

CS(HIC) + 6 mm CA

N

V

1

90

To be Designed for 1.5 kg/cm2g @ 160 degC + 1.1 FV (for Steam Out Condition) Wired Mesh Pad To be Designed for 1.5 kg/cm2g @ 160 degC + 1.7 FV (for Steam Out Condition) Wire Mesh Internal

NI

29.5

3.5 / FV

1.6

(1st Stage) Glass Filled Nylon/ Impregnated Cellulose/ Fibre Glass/ KCS HIC Resistant NI (2nd Stage) + 3 mm CA Aluminum/Teflon Coated SS Mesh/Glass filled Nylon (1st Stage) Glass Filled Nylon/ Impregnated Cellulose/ Fibre Glass/ (2nd Stage) Aluminum/Teflon Coated SS Mesh/Glass filled Nylon

1.250

5.000

65 / -25

NI

To be Designed for 1.5 kg/cm2g @ 160 degC + FV (for Steam Out Condition) With Boot Ø600 L1350 mm 9.2 To be Designed for 1.5 kg/cm2g @ 160 degC + FV (for Steam Out Condition) With Boot Ø600 L1350 mm To be Designed for 1.5 kg/cm2g @ 160 degC + 9.2 FV (for Steam Out Condition) Boot to be Traced

40

CS + 3 mm CA

PP T NI

30

44

To be Designed for 1.5 kg/cm2g @ 160 degC + FV (for Steam Out Condition) Boot : KCS HIC Resistant + 6 mm CA

To be Designed for 1.5 kg/cm2g @ 160 degC + FV (for Steam Out Condition) Wire Mesh Internal Empty Weight : 43 ton (w/ T-1555 & D-1559) To be Designed for 1.5 kg/cm2g @ 160 degC + FV (for Steam Out Condition) 47.0 Wire Mesh Internal Empty Weight : 43 ton (w/ T-1555 & D-1557) To be Designed for 1.5 kg/cm2g @ 160 degC + 7.2 FV (for Steam Out Condition) 47.0

6.6

Page 10 /19


Project - Unit

Serial N°

8474L 410

EL 001

Revision 0


REV

(1)

TAG

(2)

0

CV-1501

0

CV-1502

0

CV-1503

0

CV-1504

0

SL-1501

0

SL-1502

0

SL-1503

0 0

SERVICE

SL-1504 SL-1505

(3)

0830 - SPECIAL FABRICATED ITEMS FIRST REGENERATOR AIR RING ASSISTED CHECK VALVE SECOND REGENERATOR AIR RING ASSISTED CHECK VALVE AIR LIFT ASSISTED CHECK VALVE OTHER BLOWER AIR USERS ASSISTED CHECK VALVE

(4)

(5)

8474L-015MR-1310001 8474L-015MR-1310001 8474L-015MR-1310001 8474L-015MR-1310001

8474L-410MR-0836001 8474L-410SILENCER MR-0836001 8474L-410VENT STEAM SILENCER MR-0836001 8474L-410VENT STEAM SILENCER MR-0836001 8474L-410VENT STEAM SILENCER MR-0836001 8474L-015BOILER RELIEF VALVE H-1503 MR-0160SILENCER 001 8474L-015BOILER START-UP SILENCER H-1503 MR-0160001

D

SL-1506 SL-1507

0

EX-1501

SPENT CATALYST LINE EXPANSION JOINT

0

EX-1502

EXPANSION JOINT BETWEEN REGENERATORS

0840 - FILTERS AND SEPARATORS 0

CY-1501A

DISENGAGER CYCLONE

0

CY-1501B

DISENGAGER CYCLONE

0

CY-1501C

DISENGAGER CYCLONE

0

CY-1501D

DISENGAGER CYCLONE

0

CY-1501E

DISENGAGER CYCLONE

0

CY-1501F

DISENGAGER CYCLONE

0

CY-1502A

FIRST REGENERATOR CYCLONE FIRST STAGE

0

CY-1502B


0

CY-1502C


0

CY-1502D


0

CY-1502E


0

CY-1502F


CY-1503A

FIRST REGENERATOR CYCLONE SECOND STAGE



START-UP VENT SILENCER

D

0

PURCHASING

8474L-015MR-0830003 8474L-015MR-0830003

8474L-015MR-0840001 8474L-015MR-0840001 8474L-015MR-0840001 8474L-015MR-0840001 8474L-015MR-0840001 8474L-015MR-0840001 8474L-015MR-0840001 8474L-015MR-0840001 8474L-015MR-0840001 8474L-015MR-0840001 8474L-015MR-0840001 8474L-015MR-0840001 8474L-015MR-0840001


(6)

SPECIAL CHECK VALVE SPECIAL CHECK VALVE SPECIAL CHECK VALVE SPECIAL CHECK VALVE

SILENCER

LOCALISATION

Criticality Factors

VENDOR NAME

F

S

(7)

(8)

(9)

1310

C

C

1310

C

C

1310

C

C

1310

C

C

0836

C

C

UNIVERSAL SILENCER

(10)

WEIR VALVES & CONTROLS WEIR VALVES & CONTROLS WEIR VALVES & CONTROLS WEIR VALVES & CONTROLS

SILENCER

0836

C

C

UNIVERSAL SILENCER

SILENCER

0836

C

C

UNIVERSAL SILENCER

C

UNIVERSAL SILENCER

SILENCER SILENCER

0836 0836

C C

C

UNIVERSAL SILENCER FOSTER WHEELER ENERGY FOSTER WHEELER ENERGY

COB/WHB PACKAGE

0160

C

C

COB/WHB PACKAGE

0160

C

C

EXPANSION JOINT

0830

C

C

FLEXIDER S.R.L

EXPANSION JOINT

0830

A

A

FLEXIDER S.R.L

CYCLONES

0840

B

A

CYCLONES

0840

B

A

CYCLONES

0840

B

A

CYCLONES

0840

B

A

CYCLONES

0840

B

A

CYCLONES

0840

B

A

CYCLONES

0840

B

A

CYCLONES

0840

B

A

CYCLONES

0840

B

A

CYCLONES

0840

B

A

CYCLONES

0840

B

A

CYCLONES

0840

B

A

CYCLONES

0840

B

A

VAN TONGEREN INTERNATIO VAN TONGEREN INTERNATIO VAN TONGEREN INTERNATIO VAN TONGEREN INTERNATIO VAN TONGEREN INTERNATIO VAN TONGEREN INTERNATIO VAN TONGEREN INTERNATIO VAN TONGEREN INTERNATIO VAN TONGEREN INTERNATIO VAN TONGEREN INTERNATIO VAN TONGEREN INTERNATIO VAN TONGEREN INTERNATIO VAN TONGEREN INTERNATIO

Category (PED)

(11)

Module (PED)

(12)

PID #

(13)



S Y S T E M

(14)

G E O G R .

D E S I G N

U N I T

A R E A

(15)

(16)

DESIGN PARAMETERS

D R I V E R

P O W E R / D U T Y

P O S I T I O N

(kW)

(17)

(18)


OVERALL DIMENSIONS

(19)

(m)

(m)

(m)

(kg/cm² g)

(° C)

(° C)

I N T E R N A L

(20)

(21)

(22)

(23)

(24)

(25)

(26)

DIAMETER / WIDTH

LENGTH

HEIGHT

Design Pressure



T Y P E

B Y

(27)

(28)

(29)

T H I C K .

(mm) (30)

M A T E R I A L

(31)


(m²)

(32)


(33)

S Y S T E M

B Y

(34)

(35)

NBER OF DELIVERIES

D E L I V E R D


(36)

O F

(37)

REMARKS W E I G H T

(Tons)

(38)

(39)

15

1.676

1.626

1.93

5.2

263

238

CS

2.858

15

1.270

1.473

1.778

5.2

263

238

CS

1.724

15

1.067

1.473

1.422

5.2

263

238

CS

0.995

15

0.660

0.813

0.559

5.2

263

238

CS

0.227

6.21

CS

2.360

Old Tag Number : X-1557 Old Tag Number : X-1556

15

V

1.220

15

V

0.305

0.8

CS

0.048

15

V

0.457

1.79

CS

0.217

15

V

0.610

4.839

CS

0.750

15

V

0.457

1.791

CS

0.211

For E-1508 Old Tag Number : X-1555 For E-1503A/B/C, E-1504A/B, E-1505A/B & E1510 Old Tag Number : X-1553 For E-1506A/B, E-1513 & E-1523 Old Tag Number : X-1552

15

LATER

15

LATER

15

1.770

2.900

5.2

560

520

7.4

INCONEL 625 for Bellows (Min. 1.6 mm THK) Refractory Lined

15

1.700

1.400

5.2

350

250

3.7

INCONEL 625 for Bellows (Min. 1.6 mm THK) Refractory Lined

15

1.729

15.35

1.145

560

520

SA516 Gr70 + 3.0 mm CA

11.90

Short-term Design Temperature 650 degC Refractory Lined

15

1.729

15.35

1.145

560

520

SA516 Gr70 + 3.0 mm CA

11.90


15

1.729

15.35

1.145

560

520

SA516 Gr70 + 3.0 mm CA

11.90


15

1.729

15.35

1.145

560

520

SA516 Gr70 + 3.0 mm CA

11.90


11.90


11.90


15

1.729

15.35

1.145

560

520

SA516 Gr70 + 3.0 mm CA

15

1.729

15.35

1.145

560

520

SA516 Gr70 + 3.0 mm CA

15

1.774

17.1

1.14

770

678

SS304H + 0.75 mm CA

12.8


15

1.774

17.1

1.14

770

678

SS304H + 0.75 mm CA

12.8


12.8


15

1.774

17.1

1.14

770

678

SS304H + 0.75 mm CA

15

1.774

17.1

1.14

770

678

SS304H + 0.75 mm CA

12.8


15

1.774

17.1

1.14

770

678

SS304H + 0.75 mm CA

12.8


15

1.774

17.1

1.14

770

678

SS304H + 0.75 mm CA

12.8


678

SS304H + 0.75 mm CA

15

1.495

16.507

1.20

770

8.838


Page 11 /19


Project - Unit

Serial N°

8474L 410

EL 001

Revision 0


REV

(1)

TAG

SERVICE

(2)

(3)

0

CY-1503B


0

CY-1503C


0

CY-1503D


0

CY-1503E


0

CY-1503F

0

CY-1504A

0

CY-1504B

0 0

CY-1504C CY-1504D

0

CY-1504E

0

CY-1504F

0 0

CY-1504G CY-1504H

FIRST REGENERATOR CYCLONE SECOND STAGE SECOND REGENERATOR EXTERNAL CYCLONE FIRST STAGE SECOND REGENERATOR EXTERNAL CYCLONE FIRST STAGE SECOND REGENERATOR EXTERNAL CYCLONE FIRST STAGE SECOND REGENERATOR EXTERNAL CYCLONE FIRST STAGE SECOND REGENERATOR EXTERNAL CYCLONE SECOND STAGE SECOND REGENERATOR EXTERNAL CYCLONE SECOND STAGE SECOND REGENERATOR EXTERNAL CYCLONE SECOND STAGE SECOND REGENERATOR EXTERNAL CYCLONE SECOND STAGE FRESH CATALYST HOPPER CYCLONE

0

CY-1505

0

CY-1506

SPENT CATALYST HOPPER CYCLONE

0

CY-1507

AUXILIARY CATALYST HOPPER CYCLONE

0

F-1502A

HCO FLUSHING OIL FILTER

0

F-1502B

HCO FLUSHING OIL FILTER

0

F-1503A

SLURRY OIL PRE-FILTER

0

F-1503B

SLURRY OIL PRE-FILTER

0

EJ-1501


0

P-1501A

FEED PUMP

0

P-1501B

PURCHASING


(4)

(5)

8474L-015MR-0840001 8474L-015MR-0840001 8474L-015MR-0840001 8474L-015MR-0840001 8474L-015MR-0840001 8474L-015MR-0840001 8474L-015MR-0840001 8474L-015MR-0840001 8474L-015MR-0840001 8474L-015MR-0840001 8474L-015MR-0840001 8474L-015MR-0840001 8474L-015MR-0840001 8474L-015MR-0840001 8474L-015MR-0840001 8474L-015MR-0840001


(6)

(7)

LOCALISATION

Criticality Factors

VENDOR NAME

F

S

(8)

(9)

8474L015-PID0021-326 8474L015-PID0021-326 8474L015-PID0021-323 8474L015-PID0021-323

A

CYCLONES

0840

B

A

CYCLONES

0840

B

A

CYCLONES

0840

B

A

CYCLONES

0840

B

A

CYCLONES

0840

B

A

CYCLONES

0840

B

A

CYCLONES

0840

B

A A

CYCLONES

0840

B

A

CYCLONES

0840

B

A

CYCLONES CYCLONES

0840 0840

B B

A A

CYCLONES

0840

B

A

CYCLONES

0840

B

A

CYCLONES

0840

B

A

FILTERS

0840

C

FILTERS

0840

C

FILTERS

0840

C

FILTERS

0840

C

8474L-410STEAM MR-0852EJECTOR 001

0852

C

CENTRIFUG AL PUMPS

0910

B 410 FLOWSERVE

CENTRIFUG AL PUMPS CHEMICAL INJECTION PACKAGES CHEMICAL INJECTION PACKAGES SLURRY PUMPS

0910

B

8474L-410MR-0840301 8474L-410MR-0840301 8474L-410MR-0840301 8474L-410MR-0840301

(13)

BEA C TECHNOLOG IES SPA BEA C TECHNOLOG IES SPA BEA C TECHNOLOG IES SPA BEA C TECHNOLOG IES SPA

B

B

(12)

PID #

8474L015-PID0021-128 8474L015-PID0021-128 8474L015-PID0021-128 8474L015-PID0021-128 8474L015-PID0021-128 8474L015-PID0021-129 8474L015-PID0021-129 8474L015-PID0021-129 8474L015-PID0021-129 8474L015-PID0021-129 8474L015-PID0021-129 8474L015-PID0021-129 8474L015-PID0021-129 8474L015-PID0021-137 8474L015-PID0021-135 8474L015-PID0021-136

0840

0840

(11)

Module (PED)

VAN TONGEREN INTERNATIO VAN TONGEREN INTERNATIO VAN TONGEREN INTERNATIO VAN TONGEREN INTERNATIO VAN TONGEREN INTERNATIO VAN TONGEREN INTERNATIO VAN TONGEREN INTERNATIO VAN TONGEREN INTERNATIO VAN TONGEREN INTERNATIO VAN TONGEREN INTERNATIO VAN TONGEREN INTERNATIO VAN TONGEREN INTERNATIO VAN TONGEREN INTERNATIO VAN TONGEREN INTERNATIO VAN TONGEREN INTERNATIO VAN TONGEREN INTERNATIO

CYCLONES

CYCLONES

(10)

Category (PED)

S Y S T E M

(14)

G E O G R .

D E S I G N

U N I T

A R E A

(15)

(16)

DESIGN PARAMETERS

D R I V E R

P O W E R / D U T Y

P O S I T I O N

(kW)

(17)


OVERALL DIMENSIONS

(18)

(19)

(m)

(m)

(m)

(kg/cm² g)

(° C)

(° C)

I N T E R N A L

(20)

(21)

(22)

(23)

(24)

(25)

(26)

DIAMETER / WIDTH

LENGTH

HEIGHT

Design Pressure



T Y P E

B Y

(27)

(28)

(29)

T H I C K .

(mm) (30)

M A T E R I A L

(31)


(m²)

(32)


(33)

S Y S T E M

B Y

(34)

(35)

NBER OF DELIVERIES

D E L I V E R D


(36)

O F

(37)

REMARKS W E I G H T

(Tons)

(38)

(39)

15

1.495

16.507

1.20

770

678

SS304H + 0.75 mm CA

8.838


15

1.495

16.507

1.20

770

678

SS304H + 0.75 mm CA

8.838


15

1.495

16.507

1.20

770

678

SS304H + 0.75 mm CA

8.838


8.838


8.838


15

1.495

16.507

1.20

770

678

SS304H + 0.75 mm CA

15

1.495

16.507

1.20

770

678

SS304H + 0.75 mm CA

15

1.929

24.3

5.2

840

772

SA516 Gr70 + 1.5 mm CA

28.9 Refractory Lined

15

1.929

24.3

5.2

840

772

SA516 Gr70 + 1.5 mm CA


772

SA516 Gr70 + 1.5 mm CA


772

SA516 Gr70 + 1.5 mm CA

28.9 Refractory Lined 25.0 Refractory Lined

15

1.929

15

24.3

1.929

24.3

5.2 5.2

840 840

15

1.929

24.3

5.2

840

772

SA516 Gr70 + 1.5 mm CA

15

1.929

24.3

5.2

840

772

SA516 Gr70 + 1.5 mm CA


772

SA516 Gr70 + 1.5 mm CA


772

SA516 Gr70 + 1.5 mm CA


15

1.929

24.3

5.2

840

15

1.929

24.3

5.2

840

15

0.330

4.054

5.0 + FV

425

28

CS + 3mm CA

0.300

Dipleg with Trickle Valve

15

0.530

4.364

5.0 + FV

425

126

CS + 3mm CA

0.950


15

0.330

4.054

5.0 + FV

425

28

CS + 3mm CA

0.300


15

V

0.320

0.620

37.5

200

170

CS + 3 mm CA

50

0.5

N

0.2

15

V

0.320

0.620

37.5

200

170

CS + 3 mm CA

50

0.5

N

0.2

15

V

0.450

1.561

24.5

245

170

CS + 3 mm CA

50

2.5

N

0.7

15

V

0.450

1.561

24.5

245

170

CS + 3 mm CA

50

2.5

N

0.7

15

V

0.254

1.905

5.0 + FV

425

0850 - EJECTORS C

BOC EDWARDS HICK

8474L015-PID0021-137

MP Steam Drive 0.2 Process Side Conditions Indicated

CS + 3 mm CA

0900 - PUMPS 8474L-410MR-0910102 8474L-410FEED PUMP MR-0910102 8474L-410METAL PASSIVATION PUMP X-1509 MR-4046001 8474L-410METAL PASSIVATION PUMP X-1509 MR-4046001 8474L-015SLURRY PRODUCT PUMP MR-0910101

_ _ _ __ RA| D __| N I ||___ 0

P-1502A

0

P-1502B

0

P-1504A

067 R--22000 AV NO 0176-M EL 1 - ANG - rev. 2

4046

C

4046

C

0910

B

B FLOWSERVE SECO BONO C EXACTA S.p.A SECO BONO C EXACTA S.p.A FLOWSERVE (NIIGATA B WORTHINGT


541.0 m3/h, 258.0 m Short-term Operating Temperature of 290 degC on Emergency Feed Recirculation 541.0 m3/h, 258.0 m Short-term Operating Temperature of 290 degC on Emergency Feed Recirculation

15

M

630 H

1.385

4.590

1.84

32.0

140

115

A487-CA6NM/A 13%Cr.

A216WCB

NI

N

V

1

4.770

15

M

630 H

1.385

4.590

1.84

32.0

140

115

A487-CA6NM/A 13%Cr.

A216WCB

NI

N

V

1

4.770

15

M

35.2

65

36

SSA304 or SSA316 NI

11.0 l/h

15

M

35.2

65

36

SSA304 or SSA316 NI

11.0 l/h

15

M

24.5

245

216.6

55 H

1.260

2.520

1.052

SCS1

SCS1

NI

N

V

1

1.115

36.5 m3/h, 191.0 m Abrasion Resistant Lining Max Speed 3000RPM

Page 12 /19


Project - Unit

Serial N°

8474L 410

EL 001

Revision 0


REV

(1)

TAG

SERVICE

(2)

(3)

0

P-1504B

SLURRY PRODUCT PUMP

0

P-1505A

BACKFLUSH OIL PUMP

0

P-1505B

BACKFLUSH OIL PUMP

0

P-1506A


0

P-1506B


0

P-1507A

HCO RECYCLE PUMP

0

P-1507B

HCO RECYCLE PUMP

0

P-1508A

HCO PUMPAROUND PUMP

0

P-1508B

HCO PUMPAROUND PUMP

0

P-1509A

HCO PRODUCT PUMP

0

P-1509B

HCO PRODUCT PUMP

0

P-1510A

LCO PUMPAROUND PUMP

0

P-1510B

LCO PUMPAROUND PUMP

0

P-1511A

LCO STRIPPER PUMP

0

P-1511B

LCO STRIPPER PUMP

0

P-1512A

MTC RECYCLE PUMP

0

P-1512B

MTC RECYCLE PUMP

0

P-1513A

LEAN OIL PUMP

0

P-1513B

LEAN OIL PUMP

0

P-1514A


0

P-1514B


P-1515A


P-1515B


0

P-1516A


0

P-1516B


0 0

_ _ _ __ RA| D __| N I ||___ P-1517A


0

P-1517B


0

P-1518A


0

067 R--22000 AV NO 0176-M 0

P-1518B

EL 1 - ANG - rev. 2


PURCHASING


(4)

(5)

8474L-015MR-0910101 8474L-410MR-0910102 8474L-410MR-0910102 8474L-015MR-0910101 8474L-015MR-0910101 8474L-410MR-0910102 8474L-410MR-0910102 8474L-410MR-0910102 8474L-410MR-0910102 8474L-410MR-0910102 8474L-410MR-0910102 8474L-410MR-0910102 8474L-410MR-0910102 8474L-410MR-0910102 8474L-410MR-0910102 8474L-410MR-0910102 8474L-410MR-0910102 8474L-410MR-0910102 8474L-410MR-0910102 8474L-410MR-0910102 8474L-410MR-0910102 8474L-410MR-0910102 8474L-410MR-0910102 8474L-410MR-0910102 8474L-410MR-0910102 8474L-410MR-0910102 8474L-410MR-0910102 8474L-410MR-0910102 8474L-410MR-0910102


LOCALISATION

Criticality Factors

VENDOR NAME

F

S

(8)

(9)

0910

B

FLOWSERVE (NIIGATA B WORTHINGT

CENTRIFUG AL PUMPS

0910

C

C FLOWSERVE

CENTRIFUG AL PUMPS

0910

C

C FLOWSERVE

(6)

SLURRY PUMPS

(7)

(10)

FLOWSERVE (NIIGATA C WORTHINGT ON) FLOWSERVE (NIIGATA C WORTHINGT ON)

SLURRY PUMPS

0910

C

SLURRY PUMPS

0910

C

CENTRIFUG AL PUMPS

0910

C

C FLOWSERVE

CENTRIFUG AL PUMPS

0910

C

C FLOWSERVE

CENTRIFUG AL PUMPS

0910

C

C FLOWSERVE

CENTRIFUG AL PUMPS

0910

C

C FLOWSERVE

CENTRIFUG AL PUMPS

0910

C

C FLOWSERVE

CENTRIFUG AL PUMPS

0910

C

C FLOWSERVE

CENTRIFUG AL PUMPS

0910

C

C FLOWSERVE

CENTRIFUG AL PUMPS

0910

C

C FLOWSERVE

CENTRIFUG AL PUMPS

0910

C

C FLOWSERVE

CENTRIFUG AL PUMPS

0910

C

C FLOWSERVE

CENTRIFUG AL PUMPS

0910

C

C FLOWSERVE

CENTRIFUG AL PUMPS

0910

C

C FLOWSERVE

CENTRIFUG AL PUMPS

0910

C

C FLOWSERVE

CENTRIFUG AL PUMPS

0910

C

C FLOWSERVE

CENTRIFUG AL PUMPS

0910

C

C FLOWSERVE

CENTRIFUG AL PUMPS

0910

C

C FLOWSERVE

CENTRIFUG AL PUMPS

0910

C

C FLOWSERVE

CENTRIFUG AL PUMPS

0910

C

C FLOWSERVE

CENTRIFUG AL PUMPS

0910

C

C FLOWSERVE

CENTRIFUG AL PUMPS

0910

C

C FLOWSERVE

CENTRIFUG AL PUMPS

0910

C

C FLOWSERVE

CENTRIFUG AL PUMPS

0910

C

C FLOWSERVE

CENTRIFUG AL PUMPS

0910

C

C FLOWSERVE

CENTRIFUG AL PUMPS

0910

C

C FLOWSERVE

Category (PED)

(11)

Module (PED)

(12)

PID #

(13)

8474L015-PID0021-321 8474L015-PID0021-325 8474L015-PID0021-325 8474L015-PID0021-324 8474L015-PID0021-324 8474L015-PID0021-306 8474L015-PID0021-306 8474L015-PID0021-308 8474L015-PID0021-308 8474L015-PID0021-316 8474L015-PID0021-316 8474L015-PID0021-307 8474L015-PID0021-307 8474L015-PID0021-318 8474L015-PID0021-318 8474L015-PID0021-305 8474L015-PID0021-305 8474L015-PID0021-317 8474L015-PID0021-317 8474L015-PID0021-305 8474L015-PID0021-305 8474L015-PID0021-317 8474L015-PID0021-317 8474L015-PID0021-320 8474L015-PID0021-320 8474L015-PID0021-320 8474L015-PID0021-320 8474L015-PID0021-320 8474L015-PID0021-320

S Y S T E M

(14)

G E O G R .

D E S I G N

U N I T

A R E A

(15)

(16)

DESIGN PARAMETERS

D R I V E R

P O W E R / D U T Y

P O S I T I O N

(kW)

(17)


OVERALL DIMENSIONS

(18)

(19)


T Y P E

B Y

(29)

(m)

(m)

(m)

(kg/cm² g)

(° C)

(° C)

I N T E R N A L

(20)

(21)

(22)

(23)

(24)

(25)

(26)

(27)

(28)

DIAMETER / WIDTH

LENGTH

HEIGHT

Design Pressure


T H I C K .

(mm) (30)

M A T E R I A L

(31)


(m²)

(32)


(33)

S Y S T E M

B Y

(34)

(35)

NBER OF DELIVERIES

D E L I V E R D


(36)

O F

REMARKS W E I G H T

(Tons)

(37)

(38)

(39)

15

M

55 H

1.260

2.520

1.052

24.5

245

216.6

SCS1

SCS1

NI

N

V

1

1.115

36.5 m3/h, 191.0 m Abrasion Resistant Lining Max Speed 3000RPM

15

M

22.0 H

1.095

1.840

0.845

13.5

195

170

A487-CA6NM/A

A487-CA6NM/A

NI

N

V

1

0.915

27.0 m3/h, 89.0 m

15

M

22.0 H

1.095

1.840

0.845

13.5

195

170

A487-CA6NM/A

A487-CA6NM/A

NI

N

V

1

0.915

27.0 m3/h, 89.0 m

15

M

11.0 H

1.000

2.040

0.735

11.5

195

170

SCPH2

SCPH2

NI

N

V

1

0.462

15

M

11.0 H

1.000

2.040

0.735

11.5

195

170

SCPH2

SCPH2

NI

N

V

1

0.462

15

M

160.0 H

1.385

3.650

1.21

27.5

363

336.9

A487-CA6MN/A

A487-CA6MN/A

NI

N

V

1

2.982

181.2 m3/h, 239.0 m

15

M

160.0 H

1.385

3.650

1.21

27.5

363

336.9

A487-CA6MN/A

A487-CA6MN/A

NI

N

V

1

2.982

181.2 m3/h, 239.0 m

15

M

224.0 H

1.645

3.875

1.655

14.5

363

305

A487-CA6MN/A

A487-CA6MN/A

NI

N

V

1

5.180

786.6 m3/h, 80.0 m

15

M

224.0 H

1.645

3.875

1.655

14.5

363

305

A487-CA6MN/A

A487-CA6MN/A

NI

N

V

1

5.180

786.6 m3/h, 80.0 m

15

M

15.0 H

0.945

2.190

0.785

9.5

350

324.1

A487-CA6MN

A487-410

NI

N

V

1

0.760

38.8 m3/h, 53.0 m Weight is estimated value.

15

M

15.0 H

0.945

2.190

0.785

9.5

350

324.1

A487-CA6MN

A487-410

NI

N

V

1

0.760


4.8 m3/h, 68.0 m Abrasion Resistant Lining Max Speed 3000RPM Seal Flushing Required 4.8 m3/h, 68.0 m Abrasion Resistant Lining Max Speed 3000RPM Seal Flushing Required

15

M

355.0 H

2.400

5.300

1.75

16.0

256

230

A487-CA6MN/A

A487-CA6MN/A

NI

N

V

1

8.603

1218.0 m3/h, 99.0 m

15

M

355.0 H

2.400

5.300

1.75

16.0

256

230

A487-CA6MN/A

A487-CA6MN/A

NI

N

V

1

8.603

1218.0 m3/h, 99.0 m

15

M

90.0 H

1.305

2.490

0.98

17.0

256

219.1

A487-CA6MN7/a

CS

NI

N

V

1

1.375

208.2 m3/h, 130.0 m

15

M

90.0 H

1.305

2.490

0.98

17.0

256

219.1

A487-CA6MN7/a

CS

NI

N

V

1

1.375

208.2 m3/h, 130.0 m

15

M

75 H

1.335

2.490

0.92

21.5

208

182.6

A487-CA6MN/A

CS

NI

N

V

1

1.113

113.5 m3/h, 148.0 m

15

M

75 H

1.335

2.490

0.92

21.5

208

182.6

A487-CA6MN/A

CS

NI

N

V

1

1.113

113.5 m3/h, 148.0 m

15

M

75.0 H

1.600

2.980

1.09

29.5

187

161

A216WCB

A216WCB

NI

N

V

1

1.870

54.9 m3/h, 243.0 m

15

M

75.0 H

1.600

2.980

1.09

29.5

187

161

A216WCB

A216WCB

NI

N

V

1

1.870

54.9 m3/h, 243.0 m

15

M

224.0 H

2.115

4.950

1.65

16.5

187

155.4

CS

CS

NI

N

V

1

5.990

835.8 m3/h, 94.0 m

15

M

224.0 H

2.115

4.950

1.65

16.5

187

155.4

CS

CS

NI

N

V

1

5.990

835.8 m3/h, 94.0 m

15

M

55.0 H

1.355

2.490

0.99

19.1

242

215.4

A487-CA6MN

A350-LF2

NI

N

V

1

1.113

43.4 m3/h, 178.0 m

15

M

55.0 H

1.355

2.490

0.99

19.1

242

215.4

A487-CA6MN

A350-LF2

NI

N

V

1

1.113

43.4 m3/h, 178.0 m

15

M

110.0 H

1.695

2.810

1.23

13.5

90

42

A487-CA6MN/B

A350-LF2

NI

N

V

1

2.590

346.6 m3/h, 105.0 m

15

M

110.0 H

1.695

2.810

1.23

13.5

90

42

A487-CA6MN/B

A350-LF2

NI

N

V

1

2.590

346.6 m3/h, 105.0 m

15

M

30.0 H

1.205

2.190

0.905

15.5

90

42

A487-CA6MN/B

CS

NI

N

V

1

0.881

70.2 m3/h, 87.0 m

15

M

30.0 H

1.205

2.190

0.905

15.5

90

42

A487-CA6MN/B

CS

NI

N

V

1

0.881

70.2 m3/h, 87.0 m

15

M

250.0 H

1.800

4.150

1.64

31.0

90

42

A216WCB

A216WCB

NI

N

V

1

4.530

225.5 m3/h, 308.0 m

15

M

250.0 H

1.800

4.150

1.64

31.0

90

42

A216WCB

A216WCB

NI

N

V

1

4.530

225.5 m3/h, 308.0 m

Page 13 /19


Project - Unit

Serial N°

8474L 410

EL 001

Revision 0


REV

(1)

TAG

SERVICE

(2)

(3)

PURCHASING


(4)

0

P-1519A


0

P-1519B


0

P-1519C


P-1520A


X-1505

0

P-1520B


X-1505

0

P-1521A


0

P-1521B


0

P-1522A


0

P-1522B


0

P-1526A

LIGHT SLOPS PUMP

0

P-1526B

LIGHT SLOPS PUMP

0

P-1527A

HEAVY SLOPS PUMP

0

P-1527B

HEAVY SLOPS PUMP

0

P-1528A

TEMPERED WATER PUMP

0

P-1528B

TEMPERED WATER PUMP

P-1529A


P-1529B


0

P-1531A

HPS PHOSPHATE INJECTION X-1510 PUMP

0

P-1531B


P-1531C


P-1531D


0

P-1531E


0

P-1531F


P-1532A

MPS PHOSPHATE INJECTION X-1510 PUMP

P-1532B


P-1532C


0

0 0

0 0

0 0 0

_ _ _ __ RA| D __| N I ||___

C-1501 C-1501

P-1532D


0

P-1532E


0

P-1551A


0

067 R--22000 AV NO 0176-M EL 1 - ANG - rev. 2

(5)

8474L-015MR-0910101 8474L-015MR-0910101 8474L-015MR-0910101 8474L-410MR-4046001 8474L-410MR-4046001 8474L-410MR-0910102 8474L-410MR-0910102 8474L-410MR-0910102 8474L-410MR-0910102 8474L-410MR-0910102 8474L-410MR-0910102 8474L-410MR-0910102 8474L-410MR-0910102 8474L-410MR-0910102 8474L-410MR-0910102 8474L-015MR-1040001 8474L-015MR-1040001 8474L-410MR-4046001 8474L-410MR-4046001 8474L-410MR-4046001 8474L-410MR-4046001 8474L-410MR-4046001 8474L-410MR-4046001 8474L-410MR-4046001 8474L-410MR-4046001 8474L-410MR-4046001 8474L-410MR-4046001 8474L-410MR-4046001 8474L-410MR-0910102


(6)

(7)

LOCALISATION

Criticality Factors

VENDOR NAME

F

S

(8)

(9)

(10)

FLOWSERVE (NIIGATA WORTHINGT FLOWSERVE (NIIGATA WORTHINGT FLOWSERVE (NIIGATA WORTHINGT SECO BONO EXACTA S.p.A SECO BONO EXACTA S.p.A

SLURRY PUMPS

0910

B

B

SLURRY PUMPS

0910

B

B

0910

B

B

4046

C

C

4046

C

C

CENTRIFUG AL PUMPS

0910

C

C FLOWSERVE

CENTRIFUG AL PUMPS

0910

C

C FLOWSERVE

CENTRIFUG AL PUMPS

0910

C

C FLOWSERVE

CENTRIFUG AL PUMPS

0910

C

C FLOWSERVE

CENTRIFUG AL PUMPS

0910

C

C FLOWSERVE

CENTRIFUG AL PUMPS

0910

C

C FLOWSERVE

CENTRIFUG AL PUMPS

0910

C

C FLOWSERVE

CENTRIFUG AL PUMPS

0910

C

C FLOWSERVE

CENTRIFUG AL PUMPS

0910

C

C FLOWSERVE

CENTRIFUG AL PUMPS AIR BLOWER

0910

C

C FLOWSERVE

C

MAN TURBO C AG

SLURRY PUMPS CHEMICAL INJECTION PACKAGES CHEMICAL INJECTION PACKAGES

AIR BLOWER CHEMICAL INJECTION PACKAGES CHEMICAL INJECTION PACKAGES CHEMICAL INJECTION PACKAGES CHEMICAL INJECTION PACKAGES CHEMICAL INJECTION PACKAGES CHEMICAL INJECTION PACKAGES CHEMICAL INJECTION PACKAGES CHEMICAL INJECTION PACKAGES CHEMICAL INJECTION PACKAGES CHEMICAL INJECTION PACKAGES CHEMICAL INJECTION PACKAGES CENTRIFUG AL PUMPS

1040

MAN TURBO AG SECO BONO EXACTA S.p.A SECO BONO EXACTA S.p.A SECO BONO EXACTA S.p.A SECO BONO EXACTA S.p.A SECO BONO EXACTA S.p.A SECO BONO EXACTA S.p.A SECO BONO EXACTA S.p.A SECO BONO EXACTA S.p.A SECO BONO EXACTA S.p.A SECO BONO EXACTA S.p.A SECO BONO EXACTA S.p.A

1040

C

C

4046

C

C

4046

C

C

4046

C

C

4046

C

C

4046

C

C

4046

C

C

4046

C

C

4046

C

C

4046

C

C

4046

C

C

4046

C

C

0910

C

C FLOWSERVE

Category (PED)

(11)

Module (PED)

(12)

PID #

(13)

8474L015-PID0021-311 8474L015-PID0021-311 8474L015-PID0021-311 8474L015-PID0021-319 8474L015-PID0021-319 8474L015-PID0021-326 8474L015-PID0021-326 8474L015-PID0021-327 8474L015-PID0021-327 8474L015-PID0021-329 8474L015-PID0021-329 8474L015-PID0021-330 8474L015-PID0021-330 8474L015-PID0021-331 8474L015-PID0021-331 8474L015-PID0021-132 8474L015-PID0021-132 8474L015-PID0021-332 8474L015-PID0021-332 8474L015-PID0021-332 8474L015-PID0021-332 8474L015-PID0021-332 8474L015-PID0021-332 8474L015-PID0021-332 8474L015-PID0021-332 8474L015-PID0021-332 8474L015-PID0021-332 8474L015-PID0021-332 8474L015-PID0021-403

S Y S T E M

(14)

G E O G R .

D E S I G N

U N I T

A R E A

(15)

(16)

DESIGN PARAMETERS

D R I V E R

P O W E R / D U T Y

P O S I T I O N

(kW)

(17)

(18)


OVERALL DIMENSIONS

(19)


T Y P E

B Y

(29)

(m)

(m)

(m)

(kg/cm² g)

(° C)

(° C)

I N T E R N A L

(20)

(21)

(22)

(23)

(24)

(25)

(26)

(27)

(28)

DIAMETER / WIDTH

LENGTH

HEIGHT

Design Pressure


T H I C K .

(mm) (30)

M A T E R I A L

(31)


(m²)

(32)


(33)

S Y S T E M

B Y

(34)

(35)

NBER OF DELIVERIES

D E L I V E R D


(36)

O F

REMARKS W E I G H T

(Tons)

(37)

(38)

(39)

769.4 m3/h, 134.0 m Abrasion Resistant Lining Max Speed 1770RPM 769.4 m3/h, 134.0 m Abrasion Resistant Lining Max Speed 1770RPM 769.4 m3/h, 134.0 m Abrasion Resistant Lining Max Speed 1770RPM

15

T

400.0 H

1.280

3.340

1.572

19.5

370

339.7

SCS1

SCS1

NI

N

V

1

4.180

15

T

400.0 H

1.280

3.340

1.572

19.5

370

339.7

SCS1

SCS1

NI

N

V

1

4.180

15

T

400.0 H

1.280

3.340

1.572

19.5

370

339.7

SCS1

SCS1

NI

N

V

1

4.180

15

M

1.0

14.0

70

40

SS 316

NI

LATER

15

M

1.0

14.0

70

40

SS 316

NI

LATER

15

T

110.0 H

1.435

3.160

1.165

37.1

200

170

A487-CA6MN/A

A487-CA6MN/A

NI

N

V

1

2.730

29.1 m3/h, 289.0 m

15

M

110.0 H

1.435

3.160

1.165

37.1

200

170

A487-CA6MN/A

A487-CA6MN/A

NI

N

V

1

2.730

29.1 m3/h, 289.0 m

15

M

30.0 H

1.155

2.190

0.845

15.2

75

50

A487-CA6MN/A

CS

NI

N

V

1

0.792

25.0 m3/h, 105.0 m

15

M

30.0 H

1.155

2.190

0.845

15.2

75

50

A487-CA6MN/A

CS

NI

N

V

1

0.792

25.0 m3/h, 105.0 m

15

M

37.0 H

1.095

2.190

0.87

14.5

75

40

A487-CA6MN/A

CS

NI

N

V

1

0.870

55.0 m3/h, 101.0 m

15

M

37.0 H

1.095

2.190

0.87

14.5

75

40

A487-CA6MN/A

CS

NI

N

V

1

0.870

55.0 m3/h, 101.0 m

15

M

37.0 H

1.155

2.190

0.87

13.3

110

85

A487-CA6MN/A

CS

NI

N

V

1

0.870

55.0 m3/h, 82.0 m

15

M

37.0 H

1.155

2.190

0.87

13.3

110

85

A487-CA6MN/A

CS

NI

N

V

1

0.870

55.0 m3/h, 82.0 m

15

M

15.0 H

1.095

2.145

0.98

14.0

112

65

A487-CA6MN

A216WCB

NI

N

V

1

0.789

55.0 m3/h, 41.0 m

15

M

15.0 H

1.095

2.145

0.98

14.0

112

65

A487-CA6MN

A216WCB

NI

N

V

1

0.789

55.0 m3/h, 41.0 m

15

M

H

0.915

2.145

0.860

10.1

150

60

NI

N

V

1.2

15

M

H

0.915

2.145

0.860

10.1

150

60

NI

N

V

1.2

15

M

1.0

56.4

61

36

NI

N

V

15

M

1.0

56.4

61

36

NI

N

V

15

M

1.0

56.4

61

36

NI

N

V

15

M

1.0

56.4

61

36

NI

N

V

15

M

1.0

56.4

61

36

NI

N

V

15

M

1.0

56.4

61

36

NI

N

V

15

M

1.0

23.6

61

36

NI

N

V

15

M

1.0

23.6

61

36

NI

N

V

15

M

1.0

23.6

61

36

NI

N

V

15

M

1.0

23.6

61

36

NI

N

V

15

M

1.0

23.6

61

36

NI

N

V

15

M

160.0 H

35.0

90

42

NI

N

V

1.635

3.875

1.555

A216WCB

A216WCB

1

3.908

132.1 m3/h, 218.0 m Design Pressure & Rated Power Estimated for Water Pumping Service

Page 14 /19


Project - Unit

Serial N°

8474L 410

EL 001

Revision 0


REV

TAG

(1)

SERVICE

(2)

(3)

0

P-1551B


0

P-1552A

KO DRUM LIQUID PUMP

0

P-1552B

KO DRUM LIQUID PUMP

0

P-1553A

STRIPPER FEED PUMP

0

P-1553B

STRIPPER FEED PUMP

0

P-1554A


0

P-1554B


P-1556A


P-1556B


0 0 0

P-1557

ANTI-FOAMING PUMP

0

P-1558

ANTI-FOAMING PUMP

0

P-1559A


0

P-1559B


0

P-1560A


0

P-1560B


0

P-1561

0 0

PURCHASING


(4)

(5)

8474L-410MR-0910102 8474L-410MR-0910102 8474L-410MR-0910102 8474L-410MR-0910102 8474L-410MR-0910102 8474L-410MR-0910102 8474L-410MR-0910102 8474L-410MR-0910102 8474L-410MR-0910102 8474L-410X-1551 MR-4046001 8474L-410X-1551 MR-4046001 8474L-015C-1551 MR-1010001 8474L-015C-1551 MR-1010001 8474L-410MR-0910102 8474L-410MR-0910102


(6)

(7)

LOCALISATION

Criticality Factors

VENDOR NAME

F

S

(8)

(9)

(10)

CENTRIFUG AL PUMPS

0910

C

C FLOWSERVE

CENTRIFUG AL PUMPS

0910

C

C FLOWSERVE

CENTRIFUG AL PUMPS

0910

C

C FLOWSERVE

CENTRIFUG AL PUMPS

0910

C

C FLOWSERVE

CENTRIFUG AL PUMPS

0910

C

C FLOWSERVE

CENTRIFUG AL PUMPS

0910

C

C FLOWSERVE

CENTRIFUG AL PUMPS

0910

C

C FLOWSERVE

CENTRIFUG AL PUMPS

0910

C

C FLOWSERVE

CENTRIFUG AL PUMPS CHEMICAL INJECTION PACKAGES CHEMICAL INJECTION PACKAGES WET GAS COMPRESS OR

0910

C

C FLOWSERVE

WET GAS COMPRESS OR

4046

C

C

4046

C

C

1010

C

C

SECO BONO EXACTA S.p.A SECO BONO EXACTA S.p.A ELLIOTT EBARA TURBOMAC HINERY ELLIOTT EBARA TURBOMAC HINERY

1010

C

C

CENTRIFUG AL PUMPS

0910

C

C FLOWSERVE

CENTRIFUG AL PUMPS

0910

C

C FLOWSERVE


C

C

ITT GOULDS

P-1562


C

C

ITT GOULDS

P-1563

OILY WATER LIFT PUMP COMMON SPARE

C

C

ITT GOULDS

C

C FLOWSERVE

8474L-015MR-0910- CENTRIFUG 102 AL PUMPS

0

P-1564


0

C-1501

AIR BLOWER

C-1501

0

ST-1501

AIR BLOWER STEAM TURBINE

C-1501

0

F-1501

AIR BLOWER FILTER

C-1501

0

X-1506

AIR BLOWER VENT SILENCER

C-1501

D

C-1502A


H-1503

D

C-1502B


D

C-1551

WET GAS COMPRESSOR

Category (PED)

(11)

Module (PED)

(12)

PID #

(13)

8474L015-PID0021-403 8474L015-PID0021-401 8474L015-PID0021-401 8474L015-PID0021-404 8474L015-PID0021-404 8474L015-PID0021-406 8474L015-PID0021-406 8474L015-PID0021-410 8474L015-PID0021-410 8474L015-PID0021-411 8474L015-PID0021-411 8474L015-PID0021-402 8474L015-PID0021-402 8474L015-PID0021-451 8474L015-PID0021-451 8474L015-PID0021-454 8474L015-PID0021-454 8474L015-PID0021-454 8474L015-PID0021-453

S Y S T E M

(14)

G E O G R .

D E S I G N

U N I T

A R E A

(15)

(16)

DESIGN PARAMETERS

D R I V E R

P O W E R / D U T Y

P O S I T I O N

(kW)

(17)

(18)


OVERALL DIMENSIONS

(19)


T Y P E

B Y

(29)

(m)

(m)

(m)

(kg/cm² g)

(° C)

(° C)

I N T E R N A L

(20)

(21)

(22)

(23)

(24)

(25)

(26)

(27)

(28)

DIAMETER / WIDTH

LENGTH

HEIGHT

Design Pressure


T H I C K .

(mm) (30)

M A T E R I A L

(31)


(m²)

(32)


(33)

S Y S T E M

B Y

(34)

(35)

NBER OF DELIVERIES

D E L I V E R D


(36)

O F

REMARKS W E I G H T

(Tons)

(37)

(38)

(39)

132.1 m3/h, 218.0 m Design Pressure & Rated Power Estimated for Water Pumping Service 5.0 m3/h, 23.0 m Intermittent Service

15

M

160.0 H

1.635

3.875

1.555

35.0

90

42

A216WCB

A216WCB

NI

N

V

1

3.908

15

M

4.0 H

1.205

1.840

0.865

6.0

90

42

A351 CF3M

A216WCB

NI

N

V

1

0.785

15

M

4.0 H

1.205

1.840

0.865

6.0

90

42

A351 CF3M

A216WCB

NI

N

V

1

0.785

5.0 m3/h, 23.0 m Intermittent Service

15

M

132.0 H

1.955

2.980

1.26

25.5

90

40

A426 CPCA15

A216WCB

NI

N

V

1

2.811

535.3 m3/h, 93.0 m

15

M

132.0 H

1.955

2.980

1.26

25.5

90

40

A426 CPCA15

A216WCB

NI

N

V

1

2.811

535.3 m3/h, 93.0 m

15

M

55.0 H

1.225

2.490

0.99

31.0

121

40

A487-CA6MN/A

A350-LF2

NI

N

V

1

1.113

47.5 m3/h, 172.0 m

15

M

55.0 H

1.225

2.490

0.99

31.0

121

40

A487-CA6MN/A

A350-LF2

NI

N

V

1

1.113

47.5 m3/h, 172.0 m

15

M

224.0 H

1.685

3.650

1.605

30.0

94

47

A487-CA6MN/A

A352-LCB

NI

N

V

1

4.360

405.1 m3/h, 235.0 m

15

M

224.0 H

1.685

3.650

1.605

30.0

94

47

A487-CA6MN/A

A352-LCB

NI

N

V

1

4.360

405.1 m3/h, 235.0 m

15

M

1.0

40.2

70

40

SS 316

NI

N

V

LATER

15

M

1.0

40.2

70

40

SS 316

NI

N

V

LATER

15

M

18.5 H

0.700

1.750

0.76

10.1

110

60

ALLOY STEEL

CS

NI

N

V

1

0.7

15

M

18.5 H

0.700

1.750

0.76

10.1

110

60

ALLOY STEEL

CS

NI

N

V

1

0.7

15

M

22.0 V

0.815

4.831

6.0

110

amb / 85

NI

N

V

1

1.410

20.0 m3/h, 60.0 m Size and Weight are estimated value.

15

M

22.0 V

0.815

4.831

6.0

110

amb / 85

NI

N

V

1

1.410

20.0 m3/h, 60.0 m Size and Weight are estimated value.

15

M

7.5 H

0.533

1.321

0.5

3.5

65

amb

NI

N

V

1

0.3

15

M

7.5 H

0.533

1.321

0.5

3.5

65

amb

NI

N

V

1

0.3

15

M

7.5 H

0.533

1.321

0.5

3.5

65

amb

NI

N

V

1

15

M

V

0.800

4.572

7.0

90

64

NI

N

V

1

15

T

20.0 m3/h, 35.0 m Requisition Number & Designation : LATER

20.0 m3/h, 35.0 m Requisition Number & Designation : LATER 20.0 m3/h, 35.0 m 0.3 Requisition Number & Designation : LATER Common Warehouse Spare for all OW Lifting

1.0

1000 - COMPRESSORS



AIR BLOWER

1040

B

A

MAN TURBO AG

AIR BLOWER

1040

B

A

MAN TURBO AG

AIR BLOWER

1040

C

C

MAN TURBO AG

AIR BLOWER

1040

C

C

COB/WHB PACKAGE

0160

C

C

H-1503


0160

C

C

C-1551

8474L-015- WET GAS MR-1010- COMPRESS 001 OR

1010

B

A

MAN TURBO AG FOSTER WHEELER ENERGY LIMITED FOSTER WHEELER ENERGY LIMITED ELLIOTT EBARA TURBOMAC HINERY


24105 H

4.200

5.000

2.5

5.0

276

216

Steel + Cast Iron

Cast Iron

A

V

58

53.0 395,001.8 m3/h

15

26516 H

4.200

5.300

3.0

48.3

450

380

Steel + Cast Iron

Steel + Cast Iron

H, A

V

40

33.0

15

H

6.650

4.100

6.7

atm

36

CS

NI

34.0

15

V

3.200

8.0

atm

CS

A

12.3

276

216

15

M

13.0

Metallic Protection Screen to be Provided to Fan Suction

8474L015-PID0021-203

15

T

13.0

Metallic Protection Screen to be Provided to Fan Suction

8474L015-PID0021-402

15

T

57.0

68318.1 m3/h (1st Stage) 14186.4 m3/h (2nd Stage)

7,717 H

4.000

4.060

2.5

20.1

150

Max. 113

Steel + Cast Iron

Steel

A

V

45

N

V

1

Page 15 /19


Project - Unit

Serial N°

8474L 410

EL 001

Revision 0


REV

TAG

(1)

SERVICE

(2)

(3)

D

ST-1551

WET GAS COMPRESSOR STEAM TURBINE

0

XP-1501

RFCC LIST STATION NO.1 PIT

0

XP-1502

RFCC LIST STATION NO.2 PIT

D

XP-1503

RFCC CLOSED DRAIN PIT

0

TK-1501

CORROSION INHIBITOR TANK

0

TK-1510

PHOSPHATE TANK

0

TK-1551

ANTI-FOAMING TANK

0

CAT-D-1501

RFCC CATALYST

PURCHASING


(4)

C-1551

(5)


(6)

8474L-015- WET GAS MR-1010- COMPRESS 001 OR

(7)

1010

LOCALISATION

Criticality Factors

VENDOR NAME

F

S

(8)

(9)

(10)

A

ELLIOTT EBARA TURBOMAC HINERY

B

Category (PED)

(11)

Module (PED)

(12)

PID #

(13)

8474L015-PID0021-402

S Y S T E M

(14)

G E O G R .

D E S I G N

U N I T

A R E A

(15)

(16)

15

DESIGN PARAMETERS

D R I V E R

P O W E R / D U T Y

P O S I T I O N

(kW)

(17)

(18)


OVERALL DIMENSIONS

(19)

8,489 H


T Y P E

B Y

(m)

(m)

(m)

(kg/cm² g)

(° C)

(° C)

I N T E R N A L

(20)

(21)

(22)

(23)

(24)

(25)

(26)

(27)

(28)

(29)

450

380

Steel + Cast Iron

Steel + Cast Iron

H, A

V

DIAMETER / WIDTH

LENGTH

HEIGHT

Design Pressure


4.000

4.020

2.4

48.3

15

2.000

2.400

3.65

65

AMB

15

2.000

2.000

3.0

65

AMB

15

6.700

7.300

3

T H I C K .

(mm) (30)

M A T E R I A L

(31)


(m²)


(32)

(33)

45

N

S Y S T E M

B Y

(34)

(35)

V

NBER OF DELIVERIES

D E L I V E R D


(36)

O F

(37)

1

REMARKS W E I G H T

(Tons)

(38)

(39)

14.0

1700 - CONCRETE PITS 8474L015-PID8474L015-PID8474L015-PID-

2500 - TANKS 8474L-410MR-4046001 8474L-410X-1510 MR-4046001 8474L-410X-1551 MR-4046001 X-1505

CHEMICAL INJECTION PACKAGES CHEMICAL INJECTION PACKAGES CHEMICAL INJECTION PACKAGES

4046

C

C

4046

C

C

4046

C

C

2600

A

A

0830

C

C

SECO BONO EXACTA S.p.A SECO BONO EXACTA S.p.A SECO BONO EXACTA S.p.A

8474L015-PID0021-319 8474L015-PID0021-332 8474L015-PID0021-411

15

V

atm

70

40

SS 316

NI

15

V

atm

61

36

SS

NI

15

V

atm

70

40

SS 316

NI

2600 - CATALYSTS 8474L-015- RESIDUE MR-2600- CRACKER

3900 - UMBILICAL AND FLEXIBLE MATERIAL 0

I-1501A

0

I-1501B

FEED INJECTOR

0

I-1501C

FEED INJECTOR

0

I-1501D

FEED INJECTOR

0

I-1501E

FEED INJECTOR

0

I-1501F

FEED INJECTOR

0

I-1502A

MTC INJECTOR

0

I-1502B

MTC INJECTOR

0

I-1502C

MTC INJECTOR

0

I-1502D

MTC INJECTOR

0

I-1503A


0

I-1503B


0

I-1503C


0

I-1503D


_ _ _ __ RA| D __| N I ||___ 0

I-1504


D

SPR-1503

WATER SPRAYERS FOR FIRST REGENERATOR FLUE GAS BYPASS

067 R--22000 AV NO 0176-M EL 1 - ANG - rev. 2

8474L-015MR-0830004 8474L-015MR-0830004 8474L-015MR-0830004 8474L-015MR-0830004 8474L-015MR-0830004 8474L-015MR-0830004 8474L-015MR-0830101 8474L-015MR-0830101 8474L-015MR-0830101 8474L-015MR-0830101 8474L-015MR-0830101 8474L-015MR-0830101 8474L-015MR-0830101 8474L-015MR-0830101 8474L-015MR-0830101

FEED INJECTOR

H-1503

FEED INJECTOR FEED INJECTOR

0830

C

C

FEED INJECTOR

0830

C

C

FEED INJECTOR

0830

C

C

FEED INJECTOR

0830

C

C

FEED INJECTOR

0830

C

C

MTC INJECTOR

0830

C

C

MTC INJECTOR

0830

C

C

MTC INJECTOR MTC INJECTOR STABILIZATI ON INJECTOR STABILIZATI ON INJECTOR STABILIZATI ON INJECTOR STABILIZATI ON INJECTOR BACK FLUSH OIL INJECTOR


0830

C

C

0830

C

C

0830

C

C

0830

C

C

0830

C

C

0830

C

C

0830

C

C

0160

C

C

15

STONE & WEBSTER INTERNATIO STONE & WEBSTER INTERNATIO STONE & WEBSTER INTERNATIO STONE & WEBSTER INTERNATIO STONE & WEBSTER INTERNATIO STONE & WEBSTER INTERNATIO VINCI TECHNOLOG IES VINCI TECHNOLOG IES VINCI TECHNOLOG IES VINCI TECHNOLOG IES VINCI TECHNOLOG IES VINCI TECHNOLOG IES VINCI TECHNOLOG IES VINCI TECHNOLOG IES VINCI TECHNOLOG IES

8474L015-PID0021-121 8474L015-PID0021-121 8474L015-PID0021-121 8474L015-PID0021-121 8474L015-PID0021-121 8474L015-PID0021-121 8474L015-PID0021-122 8474L015-PID0021-122 8474L015-PID0021-122 8474L015-PID0021-122 8474L015-PID0021-122 8474L015-PID0021-122 8474L015-PID0021-122 8474L015-PID0021-122 8474L015-PID0021-122


8474L015-PID0021-201

LATER

15

32.0 (Oil) / 16.8 (Steam)

15

32.0 (Oil) / 16.8 (Steam)

15

32.0 (Oil) / 16.8 (Steam)

15

32.0 (Oil) / 16.8 (Steam)

15

32.0 (Oil) / 16.8 (Steam)

15

32.0 (Oil) / 16.8 (Steam)

15

0.088

1.861

21.5 (Oil) / 16.8 (Steam)

15

0.088

1.861

21.5 (Oil) / 16.8 (Steam)

315 (Oil) / 320 (Steam) 315 (Oil) / 320 (Steam) 315 (Oil) / 320 (Steam) 315 (Oil) / 320 (Steam) 315 (Oil) / 320 (Steam) 315 (Oil) / 320 (Steam) 320 (Oil) / 320 (Steam) 320 (Oil) / 320 (Steam) 320 (Oil) / 320 (Steam) 320 (Oil) / 320 (Steam)

170

TP-321

IFP Proprietary Item

170

TP-321


170

TP-321


170

TP-321


170

TP-321


170

TP-321

181

A565 GR616

0.13


181

A565 GR616

0.13

181

A565 GR616

0.13

181

A565 GR616

0.13

15

0.088

1.861

21.5 (Oil) / 16.8 (Steam)

15

0.088

1.861

21.5 (Oil) / 16.8 (Steam)

15

0.088

1.208

16.8

320

250

A565 GR616

0.08

15

0.088

1.208

16.8

320

250

A565 GR616

0.08

15

0.088

1.208

16.8

320

250

A565 GR616

0.08

15

0.088

1.208

16.8

320

250

A565 GR616

0.08

320 (Oil) / 16.8 (Oil) / 320 16.8 (Steam) (Steam)

170

A565 GR616

15

15

0.088

1.879

0.1

IFP Proprietary Item IFP Proprietary Item IFP Proprietary Item IFP Proprietary Item IFP Proprietary Item IFP Proprietary Item IFP Proprietary Item IFP Proprietary Item IFP Proprietary Item

LATER

Page 16 /19


Project - Unit

Serial N°

8474L 410

EL 001

Revision 0


REV

TAG

(1)

SERVICE

(2)

D

SPR-1504

D

SPR-1505

0

X-1501

(3)

WATER SPRAYERS FOR SECOND REGENERATOR FLUE GAS BYPASS WATER SPRAYERS FOR ECONOMIZER BYPASS

PURCHASING


(4)

(5)

8474L-015H-1503 MR-0160001 8474L-015H-1503 MR-0160001


(6)

(7)

LOCALISATION

Criticality Factors

VENDOR NAME

F

S

(8)

(9)

COB/WHB PACKAGE

0160

C

C

COB/WHB PACKAGE

0160

C

C

CATALYST DRAW OFF SYSTEM

4019

C

C

(10)

FOSTER WHEELER ENERGY FOSTER WHEELER ENERGY

Category (PED)

(11)

Module (PED)

(12)

PID #

(13)

8474L015-PID0021-202 8474L015-PID0021-205

S Y S T E M

(14)

G E O G R .

D E S I G N

U N I T

A R E A

(15)

(16)

DESIGN PARAMETERS

D R I V E R

P O W E R / D U T Y

P O S I T I O N

(kW)

(17)

(18)


OVERALL DIMENSIONS

(19)

(m)

(m)

(m)

(kg/cm² g)

(° C)

(° C)

I N T E R N A L

(20)

(21)

(22)

(23)

(24)

(25)

(26)

DIAMETER / WIDTH

LENGTH

HEIGHT

Design Pressure



T Y P E

B Y

(27)

(28)

(29)

T H I C K .

(mm) (30)

M A T E R I A L

(31)


(m²)

(32)


(33)

S Y S T E M

B Y

(34)

(35)

NBER OF DELIVERIES

D E L I V E R D


(36)

O F

(37)

REMARKS W E I G H T

(Tons)

(38)

(39)

15

LATER

15

LATER

4010 - SOLID HANDLING

0

CATALYST DRAW OFF SYSTEM

X-1502


X-1503


0

A-1501

CATALYST LOADING AND UNLOADING SYSTEM

0

PV-1501

PLUG VALVE

0

SV-1501


0

SV-1502


0

SV-1503


0

SV-1504


0

4030 - PNEUMATIC AND GRAVITY HANDLING

0

X-1505

4046 - INJECTION PACKAGES CORROSION INHIBITOR INJECTION PACKAGE

X-1505

X-1509


X-1509

0

X-1510


X-1510

0

X-1551


X-1551

A-1502


H-1503

0

D D

A-1502-TK-01

MEASURING TANK

H-1503

D

A-1502-P-01A

INJECTION PUMP

H-1503

D

A-1502-P-01B

INJECTION PUMP

H-1503

D

XC-1501

AIR BLOWER OVERHEAD CRANE

D

XC-1502

WET GAS COMPRESSOR OVERHEAD CRANE

0

XL-1580

ELEVATOR SYSTEM

0

A-1590

OIL MIST GENERATOR

8474L-410MR-4019001 8474L-015MR-4010002 8474L-015MR-4010002 8474L-015MR-4010003

CATALYST FEEDER CATALYST LOADING AND


SLIDE VALVES & PLUG SLIDE VALVES & PLUG SLIDE VALVES & PLUG SLIDE VALVES & PLUG SLIDE VALVES & PLUG

8474L-410MR-4046001 8474L-410MR-4046001 8474L-410MR-4046001 8474L-410MR-4046001 8474L-015MR-0160001 8474L-015MR-0160001 8474L-015MR-0160001 8474L-015MR-0160001

CHEMICAL INJECTION PACKAGES CHEMICAL INJECTION PACKAGES CHEMICAL INJECTION PACKAGES CHEMICAL INJECTION PACKAGES COB/WHB PACKAGE

8474L-015MR-4080001 8474L-015MR-4080001 8474L-015MR-4060-

OVERHEAD TRAVELING CRANE OVERHEAD TRAVELING CRANE ELEVATOR SYSTEM

CATALYST FEEDER

4010 4010

C C

C GAMBO B.V. C GAMBO B.V.

4010

C

C

KOREA COTTRELL

4010

B

A

REMOSA S.P.A

4010

B

A

REMOSA S.P.A

4010

B

A

REMOSA S.P.A

4010

B

A

REMOSA S.P.A

4010

B

A

REMOSA S.P.A

4046

C

C

4046

C

C

4046

C

C

4046

C

C

0160

C

C

COB/WHB PACKAGE

0160

C

C

COB/WHB PACKAGE

0160

C

C

COB/WHB PACKAGE

0160

C

C

4080

C

C

SEKO BONO EXACTA S.p.A SEKO BONO EXACTA S.p.A SEKO BONO EXACTA S.p.A SEKO BONO EXACTA S.p.A FOSTER WHEELER ENERGY FOSTER WHEELER ENERGY FOSTER WHEELER ENERGY FOSTER WHEELER ENERGY



8474L015-PID0021-319 8474L015-PID0021-121 8474L015-PID0021-332 8474L015-PID0021-411 8474L015-PID0021-203 8474L015-PID0021-203 8474L015-PID0021-203 8474L015-PID0021-203

15

10.6

15

V

15

V

15

15

V

0.920

2.420

2.77

0.920

2.420

2.77

2.000

2.000

4.5

1.288

8.856

10.6 10.6

770 350 350

683

SS

50

CS (SS 304 TUBING)

Proprietary Item 2.20

50

CS (SS 304 TUBING)

2.20

SS400

5.2

770

646

SS 304

9.938 15.640


15

1.500

5.570

3.55

5.2

840

712

SA 516 Gr 70

15

1.500

5.684

2.1

5.2

560

511

SA 516 Gr 70

8.820


15

1.600

8.205

1.65

5.2

770

678

SA 516 Gr 70

11.100


15

1.514

7.502

1.85

5.2

840

772

SA 516 Gr 70

11.160


15

3.500

4.000

3

NI

1

3.5 LATER

15

3.000

5.000

3

NI

1

4.5 LATER

15

3.000

8.000

3

NI

1

6.0 LATER

15

3.000

5.000

3

NI

1

4.5 LATER

15

3.000

5.000

3

NI

1

3.5 LATER

15

LATER

15

LATER

15

LATER

4060 - LIFTING

_ _ _ __ RA| D __| N I ||___

KONECRANE S PTE LTD.

15

M

17.2

3.156

12.000

2.1

6.8 Old Tag Number : Z-1501 8.5 Old Tag Number : Z-1502

4080

C

KONECRANE C S PTE LTD.

15

M

17.8

4.840

12.000

2.1

4060

C

C

CHAMPION ELEVATORS

15

M

29.1 V

2.680

3.500

71.647

4130

C

C

LUBRICATIO N SYSTEMS COMPANY

15

P

Old Tag Number : X-1580

4130 - PACKAGE

067 R--22000 AV NO 0176-M EL 1 - ANG - rev. 2

OIL MIST 8474L-000LUBRICATI MR-4130ON 001 SYSTEMS

SR prepared for JVD by KLOC

Page 17 /19


Project - Unit

Serial N°

8474L 410

EL 001

Revision 0


REV

TAG

(1)

SERVICE

(2)

(3)

0

A-1591

OIL MIST GENERATOR

0

A-1592

OIL MIST GENERATOR

PURCHASING


(4)

(5)

8474L-000MR-4130001 8474L-000MR-4130001


(6)

OIL MIST LUBRICATI ON SYSTEMS OIL MIST LUBRICATI ON SYSTEMS

LOCALISATION

Criticality Factors

VENDOR NAME

F

S

(7)

(8)

(9)

4130

C

C

4130

C

(10)

Category (PED)

(11)

Module (PED)

(12)

PID #

(13)

LUBRICATIO N SYSTEMS COMPANY LUBRICATIO C N SYSTEMS COMPANY

S Y S T E M

(14)

G E O G R .

D E S I G N

U N I T

A R E A

(15)

(16)

DESIGN PARAMETERS

D R I V E R

P O W E R / D U T Y

P O S I T I O N

(kW)

(17)

15

P

15

P

(18)


OVERALL DIMENSIONS

(19)

(m)

(m)

(m)

(kg/cm² g)

(° C)

(° C)

I N T E R N A L

(20)

(21)

(22)

(23)

(24)

(25)

(26)

DIAMETER / WIDTH

LENGTH

HEIGHT

Design Pressure



T Y P E

B Y

(27)

(28)

(29)

T H I C K .

(mm) (30)

M A T E R I A L

(31)


(m²)

(32)


(33)

S Y S T E M

B Y

(34)

(35)

NBER OF DELIVERIES

D E L I V E R D


(36)

O F

(37)

REMARKS W E I G H T

(Tons)

(38)

(39)



4240 - OTHER FILTERS D

X-1504

SLURRY SEPARATOR

0

M-1501

FEED LINE STATIC MIXER

8474L-015SLURRY MR-4240SEPARATOR 001

4240

B

A GULFTRONIC

8474L015-PID0021-323

15

8474L-410- FEED LINE MR-0850- STATIC MIXER 001

0850

C

STATIFRLO C INTERNATIO NAL LTD

8474L015-PID0021-121

15

H

LARGE DRUMS

0810

C

H

2.286

7.620

30 + FV

70

40

A516 Gr60N + 3 mm CA

SA516 Gr60N + 3 mm CA

NI

N

V

1

0810

C

16

H

2.286

7.620

30.0

70

40



NI

N

V

1

LARGE DRUMS

0810

8474L016-PID0021-111 8474L016-PID0021-112 8474L016-PID0021-151

16

LARGE DRUMS

TEPAT C TEKNIK SDN BHD TEPAT C TEKNIK SDN BHD TEPAT TEKNIK SDN BHD

16

h

2.000

5.000

3.5

110

85(AMB)

N

V

1

7.2

6.000

11.770

4.323

24.5

220

170

32.0

315 170 / 290

4

71.124

4260 - MIXING 1.2

CS + 3mm CA

1

0.3

U016 - LPG Treater (LTU)

0800 - DRUMS 0

D-1601

FIRST STAGE PHASE SEPARATOR

0

D-1602

SECOND STAGE PHASE SEPARATOR

D-1660

CAUSTIC CLOSED DRAIN DRUM

0

8474L-015MR-0810001 8474L-015D-1602 MR-0810001 8474L-015MR-0810001

D-1601

CS(HIC) + CA 3mm PP

30

MDMT : -25 degC 24.0 To be Designed for 1.5 kg/cm2g @ 160 degC + FV (for Steam Out Condition) MDMT : -25 degC 24.0 To be Designed for 1.5 kg/cm2g @ 160 degC + FV (for Steam Out Condition)

0840 - FILTERS

0

FFC-1601

FIRST STAGE FIBER-FILM CONTACTOR

D-1601

8474L-017- FIVER-FILM MR-0830- CONTACTO 301 R

0830

C

C

MERICHEM

8474L016-PID0021-111

16

V

1.067

8.029

30.0

70

40



NI

1

7.6

MDMT : -25 degC To be Designed for 1.5 kg/cm2g @ 160 degC + FV (for Steam Out Condition) Merichem Proprietary Item

0

FFC-1602

SECOND STAGE FIBER-FILM D-1602 CONTACTOR

8474L-017- FIVER-FILM MR-0830- CONTACTO 301 R

0830

C

C

MERICHEM

8474L016-PID0021-112

16

V

1.067

8.029

30.0

70

40



NI

1

7.6

MDMT : -25 degC To be Designed for 1.5 kg/cm2g @ 160 degC + FV (for Steam Out Condition) Merichem Proprietary Item

AIR 8474L-017SPARGER/C MR-0830ATALYST 301 ADDITION

0830

C

C

MERICHEM

8474L016-PID0021-112

16

SS 316L

SS 316L / TEFLON

CENTRIFUG AL PUMPS

0910

C

C FLOWSERVE

CENTRIFUG AL PUMPS

0910

C

C FLOWSERVE

CENTRIFUG AL PUMPS

0910

C

C FLOWSERVE

0870 - INTERNALS 0

SP-1601

COALESCER PAD

0

P-1601A

FIRST STAGE CAUSTIC CIRCULATION PUMP

0

P-1601B

FIRST STAGE CAUSTIC CIRCULATION PUMP

0

P-1602A

SECOND STAGE CAUSTIC CIRCULATION PUMP

P-1602B

SECOND STAGE CAUSTIC CIRCULATION PUMP

D-1602

2.286

70

0900 - PUMPS

0

_ _ _ __ RA| D __| N I ||___ 0

P-1603A

CAUSTIC METERING PUMP

0

P-1603B

CAUSTIC METERING PUMP

0

P-1604A

MEA METERING PUMP

067 R--22000 AV NO 0176-M EL 1 - ANG - rev. 2

8474L-410MR-0910102 8474L-410MR-0910102 8474L-410MR-0910102 8474L-410MR-0910102 8474L-410MR-0940103 8474L-410MR-0940103 8474L-410MR-0940103

CENTRIFUG AL PUMPS POSSITIVE DISPLACEM ENT PUMPS POSSITIVE DISPLACEM ENT PUMPS POSSITIVE DISPLACEM ENT PUMPS

0910

C

C FLOWSERVE

0940

C

C

OBL S.R.L

0940

C

C

OBL S.R.L

0940

C

C

OBL S.R.L

8474L016-PID0021-111 8474L016-PID0021-111 8474L016-PID0021-112 8474L016-PID0021-112 8474L016-PID0021-113 8474L016-PID0021-113 8474L016-PID0021-113

16

M

5.5 H

1.095

2.190

0.87

33.0

70

40

SS 316

CS

NI

N

V

1

0.775


16

M

5.5 H

1.095

2.190

0.87

33.0

70

40

SS 316

CS

NI

N

V

1

0.775


16

M

5.50

H

1.095

2.190

0.87

33.0

70

40

A351 CF3M

CS

NI

N

V

1

0.775

35.0 m3/h, 18.5 m

5.50

A351 CF3M

CS

35.0 m3/h, 18.5 m

16

M

H

1.095

2.190

0.87

33.0

70

40

NI

N

V

1

0.775

16

M

3.0 H

0.900

1.260

1.05

30.0

70

40

SS 316 with PTFE NI DIAPHRAM

N

V

1

0.400

16

M

3.0 H

0.900

1.260

1.05

30.0

70

40


N

V

1

0.400

16


N

V

1

0.080

16

M

0.37

H

0.460

0.590

0.365

30.0

70

Page 18 /19


Project - Unit

Serial N°

8474L 410

EL 001

Revision 0


REV

TAG

(1)

SERVICE

(2)

(3)

0

P-1604B

MEA METERING PUMP

0

P-1605A

WATER DILUTION METERING PUMP

0

P-1605B

WATER DILUTION METERING PUMP

0

P-1650

PURCHASING


(4)

AIR DRIVEN PUMP


(5)

(6)

8474L-410MR-0940103 8474L-410MR-0940103 8474L-410MR-0940103 8474L-016MR-0940141

POSSITIVE DISPLACEM ENT PUMPS POSSITIVE DISPLACEM ENT PUMPS POSSITIVE DISPLACEM ENT PUMPS AIR OPERATED DIAPHRAG

(7)

LOCALISATION

Criticality Factors

VENDOR NAME

F

S

(8)

(9)

(10)

0940

C

C

OBL S.R.L

0940

C

C

OBL S.R.L

0940

C

C

OBL S.R.L

0940

C

JAPAN C MACHINERY (WILDEN)

Category (PED)

(11)

Module (PED)

(12)

PID #

(13)


S Y S T E M

(14)

G E O G R .

D E S I G N

U N I T

A R E A

(15)

(16)

DESIGN PARAMETERS

D R I V E R

P O W E R / D U T Y


OVERALL DIMENSIONS P O S I T I O N

(kW)

E X T E R N A L

T Y P E

B Y

(27)

(28)

(29)

T H I C K .



(m)

(m)

(m)

(kg/cm² g)

(° C)

(° C)

I N T E R N A L

(20)

(21)

(22)

(23)

(24)

(25)

(26)

30.0

70

16


N

0.365

30.0

60

30


0.590

0.365

30.0

60

30


0.750

1.0

6.0

70

16

NI

DIAMETER / WIDTH

LENGTH

HEIGHT

(17)

(18)

(19)

16

M

0.37

H

0.460

0.590

0.365

16

M

0.37

H

0.460

0.590

16

M

0.37

H

0.460

16

P

0.400

12.1

INSULATION

Design Pressure


(mm) (30)

M A T E R I A L

(31)

(m²)

(32)

(33)

S Y S T E M

B Y

(34)

(35)

NBER OF DELIVERIES

D E L I V E R D


(36)

O F

REMARKS W E I G H T

(Tons)

(37)

(38)

V

1

0.080

N

V

1

0.080

N

V

1

0.080

N

V

1

0.078

(39)

5.0 m3/h

1390 - MISCELLANEOUS MDMT : -25 degC To be Designed for 1.5 kg/cm2g @ 160 degC + FV (for Steam Out Condition) Basket Material : SS 316 Merichem Proprietary Item MDMT : -25 degC To be Designed for 1.5 kg/cm2g @ 160 degC + FV (for Steam Out Condition) Basket Material : SS 316 Merichem Proprietary Item To be Designed for 1.5 kg/cm2g @ 160 degC + FV (for Steam Out Condition) Basket Material : SS 316 Merichem Proprietary Item

0

STR-1601A

HYDROCARBON BASKET STRAINER

8474L-017MR-0830- STRAINERS 301

0830

C

C

MERICHEM

8474L016-PID0021-111

16

30.0

70

40

A333-6 + 3 mm CA NI

0

STR-1601B


8474L-017MR-0830- STRAINERS 301

0830

C

C

MERICHEM

8474L016-PID0021-111

16

30.0

70

40

A333-6 + 3 mm CA NI

0

STR-1602A

CAUSTIC BASKET STRAINER

8474L-017MR-0830- STRAINERS 301

0830

C

C

MERICHEM

8474L016-PID0021-113

16

5.5

70

40

A106-B + 3 mm CA NI

0

STR-1602B

CAUSTIC BASKET STRAINER

8474L-017MR-0830- STRAINERS 301

0830

C

C

MERICHEM

8474L016-PID0021-113

16

5.5

70

40

A106-B + 3 mm CA NI

To be Designed for 1.5 kg/cm2g @ 160 degC + FV (for Steam Out Condition) Basket Material : SS 316 Merichem Proprietary Item

0

STR-1603A

MEA BASKET STRAINER

8474L-017MR-0830- STRAINERS 301

0830

C

C

MERICHEM

8474L016-PID0021-113

16

33.0

70

40

A106-B + 3 mm CA NI


0

STR-1603B

MEA BASKET STRAINER

8474L-017MR-0830- STRAINERS 301

0830

C

C

MERICHEM

8474L016-PID0021-113

16

33.0

70

40

A106-B + 3 mm CA NI


D

XP-1601

MEA STORAGE TANK PIT

8474L016-PID-

16

0

TK-1601

C

8474L016-PID0021-113

16

V

3.000

TEPAT C TEKNIK SDN BHD DAECHANG HRSG C CORPORATI SECO BONO C EXACTA S.p.A

8474L017-PID0021-112 8474L017-PID0021-113 8474L017-PID0021-112

17

H

3.658

17

V

0.610

17

V

C

8474L017-PID0021-112

17

V

1700 - CONCRETE PITS 3.000

6.400

2.2

2500 - TANKS 8474L-410MR-2520- TANKS 001

MEA STORAGE TANK

2520

C

0810

C

0810

C

4046

C

0830

C

3.600

0.014

70

30

304L

304L

NI

5.0 Cone Roof

U017 - RFCC Naphtha Treater (NTU)

0800 - DRUMS 0

D-1701

PHASE SEPARATOR

0

D-1702

AIR RECEIVER

_ _ _ __ RA| D __| N I ||___ 0

D-1750

ANTI-OXIDANT DRUM

8474L-015MR-0810001 8474L-410MR-0810002 8474L-410A-1750 MR-4046001

D-1701

LARGE DRUMS MEDIUM DRUMS CHEMICAL INJECTION PACKAGES

7.315 2.100

19.1 + FV

65

40



NI

N

V

1

44.0

14.0

70

45

CS + 3mm CA

CS + 3mm CA

NI

N

V

1

0.6

atm

65

36

SS

NI

19.1

65

40


NI


0840 - FILTERS

0

FFC-1701

FIBER-FILM CONTACTOR

067 R--22000 AV NO 0176-M EL 1 - ANG - rev. 2

D-1701

8474L-017LARGE MR-0830DRUMS 301

MERICHEM

1.676

7.432


N

To be Designed for 1.5 kg/cm2g @ 160 degC + 7.9 FV (for Steam Out Condition) Merichem Proprietary Item

Page 19 /19


Project - Unit

Serial N°

8474L 410

EL 001

Revision 0


REV

TAG

(1)

SERVICE

(2)

(3)

PURCHASING


(4)

(5)


LOCALISATION

Criticality Factors

VENDOR NAME

F

S

(7)

(8)

(9)

(10)

0830

C

C

MERICHEM

CENTRIFUG AL PUMPS

0910

C

C FLOWSERVE

CENTRIFUG AL PUMPS POSSITIVE DISPLACEM ENT PUMPS POSSITIVE DISPLACEM ENT PUMPS

0910

C

C FLOWSERVE

(6)

Category (PED)

(11)

Module (PED)

(12)

PID #

(13)

S Y S T E M

(14)

G E O G R .

D E S I G N

U N I T

A R E A

(15)

(16)

DESIGN PARAMETERS

D R I V E R

P O W E R / D U T Y

P O S I T I O N

(kW)

(17)

(18)


OVERALL DIMENSIONS

(19)


T Y P E

B Y

(28)

(29)

T H I C K .



(m)

(m)

(m)

(kg/cm² g)

(° C)

(° C)

I N T E R N A L

(20)

(21)

(22)

(23)

(24)

(25)

(26)

(27)

SS 316L

SS 316L / TEFLON

CS

NI

N

CS

DIAMETER / WIDTH

LENGTH

HEIGHT

Design Pressure


(mm) (30)

M A T E R I A L

(31)

(m²)

(32)

(33)

S Y S T E M

B Y

(34)

(35)

NBER OF DELIVERIES

D E L I V E R D


(36)

O F

REMARKS W E I G H T

(Tons)

(37)

(38)

(39)

V

1

1.070

75.0 m3/h, 21.0 m Weight is estimated value. 75.0 m3/h, 21.0 m Weight is estimated value.

0870 - INTERNALS 0

SP-1703

COALESCER PAD

D-1701

8474L-017LARGE MR-0830DRUMS 301

8474L017-PID0021-112

17

3.658

65

0900 - PUMPS 0

P-1701A

CAUSTIC RECYCLE PUMP

0

P-1701B

CAUSTIC RECYCLE PUMP

0

P-1702A

WATER INJECTION PUMP

0

P-1702B

WATER INJECTION PUMP

0

P-1703

CAUSTIC BATCH PUMP

P-1750A

ANTI-OXIDANT INJECTIPN PUMP

0

P-1750B

ANTI-OXIDANT INJECTIPN PUMP

0

C-1701A

OXIDATION AIR COMPRESSOR

C-1701B

OXIDATION AIR COMPRESSOR

0

8474L-410MR-0910102 8474L-410MR-0910102 8474L-410MR-0940103 8474L-410MR-0940103 8474L-410MR-0910102 8474L-410A-1750 MR-4046001 8474L-410A-1750 MR-4046001

CENTRIFUG AL PUMPS CHEMICAL INJECTION PACKAGES CHEMICAL INJECTION PACKAGES

8474L-017MR-1020001 8474L-017MR-1020001

OXIDATION AIR COMPRESS OXIDATION AIR COMPRESS

0940

C

SECO BONO EXACTA S.p.A SECO BONO EXACTA S.p.A

8474L017-PID0021-112 8474L017-PID0021-112 8474L017-PID0021-111 8474L017-PID0021-111 8474L017-PID0021-111 8474L017-PID0021-112 8474L017-PID0021-112

KAJI C TECHNOLOG Y KAJI C TECHNOLOG Y

8474L017-PID0021-113 8474L017-PID0021-113

C

OBL S.R.L

0940

C

C

OBL S.R.L

0910

C

C FLOWSERVE

4046

C

C

4046

C

C

1020

C

1020

C

AIR SPARGER

0830

C

C MERICHEM

CATALYST ADDITION PIPE

0830

C

C MERICHEM

0830

C

C MERICHEM

0830

C

C MERICHEM

0830

C

C MERICHEM

4046

C

C

0840

C

0840

C

17

M

15.0 H

1.235

2.490

1.005

23.0

65

40

A351 CF3M

17

M

15.0 H

1.235

2.490

1.005

23.0

65

40

A351 CF3M

17

M

17

M

17

0.75 0.75

H

0.715

0.720

1.22

19.7

60

NI

N

V

1

1.070

30


N

V

1

0.150


N

V

1

0.150

N

V

1

0.530

H

0.715

0.720

1.22

19.7

60

30

M

7.5 H

1.055

1.840

0.865

21.7

70

40

17

M

1.0

21.0

65

36

NI

17

M

1.0

21.0

65

36

NI

17

M

15.0

2.300

5.670

2.9

14.0

220

170

STEEL

C.S

V

1

6.2 92.0 m3/h

17

M

15.0

2.300

5.670

2.9

14.0

220

170

STEEL

C.S

V

1

6.2 92.0 m3/h

SS 316

CS

NI

5.7 m3/h, 66.0 m WeightIS estimated value.

1000 - COMPRESSORS

0

1390 - MISCELLANEOUS 0

SP-1701

AIR SPARGER

0

SP-1702

CATALYST ADDITION PIPE

0

STR-1701A


0

STR-1701B


0

STR-1702

AQUEOUS BASKET STRAINER

0

A-1750

4046 - INJECTION PACKAGES ANTI-OXIDANT INJECTION PACKAGE

_ _ _ __ RA| D __| N I ||___

8474L-017MR-0830301 8474L-017MR-0830301

8474L-017MR-0830- STRAINERS 301 8474L-017MR-0830- STRAINERS 301 8474L-017MR-0830- STRAINERS 301

A-1750

8474L-410- CHEMICAL MR-4046- INJECTION PACKAGES 001

8474L017-PID0021-111 8474L017-PID0021-112

8474L017-PID0021-111 8474L017-PID0021-111 8474L017-PID0021-111

SEKO BONO EXACTA S.p.A

8474L017-PID0021-112

BEA C TECHNOLOG IES SPA BEA C TECHNOLOG IES SPA

8474L017-PID0021-111 8474L017-PID0021-111

17

19.1

65

45

17

22.5

65

40

17

19.1

65

40

A106B + 1.5 mm CA

NI

17

19.1

65

40

A106B + 1.5 mm CA

NI

17

21.3

65

30 / 40

TP-304L

NI

17

3.500

4.000

3

CS + 1.5 mm CA

To be Designed for 1.5 kg/cm2g @ 160 degC + FV (for Steam Out Condition) Merichem Proprietary Item

NI

Merichem Proprietary Item

A106-B + 3 mm CA NI

NI

To be Designed for 1.5 kg/cm2g @ 160 degC + FV (for Steam Out Condition) Basket Material : SS 316 Merichem Proprietary Item To be Designed for 1.5 kg/cm2g @ 160 degC + FV (for Steam Out Condition) Basket Material : SS 316 Merichem Proprietary Item Basket Material : SS 316 Merichem Proprietary Item

1

3.5

4240 - OTHER FILTERS

0

F-1701A

AIR FILTER

0

F-1701B

AIR FILTER

067 R--22000 AV NO 0176-M EL 1 - ANG - rev. 2

8474L-410MR-0840- FILTERS 301 8474L-410MR-0840- FILTERS 301

17

V

0.080

0.515

1.08

19.1

70

45

TP316

0.05

Cartridge Rating : 5 Microns

17

V

0.080

0.515

1.08

19.1

70

45

TP316

0.05

Cartridge Rating : 5 Microns

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AG U A M 7 9 02

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AG U A M 7 9 02

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AG U A M 7 9 02

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AG U A M 7 9 02

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AG U A M 7 9 02

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AG U A M 7 9 02

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AG U A M 7 9 02

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AG U A M 7 9 02

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AG AU 0279-M

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AG U A M 7 9 02

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AG U A M 7 9 02

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AG U A M 7 9 02

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AG AU 0279-M

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AG U A M 7 9 02

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AG U A M 7 9 02

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AG U A M 7 9 02

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AG U A M 7 9 02

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AG U A M 7 9 02

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AG U A M 7 9 02

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AG U A M 7 9 02

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AG U A M 7 9 02

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AG U A M 7 9 02

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AG AU 0279-M

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AG U A M 7 9 02

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AG U A M 7 9 02

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AG U A M 7 9 02

_ _ _ __ RA| D __| N I ||___ 076

0 AR-2

07-M

_ _ _ __ RA| D __| N I ||___ 076

0 AR-2

07-M

_ _ _ __ RA| D __| N I ||___ 076

0 AR-2

07-M

_ _ _ __ RA| D __| N I ||___ 076

0 AR-2

07-M

_ _ _ __ RA| D __| N I ||___ 076

0 AR-2

07-M

_ _ _ __ RA| D __| N I ||___ 076

0 AR-2

07-M

_ _ _ __ RA| D __| N I ||___ 076

0 AR-2

07-M

_ _ _ __ RA| D __| N I ||___ 076

0 AR-2

07-M

_ _ _ __ RA| D __| N I ||___ 076

0 AR-2

07-M

_ _ _ __ RA| D __| N I ||___ 076

0 AR-2

07-M

_ _ _ __ RA| D __| N I ||___ 076

0 AR-2

07-M

_ _ _ __ RA| D __| N I ||___ 076

0 AR-2

07-M

_ _ _ __ RA| D __| N I ||___ 076

0 AR-2

07-M

_ _ _ __ RA| D __| N I ||___ 076

0 AR-2

07-M

_ _ _ __ RA| D __| N I ||___ 076

0 AR-2

07-M

_ _ _ __ RA| D __| N I ||___ 076

0 AR-2

07-M

_ _ _ __ RA| D __| N I ||___ 076

0 AR-2

07-M

_ _ _ __ RA| D __| N I ||___ 076

0 AR-2

07-M

_ _ _ __ RA| D __| N I ||___ 076

0 AR-2

07-M

_ _ _ __ RA| D __| N I ||___ 076

0 AR-2

07-M

_ _ _ __ RA| D __| N I ||___ 076

0 AR-2

07-M

_ _ _ __ RA| D __| N I ||___ 076

0 AR-2

07-M

_ _ _ __ RA| D __| N I ||___ 076

0 AR-2

07-M

_ _ _ __ RA| D __| N I ||___ 076

0 AR-2

07-M

_ _ _ __ RA| D __| N I ||___ 076

0 AR-2

07-M

_ _ _ __ RA| D __| N I ||___ 000067 EACR--22 D M 7 2 02

_ _ _ __ RA| D __| N I ||___ 000067 EACR--22 D M 7 02

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Hl

_ _ _ __ RA| D __| N I ||___

0077 ANR-2-20 A J M 7 5 02 ・叩−・…・仙川・−・＝・−・

THANTRATF−oRWCHITJSSPECIF［C＾LLYFURNISHEOOROUTSIDETHEEITENTOFTHEAGREEOUPONRrGHTOFUSE

DIRECTLYORUND】RECTLY．TRANSF〔RR〔D．R【PRODUCED．COPIED．DISCLOSEDORUSEDWTHOUTITSPRFORWRITTENCONSENT，FORANYPURPOSEANDINANYWAYOTHER

TH〔PRESENTDOCUMENTOROR＾㈱NGISTHEPROPERTYOFTECHNIPANDSHALLNOT．UNDERANYCIRCリMSTANCES，8ETOTALLYORPAR¶ALLY．

_ _ _ __ RA| D __| N I ||___ ・−・−・−・・−・

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_ _ _ __ RA| D __| N I ||___ 067 R--22000 AG AU 0278-M

一

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_ _ _ __ RA| D __| N I ||___ 067 R--22000 AG U A M 7 8 02

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_ _ _ __ RA| D __| N I ||___ 067 R--22000 AG U A M 7 8 02

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_ _ _ __ RA| D __| N I ||___ 000067 CATR--22 O M 7 01

DrRECTLYOR〕NDIR【CTLY，TRANSFERREO，REPROOUCED．COPトED．DISCLOSEDOR〕SEDWTHOUTITSPRORWRITTE．NCONSENT，FORANYPURPOSEANDNANYWAYOTHER

THEPR【S【NTOOCUMENTORDRAWNGSTH〔PROPERTYOFT（CHMPANDSHALLNOT．UNDERANYC】RCUNSTANCES．BETOTALLYORPARTIALしY，

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_ _ _ __ RA| D __| N I ||___ 旧

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QUA↓．≦［↓NAM

067 R--22000 AG U A M 7 8 02 トは灼

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_ _ _ __ RA| D __| N I ||___

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067 R--22000 AG U A M 7 8 02 Hl

H⊥

_ _ _ __ RA| D __| N I ||___

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067 R--22000 AG U A M 7 8 02 Hl

Hl

_ _ _ __ RA| D __| N I ||___

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_ _ _ __ RA| D __| N I ||___ 000067 CATR--22 O M 7 01

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000067 CATR--22 O M 7 01

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_ _ _ __ RA| D __| N I ||___

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_ _ _ __ RA| D __| N I ||___ 067 R--22000 AG U A M 7 8 02

067 R--22000 AG U A M 7 8 02

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_ _ _ __ RA| D __| N I ||___

_ _ _ _ _ RA| D __| N I ||___ 0067 RR--2200 A P A M 0170

_ _ _ __ RA| D __| N I ||___ 臼ヨル0人∀凡人N∀N用N∀ヨSOdヨnd人N∀ヨ0」●」N】SNO〇Nlulひ∧UO闇d5止1〔OHl州8∃Sn臼08∃SO「〇S旧一Q訓dO〇一口ヨ〇〔□0日d】辿・□】日日】」SN∀軋・人rl〇ヨ臼l□N〔臼0人1〇】ヨ旧 ‘ 人「「∀11日∀dヨ0人「「∀⊥0⊥∃8‘s∃〇N∀⊥S州∩〇臼一J人N∀臼ヨ8Nn■⊥ON「「∀＝S⊂困∀く■N＝〇弘」0人1日ヨdO凱ゴ】HIS19N州∀己＝01NヨMn〇081N】Sコ辿dコ皿

067 R--22000 AG U A M 7 8 02

_ _ _ _ _ RA| D __| N I ||___ 0067 RR--2200 A P A M 07

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ _ _ RA| D __| N I ||___ 067 R--22000 V A O N M 0270

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ _ _ RA| D __| N I ||___ 067 R--22000 V A O N M 0270

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ _ _ RA| D __| N I ||___ 067 R--22000 V A O N M 0270

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ _ _ RA| D __| N I ||___ 067 R--22000 V A O N M 0270

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ _ _ RA| D __| N I ||___ 067 R--22000 V A O N M 0270

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ _ _ RA| D __| N I ||___ 067 R--22000 V A O N M 0270

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ _ _ RA| D __| N I ||___ 067 R--22000 V A O N M 0270

_ _ _ __ RA| D __| N I ||___ 000067 EACR--22 D M 7 02

_ _ _ __ RA| D __| N I ||___ 000067 EACR--22 D M 7 02

_ _ _ __ RA| D __| N I ||___ 000067 EACR--22 D M 7 02

_ _ _ __ RA| D __| N I ||___ 000067 EACR--22 D M 7 02

_ _ _ __ RA| D __| N I ||___ 000067 EACR--22 D M 7 02

_ _ _ __ RA| D __| N I ||___ 000067 EACR--22 D M 7 02

_ _ _ __ RA| D __| N I ||___ 000067 EACR--22 D M 7 02

_ _ _ __ RA| D __| N I ||___ 000067 EACR--22 D M 7 02

_ _ _ __ RA| D __| N I ||___ 000067 EACR--22 D M 7 02

_ _ _ __ RA| D __| N I ||___ 000067 EACR--22 D M 7 02

_ _ _ __ RA| D __| N I ||___ 000067 EACR--22 D M 7 02

_ _ _ __ RA| D __| N I ||___ 000067 EACR--22 D M 7 02

_ _ _ __ RA| D __| N I ||___ 000067 EACR--22 D M 7 02

_ _ _ __ RA| D __| N I ||___ 000067 EACR--22 D M 7 02

_ _ _ __ RA| D __| N I ||___ 000067 EACR--22 D M 7 02

_ _ _ __ RA| D __| N I ||___ 000067 EACR--22 D M 7 02

_ _ _ __ RA| D __| N I ||___ 000067 EACR--22 D M 7 02

_ _ _ __ RA| D __| N I ||___ 000067 EACR--22 D M 7 02

_ _ _ __ RA| D __| N I ||___ 000067 EACR--22 D M 7 02

_ _ _ __ RA| D __| N I ||___ 000067 EACR--22 D M 7 02

_ _ _ __ RA| D __| N I ||___ 000067 EACR--22 D M 7 02

_ _ _ __ RA| D __| N I ||___ 000067 EACR--22 D M 7 0 02

_ _ _ __ RA| D __| N I ||___ 000067 EACR--22 D M 7 0 02

_ _ _ __ RA| D __| N I ||___ 000067 EACR--22 D M 7 0 02

_ _ _ __ RA| D __| N I ||___ 000067 EACR--22 D M 7 0 02

_ _ _ __ RA| D __| N I ||___ 000067 EACR--22 D M 7 02

_ _ _ __ RA| D __| N I ||___ 000067 EACR--22 D M 7 02

_ _ _ __ RA| D __| N I ||___ 000067 EACR--22 D M 7 02

_ _ _ __ RA| D __| N I ||___ 000067 EACR--22 D M 7 02

_ _ _ __ RA| D __| N I ||___ 000067 EACR--22 D M 7 02

_ _ _ __ RA| D __| N I ||___ 000067 EACR--22 D M 7 02

_ _ _ __ RA| D __| N I ||___ 000067 EACR--22 D M 7 02

_ _ _ __ RA| D __| N I ||___ 000067 EACR--22 D M 7 02

_ _ _ __ RA| D __| N I ||___ 000067 EACR--22 D M 7 02

_ _ _ __ RA| D __| N I ||___ 000067 EACR--22 D M 7 02

_ _ _ __ RA| D __| N I ||___ 000067 EACR--22 D M 7 02

_ _ _ __ RA| D __| N I ||___ 000067 EACR--22 D M 7 02

_ _ _ __ RA| D __| N I ||___ 000067 EACR--22 D M 7 02

_ _ _ __ RA| D __| N I ||___ 000067 EACR--22 D M 7 02

_ _ _ __ RA| D __| N I ||___ 000067 EACR--22 D M 7 02

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ _ _ RA| D __| N I ||___ 067 R--22000 V A O N M 0270

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV O N M 7 01

_ _ _ __ RA| D __| N I ||___ 07

0 AR-2

07-M

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV NO 027-M

_ _ _ __ RA| D __| N I ||___ 7 2-20007 JAANR0273-M

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV NO 0278-M

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV NO 0278-M

_ _ _ __ RA| D __| N I ||___ 7 --2200006 DEACR 075-M

_ _ _ __ RA| D __| N I ||___ 7 2-20007 JAANR0275-M

_ _ _ __ RA| D __| N I ||___ 7 2-20007 JAANR0275-M

_ _ _ __ RA| D __| N I ||___ 7 2-20007 JAANR0276-M

_ _ _ __ RA| D __| N I ||___ 7 --2200006 DEACR 074-M

_ _ _ __ RA| D __| N I ||___ 7 2-20007 JAANR0370-M

_ _ _ __ RA| D __| N I ||___ 7 2-20007 JAANR0179-M

_ _ _ __ RA| D __| N I ||___ 7 2-20007 JAANR0179-M

_ _ _ __ RA| D __| N I ||___ 7 2-20007 JAANR0179-M

_ _ _ __ RA| D __| N I ||___ 067 R--22000 AV NO 0175-M

_ _ _ __ RA| D __| N I ||___ 7 2-20007 FEABR072-M

_ _ _ __ RA| D __| N I ||___ 7 2-20007 JAANR0370-M

_ _ _ __ RA| D __| N I ||___ 7 2-20007 FEABR071-M

_ _ _ __ RA| D __| N I ||___ 7 2-20007 JAANR0370-M

_ _ _ __ RA| D __| N I ||___ 7 2-20007 JAANR0370-M

_ _ _ __ RA| D __| N I ||___ 0077 ANR-2-20 A J M 7 2 01

_ _ _ __ RA| D __| N I ||___ 0077 ANR-2-20 A J M 7 2 01

_ _ _ __ RA| D __| N I ||___ 0067 ANR-2-20 U J M 7 3 01

RFCC-DQ

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