Guide to Material Selection

GUIDELINE Guideline

Material Material Selection Selection

Doc Number:

Process Group

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MATERIA MATERIA L SEL SEL ECTION ECTION

B1

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Page 1 of 57

Material Material Selection Doc Number:

Revision:

3

Approval Date: Date:

24 Ju l 2009

1.0

INTRODUCTION ....................................................................................................................................... 4

2.0

AB BREVI ATIONS .................. ................. ................. .................. ................. .................. .................. .......... 4

3.0

FUNDAMENTALS OF MATERIAL SELECTION .................. ........................... ................... ................... .................. .................. .................. .................. ............ ... 5 3.1 3.2 3.3 3.4 3.5 3.6 3.7 3.8

Unall oy ed Steels .................. ........................... .................. ................... ................... .................. .................. .................. .................. ................... ................... .................. ............. .... 6 Lo w-al lo yed Steels .................. ........................... ................... ................... .................. .................. .................. .................. .................. ................... ................... .................. ........... 6 Al lo yed Steel s ......... ................. ................. .................. ................. .................. .................. ............. 6 Nick el All oy s ................. .......................... ................... ................... .................. .................. .................. ................... ................... .................. .................. .................. .................. ............ ... 7 Copp er All oy s .................. ............................ ................... .................. .................. .................. .................. ................... ................... .................. .................. .................. .................. ......... 7 Al um in um Allo Al lo ys ................. ................. ................. .................. ................. ................. .................. .. 7 Tit aniu m All oys .................. ............................ ................... .................. .................. .................. ................... ................... .................. .................. .................. .................. ............... ...... 8 Table of most commonly encountered materials ...................................................................... 9

4.0

SET-UP FOR MATERIALS SELECTION REPORTS ............................................................................ 13

5.0

MATERIAL DETERIORATION MECHANISMS ..................................................................................... 14 5.1 5.2 5.3 5.4 5.5 5.6 5.7 5.8 5.9 5.10 5.11 5.12 5.13 5.14 5.15 5.16 5.17 5.18 5.19 5.20 5.21 5.22 5.23 5.24 5.25 5.26 5.27 5.28 5.29 5.30 5.31 5.32 5.33 5.34 5.35 5.36 5.37 5.38 5.39

Overview of Corrosive Media in a Process Plant .................................................................... 14 Sulfidation or Sulfidic Corrosion .............................................................................................. 16 High temperature H2S/H2 CORROSION..................................................................................... 17 Napht heni c Aci d Cor ro si on .................. ............................ ................... .................. .................. .................. .................. .................. .................. ................... ............ .. 17 High Temper atur e Hyd ro gen Att ack ........................ ................................. ................... ................... .................. .................. .................. .................. ........... 18 Polythonic Acid Stress Corrosion Cracking ............................................................................ 19 Wet H2S Damage ......................................................................................................................... 19 Erosion-Corrosion by Ammonium Salts .................................................................................. 21 Cyani des in Sour Water .................. ........................... .................. .................. .................. .................. ................... ................... .................. .................. .................. ........... 22 Al kal in e Str ess Cor ro si on Crac ki ng (ASCC) .................. ................. .................. ................. ...... 23 Am mo ni a Str ess Cor ro si on Crac ki ng of Cop per Al lo ys ................ ................. .................. ...... 23 Crack in g by Anh yd ro us Amm on ia .................. ........................... .................. ................... ................... .................. .................. .................. .................. ........... 24 Am in e Cor ro si on ................. ................. ................. .................. ................. ................. .................. 24 Caust ic Cor ro si on .................. ........................... .................. .................. .................. .................. ................... ................... .................. .................. .................. .................. ........... 24 Potas si um Hydr ox id e Co rr os io n .......... .................... ................... .................. .................. .................. .................. .................. .................. .................. ............ ... 25 Methanol Induced Stress Corrosion of Titanium .................................................................... 25 CO2 Cor ro si on in an Aqu eous Phase .................. ........................... .................. .................. .................. .................. ................... ................... .............. ..... 26 Mercu ry Embr it tl ement ................. .......................... ................... ................... .................. .................. .................. .................. .................. ................... ................... ........... .. 28 Erosion ......................................................................................................................................... 28 CO / CO2 Str ess Cor ro si on ......................... .................................. .................. .................. .................. ................... ................... .................. .................. ................ ....... 28 Combi ned Effect o f OF CO / CO2 / H2S ..................................................................................... 28 Chlo ri de Cor ro si on ................. .......................... ................... ................... .................. .................. .................. .................. .................. ................... ................... ................. ........ 29 Seawater Cor ro si on .................. ........................... .................. .................. .................. .................. ................... ................... .................. .................. .................. ................ ....... 29 Org anic Aci d Cor ro si on .................. ............................ ................... .................. .................. .................. .................. .................. .................. ................... .................. ........ 31 Sulf ur ic Aci d Cor ro si on .................. ........................... .................. .................. .................. .................. ................... ................... .................. .................. .................. ........... 31 Hydr oc hl or ic Aci d Cor ro si on ............ ..................... .................. .................. .................. ................... ................... .................. .................. .................. ................ ....... 32 Phos ph or ic Aci d Cor ro si on ....................... ................................ .................. .................. ................... ................... .................. .................. .................. ................ ....... 33 Nit ri c Aci d Cor ro si on ....................... ................................. ................... .................. .................. .................. .................. .................. ................... ................... ................. ........ 33 Mol ten Sulp hu r .................. ........................... .................. ................... ................... .................. .................. .................. .................. .................. .................. .................. ............... ...... 33 At mo sp her ic Cor ro si on ................. ................. .................. ................. .................. ................. ...... 33 Corr osi on Under Ins ul ati on .................. ............................ ................... .................. .................. .................. .................. .................. .................. ................... ............ .. 34 Li qu id Metal Enbr it tl ement ...................... ............................... .................. .................. .................. ................... ................... .................. .................. .................. ........... 34 Lo w Temper atur e Fract ur e .................. ........................... .................. .................. ................... ................... .................. .................. .................. .................. ............. .... 35 Elevat ed Temper atur e Creep .................. ........................... .................. .................. ................... ................... .................. .................. .................. .................. ........... 35 Temper Enbr it tl ement .................. ........................... .................. .................. .................. .................. ................... ................... .................. .................. .................. ............. .... 36 Fatigue ......................................................................................................................................... 36 High Temper atur e Oxi dati on .................. ........................... .................. .................. ................... ................... .................. .................. .................. .................. ........... 37 Carbu ri zatio n .................. ........................... .................. ................... ................... .................. .................. .................. .................. .................. .................. .................. .................. ......... 37 Metal Dust in g .................. ............................ ................... .................. .................. .................. .................. ................... ................... .................. .................. .................. ................ ....... 37

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24 Ju l 2009

Fuel Ash Cor ro si on ................. .......................... ................... ................... .................. .................. .................. .................. .................. ................... ................... ................. ........ 38 Failure Failure of Dissimi lar Metal Metal Joints .............................................................................................. 38

6.0

DESCRIPTION FOR MAIN EQUIPMENT .............................................................................................. 38

7.0

DESCRIPTION FOR PIPING, INSTRUMENTATION ............................................................................. 40 7.1 7.2

Pipi ng Materi als ................. ........................... ................... .................. .................. .................. ................... ................... .................. .................. .................. .................. ............. .... 40 Specific Requirements for Instrumentation ............................................................................. 40

8.0

OTHER PROCESS DESIGN AND ENGINEERING STANDARDS ....................................................... 41

9.0

ADDITIONAL ADDITIO NAL SERVICE REQUIREMENTS REQUIREM ENTS ............... .................. ................. .................. .................. ..... 41 9.1 9.2 9.3 9.4 9.5 9.6 9.7 9.8

Typi cal Sour Servi ce Req ui remen ts .................. ........................... .................. ................... ................... .................. .................. .................. ................ ....... 41 Typi cal Hy dr og en Ind uc ed Crack in g (HIC) Requir ement s .................. ........................... ................... ................... ................. ........ 42 Typi cal Requi rem ent s f or Clad Materi al: .............. ....................... ................... ................... .................. .................. .................. .................. ............. .... 42 Typic al Requi rement s for High Strengt h Steels i n Steam Servi ce ..... ......... ........ ........ ........ ........ ........ ........ ........ ....... ... 43 Typical Fabrication Requirements for Deaerators .................................................................. 43 Typic al Design Requirem ents for Sulph ur ic Acid Service ......... ............. ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ .... 44 Typi cal PSA Syst em Requi rem ents .................. ........................... .................. .................. .................. .................. .................. .................. .................. ......... 44 Typi cal p91 Requi rem ents ................. ........................... ................... .................. .................. .................. .................. .................. .................. ................... ............... ..... 45

10.0

LGN PROJECT ENGINEERING SPECIFICATIONS ............................................................................. 50

11.0

HISTORY...................................................................................... ERROR! BOOKMARK NOT DEFINED.

12.0

REFERENCES ........................................................................................................................................ 50

13.0

TERMINOLOGY ...................................................................................................................................... 50

14.0

EXHIBITS ................................................................................................................................................ 50


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24 Ju l 2009

INTRODUCTION

This standard presents an overview of corrosion mechanisms, material degradation phenomena and material guidelines as generally encountered in oil and gas producing facilities, refineries and (petro) chemical plants. It is not intended to be complete, or give all applicable requirements, and shall be used with care. For every new job and newly prepared materials selection report, the project specifics shall be carefully studied, before parts from this standard are incorporated. The purpose of this document is to have a quick start, prevent repeating work and, most important, to get a consistent approach through all projects. 2.0

ABBREVIATIONS

The following abbreviations will be used: ASCC

Alkaline stress corrosion cracking

ASME

American Society of Mechanical Engineers

ASTM

American Society for Testing and Materials

CA

Corrosion Allowance

CE

Carbon equivalent

CI

Cast Iron

CRA

Corrosion Resistant Alloy

CS

Carbon Steel / Cast Steel

CUI

Corrosion under Insulation

DEA

Di-ethanol amine

DIPA

Di-isopropyl amine

EN

EuroNorm

EPDM

Ethylene-propylene-diene monomer rubber

FEPM

Fluorocarbon ethylene propylene monomer elastomer

FFKM

Perfluoroelastomer (Tetrafluoroethylene) (Tetrafluoroethylene)

FKM

Fluoroelastomer

GMAW

Gas Metal Arc Welding

GTAW

Gas Tungsten Arc Welding

HAZ

Heat Affected Zone

HIC

Hydrogen Induced Cracking

HTHA

High Temperature Hydrogen Attack


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3.0

IIR

Isobutene-isoprene rubber (Butyl)

LME

Liquid Metal Embrittlement

LNG

Liquefied natural gas

LPG

Liquefied petroleum gas

MDEA

Methyl-di-ethanol amine

MEA

Mono-ethanol amine

NAC

Naphthenic Acid Corrosion

NACE

National Association of Corrosion Engineers

NDT

Non Destructive Testing

PASCC

Polythionic Acid Stress Corrosion Cracking

PRE

Pitting Resistance Equivalent

PTFE

Poly-tetra-fluor ethylene

PWHT

Post weld heat treatment

SAW

Submerged Arc Welding

SCC

Stress Corrosion Cracking

SMAW

Shielded Metal Arc Welding

SOHIC

Stress Oriented Hydrogen Induced Cracking

SS

Stainless Steel

SSC

Sulfide Stress Cracking

TAN

Total Acid Number

UNS

Unified numbering system

UT

Ultrasonic Testing


24 Ju l 2009

FUNDAMENTALS OF MATERIAL SELECTION

The material selection for process units in general is determined by: a. b. c.

Pressure of the system. Temperature. Process Medium.

These operating data are given on the "process flow diagrams" and the "material balance" prepared by the Process Department. Besides these data also the mechanical design conditions (as per MDD’s) have to be checked before a

material can be selected. Main materials used in the hydrocarbon processing industry are:    

Unalloyed steels. Low-alloyed steels. Stainless steels. Nickel alloys.


Page 5 of 57

Material Selection Doc Number:

Revision:

3   

 

Approval Date:

24 Ju l 2009

Copper alloys. Aluminum alloys. Titanium alloys. Plastics. Cladded steel.

In addition to economic reasons, the selection of a material is determined by its properties, which are:    

Mechanical properties, as hardness, yield strength, tensile strength, impact strength, creep and fatigue properties. Chemical or corrosion properties, as resistance to general corrosion, pitting, crevice corrosion, stress corrosion, erosion corrosion, and corrosion fatigue. Fabrication properties, as weldability, necessity of heat treating and necessity of non-destructive testing. Physical properties, as melting point, density, thermal expansion, electrical resistance, specific heat and heat transfer coefficient.

Materials are normally selected according to ASTM or EN standards. 3.1

Unalloyed Steels Unalloyed steels (mild steel or carbon steel) are mostly applied due to the good weldability, the material strength, and its relatively cheap price.

3.2

Low-alloyed Steels For specific applications at elevated temperature, low-alloyed steels are applied. Their alloying content generally is below 5wt%. They have increased high temperature strength, resistance to creep, and resistance to oxidation. They have decreased weldability, and usually a post weld heat treatment for release of internal stresses is required. Low-alloyed steels are also applied for increased corrosion resistance in for example sulphur containing hydrocarbons.

3.3

Alloyed Steels Most commonly applied are the stainless steels with a chromium content above 12wt%. The two main classes of stainless steel are the 12%Cr ferritic or martensitic steels (AISI 400 series) and the type 18-8 austenitic stainless steels (AISI 300 series). 12%Cr steels are cheaper and stronger than the austenitic stainless steels, however they are l ess corrosion resistant and more difficult to weld. 3.3.1

AISI 400 Series Stainless Steels Wrought 12%Cr steels are mainly applied for internal parts, e.g. column trays, and should not be applied for pressure retaining components, such as pressure vessel shells. Where welding is considered, low carbon grades SS 405 or SS 410S should be considered. Cast 12%Cr steels are used for rotating equipment, valves, etc. Where welding is considered, the weldable low carbon 13Cr-4Ni grade CA6NM (UNS J91540) is preferred above the high carbon 12Cr grade CA15 (UNS J91150).

3.3.2

AISI 300 Series Stainless Steels Austenitic stainless steels are widely applied in the (petro)chemical industry where corrosive conditions are a concern. Austenitic stainless steels can also be applied for high temperatures (e.g. furnace coils) up to about 800°C and at very low temperatures (e.g. ethylene refrigerant systems) down to about -200°C.

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Austenitic stainless steels may be subject to chloride stress corrosion cracking above 65 °C. In this case, solid SS should be prevented, and instead a SS internal clad or weld overlaid construction shall be considered. For welded equipment and piping, typically the low carbon ‘L’ grades, or the chemically

stabilized grades (e.g. SS 321, 347), are specified, unless the upper design temperature restricts the use of ‘L’ grade materials.

For high temperature applications, above 450°C, it may be required to apply a high carbon ‘H’ grade for sufficient strength properties.

3.3.3

Duplex Stainless Steels An additional type of stainless steel, is duplex (ferritic / austenitic) stainless steel. The 50:50 ferrite-austenite structure gives improved corrosion and abrasion resistance together with an improved strength. Duplex SS (e.g. type 2205 or 2507) are typically used in areas where a higher resistance against chlorides is required. Alternatively, duplex SS can be applied when a higher strength is required than the AISI 300 SS have. For optimum properties the ferrite level shall be determined to be within 40-60% for the base metal, and 35-70 wt% for the weld metal and HAZ. Furthermore, the material should be essentially free of intermetallic phases.

3.3.4

Precipitation-Hardening These alloys generally contain Cr and less than 8% Ni, with other elements in small amounts. As the name implies, they are hardenable by heat treatment. PH stainless steel develop very high strength through a low-temperature heat treatment. The aging treatment produces hard, intermetallic precipitates and simultaneously tempers the martensite. The austenitic alloys must be thermally treated to transform austenite to martensite before precipitation hardening can be accomplished. Typical applications include shafts, highpressure pumps, fasteners and springs.

3.4

Nickel Alloys Nickel alloys are mainly applied when an increased corrosion resistance is required, and/or creep resistance (at high temperature) is required. Nickel alloys are resistant against strong inorganic and organic acids, alkalis, seawater, etc. There are specific types of nickel alloys for oxidizing media and for reducing media. Most types of nickel alloys contain Ni+Cr, or Ni+Cr+Mo.

3.5

Copper Alloys Copper alloys are normally applied for their good corrosion resistance, their good castability, and their excellent heat transfer properties (exchangers). They are commonly applied for water services, like brackish or seawater service. Copper alloys have a high chloride induced corrosion resistance, however are sensitive to ammonia containing media. Commonly applied types of copper alloys are brasses (Cu-Zn), bronzes (Cu-Al or Cu-Sn), and copper-nickel alloys (Cu/Ni 70-30, Cu/Ni 90-10).

3.6

Aluminum Alloys Aluminum alloys are less commonly applied, mainly due to their low strength. Common applications are for silo’s and hoppers, for prot ective sheeting (due to their good atmospheric corrosion properties and low weight) and at very low temperatures (e.g. cold boxes).


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Titanium Alloys Titanium alloys, and in a lower extent zirconium alloys, are only applied when excellent corrosion resistance is required. The major disadvantage is their high costs. Titanium alloys are mainly applied for heat exchanger tubes, for example in seawater service. Titanium has better resistance against oxidizing media, zirconium to reducing media. When there are no specific requirements, the plates, tubes, sheets, etc can be made of unalloyed Ti grade 1 or 2. For cladded plates, Ti grade 1 is normally preferred, since it is easier to form. For specific requirements, like high temperature water service (>80°C) or increased under-deposit or crevice corrosion resistance, alloyed Ti grade 12 or 7 may be required instead.


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Table of most commonly encountered materials

Name

UNS /other

Wst. nr

Brand name(s)

Composition

Remark

UNALLOYED STEELS CS

P265GH

1.0425

A285 Gr B

CS

P355NH

1.0565

A516 gr 70

LTCS

P275NL1

1.0488

A516 gr 60

General application

LOW-ALLOYED STEELS C-0.5Mo

0.5% Mo

High T strength

1Cr-0.5Mo

T12 or P12

1%Cr, 0.5%Mo

Improved creep resistance

1.25Cr-0.5Mo

T11 or P11

1.25%Cr, 0.5%Mo

Hot hydrogen resistance

2.25Cr-1Mo

T22 or P22

2.25%Cr, 1%Mo

Hot hydrogen resistance

3.5% Ni

Low temperature applications

3.5 Ni

1.5637

ALLOYED STEELS 5Cr-0.5Mo

T5 or P5

9Cr-1Mo

T9 or P9

9Cr-1Mo-V

T91 or P91

9Ni

Sulphur corrosion resist. 9%Cr-1%Mo

For heater coils SHP steam piping

1.5662

Low temperature spheres

FERRITIC/MARTENSITIC STAINLESS STEELS SS 405

UNS S40500

1.4002

13%Cr

For column trays

SS 410S

UNS S41008

1.4006

12%Cr

For column trays

SS 415

UNS S41500

1.4313

13%Cr-4%Ni

Castings, valves

SS 430

UNS S43000

1.4016

11%Cr

AUSTENITIC STAINLESS STEELS SS 304

UNS S30400

1.4301

18%Cr-8%Ni

Cryogenic service

SS 304L

UNS S30403

1.4306

18%Cr-8%Ni

Corrosive service

SS 316L

UNS S31603

1.4404

16%Cr-10%Ni- Corrosive service, 2%Mo acids

SS 321

UNS S32100

1.4541

18%Cr-10%Ni, Ti


High temperature corrosive hydrocarbons Page 9 of 57


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Name

UNS /other

Wst. nr

SS 347

UNS S34700

SS 310S

Composition

Remark

1.4550

18%Cr-10%Ni, Nb/Cb

High temperature corrosive hydrocarbons

UNS S31008

1.4842

25%Cr-21%Ni

High temperature service

SS 904L

UNS N08904

1.4539

Uranus B6 Sandvik 2RK65

20%Cr-23%Ni4.5%Mo

For organic acids

254SMO

UNS S31254

1.4547

Polarit 778

20%Cr-18%Ni- For seawater service 6%Mo-Cu

6Mo

UNS N08367

Al-6XN

20%Cr-24%Ni- For seawater service 6%Mo

25-6Mo

UNS N08926 UNS N08925

1925hMo, Incoloy 25-6Mo

20%Cr-25%Ni6%Mo-1%Cu

1.4529

Brand name(s)

24 Ju l 2009

For seawater service, caustic and acids

DUPLEX STAINLESS STEELS SS 329

UNS S32900

1.4460

28%Cr4.5%Ni1.5%Mo

Duplex 2205

UNS S31803

1.4462

SAF 2205 Uranus 45N+

22%Cr-5%Ni3%Mo

For sweet, high pressure, chloride containing media

Duplex alloy 255

UNS S32550

1.4507

Ferralium 255 Uranus 52N

25%Cr5.5%Ni3%Mo-2%Cu

For resistance to chlorides and SCC

Superduplex 2507

UNS S32750

1.4410

SAF 2507

25%Cr-7%Ni4%Mo

For seawater service without crevices

Superduplex

UNS S32760

1.4469 1.4501

Zeron 100

25%Cr-7%Ni3%Mo-Cu-W

For seawater service without crevices

For sulfuric acid, etc.

NICKEL ALLOYS Alloy 20

UNS N08020

2.4660

Carpenter 20 Nicrofer 3620

32%Ni-20%Cr2.5%Mo3.5%Cu

Alloy 28

UNS N08028

1.4563

Sanicro 28 Nicrofer 3127LC

30%Ni-27%Cr3.5%Mo-Cu

Alloy 59

UNS N06059

2.4605

Alloy 600

UNS N06600

2.4816


59%Ni-22%Cr- Resistant to mineral 15%Mo acids, chloride resistant Inconel 600, NiCr15Fe

72%Ni-15%Cr8%Fe

High temperature oxidation

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Name

UNS /other

Wst. nr

Brand name(s)

Composition

Remark

Alloy 625

UNS N06625

2.4856

Inconel 625

62%Ni-21%Cr- Highly resistant to 9%Mooxidizing acids and 3.5%Nb ClSCC

Alloy 800

UNS N08800

1.4876

Incoloy 800

30%Ni-20%Cr- Resistance to HT oxidation and 40%Fe carburization

Alloy 800H

UNS N08810

1.4958

Incoloy 800H

30%Ni-20%Cr- High creep-rupture strength 40%Fe

Alloy 825

UNS N08825

2.4858

Incoloy 825, NiCr21Mo Sanicro 41

38%Ni-21%Cr3%Mo

Resistant to acids, pitting

Alloy G-3

UNS N06985

2.4619

Hastelloy G-3

45%Ni-21%Cr19%Fe-7%Mo

For phosphoric and sulfuric acid service

Alloy C-276

UNS N10276

2.4819

Hastelloy C-276

57%Ni-15%Cr- Resistant to strong 15%Mo-5%Fe acids, oxidizers, and ClSCC

Alloy C-22

UNS N06022

2.4602

Hastelloy C-22

57%Ni-21%Cr- Resistant to strong 13%Moacids, oxidizers, and 2.5%Fe ClSCC

Alloy B-2

UNS N10665

Hastelloy B-2

68%Ni-32%Mo Resistant to reducing acids

Alloy 400

UNS N04400

2.4360

Monel 400

65%Ni30%Cu-2%Fe

For resistance to HCl, salts and seawater

COPPER ALLOYS CuNi 70/30

UNS C71500

2.0882

Cunifer 30 CuNi30Mn1Fe

69%Cu30%Ni-1%Fe

Heat exchanger tubes, Seawater pipe

CuNi 90/10

UNS C70600

2.0872

Cunifer 10 CuNi10Fe

89%Cu10%Ni-1%Fe

Heat exchanger tubes, Seawater pipe

Adm. Brass

UNS C44300

71%Cu28%Zn-1%Sn

Heat exchanger tubes

Alum-Brass

UNS C68700

77%Cu20%Zn-2%Al

Heat exchanger tubes

Bronze

UNS C93700

85%Cu, 10%Sn, 10%Pb

Valves, pumps, fittings

Si. Bronze

UNS C87200

Silicon bronze

>89%Cu, 4%Si

Valves, pumps, fittings

Al. Bronze

UNS C61400

CuAl8Fe

91%Cu-7%Al2%Fe

Seawater service

2.0932


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Name

UNS /other

Wst. nr

Ni-Al Bronze

UNS C63000 Cast: UNS C95800

2.0966 2.0975

Gun metal

UNS C90500

24 Ju l 2009

Brand name(s)

Composition

Remark

82%Cu10%Al-5%Ni3%Fe

Seawater service, Seawater pumps

Tin bronze

88%Cu10%Sn-2%Zn

valves

Al 1050A

Min. 99.5%Al

Silo’s, hoppers,

ALUMINUM ALLOYS Al 99.5

UNS A91050

3.0255

container Al-Mg2.7-Mn

UNS A95454

3.3537

Al 5454, ISO AlMg3Mn

96.4%Al, 2.7%Mg, 0.5%Mn

Silo’s, vessels,

sheeting

Al-Mn1-Cu

UNS A93003

3.0517

Al 3003, ISO AlMn1Cu

98.7%Al, 1%Mn, 0.1%Cu

Cold boxes, exchangers

Al-Mg4.5-Mn

UNS A95083

3.3547

Al 5083

94.9%Al, 4.5%Mg, 0.5%Mn

Cold boxes, cryogenics

Al-Mg5

UNS A95056

3.3355

Al 5056A

94.8%Al, 5%Mg, 0.1%Mn

Protective sheeting, vessels, marine

Al-Mg1-SiCu

UNS A96061

3.3211

Al 6061 ISO AlMg1SiCu

98%Al, 1%Mg, 0.6%Si, 0.2%Cu

Corrosion resistance, marine corrosion

TITANIUM ALLOYS Ti grade 1

UNS R50250

3.7025

Timetal 35A

Pure titanium

Clad steel in marine ind.

Ti grade 2

UNS R50400

3.7035

Timetal 50A

Pure titanium

Offshore, marine

Ti grade 3

UNS R50550

3.7055

Timetal 65A

Pure titanium

Offshore, marine

Timetal 6-4

Ti-6%Al-4%V

High strength

Timetal 50A Pd

Ti-0.2%Pd

Marine, crevice corrosion

Ti-0.2%Pd


Ti-0.3Mo-0.8Ni


Ti grade 5 Ti grade 7

UNS R52400

3.7235

Ti grade 11

UNS R52250

3.7225

Ti grade 12

UNS R53400

3.7105

Timetal code 12

In the table below, relative material costs can be determined. In the appendices, also cost ratio examples of a complex small size piping system can be viewed. Material

Cost Factor


Material

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Carbon steel

1.0

Clad alloy 600

7.0

1¼Cr-½Mo

1.3

CS, Teflon lined

7.8

2¼Cr-1Mo

1.7

Superduplex SS

7.9

5Cr-½Mo

1.9

6Mo Superaustenitic SS

8.0

Clad SS 304(L)

2.1

Clad nickel, clad 825

8.0

9Cr-1Mo

2.6

Alloy 800

8.4

SS 405 / 410

2.8

70/30 Cu/Ni

8.5

SS 304

3.2

SS 904L

8.8

SS 304L

3.3

Alloy 20

11

Clad SS 316(L)

3.3

Alloy 400 (Monel 400)

15

CS, plastic lined

3.4

Alloy 600

15

SS 316

4.0

Alloy 825

17

SS 316L

4.1

Alloy 625

26

CS, rubber lined

4.4

Titanium

28

CS, glass lined

5.8

Alloy C (Hastelloy C)

29

Duplex SS

5.8

Zirconium

34

Clad alloy 400

6.4

Alloy B (Hastelloy B)

36

90/10 Cu/Ni

6.8

Tantalum

535

Suggested material cost factors, relative to carbon steel material [API 581, Table 7-26]. Note that the cost factors may differentiate significantly over time as a result of market developments. 4.0

SET-UP FOR MATERIAL S SELECTION REPORTS

Standard set-up for a Materials Selection Report. Adjust as applicable for the project. In the introduction of the report, the following shall be mentioned as a minimum: In this materials selection report the material selection is given for mention Client & Project Name. The plant produces Name products and feed. The material selection philosophy is based on the process conditions, as indicated on the Process Flow Diagrams and in the Material Balance, and the mechanical design conditions. (Provide the document numbers and revision) The design life taken into account for the material selection of piping is 10 / 15 / 20 years, for equipment 15 / 20 / 25 years. The minimum material requirements for piping and equipment are given in the material selection report. In section 2 of the report, the applicable corrosion mechanisms are to be discussed. In section 3 and 4, the background to the material selection for main equipment items and piping are to be given.


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The complete overview of selected materials for equipment, followed by the additional service requirements, will follow in the concluding section. The selected piping materials are indicated in material selection diagrams, which are marked-up (colored) process flow diagrams. 5.0

MATERIAL DETERIORATION MECHANISMS

5.1

Overview of Corrosive Media in a Process Plant The following corrosive media are present in the plant: Select the applicable ones, and add when necessary:

  

 

 



 



Sulphur Hydrogen sulfide Naphthenic acids Ammonia Ammonium salts Cyanides Amines Carbon dioxide Chlorides Organic acids Oxygen

The presence of corrosive media and the applicable process and environmental conditions can result in different kind of deterioration mechanisms for the materials of construction. For a general impression, the following tables give a general overview of these phenomena. Table 1: Material Thinning Deterioration Mechanism

Description

Behavior

Key Variables

Examples

Galvanic Corrosion

Occurs when two metals are joined and exposed to an electrolyte.

Localised

Joined materials of construction, distance in galvanic series

Seawater and some cooling water services.

Ammonium Bisulfide Corrosion

Highly localized metal loss due to erosion corrosion in carbon steel and admiralty brass.

Localised

NH4HS % in water (Kp), velocity, pH

Formed by thermal or catalytic cracking in hydrotreating, hydrocracking, coking, catalytic cracking, amine treating and sour water effluent and gas separation systems.


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Amine Corrosion

Used in gas treatment to remove dissolved CO2 and H2S acid gases. Corrosion generally caused by desorbed acid gases or amine deterioration products.

General at low velocities, localised at high velocities

Amine type and concentration, material of construction, temperature, acid gas loading, velocity

Amine gas treating units.

Carbon Dioxide Corrosion

Carbon dioxide is a weakly acidic gas which is corrosive when dissolved in water becoming carbonic acid (H 2CO3). CO2 is commonly found in upstream units. Aqueous CO2 corrosion of carbon and low alloy steels is an electrochemical process involving the anodic dissolution of iron and the cathodic evolution of hydrogen. The reactions are often accompanied by the formation of films of FeCO3 (and/or Fe 3O4) that can be protective or nonprotective depending on the conditions.

Localised

Carbon dioxide concentration, process conditions

Refinery steam condensate system, hydrogen plant and the vapor recovery section of catalytic cracking unit.

Hydrochloric Acid corrosion

Typically causes localised corrosion in carbon and low alloy steel, particularly at initial condensation points (< 200°C). Austenitic stainless steels experience pitting and crevice corrosion. Nickel alloys can corrode under oxidizing conditions.

Localised

Acid %, pH, materials of construction, temperature

Crude unit atmospheric column overhead, Hydrotreating effluent trains, Catalytic reforming effluent and regeneration systems.

Sulfuric Acid Corrosion

Very strong acid that causes metal loss in various materials and depends on many factors.

Localised

Acid %, pH, material of construction, temperature, velocity, oxidants

Sulfuric acid alkylation units, dematerialized water.

Hydrofluoric Acid corrosion

Very strong acid that causes metal loss in various materials.

Localised

Acid %, pH, material of construction, temperature, velocity, oxidants

Hydrofluoric acid alkylation units, dematerialized water.


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Phosphoric Acid corrosion

Weak acid that causes metal loss. Generally added for biological corrosion inhibition in water treatment.

Localised

Acid %, pH, material of construction, temperature

Water treatment plants.

Phenol (carbonic acid) corrosion

Weak organic acid causing corrosion and metal loss in various alloys.

Localised

Acid %, pH, material of construction, temperature

Heavy oil and dewaxing plants.

Atmospheric Corrosion

The general corrosion process occurring under atmospheric conditions where carbon steel (Fe) is converted to iron oxide (Fe2O3).

General uniform corrosion

Presence of oxygen, temperature range and the availability of water/moisture

This process is readily apparent in high temperature processes where carbon steels have been used without protective coatings (steam piping for example).

Corrosion Under Insulation

CUI is a specific case of atmospheric corrosion where the temperatures and the concentrations of water/ moisture can be higher. Often residual/ trace corrosive elements can also be leached out of the insulation material itself creating a more corrosive environment.

General to highly localised

Presence of Insulated piping/vessels. oxygen, temperature range and the availability of water/moisture and corrosive constituents within the insulation.

Below the background is given to the most commonly encountered deterioration mechanisms, for implementation in a Materials Selection Report, as is applicable for the project. 5.2

Sulfidation or Sulfidic Corrosion (In the absence of hydrogen) High temperature sulphur corrosion (sulfidation) is a common phenomenon in the petroleum refining industry at temperatures typically above 240°C. Sulphur compounds originate with crude oils and may include poly-sulfides, mercaptans, aliphatic sulfides, etc. At elevated temperatures, these sulphur compounds react with metal surfaces forming metal sulfides. Sulphur compounds may be corrosive themselves as well as they are converted to hydrogen sulfide through thermal decomposition. Sulphur corrosion is normally in the form of uniform thinning. In case also naphthenic acids are present, corrosion can be found in the form of localised attack or erosion-corrosion. Corrosion control depends almost entirely on the formation of protective metal sulfide scales. The corrosion rate in high temperature sulfidic environments is a function of sulphur concentration (in wt%), temperature and material selected. Above 300°C the corrosion rate of carbon steel increases rapidly until around 400°C. Above 400°C the corrosion rate decreases again as a result of coke formation. The coke together with the FeS wil l form a dense, protective layer, which decreases the corrosion rate.


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The addition of chromium to steel increases its resistance to high temperature sulphidation, since the resultant corrosion scale becomes more protective. This, however, is only valid when no hydrogen is present in the process media. To predict the corrosion rates in high temperature sulfidic environments, the modified Mc Conomy curves, which apply to liquid crude oil streams, can be applied (J.Gutzeit, Process Industries Corrosion-The Theory and Practice, NACE 1986). These curves, with a correction factor for the sulphur content, are useful in the absence of naphthenic acid. More information can be found in NACE publication 34103 item number 24222 dated February 2004. In the presence of naphthenic acid, the estimated corrosion rates as tabulated in API 581, Appendix G can be applied. (If applicable) Experience for heavy hydrocarbons, as vacuum residue, however, has shown that experienced corrosion rates are generally lower than predicted ones. (If applicable) Experience for hydrocracking / isocracking units (especially units according ChevronLummusTechnology design), however, has shown that experienced corrosion rates, in cases with only traces of sulphur present, can be significantly higher than predicted ones. 5.3

High temperature H2S/H2 CORROSION (Applicable in the presence of hydrogen:) Corrosion by various sulphur compounds is a common problem above about 230°C. The presence of hydrogen, e.g. in case of hydrodesulfurising and hydrocracking operations, increases the severity of high-temperature sulphur corrosion. Hydrogen converts organic sulphur to hydrogen sulfide and corrosion becomes a function of the hydrogen sulfide concentration (or partial pressure). Medium alloys, e.g. 5Cr and 9Cr, provide limited corrosion resistance in H 2 / H 2S environments. A minimum of 12%Cr is required to provide a significant decrease in the anticipated corrosion rate. To estimate the corrosion rate in H 2 / H2S environments, the Couper - Gorman curves can be used. These curves are based on a survey conducted by the NACE Committee T-8 on refining industry corrosion. More information can be found in NACE publication 34103 item number 24222 dated February 2004.

5.4

Naphthenic Acid Corrosion Naphthenic acids are organic acids that occur naturally in many crude oils. The main acids of the naphthenic acids are saturated ring structures with a single carboxyl group. Their general formula is R (CH2)COOH, where R usually is a cyclopentane ring. The naphthenic acid content is expressed in terms of neutralization number, i.e. Total Acid Number (TAN). This TAN is determined by titration with potassium hydroxide (KOH), as described in ASTM standard test method D664 (potentiometric) or D974 (calorimetric). Naphthenic acid corrosion is only experienced at temperatures above approximately 230°C. During crude distillation, the naphthenic acids tend to concentrate in higher boiling point fractions, such as heavy atmospheric gasoil, atmospheric residue, and vacuum gasoils. The acids may also be present in vacuum residues, but often most of the naphthenic acids end up in the vacuum side streams. Corrosion may appear either as pitting or grooving. At any given temperature the corrosion rate is proportional to the T AN (a TAN value of 0.5 is normally taken as threshold value below which no special material selection requirements are applicable) . High corrosion rates can occur in carbon steel piping and equipment between 230°C and 400°C, since the formed iron naphthenics are soluble in the hydrocarbons, and thus non-protective.


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Especially high velocities and turbulence will increase the corrosion attack. Above 400°C, the naphthenic acids will either break down or distill into the vapor phase. Alloying below 12% Cr has little benefit in naphthenic acid corrosion. SS type 304L offers some resistance to naphthenic acid corrosion. However, in turbulent areas, a molybdenum containing stainless steel, e.g. SS 316L, is normally required. The amount of sulphur in the crude has some effect on the anticipated naphthenic acid corrosion. Estimated corrosion rates for a combination of sulphur and acid corrosion can be found in tables G17 to G-25 in API 581 (ed. 2000). (As applicable:) - Sulphur and naphthenic acid corrosion is most commonly experienced in atmospheric and vacuum crude distillation units and downstream systems. - In hydrotreaters, naphthenic acid corrosion is not expected downstream of the hydrogen addition point according API 571. However, plant experience has shown that naphthenic acid corrosion is not reported downstream the reactor. - In thermal crackers and delayed cokers, naphthenic acids decompose in the furnaces, and downstream normally no naphthenic acid corrosion is reported. 5.5

High Temperature Hydrogen Attack High temperature hydrogen attack (HTHA) only occurs in carbon and low-alloy steels exposed to a high partial pressure of hydrogen at elevated temperatures. Gaseous hydrogen does not easily permeate steel at normal ambient temperatures, even at high pressure. However, at elevated temperatures, formed atomic hydrogen can permeate and causes steels to crack. The damage by hot, pressurized, dry hydrogen gas is often referred to as hydrogen attack. According to the Nelson diagram as per API 941, hydrogen attack occurs only in installations with operating temperatures above approximately 230°C. The Nelson curves are based on long-term refinery experience and on results of laboratory tests. High temperature hydrogen attack has only been detected in ferritic steels: carbon steel, C- ½Mo steel and several Cr-Mo steels. Austenitic steels are considered to be resistant to hydrogen attack irrespective of temperature and hydrogen partial pressure. The Nelson diagram is not suitable for situations in which atomic hydrogen is released by a corrosion reaction, e.g. wet H 2S corrosion. In these cases the hydrogen partial pressure is unknown. The mechanism by which hydrogen attack occurs consists of the following steps:    

Dissociation of hydrogen molecules in the process gas into atomic hydrogen. Adsorption of hydrogen atoms at the metal surface. Diffusion of hydrogen atoms into the metal. Reaction of hydrogen atoms with carbon. This reaction results in methane (CH 4) molecules, especially on grain boundaries along perlite grains.

Due to the formation of methane, decarburization of the steel occurs, causing a weakening of the steel. Furthermore, the methane gas accumulates and due to its larger molecular size than hydrogen, it cannot diffuse through the metal. This causes a high internal pressure, leading to microcracks along the grain boundaries. In some cases also blistering may occur. Hot hydrogen attack can be prevented by using steels that, based on the Nelson curves, have been found to be resistant to this phenomena at the given process conditions. The following general rules are applicable to high temperature hydrogen attack. UNCONTROLL ED COPY IF PRINTED

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Carbide forming alloying elements, such as chromium, molybdenum, and vanadium, increase the resistance of steel to hydrogen attack. Increased carbon content decreases the resistance of steel to hydrogen attack. Heat-affected zones are more susceptible to hydrogen attack than the base or weld metal.

Usually low-alloy Cr-Mo steels are applied to prevent hot hydrogen attack. Another phenomenon caused by pressurized hydrogen is surface decarburization. The continuous lines in the Nelson diagram indicate whether internal decarburization will occur or not. The dashed lines are an indication for surface decarburization. The mechanism is as follows: Carbon atoms diffuse to the medium-side surface where methane is formed outside the metal. Due to the decarburization, strength and hardness will decrease while ductility increases. No internal cracks occur. As can be seen in the Nelson diagram, surface decarburization occurs at relatively low hydrogen partial pressures and high temperatures. 5.6

Polythonic Acid Stress Corrosion Cracking Polythionic acid stress corrosion cracking (PASCC) is a form of stress corrosion cracking that may occur when oxygen (air), sulphur compounds, and moisture (steam) are present. This situation generally arises during shutdown operation. Polythionic acid can cause stress cracking in sensitized austenitic materials, e.g. stainless steels type 304 and 316. Austenitic material may be sensitized to during fabrication or in-service. Sensitization occurs when the material is subject to a temperature range of 450°C to 825°C. Note: As the minimum practical sensitization temperature, 450°C is used, however, RP-01-70 mentions 370°C. Sensitization is the precipitation of chromium-rich carbides on the grain boundaries leaving a chromium depleted grain behind. Polythionic acid (H 2SxO6 where x may range from 3 to 6) is easily formed during downtime periods as a result of exposure of equipment, which normally transports sulphur-rich/H2S-rich feeds, to moisture and air. Attack only tak es place on sensitized material. To avoid sensitization, preferably stabilized stainless-steel grades like SS 321 or 347 are to be used, stabilized annealed at 843-900°C for 2 to 4 hours prior to welding. Also the application of low-carbon grades, e.g. SS 304L, can delay or avoid sensitization. For Shell projects the stabilizing heat treatment shall b e 910°C ± 10°C for 4 hour minimum for Fired Heater tubes before and again after welding (refer DEP 31.24.00.30-Gen). Polythionic acid attack can also be prevented by excluding air and moisture, or by neutralization in accordance to recommended practice as established by NACE publication RP0170, using a caustic wash, i.e. 1-2% soda ash (Na 2CO3) + 0.5% sodium nitrate. This washing action is considered not to be required when thermally stabilized SS 321 or 347 has been applied, although for reactors this is mostly executed as an extra safety precaution..

5.7

Wet H2S Damage Aqueous hydrogen sulfide corrosion (sour water corrosion) will occur at temperatures near ambient. Note: At higher temperatures, the formed corrosion product FeS is more adherent, more protective, thus lowering the H 2S activity. The NACE Publication 8X194, of June 1994, indicates that risk for sulfide stress cracking is only present between ambient and 150°C. Therefore, 150°C can be applied as a safe upper limit for wet H 2S corrosion. More background information can be found in the CLN Best Practice Tools standard PDES 04-300302.004 “Material Recommendations for Wet H2S”.

Sour water corrosion consists of the following main three types: UNCONTROLL ED COPY IF PRINTED

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

Sour water corrosion (including erosion-corrosion). Sulfide Stress Cracking (SSC). Hydrogen Induced Cracking (HIC).

5.7.1

Sour water Corrosion

 

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24 Ju l 2009

Sour water corrosion is typically a concern for carbon steel. The corrosiveness of sour water is depending on pH, temperature, velocity, and the presence of cyanides. Under low-flow conditions (v < 1.5 m/s), the corrosion rate for carbon steels at ambient temperature will be between 0.1-0.2 mm/y. In general, adequate corrosion protection is given by a corrosion allowance of 3 mm for carbon steel piping containing sour water. For hydrocarbon lines containing a small amount of sour water, a 1 mm corrosion allowance is generally sufficient. For sour water containing both hydrogen sulfides and ammonia, the corrosiveness mainly depends on the NH4HS concentration (see section 5.8 of this PDES) . 5.7.2

Sulfide Stress Cracking Sulfide stress cracking (SSC) is a form of hydrogen stress cracking resulting from the absorption of atomic hydrogen that is produced by the wet H 2S corrosion process on the metal surface. This hydrogen may diffuse to places as notches and other high-stress areas where it can contribute to crack growth. Sulfide stress cracking is defined as the cracking of a metal under the combined action of tensile stress and corrosion in the presence o f water and hydrogen sulfide. Hence, for sulfide stress cracking, a critical combination of the following factors is required:   

A hydrogen permeation flux in the steel. A total tensile stress (applied plus residual) of critical magnitude. A susceptible metallurgical condition in the steel.

SSC usually occurs in hard weld deposits or hard heat affected zones. For the steel base metal, generally SSC has not been a concern, except when metal is improperly heat-treated. The presence of as little as 1 ppm of H 2S in the water has been found to be sufficient to cause SSC. Select the applicable case: 

Prevention of SSC in Refineries

For resistance to SSC in sour petroleum refining and related processing plants, all materials exposed to wet H 2S shall fulfill the requirements as per NACE standard MR-0103. Concerning the welding of carbon steels, welds and HAZ hardnesses shall be controlled to prevent SSC as outlined in NACE standard RP-0472. For all other metals, the guidelines as outlined in NACE MR-0103 shall be followed. Since especially welds and heat-affected zones are susceptible to high hardness and stress corrosion, hardness testing shall be included in all welding procedure qualifications. Also spot checks shall be made on each piece of fabricated equipment. 

Prevention of SSC in Oil&Gas facilities

For resistance to SSC in oil & gas production sour environments, all materials exposed to the sour environment shall fulfill the requirements as per NACE standard MR-0175. Concerning welding, all welds, including HAZ’ s, shall comply with the same hardness requirements as for its base metal. Since especially welds and heat-affected zones are susceptible to high hardness and stress corrosion, hardness testing shall be included in all welding procedure qualifications. UNCONTROLL ED COPY IF PRINTED

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Hydrogen Induced Cracking (HIC) Similar to sulfide stress cracking, also hydrogen induced cracking is the result of atomic hydrogen diffusing into the material as a result of the corrosion reaction between H 2S and Fe. In this case, however, tensile stresses are not required. Furthermore, this type of corrosion affects only plate and pipe materials with elongated nonmetallic inclusions, such as MnS. Atomic hydrogen will diffuse to these inclusions and recombine to molecular hydrogen with a subsequent bigger volume. This will result in high pressures at these spots. Near the surface this will lead to blistering. In deeper zones, material separation in the form of stepwise cracking occurs. The build up of internal pressure is related to the hydrogen permeation flux in the steel, and the hydrogen permeation increase with H 2S content. A concentration of 50ppmwt H 2S has been established as the threshold value for low pH and neutral aqueous solutions, below which no hydrogen induced cracking will occur. Note: For high pH solutions, the limit for HIC to occur is much higher, and the H 2S threshold value is about 2000 ppm. To prevent hydrogen induced cracking for higher H 2S concentrations, clean and homogenous carbon steel materials shall be used, free from inclusions. Especially the presence of elongated sulfides shall be prevented. HIC failures have mainly been reported for welded pipe, not for seamless pipe. Therefore, it is recommended to use seamless ASTM A106, grade B for pipe and fine grain CS with low sulphur contents for plates. No additional requirements for forgings, castings and weld metal are necessary, since they will not contain elongated sulfides. Note: Especially for BDEP’s, when no Engineering Specificat ions are prepared yet, it is

recommended to summarize the Sour Service and HIC requirements in the MSR, under sections "sour service requirements" and "hydrogen induced cracking (HIC) requirements", see section 8 of this guideline for typical example. When a “Wet H2S” specification needs to be prepared there is a standard specification at CLN available, refer to specification SM-622 as included in PDES 04-3003-02.014 “Materials Specifications SM-621 and SM-622”. 5.7.4

Use of dissimilar metal welds (SS-CS) in wet H2S service Dissimilar metal welds (SS-CS) which are welded with a stainless steel or a nickel based alloy electrode have a chemical composition at the fusion line that may contain a small local zone with a hard martensitic microstructure. The hardness can locally be higher than 400 HV. Due to the possible high hardness, dissimilar metal welds shall not be used. Thus no welded stainless steel valves shall be installed in carbon steel lines in a wet H 2S environment.

5.8

Erosion-Corrosion by Ammonium Salts Ammonia and hydrogen sulfide gas can be released from the oil and, when cooled below 120°C, combine to ammonium bisulfide. High ammonia concentrations can saturate the process water (sour water) with ammonium bisulfide (NH 4HS) and/or ammonium chloride (NH 4Cl) and cause serious erosion-corrosion. Ammonia salts corrosion is a concern in many refining process units, notably hydrotreaters, hydrocrackers, catalytic crackers, and sour water strippers. Proper material selection, sufficient water wash injection, equal flow distribution and vel ocity considerations must be taken into account to minimize the erosion-corrosion effect.


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As stated by R.L. Piehl (see "Survey of Corrosion in Hydrocracker Effluent Air Coolers", in Material Performance 1, 1976), corrosion to carbon steels becomes severe above a concentration of 2wt% NH4HS, especially at high flow rates. Estimated corrosion rates can be found in API 581, table G-45 (ed. 2000). To minimize erosion-corrosion, the velocity in the tubes should be limited to 6 m/s. A minimum of 3 m/s is recommended, however, to minimize fouling and under deposit corrosion. Above 2wt% NH4HS, heavy wall carbon steel or corrosion resistant steels can be considered. For air cooler tubes, heavy wall carbon steel tubing can be considered wh en the chloride content is low. The header can be CS with an additional erosion-corrosion allowance of 6 mm. If besides NH 4HS, also NH4Cl is present, there is an additional risk for chloride pitting corrosion, and as a minimum duplex SS shall be applied. For NH4HS concentrations above 8wt% and/or at high velocities (~10 m/s), alloy 825, or equivalent, shall be considered. For more background information on materials of construction, ammonium salts (erosion-) corrosion, design and inspection of Reactor Effluent Aircooler (REAC) systems API RP 932-B can be consulted. 5.9

Cyanides in Sour Water Normally, in the absence of cyanides, alkalic sour water solutions cause little corrosion due to the formation of an iron sulfide film. This iron sulfide film reduces further corrosion provided that velocities are low. Dissolved hydrogen cyanide, however, accelerates the corrosion by destroying the protective FeS film and converting it into soluble ferrocyanide complexes: FeS + 6 CN- ↔ Fe(CN)6-4+S-2 Now, fresh metal is exposed to further corrosion attack. In general, the greater the bisulfide and cyanide concentrations, the greater the corrosion rate at a given pH. Contaminations such as chlorides, free oxygen, phenols and carbon dioxide can further increase the corrosiveness of the sour water. There are several options to limit cyanide corrosion, e.g.: 

Wash water:

Reduces corrosion by diluting the concentration of corrosive agents. Plant studies have shown that this method is not very effective, because it does not remove the cyanides. 

(Ammonium) polysulfide addition:

Its function is to lower corrosion rates by reducing cyanide ion concentration by the formation of thiocyanate. Its secondary role is interacting with the iron sulfide corrosion product layer to inhibit hydrogen generation. This method has, however, some disadvantages, i.e.:    

Controlling the amount of polysulfide is very difficult but crucial. High concentrations of polysulfide are required. Often there is insufficient contact time in vessels to convert all cyanides to thiocyanides. In addition wash water may be required to assure that the polysulfide stays in solution.

Note: As an indication (CLG experience), 5 times the stoichiometric quantity of polysulfides required to react with the cyanides present must be injected, with a minimum of 50-100 ppmwt polysulfides in the injection water. 

Organic filming inhibitors:

Filming inhibitors form a molecular barrier between metal surface and the alkaline sour water solution. Further, they modify the FeS film, i.e. making it more resistant to corrosion.


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Some good results have been reported, but it should be noted that application of these inhibitors is expensive and that an inhibitor is only effective in the areas it can reach. 

Using alloyed materials.

List of materials with decreasing corrosion resistance i n H 2O/NH3/H2S/HCN environments:



Zirconium or PTFE Titanium alloys Nickel alloys Alloy 400 Austenitic stainless steels Ferritic stainless steels Carbon steel Aluminum

5.9.1

Stress Corrosion

      

Another problem is that solutions containing both sulfides and cyanides have been shown to be strong crack promoting agents, especially for carbon steel. To provide SSC, NACE practice RP0472 advises to limit the hardness of carbon steel welds to 200 HB (200 HV). The pH range where cyanides have the most negative influence on corrosion performance of steel is 8 7.5). For acidic media, HCN has no influence on the corrosion behavior, and a PWHT is not required. 5.10

Alkaline Stress Corrosion Cracking (ASCC) (or Carbonate Stress Corrosion Cracking) This form of cracking is produced by the combined action of corrosion in an aqueous alkaline environment containing H 2S, CO2 and tensile stress. The cracking is branched and intergranular in nature and typically occurs in non-stress relieved steels. To minimize the risk, carbon steel welds shall receive a stress relief heat treatment. Carbonate cracking has mostly been observed in catalytic cracking units: main fractionator overhead and reflux system, the downstream wet gas compression system, and the downstream sour water systems.

5.11

Ammonia Stress Corrosion Cracking of Copper Alloys Copper base alloys can be subject to stress corrosion cracking in ammonia containing vapors and/or solutions. The rate at which this failure mechanism occurs, incubation time and crack growth, depends on many variables, such as: Internal stress levels External stress levels Specific alloy Oxygen concentration pH NH3 or NH4+ concentration Temperature


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The values of above mentioned variables are difficult to quantify. Therefore, the use of copper alloys in combination with ammonia containing media is normally avoided. 5.12

Cracking by Anhydrous Ammonia Carbon steels and low-alloy steels can be subject to stress c racking in contact with anhydrous liquid ammonia. Cracking is avoided by stress relief heat treatment or b y adding minimum 0.2 wt% water, which acts as an inhibitor in this case in the liquid phase onl y, to the ammonia. Alternatively, stainless steel can be applied. For more background information, see NACE publication 5A192 (2004 edition) “Integrity of Equipment in Anhydrous Ammonia Storage and Handling”.

5.13

Amine Corrosion Alkanol-amine solutions are widely used for the removal of H 2S and/or CO2 from acid gas since the early 1950's. It is recognized that corrosion is not caused by the amine itself, but is caused by the dissolved hydrogen sulfide and carbon dioxide gases, that are the reason of the existence of amine units. The general corrosion in amine systems is a form of thinning, which occurs on carbon steels. Carbon steel corrosion is a function of the combination of amine concentration, the acid gas loading, the temperature, fouling products, and velocities (turbulence). The most important fouling products are the amine degradation products, normally referred to as heat stable amine salts. The heat stable salts reduce the amount of active amine and cause erosion-corrosion themselves. They shall be regularly removed not to build up in large quantities. Corrosion has been found to be most severe in units removing only carbon dioxide. High velocities and turbulence can cause gas to evolve from the amine solution or disruption of protective iron sulfide films, resulting in higher, localised corrosion attack. Typically, the velocity in liquid amine streams is limited to 1.5 m/s. Austenitic stainless steels are normally applied in areas that are corrosive to carbon steel. 5.13.1 Amine stress corrosion cracking Amine stress corrosion cracking is considered a major concern in amine units. Following some catastrophes, the NACE task group T8-14 conducted a world-wide survey on stress corrosion cracking of existing amine plants (ref. API 945). The conclusion was that cracking in MEA, DEA and other amine solutions was reported for all common operating temperatures and that about 50% of the cracking cases occurred at temperatures below 65°C. Cracking occurred in all types of equipment at temperatures as low as ambient. No cracking has been reported, however, for stress-relieved piping and equipment. Therefore, all carbon steel equipment and piping in amine service shall be stress-relieved, regardless of its operating temperature. For more details on corrosion in amine treating units, see PDES 04-3003-02.008. Estimated corrosion rates can be determined with the assistance of this PDES or directly via API 581, appendix G.

5.14

Caustic Corrosion Corrosion of steels in caustic soda solutions can be divided in:  

General Corrosion Caustic Stress Corrosion Cracking


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5.14.1 General Caustic Corrosion In caustic solutions, carbon steels and low-alloy steels are slowly corroded. In general, the corrosion rate of carbon steels is less than 0.05 mm/y, since the formation of a protective oxide film protects the steel. However, several things can change the nature of the corrosion film and accelerate corrosion. This can be elevated temperature, the presence of carbon dioxide, aeration, or turbulence. Stainless steels are not corroded in caustic solutions. For elastomers, used as O-rings and other specialty seals, Viton (FKM) does not perform in caustic service and shall not be applied. As an alternative, EPDM rubber can be applied, as long as no hydrocarbons are present. 5.14.2 Caustic Stress Corrosion Cracking Caustic stress cracking of metals may occur in the presence of sodium hydroxide (NaOH) at elevated temperature. The susceptibility for carbon steels and low alloys to caustic embrittlement / stress corrosion cracking is expressed in the NACE Caustic Soda Service graph. Depending on temperature and caustic concentration, carbon steel shall be stress relieved at welds and bends to prevent embrittlement. Industry experience indicates that some caustic cracking failures occur in a few days, others after one year or more. Increasing the concentration or metal temperature accelerates the cracking rate. At high temperatures stress relieving is not sufficient to prevent cracking of CS and nickel alloy materials, such as Alloy 400, are most commonly used. Austenitic stainless steels can be applied for certain s ervices, but they are also susceptible to stress corrosion cracking at elevated temperature. Care should be taken for selection of austenitic SS in hot caustic solutions, since commercial caustic solutions are usually contaminated with chlorides. More information on Caustic Soda corrosion cracking can be found in the CLN Best Practice Tools standard PDES 04-3003-02.011. Also see NACE RP0403 – 2005 (Avoiding Caustic SCC of Carbon Steel Refinery Equipment and Piping). 5.15

Potassium Hydroxide Corrosion The corrosiveness of potassium hydroxide (KOH) is comparable to that of sodium hydroxide. At elevated temperatures it can also cause stress corrosion cracking. For elastomers, used as O-rings and other specialty seals, Viton (FKM) behaves badly in alkalic solutions and shall be avoided in KOH solutions. A suitable alternative is EPDM rubber, as long as no hydrocarbons are present.

5.16

Methanol Induced Stress Corrosion of Titanium Anhydrous methanol is unique in its ability to cause stress corrosion cracking (SCC) of titanium and titanium alloys. Industrial methanol normally contains sufficient water to provide immunity to titanium and therefore it is no problem in most practical applications. Water has an inhibiting effect. Addition of 2% water is considered sufficient to protect titanium from methanol SCC. However, the general recommendation is to have minimum 5% water content, in order to ensure effective cover for all c onditions being encountered by titanium alloys used in the offshore industry. There are 2 slightly different mechanisms concerning SCC,


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- methanol containing some halides (Cl, Br), for which pure titanium (e.g. grade 1, 2) are more susceptible - pure methanol, for which titanium alloys, e.g. grade 5 and 9, are more susceptible. 5.17

CO2 Corrosion in an Aqueous Phase In an aqueous phase containing CO 2, the CO2 will react with unalloyed and low-alloyed steels, releasing hydrogen in the process, causing a drop in the pH. Corrosion rates in these cases can be estimated using the De Waard / Milliams nomogram. De Waard, Lotz and Milliams state in their article on this subject "Predictive Model for CO 2 Corrosion Engineering in Wet Natural Gas Pipelines" in Corrosion, December 1991, that the De Waard/Milliams equation, which is the “worst case” corrosion rate prediction (V), is specified as follows:

1710 logV   58 .   0.67 * log T

P  CO2

Where T is temperature in K, and P CO2 is partial pressure of CO 2 in bara. Benefit may be drawn from the following factors: (Select only the applicable ones)     

Non-ideality of the Gas High-temperature Protective Films Contamination of the CO2 Solution with Corrosion Products Presence of Heavy Hydrocarbon Liquids Effect of Glycol

The influence of these factors can be put into the corrosion prediction formula above. If the environment contains no free water, then there is no risk of CO 2 corrosion. In gas piping, there may be a risk of condensation of water if the temperature of the line drops below the water dew point. Therefore, if possible, the piping should be insulated, or traced and insulated. Furthermore, it should be sloped and without pockets to minimize corrosion. Stainless steels as SS304(L), SS316(L) and also (lean) duplex stainless steels UNS S32001, S32304, S32205 are completely resistant against CO2 corrosion and no corrosion allowance is required. For more background information refer to the CLN Best Practice Tools standard PDES 04-300302.002 “Materials Selection Guide For CO2 Containing Oil and Gas Facilities” . 5.17.1 Non-ideality of the Gas An increase in total pressure of the gas will lead to an increase in corrosion rate. However, the increase in corrosion rate will be less than predicted b y the De Waard/Milliams equation, because the non-ideality of the gas will play an increasing role. 5.17.2 High-temperature Protective Films The precipitation of the FeCO 3 (or Fe3CO4) in itself does not necessarily result in the formation of a protective film. At low temperatures (less than 60°C) it is easily removed by flowing liquids. At higher temperatures, the film is more protective and less easily washed away. Further increase in temperature results in lower corrosion rates, which means the corrosion rate goes through a maximum (scaling temperature). At temperatures exceeding the scaling temperature, corrosion rates tend to decrease to close to zero with time. When the scale is damaged by high-speed liquid droplets in a gas UNCONTROLL ED COPY IF PRINTED

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stream (velocity > 20 m/s), the effect of the protecting scale is lost and the full corrosion rate according to De Waard / Milliams nomogram is to be expected. 5.17.3 Contamination of the CO2 Solution with Corrosion Products The contamination of the CO 2 solution with corrosion products reduces the corrosion rate. 5.17.4 Presence of Heavy Hydrocarbon Liquids The presence of crude oil can have a beneficial effect in case of CO 2 corrosion by oil-wetting the steel surfaces. However, if the flow rate of the oil is too low, water can separate and cause corrosion on the bottom of the line. The critical flow velocity is about 1 m/s. At higher flow rates the water will be kept dispersed in the oil phase. If the water cut, however, is m ore than 30 wt%, the steel surface will be water wetted and corrosion can occur again. For light hydrocarbon condensate (less than 50wt% C 5 +), water wetting and corrosion may occur at any velocity and any water content. 5.17.5 Effect of Glycol / Methanol In wet, CO2 containing gas pipelines and flow lines glycol ( or methanol) is often added to prevent hydrate formation. Glycols and methanol have a significant inhibitive effect on corrosion. The presence of glycol acts on corrosion by CO 2 in two ways:  

By reducing the corrosiveness of the water phase it mixes with. By absorbing water from the gas phase.

5.17.6 Condensation Factor Corrosion rates of unalloyed steel exposed to a condensing water phase in a CO 2 containing atmosphere quickly decreases over time. For wet gas transport piping, cooling rates and flow rates are such that condensation rates are low and the actual average corrosion rates will be approximately 1/10 of the calculated corrosion rate. 5.17.7 Corrosion Inhibition Inhibitor efficiency can be included in the corrosion model by dividing the calculated corrosion rates by an inhibition efficiency factor. If an effective inhibition can be established, the inhibitor efficiency is between 85 and 95%. This efficiency can be reached for annular mist flows, from which little condensate is formed. However, if stratified wavy flow patterns are present, surveys showed that only about 65% inhibitor efficiency in sweet gas lines was obtained. For stratified flows, it is likely that the inhibitor will be practically absent in the top of the line. Little benefit can then be expected for the top of the line corrosion rates. 5.17.8 Low pH media Besides all the factors discussed above that reduce corrosion rate, there is one factor that can increase the corrosion rate. When the actual pH is lower than the saturation pH, the corrosion rate, in the temperature range 20 - 80°C, can be a factor 2.2 to 3.3 higher, than calculated with De Waard / Milliams equation.


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Mercury Embrittlement In some natural gas receiving plants, the receipt of traces of mercury can not be excluded. This means that alloys, which are susceptible to liquid mercury, e.g. aluminum alloys and copper alloys, shall be avoided as much as possible. In case aluminum is still the preferred material of construction, it should be coated and mercury draining provisions shall be taken.

5.19

Erosion Erosion is the loss of material due to the abrasive effect of a fluid or a gas or fluid stream containing particles, like sand, salt or solids. The main factors of influence on the erosion rate are:     

Flow velocity and flow direction (impingement) Hardness and strength of the material of construction Hardness, size and geometry of solid particles Concentration of the solid particles Density and viscosity of the carrying medium

Erosion is primarily a concern in piping and equipment, where there is a change in flow direction, e.g. elbow, tee, valve, or a constriction in flow, e.g. a choke. Erosion is less of a concern in straight flow situation except in the case of a slurry. A first tool to minimize the risk of erosion in mixed phase lines is the application of API RP-14E guidelines. API RP-14E, however, does not account for solids, and incorrectly accounts for the effect of fluid density. Erosion can be divided in the following different categories: Non-corrosive, no solids present Non-corrosive, solids present Corrosive service, no solids present Corrosive service, solids present The last two categories are also described as erosion-corrosion. 5.20

CO / CO2 Stress Corrosion In an aqueous solution, at temperatures below 150°C, stress corrosion cracking may occur in carbon steel equipment, if both CO and CO 2 are present. This may happen in about any wet mixture of CO and CO2. The risk can be encountered in CO rich environments, as found in reforming gas, synthesis gas, and partial oxidation processes. SCC is most prevalent in the temperature range of 20 to 6 0°C and, due to lowering of the CO solubility in water and reduced CO adsorption onto the metal surface, cracking is unlikely to occur above 75°C. H2S in a CO / CO 2 environment has an inhibitive effect on SCC. A stress relief heat treatment (PWHT) reduces the SCC sensitivity of carbon steel. However, PWHT is not a sufficient safeguard against SCC. Stainless steels are immune to wet CO/CO 2 SCC. Stainless steels are usually also required to resist corrosion attack caused by aqueous CO 2. Hence, martensitic, austenitic, or duplex SS can be applied instead of carbon steels.

5.21

Combined Effect of OF CO / CO 2 / H2S The presence of both CO, CO 2, and H2S has some impact on the formation of the respective corrosion product layers.


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In general, the corrosion rate maintains about proportional to the CO 2 partial pressure. This means that the calculation prediction as per the CO 2 corrosion section remains the most reliable prediction tool. In CO2 / H 2S systems, the co-formation of a more protective FeS scale can make the FeCO 3 scale more stable, and hence lower the predicted corrosion r ate. At low temperatures (< 60°C), the FeS film itself is also rather unstable, and gives no protection to the FeCO3 scale. Sufficient CO can give a protective film under low wall shear stress conditions. At high temperatures (>120°C), the FeS film becomes porous and the high temperature protective FeCO3 scale may locally be disturbed, increasing the corrosion rate. 5.22

Chloride Corrosion In aqueous solutions containing chlorides, carbon steels are subject to general corrosion attack and to localized pitting corrosion. The corrosion rate of carbon steels in chloride containing oxidized aqueous solutions is fairly high. In reducing environments, the corrosion rates are lower, and also pitting corrosion is suppressed. The general corrosion rate for CS in saline water is about 0.2-0.3 mm/y. Pitting rates will be higher. For austenitic stainless steels, the limiting factors determining the suitability are chloride stress corrosion cracking (SCC), and the crevice and pitting corrosion resistance. The standard austenitic stainless steels, e.g. SS 304L, 316L, are prone to stress corrosion cracking (SCC) in chloride-bearing solutions at temperatures above 65°C. Both oxygen and water must be present along with chlorides for SCC to occur. Chloride levels required to cause SCC vary according to temperature, stress level, steel type, etc. SCC usually is found where some concentrating mechanism occurs such as crevices and vapor traps in heat exchangers around baffles. In these areas high chloride concentrations (several thousands ppm) have been found even though the nominal concentration is only a few ppm. Typically, chloride concentrations of 25 to 50 ppm are considered acceptable if no accumulation concentration of chloride is possible. However, even levels as low as 1 ppm can be hazardous if a mechanism for concentration exists. For hydrotests up to 200 ppm chlorides are acceptable, provided the vessel is flushed with demin water afterwards. It is not possible to guarantee that stainless steel will not be susceptible to SCC. Alloys containing nickel in amounts greater than 42% are immune to chloride SCC, but expensive. On the other hand, duplex SS type 2205 is resistant to ClSCC up to 100°C, and superduplex SS type 2507 up to 110°C (see NORSOK M-001), in case a high strain level is present. Other forms of chloride induced corrosion to consider are pitting and crevice corrosion. For each alloy type, there is a critical crevice and a critical pitting temperature below which these forms of attack will not occur. The resistance of an alloy to chloride pitting corrosion is given by its Pitting Resistance Equivalent (PRE) number. PRE = (% Cr) + (3.3% Mo) + (16% N)

5.23

Seawater Corrosion In general the following corrosion phenomena can occur in saline water / seawater : General corrosion Pitting and crevice corrosion


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Galvanic corrosion Erosion-corrosion Stress corrosion cracking 5.23.1 General corrosion The general corrosion rate for carbon steels in saline water / seawater will be about 0.1 - 0.3 mm/y depending on factors as salinity, oxygen content, pH, the presence of sulphur, temperature, velocity, etc. The corrosion rate increases with increasing salt content up to approximately 30,000 ppm (30 gr/l) and decreases until saturation is reached. Note that saturated brine is less corrosive than distilled water. This low corrosion rate is due to the reduced solubility of oxygen. 5.23.2 Pitting and crevice corrosion This local type of corrosion is mainly related to stainless steels exposed to aqueous chloride containing solutions, although carbon steels can also pit. At local spots the pitting rate of carbon steel can exceed the general corrosion rate. Pitting mostly occurs in stagnant areas. For stainless steels, pitting and crevice corrosion occurs under stagnant conditions and is due to a local breakdown of its passive oxide film. Such a spot becomes a small anode, which is surrounded by a large oxide covered cathodic area. Such galvanic action will introduce high corrosion rates in the pit. Furthermore, chloride concentration and oxygen depletion in the pit will introduce extra concentration cells, which again enhance the local corrosion rate. To prevent pitting corrosion a minimum velocit y of 1.5 m/s shall be maintained for stainless steel. This, however, is not possible for constructions with built-in crevices, such as flanged connections. The resistance to crevice and pitting corrosion can be increased by increasing the amount of Cr, Mo and N, as expressed in the following formula: PRE = (% Cr) + (3.3% Mo) + (16% N) A higher PRE shifts the critical temperature for pitting and crevice corrosion initiation to higher temperatures. 5.23.3 Galvanic corrosion When two different metals are joined in an electrolyte under aerated conditions, the uncoupled corrosion rate of the most active material is increased and that of the most noble material is decreased. Increased salinity will increase the electric conductivity of the water, and thus the galvanic corrosion effect. Under de-aerated conditions, galvanic corrosion can only occur in the presence of an oxidizing agent (e.g. CO 2), but the galvanic corrosion rates are significantly less than in aerated condition. Non-compatible materials shall preferably not be coupled. On the other hand, dissimilar materials can not always be prevented. As well as metal components, also some gasket materials can create galvanic problems. Non-metallic gaskets are preferred in systems subject to galvanic corrosion. Graphite gaskets should be a voided in (sea)water systems. (If applicable): A special type of galvanic corrosion is the dezincification of brass materials. This phenomena is the preferential attack of zinc-rich areas. The zinc-rich areas form a galvanic couple with areas containing less zinc. At higher pH values, as for seawater service, this effect will result in a pitting type of attack, while at lower pH values, a more uniform attack is expected. UNCONTROLL ED COPY IF PRINTED

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5.23.4 Erosion-corrosion Flow velocity has a pronounced effect on the corrosion rate of metals in saline water / seawater . For carbon steel exposed to flow rates above 1.5m/s, the corrosion rates will increase drastically. For austenitic stainless steels, pitting corrosion rates can occur under low velocities (<1.5 m/s). At average velocities corrosion rates in general are low, however, at higher velocities (>40 m/s) corrosion rates will rapidly increase due to erosion-corrosion. This latter is important for high speed pumps and control valves where high velocities can occur. In these cases, higher alloys should be used. Furthermore, it should be noted that the critical velocity for erosion-corrosion also depends on impurities such as sulphur. Copper and copper-nickel alloys, although very resistant to seawater, will experience erosion-corrosion if velocities are higher than about 3 m/s. See also the appendices to this guideline. 5.23.5 Chloride stress corrosion cracking Stress corrosion cracking in chloride containing solutions may occur for stainless steels when metallurgical structure is austenitic and temperatures rise above 65°C. Further, cast stainless steels are more resistant to SCC than wrought stainless steels. For duplex SS (type 2205) ClSCC may occur above 100°C (as per NORSOK Standard M001), for superduplex SS (type 2507) above 110°C (as per NORSOK Standard M-001). 5.24

Organic Acid Corrosion Organic acids, such as formic, acetic, propionic and benzoic acids, are weak acids, but cause corrosion to most metals. Most organic acids are neither oxidizing nor reducing to metals, hence aeration and contaminants influence the behavior to metals. The corrosiveness of organic acids depends on temperature, concentration and presence of water. Other by-products, besides water, which influence the corrosiveness are polar organic compounds, e.g. propylene glycol. They may be present as a separate phase and act as solvent for the acids. Many anhydrous organic acids can be handled by carbon steel at moderate temperatures, while diluted solutions can be highly aggressive. Carbon steel is normally not sufficiently corrosion resistant in aqueous organic acid environment. Only at very low acid concentrations and low temperatures, CS with a corrosion allowance can be used. Austenitic stainless steels are widely applied, since they are more corrosion resistant to aqueous organic acids. For lower concentrations both 304 and 316 SS can be applied up to boiling temperature of organic acids. To prevent intergranular attack of heat affected zones, low carbon grades 304L and 316L are advisable for welded constructions. Type 316 has a somewhat better resistance to concentrated acids at high temperature than type 304 SS. Contamination with chlorides, however, can have a disastrous effect. If better corrosion resistance is required, higher alloys, e.g. allo y 825, or 254 SMO can be selected.

5.25

Sulfuric Acid Corrosion Corrosion of metals in sulfuric acid (H 2SO4) is complex, since the corrosiveness of sulfuric acid varies widely and depends on many factors. The corrosiveness mostly depends on temperature and acid concentration. For carbon steels, the resistance depends on the formation of sulfate films on the


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steel surface. At low acid concentrations, the iron sulfate corrosion product readily goes into solution. At high acid concentrations, corrosion is reduced due to accumulation of soft sulfate corrosion product. This means velocity effects have a strong negative influence on the steel resistance. Steels may only be suitable at concentrations between 93-98 wt%, at ambient temperatures (< 40°C) under low flow condition (< 0.5 m/s). Stainless steels have also mixed behavior and are in general onl y applied in high acid concentration (90-100 wt%), where a stable passive corrosion behavior can be reached. The addition of molybdenum to SS increases the resistance. In general, higher alloyed materials, e.g. Alloy 20, Monel Alloy 400, or other nickel alloys are required. Aeration and impurities, especially halides, have strong effect on the corrosiveness of the acid. Aeration in general reduces corrosion of Cr-containing alloys, such as stainless steels, and accelerates corrosion of non-ferrous alloys. Anticipated corrosion rates of different materials in sulfuric acid can be found in:  

API 581, “RBI Base Resource Docum ent”, Appendix G.9 (ed. 2000). Dechema Corrosion Handbook, Volume 8, “Sulfuric acid”.

Teflon (PTFE, FEP), Kynar (PVDF), and Halar (ECTFE) are examples of sulfuric acid resistant lining materials. Coatings, in general, can only be applied for dilute sulfuric acid. One exception are hotbaked phenolic coatings, which are suitable for concentrated acid solutions also. Kalrez, Aflas, and Viton are examples of elastomer materials that may be applied for sealing rings, etc. EPDM should only be applied for sulfuric acid concentrations below 60 wt%. For sulfuric acid piping gaskets, metallic and graphite gaskets are not recommended. Mineral filled PTFE gaskets are the best solution for concentrated acid lines. For further reading on Sulfuric Acid corrosion, see PDES 04-3003-02.006. 5.26

Hydrochloric Acid Corrosion Hydrochloric acid (HCl) is corrosive to many materials of construction across a wide range of concentrations and the corrosion attack is often localised in nature, especially when it is associated with localised condensation or with the deposition of chloride containing ammonia salts. Austenitic stainless steels will often suffer pitting attack and m ay experience crevice corrosion and/or chloride stress corrosion cracking. Some of the nickel based allo ys may experience accelerated corrosion if oxidizing agents are present or if the alloys are not in the solution annealed condition. Typically, nonmetallic linings, e.g. rubber or PTFE, are applied. The primary refining units where HCl corrosion is a concern are crude distillation (see PDES 043003-02.010), hydrotreating, and catalytic reforming. (Select what is applicable:) In crude units, HCl is formed by the hydrolysis of magnesium and calcium chloride salts and results in dilute HCl in the overhead system. In hydrotreating units, HCl may form by hydrogenation of organic chlorides in the feed or can enter the unit with the hydrogen feed. HCl will condense with water in the effluent train. In catalytic reforming units, chlorides may be stripped off of the catalyst and hydrogenate resulting in HCl corrosion in the effluent train or regeneration systems. Estimated corrosion rates in dilute hydrochloric acid can be found in API 581, Tables G-12 until G15 (ed. 2000). For concentrated hydrochloric acid (typically between 27 and 37 wt%), the selection of non-metallic materials is typically the most suitable solution.


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Teflon (PTFE, FEP), Kynar (PVDF), and Halar (ECTFE) are examples of hydrochloric acid resistant lining materials. PP linings are chemically resistant up to about 65°C. Coatings that can be considered for storage tanks are vinylester and hot-bak ed phenolic coatings. Kalrez, Aflas, and Viton are examples of elastomer materials that may be applied for sealing rings, etc. EPDM and butyl rubber (IIR) should only be considered for hydrochloric acid solutions below 60°C. Neoprene and nitrile rubber seals shall not be applied. For hydrochloric acid piping gaskets, metallic and graphite gaskets are not recommended. Mineral filled PTFE gaskets are the best solution for concentrated acid lines. When metallic alloys have to be applied, Alloy B-2 (N10665) is suitable for all acid concentrations, also at elevated temperatures. Alloy C-276 (N10276) and Alloy 625 (N06625) should only be applied at moderate temperatures (ambient, 30°C max operating). 5.27

Phosphoric Acid Corrosion Phosphoric acid (H3PO4) is corrosive to steels. Austenitic stainless steels are suitable to handle phosphoric acid for full range of concentrations up to about 65°C. At elevated temperatures, type SS 316L shows a better corrosion resistance than type 304L. For elastomers, used as O-rings and other specialty seals, natural rubbers or for example NBR are not resistant against concentrated phosphoric acid, however EPDM and Viton (FKM) are suitable.

5.28

Nitric Acid Corrosion Nitric acid (HNO3) is a strong oxidizing acid. Carbon steels shall not be applied. Alloys, which form protecting oxide films, e.g. austenitic stainless steels and aluminum alloys are suitable to handle nitric acid. At ambient conditions, stainless steels can be applied up to about 95 wt% acid concentration. Aluminum alloys can only be applied for strong acid concentrations above 80 wt% at ambient conditions.

5.29

Molten Sulphur In principle molten sulphur is not corrosive to carbon steel. Only when water is also present, excessive corrosion to carbon steel might occur. A straight corrosion reaction without water (condensate) is not possible. In principle two different corrosion reactions may be active in an aqueous environment. One is a H 2S assisted corrosion process and will occur in case the amount of H 2S exceeds 10ppm. The other corrosion mechanism is a reaction involving sulphur oxide. Sulphur lines are normally steam jacketed to avoid that sulphur solidifies. Further, in a sulphurdegassing vessel (or pit) normally a steam coil is present. Such a degassing vessel shall never be operated without the steam coil; else excessive corrosion might occur to the coil and connected pumps.

5.30

Atmospheric Corrosion External corrosion is related to the atmospheric conditions, such as humidity and presence of salts. Since carbon steel will corrode due to atmospheric corrosion, a suitable coating system shall be applied. No additional corrosion allowance for external corrosion, above the specified corrosion allowances in this report, is required. Austenitic stainless steels will not corrode due to atmospheric conditions, but they are susceptible to chloride stress corrosion cracking at temperatures above 65°C.


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Since chloride and water ingress can occur under insulation, all insulated austenitic stainless steel piping and equipment, which operates above 65°C shall also be coated to minimize the risk for stress cracks. For non-insulated austenitic stainless steel piping, there is little risk for water and chloride concentration and coating is in general not required, except for some sites in marine environments with high humidity. (If applicable): Duplex stainless steels will not corrode due to atmospheric conditions, and has a high chloride resistance. Duplex stainless steel, insulated and non-insulated, do normally not require external coating. 5.31

Corrosion Under Insulation Insulated systems can be prone to corrosion under insulation (CUI). In recent years external corrosion under insulation has been a major cause for concern in contributing to unexpected failures and increasing operating costs. Corrosion of this type has been reported from plants all over the world and in many cases it has led to replacement of piping and vessels or at least substantial parts of vessels. Special attention to protection against external corrosion is required for piping and equipment, which operate below the atmospheric dew point. Unseen corrosion can occur under the insulation, and eventually cause a sudden failure. The most affected materials are externally insulated ferritic steels op erating at about -10°C to 120°C (ref. API 570, Piping Inspection Code and API 510, Pressure Vessel Inspection Code). In addition, chloride stress corrosion cracking has been reported for austenitic stainless steels under insulation. To further minimize the risk for chloride ingress under i nsulation, chloride free (< 10 ppm) insulating materials are required for stainless steel piping. A good overview of the CUI problems is given by the ASTM special technical publication 880, API 570 and by NACE RP0198. From these publications, it can be concluded that the cause of the corrosion is typically related to:   

Inadequate design. Poor installation. Lack of maintenance of the weatherproofing.

Corrosion under insulation can be prevented by applying good insulation practi ces. The insulation is to be kept dry. Adequate weatherproofing, therefore, is a must. Properly installed insulation prevents the ingress of water, however, in the course of time, sometimes small quantities of water will get through. Therefore, paint is required as part of the defense against corrosion under insulation. The application of TSA (Thermal Sprayed Aluminum) is recommended from a life cycle point of view. 5.32

Liquid Metal Enbrittlement In general, liquid metal embrittlement (LME) can be defined as a reduction in ductility and tensile strength of a solid metal in contact with a liquid metal. Sufficient tensile stresses must be present to initiate and propagate cracking. Further, for LME to occur, the need for direct contact between the liquid and the solid metal is essential. Metal oxide films, which prevent direct liquid/metal contact, can thus delay or prevent embrittlement. Experiments have shown that liquid m etal must be present at the crack tip for growth to occur. Cracking is intergranular. The occurrence of LME is different for each combination of materials. Certain combinations, which are highly susceptible to LME, are austenitic stainless steels in contact with zinc above 750°C, and steels, including stainless steels, in contact with molten aluminum.


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If applicable: For bolting, the use of cadmium plated bolts/nuts shall be restricted to 170°C, for zinc plated (galvanized) bolts/nuts, the maximum temperature is 280°C. 5.33

Low Temperature Fracture Ferritic steels undergo a ductile-to-brittle transition at some temperature below room temperature. Small changes in chemical composition, grain size, the degree of plastic constraint caused by a notch or a flaw, and even the rate at which a load is applied, can all have a marked effect on the strength, toughness and the temperature at which the ductile-to-brittle transformation occurs. The use of ferritic steels at low temperatures has to be undertaken with considerable care. In general, most metallurgical and other factors, which strengthen the material, e.g. cold work, increased alloy additions, or precipitation hardening, also lower its toughness. The only exception to this rule is the action of grain refinement as this increases both strength and toughness. Therefore, grain refinement is one of the most important methods of obtaining toughness in ferritic steels at low temperatures. This is achieved principally by increasing the manganese concentration relative to that of the carbon. The degree to which the steel is deoxidized or killed, by the addition of silicon and aluminum, is also important, fully killed steels being more ductile. Niobium and vanadium are also added to high grade steels to produce additional grain refinement, while careful control of the aluminum, nitrogen and vanadium concentrations can lead not only to enhanced grain refinement but also to precipitation hardening by their resultant nitrides and carbides. An effect similar in some respects to grain refinement is obtained by varying the microstructure in quenching and tempering treatments. The best way, however, to obtain a ferritic steel with a good low-temperature ductility is the addition of nickel as an alloying element. Various nickel alloyed steels for low-temperature service have been developed, containing up to 9% Ni. To determine if a material has sufficient ductility, a Charpy-V impact test is typically performed. For details on design code requirements for low temperature applications, see PDES 04-300302.005.

5.34

Elevated Temperature Creep Carbon steel is mostly used in non-corrosive environments up to a temperature 425°C. Although there are allowable stresses for temperatures higher than 425°C, it must be noted that prolonged exposure at these higher temperatures may result in the carbide phase of the carbon steel being converted to graphite (graphitization). The result is a weakening of the steel. Carbon steels are also increasingly affected by creep at temperatures above 400°C. Because the creep strength (for 100,000 hours) at 400°C and above rapidly decreases, unalloyed steels are normally not used above 400-425°C. Unacceptable heavy constructions would be needed. All carbide forming elements, e.g. Mo, V, and Ti, increase the resistance against creep. The fine carbides reduce deformations. Above 400°C, Mo is added; an addition of 0.5% increases creep resistance four times compared to unalloyed steels. Additions of 2 to 3% Cr to Mo steel, further increase creep resistance; higher additions decrease creep resistance again. Low-alloyed steels, e.g. 1Cr- ½Mo, 1¼Cr- ½Mo and 2¼Cr- 1Mo steels, are used from 400°C to 550°C. Above 550°C the oxidation resistance of these low-alloyed steels is too low. Up to 650°C, 5Cr-½Mo steel has still sufficient oxidation resistance, and can thus be applied instead of lower alloyed steels.


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5.35

24 Ju l 2009

Temper Enbrittlement Temper embrittlement can occur for Cr-Mo steels containing 1 to 3% chromium exposed for a prolonged time to temperatures in range the 350°C to 575°C. As a result of temper embrittlement, the ductile-to-brittle transition temperature is shifted upwards. The reduction in toughness is especially important when equipment operates at lower temperatures, such as during start-up. Temper embrittlement is caused by segregation of certain elements along grain boundaries in the steel. The phosphor and tin content are of particular importance, and their effect is worsened by silicon and manganese, which are important alloying elements. To avoid temper embrittlement, 1¼Cr-½Mo and 2¼Cr-1Mo base materials that operate in the susceptible range shall be quenched and tempered and the base metal chemistry shall typically be controlled as follows (in %wt): J-factor: (%Si + %Mn)*(%P + %Sn) x 10 4

< 100

%Cu

< 0.20

%Ni

< 0.30

%Mn + %Si

< 1.10

Also the weld metal can show tendency for embrittlement, and to control the susceptibility for the weld metal, the chemistry shall typically be controlled as follows: X-factor: (10P + 5Sb + 4Sn + As) / 100 %Mn + %Si 5.36

< 15 (in ppm) < 1.20

Fatigue Fatigue is the phenomenon of repeated or fluctuating stresses leading to fracture. The stresses are relatively low, i.e. lower than the tensile strength of the material. The fatigue life is the number of cycles that can be sustained before the component will fail. The fatigue life is depending on the stress value and the time between cycles. The repeated stress can be caused by difference in thermal expansion coefficient of connecting materials. In this case, we speak of thermal fatigue. Besides this, the repeated stress can result from rotating parts, such as i n compressors. 5.36.1 Fatigue due to Vibrations This high cycle fatigue is fatigue, which is caused by a rotational movement, which results in vibrations. High cycle fatigue is possible in compressor parts, or in other vibrating equipment. In general, compressors are vibration monitored to prevent excessive vibration and premature fatigue damage. Vibration limits shall be provided by the compressor manufacturer based on his fatigue design (amplitude, number of cycles). 5.36.2 Thermal Fatigue Thermal fatigue is fatigue under thermal cycling (low cycle fatigue). Thermal fatigue can occur for equipment and piping which operate under c yclic conditions, i.e. varying operation conditions, or frequent change over from operation mode to stand-b y situation. Thermal fatigue can also occur at areas where free expansion is no longer possible. This can be the case when sliding points or pipe hangers are defect, or when expansion bellows are plugged.


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5.37

24 Ju l 2009

High Temperature Oxidation Oxidation is the most common form of high temperature corrosion. Alloys rely on the formation of oxide film to provide corrosion resistance. Increase chromium content is the most common way to improve the oxidation resistance. Increasing the nickel content of austenitic alloys reinforces the effect of chromium on oxidation resistance. (External) oxidation can occur to CS if the temperature exceeds 500°C. For Cr-Mo alloys the starting temperature will be higher. For estimated oxidation rates, see Table G52A&B in API 581 (ed. 2000). In furnaces, the metal skin temperature of coils and coil supports should not exceed the following values to avoid severe scaling by external oxidation:

Material

Skin Temperature

Carbon steel

565 °C

1 (1.25) Cr – 0.5Mo

595 °C

2.25 Cr – 0.5Mo

625 °C

5Cr – 0.5Mo

650 °C

9Cr – 1Mo

705 °C

SS type 316, 321

870 °C

5.38

Carburization Carburization can occur when metals are exposed to carbon monoxide, methane, ethane, or other hydrocarbons at elevated temperatures. Carbon from the environment combines wi th chromium and other carbide formers present in the alloy. Carbides form within the grains and along grain boundaries. The carbides are strong and hard but very brittle. The overall effect is that the ductility is drastically reduced at temperatures up to about 500°C. Carburization also reduces oxidation resistance and creep strength. Nickel in combination with chromium is the most effecting element in controlling carburization. In addition, silicon and aluminum have a beneficial effect.

5.39

Metal Dusting Metal dusting can be seen as a form of carburization, however it differs from carburization by effect of very rapid loss of metal, and the shallow depth of carburization in advance of the metal loss. Metal dusting is mostly found in CO rich CO/CO 2/H2 environments, as found in reforming, synthesis gas, and partial oxidation processes. It typically occurs in the temperature range 480-870°C, with peak reaction rate at 700-750°C. The damage usually looks like rounded pits with a dusty surface. Metal dusting is rather unpredictable and most of the low-alloy steels, stainless steels and heat resistant alloys can be attacked. Inhibitors, if they can be added, are steam, sulphur (H 2S) or ammonia. Another cure is to adjust the gas composition and reduce the CO partial pressure.


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5.40

Approval Date:

24 Ju l 2009

Fuel Ash Corrosion Some fuels, particularly low-grade fuel oils, contain elements that can cause accelerated hightemperature corrosion in heaters and boilers. The major contaminants are vanadium and sodium. At temperatures above 650°C, vanadium oxide vapor and sodium sulfate react to form sodium vanadate, which in turn can react with metal oxides. The mechanism is further accelerated by the presence of sulphur. Sulphur contributes by sulphidation and by lowering the melting point of the vanadium oxide flux. The 50Ni-50Cr-Nb alloy is about the only alloy that can be used for hangers, tube sheets, supports, etc when the operating temperature exceeds 650°C. Else, like in reformers and ethylene furnaces, only “clean” fuels shall be used.

Concentration threshold values are not well defined. However, concentrations less than 5 ppmwt V appear to have little effect. Concentrations up to 20 ppm wt seem to be safe up to 845°C, excess of 20 ppmwt only up to about 650°C. 5.41

Failure of Dissimilar Metal Joints Joining carbon or low-alloy steel to an austenitic stainless steel in for instance a Hydrotreater unit cannot be avoided. The options for these connections are either to use dissimilar metal flanged connections or dissimilar metal welds. Both types of connection have some disadvantages. 

Disadvantage flanged connection:

The relatively great difference in thermal expansion coefficient between CS and SS has often lead to rotation of the flange resulting in flange leakage (si zes >24 inch). Also cracking of the weld overlay of the counter flange especially in the RTJ-groove of the sealing gasket is often experienced. 

Disadvantage dissimilar metal weld:

At the interface between stainless steel or nickel alloy weld metal and the carbon steel base metal, the formation of brittle phases may occur which can lead to failures. Studies indicated that, for fusion welds, the same basic metallurgical processes occur near the fusion line in the carbon or low alloy steel regardless of the weld filler metal used, i.e. stainless steel or nickel alloy. Further the relatively great difference in thermal expansion coefficient may initiate thermal fatigue cracking. It shall be recognized that both types of connections are not without risk. Therefore, the dissimilar welds should be inspected at every shutdown, as a minimum, as part of the plants normal maintenance and inspection procedures. Inspection monitoring during turnarounds using liquid penetrant examination and shear wave ultrasonic examination to verify that there are no thermal fatigue and hot hydrogen attack problems. The dissimilar metal flange connections shall be visually inspected for leakage while in service on a regular basis. If the equipment is opened, the weld overlay in the RTJ-groove of the carbon steel or low alloy steel counter flange shall be inspected by dye penetrant. Known problems with dissimilar welds are: - wet H2S service when stainless steel is welded to carbon steel. - hydrogen service when 3.5%Ni / 9%Ni steels are welded with austenitic stainless steel welding consumables. 6.0

DESCRIPTION FOR MAIN EQUIPMENT

In a materials selection report, as a minimum the following components per type of equipment shall be addressed. SHELL & TUBE HEAT EXCHANGER UNCONTROLL ED COPY IF PRINTED

Shell side Page 38 of 57


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24 Ju l 2009

Tube side (Channel) Tubes Tube sheet AIR-COOLED HEAT EXCHANGER

Header

Tubes PLATE-TYPE HEAT EXCHANGER *

End plates / Nozzles

Plates Gaskets VESSEL/COLUMN OR REACTOR

Shell

Internals, standard philosophy: For CS columns:

min. choice is:

Trays SS 410 Schoepentoeter SS 304L Mellapack

SS 304

Demister

SS 304

Grating SS 410 Internal pipes

CS

Welded-on parts, e.g. supports

CS

For SS 304L columns: min. choice is: Trays SS 304 Schoepentoeter

SS 304L

Mellapack

SS 304

Demister

SS 304

Grating SS 304 Internal pipes

SS 304L


SS 304L

For SS 316L columns: min. choice is: Trays SS 316 Schoepentoeter

SS 316L

Mellapack

SS 316

Demister

SS 316

Grating SS 316 Internal pipes UNCONTROLL ED COPY IF PRINTED

SS 316L Page 39 of 57


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24 Ju l 2009


SS 316L

COMPRESSOR/PUMP Centrifugal

Casing

Impeller Reciprocating Cylinder Piston FILTER Casing Elements (screen, basket, cartridge) EJECTOR

Casing

Nozzle/Diffuser * Concerning Plate type HE gasket materials: The gasket materials generally are available in nitrile rubber (NBR), butyl rubber (IIR), EPDM rubber, and Viton (FKM). If none of these elastomers is suitable to handle the process environment, then it shall be requested if PTFE covered gaskets are available, for e xample PTFE coated NBR or EPDM (SIGMACOAT). Otherwise, a semi-welded plate type exchanger shall be proposed to the Process Engineer. For a semiwelded plate exchanger, however, it shall be determined if the process fluid is fouling, and if special cleaning precautions have to be taken. * Concerning Plate type HE plate materials: Since the plate pack is composed of a number of very thin (0.5- 0.6 mm) corrugated heat transfer plates, the minimum to be specified material is austenitic stainless steel. Typical available plate materials are SS 316, Incoloy (alloy 825), Hastelloy (alloy C-276), and Titanium (grade 1 or 2). 7.0

DESCRIPTION FOR PIPING, INSTRUMENTATION

7.1

Piping Materials The selected materials of construction for piping will be in dicated in the materials selection diagrams / metallurgical flow diagrams, which are marked-up process flow diagrams. In the materials selection report, the materials selection is explained, specific additional requirements are highlighted, and also piping that is not on the diagrams, like utility piping, is addressed.

7.2

Specific Requirements for Instrumentation Where relevant, also the requirements for instrumentation must be addressed in the materials selection report. This is the case when for example the process service requires special materials, like high alloys or erosion/corrosion resistant internal coatings/linings, when special demands are required for the applied instrumentation, e.g. no internal pockets or full bore, or when it is anticipated that delivery times are long or costs will be high. Specific attention to materials and requirements for in strumentation is recommended in: - oil&gas piping, in erosive service due to high velocities, sand. - seawater service. - amine services, e.g. DEA, DIPA, etc. - sulfuric acid service, or other mineral acids.


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- caustic soda service. - chemical plants processing solvents, e.g. styrene, benzene. - control valves with high pressure drop. - areas where lined piping is applied, e.g. rubber-lined or PTFE lined piping. 8.0

CLN BEST PRACTICE TOOLS PROCESS DESIGN AND ENGINEERING STANDARDS

For more specific corrosion issues & materials guidelines in specific process units and process media, the following PDESs are available at CLN:

9.0

04-3003-02.002

Material Selection Guide for CO 2 containing Oil&Gas Facilities (U.D.)

04-3003-02.003

Material Selection Guide for Visbreaker Units

04-3003-02.004

Material Recommendations in wet H2S Service

04-3003-02.005

Design code aspects for low temperature applications

04-3003-02.006

Sulfuric Acid Material Selection Guide

04-3003-02.008

Material Selection Guide for Amine Units

04-3003-02.009

Material Selection Guide for Sour Water Strippers

04-3003-02.010

Material Selection Guide for Crude Distillation Overhead Systems

04-3003-02.011

Material Selection Guide for Caustic Soda

04-3003-02.013

Material Selection Guide for SSCO Units

ADDITIONAL SERVICE REQUIREMENTS

In addition to identification of the applicable material degradation mechanisms and selection of the suitable materials of construction, additional service requirements may need to be addressed in the materials selection report. The following items are normally included in a MSR prepared for BDEP. In an EPC project, these service requirements are normally included in the applicable Project (Client) engineering specifications. 9.1

Typical Sour Service Requirements Material requirements shall be as per NACE standard MR0103-2007 ( or MR0175-2003) For carbon and low-alloyed steels: 

No elements to improve machinability shall intentionally be added.



Cold deformation ≤ 5%. When outer fiber deformation is greater than 5%, steel must be



thermally stress relieved. Carbon steels shall have a maximum hardness of 22 HRC (237 HB).



For weldability, carbon steels shall have C content ≤ 0.23%, Ceq ≤ 0.43.



Weldments in carbon steels shall be as per NACE RP0472-2005.



V+Nb ≤ 0.03 wt%, Ti ≤ 0.02 wt%, B ≤ 0.0005 wt%

For austenitic stainless steels: 

Stainless steel to be in the solution annealed condition.



Hardness ≤ 22 HRC (≤ 248 HV10).



Cold deformation to enhance mechanical properties, or above 5% for formed heads and Utubes, shall be followed by a re-solution anneal heat treatment.


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9.2

24 Ju l 2009

Welds between stainless steel and carbon steel are not permitted, because these always contain local zones of high hardness. Therefore, only flanged connections shall be used.

Typical Hydrogen Induced Cracking (HIC) Requirements For CS plate: 

Vacuum treated, fine grain steels shall be applied.



S ≤ 0.002%. Alternatively: Through thickness ductility ASTM A770 -S3 (minimum 35%), or

SEL 096 Z35. For wall thickness < 15 mm (< 25 mm according to A770) testing may be executed on thicker plate of same heat. 

P ≤ 0.01%

 

US inspection for laminations as per A578 including S1, acceptance level C, or EN 10160, acceptance criteria S1 and E2. For CS pipe:



Seamless pipe material ASTM A106, grade B; S ≤ 0.01%.



For CS forgings, castings and weld metal: No additional requirements.



For CS Fittings: 

9.3

Fittings shall fulfill requirements of base material, i.e. plate, pipe or forging.

Typical Requirements for Clad Material: Cladding shall be in accordance with ASTM A264 (for SS, or A263 for 12%Cr steels, A265 for Nialloys), including shear strength test, with a minimum cladding thickness of 3 mm. Cladding shall be US tested as per ASTM A578, level S 6. Instead of an integral cladding, for equipment or part of the equipment, weld overlay may be applied. Loose liners are not acceptable. Weld overlay deposits shall be applied in two layers minimum. First layer

:

Second and other layers

AISI 309L or 309LMo SS. :

AISI 304L, 347, or 316L .

A minimum of 2 mm 304L, 347 or 316L chemical composition is required. To be checked with random chips to be removed from the actual weld overlay for wet chemical analysis of C, Cr, and Ni (for 316L also Mo). The carbon content shall be ≤ 0.035% for L -grades.

For weld overlay, the ferrite content shall be between 3 to 8% before heat treatment. Further, the weld overlay shall not contain a continuous ferrite network after heat treatment. The weld overlay shall be 100% liquid penetrant inspected. The surface shall be free of cracks. As an alternative to a two-layer weld overlay, a single weld overlay may be applied if supplier can show previous experience. A detailed description with proposed weld procedure specification, and previous weld qualification test results shall be submitted. Option for severe corrosive services: Back welding and weld overlay procedure qualifications shall be subjected to an intergranular corrosion test in accordance with ASTM A262 practice E, or DIN 50914.


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9.4

Approval Date:

24 Ju l 2009

Typical Requirements for High Strength Steels in Steam Service When a high strength steel is applied for HP boiler vessels, to apply steel (WB36) in accordance with requirements of VdTÜV 377. In addition, the following material and fabrication requirements should be included in requisition: Fabrication

Material shall be tempered at the mill in the highest temperature range, i.e. 660 - 680°C. The Post-weld heat treatment shall be executed in the temperature range of 610 - 620°C. The total heat treatment shall be simulated for each heat at the mill on a test piece, with full mechanical testing afterwards. The minimum weld preheat temperature shall be 200°C (d>30 mm) or 150°C (d 30mm). Each material heat number shall be checked for its hardness in the welded condition after post weld heat treatment. This check shall be done, on weld test plates (of same heat), which received a simulated post weld heat treatment, prior to fabrication. Weld tests are required for each welding procedure. Hardness will be checked on the side to be exposed to the steam/water environment in the HAZ and weld. A traverse shall be made as per API 582 figure 12-1. Maximum hardness ≤ 300 HV 10. The weld consumable material to be used shall be of the lowest strength still suitable. Weld materials with ultrahigh strengths shall not be used. SMAW, GTAW and SAW may be used. W elding materials shall be approved by contractor. All longitudinal and circumferential welds shall be ground flush on inside and outside to prevent crack initiation points. All nozzle attachment welds and fillet welds shall not contain notches, undercutting, etc. In general the weld quality shall be in accordance with IIS/IIW-778-83 for stringent requirements or EN 25817 class B. All corners shall be rounded off with minimum R = 5 mm. All nozzles shall in principle be welded-in. Only small size nozzles (≤ 2 inches) may be set on. For set-on nozzles the drum material shall be ordered with mechanical properties in the "Z" direction as per ASTM A770 S3 (minimum 25%) or SEL 096, güteklasse Z25, to prevent lamellar tearing. Non-destructive Testing

All weld preparations shall be magnetic particle inspected. All welds shall be 100% ultrasonic inspected after post-weld heat treatment in accordance with ASME, division 2, appendix 9.3. All welds shall be 100% magnetic particle inspected on inside and outside after h ydrotesting. Testing shall be performed wet in accordance with ASTM E709. Acceptance as per ASME VIII, division I, appendix 6.4. 9.5

Typical Fabrication Requirements for Deaerators 

Base metal and weld filler metal with minimum specified tensile strength not to exceed 460 MPa shall be specified.



Base metal shall be killed CS; C content ≤ 0.23%.



All pressure retaining welds, and internals and attachments welded to pressure retaining parts, shall be full penetration. Welds shall be ground flush. 100% MPI shall be done for part below waterline, 10% MPI for part above waterline. The deaerator shall be post weld heat treated (PWHT).

  

For more information see NACE RP0590. UNCONTROLL ED COPY IF PRINTED

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9.6

Approval Date:

24 Ju l 2009

Typical Design Requirements for Sulphuric Acid Service For Sulfuric acid concentrations of 93-98 wt%, and operating temperature below 40°C, CS can be applied, with the following restrictions:       

Velocity shall be restricted to maximum 0.50 - 0.75 m/s. Sudden changes in flow direction, turbulence, and sudden changes in velocity should be avoided. Long radius bends (5D) and elbows (1.5D) shall be applied. For branch connections, 90° tees should be avoided; 45° laterals, Y-type or sweep-in branch connections should be applied. On/off valves shall have alloy 20 trim. Control valves shall be PTFE lined. For mixing points, and points of high turbulence, PTFE lined (or Alloy 20) spool pieces shall be applied.

For piping less than 4” nominal diameter, or piping where inspection access is not possible, SS 316L

or Alloy 20 materials should be considered. 9.7

Typical PSA System Requirements Material selection for equipment in Pressure Swing Adsorption (PSA) systems is manufacturer proposal. The PSA system is subject to pressure cycles as part of the normal operating cycle. This may result in fatigue cracking, which is accelerated by the presence of hydrogen. Therefore, stress raisers should be avoided in the equipment design. Minimum design and inspection requirements for PSA vessels are:              

The design should be based on 300,000 cycles minimum, a fatigue analysis is required for nozzles and other welded attachments. Use fine grain steels, such as ASTM A516 (normalized). Do not weld internal supports to the pressure shell or if required apply full penetration welds and ground smooth afterwards. Nozzles shall be integrally reinforced types. Welds shall be dressed and contoured by grinding to prevent stress raisers. Apply PWHT. All welds shall be ground smooth (i.e. weld reinforcing < 1 mm), and free of undercut (i.e. EN 25817 class B, or equal). All corners shall be rounded off with minimum R = 5 mm. All root passes and finished welds shall be 100% magnetic particle tested on inside and outside. All welds shall be 100% radiographed or UT inspected, including nozzle attachment welds. Plates shall be free of laminations and therefore UT tested as per A578 including S1, acceptance level C (or EN 10160 level S1 E2) or equal. Weld bevels shall be 100% magnetic particle inspected. Weld peaking shall be restricted to 1.5 mm for both inward and outward. Double-sided welds shall be used. Unroundness shall be restricted to maximum of 1% of the diameter. Heads shall be without longitudinal welds and the shell shall only have one longitudinal weld. All repairs during fabrication shall be documented.


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9.8

Approval Date:

24 Ju l 2009

Typical P91 Requirements 9.8.1

Specification for Welding of Pressure Piping - Amendments to API RP582

Additional requirements specifically for P91      

      

    

9.8.2

Welding shall be with welding consumables E9015-B9-H4 / ER90S-B9 type. The application of E9018 electrodes requires prior approval from the Principal. Preheat 200°C minimum. Interpass temperature 300°C maximum. The weld shall be allowed to cool below 100°C before a PWHT. The PWHT shall be done directly after the welding and cooling. Heat input shall be monitored during welding procedure qualification and during production welding. The heat input used during production welding shall not be higher than 115% of the value recorded during PQR welding. On the Procedure Qualification Record(s) the following shall be covered. Base Material, HAZ and Weld shall adhere to the following additional requirements: Transverse Charpy impact test at 20 deg C; minimum 40J Hot yield test at 1000F (transverse). Acceptance criteria 40.2 ksi yield strength minimum Hardness maximum 290HV10, minimum hardness 200HV10 Micro examination which indicates a structure of 100% tempered martensite. The Post Weld Heat Treatment temperature shall be aimed between 745 - 760°C, but at least 15°C below the tempering temperature of the base materials (note that base m aterials have been ordered with a minimum tempering temperature of 760°C). The PWHT time shall be 2 hours minimum. The aim tempering parameter (Hollomon-Jaffe) is 20.5 - 21. This translates to min. 2.75hr@730°C. All buttwelds shall be 100%RT examined All fillet welds and branch welds 100%MT All shop and field welds shall be hardness tested by Telebrineller equipment (or equivalent). Maximum hardness is 275HBN. Minimum hardness is 190HBN. Hot bending shall be followed by a normalizing and tempering heat treatment of the entire workpiece. Local or partial heat treatment is not permitted. Pipe Specification (base materials) 9.8.2.1

Welded Pipe         

 


ASTM A691-91-52 or A691-91-42 The nitrogen content shall be 1.5 times higher than the aluminum content (N/Al> 1.5) minimum tempering temperature 760°C Supplementary Requirement S2 Impact testing with 40J@+20°C Supplementary Requirement S3 Hardness testing, maximum hardness 241HBN, minimum hardness 190HBN. Supplementary Requirement S5 Metallography, 100% tempered martensite Supplementary Requirement S7 MT of weld metal Supplementary Requirement S11 Approval required for repair welding. Hot yield test at 1000F. Acceptance criteria 40.2 ksi yield strength minimum, specimen to include base metal, HAZ and weld metal. Extent of testing shall be the same as for other mechanical tests. Welding Procedure Specifications and Procedure Qualification Records shall be submitted to Customer for review. On the Procedure Qualification Record(s) the following shall be covered. Page 45 of 57


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Base Material, HAZ and Weld shall adhere to the following additional requirements: Transverse Charpy impact test at 20 deg C; minimum 40J Hot yield test at 1000F. Acceptance criteria 40.2 ksi yield strength minimum Micro examination which indicates a structure of 100% tempered martensite. Every pipe shall be PMI checked. Acceptance of the method and equipment at the discretion of the Principal. Welded pipe shall be supplied with type 3.2 certificate to EN 10204. In case of weld repair the following shall be adhered to:

 

   

     

9.8.2.2

Seamless Pipe        

  

9.8.2.3

Repair welding shall not start until customers inspector or his representative has inspected the defect and customer has approved the repair procedure. Welding shall be with welding consumables E9015-B9-H4 / ER90S-B9 type. The application of E9018 electrodes requires prior approval from the Principal. Preheat 200°C minimum. Interpass temperature 300°C maximum. The weld shall be allowed to cool below 100°C before a Reheat treatment. Heat input shall be monitored during welding procedure qualification and during production welding. The heat input used during production welding shall not be higher than 115% of the value recorded during PQR welding. On the Procedure Qualification Record(s)the following shall be covered. Base Material, HAZ and Weld shall adhere to the following additional requirements: Transverse Charpy impact test at 20 deg C; minimum 40J Hot yield test at 1000F. Acceptance criteria 40.2 ksi yield strength minimum Hardness maximum 290HV10, hardness minimum 200HV10 Micro examination which indicates a structure of 100% tempered martensite. ASTM A335-P91 The nitrogen content shall be 1.5 times higher than the aluminum content (N/Al> 1.5) minimum tempering temperature 760°C pipes shall be hydrotested and UT examined Supplementary Requirement S5 Metallography, 100% tempered martensite Hot yield test at 1000F. Acceptance criteria 40.2 ksi yield strength minimum. Extent of testing shall be the same as for other mechanical tests. Transverse impact test 40J@+20°C. Extent of testing shall be the same as for other mechanical tests. Any repair welding is not permitted without prior approval from Contractor. In that case Welding Procedure Specifications and Procedure Qualification Records shall be submitted to Contractor for review. Every pipe shall be PMI checked. Acceptance of the method and equipment at the discretion of the Principal. Pipe shall be supplied with type 3.2 certificate to EN 10204. Hardness shall be tested on minimum one (1) pipe per charge and per size. Minimum hardness 190 HBN.

Seamless Fittings


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9.8.2.4

Approval Date:

24 Ju l 2009

ASTM A234-WP91 The nitrogen content shall be 1.5 times higher than the aluminum content (N/Al> 1.5) Minimum tempering temperature 760°C Fittings shall be ordered with 100%PT for 10% of the fittings as per ASTM E165. Acceptance criteria as per ASME VIII div 1. Transverse Charpy impact test at 20 deg C; minimum 40J Hot yield test at 1000F. Acceptance criteria 40.2 ksi yield strength minimum Extent of testing shall be the same as for other mechanical tests. Micro examination which indicates a structure of 100% tempered martensite. Hardness shall be tested on minimum 1 per charge and per size. Maximum hardness 248HBN, minimum hardness 190HBN. Every fitting shall be PMI checked. Acceptance of the method and equipment at the discretion of the Principal. Fitting shall be supplied with type 3.2 certificate to EN 10204.

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ASTM A234-WP91 The nitrogen content shall be 1.5 times higher than the aluminum content (N/Al> 1.5) Minimum tempering temperature 760°C Fittings shall be ordered with 100%PT for 10% of the fittings as per ASTM E165. Acceptance criteria as per ASME VIII div 1. Transverse Charpy impact test at 20 deg C; minimum 40J Hot yield test at 1000F. Acceptance criteria 40.2 ksi yield strength minimum. Specimen to include base metal, HAZ and weld metal. Extent of testing shall be the same as for other mechanical tests. Micro examination which indicates a structure of 100% tempered martensite. Hardness shall be tested on minimum 1 per charge and per size. Maximum hardness 248HBN, minimum hardness 190HBN. Every fitting shall be PMI checked. Acceptance of the method and equipment at the discretion of the Principal. Welding shall be with welding consumables E9015-B9-H4 / ER90S-B9 type. The application of E9018 electrodes requires prior approval from the Principal. Preheat 200°C minimum. Interpass temperature 300°C maximum. Before PWHT the weld shall be allowed to cool below 100°C. Heat input shall be monitored. The heat input used during production welding shall not be higher than 115% of the value recorded during PQR welding. Welding Procedure Specifications and Procedure Qualification Records shall be submitted to Contractor for review. On the Procedure Qualification Record(s) the following shall be covered. Base Material, HAZ and Weld shall adhere to the following additional requirements: Transverse Charpy impact test at 20 deg C; minimum 40J Hot yield test at 1000F. Acceptance criteria 40.2 ksi yield strength minimum Micro examination which indicates a structure of 100% tempered martensite. Page 47 of 57


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Hardness maximum 290HV10, hardness minimum 200HV10

In case of weld repair after tempering the following shall be adhered to:  

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9.8.3

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9.8.4

Repair welding shall not start until customers inspector or his representative has inspected the defect and customer has approved the repair procedure. Welding shall be with welding consumables E9015-B9-H4 / ER90S-B9 type. The application of E9018 electrodes requires prior approval from the Principal. Preheat 200°C minimum. Interpass temperature 300°C maximum. The weld shall be allowed to cool below 100°C before a PWHT. Heat input shall be monitored during welding procedure qualification and during production welding. The heat input used during production welding shall not be higher than 115% of the value recorded during PQR welding. On the Procedure Qualification Record(s)the following shall be covered. Base Material, HAZ and Weld shall adhere to the following additional requirements: Transverse Charpy impact test at 20 deg C; minimum 40J Hot yield test at 1000F. Acceptance criteria 40.2 ksi yield strength minimum Hardness maximum 290HV10, hardness minimum 200HV10 Micro examination which indicates a structure of 100% tempered martensite. The Post Weld Heat Treatment temperature shall be between 730 - 760°C, but at least 15°C below the tempering temperature of the base materials

ASTM A182 F91 The nitrogen content shall be 1.5 times higher than the aluminum content (N/Al> 1.5) Minimum tempering temperature 760°C Forgings shall be ordered with 100%PT for 10% of the fittings as per ASTM E165. Acceptance criteria as per ASME VIII di v 1. Hardness shall be tested on minimum 1 per charge and per size. Maximum hardness 248HBN, minimum hardness 190HBN. Any repair welding is not permitted without prior approval from Contractor. In that case Welding Procedure Specifications and Procedure Qualification Records shall be submitted to Contractor for review. Hot yield test at 1000F. Acceptance criteria 40.2 ksi yield strength minimum. Extent of testing shall be the same as for tension tests required by A182. Transverse impact test 40J@+20°C. Extent of testing shall be the same as for tension tests required by A182. Micro examination which indicates a structure of 100% tempered martensite. Extent of testing shall be the same as for tension tests required by A182. Every forging shall be PMI checked. Acceptance of the method and equipment at the discretion of the Principal.

Castings   

ASTM A217-C12A The nitrogen content shall be 1.5 times higher than the aluminum content (N/Al> 1.5) Minimum tempering temperature 760°C


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24 Ju l 2009

A703 S4 Magnetic Particle Inspection as per ASME B16.34 for Special Class Valves. Radiographic Examination as per ASME B16.34 for Special Class Valves. A703 S8 Charpy Impact Testing at 20 deg C; minimum 40J A703 S13 Hardness Testing, Maximum hardness 248HBN, minimum hardness 175HBN. A703 S10 Examination of Weld Preparation. A703 S14 Tension test from each heat and heat treatment charge. A703 S21 Heat Treatment Furnace Record A703 S22 Mandatory Post Weld heat treatment (of repair welds).The Post Weld Heat Treatment temperature shall be aimed between 745 - 760°C, but at least 15°C below the tempering temperature of the base materials Hot yield test at 1000F. Acceptance criteria 40.2 ksi yield strength minimum. Extent of testing shall be the same as for tension tests required by A703 S14. Every casting shall be PMI checked. Acceptance of the method and equipment at the discretion of the Principal. For every weld repair Welding Procedure Specifications and Procedure Qualification Records shall be submitted to Contractor fo r review.

In case of weld repair the following shall be adhered to:     

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Welding shall be with welding consumables E9015-B9-H4 / ER90S-B9 type. The application of E9018 electrodes requires prior approval from the Principal. Preheat 200°C minimum. Interpass temperature 300°C maximum. The weld shall be allowed to cool below 100°C before a PWHT. Heat input shall be monitored during welding procedure qualification and during production welding. The heat input used during production welding shall not be higher than 115% of the value recorded during PQR welding. On the Procedure Qualification Record(s)the following shall be covered: Base Material, HAZ and Weld shall adhere to the following additional requirements: Transverse Charpy impact test at 20 deg C; minimum 40J Hot yield test at 1000F. Acceptance criteria 40.2 ksi yield strength minimum Hardness maximum 290HV10, hardness minimum 200HV10 Micro examination which indicates a structure of 100% tempered martensite.


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APPENDIX 1 BASIC MATERIAL TESTING - THEORY

Tests are developed to check whether a certain material has the required properties. These properties include strength, toughness, hardness etcetera. Tensile test

A tensile test measures the resistance of a material to a static or slowly applied force. Ultimate tensile strength (UTS), often shortened to tensile strength (TS) or ultimate strength, is the m aximum stress that a material can withstand before necking, which is when the specimen's cross-section starts to significantly contract. The UTS is usually found by performing a tensile test and recording the stress versus strain; the highest point of the stressstrain curve is the UTS. It is an intensive property, therefore its value does not de pend on the size of the test specimen. However, it is dependent on other factors, such as the preparation of the specimen and the temperature of the test environment and material. Tensile strength is defined as a stress, which is measured as force per unit area. In the SI system, the unit is pascal (Pa) or, equivalently, newtons per square meter (N/m²). The customary unit is pounds-force per square inch (lbf/in² or psi), or kilo-pounds per square inch (ksi), which is equal to 1000 psi; kilo-pounds per square inch are commonly used for convenience when measuring tensile strengths. Many materials display linear elastic behavior, defined by a linear stress-strain relationship, as shown in appendix 2, in which deformations are completely recoverable upon removal of the load - that is, a specimen loaded elastically in tension will elongate, but will return to its original shape and size when unloaded. Be yond this linear region, for ductile materials, such as steel, deformations are plastic. A plastically deformed specimen will not return to its original size and shape when unloaded. Note that there will be elastic recovery of a portion of the deformation. For many applications, plastic deformation is unacceptable, and is used as the design limitation. After the yield point, ductile metals will undergo a period of strain hardening, in which the stress increases again with increasing strain, and they begin to neck, as the cross-sectional area of the specimen decreases due to plastic flow. In a sufficiently ductile material, when necking becomes substantial, it causes a reversal of the engineering stress-strain curve (curve A); this is because the engineering stress is calculated assuming the original cross sectional area before necking. The reversal point is the maximum stress on the engineering stress-strain curve, and the engineering stress coordinate of this point is the tensile ultimate strength, given by point 1. Tensile testing, also known as tension testing, is a fundamental materials science test in which a sample is subjected to uniaxial tension until failure. The results from the test are commonly used to select a material for an application, for quality control, and to predict how a material will react under other types of forces. Properties that are directly measured via a tensile test are ultimate tensile strength, maximum elongation and reduction in area. A tensile specimen is a standardized sample cross-section. It has two shoulders and a gage section in between. The shoulders are large so they can be readily gripped, where as the gage section has a smaller cross-section so that the deformation and failure can occur in this area. Impact test (Charpy im pact test)

The Charpy impact test, also known as the Charpy v-notch test, is a standardized high strain-rate test which determines the amount of energy absorbed by a m aterial during fracture. This absorbed energy is a measure of a given material's toughness and acts as a tool to study temperature-dependent brittle-ductile transition. It is widel y applied in industry, since it is easy to prepare and conduct and results can be obtained quickly and cheaply. But a major disadvantage is that all results are only comparative. The apparatus consists of a pendulum axe swinging at a notched sample of material, see appendix 3. The energy transferred to the material can be inferred by comparing t he difference in the height of the hammer before and after a big fracture. UNCONTROLL ED COPY IF PRINTED

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The notch in the sample affects the results of the impact test, thus it is necessary for the notch to be of a regular dimensions and geometry. The size of the sample can also affect results, since the dimensions determine whether or not the material is in plane strain. This difference can greatly affect conclusions made. The "Standard methods for Notched Bar Impact Testing of Metallic Materials" can be found in ASTM E23, ISO 1481 or EN 10045-1, where all the aspects of the test and equipment used are described in detail. Hardness test

Hardness is the property of a material that enables it to resist plastic deformation, usually b y penetration. Hardness is not an intrinsic material property dictated by precise definitions in terms of fundamental units of mass, length and time. A hardness property value is the result of a defined measurement procedure. The usual method to achieve a hardness value is to measure the depth or area of an indentation left by an indenter of a specific shape, with a specific force applied for a specific time. There are three principal standard test methods for expressing the relationship between hardness and the size of the impression, these being (see appendix 4 and 5): - Brinell (round, hardened steel ball), Vickers (four sided diamant pyramid), and - Rockwell (coned diamant). Each method has its pros and cons, being: - Brinell is most suitable for softer materials, e.g. carbon steels. However, this method is time consuming and leaves relative large indentations; - Rockwell is most suitable for hard materials and large amount of measurements (fast measurements possible) - Vickers is the most exact measurement, but requires well prepared (polished) surface. For production hardness measurements on equipment and piping there ar e portable hardness measurement devices available. In the old days this was the Poldi hammer. Nowadays the Telebrineller and Microdur are applied. The Equotip shall normally not be used. Creep Test

Creep occurs under load at high temperature. Boilers, gas turbine engines, and ovens are some of the systems that have components that experience creep. An understanding of high temperature materials behavior is beneficial in evaluating failures in these types of systems. High temperature progressive deformation of a material at constant stress is called creep. High temperature is a relative term that is dependent on the materials being evaluated. A typical creep curve is shown in appendix 6. In a creep test a constant load is applied to a tensile specimen maintained at a constant temperature. Strain is then measured over a period of time. The slope of the curve, identified in appendix 6, is the strain rate of the test during stage II or the creep rate of the material. Primary creep, Stage I, is a period of decreasing creep rate. Primary creep is a period of primarily transient creep. During this period deformation takes place and the resistance to creep increases until stage II. Secondary creep, Stage II, is a period of roughly constant creep rate. Stage II is referred to as steady state creep. Tertiary creep, Stage III, occurs when there is a reduction in cross sectional area due to necking or effective reduction in area due to internal void formation. Stress Rupture Stress rupture testing is similar to creep testing except that the stresses used are higher than in a creep test. Stress rupture testing is always done until failure of the material. In creep testing the main goal is to determine the UNCONTROLL ED COPY IF PRINTED

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minimum creep rate in stage II. Once a designer knows the materials will creep and has accounted for this deformation a primary goal is to avoid failure of the component. Non Destruct ive Testing

Next to the mechanical destructive testing, which give the suitability of a material for a certain application, also the fabrication method needs to be verified. This shall be done without damaging the product (i.e. non destructive testing). The most well known non destructive testing methods are: a- Liquid Dye Penetrant Testing (PT) b- Magnetic Particle Testing (MT) c- Radiographic examination (RT) d- Ultrasonic Testing (UT) All these methods aim to check for material flaws, which occur due to rolling, casting, welding, heat treatments etc. The usability of the non destructive testing methods depends on the construction and its m aterial of construction. For example it is very difficult to do UT on stainless steel welds. Non ferrous materials cannot be magnetic particle tested. Ultrasonic Inspection (UT) Ultrasonic inspection use beams of sound waves (vibrations) of short wavelength and high frequency, transmitted from a probe and detected by the same or other probes. Usually, pulsed beams of ultrasound are used and in the simplest instruments a single probe, hand held, is placed on the specimen surface. An oscilloscope display with a time base shows the time it takes for an ultrasonic pulse to travel to a reflector (a flaw, the back surface or other free surface) in terms of distance traveled across the os cilloscope screen. The height of the reflected pulse is related to the flaw size as seen from the transmitter probe. The relationship of flaw size, distance and reflectivity are complex, and a considerable skill is required to interpret the display. Comple x mutiprobe systems are also used with mechanical probe movement and digitization of signals, followed by computer interpretation are developing rapidly. Ultrasonic examinations are performed for the detection and sizing of internal defects, flaws or discontinuities in piping, castings, forgings, weldments or other components. Exact sizing techniques ha ve been developed to detect and monitor progressive cracking in a variety of equipment. Liquid Penetrant Examination (PT) This method employs a penetrating liquid, which is applied over the surface of the component and enters the discontinuity or crack. Subsequently, after the excess penetrant has been cleared from the surface, the penetrant is drawn back out of the crack to make the crack visible. Liquid penetrant testing can be applied to any non-porous clean material, metallic or non-metallic, but is unsuitable for dirty or very rough surfaces. Penetrants can contain a dye to make the indication visible under white light, or a fluorescent material that fluoresces under suitable ultraviolet light. Fluorescent penetrants are usually used when the maximum flaw sensitivity is required. Magnetic Particle Testing (MT) The Magnetic Particle testing is a method for locating surface and sub-surface discontinuities in ferromagnetic material. It depends for its operation on the fact that when the material or part under test is magnetized, discontinuities that lie in a direction generally transverse to the direction of the magnetic field, will cause a leakage field. And therefore, the presence of the discontinuity is detected by use of finely divided ferromagnetic particles applied over the surface. Some of these particles are being gathered and held by the leakage field. This magnetically held collection of particles forms an outline of the discontinuity and indicates its location, size, shape and extent.


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Guide to Material Selection

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