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Home My WebLink About203-176Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 3/2/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20250302 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# CLU 11 50133205590000 206058 2/19/2025 AK E-LINE CBL,CIBP CLU 11 50133205590000 206058 2/13/2025 AK E-LINE CIBP END 1-65A 50029226270100 203212 1/27/2025 HALLIBURTON COILFLAG END 2-56A 50029228630100 198058 2/6/2025 HALLIBURTON COILFLAG END 2-72 50029237810000 224016 2/2/2025 HALLIBURTON PPROF MPU F-29 50029226880000 196117 1/31/2025 HALLIBURTON MFC24 MPU L-02A 50029219980100 209147 2/17/2025 READ CaliperSurvey MPU L-36 50029227940000 197148 1/18/2025 HALLIBURTON MFC24 MPU R-144 50029238090000 224148 2/11/2025 HALLIBURTON WFL-TMD3D NCIU A-21 50883201990000 224086 2/18/2025 AK E-LINE Perf ODSN-25 50703206560000 212030 2/16/2025 READ MemoryLeakPoint PBU 06-05A 50029202980100 224115 1/15/2025 BAKER MRPM PBU 06-15A 50029204590200 224108 12/27/2024 HALLIBURTON RBT PBU 06-16B 50029204600200 223072 1/25/2025 BAKER MRPM PBU B-12B 50029203320200 224133 1/19/2025 BAKER MRPM PBU S-126B 50029233630200 224084 2/7/2025 HALLIBURTON RBT PBU V-105 50029230970000 202131 2/9/2025 HALLIBURTON IPROF PBU W-01A 50029218660100 203176 1/19/2025 AK E-LINE CBL PBU W-01B 50029218660200 224149 1/28/2025 HALLIBURTON RBT PCU 02A 50283200220100 224110 1/24/2025 AK E-LINE CIBP Please include current contact information if different from above. T40161 T40161 T40162 T40163 T40164 T40165 T40166 T40167 T40168 T40169 T40170 T40171 T40172 T40173 T40174 T40175 T40176 T40177 T40178 T40179 PBU W-01A 50029218660100 203176 1/19/2025 AK E-LINE CBL Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.03.03 10:15:14 -09'00' 4323 cu ft PF, Top Job: 140 cu ft PF 29 By James Brooks at 2:15 pm, Jan 24, 2025 Abandoned 12/29/2024 JSB RBDMS JSB 013025 xGJJL 5/8/25 DSR-4/7/25A.Dewhurst 02APR25 Joe Engel for Sean McLaughlin Digitally signed by Joseph Engel (2493) DN: cn=Joseph Engel (2493) Date: 2025.01.24 10:43:45 - 09'00' Joseph Engel (2493) WELL NAME: PBU W-01A 26. Acid, Fracture, Cement Squeeze, Etc. Depth Interval (MD) Amount & Kind of Material Used 12128' - 12131' Liner Punch 11728' - 11731' Tubing Punch 11294' Set Cement Retainer 11274' 60 Bbls Class G 6390' Set Cement Retainer 6250' 45 Bbls Class G (Milled) 6200' - 6205' Tubing Punch 6180' Set Cement Retainer 2950' 232 Bbls Class G 2500' Cut and Pull Tubing 2100' Cut and Pull 9-5/8" Casing 2100' Fish: 9-5/8" Cutter 2065' Set Cast Iron Bridge Plug 2023' Set Whipstock ACTIVITYDATE SUMMARY 11/15/2024 T/I/O = SSV/VAC/120. Temp = SI. OA FL (Fullbore request). OA FL @ near surface. SV, SSV, WV = C. MV = O. IA, OA = OTG. 12:30 11/16/2024 ***MIT-OA*** TFS-U4, Initial WHP T/IA/OA = 0/0/50, MIT-OA MAP pressure @ 2200, pumped 4 bbls DSL to reach MAP, Starting test pressures T/IA/OA= 0/0/2194, First 15 minutes OA lost 68 PSI, Second 15 minutes OA lost 30 PSI, ***MIT-OA PASSED*** bled OA down to starting pressure, final WHP T/IA/OA= 0/0/50 11/21/2024 T/I/O= 135/0/200 (Assist Slickline) TFS U4, Pumped 22 bbls of crude down the TBG to pressure up and maintain pressure while slickline pulled and set WFV's. *Job continues to 11-22-24* 11/21/2024 *** WELL S/I ON ARRIVAL *** (sidetrack) RAN 4-1/2" BRUSH & 3.80" GAUGE RING TO 7,100' SLM SET 4-1/2 X-CATCHER IN X NIPPLE AT 7,033' MD PULLED RK-MF-WFR FROM ST# 3 AT 6,764' MD (tbg 0 psi) SET RK-DGLV IN ST# 3 AT 6,764' MD PULLED RK-MF-WFR FROM ST# 1 AT 6,914' MD (tbg 500 psi) ***CONTINUE ON 11/22/24 WSR*** 11/22/2024 *Job continues from 11-21-24* (Assist Slickline) TFS U4. Pumped 2 bbls of crude down the TBG to pressure up while slickline set DMY valve. Pumped an additional .2 bbls of crude down the TBG to pressure up to 1000 psi and monitor pressure for 5 minutes. TBG lost no pressure over five minutes. Pumped and additional 24 bbls of crude down the TBG to try and pump down slickline. *Job continues to 11-23-24* 11/22/2024 ***CONTINUED FROM 11/21/24 WSR*** (Sidetrack) SET RK-DGLV IN ST# 1 AT 6,914' MD T-BIRD PERFORMED PASSING PT ON TBG TO 1000 psi PULLED 4-1/2" X-CATCHER AT 7,033' MD (empty) PULLED 3-1/2" PX PLUG AT 11,608' MD RAN 20' x 3.70 DUMMY WHIPSTOCK TO 11,400' SLM (all clear) RAN 10' x 2.16" DUMMY GUNS TO 11,750' SLM (all clear) RAN 1.75" DRIVE DOWN BAILER TO 11,770' SLM (unable to work further - recovered small pieces of wrp & a couple pebbles) RAN BARBELLED 2.50" LIB TO DEPLOYMENT SLEEVE AT 11,762' MD (work past tbg stub - impression inconclusive) RAN 1.77" CENT & 1.75" 3-PRONG WIRE GRAB TO 11,762' MD (unable to skip past) RAN 2-3/8" BRUSH & 1.50" 2-PRONG WIRE GRAB TO TBG STUB AT 11,428' MD (unable to skip past) RAN DOUBLE BOWSPRING CENTS & 1.75" 3-PRONG WIRE GRAB TO DEPLOYMENT SLEEVE AT 11,762' MD (unable to skip past - prongs bent) RAN 10' x 1.75" DRIVE DOWN BAILER TO DEPLOYMENT SLEEVE AT 11,762' MD (unable to skip past - no recovery - marks on bottom) ***CONTINUE ON 11/23/24 WSR*** 11/23/2024 *Job continues from 11-22-24* (Assist Slickline) TFS U4. Pumped 48 bbls of crude down the TBG at various rates to assist slickline as directed. *Job continues to 11-24- 24* Daily Report of Well Operations PBU W-01A Daily Report of Well Operations PBU W-01A 11/23/2024 ***CONTINUED FROM 11/22/24 WSR*** (Sidetrack) RAN DOUBLE BOWSPRING CENTS & 1.85" MAGNET TO 11,762' MD (unable to skip past - no recovery) RAN BOWSPRING CENT & 1.75" MAGNET TO 12,052' SLM (no recovery) RAN DOUBLE BOWSPRING CENTS & 5' x 1.75" DRIVE DOWN BAILER TO 11,762' MD (unable to skip past) RAN 1.75" CENT, 2-3/8" BLB, BULL NOSE TO 12,055 SLM, UNABLE TO MOVE OBSTRUCTION DOWN HOLE RAN 1.75" CENT, 2-3/8 BLB, 1.47" FINGER TRAP TO 12,056' SLM (no recovery, 1" piece of finger trap missing) RAN 1.75" CENT, 2-3/8" BLB, 1.75 MAGNET TO 12,056' SLM (recovered piece of finger trap) RAN 1.75" CENT, 2-3/8" BLB, 1.75 MAGNET TO 12,056' SLM (no recovery) RAN BOWSPRING CENT & 1.50 LIB TO 12,058' SLM (inconclusive) RAN DOUBLE BOWSPRING CENTS & TAPERED 1.50" LIB TO 11,775' SLM (random inconclusive dimples) RAN 5' x 1.75" PUMP BAILER (modified bottom) & WORKED FROM 11,858' SLM - 12,186' SLM (recovered 1/2 gal course sand/ pebbles/ rubber) ***CONTINUE ON 11/24/24 WSR*** 11/24/2024 *Job continues from 11-23-24* (Assist slickline) TFS U4. Standby for slickline and RDMO from job. Well left in control of slickline upon departure 11/24/2024 ***WELL SHUT IN ON ARRIVAL*** (TUBING PUNCH / CEMENT RETAINER) RIG UP AK E-LINE PCE FUNCTION TEST WLV'S PRESSURE TEST 250 L 3000 H RIH WITH 3' 1.56" TUBING PUNCHER MAGNET AND DECENTRALIZER PUNCH 2 3/8 LINER @ (12128-12131) 1 9/16 0 PHASE 6 SPF 3 GRAM CHARGES CCL STOP DEPTH=12122.9 (CCL-TS=5.1) PUNCH 3 1/2 TUBING @ (11728-11731) 1 9/16 0 PHASE 6 SPF 3.5 GRAM CHARGES CCL STOP DEPTH=11722.9 (CCL-TS=5.1') SET NS 3.57" BALL TYPE POPPET CEMENT RETAINER @ 11294' CCL STOP DEPTH=11285.7 (CCL-ME=8.3') RDMO AK E-LINE ***WELL SHUT IN ON DEPARTURE*** JOB COMPLETE 11/24/2024 ***CONTINUED FROM 11/23/24 WSR*** (Sidetrack) RAN 10' x 1.75" PUMP BAILER (modified bottom) & WORK FROM 12,184' - 12,186' SLM (restriction at 11,855' slm - recovered ~1/2 gal sand) RAN 11' x 1.56" DUMMY GUN (1.72" rings) & BULLNOSE TO FILL AT 12,189' SLM (all clear) ***WELL S/I ON DEPARTURE*** 11/29/2024 T/I/O= 206/0/183. Halliburton Cementers with LRS assist (Ivishak Reservoir Abandonment). Pressure test surface lines. Bullhead 3 bbls of 60/40 MeOH and 300 bbls of Seawater down tubing. Injection rate 3 bpm at 2900 psi. Decision made to cut excess cement by 5 bbls due to injectivity. Batch cement at 14:03 hours. Lead with 5 bbls of fresh water, 60 bbls of 15.8 ppg Class G cement, 2 bbls of FW, launch 1.75" landing ball and (2) 6" foam wiper balls with 3 bbls of FW, 107 bbls of 9.8 ppg brine and 63 bbls of diesel. See 500 psi bump as landing ball seats on cement retainer. Monitor pressure for 30 mins. Cement will reach 1000 psi compressive strength 07H:09M. Final T/I/O= 2576/0/170. Close out the permit with Pad Operator. Daily Report of Well Operations PBU W-01A 12/1/2024 T/I/O= 375/0/150 Temp= SI AOGCC MIT T PASSED to 2536 psi (Witnessed by AOGCC Inspector Bob Noble) Pumped 2.1 bbls of 88*F diesel to achieve test pressure of 2752 psi. TBG lost 153 psi during the 15 minutes and 63 psi in the second 15 minutes for a total loss of 216 psi in 30-minute test. Bled back 2.1 bbls to final T/I/O= 449/0/51. 12/1/2024 ***WELL S/I ON ARRIVAL*** (Sidetrack) RAN 2-1/2" SAMPLE BAILER TO TOP OF CEMENT @ 11,271' SLM/11,274' MD (aogcc witnessed) LRS PERFORMED PASSING MIT-T TO 2,500 PSI (aogcc witnessed) SET 4-1/2" X-CATCHER AT 7,156' MD PULLED RK-DGLV AT ST# 6 (6,527' md) MADE ATTEMPT TO PULL RK-DGLV AT ST# 1 (6,914' md) (broke skirt from top sub - recovered all parts) ***CONTINUE ON 12/2/24 WSR*** 12/2/2024 Assist S-Line ***JOB Cancelled**** 12/2/2024 ***CONTINUED FROM 12/1/24 WSR*** (Sidetrack) PULLED RK-DGLV FROM STA #5 @ 6,605' MD PULLED RK-DGLV FROM STA #4 @ 6,716' MD PULLED RK-DGLV FROM STA #3 @ 6,764' MD PULLED RK-DGLV FROM STA #2 @ 6,837' MD PULLED RK-DGLV FROM STA #1 @ 6,914' MD ***WELL LEFT S/I ON DEPARTURE*** 12/3/2024 *** WELL SI ON ARRIVAL *** (ELINE CEMENT RETAINER) MIRU YJ ELINE PT PCE 300/3000 PSI, FUNCTION WLV CORRELATE TO TUBING TALLY 6-10-2021 SET NORTHERN SOLUTIONS COMPOSITE CEMENT RETAINER AT 6390 FT. CCL - ME = 8.7 FT, CCL STOP = 6381.3 FT. TAG AFTER SET RDMO YJ ELINE *** WELL SI ON DEPARTURE *** ELINE STEP COMPLETE 12/4/2024 Halliburton Cementers with LRS assist (Schrader Reservoir Abandonment) Bullhead 150 bbls of seawater down tubing at 4 bpm 1000 psi. Found fresh water to warm to mix cement so pumped 120 of fresh water off the upright at min rate while waiting for new fluid to arrive. Batch cement at 15:32 hours. Came online with 45 bbls of 15.8 ppg class G cement followed by 2 bbls of FW, launch 1.75" landing ball and (2) 6" foam wiper balls with 3 bbls of FW and 73 bbls of diesel when the well locked up at 3000 psi. Atttempt to surge the well and increasing pressure up to 4500 psi to no avail. Estiamted TOC at 5000' with ~ 24 bbls of cement below the retainer and ~21 bbls above the retainer. Left 500 psi on the well and rigged down. Final WHPs 457/0 302. 12/5/2024 ***WELL S/I ON ARRIVAL*** (Sidetrack) RAN 3" SAMPLE BAILER TO CEMENT @ 4,892' SLM RAN MULTIPLE BAILERS & CHISELS TO WORK THROUGH CEMENT BRIDGES TO 4,991' SLM ***CONTINUED ON 12/6/24 WSR*** 12/6/2024 ***CONTINUED FROM 12/5/24 WSR*** (Sidetrack) RAN 10'x3" BAILER TO 4,989' SLM (1 cup of cement) ***WELL S/I ON DEPARTURE*** 12/14/2024 Heat Upright Tanks to 120* for upcoming CTU work. 12/14/2024 LRS CTU #2, 1.75" Blue Coil. Job Objective: Mill cement, Tubing punch, cement IA through retainer Travel to W pad, MIRU CTU. Perform weekly BOP test ***Continued to WSR on 12/15/24*** Daily Report of Well Operations PBU W-01A 12/15/2024 LRS CTU #2, 1.75" Blue Coil. Job Objective: Mill cement, Tubing punch, cement IA through retainer Travel to W pad, MIRU CTU. Perform weekly BOP test. N/U BOPs on well and function test. M/U 2-7/8" YJ milling BHA w/3.80" parabolic cement mill. RIH and tag TOC at ~ 4905' CTM. Start milling cement. Mill down to 5441, issues with ARS shutting down and then freezing up, unable to get unit to re-prime, well support enroute to wrap all lines and also add a valve to allow isolation of MOT when FP ARS. POOH to inspect tools, reconfigure iron, thaw lines and get trucks to start conventional milling without ARS until priming issue cat get resolved ***Continued to WSR on 12/16/24*** 12/16/2024 LRS CTU #2, 1.75" Blue Coil. Job Objective: Mill cement, Tubing punch, cement IA through retainer Wrapping and reconfiguring surface iron. RBIH with 2-7/8" YJ milling BHA with 3.80" turbo scale mill. Mill cement from 5440' to 5754'. ***Continued to WSR on 12/17/24*** 12/17/2024 LRS CTU #2, 1.75" Blue Coil. Job Objective: Mill cement, Tubing punch, cement IA through retainer Continue milling from 5959 down to 6136' doing 10bbl gel sweeps. Chase gel sweep to surface from 6136 after milling 382'. RBIH and mill down to 6250'. Pump20 bbl's of gel and chase OOH. Freeze protect the coil and cap the well with diesel. RIH with 5' HES. Set down at ~2422'. Make multiple attempts to get through but unsuccessful. POOH, L/D HES tubing punch. M/U LRS 2" BHA w/2.5" JSN and RIH perform state witnessed TOC tag (Kam StJohn AOGCC rep) confirmed TOC @6250. Perform 30min MIT-T 31psi loss in 1st 15m min, 23psi loss in 2nd 15min. Passing test was less than 2% loss overall. POOH, ***Continued to WSR on 12/18/24*** 12/18/2024 LRS CTU #2, 1.75" Blue Coil. Job Objective: Mill cement, Tubing punch, cement IA through retainer Finish POOH. L/D LRS BHA. M/U NS 2-1/8" MHA, YJ knuckle and 5' HES 1.56", 4 SPF, 0 degree phase tubing punch. RIH tag cement top and correct depth to bottom shot. Piick up and punch tubing from 6,200'-6,205'. POOH and circulate the TxIA to diesel. Make up 4-1/2" NS 1-trip cement retainer and RBIH. Set at 6180' Verify circulation through IA and PT down to tubing to 500psi. Rig up HES cementers, stand by to swap out compressor before start of cement ***Continued to WSR on 12/19/24*** 12/19/2024 LRS CTU #2, 1.75" Blue Coil. Job Objective: Mill cement, Tubing punch, cement IA through retainer Stand by for HES to swap out non operational air compressor. Pump 3 BBL's of fresh water followed by 231.7 BBL's of cement. Unsting from the retainer with 182 BBL's pumped into the IA(TOC ~ 2800'). Lay-in cement in the tubing up to 2800'. Freeze protect the tubing to 2500' with diesel. RDMO. **Job Complete** 12/20/2024 ***WELL S/I ON ARRIVAL*** (tag toc) RUN 3.80" CENT,1.75" S.BAILER. DRIFT TO TOC @ 2,950' SLM. RECOVERED UNCURED CEMENT ***WELL LEFT S/I ON DEPARTURE. NOTIFY PAD OP OF WELL STATUS*** Daily Report of Well Operations PBU W-01A 12/20/2024 *** WELL S/I ON ARRIVAL*** OBJECTIVE: CUT 4 1/2" TUBING @2500' MIRU YELLOW JACKET E-LINE. PT PCE 300 PSI LOW./3000 PSI HIGH CUTTING DEPTH 2500' CCL OFFSET TO CUTTER HEAD 2.8' CCL STOP DEPTH 2497.2 PRE CUT T/I/O=500/0/0. POST CUT T/I/O=100/100/0 RDMO YELLOW JACKET ELINE ***WELL S/I ON DEPARTURE *** 12/21/2024 T/I/O = 3/0/150. Set 4" H TWC #213. RD Upper tree installed DH tree, Torqued to API specs, PT'd against MV 350/5000 (Pass). FWP = TWC/0/150. MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg DATE: P.I. Supervisor SUBJECT: FROM: Petroleum Inspector Section: 21 Township: 11N Range: 12E Meridian: Umiat Drilling Rig: Service CTU Rig Elevation: Total Depth: 13135 ft MD Lease No.: ADL 028263 Operator Rep: Suspend: P&A: X Conductor: 20" O.D. Shoe@ 114 Feet Csg Cut@ Feet Surface: 13-3/8" O.D. Shoe@ 2934 Feet Csg Cut@ Feet Intermediate: 9-5/8" O.D. Shoe@ 12027 Feet Csg Cut@ Feet Liner: 5-1/2" O.D. Shoe@ 12143 Feet Csg Cut@ Feet Liner: 2-3/8" O.D. Shoe@ 12380 Feet Csg Cut@ Feet Tubing: 4-1/2" x 3-1/2" O.D. Tail@ 11798 Feet Tbg Cut@ Feet Type Plug Founded on Depth (Btm) Depth (Top) MW Above Verified Fullbore Retainer 6390 ft 6250 ft 6.8 ppg C.T. Tag Initial 15 min 30 min 45 min Result Tubing 2740 2709 2686 IA 0 0 0 OA 132 131 131 Initial 15 min 30 min 45 min Result Tubing IA OA Remarks: Attachments: Plug back for redrill. Set down 5K lbs after milling cement to 6250 ft MD. MIT-T passed (BBLS in 2.1; BBLS out 1.9) December 17, 2024 Kam StJohn Well Bore Plug & Abandonment PBU W-01A Hilcorp North Slope LLC PTD 2031760; Sundry 324-630 none Test Data: P Casing Removal: Miles Shaw Casing/Tubing Data (depths are MD): Plugging Data (depths are MD): rev. 3-24-2022 2024-1217_Plug_Verification_PBU_W-01A_ksj From:Lau, Jack J (OGC) To:Aras Worthington Cc:Rixse, Melvin G (OGC); Dewhurst, Andrew D (OGC); Joseph Engel; Abbie Barker; Tyson Shriver; Joseph Lastufka Subject:APPROVED: W-01A P&A Pre-Rotary Sidetrack PTD #203-176 Sundry #324-630 Date:Friday, December 6, 2024 9:16:44 AM Attachments:PBU W-01A Approved 10-403 11-12-24.pdf W-01A Reservoir Abandonment 10-24 Rev1.pdf image001.png image002.png image003.png Aras – I have reviewed the proposed revision and approve your request to proceed with “PBU W-01A Reservoir Abandonment 10-24 Rev1”. Jack From: Aras Worthington <aras.worthington@hilcorp.com> Sent: Friday, December 6, 2024 7:40 AM To: Lau, Jack J (OGC) <jack.lau@alaska.gov> Cc: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Joseph Engel <jengel@hilcorp.com>; Abbie Barker <Abbie.Barker@hilcorp.com>; Tyson Shriver <Tyson.Shriver@hilcorp.com>; Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Subject: RE: W-01A P&A Pre-Rotary Sidetrack PTD #203-176 Sundry #324-630 Jack et al., Thank you for the prompt response. Please see the attached revision for approval. We are proposing to use coiled tubing to execute the cement milling and finish the P&A work. Cement plugs in the TxIA will be from ~6,200’ MD up to ~2,800’ MD. We hope to have coiled tubing rigging up on the well by this evening. Original approved Sundry attached for reference. Thanks and Best Regards, Aras Worthington Operations Engineer HJMNQRU Pads Hilcorp North Slope Aras.worthington@hilcorp.com 907-564-4763 907-440-7692 mobile CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. From: Lau, Jack J (OGC) <jack.lau@alaska.gov> Sent: Thursday, December 5, 2024 5:57 PM To: Aras Worthington <aras.worthington@hilcorp.com> Cc: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Joseph Engel <jengel@hilcorp.com>; Abbie Barker <Abbie.Barker@hilcorp.com>; Tyson Shriver <Tyson.Shriver@hilcorp.com> Subject: [EXTERNAL] RE: W-01A P&A Pre-Rotary Sidetrack PTD #203-176 Sundry #324-630 Aras, After discussing this with Mel and Andy, the base of the Schrader reservoir plug needs to be at 6,200’ MD across all annuli. That puts the base of the plug at the top of the SB – N. Jack Lau Senior Petroleum Engineer Alaska Oil and Gas Conservation Commission (907) 793-1244 Office (907) 227-2760 Cell CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Sent: Thursday, December 5, 2024 5:45 PM To: Lau, Jack J (OGC) <jack.lau@alaska.gov> Subject: FW: W-01A P&A Pre-Rotary Sidetrack PTD #203-176 Sundry #324-630 From: Aras Worthington <Aras.Worthington@hilcorp.com> Sent: Thursday, December 5, 2024 1:08 PM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Tyson Shriver <Tyson.Shriver@hilcorp.com>; Joseph Engel <jengel@hilcorp.com>; Abbie Barker <Abbie.Barker@hilcorp.com> Subject: W-01A P&A Pre-Rotary Sidetrack PTD #203-176 Sundry #324-630 Mel, As discussed via phone we have pumped the Ivishak reservoir cement plug without issue, tagged and MITT’d both AOGCC witnessed. We proceeded with the first Schrader cement plug pumping 50% excess cement as planned but cement locked up before the excess could be pumped away into the perforations. We estimate there are 26 bbls of cement below the cement retainer and 19 bbls above it in the tubing. Slickline is tagging TOC today to verify. I hesitated to send this email until we had an actual tag but since I don’t think it will come in much deeper than what is described below I’m going ahead with it. As well, this is the next well for Innovation and the current well is TD’d and going into the completion phase. We propose to punch tubing just above the tag depth and perform the upper TxIA cement plug from ~5000’ MD instead of the planned ~6340’ MD. Below are the schematics: The first one on the left is what was proposed in the Sundry. The schematic on the right is the new proposal given the expected shallower tag of TOC. The approved Sundry is attached for reference. Thanks in advance for taking a look at this on short notice. Aras Worthington Operations Engineer HJMNQRU Pads Hilcorp North Slope Aras.worthington@hilcorp.com 907-564-4763 907-440-7692 mobile The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual orentity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination,distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email ortelephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onwardtransmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by thecompany in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual orentity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination,distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email ortelephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onwardtransmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by thecompany in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 4-1/2" 12.6# x 3-1/2" 9.2#/9.3# 4-1/2" HES TNT Packer (5) 3-1/2" HES TNT Packer, 3-1/2" Otis Packer 6424 / 4901, 6683 / 5050, 6794 / 5114, 7062 / 5268, 11280 / 8149, 11509 / 8319, 11688 / 8451 Digitally signed by Sean McLaughlin (4311) DN: cn=Sean McLaughlin (4311) Date: 2024.11.04 10:59:43 - 09'00' Sean McLaughlin (4311) 324-630 By Grace Christianson at 1:29 pm, Nov 04, 2024 MGR08NOV24 AOGCC to witness slickline tag and pressure test to 2750 psi of Ivishak reservoir plug. AOGCC to witness slickline tag and pressure test of Schrader Bluff reservoir plug. Full bore cement retainers to have ball seat to assure cement is not over displaced past retainers. DSR-11/6/24 X2 SFD 11/6/2024 10-407 JLC 11/8/2024 Gregory Wilson Digitally signed by Gregory Wilson Date: 2024.11.08 15:23:25 -09'00'11/08/24 Reservoir Abandonment & Pre-Rig PBU W-01A PTD: 203-176 Well Name:PBU W-01A API Number:50-029-21866-01 Current Status:Operable Schrader PW Injector Rig:SL, EL, FB Estimated Start Date:11/18/2024 Estimated Duration:Two weeks Reg.Approval Req’std?10-403 Date Reg. Approval Rec’vd: Regulatory Contact:Joe Lastufka First Call Engineer:Aras Worthington Contact:907-440-7692 Current Bottom Hole Pressure (Ivishak):3,250 psi @ 8,800’ TVD (average) Current Bottom Hole Pressure (Schrader):2,161 psi @ 5,083’ TVD (SBHPS 6/24) Max. Anticipated Surface Pressure:2,370 psi (Based on 0.1 psi/ft gas gradient) Last SI WHP:150 psi (6/19/2024) Min ID: 1.92” @ 11,762’ MD (2-3/8”Liner Top) Max Angle:96 Deg @ 12,573’ MD; 70 deg @ ~12,355’ MD Brief Well Summary: Ivishak CTD sidetrack producer drilled in 2003 and re-completed to the Schrader in 2022. Objective: Abandon the Ivishak and Schrader reservoirs with cement in preparation for a rotary sidetrack to the Schrader. Annular Cement: 2-3/8” Liner: not cemented 5-1/2” Liner: Cemented with 66 bbls Class G. No losses were reported. Plug was bumped, and cement contaminated mud was reported as being circulated out of the hole on the next run with a bit and 9-5/8” casing scraper after tagging the top of the liner top packer. The volume of cement pumped is approximately 80% excess with the 8-1/2” openhole. 9-5/8” Casing: Cemented with lead of 1036 sx Class G w/ 8% bentonite (1958 cubic feet) and tail 500 sx w/ 1% bentonite (620 cubic feet). Total 2578 cubic feet / 460 bbls. No losses were reported. The 13-3/8” x 9-5/8” annulus was downsqueezed with 300 sx of Permafrost C cement and displaced with 150 bbls dry crude. This displacement calculates to a TOC of ~2510’ MD in the OA. A CBL log run on 6/8/22 showed cement stringers in the OA starting at ~2200’ MD and good cement bond from ~2650’ MD to the bottom of the log @ ~11,400’ MD. The top of the Ivishak pool is 12,116’ MD. Top of Schrader is 6,198’ MD. Reservoir Abandonment & Pre-Rig PBU W-01A PTD: 203-176 WBL Steps: 1 S DUMMY-OFF ALL WF MANDRELS, PT, PULL PX PLUG, DRIFT FOR CEMENT RETAINER 2EPUNCH TUBING/LINER, SET CEMENT RETAINER 3FCEMENT RESERVOIR ABANDONMENT PLUG OVER IVISHAK 4 F MITT (AOGCC WITNESSED) 5 S TAG TOC (AOGCC WITNESSED), PULL ALL DUMMY GLVS FROM WF MANDRELS 6 E SET CEMENT RETAINER 7 F CEMENT RESERVOIR ABANDONMENT PLUG OVER SCHRADER 8 F MITT & MIT-IA (AOGCC WTNESSED) 9 S TAG TOC (AOGCC WITNESSED) 10 E PUNCH TUBING 11 F TXIA CEMENT PLUG 12 S TAG TOC, DRIFT FOR JET CUTTER 13 E JET CUT TUBING Procedural steps Slickline 1. Dummy off all Water-Flood-Regulating Valves (WFRVs) in the Shrader interval (Station 1 & 3 have WFRVs currently). 2. Pressure test the tubing (5 minute test, 500 psi, no more than 10% pressure loss is a pass - to ensure all Schrader valves are holding for the upcoming cement job). 3. Pull the 3-1/2” PX plug set @ 11,608’ MD. 4. Drift for 3-1/2” cement retainer and tubing punch to deviation (70 deg @ 12,355’ MD). E-Line 5. Punch the 2-3/8” Liner @ from ~12,145’ - 12,150’ MD across a collar/cementralizer for standoff from the formation. 6. Punch the 3-1/2” tubing just above the X-nipple immediately below the first full joint below the deepest packer from 11,726’ - 11,731’ MD. Reference attached tubing tally of 10/11/1988. 7. Set 4-1/2” Ball-drop cement retainer @ 11,294’ ME (middle of 13’ pup joint just below production packer @ 11,280’ MD – reference attached tubing tally of 6/10/2021). Note: Retainer modified by Northern Solutions; contact Carl Diller @ (907) 258-6679. Fullbore 8. Pump Ivishak reservoir cement plug as follows down the tubing. Max tubing pressure 3000 psi. ¾260 bbls FW, SW, or 1% KCL (1.2 x Wellbore volume). ¾65 bbls 15.8 ppg Class G cement (~50% excess of volume to fill all OH, liner, annuli, and tubing below the retainer) ¾2 bbls FW spacer ¾Landing-Ball followed by two Foam-Balls ¾110 bbls bbls heated 70 deg 9.8 ppg brine ¾61 bbls heated 70 deg-F diesel - Slow Pump rate to minimum for last 5 bbls to seat Ball. Bump Ball with ~500 psi of excess pressure. Assure TOC at cement retainer. - mgr Reservoir Abandonment & Pre-Rig PBU W-01A PTD: 203-176 Volumes: ¾4-1/2” tubing: 11,428’ x 0.0152 bpf = 174 bbls ¾3-1/2” tubing: (11,798’ – 11,428’) x 0.0087 bpf = 3 bbls ¾3-1/2” tubing x 9-5/8” annulus: (11,798’ – 11,726’) x 0.0613 bpf = 4.4 bbls ¾2-3/8” liner: (12,380’ – 11,762’) x 0.0036 bpf = 2.2 bbls ¾2-3/8” x 9-5/8” annulus (11,810’ -11,798’) x 0.068 bpf = 0.8 bbls ¾2-3/8” x 5-1/2” annulus: (12,145’ – 11,810’) x 0.0178 bpf = 6 bbls ¾2-3/8” x 3” formation annulus: (12,380’ – 12,145’) x 0.0033 bpf = 0.8 bbls ¾3” OH (sidetracked hole): (14,109’ – 12,200’) x 0.0087 bpf = 17 bbls ¾3” OH: (13,135’ – 12,150’) x 0.0087 bpf = 8.6 bbls Total volume of wellbore: 217 bbls ¾4-1/2” tubing below retainer: (11,428’ - 11,294’) x 0.0152 bpf = 2 bbls ¾3-1/2” tubing: (11,798’ – 11,428’) x 0.0087 bpf = 3 bbls ¾3-1/2” tubing x 9-5/8” annulus: (11,798’ – 11,726’) x 0.0613 bpf = 4.4 bbls ¾2-3/8” liner: (12,380’ – 11,762’) x 0.0036 bpf = 2.2 bbls ¾2-3/8” x 9-5/8” annulus (11,810’ -11,798’) x 0.068 bpf = 0.8 bbls ¾2-3/8” x 5-1/2” annulus: (12,145’ – 11,810’) x 0.0178 bpf = 6 bbls ¾2-3/8” x 3” formation annulus: (12,380’ – 12,145’) x 0.0033 bpf = 0.8 bbls ¾3” OH (sidetracked hole): (14,109’ – 12,200’) x 0.0087 bpf = 17 bbls ¾3” OH (main bore): (13,135’ – 12,380’) x 0.0087 bpf = 6.6 bbls Total volume of OH, liner, annular volume, & tbg below retainer: 43 bbls Fullbore 9. MITT to 2500 psi target pressure, 2750 psi max pressure (AOGCC witnessed). Slickline 10. Tag TOC (AOGCC witnessed). 11. Pull all DGLVs from Water-Flood Mandrels across the Schrader (Stations #1-#6). E-Line 12. Set Magnum ball-drop cement retainer in the middle of the first full joint of tubing above the shallowest production packer @ ~6,390’ MD - reference attached tubing tally of 6/10/2021. Note: Retainer modified by Northern Solutions; contact Carl Diller @ (907) 258-6679. Pull all DGLVs from Water-Flood Mandrels across the Schrader (Stations #1-#6). Reservoir Abandonment & Pre-Rig PBU W-01A PTD: 203-176 Fullbore 13. Pump Schrader reservoir cement plug as follows down the tubing. Max tubing pressure 3000 psi. ¾151 bbls FW, SW, or 1% KCL (1.2 x Wellbore volume). ¾45 bbls 15.8 ppg Class G cement (~50% excess of volume to fill all annuli, and tubing below the retainer) ¾2 bbls FW spacer ¾Landing-Ball followed by two Foam-Balls ¾97 bbls heated 70 deg-F diesel - Slow Pump rate to minimum for last 5 bbls to seat Ball. Bump Ball with ~500 psi of excess pressure. Volumes: ¾4-1/2” tubing: 6914’ x 0.0152 bpf = 105 bbls ¾4-1/2” tubing x 9-5/8” annulus: (6914’ – 6,527’) x 0.0535 bpf = 21 bbls Total volume of wellbore: 126 bbls ¾4-1/2” tubing below retainer: (6,914’ – 6,390’) x 0.0152 bpf = 8 bbls ¾4-1/2” tubing x 9-5/8” annulus: (6914’ – 6,527’) x 0.0535 bpf = 21 bbls Total volume of annulus & tbg below retainer: 29 bbls Fullbore 14. MITT to 2500 psi target pressure, 2750 psi max pressure (AOGCC witnessed). Slickline 15. Tag TOC (AOGCC witnessed). E-Line 16. Punch tubing across a collar above tag of TOC depth using 5’ of guns. (Approximately 6,340’ MD). Fullbore 17. Cement tubing and IA to ~2,800’ MD as follows pumping under 3,000 psi max tubing pressure: ¾21 bbls MEOH (20 bbls to ensure 1:1 returns from IA before pumping cement and to get adequate FP in the IA after the cement job. Note that the 97 bbls of diesel pumped to displace the previous cement job will be circulated into the IA once pumping commences so 21 bbls more are needed to FP the IA to 2200’ MD) ¾2 bbls FW ¾243 bbls 15.8 ppg Class G Cement – pump cement at maximum rate ¾2 bbls FW ¾Two Foam-Balls ¾41 bbls diesel to displace TOC in tubing to 2800’ MD. Assure TOC at cement retainer. - mgr Reservoir Abandonment & Pre-Rig PBU W-01A PTD: 203-176 Volumes: ¾4-1/2” tubing to 2800’ MD: 2800’ x 0.0152 bpf = 43 bbls ¾4-1/2” tubing x 9-5/8” annulus to 2200’ MD: 2,200’ x 0.0535 bpf = 118 bbls Total volume of wellbore: 126 bbls ¾4-1/2” tubing: (6,340’ – 2,800’) x 0.0152 bpf = 54 bbls ¾4-1/2” tubing x 9-5/8” annulus: (6,340’ – 2,800’) x 0.0535 bpf = 189 bbls Total volume of cement for TxIA cement plug: 243 bbls Slickline 18. Drift and tag TOC. 19. Drift for Jet Cutter to ~2800’ MD. E-Line 20. Jet cut tubing @ ~2700’ MD. Attachments: 1. Current Wellbore Schematic 2. Proposed Wellbore Schematic 3. Tbg tallys Reservoir Abandonment & Pre-Rig PBU W-01A PTD: 203-176 Current Wellbore Schematic Reservoir Abandonment & Pre-Rig PBU W-01A PTD: 203-176 Proposed Wellbore Schematic Ivishak Reservoir Cement Plug top @ ~11,294’ MD 13-3/8” x 9-5/8” OA downsqeezed TOC via USIT of 6/8/2022 @ ~2650’ Tubing/Liner punches Cement Retainers @ ~6,390’ MD & ~11,294’ MD Schrader Reservoir Cement Plugs TOCs @ ~6,390’ MD & 2800’ MD Reservoir Abandonment & Pre-Rig PBU W-01A PTD: 203-176 Reservoir Abandonment & Pre-Rig PBU W-01A PTD: 203-176 Sundry Application Well Name______________________________ (PTD _________; Sundry _________) Plug for Re-drill Well Workflow This process is used to identify wells that are suspended for a very short time prior to being re-drilled. Those wells that are not re-drilled immediately are identified every 6 months and assigned a current status of "Suspended." Step Task Responsible 1 The initial reviewer will check to ensure that the "Plug for Redrill" box in the upper left corner of Form 10-403 is checked. If the "Abandon" or "Suspend" boxes are also checked, cross out that erroneous entry and initial it on the Form 10-403. Geologist 2 If the “Abandon” box is checked in Box 15 (Well Status after proposed work) the initial reviewer will cross out that checkbox and instead, check the "Suspended" box and initial those changes. Geologist The drilling engineer will serve as quality control for steps 1 and 2. Petroleum Engineer (QC) 3 When the RA2 receives a Form 10-403 with a check in the "Plug for Redrill" box, they will enter the Typ_Work code "IPBRD" into the History tab for the well in RBDMS. This code automatically generates a comment in the well history that states "Intent: Plug for Redrill." Research Analyst 2 4 When the RA2 receives Form 10-407, they will check the History tab in RBDMS for the IPBRD code. If IPBRD is present and there is no evidence that a subsequent re-drill has been completed, the RA2 will assign a status of SUSPENDED to the well bore in RBDMS. The RA2 will update the status on the 10-407 form to SUSPENDED, and date and initial this change. If the RA2 does not see the "Intent: Plug for Redrill" comment or code, they will enter the status listed on the Form 10-407 into RBDMS. Research Analyst 2 5 When the Form 10-407 for the redrill is received, the RA2 will change the original well's status from SUSPENDED to ABANDONED. Research Analyst 2 6 The first week of every January and July, the RA2 and a Geologist or Reservoir Engineer will check the "Well by Type Work Outstanding" user query in RBDMS to ensure that all Plug for Redrill sundried wells have been updated to reflect current status. At this same time, they will also review the list of suspended wells for accuracy and assign expiration dates as needed. Research Analyst 2 Geologist or Reservoir Engineer 324-630 PBU W-01A SFD 11/6/2024 SFD 11/6/2024 203-176 Reservoir Abandonment & Pre-Rig Rev1 PBU W-01A PTD: 203-176 Well Name: PBU W-01A API Number: 50-029-21866-01 Current Status: Not Operable Rig: SL, EL, FB Estimated Start Date: 11/18/2024 Estimated Duration: Two weeks Reg.Approval Req’std? 10-403 Date Reg. Approval Rec’vd: Regulatory Contact: Joe Lastufka First Call Engineer: Aras Worthington Contact: 907-440-7692 Current Bottom Hole Pressure (Ivishak): 3,250 psi @ 8,800’ TVD (average) Current Bottom Hole Pressure (Schrader): 2,161 psi @ 5,083’ TVD (SBHPS 6/24) Max. Anticipated Surface Pressure: 2,370 psi (Based on 0.1 psi/ft gas gradient) Last SI WHP: 150 psi (6/19/2024) Min ID: 1.92” @ 11,762’ MD (2-3/8”Liner Top) Max Angle: 96 Deg @ 12,573’ MD; 70 deg @ ~12,355’ MD Brief Well Summary: Ivishak CTD sidetrack producer drilled in 2003 and re-completed to the Schrader in 2022. Objective: Abandon the Ivishak and Schrader reservoirs with cement in preparation for a rotary sidetrack to the Schrader. Annular Cement: 2-3/8” Liner: not cemented 5-1/2” Liner: Cemented with 66 bbls Class G. No losses were reported. Plug was bumped, and cement contaminated mud was reported as being circulated out of the hole on the next run with a bit and 9-5/8” casing scraper after tagging the top of the liner top packer. The volume of cement pumped is approximately 80% excess with the 8-1/2” openhole. 9-5/8” Casing: Cemented with lead of 1036 sx Class G w/ 8% bentonite (1958 cubic feet) and tail 500 sx w/ 1% bentonite (620 cubic feet). Total 2578 cubic feet / 460 bbls. No losses were reported. The 13-3/8” x 9-5/8” annulus was downsqueezed with 300 sx of Permafrost C cement and displaced with 150 bbls dry crude. This displacement calculates to a TOC of ~2510’ MD in the OA. A CBL log run on 6/8/22 showed cement stringers in the OA starting at ~2200’ MD and good cement bond from ~2650’ MD to the bottom of the log @ ~11,400’ MD. The top of the Ivishak pool is 12,116’ MD. Top of Schrader is 6,198’ MD. Reservoir Abandonment & Pre-Rig Rev1 PBU W-01A PTD: 203-176 WBL Steps: 1 S DUMMY-OFF ALL WF MANDRELS, PT, PULL PX PLUG, DRIFT FOR CEMENT RETAINER 2 E PUNCH TUBING/LINER, SET CEMENT RETAINER 3 F CEMENT RESERVOIR ABANDONMENT PLUG OVER IVISHAK 4 F MITT (AOGCC WITNESSED) 5 S TAG TOC (AOGCC WITNESSED), PULL ALL DUMMY GLVS FROM WF MANDRELS 6 E SET CEMENT RETAINER 7 F CEMENT RESERVOIR ABANDONMENT PLUG OVER SCHRADER 8 C MILL OUT CEMENT FROM TBG, TAG TOC (AOGCC WITNESSED), MITT & MIT-IA (AOGCC WITNESSED), PUNCH TBG, SET RETAINER, PUMP TXIA CEMENT PLUG 9 S TAG TOC, DRIFT FOR JET CUTTER 10 E JET CUT TUBING Procedural steps Slickline 1. Dummy off all Water-Flood-Regulating Valves (WFRVs) in the Shrader interval (Station 1 & 3 have WFRVs currently). 2. Pressure test the tubing (5 minute test, 500 psi, no more than 10% pressure loss is a pass - to ensure all Schrader valves are holding for the upcoming cement job). 3. Pull the 3-1/2” PX plug set @ 11,608’ MD. 4. Drift for 3-1/2” cement retainer and tubing punch to deviation (70 deg @ 12,355’ MD). E-Line 5. Punch the 2-3/8” Liner @ from ~12,145’ - 12,150’ MD across a collar/cementralizer for standoff from the formation. 6. Punch the 3-1/2” tubing just above the X-nipple immediately below the first full joint below the deepest packer from 11,726’ - 11,731’ MD. Reference attached tubing tally of 10/11/1988. 7. Set 4-1/2” Ball-drop cement retainer @ 11,294’ ME (middle of 13’ pup joint just below production packer @ 11,280’ MD – reference attached tubing tally of 6/10/2021). Note: Retainer modified by Northern Solutions; contact Carl Diller @ (907) 258-6679. Fullbore 8. Pump Ivishak reservoir cement plug as follows down the tubing. Max tubing pressure 3000 psi. ¾ 260 bbls FW, SW, or 1% KCL (1.2 x Wellbore volume). ¾ 65 bbls 15.8 ppg Class G cement (~50% excess of volume to fill all OH, liner, annuli, and tubing below the retainer) ¾ 2 bbls FW spacer ¾ Landing-Ball followed by two Foam-Balls ¾ 110 bbls bbls heated 70 deg 9.8 ppg brine ¾ 61 bbls heated 70 deg-F diesel - Slow Pump rate to minimum for last 5 bbls to seat Ball. Bump Ball with ~500 psi of excess pressure. Volumes: ¾ 4-1/2” tubing: 11,428’ x 0.0152 bpf = 174 bbls ¾ 3-1/2” tubing: (11,798’ – 11,428’) x 0.0087 bpf = 3 bbls ¾ 3-1/2” tubing x 9-5/8” annulus: (11,798’ – 11,726’) x 0.0613 bpf = 4.4 bbls Reservoir Abandonment & Pre-Rig Rev1 PBU W-01A PTD: 203-176 ¾ 2-3/8” liner: (12,380’ – 11,762’) x 0.0036 bpf = 2.2 bbls ¾ 2-3/8” x 9-5/8” annulus (11,810’ -11,798’) x 0.068 bpf = 0.8 bbls ¾ 2-3/8” x 5-1/2” annulus: (12,145’ – 11,810’) x 0.0178 bpf = 6 bbls ¾ 2-3/8” x 3” formation annulus: (12,380’ – 12,145’) x 0.0033 bpf = 0.8 bbls ¾ 3” OH (sidetracked hole): (14,109’ – 12,200’) x 0.0087 bpf = 17 bbls ¾ 3” OH: (13,135’ – 12,150’) x 0.0087 bpf = 8.6 bbls Total volume of wellbore: 217 bbls ¾ 4-1/2” tubing below retainer: (11,428’ - 11,294’) x 0.0152 bpf = 2 bbls ¾ 3-1/2” tubing: (11,798’ – 11,428’) x 0.0087 bpf = 3 bbls ¾ 3-1/2” tubing x 9-5/8” annulus: (11,798’ – 11,726’) x 0.0613 bpf = 4.4 bbls ¾ 2-3/8” liner: (12,380’ – 11,762’) x 0.0036 bpf = 2.2 bbls ¾ 2-3/8” x 9-5/8” annulus (11,810’ -11,798’) x 0.068 bpf = 0.8 bbls ¾ 2-3/8” x 5-1/2” annulus: (12,145’ – 11,810’) x 0.0178 bpf = 6 bbls ¾ 2-3/8” x 3” formation annulus: (12,380’ – 12,145’) x 0.0033 bpf = 0.8 bbls ¾ 3” OH (sidetracked hole): (14,109’ – 12,200’) x 0.0087 bpf = 17 bbls ¾ 3” OH (main bore): (13,135’ – 12,380’) x 0.0087 bpf = 6.6 bbls Total volume of OH, liner, annular volume, & tbg below retainer: 43 bbls Fullbore 9. MITT to 2500 psi target pressure, 2750 psi max pressure (AOGCC witnessed). MITT passed to 2500 psi on 12/1/24; AOGCC witnessed. Slickline 10. Tag TOC (AOGCC witnessed). TOC tagged @ 11,274’ MD on 12/1/24; AOGCC witnessed. 11. Pull all DGLVs from Water-Flood Mandrels across the Schrader (Stations #1-#6). E-Line 12. Set Magnum ball-drop cement retainer in the middle of the first full joint of tubing above the shallowest production packer @ ~6,390’ MD - reference attached tubing tally of 6/10/2021. Note: Retainer modified by Northern Solutions; contact Carl Diller @ (907) 258-6679. Reservoir Abandonment & Pre-Rig Rev1 PBU W-01A PTD: 203-176 Fullbore 13. Pump Schrader reservoir cement plug as follows down the tubing. Max tubing pressure 3000 psi. ¾ 151 bbls FW, SW, or 1% KCL (1.2 x Wellbore volume). ¾ 45 bbls 15.8 ppg Class G cement (~50% excess of volume to fill all annuli, and tubing below the retainer) ¾ 2 bbls FW spacer ¾ Landing-Ball followed by two Foam-Balls ¾ 97 bbls heated 70 deg-F diesel - Slow Pump rate to minimum for last 5 bbls to seat Ball. Bump Ball with ~500 psi of excess pressure. Volumes: ¾ 4-1/2” tubing: 6914’ x 0.0152 bpf = 105 bbls ¾ 4-1/2” tubing x 9-5/8” annulus: (6914’ – 6,527’) x 0.0535 bpf = 21 bbls Total volume of wellbore: 126 bbls ¾ 4-1/2” tubing below retainer: (6,914’ – 6,390’) x 0.0152 bpf = 8 bbls ¾ 4-1/2” tubing x 9-5/8” annulus: (6914’ – 6,527’) x 0.0535 bpf = 21 bbls Total volume of annulus & tbg below retainer: 29 bbls Cement plug pumped per procedure on 12/4/24 but locked up at ~78 bbls of displacement after cement. TOC tagged w/ SL at 4,889’ MD. Coiled Tubing 14. MU 3.80” PDC Mill and jars. Consider using one of the bi-center PDC mills at the WLTR. Consider using the re-circ skid as was done on the last big 4-1/2” cement milling job on PBU D-16B. 15. Mill cement to ~6250’ MD (top of the Schrader/base of SB-N sand is ~6,200’ MD). 16. Perform AOGCC witnessed tag of TOC. 17. MITT to 2500 psi target pressure, 2750 psi max pressure (AOGCC witnessed). 18. Punch tubing using a five-foot gun at ~6,200’ MD. 19. Establish circulation from tubing to IA to verify tubing punch. 20. Set one-trip cement retainer @ ~6,180’ MD. 21. PT the Tbg x CT backside to 500 psi to ensure retainer is set. Five-minute test. 22. Cement tubing and IA to ~2,800’ MD as follows: ¾ 120 bbls diesel (to ensure 1:1 returns from IA before pumping cement and to get adequate FP in the IA to ~2,200’ MD after the cement job) ¾ 2 bbls FW ¾ 234 bbls 15.8 ppg Class G Cement a. Unsting from the retainer @ 182 bbls of cement through the retainer b. Lay remaining 52 bbls @ 1:1 in the 4-1/2” tubing ¾ CT volume of FW ¾ Reverse-out or circulate the long-way to leave TOC in tubing & IA @ ~2800’ MD. 23. FP tubing with diesel to 2200’ MD. Reservoir Abandonment & Pre-Rig Rev1 PBU W-01A PTD: 203-176 Volumes: ¾ 4-1/2” tubing to 2,800’ MD: 2,800’ x 0.0152 bpf = 43 bbls ¾ 4-1/2” tubing x 9-5/8” annulus to 2200’ MD: 2,200’ x 0.0535 bpf = 118 bbls ¾ 4-1/2” tubing: (6,200’ – 2,800’) x 0.0152 bpf = 52 bbls ¾ 4-1/2” tubing x 9-5/8” annulus: (6,200’ – 2,800’) x 0.0535 bpf = 182 bbls Total volume of cement for TxIA cement plug: 234 bbls Slickline 24. Drift & tag TOC for Jet Cutter to ~2800’ MD. E-Line 25. Jet cut tubing @ ~2700’ MD. Attachments: 1. Current Wellbore Schematic 2. Proposed Wellbore Schematic 3. Tbg tallys Reservoir Abandonment & Pre-Rig Rev1 PBU W-01A PTD: 203-176 Current Wellbore Schematic Reservoir Abandonment & Pre-Rig Rev1 PBU W-01A PTD: 203-176 Proposed Wellbore Schematic Ivishak Reservoir Cement Plug TOC tagged @ 11,274’ MD 13-3/8” x 9-5/8” OA downsqeezed TOC via RBT of 6/8/2022 @ ~2650’ Tubing/Liner punches Cement Retainers @ ~6,180’, ~6,390’ MD & ~11,294’ MD Schrader Reservoir Cement Plug TOC milled to ~6,250’ MD Cement Plug TxIA through Tubing Punch @ ~6,200’ MD to ~2,800’ MD Reservoir Abandonment & Pre-Rig Rev1 PBU W-01A PTD: 203-176 Reservoir Abandonment & Pre-Rig Rev1 PBU W-01A PTD: 203-176 CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Wallace, Chris D (OGC) To:AOGCC Records (CED sponsored) Subject:FW: NOT OPERABLE: Injector W-01A (PTD #2031760) AOGCC MIT-T Passed reservoir cement tag Date:Monday, December 2, 2024 4:38:49 PM Attachments:MIT PBU W-01A 12-01-24.xlsx From: PB Wells Integrity <PBWellsIntegrity@hilcorp.com> Sent: Monday, December 2, 2024 4:34 PM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Cc: Regg, James B (OGC) <jim.regg@alaska.gov>; Oliver Sternicki <Oliver.Sternicki@hilcorp.com> Subject: NOT OPERABLE: Injector W-01A (PTD #2031760) AOGCC MIT-T Passed reservoir cement tag Mr. Wallace, Injector W-01 (PTD # 2031760) passed AOGCC witnessed MIT-T and reservoir cement tag on 12/01. Rotary drilling + sidetrack will recomplete W-01A as a producer. The well is now classified as NOT OPERABLE and will remain shut in until well barriers are confirmed post rig. Sundry #321-394 calls for a pulsed neutron water flow and temperature log on W-08 at defined intervals when W-01A is on water injection and is due this month. As W-01A was shut in on 01/14/24 and will no longer be on water injection the requirement for the log on W-08 will be removed from our compliance report. Please call with any questions or concerns. Ryan Holt Hilcorp Alaska LLC Field Well Integrity / Compliance Ryan.Holt@Hilcorp.com P: (907) 659-5102 M: (907) 232-1005 From: PB Wells Integrity <PBWellsIntegrity@hilcorp.com> Sent: Tuesday, June 21, 2022 9:44 AM To: chris.wallace@alaska.gov Cc: Regg, James B (CED) <jim.regg@alaska.gov>; Oliver Sternicki <Oliver.Sternicki@hilcorp.com>; PB Wells Integrity <PBWellsIntegrity@hilcorp.com> Subject: OPERABLE: Injector W-01A (PTD #2031760) RWO complete Mr. Wallace, Injector W-01A (PTD # 2031760) RWO has been completed under Sundry #321-394. As part of the Sundry, the well has been converted to a produced water injector. On 06/19/22 Fullbore performed a passing AOGCC witnessed offline MIT-T to 3075 psi and MIT-IA to 3216 psi which proves two competent well barriers. The well will now be classified as OPERABLE. Once the well is on stable injection, an online AOGCC witnessed MIT-IA will be performed. Please respond with any questions. Andy Ogg Hilcorp Alaska LLC Field Well Integrity andrew.ogg@hilcorp.com P: (907) 659-5102 M: (307)399-3816 From: PB Wells Integrity <PBWellsIntegrity@hilcorp.com> Sent: Tuesday, April 26, 2022 10:03 AM To: Brodie Wages <David.Wages@hilcorp.com>; PB EOC Specialists <PBEOCSpecialists@hilcorp.com>; PB Wells Optimization Engineers <PBWellsOptimizationEngineers@hilcorp.com>; PBW GC2 Field Lead Operator <PBWGC2FieldLeadOperator@hilcorp.com>; PBW GC2 Foreman <PBWGC2Foreman@hilcorp.com>; PBW GC2 Wellpad HUQ <PBWGC2WellpadHUQ@hilcorp.com>; PBW GC2 Wellpad LV <PBWGC2WellpadLV@hilcorp.com>; PBW GC2 Wellpad MN <PBWGC2WellpadMN@hilcorp.com>; PBW GC2 Wellpad RJ <PBWGC2WellpadRJ@hilcorp.com>; PBW GC2 Wellpad S <PBWGC2WellpadS@hilcorp.com>; PBW GC2 Wellpad W <PBWGC2WellpadW@hilcorp.com>; PBW GC2 Wellpad Z <PBWGC2WellpadZ@hilcorp.com>; PBW PCC Leads <GC3ProdContCenterLeads@hilcorp.com>; Wyatt Rivard <wrivard@hilcorp.com> Cc: Abbie Barker <Abbie.Barker@hilcorp.com>; Alaska IMS User <akimsuser@hilcorp.com>; Carrie Janowski <Carrie.Janowski@hilcorp.com>; John Condio - (C) <John.Condio@hilcorp.com>; John Menke <jmenke@hilcorp.com>; Kevin Brackett <Kevin.Brackett@hilcorp.com>; Oliver Sternicki <Oliver.Sternicki@hilcorp.com>; PB Wells Integrity <PBWellsIntegrity@hilcorp.com>; Stan Golis <sgolis@hilcorp.com> Subject: NOT OPERABLE: Producer W-01A (PTD #2031760) being prepared for RWO All, Producer W-01A (PTD #2031760) is scheduled for a RWO in 2022. Slickline left an open pocket in GLM #1 in preparation for an upcoming e-line tubing cut. The well will now be classified as NOT OPERABLE until the RWO is complete. Please respond with any questions. Andy Ogg Hilcorp Alaska LLC Field Well Integrity / Compliance andrew.ogg@hilcorp.com P: (907) 659-5102 M: (307)399-3816 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. Submit to: OPERATOR: FIELD / UNIT / PAD: DATE: OPERATOR REP: AOGCC REP: Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD 2031760 Type Inj N Tubing 449 2752 2599 2536 Type Test P Packer TVD 4901 BBL Pump 2.2 IA 0 0 0 0 Interval O Test psi 2500 BBL Return 2.1 OA 151 151 150 151 Result P Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W = Water P = Pressure Test I = Initial Test P = Pass G = Gas O = Other (describe in Notes)4 = Four Year Cycle F = Fail S = Slurry V = Required by Variance I = Inconclusive I = Industrial Wastewater O = Other (describe in notes) N = Not Injecting Notes: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov Notes: Notes: Notes: Hilcorp North Slope LLC Prudhoe Bay / PBU / W Pad Bob Noble Will Ragsdale 12/01/24 Notes:AOGCC MIT-T to 2500 psi for cement isolation plug per sundry #324-630 Notes: Notes: Notes: W-01A Form 10-426 (Revised 01/2017)MIT PBU W-01A 12-01-24 MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg DATE: P.I. Supervisor SUBJECT: FROM: Petroleum Inspector Section: 21 Township: 11N Range: 12N Meridian: Umiat Drilling Rig: n/a Rig Elevation: n/a Total Depth: 13135 ft MD Lease No.: ADL 0028263 Operator Rep: Suspend: P&A: X Conductor: 20" O.D. Shoe@ 114 Feet Csg Cut@ Feet Surface: 13 3/8" O.D. Shoe@ 2934 Feet Csg Cut@ Feet Intermediate: 9 5/8" O.D. Shoe@ 12027 Feet Csg Cut@ Feet Production: 5 1/2" O.D. Shoe@ Feet Csg Cut@ Feet Liner: 5 1/2" O.D. Shoe@ 12143 Feet Csg Cut@ Feet Liner: 2 3/8" O.D. Shoe@ 12380 Feet Csg Cut@ Feet Tubing: 2 3/8" O.D. Tail@ 11798 Feet Tbg Cut@ Feet Type Plug Founded on Depth (Btm) Depth (Top) MW Above Verified Perforation Retainer 11294 ft 11274 ft 9.8 ppg Wireline tag Initial 15 min 30 min 45 min Result Tubing 2752 2599 2536 IA 0 0 0 OA 151 150 151 Initial 15 min 30 min 45 min Result Tubing IA OA Remarks: Attachments: Plugback for redrill. Cement tag was done with wireline and 2-inch bailer. Bailer came back with very firm but contaminated cement and hard chunks. December 1, 2024 Bob Noble Well Bore Plug & Abandonment PBU W-01A Hilcorp North Slope LLC PTD 2031760; Sundry 324-630 none Test Data: P Casing Removal: Will Ragsdale Casing/Tubing Data (depths are MD): Plugging Data (depths are MD): rev. 3-24-2022 2024-1201_Plug_Verification_PBU_W-10A_bn 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9999 999 9 9Plugback for redrill. James B. Regg Digitally signed by James B. Regg Date: 2024.12.04 13:53:58 -09'00' 4-1/2" 12.6# x 3-1/2" 9.2#/9.3# 4-1/2" HES TNT Packer (5) 3-1/2" HES TNT Packer, 3-1/2" Otis Packer 6424 / 4901, 6683 / 5050, 6794 / 5114, 7062 / 5268, 11280 / 8149, 11509 / 8319, 11688 / 8451 Digitally signed by Sean McLaughlin (4311) DN: cn=Sean McLaughlin (4311) Date: 2024.11.04 10:59:43 - 09'00' Sean McLaughlin (4311) 324-630 By Grace Christianson at 1:29 pm, Nov 04, 2024 MGR08NOV24 AOGCC to witness slickline tag and pressure test to 2750 psi of Ivishak reservoir plug. AOGCC to witness slickline tag and pressure test of Schrader Bluff reservoir plug. Full bore cement retainers to have ball seat to assure cement is not over displaced past retainers. DSR-11/6/24 X2 SFD 11/6/2024 10-407 JLC 11/8/2024 Gregory Wilson Digitally signed by Gregory Wilson Date: 2024.11.08 15:23:25 -09'00'11/08/24 RBDMS JSB 111424 Reservoir Abandonment & Pre-Rig PBU W-01A PTD: 203-176 Well Name:PBU W-01A API Number:50-029-21866-01 Current Status:Operable Schrader PW Injector Rig:SL, EL, FB Estimated Start Date:11/18/2024 Estimated Duration:Two weeks Reg.Approval Req’std?10-403 Date Reg. Approval Rec’vd: Regulatory Contact:Joe Lastufka First Call Engineer:Aras Worthington Contact:907-440-7692 Current Bottom Hole Pressure (Ivishak):3,250 psi @ 8,800’ TVD (average) Current Bottom Hole Pressure (Schrader):2,161 psi @ 5,083’ TVD (SBHPS 6/24) Max. Anticipated Surface Pressure:2,370 psi (Based on 0.1 psi/ft gas gradient) Last SI WHP:150 psi (6/19/2024) Min ID: 1.92” @ 11,762’ MD (2-3/8”Liner Top) Max Angle:96 Deg @ 12,573’ MD; 70 deg @ ~12,355’ MD Brief Well Summary: Ivishak CTD sidetrack producer drilled in 2003 and re-completed to the Schrader in 2022. Objective: Abandon the Ivishak and Schrader reservoirs with cement in preparation for a rotary sidetrack to the Schrader. Annular Cement: 2-3/8” Liner: not cemented 5-1/2” Liner: Cemented with 66 bbls Class G. No losses were reported. Plug was bumped, and cement contaminated mud was reported as being circulated out of the hole on the next run with a bit and 9-5/8” casing scraper after tagging the top of the liner top packer. The volume of cement pumped is approximately 80% excess with the 8-1/2” openhole. 9-5/8” Casing: Cemented with lead of 1036 sx Class G w/ 8% bentonite (1958 cubic feet) and tail 500 sx w/ 1% bentonite (620 cubic feet). Total 2578 cubic feet / 460 bbls. No losses were reported. The 13-3/8” x 9-5/8” annulus was downsqueezed with 300 sx of Permafrost C cement and displaced with 150 bbls dry crude. This displacement calculates to a TOC of ~2510’ MD in the OA. A CBL log run on 6/8/22 showed cement stringers in the OA starting at ~2200’ MD and good cement bond from ~2650’ MD to the bottom of the log @ ~11,400’ MD. The top of the Ivishak pool is 12,116’ MD. Top of Schrader is 6,198’ MD. Reservoir Abandonment & Pre-Rig PBU W-01A PTD: 203-176 WBL Steps: 1 S DUMMY-OFF ALL WF MANDRELS, PT, PULL PX PLUG, DRIFT FOR CEMENT RETAINER 2EPUNCH TUBING/LINER, SET CEMENT RETAINER 3FCEMENT RESERVOIR ABANDONMENT PLUG OVER IVISHAK 4 F MITT (AOGCC WITNESSED) 5 S TAG TOC (AOGCC WITNESSED), PULL ALL DUMMY GLVS FROM WF MANDRELS 6 E SET CEMENT RETAINER 7 F CEMENT RESERVOIR ABANDONMENT PLUG OVER SCHRADER 8 F MITT & MIT-IA (AOGCC WTNESSED) 9 S TAG TOC (AOGCC WITNESSED) 10 E PUNCH TUBING 11 F TXIA CEMENT PLUG 12 S TAG TOC, DRIFT FOR JET CUTTER 13 E JET CUT TUBING Procedural steps Slickline 1. Dummy off all Water-Flood-Regulating Valves (WFRVs) in the Shrader interval (Station 1 & 3 have WFRVs currently). 2. Pressure test the tubing (5 minute test, 500 psi, no more than 10% pressure loss is a pass - to ensure all Schrader valves are holding for the upcoming cement job). 3. Pull the 3-1/2” PX plug set @ 11,608’ MD. 4. Drift for 3-1/2” cement retainer and tubing punch to deviation (70 deg @ 12,355’ MD). E-Line 5. Punch the 2-3/8” Liner @ from ~12,145’ - 12,150’ MD across a collar/cementralizer for standoff from the formation. 6. Punch the 3-1/2” tubing just above the X-nipple immediately below the first full joint below the deepest packer from 11,726’ - 11,731’ MD. Reference attached tubing tally of 10/11/1988. 7. Set 4-1/2” Ball-drop cement retainer @ 11,294’ ME (middle of 13’ pup joint just below production packer @ 11,280’ MD – reference attached tubing tally of 6/10/2021). Note: Retainer modified by Northern Solutions; contact Carl Diller @ (907) 258-6679. Fullbore 8. Pump Ivishak reservoir cement plug as follows down the tubing. Max tubing pressure 3000 psi. ¾260 bbls FW, SW, or 1% KCL (1.2 x Wellbore volume). ¾65 bbls 15.8 ppg Class G cement (~50% excess of volume to fill all OH, liner, annuli, and tubing below the retainer) ¾2 bbls FW spacer ¾Landing-Ball followed by two Foam-Balls ¾110 bbls bbls heated 70 deg 9.8 ppg brine ¾61 bbls heated 70 deg-F diesel - Slow Pump rate to minimum for last 5 bbls to seat Ball. Bump Ball with ~500 psi of excess pressure. Assure TOC at cement retainer. - mgr Reservoir Abandonment & Pre-Rig PBU W-01A PTD: 203-176 Volumes: ¾4-1/2” tubing: 11,428’ x 0.0152 bpf = 174 bbls ¾3-1/2” tubing: (11,798’ – 11,428’) x 0.0087 bpf = 3 bbls ¾3-1/2” tubing x 9-5/8” annulus: (11,798’ – 11,726’) x 0.0613 bpf = 4.4 bbls ¾2-3/8” liner: (12,380’ – 11,762’) x 0.0036 bpf = 2.2 bbls ¾2-3/8” x 9-5/8” annulus (11,810’ -11,798’) x 0.068 bpf = 0.8 bbls ¾2-3/8” x 5-1/2” annulus: (12,145’ – 11,810’) x 0.0178 bpf = 6 bbls ¾2-3/8” x 3” formation annulus: (12,380’ – 12,145’) x 0.0033 bpf = 0.8 bbls ¾3” OH (sidetracked hole): (14,109’ – 12,200’) x 0.0087 bpf = 17 bbls ¾3” OH: (13,135’ – 12,150’) x 0.0087 bpf = 8.6 bbls Total volume of wellbore: 217 bbls ¾4-1/2” tubing below retainer: (11,428’ - 11,294’) x 0.0152 bpf = 2 bbls ¾3-1/2” tubing: (11,798’ – 11,428’) x 0.0087 bpf = 3 bbls ¾3-1/2” tubing x 9-5/8” annulus: (11,798’ – 11,726’) x 0.0613 bpf = 4.4 bbls ¾2-3/8” liner: (12,380’ – 11,762’) x 0.0036 bpf = 2.2 bbls ¾2-3/8” x 9-5/8” annulus (11,810’ -11,798’) x 0.068 bpf = 0.8 bbls ¾2-3/8” x 5-1/2” annulus: (12,145’ – 11,810’) x 0.0178 bpf = 6 bbls ¾2-3/8” x 3” formation annulus: (12,380’ – 12,145’) x 0.0033 bpf = 0.8 bbls ¾3” OH (sidetracked hole): (14,109’ – 12,200’) x 0.0087 bpf = 17 bbls ¾3” OH (main bore): (13,135’ – 12,380’) x 0.0087 bpf = 6.6 bbls Total volume of OH, liner, annular volume, & tbg below retainer: 43 bbls Fullbore 9. MITT to 2500 psi target pressure, 2750 psi max pressure (AOGCC witnessed). Slickline 10. Tag TOC (AOGCC witnessed). 11. Pull all DGLVs from Water-Flood Mandrels across the Schrader (Stations #1-#6). E-Line 12. Set Magnum ball-drop cement retainer in the middle of the first full joint of tubing above the shallowest production packer @ ~6,390’ MD - reference attached tubing tally of 6/10/2021. Note: Retainer modified by Northern Solutions; contact Carl Diller @ (907) 258-6679. Pull all DGLVs from Water-Flood Mandrels across the Schrader (Stations #1-#6). Reservoir Abandonment & Pre-Rig PBU W-01A PTD: 203-176 Fullbore 13. Pump Schrader reservoir cement plug as follows down the tubing. Max tubing pressure 3000 psi. ¾151 bbls FW, SW, or 1% KCL (1.2 x Wellbore volume). ¾45 bbls 15.8 ppg Class G cement (~50% excess of volume to fill all annuli, and tubing below the retainer) ¾2 bbls FW spacer ¾Landing-Ball followed by two Foam-Balls ¾97 bbls heated 70 deg-F diesel - Slow Pump rate to minimum for last 5 bbls to seat Ball. Bump Ball with ~500 psi of excess pressure. Volumes: ¾4-1/2” tubing: 6914’ x 0.0152 bpf = 105 bbls ¾4-1/2” tubing x 9-5/8” annulus: (6914’ – 6,527’) x 0.0535 bpf = 21 bbls Total volume of wellbore: 126 bbls ¾4-1/2” tubing below retainer: (6,914’ – 6,390’) x 0.0152 bpf = 8 bbls ¾4-1/2” tubing x 9-5/8” annulus: (6914’ – 6,527’) x 0.0535 bpf = 21 bbls Total volume of annulus & tbg below retainer: 29 bbls Fullbore 14. MITT to 2500 psi target pressure, 2750 psi max pressure (AOGCC witnessed). Slickline 15. Tag TOC (AOGCC witnessed). E-Line 16. Punch tubing across a collar above tag of TOC depth using 5’ of guns. (Approximately 6,340’ MD). Fullbore 17. Cement tubing and IA to ~2,800’ MD as follows pumping under 3,000 psi max tubing pressure: ¾21 bbls MEOH (20 bbls to ensure 1:1 returns from IA before pumping cement and to get adequate FP in the IA after the cement job. Note that the 97 bbls of diesel pumped to displace the previous cement job will be circulated into the IA once pumping commences so 21 bbls more are needed to FP the IA to 2200’ MD) ¾2 bbls FW ¾243 bbls 15.8 ppg Class G Cement – pump cement at maximum rate ¾2 bbls FW ¾Two Foam-Balls ¾41 bbls diesel to displace TOC in tubing to 2800’ MD. Assure TOC at cement retainer. - mgr Reservoir Abandonment & Pre-Rig PBU W-01A PTD: 203-176 Volumes: ¾4-1/2” tubing to 2800’ MD: 2800’ x 0.0152 bpf = 43 bbls ¾4-1/2” tubing x 9-5/8” annulus to 2200’ MD: 2,200’ x 0.0535 bpf = 118 bbls Total volume of wellbore: 126 bbls ¾4-1/2” tubing: (6,340’ – 2,800’) x 0.0152 bpf = 54 bbls ¾4-1/2” tubing x 9-5/8” annulus: (6,340’ – 2,800’) x 0.0535 bpf = 189 bbls Total volume of cement for TxIA cement plug: 243 bbls Slickline 18. Drift and tag TOC. 19. Drift for Jet Cutter to ~2800’ MD. E-Line 20. Jet cut tubing @ ~2700’ MD. Attachments: 1. Current Wellbore Schematic 2. Proposed Wellbore Schematic 3. Tbg tallys Reservoir Abandonment & Pre-Rig PBU W-01A PTD: 203-176 Current Wellbore Schematic Reservoir Abandonment & Pre-Rig PBU W-01A PTD: 203-176 Proposed Wellbore Schematic Ivishak Reservoir Cement Plug top @ ~11,294’ MD 13-3/8” x 9-5/8” OA downsqeezed TOC via USIT of 6/8/2022 @ ~2650’ Tubing/Liner punches Cement Retainers @ ~6,390’ MD & ~11,294’ MD Schrader Reservoir Cement Plugs TOCs @ ~6,390’ MD & 2800’ MD Reservoir Abandonment & Pre-Rig PBU W-01A PTD: 203-176 Reservoir Abandonment & Pre-Rig PBU W-01A PTD: 203-176 Sundry Application Well Name______________________________ (PTD _________; Sundry _________) Plug for Re-drill Well Workflow This process is used to identify wells that are suspended for a very short time prior to being re-drilled. Those wells that are not re-drilled immediately are identified every 6 months and assigned a current status of "Suspended." Step Task Responsible 1 The initial reviewer will check to ensure that the "Plug for Redrill" box in the upper left corner of Form 10-403 is checked. If the "Abandon" or "Suspend" boxes are also checked, cross out that erroneous entry and initial it on the Form 10-403. Geologist 2 If the “Abandon” box is checked in Box 15 (Well Status after proposed work) the initial reviewer will cross out that checkbox and instead, check the "Suspended" box and initial those changes. Geologist The drilling engineer will serve as quality control for steps 1 and 2. Petroleum Engineer (QC) 3 When the RA2 receives a Form 10-403 with a check in the "Plug for Redrill" box, they will enter the Typ_Work code "IPBRD" into the History tab for the well in RBDMS. This code automatically generates a comment in the well history that states "Intent: Plug for Redrill." Research Analyst 2 4 When the RA2 receives Form 10-407, they will check the History tab in RBDMS for the IPBRD code. If IPBRD is present and there is no evidence that a subsequent re-drill has been completed, the RA2 will assign a status of SUSPENDED to the well bore in RBDMS. The RA2 will update the status on the 10-407 form to SUSPENDED, and date and initial this change. If the RA2 does not see the "Intent: Plug for Redrill" comment or code, they will enter the status listed on the Form 10-407 into RBDMS. Research Analyst 2 5 When the Form 10-407 for the redrill is received, the RA2 will change the original well's status from SUSPENDED to ABANDONED. Research Analyst 2 6 The first week of every January and July, the RA2 and a Geologist or Reservoir Engineer will check the "Well by Type Work Outstanding" user query in RBDMS to ensure that all Plug for Redrill sundried wells have been updated to reflect current status. At this same time, they will also review the list of suspended wells for accuracy and assign expiration dates as needed. Research Analyst 2 Geologist or Reservoir Engineer 324-630 PBU W-01A SFD 11/6/2024 SFD 11/6/2024 203-176 Kaitlyn Barcelona Hilcorp Alaska, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 564-4389 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 564-4422 Received By: Date: Date: 07/11/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL Well API # PTD # Log Date Log Company Log Type Notes BCU 18RD 50133205840100 222033 6/11/2022 Yellowjacket GPT-PERF + Report BCU 18RD 50133205840100 222033 6/18/2022 Yellowjacket GPT-PERF + Report BCU 18RD 50133205840100 222033 6/7/2022 Yellowjacket GPT-PLUG + Report BCU 24 50133206390000 214112 6/16/2022 Halliburton PPROF BCU 24 50133206390000 214112 5/23/2022 Yellowjacket GPT-PERF + Report BCU 24 50133206390000 214112 5/26/2022 Yellowjacket GPT-PERF + Report BCU 7A 50133202840100 214060 6/21/2022 Yellowjacket CBL BCU 7A 50133202840100 214060 6/15/2022 Yellowjacket GAMMA RAY + Report BRU 232-26 50283200770000 184138 5/25/2022 Yellowjacket CBL CLU 01RD 50133203230100 203129 5/19/2022 Yellowjacket PERF + Report CLU 01RD 50133203230100 203129 5/24/2022 Yellowjacket PERF + Report CLU 09 50133205440000 204161 5/27/2022 Yellowjacket PERF + Report CLU-1RD 50133203230100 203129 5/28/2022 Halliburton PPROF + Report END 1-17A 50029221000100 196199 5/26/2022 Halliburton LDL END 1-45 50029219910000 189124 5/23/2022 Halliburton LDL + Report END 3-17F 50029219460600 203216 6/15/2022 AK E-Line PLUG CUT FALLS CREEK 3 50133205240000 203102 6/4/2022 Yellowjacket PERF + Report HVB B-16 50231200400000 212133 6/14/2022 AK E-Line CIBP KALOTSA 1 50133206570000 216132 7/7/2022 Yellowjacket PERF + Report KBU 11-07 50133205560000 205165 6/16/2022 Yellowjacket GPT-PERF + Report KBU 11-07 50133205560000 205165 6/20/2022 Yellowjacket GPT-PERF + Report KBU 33-06X 50133205290000 203183 6/22/2022 Yellowjacket CBL MPU B-28 50029235660000 216027 5/27/2022 Halliburton LDL MPU B-28 50029235660000 216027 5/27/2022 Halliburton MFC + Report MPU B-30 50029235710000 216153 5/18/2022 Halliburton PERF MPU E-06 50029221540000 191048 5/28/2022 Halliburton MFC + Report Kaitlyn Barcelona Hilcorp Alaska, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 564-4389 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 564-4422 Received By: Date: MPU E-35 50029236150000 218152 6/15/2022 Halliburton MFC + Report MPU L-50 50029235550000 215132 6/24/2022 Read COIL FLAG PAXTON 10 50133206910000 220064 5/27/2022 Halliburton PPROF + Report PBU C-24B 50029208160200 212063 5/28/2022 Halliburton PPROF + Report PBU C-24B 50029208160200 212063 5/28/2022 Halliburton RBT PBU GNI-03 50029228200000 197189 6/25/2022 Read CALIPER PBU GNI-03 50029228200000 197189 6/25/2022 Read TEMP-PRESS PBU K-01 50029209980000 183121 6/21/2022 Halliburton PPROF + Report PBU M-13A 50029205220100 201165 5/27/2022 Halliburton TMD3D-WFL + Report PBU NGI-05 50029201960000 176014 6/7/2022 Halliburton CAST PBU W-01A 50029218660100 203176 6/8/2022 Halliburton RBT SRU 241-33 50133206630000 217047 6/13/2022 Yellowjacket PERF SRU 241-33B 50133206960000 221053 5/25/2022 Halliburton TEMP-PRESS SRU 32A-33 50133101640100 191014 6/11/2022 AK E-Line PPROF Please include current contact information if different from above. BCU 18RD PTD:222-033 T36747 BCU 24 PTD:214-112 T36748 BCU 7A PTD:214-060 T36749 BRU 232-26 PTD:184-138 T36750 CLU 01RD PTD:203-129 T36751 CLU 09 PTD: 204-161 T36752 CLU1RD PTD:203-129 T36751 END 1-17A PTD:196-199 T36753 END 1-45 PTD:189-124 T36754 END 3-17F PTD:203-216 T36755 Falls Creek 3 PTD:203-102 T36756 HVB B-16 PTD:212-133 T36757 Kalosta 1 PTD:216-132 T36758 KBU 11-7 PTD:205-165 T36759 KBU 33-06X PTD:203-183 T36760 MPU B-28 PTD:216-027 T36761 MPU B-30 PTD:216-153 T36762 MPU E-06 PTD: 191-048 T36763 MPU E-35 PTD:218-152 T36764 MPU L-50 PTD:215-132 T36765 Paxton 10 PTD:220-064 T36766 PBU C-24B PTD:212-063 T36767 PBU GNI-03 PTD:197-189 T36768 PBU K-01 PTD:183-121 T36769 PBU M-13A PTD:201-165 T36770 PBU NGI-05 PTD:176-014 T36771 PBU W-01A PTD:203-176 T36772 SRU 241-33 PTD:217-047 T36773 SRU 241-33B PTD:221-053 T36774 SRU 32A-33 PTD: 191-014 T36775 Kayla Junke Digitally signed by Kayla Junke Date: 2022.07.12 12:56:51 -08'00' MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Thursday, July 21, 2022 SUBJECT:Mechanical Integrity Tests TO: FROM:Lou Laubenstein P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL Hilcorp North Slope, LLC W-01A PRUDHOE BAY UNIT W-01A Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 07/21/2022 W-01A 50-029-21866-01-00 203-176-0 W SPT 4908 2031760 2750 1086 1086 1083 1083 158 272 280 281 INITAL P Lou Laubenstein 6/28/2022 Initial MIT-IA post Rig work over to 2750 psi per Sundry 321-394 after converrsion to an Injection well. 30 MinPretestInitial15 Min Well Name Type Test Notes: Interval P/F Well Permit Number: Type Inj TVD PTD Test psi API Well Number Inspector Name:PRUDHOE BAY UNIT W-01A Inspection Date: Tubing OA Packer Depth 529 3057 2947 2928IA 45 Min 60 Min Rel Insp Num: Insp Num:mitLOL220628144401 BBL Pumped:3.8 BBL Returned:3.8 Thursday, July 21, 2022 Page 1 of 1          7. Property Designation (Lease Number): 1. Operations Performed: 2. Operator Name: 3. Address: 4. Well Class Before Work:5. Permit to Drill Number: 6. API Number: 8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s): Abandon Suspend Plug for Redrill Perforate New Pool Perforate Plug Perforations Re-enter Susp Well Other Stimulate Fracture Stimulate Alter Casing Pull Tubing Repair Well Other: Change Approved Program Operations shutdown 11. Present Well Condition Summary: Casing Length Size MD TVD Burst Collapse Exploratory Stratigraphic Development Service 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 16. Well Status after work: 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. OIL GAS WINJ WAG GINJ WDSPL GSTOR Suspended SPLUG Authorized Name and Digital Signature with Date: Authorized Title: Contact Name: Contact Email: Contact Phone: PBU W-01A Convert to Polaris Injection Hilcorp North Slope, LLC 3800 Centerpoint Dr, Suite 1400, Anchorage, AK 99503 203-176 50-029-21866-01-00 13135 Conductor Surface Intermediate Liner Liner 8936 80 2903 11998 333 618 11608 20" 13-3/8" 9-5/8" 5-1/2" 2-3/8" 8392 30 - 110 30 - 2933 29 - 12027 11810 - 12143 11762 - 12380 30 - 110 30 - 2683 29 - 8706 8541 - 8797 8506 - 8936 11734 2670 4760 6820 11780 11608 4930 6870 7740 11200 6588 - 13135 4-1/2" 12.6#, 3-1/2" 9.2# L80, 13cr80 / L80 27 - 11798 4995 - 8936 Structural 3-1/2" HES TNT Packer 11509, 8319 Stan Golis Sr. Area Operations Manager Wyatt Rivard wrivard@hilcorp.com 907.777.8547 PRUDHOE BAY, POLARIS OIL Total Depth Effective Depth measured true vertical feet feet feet feet measured true vertical measured measured feet feet feet feet measured true vertical Plugs Junk Packer Measured depth True Vertical depth feet feet Perforation depth Tubing (size, grade, measured and true vertical depth) Packers and SSSV (type, measured and true vertical depth) 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final 13.Representative Daily Average Production or Injection Data Oil -Bbl Gas-Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: Subsequent to operation: 15. Well Class after work: Exploratory Development Service StratigraphicDaily Report of Well Operations Copies of Logs and Surveys Run Electronic Fracture Stimulation Data Sundry Number or N/A if C.O. Exempt: ADL 0028263, 0047451 3-1/2" Otis Packer 27 - 8532 11688, 8451 N/A N/A 87 244 410 422 1528 450 261 1703 321-394 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS Sr Pet Eng: Sr Pet Geo: Form 10-404 Revised 10/2021 Submit Within 30 days or Operations Sr Res Eng: No SSSV Installed 4-1/2" HES TNT Packers 6424, 4901 / 6683, 5050 / 6794, 5114 / 7062, 5268 / 11280, 8149 6424, 6683, 6794, 7062, 11280, 11509, 11688 4901, 5050, 5114, 5268, 8149, 8319, 8451 By Meredith Guhl at 1:58 pm, Jul 18, 2022 Digitally signed by Stan Golis (880) DN: cn=Stan Golis (880), ou=Users Date: 2022.07.18 13:23:06 -08'00' Stan Golis (880) MGR07SEP2022 ACTIVITY DATE SUMMARY 4/24/2022 ***WELL S/I ON ARRIVAL***(pre-rwo) DRIFTED/BRUSHED TBG TO 11,625' SLM W/ 3-1/2" BRUSH & 2.80" GAUGE RING. SET 3-1/2" PX-PLUG W/ FILL EXT IN X-NIPPLE @ 11,608' MD. SET WCS (wcs-34) @ 11,596 SLM. PULL ST# 1 @ 11,343 MD. PULL ST# 2 @ 10,802 MD. ***CONTINUE WSR ON 4-25-22*** 4/24/2022 T/I/O = 1680/500/0. Temp = SI. IA FL ( SL Request ). AL SI @ CV. IA FL @ 7945' (Sta #6, DMY). SL in control of well upon departure. 4/25/2022 ***CONT'D. WSR FROM 4-24-22***(pre-rwo) PULLED RK-LGLVS FROM ST#3 @ 10,103' MD, ST#5 @ 8705' MD, ST#7 @ 6242' MD & ST#8 @ 3690' MD. SET RK-DGLVS IN ST#2 @ 10,802' MD, ST#3 @ 10,103' MD, ST#5 @ 8705' MD, ST#7 @ 6242' MD & ST#8 @ 3690' MD. PULLED 3-1/2" WHIDDON CATCHER SUB FROM 11,596' SLM.(small piece of metal inside) LRS CIRC OUT WELL TO 8.4ppg BRINE (see lrs log) ***CONT WSR ON 4/26/22*** 4/25/2022 T/I/O= 290/692/64 Circ out (Pre RWO) Pump 1110 bbls 2% Kcl down IA taking returns up tbg down FL. Pressuer TxIA to 2750 with 46.5 bbls DSL ***Job continued to 04-26-22*** 4/26/2022 ***CONT'D. WSR FROM 4-25-22*** (rwo) LRS ATTEMPTED TO CMIT-TxIA TO 2500psi (see lrs log) ***LRS LEFT IN CONTROL OF WELL UPON DEPARTURE, PAD OP NOTIFIED OF WELL STATUS*** 4/26/2022 T/I/O = 30/110/0. Temp = SI. IA FL (Slickline request). ALP = 150 psi, SI @ CV. IA FL @ 1020' (63 bbls). SV, WV = C. SSV, MV = O. IA, OA = OTG. 23:59 4/26/2022 *** job continued from 04-25-22*** CMIT TxIA to 2500psi (max applied 2750) Test inconclusive, need to let fluids stablize, and return later. Pump 191 bbls DSL down IA for FP. U-Tube to TBG for 1 HR. FP FL w/ 3 bbls 60/40. Final WHP's1334/1334/Vac Pad Op notified on departure. 4/26/2022 Initial T/I/O= 1200/1600/100 Bleed tbg & IA called off job for a hot truck. AL casing valve leaking. Final WHP's 0/150/100 Pad op notified 4/27/2022 T/I/O= 75/110/0. Pre rig CMIT's. Pumped 2bbls 60/40 down IA followed by 77 bbls DSL down IA Pumped 6 bbls DSL down TBG *** CMIT TXIA Pass*** TBG 2745 psi and IA 2740 psi max aplied 2750 target 2500 Pumped 1 bbl DSL to reach test pressure 1st 15 min TBG lost 5 PSI and IA lost 5 PSI 2nd 15 min TBG lost 0 psi and IA lost 0 psi for total loss of 5 psi TBG and 5 psi IA Notified WSL and bled back to 500 psi Tags hung and DSO notified of well status upon departure 5/5/2022 ***WELL S/I ON ARRIVAL*** AKE LINE 9/32" LINE RIH W/ MCR RCT CUT 3.5" TUBING AT 11438' WITH RCT-2000-1000 TORCH CCL TO TORCH=12.3' Daily Report of Well Operations PBU W-01A 2bbls 60/40 down IA followed by 77 bbls TBG *** CMIT TXIA Pass*** TBG 2745 Daily Report of Well Operations PBU W-01A 5/8/2022 T/I/O= 60/65/5. Temp = SI. CMIT-TxIA **PASSED to 970/974** psi w/ DSL (pre rig). Max applied 1000 psi, target 900 psi. Well is disconnected from the system. T & IA FL @ surface. Pumped 3.5 bbls DSL to pressure T & IA from 60/65 psi to 1000/1005 psi. T & IA lost 22/19 psi in 1st 15 min, & 8/7 psi in the 2nd 15 min for a total loss of 30/26 psi in 30 min. Bled T & IA from 970/974 psi to 46/54 in 10 min (3.5 bbls). No change in OAP during CMIT. Tag hung. Final WHPs = 46/54/5. SV, WV, SSV = C. MV = O. IA, OA = OTG. 14:30 6/5/2022 Pump open SSV, terminate tech wire. bleed pressure off of tree, set 4" HCTSBPV. Assist N/D tree. clean void, remove DX seal. inspect TBG HGR lift threads. Install CTS plug. Install test sub and test CTS to 500/5000 psi. good test. bleed off pressure and R/D test equipment. Function LDS, 4 1/4" OUT. All LDS fuction good. Install new BX 160, N/U BOP. 6/5/2022 TB-1 Job Scope: Pull TBG/Cut pull tubing- TBG/Run New Completion. ND tree. NU BOP's. Spot rig mats/base beam. MIRU - spot rig mats and supporting equipment. ...Continue WSR on 6/6/2022... 6/6/2022 TB-1 Job Scope: Pull TBG/Cut pull tubing- TBG/Run New Completion. Continue from 6/5/22. Continue to MIRU - spot supporting equipment. BOPE Test to 250 psi low and 3,000 psi high. Test Annular to 250 psi low and 2,500 psi high. Test with 2- 7/8" and 4-1/2" Test Joints. AOGCC notification given on 6/5/22 at 18:00 hrs and witness was waived by Matt Herrera. ...Continue WSR on 6/7/2022... 6/7/2022 S/B for completion of BOP test. Pull CTS plug, pull HCTSBPV. S/B for circulate. M/U LJ XO into TBG HGR. only getting 6 turns on 4 1/2" TCII lift threads. pull LJ clean and inspect XO threads. re-lube threads RIH still only 6 turns. New landing joint on location. RIH and M/U to TBG HGR w/ full turns. BOLDS. Attempt to pull TBG HGR to floor. Bad TBG cut. S/B while rig works string. Pull TBG HGR to floor, terminate (1) 1/4" tech wire. Lay down TBG HGR. 6/7/2022 TB-1 Job Scope: Pull TBG/Cut pull tubing- TBG/Run New Completion. Continue from 6/6/22. Continue to test BOPE. Pull CTS/BPV. Rock out 38 bbls diesel from Tbg w/ 59 bbls 1% KCl. Pump down Tbg, CBU. BOLDS. Attempt to pull Hanger. Hanger comes free at 75k-lbs. Pick up to 150k-lbs (45k-lbs over string weight). Work pipe up and down for 60 minutes. P/U to 170k-lbs (11' of stretch) and work pipe for 30 minutes. Call for E-Line while continuing to work pipe. Tubing comes free. POH w/ 3-1/2" 9.3# Vam Top completion while spooling Sapphire Gauge Wire. Putting thread protectors on the Tubing as it is POH. ...Continue WSR on 6/8/2022... 6/8/2022 ***Thunderbird Rig Support***(RBT) Log Radial Bond Log from 10412' to surface. Estimated TOC at 2650'. ***Log Complete*** Daily Report of Well Operations PBU W-01A 6/8/2022 TB-1 Job Scope: Pull TBG/Cut pull tubing- TBG/Run New Completion. Continue from 6/7/22. Continue to pull 3-1/2" tubing. OOH w/ 3-1/2" completion. Tubing cut was high at 11,428'. Tubing Stub looking up consists of a 3.5" 4' cut pup joint, 3.95" collar, and a full 3.5" Joint). Cut is uneven due to having been parted but has no flare or pieces turned in/out. Recovered 176/176 Full Cannon Clamps and 16/16 Half Cannon Clamps. R/U HES Eline. RIH w/ CBL. Toolstring failed at 600'. POH w/ CBL. Replace CBL.RIH w/ CBL to 11,418'. Begin logging up to surface w/ CBL at 50 fpm. L/D toolstring. Download data and send to engineer. Await AOGCC approval to proceed. R/D E-Line. Prep and start tripping in hole w/Yellow Jacket BHA= 7.99' 2 7/8" pup, 0.98' x-over, 1.74 ' x-over, 1.41' x-over, 3.95' Csg Scraper, 0.60' x 8.00" Tri- cone bit. 85 joints ran in hole at midnight. ...Continue WSR on 6/9/2022... 6/9/2022 TB-1 Job Scope: Pull TBG/Cut pull tubing/Run Csg Scraper/Shoot New Perforations/Run New Completion. ...Continue WSR from 6/8/22.. Continue tripping in hole with 9-5/8" Csg Scraper. Lightly tag 28.4' into Joint #371 (11,424'). Lay Joint #372. R/U up circulate. Circulate 805 bbls of 9.0 ppg brine 4.4 BPM at 1000 psi. Trip OOH w/ 9-5/8" Casing Scraper while laying down 2-7/8" workstring. OOH w/Csg Scrapper. ...Continue WSR on6/10/2022... 6/10/2022 ...CONT RIG SUPPORT...(perf/drift) PERFORATE 6588'-6631', 6732'-6777' AND 6822'-6899' USING 3.125", 6 SPF, 60 DEG PHASED HSC LOADED W/ 21 GRAM BASIX CHARGES. RAN #20 JUNK BASKET W/ 8.48" GAUGE RING TO TUBING STUB. LOGGED PASS FROM STUB TO ABOVE PERFS TO ASSIST IN PACKER SPACE OUT. STUB AT 11433.7' ELMD. PERF DATA CAPTURED IN RIG AWGRS. ***JOB COMPLETE*** 6/10/2022 TB-1 Job Scope: Pull TBG/Cut pull tubing/Run Csg Scraper/Shoot New Perforations/Run New Completion. ...Continue WSR from 6/9/22.. OOH w/ 9-5/8" Csg Scraper. NU Shooting flange and RU HES eline. PT Shooting flange and HES PCE to 2000 psi MU 3-1/8" perforating guns. RIH w/four perf guns total length 77' and perforated the OBd: 6822'-6899' , sent tie-in to Wyatt Rivard and Kevin Eastman. RIH w/ 3-1/8" guns to zone #2: OBc: 6,732' - 6,777' and perforate. RIH w/ 3- 1/8" guns to zone #3: OBa: 6,588' - 6,631' and perforate. M/U 8.5" Gauge Ring and Junk Basket. RIH and tag top of Tubing Stub. Log from Tubing Stub to past upper perforations to 6,500'. POH from 6,500'. RD E-Line. R/U to run 4-1/2" completion. R/U Torque Turn Equipment. Spot pipe racks. Lay out completion components. Send draft completino tally to OE Wyatt Rivard to confirm. Minor change to tally and appoved. Start running new 4 1/2" 12.6# L-80 VAMTOP completion using TB Torque Turn Services. ...Continue WSR on 6/11/2022... 6/10/2022 ***THUNDERBIRD RIG SUPPORT***(perforate) STANDBY FOR RIG ...CONT ON 10-JUN-2022 WSR... ...CONT RIG SUPPORT...(perf/drift) PERFORATE 6588'-6631', 6732'-6777' AND 6822'-6899' RIH w/ CBL. Toolstring failed at 600'. POH w/ CBL. RIH w/ CBL. Toolstring fail Replace CBL.RIH w/ CBL to 11,418'. Begin logging up to surface w/ CBL at 50 fpm. Replace CBL.RIH w/ CBL to 11,418'. Begin logging up to surface w/ CBL at 50 fpm. L/D toolstring. Download data and send to engineer. Await AOGCC approval to L/D toolstring. Download da proceed. R/D E-Line. Prep an Daily Report of Well Operations PBU W-01A 6/11/2022 TB-1 Job Scope: Pull TBG/Cut pull tubing/Run Csg Scraper/Shoot New Perforations/Run New Completion. ...Continue WSR from 6/10/22... Continue running 4 1/2" 12.6# L-80 VAMTOP using TB Torque Turn Service. Having issues with heavy thick crude coming up TBG as compeltion is being ran. Stop and circulated 16 bbls of 9.0 ppg brine full circulation @ 2.5 BPM 80 psi. Shut down and monitor well for 15 mins no flow, continue in hole with completion slowly, PKR is acting like a plunger pushing fluid up new completion. Stopped at 1167' circulate 80 bbls of 9.0 ppg brine full circulation @ 2.7 BPM 150 psi. Shut down and monitor well for 15 mins no flow, Continue in hole with completion slowly, Seen fluid level drop stop at 4419' circulated 305 bbls of 9.0 ppg brine full circulation @ 3.1 BPM 230 psi. Shut down and monitor well for 15 mins no flow, continue in hole with completion,. Continue running new completion. Continue WSR on ...6/1/2/2022... 6/12/2022 TB-1 Job Scope: Pull TBG/Cut pull tubing/Run Csg Scraper/Shoot New Perforations/Run New Completion. ...Continue WSR from 6/10/22... Continued running 4 ½¿ 12.6# L-80 Multi Zonal Isolation completion. Stopped running completion at planned depth of 6545' just short of new Schrader perforations. Circ in 450 bbls of new clean 9.0 ppg Brine before continuing to run 4 1/2" 12.6# L-80 TBG. RIH slowly on Joint #146 and #147 (Slight over pull in area post perf with 6.48" drift) Just above tubing stub get up/down weights, 123k / 84k. At target setting depth but did not see shear screws while overshoting 3 ½¿ tubbing stub. We should have seen first seen screws at 10.8¿ on Joint #258 continued down to 18.8¿ looking for second set of shear screws. No indication continued down to No-Go¿ no indication. Picked up above 3 ½¿ tubing stub and started pumping establishing a rate of 3.25 bpm @ 300 psi Slowly moved completion down looking for pressure indication we were over 3 ½¿ tubing stub. Worked completion up/down several times with no definitive indication (Pressure or weight drop) The 3 ½¿ Tubing stub is 4.09¿ to the collar. Continued down while holding pump rate constant looking for 3 ½¿ collar to hit No-Go should have seen it at 25.87¿ on joint #258. Continued down tell elevators were at top of tubing slips on rig floor. 37¿ which put us 11.13¿ past 3 ½¿ collar. No pump pressure or weight indication we were over it. PU and called OE Wyatt Rivard discuss plan forward. Drop deployment joint #258, MU pup and TBG hanger. Set TBG hanger RILDS and pressure test hanger. Prep for eline to log with GAMA/CCL ...Continue WSR on 6/13/2022.... 6/13/2022 RWO, Drain Bop through IA valve, land tbg hgr with H TWC installed, Run in LDS evenly to correct measurement of 3-1/2in.. Verify landing visually from Rig floor. Back out landing joint, close blind rams and test TWC and tubing hanger packing to 1500 psi, good test. (could not see verification mark on tubing hanger pup it is covered with crude). Check out with rig manager RDMO. 6/14/22. Set New TWC 6 RH turns approx 50 ft lbs torque. Daily Report of Well Operations PBU W-01A 6/13/2022 TB-1 Job Scope: Pull TBG/Run Csg Scraper/Shoot New Perforations/Run New Completion. ...Continue WSR from 6/12/2022... Continued attempts in depth control with overshot. No luck. Called Eline out to run GAMA/CCL to help find if Multi Zone PKR system was at correct setting depth. RIH/ GAMA/CCL and tag RHC in lower most X-Nipple of the completion. Log up and Tie into HES CBL 6/9/22. Evaluate log and confer with town engineer. Good to proceed with setting packers. Circulate 220 bbls of 9.0 ppg brine with Corrossion Inhibitor (0.55 gal/bbl Concor 303A) at 4 BPM at 450 psi. Circulate 29.5bbls of 9.0 ppg brine at 4 BPM at 450 psi. Circulate 238 bbls of 9.0 ppg brine with Corrossion Inhibitor (0.55 gal/bbl Concor 303A) at 4 BPM at 450 psi. Circulate 238 bbls of 9.0 ppg brine with Corrossion Inhibitor (0.55 gal/bbl Concor 303A) at 4 BPM at 450 psi. Circulate 67.5 bbls of 9.0 ppg brine at 4 BPM at 450 psi. Shut down pump. Monitor well. No flow. MU Landing Jt and drop Rod & Ball (1.375" FN 6.625' w/ 1.875" ball).and attempted to set PKR assemblies. Multiple pump rates trying to push Rod & Ball down hole. No indication that ball had landed. Call Slickline out and drift TBG w/Bell Guide with pulling tool. Found Rod & Ball in Water Floor Regulator Mandrel #2 @ 6850' SLM, Latched up and continued in hole to RHCM. SD in RHCM having Slickline stay in hole should there be issues with ball seating. ...Continue WRS on 6/14/2022... 6/13/2022 ***T-BIRD RIG JOB*** W/ 2" RB IN 3.60" BELL GUIDE, FOUND BALL & ROD IN STA# 2 @ 6836' SLM. FLIPPED PAST STA# 2 AND RAN BALL & ROD TO RHC PLUG BODY @ 11,352' SLM. T-BIRD RIG TO TEST TBG. ***WSR CONTINUED ON 6-14-22*** 6/14/2022 T/I/O=TWC/0/0. RD BOP's. RU THA & 4 1/6" tree torque to API specs. PT'd Tree X TWC 300 psi low and 5000 psi high (PASSED). Pulled TWC. RD luricator. RU Tree cap PT'd to 500 psi (PASSED). FWP=Vac/0/0. JOB COMPLETE 6/14/2022 Assist N/D BOP, remove TBG HGR neck protector, inspect TBG HGR neck, lift threads and HTWC. Install new DX seal and BX160. N/U THA and tree. Fill void w/ test oil. R/U test equipment and test void to 5M for 30 min. -150 after first 15 min. - 50 in final 15 min. R/D test equipment and bleed off pressure. W.S. to test tree and lubricate out HTWC. 6/14/2022 Freeze Protect TBG and IA post RWO. TFS U3 ***Job Postponed unitll SL availability*** 6/14/2022 ***CONTINUED FROM 6-13-22*** T-BIRD RIG TESTED TBG. PULLED BALL & ROD FROM RHC PLUG BODY @ 11,352' SLM. ***RIG HAS CONTROL OF WELL UPON DEPARTURE*** 6/14/2022 TB-1 Job Scope: Pull TBG/Run Csg Scraper/Shoot New Perforations/Run New Completion. ... Continue WSR from 6/13/2022... Rod & Ball on seat with Slickline assiting. Pressured up 3500 psi on TBG and set five 9-5/8" x 4 1/2" HES TNT PKRS. MIT-TBG to 3,000 psi and MIT-IA to 3000 psi for 30 charted mins. Bleed TBG down and shear DRC valve in GLM #1. Bleed well to zero. Have Slickline POOH w/Rod & Ball and rig down. Rod & Ball recovered! RD Slickline. Set TWC and Rig Down. Note: Well has not been freeze protected. ***Job Complete*** Daily Report of Well Operations PBU W-01A 6/15/2022 ***WELL SI ON ARRIVAL*** STBY ON WELL SUPPORT TO INSTALL WELL HOUSE, RIH W/ 4 1/2" GS TROUBLE LATCHING @ 11,352' SLM (LOST WEIGHT @ 2411' SLM) ***CONTINUE 6/16/22*** 6/16/2022 T/I/O= 0/0/0. LRS 70 Assist SL as directed (RWO EXPENSE). Pumped 133 bbls of diesel to freeze protect the IA. Pump 50 bbls of diesel into the TBG for FP and injectivity test (1.8 bpm at 1725 psi). S/L set plug. Pumped 19.3 bbls to pressure the TxIA to 2000 psi. WSR continued to 06-17-22*** 6/16/2022 ***CONTINUED FROM 6/15/22*** PULLED 4 1/2" RHC @ 11353' MD DRIFT W/ 2.80" CENT. 2 1/2" JDC TO 11587' SLM (tight in overshot @ 11415' SLM) MADE SEVERAL RUNS w/ 2 1/2" BAILER, RECOVERED 4 GAL. SCHMOO & SMALL METAL PIECES TO TOP OF PX PLUG @ 11,608' MD PULLED 3-1/2" PX PLUG FROM X-NIPPLE @ 11,608' MD RAN 3-1/2" BRUSH w/ 2.25" CENT WHILE LRS FREEZE PROTECTED IA w/ 133 bbls DIESEL LRS PUMPED 50 bbls DIESEL DOWN TBG @ 1.8 bpm @ 1,725 psi SET 3 1/2" XX PLUG @ 11,608' MD LRS TESTED PLUG TO 2000 psi, GOOD TEST SET 4 1/2" SLIP STOP CATCHER @ 2,624' SLM PULL STA. # 1 RKP DCR VALVE @ 2,425' MD SET STA. # 1 RK DGLV @ 2,425' MD (PULL - RUN SHEET DOESN'T MATCH SCHEMATIC)** ***CONTINUED 6/17/22*** 6/17/2022 ***CONTINUED FROM 6/16/22*** PULL SLIP STOP CATCHER SUB @ 2,624' SLM FAILED MIT-T PASSING MIT-IA (see log) EQUALIZE & PULL XX PLUG FROM X-NIPPLE @ 11,608' MD SET 3-1/2" PX PLUG IN X-NIPPLE @ 11,608' MD LRS PERFORMED PASSING MIT-T --JOB INCOMPLETE, WILL RETURNS AFTER STATE WITNESSED MIT'S- ***WELL S/I ON DEPARTURE, PAD OP NOTIFIED*** 6/17/2022 ***WSR continued from 06-16-22***MIT IA to 3000 PSI (PASSED) Pressured IA to 3200 psi with 4.5 bbls DSL. IA lost 99 psi in 1st 15 min and 33 psi in 2nd 15 min for a total loss od 132 psi in 30 min test. MIT T to 3000 psi. (PASSED ) Lost 161 psi. 1st 15 min and 65 psi 2nd 15 min. Pressured up with 2.19 bbls and bled back 2.1 bbls to initial pressures. SL on well at time of departure. 6/19/2022 ** MIT T MIT IA ** State witnessed by Adam Earl. MIT T ( PASSED ) MIT IA ( PASSED ) T/I/O= 209/386/15 Pumped 2.1 bbls diesel down TBG to test pressure of 3296 psi. Lost 169 psi 1st 15 min Lost 52 psi. 2nd 15 min. Pressured up IA to 3300 psi. Lost 65 psi in 1st 15 min and 19 psi in 2nd 15 min. Bled pressures to starting pressures. FWHP's = 210/389/15 Tags hung on MV and IA valve. DSO notified of test results. 6/19/2022 ***WELL S/I ON ARRIVAL*** valve-wfr SET X-CATCHER @ 7,033' MD ***CONTINUE 6/20/22 PASSING MIT-IA (see log) ***WSR continued from 06-16-22***MIT IA to 3000 PSI (PASSED Daily Report of Well Operations PBU W-01A 6/19/2022 T/I/O= 400/400/0 TFS Unit #4 Assist SL (WFR Change out) Spot equipment, Rig up. SB for SL. ***Job continued on 06/20/2022*** 6/20/2022 ***CONTINUE FROM 6/19/22*** PULL RK-DGLV FROM ST#5 @ 6,604' MD (350 psi on tbg) SET RK-AL-WFR IN ST#5 @ 6,604' MD PULL RK-DGLV FROM ST#3 @ 6,764' MD (700 psi on tbg) SET RK-MAX FLOW WFR IN ST#3 @ 6,764' MD PULL RK-DGLV FROM ST#1 @ 6,914' MD (900 psi on tbg) SET RK-MAX FLOW WFR IN ST#1 @ 6,914' MD PULLED 4-1/2" X-CATCHER FROM X-NIP @ 7,033' MD ***WELL S/I ON DEPARTURE*** 6/20/2022 ***Job continued from 06/19/2022*** Assist SL (WFR Changeout) Pumped 5 bbls DSL down TBG to Assist SL in doing WFR change out. Maintained TBG pressure throughout job while SL set and pulled valves. SL in control of well upon TFS Departure. Final whps 700/400/0 6/28/2022 T/I/O= 1086/529/158 ***PASSED*** State witness AOGCC MIT IA Target of 2750 PSI, Max Applied pressure of 3050 PSI. Pumped 3.8 BBLS of 100* Diesel down IA to reach test pressure(3057). First 15 min IA lost 110 psi, Second 15 minute IA lost 19 psi. For a total of 129 psi. Passed, Bled back to starting pressure. Got back 3.8 BBLS. FWHP= 1083/529/174 CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Wallace, Chris D (OGC) To:AOGCC Records (CED sponsored) Subject:FW: OPERABLE: Injector W-01A (PTD #2031760) RWO complete Date:Tuesday, June 21, 2022 10:27:40 AM From: PB Wells Integrity <PBWellsIntegrity@hilcorp.com> Sent: Tuesday, June 21, 2022 9:44 AM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Cc: Regg, James B (OGC) <jim.regg@alaska.gov>; Oliver Sternicki <Oliver.Sternicki@hilcorp.com>; PB Wells Integrity <PBWellsIntegrity@hilcorp.com> Subject: OPERABLE: Injector W-01A (PTD #2031760) RWO complete Mr. Wallace, Injector W-01A (PTD # 2031760) RWO has been completed under Sundry #321-394. As part of the Sundry, the well has been converted to a produced water injector. On 06/19/22 Fullbore performed a passing AOGCC witnessed offline MIT-T to 3075 psi and MIT-IA to 3216 psi which proves two competent well barriers. The well will now be classified as OPERABLE. Once the well is on stable injection, an online AOGCC witnessed MIT-IA will be performed. Please respond with any questions. Andy Ogg Hilcorp Alaska LLC Field Well Integrity andrew.ogg@hilcorp.com P: (907) 659-5102 M: (307)399-3816 From: PB Wells Integrity <PBWellsIntegrity@hilcorp.com> Sent: Tuesday, April 26, 2022 10:03 AM To: Brodie Wages <David.Wages@hilcorp.com>; PB EOC Specialists <PBEOCSpecialists@hilcorp.com>; PB Wells Optimization Engineers <PBWellsOptimizationEngineers@hilcorp.com>; PBW GC2 Field Lead Operator <PBWGC2FieldLeadOperator@hilcorp.com>; PBW GC2 Foreman <PBWGC2Foreman@hilcorp.com>; PBW GC2 Wellpad HUQ <PBWGC2WellpadHUQ@hilcorp.com>; PBW GC2 Wellpad LV <PBWGC2WellpadLV@hilcorp.com>; PBW GC2 Wellpad MN <PBWGC2WellpadMN@hilcorp.com>; PBW GC2 Wellpad RJ <PBWGC2WellpadRJ@hilcorp.com>; PBW GC2 Wellpad S <PBWGC2WellpadS@hilcorp.com>; PBW GC2 Wellpad W <PBWGC2WellpadW@hilcorp.com>; PBW GC2 Wellpad Z <PBWGC2WellpadZ@hilcorp.com>; PBW PCC Leads <GC3ProdContCenterLeads@hilcorp.com>; Wyatt Rivard <wrivard@hilcorp.com> Cc: Abbie Barker <Abbie.Barker@hilcorp.com>; Alaska IMS User <akimsuser@hilcorp.com>; Carrie Janowski <Carrie.Janowski@hilcorp.com>; John Condio - (C) <John.Condio@hilcorp.com>; John Menke <jmenke@hilcorp.com>; Kevin Brackett <Kevin.Brackett@hilcorp.com>; Oliver Sternicki <Oliver.Sternicki@hilcorp.com>; PB Wells Integrity <PBWellsIntegrity@hilcorp.com>; Stan Golis <sgolis@hilcorp.com> Subject: NOT OPERABLE: Producer W-01A (PTD #2031760) being prepared for RWO All, Producer W-01A (PTD #2031760) is scheduled for a RWO in 2022. Slickline left an open pocket in GLM #1 in preparation for an upcoming e-line tubing cut. The well will now be classified as NOT OPERABLE until the RWO is complete. Please respond with any questions. Andy Ogg Hilcorp Alaska LLC Field Well Integrity / Compliance andrew.ogg@hilcorp.com P: (907) 659-5102 M: (307)399-3816 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Regg, James B (OGC) To:AOGCC Records (CED sponsored) Subject:FW: OPERABLE: Injector W-01A (PTD #2031760) RWO complete Date:Tuesday, June 21, 2022 9:49:49 AM Jim Regg Supervisor, Inspections AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907-793-1236 From: PB Wells Integrity <PBWellsIntegrity@hilcorp.com> Sent: Tuesday, June 21, 2022 9:44 AM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Cc: Regg, James B (OGC) <jim.regg@alaska.gov>; Oliver Sternicki <Oliver.Sternicki@hilcorp.com>; PB Wells Integrity <PBWellsIntegrity@hilcorp.com> Subject: OPERABLE: Injector W-01A (PTD #2031760) RWO complete Mr. Wallace, Injector W-01A (PTD # 2031760) RWO has been completed under Sundry #321-394. As part of the Sundry, the well has been converted to a produced water injector. On 06/19/22 Fullbore performed a passing AOGCC witnessed offline MIT-T to 3075 psi and MIT-IA to 3216 psi which proves two competent well barriers. The well will now be classified as OPERABLE. Once the well is on stable injection, an online AOGCC witnessed MIT-IA will be performed. Please respond with any questions. Andy Ogg Hilcorp Alaska LLC Field Well Integrity andrew.ogg@hilcorp.com P: (907) 659-5102 M: (307)399-3816 From: PB Wells Integrity <PBWellsIntegrity@hilcorp.com> Sent: Tuesday, April 26, 2022 10:03 AM To: Brodie Wages <David.Wages@hilcorp.com>; PB EOC Specialists <PBEOCSpecialists@hilcorp.com>; PB Wells Optimization Engineers <PBWellsOptimizationEngineers@hilcorp.com>; PBW GC2 Field Lead Operator <PBWGC2FieldLeadOperator@hilcorp.com>; PBW GC2 Foreman <PBWGC2Foreman@hilcorp.com>; PBW GC2 Wellpad HUQ <PBWGC2WellpadHUQ@hilcorp.com>; PBW GC2 Wellpad LV <PBWGC2WellpadLV@hilcorp.com>; PBW GC2 Wellpad MN <PBWGC2WellpadMN@hilcorp.com>; PBW GC2 Wellpad RJ <PBWGC2WellpadRJ@hilcorp.com>; PBW GC2 Wellpad S <PBWGC2WellpadS@hilcorp.com>; PBW GC2 Wellpad W <PBWGC2WellpadW@hilcorp.com>; PBW GC2 Wellpad Z <PBWGC2WellpadZ@hilcorp.com>; PBW PCC Leads <GC3ProdContCenterLeads@hilcorp.com>; Wyatt Rivard <wrivard@hilcorp.com> Cc: Abbie Barker <Abbie.Barker@hilcorp.com>; Alaska IMS User <akimsuser@hilcorp.com>; Carrie Janowski <Carrie.Janowski@hilcorp.com>; John Condio - (C) <John.Condio@hilcorp.com>; John Menke <jmenke@hilcorp.com>; Kevin Brackett <Kevin.Brackett@hilcorp.com>; Oliver Sternicki <Oliver.Sternicki@hilcorp.com>; PB Wells Integrity <PBWellsIntegrity@hilcorp.com>; Stan Golis <sgolis@hilcorp.com> Subject: NOT OPERABLE: Producer W-01A (PTD #2031760) being prepared for RWO All, Producer W-01A (PTD #2031760) is scheduled for a RWO in 2022. Slickline left an open pocket in GLM #1 in preparation for an upcoming e-line tubing cut. The well will now be classified as NOT OPERABLE until the RWO is complete. Please respond with any questions. Andy Ogg Hilcorp Alaska LLC Field Well Integrity / Compliance andrew.ogg@hilcorp.com P: (907) 659-5102 M: (307)399-3816 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Wednesday, July 20, 2022 SUBJECT:Mechanical Integrity Tests TO: FROM:Adam Earl P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL Hilcorp North Slope, LLC W-01A PRUDHOE BAY UNIT W-01A Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 07/20/2022 W-01A 50-029-21866-01-00 203-176-0 N SPT 8451 2031760 3000 209 3296 3127 3075 15 16 16 16 OTHER P Adam Earl 6/19/2022 MIT-T tested as per Sundry 321-394 to max ant. Inj. Psi. 30 MinPretestInitial15 Min Well Name Type Test Notes: Interval P/F Well Permit Number: Type Inj TVD PTD Test psi API Well Number Inspector Name:PRUDHOE BAY UNIT W-01A Inspection Date: Tubing OA Packer Depth 386 508 519 519IA 45 Min 60 Min Rel Insp Num: Insp Num:mitAGE220622083958 BBL Pumped:2.1 BBL Returned:2.1 Wednesday, July 20, 2022 Page 1 of 1          MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Thursday, July 21, 2022 SUBJECT:Mechanical Integrity Tests TO: FROM:Adam Earl P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL Hilcorp North Slope, LLC W-01A PRUDHOE BAY UNIT W-01A Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 07/21/2022 W-01A 50-029-21866-01-00 203-176-0 N SPT 8451 2031760 3000 1020 1250 2177 1281 17 21 22 22 OTHER P Adam Earl 6/19/2022 MIT-IA tested as per Sundry 321-394 to max ant. Inj. Psi 30 MinPretestInitial15 Min Well Name Type Test Notes: Interval P/F Well Permit Number: Type Inj TVD PTD Test psi API Well Number Inspector Name:PRUDHOE BAY UNIT W-01A Inspection Date: Tubing OA Packer Depth 644 3300 3235 3216IA 45 Min 60 Min Rel Insp Num: Insp Num:mitAGE220622084644 BBL Pumped:3.7 BBL Returned:3.7 Thursday, July 21, 2022 Page 1 of 1          5HJJ-DPHV%2*& )URP5HJJ-DPHV%2*& 6HQW7XHVGD\-XQH$0 7R1LFN)UD]LHU&%URRNV3KRHEH/2*& 6XEMHFW5(+LOFRUS7KXQGHUELUG $WWDFKPHQWV%23+LOFRUS7KXQGHUELUGUHYLVHG[OV[ /ĐŚĂŶŐĞĚηϮZĂŵ;sZͿƚŽ͞W͟ĂŶĚDŝƐĐƚŽϭ͕&W͖ƐĞĞĂƚƚĂĐŚĞĚ͘ :ŝŵZĞŐŐ ^ƵƉĞƌǀŝƐŽƌ͕/ŶƐƉĞĐƚŝŽŶƐ K' ϯϯϯt͘ϳƚŚǀĞ͕^ƵŝƚĞϭϬϬ ŶĐŚŽƌĂŐĞ͕<ϵϵϱϬϭ ϵϬϳͲϳϵϯͲϭϮϯϲ &ƌŽŵ͗EŝĐŬ&ƌĂǌŝĞƌͲ;ͿфŶĨƌĂǌŝĞƌΛŚŝůĐŽƌƉ͘ĐŽŵх ^ĞŶƚ͗dƵĞƐĚĂǇ͕:ƵŶĞϳ͕ϮϬϮϮϮ͗ϭϮWD dŽ͗ZĞŐŐ͕:ĂŵĞƐ;K'Ϳфũŝŵ͘ƌĞŐŐΛĂůĂƐŬĂ͘ŐŽǀх͖KK'WƌƵĚŚŽĞĂǇфĚŽĂ͘ĂŽŐĐĐ͘ƉƌƵĚŚŽĞ͘ďĂǇΛĂůĂƐŬĂ͘ŐŽǀх͖ ƌŽŽŬƐ͕WŚŽĞďĞ>;K'ͿфƉŚŽĞďĞ͘ďƌŽŽŬƐΛĂůĂƐŬĂ͘ŐŽǀх ^ƵďũĞĐƚ͗,ŝůĐŽƌƉdŚƵŶĚĞƌďŝƌĚϭϲͲϳͲϮϬϮϮ WůĞĂƐĞĨŝŶĚĂƚƚĂĐŚĞĚƚŚĞKWdĞƐƚ&ŽƌŵĨŽƌ,ŝůĐŽƌƉdŚƵŶĚĞƌďŝƌĚϭ͘WůĞĂƐĞůĞƚŵĞŬŶŽǁŝĨǇŽƵŚĂǀĞĂŶǇƋƵĞƐƚŝŽŶƐ͘ dŚĂŶŬƐ͕ EŝĐŬ&ƌĂǌŝĞƌ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ll BOPE reports are due to the agency within 5 days of testing* SSu b m i tt t o :jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov Owner/Contractor: Rig No.:Thunderbird 1 DATE: 6/7/22 Rig Rep.: Rig Phone: 307-321-6563 Operator: Op. Phone:907-444-7218 Rep.: E-Mail Well Name: PTD #22031760 Sundry #321-394 Operation: Drilling: Workover: x Explor.: Test: Initial: x Weekly: Bi-Weekly: Other: Rams:250/3000 Annular:250/3000 Valves:250/3000 MASP:2232 MISC. INSPECTIONS: TEST DATA FLOOR SAFETY VALVES: Test Result Test Result Quantity Test Result Location Gen.P Well Sign P Upper Kelly 0NA Housekeeping P Rig P Lower Kelly 0NA PTD On Location P Hazard Sec.P Ball Type 1P Standing Order Posted P Misc.NA Inside BOP 1P FSV Misc 0NA BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm Stripper 0NATrip Tank PP Annular Preventer 1 13 5/8" x 5M P Pit Level Indicators PP #1 Rams 1 2 7/8" x 5" vbr P Flow Indicator PP #2 Rams 1 Blinds P Meth Gas Detector PP #3 Rams 0NAH2S Gas Detector PP #4 Rams 0NAMS Misc 0NA #5 Rams 0NA #6 Rams 0NA Quantity Test Result Choke Ln. Valves 1 3 1/8"P Inside Reel valves 0NA HCR Valves 1 3 1/8"P Kill Line Valves 3 3 1/8"P Check Valve 0NAACCUMULATOR SYSTEM: BOP Misc 0 NA Time/Pressure Test Result System Pressure (psi)3000 P CHOKE MANIFOLD:Pressure After Closure (psi)1600 p Quantity Test Result 200 psi Attained (sec)21 p No. Valves 11 FP Full Pressure Attained (sec)113 P Manual Chokes 2P Blind Switch Covers: All stations Yes Hydraulic Chokes 0NA Nitgn. Bottles # & psi (Avg.): 3@2066 P CH Misc 0NA ACC Misc 1FP Test Results Number of Failures:3 Test Time:9.0 Hours Repair or replacement of equipment will be made within days. Remarks: AOGCC Inspection 24 hr Notice Yes Date/Time 6/5/22 18:22 Waived By Test Start Date/Time:6/6/2022 5:00pm (date) (time)Witness Test Finish Date/Time:6/7/2022 2:00am BOPE Test Report Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Matt Herrera Hilcorp Fresh water used to test, 2 7/8" and 4 1/2" test mandrels used to test, C-3 Failed bled off functioned valve re pressured up and passed, 2 7/8 vbr failed bled pressure and swapped 4 way valve and adjusted regulator to 1500psi passed, C-11 failed bled pressure and functioned valve and pressured back up passed Matt Rivera/Will Ragsdale Hilcorp Nick Frazier/Matt Ross PBU W-01A Test Pressure (psi): pbrwowss@hilcorp.com Form 10-424 (Revised 02/2022) 2022-0607_BOP_Hilcorp_Thunderbird1_PBU_W-01A 9 9 9 9 9999 9 9 9 9 9 9 9 9 -5HJJ +LOFRUS1RUWK6ORSH//& +LOFRUS1RUWK6ORSH//&K P FP1 FP C-3 Failed 2 7/8 vbr failed bled pressure and swapped 4 way valve and adjusted regulator to 1500psi C-11 failed CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Rixse, Melvin G (OGC) To:Wyatt Rivard Cc:AOGCC Records (CED sponsored) Subject:20220414 1504 Sundry 321-394 Work Procedure Revision 1 W-01A (PTD#203176) RWO Sundry Increased KWF Date:Thursday, April 14, 2022 3:09:21 PM Attachments:W-01A RWO Sundry 4-13-22 Revision 1.docx Wyatt, Hilcorp is approved to perform well work on well PBU W-01A (PTD 203-176) under Sundry 321- 394 per the procedure Revision 1 (attached) with the revisions discussed below. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-223-3605 Cell 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 Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). From: Wyatt Rivard <wrivard@hilcorp.com> Sent: Thursday, April 14, 2022 7:21 AM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Subject: W-01A (PTD#203176) RWO Sundry Increased KWF Hello Mel, We have an upcoming RWO to convert well W-01A (PTD#203176) to Schrader Bluff Injection under Sundry 321-394 which was approved last summer. Ahead of the upcoming RWO, we reevaluated BHPs for updated kill weights including offsets in the Schrader Bluff sands (these are perforated in step 8 of the RWO procedure). While the Schrader is expected to be under pressured in this under supported area, conservative estimates of BHP are up to 8.4 ppg. For this reason, I would like to update the planned KWF to a 9.0 ppg brine instead of original 8.4 ppg brine. KWF updated below along with a few other minor updates. Revised RWO procedure attached. W-01A RWO Program Updates Updated max expected BHP to 2184 psi (@ 5000’ TVD) based on offset Schrader Bluff Wells. Increase KWF from 8.4 ppg to 9.0 ppg Brine. Include circulating well over to 9.0 ppg KWF in step 5 prior to perforating Schrader Bluff. Removed redundant X-Nip from proposed schematic at 11410’ MD. Increased casing scraper run depth to 11400’ to accommodate lowermost packer set. Added original sundry conditions of approval to procedure including AOGCC MIT-T/MIT-IAs post slickine reset of plug /GLV as well as WFL and Temp log requirements. Please let me know if this change is acceptable. Thank You, Wyatt Rivard | Operations Engineer (PBU: J, Q, R, S, U, W pads)O: (907) 777-8547 | C: (509)670-8001 | wrivard@hilcorp.comHilcorp Alaska, LLC | Anchorage, AK 99503 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. REV # 1 4-13-22 RWO Procedure WELL: W-01A PTD: 203176 Well Name: W-01A API Number: 50029223210500 Current Status: Shut-In Producer Rig: Thunderbird #1 Estimated Start Date: 5/05/2022 Permit to Drill Number: 203176 First Call Engineer: Wyatt Rivard 907-777-8547 (O) 509-670-8001 Second Call Engineer: David Brodie Wages 713-380-9836 M AFE: 212-00553 Current BHP (Ivishak): 3,112 psi @ 8,800’ TVD 7.1 PPGE (+.3 SF) | SBHPG 10/17/2016 Max Anticipated BHP (Schrader Bluff): 2184 psi @ 5,000’ TVD 8.7 PPGE (+.3 SF) | W-205 BHP 9/22/17 Max. Anticipated Surface Pressure: 2,232 psi (Based on 0.1 psi/ft. gas gradient) Last SI WHP: 1,800 psi (Taken on 12/7/21) Min ID: 1.92” ID TOL @ 11,762’ MD Max Angle: 96 Deg @ 12,573’ MD Brief Well Summary: W-01A is a long term shut-in Ivishak producer in an ideal location to support W-205 and W-203 trilaterals in the Oba, Obc, and Obd sands. Volumetric, analog, and simulation analysis indicate recompleting the W-01 to the Oba, Obc, and Obd sands as a PW injector would increase offset producer EUR by ~480 MSTBO. Additionally, the W-01 is in a great location in the Ivishak to support W-8 and U-16. To maximize oil rate and field value it is recommended to convert W-01 into a Schrader-Ivishak PW injector. Injection between the two pools will be controlled via WFRV and a down hole MCX with orifice over the Ivishak to avoid any cross flow to the Schrader during any SI. Injection start up will consist of the Schrader zone only to get a base line injection prior to commingled injection. Once AOGCC approves an amended separate AIO amendment request, commingled injection will commence. Notes Regarding Wellbore Condition: • Ivishak perfs will remain hydraulically isolated by tested TTP at 11,608’ MD until Eline Perfs the upper zones. Objective: Convert to a PW injector. Pull the existing 3 ½” 13CR-80 tubing out of the well and replace with a WFRM completion. Achieve a passing MIT-IA & MIT-T. Variance Request: 20AAC25.412(b) Packer will be set greater than 200ft measured depth from open perfs. Tubing packer is at ~11,337’MD which is 947’ MD above the uppermost open slots at 12,284’ MD. Area of Review – PBU W-01A (PTD # 203-176) Prior to the conversion of well W-01A from Ivishak producer to Ivishak and Schrader Bluff injector, an Area of Review (AOR) has been conducted. This AOR found 4 wells and former wells within ¼ mile of W-01A’s entry point into the Ivishak formation and 6 wells within ¼ mile of W-01A’s entry point into the Schrader Bluff formation. Estimated TOCs were calculated using the daily drilling logs found in the original well files. The calculations are based on the cement volumes pumped with 30% excess in the annular space. W-08 was found to have a calculated TOC below the Schrader Bluff injection zone. See attached table Area of Review W-01A for annulus integrity and zonal isolation of all wells within the AOR. W-08A is within the 1/4 mile radius does not have cement across the Schrader interval when calculated volumetrically with 30% excess. REV # 1 4-13-22 RWO Procedure WELL: W-01A PTD: 203176 Hilcorp requests a variance from 20 AAC 25.402 (b) due to not having adequate cementing data across the confining zone for wells within the ¼ mile radius of an injection well under 20 AAC25.402(h). The assurance that the injection zone is isolated is based on the following: 1. Hilcorp provides monthly TIO plots of W-08A. If out of zone injection occurs alongside the un- cemented portion of the casings on these wells, it may show up in the OA pressure-plots as an anomaly. 2. Hilcorp performs a temperature log and pulsed neutron water flow log in W-08A 1 year after injection commences and all subsequent years. AOR Tables PTD API WELL STATUS Distance Top of Ivishak Log Est. Top of Cement from Volumetric Calculations Annulus Integrity Zonal Isolation 1881070 50-029-21866-00 W-01 P&A'd 60'12276' MD/ 8906' TVD n 6113' MD (4719' TVD) MIT-IA to 3500 psi on 06/02/2010 9-5/8" production casing cemented with 2533 ft^3 class G cement in 12-1/4" hole. Did not bump plug, floats held. Tagged TOC in tubing 188' above float collar. TOC estimated at 6113' MD assuming 30% excess. NA 50-029-21866-70 W-01APB1 P&A'd 0'12312' MD/ 8905' TVD n 6113' MD (4719' TVD) MIT-IA to 3500 psi on 06/02/2010 9-5/8" production casing cemented with 2533 ft^3 class G cement in 12-1/4" hole. Did not bump plug, floats held. Tagged TOC in tubing 188' above float collar. TOC estimated at 6113' MD assuming 30% excess. 2031760 50-029-21866-01 W-01A Operable Artificial Lift Producer 0'12304' MD/ 8904' TVD n 6113' MD (4719' TVD) MIT-IA to 3500 psi on 06/02/2010 9-5/8" production casing cemented with 2533 ft^3 class G cement in 12-1/4" hole. Did not bump plug, floats held. Tagged TOC in tubing 188' above float collar. TOC estimated at 6113' MD assuming 30% excess. 1890070 50-029-21906-00 W-08 P&A'd 1400'13078' MD/ 8885' TVD n 7307' MD (5318' TVD) MIT-IA to 2500 psi on 10/13/2015 9-5/8" production casing cemented with 2905 ft^3 class G cement in 12-1/4" hole. Did not bump plug, floats held. Tagged TOC in tubing 1449' above float collar. TOC estimated at 7307' MD assuming 30% excess. 2020900 50-029-21906-01 W-08A Operable Artificial Lift Producer 1100'12531' MD/ 8863' TVD n 7307' MD (5318' TVD) MIT-IA to 2500 psi on 10/13/2015 9-5/8" production casing cemented with 2905 ft^3 class G cement in 12-1/4" hole. Did not bump plug, floats held. Tagged TOC in tubing 1449' above float collar. TOC estimated at 7307' MD assuming 30% excess. 1971390 50-029-21953-01 W-03A Operable WAG Injector 1050'12397' MD/ 8916' TVD n 5120' MD (4980' TVD) MIT-IA to 2315 psi on 04/13/2021 9-5/8" production casing cemented with 1984 ft^3 class G cement in 12-1/4" hole. Bumped plug, floats held. Tagged TOC in tubing at float collar. TOC estimated at 5120' MD assuming 30% excess. 2130260 50-029-23485-00 U-16 Operable Artificial Lift Producer 1300'12843' MD/ 9013' TVD n 6636' MD (4661' TVD) MIT-IA to 3740 psi on 06/04/2013 7" production casing cemented with 206 bbls LiteCrete and 29 bbls class G cement in 8-3/4" hole. Bumped plug, floats held. Tagged TOC in tubing at the float collar. TOC estimated at 6636' MD assuming 30% excess. PTD API WELL STATUS Distance Top of Schrader Bluff Oba Sand Log Est. Top of Cement from Volumetric Calculations Annulus Integrity Zonal Isolation 1890070 50-029-21906-00 W-08 P&A'd 715'6745’ MD/ 4983’ TVD n 7307' MD (5318' TVD) MIT-IA to 2500 psi on 10/13/2015 9-5/8" production casing cemented with 2905 ft^3 class G cement in 12-1/4" hole. Did not bump plug, floats held. Tagged TOC in tubing 1449' above float collar. TOC estimated at 7307' MD assuming 30% excess. 2020900 50-029-21906-01 W-08A Operable Artificial Lift Producer 715'6745’ MD/ 4983’ TVD n 7307' MD (5318' TVD) MIT-IA to 2500 psi on 10/13/2015 9-5/8" production casing cemented with 2905 ft^3 class G cement in 12-1/4" hole. Did not bump plug, floats held. Tagged TOC in tubing 1449' above float collar. TOC estimated at 7307' MD assuming 30% excess. 2020970 50-029-23087-00 W-203 Operable Artificial Lift Producer 865'7132’ MD / 5035’ TVD 5456' MD (4102' TVD) Rig casing test to 3000 psi on 06/02/2002 7" production casing cemented with 94 bbls class G cement in 8-3/4" hole. Bumped plug, floats held. USIT log found TOC at 5456' MD. 2031160 50-029-23165-00 W-205 Operable Artificial Lift Producer 1185'6928’ MD / 5030’ TVD n 5458' MD (4168' TVD) Rig casing test to 3500 psi on 09/04/2003 7-5/8" production casing cemented with 122 bbls class G in 9-7/8" hole. No losses recorded. TOC estimated at ~ 5458' MD assuming 30% excess. 2061850 50-029-23339-00 W-210 Operable WAG Injector 1170'7195’ MD / 4976’ TVD 5096' MD (3777' TVD) MIT-IA to 1934 psi on 05/31/2019 7" production casing cemented with 19 bbls LiteCrete and 67 bbls class G cement in 8-3/4" hole. Bumped plug. Did not have full returns after tail was around float shoe. USIT log found TOC at ~5096' MD. 2020750 50-029-23080-00 W-211 Operable Artificial Lift Producer 1115'6135’ MD / 5052’ TVD n 4558' MD (3792' TVD) MIT-IA to 3500 psi on 05/20/2002 7" production casing cemented with 82.5 bbls class G cement in 8-3/4" hole. Bumped plug, floats held. TOC estimated at ~ 4558' MD assuming 30% excess. Area of Review W-01A REV # 1 4-13-22 RWO Procedure WELL: W-01A PTD: 203176 AOR Maps Ivishak REV # 1 4-13-22 RWO Procedure WELL: W-01A PTD: 203176 Schrader Bluff Pre Sundry Work: *Note depending on the timing of rig move, well kill and BOP installation steps may be performed on rig rather than pre rig. DHD 1. Cycle LDS’s 2. PPPOT-T 3. PPPOT-IC 4. OA Integrity test Slickline/Fullbore 1. Set PX plug with extended fill and oval junk ports at 11,608’ MD 2. Pull Station 1 DMY and leave open pocket for circ out. 3. DMY GLV stations 2,3,5,7,8. 4. Circ well with 1,182 (1.2 *Total volume) bbls of 8.4 ppg brine. 5. Pump 1,182 bbls down the IA taking returns up the TBG to FL at max rate but not to exceed 2000 psi. a. Tubing Volume to GLM St1 is .0087 bbls/ft*11,343’=99 bbls b. Annular volume to GLM St1 is .0781 bbls/ft* 11,343’=886 bbls c. Total volume to GLM St1 is 985 bbls REV # 1 4-13-22 RWO Procedure WELL: W-01A PTD: 203176 6. CMIT-TXIA to 2500 psi 7. Freeze Protect well. Pump 191 bbls of diesel down the IA while taking returns up the TBG. 8. Rig up jumper from IA to tubing to allow freeze protect to swap. Sundry Procedure (Approval required to proceed): Eline 1. Cut tubing @ ~ 11,437’ MD 2. CMIT-TXIA to 1000 psi. Valve Shop/Ops 1. Bleed WHP’s to 0 psi 2. Set and test TWC 3. Nipple Down Tree and tubing head adapter. Inspect lift threads. 4. NU BOPE configured top down, Annular, 2-7/8” x 5-1/2” VBRs, Blinds and integral flow cross. RWO 1. MIRU Thunderbird #1 Rig. 2. Test BOPE to 250psi Low/3,000psi High, annular to 250psi Low/2,500psi High (hold each ram/valve and test for 5-min). Record accumulator pre-charge pressures and chart tests. A. Perform Test per Thunderbird #1 BOP test procedure. B. Notify AOGCC 24 hrs in advance of BOP test. C. Confirm test pressures per the Sundry Conditions of approval. D. Test the 2-7/8” x 5-1/2” VBR’s with 4-½” and 2-7/8” test joints. Test the Annular preventer with a 2-7/8” test joint. E. Submit to AOGCC completed 10-424 form within 5 days of BOPE test. 3. Pull TWC. a. Utilize a lubricator for TWC removal if potential for trapped pressure exists. 4. MU landing joint or spear, BOLDS and pull hanger to the floor. PU weights are expected to be ~105K 5. Circulate bottoms up, pull 3 1/2” tubing to floor. a. Circulate well over 9.0 PPG brine prior to potential perforations in Schrader Bluff (8.4 PPG EMW) 6. Rig up Eline and log well with CBL from ~11,437 MD to surface. Confirm TOC is above the upper confining interval defined by the Polaris Oil Pool rules. a. Provide CBL to OE for submission to AOGCC 7. Contingency- If CBL does not indicate good cement above confining interval. Install kill string RDMO. 8. RIH with Eline perf OBA (6,578-6,621MD),OBC(6,722-6,767MD) and OBD(6,816-6,893MD). a. Contact OE Wyatt Rivard at 509-670-8001 or Brodie Wages at 713-380-9836 for final approval of tie-in. 9. Run casing scraper to 11,400MD to clear casing for zonal isolation packers. 10. Run 4 ½” L-80 tubing with WFRM completion as detailed on proposed schematic. 11. Land hanger and reverse in corrosion inhibited 9.0 ppg brine or equivalent 12. Drop ball and rod and set packer with 3,500psi pump pressure. 13. Perform MIT-T to 3,000 psi and MIT-IA to 3,000 psi for 30 minutes. a. Note - test will be repeated post DMY valve reset of SOV prior to injection at which point AOGCC pre injection MIT notice will be given. This is per AOGCC condition of approval sundry 321-394. 14. Shear valve in upper GLM. 15. Set TWC REV # 1 4-13-22 RWO Procedure WELL: W-01A PTD: 203176 16. Rig down Thunderbird #1. Valve Shop/Ops 1. ND BOPE 2. NU tree and tubing head adapter. 3. Test both tree and tubing hanger void to 500psi low/5,000psi high. 4. Pull TWC and freeze protect to ~2,000ft with diesel. Slickline 1. Pull Ball and rod and RHC profile 2. Pull TTP at 11,608’ MD (This is to clear any RWO debris prior to injection) 3. Pump 50 bbls away at max rate not exceeding 1800 psi and note injectivity on WSR. 4. Reset TTP at 11,608’ MD 5. Set DMY GLV in station 1 6. Perform MIT-T to 3,000 psi and MIT-IA to 3,000 psi for 30 charted minutes. a. Give the AOGCC 24hrs notice to witness MIT-IA. Document and submit on State of Alaska form 10-426. 7. CO WFRV per GL ENGR 8. RDMO & POI well. DHD 1. MIT-IA to 2750 psi after well is on stabilized injection. 2. Give the AOGCC 24hrs notice to witness online, injecting, MIT-IA. 3. Additional condition of approval for long term tracking: a. WFL and Temp log performed 6monots after initial W-01A injection on offset well W-08A then annually thereafter while W-01A on injection Attachments: 1. Wellbore Schematic 2. Proposed Wellbore Schematic 3. BOP Drawing REV # 1 4-13-22 RWO Procedure WELL: W-01A PTD: 203176 Wellbore Schematic REV # 1 4-13-22 RWO Procedure WELL: W-01A PTD: 203176 Proposed Wellbore Schematic REV # 1 4-13-22 RWO Procedure WELL: W-01A PTD: 203176 REV # 1 4-13-22 RWO Procedure WELL: W-01A PTD: 203176 RWO BOPs Changes to Approved Sundry Procedure REV # 1 4-13-22 RWO Procedure WELL: W-01A PTD: 203176 Date: Subject: Sundry #: Any modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to the AOGCC by the “first call” engineer. AOGCC written approval of the change is required before implementing the change. Step Page Date Procedure Change HAK Prepared By (Initials) HAK Approve d By (Initials) AOGCC Written Approval Received (Person and Date) Approval: Operations Manager Date Prepared: Operations Engineer Date Operator Name:2. Exploratory Development Service 5 Permit to Drill Number:203-176 6.API Number:50-029-21866-01-00 Hilcorp North Slope, LLC 5. Field/Pools:9. Well Name and Number: Property Designation (Lease Number): 10. 8. PBU W-01A 7.If perforating: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception? Stratigraphic Current Well Class:4. Type of Request:1.Abandon Plug Perforations 5 Fracture Stimulate Repair Well 5 Operations shutdown Convert to Injector Op Shutdown GAS GSTORWAG SPLUG Abandoned Oil WINJ Exploratory Development Stratigraphic 55Service WDSPL 12. Attachments: PRESENT WELL CONDITION SUMMARY 13135 Effective Depth MD: 13Cr80, L80 11. Commission Representative: 15. Suspended Contact Name: Brian Glasheen Contact Email: Brian.Glasheen@hilcorp.com Authorized Name: Stan Golis Authorized Title:Sr. Area Operations Manager Authorized Signature: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Yes No Spacing Exception Required?Subsequent Form Required: Approved by:COMMISSIONER APPROVED BYTHE COMMISSION Date: 5OtherAlter Casing Pull Tubing Conditions of approval: Notify Commission so that a representative may witness Sundry Number: COMMISSION USE ONLY 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Detailed Operations Program Packers and SSSV Type: 3-1/2" Otis Packer Packers and SSSV MD (ft) and TVD (ft): Perforation Depth MD (ft):Tubing Size: Size Total Depth MD (ft):Total Depth TVD(ft): 8936 Effective Depth TVD:Plugs (MD):Junk (MD): Other Stimulate Re-enter Susp Well Suspend Plug for Redrill 5Perforate 5Perforate New Pool 11509, 8319 11688, 8451 Date: Liner 618 2-3/8" 11762 - 12380 8506 - 8936 11200 11780 Well Status after proposed work: 16. Verbal Approval: 5 Change Approved Program 30 - 2933 30 - 2683 14. Estimated Date for Commencing Operations: BOP Sketch 30 - 110 Structural 6870 Proposal Summary 13. Well Class after proposed work: 3-1/2" HES TNT Packer 12284 - 13135 8894 - 8936 3-1/2" 9.2#27 - 11798 Liner 13135 8936 None 11734 30 - 110 13-3/8" 9-5/8" Contact Phone:907.564.5277 Date: 4760 80 20"Conductor 2670 GINJ 5 Post Initial Injection MIT Req'd? Yes No 5 5 Comm. STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 Surface 2903 4930 Intermediate 11998 29 - 12027 29 - 8706 333 5-1/2"11810 - 12143 8541 - 8797 7740 6820 Address:3800 Centerpoint Dr, Suite 1400, Anchorage, AK 99503 3. No 5Yes Casing Length MD TVD Burst Tubing Grade:Tubing MD (ft):Perforation Depth TVD (ft): Collapse MPSP (psi): Wellbore Schematic 2232 Comm.Sr Pet Eng Sr Pet Geo Sr Res Eng Form 10-403 Revised 03/2020 Approved application is valid for 12 months from the date of approval. Prudhoe Bay, Prudhoe Oil / Polaris Oil 484 55 8/30/21 ADL 0028263, ADL 0047451 By Samantha Carlisle at 2:46 pm, Aug 10, 2021 321-394 Digitally signed by Stan Golis (880) DN: cn=Stan Golis (880), ou=Users Date: 2021.08.10 14:24:53 -08'00' Stan Golis (880) * BOPE test to 3000 psi. Annular to 2500 psi. *AOGCC to witness MIT-IA to 3000 psi. * MIT-IA to 2750 psi within 5 days of stabilized injection. *CBL to AOGCC for review *Variance to 20AAC 25.412(b) Packer will be set greater than 200 ft MD from open perforations is approved pending CBL results. *Variance to 20 AAC 25.402(b) is approved per the following interventions: 1. Six months post initial injection, a pulsed neutron water flow and temperature log will be conducted on offset well W-08A. 2. Eighteen months and all subsequent years W-01A is on WINJ, a pulsed neutron water flow and 10-404 temperature log will be conducted on offset well W-08. *AOGCC to witness MIT-T to 3000 psi post final set of tubing tail plug at 11,608' MD. MGR19AUG21 Perforate New Pool Polaris only Prudhoe Oil / Polaris Oil SFD 8/17/2021 DSR-8/10/21dts 8/23/2021 JLC 8/23/2021 RBDMS HEW 8/24/2021 RWO Procedure WELL:W-01A PTD:203-176 Well Name:W-01A API Number:50-029-21866-01-00 Current Status:Shut-In Producer Rig:Thunderbird #1 Estimated Start Date:8/30/2021 Permit to Drill Number:203-176 First Call Engineer:Brian Glasheen 907-564-5277 (O)907-545-1144 M Second Call Engineer:David Brodie Wages 713-380-9836 M AFE:212-00553 Current Bottom Hole Pressure:3,112 psi @ 8,800’ TVD 7.1 PPGE (+.3 SF)| SBHPG 10/17/2016 Max. Anticipated Surface Pressure:2,232 psi (Based on 0.1 psi/ft. gas gradient) Last SI WHP:1,780 psi (Taken on 04/15/20) Min ID:1.92” ID TOL @ 11,762’ MD Max Angle:96 Deg @ 12,573’ MD Brief Well Summary: W-01A is a long-term SI Ivishak producer in an ideal location to support W-205 and W-203 trilaterals in the Oba, Obc, and Obd sands. Volumetric, analog, and simulation analysis indicate recompleting the W-01A to the Oba, Obc, and Obd sands as a PW injector would increase offset production. Additionally, the W-01A is in a great location in the Ivishak to support W-08A and U-16. To maximize oil rate and field value it is recommended to convert W-01A into a Schrader-Ivishak PW injector. Injection between the two pools will be controlled via WFRV and a down hole MCX with orifice over the Ivishak to avoid any cross flow to the Schrader during any SI. Injection start-up will consist of the Schrader zone only to get a base line injection prior to commingled injection. Once AOGCC approves an amended separate AIO amendment request, commingled injection will commence. Notes Regarding Wellbore Condition: x Ivishak perfs will remain hydraulically isolated by tested TTP at 11,608’ MD until Eline Perfs the upper zones. Objective: Convert to a PW injector. Pull the existing 3 ½” 13CR-80 tubing out of the well and replace with a WFRM completion. Achieve a passing MIT-IA & MIT-T. Variance Request:20AAC25.412(b) Packer will be set greater than 200ft measured depth from open perfs. Tubing packer is at ~11,337’MD which is 947’ MD above the uppermost open slots at 12,284’ MD. Area of Review – PBU W-01A (PTD # 203-176) Prior to the conversion of well W-01A from Ivishak producer to Ivishak and Schrader Bluff injector, an Area of Review (AOR) has been conducted. This AOR found 4 wells and former wells within ¼ mile of W-01A’s entry point into the Ivishak formation and 6 wells within ¼ mile of W-01A’s entry point into the Schrader Bluff formation. Estimated TOCs were calculated using the daily drilling logs found in the original well files. The calculations are based on the cement volumes pumped with 30% excess in the annular space. W-08A was found to have a calculated TOC below the Schrader Bluff injection zone. See attached table Area of Review W- 01A for annulus integrity and zonal isolation of all wells within the AOR. W-08A is within the ¼ mile radius and does not have cement across the Schrader interval when calculated volumetrically with 30% excess. W-08A is within the ¼ mile radius and does not have cement across the Schrader interval w convert W-01A into a Schrader-Ivishak PW injector. RWO Procedure WELL:W-01A PTD:203-176 Hilcorp requests a variance from 20 AAC 25.402 (b) due to not having adequate cementing data across the confining zone for wells within the ¼ mile radius of an injection well under 20 AAC25.402(h). The assurance that the injection zone is isolated is based on the following: 1. Hilcorp provides monthly TIO plots of W-08A. If out of zone injection occurs alongside the un- cemented portion of the casings on these wells, it may show up in the OA pressure-plots as an anomaly. 2. Hilcorp performs a temperature log and pulsed neutron water flow log in W-08A 1 year after injection commences and all subsequent years. AOR Tables PTD API WELL STATUS Distance Top of Ivishak Log Est. Top of Cement from Volumetric Calculations Annulus Integrity Zonal Isolation 1881070 50-029-21866-00 W-01 P&A'd 60' 12276' MD/ 8906' TVD n 6113' MD (4719' TVD) MIT-IA to 3500 psi on 06/02/2010 9-5/8" production casing cemented with 2533 ft^3 class G cement in 12-1/4" hole. Did not bump plug, floats held. Tagged TOC in tubing 188' above float collar. TOC estimated at 6113' MD assuming 30% excess. NA 50-029-21866-70 W-01APB1 P&A'd 0' 12312' MD/ 8905' TVD n 6113' MD (4719' TVD) MIT-IA to 3500 psi on 06/02/2010 9-5/8" production casing cemented with 2533 ft^3 class G cement in 12-1/4" hole. Did not bump plug, floats held. Tagged TOC in tubing 188' above float collar. TOC estimated at 6113' MD assuming 30% excess. 2031760 50-029-21866-01 W-01A Operable Artificial Lift Producer 0'12304' MD/ 8904' TVD n 6113' MD (4719' TVD) MIT-IA to 3500 psi on 06/02/2010 9-5/8" production casing cemented with 2533 ft^3 class G cement in 12-1/4" hole. Did not bump plug, floats held. Tagged TOC in tubing 188' above float collar. TOC estimated at 6113' MD assuming 30% excess. 1890070 50-029-21906-00 W-08 P&A'd 1400' 13078' MD/ 8885' TVD n 7307' MD (5318' TVD) MIT-IA to 2500 psi on 10/13/2015 9-5/8" production casing cemented with 2905 ft^3 class G cement in 12-1/4" hole. Did not bump plug, floats held. Tagged TOC in tubing 1449' above float collar. TOC estimated at 7307' MD assuming 30% excess. 2020900 50-029-21906-01 W-08A Operable Artificial Lift Producer 1100'12531' MD/ 8863' TVD n 7307' MD (5318' TVD) MIT-IA to 2500 psi on 10/13/2015 9-5/8" production casing cemented with 2905 ft^3 class G cement in 12-1/4" hole. Did not bump plug, floats held. Tagged TOC in tubing 1449' above float collar. TOC estimated at 7307' MD assuming 30% excess. 1971390 50-029-21953-01 W-03A Operable WAG Injector 1050'12397' MD/ 8916' TVD n 5120' MD (4980' TVD) MIT-IA to 2315 psi on 04/13/2021 9-5/8" production casing cemented with 1984 ft^3 class G cement in 12-1/4" hole. Bumped plug, floats held. Tagged TOC in tubing at float collar. TOC estimated at 5120' MD assuming 30% excess. 2130260 50-029-23485-00 U-16 Operable Artificial Lift Producer 1300'12843' MD/ 9013' TVD n 6636' MD (4661' TVD) MIT-IA to 3740 psi on 06/04/2013 7" production casing cemented with 206 bbls LiteCrete and 29 bbls class G cement in 8-3/4" hole. Bumped plug, floats held. Tagged TOC in tubing at the float collar. TOC estimated at 6636' MD assuming 30% excess. PTD API WELL STATUS Distance Top of Schrader Bluff Oba Sand Log Est. Top of Cement from Volumetric Calculations Annulus Integrity Zonal Isolation 1890070 50-029-21906-00 W-08 P&A'd 715' 6745’ MD/ 4983’ TVD n 7307' MD (5318' TVD) MIT-IA to 2500 psi on 10/13/2015 9-5/8" production casing cemented with 2905 ft^3 class G cement in 12-1/4" hole. Did not bump plug, floats held. Tagged TOC in tubing 1449' above float collar. TOC estimated at 7307' MD assuming 30% excess. 2020900 50-029-21906-01 W-08A Operable Artificial Lift Producer 715'6745’ MD/ 4983’ TVD n 7307' MD (5318' TVD) MIT-IA to 2500 psi on 10/13/2015 9-5/8" production casing cemented with 2905 ft^3 class G cement in 12-1/4" hole. Did not bump plug, floats held. Tagged TOC in tubing 1449' above float collar. TOC estimated at 7307' MD assuming 30% excess. 2020970 50-029-23087-00 W-203 Operable Artificial Lift Producer 865'7132’ MD / 5035’ TVD 5456' MD (4102' TVD) Rig casing test to 3000 psi on 06/02/2002 7" production casing cemented with 94 bbls class G cement in 8-3/4" hole. Bumped plug, floats held. USIT log found TOC at 5456' MD. 2031160 50-029-23165-00 W-205 Operable Artificial Lift Producer 1185'6928’ MD / 5030’ TVD n 5458' MD (4168' TVD) Rig casing test to 3500 psi on 09/04/2003 7-5/8" production casing cemented with 122 bbls class G in 9-7/8" hole. No losses recorded. TOC estimated at ~ 5458' MD assuming 30% excess. 2061850 50-029-23339-00 W-210 Operable WAG Injector 1170'7195’ MD / 4976’ TVD 5096' MD (3777' TVD) MIT-IA to 1934 psi on 05/31/2019 7" production casing cemented with 19 bbls LiteCrete and 67 bbls class G cement in 8-3/4" hole.Bumped plug.Did not have full returns after tail was around float shoe. USIT log found TOC at ~5096' MD. 2020750 50-029-23080-00 W-211 Operable Artificial Lift Producer 1115'6135’ MD / 5052’ TVD n 4558' MD (3792' TVD) MIT-IA to 3500 psi on 05/20/2002 7" production casing cemented with 82.5 bbls class G cement in 8-3/4" hole.Bumped plug, floats held. TOC estimated at ~ 4558' MD assuming 30% excess. Area of Review W-01A Located within the same isolated fault block as W-01, Nearby faults cut entire SB section and are sealing. assurance that the injection zone is isolated SFD 8/17/2021 2020900 Hilcorp performs a temperature log and pulsed neutron water flow log in W-08A 1 year after injection commences and all subsequent years. Hilcorp provides monthly TIO plots of W-08A. 1890070 RWO Procedure WELL:W-01A PTD:203-176 AOR Maps Ivishak RWO Procedure WELL:W-01A PTD:203-176 Schrader Bluff Pre Sundry Work: DHD 1. Cycle LDS’s 2. PPPOT-T 3. PPPOT-IC 4. OA Integrity test Slickline/Fullbore 1. Set PX plug with extended fill and oval junk ports at 11,608’ MD 2. Pull Station 1 DMY and leave open pocket for circ out. 3. DMY GLV stations 2,3,5,7,8. 4. Circ well with 1,182 (1.2 *Total volume) bbls of 8.4 ppg 1 percent KCL or Seawater. 5. Pump 1,182 bbls down the IA taking returns up the TBG to FL at max rate but not to exceed 2000 psi. a. Tubing Volume to GLM St1 is .0087 bbls/ft*11,343’=99 bbls b. Annular volume to GLM St1 is .0781 bbls/ft* 11,343’=886 bbls c. Total volume to GLM St1 is 985 bbls 6. CMIT-TXIA to 2500 psi RWO Procedure WELL:W-01A PTD:203-176 7. Freeze Protect well. Pump 191 bbls of diesel down the IA while taking returns up the TBG. 8. Rig up jumper from IA to tubing to allow freeze protect to swap. Sundry Procedure (Approval required to proceed): Eline 1. Cut tubing @ ~ 11,437’ MD 2. CMIT-TXIA to 1000 psi. Valve Shop/Ops 1. Bleed WHP’s to 0 psi 2. Set and test TWC 3. Nipple Down Tree and tubing head adapter. Inspect lift threads. 4. NU BOPE configured top down, Annular, 2-7/8” x 5-1/2” VBRs, Blinds and integral flow cross. RWO 1. MIRU Thunderbird #1 Rig. 2. Test BOPE to 250psi Low/3,000psi High, annular to 250psi Low/2,500psi High (hold each ram/valve and test for 5-min). Record accumulator pre-charge pressures and chart tests. A. Perform Test per Thunderbird #1 BOP test procedure. B. Notify AOGCC 24 hrs in advance of BOP test. C. Confirm test pressures per the Sundry Conditions of approval. D. Test the 2-7/8” x 5-1/2” VBR’s with 4-½” and 2-7/8” test joints. Test the Annular preventer with a 2-7/8” test joint. E. Submit to AOGCC completed 10-424 form within 5 days of BOPE test. 3. Pull TWC. 4. MU landing joint or spear, BOLDS and pull hanger to the floor. PU weights are expected to be ~105K 5. Pull 3 1/2” tubing to floor, circulate bottoms up. 6. Rig up Eline and log well with CBL from ~11,437 MD to surface. Confirm TOC is above the upper confining interval defined by the Polaris Oil Pool rules. 7.Contingency-If CBL does not indicate good cement above confining interval. Install kill string RDMO. 8. RIH with Eline perf OBA (6,578-6,621MD), OBC (6,722-6,767MD) and OBD (6,816-6,893MD). 9. Run casing scraper to 7,000MD to clear casing for zonal isolation packers. 10. Run 4 ½” L-80 tubing with WFRM completion as detailed on proposed schematic. 11. Land Hanger and reverse in corrosion inhibited 8.4 ppg 1% KCL or equivalent 12. Drop ball and rod and set packer with 3,500psi pump pressure. 13. Perform MIT-T to 3,000 psi and MIT-IA to 3,000 psi for 30 charted minutes. Give the AOGCC 24hrs notice to witness MIT-IA. Document and submit on State of Alaska form 10-426. 14. Shear valve in upper GLM. 15. Set TWC 16. Rig down Thunderbird #1. Valve Shop/Ops 1. ND BOPE 2. NU tree and tubing head adapter. 3. Test both tree and tubing hanger void to 500psi low/5,000psi high. 4. Pull TWC and freeze protect to ~2,000ft with diesel. Eline perf OBA (6,578-6,621MD), OBC (6,722-6,767MD) and OBD (6,816-6,893MD). RWO Procedure WELL:W-01A PTD:203-176 Slickline 1. Pull Ball and rod and RHC profile 2. Pull TTP at 11,608 MD (This is to clear any RWO debris prior to injection) 3. Pump 50 bbls away at max rate not exceeding 1800 psi and note injectivity on WSR. 4. Reset TTP at 11,608 MD 5. Set DMY GLV in station 1 6. CO WFRV per GL ENGR 7. RDMO & POI well. DHD 1. MIT-IA to 2750 psi after well is on stabilized injection. 2.Give the AOGCC 24hrs notice to witness MIT-IA test. Attachments: 1. Wellbore Schematic 2. Proposed Wellbore Schematic 3. BOP Drawing MIT-T to 3000 psi. MIT-IA to 3000 psi. AOGCC to witness. 24 hour notice. RWO Procedure WELL:W-01A PTD:203-176 Wellbore Schematic O RWO Procedure WELL:W-01A PTD:203-176 Proposed Wellbore Schematic O Packer #1 11,353'md/8203'tvd packer #5 6478' MD/4932'tvd packer #2 6993'md/5228'tvd Tubing tail plug @ 11,608' MD packer #3 6792' MD packer #4 6671'MD RWO Procedure WELL:W-01A PTD:203-176 RWO BOPs RWO Procedure WELL:W-01A PTD:203-176 Changes to Approved Sundry Procedure Date: Subject: Sundry #: Any modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to the AOGCC by the “first call” engineer. AOGCC written approval of the change is required before implementing the change. Step Page Date Procedure Change HAK Prepared By (Initials) HAK Approve d By (Initials) AOGCC Written Approval Received (Person and Date) Approval: Operations Manager Date Prepared: Operations Engineer Date Wallace, Chris D (DOA) From: AK, D&C Well Integrity Coordinator <AKDCWellIntegrityCoordinator@bp.com> Sent: Thursday, March 12, 2015 9:27 AM To: AK, OPS GC2 OSM;AK, OPS GC2 Field O&M TL; AK, OPS GC2 Wellpad Lead;AK, OPS Prod Controllers; Cismoski, Doug A; Daniel, Ryan;AK, D&C Wireline Operations Team Lead; AK, D&C Well Services Operations Team Lead;AK, RES GPB West Wells Opt Engr; AK, RES GPB East Wells Opt Engr; Burton, Kaity;AK, OPS WELL PAD W;Wallace, Chris D (DOA) Cc: AK, D&C DHD Well Integrity Engineer;AK, D&C Projects Well Integrity Engineer; AK, OPS FF Well Ops Comp Rep;AK, D&C Well Integrity Coordinator; Sternicki, Oliver R; Pettus,Whitney; Regg, James B (DOA) Subject: OPERABLE: Producer W-01A (PTD#2031706) Outer Annulus Repressurization Test Passed Attachments: image002jpg; image003.png; image001 jpg; Producer W-01 (PTD#2031760) TIO Plot.docx All, Producer W-01 (PTD#2031760) underwent a passing outer annulus repressurization test completed on 03/12/2015. The outer annulus pressure buildup rate was determined to be 5 psi per day which is considered manageable by bleeds. The well is reclassified as Operable. A copy of the TIO plot is included for reference. Thank you, Kevin Parks S ED ; (Alternate LOU,re Clm er BP Alaska-Well Integrity Coordinator G'/� Global Wells �/�/ Organization Office: 907.659.5102 WIC Email:AKDCWellIntegrityCoordinator@bp.com From: AK, D&C Well -• ity Coordinator Sent: Thursday, February 19, e 12:00 PM To: AK, OPS GC2 OSM; AK, OPS GC2 Fie • :: L• AK, OPS GC2 Wellpad Lead; AK, OPS Prod Controllers; Cismoski, Doug A; Daniel, Ryan; AK, D&C Wireline Operations Tea -Lead; AK, D&C Well Services Operations Team Lead; AK, RES GPB West Wells Opt Engr; AK, RES GPB East Wells Opt Engr; Burton, Kaity; AK, OPS WELL PAD W; 'chris.wallace@alaska.gov'; 'jim.regg@alaska.gov' Cc: AK, D&C DHD Well Integrity Engineer; AK, D&C Projects Well Integrity Engineer; AK, OPS FF Well Ops Comp Rep; AK, D&C Well Integrity Coordinator; Sternicki, Oliver R; Pettus, Whitney Subject: UNDER EVALUATION: Producer W-01A(PTD #2031706) Sustained Outer Annulus Casing_Pressure Above MOASP All, 1 Producer W-01 (PTD#2031760)TIO Plot Well M-0s 1 OCC • lA CI COQ Da 000a 8 TTTTTTT , S. II • Wallace, Chris D (DOA) From: AK, D&C Well Integrity Coordinator <AKDCWelllntegrityCoordinator@bp.com> Sent: Thursday, February 19, 2015 12:00 PM To: AK, OPS GC2 OSM; AK, OPS GC2 Field O&M TL;AK, OPS GC2 Wellpad Lead;AK, OPS Prod Controllers; Cismoski, Doug A; Daniel, Ryan; AK, D&C Wireline Operations Team Lead; AK, D&C Well Services Operations Team Lead; AK, RES GPB West Wells Opt Engr; AK, RES GPB East Wells Opt Engr; Burton, Kaity; AK, OPS WELL PAD W;Wallace, Chris D (DOA); Regg,James B (DOA) Cc: AK, D&C DHD Well Integrity Engineer; AK, D&C Projects Well Integrity Engineer;AK, OPS FF Well Ops Comp Rep; AK, D&C Well Integrity Coordinator; Sternicki, Oliver R; Pettus, Whitney Subject: UNDER EVALUATION: Producer W-01A (PTD#20 6) Sustained Outer Annulus Casing Pressure Above MOASP � _, 72,0 0 C"b"11 . Attachments: image002 jpg; image003.png; image001 jpg; V17 O1A Wellbore Schematic.pdf1 414/)-c All, Producer W-01A 9PTD#2031706) is now available for diagnostic work. At this time the well has been reclassified as Under Evaluation for high outer annulus pressure last fall. Plan forward: 1. Operations: Put the well on production 2. DHD: Perform an Outer Annulus Repressurization Test(DART) 3. WIE: Additional diagnostics as needed A copy of the wellbore schematic has been included for reference. Please call with any questions. Thank you, SUED MPR 0 2 2015 Laurie Climer (Alternate:Jack Disbrow) BP Alaska-Well Integrity Coordinator grogtman�lul ni e'usn �M tJon WIC Office: 907.659.5102 WIC Email: AKDCWellIntegrityCoordinator@BP.com From: AK, D& • -• ' Coordinator Sent: Monday, September 29, S - . To: AK, OPS GC2 OSM; AK, OPS GC2 Field O&M , • , !• GC2 Wellpad Lead; AK, OPS Prod Controllers; Cismoski, Doug A; Daniel, Ryan; AK, D&C Wireline Operations Team Lead; , !:C Well Services Operations Team Lead; AK, RES GPB West Wells Opt Engr; AK, RES GPB East Wells Opt Engr; Burton, Kaity; • , e• WELL PAD W; 'chris.wallace@alaska.gov' Cc: AK, D&C DHD Well Integrity Engineer; AK, D&C Projects Well Integrity Engineer; 'jim.regg@a . •ov'; AK, OPS FF 1 TREE= 4-1/16"CMJ SA_ NOTES: WELL ANGLE>70°@ 12352'*** WELLACTUATOD R R=• BAKVOY ER C W-O 1A *** 3-1/2"CHROME TBG ACTUATOR= BAKER C KB.ELEV= 83.26' BF.ELEV= 53.81' ( I KOP= 1000' 20"CONDUCTOR — 110' - Max Angle= 96 @ 12573' ' ' 1995' —3-1/2"HES X NIP, ID=2.813 Datum MD= 12249' Datum TV D= 8800'SS GAS LIFT MANDRELS ST MD TVD DEV TYPE VLV LATCH_PORT DATE 13-3/8"CSG,72#,L-80, ID=12.347" - 2933' 8 3690 3198 46 MMG DOME RK 10 06/15/10 7 6242 4795 54 MMG DOME RK 12 06/15/10 6 7945 5800 51 MMG DMY RK 0 06/01/10 Minimum ID = 1.92" @ 11762" 5 8705 6296 47 MMG DOME RK 12 06/15/10 TOP OF 2-3/8" LINER 4 9436 6811 43 MMG DMY RK 0 06/01/10 3 10103 7299 45 MMG DOME RK 16 06/15/10 2 10802 7800 43 MMG SO RK 22 06/15/10 1 11343 8196 42 MMG DMY RK 0 06/01/10 3-1/2"SLB SAPPHIRE NDPG —1 11413' I— • PRESSURE GAUGE, ID=2.992" ' ' 11479' —I3-1/2"HES X NIP, ID=2.813 Z 11509' I—9-5/8"X 3-1/2"HES TNT PKR, ID=2.949" 1 11546' —3-1/2"HESXNIP,ID=2.813 3-1/2"TBG,9.2#,13CR-80 VAM TOP 11639' I I 11608' —13-1/2"HES X NIP,ID=2.813 .0087 bpf, ID=2.992" 3-1/2"TUBING STUB(05/04/10) -I 11646' I---F 1i 11654' —19-5/8"X 3-1/2"UNIQUE OVERSHOT 1 11672' —3-1/2"OTIS SBR SEAL ASSY FISH:6 METAL COLLETS& —11734 11688' —9-5/8"X 3-1/2"OTIS PKR,ID=3.85" 3 RUBBER ELMENTS(07/02/10) l J\�I 11693' H4-1/2"MILLOUT EXTENSION,ID=3.958" TOP OF 2-3/8"LNR —I 11762' 'I 11699' H4-1/2"X 3-1/2"XO,ID=2.992" i _ 11731' I—3-1/2"OTIS X NIP,ID=2.75" 1 3-1/2"TBG,9.3#,L-80 EUD 8RD, —1 11798' .0087 bpf,ID=2.992" ' TOP OF 5-1/2"LNR(06/20/03) - 111810' SLM 11762' —I2.6"BKR DEPLOY SLV,ID=1.92" / 11764' I J-1/2"OTIS X NIP, ID=2.75" 9-5/8"CSG,47#,L-80, ID=8.681" -I 12027' — BEHIND 11798' —13-1/2"WLEG,ID=2.992" CT LNR 11806' —ELMD TT LOGGED 08/11/92 PERFORATION SUMMARY , REF LOG: ANGLE AT TOP PERF: Note: Refer to Production DB for historical perf data MILLOUT WINDOW(W-01A) 12143' 12154' SIZE SPF INTERVAL Opn/Sqz DATE 2-3/8" SLID 12284-12347 C 12/25/03 ��.,1 11111111 1111111111111111 12347' -BOT 0-RING SUB' TOP OF WHIPSTOCK -I 12126' 1.1.111�1�1 ve 11111111 111 RA TAG —1 12153' 111111111111111 1111 5-1/2"LNR, 17#,L-80, .0232 bpf,ID=4.892" — 12670' WAWAtt 3-118" OPEN 2-3/8"LNR,4.6#,L-80,.0036 bpf,ID=1.920" 12380' HOLE TD —1 13135' DATE REV BY COMMENTS DATE REV BY COMMENTS PRUDHOE BAY UNIT 10/13/88 N22E ORIGINAL COMPLETION 06/20/10 TAR/PJC GLV/MIN ID CORRECTION WELL: W-01A 12/26/03 NORDIC 1 CTD SIDETRACK(W-01A) 07/06/10 KSB/SV_FISH(07/02/10) PERMIT No: 2031760 06/02/10 D-141 RWO API No: 50-029-21866-01 06/02/10 PJC DRLG DRAFT CORRECTIONS SEC 21,T11 N, R12E, 1158'FNL&1189'FEL 06/04/10 DB/PJC FINAL DRLG CORRECTIONS 06/18/10 TAR/BLG GLV C/O(06/15/10) BP Exploration (Alaska) e e Image Project Well History File Cover Page XHVZE This page identifies those items that were not scanned during the initial production scanning phase. They are available in the original file, may be scanned during a special rescan activity or are viewable by direct inspection of the file. :lQ 3 - 17- b. Well History File Identifier o Two-sided ""111111111"1111 Page Count from Scanned File: /p d.. (Count does include cover sheet) Page Count Matches Number in scan~~ngrreparation: V YES ~ Date:~/èJ-fD(, If NO in stage 1, page(s) discrepancies were found: YES Organizing (done) RESCAN ~Ior Items: o Greyscale Items: DIGITAL DATA tø"'6iskettes, No. I o Other, NolType: o Poor Quality Originals: o Other: NOTES: Date ;;...,; d{ 0 ~ Date é)...:a-/ Dc:' d x 30 = (p 0 + Date :J-Iaj O~ BY: ~ Project Proofing BY: ~ Scanning Preparation BY: ~ Production Scanning Stage 1 BY: Stage 1 BY: Maria Date: Scanning is complete at this point unless rescanning is required. ReScanned BY: Maria Date: Comments about this file: o Rescan Needed 11111111111" II/III OVERSIZED (Scannable) o Maps: o Other Items Scannable by a Large Scanner OVERSIZED (Non-Scannable) o Logs of various kinds: o Other:: /s/ ~f II 111111/11I11 "II/ /s/ rnfJ I = TOTAL PAGES h I (Count does not include cover sheet) 1/1AP /s/ V YI 11111111111111" III NO Vl1f /s/ NO /s/ 11111111/11I11 "III 11111111111111" 11/ /s/ Quality Checked III 11111111I111111I 10/6/2005 Well History File Cover Page. doc Wallace, Chris D (DOA) From: AK, D&C Well Integrity Coordinator[AKDCWelllntegrityCoordinator @bp.com] Sent: Tuesday, August 20, 2013 12:56 PM To: AK, OPS GC2 OSM; AK, OPS GC2 Field O&M TL;AK, OPS GC2 Wellpad Lead; AK, OPS Prod Controllers; Cismoski, Doug A; Daniel, Ryan; AK, D&C Wireline Operations Team Lead; AK, D&C Well Services Operations Team Lead;AK, RES GPB West Wells Opt Engr;AK, RES GPB East Wells Opt Engr; Burton, Kaity;AK, OPS Well Pad SW; Regg, James B(DOA); Wallace, Chris D(DOA) Cc: AK, D&C DHD Well Integrity Engineer;AK, D&C Projects Well Integrity Engineer; Climer, Laurie A Subject: UNDER EVALUATION:W Pad Producers with Sustained Casing Pressures during TAR All, The below producer wells are ready to be brought online Under Evaluation for further diagnostics after their IA exceeded MOASP during TAR: W-16A(PTD#2031000) W-21A(PTD#2011110) W-22 (PTD#1881100) W-36 (PTD#1881060) SCANNED n t W-37A (PTD#2021490) W-38A(PTD#2021910) Should a well fail the warm TIFL, an email will be sent to the AOGCC with a plan forward.The producer well below will be brought online Under Evaluation to evaluate OA over MOASP for further diagnostics. W-01A(PTD#2031760) The OART results will be separate relayed in a arate email. Y p Please call with any questions. Regards, Laurie Climer (: /icr,uai<c:Jack Disbrow) BP Alaska - Well Integrity Coordinator GIN G Ci:ic4 v i't`1s C'rcz1a',izu1c n WIC Office: 907.659.5102 WIC Email: AKDCWelllntegritvCoordinator @BP.com 1 Pr6 -ti-13 Regg, James B (DOA) From: AK, D &C Well Integrity Coordinator [AKDCWelllntegrityCoordinator @bp.com] Sent: Sunday, May 19, 2013 7:22 AM To: AK, OPS GC2 OSM; AK, OPS GC2 Field O &M TL; AK, OPS GC2 Wellpad Lead; AK, OPS Prod Controllers; Cismoski, Doug A; Daniel, Ryan; AK, D &C Wireline Operations Team Lead; AK, D &C Well Services Operations Team Lead; AK, RES GPB West Wells Opt Engr; AK, RES GPB East Wells Opt Engr; Longden, Kaity; AK, OPS Well Pad SW; Regg, James B (DOA); Schwartz, Guy L (DOA); Weiss, Troy D Cc: AK, D &C DHD Well Integrity Engineer; Walker, Greg (D &C); Grey, Leighton (CH2M Hill); Climer, Laurie A Subject: OPERABLE: Producer W -01A (PTD #2031760) Manageable by bleeds All, Producer W -01A (PTD# 2031760) performed a passing OART on 05/18/2013 with a BUR of 21 psi /day. At this time, the well is reclassified as Operable. Regards, Laurie Climer ( lier note: Jac,4 Dish/ () SCANNED MAY 31 2013 BP Alaska - Well Integrity Coordinator w C`s`u:al'�d�*lis WIC Office: 907.659.5102 WIC Email: AKDCWellIntegrityCoordinator (a7BP.com From: AK, D &C Well Integrity Coordinator Sent: Sunday, May 05, 2013 7:59 AM To: AK, OPS GC2 OSM; AK, OPS GC2 Field O &M TL; AK, OPS GC2 Wellpad Lead; AK, *PS Prod Controllers; Cismoski, Doug A; Daniel, Ryan; AK, D &C Wireline Operations Team Lead; AK, D &C Well S -'ices Operations Team Lead; AK, RES GPB West Wells Opt Engr; AK, RES GPB East Wells Opt Engr; Longden, Kaity - , OPS Well Pad SW; 'jim.regg @alaska.gov'; 'Schwartz, Guy L (DOA)'; Weiss, Troy D Cc: AK, D &C DHD Well Integrity Engineer; AK, D &C Well Integrity Coors nator; Holt, Ryan P Subject: UNDER EVALUATION: Producer W -01A (PTD #2031760) • ter Annulus Above MOASP All, Producer W -01A (PTD #2031760) was found to have o er annulus pressure above MOASP on 05/04/2013. The tubing /inner annulus /outer annulus pressures were 870/1860/1070 psi. The well is reclassified as Under Evaluation and is placed on a 28 -day clock for further diagn • tic work. Plan forward: 1. DHD: Perform outer annulus re •, essurization test A copy of the TIO plot is included f. reference. Please call with any question • Pagel .ef'a Regg, James B (DOA) riD 7 63. -i7., From: AK, D &C Well Integrity Coordinator [AKDCWeIIIntegrityCoordinator @bp.com] Sent: Sunday, January 30, 2011 7:39 PM r l Z / To: Maunder, Thomas E (DOA); Regg, James B (DOA); Schwartz, Guy L (DOA); AK, OPS GC2 OSM; AK, OPS GC2 Field O &M TL; AK, OPS GC2 Wellpad Lead; AK, OPS Well Pad SW; AK, OPS Prod Controllers; Cismoski, Doug A; Engel, Harry R; AK, D &C Wireline Operations Team Lead; AK, D &C Well Services Operations Team Lead; AK, RES GPB West Wells Opt Engr; AK, RES GPB East Wells Opt Engr Cc: Walker, Greg (D &C); AK, D &C Well Integrity Coordinator; Oakley, Ray (PRA) Subject: OPERABLE: Producer W -01A (PTD #2031760) Verified tubing integrity - Passing TIFL All, Producer W -01A (PTD #2031760) passed a TIFL on 1/27/11 after it was reported to have sustained casing pressure on the IA. The passing test verifies tubing integrity. The well has been reclassified as Operable and may continue on production. Thank you, Torin Roschinger (alt. Jerry Murphy) Well Integrity Coordinator Office (907) 659 - 5102 Harmony Radio x2376 . Cell (406) 570 -9630 Pager (907) 659 -5100 Ext. 1154 From: AK, D &C Well Integrity Coordinator Sent: Saturday, January 22, 2011 11:20 PM To: 'Maunder, Thomas E (DOA)'; 'Regg, James B (DOA)'; 'Schwartz, Guy L (DOA)'; AK, OPS GC2 OSM; AK, OPS GC2 Field O &M TL; AK, OPS GC2 Wellpad Lead; AK, OPS Well Pad SW; AK, OPS Prod Controllers; Cismoski, Doug A; Engel, Harry R; AK, D &C Wireline Operations Team Lead; AK, ' C Well Services Operations Team Lead; AK, RES GPB West Wells Opt Engr; AK, RES GPB East We Opt Engr; Oakley, Ray (PRA) Cc: AK, D &C Well Integrity Coordinator; Walker, Greg (D &C); King, Whitney Subject: UNDER EVALUATION: Producer W -01A (PTD #2031760) Sustained Ca • g Pressure on the IA - POP to perform TxIA diagnostics All, Artificially lifted producer W -01A (PTD #2031760) was classifi-. as Not Operable during the shut down due to sustained casing pressure. The wellhead pressures ere tubing /IA/OA equal to 2100/2100/70 psi on 01/14/2011. The well has been reclassified as Under 'valuation so that it may be placed on production to perform diagnostics. The OA fluid level is near surface; please be areful of thermal expansion when placing W -01A on production. Plan forward: 1. DHD: TIFL 2. Well Integrity Engineer: Write rk request to mitigate TxIA communication pending TIFL results A TIO plot and welibore sch- atic have been included for reference. Please call if you hay • estions or concerns. 2/1/2011 • Page 1 of 2 Regg, James B (DOA) 003-17( From: AK, D &C Well Integrity Coordinator [AKDCWellIntegrityCoordinator @bp.com] Sent: Saturday, January 22, 2011 11:20 PM To: Maunder, Thomas E (DOA); Regg, James B (DOA); Schwartz, Guy L (DOA); AK, OPS GC2 OSM; AK, OPS GC2 Field O &M TL; AK, OPS GC2 Wellpad Lead; AK, OPS Well Pad SW; AK, OPS Prod Controllers; Cismoski, Doug A; Engel, Harry R; AK, D &C Wireline Operations Team Lead; AK, D &C Well Services Operations Team Lead; AK, RES GPB West Wells Opt Engr; AK, RES GPB East Wells Opt Engr; Oakley, Ray (PRA) Cc: AK, D &C Well Integrity Coordinator; Walker, Greg (D &C); King, Whitney Subject: UNDER EVALUATION: Producer W -01A (PTD #2031760) Sustained Casing Pressure on the IA - POP to perform TxIA diagnostics Attachments: Producer W -01A (PTD # 2031760) TIO Plot.doc; Producer W -01A (PTD # 2031760) Wellbore Schematic.pdf All, Artificially lifted producer W -01A (PTD #2031760) was classified as Not Operable during the shut down due to sustained casing pressure. The wellhead pressures were tubing /IA/OA equal to 2100/2100/70 psi on 01/14/2011. The well has been reclassified as Under Evaluation so that it may be placed on production to perform diagnostics. The OA fluid level is near surface; please be careful of thermal expansion when placing W -01A on production. Plan forward: 1. DHD: TIFL 2. Well Integrity Engineer: Write work request to mitigate TxIA communication pending TIFL results A TIO plot and wellbore schematic have been included for reference. Please call if you have questions or concerns. Thank you, Gerald Murphy (alt. Torin Roschinger) FEB a' 7 2MV Well Integrity Coordinator Office (907) 659 -5102 Cell (907) 752 -0755 Pager (907) 659 -5100 Ext. 1154 From: AK, D &C Well Integrity Coordinator Sent: Friday, January 14, 2011 10:34 PM To: 'Regg, James B (DOA)'; 'Maunder, Thomas E (DOA)'; 'Schwartz, Guy (DOA)'• - ismoski, Doug A; Engel, Harry R; AK, D &C Well Services Operations Team Lead; AK, D &C Wir= ne Operations Team Lead; AK, OPS FS2 DS Ops Lead; AK, OPS FS2 Ops Lead; AK, OPS FS2 OSM; e , OPS FS2 OSS; AK, RES GPB East Wells Opt Engr; AK, OPS GC3 Wellpad Lead; AK, OPS GC3 Fac' • & Field OTL; AK, OPS GC1 OSM; AK, OPS Prod Controllers; AK, OPS GC2 OSM; AK, OPS GC2 Op ead; AK, OPS GC2 Wellpad Lead; AK, OPS GC2 Field O &M TL; AK, OPS GC2 OSS; AK, OPS Well P. DFT N2; AK, OPS GC1 Wellpad Lead; AK, OPS GC1 OSM; AK, OPS GC1 Field O &M TL; AK, RES GP: est Wells Opt Engr Cc: AK, D &C Well Integrity Coordinator; King, Whit. -y; Bommarito, Olivia 0; Robertson, Daniel B (Alaska); Ramsay, Gavin; Stone, Christopher; ' ner, Carolyn J; Longden, Kaity; Phillips, Patti 3; Sayed, Mohamed; Holt, Ryan P (ASRC) Subject: Producers with sustained casi• pressure on IA and OA due to proration All, The following producers -re found to have sustained casing pressure on the IA during the proration 1/25/2011 PBU W-01A P TD 2031760 1/22/2011 TIO Pressures Plot Well: W-01 4,000 • :3,000 - T bg IA 2 - -111,- OA 0 OA 1 eas•-•••••••••••-immim......•••••••••••••–mimat —40-- 0 0 OA — on 1 - ift**********0.14,-.-.- 10/23/10 11/06/10 11120/10 12/04/10 12/18/10 01/01/11 01/15/11 TREE= 4- 1/16" CIW WELLHEAD = MCEVOY SAFETY Nil: WELL ANGLE > 70° @ 12352' * ** ACTUATOR = BAKER C VV-O 1 3-1/2" CHROME TBG*** KB. ELEV = 83.26' BF. ELEV = 53.81' I [ KOP = 1000' 120" CONDUCTOR H 110' 1- Max Angle = 96 @ 12573' I I I 1995' H3 -1/2" HES X NIP, ID =2.813 1 Datum MD = 12249' Datum TVD = 8800' SS GAS LIFT MANDRELS ST MD TVD DEV TYPE VLV LATCH PORT DATE 113 -3/8" CSG, 72 #, L -80, ID = 12.347" I-! 2933' 1-1 8 3690 3198 46 MMG DOME RK 10 06/15/10 7 6242 4795 54 MMG DOME RK 12 06/15/10 6 7945 5800 51 MMG DMY RK 0 06/01/10 Minimum ID = 1.92" c 11762" ' I 5 8705 6296 47 MMG DOME RK 12 06/15/10 TOP OF 2-3/8" LINER 1`il 4 9436 6811 43 MMG DMY RK 0 06/01/10 3 10103 7299 45 MMG DOME RK 16 06/15/10 2 10802 7800 43 MMG SO RK 22 06/15/10 1 11343 8196 42 MMG DMY RK 0 06/01/10 3 -1/2" SLB SAPPHIRE NDPG -I 11413' I • PRESSURE GAUGE, ID = 2.992" ® ' 11479' H3 -1/2" HES X NIP, ID = 2.813 1 Z x L 11509' I- 1 9 -5 /8 " X 3 -1/2" HES TNT PKR, ID = 2.949" , 1 I 11546' H3-1/2" HES X NIP, ID = 2.813 1 3 -1/2" TBG, 9.2 #, 13CR -80 VAM TOP -I 11639' 1 ' I 11608' H 3 -1/2" HES X NIP, ID = 2.813 .0087 bpf, ID = 2.992" 3 -1/2" TUBING STUB (05/04/10) H 11646' 1 r ' I 11654' H9-5/8" X 3-1/2" UNIQUE OVERSHOT I 11672' 1- 13 -1/2" OTIS SBR SEAL ASSY I � =� 11688' }- 19-5/8" X 3 -1(2" OTIS PKR, ID = 3.85" 1 FISH: 6 METAL COLLETS & H -11734 1 3 RUBBER ELMENTS (07/02/10) j_'---1 11693' I- 1 4 -1/2" MILLOUT EXTENSION, ID = 3.958" 1 11699' I- 14 -1/2" X 3 -1/2" XO, ID = 2.992" 1 'TOP OF 2 -3/8" LNR I-L 11762' L '---.,.....! r L11731' H13-1/2" OTIS X NIP, ID = 2.75" 1 3 -1/2" TBG, 9.3 #, L -80 EUD 8RD, -I 11798' .0087 bpf, ID = 2.992" (TOP OF 5 -1/2" LNR (06/20/03) 1-111810' SLM 11762' 1 -12.6" BKR DEPLOY SLV, ID = 1.92" I ` \ 11764' 1- 13 -1/2" OTIS X NIP, ID = 2.75" I 19 -5/8" CSG, 47 #, L -80, ID = 8.681" H 12027 BEHIND I 11798' H3 -1/2" WLEG, ID= 2.992" I CT LNR PERFORATION SUMMARY ` I 11806' 1 ELMD TT LOGGED 08/11/92 I REF LOG: ANGLE AT TOP PERF: MILLOUT WINDOW (W -01A) 12143' - 12154' Note: Refer to Production DB for historical perf data SIZE SPF INTERVAL Opn /Sgz DATE 2 -3/8" SLTD 12284 - 12347 C 12/25/03 1 12347' -I BOT 0-RING SUB 1 11111111 TOP OF WHIPSTOCK 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 I CK 1� 12126' 111111111 111 N 1 1 RA TAG 1 12153' ►11 111 1 5 -1 /2" LNR, 17 #, L -80, .0232 bpf, ID = 4.892" H 12670' ►1•1 1 i 1 A 1 AiA1 ' , 2. ;a^ OPEN HOLE TD —1 13135' I 12 -3/8" LNR, 4.6 #, L -80, .0036 bpf, ID = 1.920" 1 12380' DATE REV BY COMMENTS DATE REV BY COMMENTS PRUDHOE BAY UNIT 10/13/88 N22E ORIGINAL COMPLETION 06/20/10 TAR/PJC GLV/ MIN ID CORRECTION WELL: W -01A 12/26/03 NORDIC 1 CTD SIDETRACK (W -01A) 07/06/10 KSB /SV FISH (07/02/10) PERMIT No: 2031760 06/02/10 D -141 RWO API No: 50 -029- 21866 -01 06/02/10 PJC DRLG DRA CORRECTIONS SEC 21, T11 N, R12E, 1158' FNL & 1189' FEL 06/04/10 DB /PJC FINAL DRLG CORRECTIONS 06/18/10 TAR/BLG GLV C/O (06/15/10) i BP Exploration (Alaska) • • Page 1 of 1 Regg, James B (DOA) From: AK, D &C Well Integrity Coordinator [ AKDCWelllntegrityCoordinator @bp.com] Sent: Friday, January 14, 2011 10:34 PM 1( J Z-4 1 l( To: Regg, James B (DOA); Maunder, Thomas E (DOA); Schwartz, Guy L (DOA); Cismoski, Doug A; Engel, Harry R; AK, D &C Well Services Operations Team Lead; AK, D &C Wireline Operations Team Lead; AK, OPS FS2 DS Ops Lead; AK, OPS FS2 Ops Lead; AK, OPS FS2 OSM; AK, OPS FS2 OSS; AK, RES GPB East Wells Opt Engr; AK, OPS GC3 Wellpad Lead; AK, OPS GC3 Facility & Field OTL; AK, OPS GC1 OSM; AK, OPS Prod Controllers; AK, OPS GC2 OSM; AK, OPS GC2 Ops Lead; AK, OPS GC2 Wellpad Lead; AK, OPS GC2 Field O &M TL; AK, OPS GC2 OSS; AK, OPS Well Pad DFT N2; AK, OPS GC1 Wellpad Lead; AK, OPS GC1 OSM; AK, OPS GC1 Field O &M TL; AK, RES GPB West Wells Opt Engr Cc: AK, D &C Well Integrity Coordinator; King, Whitney; Bommarito, Olivia 0; Robertson, Daniel B (Alaska); Ramsay, Gavin; Stone, Christopher; Kirchner, Carolyn J; Longden, Kaity; Phillips, Patti J; Sayed, Mohamed; Holt, Ryan P (ASRC) Subject: Producers with sustained casing pressure on IA and OA due to proration All, The following producers were found to have sustained casing pressure on the IA during the proration January 12 -14. The immediate action is to perform a TIFL on each of the wells and evaluate for IA repressurization. If any of the wells fail the TIFL, a follow up email will be sent to the AOGCC for each individual well. 11 -05A (PTD #1961570) C -15A (PTD #2090520) E -17A (PTD #2042040) E -27A (PTD #1990590) #210.870) AV -01 A PT D #2031761 Y -16A (' ' #21 160) W -21A (PTD #2011110) W -25A (PTD #2091020) W -38A (PTD #2021910) The following producers were found to have sustained casing pressure on the OA during the proration January 12 -14. The immediate action is to perform an OA repressurization test and evaluate if the IAxOA pressure is manageable by bleeds. If the IAxOA communication is unmanageable, a follow up email will be sent to the AOGCC notifying you of the remedial plan. 09 -34A (PTD #1932010) M -21A (PTD #1930750) N -22B (PTD #2061610) All the wells listed above will be classified as Not Operable until start-up operations commence and are stable or the well passes a pressure test proving integrity. After start -up, the wells will then be reclassified as Under Evaluation with POP parameters to prevent any over - pressure incidents. Please call with any questions or concerns. Thank you, Torin Roschinger (alt. Jerry Murphy) Well Integrity Coordinator Office (907) 659 -5102 Harmony Radio x2376 Cell (406) 570 -9630 Pager (907) 659 -5100 Ext. 1154 1/24/2011 STATE OF ALASKA ALASK~L AND GAS CONSERVATION COMMISlN REPORT OF SUNDRY WELL OPERATIONS 1. Operations Performed: ^ Abandon ®Repair Well ^ Plug Perforations ^ Stimulate ^ Re-Enter Suspended Well ^ Alter Casing ®Pull Tubing ^ Perforate New Pool ^ Waiver ^ Other ^ Change Approved Program ^ Operation Shutdown ^ Perforate ^ Time Extension 2. Operator Name: 4. Well Class Before Work: .Permit To Drill Number: BP Exploration (Alaska) Inc. ®Development ^ Exploratory 203-176 3. Address: ^ Service ^ Stratigraphic .API Number: P.O. Box 196612, Anchorage, Alaska 99519-6612 50-029-21866-01-00 7. Property Designation: ~ 8. Well Name and Number: ~ ADL 047451 PBU W-01A 9. Field /Pool(s): ~ Prudhoe Bay Field / Prudhoe Bay Oil Pool 10. Present well condition summary Total depth: measured 13135' feet true vertical 8836' feet Plugs (measured) None Effective depth: measured 13135' feet Junk (measured) 11734' true vertical 8936' feet Casing Length Size MD TVD Burst Collapse Structural Conductor 110' 20" 110' 110' Surface 2934' 13-3/8" 2934' 2684' 4930 .2270 Intermediate 12027' 9-5/8" 12027' 8706' 6870 4760 Production Liner 362' 5-1/2" 11781' -12143' 8520' - 8797' 7740 6280 Liner 618' 2-3/8" 11762' - 12380' 8506' - 8933' 11200 11780 r Perforation Depth: Measured Depth: 12284' - 12347' True Vertical Depth: 8894' - 8922' Tubing (size, grade, measured and true vertical depth): 3-1/2", 9.2# 13Cr801 L-80 11798' 8532' Packers and SSSV (type, measured and true vertical depth): 9_5/8" x 3-1/2" HES TNT' packer; 11509'; 8319'; 9-5/8" x 3-1/2" Otis packer 11688' 8451' 11. Stimulation or cement squeeze summary: ~('~ ~ Intervals treated (measured): ~ ~~~~ L" Treatment description including volumes used and final pressure: (~ 7 2Q~ ~~~ ~Q~-SSID~ ~I~S4«~ t ~ ~~~ Q' 3~~t,0 t ,: ~; 12. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 96 1,770 -0- 1,200 300 Subsequent to operation: 324 1,849 1,107 1,360 300 13. Attachments: ^ Copies of Logs and Surveys run 4. Well Class after work: ^ Exploratory ®Development ^ Service f W ll O rations ® D il R rt y epo o e pe a ® Well Schematic Diagram Well Status after work: ®Oil ^ Gas ^ WDSPL ^ GSTOR ^ WAG ^ GINJ ^ WINJ ^ SPLUG 16. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exert: Contact David Biork, 564-5683 N/A // Printed Name Terrie Hubble Title Drilling Technologist ~ ~7 O Prepared By NameMumber. Signature Phone 564-4 28 Date 7 ~d Terrie Hubble, 564-4628 Form 10-404 Revised 07/2009 ' RBDMS JUL 0 8 ~ ~-z~-i Submit Original only • • W-01 A, Well History (Pre Rig Workover) Date Summary 4/25/2010 WELL S/I ON ARRIVAL. TAG TOP OF PATCH W/ 2.74" GUAGE RING C~ 3444' SLM. PULL 3-1/2" BKR "KB" STRADDLE PATCH @ 3444' SLM (RECOVERED ALL ELEMENTS & SLIPS). TAG X NIPP C~ 11702' SLM, 11731' MD (+29' CORK) WITH 3 1/2" X-LINE, 3 1/2" X-CATCHER. LRS CURRENTLY LOADING IA &TBG. 4/26/2010 RAN WFD SLICK PUMP SETTING TOOL & 3 1/2" WRP, UNABLE TO PASS SLD SLV C~ 11593' SLM, 11622' MD, WRP SET AT 11593' SLM. PULLED WFD SLICK PUMP SETTING TOOL FROM 11572' SLM, FISHED 3 1/2" WRP FROM 11724' SLM. SET 3 1/2"WRP ON SLB E-FIRE C~3 11714' SLM, 11743' MD. 4/27/2010 LRS CMIT-TxIA TO 3500# (PASS). DUMPED 1 BAG OF SLUGGITS ON TOP OF WFD WRP C~1 11,714' SLM (11,743' MD), TOP OF SLUGGITS C~3 -11,703' SLM (11,732' MD). WELL LEFT S/I ON DEPARTURE. DSO NOTIFIED. 5/3/2010 INITIAL T/I/O: 475/540/100 2.5" POWER CUTTER, CUT DEPTH: 11646'. CCL TO SHOT: 6.3'. CCL STOP DEPTH: 11639.7'. FINAL T/I/O: 475/550/100 JOB COMPLETED. 5/7/2010 T/IA/OA= SI/500/0 Temp=Sl PPPOT-T (PASS) PPPOT-IC (FAIL) (Pre RWO) PPPOT-T : RU 1 HP BT onto THA test void 1800 psi bled to 0 psi, flushed void till clean returns achieved. Pressure void to 5000 psi for 30 minute test, 4900/ 15 minutes, 4900/ 30 minutes. Bled void to 0 psi, RD all test equipment. Cycle LDS "Standard" all moved with no problems and are in good visual condition. PPPOT-IC : RU 1 HP BT onto IC test void 500 psi bled to 0 psi, flushed void till clean returns achieved. Pressure void to 3500 psi for 30 minute test, 3000/ 15 minutes, 2000/ 30 minutes. Bled void to 0 psi. Cycle LDS "Standard" all moved with no problems and are in good visual condition. (2nd test) 3000/ 15 Min ~~nni Rn min Rll all tact aniiinmant 5/9/2010 T/I/0= 500/500/20. Temp= SI. Circ well. (RWO prep) Pumped 2 bbls neat and 1235 bbls Sea Water down tbg taking returns from IA to flowline on W-02. Then pumped 60 bbls diesel down IA taking returns from Tbo to W-02 flowline. Pumoino in progress. 5/10/2010 Pumped 95 bbls for a total of 155 bbls 120° diesel' down IA taking returns from tbg to W-02 flowline. Freeze Protected W-02 flowline w/6 bbls neat methanol. U-tubed Tbg x IA for 1 hr. Pressured up Tbg and IA to 1000 psi for 10 min test. Failed multiple tests. Consistently losing 380 psi in 10 min and taking Q 2 bbls to repressure back up. Pressure went on a vac after 40 min. Pumped 16.5 bbls diesel down tbg and IA durinn tests. Final WHP=360/360/80 5/11/2010 T/I/O=VACNAC/0 Temp=S/I Attempt to Pressure test TxIA to 1000 psi (Post Jet Cut) Pumped 23 bbls diesel down IA with centrifugal pump TxIA remain on vac. FW HP's=VACNAC/0 5/13/2010 WELL SI ON ARRIVAL. DRIFTED TBG W/ 3 1/2" BLB & 2.50" LIB, TAGGED TOP OF SLUGGITS/WRP C~? 11704' SLM. PICTURE OF SLUGGITS & SMALL AMOUNT OF DEBRIS ON LIB, RDMO. WELL S/I ON DEPARTURE. 5/14/2010 WELL SHUT IN ON ARRIVAL. INITIAL T/I/O: 60/0/100 PSI. PERFORM LEAK DETECT LOG WITH TECWELL AND LRS PUMPING. 5/15/2010 INITIAL T/I/O: 60/0/100 PSI. PERFORM LEAK DETECT LOG WITH TECWELL AND LRS PUMPING. LEAKS DETECTED AT 3483' AND 11689'.. FINAL T/I/O: 1460/IA-NO GAUGE/0 PSI. JOB COMPLETE. WELL LEFT SI. Page 1 of 1 i C~ North America -ALASKA - BP Page i of 2 Operation Summary Report ___ __ Common Well Name: W-O1_DIMS AFE No EvenYType: MOBILIZATION (MOB) Start Date: 5/21/2010 End Date: x4-OOQT9-E (487,000.00 ) Project: Prudhoe Bay Site: PB W Pad Rig Name/No.: DOYON 141 Spud Date/Time: 9/12/1988 12:0O:OOAM Rig Release: 6/2/2010 Rig Contractor: DOYON DRILLING INC. UWI: 500292186600 Active Datum: W-01A @83.Oft (above Mean Sea Level) Date From - To Hrs Task Code NPT NPT Depth Phase Description of Operations (hr) (ft) 5/21/2010 _ 19:00 - 00:00 5.00 MOB P PRE RIG DOWN AND PREPARATION TO MOVE TO W-01 A. MOVE THE RIG MODULES AND SUB BASE OFF OF THE WELL'TO THE END OF THE PAD. RIG OFF OF THE WELL AT 23:30. 5/22/2010 00:00 - 06:00 6.00 MOB P PRE PERFORM MAINTENANCE /PREPARE FOR MOVE ON THE RIG AND BEGIN WELDING BRACKETS FOR THE COMMUNICATIONS ANTENNA ON THE SUB STRUCTURE. 06:00 - 12:00 6.00 MOB P PRE COMPLETE' MOUNTING THE COMMUNICATIONS BRACKETS ON THE RIG. BEGIN INSTALLING COMMUNICATIONS CABLES AND SYSTEM. WORK THROUGHOUT THE RIG ON CLEANING UP HAMMER UNIONSAND CHANGING OUT DAMAGED ONES. ALSO SCRUB THROUGHOUT THE DIFFERENT MODULES AND PERFORM MAINTENANCE ON THE MOTORS. 12:00 - 18:00 6.00 MOB N WAIT _ ~ PRE WORK THROUGHOUT THE RIG ON CLEANING UP ~ HAMMER UNIONS AND CHANGING OUT DAMAGED ONES. ALSO SCRUB THROUGHOUT ~ ) THEbIFFERENT MODULES AND PERFORM MAINTENANCE ON THE MOTORS. MOVE RIG MATS TO MOBILE PAD AND W-PAD. _ 18:00 - 00:00 6.00 `MOB. N WAIT `PRE CONTINUE TO WORK ON THE HAMMER UNIONS AND MOTORS ON THE RIG. ALSO CHANGING OUT PARTS ON THE TEST PUMP AND VALVES ON THE RIG. CLEANING AND SCRUBBING AROUND THE RIG. MOVE RIG MATS TO MOBILE PAD AND W-PAD. _ 5/23/2010 00:00 - 06:00 6.00 MOB N WAIT PRE CONTINUE TO PERFORM MAINTENANCE ON THE RIG WHILE WAITING ON THE PAD PREP AND THE ROAD CONDITIONS TO IMPROVE. MOVE RIG MATS TO MOBILE PAD AND W-PAD. 06:00 - 12:00 6.00 MOB N WAIT PRE CONTINUE TO PERFORM MAINTENANCE ON THE RIG. CHANGE OUT HAMMER UNION ON THE RIG FLOOR, SECURE THE LOADS IN THE PIPE SHED, REPAIR CHOKE VALVE #2 ON THE CHOKE I MANIFOLD. CONTINUE TO MOBILIZE EQUIPMENT TO W-PAD. 12:00 - 00:00 12.00 ~ MOB N WAIT PRE CLEAN THE SUB- STRUCTURE, RE-SKIN THE INTERCONNECT ON SUB-STRUCTURE. ALSO REPLACE PATCH IN THE PITS THAT WAS PREVIOUSLY DAMAGED. CONTINUE TO MOBILIZE EQUIPMENT TO W-PAD. 5/24/2010 00:00 - 06:00 6.00 MOB N WAIT PRE CONTINUE TO PERFORM MAINTENANCE ON THE RIG WHILE WAITING ON THE PAD PREP AND THE ROAD CONDITIONS TO IMPROVE. MOVE RIG - ~ MATS TO MOBILE PAD AND W-PAD. Printed 6/11/2010 3:35:29PM North America -ALASKA - BP Page 2 of 2 Operation Summary Report Common Well Name: W-01 DIMS AFE No Event Type: MOBILIZATION (MOB) Start Date: 5/21/2010 End Date: x4-OOOT9-E (487,000.00 ) Project: Prudhoe Bay Site: PB W Pad Rig Name/No.: DOYON 141 Spud Date/Time: 9/12/1988 12:0O:OOAM Rig Release: 6/2/2010 Rig Contractor: DOYON DRILLING INC. UWI: 500292186600 Active Datum: W-01A @83.Oft (above Mean Sea Level) Date From - To Hrs Task Code NPT NPT Depth Phase Description of Operations (hr) (ft) _ 06:00 - 12:00 6.00 MOB P PRE PERFORM MAINTENANCE ON THE RIG, WHILE TRANSPORTING MISC. RIG EQUIPMENT AND SUPPLIES TO W-PAD. PREP. THE CAMP FOR THE MOVE TO MOBILE PAD. 12:00 - 18:00 6.00 MOB P PRE MOVE THE CAMP FROM DS-7 TO MOBILE PAD. 18:00 - 00:00 6.00 MOB P PRE MOVETHE PIT COMPLEX AND MOTOR COMPLEX ~ TO W-PAD. _ 5/25/2010 ~ 00:00 - 04:00 4.00 MOB P PRE SPOT7HE PIT COMPLEX AND MOTOR COMPLEX ON W-PAD. DRIVE FROM W-PAD TO DS-7 AND I PREPARE TO MOVE THE SUB STRUCTURE, i PIPESHED AND ROCKWASHER. 04:00 - 12:00 8.00 MOB P , PRE MOVE THE SUB STRUCTURE, PIPESHED, ROCKWASHER, AND 4" DRILLPIPE FROM DS-7 TO W-PAD. ~ SPOT EQUIPMENT ON PAD WHILE WORKING ON ~ REMOVING THERMO-TUBE FROM BEHIND ~ WELLHEAD 12:00 21.30 _ 9.50 MOB N WAIT PRE CONTINUE TO WAIT FOR THERMO-TUBE - REMOVAL WHILE WAITING, UNLOAD PIPE SHED, SEND CREW BACK TO DS-07 TO MOVE REMAINING EQUIPMENT AND PARTS TO W-PAD, GCI WORKED ON COMS TO RIG -- - 21:30 - 22:30 1.00 - MOB P PRE LAY HERCULITE AND RIG MATS AROUND CELLAR AREA ~ SPOT CELLAR TANK, NEW TREE AND ADAPTER BEHIND WELL _ 22:30 - 00:00 1.50 MOB P PRE RIG UP TWO CATS TO SUB AND SPOT OVER I WELL 5/26/2010 00:00 - 01:00 1.00 ~ MOB P PRE FINISH SPOTTING SUB OVER WELLHEAD 01:00 - 10:00 9.00 MOB i P PRE CONTINUE TO SPOT REMAINING RIG MODULES AND HOOK UP SAME. HARDLINE CREW SPOTTED SLOP TANK CLOSER TO WELL AND RIG UP HARDLINE FROM WELLHEAD TO TANK. ~ SIMOPS: GCI WORKING ON COMMUNICATIONS IN RIG 10:00 - 12:00 2.00 MOB P PRE RIG UP HOSES AND VALVES TO WELLHEAD AND TREE FOR CIRC OUT. ~ RU LUBRICATOR TO PULL BPV _ 12:00 - 12:30 0.50 MOB P PRE TEST LUBRICATOR TO 500 PSI -GOOD TEST _ PULL BPV WITH LUBRICATOR. LD BPV. RD 1 i LUBRICATOR PRESSURES ON WELLHEAD: T= 0, IA= 100, OA= 0 Printed 6/11/2010 3:35:29PM • North America -ALASKA - BP Page 1 of 11 Operation Summary Report __ Common Well Name: W-01 DIMS AFE No Event Type: WORKOVER (WO) Start Date: 5/22/2010 End Date: 6/2/2010 x4-OOOT9-E (1,650,000.00 ) Project: Prudhoe Bay Site: PB W Pad Rig Name/No.: DOYON 141 Spud Date/Time: 9/12/1988 12:0O:OOAM Rig Release: 6/2/2010 Rig Contractor: DOYON DRILLING INC. UWI: 500292186600 Active Datum: W-01A @83.Oft (above Mean Sea Level) Date From - To Hrs Task Code NPT NPT Depth Phase Description of Operations (hr) (ft) 5/26/2010 12:30 - 13:30 1.00 KILLW P DECOMP RIG UP TO REVERSE CIRCULATE. HOOK UP TO TAKE RETURNS TO OPEN TOP TANK 13:30 - 20:00 6.50 MOB P DECOMP BRING ON SEAWATER TO PITS I SIMOPS: MU NEW TREE TO ADAPTER FLANGE IN CELLAR. CONDUCT SAFETY AUDIT WITH BILL HOPKINS AND ALLEN GRAFF. GCI CONTINUE TO WORK ON RIG COMMUNICATIONS. _ 20:00 - 21:30 1.50 KILLW P DECOMP ' REVERS'E CIRCULATE DIESEL FREEZE PROTECT OUT ORTUBING. 1 - 3 BPM, 300-500 PSI -PUMPED 42 BBLS. LINEUP TO CIRCULATE LONG WAY AND CIRC WELL - 2.5 BPM, 1,200 PSI ~ -PRESSURE INCREASING TO 2,800 PSI - __- 21:30 - 22:00 _ 0.50 KILLW P DECOMP SHUT DOWN PUMPS AND SHUT IN WELL. - INSPECT LINES AT WELLHEAD FOR DEBRIS OR ~ OTHER RESTRICTION -NONE FOUND RIG UP TO CIRCULATE AGAIN _ 22:00 - 00:00 2.00 KILLW P DECOMP CONTINUE CIRCULATING WELL TO CLEAN SEAWATER ~ - 2.0 BPM, 2,400-2,900 PSI - 312 BBLS PUMPED AT MIDNIGHT, 282 BBLS RECOVERED (30 BBLS LOST TO WELL) 5/27/2010 00:00 - 04:00 4.00 KILLW P DECOMP CONTINUE CIRCULATING LONG WAY, DISPLACING TO CLEAN SEAWATER - 2 BPM, 2,600-2,900 PSI - TOTAL LOSSES DURING CIRC: 64 BBLS _ 04:00 - 05:00 1.00 i KILLW P DECOMP MONITOR WELL FOR FLOW ~ - NO FLOW I ESTABLISH LOSS RATE - 0 LOSSES STATIC 05:00 - 05:30 0.50 WHSUR P DECOMP REMOVE SWAB CAP AND OPEN SWAP VALVE T-BAR IN TWC 05:30 - 06:00 0.50 WHSUR P DECOMP RIG UP TO PRESSURE TEST TWC i I TEST FROM ABOVE TO 3,500 PSI FOR 10 CHARTED MINUTES TEST FROM BELOW TO 1,000 PSI FOR 10 CHARTED MINUTES -GOOD TESTS 06:00 - 08:30 2.50 WHSUR P DECOMP DRAIN HANGER VOID DEPRESSURIZE CONTROL LINE N/D DOWN 3-1/8" 5K CAMERON TREE AND REMOVE FROM CELLAR. 08:30 - 10:30 ~ 2.00 BOPSUR P DECOMP N/U 13-5/8" HYDRIL BOP STACK CONFIGURED WITH 3-1/2" X 6" VBRS ON TOP, BLIND SHEAR'S IN CENTER, MUD CROSS, AND 4" RAMS ON BOTTOM. Printed 6/1112010 3:36:OOPM r~ North America -ALASKA - BP Page °f ~ ~ Operation Summary Report Common Well Name: W-01 DIMS AFE No Event Type: WORKOVER (WO) Start Date: 5/22/2010 End Date: 6/2/2010 x4-OOOT9-E (1,650,000.00 ) i Project: Prudhoe Bay Site: PB W Pad ~ Rig Name/No.: DOYON 141 Spud Date/Time: 9/12/1988 12:0O:OOAM Rig Release: 6/2/2010 Rig Contractor: DOYON DRILLING INC. (UWI: 500292186600 ___ Active Datum: W-01A @83.Oft (above Mean Sea Level) Date From - To Hrs Task Code NPT NPT Depth Phase Description of Operations (hr) (ft) 10:30 - 11:30 1.00 BOPSUR P DECOMP R/U TEST ASSEMBLY AND FILL BOP STACK AND CHOKE MANIFOLD. 11:30 - 14:30 3.00 BOPSUR P _ DECOMP TEST BOPE TO 250 PSI LOW AND 3,500 PSI HIGH PRESSURE. HOLD EACH TEST FOR 5 MINUTES ON THE CHART. TEST ANNULAR WITH 3-1/2" TEST JOINT, TEST VBR'S WITH 3-1/2" TEST JOINT AND 4" TEST JOINT. TEST VBR'S, BLIND SHEAR, ANNULAR, CHOKE MANIFOLD VALVES, MANUAL KILL AND CHOKE LINE VALVES; HCR KILL AND CHOKE LINE VALVES, FLOOR VALVES, UPPER AND LOWER (BOP VALVES ON TOP DRIVE. -PERFORM ACCUMLATOR TEST. -LOWER (BOP TEST FAILED. -AOGCC WITNESS OF TEST WAS WAIVED BY ~ CHUCK SCHEVE. -TEST WAS WITNESSED BY BP WSL BILLY BURSON AND DOYON TOOLPUSHER CHARLIE ~ HUNTINGTON. ~ -TESTED H2S AND LEL ALARMS. 14:30 - 15:30 1.00 i _ BOPSUR P f _ DECOMP .R/D TEST ASSEMBLIES ~ ~ DRAIN AND BLOW DOWN CHOKE MANIFOLD, KILL LINE AND CHOKE LINE. _ 15:30 - 16:30 1.00 BOPSUR N RREP DECOMP CHANGE OUT LOWER (BOP VALVE ON TOP DRIVE -(BOP VALVE FAILED ON BOP TEST. 16:30 - 17:30 1.00 BOPSUR N RREP DECOMP TEST LOWER (BOP TO 250 PSI LOW / 3,500 PSI ~ HIGH PRESSURE FOR 5 MINUTES EACH ON ~ ( CHART -GOOD TEST 17:30 - 18:30 1.00 WHSUR P DECOMP RIG UP DUTCH RISER AND DSM LUBRICATOR- TEST TO 500 PSI _ -GOOD TEST __ 18:30 - 19:00 0.50 WHSUR P DECOMP PULL TWC 19:00 - 20:00 1.00 WHSUR P DECOMP RIG DOWN DSM LUBRICATOR AND DUTCH RISER FILL HOLE -15 BBLS TO FILL 20:00 - 22:00 2.00 PULL P DECOMP PJSM ON PULLING COMPLETION SCREW INTO TUBING HANGER AND PULL TO RIG FLOOR -PUW 120K TO UNSEAT HANGER i -PUW 120K TO BRING HANGER TO FLOOR ~ LD HANGER 22:00 - 00:00 2.00 PULL P ~ DECOMP .BREW INTO TUBING AND CIRCULATE _ BOTTOMS-UP ~ - 5 BPM, 750 PSI WHILE CIRCULATING, RIG UP SCHLUMBERGER SPOOLING UNIT ~O~ Printed 6/11/2010 3:36:OOPM r~ i North America -ALASKA - BP Page 3 of 11 Operation Summary Report Common Well Name: W-01 DIMS AFE No Event Type: WORKOVER (WO) Start Date: 5/22/2010 End Date: 6/2/2010 x4-OOOT9-E (1,650,000.00 ) Project: Prudhoe Bay Site: PB W Pad Rig Name/No.: DOYON 141 Spud Date/Time: 9/12/1988 12:0O:OOAM Rig Release: 6/2/2010 Rig Contractor: DOYON DRILLING INC. UWI: 500292186600 Active Datum: W-01A @83.Oft (above Mean Sea Level) Date From - To i Hrs Task Code NPT NPT Depth Phase Description of Operations (hr) (ft) 5/28/2010 00:00 - 12:00 12.00 PULL P DECOMP PULL 3-1/2" 9.3# 1-80. EUE TUBING FROM 11,646' -TUBING IS IN GOOD CONDITION -RECOVERED SSSV NIPPLE ASSEMBLY, 33 CONTROL LINE CLAMPS, 2 SS BANDS - ENCAPSULATED CONTROL LINE WAS IN GOOD CONDITION RECOVERED 361 JOINTS OF 3-1/2" 9.3# L-80 EUE TUBING, 1 SLIDING SLEEVE, 5 GLM'S AND A i 9.03' CUT JOINT. GOOD CUT, FLARE ON CUT = I 4,02" OD. CALCULATED HOLEFILL = 35 BBLS, ACTUAL HOLEFILL= 36.5 BBLS. 12:00 - 12:30 0.50 PULL P DECOMP CLEAR AND CLEAN RIG FLOOR. 12:30 - 14:00 1.50 PULL P DECOMP SET MCEVOY SSH 13-5/8" TEST PLUG AND RUN IN LOCKDOWN SCREWS TO ENERGIZE TEST PLUG. -TEST LOWER PIPE RAMS TO 250 PSI LOW AND 3,500 PSI HIGH FOR 5 MINUTES EACH ON THE CHART. -GOOD TEST. -TEST WAS WITNESSED BY BP WSL BILLY BURSON AND DOYON TOOLPUSHER CHARLIE HUNTINGTON. -BACK OUT LOCK DOWN SCREWS AND PULL , TEST PLUG. 14:00 - 15:30 1.50 WHSUR P - DECOMP M/U MCEVOY PACK-OFF RUNNING TOOL AND LATCH INTO MCEVOY 9-5/8" YBT MANDREL PACK-OFF. -WHILE BACKING OUT LOCK DOWN SCREWS IT GAVE INDICATION OF CASING GROWTH. -RAN LOCK DOWN SCREWS BACK IN. ~ -DISCUSSED OPTIONS WITH WELL ENGINEER. DECISION MADE TO P/U DRESS-OFF BHA AND RIH TO ABOVE TUBING STUB @11,646' AND A RING OFF ON STORM PACKER._, _ 15:30 - 18:00 2.50 CLEAN P DECOMP P/U BHA #1, 3-1/2" DRESS-OFF BHA CONSISTING OF: - 8-1 /2" X 3-9/16" WASHPIPE SHOE -CROSSOVER BUSHING - 12' WASHPIPE EXTENSION - WASHOVER BOOT BASKET - 3-1/2" TUBING DRESS OFF MILL i - DOUBLE-PIN SUB - 9-5/8" CASING SCRAPER -BIT SUB - 4-3/4" LUB. BUMPER SUB - 4-3/4" OIL JAR - 3-1/2" PUMP OUT SUB -CROSSOVER SUB - 9 4-3/4"DRILL COLLARS TOTAL BHA LENGTH: 323.21' 18:00 - 00:00 6.00 CLEAN P DECOMP RIH ON 4" DRILLPIPE FROM 323' -SINGLE IN FROM PIPE SHED Printed 6/11/2010 3:36:OOPM i North America -ALASKA - BP Page 4 of 11 Operation Summary Report Common Well Name: W-01 DIMS AFE No Event Type: WORKOVER (WO) Start Date: 5/22/2010 End Date: 6/2/2010 x4-OOOT9-E (1,650,000.00 ) ~ _ _ Project: Prudhoe Bay Site: PB W Pad Rig Name/No.: DOYON 141 Spud Date/Time: 9/12/1988 12:0O:OOAM Rig Release: 6/2/2010 Rig Contractor: DOYON DRILLING INC. UWI: 500292186600 Active Datum: W-01A @83.Oft (above Mean Sea Level) Date From - To Hrs Task Code NPT NPT Depth Phase Description of Operations (hr) (ft) 5/29/2010 _ 00:00 - 02:00 2.00 CLEAN P DECOMP CONTINUE TO RIH WITH BHA #1 ON 4" DRILLPIPE TO 11,417' -SINGLE IN FROM PIPE SHED 02:00 02:30 0.50 CLEAN P ; DECOMP CLEAN AND CLEAR RIG FLOOR 02:30 - 03:30 1.00 DHB P DECOMP ~rK i iP HALLIBURTON STORM PACKER AND RIH ON 3 JTS OF DRILLPIPE w ~~ ESTABLISH UP AND DOWN WEIGHTS - PUW 200K, SOW 125K SET STORM PACKER AND RELEASE FROM TOOL LAY DOWN 3 JTS DRILLPIPE PLUS RUNNING TOOL -STORM PACKER USED TO KEEP CASING FROM ~ GROWING DURING PACKOFF CHANGEOUT 03:30 - 04:00 ~ 0.50 DHB P DECOMP CLOSE BLIND/SHEARS AND TEST AGAINST STORM PACKER TO 1,000 PSI FOR 10 CHARTED MINUTES -GOOD TEST I RIG DOWN TEST EQUIPMENT _ 04:00 - 05:00 1.00 WHSUR P DECOMP RIG" UP TO PULL MCEVOY PACKOFF - RIH AND J INTO PACKOFF. BOLDS. PULL PACKOFF TO FLOOR - PACKOFF BROKE FREE WITH 30K OVERPULL MAKE UP NEW PACKOFF AND RIH -NEEDED SK TO PUSH PACKOFF INTO CASING SPOOL - __ _ __ 05:00 - 07:00 2.00 WHSUR P DECOMP RILDS. PLASTIC PACK PACKOFF VOID AND ~ TEST TO 5,000 PSI FOR 30 MINUTES -GOOD TEST RIG DOWN PACKOFF TESTING EQUIPMENT 07:00 - 07:30 0.50 WHSUR P DECOMP SET 8-1/2" ID WEAR BUSHING AND RUN IN 4 LOCK DOWN SCREWS. 07:30 - 09:00 1.50 WHSUR P DECOMP p/U HES RUNNING TOOL AND 3 JOINTS OF 4" XT-39 DRILLPIPE. -LATCH INTO STORM PACKER WITH 21 TURNS TO THE RIGHT. -RELEASE AND LAY DOWN STORM PACKER AND RUNNING TOOL. 09:00 - 10:00 1.00 CLEAN P DECOMP RIH PICKING UP 4" XT-39 DRILLPIPE FROM PIPESHED TO 11,636'. -ESTABLISH PARAMETERS, P/U 215K, S/O 118K, ROT WT.160K, 3 BPM WITH 200 PSI, 60 RPM ~ WITH 8-9K TORQUE. ~ -LOCATE TOP OF 3-1/2"TUBING STUB AT i 11,643' -MADE MULTIPLE PASSES WITH CASING SCRAPER OVER PACKER SETTING DEPTH FROM 11,417-11,510' Printed 6/11/2010 3:36:OOPM North America -ALASKA - BP Page 5 °f ~ ~ Operation Summary Report --- -- - Common Well Name: W-01 DIMS AFE No Event Type: WORKOVER (WO) Start Date: 5/22/2010 End Date: 6/2/2010 x4-OOOT9-E (1,650,000.00 ) i _____ Project: Prudhoe Bay Site: PB W Pad j Rig Name/No.: DOYON 141 Spud Date/Time: 9/12/1988 12:0O:OOAM Rig Release: 6/2/2010 Rig Contractor: DOYON DRILLING INC. UWI: 500292186600 Active Datum: W-01A @83.Oft (above Mean Sea Level) Date From - To Hrs Task Code NPT NPT Depth Phase Description of Operations (hr) (ft) 10:00 - 11:00 1.00 CLEAN P DECOMP DRESS 3-1/2" TBG STUB FROM 11,643' TO 11 644'. -60 RPM WITH 8 - 10K TORQUE, 2-SK WOM, 6 BPM WITH 770 PSI. -15' OF SWALLOW ON ASSEMBLY, CLEANED OUT TO 11,659'. =ABLE TO SLIDE OVER TOP OF STUB WITHOUT ROTATING OR CIRCULATING. _ -FINAL PUW: 210K, SOW 155K _ 11:00 - 13:00 2.00 CLEAN P DECOMP PUMP 30 BBL HIGH VIS SWEEP FOLLOWED BY CLEAN'SEAWATER. -- -- 13:00 - 13:30 0.50 CLEAN -- P -. DECOMP FLOW CHECK WELL -NOfLOW START POOH FROM 11„646'. SEE 15K OVERPULL INCREASING TO 40K WITH CORRESPONDING LOSS OF FLUID. RIH 20' AND FLUID LOSSSTOPPED. TAG TOP OF STUB AGAIN AT 11,644'. POOH AGAIN WITH NO ADDITIONAL DRAG - PUW 210K 13:30 - 18:00 4.50. CLEAN P DECOMP POOH FROM 11,644' TO BHAAT 323' - RACK BACK DRILLPIPE IN DERRICK ~ 18:00 - 21:00 3.00 CLEAN P DECOMP LAY DOWN BHA #1 - CALC HOLE FILL FOR TRIP: 66 BBLS; ACTUAL FILL: 68.5 BBLS CLEAN AND CLEAR RIG FLOOR _ _ ______ j 21:00 - 23:00 2.00 CLEAN P DECOMP p/U BHA #2; WRP RETRIEVAL BHA CONSISTING ~ OF: - 8-1/8" CUT LIP GUIDE -CROSSOVER BUSHING - 5-3/4" WASHPIPE EXTENSION -WRP RETRIEVAL TOOL FOR 3-1/2" WRP -SHEAR PIN GUIDE ASSEMBLY - 4 JTS 2-1/16" 4.5# L-80 CS HYDRIL TUBING -CROSSOVER SUB - 4-3/4" LUB. BUMPER SUB - 3-1/2"PUMP-OUT SUB -CROSSOVER SUB TOTAL BHA LENGTH: 149.65' _ 23:00 - 00:00 1.00 CLEAN P DECOMP RIH ON DRILLPIPE FROM 149' TO 1,749' AT CHANGEOUT I - 60' PER MINUTE RUNNING SPEED PER BAKER I ~ FISHING 5/30/2010 00:00 - 03:30 3.50 CLEAN _ P __ _ DECOMP CONTINUE TO RIH WITH BHA #2 ON DRILLPIPE - 60' PER MINUTE RUNNING SPEED PER BAKER _ FISHING 03:30 - 05:30 2.00 CLEAN N RREP DECOMP LOST ELECTRICAL POWER TO TOP DRIVE. DIAGNOSED MAIN POWER CONNECTION ON SERVICE LOOP DISCONNECTED. INSPECT LINES FOR DAMAGE, RECONNECT POWER AND TEST. Printed 6/11/2010 3:36:OOPM ~~ North America -ALASKA - BP Page 6 of 11 Operation Summary Report Common Well Name: W-01 DIMS AFE No Event Type: WORKOVER (WO) Start Date: 5/22/2010 End Date: 6/2/2010 x4-OOQT9-E (1,650,000.00 ) Project: Prudhoe Bay Site: PB W Pad Rig Name/No.: DOYON 141 Spud Date(Time: 9/12/1988 12:0O:OOAM Rig Release: 6/2/2010 Rig Contractor: DOYON DRILLING INC. UWI: 500292186600 Active Datum: W-01A @83.Oft (above Mean Sea Level) Date From - To ( Hrs Task Code NPT NPT Depth Phase Description of Operations (hr) (ft) _ 05:30 - 08:00 2.50 CLEAN P DECOMP CONTINUE TO RIH WITH BHA #2 ON DRILLPIPE - 60' PER MINUTE RUNNING SPEED PER BAKER FISHING -TAG UP AT 11,736' P/U 200K, S/O 115K 08:00 - 09:30 1.50 CLEAN P DECOMP ESTABLISH CIRCULATION AT 3 BPM WITH 700 PSI. ATTEMPT TO REVERSE CIRCULATE DOWN ON SLUGGITS, PACKED OFF, CIRCULATE THE LONG. WAY AND WAS ABLE TO CIRCULATE AT 4 BPM AT 700 PSI. WASH DOWN -5' AND ~ PRESSURE CAME UP TO 2,200 PSI. SET 5K DOWN ON-WRP. DID NOT EQULIZE OR LATCH WRP. MAKE REPEATED ATTEMPTS TO EQUILIZE AND LATCH WRP. TRIED TO LATCH WITHOUT PUMP AND WORKED UP TO 6 BPM. TRIED SETTING ADDITIONAL WEIGHT 10K. COULD SEE PRESSURE INCREASE WHEN SETTING DOWN. 09:30 - 12:30 3.00 CLEAN P DECOMP PULL UP TO 1.1,714' AND CIRCULATE BOTTOMS UP AT 6 BPM WITH 1,000 PSI. -DISCUSS OPTIONS WITH WELL ENGINEER DAVE BJORK AND GPB WL AND COMPLETIONS ~ SUPERVISOR JERRY MIDDENDORF. DECISION MADE TO LEAVE WRP IN HOLE AND COMPLETE WELL -SAW SOME SLUGGITS ON BOTTOMS UP. --- _ ~ _ 12:30 - 20:30 8.00 CLEAN - P _ DECOMP MONITOR WELL, WELL STATIC ~ -POOH LAYING DOWN 4" XT-39 DRILLPIPE THROUGH PIPESHED. 20:30 - 21:30 1.00 CLEAN- P DECOMP LEVEL RIG SUB BASE TO RE-CENTER RIG OVER WELL - RIG SETTLING ON SOFT PAD. NO LONGER CENTERED OVER WELL. 21:30 - 22:30 1.00 CLEAN P DECOMP BREAKOUT AND L/D BHA #2 - CALC HOLE FILL FOR TRIP: 65 BBLS; ACTUAL: 73 BBLS 22:30 - 23:00 0.50 CLEAN P DECOMP CLEAN AND CLEAR RIG FLOOR 23:00 - 00:00 1.00 CLEAN P ~ DECOMP PULL WEAR RING WHILE PULLING WEAR RING, ORGANIZE COMPLETION JEWELERY IN PIPE SHED ACCORDING TO RUNNING ORDER 5/31/2010 00:00 - 01:30 1.50 CLEAN P DECOMP REMOVE BHA #2 COMPONENTS FROM RIG FLOOR 01:30 - 03:00 1.50 RUNCMM P RUNCMP MOBILIZE TO RIG FLOOR AND RIG UP EQUIPMENT TO RUN CONPLETION - DOYON CASING TORQUE TURN EQUIPMENT - SINGLE JOINT COMPENSATOR - SCHLUMBERGER I-WIRE SPOOL AND CANNON CLAMPS FOR I-WIRE 03:00 - 03:30 0.50 RUNCOM P _ RUNCMP PJSM ON RUNNING COMPLETION Printed 6/11/2010 3:36:OOPM ~~ r1 North America -ALASKA - BP Page ~ of 11 Operation Summary Report Common Well Name: W-01 DIMS AFE No Event Type: WORKOVER (WO) Start Date: 5/22/2010 End Date: 6/2/2010 x4-OOQT9-E (1,650,000.00 ) Project: Prudhoe Bay Site: PB W Pad Rig Name/No.: DOYON 141 Spud Date/Time: 9/12/1988 12:0O:OOAM Rig Release: 6/2/2010 Rig Contractor: DOYON DRILLING INC. UWI: 500292186600 Active Datum: W-01A @83.Oft (above Mean Sea Level) Date From - To Hrs Task Code NPT NPT Depth Phase Description of Operations (hr) (ft) 03:30 - 04:30 1.00 RUNCMM P __ RUNCMP RUN 3-112" 9.2# 13CR-80 VAM TOP COMPLETION AS FOLLOWS: - 9-5/8" X 3-1/2" 9CR UNIQUE MACHINE OVERSHOT - 2 ROWS OF 4 SHEAR PINS - 3-1/2" 9.2# 13CR XO PUP, VAM TOP BOX X TCII PIN ~ -3-1/2" 9.2# 13CR XO PUP, TCII BOX X VAM TOP PIN - #1 3-1/2" HES X-NIPPLE 9CR 2.813" PKG BORE W/RHCSLEEVEINSTALLED -3-1/2" 9.2# 13CR XO PUP, VAM TOP BOX X TCII PIN - 1 JT 3-1/2" 9.2# 13CR`VAM TOP TUBING - 3-1/2" 9.2# 13CR XO-PUP, TCII BOX X VAM TOP PIN - #2 3-1/2" HES'X-NIPPLE 9CR 2.813" PKG BORE = 3-1/2" 9.2# 13CR XO PUP, VAM TOP BOX X TCII PIN - 3-1/2" 9.2# 13CR XO PUP, TCII BOX X VAM TOP -PIN - 9-5/8" X 3-1/2" HES TNT PERMANENT PRODUCTION PACKER - 3-1/2" 9.2# 13CR XO PUP, VAM TOP BOX X TCII PIN ~ ! - 3-1/2" 9.2# 13CR XO PUP, TCII BOX X VAM TOP ~ ~ i PIN - #3 3-1/2" HES X-NIPPLE 9CR 2.813" PKG BORE ~ - 3-1/2" 9.2# 13CR XO PUP, VAM TOP BOX X TCII PIN - 1 JT 3-1/2" 9.2# 13CR VAM TOP TUBING - 3-1/2" 9.2# 13CR XO PUP, TCII BOX X VAM TOP PIN - SCHLUMBERGER/CAMC~O NDPG-C SAPPHIRE GAUGE - 3-1/2" 9.2# 13CR XO PUP, VAM TOP BOX X TCII PIN ~ i -ALL CONNECTIONS BELOW PACKER WERE BAKERLOK'D -ALL CONNECTIONS ABOVE PACKER UTILIZED JET LUBE SEAL GUARD -CONNECTIONS TORQUED TO AND AVERAGE 2,900 FT-LBS -ALL TORQUE TURNED CONNECTIONS WERE RECORDED 04:30 - 05:00 0.50 RUNCMM P RUNCMP CONNECT I-WIRE TO SAPPHIRE GAUGE AND INSTALL IN MANDREL TEST I-WIRE CONNECTIVITY -GOOD TEST Printed 6/11/2010 3:36:OOPM ,~ North America -ALASKA - BP Page a or ~ i Operation Summary Report Common Well Name: W-01 DIMS AFE No Event Type: WORKOVER (WO) Start Date: 5/22/2010 ~ End Date: 6/2/2010 x4-OOOT9-E (1,650,000.00 ) Project: Prudhoe Bay Site: PB W Pad Rig Name/No.: DOYON 141 Spud Date/Time: 9/12/1988 12:0O:OOAM Rig Release: 6/2/2010 Rig Contractor: DOYON DRILLING INC. UWI: 500292186600 Active Datum: W-01A @83.Oft (above Mean Sea Level) Date From - To Hrs Task Code NPT NPT Depth Phase Description of Operations (hr) (ft) 05:00 - 00:00 19.00 RUNCOM P RUNCMP RUN 3-1/2" 9.2# 13CR-80 VAM TOP COMPLETION AS FOLLOWS: - 1 JT 3-1/2" 9.2# 13CR VAM TOP TUBING - 3-1/2" 9.2# 13CR XO PUP, TCII BOX X VAM TOP ~ PIN - #1 SCHLUMBERGER/CAMCO 3-1/2" X 1-1/2" MMG GLM W/DUMMY VALVE - 3-1/2" 9.2# 13CR XO PUP, VAM TOP BOX X TCII PIN - 16 JTS 3-1/2" 9.2# 13CR-80 VAM TOP TUBING 3-1/2" 9.2# 13CR XO PUP, TCII BOX X VAM TOP PIN #2SCHLUMBERGER/CAMCO 3-112" X 1-1/2" MMG GLM W/DUMMY VALVE - 3-1/2" 9.2# 13CR XO-PUP, VAM TOP BOX X TCII PIN - 21 JTS 3-1/2" 9.2# 13CR-SO VAM TOP TUBING 3-1/2" 9.2# 13CR XO PUP, TCII BOX X VAM TOP I ~ PIN - #3 SCHLUMBERGER/CAMCO 3-1/2" X 1-1/2" -MMG GLM W/DUMMY VALVE i ~ - 3-1/2" 9.2# 13CR XO PUP, VAM TOP BOX X TCII PIN - 20 JTS 3-1/2" 9.2# 13CR-80 VAM TOP TUBING - 3-1/2" 9.2# 13CR XO PUP, TCII BOX X VAM TOP PIN - #4 SCHLUMBERGER/CAMCO 3-1/2" X 1-1/2" MMG GLM W/DUMMY VALVE - 3-1/2" 9.2# 13CR XO PUP, VAM TOP BOX X TCII PIN - 22 JTS 3-1/2" 9.2# 13CR-80 VAM TOP TUBING - 3-1/2" 9.2# 13CR XO PUP, TCII BOX X VAM TOP PIN - #5 SCHLUMBERGER/CAMCO 3-1/2" X 1-1/2" MMG GLM W/DUMMY VALVE - 3-1/2" 9.2# 13CR XO PUP, VAM TOP BOX X TCII ~ PIN - 23 JTS 3-1/2" 9.2# 13CR-80 VAM TOP TUBING - 3-1/2" 9.2# 13CR XO PUP, TCII BOX X VAM TOP PIN - #6 SCHLUMBERGER/CAMCO 3-1/2" X 1-1/2" MMG GLM W/DUMMY VALVE - 3-1/2" 9.2# 13CR XO PUP, VAM TOP BOX X TCII PIN ~ - 53 JTS 3-1/2" 9.2# 13CR-80 VAM TOP TUBING - 3-1 /2" 9.2# 13CR XO PUP, TCII BOX X VAM TOP PIN - #7 SCHLUMBERGER/CAMCO 3-1/2" X 1-1/2" MMG GLM W/DUMMY VALVE - 3-1/2" 9.2# 13CR XO PUP, VAM TOP BOX X TCII PIN - 80 JTS 3-1/2" 9.2# 13CR-80 VAM TOP TUBING ~ - 3-1/2" 9.2# 13CR XO PUP, TCII BOX X VAM TOP PIN - #8 SCHLUMBERGER/CAMCO 3-1/2" X 1-1/2" Printed 6111/2010 3:36:OOPM r~ North America -ALASKA - BP Page 9 of 11 Operation Summary Report ___ ___ Common Well Name: W-01 DIMS AFE No Event Type: WORKOVER (WO) Start Date: 5/22/2010 End Date: 6/2/2010 x4-OOQT9-E (1,650,000.00 ) Project: Prudhoe Bay Site: PB W Pad Rig Name/No.: DOYON 141 Spud Date/Time: 9/12/1988 12:0O:OOAM Rig Release: 6/2/2010 Rig Contractor: DOYON DRILLING INC. UWI: 500292186600 Active Datum: W-01A @83.Oft (above Mean Sea Level) Date From - To Hrs Task Code NPT ~ NPT Depth Phase Description of Operations (hr) ~ (ft) MMG GLM W/DCK SHEAR VALVE - 3-1/2" 9.2# 13CR XO PUP, VAM TOP BOX X TCII PIN - 53 JTS 3-1/2" 9.2# 13CR-80 VAM TOP TUBING - 3-1/2" 9.2# 13CR XO PUP, TCII BOX X VAM TOP PIN #4 3-1/2" HES X-NIPPLE 9CR 2.813" PKG BORE 3-1/2"8.2# 13CR XO PUP, VAM TOP BOX X TCII PIN i - 17 JTS 3-1/2" 9.2# 13CR-80 VAM TOP TUBING i - 307 TOTAL JOINTS RAN BY MIDNIGHT ~ -ALL CONNECTIONS ABOVE PACKER UTILIZED JET LUBE SEAL GUARD - CONNECTIONS TORQUED TO AND AVERAGE 2,900 FT-LBS -ALL TORQUE'TURNED CONNECTIONS WERE RECORDED 6/1/2010 00:00 - 03:00 3.00 i RUNCOM - -P RUNCMP RUN 3-1/2" 9.2# 13CR-80 VAM TOP COMPLETION AS FOLLOWS: - 45 JTs 3-1/2" 9.2# 13CR VAM TOP TUBING L - 352 TOTAL JOINTS - 176 FULL CANNON CLAMPS USED ~i i - 16 HALF CANNON CLAMPS USED AT GLM ASSEMBLIES -ALL CONNECTIONS ABOVE PACKER UTILIZED JET LUBE SEAL GUARD - CONNECTIONS TORQUED TO AND AVERAGE 2,900 FT-LBS -ALL TORQUE TURNED CONNECTIONS WERE RECORDED _ 03:00 - 03:30 0.50 _____ RUNCOM _ P RUNCMP SPACE OUT COMPLETION - FIRST ROW OF SHEAR PINS SHEARED 26' INTO JOINT 353 ~ -SECOND SET OF PINS SHEARED, 3' INTO JOINT ~ 354 -TAG NO-GO 6' INTO JOINT 354 - BACK OUT AND LD JTS 354 AND 353 - NO SPACEOUT PUPS NEEDED FOR COMPLETION FINAL PUW: 120K; SOW: 85K Printed 6/11/2010 3:36:OOPM ~1 North America -ALASKA - BP Page 10 of 11 Operation Summary Report Common Well Name: W-01 DIMS AFE No Event Type: WORKOVER (WO) Start Date: 5/22/2010 End Date: 6/2/2010 x4-OOOT9-E (1,650,000.00 ) Project: Prudhoe Bay Site: PB W Pad Rig Name/No.: DOYON 141 Spud Date/Time: 9/12/1988 12:0O:OOAM ~ Rig Release: 6/2/2010 Rig Contractor: DOYON DRILLING INC. UWI: 500292186600 Active Datum: W-01A @83.Oft (above Mean Sea Level) Date From - To Hrs Task Code NPT NPT Depth Phase Description of Operations (hr) {ft) ___ 03:30 - 06:00 2.50 RUNCOM P RUNCMP PICKUP LANDING JOINT AND TUBING HANGER ASSEMBLY - MU TWO CROSSOVERS TO GET FROM XT-39 ON THE LANDING JOINT TO TC-II FOR THE HANGER LIFT THREADS - MU TIW VALVE TO THE LANDING JOINT TERMINATE I-WIRE IN HANGER, PRESSURE TEST LOWER SWAGELOCK FITTING, AND PERFORM FINAL CONTINUITY CHECK ON I-WIRE fNSTALL UPPER FITTING ON I-WIRE AND DRAIN STACK LAND TUBING HANGER. 06:00 - 07:00 1.00 _ RUNCMM P RUNCMP LAND TUBING HANGER AND RUN IN LOCK DOWN SCREWS. -450 FT/LBS TORQUE ON LOCK DOWN SCREWS 07:00 - 07:30 0.50 RUNCOM P RUNCMP CLEAR AND CLEAN RIG FLOOR 07:30 - 08:30 1.00 RUNCOM P RUNCMP R/U TO REVERSE IN INHIBITED SEAWATER. -HOLD PJSM WITH ALL PERSONNEL INVOLVED iN DISPLACEMENT. 08:30 - 14:00 5.50 RUNCMM _ P RUNCMP REVERSE IN 101 BBLS OF 120 DEGREE SEAWATER FOLLOWED BY 480 BBLS OF 120 DEGREE INHIBITED SEAWATER, FOLLOWED BY ~ 226 BBLS OF 120 DEGREE SEAWATER. -INITIAL CIRCULATING PRESSURE 4 BPM WITH ~ 500 PSI RISING TO 950 PSI WITH 2.5 BPM. -USING SEAWATER FROM TANKCO TANKS ON END OF LOCATION THAT HAD BEEN STAGED FOR KUPARUK OUTAGE. -USED VAC TRUCK TO FERRY FLUID FROM TANKCO TANK TO RIG. 14:00 - 14:30 0.50 RUNCMM P RUNCMP p/U LANDING JOINT AND SCREW INTO HANGER. DROP 1-5/16" BALL AND ROD WITH 1-3/8" FISHING NECK 14:30 - 16:30 2.00 RUNCMM P RUNCMP PUMP DO__WN THE TUBING_TO SET HES TNT I 9-5/8" X 3-1/2" PACKER AND TEST TUBING TO ~ 3,500 PSI FOR 30 CHARTED MINUTES. GOOD ~ TEST. BLEED TUBING TO 1,500 PSI. r -PRESSURE UP ON THE IA TO 3,500 PSI FOR 30 CHARTED MINUTES. GOOD TEST. -BLEED TUBING OFF AND SHEAR DCK VALVE. WENT AT 2,600 PSI DIFFERENTIAL. 16:30 - 20:00 3.50 RUNCOM P _ RUNCMP CAMERON DRY ROD SET TWC. TEST FROM BELOW TO 1000-PSI AND FROM ABOVE TO 3500-PSI FOR 10 CHARTED MINUTES. FAILED TEST FROM ABOVE. PULLED TWC AND CLEANED AND REBUILT SAME. CAMERON REINSTALLED TWC. TESTED SAME FROM BELOW TO 1000-PSI AND 3500-PSI FROM ABOVE FOR 10-CHARTED MINUTES. 20:00 - 20:30 0.50 RUNCMM P RUNCMP BLOW DOWN LINES ON RIG. 20:30 - 21:30 1.00 BOPSUR P RUNCMP ND BOPE. Printed 6/11/2010 3:36:OOPM North America -ALASKA - BP Page 11 or 11 Operation Summary Report Common Well Name: W-01 DIMS AFE No Event Type: WORKOVER (WO) Start Date: 5/22/2010 End Date: 6/2/2010 x4-OOQT9-E (1,650,000.00 ) __ i Project: Prudhoe Bay i Site: PB W Pad Rig Name/No.: DOYON 141 ~ Spud DatelTime: 9/12/1988 12:0O:OOAM Rig Release: 6/2/2010 Rig Contractor: DOYON DRILLING INC. UWI: 500292186600 Active Datum: W-01A @83.Oft (above Mean Sea Level) Date From - To Hrs Task Code NPT NPT Depth Phase Description of Operations (hr) (ft) 21:30 - 00:00 2.50 WHSUR P __ RUNCMP NU TREE AND ADAPTER FLANGE. TEST TUBING HANGER VOID TO 5000-PSI FOR 30-MINUTES. GOOD TEST. __ 6/2/2010 00:00 - 01:00 1.00 WHSUR P RUNCMP RIG UP LINES TO TREE AND I/A TO PREPARE FOR TREE TEST AND TO FREEZE PROTECT WELL. _ _ 01:00 - 01:30 0.50 _ WHSUR P _ RUNCMP p~SM -PRESSURE TESTING. MIRU LRS AND ~ TEST LINES TO 3500-PSI. 01:30 - 02:00 __ 0.50 WHSUR P RUNCMP " LRS FILL TREE WITH DIESEL. PRESSURE TEST TREE TO 5000-PSI WITH RIG TEST PUMP. _ 02:00 - 04:00 2.00 RUNCMM P RUNCMP PJSM -FREEZE PROTECT WELL. LRS PUMPED 140-BBLS. OF 45F DIESEL :DOWN I/A @ 3.0-BPM AT 120-PSI TAKING RETURNS TO ROCKWASHER. 04:00 - 04:30 0.50 RUNCMM P RUNCMP RDMO LRS. 04:30 - 05:30 1.00 RUNCMM P `RUNCMP U-TUBE DIESEL FROM I/A TO TUBING FOR 1.0-HRS. _ __ ______ 05:30 - 06:00 0.50 RUNCOM P _ RUNCMP CAMERON DRY ROD SET BPV. LRS PRESSURE TEST BPV FROM BELOW TO 1000-PSI FOR 10-CHARTED MINUTES. - --- 06:00 - 07:00 1.00 RUNCMM P - - RUNCMP R/D PUMPING EQUIPMENT, SLOWDOWN AND REMOVE CIRCULATING LINES, REMOVE SECONDARY ANNULUS VALVE, INSTALL - GAUGE ASSEMBLIES ON TREE. -TUBING PRESSURE = 0 PSI, IA PRESSURE = 0 PSI, OA PRESSURE = 0 PSI. -RIG RELEASED AT 07:00 HOURS ON 6/2/2010. Printed 6/11/2010 3:36:OOPM • W-01 A, Well History (Post Rig Workover) Date Summary 6/14/2010 WELL SHUT IN ON ARRIVAL. RAN 2.60" BELL GUIDE,2.0" JUS TO B&R AT 11,595' SLM. CURRENTLY POOH. 6/15/2010 PULL B&R FROM 11,595' SLM. PULL RK-DGLV'S FROM STA# 2 (10,796' SLM) STA#3 (10,099' SLM) STA#5 (8,699' SLM) STA#7 (6,235' SLM). PULL RK-DCR FROM STA#8 AT3,671' SLM. SET RK-LGLV IN STA#8 (3,671' SLM), STA#7 (6,235' SLM) STA#5 (8,699' SLM) STA#3 (10,099' SLM). SET RK-S/O IN STA#2 (10,796' SLM). PULL 3-1/2" RHC FROM 11,801' SLM / 11,806. WINDS GUSTING TO 37 MPH. GOON WEATHER HOLD. 6/16/2010 WELL S/I ON ARRIVAL. RAN 2.25" x 10' P-BLR MULTIPLE TIMES TO 11,718' SLM (Recovered 1/2 gal of sand / 1-1/2 cups of metal pcs). RAN 2.50" MAGNET TO 11,718' SLM (Metal shavings on magnet btm). RAN 2.50" L.I.B. TO 11,718' SLM (Impression inconclusive). CURRENTLY IN HOLE W/ 2.25" x 5' PUMP BAILER C~3 11,718' SLM. 6/17/2010 RAN 2.50" P-BLR 3 TIMES TO_11,718' SLM (Recovered a few metal chunks / 1/4 cup of fine metal). LAY DOWN EQUIPMENT FOR BP SAFETY STAND-DOWN (10:00 - 15:59). RAN 12 -PRONG CENTER SPEAR TO 11,719' SLM TO LOOSEN /BREAK UP METAL TRASH. CURRENTLY RIH W/ 2.25" PUMP BAILER W/ FLAT BALL BOTTOM. 6/18/2010 MADE ASSORTED BAILER RUNS FROM 11,718' SLM to 11,720' SLM (Recovered very little metal and mud). RAN 2.62" 3-PRONG WIRE GRAB TO 11,720' SLM (Severely bent 2 arms). RAN 2.50" LIB TO 11,720' SLM (Impression inconclusive). RAN 2.50" MAGNET TO 11,715' SLM (No recovery). RAN 2.50" CENT, 5' - 1-1/2" STEM, 1-1/2" S-BLR TO 11,718' SLM (Unable to get any deeper). CURRENTLY RIH W/ 1.75" L.I.B. TO 11,718' SLM. 6/19/2010 MADE ASSORTED BAILER RUNS FROM 11,718' SLM TO 11,720' SLM (Recovered very little metal and mud). MADE ASSORTED CENTER SPEAR RUNS FROM 11,718' SLM TO 11,720' SLM (Many metal marks). RAN ASSORTED DRIVE DOWN TRAPS (No recovery, many metal scraps). JOB IS NOT COMPLETE, COIL WILL BE SCHEDULED TO DO A CLEAN OUT & PULL WRP. WELL S/I ON DEPARTURE, NOTIFIED PAD OPERATOR OF WELL STATUS. NOTE: 3-1/2" WFD WRP STILL IN HOLE C~3 11,743' MD. 6/21 /2010 RIH w / WFD motor jars &venturi junk basket w / 2 625" burn shoe. Work from 11734 to 11743'. Circ hole with safelube. Pooh. 6/22/2010 Continue pooh w/ venturi basket. Basket full of sand /rubber. RIH w/same. Dry tag top of plug C~3 11741'. Venturi on top of plug 11740.5'. POOH. Very small amount of sand in basket. RIH w /fishing assembly, set down on fish, PUH, no over pulls, make several attempts. POOH, At surface no fish. Cut 150' of coil for pipe management. RIH w/ motor, and burn shoe sleeve. 6/23/2010 RIH w/ motor w/ burnshoe to top of plug C 11743'. Pump two gel sweeps off top of plug and chase to surface. RIH w/jars, GS pulling tool, WRP pulling tool. Made several attempts to latch plug without sucess. Thin spot found in coiled tubing while POOH. Riq down unit for pipe swap. 6/24/2010 TWO ATTEMPTS TO TAKE IMPRESSION OF 3-1/2" WRP W/ 2.50" LIB, UNABLE TO PASS 11,633' SLM (one run w/inconclusive mark). TOOK IMPRESSION OF TOP OF 3-1/2"WRP W/ 2.12" LIB BARBELL SETUP C~ 11,729' SLM. ATTEMPT TO PULL 3-1/2"WRP AND UNABLE TO LATCH 11,729' SLM. BAILED ~ 11,729' SLM W/ 2.5" PUMP BAILER, NO RETURNS AND TATTLE TAIL PIN 11" INSIDE BENT UP. MADE SECOND ATTEMPT TO PULL 3-1/2"WRP C~3 11,729' SLM. TWO RUNS WITH 2.5" MAGNET TO 11,729' SLM AND RECOVERED 3-1/2"WRP FISH NECK. 6/25/2010 RAN 2.15" LIB TO 11,729' SLM & TOOK IMPRESSION OF TOP OF REMAINING 3-1/2"WRP (circular, measuring .75"). ATTEMPT TO GET OVER 3-1/2" WRP ~ 11,729' SLM W/ 2.50" WRP EQU. BLR. BTM, T.T. PINS SHOW PENETRATION OF WRP AT 4-1/2" BLR. BTM TIP. TOOK IMPRESSION W/ 2.25" LIB OF 3-1/2"WRP, WEATHERFORD VERIFIED IMPRESSION WAS INTERNAL COLLETS. MADE ADDITIONAL RUN W/ 2.50" EQUALIZING BTM TO 11,729' SLM--BTM PINS BENT 4-1/2" UP. FISH 3-1/2"WRP INNER CORE W/ 2.25" SHEARABLE OVERSHOT C~ 11,729 (measures 7-3/4" oal). TOOK IMPRESSION W/ DECENTRALIZER & 2.25" LIB @ 11,731' SLM. RAN 2.50" MAGNET TO 11,729' SLM AND RECOVERED NOTHING. PREFORM WSL WITNESSED WEEKLY BOP TEST. 6/26/2010 MULTIPLE ATTEMTS TO RETRIEVE 3-1/2"WRP EQU. SLV. W/ 2.31" OD OVERSHOT ~ 11,733' SLM--NO RECOVERY. ATTEMPT TO FISH 3-1/2"WRP EQU. SLV. W/ 2.31" BOX TAP C~3 11,731' SLM--NO RECOVERY. TOOK IMPRESSION W/ 2.5" LIB ~ 11,731' SLM, IMPRESSION REMAINS UNCHANGED. RAN 2.5" DRIVE DOWN BAILER TO 11,731' SLM, NO RETURNS. ATTEMPT TO FREE EQUALIZING SLEEVE OR DEBRIS ON SIDE OF WRP C~ 11.731' SLM W/2.62" SINGLE PRONG WIRE GRAB. Page 1 of 2 W-01 A, Well History (Post Rig Workover) Date Summary 6/27/2010 ATTEMPT TO CLEAR DEBRIS FROM SIDE OF 3-1/2"WRP @ 11,731' SLM W/ 2.62" SINGLE PRONG WIRE GRAB. RAN 2.5" MAGNET TO 11,732' SLM WITH NO RECOVERY. TOOK IMPRESSION OF 3-1/2"WRP INNER CORE W/ 2.50" LIB ~ 11,732' SLM. TWO ATTEMPT TO PULL 3-1/2" WRP EQU SLV W/ 2.25" OVERSHOT ~ 11,734' SLM (changed grapple sizes). WORKED DE-CENTRALIZED 2.62" TWO PRONG WIRE GRAB ~ 11,732' SLM, PULLING HEAVY BINDS. RAN 2.5" MAGNENT TO 11,732' SLM WITH NO RECOVERY. TOOK IMPRESSION OF 3-1/2"WRP INNER CORE W/ 2.50" LIB C~3 11,732' SLM. 6/28/2010 RAN 2.31" TWO PRONG WIRE GRAB ON DECENTRALIZER AND WORKED TOOLS ~ 11,732' SLM. TAG 3- 1/2" WRP WITH 2.50" MAGNET ~ 11,732' SLM--NO RECOVERY. RAN 1.81" ONE PRONG WIRE GRAB ON DECENTRALIZER AND WORKED TOOLS ~ 11,732' SLM. TAG 3-1/2"WRP WITH 2.50" MAGNET ~ 11,732' SLM--NO RECOVERY. TOOK IMPRESSION OF 3-1/2"WRP INNER CORE W/ 2.50" LIB @ 11,732' SLM. TOOK IMPRESSION C~ 11,732' SLM. SLIGHTLY PAST TOP OF REMAINING 3-1/2" WRP W/MILLED OUT 2.60" LIB, PICTURE POSSIBLY OF WRP SHEAR STUD. 6/29/2010 RAN 2.313" MODIFIED OVERSHOT/SLEEVE TO 3-1/2"WRP C~3 11,735' SLM & DISLODGED SHEAR STUD FROM SIDE OF FISH. RET_R_IE_VED HEAVILY DAMAGED WRP SHEAR STUD W/ 2.5" MAGNET FROM 11.741' SLM. TWO ATTEMPTS TO FISH 3-1/2"WRP WITH 2.313" MODIFIED OVERSHOT/SLEEVE C~ 11,740' SLM. MOVED 3-1/2" WRP TO X NIPPLE C~ 11,717' SLM OVERSHOT PULLED OFF INNER CORE. TWO ATTEMPTS TO OVERSHOT 3-1/2" WRP INNER CORE W/TWO DIFFERENT SLIP SIZES C~ 11,717' SLM. 6/30/2010 RAN 2 1/2" MODIFIED BAILER BTM TO 11717' SLM, TWICE, WITH NO LUCK. CURRENTLY RUNNING KJ, 3 1/2" BAIT SUB, 2.13" OVER SHOT. 7/1/2010 RAN 2.13" SPIRAL GRAPPLE OVER SHOT TO WRP @ 11704' SLM (RECOVERED EO SLEEVE). MADE 2 RUNS W/ 10' x 2.50" P. BAILER W/ EXT. FLAPPER BTM TO TOP OF FISH C~3 11,709' SLM (RECOVERED SMALL PIECES OF RUBBER ELEMENTS & -4 TBLS OF METAL SHAVINGS). PLANTED 3 1/2" BAIT SUB, 2.72" OVER SHOT WITH 1 9/16" GRAPPLES TO FISH ~ 11720' SLM. CURRENTLY RUNNING 3 1/2" GS. 7/2/2010 FISHED 3 1/2" WFD WRP FROM 11726' SLM (missing 3 elements, 7 out of 8 collets). RAN 2.23" WIRE GRAB TO TOP OF DEPLOYMENT SLEEVE ~ 11,730' SLM...NO RECOVERY. MADE 2 RUNS W/ 2.70" MAGNET TO 11,730' SLM...RECOVERED 1 COLLET FROM WRP. ATTEMPT TO DRIFT INTO 2-3/8" LINER W/ 1.75" CENT & BRUSH. UNABLE TO PASS 11,734' SLM. WELL LEFT S/I ON DEPARTURE, PAD OP NOTIFIED. Page 2 of 2 r TREE= ~ 4-1/16" CNV WELL}1EAD = MCEVOY ACTUATOR = BAKER C KB. ELEV = 83.26' BF. ELEV...- 53.81' KOP = 1000' Max Angle = 96 @ 12573' Datum MD = 12249' Datum TVD = 8800' SS . SAFETY: WELL ANGLE> 70° @ 12352"""* W-01 A 3-1 /2" C ETBG""" 20" CONDUCTOR 110' 13-318" CSG, 72#, L-80, ID = 12.347" 2933' Minimum ID =1.92" @ 11762" TOP OF 2-3/8" LINER 3-1/2" SLB SAPPHIRE NDPG 11413' PRESSURE GAUGE, ID = 2.992" 1995' -~ 3-1/2" HES X NIP, ID = 2.813 GAS LIFT MANDRELS ST MD TVD DEV TYPE VLV LATCH PORT DATE 8 3690 3198 46 MMG DOME RK 10 06/15/10 7 6242 4795 54 MMG DOME RK 12 06/15/10 6 7945 5800 51 MMG DMY RK 0 06/01/10 5 8705 6296 47 MMG DOME RK 12 06/15/10 4 9436 6811 43 MMG DMY RK 0 06/01/10 3 10103 7299 45 MMG DOME RK 16 06/15/10 2 10802 7800 43 MMG SO RK 22 06/15/10 1 11343 8196 42 MMG DMY RK 0 06/01/10 11479' I~ 3-1/2" HES X NIP, ID = 2.813 11509' ~ 9-5/8" X 3-1 /2" HES TNT PKR, ID = 2.949" 11546' 3-1/2" HES X NIP, ID = 2.813 3-1/2" TBG, 9.2#, 13CR-80 VAM TOP I 11639' .0087 bpf, ID = 2.992" 3-1/2" TUBING STUB (05/04/10) 11646' IRS P"`kS FISH: 6 METAL COLLETS & -11734 3 RUBBER ELMENTS (07/02/10) TOP OF 2-3/8" LNR 11762' 3-1/2" TBG, 9.3#, L-80 EUD 8RD, 11798' .0087 bpf, ID = 2.992" TOPOF 5-1/2" LNR (06/20/03) 11810' SLM 9-5/8" CSG, 47#, L-80, ID = 8.681" 12027' PERFORATION SUMMARY REF LOG: ANGLE AT TOP PERF: Note: Refer to Production DB for historical pert data SIZE SPF INTERVAL Opn/Sqz DATE 2-3/8" SLT 12284 - 12347 C 12/25/03 TOP OF WHIPSTOCK 12126' RA TAG 12153' 5-1/2" LNR, 17#, L-80, .0232 bpf, ID = 4.892" 12670' 11608' I~ 3-1/2" HES X NIP, ID = 2.813 11654' I-i9-5/8" X 3-1/2" UNIQUEOVERSHOT 11672' 3-1/2" OTIS SBR SEAL ASSY 11688' 9-5/8" X 3-1 /2" OTIS PKR, ID = 3.85" 11693' H 4-1/2" MILLOUT EXTENSION, ID = 3.958" 11699' 1-14-1/2" X 3-1/2" XO, ID = 2.992" 11731' 3-1/2" OTIS X NIP, ID = 2.75" 11 17sz' I--12.6" BKR DEPLOY SLV, ID = 1.92" 11764' 3-1/2" OTIS X NIP, ID = 2.75" BEHIND 11798' 3-1/2" WLEG, ID = 2.992" CT LNR 11806' ELMD TT LOGGED 08/11/92 MILLOUT WINDOW (W-01 A) 12143' - 12154' 12347' -1 BOT O-RING SUB ~~ .~ `L_ Z-,~a- OPEN 2-3/8" LNR, 4.6#, L-80, .0036 bpf, ID = 1.920" 12380' H O L E DATE REV BY COMMENTS DATE REV BY COMMENTS 10/13/88 N22E ORIGINAL COMPLETION 06/20/10 TAR/PJC GLV/ MIN ID CORRECTION 12/26/03 NORDIC 1 CTD SIDETRACK (W-01A) 07/06/10 KSB/SV FISH (07/02/10) 06/02/10 D-141 RWO 06/02/10 PJC DRLG DRAFT CORRECTIONS 06/04/10 DB/PJC FINAL DRLG CORRECTIONS 06/18/10 TAR/BLG GLV C/O (06/15/10) PRUDHOE BAY UNIT WELL: W-01A PERMfI' No: 2031760 API No: 50-029-21866-01 SEC 21, T11 N, R12E, 1158' FNL & 1189' FEL BP Exploration (Alaska) BOPE testing W-Ola (PTD 2031760) Non Sundry RWO Page 1 of 1 Schwartz, Guy L (DOA) From: Schwartz, Guy L (DOA) Sent: Wednesday, May 19, 2010 1:02 PM To: 'Bjork, David (Northern Solutions)' Subject: RE: BOPE testing W-01a (PTD 2031760) Non Sundry RWO Dave, Thanks for the heads up on this. Your procedure as stated below is fine if you can't get a spacer spool fitted in. Our policy has been that you test the LPR as soon as possible after getting out of the hole with the completion and before RIH with any BHA . Thanks, Guy Schwartz ,. ~ 1, ~ ~~ ;; r ~ ~ _; ~~, Senior Petroleum Engineer ~~'`~"" °;~' i,~, ),f- AOGCC 793-1226 (office) 444-3433 (cell) From: Bjork, David (Northern Solutions) [mailto:David.Bjork@bp.com] Sent: Wednesday, May 19, 2010 10:56 AM To: Schwartz, Guy L (DOA) Subject: BOPE testing W-Oia (PTD 2031760) Non Sundry RWO Guy, W-01 a is a ivishak Producer with TxIA communication. The well is completed with 3-1/2" L-80 tubing. We intent to pull the old tubing, replace the casing pack-offs and run a new 3-1/2" CRA completion. We will be using the following BOPE configuration. Annular, 3-'/" x 6" VBR's, Blind Ram, Mud Cross and 4" solid Ram. The tubing hanger neck seals will stick above the tubing hanger flange ~10". We will attempt to utilize a spacer spool if sub height will allow. If a spacer spool is not feasible due to sub and BOPE height we will be unable to test the lower 4" solid ram until after the tubing hanger is pulled. We would like to pull the completion, set a test plug and then test the lower 4" solid RAM. Is this an acceptable practice with the AOGCC? Regards, Dave Bjork BPXA RWO Engineer 5/19/2010 10/16/09 Schimnherger "• �' - r' - NO. 5418 Alaska Data & Consulting Services Company: State of Alaska 2525 Gambell Street, Suite 400 Alaska Oil & Gas o Anchorage, AK 99503 -2838 Attn: Christine MC C mm n ons s C C ATTN: Beth 333 West 7th Ave, Suite 100 Anchorage, AK 99501 Well Job R Log Description Date BL Color CD P1 -25 AP30 -00063 INJECTION PROFILE 10/0209 1 1 W -01A 62NJ -00026 MEMORYGLS — 10/02/09 1 1 12 -06A AZCM -00043 LDL — 10/03/09 1 1 W -36 AV1H -00028 PROD PROFILEW /GL 09/29/09 1 1 E -35A B2NJ -00027 MEM CEMENT BOND LO 10/03/09 1 1 12 -34 AYS4 -00104 INJECTION PROFILE 10/11/09 1 1 Z -07A AYS4 -00101 PRODUCTION PROFILE 10/08/09 1 1 15 -18A B2 WT- 00015 MEM PROD PROFILE — 07101/09 1 1 • 05 -18A B04C -00069 SCMT 07/30/09 1 1 U -05A 8148 -00068 USIT — 08/17/09 1 1 P -07A AWJI.00051 MEM P PROFILE 10109/09 1 1 09.03 AZCM -00044 PRODUCTION LOG 10/10/09 1 1 1. 4510 -26 B2NJ -00032 MEM LDL — 10/10/09 1 1 S -134 AWLS -00039 09/28/09 1 1 V -105 B3S0 -00026 IPROF — 10/03/09 1 1 PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING ONE COPY EACH TO: BP Exploration (Alaska) Inc. Alaska Data & Consulting Services Petrotechnical Data Center LR2 -1 2525 Gambell Street, Sude 400 900 E. Benson Blvd. Anchorage, AK 99503 -2838 a �� i • 1 Schlumherger Alaska Data & Consulting Services 2525 Gambell Street, Suite 400 Anchorage, AK 99503-2838 ATTN: Beth Weil .Inh !F 4,~aY~,~ 1. it Y~iA+' LIJ Inn nncrrinfinn .~, ,~ ~3 '..~~s~ ~~~ ~.:A. ~~;. .~'.f3D'e'3y IIIf g~l~~~~ NO.5072 Company: State of Alaska Alaska Oil & Gas Cons Comm Attn: Christine Mahnken 333 West 7th Ave, Suite 100 Anchorage, AK 99501 rhtn RI f_nlnr en 02/09/09 W-210 40014842 OH MWD/LWD EDIT (REVISED) 5 02/26/07 2 1 W-36 11968735 RST 03/07/08 1 1 C-30A AMJI-00009 MCNL _ / ~ 12/04/08 1 1 W-01A AWJB-00020 MEMORY LDL - ~~(o $-jp 01/26/09 1 1 E-37A AXBD-00012 MEMORY PROD PROFILE b - 01/26/09 1 1 F-19 AP3O-00019 CORROSION EVALUATION r 02/01/09 1 1 Q ~ ~ C S- YItASt AGKNUWLtUGt HtGE1P 1 BY SIGNING ANU HEI UHNINCi UNE GUPY EACH TO: BP Exploration (Alaska) Inc. Petrotechnical Data Center LR2-1 900 E. Benson Blvd. Anchorage, Alaska 99508 Date Delivered: Alaska Data & Consulting Services 2525 Gambell Street, Suite 4 // ~~ Anchorage, AK 9950 -2838 I - ATTN: Beth Received by: ~,...~__-.-~ • ''~~ ~• ~ 03/01/2008 DO NOT PLACE .. ~~ Tom. ~. ANY NEW MATERIAL UNDER THIS PAGE F:~LaserFiche\CbrPgs_InsertslMicrofilm Marker.doc ~ ~ j(\iI\ DATA SUBMITTAL COMPLIANCE REPORT 1/3/2006 Permit to Drill 2031760 Well Name/No. PRUDHOE BAY UNITW-01A Operator BP EXPLORATION (ALASKA) INC ¥ 11 ~~~ API No. 50-029-21866-01-00 MD 13135""""""-- TVD 8936 __ Completion Date 12/26/2003 ,. Completion Status 1-01L Current Status 1-01L UIC N --~-~ REQUIRED INFORMATION Mud Log No Samples No Directional suç ~ DATA INFORMATION Types Electric or Other Logs Run: MWD / GR / CCL / PRESS, Memory induction log Well Log Information: (data taken from Logs Portion of Master Well Data Maint Log/ Data .!ïPe ~D Electr Digital Dataset Med/Frmt Number C Lis 12576 Name Difectiollc:iI SUlýey Log Log Scale Media Run No Interval OH / Start Stop CH Received 12078 14109 Open 7/23/2004 . Comments TIF, MWD- GRlDIRECTIONAL, GRAPHICS 1~ D Las 12368 Induction/Resistivity 12149 13130 Open 1/20/2004 D Las 12368 Casing collar locator 12149 13130 Open 1/20/2004 vt°g I nd uction/Resistivity 25 BM 12149 13130 Open 1/20/2004 Induction Log og Casing collar locator 25 BM 12149 13130 Open 1/20/2004 Induction Log JED D Asc Directional Survey 12170 13135 2/13/2004 ED D Pdf Directional Survey 12170 13135 2/13/2004 rRPt Directional Survey 12170 13135 2/13/2004 ~~ D Asc Directional Survey 12114 14109 2/13/2004 PB1 . D Pdf Directional Survey 12114 14109 2/13/2004 PB1 ~t Directional Survey 12114 14109 2/13/2004 PB1 ,¿; C Lis 12575 DireGtio"nðl gurvcy . 12078 13135 Open 7/23/2004 TIF, MWD- GR/DIRECTIONAL, ! GRAPHICS, i Gamma Ray MO 25 Blu 12078 13135 7/23/2003 DSN !~g 12575,DIRECTIONAL, 'tVD PRESSTEQ I, W-01A ......cog Gamma Ray 25 Blu 12078 13135 Open 7/23/2003 DSN 12575, DIRECTIONAL, PRESSTEQ I, W-01A -t1)g Gamma Ray (tit /) 25 Blu 12078 14109 Open 7/23/2003 DSN 12575,DIRECTIONAL, PRESSTEQ I, W-01APB1 DATA SUBMITTAL COMPLIANCE REPORT 1/3/2006 Permit to Drill 2031760 Well Name/No. PRUDHOE BAY UNIT W-01A Operator BP EXPLORATION (ALASKA) INC API No. 50-029-21866-01-00 yo 13135 TVD 8936 Completion Date 12/26/2003 Completion Status 1-01L Current Status 1-01L UIC N Log Gamma Ray ì V tJ 25 Blu 12078 14109 Open 7/23/2003 DSN 12575,DIRECTIONAL, X PRESSTEQ I, W-01APB1 LIS Verification 12078 13135 Open 7/23/2004 DSN 12575 pt LIS Verification 12078 14109 Open 7/23/2004 DSN 12576 ~ Leak 25 Blu 0 11720 6/21/2005 Leak Detection Log/press- tem p-ccl-g rIg rad ili Is/fbs . Well Cores/Samples Information: Sample Interval Set Name Start Stop Sent Received Number Comments ADDITIONAL INFORMATION Well Cored? ~ Chips Received? . Y / N Daily History Received? Œ¥N rG/N Formation Tops Analysis Received? ~ Comments: Compliance Reviewed By: .~ Date: S JA-N ~~ . RE: W -01 (PTD #2031760) Classified as Problem Well l',J-Oi A- . Subject: RE: W41f (PTD #2031760) Classified as Problem Well From: "NSU, ADW Well Integrity Engineer"<NSUADWWelUntegrityEngineer@BP.com> Date: Mon, 07 Mar 2005 15:59:53 -0900 To: James Reggkjim_regg@admin.state.ak.us> .. '.<:.,< CC:~ "NSD, AQW Well Integrity Engineer" <NSq~:D.WW . ," 'V". . , ú·<,··, ";:." ... ". ....-{ :~(f. -:" . 'IntegrityEnginee~@\BP.com> . .. ... Hi Jim. lJ~CIA The TIO's for ~ on 3/5/05 are 390/710/140. The well is currently online, scheduled for slickline to run DGLV's. Let me know if you have any other questions. Thanks! Joe -----Original Message----- From: James Regg [mailto:jim regg@admin.state.ak.us] Sent: Monday, March- 07, 2005-2~;4j PM~- To: NSU, ADW Well Integrity Engineer Subject: Re: ~ (PTD #2031760) Classified as Problem Well lv·-o I A pressures? NSU, ADW Well Integrity Engineer wrote: Hello all.l,J--OiA Well~· (PTD #2031760) has sustained casing pressure on the IA and has been classified as a Problem well. The well failed a Gas Leak Rate test on 03/04/05. This well is currently waivered for TxIA comm. The plan for this well is as follows: 1. SL: Run DGLV's 2. DHD: Re-TIFL Attached is a wellbore schematic. Please call if you have any questions. «W-01A.pdf» Joe Anders, P.E. Well Integrity Coordinator BP Exploration (Alaska), Inc 1-907-659-5102 anders22@bp.com lofl JEJ'-- :47~5 3/7/20054:03 PM TREE:::: 3-118" MCEVOY WELLHEAD = MCEVOY n~"~ CN U ACTUA TOR:::: OTIS KB. ELEV = 83.26' BF. ELEV = 53.81' KOP:::: 1000' Max Angle:::: 96 @ 12573' """"" '" _~M._ ^ '^ _,___^~~ , Datum MD :::: 12249' . ^ ___'M" ,~ _.m~~~._~'~ Datum 1VD = 8800' SS . W-01A ~OTES: ***T X IA COMM. OPERATING LIMITS: MAX lAP = 2000 PSI; MAX OAP :: 1000 PSI (02/08/04 WAlVER)*** I 13-318" CSG, 72#, L-80, ID= 12.347" H 2933' ~ Minimum ID = 1.920" @ 11763" TOP OF 2-3/8" LINER 13-112" TBG, 9.2#, L-80, .0087 bpf, ID = 2.992" H 11672' I TOP OF 3-112" TBG T A IlPlÆ H 11672' i Z 13-1/2" TBG, 9.3#, L-80. .0087 bpf, ID:::: 2.992" H 11789' I I TOP OF 5-112" LNR (06120103) H 11810' SLM I ~ 9-518" CSG, 47#, l-80, 10= 8.681" H 12027' I TOP OF WHIPSTOCK H 12126' I RA TAGH 12153' - ÆRFORATION SUMMARY REF LOG: ANGLE AT TOP ÆRF: Note: Refer to Production DB for historical perf data SIZE SPF INTERV AL OpnlSqz DA TE SLOTTED LINER 12284 - 12347 0 12/25103 15-112" LNR, 17#, l-80, .0232 bpf, 10 = 4.892" H 12670' . 2093' H3-112" OTIS SSSV LANDING NIP, 10 = 2.75" I .. GAS LIFT MANDRELS ST MD 1VD DEV TYÆ VLV lA TCH PORT DATE 5 3422 3013 47 OTIS DOME RM 16 01105/05 4 7969 5815 51 OTIS DOME RrvI 16 01/05/05 L 3 9990 7218 44 OTIS DOME RM 16 01/05/05 2 11092 8012 43 OTIS DMY RM 0 01/05/05 1 11562 8358 42 OTIS SO RM 20 01/05/05 I 11622' H3-1/2" OTIS SLIDING SlV, 10=2.75" I I I - ¡ 1 11672' H 3-112" OTIS SBR SEAL ASSY I ~ 11688' H9-518" X 3-1/2" OTIS PKR, 10:::: 3.85" I 11731' H3-112" OTIS X NIP, 10:::: 2.75" I . . I 11762' H2.6" BKR DEPlOYMENT SLV, 10 = 2.25" - 11764' H3-112" OTIS X NIP, 10:::: 2.75" (BEHIND CT LNR) I 11798' H 3-1 12" WLEG, ID:::: 2.992" (BEHIND CT LNR) I I I 11806' H ELMO TT lOGGED 08/11/92 I '" MlllOUTWINDOW 12143'-12154' H BOT O-RING SUB I 2-3/8" lNR, 4.6#, l-80, .0036 bpf, ID:::: 1.920" H 12380' I DATE 10/13/88 12/26/03 01/26/04 02/08/04 01/05/05 REV BY COMMENTS HENRY ORIGINAL COMPLETION JDM/KK CTD SIDETRACK (W-01A) KSBlTLH GL V C/O JLA/KK WAIVER SAFElY NOTE LWBlTlP MANDREL 1VD CORRECTIONS REV BY DATE COMMENTS PRUDHOE BA Y UNIT WELL: W-01A ÆRMIT No: 2031760 A PI No: 50-029-21866-01 SEC21, T11N, R12E, 1157' SNL & 1189' WEL BP Exploration (Alaska} e Transmittal Form INTEQ To: AOGCC 333 West 7th Ave, Suite 100 Anchorage, Alaska 99501 Attention: Robin Deason Reference: W-01A & W-01APB1 Contains the following for each wellbore: 1 LDWG Compact Disc (Includes Graphic Image files) 1 LDWG lister summary . :M3-176 ,,¡_ BAKER HUGHES Anchorage GEOScience Center 1 blueline - GRlDirectional Measured Depth Log 1 blue line - GRlDirectional TVD Log LAC Job#: 599386 SentB~~.nH él ReceivedUe-Ø..a. .hC~ ::::: ; l~{ PLEASE ACKNOWLE GE RECEIPT BY SIGNING & RETURNING OR FAXING YOUR COpy FAX: (907) 267-6623 Baker Hughes INTEQ 7260 Homer Drive Anchorage, Alaska 99518 Direct: (907) 267-6612 FAX: (907) 267-6623 QJU~~~,-I~~tu~~" .1 _m;.;;::;:_;;:'_;~;;';';~,¡;;;___ ...__ '''-C," : _.., _ u "" ._:..' , ...: " -. ·-------·,-··--:,>:~~~-~.;:-,·,·_-----_·'·-'·I -""" - ... .., -. > hi --.... ~ 4 . STATE OF ALASKA .a~ ALASKA AND GAS CONSERVATION COMM~N WELL COMPLETION OR RECOMPLETION REPORT AND LOG 1a. Well Status: 181 Oil 0 Gas 0 Plugged 0 Abandoned 0 Suspended 0 WAG 20AAC 25.105 20AAC 25.110 Memory Induction Log CASING, LINER AND CEMENTING RECORD SmlNGDePTHMD SeTTING DePTH T\ÎD HOLE Top -SOTTOMIOP BOTTOM SIZE Surface 110' Surface 110' Surface 2934' Surface 2684' 29' 12027' 29' 8706' 11781' 12143' 8520' 8797' 11762' 12380' 8506' 8933' o GINJ 0 WINJ 0 WDSPL No. of Completions 2. Operator Name: BP Exploration (Alaska) Inc. 3. Address: P.O. Box 196612, Anchorage, Alaska 99519-6612 4a. Location of Well (Governmental Section): Surface: 1157' SNL, 1189' WEL, SEC. 21, T11N, R12E, UM Top of Productive Horizon: 4427' SNL, 542' EWL, SEC. 23, T11N, R12E, UM Total Depth: 4432' SNL, 1322' EWL, SEC. 23, T11N, R12E, UM 4b. Location of Well (State Base Plane Coordinates): Surface: x- 612049 y- 5959100 Zone- ASP4 TPI: x- 619115 y- 5955938 Zone- ASP4 Total Depth: x- 619895 y- 5955945 Zone- ASP4 18. Directional Survey 181 Yes 0 No 21. Logs Run: MWD / GR / CCL / PRESS, 22. Wr.PER Conductor 68# 47# 17# 4.6# GRADE 20" 13-3/8" 9-5/8" 5-1/2" 2-3/8" L-80 L-80 L-80 L-80 23. Perforations open to Production (MD + TVD ofTop and Bottom Interval, Size and Number; if none, state "none"): 2-3/8" Slotted Section MD TVD MD TVD 12284' - 12347' 8894' - 8922' 26. Date First Production: January 28, 2004 Date of Test Hours Tested 2/2/2004 4 Flow Tubing Casing Pressure Press. 316 PRODUCTION FOR TEST PERIOD + CALCULATED + 24-HoUR RATE Form 10-407 Revised 12/2003 One Other 5. Date Comp., Susp., or Aband. 12/26/2003 6. Date Spudded 12/11/2003 7. Date ToO. Reached 12/22/2003 8. KB Elevation (ft): KBE = 83' 9. Plug Back Depth (MD+ TVD) 13135 + 8936 10. Total Depth (MD+TVD) 13135 + 8936 11. Depth where SSSV set (Nipple) 2093' MD 19. Water depth, if offshore N/A MSL 17-1/2" 12-1/4" 8-1/2" 3" 24. SIZE 3-1/2", 9.2#, L-80 DEPTH INTERVAL (MD) 2000' Revised: 02/04/04, Put on Production 1 b. Well Class: 181 Development 0 Exploratory o Stratigraphic Test 0 Service 12. Permit to Drill Number 203-176 13. API Number 50-029-21866-01-00 14. Well Name and Number: PBU W-01A 15. Field / Pool(s): Prudhoe Bay Field / Prudhoe Bay Pool Ft Ft 16. Property Designation: ADL 047451 17. Land Use Permit: 20. Thickness of Permafrost 1900' (Approx.) CEMENTING RECORD 8 cu yds Concrete 4323 cu ft PF, Top Job: 140 cu ft PF 2533 cu ft Class 'G' 371 cu ft Class 'G' Uncemented Slotted Liner AMOUNT PULLED TUBING RECORD DEPTH SET (MD) 11798' PACKER SET (MD) 11688' AMOUNT & KIND OF MATERIAL USED Freeze Protected with 18 Bbls of MeOH GAs-McF 4,925 GAs-McF 29,550 WATER-BBL 480 WATER-BBL 2,880 PRODUCTION TEST Method of Operation (Flowing, Gas Lift, etc.): Flowing OIL-BBL 1,913 OIL -BBL 11,478 27. CORE DATA c: r:¡..... r:: n Ie r-., Brief description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water (A"n::.~t ¥C l1ßecessary). Submit core chips; if none, stat~~Don~'."... , CD¡\~_:~:_~~:,.;¡·,~-nx~ j None 1/2. .¡'it .~á , -V:;-~73'''' 1,', ! :z,C!; \ 1~__,~~::::J iL'ï:;D\ '(';-' \r'\rJD': (II OR\G1~^' CONTINUED ON REVERSE SIDE tiIIJMS SFl FEB 0 '. ¡10t)\ \./ CHOKE SIZE I GAS-OIL RATIO 70° 2,574 OIL GRAVITY-API (CORR) 26.5 FE8 0 4 2004- "lIJt~ A~f;;:,:~::-:'::l 2~. GEOLOGIC MARKERS. 29. .MATlON TESTS Include and briefly summarize test results. List intervals tested, and attach detailed supporting data as necessary. If no tests were conducted, state "None". NAME MD TVD Shublik A 12146' 8799' None Shublik B 12209' 8848' Shublik C 12241 ' 8869' Eileen 12277' 8890' Sadlerochit 12304' 8904' Sadlerochit (Invert) Sadlerochit (Revert) 12892' 8928' 13067' 8932' 30. List of Attachments: Summary of Daily Drilling Reports, Well Schematic Diagram, Surveys 31. I hereby certify that the foregoing is true and correct to the best of my knowledge. Signed Terrie Hubble ~lIJ\/() .J ~ Title Technical Assistant Date 0 ;2.-()-{-oLf PBU W-01A 203-176 Prepared By Name/Number: Terrie Hubble, 564-4628 Well Number Drilling Engineer: Ted Stagg, 564-4694 Permit No. / Approval No. 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 1a: Classification of Service Wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. 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 4b: TPI (Top of Producing Interval). ITEM 8: The Kelly Bushing elevation in feet above mean low low water. Use same as reference for depth measurements given in other spaces on this form and in any attachments. ITEM 13: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). ITEM 20: True vertical thickness. ITEM 22: Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool. ITEM 23: 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 26: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-In, or Other (explain). ITEM 27: If no cores taken, indicate "None". ITEM 29: List all test information. If none, state "None". Form 10-407 Revised 12/2003 · STATE OF ALASKA ALASK AND GAS CONSERVATION COM~ION WELL COMPLETION OR RECOMPLETION REPOR1fND LOG 1a. Well Status: IS! Oil 0 Gas 0 Plugged 0 Abandoned 0 Suspended 0 WAG 20AAC 25.105 20AAC 25,110 o GINJ 0 WINJ 0 WDSPL No. of Completions 2. Operator Name: BP Exploration (Alaska) Inc. 3. Address: P.O. Box 196612, Anchorage, Alaska 99519-6612 4a. Location of Well (Governmental Section): Surface: 1157' SNL, 1189' WEL, SEC. 21, T11 N, R12E, UM Top of Productive Horizon: 4427' SNL, 542' EWL, SEC. 23, T11N, R12E, UM Total Depth: 4432' SNL, 1322' EWL, SEC. 23, T11N, R12E, UM 4b. Location of Well (State Base Plane Coordinates): Surface: x- 612049 y- 5959100' Zone- ASP4 -- -------- -_._-.'--- TPI: x- 619115 y- 5955938 Zone- ASP4 - -------------------- Total Depth: x- 619895 y- 5955945 Zone- ASP4 18. Directional Survey IS! Yes 0 No 21. Logs Run: MWD / GR / CCL / PRESS, One Other 5. Date Comp., Susp., or Aband. 12/26/2003 6. Date Spudded 12/11/2003 7. Date T.D. Reached 12/22/2003 8. KB Elevation (ft): KBE = 83' 9. Plug Back Depth (MD+ TVD) 13135 + 8936 10. Total Depth (MD+ TVD) . 13135 + 8936 11. Depth where SSSV set (Nipple) 2093' MD 19. Water depth, if offshore N/A MSL CASING SIZE 20" 13-3/8" 9-5/8" 5-1/2" 2-3/8" Memory Induction Log CASING, liNER AND CEMENTING RECORD SETTING DEPTH MD SETTING DEPTH TVD HOLE Top BOTTOM Top BOTTOM SIZE Surface 110' Surface 110' Surface 2934' Surface 2684' 29' 12027' 29' 8706' 11781' 12143' 8520' 8797' 11762' 12380' 8506' 8933' 22. WT. PER FT. Conductor 68# 47# 17# 4.6# GRADE L-80 L-80 L-80 L-80 23. Perforations open to Production (MD + TVD of Top and Bottom Interval, Size and Number; if none, state "none"): 2-3/8" Slotted Section MD TVD MD TVD 12284' - 12347' 8894' - 8922' 26. Date First Production: Not on Production Yet Date of Test Hours Tested 17-1/2" 12-1/4" 8-1/2" 3" 24. SIZE 3-1/2",9.2#, L-80 1b. Well Class: IS! Development 0 Exploratory o Stratigraphic Test 0 Service 12. Permit to Drill Number 203-176 13. API Number 50- 029-21866-01-00 14. Well Name and Number: PBU W-01A 15. Field / Pool(s): Prudhoe Bay Field 1 Prudhoe Bay Pool Ft 16. Property Designation: Ft ADL 047451 17. Land Use Permit: 20. Thickness of Permafrost 1900' (Approx.) ·~7Á.J;~.:"""; 1'2-, 1'/'3 ',.rJþ ii',7C¡'? ( rve> AMOUNT CEMENTING RECORD PUllED 8 cu yds Concrete 4323 cu ft PF, Top Job: 140 cu ft PF 2533 cu ft Class 'G' 371 cu ft Class 'G' Uncemented Slotted Liner TUelNG RECORD DEPTH SET (MD) 11798' PACKER SET (MD) 11688' 25. ACID, FRACTURE, CEMENT SaUEEZi;;, ETC. DEPTH INTERVAL (MD) 2000' PRODUCTION TEST Method of Operation (Flowing, Gas Lift, etc.): NIA Oil-Bel GAs-McF WATER-Bsl PRODUCTION FOR TEST PERIOD ... CALCULATED -IIr.. 24-HoUR RATE""" Oll-Bsl Flow Tubing Casing Pressure Press. GAs-McF WATER-Bsl AMOUNT & KIND OF MATERIAL USED Freeze Protected with 18 Bbls of MeOH CHOKE SIZE I GAS-OIL RATIO Oil GRAVITY-API (CORR) CORE DATA Brief description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water (attach separate sheet, if necessary). Submit core chips; if none, state "none". R Eel None 27. Form 10-407 Revised 12/2003 ORIGI~L~L JAN;2. 9t61D4 CONTINUED ON REVERSE SIDE ~ v~¡.'".,.~~1~, .', ' r', t1fL J\~~~ ,~,->- fEB 0 2~. / - GEOLOGIC MARKERS. 29. .... <JRMATION TESTS NAME MD TVD Include and briefly summarize test results. List intervals tested, and attach detailed supporting data as necessary. If no tests were conducted, state "None". Shublik A 12146' 8799' None Shublik B 12209' 8848' Shublik C 12241' 8869' Eileen 12277' 8890' Sadlerochit 12304' 8904' Sadlerochit (Invert) Sadlerochit (Revert) 12892' 8928' 13067' 8932' R E.'"(-: . ""- ,..$ JAN '\Ii ~., Ala;;~a 30. List of Attachments: Summary of Daily Drilling Reports, Well Schematic Diagram, Surveys 31. I hereby certify that the foregoing is true and correct to the best of my knowledge. Signed Terrie Hubble ~01Jt¡ {; f{u~_ Title Technical Assistant Date Ol-:¿q -OL{ PBU W -01 A 203-176 Prepared By Name/Number: Terrie Hubb/e, 564-4628 Well Number Drilling Engineer: Ted Stagg, 564-4694 Permit No. / Approval No. 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 1a: Classification of Service Wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. 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 4b: TPI (Top of Producing Interval). ITEM 8: The Kelly Bushing elevation in feet above mean low low water. Use same as reference for depth measurements given in other spaces on this form and in any attachments. ITEM 13: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). ITEM 20: True vertical thickness. ITEM 22: Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool. ITEM 23: 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 26: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-In, or Other (explain). ITEM 27: If no cores taken, indicate "None". ITEM 29: List all test information. If none, state "None". Form 10-407 Revised 12/2003 OD\(;''''':l\\- Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: Date From - To --------..- . 12/1/2003 06:00 - 07:00 07:00 - 08:00 08:00 - 09:00 09:00 - 10:00 10:00 - 11 :00 11 :00 -12:00 12:00 - 13:00 13:00 -14:00 14:00 - 15:00 15:00 -16:00 16:00 - 17:00 17:00 - 18:00 18:00 - 19:00 19:00 - 20:00 20:00 - 21 :00 12/9/2003 21 :00 - 22:00 22:00 - 23:00 23:00 - 00:00 00:00 - 06:00 ..... - Page 1 of 14 BP EXPLORATION Operations Summary Report W-01 W-01 REENTER+COMPLETE NORDIC CALISTA NORDIC 1 __Ho~r~_L~ask Code NPT 1.00 RIGU P 1.00 KILL P 1.00 BOPSURP 1.00 PULL P 1.00 BOPSURP 1.00 WHIP P 1.00 ZONISO P 1.00 STWHIP P 1.00 DRILL P 1.00 DRILL P 1.00 CASE P 1.00 CEMT P 1.00 CEMT P 1.00 BOPSURP 1.00 RUNCOMP Phase PRE DECOMP DECOMP DECOMP WEXIT WEXIT WEXIT WEXIT PROD1 PROD1 COMP COMP COMP COMP COMP 1.00 WHSUR P 1.00 RIGD P 1.00 BOPSURP 6.00 MOB P COMP COMP POST PRE Start: 10/17/2002 Rig Release: Rig Number: N1 Spud Date: 7/13/1982 End: 12/26/2003 Description of Operations PUMP SLACK MANAGEMENT KILL WELL ND TREE, NU BOPE, TEST PULL TUBING HANGER, PULL TUBING. NU CTD BOPE, TEST RUN AND SET WHIPSTOCK DOWNSQUEEZE CEMENT MILL WINDOW, DRESS DRILL BUILD, LATERAL STRIP IN BHA DURING PRESSURE DEPLOYMENT RUN CASING SWAP TO CONVENTIONAL COIL CEMENT LINER ND CTD BOPE, NU WOV BOPE PU PACKER, COMPLETION TUBING, GLMS, SSSV, CONTROL LINE, RIH, SPACE OUT, SET PACKER FREEZE PROTECT PURGE COIL WITH N2 ND BOPE, NU TREE Leave K Pad at 2345 on 12/8/03. Continue to move from K-10 to W-01 0600hrs update: Rig currently passing J Pad 0730 update: Rig pulled over at "Mary" pad entrance to allow traffic to pass prior to crossing river bridges. Continue moving Update 1020 hrs rig just west of "S" pad entrance. Rig arrive on location 13:00 hrs. Attempt to back over well. Remove hand rail from adjacent well house after consulting with pad operator. Spot rig over well. Agreed to accept rig 14:00 Set rig down and level rig. Remove tree cap. Install XO and NU BOP. PJSM for hoisting reel. Hoist reel Test BOP. AOGCC Chuck Shieve waived witnessing the BOP test. Continue to Test BOP's. Load MWD tool into pipe shed. PJSM to pull coil tubing across. Pull coil across pipe shed. Stab injector. Pull BPV with lubricator. Install Kendall coil connector. Pull and pressure test same. Trouble shoot e-line connection problem inside reel. Open well and bleed off some gas & fluid to Tiger tank. (whp:100 psi, dropping rapidly). IA:160 psi. Shut well in. Pressure builds back up in a few minutes. Repeat bleed operation. Same result. Bleed IA from 165 psi to trailer until fluid returns. IA 115 psi. Getting some gas & liquid. Pressure not dropping very fast. WEXIT MU nozzle assembly. RIH. Take gas & fluid to tiger tank. Tag WS at 12158' ctd. WEXIT Pump 100 bbls kcl water (2.0 bpm@2600 psi). Start flo pro down coil. 06:00 - 07:30 1.50 MOB P PRE 07:30 - 08:10 0.67 MOB P PRE 08:10 - 13:00 4.83 MOB P PRE 13:00 - 16:00 3.00 MOB P PRE 16:00 -19:00 3.00 RIGU P PRE 19:00 - 21 :00 2.00 RIGU P PRE 21 :00 - 00:00 3.00 BOPSURP PRE 12/10/2003 00:00 - 02:30 2.50 BOPSURP PRE 02:30 - 03:15 0.75 RIGU P PRE 03:15 - 03:30 0.25 RIGU P PRE 03:30 - 04:30 1.00 RIGU P PRE 04:30 - 06:00 1.50 RIGU P PRE 06:00 - 10:00 4.00 STWHIP P WEXIT 10:00 - 12:15 2.25 STWHIP P WEXIT 12:15 -15:30 15:30 - 16:00 3.25 STWHIP P 0.50 STWHIP P Printed: 12/29/2003 9:49: 13 AM . . Page 2 of 14 BP EXPLORATION Operations Summary Report Legal Well Name: W-01 Common Well Name: W-01 Event Name: REENTER+COMPLETE Contractor Name: NORDIC CALISTA Rig Name: NORDIC 1 Date I From - To Hours! Task! Code .....___ ...._. _.___.__1_ _______..__... 12/10/2003 16:00 - 18:00 2.00 STWHIP P 18:00 - 18:30 0.50 STWHIP P 18:30 - 19:10 0.67 STWHIP P 19:10-19:50 0.67 STWHIP P 19:50 - 22:20 2.50 STWHIP P 22:20 - 00:00 1.67 STWHIP P 12/11/2003 00:00 - 05:00 5.00 STWHIP P 05:00 - 06:45 1.75 STWHIP P 06:45 - 09:30 2.75 STWHIP P 09:30 - 11 :45 2.25 STWHIP P 11 :45 - 12:30 0.75 DRILL P 12:30 - 15:45 3.25 DRILL P 15:45 -16:15 0.50 DRILL P 16:15 - 18:00 1.75 DRILL P 18:00 - 20:10 2.17 DRILL P 20: 1 0 - 20:25 0.25 DRILL P 20:25 - 22:30 2.08 DRILL P NPT· Phase ... .. .--...--- WEXIT WEXIT WEXIT WEXIT WEXIT WEXIT WEXIT WEXIT WEXIT WEXIT PROD1 PROD1 PROD1 PROD1 PROD1 PROD1 PROD1 22:30 - 23:00 0.50 DRILL P PROD1 23:00 - 23:30 0.50 DRILL P PROD1 23:30 - 00:00 0.50 DRILL P PROD1 12/12/2003 00:00 - 01 :45 1.75 DRILL P PROD1 01 :45 - 02:30 0.75 DRILL P PROD1 02:30 - 05:00 2.50 DRILL P PROD1 05:00 - 07:30 2.50 DRILL N DFAL PROD1 07:30 - 10:00 2.50 DRILL N DFAL PROD1 10:00 - 12:00 2.00 DRILL N DFAL PROD1 12:00 - 12:15 0.25 DRILL N DFAL PROD1 12:15 - 13:45 1.50 DRILL P PROD1 Start: 10/17/2002 Rig Release: Rig Number: N1 Spud Date: 7/13/1982 End: 12/26/2003 Description of Operations -. ... ..--..--..- POOH displacing well to flo pro mud. 1.95 bpm@3100 psi. Take all well fluids to Tiger tank. Monitor well. No Flow. POH set back injector. LD nozzel and PU window milling bha. RIH tag at 12150'. Mill at 1.7 bpm 3460 psi = FS. 33K Up 12.5K DN Pinch point at 12148.6 ECD 10.7ppg Time milling .5 to 1 ftIhr 3600 psi WOB 400 - 600 # Mill to 12149.4' Continue to mill at 3550 psi, 1.7 bpm, 1.2k WOB, 10.7 ECD ppg, Mill to 12154 Appear to be in open hole. Drill to 12165'. Back ream through window at 0.2 fpm three times. Drift dry. Window smooth. Est top: 12148', btm:12154' (uncorrected) Circulate out of hole. MU open hole build assembly: 3.0" DPI bi-cent on 2.1 deg Baker extreme. RIH. Log initial GR tie in. Correlate to CNL and PDC logs. Log from 12120' to 12140'. Subtract 5' correction. Corrected window is 12143' to 12149'. Drill ahead from 12160'. 2975psi@1.55bpm fs 100 psi mw WOB:1k-2k#. ECD:10.54, 4800 psi. Drill to 12235'. Some stalls, avg ROP: 30 fph Continue to drill build at 3260 psi with 1.56 bpm WOB 3.7K, ROP 24 ftIhr, FS 3050 psi. DH tubing pressure 5430 psi, DH annular pressure 4832 psi. ECD 10.6 PPG Drill to 12290' Wiper to 12,170' resurvey 12,189 and 12,230 Directionally drill 1.5 bpm, 3250 psi, 3050 psi FS, DH annular pressure 4890, DH tubing pressure 5500 psi, ECD 10.68, WOB 3.6K, ROP 48 ftIhr. At 12,330 ROP increased gradually to 90+. Drill to 12,397 stack out once. Drill at 1.7 bpm 3780 psi 2.5K WOB, ROP 108 ftIhr, DH annular pressure 4995 psi. DH tubing pressure 5825 psi. ECD 10.8 ppg. Drill to 12,410 EOB. POH to 11850 circulating at 1.7 bpm. Circulate bottoms up collect last sample up. Precautionary clearing cutting from annulur prior to logging window. Log down 12,100' to 12,170' at 2.5 ftImin for GR data to merge PDC log with new wellbore per Anchorage geo request. POH. POH to surface. Change out BHA for lateral drilling assembly. RIH to 12060. Attempt to close EDC. Indication it only partially closed. Unable to function EDC. Diagonistics can't confirm position of EDC. EDC failed. POH for failed EDC sub. At surface. Unstab. Change out mwd tools. Replace EDC sub. Orienter acting up. Replace it too. Surface test good. PU tools MU to coil. Get on well. RIH. Log gr tie in from 12120'. Subtract 7' correction. Drill ahead at 12410'. 1.5 bpm@2900 psi fs. 200-400 psi mw. Printed: 12/29/2003 9:49: 13 AM . . Page 3 of 14 BP EXPLORATION Operations Summary Report Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: W-01 W-01 REENTER+COMPLETE NORDIC CALISTA NORDIC 1 Date ¡ From - To I Hours Task Code NPT Phase , --- ... --....-....-..-- 12/12/2003 12:15 - 13:45 1.50 DRILL P 13:45 - 14:15 0.50 DRILL P 14:15 - 16:30 2.25 DRILL P 16:30 - 18:00 1.50 DRILL P 18:00 - 18:30 0.50 DRILL P 18:30 - 19:30 1.00 DRILL P PROD1 PROD1 PROD1 PROD1 PROD1 PROD1 19:30 - 20:00 0.50 DRILL P PROD1 20:00 - 21 :00 1.00 DRILL P PROD1 21 :00 - 21 :45 0.75 DRILL P PROD1 21:45 - 23:00 1.25 DRILL P PROD1 23:00 - 00:00 12/13/2003 00:00 - 01 :20 PROD1 PROD1 1.00 DRILL P 1.33 DRILL P 01 :20 - 02:30 1.17 DRILL P PROD1 02:30 - 06:00 3.50 DRILL P PROD1 06:00 - 07:00 1.00 DRILL P PROD1 07:00 - 09:15 2.25 DRILL P PROD1 09:15 - 11 :30 11 :30 - 13:30 2.25 DRILL P 2.00 DRILL P PROD1 PROD1 13:30 - 14:30 1.00 DRILL P PROD1 Start: 10/17/2002 Rig Release: Rig Number: N1 Spud Date: 7/13/1982 End: 12/26/2003 Description of Operations ....-.-.--.--- WOB:1 K-3K#. ECD:10.7 ppg, 4900 ann /5475 bore psi. ROP:50-80 fph. Slight amount of gas with bottoms up. Drilling erratic. Overpulls when PU off btm. Short trip to outside of window. Hole smooth, weight transfer good while tripping. Drill ahead. 1.5bpm@2850 psi fs. 200-400 psi mw. WOB:2k-3k#. 10.6 ECD, 4880/5536 psi ann/bore. Drill to 12600' . Drill ahead to 12625 Wiper to tail pipe Directionally at 2600 spi 1.7 bpm, 2.1 K WOB, 120-170 ftlhr, DH annular pressure 4940 psi, DH tubing pressure 5780 psi, ECD 10.7.3150 psi FS. drill to 12700. Drill at 1.6bpm, 3000 psi FS, 3580 psi WOB2.1 K, ROP 180 ftlhr,DH annular pressure 4926 psi, DH tubing pressure 5888 psi, ECD 10.7 ppg.400 psi MW. Drill to 12738. Wiper to window at 12160. Directionally drilling at 1.6 bpm, 3585 psi, 2.5 K WOB, 126 ftlhr,4940 psi DH annular pressure, 58879 psi DH tubing pressure. Drill to 12862, Wiper to window. Similtaneous operation swap to new mud. Directionally drill at 3250 psi 1.6 bpm,with new mud at bit DH annular pressure 4930 psi, DH tubing pressure 5755 psi. ECD 10.7. WOB 2.1K , ROP 168 ftlhr. Periodic stacking. FS 2600 psi. Drilling at 12950 new mud back to surface. DH annular pressure 4775 psi, DH tubing pressure 5588 psi. ECD 10.2450 psi MW. Drill to 12994'. Stacking occasionally sticky. Wiper to window. Clean trip. Directionally drill 1.6 bpm, at 3230 psi, 2600 psi FS, 3K WOB, 132 ROP, DH annular pressure 4733 psi, DH tubing pressure 5147 psi, ECD 10.2. Experiencing some stacking. Drill to 13,114. Wiper to the window. Hole in good shape. Directionally drill at 1.6 bpm, 2900 psi, 2600 psi FS, 3.4K WOB, DH annular pressure 4757 psi, DH tubing pressure 5338 psi. Drill to 13250'. Drill ahead. 1.75 bpm @ 3000 psi fs. 300-500 psi mw. WOB: 2.5K#. ECD/ann/bore: 10.54/4915/5362 psi. ROP: 80-140 fph. Drill to 13260'. PU to start short trip. Coil stuck. Circulate btms up, then relax hole while spotting crude transport. Came free. Short trip to window. Log gr tie in from 12120'. Add 7' correction. Continue wiper in hole. Install coil clamp inside reel, to prep for using base wrap to reach TD. Tight at 13095 to 13140. Ream thru at reduced pump rate. Back ream. Another spot at 13180'. 32k# up, 12k# dn wt at TD. Drill ahead to 13401'. 2600 psi @1.59 bpm. Wiper trip to tbg tail at 11798' to clean hole and 5-1/2" liner. Tight spots from 13100' to 13180' mostly clean. Drill ahead. 2600 psi @ 1.55 bpm 300-500 psi mw. WOB:2k-3.5k#. ECD/ann/bore: 10.4/4772/6000 psi. Drill to 13405'. Unable to make any progress. Motor work & WOB good. Try to stall motor. Unable to stall. Note some rubber on Printed: 12/29/2003 9:49: 13 AM 18:00 - 20:00 20:00 - 20:30 20:30 - 21 :20 21 :20 - 22:30 22:30 - 23:19 23: 19 - 23:30 23:30 - 00:00 12/14/2003 00:00 - 00:30 00:30 - 02:00 02:00 - 04:20 04:20 - 04:50 04:50 - 05:45 05:45 - 08:30 08:30 - 09:30 09:30 - 11 :30 11 :30 - 11 :45 11 :45 - 13:00 13:00-17:15 17:15-18:30 . . BP EXPLORATION Operations Summary Report 2.00 DRILL 0.50 DRILL N 0.83 DRILL N 1.17 DRILL N 0.82 DRILL N 0.18 DRILL N 0.50 DRILL N 0.50 DRILL P 1.50 DRILL P 2.33 DRILL P 0.50 DRILL P 0.92 DRILL P 2.75 DRILL N 1.00 DRILL N 2.00 DRILL N 0.25 DRILL N 1.25 DRILL N 4.25 DRILL P 1.25 DRILL P Phase P N N PROD1 DFAL PROD1 DFAL PROD1 Legal Well Name: W-01 Common Well Name: W-01 Event Name: REENTER+COMPLETE Contractor Name: NORDIC CALISTA Rig Name: NORDIC 1 Date I From - :0 ' H_ours I Task : Code i NPT 12/13/2003 13:30 - 14:30 1.00 DRILL 14:30 - 16:45 2.25 DRILL 16:45 - 18:00 1.25 DRILL N DFAL PROD1 PROD1 Tie -in Correction -5" PROD1 PROD1 PROD1 PROD1 PROD1 PROD1 PROD1 PROD1 PROD1 PROD1 DFAL PROD1 DFAL PROD1 DFAL PROD1 DFAL PROD1 DFAL PROD1 PROD1 PROD1 Page 4 of 14 Start: Rig Release: Rig Number: N1 Spud Date: 7/13/1982 End: 12/26/2003 10/17/2002 Description of Operations ....._ ..._u _u_._._____ shaker. Suspect motor has chunked out. POOH to check motor & bit. At surface. Get off well. LD motor & bit. One broken nose cutter, two broken back reamer cutters. Motor stator chunked out, unable to turn shaft. MU to coil. Get on well. RIH. RIH to 12408. Attempt to drill experiencing stacking and over pulls Drill to 10422.Stackout. PU can't get back to bottom with pumps on. Back ream to shales at 13100'. Sticky 13400 -13380 and 13150 to13058 MW 200 psi @ 13138. MW 800 psi @ 13100, Over pull 50k. RIH pumping.3 bpm stackout. PU RIH pumping 1.6 pbm, PU to 13 000 . RIH stacking @ 13055 . Backream thru 13055 again. RIH 1.6 bpm stacking@ 13141. Back ream 13155 to 13095, RIH 1.6 bpm,2770 psi FS, RIH to 13410. No Problem. PU WT 30K versus 50 prior to backreaming. Drill at 1.6 bpm, 2770 psi FS, 3545 psi, WOB 3.3K, 126 ROP, DH annular pressure 4847 psi, DH tubing pressure 5910 psi, EDC 10.6, Drill to 13470. Directionally drill to 13,500. Wiper to 12,200. Sticky coming off bottom at 13,125 took 5K in surface wt. Directionally drill at 1.6 bpm 3070 psi, 2700 psi FS, 3.6K WOB, 150 ftIhr ROP, DH annular pressure 4870 psi, DH tubing pressure 5400psi, ECD 10.48 ppg, Drill to 13513 having trouble sliding. Pump lub pill.( I drum Flo Lub in 20 bbl FloPro). Pill improved sliding. Drill to 13595. 600 psi motor work, 3K WOB,pick-up clean. Hard spot? Drill to 13600. No progress after an hour. Wiper to 13,000. Clean pu off bottom. Attempt to drill. No progress. Stator rubber in cuttings. Unable to stall. POH At surface. Unstab. LD motor. Found small service plug had backed out from motor housing. Bit missing backream cutters. MU replacement motor with a used HC bicenter. MU to coil. Get on well. RIH. Log gr tie in from 12120'. Subtract 8' correction. Run in open hole. Set down at 12300' Work thru. Set down at 13515'. Work thru. 13100-140' clean. Drill ahead. 2700psi@1.4 bpm fs 300-500 psi mw. WOB:2K-3K#. ROP: 50-70 fph ECD/ann/bore: 1 O. 7/4926/5500psi. Weight transfer deteriorating. New mud ordered out. Drill to 13744' Short trip while displacing to new flo-pro. Start new mud down hole. 10ppb Klagard, 3% lubtex, 2% flo-Iub, 35K Isrv. Free spin dropped from 2700 psi to 2350 psi @ 1.55 bpm with new mud to bit. Printed: 12/29/2003 9:49: 13 AM .... . BP EXPLORATION Operations Summary Report Page 5 of 14 Legal Well Name: W-01 Common Well Name: W-01 Spud Date: 7/13/1982 Event Name: REENTER+COMPLETE Start: 10/17/2002 End: 12/26/2003 Contractor Name: NORDIC CALISTA Rig Release: Rig Name: NORDIC 1 Rig Number: N1 I Date From - To ¡ Hours I Task Code NPT Phase Description of Operations ..... ........--.----.-- un. .__ _________.._ 12/14/2003 18:30-19:10 0.67 DRILL P PROD1 Back ream 180 degrees out @ 1.6 bpm 13150 - 13040. MW and over pulls at 13096 19:10 - 19:35 0.42 DRILL P PROD1 Complete wiper. Set down 13103. Over pull. Work past. Back ream 180 degrees out @ 1.6 bpm 13150 - 13040. Second time 19:35 - 19:55 0.33 DRILL P PROD1 Complete wiper. Clean thru 13050 thru 13180. 19:55 - 22:10 2.25 DRILL P PROD1 Drill at 1.6 bpm, 2630 psi, 2400 psi FS, 1.7K WOB. 84 ft/hr ROP, DH annular pressure 4615 psi, DH tubing pressure 5280 psi, ECD 10. ppg, Having trouble sliding. Drill to 13,786'. Pump pill (1 drum Flo Lub in 20 bbls Flo Pro). 1.6 bpm 1.9 K WOB, 2700 psi, FS 2300 psi, ROP 60. Steady drilling. Pill worked. Got positive surface weight and an increase of 200# WOB. DH annular pressure 4680 psi, DH tubing pressure 5148 psi. ECD 10.2 Drill to 13838'. 22:10 - 23:50 1.67 DRILL P PROD1 Wiper. Clean PU. Hole on good shape. 23:50 - 00:00 0.17 DRILL P PROD1 Drill to 13845'. 12/15/2003 00:00 - 03:00 3.00 DRILL P PROD1 Directionally drill 1.6 bpm 2660 psi, FS 2350 psi, 2K WOB, 80 ft/hr, DH annular pressure 4650 psi, DH tubing pressure 5100 psi, Having trouble sliding. Try 20 bbl Flo Pro with 8ppb 1.13 sg. copolymer beads. When beads turn corner pu lay in 3 bbl. Drill ahead with trouble sliding. No noticable improvement. Drill @ 1.6 bpm 1.7K WOB ROP 15ft/hr. Geo think were back in the 45N. shale. Drill to 13942'. 03:00 - 04:45 1.75 DRILL P PROD1 Wiper trip to window. 13080 mw and over pull. Set down at 13105 04:45 - 07:30 2.75 DRILL P PROD1 Directionally drill at 1.6 bpm, 2460 psi FS, 2680 psi, 1 k WOB, 60 ROP, DH annular pressure 4688 psi, DH tubing pressure 5460 psi, ECD 10.2 ppg. Drill to 14010'. Hole sticky on btm. 07:30 - 08:00 0.50 DRILL P PROD1 Wiper trip to 13800'. 08:00 - 09:30 1.50 DRILL P PROD1 Drill ahead. Having a lot of trouble getting weight to bit. Difficult to get to btm without reducing pump rate. 09:30 - 11 :00 1.50 DRILL P PROD1 Wiper trip to window. Ream shale from 13780' to 13900'. Motor work but only slight overpulls. 11 :00 - 17:30 6.50 DRILL P PROD1 Drill ahead with several short wiper trips. Drill to 14109'. Pump 17 bbl new mud with 9 %Iibs. Experience Hi circulating pressures. Switch back to active system. Decide to POH 17:30 - 22:00 4.50 DRILL N FLUD PROD1 POH circulating at .3 bpm 4500 psi. Check surface systems. Open EDC to determine if BHA is plugged. No Change. DH pressures are tracking. Look like fluid issue. Thick fluid blinding shaker. Thick fluid at surface 50 bbl in to displacement of 9% lub mud. Had discussions with MI Dean Briant. The unpumped 9% mud properties had changed substantailly while in pits. Dean feels concentration to high. Decide to swap out mud systen to recondition system. NO vac trucks available due to week of bad weather, operaters and 16 hr rule. 22:00 - 23:00 1.00 DRILL N FLUD PROD1 Inspect BHA components. Change out bit one backreamer missing. 23:00 - 00:00 1.00 DRILL N FLUD PROD1 RIH circulating 1.6 bpm at 2164 psi. ( mud looking OK) 12/16/2003 00:00 - 01 :15 1.25 DRILL N FLUD PROD1 RIH to tie-in at 12120'. 01:15 - 01:30 0.25 DRILL N FLUD PROD1 Tie-in -11 'correction. 01 :30 - 03:00 1.50 DRILL N FLUD PROD1 RIH to 14103'. MW at 13870, Set down 13880, & 13902. Backream to 13850. RIH miminum rate. Set down at 13905, Back ream @ 1.6 bpm from 13920 to 13880. Printed: 12/29/2003 9:49: 13 AM . . Page 6 of 14 BP EXPLORATION Operations Summary Report PROD1 Attempt to Directionallly drill at 1.55 bpm. 2950 psi FS Hole ratty 14103 to 13900 28K over pull @ 13903 Stuck 13900+- with full returns 1.6 bpm. Set -8K surface while circulating 1.6 bpm. Pop Free. Wiper to window. Wait on mud. Phase 2 weather really slowing down trucking. Mud on location. Move snow, spot trucks. Begin displacing to new mud while running in hole. BHA stopping at 12269' (btm of Shublik). Try varying pump rate, pipe speed, tool face from 90L to 10R (originally drilled with 10L TF). No progress. Stopping abruptly, clean pick ups, no overpull. Discuss options with Town Team. Decide to PU 2.1 motor with DPI SR933. (same assembly used to drill this section) POOH. Continue mud swap to new flo pro system. Change out BHA for 2.1 bend motor. RIH to 12120. Tie - in. correction.-8' RIH .4 bpm TF 0 degrees 12263 set down. 1 bpm 12276 set down, reactive torque shifting tool face. .1.7 bpm. Work thru.rih to 12410. Back ream 180 out. Fin ream/backream to 12450' 1.6/3000 and clean. Wiper to window and CT press on a gradual rise. . . stabilized at 1.6/4200 when pulling 25'/min POOH for lateral assy. Pressure gradually came back down to normal 1.6/2730 by 7000' (at about btms up), but then started increasing again. Then, got a bunch of metal flakes (up to 1/2" long), paint (from pits?) and small aluminum flakes over shaker just before tag up. Mud from CT is very viscous (over 100 LSRV). Microscope showed scale/plastic coating (from tubing) and metal from tubing wall DPRB PROD1 Adjust motor bend to 1.1 deg. Bit condition same as it went in the hole. Change bit to DS1 00 Displace viscous mud in CT w/ sheared mud. Work on pit mud properties while RIH RIH w/ BHA #9 Continue RIH w/lateral assy Log tie-in down from 12120'. Corr -8.0' RIH thru window, clean and go thru 12269', clean. Continue wiper 1.6/2830 30'/min and set down at 12980', then at 13115' several times. RIH, clean to 13815' and set down 32k, 13k Ream sloughing shale from 13815' 1.6/3940/60-90L with 10-20k overpulls and motor work (ECD=1 0.46). Get to 13836' and acts like ledge. Work to 13859' and set down. Try to drill it and made little progress. Start losing ground back to 13836', then 13820'. Work back down to 13859' and can't drill it. Poked around a little too long and were temporarily immobile-give up PROD1 Wiper to window while discuss. Minor overpulls at 13800', 13000'. Clean thru 12269' PROD1 POOH to perform weekly BOPE test while formulate sidetrack plan Still Phz 1/2 Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: W-01 W-01 REENTER+COMPLETE NORDIC CALISTA NORDIC 1 Date , I From - To Hours Task ¡ Code! NPT Phase i 12/16/2003 03:00 - 04:00 0.00 DRILL P 04:00 - 05:00 1.00 DRILL P PROD1 05:00 - 09:30 4.50 DRILL N FLUD PROD1 09:30 - 10:00 0.50 DRILL P PROD1 10:00 - 11 :00 1.00 DRILL P PROD1 11 :00 - 11: 15 0.25 DRILL N DPRB PROD1 11:15 -13:00 1.75 DRILL N DPRB PROD1 13:00-14:15 1.25 DRILL N DPRB PROD1 14:15 - 16:55 2.67 DRILL N DPRB PROD1 16:55 -17:10 0.25 DRILL N DPRB PROD1 17:10-18:50 1.67 DRILL N DPRB PROD1 18:50 -19:15 0.42 DRILL N DPRB PROD1 19:15 - 21:15 2.00 DRILL N DPRB PROD1 21 :15 - 22:30 1.25 DRILL N 22:30 - 00:00 1.50 DRILL N DPRB PROD1 12/17/2003 00:00 - 00:25 0.42 DRILL N DPRB PROD1 00:25 - 00:45 0.33 DRILL N DPRB PROD1 00:45 - 01 :45 1.00 DRILL N DPRB PROD1 01 :45 - 03:25 1.67 DRILL N DPRB PROD1 03:25 - 04:15 0.83 DRILL C 04:15 - 06:15 2.00 DRILL C Start: 10/17/2002 Rig Release: Rig Number: N1 Spud Date: 7/13/1982 End: 12/26/2003 Description of Operations .....------.- Printed: 12/29/2003 9:49: 13 AM . . BP EXPLORATION Operations Summary Report Page 7 of 14 Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: W-01 W-01 REENTER+COMPLETE NORDIC CALISTA NORDIC 1 Start: 10/17/2002 Rig Release: Rig Number: N1 Spud Date: 7/13/1982 End: 12/26/2003 Date From - To Hours Task Code NPT. Phase Description of Operations .. ._n___..________. ... ....-.-- 12/17/2003 06:15 -15:30 9.25 BOPSUB C PROD1 Test BOP. Test witnessed by John Crisp AOGCC. 15:30 - 18:30 3.00 BOPSURN PROD1 Repair and retest HCR 18:30 -19:15 0.75 STKOH C PROD1 MU WII 2-1/2" OH aluminum WS assy on BHI running tools 19:15 - 19:30 0.25 STKOH C PROD1 RIH w/ BHA #10. Stop at 331' after notice WHP at 200 psi and increasing. Open return line valves and bleed off pressure. Start pump to verify can eire, but (EDC not opened and) CTP rapidly increased to 2000 psi. SD pump, bleed off press. PUH 5', clean. RIH and stacked wt at 331 '. May have started to set WS 19:30 - 19:40 0.17 STKOH X HMAN PROD1 POOH to check BHA 19:40 - 20:00 0.33 STKOH X HMAN PROD1 LD BHI running tools. LD WII WS assy. Top shear pin in WS was set for 1200 psi and had sheared and top slips had opened (rubber retainer still in place) 20:00 - 21 :20 1.33 STKOH X HMAN PROD1 WO WII to bring another WS 21:20-22:10 0.83 STKOH X HMAN PROD1 Attach 2nd WS pinned for 2400 psi to running tools. MU BHI tools 22:10 - 00:00 1.83 STKOH C PROD1 RIH w/ BHA#10RR 12/18/2003 00:00 - 00:25 0.42 STKOH C PROD1 Log down from 12120'. Corr -10' Phz 1 00:25 - 00:35 0.17 STKOH C PROD1 RIH to set down at 12260' 00:35 - 01 :00 0.42 STKOH X DPRB PROD1 Attempt to get by 12260' at various speeds, etc. Solid set downs each time and acts like ledge 01 :00 - 03:15 2.25 STKOH X DPRB PROD1 POOH w/ WS 03:15 - 04:00 0.75 STKOH X DPRB PROD1 LD BHI assy. LD WS assy. Found sticky whitish clayball on anchor nose. Missing retaining rubber on top slips and all slips were packed with clay MU 2.1 motor and STR 324 bit 04:00 - 06:20 2.33 STKOH X DPRB PROD1 RIH w/ BHA #11 06:20 - 06:40 0.33 STKOH X DPRB PROD1 Tie -in -12 correction. 06:40 - 06:50 0.17 STKOH X DPRB PROD1 PJSM 06:50 - 10:30 3.67 STKOH X DPRB PROD1 RIH set down 12263. Work thru. three stalls. RIH to 12900 no problem. Back ream 180 TS back to 12200'. RIH 12400. No problem. Back ream 120 TS to 12200. RIH to 12400. No Problem. Back ream 225 TF to 12200. RIH 12400 backream. No Problems. Backream 180 TF. RIH to 12900. Pump 5 bbl sweep and displace with used mud system from Nordic 1. Circulating at 1.5 bpm at 2550 psi. 10:30 -13:00 2.50 STKOH X DPRB PROD1 POH. 13:00 - 13:30 0.50 STKOH X DPRB PROD1 LD 2.1 cleanout assy and PU Weatherford Aluminum Billet open open whipstock. 13:30 - 13:50 0.33 STKOH X DPRB PROD1 RIH. Tagged in SSSV nipple. Set down in sssv nipple numerous times. No Go 13:50 - 14:30 0.67 STKOH X DPRB PROD1 POH upper slips on anchor rattehed up a couple of wickers. Won't gage 14:30 - 17:45 3.25 STKOH X DPRB PROD1 Wait on arrival of new anchor. 17:45 - 18:35 0.83 STKOH X DPRB PROD1 MU new anchor to WS. MU BHI assy 18:35 - 20:35 2.00 STKOH X DPRB PROD1 RIH w/ BHA #12RR 20:35 - 20:55 0.33 STKOH X DPRB PROD1 Log tie-in down from 12120' 0.7/1800. Corr -11.0' 20:55 - 21 :05 0.17 STKOH X DPRB PROD1 RIH and set down at 12268', solid. PUH to new set depth 32k 21 :05 - 21 :20 0.25 STKOH C PROD1 Close EDC. Pressure to 3000 psi to activate slips. Set WS with billet top at 12200' ELMD. PUH 30k. Open EDC 21 :20 - 23:05 1.75 STKOH C PROD1 POOH 23:05 - 00:00 0.92 STKOH C PROD1 LD WS setting tool. MU KO BHA Printed: 12/29/2003 9:49: 13 AM . . Page 8 of 14 BP EXPLORATION Operations Summary Report Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: W-01 W-01 REENTER+COMPLETE NORDIC CALISTA NORDIC 1 Date From - To : Hours Task \ Code NPT Phase 12/19/2003 00:00 - 02:00 2.00 STKOH C PROD1 02:00 - 02:25 0.42 STKOH C PROD1 02:25 - 02:45 0.33 STKOH C PROD1 02:45 - 04:30 1.75 STKOH C PROD1 04:30 -13:15 8.75 STKOH C PROD1 13:15-15:15 2.00 STKOH C PROD1 15:15 -16:10 0.92 STKOH C PROD1 16:10 - 18:15 2.08 STKOH C PROD1 18:15 - 18:30 0.25 STKOH C PROD1 18:30 - 18:45 0.25 STKOH C PROD1 18:45 - 21:00 2.25 STKOH C PROD1 21 :00 - 22:10 22: 10 - 22:45 22:45 - 00:00 1.17 STKOH C 0.58 STKOH C 1.25 STKOH C PROD1 PROD1 PROD1 12/20/2003 00:00 - 01 :20 1.33 STKOH C PROD1 01 :20 - 02:00 0.67 STKOH C PROD1 02:00 - 03:30 1.50 STKOH C PROD1 03:30 - 03:55 0.42 STKOH C PROD1 03:55 - 04:15 0.33 STKOH C PROD1 04:15 - 04:35 0.33 STKOH C PROD1 04:35 - 05:20 0.75 STKOH C PROD1 05:20 - 05:45 0.42 STKOH X SFAL PROD1 05:45 - 06:00 0.25 STKOH X SFAL PROD1 06:00 - 07:45 1.75 STKOH X SFAL PROD1 07:45 - 13:00 5.25 STKOH X SFAL PROD1 13:00 - 15:45 2.75 STKOH X SFAL PROD1 15:45 - 16:00 0.25 STKOH X SFAL PROD1 16:00 - 16:30 0.50 STKOH X SFAL PROD1 16:30 - 17:30 1.00 STKOH C PROD1 Start: 10/17/2002 Rig Release: Rig Number: N1 Spud Date: 7/13/1982 End: 12/26/2003 Description of Operations ------...--.--.-.- - ..... .._-_.. .. - -..--- ...-----.. .-----.----. RIH w/ BHA #13 (2.1 deg motor, STR324 bit) Log tie-in down from 12120'. Corr -10' RIH thru window, clean. Tag WS at 12202' and stall. PUH 33k. RIH See first motor work at 12201.3'. Begin sidetrack 1.6/3250/45L. Drill to 12205' and appear to be off. Control drill to 12207' Drill from 12207' 1.6 bpm 30L off face of billet. 1.6 bpm 3900 psi 3350 psi FS DH annular pressure 5080 psi, DH tubing pressure 3920 psi, ECD 11.0 ppg WOB 4.5K, ROP 120, Drill to 12476. End of build. POH. Dial down motor to 0.9 degree and change to a bicenter bit. RIH to 12,120' Tie - in correction -11' RIH. tag up at 12,480. Directionally drill at 1.6 bpm 3775 psi, 3300 psi FS, DH annular pressure 5000 psi, DH tubing pressure 5800 psi, 10.9 ECD, 2.2 k WOB, ROP 50 ftlhr. Reflection meeting Drill from 12552' 1.6/3200/80L to 12610' and stacking Wiper to window, clean thru sidetrack point both ways Drill from 12610' 1.6/3200/135R with several BHA length backreams. Hit a hard spot at 12645' w/ numerous stalls. Drill to 12657' Phz 2 Drill from 12657' 1.6/3200/90R to level out at 8845-50' TVD. Drill to 12720' and stacking Wiper to window, clean both ways Drill from 12720' 1.6/3200/135-40R to hold at 8845' TVD and drill to 12804' Wiper to window while swap to new mud (3% L T, 1.5% FL, 14# KG) Phz 1/2 Log tie-in down from 12100'. Corr +7' RIH to TD tagged at 12810' Drill from 12810' 1.6/2600/90R with new mud. Drill to 12855' Wiper while wo BHI to reboot PC's Unable to fix (tool communication problem), fin wiper to window POOH for MWD failure Change out MWD. Pump slack management. cut 192' coil, Rehead. Phz 1 Well on vaccuum. 4 bbl to fill. RIH gas and oil in returns. Tie - in correction -10'. RIH at .5 bpm set down 12422' ,12486', orient 60L continue to rih, 12500 MW to 12560 . Tag at 12845'. Attempt to directionally drill 1.6 bpm, at 3250 psi FS, Loss rate .8 bpm. Back ream 12845 to with 400 psi increase in circulation rate. Circulating rate increasing to 3780 psi at 12560 pressure returned to nornal and losses stopped. Continue to backream to 12350 await on bottoms up. Nothing in bottoms up. 1.3 bpm at 2417psi. Printed: 12/29/2003 9:49:13 AM Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: Date From - To ......... .--......-....-- 12/20/2003 17:30 - 19:00 19:00 - 19:30 . . Page 9 of 14 BP EXPLORATION Operations Summary Report W-01 W-01 REENTER+COMPLETE NORDIC CALISTA NORDIC 1 Hours I Task I Code NPT Phase 1.50 STKOH C PROD1 0.50 STKOH C PROD1 19:30 - 19:50 0.33 STKOH C PROD1 19:50 - 20:05 0.25 STKOH C PROD1 20:05 - 20:40 0.58 STKOH C PROD1 20:40 - 21 :00 0.33 STKOH C PROD1 21 :00 - 21 :45 0.75 STKOH C PROD1 21:45 - 22:35 0.83 STKOH C PROD1 22:35 - 22:50 0.25 STKOH C PROD1 22:50 - 23:45 0.92 STKOH C PROD1 23:45 - 00:00 0.25 STKOH C PROD1 12/21/2003 00:00 - 00:40 0.67 STKOH C PROD1 00:40 - 00:55 0.25 STKOH X DFAL PROD1 00:55 - 01 :15 0.33 STKOH X DFAL PROD1 01 :15 - 03:00 1.75 STKOH X DFAL PROD1 03:00 - 03:50 0.83 STKOH X DFAL PROD1 03:50 - 05:35 1.75 STKOH X DFAL PROD1 05:35 - 06:30 0.92 STKOH N FLUD PROD1 06:30 - 12:00 12:00 - 12:30 12:30 - 12:50 12:50 - 16:00 5.50 STKOH N FLUD PROD1 0.50 STKOH X 0.33 STKOH X 3.17 STKOH X FLUD PROD1 FLUD PROD1 FLUD PROD1 Start: 10/17/2002 Rig Release: Rig Number: N1 Spud Date: 7/13/1982 End: 12/26/2003 Description of Operations RIH 1.5 bpm, 2570 psi FS, Drill at 2970 psi 2.7K WOB, 105 ROP, DH annular pressure 4650 psi, DN tubing pressure 5385 psi, ECD 10.1 ppg. Drill ahead 1.6/2850/75R at 89 deg and stacking with sticky pickups to 12930' Drill from 12930' 1.6/2850/90R and having trouble sliding along with sticky pickups. Mud is dark brown from crude and assume we have lost lubricity. A little low on volume too. Drill to 12970'/order new mud GR is staying hot at 300+ api. Do a 150' wiper to check GR and see that it is working normally-assume we plowed back into Shublik. See GR character change at 12890' (8844' TVD) Drill from 12970' 1.6/2850/160R and begin aggressive drop. Drill to 12991' and penetration rate picked up so assume back in sand Wiper to EOT, then open EDC while RIH to remove any cuttings in liner Log tie-in down from 12100'. Corr +6'. Close EDC RIH thru window and sidetrack point, clean. Set down at 12292' w/ LS TF. RIH w/ HS TF and had set downs and motor work at 12317',12325',12338'. RIH to TD, clean and tag at 12991 ' Drill from 12991' 1.6/2860/130R and continue in 300+ api formation at 88 deg. Drilling too good to be shale. Drill to 13058' Wiper to 12850'. GR returns to normal. Wiper was clean Drill from 12991' 1.6/2900/165R and begin swap to new mud. GR is back to normal at 13080'. Drill to 13120' (8850' TVD) Wiper to window Fin wiper to window, clean (had 2.5k extra string wt due to new mud while RIH). Tag at 13120' Attempt to get motor to drill and got no differential pressure. Definitely getting wt to bit. Assume motor failure Wiper to window POOH for motor Change motor, bit RIH w/ BHA #16 (0.9 deg motorIDS100 bit) Park at 11246' after starting to lose returns and abnormally high CTP. Started getting white viscous mud back over shaker. Continue to circ 0.5/0/3/2520 while yo-yo'ing pipe and limiting ECD to 12.3 ppg. Dump the nasty stuff. Assuming IA is leaking a chemical to tubing and contaminating the mud. Bleed IA from 172 psi to zero and got all fluid (diesel/crude) Communication outage DIMS out of service. Experiencing high pressure while circulating Rlh circulating limiting ECD to < 12.3 ppg had to reduced rate to .23 bpm at 1700 psi. MI investigating fluid properties. Looks like latex paint coming across shaker. Properties improved as we circulated. Maybe insuffient shearing. Try experiment shearing thru hopper seen improved fluid properties. Will try to drill. Continue to RIH 1.6 bpm 2300 psi. Fluid looking good. Tie - in correction -10 correction. Phz 1 ends RIH .6 bpm @ 12,300 had MW , Pressure increases look like some thing around us. POH 15 ft / min pressure back to Printed: 12/29/2003 9:49:13 AM Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: ....... . . Page 10 of 14 BP EXPLORATION Operations Summary Report W-01 W-01 REENTER+COMPLETE NORDIC CALISTA NORDIC 1 Start: 10/17/2002 Rig Release: Rig Number: N1 Spud Date: 7/13/1982 End: 12/26/2003 Date From - To ,Hours Task' Code i NPT Phase ............ .........- .....---.....------.--.-...---.---...-. ___________._______.__..._n. ___ 12/21/2003 12:50 - 16:00 16:00 - 18:30 18:30 - 19:30 19:30-21:00 21 :00 - 21 :45 21:45 - 22:30 22:30 - 00:00 12/22/2003 00:00 - 00:40 00:40 - 00:55 00:55 - 01 :50 01 :50 - 02:15 3.17 STKOH X 2.50 STKOH X 1.00 STKOH X 1.50 STKOH X 0.75 STKOH X 0.75 STKOH X 1.50 STKOH X 0.67 STKOH X 0.25 STKOH X 0.92 STKOH X 0.42 STKOH X Description of Operations FLUD PROD1 normal. RIH 330 TF, 1 bpm @ 12325' pressure up Thick mud? Then back to normal pressure after a few minutes. Nothing obviuos on bottons up. Continue to RIH 1.6 bpm 2950 psi FS . RI H set down 13060', Orient 120 TF, set down at 13106 tag at 13124'. Getting wt to bit but will not slide. Backed ream four times at differnt TF's. No Go. Unable to get BHA to slide. Decide to swap mud to used Nordic system. FLUD PROD1 Backream at 1.6 bpm 2ft/min. While waiting on arrival of mud. FLUD PROD1 RIH 1.6/2800 and had lost the 2.5k extra string wt from previous wiper (not sliding as good). IA at 173 psi. Bleed down lA, gas initially then changed to fluid and pressure stabilized at 80 psi while bleeding. SIIA after getting approximately 4 bbls back, ISIP 120, 15 min 150. Attempt to drill and no motor work at 13120' FLUD PROD1 Wiper to 12300' while MIRU trucks. Motor work at 12530' on RIH 1.6/3500. Begin mud swap to N1 used system w/3% L T, 2% FL and 14# KG. Preceeded used mud with a 10% L T pill mixed in same mud. Several set downs 12940-13010' FLUD PROD1 Tag TD at 13130' 1.6/3700 and got differential to bit. Drill ahead at a slow P rate with 0-200 psi differential w/ max neg wt 1.6/3700/135L. DD's have changed TF to left side so this may be compounding problem in combination with maybe penetrating a shale. 100+ api showing on GR 13115' after drilling the first few feet. Drill to 13140' IA 173 FLUD PROD1 At 13140', progress stopped-no diff, max stacking, clean pickups. When new mud was nearly back to surface, CTP started increasing while ECD has been on a gradual rise from 10.2 ppg (prior mud system) to 11.7 ppg. Started losing returns 1.6/1.4/4000. Reduce rate to keep ECD below 12.3 ppg. Begin wiper while discuss Note: DIMS Mud Report shows bottoms up mud properties FLUD PROD1 Pull BHA into 5-1/2" liner and circ out white viscous mud (along with a bunch of shale) beginning at 0.5/0.3/2200 ECD 12.3. Gradually work rate up as fluid sheared in the hole. Dump the contaminated fluid. Discussions are leaning toward suspending ops, but need data to decide if well is worth coming back to. Contact PDS for Induction log. Will take about 4 hours for a tech to arrive with tool since another job is in progress FLUD PROD1 Continue circ and condition mud with BHA in 5-1/2" 1.6/3730 ECD11.0ppg IA173 FLUD PROD1 Log tie-in down from 12120' 1.5/3500/15L Corr +5' FLUD PROD1 Wiper in hole 30'/min 1.5/3500 Set down at 12270' and had to drill it to get thru. Set down at 12335'. Ream in hole from 12335' at 5'/min w/4k WOB 1.5/4000 ECD 11.0 to 12395'. Wiper to 12300', clean. RIH 1.5/3600 to 12500' with lots of wt loss spots 12300-400'. Wiper back to 12390', clean. RIH clean to 12960' and set down twice. Ream 30'/min 1.5/3800 ECD 11.6 to TD tagged at 13134'. Get 300# diff initial w/-3k wt ECD 11.8 FLUD PROD1 Attempt to driIl1.5/3700/135L ECD 11.6 IA 177. Stack max wt to trip injector and get 1.5k to bit w/ 0-200# diff. No drill off and fairly clean PU's. Give up. Official TD 13135'. Max BHCT Printed: 1212912003 9:49: 13 AM Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: ..... . Page 11 of 14 BP EXPLORATION Operations Summary Report W-01 W-01 REENTER+COMPLETE NORDIC CALISTA NORDIC 1 From - To I Hours I Task : Code . ! Date ----" 12/22/2003 01:50 - 02:15 02:15 - 02:45 02:45 - 04:30 04:30 - 05: 15 05: 15 - 07:00 07:00 - 10:25 10:25-11:15 11:15 -13:15 13:15-18:15 18:15 -18:30 18:30 - 19:40 19:40 - 20:15 20:15 - 20:45 20:45-21:15 21 :15 - 00:00 12/23/2003 00:00 - 06:15 06: 15 - 08:20 08:20 - 08:40 08:40 - 10:15 10:15 - 12:00 12:00 -15:00 -.-- ..---.-....---.... 0.42 STKOH X 0.50 STKOH X 1.75 STKOH P 0.75 STKOH P 1.75 STKOH P 3.42 STKOH P 0.83 STKOH P 2.00 STKOH P 5.00 STKOH P 0.25 STKOH P 1.17 STKOH P 0.58 STKOH P 0.50 STKOH N 0.50 STKOH N 2.75 STKOH N 6.25 STKOH N 2.08 STKOH P 0.33 STKOH P 1.58 STKOH P 1.75 STKOH N 3.00 STKOH N NPT I Phase .--_. .~.__.. FLUD PROD1 FLUD PROD1 PROD1 PROD1 PROD1 PROD1 PROD1 PROD1 PROD1 PROD1 PROD1 PROD1 DFAL PROD1 DFAL PROD1 DFAL PROD1 DFAL PROD1 PROD1 PROD1 PROD1 DFAL PROD1 DFAL PROD1 Start: Rig Release: Rig Number: N1 Spud Date: 7/13/1982 End: 12/26/2003 10/17/2002 Description of Operations ______..n .~_._.... ..____n._ ...--.-... from BHI was 188 deg F Wiper to window. Minor overpulls at 12600', 12330' POOH for log LD drilling BHA Remove BHI encoder. Install PDS. MU PDS Induction tool assy RIH logging. Set down at 12300, 12317, 12330, 12348, 12355, 12383, 12388, 12394, 12405, Pick up clean Run back to same depth .6 BPM 12353 circulating pressure increased for 2000 to 2880 psi, (Thick mud) over pull 12400. 12342 seen pressure rise to 2800 psi over pull10K Pu to 12300. RIH set down at 12438, 12445, 12454, 12467, 12500, RIH with full returns 2450 psi at .4 bpm, 13063 set dn clean pick up, Tag 13151. Clean pick up. Log up a 40 ftlmin . Clean pick up. 13010 over pu1l10K, Continue to log up to 11,600. POH to 11200' paint flag .EOP. Continue POH. Down load data and process memory log. RDMO PDS TLlsafety mtg MU cleanout BHA Phz 1 RIH w/ BHA #17 (0.9 deg motor, DS100 bit) to 2500' and can't communicate w/ BHI tool 0.5/1380 POOH to check BHA 0.5/2730 CTP pressure is rising and is higher than normal on POH LD BHA and determine problem is in tool connections-lower quick connect has failed BHI has to go to Deadhorse shop to get/put together a tool Circ CT 0.5/2500 and shear mud to 0.5/1600 then cycle repeats. Incr rate 1.0/2800 Install thread protectors on excess liner and load out of pipeshed. Prep liner Still working to rebuild MWD tool. Found another short. Head back to Deadhorse. Found several shorts in different connections due to deteriorating rubber seals Circ mud in pits 1.0/2000-this rate avoids the pressure swings. Final circ rate/press 1.0/1840 RIH with cleanout assembly. .5 bpm at 2750 psi Pressure as high as 3400 psi due to Thick mud. tie - in correction -10'. RIH .7 bpm 3140 psi, .7bpm in .26bpm out @ 12292'. Pull back to shoe to clean up annulus and shear mud. Pump at 1.2 bpm 3760 psi. .3 bpm returns. Annulus mud thick. .6 bpm in .3 bpm out. 9.88 ECD at 11800' . RIH wo pump to top window. POH at 100 ftlmin while pumping @ 3900 psi 1.1 bpm (.5 bpm out rate) to reduce annular friction .1 bblloss rate. POH to 9900 1.1 bpm @ 3700 psi. RIH with out pump (ECD 9.86.at 11,000'.) to 12000' . POH 104 ftlmin 1.2 bpm in .45 out =.2.5 bpm loss rate. Circulating pressure 3550 psi. Look like circulating pressure is reducing. POH circulating 3930 psi @ 1.4 bpm in .6 bpm out. .2 bpm loss. Adding 20% water to suction pit to thin mud. EDC failure. POH. LD drilling BHA. Find short at EDC. BHI shop has been Printed: 12/29/2003 9:49: 13 AM .... . Page 12 of 14 BP EXPLORATION Operations Summary Report rebuilding the prior failure, but will be a couple hours before they are ready (trip to Deadhorse too) MU clean out BHA. RIH circulating at 2775 psi and 1.3 bpm, getting 1.7 bpm rtns. ECD: 10.2 Log GR tie in. Subtract 10' correction. Displace cased hole to 2%KCL from 12100'. 2700 psi @ 0.85 bpm. 0.75 bpm out. ECD: 9.15 Pressure slowly dropping with displacement. Mud returns look good, no thick material (so far) increased rate to 1.5 on final 1 00 bbls without losses. Switched to new Flo-Pro mud and displaced KCL.' PROD1 RIH through window no problem. Continue RIH 1.4 bpm 2380psi 10.1 ECD 1:1 returns setdown at 12385' work through to 12500' PUH and rework area. PROD1 Continue RIH cleaning out contaminated mud from openhole. Pumping 1.5bpm 1: 1 returns 10.36ECD BHT is 200 deg. Setdown at 12975'. Work back up, small overpulls and motorwork to 12930' then smooths out pull to 12890' RIH taking weight. This could be the major area of contamination. Continue washing with numerous setdowns to 13108'. Work area. Bottoms up mud diverted to cuttings tank. Continue down to TD with less problem. Still 1 : 1 returns and 10.8 ecd PUH to 12980' and working back down with more difficulty. Maintaining TF's as drilled and surging coil back to TD. From 12900' to 13080' is the worst section. Turn TF over to 180 and slowly ream back up to 12200'. Pulled tight at 12500' but worked through easily. RIH with 1.5 pump 2400psi 10.1 ecd went past all trouble spots without problems to TD. Return mud has small amount of "fish eyes" but other than that looks okay. TOH. Paint EOP flag at 10500'. LID BHA #18 Rig up to run 2 3/8" liner. Hold TL meeting and PJSM regarding liner MU and running. MU 2-3/8" slotted/solid liner. PU 1" CSH work string with stinger. MU liner running tools (GS spear, EDC assembly) MU to coil. Get on well. RIH with liner assembly (1398' OAL). Circulate at 0.4 bpm at 1150 psi. Tie into EOP flag at 10500'. Subtract 10' correction. 35K# up, 18.5K# down wt at 11900'. Continue into open hole. Circ at .35 bpm at 1050 psi. Set down at 12296' Work down to 12322'. Packing off, no rtns. Bleed coil prs. PU. Liner released from coil. Set back down several times. Re-Iatch and pooh to 12234'. Circ at 0.4/1550 psi. 1:1 rtns, RIH. Short In BHI tool. Will not be able to activate disconnect. Discuss with town, will rely on GS spear. Continue in hole. Slowly wash to 12303'. Stack out. Reduce circ rate to 0.38. Work to 12322'. Lose rtns. POOH to 12250'. Regain full circ. RIH hard. Work to 12350'. PU. Work to 12380'. PU and circulate at 1.4 in/out @3100 psi to clean up hole back to 12320'. RIH. Hole smooth to 12375'. DPRB COMP Continue trying to work past 12380'. Stack max weight, clean pick ups. Appear to be on a ledge. Able to circulate at 1.4 Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: W-01 W-01 REENTER+COMPLETE NORDIC CALISTA NORDIC 1 Date ; From - To : Hours Task Code NPT Phase ._..._.__......_. ___n__..___n_.. ........ __ .._. __ .__._..... 12/23/2003 12:00 - 15:00 3.00 STKOH N DFAL PROD1 15:00 - 16:00 1.00 STKOH P PROD1 16:00 - 19:00 3.00 STKOH P PROD1 19:00 - 19:30 0.50 STKOH P PROD1 19:30 - 23:40 4.17 STKOH P PROD1 23:40 - 00:00 0.33 STKOH P 12/24/2003 00:00 - 02:20 2.33 STKOH P 02:20 - 04:50 2.50 STKOH P PROD1 04:50 - 05: 15 0.42 STKOH P PROD1 05: 15 - 06:30 1.25 CASE P COMP 06:30 - 07:00 0.50 CASE P COMP 07:00 - 12:00 5.00 CASE P COMP 12:00 - 14:00 2.00 CASE P COMP 14:00 - 16:15 2.25 CASE N DPRB COMP 16:15 - 17:00 0.75 CASE N Start: 10/17/2002 Rig Release: Rig Number: N1 Spud Date: 7/13/1982 End: 12/26/2003 Description of Operations Printed: 12/29/2003 9:49: 13 AM . . Page 13 of 14 BP EXPLORATION Operations Summary Report Legal Well Name: W-01 Common Well Name: W-01 Event Name: REENTER+COMPLETE Contractor Name: NORDIC CALISTA Rig Name: NORDIC 1 Date I From - To I Hours Task Code NPT Phase 12/24/2003 16: 15 - 17:00 17:00 - 19:00 DPRB COMP DPRB COMP 0.75 CASE N 2.00 CASE N 19:00 - 19:45 0.75 CASE N DPRB COMP 19:45 - 22:30 22:30 - 22:45 22:45 - 00:00 2.75 CASE N 0.25 CASE N 1.25 CASE N DPRB COMP DPRB COMP DPRB COMP 12/25/2003 00:00 - 00:20 0.33 CASE N DPRB COMP 00:20 - 02:00 1.67 CASE N DPRB COMP 02:00 - 03:50 1.83 CASE N DPRB COMP 03:50 - 06:00 2.17 CASE N DPRB COMP 06:00 - 08:30 2.50 CASE N DPRB COMP 08:30 - 10:30 2.00 CASE N DPRB COMP 10:30 - 11 :00 0.50 CASE N DPRB COMP 11 :00 - 12:30 1.50 CASE N DPRB COMP 12:30 - 14:00 1.50 CASE N DPRB COMP Start: 10/17/2002 Rig Release: Rig Number: N1 Spud Date: 7/13/1982 End: 12/26/2003 Description of Operations in/out at 3000 psi with max set dn weight. No progress. TOH with liner. Hold PJSM discuss plan forward options in TL meeting. Break off and setback injector. Test voltage from connector back to MWD control - okay. Ud BHi tools and test EDC. Make up 1" safety joint. Same time I/d BOT liner running tools. EDC is shot. Will need to take into Deadhorse shop for further analysis. Discuss with town the options available. Will go with option of redressing liner guide shoe to centralized tapered type. Standback 1" CSH and 2 3/8" liner. PJSM review plan forward. P/U centralized tapered guide shoe. Make-up 22 stds of 2 3/8" slotted/soild liner. Recent update of BHi EDC: Found burst o-ring at the connector point. Reason for failure not understood but does not seem likely the mud would have caused the problem as in other recent tool failures. Repaired o-ring and was able to communicate with tool but unable to activate the disconnect or circ port. Further diagnoses not possible in the Deadhorse shop. Continue to make-up 22 stds (1376.83') 2 3/8" tubing from derrick. (redressed o-ring sub) Make-up 10' BTT slick stick on 21 stds, 1 jt and 2-3' pups of 1" CSH inner string tubing, this will provide +8' of extension into o-ring sub. Check condition of and make-up BTT 3" GS profile Deployment Sleeve, GS spear & running assemble. Stab injector. RIH with liner and tools (1384.11 '). No flag seen, no correction. Check weights above window 39k up, 18.8 down pump at min rate .2bpm 900 psi. Working liner to bottom okay though window, past aluminum billet. RIH speed 75'/min setdown at 12270'. work past rih setdown at 12366' p/u rih stdw again. p/u rih set at 12370' and pump. Increase rate to 1.3 2800psi and set 10 min slow to min rate and P/U try again. Setdown same place, increase rate to 1.75bpm 4130psi full returns, flatline on wt. P/U to 12307 rih at 115'/min setdown same place, pump at 1.4 2910psi p/u (all clean so far) to 12445' RIH 120'/min hitting same place. (worst coil life 15%) P/U and get wt back try jerkin' back to bottom. Hard spot down there. Not seeing any progress with gaining wt back while pumping on bottom. Will try just working pipe and watching coil life. Bumped life up to 22%. P/U and set at 12367' bring pump up to 1.65 working down very slowly back to bottom. Wash slowly down to 12370'. Stack -4K#. Continue circulating at 1.57 bpm in/out at 3350 psi. Pump 20 bbl hi vis/hi lub pill. POOH with liner. Hold PJSM and TL mtg in ops cab while tripping. Discuss plan forward. Remove electrical connector from coil connector. Secure e-line. Install crossover. Stand back 9 stands CSH. LD remainder in pipe shed. Stand back 9 stands solid liner and 1 stand slotted. LD remainder in pipe shed. Check o-ring sub and tappered guide Printed: 12/29/2003 9:49: 13 AM ..... . BP EXPLORATION Operations Summary Report Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: i Date From - To . W-01 W-01 REENTER+COMPLETE NORDIC CALISTA NORDIC 1 Hours Page 14 of 14 Start: Rig Release: Rig Number: N1 Spud Date: 7/13/1982 End: 12/26/2003 10/17/2002 12/25/2003 12:30 - 14:00 1.50 CASE N Task Code NPT: Phase ._ ________ __._u_. .._.. . . - ..... ....- 14:00 - 16:30 2.50 CASE N 16:30 - 18:40 2.17 CASE N 18:40 - 21:45 3.08 CASE P 21:45-22:15 0.50 CASE P 22:15 - 22:30 0.25 WHSUR P 22:30 - 23:30 1.00 WHSUR P 23:30 - 23:45 0.25 RIGD P 23:45 - 00:00 0.25 RIGD P 12/26/2003 00:00 - 01:45 1.75 RIGD P 01 :45 - 04:00 2.25 RIGD P Description of Operations .. ... ..h._n_._._.__._.____ DPRB COMP DPRB COMP DPRB COMP COMP COMP COMP COMP COMP COMP COMP COMP shoe. O-ring sub had a lot of shale on top, inside btm slotted joint. MU 1 solid float joint, 2 slotted, 17 solid on liner deployment sleeve (OAL: 618.26'). Space out 19 joints 1" CSH into o-ring sub. MU deployment sleeve and GS spear. MU to coil. Get on well. RIH. Check wts above window 34.4k up 15.9 dwn. RIH to 12380' and setdown. Release from liner and confirm with 30k pick-up. Swap to KCL and displace mud from liner/open hole and annulus at 2 bpm while TOH. UD liner running tools and 18 jts. 1" CSH P/U nozzle BHA RIH to 2000' frezze protect well back to surface with 18 bbl 60/40 methanol. PJSM review plan forward for rig down. Prep to unstab coil from injector. Unstab coil from injector and secure reel. Nipple down BOP's and install tree cap and test to 4500psi. Rig Released at 0400 hrs 2-26-2003 Printed: 12/29/2003 9:49: 13 AM TREE = 3-118" WCEVOY WELLHEAD = WCEVOY ACTUA. TOR = 011S KB. 8..EV = 83.26; BF. 8..EV = 53.81' KOP = 1000' Max Angle = 96 @ 12573' Datum M) = 12249' DatumTVD= 88OO'SS . 1 13-318" CSG, 72#, L-80, ID= 12.347" H 2933' r---J IMinimum ID = 1.920" @ 11763" I TOP OF 2-3/8" LINER I 3-1/2" TBG, 9.2#, L-BO, .0087 bpf, ID = 2.992" H 11672' 1 TOPOF3-1/2"TBGTAILAPE H 11672' 13-1/2" TBG, 9.3#, L-BO, .0087 bpf, ID = 2.992" H 11789' 1 1 TOP OF 5-1/2" LNR(OGI20m) I 111010' SLM \\'7g\ 1 9-5/8"CSG,47#, L-80,ID=8.681" H 1 TOPOFWHIPSTOCK H I RATAGH 12027' 12126' 12153' PERFORATION SUMIi1ARY REF LOG: ANGLEATTOPPERF: f\bte: Refer to A"oduction DB for historical perf data SIZE SPF INfER\! AL Opn/Sqz )A, TE SLOTTB> LINER 12284 - 12347 0 12/25103 l5-1/2" LNR, 17#, L-80, .0232 bpf, ID = 4.892" H 12670' DATE 10/13/88 12/26/03 01/26/04 REV BY COMli1ENfS HENRY ORIGINAL COM PLETION JDM/KK CTD SIŒTRACK (W-01A) KSBlTLH GLV CIO )A, lE W-01A ¡.;!OTES' . - 2093' H3-1/2" OTIS SSSV LANDING NIP, ID = 2.75" 1 GAS LIFT MANDR8..S ST MD TVD DEV 1YÆ VLV ! LATCH FORT DAlE ~ 5 3422 2930 47 OTIS DOM: I RM 16 01/26/04 4 7969 5732 51 OTIS DOM: RM 16 01/26/04 3 9990 7135 44 OTIS DOM: RM 16 01/26/04 2 11092 7928 43 OTIS DMY RM 0 11/03103 1 11562 8275 42 OTIS SO RM 20 01/26/04 L ...LL I 11622' H3-1/2"OTISSLlDINGSLV,ID=2.75" 1 í i I 11672' H3-1/2" OTIS SBR SEAL ASSY 1 :8: ~ 11688' H9-5I8" X 3-1/2" 011S A<R, ID = 3.85" 1~1 I 11731' H3-1/2" OTIS X NIP, ID = 2.75" I 1 11762' 1-12.6" BKR ŒPLOYMENT SLV, ID = 2.25" I 1 11764' H3-1/2" OTIS X NIP, ID = 2.75" (BB-iIND cr LNR) 1 11798' H3-1/2" WLB3,ID = 2.992" (BB-iIND cr LNR) 1 .. I 1 11806' HELM) TT LOGGED 08111/92 - ~ MILLOur WINDOW 12143' -12154' 1234 7' H BOT O-RING SLB , .... 12-3/8" LNR, 4.6#, L-80, .0036 bpf, ID = 1.920" H 12380' 1 REV BY FRLDHOE SA Y UNIT WELL: W-01A PERMIT No: 2031760 AA No: 50-029-21866-01 SEC 21, T11N, R12E, 1157' SI'L & 1189' WEL COMMENTS BP Exploration (Alas ka) ~ ObP BP-GDB Baker Hughes INTEQ Survey Report . . V03·- J7 LC) Bií. BA.KD IIUGtIU INTEQ \ Company: BP Amoèo Field: Prudhoe Bay Site: PB W Pad Well: W:01'..f.>'·' Wellpath:¡~~.. ".Oi¡¡é>, . . .. f~~~ Field: Prudhoe Bay North Slope UNITED STATES Map System:US State Plane Coordinate System 1927 Geo Datum: NAD27 (Clarke 1866) Sys Datum: Mean Sea Level Date: 1/16/2004 Time: 13:09:49 Page: Co-()rdlnate(NE) Reference: Well: W-01, True North Vertical (fVD) Reference: 1 : 01 9/12/1988 00:00 83.0 Section (VS) Reference: Well (0.00N,O.00E,102.00Azi) Survey Calculation Method: Minimum Curvature Db: 1 Oracle Map Zone: Coordinate System: Geomagnetic Model: Alaska, Zone 4 Well Centre bggm2003 Site: PB W Pad TR-11-12 UNITED STATES: North Slope Site Position: Northing: From: Map Easting: Position Uncertainty: 0.00 ft Ground Level: 47.83 ft 5957194.18 ft 609919.18 ft Latitude: 70 17 Longitude: 149 6 North Reference: Grid Convergence: 31.506 N 36.343 W True 0.84 deg Well: W-01 Slot Name: 01 W-01 Well Position: +N/-S 1874.68 ft Northing: 5959100.04 ft Latitude: 70 17 49.941 N +E/-W 2157.64 ft Easting : 612048.99 ft Longitude: 149 5 33.450 W Position Uncertainty: 0.00 ft Wellpath: W-01A 500292186601 Current Datum: 1 : 019/12/198800:00 Magnetic Data: 11/26/2003 Field Strength: 57557 nT Vertical Section: Depth From (fVD) ft 30.09 +N/-S ft 0.00 Drilled From: Tie-on Depth: Above System Datum: Declination: Mag Dip Angle: +E/-W ft 0.00 W-01APB1 12200.00 ft Mean Sea Level 25.24 deg 80.80 deg Direction deg 102.00 Height 83.00 ft Survey Program for Definitive Wellpath Date: 1/16/2004 Validated: Yes Version: 4 Actual From To Survey Toolcode ft ft 36.14 12114.23 1 : Schlumberger GCT multishot (36.14-126~ 12139.00 12170.83 MWD (12139.00-14109.00) (2) MWD 12200.00 13135.00 MWD (12200.00-13135.00) MWD Tool Name Schlumberger GCT multishot MWD - Standard MWD - Standard Annotation MD ft 12170.83 12200.00 13135.00 TVD ft 8818.96 8841.27 8936.15 TIP KOP TO Survey: MWD Start Date: 12/21/2003 Company: Baker Hughes INTEQ Tool: MWD,MWD - Standard Engineer: Tied-to: From: Definitive Path RECEIVED FED 1 ~,. 2004 AJ&,keOil & Gas Cons. CommisaIan Aoohtxage ,,~';b \\\~ ObP . BP-GDB . Biï. BAKU IIUGIfU Baker Hughes INTEQ Survey Report INTEQ Company: BP Amoco Date: 1/16/2004 Time: 13:09:49 Page: 2 Field: Prudhoe Bay Co-ordinate(NE) Reference: Well: W-01, True North Site: PB W Pad Vertical (fVD) Reference: 1 :01 9/12/198800:0083.0 Well: W-01 Section (VS) Reference: Well (0.00N,O.00E,102.00Azi) Wellpath: W-01A Survey Calculation Method: Minimum Curvature Db: Oracle Survey MD Incl Azim TVD SSTVD N/S E/W MapN MapE VS DLS ft deg deg ft ft ft ft ft ft ft deg/10OO 12170.83 36.70 146.65 8818.96 8735.96 -3212.02 6937.80 5955992.09 619033.31 7454.01 0.00 12200.00 43.46 146.84 8841.27 8758.27 -3227.71 6948.10 5955976.54 619043.84 7467.34 23.18 12229.90 50.54 129.42 8861.73 8778.73 -3243.74 6962.72 5955960.74 619058.69 7484.97 48.59 12259.72 52.81 112.44 8880.31 8797.31 -3255.64 6982.68 5955949.14 619078.83 7506.98 45.24 12290.55 59.20 100.84 8897.57 8814.57 -3262.84 7007.12 5955942.31 619103.37 7532.38 37.41 12321.27 65.76 91.01 8911.79 8828.79 -3265.58 7034.16 5955939.97 619130.45 7559.40 35.49 12351.65 69.05 84.34 8923.47 8840.47 -3264.42 7062.16 5955941.55 619158.42 7586.55 22.98 12382.84 73.28 84.28 8933.54 8850.54 -3261.49 7091.53 5955944.91 619187.74 7614.66 13.56 12422.43 81.23 81.67 8942.27 8859.27 -3256.76 7129.82 5955950.21 619225.95 7651.13 21.08 12453.98 89.88 80.05 8944.71 8861.71 -3251.77 7160.84 5955955.67 619256.90 7680.44 27.89 12484.09 93.38 73.62 8943.85 8860.85 -3244.92 7190.13 5955962.95 619286.08 7707.66 24.30 12513.21 95.97 72.28 8941.48 8858.48 -3236.41 7217.87 5955971.87 619313.69 7733.03 10.01 12543.02 93.84 68.11 8938.93 8855.93 -3226.35 7245.81 5955982.35 619341.47 7758.26 15.66 12572.50 96.43 65.24 8936.29 8853.29 -3214.73 7272.77 5955994.37 619368.25 7782.22 13.08 12602.09 95.62 65.28 8933.18 8850.18 -3202.41 7299.49 5956007.08 619394.79 7805.80 2.74 12631.38 94.09 69.29 8930.70 8847.70 -3191.14 7326.41 5956018.75 619421.53 7829.78 14.61 12664.41 91.78 73.37 8929.01 8846.01 -3180.59 7357.65 5956029.77 619452.61 7858.15 14.18 12690.91 91.14 76.04 8928.34 8845.34 -3173.60 7383.20 5956037.13 619478.05 7881.69 10.36 12721.41 89.97 78.03 8928.04 8845.04 -3166.76 7412.92 5956044.42 619507.66 7909.33 7.57 12749.77 88.71 82.72 8928.37 8845.37 -3162.02 7440.87 5956049.57 619535.53 7935.69 17.12 12783.58 90.37 85.69 8928.64 8845.64 -3158.61 7474.50 5956053.49 619569.11 7967.88 10.06 12813.81 89.30 89.73 8928.73 8845.73 -3157.40 7504.70 5956055.14 619599.28 7997.16 13.82 12843.85 90.40 94.85 8928.81 8845.81 -3158.60 7534.70 5956054.39 619629.30 8026.76 17 .43 12872.55 90.40 99.36 8928.61 8845.61 -3162.15 7563.18 5956051.27 619657.82 8055.35 15.71 12905.70 92.21 104.91 8927.85 8844.85 -3169.11 7595.56 5956044.79 619690.30 8088.48 17.61 12935.47 89.54 105.41 8927.40 8844.40 -3176.89 7624.29 5956037.44 619719.14 8118.20 9.12 12965.00 89.14 109.70 8927.74 8844.74 -3185.80 7652.44 5956028.95 619747.41 8147.58 14.59 12992.38 87.76 111.69 8928.48 8845.48 -3195.47 7678.04 5956019.66 619773.16 8174.63 8.84 13023.84 87.76 115.35 8929.71 8846.71 -3208.01 7706.86 5956007.55 619802.16 8205.43 11.62 13056.62 87.04 120.81 8931.20 8848.20 -3223.42 7735.74 5955992.58 619831.26 8236.88 16.78 13086.78 85.41 124.32 8933.18 8850.18 -3239.61 7761.10 5955976.77 619856.86 8265.05 12.81 13111.80 86.85 129.24 8934.87 8851.87 -3254.56 7781.08 5955962.13 619877.06 8287.71 20.45 13135.00 86.85 129.24 8936.15 8853.15 -3269.21 7799.03 5955947.74 619895.22 8308.31 0.00 BP Amoco Parent Wellpath: Tie on MD: WELLPATH DETAILS W·01A 500292186801 W·01APB1 12200.00 Rig: Ref. Datum: Nordic 2 1 : 01 9/12/198800:00 83.000 V.Section Origin Origin Angle +N/~S +E/~W 102.00° 0.00 0.00 Starting From TVO 30.09 REFERENCE INFORMATION Co-ordinate iN/E¡ Reference: Well Centre: W-01. True North Vertical (tVD Reference: System: Mean Sea Level Section (VS Reference: Slot - 01 (O.OON,O.OOE) Measured Depth Reference: 1 : 01 9/12/198800:00 83.00 Calculation Method: Minimum Curvature 8100 ë8200 ;¡;¡ ë8300 o ~400 .I: '¡8500 III 1:18600 "i (,)8700 :e ::8800 ë8900 ....9000 ANNOTATIONS ~E!·W Shaµ~ TVO MO Annotation 8735.96 12170.83 TIP 875827 12200.00 KOP 8853.15 13135.00 TO 7800 7900 8000 9100 9200 9300 LEGEND T '1 Wellpa!h: (W-011W-01A) Azimuths to True North Magnetic North: 25.24° Cre.ated By: Brij Potni$ Date: 1/16/2004 Stre Dip gle: 80.80° Date: 11/26/2003 Model: bggm2003 :¡::--3200 -- .I: 1:: -3300 CI i-3400 ;È-3500 .... g -3600 U') -3700 6900 7000 7100 7200 7300 7400 7500 7600 7700 7800 7900 8000 8100 8200 8300 8400 8500 8600 8700 8800 8900 9000 9100 9200 9300 9400 9500 West(-)/East(+) [100ft/in] 6700 6800 6900 7000 7100 7200 7300 7400 7500 7600 7700 7800 7900 8000 8100 8200 8300 8400 8500 8600 8700 8800 8900 9000 9100 9200 9300 9400 9500 9600 9700 9800 9900100001010010200103001040010500 Vertical Section at 102.00· [100ft/in] ---UW/2004 1 :05 PM ( ObP BP-GDB Baker Hughes INTEQ Survey Report . . 303- ) '7-0- Bií. IIAKBt NUGIIIS ----- INTEQ -1". Company: Field: Site: Well: L.~e~lpath: BP Amoco Prudhoe Bay PBW Pad V\l~Q.t';'N'P' ., .W.tffAHf ,- Date: 1/16/2004 Time: -13:15:08 Page: 1 Co-ordinate(NE) Reference: Well: W-01. True North Vertical (TVD) Reference: 1 : 01 9/12/198800:0083.0 Section (VS) Reference: Well (0.00N,O.00E,111.84Azi) Survey Calculation Method: Minimum Curvature Db: Oracle ._____n_ -.--... Field: Prudhoe Bay North Slope UNITED STATES Map System:US State Plane Coordinate System 1927 Geo Datum: NAD27 (Clarke 1866) Sys Datum: Mean Sea Level Map Zone: Coordinate System: Geomagnetic Model: Alaska, Zone 4 Well Centre bggm2003 Site: PB W Pad TR-11-12 UNITED STATES: North Slope Site Position: Northing: From: Map Easting: Position Uncertainty: 0.00 ft Ground Level: 47.83 ft 5957194.18 ft 609919.18 ft Latitude: 70 17 Longitude: 149 6 North Reference: Grid Convergence: 31.506 N 36.343 W True 0.84 deg Well: W-01 Slot Name: 01 W-01 Well Position: +N/-S 1874.68 ft Northing: 5959100.04 ft Latitude: 70 17 49.941 N +E/-W 2157.64 ft Easting : 612048.99 ft Longitude: 149 5 33.450 W Position Uncertainty: 0.00 ft Wellpath: W-01APB1 500292186670 Current Datum: 1: 019/12/198800:00 Magnetic Data: 12/17/2003 Field Strength: 57559 nT Vertical Section: Depth From (TVD) ft 30.09 +N/-S ft 0.00 Drilled From: Tie-on Depth: Above System Datum: Declination: Mag Dip Angle: +E/-W ft 0.00 W-01 12139.00 ft Mean Sea Level 25.22 deg 80.80 deg Direction deg 111.84 Height 83.00 ft Survey Program for Definitive Wellpath Date: 12/17/2003 Validated: Yes Actual From To Survey ft ft 36.14 12114.23 12139.00 14109.00 Version: Toolcode Tool Name 1 : Schlumberger GCT multishot(36.14-126~ MWD (12139.00-14109.00) MWD Schlumberger GCT multishot MWD - Standard Annotation 12114.23 8773.76 TIP 12139.00 8793.47 KOP 14109.00 8968.11 TO Survey: MWD Company: BakerHugheslNTEQ Tool: MWD,MWD - Standard Survey MD loci Azlm TVD SSTVD ft deg deg ft ft 12114.23 37.65 145.81 8773.76 8690.76 12139.00 36.87 146.48 8793.47 8710.47 12170.83 36.70 146.65 8818.96 8735.96 12202.02 43.93 146.85 8842.73 8759.73 12232.13 49.70 131.41 8863.39 8780.39 12261.95 54.33 122.51 8881.76 8798.76 12292.40 63.82 124.60 8897.40 8814.40 12322.35 71.76 116.88 8908.72 8825.72 12353.40 77.73 108.40 8916.90 8833.90 12382.93 82.49 103.52 8921.98 8838.98 12414.85 86.99 94.64 8924.91 8841.91 HECEIVED Start Date: F:.Ij 1: 2004 12/15/2003 Aja~k9 Oil & Gas Cons. Comm111on Arim. Engineer: Tied-to: From: Definitive Path NIS EìW MapN MapE VS DLS ft ft ft ft ft degl100ft; -3183.66 6918.95 5956020.16 619014.04 7606.72 0.00 -3196.11 6927.30 5956007.83 619022.58 7619.11 3.55 -3212.02 6937.80 5955992.09 619033.31 7634.78 0.62 -3228.88 6948.86 5955975.39 619044.62 7651.31 23.18 -3245.29 6963.24 5955959.20 619059.24 7670.76 41.92 -3259.34 6982.02 5955945.43 619078.22 7693.42 28.16 -3273.79 7003.75 5955931.31 619100.16 7718.96 31.71 -3287.89 7027.56 5955917.57 619124.18 7746.32 35.65 -3299.37 7055.18 5955906.50 619151.97 7776.23 32.60 -3307.36 7083.14 5955898.93 619180.04 7805.14 22.91 -3312.36 7114.48 5955894.40 619211.45 7836.10 31.08 ~~~ f"\ð-.., .... . . miï. ObP BP-GDB IIAKUt IIUGIIIS Baker Hughes INTEQ Survey Report lNTEQ Company: BP Amoco Date: 1/16/2004 Time: 13:15:08 Page: 2 Field: Prudhoe Bay Co-ordinate(NE) Reference: Well; W-01, True North Site: PB W Pad Vertical (TVD) Reference: 1 : 01 9/12/198800:0083.0 Well: W-01 Section (VS) Reference: Well (0.00N,O.00E,111.84Azi) Wellpath: W-01APB1 Survey Calculation Method: Minimum Curvature Db: Oracle Survey MD IncI Azim TVD SSTVD N/S EIW MapN MapE VS DLS ft deg deg ft ft ft ft ft ft ft deg/10OO 12446.69 86.96 90.62 8926.59 8843.59 -3313.82 7146.24 5955893.41 619243.23 7866.12 12.61 12480.42 89.85 86.63 8927.53 8844.53 -3313.01 7179.94 5955894.72 619276.90 7897.10 14.60 12514.81 89.75 80.98 8927.65 8844.65 -3309.30 7214.11 5955898.94 619311.02 7927.44 16.43 12548.96 90.15 76.22 8927.68 8844.68 -3302.55 7247.58 5955906.19 619344.38 7956.00 13.99 12585.45 87.88 72.59 8928.30 8845.30 -3292.74 7282.71 5955916.52 619379.36 7984.96 11.73 12615.56 86.04 68.83 8929.90 8846.90 -3282.81 7311.09 5955926.87 619407.58 8007.60 13.89 12645.76 85.91 62.98 8932.02 8849.02 -3270.52 7338.57 5955939.57 619434.88 8028.55 19.33 12675.08 87.85 60.84 8933.62 8850.62 -3256.74 7364.40 5955953.73 619460.49 8047.39 9.84 12707.26 89.08 66.67 8934.48 8851 .48 -3242.52 7393.24 5955968.38 619489.11 8068.87 18.51 12736.52 87.33 72.47 8935.40 8852.40 -3232.31 7420.63 5955978.99 619516.35 8090.50 20.69 12764.89 88.40 75.11 8936.46 8853.46 -3224.40 7447.85 5955987.31 619543.45 8112.82 10.03 12794.09 89.23 81.94 8937.06 8854.06 -3218.60 7476.45 5955993.54 619571.95 8137.20 23.56 12825.57 89.36 87.47 8937.45 8854.45 -3215.69 7507.78 5955996.91 619603.23 8165.21 17.57 12855.63 86.74 94.31 8938.47 8855.47 -3216.16 7537.79 5955996.89 619633.25 8193.24 24.35 12884.11 88.34 98.67 8939.70 8856.70 -3219.37 7566.06 5955994.10 619661.55 8220.67 16.29 12914.83 89.05 105.66 8940.40 8857.40 -3225.84 7596.06 5955988.08 619691.65 8250.93 22.86 12945.66 89.60 111.75 8940.76 8857.76 -3235.72 7625.25 5955978.63 619720.97 8281.70 19.83 12980.93 87.63 117.88 8941.61 8858.61 -3250.51 7657.24 5955964.32 619753.18 8316.89 18.25 13010.68 86.59 121.67 8943.11 8860.11 -3265.27 7683.02 5955949.96 619779.18 8346.31 13.19 13044.42 87.24 121.33 8944.93 8861.93 -3282.87 7711.75 5955932.79 619808.16 8379.53 2.17 13073.02 88.43 116.83 8946.01 8863.01 -3296.76 7736.72 5955919.27 619833.33 8407.87 16.26 13104.53 88.50 111.80 8946.85 8863.85 -3309.72 7765.41 5955906.74 619862.21 8439.33 15.96 13134.50 87.91 104.72 8947.79 8864.79 -3319.10 7793.84 5955897.78 619890.78 8469.21 23.69 13164.10 90.49 102.65 8948.21 8865.21 -3326.10 7822.59 5955891.21 619919.63 8498.50 11.17 13204.00 91.42 96.11 8947.54 8864.54 -3332.60 7861.93 5955885.30 619959.06 8537.43 16.55 13245.46 89.32 92.68 8947.27 8864.27 -3335.78 7903.26 5955882.74 620000.42 8576.98 9.70 13277.86 89.29 90.60 8947.67 8864.67 -3336.70 7935.64 5955882.30 620032.81 8607.38 6.42 13318.49 90.52 85.37 8947.73 8864.73 -3335.28 7976.23 5955884.33 620073.38 8644.53 13.22 13356.77 88.43 80.19 8948.09 8865.09 -3330.47 8014.19 5955889.70 620111.26 8677.97 14.59 13385.51 88.80 76.80 8948.78 8865.78 -3324.74 8042.34 5955895.85 620139.32 8701.97 11.86 13414.73 89.11 77.15 8949.31 8866.31 -3318.15 8070.81 5955902.86 620167.68 8725.94 1.60 13433.61 90.49 80.98 8949.38 8866.38 -3314.57 8089.34 5955906.72 620186.15 8741.81 21.56 13464.67 90.77 86.46 8949.04 8866.04 -3311.18 8120.20 5955910.57 620216.95 8769.19 17.67 13496.03 88.81 91.49 8949.15 8866.15 -3310.62 8151.54 5955911.60 620248.28 8798.08 17.21 13522.66 85.59 93.21 8950.45 8867.45 -3311.71 8178.11 5955910.91 620274.87 8823.15 13.70 13555.18 87.39 98.33 8952.45 8869.45 -3314.97 8210.40 5955908.13 620307.19 8854.33 16.66 13589.59 87.21 103.29 8954.07 8871.07 -3321.41 8244.15 5955902.19 620341.03 8888.05 14.41 13622.69 85.27 106.96 8956.24 8873.24 -3330.03 8276.03 5955894.05 620373.03 8920.85 12.52 13654.17 86.00 113.94 8958.64 8875.64 -3340.99 8305.42 5955883.53 620402.58 8952.21 22.23 13688.61 87.95 121.48 8960.46 8877.46 -3356.97 8335.84 5955868.00 620433.24 8986.39 22.58 13720.96 88.25 126.85 8961.53 8878.53 -3375.12 8362.58 5955850.25 620460.24 9017.97 16.62 13750.97 87.02 129.99 8962.77 8879.77 -3393.75 8386.07 5955831.98 620484.01 9046.70 11.23 13780.67 86.56 125.22 8964.43 8881 .43 -3411.84 8409.56 5955814.24 620507.76 9075.23 16.11 13810.55 86.16 122.04 8966.33 8883.33 -3428.35 8434.38 5955798.10 620532.82 9104.42 10.71 13840.61 88.25 118.73 8967.80 8884.80 -3443.54 8460.28 5955783.31 620558.94 9134.10 13.01 13870.97 88.22 113.10 8968.73 8885.73 -3456.79 8487.56 5955770.46 620586.41 9164.36 18.54 13901.56 88.10 110.35 8969.72 8886.72 -3468.11 8515.96 5955759.57 620614.98 9194.93 8.99 13931.62 89.69 105.70 8970.30 8887.30 -3477.41 8544.53 5955750.70 620643.68 9224.91 16.35 13961.23 90.09 102.01 8970.35 8887.35 -3484.50 8573.28 5955744.04 620672.52 9254.23 12.53 13994.69 90.12 97.58 8970.29 8887.29 -3490.19 8606.24 5955738.84 620705.57 9286.94 13.24 14027.81 90.14 94.60 8970.22 8887.22 -3493.70 8639.17 5955735.82 620738.54 9318.82 9.00 14057.12 90.99 90.92 8969.93 8886.93 -3495.11 8668.44 5955734.85 620767.83 9346.51 12.89 14082.46 92.33 89.49 8969.19 8886.19 -3495.20 8693.77 5955735.13 620793.15 9370.05 7.73 ,. I ObP Company: Field: Site: Well: Wellpath: BP Amoco Prudhoe Bay PB W Pad W-01 W-01APB1 Survey MD ft 14109.00 Incl deg 92.33 Azim deg 89.49 . BP-GDB . Baker Hughes INTEQ Survey Report TVD ft 8968.11 SSTVD ft 8885.11 -¡¡. BAKU. IIUGHIS ._,------- INTEQ Da~: 1/16/2004 Time: .. 13:15:08 Page: 3 Co-ordinate(NE) Reference: Well: W-01, True North Vertical (TVD) Referenc¢: 1 : 01 9/12/1988 00:00 83.0 Section (VS) Reference: Well (0.00N,O.00E,111.84Azi) Survey Calculation Method: Minimum Curvature Db: Oracle N/S ft -3494.97 EIW ft 8720.28 MapE ft 620819.66 MapN ft 5955735.77 VS ft 9394.58 DLS deg/100ft 0.00 Ids ~ ,. . WELL LOG TRANSMITTAL fJ03-1'f0 . ProActive Diagnostic SelVices, Inc. To: State of Alaska AOGCC 333 W. 7'" Street Suite # 700 Anchorage, Alaska 99501 RE: Distribution - Final Print{s] The technical data listed below is being submitted herewith. Please acknowledge receipt by returning a signed copy of this transmittal letter to the attention of : Joey Burton / Jeni Thompson ProActive Diagnostic Services. Inc. P. O. Box 1369 Stafford. TX 77497 BP Exploration (Alaska). Inc. Petrotechnical Data Center LR2-1 900 E. Benson Blvd. Anchorage. AK 99508 WELL DATE LOG TyPE DIGITAL OR CD-ROM 1 J t/~ (Or¡; MYLAR / SEPIA FILM 1 BLUE LINE PRINT(S) REPORT OR COLOR WoO 1 A 12-22-03 Open Hole 1 Res. Eva!. CH 1 1 1 Mech. CH 1 Caliper Survey Signed : -='~k~~\~,&Q.~~JY"'\ Date: RECt:IVEIJ Print Name: J,f\¡W 2 0 2ô04 Alaska Oil & Gas Cons. Commision Þtachorage PRoACTivE DiAGNOSTic SERvicES, INC., PO Box J }69 STAffoRd TX 77477 Phone:(281) 565-9085 Fax:(281) 565-1369 E-mail: pds@memorylog.com Website: www.memorylog.com ~~'D\\t0 ~~~~L~E (IDr~~~~~~~ . ft. I,ASIiA. OIL AlWD GAS CONSERVATION COMMISSION FRANK H. MURKOWSK/, GOVERNOR 333 W. 7'" AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Mary Endacott CT Drilling Engineer BP Exploration (Alaska), Inc. PO Box 196612 Anchorage, AK 99519 Re: Prudhoe Bay Unit W-01A BP Exploration (Alaska), Inc. Pennit No: 203-176 Surface Location: 1157' SNL, 1189' WEL, Sec. 21, T11N, R12E, UM Bottomhole Location: 4798' SNL, 2626' EWL, SEC. 23, TllN, R12E, UM Dear Mr. Endacott: Enclosed is the approved application for pennit to redrill the above development well. This pennit to redrill does not exempt you from obtaining additional pennits or approvals required by law from other governmental agencies, and does not authorize conducting drilling operations until all other required penn its and approvals have been issued. In addition, the Commission reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the Commission specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or a Commission order, or the tenns and conditions of this pennit may result in the revocation or suspension of the pennit. Please provide at least twenty-four (24) hours notice for a representative of the Commission to witness any required test. Contact the Commission's North Slope petroleum field inspector at 659-3607 (pager). Sincerely, R...-.~ pÁ-~ Randy iuedrich Commissioner BY ORDER OF THE COMMISSION DATED tbisA day of October, 2003 cc: Department ofFish & Game, Habitat Section w/o encl. Department of Environmental Conservation w/o encl. Exploration, Production and Refineries Section _ STATE OF ALASKA a ALASKA OWAND GAS CONSERVATION COM_SION PERMIT TO DRILL 20 MC 25.005 1b. Current Well Class 0 Exploratory o Stratigraphic Test 0 Service 5. Bond: 0 Blanket 0 Single Well Bond No. 2S100302630-277 6. Proposed Depth: MD 14500 TVD 8845ss 7. Property Designation: ADL 047451 19. PRESENT WELL CONDITION SUMMARY (To be completed for Redrill AND Re-entry Operations) Total Depth MD (ft): Total Depth TVD (ft): Plugs (measured): Effective Depth MD (ft): Depth TVD (ft):1 12670 9241 NIA 12431 9036 Casing MD Structural Conductor Surface Intermediate Production Liner 21. Verbal Approval: Commission Representative: 22. I hereby certify that the foregoing is true and correct to the best of my knowledge. ;:::~,jð~ïAttl(nrccf ::e CT Dn::::"_ /" . j Commission Use Only Permit To Drill ' I API Number: I Permit A£gF0val .1 See cov.. er letter fO. r Number: ¿oJ. - /7 h 50-029-21866-01-00 Date: ¡if 1'"/0 :J r~Jtle(T8cpttïr,~~ Conditions of Approval: Samples Required 0 Yes J8!'No Mud Log Required TI~f-¡:gMcf.", Other: ·r~c:.t '~oPE ~dr~~~;u;~7 .Measures ßi Yes No Directional Survey Required G~tl ¡P~~i. 1a. Type of work o Drill ORe-Entry iii Redrill 2. Operator Name: BP Exploration (Alaska) Inc. 3. Address: P.O. Box 196612, Anchorage, Alaska 99519-6612 4a. Location of Well (Governmental Section): Surface: 1157' SNL, 1189' WEL, SEC. 21, T11 N, R12E, UM Top of Productive Horizon: 4422' SNL, 494' EWL, SEC. 23, T11 N, R12E, UM Total Depth: 4798' SNL, 2626' EWL, SEC. 23, T11N, R12E, UM 4b. Location of Well (State Base Plane Coordinates): Surface: x-612049 y-5959100 Zone¡t\SP4 16. Deviated Wells: Kickoff Depth 18. Casing Program Size Casinç¡ 2-3/8" Hole 12145 ft Maximum Hole Angle Specifications Grade Couplinç¡ L-80 STL 3" Weight 4.6# 110' 2934' 12027' 20" 13-3/8" 9-518" 889' 5-1/2" Perforation Depth MD (ft): 12280' - 12430' 20. Attachments IS! Filing Fee IS! BOP Sketch o Property Plat 0 Diverter Sketch Appm'ed Bv: ~ t-o~ ~ Form 10-401 Revised 3/2003 / WGA- lot IS" ¡z.oo '5 iii Development Oil 0 Multiple Zone o Development Gas 0 Single Zone 11. Well Name and Number: PBU W-01A 12. Field 1 Pool(s): Prudhoe Bay Field 1 Prudhoe Bay Pool 8. Land Use Permit: 13. Approximate Spud Date: 11/15/03 ~. 14. Distance to Nearest Property: 14,400' 9. Acres in Property: 2560 10. KB Elevation 15. Distance to Nearest Well Within Pool (Height above GL): KBE = 83' feet W-08 is 973' away at 12340' MD 17. Anticipated pressure (see 20 MC 25.035) ../ 960 Max. Downhole Pressure: 3400 psig. Max. Surface Pressure: 2344 psig Setting Depth Quantity of Cement Top Bottom (d. or sacks) Lenç¡th MD TVD MD TVD (includinç¡ staç¡e data) 2760' 11740' 8406' 14500' 8845' Uncemented Slotted Liner /" Junk (measured): N/A 8 cu yds Concrete 4323 cu ft PF, 140 cu ft PF Top Job 2533 cu ft Class 'G' 110' 2934' 12027' 110' 2684' 8706' 371 cu ft Class 'G' 11781'-12670' 8520' - 9241' IPerfOration Depth TVD (ft): 8909' - 9035' IS! Drilling Program 0 Time vs Depth Plot 0 Shallow Hazard Analysis o Seabed Report IS! Drilling Fluid Program IS! 20 MC 25.050 Requirements Date: Contact Mary Endacott, 564-4388 ) /, ç; It Prepared By Name/Number: Date 10/Y1 O~) Terrie Hubble. 564-4628 (; BY ORDER OF å~1sbT~ A [E COMMISSION !\" "I., . .,. ?'i,lt,'t",if {¡,üe, Date ~~t'~¿te e BP W-01A CTD Sidetrack e Phase 1 Operations: Non rig Prep Work: / · Integrity pressure test OA, IA &tbg, wellhead seals & Xmas tree valves. · Mill obstruction in 3 W' tubing · Lay in cement from perfs to tubing tail Phase 2 Operations: Drill cement ramp, Mill window, Drill and Complete sidetrack. Mud Program: · Phase 1: Seawater/1 % KCI L;.. · Phase 2: Mill with seawater I Y2lb biozan, drill with Solids Free Flo-Pro (8.6 -~pg) Disposal: · All drilling and completion fluids and all other Class" wastes will go to Grind & Inject. · All Class I wastes will go to Pad 3 for disposal. Casing Program: 2 3/8" production liner from -14,500, (-8844'ss) to 11 ,740'MD (-8406) Approximately 1400ft will be slotted. /' Parent Well Casings 133/8" 72# L-80 9%" 47#, L-80, BTC 5 W' 17# L-80 liner Sidetrack Casing 23/8" 4.6#, L-80, STL slotted - Prod LNR Burst (psi) 5380 6870 7740 Collapse (psi) 2670 4750 6280 NA NA Hole size 3" 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 2500 psi. Directional · See attached directional plan. Max. planned hole angle is 95°. · Magnetic and inclination surveys will be taken every 30 ft. No gyro will be run. · W-01A will be approximately 973' ctr-ctr away from well W-08 at 12,340'md · W-01A will be approximately 14,400' from the unit boundary, (Prudhoe Bay Unit) Logging · MWD Gamma Ray and Resistivity will be run in the open hole section. HaZar~j · Op m is the maximum H2S measured on the W pad. · . e fault will likely be cut by the wellpath. The risk of a lost circulation event is considered low to medium. No losses in neighboring well that crossed same fault. Reservoir Pressure · Res. press. is estimated to be 3400 psi at 8800'ss (7.4 ppg emw). / · Max. surface pressure with gas (0.12 psi/ft) to surface is 2344 psi. TREE=' 3-1/8" MCEVOY WELLHEAD = MCEVOY ACTUA TOR = / I TES: 2093' 1-13-1/2" OTIS SSSV LANDING NIP, ID = 2.75" I ~STMD 5 3422 4 7969 3 9990 2 11092 1 11562 iVD 2930 5732 7135 7928 8275 GAS LIFT MANDRELS OEV TYPE VLV LATCH PORT 47 OTIS RA 51 OTIS RA 44 OTIS RA 43 OTIS RA 42 OTIS RA DATE 11612' H 3-1/2" OTIS SBR SEAL ASSY ] 11688' H9-5/8" x 3-1/2" OTIS PKR, ID = 3.85" IiIII 11731' H3-1/2" OTIS X NIP, ID = 2.75" 11164' H3-1/2" OTIS X NIP, 10 = 2.75" 11198' H3-1/2" TBG TAIL 10 = 2.992" 11806' H ELMD TT LOGGED 08/11/92 ¡ I 13-3/8" CSG, 72#, L-80, 10= 12.347" H 2933' ~ Minimum II)::::: 2.75" @ 2093' 3-1/2" OTIS SSSV lANDING NIPPLE L - 13-1/2" TBG, 9.2#, L-80, .0087 bpf, 10 = 2.992" H 11672' I TOP OF 3-1/2" TBG TAILPIPE H 11672' H J 13-1/2" TBG, 9.3#, L-80,.0087 bpf, ID = 2.992" H 11189' I I TOPOF5-1/2"LNR(06/20/03) 1-111810' Sllllll I 9-5/8" CSG, 47#, L-80, 10 = 8.681" H 12027' PERFORATION SUMMARY REF LOG: MWD NEUTRONl GRI SWS/ CBT ON 10/01/88 ANGLE AT TOP PERF: 34 @ 12280' Note: Refer to Production DB for historical perf data SIZE SPF INTERV AL Opn/Sqz DA TE 3-3/8" 4 12280 - 12295 3-3/8" 4 12310 - 12320 3-3/8" 4 12326 12386 3-3/8" 4 12398 - 12408 3-3/8" 4 12418 - 12430 I PBTD H 12431' 15-1/2" LNR, 17#, L-80, .0232 bpf, ID = 4.892" H 12670' DATE 10/13/88 03/05/01 08/27/01 06/20/03 REV BY COMMENTS REV BY COMMENTS HENRY ORiGINAL COMPLETION SIS-LG FINAL RNlKAK CORRECTIONS JBM/TLH 5-1/2" lNR TOP CORRECTION DATE I 11622' 1-13-1/2" OTIS SLIDING SLV, ID = 2.75" I 1-1 PRUDHOE BA Y UNIT WELL: W-01 PERMIT No: 1881070 API No: 50-029-21866-00 SEC 21, T11N, R12E, 1157' SNL & 1189' WEL SP Exploration (Alaska) ESP Amoco ...... - Tie_MOil Wl:LLPATH DnAILS. ~w.o1A ..........., ...., 12114.2S .... .......... V_ - ,...... 1 t 011t112M", 0010O 1t#.OOft ~Jl'~ - ...... ~o .... REFERENCE INFORMATION Co=r(~~~:=: ~~~~~l=INOrth M~~~~:=: rl~1~}1~1O:8%~& 83.00 Calculation i\IIathod: Minimum Curvature s~ MO 1m: 1 12114.2.3 37..5 145"1 2: 12145,'1 3.... 14$.f!! : U1$'." 42.2& 14$;.2& " 121n... 1U.'. 1411." $ 12<Ø1.U .a." 81." · 12.,..", ..... .1.3& T 12"1.7' ..... ...3' · 13&1'.11 ..... 113.'3 · uni.n .1.08 ..... 18"13$41.1-$ ft... 111.14 1113l'U.1' -81.21 92;3. U13tu.n ".81 112.54 U 1405&;1& '$..0 .'.M 141438..1$ M.as 128.1$ 1$14$8'.0& MAl: 184... +tJ.W Olq 1"_. ...1..15 .... '.Ð. 11II2'.2' 3.54152.12 ::~fäßU:::: 1171..' 211." Hit.'. un.'. 12." 21t1.II' Te.u.,. 12." 1.18.0' 114".74 12"." ..8::." 1$'fO." 11:." tn... U:11..3 12." 111." 1416M 12... 21.... Ut".$4 12.110 113." ,T.'.)' 12." 291.11. :t:~:n ~i::: 2~:::: ,- .....1. 811$-.2:1 .12.... .u'--n "45.'1 .'4$... 'fl4$." '.41$ .....n U14.41i "'$.72 ......1. ......1 ¡"D.7D ...." 41n." 411..11 4203.47 422..73 4....... -324$.7. 4115.11 42:3..11 -3271.'" 4327.3:5 ·un.:u -34U.&1 -34S3.7. ·U5..34 4&35.13 742'.$7 74<U..' ,...... 1471.41 11'1.3' 1852:.@7 UÞ.'. :,¡:: #123.3. '.3$." $1t4... t2S4.n 1415.$1 .eG...O ANNOTATtOM$ ,.0_ TVD ~NI-$ -€l·W $I\II¡:m .... 1:8100- ~ 8200 Q t:.8300 .c::: 'So 840 III ø= 8500- 'i U860 1: ~ 8700 11I880 i! .... 8900 LEGEND W~~~?J1A P1an#3 T Azimuths to True North Plan, Plan #3 (W-01IP'an#3 W-01A) Magnetic North: 25.58' Created By, Bnj Potni. Da"',6I3OI2oo3 M ¡ ! ¡Pt!lj 11f ¡I ¡¡¡IT 7200 7300 7400 7500 7600 7700 71100 7900 8100 8400 8500 86'00 8700 8800 89'00 9000 9100 9200 9300 8400 West(-)/East(+) [100ftJin) i ¡ , j1 'ji Iii t¡ Ii! ' 8100 8200 8300 8400 8500 8600 8700 8800 8900 9000 9100 Vertical Section at 102.00· [100ft/in] 6/30/2003 2:'15 PM e BP Baker Hughes INTEQ Planning Report e Time: 14:45:42 Well: W-01, True North System: Mean Sea Level Well (0.00N,O.OOE.1 02.00Azi) Minimum Curvature Uh: Oracle - -- .....--..------.... .. ---..... -.-- ....---.--..... .--... I>a~e: Date: 6/30/2003 Co-ordinaleC"iE) I~eference: Verlical (TVD) I~eference: SLoction (VS) Refercnce: SUI·vey Calculalion \lelhod ..--.-.---.-.-- .. BP Amoco Prudhoe Bay PB W Pad W-01 Plan#3 W-01A .....-.-. Company Field: Sitc: Well: Wcllpath: Fiel Alaska. Zone 4 Well Centre BGGM2002 V1ap Zone: Coordinate S~slelll: (;eoma¡:netic '1nde! 1927 Prudhoe Bay North Slope UNITED STATES :US State Plane Coordinate System NAD27 (Clarke 1866) Mean Sea Level \1311 Systen Gen Dahllll Sys Dahill -.--.. - ..- PB W Pad TR-11-12 UNITED STATES: North Slope Northing: Easting: Site: 31.506 N 36.343 W True 0.84 deg 17 6 70 149 Latitude: Longitudc: North Reference: Grid Convergence: 5957194.18 ft 609919.18 ft 0.00 ft 47.83 ft Site Position: From: Map Position Uncertainty: Ground Level: N W 49.941 33.450 01 17 5 70 149 Slot Name: Latitudc: Longitude: 5959100.04 ft 612048.99 ft Northing: Easting : 1874.68 ft 2157.64 ft 0.00 ft Wel +N/-S +E/-W Position Uncertainty: W-01 W-01 Position: Wel W-01 12114.23 ft Mean Sea Level 25.58 deg 80.77 deg Direction deg 102.00 Drilled From: 1'ie-on Depth: Above System Datum: Declination: Mag Dip Angle: +E/-W ft 0.00 83.00 ft Height +N/-S ft 0.00 Plan#3 W-01A 500292186601 Current Datum: 1 : 01 9/12/1988 00:00 Magnetic Data: 6/30/2003 Field Strength: 57524 n1' Vertical Section: Depth From (1'VD) ft 0.00 Wellpath: <-- Lon¡:itude --> I)e~ 'Un Sec ....--....---. <---- I.atitndc ---> Ueg 'Un Sec 2 9.570 W 2 9.570 W 1 58.064 W 1 46.502 W 1 29.871 W 1 17.319 W 1 0.406 W o 59.806 W 1 17.542 W 1 30.465 W 1 45.728 W 2 14.282 W ........ 149 149 149 149 149 149 149 149 149 149 149 149 16.381 N 16.381 N 16.900 N 16.120 N 14.702 N 13.926 N 11.728 N 15.729 N 17.803 N 18.758 N 20.158 N 19.062 N 17 17 17 17 17 17 17 17 17 17 17 17 70 70 70 70 70 70 70 70 70 70 70 70 \lap Easling ft 619096.00 619096.00 619490.00 619888.00 620461.00 620893.00 621477.00 621491.00 620879.00 620434.00 619908.00 618930.00 .....-. \1311 :\'orthing ft Targets 5955795.99 5955795.99 5955854.99 5955781.99 5955646.99 5955574.99 5955360.99 5955767.99 5955968.99 5956058.99 5956192.99 5956065.99 +:\/-8 H:/-W ft ft . ...-.--..-. .. . -3409.04 6997.57 -3409.04 6997.57 -3355.92 7392.44 -3434.85 7789.34 -3578.39 8360.31 -3656.83 8791.23 -3879.53 9372.02 -3472.75 9392.09 -3262.63 8783.10 -3166.00 8339.46 -3024.16 7815.47 -3136.57 6835.60 TVI) ft 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Dir. Description Dip. :\ame W-01A Polygon3. -Polygon 1 -Polygon 2 -Polygon 3 -Polygon 4 -Polygon 5 -Polygon 6 -Polygon 7 -Polygon 8 -Polygon 9 -Polygon 10 . Polygon 11 22.308 W 22.308 W 24.745 W 25.384 W 30.966 W 25.384 W 24.745 W 1 1 1 1 1 1 1 149 149 149 149 149 149 149 18.035 N 18.035 N 11 .634 N 6.346 N 3.100 N 6.346 N 11.634 N 17 17 17 17 17 17 17 70 70 70 70 70 70 70 5955989.99 620715.10 5955989.99 620715.10 5955337.99 620641.90 5954799.99 620628.60 5954466.99 620442.30 5954799.99 620628.60 5955337.99 620641.90 8619.52 8619.52 8536.60 8515.28 8324.02 8515.28 8536.60 -3239.19 -3239.19 -3890.08 -4427.87 -4758.08 -4427.87 -3890.08 0.00 0.00 0.00 0.00 0.00 0.00 0.00 W-01A Fault 1 -Polygon 1 -Polygon 2 -Polygon 3 -Polygon 4 -Polygon 5 -Polygon 6 2 5.659 W 2 5.659 W 1 58.080 W 1 50.932 W 1 44.443 W 1 50.932 W 1 58.080 W 149 149 149 149 149 149 149 15.455 N 15.455 N 15.877 N 15.317 N 13.187 N 15.317 N 15.877 N 17 17 17 17 17 17 17 70 70 70 70 70 70 70 5955703.99 619231.70 5955703.99 619231.70 5955750.99 619491.10 5955697.99 619737.30 5955485.00 619963.40 5955697.99 619737.30 5955750.99 619491.10 7131.89 7131.89 7391.98 7637.39 7860.31 7637.39 7391.98 -3503.06 -3503.06 -3459.93 -3516.60 -3732.96 -3516.60 -3459.93 0.00 0.00 0.00 0.00 0.00 0.00 0.00 W-01 A Rp.gional Fault 2 ·Polygon 1 -Polygon 2 ··Polygon 3 -Polygon 4 -Polygon 5 -Polygon 6 W W W 24.003 24.003 19.602 149 149 149 19.097 N 19.097 N 30.061 N 17 17 17 70 70 70 5956096.99 620655.20 5956096.99 620655.20 5957213.99 620788.30 8561.22 8561.22 8710.97 -3131.30 -3131.30 ..2016.31 0.00 0.00 0.00 W-01A Regional Fault 1 -Polygon 1 -Polygon 2 e BP Baker Hughes INTEQ Planning Report e <--- I.atitudc ----> Dcg :\c1in Scc Ta r¡:cts --> 18.723 W 19.602 W <--- LunKitudc »c¡: :\ctin Scc ..... 149 149 :\1ap Eastin!: ft 5957852.99 620808.20 5957213.99 620788.30 :\1ap :\lIrthinK ft +t:/-W ft +:"/-S ft TV» ft Dir. Desc"iption Dip. 'ame 2 8.297 W 2 8.297 W 2 2.942 W 1 55.854 W 1 44.668 W 1 31.787 W 1 44.668 W 1 55.854 W 2 2.942 W 149 149 149 149 149 149 149 149 149 N N 17 29.477 N 17 29.477 N 17 27.943 N 17 26.135 N 17 24.835 N 17 22.542 N 17 24.835 N 1726.135 N 17 27.943 N 17 36.342 17 30.061 70 70 70 70 70 70 70 70 70 70 70 5957127.99 619118.60 5957127.99 619118.60 5956975.00 619304.80 5956794.99 619550.90 5956668.99 619936.81 5956442.99 620382.50 5956668.99 619936.81 5956794.99 619550.90 5956975.00 619304.80 8740.40 8710.97 7040.03 7040.03 7223.94 7467.35 7851.37 8293.68 7851.37 7467.35 7223.94 -1377.63 -2016.31 -2077.41 -2077.41 -2233.18 -2416.85 -2548.60 -2781.24 -2548.60 -2416.85 -2233.18 0.00 0.00 OM OM OM OM OM 0.00 OM OM OM -Polygon 3 -Polygon 4 W-01A Regional Fault 3 -Polygon 1 -Polygon 2 -Polygon 3 -Polygon 4 -Polygon 5 -Polygon 6 -Polygon 7 -Polygon 8 W 2.031 149 13.705 N 17 70 5955560.99 621418.00 9316.00 -3678.66 8830.00 W-01A T3.3 50.939 W 149 18.435 N 17 70 5956014.99 619732.00 7636.82 -3199.53 8845.00 W-01A T3. 23.419 W 149 6.172 N 17 70 5955799.99 620680.00 8581.59 -3428.66 8890.00 W-01A T3.2 Annotation TIP KOP 3 4 5 6 7 8 9 10 11 12 13 14 TO 8690.76 8715.28 8726.08 8753.37 8845.09 8845.09 8845.09 8848.75 8860.85 8874.48 8885.72 8890.19 8884.01 8860.70 8844.81 12114.23 12145.00 12159.00 12199.00 12461.79 12636.79 12951.79 13076.79 13291.79 13541.79 13756.79 13926.79 14056.79 14306.79 14500.00 6/30/2003 4 From: Definitive Path Date Composed: Version: Tied-to: Plan #3 Identical to Lamar's Plan #3 Yes Plan: Principal Plan Section Information 0.00 152.72 350.00 340.00 290.90 270.00 90.00 103.00 270.00 91.00 270.00 83.00 292.00 90.00 270.00 0.00 2.73 -10.32 -10.85 -22.21 -12.00 12.00 11.71 -12.02 12.02 -12.02 11.91 -11.16 12.05 -12.04 0.00 -3.15 39.46 23.72 14.58 0.00 0.00 -2.67 0.15 -0.04 0.14 1.53 4.45 -0.30 -0.20 0.00 3.56 40.00 25.00 25.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 6918.95 6929.28 6934.27 6951.88 7171.88 7337.38 7642.36 7761.76 7970.68 8211.03 8416.45 8581.54 8706.39 8932.71 9103.83 -3183.66 -3199.11 -3206.47 -3229.73 -3300.48 -3246.70 -3195.10 -3230.71 -3271.36 -3327.35 -3383.23 -3419.61 -3453.79 -3550.34 -3635.73 8690.76 8715.28 8726.08 8753.37 8845.09 8845.09 8845.09 8848.75 8860.85 8874.48 8885.72 8890.19 8884.01 8860.70 8844.81 145.81 146.65 145.20 140.86 82.50 61.50 99.30 113.93 88.09 118.14 92.30 112.54 98.04 128.15 104.89 37.65 36.68 42.20 51.69 90.00 90.00 90.00 86.66 87.00 86.90 87.21 89.81 95.60 94.85 94.46 12114.23 12145.00 12159.00 12199.00 12461.79 12636.79 12951.79 13076.79 13291.79 13541.79 13756.79 13926.79 14056.79 14306.79 14500.00 e BP e Baker Hughes INTEQ Planning Report ,. ...- ..--..... . . -~--------.---.- .. . . . Comllall~ : BP Amoco Dale: 6/30/2003 Time: 14:45:42 I'al:e: 3 Field: Prudhoe Bay Co-ordinate(:'\i E) Reference: Well: W-01, True North Site: PB W Pad Verlical (T\'I» Reference: System: Mean Sea Level Well: W-01 Section (\'8) Reference: Well (0.00N,0.00E,102.00Azi) : 'V.elll~~~~:.. Plan#3 W-01A Suney Calculation :\Ielhod: Minimum Curvature J>h: Oracle .......----- . .. __..__.__n. ..-.-.-----... - . Survey - ...-----... .. .., ...-""-...'---.-.. :\11> IlId Azim ssn'n 'IS E/W :\1ap~ 'lapE "S I)LS TFO Tool ft deg deg ft ft ft ft ft ft deg/10OO deg ... . -..----.. ...........---..---. . ....--... .. -.---.- . . .......---- . ..--.---.. 12114.23 37.65 145.81 8690.76 -3183.66 6918.95 5956020.16 619014.04 7429.67 0.00 0.00 TIP 12125.00 37.31 146.10 8699.30 -3189.09 6922.62 5956014.78 619017.79 7434.39 3.56 152.72 MWD 12145.00 36.68 146.65 8715.28 -3199.11 6929.28 5956004.86 619024.60 7442.99 3.56 152.49 KOP 12150.00 38.65 146.09 8719.23 -3201.65 6930.97 5956002.35 619026.33 7445.18 40.00 350.00 MWD 12159.00 42.20 145.20 8726.08 -3206.47 6934.27 5955997.58 619029.69 7449.40 40.00 350.44 3 12175.00 45.98 143.30 8737.57 -3215.50 6940.77 5955988.65 619036.33 7457.64 25.00 340.00 MWD 12199.00 51.69 140.86 8753.37 -3229.73 6951.88 5955974.58 619047.65 7471.47 25.00 341.37 4 12200.00 51.78 140.57 8753.99 -3230.34 6952.38 5955973.98 619048.16 7472.08 25.00 290.90 MWD 12225.00 54.25 133.38 8769.04 -3244.91 6966.01 5955959.62 619062.00 7488.44 25.00 291.08 MWD 12250.00 57.12 126.65 8783.14 -3258.16 6981.82 5955946.61 619078.01 7506.66 25.00 295.41 MWD 12275.00 60.33 120.37 8796.12 -3269.93 6999.63 5955935.11 619095.99 7526.53 25.00 299.21 MWD 12300.00 63.82 114.50 8807.84 -3280.08 7019.23 5955925.25 619115.73 7547.81 25.00 302.47 MWD 12325.00 67.53 108.98 8818.14 -3288.50 7040.38 5955917 .15 619137.01 7570.25 25.00 305.23 MWD 12350.00 71.41 103.75 8826.91 -3295.08 7062.83 5955910.91 619159.55 7593.58 25.00 307.50 MWD 12360.11 73.03 101.71 8830.00 -3297.20 7072.22 5955908.93 619168.97 7603.20 25.00 309.34 W-01A T3 12375.00 75.44 98.76 8834.05 -3299.74 7086.32 5955906.59 619183.11 7617.52 25.00 309.96 MWD 12400.00 79.56 93.95 8839.46 -3302.43 7110.57 5955904.27 619207.39 7641.80 25.00 310.76 MWD 12425.00 83.76 89.27 8843.09 -3303.12 7135.28 5955903.95 619232.11 7666.11 25.00 311.81 MWD 12450.00 88.00 84.66 8844.88 -3301.80 7160.17 5955905.64 619256.97 7690.18 25.00 312.49 MWD 12461.79 90.00 82.50 8845.09 -3300.48 7171.88 5955907.13 619268.66 7701.36 25.00 312.82 5 12475.00 90.00 80.91 8845.09 -3298.57 7184.95 5955909.23 619281.70 7713.75 12.00 270.00 MWD 12500.00 90.00 77.91 8845.09 -3293.98 7209.52 5955914.19 619306.20 7736.83 12.00 270.00 MWD 12525.00 90.00 74.91 8845.09 -3288.11 7233.82 5955920.42 619330.40 7759.38 12.00 270.00 MWD 12550.00 90.00 71.91 8845.09 -3280.97 7257.78 5955927.92 619354.25 7781.33 12.00 270.00 MWD 12575.00 90.00 68.91 8845.09 -3272.59 7281.33 5955936.65 619377.67 7802.62 12.00 270.00 MWD 12600.00 90.00 65.91 8845.09 -3262.99 7304.41 5955946.59 619400.60 7823.20 12.00 270.00 MWD 12625.00 90.00 62.91 8845.09 -3252.19 7326.95 5955957.72 619422.98 7843.01 12.00 270.00 MWD 12636.79 90.00 61.50 8845.09 -3246.70 7337.38 5955963.37 619433.33 7852.07 12.00 270.00 6 12650.00 90.00 63.08 8845.09 -3240.55 7349.08 5955969.69 619444.93 7862.23 12.00 90.00 MWD 12675.00 90.00 66.08 8845.09 -3229.82 7371.65 5955980.75 619467.34 7882.08 12.00 90.00 MWD 12700.00 90.00 69.08 8845.09 -3220.29 7394.76 5955990.62 619490.30 7902.71 12.00 90.00 MWD 12725.00 90.00 72.08 8845.09 -3211.98 7418.34 5955999.28 619513.75 7924.04 12.00 90.00 MWD 12750.00 90.00 75.08 8845.09 -3204.92 7442.32 5956006.70 619537.62 7946.02 12.00 90.00 MWD 12775.00 90.00 78.08 8845.09 -3199.12 7466.63 5956012.87 619561.84 7968.60 12.00 90.00 MWD 12800.00 90.00 81.08 8845.09 -3194.60 7491.22 5956017.75 619586.36 7991.71 12.00 90.00 MWD 12825.00 90.00 84.08 8845.09 -3191.37 7516.00 5956021.35 619611.09 8015.29 12.00 90.00 MWD 12850.00 90.00 87.08 8845.09 -3189.45 7540.93 5956023.64 619635.98 8039.26 12.00 90.00 MWD 12875.00 90.00 90.08 8845.09 -3188.83 7565.92 5956024.63 619660.96 8063.58 12.00 90.00 MWD 12900.00 90.00 93.08 8845.09 -3189.52 7590.90 5956024.31 619685.95 8088.16 12.00 90.00 MWD 12925.00 90.00 96.08 8845.09 -3191.52 7615.82 5956022.69 619710.89 8112.95 12.00 90.00 MWD 12950.00 90.00 99.08 8845.09 -3194.82 7640.60 5956019.76 619735.71 8137.87 12.00 90.00 MWD 12951.79 90.00 99.30 8845.09 -3195.10 7642.36 5956019.50 619737.48 8139.66 12.00 90.00 7 12975.00 89.37 102.01 8845.22 -3199.39 7665.17 5956015.55 619760.35 8162.86 12.00 103.00 MWD 13000.00 88.70 104.94 8845.64 -3205.22 7689.48 5956010.09 619784.74 8187.85 12.00 102.99 MWD 13025.00 88.03 107.86 8846.35 -3212.27 7713.45 5956003.39 619808.81 8212.76 12.00 102.94 MWD 13050.00 87.37 110.79 8847.36 -3220.54 7737.02 5955995.48 619832.50 8237.54 12.00 102.85 MWD 13075.00 86.71 113.72 8848.65 -3229.99 7760.12 5955986.37 619855.74 8262.10 12.00 102.73 MWD 13076.79 86.66 113.93 8848.75 -3230.71 7761.76 5955985.68 619857.38 8263.85 12.00 102.58 8 13100.00 86.67 111.14 8850.10 -3239.59 7783.16 5955977.12 619878.91 8286.63 12.00 270.00 MWD 13125.00 86.68 108.13 8851.55 -3247.98 7806.66 5955969.08 619902.54 8311.36 12.00 270.16 MWD 13150.00 86.70 105.13 8853.00 -3255.12 7830.57 5955962.30 619926.55 8336.23 12.00 270.34 MWD 13175.00 86.73 102.13 8854.43 -3261.00 7854.83 5955956.78 619950.89 8361.18 12.00 270.51 MWD 13200.00 86.77 99.12 8855.84 -3265.60 7879.36 5955952.55 619975.48 8386.13 12.00 270.68 MWD e BP e Baker Hughes INTEQ Planning Report Company: BP Amoco Date ,6/30/2003 Time: 14:45:42,':":':,,:: Page: 4 Field: ,Prudhoe Bay Co ' ate(NE) Referençe:, Well: W-01, T¡'LJ'~:r\lorth Site: ,;PßW Pad Vertl " VD) Referençe:,'/;< ' System: Meari;S~ª: ~~vel Well:m:W~01 " Sedl'S)Referençe: ,'<,', , Well (0.00l,0.OOE:,'102.00Azi) Welllilit~';} Plan#3 W-01A Survey Calculatiou Meti\od: MinimurriCürvature" Db: Oracle Survey MD ' IjÌ~L, Azim SSiVD N/S ~: :.~ E/W Majll'l: MapE VS DLS" '",'"m,TFO Tool ft ';~e9 :L:deg ft ::ff:::" " ft fL ft !', ft deg/10OO(' i deg 13225.00 86.82 96.12 8857.24 -3268.91 7904.09 5955949.61 620000.26 8411.02 12.00 270.85 MWD 13250.00 86.88 93.11 8858.62 -3270.92 7928.97 5955947.97 620025.16 8435.77 12.00 271.02 MWD 13275.00 86.95 90.11 8859.96 -3271.62 7953.92 5955947.64 620050.12 8460.32 12.00 271.19 MWD 13291.79 87.00 88.09 8860.85 -3271.36 7970.68 5955948.15 620066.87 8476.66 12.00 271.35 9 13300.00 86.98 89.08 8861.28 -3271.16 7978.88 5955948.48 620075.07 8484.64 12.00 91.00 MWD 13325.00 86.93 92.08 8862.61 -3271.41 8003.84 5955948.60 620100.03 8509.10 12.00 90.95 MWD 13350.00 86.90 95.09 8863.96 -3272.97 8028.76 5955947.41 620124.96 8533.80 12.00 90.79 MWD 13375.00 86.87 98.09 8865.32 -3275.83 8053.55 5955944.91 620149.79 8558.65 12.00 90.63 MWD 13400.00 86.85 101.10 8866.69 -3279.99 8078.16 5955941.12 620174.46 8583.58 12.00 90.46 MWD 13425.00 86.84 104.10 8868.06 -3285.44 8102.52 5955936.04 620198.89 8608.54 12.00 90.30 MWD 13450.00 86.83 107.11 8869.44 -3292.15 8126.56 5955929.69 620223.03 8633.45 12.00 90.13 MWD 13475.00 86.84 110.11 8870.82 -3300.11 8150.21 5955922.08 620246.80 8658.24 12.00 89.97 MWD 13500.00 86.85 113.11 8872.20 -3309.31 8173.42 5955913.23 620270.13 8682.85 12.00 89.80 MWD 13525.00 86.88 116.12 8873.57 -3319.70 8196.11 5955903.18 620292.98 8707.21 12.00 89.64 MWD 13541.79 86.90 118.14 8874.48 -3327.35 8211.03 5955895.76 620308.00 8723.39 12.00 89.47 10 13550.00 86.90 117.15 8874.92 -3331.15 8218.29 5955892.06 620315.32 8731.29 12.00 270.00 MWD 13575.00 86.91 114.14 8876.27 -3341.96 8240.79 5955881.60 620337.98 8755.54 12.00 270.05 MWD 13600.00 86.92 111.14 8877.62 -3351.56 8263.83 5955872.33 620361.16 8780.08 12.00 270.22 MWD 13625.00 86.95 108.14 8878.96 -3359.95 8287.34 5955864.30 620384.79 8804.81 12.00 270.38 MWD 13650.00 86.98 105.13 8880.28 -3367.10 8311.26 5955857.51 620408.81 8829.70 12.00 270.54 MWD 13675.00 87.02 102.13 8881.59 -3372.98 8335.52 5955851.99 620433.15 8854.65 12.00 270.70 MWD 13700.00 87.07 99.12 8882.88 -3377.58 8360.05 5955847.75 620457.75 8879.60 12.00 270.85 MWD 13725.00 87.12 96.12 8884.15 -3380.90 8384.80 5955844.81 620482.54 8904.50 12.00 271.01 MWD 13750.00 87.19 93.12 8885.39 -3382.91 8409.68 5955843.17 620507.45 8929.26 12.00 271.16 MWD 13756.79 87.21 92.30 8885.72 -3383.23 8416.45 5955842.95 620514.22 8935.95 12.00 271.31 11 13775.00 87.48 94.47 8886.57 -3384.30 8434.61 5955842.15 620532.40 8953.93 12.00 83.00 MWD 13800.00 87.85 97.45 8887.59 -3386.90 8459.46 5955839.92 620557.27 8978.77 12.00 82.90 MWD 13825.00 88.23 1 00.43 8888.44 -3390.78 8484.13 5955836.41 620582.00 9003.72 12.00 82.78 MWD 13850.00 88.61 103.41 8889.13 -3395.94 8508.58 5955831.61 620606.52 9028.71 12.00 82.68 MWD 13875.00 89.00 106.38 8889.65 -3402.37 8532.73 5955825.55 620630.77 9053.67 12.00 82.59 MWD 13900.00 89.39 109.36 8890.00 -3410.04 8556.52 5955818.24 620654.67 9078.53 12.00 82.53 MWD 13925.00 89.79 112.33 8890.18 -3418.93 8579.88 5955809.69 620678.15 9103.23 12.00 82.49 MWD 13926.79 89.81 112.54 8890.19 -3419.61 8581.54 5955809.04 620679.82 9104.99 12.00 82.47 12 13950.00 90.86 109.96 8890.05 -3428.03 8603.17 5955800.95 620701.57 9127.89 12.00 292.00 MWD 13975.00 91.98 107.18 8889.43 -3435.98 8626.86 5955793.34 620725.37 9152.72 12.00 291.98 MWD 14000.00 93.10 104.39 8888.32 -3442.78 8650.89 5955786.91 620749.50 9177.64 12.00 291.92 MWD 14025.00 94.21 101.60 8886.73 -3448.39 8675.19 5955781.66 620773.88 9202.58 12.00 291.79 MWD 14050.00 95.31 98.80 8884.66 -3452.80 8699.71 5955777.62 620798.46 9227.48 12.00 291.61 MWD 14056.79 95.60 98.04 8884.01 -3453.79 8706.39 5955776.73 620805.16 9234.22 12.00 291.38 13 14075.00 95.60 100.23 8882.23 -3456.66 8724.29 5955774.12 620823.09 9252.32 12.00 90.00 MWD 14100.00 95.58 103.25 8879.80 -3461.72 8748.65 5955769.42 620847.52 9277.20 12.00 90.21 MWD 14125.00 95.55 106.26 8877.37 -3468.06 8772.71 5955763.45 620871.67 9302.05 12.00 90.51 MWD 14150.00 95.50 109.27 8874.97 -3475.65 8796.40 5955756.21 620895.48 9326.81 12.00 90.80 MWD 14175.00 95.43 112.29 8872.59 -3484.48 8819.67 5955747.73 620918.87 9351.40 12.00 91.09 MWD 14200.00 95.35 115.30 8870.24 -3494.52 8842.44 5955738.03 620941.78 9375.76 12.00 91.38 MWD 14225.00 95.26 118.31 8867.93 -3505.74 8864.65 5955727.14 620964.16 9399.83 12.00 91.66 MWD 14250.00 95.15 121.32 8865.66 -3518.12 8886.25 5955715.09 620985.94 9423.53 12.00 91.94 MWD 14275.00 95.03 124.33 8863.44 -3531.62 8907.18 5955701.91 621007.06 9446.80 12.00 92.21 MWD 14300.00 94.89 127.34 8861.28 -3546.20 8927.37 5955687.63 621027.47 9469.58 12.00 92.48 MWD 14306.79 94.85 128.15 8860.70 -3550.34 8932.71 5955683.57 621032.87 9475.67 12.00 92.74 14 14325.00 94.85 125.96 8859.17 -3561.27 8947.20 5955672.85 621047.51 9492.11 12.00 270.00 MWD 14350.00 94.83 122.95 8857.06 -3575.36 8967.73 5955659.07 621068.26 9515.13 12.00 269.81 MWD BP Baker Hughes INTEQ Planning Report e e Company: BP Amoco Date: 6/30/2003 Time: 14:45:42 I'age: 5 Field: Prudhoe Bay Co-ordinah~(~ E) I{eference: Well: W-01, True North Site: PB W Pad Vertical (T\'D) I{eference: System: Mean Sea Level Well: W-01 Section (\'8) Rert~rencc: Well (0.00N,0.00E,102.00Azi) Wcllpatll: Plan#3 W-01A Sllrve~' Calculation 'Ietllod: Minimum Curvature Db: Oracle . . ..- . .-.------- . Survey MD Incl A¡¡;im SSTVD: ,< N/S E/W MapN MapE VS DLS TFO Tool ft deg deg ft ft ft ft ft ft deg/10OO deg 14375.00 94.80 119.94 8854.96 -3588.36 8988.98 5955646.40 621089.70 9538.62 12.00 269.56 MWD 14400.00 94.76 116.93 8852.87 -3600.22 9010.89 5955634.86 621111.78 9562.51 12.00 269.31 MWD 14425.00 94.70 113.92 8850.81 -3610.91 9033.39 5955624.51 621134.43 9586.74 12.00 269.06 MWD 14450.00 94.63 110.91 8848.78 -3620.41 9056.42 5955615.35 621157.60 9611.24 12.00 268.81 MWD 14475.00 94.55 107.90 8846.77 -3628.69 9079.92 5955607.43 621181.22 9635.95 12.00 268.56 MWD 14500.00 94.46 104.89 8844.81 -3635.73 9103.83 5955600.75 621205.23 9660.80 12.00 268.32 TD Well I I 1$.~:$QØ9Þ~¡ 1 1 1 , :}/::/:::::~ -r=:r - ..·..1 IIIIIIIII! I' , e Nordic 2 Slim hole BOP e I 1 , KB Elevation I I ~ Rig ~Io~~ ....... ..... ~ I t..·çqpJ..l, I ::::::::::::::::4.µijij@~ÞðpWG;~7§~~Þ~1:aù~ô~¡8~~ è 111110' 5000 p" BOP',. ID-1.<)6' I········, ····:·:·:·:·:·:·:.:::.:J¡i¡i¡i.i¡i¡i¡i:i:i·i:i:i:i:i¡i:i:¡[::.~:'" . lijhij:i~:ümB*iffi:::r::' ....¡;¡¡i~dï.i~~..·L I / ...........mr.........: ~.. I'··.. ..;;.:.:.:.:.:, ..... '.... ..Ip':·:·:·:·:· y ~~"":"'.";d, ~ M ï~~~~ I @ OJ IHCR[ - Choke Line I I'u,. 'r .. I, Kill Line I t -r:::::r : ~r~:~~ip,,~~~::~:~::11 b:W,t::~-¡;;::':mM:J .-- 4 ~:':6' SCOO psi ¡RX-3!./) I ~:':,*Ji~I' , . .;:;. "~;': I ..':::.:.......:::::::' I, Swab Valve I Tree Size i&;..JþJ t,,::.. :,~: ::,::: I~- /" / I Master Valve SSV I I . · F:("~'~ Base Flange I I P055149 DATE INVOICE / CREDiT MEMO 8/22/2003 iNV# PR082003J THE ATTACHED CHECK IS IN PAYMeNT FOR ITEMS DESCRIBeD ABOVE. BP EXPLORATION, (ALASKA) INC. PRUDHOE BAY UNIT PO BOX 196612 ANCHORAGE, AK99519-6612 PAY: PERMIT TO DRilL EE 0.0\ f} DESCRIPTION 11 P ~.. ':J'~ ,JlI~ ,IUI'I ii. ...~ ~..If.. I,IU" f\/II,'""" TO THE ORDER OF: ~$KA Qlllf;þ/¡s CONS€~v.¡¡Î¡Ot¡¡ CQ"1MIS$¡ON 333 W 7TH A VËNJ.JE SUITE 100 ANCHORAGE, AI< 99501-3539 GROSS NATIONAL CITY BANK Ashland, Ohio DATE AugUSt22,2003 1/'055 U. '11/' I:O~. W 38 '151: 0." ?8'1¡;". DATE 8/22/2003 CHECK NO. 055149 VENDOR DISCOUNT NET AlasKa Oil & Gas Cons ~ 412 No.. P 055149 CONSOUDATE:D COMME:RCA~ ACCOUNT AMÖUNT ..h........$1 00 .00.............. H e e e e TRANSMIT AL LETTER CHECK LIST CIRCLE APPROPRIATE LETTERJP ARAGRAPHS TO BE INCLUDED IN TRANSMITTAL LETTER WELL NAME PTD# CHECK WHAT APPLIES ADD-ONS (OPTIONS) MULTI LATERAL (If API num ber last two (2) digits are between 60-69) "CLUE" The permit is for a new wellbore segment of existing well ~ Permit No, API No. Production should continue to be reported as a function ·of the original API number stated above. HOLE In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both name (name on permit plus PH) and API number (50 70/80) from records, data and logs acquired for well (name on permit). P~OT (PH) SPACING EXCEPTION DRY DITCH SAMPLE Rev: 07/10/02 C\jody\templates The permit is approved subject to full compliance with 20 AAC 25.055. Approval to perforate and produce is contingent upon issuance of a conservation order approving a spacing exception. (Company Name) assumes the liability of any protest to the spacing exception that may occur. All dry ditch sample sets submitted to the Commission must be in no greater than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. WELl+.PERMIT,CH.ECKLIS-r. Company BP EXPLORATION (ALASKA) INC Well Name: PRUDHOE BAY UNIT W-01A Program DEV Well bore seg D PTD#:2031760 Field & Pool PRUDHOE BAY. PRUDHOE OIL - 640150 Initial ClasslType DEV /1-0IL GeoArea 890 Unit 11650 On/Off Shore ~ Annular Disposal D Administration 1 Permit fee attached _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yj;!$ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ 2 Leasj;!numberappropriale_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ 3 _U_nlque well_n_a(T1j;!_aod oumb_er _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Y_e$ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ _ _ 4 WelUocatj;!d In_a_d_efil)e_dpool _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yj;!$ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ 5 WeJUocaled prpper _dlsta/lce_ from driJli/lg ul)ilb_oUl)d_ary_ _ _ _ _ Yj;!$ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ 6 WellJocatj;!d properdlsta/lce_ from Qther welJs_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yj;!$ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ 7 _S_utfjcieI)Lacreage_aYailable indrilJiog unjL _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yj;!$ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ 8 Jtdj;!vi¡¡ted, js_ weJlbore plaUl)cJu_ded _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yj;!$ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ 9 Qperator ol)ly afte'cted party _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yj;!$ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ 10 _Qper_ator has_appropriate_bo/ld lnJQrce. . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yj;!$ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ 11 pj;!rmil c_ao be lS$ued without co_n$ervaJiOI) order _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yj;!$ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Appr Date 12 Pj;![Il)il c_ao be lS$ued without admil)istratilleapprpvaJ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ RPC 10/15/2003 13 Can permit be approved before 15-day wait No 14 WeJUocatj;!d wlthil) ¡¡rea ¡¡lld_strata_authQrlzed by_lojeetioo Or d_er#(putlO#in_cpmmeots)(FQr_NA _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ __ 15 AJI welJs_withtn.114Joile_are.a_of reyiew id_eotlfied (Fpr seNjcj;!J^/.ell ol)lYL _ _ _ _ _ _ _ _ _ _ _ _ _ _ NA _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ 16 Pre-produced iojeetor; ~uralion_of pre-pro~uetiol) Ij;!$s thall3 mOl)ths_ (For_servlce welt QnJy) _ _ NA _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ 17 _AÇMP_FilldingpfCQIlSisle/lcy_h_a$beenissuedforJhi$project _ _ _ _ _ _ _ _ _ NA _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ __ Appr WGA 18 19 20 21 22 23 24 25 26 27 Date 28 10/15/2003 29 30 31 32 33 34 Engineering Geology 35 36 Date 37 10/15/2003 38 39 Appr RPC Geologic Commissioner: JJT~ e _Cpoduclor strillg_provided _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _NA _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _S_urfacj;!_casillg_prQtects alLk/lowll USDWs _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _NA _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _CMTv_oladequateJo circulate_oncOl)ductor_& SUJtC$g _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _NA _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ CMT vol adequateJo tie-in Jong _slriog lo_surf csg_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ NA _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _CMTwill coyeraJl kl)ownpro_duetiye horilon_s_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ No_ _ _ _ _ _ _ Slotte_d, _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _C_a$iog desigos adequate. fpr C,T~ B&_perrTJafrp$t _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yj;!$ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Mequaletan_kage_oJ re_serve pit _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yj;!$ _ _ _ _ _ _ _ CTDU. _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ JtaJe-drilL has_a to-403 for abandollment bej;!O apPJQved _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yj;!$ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _Mequalewellbore.sep¡¡ratio_n_proposed_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yj;!$ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Jtdivecter req_uired, does it meel reguJatiol)s_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ NA _ _ _ _ _ _ _ Sidetrack. _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ DJilJiogf]uid_prQgram$chematic&equipJi$!adequale_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yj;!$_ _ _ _ _M¡¡xMW_8Jpp.9. _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ __ _ _ __ _BOPEs,_dpthey meetreguJatiol) _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _Yj;!$ _ _ _ _ _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . . _ _ _BOPEpres$ raJiOQ appropriate;_testto(put psig tn_commel)ts)_ _ _ _ . . . . _ _ _ _ _ _ Yes _ _ _. .. Testto_35QO_psi. _MS~ 23M psi. _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ . _ . . . ChokerTJanifold compJies. w/APIR~-53 (May 64>- _ . _ _ . . _ _ _ _ _ . _ _ _ _ _ _ . _ _ _ _ _ _ _ _ Yj;!$ . . _ _ _ _ _ _ . _ _ _ _ . _ _ _ _ _ _ _ . _ . Work will occ_ur withouLoperatio/l.shutdown_ _ _ . _ _ _ _ _ _ _ _ _ _ . _ . _ _ _ _ _ _ Yes _ . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . . . . . _ _ _ _ . _ . _ _ _ _ _ _ _ _ _ . _ . Js. preseoce_ of H2S gas_ probable. _ _ _ _ _ _ _ . . _ _ _ _ _ . _ _ _ _ _ _ _ _ _ . _ _ _ _ _ No. _ . _ _ _ _ _ _ _ _ _ _ . _ _ _ _ _ _ . _ _ . Meçha.nicaLcpodjtlo/lpfwe.II$withiI)80Ryerified (forservicewelJ onJ y)_ _ _ _ _ _. _ _NA _ _ _ _ . _. . _ _ _ _ _ _ _ _ _ _ . _ . _ . _ _ _ _ . . _ _ _ _ _ _ _ . _ _ _ . _ _ _ _ _ _ _ _ _ _ . . e - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - pj;!rmit c.ao be iS$ued w/o_ hydrogen_ s_ulfide measures _ _ _ _ _ _ _No_ .D_atapreseoted on_ pote_ntial oveJpres.surezOl)es _ _ _ _ _ _ _ _ _ _ _ _ _ . _ _ _ _ _ _ NA _ _ _ _ . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . Sj;!ismic_a/lalysjs_ of shallow gaszpoes _ _ _ _ _ _ . _ . _ _ . _ _ _ _ _. . _NA Sj;!¡¡bedcOl)djtipo survey _(if of(-sh_ore) _ _ _ _ _ _ _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ _ _ _ _NA _ . . _ Conta_ct l)amelphOlleJorweekly progress_reports [exploratpryonlYl _ _ _ _ _ _ _ _ . _ _ _ _ _ _ _ _NA _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -- - - - - - - - - - - - - - - - - - - - - - - - - - -- - - - - - - ~ - - - - - - - -- - - - - - - - - - - - - - - - - - - - -- Date: /01/6(0) Engineering Commissioner: ~~~' f' Í/ ~.;\/, Date Public Q-P Commissioner ¿/ /~~ A e e 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 APPENDIX. No special effort has been made to chronologically organize this category of information. e e **** REEL HEADER **** MWD 04/07/20 BHI 01 LIS Customer Format Tape **** TAPE HEADER **** MWD 03/12/22 599386 01 2.375" CTK *** LIS COMMENT RECORD *** Remark File Version 1.000 Extract File: Idwg.las !!!!!!!!!!!!!!!!!! ! !!!!!!!!!!!!!!!!!! ! -Version Information VERSo WRAP. -Well Information Block #MNEM.UNIT Data Type #--------- ------------- STRT.FT 12078.0000: STOP.FT 13135.0000: STEP.FT 0.5000: NULL. -999.2500: COMP. COMPANY: WELL. WELL: FLD . FIELD: LOC . LOCATION: CNTY. COUNTY: STAT. STATE: SRVC. SERVICE COMPANY: TOOL. TOOL NAME & TYPE: DATE. LOG DATE: API . API NYUMBER: -Parameter Information Block #MNEM.UNIT Value #--------- ------------------------- SECT. 21 TOWN.N 11N RANG. 12E PDAT. MSL EPD .F 0 LMF . RKB FAPD.F 83 DMF KB EKB .F 83 EDF .F N/A EGL .F N/A CASE.F N/A OSl . DIRECTIONAL -Remarks (1) All depths are Measured Depths (MD) unless otherwise noted. 1. 20: NO: CWLS log ASCII Standard -VERSION 1.20 One line per frame Information ------------------------------- Starting Depth Ending Depth Level Spacing Absent Value BP Exploration (Alaska), Inc. W-01A Prudhoe Bay Unit 70 deg 17' 49.941" N 149 deg 5' 33.450" W North Slope Alaska Baker Hughes INTEQ 2.375 Coil Track 22-Dec-03 500292186601 Description ------------------------------- Section Township Range Permanent Datum Elevation Of Perm. Datum Log Measured from Feet Above Perm. Datum Drilling Measured From Elevation of Kelly Bushing Elevation of Derrick Floor Elevation of Ground Level Casing Depth Other Services Line 1 ,?O':;'- 17 ~ -' )Jv r7 ~ e e (2) All depths are Bit Depths unless otherwise noted. (3) All Gamma Ray data (GRAX) presented is realtime data. (4) Baker Hughes INTEQ utilized CoilTrack downhole tools and ADVANTAGE surface system. (5) Tools ran in the string included Casing Collar Locator, Electrical Disconnect and Circulating Sub, a Drilling Performance Sub, (inner and outer downhole pressure, downhole weight on bit, downhole temperature), a Gamma and Directional Sub, and Hydraulic Orienting Sub with near bit inclination sensor. (6) The data presented here is final and was depth shifted to a PDC (Primary Depth Control) recorded by SWS on December 22, 2003. (7) The sidetrack was drilled from a milled window in 5 1/2 inch liner. Top of window: 12143.6' MD (8714.2' SSTVD) Bottom of window: 12149.3' MD (8718.7' SSTVD). (8) The interval from 13112' to 13135' MD (8851' to 8853' SSTVD was not logged due to bit to sensor offset at TD. (9) Tied in to W-Ol at 12122' MD. (9) Tied in to W-Ol at 12122' MD. MNEMONICS: GRAX -> Gamma Ray MWD-API [MWD] (MWD-API units) ROPS -> Rate of Penetration, feet/hour TVD -> Subsea True Vertical Depth, feet CURVE SHIFT DATA BASELINE, MEASURED, 12101.6,12101.8, 12110.9,12112, 12114.2, 12115.5, 12118.8, 12119.6, 12123, 12124, 12143.1, 12142.3, 12151,12152.1, 12159.1, 12159.1, 12174, 12174.6, 12191.2,12192.1, 12199.1,12198.3, 12218.7, 12217.8, 12220.4, 12220.2, 12249.2, 12248.4, 12256.8, 12257.8, 12272, 12272, 12291.7, 12292.3, 12294.6, 12296.5, 12308.9, 12309.9, 12314.3, 12314.7, 12322.2, 12323.8, 12340.9, 12341.9, 12344, 12344.8, 12391.1, 12388.8, 12392.2, 12389, 12396.9,12392.2, 12425.9, 12424.5, 12429.5, 12428.4, 12485, 12485, 12497.3, 12495.8, 12504.4, 12500.7, 12509.9, 12506.2, 12524.7, 12524.1, 12558.4, 12556.1, 12616.8, 12615.3, 12639.2, 12642.1, 12705.9, 12708.8, 12745.5, 12748.8, 12804.1, 12808, 12815.9, 12813.6, DISPLACEMENT 0.207031 1.03906 1.24707 0.831055 1. 03906 ! -0.832031 1. 03906 o 0.624023 0.831055 -0.831055 -0.831055 -0.208008 -0.831055 1. 03906 o ! 0.623047 ! 1. 87012 1. 03906 0.416016 1. 66309 1. 03906 0.832031 -2.28516 -3.11719 -4.78027 -1.4541 -1.03906 o -1.45508 -3.74121 -3.74023 -0.623047 -2.28613 -1.45508 2.90918 2.90918 3.3252 3.94824 -2.28613 e e 12847.8, 12848.4, 12884.4, 12888.8, 12894.2, 12899.2, 13065.2, 13059.8, 13108, 13113.4, EOZ END END 0.623047 4.36426 4.9873 -5.40332 5.40332 ! BASE CURVE: GROH, OFFSET CURVE: GRAX Tape Subfile: 1 117 records... Minimum record length: Maximum record length: 8 bytes 132 bytes **** FILE HEADER **** MWD .001 1024 *** INFORMATION TABLE: CONS MNEM VALU ------------------------------------ WDFN LCC CN WN FN COUN STAT W-01A 5.xtf 150 BP Exploration (Alaska) Inc. W-01A Prudhoe Bay Unit North Slope Alaska *** LIS COMMENT RECORD *** !!!!!!!!!!!!!!!!!!! Remark File Version 1.000 The data presented here is final and has been depth shifted to a PDC (Primary Depth Control) recorded by SWS, 22-Dec-03 *** INFORMATION TABLE: CIFO MNEM CHAN DIMT CNAM ODEP ---------------------------------------------------- GR ROP GR ROP GRAX01 ROPA01 0.0 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: 1 e e FRAME SPACE = 0.500 * F ONE DEPTH PER FRAME Tape depth ID: F 2 Curves: Name Tool Code Samples Units Size Length 1 2 68 68 1 1 4 4 4 4 GR ROP MWD MWD AAPI F/HR ------- 8 Total Data Records: 26 Tape File Start Depth Tape File End Depth Tape File Level Spacing Tape File Depth Units 12078.000000 13135.000000 0.500000 feet **** FILE TRAILER **** Tape Subfile: 2 35 records... Minimum record length: Maximum record length: 54 bytes 4124 bytes **** FILE HEADER **** MWD .002 1024 *** INFORMATION TABLE: CONS MNEM VALU -------------------------------- WDFN LCC CN WN FN COUN STAT W-01A.xtf 150 BP Exploration (Alaska) W-01A Prudhoe Bay Unit North Slope Alaska *** LIS COMMENT RECORD *** !!!!!!!!!!!!!!!!!!! Remark File Version 1.000 This file contains the raw-unedited field data. *** INFORMATION TABLE: CIFO MNEM CHAN DIMT CNAM ODEP GRAX ROPS ---------------------------------------------------- GRAX ROPA GRAX ROPS 0.0 0.0 e e * 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: 0.250000 Frame spacing units: [F ] Number of frames per record is: 84 One depth per frame (value= 0) Datum Specification Block Sub-type is: 1 FRAME SPACE = 0.250 * F ONE DEPTH PER FRAME Tape depth ID: F 2 Curves: Name Tool Code Samples Units Size Length 1 2 GRAX MWD ROPS MWD 68 68 1 1 AAPI F/HR 4 4 4 4 ------- 8 Total Data Records: 51 Tape File Start Depth Tape File End Depth Tape File Level Spacing Tape File Depth Units 12079.500000 13135.000000 0.250000 feet **** FILE TRAILER **** Tape Subfile: 3 60 records... Minimum record length: Maximum record length: 54 bytes 4124 bytes **** TAPE TRAILER **** MWD 03/12/22 599386 01 **** REEL TRAILER **** MWD 04/07/20 BHI 01 Tape Subfile: 4 2 records... e e Minimum record length: 132 bytes Maximum record length: 132 bytes Tape Subfile 1 is type: LIS - e Tape Subfile 2 is type: LIS DEPTH GR ROP 12078.0000 -999.2500 -999.2500 12078.5000 -999.2500 -999.2500 12100.0000 44.8479 -999.2500 12200.0000 178.6572 2.8766 12300.0000 246.8040 20.0064 12400.0000 31.1570 93.7889 12500.0000 67.8625 59.6411 12600.0000 26.4471 46.0112 12700.0000 35.5396 107.2012 12800.0000 41.5578 47.5444 12900.0000 153.0093 96.5441 13000.0000 323.8058 74.6899 13100.0000 54.8332 101.8736 13135.0000 -999.2500 11.7163 Tape File Start Depth 12078.000000 Tape File End Depth 13135.000000 Tape File Level Spacing 0.500000 Tape File Depth Units feet , ... e e Tape Sub file 3 is type: LIS DEPTH GRAX ROPS 12079.5000 -999.2500 -999.2500 12079.7500 53.7500 -999.2500 12100.0000 42.5200 -999.2500 12200.0000 103.4100 2.3000 12300.0000 292.2700 24.1000 12400.0000 52.7200 95.1200 12500.0000 49.1000 52.3600 12600.0000 23.6700 63.8000 12700.0000 32.6200 133.8700 12800.0000 36.5700 93.6700 12900.0000 315.8400 80.7500 13000.0000 323.6700 68.6500 13100.0000 60.2000 104.3100 13135.0000 -999.2500 -999.2500 Tape File Start Depth 12079.500000 Tape File End Depth 13135.000000 Tape File Level Spacing 0.250000 Tape File Depth Units feet e e **** REEL HEADER **** MWD 04/07/15 BHI 01 LIS Customer Format Tape **** TAPE HEADER **** MWD 03/12/17 599386 01 2.375" CTK *** LIS COMMENT RECORD *** !!!!!!!!!!!!!!!!!! ! !!!!!!!!!!!!!!!!!! ! -Version Information VERSo WRAP. -Well Information Block #MNEM.UNIT Data Type #--------- ------------- STRT.FT 12078.0000: STOP.FT 14109.0000: STEP.FT 0.5000: NULL. -999.2500: COMPo COMPANY: WELL. WELL: FLD . FIELD: LOC . LOCATION: CNTY. COUNTY: STAT. STATE: SRVC. SERVICE COMPANY: TOOL. TOOL NAME & TYPE: DATE. LOG DATE: API . API NYUMBER: -Parameter Information Block #MNEM.UNIT Value #--------- ------------------------- SECT. 21 TOWN.N 11N RANG. 12E PDAT. MSL EPD .F 0 LMF . RKB FAPD.F 83 DMF KB EKB .F 83 EDF .F N/A EGL .F N/A CASE.F N/A OS1 . DIRECTIONAL -Remarks (1) All depths are Measured Depths (MD) unless otherwise noted. Remark File Version 1.000 Extract File: ldwg.las 1. 20: NO: CWLS log ASCII Standard -VERSION 1.20 One line per frame Information ------------------------------- Starting Depth Ending Depth Level Spacing Absent Value BP Exploration (Alaska), Inc. W-01APB1 Prudhoe Bay 70 deg 17' 49.941" N 149 deg 5' 33.450" W North Slope Alaska Baker Hughes INTEQ 2.375 Coil Track 17-Dec-03 500292186670 Description ------------------------------- Section Township Range Permanent Datum Elevation Of Perm. Datum Log Measured from Feet Above Perm. Datum Drilling Measured From Elevation of Kelly Bushing Elevation of Derrick Floor Elevation of Ground Level Casing Depth Other Services Line 1 )&:J-17Ç:, ~ /2j'7~ e e (2) All depths are Bit Depths unless otherwise noted. (3) All Gamma Ray data (GRAX) presented is realtime data. (4) Baker Hughes INTEQ utilized CoilTrack downhole tools and ADVANTAGE surface system. (5) Tools ran in the string included Casing Collar Locator, Electrical Disconnect and Circulating Sub, a Drilling Performance Sub, (inner and outer downhole pressure, downhole weight on bit, downhole temperature), a Gamma and Directional Sub and Hydraulic Orienting Sub with near bit inclination sensor. (6) The data presented here is final and has been depth shifted to a PDC (Primary Depth Control), recorded by SWS on December 22, 2003. A block shift was applied below the W-01A kick off point at 12200' MD, as the PDC curve is no longer common with thw W-01APB1 wellbore below that depth. (7) The sidetrack was drilled from a milled window in 5 1/2 inch liner. Top of window: 12143.7' MD (8714.2' SSTVD) Bottom of window: 12149.3' MD (8718.7' SSTVD). (8) The interval from 14087' MD (8886' SSTVD) to 14109' MD (8885' SSTVD) was not logged due to sensor bit offset at TD. (9) Tied in to W-01 at 12122' MD. MNEMONICS: GRAX ROPA TVD -> Gamma Ray MWD-AAPI [MWD] (MWD-API units) -> Rate of Penetration, feet/hour -> Subsea True Vertical Depth, feet CURVE SHIFT DATA BASELINE, MEASURED, 12101.6,12101.8, 12110.9, 12112, 12114.2, 12115.5, 12118.8, 12119.6, 12123, 12124, 12143.1, 12142.3, 12151, 12152.1, 12159.1, 12159.1, 12174, 12174.6, 12191.2,12192.1, 12199.1, 12198.3, EOZ END END DISPLACEMENT 0.207031 1. 03906 1.24707 0.831055 1.03906 ! -0.832031 1.03906 o 0.624023 0.831055 -0.831055 ! BASE CURVE: GROH, OFFSET CURVE: GRAX Tape Subfile: 1 Minimum record length: Maximum record length: **** FILE HEADER **** MWD .001 1024 *** INFORMATION TABLE: CONS MNEM VALU 85 records... 8 bytes 132 bytes WDFN mwd.xtf ------------------------------------ e e LCC CN WN FN COUN STAT 150 BP Exploration (Alaska) Inc. W-OIAPBl Prudhoe Bay Unit North Slope Alaska *** LIS COMMENT RECORD *** !!!!!!!!!!!!!!!!!!! Remark File Version 1.000 The data presented here is final and has been depth shifted to a PDC (Primary Depth Control) recorded by SWS, 22-Dec-03 *** INFORMATION TABLE: CIFO MNEM CHAN DIMT CNAM ODEP ---------------------------------------------------- GR ROP GR ROP GRAX ROPA 0.0 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: 1 FRAME SPACE = 0.500 * F ONE DEPTH PER FRAME Tape depth ID: F 2 Curves: Name Tool Code Samples Units Size Length 1 2 GR ROP MWD MWD 68 68 1 1 AAPI F/HR 4 4 4 4 ------- 8 Total Data Records: 49 Tape File Start Depth Tape File End Depth Tape File Level Spacing Tape File Depth Units 12078.000000 14109.000000 0.500000 feet **** FILE TRAILER **** Tape Subfile: 2 58 records... Minimum record length: Maximum record length: 54 bytes 4124 bytes **** FILE HEADER **** MWD .002 e e 1024 *** INFORMATION TABLE: CONS MNEM VALU -------------------------------- WDFN LCC CN WN FN COUN STAT raw.xtf 150 BP Exploration (Alaska) W-OIAPBl Prudhoe Bay Unit North Slope Alaska *** LIS COMMENT RECORD *** !!!!!!!!!!!!!!!!!!! Remark File Version 1.000 This file contains the raw-unedited field data. *** INFORMATION TABLE: CIFO MNEM CHAN DIMT CNAM ODEP GRAX ROPS ---------------------------------------------------- GRAX ROPA GRAX ROPS 0.0 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: 0.250000 Frame spacing units: [F ] Number of frames per record is: 84 One depth per frame (value= 0) Datum Specification Block Sub-type is: 1 FRAME SPACE = 0.250 * F ONE DEPTH PER FRAME Tape depth ID: F 2 Curves: Name Tool Code Samples Units Size Length 1 2 68 68 GRAX MWD ROPS MWD 1 1 4 4 4 4 AAPI F/HR ------- 8 Total Data Records: 97 Tape File Start Depth Tape File End Depth Tape File Level Spacing Tape File Depth Units 12079.250000 14109.000000 0.250000 feet **** FILE TRAILER **** e e Tape Subtile: 3 106 records... Minimum record length: Maximum record length: **** TAPE TRAILER **** MWD 03/12/17 599386 01 **** REEL TRAILER **** MWD 04/07/15 BHI 01 Tape Subtile: 4 Minimum record length: Maximum record length: Tape Subtile 1 is type: LIS 54 bytes 4124 bytes 2 records... 132 bytes 132 bytes Tape Subfile 2 is type: LIS DEPTH 12078.0000 12078.5000 12100.0000 12200.0000 12300.0000 12400.0000 12500.0000 12600.0000 12700.0000 12800.0000 12900.0000 13000.0000 13100.0000 13200.0000 13300.0000 13400.0000 13500.0000 13600.0000 13700.0000 13800.0000 13900.0000 14000.0000 14100.0000 14109.0000 GR -999.2500 53.3900 42.5633 192.4000 174.1400 49.0400 26.4550 30.1300 41.4575 31. 5500 22.5933 29.5800 103.9700 25.5750 34.9300 104.4700 64.9400 50.2800 31. 2800 134.1400 194.8200 28.7300 -999.2500 -999.2500 Tape File Start Depth Tape File End Depth Tape File Level Spacing Tape File Depth Units e e ROP -999.2500 -999.2500 -999.2500 33.6800 46.9400 95.4400 107.7400 95.3400 58.3100 146.5900 139.1900 183.6000 110.5200 56.7200 85.8900 82.0600 49.8000 404.8300 71.8700 64.5000 24.7000 59.9900 7.8200 -999.2500 12078.000000 14109.000000 0.500000 feet , " e e Tape Subtile 3 is type: LIS DEPTH GRAX ROPS 12079.2500 -999.2500 -999.2500 12079.5000 53.3900 -999.2500 12100.0000 42.5467 -999.2500 12200.0000 93.8900 36.9300 12300.0000 187.3300 46.0000 12400.0000 60.0900 64.5600 12500.0000 28.3300 105.7400 12600.0000 32.4400 42.1100 12700.0000 42.8050 68.6000 12800.0000 31.2200 141. 2800 12900.0000 22.8300 142.2400 13000.0000 28.8500 172.1300 13100.0000 110.4900 145.4900 13200.0000 27.9100 72 . 0000 13300.0000 35.6200 77.7400 13400.0000 111.5800 87.3400 13500.0000 51.9900 117.9200 13600.0000 47.8800 410.4000 13700.0000 35.2000 83.6300 13800.0000 121.8900 30.0200 13900.0000 211.5700 29.8200 14000.0000 27.0800 80.1500 14100.0000 -999.2500 10.1500 14109.0000 -999.2500 44.6500 Tape File Start Depth 12079.250000 Tape File End Depth 14109.000000 Tape File Level Spacing 0.250000 Tape File Depth Units feet