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									                              Well Muzhil #1 – Tie back & DST program




         Muzhil – 1
    Tie back & DST Program
          Bennevis rig
          January 23rd 2007




1
                                                                           Well Muzhil #1 – Tie back & DST program




                                             Operation Department
                                           Document Distribution List

                                               January 23rd 2007


                                     Tie back & DST Program
                                               Well 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
              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                           1
                                                  Total                                  10




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                                                 Well Muzhil #1 – Tie back & DST program




                        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


    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




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                                                                    Well Muzhil #1 – Tie back & DST program




1 List of main Contractors
            Type of Service            Contractor    Name of Key Person          Mob. No./fax No.
                                          Name

    Drilling Unit (Bennevis)        Pyramid          Nigel Marlow


    ROV, Weather Forecast Service   Fugro            Ahmad Khosht


    Sea Bottom Survey & Diving      CDC              Saed Amer
    Service

    Cementing                       Dowell           Khaled Faroun


    Drilling Fluids                 Baroid           Ahmad Ezz


    Mud Line Suspension System      Cameron          Mohamed Abdallah


    XLF system                      Oil Tech         Moumtaz Fawaz


    Casing Services                 Weatherford      Ibrahim Bassiony


    Pre-Heating Braden Head &       Hot-Head         Husseiny Ibrahim
    Casing Cold Cutter

    Stabilizer Services             Halliburton      Diab Saad


    Cased Hole Logging              Schlumberger     Sherif Bayoumi


    Completion Equipment &          Halliburton      Ashraf Ashry
    Completion Engineer

    TCP Gun & Perforating Service   Halliburton      Khaled Shell


    Coiled Tubing, Nitrogen &       Halliburton      Moustafa Amin
    Stimulation Service

    DST & Well flow Surface         Power Well       Mohamed Gamal
    Equipment                       Services

    Fishing, Re-Entry, Rental       Baker Oil Tool   Omar Majed
    Equipment & Machine Shop
                                    Napesco          Ahmad Shalash

    Safety & H2S Service            Total Safety     Mohamed Ehab



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                                                                         Well Muzhil #1 – Tie back & DST program


    Mud Logging Services              PetroServices       Mohamed Diab



2 General Well Information

    Well Name                            Muzhil - 1
    Country / Concession                 Egypt / South Abu Zenima concession Gulf of Suez area
    Drilling Unit                        Bennevis
                                         Y = 689,978.00 m (N), X = 823,071.00 m (E)
    Well Head coordinates                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

    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            414
    13 3/8"             K-55          68.0 #       BTC           275            3982
    9 5/8"              DST-110HC     53.5 #       LT&C          275.3          8905
    7”                  P110          29.0 #       N.VAM         4400           12517

T & A status:

                            At        from            to                 remarks
    Cement plug #1                    600             1000
    9”5/8 Fast drill plug   1000                                         Bridge plug "Halliburton"
    Cement plug #2          4400      4125            4400
    Cement plug #3          12517     12517           12397              BPTD

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                                                                                                                             Well Muzhil #1 – Tie back & DST program



3 Well Status
                                      MUZHIL
                                  WELL BORE SKITCH
                                        RIG: COMET
           ft
RKB-MSL 89 90'                                                                                    Landing Ring @ 277 ft
W.D     109 ft                                                                                    13 3/8" MLH @ 275 ft
RKB-ML 198 ft                                                                                     9-5/8" MLH @   275.3 ft

                                                                                             30” Trash Cap @ 178' RT


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

      30" COND. XL 310 PPF

                                                                                             13-3/8" Corrosion Cap
                                             8.6 PPG
                                             Ihibited
                                               Sea
                                             Water




                                                                                             30” COND @ 414'
                                                400 '
                                            16 PPG " G"                                                                      Actual measurments for 30"
                                                CMT                                                                          Conductor made July 2006

    13-3/8" K55 68 PPF BUTT
    13-3/8" CMT Job.                                                                       9-5/8" FAST DRILL PLUG @ ±1000' MD
    12.0 ppg lead CMT " G Neat"
    16.0 ppg tail CMT " G Neat"
                                                    Ihibited Sea Water 8.6 PPG




                                                                                        13-3/8” CSG @ 3982’ MD




                                          275 ft 16 PPG
                                             "G" CMT
                                                                                   7" TOSL @ 4400’ MD
    9-5/8" DST 110HC 53.5 PPF LT&C
    9-5/8" Casing CMT job.
    first stage
    16 ppg CMT " G+35% S.F"
                                                Ihibited Sea Water 8.6 PPG




    Second stage
    14.5 ppg lead CMT " G Neat"
    16.0 ppg tail CMT " G Neat"




                                                                                   9-5/8" DVT @ 7136’ MD




                                                                                    7" TOL @ 8505’ MD



      7" Lnr 29 ppf, DST 110HC N. Vam
      7" Liner CMT job.
                                                 8.6 PPG Sea Water




      16.0 ppg CMT " G+35% S.F"
      7" Scab liner CMT job.
      16.0 ppg CMT " G+35% S.F"
                                                                                     9-5/8” CSG @ 8905’ MD




                                                                                 7" L.C @ 12397’ MD
                                             120 ft 16
                                             PPG "G"
                                               CMT                               7" Liner @ 12517’ MD



                                          FTD @ 12522’ MD




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                                                                    Well Muzhil #1 – Tie back & DST program


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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                                                                             Well Muzhil #1 – Tie back & DST program



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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                                                                    Well Muzhil #1 – Tie back & DST program


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.

9
                                                                       Well Muzhil #1 – Tie back & DST program

       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 1 ST 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).
        The running tool should be installed and torqued to 9-5/8” casing joint.
10
                                                                         Well Muzhil #1 – Tie back & DST program

         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.

11
                                                                     Well Muzhil #1 – Tie back & DST program

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.




12
                                                               Well Muzhil #1 – Tie back & DST program


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
                                                                  Well Muzhil #1 – Tie back & DST program

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              8.6
  Nukhul         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 - 8.9
 MATULLA        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              8.6
  RAHA          12001    11478.27 5305.5           8.89
  RAHA          12003    11480.18 5306.5           8.89           8.6 - 8.8
  RAHA          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              8.6
  NUBIA         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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                                                                 Well Muzhil #1 – Tie back & DST program

     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.




15
                                                                 Well Muzhil #1 – Tie back & DST program

 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 psi
     C) Heater inlet to 2500 psi
     D) Downstream valves on the choke manifold to 2500 psi
     E) 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.
16
                                                                Well Muzhil #1 – Tie back & DST program

        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
                                                                       Well Muzhil #1 – Tie back & DST program

             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
                                                                         Well Muzhil #1 – Tie back & DST program



     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
                                                                  Well Muzhil #1 – Tie back & DST program

     32. Open annulus to trip tank. Displace test string contents with N 2 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
                                                                   Well Muzhil #1 – Tie back & DST program

      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 N 2
       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” formation
Perforation 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
                                                                        Well Muzhil #1 – Tie back & DST program

           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.


                                        Hours
 1    1st Flow period (Initial            1     Open the well gradually at adjustable choke
      flow period)                              64/64’’
 2    1st Shut-in                          2    BU
 3    2nd Flow period (Main                     Perform the reservoir limit test. Choke 32/64’’
                                       48 to 72
      flow period)                              Choke 64/64’’ or 48/64’’
 4    2nd Shut-in                         72    Main build up period
      3rd flow Period                     24    ( 1/4" , 3/8",1/2" & 5/8") , 6 hrs each ,
 5    3rd Flow period                 3 or more Sampling, 16/64’’
      (Sampling flow)


PREDICTED TIMES IF THE WELL CEASED TO FLOW NATURALLY:

                                        hours
 1    1st Flow period (Initial             1        Open the well gradually at adjustable choke 64/64’’
      flow period)
 2    1st SHUT-IN                          2        BU
      2nd Flow period (Main            Max 24       Cleaning up period with C.T. + N2
 3    flow period)                        12        Choke 32/64’’
                                          12        Choke 64/64’’ or 48/64’’
 4    3rd FLOW PERIOD                 3 or more     Sampling, 16/64’’
      (SAMPLING FLOW)


1st 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
22
                                                                      Well Muzhil #1 – Tie back & DST program

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

1st 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.


2nd 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.



23
                                                                  Well Muzhil #1 – Tie back & DST program

     49. Open well gradually on 8/64” adjustable choke. Bean up the well gradually in 4/64”
        increments to required 32/64” adjustable choke.
     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.




24
                                                                    Well Muzhil #1 – Tie back & DST program

Contingency plan (if well doesn't flow naturally)

     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.

25
                                                                   Well Muzhil #1 – Tie back & DST program

     64. When E/L on surface, R/D E/L equipment.
     65. Based on the pressure stabilization, the final build up period (36 or 48 hrs) will be
        determined.


3rd 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.
26
                                                                    Well Muzhil #1 – Tie back & DST program



     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.




27
                                                                Well Muzhil #1 – Tie back & DST program




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.




28
                                                                                            Well Muzhil #1 – Tie back & DST program


12     Halliburton test string schematic
                   HALLIBURTON TOOL STRING SCHEMATIC
                                                                CUSTOMER:         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

               X-OVER 3 1/2" IF (P) X 3 1/2" PH-6 (B)            2.250    4.750      1.50       11054.61   Halliburton 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

               X-OVER 3 1/2" IF (P) X 3 1/2" PH-6 (B)            2.250    4.750      1.30       11112.86   Halliburton 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 supply
               3 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
29

								
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