Drilling Program Main File - Web viewTie back & DST Program. Bennevis rig. January 23rd 2007....

Well Muzhil #1 – Tie back & DST program

Muzhil – 1Tie back & DST Program

Bennevis rigJanuary 23rd 2007

Operation Department

Document Distribution List

January 23rd 2007

Tie back & DST ProgramWell Muzhil – 1

Position Name Signature

Prepared by Sr. Reservoir Engineer

Prepared by Drilling & W/over Superintendent

Approved by Drilling Manager

Company Distribution No. Of Copies

1


Office Original to Cairo office Master

Drilling Superintendent 1

Drilling Manager 1

Chief Operations Officer 1

Chief Technical Officer 1

Geologist Office 1

Reservoir Office 1

Contractors Pyramid Drilling S.A 1

Halliburton 1

Schlumberger 1

Power Well Services 1Total 10

Table of content

No. Content Page No.

1 List of main Contractors 4

2 General Well Information 5

3 Well Status 6

4 Tie back objectives and highlights 7

5 Safety and Environment Issues 8

2


6 Rig Move Positioning And Pre-Load 8

7 Tie Back Procedure 9

8 Drill Stem Test Program 13

9 Testing Matulla formation 21

10 Kill well and retrieve test string 26

11 Testing "Nukhul" Formation 28

12 Halliburton test string schematic 29

1 List of main Contractors Type of Service Contractor

NameName of Key Person Mob. No./fax No.

Drilling Unit (Bennevis) Pyramid Nigel Marlow

ROV, Weather Forecast Service Fugro Ahmad Khosht

Sea Bottom Survey & Diving Service

CDC Saed Amer

Cementing Dowell Khaled Faroun

Drilling Fluids Baroid Ahmad Ezz

Mud Line Suspension System Cameron Mohamed Abdallah

3


XLF system Oil Tech Moumtaz Fawaz

Casing Services Weatherford Ibrahim Bassiony

Pre-Heating Braden Head & Casing Cold Cutter

Hot-Head Husseiny Ibrahim

Stabilizer Services Halliburton Diab Saad

Cased Hole Logging Schlumberger Sherif Bayoumi

Completion Equipment & Completion Engineer

Halliburton Ashraf Ashry

TCP Gun & Perforating Service Halliburton Khaled Shell

Coiled Tubing, Nitrogen & Stimulation Service

Halliburton Moustafa Amin

DST & Well flow Surface Equipment

Power Well Services

Mohamed Gamal

Fishing, Re-Entry, Rental Equipment & Machine Shop

Baker Oil ToolNapesco

Omar MajedAhmad Shalash

Safety & H2S Service Total Safety Mohamed Ehab

Mud Logging Services PetroServices Mohamed Diab

2 General Well Information

Well Name Muzhil - 1Country / Concession Egypt / South Abu Zenima concession Gulf of Suez areaDrilling Unit Bennevis

Well Head coordinates Y = 689,978.00 m (N), X = 823,071.00 m (E)Latitude = 28 54 01.119 N, Long = 33 07 59.054 E

Water Depth 109'

Well profile : Directional

Well classification: exploratory – to be Tie back and DST.

Total depth: 12,522' RKB. Plugged back from TD to 12397m

Authorized Cost : $5,500,000

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Authorized Days : 25 Days

Well History

The SAZ175-1 (Muzhil-1) Prospect lies in South Abu Zenima concession Gulf of Suez area, north east of the Main October Nubia field. SAZ175-1 (Muzhil-1) well was drilled by GUPCO as an exploratory well to Nubia sand with total depth of 12522 ft utilized Trance Ocean Comet jack-up rig. The well was spud on 28th of October 2004 and completed by cemented 7" liner on 14th of January 2005. No test has been carried out for both "Matulla" and "Nukhil" formations and the well left in temporary abandon situation.

Well status configuration:

Casing size Grade Weight Conn From to

30” x 1” X-52 310# XLF 178 41413 3/8" K-55 68.0 # BTC 275 39829 5/8" DST-110HC 53.5 # LT&C 275.3 89057” P110 29.0 # N.VAM 4400 12517

T & A status:

At from to remarksCement plug #1 600 10009”5/8 Fast drill plug 1000 Bridge plug "Halliburton"Cement plug #2 4400 4125 4400Cement plug #3 12517 12517 12397 BPTD

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3 Well Status MUZHIL

WELL BORE SKITCHRIG: COMET

RKB-MSL 90'89 ft Landing Ring @ 277 ftW.D 109 ft 13 3/8" MLH @ 275 ftRKB-ML 198 ft 9-5/8" MLH @ 275.3 ft

Actual measurments for 30"Conductor made July 2006

9-5/8" FAST DRILL PLUG @ ±1000' MD

13- 3/8” CSG @ 3982’ MD

30” COND @ 414'

30” Trash Cap @ 178' RT (20' above ML) not existed. Removed during last pipe line survey J uly 2006.

9- 5/8” CSG @ 8905’ MD

FTD @ 12522’ MD

275 ft 16 PPG "G" CMT 7" TOSL @ 4400’ MD

7" Lnr 29 ppf, DST 110HC N. Vam7" Liner CMT job.16.0 ppg CMT " G+35% S.F"7" Scab liner CMT job.16.0 ppg CMT " G+35% S.F"

8.6

PPG

Sea

Wat

er

9- 5/8" DST 110HC 53.5 PPF LT&C 9- 5/8" Casing CMT job.first stage16 ppg CMT " G+35% S.F"Second stage14.5 ppg lead CMT " G Neat"16.0 ppg tail CMT " G Neat"

13- 3/8" K55 68 PPF BUTT13- 3/8" CMT J ob.12.0 ppg lead CMT " G Neat"16.0 ppg tail CMT " G Neat"

400 ' 16 PPG " G"

CMT

Ihib

ited

Sea

Wat

er 8

.6 P

PG

30" COND. XL 310 PPF

13- 3/8" Corrosion Cap

30” Trash Cap @ 178' RT

Ihib

ited

Sea

Wat

er

8.

6 PP

G

7" Liner @ 12517’ MD

7" TOL @ 8505’ MD

9- 5/8" DVT @ 7136’ MD

Ihib

ited

Sea

Wat

er 8

.6 P

PG

120 ft 16 PPG "G"

CMT

7" L.C @ 12397’ MD

6


4 Tie back objectives and highlights

The objective of the tie back operations is to prepare the well for cased hole test against Matulla and Nukhul Reservoir.

The program foresees to run and tie back the 30” CP, 13”3/8 casing and 9 5/8" casing as follows:

1. Tie back 30” conductor by using 36” x 30” extension on 30” conductor (30" Trash cap removed in the last pipe line survey at July 2006, stored at Ras Badran Yard).

2. Retrieve 13-3/8” corrosion cap and tie-back 13-3/8” casing to surface.

3. Install 13 5/8" x 13 3/8" 5M Braden head with base plate.

4. Tie-back 9-5/8” casing to surface.

5. Install 13 5/8" x 11" 5M tubing head spool.

6. N/U BOP’s. Drill out cement and 9-5/8” bridge plug. Cleanout well bore to perform DST program for the well.

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5 Safety and Environment Issues Hold safety meetings prior to commencing any operation, ensuring that all involved

understand the forth-coming operations & risks. No oil spill or toxic material to sea. No well control incidents. Lifting plan to be issued and implemented for all lifting operations. While Tie back operation, hold abandon ship, fire drills, BOPE and accumulator drills &

H2S tests weekly. Report all tests on IADC reports. All people on rig should be trained for stop cards including involved service companies If have any emergency proceed w/ PETZED Mediaevac and Emergency plan. Hot challenge permit should issue before job. In case of trip for any reason fill trip tank with mud to be sure that the well is not flowing.

6 Rig Move Positioning And Pre-Load Bennevis Jack up rig will move from Gamma platform to Muzhil -1 location (52 miles) with assist of Gulfo de siam, M/V 104 & M/V 13 tug boats, the final rig positioning services will be provided by Rig Mover, PETZED Marine superintendent, Fugro and Tow Master.Note:-

Tug boats will move the rig to Abu Zenima Bay and released same if bad weather encountered.

Make sure the axis chart & sea bottom survey for well location & Abu zenima bay location had been done by FUGRO & CDC as per the pre-move meeting.

Ensure the marker boy is installed. Move the rig into position with the agreed rig heading (+/-250 deg.) during pre-

move meeting, Pin down legs jacks up to 5 ft and conduct pre-load test according to rig specifications, dump water and jack up to working safe level.

The following materials and equipment should be on the first supply boat: All bulk materials (Cement, Barite, and bentonite). Mud Engineer. 6 1/4” drill collars, 5” DP. 13 5/8”-5M Gupco Riser, 13 5/8”-5M x 11”-5M psi Pyramid DSA. 30” XLF system equipment. 6 jts 30” conductor pipe. 36" x 30" over shot. 20 jts 13 3/8" casing. 20 jts of 9 5/8" casing. Tie back equipment for 13 3/8" & 9 5/8" equipment 26" Stabilizer, 7 5/8" Reg. Connection. X/Over 7 5/8" Reg. box x 4 1/2" IF pin. X/Over 7 5/8" Reg. pin x 4 1/2" IF box. safety man.

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7 Tie Back Procedure

1. Move rig to SAZ175-1 Location, Measure and report the following:

a) Water Depth = 109’.b) RKB-MSL.c) Rig Heading.d) RKB – ML.e) Leg Penetration.

Note: Depths Should Be Related To:-

ORKB During The Tieback And Cleanout Operations And THF during Completion Operations. The well was Drilled by rig Bennevis (ORKB-MSL= 89 ft).

2. Hold pre-job safety meeting. R/U XLF system to run 30”, 310 PPF XLF conductor.

3. PU & MU 4 joints of 30”- 310 PPF, XLF conductor pipe on top of 36”x30” overshot extension and RIH to ± 170’ ORKB (±8’ above 30” stump ).

Note: Run ROV to monitor running of conductor and stab in 36" overshot extension into the

30" conductor stump.

4. Continue RIH to swallow the 30” stub @ 178’ ORKB with diver's assistance to pull and guide the 36” x 30” overshot the cut off 30” conductor, MU last joint # 5 of 30” conductor and land the extension on 30” conductor stub. Bottom of 36” extension will be @ 200’.

5. R/U Hot-Head Cold cutter, Cut off 30” C.P at the proposed production deck above Texas deck level.

6. P/U 5" cement diverter and RIH to 170' ORKB, start jetting the 30" conductor stump at 1000 GPM down to the MLH depth at 277' ORKB.

7. Sweep hole with 50 bbl's Hi-Vis pill and circulate hole clean, report any debris over shakers, POOH L/D CMT diverter.

8. RIH with Cameron 13-3/8” corrosion cap retrieving tool, 1x5" D/P X-over, 26" STRG STAB, X-over on 5” drill pipe. Check rotary table alignment, Engage into 13 3/8" corrosion cap (J slot) @ 275’ and retrieve it by rotating 5-6 turns to the right. POOH & L/D corrosion cap.

Note:If the corrosion cap threads in good condition and there is no damage, proceed to step # 10, otherwise go to step # 9.

9. MU 13-3/8” Cameron tapping tool on 5” drill pipe and RIH. Carefully tag top of 13-3/8” MLH @ 275’ with rotation & circulation. Pump 50 BBLs high visc pill with 1000 GPM Cleanout the top of the 13-3/8” mud line hanger. Lower tool into MLH and MU same by 5-6 LHT to clean the MLH threads with no torque, POOH.

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Note: 9-5/8” MLH top @ 275.3 (1’ extending above 13-3/8” MLH). Check the M/U of tapping tool into a MLH prior sending to rig. Cameron representative prepares contingency plan if we can’t release tapping tool.

10. R/U 13-3/8” Weatherford casing running equipment.

11. M/U CIW 13-3/8” hanger running tool (or tie back tool if available) and RIH on 13-3/8” butt, 68 ppf casing. Strap weld every collar & 20% Over torque 13-3/8” Casing while RIH to prevent back out when the running tool is torqued up. RIH to 13-3/8” MLH at 275’ ORKB.

Notes:- A 13 3/8” pup joint to be used to space out minimum distance above rotary table. Ensure to weld 4 straps for all collars of 13-3/8” casing joints (Have a back up 13-

3/8” casing string in case unable to screw tieback tool and had to pull casing). Prior to leaving the "Ras Badran" base, the running tool should be installed and

torqued to 13-3/8” casing joint. Using 13-3/8”x26” positive centralizer installed just below the collar of 1ST 13-3/8”

joint above running tool with 2 stop collar around it. MU 13-3/8” Dowell circulating swage to one joint at the V-Door prior to RIH (off

line operation).

12. At top of MLH mark casing at rotary table and spot 50 bbls hi-vis-pill, rotate approximately 5 turns to the left and torque tieback tool to maximum of 3000 Ft-Lb, observe the slack down stroke while Make Up.

13. R/U Dowell cement unit and lines, connect the line to the circulating swage, test same to 2000 psi. Pressures test the string to 1000 psi for 15 minutes. If pressure test fails contact Cairo team for further instructions. If successful then proceed to step #14 then step # 15.

14. R/U 13 3/8" Hot-Head cold cutter, Cut off the 13-3/8” casing be careful to avoid any drop objects inside 13-3/8” casing. Install 13-3/8” x 30” base plate (without gussets) as per FMC Engineer. Base plate to have two 4” holes cut out of body so that cement string can be run.

15. Weld 13-5/8” x 13 3/8" x 5000 psi FMC Braden head using a hot head. Test the Braden head to 1000 psi (hot head Eng) as per FMC Engineer. Install gussets on Braden head.

16. M/U 9-5/8” Cameron tapping tool on 5” drill pipe and RIH. Carefully tag top of 9-5/8” MLH @ 275.3’ with rotation & circulation. Pump 50 BBL's high viscous pill with 800 GPM Cleanout the top of the 9-5/8” mud line hanger. Lower tool into MLH and MU same by 5-6 LHT to clean the MLH threads. POOH & L/D tapping tool.

Note:-

A 9-5/8” pup joint to be used to space out minimum distance above rotary table. Check in "Ras Badran" base the MU of tapping tool into a MLH prior sending to rig.

17. M/U the 9-5/8” hanger running tool (or tie back if available) and Run on 9-5/8”, 47 ppf, BTC casing. Strap weld every collar & 20% Over torque 13-3/8” Casing while RIH to prevent back out when the running tool is torqued up while RIH. RIH to MLH at 275.3' ORKB.

Notes:- (Have a back up 9-5/8” casing string in case unable to screw tieback tool and had to pull

casing).

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The running tool should be installed and torqued to 9-5/8” casing joint. MU 9-5/8” Dowell Circulating swage to one joint at the V-Door prior to RIH (off line

operation).

18. Displace the hole to inhibited sea water.

19. At top of MLH mark casing at rotary table, engage the running tool and rotate approximately 5 turns to the left and torque to a maximum of 3000 ft-lb. Observe the slack down stroke while M/U.

20. R/U Dowell cement unit and lines, connect the line to the circulating swage, test line to the to 3500 psi, pressure test 9-5/8” casing to 3000 psi.

Notes:- IF could not achieve the required M/U torque and the proper number of LHT and not holding

pressure. POOH. As contingency plan be prepared to send a 9-5/8” right hand release spear to the rig. If successful pressure test and proceed to step # 21. If pressure test fails contact Cairo team, if 5-6 rounds of left hand turn is not obtained prior to

reaching max torque, release by RHT and POOH with string. Re-run tapping tool and attempt to clean MLH area again. Repeat step 16 to 20.

21. Pull 20k tension on 9-5/8” and set FMC “Casing” slips and seal assembly as per FMC Engineer.

22. R/U 9 5/8" Hot-Head cold cutter, Cut off the 9-5/8” casing above the Braden head flange (4-1/2”).

23. Installed 13-5/8” x 5000 x 11” 5000 psi Vetco Grey tubing head spool with Energize and test as per Vetco Grey Engineer. Report ORKB-THF on IADC and daily morning drilling report.

24. Installed 13 5/8”-5M x 11”-5M psi Pyramid DSA & 13 5/8" x 5000 PSI riser.

25. N/U 13 /8" x 10,000 psi BOP’s with 5” rams on top and 3-1/2” rams in the middle.

Function testing and flow testing 13 5/8" BOP’s as follows: Close and open all preventer. Pump through thé kill line, flow line, mud gas separator and choke lines with water. Fill the stack with water. Installed the wear bushing inside the tubing spool, Land test plug and test joint in the

tubing spool and open wing valve, press. Test Hydrill, all pipe rams, choke line, kill line, and manifold to 300 – 3000 psi for 5 mins each.

POOH, L/D test plug and test assembly.

26. P/U 8-1/2” Reed bit with open jets on a slick BHA with a junk sub (bit, junk sub, 10 x 6 1/4" DC, jar, 2 x 6 1/4" DC, on 5" DP and RIH to 300' depth (100’ above top CMT plug). Wash down to the top of cement plug at +/- 400', drill out the cement and bridge plug @ +/- 1000' with sea water and 20 bbls gel sweeps every connection.

27. Continue RIH to 4000’ ORKB, wash down to top of CMT plug at +/- 4125', Drill out cement to top of the 7" scab liner at 4400'.

28. Circulate 50 bbls HI-VIs Pill and circulate minimum of 1.5 bottoms up or until returns clean with maximum rate. Rotate / reciprocate pipe at max safe speed to aide in cleaning hole of debris.

POOH L/D 6 1/4" DC & 8-1/2" bit.

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29. P/U 7" liner clean out assembly as follow, 6" Reed bit with open jet, 12x 4 3/4" DC, 9 x 3 1/2" HWDP, 3 1/2" DP to 200' above the 7" scab liner, X/O, 9 X 5" DP, JAR, 5" DP to surface.

30. RIH, circulate bottoms up every 2500 ft, continue RIH wash down from 100' above the expected top of cement at 12277' ORKB, clean out cement to PBTD @ 12,397'.

31. Sweep hole with 50 bbl's Hi-Vis Pill and circulate the hole clean. POOH.

32. RIH with tandem scraper 7" and 9-5/8", space out the BHA to have the 9-5/8" scraper at top of scab liner when the 6" bit become at ± 20' above PBTD. Work scraper across the proposed DST PKR setting depth and proposed perforated intervals, (Nukhl 8948' - 8980'), (Matulla 11358' – 11484') confirm with Cairo Team.

33. Sweep hole with 50 bbl's HI-VIs pill and circulate hole clean.

34. Displace the hole with 9.4 ppg filtrated Nacl brine water.

35. R/U Schlumberger W/L unit, RIH & record CBL-VDL-GR log from PBTD to 300' above the 7" scab liner, send log to Cairo office.

36. R/U and run VSP log, record same from PBTD to surface as per logging program.

37. POOH and L/D VSP & R/D Schlumberger W/L unit.

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8 Drill Stem Test Program

The DST program will cover the following main issues:A. The test objectives.B. Basic well data.C. Safety precaution and risk assessment.D. Testing procedures.

A. Objectives

1. The objectives of this DST are to test the Nukhul and Matulla formations individually, minimizing environmental impact with clean burning technology. The well productivity will be obtained by accurate measurements of the oil rates for economic success.

2. Perforate, perform flow test, pressure buildup test, and collect reservoir samples from the Matulla oil pay zones. POOH with test string. Set EZSV above perforations to isolate Matulla perforations.

3. Perforate, perform flow test, pressure buildup test, and collect reservoir samples from the Nukhul pay zones. POOH with test string. Set EZSV above perfs to T&A the well.

4. T&A the well.

B. Basic well Data

1. Average "Nukhul" reservoir pressure is 2594 psi at –8639’ SS (equivalent to 5.77 ppg EMW) based on MDT data.

2. Average "Matulla" reservoir pressure is 5211 psi at –10974’ SS (equivalent to 9.13 ppg EMW) based on MDT data.

3. Sea water will give 1270 psi over balance at the -8639' SS TVD (Nukhul).

4. A 9.4 PPG Nacl brine will give 152 psi over balance at the -10974' SS TVD (Matulla).

5. Under balance pressure while perforating "Matulla" will be 1500 PSI and 1000 PSI for "Nukhul.

6. The maximum allowable Surface Pressure using seawater is 1450 psi based on estimated fracture gradient of 0.61 psi/ft.

7. The maximum allowable Surface Pressure using 9.4 ppg brine is 2440 psi based on estimated fracture gradient of 0.71 psi/ft.

8. Static bottom hole temperature 251 F based on open hole log dated.13


9. Open hole drilled with 9.4 ppg OBM. 10. Drill stem test string will be filled with filtered treated sea water to surface, creating ±

303 psi under balance (assuming an average reservoir pressure of 9.13 ppg at 10974' SSTVD).

11. The well MDT data as follow.

Formations MD TVDss Pressure Eq MW Pore pressure FT FT PSIA PPG PPG

Nukhul 8976 8631.48 2592.7 5.78 Nukhul 8980 8635.19 2592.8 5.77 8.6Nukhul 8984 8638.9 2593.7 5.77

MATULLA 11359 10862 5161.6 9.14 MATULLA 11362 10865.49 5162.8 9.14 MATULLA 11370 10873.18 5165.3 9.14 MATULLA 11374 10877.02 5166.6 9.13 8.6 - 8.9MATULLA 11378 10880.86 5168.1 9.13 MATULLA 11384 10886.63 5170.2 9.13 MATULLA 11390 10892.39 5172.3 9.13 MATULLA 11397 10899.11 5174.9 9.13 MATULLA 11414 10915.44 5224.9 9.21 MATULLA 11436 10936.57 5189.1 9.12 MATULLA 11455 10954.82 5203.4 9.13 MATULLA 11473 10972.09 5210.4 9.13 MATULLA 11475 10974.01 5211.2 9.13

WATA 11513 11010.49 3800 6.64 8.6RAHA 12001 11478.27 5305.5 8.89 RAHA 12003 11480.18 5306.5 8.89 8.6 - 8.8RAHA 12012 11488.8 5312.8 8.89 NUBIA 12297 11761.34 5382.4 8.80 NUBIA 12301 11765.16 5383.5 8.80 NUBIA 12304 11768.03 5384.7 8.80 NUBIA 12330 11792.87 5422.3 8.84 8.6NUBIA 12356 11817.7 5406.1 8.80 NUBIA 12368 11829.16 5411.5 8.80 NUBIA 12492 11947.55 5461.4 8.79 NUBIA 12502 11957.1 5465.7 8.79

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C. Safety precaution and risk assessment.

1. The firing of the TCP perforating guns should only be performed during daylight hours.

2. A boat with fire fighting equipment will be stationed in close proximity to the rig, loaded with dispersant and capable of applying the dispersant in the vicinity of the rig. The DST will not commence until this vessel is in position.

3. Refer to the D.O.M. for details all contractor and/or sub-contractors associated with the work detailed herein must be made aware of specific HSE procedures for the rig and its associated areas and operations. This should not be limited to the general safety introduction and emergency response plans for the rig in question.

4. All such personnel must be instructed to participate in not only tool box meetings, but also the weekly HSE meetings conducted by rig contractor.

5. Each individual should be aware of who is ultimately responsible for safety on the rig and that they are part of a team who contribute to the safety record of that rig. Active participation in the rig’s stop program should be encouraged.

6. Key personnel should attend the daily operations meeting held between PETZED and key rig site personnel.

7. All contractors should also be made aware of the concerns and requirements relating to the environment and the measure in place to minimize their individual effects.

8. All work is to be performed including but not limited to rig ups, rig downs, RIH, POOH and pressure testing is to be up to standards unless otherwise specified in this document.

9. No variations from this program are permitted unless advised by Cairo office management.

10. Contact Cairo office if in any doubt about the program and the procedures contained herein.

11. Toolbox Safety meetings should be conducted before each new operation in the program.

12. Good house keeping practices shall maintain through out the course of the program.13. The site is to be left clean at completion of the program. Consult Co-man for waste

disposal.14. There are currently no indications that the H2S will be present in the formation fluids to

be tested. All personnel should be properly trained on handling of H2S situations prior to commencing with DST. "Draeger" tubes will be used to determine the presence of any H2S as soon as the first hydrocarbons reach the surface. They will be used at regular intervals thereafter. If H2S is encountered at unacceptable level then the DST will be terminated immediately.

15. A representative from Cairo Reservoir engineering should be on board for the test as well as Halliburton reservoir test specialist.

16. A safety meeting involving all key personnel will be held before each phase of this test. The emergency shut down procedures should be thoroughly discussed and posted on the rig floor, radio room and test site.

17. All rig crew members should be cautioned about accidentally opening any valves that are involved with the DST. Valves should only be opened or closed under the direct supervision of those involved in the test.

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18. Chain of Command:

i) The Rig Superintendent has the final word when it comes to the safety of the rig and all personnel on board. He will coordinate with the PETZED Co. Man.

ii) The Company man has the overall responsibility for conducting the test. He will coordinate with the test engineer to issue all instructions to service company personnel.

iii)The tool pusher coordinates with the company man to ensure the drilling operations required during the test are carried out as per the program.

iv)The Halliburton test supervisor is responsible for the execution of the test program. He reports to the Company man.

v) The driller is responsible for all actions taking place on the rig floor. All operations throughout the test must be cleared through the driller.

D DST Procedures

1. RIH with Bull Noose tool on 1 stand of 5” DP. Pump with maximum pump rates with seawater and jet BOP stack and ram cavities. POH and LD cement diverter.

2. P/U a stand of 5” drill pipe and close the top set of 5” rams on the pipe. Mark the pipe at the rotary and open rams. Note the distance between the mark at the rotary and the middle of the top rams. This measurement is very important in spacing out the lubricator valve.

3. R/U Power Well Flow Surface testing equipment and test as follows using a chart recorder:

A) Burner to 500 psi.B) Separator, oil and gas manifolds to 1000 psiC) Heater inlet to 2500 psiD) Downstream valves on the choke manifold to 2500 psiE) Upstream valves on the choke manifold to 4000 psi.F) In line (isolation valve) to 4000 psi. (Function test at the same time)G) Fail-safe valve on the flow line to 4000 psi. (Function test at the same time)

4. Pressure test the following on the catwalk prior to P/U to 5000 psi:

A) Tubing string test valve.B) X-O to Test packer (if required) Sub 4-1/2” IF Box X 3-1/2” EUE Pin C) 7” Test Packer.

NOTE: D) All DST tools and accessories will be drifted with a 2.125” drift prior to RIH.

5. Reset the tubing string test valve and install the rupture disc (if required).

6. Hold a safety meeting prior to PU Perforating guns and DST string. Follow the Service Company Engineer’s instructions while making up the guns and DST tools. Ensure the following are on the rig floor at all times:

A) 4-1/2” IF Pin X 2” 1502 Female.B) 2” 1502 Lo-Torque valve.C) 3-1/2” if pin x 2” 1502 Female.

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D) Gray valve or TIW valve with 4-1/2” IF and 3-1/2” connection.

7. M/U 4 5/8” TCP gun assembly on rig floor as per attached schematic which will consists of the following:

Ported Bull Plug. Time Delay Firing Head. Extended Delay elements. 78 ft of loaded guns of 4 5/8” TCP, 12 SPF, Millennium charges, SDP

conjunction with Steam sleeve. 4 5/8" Gun safety spacer. Mod II D Pressure assisted mechanical Firing head. 4 ft 2 7/8” Pup Joint HW with No Go. 3 X 10 2 7/8” EUE HW Pup Joint. Ported BIT sub. 2 7/8” EUE Pup Joint. Mechanical tubing release. 2 7/8” EUE Pup Joint. X Over 2 7/8” Pin X 3 ½” IF Box 1 Stand 3 ½” Drill Pipe. Radial shock absorber. Vertical shock absorber. 7” Champ Packer with concentric bypass. Safety Joint. Hydraulic Jar. TST valve. 2nd Memory gauges bundle carrier (including two gauges). Select Tester Valve in Lock Open position. ATS Transmitter Drain valve. X Over 3 ½” IF Pin X 3 ½” PH-6 Box. 1 joint 3 ½” PH-6. X Over 3 ½” PH-6 Pin X 3 ½” IF Box. OMNI Valve. RD valve. X Over 3 ½” IF Pin X 3 ½” PH-6 Box. 1 stand 3 ½” PH-6. RA Marker Sub. 3 ½” PH-6 TBG (51 stands) X Over 3 ½” PH-6 Pin X 3 ½” IF Box. 5” Slip Joint (close). 5” Slip Joint (open). X Over 3 ½” IF Pin X 3 ½” PH-6 Box. 3 ½” PH-6TBG to Surface

Notes:

TCP Specialist’s will be present and supervise at all times the lifting of TCP BHA equipment.

DST Tool Specialists to be present and supervise at all times lifting of Tools BHA equipment.

Extreme care to be taken during all lifting operations and making up TCP tools. The measurement between top of the TCP gun and R/A marker is being

carefully measured and allowing packer to set.17


Scanning rate of memory gauge will be 5 sec for one gauge while the other will be 10 sec.

Make up torques on rig floor to be supervised by Tool Specialist who will advice Driller.

8. Reverse circulate 25 BBL's of brine, this cleans up any debris from the TST valve flapper. Pressure Test string to 5000 psi for 10 min against TST valve then bleed off. Use Cement pump unit and record on strip / chart recorder.

9. Pick up and make up ± 6 joints of drill pipes below the packer while perforating.

10. Pick up and make up two slip joints (One opened and one closed).

11. Pick up and make up rest of 3 ½” PH-6 TBG to surface.

Notes:

Final space out tool string will allow leaving one slip joint open and one slip joint closed with the Super Safety Valve landed across BOP after the packer being set.

While RIH with drill pipe, Apply pipe dope sparingly to pin ends only using a paint brush, if there is dope excess around the external diameter of the tool joint, it must be removed.

Drift PH-6 TBG while picking up. The TST valve will fill the string while running in hole

Depth Correlation

12. Rig up Schlumberger W/L unit & logging equipment.

13. With string being under tension, RIH with GR-CCL, Correlate depth with open hole logs, record Radio Active bead and space out for guns.

Note:

Open hole logs including GR should be available on rig site.

14. POOH and R/D logging equipment.

15. Space out to position guns on the required depth.

Test String

16. R/U surface test tree and connect kill line to Rig stand pipe

17. Reverse circulate 25 Bbls of brine, this cleans up any debris from the TST valve flapper. Pressure Test string to 5000 psi for 10 min against TST valve then bleed off. Use Cement pump unit and record on strip / chart recorder. Measure pump and returned volumes.

18. At this situation, the two slip joints & jar are fully open. Space out to allow one slip joint open and the jar and other slip joint will be closed after setting the packer.

18


19. Set Champ packer as per DST Tool specialist instructions (away from any CSG collar).

20. Land test tree to the required depth to allow close jar, one slip joint and open the other slip joint.

21. Cycle OMNI Circulating Valve to the circulation position by pressuring up the annulus to 1100 psi and bleeding off.

Note:

All annulus pressure cycles are to be recorded and the ratchet position of Omni Valve must be updated.

22. Connect flow line to Cofflex hose.

23. Close master valve, swab valve & open kill valve.

24. Flush the lines, cofflex hose and test tree to kill line to flare or water pit.

25. Close kill wing valve & P/T cofflex hose against master, swab and kill valves to 5000 psi.

26. All other flowing system down-stream choke manifold must be previously tested.

Note: No pressure test on string after setting the Packer.

27. R/U Schlumberger W/L unit & logging equipment. Re-RIH with GR-CCL, Correlate depth with open hole logs, record R/A bead to be sure that the guns are in its position. Re- space out for guns if required.

Note:

Open hole logs including GR should be available on rig site.

28. Close pipe ram lock sub and pressure test annulus to 2300 psi for 10 min and release the pressure (this will lock open the TST valve and unlock open the Select tester valve)

Note:

All annulus pressure cycles are to be recorded and the ratchet position of Omni Valve must be updated.

Function test the ESD system from the well test area, drill floor and safe areas by activating the push buttons on the shutdown panel. These function tests must be witnessed by the rig CO.MAN, TESTING SUPERVISOR and WELL TESTING SUPERVISOR.

31. R/U N2 unit and connect same to test tree and pressure test line to 5000 psi.

19


32. Open annulus to trip tank. Displace test string contents with N2 through OMNI valve as cushion fluid down of brine exists in well. Check the brine volume equivalent to this depth received on trip tank.

33. RIH with the Amerada on slick line, determine the fluid level and calculate the draw down equivalent to 1500 psi under balance.

34. Cycle the OMNI valve to well test position by pressuring up annulus to 1500 psi and then Pressure up annulus to open the Select Tester Valve.

Perforate Well: The "Matulla" formation contains 2 main sand bodies. The bottom sand body (48 ft) and the top part of "Matulla" formation (30 ft) will be perforated and tested in commingle.

35. R/U Slick line lubricator.

36. Open Swab valve and RIH With 2” slick line string with mechanical jar till depth of champ packer to check the OMNI and Select Tester Valve and TST Openings.

37. POOH with Slick Line and Close Swab Valve.

Notes:

Scan should continuously monitor WHP & annulus pressure from this time every 1 sec.

38. Line up the testing choke manifold to the flare line, ensure Scan unit is recording pressure and sampling at 1 second. Scan pressure data to be checked and confirmed by DWT (dead weight tester) readings.

Note:

Announcement to be made over rig system advising personnel that well is to be perforated.

Equip the slick line lubricator with firing bar.

Connect the drill pipe to a rubber hose to water bucket and put the sound recording device to the well head.

Open swab valve to drop bar and close it again. Monitor WHSIP on choke manifold and on scan system.

If there is no indication of fire, R/U the slick line unit and make up the tool string connected with the bar pulling tool to fish the perforating bar. Enough weight is required to avoid jumping of the tool string. Pressures test the S/L lubricator to 1000 psi.

RIH with the pulling tool, record the fluid level (IF POSSIBLE) while RIH and compare same with the original fluid level filling the string. Latch the perforating bar and POOH and check the mark on the bar, the indent plug and R/D the S/L.

20


If there is no mark on the indent plug and no influx from the well, Use the following procedure to activate the time delay firing head to fire the guns hydraulically with N2

as follows:

Connect nitrogen lines to power well tree and test same to 5000 psi. Pressure up the tubing with N2 quickly till reaching all Fire. The N2 pump should be able to reach the pressure from No Fire to All Fire and keep

for 1-3 min's at All Fire within 12 min's (time of TDF) to avoid perforating overbalance. Final timing will be advised by TCP engineer.

At any time there is an indication for firing the guns during pressure up the tubing, immediately bleed off the tubing pressure to zero through choke manifold via flare pit then shut in the well and proceed with test program.

The calculation of the TDF based on 500 psi pressure test on the packer, mud weight 9.4 ppg, temp 251 F, safety factor, the no. of shear pin is 8 shear pin (+/- 960 psi/pin), (+/- 4000 psi).

The timing including the time of pressurizing up tubing side with nitrogen from minimum surface pressure required for firing the guns to maximum surface pressure required for firing the guns, holding pressure for 1.0 minute and bleed off to zero shouldn’t exceed +/- 12 minutes to avoid perforation overbalance.

Operating instructions of the Time-Delay Firer:o The Time–Delay Firer (TDF) allows under or overbalanced perforating

through the use of a pressure actuated firing head with a time-delay fuse. The time delay firing head and delay fuse allows (+/- 10 to 12 minutes) for adjusting the acting pressure in the tubing to achieve the desired pressure before firing the guns. The TDF is run with a predetermined number of shear pins for specific well conditions.

o Based on well performance, each flow period and / or choke size could be

changed according to Well Site Test Reservoir engineer recommendations after consulting with Office managers.

9 Testing “Matulla” formationPerforation intervals for bottom & top "Matulla" formation:

11484 – 11470 (14 ft)11464 – 11454 (10 ft)11444 – 11428 (16 ft)11420 – 11412 (8 ft)

11388 – 11358 (30 ft)

General Notes:

Surface well test should be rigged up and pressure tested before the next procedures.

Two flare lines should be prepared with 3½” N. Vam connection from well site to hot flare line. Box should be at Rig site while pin to be at flare pit.

Another three flare lines to be prepared with 3½” N Vam connection from well site to cold pit. Box should be at Rig site while pin to be at cold pit.

Annulus pressure should be bleed off (as per DHT engineer advice) during next testing operations to avoid string buckling due to expected heat transfer effect.

21


Ear protection should be used during the testing operation. The housekeeping should be followed up daily and the site should be clean all

the times. Pressure on the annulus should be monitored during all the testing period

through the data gathering system. All Equipment certificates and annual inspection should be available on the well

site with contractor supervisor. Continuously monitor the flow-lines for leaks throughout any flowing period

Well TESTING OPERATION SCHEDULE PREDICTED TIMES IF THE WELL FLOW NATURALLY

40. Perform Static Gradient inside the well bore, to define the fluid distribution as well as the pressure gradient inside the tubing, and consequently the reservoir pressure.

Hours1 1st Flow period (Initial

flow period)1 Open the well gradually at adjustable choke

64/64’’2 1st Shut-in 2 BU3 2nd Flow period (Main

flow period) 48 to 72 Perform the reservoir limit test. Choke 32/64’’Choke 64/64’’ or 48/64’’

4 2nd Shut-in 72 Main build up period3rd flow Period 24 ( 1/4" , 3/8",1/2" & 5/8") , 6 hrs each ,

5 3rd Flow period (Sampling flow)

3 or more Sampling, 16/64’’

PREDICTED TIMES IF THE WELL CEASED TO FLOW NATURALLY:

hours1 1st Flow period (Initial

flow period)1 Open the well gradually at adjustable choke 64/64’’

2 1st SHUT-IN 2 BU

32nd Flow period (Main flow period)

Max 24 Cleaning up period with C.T. + N2

12 Choke 32/64’’12 Choke 64/64’’ or 48/64’’

4 3rd FLOW PERIOD (SAMPLING FLOW)

3 or more Sampling, 16/64’’

1 st Flow Period (Initial Flow Period) "I.F.P" (64/64") {1 hr}:

41. After confirming firing of the guns hydraulically and with annulus pressure has 2300 psi

to keep Tester Valve open, open well to flare gradually by 4/64" till reach 64/64".

42. Continue flow well on 64/64" choke for 1 hr for cleaning and as an initial flowing period.

Notes Record BS&W at least every 10 min's.

22


Check H2S and CO2 if there is hydrocarbon on surface. Collect surface samples of gas and liquid every 30’ and analyze them in lab to

see the presence of reservoir fluids. Record and Plot THP, THT, BS&W, H2S, and water salinity, if possible. All data recorded will be reported in psi, Deg. F, in the 24-hour clock. Monitor annulus pressure and always keep only 2300 psi to keep tester valve.

Bleed off any more pressures than 2300 to avoid increasing pressure and open RD valve (@ 2800-3000 psi).

1 st Shut-in Period (Initial Shut in Period) "I.S.P" {2 hrs}:

43.Bleed Off the annulus press to zero to close in the well at select tester valve as per

Halliburton procedures.

44.With positive indication at surface of select tester valve closed, close in well from

choke manifold.

45.Keep monitoring the WHSP to check the sealing of tester valve, keep in mind that

the WHSP may be increased due to possible gas expansion.

46.Keep well close in for 2 hrs as initial build up period.

47.During the main build up, the annulus should be monitored via scan system. No

positive pressure should be on the annulus.

Note: CTU and at lease 6000 gals should be stand by on rig site as contingency if

well doesn't flow naturally. If start uses N2 ask for more N2 to be mobilized. If the well ceased to flow naturally, proceed to RIH C.T. as deep as possible

and lift the well with N2 (400-500 scf/m). Wait for 6 hours and lift the well again. Lifted fluid will be diverted to separator or stored in a tank. Wait again for six hours and in the case of not flowing to surface, close the well for B/U, otherwise continue with production period on two different choke, as described above. In the case of water production close the well for B/U.

2 nd Flow Period (Main Flow Period) (32/64") {48 - 72 hrs}:

48.After completion of the I.S.P period, pressure up annulus with rig pumps to 2300 PSI

as per Halliburton procedures to lock open Select tester valve. Well head pressure

will be increased on choke manifold.

49.Open well gradually on 8/64” adjustable choke. Bean up the well gradually in 4/64”

increments to required 32/64” adjustable choke.

23


50.Monitor the flowing wellhead pressure and temperature. Note the BS&W every 30

minutes initially and hourly once stabilized. Guidelines for when the well may be

considered as clean are as follows:

The flowing wellhead pressure has stabilized within 5 Psi / 30 min's.

The BS&W has been constant over the previous two hours.

51.Once well is stabilized and clean, switch it to test separator on choke 32/64" fixed

bean and flow well for 12 hrs stable flow.

Record BS&W every at least every 1 hr. Check H2S and CO2 if there is hydrocarbon on surface. Collect samples of gas and liquid every 30 min's and analyze them (content

of mud, brine and oil, oil density, gas density, water salinity, K+ Ca++ in water/brine) to see the presence of reservoir fluids.

Record and Plot THP, THT, BS&W, H2S, and water salinity, if possible. All data recorded will be reported in PSI, Deg. F, in the 24-hour clock.

52.Collect surface oil and gas recombination samples at end of 12 hrs flowing period.

53. B/U choke to 48/64 or 64/64" (will be advised later from well site reservoir engineer)

and test well for another 12 hrs via test separator.

Record BS&W every at least every 1 hr. Check H2S and CO2 if there is hydrocarbon on surface. Collect samples of gas and liquid every 30 min's and analyze them (content

of mud, brine and oil, oil density, gas density, water salinity, K+ Ca++ in water/brine) to see the presence of reservoir fluids.

Record and Plot THP, THT, BS&W, H2S, and water salinity, if possible. All data recorded will be reported in PSI, Deg. F, in the 24-hour clock. Stabilized minimum separator pressure should be achieved during the test

periods. Two-meter & shrinkage factors should be conducted during each test period. Check the gas gravity in every 2 hrs. Well head samples should be collected during the test periods every 30

min's.

54. Collect surface oil and gas recombination samples at end of 12 hrs flowing period.

Contingency plan (if well doesn't flow naturally)

24


If the well ceased to flow naturally during the clean up period, proceed to RIH with C.T

to deepest point and lift the well with N2 after consulting reservoir engineers and drilling

manager. The choke should be fully open while lifting the well, till getting natural flow.

a) Based on the well performance during the clean up period, the main flow

period could be changed according to the test engineer recommendations

after consulting with Cairo office managers.

b) Casing pressure should be monitored during all the flow periods to check

the leakage to avoid shearing the R/D valve and keeping tester valve

open.

c) Do not inject any chemicals during the sampling period to avoid collecting

contaminated samples.

d) Monitor the well till achieving stabilized WHFP, GOR & separator

pressure. Then, start collecting the required sets of separator re-

combination samples.

2nd Shut-in Period {48 - 72 hrs}:

55.Bleed Off the annulus press to zero to close in the well at select tester valve as per

Halliburton procedures.

56.With positive indication at surface of select tester valve closed, close in well from

choke manifold to allow scan monitor pressures all the time.

57.Keep monitoring the WHSP to check the sealing of tester valve, keep in mind that

the WHSP may be increased due to possible gas expansion.

58.Keep well close in for 48 – 72 hrs (depend on final WHSIP) as build up period.

59.During the main build up, the annulus should be monitored via scan system. No

positive pressure should be on the annulus.

Retrieve BHP and BHT

60.R/U Electric line unit and pressure test Lubricator to WHSIP.

61.RIH with SRO probe to the depth of ATS transmitter carrier, pull and run across this

depth till get a signal of pressure and temperature transmition.

62.Retrieve the bottom hole pressure and temperature and report same to test and

reservoir engineer.

63.After confirming stable BHP, POOH with SRO probe and close swab valve.

64.When E/L on surface, R/D E/L equipment.

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65.Based on the pressure stabilization, the final build up period (36 or 48 hrs) will be

determined.

3 rd Flow Period (Sampling Period) (1/4", 3/8",1/2" & 5/8") {+ 24 hrs}

66.Pressure up annulus with rig pumps to 2300 PSI as per Halliburton procedures to

lock open Select tester valve.

67.R/U logging or slick line unit which is available.

68.Connect two bottom hole samplers to tool string, adjust clock to read after ± 3 hrs.

69. Install samplers into lubricator and pressure test same to WHSIP.

70.Open master valve and RIH with samplers to deepest point in string.

71.Open well gradually on 1/4", 3/8",1/2" & 5/8" fixed choke (or other choke depend on

main flow data "will be advised by reservoir engineer) to test separator.

72.Monitor the flowing well head pressure stabilization.

Record BS&W every at least every 1 hr. Check H2S and CO2 content. Collect samples of gas and liquid every 30 min's and analyze them (content of

mud, brine and oil, oil density, gas density, water salinity, K+ Ca++ in water/brine) to see the presence of reservoir fluids.

Record and Plot THP, THT, BS&W, H2S, and water salinity, if possible. All data recorded will be reported in psi, Deg. F, in the 24-hour clock.

73.Keep well flows to test separator for at least 3 hrs.

74.Wait till the samplers open and take samples.

75.Collect surface oil and gas recombination samples from test separator at end of

flowing period.

76.C/I well and POOH with sampler. Transfer the samples to pressurized bottles and

give them to reservoir engineer.

10 Kill well and retrieve test string.

83. With OMNI valve on test position and Select test valve close as in last shut in period.

84. Bleed off the tubing pressure via choke manifold to the flare to Zero.

85. Pump killing fluid (9.4 ppg Nacl brine) to fill tubing monitoring pumped volumes.

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86. Keep the OMNI Valve on well test position, pressure up annulus to 2300 psi to lock open the Select Tester Valve.

87. Bullhead the volume between the packer and the perforations and inject 10 bbls of kill fluid with low pressure taking care not to fracture the formation.

88. Stop pumping and observe well for static.

89. Open the concentric by-pass of champ packer and start reverse out from the lowest point in the string. Care must be taken while apply annulus pressure in order to not close select tester valve.

90. Stop pumping and observe well static for ½ hour.

91. Open pipe rams and unseat packer. Stop and Observe well for possible gas migration.

92. Circulate at least 1.5 tubing volume the reverse way via the rig’s choke with kill fluid, then open pipe rams and complete circulation with at least one hole volume directly (long circulation) conditioning and balance kill fluid weight monitoring well for losses.

93. Monitor well for 1/2 hour.

94. If well is stable, close the master valve, flush surface equipment with fresh water and R/D flow head and lines.

95. Open pipe rams, POOH with DST string slowly laying down tubing (on pulling out monitor fluid level).

96. Perform flow checks every 1500 FT.

97. Use drain valve to bleed off pressure and drain fluids trapped between OMNI and tester valves.

98. Lay down BHA and dump recorded data from memory gauges.

99. R/U Schlumberger W/L unit, P/U and RIH with 9-5/8" EZSV bridge plug GR-CCL and RIH, correlate and set the EZSV above the top "Matulla" perorations at 11200 ft.

100. POOH and R/D Schlumberger W/L unit.

101. Test the annulus above the EZSV to 2000 psi using 9.4 ppg brine in hole.

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11 Testing "Nukhul" Formation

102.The "Nukhul" intervals will be perforated as follows:

8948 – 8960 (12 ft)8966 – 8980 (14 ft)

103.P/U the previous testing assembly and RIH to 9300 ft, perforate the mentioned interval under balance pressure ± 1000 Psi.

104.Use the same steps and duration for testing Matulla formation to test the Nukhul formation.

105.R/U Schlumberger W/L unit and RIH with Halliburton 9-5/8” EZSV on GR-CCL running tool. Correlate and set EZSV ± 100 ft above Nukhul perforations. POOH and R/D W/L unit.

106.Temporarily abandon program to follow.

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12 Halliburton test string schematic

29

HALLIBURTON TOOL STRING SCHEMATICCUSTOMER: PETZED

WELL NAME: MUZHIL-1 RIG:

TEST: DST#1

TOOL STRING DESCRIPTION ID(in)* OD(in)*LENGTH(ft)*DEPTH(ft) COMMENTS

Surface Test Tree

3 1/2" PH-6 TBG To Surface 2.250 4.750 7218.66 PETZED to supply

X-OVER 3 1/2" IF (P) X 3 1/2" PH-6 (B) 2.250 4.750 1.50 7218.66 Halliburton to supply

5" Slip Joint (1 EA ) Open 2.250 5.000 21.00 7220.16 Halliburton to supply

5" Slip Joint (1 EA ) Close 2.250 5.000 21.00 7241.16 Halliburton to supply

X-OVER 3 1/2" PH-6 (P) X 3 1/2" IF (B) 2.250 4.750 1.25 7262.16 Halliburton to supply

3 1/2" PH-6 TBG 2.250 4.750 3700.00 7263.41 PETZED to supply

3 1/2"PH-6 R/A Marker Sub or Bead 2.250 4.750 1.20 10963.41 Halliburton to supply

3 1/2" PH-6 TBG Joint (Three Joints) 2.250 4.750 90.00 10964.61 PETZED to supply


5" RD Circulating Valve 2.250 5.000 3.50 11056.11 Halliburton to supply

5" OMNI Circulating Valve 2.250 5.000 21.00 11059.61 Halliburton to supply

X-OVER 3 1/2" PH-6 (P) X 3 1/2" IF (B) 2.250 4.750 1.25 11080.61 Halliburton to supply

3 1/2" PH-6 TUB Joint (ONE JOINT) 2.250 4.750 31.00 11081.86 PETZED to supply


5" Drain Valve 2.250 5.000 2.00 11114.16 Halliburton to supply

ATS Trasmitter 2.250 5.000 9.80 11116.16 Halliburton to supply

5" Select Tester Valve 2.250 5.000 18.70 11125.96 Halliburton to supply

5" Bundle carrier with (4 gauges) 2.250 5.500 16.53 11144.66 Halliburton to supply

5" TST String Tester Valve 2.250 5.000 4.00 11161.19 Halliburton to supply

Big John Jar 2.250 4.630 6.50 11165.19 Halliburton to supply

Safety Joint 2.400 5.000 3.40 11171.69 Halliburton to supply

7" Champ Packer 2.400 8.250 10.50 11175.09 Halliburton to supply

5" Vertical Shock Absorber (2 EA) 2.250 5.000 1.48 11185.59 Halliburton to supply

7" Redial Shock Absorber 2.250 8.250 3.50 11187.07 Halliburton to supply

3 1/2" Drill Pipe ( 3 EA ) 2.760 4.750 90.50 11190.57 PETZED to supply

X-OVER 2 7/8" EUE (P) X 3 1/2" IF (B) 2.440 4.750 0.25 11281.07 Halliburton to supply

2 7/8" EUE TBG Jnt. ( 1 EA ) 1.990 3.670 31.00 11281.32 PETZED to supply

2 7/8" Ported B.I.T. Sub 2.400 3.750 0.68 11312.32 Halliburton to supply

2 7/8" EUE Pup Joint HW ( 3 EA ) 1.990 3.670 30.00 11313.00 Halliburton to supply

2 7/8" EUE Pup Joint HW X 4' with No Go 1.560 3.670 4.50 11343.00 Halliburton to supply

3 3/8" Mechanical Firing Head N/A 3.375 0.50 11347.50 Halliburton to supply

4 5/8" Safety spacer Gun N/A 4.625 10.00 11348.00 Halliburton to supply

Top Shot N/A 11358.00 Halliburton to supply

4 5/8"Guns, HMX,12 SPF, Mill, SDP,W/Stim,102'L N/A 4.625 126.00 Halliburton to supply

Bottom Shot N/A 11484.00 Halliburton to supply

Blank Gun N/A 4.625 2.38 11488.76 Halliburton to supply3 3/8" Extended Delay Assembly N/A 3.375 1.10 11489.86 Halliburton to supply

3 3/8" Time Delay Firing Head N/A 3.375 1.83 11491.69 Halliburton to supply

Ported Nose Plug N/A 3.375 0.45 11492.14 Halliburton to supply

* Actual length, OD & ID will be measured at well site

* PETZED To Supply : 2 7/8" & 3 1/2" SLIPS and ELEVATOR

Drilling Program Main File - Web viewTie back & DST Program. Bennevis rig. January 23rd 2007....

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Transcript of Drilling Program Main File - Web viewTie back & DST Program. Bennevis rig. January 23rd 2007....