258 Colibasi Drilling Program FINAL

Table of Contents 1

WELL OBJECTIVES .......................................................................................................4 1.1

Key Performance Indicators (KPIs)

4

1.2

AFE MD vs Days and MD vs Expenditure

5

2

COMMITMENTS ..............................................................................................................7

3

CONTACT LIST ...............................................................................................................9

4

SURFACE AND TARGET LOCATIONS ........................................................................ 10 4.1

5

258 Colibasi Structural Surface locations

11

RESERVOIR AND GEOLOGICAL CONDITIONS ......................................................... 11 5.1

Correlation wells

11

5.2

Off-set Wells

12

5.3

Geological Cross Section

14

5.4

Formation Tops and Geological Description

16

5.4

Temperature Gradient

16

5.5

Pore Pressure and Fracture Gradient

16

6

PORE PRESSURE AND FRACTURE GRADIENT ........................................................ 17

7

TRAJECTORY ............................................................................................................... 18 7.1

Trajectory Description (J-Shaped)

19

8

MUD PROGRAM SUMMARY ........................................................................................ 21

9

CASING PROGRAM SUMMARY .................................................................................. 23 9.1

Casing Objectives

24

9.2

13-⅜” Casing Accessories

25

9.3

9-⅝” Casing Accessories

25

9.4

7” Casing Accessories

25

10

BIT PROGRAM ............................................................................................................. 26

11

CEMENTING PROGRAM SUMMARY ........................................................................... 27

12

11.1

13-⅜” Surface Casing

27

11.2

9-⅝” Surface Casing

27

11.3

7” Production Casing

27

LOGGING AND EVALUATION SUMMARY .................................................................. 28 12.1

Geophysical logging

28

12.2

Directional survey

28

12.3

Cement bond log

28

13

WELL HEAD.................................................................................................................. 29

14

BOP STACK .................................................................................................................. 30

15

DRILLING OPERATIONS SEQUENCE ......................................................................... 31 15.1

30” Conductor.

258 Colibasi Drilling Program Rev 3.0

31

Page 1 of 76

15.2

Conductor clean out / Pilot hole

31

15.3

13-⅜” Casing Drilling

32

15.4

12-¼” Hole and 9-⅝” Casing.

35

15.5

8-½” Hole and 7” Casing.

40

16

WELL PERFORMANCE: ............................................................................................... 45

17

OFFSET WELLS REVIEW ............................................................................................ 46

18

RISK ASSESSMENT ..................................................................................................... 49 18.1

Risks Applicable to all Sections

49

18.2

13-⅜” Casing Drilling (17-½” Hole)

50

18.3

9-⅝” Section (12-¼” Hole)

51

18.4

7” Section (8-½” Hole)

52

18.5

Wellhead, BOP and Pressure Test Program.

53

18.5.1

53

18.6

19

Barrier Policy

Management of Change

53

APPENDIX .................................................................................................................... 54 19.1

Bit Program

54

19.2

Directional Program

56

19.3

Mud Program

58

19.4

Casing Design

60

19.5

Cement Program

62

19.6

Casing Running Good Practise

64

19.7

Salt Exit Strategy

66

19.8

DWOP

68

19.9

WDP1

70

19.10 WRB1 slides and minutes

72

19.11 WRB2 slides and minutes

74


Page 2 of 76

EXECUTIVE SUMMARY 258 Colibasi is an oil and gas production well with a predicted production of 15MT oil/d and 6970 St m3 gas/d. The well has an expected service life of 16 years and will be part of OMV Petrom Asset VI Muntenia Central. The well is planned to have a 3 casing string design and a deviated ‘J’ shaped trajectory with a planned TD at 2325m MDRT (2295mTVDRT). The well will remain vertical until a kick-off at 1400m MDRT. The trajectory then builds in 12-¼” hole at DLS= 2.0deg/30m until 15.6 deg inc is achieved. A tangent will then be held for ~700m until well TD. A constant 277 deg azimuth is planned throughout. The well will be TD’s in 8-½” hole to accommodate a 7” production casing set across the Kliwa sup II target reservoir (planned horizontal displacement at TD = 217m). Most notably this well will apply the ‘casing whilst drilling’ technique in the 13-⅜” section to mitigate the losses and associated operational inefficiencies encountered in the surface formations on offset wells. The well will be drilled on the 258 / 291 cluster location using the drilling contractor Dafora and an MR8000 rig. The well is predicted to take 33 days to drill + 5 days to complete and test.


Page 3 of 76

1

WELL OBJECTIVES

HSSE • •

No accidents, No incidents, No harm to people. No damage to the environment.

Geological • • • •

Oil and gas producer from the Kliwa sup II Exp. rate: 15 t/day, 6,97 St m3/d gas,. Exp. service life: 16 years Exp. recoverable reserves: - 23.8t tons of oil. - 13.9 million m3 gas assoc.

Financial • •

1.1

Drill the well in or below the AFE of 33 drilling days + 5 days completion. Drill and complete the well in or below the allocated cost: € 2,933,627.

Key Performance Indicators (KPIs)

Metric

Target

Start cards / day Near miss reported / well Planned (drilling + prod casing) Planned cost (drilling) Planned cost/m Planned days/1000m drilled

35 1 33 days €2,573,427 €1107/m 11.6 days


Page 4 of 76

1.2

AFE MD vs Days and MD vs Expenditure

AFC Time 0

500

Measured Depth

1000

1500

2000

2500 0

10

20

30

UPPER LIMIT


40

50

60

AFE

Page 5 of 76


Page 6 of 76

2

COMMITMENTS Activity Disposal of drilling fluid and drilling cuttings

Well site drainage, chemical storage and management

Liquid Discharges

Incident Reporting Waste Oil Management Spillage of diesel fuel or oil

Discharge of combustion products Solid waste management •Food scraps •Garbage •Litter •Scrap metal and wood etc Light Overspill Noise

Requirement • WBM coated cuttings will be conserved and dried, with recovered water flocculated and filtered for re-use and/or disposal (Eco-Med). • Solids control equipment to be optimised to ensure maximum separation of fluid from cuttings. • Record volume of drilled cuttings and fluid disposed on environmental spreadsheet. Results to be reported to the HSEQ field Manager at the end of the well. • OBM coated cuttings will be dried to less than 3% oil content by use of a vortex drying equipment at the rig site. The remaining cutting will then either be used to generate heat for cement manufacture or mixed with cattle manure as part of an environmental disposal method. • Maintain good housekeeping practices • Chemicals are to be stored in bunded areas away from open drains and chemical containers are to be intact. • Drip trays are to be used under all machinery and fuel points and valves. • In the event of a spill, all actions are to be taken to control the spill and divert area drainage to tanks, for treatment through oil-water separator. • Ensure absorbent material is on location to use in soaking up chemical or oil spills. • All spills >100 L must be reported to field office within 2 hours • Treated sewage and grey water under routine operating conditions to be discharged to a special tank. • Rig wash water to be collected from cellar and disposed correctly. • Use of the Petrom incident reporting system to report incidents within 2 hours. Ensure that a set of incident report sheets is available. • Waste oil and grease to be drummed and returned for recycling • Records of volume of waste oil taken off rig forwarded to the Environmental manager at the end of the well. • In event of a spill, take all action to control the spill. • All spills >100L must be reported to field office within 2 hours. • Report all spills <100L through Petrom incident reporting system • Diesel Tank should be equipped with retain tray for 1.5 tank capacity. • Inspections and tuning of engines and equipment are included on a regular maintenance schedule. • Optimise combustion of well test fluids and gas. • No disposal of debris, garbage or litter into rig area • Segregate industrial waste (scrap metals / drums etc), wherever possible, for appropriate disposal. Scrap metal must be segregated onsite in a ‘walled’ basket i.e. not just in a loose pile. • Reduce, reuse and recycle waste wherever practicable. • Record the volume and type of waste taken off rig and forward to the HSEQ Manager at the end of the well. Minimise use of non essential lighting, whilst maintaining safety standards on the drill rig. • Minimise noise emissions when operating near noise sensitive environments.


Page 7 of 76

Bucharest / Field cluster office commitments:

Activity Prior to drilling

Discharge of combustion products from engines Environmental Audit

Requirement • Make Drilling Program available to personnel involved in project. • Conduct Rig Acceptance Audit. • Conduct a Pre-Spud meeting with Petrom drilling staff, Drilling contractor rd and 3 party service companies involved in the well construction operations. • Agree/Sign DWOP with Drilling Contractor. • Report greenhouse gas emissions data to Federal Government annually.

• Audit drilling rigs every year whilst under contract to Petrom. • Review electronic waste and chemical log received from rig.

The following are the responsibility of Petrom DSV (Drilling Supervisor). Management of the implementation of commitments will be performed by the stated personnel.

#

1

Commitment

Action by

Action

Order tools and consumables needed for the well in good time. These include; running tools, wear bushing, casing, casing accessories, wellhead, Xmas tree, test tools and hangers. Offline testing of BOP

DSV

DSV must order each of these items 3 weeks before they are required and have them onsite no later than 1 week before they are required. This means some items will need ordering at the start of the well.

At all times.

DSV. Rig manager.

The DSV must ensure, where possible, the BOP is tested offline and in compliance with Petrom Drilling Operations Manual. Follow the refuelling procedure. Keep all spills contained.

At all times.

2

3

The risk of diesel spillage during refuelling shall be minimised. Oil loss during production testing will be minimised.

Rig Manager

All personnel on site will undergo an induction and education program.

Rig Manager/ Medic/ Safety Officer/ DSV.

DSV

4

5

6

7 8

Post copies of MSDS and environmental commitments. A handover shall be conducted. Permit to Work System

Rig Manager/ Medic / Safety Off. DSV

DSV/Rig Manager


Follow guidelines for minimising production testing fallout as referenced in the Petrom Environmental Guidelines, Commitments and Responsibilities under Spillage of Oil. Outline the environmental management requirements as referenced in the previous page. It is the responsibility of the DSV to verify that the drilling contractor staff have been trained in accordance with Petrom standards (MAVLO1) Post copies of the MSDS and environmental commitments outlined on the previous page on all notice boards. Site inspection shall be conducted at end of well, prior to handover to production department Ensure PTW and JSA is used on location as per Petrom/OMV system

Timing

At all times.

During well testing.

To be given to all personnel during their induction to the rig and re-iterated at safety meetings.

Prior to the start of the well.

At end of drilling after rig move At All Times

Page 8 of 76

3

CONTACT LIST

Name Iana Ioan Chiran Ioan Parfichi Vasile

Petrom DSI Petrom DSI Petrom DSV

Title

Mobile 0726 333 138 0730 170 706 0729 996 135

Office -

Cucu Mircea Marcu Pompiliu

Petrom DSV Petrom DSV

0728 628 930 0729 996 130

-

Zarnescu Andrei

Petrom WSDE

0728 220 788

-

Title Project & Engineering Manager

Mobile 0728 852 895

Office

Asset Office engineer Geologist engineer

0728 727 082 / 0724 252 434

0372 429 462

HSE Department Name Eduard Steanescu

Title Drilling Department HSE

Mobile 0724 330 265

Office 0372 449 952

Drilling Department Bucharest Name Alexandru Schlett Frans van Rixel Sorin Milea Mark Smith

Title Well Delivery TL (Team 4) TL Well Delivery Operations Senior Drilling Engineer Drilling Engineer

Mobile 0728 292 444 0720 202 136 0728 727 114 0720 017 773

Office 0372 849 677 0372 483 497 0372 448 580 0372 854 346

Asset 6 Department Name Stanciu Viorica Argentina Marinescu Dumitru Popescu Catalina

Vendor List Service

Company

Drilling Contractor

Dafora

Jar, Accelerators, PBLs

Odfjell

Drilling Bits

Baker Hughes

Drilling & LWD/MWD

Baker Hughes

Wellhead Equipment Mud Logging System

Contact Cristian Georgescu Manager) Olsen Torgeir

-

Cell Phone (Drilling

0730 099 389

Cameron Rompetrol

Raul Stanel Vasile Cosmeanu (Coordinator) Ramona Harabagiu (Engineer) Tudor Constantin

47 90 776 671 0730 013 746 0733 109 369 0731 495 926 0728 221 627

Alexandru Gomoescu

0732 141 454

Cementing Cementing Drilling Fluids Casing running and Casing drilling Casing accessories

Rompetrol SLB AVA Odfjell

Constantin Radu Ahmed Anisse Salhi Deliu Constantin Olsen Torgeir

0740 078 923 0730 714 841 0751 039 900 47 90 776 671

Weatherford

Fishing Slickline

Weatherford Rompetrol

Arthur Iordache Cristian Carpen Arthur Iordache Mr. Iancu Marcel

0736 101 909 0755 102 077 0736 101 909 0745 349 969

Gyro measurement

Scientific Drilling

Constantin Pinta

0720 947 765


Page 9 of 76

4

SURFACE AND TARGET LOCATIONS

The surface location and target location of the 258 Colibasi well is outlined below; UTM Spheroid, Projection, Datum:

Pulkovo 1942(58) / Stereo 70

SURFACE LOCATION* Surface Co-ordinates (Lat./Long.):

Grid Co-ordinates (Easting/Northing):

Lat φ = 44°59'57.093" N Long λ = 25°33'48.103" E E = 544412.75m N = 388947.54m Z = 349.16m (RF elevation above MSL)

GL elevation above MSL

344.16m

DF elevation above MSL

349.16m

*The surface location coordinates and elevation will be confirmed during the post rig-up survey.

TARGET LOCATION Co-ordinates (Lat./Long.): Grid (Easting/Northing):

Lat φ = 44°59'57.437" N Long λ = 25°33'40.674" E E = 544250m N = 388957m Z = 2135m TVD BRT

Depth of target (BRT):

2157.1m MD / 2135m TVD

Target Geological Formation:

Kliwa Sup II

Required tolerance:

Circular: 50m radius


Page 10 of 76

4.1

5

258 Colibasi Structural Surface locations

RESERVOIR AND GEOLOGICAL CONDITIONS 5.1

Correlation wells

The Colibasi structure is located in Dambovita county, on the NE structural alignment Ocnita-Colibasi– Draganeasa–Runcu depression of the Carpathians. Geographically, the structure is part of the Carpathian hills (400-500m high) and is located about 10 km N-NE of Gura Ocnitei and 7 km NW from Moreni. The location is situated in Ocnita village, at cca. 34m S-SE from 290 Colibasi well. It is part of the SW Precarpathian depression, on diaper creases alignment based on a exaggerated diaprism, which contains salt at the surface. Please note, however, that salt was not recorded on the most relevant offset well (290 Colibasi) but has been observed on more distance offset wells in the Colibasi field. Hydrocarbon bearing formations include the Meotian (East) and Oligocen (Central and West). The reservoir targeted by 258 Colibasi is Oligocen (oil and gas), more specifically Kliwa Sup II (2135 TVD BRT). The 258 Colibaşi well is proposed to be drilled primarily for oil exploitation to add to the existing production achieved on the recent 290 Colibasi well (2011). The 259 Coibasi offset well was put on produciton on 2Q12 and produced significantly more than originally anticipated. The 258 Colibasi drilling program has been primarily based on the learning from the offset wells; 290 Colibasi (same block, different rig) and 258 Colibasi (different block, same rig). The reservoirs are stratiform, tectonically and lithologically sealed (see pore pressure fracture gradient plot).


Page 11 of 76

5.2

Off-set Wells

The below plot shows those wells planned and drilled in the Colibasi field. It can be seen that 290 Colibasi is the closest offset well to 258 Colibasi and is in the same block. As such it is the most relevant to 258 Colibasi in terms of geological conditions and drilling problems. 259 Colibasi is in a different block but was the well drilled directly prior to the 258 Colibasi in the drilling sequence and was drilled using the same rig as will be used for 258 Colibasi. As such 259 Colibasi has been most relevant to 258 planning in terms of performance/ operational data. -19 00

544500 -1980

-1940

-1930

0 84 -1 8 -1

-1 88 0

-19 70 -19 60

545000 -1 89 0

544000

-183

545500 0

50

-1800

-19 50

-1900 -2000 -2100

92 0

0 -195 0 -194 -1930 -1920 -191 -19000 -1890 DT -1880 -1870 O -1860 -18500 -184 0 -183

-2300 -2400 -2500

-1825

-2600 -1920

0 81

0

0 -191

-1

-180

-1

0 -193

-19 10

00 -19

m

-1820

-189

0

60

260 -1799

259_op3 261

20 -18

-18 70

-1 9 60

90 -17

6 18 TOD

60 -1 8

0m

-1 9 -1 00 -1 890 8 -1 80 87 0 -1 86 0 -18 50 -18 40 -18 30 -182 0

50 -19 40 -19 0 93 0 1 0 92 -1 191 -

389500

389500

-2200

-18

70 -18

-181

0

-1805

-1795

-1 7

90

389000

389000

290

00 -18

258

0

50

100

150

200

250m

1:5000 0 83 -1

-1 84 0

COLIBASI Fragm.de Harta Structurala Top KLIWA Super II Scale

1:5000

Date

01/23/2012

Intocmit

Iordache Claudiu 544000

544500

545000

545500

The following schematic shows data relating to the 260 and 261 offset wells (different block, different rig). As described, the 290 Colibasi well is the most relevant to 258 Colibasi planning in terms of geological conditions and drilling problems. As such the learning’s from 290 have been included on the Well Schematic in ‘Offset Well Review’.


Page 12 of 76

Review of the offset data indicates the following potential drilling problems: • • • •

Fluid losses in Helvetian and Oligocen; Tight hole in Pontian and Oligocen (severe reaming+ backreaming ) Gas content in Helvetian and Oligocen (reservoir); Stuck pipe tendency

The potential drilling problems have also be identified in the ‘Offset wells Review’.


Page 13 of 76

5.3

Geological Cross Section

Based on WDP1 and discussion with the drilling geologist, the well is estimated to cross the following formations (all depths referenced to TVD BRT): Inferior Miocen (0-420mTVD) interval crossing Pliocene deposits, made from marls and calcareous sandstones with thin anhydrite and gypsum inter-layers, having the possibility for salt to be present near Câmpina fault. Romanian (Levantin)-Dacian, (420-1110mTVD) interval and is made from gravel, on superior part, and clay sand with thin inter-layers of marls and clay and in inferior part some coals. Pontian (1110-1710mTVD i.e. 600m TVT), is generally made from marls, represented in superior part by marls with thin inter-layers of sand and in inferior part purple marls with pyrites on the last 50-100m. Meotian (1710-1790mTVD) interval, is layered transaggressive on erosion relief of inferior miocen age. The superior part is made from marls with thin inter-layers and in inferior part is made from sands and sandstone, sometimes saturated with hydrocarbons. Layer inclination is ∼5-10º. Inferior Miocen (1790-2030mTVD) interval, is layed transaggressive and discordant on erosion relief of oligocen age and is made from marls with calcareous sandstones inter-layers, sandy marls with gypsum inter-layers and sand-marly breccia sometimes conglomerated. Oligocen (2050-2325mTVD) interval, being developed by Kliwa in sandstone facies, is made from siliceous sandstone good cemented, with black compacted clay inter-layers. Transit from Oligocen to Miocen is generally made through clay, black, compacted with syschtous look dysodile. Oligocen was divided in some complexes, based on lithological aspects and tested interval behaviour in production. A description of these formations is also given in the WDP1 (see appendix). The predicted stratigraphic column including offset wells is shown on the below plot.


Page 14 of 76


Page 15 of 76

5.4

Formation Tops and Geological Description Tops TVD (MD) BRT m

Uncertainty TVD m

5 (5)

±10

Dacian

420 (420)

±10

Pontian

1110 (1110)

±10

Meotian

1710 (1716)

±10

Helvetian

1790 (1799)

±10

Kliwa sup I Kliwa sup II Kliwa sup III TD

2030 (2048) 2135 (2157) 2240 (2266) 2295 (2325)

±10 ±10 ±10 ±10

Formation Helvetian

5.4

Description Predominantly clays ,marls ,sandstone with intercalations of anhydrite Clays ,marls and sands with thin coal intercalations Shally facies Sand and oolitic sandstones with marls and sandy marls Predominantly clays ,marls ,sandstone with intercalations of anhydrite Kliwa’s facies (siliceous sandstone, good consolidation with compacted argillaceous thickness)

Temperature Gradient

Analysis indicated the formation temperature gradient is ~3.0 deg C / 100m. Maximum anticipated borehole temperature 69°C at TD (2295mTVD).

5.5

Pore Pressure and Fracture Gradient

Analysis and interpretation of complex information from offset wells drilled to date on the structure (geological data from geophysical logs and drilling of production data) allowed an assessment of pressure and fracture gradient related to depth for the sequence-stratigraphic estimated to be found in 258 Colibasi well. Geological

Estimated Pressure

Estimated Fracture

Formation

gradients (SG)

gradients (SG)

Helvetian

0.98 - 0.99

1.35 – 1.50

Dacian

1 - 1.01

1.50 – 1.71

Pontian

1 - 1.01

1.71 – 1.80

Meotian

1.03

1.80 – 1.83

Helvetian

1.03

1.80 – 1.82

Kliwa sup I

1.03 – 1.04

1.85 – 1.89

Kliwa sup II

1.05 – 1.20

1.85 – 1.89

Kliwa sup III

1.20

1.85 – 1.89

The reservoir (Kliwa I, II, III) formation pressure is estimated at 205-263 bars.


Page 16 of 76

6

PORE PRESSURE AND FRACTURE GRADIENT

The well design along with predicted pore pressure and fracture gradient is summarised below; REVISION 4.0 (21-06-2012) {Based on Traj Rev B.0} Formation tops Directional data

258 Colibasi

KEY

All depths are quoted MD (TVD) BRT m RT elevation above MSL = 349.16m GL elevation above MSL = 344.16m 3m rat holes assumed

Pressure Gradient (S.G.) 0.5

1.0

1.5

2.0

2.5

0 30" @ 22m (Hammer to refusal)

Mud Weight

200

Helv.

Max Pore Pressure Fracture Gradient

17-½" Spud mud (1.05sg) 400 He/D @429m-

TVD BRT (m)

13-⅜" @ 500(500)m

FIT @504m = 1.45sg

600

800

1,000 12-¼" NAF (1.20-1.25 sg)

D/P @1119m 1,200

KOP@ 1425m o/30m 1,400 BUR =2 Max inc =15o

Top of tail @ 1400(1400)m


1,600 EOB@ 1651(1648)m P/M @1719m -

9-⅝" @ 1737(1730)m

FIT @1737m = 1.55sg M/He @1799m 1,800

8-½" NAF (1.25 sg)

Kliwa 2,000 Sup I @2039m Sup II@2144m -

..

2,200 Sup III@2249m7" @ 2325(2299)m

2,400

Temp Gradient = 3°C / 100m


Page 17 of 76

7

TRAJECTORY


Page 18 of 76

7.1

Trajectory Description (J-Shaped)

•

KOP at 1425m MDRT in Pontian Shale (12-¼” hole).

•

Build with DLS = 2.0 deg/30m to a maximum inc = 15.0 deg (constant azimuth = 273 deg).

•

End of build at 1651m MDRT in Pontian Shale (building to 15.0deg in 226 m) in 12-¼” hole. Directional work is planned to be completed ~86mMD before setting the 9-5/8” shoe and 73mMD before entering top Meotian.

•

Hold tangent at 15.0 deg inc from 1651mMD to prognosed TD at 2325mMD (674m).

•

290 Colibasi shows the formation natural tendency to be between 260-300 deg azimuth. As such 258 Colibasi (azi = 273 deg) will be drilled with the natural tendency.

The option to keep the well vertical to 12-¼” TD and then KO at 1750m (20m below 9-5/8” shoe) in the 8½” hole was considered but rejected for the following reasons; •

A tangent inc of 48deg would be required. Conventional suckers rod artificial lift cannot function at this inclination. Wear on the 9-5/8” casing may have become significant during the potential reaming of the 8-½” hole section. This inclination would have been suboptimal from a reservoir standpoint.

•

A DLS of 3.33 deg/30m would have been required which would increase wear during artificial lift (even with co-rod suckers) and would have been technically more difficult to drill (a rotary steerable may have been required).

Anti-collision is not a major concern for 258 Colibasi. As described, 290 Colibasi is the only proximate offset well which currently exists. The 258 to 290 Colibasi minimum separation factor = 11.33 (at depth = 1933mMD). The minimum centre-to-centre distance = 125.11m (at depth = 507.4mMD). Anti-collision will, however, become a concern when the planned 291 Colibasi well is drilled. At the time of writing 291 Colibasi is planned to be drilled immediately after 258 Colibasi. The first 500m of 258 Colibasi is will be casing drilled i.e. no directional surveys will be taken whilst drilling. To mitigate, anti collision concerns for 291 Colibasi it will be necessary to run a gyro in the 291 Colibasi 13-3/8” casing once the casing is cemented in place.

The following graphic illustrates the planned 258 Colibasi well in relation to the 290 Colibasi offset well.


Page 19 of 76

290 Colibasi

258 Colibasi

The full planned survey for the 258 Colibasi well can be found within the directional Program in ‘Appendix Directional Program’.


Page 20 of 76

8

MUD PROGRAM SUMMARY

The mud program and waste management process are recommended by OMV Petrom in association with AVA. In general the mud weight should be kept to the minimum planned value unless hole conditions dictate an increase is advantageous. If in doubt contact the office. 17-½” Strategy: 0-500m (Top Hole) The 17-½” top hole section will be casing drilled using Spud Mud. 290 Colibasi showed 2 distinct loss zones in the top hole at 47-66m and 91-95m. As such it is predicted heavily losses will be encountered when drilling the top hole section on 258 Colibasi. Spud mud is comparatively inexpensive and is, therefore, be suitable for this application. In 290 Colibasi a salt saturated spud mud (weight ~1.16sg) was maintained due to concern over salt. Salt was not, however, detected. As such a salt saturated system is not the primary plan for 258 Colibasi. This results in a lower mud weight and so it is hoped less losses will result. Salt additive must be on hand, however, to saturate the mud system if salt is in encountered.

12-¼” Strategy: 500-1737m In 290 Colibasi a WBM system was used in this section. Overpulls were evident and significant reaming required when drilling the 12-¼” section on 290 Colibasi. ROP was also low. 259 Colibasi adopted a NAF system in the 12-¼” section and significantly fewer overpulls resulted. ROP was also higher. It is believed that the NAF’s superior inhibition avoided repetition of overpulls within the shale regions. As such a NAF system will be applied on 258 Colibasi.

8-½” Strategy: 1737-2325m High torque and drag was encountered in the 8-½” section in 290 Colibasi with WBM. This was successfully mitigated in 259 Colibasi through use of a NAF system. As such NAF will be applied in the 8-½” section on 258 Colibasi. It is believed the increased ROP on 259 Colibasi can also partly be attributed to the NAF mud system. Losses were encountered in 290 Colibasi whilst penetrating the lower Kliwa III (at ~2400m TVD). 258 Colibasi is planned to TD at 2295m TVD and so the loss zone should not be encountered.


Page 21 of 76

MUD PARAMETERS

Interval (MD) Footage Type of fluid Density Marsh Viscosity PV Yield Point Gel 10 sec. Gel 10 min 6 RPM 3 RPM API Filtrate PH Ca++ MBT LGS HPHT-Filtrate O/W Ratio Emulsion stability Alcalinity Sand WPS Water phase activity

U.M. in m-m m kg/dm³ sec/l cP lb/100ft² lb/100ft² lb/100ft² lb/100ft² lb/100ft² cm³/30' mg/l kg/m3 % Vol ml Volts ml H2SO4 0.1 N % vol g/l


II 17 ½" 0-500 500 Spud Mud 1.05-1.15 120-60 ALAP 20-30 10-15 20-35 12-8 8.5-9 <200 <60 <10 <0.35 -

Interval III 12 ¼" 500-1737 1237 NAF 1.20-1.25 ALAP 15-25 8-12 15-20 10-12 8-9

<5 <5 75-25 >750 2-3 <0.25 200-250 0.75-0.8

IV 8 ½" 1737-2325 588 NAF 1.25 ALAP 15-20 7-10 12-22 8-9 5-6 -

<4 <5 80-20 >800 2-3 <0.2 200-250 0.75-0.8

Page 22 of 76

9

CASING PROGRAM SUMMARY All depths below are referenced to BRT. Interval Length MD BRT [m] [m]

Nom. Size [in]

Wall Nominal Grade Connection thickness Weight [mm] [kg/m]

Section Weight* [kg]

Make-up Torque [N.m] min. opt. max.

Conductor 30” 0 - 21.75

30

30

25.4

X52

Welded

460.9

13827

-

-

-

Surface Casing 13-⅜” - CASING DRILLING 0 - 500

500

13-⅜

12.19

K55

TSH ER

101.16

45100

12770 13800 14840

11.99

L80

TSH Blue

69.94

128133

24100 26800 29500

10.36

L80

TSH Blue

43.19

100347

14100 15600 17200

Intermediate Casing 9-⅝” 0 - 1737 1737

9-⅝

Production Casing 7” 0-2325

2325

7

*Total section weight assumes hangers, float collars and shoes to be of a like-wise weight to the tubular body.

A 4.5” liner is available as a contingency should it not be possible to run the 7” casing to TD. Alternatively a failure to casing drill the 13-⅜” to TD may require a higher 7” casing setting depth and so application of a 4.5” production liner may be required. Interval Length MD BRT [m] [m]

Nom. Size [in]

Wall Nominal Grade Connection thickness Weight [mm] [kg/m]

Section Weight** [kg]

Make-up Torque [N.m] min. opt. max.

Production Casing 4.5” TBC

500

4.5

7.37

L80

TSH Blue

20.09

10045

7253

8054

8853

The following pups must be available to aid with casing string space-out. 9-5/8” Pups

7” Pups

1 x 4.5m

1 x 4.5m

1 x 3m

1 x 3m Internal Yield

Collapse

Body Yield Strength

Standard Drift

Connection

[MPa]

[MPa]

[x1000daN]

Diameter [mm]

OD [mm]

476

311.4

365.1

483

216.5

269.9

332

151.6

196.4

Surface Casing 13-⅜” – CASING DRILLING 23.8

13.4

Intermediate Casing 9-5/8” 47.3

32.8

Production Casing 7” 62.5

59.3


Page 23 of 76

9.1

Casing Objectives

13-⅜” Surface Casing (casing drilling) The 13-⅜” surface casing will be set vertically across the Helvetian and into the Dacian at ∼500m BRT. The objective is to isolate the losses section and isolate any potential salt which may be present in the Helvetian (low change of encountering salt). The 13-⅜” will also permit rig-up of the BOP to provide well control when drilling the 12-¼” hole through the potentially gas bearing Pontian (low chance of encountering hydrocarbons in Pontian or top Meotian). The 13-⅜” section will be casing drilled to help minimise the losses encountered on this section and reduce the time spent attempting to cure them which was evident on offset wells.

9-5/8” Intermediate Casing The 9-5/8” intermediate casing will be set after penetration into the Meotian sandstone at 1737m TVD / 1730m MD. The objective is the isolate the overlying Pontian and Dacian before drilling the Meotian, Helvetian and Oligocen reservoir. It is also necessary to set the 9-5/8” casing to ensure Petrom Drilling Standards on kick tolerance are satisfied when drilling through the reservoir.

7” Production Casing The 7” production casing will be set across the Meotian, Helvetian and Oligocene reservoir at 2295m TVD / 2325m MD. The objective is to provide a good isolation across the Kliwa Sup II formation (Oligocene) to permit perforation and production. Section TD criteria has been outlined in ‘Drilling Operational Sequence’.


Page 24 of 76

9.2

13-⅜” Casing Accessories Model

Float collar (non-rotating), single valve

-

13-⅜

2. Centralisers (Odfjell)

Econ-OGlider

17“

-

450-500

1/1

5

3. Stop collars (Odfjell)

DHP

14”

-

450-500

as above

10

1.

9.3

2.

3. 4.

9.4

Diameter Conn.

9-⅝” Casing Accessories Position Frequency Total m (MD) cents/jnts Reamer shoe, single valve 9-⅝” TSH-Blue 1 ~1712 (top Float collar, single valve 9-⅝” TSH-Blue of shoe1 track) 0-1250 1/10 10 Standard Centralisers (Centek) 9-⅝ x 12-¼ 1250-1700 ½ 18 S2 1700-1737 1/1 3 Stop collars (Centek) Slip on 9-⅝ x 12-¼ as above as above 62 Casing accessories

1.

Position Frequency Total m (MD) cents/jnts ~475 (top of T-ER 1 shoe-track)

Casing accessories

Model

Diameter

Conn.

7” Casing Accessories Casing Accessories

Model

1. Reamer shoe, single valve 2. Float collar, single valve

3. Centralisers (Centek) 4. Stop collars (Centek)

-

Diameter 7” 7”

Standard 7“ x 8-½ S2 Slip on

7“ x 8-½

Position m Frequency Total (MD) cents/jnts TSH-Blue 1 ~2300 (top TSH-Blue of shoe1 track) 0-1400 1/10 11 1400-2300 2/3 49 2300-2325 1/1 2 as above as above 124 Conn.

Note:Float equipment and cementing plugs must be PDC drillable. Centralisers will be installed whilst on the racks i.e. offline. The frequency of centralisers may be updated based on conditions encountered while drilling (e.g. if cavings are observed while drilling Dacian, Pontian shale, or cross Salt formation).


Page 25 of 76

10

BIT PROGRAM

The below table is a summary only. The full drill bit program is outlined in ‘Appendix – Bit Proposal’. The below proposal has been based on the learning from 259 Colibasi. The 17-½” pilot hole bit (to drill out 30” conductor will be a junk bit provided by Baker Hughes). The 26” hole opener (run above 17-1/2” pilot hole bit) will be provided by Smith.


Page 26 of 76

11

CEMENTING PROGRAM SUMMARY

The below is intended as a summary only. Full cement programs are included in ‘Appendix Cementing Program’. The cement proposals have been produced based on the learning’s from 290 and 259 Colibasi.

11.1

13-⅜” Surface Casing

Mean Annular Excess = 80% (Equivalent OH Diameter = 20.2”) 3

1. Water Spacer: 4m 1.00 SG 3

2. Spacer: 4m 1.40 SG 3. Tail Slurry: 58.5m3 1.80 SG (0 – 500m) 4. Mud: 37.5m3 1.20 SG (NAF)

11.2

9-⅝” Surface Casing


1.

Oil Spacer: 4m 1.30 SG

2.

Water Spacer: 6m 1.35 SG

3.

Lead Slurry: 46.2m3 1.45 SG (190 - 1337m).

4.

Tail Slurry: 18.2m3 1.90 SG (1337 - 1737m).

5.

Mud: 65.6m 1.25 SG

11.3

3

3

7” Production Casing


1. Chemical wash: 4m 1.00 SG 2. Scavenger Slurry: 20.2m3 1.45 SG (0 – 1510m) 3. Tail Slurry: 11.8m3 1.90 SG (1510 – 2325m) 3

4. Mud: 43.3m 1.25 SG


Page 27 of 76

12 12.1

LOGGING AND EVALUATION SUMMARY Geophysical logging Hole Size

MWD

Wireline

17-½”

--

--

12-¼”

GR (MWD)

--

8-½”

GR + Res

Run #1: GR - CNL - LDL - LEH -T Run #2: GR – XPT* Run #3: GR - CBL - VDL

*XPT log is provisionally planned but will be confirmed based on well bore conditions during drilling. Mud logging will take place from surface.

12.2

Directional survey

-

m

Distance between surveys m

I

0 - 500 500 - 2325

1 Stand (2 joints) = 18m

Section

II, III

12.3

Interval (MD)

Tool

Method

-

-

OnTrak

None (casing drilling) MWD

Cement bond log

A CBL will be made of the 7” production casing string from 1500m to TD.


Page 28 of 76

13 WELL HEAD

No

Casing head components

Size/ Pressure

-

-

Casing Primary seal

Hanger

Secondary seal

in / bar

in

in

in

13-5/8 x 13-⅜ x 350

9-5/8

9-5/8

-

1

Casing head flange

2

Casing spool

13-5/8 x 11 x 350

7

7

9-5/8

3

Tubing head

11 x 7.1/16 x 350

2-7/8

2-7/8

7

Wellhead: 13.5/8 x 13.⅜ x 11 x 9.5/8 x 7 x 7.1/16 x 2.7/8 x 350 bar.


Page 29 of 76

14 BOP STACK Previous Casing In

13-5/8” BOP Stack Inside Type Pressure diameter

Rams Drilling

Run casing*

in

-

bar

in

in

13-5/8

Pipe/blind

350

5

5

13-5/8

Annular

210

annular

annular

13-5/8 Pipe/blind 350 5 13-5/8 Annular 210 annular *Only install casing rams if the rams can be tested after the installation.

5 annular

13-⅜” 9-⅝”


Page 30 of 76

15

DRILLING OPERATIONS SEQUENCE

The following section outlines the planned operational sequence for 258 Colibasi. The over-riding operational objectives; •

No accidents, incidents, harm to people

•

No damage to the environment

•

Do it right first time

Remember, anyone can STOP the job at anytime if they feel it is unsafe.

15.1

30” Conductor.

The conductor has been hammered to refusal by DOSCO before rig-up at 258 Colibasi. The conductor has been confirmed as vertical with a seat = 21.75mBT.

15.2

Conductor clean out / Pilot hole

15.2.1

Install flow riser.

15.2.2

Prepare 1.05sg spud mud as per mud program (see ‘Appendix mud program’).

15.2.3

Confirm mast alignment using 2 DCs before commencing drilling pilot hole.

15.2.4

JSA before P/U of 17-½” x 26” pilot hole

15.2.5

P/U the 17-½” x 26” pilot hole/ conductor cleanout assembly. This assembly will consist of a 17-½” roller cone bit (Baker Hughes supplied) made-up directly below a 26” hole opener (Smith supplied) with 8” DCs above (XO between hole opener and DCs may be required). The bit should have the nozzles removed to maximise flow rate during drilling. It will be necessary to jet / wash as much as possible of the 30” conductor contents before commencing drilling.

15.2.6

Drill 17-½” x 26” pilot hole to excavate all contents of the 30” conductor i.e. the 26” hole opener should be drilled to ~22m BRT with the 17-1/2” pilot hole to ~23m BRT. The objective is to remove all earth/debris from inside the 30” conductor (ID = 27”) and create a centralised 17-½” pilot hole below the 30” conductor in preparation for the 17½” casing drilling bit. Pumping should be at 4000L/min or the maximum rig capacity to ensure sufficient hole cleaning. Hi-vis pills should be used to improve hole cleaning.

15.2.7

POOH and LD 17-½” x 26” pilot hole drilling assembly.


Page 31 of 76

15.3 15.3.1

13-⅜” Casing Drilling Apply 13-⅜” Econ-o-glider centralisers to 13-⅜” casing offline and as per centraliser program.

15.3.2

JSA before commencing casing drilling. Ensure all involved understand the planned operations and risks. Anyone can stop the job at anytime if they feel it is unsafe.

15.3.3

P/U Odfjell CRTI as per Odfjel instruction in preparing for casing drilling.

15.3.4

Make-up 13-⅜” casing drilling shoe track assembly (17-½” casing drilling bit, 2 x intermediate joint, 1x float collar). Casing drilling bit TFA=0.663 (6x12/32). Apply pipe lock to the shoe track only as per Odfjell instruction.

15.3.5

Function test all float equipment.

15.3.6

Confirm rig alignment before commencing casing drilling.

15.3.7

Casing drill as per Odfjell instruction.

Recommended Casing Drilling Parameters: Operating Flow Rate* = 2200-2400 l/min (HSI = 0.8-1.05).

o

Predicted SPP: 46 - 53 bars at TD (500m). Predicted ECD: 1.20 sg *Flow rate must be optimised to prevent down hole and surface losses whilst ensuring hole cleaning. o

WOB: 2-3 tons. WOB should be varied to optimise ROP but do not exceed 4 tons

o

RPM: 50-70. RPM should be varied to optimise ROP. Varying the above parameters should be done with instruction from Odfjell. Significant deviation from the above parameters should be confirmed with the office. Warning: Excessive RPM can increase bit wear and excessive WOB can lead to bit balling.

15.3.8

Drill the 13-⅜ casing (17-½” casing drilling bit) to TD at 500m. o

To avoid losses while drilling the surface formations, it is recommended to drill the first 100 - 150m with reduced ROP and reduced flow rate when required.

o

LCM must be run the mud system throughout the drilling activity to minimise losses.

o

Detergent must be continually added to the mud system to minimise bit balling.

o

There is a low chance of encountering salt in the surface formations. If salt is encountered the mud system should be made salt saturated as per AVA instruction. The additives required for this must be available on the rig site.


Page 32 of 76

NOTE: All companies involved must be made aware about the losses predicted in this section. Casing drilling does not permit the possibility of setting a cement plug. 25m3 of LCM mediumcourse LCM pill must be ready before commencing drilling. As soon as losses are detected 12m3 LCM must be pumped for every joint of casing run (as per AVA instruction). The mud logging company must monitor at all times the mud levels in the pits. Cuttings should also be analysis for indications of pyrite and salt.

15.3.9 After reaching TD with casing the casing must be spaced out to permit optimal well head positioning. 15.3.10 Before commencing casing cementation consider opportunity for offline BOP testing. 15.3.11 JSA for Cementing and Pressure Testing. Encourage full team involvement and participation. Consider the implications of a failed pressure test. 15.2.8

The cement job should be performed as per Rompetrol Well Service cement program (see ‘Appendix – cement program’). Displace with 1.2sg NAF in preparation for the 12¼” section.

15.2.9 Pump To Bump. Bump the plug @ ±35 bar over the displacing pumping pressure (for more details see Drilling Operations Manual, 12.5.3 Cementing P.374). 15.2.10 Perform green cement pressure test at 80 bar for 15 minutes – bleed off pressure and check for back flow. As per Drilling Operations Manual (12.5.2 Cementing P.375), if the floats in the casing string do not hold, the string shall be pressured up - after pressure testing - to the differential pressure between the cement and the displacement fluid and held until surface cement samples have hardened. 15.3.12 Slack-off casing weight – N/D bell nipple. 15.3.13 Screw wellhead to 13-⅜” casing. 15.3.14 Install 13-⅜” wear bushing flange (DSAF – Double Studded Adapter Flange). 15.3.15 JSA for N/U BOP. Consider how best to suspend the BOP to avoid unplanned movement or rotation. 15.3.16 N/U 13-⅜” BOP’s including annular preventer and install bell nipple. 15.3.17 Install choke and kill lines. Connect hydraulic hoses.


Page 33 of 76

15.3.18 JSA for pressure testing of BOP stack (if BOP testing not already completed offline). Encourage full team involvement and participation. Consider the possible outcome of a failed test. 15.3.19 Run in Cup Type Tester (CTT). 15.3.20 Perform pressure test connection between 13-⅜” casing and CHH (screwed connection) at 20bar for 5 minutes and then 180 bar for 10 minutes (80% of casing burst pressure). Keep the DP open during the pressure test to vent any pressure passing the cup seal. 15.3.21 Pull out cup type tester (CTT). 15.3.22 RIH Plug Type Tester (PTT) and test blind rams, pipe rams, DSA to casing flange, mud cross blanks, inside and outside kill valves, inside and outside HCR valves at 20bar for 5 minutes and then 350 bar for 10 minutes. Pressure test annular – 20bar for 5 minutes and then 145bar for 10 minutes. 15.3.23 Pressure test kill and choke manifold at 20bar for 5 minutes and then 350bar for 10 minutes. 15.3.24 POOH plug type tester. 15.3.25 RIH and set wear bushing. 15.3.26 Pressure test Top Drive, drilling hose and standpipe manifold at 20bar for 5 minutes and then 350bar for 10 minutes. 15.3.27 If required (depending on date of last test), test accumulator unit as per Petrom Drilling Operations Manual - Chapter 2 Wellhead and BOP testing requirements. A Work permit and JSA must be in place before starting operation. 15.3.28 JSA for slick-line / gyro measurement of 13-⅜” casing. 15.3.29 RU Slick-line / gyro tools as per Rompetrol and Scientific Drillings instruction. 15.3.30 Perform gyro measurement of casing at TOC and at 100m increment to surface (5 surveys in total) as per Scientific Drilling instruction. 15.3.31 Rig-down slick-line and gyro tool.


Page 34 of 76

15.4

12-¼” Hole and 9- ⅝” Casing.

15.2.11 JSA before P/U and rack back DP. P/U +/- 1800m of 5” DP and rack back. MU DP using the elevators and well bore (i.e. do not use top drive or mouse hole). 15.4.1

JSA for P/U BHA. P/U 12-¼” roller cone bit (TFA=0.7854, 4x16s) + Motor BHA (AKO 1.1º) + MWD (NaviGam).

15.4.2

PU DP from the pipe rack and RIH 12-¼” BHA on singles to TOC inside 13-⅜” casing (this will leave 1800m DP racked back in the derrick when at TOC).

15.4.3

Drill out the 13-⅜” casing shoe track and 17-½” casing drilling shoe using the following drilling parameters (as per Hughes Christensen casing while drilling operations manual (p.58). WOB: 11.5t

RPM: 40-60

Flow rate: 1600-2200 l/min

Frequently raise the string several feet off the bottom of the hole while circulating and rotating to clear debris from bit. Monitor returns at the shakers. The nature and appearance of debris can give valuable indications of the progress of the drilling out operation, but bear in mind the lag time for debris to reach the shakers. If there is a lack of progress and no significant increase in torque when weight is applied to the bit, additional WOB. 15.4.4

RIH, circulate and condition SBM mud @ 1.2sg, drill out shoe track and 5m of new formation.

15.4.5

Perform FIT @ 1.45 EMW. Pressure at surface =13bar (assuming 1.20 SG mud in hole and TVD = 505m). Pressure must be recalculated for a different mud weight or TVD.


Page 35 of 76

Recommended Drilling Parameters: o

Operating Flow Rate*: 2600-2800 L/min Predicted SPP**: 156-174bar (at 500mMD), 196-219bar (at 1737mMD). *Flow rate must be optimised to ensure hole cleaning, prevent down hole losses and prevent cavings. **Assuming max programmed MW = 1.25sg. SSP will be lower at reduce mud wt.

o

Minimum flow rate for 100% hole cleaning = 2300 l/min (for an ROP=25m/h).

o

WOB: Up to 13.5t in vertical section (do not exceed to avoid buckling / NP in jar). Up to 13.5t or 15.5-20t in tangent, gradually increase WOB in tangent section from


Page 36 of 76

15.5t@1400mMD to 19t@1500mMD. WARNING: Avoid 13.5-15t in both vertical and tangent to avoid NP in jar. o

Surface RPM: 85. RPM should be varied to optimise ROP and hole cleaning. WARNING: Do not exceed 90 RPM to avoid BHA damage.

o

15.4.6

Soft Drilling Parameters must be followed at all times. If in doubt ask the office.

Drill ahead 12-¼” hole to section TD. Only perform reaming / wiping trip if hole conditions dictate – always confirm with the office team first.

TD Criteria: 10m penetration into Meotian. Top Meotian is prognosed at 1710m TVDRT with ±10m TVD uncertainty. For planning purposes a ‘deep’ top Meotian has been assumed with top at 1720mTVDRT. As such for planning purposes a TD = 1730mTVDRT has been assumed. The GR tool run in 12-¼” BHA is 16m back from the bit. As such if Meotian does come in deep it will not be possible to see it using GR (it would only become evident on GR when bit was at 1736 which is too deep). As such ROP should be limited to 5m/hr when at 1710mTVD to allow Meotian to be identified based on cutting analysis as well as GR.

15.4.7

At 12-¼” section TD, circulate until shakers clean using operating flow rate and RPM.

15.4.8

Pump viscous pill POOH to surface. Rack back directional BHA.

15.4.9

Pull out 13-⅜ wear bushing.

15.4.10 Confirm rig alignment before commencing running casing. 15.4.11 JSA for running 9-5/8” Casing. Encourage full team involvement and participation. Consider the most efficient and safe method of delivering casing from the pipe rack to the rig floor. Casing Running Notes: Please review the casing notes in ‘Appendix 6 - Casing Running Good Practise’. Please review casing & liner running guidance in the OMV Petrom Drilling Operations Manual (p.329). When producing the casing tally it is important to carefully select a landing joint length, making use of 3m and 4.5m pup joints to achieve the required stick-up. It is the DSV’s responsibility to ensure these are onsite and used if required. The stick-up will depend on the Casing Head Housing i.e. do not have a collar across the CHH. Space must be left over head to permit easy installation of cement head.


Page 37 of 76

Double check the casing tally, the more people who review it the better. All the centralisers should be installed on the casing whilst the casing is on the pipe rack (an offline operation).

15.4.12 Make-up 9-5/8” casing shoe and float valve/collar offline (apply pipe lock to shoe track only). Function test float equipment. 15.4.13 RIH 9-5/8’’ casing as per running tally using CRTI tool – fill up every casing joint (Reference Petrom Drilling Operations Manual – chapter 10). The casing connections should be made-up using the CRTI tool and not separate casing tongs if possible. This will be safer and faster. An average running rate of 14 joints/hr should be exceeded. Operational performance must in no way compromise safety. 15.4.14 When tight hole is encountered reciprocate/rotate casing. Circulation should be considered as last resort, due to high risk of pack-off. If in doubt call the office. 15.4.15 JSA for Cementing and Pressure Testing. Encourage full team involvement and participation. Consider the implications of a failed pressure test. 15.4.16 Cement casing through CRTI as per Rompetrol Well Service cementing program (See ‘Appendix – Cementing Program). Displace with 1.25sg NAF to enable immediate use of this mud type for the 8-½” section. 15.4.17 Pump to Bump. Bump the plug @ ±35bar over the displacing pumping pressure (for more details see Drilling Operations Manual, 12.5.3 Cementing P.374). 15.4.18 Perform green cement pressure test at 100bar for 15 minutes – bleed off pressure and check for back flow. As per Drilling Operations Manual (12.5.2 Cementing P.375), if the floats in the casing string do not hold, the string shall be pressured up - after pressure testing - to the differential pressure between the cement and the displacement fluid and held until surface cement samples have hardened. NOTE: Cameron representative must be onsite before wellhead operations start with all equipment necessary for the operation. A JSA must be in place before starting operation.

15.4.19 N/D BOP from wellhead and lift up BOP as high as possible. A JSA must be in place before starting operation. 15.4.20 Clean slip seating area. 15.4.21 Install wrap around casing slips on 2 wooden boards around 9-5/8” casing on top of 13⅜” wellhead, set slips.


Page 38 of 76

15.4.22 Drop slips, slack off casing weight, land casing. 15.4.23 Cut 9-5/8’’casing – lay out 9-5/8’’ cut off piece. 15.4.24 Remove 13-5/8” wear bushing flange (DSAF Double Studded Adapter Flange). 15.4.25 Install Casing Head Housing (CHH) – energise ‘’P’’ seals and test seals as per Cameron engineers instruction. 15.4.26 Install 11” wear bushing flange. 15.4.27 N/U BOP. 15.4.28 Install Kill and Choke lines. Connect hydraulic hoses. 15.4.29 JSA for Pressure testing of BOP stack. Encourage full team involvement and participation. Consider the possible outcome of a failed test. 15.4.30 RIH Plug Type Tester (PTT) and test blind rams, pipe rams, DSA to casing flange, mud cross blanks, inside and outside kill valves, inside and outside HCR valves at 20bar for 5 minutes and then 350 bar for 10 minutes. Pressure test annular – 20bar for 5 minutes and then 145bar for 10 minutes. When pressure testing using PTT, keep the side outlets below the PTT open to vent any pressure passing the plug. 15.4.31 Pressure test kill and choke manifold at 20bar for 5 minutes and then 350bar for 10 minutes. 15.4.32 RIH and set 9-5/8” Wear Bushing. 15.4.33 Pressure test Top Drive, Drilling hose and Standpipe manifold at 20bar for 5 minutes and then 350bar for 10 minutes. 15.4.34 If required (depending on date of last test), test accumulator unit as per Petrom Drilling Operations Manual - Chapter 2.


Page 39 of 76

15.5 15.5.1

8-½” Hole and 7” Casing. P/U 8-½” PDC bit + Motor BHA (AKO 1.1°) + On Trak. TFA = 0.902; Bit nozzles= 6x14/32.

15.5.2

RIH, circulate and condition SBM mud @ 1.25 SG MW, drill out shoe track and 5 m of new formation.

15.5.3 Perform FIT @ 1.55 EMW, surface pressure = 74bar (assuming 1.25 SG mud in hole and TVD = 1734m). Pressure must be recalculated for a different mud weight or TVD.


Page 40 of 76

Recommended Drilling Parameters: o

Operating Flow Rate*: 1600-1800 l/min Minimum flow rate for 100% hole cleaning = 800 l/min (for an ROP=25m/h). *Flow rate must be optimised to ensure hole cleaning, prevent down hole losses and prevent cavings.

o

Predicted SPP** = 164-192bar (at 1737mMD), 189-223bar (at 2325mMD). **Assuming worst case MW = 1.4sg. SSP will be lower at reduce mud wt.

o

WOB: 5-10tons. WOB should be varied to optimise ROP. WARNING: Do not applying more than 10t to avoid the NP in the jar and bit damage.

o

Surface RPM: 75 RPM should be varied to optimise ROP and hole cleaning. WARNING: Do Not exceed 80 RPM to avoid BHA damage.

15.5.4 Drill ahead 8-½” hole to section TD (prognosed at 2325mMD) to be confirmed by operations geologist based on GR and resistivity logs. Carefully monitor for signs of salt and gas increases. Gas cut mud was observed on offset wells but was determined to be ‘drilled gas’ and not an influx. Monitor mud logging trends to identify if any gas observed is ‘drilled gas’ or is in fact an influx. Only perform reaming / wiping trip if hole conditions dictate – confirm with the office team first. There is a low chance of encountering salt whilst drilling this section. If salt is encountered reference ‘Appendix – Salt exit strategy notes’. 15.5.5 At 8-½” section TD, circulate until shakers clean using operating flow rate and RPM. 15.5.6 Pump slug and POOH to surface. Rack back directional BHA. 15.5.7 If hole conditions observed during drilling the 8-½” are stable perform wireline logging as per logging plan. Do not perform wireline logging if there is a significant risk of hole deterioration before running casing. 15.5.8 If wireline logging was performed, perform wiper trip to TD before running 7” casing (use the same drilling BHA). 15.5.9 Pull out 9-5/8” wear bushing. 15.5.10 Confirm rig alignment before commencing running casing. 15.5.11 JSA for running 7” Casing. Encourage full team involvement and participation. Consider the most efficient and safe method of delivering casing from the pipe rack to the rig floor.


Page 41 of 76

Casing Running Notes: Please review the casing notes in ‘Appendix 6 - Casing Running Good Practise’. Please review casing & liner running guidance in the OMV Petrom Drilling Operations Manual (p.329). When producing the casing tally it is important to carefully select a landing joint length, making use of 3m and 4.5m pup joints to achieve the required stick-up. It is the DSV’s responsibility to ensure these are onsite and used if required. The stick-up will depend on the CHH. Double check the casing tally (the more people who review it the better). All the centralisers should be installed on the casing whilst the casing is on pipe rack (this should be an offline operation).

15.5.12 Make-up 7” casing shoe and float valve/collar offline (apply pipe lock to shoe track only). Function test all float equipment. 15.5.13 RIH 7’’ casing as per running tally using CRTI tool – fill up every casing joint (Reference to Petrom Drilling Operations Manual – chapter 10). The casing connections should be made-up using the CRTI tool and not separate casing tongs if possible. This will be safer and faster. An average running rate of 14 joints/hr should be exceeded. Operational performance must in no way compromise safety 15.5.14 Reciprocate and rotate casing through tight spots. Circulate (max flow rate 1000 l/m) as a last resort as circulation can induce wellbore damage. Confirm with the office before initiating casing circulation. Wash down the last casing joint to bottom. 15.5.15 JSA for Cementing and Pressure Testing. Encourage full team involvement and participation. Consider the implications of a failed pressure test. 15.5.16 Cement casing thru CRTI as per Schlumberger cementing program (See ‘Appendix – Cementing Program). 15.5.17 Bump the plug ±35bar over the displacing pumping pressure. Only pump half the shoe track capacity if plug fails to bump (for more details see Drilling Operations Manual, 12.5.3 Cementing P.375) 15.5.18 Wait for 15 minutes – bleed off pressure and check for back flow. As per Drilling Operations Manual (12.5.2 Cementing P.375), if the floats in the casing string do not hold, the string shall be pressured up - after pressure testing - to the differential pressure between the cement and the displacement fluid and held until surface cement samples have hardened. If the pressure test fails for some reason, do NOT repeat the


Page 42 of 76

full pressure test after cement has hardened out. This will crack the cement sheet and results in annular pressures. 15.5.19 WOC until sufficiently hard for well control purposes as per Schlumberger program. 15.5.20 NOTE: Cameron representative must be onsite before wellhead operations start with all equipment necessary for the operation. A JSA must be in place before starting operation. 15.5.21 N/D BOP from wellhead and lift up BOP as high as possible. A Work permit and JSA must be in place before starting operation. 15.5.22 Clean slip seating area. 15.5.23 Install wrap around casing slips on 2 wooden boards around 7” casing on top of 9-5/8” wellhead, set slips. 15.5.24 Drop slips, slack off casing weight, land casing. 15.5.25 Cut 7’’casing – lay out 7’’ cut off piece. 15.5.26 Remove 11” Wear Bushing flange (DSAF Double Studded Adapter Flange). 15.5.27 Install Tubing Head Housing (THS) – energise ‘’P’’ seals and test seals as per Cameron engineers instruction. 15.5.28 Reinstall BOP. 15.5.29 Test wellhead connection between BOP and top of THS with Cup type tester (CTT) in 7” casing. Pull out cup type tester (CTT). A JSA must be in place before starting operation. 15.5.30 L/D all 5” DP and M/U 4” DP +/- 2500m. 15.5.31 RIH 4” DP with frontal mill and rotating scraper casing clean-up assembly. 15.5.32 Circulate and condition mud 15.5.33 Circulate clean out pills and displace NAF with reservoir water as per completion program. 15.5.34 Perform inflow test. Monitor well for 2 hrs. Record inflow test results. Keep Geolog unit onsite to monitor. 15.5.35 Circulate bottoms-up and monitor gas content (Geolog to monitor). If inflow test fails or gas is observed CALL THE OFFICE. 15.5.36 POOH clean-up assembly, L/D 4” DP, L/D clean up assembly and L/D any tools remaining in the derrick.


Page 43 of 76

15.5.37 Run jetting tool and wash/jet BOP and hanger area for a minimum of 20 minutes until returns are absolutely clean. 15.5.38 L/D jetting tool. 15.5.39 Perform 4-½” and 7” CBL from 1500mMD to TD. 15.5.40 Handover 258 Colibasi to production department.


Page 44 of 76

16

WELL PERFORMANCE:

Petrom S.A.

AFC Time Curve

Well Name: 258 Colibasi

258 Colibasi 0

Dry Hole = 27days Suspended well = 33 days Well + completion = 38 days

Casing drill 13-3/8" = 8 days

Cement 13-3/8" = 3 days

500

Drill 12-1/4" = 7 days

Measured Depth

1000

1500

Run+Cemented 9-5/8 = 4 days

2000

Drill 8-1/2" = 5 days

Run+Cement 7" = 6 days

Testing & Completion = 5 days 2500 0

10

20

30

40

50

60

Days AFE


UPPER LIMIT

Page 45 of 76

17

OFFSET WELLS REVIEW

As described 4 offset wells exist in the Colibasi field. 290 Colibasi is the only offset well in the same block as 258 Colibasi and as such is the most relevant in terms of drilling and geological conditions. 259, 261 and 260 Colibasi exist in an adjacent block. 259 Colibasi was drilled directly before 258 in the drilling sequence and the 2 wells will be drilled using the same rig. As such 259 Colibasi is most relevant in terms of rig and operational performance. The below schematic illustrates the casing design strategy adopted for the offset wells in relation to the geological column. It can be seen that the 258 Colibasi adopts a similar casing design to that used previously. The major difference is that the 13-⅜” surface casing will be casing drilled rather than by means of convention methods. This strategy should mitigate the losses historically encountered in the top hole section of wells in the Colibasi field. Please note that an alternative strategy of running an additional 20” surface casing string to 100m was reviewed but rejected as it was felt that the casing drilling strategy would save more time. TVD (m) 0 50 100 150 200 250 300 350 400 450 500 550 600 650 700 750 800 850 900 950 1000 1050 1100 1150 1200 1250 1300 1350 1400 1450 1500 1550 1600 1650 1700 1750 1800 1850 1900 1950 2000 2050 2100

260 Colibasi

261 Colibasi

259 Colibasi

290 Colibasi

258 Colibasi

12

30

415

Helvetian

Dacian

436 502

498

692

502

500

693

715

1110

Pontain

1710 1737 1790

Meotian

1130 1234

1235

1213

1833 1835 1900 1917

1860 1873 1960

1755 1799 1835

Helvetian

1913 Oligocean / Kliwa

2055 2135

2150

2152

2200 2250 2300 2350 2400 2450 2500

2172

2158 2227 2254 2274 2325 2360 2429

2509

2527


Page 46 of 76

The below shows the well design diagram for 258 Colibasi with those drilling problems encountered on the 290 Colibasi offset well (same block, different rig) added in red. REVISION 4.0 (21-06-2012) {Based on Traj Rev B.0}

258 Colibasi

Formation tops Directional data Offset problems (290 Colibasi)

KEY

0.5

All depths are quoted MD (TVD) BRT m RT elevation above MSL = 349.16m GL elevation above MSL = 344.16m 3m rat holes assumed


1.5

2.0

2.5

0 30" @ 22m (Hammer to refusal)

Helv.

Losses 5m3 @ 47-66m @ 91-95m

200 Pyrite, Glauconite and Microconglomerates

Mud Weight Max Pore Pressure Fracture Gradient 290 Colibasi mud wt

17-½" Spud mud (1.05sg)

400 He/D @429m-

FIT @504m = 1.45 sg

TVD BRT (m)

13-⅜" @ 500(500)m

600

800 Overpulls (+ Reaming) 15-25t@ 510-650m stuck@ 666m 10t@ 660-740m 25t@ 750m 25t@ 1120m 25t@ 1545-1425m

1,000 Losses 5m3 @ 1092m

12-¼" NAF (1.20-1.25sg)

D/P @1119m 1,200 Losses 5m3 @ 1293m

KOP@ 1425m o/30m BUR =21,400 Max inc =15o



1,600 EOB@ 1651(1648)m P/M @1719m -

9-⅝" @ 1737(1730)m

FIT @1742 = 1.55sg

M/He @1799m 1,800 T&D @1802-

8-½" NAF (1.25 sg)

Kliwa 2,000 Sup I @2039m -

. Sup II@2144m Overpulls (+ Reaming) 15t@ 2080m, 20t@2145-2290m

.

2,200 Sup III@2249m 7" @ 2325(2299)m

2,400 Losses 42m3 @ 2430m

Temp Gradient = 3°C / 100m


Page 47 of 76

The below plot is the predicted time-depth plot for 258 Colibasi against offset wells. It can be seen the strategy of casing drilling is predicted to save 2 days during drilling and an additional 1 day through not having to run casing when compared to 259 Colibasi. Operational performance in the 12-¼” and 8-½” sections have been calibrated with respect to 259 Colibasi (same rig, different block) and 290 Colibasi (same block, different rig). Additional discrepancies in time between 259 and 258 Colibasi can be attributes to NPT incurred on 259 Colibasi due to top drive repair and tripping due to a motor failure in the 12-¼” section.

258 COLIBASI AFE Time-Depth VS Offset 0

260 Colibasi

200

261 Colibasi 400

290 Colibasi 259 Colibasi

600

258 Colibasi 800 1000

Depth (m)

1200 1400 1600 1800 2000 2200 2400 2600 2800 0

10

20

30

40

50

60

70

80

Days


Page 48 of 76

18

RISK ASSESSMENT

The following summarises the most likely risks encountered in this well: Mud losses in surface formations (Helvetian);

•

Bit balling in surface formation.

•

Cement losses in Oligocene.

Mitigation and Control

Remnant Risk

Consequence

Risk

Potential Risk/Hazard

Probability

Risks Applicable to all Sections

Impact

18.1

•

Supervisor in charge of the operations to lead the JSA to all crews involved. RSS and Toolpusher to participate into tool box meeting. Participation of all crew involved in the job should be mandatory.

Incident during operation with multiple crew members (e.g. R/U,R/D lifting /handling equipment, High pressure testing, Casing running)

The Dafora RSS and Petrom DSV to monitor the execution of such operations. HSSE incident. NPT caused by equipment damage.

H

M

H

Dafora rig manager to provide pressure test procedures for BOP/Pump Manifold/Choke Manifold/Accum unit.

L

Dafora to provide hazard area classification on the rig and install signs indicating hazard areas on the rig. Aspire to keeping ‘hands-off’ all loads. Remind all crews that anyone can stop the job for safety reasons. Service company personnel to inspect the equipment at rig site together with Dafora tool-pusher (baskets, slings, crates, certification) prior to back-loading or moving.

Loading and back-loading equipment - Risk of dropping/damaging equipment.

HSSE incident e.g. fatality or damage to equipment.

H

M

H

Service Companies shall inspect all lifting gear for equipment for proper certification and colour coding prior to sending to the rig.

L

Do not use web slings. Always use tag lines – No hands on loads! Work permits to be issued for lifts over 5t. NEVER STAND UNDER A MOVING LOAD Program changes have to be approved by DOTL and ETL.

Project fast tracking

Exceeding project AFE due to NPT

M

L

M

L

Accurate reporting in DDR. Make use of expertise within the team e.g. service companies.


Page 49 of 76


Remnant Risk

Consequence

Risk


Probability

13-⅜” Casing Drilling (17-½” Hole)

Impact

18.2

Maintain low mud weight. Using WBM which is comparatively cheaper than NAF.

Mud losses in surface formation (Helvetian), particularly @ ~50m and ~100m. No possibility to set cement plug as loss prevention strategy.

Ensure mud properties are optimised for filter cake building. • NPT. • Cost of lost mud + LCM. • Poor ROP. • Poor hole cleaning • Failure to reach TD with casing.

M

H

H

LCM pills mixed and ready onsite in case of losses. Use medium-coarse LCM which is continually added to the active system.

H

Limit ROP and pump rate if losses are encountered (reducing ECD). Casing drilling should minimise losses due to smear effect. Predicted FG permits drilling 12-¼” from 300m if required. Keep mud properties as per Program, thin and dilute as required.

Bit/BHA balling (shale bands).

Have detergent continually added to the active mud system.

NPT due to low ROP. This section will be drilled with spud mud (WBM) using a PDC bit with a low HSI (large nozzles for LCM). Bit trip not possible.

Bit wear (pyrite and microconglomerates in surface formations) All offset wells used a PDC bit.

Hole instability.

Inability to reach TD with casing.

H

M

H

M Casing drilling minimises WOB and so balling tendency should be reduced. Predicted FG permits drilling 12-¼” from 300m if required. Bit selected which is optimised for highly abrasive environments.

• NPT due to low ROP. • Inability to reach TD with casing.

H

M

H

Casing drilling requires less WOB and RPM than conventional drilling which will result in less wear.

L

Predicted FG permits drilling 12-¼” from 300m if required. NPT caused by stuck pipe. Fishing operations.

M

L

M

Keep mud parameters as per program (MW, Viscosity).

L

Loss zones thought to be above 100m and so most of cement slurry should be unaffected.

Cement losses.

• NPT. • Cost of lost cement. • Wellhead / BOP instability.

M

H

M

If losses are encountered during drilling LCM will be added to cement slurry. At first sign of losses reduced pump rate. Perform surface top-up job if necessary.


Page 50 of 76

L


Remnant Risk

Consequence

Risk


Probability

9-⅝” Section (12-¼” Hole)

Impact

18.3

NAF planned for this section; increased inhibition compared to offset wells which used WBM. 259 Colibasi had low incidents of over pulls through use of NAF. NPT caused by overpulls and excessive reaming.

M

Shale instability.

L

M

Potential pack-off and fishing operations.

Follow program and Baker Hughes guidance to ensure sufficient flow rate and RPM for hole cleaning.

L

Supervisor to provide ‘best practices’ for hole cleaning guidance. Ream stand prior to connection ONLY IF HOLE CONDITIONS DICTATE. If losses are encountered during drilling LCM will be added to cement slurry.

Cement losses e.g. if penetration into Meotian is excessive.

Ineffective zonal isolation of overburden formations (above reservoir).


M

L

M

At first sign of losses during cement job reduced pump rate.

L

Maximum 10m penetration into Meotian will be ensured through cutting analysis as outlined in the drilling operations summary

Page 51 of 76


Remnant Risk

Consequence

Risk


Probability

7” Section (8-½” Hole)

Impact

18.4

Use Soft Drilling Techniques and drilling best practices. Borehole stability. BHA pack-off during drilling or tripping (in Oligocen).

NPT caused by stuck pipe and/or fishing operations.

Keep mud parameters as programmed. M

H

H

BHA lost on hole charge. Side-track.

Periodically perform wiper trips only if hole conditions dictate.

L

Minimse open hole exposure time i.e. case off section as quickly as possible. 290 offset well only encountered losses at 2430mTVD i.e. 135mTVD deeper than 258 Colibasi is planned.

Mud losses in Oligocene .

• NPT. • Cost of lost NAF. • Poor ROP • Losses during cement job likely

Maintain low mud weight (only increase if hole conditions dictate).

M

L

M

Limit ROP and pump rate if losses are encountered (reducing ECD).

L

Ensure mud properties are optimised for filter cake building. LCM onsite in case of losses. Use LCM continually added to the active system. Set cement plug if necessary. 290 offset well indicated low chance of encountering salt.

Salt encountered during drilling.

Chemicals onsite to make mud system salt compatible if required. Stuck pipe possibility.

M

L

L

M

Suitable cement slurry will have been worked as a contingency. Salt exit strategy guidelines in appendix. Ops geologist to use Gamma Ray for correlation.

NPT caused by remedial Wrong Casing Setting Depth works at the shoe.

M

L

M

Control ROP to 5 m/hr prior to intercepting the prognosed TD to permit cutting analysis by ops geologist.

L

Can mill out shoe track if required. Have 4.5” contingency liner if required. Use CemNet in cement slurry and LCM if losses are encountered when drilling.

Loss of production. Losses during cement job failure to provide good zonal isolation over pay-zone.

Hydrocarbon migration into the B-annulus. NPT due to repair/water shut-off works.


H

M

M

Reduce cement displacement rate if losses are encountered whilst pumping cement. 258 Colibasi slurry excess calibrated with respect to 259 Colibasi cementing performance.

Page 52 of 76

M

18.5

Wellhead, BOP and Pressure Test Program.

18.5.1 Barrier Policy “Independent” means that any barrier must not rely on another barrier for its integrity. “Tested” means that there is no flow and no pressure drop across the barrier. Where possible, the barrier should be tested in the direction of potential flow and to the maximum anticipated differential pressure. When a fluid is used as one of the barriers, its level, weight and properties must be continuously monitored. • • •

•

•

18.6

A minimum of two independent and tested barriers shall be established and maintained during all planned well operations. When a barrier fails, immediate action must be taken to restore the two barrier situation as soon as possible. Two Temporary Barriers shall be installed prior to undertaking the removal of any well control equipment (i.e.: BOPs and Christmas tree) after hydrocarbon bearing or overpressured permeable zones have been encountered. Temporary Barriers may come from the following families of equipment: cement plugs, packers, retrievable packers, bridge plugs, tubing hanger plugs, wire-line plugs, DHSVs and tree valves as long as they can be tested leak tight. During drilling operations, the mud column is deemed as a barrier since its level, weight and properties can be continuously verified and the BOP stack is a barrier since it can be closed quickly. It is also only deemed as a single barrier since only the lowest connection can be verified. The temporary barriers shall be installed in such a way that the well can be re-entered and secured using the well control equipment without compromising these barriers.

Management of Change

Deviations from the Drilling Program may become necessary due to changes in well conditions, procedures or equipment requirements. In this event change control will be achieved through the implementation of the change control procedure as detailed below: • •

Minor changes to the program are discussed and agreed at the Morning Operations meeting. All program changes should be recorded in the meeting minutes or DDR. Significant changes to the program, or significant additional operations not included in the program, should be discussed and agreed to by rig and office teams and confirmed in writing with a Program Supplement issued prior to commencing the change in program. Program Supplements are communicated to the Budget Holder and the Drilling Manager, or their delegates, and form part of the Drilling Program.

When the events occur outside normal working hours, if operational constraints require immediate action, it will be permissible to proceed on the basis of verbal authorisation from the Drilling Manager, or his delegate, if this is in agreement with the Senior Drilling Supervisor. Changes affecting safety must as a minimum be discussed and agreed with PETROM Well Site Supervisor. Verbal instructions must be confirmed in writing on the next working day.


Page 53 of 76

19 19.1

APPENDIX Bit Program


Page 54 of 76


Page 55 of 76

19.2

Directional Program

The directional program may be updated during operations.


Page 56 of 76


Page 57 of 76

Advancing Reservoir Performance

Technical Proposal Rev.3 258 Colibasi

© Baker Hughes 25.06.2012; R. Harabagiu, J. Maeh

© 2012 Baker Hughes Incorporated. All rights reserved.

www.bakerhughes.com

Technical Proposal Directional well 258 Colibasi

Technical Proposal Rev.3 Directional- and MWD-Service Directional Well

258 Colibasi Drilling Engineering Contact: Ramona Harabagiu / J. Maehs Baker Hughes 10 Conului St Ploiesti, Romania +40 0731 495 926

25-Jun-2012

The information contained herein is believed to be accurate and, where appropriate, based on sound engineering principles. However, Baker Hughes INTEQ Inc. makes no warranties or representations to that effect. All such information is furnished "as is", and use of such information is entirely at the risk of the user.

© Baker Hughes 25.06.2012;

Ramona Harabagiu, J. Maehs


Table of Content

1. Introduction 2. Well Trajectory 3. 12 1/4” Hole Section 4. 8 1/2” Hole Section 5. 6” Hole Section Contingency BHA

6. Attachments HS&E Inspection Sheet Rig Operations Anti-collision Summary




Changes: Rev.0 (27-04-2012)\ Rev.2 (10-06-2012) Rev.3 (25-06-2012)

\




1.

Introduction




1. Introduction This Proposal contains the BHA’s design for the drilling process of the well 258 Colibasi, Romania. 258 Colibasi is a deviated well with a TD of 2325m MD (2300 TVD RT). After the 30” conductor will be hammered at ±21.75m MD, the casing while drilling operation will start for drill the top section, until 500m with the purpose of isolating the top formation where major mud losses can occur. The next section will be drill directional to 1737m MD (1731m TVD RT) where the 9 5/8 casing shoe will be set to close the Dacian and Pontian formation. This section will be drill vertically KOP at 1425m MD and afterward build up to 15.072˚ inclination with a DLS of ±2de/30m into direction of 273.327˚. For this section a steerable BHA with a roller/PDC cone bit, 8in Ultra XL motor and 8 1/4in NaviGamma LWD will be run. For 8 1/2in section we propose a fully stabilized steerable BHA with 6 3/4in Ultra XL motor (8 1/4in UBHS) and OnTrak LWD for resistivity and gamma ray data in real time. An AKO of 1.1˚ will be set on the motor in order to keep the inclination to well TD 2325m MD(2300m TVD) and hit the given target at 2164m MD (2144m TVD RT).




2.

Well Trajectory




2. Well Trajectory

The following surface coordinates for well 258 Colibasi have been given: Northing: 388 947.54

Easting: 544 412.75

Latitude: 44° 59' 57.093"N

Longitude: 25°33' 48.103"E

TVD reference is RT with 349.16m above MSL.

The well was planned to be drilled deviated and hit given target: T-Kliwa Sup II Northing 388 957

Easting: 544 250

2144m TVD RT

All coordinates are given in the Stereo-70 Grid system. The azimuth values are referenced to Grid North. The targets are given as a drillers target with a tolerance circle of 50m radius. The anti-collision calculation was run with the next offsets wells: 290 Colibasi and 259 Colibasi. The minimum separation factor seen is 11.51 diverging from 1735.5m MD and minimum C-C distance of 125.11m at 510m MD.



OMV PETROM

Location: ROMANIA Field: Colibasi 2011 Facility: Colibasi

Slot: Slot#258 Colibasi Well: #258 Colibasi Wellbore: #258 Colibasi(PWP)

Easting (m)

15 de g H ol d

En d

of t

En d

an ge n

Ta ng en t -T D

Dacian @429m MD(TVD) 13 3/8in CSG 500m MD

Well Profile Data

True Vertical Depth (m)

Design Comment Tie On End of tangent End of build Hold 15deg Tangent-TD

MD (m) 0.00 1425.00 1651.08 2164.42 2325.00

Inc (°) 0.000 0.000 15.072 15.072 15.072

Az (°) 273.327 273.327 273.327 273.327 273.327

TVD (m) 0.00 1425.00 1648.48 2144.16 2299.22

Local N (m) 0.00 0.00 1.72 9.46 11.88

Local E (m) 0.00 0.00 -29.52 -162.78 -204.46

DLS (°/30m) 0.00 0.00 2.00 0.00 0.00

VS (m) 0.00 0.00 29.57 163.05 204.81

TVD (m)

Local N (m)

Local E (m)

Grid East (m)

Grid North (m)

Latitude

Longitude

9.46

-162.78

544250.00

388957.00

44°59'57.437"N

25°33'40.674"E

Targets

Pontian @1119m MD(TVD) Name

T-Kliwa II Sup

MD (m)

2164.42 2144.16

Hole and Casing Sections End of tangent KOP @1425m MD

Name

Start MD (m)

End MD (m)

Interval (m)

Start TVD (m)

End TVD (m)

Start Local N (m)

Start Local E (m)

End Local N (m)

End Local E (m)

Wellbore

20in Conductor

0.00

21.75

21.75

0.00

21.75

0.00

0.00

0.00

0.00

#258 Colibasi(PWP)

13.375in Casing

0.00

500.00

500.00

0.00

500.00

0.00

0.00

0.00

0.00

#258 Colibasi(PWP)

12.25in Open Hole

500.00

1736.54

1236.54

500.00

1731.00

0.00

0.00

3.01

-51.70

#258 Colibasi(PWP)

9.625in Casing

0.00

1736.54

1736.54

0.00

1731.00

0.00

0.00

3.01

-51.70

#258 Colibasi(PWP)

8.5in Open Hole

1736.54

2325.00

588.46

1731.00

2299.22

3.01

-51.70

11.88

-204.46

#258 Colibasi(PWP)

7in Casing

0.00

2325.00

2325.00

0.00

2299.22

0.00

0.00

11.88

-204.46

#258 Colibasi(PWP)

2.00°/30m

End of build Meotian @1715m MD(@1719m TVD) 9 5/8in CSG Shoe @1737m MD(1731m TVD) Helvetian @1807m MD(1799m TVD) Meotian

KliWa Sup I@2056m MD(2039m TVD) T-Kliwa II Sup

Hold 15deg Kliwa Sup III @2273m MD (2249m TVD) #258

Tangent-TD 7in CSG Shoe @2325m MD(2300m TVD)

WP) asi(P Colib Plot reference wellpath is #258 Colibasi Rev.B.0

Vertical Section (m)

Scale 1 cm = 125 m

Azimuth 273.33° with reference 0.00 N, 0.00 E

True vertical depths are referenced to Rig on Slot#258 Colibasi (RT)

Grid System: Pulkovo 1942(58) / Stereo 70

Measured depths are referenced to Rig on Slot#258 Colibasi (RT)

North Reference: Grid north

Rig on Slot#258 Colibasi (RT) to Mean Sea Level: 349.16 meters

Scale: True distance

Mean Sea Level to Mud line (At Slot: Slot#258 Colibasi ): -344.16 meters

Depths are in meters

Coordinates are in meters referenced to Slot

Created by: hararam on 25-Jun-12

Northing (m)

T-Kliwa II Sup

#258 Colibasi(PWP)

t Slot#258 Colibasi

Tie On 20in Conductor

of bu ild

Scale 1 cm = 125 m

Scale 1 cm = 20 m

Œâ

Planned Wellpath Report #258 Colibasi Rev.B.0 Page 1 of 5 REFERENCE WELLPATH IDENTIFICATION Operator Area Field Facility

PETROM ROMANIA Colibasi 2011 Colibasi

Slot Well Wellbore

Slot#258 Colibasi #258 Colibasi #258 Colibasi(PWP)

REPORT SETUP INFORMATION Projection System North Reference Scale Convergence at slot

Pulkovo 1942(58) / Stereo 70 Grid 0.999838 0.40° East

Software System User Report Generated Database/Source file

WellArchitect® 3.0.0 Hararam 25-Jun-12 at 14:56:09 WellArchitectDB/#258_Colibasi_PWP_.xml

WELLPATH LOCATION

Slot Location Facility Reference Pt Field Reference Pt

Local coordinates North[m] East[m] -458.53 -158.28

Grid coordinates Easting[m] Northing[m] 544412.75 388947.54 544571.00 389406.00 544571.00 389406.00

Geographic coordinates Latitude Longitude 44°59'57.093"N 25°33'48.103"E 45°00'11.910"N 25°33'55.476"E 45°00'11.910"N 25°33'55.476"E

WELLPATH DATUM Calculation method Horizontal Reference Pt Vertical Reference Pt MD Reference Pt Field Vertical Reference

pç

Minimum curvature Slot Rig on Slot#258 Colibasi (RT) Rig on Slot#258 Colibasi (RT) Mean Sea Level

Rig on Slot#258 Colibasi (RT) to Facility Vertical Datum Rig on Slot#258 Colibasi (RT) to Mean Sea Level Rig on Slot#258 Colibasi (RT) to Mud Line at Slot (Slot#258 Colibasi ) Section Origin Section Azimuth

349.16m 349.16m 5.00m N 0.00, E 0.00 m 273.33°

Œâ



Slot Well Wellbore

WELLPATH DATA (90 stations) MD [m]

0.00 30.00† 60.00† 90.00† 120.00† 150.00† 180.00† 210.00† 240.00† 270.00† 300.00† 330.00† 360.00† 390.00† 420.00† 429.00† 450.00† 480.00† 500.00† 510.00† 540.00† 570.00† 600.00† 630.00† 660.00† 690.00† 720.00† 750.00† 780.00† 810.00†

pç

† = interpolated/extrapolated station

Inclination Azimuth TVD TVD from Vert Sect North East Grid East Grid North [°] [°] [m] Fld Vert Ref [m] [m] [m] [m] [m] [m]

0.000 273.327 0.00 0.000 273.327 30.00 0.000 273.327 60.00 0.000 273.327 90.00 0.000 273.327 120.00 0.000 273.327 150.00 0.000 273.327 180.00 0.000 273.327 210.00 0.000 273.327 240.00 0.000 273.327 270.00 0.000 273.327 300.00 0.000 273.327 330.00 0.000 273.327 360.00 0.000 273.327 390.00 0.000 273.327 420.00 0.000 273.327 429.00 0.000 273.327 450.00 0.000 273.327 480.00 0.000 273.327 500.00 0.000 273.327 510.00 0.000 273.327 540.00 0.000 273.327 570.00 0.000 273.327 600.00 0.000 273.327 630.00 0.000 273.327 660.00 0.000 273.327 690.00 0.000 273.327 720.00 0.000 273.327 750.00 0.000 273.327 780.00 0.000 273.327 810.00


-349.16 -319.16 -289.16 -259.16 -229.16 -199.16 -169.16 -139.16 -109.16 -79.16 -49.16 -19.16 10.84 40.84 70.84 79.84 100.84 130.84 150.84 160.84 190.84 220.84 250.84 280.84 310.84 340.84 370.84 400.84 430.84 460.84

0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

544412.75 544412.75 544412.75 544412.75 544412.75 544412.75 544412.75 544412.75 544412.75 544412.75 544412.75 544412.75 544412.75 544412.75 544412.75 544412.75 544412.75 544412.75 544412.75 544412.75 544412.75 544412.75 544412.75 544412.75 544412.75 544412.75 544412.75 544412.75 544412.75 544412.75

388947.54 388947.54 388947.54 388947.54 388947.54 388947.54 388947.54 388947.54 388947.54 388947.54 388947.54 388947.54 388947.54 388947.54 388947.54 388947.54 388947.54 388947.54 388947.54 388947.54 388947.54 388947.54 388947.54 388947.54 388947.54 388947.54 388947.54 388947.54 388947.54 388947.54

Latitude

Longitude

44°59'57.093"N 44°59'57.093"N 44°59'57.093"N 44°59'57.093"N 44°59'57.093"N 44°59'57.093"N 44°59'57.093"N 44°59'57.093"N 44°59'57.093"N 44°59'57.093"N 44°59'57.093"N 44°59'57.093"N 44°59'57.093"N 44°59'57.093"N 44°59'57.093"N 44°59'57.093"N 44°59'57.093"N 44°59'57.093"N 44°59'57.093"N 44°59'57.093"N 44°59'57.093"N 44°59'57.093"N 44°59'57.093"N 44°59'57.093"N 44°59'57.093"N 44°59'57.093"N 44°59'57.093"N 44°59'57.093"N 44°59'57.093"N 44°59'57.093"N

25°33'48.103"E 25°33'48.103"E 25°33'48.103"E 25°33'48.103"E 25°33'48.103"E 25°33'48.103"E 25°33'48.103"E 25°33'48.103"E 25°33'48.103"E 25°33'48.103"E 25°33'48.103"E 25°33'48.103"E 25°33'48.103"E 25°33'48.103"E 25°33'48.103"E 25°33'48.103"E 25°33'48.103"E 25°33'48.103"E 25°33'48.103"E 25°33'48.103"E 25°33'48.103"E 25°33'48.103"E 25°33'48.103"E 25°33'48.103"E 25°33'48.103"E 25°33'48.103"E 25°33'48.103"E 25°33'48.103"E 25°33'48.103"E 25°33'48.103"E

Polar Radius Polar Bearing Closure Dist Closure Dir DLS Comments [m] [°] [m] [°] [°/30m]

0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000

0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000

0.00 Tie On 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Dacian @429m MD(TVD) 0.00 0.00 0.00 13 3/8in CSG 500m MD 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

Œâ



Slot Well Wellbore


Inclination Azimuth [°] [°]

TVD [m]


TVD from Fld Vert Ref [m]

Vert North East Sect [m] [m] [m]

840.00† 870.00† 900.00† 930.00† 960.00† 990.00† 1020.00† 1050.00† 1080.00† 1110.00† 1119.00† 1140.00† 1170.00† 1200.00† 1230.00† 1260.00† 1290.00† 1320.00† 1350.00† 1380.00† 1410.00†

0.000 273.327 840.00 0.000 273.327 870.00 0.000 273.327 900.00 0.000 273.327 930.00 0.000 273.327 960.00 0.000 273.327 990.00 0.000 273.327 1020.00 0.000 273.327 1050.00 0.000 273.327 1080.00 0.000 273.327 1110.00 0.000 273.327 1119.00 0.000 273.327 1140.00 0.000 273.327 1170.00 0.000 273.327 1200.00 0.000 273.327 1230.00 0.000 273.327 1260.00 0.000 273.327 1290.00 0.000 273.327 1320.00 0.000 273.327 1350.00 0.000 273.327 1380.00 0.000 273.327 1410.00

490.84 520.84 550.84 580.84 610.84 640.84 670.84 700.84 730.84 760.84 769.84 790.84 820.84 850.84 880.84 910.84 940.84 970.84 1000.84 1030.84 1060.84

0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

1425.00

0.000 273.327 1425.00

1075.84

0.00 0.00

1440.00† 1470.00† 1500.00† 1530.00† 1560.00† 1590.00† 1620.00† 1650.00†

1.000 273.327 1440.00 3.000 273.327 1469.98 5.000 273.327 1499.90 7.000 273.327 1529.74 9.000 273.327 1559.45 11.000 273.327 1588.99 13.000 273.327 1618.33 15.000 273.327 1647.44

1090.84 1120.82 1150.74 1180.58 1210.29 1239.83 1269.17 1298.28

pç


0.13 1.18 3.27 6.41 10.58 15.79 22.03 29.28

0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

0.01 0.07 0.19 0.37 0.61 0.92 1.28 1.70

Latitude

Longitude

44°59'57.093"N 44°59'57.093"N 44°59'57.093"N 44°59'57.093"N 44°59'57.093"N 44°59'57.093"N 44°59'57.093"N 44°59'57.093"N 44°59'57.093"N 44°59'57.093"N 44°59'57.093"N 44°59'57.093"N 44°59'57.093"N 44°59'57.093"N 44°59'57.093"N 44°59'57.093"N 44°59'57.093"N 44°59'57.093"N 44°59'57.093"N 44°59'57.093"N 44°59'57.093"N

25°33'48.103"E 25°33'48.103"E 25°33'48.103"E 25°33'48.103"E 25°33'48.103"E 25°33'48.103"E 25°33'48.103"E 25°33'48.103"E 25°33'48.103"E 25°33'48.103"E 25°33'48.103"E 25°33'48.103"E 25°33'48.103"E 25°33'48.103"E 25°33'48.103"E 25°33'48.103"E 25°33'48.103"E 25°33'48.103"E 25°33'48.103"E 25°33'48.103"E 25°33'48.103"E

0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000

0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000

0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Pontian @1119m MD(TVD) 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

0.00 544412.75 388947.54 44°59'57.093"N 25°33'48.103"E

0.00

0.000

0.00

0.000

0.13 1.05 2.09 3.14 4.17 5.21 6.24 7.26

273.327 273.327 273.327 273.327 273.327 273.327 273.327 273.327

0.13 1.18 3.27 6.41 10.58 15.79 22.03 29.28

273.327 273.327 273.327 273.327 273.327 273.327 273.327 273.327

0.00 KOP @1425m MD 2.00 2.00 2.00 2.00 2.00 2.00 2.00 2.00

0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

-0.13 -1.18 -3.26 -6.40 -10.56 -15.76 -21.99 -29.24

Grid East Grid North [m] [m]

544412.75 544412.75 544412.75 544412.75 544412.75 544412.75 544412.75 544412.75 544412.75 544412.75 544412.75 544412.75 544412.75 544412.75 544412.75 544412.75 544412.75 544412.75 544412.75 544412.75 544412.75

544412.62 544411.57 544409.49 544406.36 544402.19 544396.99 544390.76 544383.52

388947.54 388947.54 388947.54 388947.54 388947.54 388947.54 388947.54 388947.54 388947.54 388947.54 388947.54 388947.54 388947.54 388947.54 388947.54 388947.54 388947.54 388947.54 388947.54 388947.54 388947.54

388947.55 388947.61 388947.73 388947.91 388948.15 388948.46 388948.82 388949.24

44°59'57.093"N 44°59'57.096"N 44°59'57.100"N 44°59'57.107"N 44°59'57.115"N 44°59'57.126"N 44°59'57.140"N 44°59'57.155"N

25°33'48.097"E 25°33'48.049"E 25°33'47.954"E 25°33'47.811"E 25°33'47.621"E 25°33'47.383"E 25°33'47.099"E 25°33'46.769"E

Polar Radius [m]

Polar Bearing [°]

Closure Dist [m]

Closure DLS Comments Dir [°/30m] [°]

End of tangent;

Œâ



Slot Well Wellbore


Inclination Azimuth [°] [°]

TVD [m]



TVD from Fld Vert Ref [m]

Vert Sect [m]

East [m]

Grid East Grid North [m] [m]

Latitude

Longitude

1651.08 1680.00† 1710.00† 1724.11† 1736.54† 1740.00† 1770.00† 1800.00† 1806.96† 1830.00† 1860.00† 1890.00† 1920.00† 1950.00† 1980.00† 2010.00† 2040.00† 2055.51† 2070.00† 2100.00† 2130.00† 2160.00† 2164.42 2190.00† 2220.00† 2250.00† 2272.99† 2280.00† 2310.00†

15.072 273.327 1648.48 1299.32 15.072 273.327 1676.41 1327.25 15.072 273.327 1705.37 1356.21 15.072 273.327 1719.00 1369.84 15.072 273.327 1731.00 1381.84 15.072 273.327 1734.34 1385.18 15.072 273.327 1763.31 1414.15 15.072 273.327 1792.28 1443.12 15.072 273.327 1799.00 1449.84 15.072 273.327 1821.25 1472.09 15.072 273.327 1850.21 1501.05 15.072 273.327 1879.18 1530.02 15.072 273.327 1908.15 1558.99 15.072 273.327 1937.12 1587.96 15.072 273.327 1966.09 1616.93 15.072 273.327 1995.05 1645.89 15.072 273.327 2024.02 1674.86 15.072 273.327 2039.00 1689.84 15.072 273.327 2052.99 1703.83 15.072 273.327 2081.96 1732.80 15.072 273.327 2110.93 1761.77 15.072 273.327 2139.89 1790.73 15.072 273.327 2144.161 1795.00 15.072 273.327 2168.86 1819.70 15.072 273.327 2197.83 1848.67 15.072 273.327 2226.80 1877.64 15.072 273.327 2249.00 1899.84 15.072 273.327 2255.77 1906.61 15.072 273.327 2284.73 1935.57

2325.00

15.072 273.327 2299.22 1950.06 204.81 11.88 -204.46 544208.32 388959.42 44°59'57.525"N 25°33'38.772"E

pç

29.57 37.09 44.89 48.56 51.79 52.69 60.49 68.29 70.10 76.09 83.89 91.69 99.49 107.29 115.10 122.90 130.70 134.73 138.50 146.30 154.10 161.90 163.05 169.70 177.50 185.31 191.28 193.11 200.91

North [m]

1.72 -29.52 544383.24 388949.26 44°59'57.155"N 25°33'46.756"E 2.15 -37.02 544375.73 388949.69 44°59'57.171"N 25°33'46.413"E 2.60 -44.81 544367.95 388950.14 44°59'57.188"N 25°33'46.058"E 2.82 -48.47 544364.28 388950.36 44°59'57.195"N 25°33'45.891"E 3.01 -51.70 544361.06 388950.54 44°59'57.202"N 25°33'45.743"E 3.06 -52.60 544360.16 388950.60 44°59'57.204"N 25°33'45.702"E 3.51 -60.39 544352.37 388951.05 44°59'57.221"N 25°33'45.347"E 3.96 -68.17 544344.59 388951.50 44°59'57.237"N 25°33'44.991"E 4.07 -69.98 544342.78 388951.61 44°59'57.241"N 25°33'44.909"E 4.42 -75.96 544336.80 388951.95 44°59'57.253"N 25°33'44.636"E 4.87 -83.75 544329.01 388952.41 44°59'57.270"N 25°33'44.281"E 5.32 -91.54 544321.23 388952.86 44°59'57.286"N 25°33'43.925"E 5.77 -99.33 544313.44 388953.31 44°59'57.303"N 25°33'43.570"E 6.23 -107.11 544305.65 388953.77 44°59'57.319"N 25°33'43.214"E 6.68 -114.90 544297.87 388954.22 44°59'57.336"N 25°33'42.859"E 7.13 -122.69 544290.08 388954.67 44°59'57.352"N 25°33'42.504"E 7.58 -130.48 544282.29 388955.12 44°59'57.368"N 25°33'42.148"E 7.82 -134.50 544278.27 388955.36 44°59'57.377"N 25°33'41.964"E 8.04 -138.27 544274.51 388955.58 44°59'57.385"N 25°33'41.793"E 8.49 -146.05 544266.72 388956.03 44°59'57.401"N 25°33'41.437"E 8.94 -153.84 544258.93 388956.48 44°59'57.418"N 25°33'41.082"E 9.39 -161.63 544251.15 388956.93 44°59'57.434"N 25°33'40.726"E 9.46 -162.78 544250.00 388957.00 44°59'57.437"N 25°33'40.674"E 9.85 -169.42 544243.36 388957.39 44°59'57.451"N 25°33'40.371"E 10.30 -177.21 544235.57 388957.84 44°59'57.467"N 25°33'40.016"E 10.75 -184.99 544227.79 388958.29 44°59'57.483"N 25°33'39.660"E 11.10 -190.96 544221.82 388958.64 44°59'57.496"N 25°33'39.388"E 11.21 -192.78 544220.00 388958.74 44°59'57.500"N 25°33'39.305"E 11.66 -200.57 544212.21 388959.20 44°59'57.516"N 25°33'38.949"E

Polar Polar Closure Closure DLS Comments Radius Bearing Dist Dir [°/30m] [m] [°] [m] [°]

0.28 7.52 7.80 3.67 3.23 0.90 7.80 7.80 1.81 5.99 7.80 7.80 7.80 7.80 7.80 7.80 7.80 4.03 3.77 7.80 7.80 7.80 1.15 6.65 7.80 7.80 5.98 1.82 7.80

273.327 273.327 273.327 273.327 273.327 273.327 273.327 273.327 273.327 273.327 273.327 273.327 273.327 273.327 273.327 273.327 273.327 273.327 273.327 273.327 273.327 273.327 273.327 273.327 273.327 273.327 273.327 273.327 273.327

29.57 37.09 44.89 48.56 51.79 52.69 60.49 68.29 70.10 76.09 83.89 91.69 99.49 107.29 115.10 122.90 130.70 134.73 138.50 146.30 154.10 161.90 163.05 169.70 177.50 185.31 191.28 193.11 200.91

273.327 273.327 273.327 273.327 273.327 273.327 273.327 273.327 273.327 273.327 273.327 273.327 273.327 273.327 273.327 273.327 273.327 273.327 273.327 273.327 273.327 273.327 273.327 273.327 273.327 273.327 273.327 273.327 273.327

3.90 273.327 204.81 273.327

2.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

End of build

Meotian @1715m MD(@1719m TVD) 9 5/8in CSG Shoe @1737m MD(1731m TVD)

Helvetian @1807m MD(1799m TVD) Meotian

Kliw Sup I @2056m MD(2039m TVD)

Hold 15deg

Kliwa Sup III @2273m MD (2249m TVD)

Tangent-TD;

0.00 7in CSG Shoe @2325m MD(2300m TVD)

Œâ



HOLE & CASING SECTIONS - Ref Wellbore: #258 Colibasi(PWP) String/Diameter

Start MD [m]

20in Conductor 13.375in Casing 12.25in Open Hole 9.625in Casing 8.5in Open Hole 7in Casing


Slot Well Wellbore

End MD [m]

0.00 0.00 500.00 0.00 1736.54 0.00

Ref Wellpath: #258 Colibasi Rev.B.0

Interval [m]

21.75 500.00 1736.54 1736.54 2325.00 2325.00

Start TVD [m]

21.75 500.00 1236.54 1736.54 588.46 2325.00

End TVD [m]

0.00 0.00 500.00 0.00 1731.00 0.00

Start N/S [m]

21.75 500.00 1731.00 1731.00 2299.22 2299.22

Start E/W [m]

0.00 0.00 0.00 0.00 3.01 0.00

0.00 0.00 0.00 0.00 -51.70 0.00

End N/S [m]

0.00 0.00 3.01 3.01 11.88 11.88

End E/W [m]

0.00 0.00 -51.70 -51.70 -204.46 -204.46

TARGETS Name

MD [m]

TVD [m]

2164.42

1) T-Kliwa II Sup

North [m]

2144.16

9.46

East [m]

-162.78

Grid East [m]

544250.00

Grid North [m]

388957.00

Latitude

Longitude

44°59'57.437"N

25°33'40.674"E circle

SURVEY PROGRAM - Ref Wellbore: #258 Colibasi(PWP) Start MD [m]

5.00 500.00 1736.00

pç

End MD [m]

Ref Wellpath: #258 Colibasi Rev.B.0 Positional Uncertainty Model

500.00 Gyrodata standard - Drop gyro or Multi-shot 1736.00 NaviTrak (SAG, MagCorr) 2325.00 OnTrak (SAG, MagCorr)

Log Name/Comment

Shape

Wellbore

#258 Colibasi(PWP) #258 Colibasi(PWP) #258 Colibasi(PWP)

CASING WHILST DRILLING

ADVANTAGE T&D Calculation - Summary Report Case - 17 1/2" Rotary_258_Colibasi_CSWD Operator

OMV Petrom

Facility

Well

#258 Colibasi

Field

Colibasi Colibasi

Drilling Parameter

Analysis Setup

Bit Depth

500 m

Weight on Bit

1 tonne

Torque on Bit

1.598 kN.m

Calculate Indicated Hook Loads

No

Bit Drag Force

- tonne

Overpull Force

- tonne

Include Bending Influence

Yes

ROB Torque Resistance

- kN.m

Buckling Criterion

Conservative - (Unloading)

Depth Interval m

Inner Fluid Density sg 500

Depth Interval m

1.1000

Drill String Type

OD in

Csg Bit - PDC - fixed cutter

ID in

13 3/8 17 1/2

1.1000

Casing / Open Hole

TJOD in

TJID in

Act.Wt lb/ft

12.415

Length m

68.00 100.80

OD in

ID in

499.50 Open Hole 0.50

Bottom MD m

17 1/2

Tortuosity / Noise Bottom MD m

Outer Fluid Density sg 500

500.00

Friction Factor

Build-Plane Curvature Turn-Plane Curvature deg/30m deg/30m

Bottom MD m

Variation

Axial 500

Hook Load @ 0.0 MD Indicated Hook Load tonne tonne

Torsional 0.35 i

Rotary Torque kN.m

Axial Velocity Rotary Speed m/hr RPM

Drilling

43

43

1.971

ROP

20.00

45

Slack-Off

43

43

0.000

RIH

10.00

0

Pick-Up

44

44

0.000

POOH

10.00

0

Rot off Btm

44

44

0.370

Rotational Discontinuity

Drag tonne Drilling Slack-Off Pick-Up Drawwork HP Power

0 rev

Drill String Twist 0 0 0

Max Allowable HookLoad (@min. Yield) DrillString Weight in Air Bit To Neutral Point ( Drilling ) Sin. Buckling WOB at Fastline Load tonne

1.6 P O.Mode

Rotary HP

44 P Stress

No 2 deg

485 tonne 51 tonne 11.26 m 43 tonne Mud Pumps HP

12.4 D

Max Flowrate l/min 0.0

at MD

psi

Stretch cm Drilling Slack-Off Pick-Up Rot off Btm

3.84 4.01 4.05 4.03 Max SPP bar

0 O.Mode

m

300.000

Safety

at MD

Factor

m

Max Axial

P

4858.7

0.00

Min Yield Safety Factor

P

10.67

0.00

Max Torsional

D

143.1

0.00

Min Fatigue Safety Factor

D

44.14

300.00

Max Bending

D

581.7

499.50

Max Combined

D

5155.1

D Drilling

S Slack-Off

P Pick-Up

Comment Case 1: WOB=1t RPM=45 BA=1.1 FF=0.35

0.00 R Rot off Btm

i input

c calculated

Date 08-Jun-12 11:20:48 Prepared by dtquser


OMV Petrom

Facility

Well

#258 Colibasi

Field

Colibasi Colibasi

Drilling Parameter

Analysis Setup

Bit Depth

500 m

Weight on Bit

3 tonne

Torque on Bit

4.795 kN.m


No

Bit Drag Force

- tonne

Overpull Force

- tonne


Yes


- kN.m

Buckling Criterion


Depth Interval m


Depth Interval m

1.1000

Drill String Type

OD in


ID in

13 3/8 17 1/2

1.1000

Casing / Open Hole

TJOD in

TJID in

Act.Wt lb/ft

12.415

Length m

68.00 100.80

OD in

ID in

499.50 Open Hole 0.50

Bottom MD m

17 1/2



500.00

Friction Factor


Bottom MD m

Variation

Axial 500


Torsional 0.35 i

Rotary Torque kN.m


Drilling

41

41

5.176

ROP

20.00

65

Slack-Off

43

43

0.000

RIH

10.00

0

Pick-Up

44

44

0.000

POOH

10.00

0

Rot off Btm

44

44

0.370



0 rev



1.6 P O.Mode

Rotary HP

44 P Stress

No 5 deg


47.2 D


at MD

psi


3.46 4.01 4.05 4.03 Max SPP bar

0 O.Mode

m

300.000

Safety

at MD

Factor

m

Max Axial

P

4858.7

0.00


P

10.67

0.00

Max Torsional

D

377.5

0.00


D

44.20

300.00

Max Bending

D

581.7

499.50

Max Combined

D

5155.1

D Drilling

S Slack-Off

P Pick-Up


0.00 R Rot off Btm

i input

c calculated



OMV Petrom

Facility

Well

#258 Colibasi

Field

Colibasi Colibasi

Drilling Parameter

Analysis Setup

Bit Depth

500 m

Weight on Bit

5 tonne

Torque on Bit

7.992 kN.m


No

Bit Drag Force

- tonne

Overpull Force

- tonne


Yes


- kN.m

Buckling Criterion


Depth Interval m


Depth Interval m

1.1000

Drill String Type

OD in


ID in

13 3/8 17 1/2

1.1000

Casing / Open Hole

TJOD in

TJID in

Act.Wt lb/ft

12.415

Length m

68.00 100.80

OD in

ID in

499.50 Open Hole 0.50

Bottom MD m

17 1/2



500.00

Friction Factor


Bottom MD m

Variation

Axial 500


Torsional 0.35 i

Rotary Torque kN.m


Drilling

39

39

8.383

ROP

20.00

80

Slack-Off

43

43

0.000

RIH

10.00

0

Pick-Up

44

44

0.000

POOH

10.00

0

Rot off Btm

44

44

0.370



0 rev



1.6 P O.Mode

Rotary HP

44 P Stress

No 9 deg


94.1 D


at MD

psi


3.09 4.01 4.05 4.03 Max SPP bar

0 O.Mode

m

300.000

Safety

at MD

Factor

m

Max Axial

P

4858.7

0.00


P

10.67

0.00

Max Torsional

D

612.0

0.00


D

44.21

300.00

Max Bending

D

581.7

499.50

Max Combined

D

5155.1

D Drilling

S Slack-Off

P Pick-Up


0.00 R Rot off Btm

i input

c calculated


ADVANTAGE Hydraulics Spreadsheet Report Including Cuttings Transport Case - 17 1/2" Rotary_258_Colibasi_CSWD Operator

OMV Petrom

Facility

Well

#258 Colibasi

Field

Colibasi Colibasi

General

Drill String

Max Allw.SPP

300.000 bar

Surface Equipment

Type

Length m

Type 4

Bit Depth 500.00 Bit Nozzles in/32 6x12 ROP 20.00 m/hr

Bit TVD 499.91 m TFA 0.6627 in^2 RPM 80 RPM

CSG - / K-55 Bit - EZC406/BH

499.50 0.50

OD in

ID in

13 3/8 17 1/2

12.415

TJ in \ in

Weight lb/ft 68.00 100.80

Drilling Fluid Mud System Spud Mud Mud Weight 1.1000 sg PV \ YP 20.00 cP \ 30.00 lbf/100ft^2 Gel Strength, 10s\10min 11 \ 27 lbf/100ft^2 Rheological Model Power Law, API 13D K: 5.856[#sec^n/100ft^2] N: 0.362[-]

Casing / Open Hole Type

OD in

Openhole

ID in

Bottom MD m

17 1/2

500.00

Volumes bbl Annulus Volume String Displacement Flowrate

202.950 Hole Volume 39.450 String Volume l/min

488.020 245.620

3000

2800

2600

79.599 533.3 72.304 90.83 383.7 6.0 2.04

70.143 438.6 62.985 89.79 358.1 5.2 1.66

61.390 356.5 54.308 88.46 332.5 4.5 1.33

2400

2200

2000

1800

1600

1400

1200

46.094 226.5 38.883 84.36 281.4 3.2 0.81

39.655 177.1 32.135 81.04 255.8 2.7 0.61

34.180 137.4 26.029 76.15 230.2 2.2 0.44

29.991 107.2 20.566 68.57 204.6 1.7 0.31

28.084 87.8 15.746 56.07 179.1 1.3 0.21

33.800 90.6 11.569 34.23 153.5 1.0 0.13

Bit Hydraulics SPP Surface HP Bit Pressure Drop %SPP Jet Velocity Impact Force HSI

bar HP bar % ft/sec lbf/in^2 HP/in^2

53.361 286.0 46.274 86.72 307.0 3.8 1.05

System Pressure Loss - W/ Cutting Effect Surf Equip DP, CSG, LNR, TBG Annulus

bar bar bar

ECD w/ Cut- CSG Shoe sg ECD w/ Cut - BH sg

2.433 0.330 4.533

2.174 0.319 4.666

1.927 0.307 4.848

1.691 0.296 5.100

1.468 0.284 5.459

1.257 0.271 5.992

1.058 0.257 6.835

0.874 0.243 8.309

0.703 0.228 11.407

0.547 0.211 21.474

1.1925 1.1925

1.1952 1.1952

1.1989 1.1989

1.2040 1.2040

1.2114 1.2114

1.2222 1.2222

1.2394 1.2394

1.2695 1.2695

1.3327 1.3327

1.5380 1.5380

101.68 L

91.51 L

81.34 L

71.17 L

71.17 L

0.3 0.3

0.4 0.3

0.4 0.3

0.5 0.4

0.5 0.4

Annular Velocities ft/min Flow Regime Hole ID in

String OD in

17 1/2

13 3/8

152.52 L

142.35 L

132.18 L

122.01 L

111.85 L

Fluid Circulation Times Surface to Bit Bottom Up

hr hr

0.2 0.2

0.2 0.2

0.3 0.2

0.3 0.2

0.3 0.2

Page 1 Comment Hydraulics Results at 500m MD: ROP =20m/h with 6x10/32" Nozzles FR=200lpm


ADVANTAGE Hydraulics Spreadsheet Report Including Cuttings Transport Case - 17 1/2" Rotary_258_Colibasi_CSWD Operator

OMV Petrom

Facility

Well

#258 Colibasi

Field

Colibasi Colibasi

General

Drill String

Max Allw.SPP

300.000 bar

Surface Equipment

Type

Length m

Type 4



CSG - / K-55 Bit - EZC406/BH

499.50 0.50

OD in

ID in

13 3/8 17 1/2

12.415

TJ in \ in

Weight lb/ft 68.00 100.80

Drilling Fluid Mud System Spud Mud Mud Weight 1.1000 sg PV \ YP 20.00 cP \ 30.00 lbf/100ft^2 Gel Strength, 10s\10min 11 \ 27 lbf/100ft^2 Rheological Model Power Law, API 13D K: 5.856[#sec^n/100ft^2] N: 0.362[-]


OD in

Openhole

ID in

Bottom MD m

17 1/2

500.00



488.020 245.620

3200

3000

2800

336.540 2405.1 329.062 97.78 818.5 13.7 9.92

296.510 1986.6 289.215 97.54 767.4 12.0 8.17

259.097 1620.2 251.938 97.24 716.2 10.5 6.65

2600

2400

2200

2000

1800

1600

1400

192.184 1030.1 185.097 96.31 613.9 7.7 4.19

162.744 799.6 155.533 95.57 562.7 6.5 3.22

136.060 607.7 128.540 94.47 511.6 5.3 2.42

112.268 451.3 104.117 92.74 460.4 4.3 1.77

91.691 327.6 82.265 89.72 409.3 3.4 1.24

75.322 235.5 62.985 83.62 358.1 2.6 0.83



224.314 1302.5 217.232 96.84 665.1 9.0 5.32

System Pressure Loss - W/ Cutting Effect Surf Equip DP, CSG, LNR, TBG Annulus

bar bar bar


2.702 0.340 4.435

2.433 0.330 4.533

2.174 0.319 4.666

1.927 0.307 4.848

1.691 0.296 5.100

1.468 0.284 5.459

1.257 0.271 5.992

1.058 0.257 6.835

0.874 0.243 8.309

0.703 0.228 11.407

1.1905 1.1905

1.1925 1.1925

1.1952 1.1952

1.1989 1.1989

1.2040 1.2040

1.2114 1.2114

1.2222 1.2222

1.2394 1.2394

1.2695 1.2695

1.3327 1.3327

111.85 L

101.68 L

91.51 L

81.34 L

81.34 L

0.3 0.2

0.3 0.3

0.4 0.3

0.4 0.3

0.5 0.4


String OD in

17 1/2

13 3/8

162.68 L

152.52 L

142.35 L

132.18 L

122.01 L

Fluid Circulation Times Surface to Bit Bottom Up

hr hr

0.2 0.2

0.2 0.2

0.2 0.2

0.3 0.2

0.3 0.2

Page 1 Comment Hydraulics Results at 500m MD: ROP =20m/h with 6x10/32" Nozzles FR=200lpm



3. 12 1/4” Hole section




12 1/4” Directional-BHA with Ultra XL motor and NaviGamma --------------------------------------------------------------------------------------------------------------------------Section: Length: Profile: Formations:

500 m to 1737 m MD 1237m Deviated Grey-yellowish sandstones, fine to medium grained with grey sandy-marls intercalations BHA: Fully stabilized rotary BHA with 8” Ultra XL motor and NaviGamma MWD/LWD: NaviGamma Corrections: Azimuth-Correction to Grid Nord (Stereo70) / MagCorr, ----------------------------------------------------------------------------------------------------------------------12 1/4”

Roller/PDC Bit

BHI

Navi-Drill UltraXL, AKO 1.1˚, 12 1/8” UBHS

BHI

12 1/8”

String Stabilizer

6-5/8” Reg PxB

BHI

8”

Float Sub(bored)

6-5/8” Reg PxB

BHI

8 1/4”

NaviGamma(Gamma , directional) 6-5/8” Reg PxB

BHI

8 1/4”

Pulser Sub

6-5/8” Reg PxB

BHI

Filter sub

6-5/8” Reg PxB

BHI

String Stabilizer

6-5/8” Reg PxB

BHI

8”

Drill Collar

6-5/8” Reg PxB

8”

Cross Over

6-5/8” Reg PxNC50B

2x

6 1/2”

Drill Collar

NC50PxB

18m

Client

8x

5”

HWDP

NC50PxB

72m

Client

Jar

NC50 PxB

5”

HWDP

NC50PxB

45m

Client

5”

Drill Pipe (S-135, 19.5 lbs/ft)

NC50 PxB

to surface

Client

8”

8” 12” 2x

6 1/2” 5x

18m

Client Client

Client

Note: Maximum surface rotation allowed for 8” Ultra XL motor with actual stabilization 1.1˚AKO is 90RPM.



ADVANTAGE String Report Case - 12.25" Rotary_258_Colibasi_Rev.B.0 Operator

OMV Petrom

Facility

Colibasi

Well

#258 Colibasi

Field

Colibasi

String Components Item

#

Component

Gauge OD

OD

ID

Length

Total Len

in

in

in

m

m

13

Drill pipe

5

4.276

1560.88

1755.00

12

HWDP

5

3

45.00

194.12

11

Jar

6 1/2

2 3/4

12.65

149.12

10

HWDP

5

3

72.00

136.47

9

Drill collar

6 1/2

2 13/16

18.00

64.47

8

Sub - X/O

8

3

1.50

46.47

7

Drill collar

8

2 13/16

18.00

44.97

6

Stab - string

8

3 1/4

1.77

26.97

5

Sub - filter

8

3

1.50

25.20

4

MWD - pulser

8 1/4

2 13/16

10.97

23.70

3

Stab - string

12 1/8

8

3 1/4

1.77

12.73

2

Motor - steerable

12 1/8

8

6.400

10.65

10.95

1

Bit - insert - roller cone

12 1/4

12 1/4

0.30

0.30

12

13 String components with a total length of 1754.99 m. Page 1


Summary Torque and Drag, Hydraulic Calculations The calculation was done for the PDM/NaviGamma BHA with 5” Drill Pipe, 19.5 lbs/ft S-135 Class II 12 1/4” Directional BHA Calculation Depth

m

1737

Assumed WOB O-Mode

t

13

Friction Factors (cased /open hole)

--

0.2/ 0.3

Hookload Pick up

t

70

Drag Slack off

t

5

Drag (Pick up)

t

5

Torque (Drilling-at surface)

kNm

4.9

Torque (Rot off Bottom at surface)

Nm

4.1

Max. allowed Hookload

t

190t(=103 t Overpull )

Case of Overpull With a WOB of 13 tons the jar will be in tension and the neutral point is located in the HWDP below the jar. With a WOB of 13.5-15 tons the NP will be in the Jar. With a WOB of more than15 tons the jar will be in compression.

The calculation was done for 5” Drill Pipe 19.5 lbs/ft S.135 Class II. Overpull was calculated with a safety factor of 1.68 for a maximum hookload of 190tons. The calculated loads are calculated without block weight.



ADVANTAGE T&D Calculation - Summary Report Case - 12.25" Rotary_258_Colibasi_Rev.B.0 Operator

OMV Petrom

Facility

Colibasi

Well

#258 Colibasi

Field

Colibasi

Drilling Parameter

Analysis Setup

Bit Depth

1737 m

Weight on Bit

13 tonne

Torque on Bit

2.014 kN.m


No

Yes

Bit Drag Force

- tonne

Overpull Force

- tonne



- kN.m

Buckling Criterion

Depth Interval m

Inner Fluid Density sg


Depth Interval m

1.2500

1737

1737

Drill String Type

OD in

Drill pipe HWDP Jar HWDP Sub - X/O Drill collar Sub - X/O Drill collar Stab - string Sub - filter MWD - pulser Stab - string Motor - steerable Bit - insert - roller cone

6

6

8

12

ID in

5 5 1/2 5 8 1/2 8 8 8 8 1/4 8 8 1/4

TJID in

Act.Wt lb/ft

6 5/8 6 1/2

3 1/4 3

6 1/2

3

Length m

23.89 49.00 138.90 49.00 146.82 91.67 146.82 150.00 184.46 146.82 240.86 183.58 94.64 40.00

OD in

1541.38 Casing 45.00 Open Hole 12.65 72.00 1.50 18.00 1.50 18.00 1.77 1.50 10.97 1.77 10.65 0.30

ID in

13 3/8


1.2500

Casing / Open Hole

TJOD in

4.276 3 2 3/4 3 3 2 13/16 3 2 13/16 3 1/4 3 2 13/16 3 1/4 6.400

Outer Fluid Density sg

Bottom MD m

12.437 12 1/2

500.00 1737.00

Friction Factor


Bottom MD m

Variation

Axial

Torsional

250

0.6

1.2 Random

500

0.20 i

1737

0.8

1.6 Random

1737

0.30 i


Rotary Torque kN.m


Drilling

49

49

2.014

ROP

25.00

0

Slack-Off

61

61

0.000

RIH

10.00

0

Pick-Up

70

70

0.000

POOH

10.00

0

Rot off Btm

65

65

4.124


Drag tonne Drilling Slack-Off Pick-Up

3 5 5 Drawwork HP

Power

Drill String Twist Max Allowable HookLoad (@min. Yield) DrillString Weight in Air Bit To Neutral Point ( Drilling ) Sin. Buckling WOB at Fastline Load tonne

2.6 P O.Mode

Rotary HP

70 P

0 rev 321 tonne 80 tonne 129.91 m 22 tonne

at MD

psi

m


P

29285.8

0.00


Max Torsional

R

3197.2

0.00


Max Bending

P

15146.3

1400.00

D Drilling Comment Sliding

P S Slack-Off

30146.9 P Pick-Up

57.01 83.97 99.52 91.27 Max SPP bar

0 O.Mode

Max Axial

Max Combined


Mud Pumps HP 0.0 D

Stress

No

197 deg

300.000

Safety

at MD

Factor

m

P

4.48

10.00

N/A

N/A

N/A

10.00 R Rot off Btm

i input

c calculated



OMV Petrom

Facility

Colibasi

Well

#258 Colibasi

Field

Colibasi

Drilling Parameter

Analysis Setup

Bit Depth

1737 m

Weight on Bit

13 tonne

Torque on Bit

2.014 kN.m


No

Yes

Bit Drag Force

- tonne

Overpull Force

- tonne



- kN.m

Buckling Criterion

Depth Interval m



Depth Interval m

1.2500

1737

1737

Drill String Type

OD in


6

6

8

12

ID in

5 5 1/2 5 8 1/2 8 8 8 8 1/4 8 8 1/4

TJID in

Act.Wt lb/ft

6 5/8 6 1/2

3 1/4 3

6 1/2

3

Length m

23.89 49.00 138.90 49.00 146.82 91.67 146.82 150.00 184.46 146.82 240.86 183.58 94.64 40.00

OD in

1541.38 Casing 45.00 Open Hole 12.65 72.00 1.50 18.00 1.50 18.00 1.77 1.50 10.97 1.77 10.65 0.30

ID in

13 3/8


1.2500

Casing / Open Hole

TJOD in

4.276 3 2 3/4 3 3 2 13/16 3 2 13/16 3 1/4 3 2 13/16 3 1/4 6.400


Bottom MD m

12.437 12 1/2

500.00 1737.00

Friction Factor


Bottom MD m

Variation

Axial

Torsional

250

0.6

1.2 Random

500

0.20 i

1737

0.8

1.6 Random

1737

0.30 i


Rotary Torque kN.m


Drilling

49

49

2.014

ROP

25.00

0

Slack-Off

61

61

0.000

RIH

10.00

0

Pick-Up

70

70

0.000

POOH

10.00

0

Rot off Btm

65

65

4.124



3 5 5 Drawwork HP

Power


2.6 P O.Mode

Rotary HP

70 P


at MD

psi

m


P

29285.8

0.00


Max Torsional

R

3197.2

0.00


Max Bending

P

15146.3

1400.00

D Drilling Comment Rotary Mode

P S Slack-Off

30146.9 P Pick-Up

57.01 83.97 99.52 91.27 Max SPP bar

0 O.Mode

Max Axial

Max Combined


Mud Pumps HP 0.0 D

Stress

No

197 deg

300.000

Safety

at MD

Factor

m

P

4.48

10.00

N/A

N/A

N/A

10.00 R Rot off Btm

i input

c calculated



OMV Petrom

Facility

Colibasi

Well

#258 Colibasi

Field

Colibasi

Drilling Parameter

Analysis Setup

Bit Depth

1737 m

Weight on Bit

13 tonne

Torque on Bit

2.014 kN.m


No

Yes

Bit Drag Force

- tonne

Overpull Force

- tonne



- kN.m

Buckling Criterion

Depth Interval m



Depth Interval m

1.2500

1737

1737

Drill String Type

OD in


6

6

8

12

ID in

5 5 1/2 5 8 1/2 8 8 8 8 1/4 8 8 1/4

TJID in

Act.Wt lb/ft

6 5/8 6 1/2

3 1/4 3

6 1/2

3

Length m

23.89 49.00 138.90 49.00 146.82 91.67 146.82 150.00 184.46 146.82 240.86 183.58 94.64 40.00

OD in

1541.38 Casing 45.00 Open Hole 12.65 72.00 1.50 18.00 1.50 18.00 1.77 1.50 10.97 1.77 10.65 0.30

ID in

13 3/8


1.2500

Casing / Open Hole

TJOD in

4.276 3 2 3/4 3 3 2 13/16 3 2 13/16 3 1/4 3 2 13/16 3 1/4 6.400


Bottom MD m

12.437 12 1/2

500.00 1737.00

Friction Factor


Bottom MD m

Variation

Axial

Torsional

250

0.6

1.2 Random

500

0.20 i

1737

0.8

1.6 Random

1737

0.30 i


Rotary Torque kN.m


Drilling

52

52

4.932

ROP

25.00

90

Slack-Off

61

61

0.000

RIH

10.00

0

Pick-Up

70

70

0.000

POOH

10.00

0

Rot off Btm

65

65

4.124



0 5 5 Drawwork HP

Power


2.6 P O.Mode

Rotary HP

70 P


at MD

psi

m


Mud Pumps HP 62.3 D

Stress

No 45 deg


62.16 83.97 99.52 91.27 Max SPP bar

0 O.Mode

300.000

Safety

at MD

Factor

m

Max Axial

P

29285.8

0.00


P

4.48

10.00

Max Torsional

D

3823.8

0.00


D

1.72

1400.00

Max Bending

P

15146.3

1400.00

Max Combined

P

30146.9


S Slack-Off

P Pick-Up

10.00 R Rot off Btm

i input

c calculated



OMV Petrom

Facility

Colibasi

Well

#258 Colibasi

Field

Colibasi

Drilling Parameter

Analysis Setup

Bit Depth

1737 m

Weight on Bit

- tonne

Torque on Bit

2.014 kN.m

Bit Drag Force

- tonne

Overpull Force

103 tonne


- kN.m

Depth Interval m


No


Yes

Buckling Criterion



Depth Interval m

1.2500

1737

1737

Drill String Type

OD in


6

6

8

12

ID in

5 5 1/2 5 8 1/2 8 8 8 8 1/4 8 8 1/4

TJID in

Act.Wt lb/ft

6 5/8 6 1/2

3 1/4 3

6 1/2

3

Length m

23.89 49.00 138.90 49.00 146.82 91.67 146.82 150.00 184.46 146.82 240.86 183.58 94.64 40.00

OD in

1541.38 Casing 45.00 Open Hole 12.65 72.00 1.50 18.00 1.50 18.00 1.77 1.50 10.97 1.77 10.65 0.30

ID in

13 3/8


1.2500

Casing / Open Hole

TJOD in

4.276 3 2 3/4 3 3 2 13/16 3 2 13/16 3 1/4 3 2 13/16 3 1/4 6.400


Bottom MD m

12.437 12 1/2

500.00 1737.00

Friction Factor


Bottom MD m

Variation

Axial

Torsional

250

0.6

1.2 Random

500

0.20 i

1737

0.8

1.6 Random

1737

0.30 i


Rotary Torque kN.m


Drilling

65

65

6.135

ROP

25.00

90

Slack-Off

61

61

0.000

RIH

10.00

0

191

191

0.000

POOH

10.00

0

65

65

4.124


Pick-Up Rot off Btm Drag tonne Drilling Slack-Off Pick-Up

0 5 22 Drawwork HP

Power


7.0 P O.Mode

191 P at MD

psi

m

P

Max Torsional

D

4756.8

Max Bending

P

33200.5

D Drilling Comment Overpull

P S Slack-Off

79552.9

90323.5 P Pick-Up

No

127 deg

323 tonne 80 tonne 0.00 m 23 tonne


Mud Pumps HP 77.5 D

Stress

Max Axial

Max Combined

Rotary HP

1 rev


91.20 83.97 359.33 91.27 Max SPP bar

0 O.Mode

300.000

Safety

at MD

Factor

m

0.00


P

1.49

1400.00

0.00


D

1.27

1400.00

1400.00 Yielding occurs 1400.00 R Rot off Btm

i input

c calculated



Hydraulic Calculation: 12 1/4” Directional BHA Mud weight

sg

1.25

PV / YP

cP / lbf/100ft2

TFA

in2

HSI of 2800/2600 lpm

HP/in2

2.74(2.3)

SPP of 2800pm (2600lpm) Pump rate @500m MD

bar

174(148)

SPP of 2800pm (2600lpm) Pump rate @1737 MD

bar

218(196)

20 / 25 0.7854 (4x16 )

The expected SSP´s for further flow rates can be found on the hydraulics spreadsheet report and the hydraulics diagram. The bit TFA was chosen for best hydraulics, but can be further optimized by the bit provider.

The minimum required Flow rate for 100% hole cleaning, 25m/h ROP, 12 1/2in Open Hole ID and mud proprieties listed above is around 2300lpm considering cuttings size of 1cm average.



ADVANTAGE Hydraulics Spreadsheet Report Including Cuttings Transport Case - 12.25" Rotary_258_Colibasi_Rev.B.0 Operator

OMV Petrom

Facility

Well

#258 Colibasi

Field

Colibasi Colibasi

General

Drill String

Max Allw.SPP

300.000 bar

Surface Equipment

Type

Length m

Type 4



Drilling Fluid Mud System Synthetic Based Mud Weight PV \ YP 20.00 cP Gel Strength, 10s\10min Rheological Model Herschel-Bulkley k: 0.895[#sec^n/100ft^2] N: 0.611[-] OD in

Casing

ID in

Bottom MD m

13 3/8 12.437

ID in

TJ in \ in

Weight lb/ft

DP - NC50 (IF) / S-1 ... HWDP - NC50 / HW-55 Jar

304.38 45.00 12.65

5 5 6 1/2

4.276 3 2 3/4

6 5/8 \ 3 1/4 6 1/2 \ 3

19.50 49.00 138.90

HWDP - NC50 / HW-55

72.00

5

3

6 1/2 \ 3

49.00

1.50 18.00 1.50 18.00 1.77 1.50

8 6 1/2 8 8 8 8

3 2 13/16 3 2 13/16 3 1/4 3

146.82 100.00 146.82 150.00 184.46 146.82

MWD - NAVITRAK II/IN ...

10.97

8 1/4

2 13/16

240.86

Stab - string PDM - Ultra XL w/ In ...

1.78 10.65

8 8

3 1/4 6.400

183.58 94.64

0.30

12 1/4

2400

2300

2200

2100

2000

1900

139.363 747.0 37.436 26.86 259.0 7.5 1.73

131.371 674.8 34.381 26.17 248.2 6.9 1.52

123.675 607.7 31.456 25.43 237.4 6.3 1.33

116.280 545.4 28.662 24.65 226.6 5.8 1.16

109.190 487.7 25.997 23.81 215.8 5.2 1.00

102.412 434.6 23.462 22.91 205.0 4.7 0.86

Sub - X/O 1.2500 sg DC - API N.C. 50 \ 25.00 lbf/100ft^2 Sub - X/O 10 \ 18 lbf/100ft^2 DC - 6 5/8 API REG Stab - string YP: 8.000[lbf/100ft^2] Sub - filter


OD in

500.00 Bit - insert - rolle ...

40.00



246.490 23.890

2800

2700

2600

174.238 1089.6 50.954 29.24 302.2 10.2 2.74

165.088 995.5 47.379 28.70 291.4 9.5 2.46

156.224 907.1 43.935 28.12 280.6 8.8 2.20

2500



147.648 824.4 40.620 27.51 269.8 8.2 1.95

System Pressure Loss - W/ Cutting Effect Surf Equip DP, CSG, LNR, TBG HWDP/CSDP DC/CT MWD Motor Additional Tools Annulus

bar bar bar bar bar bar bar bar


4.978 9.656 16.273 6.623 37.879 42.143 3.541 2.190

4.662 9.112 15.359 6.251 35.222 41.531 3.342 2.230

4.356 8.579 14.465 5.886 32.661 40.918 3.147 2.275

4.059 8.059 13.591 5.530 30.197 40.306 2.956 2.328

3.772 7.552 12.738 5.183 27.830 39.694 2.771 2.389

3.494 7.057 11.905 4.843 25.559 39.082 2.589 2.461

3.225 6.575 11.094 4.513 23.385 38.469 2.413 2.545

2.966 6.106 10.304 4.191 21.307 37.857 2.241 2.645

2.717 5.650 9.537 3.879 19.326 37.245 2.074 2.765

2.477 5.208 8.792 3.575 17.442 36.633 1.912 2.911

1.2947 1.2947

1.2955 1.2955

1.2964 1.2964

1.2975 1.2975

1.2987 1.2987

1.3002 1.3002

1.3019 1.3019

1.3039 1.3039

1.3064 1.3064

1.3094 1.3094

114.84 L 132.46 L 164.23 L

109.84 L 126.70 L 157.09 L

104.85 L 120.94 L 149.95 L

99.86 L 115.18 L 142.81 L

99.86 L 115.18 L 142.81 L

0.0 0.2

0.0 0.2

0.0 0.3

0.0 0.3

0.0 0.3


String OD in

12.437 12.437 12.437

5 6 1/2 8

Surface to Bit Bottom Up

hr hr

139.80 L 161.25 L 199.93 L

134.81 L 155.49 L 192.79 L

0.0 0.2

0.0 0.2

129.82 L 149.73 L 185.65 L

124.82 L 143.98 L 178.51 L

119.83 L 138.22 L 171.37 L

Fluid Circulation Times 0.0 0.2

0.0 0.2

0.0 0.2

Page 1 Comment Hydraulics 500m MD


ADVANTAGE Hydraulics Spreadsheet Report Including Cuttings Transport Case - 12.25" Rotary_258_Colibasi_Rev.B.0 Operator

OMV Petrom

Facility

Well

#258 Colibasi

Field

Colibasi Colibasi

General

Drill String

Max Allw.SPP

300.000 bar

Surface Equipment

Type

Length m

OD in

DP - NC50 (IF) / S-1 ... HWDP - NC50 / HW-55 Jar

1541.38 45.00 12.65

5 5 6 1/2

4.276 3 2 3/4

6 5/8 \ 3 1/4 6 1/2 \ 3

19.50 49.00 138.90

HWDP - NC50 / HW-55

72.00

5

3

6 1/2 \ 3

49.00

Sub - X/O DC - API N.C. 50 Sub - X/O DC - 6 5/8 API REG Stab - string Sub - filter

1.50 18.00 1.50 18.00 1.77 1.50

8 6 1/2 8 8 8 8

3 2 13/16 3 2 13/16 3 1/4 3

146.82 100.00 146.82 150.00 184.46 146.82

MWD - NAVITRAK II/IN ...

10.97

8 1/4

2 13/16

240.86

Stab - string PDM - Ultra XL w/ In ...

1.78 10.65

8 8

3 1/4 6.400

183.58 94.64

0.30

12 1/4

Type 4



Drilling Fluid Mud System Synthetic Based Mud Weight 1.2500 sg PV \ YP 20.00 cP \ 25.00 lbf/100ft^2 Gel Strength, 10s\10min 10 \ 18 lbf/100ft^2 Rheological Model Herschel-Bulkley k: 0.895[#sec^n/100ft^2] N: 0.611[-] YP: 8.000[lbf/100ft^2]


OD in

Casing Openhole

ID in

13 3/8

Bottom MD m

12.437 12 1/4

500.00 Bit - insert - rolle ... 1737.00

ID in

TJ in \ in

Weight lb/ft

40.00



2800

838.100 94.450

2700

2600

2500

2400

2300

2200

2100

2000

1900

175.550 940.9 37.436 21.32 259.0 7.5 1.73

165.710 851.2 34.381 20.75 248.2 6.9 1.52

156.246 767.7 31.456 20.13 237.4 6.3 1.33

147.181 690.3 28.662 19.47 226.6 5.8 1.16

138.527 618.8 25.997 18.77 215.8 5.2 1.00

130.299 552.9 23.462 18.01 205.0 4.7 0.86



218.521 1366.5 50.954 23.32 302.2 10.2 2.74

207.249 1249.7 47.379 22.86 291.4 9.5 2.46

196.326 1140.0 43.935 22.38 280.6 8.8 2.20

185.758 1037.1 40.620 21.87 269.8 8.2 1.95




4.978 48.900 16.273 6.623 37.879 42.143 3.541 7.230

4.662 46.142 15.359 6.251 35.222 41.531 3.342 7.361

4.356 43.446 14.465 5.886 32.661 40.918 3.147 7.512

4.059 40.812 13.591 5.530 30.197 40.306 2.956 7.685

3.772 38.242 12.738 5.183 27.830 39.694 2.771 7.886

3.494 35.736 11.905 4.843 25.559 39.082 2.589 8.121

3.225 33.295 11.094 4.513 23.385 38.469 2.413 8.395

2.966 30.921 10.304 4.191 21.307 37.857 2.241 8.732

2.717 28.614 9.537 3.879 19.326 37.245 2.074 9.139

2.477 26.376 8.792 3.575 17.442 36.633 1.912 9.631

1.2917 1.2926

1.2926 1.2934

1.2936 1.2943

1.2948 1.2953

1.2962 1.2965

1.2978 1.2979

1.2996 1.2995

1.3018 1.3015

1.3044 1.3039

1.3076 1.3068


String OD in

12.437 12 1/4 12 1/4 12 1/4

5 5 6 1/2 8


hr hr

139.80 144.96 168.16 210.66

L L L L

134.81 139.79 162.15 203.13

L L L L

129.82 134.61 156.15 195.61

L L L L

124.82 129.43 150.14 188.08

L L L L

119.83 124.25 144.14 180.56

L L L L

114.84 119.08 138.13 173.04

L L L L

109.84 113.90 132.12 165.51

L L L L

104.85 108.72 126.12 157.99

L L L L

99.86 103.55 120.11 150.47

L L L L

99.86 103.55 120.11 150.47

L L L L


0.1 0.7

0.1 0.7

0.1 0.7

0.1 0.8

0.1 0.8

0.1 0.8

0.1 0.9

0.1 0.9

0.1 1.0 Page 1

Comment Hydraulics 1737m MD



4. 8 1/2” Hole section




8-1/2” Directional BHA ----------------------------------------------------------------------------------------------------------------------Section: 1737m to 2325 MD Length: 588 m Profile: Deviated-J-shape; Formation: Sands, quartitic sandstone and microconglomerate, with blackish clay intercalations BHA: Fully stabilized rotary BHA with 6 ¾” Ultra XL Motor and LWD MWD/LWD: -OnTrak with BCPM Corrections: Azimuth-Correction to Grid Nord (Stereo70) / MagCorr, SAG ----------------------------------------------------------------------------------------------------------------------8 1/2" PDC-fixed cutter 4-1/2” Reg P Client/BHI

4x 9x

6 3/4"

Ultra XL Motor 1.1AKO, 8 1/4” UBHS 4-1/2” Reg Bx NC50 B

BHI

8 1/4 "

String Stabilizer

NC50 PxB

BHI

6 1/2"

Float Sub(bored)

NC50 PxB

BHI

6 3/4”

Stop Sub

NC50 PxT2 B

BHI

6 3/4”

OnTrak(Directional,Gamma, Resistivity)T2 PxB

BHI

8 3/8"

Modular Stab

T2PxB

BHI

6 3/4"

BCPM

T2 PxB

BHI

6 3/4”

Stop Sub

T2 PxNC50 B

BHI

6 3/4”

Filter Sub

NC50Px B

BHI

6 3/4”

PBL Sub

NC50Px B

BHI

6 1/2” DC

NC50 PxB

36m

Client

HWDP

NC50PxB

81m

Client

Jar

NC50 PxB

HWDP

NC50PxB

Accelerator

NC50 PxB

5”

HWDP

NC50PxB

36m

Client

5”

Drill Pipe (S-135, 19.5 lbs/ft)

NC50 PxB

to surface

Client

5” 6 1/2”

3x

5” 6 1/2”

4x

Client 27m

Client Client

Note: Maximum surface rotation allowed for a 6 ¾” Ultra XL motor with actual stabilization and 1.1˚AKO is 80RPM.




Summary Torque and Drag, Hydraulic Calculation The calculation was done for the Packed Rotary BHA with 5” Drill Pipe, 19.5 lbs/ft S-135 Class Premium 8 1/2” Directional Calculation Depth

m

2389

Assumed WOB R-Mode

t

10

Friction Factors (cased /open hole)

--

0.2/0.3

Hookload Pick up

t

87

Torque (Drilling-at surface)

kNm

10.7

Torque (Rot off Bottom-at surface)

kNm

5.1

Drag Pick up

t

6

Drag Slack Off

t

7

Max. allowed Hookload

t

190(=93tons Overpull)

Case of Overpull No critical loads are calculated. Buckling of the drill string is not expected. With a WOB of 10 tons the jar will be in tension and the neutral point is located in the HWDP below the jar. With a WOB of 11-12 tons the NP will be in the Jar. With a WOB of more than12 tons the jar will be in compression. ..

The calculation was done for 5” Drill Pipe 19.5 lbs/ft S-135 Class II. Overpull was calculated with a safety factor of 1.67 for a maximum hookload of 190tons. The calculated loads are calculated without block weight.



ADVANTAGE String Report Case - 8 1/2 In_#258_Colibasi_Rev. A.0 Operator

OMV Petrom

Facility

Colibasi

Well

#258

Field

Colibasi

String Components Item

#

Component

Gauge OD

OD

ID

Length

Total Len

in

in

in

m

m

17

Drill pipe

5

4.276

2096.17

2325.00

16

HWDP

5

3

36.00

228.83

15

Accelerator

6 1/2

2 3/4

9.00

192.83

14

HWDP

5

3

27.00

183.83

13

Jar

6 1/2

2 3/4

12.65

156.83

12

HWDP

5

3

81.00

144.18

11

Drill collar

6 1/2

2 13/16

36.00

63.18

10

Sub - circulation

6 3/4

2 3/4

2.00

27.18

9

NM Sub - filter

6 3/4

2 3/4

1.00

25.18

8

NM Sub - stop

6 3/4

2 3/4

1.00

24.18

7

BCPM

6 3/4

2 13/16

3.39

23.18

6

MWD - stab - mod

6 3/4

2.800

1.50

19.79

5

OnTrak - MWD

6 3/4

2 3/4

5.20

18.29

4

NM Sub - stop

6 3/4

2 3/4

1.00

13.09

3

Stab - string

8 1/4

6 3/4

2 1/4

2.17

12.09

2

Motor - steerable

8 1/4

6.791

5.400

9.60

9.92

1

Bit - PDC - fixed cutter

8 1/2

8 1/2

0.32

0.32

8 3/8

17 String components with a total length of 2325 m. Page 1

ADVANTAGE T&D Calculation - Summary Report Case - 8 1/2 In_#258_Colibasi_Rev. A.0 Operator

OMV Petrom

Facility

Colibasi

Well

#258

Field

Colibasi

Drilling Parameter

Analysis Setup

Bit Depth

2325 m

Weight on Bit

10 tonne

Torque on Bit

6.352 kN.m


No

Yes

Bit Drag Force

- tonne

Overpull Force

- tonne



- kN.m

Buckling Criterion

Depth Interval m


OD in

Drill pipe HWDP Accelerator HWDP Jar HWDP Drill collar Sub - circulation NM Sub - filter NM Sub - stop BCPM MWD - stab - mod OnTrak - MWD NM Sub - stop Stab - string Motor - steerable Bit - PDC - fixed cutter

ID in

5 5 6 1/2 5 6 1/2 5 6 1/2 6 3/4 6 3/4 6 3/4 6 3/4 6 3/4 6 3/4 6 3/4 6 3/4 6.791 8 1/2


1.4000

2325

Drill String Type


Depth Interval m

Casing / Open Hole

TJOD in

4.276 3 2 3/4 3 2 3/4 3 2 13/16 2 3/4 2 3/4 2 3/4 2 13/16 2.800 2 3/4 2 3/4 2 1/4 5.400

TJID in

Act.Wt lb/ft

6 5/8 6 1/2

3 1/4 3

6 1/2

3

6 1/2

3

Length m

24.38 49.00 138.90 49.00 138.90 49.00 90.00 101.44 101.44 101.44 151.05 100.70 152.16 101.44 109.14 87.04 120.00

OD in

2096.17 Casing 36.00 Open Hole 9.00 27.00 12.65 81.00 36.00 2.00 1.00 1.00 3.39 1.50 5.20 1.00 2.17 9.60 0.32

ID in 9 5/8


1.4000

8.819 9

1737.00 2325.00

Friction Factor


Bottom MD m

Variation

Axial

Torsional

1737

0.6

1.2 Random

1737

0.20 i

2325

0.8

1.6 Random

2325

0.30 i

Hook Load @ 0.0 MD tonne

Bottom MD m

Indicated Hook Load tonne

Rotary Torque kN.m

Axial Velocity m/hr

Rotary Speed RPM

Drilling

70

70

10.679

ROP

25.00

80

Slack-Off

74

74

0.000

RIH

300.00

0

Pick-Up

87

87

0.000

POOH

300.00

0

Rot off Btm

80

80

5.073



0 6 7 Drawwork HP

Power

at Fastline Load tonne 95.0 P

O.Mode


Drill String Twist Max Allowable HookLoad (@min. Yield) DrillString Weight in Air Bit To Neutral Point ( Drilling ) Sin. Buckling WOB Rotary HP

87 P at MD

psi

m

160 deg


Mud Pumps HP 119.9 D

Stress

No


113.53 131.83 157.21 143.94 Max SPP bar

0 O.Mode

250.000

Safety

at MD

Factor

m

Max Axial

P

36125.0

0.00


P

3.64

10.00

Max Torsional

D

8279.7

0.00


D

3.58

1470.00

Max Bending

P

6056.4

1470.00

Max Combined

P

37091.8


S Slack-Off

P Pick-Up

10.00 R Rot off Btm

i input

c calculated



OMV Petrom

Facility

Colibasi

Well

#258

Field

Colibasi

Drilling Parameter

Analysis Setup

Bit Depth

2325 m

Weight on Bit

10 tonne

Torque on Bit

6.352 kN.m


No

Yes

Bit Drag Force

- tonne

Overpull Force

- tonne



- kN.m

Buckling Criterion

Depth Interval m


OD in


ID in

5 5 6 1/2 5 6 1/2 5 6 1/2 6 3/4 6 3/4 6 3/4 6 3/4 6 3/4 6 3/4 6 3/4 6 3/4 6.791 8 1/2


1.4000

2325

Drill String Type


Depth Interval m

Casing / Open Hole

TJOD in

4.276 3 2 3/4 3 2 3/4 3 2 13/16 2 3/4 2 3/4 2 3/4 2 13/16 2.800 2 3/4 2 3/4 2 1/4 5.400

TJID in

Act.Wt lb/ft

6 5/8 6 1/2

3 1/4 3

6 1/2

3

6 1/2

3

Length m

24.38 49.00 138.90 49.00 138.90 49.00 90.00 101.44 101.44 101.44 151.05 100.70 152.16 101.44 109.14 87.04 120.00

OD in

2096.17 Casing 36.00 Open Hole 9.00 27.00 12.65 81.00 36.00 2.00 1.00 1.00 3.39 1.50 5.20 1.00 2.17 9.60 0.32

ID in 9 5/8


1.4000

8.819 9

1737.00 2325.00

Friction Factor


Bottom MD m

Variation

Axial

Torsional

1737

0.6

1.2 Random

1737

0.20 i

2325

0.8

1.6 Random

2325

0.30 i


Bottom MD m


Rotary Torque kN.m

Axial Velocity m/hr

Rotary Speed RPM

Drilling

65

65

6.352

ROP

25.00

0

Slack-Off

74

74

0.000

RIH

300.00

0

Pick-Up

87

87

0.000

POOH

300.00

0

Rot off Btm

80

80

5.073



5 6 7 Drawwork HP

Power

at Fastline Load tonne 95.0 P

O.Mode


Drill String Twist Max Allowable HookLoad (@min. Yield) DrillString Weight in Air Bit To Neutral Point ( Drilling ) Sin. Buckling WOB Rotary HP

87 P at MD

psi

m

123 deg

0.0

36125.0

0.00


Max Torsional

D

4924.8

0.00


Max Bending

P

6056.4

1470.00

Comment Oriented Mode

P S Slack-Off

37091.8 P Pick-Up

Max SPP bar 0

O.Mode

P

D Drilling

103.03 131.83 157.21 143.94

Max Flowrate l/min

Max Axial

Max Combined


Mud Pumps HP 0.0 D

Stress

No

250.000

Safety

at MD

Factor

m

P

3.64

10.00

N/A

N/A

N/A

10.00 R Rot off Btm

i input

c calculated



OMV Petrom

Facility

Colibasi

Well

#258

Field

Colibasi

Drilling Parameter

Analysis Setup

Bit Depth

2325 m

Weight on Bit

- tonne

Torque on Bit

6.352 kN.m

Bit Drag Force

- tonne

Overpull Force

93 tonne


- kN.m

Depth Interval m


No


Yes

Buckling Criterion


OD in


ID in

5 5 6 1/2 5 6 1/2 5 6 1/2 6 3/4 6 3/4 6 3/4 6 3/4 6 3/4 6 3/4 6 3/4 6 3/4 6.791 8 1/2


1.4000

2325

Drill String Type


Depth Interval m

Casing / Open Hole

TJOD in

4.276 3 2 3/4 3 2 3/4 3 2 13/16 2 3/4 2 3/4 2 3/4 2 13/16 2.800 2 3/4 2 3/4 2 1/4 5.400

TJID in

Act.Wt lb/ft

6 5/8 6 1/2

3 1/4 3

6 1/2

3

6 1/2

3

Length m

24.38 49.00 138.90 49.00 138.90 49.00 90.00 101.44 101.44 101.44 151.05 100.70 152.16 101.44 109.14 87.04 120.00

OD in

2096.17 Casing 36.00 Open Hole 9.00 27.00 12.65 81.00 36.00 2.00 1.00 1.00 3.39 1.50 5.20 1.00 2.17 9.60 0.32

ID in 9 5/8


1.4000

8.819 9

1737.00 2325.00

Friction Factor


Bottom MD m

Variation

Axial

Torsional

1737

0.6

1.2 Random

1737

0.20 i

2325

0.8

1.6 Random

2325

0.30 i


Bottom MD m


Rotary Torque kN.m

Axial Velocity m/hr

Rotary Speed RPM

Drilling

74

74

6.352

ROP

25.00

0

Slack-Off

74

74

0.000

RIH

300.00

0

190

190

0.000

POOH

300.00

0

80

80

5.073


6 6 17

Drill String Twist Max Allowable HookLoad (@min. Yield) DrillString Weight in Air Bit To Neutral Point ( Drilling ) Sin. Buckling WOB

Pick-Up Rot off Btm Drag tonne Drilling Slack-Off Pick-Up Drawwork HP Power

at Fastline Load tonne

208.0 P O.Mode


Rotary HP

190 P at MD

psi

m

123 deg

0.0

79272.1

0.00


Max Torsional

D

4924.8

0.00


Max Bending

P

11503.7

1580.00

Comment Overpull

P S Slack-Off

80802.4 P Pick-Up

Max SPP bar 0

O.Mode

P

D Drilling

131.83 131.83 458.13 143.94

Max Flowrate l/min

Max Axial

Max Combined


Mud Pumps HP 0.0 D

Stress

No

250.000

Safety

at MD

Factor

m

P

1.67

20.00

N/A

N/A

N/A

20.00 R Rot off Btm

i input

c calculated



Hydraulics Calculation:

8 1/2” Directional BHA Mud weight

sg

1.4

PV / YP

cP / lbf/100ft2

TFA

in2

HSI of 2000/1800lpm

HP/in2

1.76(1.29)

SPP of 2000 lpm (1800 lpm) Pumprate @1737m MD

bar

223(192)

SPP of 2000 lpm (1800lpm) Pumprate @2325 m MD

bar

260(228)

18 / 20 0.9020(6x14)

The expected SSP´s for further flow rates can be found on the hydraulics spreadsheet report and the hydraulics diagram. The bit TFA was chosen for best hydraulics, but can be further optimized by the bit provide The minimum required Flow rate for 100% hole cleaning, 25m/h ROP, 9in Open Hole ID and mud proprieties listed above is around 790lpm considering cuttings size of 1cm average.



ADVANTAGE Hydraulics Spreadsheet Report Including Cuttings Transport Case - 8 1/2 In_#258_Colibasi_Rev. A.0 Operator

OMV Petrom

Facility

Well

#258

Field

Colibasi Colibasi

General

Drill String

Max Allw.SPP

250.000 bar

Surface Equipment

Type




Casing / Open Hole Type Casing

OD in

ID in

Bottom MD m

9 5/8

8.819

Annulus Volume String Displacement


OD in

ID in

TJ in \ in

Weight lb/ft

DP - / S-135 HWDP - NC50 / HW-55 Accelerator

1508.17 36.00 9.00

5 5 6 1/2

4.276 3 2 3/4

6 5/8 \ 3 1/4 6 1/2 \ 3

19.50 49.00 138.90

HWDP - NC50 / HW-55

27.00

5

3

6 1/2 \ 3

49.00

Jar HWDP - NC50 / HW-55 DC - API N.C. 50 Sub - circulation NM Sub - filter NM Sub - stop

12.65 81.00 36.00 2.00 1.00 1.00

6 5 6 6 6 6

MWD - BCPM Std 52mm/ ...

3.39

MWD - stab - mod MWD - ONTRAK/INTEQ

1.50 5.20

1737.00 NM Sub - stop

1/2

13/16 3/4 3/4 3/4

138.90 49.00 91.00 101.44 101.44 101.44

6 3/4

2 13/16

151.05

6 3/4 6 3/4

2.800 2 3/4

100.70 152.16

1/2 3/4 3/4 3/4

2 3 2 2 2 2

3/4 6 1/2 \ 3

1.00

6 3/4

2 3/4

101.44

Stab - string

2.17

6 3/4

2 1/4

109.14

430.550 PDM - Ultra XL/INTEQ 92.920 Bit - PDC - fixed cu ...

9.60

6.791

5.400

87.04

0.32

8 1/2

Volumes bbl

Flowrate

Length m

Type 4

2000

1900

1800

222.775 995.1 22.076 9.91 187.9 10.6 1.76

207.085 878.7 19.924 9.62 178.5 9.6 1.51

192.021 771.9 17.882 9.31 169.1 8.6 1.29

1700

120.00

1600

1500

1400

1300

1200

1100

163.745 585.1 14.129 8.63 150.3 6.8 0.90

150.512 504.2 12.418 8.25 140.9 6.0 0.74

137.943 431.3 10.817 7.84 131.6 5.2 0.60

125.700 364.9 9.327 7.42 122.2 4.5 0.48

115.293 309.0 7.947 6.89 112.8 3.8 0.38

105.516 259.2 6.678 6.33 103.4 3.2 0.29



177.574 674.2 15.950 8.98 159.7 7.7 1.08




2.912 67.253 13.285 4.401 34.463 41.000 4.487 32.897

2.655 61.288 12.236 4.053 31.891 40.200 4.131 30.706

2.409 55.580 11.221 3.716 29.375 39.400 3.787 28.650

2.174 50.132 10.240 3.391 26.914 38.600 3.455 26.719

1.949 44.945 9.294 3.077 24.508 37.800 3.135 24.908

1.735 40.021 8.383 2.774 22.158 37.000 2.826 23.196

1.533 35.361 7.509 2.484 19.863 36.200 2.530 21.646

1.341 30.968 6.672 2.207 17.303 35.400 2.247 20.235

1.161 26.845 5.873 1.942 15.972 34.600 1.977 18.976

0.993 22.992 5.113 1.690 14.641 33.800 1.720 17.889

1.5939 1.5939

1.5810 1.5810

1.5688 1.5688

1.5575 1.5575

1.5468 1.5468

1.5367 1.5367

1.5276 1.5276

1.5192 1.5192

1.5118 1.5118

1.5054 1.5054

184.04 L 273.41 L

171.77 L 255.18 L

159.50 L 236.95 L

147.23 L 218.73 L

147.23 L 218.73 L

0.2 0.5

0.2 0.5

0.2 0.6

0.2 0.6

0.2 0.7


String OD in

8.819 8.819

5 6 1/2


hr hr

245.38 L 364.54 T

233.11 L 346.32 L

0.1 0.4

0.1 0.4

220.85 L 328.09 L

208.58 L 309.86 L

196.31 L 291.63 L


0.1 0.4

0.2 0.5

Page 1 Comment Hydraulics at 1737m MD


ADVANTAGE Hydraulics Spreadsheet Report Including Cuttings Transport Case - 8 1/2 In_#258_Colibasi_Rev. A.0 Operator

OMV Petrom

Facility

Well

#258

Field

Colibasi Colibasi

General

Drill String

Max Allw.SPP

250.000 bar

Surface Equipment

Type




Casing Openhole

OD in

ID in

9 5/8

8.819 9

l/min

2000

Weight lb/ft

DP - / S-135 HWDP - NC50 / HW-55 Accelerator

2096.17 36.00 9.00

5 5 6 1/2

4.276 3 2 3/4

6 5/8 \ 3 1/4 6 1/2 \ 3

19.50 49.00 138.90

HWDP - NC50 / HW-55

27.00

5

3

6 1/2 \ 3

49.00

Jar HWDP - NC50 / HW-55 DC - API N.C. 50 Sub - circulation NM Sub - filter NM Sub - stop

12.65 81.00 36.00 2.00 1.00 1.00

6 5 6 6 6 6

MWD - BCPM Std 52mm/ ...

3.39

MWD - stab - mod MWD - ONTRAK/INTEQ

1.50 5.20

2 13/16

151.05

6 3/4 6 3/4

2.800 2 3/4

100.70 152.16

1.00 2.17

6 3/4 6 3/4

2 3/4 2 1/4

101.44 109.14

PDM - Ultra XL/INTEQ

9.60

6.791

5.400

87.04

582.340 Bit - PDC - fixed cu ... 126.460

0.32

8 1/2

1737.00 NM Sub - stop 2325.00 Stab - string

1900

TJ in \ in

6 3/4

Bottom MD m

385.420 Hole Volume 70.460 String Volume

ID in

13/16 3/4 3/4 3/4

Volumes bbl Annulus Volume String Displacement

OD in

138.90 49.00 91.00 101.44 101.44 101.44


Flowrate

Length m

Type 4

1800

1700

1/2 1/2 3/4 3/4 3/4

2 3 2 2 2 2

3/4 6 1/2 \ 3

120.00

1600

1500

1400

1300

1200

1100

188.907 675.0 14.129 7.48 150.3 6.8 0.90

173.213 580.3 12.418 7.17 140.9 6.0 0.74

158.295 494.9 10.817 6.83 131.6 5.2 0.60

143.845 417.6 9.327 6.48 122.2 4.5 0.48

131.379 352.1 7.947 6.05 112.8 3.8 0.38

119.692 294.0 6.678 5.58 103.4 3.2 0.29



259.291 1158.2 22.076 8.51 187.9 10.6 1.76

240.580 1020.9 19.924 8.28 178.5 9.6 1.51

222.612 894.9 17.882 8.03 169.1 8.6 1.29

205.394 779.8 15.950 7.77 159.7 7.7 1.08




2.912 93.474 13.285 4.401 34.463 41.000 4.487 43.193

2.655 85.182 12.236 4.053 31.891 40.200 4.131 40.306

2.409 77.249 11.221 3.716 29.375 39.400 3.787 37.572

2.174 69.677 10.240 3.391 26.914 38.600 3.455 34.993

1.949 62.468 9.294 3.077 24.508 37.800 3.135 32.548

1.735 55.624 8.383 2.774 22.158 37.000 2.826 30.294

1.533 49.148 7.509 2.484 19.863 36.200 2.530 28.210

1.341 43.042 6.672 2.207 17.303 35.400 2.247 26.307

1.161 37.311 5.873 1.942 15.972 34.600 1.977 24.597

0.993 31.956 5.113 1.690 14.641 33.800 1.720 23.101

1.6077 1.5918

1.5933 1.5790

1.5796 1.5668

1.5667 1.5554

1.5546 1.5445

1.5434 1.5345

1.5330 1.5253

1.5236 1.5168

1.5151 1.5092

1.5077 1.5026

184.04 L 173.43 L 250.64 L

171.77 L 161.87 L 233.93 L

159.50 L 150.31 L 217.22 L

147.23 L 138.75 L 200.51 L

147.23 L 138.75 L 200.51 L

0.2 0.7

0.2 0.7

0.3 0.8

0.3 0.9

0.3 0.9


String OD in

8.819 9 9

5 5 6 1/2


hr hr

245.38 L 231.24 L 334.18 L

233.11 L 219.68 L 317.48 L

0.2 0.5

0.2 0.5

220.85 L 208.12 L 300.77 L

208.58 L 196.56 L 284.06 L

196.31 L 184.99 L 267.35 L


0.2 0.6

0.2 0.6

Page 1 Comment Hydraulics at 2325m MD



5. 6”Hole Section Contingency BHA




6” Contingency BHA with motor and MWD+GR ----------------------------------------------------------------------------------------------------------------------Section: 1858 m to 2389 m MD Length: 531 m Profile: Deviated-tangent section; BHA: Fully stabilized rotary BHA with 4-3/4” NaviGamma MWD and Ultra XL motor MWD/LWD: NaviGamma Corrections: Azimuth-Correction to Grid Nord (Stereo70) / MagCorr, SAG ----------------------------------------------------------------------------------------------------------------------6”

12x

BHI

Ultra XL Motor 0.8AKO(5 3/4’’UBHS, 5 ¾” CCT) 4-1/2” Reg Bx NC38 BHI

5 3/4"

String Stabilizer

NC38 PxB

BHI

4 3/4”

NMDC (NaviGamma,MWD)

NC38 PxB

BHI

4 3/4”

Pulser Sub

NC38 PxB

BHI

4 3/4"

NM Filter Sub

NC38 PxB

BHI

5 3/4"

String Stabilizer

NC38 PxB

BHI

4 3/4"

Float Sub(bored)

NC38 PxB

BHI

5 3/4"

String Stabilizer

NC38 PxB

BHI

4 3/4"

PBL

NC38 PxB

Customer

HWDP

NC38 PxB

Jar

NC38 PxB

HWDP

NC38 PxB

Accelerator

NC38 PxB

4“

HWDP

NC38 PxB

4”

Drill Pipe

NC38PxB

4“

4“ 4 1/2”

4x

3-1/2” Reg P

4 3/4’’

4 1/2” 2x

PDC-fixed cutter

108m

Customer Customer

18m

Customer Customer

36m

Customer Customer

Note: Maximum surface rotation allowed for a 4 ¾” Ultra XL motor with actual stabilization and 0.8˚AKO is 120RPM.




6. Attachments - HS&E inspection sheet - Anti-collision Report




HS&E Inspection Sheet Rig Operations


Health and Safety Plan 1

Baker Hughes Organisation

Responsible Person by Law Technical / OPS coordination Drilling Engineer Health and Safety coordinator 2

Operations Manager OPS Coordinator Drilling Engineer HS&E Coordinator

Personal requirements

Directional Drilling (optional)

Measurement while drilling MWD/LWD

3

W. Koroletz Vasile Cosmeanu R. Harabagiu Rainer Maris

12-1/4” / 8-1/2” 2 Directional Drillers 1 Dir. Driller Min. Qualification DD II 1 Dir. Driller Min. Qualification DD I 12-1/4” / 8-1/2” 2 MWD engineers (APS operator for LithoTrak) Qualification MWD Operator

Investigation of potential dangers

Type of well H2S well Rig Special dangers Personal Protection equipment (PPE)

Working permission Remarks

Deviated well

On the rigsite (outside the Office-rooms) the following personal safety equipment has to be used: Helmet/ Hardhat Working Overall with long sleeves Safety boots Safety Glasses Safety gloves on demand Not required


4.

Emergency plan Baker Hughes Drilling Systems emergency phone numbers

Plant Celle

(24h/ 7 d)

Safety and Environment engineer Operations Manager Operations Coordinator

+49 5141/2030

Rainer Margis

work direct: +49 5141/203 484 mobile: +49 171 305 106 3 work direct: +49 5141/203-9042 mobile: +49 170/6383963 work direct: +40 244-436111-225 mobile: +40 733-109-369 work direct: +40 244-436111-236 mobile: +40 731 459 926

Wilhelm Koroletz Vasile

Cosmeanu Drilling Engineer

Ramona Harabagiu

Health and Safety checklist for Pre-Spud-Meeting/ Crew change A rig safety inspection will be made before the job starts. Topic

Date of completion

Signature

Was an inspection of the BHI working area done? Did the BHI employees get an introduction about the well planning? Have all BHI employees done the necessary safety trainings? Did the BHI employees discuss project specific safety risks? Is the emergency plan for the rigsite well known? Are the designated personal protection equipments available and inspected? Are the electrical installations inspected and accepted? Are possible peculiarities for the driveway to the rigsite known? Is the BHI well folder complete?

Other: Container safety, when not present on the rigsite In this case (i.e. RIH with the casing) the Baker Hughes employees have to lock the containers and deposit the key at the company man.

Œâ

Clearance Summary Report #258 Colibasi Rev.B.0-Closest Approach Page 1 of 3 REFERENCE WELLPATH IDENTIFICATION Operator Area Field Facility


Slot Well Wellbore





WellArchitect® 3.0.0 Hararam 25-Jun-12 at 15:33:22 WellArchitectDB/#258_Colibasi_PWP__CR.xml

WELLPATH LOCATION Local coordinates North[m] East[m] -458.53 -158.28





Minimum Curvature Slot Rig on Slot#258 Colibasi (RT) Rig on Slot#258 Colibasi (RT) Mean Sea Level

Rig on Slot#258 Colibasi (RT) to Facility Vertical Datum 349.16m Rig on Slot#258 Colibasi (RT) to Mean Sea Level 349.16m Rig on Slot#258 Colibasi (RT) to Mud Line at Slot (Slot#258 Colibasi ) 5.00m

POSITIONAL UNCERTAINTY CALCULATION SETTINGS Ellipse Confidence Limit Declination Slot Surface Uncertainty @1SD Facility Surface Uncertainty @1SD

pç

3.00 Std Dev 5.02° East of TN

Ellipse Start MD Dip Angle Horizontal Horizontal

5.00m 62.29° 0.610m 6.096m

Surface Position Uncertainty Mag Field Strength Vertical Vertical

included 48309 nT 0.305m 0.914m

Œâ



Slot Well Wellbore


ANTI-COLLISION RULE Rule Name

Petrom rule_R-Type_2SF

Rule Based On

Ratio

Plane of Rule

Closest Approach

Threshold Value

2.00

Subtract Casing & Hole Size

yes

Apply Cone of Safety

no


Start MD [m]


0.00 0.00 500.00 0.00 1736.54 0.00

End MD [m]

21.75 500.00 1736.54 1736.54 2325.00 2325.00

Ref Wellpath: #258 Colibasi Rev.B.0 Interval Start TVD End TVD [m] [m] [m]

21.75 500.00 1236.54 1736.54 588.46 2325.00

0.00 0.00 500.00 0.00 1731.00 0.00

21.75 500.00 1731.00 1731.00 2299.22 2299.22

Start N/S [m]

Start E/W [m]

0.00 0.00 0.00 0.00 3.01 0.00

0.00 0.00 0.00 0.00 -51.70 0.00

End N/S [m]

0.00 0.00 3.01 3.01 11.88 11.88


5.00 500.00 1736.00

pç

End MD [m]



Log Name/Comment

Wellbore


End E/W [m]

0.00 0.00 -51.70 -51.70 -204.46 -204.46

Œâ



Slot Well Wellbore


CALCULATION RANGE & CUTOFF From: 0.00m MD

To: 2325.00m MD

C-C Cutoff: (none)

OFFSET WELL CLEARANCE SUMMARY (2 Offset Wellpaths selected) Ratios are calculated in Closest Approach plane C-C Clearance Distance Offset Facility Colibasi Colibasi

pç

Offset Slot Slot#290 Colibasi Slot#259 Colibasi

Offset Well #290 Colibasi #259 colibasi

Offset Wellbore #290 Colibasi #259 Colibasi (AWB)

Offset Wellpath #290 Colibasi(AWP) #259 Colibasi (AWP)

Ref MD [m] 510.00 0.00

Min C-C Clear Dist [m] 112.47 493.52

Diverging from MD [m] 1650.00 1380.00

ACR Separation Ratio Ref MD of Min Ratio [m] 1736.54 1715.72

Min Ratio 11.51 56.43

Min Ratio Dvrg from [m] 1770.00 2325.00

ACR Status PASS PASS

Œâ



Slot Well Wellbore





WellArchitect® 3.0.0 Hararam 25-Jun-12 at 15:34:21 WellArchitectDB/#258_Colibasi_PWP__CR.xml

WELLPATH LOCATION Local coordinates North[m] East[m] -458.53 -158.28





Minimum Curvature Slot Rig on Slot#258 Colibasi (RT) Rig on Slot#258 Colibasi (RT) Mean Sea Level

Rig on Slot#258 Colibasi (RT) to Facility Vertical Datum 349.16m Rig on Slot#258 Colibasi (RT) to Mean Sea Level 349.16m Rig on Slot#258 Colibasi (RT) to Mud Line at Slot (Slot#258 Colibasi ) 5.00m

POSITIONAL UNCERTAINTY CALCULATION SETTINGS Ellipse Confidence Limit Declination Slot Surface Uncertainty @1SD Facility Surface Uncertainty @1SD

pç

2.00 Std Dev 5.02° East of TN

Ellipse Start MD Dip Angle Horizontal Horizontal

5.00m 62.29° 0.610m 6.096m

Surface Position Uncertainty Mag Field Strength Vertical Vertical

included 48309 nT 0.305m 0.914m

Œâ



Slot Well Wellbore


ANTI-COLLISION RULE Rule Name

Ellipse Seperation Limit 10m

Rule Based On

Ellipsoid Separation

Plane of Rule

Closest Approach

Threshold Value

10.00m

Subtract Casing & Hole Size

yes

Apply Cone of Safety

no


Start MD [m]


0.00 0.00 500.00 0.00 1736.54 0.00

End MD [m]

21.75 500.00 1736.54 1736.54 2325.00 2325.00

Ref Wellpath: #258 Colibasi Rev.B.0 Interval Start TVD End TVD [m] [m] [m]

21.75 500.00 1236.54 1736.54 588.46 2325.00

0.00 0.00 500.00 0.00 1731.00 0.00

21.75 500.00 1731.00 1731.00 2299.22 2299.22

Start N/S [m]

Start E/W [m]

0.00 0.00 0.00 0.00 3.01 0.00

0.00 0.00 0.00 0.00 -51.70 0.00

End N/S [m]

0.00 0.00 3.01 3.01 11.88 11.88


5.00 500.00 1736.00

pç

End MD [m]



Log Name/Comment

Wellbore


End E/W [m]

0.00 0.00 -51.70 -51.70 -204.46 -204.46

Œâ



Slot Well Wellbore


CALCULATION RANGE & CUTOFF From: 0.00m MD

To: 2325.00m MD

C-C Cutoff: (none)

OFFSET WELL CLEARANCE SUMMARY (2 Offset Wellpaths selected) Ellipse separations calculated in Closest Approach plane C-C Clearance Distance Offset Facility Colibasi Colibasi

pç

Offset Slot Slot#290 Colibasi Slot#259 Colibasi

Offset Well #290 Colibasi #259 colibasi

Offset Wellbore #290 Colibasi #259 Colibasi (AWB)

Offset Wellpath #290 Colibasi(AWP) #259 Colibasi (AWP)

Ref MD [m] 510.00 0.00

Min C-C Clear Dist [m] 112.47 493.52

Diverging from MD [m] 1650.00 1380.00

ACR Ellipse Separation Distance Ref MD of Min Ell Sep [m] 519.96 30.00

Min Ell Sep [m] 109.50 490.93

Min Ell Sep Dvrg from [m] 1651.08 1380.00

ACR Status PASS PASS

19.3

Mud Program

The mud program may be updated during operations based on the hole conditions encountered.


Page 58 of 76


Page 59 of 76

Technical Proposal 258 Colibasi-NAF Cost Break-Down Lot 6 27.06.2012

PETROM-OMV 258 Colibasi-Cost Break Down, Lot 6 Rev 3

REV 3 Ava (Ava Eastern Europe – Romania)

Page 1 of 16


AVA EASTERN EUROPE Technical Proposal for PETROM/OMV 258 Colibasi Cost Break-Down, Lot 6 Rev 3 27.06.2012

Copies

Distribution

1

PETROM/OMV

1

Ava Eastern Europe

Drilling Fluids Company Petre Ion Mihai Tudose

Date: 27/06/12

Checked by:

Vilson Dunareanu

Date: 27/06/12

Approved by:

Rodolfo Di Marino

Date: 27/06/12

Issued by:

Oil Company Checked by:

Date:

Approved by:

Date:


Page 2 of 16


WELL DESIGN AND MUD PARAMETERS


Page 3 of 16


MUD PARAMETERS Interval (MD) Footage Type of fluid Density Marsh Viscosity PV Yield Point Gel 10 sec. Gel 10 min 6 RPM 3 RPM API Filtrate PH Ca++ MBT LGS HPHT-Filtrate O/W Ratio Emulsion stability Alcalinity Sand WPS

U.M. in m-m m kg/dm³ sec/l cP lb/100ft² lb/100ft² lb/100ft² lb/100ft² lb/100ft² cm³/30' mg/l kg/m3 % Vol ml Volts ml H2SO4 0.1 N

Water phase activity

% vol g/l

II 17 1/2" 0-500 500 Spud Mud 1.05-1.15 120-60 ALAP 22-30 10-15 20-35 11 10 12-8 8.5-9 <200 <60 <10 -

Interval III 12 1/4" 500-1737 1237 NADF 1.20-1.25 ALAP 15-25 8-12 15-20 10-12 8-9

IV 8 1/2" 1737-2325 588 NADF 1.25 ALAP 15-20 7-10 12-22 8-9 5-6 -

<0.35 -

<5 <5 75-25 >750 2-3 <0.25 200-250

<4 <5 80-20 >800 2-3 <0.2 200-250

-

0.75-0.8

0.75-0.8


Page 4 of 16


1. Interval from 0 to 500 m (500 m) - Hole Size 17 ½” 1.1 Section Outline This surface section will be drilled using Spud Mud. The drilling mode used will be casing while drilling. This type of mud will provide the necessary hole cleaning properties and well bore stability. Makeup water should be checked and treated with SODA ASH to treat out hardness as needed. For a good hole cleaning we suggest to have already mixed bentonite slurry to add in active system. It is mandatory to maintain 6 RPM/3 RPM ratio at 11/10 and YP no less than 22 for an expected ROP around 10 m/hour. Flow rate will be minimum 1500 l/min. These parameters will assure a cleaned hole for entire section. Mud density for this section will be kept ALAP in order to avoid or mitigate losses. LCM accepted for this interval is: • GRANULAR M=30 kg/m3 • INTAFLOW=40 kg/m3 • INTASOL M=30 kg/m3 Tacking in consideration bit nozzles diameter we suggest not exceeding recommended concentration. Also coarse size is forbidden to use. Prior to make connection pump an amount of mud without any LCM in recipe in order to get all mud containing LCM in annulus space to avoid nozzle plugging because of LCM sag. 1.2 Interval Discussion During drilling add CMC HV for adjusting rheological parameters and CMC LV to keep the filtrate 8-12 ml. AVA ZR 5000 will be add to slightly disperse the system and to treat the circulation system only prior to cement job. Being the formation “mud making in nature, add water dilution to minimize mud density. To prevent dropping sands and to minimize bit balling we recommend treating system with 2 kg/m3 AVADETER. Run and optimize the solid control equipments (including Mud Cleaner to keep the sand content below 1%) to hold the LGS into the range <10% and MW into the range 1.05 -1.15 sg. In case of salt layer interception the spud mud can be treated with NaCl from safety stock in order to avoid mud contamination. In case of lost circulation and seepage losses cure them with LCM accordingly. All needed LCM will be available on location being sure there are fine and medium size for every type of material. Prior to drilling out cement, the system should be pretreated with SODIUM BICARBONATE to avoid cement contamination. Makeup water should be checked and treated with SODA ASH to treat out hardness as needed. 1.3 Solids Control Good solids control is fundamental to good mud control. Most of the mud treatment cost can be directly attributed to the build up of drilled solids and it is almost always cheaper to remove these solids than to combat them with chemicals. A good solids control system has the potential to reduce mud costs and to provide consistency of mud properties which will be reflected in better hole conditions and well stability.


Page 5 of 16


Shale Shakers: While drilling this section, performing shale shakers are recommended in order to handle the flow rate and volume of cuttings that will be generated. Shale shakers should be monitored closely to ensure that the highest API numbers screens as possible are used in order to minimize LGS building up. If necessary run the mud cleaner to keep the sand content below 0.35% by volume. For this section the following screens combination is required: API 120 to API 140 Centrifuges: Because Shale shakers cannot remove silt and colloidal-size solids, so dilution and others equipments as centrifuges are required to control ultra fine drilled solids. We would suggest running continuously centrifuge in order to minimize solids build up in the system and control the mud weight. The setup should permit running the centrifuges on the active system and reserve tanks in order to control low gravity solids and minimize dilution volumes. For discharging LGS the following centrifuge parameters have to be selected: ABSOLUTE SPEED DIFFERENTIL SPEED

2800 - 3500 tours /min 25 - 35 tours /min

1.4 Product Function Product CAUSTIC SODA SODA ASH SODIUM BICARBONATE CMC LV AVA ZR 5000 CMC HV AVADETER AVAGEL

Function Alkalinity Control Ca++ remover Prevent cement contamination Filter reducer Thinner Viscosifier/Filtrate Control Bit Balling Reducer Viscosifier

1.5 Mud Volumes VOLUME Hole Volume 17 1/2" Surface Volume Maintenance volume Total Mud Volume required Mud prepared at beginning Total New Volume to build up

m3 85 70 128 283 70 213

1.6 Mud Formulation and Estimated Consumption Product AVAGEL CAUSTIC SODA CMC HVS CMC LVS

Build (kg/m3) 80 1 0 0

Condition (kg/m3) 10 1 1.5 2

Package

Qty. (ton)

B.B. 1000 kg sack 25 kg sack 25 kg sack 25 kg

8.000 0.275 0.325 0.425


Page 6 of 16

Technical Proposal 258 Colibasi-NAF Cost Break-Down Lot 6 27.06.2012 AVADETER AVA ZR 5000 SODA ASH BICARBONATE Total

2 0 1 0

2 3 2

drum 200 kg drum 250 kg sack 50 kg sack 50 kg

0.600 0.750 0.500 0.300 11.175

2. Interval from 500 to 1737 m (1237 m) -Hole Size 12 ¼” 2.1 Section Outline This section will be drilled efficiently with the use of NADF 75/25. 2.2 Interval Discussion WBM system will be displaced out of csg 13 3/8” to NADF. The spacer will be built using recovered NADF viscosified by AVABENTOIL. The NADF guarantees a great stability in the most prohibitive condition of use such as high temperature, presence of soluble salts, water contamination from the formation, etc. AVOIL PE/LT and AVOIL SE/LT will be used respectively as primary and secondary emulsifiers. AVOIL FC will act as filtrate reducer to keep the HTHP filtrate <5 ml. AVOIL WA/LT is the wetting agent that will be used to protect the NADF system from water wetting phenomena. AVOIL VS/LT is a rheology modifier that it will be use to raise the low shear rheology without increasing PV of the invert system. AVABENTOIL is special organophilic clay which provides viscosity in NADF system. An excess of LIME will be used to ensure stability to the emulsifiers and to provide alkalinity. The water phase activity will be controlled by the use of CaCl2 (WPS= 200.000-250.000 mg/lt). During drilling run and optimize the solid control equipments to keep the LGS <5 % and MW into the projected range 1.2-1.25 sg. In case of lost circulation LCM pills should be built with the use of INTAFLOW and INTASOL. 2.3 General recommendation when use NADF Before starting the activity with oil base mud check and change the rubber parts if they are damaged. Pits system has to be design in order to mix separately brine, NADF, store NADF and NAF. Moreover all the pits have to be cover. SUGGESTIONS: Use GRACO High Pressure Cleaner to clean screens. Use RAPID VAC vacuum cleaner to clean and recover mud from rig floor. Use AVAWASH OBM (detergent for NADF) in order to remove NADF residues from metal surfaces. Use AVAWASH WBM to clean coveralls. 2.4 Mixing procedure


Page 7 of 16


Calculate the composition of the mud to be prepared on the basis of the O/W ratio and the density required. The build up of the system should be done under maximum shear in order to enable a better emulsion: 1. 2. 3. 4. 5.

In a separated pit mix Calcium Chloride Brine with the requested salinity. To another pit add the required volume of AVOIL base Mix AVOIL PE/LT and AVOIL SE/LT Add Lime through the hopper Slowly add the required volume of Brine and leave to mix on maximum shear minutes 6. Add AVOIL WA/LT 7. Add AVABENTOIL 8. Add AVOIL FC 10. Add AVOIL VS/LT to adjust the rheological parameters

for 20

11. Add BARITE to the correct density

2.5 Displacement Procedures Displacement WBM with NADF While displacing from WBM to NADF the following procedure is recommended, however the final decision for concentrations and volumes will be calculated by the mud engineer with the agreement of the Company Man. The substitution of WBM with NADF system should occur so as to greatly limit the mixing of the systems (in the area of contact) which are incompatible. Generally the substitution is carried out in a cased hole before drilling out of the shoe and during drilling out cement, using a spacer formulated with use of recovered NADF viscosified by AVABENTOIL SA. The spacer could be built even with the use of DE BLOCK’S/LT (blend of lubricants, wetting agents and gellants), NAF, WATER and Barite. The volume of the spacer should cover at least 200 - 250 m of annular space, so that to be sure there is no interaction between WBM and the NADF. Preferably the NADF mud should have a density which is 10-20 g/l more than that of the water based mud which has to be substituted, while the spacer should have a density which ranges between that one of the two mud. Operative course for displacement: 1) Reduce the viscosity and the gels of the water based mud to be substituted with the use of dilution. 2) prepare the spacer with De BLOCK’S/LT, AVOIL, Water and Barite, in the proportions later reported. 3) Pump a 5-10 m3 water pill followed by a volume of spacer sufficient to cover 200 – 250 m of the annulus. Displace with NADF, pumping at the maximum flow rate, while rotating drill-string at 50 – 60 rpm. 4) Dump WBM which leaves the well waiting the return of the NADF system free of contamination, and reintroduce it the circulation. Formulation of the SPACER for 1 m3:


Page 8 of 16


Density AVOIL base De Block's/lt Water Barite O/W

Kg/l Lt Lt Lt Kg

1,2 635 90 272 387 70/30

1,4 593 90 254 638 70/30

1,6 550 90 235 895 70/30

1,8 578 90 145 1205 80/20

2,0 450 90 133 1420 80/20

Once the displacement has taken place mud may appear slightly opaque and with a low electric stability; this phenomenon is more obvious when the substitution occurs in open hole. The phenomena will quickly regress in the course of the following circulations, adding AVOIL WA/LT. 2.6 RIH csg Before RIH 7” csg, we suggest to decrease rheological parameters (YP should be around 12 lb/100 ft2) by adding 2-3 Kg/m3 of viscosity reducing agent AVOIL TN/LT. It is particularly effective in high weight mud where unacceptably high strength can became a problem. 2.7 Solids Control Good solids control is fundamental to good mud control. Most of the mud treatment cost can be directly attributed to the build up of drilled solids and it is almost always cheaper to remove these solids than to combat them with chemicals. A good solids control system has the potential to reduce mud costs and to provide consistency of mud properties which will be reflected in better hole conditions and well stability. Shale Shakers: While drilling this section, performing shale shakers are recommended in order to handle the flow rate and volume of cuttings that will be generated. Shale shakers should be monitored closely to ensure that the highest API numbers screens as possible are used in order to minimize LGS building up. If necessary run the mud cleaner to keep the sand content below 0.25 % by volume. For this section the following screens combination is required: API 170 to API 200 Centrifuges: During drilling if necessary run the centrifuges to maintain the MW in the active system. Use one centrifuge to clean the mud recovered from Vortex. AVA Tornado Drier: The Vortex drier will be mounted at the rig side to treat the cuttings. It uses centrifugal force to make cuttings drier so recovering oil from drilled solids in NADF Vortex drier will be used to treat drilling cuttings in order to reduce oil content from 20 % by weight to 5-4%. NAF recovered by Vortex has to be cleaned with centrifuge in order to be reused. Also it can: -reduce oil content of cuttings in some cases below 1% (not more than 5%) -reduce solid waste volume so reducing costs for transport -recover valuable base fluid for reuse -reduce fluid content on cuttings prior to other forms of treatment, thereby increasing waste treatment efficiency.


Page 9 of 16


2.7 Product Function Product AVOIL BASE AVOIL PE/LT AVOIL SE/LT AVOIL FC AVOIL VS/LT AVABENTOIL AVOIL WA LIME CaCl2 BARITE

Function continuous phase for SBM Prime emulsifier Secondary emulsifier Filtrate reducer Polymeric rheology modifier Organophilic bentonite Oil wetting agent Control alkalinity Control water activity Weighting material

2.8 Mud Volumes VOLUME Csg 13 3/8" Volume Hole Volume 12 1/4" Surface Volume Maintenance volume Total Mud required Mud recovered from Mud Plant Products volume from increase MW mud from Mud Plant Total New Volume to build up

m3 39 104 70 75 288 100 6 182

Note

• Fluid volume doesn’t take in consideration losses in formation. • Hole volume has been calculated considering 5% of washout. • Volume of Maintenance and Dilution includes losses due to •

cuttings wetting and solids removal equipment. Rate of dilution is based on experience and could be changed in function of lithology, ROP, type of bit, efficiency of solid control equipments.

2.9 Mud Formulation and Estimated Products Consumption Product NAF AVOIL PE/LT AVOIL SE/LT AVOIL FC AVOIL WA/LT AVOIL VS/LT AVABENTOIL LIME CaCl2 BARITE AVACARB INTAFLOW Water

Build (kg/m3) 471 14 14 14 4 3 20 30 62 412

Recovered (kg/m3) 2 2 2 4 0 0 0 0 71

195

Package

Qty. (ton)

Bulk Drum x 180 Kg Drum x 180 Kg Drum x 180 Kg Drum x 180 Kg Drum x 180 Kg Sac x 25 Kg Sac x 25 Kg Sac x 25 Kg BB x 1500 Kg Sac x 25 Kg Sac x 25 Kg Bulk

86.284 2.700 2.700 2.700 1.080 0.540 3.650 5.475 11.300 82.500 0.000 0.000 36.000


Page 10 of 16

Technical Proposal 258 Colibasi-NAF Cost Break-Down Lot 6 27.06.2012 Brine at 1.21 sg Estimated AVOIL BASE Lost Total Price

269

Bulk -

49.000 62.345 198.929

3. Interval from 1737 to 2325 m (588 m) -Hole Size 8 ½” 3.1 Section Outline This section will be drilled efficiently with the use of NADF 80/20. 3.2 Interval Discussion The NADF recovered from previous interval with OWR 75/25 will be treated with Avoil Base in order to get OWR 80/20 as we need for current interval. The MW for this section will be kept 1,25 sg and if the hole conditions dictate can be increased step by step to 1,4 sg . The NADF guarantees a great stability in the most prohibitive condition of use such as high temperature, presence of soluble salts, water contamination from the formation, etc. AVOIL PE/LT and AVOIL SE/LT will be used respectively as primary and secondary emulsifiers. AVOIL FC will act as filtrate reducer to keep the HTHP filtrate <4 ml. AVOIL WA/LT is the wetting agent that will be used to protect the NADF system from water wetting phenomena. AVOIL VS/LT is a rheology modifier that it will be use to raise the low shear rheology without increasing PV of the invert system. AVABENTOIL is special organophilic clay which provides viscosity in NADF system. An excess of LIME will be used to ensure stability to the emulsifiers and to provide alkalinity. The water phase activity will be controlled by the use of CaCl2 (WPS= 200.000-250.000 mg/lt). During drilling run and optimize the solid control equipments to keep the LGS <4 % and MW into the projected range 1.25 (1.4) sg. In case of lost circulation LCM pills will be built with the use of INTAFLOW and INTASOL according to Directional Drilling Tools Specifications. If the rig capabilities permit we suggest to have a LCM pill already mixed and stored in one slug pit. 3.3 Solids Control Good solids control is fundamental to good mud control. Most of the mud treatment cost can be directly attributed to the build up of drilled solids and it is almost always cheaper to remove these solids than to combat them with chemicals. A good solids control system has the potential to reduce mud costs and to provide consistency of mud properties which will be reflected in better hole conditions and well stability. Shale Shakers: While drilling this section, performing shale shakers are recommended in order to handle the flow rate and volume of cuttings that will be generated. Shale shakers should be monitored closely to ensure that the highest API numbers screens as possible are used in order to minimize LGS building up. If necessary run the mud cleaner to keep the sand content below 0.2 % by volume. For this section the following screens combination is required: API 200 Centrifuges: During drilling if necessary run the centrifuges to maintain the MW in the active system. Use one centrifuge to clean the mud recovered from Vortex.


Page 11 of 16


AVA Tornado Drier: The Vortex drier will be mounted at the rig side to treat the cuttings. It uses centrifugal force to make cuttings drier so recovering oil from drilled solids in NADF. Vortex drier will be used to treat drilling cuttings in order to reduce oil content from 20 % by weight to 5-4%. NAF recovered by Vortex has to be cleaned with centrifuge in order to be reused. Also it can: -reduce oil content of cuttings in some cases below 1% (not more than 5%) -reduce solid waste volume so reducing costs for transport -recover valuable base fluid for reuse -reduce fluid content on cuttings prior to other forms of treatment, thereby increasing waste treatment efficiency.

3.4 Product Function Product AVOIL BASE AVOIL PE/LT AVOIL SE/LT AVOIL FC AVOIL VS/LT AVABENTOIL AVOIL WA LIME CaCl2 BARITE

Function continuous phase for SBM Prime emulsifier Secondary emulsifier Filtrate reducer Polymeric rheology modifier Organophilic bentonite Oil wetting agent Control alkalinity Control water activity Weighting material

3.5 Mud Volumes VOLUME Csg Volume 9 5/8" Hole Volume 8 1/2" Surface Volume Maintenance volume Reserve 1.25 sg Total Mud required Mud recovered from previous section Products volume from increase MW and change ratio Total New Volume to build up

m3 66 24 70 18 111 178 110 40 28

Note

• Fluid volume doesn’t take in consideration losses in formation. • Hole volume has been calculated considering 5% of washout. • Volume of Maintenance and Dilution includes losses due to •

cuttings wetting and solids removal equipment. Rate of dilution is based on experience and could be changed in function of litology, ROP, type of bit, efficiency of solid control equipments.


Page 12 of 16


3.6 Mud Formulation and Estimated Products Consumption Product NAF AVOIL PE/LT AVOIL SE/LT AVOIL FC AVOIL WA/LT AVOIL VS/LT AVABENTOIL LIME CaCl2 BARITE AVACARB INTAFLOW Water Brine at 1.21 sg Estimated AVOIL BASE Lost Total Price

Build (kg/m3) 495 14 14 14 4 3 20 30 49 480 87 80 153 211

Recovered (kg/m3) 161 2 2 3 2 1 0 5 0 399 0 0

Package

Qty. (ton)

Bulk Drum x 180 Kg Drum x 180 Kg Drum x 180 Kg Drum x 180 Kg Drum x 180 Kg Sac x 25 Kg Sac x 25 Kg Sac x 25 Kg BB x 1500 Kg Sac x 25 Kg Sac x 25 Kg Bulk Bulk -

31.746 0.540 0.540 0.720 0.360 0.180 0.550 1.375 1.350 57.000 2.425 2.225 4.000 0.000 19.286 99.011

4. Total estimated consumption for entire well Products AVAGEL CAUSTIC SODA CMC HVS CMC LVS AVADETER AVA ZR 5000 SODA ASH BICARBONATE NAF AVOIL PE/LT AVOIL SE/LT

Qty. (ton) 8.000 0.275 0.325 0.425 0.600 0.750 0.500 0.300 118.030 3.240 3.240


Page 13 of 16

Technical Proposal 258 Colibasi-NAF Cost Break-Down Lot 6 27.06.2012 AVOIL FC AVOIL WA/LT AVOIL VS/LT AVABENTOIL LIME CaCl2 BARITE AVACARB INTAFLOW Water Brine at 1.255 sg Estimated AVOIL BASE Lost TOTAL

3.420 1.440 0.720 4.200 6.850 12.650 139.500 2.425 2.225 40.000 49.000 81.631 309.115

5. SAFETY MATERIAL STOCK Products INTASOL F/M/C INTAFLOW AVAGEL NaCl CMC LVS CMC HVS CAUSTIC SODA SODA ASH BICARBONATE AVADETER INCORR 2275 BARITE POLICELL SL GRANULAR F/M/C AVAMICA F/C SAND SEAL DE BLOCK S AVATENSIO LT TOTAL

U.M sac x 25 kg sac x 25 kg BB 1000 kg BB 1000 kg sac x 25 kg sac x 25 kg sac x 25 kg sac x 50 kg sac x 50 kg Drums x 200 kg Drums x 250 kg sac x 25 kg 26 X 25 kg sac x 25 kg sac x 25 kg sac x 25 kg Drums x 180 kg Drums x 180 kg

Function Lost circulation material Lost circulation material Viscosifier Salt Filter reducer Viscosifier/Filtrate Control Alkalinity Control Ca++ remover Ca++ remover Detergent for WBM Corrosion inhibitor Lost circulation material Filtrate control Lost circulation material Lost circulation material Lost circulation material Pipe Free Pipe Free

Ton 2.000 2.000 15.000 46.000 2.500 2.500 0.700 1.500 0.700 1.000 0.250 10.000 0.500 2.000 2.000 1.000 0.900 0.720 91.270

6. SERVICES Engineering Personnel Drilling Fluids- Engineer 1 Drilling Fluids- Engineer 2 Solid Control- Engineer 1 Solid Control- Engineer 2

Unit day day day day

17 1/2" 16 16 16 16

12 1/4" 11 11 11 11

8 1/2" 9 9 9 9

Total unit 36.0 36.0 36.0 36.0

Solids Control Equipment


Page 14 of 16

Technical Proposal 258 Colibasi-NAF Cost Break-Down Lot 6 27.06.2012 Equipments Centrifuge HS 3400 Centrifuge HS 3400 Lab. Cabin Floculate Unit AVA Tornado Drier HG Graco High pressure cleaner (Two pieces) Hauger screw Conveyor 1 Hauger screw Conveyor 2 Mud Vac

Unit day day day day day

17 1/2" 16 16 16 16

12 1/4" 11 11 11

8 1/2" 9.00 9.00 9.00

11

9.00

Total unit 36.00 36.00 36.00 16.00 20.00

day

11

9.00

20.00

day day day

11 11 11

9.00 9.00 9.00

20.00 20.00 20.00

12 1/4"

8 1/2"

Total unit

Transports Transports Transport safety materials Transport Centrifuges Transport Lab Cabin Transport Flock unit Transport AVA Tornado drier Transport NADF from MP to rig side Transport NAF from MP to rigside Send back NADF to mud plant

Unit

17 1/2"

Trip

5

5

10

Trip Trip Trip

2 1 2

2 1

4 2 2

1

2

238 16

100 7 118 8 238 16

Trip

1 100 7 118 8

m3 trip Ton Trip m3 Trip

Shaker Screens for Mongoose Shakers Screen Type API API API API

Unit

17 1/2"

pcs pcs pcs pcs

6 12

Unit trip Ton m3 m3 Ton trip

17 1/2" 20 290 154 154 290 17

120 140 170 200

12 1/4" 4 10

8 1/2"

2 8

Total unit Mongoose 6 16 12 8

Waste Management Waste Management Cutting transport WBM la Vitalia Boldesti Cutting disposal WBM la Vitalia Boldesti Liquid transport WBM la

12 1/4"

8 1/2"

Total unit 20 290 154 154 290 17


Page 15 of 16

Technical Proposal 258 Colibasi-NAF Cost Break-Down Lot 6 27.06.2012 Vitalia Boldesti

Ton m3

187 156

187 156

Liquid disposal WBM la Vitalia Boldesti

Ton

187

187

Transport NADF cuttings la Vitalia Boldesti

Ton m3 trip

430 183 33

180 77 12

610 260 45

Ton

430

180

610

11

9 1

36 2 0.139

NADF cuttings disposal la Vitalia Boldesti Excavator Transport excavator Flocculants

day trip Ton

16 1 0.139

Additional Rig waste Additional Management

Unit

Total unit

Ton

100

Disposal Rig solid phase

Ton

100

Transport Rig Liquid Phase

m3 Ton

80 80

Disposal Rig Liquid Phase

Ton

80

Transport Rig solid phase


Page 16 of 16

19.4

Casing Design


Page 60 of 76


Page 61 of 76

19.5

Cement Program

All cementation programs will be updated during operations with exact section depths and improved annular open hole excesses based on conditions seen whilst drilling.


Page 62 of 76


Page 63 of 76

CemCADE

*

well cementing recommendation for 13 3/8 in casing

Operator

: OMV-Petrom

Well

: 258 Colibasi

Country State

: Romania :

Field

: Colibasi

Prepared for

:

Location

: VI Muntenia Central

Proposal No. Date Prepared

: Prelim rev3 : 06-06.2012

Service Point Business Phone FAX No.

: RWS Ploiesti : :

Prepared by Phone E-Mail

: Lavinia Tataru : : [email protected]

well description Configuration Casing Prev.String MD : 100.0 m Csg/Liner MD : 500.0 m Landing Collar MD Casing/liner Shoe MD Mud Line Total MD BHST Bit Size Mean OH Diameter Mean Annular Excess Mean OH Equivalent Diameter Total OH Volume

Stage : Single OD : 508 mm OD : 340 mm 480.0 m 500.0 m 0.0 m 500.0 m 23 degC 444.50 mm 444.50 mm 80.0 % 513.14 mm 82.7 m3 (including excess)

Rig Type : Land Weight : 251.5 kg/m Weight : 101.2 kg/m

Disclaimer Notice: This information is presented in good faith, but no warranty is given by and Schlumberger assumes no liability for advice or recommendations made concerning results to be obtained from the use of any product or service. The results given are estimates based on calculations produced by a computer model including various assumptions on the well, reservoir and treatment. The results depend on input data provided by the Operator and estimates as to unknown data and can be no more accurate than the model, the assumptions and such input data. The information presented is Schlumberger's best estimate of the actual results that may be achieved and should be used for comparison purposes rather than absolute values. The quality of input data, and hence results, may be improved through the use of certain tests and procedures which Schlumberger can assist in selecting. The Operator has superior knowledge of the well, the reservoir, the field and conditions affecting them. If the Operator is aware of any conditions whereby a neighboring well or wells might be affected by the treatment proposed herein it is the Operator's responsibility to notify the owner or owners of the well or wells accordingly. Prices quoted are estimates only and are good for 30 days from the date of issue. Actual charges may vary depending upon time, equipment, and material ultimately required to perform these services. Freedom from infringement of patents of Schlumberger or others is not to be inferred.

Page 1 258 colibasi.cfw ; 06-06-2012 ; LoadCase 13 3/8in casing Prelim rev3 ; Version wcs-cem441_51

Client Well String District Country Loadcase

: : : : : :

OMV-Petrom 258 Colibasi 13 3/8 in casing RWS Ploiesti Romania 13 3/8in casing Prelim rev3

Section 1: fluid sequence Original fluid

Mud Pv : 20.0 cP 37.5 m3 101.6 m3 0.0 m

Displacement Volume Total Volume TOC

1200.00 kg/m3 Ty : 30.00 lbf/100ft2

Fluid Sequence Name Water Spacer Tail Slurry Displacing Mud

Volume (L) 4000.0 4000.0 56072.3 37488.0

Ann. Len (m) 0.0 0.0 500.0

Top (m)

0.0 0.0

Density (kg/m3) 1000.00 1400.00 1800.00 1200.00

Rheology viscosity:3.0 cP Pv:11.0 cP Pv:47.1 cP Pv:20.0 cP

Ty:6.00 lbf/100ft2 Ty:7.50 lbf/100ft2 Ty:15.00 lbf/100ft2

WARNING : LOSSES Static Security Checks : Frac Pore Collapse Burst Csg.Pump out

-1760 kPa 794 kPa 10215 kPa 23787 kPa 17 tonne

at 500.0 m at 100.0 m at 480.0 m at 0.0 m



: : : : : :


Section 2: pumping schedule Pumping Schedule Name

Flow Rate (l/min)

Water Spacer Pause Tail Slurry Pause Displacing Mud Displacing Mud

1200.00 1200.00 0.00 1200.00 0.00 2000.00 400.00

Volume (l)

Stage Time (min)

4000.0 4000.0 0.0 56072.3 0.0 35488.0 2000.0

3.3 3.3 3.0 46.7 3.0 17.7 5.0

Total

01:22 hr:mn

Cum.Vol (m3). 4.0 4.0 0.0 56.1 0.0 35.5 37.5

Inj. Temp. (degC) 27 27 27 27 27 27 27

Comments

101.6 m3

WARNING : LOSSES Dynamic Security Checks : -1815 kPa 114 kPa 10215 kPa 20861 kPa

at 500.0 m at 100.0 m at 480.0 m at 0.0 m

Back Pressure A cquired WHP Well Head Pressure Pump Pressure

0

WHP (atm) 10 20

30

Frac Pore Collapse Burst

0

30

60

90

Flow Rate (L/min) (x 1000) 0 3 1 2

Time (min)

0

Fluids at

500 m

A cquired Q Out A cquired Q In Q Out Q In

30

60

90

Time (min)



: : : : : :


Section 3: fluid descriptions Water DESIGN Fluid No: 1 Rheo. Model At temp.

Density : NEWTONIAN : 24 degC

: 1000.00 kg/m3

Viscosity : 3.0 cP Gel Strength : (Pa)

WASH Wash Type : Mud Type : WBM

Water/Wash : 100.0 %

BASE FLUID Type : Fresh water

Density

Job volume : 4000.0 l

: 1000.00 kg/m3

Spacer DESIGN Fluid No: 2 Rheo. Model

: BINGHAM

At temp.

: 24 degC

Density

Pv Ty

: 1400.00 kg/m3 : 11.0 cP

: 6.00 lbf/100ft2 Gel Strength : (Pa)

SPACER Spacer Type : ( ) Mud Type : WBM

Porosity : 88.2 % Water/Spacer : 88.1 %


Density


: 1000.00 kg/m3

Weighting Agent(s) Code BaSO4

Conc. 503.56 kg/m3 of spacer ()

Density 4.25 kg/l (kg/l)

Additives Code CSP 500 DF 540

Conc. 2.400 %BWOW 1.000 L/m3 of spacer

Function Spacer Defoamer



: : : : : :


Tail Slurry DESIGN Fluid No: 3 Rheo. Model At temp.

Density

: 1800.00 kg/m3 : 47.1 cP : 7.50 lbf/100ft2 Gel Strength : (Pa)

: BINGHAM : 24 degC

Pv Ty

DESIGN BLEND Name :G Dry Density : 3.15 kg/l Sack Weight : 43 kg

SLURRY Mix Fluid : 0.560 L/kg Yield : 0.877 L/kg Porosity : 61.8 %

Job volume : 56072.3 l Quantity : 1499.5 sk Solid Fraction : 38.2 %


Density

Base Fluid : 0.541 L/kg

: 1000.00 kg/m3

Additives Code BDC 031 DF 540 CaCl2

Conc. 0.200 %BWOC 1.000 L/tonne cement 3.500 %BWOC

Function Fluid Loss Control Defoamer Accelerator

Rheometric Measurements Rheometer type : 35 Geometry : R1B1 Spring No : 1.0

(rpm) 300 200 100 60 30 6 3

At 24 degC (deg) 54.0 39.0 24.5 17.0 11.0 5.5 3.5

Pv : 47.1 cP Ty : 3.59 Pa

Displacing Mud DESIGN Fluid No: 4 Rheo. Model At temp.

Density : BINGHAM : 24 degC


Pv Ty

MUD Mud Type : NAF Water Type : Fresh

Job volume

: 37488.0 l



: : : : : :


Section 4: operator summary TOTAL MATERIAL REQUIREMENTS Additives G BDC 031 DF 540 CaCl2 CSP 500 BaSO4

Total Quantity 67000 kg 134 kg 71.0 l 2345 kg 84 kg 2014 kg

Item Quantity 1572 6 3 94 4 2

Pack. Name sack sack can sack sack big bag

Packaging

Comments

43 kg 25 kg 25.0 l 25 kg 25 kg 1500 kg

Mix Water Requirements : Fresh water

43.7 m3

MIXING PREPARATION Water Code

Volume : 4.00 m3 Quantity

Fresh water

Spacer Code

Density : 1000.00 kg/m3 Design

4.000 m3

Volume : 4.00 m3 Quantity

Fresh water CSP 500 DF 540 BaSO4

Density : 1400.00 kg/m3

3.498 m3 83.948 kg 4.000 l 2014.226 kg

Design 2.400 %BWOW 1.000 L/m3 of spacer 503.56 kg/m3 of spacer

Tail Slurry Volume : 58.76 m3

Density Yield

: 1800.00 kg/m3 : 0.877 L/kg

Dry Phase Blend : G

67000 kg 67000.00 kg

Liquid Phase Design

Mix Water Fresh water BDC 031 DF 540 CaCl2

37.49 m3 36.225 m3 134.000 kg 67.000 l 2345.000 kg

Design 0.200 %BWOC 1.000 L/tonne cement 3.500 %BWOC

Note: Treat Tail Slurry with LCM to prevent / reduce losses


CemCADE

*

well cementing recommendation for 9 5/8 in casing

Operator

: OMV-Petrom

Well

: 258 Colibasi

Country State

: Romania :

Field

: Colibasi

Prepared for

:

Location



: Prelim rev2 : 06-06-2012

Service Point Business Phone FAX No.

: RWS Ploiesti : :


: Lavinia Tataru : : [email protected]

well description Configuration Casing Prev.String MD : 500.0 m Csg/Liner MD : 1737.0 m Landing Collar MD Casing/liner Shoe MD Mud Line Total MD BHST Bit Size Mean OH Diameter Mean Annular Excess Mean OH Equivalent Diameter Total OH Volume

Stage : Single OD : 340 mm OD : 244 mm 1717.0 m 1737.0 m 0.0 m 1737.0 m 54 degC 311.20 mm 311.20 mm 50.0 % 339.68 mm 112.1 m3 (including excess)


Disclaimer Notice: This information is presented in good faith, but no warranty is given by and Schlumberger assumes no liability for advice or recommendations made concerning results to be obtained from the use of any product or service. The results given are estimates based on calculations produced by a computer model including various assumptions on the well, reservoir and treatment. The results depend on input data provided by the Operator and estimates as to unknown data and can be no more accurate than the model, the assumptions and such input data. The information presented is Schlumberger's best estimate of the actual results that may be achieved and should be used for comparison purposes rather than absolute values. The quality of input data, and hence results, may be improved through the use of certain tests and procedures which Schlumberger can assist in selecting. The Operator has superior knowledge of the well, the reservoir, the field and conditions affecting them. If the Operator is aware of any conditions whereby a neighboring well or wells might be affected by the treatment proposed herein it is the Operator's responsibility to notify the owner or owners of the well or wells accordingly. Prices quoted are estimates only and are good for 30 days from the date of issue. Actual charges may vary depending upon time, equipment, and material ultimately required to perform these services. Freedom from infringement of patents of Schlumberger or others is not to be inferred.



: : : : : :


Section 1: fluid sequence Original fluid

Mud Pv : 20.0 cP 65.6 m3 140.0 m3 190.0 m

Displacement Volume Total Volume TOC

1250.00 kg/m3 Ty : 25.00 lbf/100ft2

Fluid Sequence Name Oil Spacer Water Spacer Lead Slurry Tail Slurry Mud

Volume (L) 4000.0 6000.0 46219.9 18236.0 65564.3

Ann. Len (m) 0.0 190.0 1147.0 400.0

Top (m)

190.0 1337.0 0.0

Density (kg/m3) 1300.00 1350.00 1450.00 1900.00 1250.00

Rheology Pv:18.5 cP Pv:8.8 cP Pv:15.9 cP Pv:140.1 cP Pv:20.0 cP

Ty:14.97 lbf/100ft2 Ty:5.75 lbf/100ft2 Ty:13.73 lbf/100ft2 Ty:28.25 lbf/100ft2 Ty:25.00 lbf/100ft2

Static Security Checks : Frac Pore Collapse Burst Csg.Pump out

432 kPa 1971 kPa 22632 kPa 40541 kPa 79 tonne

at 500.0 m at 500.0 m at 1717.0 m at 0.0 m



: : : : : :


Section 2: pumping schedule Pumping Schedule Name

Flow Rate (l/min)

Oil Spacer Water Spacer Pause Lead Slurry Tail Slurry Pause Mud Mud

Volume (l)

1000.00 1000.00 0.00 1000.00 1000.00 0.00 1400.00 400.00

Stage Time (min)

4000.0 6000.0 0.0 46219.9 18236.0 0.0 63564.2 2000.0

4.0 6.0 3.0 46.2 18.2 3.0 45.4 5.0

Total

02:10 hr:mn

Cum.Vol (m3). 4.0 6.0 0.0 46.2 18.2 0.0 63.6 65.6

Inj. Temp. (degC) 27 27 27 27 27 27 27 27

Comments

140.0 m3

Dynamic Security Checks : 245 kPa 1177 kPa 22632 kPa 34520 kPa

at 500.0 m at 500.0 m at 1717.0 m at 0.0 m

Bac k Pres s ure A c quired WHP Well Head Pres s ure Pump Pres s ure

0

WHP (atm) 25 50

75

Frac Pore Collapse Burst

Flow Rate (L/min) (x 1000) 0 0.4 0.8 1.2 1.6

0

0

30

60 90 Time (min) Fluids at

120

150

120

150

1737 m

A c quired Q Out A c quired Q In Q Out Q In

30

60 90 Time (min)



: : : : : :


Section 3: fluid descriptions Mud DESIGN Fluid No: 1 Rheo. Model At temp.

Density


: BINGHAM : 24 degC

Pv Ty

MUD Mud Type : NAF Water Type : Fresh

Job volume

: 65564.3 l

Oil Spacer DESIGN Fluid No: 2 Rheo. Model

: BINGHAM

At temp.

: 24 degC

Density

Pv Ty

: 1300.00 kg/m3 : 18.5 cP


SPACER Spacer Type : ( ) Mud Type : NAF



Density


: 1000.00 kg/m3




Additives Code CSP 500 Mineral Oil Emulsifier

Conc. 18.000 kg/m3 of spacer 250.000 L/m3 of spacer 2.000 L/m3 of spacer

Function Spacer Mineral Oil Emulsifier


(rpm) 600 300 200 100 60 30 6 3

At 24 degC (deg) 51.0 34.0 28.5 21.0 17.5 13.5 8.5 6.5

Pv : 18.5 cP Ty : 7.17 Pa Page 4 258 colibasi.cfw ; 06-06-2012 ; LoadCase 9 5/8in casing Prelim rev2 ; Version wcs-cem441_51


: : : : : :


Water Spacer DESIGN Fluid No: 3 Rheo. Model At temp.

Density


: BINGHAM : 24 degC

Pv Ty

SPACER Spacer Type : ( ) Mud Type : NAF



Density


: 1000.00 kg/m3




Additives Code CSP 500 DF 540 BDC 011

Conc. 23.000 kg/m3 of spacer 2.000 L/m3 of spacer 0.400 kg/m3 of spacer

Function Spacer Defoamer Retarder


(rpm) 600 300 200 100 60 30 6 3

At 24 degC (deg) 23.0 15.0 11.5 9.0 7.0 5.0 3.0 2.0

Pv : 8.8 cP Ty : 2.75 Pa



: : : : : :


Lead Slurry DESIGN Fluid No: 4 Rheo. Model At temp.

Density

: 1450.00 kg/m3 : 15.9 cP Ty : 13.73 lbf/100ft2 Gel Strength : (Pa)

: BINGHAM : 45 degC

Pv





Density


: 1000.00 kg/m3

Additives Code CaCl2 DF 540 BDC 031 Bentonite Na Silicate BDC 011

Conc. 1.000 %BWOC 3.000 L/tonne cement 0.450 %BWOC 1.500 %BWOC 15.000 L/tonne cement 0.050 %BWOC

Function Accelerator Defoamer Fluid Loss Control Extender Extender Retarder


(rpm) 300 200 100 60 30 6 3

At 45 degC (deg) 29.0 25.0 19.0 17.0 15.0 12.0 10.0

Pv : 15.9 cP Ty : 6.57 Pa



: : : : : :


Tail Slurry DESIGN Fluid No: 5 Rheo. Model

: BINGHAM

At temp.

: 45 degC

Density

Pv Ty

: 1900.00 kg/m3 : 140.1 cP






Density


: 1000.00 kg/m3

Additives Code BDC 043 BDC 031 DF 540

Conc. 0.150 %BWOC 0.250 %BWOC 1.000 L/tonne cement

Function Dispersant Fluid Loss Control Defoamer


(rpm) 300 200 100 60 30 6 3

At 45 degC (deg) 166.0 123.5 78.0 57.0 38.5 23.0 20.0

Pv : 140.1 cP Ty : 13.53 Pa



: : : : : :


Section 4: operator summary TOTAL MATERIAL REQUIREMENTS Additives G CSP 500 DF 540 BDC 011 BaSO4 BDC 043 BDC 031 CaCl2 Bentonite Na Silicate Mineral Oil Emulsifier

Total Quantity 56000 kg 210 kg 130.0 l 19 kg 4385 kg 38 kg 203 kg 310 kg 465 kg 465.0 l 1000.0 l 8.0 l

Item Quantity 1314 9 6 1 3 2 9 13 12 24 2 1

Pack. Name sack sack can sack big bag sack sack sack sack drum drum drum

Packaging

Comments

43 kg 25 kg 25.0 l 25 kg 1500 kg 23 kg 25 kg 25 kg 40 kg 20.0 l 1000.0 l 208.0 l


56.6 m3

MIXING PREPARATION Oil Spacer Code Fresh water CSP 500

Mineral Oil Emulsifier BaSO4

Water Spacer Code Fresh water CSP 500 DF 540 BDC 011 BaSO4

Volume : 4.00 m3 Quantity 2.553 m3 72.000 kg 1000.000 l 8.000 l 1753.459 kg

Volume : 6.00 m3 Quantity 5.316 m3 138.000 kg 12.000 l 2.400 kg 2631.256 kg

Density : 1300.00 kg/m3 Design 18.000 kg/m3 of spacer 250.000 L/m3 of spacer 2.000 L/m3 of spacer 438.36 kg/m3 of spacer

Density : 1350.00 kg/m3 Design 23.000 kg/m3 of spacer 2.000 L/m3 of spacer 0.400 kg/m3 of spacer 438.54 kg/m3 of spacer



: : : : : :


Lead Slurry Volume : 48.61 m3

Density Yield

Dry Phase Blend : G

31000 kg 31000.00 kg

: 1450.00 kg/m3 : 1.568 L/kg Liquid Phase

Design

Mix Water Fresh water CaCl2 DF 540 BDC 031 Bentonite Na Silicate BDC 011

38.77 m3 37.764 m3 310.000 kg 93.000 l 139.500 kg 465.000 kg 465.000 l 15.500 kg

Design 1.000 %BWOC 3.000 L/tonne cement 0.450 %BWOC 1.500 %BWOC 15.000 L/tonne cement 0.050 %BWOC


Density Yield

Dry Phase Blend : G

25000 kg 25000.00 kg

: 1900.00 kg/m3 : 0.760 L/kg Liquid Phase

Design

Mix Water Fresh water BDC 043 BDC 031 DF 540

11.06 m3 10.960 m3 37.500 kg 62.500 kg 25.000 l

Design 0.150 %BWOC 0.250 %BWOC 1.000 L/tonne cement

Note: Treat Slurries with LCM in case of losses


CemCADE* well cementing recommendation for 7in casing Operator

: OMV Petrom

Well

: 258 Colibasi

Country

: Romania

Field

: Colibasi 2011

Prepared for

: Mr Mark Smith

Location



: Prelim v1.0 : 20-Apr-2012

Service Point Business Phone

: ROOP : +40372152124


: Suleyman Sari : +40721221098 : [email protected]

Well Description Configuration Casing Prev.String MD : 1737.0 m Csg/Liner MD : 2325.0 m Landing Collar MD Casing/liner Shoe MD Mud Line Total MD BHST Bit Size Mean OH Diameter Mean Annular Excess Mean OH Equivalent Diameter Total OH Volume

Stage : Single OD : 9 5/8 in OD : 7 in 2300.6 m 2325.0 m 0.0 m 2325.0 m 71 degC 8 1/2 in 8.500 in 20.0 % 8.769 in 22.9 m3 (including excess)


Disclaimer Notice: Schlumberger submits this document with the benefit of its judgment, experience, and good oilfield practices. This information is provided in accordance with generally accepted industry practice, relying on facts or information provided by others, limitations, computer models, measurements, assumptions and inferences that are not infallible. Calculations are estimates based on provided information. All proposals, recommendations, or predictions are opinions only. NO WARRANTY IS GIVEN CONCERNING ACCURACY OR COMPLETENESS OF DATA, INFORMATION PRESENTED, EFFECTIVENESS OF MATERIAL, PRODUCTS OR SUPPLIES, RECOMMENDATIONS MADE, OR RESULTS OF THE SERVICES RENDERED. Freedom from infringement of any intellectual property rights of Schlumberger or others is not to be inferred and no intellectual property rights are granted hereby.

*

Mark of Schlumberger Page 1 258 Colibasi.cfw ; 04-21-2012 ; LoadCase 7in prod csg ; Version wcs-cem470_06

Client String Country

: OMV Petrom : 7in casing : Romania

Well : 258 Colibasi District : ROOP Loadcase : 7in prod csg

Section 1: Fluid Sequence Original fluid Displacement Volume Total Volume TOC

NAF Mud Pv: 27.359 43.3 m3 80.3 m3 0.0 m

1.30 SG Ty : 17.46 lbf/100ft2

Fluid Sequence Name CW8 Scavenger Slurry Tail Slurry NAF Mud

Volume (m3) 4.0 20.2 11.8 43.3

Ann. Len (m) 0.0 1510.0 815.0

Top (m)

Density (SG) 0.99 1.45 1.90 1.30

0.0 1510.0 0.0

Rheology viscosity:3.000 cP Pv:9.300 cP Pv:97.500 cP Pv:27.359 cP

Ty:22.92 lbf/100ft2 Ty:7.11 lbf/100ft2 Ty:17.46 lbf/100ft2

Static Security Checks : Frac Pore Collapse Burst Csg.Pump out Check Valve Diff Press

49 bars 81 bars 489 bars 583 bars 82 ton 67 bars

at 1790.0 m at 1737.0 m at 2300.6 m at 0.0 m

bars

m

250

500

0

250

500

0

0

bars Hydrostatic Max. Dynamic Min. Dynamic Frac Pore

2400

2000

1600

1200

800

400

Hydrostatic Frac Pore

Fluid Sequence

Static Well Security

Dynamic Well Security Page 2

258 Colibasi.cfw ; 04-21-2012 ; LoadCase 7in prod csg ; Version wcs-cem470_06




Section 2: Pumping Schedule Note: Add CemNET to the slurry if losses are observed or suspected. Pumping Schedule Name

Flow Rate (l/min)

CW8 Pause Scavenger Slurry Tail Slurry Pause NAF Mud NAF Mud NAF Mud

Volume (m3)

800.0 0.0 800.0 800.0 0.0 1000.0 800.0 400.0

Stage Time (min)

4.0 0.0 20.2 11.8 0.0 22.0 19.0 2.3

5.0 10.0 25.2 14.8 10.0 22.0 23.8 5.7

Total

01:56 hr:m

Cum.Vol (m3). 4.0 0.0 20.2 11.8 0.0 22.0 41.0 43.3

Inj. Temp. (degC) 27 27 27 27 27 27 27 27

Comments

Pump Chemical Wash Drop Bottom Plug Mix & Pump Scav Slurry Mix & Pump GasBLOK Slurry Drop Top Plug Displace with Mud Continue displacement Bump the Plug

79.3 m3

Dynamic Security Checks : Frac Pore Collapse Burst

24 bars 15 bars 489 bars 478 bars

at 1790.0 m at 2325.0 m at 2300.6 m at 0.0 m

Temperature Results 52 degC 43 degC 26 degC

120

API BHCT Simulated BHCT CT at TOC

Simulated Max HCT Max HCT Depth Max HCT Time

45 degC 2135.2 m 01:07:35 hr:mn:sc

0

Surf. Press. (bars) 40 80

Calc. CemHP Calc. Pump Press.

0

25

50

75

100

125

100

125

Time (min)

Flow Rate (l/min) (x 1000) 0 1.5 0.5 1.0

Fluids at 2325 m Q Out Q In

0

25

50

75 Time (min)

Page 3 258 Colibasi.cfw ; 04-21-2012 ; LoadCase 7in prod csg ; Version wcs-cem470_06




Section 3: Centralizer Placement Top of centralization Bottom Cent. MD Casing Shoe NB of Cent. Used NB of Floating Cent.

:0.0 m :2322.2 m :2325.0 m :88 :88

Bottom MD (m) 1384.2 1608.2 2280.2 2325.0

Cent. / Joint 1/5 4/5 2/3 2/1

Centralizer Placement Nbr. 24 16 40 8

Cent. Name

Code

CENTEK STD. S2 CENTEK STD. S2 CENTEK STD. S2 CENTEK STD. S2

Min. STO (%) 100.0 41.3 52.3 82.0

S2 S2 S2 S2

Centralizer Description Cent. Name

@ Depth (m) 1378.6 1417.8 1614.5 2325.0

Centralizer Tests

Casing Max. Min. OD Rigid Origin Hole Size Running Restoring OD OD Force Force (in) (in) (in) (in) (lbf) (lbf) CENTEK STD. S2 STD 7 8.500 7.120 No Centek 8.500 0.00 2650.00 (1) - Centralizer performance data is based on tests by WEATHERFORD as per the current API 10D specifications

m

Code

deg/30m 20

0

2.5

0

% 20 40 60 80 100

0

0

deg 10

DLS

Betw een Cent. At Cent.

2400

2000

1600

1200

800

400

Deviation

Well

Deviation

Dogleg Severity

Pipe Standoff Page 4

258 Colibasi.cfw ; 04-21-2012 ; LoadCase 7in prod csg ; Version wcs-cem470_06




Section 4: WELLCLEAN II Simulator

%

%

0 20 40 60 80 100

0 20 40 60 80 100

% 0

50

100

0

m

Std Betw . Cent. Cement Coverage

Mud Contamination Uncontaminated Slurry

2400

2000

1600

1200

800

400

Betw een Cent. At Cent.

Well

Pipe Standoff

Cement Coverage

Uncontaminated Slurry





Section 5: Operator Summary TOTAL MATERIAL REQUIREMENTS Dead Volumes

Operator Volumes Name

PumpedVolume (m3) 4.0 20.2 11.8

CW8 Scavenger Slurry Tail Slurry Additives D907 D020 D145A D201 D206 D500 F110 U066

Dead Vol. (m3) 0.0 0.5 0.3 Total Qty

Class G Cement Bentonite Extender Dispersant Retarder Antifoam GasBLOK LT Surfactant Mutual Solvent

28,370 kg 334 kg 145 L 23 kg 30 L 1,285 L 200 L 100 L

Item Qty 666 14 8 2 2 7 1 1

Applies to Total Fluid Mix Fluid Mix Fluid Pack. Name sack sack can sack can drum drum drum

Pck

Blend Dead Mass (kg) 0 0 0 Comments

In silo 25 kg 18.9 l 11.3 kg 18.9 l 200 l 200 l 189 l


26 m3

MIXING PREPARATION Volume : 4.0 m3 Quantity

CW8 Code Fresh water F110 U066

Density : 0.99 SG

3.700 m3 200.0 l 100.0 l

Design 50.0 L/m3 of wash 25.0 L/m3 of wash

Scavenger Slurry Volume : 20.2 m3

Density Yield

Dry Phase Blend : G

: 1.45 SG : 1554.70 L/tonne Liquid Phase

Design

12,973 kg 12,972.68 kg

Mix Water Fresh water D206 D020 D201

16.6 m3 16.466 m3 13.37 l 334.25 kg 6.69 kg

Design 1.00 L/tonne cement 25.00 kg/t cement 0.50 kg/t cement


Density Yield

Dry Phase Blend : G

15,397 kg 15,397.42kg

: 1.90 SG : 766.59 L/tonne Liquid Phase

Design

Mix Water Fresh water D206 D145A D500 D201

7.3 m3 5.838 m3 16.05 l 144.47 l 1,284.21 l 16.05 kg

Design 1.00 L/tonne cement 9.00 L/tonne cement 80.00 L/tonne cement 1.00 kg/t cement


19.6

Casing Running Good Practise

Team, Over the last few months I have observed a number of wrong casing running practices. Therefore please take note of the following correct casing preparation and running practices: Pipe Thread Locking It has been observed that pipe thread locking compound is frequently applied to more that the shoetrack and at times 7 to 8 joints of casing are "pipe locked". This is not in line with normal practices and the drilling program and is also a an unnecessary time consuming operation. The drilling program specifies "PIPELOCK THE SHOE TRACK". The shoetrack is all the connections from the floatshoe upto and including the float collar. The last casing pin to which "pipe lock" is to be applied is the joint that screws into the floatcollar. Any joints above that do NOT require pipe lock. When thread lock is required, both pin and box connections must be cleaned, dried, and free of contaminants. Apply thread lock to the pin thread end only (not the seal area of the pin). This will reduce the possibility of the thread lock progressing into the ID. A uniform coat should be applied, a full 360 degrees, covering all the threads of the upper half of the pin Cleaning casing threads Casing threads should be cleaned and all storage dope is to be removed. Cleaning of the connections to remove storage compound prior to running in the well should be carried out as close to the time of running as possible. Only fresh water or cleaning solvent which leaves no residue mixed with water should be used to clean the connections. Once cleaned the connections should be dried with the use of compressed air, the protectors washed, dried and re-installed. Drifting casing All casing is to drifted from the box towards the pin only. This prevents any debris from within the pipe to lodge in the box-end threads and prevents thread damage Centralizer installation. There seems to be a misconception on the installation of CENTEK centralizers. Attached are two documents which explain the manufacturers recommendation. In order to save time it is advisable to install ONE stop collar on the pipe rack casing on these joints that require a centralizer. Also not the sequence and method of tightening the stop collar retaining screws

CENTEK Centek stop Centraliser stop collar... collar_installx.pd...

Cu Stima Kind Regards Frans van Rixel Team Leader Well Delivery Operations Team 4 OMV Petrom S.A. No. 22 Coralilor 22, 103339 Bucharest Romania

Email : [email protected] Office :+40 (0) 372 483 497 Mobile :+40 (0) 720 202 136


Page 64 of 76


Page 65 of 76

19.7

Salt Exit Strategy

Note: Salt exit strategy and section TD Prior to reaching base of salt (25m) 1) Review Salt Exit Strategy and Lost Circulation options with drilling crew. Perform kick drill. 2) Take SCR’s 3) If possible space out string where 12-15m of formation below salt can be drilled and the bit can be pulled into the salt without having to make connection. 4) Drill ahead with 5m/h controlled ROP monitor cuttings and LWD for formation change indications. Salt exit 5) Once salt exit is established, drill 5 m below salt and stop drilling. 6) With pumps on and without rotation pull back to salt. Look for changes in drag, pump pressure. 7) Shut down pumps and flow check for 15min. 8) With pumps on, slowly run back to bottom without rotation. Check fill. Pick up into salt. 9) Circulate bottoms up. Analyze cuttings for indications of unstable hole, pressure splintering, gas increase. Confirm marly shales (>20-30%) in cuttings. - if positive – section TD. - if negative – drill 5 m of formation and repeat steps 5 to 9.


Page 66 of 76


Page 67 of 76

12:00 Tue 10-Jul

20:00 Tue 10-Jul 21:30 Tue 10-Jul 22:00 Tue 10-Jul 23:00 Tue 10-Jul

01:00 Wed 11-Jul

06:00 Mon 16-Jul 08:00 Mon 16-Jul

15:30 Mon 16-Jul

15:30 Mon 16-Jul

16:00 Mon 16-Jul

20:00 Mon 16-Jul

04:00 Tue 17-Jul

04:30 Tue 17-Jul

04:30 Wed 18-Jul 05:30 Wed 18-Jul 15:30 Wed 18-Jul 03:30 Thu 19-Jul

15:30 Wed 18-Jul

06:00 Thu 19-Jul

06:00 Fri 20-Jul 06:30 Fri 20-Jul

14:30 Fri 20-Jul

18:30 Fri 20-Jul 22:30 Fri 20-Jul 23:30 Fri 20-Jul 17:30 Tue 24-Jul 19:30 Thu 26-Jul

07:30 Fri 27-Jul

10:30 Fri 27-Jul 18:30 Fri 27-Jul 00:30 Sat 28-Jul 01:30 Sat 28-Jul

1.04

1.09

1.10 1.11

2.00

2.01

2.02

2.03

2.04

2.05

2.06 2.07 2.08 2.09

3.00

3.01

3.02 3.03

3.04

3.05 3.06 3.07 3.08 3.09

3.10

3.11 3.12 3.13 3.14

00:00 Tue 10-Jul 10:00 Tue 10-Jul 10:30 Tue 10-Jul

1.01 1.02 1.03

1.05 1.06 1.07 1.08

06:15 Wed 15-Aug 15:30 Mon 16-Jul

00:00 Tue 10-Jul 00:00 Tue 10-Jul

1.00


18:30 Fri 27-Jul 00:30 Sat 28-Jul 01:30 Sat 28-Jul 09:30 Sat 28-Jul

10:30 Fri 27-Jul

22:30 Fri 20-Jul 23:30 Fri 20-Jul 17:30 Tue 24-Jul 19:30 Thu 26-Jul 07:30 Fri 27-Jul

18:30 Fri 20-Jul

06:30 Fri 20-Jul 14:30 Fri 20-Jul

06:00 Fri 20-Jul

09:30 Sat 28-Jul

05:30 Wed 18-Jul 15:30 Wed 18-Jul 03:30 Thu 19-Jul 06:00 Thu 19-Jul

04:30 Wed 18-Jul

04:30 Tue 17-Jul

04:00 Tue 17-Jul

20:00 Mon 16-Jul

16:00 Mon 16-Jul

06:00 Thu 19-Jul

08:00 Mon 16-Jul 15:30 Mon 16-Jul

06:00 Mon 16-Jul

21:30 Tue 10-Jul 22:00 Tue 10-Jul 23:00 Tue 10-Jul 01:00 Wed 11-Jul

20:00 Tue 10-Jul


Finishing

Start

#

DELETE ROW

INSERT ROW

259 Colibasi Well Well

Drill directionally from 1425-1651m (BUR= 2o/30m). Max inc= 15.o Drill tangent section from ±1651-1737m. Circulate mud to clean hole (poss ible reaming, wiper trip for gauging borehole). POOH to surface. L/D BHA Pull wear bus hing Rig repair as per contract (1hr / day).

M/U ±1800m 5" DP in doubles and rack back (using wellbore and elevators). JSA before commence drilling Make up 12-1/4" BHA including shallow test. RIH to TOC (@ ±475mMD) on DP singles (1800m DP still in derrick) Drilling out shoe track + 5m of new formation. Perform and record FIT @ EMW =1.45sg. Drill vertically from ±505-1425m.

Drill 12-¼" Hole

JSA before commencing cement job. Cement 13-3/8" surface casing through CRTI. Displace cement with 1.2sg NAF in preperation for the next section. L/D; surface lines, cementing equipment and casing running equipment. JSA before BOP pressure testing Screw 13-3/8 CHH to 13-3/8" casing. N/U BOP stack. Install kill/choke lines and hydraulic hoses. Function test Accumulator unit and BOP rams. Pressure test BOP stack and Pumping lines. RIH and set wear bus hing N/U bell nipple and flow line. Perform gyro survey measurement of 13-3/8" casing. Rig repair as per contract (1hr / day).

Cement 13-⅜" Casing

Prepared to start drilling (including verifing rig alignment). JSA before commencing 17-1/2" x 26" pilot hole drilling. P/U 17-1/2" x 26" pilot hole / clean-out drilling assembly. Jet/drill 17-1/2" x 26" pilot hole to ~23mBRT (clear all conductor contents) L/D 17-1/2" x 26" pilot hole drilling ass embly. JSA before commencing casing drilling. P/U CRTI as per odfjell instructions. M/U 13-3/8" cas ing driling shoe track + test. Commence casing drilling 13-3/8" section as per program and Odfjell instruction from ~23-500m. Circulate at TD until shakers are clean. Rig repair as per contract (1hr / day).

Casing Drill 13-⅜"

Operation

MR 8000

259 Colibasi Well

OMV Petrom DWOP

0

0

hrs 0

0.0 0.0 0.0 0.0

0.0

0.0 0.0 0.0 0.0 0.0

0.0

0.0 0.0

0.0

8.0 6.0 1.0 8.0

3.0

4.0 1.0 90.0 50.0 12.0

4.0

0.5 8.0

24.0

220

1.0 10.0 12.0 2.5

24.0

0.0 0.0 0.0 0.0 0.0

0.5

8.0

4.0

0.5

63

2.0 7.5

125.0

1.5 0.5 1.0 2.0

8.0

10.0 0.5 1.5

hrs 160

17.8 18.0 18.1 18.4

17.4

10.9 11.0 14.7 16.8 17.3

10.8

10.3 10.6

10.3

8.2 8.6 9.1 9.3

8.2

7.2

7.2

6.8

6.7

6.3 6.6

6.3

0.9 0.9 1.0 1.0

0.8

0.4 0.4 0.5

days

Cum.

Plan

0.0

0.0

0.0

0.0

0.0 0.0

0.0

0.0 0.0 0.0 0.0

0.0

0.0 0.0 0.0

days

Cum.

Actual

0.00

0.00

hrs 0.00

Depth

0

0

500

500

0.00

1737 1737 1737 1737 1737

0.00 0.00 0.00 0.00 0.00

505 505 1425 1651 1737

500 500

0.00 0.00 0.00 0.00 0.00

500 0.00 0.00

1737 0.00

0.00

500 500

0.00 0.00 0.00 0.00

500

0.00

500

500

0.00

0.00

500

500 0.00

0.00

500

500 500

0.00 0.00

0.00

500

0.00

10 10 10 10

10

0.00 0.00 0.00 0.00

0.00

m 500 0 0 0

m 0

Actual Plan

0.00 0.00 0.00

hrs 0.00

NPT ILT

(Explain all NPT and ILT)

Comment

Queries or suggestion regarding the functionality of this spreadsheet should be addressed to [email protected]

NPT = Non Productive Time e.g. equipment failure or waiting on equipment ILT = Invisible Lost Time i.e the planned time was exceeded but all time was productive (invisible during planning). Negative ILT indicates an operation was completed more quickly than planned.

19.8 DWOP

Page 68 of 76


Page 69 of 76

09:15 Wed 08-Aug

10:15 Wed 08-Aug 10:45 Wed 08-Aug 14:45 Wed 08-Aug 02:45 Thu 09-Aug

04:45 Thu 09-Aug

08:45 Thu 09-Aug

21:45 Thu 09-Aug

02:15 Fri 10-Aug

02:15 Sat 11-Aug

02:15 Sun 12-Aug 08:15 Sun 12-Aug 12:15 Sun 12-Aug 14:15 Sun 12-Aug 02:15 Mon 13-Aug 07:15 Mon 13-Aug 08:15 Mon 13-Aug 12:15 Mon 13-Aug

18:15 Mon 13-Aug

22:15 Mon 13-Aug 03:45 Tue 14-Aug

7.01 7.02 7.03 7.04

7.05

7.06

7.07

7.08

7.09

7.10 7.11 7.12 7.13 7.14 7.15 7.16 7.17

7.18

7.19 7.20

05:30 Sat 04-Aug 08:30 Sat 04-Aug 19:30 Sat 04-Aug 01:30 Sun 05-Aug

5.08 5.09 5.10 5.11

7.00

12:30 Wed 01-Aug

5.07

06:45 Tue 07-Aug 07:15 Tue 07-Aug 09:15 Tue 07-Aug 10:15 Tue 07-Aug 06:15 Wed 08-Aug 09:15 Wed 08-Aug

16:00 Tue 31-Jul 16:30 Tue 31-Jul 22:30 Tue 31-Jul 06:30 Wed 01-Aug 10:30 Wed 01-Aug 11:30 Wed 01-Aug

5.01 5.02 5.03 5.04 5.05 5.06

6.01 6.02 6.03 6.04 6.05 6.06

12:30 Tue 31-Jul

5.00

23:30 Mon 06-Aug


4.10 4.11 4.12

6.00

02:30 Mon 30-Jul

4.09

17:30 Sun 05-Aug

14:30 Sun 29-Jul

4.08

23:30 Mon 06-Aug 00:30 Tue 07-Aug

08:30 Sun 29-Jul

4.07

5.13 5.14

09:30 Sat 28-Jul 10:00 Sat 28-Jul 12:00 Sat 28-Jul 13:00 Sat 28-Jul 05:00 Sun 29-Jul 08:00 Sun 29-Jul

4.01 4.02 4.03 4.04 4.05 4.06

5.12

00:30 Sat 28-Jul

4.00

JSA prior to cement job. Cement 7" casing. WOC. N/D + lift BOP. Drop s lips. Cut 7" casing. Install Tubing Head Housing (THS) – energise ‘’P’’ seals and test seals . Reinstall BOP. Test wellhead connection between BOP and top of THS with Cup type tes ter (CTT) in 7” casing. Pull out cup type tester (CTT). L/D all 5” DP. M/U +/- 2300m 2-7/8" tubing and RIH with rotating scraper assembly. Circulate and conditions mud in preperation for displacement. Displace NAF with filtered formation water. Inflow test. POOH 2-7/8" tubing and clean-up assembly. Perform CBL 7’’ casing from TD to 1500m. Jet BOP and hanging area. M/U and RIH 300m of 2-7/8" tubing kill string. Install X-mas tree. Energise seals and pressure test X-mas tree. (each valve at 350 bars for 15 min). Rig repair as per contract (1hr / day). Rig repair as per contract (1day / month).

Cement 7" Production Casing.

JSA before running production casing. P/U CRTI + equipment for running 7" casing. M/U 7" shoe track + test. Run 7"casing to TD (prognosed @2325m) using CRTI. Circulate at TD until shakers are clean. Rig repair as per contract (1hr / day).

Run 7" Production Casing.

JSA before commencing resevoir drilling. M/U 8-1/2" PDC bit and drilling BHA. Perform shallow test. Run in hole with 8-1/2" BHA to TOC (~1710m). Drill shoe track and 5m of new formation. Circulate to homogenise NADF at 1.25 SG. Perform and record FIT (EMW= 1.55sg). Drill tangent to section TD prognosed at 2325mMD. (Only ream or perform wiper trip if hole conditions dictate). Circulate until shakers are clear. POOH DP to top of BHA and rack back. POOH BHA and rack back. Wireline logging (2 runs if hole conditions permit). Wiper trip to TD (2325m) before running production casing. If hole conditions dictate. Pull wear bus hing. Rig repair as per contract (1hr / day).

Drill 8-1/2" Hole (including logging)

JSA before running casing P/U CRTI + equipment for running 9-5/8" casing. M/U float shoe and shoe track + test. Run 9-5/8"casing to TD (prognosed @1732m) using CRTI. Circulate at TD until shakers are clean. JSA prior to cement job. Cement 9-5/8" casing. Displace cement with 1.25sg NAF in preperation for the next section. WOC. N/D + lift BOP and drop slips. Cut 9-5/8" casing. N/U BOP stack. Install Kill, Choke lines and hydraulic hoses. Function test Accumulator unit and BOP rams. Pressure test BOP stack and Pumping lines. N/U bell nipple and flow line + collector. Run wear bushing Rig repair as per contract (1hr / day).

Run + Cement 9-5/8" Casing

GRAND TOTALS

03:45 Tue 14-Aug 06:15 Wed 15-Aug

22:15 Mon 13-Aug

08:15 Sun 12-Aug 12:15 Sun 12-Aug 14:15 Sun 12-Aug 02:15 Mon 13-Aug 07:15 Mon 13-Aug 08:15 Mon 13-Aug 12:15 Mon 13-Aug 18:15 Mon 13-Aug

02:15 Sun 12-Aug

02:15 Sat 11-Aug

02:15 Fri 10-Aug

21:45 Thu 09-Aug

08:45 Thu 09-Aug

10:45 Wed 08-Aug 14:45 Wed 08-Aug 02:45 Thu 09-Aug 04:45 Thu 09-Aug

06:15 Wed 15-Aug

07:15 Tue 07-Aug 09:15 Tue 07-Aug 10:15 Tue 07-Aug 06:15 Wed 08-Aug 09:15 Wed 08-Aug 10:15 Wed 08-Aug

10:15 Wed 08-Aug

00:30 Tue 07-Aug 06:45 Tue 07-Aug

23:30 Mon 06-Aug

08:30 Sat 04-Aug 19:30 Sat 04-Aug 01:30 Sun 05-Aug 17:30 Sun 05-Aug

05:30 Sat 04-Aug

16:30 Tue 31-Jul 22:30 Tue 31-Jul 06:30 Wed 01-Aug 10:30 Wed 01-Aug 11:30 Wed 01-Aug 12:30 Wed 01-Aug

06:45 Tue 07-Aug


02:30 Tue 31-Jul

02:30 Mon 30-Jul

14:30 Sun 29-Jul

10:00 Sat 28-Jul 12:00 Sat 28-Jul 13:00 Sat 28-Jul 05:00 Sun 29-Jul 08:00 Sun 29-Jul 08:30 Sun 29-Jul

16:00 Tue 31-Jul

0.00

0

0

0

0

79

0.0

0.0

0.0 0.0

870.25

5.5 26.5

4.0

6.0 4.0 2.0 12.0 5.0 1.0 4.0 6.0

24.0

0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

24.0

4.5

0.0 0.0

13.0

4.0

0.5 4.0 12.0 2.0

164

0.5 2.0 1.0 20.0 3.0 1.0

0.0

0.0

0.0 0.0 0.0 0.0

0.0 0.0 0.0 0.0 0.0 0.0

28

1.0 6.3

30.0

0.0 0.0 0.0

3.0 11.0 6.0 16.0

65.0

0.5 6.0 8.0 4.0 1.0 1.0

159

10.0 1.0 2.5

24.0

12.0

6.0

0.5 2.0 1.0 16.0 3.0 0.5

0.0 0.0 0.0 0.0

0.0

0.0 0.0 0.0 0.0 0.0 0.0

0.0 0.0 0.0

0.0

0.0

0.0

0.0 0.0 0.0 0.0 0.0 0.0

36.3

35.2 36.3

34.9

33.3 33.5 33.6 34.1 34.3 34.3 34.5 34.8

33.1

32.1

31.1

30.9

30.4

29.4 29.6 30.1 30.2

28.3 28.4 28.4 29.3 29.4 29.4

28.0 28.3

28.0

25.4 25.8 26.1 26.7

25.2

21.7 21.9 22.3 22.4 22.5 22.5

21.5 21.6 21.7

21.1

20.1

19.6

18.4 18.5 18.5 19.2 19.3 19.4

0.00

0.00

0.00

0.00

0.00

2325

0

2325 0.00

2325

2325 2325

0.00 0.00

0.00

2325

0.00

2325 2325 2325 2325 2325

2325 2325

2325 0.00

0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

2325 0.00

2325

0.00 0.00

2325 2325 2325 2325

2325

2325 2325 2325 2325 2325 2325 0.00 0.00 0.00 0.00

0.00

0.00 0.00 0.00 0.00 0.00 0.00

0

2325

0.00 0.00

2325

2325

0.00

0

2325 2325 2325 2325

0.00 0.00 0.00 0.00

0.00

2325

0.00

2325 1737 1737 1737 1742 1742 1742

0

1737 1737 1737

0.00 0.00 0.00 0.00 0.00 0.00

0.00

0.00 0.00 0.00

1737

1737

0.00 0.00

1737

0.00

1737 1737 1737 1737 1737 1737 1737

0

0.00 0.00 0.00 0.00 0.00 0.00

0.00

19.9

WDP1


Page 70 of 76


Page 71 of 76

Document reference number:

PETROM WELL DELIVERY PROCESS Rev 4 - 19.01,2012

Well Data Pack - WDP1 - 258 Colibasi

Well Name

UWI

Project Name

Field Name

Planned spud

Project Type

Asset

258 Colibasi

RO01010624

FRD -DrillingColibasi

Colibasi

H2 2012

Exploatare

A6 Muntenia Central

Location

Well Type

Prod. Type

Security Status

Water Depth

Remarks for Rig

Rig Type

Diapiric zone/ Colibasi approx 12 Km NE from Moreni town

Oil Producer

SRP - Sucker Rod Pump

Not Tight

nn

A. GENERAL / GENERAL

Objectives

CommitProcess ment well Complexity yes

Medium

The exploitation well 258 Colibasi was proposed in "FRDP Drilling Colibasi" - Febr. 2009, target Oligocen. (main objectif Kliwa upper II ). The well will be drill in the same block with well 290 Colibasi . Pontian must be separated with intermediate casing for optimal open and investigation in Oligocen. The casing design of all wells drilled included intermediate casing after Pontian crossing. Estimate flow rate: 21m3 x 15% = 15 t/d and 6,97 th Stm3/d associate gas. Estimate cumulative in period 2012-2027, oil - 23800 tons and 13900 th Stm3 associate gas.

Step I. The well will be drill to 500 m, setup 13 3/8" casing and cementing to surface for isolate surface formations. Summary of Step 2. The drilling will continue below the Pontian/Meotian limit (aprox. 1750 m), where will be setup and cementing 9 5/8" casing. Proposed Activities Step 3. The drilling will continue to the final depth (2325 mMD), setup and cementing 7" exploitation casing.

Expectations

Estimate flow rate:

15 t/zi titei si 6,97 mii Stmc/zi gaze

Production Perioad

16 years

Estimate cumulative: Kliwa sup II Oil ( tons) Associate Gas ( th Stm3)

P90 16900 9800

P50 23800 13900

P10 56800 32900

FORMATION PRESSURE PROGNOSIS / MUD WEIGHT

Formation /Marker

UncerDepth top tainty +/TVDSS TVDSS [m] [m]

Helvetian

335

Dacian

-80

Pontian

-770

Meotian

Pore Content

Fluid Gradient Interval

Lithology Interval

Estimated Pressure at top of formation

[bar/10m] Min [bar]

apa

Brownish and grey marls with sands intercalation and micafere calcareous sandstone or marly sandstones, fine to medium grained, with calcareous cement.

Exp [bar]

Max [bar] [bar/10m]

0,98-0,99

40

40

40

Deltaic sands with clays and coals thin intercalation

1-1,01

41

41

41

gas

Marls

1-1,01

108

109

109

-1370

gas

Grey-yellowish sandstones, fine to medium grained with grey sandy-marls intercalations

1.03

172

172

172

Helvetian

-1450

gas

Brownish and grey marls with sands intercalation and micafere calcareous sandstone or marly sandstones, fine to medium grained, with calcareous cement.

1.03

180

180

180

Kliwa sup I

-1690

oil, gas

Turbiditic facies consist of sands, quartitic sandstone with blackish clay intercalations

1,03-1,04

205

206

207

Kliwa supII

-1795

oil, gas

consist of sands, quartitic sandstone and microconglomerate, with blackish clay intercalations

1,05-1,20

219

235

251

Kliwa sup III

-1900

oil, gas


1.2

263

263

263

Well Objectivs: Petrom, 28/06/2012

Page 1 of 4

Mud Weight

258 Colibasi_WDP1_Rev6 en (17 04 2012).xls / Form_WDP1



Kliwa supII

Well Data Pack - WDP1 - 258 Colibasi

-1795

Offset wells


oil, gas

290 drilled in 2011

Offset wells

1,05-1,20

260 drilled in 2008,

219

235

251

261 drilled in 2009 (other block)

B. SUBSURFACE UNCERTAINTIES / INCERTITUDINI SUBTERANE Description

Reference

*Temperature gradient is normal 3°C / 100m *Initial pressure measured in well 260 Colibasi is 262 atm (2008). The well is in production, natural flow, choke Ø 8 mm , flow rate 43m3 x 18% = 29,5 t/d, tbg pressure 35-42 bar. Pressure gradient is 0,9-1,01atm / 10 m. Dynamic pressure measured in well 260 Colibasi in noiember 2008 was 208 atm. (static pressure 262atm). In august 2009 dynamic pressure in well 261 Colibasi was 170 atm , static pressure was 221 atm. In well 290 colibasi in june 2011 dynamic pressure was 244 atm and static pressure was 255 atm. Permeability is 138 mD.

FRD-Drilling( febr. 2009)

C. WELL HAZARDS / PERICOLE DE FORAJ Description

Reference

*Drilling difficulties in the offset wells: -instability of borehole in surface formations (Dacian) -overpull in Ponţian -overpull and frequently reaming in Badenian, Helveţian, Oligocen * The colision risk doesn't exist because there isn't wells on radius at 100 m.

Offset well 290 Colibasi

D. FACILITIES IMPACT / IMPACTUL FACILITATILOR Description

Reference

E. BASIS FOR COST ESTIMATE / BAZELE ESTIMARILOR DE COSTURI E.1 WELL / SONDA Estimated well TD TVDSS [m]

GL elevation [m]

DF elevation [m]

Estimated well depth MDBRT [m]

Well Profile

Sidetrack

Max. Inclination [deg]

-1985

335

340

2325

Deviated

N

22

SIMOPS

Y

Casing OD [inch]

Grade, Weight, [ppf]

Shoe Depth MD [m]

13 3/8

500

9 5/8

1750

7

2325

Casing Type Surface casing Intermediate casing Production casing

Target Description

TVDSS [m]

Isolate surface formations

Surface location elevation

335

388,936

Isolate Pontian

top of Kliwa sup II

-1795

388,957

Objectiv

Mud Type

N(+)/S(-) E(+)/W(-) [m] [m]

Target shape

Target Size

544,421

n/a

n/a

544,250

Circle

50m radius

Casing setup in the top of Kliwa III Natural tendency NE

Other requirements

Trajectory Deviation 160 m / 280° restrictions

The casing shoe depth refers to the given objectiv, above depths are only approximate.

E.2 EVALUATION / EVALUARE Hole Size [inch]

Log Section TVDSS [m]

17 1/2 12 1/4 Petrom, 28/06/2012

Wireline Log Type N N

Page 2 of 4

LWD Log Type

Pipe Conveyed Logging

Core Section TVDSS [m]

N

N

N

GR from MWD

N

N




Well Data Pack - WDP1 - 258 Colibasi Run #1: Run# 2: Run # 3:

8 1/2

GR - CNL - LDL - LEH -T, Mud Logging GR - XPT GR - CBL - VDL

Type of Production Test

GR- Resistivity

N

N

Mud Logging from surface

Other

E.3 RESERVOIR/ REZERVOR Formation

Lithology

H/C Type

Est. std. rate/day [m3/sm3]

Max. CITHP [bar]

Max. BHP [bar]

Max. BHT [°C]

Permeability [mD]

Porosity [%]

Oligocen

Quartitic sandstoane

Oil

15/21

nn

225

72

50-70

24.6

Gas-Oil Oil/Gas Oil ratio density viscosity [cm/cm] [kg/dm3] [cP] 200

0,852

0.7

H2S [ppm]

CO2 [%]

0

0

E.4 COMPLETION/ COMPLETARE Wellhead pressure rating [bar]

Wellhead Type

Completion Completion Type Depth [m] Single

Lift mechanism

Tubing Size [in]

SRP - Sucker Rod Pump

2 7/8

Number of Comingled Perforated intervals MD [m] prod. zones

X-mas tree Type

Tubing Material

Weight [lb\ft]

X-mas tree press. rating [bar]

Wall Th. [mm]

SSSV Type

Upper Completion Equipment

Perforating equipment

Perforating Gun Type, OD [in]

Perforating Method

2230-2200m

TCP

4", 20gun/ ml

Overbalanced

Volume of displaced fluids [m3]

Type of fluids analysis

50

Oil, Gas, Water

Temperature measurements One Time Measurement

Rig for Testing

Completion Lifetime [month]

Pressure measurements One Time Measurement Compl. Intervent. Time [month]

Yes

Workover Rig

Control Line Type

Production Packer Type

Lower Completion equipment

Perforating fluid Exp. Flowrate [initial/3 years] oil / water / gas type/density [kg/m3] Filtered (2 micron) 3% KCl brine 1.02

Sand Control

Stimulation

Inhibitors

Inhibitors Cycle

No

No

Parafin inhibition

Permanent

Comments/ Expected prod. Problems:

E.5 SURFACE / SUPRAFATA Land contract available

Drilling square [m x m]

Type of land

It belong Elevation of to town/ surface coordinates vilage

Slope [deg]

Existing roads (type, conditions)

other projects

Other projects

Distance from inhabited FC areas facilities

acces roads

electrical lines

flow lines

water sources

Obstacles/ constraints:

Surface Injection Works line difficulty required

Flow-line Injection-line length and diameter length and diameter

Electrical line [V, A, Hz]

Acces road length and width

E.6 UP FRONT WORK / MUNCA PREGATITOARE Kill Fluid Weight

Milling (Packers, etc.)

Strings to Remove

Length of WWS to Remove

Type

Number of Zones to Abandon

Total Length of Perforations

Size [inch]

Length [m]

1 Other Work with Significant Cost Impact

E.7 NOTES / NOTE

E.8 ECONOMICS & COST / ECONOMIE SI COSTURI Petrom, 28/06/2012

Page 3 of 4




Well Data Pack - WDP1 - 258 Colibasi Duration [days]

Cost Estimate Level

Cost [RON]

Site Preparation & Survey

30

1,172,000

Cost Estimate Accuracy

Rig Move On & Off

14

528,000

Cost Estimate Contingency

Upfront Work Drilling

28

9,000,000

WDP1 Project Team (Names)

Evaluation

30

1,300,000

Drilling

Stanciu Viorica

Completion

3

350,000

Production

Tudor Vasile

Testing

5

500,000

Reservoir

Popescu Catalina

Prod./Inj. Test Duration

1,285,000

TOTAL

110

14,135,000

Exploration (if applicable) Surface

Stoica Ionel

F. SUPPORTING DOCUMENTATION / DOCUMENTATIE App. 1

Structural map

App. 2

Cross section

App. 3

Pressure gradients diagram, pore pressure and frack pressure

App. 4

Surface location

App. 5

Well Deviations:

App. 6

Production tests in offset wells

App. 7

Drilling difficulties in offset wells

App. 8

Technical data for surface work

App. 9

Completion in offset wells

App. 10

Geotehnical study, if exist in specify area.

G. WELL DATA PACK SIGNATURES / SEMNATURI Position

Role

Drilling Engineering Team Leader

Supports

Head of Production Engineering

Supports

Andreas Bramlage

Reservoir Manager (Develop.) Exploration Manager (Expl/App)

Approves (technical)

Catalina Popescu

Asset Manager (Development) Exploration Manager (Expl/App)

Approves (budget)

Emil Eugen Iosif

Petrom, 28/06/2012

Name

Signature

Date 19,12,2011

Page 4 of 4


19.10

WRB1 slides and minutes


Page 72 of 76


Page 73 of 76

19.11

WRB2 slides and minutes


Page 74 of 76


Page 75 of 76

Agenda

Well Review Board 2 258 Colibasi

Well Objectives

Well Engineering Team 4 Asset VI

Location and Geology

Project Status

Well Design and Trajectory Bits and Mud Formation Evaluation Section Summaries and Risks

31 May 2012 │ Petrom City │Bucharest

Time vs Depth Cost, Budget , Economics 2

258 Colibasi

Project status (Permits ) 258 Colibasi Mar2012-IUN2012

Well Objectives

WDP1 receiving 21.02.2012

HSSE No accidents, incidents, harm to people No damage to the environment >35 SC/day Geological Oil (+Gas) producer from Kliwa Sup II Exp. rate: 15 MT/day; 6.97 th Stcm/day Exp. reserves (until 2027): 23,800 MT oil 13.9 mil Stm3 associated gas

Today

PM Drilling: Stanciu Viorica

IAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC JAN FEB MAR APR MAY JUN JUL AUG

Land acquisition (drilling site & flowline )

Permits (drilling site & flowline)

AFE Drill well < 33 days (29 days for dry hole) & complete < 5 days Drill & Completion < 3,283,000 Euro Drilling: 12.5 d/1000m

3

258 Colibasi

-Urbanism

Cert.

-Environment -Constr. Auth.

4

258 Colibasi

1

29 May 2012

Project status (Drilling) 258Colibasi

mar

feb

PM Drilling: Stanciu Viorica

Today

WDP2 receiving date:21.02.2012 apr

mai

iun

iul

aug

oct

sep

nov

dec

Ma y

AFE (LS) AFE (LLI) Drilling site construction Dilling Rig Rig mobilization Drilling Rig down

5

258 Colibasi

6

258 Colibasi

Asset

Diameter (inch)

6

3/6’’

Project status (tie-in) 258 Colibasi apr.2012- aug.2012 Today oct

nov

dec

jan

feb

march

apr

mai

iun

iul

aug

sep

oct

Flow line

Flowline Well 258 Colibasi HP 1

-Engineering -Contracting

Length (m)

Delivery Date

Approval Date

HP 2 Deliver Date

Approval Date

HP 3 Deliver Date

HP 4

Approval Date

-Execution Production site

200m/1000m 09.03.2012 13.04.2012 20.04.2012 20.05.2012 10.06.2012 15.07.2012

PARK WHERE THE WELL IS ASSIGNED

30.08.2012

Claviatura sd.259 Colibasi

Rig up PERMITS STATUS

Testing

-The Urbanism Ceritificate obtained in apr.2012 -The Construction Permit obtained in iun.2012

Equiping Tie-in Rig down PIF

7

258 Colibasi

8

258 Colibasi

2

Surface location

Field Cross-section and Offset Wells.

Surface Location: E = 544421m N = 388936m Z = 340m (RF above MSL)

9

Target Location:

OFFSET WELLS

E = 544250m N = 388957m Z = 2135m TVD BRT

In same block • 290 (1Q11) exploration well In adjacent block • 259 (2Q12) • 260 (3Q08) • 261 (2Q09)

258 Colibasi

10 258 Colibasi

Formation Tops

Formation

Tops TVD (MD) BRT m

Uncertainty TVD m

Helvetian Dacian Pontian Meotian Helvetian Kliwa sup I Kliwa sup II Kliwa sup III TD

5 (5) 420 (420) 1110 (1110) 1710 (1716) 1790 (1799) 2030 (2048) 2135 (2157) 2240 (2266) 2295 (2325)

±10 ±10 ±10 ±10 ±10 ±10 ±10 ±10 ±10

Description Clays ,marls, sandstone and intercalations of anhydrite. Clays ,marls and sandstone. Shaley facies Sand, sandstones and marls Clays ,marls, sandstone and intercalations of anhydrite.

Kliwa (consolidated siliceous sandstone)

$$PAYZONE$$ 11

258 Colibasi

12 258 Colibasi

3

Offset Casing Designs 260 Colibasi

261 Colibasi

259 Colibasi

Well Design

290 Colibasi 12

258 Colibasi 20 80 100

Helvetian

258 Colibasi

REVISION 3.0 (30-05-2012) {Based on Traj Rev A.1}

All depths are quoted MD (TVD) BRT m RT elevation above MSL = 340m GL elevation above MSL = 335m 3m rat holes assumed


1.0

0

415 502

498

502

1.5

500

200

2.0

26" Spud mud (1.05sg)

Mud Weight Max Pore Pressure Fracture Gradient 17-½" Spud mud (1.05sg)

692

290 Colibasi mud wt

693 400

715

13-⅜" @ 500(500)m

1110

Pontain

1130 1234

2.5

30" @ 30m (Hammer to refusal) 20" @ 100(100)m

Dacian

436

Helv.

0 50 100 150 200 250 300 350 400 450 500 550 600 650 700 750 800 850 900 950 1000 1050 1100 1150 1200 1250 1300 1350 1400 1450 1500 1550 1600 1650 1700 1750 1800 1850 1900 1950 2000 2050 2100 2150 2200 2250 2300 2350 2400 2450 2500

TVD BRT (m)

TVD (m)

1235

FIT @504m = 1.45sg

600

800

1,000

1213

12-¼" NAF (1.20-1.25 sg)

D/P @1110m 1,200


1,400

1833 1835 1900 1917

1860 1873 1960

1755 1799 1835

1710 1737 1790

Meotian Top of tail @ 1550(1549)m

1,600

Helvetian

P/M @1710m -

1913 Oligocean / Kliwa

2055 2135 2158

2152 2172

9-⅝" @ 1737(1730)m FIT @1737m = 1.55sg

M/He @1790m 1,800

8-½" NAF (1.25 sg)

Kliwa 2,000 Sup I @2030m -

2227 2254

. Sup II@2135m -

2274

.

2,200 Sup III@2240m -

2325 2360

7" @ 2325(2295)m

2429 2509

2527

2,400

Temp Gradient = 3 degC 3°C / 100 m

13 258 Colibasi

Casing Design

14 258 Colibasi

Trajectory

Trajectory Details: • “J” shaped • KOP = 1400m (in Pontian); • BUR = 2/30mº (234mMD building) • Tangent inc = 16°, azi = 277°(length =691m) • 9-⅝” shoe 100m into tangent • Displacement @ TD = 217m (26mN, 215mW) Anti-Collision: Min SF = 11.33, Min C-C = 125.1m Geo target = Circle 50m radius 15 258 Colibasi

16 258 Colibasi

4

Trajectory

Mud Proposal MUD PARAMETERS

290 Colibasi

258 Colibasi

17 258 Colibasi

Interval (MD) Footage Type of fluid Density Marsh Viscosity PV Yield Point Gel 10 sec. Gel 10 min 6 RPM 3 RPM API Filtrate PH Ca++ MBT LGS HPHT-Filtrate O/W Ratio Emulsion stability Alcalinity Sand WPS Water phase activity

U.M. in m-m m kg/dm³ sec/l cP lb/100ft² lb/100ft² lb/100ft² lb/100ft² lb/100ft² cm³/30' mg/l kg/m3 % Vol ml Volts

I 26" 0-80 80 Spud Mud 1.05-1.1 120-80 15-25 20-35 10-15 20-35 <15 8.5-9 <200 <77 <12

ml H2SO4 0.1 N

% vol g/l

<1 -

Interval II III 17 1/2" 12 1/4" 80-500 500-1737 420 1237 Spud Mud NADF 1.05-1.1 1.20-1.25 80-60 ALAP ALAP 20-30 15-25 10-15 8-12 20-35 15-20 10-12 8-9 12-8 8.5-9 <200 <60 <10 <5 <5 75-25 >750 2-3 <0.35 <0.25 200-250 0.75-0.8

IV 8 1/2" 1737-2325 588 NADF 1.25 ALAP 15-20 7-10 12-22 8-9 5-6 -

<4 <5 80-20 >800 2-3 <0.2 200-250 0.75-0.8

18 258 Colibasi

Bit Program

Formation Evaluation Geophysical Logging LWD

What Has Changed? Addition of 26” bit 12 ¼”

12-¼”: Change from MXL1 to MXLX.

Directional survey

Mud logging will take place from surface 19 258 Colibasi

20 258 Colibasi

5

Section Summaries

Section Summaries

30” Conductor To be hammered to refusal (~2 wks) Risk Mitigation • Drive shoe (1.5” wall) 26” hole Objective: Provide conduit for drilling Shallow • 30” Conductor with 1” wall conductor Casingseat Spec: X52 │460.9kg/m │welded

26” Hole (100m) / 20” Surface Casing (0 - 100m)

Risk

Objective: Isolate loss zones and support unstable Helvetian

Mitigation

Trajectory: Vertical

Losses

• Minimum mud wt Bit: Roller Cone• (IADC=111) 25m3 LCM on hand (2m3 added per stand) BHA: Shock sub• Cement + DCs truck on standby

Mud: ~1.05sg spud mud Cement: 1.8sg to surface

17-½” Hole (400m) / 13-⅜” Surface Casing (0-500m) Objective: Permits; switch to NAF, mud wt increase, BOP N/U. Isolates Helvetian

Risk Mitigation Trajectory: Vertical Losses

• Min mud wt.

Bit: Roller Cone (IADC=118) • Loss zone isolated with 20” Packed sub (nobit. motor) Bit BHA: wear (pyrite + + shock • Roller cone conglomerates)

Mud: ~1.05sg spud mud

Bit balling

• 2-3% detergent in mud

Cement: 1.8sg to •surface Nozzles to provide sufficient HSI

Casing Spec: K55• Salt │101.16kg/m │Tenaris ER Salt contamination onsite to treat mud if required

Casing Spec: K55 │197.9kg/m │Tenaris ER 21 258 Colibasi

22 258 Colibasi

Section Summaries

Section Summaries

12-¼” Hole (1237m) / 9-⅝” Intermediate Casing (0-1737m)

8-½” Hole (588m) / 7” Production Casing (0-2325m)

Dacian and Pontian over burden before RiskObjective: Isolate Mitigation

Risk Objective: Accommodate Mitigation cement and perforate completion

Over pulls due to • NADF (wt same as 259 Colibasi) shale activity Trajectory: KOP= 1400m. BUR= 2º/30m. Tangent= 16º inc Bit wear (pyrite + cone bit. Bit: Roller Cone• Roller (IADC=117) conglomerates)

Trajectory: Tangent @ 16º inc Losses Mud wt reduce (compared to 290) and Bit: 5 Blade PDC (IADC=M223) shallower TD. Both salt and non salt cement slurries will have Salt contamination BHA: Motor (AKO=1º) + OnTrak been worked in advance.

entering reservoir

BHA: Motor (AKO=1.1º) + NaviGam + 2 additional DCs Logging: Gamma (LWD) Mud: 1.20-1.25sg NADF Cement: Tail (1.9sg) to 1400m. Scavenger to surface Casing Spec: L80 │69.94kg/m │Tenaris Blue

23 258 Colibasi

Logging: Gam+Res (LWD). Neutron Density (wireline) Mud: 1.25sg NADF Cement: Tail (1.9sg) to 1550m. Scavenger to surface Casing Spec: L80 │43.16kg/m │Tenaris Blue

24 258 Colibasi

6

Offset Wells

AFE Time-Depth Curve

0 200

260 Colibasi 261 Colibasi 261 Colibasi 290 Colibasi 290 Colibasi 259 Colibasi 259 Colibasi Colibasi 258

400 600 800

Depth (m)

1000

1200 1400 1600 1800 2000 2200 2400

Dry Hole = 29days Well = 33days Well + Completion = 38 days

2 days ahead of 259

2600 2800 0

10

20

30

40

Days

50

60

70

80

25 258 Colibasi

26 258 Colibasi

Well Cost, Economics, Budget

Thank you

0 UPPER LIMIT

AFE

Measured Depth

500 1000

Any questions?

1500 2000 2500 0

27 258 Colibasi

1000

2000 AFC Cost (€M)

3000

4000

28 258 Colibasi

7

258 Colibasi Well Review Board 2 - Meeting Minutes Topic

258 Colibasi WRB2

Date

31-May-2012

Place

IB-02-B705-Brancusi 2

Time

12:00 – 13:00

Author

Mark Smith

Permanent Participants

Maekiaho, Leo; Selischi, Gabriel; Stoica, Liliana; Zelezneac, Mihai; Antohi, Roberto Manuel; Spencer, David; Van Dongen, Harald; Tomics, Jozsef; Timus, Constantin; Gortoescu, Daniela Luminita; Dumitrescu, Razvan; Paun, Razvan; Schlett, Alexandru; Van Rixel, Frans; Milea, Sorin Cristian; Serban, Madalina; Dumitrache, Bogdan Andrei; Ion, Andrei Corneliu; Pinta, Marius-Razvan; Micu, Octavian Ioan; Rotaru, Andrei; Petre, Toma; Stanciu, Viorica Argentina; Bajinaru, Sorin; Popescu, Catalina; Iosif, Emil Eugen; Dumitru, Valentin; Tudor P, Vasile; Manea, Bogdan; Stancu, Ioana; Stanca, Cristina; Angheli, Alexandru; Iacob, George Ovidiu; Nedelcu, Bogdan; Istrate, Nicolae

Distributed to

All invitees.

Attachments

WRB2 presentation

KEY POINTS •

The surface location is still under construction and will not be ready for 2-3 weeks. Wireline XPT measurement is provisionally in the program. TBC by the drilling and reservoir team based on: → 259 Colibasi CBL results (i.e. hole condition); → Borehole conditions evident whilst drilling 258 Colibasi; and → Overall well economics. Full economic justification must be presented at WRB2 in future including bench marking. AFE costs should be fed into well economics modeling. Block boundary uncertainty exists. This will be interpreted during drilling to determine if 258 is in fact an exploration of a different block.

•

• •

FULL MEETING MINUTES No. Type 1

I

2.

I

3.

I

Topics / Results of Meeting The surface location is still under construction and will not be ready for 2-3 weeks. Progress was hindered by cluster location AFE issues (258/291 cluster location) and poor weather. 290 was an exploration well and is most relevant offset well in terms of geology and drilling problems (as it is believed to be in the same block as 258). 290 and 258 block sharing will be confirmed during drilling. 259 is the most relevant offset well in terms of rig performance as drilling was completed in late May 2012 (drilled in different Colibasi block) and same rig will be used. 3D seismic data does not clearly show block boundaries. The original model (outlined in WDP1) may be inaccurate. We will learn more about block location whilst drilling.

Responsible Sorin Bajinaru.

Mark Smith

Sorin Bajinaru.

Types: I = Information, R = Recommendation, C = Comment, T = Task, D = Decision 1/3

258 Colibasi Well Review Board 2 - Meeting Minutes

4.

R

5.

I

6.

C

7.

R

Due to this uncertainty it is possible to meet faults whilst drilling 258 Colibasi, particularly to the West. We should make every effort to identify which block we are in whilst drilling to better determine the pressure regime in the reservoir. 258 could in fact be an exploration well (not a development well) of a new block and, therefore, may need a higher mud wt across reservoir. The chance of encountering salt in this well is small. Salt is likely to the South but not so likely to the North 258 is planned to have a additional 20” surface casing (not present in 259 Colibasi) to mitigate losses in upper hole section. 263m3 losses were recorded in 259 Colibasi. Wireline pressure measurement (XPT) is provisionally planned for this well. It will, however, be confirmed based on; 1) Hole condition interpreted from 259 Colibasi CBL (259 had 8-1/2” hole open for 1 wireline run only). 2) Borehole conditions present whilst drilling 258 Colibasi. 3) Overall well economics (XPT ~120,000 Euro).

Schlett, Alexandru Sorin Bajinaru. Mark Smith

Schlett, Alexandru / Leo Maekiaho

This will be a team decision between drilling and reservoir. 8.

R

Performance is very important but we need to ensure we do not encourage unsafe operations by pushing performance too hard, too quickly.

Schlett, Alexandru

9.

R

Use central jet nozzle to mitigate against bit balling in 17-1/2” and 26” hole sections.

Leo Maekiaho

10.

C

17-1/2” hole is not standard for Petrom. The well catalogue dictates 16” to be standard. The risk of salt does, however, justify 17-1/2” in 258.

Leo Maekiaho

11.

D

We will perform FITs and not LOTs in this well.

Schlett, Alexandru

12.

I

Kliwa is a layer cake reservoir with oil and gas. This makes an ESP artificial lift difficult.

Sorin Bajinaru.

13.

C

Possibly 2 more wells next year in this field depending on the results for 258.

Catalina Popescu

Consider Kymera drill bits for wells which have interbedded hard and soft bands (OMV have had success elsewhere). 14.

R

http://www.otcnet.org/2011/pages/general/spotlight/kymera.php

Leo Maekiaho

In the future Petrom may consider ‘compact’ wellheads. These have also been successfully run in other OMV operations and will save days of operation. WRB2 should have a full economic comparison to justify the well; not just an AFE cost.

Sorin Bajinaru.

15.

T

16.

D

Ensure benchmarking and economics models are done for each well in the future.

Leo Maekiaho

17.

R

In future try to avoid surface location hold-ups as it forces us to break a continuous drilling campaign and our drilling contractors were promised this during tender. It also reduces the feeling of operational urgency amongst crews.

Leo Maekiaho


ATTENDEES


258 Colibasi Drilling Program FINAL

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