Carapal Ridge #1 Recompletion# 2 Fluids Recap

BG TRINIDAD CENTRAL BLOCK LIMITED

WELL: CARAPAL RIDGE-1

Revision: 0.0File Name: xxxx

11-January-06

CONTROLLED DOCUMENT

BG Trinidad Central BlockWorkover ProgrammeWell: Carapal Ridge -1 ; Re-completion # 2

APPROVALS

Prepared by:_____________________________________

Senior Fluids Engineer – Deoraj Beephan

____________

Date

Reviewed by: _____________________________________Project Engineer – Jason Ramcharan

_____________________________________

____________Date

____________Date

Approved by:_________________________________Ken Borain – Senior Drilling Superintendant

____________Date

REVISION HISTORY

Rev Section Pages Approved Date

DISTRIBUTION

Name Position Company Copy No.

HSSE POLICY STATEMENT

File: C05.XXXX

Ver: 0.0

Page 2 of 27 Date Printed: xxxx


The protection of people who work for BG T&T and the protection of the environment in which the Company operates are essential aspects of doing business in Trinidad and Tobago. BG T&T will be open and transparent in HSSE practices and management to demonstrate its commitment to continuous improvement in the development of HSSE standards both within the company and Trinidad and Tobago as a whole.

As such BG T&T will:-

Identify and minimize all HSSE risks to people, the environment and assets

Comply with Trinidad & Tobago’s legislation and, where reasonably practicable, improve on the performance standards they specify

Require our contract partners and seek to influence our joint venture partners to demonstrate the same level of commitment to HSSE performance

Report publicly on HSSE performance

TABLE OF CONTENTS

File: C05.XXXX

Ver: 0.0



1 INTRODUCTION............................................................................................................................ 6

1.1 WELL DATA AND STATUS....................................................................................................61.2 WORKOVER OBJECTIVES....................................................................................................61.3 PROGRAMME OUTLINE & TIME ESTIMATE........................................................................71.4 COMPLETION SCHEMATICS................................................................................................9

1.4.1 EXISTING COMPLETION................................................................................................91.4.2 NEW COMPLETION......................................................................................................101.4.3 NEW COMPLETION ASSEMBLY DETAILS..................................................................11

1.5 GENERAL WELL DATA AND RESERVOIR DATA...............................................................121.6 WELL SERVICES RIG NO 4 EQPT INVENTORY................................................................13

2 OPERATIONS.............................................................................................................................. 15

2.1 HEALTH, SAFETY AND ENVIRONMENT............................................................................152.2 GAUGE CUTTER AND BAILER RUN...................................................................................152.3 CONDUCT PLT SURVEY.....................................................................................................162.4 WELL KILL............................................................................................................................ 172.5 PRE-WORKOVER PREPARATION......................................................................................18

2.5.1 PREPARATION OF WORKOVER AND LCM FLUIDS..................................................182.5.2 BOP PREPARATION.....................................................................................................182.5.3 TUBING PREPARATION...............................................................................................192.5.4 COMPLETION EQUIPMENT PREPARATION..............................................................19

2.6 DETAILED WORKOVER PROCEDURE...............................................................................202.6.1 RECOVERY OF EXISTING COMPLETION...................................................................202.6.2 GAUGE RING/JUNK BASKET, USIT & MAGNET RUN................................................212.6.3 RUN COMPLETION......................................................................................................222.6.4 DISPLACING IN DIESEL AND SETTING OF THE PACKER........................................242.6.5 MULTIRATE TESTS......................................................................................................25

3 RISK REGISTER.......................................................................................................................... 26

File: C05.XXXX

Ver: 0.0



NOTE THAT ALL DEPTHS QUOTED IN THIS PROGRAMME ARE THE DEPTHS STATED IN THE ORIGINAL WELL COMPLETION AND SUBSEQUENTLY USED IN THE A) CENTRAL BLOCK BASIS OF DESIGN DOCUMENT AND B) THIS WORKOVER PROGRAMME ; THESE DEPTHS USE A ROTARY ELEVATION OF 17.5FT ABOVE GROUND LEVEL.

THE WELL SERVICES RIG #4 HAS A ROTARY TABLE ELEVATION OF 15ft ABOVE GROUND LEVEL. THE CURRENT TUBING SPOOL IS 1.3FT ABOVE GROUND LEVEL

File: C05.XXXX

Ver: 0.0



1 INTRODUCTION

1.1 WELL DATA AND STATUS

The Carapal Ridge field was discovered by the Carapal Ridge-1 well, the first well to penetrate the Carapal Ridge thrust sheet. The Carapal Ridge-1 exploration well is currently the only well within the field and has been completed as a producer. The well is producing 20mmscfd from a 678ft interval (6568ft - 7246ft) within the Herrera Member sandstones of Mid Miocene age.

The Carapal Ridge-1 well encountered a 937ft continuous column of gas condensate pay within a single thrust sheet of good quality Herrera Member sandstones. Herrera sandstones have an average porosity of 17% and a net-to-gross of 58% within the pay interval. The sands consist predominantly of stacked upwards fining and blocky proximal turbidite channels and lobes. FMI and dipmeter data confirm low angle amalgamated sand bodies.

The Carapal Ridge fluid is a rich retrograde / gas condensate with an initial CGR variable from 50 to 22 bbl/mmscf. Top Herrera sandstone is at a depth of 6568ft. A gas water contact was not encountered in the well. The proven gas column is down to 7505ft and is based on log and test data and coincides with a complex basal imbricate thrust system. Below the basal imbricate thrust system the well penetrated a lower Herrera thrust sheet, referred to as the underthrust play. DST 1 encountered oil in the underthrust play. The well drilled to a total depth of 8829ft within the Herrera Member sandstones. The well is currently on production. Pressure buildup currently exists in the annulus and could be due to a leak from the tubing or packer. A gas leak also exists in the 13.375in and 18.625in casing annulus.

1.2 WORKOVER OBJECTIVES

1. To conduct multirate tests on the oil and gas zones to : a) confirm well/max deliverability b) determine the effect of different drawdown on condensate and gas production c) investigate reservoir boundaries d) determine reservoir pressure for reserve estimation e) determine vertical permeability

2. To obtain PVT samples for reservoir engineering purposes as required after PLT operations.

3. To determine pressure, temperature, gradient, layer crossflow and fluid inflow via PLT run

4. To determine cement quality behind the 9.625in casing and check for casing corrosion (USIT).

5. To improve well integrity. Effects of CO2 corrosion to be minimised by a) replacing the existing EUE connection tubing with premium connection tubing and 450ft 4.5in 13Cr tubing on the top b) specifying chrome material for major downhole components and surface tubing hanger & Christmas tree flow areas

6. To improve well safety by installing a downhole safety valve and automated valve on the Christmas tree.

7. To obtain real time tubing pressure and temperature data by installing a permanent downhole gauge.

File: C05.XXXX

Ver: 0.0



1.3 PROGRAMME OUTLINE & TIME ESTIMATE

OFFLINE ACTIVITY timecumulative

timehrs hrs

1 Rig up slickline on Christmas tree and test 6 62 Perform gauge cutter run 5 113 Perform bailer run 6 17

4Perform PLT survey in both static and flowing conditions 24 41

5 Set TAM packer above XN nipple profile 5 466 Lubricate Hi Vis pill into tubing 6 527 Punch hole in tubing @ 6400 ft 5 578 Circulate 3 609 Set TAM packer at 500ft 4 64

10 Set back pressure valve 3 6711 Secure well 8 75

Cumulative time 75hrs ( 3.125days )

Risked time 17hrs ( 0.7days )

Total time 92hrs ( 3.825days )

File: C05.XXXX

Ver: 0.0



DAILY OPERATIONAL LOG timecumulative

timehrs hrs

1 Nipple up BOP 15 152 Recover back pressure valve. 3 183 Install two way check valve, pressure test BOP and recover valve. 5 234 Recover TAM at 500ft 6 295 Install landing joint into tubing hanger 3 326 Unsting the seal assembly from the packer. 3 357 POOH and layout completion. 24 598 Install wear bushing. 2 619 Run gauge ring / junk basket 5 6610 Run USIT in 9.625in casing followed by magnet run. 10 7611 Run wireline magnet 5 8112 Recover wear bushing. 2 8313 RIH completion string 24 10714 Set the TAM packer above safety valve profile 5 11215 Install back pressure valve in tubing hanger. 4 11616 Nipple down BOP stack. 12 12817 Nipple up Christmas tree 8 13618 Recover backpressure valve. 3 13919 Install two way check valve. 3 14220 Pressure test Christmas tree 3 14521 Recover two way check valve 3 14822 Recover TAM packer from above safety valve 5 15323 Displace tubing to diesel 5 15824 Set TAM packer below MRP packer 5 16325 Set the MRP packer 3 16626 Recover TAM packer 5 17127 Recover TAM packer from old tailpipe 6 17728 Conduct multirate gas tests. 28 20529 Rig down 24 229

Cumulative time 229hrs ( 9.54days )

Risked + contingency time 251hrs ( 10.46days )

Total time 480hrs ( 20days )

File: C05.XXXX

Ver: 0.0



1.4 COMPLETION SCHEMATICS

1.4.1 EXISTING COMPLETION

1.4.2 NEW COMPLETION

File: C05.XXXX

Ver: 0.0


Carapal Ridge-1 new completion

7in landing collar (PBTD) @ 8679ft7in shoe @ 8826ft (7in liner is 29ppf P110 BTC)

TRM-4E Safety Valve @ 450ft

Perforations 6568ft to 6582ft 6590ft to 6610ft 6619ft to 6639ft 6641ft to 6661ft 6668ft to 6688ft 6705ft to 6739ft 6751ft to 6771ft 6778ft to 6810ft

MRP Packer @ 6393ft

Gauge mandrel @ 6384ft

13 3/8in shoe @1001ft

7in liner top @ 6838ft

Old completion (depths shown are tops) :6420ft VTA packer6426.13ft bottom sub6426.84ft millout extension6429.34ft seal bore extension6431.34ft extension6434.34ft crossover6435.34ft tubing joint6467.71ft XN landing nipple (3.72/3.81)6469.21ft reentry guide6470ft BOTTOM

Perforations 8518ft to 8538ft

4.5in tubing 13Cr 12.6ppf N80 Range 2 FOX K to 450ft 4.5in tubing L80 12.6ppf Range 3 KS BEAR remainder

9.625in casing consists of :43.5ppf N80 BTC to 3643ft47ppf N80 BTC to 6266ft 53.5ppf L80 BTC to 6934ft

8.6ppg packer fluid

9.625in shoe @ 6934ft




Perforations 7420ft to 7440ft 7450ft to 7465ft

Bridge plug 8400ft

Bridge plug 7600ft

Bridge plug 7530ft

Bridge plug 7490ft

Bridge plug 7410ft

Bridge plug 7270ftPerforations 7382ft to 7302ft



Perforations 6820ft to 6840ft 6842ft to 6860ft 6864ft to 6884ft

18 5/8in shoe @ 58ft


File: C05.XXXX

Ver: 0.0



1.4.3 NEW COMPLETION ASSEMBLY DETAILS

NOTE THAT ALL DEPTHS QUOTED IN THIS PROGRAMME ARE THE DEPTHS STATED IN THE ORIGINAL WELL COMPLETION AND SUBSEQUENTLY USED IN THE A) CENTRAL BLOCK BASIS OF DESIGN DOCUMENT AND B) THIS WORKOVER PROGRAMME. THESE DEPTHS USE A ROTARY ELEVATION OF 17.5FT ABOVE GROUND LEVEL.

THE WELL SERVICES RIG #4 HAS A ROTARY TABLE ELEVATION OF 15FT ABOVE GROUND LEVEL. THE CURRENT TUBING SPOOL IS 1.3FT ABOVE GROUND LEVEL

File: C05.XXXX

Ver: 0.0



1.5 GENERAL WELL DATA AND RESERVOIR DATA

General

13 3/8in casing shoe 1001ft

9 5/8in casing shoe 6934ft

7in liner shoe 8826ft

Deviation Max 3.5deg @ 9331ft

Current tubing 4 1/2in EUE L80 12.75ppf

Packer fluid 8.5ppg

Reservoir/Well Data

Expected reservoir pressure Calculated pressure at top perforation at 6568ft : 3345psi = 10.58ppg assuming 0.083psi/ft and 2800psi SITP

Expected shut in tubing pressure:

2800psi (data from 8th August 2005 shut in)

Reservoir temperature:0.0182xdepth + 71 or188degF @ 6400ft – approx. VTA packer depth203degF @ 7246ft – bottom perforation

Max. expected gas flow rate: 65MMSCFD

Min. & Max. expected condensate flow rate:

700-2275BPD

Expected CGR: 35bbl/MMSCF

Condensate API 60API Gravity at 60degF (water free)

GWC: No GWC encountered; gas estimated down to 7505ft

Expected Permeability: 25-50Md

Expected dew point pressure: 3500psi

H2S Expected: Nil

CO2 Expected: 0.626mol%

File: C05.XXXX

Ver: 0.0



1.6 WELL SERVICES RIG NO 4 EQPT INVENTORY

ITEMS DESCRIPTION

DRAWWORKS Gardner Denver Model DW-500 single drum Drawworks complete with 2 Catheads, Parmac 22in hydromatic brake pneumatic driller's control console, mechancial rotary driven by counter shaft from drawworks, crown-o-matic. ENGINE Gardner Denver 2 engine compound with Ingersoll-Rand COMPOUND Type 30 Air compressor ENGINES Caterpillar 3406TA diesel engines with air starters, fail safety system. Allison 575 convertors 18in clutches, 650hp TRAILER All mounted on 3 axle trailer, 45ft long MAST Pyramid 108ft x 400 K Cantilevered mast with 6 sheave Crown block, crown safety platform, drill pipe, racking platform, tong counter-weights, 4in rotary hose and standpipe manifold, 2in cementing standpipe and 2in hose. SUBSTRUCTURE 14ft H x 22ft L x 10ft W substructure 500,000#, & BACK-UP RAMP 8,000ft., 5in drillpipe, 18 drillcollars with 30ft L x 8ft W x 6ft H trailer ramp, 3 sets of steel stairways steel V-door ramp, steel drill floor PUMPS Two (2) National 9P100 triplex skidded unitized to Caterpillar D399TA diesel engines and National C-300-100 converters with mission 5 x 6 x 9 40hp centrifugal pump boosters ; 6¼in Liners. PUMP One (1) National JWS 400 Triplex HP pump powered by Cat. 3406B engine and Allison 6061 transmission. DRILL PIPE 9,000ft 5in 19.50# Grade S-135 drillpipe 15 pieces 5in Hevi-wate drillpipe 6 pieces 6¼in spiral drillcollars UTILITY 2 each 3406 Cat. Diesels with 320KW generators Koomey 80 4 Station Accumulator One Ingersoll-Rand Type 30 compressor Gardner Denver ADL screw type 200cfm compressor BOP 1 each Hydrill GK 10in 5000psi annular 1 Shaffer 11in 5000psi double ram type BOP 5,000psi 3 1/16in x 2 1/16in choke manifold with 2 manual adjustable chokes MUD SYSTEM 2 tanks total 600bbls with: 3 - Derrick FloLine cleaners 1 - Derrick 12 Cone 3 in 1 mudcleaner 1 - Drillco degasser 2 - Magnum 5 x 6 x 10 centrifugals 4 - 10 HP agitators Trip and pill sections

File: C05.XXXX

Ver: 0.0



HANDLING TOOLS Varco 6600 kelly spinner Varco SSW 40 pipe spinner BJ Type B Tongs 3½in to 95/8in ROTARY Ideco 17½in x 44in Model SR-175 SWIVEL National N47 TRAVELLING Gardner Denver 200-ton Block BLOCK 4 Sheave 1 1/8in unitized with Joy 150 Hook AIR TUGGER Ingersoll-Rand K5 UL ACCOMMODATION Rig manager's quarters Men's and driller's doghouses Toolpusher's trailer/first aid clinic Water storage - 1,000gal Sewerage disposal tank COOLING SYSTEM 200bbl for brake, hydromatic and pump torque converters FUEL 4,000gal fuel tank with filters and fuel transfer pump PIPE HANDLING Pipe racks, catwalk FORKLIFT 12ton

File: C05.XXXX

Ver: 0.0



2 OPERATIONS

2.1 HEALTH, SAFETY AND ENVIRONMENT

a. All activities will be planned and executed to ensure proper regard is given to the health and safety of all personnel.

b. The BG Well Engineering Management System (WEMS) will be used as the governing document for the well operations.

c. The Central Block Bridging Document will link the safety management systems of BG Trinidad & Tobago with those of the drilling contractor. This document will reference the BG Central Block Emergency Response Procedure.

d. The Central Block Standard Field Operating Guidelines will act as a guide to all matters pertaining to day to day operations.

e. The Central Block Workover Supplementary Information manual will contain all technical data required for the workover/completion.

f. The workover operations will meet all MOE legislative prerequisites.

2.2 GAUGE CUTTER AND BAILER RUN

The objective is to perform a gauge cutter run to prove the well is safe for wire line intervention and to attain a sample of any fill at the bottom of the hole

The original 4.5in tubing tally will be available.

1. Move Tucker wireline mast, 0.108in slick line unit, power pack, pump skid, onsite and position.

2. Conduct a JSA for rigging up, valve opening/closing sequence and slickline operations.

3. Shut in well at choke and upper master valve.

4. Confirm swab valve closed.

5. De-pressurise above swab valve using needle valve. Check for leakage of swab valve.

6. Bleed off above upper master valve via flowline. Check for any leakage. Close wing valve

7. Remove tree cap flange and install BOP crossover flange.

8. Rig up mast and slick line unit.

9. Pick up 3.74in gauge cutter and sufficient stem and install into lubricator

10. Pressure test lubricator against swab valve to 3500psi

11. Open upper master valve slowly - count turns to open

12. Open swab valve

13. RIH to 6300ft slow down as tools pass X nipple at 6386ft

14. Slowly RIH to hang up in XN nipple @ 6467ft.

15. POOH

16. Close swab/master valve valve, de-pressurise lubricator

17. Remove gauge cutter, install 2 1/8in bailer (pump type)

18. Make up lubricator and pressure test using in situ sub

19. Open upper master valve

File: C05.XXXX

Ver: 0.0



20. Open swab valve.

21. RIH to 6300ft slow down as tools pass X nipple at 6386ft

22. Keep on running in hole slowly to 6470ft to exit tubing

23. RIH to TD. Take sample

24. POOH. Use extreme vigilance at 6470ft when re-entering tubing.

25. POOH slowly until 6300ft. POOH into lubricator

26. Close swab/master valve, de-pressurise lubricator

27. Remove bailer,

28. Rig down tools and lubricator

29. Remove BOP crossover flange

2.3 CONDUCT PLT SURVEY

1. Conduct a JSA for rigging up and wireline operations.

2. Rig up Schlumberger adapter flange (3 1/16in 10000lbs) and BOP/lubricator. A double studded adapter will be required to 4 1/16in 5000psi on the tree.

3. Rig up 10,000psi BOP/lubricator. Establish 0.319in monocable through stuffing box and make up Schlumberger production logging tool (spinner, gradiometer, temperature, pressure, collar detector) - PFCS / PGMS / PBMS-B / weight stems as required. Pressure test lubricator against swab valve 3500psi. Open master/swab valve.

4. RIH with logging string. Perform weight checks every 2000ft.

5. Monitor gradient and temperature in real time while RIH. Note any fluid contacts.

6. Stop gauges at mid perforations 6907ft wait for 1 hr to determine gradient

7. Continue RIH. Perform shut-in (static) calibration passes up and down across the perforated intervals 7246 – 6568ft. Note that a bridge plug is present at 7270ft (distance from bottom perforations to plug is 24ft). The number of passes will be advised.

8. Position the PLT tools above the top perforations @ 6568ft. Take station log to check stability of readings.

9. Open well slowly to achieve same flowrate during production approx 20mmscfd. Lift force calculations to be made based on this flowrate.

10. Flow the well until stable flowing conditions are achieved.

11. Conduct spinner passes down and up across the interval 7246-6568ft. The number of passes will be advised.

12. Shut in well.

13. POOH with tools into lubricator. Caution when entering wireline reentry guide at 6470ft.

14. Close swab/master valve, de-pressurise lubricator

15. Rig down tools

File: C05.XXXX

Ver: 0.0



2.4 WELL KILL

1. Conduct a JSA for forward operations

2. Rig up TAM packer using Schlumberger. Pressure test lubricator against swab valve.

3. Open master/swab valve. RIH and set TAM packer at midpoint of tubing joint (6450ft) above the XN nipple.

4. POOH into lubricator. Close swab/master valve valve, de-pressurise lubricator. Remove running tool.

5. Bleed off tubing pressure by 200psi (inflow test plug). Bleed off all pressure in annulus.

Note: If there is no tubing pressure decrease, but there is pressure increase in the annulus, the seal assembly or the VTA packer will be assumed to be leaking. If the tubing pressure drops and annulus pressure increases, the tubing will be assumed to be leaking.

6. Pump/lubricate into tubing 20bbls 10.5ppg Hi Vis brine pill. Allow pill to lubricate to bottom of tubing. A spreadsheet for calculating the pumping and bleeding schedule will be available.

Note: All fluids pumped will be inhibited and contain a fluid marker. NTU < 60

7. Pump/lubricate a further 40bbls normal 10.5ppg brine. Bleed off any remaining tubing pressure. Fill up remaining tubing (approx. 35bbls) with 10.5ppg brine.

Note: When the tubing is punched, a U tube pressure into annulus of 660psi will be seen (8.5ppg packer fluid in annulus). Observe for any losses on annulus side. A 10.7ppg brine will give a 240psi overbalance at the VTA packer (assuming leak at seal assembly or packer).

8. Rig up Schlumberger flange, BOP/lubricator with 1 11/16in tubing punch/magnetic positioning tool/CCL. Pressure test lubricator against swab valve.

Note: Tubing punch : 4ft at 4 shots/ft (max 4 shots/ft) at 0.32in opening per shot = approx. 16x10/32nozzles

9. Open master/swab valve. RIH to 6370ft (above the X nipple) and punch tubing.

10. POOH into lubricator. Close swab/upper master valve, de-pressurise lubricator. Remove running tool

11. Open upper master valve. Circulate tubing contents the long way up annulus with 10.5ppg brine displacing out the 8.6ppg packer fluid. (335bbls in annulus, 95bbls in tubing).

Note: Spot a 30bbls Hi Vis pill in the annulus at the end (to counter any potential losses via the seal assembly or packer)

12. Perform flow check.

13. Rig up TAM packer into lubricator. Pressure test lubricator against swab valve. Open swab valve

14. RIH and set at 500ft (away from couplings)

15. POOH into lubricator. Pressure test TAM packer to 1000psi – watch annulus pressure. Close swab/master valve. Remove tools and rig down.

16. Open swab valve/master valve. Rig up IAL back pressure valve and install same on tubing hanger with dry rod.

17. Secure well for rig down.

File: C05.XXXX

Ver: 0.0



2.5 PRE-WORKOVER PREPARATION

2.5.1 PREPARATION OF WORKOVER AND LCM FLUIDS

1. The mud tanks, surface lines and equipment should be cleaned thoroughly. This would include the internal cavities in the BOP, kill / choke lines, solids control system, mud tanks, cement unit and lines, filtration unit and lines. All valves should be worked to clean internal cavities, pressure tested and repaired. The tanks tops, gratings, agitator housings …etc. will be clean and free off rust scale, paint flakes and residual mud debris build-up. The gates and dump valves will be sealed with DENSO tape or silicon - do not use bentonite. Test all valves for leaks.

2. A high-pressure water / detergent gun will be required on all surfaces. A detergent solution will be flushed through all mud tanks, surface lines and solids control equipment.

3. All personnel will be instructed that a high standard of cleanliness is expected and will be maintained throughout operations. All debris such as, rope, rubber, sack fibre, paint chips, rust scale must be kept out of the system.

4. The shale shakers should be fitted with the finest mesh screens available. All returns will be passed over the shale shaker screens before entering the surface system. The shakers should never be bypassed.

5. All the materials / equipment for operations and emergency contingencies should be in place prior to starting operations. Check on tank capacity available for the various fluid volumes required and storage of returned packer fluid and dirty brine. Additional storage capacity – 3x700bbl tanks will be available.

6. Brine details to be advised (brine formulation, Hi Vis pills and LCM pills. A fluid marker will incorporated into all liquids pumped into the well. Brine left in hole will be inhibited.

2.5.2 BOP PREPARATION

The BOPs will have been pressure tested 500/5,000psi prior to rig up on location. Internal of BOPs will be clean prior to installation.

A body test will be required after initial installation. Thereafter, BOPs will be tested to BG standards with the pressures specified in the table below.

Item Low High11in 5000psi annular 500 3,50011in 5000psi 4.5in pipe rams 500 3,50011in 5000psi blind shear ram 500 3,500Valves 500 3,500Choke and Kill Lines 500 3,500Surface Equipment (+safety valve, IBOP) 500 3,500

File: C05.XXXX

Ver: 0.0



2.5.3 TUBING PREPARATION

1. Lay out tubing in rows with wood battens between each row. Allow sufficient room to roll tubing and strap.

2. Clean and inspect tubing joints. Strap the tubing and mark up with number and dimension in white paint. A laser measuring device will be used for measuring all lengths

3. Drift 4 1/2in tubing with a 42in long API nylon drift for 12.6ppf tubing.

4. Clean all connections with nylon brush.

5. Inspect the threads and seal area for damage.

6. Inspect and list all crossovers required for all runs in the hole. Drift all crossovers.

7. Check all handling tools

8. Ensure torque/turn and handling equipment is placed correctly on the drill floor and has been calibrated and dressed for the tubulars to be run.

9. The tubing spider to be used will be capable of accommodating the control line and gauge cable.

10. Note special handling procedures for 4 1/2in chrome tubing.

2.5.4 COMPLETION EQUIPMENT PREPARATION

1. Completion eqpt will be pre-assembled with pup joints and pressure tested. Drift nipples and assemblies with lock mandrels where applicable. Check TAM packer running tools will pass through all items.

2. Check dimensions of all completion eqpt.

3. Check part and serial numbers of completion eqpt

4. Confirm shear pin qty on packer

5. Check all equipment for damage

6. Measure completion string and mark lengths.

7. Measure completion sub-assemblies.

8. Function gas/test safety valve.

9. Christmas tree will have been pressure tested to 500/5000psi

10. Check tubing hanger seals and dimensions.

11. Stackup tubing hanger with IAL tubing spool if possible to ascertain proper fit

File: C05.XXXX

Ver: 0.0



2.6 DETAILED WORKOVER PROCEDURE

NOTE THAT ALL DEPTHS QUOTED IN THIS PROGRAMME ARE THE DEPTHS STATED IN THE ORIGINAL WELL COMPLETION AND SUBSEQUENTLY USED IN THE A) CENTRAL BLOCK BASIS OF DESIGN DOCUMENT AND B) THIS WORKOVER PROGRAMME ; THESE DEPTHS USE A ROTARY ELEVATION OF 17.5FT ABOVE GROUND LEVEL.

THE WELL SERVICES RIG #4 HAS A ROTARY TABLE ELEVATION OF 15ft ABOVE GROUND LEVEL. THE CURRENT TUBING SPOOL IS 1.3FT ABOVE GROUND LEVEL

2.6.1 RECOVERY OF EXISTING COMPLETION

1. Carry out JSA with particular reference to handling potentially corroded tubing and dropped objects into hole

2. Nipple up 11in 5000psi BOP.

3. Recover back pressure plug with dry rod. Check for pressure before recovery.

4. Install two way check valve and pressure test BOP body (one test) to 500/3500psi. Recover two way check valve.

5. Make up landing joint to tubing hanger (4.5in EUE profile).

6. Makeup ball valve, pump in sub, ball valve, BOP/slickline lubricator and packer retrieval tool. Pressure test against lower ball valve to 2000psi.

7. Close annular. RIH and recover TAM packer at 500ft.

8. Circulate bottoms up. Spot balanced 20bbl 10.5ppg brine Hi Vis in the tubing/annulus

Note: All fluids pumped into hole will be inhibited and will contain a fluid marker.

9. Undo tubing hanger lock pins.

10. Pick up tubing hanger and pull tubing. String weight should be 70,000lbs buoyed weight with 10.5ppg brine.

Note: The seal assembly is approximately 16 ft long.

11. POOH and layout tubing. Hole to be filled as per standard procedures.

Note: Assuming that the tensile strength of the tubing is de-rated by 1.6 of the API value for new pipe ie 180,000lbs, max O/P to be 110,000lbs over buoyed weight.

Note: Tubing pulled to be measured to give accurate spaceout for run with new completion

12. Blind rams to be closed when out of hole. Hole cover to be put in.

New tubing detailsTensile

(lbs)

Burst

(psi)

Collapse

(psi)Connection

OD (in)ID (in)

Drift ID (in)

4.5in L80 12.75ppf EUE

(external upset tubing)288,000 8430 7500 5.563 3.958 3.833

File: C05.XXXX

Ver: 0.0



2.6.2 GAUGE RING/JUNK BASKET, USIT & MAGNET RUN

1. Carry out JSA with particular reference to dropped objects into hole

2. Run and set wear bushing.

3. Rig up Schlumberger. Run gauge ring / basket. POOH. Rig down tools

4. Run up USIT/CCL/GR tool.

5. RIH and log 9.625in casing in cement evaluation mode (to top of cement only) and corrosion mode – entire length of casing. POOH. Rig down tools.

6. Rig up and run wireline magnet with Schlumberger

7. POOH and lay down tools and rig down.

8. Hole cover to be put in when out of hole/rigged down. Close blind rams.

Note: Depending on the condition of the tubing pulled, a scraper run maybe considered

Note: A pressure test to be carried via blind rams. Pressure test value to be dependent on the USIT run results.

File: C05.XXXX

Ver: 0.0



2.6.3 RUN COMPLETION

Note:

a. All tool joints should be wiped clean and examined before stabbing. b. Apply a thin film of API tubing dope to the pin and box seal area. c. Keep dope bucket covered to avoid debris or water contamination. d. A stabbing guide is to be used at all times.e. Tubing makeup torque to be advisedf. Limit make-up speed to 2-3 rpm. when engaging seal faces.g. A full bore safety stab in valve (and tubing crossover) plus the internal IBOP (and tubing

crossover) will be available on the rig floor.h. Monitor fluid level with the trip tank when running in.i. Fill every jointj. All pressure tests to be on a chart. Volumes pumped and returned to be noted where

applicable. During all tubing pressure tests, the tubing spool outlet (annulus) should be open and monitored

k. Keep record of all protectors run. Put one cross coupling protector per joint to surfacel. Check tubing hanger will pass through the bell nipple/BOPm. Set packer away from casing couplings n. Put safety valve protector at top and bottom of safety valve o. Ensure chrome and carbon steel tubing (plus pup jts) at rig site are well distingushed p. Review chrome tubing handling and storage proceduresq. All efforts to be made to minimize objects being dropped into hole around the slip area. r. Pressure testing of tubing will not be performed. This qualification will assume that each

connection meets the required makeup pattern from the torque turn system. s. Efforts will be made to move the rig off after the BOP has been rigged down and

the Christmas tree has been rigged up and secured.

Tubing detailsTensile

(lbs)

Burst

(psi)

Collapse

(psi)Connection

OD (in)ID (in)

Drift ID (in)

4.5in L80 12.6ppf KS BEAR

makeup torque (ft-lb) :

min 4050; opt 4500; max 4950

(non upset tubing)

288,000 8430 7500 4.9 3.958 3.833

4.5in N8013Cr 12.6ppf K FOX

makeup torque (ft-lb) :

min 3940; opt 4240; max 4530

(non upset tubing)

288,000 8430 7500 4.9 3.958 3.833

File: C05.XXXX

Ver: 0.0



1. Recover wear bushing

2. Carry out JSA for running completion with particular reference to high pressure control line and minimization of dropped objects into hole and well control

3. Pick up and make up tubing, pup joints, sub assemblies as shown below :

assembly #1 4.5in tubing with mule shoe end 5ft of tubing to be stung in when tubing hanger is landed

assembly #2 4.5in crossover L80 12.6ppf K FOX box up x KS BEAR pin down Set packer away from couplings 9.625in x 4.5in MRP packer K FOX (box up x pin down)4.5in crossover L80 12.6ppf K FOX pin down x KS BEAR box up

assembly #34.5in pup joint L80 12.6ppf K FOX box up x KS BEAR pin down

Set packer away from couplings Put one cross coupling protectorper joint to surface

4.5in gauge mandrel with DPG-PS gauge K FOX (pinxpin)4.5in crossover L80 12.6ppf K FOX pin down x KS BEAR box up

Run full KS BEAR tubing jts as required

assembly #4Crossover 4.5in N80 12.6ppf KS BEAR pin down x VAM ACE box up

Set safety valve at 450ftPut valve protector top & bottomof safety valve

4.5in TRM-4E safety valve with DB 3.812in profile Vam Ace (pin down x box up)Crossover 4.5in N80 13 Cr 12.6ppf VAM ACE pin down x K FOX box up

4. After picking up the safety valve, makeup control line, function test safety valve and pressure test control line to 6,000psi. Control line would have been purged of air etc. Note and record safety valve opening and closing pressures. Ensure safety valve control line pressure is maintained at 6,000psi at all times whilst RIH and monitored continually.

5. Run chrome tubing as per special handling procedures.

6. Prior to picking up tubing hanger assembly, pick up landing joint with circulating head and circulating line made up.

7. RIH slowly while circulating until mule shoe is 2-3ft inside the VTA packer or when pressure increases. Note : Tubing stretch is 22in

8. Mark pipe at rotary table.

9. Pull back landing joint and calculate space out required to put the mule shoe 5ft inside the existing completion. Note: There is 14ft space below VTA packer available for sting in.

10. Install correct space out pups and install tubing hanger assembly/landing joint and circulating head/line.

11. Terminate control line and gauge cable at hanger. Make up connections to top and bottom of hanger. Function test safety valve and pressure test control line to 6,000psi. Test gauge and ensure communicating.

File: C05.XXXX

Ver: 0.0



12. Open tubing spool outlet. RIH slowly and sting into the VTA packer. Lock in tubing hanger and energise seals.

13. Perform low pressure test 500psi on annulus / bottom tubing hanger.

14. Rig up Tucker slickline BOP/lubricator.

15. Rig up TAM packer

16. RIH and set TAM packer above safety valve. POOH

17. Rig down surface gear. Terminate control lines and gauge cable.

18. Install backpressure valve into tubing hanger

19. Carry out JSA for nippling down BOP and rigging up Christmas tree.

20. Nipple down BOP.

2.6.4 DISPLACING IN DIESEL AND SETTING OF THE PACKER

1. Nipple up tubing hanger adapter and Christmas tree. Pressure test tubing hanger seals to 5000psi.

2. Reestablish control lines and gauge cable into tubing head adapter, pressure test 6,000psi and function same.

3. Recover back pressure valve

4. Set two way check valve

5. Pressure test Christmas tree body against the check valve to 5,000psi.

6. Remove two way check valve

7. Install lubricator on top of tree cap. Install the following on top of the extension joint : lower ball valve, side entry circ head, upper ball valve, Tucker BOP/slickline lubricator. Pressure test assembly against swab valve 3500psi.

8. Rig up and RIH to pull the TAM packer. POOH

9. Open safety valve

10. With upper ball valve closed, circulate in 6.8ppg diesel into tubing to a depth of 5500ft (84bbls).

Note: At the end of the diesel displacement, the U tube effect into the tubing will be 1120psi.

When the MRP packer is set, with 6.8ppg diesel to 5500ft plus 950ft of 10.7ppg brine down to +/-6450ft (TAM packer depth in tailpipe) and the TAM packer is pulled, the underbalance is 860psi

All pressure testing at surface to be done with water.

Ensure that no untreated water gets into the system

11. RIH and set TAM packer below the MRP packer

12. Increase control line pressure to 6,000psi. Pressure up 4000psi tubing against the TAM packer to set the MRP packer.

13. Pressure test annulus/packer (to be advised based on USIT run).

File: C05.XXXX

Ver: 0.0



Note: The safety valve will be inflow tested from below after the completion of the gas multirate flow

14. Recover TAM packer

2.6.5 MULTIRATE TESTS

1. Rig up and RIH to pull the TAM packer in the existing tailpipe. Note that when the plug is relieved of pressure it will see the underbalance pressure of 860psi. POOH

2. Rig up flowlines to Christmas tree

3. Bean up well progressively until the tubing contents have been unloaded and well is flowing clean.

4. Divert flow through test separator.

5. Conduct 4 point multirate test.

6. At the end of the test, close downhole safety valve. Bleed off tubing pressure to 500psi and perform inflow test.

7. Open safety valve.

8. Perform shut in sequence and shut in well. Close safety valve.

9. Rig down and demobilize rig

10. Handover well to Production.

File: C05.XXXX

Ver: 0.0



3 RISK REGISTER

Item Area Risk Description

Current Risk Assessment

Plans to mitigate Inherent Manageability

Imp Prob Total

Good (1-2)

Satisfactory (3-4)

Poor (6-9)

1Stuck gauge ring.

Stuck gauge ring due to debris in tbg 1 1 1 1Smaller than tubing ID; tubing should be clean from continuous flow.

2

Bailer encountering difficulty re-entering tubing.

Bailer having difficulty in re-entering tubing. 1 2 2 1Run smallest bailer to do the job.Wireline re-entry guide at end of tubing.

3Parted Slickline

Slickline may part while working a stuck tool. 1 2 2 1Run 0.108in slickline. QC slickline before job. If stuck use 0.125in wire

4Stuck PLT tools

Stuck PLT in tubing 1 1 1 1 All tools 1 11/16in. Gauge ring run made prior to PLT.

5Blow tools up due to flow

Excessive flow could cause tools to enter the tubing on flowing passes

1 1 1 1 Use correct weight to flow ratio.

6Tools hanging up outside tubing.

Unable to pull tools back into tubing 1 1 1 1Wireline reentry guide(ID : 3.920”) below tubing; spinner cage is compressible; use max weak point rating

7Unable to set XN plug in profile

Unable to set XN plug in profile 1 1 1 1 Set inflatable bridge plug instead as first option.

8 Gas migrationDue to buoyancy, residual gas in the tubing could percolate to surface.

1 1 1 1 Set second inflatable bridge plug at 500ft

9Corroded Threads in tubing hanger

Unable to set back pressure valve(BPV) in tubing hanger

1 3 3 1Already have two other bridge plugs plus kill weight brine in place - 3 barriers

File: C05.XXXX

Ver: 0.0



10Stuck tubing hanger

Difficulty in unseating or stuck tubing hanger 1 2 2 1 Have surface jar available

11Pressure on 41/2”x9 5/8” annulus

Potential integrity concerns with casingIssue of tubing leak and/or packer leak

1 2 2 2

Well will have control fluid in annulus. Problem will be corrected by new completion. However if leak is from the 9 5/8” casing, this will remain an issue. Run corrosion log to determine casing condition

12Recovery of Inflatable at 500 ft.

Difficulty in recovering inflatable plug at 500ft 1 1 1 1 Pull tubing with inflatable packer in place.

13Corroded Threads in tubing hanger

Unable to makeup pup jt to tubing hanger for recovery

1 3 3 1 Have spear available and or taper tap.

14Corroded tubing

Potential for corroded tubing due to gas co2 content.

1 3 3 1Have range of fishing tools available eg overshot, chemical cutter, IB’s

15

Unable to unseat seal assembly from VTA packer

Unable to pull production string 1 2 2 1Have range of fishing tools available eg overshot, chemical cutter, IB’s

16Debris on top of the VTA packer

Potential for debris falling on top of VTA packer from the scraper run.

1 2 2 2Hi Vis pill in tubing will sit above plug and packer; close blind rams and put on hole cover whenever out of the hole.

17

Potential damage to control & gauge cables

Control line and gauge cable can be damaged while running in the hole.

1 1 1 1 Special services will be used for running cables with tubing.

File: C05.XXXX

Ver: 0.0


Carapal Ridge #1 Recompletion# 2 Fluids Recap

Documents

cross coupling

central block

upper master

herrera member

close swabmaster

lower ball

ks bear box

current tubing