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200-217
MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg � �ej 13�, DATE: 6/18/2019 P. I. Supervisor FROM: Adam Earl SUBJECT: Location Clearance Petroleum Inspector PBU 02-03B BPXA PTD 2002170; Sundry 319-037 6/2/2019: PBU 02-03B was deemed abandoned effective 5/8/2019. 1 inspected the well site which is located on PBU DS2, an active producing pad. The location is clean — no trash, no sheen or stained gravel. The well sign was mounted to a barrier marking the location. Attachments: Photos (2) 2019-0602_Location_Clear_PBU_02-03B ae.docx Page 1 of 2 Location Clearance — PBU 02-03B PTD 2002170 Photos by AOGCC Inspector A. Earl 6/2/2019 2019-0602_ Location _ Clear_ PBU_ 02-03B_ae. docx Page 2 of 2 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG HEGE"NE A44 ^ x ^'19 RBDMS-Li*v JUN 10 2019 /I J(A All Im '1 '11-110 la. Well Status: Oil ❑ Gas ❑ SPLUG ❑ Other ❑ Abandoned 0 Suspended ❑ Well Class: 20AAC 25.105 20AAC 25.710 GINJ ❑ WINJ El WAG ❑ WDSPL 11 No. of Completions: Zero 11b. n q A Develop m (I�`.®�AE`�prlalrE�✓7J,�' 1� Service ❑ Stratigrephic Test ❑ 2. Operator Name: BP Exploration (Alaska), Inc 6. Date Comp., Susp., rA an 5/8/2019 14. Permit to Drill Number/Sundry 200-217' 319-037 3. Address: 7. Date Spudded 15. API Number: P.O. Box 196612 Anchorage, AK 99519-6612 5/22/2001 50-029-20077-02-00 ' 4a. Location of Well (Governmental Section): 8. Date TD Reached: 16. Well Name and Number: Surface: 946FNL, 1749' FWL, Sec. 36, T71 N, R14E, UM Top Of Productive Interval: 4075' FNL, 353' FWL, Sec. 31, Ti iN, RISE, UM 5/28/2001 PBU 02-03B 9 Ref Elevations KB 64 GL 34.50 BF Surface 17. Field/Pool(s): PRUDHOE BAY, PRUGHOE OIL ' Total Depth: 3920' FNL, 822' FEL, Sec. 36, Ti IN, R14E, UM 10. Plug Back Depth(MD/TVD)' 18. Property Designation: Surface / Surface ADL 028308 & 028326 4b. 4b. Location of Well (State Base Plane Coordinates, NAD 27): 11. Total Depth (MDrTVD): 19. DNR Approval Number: Surface: x- 688499 • y- 5950279 - Zone - ASP 4 12566'19041' 74-017 TPI: x- 692462 y- 5947248 Zone - ASP 4 Total Depth: x- 691284 y- 5947374 Zone - ASP 4 12. SSSV Depth (MDrrVD): None 20 Thickness of Permafrost MD/WD: 1900' (Approx.) 5. Directional or Inclination Survey: Yes ❑ (attached) No 0 13. Water Depth, if Offshore: 21_ Re-drill/Lateral Top NAndow Submit electronic and printed information per 20 AAC 25.050MDrrVD: NIA (ft MSL) 10553'18642' 22. Logs Obtained List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data and printed logs within 90 days of completion, suspension, or abandonment. whichever occurs first. Types of logs to be listed include, but are not limited to: mud log, spontaneous potential, gamma ray, caliper, resistivity, porosity, magnetic resonance, dipmeter, formation tester, temperature, cement evaluation, casing collar locator, jewelry, and perforation record. Acronyms may be used. Attach a separate page if necessary MWD/GR, GR/CCL /CNL 23. CASING, LINER AND CEMENTING RECORD CASING WT. PER FT. GRADE SETTING DEPTH MD SETTING DEPTH TVD HOLE SIZE CEMENTING RECORD AMOUNT PULLED TOP BOTTOM TOP BOTTOM 30" 157.5# B Surface 115' Surface 115' 39" Fondu circulated to Surface 20" 94#/133# H -4a Surface 1219' Surface 1219' 26" 1010 ax Fondu, 11 Bbls AS I, 56 able Arctic Pack 13-3/8" 72# N-80 Surface 2688' Surface 2688' 17-1/2" 530 sx Fondu, 550 sx Class 'G' 9-5/8" M-95 Surface 10553' Surface 8642' 12-1/4"1810 sx Class'G' 3-12"x3-3/16#/6.2# L471143.5# L-sp 10095' 12565' 8302' 9041' 3-3/4" 26 Bola LARC x2-7/8".4# 24. Open to production or injection? Yes ❑No 0 25. TUBING RECORD If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number, Date Perfd): GRADE DEPTH SET (MD) PACKER SET (MD/TV 5-1/2" 17# N-80 10143' 10005'/ 8233' x 4-1/2" 12.6# N-80 ,�J• a - I�CYt 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. Was hydraulic fracturing used during completion? Per 20 AAC 25.283 (i)(2) attach electronic and printed Yes ❑ No 0 information n�op/{LTaar�klb�� Wrr DATP S� 14 , VERIFIED DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED Surface -10 Gal AS I Cement 69N 27. PRODUCTION TEST Data First Production: Abandoned Method of Operation (Flowing, gas lift, etc): WA Date of Test: =How. Production for Test Period -► at Oi4Bb1' Gas -MCF: Water -Bbl: Choke Size GasOil Ratio: 71 Tubing Press: Calculated Oil -Bbl: Gas -MCF: Water -Bbl: Oil GravlN-API loom: Press 24 Ebur Rate --► Form 10407 Revised 5201 ] CONTINUED ON PAGE 2 Submit ORIGINAL only A44 ^ x ^'19 RBDMS-Li*v JUN 10 2019 /I J(A 28. CORE DATA Conventional Com(s) Yes ❑ No 0 Sidewall Cores Yes ❑ No 0 If Yes to either question, list formations and intervals cored (MD+TVD of top and bottom of each), and summarize lithology and presence of oil, gas or water (submit separate sheets with this form, if needed). Submit detailed descriptions, core chips, photographs and laboratory analytical results per 20 AAC 25.071. 29. GEOLOGIC MARKERS (List all formations and markers encountered): 30. FORMATION TESTS NAME MD TVD Permafrost - Top Well Tested? Yes ❑ No 0 ' Permafrost - Base If yes, list intervals and formations tested, briefly summarizing test results. Attach Top of Productive Interval 11003' 9003• separate sheets to this form, if needed, and submit detailed test information per 20 AAC 25.071. CGL - Zone 3 10649' 8719' Base of CGL - Zone 2 10740' 8796' Zone 1 B 11003' 9003' TDF - Zone 1A 11093' 9033' Zone 1B (Invert) 11890' 9033' Zone 1A (Revert) 12154' 9033' Fornation at total depth: Zone 1A 12154' 9033' 31. List of Attachments: Summary of Daily Reports, Photo Documentation, Wellbore Schematic Diagram Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, core analysis, paleontological report, production or well test results, per 20 AAC 25.070. 32. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Authorized Name: Lastufka, Joseph N Contact Name: Montgomery, Travis J Authorized Title: SIIdSialist I Contact Email: Travis.Montgomery@bp.com Authorized Signature: Date: Contact Phone: +1 907 564 4127 INSTRUCTIONS General: This form is designed for submitting a complete and correctwell completion reportand logon all types of lands and leases in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is Changed. All laboratory analytical reports regarding samples or tests from a well must be submitted to the AOGCC, no matter when the analyses are Conducted, Item 1a. Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item 1b. Well Class Service wells: Gas Injection, Water Injection, Water-Altemating-Gas Injection, Salt Water Disp, Water Supply for Injection, Observation or Other. Item 41b. TPI (Top of Producing Interval). Item 9. The Kelly Bushing and Ground Level elevations in feet above mean sea level. Use same as reference for depth measurements given in other spaces on this forth and in any attachments. Item 15. The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Item 20. Report true vertical thickness of permafrost in Box 20. Provide MD and TVD for the lop and base of permafrost in Box 29. Item 22. Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data and printed logs within 90 days of completion, suspension, or abandonment, whichever occurs first. Item 23. Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. Item 24. If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Item 27. Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other ( explain). Item 28. Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Submit detailed description and analytical laboratory information required by 20 AAC 25.071. Item 30. Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Item 31. Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and other tests as required including, but not limited to: core analysis, paleontological report, production or well test results. Forth 10-407 Revised 5/2017 Submit ORIGINAL Only Job Scope: Prep and cut wellhead 3' below tundra for full abandonment. Wellhead cut 5/3/2019 complete in -6 hrs. All equipment is on location and secure. Job scope: Remove saw from excavation, cement top job on conductor. Poured -10 5/4/2019 gallons of AS1 cement to fill void after cuffing. Allow cure time for inspection. Job Scope: Excavate around Wellhead / Install Shoring Box (Permanent Plug and Abandon) Used an excavator to dig 12'x12' hole around wllhead to -16' deep. Assembled Engineered Modular Shoring Box and placed in excavation hole for wellhead cut. Cut wellhead 40" below tundra, Welded Top Cap and AOGCC inspection, pulled Shoring Box. Backfilled excavtion hole with gravel (-115 yds), deliniated around excavation and installed cattle guard around hole footprint. 5/8/2019 '"Job Complete" Pre -Suspended Well Inspection. Well is cut off below tundra grade. Cattle guard in area of well. Proper signage on cattle guard. 5/31/2019 02:00 T/I/O = N/A. Temp = SI. AOGCC SU Inspection (Regulatory Compliance). State witnessed by Adam Earl. Pictures taken. 6/2/2019 SV, WV = C. IA, OA = OTG. 13:00 I .10 4, 7NN TI2m= FMC 120 VY9JJfAD= MCLVOY GEN1 ACTUATOR= BAKORC liFYL KB. EE 64' BF. ELEV = 11/28176 ORgNAL COMPLETION K0P= 3100 Max Angle = 94' @ 11163' Datum MD= 10821' DahrnTVD= 6800 SS SAFETY NOTES: VVELL ANGLE >70'1211067'. ABANDONED 02-03B FULL Af3ANDONMFM-WELLHEAD CUT 3- BELOW TUNDRA, MARKER CAP INSTALLED AND BACKFILLED (05108M 9) TEG PIINCH� 1000'-1010' 9-5/8'CSG � 1 PATCH 13.3/8' CSG, 720, N-80, D =12.347' 2 LTSG PUNCH (11/14/17) 2698' - Minimum ID = 2.380" @ 10612' 33116" X 2-718" XO I BALANCE CMF RUG N TBG & IA fa6m6/171 I 5-12• 131/2• LNR 9.30, L-80 FL4S, D = 2.992- 4-1/2' TBG-NPC.126#, N-80, .0152 bpf, D = 3.958' ESTIMATED TOP OF COVENT FSTMATED TOPOF CBJBNT (08/01/17 .12•, 9.3# FL4S X 3-3/18', 820 TC2 XO, D = 2800 1 9518• CSG, 47#, 50095, D= 8.681- H 10801=—) TOPOFOLD9-518'SDTRKVZ OW -02-03A 10095' TOP OF DPZ1 NIP, 1890' ID = 4.56' 13-1/2'WFDXNP.13=2.81' I BAKERSBRASSY X 5.1/2- BAKBRSAB PKR, D=3.875• K4-1/2•xo, o=3ssa• TOP OF DPZ2 10052' BOTTOM OF DPZ2 11TId'idEr'. 94/8' CEMENT WNDOW 10553'- 10560' bm 3-3/16', 620, TC2 X 2-7/8' 6.16# STL XO, ID - 2.380' 12624' 2-7/6' 1M�Ht FLUG PB7rD� .00579 bpf, D=2.380' PERFORATION SUtvWRY PRLDFDEBAY UNIT WELL: 02-036 PBMFNo:2002170 AR No: 50-029-20077-02 SED36,T11N,RR14E�945'FTL&1748'FVYL REFLOG: BRCS ON 08/28!70 DATE REV BYCOMMBNIS 11/28176 ORgNAL COMPLETION ANGLEATTOP: EW@11399' 11/30195 CTO SIDETRACK Note: Refer to %duction B for historical pert data SIZE SPF NTERVAL SHOT DATE SO2 2• 4 11399-11500 C 05/31/01 2• 4 11640-12170 C 05/31/01 2" 4 12230 -12340 C 05/31/01 2' 4 12430-12500 C 05/31/01 1 9518• CSG, 47#, 50095, D= 8.681- H 10801=—) TOPOFOLD9-518'SDTRKVZ OW -02-03A 10095' TOP OF DPZ1 NIP, 1890' ID = 4.56' 13-1/2'WFDXNP.13=2.81' I BAKERSBRASSY X 5.1/2- BAKBRSAB PKR, D=3.875• K4-1/2•xo, o=3ssa• TOP OF DPZ2 10052' BOTTOM OF DPZ2 11TId'idEr'. 94/8' CEMENT WNDOW 10553'- 10560' bm 3-3/16', 620, TC2 X 2-7/8' 6.16# STL XO, ID - 2.380' 12624' 2-7/6' 1M�Ht FLUG PB7rD� .00579 bpf, D=2.380' PRLDFDEBAY UNIT WELL: 02-036 PBMFNo:2002170 AR No: 50-029-20077-02 SED36,T11N,RR14E�945'FTL&1748'FVYL DATE REV BY COMMENTS DATE REV BYCOMMBNIS 11/28176 ORgNAL COMPLETION 12X15/17 OS/JMD CMTW&CMT 7BG(1 V27M7) 11/30195 CTO SIDETRACK 12/05/17 KFMJMD TBGR RCH(12/01/17) 06/01/01 ADK CTD SIDETRACK 12/17/17 AB/JbD CMT 004, 0A & TBG TO SLWAC 06/07/17 KFS/JMD TBGRAICH(MM17) 02/19118 AS/JMD SUSPBC®(02M3/18) 06/08/17 TS/JMD BALANCECMTR-UG(06/06117 01/17/19 AWJMD EDITS TO SUSPEIDM VYBS BP 5tploration(Apska) 11/15/17 NXWJRC TBG RfNCH(11/14/17) 05/23M9 JA/.MD RLL ABAPDOPIVENT(05/08/19) JUN 0 6 AQGSuspended Well Site Inspection Form Initial Inspection C inspectors at least 10 days prior to inspection to allow witness Well Name: 02-03B Field/Pool: Prudhoe Bay / Prudhoe Oil Permit# (PTD): 20021(0 API Number: 50-029-20077-02 Operator: BP EXPLORATION (ALASKA) INC Date Suspended: 2/13/2018 Surface Location: Section: 36 Twsp: 11N Range: 14E Nearest active pad or road: DS -02 Take to Location Digital camera Brief well history Latest Sundry or Completion report Past Site Visit documentation Pressure gauges, fittings, tools Map showing well location /Aerial photos Wellbore diagram showing downhole condition Site clearance documentation Sample containers for fluids on or near pad Condition of Surface Location AOGCC requires: 1) a description of the condition of the surface location, including discoloration, fluids or sheens visible on the ground or in any nearby water, 2) photographs showing the condition of the location surrounding the well General location condition: Clean Pao or location surface: Location cleanup needed: Pits condition: Surrounding area conditio Water/fluids on pad: Discoloration, Sheens on Samples taken: None IPfiG1 Access road condition: Good Photographs taken (# and description): Sign, Gravel Pad Condition of Wellhead AOGCC requires: 1) a description of the condition of the wellhead, 2) well pressure readings, where practicable. 3) photographs showing the wellhead condition Wellhead/tree/valve description, condition: Cellar description, condition, fluids: N/A Rat Hole: N/A Wellhouse or protective barriers: Cattle Guard Well identification sign: Yes Tubing Pressure (or casing if no tubing): N/A Annulus pressures: NIA Wellhead Photos taken (# and description): N/A Work Required: None Operator Rep (name and signature): Josh Prowant AOGCC Inspector: Adam Earl Other servers: Inspection Date: 6/2/2019 AOGCC Notice Date: 6/1/2019 Time of arrival: 12:30 PM Time of Departure: 12:40 PM Site access method: Access Road wt(b t2�a .Ils�1� ,F'c r"`ams-4— '� •s � ,� i'r IF Ifs .'�, �� '�• `a- 4 �` -. � = �•' N .. �,ai- .. ,F'c r"`ams-4— '� •s � ,� 4 a ' -.L .�� ( �..r', ♦. C .moi r MEMORANDUM TO: Jim Regg 51)11,9 P. I. Supervisor FROM: Bob Noble Petroleum Inspector State of Alaska Alaska Oil and Gas Conservation Commission DATE: 5/05/2019 SUBJECT: Surface Abandonment PBU 02-03B BPXA PTD 2002170; Sundry 319-037 5-05-2019: 1 traveled to PBU 02-03B to inspect the final cut-off and marker plate for surface abandonment. I met with BP representative Rob Liddelow. The cut-off was found to be 40 inches below tundra level. The 30 -inch pipe had about 3/8 -inch of watered-down cement on top with good hard cement under that. The marker plate was the correct size and had the proper markings welded onto it. I allowed Rob Liddelow to weld the plate on and back fill the well. Attachments: Photos (2) 2019-0505_Surface_Abandon_PBU_02-03B_bn.docx Page I of 2 Surface Abandonment — PBU 02-03B (PTD 2002170) Photos by AOGCC Inspector B. Noble 5/5/2019 d.� 2019-0505_Suit'ace_Abandon_PBU_02-03B_bn.docx Page 2 of 2 THE STATE °fALASKA GOVERNOR MIKE DUNLEAVY Aras Worthington Interventions and Integrity Engineer BP Exploration (Alaska), Inc. PO Box 196612 Anchorage, AK 99519-6612 Re: Prudhoe Bay Field, Prudhoe Bay Oil Pool, PBU 02-03B Permit to Drill Number: 200-217 Sundry Number: 319-037 Dear Mr. Worthington: Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 Www. a ogc c .a la s ka.gev Enclosed is the approved application for the sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Cathy P. oerster Commis ioner DATED thisiff- Sy of February, 2019. SCANNED F:._, 0 7 2019 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FIECEIVED 07S 471P P JAN 2 9 2019 1. Type of Request. Abandon 0 Plug Perforations ❑ Fracture Stimulate ❑ Repair Well ❑ Oper, .0 Suspend ❑ Perforate ❑ Other Stimulate 11Pull Tubing ❑ Change Approve Plug for Rednll ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other ❑ 2. Operator Name: BP Exploration (Alaska), Inc 4. Current Well Class: Exploratory ❑ Development 0 5. Permit to Drill Number 200-217 3. Address: P.O. Box 196612 Anchorage, AK 99519-6612 St2tigrephic ❑ Service ❑ 6. API Number: 50-029-20077-02-00 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception? Yes ❑ No 0 PBU 02-038 9. Property Designation (Lease Number): 10. Field/Pools: r ADL 028308 & 026326 PRUDHOE BAY. PRUDHOE OIL ' 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (6)'. Total Depth TVD(ft): Effective Depth MD: EBective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 12566 9041 Surface Surface Surface None Casing Length Size MD TVD Buret Collapse Conductor 80 30" Surface -115 Surface -115 880 Surface 1184 20" Surface - 1219 Surface - 1219 1530/2320 52011500 Intermediate 2653 13-3/8" Surface -2688 Surface -2688 5380 2670 Intermediate 10518 9-5/8" Surface - 10553 Surface - 8642 8150 / 6820 / 7510 5080 / 3330 / 4130 Production Liner 2470 3 -1/2"x3 -3116"x2-718# 10095 .12565 8302-9041 Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): I None 5-1/2"17#x4-1/2"12.6# 1 N-80 Surface -10143 Packers and SSSV Type: 5-12" Baker SAB Packer Packers and SSSV MD (ft) and TVD (ft): 10005 / 8233 No SSSV Installed No SSSV Installed 12. Attachments: Proposal Summary 0 Wellbore Schematic 0 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Stratigraphic ❑ Development 0 Service ❑ 14. Estimated Date for Commencing Operations: February, 15, 2019 15, Well Status after proposed work: Oil ❑ WINJ ❑ WDSPL ❑ Suspended ❑ 16. Verbal Approval: Date: GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned 0 17. I hereby certify that the foregoing is true and the procedure approved herein will not Contact Name: Worthington, Area J be deviated from without prior written approval. Contact Email: Aras.Worthingtonabp.com Authorized Name: Worthington, Area J Contact Phone: +1 907 564 4102 Authorized Title: Interven ns 8 Integrity Engineer Authorized Signature: Date: COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity❑ BOP Test ❑ Mechanical Test ❑ Location Clearance p� 1Ir'ntegrity 11 1fI /) Other: � A.O � CCU Q.-$ (v1 -Q-1 , c a-A-'Qd� ( Yt. w� Post Initial Injection MIT Req'd? Yes ❑ No 11 Spacing Exception Required? Yes ❑ No (N Subsequent Form Required: APPROVED BYTHE Approved by: COMMISSIONER COMMISSION Date: 2 -7_ ORIGINAL ROMS FEBO$1019 MG A6(s X�81i Submit For in and Form 10-403 Revised 04/2017 Approved application is valid for 12 months from the date of approval. Attachments in Duplicate uG.B- of%o/19 by 02-03B Plug and Abandon Intervention Engineer Aras Worthington (907) 564-4102 Production Engineer Paulina Meixueiro (907) 564-5971 Expected start date: February 15'h 2019 History 02-03 was originally drilled in 1970, worked over in 1975, finally recompleted in 1976. 02-03B is a June 2001 CTD sidetrack and completed with 2-7/8" x 3-3/16" x 3-1/2" production liner. The well was a naturally flowing producer completed in the Z1A and Z1 B. An employee discovered an uncontrolled gas release from the top of the well shelter at approximately 7:30 a.m. on April 14, 2017, resulting in mobilization of the Incident Management Team. Leaks were noted from a sheared -off S -riser fitting and the tubing head adapter clamp/flange. The well was killed and the leaks stopped. The crude spray plume did not leave the well pad or adjacent reserve pit. There were no reported injuries. The well has been P&A'd with cement to surface in all tubing and annuli in 2017. The well was cut off —1' below pad level and the name cap temporarily installed. Objective Excavate and cut off all casings 3' below original tundra and permanently install well name cap. Procedural steps Special Projects p ka e ©cu.° 1. Excavate and Cutoff all casings and wellhead 3' below original tundra level. Top job all annuli and tubing with cement as needed. 2. AOGCC witness cement tops in all annuli, 3. Bead weld marker cap on outermost casing string (30" Conductor) to read as follows: BP Exploration Alaska, Inc. 02-03B PTD # 200-217 API # 50-029-20077-02 TREE= FMC 12D WELLHEAD= MCEVOY cep, _ ACTUATOR= BAKERC MNL KB. ELE 64' OF. ELEV = 11130196 CTDSIDETRACK KOP= 3100' Max Angle = 94' @ 1116T Dakar MD= 10821' Datum TVD= 88W SS SAFETY NOTES: WaL ANGLE > 70' l� ttosr. SUSPENDED 02-03B SUSPENDED- WRIIa=AD CUT V BELOW PAD GRADE, MARKER CAP INSTALLED AND BACKRI 1 (02113118) ID -12.347' Minimum ID = 2.380" @ 10612' 33116" X 2-718" XO II S-lrz' T NPC.17a, N -W..0232 6Pf, D = 4.892' H 10018' I Ras X 9-518' CSG, 479-, S0095, D = 6681' 1 -tom 1 TOPOF OLD 9-516' SDm( WIDOW - 02-03A 1 1189' H9-518- CSG PATCH I J-19-5/8' FOC 5-l12' BAKER PFVE SSSV NP. D = 4.58' D = 4.471' 3.875' SLV W/ GS t loco H.4-1/2' BAKER SFEAROUT SUB PERFORATION SL MARY 4-1/2' TUBING TAR BEHIND WI 70130' H RIF LOG: BHCS ON 08128/70 06!08/17 TS/JM) BALANCECMr RIJG(06/O6/17) 11130196 CTDSIDETRACK ANGLE AT TOP PERF: 85-@1139W 06101101 ADK CTDSIDETRACK Wle: Refer to Production DB fm historical perf data SIZE SPF NTE2VAL SHOT DATE SOZ 2' 4 11399-11500 C 05f31/01 7 4 11640-12170 C 05/31/01 2' 4 12230 - 12340 C 05131101 2- 4 12430-12500 C 05/31/01 9-518' CSG, 479-, S0095, D = 6681' 1 -tom 1 TOPOF OLD 9-516' SDm( WIDOW - 02-03A 1 1189' H9-518- CSG PATCH I J-19-5/8' FOC 5-l12' BAKER PFVE SSSV NP. D = 4.58' D = 4.471' 3.875' SLV W/ GS t loco H.4-1/2' BAKER SFEAROUT SUB 70747 4-1/2' TUBING TAR BEHIND WI 70130' H sAu TT LOGGED 03/08177 114' 1-13-12' FES EVOTREV E 9-5/8• CEMENT wNb;w 10553'- 1056W 3-3/1, 6 2#, TC2 X 2-7 8.16 80 STL XO, D = 2.380' 18' 72624' 2-7/e' 1NFHR RUG 1�1m PRIAFDE BAY LINT WELL: 02-03B PEMITW w2OM170 APINo: 50.029-20077-02 SEC36,T11NR14E,945'FN-&174&PAL DATE REV BY COMMENTS DATE FEN/ BY I COKNA94TS 11128178 OWCINALCOMPLETION 06!08/17 TS/JM) BALANCECMr RIJG(06/O6/17) 11130196 CTDSIDETRACK 11/15/17 NXWIJMD TBGFUNCH(11/14/17) 06101101 ADK CTDSIDETRACK 12!05/17 DS(JM) CMT 1A B CMT TBG (I 1127117) 04/20/17 JMG/JM) SEf EVOTREVE FLLIG(04/20/1 12/05117 KFMJMD TBGRNpI(12101/17) 06/07117 MF0JM) DUMP BAL CMr(06/01/17) 12112J17 ABIJM) CMT ODA, OA B TBG TO SURFACE 13P Egiloradon(Alaska) 06107/17 KFVJM) TBG R4CH(0610M17) 02/19/18 ABIJM) SLISPMW(02/13/18) Suspended Well In ction Review Report - alb • t 414 P11, InspectNo: susSAM 180602153953 Date Inspected: 6/2/2018 Inspector: Austin McLeod Type of Inspection: Initial Well Name: PRUDHOE BAY UNIT 02-03B Date AOGCC Notified: 6/1/2018 — Permit Number: 2002170 Operator: BP EXPLORATION (ALASKA) INC. Suspension Approval: Sundry # 317-327 — Operator Rep: Josh Prowant Suspension Date: 2/13/2018 Wellbore Diagram Avail? El Location Verified? El Photos Taken? k If Verified, How? Other(specify in comments) Offshore? LII Well Pressures (psi): Tubing: Fluid in Cellar? IA: BPV Installed? OA: VR Plug(s) Installed? 0 Wellhead Condition N/A MatiEV JUN 2 11 Condition of Cellar N/A Surrounding Surface Condition tv The wellhead was cutoff and buried 1' below PAD grade(suspension not abandonment) prior to me inspecting the area.The area was level gravel with snow and puddles from the spring thaw with no signs of seepage or sheens.The area looked identical to the remaining areas of the pad. Comments Barracaded off with proper well sign posted. A schematic and completion report and log was received with information about the suspension and PTD and Sundry numbers. Supervisor Comments Photos attached / 11-- Wednesday,June 13, 2018 • • Suspended Well Inspection—PBU 02-03B PTD 2002170 Photos by AOGCC Inspector A. McLeod 6/2/2018 , .,u...- 2 p38 . \. . .,.. , if . 5s, S�rn.- a1y' ..- d -t- - • . • • • -, . e { #� 11 . --...--,,.,,.=,-- „. \ . ,' :: \ WELLO2;O3B: .7..?,,. ,, R v. ear 0511 ..- !:' `, �. OPERATWi BV E•plora.n(AWaMei in. - - - < AM NUMBER 30-029-20017-02-00 _ .....__......_.:907 —...•” a *'y - 9 . '''.4',.•k • Q v 0 2018-0602_Suspend_PBU_02-03B photos_am.docx Page 1 of 1 LI'a ' yr STATE OF ALASKA t ALASKA OIL AND GAS CONSERVATION CO ION W�COMPLETION OR RECOMPLETION RE RT AND LOG MAR 1 3 ';°'3 la. Well Status: Oil ❑ Gas 0 SPLUG 0 Other 0 Abandoned 0 Suspended 0 ' lb.Well Classy 20AAC 25.105 20AAC 25.110 Development �l1 .1 GINJ 0 WINJ 0 WAG 0 WDSPL 0 No.of Completions: Zero 41t Service 0 Stratigraphic Test • 2. Operator Name: 6. Date Corr)p,Susp.,r Abend.: 14.Permit to Drill Number/Sundry BP Exploration(Alaska),Inc 2/13/2016-- .. 200-217 ' 317-183&317-327 3. Address: 7. Date Spudded: 15 API Number: _ P.O.Box 196612 Anchorage,AK 99519-6612 5/22/2001 50-029-20077-02-00 4a. Location of Well(Governmental Section): 8. Date TD Reached 16. Well Name and Number: 5/28/2001 PBU 02-03B • Surface: 946'FNL,1749'FWL,Sec.36,T11N,R14E,UM • 9 Ref Elevations KB 64 • 17. Field/Pool(s): Top of Productive Interval: 4075'FNL,353'FWL,Sec.31,T11N,R15E,UM GL 34.50 • BF Surface PRUDHOE BAY,PRUDHOE OIL Total Depth: 3920'FNL,822'FEL,Sec.36,T11N,R14E,UM 10. Plug Back Depth(MD/TVD): 18. Property Designation: Surface/Surface ADL 028308&028326 4b. 4b.Location of Well(State Base Plane Coordinates,NAD 27): 11. Total Depth(MD/TVD): 19. DNR Approval Number: Surface:x- 688499 • y- 5950279 • Zone - ASP 4 • 12566'/9041' • 74-017 TPI: x- 692462 y- 5947248 Zone - ASP 4 12. SSSV Depth(MD/TVD): PO Thickness of Permafrost MD/TVP: Total Depth:x- 691284 y- 5947374 Zone - ASP 4 None 1900'(Approx.) 5. Directional or Inclination Survey: Yes 0 (attached) No 0 • 13. Water Depth,if Offshore: 21. Re-drill/Lateral Top window MD/TVD: Submit electronic and printed information per 20 AAC 25.050 N/A (ft MSL) 10553'/8642' 22. Logs Obtained List all logs run and,pursuant to AS 31.05.030 and 20 AAC 25.071,submit all electronic data and printed logs within 90 days of completion, suspension,or abandonment,whichever occurs first.Types of logs to be listed include,but are not limited to:mud log,spontaneous potential,gamma ray,calipe, resistivity,porosity,magnetic resonance,dipmeter,formation tester,temperature,cement evaluation,casing collar locator,jewelry,and perforation record. Acronyms may be used.Attach a separate page if necessary MWD/GR,Mem GR/CCL/CNL 23. CASING,LINER AND CEMENTING RECORD CASING wT.PER GRADE SETTING DEPTH MD SETTING DEPTH TVD HOLE SIZE CEMENTING RECORD AMOUNT FT. PULLED TOP BOTTOM TOP BOTTOM - 30" 157.5# B Surface 115' Surface 115' 39" Fondu circulated to surface 20" 94#/133# H-40 Surface 1219' Surface 1219' 26" 1010 sx Fondu,11 Bbls AS I,56 Bbls Arctic Pack 13-3/8" 72# N-80 Surface 2688' Surface 2688' 17-1/2" 530 sx Fondu,550 sx Class'G' 9-5/8" 47#/43.5###/44#3'5# 500-95 Surface 10553' Surface 8642' 12-1/4" 1810 sx Class'G' 3-1/2"x3-3-/16" 9.3#/6.2# L-80 10095' 12565' 8302' 9041' 3-3/4" 26 Bbls LARC x2-7/8" /6.16# 24. Open to production or injection? Yes 0 No 0 25. TUBING RECORD If Yes,list each interval open(MD/TVD of Top and Bottom;Perforation GRADE DEPTH SET(MD) PACKER SET(MD/TV Size and Number): 5-1/2"17#N-80 10143' 10005'/8233' I x 4-1/2"12.6#N-BO 26. ACID,FRACTURE,CEMENT SQUEEZE,ETC. Was hydraulic fracturing used during completion? Yes 0 No 0 ' Per 20 AAC 25.283(i)(2)attach electronic and printed SCANNED JUN 1.8 2018 nryp information DEPTH INTERVAL(MD) AMOUNT AND KIND OF MATERIAL USED See Attached - 1 27. PRODUCTION TEST Date First Production: Not on Production Method of Operation(Flowing,gas lift,etc.):N/A Date of Test: Hours Tested: Production for Oil-Bbl: Gas-MCF: Water-Bbl: Choke Size. Gas-Oil Ratio: Test Period ..i► - I Flow Tubing Casing Press: Calculated Oil-Bbl: Gas-MCF: Water-Bbl: Oil Gravity-API(torr): Press 24 Hour Rate ...00' 1 Form 10-407 Revised 5/2017 CONTINUED ON PAGE 2 Submit ORIGINAL only V71- W17-Jj we RBDMS w vI4-1/I :19 e_isl./13 I 28. CORE DATA 411 Conventional Core(s) Yes 0 No E Sidewall Cores Yes 0 No IZI • If Yes to either question,list formations and intervals cored(MD+TVD of top and bottom of each),and summarize lithology and presence of oil,gas or water (submit separate sheets with this form,if needed).Submit detailed descriptions,core chips,photographs and laboratory analytical results per 20 AAC 25.071. 29. GEOLOGIC MARKERS(List all formations and markers encountered): 30. FORMATION TESTS NAME MD TVD Permafrost-Top Well Tested? Yes ❑ No Il • Permafrost-Base If yes,list intervals and formations tested,briefly summarizing test results.Attach Top of Productive Interval 11003' 9003' separate sheets to this form,if needed,and submit detailed test information per 20 AAC 25.071. Sag River 10251' 8420' Sadlerochit-Zone 4 10403' 8533' Zone 1B 11003' 9003' TDF-Zone lA 11093' 9033' Formation at total depth: Zone lA 11093' 9033' 31. List of Attachments: Summary of Daily Work,Photo Documentation,Wellbore Schematic Diagram Information to be attached includes,but is not limited to:summary of daily operations,wellbore schematic,directional or inclination survey,core analysis, paleontological report,production or well test results,per 20 AAC 25.070. 32.I hereby certify that the foregoing is true and correct to the best of my knowledge. Authorized Name: Lastufka,Joseph N Contact Name: Worthington,Aras J Authorized Title: SIM ea •st Contact Email: Aras.Worthington©bp.com Authorized Signature: Date: 3/1241 v Contact Phone: +1 907 564 4102 INSTRUCTIONS General:This form is designed for submitting a comp ete and correct well completion report and log on all types of lands and leases in Alaska.Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed. All laboratory analytical reports regarding samples or tests from a well must be submitted to the AOGCC,no matter when the analyses are conducted. Item la. Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated.Each segregated pool is a completion. Item 1 b.Well Class Service wells:Gas Injection,Water Injection,Water-Alternating-Gas Injection,Salt Water Disp,Water Supply for Injection,Observation or Other. Item 4b.TPI(Top of Producing Interval). Item 9. The Kelly Bushing and Ground Level elevations in feet above mean sea level.Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 15.The API number reported to AOGCC must be 14 digits(ex:50-029-20123-00-00). Item 20.Report true vertical thickness of permafrost in Box 20.Provide MD and TVD for the top and base of permafrost in Box 29. Item 22.Review the reporting requirements of 20 AAC 25.071 and,pursuant to AS 31.05.030,submit all electronic data and printed logs within 90 days of completion,suspension,or abandonment,whichever occurs first. Item 23.Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. Item 24.If this well is completed for separate production from more than one interval(multiple completion),so state in item 1,and in item 23 show the producing intervals for only the interval reported in item 26.(Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Item 27.Method of Operation:Flowing,Gas Lift,Rod Pump,Hydraulic Pump,Submersible,Water Injection,Gas Injection,Shut-in,or Other(explain). Item 28.Provide a listing of intervals cored and the corresponding formations,and a brief description in this box.Submit detailed description and analytical laboratory information required by 20 AAC 25.071. Item 30.Provide a listing of intervals tested and the corresponding formation,and a brief summary in this box.Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Item 31.Pursuant to 20 AAC 25.070,attach to this form:well schematic diagram,summary of daily well operations,directional or inclination survey,and other tests as required including,but not limited to:core analysis,paleontological report,production or well test results. Form 10-407 Revised 5/2017 Submit ORIGINAL Only � l - • WELL NAME: 02-03B 26. Acid, Fracture, Cement Squeeze, Etc. Depth Interval (MD) 1 Amount & Kind of Material Used 10314' Set Evotrieve Plug 10827' 10 Gallons Ultra Shear Bond Cement 9845' - 9850' Tubing Punch 8800' - 9850' 70 Bbls Class 'G' 2698' -2703' Tubing Punch 1420' 162 Bbls Class'G' 1000' - 1010' Punch through tubing, 9-5/8" and 13-3/8" Surface 320 Bbls Class'G' Surface 2.28 Bbls Cement S • Daily Report of Well Operations 02-03B ACTIVITYDATE SUMMARY LRS Unit 72 Rigged up jointly with LRS Unit 70 to tree cap of 02-01 for well control on 02-03 Pumped 51 bbls 60/40 meth toward manifold to fluid pack 02-01 flowline. Pumped additional 44 bbls 60/40 meth toward 02-03 as directed. 4/14/2017 ***WSR continued on 04/15/2017*** LRS Unit 70 Rigged up jointly with LRS Unit 72 to tree cap of 02-01 for well control on 02-03 (This unit is for contingency). Rig up, PT lines, Standby for plan forward. 4/14/2017 ***WSR conintued on 4/15/2017*** ***WSR continued from 04/14/17*** LRS Unit 72 Rigged up with LRS Unit 70 to tree cap of 02-01 for Well Control on 02-03. Pumped Freeze Protect of well 02-40 from 02-01 Treecap. 125 60/40 meth total. 4/15/2017 ***WSR continued on 04/16/2017*** **WSR continued from 04/14/17*** LRS Unit 70 Rigged up with LRS Unit 72 to 02-01 treecap for Well Control on 02-03 (This unit is for contingency) Standby for plan forward. 4/15/2017 ***WSR continued on 4/16/2017*** ***WSR continued from 04/15/17***** Unit 70 and unit 72 rigged up jointly to tree cap of well 02-01 to kill well 02-03 through manifold building drain header. Unit 72 is primary pump unit while unit 70 is to assist at higher pump rates if necessarry. Stand by for plan forward. 4/16/2017 ***WSR continued on 04/17/17*** ***WSR continued from 04/15/17*** T/I/O= 2350/800/800 Unit 72 and 70 rigged up jointly to tree cap of well 02-01 to kill well 02- 03 through manifold building drain header. Unit 72 is primary pump unit while unit 70 to assist at higher pump rates if necessarry. Standby for plan forward. 4/16/2017 ***WSR continued on 4/17/2017*** ***WSR continued from 04-16-17*** Unit 70 & 72 sequentailly pumped 580 bbls, 85*F, 1% kcl down 02-03 TBG from 02-01 tree cap through drain header at 5 bpm to kill well. Shut down and monitored static well for a response. No pressure increase, unit 72 resumed pumping 1% kcl down TBG at 2 bpm to control well pressure. Unit 70 pumped a total of 1535 bbls of 1% Kcl throughout the day to control pressure, unit 72 pumped a total of 1557 bbls for a combined total of 3092 bbls over 4/17/2017 24 hours. ***WSR continued on 04-18-17*** T/I/O = SSV/862/SI. Monitor& bleed IAP, OAP if needed. (Well Kill). IA&OA FL's @ Surface. Bled IAP from 862 psi to 0 psi in 2 hours 48 minutes, 5.29 bbl of fluid returned. Continue open bleed on IA. 4/17/2017 WSR continued on 4/18/17. ***WSR continued from 4/16/2017*** LRS#72: Pumped 27.5 bbls of 60/40 meth to pressure test 02-01 to 02-03 flowlines through manifold building and bull plug in S-Riser to 2500 psi. Pumped 50 bbls of 1% KCL to displace 02-01 flowline to drain header in manifold building. After displacemet, lined up down 02-01 flowline to 02-03 wellhead with 1% KCL. Pumped 7 bbls to pressure up FL to equialize with TBG psi and opened SSV. After SSV open, pumped @ 5 bpm to kill well. Pumped 250 bbls of 1% KCL before LRS unit 70 took over. Unit 70 pumped 300 bbls @ 5 bpm. Unit 72 took back over and pumped 30 bbls @ 5 bpm for a total of 580 bbls for well kill. SD pumps for 2 min to monitor WHP (-10 psi). Continued pumping 1%KCL at 2 bpm, alternating between unit 72 and unit 70 as transports were emptied. Pumped a total of 3042 bbls of 1% KCL by midnight. Continued pumping beyond midnight. See LRS unit 70 and 72 log for rate details. 4/17/2017 ***WSR continued on 4/18/2017*** • Daily Report of Well Operations 02-03B ***WSR continued from 04-17-17*** Pumped 17 bbls 60/40 down 02-03 flowline to pressure test new double stacked swab valve. LRS unit 70 pumped 1,228 bbls 1% kcl, LRS unit 72 pumped 1,384 bbls 1% kcl for a combined daily total of 2,612 bbls to manage well bore pressure. Current job total pumped 4/18/2017 away equals 5,654 bbls 1% kcl. ***LRS IN CONTROL OF WELL ON ARRIVAL***(secure well) RIG UP SWCP 4522 4/18/2017 ***CONT ON 4-19-17 WSR*** ***LRS IN CONTROL OF WELL ON ARRIVAL***(secure well) RIG UP SWCP 4522 4/18/2017 ***CONT ON 4-19-17 WSR*** WSR continued from 4/17/17. T/I/O = SSV/862/SI. Monitor& bleed IAP, OAP as needed. (Well Kill). IA& OA FLs @ surface. Bled IAP from 862 psi to 0 psi in 2 hrs &48 mins (5.29 bbls). Continue open bleed on IA, IAP increases in pressure when bleed is shut in. 4/18/2017 WSR continued on 4/19/17. ***WSR continued from 4/17/2017 (WELL SECURE) Continue pumping 1% KCL to secure well. Pumped 3042 bbls down TBG before midnight. LRS units combined pumped an additioinal 2612 bbls of 1% KCL (5654 total to secure well) Pumped 11 bbls of 60/40 meth throughout the process to FP surface lines as needed. Continue pumping through midnight. 4/18/2017 See LRS unit 70 and 72 log for pump rate details. ***Job continued to 4/19/2017. WSR continued from 4/18/17. T/I/O = SSV/862/SI. Monitor& bleed IAP, OAP as needed. (Well Kill). IA&OA FLs @ surface. Bled IAP from 862 psi to 0 psi in 2 hrs &48 mins (5.29 bbls). Continue open bleed on IA, IAP no longer increases in pressure when bleed is shut in —2 min. 4/19/2017 SL in control of well upon departure. ***WSR Continud from 04/18/17 *** LRS unit 70 pumped 616 bbls 1% kcl, LRS unit 72 pumped 320 bbls 1% kcl for a combined dailey total of 936 bbls to manage well bore pressure. Job total pumped away equals 6,590 bbls 1% kcl. Unit 70 pumped 49 bbls 60/40 to reach test pressure of 250 psi while unit 72 recorded test. See unit 72 AWGR's for test results. Freeze protected F/L of 02-01 and 02-03 and tbg of 02-01 with 160 bbls 60/40. Unit 72 will monitor well head pressure and standy as site control for 24 hrs. Unit 70 remained rigged up to 02-01 to serve as well kill truck with unit 72 as a contingency. 4/19/2017 ***WSR continued on 04/20/17*** ***CONT FROM 4-18-17 WSR***(Secure Well) DRIFTED INTO 3-1/2" LINER W/ 10'x 2.70" EVO-TRIEVE DRIFT&2.805" CENT.(no issues) TAGGED 3-3/16"XO @ 10358' SLM/ 10359' MD(+1' correction). SET 3.5" HES EVO-TRIEVE PLUG @ 10,314' MD. LRS PERFORMED PASSING PRESSURE TEST 4/19/2017 ***WELL LEFT IN LRS CONTROL*** ***WSR continued from 4/19/2017*** Continue pumping 1% KCL to secure well. LRS units combined pumped 2612 bbls before midnight(5654 bbls total since well kill started) LRS units combined pumped an additioinal 936 bbls of 1% KCL (6590 total to secure well) Pumped 4 bbls of 60/40 Meoh throughout the process to FP surface lines as needed. LRS unit 70 pumped 160 bbls of 60/40 Meoh to freeze protect from 02-01 wellhead, through flowlines and down the TBG of 02-03. See LRS unit 70 and 72 log for pump rate details. SL set tubing plug. LRS unit 70 pumped 49 bbls of 60/40 Meoh to fill TBG volume and test plug. ***SEE LOG FOR PLUG SET/TEST 4/19/2017 DETAILS*** • Daily Report of Well Operations 02-03B SET 3-1/2" HES EVO-TRIEVE @ 10,314' MD 05/21/17: HES EVOTRIEVE MONTHLY RENTAL FOR 05/2017 - 06/2017. MO 2 (TH) 4/19/2017 11/03/17: PLUG PURCHASED - PAID IN FULL 04/19/17 SL AWGRS. (CF) ***WSR Continued from 04/19/17 *** Unit 70 & 72 will monitored well head pressures and stoodby to serve as contingent well kill 4/20/2017 trucks. Released and rigged down. FWHP's=167/6/6 ***WSR continued from 4/19/2017. LRS unit 70 and 72 continue to standby to monitor T/I/O pressures for change. T/I/O= 171/4/4. TP increased 1 psi, IAP increased 1 psi, OAP increased 3 psi in an 8 hour period. FWHP= 172/5/7. DHD to continue monitoring pressure. IMT had site control upon departure. WV= closed. SSV, Double SV, MV= open. IA/OA= 4/20/2017 OTG. T/I/O = 143/15/0. Temp = SI. Well secure. Monitored WHPs post load and kill and plug set. No leaks noted on wellhead. 4/20/2017 WSR continued on 4/21/17. WSR continued from 4/20/17. T/I/O = 143/15/0. Temp = SI. Well secure. Monitored WHPs post load and kill and plug set. No leaks noted on wellhead. 4/21/2017 WSR continued on 4/22/17. WSR continued from 4/21/17. Well secure. Monitored WHPs post load and kill and plug set. No leaks noted on wellhead. 4/22/2017 Cont on WSR 4/23/17. Cont from WSR 4/22/17. T/I/O = 143/15/0. Temp = SI. Well secure. Monitored WHPs post load and kill and plug set. No leaks noted on wellhead. 4/23/2017 Cont on WSR 4/24/17. Cont from WSR 4/23/17. T/I/O = 5/21/23. Temp = SI. Well secure. Monitored WHPs post load and kill and plug set. Clean Greyloc clamp on tubing head adaptor. 9 of the nuts from the 8 o'clock position to the 4 o'clock position are loose. Flowline was resting 12" under the back of the wellhouse tear and -22" from the bottom of the 6.65" flowline to the center of the original opening. No leaks noted on wellhead. 4/24/2017 Cont on WSR 4/25/17. Cont from WSR 4/24/17. T/I/O = 5/21/23. Temp = SI. Well secure. Monitored WHPs post load and kill and plug set. No leaks noted on wellhead. Remove sheet metal shroud from top of conductor, clean inside conductor and 20" casin pin and box, video and caliper 20" casing pin and box, No visual damage to 20" pin or box was noted although some of the pin threads appear to be 'rounded'. 4/25/2017 Cont on WSR 4/26/17. Cont from WSR 4/25/17. T/I/O = 7/22/24. Temp = SI. Well secure. Monitored WHPs post load and kill and plug set. No leaks noted on wellhead. 4/26/2017 Cont on WSR 4/27/17. Cont from WSR 4/26/17. T/I/O = 7/22/24. Temp = SI. Well secure. Monitored WHPs post load and kill and plug set. No leaks noted on wellhead. 4/27/2017 Cont on WSR 4/28/17. Cont from WSR 4/27/17. T/I/O = 6/26/23. Temp = SI. Well secure. Monitored WHPs post load and kill and plug set. No leaks noted on wellhead. 4/28/2017 Cont on WSR 4/29/17. Cont from WSR 4/28/17. T/I/O = VAC/27/25. Temp = SI. Well secure. Monitored WHPs post load and kill and plug set. No leaks noted on wellhead. 4/29/2017 Cont on WSR 4/30/17. • Daily Report of Well Operations 02-03B T/I/O =VAC/27/25. Torqued 7-1/16" x 5-1/8" FMC 120 tree to API specs; ( MV x THA, MV x SSV, SSV x FC, FC x WV). Calibrated Hytorc#32-024 @ API shop; L7M 5850 PSI = 769 ft- lbs., L7 red coated 5750 PSI = 739 ft-lbs. Documented in API torque log book. Arrived at Location. Opened HWSP permit&conducted TBT/reviewed risk assesment w/DSO & crew. Torqued THA x MV to API spec; L7M, 769 ft-lbs. Stud movement as followed; #1 - 1- 1/4, #2 - 3/4, #3 - 1/2, #4 - 1/4, #5 - 1/6, #6 - 1/6, #7 - 0, #8 - 1/12, #9 - 1/6, #10 - 1/2, #11 - 1/2, #12 - 1-1/4. Torque record retained in TRP folder.Torqued MV x SSV to API spec; L7 red coated, 739 ft-lbs. Stud movement as followed; #1 - 3/8, #2 - 1/4, #3 - 1/6, #4 - 1/6, #5 - 1/8, #6 -0, #7 - 1/6, #8 - 1/6, #9 - 1/6, #10 - 1/4, #11 - 1/3, #12 - 1/3. Torque record retained in TRP folder.Torqued SSV x FC to API spec; L7 red coated, 739 ft-lbs. Stud movement as followed; #1 - 1/4, #2 - 1/6, #3 - 1/12, #4 - 1/12, #5 - 1/12, #6 - 1/12, #7 - 1/12, #8 - 1/6, #9 - 1/6, #10 - 1/6, #11 - 1/6, #12 - 1/3. Torque record retained in TRP folder.Torqued FC x WV to API spec; L7 red coated, 739 ft-lbs. Stud movement as followed; #1 - 1/6, #2 - 1/12, #3 - 1/12, #4 - 1/12, #5 - 0, #6 - 0, #7 - 0, #8 - 1/12, #9 - 1/12, #10 - 1/6, #11 - 1/6, #12 - 1/6. Torque record retained in TRP folder.. RDMO. ***JOB COMPLETE***. FWHP's = 4/29/2017 VAC/27/25. Cont from WSR 4/29/17. T/I/O = VAC/27/25. Temp = SI. Well secure. Monitored WHPs post load and kill and plug set. No leaks noted on wellhead. 4/30/2017 Cont on WSR 5/1/17. Cont from WSR 4/30/17. T/I/O = 12/28/29. Temp = SI. Well secure. Monitored WHPs post load and kill and plug set. No leaks noted on wellhead. 5/1/2017 Cont on WSR 5/2/17. Cont from WSR 5/1/17. T/I/O = 12/28/29. Temp = SI. Well secure. Monitored WHPs post load and kill and plug set. No leaks noted on wellhead. 5/2/2017 Cont on WSR 5/3/17. Cont from WSR 5/2/17. T/I/O = 15/30/30. Temp = SI. Well secure. Monitored WHPs post load and kill and plug set. No leaks noted on wellhead. 5/3/2017 Cont on WSR 5/3/17. Cont from WSR 5/3/17. T/I/O = 14/31/31. Temp = SI. Well secure. Monitored WHPs post load and kill and plug set. No leaks noted on wellhead. 5/4/2017 Cont on WSR 5/5/17. Cont from WSR 5/4/17. T/I/O = 13/33/32. Temp = SI. Well secure. Monitored WHPs post load and kill and plug set. No leaks noted on wellhead. BPV installed in Well. 5/5/2017 Cont on WSR 5/6/17 T/I/O = 33/33/33. Set 5" Tree test plug#527 @160", PT'd tree to 350/2500 PSI (Pass). Pulled 5" Tree test plug#527 @160". Set 5" BPV#538 @160", Performed LTT on BPV 5/5/2017 (Pass). RDMO. ***Job Complete*** FWPs = BPV/33/33. See log for details. Cont from WSR 5/5/17. T/I/O = BPV/31/33. Temp = SI. Well secure. Monitored WHPs post load and kill and plug set. No leaks noted on wellhead. Scaffolding crew removed temporary scaffolding from inside wellhouse. 5/6/2017 Cont on WSR 5/7/17. Cont from WSR 5/6/17. T/I/O = BPV/32/35. Temp = SI. Well secure. Monitored WHPs post load and kill and plug set. No leaks noted on wellhead. Scaffolding crew removed temporary scaffolding from inside wellhouse. 5/7/2017 Cont on WSR 5/8/17. Cont from WSR 5/7/17. T/I/O = BPV/32/35. Temp = SI. Well secure. Monitored WHPs post load and kill and plug set. No leaks noted on wellhead. Scaffolding crew removed temporary scaffolding from inside wellhouse. 5/8/2017 Cont on WSR 5/9/17. S • Daily Report of Well Operations 02-03B Cont from WSR 5/8/17. T/I/O = BPV/34/37. Temp = SI. Well secure. Monitored WHPs post load and kill and plug set. No leaks noted on wellhead. Scaffolding crew removed temporary scaffolding from inside wellhouse. 5/9/2017 Cont on WSR 5/10/17. Cont from WSR 5/9/17. T/I/O = BPV/35/37. Temp = SI. Well secure. Monitored WHPs post load and kill and plug set. No leaks noted on wellhead. Scaffolding crew removed temporary scaffolding from inside wellhouse. Wellhouse removed. 5/10/2017 Cont on WSR 5/11/17. Cont from WSR 5/10/17. T/I/O = BPV/36/38. Temp = SI. Well secure. Monitored WHPs post load and kill and plug set. No leaks noted on wellhead. Scaffolding crew removed temporary scaffolding from inside wellhouse. 5/11/2017 Cont on WSR 5/12/17. Cont from WSR 5/11/17. T/I/O = BPV/37/39. Temp = SI. Well secure. Monitored WHPs post load and kill and plug set. No leaks noted on wellhead. Scaffolding &wellhouse has been removed. 5/12/2017 Cont on WSR 5/13/17. Cont from WSR 5/12/17. T/I/O = BPV/38/40. Temp = SI. Well secure. Monitored WHPs post load and kill and plug set. No leaks noted on wellhead. Scaffolding &wellhouse has been removed. 5/13/2017 Cont on WSR 5/14/17. Cont from WSR 5/13/17. T/I/O = BPV/38/40. Temp = SI. Well secure. Monitored WHPs post load and kill and plug set. No leaks noted on wellhead. Scaffolding &wellhouse has been removed. 5/14/2017 Cont on WSR 5/15/17. Cont from WSR 5/14/17. T/I/O = BPV/40/42. Temp = SI. Well secure. Monitored WHPs post load and kill and plug set. No leaks noted on wellhead. Scaffolding &wellhouse has been removed. 5/15/2017 SSV= C. IA, OA= OTG. 17:30 T/I/O = BPV/40/43. Temp = SI. WHPs (eval secure). Scaffold &wellhouse has been removed. No leaks seen or heard @ this time. Crystal battery @ 25%. 5/16/2017 SSV= C. SV, SV, WV, MV= ?. IA, OA= OTG. 04:30 T/I/O = BPV/41/44. Temp = SI. WHPs (eval secure). Scaffold &wellhouse has been removed. No leaks seen or heard @ this time. Crystal batteries replaced. IAP & OAP increased 1 psi in 11 hrs. 5/16/2017 SSV= C. SV, SV, WV, MV= ?. IA, OA= OTG. 15:30 T/I/O = BPV/42/45. Temp = SI. WHPs (eval secure). Scaffold &wellhouse has been removed. No leaks seen or heard @ this time. IAP & OAP increased 1 psi overnight. 5/17/2017 SSV= C. SV, SV, WV, MV= ?. IA, OA= OTG. 16:20 T/I/O = SSV/41/44. Temp = SI. WHPs (eval secure). No AL. Flowline, scaffold, and wellhouse has been removed. No leaks seen or heard @ this time. IAP & OAP unchanged in 8 hrs 30 min. 5/17/2017 SSV= C. IA, OA= OTG. 00:00 T/I/O = SSV/43/46. Temp = SI. WHPs (eval secure). No AL. Flowline, scaffold, and wellhouse has been removed. No leaks seen or heard @ this time. IAP unchanged & OAP increased 1 psi in 16 hrs. 5/18/2017 SSV= C. IA, OA= OTG. 16:00 T/I/O = SSV/43/45. Temp = SI. WHPs (eval secure). No AL. Flowline, scaffold, and wellhouse has been removed. No leaks seen or heard @ this time. IAP increased 1 psi & OAP unchanged in 12 hrs 40 min. 5/18/2017 SSV= C. IA, OA= OTG. 00:00 • • Daily Report of Well Operations 02-03B T/I/O = SSV/43/46. Temp = SI. WHPs (eval secure). No AL. Flowline, scaffold, and wellhouse has been removed. No leaks seen or heard @ this time. WHPs unchanged in 13 hrs 30 min. 5/19/2017 SSV= C. IA, OA= OTG. 05:30 T/I/O = SSV/44/47. Temp = SI. WHPs (eval secure). No AL. Flowline, scaffold, and wellhouse has been removed. No leaks seen or heard @ this time. IA& OA increased 1 psi in 9 hrs. 5/19/2017 SSV= C. IA, OA= OTG. 14:30 T/I/O = SSV/44/46. Temp = SI. WHPs (eval secure). No AL. Flowline, scaffold, and wellhouse has been removed. No leaks seen or heard @ this time. IAP unchanged, OAP decreased 1 psi in 15 hrs. 5/20/2017 SSV= C. IA, OA= OTG. 05:30 T/I/O = SSV/45/47 Temp = SI. WHPs (eval secure). No AL. Flowline, scaffold, and wellhouse has been removed. No leaks seen or herd @ this time. IAP & OAP increased 1 psi overnight. 5/21/2017 SSV= C. IA, OA= OTG. 05:00 T/I/O = SSV/46/48 Temp = SI. WHPs (eval secure). No AL. Flowline, scaffold, and wellhouse has been removed. No leaks observed at this time. IAP & OAP increased 1 psi in 10.5 hrs. Measurement @ 12 o'clock position on 20 " casing = -7 3/8". 5/21/2017 SSV= C. IA, OA= OTG. 15:30. T/I/O = SSV/47/49 Temp = SI. WHPs (Eval secure). No AL. Scaffold, and wellhouse has been removed. No visible leaks detected. IAP and OAP increased 2 psi since 03:00 this morning. SSV= C. IA, OA= OTG. 14:50 5/22/2017 T/I/O = SSV/45/47 Temp = SI. WHPs (eval secure). No AL. Flowline, scaffold, and wellhouse has been removed. No leaks seen or herd @ this time. IAP & OAP unchanged overnight. 5/22/2017 SSV= C. IA, OA= OTG. 03:00 T/I/O = SSV/51/48 Temp = SI. WHPs (eval secure). No AL. Flowline, scaffold, and wellhouse has been removed. Crew on site removing flowline at this time. No leaks observed at this time. IAP increased 4 psi & OAP decreased 1 psi in 11 hrs. Measurement @ 12 o'clock position on 20 " casing = -7 1/8". 5/23/2017 SSV= C. IA, OA= OTG. 15:00. T/I/O = SSV/47/49. Temp = SI. WHIPs (eval secure). Scaffold, floor and wellhouse removed. No leaks seen or heard at this time. IAP & OAP unchanged since 14:50 5/22/17 -12 hrs. 5/23/2017 SSV= C. IA, OA= OTG. 04:00 T/I/O = SSV/48/51. Temp = SI. WHPs (eval secure). No AL. Well is disconnected from the system, no flow line, scaffolding or well house. WHPs unchanged. 5/24/2017 SSV= C. IA, OA= OTG. 05:00 T/I/O = SSV/49/53. Temp = SI. WHPs (eval secure). No AL. Well is disconnected from the system, no flow line, scaffolding or well house. IAP increased 1 psi and the OAP increased 2 psi since 05:00 this morning. SSV= C. IA, OA= OTG. 17:00 5/24/2017 T/I/O = SSV/49/52. Temp = SI. WHPs (eval secure). No AL. Well is disconnected from the system, no well house, flow line, scaffolding. IAP unchanged, OAP decreased 1 psi. 5/25/2017 SSV= C. IA, OA= OTG. 05:00 . • Daily Report of Well Operations 02-03B T/I/O = SSV/50/53. Temp = SI. WHPs (eval secure). No AL. Well is disconnected from the system, no flow line, scaffolding or well house. IAP increased 1 psi and the OAP increased 1 psi since 05:00 this morning. 5/25/2017 SSV= C. IA, OA= OTG. 17:00 T/I/O = SSV/51/54. Temp= SI. WHPs (eval secure). No AL. Well is disconnected from the system, no flow line, scaffolding or well house. IAP increased 1 psi and the OAP increased 1 psi overnight SSV= C. IA, OA= OTG. 10:30 5/26/2017 T/I/O = SSV/53/57. Temp = SI. WHPs (eval secure). Well is disconnected from the system, no flow line, scaffolding or well house. IAP increased 2 psi and the OAP increased 3 psi overnight. Measurement @ 12 o'clock position on 20" casing = 7 1/4". 5/28/2017 SSV= C. IA, OA= OTG. 17:00. T/I/0 = SSV/53/56. Temp = SI. WHPs (eval secure). Flowline, scaffold and wellhouse disconnected. IAP increased 2 psi and the OAP increased 3 psi overnight. Measurement @ 12 o'clock position on 20" casing = 7 1/4". 5/29/2017 SSV= C. IA, OA= OTG. 01:30 T/I/O = SSV/54/56. Temp= SI. WHPs (Eval secure). Wellhouse, flooring, scaffold, ladder and flowline removed. IAP increased 1 psi since 01:30 this morning. No evidence of leaks on tree or wellhead. No fluid in cellar. 5/29/2017 SSV= C. IA, OA= OTG. 16:30 T/I/O = BPV/55/58. Pulled 5" FMC ISA BPV#538 tagging at 157". (See Log). Final T/I/O = 5/30/2017 0/55/58. RDMO ***Job Complete*** T/I/O = SSV/54/57. Temp = SI. WHPs (Eval secure). Wellhouse, flooring, scaffolding, ladder and flowline removed. IAP unchanged, OAP increased 1 psi. No evidence of leaks on tree or wellhead. No fluid in cellar. 5/30/2017 SSV= C. IA, OA= OTG. 05:00 T/I/O = SSV/55/58. Temp = SI. WHPs (Eval secure). Wellhouse, flooring, scaffolding, ladder and flowline removed. IAP &OAP increased 1 psi since 05:00 this morning. No evidence of leaks on tree or wellhead. No fluid in cellar. Scaffolding being built around well. SSV= C. IA, OA= OTG. 14:50 5/30/2017 T/I/O = SSV/55/58. Temp= SI. WHPs (Eval secure). Wellhouse, flooring, scaffolding, ladder and flowline removed. IAP increased 1 psi, OAP increased 1 psi. No evidence of leaks on tree or wellhead. No fluid in cellar. 5/31/2017 SSV= C. IA, OA= OTG. 00:00 ***WELL SHUT IN ON ARRIVAL***(SLB ELINE - DUMP BAIL CEMENT) INITIAL T/I/O : 0/0/0 PSI RU/PT. LPT 280 PSI. HPT 3400 PSI. 5/31/2017 ***JOB CONTINUED 01-JUN-2017*** T/I/O = SSV/57/59. Temp = SI. WHPs (Eval secure). Wellhouse, flooring, scaffolding, ladder and flowline removed. IAP increased 2 psi, OAP increased 1 psi overnight. No evidence of leaks on tree or wellhead. No fluid in cellar. 5/31/2017 SSV= C. IA, OA= OTG. 22:35 T/I/O = 2/56/59. Temp= SI. WHPs (Eval secure). No AL, wellhouse or flowline. Temporary scaffolding installed. BPV removed. IA&OAP increased 1 psi sonce 5-30-17. 5/31/2017 SV, 2nd SV, WV= C. SSV, MV= O. IA, OA= could not reach. 1055 hrs. • • Daily Report of Well Operations 02-03B ***JOB CONTINUED FROM 31 MAY 2017 (SLB ELINE DUMP BAIL CEMENT) INITIAL T/I/O FROM 31 MAY 2017 = 0/0/0 RUN 1: HEAD/ERS/CCL/40' X 2-1/8" DUMP BAILER FILLED W/5 GAL ULTRA SHEAR BOND CEMENT 15.8 PPG. DUMP BAIL CEMENT ON TOP OF EVOTRIEVE PLUG AT 10314'. ESTIMATED TOC —10300.3'. RUN 2: HEAD/ERS/CCL/40' X 2-1/8" DUMP BAILER FILLED W/5 GAL ULTRA SHEAR BOND CEMENT 15.8 PPG. DUMP BAIL CEMENT. ESTIMATED TOC —10286.6'. ***10 GALLONS CEMENT TOTAL*** FINAL T/I/O = 0/0/0 6/1/2017 ***JOB COMPLETE. WELL LEFT SHUT IN ON DEPARTURE*** T/I/O = 3/63/59. Temp = SI. WHPs (Eval secure). Scaffold installed around wellhead to treecap. IAP increased 6 psi overnight. No evidence of any new leaks on tree or wellhead. Cellar is dry. 6/1/2017 SV1, SV2, WV= C. SSV, MV= 0. IA, OA= OTG. 16:30. T/I/O = 3/61/63. Temp = SI. WHPs (Eval secure). Scaffold installed around wellhead to treecap. IAP decreased 2 psi, OAP increased 4 psi overnight. No evidence of any new leaks on tree or wellhead. Cellar is dry. SV1, SV2, WV= C. SSV, MV= 0. IA, OA= OTG. 15:40 6/2/2017 T/I/O = 3/61/63. Temp = SI. WHPs (eval secure). Scaffolding installed around wellhead to tree cap. No changes in WHPs. No sign of any new leaks on tree or wellhead. Cellar is dry. 6/3/2017 SV1, SV2, WV= C. SSV, MV= 0. IA, OA= OTG. 03:30 T/I/O = 10/62/64. Temp = SI. MIT-T PASSED to 964 psi. (8th attempt) (Post Cement Dump). Max applied = 1000 psi. Target= 900 psi. TBG FL @ 646', (15 bbl). Pumped 19.2 bbl of Diesel to achieve test pressure for 1st test. On 8th test TP lost 21 psi in the first 15 minutes and 15 psi in second 15 min fora total loss of 36 psi in 30 min. Bled TP to BT from 964 psi to 10 psi in 10 min (1.23 bbls). Tags hung. Final WHP's = 10/74/72. 6/4/2017 SV1, SV2, WV= C. SSV, MV= 0. IA, OA= OTG. 10:30. ***WSR continued from night shift*** T/I/O = 818/74/72. Temp = SI. MIT-T. (Post Cement Dump). Bled TP from psi to psi in min ( bbls). Tags hung. Final WHPs =//. 6/4/2017 SV= C. WV, SSV, MV= 0. IA, OA= OTG. :. ***WELL SHUT-IN ON ARRIVAL*** (SLB E-LINE TUBING PUNCH) INITIAL T/I/O=0/100/75 RIH W/ HEAD/SWIVEL/CCL/MPD/BOW SPRING DE-CENTRALIZER/5' X 1.56" TUBING PUNCHER, 4 SPF, 0 DEG PHASE/SPD, SMALL CHARGES. TUBING PUNCH ACROSS COLLAR FROM 9845' -9850'. GOOD INDICATION, TUBING PRESSURE INCREASE 70 PSI. TIE INTO ARCO ALSASKA TUBING TALLY DATED: 28-NOV-1976. FINAL T/I/0=70/70/75 6/4/2017 ***JOB COMPLETE. WELL S/I UPON DEPARTURE** T/I/0=53/64/55/-2 Temp=SI Circ Out w/9.8 brine (PLUG AND ABONDONMENT- RESERVOIR) Pumped 5 bbls 60/40 meth and 115 bbls of 9.8 NaCI down Tbg into IA and out 6/5/2017 to tanks for pre-cement circ out***Job Cont to 06-06-2017 WSR*** T/I/O = SSV/70/72. Temp = SI. WHP's. (Eval Secure). IAP decreased 4 psi, No change in OAP overnight. 6/5/2017 SV, WV, SSV= C. MV= 0. IA, OA= OTG. 04:50 ***Job Cont from 06-05-2017 WSR*** Circed 545 bbls (660 bbls total) 9.8 NaCL down Tbg into IA and out to open top tank. DSO notified of well status per LRS departure. 6/6/2017 FWHP's=vac/0/0/vac SV,SV,SSV=C MV=O IA,OA,00A=OTG Choke trailer= SI • • Daily Report of Well Operations 02-03B T/I/O = SSV/3/2. Temp = SI. WHP's. (Eval Secure). 2" hardline and choke connected to TBG and IA. IAP &OAP decreased 70 psi overnight. 6/6/2017 SV, WV, SSV= C. MV= O. IA= C (flagged). OA= OTG. 05:00 SLB Cementing Services. Job Scope: Fullbore balanced cement plug (P&A). Pumped down TBG through punched holes @ 9845-9850' MD and up IA leaving cement top @ -8800' MD in TBG/IA. Cement wet at 12:15 hours and in place at 14:15 hours. Location secured, tags hung on Master and IA CSG valve. Valve crew contacted to service tree valves. NOTE: 100221 (10- 60) compliance info on "Fluids" tab. Fluids calculated in TBG as follows: 9.8 ppg Brine - Surface to 8060' MD/6767' TVD Fresh Water- 8060' MD to 8146' MD/6828' TVD Mud Push - 8146' MD to 8577' MD/7137' TVD Fresh Water- 8577' MD to 8793' MD/7301' TVD Cement- 8793' MD to 9850' MD/8115'TVD 6/6/2017 ***Job Complete*** T/I/O = ONacNac. Temp = SI. TBG FL. (Pre-MIT). TBG & IA FL's = Near surface. IA lost 3 psi, OAP lost 2 psi in 4 days. 6/10/2017 SV, SV, WV. SSV= C. MV= O. IA, OA= OTG. 20:00. ***WELL S/I ON ARRIVAL*** (plug and abandonment- reservoir). TAG TOC (STATE WITNESSED) W/2-1/2" SAMPLE BAILER @ 8,532' SLM (recovered —3 cups of wet cement). 6/11/2017 ***WELL S/I ON DEPARTURE*** (pad op notified=job complete, well &well head status). T/I/O = 55NacNac. Temp = SI. CMIT -TxIA PASSED to 958 psi (post P&A). Max 1000 psi, Target 900 psi. Tbg FL @ surface & IA FL near surface. Used 4.7 bbls of DSL to pressure up Tbg/IA to 1002/1000 psi. During increase on Tbg/IA the OA tracked. TBG & IA decreased 35/37 psi in the 1st 15 mins & 8/5 psi in the 2nd 15 min for a total loss of 43/42 psi in 30 mins. Bled Tbg/IAP to 0+/0+ psi (1.9 bbls). Hung Tags. Final WHPs = 0+10+10+. SV, WV, SSV= C. SV(2nd swab unable to close due to scaffold), MV= O. IA, OA= OTG. 6/15/2017 14:30 T/I/O = 10/10/10. Temp = SI. WHPs (Post CMIT). Fluid level in the conductor is 80-1/2" from the top of the conductor. TP, IAP, OAP increased 10 psi overnight. 6/16/2017 SSV, WV, SV= C. MV= O. IA, OA= OTG. 09:00. ***WELL SHUT-IN ON ARRIVAL*** (SLB E-LINE TUBING PUNCH) SPOT IN, RIG UP, PT RIH .23 CABLE W/ MH-22 (1.375" FN)/WEGHT X 2/CCL/MPD/5' X 1.56"TUBING PUNCHER (SMALL CHARGES)/SPD. PUNCH TUBING FROM 2698' -2703'; CCL TO TS = 5.7'; CCL STOP DEPTH = 2692.3'. POOH. TIE INTO TUBING TALLY DATED 11-28-1976. RD. WELL SI ON DEPARTURE. FINAL T/I/O = 0/0/0. PAD OP NOTIFIED. 11/14/2017 ***JOB COMPLETE 14-NOV-2017*** T/I/O = SSV/10/10. Temp = SI. Cement C & B lines. (Secure). Pumped 14 ppg 11/16/2017 SqueezeCrete down SSSV lines. Return to pressure test in 72 hours ***Job Complete*** T/I/O = SSV/10/10. Temp = SI. PT C & B lines (Pre P&A). No wellhouse or flowline. Dryhole tree installed. Temporary scaffolding installed. Control and balance lines passed their PT's. 11/20/2017 SV, 2nd SV= C. IA, OA, OOA= OTG. 0950 hrs. • • Daily Report of Well Operations 02-03B SLB Fullbore Pumping Crew. Job Scope: Plug &Abandonment cement down 5 1/2" TBG & up 9 5/8" IA to surface. Pumped 5 bbl fresh water spacer then pumped 160 bbls of 15.8 ppg cement. Swapped to fresh water spacer(2 bbls) shut down and launched 7" foam ball. Pumped 29 bbls of 9.8 ppg brine, 4 bbls of 60/40 methanol. shut down and secure well. Call and have tree serviced. Cement in IA from 2700' MD/2700' TVD to Surface Cement in TBG from 2700' MD/2700'TVD to 1506' MD/ 1506'TVD 9.8 ppg NaCI in TBG from 1506' MD/ 1506' TVD to 186' MD/ 186'TVD 60/40 Methanol Water in TBG from 186' MD/ 186' TVD to Surface Foam ball in TBG at 1420' MD/ 1420'TVD 11/27/2017 ***Job Complete*** ***WELL SHUT IN ON ARRIVAL***(P&A) TAGGED TOP OF CEMENT @ 1368' SLM (state witnessed) 11/28/2017 ***DSO NOTIFIED*** T/I/O/OO. Pre P&A. Removed 3" OOA tapped bull plug and installed 3"x 2" reducer and 1502 11/29/2017 pin and cap. PT to 2000 psi. Pass. ***Job Complete***See log. Final WHP's 0/0/0/0. ***JOB STARTED 30-NOV-2017. WELL SI ON ARRIVAL.***(SLB ELINE DRIFT/PERF) MIRU. PT. RIH WITH 1-32 CABLE/PEH-EF/EQF-46(x2)/UPCT/3.90" CENTRALIZER; OAL = 25'; OAW = 220 LBS; MAX OD = 3.90". 11/30/2017 ***JOB CONTINUED 1-DEC-2017*** ***JOB CONTINUED FROM 30-NOV-2017.*** (SLB ELINE DRIFT/PERF) CONTINUE RIH WITH 1-32 CABLE/PEH-EF/EQF-46(x2)/UPCT/3.90" CENTRALIZER; OAL = 25'; OAW = 220 LBS; MAX OD = 3.90". TAG TOP OF CEMENT AT 1356'. LOG UP AT 60 FPM TO SURFACE. RIH W/ 1-32ZA-XS/PEH-EF(1-3/8" FN)/PEK/PGGT/SHOCK ABSORBER/FH/3.375"x10' HSD LOADED 6 SPF WITH HYPERJET CHARGES 60 DEG PHASED. OAL = 28'; MAX OD = 3.61" (GUN SWELL); OAW = 450 LBS. TIED IN TO GR/CCL LOG FROM FIRST RUN. PUNCH THROUGH TBG/PC/SC FROM 1000 - 1010'; CCL TO TS = 7.7'; CCL STOP DEPTH = 9932.3'. RD. WELL SI ON DEPARTURE. FINAL T/I/O = 0/0/0 PSI. 12/1/2017 ***JOB COMPLETE. 1-DEC-2017.*** T/I/O/00=0/0/0/0 Temp=S/I (LRS Unit 46 Assist Special Projects - Spot OOA surface Ice Plug pre OA/OOA Circ Out) Pumped .8 bbls 60/40 down TBG taking returns up OA to tank, Note movement of 20" (OOA) immediately. Shut down. This spots water at surface in OOA to act as ice plug once it freezes, will act as temporary ice plug for upcoming OA/OOA circ out pre P&A. R/D to allow Water to Freeze. 12/1/2017 FWHP=0/0/0/0 SVs, SSV, CVs = C MV= 0 Hardline S/I Drive to location, standby for Snow Removal 12/3/2017 ***Job continued on 12/04/17 *** • • Daily Report of Well Operations 02-03B ***Job continued from 12/03/17 WSR*** T/I/O/O=0/0/0/0 SI (LRS Unit 46 Assist Special Projects- Heat Fluids, Circulate Arctic Pack from OA/OOA) Heat Brine UR to 160*/Heat DSL onboard to 90*. Circ Out OA/OOA of Arctic Pack Pumped 5 bbls 60/40 followed by 10 bbls 90* DSL down TBG. Pumped 58 bbls 90* DSL followed by 52 bbls 160* DSL down OA taking returns up TBG to tank. Pumped 75 bbls of Surfrac. down OA followed by 260 bbls of Brine. Pumped 10 bbls of DSL down OA. U-tube DSL from OA to OOA. Done pumping for the day. Start heating fluids for next day . 12/4/2017 ***Job continued on, 12/05/17 **** ***Job continued from 12/04/17 *** Job Scope: Special Projects - Heat Fluids, Circulate Arctic Pack from OA/OOA) (LRS Unit 46 ) Continue to heat Brine up to 160*. Brine at 164*. Heat surfactant to 160*. Circ out. Pumped 5 bbls 60/40 down tbg to establish communication with OOA. Pumped 147 bbls surfactant, followed by 231 bbls 9.8 brine down tbg taking returns up OOA to surface. 1:1 returns returns going to vac trucks. Pump 15 bbls of 9.8 brine/red dye, followed by 266 bbls of 9.8 brine down OA taking returns up OOA to surface. Returns going to vac trucks. Dye returned 39 bbls early @ 200 bbls pumped and returned -OA and OOA volume = 239 bbls. Pump 5 bbls dsl down tbg for freeze protect. Pump 10 bbls dsl down OA and U tube to OOA for freeze protection. **Fluid packed tags hung on MV/OA** **AFE sign hung on MV** 12/5/2017 FWHP=25/25/26 Job Scope: Cement Tbg, OA. and OOA to surface (Pre P&A) Pump 320 bbls cement down tbg and OA w/all returns up OOA to conductor. Good quality cement returns noted @ 295 away and 1:1 returns noted throughout(no losses) Tbg and OA valves closed w/cement in tree and well head. Surface lines washed up via wash-up line. Field Blend Thickening time 5:37 to 50 be Cement Surface to 1000' in Tbg, OA, and OOA. Cement in OOA fell back to 8' below top of conductor. Final pressures T/OA/OOA- 10/10/0 12/10/2017 Excavate & Remove Wellhead (Plug &Abandonment). Well Support Crew does snow removal and spotted equipment. Tagged top of cement @ 20' below tree cap (top of the OA spool). Pulled tree and installed tree cap assembly on THA Cleaned up area and staged 2/5/2018 equipment. T/I/O = 0/0/0. Removed Production tree and installed tree cap assembly on THA. Final T/I/O 2/5/2018 = 0/0/0. ***Job Complete*** SEE LOG FOR DETAILS Excavate & Remove Wellhead (Plug &Abandonment). Opened HWSP permit#203841. Crew did snow removal around wellhead and cleaned up debris in cellar. Used Super Sucker and Vac Truck with hot water to Hydro Excavate behind wellhead to expose 8" buried pipe. The pipe is —2' below grade and runs from —3' behind wellhead out toward the pits. Cleaned up area and set up signs and barricades. 2/6/2018 Off location 18:30 Excavate & Remove Wellhead (Plug &Abandonment). Excavated a foot print of 10'x10' around the wellhead at a depth of—5'. The excavation walls were sloped at a 2:1 ratio on all 4 sides. The total excavation foot print is —28'x28' (-14' from the wellhead on all 4 sides). —40 cy of material was manifested to GNI. Barricades and Open Excavation signs were placed all around the excavation area. 2/7/2018 Off location at 20:00 • • Daily Report of Well Operations 02-03B Excavate & Remove Wellhead (Plug &Abandonment). Manifested 30 cy of Excavation material to GNI. Set up Goliath Wach's Saw on wellhead and cut wellhead off @ 1' below pad grade. Wellhead delivered to Wells Support API shop. Cement to surface in all strings, accept 13 3/8"x20" (2.28 bbls) top of cement @ 12.5'. 2/8/2018 Off location 17:30 Excavate & Remove Wellhead (Plug &Abandonment). Crew mixed and poured 96 gallons of AS1 cement into 13 3/8"x20"void (TOC strapped @ 12.5'). Marker Plate will not fit over damaged conductor. Sent cap to Jacobs Fab Shop for modification. Barricades and "Open Excavation" signs set up around excavation hole. AOGCC witness waived. Send Pictures to AOGCC and placed in Well Pictures Folder. 2/9/2018 Excavate & Remove Wellhead (Plug &Abandonment). Crew backfills excavation hole. Prep equipment for de-mobe. Left an area -3'x3' open to the top of the well to allow the Marker Plate to be attached when it is cpompleted. Placed 3 sided steel barricade around wellhead. 2/10/2018 Job complete 18:00 Installed marker plate over wellhead stub (post wellhead cut).. AOGCC witnessed by Lou 2/13/2018 Laubenstein. kR.s y . ;.. .. Xti 4 y k fi ., bb y" „Ai, ,:ih.'.:".„,,:,,.:+4,:' ,i ... n, ,4„,i,....,:•,,,,,,,.;!„;,;,f,":„.,:,, ,T,f;-.;',72'4,.' et, .t't''#d?.A "�N� 14. PP" 1�' "d' • ` d'.�5"�`c '�4. 'Si " a0 n ..f . ,,,,,ii,„ A t' "2 y„ a� 'Y'" a 'K`n*Alsii:!..,...V....,„,,,,,,... ' •"-14,..7;•'!... ,: ti it 41 x f : -- tr t s '''','..„,,,•:' 'u • '°� ¢P,^�•,'a, .. :. �.'t+#. ,y;! "ft .; . , ''`Y. • eta... ♦ .. 4. 'fir • `j• } • r`,l e' S w 'rrn '#, :' wE • rF'� i' .'- .4. 2'i„ `x: ' .gyp n+" I '. _ �. lit-. .518. M'L�' v� L ,4ei:. . . '}.{`. r lam_ rQ j'y!.�`}*}X`/yj}.', L'""w, d� 'i 2 i , 4.:l F A — F i,+. F,^t ,'di,.' +t : Y ..• .." m ,. . , 1P1**' ' ' *—•"'•'. ''''' '.'. . ., . .. ‘ :;;;;,•4, ;;:,,,,'•;...:4446:1.:.:....•1"4.•,:' . ' • ? 1 1 .64 47g • r� • 0. • ♦ Y`w M 'fir:i, aMlFrM '''''.4. } + $$,,,� <*. y'f • it- y .1:1" M +3, « * ' ' lP. ..i • 4. ". t �$ r P ,qtr• - < � e4,, 1 �R 7 ' • • flop ' - a* 4 t ai ''''' ' .. 4.' ';:i''' '''''' ' ' e k ai• ` fp , a_.,j • t :: i e * , 5S C ."- tio.7.4"7,:,,,,1 -41r,,i'.,<,.:0...,-....7:-...,....,:;: ..,,,,-;;:;,.....,..f,..„2.! ,....,.,.„..., !.,1,-.... aa"✓ ,e S r rfi • krt ..„., , -- iy.. .0 -:- ...,.„ -,4%,-,', .0 . ..2„, . ,.;,...,.,if 1 . . Asolk 'gw m -<. dr r. sa k 5 {' l. ^va ...,..„...-i''''.." s ;1 R"►. x*',. a f S � p dice R� , .ye .t,uq .1 shhr;y ,V-:-A.,..,,..,:,, ' sxc „.asyy � �' �, r.7*, t • w µ�'"R`C° }' c%! -...t, w,.. ki 'mo'i : '1,1 .,„ , „... . ig. „,,,,..1., .... ,„,, ,e'e � j µf_ , , A 8 ,..t. '.,, - . v .4,,,,- 4. ,.,,,,,%,!;:!i-.7.,,,..,:,,ip.:1,,,....,!..,,, . ,, .: � ; y .n ,-;, „,,,,i,-,,,,, .°' R k , * y ” >. TREE= FMC 120 S NOTES: WELL ANGLE>70"@ 11067'. WELLHEAD= MCEVOY GEN1 SUSIIIDED 0 ACTUATOR= BAKER C 2 0 3 ._ SUSP -WELLHEAD CUT 1'BELOW PAD GRADE, INTIAL KB EIS 64' MARKER CAP INSTALLED AND BACKHLLED(02/13/18) BF.ELEV= TBG PUNCH -) 1000'-1010' -4- "- ie.. • 1148' 9518"FOC KOP= 3100' (12/01/17) �� i# Max Angle= 94° 11163' •#1 ## 1189' H9-5/8"CSG PATCH Datum MD 10821' 20"CSG H 1219' #+1 j# 40 Datum TVD= _ . 8800 SS *A t TOC TBG - 1420' i•7#i#-40-. 40 #1►###•# (11/27/17) #••,�••40 i## 9-5/8"CSG - 1850' f •4••4••• 40 1806' �9 5t8"FOC_ ###♦#•i0 PATCH # ''.7" 2171' 5-1/2"BAKER PFVE SSSV NP,ID=4.56" 13-3/8-CSG,72#,N-80,D=12.347" -I 2688' ##1�•#####•!## .4#,,;►,�#####4►#4 l �� 2700' �( IT BOTTOM(11/30/17) TBG PUNCH(11/14/17) -I 2698'-2703' Minimum ID =2.380" @ 10612' 3-3116" X 2-7/8" XO 6776' -13-1/2"WFD X rte,D=2.81" 3-1/2"WFD ER PATCH(01/08/09) H 6668' , i 6778' —13-1/2"WLEG 3-1/2"WFD ER PATCH(12/31/08) H 6761' I I 9883' -15-1f2"BAKER L SLIDING SLV,D=4.56" BALANCE CMT PLUG N TBG&IA(06/06/17) -I -8800'-9850' 9947' I-5-1/2"BAKER R NP,ID=4.472" TBG PUNCH(06/04/17) H 9845'-9850' 9954' -15-1/2"BAKER SBR ASSY M. k, 10005' -I9-5/8"X 5-1/2"BAKER SAB PKR,ID=3.875" 5-1/2"TBG•0PC,17#,N-80,.0232 bpf,D=4.892" -I 10018' 10018' H5-1/2"X 4-1/2'XO,D=3.958" 10080' -{4-1/2"BAKER R NP,D=3.759" 10095' -I 3.60"BKR DEPLOY SLV W/GS PROFLE,D=3.00" 3-1/2"LNR,9.3#,L-80 FL4S,D=2.992" -I 10101' 10140' -14-1/2"BAKER SHEAROUT SUB 4-1/2'TBG-NPC,12.6#,N-80,.0152 bpf,D=3.958" I- 10143' / \ ' 10143' H4-1/2"TUBING TAIL(BEHIND LNR) ESTNtATED TOP OF cauiT -I 10231' 10130' H ELND TT LOGG»03/06,477 111111, 1�ffi ESTIMATE)TOP OF C�V�1T(06/01/17) 10287'.. •11111 014,44.1 .J 10314' 3-1n'FES EVOTRIEV E PLUG(04/19/17) 111111 !11'11 111 ►111 3-1/7,9.3#FL4S X 3-3/16",6.2#TC2 XO,D=2.800" -{ 10359' 111111 X111111 1111111 1111111 9-5/8" CB ENT WINDOW 1111 10111 PERFORATION SUMMARY 1111111 1111111 10553'-10560' REF LOG: BHCS ON 08/28/70 1111111 1111111 1111111 111111 ANGLE AT TOP PERF: 85°@ 11399' 111 4.1, Note:Refer to Production DB for historical pert data 11111111# 111111♦ SIZE SPF MB21/AL SHOT DATE SOZ 1111111► 10612' I--3-3/16',6.2#,TC2 X 2-7/8" 111111111 , 2" 4 11399-11500 C 05/31/01 11111111111111111111 6.16#STL XO,o=2.380" 111111111 2" 4 11640-12170 C 05/31/01 1111111111 2" 4 12230-12340 C 05/31/01 11111111111111111111 1111111111 12524' -I2-7/8"WEIR PLUG 2" 4 12430-12500 C 05/31/01 1111111111 1111111111 11 111 ` STD 0 11111100 1111 1111111111 11111111111111111111 11111111111111111111 ,�, 11111111111111111111 'V 9-58"CSG,47#,S0O95,D=8.681" H 10809' I-- 1111111111 TD I 12566' TOP OF OLD 9-5/8"SDTRK VA DOW-02-03A 2-7/8'LM-CT,6.16#,L-80 STL,.00579 bpf,D=2.380" -1 12566' DATE REV BY OONMENTS DATE REV BY COMVEMIS PRUDHOE BAY UNT 11/28/76 ORIGINAL COMPLETION 06/08/17 TS/JM) BALANCE CMT PLUG(06/06/17) WELL: 02-03B 11/30/95 CTD SIDETRACK 11/15/17 NXW/JMD TBG PUNCH(11/14/17) PERfVIT No:"L002170 06/01/01 ADK CTD SIDETRACK 12/05/17 DS/313 CMT IA&CMT TBG(11/27/17) API No: 50-029-20077-02 04/20/17 JMG/JMD SET EVOTRIEVE PLUG(04/20/1', 12/05/17 KFMJMD TBG PUNCH(12/01/17) SEC 36,T11 N,R14E,945'FNL&1748'FWL 06/07/17 043DYJM3 DUMP BAL(XVII(06/01/17) 12/12/17 AB/JVD CMT OOA,OA&186 TO SURFACE 1 06/07/17 KFS/JM3 TBG PUNCH(06/04/17) 02/19/18 AB/JM) SUSPENDED(02/13/18) ( BP Exploration(Alaska) • • MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg DATE: 2/15/18 P. I. Supervisor FROM: Lou Laubenstein SUBJECT: Surface Abandonment (Temporary) Petroleum Inspector PBU 02-03B BP Exploration PTD 2002170; Sundry 317-327 2/13/18: I traveled to PBU 02-03B for a marker cap and location inspection. The wellhead was cut off 6-8 inches below the pad grade and all annuli have cement to surface (email from BPXA with photos dated 2/10/2018). The well status is considered "Suspended" by AOGCC since it does not meet the cutoff depth requirements of 20 AAC 25.170. The marker cap rests on top of the cutoff wellhead and held in place with lockdown screws; it had all the appropriate information on it. There is a barricade in place around the area with a sign showing the well information. Attachments: Photos (2) ' MSD 6; cket,k etre_ plus i n rzkr- c4A.,;;k atecijSuyPice ct 't.ao cm4,eS imilt4ED 1,;; 2018-0213_Surface_Abandon_temp_PBU_02-23 B_11.docx Page 1 of 2 • • . , • ,. . . ,...„, ., _ , ,' .,... ,,,_ ; , p, L .... .„ 1 i„, . , . Ati ' ' 1iL r ..:.i ' . � .1 LU • t • U 0 • 14.. t +�� CQ rWefv . • 1` f yel w pti o a) O cd l b N co py D Q H N CO y,,.s ' ix 'ra> CD N " N r �.. COCD ' '� ` ' 03 L. Q J E L • G1 O Hv fit } . , .w' IIt rr ;•, 09 O ' tri z_ rri : co a c� (: • p Z o 3I3 ?r 2.0 0 zl 10 Regg, James B (DOA) From: Bass, Arvell C <Arvell.Bass@bp.com> Sent: Saturday, February 10, 2018 6:42 AM To: DOA AOGCC Prudhoe Bay Subject: RE: AOGCC Test Witness Notification Request: Inspection, Dreillsite 02 Well 03 Pics 2 Attachments: IMG_1314.JPG; IMG_1315.JPG; IMG_1316.JPG; IMG_1313.JPG end of pics... From: Bass, Arvell C Sent: Saturday, February 10, 2018 6:38 AM To: 'DOA AOGCC Prudhoe Bay' Subject: RE: AOGCC Test Witness Notification Request: Inspection, Dreillsite 02 Well 03 Pics 1 From: Bass, Arvell C Sent: Saturday, February 10, 2018 6:29 AM To: DOA AOGCC Prudhoe Bay Subject: RE: AOGCC Test Witness Notification Request: Inspection, Dreillsite 02 Well 03 Guy, 02-03 was cemented to surface w/96 gallons of AS1 yesterday. The marker cap wouldn't fit over the conductor due to irregularities in the conductor. It is being modified and will be installed next week. I'll send you pictures of the cap once it's installed. Please find the requested information attached. Procedure, schematic, Yesterday's report Pictures to follow in 2nd email Arvell Bass GWO Special Projects Office (907) 659-5580 Cell (870)421-5555 Harmony Radio #2382 From: Cook, Guy D (DOA) [mailto:guy.cook@ alaska.gov] Sent: Thursday, February 08, 2018 4:32 PM To: Bass, Arvell C Cc: DOA AOGCC Prudhoe Bay Subject: Re: AOGCC Test Witness Notification Request: Inspection, Dreillsite 02 Well 03 Notification received. Witness is waived. As we discussed on the phone, please send pictures and associated paperwork of the operation to doa.aogcc.prudhoe.bay(aalaska.gov. Thank you, 1 Guy Cook AOGCC 907-227-2614 Sent from my iPhone On Feb 8, 2018, at 3:50 PM, Arvell Bass <noreply@formresponse.com> wrote: Question Answer Type of Test Requested: Inspection Requested Time for 02-09-2018 3:40 PM Inspection Location Dreillsite 02 Well 03 Name Arvell Bass E-mail arvell.bass@bp.com Phone Number (907) 659-5580 Company BP 02-03 is being suspended. The wellhead is being cut below pad Other Information: grade. Expect to be ready for inspection tomorrow afternoon. Fell free to call my personal cell 870-421-5555. Submission ID: 3939465916189802158 2 • • n , , :y�' if 5 F IA i _________-----7: f litik' - '21 ' ' �/ I N pNI al gym - - N • . Y��\A.lr.\Vl�7016 a `+. ) ♦L, a jf0c._3 IP GQ a- • Y 0 cu 0i ializ, . ift* I / y 0 ._ - U • 0 "� ski z z L,'.' +s C- czt 0 .i & r N . .i t.. N 4. A.4 ' 7 :. r v enN cz . ' ' r ''' ' - " ' . pa ilo I 0 1 000 _ N x ` 't O eC,j, . ,�„ 45 �" '#e. . . • i w Sr„. r K1„....„. ..4,„.,„, .. 14,, $ 4.,,,,44. . F M k:. er „ -rt t - '':!. . - 1 L A j 1 * 5 4 "�3Y4 • 4; Y1' , * t� �' � Y t 41 . 1; - • t'i,v+. ' E;” O O CVL CO - .r t N iikfr 'A 1 *' ' . .. —''''. . " ' ' L— • Af 1 : . i "' k1,-;;L.-4 ak*, L b ::'Mk. `. �� I. � LS;. 1 & r . � al C) . , «`s 4 1 , t. 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'l t • r r r444 f, 4. .� ** r �r, b WSR- 02-03B - 2/9/2018 • Page 1 of 1 • WELL SERVICE REPORT WELL DATE JOB SCOPE DAY SUPV 02-03B 2/9/2018 PLUG AND ABANDONMENT BASS AFE Code DAILY WSR DAILY WORK NIGHT SUPV COSTS Z3-0020M-E:EXCAV $190 PLUG&ABANDON--IN PROGRESS MIN ID DEPTH TTL SIZE KEY PERSON UNIT 0" 0 FT 0" CH2-HOULTON , NONE DAILY SUMMARY Excavate&Remove Wellhead(Plug&Abandonment). Crew mixed and poured 96 gallons of AS1 cement into 13 3/8"x20" void(TOC strapped @ 12.5). Marker Plate will not fit over damaged conductor. Sent cap to Jacobs Fab Shop for modification. Barricades and"Open Excavation"signs set up around excavation hole.AOGCC witness waived. Send Pictures to AOGCC and placed in Well Pictures Folder. LOG ENTRIES Init Tbg, IA,OA-> TIME COMMENT 06:00 Arrive on location.Terry Hunt inspects the excavation hole. 06:30 Take HWSP Excavation and Cold Work Cement live. 07:00 DHD drops off their Special Projects trailer with their cementing equipment.They leave pad to pick up more material. 08:30 Water truck is on location. 09:00 DHD stages equipment for cementing. 10:00 TOC @ 12.5'in 13-3/8"x 20"annulus. Start mixing cement by hand and pouring into void. 13:00 96 gallons of 15.7 AS1 mixed and poured into void. Cement @ surface.Top cap will not fit due to damaged conductor. Sent cap to Jacobs Fab Shop for modification. Clean up work area. 14:00 DHD crew off location. Final Tbg,IA,OA->I I I JOB COSTS SERVICE COMPANY-SERVICE DAILY WSR COST CUMUL TOTAL BP $190 $1,235 CH2MHILL $0 $38,670 WAREHOUSE $0 $11,974 HALLIBURTON PLUS 17 PERCENT $0 $370 SCHLUMBERGER $0 $104,024 LITTLE RED $0 $14,958 HALLIBURTON $0 $2,175 LITTLE RED PLUS 10 PERCENT $0 $1,494 EQUIPMENT FLEET $0 $58,399 MI FLUIDS $0 $30,464 NORTHERN SOLUTIONS $0 $800 HOT WATER PLANT $0 $384 WS DISPATCHED $0 $4,940 SCHLUMBERGER PLUS 17 PERCENT $0 $3,280 TOTAL FIELD ESTIMATE: $190 $273,166 file:///C:/Program%20Files%20(x86)/AWGRS/Reports/Report.htm 2/10/2018 • by 02-03 Surface plug/Suspend Well Intervention Engineer Aras Worthington (907) 564-4102 Production Engineer Chris Stone (907) 564-5518 History 02-03 was originally drilled in 1970, worked over in 1975, finally recompleted in 1976. 02-03B is a June 2001 CTD sidetrack and completed with 2-7/8" x 3-3/16" x 3-1/2" production liner. The well was a naturally flowing producer completed in the Z1A and Z1 B. It was a full time producer until 2007 when it was SI for a flowline corrosion issue. After the flowline issue was resolved, it came online briefly in July of 2008 at which point it developed TxIA communication. A tubing patch was set from 6,668' -6,761' MD in December 2008 which resolved the TxIA communication. Increasing GOR resulted in lower ontime over the next several years. The well was POP'd briefly in late 2013 and then SI for a PMP on the flowline and remained SI for close to 3 years. In November 2016, the PMP was addressed and the well was brought online. An employee discovered an uncontrolled gas release from the top of the well shelter at approximately 7:30 a.m. on April 14, 2017, resulting in mobilization of the Incident Management Team. Leaks were noted from a sheared-off S-riser fitting and the tubing head adapter clamp/flange. The well was killed and the leaks stopped. The crude spray plume did not leave the well pad or adjacent reserve pit. There were no reported injuries. Slickline set an Evo-trieve plug in the the 3-1/2" Liner @ 10,314' MD on 4/19/2017. The plug was successfully pressure-tested to -250 psi to confirm it was set. A sundry was submitted and approved for placing -1000' of cement in the tubing and IA as part of the reservoir abandonment. The cement was in put on place on 6/6/2017. The cement plug was tagged at 8532' SLM on 6/15/2017. The cement plug was pressure-tested via a CMIT TxIA to 958 psi on 6/15/2017. Objective Place surface cement plugs in the well and remove the wellhead to suspend the well. • • Volume Calculations: volume top MD bot MD Size ID bbls/ft. Ft. bbls 19.124" 20" x 13-3/8" annulus to 20" 94#x x 897' Surface 897' 13-3/8" 13.375" 0.182 897' 163 18.73" 20" x 13-3/8" annulus to 20" 133#x x 1000' 897' 1000' 13-3/8" 13.375" 0.167 103' 17 12.347" 13-3/8" 72# x 13-3/8" x 9-5/8" Surface 1000' x 9-5/8" 9.625" 0.0581 1000' 58 8.681" 9-5/8" x 5-1/2" annulus Surface 2700' 9-5/8"47# x 5-1/2" 0.0438 2700' 118 5-1/2" tubing Surface 1000' 5-1/2" 17# 4.892" 0.0232 1000' 23 5-1/2" tubing Surface 1500' 5-1/2" 17# 4.892" 0.0232 1500' 35 5-1/2" tubing 1500' 2700' 5-1/2" 17# 4.892" 0.0232 1200' 28 Procedural steps Special Projects 1. Injectivity test down the control and balance lines with hydraulic oil. 2. Cement control and balance lines w/ 1.2 gals of squeezecrete or finecem each (-1300'). Reference small volume cement RP. If pump pressures allow (<5000 psi), fill the entire control and balance lines with cement (Control lines are 1,060ft/gal; total displacement to 2171' MD is 2 gallons each). DHD 1. WOC 3 days and PT control lines to 2500 psi. E-Line 1. Tubing Punch 2695'-2700 ' MD through 5-1/2" tubing. Punch across a tubing collar in this vicinity. Fullbore 1. Circulate cement down tubing and up IA to surface. Max tubing pressure 1500 psi. ➢ 5 bbl MEOH spear ➢ 50 bbls of hot surfactant wash (160F FW + 2 gal/mgal of F103 and 2 gal/mgal of U067) additive concentration changed 11/22/2017 per Aras Worthington ➢ 5 bbls FW spacer ➢ 150 bbls 15.8 ppg cement per design ➢ 2 bbls FW spacer ➢ 29 bbls 9.8 ppg brine ➢ 4 bbls diesel (brine and diesel displaces cement up IA and cement top in tubing to —1500' MD) 1St Cement Job 9-5/8" x 5-1/2" volume from 2700' MD to surface 118 bbls 5-1/2" volume from 2700' MD to 1500' MD 28 bbls 2 • Total Cement to Pump (9 bbls excess) 150 bbls Cement Type/weight: Class G 15.8 ppg mixed on the fly. Field blend to be =lab ppg +/- 0.1 ppg Slurry Temperature: between 80° and 110°F Fluid Loss: 40-200cc (20-100cc/30min) Compressive Strength: 2000 psi in 48 hrs. Thickening Time: Minimum 4 hours Activity Time (hours) Shearing time, quality control, PJSM 0 Cement displacement 4 Cement contamination 0 Safety 0 _ Minimum required thickening time: 4 Cement Ramp for Blend Time Temp Pressure 0:00 90 0 1:00 80 1400 2:00 70 700 3:00 60 0 4:00 50 0 7:00 40 0 15:00 30 0 Valve Shop 1. Install Katch-Kan and/or cellar liner around wellhead to allow taking returns from parted 20" casing to Katch-Kan. Slickline 1. Tag TOC in tubing. E-line 1. Run GR log from TOC to surface (log all the way into the Tree - this log is for future subsidence surveillance/analysis). 2. MU guns and perforate @ -1000' MD through 5-1/2" tubing, 9-5/8" casing, and 13-3/8" casing. 3-3/8" Guns w/ Hyperjet 3406 RDX charges. 3 • • 2nd Cement Job: 20" x 13-3/8" volume from 1000' MD to surface 180 Bbls 13-3/8" x 9-5/8" volume from 1000' MD to surface 58 Bbls 5-1/2"tubing volume from 1000' MD to surface 23 Bbls Total Cement to Pump (19 bbls excess) 280 Bbls Cement Type/weight: Class G 15.8 ppg mixed on the fly. Field blend to be =lab ppg +/- 0.1 ppg Slurry Temperature: between 80° and 110°F Fluid Loss: 40-200cc (20-100cc/30 min) Compressive Strength: 2000 psi in 48 hrs. Thickening Time: Minimum 4 hours Activity Time(hours) Shearing time,quality control,PJSM 0 Cement displacement 4 Cement contamination 0 Safety 0 Minimum required thickening time: 4 Cement Ramp for Blend Time Temp Pressure 0:00 90 0 1:00 70 800 2:00 60 0 3:00 50 0 4:00 40 0 7:00 40 0 15:00 30 0 5 • Special Projects 1. Cut off all casings and wellhead -1' below pad level. Top job the 30" x 20" annulus and all other annuli and tubing with cement as needed. Install marker cap on outermost casing string to read as follows: BP Exploration Alaska, Inc. 02-03B PTD #200-2170 API # 50-029-20077-02-00 Note: Final excavation, casing removal to 3' below tundra, and marker plate welding to occur at pad remediation. 6 • • DS 02-03 Current Status 5-4"174INPC-Pe-80 --- 15/8'Casing set on EI/1 Saps*340-150K Over .6V13-3/8"Casing set on EM Slips[a 50K Over I i F 6 t 'lb. i1 ;i ' 20'Stip Fount 242',362436' id i p 2 1 30"Conductor I .6 g 20'fp 61e 1 9.8 ppg brine in ' Tubing & IA from TOC to Surface I—Stara-FOC-Col DPZ 1: 4-----TOC in 13-3J - TOC in 9-5/8" x 13-3/8" 1890' il We-d,;,g cut enditri rind annulus @—1875 —2348' MD tO 21.71'Baker°FYESSW NI MD 7636' MD r -4-1 -3/11'Cad E g TOC 6450' MD 4s6o B 6663 Upper Element-6761`lower Element Manimwn ID 6776'm 2.61'ID WLFG 0 6778' Cement in Tbg & IA from—9850' MD to 8800' MD ./.`ti X." 10005'MD 18234 TVDI 9-5/3"a 5-15"Baker 546 Pecker DPZ2: 10,052' -'4 10O18 546`ii 4-3,..foo MD to 10,057' MD II ts— 10080'Baker 4-15^"R"Kpple a - 10095 3.60'OD Baker Deployment Sleeve DPZ3: �1 ''' Evo-Trieve Plugset 10,314' MD 10,256' :.::+—►' '' MD to TD .li:': Mar*OW a 3-1/16- : ... .. - -r 1■■12 X-0 3-3/18r it 2-7/'11' 12556 ., .........:• ♦ 15/8"Casing Shoe#11372?(Reports on amine depth vary)— Top Bottom+ Weight Burst Collapse Size (MD) (MD) 0/FT Grade [PSI) (PSI) 20" 30' 89/' 94 H i 40 1530 520 20" 897' 1219' 133 K 55 3060 1500 •TOC Based on Sacks Pumped and 20'h hole washout 13-3/8" 26' 2688' 72 N-80 5380 2670 9-5/8" 24' 1807' 47 S00-95 8150 7100 9-5/8' 180/ 64/4' 40 500-95 6820 4230 9.5/8" 6474 0668' 43.5 500-95 7510 5600 9-5/8" 9668 11344' 47 S00-95 8150 7100 • • DS 02-03 Post Surface Cement 5-)4"176 NPC-N-S0 _ 9-5/2'9.5/8'Casing set on EM Sups 80 340-150K Over 13-3/8"Ceung set on EM Slips 0 50K Over mr . Cement in OA and OOA from 1000' MD to mr .\ Z ^� surface, top job in 30" x 20" Annulus at surface. - 13-3/8 FOC-Coder 0 1146'--- —x- T- 13-3/6"Casnt6 Cut end Pull and Patch e.118-6' I '217 Cement in IA from 2700' MD to surface, cement in ` ' II. tubing from 2700' to 1500' MD. I Ad DPZ1•: TCC in 13-3/B"6c 1453 TOC in 9-5/8"x 13-3/8" 1890' �'' "end P'�'®1 annulus @ 1875' - 2348' MD to 2171'Brew PFVE SSSV ------------..___. 7636' x-13 MD MD E E --- TOC 6450' MD _ a 3-74' C 2+_ 6668'Upper Element 4761'Lower Element Primmum ID 6716'0 2.81'ID lin AG 42 6772' Cement in Tbg& IA from 9850' MD to 8800' MD fA'* r .. 100057AD(5234'TWion D$9-5/6"r 5-8"Baker SAS Pot , '4 10018 5-st"a 4-7S"X0 DPZ2: 10,052' MD to 10,057' ■ 10080'Bauer 4-8"'Ir PePPk MD 10095'3.60"OD Beier Deployment Sleeve DPZ3: 10,256' r: Evo-Trieve Plug set @ 10,314' MD MD to TD 10359 8-03-74`Is 3-3/16" 17555 TD- A' rk t ;: ' . s5/r Coring shoe tla 11372?(Reports on awing depth vaey) — Top Bottom Weight Burst Collapse Size (MD) (MD) OfFT Grade (PSI) (PSI) 2[:" 30' 89!' 94 1140 1530 520 2C• 897' 1219' 133 K 55 3060 1500 '1'0C Based on Sacks Pumped and 2044 hole washout 13-318" 26' 2688' 72 N-80 5380 2670 9-5/8' 24' 1807' 47 S00-95 8150 7100 9.5/8' 180/' b4/4' 40 500-95 6820 4230 9.5/8' 6474' 9668' 43.5 500.95 7510 5600 9-5/8' 9668' 11344' 47 500-95 8150 7100 • ALASKA WELL ACTIVITY STATEMENT OF REQUIREMENTS (V2.0,DBR,LHD,EAZ, BPG 10/12/15) General Information Well Name: 02-03B Well Type: Natural Flow Producer API Number: 50-029-20077-02 Well Activity Conventional 4 Classification: Activity Description: Secure Cost Code/AFE: Z3-0020M-E:EXCAV Field/Reservoir: PRUDHOE IVISHAK 12 Month Avg IOR, bopd: Job Type: NOT OPERABLE Estimated Cost, $500 $K: AWGRS Job Scope: PLUG and ABANDONMENT Other regulatory requirements? Sundry Form 10-403 Yes Required? Sundry Form 10-404 Required? Yes Primary Secondary Engineer: Chris Stone Contact numbers: (907)564-5518 (907)440-4011 Well Intervention Engineer: Aras Worthington Contact numbers: 907-564-4102 907-440-7692 Lead Engineer: Chris Stone Contact numbers: (907)564-5518 (907)440-4011 Date Created: April 17,2017 Revisions(date,who,what changed): Current Well Status Information Water Rate or Gas Rate or FTP or Injection Oil Rate Inj Rate Gas Injection GOR Gas Lift Rate Date Pressure (bopd) (bwpd)Water Rate (scf/stbo) Choke Setting (Mscf/Day) Cut(%) (Mscf/Day) (psi) 3/29/2017 482 6 35,875 74,410 64 0 894 Current Status: Not Operable Shut In Inclination>70°at Depth(ft) 11,070'MD Recent H2S (date,ppm) 3/19/2017 Maximum Deviation(Angle and 11,113'MD Depth) Datum depth,ft TVDss 8,800'TVDss Dogleg Severity(Angle and Depth) 39° 10,917'MD Reservoir pressure(date, 6/5/1993 3,518 psi Minimum ID and Depth 2.810" 6,776'MD psig) Reservoir Temp,F 192° F 'Shut-in Wellhead Pressure 2,500 psi Known mech.integrity IA and OA pressure tracking(failure),Tubing adapter clamp leaking,currently unknown if TxIA exists post problems(specifics) well control incident. Last downhole operation(date,operation) 1.21/2016 PULL 3-1/2"WFD WRP @ 10272'SLM Most recent TD tag(date,depth, toolstring OD) 12/26/2013 10,627'MD 2.71"WRP drift Surface Kit Fit-for-Service? If No,Wh If well has been shut in for> 1 year or job cost>$500M, fill out Non Rig y' Surface Equipment Checklist. Comments,well history, Currently the well is assumed to have TxlxO communication with a leak at a wellhead clamp that has been background information, repaired. The 20"casing has separated completely just below the wellhead. A reservoir abandonment, etc: balanced cement plug 1000'MD in length has been placed in the Tubing&IA,tagged and PT'd to 958 psi. i i Well Intervention Details Please contact the SOR author if: 1.There is a change in work scope to the approved SOR 2.For well work>$100M estimated total cost, as soon as it is reasonably anticipated that the actual cost will exceed the estimated cost by 20%. Suspected Well Problem: Leaking Wellhead with TxIxO communication Specific Intervention or Well Objectives: 1 P&A 2 3 Key risks,critical issues: Mitigation plan: 1 TxIA unknown,IA,OA tracking, Leaking wellhead clamp. Pump Dyed diesel through to OA to ensure the OA is being swept entirely before pumping cement. 2 3 Summary Service Line Activity Step# 1 O Cement Control and Balance lines 2 D PT Control and Balance lines to 2500 psi 3 E Punch Tubing 4 F Circulate out and Cement IA 5 V Install Catch-Kan/lined cellar 6 S Tag TOC 7 E GR Log. Perforate tubing, PC,and 13-3/8"casing. 8 F Circulate out Arctic Pack from OA and OOA 9 F Cement OOA,OA,and Tbg to surface 10 0 Cut off casings and wellhead. Top Job&install marker plate. Detailed work scope(If no RP/SOP exists for the intervention type,a well-specific procedure is required in addition to the SOR): 1 See detailed program attached. 2 2 3 4 Performance Expectations(may be NA if no change anticipated due to the intervention) BOPD: MMSCFD: BWPD: Expected Production Rates: FTP(psi): Choke setting: PI(bfpd/psi dp) Post job POP instructions: Attachments-include in separate excel worksheets Required attachments: Current wellbore schematic As needed: Perf form, logging form,well test chart,annotated mini log,annotated log section,tubing/casing tallies,Wellhead info,etc r TREE= FMC 120 ) WEILI-FAD= MCEVOY GEN1 • SA OTES: WELL ANGLE>70°@ 11067'. 1 'ACTUATOR= BAKER C 02-03B INITIAL KB.Ell 64' BF.ELEV= - ._ TBG PUNCH H 1000'-1010' _ " ' r�'`': KOP- 3100' .r.} , *x ; 1148' H95/8"FOC (12/01/17) Max Angle= 940 @ 11163' " i y 1189' -19-5/8"CSG PATCH Datum MD= 10821' 20'CSG HI 1219' •'• . r Datum TVD= 8800'SSTOC TBG - 1420' 494- so •' (11/27/17) - 1806' H9-5/8"FOC 9-5/8"CSG H 1850' Mt _ PATCH .rr 2171' H5-1/2"BAKER PEVE SSSV NP,ID=4.56" 113-3/8"CSG,72#,N-80,10 12.347',-I 2688' '. ' '`'ti\ r' \ 2700' }-1CMTBOTTOM J 1,T3GPtJNCH(11/14117)[-{2698' -2703' Minimum ID =2.380" @ 10612' 3-3/16" X 2-7/8" XO ,75._______..-1 6776' —j3-uWED ED x NP,0=2.81" ' " 3-1/2"WFD ER PATCH(01/08/09) [--1 6668' 6778 - j3-1/2WLEG-------- 3-1/2" PATCH( WFD ER 12/31/08) 6761 —._ -.- __--. J- _ I I 9883' H5-112"BAKER L SLIDING SLV.D=4.56" BALANCE CMT PLUG N TBG&IA(06/06/17) -8800'-9860' + 9$47 -5-1/2"BAKER R NP,ID=4.472" ITBG PUNCH(06/04/171- 9846'-9860' 9954' -I 5-1/2"BAKER SBR ASSY M _ 10005' -19-5/8"X 5-1/2"BAKER SAB PKR,ID=3.875'j 15-1/2'TBG-NPC,17#,N-80,.0232 bpf,0=4.892"_]-1 10018' ) - — -- --- 10018' -{5-1/2"X 4-112"XO,O=3.958" ' ' 10080' H4-1/2"BAKER R NP,ID=3.759" 10095' 3.60"BKR DEPLOY SLV W/GS PROFLE,D=3.001 3-1/2'LNR,9.3#,L-80 FL4S,D=2.992" -1 10101' 10140' 1-14-112"BAKER SHEA ROUT SUB 4-1/2'TBG-NPC,12.6#,N-80,.0152 bpf,DH /=3.958' 10143' I\ 10143' ]-{4-1/2'TUBING TAIL(BEHIND LNR) 10130' -1 ELMD TT LOGGED 03/06/77 ESTIMATED TOP OF CENENT H 10231' •1V1•4 1�1.vg [ESTIMATED TOP OF CEMENT(06/01/17)J-L-10287' ow. 1�1�0 111111111111/1 I 10314' 1-[3-1/2"HES EVOTREVEPLUG(04/19/17) ) 3-1/2",9.3#FL4S X 3-3/16',6.2#TC2 XO,D=2.800" 10359' 1?.11 11111 111 1111 11111 j111111 9-5/8" CEMENT WINDOW PERFORATION SUMMARY 111 1111 111111 111111 10553'-10560' FIEF LOG: BHCS ON 08/28/70 1111111 11111 111 1.111 ANGLE AT TOP PERF: 85°@ 11399' 111111 14 4,, Note:Refer to Production DB for historical perf data 1111111ft. SIZE SPF _ INTERVAL SI-OT DATE SOZ 111111 11111111, 10612' -3-3/16",6.2#,TC2 X 2-7/8" . 111111111 , 1111111111 2" 4 11399-11500 C 05/31/01 111111111 6.16#STL XO,D=2.380" 111111111 2" 4 11640- 12170 C 05/31/01 1111111111 1111111111 2" 4 12230- 12340 C 05/31/01 111111111♦ 12524' 2-7/13•ws 2 R u<; 2" 4 12430-12500 C 05/31/01 1111111 1111111111 __ - _ 1111111111 PBTDJ 1111111111 1 ` 1111111111 -- 111111111 -- 11111111111111 11111111111111111111 11111111111111111111 9-5/8"CSG,47#,SO095,D=8.681" - 10809' •1. 1.....1.1.1 TD H 12566' TOP OF OLD 9-5/8"SDTRK WNDOW-02-03A 2-7/8'LNR-CT,6.16#,L-80 STL,.00579 bpf,0=2.380" H 12566' DATE REV BY COATAE TS DATE REV BY COMMENTS PRUDHOE BAY UI"IT 11128/76 ORIGINAL COMPLETION 06/08/17 TS/JMD BALANCE CMT PLUG(06/06/17) WELL: 02-038 11130/95 CTD SIDETRACK 11/15/17 NXW/JMD TBG PUNCH(11/14/17) PERMIT No: 2002170 06/01/01 ADK CTO SIDETRACK 12/05/17 DS/JM) CMT IA&CMT TBG(11/27/17) API No: 50-029-20077-02 04/20/17 JMG/JMD SET EVOTRIEVE PLUG(04/20/1; 12/05/17 KFMJMD TBG PUNCH(12101/17) SEC 36,T11N,R14E,945'FNL&1748'FWL 06/07/17 MRLYJMD DUM3 BA CMT(06/01/17) 12/12/17 AB/JMD CMT OOA,OA&TBG TO SURFACE 06/07/17 KFS/JMD TBG PUNCH(06/04/17) l BP Exploration(Alaska) • prp foo --• a � � Loepp, Victoria T (DOA) From: Loepp,Victoria T(DOA) Sent: Wednesday, December 06, 2017 9:24 AM To: Worthington,Aras J' Subject: PBU 02-03 P&A PTD#200-217,Sundry 317-327 Thanx Aras for the update. Approval is granted to proceed with cementing operations outlined in the approved sundry. Thanx, Victoria Victoria Loepp Senior Petroleum Engineer State of Alaska Oil&Gas Conservation Commission CANNED 333 W.7th Ave Anchorage,AK 99501 Work: (907)793-1247 Victoria.Loepo a(�alaska.Qov CONFIDENTIALITY NOTICE:This e-mail message,including any attachments,contains information from the Alaska Oil and Gas Conservation Commission(AOGCC),State of Alaska and is for the sole use of the intended recipient(s).It may contain confidential and/or privileged information.The unauthorized review,use or disclosure of such information may violate state or federal law.If you are an unintended recipient of this e-mail,please delete it,without first saving or forwarding it,and,so that the AOGCC is aware of the mistake in sending it to you,contact Victoria Loepp at(907)793-1247 or Victoria.Loem@alaska.gov From:Worthington,Aras 1 [mailto:Aras.Worthington@bp.com] Sent:Tuesday, December 05, 2017 3:33 PM To: Loepp,Victoria T(DOA)<victoria.loepp@alaska.gov> Subject:02-03 P&A PTD#200-217 Good Afternoon Victoria, As indicated via our phone conversation today,we have pumped the planned heated diesel, heated surfactants,and brine to circulate all the remaining open annuli and established good circulation from all (at this time these are the OA and OOA). Note that the IA has already been cemented from"2700'MD to surface. Subsequently,we pumped a dyed pill carried in 9.8ppg brine down the OA(9-5/8"x 13-3/8")and taking returns up the OOA(13-3/8"x 20"). The OA is^'58-bbls in volume and the OOA is"180-bbls in volume for a total of"'238-bbls. We observed the dye-pill coming back at"200-bbls away. This is within 20%of the calculated volume which is a very good indicator that we are getting full circulation to the perforations @ -1000' MD. When we pump the final cement job we expect any remaining mobile solids or contaminants to be expelled with the excess cement we will pump. We would like to proceed with circulating the final cement job which will fill the production tubing,OA,and OOA with cement from surface to the perforations at 1000' MD. Thanks, Aras Worthington Well Interventions&Integrity Engineer 1 • • MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg elf �(j 2a(r DATE: 11-28-17 P. I. Supervisor FROM: Adam Earl SUBJECT: Plug Verification Petroleum Inspector PBU 02-03B BPXA PTD 2002170 November 28, 2017: I went out to PBU Drillsite 2 today and met with BPXA Lee Grey to witness a cement plug tag on PBU 02-03B. Slickline ran in with a bailer to tag the top of cement (TOC) and catch a sample. They tagged TOC @1,368 ft (slickline measurement). After setting down on the cement several times they came out of the hole and confirmed a solid plug with some interface sludge up top. Attachments: None SCANNED t [ 2017-1128_Plug_Verification_PBU_02-03B_ae.docx Page 1 of 1 • • Quick, Michael J (DOA) From: Quick, Michael J (DOA) Sent: Monday, November 06, 2017 10:38 AM To: 'Worthington, Aras J' Subject: RE: P&As for 02-03 and L5-13 �� Aras— 01/ Your changes to sundry 317-327 as noted in your revised procedure are approved. Michael Quick Sr. Petroleum Engineer Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage,AK 99501 (907)793-1231(phone) (907) 276-7542(fax) mike.quickPalaska.gov CONFIDENTIALITY NOTICE:This e-mail message,including any attachments,contains information from the Alaska Oil and Gas Conservation Commission (AOGCC),State of Alaska and is for the sole use of the intended recipient(s).It may contain confidential and/or privileged information.The unauthorized review,use or disclosure of such information may violate state or federal law.If you are an unintended recipient of this e-mail,please delete it,without first saving or forwarding it,and,so that the AOGCC is aware of the mistake in sending it to you,contact Mike Quick at 907-793-1231 or mike.auick@alaska.gov. From:Worthington,Aras J [mailto:Aras.Worthington@bp.com] Sent: Monday, October 16, 2017 10:15 AM y��p To:Quick, Michael J (DOA)<michael.quick@alaska.gov> S`� E Subject: P&As for 02-03 and L5-13 Michael, These wells are both moving through BP internal deviation processes in order to P&A as per the Sundry applications that are already approved by AOGCC. We apologize for the delay. L5-13 will then be excavated and the failed casings removed and materially analyzed, as discussed. We expect to have the P&As done before year-end but I do not know how long it will take to do the materials analysis and get a final report for L5-13. I will get back to you once I have a good time estimate for that delivery. Also, as discussed via phone today,we are proposing a slight change to the P&A strategy on 02-03 as a result of the deviation process. The program detailing these changes is attached. In summary, we would punch tubing deeper than originally planned and get a deeper cement plug in the tubing and IA, then perforate into the OA and OOA^'300' shallower than originally planned and circulate those annuli with cement from 1000' MD, instead of the OA from 1300' MD, and the OOA from 1000' MD. Please let me know if there are any questions, concerns, or comments on this. I am happy to come in personally to discuss at your convenience as well. Thanks, Aras Worthington Well Interventions & Integrity Engineer 1 • bp 0+00 02-03 Surface plug/Suspend Well Intervention Engineer Aras Worthington (907) 564-4102 Production Engineer Chris Stone (907) 564-5518 History 02-03 was originally drilled in 1970, worked over in 1975, finally recompleted in 1976. 02-03B is a June 2001 CTD sidetrack and completed with 2-7/8" x 3-3/16" x 3-1/2" production liner. flowingproducer completed in the Z1A and Z1 B. It was a full time producer The well was a naturallyp until 2007 when it was SI for a flowline corrosion issue. After the flowline issue was resolved, it came online briefly in July of 2008 at which point it developed TxIA communication. A tubing patch was set from 6,668' — 6,761' MD in December 2008 which resolved the TxIA communication. Increasing GOR resulted in lower ontime over the next several years. The well was POP'd briefly in late 2013 and then SI for a PMP on the flowline and remained SI for close to 3 years. In November 2016, the PMP was addressed and the well was brought online. An employee discovered an uncontrolled gas release from the top of the well shelter at approximately 7:30 a.m. on April 14, 2017, resulting in mobilization of the Incident Management Team. Leaks were noted from a sheared-off S-riser fitting and the tubing head adapter clamp/flange. The well was killed and the leaks stopped. The crude spray plume did not leave the well pad or adjacent reserve pit. There were no reported injuries. Slickline set an Evo-trieve plug in the the 3-1/2" Liner @ 10,314' MD on 4/19/2017. The plug was successfully pressure-tested to —250 psi to confirm it was set. in the tubingand IA as part of A sundrywas submitted and approved for placing -1000' of cement pp the reservoir abandonment. The cement was in put on place on 6/6/2017. The cement plug was tagged at 8532' SLM on 6/15/2017. The cement plug was pressure-tested via a CMIT TxIA to 958 psi on 6/15/2017. Objective Place surface cement plugs in the well and remove the wellhead to suspend the well. • • Volume Calculations: volume top MD bot MD Size ID bbls/ft. Ft. bbls 19.124" 20" x 13-3/8" annulus to 20" 94#x x 897' Surface 897' 13-3/8" 13.375" 0.182 897' 163 18.73" 20" x 13-3/8" annulus to 20" 133#x x 1000' 897' 1000' 13-3/8" 13.375" 0.167 103' 17 12.347" 13-3/8" 72# x 13-3/8" x 9-5/8" Surface 1000' x 9-5/8" 9.625" 0.0581 1000' 58 8.681" 9-5/8" x 5-1/2" annulus Surface 2700' 9-5/8" 47# x 5-1/2" 0.0438 2700' 118 5-1/2" tubing Surface 1000' 5-1/2" 17# 4.892" 0.0232 1000' 23 5-1/2" tubing Surface 1500' 5-1/2" 17# 4.892" 0.0232 1500' 35 5-1/2" tubing 1500' 2700' 5-1/2" 17# 4.892" 0.0232 1200' 28 Procedural steps Special Projects 1. In1ectivit test down the control and balance lines with hydraulic oil. 2. Cement control and balance lines w/ 1.2 gals of squeezecrete or finecem each (1300). Reference small volume cement RP. If pump pressures allow (<5000 psi), fill the entire control and balance lines with cement (Control lines are 1,060ft/gal; total displacement to 2171' MD is 2 gallons each). DHD 1. WOC 3 days and PT control lines to 2500 psi. E-Line 2. Tubing Punch 2695'-2700 ' MD through 5-1/2" tubing. Punch across a tubing collar in this vicinity. Fullbore 1. Circulate cement down tubing and up IA to surface ➢ 5 bbl MEOH spear ➢ 50 bbls of hot surfactant wash (160F FW + 2 gal/bbls of F103 and 2 gal/bbl of U067) ➢ 5 bbls FW spacer ➢ 150 bbls 15.8 ppg cement per design ➢ 2 bbls FW spacer ➢ 33 bbls 9.8 ppg brine (displaces cement up IA and cement top in tubing to —1500' MD) 1St Cement Job 9-5/8" x 5-1/2" volume from 2700' MD to surface 118 bbls 5-1/2" volume from 2700' MD to 1500' MD 28 bbls Total Cement to Pump (9 bbls excess) 150 bbls 2 • • Cement Type/weight: Class G 15.8 ppg mixed on the fly. Field blend to be =lab ppg +/- 0.1 ppg Slurry Temperature: between 80° and 110°F Fluid Loss: 40-200cc Compressive Strength: 2000 psi in 48 hrs. Thickening Time: Minimum 4 hours Activity Time (hours) Shearing time, quality control, PJSM 0 Cement displacement 4 Cement contamination 0 Safety 0 Minimum required thickening time: 4 Cement Ramp for Blend Time Temp Pressure 0:00 90 0 1:00 80 2000 2:00 70 1000 3:00 60 0 4:00 50 0 7:00 40 0 15:00 30 0 Valve Shop 1. Install Katch-Kan and/or cellar liner around wellhead to allow taking returns from parted 20" casing to Katch-Kan. Slickline 1. Tag TOC in tubing. 2. Perforate @ -1000' MD through 5-1/2" tubing, 9-5/8" casing, and 13-3/8" casing. 3-3/8" Guns w/ Hyperjet 3406 RDX charges. 3 • • Fullbore 1. Circulate Arctic Pack out of OA and OOA from 1000' MD to surface via the following pump schedule: ➢ 50 bbls heated diesel (take returns from OA) y 60 bbls heated 9.8 ppg brine (take returns from OA & SD pumping for 1 hour to let diesel soak in Arctic pack after 23 bbls brine away) ➢ 5 bbls of dyed brine (take returns from OA) 50 bbls of hot surfactant wash (160F FW + 2 gal/bbls of F103 and 2 gal/bbl of U067 -take returns from the OA) 100 bbls of hot 9.8 ppg brine (160F - take returns from OA-verify that dyed brine arrives at surface after pumping 26 bbls of 9.8 brine). 50 bbls of heated diesel (take returns from OOA/KatchKan after 23 bbls diesel away) ➢ 100 bbls heated 9.8 ppg brine (160 F - take returns from OOA & SD pumping for 1 hour to let diesel soak in Arctic pack after 23 bbls brine away) ➢ 50 bbls of hot surfactant wash (160F FW + 2 gal/bbls of F103 and 2 gal/bbl of U067 -take returns from the OOA) ➢ 220 bbls of 9.8 ppg brine (take returns from OOA) • 20 bbls diesel or MEOH. U-tube between tubing, OA, and OOA to freeze-protect wellhead and shallow annuli/tubulars from ambient temperatures at surface. 9.8 ppg brine is ample FP below surface. Note: Report results of dyed circulation test to Interventions Engineer before pumping cement. Interventions Engineer will need to report this result to AOGCC before cement can be pumped. Fullbore 1. Circulate cement down tubing and up OA and OOA to cement all from -1000' MD to surface via the following pump schedule: ➢ 5 bbls MEOH (take returns from OA) ➢ 5 bbls freshwater spacer (take returns from OA) ➢ 280 bbls 15.8 ppg cement per design i. Swap to taking returns from OOA/KatchKan after 10 bbls of cement away ii. After clean cement returns are observed at surface and at at least 205 bbls cement away, swap to taking returns from OA. iii. SD and wash up without pumping any wash up water downhole after -280 bbls cement away. 4 • 2nd Cement Job: 20" x 13-3/8" volume from 1000' MD to surface 180 Bbls 13-3/8" x 9-5/8" volume from 1000' MD to surface 58 Bbls 5-1/2" tubing volume from 1000' MD to surface 23 Bbls Total Cement to Pump (19 bbls excess) 280 Bbls Cement Type/weight: Class G 15.8 ppg mixed on the fly. Field blend to be =lab ppg +/- 0.1 ppg Slurry Temperature: between 80° and 110°F Fluid Loss: 40-200cc Compressive Strength: 2000 psi in 48 hrs. Thickening Time: Minimum 4 hours Activity Time(hours) Shearing time, quality control, PJSM 0 Cement displacement 4 Cement contamination 0 Safety 0 Minimum required thickening time: 4 Cement Ramp for Blend Time Temp Pressure 0:00 90 0 1:00 70 800 2:00 60 0 3:00 50 0 4:00 40 0 7:00 40 0 15:00 30 0 5 • • Special Projects 2. Cut off all casings and wellhead —1' below pad level. Top job the 30" x 20" annulus and all other annuli and tubing with cement as needed. Install marker cap on outermost casing string to read as follows: BP Exploration Alaska, Inc. 02-03B PTD # 200-2170 API # 50-029-20077-02-00 Note: Final excavation, casing removal to 3' below tundra, and marker plate welding to occur at pad remediation. 6 • • . 1 DS 02-03 Current Status I 1 3 3 N i 41 -W' M ,,1 . AZ „....,,,,,,,,,:38:3-1.115.,,e;171'1,9,:cos4- 1"p:;,g70.34°b;or.-1Kipn,„.7e:Tin' ' 0-' „,.. 4,r P :..1, -4 „Ix di r•-'---- --- k a !,, 416, .4 g 4 4 /". "7 20-filip Jit 242.7,362',486" 39-Eonductor------ - TOC in 29"•616" . . Tubing &IA from TOC to Surface .._ F-513"FOC-Coder•iser— , I1W1 :a11, - TOC in 9-5/8" x 13-3/8" DPZ I: NV 'i ,. . flH441 - ' '''''. TOC in 13-305-• 1890' 'iltal ''i',. "'' SI-5A-Casing Cud and WA!and annulus @—1875 —2348' MD t0 2171'Baker FRIT SSW N. mD 7636' Pt, -4-2.3-7/3'Can MD ei4969' TOC 6450' MD It% II 668 „„.,,,..,_......... ..._, aral In rA 6 'Upper Element-6751Lower Element ---E, Minirrium ID 6776'•2.81'ID WLtG•6778' -iy•',,',"',2F-:tt,-E4tAliiMi Cement in Tbg & IA from—9850' MD to 8800' MD lit MN Iplior '`'t 'Ile i' 19095700(8234'TVOI 9-3/8"x 5-V 8aker 5A8 Packer DV AL Aille . DPZ2: "!31,:, 1111 Ati Al! . -:nno 19313'5-ti'x 41-'5.X0 10,052' !!IO:. ' pr:;; MD to .... .....„, 10,057' , V101 no, MD 1 10080'Baker 4-,i""P.'Nipple ,,_ 19995'3.69-00 3alter Deployment Reeve Evo-Trieve Plug set @ 10,314' MD MD to NIil]ii ‹.*:'$-Ii:,', I'D -4.14 rigi !147/3 7',;('", 5*"!'n',) ''''"., •at. --%•,V,A',....,. -"''';',, W; ...„S:i:eA., 106/2'X-0 3-3/16"x 2-718- tie, "oi-,` ;.,C,C :. ,-.,• '-05,:V, YCx,, '------..--...„-____ \;x." ;VV7,1;$:.W, ;6'e". . '.?;:',' ii(En!,i,*,,,..t.4),"'., :n*, t'•!t::. 41,,:W:<;;::• „ ,'.7.Abb. 9-5134.-uai,,ng sea.•11372'3(Reports on easing deitith wiry( lop Bottom Weight Surat CoDapse Size (MD) (MD) Of FT Grade [P51) (PSI) 20' 30' 897' 94 H-40 1530 520 20- 897 1219 133 K-55 3060 1500 .133C Based on sacks Pumped and 20%hole washout 1)-3/8” 26' 2688' 72 N-80 5380 2670 9-5/81 24' 18137' 47 S00-45 8150 7100 9-5181' 180T 6474' 40 S00-95 1820 4230 9.5/11 En474' 966/1' 43.5 sloo-9s 7510 5600 9-5/81 966,8" 11344" 47 S00-95 8150 7100 • 0 DS 02-03 Post Surface Cement /— 5-'1'17c NPC-11-13 / / 9-5/3"Cason set on Efd Stops.340-150X Over / r / 13-3/3"Contras set on EPA 31x3r PP Cement in OA and 00A from—1000' surface, top job in 30"x 20" Annulus atipsurface.to 13-1-J.For_.0,48,,,,tro 1145' R, 13-3/B h c '- a ''g Cut and Pnit'd'd P'tth a 1184' i-.1..... Cement in IA from 2700' MD to surface, cement in 9_51,, tubing from 2700' to 1500' MD. .PP-,,v ,,, 1 „ '1111 ''.1 DPZ I ' ' ,,4 - st.5/8- . T.°C"1.1,3:71/4.1318:::1P.445ch3-01 TannOCuluins 95/188';5x,1_32-33/488"' Ionr, , , 3.35/r4Fp '", o7 k;Nil)ii 2171'Baker PFVE 3, 'I ' .4-13-3P 7636' 4 TOC 6450MD ........., MD MD 1il4l' . . , mi .. iD7-76:;Loweiltr W1E0 On 6773' ... Cement in Tbg& IA from—9850' MD to 8800' MD XO5 'MD 023,p WD I 9-5/8-a 5-%'Baker SAB Packer locar 5-1i*a 4-hr X0 DPZ2 . 'MD -'1 10,052' 10057' ..., . - 10030'Baker 4-5"'V Nipple , MD 5 3 643' OD 5aker Deployment Deese ' !' DPZ3. ie:,,ti,,,It,„,, , 10,256' '....J'':t.:,?‹..7.4. ..,.h. , Evo-Trieve Plug set @ 10,314' MD m D to t.-7-77,,,,,i,:, ,,,..,,,› .. „ 13353,X-0• 3-5"k 3-3/16- ,X.3W..,:`,, ,. „.,,,,,. r TD '. '''''. 41:, >"*„. -106ir X-03-3/13'x 2-7t8 ---------- :> ,;.0:x---'>' ..$'"; --- 12336'TO 1 l'k0",,V.q,"3On,,.' A "'Va„ ; s-sia-Cg 0/1372/' R-pot, ,s.on casang depth...ryt wsi. Bunt conapset Weight ToP Bottom Sla,* (MD) (MD) #/rr Gr (I)St)ads (PSO 520 1530 94 40 20," 30' 89 t 20 133 55 1500 ." 897' 1219 8 3060 .r GC Based on sacks Pumped end 20%hole washout 72 N-60 5380 2670 13..3/8ll 26' 2698' 47 800-95 8150 /100 9.,5/8' 24' 1807' 40 SOU-95 6820 4230 5/8„, nor 64/4' 0. 7510 s600 43 5 SC30-9B..518' 64?4' 96'68' 7100 47 800-95 8S()9-5/8' 9688' 11344' „ OF 7� • • 4. THE STATE Alaska Oil and Gas llhow k7 of Conservation Commission _ LAsKA 333 West Seventh Avenue ” ' GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 rti'' � Main: 907.279.1433 46:4* Fax: 907.276.7542 www.aogcc.alaska.gov Aras Worthington _ Interventions and Integrity Engineer �NEQ SES' 0 ] r1fil—; BP Exploration(Alaska), Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Re: Prudhoe Bay Field, Prudhoe Bay Oil Pool, PBU 02-03B Permit to Drill Number: 200-217 Sundry Number: 317-327 Dear Mr. Worthington: Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown,a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Cathy . Foerster ,,, Commissioner DATED this day of August, 2017. RBDMS k- AUG 3 1 2017 STATE OF ALASKA ("ALASKA OIL AND GAS CONSERVATION COMM! N • APPLICATION FOR SUNDRY APPROVA S 20 AAC 25.280 1. Type of Request: Abandon ❑ Plug Perforations 0 Fracture Stimulate 0 Repair Well ❑ Operations shutdown 0 Suspend m • Perforate 0 Other Stimulate ❑ Pull Tubing 0 Change Approved Program 0 Plug for Redrill 0 Perforate New Pool 0 Re-enter Susp Well 0 Alter Casing 0 Other 0 2. Operator Name: BP Exploration(Alaska),Inc 4. Current Well Class: 5. Permit to Drill Number: 200-217 ^ 3. Address: P.O.Box 196612 Anchorage,AK Exploratory 0 Development m• 99519-6612 Stratigraphic 0 Service 0 6. API Number: 50-029-20077-02-00 • 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this CEIVED EIV Will planned perforations require a spacing exception? Yes ❑ Nom • PBU 02-03B• RE 9. Property Designation(Lease Number): 10. Field/Pools: ADL 028308&028326 ' PRUDHOE BAY,PRUDHOE OIL • JUL 13 2017 _ 11. PRESENT WELL CONDITION SUMMARY _� , ( Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD: Effective Depth ND: MPSP(psi): Plugs(MD): Mll.i 12566 ' 9041 . 8800 7306 8800,10314 None Casing Length Size MD TVD Burst Collapse Structural 80 30" 31-115 31-115 880 Conductor 1189 20" 30-1219 30-1219 1530/2230 520/1500 Surface 2662 13-3/8" 26-2688 26-2688 4930 2670 Intermediate Production 1 10529 9-5/8" 24-10553 24-8642 8150/6820/7510 5080/3330/4130 Liner 2470 3-1/2"x 3-3/16"x 2-7/8" 10095-12565 8302-9041 Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): 11399-12500 9035-9039 5-1/2"17#x 4-1/2"12.6# N-80 22-10143 Packers and SSSV Type: 5-1/2"Baker SAB Packer Packers and SSSV MD(ft)and TVD(ft): 10005/8233 No SSSV installed No SSSV Installed 12.Attachments: Proposal Summary Iv] Wellbore Schematic m 13.Well Class after proposed work: Detailed Operations Program 0 BOP Sketch 0 Exploratory ❑ Stratigraphic ❑ Development m • Service 0 14.Estimated Date for Commencing Operations: August 1,2017 15. Well Status after proposed work: Oil 0 WINJ 0 WDSPL 0 Suspended m ' 16.Verbal Approval: Date: GAS 0 WAG 0 GSTOR 0 SPLUG 0 Commission Representative: GINJ 0 Op Shutdown 0 Abandoned 0 17.I hereby certify that the foregoing is true and the procedure approved herein will not Contact Name: Worthington,Aras J be deviated from without prior written approval. Contact Email: Aras.Worthington@bp.com Authorized Name: Worthington,Aras J Contact Phone: +1 907 564 4102 Authorized Title: Interventienti &Integrity Engineer Authorized Signature: // �/ Date: /3 n,.,i /'fir �((// COMMISSION USE ONL of approval:Notify Commission so that a representative may witness Sundry Number: -e 3t"1- 327 Plug Integrity I f BOP Test 0 Mechanical Integrity Test 0 Location Clearance V Other: p h&fa ci n e vwt rv,1' a v- i:--z,J "d Post Initial Injection MIT Req'd? Yes 0 No LiJ" Spacing Exception Required? Yes 0 No L-+f Subsequent Form Required: /0 —iD 7- n / APPROVED BYTHE Approved by:aziy {✓ y� ,, -1/ COMMISSIONER COMMISSION Date: �j-3b. 17 tvtlia 47_51 ORIGINAL RBDMS LvF, 0312017 Submit Form and Form 10-403 Revised 04/2017 Approved application is valid for 12 months from the date of approval. ,�/ AttainDuplicate • 02-03 Surface plug/Suspend Well Intervention Engineer Aras Worthington (907) 564-4102 Production Engineer Chris Stone (907) 564-5518 History 02-03 was originally drilled in 1970, worked over in 1975, finally recompleted in 1976. 02-03B is a June 2001 CTD sidetrack and completed with 2-7/8" x 3-3/16" x 3-1/2" production liner. The well was a naturally flowing producer completed in the Z1A and Z1 B. It was a full time producer until 2007 when it was SI for a flowline corrosion issue. After the flowline issue was resolved, it came online briefly in July of 2008 at which point it developed TxIA communication. A tubing patch was set from 6,668' - 6761' MD in December 2008 which resolved the TxIA communication. Increasing GOR resulted in lower ontime over the next several years. The well was POP'd briefly in late 2013 and then SI for a PMP on the flowline and remained SI for close to 3 years. In November 2016, the PMP was addressed and the well was brought online. An employee discovered an uncontrolled gas release from the top of the well shelter at approximately 7:30 a.m. on April 14, 2017, resulting in mobilization of the Incident Management Team. Leaks were noted from a sheared-off S-riser fitting and the tubing head adapter clamp/flange. The well was killed and the leaks stopped. The crude spray plume did not leave the well pad or adjacent reserve pit. There were no reported injuries. Slickline set an Evo-trieve plug in the the 3-1/2" Liner @ 10,314' MD on 4/19/2017. The plug was successfully pressure-tested to -250 psi to confirm it was set. A sundry was submitted and approved for placing -1000' of cement in the tubing and IA as part of the reservoir abandonment. The cement was in put on place on 6/6/2017. The cement plug was tagged at 8532' SLM on 6/15/2017. The cement plug was pressure-tested via a CMIT TxIA to 958 psi on 6/15/2017. Objective Place surface cement plugs in the well and remove the wellhead to suspend the well. . Procedural steps • Special Projects 1. Cement SSSV nipple control and balance lines. E-Line N aGt 2. Perforate @ -1300' MD through 5-1/2" tubing & 9-5/8" casing. agFetZ10-. IC MTV a z►-=a 1.E A?... PATVL PCZ.0c-% "CO Fullbore 0" gc. uArc o AOC; .. pstti&aL MC+7.' Valk-r\�c 3. Circulate cement down tubing and up OA & IA to cement both the OA & IA from -1300' MD to surface via the following pump schedule: ➢ 50 bbls heated diesel (take returns from OA) ➢ 100 bbls heated 9.8 ppg brine ➢ 5 bbls freshwater spacer ➢ 150 bbls 15.8 ppg cement per design (swap to taking returns from IA @ 110 bbls away) ➢ 23 bbls 9.8 ppg brine (displaces cement up IA and cement top in tubing to -1000' MD) Cement Design: ➢ BHST- 15 deg F ➢ BHCT- 50 deg F ➢ Cement: Class G Unislurry cement- mix on the fly ➢ Density: 15.8 ppg ➢ Thickening time: 3 to 5 hrs ➢ API Fluid Loss: 150-250 cc (75-125 cc/30 min) ➢ Compressive Strength: Minimum of 2000 psi ➢ Pump time: 30 minutes at assumed rate of 5 bpm ➢ Volume: 150 bbls (pumpable) Slickline fo ,v.thrSS . 4. Tag TOC in tubing. A/121';1-- 4° �G e1 /2 Gf homer iz- Ifra Eline 5. Perforate @ -1000' MD through 5-1/2" tubing, 9-5/8" casing, and 13-3/8" casing. Fullbore 6. Circulate cement down tubing and up OOA to cement the OOA from -1000' MD to surface via the following pump schedule: ➢ 50 bbls heated diesel (take returns from OOA throughout pumping) ➢ 200 bbls heated 9.8 ppg brine ➢ 5 bbls freshwater spacer ➢ 225 bbls 15.8 ppg cement per design Cement Design: ➢ BHST- 15 deg F ➢ BHCT- 50 deg F ➢ Cement: Class G Unislurry cement- mix on the fly ➢ Density: 15.8 ppg ➢ Thickening time: 3 to 5 hrs ➢ API Fluid Loss: 150-250 cc (75-125 cc/30 min) ➢ Compressive Strength: Minimum of 2000 psi ➢ Pump time: 45 minutes at assumed rate of 5 bpm ➢ Volume: 225 bbls (pumpable) 2 • . Special Projects • 7. Cut off all casings and wellhead -1' below pad level. Top job the 30" x 20" annulus and all other annuli and tubing with cement as needed. Install marker cap on outermost casing string. ph o fo c/a C_vs-vi t Y, - Note: final excavation, casing removal to 3' below tundra, and marker plate welding to occur at pad remed' tion. /Vot�f� %DC�CC Ir�s�t� ✓ i-.0 wftrits-S mark rr--. e'.,r h .-7 F r.v, S II 5,P �xpIoe-a ,t1. ,-, 4l a sway T' c. tO - 0313 p TD e 20 0 - 21 7-6 A'P.z DVc SD - DZ 9 - ZU a 7-9--'r 2 -'4° 3 0 • DS 02-03 Current Status 5-..174 rot-so-so 9-5/8*Cosine set an EM gips 0,340-1501(Osier //// „...- ..../ ....- 13-3/W'Courts set an EM Slif.s)BOK over 0 11 41I i 1 J +Yr 1 3 3 N 4 e; ; 20'giploint 242;362%4SC 1 X f It al r- ,tg 1 4 0,. 1 I BO^Condoetar---- WIC in 20''0 61.6 J I 9.8 ppg brine in I Tubing& IA from TOC to Surface I I TOC in 13-3/V t,, 1452-- . I •.. 1 ., I 9.-5/4-Casing Cut and PWI and pertein0(1.35D2 I 2171 Baker PF'siE SSW hippie ID0 4.56- 11.°C in 9-511r•7C1V .". I L....,,3_3,..-Casing Sha.0 2.61112MID I 26Ste Tti'D4— I n 965Ar DIVCoMar 0 4960 E co -0,:.In 4-5,E',iii 53 57 ll WFT Patch 5-'10'x 3-kk' E a 6661F tipper Element-6761'bower Eiernent i Minimum ID 4774 sa 241"ID %MUG 0 6774' 4 Cement in Tbg & IA from 9850' MD to 8800' MD 10005'MD 44234TDI 9-5/5 11 5-si'Baker 5A5 ineker 1111 1001S"5-k:"K ., . . 10040'Baker 4-v'"Ir Mople 10095 3.60' OD Baker Deolarroe-ne Sleeve [><------ Evo-Trieve Plug set @ 10,314' MD ...::.. s::: 1.0350 4-0 3-Si"x 3-3./W ... .. ..,... -..;„ :::::::: " ::.:::.':'• .:::' ..s."%k.„ —__ mar x-o3-3/26-22-715 ----- :- h-- -- - -- ------------__---------- _ ::,:: ---------.1----------___ ........•••-.........••••••.... TD :::::: -:-::::::.._.::akt..4 9-5/fir[Turns Shoe 0 11372"!flteparta asseasing deptisoorp)— Top Sotto ril Weight Burst Collapse 5i44 (MD) (MD) OFT Grads (PSI) (PBS) 20" 30' 69 i' 94 H-40 1530 520 20' 89?' 1219' 133 IC55 3060 1500 *TOC Based on Sacks Pumped and 20%hole washout 13-3/8,' 26, 2688, 72 N-80 5380 2670 9-5/v 24' 1807' 47 SO)-95 8150 7100 9-5/8' 180 t 5414' 40 500-95 e1120 4230 us/Er 6474 9668' 43.5 500-415 7510 5600 9-5/8" 966W 11344' 47 S00-95 8150 7100 0 • DS 02-03 Post Surface Cement 5-,4'175 NPC-N-84 -,,5:3'Colons,,et r,F44 SI F...7 4t 1.10-150W Ove, ->-.31 2 Ln.no4 L G't on tftel olap:e,5.3K Over .II. Cement in 00A from 1000' MD to surface, top job in 30"x 20" Annulus at surface. At_ .--13-3ig FOC-Coale.11417 1 1.3-3/5"Ci.tris£t and Pull.and Patch 4...,,1154' '41, Al 1 Cement in Tbg, IA, & OA from —1300' MD to I - surface TOC in 13-3/8".1453' i I I. - Do g L0000g eat End 119Aand pan*.1115111---- TOC in 9-5A"40 2512 -414 I 2171'tinker MIX 555V Nipple MO 4.56"— -.4—13-5.4.Cnnno 58oe iM.2.6851.410 125air MS— S DV Collar 0 4950 TOC in 9-51 tr 0 same WAFT Patch 5-11, E ICE..1 656w Upper Bement-675/ Lower Element 1 . Minn ,10 6774 0 231ID livelFG ilall7712' 4 Cement in Tbg & IA from 9850' MD to 8800' MD '1- 1004251VID 41234'TVIDis-slir II 5-14"Bilker 5745 Pecker [ , ."4 10013 5-1.4"c 4-91"XO I Ifs-x 10021C'Bailer 4-14""ir Minx& 15095 3.5O OD 5.4iiser Depberrient Sleeve / Evo-Trieve Plug set @ 10,314' MD ... . _ MOLT X-O 3.3121r is 2-7/Ir - g-51fr Ce.,-ang 5hoe 43 11372,IReports on cooing depth varyl— Top Bottom Weight Burst Collars* S,zio (MO) (MO) 6/Fr Grad, (851) (PSI) 30' 89 t 94 F 40 1530 520 20- 897' 1219' 133 K-55 30150 15(X) •Toc Based on Sacks Pumped and 20%hale washout 13-3/8" 26' 2888' 72 N-80 5380 2670 9-5/W' 24' 1807' 47 S00-95 8150 7100 9-5i4r 180t ,4/4E ' 40 500-95 6820 4230 9-sta- 6474 3663' 43.5 500-95 7510 5600 9-5if8a 9668 11344' 47 SC/0-95 8150 7100 MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg N61131 !7 DATE: June 11, 2017 P.I. Supervisor SUBJECT: Well Bore Plug &Abandonment PBU 02-03B - FROM: Matt Herrera BPXA Petroleum Inspector Prudhoe Bay Unit PTD # 2002170 - Sundry# 317-183 Section: 36 Township: 11N Range: 14E Meridian: Umiat Drilling Rig: Wireline Rig Elevation: 20 ft Total Depth: 12,556 ft MD - Lease No.: ADL 0028326(Surface) - Operator Rep: Jerry Boyles Casing/Tubing.Data: Casing Removal: Conductor: 20" - O.D. Shoe@ 1219 ft MD - Feet Casing Cut@ Feet Surface: 13-3/8" - O.D. Shoe@ 2688 ft MD - Feet Casing Cut@ Feet Intermediate: O.D. Shoe@ Feet Casing Cut@ Feet Production: 9-5/8" - O.D. Shoe@ 10809 ft MD - Feet Casing Cut@ Feet Liner: 3-1/2" - O.D. Shoe@ 12556 ft MD - Feet Casing Cut@ Feet Tubing: 5-1/2"x 4-1/2" - O.D. Tail@ 10143 ft MD Feet Casing Cut@ Feet Plugging Data: Type Plug Bottom of T.O.C. Mud Weight Pressure (bottom up) Founded on Cement T.O.C. Depth Verified? above plug Test Reservoir Bridge Plug . 10314 ft MD - 10289 ft MD- Wireline Tag• unknown - unknown Full Bore Balanced . 9850 ft MD . 8560 ft MD- Wireline Tag- 9.8 ppg - Type Plug Founded on: Verified? Open Hole Bottom Drillpipe tag 17 Perforation Bridge plug Wireline tag SCANNED �, � 2017 Annulus Balanced C.T. Tag Casing Stub Retainer No Surface This well (PBU 02-03B)was involved in an incident on April 14, 2017 where an uncontrolled gas release was identified. Refer to BPXA 30-day Report dated 5/15/2017 for details. BPXA is doing a reservoir abandonment procedure. On 4/19/17 BPXA set an Evo-Trieve plug in the 3-1/2"liner at 10,314 ft MD and followed with cement dump bailed on top (TOC at 10,289 ft MD). BPXA punched holes in the 5-1/2"tubing at 9850 ft MD and pumped a balanced plug with 15.8ppg cement in the tubing and tubing-casing annulus. Today I witnessed the verification (tag only; CPAI said required pressure test will be done at a later datee)of the uphole full bore balanced plug. The top of cement was tagged with bailer on wireline and found at 8560 ft MD. cc: Attachments: none rev. 4-20-16 2017-0611 Plug_Verification_PBU_02-03B_mh • • MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg 1 m 6/ 1 i 7 DATE: 5/30/2017 P. I. Supervisor FROM: Jeff Jones SUBJECT: Well Control Incident Petroleum Inspector BPXA PBU 02-03B (PTD 2002170) Prudhoe Bay Unit April 14, 2017: At approximately 8:50 am I received a call from John Ebel with the ADEC (Alaska Dept. of Environmental Conservation), inquiring about a gas release from BPXA (British Petroleum Exploration Alaska) PBU 02-03B. I had not been notified of a hydrocarbon release so I told Mr. Ebel I would get more information and relay it to the Alaska Oil and Gas Conservation Commission (AOGCC) Anchorage office and the ADEC. I called Flow Station 1 and spoke with the Control Room Operator Zachary Bell, who indicated that an uncontrolled hydrocarbon release was occurring at BPXA- operated PBU 02-03B and they had shut down production from Drill Site 2 and were in the process of depressuring the system. All indications were showing that the SSV (Surface Safety Valve) had closed. BPXA ERT (Emergency Response Teams) had been activated and were assembling at the site. The well normally produces approximately 3.5 MMscf of gas and +/- 500 bbls of oil per day. I relayed this information to acting AOGCC Inspection Group Supervisor Mike Quick and ADEC Environmental Specialist III John Ebel. I then drove over to the area of the release and from a distance saw that BPXA Security had stopped all traffic from entering the area in an approximately 1/2 mile perimeter, preventing unauthorized access. At approximately 10:30 pm, Mr. Quick called the AOGCC North Slope office and asked me to report first thing in the morning to the UC/IMT (Unified Command/Incident Management Team) Command Center that was being set up at the BPXA Prudhoe Bay Operations Center. My role was to provide technical assistance to UC Team and SOSC (State of Alaska On Scene Coordinator) Tom DeRuyter, who was assisted by ADEC Environmental Specialists III Jessica Starzman and John Ebel. April 15, 2017: I reported to the UC/IMT at 5:30 am and met with ADEC's Mr. Tom DeRuyter, and BPXA's UC Incident Commander Mr. Eric Burdon and IMT Leaders Mr. Len Seymore and Mr. John McMullen. I was added to the Operations Team as the AOGCC representative advising ADEC SOSC Tom DeRuyter and began attending situation report meetings. I also participated in developing source control risk assessments and action plans to respond to the incident. The UC/IMT were receiving site assessments from BPXA ERT personnel located at the Mobile Command Center set up near PBU 02-03B. SCANNED `,,E1-- 1 5 201:: 2017-0418_W ell_ControlPBU_02-03 B,j j Page 1 of 3 • • PBU 02-03B has an older-style McEvoy Generation 1 well head that reportedly had risen approximately 4 feet from its original position, causing the production tree to impact the steel well house. There were uncontrolled hydrocarbon releases flowing from the S-riser flow line where it impacted the well house and broke off a pressure gauge, and from a large well head flange clamp located below the master valve. The northeast wind was blowing most of the gas away from the site with lower explosive level (LEL) readings in a 5 to 20 PPM range. Well head pressure readings (from wireless telemetry gauges) indicated inner annulus (IA; tubing-casing annulus) of 799 psi and outer annulus (OA; casing-casing annulus) of 790 psi and were increasing. No injuries or impacts to wildlife were reported. Equipment was being staged to assist the response. Freeze protecting the shut-in wells at Drill Site 2 was in progress and safe zones were established by ERT personnel and enforced by BPXA Security. Three action plans being developed were to: 1. Open well house doors for more ventilation; 2. Evaluate well head IA/OA connections; 3. Attach bleed lines to control annulus pressures. Work on these action plans continued throughout the day and late into the evening. I participated as the AOGCC representative, relaying proposed action/entry plans to Mr. Quick in the Anchorage AOGCC office for approval. BPXA contacted Boots & Coots Well Control for contingency support. The EPA FOSC (Federal on Scene Coordinator) — Mr. Richard Franklin — arrived this evening and joined the UC/IMT for input and assistance developing action plans and federal approval. I traveled to the site with the UC/IMT for inspection and observed gas flowing from the top of the well house and some fluid on the ground. The well house doors were partially open but I was unable to clearly see the well house interior. BPXA brought an infrared camera to the site and captured video footage of the leak from a distance. BPXA ERT personnel fully opened the well house doors, increasing ventilation. They assessed damage to the well head and associated equipment, including the SSV which appeared to be closed and operable. BPXA Down Hole Diagnostic (DHD) personnel attached bleed lines from the IA and OA to large portable tanks and regained control of rising annulus pressures, recording bleed time, pressure, build up rate and fluid volume in the bleed tanks. In consultation with Mr. Quick, a not-to-be-exceeded 1000 psi pressure limit was set by the AOGCC on the OA of PBU 02-03B until notified otherwise. The site was continuously monitored around the clock by BPXA ERT personnel at the onsite Mobile Command Center. DHD personnel continued bleeds, mostly dead crude fluid, to control annulus pressures. All other activities ceased after sundown to be resumed, at daybreak April 16, 2017. April 16, 2017: I reported to the UC/IMT at 5:30 am and continued participating in developing action plans for response activities. Wind direction is still beneficial from the northeast. LEL readings were diminishing (+/- 7% LEL), due to hydrates forming at the leaking wellhead flange clamp. The well head dropped +/- 11" from the previous height. Five (5) bleed cycles have been completed with approximately 20 gallons of fluid from each bleed. The leak rate has not changed (visual observation) and duration between 2017-0418_W e llControl_PBU_02-03 B_i j Page_ 2 of-3 • • bleeds to control annulus pressures is decreasing. No injuries or impacts to wildlife were reported. BPXA well control expert Chris Scarborough arrived on scene and requested a one-on- one meeting with me where we discussed the situation and we both agreed that the quicker we act to kill PBU 02-03B, the better it would be for all. He indicated to me that he would advise the BPXA UC/IMT to utilize Boots & Coots personnel for well house entry & well repair work to speed up the process. Because Boots & Coots has much more experience with this kind of activity than BPXA personnel and when speaking with them, they were confident they could perform the necessary work safely and quickly, I agreed with his assessment. I relayed this information to Mr. Quick in Anchorage who also agreed and I supported Mr. Scarborough's recommendation to the UC/IMT. The well house entry plan was finalized and approved by the UC/IMT and AOGCC; Boots and Coots personnel made entry and repaired the S-riser leak. There was no change in the leak rate and no well head movement reported during entry. Meanwhile, the UC/IMT worked on risk assessments and preparing an action plan to pump a 1% KCL (calcium chloride) KWF (kill weight fluid) weighing 8.34 pounds per gallon (ppg) through an adjacent well flowline, to the drain system in the Drill Site 2 manifold building, into the PBU 02-03B well flowline and down the tubing to kill the well. This piping configuration was pressure tested, equipment was being staged for this procedure, and personnel were briefed in-depth on the specifics of the procedure. April 17, 2017: Continuing preparations to pump KWF (1% KCL 8.34 ppg) into well PBU 02-03. I remained on site at the BPXA ERT Mobile Command Center to observe the entire procedure. At 2:24 am the SSV was opened and a Little Red pump truck was brought on line and began pumping KWF down the tubing of PBU 02-03B. Indicated pump pressure was 2353 psi @ 2 BBL/min (barrels per minute). They slowly increased to 5 BBUmin while bleeding the IA and OA to control pressures below 1000 psi. No well head movement was observed. Pumping continued and at 3:28 am hydrocarbon flow from the leaking well head clamp ceased. LEL readings went to zero and pump pressure began decreasing. At 4:12 am with 580 BBL KWF away, pump pressure decreased to negative 5 psi. The pump was shut down and the well pressure and flow were monitored. The well went on a vacuum (no positive pressure) and was killed. Pumping KWF resumed at 2 BBL/min until a tubing plug could be set down hole to secure the well. No well head movement was observed during this procedure. April 18, 2017: I reported to the UC/IMT at 5:30 am and continued participating in developing action plans for setting the down hole tubing plug in PBU 02-03B. I arranged to hand my position on the IMT Operations Team to AOGCC Inspector Lou Grimaldi, as I was scheduled to go off shift and travel home tomorrow morning. At 6:00 pm we met with the UC/IMT leads to introduce Mr. Grimaldi to the Team and review the upcoming plugging procedure for well PBU 02-03B. Attachments: PBU 2-03B incident associated documents lL ct 2017-0418_W ellControlPBU_02-03 B_j j Page_ 3 of-3 • • of TtJ I//j:s, THE STATE Alaska Oil and Gas ti ,7r-- i r, of AL ASKA Conservation Commission 2 333 West Seventh Avenue 1."e' ti f. GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 Main: 907.279.1433 OF ALAS Fax: 907.276.7542 www.aogcc.alaska.gov Aras Worthington M4ittED Interventions & Integrity Engineer S BP Exploration(Alaska), Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Re: Prudhoe Bay Field, Prudhoe Bay Oil Pool, PBU 02-03B Permit to Drill Number: 200-217 Sundry Number: 317-183 Dear Mr. Worthington: Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown,a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Cathy P. oerster Chair DATED this f S day of May, 2017. RBDMS �'-" f 1 6 2617 STATE OF ALASKA •ALASKA OIL AND GAS CONSERVATION COMMI N APPLICATION FOR SUNDRY APPROV�S 20 MC 25.280 1. Type of Request: Abandon 0 Plug Perforations ❑ Fracture Stimulate 0 Repair Well ❑ Operations shutdown 0 Suspend !"�� Perforate ❑ Other Stimulate 0 Pull Tubing 0 Change Approved Program/ 0 Plug for Redrill ❑ Perforate New Pool 0 Re-enter Susp Well 0 Alter Casing 0 Other i2tcSeCtvctt,`i. G- }. r- G-tt-i- 2. Operator Name: BP Exploration(Alaska),Inc 4. Current Well Class: 5. Permit to Drill Number: 200-217 " 3, Address: P.O.Box 196612 Anchorage,AK Exploratory 0 Development H. 99519-6612 Stratigraphic 0 Service 0 6. API Number: 50-029-20077-02-00" 7. If perforating: 8. Well Name and Number: VED What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception? Yes 0 No ® PBU 02-03B " RE + 9. Property Designation(Lease Number): C�' 10. Field/Pools: ADL 028308&028326 ' PRUDHOE BAY,PRUDHOE OIL " MAY 0 5 Z017 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD: Effective Depth ND: MPSP(psi): Plugs(MD): J i M : C` - 12566 - 9041 ' 10314 8467 10314 None `d Casing Length Size MD TVD Burst Collapse Structural 80 30" 31-115 31-115 880 Conductor 1189 20" 30-1219 30-1219 1530/2320 520/1500 Surface 2662 13-3/8" 26-2688 26-2688 4930 2670 Intermediate Production 10529 9-5/8" 24-10553 24-8642 8150/6820/7510 5080/3330/4130 Liner 2470 3-1/2"x 3-3/13"x 2-7/8" 10095-12565 8302-9041 Perforation Depth MD(ft): Perforation Depth ND(ft): Tubing Size: Tubing Grade: Tubing MD(ft): 11399-12500 9035-9039 5-1/2"17#x 4-1/2"12.6# N-80 22-10143 Packers and SSSV Type: 5-1/2"Baker SAB Packer Packers and SSSV MD(ft)and ND(ft): 10005/8233 No SSSV Installed No SSSV Installed 12.Attachments: Proposal Summary 0 Wellbore Schematic 0 13.Well Class after proposed work: Detailed Operations Program 0 BOP Sketch 0 Exploratory 0 Stratigraphic 0 Development Il ' Service 0 14.Estimated Date for Commencing Operations: May 10,2017 15. Well llStatus after proposed work: Oi",yl /'A'4WINJ 0 WDSPL 0 Suspended 16.Verbal Approval: Date: GAS 0 WAG 0 GSTOR 0 SPLUG 0 Commission Representative: GINJ 0 Op Shutdown 0 Abandoned 0 17.I hereby certify that the foregoing is true and the procedure approved herein will not Contact Name: Worthington,Ares J be deviated from without prior written approval. Contact Email: Aras.Worthington@bp.com Authorized Name: Worthington,Aras J Contact Phone: +1 907 564 4102 Authorized Title: Interven• &Integrity�tetyEngineer Authorized Signature: Date: cig/� COMMISSION USE ONLY Conditions of approval:Notify Commission so that a representative may witness Sundry Number: max) PlugIntegrity � 3k1—AC? 9 tytj�� ✓— . BOP( Test 0 Mechanical Integrity Test 0 Location Clearance 0 Other: ) �:aL-►.x:'>1L. RAt,) (i EICA.ttCLEtt. -Li) QC Sr'AGA•.tTtk"1 V.) i0\06,Ci-- wtTvtt� ) CNAc`1GS t Ce•MEW t'-J P�AGZ / Post Initial Injection MIT Req'd? Yes 0 No 0/ r1SF C l ts' 1-4 Spacing Exception Required? Yes 0 No CI Subsequent Form Required: \ 4.04 u APPROVED BYTHE Approved by: � ?a �` COMMISSIONER COMMISSION Dates_/...c„ / ORIGINAL RBDMS Uv MAY 16 217 Submit Form and Form 10-403 Revised 04/2017 Approved application is valid for 12 months from the date of approval. Attachments in M41----0Duplicate S�tSlC`1221/7 ''''-' /- 5'71C./2 • 02-03 Reservoir Abandonment Intervention Engineer Aras Worthington (907) 564-4102 Production Engineer Chris Stone (907) 564-5518 History 02-03 was originally drilled in 1970, worked over in 1975, finally recompleted in 1976. • 02-03B is a June 2001 CTD sidetrack and completed with 2-7/8" x 3-3/16" x 3-1/2" production liner. The well was a naturally flowing producer completed in the Z1A and Z1B. It was a full time producer until 2007 when it was SI for a flowline corrosion issue. After the flowline issue was resolved, it came online briefly in July of 2008 at which point it developed TxIA communication. ." A tubing patch was set from 6,668' —6761' MD in December 2008 which resolved the TxIA communication. Increasing GOR resulted in lower ontime over the next several years. The well was POP'd briefly in late 2013 and then SI for a PMP on the flowline and remained SI for close to 3 years. In November 2016, the PMP was addressed and the well was brought online. An employee discovered an uncontrolled gas release from the top of the well shelter at approximately 7:30 a.m. on April 14, 2017, resulting in mobilization of the Incident Management Team. Leaks were noted 'from a sheared-off S-riser fitting and the tubing head adapter clamp/flange. The well was killed and the leaks stopped. The crude spray plume did not leave the well pad or adjacent reserve pit. There were no reported injuries. Slickline set an Evo-trieve plug in the the 3-1/2" Liner @ 10,314' MD on 4/19/2017. The plug was successfully pressure-tested to —250 psi to confirm it was set. Objective Place a reservoir-abandonment cement plug in the well above the existing liner plug to fully secure the well. Procedural steps Valve Shop 1. Set Tree-Test-Plug in BPV Profile. 2. Re-Torque Adapter Flange. 3. Test Tree and Adapter Flange to 2500 psi. 4. Remove Flowline from S-Riser. Manipulate S-Riser to relieve any trapped energy in the wellhead and allow wellhead to settle to neutral point. 5. Pull Tree-Test-Plug. E-Line • • 6. Dump-bail 25' of cement on top of Evo-Trieve plug @ 10,314' MD (2 runs/9 gallons with a 2-1/8" bailer). Fullbore 7. WOC 3 days. Pressure-test Tubing to 1000 psi to verify that suspected TxIA is not active (or is minimal/manageable) up to 1000 psi. E-Line 8. Tubing Punch at -9850' MD across the top collar of the first full joint of tubing above the production packer. Fullbore 9. Circulate down tubing and up IA swapping the entire wellbore to 9.8 ppg brine. Total volume -660 bbls. Tubing pressure not to exceed 700 psi. 10. Pump cement down Tubing and up the IA to get the TOC in the IA and tubing up to -8800' MD via the following pump schedule not to exceed 700 psi tubing pressure: ➢ 70 bbls 15.8 ppg Class G cement ✓ ➢ Drop foam wiper ball ➢ 5 bbls freshwater spacer ➢ 10 bbls 10.0 ppg mud push ➢ 2 bbls fresh water spacer ➢ 187 bbls 9.8 ppg brine Cement Design: ➢ BHST- 193 deg F ➢ BHCT- 165 deg F ➢ Cement: Class G Unislurry cement- batch mixed ➢ Density: 15.8 ppg ✓ ➢ Thickening time: 3 to 5 hrs ➢ API Fluid Loss: 150-250 cc (75-125 cc/30 min) ➢ Compressive Strength: Minimum of 2000 psi v ➢ Pump time: 60 minutes at assumed rate of 5 bpm ➢ Volume: 70 bbls (pumpable) Slickline 11. Tag TOC in tubing. DHD 12. After WOC 5 days, CMIT-TxIA to 1000 psi. ‘,/ -)4 ALL- .,. w opt✓ mow,ze--s ac * oc171L trh1.-) tit WE:u NCk�S -TO R'Cr yA%I-111T A U G(A!✓ w CTIA►t..) * o tc\-f S c)F- ‘t..) P 2 • • • DS 02-03 Current Status 5-}4"170 NPC-N-80 --- f'`; 9-5/8'Casing set on EM Slips 0 340-150K Over ,('+ 13-3/B."Cozens set on EM Slips 0 56K Over s Al I i 1 KCI Ys 1 e MeOh .4 -420'Slip home 242',36',486' Ir r -1 FP in i i d 0.4 Tbg n i E = - 30"Cnn friataa .i - $ « roc i,zo-0 616 1 ----13-3/8.FOC-Calla 0 114W ' '-• 13-3,4"Casing Cwt and Pvll and'hitch 0 11841' Dp ct cement 13-3/8 x 20"0 1215'(based on rasing recovery report) 20"Casing Shoe 1214",1[11219'TL`D/!- g 13 3AS Dv Ceder Ca 1211' I If 9-5./8"FOC-Collar VY 1807* ' ITOC in13-3/8"0 1453' I ?-5.'8"Casing Cwt and pull and pa c h&1350' I -- - ----- — le ID _ +zP B" 25.12'-- • 2111 3aker PP.5 55.54'Nippler 456"— -.F 13-3,a'Casing Shoe a 2688'MC 12688 .'''4T/l— a 8.5/6"jW Colter 0 4960 E E I TCIC in 9-504'e, = TNFT Patch 544'x3-4• E E..— am or Upper Element 6761'Lauver Element T T Minimum ID 5776'et 2.81'ID wiEd"a 0 677$' I tit al 9883 Baker Model"L'Sliding Skcv, 1 I-rt— 4947 Baker Model"R'Nippl. ci.x...- 9464'Baker SBA ASSN 'N: r,A.` 4 100051/10+8234"TOD'9-5/1"x 5-ti6 "Baker 58 Packer j4 10013 5-4"x 4-ici X0 I i.....__. 100$0'Baker 4-:S""R''Nipple 13055'3.66 00 30ker Deployment Sleeve .1 Evo-Trieve Plug set @ 10,314' MD 14369'X-03-9G":7-3416' 16111Z'X-o 3-8/ r E 2-7/8•.. - 4 '9-5/8'Casing Shoe 0 11372''Report"-on casing dap&naav)--- Top Bottom Weight Burst Collapse 5:zit (MD) (MD) #/FT Grade [PSI) (P51) ii;"' 30' 89/' 94 1-4-40 1530 520 20 897' 1219' 133 K 55 3060 1500 "TGC Based on Sacks Pumped and 2035 hole washout 13-3/8" 26' 2688' 72 N-80 5380 2670 9-5/8" 24' 1807' 47 S00-95 8150 7100 9-518" 180/ 54/4' 40 5000-95 6820 4230 9 5/&" 6474" 9668' 43.5 530-95 7510 5600 9-518° 96668' 11344` 47 S00-95 8150 7100 • I ' DS 02-03 Post Cement 5-Si"174 NPC-N-84 _. 9-548-Casing set on EMI S=ps s 340-150X Over '` ,� 13318"Caning set on EM Slips 050K Over —.. I I 1 ' '< J - 20'Stip lolut 242"',342' 486' 4 ]-.- .4 4 ; y 66 30"Conductor-- • TOC in 2i .615 9.8 ppg brine in II Tubing & IA from TOC to Surface ■ I --TOC ev 13-318"to 1453' II 9-Si9"Cc-en Cut end liven wed pitch.------ 2871'Baker PP&56511 Nipple ID.4.56"— TOC in 3515" 251 i 8_, 113-3,5'Ca:ing Shoe 2688'IYO[208'11lW SSi(8"W"CdAar 4n 49617 0 g ,_in 3518'= 5•35i' I WFT Watch 5-`'i*x 3-'4' el V.,, 6668 Jpper Element-6761'Lower Element i Minimum ID 6776'gi.2.81'ICS WL5I.L1 6775' r '7 �„-' Cement in Tbg & IA from—9850' MD to '„ .�' 8800' MD ..,.x_, ,•...c 'I 10005'MD y'323t'T9+E7!3-518-x 5-:5"'Baker 533 Wacker "4— 10018'5-ti.'x 4-91.r XC + 10380'Baker 4-'S""R''Niipple ._.. 10035.3.60”00 Taker Deployment Sleeve r::illir:: Evo-Trieve Plug set @ 10,314' MD .ii:-:-: . 1:7355 X-0 3-'s"c 3-3116. AYE -. -... -y_..-_. 181677X 18 -03-31'1[2-718 �.......... .... .a 9-5{8'.Casing Shoe if!11372'!Reports on casing depth var-al Top bottom Weight Bunt Collapse 5-.re [MD) GMDI Wit Bradt (PSI) (PSI) .z.� 30' 897' 94 H-40 1530 520 2C 897' 1219 133 X55 3080 1500 'TOC Based on Sacks Pumped and 20%hole washout 13-3/8" 26' 2688' 72 N-80 5380 2670 9-518' 24' 1807' 47 SA0-95 8150 7100 9.5/8' 180/ b4/4' 40 S00-95 6820 4230 9-S/8' 6474 44668' 43.5 500-95 7570 5600 9-5/8' 9668 11344' 47 SOO-95 8150 7100 • • Wallace, Chris D (DOA) From: AK, GWO Well Integrity Engineer <AKGWOWellSiteEnginee@bp.com> Sent: Tuesday,April 18, 2017 2:35 PM To: AK, GWO SUPT Well Integrity;AK, OPS FS1 OSM;AK, OPS FS1 Facility OTL;AK,OPS FS1 Field OTL;AK, OPS FS1 DS Ops Lead;AK, OPS FS1 DS1 Operator;G GPB FS1 Drillsites; Cismoski, Doug A; Daniel, Ryan;AK, RES GPB West Wells Opt Engr;AK, RES GPB East Wells Opt Engr;AK, OPS EOC Specialists;AK, OPS Prod Controllers; Stone, Christopher; Wallace, Chris D (DOA); Regg,James B (DOA) Cc: AK, GWO DHD Well Integrity;AK, GWO SUPT Well Integrity;AK, GWO Well Integrity Well Information;AKIMS App User; Dempsey, David G; Hibbert, Michael;Janowski, Carrie; Montgomery,Travis J; Munk, Corey; Obrigewitch, Beau; Pettus,Whitney; Sternicki, Oliver R;Tempel, Troy;Worthington,Aras J Subject: NOT OPERABLE: Producer 02-03B (PTD#2002170)Well Failure resulting in TxIA, IAxOA and leak to atmosphere at the wellhead. All, Producer 02-03B(PTD#2002170)experienced a failure on 04/14/17 that resulted in TxIA, IAxOA,and a leak to atmosphere at the wellhead. The well was successfully killed on 04/17/17 and efforts are underway to set a mechanical plug downhole. The well is classified as Not Operable. Please respond with any questions, Joshua Stephens2 Well Integrity Engineer SCANNED ;F'k Q (� Office: 907-659-8110 Cell: 907-341-9038 WO ww.0101401100.1.6e. 1 • 1111 N r w N co p E N 0 0 N d 4--' 1) O O p _U 0 � o N N m Cr' a) ct 00 Y C9 c Q Y CO.� 00 y co -.7.. t Q C -, N t wig - z O ora) a16 CO c U Q va ai T CI co m ID c CI n c in E 0 N N °a o Q z Q J r ,- C• e'0 C.7 co 0 ' E Q N M O e- M N � 1--r I CI o 0 <"`! ., W CO T.u a CI N d O U ,Q W o z J 0 O' 4' C' R' Z z LL LL LL LL re I- 0 I- 0 I- I- _FFF- ill 0000 rt W W W W 0 in 07000 Q 0 0 0 0 0 J J J J Z Z CO O W CCO 000 y O 0 0000 9 9 m H • Y Y Y F o Z m CO m a 2 mmmm w 07 W N N O Ce _J CO O- CDH W v c `m co p = 7 p c N N M — W Y U LCIS _ o • J CN tb 0. _ m Q01 v CO 16 :9 'd 0!S N Y C CD 0) O M N Z Q 0 m Q < ns O O ' 0 Q 2 r c m a La W CO ca p n a c?:), GAch N V Z Ill< O WO Q N a F J a N p a a m d rn • • bp BP Exploration (Alaska) Inc. Attn: Well Integrity Coordinator, PRB -20 Post Office Box 196612 0 Anchorage, Alaska 99519 -6612 RECEIVED August 22, 2011 AUG 31 2O1 Nike . 011 & Gas Cos. Commission Mr. Tom Maunder Anctaers ge Alaska Oil and Gas Conservation Commission 333 West 7 Avenue � fj✓ 2-.17 Anchorage, Alaska 99501 p - 313 Subject: Corrosion Inhibitor Treatments of GPB DS -02 Q S Dear Mr. Maunder, � rE!; t_ 70Y, Enclosed please find multiple copies of a spreadsheet with a list of wells from GPB DS- 02 that were treated with corrosion inhibitor in the surface casing by conductor annulus. The corrosion inhibitor is engineered to prevent water from entering the annular space and causing external corrosion that could result in a surface casing leak to atmosphere. The attached spreadsheet represents the well name, API and PTD numbers, top of cement depth prior to filling and volumes of corrosion inhibitor used in each conductor. As per previous agreement with the AOGCC, this letter and spreadsheet serve as notification that the treatments took place and meet the requirements of form 10 -404, Report of Sundry Operations. If you require any additional information, please contact me or my alternate, Gerald Murphy, at 659 -5102. Sincerely, Mehreen Vazir BPXA, Well Integrity Coordinator • • BP Exploration (Alaska) Inc. Surface Casing by Conductor Annulus Cement, Corrosion inhibitor, Sealant Top -off Report of Sundry Operations (10 -404) DS -02 Date: 07/21/2011 Vol. of Corrosion Initial top of cement Final top of Cement top off Corrosion inhibitor/ Well Name PTD # API # cement pumped cement date inhibitor sealant date ft bbls ft na gal 02-01B 1971400 500292044201 Sealed NA Sealed N/A NA NA 02 -02A 1971680 500292007401 5' NA 5' N/A 74.80 5/20/2011 02 -03B 2002170 500292007702 38' 11.0 4" 7/13/11 3.40 7/21/2011 02 -04A 1961580 500292006401 0.2 NA 0.2' N/A 1.70 4/27/2011 5/19/2011 6/2/2011 02 -05A 2030820 500292008101 4.5' NA 4.5' N/A 68.00 02 -06B 2040850 500292008602 6' NA 6' N/A 20.40 02 -07A 1981070 500292015401 Sealed NA Sealed N/A NA NA 02 -08B 1980950 500292015502 Sealed NA Sealed N/A NA NA 02 -09C 2071390 500292015303 Sealed NA Sealed N/A NA NA 02 -10B 2000640 500292016302 Sealed NA Sealed N/A NA NA 02 -11A 1981260 500292027301 Sealed NA Sealed N/A NA NA 02 -12B 2070580 500292027702 Sealed NA Sealed N/A NA NA 02 -13B 2012430 500292043302 Sealed NA Sealed N/A NA NA 02 -14A 2031250 500292044601 Sealed NA Sealed N/A NA NA 02 -15A 1960420 500292044701 Sealed NA Sealed N/A N/A NA 02 -16C 2070870 500292044803 Sealed NA Sealed N/A NA NA 02 -17B 2051300 500292045302 Sealed NA Sealed N/A NA NA 02 -18B 2061860 500292045402 Sealed NA Sealed N/A NA NA 02 -19 1811860 500292069300 Sealed NA Sealed N/A NA NA 02 -20 1820290 500292072100 Sealed NA Sealed N/A NA NA 02 -21A 2010990 500292078101 Sealed NA Sealed N/A NA NA 02 -22B 2100520 500292074002 Sealed NA Sealed N/A NA NA 02 -23A 2000530 500292079501 0.5 NA .5' N/A 5.10 5/19/2011 02 -24A 2040300 500292074401 0.5 NA .5' N/A 3.40 5/19/2011 02 -25A 2080910 500292076601 0.2 NA .2' N/A 0.85 5/19/2011 02 -26C 2050190 500292077403 0.2 NA .2' N/A 0.85 5/19/2011 02 -27A 1990930 500292199401 12.5' 8.5 3" 7/8/11 1.70 7/12/2011 02 -28A 2041640 500292201201 Sealed Sealed N/A NA NA 02 -29C 2040510 500292201103 65' Top Plate N/A NA NA 02 -30B 2001260 500292220202 Sealed NA NA N/A NA NA 02 -31A 1990150 500292222701 1.5' 1.5' N/A 11.05 5/18/2011 02 -32B 2020230 500292220902 1.1' 1.1' N/A 5.10 5/19/2011 02 -33B 2090450 500292221402 1' 1' N/A 8.50 6/1/2011 02 -34B 2100290 500292223402 0.8' 0.8' N/A 5.10 5/18/2011 02 -35B 2060020 500292222202 1.5' 1.5' N/A 10.20 6/1/2011 02 -36A 2100780 500292287701 19.6' 11.5 5" 7/8/11 2.55 7/12/2011 02 -37 1961750 500292271700 0.1 0.1 N/A 0.85 5/18/2011 02 -38 1961610 500292270800 1.5' 1.5' N/A 15.30 5/18/2011 02 -39A 1971100 500292272100 1.5' 1.5' N/A 11.90 5/18/2011 02 -40 2071620 500292337700 2.9' 2.9' N/A 25.5 5/18/2011 /-mss P9 STATE OF ALASKA ~~~~~® /~~ ~~ ~~\ ALA OIL AND GAS CONSERVATION COM~ION .JAN ~. ~ ZOOS ~, REPORT OF SUNDRY WELL OPERATION' Al'ae4a flil ~ (wac f'.nnr 1'.nmmiccinn 1. Operations Abandon ~ Repair Well 0 i Plug Perforations ~ Stimulate ~ Other SO TUBING PATCH . ~~ Performed: Alter Casing ~ Pull Tubing ~ Perforate New Pool ~ Waiver ~ Time Extension - 6765' -- Change Approved Program ~ Operat. Shutdown ~ Perforate ~ Re-enter Suspended Well 2. Operator BP Exploration (Alaska), Inc. 4. Current Well Class: 5. Permit to Drill Number: Name: Development r - Exploratory ~~ 200-2170 3. Address: P.O. Box 196612 Stratigraphic Service (~~~ 6. API Number: Anchorage, AK 99519-6612 50-029-20077-02-00 7. KB Elevation (ft): 9. Well Name and Number: 64 KB - PBU 02-036 8. Property Designation: 10. Field/Pool(s): ADLO-028308 ~ PRUDHOE BAY Field/ PRUDHOE OIL Pool 11. Present Well Condition Summary: Total Depth measured 12566 ~ feet Plugs (measured) None true vertical 9041.36 - feet Junk (measured) None Effective Depth measured 12524 feet true vertical 9040 feet Casing Length Size MD TVD Burst Collapse Conductor 115' 30" Surface - 115' Surface - 115' 880 Surface 2688' 13-3/8" 72# N-80 Surface - 2688' Surface - 2688' 5380 2670 Production 10809' 9-5/8" 47# S0095 Surface - 10809' Surface - 8854' 8150 5080 Liner 258' 3-1/2" 9.3# L-80 10101' - 10359' 8307' - 8500' 10160 10530 Liner 253' 3-3/16" 6.2# TC2 10359' - 10612' 8500' - 8688' Liner 1954' 2-7/8" 6.16# L-80 10612' - 12566' 8688' - 9041' Perforation depth: Measured depth: SEE ATTACHED - _ True Vertical depth: _ _ _ Tubing: (size, grade, and measured depth) 2.992" TUBING PATCH 0 6660' - 6765' 5-1/2" 17# L-80 SURFACE - 10018' 4-1/2" 12.6# N-80 10018' - 10143' Packers and SSSV (type and measured depth) 5-1/2X3/1/2"WFD ER PKR 6668' 5-1/2X3/1/2" WFD ER PKR 6791' 9-5/8"X5-1/2" BAKER SAB PKR 10005' 0 0 12. Stimulation or cement squeeze summary: Intervals treated (measured): _ }~~ > ( fi Treatment descriptions including volumes used and final pressure: 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing pressure Prior to well operation: 602 29262 26 1115 Subsequent to operation: 779 28484 44 978 14. Attachments: 15. Well Class after proposed work: Copies of Logs and Surveys Run Exploratory ~ Development - Service Daily Report of Well Operations X 16. Well Status after proposed work: Oil ~ Gas ~ WAG I~" GINJ ~ WINJ I"" WDSPL 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: N/A Contact Gary Preble - ~~~ ,j,~~j ~ ~ ~~(~ ~ `~-~ t E i ~ Ti l D t M . ng neer t e a anagemen Printed Name Gary Preble a Signature Rhone 5fr4-419,44 x;, ~'~ Date 1/14/2009 s 8 ~ ~:.. 02-03B 200-217 PFRF OTTOC:HMFNT • Sw Name Operation Date Perf Operation Code - ---- --- ----------- Meas Depth Top -- Meas Depth Base Tvd Depth Top Tvd Depth Base 02-03B 5/31/01 PER 11,399. 11,500. 9,035.02 9,040.3 02-038 5/31/01 PER 11,640. 12,170. 9,039.95 9,033.43 02-03B 5/31/01 PER 12,230. 12,340. 9,033.11 9,033.94 02-03B 5/31/01 PER 12,430. 12,500. 9,036.17 9,039.06 AB ABANDONED PER PERF APF ADD PERF RPF REPERF BPP BRIDGE PLUG P ULLED SL SLOTTED LINER BPS BRIDGE PLUG SET SPR SAND PLUG REMOVED FCO FILL CLEAN OUT SPS SAND PLUG SET FIL FILL SQF SQUEEZE FAILED MIR MECHANICAL ISOLATED REMOVED SQZ SQUEEZE MIS MECHANICAL ISOLATED STC STRADDLE PACK, CLOSED MLK MECHANICAL LEAK STO STRADDLE PACK, OPEN OH OPEN HOLE u • 02-03B DESCRIPTION OF WORK COMPLETED NRWO OPERATIONS EVENT SUMMARY ACTIVITYDATE SUMMARY 12/29/2008 ~ "**WELL S/I ON ARRIVAL*** (pre patch) ' PULLED 4-1/2" LTTP FROM 10087' SLM RAN 5 1/2" DMY PATCH DRIFT TO 9938' SLM._ i ~ ***WELL LEFT S/I ON DEPARTURE, DSO NOTIFIED*** 12/31/2008 ***WELL SHUT IN ON ARRIVAL*** ~ INITIAL T/I/O: 500 / 550 / 0 PSI. SET WEATHERFORD ER 5-1/2" LOWER PATCH PACKER ASSEMBLY AT 6765' MID ELEMENT. TOP OF PACKER AT 6761'. WLEG LOCATED AT 6778', 17' BELOW TOP OF PACKER. PX PLUG BODY NO PRONG) LOCATED AT 6776' IN X NIPPLE. MINIMUM ID THROUGH PACKER /TAILPIPE ASSY IS 2 81" AT X-NIPPLE WELL SHUT IN , ON DEPARTURE. FINAL T/I/O :500/550/0. ~ ***JOB COMPLETE*** 1/1/2009 T/I/O/00= 500/600/0/0+. Temp= SI. TBG & IA FL for fullbore. No AL. TBG FL @ 690' (17 bbls) IA FL @ 960' (56 bbls). SV,WV=C. SSV,MV=O. IA,OA,OOA=OTC. NOVP. _____ 1/5/2009`***WELL SHUT IN ON ARRIVAL*** SET P PRONG IN PLUG BODY $FT IN LOWER ~ M ~***JOB CONT. ON 1/6/09** _ 1/6/2009jT11/O/00 = 400/770/20. Temp = SI. T & IA FL (assist SL). No AL line. T FL @ 'surface. IA FL @ 714' (32 bbl). SL rigged onto well. 1/6/2009 T/I/0=550/600/35 Temp=S/I Assist S-Line MIT TBG to 3000 psi. FAILED (Restore tubing integrity) Spear in toTBG w/5 bbls of meth followed by 59 bbls of 10* diesel to bring up to test pressure 3000 psi IA PSI climbing Several TBG hanger lock down screw's weeping about 9 oclock and 1 casing lock down screw about 9 oclock Bleed well head psi down Final Whp's=400/700/35 wing shut swab shut master open ssv open casing valves open to gauges 1/6/2009 T/I/O/00=450/750/60/0 Assist S/L w/CMIT-TxIA to 3000 osi (Restore TBG Integrity) RU & PT. ***Continued on 01-07-09 WSR*** 1/6/2009 ***JOB CONT. FROM 1/5/09*** 'LRS BEGIN PUMPING AND CALLED OFF JOB 'LRS RETURN AND BEGIN PUMPING, LOCK-DOWN SCREW BELOW TBG HEAD ADAPTER BEGAN LEAKING, =SHUT DOWN WHILE WELLHEAD CREW REPAIRS, LRS RESUMES '.CMIT-Tx IA TO 3000#. (IN PROGRESS) ''**JOB CONT. ON 1/7/08*** E 1/7/2009 **"Continued from 01-06-09 WSR*** Assist S/L w/CMIT-TxIA to 3000 psi ""*"PASS***'' Restore TBG Integrity) Pumped 73 bbls crude down TBG while leeding gas off of IA to well #29 tree cap. T/IA lost 0/0 psi 1st 15 min, 40/0 psi 2nd 15 min. Tbg gained 10 psi IA lost 0 psi 3rd 15 min. FWHP'S=300/600/160 SV, WV=C SSV, MV=O IAV, OAV, OOAV=OTG MIT tags hung on MV &IAV. 1/7/2009***JOB CONT. FROM 1/6/09**" (patch) CMIT TxIA TO 3000# W/ LRS (PASS) ~ PULLED 3-1/2" PX PLUG FROM X-NIPPLE BELOW LOWER WFD 5-1/2" ER PACKER @ 6739' SLM SET THREE 32' X 2.992" SECTIONS OF WFD SPA( ***JOB CONT. ON 1/8/09'`** 1/8/2009'"**JOB CONT. FROM 1/7/09*** (patch) RIH W/ E-FIRE AND WEATHERFORD ER PKR (24.02' LONG) ;SET UPPER WFD ER PACKER @ 6645' SLM, LRS,PUMPED 38.4 BBLS CRUDE, PASSED MIT IA - TO 3000 PSI BLED IA-BACK DOWN TO 600 PSI.RDMO. *** LEFT WELLSHUT IN,TURNED WELL OVER TO DSO "*** T/I/0= 180/400/80/0 Temp= SI Assist Slickline pump as directed- MIT IA to 3000 psi PASSED (Restore TBG Integrity) Pressured up IA to 3000psi w/ 38.4 bbls 100" crude. MIT-IA lost 100osi in 1st 15 min, and 40osi in 2nd 15 min, w/ a total loss of 140psi over 30 min test. Bled IAP down. Bled back 10bbls. FWHP's= 180/600/160/20. ***Annulus casing valves tagged and left open to gauges*** SSL still on well at time of departure. FLUIDS PUMPED BBLS 63 diesel 2 MEOH 65 Total OPERABLE: 02-03B (PTD #2002170) Tubing Integrity Restored Page 1 of 2 • Regg, James B (DOA) From: NSU, ADW Well Integrity Engineer [NSUADWWeIIlntegrityEngineer@BP.comj ~ 2~~5~~ Sent: Friday, January 09, 2009 3:39 PM To: NSU, ADW Well Integrity Engineer; Regg, James B (DOA); Maunder, Thomas E (DOA); GPB, FS1 DS Ops Lead; GPB, FS1 OTL; GPB, Area Mgr East (FS1/2/COTU/Seawater); NSU, ADW Well Operations Supervisor; Rossberg, R Steven; Engel, Harry R; GPB, Wells Opt Eng; GPB, EOC Specialists; NSU, ADW WL & Completion Supervisor; GPB, Wells Opt Eng Cc: Kaminski, Alice; NSU, ADW Well Integrity Engineer; Quy, Tiffany Subject: OPERABLE: 02-03B (PTD #2002170) Tubing Integrity Restored All, Well 02-036 (PTD #2002170} passed an MIT-IA on 01108/09 after a tu.bin was set. The passing test confirms that tubing integrity has been restored. ere are, the well has been reclassified as Operable and may be placed on production when convenient. Operations: Please take caution of annular fluid expansion when putting the well online, as the IA and OA are liquid packed. Please call with any questions or concerns. Thank you, Andrea Hughes Well Integrity Coordinator Office: (907) 659-5102 Pager: (907) 659-5100 x1154 From: NSU, ADW Well Integrity Engineer Sent: Wednesday, July 16, 2008 8:37 PM s;,r K'+~ ~^~ To: 'Regg, James B (DOA)'; 'Maunder, Thomas E (DOA)'; GPB, FSl DS Ops Lead; GPB, FSl OTL; GPB, Area Mgr East (FSl/2/COTU/Seawater); NSU, ADW Well Operations Supervisor; Rossberg, R Steven; Engel, Harry R; GPB, Wells Opt Eng; GPB, EOC Specialists; NSU, ADW WL 8e Completion Supervisor Cc: Kaminski, Alice; NSU, ADW Well Integrity Engineer Subject: NOT OPERABLE: 02-03B (PTD #2002170) TxIA Communication All, A load and kill was pumped on well 02-03 after it failed an MIT-IA on 07/05/08. The well has remained at safed aut pressures since and has been reclassified as Not Operable. The plan forward is to set a tubing tail plug upon the rig's departure from well 02-40; as the rig is currently blocking access to 02-03. Please call with any questions or concerns. Thank you, 2/25/2009 OPERABLE: 02-03B (PTD #2002170) Tubing Integrity Restored Page 2 of 2 • Andrea Hughes From: NSU, ADW Well Integrity Engineer Sent: Sunday, July 06, 2008 3:04 PM To: 'Regg, James B (DOA)'; 'Maunder, Thomas E (DOA)'; GPB, FSi DS Ops Lead; GPB, FSl OTL; GPB, Area Mgr East (FSi/2/COTU/Seawater); NSU, ADW Well Operations Supervisor; Rossberg, R Steven; Engel, Harry R; GPB, Wells Opt Eng; GPB, EOC Specialists; NSU, ADW WL 8c Completion Supervisor; Bulloch, Kenneth S Cc: Roschinger, Torin T.; NSU, ADW Well Integrity Engineer; Holt, Ryan P (ASRC); Kaminski, Alice Subject: UNDER EVALUATION: 02-03B (PTD #2002170) Sustained casing pressure Hi all, Well 02-03B (PTD #2002170) has been found to have sustained casing pressure on the IA. The wellhead pressures were tubing/IA/OA equal to 1043/2250/420 psi on 06/29/08. Due to the constraints of having a rig on the neighboring well and not being able to bleed pressure down to the production system due to the shut-down, the diagnostic work took more days to complete. On 07/05/08, fullbore performed aMIT-IA that failed confirming TxIA communication and establishing a liquid leak rate of 1.1 bpm at 3000 psi. The well has been reclassified as Under Evaluation and placed on a 28-day clock. Operations may allow the IA pressure to continue to build pressure. The plan forward for the well is as follows: 1. Fullbore: MIT-IA to 3000 psi -FAILED 2. Production Engineer: Evaluate for a leak detection log and caliper 3. Wireline: Leak detection log, caliper, and secure well A TIO plot and wellbore schematic have been included for reference. Please call with any questions. Thank you, ~Cnna ~Du6e, ~? E. Weft integrity Coordinator GPB Wells Group Phone. (907) 659-5102 Pager: (907j 659-5100 x1154 2/25/2009 NOT OPERABLE: 02-03B (PTD #2002170) TxIA Communication Page 1 of 2 • • Regg, James B (DOA) From: NSU, ADW Well Integrity Engineer [NSUADWWeIIlntegrityEngineer@BP.com] ~~~ Gv,~~ i ~~ Sent: Wednesday, July 16, 2008 8:37 PM To: Regg, James B (DOA); Maunder, Thomas E (DOA); GPB, FS1 DS Ops Lead; GPB, FS1 OTL; GPB, Area Mgr East (FS1/2/COTU/Seawater); NSU, ADW Well Operations Supervisor; Rossberg, R Steven; Engel, Harry R; GPB, Wells Opt Eng; GPB, EOC Specialists; NSU, ADW WL & Completion Supervisor Cc: Kaminski, Alice; NSU, ADW Well Integrity E~eer Subject: NOT OPERABLE: 02-03B (PTD #2002170) TxIA Communication All, A load and kill was pumped on well 02-03 after it failP-~ ~~ fl~IT-IA on 07105108. The well has remained at safed out pressures since and has been reclassified as Not Operable. The plan forward is to set a tubing tail plu upon the rig's departure from Weil 02-40; as the rig is currently blocking access to 02-03. M Please call with any questions or concerns. Thank you, Andrea Hughes From: NSU, ADW Well Integrity Engineer Sent: Sunday, July 06, 2008 3:04 PM u~•',i'-2111 tl~~ J ~ ~ ~ L U ~ U To: 'Regg, James B (DOA)'; 'Maunder, Thomas E (DOA)'; GPB, FSl DS Ops Lead; GPB, FSl OTL; GPB, Area Mgr East (FSl/2/COTU/Seawater); NSU, ADW Well Operations Supervisor; Rossberg, R Steven; Engel, Harry R; GPB, Wells Opt Eng; GPB, EOC Specialists; NSU, ADW WL & Completion Supervisor; Bulloch, Kenneth S Cc: Roschinger, Torin T.; NSU, ADW Well Integrity Engineer; Holt, Ryan P (ASRC); Kaminski, Alice Subject: UNDER EVALUATION: 02-03B (PTD #2002170) Sustained casing pressure Hi all, Well 02-03B (PTD #2002170) has been found to have sustained casing pressure on the IA. The wellhead pressures were tubing/IA/OA equal to 1043/2250/420 psi on 06/29/08. Due to the constraints of having a rig on the neighboring well and not being able to bleed pressure down to the production system due to the shut-down, the diagnostic work took more days to complete. On 07/05/08, fullbore performed aMIT-IA that failed confirming TxIA communication and establishing a li uid leak rate of 1.1 b m at'3000 si. The well has been reclassified as Under Evaluation and placed on a 28-day clock. Aerations may allow the IA pressure to continue to build pressure. The plan forward for the well is as follows: Fultbore: MIT-IA to 3000 psi -FAILED Production Engineer: Evaluate for a leak detection log and caliper 3. Wireline: Leak detection log, caliper, and secure well A TIO plot and wellbore schematic have been included for reference. 8/29/2008 NOT OPERABLE: 02-03B (PTD #2002170) TxIA Communication Page 2 of 2 • Please call with any questions. Thank you, Anna tDude, ~P. E. Weil Integrity Coordinator GPB Wells Group Phone: {907} 659-5102 Pager; {907) 659-5140 x1154 8/29/2008 PBU 02-03B PTD 200-217 x,000. .........................o~'~s1ZC7rPrbr.......,..........,, , _ _. 3,000 2,000 1,000 t Tbg -E- IA f OA OOA -f- OOOA • • 0 4/611008 4f21(1008 SA6I2008 SI21 (2008 6!5!1008 6l20~1008 7A3l2008 7x2102008 TREE = MCEV OY WELLHEAD= MCEVOY ACTUATOR = AXELSON KB. ELEV = ~ 64' BF. ELEV.. KOP = Max Angle = 3100' 94 cz 111fi3' Datum MD = 10821' Datum TVD = 8800' SS ~ 02 9-5(8" CSG PATCH 1$50' 13-3f8" CSG, 72#, N-80, ID =12.347" 2688' Minimum ID = 2.380" @ 10612' 3-3/16" X 2-7/$" XO 5-1i2" TBG-NPC,17#, N-80, .0232 bpf, ID = 4.892" 3-1/2" LNR, 9.3#, L-80 FL4S, ID = 2.992" ~--~ 10101' 4-1 (2" TBG-NPC,12.6#, N-80, .0152 bpf, ID = 3.958" ~ 10143' ESTIMATED TOP OF CEMENT X0231' ~ 3-1t2", 9.3# FL4S X 3-3/16", 6.2# TG2 XO, ID = 2.800" ~-{ 10359° PERFORATION SUMMARY REF LOG: BHCS ON 08f28/70 ANGLE AT TOP PERF: 85 @ 11399' Note: Refer to Production DB for historical perf data SIZE SPF INTERVAL Opn/Sqz DATE 2" 4 11399 - 11500 O 05/31/01 2" 4 11640 - 12170 O 05/31f01 2" 4 12230 - 12340 O 05!31/01 2" 4 12430 - 12500 O 05/31!01 9-518" CSG, 47#, S0095, ID = 8.681" ~-~ 10809' f TOP OF OLD 9-578" SDTRK WINDOW - 02-03A I 1148° 95/8" FOC 1189' - 9-518" C5G PATCH 1$06' 9-518" FOC FV " " ' 5-112 BAKER P E SSSV NIP, lD = 4.56 2171 9$$3' S-112" BAKER L SLIDING SLV, ID = 4.56" 112" BAKER R NIP ID 4 47 " 9947' 5 . - = . 2 9954' 5-112" BAKER SBR ASSY 10005' 9-5/8" X 5-112" BAKER SAB PKR, ID = 3.875" 10018' S-112" X 4-112" XO, ID = 3.958" 10080° -~ 4-1/2" BAKER R NIP, !D = 3.759" , 10095' 3.60" BKR DEPLOY SLV W/ GS PROF~E, ID = 3.000" 10140' 4-1/2" BAKER SHEAROUT SUB 10143' 4-1!2" TUBING TAIL {BEHIND LNR) 10130° ELMD TT LOGGED 03/06177 9-5/8" CEMENT WINDOW 10553' - 10560' 10612° 3-3(16", 6.2#, TC2 X 2-718" 6.16# STL XO, ID = 2.380" 12524' 2-7f8" WIPER PLUG PBTD TD 125ss' 2-718" LNR-CT, 6.16#, L-80 STL, .00579 bpf, ID = 2.38fl" 12566' DATE REV BY COMMENTS DATE REV BY COMMENTS 11!28!76 ORIGINAL COMPLETION 12!21(05 COMlPAG WAiVERSAFETYNOTEREV 11!30195 CTD SIDETRACK 05/10;07 RDWlPAG WAVER SFTY NOTE DELETED 06/01/01 ADK CTD SIDETRACK 06/05101 CHIKAK CORRECTIONS 09126/02 BNUTP WAVER SAFETY NOTE 03!10103 JMP/TP WAiVERSAFETY NOTE PRUDHOE BAY UN(f WELL: 02-03B PERMff No: 1002170 API No: 50-029-20077-02 SEC 36, T11 N, R14E, 946' SNL & 1749' EWL BP Exploration (Alaska} 02-03B (PTD #2002170) Internal Waiver Cancellation - Normal Well . . All, An internal waiver was issued for IAxOA communication on well 02-038 (PTO #2002170) on 12/10/05. The well passed an MITIA on 04/02/07 proving two comepentent barriers. Under the new WI System Policy set to take effect on June 1, 2007, 02-03 will be Operable. The well is reclassified as a Normal well. Please remove all waivered well signs and the lamintaed copy of the waiver from the well house. Thank you, Andrea Hughes Well Integrity Coordinator Office: (907) 659-5102 Pager: (907) 659-5100 x1154 i)'~ED MAY 1 6 2007 I of 1 5/8/20074:51 PM F: \LaserFiche\CvrPgs _ Inserts\Microfilm _ Marker.doc MICROFILMED 04/01/05 DO NOT PLACE ANY NEW MATERIAL UNDER THIS PAGE Permit to Drill 2002170 MD 12566 '''''~ 'FVD DATA SUBMITTAL COMPLIANCE REPORT 61412003 Well Name/No. PRUDHOE BAY UNIT 02-03B Operator BP EXPLORATION (ALASKA) INC 9041 -~ Completion Dar 6/1/2001 f Completion Statu l-OIL Current Status l-OIL APl No, 50-029-20077-02-00 UIC N REQUIRED INFORMATION Mud Log N._~o Sample N_go Directional Survey DATA INFORMATION Types Electric or Other Logs Run: Well Log Information: Log/ Data Digital Digital Type Media Fmt Log Log Run Name Scale Media No Interval Start Stop (data taken from Logs Portion of Master Well Data Maint) OH I Dataset CH Received Number Comments ~ Ver LIS Verification ,-~COMP/NEU ,-117155 D.j~ectional Survey ~ Survey 9881 12520 7811 12291 7810 11670 10542 12561 FINAL 9881 12520 FINAL 9881 12520 FINAL FINAL FINAL ~ FINAL 78.~9~'~1-t670 Case 6/22/2001 10155,"'~881-12520 Open 8/14/2001 ~ 7811-12291~-----~ Open 8/14/2001 7810-11670 Open 4/18/2002 ~J;hT-6-W~ OH 6/22/2001 CH 6/22/2001 OH 7/6/2001 OH 7/6/2001 oh 8/20/2001 oh 8/20/2001 9881-12520 BL, Sepia 10155 ~cJ881-12520, Digital Data Directional Survey, Paper Copy MWD Survey, Digital Data 10~2/'~-7811-1~ta 1~263 .--7810-1~.data Well Cores/Samples Information: Name Start Interval Stop Sent Received Dataset Number Comments ADDITIONAL INFORMATION Well Cored? Y/~) Chips Received? Analysis R~.c.~.iv~.d'~ Daily History Received? Formation Tops Comments: Permit to Drill 2002'170 MD 12566 'I'VD DATA SUBMITTAL COMPLIANCE REPORT 614/2003 Well Name/No. PRUDHOE BAY UNIT 02-03B Operator BP EXPLORATION (ALASKA) INC 9041 Completion Dar 6/1/2001 Completion Statu 1-OIL Current Status 1-OIL APl No. 50-029-20077-02-00 UIC N Compliance Reviewed By: Date: WELL COMPLETION OR RECOMPLETION REPORT AND LOG .1. Status of well Classification of Service Well OIL r'~ GAS [~ SUSPENDED [~ ABANDONED ~] SERVICE 2. Name of Operator ~!~ 7. Permit Number BP Exploration (Alaska), Inc.~ 200-217 3. Address ,~ , 8. APl Number P. O. Box 196612 Anchorage, AK 99519-6612 ~ 50-029-20077-02 4. Location of well at sudace ;. ...... ., 9. Unit or Lease Name 945' FNL, 3530' FEL, Sec. 36, T11N, R14E, UM (asp's 688500, 5950277) .... .. ..,. Prudhoe Bay Unit , :;~ 10. Well Number At Top Producing Interval ~) , 4076' FNL, 4658' FEL, SEC(~ T11 N, R15E, UM (asp's 692461, 5947245) ................. 02-03B At Total Depth ..... ;,'-'-~:- - ,~'/-~-. .: 11. Field and Pool 3919' FNL, 822' FEL, SEC 36, T11N, R14E, UM (asp's 691283, 5947373)' . ..... .... Prudhoe Bay Field 5. Elevation in feet (indicate KB, DF, etc.) 16. Lease Designation and Serial No. RKB 64 feetI ADL 28308 Prudhoe Bay Oil Pool 12. Date Spudded 13. Date T.D.R..~,ached ¢z-~ 14. Date Comp., Susp. Or Aband. 115. Water Depth, if offshore 16. No. of Completions May 22, 2001 Ma~"~', 2001~J'/ June 1,2001Ii N/A feet MSL 1 17. Total Depth (MD + TVD) 18. Plug Back Depth (MD + TVD) 19. Directional Survey 120. Depth where SSSV set 21. Thickness of Permafrost 12566' MD /9041' TVD 12524' MD /9040' TVD YES r~l No ~-1I 2171' feet MD 1900' (approx) 22. Type Electric or Other Logs Run MWD GR & Mem GR/CCL/CNL 23. CASING, LINER AND CEMENTING RECORD SETTING DEPTH MD CASING SIZE WT. PER FT. GRADE TOP BOq-I'OM HOLE SIZE CEMENTING RECORD AMOUNT PULLED 30" 157.5# B Surface 115' 39" Fondu circulated tu surface 20" 94#/133# H-40 Surface 1219' 26" 1010 Sx Fondu 13-3/8" 72# N-80 Surface 2688' 17-1/2" 53o Sx Fondu & 550 Sx Class G 9-5/8" 47#/43#/40# S00-95 Surface 10553' 12-1/4" 1810 Sx Class G 3-1/2" x 3-3/16" 9.3#/6.2#/ L-80 10095' 12566' 3-3/4" 26 bbls 15.8 ppg LARC x 2-7/8" 6.16# 24. Perforations open to Production (MD + TVD of Top and Bottom and 25. TUBING RECORD interval, size and number) SIZE DEPTH SET (MD) PACKER SET (MD) (2" carriers, 6 SPF, & Zone 1 ) 5-1/2" 10018' 10005' 11399' - 11500' MD; 9035' - 9040' TVD 4-1/2" 10143' 11640' - 12170' MD; 9040' - 9033' TVD 12230' - 12340' MD; 9033' - 9034' TVD 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. 12430' - 12500' MD; 9036' - 9039' TVD DEPTH INTERVAL (MD) AMOUNT & KIND OF MATERIAL USED (See Sidetrack Summary for details) 27. PRODUCTION TEST Date First Production Method of Operation (Flowing, gas lift, etc.) June 11,2001 Flowing Date of Test Hours Tested Production for OIL-BBL :GAS-MCF WATER-BBL CHOKE SIZE I GAS-OIL RATIO 7/4/2001 6.6 Test Period >I 70 Flow Tubing Casing Pressure Calculated OIL-BBL GAS-MCF WATER-BBL OIL GRAVITY - APl (corr) Press. -290 psi 24-Hour Rate > 1627 113 61 28. CORE DATA Brief description of lithology, porosity, fractures, apparent dips and pressence of oil, gas or water. Submit core chips. * This 10-407 is submitted as directed per the 10-401 form approved January31,2001 (Permit#200-217) Form 10-407 Rev. 7-1-80 CONTINUED ON REVERSE SIDE GEOLOGIC MARKERS FORMATION TESTS NAME Include interval tested, pressure data, all fluids recovered and MEAS. DEPTH TRUE VERT. DEPTH gravity, GOR, and time of each phase. Top of Sag River Sand 10251' 8436' Top of Sadlerochit 10403' 8549' Top of Zone 1B 11003' 9003' Top of Zone lA 11093' 9033' 31. LIST OF ATTACHMENTS Summary of 02-03B CT Sidetrack Drilling Operations + End of Well Survey. 32. I hereby cedify that the following is t~e and co~ect to the best of my knowledge. ~/'~~~ Title Coiled Tubin, En,ineer Date ~//¢0/ Signed ~ MarkJohn"t-n' --;° Mo~ Prepared by Paul Rauf 564-5799. INSTRUCTIONS General: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. Item 1: Classification of Service wells: Gas injection, water injection, steam injection, air injection, salt water disposal, water supply for injection, observation, injection for in-situ combustion. Item 5: Indicate which elevation is used as reference (where not otherwise shown) for depth measurements given in other spaces on this form and in any attachments. Item 16 and 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 16, and in item 24 show the producing intervals for the interval reported in item 27. Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval. Item 21: Indicate whether from ground level (GL) or other elevation (DF, KB, etc.). Item 23: Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool. Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, Other-explain. Item 28: If no cores taken, indicate "none". Form 10-407 BP AMOCO Page 1 of 1 Final Well ! Event Summary Legal Well Name: 02-03B Common Well Name: 02-03B Event Name: REENTER+COMPLETE Start Date: 5/19/2001 End Date: 6/1/2001 DATE TMD 24 HOUR SUMMARY 5/19/2001 (ft) MIRU Nabors 3S and Dowell unit #4. 5/20/2001 10,365.0 (ft) NU & test BOPE. Try to pull TTV. Junk on top. ND. 5/21/2001 10,418.0 (ft) Finish repairs to BOP's & test. Start pilothole drilling. 5/22/2001 10,552.0 (ft) Drill pilot hole and ramp. Pull for BHA. Mill window. ., 5/23/2001 10,568.0 (ft) 20XP failures, 1 attempt to dress window. 5/24/2001 10,659.0 (ft) Dressed window, swapped to mud, drilled to Z-3, pulled for bit. 5/25/2001 10,900.0 (ft) Drilled Z-3, C/O Motor & bit, drill build in Z-2. 5/26/2001 11,468.0 (ft) Complete build and turn. Pull f/motor and bit. Drill Horizontal. 5/27/2001 12,487.0 (ft) Drill f/11468' to 12487' with mud swap. 5/28/2001 12,561.0 (ft) TD well. Condition hole. L/D drilling BHA and CTE. M/U Liner. 5/29/2001 12,561.0 (ft) Ran and cemented liner. Change well over to brine. Test BOP 5/30/2001 12,561.0 (ft) Clean out liner to 12,527. Run memory log CNL/GR/CCL. POH 5/31/2001 12,566.0 (ft) Lay down logging tools. Perforate well. 6/1/2001 12,566.0 (ft) Freeze protect tbg. ND. RD. Printed: 7/16/2001 2:55:52 PM BP AMOCO Page I of 7 Operations Summa Report Legal Well Name: 02-03B Common Well Name: 02-03B Spud Date: 5/22/2001 Event Name: REENTER+COMPLETE Start: 5/19/2001 End: 6/1/2001 Contractor Name: NABORS Rig Release: 6/1/2001 Rig Name: NABORS 3S Rig Number: Date From -To Hours Activity Code NPT Phase Description of Operations 5/19/2001 - 0.00 RIGU P PRE Move from Milne Point MPJ-01A to weigh station and back to DS #2. Position rig over well (double mat). RU pits. - 0.00 PRE Accept Dowell ~ at 2000 hrs, Nabors 3S at 2200 hrs. 22:00 - 23:00 1.00 RIGU P PRE Pull BPV. R/U HB&R to pump-in sub, PT lines, open master valve, 0 psi on well. Fill wellbore with water only took 1+ bbls to fill, pressure test wellbore with 1000 psi holding for 10 min confirming cement kick-off plug's isolation. No bleed off, release pressure and re-install BPV. .23:00 - 00:00 1.00 RIGU P PRE Remove master valve from wellhead assembly. (required for BOP stack to fit) Change out 2 3/8" pipe/slips rams damaged from previous well liner job. 5/20/2001 00:00 - 01:30 1.50 RIGU P PRE Prep wellhead and BOP stack for nipple up. Replacing 2 valves in Nabors choke manifold. Setting in return tanks, upright tanks and berms. 01:30 - 02:00 0.50 RIGU P PRE Held PJSM covering the operational plan, coordination required , and hazards associated with lifting the bop stack in place. (Very little room for error due to height of wellhead assembly) 02:00 - 06:00 4.00 RIGU P PRE Lift BOP assembly in place and nipple-up. 06:00 - 06:30 0.50 RIGU P PRE Safety meeting. 06:30 - 08:00 1.50 RIGU P PRE RU equip for BOP test. 08:00 - 09:00 1.00 RIGU P PRE Pull BPV. Attempt to set tubing test plug - cut the O-ring. 09:00 - 09:45 0.75 STWHIP N WAIT WEXIT Wait on some redress parts for tubing test plug. Set it. 09:45 - 17:45 8.00 STWHIP P WEXIT Perform initial BOP test. Witness waived by John Crisp of the AOGCC. 17:45 - 18:00 0.25 S'I'WHIP P WEXIT RU to stab inj. 18:00 - 18:30 0.50 STWHIP P WEXIT Safety meeting, crew change. 18:30 - 19:15 0.75 STWHIP P WEXIT PT inner reel valve and packoff and coil connector. Repair leak in swivel. 19:15 - 19:45 0.50 STVVHIP P WEXIT Displace coil with KCL 19:45 - 20:15 0.50 STVVHIP P WEXIT R/U to pull tubing test plug. Unable to get onto test plug. 20:15 - 20:45 0.50 STWHIP N SFAL WEXIT M/U nozzle to CT. RIH to top of test plug and wash. 20:45 - 21:00 0.25 STVVHIP N SFAL WEXIT Attempt to latch up to test plug but unable to. 21:00 - 22:30 1.50 STWHIP N SFAL WEXIT Pump out water from stack. Appears to be chunk of annular rubber sitting on top of test plug. Make-up "spear" to T-bar and fish out. Retrieved 1/2 set of 2 3/8" slip/pipe ram inserts. 22:30 - 23:00 0.50 STWHIP N SFAL WEXIT Prepare to nipple down. R/U to circulate CT. Plan is to remove doors from upper/lower 2 3/8" rams and inspect carriers/inserts. 23:00 - 00:00 1.00 STWHIP N SFAL WEXIT Remove doors on both upper/lower 2 3/8" rams. Only 1/2 set remain in lower ram body. Replacing rubber seals on both sets of rams. Will still need to N/D stack below 7 1/16" x 5K spacer spool and remove stainless steel keeper pins (laying on top of test plug) that were torn away from rubber insert seals. 5/21/2001 00:00 - 00:45 0.75 STWHIP N SFAL WEXIT Continue replacing seals on upper/lower 2 3/8" pipe/slip rams. 00:45 - 01:15 0.50 S'I'WHIP N SFAL WEXIT Nipple down BOP at spacer spool. Pick up and retreive both stainless steel keeper pins on top of test plug. 01:15- 02:45 1.50 STWHIP N SFAL WEXIT Nipple up BOP stack. 02:45 - 04:00 1.25 STVVHIP N SFAL WEXIT PT upper/lower 2 3/8" pipe/slips rams, blind rams and doors 300 psi Iow 3500 psi high. 04:00 - 04:30 0.50 S'I'WHIP N SFAL WEXIT Rig up and pull test plug. 04:30 - 05:30 1.00 S'I'WHIP P WEXIT P/U BHA #1 (64.32') 05:30 - 06:00 0.50 STWHIP P WEXIT Stab on injector. 06:00 - 08:00 2.00 STWHIP P WEXIT TIH to 10275'. Tools shorted. Printed: 7/16/2001 2:54::23 PM BP AMOCO Page 2 of 7 Operations Summar Report Legal Well Name: 02-03B Common Well Name: 02-03B Spud Date: 5/22/2001 Event Name: REENTER+COMPLETE Start: 5/19/2001 End: 6/1/2001 'Contractor Name: NABORS Rig Release: 6/1/2001 Rig Name: NABORS 3S Rig Number: Date From -To Hours Activity Code NPT Phase Description of Operations 5/21/2001 08:00-13:00 5.00 STWHIP N DFAL WEXIT POOH. Short in flapper valve sub. Replace. RIH. 13:00 - 14:00 1.00 STWHIP P WEXlT Log tie-in at 10260'. Correct depth (-11'). Wt check 52k up. RIH and tag top of cement plug 10365'. 14:00 - 20:00 6.00 STWHIP N DFAL WEXlT Attempt to orient. Can't get TF to change. Good current, then shorted-out. POOH. LD BHA. Short in EDC. CIO OXP and EDC. RIH 20:00 - 21:20 1.33 STWHIP N DFAL WEXlT Log tie-in at -16' correction. RIH tag cement at 10365'. 21:20 - 00:00 2.67 STWHIP P WEXlT Drill pilot hole. 2.2k web, 2.6/2.6 bpm, 3390 TP 3923 AP. Pumping 10 bbl 3# Bio-Zan pill every 30'. Drilled to 10418' 5/22/2001 00:00 - 06:10 6.17 STWHIP P WEXlT Continue drilling pilot hole from 10418'. 2.2KIbs WeB, 2.6/2.6 bpm, 3375 CTP 4025 AP. Pumping 10 bbl 3 ppg Bio-Zan pillevery 30' drilled. Drilled pilothole to 10538'. ReP steady at 25 - 30 FPH. 06:10 - 07:00 0.83 STWHIP P WEXlT Start drilling ramp with 135L TF. Drill ramp to 10550'. Pump last pill. 07:00 - 07:45 0.75 STWHIP P WEXlT Circulate hole clean, laying in last of pill in pilot hole. Note: Wt 60k steady thru pilot hole and above at 25 FPM. Open circ sub and wash 9-5/8" area 3.0 BPM; 2800 psi. 07:45 - 09:30 1.75 STWHIP P WEXlT POOH. 09:30 - 10:30 1.00 STWHIP P WEXlT LD 1.3 deg motor and pilot mill. MU 3.0 deg motor and DSM. 10:30 - 13:15 2.75 STWHIP P WEXIT RIH with BHA #4. Tag at 9905' and 10090'. Skipped thru both spots with minimum pump. 13:15 - 13:40 0.42 STVVHIP P WEXIT Log tie-in. Correct depth (-16.5'). 13:40 - 14:15 0.58 STVVHIP P WEXIT RIH while orienting to 135L Tag top of pilot hole at 10365' dry. Repeat. Bring pumps to minimum and run thru clean. RIH and tag at 10553' w/rain pump. PUH. Bring pumps to full rate 2.5/3200. RIH and tag 10552,5'. Flag pipe. PUH 1'. 14:15 - 00:00 9.75 STWHIP P WEXIT Time mill window following schedule. 2.5 bpm, 3100# ctp, 12k# string weight. 5/23/2001 00:00 - 04:30 4.50 STWHIP P WEXIT Continue milling window. Bottom of window @ 10558'. 04:30 - 05:20 0.83 STWHIP P WEXIT Drill 10' of rat hole. 05:20 - 06:15 0.92 STWHIP P WEXIT Ream window and drift. Pump biozan pill around. Log tie-in, (+2') Bottom of window 10560', rat hole to 10570'. 06:15 - 09:15 3.00 STWHIP P WEXIT Pull out of hole for crayola mill. Off bottom weight @ 60k#. 09:15 - 10:30 1.25 STWHIP P WEXIT L/D window mill and motor. Window mill worn across face as normal. M/U 1.69 deg. MM with crayola mill. C/O EDC, extruded o-ring. 10:30 - 12:45 2.25 STWHIP P WEXIT Zero weight indicator at surface. Showed 8k# w/o tools. Run in hole w/BHA #5, OAL=65.15'. Up weight on bottom still around 60k#. Injector hydraulic pressure corresponds with weight indicator cells. Close circulation sub, tools short out! 12:45 - 15:30 2.75 STWHIP N DFAL WEXIT Pull out of hole. 15:30 - 16:30 1.00 STWHIP N DFAL WEXIT Out of hole. Find Short in OXP. Change out. 16:30 - 19:00 2.50 S'I'WHIP N DFAL WEXIT RIH w/BHA #6. 19:00 - 19:20 0.33 STWHIP P WEXlT Log GR tie-in (-10.5') Attempt to drift window. Set down @ 10552.8' 19:20 - 20:30 1.17 STWHIP P WEXlT Dress window with crayola mill. Pumping 2.3 bpm, 3250# ctp. Stall 3 times. Mill through window at 10 fph. Continue to stall. Lose OXP again. 20:30- 23:45 3.25 STWHIP N DFAL WEXlT Pull for eXP. Up wt. 58k# off bottom. 23:45 - 00:00 0.25 STWHIP N DFAL WEXlT Change out OXP and crayola mill. 5/24/2001 00:00 - 00:30 0.50 STWHIP N DFAL WEXlT M/U BHA #7. 3.8" OD crayola with full button cutters (not , Printed: 7/16/2001 2:54:23 PM BP AMOCO Page 3 of 7 Operations Summary Report Legal Well Name: 02-03B Common Well Name: 02-03B Spud Date: 5/22/2001 Event Name: REENTER+COMPLETE Start: 5/19/2001 End: 6/1/2001 Contractor Name: NABORS Rig Release: 6/1/2001 Rig Name: NABORS 3S Rig Number: Date From -To Hours Activity Code NPT Phase Description of Operations 5/24/2001 00:00 - 00:30 0.50 STWHIP N DFAL WEXlT ground down) 00:30 - 02:15 1.75 STWHIP N DFAL WEXIT RIH w/BHA #7. OAL = 65.16' 02:15 - 02:45 0.50 STWHIP N DFAL WEXlT Log GRtie-in. (-11.5') 02:45 - 03:00 0.25 STWHIP N DFAL WEXlT Continue in hole. Close circ. sub. 03:00 - 06:45 3.75 STWHIP P WEXIT Tag up and stall @ 10552.8'. Work through with two stalls. Stall at bottom of window. Work through. Make two passes @ 10 fph up and down. Clean. Drift down and up with pumps off without any bobbles. Circulate 20 Bbl pill of biozan off bottom. 06:45 - 09:15 2.50 STWHIP P WEXIT Pull out of hole circulating through circ. sub. 09:15 - 10:20 1.08 STWHIP P WEXIT Change out Mud motor and bit. 10:20 - 12:30 2.17 DRILL P PROD1 Run in hole with BHA #8. OAL = 63.14'. 1.2 deg AKO 12:30 - 13:00 0.50 DRILL P PROD1 Log GR tie-in. (-16') RIH weight ~ 18.5k#. 13:00 - 13:45 0.75 DRILL P PROD1 Orient TF to 135L. RIH. Set down at top of cement plug @ 10355'. Close circ. sub, pump 1/2 bpm and get past. Continue in hole. 13:45 - 13:55 0.17 DRILL P PROD1 Drift through window w/o problem. Pump 2.4 bpm, 2800# with 3% KCL (milling fluid, mud en-route). Begin drilling slowly from 10566'. Drill to 10571'. Pull up hole to wait on mud. 113:55 - 15:15 1.33 DRILL P PROD1 Pull up to top of cement and dress entrance to pilot hole by back reaming. Pump 15 Bbl pill of 2# biozan. 15:15 - 16:00 0.75 DRILL P PROD1 Begin circulating in 8.9# Flopro. Displace coil and run to bottom. 16:00 - 21:20 5.33 DRILL P PROD1 Pump 2.4 bpm, 2600# ctp, 19k# string wt. 2k# wob, 60 fph. Full returns. Drill ahead to 10629'. Expect Z-3 ~ 10630'. Start seeing increased reactive torque. ROP decreases to between 25 to 10 fph. 10659'. 21:20 - 23:45 2.42 DRILL P PROD1 Pull out of hole for bit, open circ sub. 23:45 - 00:00 0.25 DRILL P PROD1 Change out bit MO9 for Smith mono-cone. MO9 gage cutters broken. 5/25/2001 00:00 - 00:45 0.75 DRILL P PROD1 Continue to change out bit. Change wire on EDC. 00:45 - 02:30 1.75 DRILL P PROD1 Run in hole w/BH^ #9. OAL = 62.12' (Smith Mono-cone) 02:30 - 03:15 0.75 DRILL P PROD1 Log GR Tie-in, -16.5'. 03:15 - 03:30 0.25 DRILL P PROD1 Continue running in hole. 03:30 - 07:30 4.00 DRILL P PROD1 Drill ahead f/10659'. Unable to put weight on bit without stalling motor. Making 10 fph at best. Continue to work with bit. Work weight to ~4k. Still stalling. 10677'. 07:30 - 10:15 2.75 DRILL P PROD1 Pull out of hole for bit. 10:15 - 10:45 0.50 DRILL P PROD1 Change out bit. Mono-cone insert teeth worn close to flat. Bearing turns but still tight. M/U Hughs tricone insert bit. Change mechanical disconnect. 10:45-13:00 2.25 DRILL P PROD1 RIHw/BHA#10. OAL=63.04'. 13:00 - 13:30 0.50 DRILL P PROD1 Log GR tie-in. (-18') 13:30 - 13:45 0.25 DRILL P PROD1 Continue running in hole. 20k# String weight. 13:45 - 16:15 2.50 DRILL P PROD1 Increase pump rate to 2.5 bpm, 3310# ctp, take it easy getting to bottom from 10650'. See slight motor work @ 10667'. Hole seemed to be in decent gauge. Drill ahead from 10677'. 30 fph, 2.5k# wob. Making good progress w/@ 4k# wob, 50 fph. 3340 ctp. 17k# string wt. Drilling smooth. No stalls. Drill to 10760' md, est @ 8745' TVD. 16:15 - 19:00 2.75 DRILL P PROD1 Pull for motor/bit. 50k# off bottom wt. 19:00 - 19:45 0.75 DRILL P PROD1 Change out motor and bit. AKO 2.2 deg. Bit MO9. 19:45-21:20 1.58 DRILL P PROD1 RIHw/BHA#11. OAL=63.23 Printed: 7/16/2001 2:54:23 PM BP AMOCO Page 4 of 7 Operations Summa Report Legal Well Name: 02-03B Common Well Name: 02-03B Spud Date: 5/22/2001 Event Name: REENTER+COMPLETE Start: 5/19/2001 End: 6/1/2001 :Contractor Name: NABORS Rig Release: 6/1/2001 'Rig Name: NABORS 3S Rig Number: Date From -To Hours Activity Code NPT Phase Description of Operations 5/25/2001 21:20 - 22:00 0.67 DRILL P PROD1 Log GR Tie-in, -15'. 22:00 - 22:15 0.25 DRILL P PROD1 Continue running in hole. 22:15 - 00:00 1.75 DRILL P PROD1 Resume drilling build fl 10760' to 10900'. 5/26/2001 00:00 - 01:00 1.00 DRILL P PROD1 Drill f/10900' to 10960'. 01:00-01:40 0.67 DRILL P PROD1 Short trip to window. PUwt. 45k, RIHwt18k. 01:40 - 02:45 1.08 DRILL P PROD1 Drill to 11040'. Stick BHA. 02:45 - 04:15 1.50 DRILL P PROD1 Attempt to work pipe. Mechanical weak piont set @ 10k#. Pump 10 Bbl crude. Pipe free w/6 Bbls out bit. 04:15 - 04:50 0.58 DRILL P PROD1 Short trip to window. 04:50 - 10:15 5.42 DRILL P I PROD1 Drill ahead. Reduce circulating rate to smooth out survey data. Pumping 2.1 bpm, 3000# ctp, drilling -60 to 100 fph. Land in Z-1 @ 11,120' md, 8975' TVD. Continue to get turn locked in. Drill to 11233'. Stick pipe. 10:15 - 11:15 1.00 DRILL P PROD1 Circulate 10 Bbls crude. Pop free w/5 Bbls out. 11:15- 12:15 1.00 DRILL P PROD1 Shorttrip towindow. 12:15 - 15:00 2.75 DRILL P PROD1 Drill f/11233'. Stacking out frequently. Drill solids only at 0.3%. Order new mud system at 8.6 ppg 50k LSRV for next trip in hole. Drill to 11367'. 15:00 - 18:30 3.50 DRILL P PROD1 Pull out of hole for AXO and bit. 18:30 - 19:15 0.75 DRILL P PROD1 LID MO9, face almost cored out. M/U DS-49 and bend motor to 1.2 deg. 19:15 - 21:15 2.00 DRILL P PROD1 Run in hole with BHA #12. OAL = 63.07'. 21:15 - 21:40 0.42 DRILL P PROD1 Log GRtie-in. -14'. 21:40 - 22:45 1.08 DRILL P PROD1 Continue running in hole. Swap out mud to new 9.6 ppg system. 22:45 - 00:00 1.25 DRILL P PROD1 Drill f/11368'. 54k# up wt. 2.5 bpm, 3300 off bottom 3450 drilling, seeing some differential sticking, but nothing like last bit run. Drill to 11468'. 5/27/2001 00:00 - 01:00 1.00 DRILL P PROD1 Drill ahead to 11540'. 01:00 - 02:00 1.00 DRILL P PROD1 Short trip to window. 02:00 - 03:40 1.67 DRILL P PROD1 Drill fl 11540'. 2.5 bpm, 3150 ctp, 49k# up wt, 15k# rih wt, lk# wob, +100 fph. Stacking out some. Drill to 11768'. 03:40 - 04:45 1.08 DRILL P PROD1 Short trip to window. 04:45 - 07:10 2.42 DRILL P PROD1 Drill ahead. 2.4 bpm, 3100 ctp, 49k# up wt, 14k# rih wt, 2k# wob, 40-100 fph. Stacking weight more frequently. Drill to 11970'. 07:10 - 09:00 1.83 DRILL P PROD1 Short trip to window. Annular pressure prior to short trip ~ 4520#. After ~ 4525#. 09:00 - 11:30 2.50 DRILL P PROD1 Drill f/11970', 2.4 bpm, 3250 ctp, 50k# up wt, 14k rih wt, 2k# wob. Hitting some shale stringers that cause stacking out of weight. Drill to 12135'. Annular pressure ~ 4535#. 11:30 - 13:45 2.25 DRILL P PROD1 Wiper trip to window. Pull up into casing and circulate out casing through EDC at 3.1 bpm. 4525# after trip. Mud running 45k LSRV and 8.6 ppg >0.5% solids. 13:45 - 15:20 1.58 DRILL P PROD1 Drill ahead f/12135'. 2.5 bpm, 3100 ctp, 51 K# up wt, 15k# rih wt. tough getting started then drill 60' pretty quickly. Stacking out again. Break free and drill to 12228'. Stick pipe. 15:20 - 16:30 1.17 DRILL P PROD1 Circulate 10 bbls crude. 5 bbls out, pipe comes free. Make 100' short trip. Almost 900' on this system. Order out new mud. Printed: 7/16/2001 2:54:23 PM BP AMOCO Page 5 of 7 Operations Summary Report Legal Well Name: 02-03B Common Well Name: 02-03B Spud Date: 5/22/2001 Event Name: REENTER+COMPLETE Start: 5/19/2001 End: 6/1/2001 Contractor Name: NABORS Rig Release: 6/1/2001 Rig Name: NABORS 3S Rig Number: Date From -To Hours Activity Code NPT Phase Description of Operations 5/27/2001 16:30 - 18:00 1.50 DRILL P PROD1 Takes off drilling +120 fph. Very clean sand @ 25 APl. Drill to 12320'. 18:00 - 20:00 2.00 DRILL P PROD1 Make wiper trip to window. 20:00 - 00:00 4.00 DRILL P PROD1 Resume drilling. 2.5 bpm, 3200# ctp, 4500# outer pressure. 50k# up wt. Slow starting until new mud in open hole. Takes off @ 60+ fph. 3k# string wt, 2k# wob. Drill to 12487'. 5/28/2001 00:00 - 01:00 1.00 DRILL P PROD1 Drill ahead to TD of 12532'. 2.5 bpm, 3300 ctp, 4450 bhp, 50 fph, stacking slightly. 01:00 - 03:00 2.00 DRILL P PROD1 Wiper trip to casing. 03:00 - 03:30 0.50 DRILL P PROD1 Log GR tie-in, +31'. 03:30 - 04:45 1.25 DRILL P PROD1 Run in hole pumping 1/2 bpm. See wt losses @ 11048', 11780', 11896', 12086', 12194', 12359', 12465' and 12430'. Tag corrected TD of 12561'. 04:45 - 10:30 5.75 DRILL P PROD1 Condition hole working shales. Drift w/o pumping. Bounce by 11048'. Set down 12194'. Ream this spot wi varying tool faces. Same w/12359'. 10:30 - 11:30 1.00 DRILL P PROD1 Lay in new Flopro from TD. 11:30 - 14:00 2.50 DRILL P PROD1 Pull out of hole. Circulate out casing. Lay in 1600' of 2% KCL. Freeze protect coil. 14:00 - 15:00 1.00 DRILL P PROD1 Lay down OXP BHA. 115:00 - 21:00 6.00 DRILL P PROD1 Lay down injector. Pull CTE. Stab ROC. Set test plug in tubing hanger. Install and test 3-1/2" TOT combination rams. ~ Pull test plug. '21:00 - 00:00 3.00 CASE P PROD1 Make up liner. 60 Jts. 2-7/8" STL (1 turbolator per joint), 8 Jts. 3-3/16" TC2, 8 Jts. 3-1/2" FL4S, 3-1/2" Liner deployment I sleeve, 6 x 3-1/2" Drill collars. 5/29/2001 !00:00 - 04:15 4.25 CASE P COMP Continue to make up liner assembly. 60 Jts. 2-7/8" STL (1 turbolator per joint), 8 Jts. 3-3/16" TC2, 8 Jts. 3-1/2" FL4S, 3-1/2" Liner deployment sleeve, 6 x 3-1/2" Drill collars. !04:15 - 06:30 2.25 CASE P COMP Run liner in hole. Check weight before entering window, 54k#. Run in open hole smooth until 12116'. See major weight bobbles; 12116', 12193', 12219' and 12300'. Set down at 12413'. Pick up w/60k# and bounce past. Set on bottom @ 12585' -24' correction = 12,561'. Pick-up weight 62k#. 06:30 - 07:45 1.25 CASE P COMP Circulate 5/8" ball 2.4 bpm, 2200 psi. Ball lands @ 48 Bbls away. Pressure up and shear w/3600#. Pick up on coil. Free at 32k# when pumping 1/2 bpm. Stack back down on liner and circulate 2.4 bpm, 2200psi. Rig up cementers. 07:45 - 08:00 0.25 CEMT P COMP PJSM for cement job. 08:00 - 10:25 2.42 CEMT P COMP Mix 30 Bbls 15.8ppg latex cement. Cement to weight @ 09:00. Pump 5 Bbls KCL. PT 4500#. Pump 26 Bbls cement 2 bpm @ 2200 psi. Load and launch dart. Pump 1 Bbl. Check for dart. Dart in Inner reel valve. Relaunch. Confirm dart is in coil. Chase cement w/20 Bbls 2# Biozan in 2% KCL. Follow with KCL. See dart land in LWP at 61.3 Bbls displacement (1Bbls more than calculated). 1 for 1 returns throughout entire job. Under displace liner by 1 Bbl. Check floats. Good. 26 Bbls returned once cement at shoe. Rig down cementers. Estimate top of cement in 9-5/8" @ 10231'. Cement in place @ 10:15. Sample taken to UCA. 10:25 - 13:10 2.75 CEMT P COMP P/U off of liner w/o pumping, 47k#. Pump KCL @ 2.7 bpm 2200 psi. Displace drilling mud from hole with KCL. Ship mud back to MI for next well. Pull out of hole @ 80% of 1 for 1. No Printed: 7/16/2001 2:54:23 PM BP AMOCO Page 6 of 7 Operations Summary Report Legal Well Name: 02-03B Common Well Name: 02-03B Spud Date: 5/22/2001 , Event Name: REENTER+COMPLETE Start: 5/19/2001 End: 6/1/2001 :Contractor Name: NABORS Rig Release: 6/1/2001 Rig Name: NABORS 3S Rig Number: Date From -To Hours Activity Code NPT Phase Description of Operations 5/29/2001 10:25 - 13:10 2.75 CEMT ~ COMP cement returns to surface. 13:10- 14:00 0.83 CEMT P COMP Lay down LRT. 14:00 - 15:30 1.50 BOPSUF.P COMP Run Test plug in tubing hanger for weekly BOP test. 15:30 - 22:00 6.50 BOPSUF. P ;COMP Perform weekly BOP test. Test witness waived by AOGCC inspector Jeff Jones. 22:00 - 22:30 0.50 BOPSUF.P COMP Pull BPV. 22:30 - 00:00 1.50 CLEAN P COMP Rig up floor to run CS hydril cleanout string. 5/30/2001 00:00 - 04:00 4.00 CLEAN P COMP PU cleanout assembly and 78 joints CS Hydril cleanout string 04:00 - 05:00 1.00 CLEAN P COMP MU coil connector assembly 05:00- 05:45 0.75 CLEAN P COMP PU injector head 05:45 - 07:00 1.25 CLEAN P COMP RIH w/BHA #14. OAL = 2529.76'. NOTE: Cement compressive strength on UCA @ 3120 psi after 19 Hrs. 07:00 - 08:45 1.75 CLEAN P COMP Wt. check at 10000'. 40k#. RIH to liner pumping 1/2 bpm. 19k# RIH wt. Wt checks at 11000' and 12000'. See slight weight bobble at 12145' ctm with 50 psi increase in circulating pressure. Slight weight bobbles every 30+ feet. Set down at 12532' ctm. Landing collar at 12527' dpm. (-5' correction) Liner wiper plug pushed to landing collar. Pick up clean. Circulate 2# Biozan at 1.7 bpm. 08:45 - 11:00 2.25 CLEAN 'P COMP POH circulating. 11:00 - 14:45 3.75! CLEAN P COMP Rack back injector and CS Hydril. 14:45 - 15:00 0.25 CLEAN ~P COMP Safety meeting prior to P/U of M-CNL tool. 15:00 - 17:15 2.25 EVAL ! P COMP M/U M-CNL tools and CSH. 17:15-19:00 1.75 EVAL P COMP RIHw/BHA#15. OAL = 2534'. to 9900' 19:00 - 22:50 3.83 EVAL P COMP Log from 12,531' to 9,900' 22:50 - 23:30 0.67 EVAL P COMP Lay in new mud in liner. 23:30 - 00:00 0.50 EVAL P COMP POH. 5/31/2001 00:00 - 05:15 5.25 EVAL P COMP POH Lat down 30 singles and stand back 24 stands. Lay down memory logging tools. 05:15 - 06:45 1.50 EVAL P COMP Test liner lap to 2000 psi. Held solid, zero leak off. Prepare to pick up guns. 06:45 - 09:15 2.50 PERF P COMP Pick up Perfguns. 09:15 - 10:00 0.75 PERF P COMP Lay down 11 guns for reduction of upper perf interval. 10:00 - 11:30 1.50 PERF P COMP CS Hydril. 48 Jts. 11:30 - 13:00 1.50 PERF P COMP Run in hole w/BHA #16. OAL - 2665.06'. Tag bottom and get pick up weight at 12524', on depth with GR/CNL. Pick up for bottom shot to be at 12500'. 13:00 - 14:15 1.25 PERF P COMP Circulate 5/8" ball at 2.5 bpm. Reduce rate at 45 Bbls away. Ball on seat at 58 bbls. Ball seat shears at 3100 psi. Pick up coil, free. 52k# with a couple bumps up to 60k#. Perforation depths 1!399-11500, 11640-12170, 12230-12340, 12430-12500 14:15 - 16:15 2.00 PERF P COMP Lose 1/2 Bbl with shot. (+100k LSRV Flopro in liner) Circulate across the top of well. POH w/perf, assembly. Well still taking @ 15 Bbls / hour. 16:15 - 16:45 0.50 PERF P COMP Hold PJSM to lay down CS Hydril. Monitor well while pumping across top. 16:45 - 20:00 3.25. pERF . P COMP Lay down CS Hydril. Keep hole full. 20:00 - 23:40 3.67 PERF I p COMP Lay down Perf guns. Keeping hole full well taking 15 bbl/hr 23:40 - 00:00 0.33, PERF P COMP Clear floor of handling tools etc. 6/1/2001 00:00 - 01:00 1.00 PERF ;P COMP Continue to clear floor 01:00 - 03:30 2.50: PERF , P COMP RIH to 2000' and freeze protect. Printed: 7/16/2001 2:54:23 PM BP AMOCO Page 7 of 7 Operations Summary Report Legal Well Name: 02-03B Common Well Name: 02-03B Spud Date: 5/22/2001 Event Name: REENTER+COMPLETE Start: 5/19/2001 End: 6/1/2001 Contractor Name: NABORS Rig Release: 6/1/2001 Rig Name: NABORS 3S Rig Number: Date From - To Hours Activity Code NPT Phase Description of Operations 6/1/2001 03:30 - 04:00 0.50 PERF P COMP POH 04:00 - 08:00 4.00 PERF P COMP Set BPV and ND BOP. NU master valve. 08:00 - 10:30 2.50 PERF P COMP Pull master valve, set test plug. Test master valve. Pull test plug, set BPV. Rig Released 10:30 6/01/2001. Printed: 7/16/2001 2:54:23 PM !' 02-03B DESCRIPTION OF WORK COMPLETED COILED TUBING SIDETRACK DRILLING OPERATIONS SUMMARY SUPPLEMENT Date Event Summary 6/11/2001 - 6/12/2001' 6/15/2001' 6/19/2001' 6/26/2001: 6/27/2001: Performed N2 lift w/CTU to kickoff well. First welltest. Well quit producing. Shutin well. MIRU SLU. RIH & drifted to 9879' but no further. POOH. RIH w/LIB - impression inconclusive. RIH w/pump bailer to obstruction. POOH. FM sand in bailer. RD. MIRU CTU. PT'd BOPE to 4000 psi. RIH w/CT to 11700' CTM. Pumped Slick 1% KCI Water & Biozan sweeps w/N2. FCO'd to PBTD @ 12524'. Kicked off well. POOH w/CT. RD CTU. Obtained a representative well test. Sidetrack Summary Page 1 TREE = MCEV OY ~" ,c vo 02 03B SAFETY NOTES: WELL EXOEEDS 7O DEG. ACTUATOR= AXELSON =' @ 11067' & GOES HOPJZONTAL @ 11133'. KB. ELEV = 64' BF. ~ = . ..... i KOP = 3100' MaxAngle= 94@ 11163' . .... I_~ 1148' I-l~,~,,~ocI ~'-- 8800'SS - -[ 1189' Id9-5/8"CSGPATCH ..... -'1 ~sos' H~-~,~"~ooI 19-5/8"CSGPATCHI--~ 1880' l'---I ~'-~-fl 2171' 1_I5-1/2"BAKER~--VESSSVN,P.,D:4.S6" I 113-3'8" CSG, 72#, N-80, ID :12.347" H 2688' ]-~ ~.~]--~ 9883' I--~5-1/2"BAKER LSLIDINGSLV, ID=4.S6"I Minimum ID = 2.380" @ 10612' 3-3/16" x 2-7/8" XO ~ ~--~ 9947' Id 5-1/2" BAKER R NIP, ID = 4.472" I ~--~~' 9954' ]--~5-1/2"BAKERSBRASSYI 5-1/2"TBG-NPC, 17#, N-S0, .0232 bpf, ID= 4.892" H ~00~8' t t ~00~8' 1--15-~"X4-1/2" XO, ID= 3.958"I I I----J 1o08o' I--J4-1/2"BAKERRN]P,,D=3.759"I ' ' -- "} 10095' Id3.60" BKR DEPLOY SLV W/GS PROFILF~ ID = 3.000" I~-~,~",N~, 9.~#,,-,0 ~,48, ,~= ~.~" H ~0~0~' 14-1/2"TBG-N~;,12.6#,N-80,.0152bpf, ID=3.95e"I-J 10143' l----~ ,.__~ 10143' I--]4-1/2" TUBING TAIL (BEHIND LNR)I I~s~'~o~°~°~c~M~N~ I-I ~023~' p- I ~0~30' H ~_MO,O~o~,o~ I :1~-~,~", ~.~# ~,~ x ~-~", ~.~# ~c~ xo, .~= ~..oo" H ~0389' I-- PERFORATION SUMMA RY I W'N °W I REF LOG: BHCS on 8/28/1970 ANGLE A TTOP PERF: 85 @11399' Note: Refer to Production DB for historical perf data s,z, ,N,,VA. Opn, qz , 2" 4 11399-11500 O 05/31/01 2" 4 11640-12170 O 05/31/01 I 2" 4 12230- 12340 O 05/31/01 i : 2" 4 12430- 12500 O 05/31/01 I DATE REV BY COMM~XlTS DATE R~t BY COMMEN-I'S F~UDHOE BAY uNrr 11/28/76, ORIGINAL COMPLETION 06/05/01 CH/KAK CORRECTIONS WF1L: 02-03B 11/30/95: CID SIDETRACK F~r_RMIT No: 200-217 12/28/00 SIS-SLI COIWE. RIEDTO CANVAS AH No: 50-029-20077-02 01/05/01 SIS-LG I REVISION SEC 36, TllN, R14[ 946' SNL. 8, 1749' ~/1_ 06/01/01 ADK CID SIDETRACK Bp Exploration {Alas La) ' SIZE SPF INTERVAL Opn/Sqz DATE 2" 4 11399-11500 O 05/31/01 2" 4 11640-12170 O 05/31/01 2" 4 12230- 12340 O 05/31/01 2" 4 12430- 12500 O 05/31/01 DATE REV BY COMMENTS DATE REV BY COMMENTS 11/28/76 ORIGINAL COMPLETION 06/05/01 CH/KAK CORRECTIONS 11/30/95 CTD SIDETRACK 12/28/00 SIS-SLT CONVERTEDTO CANVAS 01/05/01 SIS-LG REVISION 06/01/01 ADK CTD SIDETRACK BP Amoco Baker Hughes INTEQ Survey Report INTEQ Comlmny: BP ~ S#e: PB DS02 Well: 02-03 Wellpa~: 02-03B Date: 6/15/2001 Time: 11:06:04 Page: 1 Co-ordtaate(l~) Reference: Well: 02-03, True Nor~ Verth:ai Cf'VD) Reference: 7: 03 5/3011996 11:36 64.0 Section O/S) Refecence: Well (0.00N,0.00E~80.00Azt) Sur~ Calenlatlon Method: Minimum Curvature Db: Oracle Field: Prudhoe Bay North Slope UNITED STATES Map System:US State Plane Coordinate System 1927 Cee Datum: NAD27 (Clarke 1866) Sys Datum: Mean Sea Level Map Zone: Alaska, Zone 4 Coorainate System: Well Centre Geomagnetic Model: BGGM2001 Site: PB DS 02 TR-11-14 UNITED STATES: North Slope Site Position: Northing: From: Map Easflng: Position Uncertainty: 0.00 ft Ground Level: 0.00 ft 5948800.37 ft 687638.44 ft Latitude: 70 15 53.847 N Longitude: 148 28 58.060 W North Reference: True Grid Convergence: 1.43 deg Well: 02-03 02-03 Well Position: +N/-S 1456.36 ft Northb~g: 5950278.55 ft +E/-W 897.16 ft Easting: 688498.97 ff Position Uncertainty: 0.00 ff Slot Name: 03 Latitude: 70 16 8.170 N Longitude: 148 28 31.945 W Wellpath: 02-03B Drilled From: 02-03 500292007702 Tie=on Depth: Current Datum: 7: 03 5130/1996 11:36 64.00 ft Above System Datum: Magnetic Data: 5/17/2001 Declination: Field Strength: 57488 nT Mag Dip Angle: Vertical Section: Depth From (TVD) +E/-W ff ff 10550.00 ft Height Mean Sea Level 'JUL 0 6 2001 80.78 deg +N/-S Direction ~t dog Ala~ Oil & Gas Cons. Commmi o,oo o,oo o.oo 280.00 Anchor~ Survey: MWD Start Date: 5/28/2001 Company: Baker Hughes INTEO Euglueer: Tool: MWD,MWD - Standard Tied-to: From: Definitive Path Annotation ~= MD,'!: :~O':, ~ . ,': ,, ,",, , ,' .... ,,,, , 10550.00 8640.20 KO P 12561.00 9041.19 Projected to TD Survey ::MD, ,:],::: ,:,:inCl '' TVD:, ': SS~' ,: :' N/S: ",:':':' E/TM '::,,! MapN,,:,'] ' ', :': ,'DLS ':, :fi:,:':,, ,,,~,':deg: ~, ,d'eg::,,! :,ff,,:, I::,: :ft!:!~,:,,,,:':, ft',,'i:,:' : ' :,!': : :',,, i ":":ff:'~":";'::':deg/!OOff "::: ,: 10550.00 43.54 142.00 8640.20 8576.20 -3172.84 3691.29 5947199.34 692268.34 0.00 -4186.17 10612.00 35.40 131.20 8688.08 8624.08 -3201.57 3718.03 5947171.28 692295.78 17.14 -4217.49 10639.00 34.10 126.50 8710.27 8646.27 -3211.23 3730.00 5947161.92 692307.99 11.03 -4230.96 10670.00 32.90 116.90 8736.14 8672.14 -3220.21 3744.51 5947153.31 692322.72 17.51 -4246.80 10700.00 32.00 110.00 8761.46 8697.46 -3226.62 3759.25 5947147.27 692337.61 12.69 -4262.43 10735.00 31.50 94.30 8791.28 8727.28 -3230.49 3777.11 5947143.86 692355.56 23.59 -4280.70 10768.00 31.80 80.50 8819.40 8755,40 -3229.70 3794.31 5947145.08 692372.73 21.92 -4297.49 10797.00 32.20 67,80 8844,03 8780,03 -3225.51 3809.01 5947149.63 692387.33 23.21 -4311.25 10827.00 32.30 52.00 8869.44 8805.44 -3217.54 3822.75 5947157,94 692400.87 28.04 -4323.40 10857.00 24.20 58.90 8895.86 8831.86 -3209.42 3834.36 5947166.35 692412.26 29.07 -4333.41 10687.00 30.80 50.70 8922.46 8858.46 -3201.36 3845.58 5947174.68 692423.28 25.32 -4343.07 10917.00 39.40 37.00 8947.02 8883.02 -3188.85 3857.30 5947187.48 692434.68 38.73 -4352.43 10947.00 46.10 28.10 8969.06 8905.06 -3171.68 3868.14 5947204.92 692445.09 30.03 -4360.13 10977.00 53.60 20.10 8988.41 8924.41 -3150.78 3877.40 5947226.07 692453.82 32.22 -4365.62 11006.00 60.30 18.10 9004.21 8940,21 -3127.80 3885.33 5947249.22 692461.18 23.81 -4369.44 11036.00 66.70 12.00 9017.60 8953.60 -3101.89 3892.26 5947275.29 692467.45 28.03 -4371.76 11067.00 74.80 9.90 9027.82 8963.82 -3073.18 3897.80 5947304.13 692472.27 26.90 -4372.24 11101.00 84.80 3.20 9033.84 8969.84 -3039.99 3901.58 5947337.39 692475.22 35.22 -4370.20 BP Amoco Baker Hughes INTEQ Survey Report Company: BPAmoco Date: 6/15/2001 Time: 11:06:04 PaRe: 2 Field: F)rud~ Bay Ce.ordlmalz(NE) Refm'emce: Well: 02-03, True Norlll Site: PB DS 02 Vertical (TVI)) Reference: 7: 03 5/3011996 11:36 64.0 WeB: 02-03 Section (V$) Reference: Well (0.00N,0.00E,280.00Azi) Welilm~: 02..03B Smrvey Calcmlaflom MeBmd: Minimum Curv'atum Db: Oracle Survey MD I~cl Azlm TVD SSTVD N/S E/W MapN MapE DLS VS 11133.00 91.20 1.10 9034.95 8970.95 -3008.05 3902.78 5947369.35 692475.62 21.05 -4365.83 11163.00 94.40 356.00 9033.49 8969.49 -2978.11 3902.02 5947399.26 692474.11 20.05 -4359.89 11197.00 93.10 344.70 9031.26 8967.26 -2944.72 3896.34 5947432.50 692467.60 33.38 -4348.49 11228.00 91.80 337.20 9029.93 8965.93 -2915.47 3886.24 5947461.49 692456.76 24.53 -4333.46 11259.00 89.00 328.80 9029.71 8965.71 -2887.87 3872.18 5947488.72 692442.02 28.56 -4314.83 11292.00 89.40 320.30 9030.17 8966.17 -2861.02 3853.06 5947515.09 692422.23 25.78 -4291.33 11322.00 89.50 313.70 9030.46 8966.46 -2839.09 3832.61 5947536.49 692401.24 22.00 -4267.39 11352.00 87.00 307.10 9031.38 8967.38 -2819.67 3809.79 5947555.34 692377.95 23.51 -4241.54 11382.00 84.80 302.20 9033.52 8969.52 -2802.66 3785.19 5947571.72 692352.92 17.86 -4214.36 11409.00 85.30 297.80 9035.86 8971.86 -2789.22 3761.90 5947584.56 692329.31 16.34 -4189.09 11440.00 86.70 293.20 9038.02 8974.02 -2775.91 3733.99 5947597.19 692301.08 15.48 -4159.29 11472.00 87.90 290.30 9039.53 8975.53 -2764.06 3704.31 5947608.28 692271.11 9.80 -4128.00 11 502.00 89.00 288.80 9040.34 8976.34 -2754.03 3676.05 5947617.60 692242.61 6.20 -4098.43 11532.00 90.00 287.50 9040.60 8976.60 -2744.68 3647.54 5947626.23 692213.88 5.47 -4068.74 11567.00 90.10 283.90 9040.57 8976.57 -2735.22 3613.85 5947634.65 692179.97 10.29 -4033.92 11599.00 90.50 281.40 9040.40 8976.40 -2728.21 3582.63 5947641.08 692148.58 7.91 -4001.95 11633.00 90.70 277.80 9040.05 8976.05 -2722.54 3549.12 5947645.90 692114.94 10.60 -3967.96 11677.00 92.00 272.60 9039.01 8975.01 -2718.55 3505.33 5947648.79 692071.06 12.18 -3924.14 11713.00 90.90 267.50 9038.10 8974.10 -2718.52 3469.35 5947647.92 692035.10 14.49 -3868.71 11747.00 90.50 264.90 9037.68 8973.68 -2720.78 3435.43 5947644.82 692001.25 7.74 -3855.70 11781.00 90.60 258.90 9037.35 8973.35 -2725.56 3401.79 5947639.19 691967.74 17.65 -3823.39 11810,00 90.90 254.40 9036.97 8972.97 -2732.26 3373.58 5947631.79 691939.71 15.55 -3796.78 11846.00 92.40 253.10 9035.94 8971.94 -2742.33 3339.03 5947620.86 691905.43 5.51 -3764.51 11879.00 94.00 257.00 9034.10 8970.10 -2750.83 3307.21 5947611.57 691873.83 12.76 -3734.64 11915.00 94.00 262.60 9031.58 8967.58 -2757.18 3271.88 5947604.33 691838.67 15.52 -3700.95 11948.00 91.90 267.30 9029.88 8965.88 -2760.08 3239.06 5947600.61 691805.94 15.58 -3669.13 11979.00 91.40 269.90 9028.99 8964.99 -2760.64 3208.08 5947599.08 691774.99 8.54 -3638.76 12010.00 89.40 274.50 9028.77 8964.77 -2759.65 3177.12 5947599.49 691744.01 16.18 -3608.06 12040.00 89.50 279.10 9029.06 8965.06 -2756.10 3147.34 5947602.30 691714.15 15.34 -3578.11 12076.00 87.10 274.10 9030.13 8968.13 -2751.96 3111.61 5947605.54 691678.33 15.40 -3542.21 12102.00 87.40 272.00 9031.38 8967.38 -2750.58 3085.67 5947606.27 691652.37 8.15 -3516.43 12133.00 87.80 266.90 9032.68 8968.68 -2750.68 3054.71 5947605.20 691621.43 16.49 -3485.99 12163.00 89.50 262.20 9033.38 8969.38 -2753.73 3024.87 5947601.60 691591.66 16.66 -3457.09 12192.00 90.40 259.10 9033.41 8969.41 -2758.44 2996.26 5947596.18 691553.18 11.13 -3429.73 12226.00 90.50 254.40 9033.14 8969.14 -2766.23 2963.17 5947587.56 691530.30 13.83 -3398.50 12256.00 90.50 250.50 9032.88 8968.88 -2775.27 2934.57 5947577.80 691501.94 13.00 -3371.91 12286.00 90.80 248.60 9032.54 8968.54 -2785.75 2906.47 5947566.62 691474.11 6.41 -3346.05 12316.00 88.00 244.00 9032.85 8968.85 -2797.80 2879.01 5947553.89 691446.97 17.95 -3321.11 12346.00 86.50 240.00 9034.29 8970.29 -2811.87 2852.56 5947539.16 691420.88 14.23 -3297.50 12376.00 88.40 234.80 9035.63 8971.63 -2828.01 2827.32 5947522.40 691396.05 18.44 -3275.45 12406.00 90.10 231.10 9036.02 8972.02 -2846.08 2803.38 5947503.73 691372.58 13.57 -3255.01 12436.00 89.00 225.40 9036.26 8972.26 -2866.05 2781.01 5947483.21 691350.71 19.35 -3236.45 12466.00 86.50 215.60 9037.44 8973.44 -2888.81 2761.57 5947459.97 691331.85 33.69 -3221.25 12499.00 88.00 210.00 9039.02 8975.02 -2916.51 2743.72 5947431.64 691314.70 17.55 -3208.48 12561.00 88.00 210.00 9041.19 8977.19 -2970.17 2712.74 5947377.42 691285.07 0.00 -3187.29 Amoco -2550 2600 N:EFERENCE IN FO~tMA rION 2f~50 ;o ordinate (N/E) Reference Wel]Centre 02-03 TF~e Nad~ 2708 Ved~{TVD) Referen~ Systen Mear~SeaLeVe] 3edlo~ VS~ Re~erence Sloi 03 000N 0 0OE' Me~uredDegthReferen~ 7 035/2}/19961136 640L -2750 Calculation Meth~ M*nlmum C uP~a~u re 3200 340O 8350 £6oo ~NTF~O Z650 2/00 2[50 2800 2~50 2900 295{ 3000 3050 3~00 3150 3200 3250 3300 3350 3400 3450 3500 355( 3600 3650 3~00 3750 3800 3850 3900 3950 West (*}/East(+) [50ffJ~1 '~400-4350 4300-4250 4200-4150 4100 4050 4O0O 3950-3900 3850-3~00-3750 37O0-3650 3600-3550-3500 3450 3400-3350 33OO 325O 3200-3150 3100 3000 3000 2950 2900-2950 2000 ;'750 2/00 2650 2600 2550.250( Vertica~ Section at ~80.00' C~5/2001 11:07 A~ 06/19/01 Schlumberger Alaska Data & Consulting Services 3940 Arctic Blvd, Suite 300 Anchorage, AK 99503-5711 ATTN: Sherrle NO. 1231 Company: S~ate of Alaska Alaska Oil & Gas Cons Comm Attn: Lisa Weepie 333 WeSt 7th Ave, Suite 100 Anchorage, AK 99501 Field:' Prudhoe Bay Color Well Job # Log Description Date Blueline Sepia Prints CD ~,22A I11-- 20~ 21287 SCMT 05123101 '~).S. t1-38 I~q' 0~-~ 21286 SCMT 06122/01 D -26A 2.'~]- O~e rD 21279 MCNL 0512710t 1 .S. 2-03B ~_1~_-~,l'1 21278 MCNL 05/30101 1 1 t C-33A ~__P~D_ -~"J-/~, 21058 MCNL (REDO) 01/28101 1 *REDO - Changed depth shift edits - remove below KOP of A Well. PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING ONE COPY EACH TO: BP Exploration (Alaska) Inc. Petrotectnical Data Center LR2-1 900 E. Benson Blvd. Anchorage, Alaska 99508 Date Delivered: Schlumberger GeoQuest 3940 Arctic Blvd, Suite 300 RECEIVED Anchorage, AK 99503-5711 A'I-I'N: Sherde JUN 2: 001 ~KA OIL AND GAS CONSERVATION COPl~VI~SSION TONY KNOWLES, GOVERNOR 333 W. 7TM AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Dan Kara CT Drilling Engineer · BP Exploration (Alaska) Inc. P O Box 196612 Anchorage, AK 99519-6612 Re: Pmdhoe Bay Unit' 02-03B BP Exploration (Alaska) Inc. Permit No: 200-217 Sur Loc: 946'SNL, 1749'EWL, Sec. 36, T1 IN, R14E, UM Btmhole Loc. 3940'SNL, 4384'EWL,. Sec.' 36, T1 IN, R14E, UM Dear Mr. Kara: Enclosed is the approved application for permit to re&ill the above referenced Well. The permit to redrill does not exempt you from obtaining additional permits required by law from other governmental agencies, and does not authorize conducting drilling operations until all other, required permitting determinations are made. BlowoUt prevention equipment (BOPE) must be tested in accordance with 20 AAC 25 035.. Sufficient notice (approximately 24 hours) must be given to allow a representative of the Commission to witness a test of BOPE installed prior to drilling neW hole. Notice may be given by contacting the Commission petroleum field inspector on the North Slope pager at 659-3607. Sincerely, J. M. Heusser Commissioner BY ORDER OF THE COMMISSION DATED this ~ ~C~ day of January, 2001 dlf/Enclosures CC: Department offish & Game, Habitat Section w/o encl. Department of Environmental Conservation w/° encl. ' STATE OF ALASKA ALASKJ{ .,IL AND GAS CONSERVATION COM~i' iSION PERMIT TO DRILL 20 AAC 25.005 la. Type of work B Ddll [] Redrill 1 lb. Type of well [] Exploratory [] Stratigraphic Test [] Development Oil Re-Entry [] DeepenI [] Service [] Development Gas [] Sjp, rqle Zone [] Multiple Zone 2. Name of Operator 5. Datum Elevation (DF or KB') 10. Field and Pool BP Exploration (Alaska) Inc. RKB = 64' Prudhoe Bay Field / Prudhoe 3. Address 6. Property Designation Bay Pool P.O. Box 196612, Anchorage, Alaska 99519-6612 ~z~-~; .<~.ADL 028308 4. Location of well at surface v"' ,./ -/ 7. Unit or--'~roperty Name 11. Type Bond (See 20 AAC 25.025) 946' SNL, 1749' EWL, SEC. 36, T11N, R14E, UM Prudhoe Bay Unit At top of productive interval 8. Well Number 4040' SNL, 97' EWL, SEC. 31, T11N, R15E, UM 02-03B Number 2S100302630-277 At total depth 9. Approximate spud date 3940' SNL, 4384' EWL, SEC. 36, T11N, R14E, UM 01/23/01 Amount $200,000.00 12. Distance to nearest property line 113. Distance to nearest well 14. Number of acres in property 15. Proposed depth (MD and TVD) ADL 028326, 895' MDI No Close Approach 2560 12267' MD / 8970' TVDss 16. To be completed for deviated wells '17. Anticipated pressure {see 20 AAC 25.035 (e) (2)} Kick Off Depth 10400' MD Maximum Hole Angle 90 o Maximum surface 2470 psig, At total depth (TVD) 8800' / 3370 psig 18. Casing Program Specifications Setting Depth Size Top Bottom Quantity of Cement Hole Casin,q Weight Grade Coupling Len,qth MD TVD MD ~TVD (include sta,qe data) 3-3/4" 2-7/8" 6.4# L-80 FL4S 2192' 10075' 8223' 12267' 8970' 123 sx Class 'G' L,I- I V I::::i_2 _ ___ m _, DEC i 5 19. To be completed for Redrill, Re-entry, and Deepen Operations. Present well condition summary Alaska 0il & Gas Cons. Commission Total depth: measured 12180 feet Plugs (measured) Anchorage true vertical 9032 feet Effective depth: measured 12156 feet Junk (measured) CIBP Milled & Pushed to bottom, 12160' (09/97) true vertical 9032 feet Casing Length Size Cemented MD TVD Structural Conductor 115' 30" Fondu circulated to Surface 115' 115' Surface 1219' 20" 1010 sx Fondu 1219' 1219' Intermediate 2688' 13-3/8" 530 sx Fondu, 550 sx Class 'G' 2688' 2688' Production 10815' 9-5/8" 1810 sx Class 'G' 10809' 8826' Liner 2098' 2-7/8" 93 sx Class 'G' 10078' - 12176' 8289' - 9032' Perforation depth: measured 11400'- 11500', 11590'- 11610', 11610'- 11630', 11680'- 11822', 11860'- 12040', 12065' - 12155' true vertical 9022' - 9023', 9024' - 9024', 9024' - 9024', 9024' - 9027', 9029' - 9030', 9030' - 9032' 20. Attachments [] Filing Fee [] Property Plat [] BOP Sketch [] Diverter Sketch [] Drilling Program [] Drilling Fluid Program [] Time vs Depth PIct [] Refraction Analysis [] Seabed Report [] 20 AAC 25.050 Requirements Contact Engineer Name/Number: Dan/(ara, 564-5667 Prepared By Name/Number: Terrie Hubble, 564-4628 21. I hereby certify that~e foregoing ,is t/ue and~or_rect to the best of my knowledge Signed DanKara(~~,~~'7'/~' Title CT Drilling Engineer Date /~.....//~/~..~ .'.: .:?.' :i !'.: i::i..".' ..:': '.::'. '.... "i'.:'.....':"...~ :':;.'?.' :.':.'...::".:..'.'.!.:':.:.' :." :::.:": '.". "::. :::"ii::":.: :.:~:'::.i.~.i.Co.m~::iS~io:,:'.:U.sei':O~i~'.:..~ ::...i:,'.i: ::i.:.:.:::.~ ~'!':.:',..:.~'.; :.'~.~'i :::...... :/:;;;..;..: ;;:!.i :.::.:.:.. :./! :.; .i.': ;:: :/:..": i": Permit'Number ' " ' I APi Number ' ' . ' '" "' ' ' i' "' APProval Date." I See co'ver'iett~r ' ~- Z. /"~' 150- 029-20077-02 ~f I /---' ~_'~/, "" ~) I I for other requirements Conditions of Approval: Samples Required [] Yes I~No Mud Log Required [] Yes [] No Hydrogen Sulfide Measures ,1~ Yes [] No Directional Survey Required I~[,Yes [] No Required Working Pressure for BOPE [] 2K [] 3K [] 4K [] 5K [] 10K [] 15K /~3.5K psi for CTU Other: by order of t/ Approved By ,.-'v(--"-'~.-~/ ~t_- Commissioner the commission Date .. Form 10-401 Rev. 12-01-85 Submit In Triplicate BPX Prudhoe 02-03B Sidetrack Summary of Operations: 2-03a is being sidetracked to target Zone I reserves. This sidetrack will be conducted in two phases. Phase 1: Install ClBP, cut & pull liner, P&A, mill window Planned for Mid December. · A Mechanical Integrity Test will be performed. · A 3.75" drift will be run. · E-line install cast iron bridge plug at 10640' (below top of cement in 2-7/8" liner lap) to isolate/abandon existing perforations. · Cut and pull 2-7/8" liner from 10600' · RU service CTU, Pump 17 ppg cement to isolate 2-7/8" liner and provide a kick-off plug for window milling. · Mill 3.80" window at -10400' (Zone 4 KOP) Phase 2: Drill and Complete sidetrack: Planned for Jan 23, 2001. Drilling coil will be used to drill and complete the directional hole as per attached plan. Mud Program: · Phase 1: Water · Phase 2: Water for window milling, FIo-Pro (8.5 - 8.7 ppg) for drilling operatins. Disposal: · No annular injection on this well. · All drilling and completion fluids and all other Class II wastes will go to Grind & Inject. · All Class I wastes will go to Pad 3 for disposal. Casing Program: · 2 7/8", 6.4#, L-80, FL4S liner will be run from TD to approx. 10075' MD (into tubing tail) and cemented with approx. 25 bbls. Top of cement is planned to be at -10200'. The liner will be pressure tested to 2000 psi and perforated with coiled tubing conveyed guns. Well Control: · BOP diagram is attached. · Pipe rams, blind rams and the CT pack off will be pressure tested to 400 psi and to 3500 psi. · The annular preventer will be tested to 400 psi and 2000 psi. Directional · See attached directional plan · Magnetic and inclination surveys will be taken every 30 ft. No gyro will be run. Logging · A Gamma Ray Icg will be run over all of the open hole section. · A Memory CNL will be run in cased hole. RECEIVED BEC I 5 2000 Alaska Oil & Gas Cons Hazards Lost circulation risk is ]ow. No faults are mapped inside the polygon from this well was 8 ppm on 1/07/86. The highest H2S reading Reservoir Pressure Res. pressure is approx. 3370psi @ 8800ss. Max. surface pressure with gas (0.1 psi/ft) to surface is 2470 psi. 2-03B Potential Drilling Hazards Post on Rig o Please perform pre-job Hazard ID and Safety meetings prior to every change in work scope during the operation. Also, if things don't feel right shut-down the operation and discuss the situation before making the next operational move. SAFETY FIRST. 2. The highest H2S reading from this well was 8 ppm on 1/07/86. Ensure H2S pit monitors and personal monitors are operational. 3. BHP is expected to be 3370psi (7.4 ppg) @ 8800ss. 4. Maximum anticipated well head pressure w/full column of gas 2490 psi. 5. Lost circulation risk is low. No faulting is predicted. DS 02-03 13 3/8"@ 2688' ROPOSED CT HORIZONTAl . IDETRACK 5-1/2" SSSV Nipple @ 2171' (id= 4.562") 5-1/2", 17#, N-80 Production Tubing to 10018' 5-1/2" Sliding Sleeve @ 9883' 5-1/2" Baker R Nipple @ 9947' (id=4.472") 5-1/2 x 4- 1/2" Crossover @ 10,018' 9 5/8 .... x 5-1/2" Baker SAB Packer @ 10,005' 4-1/2" Baker R Nipple @ 10080' (id = 3.812") 4-1/2" Tubing tail @ 10143' (10130' elmd) Estimated TOC @ I 10,200'md I Desired Top of 2-7/8" Liner @ ~ 10,075', inside 4-1/2" TT Mill Window through 9-5/8" Liner @ ~ 10,400' off of cement ramp Cut Top of 2-7/8" liner @ -10600'md Install CIBP @ 10640'md Existing 9 5/8" window @ 10,809 Isolated w/CIBP 2-7/8" Liner @ 12,176' 2-7/8" 6.4# STL Liner Cemented & Perforated 3.75" Open Hole TD @ ~12267' ARCO ALASKA, INC. FO @ 1148' Tubing-NPC CP @ 1189' Casing ............................ Casing CP @ 1850' SSSVNIP SLS NIP SBR PKR Tubing-NPC XO OTHER' 10079 MIN ID =2.440" Crossover 3-1/2" x 2-7/8" XO SOSUB Liner-CT TTL Window J Perf ............ -- -- -- FISH ~ OTHER A 02-03A APl: 500292007701 SSSV Type: Annular Fluid: Diesel/10,8 CaCI2 Reference Log: BHCS Last Tag: 11202 Last Tag Date: 10/11/97 Well Type: PROD Depth Annotations Depth Comment 1148 FO @ 1148' 1189 CP @ 1189' 1807 FO @ 1807' 1850 CP @ 1850' Prudhoe Bay Odg Compltn: 11/30/95 Last W/O: 12/1/95 Ref Log Date: 8/28/70 RKB: 64 ft TD: 12180 ffKB Max Hole 91 deg @ 12001 Angle: Angle @ TS: 43 deg @ 10404 02-03 Angle @ TD: 88 deg @ 12180 Rev Reason: Pull PKR-kak Last Update: 6/27/00 10079 10079 MIN ID =2.440" Crossover 3-1/2" x 2-7/8" 10809 10809'- 10815' 9-5/8" Window General Notes Date Note 3/6/77 TTL ELM @ 10130: ELM Tubing Tail (Logged 03/06/77) (Behind CT) Other (plugs, equip., etc,) - JEWELRY Depth TVD Type Description ID 2171 2171 SSSVNIP 5-1/2" Baker PFVE SSSV Nipple 4.560 9883 8140 SLS 5-1/2" Baker L Sliding Sleeve 0.000 9947 8189 NIP 5-1/2" Baker R Nipple 4.472 9954 8194 SBR 5-1/2" Baker SBR Assembly 0.000 10005 8233 PKR 9-5/8" x 5-1/2" Baker SAB Packer 0.000 10018 8243 XO Crossover 5-1/2" x 4-1/2" 2.441 10078 8289 OTHER 4-1/2" Seal Sub 3.812 10079 8290 XO Crossover 3-1/2" x 2-7/8" 2.440 10080 8291 NIP 4-1/2" Baker R Nipple (Behind CT) 3.810 10140 8336 SOSUB 4-1/2" Baker Shearout Sub (Behind CT) 0.000 10143 8339 TTL 4-1/2" Tubing Tail (Behind CT) 0.000 12176 9032 OTHER 2-7/8" Davis Lynch Float Shoe 0.000 Fi:sh ;: F!SH i : : Depth Description Comment Date 12160 FISH FISH: CIBP Milled & Pushed to bottom (09~04~97) 11/30/95 Size Weight Grade Top Btm Feet Description 13.375 72.00 N-80 0 2688 2688 Casing 9.625 47.00 SOO-95 0 10809 10809 Casing 2.875 6.50 L-80 10078 12176 2098 Liner-CT Size Weight Grade Top Btm Feet Description 5.500 17.00 N-80 0 10018 10018 Tubing-NPO 4.500 12.60 N-80 10018 10143 125 Tubing-NPC Interval TVD Zone Status FeetSPF Date Type Comment 11415- 11565 9022 - 9024 ZONE lB O 150 4 11/30/95 IPERF 11590- 11610 9024-9024 ZONE lB O 20 4 7/17/97 APERF 11610- 11630 9024-9024 ZONE lB O 20 4 7/16/97 APERF 11680 - 11822 9024 - 9027 ZONE lB O 142 411/29/95 IPERF 11860 - 12040 9028- 9030 ZONE lB O 180 4 11/29/95 IPERF 12065- 12155 9030 - 9031 ZONE lB O 90 411/29/95 IPERF / Iraqi Proposal Calculations BAKER HUGHES Coordinates provided in: TR~ relative to Wellhead INTEQ and ALAS~ STATE PLAN Company: Bp Exploration Ve~ical ~ct. Plane: 2~.~ TR~ Job No: Well: 2-03B Plan $1 Mag. Dec, nation: 26.910 AFE No: API No: 50-029-~7-02 Grid Corr~tion: 1.4~ D~led From: 2-03 ~g: Nabors 3S Dip: 80.7~ S~ Date: Field: Pm~ Bay Uffit RKB Height: ~.~ End Date: Me~. Incl. TRUE ~D TVD C~rds. - ASP C~rds. - TRUE Dogleg Vefli~l Tool Face Build Turn Depth Angle Azl. Sub~ R~ N(+)/S(-) E(+)~(-) N(+)/S(-) E(+)~(-) Seved~ ~tion Commen~ (deg) (deg) (ft) (fi) Lat. fi) Dep. (X) La~ (Y) Dep. (X) (°/100fi) TIP (°/100fl) ( 103~.~ 42.00 141.50 8392.73 8456.73 5947330.29 692160.26 -3039.21 3586.52 0.89 -4059.79 21.98 0.83 0.50 Tie-in Position 1~.~ 42.58 142.~ 8466.71 8530.71 5947278.51 692203.22 -3~2.05 3628.18 0.67~ 4109.99 30.30 0.58! 0.50 Kick off Point 1~25.~ 38.38 138.82 8485.72 8549.72 59472~.26 692213.85 -31~.56 3638.50 18.70 4122.33 -155.00 -16.78 -12.72 1~50.~ 34.29 135.~ 8505.86 8569.86 5947255.69 692224.22 -3115.39 3~8.60 18.70 -4134.15 -152.58 -16.37 -15.28 10475.~ 30.35 130.30 8526.98 8590.98 5947246.87 692234.24 -3124.46 3658.40 18.70 -4145.38 -149.50 -15.79 -18.79 105~.~ 26.61 124.39 8548.96 8612.96 5947239.86 692243.86 -3131.71 3~7.84 18.70 -4155.93 -145.53 -14.94 -23.65 10525.~ 23.19 116.80 8571.~ 8635.64 5947234.70 692253.01 -3137.10 3676.86 18.70 -4165.75 -140.33 -13.68 -30.37 10550.~ 20.25 1~.95 8594.87 8658.87 5947231.43 692261.63 -3140.58 3685.40 18.70 -4174.76 -133.44 -11.77 -39.39 10575.~ 18.02 94.38 8618.50 8682.50 5947230.07 692269.67 -3142.14 3693.39 18.70 -4182.91 -124.28 -8.93 -50.31 1~.~ 16.78 79.25 8~2.36 8706.36 5947230.~ 692277.06 -3141.76 37~.80 18.70 -4190.14 -112.39 -4.94 -60.52 10625.~ 16.77 63.00; 8~6.31 8730.31 5947233.12 692283.76 -3139.45 3707.56 18.70 -4196.39 -97.95 -0.05 -~.99 1~50.~ 17.98 47.83 8690.18 8754.18 5947237.50 692289.73 -3135.22 3713.~ 18.70 -4201.~ -82.38 4.84 -60.69 10675.~ 20.19 35.19~ 8713.82 8777.82 5947243.75 692294.92 -3129.10 3718.98 18.70 4205.85 -67.89 8.85 -50.55 10700.~ 23.12 25.29 8737.06 8801.06 5947251.83 692299.31 -3121.13 3723.57 18.70 -4208.98 -55.94 11.72 -39.61 10725.~ 26.53 17.65 8759.75 8823.75 5947261.69 692302.85 -3111.36 3727.36 18.70 -4211.02 -46.73 13.65 -30.54 10750.~ 30.26 11.71 8781.74 8845.74 5947273.25 692305.54 -3~9.87 3730.34 18.70 -4211.95 -39.80 14.92 -23.77: 10775.~ 34.21 6.99 8802.89 8866.89 5947286.45 692307.34 -3086.72 3732.47 18.70 -4211.77 -34.57 15.77 -18.88 108~.~ 38.29 3.16 8823.05 8887.05 5947301.19 692308.26 -3072.~ 3733.75 18.68 -4210.48 -30.57 16.34 -15.33 I 10825.~ 41.44 357.71 8842.24 8906.24 5947317.20 692307.95 -3055.99 3733.85 18.80 -4207.79 -50.07 12.60 -21,79 10850.~ 44.81 352.92 8860.49 8924.49 5947334.18 692306.11 -3038.97 3732.43 18.80 -4203.~ -45.89 13.50 -19.15 10875.~ 48.37; 348.69 8877.67 8941.67 5947352.01 692302.74 -3021.~ 3729.51 18.80 -4197.46 -42.39 14.21 -16.95 109~.~ 52.06 3~.90 8893.67 8957.67 5947370.58 692297.87 -3~2.37 3725.11 18.80 -4189.87 -39.47 14.77 -15.15 10925.00 55.86 341.48 8908.38 8972.38 5947389.77 692291.53 -2983.03 3719.25 18.80 -4180.75 -37.05 15.21 -13.68 1~50.00 59.75 338.36 8921.70 8985.70 5947409.~ 692283.77 -2963.17 3711.98 18.80 -4170.14 -35.~ 15.55 -12.49 10975.00 63.71 335.48 8933.54 8997.54 5947429.46 692274.62 -2942.93 3703.34 18.80 -4158.11 -33.37 15.83 -11.53 110~.00 67.72 332.79 8943.82 9~7.82 5947449.69 692264.17 -2922.~ 3693.39 18.80~ -4144.76 -32.01 16.04 -10.76 11025.~ 71.77 330.25 8952.48 9016.48 5947470.01 692252.47 -2901.83 3682,21 18.80 -4130.16 -30.90 16.21 -10.16 11050.00 75.85 327.82 8959.45 9023.45 5947490.27 692239.60 -2881.25 3~9.85 18.80 -4114.42 -30.02 16.34 -9.69 11075.~ 79.96 325.49 89~.69 9028.69 5947510.34 692225.66 -2860.84 3656.42 18.80 -4097.65 -29.34 16.43 -9.35 11100.00 84.08 323.21 8968.16 9032.16 5947530.08 692210.73 -2840.73 3~1.99 18.80 -4079.95 -28.85 16.49 -9.11 11125.~ 88.22 320.96 8969.83 9033.83 5947549.37 692194.92 -2821.~ 3626.67 18.80 -4~1.44 -28.54 16.53 -8.98 11135.81 90.00 320.00 8970.00 9034.00 5947557.53 692187.84 -2812.72 3619.79 18.76 -4053.22 -28.41 16.50 -8.93 2 11150.00 90.00 317.39 8970.00~ 9034.00 5947567.95 692178.2t -2802.~ 3610.42 18.39 -4~2.14 -90.~ 0.00 -18.39 11175.~ 90.00 312.79 8970.00 9034.00 5947585.20 692160.13 -2784.36 3592.78 18.39 -4021.69 -90.~ 0.00 -18.39 11200.~ 90.00 308.20 8970.00 9034.00 59476~.95 692140.72 -2768.13 3573.77 18.39 -4~0.16 -90.~ 0.~ -18.39 11225.00 90.00 303.60 89~0.00 9034.00 5947615.09 692120.12 -2753.47 3553.53 18.39 -3977.67 -90.~ 0.00 -18.39 11250.00 90.~ 299.00 8970.00 9034.00 5947627.53 692098.45 -2740.49 3532.17 18.39 -3954.39 -90.~ 0.00 -18.39 11275.~ 90.00 294.40 8970.00 9034.00 5947638.20 692075.84 -2729.26 3509.84 18.39 -3930.45 -90.00; 0.00 -18.39 11285.72 90.00 292.43 8970.00 9034.00 5947~2.21 692065.90 -2725.~ 3500.00 18.40 -3920.02 -90.~~ 0.00 -18.4~ 3 Meas. Incl. TRUE TVD TVD Coords. - ASP Coords. - TRUE Dogleg Vertical Tool Face Build Turn Depth Angle Azi. Subsea RKB N(+)/S(-) E(+)~V(-) N(+)/S(-) E(+)/W(-) Seventy Section Comments (deg) (deg) (~) (ft) Lat. (Y) Dep. (X) LaL (Y) Dep. (X) (°/100fl) TiP (°/100~) (°/100ft) 11300.00 90.00 291.27 8970.00 9034.00 5947647.20 692052.52 -2719.69 3486.75 8.12 -3906.05 -90.00 0.00 -8.12 11350.00 90.00 287.21 8970.00 9034.00 5947662.48 692004.93 -2703.21 3439.55 8.12 -3856.71 -90.00 0.00 -8.12 11400.00 90.00 283.15 8970.00 9034.00 5947674.36 691956.38 -2690.12 3391.31 8.12 -3806.92 -90.00 0.00 -8.12 11450.00 90.00 279.09 8970.00 9034.00 5947682.77 691907.10 -2680.48 3342.26 8.12 -3756.94 -90.00 0.00 -8.12 11500.00 90.00 275.03 8970.00 9034.00 5947687.67 691857.36 -2674.34 3292.65 8.12 -3707.02 -90.00 0.00 -8.12 11550.00 90.00 270.97 8970.00 9034.00 5947689.03 691807.39 -2671.72 3242.73 8.12 -3657.40 -90.00 0.00 -8.12 11600.00 90.00 266.91 8970.00 9034.00 5947686.86 691757.45 -2672.64 3192.74 8.12 -3608.34 -90.00 0.00 -8.12 11650.00 90.00 262.85 8970.00 9034.00 5947681.15 691707.79 -2677.10 3142.95 8.12 -3560.08 -90.00 0.00 -8.12 11700.00 90.00 258.79 8970.00 9034.00 5947671.94 691658.66 -2685.08 3093.61 8.12 -3512.87 -90.00 0.00 -8.12 11750.001 90.00 254.73 8970.00 9034.00 5947659.28 691610.30 -2696.53 3044.94 8.12 -3466.93 -90.00 0.00 -8.12 11800.00 90.00 250.67 8970.00 9034.00 5947643.23 691562.96 -2711.39 2997.22 8.12 -3422.51 -90.00 0.00 -8.12 11850.00 90.00 246.61 8970.00 9034.00 5947623.86 691516.88 -2729.60 2950.66 8.12 -3379.82 -90.00 0.00 -8.12 I1900.00 90.00 242.55 8970.00 9034.00 5947601.28 691472.28 -2751.06 2905.51 8.12 -3339.09 -90.00 0.00 -8.12 11950.00 90.00 238.49 8970.00 9034.00 5947575.60 691429.40 -2775.66 2861.99 8.12 -3300.50 -90.00 0.00 -8.12 12000.00 90.00 234.43 8970.00 9034.00 5947546.95 691388.44 -2803.28 2820.33 8.12 -3264.26 -90.00 0.00 -8.12 12050.00 90.00 230.37 8970.00 9034.00 5947515.46 691349.61 -2833.78 2780.72 8.12 -3230.55 -90.00 0.00 -8.12 12100.00 90.00 226.31 8970.00 9034.00 5947481.31 691313.11 -2867.01 2743.37 8.12 -3199.54 -90.00 0.00 -8.12 12150.00 90.00 222.25 8970.00 9034.00 59474~4.66 691279.12 -2902.80 2708.47 8.12 -3171.39 -90.00 0.00 -8.12 12200.00 90.00 218.19 8970.00 9034.00 5947405.70 691247.81 -2940.97 2676.19 8.12 -3146.23 -90.00 0.00 -8.12 12250.00 90.00 214.13 8970.00 9034.00 5947364.62 691219.33 -2981.33 2646.70 8.12 -3124.19 -90.00 0.00 -8.12 12266.87 90.00 212.77 8970.00 9034.00 5947350.31 691210.39 -2995.40 2637.40 8.06 -3117.47 -90.00 0.00 -8.06 TD Drilling Wellhead Detail Methanol Injection Otis 7" WLA Quick Connect- ~ CT Injector Head ~ Stuffing Box (Pack-Off), 10,000 psi Working Pressure 7" Riser Annular BOP (Hydril),7-1/16" ID 5000 psi WP Alignment Guide Flange -----__. 7-1/16", 5M Ram Type Dual Gate BOPE ~ Flanged Fire Resistant Man Kelly Hose to Dual HCR Choke Manifold Combination Cutter/Blinds 2-3/8" Slip/Pipe Rams Manual Valves Drilling spool 7-1/16", 5M by 7-1/16", 5M Manual over Hydraulic Ram Type Dual Gate BOPE 7-1/16" ID with 2-7/8" Pipe & Slip Rams Manual Master Valve 0.458' (5.5") 2" Pump-In Hanger Fire resistant Kelly Hose to Flange by Hammer up 1/4 Turn Valve on DS Hardline to Standpipe manifold Upper Annulus Lower Annulus I DATE II CHECK NO. H 1 7 917 5 ~2,,o~,,oo 00179175 VEN~R ALASKASTAT 10 DATE INVOICE/CRED~MEMO DE~RIFTION GRO~ DIS~UNT N~ 113000 CKll3OOOA 100.00 100.00 PYMT (:OMMENTS: Peef~it to D~iii l'ee HANDLiiNO INST: S/H - Teeeie Hubl le X4&28 EA~ACHEDCHECKISINPAY=:~FOR~==DE~RiBEDABOVE. ~[e]~il~ 100,00 100,00 .... .:'.:if..:': ."i~ .~AN::Ai~.~IATE:(~ .:i:ii' :'::<'.'. ':~:::~ ::...::' NA~tDNAE.~I~..BAHK "':: ':: ~:.' "::~.::L.....::::~ 'C~VE~A~D, 5Nib .':?::' :': :..' 412 P'AY TO ';Th.e 3R'DER : .... ~2,'o~,'00 ........... '"'"' $~o°' oo .... ':.':;; : ..:"."::. "..:.:'v O :'ii ALID AFTER 120 DAYS ..:: ..:. !::'... . '."': !!'" ti" 2. ? ~ 2. ? 5," ':0 h ], ~0 3.°, ~ 5': 008 t., [, 2. ti,, WELL pERMIT CHECKLIST COMPANY ~,'3. . WELL NAME ~)~-" C~j~ PROGRAM: exp ~ ., FIELD & POOL ~/--//~/~ INIT C~SS -~~ ./t~'~/~/ ~.. GEOL AREA ADMINISTRATION II APER DATE 1. Permit fee attached ........................ 2. Lease number appropdate?~..,~:~.., .~. '.~. ~. /4) T.~.~/. 3. Unique well name and number .......... : ....... 4. Well located in a defined pool .................. 5. Well located proper distance from drilling unit boundary .... 6. Well located proper distance from other wells .......... 7. Sufficient acreage available in ddlling unit ............ 8. If deviated, is wellbore plat included ............... 9. Operator only affected party ................... 10. Operator has appropriate bond in force ............. 11. Permit can be issued without conservation order ........ 12. Permit can.be issued without administrative approval ...... 13. Can permit be approved before 15-day wait ........... Conductor string provided ................... DATE dev ~ redrll v/ serv ~ wellbore seg ann. disposal para req ~ ~'~_.~ UNIT# <~)///~:>_~'(~ ON/OFF SHORE ~ 14. Y 15. Surface casing protects all known USDWs ........... Y 16. CMT vol adequate to circulate on conductor & surf csg ..... Y 17. CMT vol adequate to tie-in long string to surf csg ........ .,Y,, 18. CMT will cover all known productive horizons .......... 19. Casing designs adequate for C, T, B & permafrost ....... 20. Adequate tankage or reserve pit ................. 21. If a re-drill, has a 10-403 for abandonment been approved... 22. Adequate wellbore separation proposed ............. 23. If diverter required, does it meet regulations .......... 24. Drilling fluid program schematic & equip list adequate ..... 25. BOPEs, do they meet regulation ................ 26. BOPE press rating appropriate; test to ~.u~"~,~ psig. 27. Choke manifold complies w/APl RP-53 (May 84) ........ 28. Workwill occur without operation shutdown ........... 29. Is presence of H2S gas probable ................. ,N , . · . , )N N N N N N GEOLOGY A,,~ DATE (- 30. 31. 32. 33. 34. Permit can be issued w/o hydrogen sulfide measures ..... Y Data presented on potential overpressure zones ...... . Y Seismic analysis of shallow gas zones ........ ..... r/!/Y/N Seabed condition survey (if off-shore) ............. ~ ~ Y N Contact name/phone for weekly progress reports [explora.~'o'nly] Y N ANNULAR DISPOSAL35. With proper cementing records, this plan (A) will contain waste in a suitable receiving zonei ....... Y N APPR DATE (B) will not contaminate freshwater; or cause drilling waste... Y N to surface; (C) will not impair mechanical integrity of the well used for disposal; Y N (D) will not damage producing formation or impair recovery from a Y N pool; and (E) will not circumvent 20 AAC 25.252 or 20 AAC 25.412. Y N O Z O Z -.-I 'r" GEOLOGY: ENGINEERING: UIC/~nnular COMMISSION: Commentsllnstructions: c:\msoffice\wordian\diana\checklist (rev. 11/01fl00) Well History File APPENDIX Information of detailed nature that is not particularly germane to the Well Permitting Process but is part of the history file. To improve the readability of the Well History file and to simplify'finding informatiOn, information, of this nature is accumulated at the end of the file under APPENDIXi .. No 'special 'effort has been made to chronologically organize this category of information. **** REEL HEADER **** MWD 02/03/29 BHI 01 LIS Customer Format Tape **** TAPE HEADER **** MWD 02/03/29 125091 01 1.75" NaviGamma - Gamma Ray *** LIS COMMENT RECORD *** !!!!!!!!!!!!!!!!!!! Remark File Version 1.000 !!!!!!!!!!!!!!!!!!! Extract File: Idwg.las ~Version Information VERS. 1.20: CWLS log ASCII Standard -VERSION 1.20 WRAP. NO: One line per frame -Well Information Block #MNEM.UNIT Data Type Information STRT.FT 10542.0000: Starting Depth STOP.FT 12561.0000: Ending Depth STEP.FT 0.5000: Level Spacing NULL. -999.2500: Absent Value COMP. COMPANY: BP Exploration, Inc. WELL. WELL: 02-03B FLD. FIELD: Prudhoe Bay Unit LOC. LOCATION: 946' SNL, 97' EWL CNTY. COUNTY: North Slope STAT. STATE: Alaska SRVC. SERVICE COMPANY: Baker Hughes INTEQ TOOL. TOOL NAME & TYPE: 1.75" NaviGamma - Gamma Ray DATE. LOG DATE: 28-May-01 API. API NUMBER: 500292007702 ~Parameter Information Block #MNEM.UNIT Value Description SECT. 36 : Section TOWN.N 11N : Township RANG. 14E : Range PDAT. MSL : Permanent Datum EPD .F 0 : Elevation Of Perm. Datum LMF. RKB : Log Measured fi'om FAPD. F 64.00 : Feet Above Perm. Datum DMF. KB : Drilling Measured From EKB .F 64.00 : Elevation of Kelly Bushing EDF .F N/A : Elevation of Derrick Floor EGL .F N/A : Elevation of Ground Level CASE.F N/A : Casing Depth OS1. DIRECTIONAL : Other Services Line 1 ~Remarks (1) All depths are Measured Depths (MD) unless otherwise noted. (2) All depths are Bit Depths unless otherwise noted. (3) Ail Gamma Ray data (GRAX) presented is realtime data. (4) Well 02-03B was drilled as a lateral si&trak on Well 02-03. (5) The sidetrack began at 10550' MD (8576' SSTVD). (6) Well 02-03B was drilled to TD at 12561' MD (8977' SSTVD). (7) The interval from 12522' MD (8976' SSTVD) to 12561' MD (8977' SSTVD) was not logged due to sensor to bit offset. (8) The data presented here is final and has been depth shit~ed to a PDC (Primary Depth Control) supplied by BPX (SWS, 3 l-May-01). (9) A Magnetic Declination correction of 26.76 degrees has been applied to the Directional Surveys. MNEMONICS: GRAX -> Gamma Ray MWD-API [MWD] (MWD-API units) ROPS -> Rate of Penetration, feet/hour TVD -> Subsea True Vertical Depth, feet SENSOR OFFSETS: RUN GAMMA DIRECTIONAL N/A N/A N/A CURVE SHIFT DATA BASELINE, MEASURED, DISPLACEMENT 10560.0 10560.6, ! 0.606445 10586.6 10586.8, t 0.201172 10601.6 10602.2, ! 0.606445 10628.4 10628.8, ! 0.404297 10637.5 10634,5, ! -3.03027 10661.8 10657.5, ! -4.24316 10828.7 10822.3, ! -6.46484 10863.7 10856.8, ! -6.86914 10905.7 10898.0, ! -7.67676 10975.9 10968.4, ! -7.47559 10994.7 10986.0, ! -8.68652 10999.3 10990.4, ! -8.88867 11008.6 11000.1, ! -8.48535 11013.1 11003.2, ! -9.89941 11050.6 11044.7, ! -5.8584 11093.7 11087.8, ! -5.8584 11115.2 11109.1, ! -6.06055 11145.8 11139.7, ! -6.06055 11175.8 11167.1, ! -8.68652 11237.7 11230.2, ! -7.47461 11309.9 11300.0, ! -9.89844 11340.8 11332.1, ! -8.68652 11375.9 11361.3, ! -14.5449 11386.5 11373.6, ! -12.9287 11479.3 11464.8, ! -14.5459 11506.5 11492.8, ! -13.7373 11525.7 11510.2, ! -15.5557 11544.1, 11528.9, ! -15.1523 11557.5, 11540.7, ! -16.7676 11573.0, 11558.5, ! -14.5459 11579.1,11565.4, ! -13.7373 11708.7 11688.3, ! -20.4033 11897.5 11935.0 11947.5 12002.3 12034.0 12099.2 12168.0. 12227.8 12358.6. 12440.9. 12480.3. 11880.0, ! -17.5752 11916.0, ! -18.9902 11928.5, ! -18.9893 11987.9, ! -14.3438 12017.6, ! -16.3633 12081.9, ! -17.374 12154.3, ! -13.7373 12214.7, ! -13.1318 12345.6, ! -12.9287 12429.8, ! -11.1113 12469.6, ! -10.707 EOZ END ! BASE CURVE: GROH, OFFSET CURVE: GRAX Tape Subtile: I 113 records... Minimum record length: 8 bytes Maximum record length: 132 bytes **** FILE HEADER **** MWD .001 1024 *** INFORMATION TABLE: CONS MNEM VALU WDFN mwd.xtf LCC 150 CN BP Exploration, Inc. WN 02-03B FN Prudhoe Bay Unit COUN North Slope STAT Alaska *** LIS COMMENT RECORD *** !!!!!!!!!!!!!H!!I! Remark File Version 1.000 1. The data presented has been edited from the field raw data. 2. The data has been depth shifted to match the PDC supplied by BPX 3. The PDC used is a Schlumberger Gamma Ray dated 31-May-01. *** INFORMATION TABLE: CIFO MNEM CHAN DIMT CNAM GR GR GRAX12 0.0 ROP ROP ROPS12 0.0 ODEP * FORMAT RECORD (TYPE# 64) Data record type is: 0 Datum Frame Size is: 12 bytes Logging direction is down (value= 255) Optical Log Depth Scale Units: Feet Frame spacing: 0.500000 Frame spacing units: [F ] Number of frames per record is: 84 One depth per frame (value= 0) Datum Specification Block Sub-type is: FRAME SPACE = 0.500 * F ONE DEPTH PER FRAME Tape depth ID: F 2 Curves: Name Tool Code Samples Units Size Length 1 GR MWD 68 1 API 4 4 2 ROP MWD 68 1 F/HR 4 8 Total Data Records: 49 Tape File Start Depth = 10542.000000 Tape File End Depth = 12561.000000 Tape File Level Spacing = 0.500000 Tape File Depth Units = feet **** FILE TRAILER **** Tape Subtile: 2 58 records... Minimum record length: 54 bytes Maximum record length: 4124 bytes **** FILE HEADER **** MWD .002 1024 *** INFORMATION TABLE: CONS MNEM VALU WDFN mwd.xff LCC 150 CN BP Exploration, Inc. WN 02-03B FN Prudhoe Bay Unit COUN North Slope STAT Alaska *** LIS COMMENT RECORD *** !!!!!!!!!!!!!!!!!!! Remark File Version 1.000 The data presented here is the unedited field raw data. *** INFORMATION TABLE: CIFO MNEM CHAN DIMT CNAM GRAX GRAX GRAX 0.0 ROPS ROPS ROPS 0.0 * FORMAT RECORD (TYPE# 64) Data record type is: 0 Datum Frame Size is: 12 bytes Logging direction is down (value= 255) Optical Log Depth Scale Units: Feet Frame spacing: 0.500000 Frame spacing units: [F ] Number of frames per record is: 84 One depth per frame (value= 0) Datum Specification Block Sub-type is: FRAME SPACE = 0.500 * F ONE DEPTH PER FRAME ODEP Tape depth ID: F 2 Curves: Name Tool Code Samples Units 1 GRAX MWD 68 1 API 2 ROPS MWD 68 1 F/HR 8 Total Data Records: 49 Tape File Start Depth = 10542.000000 Tape File End Depth = 12561.000000 Tape File Level Spacing = 0.500000 Tape File Depth Units = feet **** HLE TRAILER **** Tape Subtile: 3 58 records... Minimum record length: 54 bytes Maximum record length: 4124 bytes **** TAPE TRAILER **** MWD 02/03/29 125091 01 Size Length 4 4 4 4 **** REEL TRAILER **** MWD 02/03/29 BHI 01 Tape Subtile: 4 2 records... Minimum record length: 132 bytes Maximum record length: 132 bytes Tape Subtile 1 is type: LIS Tape Subtile 2 is type: LIS DEPTH 10542.0000 10542.5000 10600.0000 10700.0000 10800.0000 10900.0000 11000.0000 11100.0000 11200.0000 11300.0000 GR ROP 20.7710 -999.2500 20.7710 -999.2500 29.6277 43.2002 16.7521 34.2429 22.5297 49.3247 94.5539 28.9946 104.6221 87.7115 21.9016 94.4683 26.4686 123.6488 82.3461 43.9038 11400.0000 42.5009 92.0192 11500.0000 68.5306 146.4146 11600.0000 82.4758 112.8005 11700.0000 45.3837 146.9390 11800.0000 34.8270 138.7433 11900.0000 28.6490 114.7697 12000.0000 44.3326 114.8615 12100.0000 27.8978 26.3053 12200.0000 48.9587 139.0943 12300.0000 26.0884 123.6031 12400.0000 70.9930 86.5706 12500.0000 42.6523 113.3481 12561.0000 -999.2500 -999.2500 Tape File Start Depth = 10542.000000 Tape File End Depth = 12561.000000 Tape File Level Spacing = 0.500000 Tape File Depth Units = feet Tape Subtile 3 is type: LIS DEPTH GRAX ROPS 10542.0000 20.7710 -999.2500 10542.5000 20.0680 -999.2500 10600.0000 37.6380 63.9680 10700.0000 22.3960 45.8720 10800.0000 27.5910 129.2130 10900.0000 37.0920 97.8150 11000.0000 21.9430 90.1600 11100.0000 32.0940 43.8270 11200.0000 21.8380 130.5090 11300.0000 61.4550 88.5450 11400.0000 47.3730 32.2860 11500.0000 62.2350 78.1910 11600.0000 100.6540 145.2170 11700.0000 33.3960 147.4340 11800.0000 39.1470 147.6380 11900.0000 42.3230 128.2880 12000.0000 81.2050 108.3540 12100.0000 85.5570 93.6850 12200.0000 153~2840 68.6830 12300.0000 26.7060 146.8230 12400.0000 69.6530 84.3640 12500.0000 41.7760 107.2550 12561.0000 -999.2500 -999.2500 Tape File Start Depth = 10542.000000 TapeFile EndDepth = 12561.000000 Tape File Level Spacing = 0.500000 Tape File Depth Units = feet Tape Subtile 4 is type: LIS
