258 Colibasi Drilling Program FINAL

258 Colibasi Drilling Program Rev 3.0 Page 1 of 76

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

4.1 258 Colibasi Structural Surface locations 11 5 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- Casing Accessories 25 9.3 9- Casing Accessories 25 9.4 7 Casing Accessories 25

10 BIT PROGRAM ............................................................................................................. 26 11 CEMENTING PROGRAM SUMMARY ........................................................................... 27

11.1 13- Surface Casing 27 11.2 9- Surface Casing 27 11.3 7 Production Casing 27

12 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. 31


15.2 Conductor clean out / Pilot hole 31 15.3 13- Casing Drilling 32 15.4 12- Hole and 9- Casing. 35 15.5 8- 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- Casing Drilling (17- Hole) 50 18.3 9- Section (12- Hole) 51 18.4 7 Section (8- Hole) 52 18.5 Wellhead, BOP and Pressure Test Program. 53

18.5.1 Barrier Policy 53 18.6 Management of Change 53

19 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


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- 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 TDs in 8- 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- 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.


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

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.

1.1 Key Performance Indicators (KPIs)

Metric Target Start cards / day 35 Near miss reported / well 1 Planned (drilling + prod casing) 33 days Planned cost (drilling) 2,573,427 Planned cost/m 1107/m Planned days/1000m drilled 11.6 days


1.2 AFE MD vs Days and MD vs Expenditure

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2 COMMITMENTS Activity Requirement

Disposal of drilling fluid and drilling cuttings

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.

Well site drainage, chemical storage and management

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

Liquid Discharges 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.

Incident Reporting 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 Management

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.

Spillage of diesel fuel or oil

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


Bucharest / Field cluster office commitments:

Activity Requirement Prior to drilling

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

Discharge of combustion products from engines

Report greenhouse gas emissions data to Federal Government annually.

Environmental Audit 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.

# Commitment Action by Action Timing

1

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.

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.

2 Offline testing of BOP DSV.

Rig manager. The DSV must ensure, where possible, the BOP is tested offline and in compliance with Petrom Drilling Operations Manual.

At all times.

3 The risk of diesel spillage during refuelling shall be minimised.

Rig Manager Follow the refuelling procedure. Keep all spills contained.

At all times.

4

Oil loss during production testing will be minimised.

DSV Follow guidelines for minimising production testing fallout as referenced in the Petrom Environmental Guidelines, Commitments and Responsibilities under Spillage of Oil.

During well testing.

5

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

Rig Manager/ Medic/ Safety Officer/ DSV.

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)

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

6 Post copies of MSDS and environmental commitments.

Rig Manager/ Medic /

Safety Off.

Post copies of the MSDS and environmental commitments outlined on the previous page on all notice boards.

Prior to the start of the well.

7 A handover shall be conducted.

DSV Site inspection shall be conducted at end of well, prior to handover to production department

At end of drilling after rig move

8 Permit to Work System DSV/Rig Manager Ensure PTW and JSA is used on location as per Petrom/OMV system

At All Times


3 CONTACT LIST Name Title Mobile Office

Iana Ioan Petrom DSI 0726 333 138 - Chiran Ioan Petrom DSI 0730 170 706 Parfichi Vasile Petrom DSV 0729 996 135 - Cucu Mircea Petrom DSV 0728 628 930 - Marcu Pompiliu Petrom DSV 0729 996 130 Zarnescu Andrei Petrom WSDE 0728 220 788 -

Asset 6 Department Name Title Mobile Office

Stanciu Viorica Argentina Project & Engineering Manager 0728 852 895 Marinescu Dumitru Asset Office engineer 0728 727 082 / Popescu Catalina Geologist engineer 0724 252 434 0372 429 462

HSE Department Name Title Mobile Office

Eduard Steanescu Drilling Department HSE 0724 330 265 0372 449 952

Drilling Department Bucharest Name Title Mobile Office

Alexandru Schlett Well Delivery TL (Team 4) 0728 292 444 0372 849 677 Frans van Rixel TL Well Delivery Operations 0720 202 136 0372 483 497 Sorin Milea Senior Drilling Engineer 0728 727 114 0372 448 580 Mark Smith Drilling Engineer 0720 017 773 0372 854 346

Vendor List Service Company Contact Cell Phone

Drilling Contractor Dafora Cristian Georgescu (Drilling Manager) 0730 099 389 Jar, Accelerators, PBLs Odfjell Olsen Torgeir 47 90 776 671 Drilling Bits Baker Hughes Raul Stanel 0730 013 746

Drilling & LWD/MWD Baker Hughes Vasile Cosmeanu (Coordinator) Ramona Harabagiu (Engineer) 0733 109 369 0731 495 926

Wellhead Equipment Cameron Tudor Constantin 0728 221 627 Mud Logging System Rompetrol Alexandru Gomoescu 0732 141 454 Cementing Rompetrol Constantin Radu 0740 078 923 Cementing SLB Ahmed Anisse Salhi 0730 714 841 Drilling Fluids AVA Deliu Constantin 0751 039 900 Casing running and Casing drilling

Odfjell Olsen Torgeir 47 90 776 671

Casing accessories Weatherford Arthur Iordache Cristian Carpen

0736 101 909 0755 102 077

Fishing Weatherford Arthur Iordache 0736 101 909 Slickline Rompetrol Mr. Iancu Marcel 0745 349 969 Gyro measurement Scientific Drilling Constantin Pinta 0720 947 765


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.): Lat = 4459'57.093" N Long = 2533'48.103" E

Grid Co-ordinates (Easting/Northing): 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.): Lat = 4459'57.437" N Long = 2533'40.674" E

Grid (Easting/Northing): 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


4.1 258 Colibasi Structural Surface locations

5 RESERVOIR AND GEOLOGICAL CONDITIONS 5.1 Correlation wells The Colibasi structure is located in Dambovita county, on the NE structural alignment Ocnita-ColibasiDraganeasaRuncu 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 Colibai 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).


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COLIBASIFragm.de Harta Structurala Top KLIWA Super II1:5000

Iordache Claudiu01/23/2012

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0m

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.

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 learnings from 290 have been included on the Well Schematic in Offset Well Review.


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.


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 Cmpina 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 5-10.

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.


5.4 Formation Tops and Geological Description

5.4 Temperature Gradient Analysis indicated the formation temperature gradient is ~3.0 deg C / 100m.

Maximum anticipated borehole temperature 69C 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 Formation

Estimated Pressure gradients (SG)

Estimated Fracture 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.

Formation Tops TVD (MD) BRT m Uncertainty

TVD m Description

Helvetian 5 (5) 10 Predominantly clays ,marls ,sandstone with intercalations of anhydrite Dacian 420 (420) 10 Clays ,marls and sands with thin coal intercalations Pontian 1110 (1110) 10 Shally facies Meotian 1710 (1716) 10 Sand and oolitic sandstones with marls and sandy

marls Helvetian 1790 (1799) 10 Predominantly clays ,marls ,sandstone with intercalations of anhydrite Kliwa sup I 2030 (2048) 10

Kliwas facies (siliceous sandstone, good consolidation with compacted argillaceous thickness)

Kliwa sup II 2135 (2157) 10 Kliwa sup III 2240 (2266) 10 TD 2295 (2325) 10


6 PORE PRESSURE AND FRACTURE GRADIENT The well design along with predicted pore pressure and fracture gradient is summarised below;

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Pressure Gradient (S.G.)258 Colibasi

Mud Weight

Max Pore Pressure

Fracture Gradient

30" @ 22m (Hammer to refusal)

13-" @ 500(500)m

9-" @ 1737(1730)m

7" @ 2325(2299)m

12-" NAF (1.20-1.25 sg)

All depths are quoted MD (TVD) BRT mRT elevation above MSL = 349.16mGL elevation above MSL = 344.16m

3m rat holes assumed

KOP@ 1425mBUR =2o/30mMax inc =15o

REVISION 4.0 (21-06-2012){Based on Traj Rev B.0}

D/P @1119m -

P/M @1719m -

Hel

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He/D @429m-

M/He @1799m -

FIT @504m = 1.45sg

KliwaSup I @2039m -

Sup II@2144m -

..

Sup III@2249m-

FIT @1737m = 1.55sg

17-" Spud mud (1.05sg)

8-" NAF (1.25 sg)

Formation topsDirectional data

Top of tail @ 1400(1400)m

EOB@ 1651(1648)m

Temp Gradient = 3C / 100m

KEY



7 TRAJECTORY


7.1 Trajectory Description (J-Shaped)

KOP at 1425m MDRT in Pontian Shale (12- 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- 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- TD and then KO at 1750m (20m below 9-5/8 shoe) in the 8- 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- 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.


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

290 Colibasi

258 Colibasi


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- Strategy: 0-500m (Top Hole)

The 17- 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- 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- section on 290 Colibasi. ROP was also low.

259 Colibasi adopted a NAF system in the 12- section and significantly fewer overpulls resulted. ROP was also higher. It is believed that the NAFs superior inhibition avoided repetition of overpulls within the shale regions. As such a NAF system will be applied on 258 Colibasi.

8- Strategy: 1737-2325m

High torque and drag was encountered in the 8- 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- 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.


MUD PARAMETERS U.M. Interval

II III IV

in 17 " 12 " 8 "

Interval (MD) m - m 0-500 500-1737 1737-2325

Footage m 500 1237 588

Type of fluid - Spud Mud NAF NAF

Density kg/dm 1.05-1.15 1.20-1.25 1.25

Marsh Viscosity sec/l 120-60 - -

PV cP ALAP ALAP ALAP

Yield Point lb/100ft 20-30 15-25 15-20

Gel 10 sec. lb/100ft 10-15 8-12 7-10

Gel 10 min lb/100ft 20-35 15-20 12-22

6 RPM lb/100ft - 10-12 8-9

3 RPM lb/100ft - 8-9 5-6

API Filtrate cm/30' 12-8 -

PH 8.5-9

Ca++ mg/l


9 CASING PROGRAM SUMMARY All depths below are referenced to BRT.

Interval MD BRT

[m] Length

[m] Nom. Size [in]

Wall thickness

[mm] Grade

-

Connection -

Nominal Weight [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- - CASING DRILLING 0 - 500 500 13- 12.19 K55 TSH ER 101.16 45100 12770 13800 14840

Intermediate Casing 9- 0 - 1737 1737 9- 11.99 L80 TSH Blue 69.94 128133 24100 26800 29500

Production Casing 7

0-2325 2325 7 10.36 L80 TSH Blue 43.19 100347 14100 15600 17200

*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- to TD may require a higher 7 casing setting depth and so application of a 4.5 production liner may be required.

Interval MD BRT

[m] Length

[m] Nom. Size [in]

Wall thickness

[mm] Grade

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Connection -

Nominal Weight [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.

Internal Yield [MPa]

Collapse [MPa]

Body Yield Strength [x1000daN]

Standard Drift Diameter [mm]

Connection OD [mm]

Surface Casing 13- CASING DRILLING 23.8 13.4 476 311.4 365.1

Intermediate Casing 9-5/8 47.3 32.8 483 216.5 269.9

Production Casing 7 62.5 59.3 332 151.6 196.4

9-5/8 Pups 1 x 4.5m 1 x 3m

7 Pups 1 x 4.5m 1 x 3m


9.1 Casing Objectives

13- Surface Casing (casing drilling) The 13- 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- will also permit rig-up of the BOP to provide well control when drilling the 12- hole through the potentially gas bearing Pontian (low chance of encountering hydrocarbons in Pontian or top Meotian). The 13- 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.


9.2 13- Casing Accessories

Casing accessories Model Diameter Conn. Position m (MD)

Frequency cents/jnts Total

1. Float collar (non-rotating), single valve - 13- T-ER

~475 (top of shoe-track) - 1

2. Centralisers (Odfjell) Econ-O-Glider 17 - 450-500 1/1 5 3. Stop collars (Odfjell) DHP 14 - 450-500 as above 10

9.3 9- Casing Accessories

Casing accessories Model Diameter Conn. Position m (MD)

Frequency cents/jnts Total

1. Reamer shoe, single valve - 9- TSH-Blue - - 1

2. Float collar, single valve -

9- TSH-Blue ~1712 (top

of shoe-track)

- 1

3. Centralisers (Centek) Standard S2 9- x 12- - 0-1250

1250-1700 1700-1737

1/10

1/1

10 18 3

4. Stop collars (Centek) Slip on 9- x 12- - as above as above 62

9.4 7 Casing Accessories

Casing Accessories Model Diameter Conn. Position m (MD) Frequency cents/jnts Total

1. Reamer shoe, single valve - 7 TSH-Blue - - 1

2. Float collar, single valve - 7 TSH-Blue ~2300 (top

of shoe-track)

- 1

3. Centralisers (Centek) Standard S2 7 x 8- - 0-1400

1400-2300 2300-2325

1/10 2/3 1/1

11 49 2

4. Stop collars (Centek) Slip on 7 x 8- - as above as above 124

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).


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- 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.


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 learnings from 290 and 259 Colibasi.

11.1 13- Surface Casing Mean Annular Excess = 80% (Equivalent OH Diameter = 20.2)

1. Water Spacer: 4m3 1.00 SG 2. Spacer: 4m3 1.40 SG 3. Tail Slurry: 58.5m3 1.80 SG (0 500m) 4. Mud: 37.5m3 1.20 SG (NAF)

11.2 9- Surface Casing Mean Annular Excess = 50% (Equivalent OH Diameter = 13.37)

1. Oil Spacer: 4m3 1.30 SG 2. Water Spacer: 6m3 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: 65.6m3 1.25 SG

11.3 7 Production Casing Mean Annular Excess = 20% (Equivalent OH Diameter = 8.77)

1. Chemical wash: 4m3 1.00 SG 2. Scavenger Slurry: 20.2m3 1.45 SG (0 1510m) 3. Tail Slurry: 11.8m3 1.90 SG (1510 2325m) 4. Mud: 43.3m3 1.25 SG


12 LOGGING AND EVALUATION SUMMARY 12.1 Geophysical logging

Hole Size MWD Wireline 17- -- -- 12- GR (MWD) --

8- 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

Section Interval (MD) Distance between surveys Tool Method

- m m - - I 0 - 500 - - None (casing drilling)

II, III 500 - 2325 1 Stand (2 joints) = 18m OnTrak MWD

12.3 Cement bond log A CBL will be made of the 7 production casing string from 1500m to TD.


13 WELL HEAD

No Casing head components

Size/ Pressure

Casing Primary

seal Hanger Secondary

seal - - in / bar in in in 1 Casing head flange 13-5/8 x 13- x 350 9-5/8 9-5/8 - 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. x 11 x 9.5/8 x 7 x 7.1/16 x 2.7/8 x 350 bar.


14 BOP STACK

Previous Casing

13-5/8 BOP Stack Rams Inside

diameter Type Pressure

Drilling Run casing*

In in - bar in in

13- 13-5/8 Pipe/blind 350 5 5 13-5/8 Annular 210 annular annular

9- 13-5/8 Pipe/blind 350 5 5 13-5/8 Annular 210 annular annular

*Only install casing rams if the rams can be tested after the installation.


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- x 26 pilot hole

15.2.5 P/U the 17- x 26 pilot hole/ conductor cleanout assembly. This assembly will consist of a 17- 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- 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- pilot hole below the 30 conductor in preparation for the 17- 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- x 26 pilot hole drilling assembly.


15.3 13- Casing Drilling

15.3.1 Apply 13- Econ-o-glider centralisers to 13- 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- casing drilling shoe track assembly (17- 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:

o Operating Flow Rate* = 2200-2400 l/min (HSI = 0.8-1.05). 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- casing (17- 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.


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 medium-course LCM pill must be ready before commencing drilling. As soon as losses are detected 1-2m3 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 12- 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- casing.

15.3.14 Install 13- 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- BOPs including annular preventer and install bell nipple.

15.3.17 Install choke and kill lines. Connect hydraulic hoses.


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- 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- 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.


15.4 12- Hole and 9- 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- roller cone bit (TFA=0.7854, 4x16s) + Motor BHA (AKO 1.1) + MWD (NaviGam).

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

15.4.3 Drill out the 13- casing shoe track and 17- 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.


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


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

15.4.6 Drill ahead 12- 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- 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- 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- 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 DSVs 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.


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.


15.4.16 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- 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 13- wellhead, set slips.


15.4.22 Drop slips, slack off casing weight, land casing.

15.4.23 Cut 9-5/8casing 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 out-lets 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.


15.5 8- Hole and 7 Casing.

15.5.1 P/U 8- 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.


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- 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- 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- 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.


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 DSVs 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.


15.5.16 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


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 7casing 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.


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- and 7 CBL from 1500mMD to TD.

15.5.40 Handover 258 Colibasi to production department.


16 WELL PERFORMANCE: Petrom S.A. AFC Time Curve

Well Name: 258 Colibasi

0

500

1000

1500

2000

25000 10 20 30 40 50 60

Me

asu

red

Dept

h

Days

258 Colibasi

AFE UPPER LIMIT

Drill 12-1/4" = 7 days

Run+Cemented 9-5/8 = 4 days

Testing & Completion = 5 days

Drill 8-1/2" = 5 days

Run+Cement 7" = 6 days

Cement 13-3/8" = 3 days

Casing drill 13-3/8" = 8 days

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


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- 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 12 30 Helvetian50

100150200250300350400 415 Dacian450 436500 502 498 502 500550600650 692 693700 715750800850900950

100010501100 1110 Pontain1150 113012001250 1234 1235 1213130013501400145015001550160016501700 1710 Meotian1750 1755 17371800 1833 1799 17901850 1835 1860 1835 Helvetian1900 1900 1873 19131950 1917 19602000 Oligocean / 2050 2055 Kliwa2100 21352150 2152 21582200 2172 22272250 22542300 22742350 23252400 23602450 24292500 2509 2527

260 Colibasi 261 Colibasi 259 Colibasi 258 Colibasi290 Colibasi


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.

0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

2,000

2,200

2,400

0.5 1.0 1.5 2.0 2.5

TVD

B

RT (m

)

Pressure Gradient (S.G.)

258 Colibasi

Mud WeightMax Pore PressureFracture Gradient290 Colibasi mud wt

30" @ 22m (Hammer to refusal)

13-" @ 500(500)m

9-" @ 1737(1730)m

7" @ 2325(2299)m

12-" NAF (1.20-1.25sg)

All depths are quoted MD (TVD) BRT mRT elevation above MSL = 349.16mGL elevation above MSL = 344.16m

3m rat holes assumed

KOP@ 1425mBUR =2o/30mMax inc =15o

REVISION 4.0 (21-06-2012){Based on Traj Rev B.0}

D/P @1119m

P/M @1719m -

Helv

.

He/D @429m-

M/He @1799m -

FIT @504m = 1.45 sg

KliwaSup I @2039m -.

Sup II@2144m -

.

Sup III@2249m -

FIT @1742 = 1.55sg

17-" Spud mud (1.05sg)

8-" NAF (1.25 sg)

Losses 5m3 @ 47-66m

@ 91-95m

Overpulls (+ Reaming)15-25t@ 510-650mstuck@ 666m10t@ 660-740m25t@ 750m25t@ 1120m25t@ 1545-1425m

Pyrite, Glauconite and Microconglomerates

Formation topsDirectional dataOffset problems (290 Colibasi)



EOB@ 1651(1648)m

Losses 5m3 @ 1293m

T&D @1802-

Overpulls (+ Reaming)15t@ 2080m, 20t@2145-2290m

Losses 42m3 @ 2430m

Losses 5m3 @ 1092m

Temp Gradient = 3C / 100m

KEY


0

200

400

600

800

1000

1200

1400

1600

1800

2000

2200

2400

2600

28000 10 20 30 40 50 60 70 80

Dep

th (m

)

Days

260 Colibasi

261 Colibasi

290 Colibasi

259 Colibasi

258 Colibasi

258 COLIBASI AFE Time-Depth VS Offset

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- and 8- 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- section.


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.

18.1 Risks Applicable to all Sections

Potential Risk/Hazard Consequence Im

pact

Pro

babi

lity

Risk

Mitigation and Control

Rem

nan

t Ri

sk

Incident during operation with multiple crew

members (e.g. R/U,R/D lifting /handling

equipment, High pressure testing, Casing running)

HSSE incident. NPT caused by

equipment damage. H M H

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.

The Dafora RSS and Petrom DSV to monitor the execution of such operations.

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

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.

L

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

equipment.

HSSE incident e.g. fatality or damage to

equipment. H M H

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.

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

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

L

Project fast tracking Exceeding project AFE due to NPT M L M

Program changes have to be approved by DOTL and ETL.

Accurate reporting in DDR.

Make use of expertise within the team e.g. service companies.

L


18.2 13- Casing Drilling (17- Hole)


pact

Pro

babi

lity

Risk


Rem

nan

t Ri

sk

Mud losses in surface formation (Helvetian),

particularly @ ~50m and ~100m.

No possibility to set cement plug as loss prevention strategy.

NPT. Cost of lost mud + LCM. Poor ROP. Poor hole cleaning Failure to reach TD with casing.

M H H

Maintain low mud weight.

Using WBM which is comparatively cheaper than NAF.

Ensure mud properties are optimised for filter cake building.

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

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- from 300m if required.

H

Bit/BHA balling (shale bands).

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.

NPT due to low ROP.

Inability to reach TD with casing.

H M H

Keep mud properties as per Program, thin and dilute as required.

Have detergent continually added to the active mud system.

Casing drilling minimises WOB and so balling tendency should be reduced.


M

Bit wear (pyrite and micro-conglomerates in surface

formations)

All offset wells used a PDC bit.

NPT due to low ROP. Inability to reach TD with

casing. H M H

Bit selected which is optimised for highly abrasive environments.

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


L

Hole instability. NPT caused by stuck pipe. Fishing operations. M L M Keep mud parameters as per program (MW, Viscosity). L

Cement losses. NPT. Cost of lost cement. Wellhead / BOP

instability. M H M

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

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.

L


18.3 9- Section (12- Hole)


pact

Pro

babi

lity

Risk


Rem

nan

t Ri

sk

Shale instability.

NPT caused by overpulls and excessive reaming.

Potential pack-off and fishing operations.

M L M

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.

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

Supervisor to provide best practices for hole cleaning guidance.

Ream stand prior to connection ONLY IF HOLE CONDITIONS DICTATE.

L

Cement losses e.g. if penetration

into Meotian is excessive.

Ineffective zonal isolation of overburden formations (above

reservoir). M L M

If losses are encountered during drilling LCM will be added to cement slurry.

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

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

L


18.4 7 Section (8- Hole)

Potential Risk/Hazard Consequence

Impa

ct

Pro

babi

lity

Risk


Rem

nan

t Ri

sk

Borehole stability.

BHA pack-off during drilling or tripping (in Oligocen).

NPT caused by stuck pipe and/or fishing

operations.

BHA lost on hole charge.

Side-track.

M H H

Use Soft Drilling Techniques and drilling best practices.

Keep mud parameters as programmed.

Periodically perform wiper trips only if hole conditions dictate.

Minimse open hole exposure time i.e. case off section as quickly as possible.

L

Mud losses in Oligocene .

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

M L M

290 offset well only encountered losses at 2430mTVD i.e. 135mTVD deeper than 258 Colibasi is planned.

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

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

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.

L

Salt encountered during drilling. Stuck pipe possibility. M L M

290 offset well indicated low chance of encountering salt.

Chemicals onsite to make mud system salt compatible if required.

Suitable cement slurry will have been worked as a contingency.

Salt exit strategy guidelines in appendix.

L

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

Ops geologist to use Gamma Ray for correlation.

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

Can mill out shoe track if required.

Have 4.5 contingency liner if required.

L

Losses during cement job -failure to provide good zonal

isolation over pay-zone.

Loss of production.

Hydrocarbon migration into the B-annulus.

NPT due to repair/water shut-off works.

H M M

Use CemNet in cement slurry and LCM if losses are encountered when drilling.

Reduce cement displacement rate if losses are encountered whilst pumping cement.

258 Colibasi slurry excess calibrated with respect to 259 Colibasi cementing performance.

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.

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.

18.6 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.


19 APPENDIX 19.1 Bit Program


19.2 Directional Program

The directional program may be updated during operations.

Technical Proposal Directional well 258 Colibasi

Baker Hughes 25.06.2012; Ramona Harabagiu, J. Maehs

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.



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 BHAs 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: 2533' 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.

T-Kliwa II Sup

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

#258 C

olibasi(PWP)

20in ConductorTie On

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

Pontian @1119m MD(TVD)

KOP @1425m MDEnd of tangent

2.00/30m

End of buildMeotian @1715m MD(@1719m TVD)

9 5/8in CSG Shoe @1737m MD(1731m TVD)Helvetian @1807m MD(1799m TVD) Meotian

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

Hold 15deg

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

258 Colibasi Drilling Program FINAL

Documents

casing drilling

surface casing

casing program summary

casing accessories

casing objectives

production casing

colibasi drilling program

mud program summary