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Post Office Box 244027 Anchorage, AK 99524-4027 3800 Centerpoint Drive Suite 1400 Anchorage, AK 99503 Phone: (907) 564-4891 02/09/2024 Mr. Mel Rixse Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 Re: Prudhoe Bay Surface Casing by Conductor Annulus Top-offs of Cement, Corrosion Inhibitor through 02/09/2024. Dear Mr. Rixse, Enclosed please find a copy of a spreadsheet with a list of Prudhoe Bay wells that were topped-off with cement, corrosion inhibitor in the surface casing by conductor annulus through 02/09/2024. Cement top-offs are executed as needed to mitigate the void space left at surface by minor cement fallback during the primary surface casing by conductor cement job. The remaining void space between the top of the cement and the top of the conductor is filled with a heavier than water corrosion inhibitor to reduce the risk of external surface casing corrosion. The attached spreadsheets include the well names, API and PTD numbers, treatment dates and volumes. As per previous agreement with the AOGCC, this letter and spreadsheet serve as notification that the treatments took place and meet the requirements of form 10-404 Report of Sundry Operations. If you have any additional questions, please contact me at 564-4891 or oliver.sternicki@hilcorp.com. Sincerely, Oliver Sternicki Well Integrity Supervisor Hilcorp North Slope, LLC Digitally signed by Oliver Sternicki DN: cn=Oliver Sternicki, c=US, o=Hilcorp North Slope LLC, ou=PBU, email=oliver.sternicki@hilcorp.com Date: 2024.02.09 11:15:58 -09'00' Oliver Sternicki Hilcorp North Slope LLC. Surface Casing by Conductor Annulus Cement, Corrosion Inhibitor Top-off Report of Sundry Operations (10-404) 02/09/2024 Well Name PTD # API # Initial top of cement (ft) Vol. of cement pumped (gal) Final top of cement (ft) Cement top off date Corrosion inhibitor (gal) Corrosion inhibitor/ sealant date L-293 223020 500292374900 30 8/29/2023 S-09A 214097 500292077101 2 9/19/2023 S-102A 223058 500292297201 2 9/19/2023 S-105A 219032 500292297701 10 9/19/2023 S-109 202245 500292313500 7 9/19/2023 S-110B 213198 500292303002 35 9/19/2023 S-113B 202143 500292309402 10 9/19/2023 S-115 202230 500292313000 4 9/19/2023 S-116A 213139 500292318301 4 9/19/2023 S-117 203012 500292313700 3 9/19/2023 S-118 203200 500292318800 9 9/19/2023 S-122 205081 500292326500 5 9/19/2023 S-125 207083 500292336100 2 9/19/2023 S-126 207097 500292336300 3 9/19/2023 S-134 209083 500292341300 35 9/19/2023 S-200A 217125 500292284601 7 9/19/2023 S-202 219120 500292364700 13 9/19/2023 S-210 219057 500292363000 10 9/19/2023 S-213A 204213 500292299301 4 9/19/2023 S-215 202154 500292310700 3 9/19/2023 S-216 200197 500292298900 4 9/19/2023 S-41A 210101 500292264501 3 9/19/2023 W-16A 203100 500292204501 2 9/23/2023 W-17A 205122 500292185601 3 9/23/2023 Well Name PTD #API # Initial top of cement (ft) Vol. of cement pumped (gal) Final top of cement (ft) Cement top off date Corrosion inhibitor (gal) Corrosion inhibitor/ sealant date W-19B 210065 500292200602 8 9/23/2023 W-21A 201111 500292192901 8 9/23/2023 W-32A 202209 500292197001 4 9/23/2023 W-201 201051 500292300700 44 9/23/2023 W-202 210133 500292343400 6 9/23/2023 W-204 206158 500292333300 3 9/23/2023 W-205 203116 500292316500 3 9/23/2023 W-207 203049 500292314500 3 9/23/2023 W-211 202075 500292308000 8 9/23/2023 W-213 207051 500292335400 3 9/23/2023 W-214 207142 500292337300 10 9/23/2023 W-215 203131 500292317200 2 9/23/2023 W-223 211006 500292344000 7 9/23/2023 Z-69 212076 500292347100 2.0 27 1.5 10/24/2023 S-128 210159 500292343600 11 12/27/2023 S-135 213202 500292350800 16 12/27/2023 V-113 202216 500292312500 24 12/31/2023 V-114A 203185 500292317801 5 12/31/2023 V-122 206147 500292332800 5 12/31/2023 V-205 206180 500292333800 2 12/31/2023 V-207 208066 500292339000 8 12/31/2023 V-214 205134 500292327500 5 12/31/2023 V-215 207041 500292335100 2 12/31/2023 V-218 207040 500292335000 5 12/31/2023 V-224 208154 500292340000 16 12/31/2023 V-225 209118 500292341900 6 12/31/2023 V-01 204090 500292321000 3 1/1/2024 V-02 204077 500292320900 5 1/1/2024 V-04 206134 500292332200 5 1/1/2024 V-102 202033 500292307000 8 1/1/2024 V-104 202142 500292310300 5 1/1/2024 V-220 208020 500292338300 4 1/1/2024 V-02 204077 500292320900 5 1/1/2024 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): Susp Well Insp Install Whipstock Mod Artificial Lift Perforate New Pool Perforate Plug Perforations Coiled Tubing Ops 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 V-02 Hilcorp North Slope, LLC 3800 Centerpoint Dr, Suite 1400, Anchorage, AK 99503 204-077 50-029-23209-00-00 15086 Conductor Surface Intermediate Production Liner 8938 80 2683 9229 6030 9221 20" 9-5/8" 7" 4-1/2" 8723 30 - 110 29 - 2712 26 - 9255 9054 - 15084 30 - 110 29 - 2708 26 - 8749 8596 - 8939 None 520 3090 5410 7500 9221, 9250 1530 5750 7240 8430 6660 - 14985 4-1/2" 12.6# L-80 24 - 6648 6656 - 8948 Structural 4-1/2" HES TNT Packer 6585, 6581 6585 6581 Torin Roschinger Operations Manager Tyson Shriver tyson.shriver@hilcorp.com 907-564-4542 PRUDHOE BAY, Borealis 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 pressure: 13a.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 0028240 24 - 6644 Perforations 6660' - 6720'MD See attached Fracturing report 26 309 255 320 192 3698 1056 1586 332 320 323-267 13b. Pools active after work:Borealis Oil No SSSV Installed STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS Sr Pet Eng: Sr Pet Geo: Form 10-404 Revised 10/2022 Submit in PDF format to aogcc.permitting@alaska.gov Sr Res Eng: Due Within 30 days of Operations By Grace Christianson at 11:58 am, Oct 11, 2023 CDW 10/16/2023 DSR-10/13/23 ACTIVITY DATE SUMMARY 8/26/2023 ***WELL S/I ON ARRIVAL*** RAN 4-1/2" X CATCHER, SET @6,620'SLM/6619'MD PULLED ST#1 BK- SO GLV FROM 6,525'SLM/6,523'MD PULLED ST#2 BK-LGLV FROM 5,999'SLM/5,997'MD PULLED ST#3 BK-LGLV FROM 5,381'SLM/5,379'MD PULLED ST#4 BK-LGLV FROM 4,490'SLM/4488MD PULLED ST#5 BL-LGLV FROM 3,004'SLM/3,010'MD SET BK-DUMMY VALVE ST#5 ***CONTINUE ON 8/27/2023*** 8/27/2023 ***CONTINUE FROM 8/26/2023*** SET ST#4 BK-DGLV @4,487'SLM SET ST#3 BK-DGLV @5381'SLM SET ST#2 BK-DGLV @ 5999'SLM LOADED IA w/114BBL KCL + 43BBL DIESEL SET ST#1 BK-DGLV @ 6525'SLM LOADED TUBING w/ SET 4-1/2" PX PLUG BODY & PRONG PASSING MIT-T TO 3500PSI ***CONTINUE ON 8/28/2023*** 8/27/2023 Assist SL Load and Test, load IA with 111 BBLS 2% KCL followed by 43 BBLS DSL to FP, Load TBG with 110 BBLS 2% KCL followed by 42 BBLS DSL to FP,MIT-T PASS at 3762 PSI 15 min loss of 89 PSI, 30 min loss of 27 PSI JOB CONTINUES ON 08-28-23 8/28/2023 JOB CONTINUES FROM 08-27-23 Asisst SL, ::::::MIT-IA PASSED:::::: at 3752 PSI 15 min loss of 80 PSI 30 min loss of 15 PSI, FP FL with 13 BBLS 60/40, SL in controll upon Departure 8/28/2023 ***CONTINUE FROM 8/27/2023*** PASSING MIT-IA TO 3500PSI MAINTAING 2,000PSI ON TUBING PULL PX PLUG PRONG PULL PX PLUG BODY ***WELL SHUT IN ON DEPARTURE, LOCATION INSPECTED, DSO NOTIFIED, CLOSE PERMIT MOVE OVER TO V218*** 9/12/2023 LRS Welltesting Line Heater #1. Begin WSR on 09/12/23. Conduct Welltests through test header on V-pad. RU complete, SB for Ops. Continue WSR on 09/13/23. 9/13/2023 Job Scope: Post RWO Frac T-reatment. Spot (5) 500 bbl Frac tanks. Lynden Loading 16/20 Carbo Bond Frac sand from super sacks to SLB sand chief. Spot Frac Pumps, Frac Manifold (Missle), & POD Blender. Sand loading complete. 62 super sack total. 198,400 lbs. Job in Progress. 9/14/2023 Job Scope: Post RWO Frac T-reatment. Finish loading frac tanks Total 1800 bbls, 450 bbls in 4 tanks. Continue rigging up treating Iron to pumps and SLB Missle.Connect electronics in the Frac Cat Mod. Pull water sample from each Frac Tank for testing. Job in Progress. Daily Report of Well Operations PBU V-02 Daily Report of Well Operations PBU V-02 9/15/2023 Job Scope: V-02 Post RWO Frac Treatment. SLB on location at 0630, Warm up equipment. Transfer diesel from transport to SLB. Function checkig equipment. RU LRS to IA. PT lines, Set & test PRV skid 3500 psi. Prime pumps and frac system. Correct a couple small leaks. Verify Water quality lab results. All Lab results fall in range or requirements, 100 deg. Verify Sieve analysis passing at 91%. PT Treating lines. Verify OA bleed line is hooked up. PT to 5500 psi. - Change out check valve. Re- PT to 5500 psi - Good test. IA-1765 psi , OA-335 psi. PJSM - Review Hazards of high pressure pumping. Mitigations / Site control & exclusion zones. Open well and start. Injection. Bring IA psi up from 1750 at start to 3300. Pump 125 bbls 8.4 PPG water 100 deg. 20 bpm. See break over at 2030 psi. Shut down watch closure. ISIP -1460, Closure pressure at 1045 psi in 6 min. Pump Frac stimulation per Measured Pump schedule. Average Treating Pressure 2238 psi, Max Treat Psi -4569, Avg Inj Rate-20.3 bpm.Screen out once started on 12 ppa. Start on flush after starting 12 ppa, Leaving 11 ppa in the pipe, 10 ppa completely behind pipe. Total Proppant (16/20 CarboBOND Lite) Pumped (lbs.) 176,817, Total BH Proppant Pumped (lbs.) 143,519- ~82% Behind Pipe. Close well. Start Clean up and Rig down. Job complete 9/15/2023 T/I/O=frac/1750/334 (FRACTURING) Pumped 3 bbls diesel down IA to hold pressure between 3025 psi and 3325 psi while frac was pumping. FWHP=Frac/988/358 Left well in Fracs control. 9/17/2023 CT #9 1.75" Coil Tubing - Job Scope = Post Frac FCO MIRU, MU 1.75" Coil Tubing JSN. Issues w/ CTU 9 surging. Cld out Slb Mech & ET's. Trouble shoot. Loose Connection off Denison Valve. ***Continue on WSR 9/18/23*** 9/18/2023 CT #9 1.75" Coil Tubing - Job Scope = Post Frac FCO RIH w/ Slb slim 1.75" JSN. Tagged @ 4066' CTM 4068' Mech. Start FCO. FCO'd down to 6776 ctmd. quit seeing sand in the returns. Upped the pump rate in the 7" and pumped a bottoms up, still no sand. Chased out to surface washing jewelry on the way out. Bullhead freeze protect. RDMO CTU 9 ***Job Complete*** 9/19/2023 Assist SL with Brush & Flush Rig up and PT ***job continued to 09-20-23*** 9/19/2023 ***WELL S/I UPON ARRIVAL*** (fracturing) R/U HES 759 SLICKLINE UNIT ***CONT WSR ON 9/20/23*** 9/20/2023 ***job continued from 09-19-23*** T/I/O= 417/270/338 Pump 100 bbls crude down tbg while SL brushed tbg. Final WHP's 750/455/347 SL on well at departure Daily Report of Well Operations PBU V-02 9/20/2023 ***CONT WSR FROM 9/19/23*** (fracturing) B&F W/ 4 1/2" BRUSH, 3.80" GAUGE RING OUT TT TO 6,700' SLM (lrs pumped 100bbls crude) SET 4-1/2" X-CATCHER SUB IN X-NIPPLE @ 6619' MD. PULLED BK-DGLV FROM ST#1 @ 6523' MD. PULLED BK-DGLV FROM ST#2 @ 5997' MD. PULLED BK-DGLV FROM ST#3@ 5379' MD PULLED BK-DGLV FROM ST#4@ 4488' MD PULLED BK-DGLV FROM ST#5 @ 3010' MD. SET BK-LGLV STA #5 @ 3010'MD SET BK-LGLV STA #4 @ 4488' MD SET BK-LGLV STA #3 @ 5379' MD SET BK-LGLV STA #2 @ 5997' MD RAN POCKET BRUSH TO STA #1 @ 6,523' MD ***CONT WSR ON 09/21/2023*** 9/21/2023 LRS Well testing Unit #1 Begin WSR. IL Well V-02, OL Well V-107, Fill Clean out, Unit move, RU, Pressure Test, POP well, Continue to 9/22/23 WSR 9/21/2023 ***CONT WSR FROM 09/20/2023*** SET 1" BK-OGLV (22/64" ports) IN STA #1 @ 6,523' MD PULL 4-1/2" X-CATCHER FROM X-NIPPLE @ 6,619' MD ***WELL LEFT S/I ON DEPARTURE, PAD OP NOTIFIED ON WELL STATUS*** 9/22/2023 LRS Well testing Unit #1, Continued from 9/21/23 WSR. IL Well V-02, OL Well V- 107, Fill Clean out, Continue Flow Back, Continue to 9/23/23 WSR 9/23/2023 LRS Well Testing Unit #1, Continued from 9/22/23 WSR. IL Well V-02, OL Well V- 107, Fill Clean out, Continue Flow Back, Continue to 9/24/23 WSR 9/24/2023 LRS Well Testing Unit #1, Continued from 9/23/23 WSR. IL Well V-02, OL Well V- 107, Fill Clean out, Continue FB, 8 Hr.Piggy Back Test, Continue to 9/25/23 WSR 9/25/2023 LRS Well Testing Unit #1, Continued from 9/24/23 WSR. IL Well V-02, OL Well V- 107, Fill Clean out, End, 8 Hr.Piggy BackTest,BD, RD, Unit move, End WSR FracCAT Treatment Report Well : V-02 Field : Borealis Formation : Kuparuk C County : North Slope Borough State : Alaska Country : United States Prepared for : Hilcorp Client Rep : Tyson Shriver Date Prepared : September 15, 2023 Prepared by Name : Michael Hyatt Division : Schlumberger Phone : 907 227 9897 Pressures Initial Wellhead Pressure (psi)411 Surface Shut in Pressure(psi)3,100 Maximum Treating Pressure (psi)5,049 Injection Test ISIP (psi)1,460 Average Treating Pressure (psi)2,238 ISIP (psi)Screenout Treatment Totals Total Slurry Pumped (Water+Adds+Proppant) (bbl)1410.8 Total Proppant Pumped (lbs.); FracCat Totals 176,817 Total Crosslink Fluid (bbl) 1099.3 Total BH Proppant Pumped (lbs.); FracCat Totals 143,519 Water for Injection Test 125.2 Total Chemical Additives Invoiced Past WH Invoiced Past WH F103 (gal)51 50 J134 (lb)6 0 L065 (gal)51 50 J475 (lb)220 218 L071 (gal)103 102 J580 (lb)1,292 1,174 J532 (gal)101 100 Diesel (bbl)0 0 S123 (gal)55 54 5,049 Client: Hilcorp Well: V-02 Formation: Kuparuk C District: Prudhoe Bay Country: United States Disclaimer Notice This information is presented in good faith, but no warranty is given by and Schlumberger assumes no liability for advice or recommendations made concerning results to be obtained from the use of any product or service. The results given are estimates based on calculations produced by a computer model including various assumptions on the well, reservoir and treatment. The results depend on input data provided by the Operator and estimates as to unknown data and can be no more accurate than the model, the assumptions and such input data. The information presented is Schlumberger's best estimate of the actual results that may be achieved and should be used for comparison purposes rather than absolute values. The quality of input data, and hence results, may be improved through the use of certain tests and procedures which Schlumberger can assist in selecting. The Operator has superior knowledge of the well, the reservoir, the field and conditions affecting them. If the Operator is aware of any conditions whereby a neighboring well or wells might be affected by the treatment proposed herein it is the Operator's responsibility to notify the owner or owners of the well or wells accordingly. Prices quoted are estimates only and are good for 30 days from the date of issue. Actual charges may vary depending upon time, equipment, and material ultimately required to perform these services. Freedom from infringement of patents of Schlumberger or others is not to be inferred. Client: Hilcorp Well: V-02 Formation: Kuparuk C District: Prudhoe Bay Country: United States Injection Prior to the main job, an injection test was performed and the decline was analyzed for about 20 minutes. The selected fluid was water and closure was estimated to be about 1,045 psi. Based on the data, the decision was made to reduce the PAD volume by 50 bbl. The treatment plot for the injection is below: 13:13:27 13:30:07 13:46:47 14:03:27 14:20:07 Time - hh:mm:ss 0 1000 2000 3000 4000 Pressure - psi0 5 10 15 20 25 30 Rate - bbl/min-0.1 0 0.1 0.2 0.3 0.4 0.5 0.6 Concentration - PPATr. Press AN_PRESS Slurry Rate Injection Test © Schlumberger 1994-2017 Hilcorp V-02 09-15-2023 Client: Hilcorp Well: V-02 Formation: Kuparuk C District: Prudhoe Bay Country: United States As Measured Pump Schedule As Measured Pump Schedule Step #Step Name Slurry Volume (bbl) Slurry Rate (bbl/min) Pump Time (min) Fluid Name Fluid Volume (gal) Proppant Name Max Prop Conc (PPA) Prop Conc (PPA) Prop Mass (lb) 1 Displace WB 0.7 1.4 0.5 Water 27 0.0 0.0 0 2 Injection 124.5 18.2 8.1 Water 5212 0.0 0.0 0 3 Shutdown 0.0 18.2 0.0 YF128ST 0 0.0 0.0 0 Stage Pressures & Rates Step #Step Name Average Slurry Rate (bbl/min) Maximum Slurry Rate (bbl/min) Average Treating Pressure (psi) Maximum Treating Pressure (psi) Minimum Treating Pressure (psi) 1 Displace WB 1.4 2.1 687 1150 386 2 Injection 18.2 25.0 2439 2790 544 3 Shutdown 18.2 0.0 2439 1358 512 As Measured Totals Slurry (bbl) Pump Time (min) Clean Fluid (gal) Proppant (lb) 125.2 8.6 5239 0 Average Treating Pressure:2430 psi Maximum Treating Pressure:2790 psi Minimum Treating Pressure:386 psi Average Injection Rate:18.1 bbl/min Maximum Injection Rate:25.0 bbl/min Average Horsepower:1103.4 hhp Maximum Horsepower:1569.1 hhp Maximum Prop Concentration:0.0 PPA Client: Hilcorp Well: V-02 Formation: Kuparuk C District: Prudhoe Bay Country: United States Job Messages Message Log #Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop. Conc. (PPA) 1 Reset Executed Steps 0 0 0.0 0.0 0.0 2 Reset Executed Steps 0 0 0.0 0.0 0.0 3 10:47:58 Vac Truck arrived 1 1794 0.0 0.0 0.0 4 11:00:10 Starting Prime up 1 1793 0.0 0.0 0.0 5 11:37:56 Starting PT 1685 1791 0.0 0.0 0.0 6 11:48:44 Clearing line for check valve 51 1791 0.0 0.0 0.0 7 11:53:35 Check Valve Failed 15 1790 0.0 0.0 0.0 8 12:19:45 Good Check Valve 3051 1788 0.0 0.0 0.0 9 12:34:15 Good PT 63 1786 0.0 0.0 0.0 10 12:56:16 PJSM 106 1777 0.0 0.0 0.0 11 13:23:20 Waiting to open SSV 154 1762 0.0 0.0 0.0 12 13:28:56 Start Displace WB Automatically 385 1761 0.0 0.0 0.0 13 13:28:56 Start Diagnostic Automatically 385 1761 0.0 0.0 0.0 14 13:28:56 Start Design Automatically 385 1761 0.0 0.0 0.0 15 13:29:02 Started Pumping 386 1761 0.0 0.0 0.0 16 13:30:57 Open Well 413 1761 0.1 0.0 0.0 17 13:32:39 Start Injection Manually 615 1780 0.7 2.8 0.0 18 13:32:54 Activated Extend Stage 1133 1811 1.6 4.8 0.0 19 13:39:52 Stage at Perfs: Displace WB 2408 2979 113.7 20.0 0.0 20 13:39:54 Stage at Perfs: Injection 2402 2978 114.4 20.0 0.0 21 13:41:46 Deactivated Extend Stage 1350 2908 125.2 0.0 0.0 22 13:41:46 Start Shutdown Manually 1350 2908 125.2 0.0 0.0 23 13:42:14 Shutdown watch closure 1326 2897 125.2 0.0 0.0 Client: Hilcorp Well: V-02 Formation: Kuparuk C District: Prudhoe Bay Country: United States Main Treatment Overall, the stage treated as expected until the well screened out. Treating pressure was generally declining until we ended the 8 ppa started going into formation. At this point pressures started increasing on surface. This is quite normal for fracs in this formation, and usually indicative of a tip screenout. Moving forward throughout the stage pressures were increasing at an increasing rate. Once the blender had cleared the hopper of 12ppa the well pressured out approximately 2 bbl into flush. At this point, the pressure decline was monitored, and an attempt was made to flush the surface lines of proppant. This attempt failed and the well was shut in. The shut in pressure was 3,088 psi. Once shut in, the surface lines were cleared using the remaining linear gel in the PCM. This was approximately 100 bbl. There was not any major equipment issues during the job. There was one issue at the beginning of the 12ppa stage where a pump lost rate (2± bpm) but was able to recover rate. Fortunately, the pump was able to maintain some rate and recover. This could have been due to debris passing through the pump. Shortly after the pump started coming back to full rate the well pressured out. Moving forward, the fluid end will be inspected and valves/seats will be replaced if needed before the next job. The PRC plot for the main treatment is below: 13:56:34 14:25:44 14:54:54 15:24:04 15:53:14 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 Pressure - psi0 5 10 15 20 25 Rate - bbl/min0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 Concentration - PPATr. Press AN_PRESS Slurry Rate Prop Con BH_PROP_CON Main Treatment © Schlumberger 1994-2017 Hilcorp V-02 09-15-2023 Client: Hilcorp Well: V-02 Formation: Kuparuk C District: Prudhoe Bay Country: United States As Measured Pump Schedule As Measured Pump Schedule Step # Step Name Slurry Volume (bbl) Slurry Rate (bbl/min) Pump Time (min) Fluid Name Fluid Volume (gal) Proppant Name Max Prop Conc (PPA) Prop Conc (PPA) Prop Mass (lb) 1 Pad 37.6 16.6 2.7 YF128ST 1566 0.0 0.0 0 2 Pad 150.0 20.1 7.5 YF128ST 6300 0.0 0.0 0 3 Scour 100.0 19.9 5.0 YF128ST 4112 16/20 CarboBOND Lite 0.5 0.5 1982 4 Pad 2 150.0 20.1 7.5 YF128ST 6298 16/20 CarboBOND Lite 0.5 0.0 55 5 1.0 PPA 100.0 19.9 5.0 YF128ST 4032 16/20 CarboBOND Lite 1.0 0.9 3782 6 2.0 PPA 50.0 19.9 2.5 YF128ST 1936 16/20 CarboBOND Lite 2.0 1.9 3693 7 3.0 PPA 50.0 20.0 2.5 YF128ST 1860 16/20 CarboBOND Lite 3.1 2.9 5422 8 4.0 PPA 50.0 20.1 2.5 YF128ST 1790 16/20 CarboBOND Lite 4.0 3.9 7004 9 5.0 PPA 50.0 20.0 2.5 YF128ST 1725 16/20 CarboBOND Lite 5.1 4.9 8470 10 6.0 PPA 50.0 20.0 2.5 YF128ST 1665 16/20 CarboBOND Lite 6.2 5.9 9841 11 7.0 PPA 50.0 20.0 2.5 YF128ST 1609 16/20 CarboBOND Lite 7.1 6.9 11090 12 8.0 PPA 100.0 20.0 5.0 YF128ST 3107 16/20 CarboBOND Lite 8.2 8.0 24716 13 9.0 PPA 100.0 20.0 5.0 YF128ST 3007 16/20 CarboBOND Lite 9.2 9.0 26959 14 10.0 PPA 100.0 20.0 5.0 YF128ST 2917 16/20 CarboBOND Lite 10.3 9.9 29018 15 11.0 PPA 100.0 19.9 5.0 YF128ST 2830 16/20 CarboBOND Lite 11.4 10.9 30982 16 12.0 PPA 48.0 18.8 2.6 YF128ST 1418 16/20 CarboBOND Lite 13.2 9.8 13801 17 LG Flush 1.4 6.7 16.2 WF128 64 16/20 CarboBOND Lite 0.1 0.0 0 Stage Pressures & Rates Step #Step Name Average Slurry Rate (bbl/min) Maximum Slurry Rate (bbl/min) Average Treating Pressure (psi) Maximum Treating Pressure (psi) Minimum Treating Pressure (psi) 1 Pad 16.6 20.0 2375 2590 509 2 Pad 20.1 20.2 2650 2837 2536 3 Scour 19.9 20.1 2666 2723 2617 4 Pad 2 20.1 20.2 2676 2739 2604 5 1.0 PPA 19.9 20.2 2659 2738 2552 6 2.0 PPA 19.9 20.0 2502 2551 2454 7 3.0 PPA 20.0 20.2 2389 2453 2313 8 4.0 PPA 20.1 20.3 2237 2312 2158 9 5.0 PPA 20.0 20.2 2080 2155 1997 10 6.0 PPA 20.0 20.2 1924 1994 1852 11 7.0 PPA 20.0 20.2 1775 1851 1710 12 8.0 PPA 20.0 20.2 1626 1709 1577 13 9.0 PPA 20.0 20.2 1586 1616 1572 14 10.0 PPA 20.0 20.3 1699 1815 1614 15 11.0 PPA 19.9 20.1 1992 2265 1809 16 12.0 PPA 18.8 19.8 2422 4569 2032 17 LG Flush 6.7 15.4 4203 4569 2629 As Measured Totals Slurry (bbl) Pump Time (min) Clean Fluid (gal) Proppant (lb) 1287.0 81.4 46236 176817 Client: Hilcorp Well: V-02 Formation: Kuparuk C District: Prudhoe Bay Country: United States Average Treating Pressure:2238 psi Maximum Treating Pressure:4569 psi Minimum Treating Pressure:509 psi Average Injection Rate:19.8 bbl/min Maximum Injection Rate:20.3 bbl/min Average Horsepower:1086.8 hhp Maximum Horsepower:1760.6 hhp Maximum Prop Concentration:13.2 PPA Client: Hilcorp Well: V-02 Formation: Kuparuk C District: Prudhoe Bay Country: United States Job Messages Message Log #Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop. Conc. (PPA) 1 14:14:01 Start Pad Manually 511 2275 125.2 0.0 0.0 2 14:14:01 Start Propped Frac Manually 511 2275 125.2 0.0 0.0 3 14:15:06 Start Pumping 1874 2360 2.1 5.0 0.0 4 14:17:17 Start Pad Manually 2533 2886 37.6 20.0 0.0 5 14:21:03 Stage at Perfs: Pad 2604 2902 113.3 20.2 0.0 6 14:22:55 Stage at Perfs: Pad 2786 3030 151.0 20.2 0.0 7 14:24:45 Start Scour Automatically 2720 3063 187.9 20.1 0.0 8 14:24:45 Started Pumping Prop 2720 3063 187.9 20.1 0.0 9 14:29:47 Start Pad 2 Automatically 2610 3071 287.9 19.9 0.5 10 14:29:58 Stopped Pumping Prop 2604 3071 291.6 19.9 0.0 11 14:30:27 Stage at Perfs: Scour 2603 3074 301.2 20.1 0.0 12 14:35:25 Stage at Perfs: Pad 2 2731 3053 401.3 20.2 0.0 13 14:37:14 Start 1.0 PPA Automatically 2735 3054 437.8 20.1 0.0 14 14:37:15 Started Pumping Prop 2739 3055 438.2 20.1 0.0 15 14:42:15 Start 2.0 PPA Automatically 2543 3087 537.8 20.0 1.0 16 14:42:55 Stage at Perfs: 1.0 PPA 2507 3080 551.1 19.9 2.0 17 14:44:46 Start 3.0 PPA Automatically 2453 3057 587.9 20.1 2.0 18 14:47:16 Start 4.0 PPA Automatically 2312 3079 637.9 19.9 2.9 19 14:47:56 Stage at Perfs: 2.0 PPA 2261 3065 651.2 20.1 4.0 20 14:49:45 Start 5.0 PPA Automatically 2155 3088 687.7 20.2 4.1 21 14:50:25 Stage at Perfs: 3.0 PPA 2116 3075 701.0 19.8 5.1 22 14:52:15 Start 6.0 PPA Automatically 1991 3111 737.7 19.9 4.9 23 14:52:55 Stage at Perfs: 4.0 PPA 1951 3091 751.0 20.0 6.0 24 14:54:45 Start 7.0 PPA Automatically 1835 3116 787.8 19.9 6.1 25 14:55:25 Stage at Perfs: 5.0 PPA 1819 3099 801.1 20.0 7.1 26 14:57:15 Start 8.0 PPA Automatically 1705 3132 837.8 20.0 7.0 27 14:57:54 Stage at Perfs: 6.0 PPA 1693 3117 850.9 20.1 8.2 28 15:00:25 Stage at Perfs: 7.0 PPA 1591 3143 901.1 19.9 7.9 29 15:02:15 Start 9.0 PPA Automatically 1580 3159 937.8 20.0 7.9 30 15:02:55 Stage at Perfs: 8.0 PPA 1564 3138 951.1 19.9 9.1 31 15:07:15 Start 10.0 PPA Automatically 1619 3157 1037.7 20.1 9.0 32 15:07:55 Stage at Perfs: 9.0 PPA 1613 3143 1051.1 19.8 10.3 33 15:12:15 Start 11.0 PPA Automatically 1797 3122 1137.7 20.0 10.0 34 15:12:54 Stage at Perfs: 10.0 PPA 1845 3187 1150.8 20.0 11.4 35 15:17:17 Start 12.0 PPA Automatically 2121 3092 1237.7 19.3 11.2 36 15:18:00 Stage at Perfs: 11.0 PPA 2044 3117 1250.9 19.7 10.8 37 15:18:04 Activated Extend Stage 2014 3095 1252.2 19.7 11.3 38 15:19:52 Deactivated Extend Stage 4569 3307 1285.6 7.3 -0.0 39 15:19:52 Start LG Flush Manually 4569 3307 1285.6 7.3 -0.0 40 15:35:04 Stopped Pumping Prop 3304 3119 1287.0 0.0 -0.1 41 15:38:56 Closed Well 3088 2947 1287.0 0.0 0.0 42 15:47:22 Cleaning up pumps 115 1001 1287.0 2.5 0.0 Additive Additive Description F103 Surfactant 1.0 Gal/mGal 50.0 gal J475 Breaker J475 4.2 lb/mGal 218.0 lbm J532 Crosslinker 1.9 Gal/mGal 100.0 gal J580 Gel J580 22.8 lb/mGal 1,174.0 lbm L065 Scale Inhibitor 1.0 Gal/mGal 50.0 gal L071 Clay Control Agent 2.0 Gal/mGal 102.0 gal M275 Bactericide 0.5 lb/mGal 24.0 lbm S123 Activator 1.0 lb/mGal 54.0 lbm S526-1620 Propping Agent varied concentrations 143,519.0 lbm 74.45013 % 25.03312 % 0.20426 % 0.11024 % 0.03600 % 0.03042 % 0.02939 % 0.01835 % 0.01703 % 0.01592 % 0.01364 % 0.01253 % 0.00722 % 0.00680 % 0.00471 % 0.00318 % 0.00209 % 0.00163 % 0.00109 % 0.00051 % 0.00042 % 0.00025 % 0.00021 % 0.00019 % 0.00019 % 0.00017 % 0.00009 % 0.00009 % 0.00004 % 0.00004 % 0.00004 % 0.00001 % 100 % 64-19-7 Acetic acid (impurity) Total * Mix water is supplied by the client. Schlumberger has performed no analysis of the water and cannot provide a breakdown of components that may have been added to the water by third-parties. * The evaluation of attached document is performed based on the composition of the identified products to the extent that such compositional information was known to GRC - Chemicals as of the date of the document was produced. Any new updates will not be reflected in this document. 14464-46-1 Cristobalite 14808-60-7 Quartz, Crystalline silica 127-08-2 Acetic acid, potassium salt (impurity) 111-46-6 2,2''-oxydiethanol (impurity) 1310-73-2 Sodium hydroxide (impurity) 7447-40-7 Potassium chloride (impurity) 7786-30-3 Magnesium chloride 9002-84-0 poly(tetrafluoroethylene) 14807-96-6 Magnesium silicate hydrate (talc) 7631-86-9 Silicon Dioxide (Impurity) 10377-60-3 Magnesium nitrate 55965-84-9 5-chloro-2-methyl-4-isothiazolin-3-one and 2-methyl-4-isothiazolin-3-one 91053-39-3 Diatomaceous earth, calcined 10043-52-4 Calcium chloride 112-42-5 1-undecanol (impurity) 68131-39-5 Ethoxylated Alcohol 68131-40-8 Alcohols, c11-15-secondary, ethoxylated 7647-14-5 Sodium chloride 111-76-2 2-butoxyethanol 34398-01-1 Ethoxylated C11 Alcohol 25038-72-6 Vinylidene chloride/methylacrylate copolymer 67-63-0 Propan-2-ol 107-21-1 Ethylene Glycol 129898-01-7 2-Propenoic acid, polymer with sodium phosphinate 56-81-5 1, 2, 3 - Propanetriol 7727-54-0 Diammonium peroxidisulphate 1303-96-4 Sodium tetraborate decahydrate 66402-68-4 Ceramic materials and wares, chemicals 9000-30-0 Guar gum 67-48-1 2-hydroxy-N,N,N-trimethylethanaminium chloride CAS Number Chemical Name Mass Fraction -Water (Including Mix Water Supplied by Client)* YF128ST:WF128:Fesh water 51,475 gal † Proprietary Technology The total volume listed in the tables above represents the summation of water and additives. Water is supplied by client. Report ID:RPT-1709 Fluid Name & Volume Concentration Volume Disclosure Type:Post-Job Well Completed: Date Prepared:10/2/2023 State:Alaska County/Parish:North Slope Borough Case: Client:HILCORP NORTH SLOPE LLC Well:PRUDHOE BAY UNIT V-02 Basin/Field:PRUDHOE BAY # SLB-Private Page: 1 / 1 Additive Additive Description F103 Surfactant 1.0 Gal/mGal 50.0 gal J475 Breaker J475 4.2 lb/mGal 218.0 lbm J532 Crosslinker 1.9 Gal/mGal 100.0 gal J580 Gel J580 22.8 lb/mGal 1,174.0 lbm L065 Scale Inhibitor 1.0 Gal/mGal 50.0 gal L071 Clay Control Agent 2.0 Gal/mGal 102.0 gal M275 Bactericide 0.5 lb/mGal 24.0 lbm S123 Activator 1.0 lb/mGal 54.0 lbm S526-1620 Propping Agent varied concentrations 143,519.0 lbm 74.45013 % 25.03312 % 0.20426 % 0.11024 % 0.03600 % 0.03042 % 0.02939 % 0.01835 % 0.01703 % 0.01592 % 0.01364 % 0.01253 % 0.00722 % 0.00680 % 0.00471 % 0.00318 % 0.00209 % 0.00163 % 0.00109 % 0.00051 % 0.00042 % 0.00025 % 0.00021 % 0.00019 % 0.00019 % 0.00017 % 0.00009 % 0.00009 % 0.00004 % 0.00004 % 0.00004 % 0.00001 % 100 % 64-19-7 Acetic acid (impurity) Total * Mix water is supplied by the client. Schlumberger has performed no analysis of the water and cannot provide a breakdown of components that may have been added to the water by third-parties. * The evaluation of attached document is performed based on the composition of the identified products to the extent that such compositional information was known to GRC - Chemicals as of the date of the document was produced. Any new updates will not be reflected in this document. 14464-46-1 Cristobalite 14808-60-7 Quartz, Crystalline silica 127-08-2 Acetic acid, potassium salt (impurity) 111-46-6 2,2''-oxydiethanol (impurity) 1310-73-2 Sodium hydroxide (impurity) 7447-40-7 Potassium chloride (impurity) 7786-30-3 Magnesium chloride 9002-84-0 poly(tetrafluoroethylene) 14807-96-6 Magnesium silicate hydrate (talc) 7631-86-9 Silicon Dioxide (Impurity) 10377-60-3 Magnesium nitrate 55965-84-9 5-chloro-2-methyl-4-isothiazolin-3-one and 2-methyl-4-isothiazolin-3-one 91053-39-3 Diatomaceous earth, calcined 10043-52-4 Calcium chloride 112-42-5 1-undecanol (impurity) 68131-39-5 Ethoxylated Alcohol 68131-40-8 Alcohols, c11-15-secondary, ethoxylated 7647-14-5 Sodium chloride 111-76-2 2-butoxyethanol 34398-01-1 Ethoxylated C11 Alcohol 25038-72-6 Vinylidene chloride/methylacrylate copolymer 67-63-0 Propan-2-ol 107-21-1 Ethylene Glycol 129898-01-7 2-Propenoic acid, polymer with sodium phosphinate 56-81-5 1, 2, 3 - Propanetriol 7727-54-0 Diammonium peroxidisulphate 1303-96-4 Sodium tetraborate decahydrate 66402-68-4 Ceramic materials and wares, chemicals 9000-30-0 Guar gum 67-48-1 2-hydroxy-N,N,N-trimethylethanaminium chloride CAS Number Chemical Name Mass Fraction -Water (Including Mix Water Supplied by Client)* YF128ST:WF128:Fesh water 51,475 gal † Proprietary Technology The total volume listed in the tables above represents the summation of water and additives. Water is supplied by client. Report ID:RPT-1709 Fluid Name & Volume Concentration Volume Disclosure Type:Post-Job Well Completed: Date Prepared:10/2/2023 State:Alaska County/Parish:North Slope Borough Case: Client:HILCORP NORTH SLOPE LLC Well:PRUDHOE BAY UNIT V-02 Basin/Field:PRUDHOE BAY # SLB-Private Page: 1 / 1 FracCAT Treatment Report Well : V-02 Field : Borealis Formation : Kuparuk C County : North Slope Borough State : Alaska Country : United States Prepared for : Hilcorp Client Rep : Tyson Shriver Date Prepared : September 15, 2023 Prepared by Name : Michael Hyatt Division : Schlumberger Phone : 907 227 9897 Pressures Initial Wellhead Pressure (psi) 411 Surface Shut in Pressure(psi) 3,100 Maximum Treating Pressure (psi) 5,049 Injection Test ISIP (psi) 1,460 Average Treating Pressure (psi) 2,238 ISIP (psi) Screenout Treatment Totals Total Slurry Pumped (Water+Adds+Proppant) (bbl) 1410.8 Total Proppant Pumped (lbs.); FracCat Totals 176,817 Total Crosslink Fluid (bbl) 1099.3 Total BH Proppant Pumped (lbs.); FracCat Totals 143,519 Water for Injection Test 125.2 Total Chemical Additives Invoiced Past WH Invoiced Past WH F103 (gal) 51 50 J134 (lb) 6 0 L065 (gal) 51 50 J475 (lb) 220 218 L071 (gal) 103 102 J580 (lb) 1,292 1,174 J532 (gal) 101 100 Diesel (bbl) 0 0 S123 (gal) 55 54 Client : Hilcorp Well : V-02 Formation : Kuparuk C District : Prudhoe Bay Country : United States Disclaimer Notice This information is presented in good faith, but no warranty is given by and Schlumberger assumes no liability for advice or recommendations made concerning results to be obtained from the use of any product or service. The results given are estimates based on calculations produced by a computer model including various assumptions on the well, reservoir and treatment. The results depend on input data provided by the Operator and estimates as to unknown data and can be no more accurate than the model, the assumptions and such input data. The information presented is Schlumberger's best estimate of the actual results that may be achieved and should be used for comparison purposes rather than absolute values. The quality of input data, and hence results, may be improved through the use of certain tests and procedures which Schlumberger can assist in selecting. The Operator has superior knowledge of the well, the reservoir, the field and conditions affecting them. If the Operator is aware of any conditions whereby a neighboring well or wells might be affected by the treatment proposed herein it is the Operator's responsibility to notify the owner or owners of the well or wells accordingly. Prices quoted are estimates only and are good for 30 days from the date of issue. Actual charges may vary depending upon time, equipment, and material ultimately required to perform these services. Freedom from infringement of patents of Schlumberger or others is not to be inferred. Client : Hilcorp Well : V-02 Formation : Kuparuk C District : Prudhoe Bay Country : United States Injection Prior to the main job, an injection test was performed and the decline was analyzed for about 20 minutes. The selected fluid was water and closure was estimated to be about 1,045 psi. Based on the data, the decision was made to reduce the PAD volume by 50 bbl. The treatment plot for the injection is below: 13:13:27 13:30:07 13:46:47 14:03:27 14:20:07 Time - hh:mm:ss 0 1000 2000 3000 4000 Pressure - psi0 5 10 15 20 25 30 Rate - bbl/min-0.1 0 0.1 0.2 0.3 0.4 0.5 0.6 Concentration - PPATr. Press AN_PRESS Slurry Rate Injection Test © Schlumberger 1994-2017 Hilcorp V-02 09-15-2023 Client : Hilcorp Well : V-02 Formation : Kuparuk C District : Prudhoe Bay Country : United States As Measured Pump Schedule As Measured Pump Schedule Step # Step Name Slurry Volume (bbl) Slurry Rate (bbl/min) Pump Time (min) Fluid Name Fluid Volume (gal) Proppant Name Max Prop Conc (PPA) Prop Conc (PPA) Prop Mass (lb) 1 Displace WB 0.7 1.4 0.5 Water 27 0.0 0.0 0 2 Injection 124.5 18.2 8.1 Water 5212 0.0 0.0 0 3 Shutdown 0.0 18.2 0.0 YF128ST 0 0.0 0.0 0 Stage Pressures & Rates Step # Step Name Average Slurry Rate (bbl/min) Maximum Slurry Rate (bbl/min) Average Treating Pressure (psi) Maximum Treating Pressure (psi) Minimum Treating Pressure (psi) 1 Displace WB 1.4 2.1 687 1150 386 2 Injection 18.2 25.0 2439 2790 544 3 Shutdown 18.2 0.0 2439 1358 512 As Measured Totals Slurry (bbl) Pump Time (min) Clean Fluid (gal) Proppant (lb) 125.2 8.6 5239 0 Average Treating Pressure: 2430 psi Maximum Treating Pressure: 2790 psi Minimum Treating Pressure: 386 psi Average Injection Rate: 18.1 bbl/min Maximum Injection Rate: 25.0 bbl/min Average Horsepower: 1103.4 hhp Maximum Horsepower: 1569.1 hhp Maximum Prop Concentration: 0.0 PPA Client : Hilcorp Well : V-02 Formation : Kuparuk C District : Prudhoe Bay Country : United States Job Messages Message Log # Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop. Conc. (PPA) 1 Reset Executed Steps 0 0 0.0 0.0 0.0 2 Reset Executed Steps 0 0 0.0 0.0 0.0 3 10:47:58 Vac Truck arrived 1 1794 0.0 0.0 0.0 4 11:00:10 Starting Prime up 1 1793 0.0 0.0 0.0 5 11:37:56 Starting PT 1685 1791 0.0 0.0 0.0 6 11:48:44 Clearing line for check valve 51 1791 0.0 0.0 0.0 7 11:53:35 Check Valve Failed 15 1790 0.0 0.0 0.0 8 12:19:45 Good Check Valve 3051 1788 0.0 0.0 0.0 9 12:34:15 Good PT 63 1786 0.0 0.0 0.0 10 12:56:16 PJSM 106 1777 0.0 0.0 0.0 11 13:23:20 Waiting to open SSV 154 1762 0.0 0.0 0.0 12 13:28:56 Start Displace WB Automatically 385 1761 0.0 0.0 0.0 13 13:28:56 Start Diagnostic Automatically 385 1761 0.0 0.0 0.0 14 13:28:56 Start Design Automatically 385 1761 0.0 0.0 0.0 15 13:29:02 Started Pumping 386 1761 0.0 0.0 0.0 16 13:30:57 Open Well 413 1761 0.1 0.0 0.0 17 13:32:39 Start Injection Manually 615 1780 0.7 2.8 0.0 18 13:32:54 Activated Extend Stage 1133 1811 1.6 4.8 0.0 19 13:39:52 Stage at Perfs: Displace WB 2408 2979 113.7 20.0 0.0 20 13:39:54 Stage at Perfs: Injection 2402 2978 114.4 20.0 0.0 21 13:41:46 Deactivated Extend Stage 1350 2908 125.2 0.0 0.0 22 13:41:46 Start Shutdown Manually 1350 2908 125.2 0.0 0.0 23 13:42:14 Shutdown watch closure 1326 2897 125.2 0.0 0.0 Client : Hilcorp Well : V-02 Formation : Kuparuk C District : Prudhoe Bay Country : United States Main Treatment Overall, the stage treated as expected until the well screened out. Treating pressure was generally declining until we ended the 8 ppa started going into formation. At this point pressures started increasing on surface. This is quite normal for fracs in this formation, and usually indicative of a tip screenout. Moving forward throughout the stage pressures were increasing at an increasing rate. Once the blender had cleared the hopper of 12ppa the well pressured out approximately 2 bbl into flush. At this point, the pressure decline was monitored, and an attempt was made to flush the surface lines of proppant. This attempt failed and the well was shut in. The shut in pressure was 3,088 psi. Once shut in, the surface lines were cleared using the remaining linear gel in the PCM. This was approximately 100 bbl. There was not any major equipment issues during the job. There was one issue at the beginning of the 12ppa stage where a pump lost rate (2± bpm) but was able to recover rate. Fortunately, the pump was able to maintain some rate and recover. This could have been due to debris passing through the pump. Shortly after the pump started coming back to full rate the well pressured out. Moving forward, the fluid end will be inspected and valves/seats will be replaced if needed before the next job. The PRC plot for the main treatment is below: 13:56:34 14:25:44 14:54:54 15:24:04 15:53:14 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 Pressure - psi0 5 10 15 20 25 Rate - bbl/min0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 Concentration - PPATr. Press AN_PRESS Slurry Rate Prop Con BH_PROP_CON Main Treatment © Schlumberger 1994-2017 HilcorpV-0209-15-2023 Client : Hilcorp Well : V-02 Formation : Kuparuk C District : Prudhoe Bay Country : United States As Measured Pump Schedule As Measured Pump Schedule Step # Step Name Slurry Volume (bbl) Slurry Rate (bbl/min) Pump Time (min) Fluid Name Fluid Volume (gal) Proppant Name Max Prop Conc (PPA) Prop Conc (PPA) Prop Mass (lb) 1 Pad 37.6 16.6 2.7 YF128ST 1566 0.0 0.0 0 2 Pad 150.0 20.1 7.5 YF128ST 6300 0.0 0.0 0 3 Scour 100.0 19.9 5.0 YF128ST 4112 16/20 CarboBOND Lite 0.5 0.5 1982 4 Pad 2 150.0 20.1 7.5 YF128ST 6298 16/20 CarboBOND Lite 0.5 0.0 55 5 1.0 PPA 100.0 19.9 5.0 YF128ST 4032 16/20 CarboBOND Lite 1.0 0.9 3782 6 2.0 PPA 50.0 19.9 2.5 YF128ST 1936 16/20 CarboBOND Lite 2.0 1.9 3693 7 3.0 PPA 50.0 20.0 2.5 YF128ST 1860 16/20 CarboBOND Lite 3.1 2.9 5422 8 4.0 PPA 50.0 20.1 2.5 YF128ST 1790 16/20 CarboBOND Lite 4.0 3.9 7004 9 5.0 PPA 50.0 20.0 2.5 YF128ST 1725 16/20 CarboBOND Lite 5.1 4.9 8470 10 6.0 PPA 50.0 20.0 2.5 YF128ST 1665 16/20 CarboBOND Lite 6.2 5.9 9841 11 7.0 PPA 50.0 20.0 2.5 YF128ST 1609 16/20 CarboBOND Lite 7.1 6.9 11090 12 8.0 PPA 100.0 20.0 5.0 YF128ST 3107 16/20 CarboBOND Lite 8.2 8.0 24716 13 9.0 PPA 100.0 20.0 5.0 YF128ST 3007 16/20 CarboBOND Lite 9.2 9.0 26959 14 10.0 PPA 100.0 20.0 5.0 YF128ST 2917 16/20 CarboBOND Lite 10.3 9.9 29018 15 11.0 PPA 100.0 19.9 5.0 YF128ST 2830 16/20 CarboBOND Lite 11.4 10.9 30982 16 12.0 PPA 48.0 18.8 2.6 YF128ST 1418 16/20 CarboBOND Lite 13.2 9.8 13801 17 LG Flush 1.4 6.7 16.2 WF128 64 16/20 CarboBOND Lite 0.1 0.0 0 Stage Pressures & Rates Step # Step Name Average Slurry Rate (bbl/min) Maximum Slurry Rate (bbl/min) Average Treating Pressure (psi) Maximum Treating Pressure (psi) Minimum Treating Pressure (psi) 1 Pad 16.6 20.0 2375 2590 509 2 Pad 20.1 20.2 2650 2837 2536 3 Scour 19.9 20.1 2666 2723 2617 4 Pad 2 20.1 20.2 2676 2739 2604 5 1.0 PPA 19.9 20.2 2659 2738 2552 6 2.0 PPA 19.9 20.0 2502 2551 2454 7 3.0 PPA 20.0 20.2 2389 2453 2313 8 4.0 PPA 20.1 20.3 2237 2312 2158 9 5.0 PPA 20.0 20.2 2080 2155 1997 10 6.0 PPA 20.0 20.2 1924 1994 1852 11 7.0 PPA 20.0 20.2 1775 1851 1710 12 8.0 PPA 20.0 20.2 1626 1709 1577 13 9.0 PPA 20.0 20.2 1586 1616 1572 14 10.0 PPA 20.0 20.3 1699 1815 1614 15 11.0 PPA 19.9 20.1 1992 2265 1809 16 12.0 PPA 18.8 19.8 2422 4569 2032 17 LG Flush 6.7 15.4 4203 4569 2629 As Measured Totals Slurry (bbl) Pump Time (min) Clean Fluid (gal) Proppant (lb) 1287.0 81.4 46236 176817 Client : Hilcorp Well : V-02 Formation : Kuparuk C District : Prudhoe Bay Country : United States Average Treating Pressure: 2238 psi Maximum Treating Pressure: 4569 psi Minimum Treating Pressure: 509 psi Average Injection Rate: 19.8 bbl/min Maximum Injection Rate: 20.3 bbl/min Average Horsepower: 1086.8 hhp Maximum Horsepower: 1760.6 hhp Maximum Prop Concentration: 13.2 PPA Client : Hilcorp Well : V-02 Formation : Kuparuk C District : Prudhoe Bay Country : United States Job Messages Message Log # Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop. Conc. (PPA) 1 14:14:01 Start Pad Manually 511 2275 125.2 0.0 0.0 2 14:14:01 Start Propped Frac Manually 511 2275 125.2 0.0 0.0 3 14:15:06 Start Pumping 1874 2360 2.1 5.0 0.0 4 14:17:17 Start Pad Manually 2533 2886 37.6 20.0 0.0 5 14:21:03 Stage at Perfs: Pad 2604 2902 113.3 20.2 0.0 6 14:22:55 Stage at Perfs: Pad 2786 3030 151.0 20.2 0.0 7 14:24:45 Start Scour Automatically 2720 3063 187.9 20.1 0.0 8 14:24:45 Started Pumping Prop 2720 3063 187.9 20.1 0.0 9 14:29:47 Start Pad 2 Automatically 2610 3071 287.9 19.9 0.5 10 14:29:58 Stopped Pumping Prop 2604 3071 291.6 19.9 0.0 11 14:30:27 Stage at Perfs: Scour 2603 3074 301.2 20.1 0.0 12 14:35:25 Stage at Perfs: Pad 2 2731 3053 401.3 20.2 0.0 13 14:37:14 Start 1.0 PPA Automatically 2735 3054 437.8 20.1 0.0 14 14:37:15 Started Pumping Prop 2739 3055 438.2 20.1 0.0 15 14:42:15 Start 2.0 PPA Automatically 2543 3087 537.8 20.0 1.0 16 14:42:55 Stage at Perfs: 1.0 PPA 2507 3080 551.1 19.9 2.0 17 14:44:46 Start 3.0 PPA Automatically 2453 3057 587.9 20.1 2.0 18 14:47:16 Start 4.0 PPA Automatically 2312 3079 637.9 19.9 2.9 19 14:47:56 Stage at Perfs: 2.0 PPA 2261 3065 651.2 20.1 4.0 20 14:49:45 Start 5.0 PPA Automatically 2155 3088 687.7 20.2 4.1 21 14:50:25 Stage at Perfs: 3.0 PPA 2116 3075 701.0 19.8 5.1 22 14:52:15 Start 6.0 PPA Automatically 1991 3111 737.7 19.9 4.9 23 14:52:55 Stage at Perfs: 4.0 PPA 1951 3091 751.0 20.0 6.0 24 14:54:45 Start 7.0 PPA Automatically 1835 3116 787.8 19.9 6.1 25 14:55:25 Stage at Perfs: 5.0 PPA 1819 3099 801.1 20.0 7.1 26 14:57:15 Start 8.0 PPA Automatically 1705 3132 837.8 20.0 7.0 27 14:57:54 Stage at Perfs: 6.0 PPA 1693 3117 850.9 20.1 8.2 28 15:00:25 Stage at Perfs: 7.0 PPA 1591 3143 901.1 19.9 7.9 29 15:02:15 Start 9.0 PPA Automatically 1580 3159 937.8 20.0 7.9 30 15:02:55 Stage at Perfs: 8.0 PPA 1564 3138 951.1 19.9 9.1 31 15:07:15 Start 10.0 PPA Automatically 1619 3157 1037.7 20.1 9.0 32 15:07:55 Stage at Perfs: 9.0 PPA 1613 3143 1051.1 19.8 10.3 33 15:12:15 Start 11.0 PPA Automatically 1797 3122 1137.7 20.0 10.0 34 15:12:54 Stage at Perfs: 10.0 PPA 1845 3187 1150.8 20.0 11.4 35 15:17:17 Start 12.0 PPA Automatically 2121 3092 1237.7 19.3 11.2 36 15:18:00 Stage at Perfs: 11.0 PPA 2044 3117 1250.9 19.7 10.8 37 15:18:04 Activated Extend Stage 2014 3095 1252.2 19.7 11.3 38 15:19:52 Deactivated Extend Stage 4569 3307 1285.6 7.3 -0.0 39 15:19:52 Start LG Flush Manually 4569 3307 1285.6 7.3 -0.0 40 15:35:04 Stopped Pumping Prop 3304 3119 1287.0 0.0 -0.1 41 15:38:56 Closed Well 3088 2947 1287.0 0.0 0.0 42 15:47:22 Cleaning up pumps 115 1001 1287.0 2.5 0.0 Nolan Vlahovich Hilcorp Alaska, LLC Geo Tech 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: 06/14/2023 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20230418 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# KU 12-17 50133205770000 208089 4/19/2023 YELLOW JACKET PERF MPU C-42 50029231960000 204028 3/22/2023 YELLOW JACKET PERF MPU E-19 50029227460000 197037 4/11/2023 YELLOW JACKET SCBL-CALIPER MPU H-15 50029232840000 205159 3/8/2023 YELLOW JACKET PERF MPU L-12 50029223340000 193011 4/2/2023 YELLOW JACKET CUT PBU 01-31 50029216260000 186132 5/1/2023 YELLOW JACKET SCBL PBU L-117 50029230390000 201167 3/5/2023 YELLOW JACKET SCBL PBU V-02 50029232090000 204077 3/27/2023 YELLOW JACKET SCBL SRU 231-33 50133101630100 223008 3/31/2023 YELLOW JACKET GPT-PERF SRU 231-33 50133101630100 223008 4/14/2023 YELLOW JACKET GPT-PLUG-PERF Please include current contact information if different from above. T37746 T37747 T37748 T37749 T37750 T37751 T37752 T37753 T37754 T37754 PBU V-02 50029232090000 204077 3/27/2023 YELLOW JACKET SCBL Kayla Junke Digitally signed by Kayla Junke Date: 2023.06.14 14:53:01 -08'00' 7. If perforating: 1. Type of Request: 2. Operator Name: 3. Address: 4. Current Well Class:5. Permit to Drill Number: 6. API Number: 8. Well Name and Number: 9. Property Designation (Lease Number):10. Field: 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 What Regulation or Conservation Order governs well spacing in thes pool? Will planned perforations require a spacing exception?Yes No 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): PRESENT WELL CONDITION SUMMARY Perforation Depth MD (ft): Perforation Depth TVD (ft):Tubing Size: Tubing Grade: Tubing MD (ft): Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): Casing Length Size MD TVD Burst Collapse Exploratory Stratigraphic Development Service 12. Attachments: 14. Estimated Date for Commencing Operations: 13. Well Class after proposed work: 15. Well Status after proposed work: 16. Verbal Approval: 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approcal. Proposal Summary Wellbore schematic BOP SketchDetailed Operations Program OIL GAS WINJ WAG GINJ WDSPL GSTOR Op Shutdown Suspended SPLUG Abandoned ServiceDevelopmentStrastigraphicExploratory Authorized Name and Digital Signature with Date: Authorized Title: Contact Name: Contact Email: Contact Phone: AOGCC USE ONLY Commission Representative: Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Location ClearanceMechanical Integrity TestBOP TestPlug Integrity Other: Post Initial Injection MIT Req'd? Spacing Exception Required?Yes Yes No No Subsequent Form Required: Approved By:Date: APPROVED BY THE AOGCCCOMMISSIONER PBU V-02 Hilcorp North Slope, LLC 3800 Centerpoint Dr, Suite 1400, Anchorage, AK 99503 204-077 50-029-23209-00-00 N/A ADL 0028240 15086 Conductor Surface Intermediate Production Liner 8938 80 2683 9229 6030 9221 20" 9-5/8" 7" 4-1/2" 8723 30 - 110 29 - 2712 26 - 9255 9054 - 15084 2858 30 - 110 29 - 2708 26 - 8749 8596 - 8939 None 520 3090 5410 7500 9221, 9250 1530 5750 7240 8430 6660 - 14985 4-1/2" 12.6# L-80 24 - 66486656 - 8948 Structural 4-1/2" HES TNT Packer No SSSV Installed 6585, 6581 Date: Torin Roschinger Area Operations Manager Brodie Wages David.Wages@hilcorp.com 907.564.5006 PRUDHOE BAY 5/30/23 Current Pools: Borealis Oil Proposed Pools: Borealis Oil STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 Comm. Comm.Sr Pet Eng Sr Pet Geo Sr Res Eng Form 10-403 Revised 10/2022 Approved application is valid for 12 months from the date of approval.Submit PDF to aogcc.permitting@alaska.gov 323-267 By Kayla Junke at 11:27 am, May 04, 2023 Digitally signed by Torin Roschinger (4662) DN: cn=Torin Roschinger (4662), ou=Users Date: 2023.05.04 10:40:00 -08'00' Torin Roschinger (4662) CDW 05/15/2023 MGR15MAY23 SFD 5/15/2023 10-404 DSR-5/9/23 Fracture Stimulate JLC 5/16/2023 GCW 05/16/23 5/16/2023 Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2023.05.16 11:10:00 -08'00' RBDMS JSB 051823 Frac post RWO Well: V-02 PTD: 204-077 Well Name:V-02 API Number:50-029-23209-00 Current Status:Operable Shut In producer for marginals Estimated Start Date:5/30/2023 Rig:SL/Coil Sundry #:Date Reg. Approval Rec’vd: Regulatory Contact:Abbie Barker First Call Engineer:Brodie Wages (907) 564-5006 (O)(713) 380-9836 (M) Second Call Engineer:Claire Mayfield (970) 443-3631 (M) Current Bottom Hole Pressure:3718 psi @ 8600’ TVD 8.4 PPG | (10/28/2016 static) 9.5 PPG with 2500’ freeze protect Max. Anticipated Surface Pressure:2858 psi (Based on 0.1 psi/ft. gas gradient) Last SI WHP: 275 psi (Taken on 5/1/2023) Min ID:3.813” X at 9040’ MD Max Angle:96 Deg @ 15,046’ MD 70 deg:9660’ (~Vertical to Kuparuk) High DLS@ 7107’ Formation Tops: Kuparuk: 6647’ MD/6643’MD Kingak: 7664’ MD/7581’ TVD – confining zone for Sag/Ivishak Sag: 9260’ MD/8753’ TVD Sadlerochit: 9577’ MD/8946’ TVD MITs: MIT-T: 3500 psi on 3/28/2023 MIT-IA: 3500 psi on 3/28/2023 Brief Well Summary: The Ivishak reservoir no longer remains economically viable and the Kuparuk interval for V-02 motherbore is in a perfect location to optimize lost production associated with compromised V-109. A RWO has been completed to re-complete the well from an Ivishak producer to a Kuparuk producer. The well was POP’d early in April to favorable oil cut which greenlit the frac operations described in this program. V-02: Some losses while drilling 12.25” surface hole at ~800’ that did heal up. 9-5/8” surface casing was set at 2712’ and cemented with 367 bbls of 10.7 ppg lead followed by 42 bbls of 15.8 ppg tail. Plug was bumped at calculated strokes with 100 bbls of cement circulated to surface. An 8.75” production hole was drilled with some hydrate cut mud at ~4500’. After TDing the hole section, mud continued to show signs of hydrates. After conditioning the hole for a while, 120 bbls of “G-seal” pill was pumped across Shrader interval which seemed to help with hydrate issues. 7” casing was run to 9255’ and cemented in place with 247 sx of ~12 ppg LiteCrete followed by 100 sx of 15.8 ppg classG. No losses noted while cementing, plug was bumped with 1300 psi of lift pressure and held after 2000 psi applied. The stage tool was opened at 4989’ and stage 2 was cemented with 67 sx of LiteCrete followed by 108 sx of classG. The production hole was drilled, cased and cemented with little issues. The rig perforated. Notes Regarding Wellbore Condition x 6/17/2004: Slickline install LGLVs, well POP’d at 660 bopd that quickly declined to 300 bopd in a week x 4/6/2006: GLRD x 4/18/2007: Slickline tagged hydrates, coil followed up with jet job then acid with a foamed mud acid. The acid added 600 bopd initially and hung in there at 500+ BOPD, good job. x 7/27/2009: Coil PPROF 100 bbls of cement circulated to surface. o re-complete the well from an Ivishak producer to a Kuparuk producer. Frac post RWO Well: V-02 PTD: 204-077 x 2/1/2011: Coil memory CBL showed good cement in production hole section x Since: GL work, surveillance x Surface subsidence (pad level is settling causing VSMs to lose contact with flowlines) has been noted on all of V pad, however, V-02 flowlines repaired November 2022 simply by adding gravel and adjusting the adjustable VSMs. x RWO March 2023: went smooth, issues pulling tubing associated with the packer element not relaxing Objective: x DMY valves, circ packer fluid, frac and flowback Sundry Procedure (Approval Required to Proceed) Slickline with fullbore assist 1. Dummy GLVs 2. Set plug in X-nipple in tubing tail 3. Pull St1 GLV for circ’ing in KWF 4. Load hole with 2% KCl + Freeze protect a. Total T+IA volume to St#1: 221 bbls b. Freeze protect volume to 2500’: 85 bbls 5. Dummy st#1 6. MIT-T to 3500 psi 7. Obtain 3500 psi MIT-IA a. Hold 2000 psi on the tubing during MIT-IA 8. Pull plug in X nipple Frac/Special Projects 1. Spot water tanks and fill with fresh water a. Heat water to 110 degF b. Minimum pumping temp for water: 90 degF 2. Pull water from each tank and have SLB lab test our water quality: a. pH - ~7 i. Higher pH delays the hydration of the gel and delays break b. Calcium/magnesium <500 mg/l i. Mg/Ca Negative side effects in the formation such as carbonate deposits, which tend to be insoluble c. Bicarbonate - <400 mg/l i. High bicarbonate levels will cause slow hydration times and elevated delay times with X-linking fluids. If we have elevated bicarbonate levels and have introduced delay agents, it could have an exponential effect in delay times. d. Chlorides-<10,000 mg/l i. This fluid system should be able to cope with elevated Chloride levels e. Iron (Fe+3) - <5 mg/l i. Elevated Iron concentrations exist, the ammonium persulfate (breaker) can have an accelerated effect. Can cause viscosity degradation in linear gels (especially if batch mixed). Also can interfere with X-linking b/c iron will tie up the X-linking sites. f. TDS – minimal/<5000 Coil memory CBL showed good cement in production hole section Frac post RWO Well: V-02 PTD: 204-077 i. Effects depend on the solids that are dissolved in the fluid. 3. Frac per pump schedule Maximum Anticipated Treating Pressure: 3160 psi Maximum Allowable Treating Pressure: 4500 psi w/ 3025 psi on IA Stagger Pump Kickouts Between: 4000 psi and 4275 psi (95% to 90% of MATP) Global Kickout: 4275 psi (95% of MATP) IA Pop-off Set Pressure: 3325 psi (~95% of MIT-IA) IA Minimum Hold Pressure: 3025 psi Treating Line Test Pressure: 5500 psi OA Pressure: Monitor and maintain open to atmosphere Max Anticipated Proppant Loading: 12 PPA N2 POP-off set pressure 6000 psi x If treating pressure starts acting sporadic, consider dropping rate to as low as 12 ppa. If it is acting up at 12 ppa, we should be on flush. Coil Tubing 1. MIRU and pressure test 2. MU JSN or down jet 3. FCO to 6770’ a. ~50’ below bottom perf b. We may go on losses during FCO, it may be necessary to have slickline install LGLVs prior to coil FCO 4. POH Slickline This step may need to be performed prior to coil FCO if stable returns cannot be established 1. Drift, install catcher 2. Install LGLVs 3. Pull catcher 4. RDMO Testers: 1. MIRU, pressure test 2. POP the well to ASRC with 1-1.5 MMSCFD Lift gas at minimum choke, adjust GL rate as necessary to eliminate slugging. Flow the initial returns to the flowline as long as the shake-outs meet the returned fluid/solids management guidelines. 3. Limit flow to 500 bpd 4. If solids are < 1%, after 1.5 wellbore volumes (120 bbls) increase the production rate to 750 BLPD. 5. Flow bottoms up and sample for solids production. If solids are still below 1%, increase flow to 1000 BFPD. 6. Flow bottoms up and sample for solids production. If solids are still below 1% continue to increase the flow rate in 250 BPD increments. The objective is to achieve maximum drawdown. Watch returns and do not continue to open choke if solids > 1%; allow well clean up before choke is opened further. 7. Once at FOC, stabilize the well for 4 hrs. Obtain an 8 hr welltest. Prior to fracturing, pressure test IA pop off (3325 psi), treating lines (5500 psi min), pump trips 4000 psi & 4275 psi. - mgr Frac post RWO Well: V-02 PTD: 204-077 Current WBD: Date: May 4, 2023 Subject: V-02 Fracture Stimulation From: David Wages O: (907) 564-5006 C: (713) 380-9836 To: AOGCC Estimated Start Date: 5/30/2023 Attached is Hilcorp’s proposal and supporting documents to perform a 1 stage fracture stimulation on well V-02 in the Kuparuk reservoir of the Prudhoe Bay Unit. A recent workover, V-02 has been recompleted to the Kuparuk formation after P&A’ing the Ivishak formation. Following the workover, live gas lift valves were installed and the well was POP’d to favorable oil/water cut% which greenlights the fracture stimulation described below. Hilcorp requests a variance to sections 20 AAC 25. 283, a, 3- 4 which require identification of fresh - water aquifers and a plan for base-water sampling. Please direct questions or comments to David Wages. 1 stage fracture stimulation o SECTION 1 - AFFIDAVIT (20 AAC 25. 283, a, 1): Below is an affidavit stating that the owners, landowners, surface owners and operators identified on a plat within one-half mile radius of the current or proposed wellbore trajectory have been provided notice of operations in compliance with 20 AAC 25.283, a 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): Susp Well Insp Install Whipstock Mod Artificial Lift Perforate New Pool Perforate Plug Perforations Coiled Tubing Ops 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 V-02 Recomplete to Borealis Hilcorp North Slope, LLC 3800 Centerpoint Dr, Suite 1400, Anchorage, AK 99503 204-077 50-029-23209-00-00 15086 Conductor Surface Intermediate Production Liner 8938 80 2683 9229 6030 9221 20" 9-5/8" 7" 4-1/2" 8723 30 - 110 29 - 2712 26 - 9255 9054 - 15084 30 - 110 29 - 2708 26 - 8749 8596 - 8939 None 520 3090 5410 7500 9221, 9250 1530 5750 7240 8430 6660 - 14985 4-1/2" 12.6# L-80 24 - 6648 6656 - 8948 Structural 4-1/2" HES TNT Packer 6585, 6581 6585 6581 Torin Roschinger Area Operations Manager Brodie Wages David.Wages@hilcorp.com 907.564.5006 PRUDHOE BAY, Prudhoe Oil / Borealis 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 pressure: 13a.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 0028240 24 - 6644 9221 - 9249 in 4-1/2" Liner Dump 22-gals of 17-ppg Cement. 96 26 265 255 812 192 1460 1056 347 332 323-031 13b. Pools active after work:Borealis Oil No SSSV Installed STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS Sr Pet Eng: Sr Pet Geo: Form 10-404 Revised 10/2022 Submit in PDF format to aogcc.permitting@alaska.gov Sr Res Eng: Due Within 30 days of Operations By Kayla Junke at 3:13 pm, Apr 25, 2023 Digitally signed by Torin Roschinger (4662) DN: cn=Torin Roschinger (4662), ou=Users Date: 2023.04.25 14:42:41 -08'00' Torin Roschinger (4662) RBDMS JSB 050223 PBU V-02 204-077 WCB 12-29-2023 DSR-4/26/23 ACTIVITY DATE SUMMARY 1/2/2023 T/I/O=SHUT IN/1650/700 -Surface hanger is ~18-1/2" above landing ring. -Tubing hanger void=700 psi, bled off quickly, function all LDS 1 at a time to 4-5/8" out, re-torque to 500 ft/lbs, test void 5k/30 min., lost 100 psi first 15 min., lost 0 psi second 15 min., bleed off. -ICPO=700 psi, bled off quickly, test 3500 psi/30 min, 0 psi loss in 30 min. bleed off. -SBMS=900 psi, bled off quickly, shut in ~5 min., 0 psi., RDMO 2/15/2023 ***WELL S/I ON ARRIVAL*** R/U POLLARD #58 WEATHER STBY ***WSR CONT ON 2-16-23*** 2/15/2023 Assist Slickline w/ Brush and Flush (RWO CAPITAL) SU/PJSM / SB for SL ***Job Cont to 02-16-2023 WSR*** 2/16/2023 ***WSR CONT FROM 2-15-23*** B&F w/ KJ, 3-1/2" BLB, 2.74" G-RING FROM SURFACE DOWN TO 9,400' SLM (LRS PUMPED TOTAL 100BBLS HOT CRUDE @ 1BPM) DRIFTED FOR CALIPER w/ KJ, 1.90" CENT, 13' x 1.75" BAILER, DRIFTED FREELY TO 9,400' SLM LOG W/ 1.90" CENT, 24 ARM READ CALIPER @50'/MIN @10:11 FROM 9056' SLM (9,064' MD) SET 2.75" PXN PLUG BODY @ 9,036' SLM (9,040' MD) (=23" oal, 2.79" no-go, x4 3/16" eq ports). ***CONTINUE ON 2/17/2023 *** 2/16/2023 ***Job Cont from 02-15-2023 WSR*** B&F w/ SL (RWO CAPITAL) Pumped 2 bbls 60/40 meth and 100 bbls 180* crude down Tbg while SL brushed. SL in control of well per LRS departure. IA,OA=OTG 2/17/2023 *** CONTINUED FROM 2/16/2023 *** SET EQ PRONG (96" lih) IN PXN PLUG BODY @ 9,038' SLM (9,040' MD) SET WHITTON CATCHER (63" OAL, 2.78" OD WCS33) @ 9,029' SLM PULL STA #1 RK-DGLV @8,893' MD PULLED STA #2 RK-SO @6,986' MD PULLED RK-LGLV'S FROM STA #3, 4, 5, 6, 7 SET RK-DGLV'S IN STA #7, 6, 5, 4, 3 *** CONTINUE ON 2/18/2023 *** 2/18/2023 *** CONTINUE FROM 2/17/2023 *** SET RK-DGLV IN ST # 2 T-BIRD PUMP CIRC OUT, 290 BBLS 2% KCL, 88 BBLS DIESEL, U-TUBE SET RK-DGLV IN STA #1 T-BIRD PERFORM MIT-T TO 3700 PSI ( FAILED) PERFORM COMBO MIT-IA TO 3000 PSI (PASSED) RUN 3 -1/2" D & D HOLE FINDER, TEST BELOW & ABOVE STA # 1 & STA # 2, TEST ABOVE STA # 2 IS GOOD. SET WHIDDON CATCHER @ 9,030' SLM (63" OAL, 2.78" OD, WCS33) *** CONTINUE ON 2/19/2023 *** Daily Report of Well Operations PBU V-02 Daily Report of Well Operations PBU V-02 2/18/2023 T/I/O= 1120/1400/250 Temp=S/I (TFS unit 4 Conduct Circ-out and MIT-T/MIT-IA) Pumped 3 bbls 60/40 followed by 290 bbls of 2% KCL down TBG taking returns up IA to adjacent FL. Further pumped 2 bbls 60/40 followed by 88 bbls DSL down TBG. Pumped 2 bbl 60/40 tail. Freeze Protected surface lines with 2 bbls 60/40. U-Tubed TxIA for 3 hours through 1/2 inch bleed hose. CMIT-TxIA ***PASSED*** to 2916/2923 psi Max applied psi of 3000 psi. 1st 15 min TxIA lost 52/43 psi. 2nd 15 min TxIA lost 19/20 psi. SL Ran D and D Hole Finder pressured TBG and Bleed off. ******Job Continued on 02/19/2023******* 2/19/2023 ***Job Continued from 02/18/2023**** MIT-IA ***PASSED*** to 3667 psi. pumped 2.5 bbl DSL to reach max applied psi of 3750. with a target of 3500 psi, 1st 15 min TBG lost 60 psi. 2nd 15 min TBG lost 13 psi. Total loss of 73 psi in 30 min. Bled back 3 bbl DSL. MIT-T ***PASSED*** To 3561 psi. pumped 1 bbl DSL too Achieve Max applied psi of 3750. With a target psi of 3500. 1st 15 min TBG lost 142 psi. 2nd 15 min TBG lost 51 psi. Total loss of 193 psi in 30 min. Bled back 1 bbl DSL. Tags hung on MV & IAC, SL in control of well upon departure. FWHP= 300/311/470 2/19/2023 *** CONTINUE FROM 2/18/2023 *** PULLED RK-DGLV FROM STA #2 @ 6,986' MD, VALVE MISSING TOP PKG STACK RAN 1.5" POCKET BRUSH TO STA # 2 @ 6,986' MD, GOOD NO-GO MARKS SET RK-DGLV IN STA #2 @ 6,986' MD. MIT-IA TO 3667 PSI FOR 30 MIN (pass) PULLED WCS FROM 9,023' SLM (empty) SET X-SELECTIVE TEST TOOL IN X-NIP @ 9,016' MD MIT-TBG TO 3561 PSI FOR 30 MIN (pass) PULLED X-SELECTIVE TEST TOOL FROM X-NIP @ 9,016' MD PULLED 2.75" PXN PLUG FROM 9,036' SLM (9,040' MD) *** CONTINUE ON 2/20/2023 *** 2/20/2023 *** CONTINUE FROM 2/19/2023 *** DRIFT W/ 23' x 2.29" DUMMY GUNS FOR IBP (9,260' MD TARGET DEPTH) , DRIFT DOWN TO 9,560' SLM W/ NO ISSUES JOB COMPLETE, HAND WELL BACK OVER TO DSO *** WELL S/I ON DEPARTURE *** 2/23/2023 ***WELL S/I ON ARRIVAL*** PRESSURE TEST PCE TO 200#LP-3,000#HP RIH W/ 1-7/16" CHD (1" FN), 2-1/8" BKR IBP (29' OAL) CORRELATE TO SLB MEMORY CBL DATED 31-JANUARY-2011 ME SET DEPTH=9,260', CCL OFFSET=24.4', CCL STOP DEPTH=9,235.6' ***WELL LEFT S/I*** 2/24/2023 ***WELL S/I ON ARRIVAL*** PRESSURE TEST PCE TO 200#LP-3,000#HP RIH W/ 1-7/16" CHD (1" FN), 2" WEIGHT BAR, 1-11/16" WEIGHT BAR, 2-1/8" CCL, 2-1/2" DUMP BAILER (46' OAL) DRIFT TO PLUG @ 9,260' DUMP 43# OF RIVER SAND ON TOP OF IBP @ 9,260' ***WELL LEFT S/I*** JOB CONTINUED 2/25/2023 RIH W/ 1-7/16" CHD (1" FN), 2-1/8" BKR IBP (29' OAL)() ( ) CORRELATE TO SLB MEMORY CBL DATED 31-JANUARY-2011 ME SET DEPTH=9,260', ( DRIFT TO PLUG @ 9,260'@ DUMP 43# OF RIVER SAND ON TOP OF IBP @ 9,260' Daily Report of Well Operations PBU V-02 2/25/2023 JOB CONTINUED FROM 2/24/2023 ***WELL S/I ON ARRIVAL*** PRESSURE TEST PCE TO 200#LP-3,000#HP RIH W/ 1-7/16" CHD (1" FN), 2" WEIGHT BAR, 1-11/16" WEIGHT BAR, 2-1/8" CCL, 2-1/2" DUMP BAILER (46' OAL) DUMP 42# OF RIVER SAND @ 9,240' (85# OF RIVER SAND TOTAL ON IBP @ 9,260') DUMP 16 GAL OF 17 PPG CEMENT ON TOP OF SAND (TOC=9,206') PLANNED TO PLACE 10 FT. OF SAND AND 25 FT OF CEMENT ON TOP OF IBP @ 9260 FT. 9206 FT. IS ELM ***WELL LEFT S/I*** 2/28/2023 ***WELL S/I ON ARRIVAL*** RAN 2.80'' G-RING & S/D IN X-NIP @ 8973'SLM/8982'MD (+9' correction) RAN 2-1/2'' SAMPLE BAILER 2 TIMES, S/D @ 9227'SLM/9236'MD (full of sand both times) TAGGED XN-NIP W/ 2.76'' CENT @ 9031'SLM/9040'MD (+9' correction) *** WELL LEFT S/I ON DEPARTURE*** 2/28/2023 T/I/O= 105/1605/417. LRS 72 Assist Slickline with AOGCC MIT-T postponed pending cement eval. Final T/I/O= 150/1580/417. 3/2/2023 ***WELL S/I ON ARRIVAL*** JOB SCOPE: DUMP BAIL CEMENT (Pre RWO) PT PCE 250LP-3000HP RAN GUN GAMMA RAY & 2.5" X 30' EMPTY DUMP BAILER. TAG HIGH AT 8476'. WORK BAILER DOWN TO 8531'. UNABLE TO PASS. 50#-100# OVERPULLS TO GET FREE. RECOVERED 1 CUP OF CEMENT IN BAILER. ***WELL S/I ON DEPARTURE, TURN OVER TO SLICKLINE*** 3/3/2023 ***WELL S/I UPON ARRIVAL*** (pre rwo) BRUSHED TBG W/ 3-1/2" BRUSH & 2.70" GAUGE RING, HARD TAG @ 9,226' SLM.(s/d in multiple spots) DRIFTED W/ 22' x 2-7/8" DUMMY GUNS(2.66" rings) & 2.50" SAMPLE BAILER, TAGGED CEMENT @ 9,227' SLM/ 9,224' MD.(recovered sample, s/d @ 8,806' slm) RAN 2.80" GAUGE RING, TAGGED XN-NIPPLE @ 9,040' MD. ***WELL S/I ON DEPARTURE, PAD-OP NOTIFIED OF WELL STATUS*** 3/11/2023 ***WELL S/I ON ARRIVAL*** PT PCE 250LP-3000HP RAN 2.50" X 30' DUMP BAILER WITH 5 GALLONS OF 17 PPG CEMENT. SAT DOWN AT 8695' MD, NOTIFY WELLS GROUP. INCREASE LSPD TO 200 FPM AND SAT DOWN AT 8961' MD ATTEMPTED TO PASS 8961' MD THREE TIMES. NO LUCK, RECOVERED ALL CEMENT FROM BAILER. ***CONTINUED ON 3-12-2023*** 3/12/2023 LRS CTU #2, 1.5" Blue Coil, Job Objective: FCO and mill 5' of cement MIRU & MU 2-1/8" BOT milling BHA with 2.70" PDC mill. RIH and drift cleanly to tag TOC at ~ 9229' CTM / 9225' MD. Paint white flag at 9208' CTM. Start POOH to pick up the underreamer. ***Job in Progress*** g TOC at ~ 9229' CTM / 9225' MD. Paint white flag at 9208' CTM ( TAGGED CEMENT @ 9,227' SLM/ 9,224' MD.( RIH W/ 1-7/16" CHD (1" FN), 2" WEIGHT BAR, 1-11/16" WEIGHT BAR, 2-1/8" CCL, () 2-1/2" DUMP BAILER (46' OAL)() DUMP 42# OF RIVER SAND @ 9,240' (85# OF RIVER SAND TOTAL ON IBP @ 9,260')) DUMP 16 GAL OF 17 PPG CEMENT ON TOP OF SAND (TOC=9,206') LRS CTU #2, 1.5" Blue Coil, Job Objective: FCO and mill 5' of cementb Daily Report of Well Operations PBU V-02 3/12/2023 ***CONTINUED FROM 3/11/2023 WSR*** PT PCE 250LP-3000HP DRIFTED TO 9160' MD AT 150 FPM WITH 2" X 30' DUMP BAILER. NO ISSUES FROM 8695' MD - 8961' MD. TIE INTO XN NIPPLE AT 9040' MD AND WORKED BAILER AGGRESSIVELY DOWN TO 9168' MD, #100 OVERPULL TO GET FREE. UNABLE TO GET ANY DEEPER. NO METAL MARKS OR SAMPLE INSIDE DUMP BAILER. ***WELL LEFT S/I, PAD OP NOTIFIED*** 3/13/2023 LRS CTU #2 1.5" Blue Coil. Job Objective: FCO and mill 5' of cement POOH & MU 2.63" DB underreamer with 4-1/2" 12.6# blades & 2.70" PDC mill. Underream from 9090' to 9035' (no motor work seen). PU and dry tag at 9035'. Underream to 9040' with no motor work (milling sand). Pump two 5 bbl gel pills and 1/2" circ sub ball. POOH & freeze protect the well to 2500' TVD. RDMO. ***Job complete*** 3/13/2023 ***WELL S/I ON ARRIVAL*** DRIFT W/ 2.50" CENT, 30' X 2.50" BAILER S/D @ 9,229' SLM (STICKY BOTTOM, NO RECOVERY) RUN KJ, 3 1/2" BLB, 2.80" GAUGE RING, TAG XN @ 9,031' SLM (-9' CORRECTION) RUN 2.50" CENT. 1 3/4" SAMPLE BAILER, TAG @ 9,232' SLM (9,241' MD, RECOVERED 1 CUP SAND) RIH 30' X 2.50" BAILER (8' X 1 7/8" STEM INSIDE FOR WEIGHT) ***CONTINUE 3/14/23*** 3/14/2023 ***CONTINUED FROM 3/13/23*** DRIFT W/ 30' X 2.50" BAILER MSBB (8' X 1 7/8" STEM INSIDE) S/D @ 9,233' SLM ***WELL LEFT S/I*** 3/14/2023 ***WELL S/I ON ARRIVAL***(pre rwo) RAN 2.50" X 20' EMPTY BAILER AND TAGGED BOTTOM AT 9249.6' MD. DUMPED 5 GALLONS OF RIVER SAND/100 MESH SAND AT 9249' MD. DUMPED 16.7' OF NEO CEMENT ON TOP OF SAND/100 MESH SAND. TOP OF SAND AT 9246' MD & ESTIMATED TOC CURRENTLY AT 9229.3' MD. ***CONTINUED ON 3/14/2023*** 3/15/2023 (CONTINUED FROM 3/14/2023) ***WELL S/I ON ARRIVAL*** PRESSURE TEST PCE TO 200#LP-3,000#HP RIH W/ 1-7/16" CHD (1" FN), 2" WEIGHT, 2-1/8" CCL, 20' X 2-1/2" DUMP BAILER (LOADED W/ 17PPG NEO CEMENT) DUMP 8.3' OF 17PPG NEO CEMENT, ESTIMATED TOC=9,221' MD TREECAP INTALLED & PRESSURE TESTED ***WELL LEFT S/I*** 3/19/2023 ***WELL S/I ON ARRIVAL*** PERFORMED AOGCC CEMENT TAG W/ 2 1/2" SAMPLE BAILER TO 9,221' SLM (sample of good cement) LRS PERFORMED PASSING MIT-T TO 2,500 PSI ***WELL LEFT S/I ON DEPARTURE, PAD OP NOTIFIED OF STATUS*** 3/19/2023 T/I/O= 80/225/282. LRS 72 Assist S/L (RWO CAPITAL) AOGCC (Sully) MIT-T to 2500 psi (2750 psi max applied pressure) PASSED at 2503 psi. TBG lost 159 psi during the first 15 minutes and 86 psi during the second 15 minutes. TBG lost 245 psi during the 30 minute test. Pumped 1.4 bbls of 87*F diesel to achieve test pressure. Bled back 1.3 bbls to Final T/I/O= 133/227/277. PERFORMED AOGCC CEMENT TAG W / 2 1/2" SAMPLE BAILER TO 9,221' SLM (sample of good cement)(g ) LRS PERFORMED PASSING MIT-T TO 2,500 PSI Required in Sundry 323-031. -WCB Daily Report of Well Operations PBU V-02 3/20/2023 *** WELL SI ON ARRIVAL *** INITIAL T/I/O = 0/250/300 MIRU YELLOWJACKET ELINE AND WELLTEC TO CUT PKR. CUT DEPTH 8997.3', CCL OFFSET = 18.0', CCL STOP = 8979.3', CORRELATE TO TUBING TALLY AND APPROVE CORRELATION W/ TOWN. AT SURFACE, DISCOVERED CUTTING TOOL FAILURE AT SURFACE. REGROUP AND MAKE SECOND ATTEMPT TOMORROW. FINAL T/I/O = 0/250/300 *** JOB IN PROGRESS *** 3/21/2023 T/I/O = VAC/330/290. Temp = SI. Bleed WHPs to 0 psi (pre RWO). No AL. FL and AL disconnected, wellhouse removed. IA FL @ surface. Bled IAP to BT to 0 psi in 5 min (fluid, 0.25 bbls). OA FL @ 200'. Bled OAP to BT to 0 psi in 30 min (gas). Monitored for 30 min. WHPs and FLs unchanged. Final WHPs = VAC/0/0 SV, WV, SSV = C. MV = O. IA, OA = OTG. 01:00. 3/21/2023 *** CONTINUED FROM 03/20/2023 *** T/I/O = 0/0/0, VERIFIED VALVE POSITIONS, YESTERDAY HAD PRESSURE ON DEPARTURE. DHD BLED OFF WELL OVERNIGHT. TOOL FAILURE PREVIOUS DAY, CUT NOT COMPLETED. MAKING ANOTHER CUT. CCL OFFSET = 18.0 FT. STOP AT 8979.8 FT, O.5 FT BELOW PREVIOUS ATTEMPT. PERVIOUS ATTEMPT WAS VISIBLE ON COLLAR LOG. WELLTEC REPORTS 3.64" CUT OD. FINAL T/I/O = 0/0/0. WELL SI ON DEPARTURE, DSO NOTIFIED. *** JOB COMPLETE *** 3/22/2023 T/I./O=0/0/20 Set CTS BPV. RD production upper tree. RU dry hole tree Torque to API specs. PT 300 psi low & 5000 psi high (PASSED). Final WHP's=0/0/20. 3/23/2023 Nordic 3 Job Scope: Pull tubing, CBL, Recomplete from Ivishak to Kuparuk. Complete rig down operations on H-pad. Rig move from H-pad to V-pad. 3/24/2023 Remove THA & dry hole tree, clean void, hanger ID, & ring groove, install CTS plug, make up 4-1/2" TC-II test sub to hanger, test 500 psi/5 min., 3000 psi/15 min., 0 psi loss on both tests, bleed off test psi., rig down test equip., function all upper lock down screws one at a time to full out measurement 4-5/8", run in tag hanger, tighten gland nuts, torque lock down screw to 500 ft/lbs, all functioned well, install new RX-54 in tubing head top ring groove, S/B for BOP N/U & test. 3/24/2023 Nordic 3 Job Scope: Pull tubing, CBL, Recomplete from Ivishak to Kuparuk Continue to spot rig over V-02, set remaining mats, shut down and removed ODS lower stairs due to well house clearance. Move rig over V-02, set down rig to check level and shim rig. Hard line crew rigging up 2" hard line from open top tank to rig. Rig up steam and water. Spot cuttings box and install cuttings shoot. N/D dry hole tree. Vault rep verified pulling threads. Set & test CTS 500 psi / 3000 psi, NU BOPE, reconfigure choke/kill lines to accomodate taller WH. Fill stack with water and shell test BOPE. Test BOPE to 250/3000 psi per Sundry. AOGCC waived witness 3/23/23 (Austin McLeod). Currently testing BOPE with 1 FP on the annular due to leaking o- ring on test hose and block valve on choke manifold. Swapped out both retested- good test. g( ) Nordic 3 Job Scope: Pull tubing, CBL,Recomplete from Ivishak to Kuparuk MIRU YELLOW JACKET ELINE AND WELLTEC TO CUT PKR Daily Report of Well Operations PBU V-02 3/25/2023 Nordic 3 Job Scope: Pull Tubing, CBL, Recomplete from Ivishak to Kuparuk Cont. testing BOPE as per sundry requirements. Failure on manual choke, change out and complete BOPE test. Pulled CTS / BPV. M/U landing joint to hanger. BOLDS. Worked top drive incrementally up to 160k and completion string popped free. Pull hanger to floor and L/D. Attempt to circulate down the tubing with no success. Pulled 250' working pipe multiple times attempting to establish circulation both down the tubing and reverse with no succes. 3/26/2023 Nordic 3 Job Scope: Pull Tubing, CBL, Recomplete from Ivishak to Kuparuk Pull & L/D 22 joints of 3-1/2" 9.2# IBT-M completion, unable to establish circulation forward/reverse. Work packer element up/down for one hour, no circulation. Discuss plan forward w/Wells Foreman. M/U tubing hanger, and land 3-1/2" IBT-M completion. PUW 112k, SOW 102k. RU YellowJacket Eline w/P-sub and pack off. RIH w/CCL & 1-9/16" tubing punch (4 spf, 0 deg phasing), make tie in pass and shoot tubing punch in center of 9.77' pup joint above Baker Premier Packer. Pooh and confirm shots fired. Reverse circulate 1 bpm @ 40 psi, 1:1 returns. RIH w/2nd tubing punch, tie in, and shoot tubing punch in center of 9.85' pup joint below Baker packer. Reverse circulate 28 bbl depp clean pill followed by STS volume 333 bbls with 8.4 all around. Monitored well- static. R/D dutch riser. R/U and pulled hanger to floor- Unseat at 112K. L/D hanger and XO pup. 3/26/2023 Temporarily land tubing hanger in order for wire line to RIH to cut. Made hanger up to string, land, run iin lock down screws tag hanger, tighten gland nuts, torque lock down screws to 500 ft/ lbs, RDMO 3/27/2023 Nordic 3 Job Scope: Pull Tubing, CBL, Recomple from Ivishak to Kuparuk Pulled & L/D 3 1/2" 9.2# IBT-M completion. Recovered all 3-1/2" IBT-M completion. Test 7" casing to 500 psi for 15 min, good. MIRU YJ Eline. Logged CBL from 9054' to surface. Sent off and approved by AOGCC (23:00). Continue loading/strapping 4 1/2" Vamtop tubing in pipe shed. RU GBR TTS. 3/27/2023 Nordic 3 Job Scope: Pull Tubing, CBL, Recomple from Ivishak to Kuparuk Cont. pulling and L/D 3 1/2" 9# IBT-M tubing. 3/28/2023 Nordic 3 Job Scope: Pull Tubing, CBL, Recomplete from Ivishak to Kuparuk Continue R/U GBR torque turn. Load completion assemblies in pipe shed and verify running order. PJSM, RIH w/ 4 1/2" 12.6#, L-80 Vamtop completion as per approved tally. P/U Tubing Hanger, PUW 113k, SOW 111k, Bk Wt = 36k. Land hanger. RILDS. Blow down stack. Reverse circulate 40 bbls of corrosion inhibitor followed by 85 bbls of 2% KCI. Dropped Ball & Rod (1-3/8" FN). Set HES TNT packer, good indication of set @ 2000 psi. MIT-T to 3500 psi, test passed. Bled tubing to 2000 psi. MIT-IA to 3500 psi, test passed. Bleed tubing pressure and shear DCK valve, bleed T x IA to zero. Set BPV / CTS. ......Continued on 3/29/23 WSR 3/29/2023 Nordic 3 Job Scope: Pull Tubing, CBL, Recomplete from Ivishak to Kuparuk N/D BOP stack and rack back. N/U wellhead. Test hanger void & tree to 5000 psi. Pulled CTS/BPV. LRS freeze protected IA x Tbg w/95 bbls of diesel. RDMO Nordic 3. Nordic 3 rig move to MPU I-27. ......RWO program completed. 3/29/2023 Make up tubing hanger to string, land in well head, run in lock down screws tag hanger, tighten gland nuts, torque lock down screws to 500 ft/lbs, clean void & BPV profile, install CTS plug, land THA, remove dry hole tree from it, M/U full tree, test void 500 psi/5 min., 5,000 psi/15 min., 0 psi loss on both tests, bleed off test psi, rig down stand by for tree test & CTS BPV removal. g Pulled & L/D 3 1/2" 9.2# IBT-M completion. Recovered all 3-1/2" IBT-M completion Logged CBL from 9054' to gg surface. Sent off and approved by AOGCC (23:00). g Make up tubing hanger to string, land in well head, run in lock down screws tag gg g hanger, tighten gland nuts, torque lock down screws to g P/U Tubing Hanger, PUW 113k, SOW 111k, Bk Wt = 36k. Land hanger. RILDS.ygg g Blow down stack. Reverse circulate 40 bbls of corrosion inhibitor followed by 85 bblsy of 2% KCI. Dropped Ball & Rod (1-3/8" FN). Set HES TNT packer, good indication of()g set @ 2000 psi. MIT-T to 3500 psi, test passed. Bled tubing to 2000 psi. MIT-IA to@ 3500 psi, test passed M/U tubing hanger, and land 3-1/2" IBT-M completion g Pull & L/D 22 joints of 3-1/2" 9.2# IBT-M completion make tie in pass and shoot g(gg) tubing punch in center of 9.77' pup joint above Baker Premier Packer. Pooh andfgj confirm shots fired. Reverse circulate 1 bpm @ 40 psi, 1:1 returns. RIH w/2nd tubing@g punch, tie in, and shoot tubing punch in center of 9.85'pup joint below Baker packer. Daily Report of Well Operations PBU V-02 3/31/2023 ***WELL S/I ON ARRIVAL**(post rig) PULL BALL & ROD @ 6,619' MD PULL BK-DGLV STA. # 1 6523' MD PULL BK-DGLV STA. # 2 @ 5,997' MD ***CONTINUE 4/1/23*** 4/1/2023 ***CONTINUE FROM 3/31/23*** PULL STA.# 3 BK-DGLV @ 5,379' MD PULL STA.# 4 BK-DGLV @ 4,488' MD PULL STA.# 5 BK-DCK ) @ 3,010' MD SET BK-LGLV'S IN ST#5 (3,010' MD), ST#4 (4,488' MD), ST#3 (5,379' MD) & ST#2 (5,997' MD) SET BK-OGLV IN ST#1 (6,523' MD) PULLED RHC FROM X-NIPPLE @ 6,619' MD DRIFTED w/ 30' x 2-7/8" DUMMY GUNS (max od = 3.16") TO 7,000' SLM ***WELL S/I ON DEPARTURE*** 4/1/2023 LRS Well Test Unit 1. Begin WSR. IL V-02, OL V-234. Standby, Continue to 4/2/23 WSR 4/2/2023 ***WELL S/I ON ARRIVAL, DSO NOTIFIED***(perf) PT 300L/3000H. PERFORATE 6660'-6720' USING 3.125", 6 SPF, 60 DEG PHASED HSC LOADED W/ 21 GR GEO CHARGES. ...JOB CONT ON 3-APR-2023... 4/2/2023 LRS Well Test Unit 1. Continued from 4/1/23 WSR. IL V-02, OL V-234. Standby, Continue to 4/2/23 WSR 4/3/2023 LRS Well Test Unit # 1. Continued from 4/2/23 WSR. IL V-02, OL V-234. Standby, Unit move, Begin RU, Continue to 4/4/23 WSR 4/3/2023 ...CONT FROM 2-APR-2023... RDMO ELINE. ***JOB COMPLETE, WELL SECURE AND TURNED OVER TO DSO*** 4/4/2023 LRS Well Test Unit #1. Continued from 4/3/23 WSR. IL V-02, OL V-234, Continue RU, POP V-02 , Flow back, Continue to 4/5/23 WSR 4/5/2023 T/I/O = 390/950/70. Temp = SI. IA FL (Testers req). ALP = 1050 psi, online. Testers RU on well. IA FL @ 6523' (sta #1 SO). WV = C. SV, SSV, MV = O. IA, OA = OTG. 21:30. 4/5/2023 LRS Well Test Unit #1. Continued from 4/4/23 WSR. IL V-02, OL V-234, Continue Flowback, Monitor for solids, Continue to 4/6/23 WSR 4/6/2023 LRS Well Test Unit #1. Continued from 4/5/23 WSR. IL V-02, OL V-234, Continue Flowback, Monitor for solids, Continue to 4/7/23 WSR 4/7/2023 LRS Well Test Unit # 1. Continued From 4/6/23 WSR. IL V-02. OL V-234. Continue Flowback. Monitor for solids. Continue to 4/8/23 WSR 4/8/2023 LRS Well Test Unit # 1. Continued From 4/7/23 WSR. IL V-02. OL V-234. Continue Flowback. Monitor for solids. RD, Begin Unit move, End WSR PERFORATE 6660'-6720' USING 3.125", 6 SPF, 60 DEG PHASED HSC LOADED W / 21 GR GEO CHARGES ( PULL BALL & ROD @ 6,619' MD SIGNED AFFIDAVIT: COPY OF NOTIFICATION SENT VIA EMAIL: SECTION 2: PLAT IDENTIFYING ALL WELLS WITHIN ½ MILE (20 AAC 25. 283, a, 2): List of wells in Plat 20 AAC 25.283, a, 2 Sw Name Well Class Desc Well Status Desc Sw Name Well Class Desc Well Status Desc V-01 Development Oil Producer Shut-In V-203 Development Oil Producer Gas Lift V-02 Development Oil Producer Gas Lift V-203L1 Development Oil Well V-03 Development Oil Producer Shut-In V-203L2 Development Oil Well V-04 Development Oil Producer Gas Lift V-203L3 Development Oil Well V-05 Service Water Injector Injecting V-203L4 Development Oil Well V-07 Development Oil Producer Shut-In V-204 Development Oil Producer Gas Lift V-08 Development Oil Producer Gas Lift V-204L1 Development Oil Well V-08PB1 Development Plugged Back For Redrill V-204L1PB1 Development Plugged Back For Redrill V-100 Service Water Injector Injecting V-204L2 Development Oil Well V-101 Development Oil Producer Gas Lift V-204L2PB1 Development Plugged Back For Redrill V-102 Development Oil Producer Gas Lift V-204L3 Development Oil Well V-103 Development Oil Producer Shut-In V-204PB1 Development Plugged Back For Redrill V-104 Service Water Injector Injecting V-204PB2 Development Plugged Back For Redrill V-105 Service Miscible Injector Operating V-205 Development Oil Producer Shut-In V-105L1 Development Miscible Injector Operating V-205L1 Development Oil Well V-106 Development Abandoned V-205L2 Development Oil Well V-106A Development Oil Producer Gas Lift V-207 Development Oil Producer Gas Lift V-106APB1 Development Plugged Back For Redrill V-207L1 Development Oil Well V-106APB2 Development Plugged Back For Redrill V-207L2 Development Oil Well V-106APB3 Development Plugged Back For Redrill V-207L3 Development Oil Well V-107 Development Oil Producer Shut-In V-207L4 Development Oil Well V-108 Development Oil Producer Shut-In V-207L4PB1 Development Plugged Back For Redrill V-109 Development Oil Producer Shut-In V-207L4PB2 Development Plugged Back For Redrill V-109PB1 Development Plugged Back For Redrill V-207PB1 Development Plugged Back For Redrill V-109PB2 Development Plugged Back For Redrill V-210 Service Miscible Injector Operating V-111 Development Oil Producer Gas Lift V-211 Service Water Injector Shut-In V-111PB1 Development Plugged Back For Redrill V-212 Service Miscible Injector Operating V-111PB2 Development Plugged Back For Redrill V-213 Service Abandoned V-111PB3 Development Plugged Back For Redrill V-213A Service Miscible Injector Operating V-112 Service Water Injector Injecting V-213PB1 Service Plugged Back For Redrill V-113 Development Oil Producer Shut-In V-214 Service Water Injector Injecting V-114 Development Abandoned V-214PB1 Service Plugged Back For Redrill V-114A Service Water Injector Injecting V-214PB2 Service Plugged Back For Redrill V-115 Development Oil Producer Shut-In V-214PB3 Service Plugged Back For Redrill V-115L1 Development Oil Well V-214PB4 Service Plugged Back For Redrill V-115L2 Development Oil Well V-215 Service Water Injector Injecting V-115L2PB1 Development Plugged Back For Redrill V-216 Service Miscible Injector Operating V-115PB1 Development Plugged Back For Redrill V-217 Service Water Injector Injecting V-117 Development Oil Producer Shut-In V-218 Service Water Injector Shut-In V-117PB1 Development Plugged Back For Redrill V-219 Service Water Injector Injecting V-117PB2 Development Plugged Back For Redrill V-220 Service Miscible Injector Operating V-119 Service Abandoned V-221 Service Water Injector Injecting V-120 Development Abandoned V-222 Service Water Injector Injecting V-120A Service Miscible Injector Operating V-223 Service Water Injector Injecting V-121 Service Miscible Injector Operating V-224 Service Water Injector Shut-In V-122 Development Oil Producer Gas Lift V-224PB1 Service Plugged Back For Redrill V-122PB1 Development Plugged Back For Redrill V-225 Service Water Injector Injecting V-122PB2 Development Plugged Back For Redrill V-227 Service Abandoned V-123 Service Water Injector Injecting V-227A Service Water Injector Shut-In V-137 Service Miscible Injector Operating V-229 Service Water Injector Injecting V-200 Exploratory Abandoned V-234 Development Oil Producer Gas Lift V-201 Service Abandoned V-234PB1 Development Plugged Back For Redrill V-202 Development Oil Producer Gas Lift V-234PB2 Development Plugged Back For Redrill V-202L1 Development Oil Producer Gas Lift WKUPST-01 Exploratory Abandoned V-202L2 Development Oil Producer Gas Lift SECTION 3: EXEMPTION FOR FRESWATER AQUIFERS (20 AAC 25. 283, a, 3): Well V-02 is in the West Operating Area of Prudhoe Bay. Per Aquifer Exemption Order No. 1 dated July 11, 1986 where Standard Alaska Production Company requested the Alaska Oil and Gas Conservation Commission to issue an order exempting those portions of all aquifers lying directly below the Western Operating Area and K Pad Area of the Prudhoe Bay Unit for Class II Injection activities. Findings 1- 4 state: 1. Those portions of freshwater aquifers occurring beneath the Western Operating and K pad areas of the Prudhoe Bay Unit do not currently serve as a source of drinking water. 2. Those portions of freshwater aquifers occurring beneath the Western Operating and K pad areas of the Prudhoe Bay Unit are situated at a depth and location that makes recovery of water for drinking water purposes economically impracticable. 3. Those portions of freshwater aquifers occurring beneath the Western Operating and K pad areas of the Prudhoe Bay Unit are reported to have total dissolved solids content of 7000 mg/ I or more. 4. By letter of July 1, 1986, EPA- Region 10 advises that the aquifers occurring beneath the Western Operating and K pad areas of the Prudhoe Bay Unit qualify for exemption. It is considered to be a minor exemption and a non-substantial program revision not requiring notice in the Federal Registrar. Per the above findings, " Those portions of freshwater aquifers lying directly below the Western Operating and K Pad Areas of the Prudhoe Bay Unit qualify as exempt freshwater aquifers under 20 AC 25. 440" thus allowing Hilcorp exemption from 20 AAC 25. 283, a, 3- 4 which require identification of freshwater aquifers and establishing a plan for base-water sampling. SECTION 4: PLAN FOR BASELINE WATER SAMPLING FOR WATER WELLS 20 AAC 25.283.a.4 There are no water wells located within one-half mile of the current or proposed wellbore trajectory and fracturing interval. A water well sampling plan is not applicable SECTION 5: DETAILED CEMENTING AND CASING INFORMATION (20 AAC 25. 283, a, 5): All casing is cemented in accordance with 20 AAC 25.52, b and tested in accordance with 20 AAC 25.030, g when completed. See wellbore schematic for casing details: SECTION 6: ASSESSMENT OF EACH CASING AND CEMENTING OPERATION TO BE PERFORMED TO CONSTRUCT OR REPAIR THE WELL 20 AAC 25.283, a, 6 Summary: Some losses while drilling 12.25” surface hole at ~800’ that did heal up. 9-5/8” surface casing was set at 2712’ and cemented with 367 bbls of 10.7 ppg lead followed by 42 bbls of 15.8 ppg tail. Plug was bumped at calculated strokes with 100 bbls of cement circulated to surface. An 8.75” production hole was drilled with some hydrate cut mud at ~4500’. After TDing the hole section, mud continued to show signs of hydrates. After conditioning the hole for a while, 120 bbls of “G-seal” pill was pumped across Shrader interval which seemed to help with hydrate issues. 7” casing was run to 9255’ and cemented in place with 247 sx of ~12 ppg LiteCrete followed by 100 sx of 15.8 ppg classG. No losses noted while cementing, plug was bumped with 1300 psi of lift pressure and held after 2000 psi applied. The stage tool was opened at 4989’ and stage 2 was cemented with 67 sx of LiteCrete followed by 108 sx of classG. The production hole was drilled, cased and cemented with little issues. The rig perforated. x 6/17/2004: Slickline install LGLVs, well POP’d at 660 bopd that quickly declined to 300 bopd in a week x 4/6/2006: GLRD x 4/18/2007: Slickline tagged hydrates, coil followed up with jet job then acid with a foamed mud acid. The acid added 600 bopd initially and hung in there at 500+ BOPD, good job. x 7/27/2009: Coil PPROF x 2/1/2011: Coil memory CBL showed good cement in production hole section x Since: GL work, surveillance x Surface subsidence (pad level is settling causing VSMs to lose contact with flowlines) has been noted on all of V pad, however, V-02 flowlines repaired November 2022 simply by adding gravel and adjusting the adjustable VSMs. In early 2023, a RWO was completed to convert the well to a Kuparuk Producer. The well was perforated and turned on production. A well test was obtained confirming good oil cut%. All casing is cemented in accordance with 210 AAC 25.030 and each hydrocarbon zone penetrated by the well is isolated. Based on engineering evaluation of the wells referenced in this application, Hilcorp has determined that this well can be successfully fractured within its design limits. 9255’ 7” casing was run to stage tool was opened at 4989’ a 100 bbls of cement circulated to surface. SECTION 7 – PRESSURE TEST INFORMATION AND PLANS TO PRESSURE TEST CASINGS AND TUBING INSTALLED IN THE WELL 20 AAC 25.283, A, 7 On 3/28/2023, the production casing was pressure tested to 3500 psi for a passing MIT-IA On 3/28/2023, the tubing was pressure tested to 3500 psi for a passing MIT-T The production casing annulus pressure will be monitored during the frac, if any change of pressure is seen outside of thermal expansion, the job will be flushed and the pressure source diagnosed before frac operations continue. SECTION 8: PRESSURE RATINGS AND SCHEMATICS FOR THE WELLBORE, WELLHEAD, BOPE AND TREATING HEAD 20 AAC 25.283, A, 8 Wellbore Tubular Ratings Size/Name Weight Grade Burst, psi Collapse, psi 9-5/8” Surface Casing 40#L80 5750 3090 7” Production Casing 26#L80 7240 5410 4-1/2” Production Tubing 12.6#L80 8430 7500 4-1/2” Production Liner 12.6#L80 8430 7500 Wellhead FMC manufactured wellhead, rated to 5, 000 psi. Tree: CIW 4-1/16" 5,000 psi Tubing head adaptor: 11" 5, 000 psi x 4-1/16" 5,000 psi Tubing Spool: 11" 5, 000 psi w/ 2-1/16" side outlets Casing Spool: 11" 5, 000 psi w/ 2-1/16" side outlets SECTION 9: DATA FOR FRACTURING ZONE AND CONFINING ZONES 20 AAC 25.283, A, 9 Formation MD Top MD Bot TVDss Top TVDss Bot TVD Thickness Frac Grad psi/ft Lith. Desc. THRZ 6358 6567 -6272 -6481 209 0.7 Shale TKLB 6567 6647 -6481 -6561 80 0.7 Shale Top Kup/C interval 6647 6771 -6561 -6685 124 0.62 Silts/SS LCU/ Kuparuk B 6771 6883 -6685 -6797 112 0.64 Silts/SS Kuparuk A 6883 6947 -6797 -6860 63 0.66 Silts/SS Miluveach 6947 7841 -6860 - 7630.27 770.25 0.70 Shale *Depths are taken from the V-02. SECTION 10: LOCATION, ORIENTATION AND A REPORT ON MECHANICAL CONDITION OF EACH WELL THAT MAY TRANSECT CONFINING ZONE 20 AAC 25.283, a, 10 Plat of wells within one-half mile ofV-02 wellbore reservoir trajectory and location of faults. The blue line indicates the approximate fracture length and orientation of the frac’s. The plat shows the location and orientation of each well that transects the confining zone. Hilcorp has formed the opinion, based on the following assessments for each well and seismic, well and other subsurface information currently available that none of these wells will interfere with containment of the hydraulic fracturing fluid within the one-half mile radius of the proposed wellbore trajectory. Casing and Cement assessments for all wells that transect the confining zone (annular capacity increased by 25% to take into account washout): V-02:TOC verified via CBL obtained during 2023 RWO to Kuparuk. State Approval obtained prior to running completion string and perforating. TOC determined at 6080’ MD. V-03:after casing landed @ 9763, 125 bbls of 15.8 ClassG pumped with returns lost after 265 bbls of cement pumped (108 bbls of cement in pipe, 17 behind pipe). After working the casing, partial returns were seen and eventually the plug was bumped. TOC at the shoe is estimated at 9161’ MD. Plug held a negative test then the EZ cementer at 5102’ was opened and 54 bbls of 15.6 ppg LXT cement pumped and displaced with no losses and full returns noted during the second stage. TOC above the stage tool is estimated at 3189’ MD. No CBL has been run on the production casing string. V-105:Casing landed with shoe at 8242’ and EZ cementer stage tool at 6011’. 1st stage cemented with 35 bbls of 15.8 ppg ClassG. No losses see and plug bumped on calculated strokes. TOC at shoe estimated at 7196’ MD. The stage tool was opened, circulation established with no losses then 69 bbls of 15.6 ppg ClassG with slight losses noted until rate was reduced during displacement. TOC above the stage tool is estimated at 3434’ MD. No CBL has been run on the production casing string. V-105L1:Casing landed with shoe at 8242’ and EZ cementer stage tool at 6011’. 1st stage cemented with 35 bbls of 15.8 ppg ClassG. No losses see and plug bumped on calculated strokes. TOC at shoe estimated at 7196’ MD. The stage tool was opened, circulation established with no losses then 69 bbls of 15.6 ppg ClassG with slight losses noted until rate was reduced during displacement. TOC above the stage tool is estimated at 3434’ MD. No CBL has been run on the production casing string. V-107:3-1/2” x 5-1/2” production casing run and cemented without losses and full returns from shoe at 7418’ to calculated TOC @ 5349’ MD V-109/V-109PB1/V-109PB2:TOC verified via 2002 USIT. The Kuparuk is isolated by ~500’ MD cement while the shrader is isolated with the 2nd stage cement job. V-111:after a very troublesome production casing hole drilling, the 7” casing was run and cemented in one stage with 223 bbls 12.5 ppg HOWCO micro lite cement followed by 33 bbls 15.8 ppg HOWCO super CBL tail. Full returns were noted throughout displacement and the plugs were bumped on calculated strokes. TOC calculated at 2411’ MD. V-111PB1:shale sloughing led to sidetrack, PB1 abandoned with 72 bbls ClassG cement, HWDP and BHA left in hole from 7056’ – 7315’, a sidetrack was performed at 6261’. V-111PB2:Shale sloughing led to sidetrack, PB2 abandoned with 181 bbls Class F cement + 25 bbls Form-a-Plug. The cement was place from 2804’ – 5290’ MD, the sidetrack to the final wellbore trajectory started at 2804’. V-111PB3:PB3 is the pilot hole below the EZSV plug/whipstock used to collect core data. Cemented with same cement as V-111, TOC calculated at 2411’ MD. V-112:7” production casing run and set at 8193’ MD with HES cementer at 5219’. First stage cement pumped 80 bbls LiteCrete followed by 30 bbls ClassG, pipe was reciprocated and full returns were noted throughout job. After plug was landed, the cementer was opened and 12 bbls LiteCrete followed by 31 bbls 15.8 ppg ClassG were pumped for the 2nd stage. Plug bumped on stroke and full returns noted throughout job. 2006 USIT showed good cement from top of logging interval at 5200’ to 5464’ and from first recording at 7485’ to 6746’. TOC above the stage tool is estimated at 3189’MD. TOC calculated at 2411’ MD. TOC determined at 6080’ MD. 6 USIT showed good cement from top of logging interval at 5200’ to 5464’ and from first recording at 7485’ to 6746’. TOC calculated at 2411’ MD. t 3434’ MD. TOC verified via 2002 USIT. t 7196’ MD.T calculated TOC @ 5349’ MD SECTION 11: LOCATION OF, ORIENTATION OF AND GEOLOGICAL DATA FOR FAULTS AND FRACTURES THAT MAY TRANSECT THE CONFING ZONES 20 AAC 25.283, A, 11 Hilcorp’s technical analysis based on seismic, well and other subsurface information available indicates that there are 8 mapped faults that transect the Kuparuk interval and enter the confining zone within the ½ mile radius of the production and confining zone trajectory for the V-02 well. Fracture gradients within the confining zone (Kalubik and HRZ) will not be exceeded during fracture stimulation and would therefore confine injected fluids to the pool. The HRZ and Kalubik in this area are predominately shale with some silts with an estimated fracture pressure of ~13.5ppg. Faults 1-4 intersect the production interval and confining zone within the ½ mile radius of the planned fracs. Their displacements, sense of throw, and zone in which they terminate upwards are given below. The wellbore trajectory is a slant well through the Kuparuk. Maximum stress direction is estimated to be ~30 deg W of N. The fracs should not reach any of the mapped faults. The frac is 980’ from fault #1, 2310’ from fault #2, 1940’ from fault #3, and 2360’ from fault #4. The maximum anticipated fracture half-length of 200’ is well short of theses distances. Half-length is modeled using hydraulic fracture modelling software and is corroborated by what we have seen in other frac treatments. The frac stages should have sufficient offset to faults #1, #2, #3, and #4 and should not intersect. If a sudden drop in treating pressure or increase in pump rate is seen during the stimulation that cannot be explaining by fluids pumped or annular pressure monitoring, pumping operation will stop until a plan forward and explanation can be put forth. Fault Throw Direction Top Bottom 1 0-30' DTW HRZ Kingak 2 0-100' DTS HRZ Kingak 3 0-100' DTW Colville Ivishak 4 0-235' DTW Colville Basement 5 0-230' DTS Sagavanirktok Basement 6 80-230' DTW Sagavanirktok Basement 7 90-180' DTSW Sagavanirktok Basement 8 0-50' DTS HRZ Miluveach 9 10' DTE HRZ Miluveach SECTION 12: PROPOSED HYDRAULIC FRACTURING PROGRAM 20 AAC 25.283, a, 12Fracture Stimulation Pump SchedulePlease see Frac program included with this sundry application Table 5 – Anticipated Pressures Maximum Anticipated Treating Pressure: 3160 psi Maximum Allowable Treating Pressure: 4500 psi w/ 3025 psi on IA Stagger Pump Kickouts Between: 4000 psi and 4275 psi (95% to 90% of MATP) Global Kickout: 4275 psi (95% of MATP) IA Pop-off Set Pressure: 3325 psi (~95% of MIT-IA) IA Minimum Hold Pressure: 3025 psi Treating Line Test Pressure: 5500 psi OA Pressure: Monitor and maintain open to atmosphere Max Anticipated Proppant Loading: 12 PPA N2 POP-off set pressure 6000 psi There are three overpressure devices that protect the surface equipment and wellbore from overpressure. 1) Each individual frac pump has an electronic kickout that will shift the pumps into neutral as soon as the set pressure is reached. Since there are multiple pumps, these set pressures are staggered between 90% and 95% of the maximum allowable treating pressure. 2) A primary pressure transducer in the treating line will trigger a global kickout that will shift all the pumps into neutral. 3) There is a manual kickout that is controlled from the frac van that can shift all pumps into neutral. All three of these shutdown systems will be individually tested prior to high pressure pumping operations. Additionally, the treating pressure, IA pressure and OA pressure will be monitored in the frac van. Based on a regional stress map, the maximum horizontal stress in the Kuparuk sands is determined to run ~30° W of N). Due to the nearly vertical nature of the wellbore through the Kuparuk formation, wellbore deviation will not significantly affect fracturing operations. Frac Dimensions: Frac #MD Location, ft TVDss top, ft TVDss Bottom, ft Frac Half-Length, ft 1 6660’-6574 -6654 ~370’ Disclaimer Notice: This model was generated using commercially available modelling software and is based on engineering estimates of reservoir properties. Hilcorp is providing these model results as an informed prediction of actual results. Because of the inherent limitations in assumptions required to generate this model, and for other reasons, actual results may differ from the model results. Frac Modelling: Maximum Anticipated Treating Pressure: ~3160 psi Surface pressure is calculated based on a closure pressure of ~0.62 psi/ ft or ~4100 psi. Closure pressure plus anticipated net pressure to be built (500 psi) and friction pressure minus hydrostatic results in a surface pressure of ~3160 psi at the time of flush. 4100 psi (closure)+ 500 psi (net)+ 2160 psi (friction)- 4600 psi (hydrostatic)= 3160 psi (max surface press) The difference in closure pressures of the confining shale layers determines height of the fracture. Average confining layer stress is anticipated to be ~0.7 psi/ ft limiting fracture height to ~100 ft TVD. Fracture half-length is determined from confining layer stress as well as leak-off and formation modulus. The modeled frac is anticipated to reach a half-length of ~375 ft at the current leakoff coefficient of 0.0005 ft/root(min). MD Pre-Job Anticipated Chemicals to be pumped: 57,162 gal SECTION 13: POST FRACTURE WELLBORE CLEANUP AND FLUID RECOVERY PLAN 20 AAC 25.283, A, 13 After the fracture stimulation and potentially during the post frac coil fill cleanout, the well will be put on production through portable well testers. All liquids will be captured and either sent to production facilities or diverted to flowback tanks if solid% becomes too high for our facilities to manage. The initial flowback period is intended to produce back the fracture fluids to tanks as quickly as possible, until the well is produced less than 10% water cut and less than 0.5% solids, at which time the produced fluids meet the GC2 acceptance criteria for start-up. There will be a tank farm on pad to store the produced fluids from flowback operations. The flowback fluids not suitable for GC2 processing will be hauled to another facilities slop tanks for additional settling time and or disposal. Hilcorp will work to separate and recover fluid that meets the facility specification for the flowback fluids. A fluid manifest form will be completed for each load trucked offsite. Hilcorp North Slope, LLCHilcorp North Slope, LLCChanges to Approved Work Over Sundry ProcedureDate: May 3, 2023Subject: Changes to Approved Sundry Procedure for Well V-02Sundry #:Any modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to theAOGCC by the workover (WO) “first call” engineer. AOGCC written approval of the change is required before implementing the change.StepPageDate Procedure ChangeHNSPreparedBy (Initials)HNSApprovedBy (Initials)AOGCC WrittenApproval Received(Person and Date)Approval:Asset Team Operations Manager DatePrepared:First Call Operations Engineer Date 20 AAC 25.283 Hydraulic Fracturing Application – Checklist PBU V-02 (PTD No. 204-077; Sundry No. 323-267) Paragraph Sub-Paragraph Section Complete? AOGCC Page 1 May 16, 2023 (a) Application for Sundry Approval (a)(1) Affidavit Provided with application. SFD 5/8/2023 (a)(2) Plat Provided with application. SFD 5/8/2023 (a)(2)(A) Well location Provided with application. Well lies in Sections 11, 3, and 2 of T11N, R11E, UM. SFD 5/8/2023 (a)(2)(B) Each water well within ½ mile None: According to the Water Estate map available through DNR’s Alaska Mapper application (accessed online May 9, 2023), there are no wells are used for drinking water purposes are known to lie within ½ mile of the surface location of PBU V-02. There are no subsurface water rights or temporary subsurface water rights within 6-3/4 miles of the surface location of PBU V-02. SFD 5/9/2023 (a)(2)(C) Identify all well types within ½ mile List of all wells within ½-mile radius of the PBU V-02 well path is provided with application. SFD 5/9/2023 (a)(3) Freshwater aquifers: geological name; measured and true vertical depth None. No freshwater aquifers are present within the former Western Operating and K-Pad areas of the Prudhoe Bay Unit per AEO 1. An outline of the EPA’s current Aquifer Exemption Area for the Prudhoe Bay Unit is available on the EPA’s “Alaska Oil & Gas Aquifer Exemptions Interactive Map” available online under the “Permits” section of EPA Region 10’s web page at https://www.epa.gov/uic/underground-injection-control-region-10-ak-id-or-and-wa. SFD 5/9/2023 (a)(4) Baseline water sampling plan None required: No freshwater aquifers are present. SFD 5/9/2023 (a)(5) Casing and cementing information Provided with application. schematic attached CDW 05/15/2023 (a)(6) Casing and cementing operation 9-5/8” casing cemented to surface with 100 bbl returns to 20 AAC 25.283 Hydraulic Fracturing Application – Checklist PBU V-02 (PTD No. 204-077; Sundry No. 323-267) Paragraph Sub-Paragraph Section Complete? AOGCC Page 2 May 16, 2023 assessment surface. Two stage cement job in 7” casing went as planned. Stage tool at 4989, casing TD of 9255 ft. CBL shows 6080 ft TOC. No issues with cement for the upcoming stimulation. 7”casing was pressure tested to 3500 psi . MGR 5/15/2023 (a)(6)(A) Casing cemented below lowermost freshwater aquifer and conforms to 20 AAC 25.030 No freshwater aquifers present. (See Section (a)(3), above.) SFD 5/9/2023 (a)(6)( B) Each hydrocarbon zone is isolated Yes: Surface casing was set at 2,712’ MD (-2,627’ TVDSS) and cemented with 100 barrels of cement returns reported at surface. For PBU V-02, 8-3/4” hole was drilled from the base of surface casing to a total depth of 9,255’ MD (-8,667’ TVDSS). The 7” intermediate casing stage tool is set at 4,989’ MD (-4,904’ TVDSS). Top of good-quality cement above the intermediate casing stage tool interpreted from the CBL at about 3,275’ MD (-3,190’ TVDSS), which covers the Ugnu and Schrader Bluff N and O sands. The 7” casing shoe is set at 9,255’ MD (-8,667’ TVDSS). Top of good-quality cement interpreted from the CBL for the intermediate casing shoe is about 6,080’ MD (-5,994’ TVDSS), which covers the HRZ, Kalubik shale, Kuparuk sands, Miluveach shale and part of the Kingak Shale and isolates the Kuparuk sands from the underlying Sag River, Shublik, and Ivishak intervals. So, cement isolates each hydrocarbon zone. SFD 5/9/2023 (a)(7) Pressure test: information and pressure-test plans for casing and tubing Provided with application. 3500 psi MITIA completed, 3500 psi MITT completed. CDW 05/15/2023 20 AAC 25.283 Hydraulic Fracturing Application – Checklist PBU V-02 (PTD No. 204-077; Sundry No. 323-267) Paragraph Sub-Paragraph Section Complete? AOGCC Page 3 May 16, 2023 installed in well (a)(8) Pressure ratings and schematics: wellbore, wellhead, BOPE, treating head Provided with application. 5K psi wellhead max. frac. Pressure 4500 psi. Pump knock out 4000 and 4275 psi., lines test 5500 psi. CDW 05/15/2023 (a)(9)(A) Fracturing and confining zones: lithologic description for each zone (a)(9)(B) Geological name of each zone (a)(9)(C) and (a)(9)(D) Measured and true vertical depths (a)(9)(E) Fracture pressure for each zone Upper confining zones: HRZ shale and Kalubik Shale consisting of condensed mudstone overlain by claystone and silty claystone that has an aggregate thickness of about 289’ true vertical thickness (TVT). Fracture gradient is expected to be about 0.70 psi/ft (13.5 ppg EMW). Fracturing Zone: Kuparuk sandstone very fine- to fine-grained sandstone that grades downward to sandstone lenses interbedded within siltstone and mudstone. Fracture gradient expected to be about 0.62 psi/ft (11.9 ppg EMW). Lower confining zones: Miluveach silty shale and shale intervals that have an aggregate TVT of over 700’ TVD. Fracture gradient is expected to be about 0.70 psi/ft (13.5 ppg EMW). SFD 5/9/2023 (a)(10) Location, orientation, report on mechanical condition of each well 12 wells identified including plug backs/sidetracks and cement assessments provided including top of cement estimates/CBL runs. V-02 included in table for ease of reference CDW 05/15/2023 (a)(11) Sufficient information to determine wells will not interfere with containment within ½ mile Yes. There are 6 wells, 1 lateral well branch, and 5 plugged-back wellbores within ½ mile of PBU V-02. Cementing and—when available--cement evaluation logs were examined and the Ugnu, Schrader Bluff, HRZ, and Kuparuk intervals all appear to be cement-isolated. It is highly unlikely that the identified wellbores within the one-half-mile AOR will interfere with containment. SFD 5/12/2023 20 AAC 25.283 Hydraulic Fracturing Application – Checklist PBU V-02 (PTD No. 204-077; Sundry No. 323-267) Paragraph Sub-Paragraph Section Complete? AOGCC Page 4 May 16, 2023 (a)(11) Faults and fractures, Location, orientation (a)(11) Faults and fractures, Sufficient information to determine no interference with containment within ½ mile None. The operator has identified four faults or fracture zones on seismic data within a ½-mile radius of PBU V-02 but they are located at such a distance from the planned induced fracture that it is unlikely that any of these faults will interfere with containment of the injected fracturing fluids. However, if there are indications that a fracture has intersected a fault or natural-fracture interval during frac operations, the operator will go to flush and terminate the stage immediately. SFD 5/13/2022 (a)(12) Proposed program for fracturing operation Provided with application. CDW 05/15/2023 (a)(12)(A) Estimated volume Provided with application. 1361 bbl total dirty vol. 194K lb total proppant CDW 05/15/2023 (a)(12)(B) Additives: names, purposes, concentrations Provided with application. CDW 05/15/2023 (a)(12)(C) Chemical name and CAS number of each Provided with application. Schlumberger disclosure provided. No proprietary products identified CDW 05/15/2023 (a)(12)(D) Inert substances , weight or volume of each Provided with application. CDW 05/15/2023 (a)(12)(E) Maximum treating pressure with supporting info to determine appropriateness for program Simulation shows max surface pressure 3160 psi. Max. 4500 psi allowable treating pressure. Max pressure is 4000 psi to 4275 psi to Pump shutdown. With 3025 psi back pressure IA (IA popoff set 3325 psi), max tubing differential should be 1475 psi (4500-3025). CDW 05/15/2023 (a)(12)(F) Fractures – height, length, MD and TVD to top, description of fracturing model Provided with application. The anticipated half-length of the induced fractures is 370’ according to the Operator’s computer simulation. Computer simulation indicates the anticipated height of the induced fractures will be 80’ (top TVDSS of about -6,574’ and base TVDSS of about -6,654’), so induced fractures will likely penetrate into, but not through, SFD 5/13/2023 20 AAC 25.283 Hydraulic Fracturing Application – Checklist PBU V-02 (PTD No. 204-077; Sundry No. 323-267) Paragraph Sub-Paragraph Section Complete? AOGCC Page 5 May 16, 2023 the overlying confining Kalubik and HRZ Shales that are about 290’ thick in this area. (a)(13) Proposed program for post-fracturing well cleanup and fluid recovery Well cleanout and flowback procedure provided with application. No disposal identified but Hilcorp has many option on North Slope. CDW 05/15/2023 (b)Testing of casing or intermediate casing Tested >110% of max anticipated pressure 3025 psi back pressure, IA tested to 3500 psi, popoff set as 3325 psi CDW 05/15/2023 (c) Fracturing string (c)(1) Packer >100’ below TOC of production or intermediate casing 4.5” tubing will be anchored with a packer set at approx. 6585 ft with perforations planned for 6660 ft. 9-5/8” surface casing cemented to surface with 100 bbl returns to surface. TOC in 7” casing at 6080 ft. Used ES tool at 4989 ft. CDW 05/15/2023 (c)(2) Tested >110% of max anticipated pressure differential Tubing test of 3500 psi. Max pressure differential is estimated as 1475 psi (4500 with 3025 psi backpressure) so test of 3500 psi satisfies the 110% testing requirement. CDW 05/15/2023 (d) Pressure relief valve Line pressure <= test pressure, remotely controlled shut-in device 5500 psi line pressure test, pump knock out 4000 and 4275 psi with max. global kickout 4275 psi and N2 POP OFF set as 6000 psi. IA PRV set as 3325 psi. CDW 05/15/2023 (e) Confinement Frac fluids confined to approved formations Provided with application. CDW 05/15/2023 (f) Surface casing pressures Monitored with gauge and pressure relief device IA PRV set at 3325 psi. Surface annulus open. Frac pressures continuously monitored. CDW 05/15/2023 (g) Annulus pressure monitoring & notification 500 psi criteria During hydraulic fracturing operations, all annulus pressures must be continuously monitored and recorded. If at any time during hydraulic fracturing operations the annulus pressure increases more than 500 psig above those anticipated increases caused by pressure or thermal transfer, the operator shall: CDW 05/15/2023 (g)(1) Notify AOGCC within 24 hours (g)(2) Corrective action or surveillance 20 AAC 25.283 Hydraulic Fracturing Application – Checklist PBU V-02 (PTD No. 204-077; Sundry No. 323-267) Paragraph Sub-Paragraph Section Complete? AOGCC Page 6 May 16, 2023 (g)(3) Sundry to AOGCC (h) Sundry Report (i) Reporting (i)(1) FracFocus Reporting (i)(2) AOGCC Reporting: printed & electronic (j) Post-frac water sampling plan Not required (see Section (a)(3), above), (k) Confidential information Clearly marked and specific facts supporting nondisclosure Confidential exploratory well. (l) Variances requested Modifications of deadlines, requests for variances or waivers No plan for post fracture water well analysis. Commission may require this depending on performance of the fracturing operation. 1 Regg, James B (OGC) From:Christopher Yearout - (C) <Christopher.Yearout@hilcorp.com> Sent:Monday, March 27, 2023 5:43 AM To:DOA AOGCC Prudhoe Bay; jim.regg@alaska.gov:; Brooks, Phoebe L (OGC) Cc:PB Wells RWO WSS Subject:Hilcorp Nordic 3 V-02 Initial BOPE Test Attachments:Nordic 3 BOP TEST 03-24-23.xlsx Please see attached. Thanks, Chris yearout 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 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. Some people who received this message don't often get email from christopher.yearout@hilcorp.com. Learn why this is important 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. PBU V-02PTD 2040770 STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION *All BOPE reports are due to the agency within 5 days of testing* Submit to:jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov Rig Owner:Rig No.:3 DATE:3/24/23 Rig Rep.:Rig Email: Operator: Operator Rep.:Op. Rep Email: Well Name:PTD #2040770 Sundry #323-031 Operation:Drilling:Workover:xxx Explor.: Test:Initial:xxx Weekly:Bi-Weekly:Other: Rams:250/3000 Annular:250/3000 Valves:250/3000 MASP:2858 MISC. INSPECTIONS:TEST DATA FLOOR SAFETY VALVES: Test Result/Type Test Result Quantity Test Result Housekeeping P Well Sign P Upper Kelly 1 P Permit On Location P Hazard Sec.P Lower Kelly 1 P Standing Order Posted P Misc.NA Ball Type 1 P Test Fluid Water Inside BOP 1 P FSV Misc 0 NA BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm Stripper 0 NA Trip Tank P P Annular Preventer 1 GK13 5/8" FP Pit Level Indicators P P #1 Rams 1 2 7/8 x 5 1/2 VBR P Flow Indicator P P #2 Rams 1 BLIND P Meth Gas Detector P P #3 Rams 0 NA H2S Gas Detector P P #4 Rams 0 NA MS Misc 0 NA #5 Rams 0 NA #6 Rams 0 NA ACCUMULATOR SYSTEM: Choke Ln. Valves 1 3 1/8"FP Time/Pressure Test Result HCR Valves 2 3 1/8"FP System Pressure (psi)3000 P Kill Line Valves 1 3 1/8"P Pressure After Closure (psi)1650 P Check Valve 0 NA 200 psi Attained (sec)19 P BOP Misc 0 NA Full Pressure Attained (sec)127 P Blind Switch Covers:All stations Yes CHOKE MANIFOLD:Bottle Precharge:P Quantity Test Result Nitgn. Bottles # & psi (Avg.):4@2000psi P No. Valves 12 P ACC Misc 0 NA Manual Chokes 1 P Hydraulic Chokes 1 P Control System Response Time:Time (sec)Test Result CH Misc 1 P Annular Preventer 17 P #1 Rams 4 P Coiled Tubing Only:#2 Rams 5 P Inside Reel valves 0 NA #3 Rams NA #4 Rams NA Test Results #5 Rams NA #6 Rams NA Number of Failures:3 Test Time:17.5 HCR Choke 1 P Repair or replacement of equipment will be made within days. HCR Kill 1 P Remarks: AOGCC Inspection 24 hr Notice Yes Date/Time 3/22/23 / 1630 Waived By Test Start Date/Time:3/24/2023 /20:00 (date)(time)Witness Test Finish Date/Time:3/25/2023 /13:30 BOPE Test Report Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Austin McLeod Nordic Test BOPE & Annular With 4 1/2" and 3 1/2" test JT. Test gas alarms. Test PVT & flow paddle. Annular fail, Function Annular and retest - pass. Choke HCR Fail, Function & Grease - pass. Choke Ln. manual Valve fail, change out valve & retest - pass Henry / Bondietti Hilcorp Wilson / Yearout PBU V-02 Test Pressure (psi): al.hansen@nordic-calista.com pbwellsrwowss@hilcorp.com Form 10-424 (Revised 08/2022)2023-0325_BOP_Nordic3_PBU_V-02 J. Regg; 8/24/2023 MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg DATE: P.I. Supervisor SUBJECT: FROM: Petroleum Inspector Section:11 Township:11N Range:11E Meridian:Umiat Drilling Rig:n/a Rig Elevation:n/a Total Depth:15086 ft MD Lease No.:ADL 0028240 Operator Rep:Suspend:P&A:X Conductor:20"O.D. Shoe@ 110 Feet Csg Cut@ Feet Surface:O.D. Shoe@ Feet Csg Cut@ Feet Intermediate:9 5/8"O.D. Shoe@ 2712 Feet Csg Cut@ Feet Production:7"O.D. Shoe@ 9255 Feet Csg Cut@ Feet Liner:4 1/2"O.D. Shoe@ 15084 Feet Csg Cut@ Feet Tubing:3 1/2"O.D. Tail@ 9064 Feet Tbg Cut@ Feet Type Plug Founded on Depth (Btm)Depth (Top)MW Above Verified Tubing Bridge plug 9260 ft 9222 ft Wireline tag Initial 15 min 30 min 45 min Result Tubing 2748 2589 2503 IA 319 319 314 OA 278 277 277 Initial 15 min 30 min 45 min Result Tubing IA OA Remarks: Attachments: Jerry Culpepper Casing/Tubing Data (depths are MD): Plugging Data (depths are MD): Plug perfs to recomplete to Boreolis producer. Tag at 9222 ft MD with 28-ft tool string with bailer on slickline. Cement was soft enough to get in bailer but difficult to break apart. March 19, 2023 Sullu Sullivan Well Bore Plug & Abandonment PBU V-02 Hilcorp North Slope LLC PTD 2040770; Sundry 323-031 none Test Data: P Casing Removal: rev. 3-24-2022 2023-0319_Plug_Verification_PBU_V-02_ss 2500 psi test required per Sundry MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg DATE: P.I. Supervisor SUBJECT: FROM: Petroleum Inspector Section: 11 Township: 11N Range: 11E Meridian: Umiat Drilling Rig: N/A Rig Elevation: N/A Total Depth: 15086 ft MD Lease No.: ADL 028240 Operator Rep: Suspend: P&A: Conductor: 20" O.D. Shoe@ 110 Feet Csg Cut@ Feet Surface: 9 5/8" O.D. Shoe@ 2712 Feet Csg Cut@ Feet Intermediate: O.D. Shoe@ Feet Csg Cut@ Feet Production: 7" O.D. Shoe@ 9255 Feet Csg Cut@ Feet Liner: 4 1/2" O.D. Shoe@ 15084 Feet Csg Cut@ Feet Tubing: 3 1/2" O.D. Tail@ 9064 Feet Tbg Cut@ Feet Type Plug Founded on Depth (Btm) Depth (Top) MW Above Verified Tubing Bridge plug 9260 ft 9227 ft Wireline tag Initial 15 min 30 min 45 min Result Tubing IA OA Initial 15 min 30 min 45 min Result Tubing IA OA Remarks: Attachments: Stefan Reed Casing/Tubing Data (depths are MD): Plugging Data (depths are MD): Plug to isolate the Ivashak recomplete to Boreolis. Tagged soft material at 9227 ft MD. Bailer was full of sand. Continued to bail to 9224 ft MD attempting to locate good cement. Cement plug was set on top of sand that is founded on an inflatable plug for easy reentry of the well. They did not continue with MIT due to bad cement job. Hilcorp will resubmit for witness of tag and mit at a later date. February 28, 2023 Sully Sullivan Well Bore Plug & Abandonment PBU V-02 Hilcorp North Slope LLC PTD 2040770; Sundry 323-031 none Test Data: Casing Removal: rev. 3-24-2022 2023-0228_Plug_Verification_PBU_V-02_ss 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 James B. Regg Digitally signed by James B. Regg Date: 2023.06.13 14:50:13 -08'00' 7. If perforating: 1. Type of Request: 2. Operator Name: 3. Address: 4. Current Well Class:5. Permit to Drill Number: 6. API Number: 8. Well Name and Number: 9. Property Designation (Lease Number):10. Field: 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 What Regulation or Conservation Order governs well spacing in thes pool? Will planned perforations require a spacing exception?Yes No 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): PRESENT WELL CONDITION SUMMARY Perforation Depth MD (ft): Perforation Depth TVD (ft):Tubing Size: Tubing Grade: Tubing MD (ft): Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): Casing Length Size MD TVD Burst Collapse Exploratory Stratigraphic Development Service 12. Attachments: 14. Estimated Date for Commencing Operations: 13. Well Class after proposed work: 15. Well Status after proposed work: 16. Verbal Approval: 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approcal. Proposal Summary Wellbore schematic BOP SketchDetailed Operations Program OIL GAS WINJ WAG GINJ WDSPL GSTOR Op Shutdown Suspended SPLUG Abandoned ServiceDevelopmentStrastigraphicExploratory Authorized Name and Digital Signature with Date: Authorized Title: Contact Name: Contact Email: Contact Phone: AOGCC USE ONLY Commission Representative: Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Location ClearanceMechanical Integrity TestBOP TestPlug Integrity Other: Post Initial Injection MIT Req'd? Spacing Exception Required?Yes Yes No No Subsequent Form Required: Approved By:Date: APPROVED BY THE AOGCCCOMMISSIONER PBU V-02 Recomplete to Borealis Hilcorp North Slope, LLC 3800 Centerpoint Dr, Suite 1400, Anchorage, AK 99503 204-077 50-029-23209-00-00 341J / 471.011 ADL 0028240 15086 Conductor Surface Intermediate Production Liner 8938 80 2683 9229 6030 14996 20" 9-5/8" 7" 4-1/2" 8947 30 - 110 29 - 2712 26 - 9255 9054 - 15084 2858 30 - 110 29 - 2708 26 - 8749 8596 - 8939 None 520 3090 5410 7500 None 1530 5750 7240 8430 9585 - 14985 3-1/2" 9.2# L-80 24 - 90648949 - 8948 Structural 3-1/2" Baker Premier Packer No SSSV Installed 8993, 8551 Date: Stan Golis Sr. Area Operations Manager Brodie Wages David.Wages@hilcorp.com 907.564.5006 PRUDHOE BAY 3/15/23 Current Pools: PRUDHOE OIL Proposed Pools: Borealis Oil STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 Comm. Comm.Sr Pet Eng Sr Pet Geo Sr Res Eng Form 10-403 Revised 10/2022 Approved application is valid for 12 months from the date of approval.Submit PDF to aogcc.permitting@alaska.gov By Meredith Guhl at 9:38 am, Jan 20, 2023 323-031 Digitally signed by Stan Golis (880) DN: cn=Stan Golis (880), ou=Users Date: 2023.01.20 08:55:06 -09'00' Stan Golis (880) DSR-2/6/23 10-404 MGR06FEB23 2858 * BOPE test to 3000 psi. Annular to 2500 psi. X DLB 01/24/2023 * CBL to AOGCC upon completion. * AOGCC to witness tag (~9,225' MD minimum) and pressure test to (2500 psi) of reservoir abandonment plug. * Variance to AAC 25.112(c)((1)(E) approved for a 25' cement plug to be set higher than 50' from top of perforations (mechanical plug @ ~9260' MD, TOC @ ~9225' MD) and within the confining zones of the Prudhoe Bay oil pool. GCW 02/07/23 JLC 2/7/2023 2/7/2023 Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2023.02.07 15:06:52 -09'00' RBDMS JSB 020823 Recomplete to Kuparuk Well: V-02 PTD: 204-077 Well Name:V-02 API Number:50-029-23209-00 Current Status:Operable Shut In producer for marginals Estimated Start Date:3/15/2023 Rig:Nordic 3 Sundry #Date Reg. Approval Rec’vd: Regulatory Contact:Abbie Barker Permit to Drill Number: First Call Engineer:Brodie Wages (907) 564-5006 (O)(713) 380-9836 (M) Second Call Engineer:Claire Mayfield (970) 443-3631 (M) Current Bottom Hole Pressure:3718 psi @ 8600’ TVD 8.4 PPG | (10/28/2016 static) 9.5 PPG with 2500’ freeze protect Max. Anticipated Surface Pressure:2858 psi (Based on 0.1 psi/ft. gas gradient) Last SI WHP:617 psi (Taken on 12/15/2022) Min ID:2.725” XN at 9040’ MD Max Angle:96 Deg @ 15,046’ MD 70 deg: 9660’ (Vertical to Kuparuk) High DLS @ 7107’ and again at 9305’+ Formation Tops: Kuparuk: 6647’ MD/6643’MD Kingak: 7664’ MD/7581’ TVD – confining zone for Sag/Ivishak Sag: 9260’ MD/8753’ TVD Sadlerochit: 9577’ MD/8946’ TVD MITs: CMIT-TxIA: 2500 psi on 7/9/2016 MIT-T: 2500 psi on 7/9/2016 Brief Well Summary: The Ivishak reservoir no longer remains economically viable and the Kuparuk interval for V-02 motherbore is in a perfect location to optimize lost production associated with compromised V-109. A RWO is planned to recomplete to Kuparuk to test production rates and water cuts at the Kuparuk interval. If favorable water cut is observed, a frac will be performed at a later date and will be covered by a separate program and sundry. V-02: Some losses while drilling 12.25” surface hole at ~800’ that did heal up. 9-5/8” surface casing was set at 2712’ and cemented with 367 bbls of 10.7 ppg lead followed by 42 bbls of 15.8 ppg tail. Plug was bumped at calculated strokes with 100 bbls of cement circulated to surface. An 8.75” production hole was drilled with some hydrate cut mud at ~4500’. After TDing the hole section, mud continued to show signs of hydrates. After conditioning the hole for a while, 120 bbls of “G-seal” pill was pumped across Shrader interval which seemed to help with hydrate issues. 7” casing was run to 9255’ and cemented in place with 247 sx of ~12 ppg LiteCrete followed by 100 sx of 15.8 ppg classG. No losses noted while cementing, plug was bumped with 1300 psi of lift pressure and held after 2000 psi applied. The stage tool was opened at 4989’ and stage 2 was cemented with 67 sx of LiteCrete followed by 108 sx of classG. The production hole was drilled, cased and cemented with little issues. The rig perforated. Notes Regarding Wellbore Condition x 6/17/2004: Slickline install LGLVs, well POP’d at 660 bopd that quickly declined to 300 bopd in a week x 4/6/2006: GLRD x 4/18/2007: Slickline tagged hydrates, coil followed up with jet job then acid with a foamed mud acid. The acid added 600 bopd initially and hung in there at 500+ BOPD, good job. x 7/27/2009: Coil PPROF -00 DLB Recomplete to Kuparuk Well: V-02 PTD: 204-077 x 2/1/2011: Coil memory CBL showed good cement in production hole section x Since: GL work, surveillance x Surface subsidence (pad level is settling causing VSMs to lose contact with flowlines) has been noted on all of V pad, however, V-02 flowlines repaired November 2022 simply by adding gravel and adjusting the adjustable VSMs. Ivishak Abandonment Plug: The proposed Ivishak abandonment plug will be set at the top of Sag @ 9260’. This is set below the production casing show but in good cement of the 4-1/2” liner confirmed by USIT. After setting the inflatable plug, we will dump bail sand to protect it for future retrieval prior to dumping 25’ of cement on top of the sand. The planned top of cement is at 9225’ inside the production liner. We have good cement in the 4-1/2” liner and expect good cement quality at the production casing shoe. With a cement top at 9225, we will have good circumferential coverage from 9225’ – 9250’. Objective: x Caliper tubing to determine re-usability x Recomplete to Kuparuk Sundry Procedure (Approval Required to Proceed) Pre-Rig 1. Obtain updated pressure tests on WH seals Slickline with fullbore assist 1. Drift 2. B&F tubing 3. Pull caliper from tubing tail to surface a. Looking to evaluate tubing re-usability 4. Set plug in XN nipple @ 9040’ 5. Dummy GLVs 6. Pull St1 GLV for circ’ing in KWF 7. Load hole with 2% KCl + Freeze protect a. Total T+IA volume to St#1: 312 bbls b. Freeze protect volume to 2500’: 88 bbls 8. Dummy st#1 Recomplete to Kuparuk Well: V-02 PTD: 204-077 9. Obtain 3500 psi MIT-IA 10. MIT-T to 3500 psi 11. Pull plug in XN 12. Drift to deviation a. Will set IBP @ 9260’ b. 7 deg DLS @ 7100’, 14 DLS @ 9305 c. 70 deg @ 9660’ Eline 1. Spot E-Line unit to well, RU and PT. 2. MU and RIH and set IBP 9260’ per tie in below Slickline 1. Dump bail 10’ of sand on IBP then 25’ of cement NOTE: AOGCC to witness slickline tag and pressure test 2. Pressure test cement plug to 2500 psi 3. Slickline tie in to tubing tail then tag cement top Eline 1. MU mechanical tubing cutter and RIH and correlate. 2. Pick up and cut in the packer cut zone a. The Premier packer is cut to release b. The window is 21” long starting 17” from the top of the pin threads, see drawing attached c. Contact OE Brodie Wages 1(713)380-9836 prior to cut for final approval of tie in. d. Correlate to Tubing Tally dated 6/15/2004. 3. RDMO Eline. Pre-RWO *Note: Depending on timing of rig move, well kill and BOP installation steps may be performed on rig rather than pre-rig. Most recent static was obtained in 2016. This value should be accurate and ~2% KCl may be used as KWF. 1. Spot Pump Truck, RU and PT. a. Circulate in at least 320 bbls of 1% KCl through st1 b. Total T+IA volume to St#1: 312 bbls c. Tubing Volume to punch holes: 78 bbls d. IA volume to punch holes: 234 bbls 2. Ensure well is dead, weight up as necessary 3. RD well house and flowlines. Clear and level area around well. 4. Set BPV w/insert (TWC) and test. ND Tree and THA. 5. NU BOPE configured top down: Annular, 2-7/8” x 5” VBRs, Blinds and integral flow cross. Recomplete to Kuparuk Well: V-02 PTD: 204-077 RWO Procedure: 1. MIRU Nordic 3 workover rig and ancillary equipment 2. Bleed TBG/IA pressures to ~0psi. Kill well w/2% KCl as needed. 3. Test BOPE to 250 psi Low/ 3,000 psi High, annular to 250 psi Low/ 2,500 psi High (hold each ram/valve and test for 5-min). Record accumulator pre-charge pressures and chart tests. a. Notify AOGCC 24 hours in advance of BOP test. b. Perform Test per “Nordic #3 Test Procedure” c. Confirm test pressures per the Sundry Conditions of approval. d. Test VBR ram and Annular on 4-1/2”and on 3-1/2”test joint. e. Submit to AOGCC completed 10-424 form within 5 days of BOPE test. 4. Pull TWC insert and BPV. a. Utilize lubricator for BPV removal if potential for trapped pressure exists. 5. MU landing joint or spear, BOLDS and PU on the tubing hanger. a. ~9063’ of 3-1/2” 9.2# tubing weighs ~ 73klbs (buoyed by 8.4 ppg fluid) b. If pulled up to 165 Klbs (80% of 3-1/2” yield strength) with no hanger movement, RU eline and perform 2nd tubing cut in cut window, discuss with OE. 6. POOH and stand back the 3-1/2” tubing. a. Save tubing if possible, pre-rig caliper will inform joints to be discarded b. If re-usable, landing depth will remain the same, only the jewelry will be replaced as needed c. Discuss with OE the need to run a casing scraper, based on OD condition of pulled pipe 7. RU Eline 8. Pull CBL from liner hanger tieback sleeve @ 9054’ to surface to verify cement quality over Kuparuk interval a. Send copy of log to David.wages@hilcorp.com b. Send copy of log with vendor TOC interpretation to AOGCC @ melvin.rixse@aogcc.com c. If no cement, work with OE for plan forward, very likely will run kill string 9. Run V-02 completion per V-02 Proposed Completion Running Order. a. Refer to appropriate 3-1/2” or 4-1/2” completion running order depending on re-usability of existing tubing b. Load IA with inhibited KWF brine c. Land tubing with mule shoe/WLEG @ ~6560’ a. Packer must be within 200’ of top Kuparuk perf planned at 6659’. d. Ensure RHC plug body pre-installed in lowermost X profile 10. Land the tubing hanger and RILDS. Lay down landing joint. Note Pick-up and slack-off weights on tally. 11. Drop ball and rod and hydraulically set the packer per manufacturer’s setting procedure a. Conduct MIT-T to 3500 psi and MIT-IA to 3,500 psi for 30 mins (charted, state witnessed) 12. Shear circ valve in shallow GLM and circ freeze protect. 13. Bleed tubing pressure back to ~0 psi. Set BPV with TWC insert. 14. RDMO Nordic 3 WO Rig and ancillary equipment. Move to next well location. 15. RU crane. ND BOPE. o AOGCC @ melvin.rixse@aogcc.com Recomplete to Kuparuk Well: V-02 PTD: 204-077 16. NU the tubing head adapter and tree. Test tubing hanger void and tree to 500 psi low/5,000 psi high. 17. Pull BPV with TWC insert. 18. Replace wellhouse and gauge(s) if removed. Post-Rig Procedure: Slickline 1. Spot Slickline unit, RU and PT. 2. RIH and pull RHC plug from X profile at ±6530’ MD 3. Install LGLVs per GL engineer 4. RDMO Eline 5. Perforate per geologist a. Charges will be 2-7/8” MaxForce or similar b. 6 SPF c. 60 deg Phasing Testers 6. POP well a. Start well at minimum choke and 1 mmscfd until well IA cleared and well is flowing b. After well is online and stable, Open choke ~10 steps per hour, checking solids every choke adjustment and bottoms up c. Increase GL as needed to keep flow stable d. Obtain 8 hour piggyback well test with pad separator prior to RDMO Operations 7. Obtain AOGCC witnessed SVS test within 5 days of putting well online. NOTE: A separate frac sundry and program will be submitted. This program only covers the RWO. Details to be included in future frac program that will require a frac sundry: 1. Slickline dummy GLVs, load hole with 2% KCl and freeze protect, obtain 3500 psi MIT-T and MIT-IA 2. Special Projects frac well 3. Contingent post frac coil FCO 4. Slickline install LGLVs 5. Well testers POP well for frac flowback 6. Handover to Ops Attachments: 1. Current Wellbore Schematic 2. Proposed Wellbore Schematic 3. Nordic 3 BOP Stack 4. Packer Schematic 5. Liner CBL 6. Sundry Change Form Recomplete to Kuparuk Well: V-02 PTD: 204-077 Current WBD: Recomplete to Kuparuk Well: V-02 PTD: 204-077 Recomplete to Kuparuk Well: V-02 PTD: 204-077 Proposed WBD: Recomplete to Kuparuk Well: V-02 PTD: 204-077 Nordic Rig 3 BOP Schematic Recomplete to Kuparuk Well: V-02 PTD: 204-077 V-02 3-1/2” x 7” Cut to release Packer: Recomplete to Kuparuk Well: V-02 PTD: 204-077 4-1/2” Liner CBL (1-Feb-2011): Top of Sag @ 9260’ Production Casing Shoe @ 9255’ Plug set @ 9260’ 10’ of sand + 25’ cement dump bailed to 9225’ Hilcorp North Slope, LLCHilcorp North Slope, LLCChanges to Approved Rig Work Over Sundry ProcedureDate: January 19, 2023Subject: Changes to Approved Sundry Procedure for Well V-02Sundry #:Any modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to theAOGCC by the rig workover (RWO) “first call” engineer. AOGCC written approval of the change is required before implementing the change.StepPageDate Procedure ChangeHNSPreparedBy (Initials)HNSApprovedBy (Initials)AOGCC WrittenApproval Received(Person and Date)Approval:Asset Team Operations Manager DatePrepared:First Call Operations Engineer Date • Wallace, Chris D (DOA) From: AK, GWO SUPT Well Integrity <AKDCWellIntegrityCoordinator@bp.com> Sent: Sunday,July 10, 2016 9:57 AM To: AK, OPS GC2 OSM;AK, OPS GC2 Field O&M IL;AK, OPS GC2 Wellpad Lead;AK, OPS Well Pad LV;Cismoski, Doug A; Daniel, Ryan;AK, RES GPB West Wells Opt Engr;AK, RES GPB East Wells Opt Engr;AK, OPS Prod Controllers; Peru, Cale;Wallace, Chris D (DOA); Regg,James B (DOA) Cc: AK, OPS FF Well Ops Comp Rep;AK, GWO DHD Well Integrity;AK, GWO Projects Well Integrity;AK, GWO SUPT Well Integrity; Hibbert, Michael;Janowski, Carrie; Montgomery, Travis J; Munk, Corey; Obrigewitch, Beau; Pettus,Whitney; Sternicki, Oliver R;Tempel, Troy;Worthington,Aras J Subject: OPERABLE: Producer V-02 (PTD#2040770) Passing MIT-T and CMIT-TxIA All, Producer V-02 (PTD#2040770) passed an MIT-T and a CMIT-TxIA to 2700 psi on 07/10/16,following gas lift valve work. The passing MIT's confirm two competent well barrier envelopes.The well is reclassified as Operable. Thanks, Adrienne McVey Well Integrity Superintendent—GWO Alaska (Alternate:Jack Lau) SCANNED UEC 4) 5 2016 0:(907)659-5102 C:(907)943-0296 H:2376 Email: AKDCWelllntegrityCoordinator@BP.com Fro • AK, GWO SUPT Well Integrity Sent: Tu- ,. , July 05, 2016 12:48 PM To: AK, OPS G 9 M; AK, OPS GC2 Field O&M TL; AK, OPS GC2 Wellpad Lead; AK, OPS Prod Controllers; Cismoski, Doug A; Daniel, Ryan; , WO SUPT Slickline; AK, GWO SUPT Special Projects; AK, RES GPB West Wells Opt Engr; AK, RES GPB East Wells Opt Engr; • OPS Well Pad LV; Peru, Cale; 'chris.wallace@alaska.gov'; 'Regg, James B (DOA) (jim.regg@alaska.gov)' Cc: AK, OPS FF Well Ops Comp Rep; AK, t + 0 DHD Well Integrity; AK, GWO Projects Well Integrity; AK, GWO SUPT Well Integrity; Sternicki, Oliver R; Pettus, Whitney Subject: UNDER EVALUATION: Producer V-02 (PT, ,2040770) Sustained Inner Annulus Casing Pressure Over MOASP All, Producer V-02 (PTD#20400770)was reported as having inner annulus p sure over MOASP on July 3`d 2016. IA pressure was confirmed to be 2070 psi over MOASP and subsequent TIFL faile. ' dicating a lack of two well barrier envelopes.The well is now reclassified as Under Evaluation and will be repaired or - ured within 28 days. Plan Forward: 1. Slickline:Set tubing tail plug 2. Fullbore: MIT-T&CMIT-TxIA 3. Well Integrity: Further diagnostics as required Please call with any questions or concerns. \\ 1 • . Wallace, Chris D (DOA) From: AK, GWO SUPT Well Integrity <AKDCWellIntegrityCoordinator@bp.com> Sent: Tuesday,July 05, 2016 12:48 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, GWO SUPT Slickline;AK, GWO SUPT Special Projects;AK, RES GPB West Wells Opt Engr;AK, RES GPB East Wells Opt Engr;AK, OPS Well Pad LV; Peru, Cale;Wallace, Chris D (DOA); Regg,James B (DOA) Cc: AK, OPS FF Well Ops Comp Rep;AK, GWO DHD Well Integrity;AK, GWO Projects Well Integrity;AK, GWO SUPT Well Integrity; Sternicki, Oliver R; Pettus,Whitney Subject: UNDER EVALUATION: Producer V-02 (PTD#2040770) Sustained Inner Annulus Casing Pressure Over MOASP All, Producer V-02 (PTD#20400770)was reported as having inner annulus pressure over MOASP on July 3rd 2016. IA pressure was confirmed to be 2070 psi over MOASP and subsequent TIFL failed indicating a lack of two well barrier envelopes.The well is now reclassified as Under Evaluation and will be repaired or secured within 28 days. Plan Forward: 1. Slickline: Set tubing tail plug 2. Fullbore: MIT-T&CMIT-TxIA 3. Well Integrity: Further diagnostics as required Please call with any questions or concerns. Ryan Holt (Alternate: i ec (,rey) BP Alaska Well Inteity Global Wells < TED DEC 0 92016 GVV Organization Office: 907.659.5102 WIC Email:AKDCWeIIIntegrityCoordinator@bp.com From: AK, C Well Integrity Coordinator Sent: Friday, Se• -mber 26, 2014 10:19 PM To: AK, OPS GC2 OS` . , OPS GC2 Field O&M TL; AK, OPS GC2 Wellpad Lead; AK, OPS Prod Controllers; Cismoski, Doug A; Daniel, Ryan; AK, Pe ireline Operations Team Lead; AK, D&C Well Services Operations Team Lead; AK, RES GPB West Wells Opt Engr; AK, RES '' ast Wells Opt Engr; AK, OPS Well Pad LV; Burton, Kaity; 'chris.wallace@alaska.gov'; 'Regg, James B .,*A) (jim.regg@alaska.gov)' Cc: AK, OPS FF Well Ops Comp Rep; AK, D&C D ell Integrity Engineer; AK, D&C Projects Well Integrity Engineer Subject: OPERABLE: Producer V-02 (PTD #2040770)'• 'ng TIFL demonstrates barriers All, Producer V-02 (PTD#20400770) had a passing TIFL performed on September 24, _ ! 4,demonstrating competent downhole barriers.At this time,the well has been reclassified as Operable and may re online as needed. Thank you, 1 STATE OF ALASKA ' ALASKA AND GAS CONSERVATION COMMIS . REPORT OF SUNDRY WELL OPERA 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: 5. Permit To Drill Number: BP Exploration (Alaska) Inc. ® Development ❑ Exploratory .• 204 - 077 3. Address: ❑ Service ❑ Stratigraphic 6. API Number: P.O. Box 196612, Anchorage, Alaska 99519 - 6612 - 50 - 029 - 23209 - 00 - 00 7. Property Designation: 8. Well Name and Number: ADL 028240 - PBU V-02 9. Field / Pool(s): Prudhoe Bay Field / Prudhoe Bay Oil Pool 10. Present well condition summary Total depth: measured 15086 feet Plugs (measured) None feet true vertical 8938 feet Junk (measured) None Effective depth: . measured 14996 feet Packer: (measured) 8993 feet true vertical 8947 feet Packer. (true vertical) 8551' feet Casing Length Size MD TVD Burst Collapse Structural Conductor 80' 20" 109' 109' 1490 470 Surface 2683' 9-5/8" 2712' 2708' 5750 3090 Intermediate 9229' 7" 9255' 8749' 7240 5410 Production Liner 6030' 4-1/2" 9054' - 15084' 8596' - 8939' 8430 7500 Perforation Depth: Measured Depth: 9585' - 14985' ,• True Vertical Depth: 8949' - 8948' Tubing (size, grade, measured and true vertical depth): 3 -1/2 ", 9.2# L -80 9064' 8604' Packers and SSSV (type, measured and true vertical depth): 7" x 3 Baker Prem Packer 8993' 8551' 11. Stimulation or cement squeeze summary: RECEIVE.* Intervals treated (measured): Treatment description including volumes used and final pressure: t; f Alaska Gil & Gas Cons. &emission Anclerage 12. Representative Daily Average Production or Injection Data Oil -Bbl Gas -Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: 245 385 288 1,280 580 Subsequent to operation: 249 362 319 1,540 220 13. Attachments: ❑ Copies of Logs and Surveys run 14. Well Class after work: ❑ Exploratory ® Development ❑ Service ❑ Stratigraphic ® Daily Report of Well Operations ® Well Schematic Diagram 15. Well Status after work: ❑ GINJ f ® Oil ❑ SUSP ❑ WDSPL ❑ Gas ❑ GSTOR ❑ SPLUG ❑ WAG ❑ WINJ 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. Exempt: Contact Matt Ross, 564-5782 N/A Printed Name erne Hubble Title Drilling Technologist �� Prepared By NamelNumber Signature • Phone 564 - 4628 Date D 1 1 11 Terrie Hubble, 564 - 4628 Form 10-404 Revised 10/2010 RSDMS APR g - , Y Z` !� Submit Original Only • V -02, Well History (Pre Rig Work) Date Summary 03/05/11 WELL FLOWING ON ARRIVAL. LRS LOADS TBG W/ 93 bbls OF CRUDE, LOADS IA W/ 364 bbls OF CRUDE & 5 bbls NEAT. DRIFT TBG W/ 2.75" GUAGE RING, TAG XN -NIP @ 9021' SLM / 9040' MD, NO OBSTRUCTIONS. SET 3 -1/2" PXN PLUG IN XN -NIP @ 9021' SLM / 9040' MD. 03/06/11 LRS HAS PERFORMED A CMIT -T /IA TO 3000 psi DURING THE NIGHT, TEST PASSES. PULLED 3- 1/2" PXN FROM XN -NIP @ 9021' SLM / 9040' MD. WELL LEFT S/I ON DEPARTURE, PAD OP NOTIFIED. 03/12/11 T /I /0= 200/1500/750, Temp =Sl. PPPOT-T (PASS), pre CTD. PPPOT -T: Stung into test port (500 psi), bled to 0 psi. Functioned LDS, all moved freely (1 "). Pumped through void, good returns. Pressured void to 5000 psi for 30 min test, lost 200 psi in 15 min, lost 100 psi in second 15 min (PASS). Bled void to 0 psi. 03/13/11 T /I /0 = 600/1700/725 Tried to ensure integrity of IA valve. Gate would not hold. Grease crew came and serviced valve. 0 psi pressure build up after valve was serviced. Removed companion flange and installed 2 1/16 5K CIW gate valve on the outside of existing IA valve. Installed companion flange and torqued both flanges to spec. Tested to 500/5000 psi for 5 min against gate of inside valve. Tests passed. Job Complete. I I Page 1 of 1 North. America - ALASKA . = BR' Pogo 1 of tO Operation Summary Report Common Well Name: V -02 AFE No Event Type: WORKOVER (WO) Start Date: 3/22/2011 I End Date: 3/27/2011 I X3 -OOYPP (1,468,521.00 ) Project: Prudhoe Bay I Site: PB V Pad Rig Name /No.: NORDIC 2 Spud Date/Time: 5/18/2004 12:00:00AM Rig Release: 3/27/2011 Rig Contractor: NORDIC CALISTA UWI: 50029232090000 - --- -- - - - - -- - - - -- - - -- - Active Datum: V -02 @81.60ft (above Mean Sea Level) Date � From - To 1 Hrs Task Code NPT ! NPT Depth I Phase 1 Description of Operations , (hr) ! (ft) 3/22/2011 100:00 - 03:30 j 3.50 MOB P ' PRE HOLD PJSM WITH RIG CREW, TOOLPUSHERS, WSL, CHECK 6 ON MOVING OFF OF S-01. DISCUSS THE IMPORTANCE OF COMMUNICATION, NEARBY WELLS, pDRILLER'S FIRST TIME MOVING RIG. PAD OPERATOR WAIVED WITNESSING RIG BACK OFF OF WELL. ' ! 'MOVE RIG OFF OF S-02 AND STAGE ON THE PAD. ' I 03:30 11:00 7.50 MOB P PRE 1.HOLD PJSM WITH RIG CREW, TOOLPUSHER, WSL, CHECK 6AND SECURITY ESCORT ON MOVING RIG. DISCUSS IMPORTANCE OF COMMUNICATION, ROUTE OF TRAVEL, i POSITIONS OF PEOPLE, PROPER PPE FOR I WORKING OUTDOORS. i MOVE RIG FROM S PAD TO V PAD. 11:00 12 00 1.00 � MOB PRE PREP AREA AROUND WELL FOR SPOTTING I P 1 1 ' RIG. 12 :00 - 13:00 1.00 MOB P PRE I HOLD PJSM ON SPOTTING RIG OVER WELL. I I MOVE RIG OVER WELL AND SET DOWN. WITNESSED BY BOTH NORDIC t LTTOOLPUSHERS. I 4: - 1.50 I ,— - -. MOB P PRE ,ACCEPT RIG AT 1300 -HRS. RU HANDY BERM AND CELLAR EQUIPMENT. 14:30 - 17:30 3.00 BOPSUR P 1 PRE HOLD PJSM ON ND TREE CAP / NU BOP STACK. REMOVE TREE CAP. NU BOP STACK ON SWAB FLANGE. ,17:30 18:30 1.00 BOPSUR P 1 PRE I HOLD RIG EVAC AND H2S DRILL. 1 L V PAD IS AN H2S PAD. ,HOLD AARON DRILL. 18:30 - 20:00 1.50 BOPSUR P I PRE RU FOR WEEKLY BOPE TEST. 1 1GREASE CHOKE. ,- FILL BOP STACK. _ 20 00 - 00:00 PRE 4.00 BOPSUR P I HOLD PJSM ON PERFORMING WEEKLY BOPE TEST. PERFORM WEEKLY BOPE TEST. 1 I TEST TO 250 -PSI LOW AND 3500 -PSI HIGH QDP 1 FOR ALL TESTS. p HOLD AND CHART EACH TEST FOR I 5- MINUTES. 'TEST 2 -3/8" COMBIS, 2 -3/8" X 3 -1/2" VBRS AND I ANNULAR USING 2 -3/8" TEST JT. ALL TESTS WITNESSED BY NORDIC TOOLPUSHER, BP WSL AND AOGCC REP LOU GRIMALDI. I 1 BEGIN TAKING ON 8.6 -PPG RECYCLED POWERVIS MUD TO PITS. 3/23/2011 00:00 - 03:30 1 3.50 BOPSUR P PRE I CONTINUE WEEKLY BOPE TEST. TEST TO 250 -PSI LOW AND 3500 -PSI ON ALL ,TESTS. HOLD AND CHART EACH TEST FOR 5- MINUTES. TEST 2 -3/8" COMBIS, 2-3/8" X 3-1/2" VBRS AND ' I ANNULAR USING 2 -3/8" TEST JT. ALL TESTS WITNESSED BY BP WSL, NORDIC I 1 TOOLPUSHER AND AOGCC REP LOU ' I GRIMALDI. Printed 4/20/2011 4:08:00PM h A ALASKA BP Page 2 OLIO Operation Summa; Report Common Well Name: V -02 I AFE No Event Type: WORKOVER (WO) Start Date: 3/22/2011 End Date: 3/27/2011 X3 -00YPP (1,468,521.00 ) Project: Prudhoe Bay Site: PB V Pad Rig Name /No.: NORDIC 2 Spud Date/Time: 5/18/2004 12:00:00AM ' Rig Release: 3/27/2011 Rig Contractor: NORDIC CALISTA UWI: 50029232090000 Active Datum: V -02 @81.60ft (above Mean Sea Level) Date From - To I Hrs Task I Code I NPT I NPT Depth Phase 1 Description of Operations 1 04 00 0.50 I BOPSUR P (ft) (hr) 03 30 - 1 PRE , RD ROPE TEST EQUIPMENT. 04:00 05:00 1 1.00 I RIGU P 1 1 PRE i HOLD RIG EVACUATION/H2S DRILL WITH RIG 1 ',AND SLB CREWS. I I HOLD AAR AND HIGHLIGHT THAT EVERYONE RESPONDED CORRECTLY AND THAT THE ONE EXTRA PERSON ON LOCATION (CH2MHILL TRUCK DRIVER) WAS ALERTED AND RESPONDED CORRECTLY AS WELL HOLD PRE -SPUD MEETING. DISCUSS PLANNED PERFORATION RUNS, HAZARDS ASSOCIATED WITH RUNNING PERF GUNS, AND WELL CONTROL CONSIDERATIONS I ' 1 WITH A FOCUS ON KILLING THE WELL AND 1 I HANDLING FLUID LOSSES. 105:00 - 06:00 I 1.00 RIGU P PRE PREPARE TO STAB AND RU COIL. 1 PU INJECTOR HEAD. N CHANGE OUT LINE ON TUGGER FOR PULLING COIL TO GOOSENECK. I PULL TEST COIL GRAPPLE - GOOD TEST. ! I ,REMOVE COIL CLAMPS, CHAIN AND SHIPPING BAR. 06:00 - 09:00 I 3.00 RIGU P I PRE CREW CHANGE AND PJSM FOR PULLING ',COIL ACROSS. PULL COIL ACROSS AND STAB INTO I INJECTOR CUT COIL TO FIND E LINE I CUT 15 FT OF COIL • STAB INJECTOR ONTO WELL AND FILL COIL 09:00 - 09:30 0.50 BOPSUR P PRE PRE TEST INNER REEL VALVE AND HARD LINE 109:30 - 11:00 r 1.50 BOPSUR P PRE . .. WAIT ON AOGCC REP TO WITNESS TESTING 11:00 - 11:30 0.50 BOPSUR P . 1 PRE I PRESSURE TEST PACK OFFS AND INNER REEL VALVE TO 250 PSI LOW AND 3500 PSI HIGH_ GOOD TEST — — — 1 11:30 - 12:00 0.50 BOPSUR --- �1 P PRE ! RD TEST EQUIPMENT 12:00 - 13:30 1.50 RIGU P 1 PRE PJSM / INSTALL BTT KENDALL CONNECTOR PULL TEST TO 25K PRESSURE TEST TO 3500 PSI PUMP 5/8" DRIFT BALL THROUGH COIL AND RECOVERED SAME. I ! !,I ! I BLED IA FROM 875 PSI DOWN 350 PSI - LOTS OF GAS 13:30 - 16:00 2.50 WHSUR P DECOMP I PJSM -PU DSM LUBRICATOR AND MU LUBRICATOR EXTENSIONS PJSM - MU LUBRICATOR TO WELL AND PT i 1 FOR 250 PSI LOW AND 3500 PSI HIGH PULL 2 WAY CHECK - HAD 575 PSI WHP ICI - - -- ------- - -��— - - -- RD DSM AND MO Printed 4/20/2011 4:08:00PM rfh America - ALASKA BP?. Page 3 of 10 Operation Summary Report Common Well Name: V -02 I AFE No Event Type: WORKOVER (WO) Start Date: 3/22/2011 End Date: 3/27/2011 IX3 -00YPP (1,468,521.00 ) Project: Prudhoe Bay 1 Site: PB V Pad i Rig Name /No.: NORDIC 2 Spud Date/Time: 5/18/2004 12:00:00AM . Rig Release: 3/27/2011 Rig Contractor: NORDIC CALISTA j UWI: 50029232090000 Active Datum: V -02 @81.60ft (above Mean Sea Level) Date I From - To I Hrs I Task j Code I NPT NPT Depth ! Phase Description of Operations (hr) (ft) 16:00 - 18:00 2.00 KILLW I P DECOMP PJSM - BULL HEAD KILL WELL LEAD IN WITH 10 BBLS McOH I PUMP 170 BBLS OF KCL AT 6 BPM @ 935 PSI I PUMP PRESSURE / 915 PSI WHP IA =350 PSI :AND OA = 115 PSI SHUT DOWN PUMPS AT 170 BBLS OF KCL IN SWAP TO 8.6 PPG POWER VIS PUMP 5 BBLS THROUGH COIL CONTINUE TO BULLHEAD AT 6 BPM WHP I 'SLOWLY CLIMBING UP FROM 925 PSI TO FINAL PRESSURE OF 1600 PSI ' SD PUMPS. AND BLEED OFF CIR PRESSURE 18:00 - 19:30 1.50 KILLW P DECOMP I i SHUT WELL IN AGAINST HAND CHOKE AND 'MONITOR FOR PRESSURE DURING CREW I CHANGE OUT WELL IS ON A VAC - PULL NIGHT CAP AND VISUALLY CHECK LOSS RATE j REINSTALL NIGHT CAP AND LINE UP TO I CIRULATE DOWN KILL AND OUT CHOKE LINE ! I TO KEEP HOLE FULL WHILE GETTING MEMORY LOGGING TOOLS READY (MEMORY , LOGGER WAS STUCK BEHIND 16E RIG f MOVE) r GLOSS RATE = 14 TO 18 -BPH. 19:30 - 21:00 1.50 EVAL P OTHCMP l BENCH TEST DBPV TO 250 -PSI LOW AND 1 1500-PSI HIGH. HOLD AND CHART EACH TEST FOR 5- MINUTES. 21:00 - 21:30 0.50 EVAL P OTHCMP HOLD PJSM ON MU/RIH WITH MEMORY ! LOGGING BHA. DISCUSS WELL CONTROL CONSIDERATIONS 1 WITH REGARD TO SHEARABILITY OF BHA COMPONENTS AND MAINTAINING CONTINUOUS HOLE FILL. ! I I REVIEW BHA RUNNING ORDER. 21:30 - 22:00 0.50 EVAL P OTHCMP ATTEMPT TO MU MEMORY LOGGING BHA, I BUT UNABLE TO MU 2.72" DSM TO 2 -1/8" MOTOR USING LITTLE JERK TONGS DUE TO VERY SHORT TONG SPACING. NO TOOLS AVAILABLE AT RIG TO MU CONNECTION SAFELY AND WITH KNOWN APPLIED 1 TORQUE. 22 00 - 00 :00 ! 2.00 EVAL N WAIT f OTHCMP SEND 2.72" DSM AND 2 -1/8 MOTOR TO BAKER THRU TUBING TO BE TORQUED SAFELY AND PROPERLY. NABORS 16E MOVING FROM W -PAD IS I BLOCKING SPINE RD AT KUPARUK RIVER I BRIDGES. COORDINATE GETTING EQUIPMENT AROUND , RIG VIA TOOL SERVICE AND SECURITY. MAINTAIN CONTINUOUS HOLE FILL. LOSS -' RATE = 12 BPH. 3/24/2011 00:00 - 00:30 0.50 EVAL N WAIT OTHCMP 2.72" DSM AND MOTOR AT BAKER THRU TUBING BEING MADE UP PROPERLY TO 1000-FT /LBS Printed 4/20/2011 4:08:00PM r Amert . -�/ t ASKA EAR Page 4 oija Operation Summary Report Common Well Name: V -02 AFE No Event Type: WORKOVER (WO) Start Date: 3/22/2011 End Date: 3/27/2011 X3 -00YPP (1,468,521.00 ) Project: Prudhoe Bay Site: PB V Pad Rig Name /No.: NORDIC 2 Spud Date/Time: 5/18/2004 12:00:00AM Rig Release: 3/27/2011 Rig Contractor NORDIC CALISTA UWI: 50029232090000 Active Datum: V -02 @81.60ft (above Mean Sea Level) Date From - To Hrs Task Code NPT NPT Depth Phase Description of Operations (hr) — (ft) 00:30 - 00:45 0.25 EVAL P OTHCMP HOLD PJSM WITH TCP CREW ON LOADING PERF GUNS INTO PIPE SHED. HIGHLIGHT DROPPED OBJECTS POTENTIALS ,AND IMPORTANCE OF HAZARD , COMMUNICATION. 'REVIEW PIPE SHED LOADING PROCEDURE. LOSS RATE = 7 -BPH. 00:45 - 01:45 1.00 EVAL P OTHCMP BEGIN LOADING PERF GUNS FOR FIRST PERF RUN. MILL AND MOTOR ARE TORQUED AND EN 1 _ 1 ROUTE TO THE RIG VIA TOOL SERVICE. 01:45 - 02:45 1.00 EVAL P OTHCMP I BRING MILL AND MOTOR TO RIG FLOOR. MU MEMORY LOGGING BHA. BHA CONSISTS OF 2.72" GO/ 2.73" NOGO DSM 2 -1/8" MOTOR, GR/CCL CARRIER, 1/2" CIRC SUB, 5/8" DISCONNECT, DBPV, XO, 14 -JTS OF 2-1/16" CSH TBG, XO, BAKER QC, IXO, BAKER KENDAL CTC. ' OAL = 152.42' 02:45 - 06:00 3.25 EVAL P OTHCMP 1 STAB ON COIL TUBING INJECTOR. TOOK 4 -BBLS TO GET RETURNS. - I RIH WITH GR/CCL MEMORY LOGGING BHA AT _ 0 90 -FPM TO 12850'. PUMP AT .4 -BPM WITH 600 -PSI ICP / 1200 -PSI j FCP. PRESSURE RISES STEADILY WHILE RIH. LOSS RATE = -20 -BPH WHILE RIH. WT CHECK AT 9000'. PU WT = 38K -LBS. DID NOT "SEE" ANY OF THE COMPLETION 'JEWELRY IN THE 3 -1/2" TBG. IA PRESSURE = 354 -PSI. WT CHECK AT 12,850' = 42K -LBS. TOTAL LOSSES FOR TRIP TO BOTTOM = 63 -BBLS. 06:00 07:30 1.50 EVAL P OTHCMP MEMORY LOG UP FROM 12850' TO 12100' AT 145 -FPM. PUMP AT .9 -BPM WITH 1500 -PSI. PAINT EOP © 12293 FT UNCORRECTED - YELLOW PU AND LOG FROM 9750 TO 9450 , I PAINT WHITE EOP @ 9400 FT LOG FROM 9450 TO 9200 FT 07:30 - 10:00 2.50 EVAL P OTHCMP POOH WITH FLOW CHECK @ 9200 FT, 5850 , FT, AND 100 FT HELD PJSM FOR LD OF BHA WHILE POOH 10:00 - 11:30 1.50 EVAL P OTHCMP STOP AT 100 FT AND UNSTAB INJECTOR, STRIP OUT OF HOLE FINAL 100 FT. HELD PIN HOLE DRILL AND SPILL DRILL IN 1 I REEL HOUSE AT THIS POINT - GOOD RESPONSE FROM CREWS. I I LD MEMORY LOGGING BHA AND RD MEMORY , LOGGER. 11 :30 - 13:00 1.50 PERFOB P 1 OTHCMP PJSM - BRING TOOLS TO RIG FLOOR RU TO PU PERF GUNS Printed 4/20/2011 4:08:00PM �A a a-A S A ., salt) , Page Operation Summary Report Common Well Name: V -02 I AFE No Event Type: WORKOVER (WO) I Start Date: 3/22/2011 ' End Date: 3/27/2011 `X3 -00YPP (1,468,521.00 ) I Project: Prudhoe Bay I Site: PB V Pad Rig Name /No.: NORDIC 2 I Spud Date/Time: 5/18/2004 12:00:00AM I Rig Release: 3/27/2011 Rig Contractor: NORDIC CALISTA UWI: 50029232090000 Active Datum: V -02 ©81.60ft (above Mean Sea Level) Date I From - To I Hrs I Task ; Code I NPT I NPT Depth I Phase Description of Operations 13:00 - 20:00 , 7.00 PERFOB P � (ft) OTHCMP I PJSM - PU PERF 115 PERF GUNS I STOP AT GUN 5 TO EVALUATE JOB FLOW 1 AT GUN 10 FILL HOLE AND HAVE KICK WHILE (TRIPPING DRILL WITH UNSHEARABLE I EQUIPMENT ACROSS STACK. HAD SMALL AAR ON RIG FLOOR FOLLOWING GOOD DRILL WITH NO MAJOR LESSONS LEARNED. 20:00 - 20:45 0.75 PERFOB P OTHCMP I HOLD PJSM ON MU FIRING HEAD AND 2- 1/16" CSH. I MU PERF GUN RUNNING BHA. BHA CONSISTS OF: BULLNOSE, PERF GUNS PER PLAN , E-FIRE FIRING HEAD, 5/8" DISCONNECT, DBPV, XO, 4 -JTS OF 2- 1/16" CSH TBG, XO, BAKER QC, XO AND CTC. OAL = 2588.21' - O 20:45 - 00:00 3.25 PERFOB P , OTHCMP PU INJECTOR AND STAB ON COIL. j FILL WELL WITH -8.6 -PPG RECYCLED j 1 I PQWERVIS. TOOK 1.5 -BBLS TO GET l RETURNS. 1 I 1 I RIH AT 80 -FPM, CIRCULATING AT .3 -BPM WITH 540 -PSI INITIALLY AND 1400 -PSI BY 12,400'. WT CHECK AT 9000'. PU WT = 39K -LBS. CONTINUE TO RIH WITH ABOVE I PARAMETERS. SLOW DOWN TO 48 -FPM AT 12,400' TO KEEP PUMP PRESSURE AT .3 -BPM BELOW 1500 -PSI } TRIP. --------- -- 3/25/2011 00:00 00:45 0.75 PERFOB OTHCMP CONTINUE TO RIH WITH PERF GUN RUN #1 I TO FLAG. RESET PUMP TRIP TO 1800 -PSI PER SLB TCP REP TO KEEP PUMP RATE CONSTANT. RIH AT 65 -FPM, CIRCULATING AT .3 -BPM WITH 1580 -PSI. 30 -BBLS LOST DURING RIH WITH PERF GUNS. 00:45 - 01:00 0.25 PERFOB P 1 OTHCMP AT FLAG 14887' PER CTDS. APPLY -17' DEPTH CORRECTION TO 14870'. CONTINUE TO RIH AT 20 -FPM CIRCULATING j AT .3 -BPM WITH 1500 -PSI TO 14,970'. I PU HOLE WITH PU WT = 45K -LBS TO , POSITION BOTTOM SHOT AT 14952' 1101:00 - 01 :30 F 0.50 PERFOB P OTHCMP ESTABLISH RATE/PRESSURE FOR E -FIRE FIRING SEQUENCE. I i 1.3 -BPM AT 1500 -PSI AND 1.5 -BPM WITH 1 2700 -PSI. MARK PUMP RHEOSTAT IN PREP I FOR FIRING. PERFORM FIRING SEQUENCE PER SLB TCP I REP. 5 -BBLS PUMPED TO PERFORM SEQUENCE. GOOD INDICATION OF GUNS FIRING AT I SURFACE - PRESSURE DROPS OFF I IMMEDIATELY AND LOSE RETURNS. I ABLE TO MOVE UP HOLE SLOWLY WITHOUT I ISSUE. TAKES 8 -BBLS TO GET RETURNS. Printed 4/20/2011 4:08:00PM • rth America - ALASKA BP Page,6 of 'E0 O ration Summary F eppiort Common Well Name: V -02 AFE No Event Type: WORKOVER (WO) Start Date: 3/22/2011 I End Date: 3/27/2011 X3 -00YPP (1,468,521.00 ) Project: Prudhoe Bay Site: PB V Pad Rig Name /No.: NORDIC 2 , Spud Date/Time: 5/18/2004 12:00:00AM Rig Release: 3/27/2011 Rig Contractor: NORDIC CALISTA UWI: 50029232090000 Active Datum: V -02 @81.60ft (above Mean Sea Level) Date From - To 1 Hrs Task Code I NPT NPT Depth Phase Description of Operations (hr) _— (ft) 01:30 - 06:30 5.00 PERFOB P OTHCMP ESTABLISH CIRCULATION THROUGH THE KILL LINE, ACROSS THE TOP OF THE WELL, HOLDING 400 -PSI BACK PRESSURE ON THE WELL. POH AT 40 -FPM FROM 14952' TO 14600'. 1 1 PERFORM 15- MINUTE FLOW CHECK - NO FLOW. 1 LINE UP AND CIRCULATE BOTH DOWN COIL AND BACKSIDE, HOLDING 400 -PSI BACK - 1PRESSURE WITH CHOKE. CONTINUE TO POH AT 60 -FPM, CIRCULATING 1 AT 1.3 -BPM WITH 1680 -PSI. 10 -BPH LOSS 1 I RATE. I REPAINT FLAG AT 9400' UNCORRECTED FOR I TIE IN ON NEXT PERF RUN. CONTINUE TO POH AT 60 -FPM FROM 11988' TO 11,600'. i I FLOW CHECK WELL AT 11600' - NO FLOW. CONTINUE TO POH FROM 11,600' at 70 -FPM 1 I WHILE CIRCULATING DOWN COIL AND I ACROSS THE TOP OF THE WELL, HOLDING , 400 -PSI WHP. I 'LOSS RATE 4 -6 BPH WHILE POH. 06:30 - 09:00 2.50 PERFOB P OTHCMP CIRCULATE TO CLEAN UP GUNS AND "LUBRICATOR. FLOW CHECK WELL AND PJSM FOR LD OF GUN RUNNING TOOLS 09:00 - 09:30 0.50 PERFOB P OTHCMP UNSTAB INJECTOR AND LD RUNNING TOOLS HAD FLOOR VALVE DRILL TO SECURE WELL FOR TCP CHANGE OUT 09:30 - 10:00 l i 0.50 PERFOB P ; OTHCMP RU TO LD GUNS AND FIRE DRILL IN SCR I ROOM AAR FOR FIRE DRILL WITH GREAT 'RESPONSE BY ALL 10:00 - 18:00 8.00 PERFOB 1 P OTHCMP 1 LD PERF GUNS FIRST 20 GUNS HAD TRAPPED PRESSURE TO THEM - MAINLY IN THE TOP BLANK INTERVAL AREA. ' 18:00 - 21:00 3.00 PERFOB P 1 I OTHCMP I HOLD PJSM ON LOADING PIPE SHED WITH I GUNS FOR PERF RUN #2. LOAD GUNS FOR PERF RUN #2 ON TOP OF I SPENT GUNS FROM RUN #1. 1 SLB TCP LAY OUT RUNNING ORDER AND I CONFIRM WITH WSL. I MAINTAIN CONTINUOUS HOLE FILL WITH LOSS RATE OF —1 -BPH. 1 21:00 - 00:00 3.00 r PERFOB ' P OTHCMP HOLD PJSM ON RUNNING PERF GUNS WITH � RIG CREW AND SLB TCP. DISCUSS POSITIONS OF PEOPLE, REVIEW 1 PROCEDURE FOR RUNNING PERF GUNS. 1 1 I RIH WITH 78(EA) 2" PERF GUNS PER I I RUNNING ORDER. 1 1 I HUDDLE UP AFTER RUNNING 5 -GUNS AND 1 I DISCUSS HOW THE JOB IS GOING. EVERYONE SATISFIED AND 1 COMMUNICATING WELL. CONTINUE TO RIH WITH 2" PERF GUNS PER RUNNING ORDER TO 1045 3/26/2011 1 00:00 - 02:30 1 2.50 PERFOB I OTHCMP I CONTINUE TO MU PERF RUN #2 BHA FROM 1 1045' to 1799'. Printed 4/20/2011 4:08:00PM aprth: America ALASKA - BP Page of'c Operation Summary Report Common Well Name: V -02 AFE No Event Type: WORKOVER (WO) Start Date: 3/22/2011 End Date: 3/27/2011 `X3 -00YPP (1,468,521.00 ) Project: Prudhoe Bay I Site: PB V Pad Rig Name /No.: NORDIC 2 Spud Date/Time: 5/18/2004 12:00:00AM I Rig Release: 3/27/2011 Rig Contractor NORDIC CALISTA UWI: 50029232090000 Active Datum: V -02 @81.60ft (above Mean Sea Level) Date From - To Hrs I Task Code I NPT NPT Depth Phase Description of Operations (hr) (ft) 02:30 - 07:00 4.50 PERFOB OTHCMP I MU INJECTOR TO PERF GUN BHA AND STAB I ONTO WELL. I RIH AT 75 -FPM FROM 1799'. CIRCULATE AT .3 -BPM WITH 600 -PSI INITIALLY. PUMP PRESSURE INCREASES SLOWLY DURING RUN TO 1480 -PSI. PERF GAS BREAKING OUT AT THE POSSUM BELLY. CHECK WITH GAS MONITOR - CARBON MONOXIDE. GAS CAUSING MICROMOTION LOSE READING PERIODICALLY. STOP TRIPPING AND CIRCULATE UNTIL WELL CLEAN AND MICROMOTION READINGS RETURN TO NORMAL. 1 PVT AND MANUAL PIT STRAPS SHOW LOSS I ( RATE OF -2 -BPH. i ! STAGE IN WELL CIRCULATING CLEAN AS ?NEEDED- CONTINUE RIH- TO FLAG AT 9400' EOP IUNCORRECTED. LOST 16 -BBLS DURING TRIP IN THE WELL. 07 :00 - 08:05 I 1.08 I PERFOB ' OTHCMP 'OBTAIN PU WT AT FLAG - 42K -LBS. FLAG AT 11,212.T ON CTDS. APPLY -24.1' 't DEPTH CORRECTION AND RESET CTDS. RIH TO 11,262' AND PU TO FIRING POSITION AT 11,240'. j ESTABLISH RATES & PRESSURE FOR FIRING SEQUENCE - .3 -BPM @ 1270 -PSI / 1.5 -BPM @ 2650 -PSI. PERFORM E -FIRE FIRING SEQUENCE PER SLB TCP. GOOD INDICATION OF FIRE ON METER AND PULLING A LITTLE HEAVY AT 47 -47K TOOK 3 BBLS TO START GETTING PARTIAL IRETURNS Q= 1.2/.3 BPM 08:05 - 09:40 1.58 PERFOB OTHCMP POOH WITH PERF GUNS CIRCULATE THROUGH COIUFIRING HEAD AND DOWN BACK SIDE OF COIL W/ 340 PSI WHP LOST 10 BBLS IN FIRST 1000 FT PULLING SLOW STOP AND FLOW CHECK AT 9000 FT WITH ALL GUNS OUT OF PERF INTERVAL - NO FLOW CONTINUE TO POH WITH .5 BPM DOWN COIL AND 1.0 ACROSS THE TOP AND 400 PSI WHP 09:40 10:30 0.83 PERFOB OTHCMP STOP AT 8400 FT AND FLOW CHECK AS IN & OUT MM WITH CURRENT FLOW PATH IS CONFUSING THE FACTS & PVT IS ACCURATE WITH NO GAINS. -- NO FLOW LINE UP TO CIRC DOWN COIL ONLY AND ESTABLISH CIR RATES/LOSSES Q =1.05 / .99 BPM @1780 BBLS CBU FROM 8400 FT - CLEAN NO GAS BUT WE 'ARE BRING OUT SOME DIRTY GUN RESIDUE / GUNK. Q= 1.04/1.03 WITH NO BACK PRESSURE ADD 300 PSI WHP= 1.04/0.85 BPM Printed 4/20/2011 4:08:00PM •rth Ar erica - ALASKA B Operation Summary Report Common Well Name: V -02 ! AFE No Event Type: WORKOVER (WO) ! Start Date: 3/22/2011 End Date: 3/27/2011 i X3 -00YPP (1,468,521.00 ) Project: Prudhoe Bay Site: PBVPad 1 Rig Name /No.: NORDIC 2 Spud Date/Time: 5/18/2004 12:00:00AM i Rig Release: 3/27/2011 Rig Contractor: NORDIC CALISTA I UWI: 50029232090000 Active Datum: V -02 @81.60ft (above Mean Sea Level) Date From - To Hrs Task Code 1 NPT NPT Depth 1 Phase Description of Operations ; (hr) (ft) I ; 10:30 - 12:00 ; 1.50 PERFOB I OTHCMP POH @ 65 FPM & Q =1.05/.66 BPM LOSS RATE OF 0.04 BPM I CP =1870 PSI WHP =315 PSI TOTAL LOSS ON TOH 17 BBLS 112:00 - 13 :20 1.33 PERFOB OTHCMP ` CIRCULATE OUT TRAPPED CO FROM GUNS PJSM FOR LD OF RUNNING TOOLS i FLOW CHECK WELL - NO FLOW 13:20 - 14:00 0.67 PERFOB OTHCMP UNSTAB INJECTOR AND STAND BACK LD GUN RUNNING TOOLS 1 14:00 - 14:25 0.42 PERFOB OTHCMP `°PJSM FOR LD OF PERF GUNS WITH SLB, NORDIC AND, SLB TCP CREWS 1 14:25 - 20:00 j 5.58 PERFOB OTHCMP LD SPENT PERF GUNS 20:00 - 22:00 2.00 DHEQP POST I CLEAN & CLEAR RIG FLOOR. TEST DBPV TO 250-PSI LOW AND 1500 -PSI. HOLD AND CHART EACH TEST FOR 5= MINUTES. I'DHD SHOOT IA FLUID LEVEL. ' ** *** FLUID LEVEL IS AT 3510'. * * * ** 22:00 - 00:00 2.00 DHEQP POST MU NOZZLE BHA AND STAB ON INJECTOR. RIH WITH NOZZLE BHA AT 100 -FPM WITH 1 - 11.8 -BPM AT 1900 -PSI. 3/27/2011 00:00 - 00:30 0.50 DHEQP P POST CONTINUE TO RIH WITH NOZZLE BHA AT 100 -FPM TO 9500'. I I 'PUMP AT 00:30 - 02:30 2.00 DHEQP P I POST DISPLACE WELL TO 8.4 -PPG KCL AT 2.3 -BPM 1 WITH 2600 -PSI. ONCE KCL ALL THE WAY AROUND, LOSS j , RATE CLIMBS TO 18 -BPH WHILE PUMPING AT 1 , 2.3 -BPM WITH 3000 -PSI.\ 1 I REDUCE PUMP RATE TO .8-BPM WITH 560 -PSI AND MAINTAIN 1 FOR 1 RETURNS. 02 :30 - 04:00 1.50 DHEQP P ' I POST I HOLD PJSM WITH LRS ON PUMPING DIESEL ' FREEZE PROTECTION. SPOT LRS UNIT AND LRS PT LINES TO 13500 -PSI. 1 , 1 POH TO 2000' AT 100 -FPM. LOSS RATE j NEGLIGIBLE. 04:00 - 05:30 1.50 , WHSUR P POST I OPEN UP LRS TO COIL. I LRS PUMP 26 -BBLS OF 70- DEGREE 6.8 -PPG 1 ! DIESEL INTO THE REEL AT 2 -BPM WITH 1 1250 -PSI. I POH AT 85 -FPM, LAYING IN DIESEL FREEZE PROTECTION. WELL FREEZE PROTECTED TO 2000'. I LEAVE 6 -BBLS OF DIESEL IN COIL TO I FREEZE PROTECT FOR MOVE. 05:30 - 06:00 0.50 WHSUR P POST CLOSE MASTER & SWAB VALVE. I BLOW DOWN KILL LINE I UNSTAB INJECTOR AND LD NOZZLE BHA. 06:00 - 06:30 0.50 WHSUR P I POST CREW CHANGE, PJSM'S, WALK AROUNDS - GREASE CREW SERVICED TREE 06:30 - 07:35 1 1.08 WHSUR P 1 POST BLOW DOWN KILL LINE AND BLOW BACK COIL FOR RIG MOVE UNSTAB AND STAND BACK INJECTOR Printed 4/20/2011 4:08:00PM rthAinertca ALAS BP Page aP 1 O Operation Summary R eport Common Well Name: V -02 AFE No Event Type: WORKOVER (WO) Start Date: 3/22/2011 End Date: 3/27/2011 X3 -00YPP (1,468,521.00 ) Project: Prudhoe Bay Site: PB V Pad Rig Name /No.: NORDIC 2 Spud Date/Time: 5/18/2004 12:00:00AM ' Rig Release: 3/27/2011 Rig Contractor: NORDIC CALISTA UWI: 50029232090000 Active Datum: V -02 @81.60ft (above Mean Sea Level) Date From - To I Hrs Task I Code NPT NPT Depth I Phase Description of Operations (hr) 1 (ft) 07:35 - 11:15 3.67 WHSUR P I I POST -PJSM FOR BRINGING DSM LUBRICATOR TO I FLOOR AND RU -BRING IN DSM LUBRICATOR AND RU I -PJSM FOR SET AND TEST OF BPV -STAB ON LUBRICATOR WITH BPV 1 -PT LUBRICATOR TO 250 LOW AND 3500 HIGH -AND CHART ' -HAVE LRHOS FILL IA WITH DIESEL AND PRESSURE UP TILL WE CAN SEE WHP 1 STARTING. PRESSURES - WHP=0 IA =365 PSI (FLUID AT 3500 Fl) OA =250 PSI -AS WE FILLED IA WITH DIESEL IA 1 PRESSURE -FELL TO - 100 PSI BEFORE (STARTING TO PRESSURE UP AGAIN AT 67 BBLS IA =225 PSI AND WHP = 181 PSI -SD AND SET BPV ' -PRESSURE UP. TO TEST BPV - AT 400 PSI I BPV STARTED TO LEAK SD PUMPS WITH IA =400 PSI AND WHP =70 WITH FLOW OUT WHITEY VALVE ' -SD PUMPS AT 73 BBLS AND BLEED OFF ,PRESSURE 11:15 - 12:00 0.75 j WHSUR P I POST !PJSM - UNSTAB LUBRICATOR AND INSTALL BPV PULLING TOOL STAB ON PT LUBRICATOR TO 250/3500 PSI 1 PULL BPV AND UNSTAB SAME T ' NO VISABLE REASON AS TO WHY IT LEAKED 112:00 - 12 :30 0.50 WHSUR I P - POST I NORDIC CREW CHANGE, PJSM'S AND WALK L 12:30 - 14:40 1 2.17 WHSUR I P j POST I CHANGE OUT BPV AND STAB ON PT- 250/3500 PSI WITH MULTIPLE ATTEMPTS ! TO GET AIR OUT OF LUBRICATOR SET BPV AND TEST I LRHOS PUMPED UP IA TO 500 PSI AND TRIED TO MAINTAIN PRESSURE FOR A ROLLING TEST FOR 5 MIN WITH 0 PSI WHP I SD PUMPS FOR A TOTAL OF 86 BBLS DIESEL PUMPED INTO IA. j — I SD AND BLEED OFF PRESSURE 14:40 - 18:30 3.83 WHSUR P ! POST I RD LRHOS FROM IA AND RELEASE I RU AND BLEED OFF IA AND OA PRESSURES TO TIGER TANK I INITIAL PRESSURES OF IA = 107 PSI AND OA = 220 PSI BLED IA TO 25 PSI AND OA TO 0 -PSI. 1 18:30 - 21:00 2.50 1 BOPSUR P POST OPEN ALL BOP RAM DOORS AND VISUALLY INSPECT PER NORDIC PREVENTATIVE MAINTENANCE PLAN. ALL RAMS IN GOOD CONDITION. 1 21:00 - 22:30 1.50 BOPSUR P POST HOLD PJSM WITH RIG CREW ON ND BOP STACK. DISCUSS POSITIONS OF PEOPLE, TETHERED TOOLS, RESTRICTED ACCESS TO THE CELLAR AND PROPER USE OF HAMMER WRENCHES. PULL LUBRICATOR AND CHECK BAG CONDITION. I ND BOP STACK. I I2 BARRIERS FOR ND BOP STACK ARE 1) I 1 I MASTER VALVE, 2) SWAB VALVE. I 'ADDITIONAL BARRIER - TESTED BPV. CH2MHILL MOVES SATELLITE OFFICE TO Y ',,.....,. I PAD. Printed 4/20/2011 4:08:00PM , rth America- AIASKABP 4000 -PSI AND CHART EACH T EST to of FOR to Operation. Summary Report Common Well Name: V -02 AFE No Event Type: WORKOVER (WO) I Start Date: 3/22/2011 End Date: 3/27/2011 X3 -00YPP (1,468,521.00 ) Project: Prudhoe Bay I Site: PB V Pad f Rig Name /No.: NORDIC 2 Spud Date/Time: 5/18/2004 12:00:00AM Rig Release: 3/27/2011 Rig Contractor: NORDIC CALISTA UWI: 50029232090000 Active Datum: V -02 @81.60ft (above Mean Sea Level) Date From - To Hrs Task Code NPT NPT Depth ' Phase Description of Operations Jr) h (ft) 22:30 - WHSUR j P POST I NU TREE CAP. TEST TREE CAP TO 250 -PSI LOW AND 1 5- MINUTES. GOOD TESTS. I SECURE WELL. TBG/IA/OA = BPV /25/0. RELEASE RIG AT MIDNIGHT. Printed 4/20/2011 4:08:00PM TWELREE = 4- 1116" CNV I SAFETY N WELL ANGLE> 70° @ 9663' I EL = FMC V-O2 ACTUATOR = N/A KB. ELEV = 81.60' BF. ELEV = 53.1' — 980' I-I -518" TAM PORT COLLAR KOP= 9920' DRLG DRAFT Max Angle = 96° @ 9924' Datum MD = 9449' ' I 1933' H 3 -1/2" HES X NIP, ID = 2.813" 1 Datum TVD = 8800' SS GAS LIFT MANDRELS ST MD TVD DEV TYPE VLV LATCH PORT DATE 19 -5/8" CSG, 40 #, L -80 BTC, ID = 8.835" H 2712' 8 2012 2009 1 MMG DOME RK 16 04/06/06 7 3288 3284 0 MMG DMY RK 0 06/17/04 6 4177 4173 1 MMG DOME RK 16 04/06/06 5 5105 5101 1 MMG DMY RK 0 06/17/04 4 5780 5776 1 MMG DOME RK 16 04/06/06 3 6392 6388 2 MMG DMY RK 0 06/17/04 2 6986 6981 8 MMG DOME RK 16 04/06/06 17" HES ES CEMENTER, ID = 6.276" 1-I 4989' I-a • 1 8893 8478 43 MMG SO RK 20 _04/06/06 4 Minimum ID = 2.75" @9040' ' I 8982' H3-1/2" HES X NIP, ID = 2.813" I 3 -1/2" HES XN NIPPLE 1 . 1 8993' H 7" X 3-1/2" BKR PREM PKR, ID = 2.870" I I ' H , I = " I 90409019' ....1--1 I 33:11//22,',' HES HES XN X NIP , ID = 2.752.813" I ' I TOP OF 4-1/2" LNR I-1 9054' I— I 9054' I— 7" X 5" BKR ZXP LTP w / TIEBACK SLV, ID = 5.960" 3 -1/2" TBG, 9.2 #, L -80 IBT -M, --I 9063' 1---... 0087 bpf, ID = 2.992" IM 9061' H 3 -1/2" X 4 -1/2" XO, ID = 2.992" I M 9064' H 4-1/2" WLEG, ID = 3.958" I 9076' 1-17" X 5" BKR HMC LNR HGR, ID = 4.45" I 17" CSG, 26 #, L -80 BTC-M, .0383 bpf, ID = 6.276" H 9255' 9084' H 5" X 4-1/2" XO, ID = 3.958" I I I 10700' I—I 20' MARKER JT W/ RA TAG I 12135' - MARKER JT W/ RA TAG 1 PERFORATION SUMMARY REF LOG: SWS RES -CDR 6/10/2004 11 13565' —120' MARKER JT W/ RA TAG 1 & MEM GR/ CCL ON 3/24/2011 ANGLE AT TOP PERF: 63° @ 9585' N44, Note: Refer to Production DB for historical perf data SIZE' SPF 1 INTERVAL 1 Opn /Sqz 1 DATE SEE PAGE 2 FOR PERFORATION DATA wn.. I I I I All'IMIP ILIMILr \II PBTD H 14996' 4 -1 /2" LNR, 12.6 #, L -80 IBT -M, .0152 bpf, ID = 3.958" I--I 15084' I DATE REV BY COMMENTS DATE REV BY COMMENTS PRUDHOE BAY UNIT 06/22/04 TWA /KAK ORIGINAL COMPLETION WELL: V -02 03/27/11 NORDIC 2 ADPERF PERMIT No: '2040770 03/30/11 PJC DRLG HO CORRECTIONS API No: 50- 029 - 23209 -00 SEC 11, T11 N, R11 E, 448' FNL & 1804' FEL BP Exploration (Alaska) • V -02 • PERFORATIONS • J L PERFORATION SUMMARY a • REF LOG: SWS RES -CDR 6/10/2004 & MEM GR/ CCL ON 3/24/2011 ANGLE AT TOP PERF: 63° @ 9585' ' I Note: Refer to Production DB for historical perf data SIZE SPF INTERVAL Opn /Sqz DATE _ 2" 6 9585 - 9625 0 03/27/11 g M 2" 6 9650 - 9680 0 03/27/11 2" 6 10080 - 10365 0 03/27/11 , 2" 6 10380 - 10560 0 03/27/11 2 -1/2" 4 10410 - 10560 0 06/15/04 , ' 2 -1/2" 4 10610 - 10820 0 06/15/04 2" 6 10610 - 10895 0 03/27/11 2 -1/2" 4 10930 - 11110 0 06/15/04 2" 6 11165 - 11240 0 03/27/11 2 -1/2" 4 11290 -11370 0 06/15/04 r 111 2 -1/2" 4 11410 - 11630 0 06/15/04 I 2 -1/2" 4 11680 - 12160 0 06/15/04 2" 6 12510 - 12570 0 03/27/11 2" 6 12595 - 12625 0 03/27/11 2" 6 12690 - 12710 0 03/27/11 4 2" 6 12735 - 13005 0 03/27/11 ' 2" 6 13045 - 13260 0 03/27/11 10700' H 20' MARKER JT W/ RA TAG I 2" 6 13280 - 13365 0 03/27/11 2" 6 13395 - 13465 0 03/27/11 ' 2 -1/2" 4 13480 - 13580 0 06/15/04 2 -1/2" 4 13650 - 13750 0 06/15/04 ` I 12135' H20' MARKER JT W/ RA TAG I 2" 6 13835 - 13915 0 03/27/11 2 -1/2" 4 13950 - 14060 0 06/15/04 ( 13565' -1 20' MARKER JT W/ RA TAG, 2" 6 14060 - 14105 0 03/27/11 2" 6 14420 - 14515 0 03/27/11 2 -1/2" 4 14650 - 14780 0 06/15/04 2" 6 14655 - 14725 0 03/27/11 2" 6 14755 - 14950 0 03/27/11 4■` 2 -1/2" 4 14920 - 14985 0 06/15/04 &Will DATE R EV BY COMM DATE REV BY COMMENTS PRUDHOE BAY UNIT 06/22/04 TWA /KAK ORIGINAL COMPLETION WELL: V -02 03 /27/11 NORDIC 2 ADPERF PERMIT No: 8 2 040770 03/30/11 PJC DRLG HO CORRECTIONS API No: 50- 029 - 23209 -00 1 SEC 11, T11 N, R11 E, 448' FNL & 1804' FEL BP Exploration (Alaska) 03/08/11 Schiumberger NO. 5701 Alaska Data & Consulting Services Company: State of Alaska 2525 Gambell Street, Suite 400 Alaska Oil & Gas Cons Comm Anchorage, AK 99503 -2838 Attn: Christine Shartzer ATTN: Beth 333 West 7th Ave, Suite 100 Anchorage, AK 99501 Well Job # Log Description Date BL Color CD W -202 BMSA -00004 MDT am- / ;'j 01/22/11 P.6 1 1 W -202 BMSA -00005 ISOLATION SCANNER (USIT „()— i 33 01/30/11 1 1 V -02 BL65-00016 SCMT T f)(1 C7rIO 02/01/11 1 1 A -39A BL65 -00018 MEM DEPTH CORRELATION 0 ^- 'r 02/03/11 1 1 J -17C BAUJ -00081 MEM PROD PROFILE a CAS � 02/09/11 1 ' 6-}4 a 1 18 -13C AWJI -00126 MEMORY CBL j/n - / 02/10/11 an- I 1 R -12 BBKA -00087 PRIMARY DEPTH CONTROL LOG rf( -• t;73 :r 02/18/11 1 1 D -21 BG4H -00036 PRODUCTION PROFILE .. 02/20/11 1 1 W -18 - BJOH -00010 PRODUCTION PROFILE t���!� 02/13/11 1 1 H -20 BBSK -00051 PRODUCTION PROFILE „' , — di, 02/11/11 1 d Q 4 1 • P2 -52 BCRD -00082 SCMT g CI "4- - , Q ( 02/10/11 gerl j 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, Suite 400 900 E. Benson Blvd. Anchorage, AK 99503 -2838 al rL O MAR A 4 ? 011 E g Aratoww: Producers with sustained casing pressun IA and OA due to proration . Page 1 of 1 Regg, James B (DOA) From: AK, D &C Well Integrity Coordinator [AKDCWeIIIntegrityCoordinator @bp.com] f f / I( Sent: Tuesday, January 18, 2011 1:40 PM J 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; Ramsay, Gavin; Kirchner, Carolyn J; 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 15 -18. 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. 04 -24 (PTD #1853010) K -20C (PTD #2080490) FEB ` -02 (PTD #2040770) Z -14B (PTD # 2060990) The following producer was found to have sustained casing pressure on the OA during the proration January 15 -18. 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. Z -11A (PTD #2050310) All the wells listed above will be classified as Not Operable until start-up operations are complete 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 1/25/2011 ~ BP Exploration (Alaska) Inc. Attn: Well Integrity Coordinator, PRB-20 Post Office Box 196612 Anchorage, Alaska 99519-6612 August 14, 2009 t ~7 ~f~,~`\~~~`.C..~.*' ~ ~ ~., ._ ~ C._L/l>~' • bp ~~~GI V ~~ OCT 0 5 2009 Mr. Tom Maunder Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, Alaska 99501 Subject: Corrosion Inhibitor Treatments of GPB V-Pad Dear Mr. Maunder, ~ Oil & Gas Cons. GammiR~~c~, Anchar~ge ~„~~ ~ ~ 7 7 ~/ ~ C~ o~-. Enclosed please find multiple copies of a spreadsheet with a list of wells from GPB V- Pad that were treated with corrosion inhibitor in the surface casing by conductor annulus. The corrosion inhibitor is engineered to prevent water from entering the annular space and causing external corrosion that could result in a surface casing leak to atmosphere. The attached spreadsheet represents the well name, API and PTD numbers, top of cement depth prior to filling and volumes of corrosion inhibitor used in each conductor. As per previous agreement with the AOGCC, this letter and spreadsheet serve as notification that the treatments took place and meet the requirements of form 10-404, Report of Sundry Operations. If you require any additional information, please contact me or my alternate, Anna Dube, at 659-5102. Sincerely, Torin Roschinger BPXA, Well Integrity Coordinator • ` BP Exploration (Alaska ) Inc. Surface Casing by Conductor Annulus Cement, Corrosion inhibitor, Sealant Top-off Report of Sundry Operations (10-404) Date V-pad 8/13/2009 Well Name PTD # API # Initial top of cement Vol. of cement um ed Final top of cement Cement top off date Corrosion inhibitor Corrosion inhibitor/ sealant date ft bbls ft na al V-Ot 2040900 50029232100000 NA 2 NA 17 6/30/2009 V-02 2040770 50029232090000 NA 3 NA 43.4 7/11/2009 V-03 2022150 50029231240000 surface NA NA NA NA V-04 2061340 50029233220000 NA 1.5 NA 20.4 6/29/2009 V-05 2080930 50029233910000 NA 1.75 NA 20.4 5/10/2009 V-07 2071410 50029233720000 NA 0.25 NA 1.7 6/29/2009 V-100 2010590 50029230080000 NA 1.5 NA 20.4 5/9/2009 V-t01 2020560 50029230740000 NA 3.75 NA 32.3 7/10/2009 v-102 2020330 50029230700000 NA 7.75 NA 98.2 8/7/2009 V-103 2021860 50029231170000 NA 0.5 NA 9.4 7/12/2009 V-104 2021420 50029231030000 NA 1.5 NA 21.3 7/11/2009 V-105 2021310 50029230970000 NA 225 NA 23.8 6/29l2009 V-106A 2041850 50029230830t00 NA 1.75 NA 17 6/29/2009 V-107 2021550 5002923t080000 NA 1.75 NA t3.6 7/11/2009 V-108 2021660 50029231120000 NA 1.5 NA 14.5 7/10/2009 V-109 2022020 50029231200000 NA 1.2 NA 10.2 6/30/2009 V-111 2031030 50029231610000 NA 1.5 NA 11.9 7/12/2009 V-112 2060200 50029233000000 NA 1.5 NA 15.3 5/10/2009 V-113 2022160 50029231250000 NA 2.5 NA 37.4 5/10/2009 V-114A 2031850 5002923178ot00 NA 2.5 NA 34 6/30/2009 V-115 2040270 50029231950000 NA 1.5 NA 13.1 5/9/2009 V-117 2030900 50029231560000 NA 1.25 NA 22.1 5/10/2009 V-119 2040410 50029232010000 NA 2 NA 18.7 6/30/2009 V-120 2041790 50029232250000 NA 1.5 NA 8.5 7/12/2009 V-121 2070360 50029233480000 NA 1.9 NA t7 6/30/2009 V-122 2061470 50029233280000 NA 1.5 NA 6.8 5/10/2009 V-201 2012220 50029230540000 SC leak NA 4 NA 90.6 S/7/2009 V-202 2030770 50029231530000 NA 1.75 NA 12.8 7/11/2009 V-203 2051680 50029232850000 NA 2 NA 12.8 7/10/2009 V-204 2041310 50029232170000 NA 2 NA 22.1 6/30/2009 V-205 2061800 50029233380000 NA 1.8 NA 13.6 6/30/2009 V-207 2080660 50029233900000 NA 1.75 NA 18.28 1/9/2009 V-210 2042100 50029232310000 NA 2 NA 18.7 7/11/2009 V-21i 2042200 50029232320000 NA 1.5 NA 13.6 7/10/2009 V-212 2051500 50029232790000 NA 1.2 NA 11.9 6/29/2009 V-213 2041160 50029232130000 NA 1.75 NA 6.3 5/9/2009 V-214 2051340 50029232750000 NA 0.5 NA 9.4 7/11/2009 V-215 2070410 50029233510000 NA 2.8 NA 30.6 6/30/2009 V-216 2041300 50029232160000 NA 1.5 NA 13.6 6/29/2009 V-217 2061620 50029233340000 NA 2.3 NA 25.5 6/30/2009 V-218 2070400 50029233500000 NA 2 NA 17.9 7/12/2009 V-219 2081420 50029233970000 NA 1 NA 16.2 7/12/2009 "~ 2080200 50029233830000 NA 1.75 NA ~b 3/9/2008 V-221 2050130 50029232460000 NA 0.8 NA 8.5 6/29/2009 V-222 2070590 50029233570000 NA 2.5 NA 21.3 7/11/2009 V-223 2080220 50029233840000 NA 2 NA 20.5 9/7/2008 SchiumUerger Alaska Data & ConsWting Services 2525 Gambsll Sireet, Suila 400 Mchorage, AK 99503-2836 ATTN: Beth Well Job # ~by--~`7 ~ Log Description NO. 5353 Company: State ot Alaska Alaska Oil & Gas Cons Comm Attn: Christine Mahnken _f.O ~" 333 West 7th Ave, Suite 100 Mchorage, AK 99501 Date BL Color CD osii vos , . .. ,, ~ , ., _ ~ . s_ ~ ... 1 Li 'I~-;~ _ G V-02 W-26A H-32 B2WY-00078 BiJJ-00033 ANHY-00702 MEMPRODUCTIONPROFILE ' MEM PRODUCTION PROFILE ~ PRODUCTIONPpOPILE ~ L- 07/27/09 07/26/09 07/25/09 / 1 7 1 1 ~ P2-29 L2-11 L2-06 P2-28 L-213 V-221 L-220 07-22 AVTU-00052 ANHY-00106 B69K-00007 AYTU-00051 B2WY-00018 AXBD-00037 B7JJ•00035 AZCM-00036 INJECTION PROPILE " '~ -~ LDL ~ CROSS FL W CHECK INJECTION PROPILE C, -~ MEM INJECTION PROFI E' - MEM INJECTION PpOFILE " - MEM INJECTION PqOFILE ~ - PRODUCTION PROFILE - ~ 08/02/08 0&02/09 07/31/09 OB/01/09 07/29/09 07/28/09 07/30/09 08/09(09 1 1 1 1 1 } y 1 1 1 ~ 7 1 ~ ~ ~ 04-02A ~J-11A L7-09 AYS4-00091 AW18-00029 AYS4-00089 USIT USIT PRODU TION PROFILE '_~ Qg~~~~pg 08/OS/09 08/08/09 1 ~ > ~ > 1 X•28 L2-06 3•29/J-32 AXBD-00026 B3SQ-00020 AP30-00055 MEM INJECTION PROFILE U' - PRODUCTION PqOFILE IBP SET RECORD W/CROS GLOW ! - OS/17/09 pg/~q/pg 08/08/09 1 ~ 1 1 ~ ~ 06-04A B5JN-00009 RST 08/23/09 1~ 7 15-498 B2NJ-00013 MCNL - 07/15/09 1 1 03•32B 09AKA0030 OH MWD/LWD EDIT _ 02/28/09 2 ~ G•148 AWJI-00043 MCNI 07/24/09 1 7 L2•13A AWJI-00036 MCNL O6M7/09 ~ 18-028 AWJI-00045 MCNL q- ' Q~ 08/17/09 1 ~ . P1-OS AWLB-00032 RST 08/09/09 1 ~ B-16A B2WY-00020 MCNL '~ ~ Q 08/03/09 1 ~ J-208 AXBD-00020 MCNL(qEVISED) c5~ .~ ~"L' 04A2/09 ~ PLEASE ACKN~WLEI]GE RPC FIP7 wv Cit.uw c eun ocn iouuir_ n.~e rnn.. e...., ~... BP Exploration (Alaska) Inc. Petrolechnical Da~a Center LR2-t 900 E. Benson Blvd. Alaska Data & Consulting Services 2525 Gambell Slreet, Suda 400 Anchorage, AK 99503-2838 • • fiqq r~ rx ~; i i'!3' ~~, ~. Y,_~ .-~ }. ,r f e' , ~ ~ ~. ,. . . % L rv..~ ~ • • --_- MICROFILMED 03/01/2008 DO NOT PLACE rv,M.: .~; ,, rr4 ANY NEW MATERIAL UNDER THIS PAGE F: \LaserFiche\CvrPgs_Inserts\Microfilm_Marker. doc RECEIVED Schlumbel'ger SEP 1 2 2006 NO. 3952 iìJa..<:ka Oit & Gas CeliS. Ccmrr.<ÌSSÍCn Ancr.craç~ Company: State of Alaska Alaska Oil & Gas Cons Comm Attn: Christine Mahnken 333 West 7th Ave, Suite 100 Anchorage, AK 99501 Alaska Data & Consulting Services 2525 Gambell Street, Suite 400 Anchorage, AK 99503·2838 ATTN: Beth 6).)':( - OT'1- '# 1~/3Ò -'J Q ¿Df\a SCANNED SfP 1 a U Field: Prudhoe Bay Well Job# Log DescriDtion Date BL Color CD X-16 10830812 RSTlGRAVEL PACK 05/31/04 1 C-24A 11209609 MEM PROD PROFILE 06/19/06 1 V-02 40010525 OH EDIT OF MWD/LWD 06/10/04 2 1 N-07A 40010734 OH EDIT OF MWD/LWD 07119/04 2 1 17-07A 40010150 OH EDIT OF MWD/LWD 02/17/04 2 1 Petrotechnical Data Center LR2-1 900 E. Benson Blvd. Anchorage, Alaska 99508 Alaska Data & Consulting Services 2525 Gambell Street, Suite 400 Anchorage. AK 99503-2838 A TTN: Beth 09/11/06 . . PBU V-02 . . Andy, No open hole logging data was submitted for PBU V-02 API 50-029-23209-00. Please send over bluelines, reproduceables, and digital logging data for this well. TNX Howard 1 of 1 7/3/200612:04 PM ß J \}\~ DATA SUBMITTAL COMPLIANCE REPORT 6/26/2006 Permit to Drill 2040770 Well Name/No. PRUDHOE BAY UNIT V-02 Operator BP EXPLORATION (ALASKA) INC )p<.t-L I f ~ .:t,\M) 'f API No. 50-029-23209-0~OO MD 15086./' TVD 8938 - Completion Date 6/18/2004 "" Completion Status 1-01L Current Status 1-01L UIC N REQUIRED INFORMATION Mud Log No Samples No Directional Su~ Yes ~ DATA INFORMATION Types Electric or Other Logs Run: DIR 1 GR, DIR I RES / GR / PWD, DIR / RES 1 GR I AIM / PWD Well Log Information: Logl Electr Data Digital Dataset Tyge Med/Frmt Number Z D IdJS M(,\~ (data taken from Logs Portion of Master Well Data Maint . Name Directional Survey Directional Survey Log Log Scale Media Run No Interval OH I Start Stop CH Received Comments o 15086 7/9/2004 o 15086 7/9/2004 Well Cores/Samples Information: Name Interval Start Stop Sent Received Sample Set Number Comments ADDITIONAL INFORMATION Well Cored? yQ]:) Chips Received? ~ Daily History Received? ~N ÐN Formation Tops Analysis Received? ~ . Comments: Compliance Reviewed By: , ~ Date: 3~)~ 2..~ \ø IJ'... Q~ l~ ..L::t:. '-~ t>f1X. V -02 (PTD #2040770) Classified as Problem Well . I" . All, Well V-02 (PTD #2040770) has been found to have sustained casing pressure on the IA. The TIO's on 03/25/06 were 2200/2200/380 when a TIFL failed. The plan forward for this well is as follows: 1. DHD: TIFL - FAILED 2. SL: GL V c/o 3. DHD: Re-TIFL A wellbore schematic has been included for reference. «V-02.pdf» The well has been classified as a Problem well. Please call if you have any questions. Thank you, )lnna (})u6e Well Integrity Coordinator GPB Wells Group Phone: (907) 659-5102 Pager: (907) 659-5100 x1154 Content-Description: V -02.pdf Content-Type: application/octet-stream Content-Encoding: base64 ðA 7~i 575DfSÎ ~ M.:h;:IP 3."),4i " ¡&i- J t~ per C() ¿¡ei l.. ¡ ¿4~ ~f' .~ scp 2u.vp:>i "5bO(-5; .\..0:<.( P 1 of 1 3/28/20064:15 PM . -...- lREE= \llÆLL H E'A D = AClUATOR= KB. ELBf = BF. B..Bf = KOP= Max Angle = Datum fv[) = Datum W D = - 4-1/16" CIW FMC N/A 81.60' 53.1' 6720' 96° @ 9924' 9450' 8800' SS V-02 I 9-5/8" CSG, 40#, L-80, ID = 8.835' H ,---4 2712' , 9-5/8" I-ES ES CÐÆN1£R, ID = 6.276" H - - 4989' IMinimum ID = 2.725" @ 9040' 4-1/2" HES XN NIPPLE :8: z , 3-1/2" TBG, 9.2#, L-BO, .0087 bpf, ID = 2.992" H 9061' ~ I 7" CSG, 26#, L-BO, ID = 6.276" H 9255' - PffiFORA TION SUfv1IMRY REF LOG: SWS RES-CDR6/10/2004 ANGLEATTOP ÆRF: 93 @ 10410 Note: Refer to Production DB for historcal perf data SIZE SPF INlERVA L Opn/Sqz [)6. TE 2-1/2" 4 10410-10560 0 06/15/04 2-1/2" 4 10610- 10820 0 06115/04 2-1/2" 4 10930- 11110 0 06115/04 2-1/2" 4 11290 -11370 0 06/15/04 2-1/2" 4 11410- 11630 0 06/15/04 2-1/2" 4 11680- 12160 0 06/15/04 2-1/2" 4 13480 - 13580 0 06/15/04 2-1/2" 4 13650 - 13750 0 06/15/04 2-1/2" 4 13950 - 14060 0 06115/04 2-1/2" 4 14650 - 14780 0 06/15/04 2-1/2" 4 14920 - 14985 0 06115/04 . SAFETY NOTES: I -~ 980' H9-5I8" TAM PORT COLLAR I 1933' H3-1/2"HESXNlP,ID=2.813" , - - GAS LIFT MClNDRB..S .. ST MD WD DEV TYPE VLV LA TCH PORT DATE 8 2012 2009 1 MWG DOME RK 16 07/23/04 7 3288 3284 0 MWG aIt1Y RK 0 06/17/04 6 4177 4173 1 MWG DOME RK 16 07/23/04 L 5 5105 5101 1 MWG av1Y RK 0 06/17/04 4 5780 5776 1 MWG DOME RK 16 07/23/04 3 6392 6388 2 MWG aIt1Y RK 0 06/17/04 2 6986 6981 8 MWG DOME RK 16 07/23/04 1 8893 8478 43 MWG SO RK 20 07/23/04 , 8982' H3-112" I-ES X NIP, D = 2.813" , Z I 8993' H7"X 3-1/2" BKRPRBlAIER A<R I 9019' H3-1/2" HES X NIp, ID= 2.813" I - ---t 9040' H3-112" HESXN NIP, ID= 2.725" , ?< 1 9054' ,- 7" X 5" BKR ZXP LNR TOP A<R I ~ W/TIEBACK SlV 9061' 1- 4-1/2" X 3-1/2" XO, ID= 3.958" I 9064' H4-112" WL83, D = 3.958" I .. ~ 10700' H20'MClRKERJTW/RA TAG I 12135' H20' MARKERJTW/ RA TAG' H20' MClRKER JTW/ RA TAG I 14996' I , 4-112"LNR,12.6#,L-80,.0152bpf,ID=3.958" H 15084' I DA 1£ REV BY COMIllENTS 06122/04 TWAlKAK ORIGINAL COMPLETION 07/23/04 RMHtKAK GLV C/O DATE REV BY COMv1ENTS PRUDHOE BAY lJIIIT \llÆLL V-02 PERMIT N?: 2040770 AA No: 50-029-23209-00 SEC 11, T11 N, R11 E, 4831' NSL & 1804' \llÆL BP Exploration (Alaska) .- .. . STATE OF ALASKA . ALASKA~L AND GAS CONSERVATION COM~SION WELL COMPLETION OR RECOMPLETION REPORT AND LOG 1a. Well Status: 1m 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: 4831' NSL, 1804'WEL, SEC. 11, T11N, R11E, UM Top of Productive Horizon: 4697' NSL, 3410' WEL, SEC. 11, T11 N, R11 E, UM Total Depth: 1912' NSL, 3504' WEL, SEC. 02, T11 N, R11 E, UM 4b. Location of Well (State Base Plane Coordinates): Surface: x- 590497 y- 5970078 Zone- ASP4 TPI: x- 588893 y- 5969924 Zone- ASP4 Total Depth: x- 588766 y- 5972418 Zone- ASP4 18. Directional Survey 1m Yes 0 No 21. Logs Run: DIR I GR, DIR I RES I GR I PWD, One Other 5. Date Comp., Susp., or Aband. 6/18/2004 6. Date Spudded 5/18/2004 7. Date T.D. Reached 6/10/2004 8. KB Elevation (ft): 81.6' 9. Plug Back Depth (MD+ TVD) 14996 + 8947 10. Total Depth (MD+TVD) 15086 + 8938 11. Depth where SSSV set (Nipple) 1933' MD 19. Water depth, if offshore NIA MSL CASING SIZE 20" 9-5/8" 7" 4-1/2" DIR / RES I GR / AIM I PWD CASING, LINER AND CEMENTING RECORD Srnll\l<:H::>EP'"I'A Mô SETTINGDEP"tliTVO BoTTOM Top BOttOM 109' 29' 109' 2712' 29' 2708' 9255' 26' 8749' 15084' 8596' 8939' 23. Perforations op'en to Production (MD + TVD of Top and Bottom Interval, Size and Number; if none, state "none"): 2-1/2" Gun Diameter, 4spf 2-1/2" Gun Diameter, 4spf MD TVD MD TVD 10410' - 10560' 8979' - 8969' 13950' - 14060' 8973' - 8971' 10610' - 10820' 8965' - 8958' 14650' - 14780' 8955' - 8953' 10930' - 11110' 8962' - 8969' 14920' - 14985' 8950' - 8948' 11290' - 11370' 8972' - 8972' 11410' - 11630' 8971' - 8968' 11680' - 12160' 8967' - 8966' 13480' -13580' 8977' - 8974' 13650' - 13750' 8974' - 8976' 22. 91.5# 40# 26# 12.6# H-40 L-80 L-80 L-80 26. Date First Production: August3,2004 Date of Test Hours Tested PRODUCTION FOR 8/3/2004 4 TEST PERIOD .. Flow Tubing Casing Pressure CALCULATED ...... Press. 299 1300 24-HoUR RATE""'" 29' 29' 26' 9054' 42" 12-1/4" 8-314 " 6-1/8" 24. SIZE 3-1/2", 9.2#, L-80 Revised: 08/10/04, Put on Production 1b. Well Class: 1m Development 0 Exploratory o Stratigraphic 0 Service 12. Permit to Drill Number 204-077 13. API Number 50- 029-23209-00-00 14. Well Name and Number: PBU V-02 15. Field I Pool(s): Prudhoe Bay Field I Prudhoe Bay Pool Ft Ft 16. Property Designation: ADL 028240 17. Land Use Permit: 20. Thickness of Permafrost 1900' (Approx.) AMOUNT PULLED 260 sx Arctic Set (Approx.) 469 sx Permafrost II, 218 sx 'G' 309 sx LiteCrete, 183 sx 'G', 532 sx Class 'G' DEPTH SET (MD) 9064' PACKER SET (MD) 8993' DEPTH INTERVAL (MD) AMOUNT & KIND OF MATERIAL USED Freeze Protect with 77 Bbls of Diesel Øl\l- PRODUCTION TEST Method of Operation (Flowing, Gas Lift, etc.): Gas Injection Oll-Bsl GAs-McF WATER-Bsl 404 192 61 GAs-McF 1,154 WATER-Bsl 366 Oll-Bsl 2,423 CHOKE SIZE I GAS-Oil RATIO 176 476 Oil GRAVITY-API (CORR) 27. CORE DATA Brief description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water (a1íach separate sheet, if necessary). Submit core chips; if none, state "none". None ¥(8~ Sfl Form 10-407 Revised 12/2003 ~v CONTINUED ON REVERSE SIDE ORIG\NAL ....'. e GEOLOGIC MARKERS 29. e FORMATION TESTS 28.# 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". Ugnu 2945' Ugnu M 3897' Schrader Bluff N 4225' Schrader Bluff 0 4391' Base Schrader Bluff I Top Colville 4757' HRZ 6358' Kalubik 6567' Kuparuk D 6647' Kuparuk C 6659' Kuparuk B 6771' Kuparuk A 6883' Miluveach 6947' Kingak 7664' Sag River 9260' Shublik 9306' Eileen 9506' Sadlerochit 9577' 2941' 3983' None 4221' 4387' 4753' 6354' 6563' 6643' 6655' 6767' 6878' 6942' 7581' 8753' 8787' 8912' 8946' 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~ _ kLIM& Title Technical Assistant Date c::g. { O-Oc.¡ PBU V-02 204-077 Prepared By Name/Number: Terrie Hubble, 564-4628 Well Number Drilling Engineer: Jim Smith, 564-5773 Permit NO.1 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-Altemating-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 Submit Original Only · .. STATE OF ALASKA _ ALASKA'e'IL AND GAS CONSERVATION COMMI~SION 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 21. Logs Run: DIR I GR, DIR I RES I GR I PWD, DIR I RES I GR I AIM I PWD CASING, liNER AND CEMENTING RECORD SETtiNG OePTHMO SËTTINGOEPTHTVÐ Top BOTrOM ToP BO.TTOM 29' 109' 29' 109' 29' 2712' 29' 2708' 26' 9255' 26' 8749' 9054' 15084' 8596' 8939' 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: 4831' NSL, 1804'WEL, SEC. 11, T11N, R11E, UM Top of Productive Horizon: 4697' NSL, 3410' WEL, SEC. 11, T11N, R11E, UM Total Depth: 1912' NSL, 3504'WEL, SEC. 02, T11N, R11E, UM 4b. Location of Well (State Base Plane Coordinates): Surface: x- 590497 y- 5970078 _ Zone- ASP4 TPI: x- 588893 y- 5969924 Zone- ASP4 Total Depth: x- 588766 y- 5972418 Zone- ASP4 18. Directional Survey 181 Yes 0 No 22. 20" 9-5/8" 91.5# 40# 26# 12.6# H-40 L-80 L-80 L-80 7" 4-1/2" 23. Perforations open to Production (MD + TVD of To,e and Bottom Interval, Size and Number; if none, state 'none"): 2-1/2" Gun Diameter, 4 spf 2-1/2" Gun Diameter, 4spf MD TVD MD TVD 10410' -10560' 8979' - 8969' 13950' - 14060' 8973' - 8971' 10610' -10820' 8965' - 8958' 14650' - 14780' 8955' - 8953' 10930' - 11110' 8962' - 8969' 14920' - 14985' 8950' - 8948' 11290' - 11370' 8972' - 8972' 11410'-11630' 8971'-8968' 11680' - 12160' 8967' - 8966' 13480' - 13580' 8977' - 8974' 13650' -13750' 8974' - 8976' 26. Date First Production: Not on Production Yet Date of Test Hours Tested PRODUCTION FOR TEST PERIOD + Flow Tubing Casing Pressure CALCULATED + Press. 24-HoUR RATE One Other 5. Date Comp., Susp., or Aband. 6/18/2004 6. Date Spudded 5/18/2004 7. Date T.D. Reached 6/10/2004 8. KB Elevation (ft): 81.6' 9. Plug Back Depth (MD+ TVD) 14996 + 8947 10. Total Depth (MD+TVD) 15086 + 8938 11. Depth where SSSV set (Nipple) 1933' MD 19. Water depth, if offshore NIA MSL 42" 12-1/4" 8-3/4" 6-1/8" 24. SIZE 3-1/2", 9.2#, L-80 1 b. Well Class: 181 Development 0 Exploratory o Stratigraphic 0 Service 12. Permitto Drill Number 204-077 13. API Number 50- 029-23209-00-00 14. Well Name and Number: PBU V-02 15. Field I Pool(s): Prudhoe Bay Field I Prudhoe Bay Pool Ft Ft 16. Property Designation: ADL 028240 17. Land Use Permit: 20. Thickness of Permafrost 1900' (Approx.) 260 sx Arctic Set (Approx.) 469 sx Permafrost II, 218 sx 'G' 309 sx LiteCrete, 183 sx 'G', 532 sx Class 'G' TUalNGREOORO DEPTH SET (MD) 9064' PACKER SET (MD) 8993' DEPTH INTERVAL (MD) AMOUNT & KIND OF MATERIAL USED Freeze Protect with 77 Bbls of Diesel PRODUCTION TEST Method of Operation (Flowing, Gas Lift, etc.): NIA OIL-BeL GAs-McF WATER-BeL 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". ;(70" PI;::¡'?OOy' None; ./""'.~" h~-11!.;;; J.' t':.ý .h""/~é:A L~~t t"'..,.....~..._ . OIL-BeL 27. Form 1 0-407 Revised 12/2003 GAs-McF WATER-BeL CHOKE SIZE I GAS-OIL RATIO OIL GRAVITY-API (CORR) ORIGINAL"Bft n_ 2 2 G{ '".~\ CONTINUED ON REVERSE SIDE , 28. e GEOLOGIC MARKERS 29. e FORMATION 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". Ugnu 2945' Ugnu M 3897' Schrader Bluff N 4225' Schrader Bluff 0 4391' Base Schrader Bluff I Top Colville 4757' HRZ 6358' Kalubik 6567' Kuparuk D 6647' Kuparuk C 6659' Kuparuk B 6771' Kuparuk A 6883' Miluveach 6947' Kingak 7664' Sag River 9260' Shublik 9306' Eileen 9506' Sadlerochit 9577' 2941' 3983' None 4221' 4387' 4753' 6354' 6563' 6643' 6655' 6767' 6878' 6942' 7581' 8753' 8787' 8912' 8946' 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 knowtedge. Signed ~l kl /l fÎß A T·tl T h· I A . t t D t On... /J/ Ò ( J Terrie Hubble ~ ~~ I e ec nlca 5515 an a e {A· "1 PBU V-02 204-077 Prepared By Name/Number: Terrie Hubble, 564-4628 Well Number Drilling Engineer: Jim Smith, 564-5773 Permit No. I 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-Altemating-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 Submit Original Only Legal Name: V-02 Common Name: V-02 ¡/22/2004 FIT 5/31/2004 FIT ,963 (psi) 13.78 (ppg) 4,791 (psi) 10.54 (ppg) e e Printed: 6/22/2004 10:13:56 AM 610 (psi 700 (psi 9.50 (ppg) 9.00 (ppg) 2,741.0 (It) 8,750.0 ift 2,745.0 (It) 9,255.0 (It) e e Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: V-02 V-02 DRILL+COMPLETE NABORS ALASKA DRILLING I NABORS 9ES Start: Rig Release: Rig Number: 5/17/2004 6/18/2004 Spud Date: 5/18/2004 End: 6/18/2004 5/17/2004 12:00 - 19:00 7.00 MOB P PRE Move rig from L Pad to V Pad, pre-move camp, shop and pump trailer 19:00 - 22:00 3.00 RIGU P PRE Spot rig, spot pump trailer, rig to spud. Rig accepted at 22:00 hrs 22:00 - 00:00 2.00 RIGU P PRE Rig up to spud, spot camp and shop 5/18/2004 00:00 - 04:00 4.00 P PRE Rig up to spud, take on water, mix mud, NU diverter, load pipe shed with drillpipe, pick up and make stands of drillpipe, spot MWD trailer, Geology trailer, Mi trailer, 04:00 - 04:30 0.50 RIGU P PRE Rig service, service top drive 04:30 - 08:00 3.50 RIGU P PRE Mix mud to 8.7 ppg, 300 vis, load 96 jts 4" HT-40 in pipe shed 08:00 - 12:00 4.00 RIGU P PRE Pick up drillpipe, stand back in derrick, pick up HWDP, stand back 12:00 -12:30 0.50 RIGU P PRE Pick up, make jars to stand of DCs 12:30 - 13:00 0.50 RIGU P PRE Test diverter, accumulator drill, witness waived by AOGCC 13:00 - 16:00 3.00 RIGU P PRE Make up bit, motor to 1.5 degrees, stab, MWD, stab, XO, UBHO sub 16:00 - 16:30 0.50 DRILL P SURF Rig spud at 16:00 hrs Circulate mud system, check for leaks, tag bottom at 108' 16:30 - 00:00 7.50 DRILL P SURF Directional drill 12 1/4" wellbore from 108' to 455', 70K UP, 50K DN AST 1.14, ART 0.69, Gyro survey every stand drilled 5/19/2004 00:00 - 07:30 7.50 DRILL P SURF Directional drill 12 1/4" surface well bore from 455' to 1285' Inc 7.7, Az 184, 77K UP, 72K DN, 30 - 35K WOB, 560 GPM 1660 SPP, Rig down Gyro Data, use MWD surveys Losses downhole of 60 bblslhr started at +/- 800' AST 3.10 hrs, ART 2.54 hrs 07:30 - 08:30 1.00 DRILL P SURF Circulate bottoms up at drilling rate, 08:30 - 11 :00 2.50 DRILL P SURF POH due to failed traction motor on mud pump # 1 11 :00 - 11 :30 0.50 DRILL P SURF Clean and clear rig floor 11 :30 - 12:00 0.50 DRILL P SURF Rig service, sevice top drive 12:00 - 13:00 1.00 DRILL P SURF Rig service, slip and cut 40' drilling line 13:00 - 00:00 11.00 DRILL N RREP SURF Rig repair, change out traction motor on mud pump # 1 Total losses to well bore from 12:00 to 00:00 hrs, 293 bbls 5/20/2004 00:00 - 00:30 0.50 DRILL N RREP SURF Rig repair, traction motor mud pump # 1 00:30 - 01 :30 1.00 DRILL P SURF Make up bit # 2, handle and run directional BHA 01 :30 - 03:00 1.50 DRILL P SURF Trip in, break circulation and re-survey 4 survey points, wipe 2 tight spots, 765',1048', well bore in good condition, no losses while running in 03:00 - 09:00 6.00 DRILL P SURF Directional drill from 1285' to 2725' TD, 104K UP, 92K DN, 100K RT 650 gpm, 2880 psi, 80 rpm, 45K wob, 2500 TO OFF, 6500 TO ON No losses while drilling AST .28, ART 3.65 09:00 - 10:00 1.00 DRILL P SURF Circulate bottoms up twice, 675 gpm, 85 rpm, 2660 psi, 2000 TO 10:00 - 14:00 4.00 DRILL P SURF POH, slight drag, 10-15K, wipe,OK, well bore in good condition, no losses 14:00 - 15:00 1.00 DRILL P SURF Handle BHA, lay down BHA 15:00 - 15:30 0.50 DRILL P SURF Clear and clean rig floor 15:30 - 16:00 0.50 CASE P SURF Make dummy hanger run, 29.30' 16:00 - 18:00 2.00 CASE P SURF Rig up casing equipment, long bales, 350 ton elevators, slips, Printed: 6/22/2004 10:14:03 AM · e Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: V-02 V-02 DRILL+COMPLETE NABORS ALASKA DRILLING I NABORS 9ES Start: 5/17/2004 Rig Release: 6/18/2004 Rig Number: Spud Date: 5/18/2004 End: 6/18/2004 5/20/2004 16:00 - 18:00 2.00 CASE P SURF Franks tool, power tongs 18:00 - 18:30 0.50 CASE P SURF PJSM with all personnel, casing safety 18:30 - 23:00 4.50 CASE P SURF Pick up, make up 9 5/8", L-80, 40 #, casing, dope wi BOL 2000 NM, make up TO 9200 ftllbs, run jewelry as per running order, land at 22:50 hrs, mud losses of 27 bbls while running casing 23:00 - 23:30 0.50 CASE P SURF Rig down Franks tool, rig up cement head, plug loading witnessed by CO Rep, blow down top drive 23:30 - 00:00 0.50 CEMT P SURF Ciurculate casing, stage pumps up to 3 bpm, 115K UP, 105K DN pump on 150K UP, 105K DN pump off 5/21/2004 00:00 - 03:00 3.00 CEMT P SURF Circulate casing, two circulations at 6 bpm, back to 4 bpm, condition mud for cementing, vis 75, 25 yp Wait on water truck for cementing, 03:00 - 03:30 0.50 CEMT P SURF PJSM, safety meeting wi rig crew, cememters, truckers Circulate casing 03:30 - 05:30 2.00 CEMT P SURF Cement as per program wi 75 bbls 10.2# Spacer; 367 bbls 10.7# Lead; and 42 bbls 15.8# Tail cement. Bump plug to 3000 psi wi calculated strokes. CIP @ 0530 hrs on 5/21/2004. Circulated 100 bbls to surface. Reciprocated till cement at surface. 05:30 - 08:30 3.00 CEMT P SURF Flush all lines, diverter stack, rig down cement head, lay down landing jt, lay down cementing equipment 08:30 - 10:00 1.50 DIVRTR P SURF Nipple down riser, surface annular, diverter lines 10:00 - 11 :00 1.00 WHSUR P SURF Lift speed head into cellar area 11 :00 - 12:00 1.00 WHSUR P SURF Nipple up speed head 12:00 - 13:00 1.00 WHSUR P SURF Pressure test MIM seals to 1000 psi 13:00 - 15:30 2.50 BOPSUPP SURF PJSM, nipple up BOPE 15:30 - 21 :30 6.00 BOPSUP P SURF Pressure test BOPE to 250/3500 psi, blow down choke and kill line Test H2S and LEL alarms Test witnessed by Jeff Jones, AOGCC 21 :30 - 22:00 0.50 BOPSUP P SURF Run wear bushing, install mouse hole 22:00 - 00:00 2.00 DRILL P INT1 PJSM, pick up and make up drill pipe, to TD intermediate well bore 5/22/2004 00:00 - 04:30 4.50 DRILL P INT1 Pick up and stand back drill pipe to TD intermediate wellbore 04:30 - 05:00 0.50 DRILL P INT1 Clear and clean rig floor, BHA to rig floor 05:00 - 08:00 3.00 DRILL P INT1 Make up BHA # 3, RIH, test MWD at first stand HWDP 08:00 - 09:00 1.00 DRILL P INT1 Trip in to 10 stands of drillpipe, pressure test casing to 1000 psi 09:00 - 10:00 1.00 DRILL P INT1 RIH picking up drillpipe from pipe shed, add ghost reamer at 2041' 10:00 - 10:30 0.50 DRILL P INT1 Pressure test casing to 3500 psi for 30 minutes, charted 10:30 - 14:00 3.50 DRILL P INT1 Tag cement at 2607', drill cement at 550 gpm, 50 rpm, 0-5 wob, 103K UP, 92K DN Drill 20' of new well bore from 2725 to 2745' 14:00 - 15:00 1.00 DRILL P INT1 Circulate bottoms up, displace well bore to new 9.5 #, 58 vis, LSND mud, obtain SPRs 15:00 - 15:30 0.50 DRILL P INT1 Perform FIT EMW = 13.8 #, break over pressure 610 psi, Established base line ECD 15:30 - 00:00 8.50 DRILL P INT1 Directional drill 8 3/4" well bore from 2745 to 4193' 1980 psi off, 2100 psi on, 590 gpm, 80 rpm, 5-15K wob 125KUP, 111KDN, 118K RT, 2.1 TO off, 3.0TOon Printed: 6/22/2004 10: 14:03 AM · e legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: V-02 V-02 DRlll+COMPlETE NABORS ALASKA DRilLING I NABORS 9ES Start: 5/17/2004 Rig Release: 6/18/2004 Rig Number: Spud Date: 5/18/2004 End: 6/18/2004 5/22/2004 15:30 - 00:00 8.50 DRILL P INT1 ART 3.8, AST 0.35 5/23/2004 00:00 - 01 :30 1.50 DRILL P INT1 Directional drill 8 3/4" well bore from 4193' to 4474' 580 gpm, 2150 psi on, 1800 psi off, 4 tq on, 2 tq off, 129K UP, 118K DN, 120K RT, ECD 9.96 110.54, 80 rpm, 10-15 wob 01 :30 - 02:00 0.50 DRILL P INT1 Circulate bottoms up, hydrate cut mud, shut off pumps, well will not flow, Schrader Oa, mud wt 9.5 # in lout 02:00 - 19:00 17.00 DRILL P INT1 Directional drill from 4474' to 6047' Raise mud weight to 9.8 ppg, slight hydrate cut mud, Raise mud weight to 10.3 ppg for HRZ 580 gpm, 2475 psi on, 2200 psi off, 5 tq on, 2.5 tq off, 153K UP 131 K DN, 138K RT, ECD 10.26/10.72, 80 rpm, 10-15 wob 19:00 - 00:00 5.00 DRILL N RREP INT1 Rig repair, mud pump # 2, cylinder # 3, cracked fluid end, change out fluid end 5/2412004 00:00 - 03:30 3.50 DRILL N RREP INT1 Rig repair, pump # 2, fluid end on cylinder # 3 replaced 03:30 - 04:30 1.00 DRILL P INT1 Directional drill 83/4" well bore from 6047' to 6155' 230 spm, 3200 psi on, 2950 psi off, 5 tq on, 2.6 tq off, 150K UP, 136K DN, 142K RT, ECD 10.83/11.14, 80 rpm, 1 0-20 wob 04:30 - 05:00 0.50 DRILL P INT1 Circulate bottoms up at 580 gpm, 80 rpm, ECD 10.80/11.14, 05:00 - 05:30 0.50 DRILL P INT1 Monitor well bore, Pump dry job, blow down top drive, 05:30 - 06:30 1.00 DRILL P INT1 Wiper trip ghost reamer to casing shoe at 2709', Monitor well bore 06:30 - 07:30 1.00 DRILL P INT1 RIH, ream last stand to bottom 07:30 - 00:00 16.50 DRILL P INT1 Directional drill 8 3/4" well bore from 6155 to 6994' 590 gpm, 3450 psi on, 3300 psi off, 80 rpm, 5-15 wob 5 tq on, 3 tq off, 168K UP, 148K DN, 160K RT ART 7.18, AST 3.32 5/25/2004 00:00 - 00:00 24.00 DRILL P INT1 Continue Directional drilling 83/4" well bore from 6,994 to 8,209' - Art 6.55 hrs, Ast 9.12 hrs, Average Rop 77.5 ftIhr - Top Kingak at 7844' -Slow pump rate to 590 to 520 gpm for drilling of Kingak, Control drill 100 ftIhr - Maintain mud wt. 10.8 ppg - Kick off at 6300' build angle at avrage 4.5 deg 1100' - Finish building angle to 43 deg at 7800' - Maintain azimuth at 264 deg - PIU 183k, S/O 153k, Rt wt 165K - WOB 5-15k with 3-5K torque - Flow rate 520 gpm at 3600 psi - ECD 11.2 to 11.47 ppg 5/26/2004 00:00 - 11 :00 11.00 DRILL P INT1 Continue Directional drilling 8,209 to 8,785 - Pumping 530- 520 gpm at 3800 psi, Rotating at 80 rpm's with 5 - 6K torque on bottom - angle dropping 1 1/2 deg 1100' rotating ahead - slide as needed to maintain angel 43 deg. 11 :00 - 12:00 1.00 DRILL P INT1 Pump pressure increased slowly to 4200 psi, Check out pumps, no problems found - Rotary torque, pick up and slack off wt. all the same - Suspect mud motor 12:00 - 13:00 1.00 DRILL P INT1 Pump pressure back down to 3700 - Drill ahead 8,785 to 8,865' 13:00 - 13:30 0.50 DRILL N SFAL INT1 Circulate while change #3 swab on #2 mud pump 13:30 - 17:30 4.00 DRILL P INT1 Drill 8,865 to 8,990 - Pumping 520 gpm 3600 - 3800 psi, rotating at 80 rpm with 6 - 7K torque 17:30 - 18:00 0.50 DRILL N SFAL INT1 Circulate while change seat and valve in #3 discharge of #1 pump, Change discharge valve #1 & 2 in #2 pump 18:00 - 00:00 6.00 DRILL P INT1 Drill 8,990 to 9,142 - Pump pressure erratic 3600 - 4000 psi - assembly dropping angle 1 1/2 deg 1100, continue to slide as Printed: 6/22/2004 10: 14:03 AM e e Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: V-02 V-02 DRILL+COMPLETE NABORS ALASKA DRILLING I NABORS 9ES Start: Rig Release: Rig Number: 5/17/2004 6/18/2004 Spud Date: 5/18/2004 End: 6/18/2004 5/26/2004 18:00 - 00:00 6.00 DRILL P INT1 need to maintain, sliding at 15 -20 ftlhr - Jurassic 'B' marker at 9,050' - 24 hr total Art 13.56 hrs, Ast 4.71 hrs, Average rop 51 ftlhr - Increasing amount of long, splintery shale over shakers from yesterday 5/27/2004 00:00 - 03:30 3.50 DRILL P INT1 Continue directional drilling 9,142 to 9,245' md. ART = 2.05 hrs, AST = 0.97 hrs. Notes: 1) 525 gpm 3600 psi, 2) 75 rpm's with 6 - 7K torque. 3) Stop additions of Resinex, and Asphasol (black products) at 9142' -- Geologist request for analyzing samples. 4) Pump 25 bbls 13.8 ppg high vis sweep at 9165', no additional cuttings back with sweep. 03:30 - 04:30 1.00 DRILL P INn Circulate bottoms up to collect samples for Geologist to pick top of Sag. Notes: 1) Pumping 520 gpm 3750 psi, 2) Rotating 100 rpm's - Suspect bearing out of mud motor, Pick up off bottom and gain 150 psi pump pressure - As Circulating bottoms up, Pump pressure increased rapidly, slow pump rate to 240 gpm at 3800 psi, Increase pump rate as pressure came down, 400 gpm 3800 psi 04:30 - 05:30 1.00 DRILL P INT1 Drill 9,245 to 9,250' md -- drilling parameters: WOB 25k, 80 rpm's with 6 -1 OK Ibs torque. Notes: 1) ROP fell of to 7 ftlhr. 2) Can not tell if motor turning, no differential pressure. 3) Pump rate limited to 400 gpm @ 3800 psi on and off bottom. 05:30 - 08:30 3.00 DRILL P INn Circulate bottoms up x3 in preparation to POOH for rotating assembly to TD hole section. Notes: 1) Flowrate is limited to 400 gpm so hole cleaning is not optimal. 2) Planned wiper trip to shoe, therefore, only 2700 feet to drop motor and regain full circulating capability. 3) Geologist predicts we are right at the top of the transition interval on top of the Sag River formation. 4) PWD measured 11.18 ppg @ initial circulation & 11.19 ppg @ final circulation -- Calculated ECD = 10.95ppg. 08:30 - 09:45 1.25 DRILL P INT1 Monitor Well -- Static. POOH 10 stands @ 1 fps. Pump dry job and blowdown top drive and lines. 1) Hydrate bubbles breaking in bell nipple; however, well static with fluid level is dropping slightly. 2) Hole in great shape with 10-15K overpull. 3) Hole taking fluid in excess of pipe displacement due to seepage into shallow sands. 09:45 - 13:30 3.75 DRILL P INT1 POOH @ 1 fps to 9-5/8" surface shoe. Notes: 1) Hole in excellent shape with 10 to 20K overpull throughout trip. 2) Wiped tight spots top of Kingak @ 7840' md and in Miluveach @ 7665' md. 3) Hole taking approximately 30% more than calculated pipe Printed: 6/22/2004 10: 14:03 AM . e Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: V-02 V-02 DRILL+COMPLETE NABORS ALASKA DRILLING I NABORS 9ES Start: 5/17/2004 Rig Release: 6/18/2004 Rig Number: Spud Date: 5/18/2004 End: 6/18/2004 5/27/2004 09:45 - 13:30 3.75 DRILL P INT1 displacment due to seepage in shallow sands. 13:30 - 14:30 1.00 DRILL P INT1 Monitor well at shoe -- circulate and address hydrate cut mud. Well Static -- Pump dry job and blow down lines. Notes: 1) While monitoring well at shoe, driller observed hydrate gas bubbling with slight flow into flowline. 2) Circulated surface to surface while monitoring pit volume and flowline -- no influx observed. 3) Return MW gas cut to 10.5 non pressure scale (10.9 with pressure scale). MW in 10.8+ with pressure scale. 4) Hydrate gas cleaned up immediately after bottoms up. 14:30 - 15:00 0.50 DRILL N DFAL INT1 Continue POOH to BHA. 15:00 - 16:30 1.50 DRILL N DFAL INT1 Stand back HWDP and handle BHA #3. Lay down motor and bit. Notes: 1. Observations of bit and motor indicated that fluid was not circulating through bit. 2. Bit was completely balled with clay that had been hardened and dehydrated. - 2 jets were completely plugged with rubber and others were partially plugged. - Hycalog bit rep cleaned hardened clay ball from bit and detected evidence of heat checking. · Comments were that bit was rebuildable -- bit rep took bit to Deadhorse. · Pictures and report forthcoming. 3. Motor Bearing section was worn out and motor and unable to rotate bit on end of bearing section. · Motor will be sent to Anadrill Deadhorse shop for tear down and damage assessment. 16:30 - 17:00 0.50 DRILL N DFAL INT1 Clear and Clean Rig Floor. Hole took 22 bbls more than calculated due to seepage into shallow sands. 17:00 - 17:30 0.50 DRILL N DFAL INT1 MU BHA #4. PU used DS70 bit, NBST AB and Full Gauge Stabilizer. 17:30 - 18:00 0.50 DRILL N DFAL INT1 Reprogram CDR. 18:00 - 18:30 0.50 DRILL N DFAL INT1 RIH with BHA #4. 18:30 - 19:00 0.50 DRILL N DFAL INT1 Shallow Test CDR and blow down lines. 19:00 - 20:00 1.00 DRILL N DFAL INT1 RIH to 9-5/8" surface casing shoe. 20:00 - 22:00 2.00 DRILL N DFAL INT1 Slip and Cut Drill Line and Service Top Drive and Rig. 22:00 - 00:00 2.00 DRILL P INT1 RIH to 4726' md. 5/28/2004 00:00 - 01 :00 1.00 DRILL P INT1 Continue TIH, Fill pipe at 6000' with top drive, Difficult backing out of drill pipe due to electrical probem wtih top drive, Continue TIH slowly to 6,950' while attempting to operate top drive electrical 01 :00 - 03:30 2.50 DRILL N RREP INT1 Top drive not working electrically - Pooh slowly while trouble shoot electrical on top drive - Found problem with Mico switch on driller top drive console - TIH hole to 6,950 03:30 - 05:00 1.50 DRILL P INT1 Continue TIH, work tight spot without pump 7,550, 7,640, 7,950 & 8,175, appeared to be BHA going thru slides, Continue TIH to 9,025' without problem 05:00 - 07:00 2.00 DRILL P INT1 Break circulation and circulate bottoms up while stagging pumps up from 250 gpm to 480 gpm 07:00 - 08:30 1.50 DRILL N DFAL INT1 MAD PASS 9,150 to bottom at 9,250' - Rotating at 80 rpm's Printed: 6/22/2004 10: 14:03 AM e e Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: V-02 V-02 DRILL+COMPLETE NABORS ALASKA DRILLING I NABORS 9ES Start: 5/17/2004 Rig Release: 6/18/2004 Rig Number: Spud Date: 5/18/2004 End: 6/18/2004 5/28/2004 07:00 - 08:30 1.50 DRILL N DFAL INT1 pumping 500 gpm Note: This NPT is from the motor failure from BHA #3. 08:30 - 09:30 1.00 DRILL N DFAL INT1 Circulate bottoms up to clean hole of old cutttings 09:30 - 10:00 0.50 DRILL P INT1 Rotary drill 9,250 to 9,257' - 80 rpm's 5-7k torque, 500 gpm at 3300 psi 10:00 - 11 :30 1.50 DRILL P INT1 Circulate bottoms up for samples to verify TD by geologist- ECD 11.05 Calculated, 11.3 Actual 11 :30 - 12:30 1.00 DRILL P INT1 Spot 120 bbls G-Seal pill across Schrader sands followed by Lube tex treated mud in directional section of wellbore - Monitor well 12:30 - 16:30 4.00 DRILL P INT1 Pump slug, Pooh slowly, no problem 16:30 - 17:30 1.00 DRILL P INT1 Monitor well at caisng shoe - Circulate one full circulate at 500 gpm 1000 psi 17:30 - 21 :30 4.00 DRILL P INT1 Finish Pooh, Lay down BHA and clear floor 21 :30 - 22:30 1.00 CASE P INT1 Jet stack, Pull wear bushing, Install Test plug - Pull casing tools to rig floor 22:30 - 00:00 1.50 CASE P INT1 Change top rams to 7" 5/29/2004 00:00 - 00:30 0.50 CASE P INT1 Test door seal to 3500 psi - ok - Pull test plug 00:30 - 01 :00 0.50 CASE P INT1 Finish rigging up 350 ton caisng tools and power tongs 01 :00 - 05:30 4.50 CASE P INT1 Safety meeting with Drill crew and Nabors Casing - Run 7" 26# L-80 Btc-mod R-3 Casing, Make up torque 7600 ftIlbs - Run pipe slowly, slack off one minute per jt - 66 jts at 2,708' 05:30 - 06:30 1.00 CASE P INT1 Circulate at casing shoe before going into open hole - Break circulation at 2 bpm stage up to 5 bpm 235 psi - Plu 98k, slo 92k - Circulate 1.5 hole volume 06:30 - 18:30 12.00 CASE P INT1 Continue Run 7" 26# L-80 Btc-mod R-3 total 226 jts 9255.58' - Fill pipe every jt, Break circulation every 5 jts, Circulate bottoms up while running pipe slowly at 4100, 5123, 6593, 6914, - Continue running pipe slowly to bottom filling every jt. - Taking wt. at 9,222' 18:30 - 19:00 0.50 CASE P INT1 Rig down Franks Fill up tool, Make up Dowell 7" Cement head 19:00 - 21 :30 2.50 CEMT P INT1 Break circulation at .5 bpm 500 psi, Wash to bottom at 9,255' caisng measurement - Stage up pumps to 5.5 bpm 600 psi - Circulate three bottoms up, Did not reciprocate pipe, Final mud wt. 10.9 ppg in and out 21 :30 - 23:00 1.50 CEMT P INT1 Cement with Dowell as Followes: Pump 5 bbls Water, Test lines 4000 psi, Pump 40 bbls Mud Push II mixed at 11.8 ppg, Drop by-pass dart with last 5 bbls of spacer, Load shut of dart - Cement with 247 sx LiteCrete blend, Yield 2.51 cf/sx, 110 bbl slurry mixed at 12.0 ppg, Tailed with 100 sx Class 'G', yield 1.16 cf/sx, 20.5 bbls of slurry mixed at 15.8 ppg - Drop shut off dart with 10 bbls of water - Give to rig 23:00 - 00:00 1.00 CEMT P INT1 Displace with 10.9 ppg mud and rig pump at 5.0 to 5.5 bpm 450 psi, Full returns, slight packing off after lead slurry out of shoe, slow pump to 3 bpm, increase rate back to 5 bpm after +1- 20 bbls as pressure stablized 5/30/2004 00:00 - 00:30 0.50 CEMT P INT1 Slow pump to 3 bpm with pressure of 1300 psi - Bump plug to 2000 psi, Rig pump 94.2% efficiency rate - Bled back and Check floats, ok- CIP at 1205 hrs 5/30/2004 -load ES cementer closing plug 00:30 - 03:00 2.50 CEMT P INT1 Pressure caisng with rig pump and open ES cementer at 4189' with 3100 psi, Continue circulate and condition mud at 5 bpm 300 psi - Slight contaminated mud on bottoms up, no cement Printed: 6/22/2004 10: 14:03 AM -- e Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: V-02 V-02 DRILL+COMPLETE NABORS ALASKA DRILLING I NABORS 9ES Start: 5/17/2004 Rig Release: 6/18/2004 Rig Number: Spud Date: 5/18/2004 End: 6/18/2004 5/30/2004 00:30 - 03:00 2.50 CEMT P INT1 or spacer back 03:00 - 03:30 0.50 CEMT P INT1 Pump stage two as follows: 5 bbls water ahead, 20 bbls of mud push II spacer mixed at 11.8 ppg, Pump 67 sx Lite Crete blend, yield 2.51 cf/sx, 30 bbls slurry mixed at 12.0 ppg, Tailed with 108 sx Class 'G', yield 1.16 cf/sx, 22.5 bbls of slurry mixed at 15.8 ppg - Drop closing plug with 10 bbls of water, give to rig 03:30 - 04:00 0.50 CEMT P INT1 Displace with 10.9 ppg mud and rig pump at 5.5 bpm 450 psi » 700 psi, slow to 3 bpm 450 psi, bump plug and close ES Cementer with 1600 psi - Bled back, no flow - CI P at 0400 hrs 5/30/2004- Full returns 04:00 - 04:30 0.50 CEMT P INT1 Drain stack - Rig up to lower annulus valve, flush stack with fresh water 04:30 - 05:30 1.00 CEMT P INT1 Break wellhead between casing and tubing head, Pick up bop stack 05:30 - 08:00 2.50 WHSUR P INT1 Install 11 x 7" slips with 150k net on slips, Cut and dress 7" casing, Install 7" x 11' Pack-off 08:00 - 10:00 2.00 BOPSUF P INT1 Nipple up Tubing head and Bop stack - Test pack-off to 4300 psi, 80% of collapse of 7" 26# caisng 10:00 - 11 :00 1.00 BOPSUF P INT1 Change top rams to 3112 x 6" varaible 11 :00 - 15:00 4.00 BOPSUF P INT1 Rig up & Test Bop: Test all rams, lines and valves to 250 low I 3500 high - Test hydrill, floor valves, top drive manual and IBOP to 250 and 3500 psi - Witness of Bop test waived by Mr. Chuck Scheve of AOGCC 15:00 - 16:00 1.00 BOPSUP P INT1 Pull test plug, Install wear bushing, blow down lines 16:00 - 17:00 1.00 WHSUR P INT1 Service rig - Freeze protect 7 x 9 5/8 annulus with 65 bbls dead crude to 2300' -- See Remarks. 17:00 - 18:00 1.00 DRILL P PROD1 Make up slick clean out BHA: Hughes 61/8" STR-1 mill tooth bit, 3 - 4 3/4 monel Flex collar, 1 jt 4" hwt, jars, 22 - 4" hwt = 833.71 ' 18:00 - 21:00 3.00 DRILL P PROD1 TIH to 4900', single in drill pipe from pipe shed 21 :00 - 22:30 1.50 DRILL P PROD1 Break circulation and wash down, Tag cement at 4957' - drill cement and tag ES cementer at 4989' - Drill ES cementer with 20 -25k wob, 60 rpm - Circulate bottoms up clean hole of rubber 22:30 - 23:30 1.00 DRILL P PROD1 Service top drive, Change out saver sub 23:30 - 00:00 0.50 DRILL P PROD1 Continue TIH picking up single from pipe shed 5/31/2004 00:00 - 01 :00 1.00 DRILL P PROD1 Continue TIH, single in drill pipe from pipe shed to 7,282' 01 :00 - 02:00 1.00 DRILL P PROD1 TIH with drill pipe from derrick to 8,956' 02:00 - 02:30 0.50 DRILL P PROD1 Wash down from 8,956 to top of cement at 9,135' 02:30 - 03:30 1.00 DRILL P PROD1 Test casing to 3500 psi for 30 minutes on chart - ok 03:30 - 04:30 1.00 DRILL P PROD1 Drill cement, Float equipment 9,135 to bottom at 9,257 - Pumping 300 gpm 2400 psi, rotating at 80 rpm's, 25-30 wob - Hard cement in shoe jts- Tag Landing collar at 9,170' , Float collar at 9,212' & Float shoe at 9,254' 04:30 - 05:00 0.50 DRILL P PROD1 Circulate bottoms up at 350 gpm, 3000 psi - Rotating at 120 rpm's 05:00 - 06:00 1.00 DRILL P PROD1 Displace to drill in fluid - Pump 40 bbls high vis polymer spacer followed by 9.1 ppg flo-Pro mud - displace at 350 gpm, rotating at 120 rpm's 06:00 - 06:30 0.50 DRILL P PROD1 Monitor well, Clean out from under shakers - obtain Slow pump rates with new mud system - Pump slug 06:30 - 11 :30 5.00 DRILL P PROD1 Pooh, Stand back BHA 11 :30 - 12:30 1.00 DRILL P PROD1 Make up BHA: Make up Hughes 6 1/8" MX-20DX insert bit Printed: 6/22/2004 10: 14:03 AM - e Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: V-02 V-02 DRILL+COMPLETE NABORS ALASKA DRILLING I NABORS 9ES Start: 5/17/2004 Rig Release: 6/18/2004 Rig Number: Spud Date: 5/18/2004 End: 6/18/2004 5/31/2004 11 :30 - 12:30 1.00 DRILL P PROD1 jetted wI 3-12's, Anadrill 4 3/4 motor set at 1.5 deg bend, MWD/Gr/Res/PWD 12:30 - 15:30 3.00 DRILL P PROD1 TIH fill pipe every 25 stands - Break circulation at 9,127' and wash to bottom at 9,257' 15:30 - 16:00 0.50 DRILL P PROD1 Drill 9,257 to 9,277' - pull into casing 16:00 - 16:30 0.50 DRILL P PROD1 Preform FIT: Test formation to 700 psi at 9,255'md I 8,750' tvd with 9.0 ppg mud in hole, 10.5 EMW 16:30 - 00:00 7.50 DRILL P PROD1 Directional drill 9,277' to 9,465' - 100% sliding Ast 5.54 hrs, Average rop 34 ft/hr - build angle and turn to right - Pumping 290 - 300 gpm at 2200 psi - plu 184k, s/o 456k 6/1/2004 00:00 - 00:00 24.00 DRILL P PROD1 Directional Drill 9,465' to 10,590' - projecting to target #4 11,480' MD - 8,936'TVD. AST =9.07 hrs ART =7.84 hrs. Sliding getting more diffucult. Mud wt 9.1 ppg. Pumping 275 gpm 2,200 psi.CAL ECD=10.38 ppg, ECD=10.43 ppg. plu wt 204 dn wt 155 6/2/2004 00:00 - 04:00 4.00 DRILL P PROD1 Continue drilling to 10711'. Attempting to slide to drop angle but getting no response from motor. Got up to TVD of 8956' and still at 93.6 deg. Approaching target TVD of 8936' too rapidly. Decision to POH & chk bit for undergauge wear. 04:00 - 06:00 2.00 DRILL P PROD1 Circ hole clean at 275 gpm. Rotary speed 60 rpm. Pump hi vis sweep around. 06:00 - 07:30 1.50 DRILL P PROD1 Monitor well. POOH to 9,404' 1 minI std. Drag 5k - 10k over. 07:30 - 09:30 2.00 DRILL P PROD1 Mad Pass f/ 9,404' - 9,030'. 09:30 - 13:30 4.00 DRILL P PROD1 Monitor well - pump dry job. POOH to HWDP. Hole in good shape. 13:30 - 15:00 1.50 DRILL P PROD1 LD 4" HWDP and rest of BHA - down load Iwd's 15:00 - 17:00 2.00 DRILL P PROD1 MU BHA#7 - 61/8" PDC bit, Rotary steerable tools, MWD/LWD - Test tools at surface. Bit was worn with broken/missing teeth and gauge buttons were worn round. 1/16 under gauge. 17:00 - 17:30 0.50 DRILL P PROD1 RIH to 1,171'. 17:30 - 18:00 0.50 DRILL P PROD1 Service rig. 18:00 - 20:30 2.50 DRILL P PROD1 Cont RIH to 9,200' - fill DP @ 3100',6300',& 9200'. 20:30 - 22:00 1.50 DRILL P PROD1 PJSM - Cut and slip drilling line. 22:00 - 23:00 1.00 DRILL P PROD1 Cont RIH & tagged up @ 10,048' w/ 50k on bit. 23:00 - 00:00 1.00 DRILL P PROD1 MU Top drive. Pump and rotate f/1 0,048' - 10,318. 6/3/2004 00:00 - 00:30 0.50 DRILL P PROD1 Cont wash and rotate down f/10,318' - 10,692' staging pumps up to 300 gpm 12,345 psi 1140 rpm. 00:30 - 20:00 19.50 DRILL P PROD1 Obtain base line ECD readings. Drill with rotary steerable system f/10,711' - 11,847'. Anadril Rotary steerable tools failed. Getting no response from commands sent down to tool. ART=13.39 hrs. ECD=10.69 ppg 20:00 - 22:00 2.00 DRILL N DFAL PROD1 Circ hole clean. Pumped lo/hi sweep around. circ bottoms up 3 times. ECD=10.61 ppg 22:00 - 00:00 2.00 DRILL N DFAL PROD1 Monitor well - ok. POOH to 9200' - hole in good shape- one tight spot at 10,905' - pulled 50k over. 6/4/2004 00:00 - 03:00 3.00 DRILL N DFAL PROD1 POOH to BHA. 03:00 - 04:00 1.00 DRILL N DFAL PROD1 Stand back jars and flex collars - LD MWD I LWD, RSS tools. Bit in new conditon. 04:00 - 04:30 0.50 DRILL N DFAL PROD1 Down load and reprogram LWD. Clear rig floor. 04:30 - 07:30 3.00 DRILL N DFAL PROD1 MU BHA #8 - Re-run Bit #7, Rotary steerable tools, MWD I LWD. Surface test tools. 07:30 - 11 :30 4.00 DRILL N DFAL PROD1 RIH to shoe 11 :30 - 12:00 0.50 DRILL N DFAL PROD1 Service top drive and DW Printed: 6/22/2004 10: 14:03 AM e e legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: V-02 V-02 DRlll+COMPlETE NABORS ALASKA DRilLING I NABORS 9ES Start: Rig Release: Rig Number: 5/1 7/2004 6/18/2004 Spud Date: 5/18/2004 End: 6/18/2004 6/412004 12:00 - 14:00 2.00 DRILL N DFAL PROD1 Cont RIH fI shoe to 11,754'. Tight at 10,905'. Work pipe - "OK". Stage up pumps to drlg rate - wash to bottom at 11,847'. Hole cleaned up good at bu's. Cal ECD=10.66ppg, ECD=10.89 ppg. 14:00 - 19:00 5.00 DRILL P PROD1 Drill f/11 ,847' to 12,120'. Anadrill RSS tools failed. Getting no reaction from commands sent down to tool. ART =3.67 hrs ECD=10.73 ppg. 19:00 - 21 :00 2.00 DRILL N DFAL PROD1 CBU 2X at drill rate. ECD = 10.69 ppg 21 :00 - 22:00 1.00 DRILL N DFAL PROD1 Start POOH for mud motor. Pulled up to 50K over at 10,905' 22:00 - 22:30 0.50 DRILL N DFAL PROD1 Back Ream f/1 0,940' to 10,850 two times. Slight pack off - 200psi - 300psi pump press increase. 22:30 - 00:00 1.50 DRILL N DFAL PROD1 Continue POOH to shoe. Monitor well - ok. 6/5/2004 00:00 - 03:00 3.00 DRILL N DFAL PROD1 POOH to BHA. 03:00 - 04:30 1.50 DRILL N DFAL PROD1 Monitor well. Stand back jars and flex collars. LD BHA. Bit new condition. Clear floor. Down load VPWD. 04:30 - 06:00 1.50 DRILL N DFAL PROD1 MU BHA #9 - 6.125" tri-cone bit, 1.5 deg motor, MWD I LWD, orient tools. RIH I BHA. 06:00 - 09:30 3.50 DRILL N DFAL PROD1 RIH wI DP - Test MWD @ 1,080'. RIH to 8,450'. Fill pipe. 09:30 - 10:00 0.50 DRILL N DFAL PROD1 PU 24 jts 4" HWDP. 10:00 - 11 :00 1.00 DRILL N DFAL PROD1 Cut and slip drilling line. 11 :00 - 11 :30 0.50 DRILL N DFAL PROD1 Service top drive. 11 :30 - 13:00 1.50 DRILL N DFAL PROD1 Cont RIH to 11,989'. Open hole in good shape on trip in. 13:00 - 13:30 0.50 DRILL N DFAL PROD1 MU Top Drive. Stage up pumps to 300 gpm. Wash to bottom at 12,120'. 13:30 - 00:00 10.50 DRILL P PROD1 Drill ahead f/ 12,120' - 12,395'. Changed out mud with 580 bbls new flopro mud @ 8.9 ppg. Cal ECD=10.27 ppg, ECD= 10.33 ppg. AST=7.4 hrs, ART= 0 hrs. 6/6/2004 00:00 - 00:00 24.00 DRILL P PROD1 Continue drilling ahead in 6 118" hole fl12,395' - 13,350'.100% sliding for right hand turn - getting avg 12 deg doglegs. Cal ECD=10.35 ppg, ECD= 10.68 ppg, AST=16.9 hrs, ART= 0 hrs. No problems. 6/7/2004 00:00 - 03:30 3.50 DRILL P PROD1 Drill f/13,350' to 13,544'. Lost 150 psi pump pressure. 03:30 - 05:00 1.50 DRILL P PROD1 Circ - Go thru pumps and check surface lines for leaks. 05:00 - 16:30 11.50 DRILL P PROD1 Continue Drill f/13,544' - 13,950'. ROP 30 FPH - motor stalling with bit on bottom. Acts like bit or motor are damaged. AST =1.38 hrs, ART =9.19 hrs. Cal ECD=1 0.37 ppg, ECD= 10.72 ppg 16:30 - 18:30 2.00 DRILL P PROD1 Circ hole clean for trip - bottoms up 3 times. Cal ECD= 10.39 ppg, ECD = 10.78 ppg. 18:30 - 00:00 5.50 DRILL P PROD1 Monitor well - o.k. POOH to shoe. Pulled 40K over at 11,230'. Work pipe thru tight spot at 11,230'. Monitor well at shoe. 6/8/2004 00:00 - 01 :00 1.00 DRILL P PROD1 POOH to BHA. 01 :00 - 02:00 1.00 DRILL P PROD1 Stand back jars and flex collars, break off bit - 1/2" under gage & cutting structure severely damaged. LD PWD, MWD, and motor. 02:00 - 02:30 0.50 DRILL P PROD1 Clear rig floor, down load PWD, PJSM. 02:30 - 03:30 1.00 DRILL P PROD1 PU BHA #10 - 61/8" MX-09, 1.5 deg motor, MWD ILWD- orient tools - surface test. 03:30 - 07:00 3.50 DRILL P PROD1 RIH to 5000', 9200', fill pipe 07:00 - 08:00 1.00 DRILL P PROD1 Slip I cut drilling line, 46' 08:00 - 08:30 0.50 DRILL P PROD1 Service crown and top drive 08:30 - 10:30 2.00 DRILL P PROD1 RIH to 13,297' 10:30 - 12:30 2.00 DRILL P PROD1 Make up top drive, stage pumps up, wash I ream from 13,297' to 13,950', 270 GPM, 2670 PSI, 40 RPM, 4K TQ Printed: 6/22/2004 10: 14:03 AM e e Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: V-02 V-02 DRILL+COMPLETE NABORS ALASKA DRILLING I NABORS 9ES Start: Rig Release: Rig Number: 5/17/2004 6/18/2004 Spud Date: 5/18/2004 End: 6/18/2004 6/812004 10:30 - 12:30 2.00 DRILL P PROD1 190K UP, 150K DN, 170K RT 12:30 - 14:00 1.50 DRILL P PROD1 Drill 6 1/8" well bore from 13,950' to 14,045', 200K UP, 130K DN, 168 RT, 300 GPM, 3060 PSI ON, 2900 PSI OFF, 60 RPM 15 - 20K WOB, 7 - 9K TO ON, 5K TQ OFF, CAL ECD 10.40, ACT ECD 10.90 Backream, survey each stand, AST 0.2 HR, ART 0.9 HR 14:00 - 15:00 1.00 DRILL P PROD1 MAD pass from 14,041' to 13,845' at drilling rate 15:00 - 16:30 1.50 DRILL N DFAL PROD1 Circulate 2 bottoms up at 300 GPM, 2880 PSI, 60 RPM, 167 RT, 4K TO, CAL ECD 10.40, ACT ECD 10.75 16:30 - 22:30 6.00 DRILL N DFAL PROD1 Monitor wellbore, POOH, pull 30K over at 11,270', work pipe, pump dry job at 10,800', POOH to BHA 22:30 - 00:00 1.50 DRILL N DFAL PROD1 Flush tools with fresh water, stand back jars and DCs, lay down VPWD and MWD I LWD, check bit 6/9/2004 00:00 - 01 :00 1.00 DRILL N DFAL PROD1 Make up BHA # 11, new MWD, new circ sub, change bit to MX20DX, RIH to 260', test MWD at 275 GPM, 1080 PSI 01 :00 - 03:30 2.50 DRILL N DFAL PROD1 RIH to 4950',9280', fill pipe 03:30 - 04:00 0.50 DRILL N DFAL PROD1 Rig service, service top drive 04:00 - 06:00 2.00 DRILL N DFAL PROD1 RI H to 12,175', 13,950', fill pipe 06:00 - 06:30 0.50 DRILL N DFAL PROD1 Break circulation, stage pumps up to 250 GPM, 2250 PSI 06:30 - 07:00 0.50 DRILL N DFAL PROD1 Mad Pass from 13,950' to 14,044', 300 GPM, 2550 PSI, 130K DN 07:00 - 12:00 5.00 DRILL P PROD1 Dir drill from 14,045' to 14,231', 200K UP, 125K DN, 167K RT 6-10 TO ON, 300 GPM, 2880 PSI OFF, 3170 PSI ON, Cal ECD 10.40, Act ECD 10.77, AST 0.25, ART 2 12:00 - 18:00 6.00 DRILL P PROD1 Dirdrillfrom14,231't014,573', 207KUP, 118KDN, 169KRT 9-10 TO ON, 250 GPM, 2470 PSI OFF, 2350 PSI ON, Cal ECD 10.45, Act ECD 10.61, Mud losses at +1- 20 BPH from 14,300' Add Safecarb and S200 to reduce losses 18:00 - 19:30 1.50 DRILL P PROD1 Circulate bottom hole sample for Geology at 14,573' 19:30 - 00:00 4.50 DRILL P PROD1 Dir drill from 14,573' to 14,696', 205K UP, 120K DN, 170K RT 9-10 TO ON, 6.5 TO OFF, 250 GPM, 2340 PSI OFF, 2570 PSI ON, 60 RPM, 20K WOB, Backream each stand Cal ECD 10.47, Act ECD 10.79, AST 0.5, ART 6.46 Mud losses at +1- 15 BPH, adding Safecarb 6/10/2004 00:00 - 01 :30 1.50 DRILL P PROD1 Dir drill from 14,696' to 14,862' 205K UP, 115K DN, 170K RT, 60 RPM, 18-20K WOB 10.5 TO ON, 6.5 TO OFF, 250 GPM, 2650 PSI ON, 2450 PSI OFF, Cal ECD 10.7, Act ECD 10.77 Backream every stand, survey every single 01 :30 - 02:00 0.50 DRILL P PROD1 Circulate bottom hole sample for geology 02:00 - 12:00 10.00 DRILL P PROD1 Dir drill from 14,862' to 15,017' 205K UP, 119K DN, 167K RT, 60 RPM, 18-20K WOB 9-10 TO ON, 6-7 TO OFF, 2650 PSI ON, 2450 PSI OFF Cal ECD 10.76, Act ECD 10.96, ART 4.36, AST 2.06 Backream every stand, survey every single Mud losses from 00:00 to 12:00 263 bbls 12:00 - 20:30 8.50 DRILL P PROD1 Dir drill from 15,017' to 15,087' TD - Hard sliding f/14,977' - 15,035'. Spotted two glass bead pills. Unable to slide.Decided bit was worn out. Continue drilling to T.D. @ 15,086'. ROP 7'per hour. Pyrite Ichert in samples 15,075' -15,086'. 205K UP, 130K DN, 166K RT, 40 RPM, 20K WOB Printed: 6/22/2004 10: 14:03 AM e e Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: V-02 V-02 DRILL+COMPLETE NABORS ALASKA DRILLING I NABORS 9ES Start: Rig Release: Rig Number: 5/17/2004 6/1 8/2004 Spud Date: 5/18/2004 End: 6/18/2004 6/10/2004 12:00 - 20:30 8.50 DRILL P PROD1 8.3 TO ON, 6.5 TO OFF, 2600 PSI ON, 2450 PSI OFF Cal ECD 10.31, Act ECD 10.85, ART 3.85, AST 0.93 Backream every stand, survey every single Mud losses from 12:00 to 20:30 176 bbls Mud losses for well 660 bbls 20:30 - 00:00 3.50 DRILL P PROD1 Circulate bottoms up, pump Hi-Vis sweep surf/surf, slight increase in cuttings at shaker, mostly glass beads, pump total of 3 bottoms up at 250 GPM, 2730 PSI, 80 RPM, 7 TO, 166K RT Cal ECD 10.31, Act ECD 10.6 Pumping 220 bbls balanced liner running pill 6/11/2004 00:00 - 00:30 0.50 DRILL P PROD1 Pump 220 bbls of balanced liner running pill, monitor well bore, pump dry job 00:30 - 04:30 4.00 DRILL P PROD1 Trip out, monitor wellbore for losses, drop 2 3/8" rabbit 04:30 - 05:00 0.50 DRILL P PROD1 Rig service, service top drive, well bore dropped 2 feet in ten minutes 05:00 - 06:30 1.50 DRILL P PROD1 Trip out, monitor wellbore for losses, rack back drillpipe 06:30 - 10:30 4.00 DRILL P PROD1 Lay down 186 jts drillpipe 10:30 - 11 :30 1.00 DRILL P PROD1 Flush BHA with fresh water, lay down BHA 11 :30 - 12:00 0.50 DRILL P PROD1 Clear and clean rig floor, send out jewelry 12:00 - 13:00 1.00 CASE P LNR1 Rig up 4 1/2" liner running equipment 13:00 - 13:30 0.50 CASE P LNR1 PJSM with all rig crew and power tong hand 13:30 - 20:30 7.00 CASE P LNR1 Run 143 jts 41/2", 12.6 #, L-80, BTC-Mod, 5931.64' with 78.55' jewelry, total length 6010.55' 4000 ftllbs TO, fill each jt 20:30 - 21 :30 1.00 CASE P LNR1 Prepare / run Baker ZXP packer, make up plug dropping head 21 :30 - 22:00 0.50 CASE P LNR1 Circulate liner volume at 3 BPM, 400 PSI, 107K UP, 102K DN 22:00 - 00:00 2.00 CASE P LNR1 Run 41/2" liner on drillpipe at 9007', fill every 10 stands Run at 2 minutes per stand, 00:00 to 12:00 mud losses at 121 bbls 12:00 to 00:00 mud losses at 38 bbls Total losses 819 bbls 6/12/2004 00:00 - 00:30 0.50 CASE P LNR1 Run 4 1/2" liner on DP f/7,993' to 9,113'. 00:30 - 01 :30 1.00 CASE P LNR1 CBU @ 7" shoe - 3 BPM - 650 psi. Up WT - 150K, down wt - 140K. Mud loss 5 -10 bbls/hr. 01 :30 - 02:00 0.50 CASE P LNR1 M.U cementing head and set on skate. 02:00 - 06:30 4.50 CASE P LNR1 RIH w/4 1/2" liner f/9, 113' - 14,746'. Fill DP every 10 stands. 06:30 - 07:00 0.50 CASE P LNR1 RIH to 15,079' - Work thru tight spot f/14,746' to 14,752' and 15,010' 'to 15,015'. 07:00 - 10:30 3.50 CASE P LNR1 MU cement head - wash 8' to bottom @ 15,086'. Circ and cond mud - stage pumps up to 5 bpm @ 1,530 psi. Recipicate pipe. Mud loss 5 bbls/hr. Str wt 195K up and 135K down. PJSM. Batch up spacer and cement. 10:30 - 12:30 2.00 CEMT P LNR1 Presure test lines to 4,500 psi. Dowell cemented 4 1/2" liner pumping 35 bbls Mud Push 11 @ 10.0 ppg, 149 bbls Class "G" wI additives at 15.8 ppg (532 sx). Dowell dispaced @ 4.5- 5 bpm wI 9.0 ppg mud. Unable to recipicate after cement out shoe. Full returns. Bumped plug to 4,000 psi. Plug down at 12:15 hrs. 4.5" Liner top @ 9,054', shoe @ 15,084'. Set packer with 50K DN, 15 RPM, pressure up to 500 psi, unsting, packer set as per Baker Rep 12:30 - 13:00 0.50 CEMT P LNR1 Circulate bottoms up, 10 bpm, 2560 psi, 30 bbls of good cement to surface Printed: 6/22/2004 10: 14:03 AM e e Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: V-02 V-02 DRILL+COMPLETE NABORS ALASKA DRILLING I NABORS 9ES Start: Rig Release: Rig Number: 5/17/2004 6/18/2004 Spud Date: 5/18/2004 End: 6/18/2004 6/12/2004 13:00 - 14:00 1.00 CEMT P LNR1 Rig down cement head, lay down cement head 14:00 - 15:00 1.00 CASE P LNR1 Slip and cut 104' of drilling line 15:00 - 15:30 0.50 CASE P LNR1 Service top drive and crown 15:30 - 19:30 4.00 CASE P LNR1 Pump dry job, trip out 19:30 - 20:00 0.50 CASE P LNR1 Inspect, break down Baker running tools, lay down tools 20:00 - 20:30 0.50 CASE P LNR1 Flush BOP stack 20:30 - 21 :00 0.50 CASE P LNR1 Pull wear bushing, run test plug, rig up BOP test equipment 21 :00 - 00:00 3.00 CASE P LNR1 Pressure test BOP equipment at 250 13500 psi, witness waived by John Crisp AOGCC Rep 6/13/2004 00:00 - 00:30 0.50 CASE P LNR1 Pressure test BOPe, 250 / 3500 psi 00:30 - 01 :00 0.50 CASE P LNR1 Pull test plug, run wear bushing, blow down kill I choke lines 01 :00 - 03:00 2.00 CASE P LNR1 PJSM, change out lower actuator valve and test same 03:00 - 03:30 0.50 CLEAN P CLEAN PJSM, PU, MU, run 3 1/8" BHA, 27/8" drill string 03:30 - 12:00 8.50 CLEAN P CLEAN MU, PU, 3 1/8" BHA, 2 7/8" Dp, drift on skate, 186 jts 12:00 - 16:00 4.00 CLEAN P CLEAN RIH w/ first stand of 4" DP, pump volume of 27/8" DP, at 112 gpm, 1075 psi, RIH, fill pipe at 9042',14,125', 194K UP, 155K DN wlo pump 16:00 - 16:30 0.50 CLEAN P CLEAN Wash from 14,925' to 14,984', scraper at 9016' 194KUP, 155KDN, 112gpm, 1880 psi 16:30 - 18:30 2.00 CLEAN P CLEAN Circulate bottoms up at 116 gpm, 2090 psi 18:30 - 19:30 1.00 CLEAN P CLEAN Rig up to test casing, test to 3500 psi for 30 minutes, rig down 19:30 - 21 :00 1.50 CLEAN P CLEAN Displace 100 bbls of perf pill in liner 21 :00 - 21 :30 0.50 CLEAN P CLEAN Pull 7 stands of 4" DP 21 :30 - 22:30 1.00 CLEAN P CLEAN Drop ball, open CÎrc sub wI 1800 psi, displace casing w/18 bbls spacer, followed by 9.0 ppg brine, start at 8 bpm, 1200 psi increase to 10 bpm, 1600 psi until clean brine to surface 22:30 - 23:30 1.00 CLEAN P CLEAN Clean mud troughs, shakers, tanks, 23:30 - 00:00 0.50 CLEAN P CLEAN Service top drive, crown 6/14/2004 00:00 - 04:00 4.00 CLEAN P CLEAN POH, rack 4' DP in derrick, lay down scraper 04:00 - 05:30 1.50 CLEAN P CLEAN PJSM, change out to 2 7/8" handling equipment, make derrick ready with ropes for racking 2 7/8" DP 05:30 - 06:00 0.50 CLEAN P CLEAN Pressure up to open circ sub, pump dry job 06:00 - 13:30 7.50 CLEAN P CLEAN POH, rack 15 stands of 2 7/8" in derrick, lay down 141 jts, BHA 13:30 - 14:00 0.50 CLEAN P CLEAN Clear and clean rig floor, send out clean out BHA 14:00 - 15:00 1.00 PERFOB P OTHCMP Load pipe shed with perf guns 15:00 - 15:30 0.50 PERFOB P OTHCMP PJSM, Schlumberger and rig crew on running perf guns 15:30 - 00:00 8.50 PERFOB P OTHCMP RIH wI perf assembly as per TCP program 6/15/2004 00:00 - 01 :00 1.00 PERFOB P OTHCMP Pick up perf gun assembly to 4605' 01 :00 - 02:00 1.00 PERFOB P OTHCMP PJSM, rig up, RIH w/2 7/8" pipe to 5694' 02:00 - 02:30 0.50 PERFOB P OTHCMP PJSM, rig up to run 4" DP, remove belly ropes from derrick 02:30 - 06:30 4.00 PERFOB P OTHCMP RIH wI 4" DP to 14,985' 06:30 - 07:00 0.50 PERFOB P OTHCMP Safety meeting wI crew and Schlumberger hands 07:00 - 07:30 0.50 PERFOB P OTHCMP Perforate as per program 07:30 - 09:30 2.00 PERFOB P OTHCMP Trip out 51 stands 4" DP, guns above upper perfs, Wellbore taking 2 bbls/hr, then 10 bbls/hr 09:30 - 10:00 0.50 PERFOB P OTHCMP Circulate bottoms up, pump dry job, 10:00 - 13:00 3.00 PERFOB P OTHCMP Trip out, lay down 4" DP Wellbore losses 10 bbls/hr 13:00 - 15:30 2.50 PERFOB P OTHCMP Trip out, lay down 2 7/8" DP Wellbore losses 5 bbls/hr 15:30 - 16:00 0.50 PERFOB P OTHCMP PJSM, change handling tools to lay down guns Wellbore losses 5 bbls/hr 16:00 - 00:00 8.00 PERFOB P OTHCMP Trip out, lay down perf guns in 20' sections Printed: 6/22/2004 10: 14:03 AM e . Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: V-02 V-02 DRILL+COMPLETE NABORS ALASKA DRILLING I NABORS 9ES Start: 5/17/2004 Rig Release: 6/18/2004 Rig Number: Spud Date: 5/18/2004 End: 6/18/2004 6/15/2004 16:00 - 00:00 8.00 PERFOB P OTHCMP Well bore losses 5 bbls/hr 6/16/2004 00:00 - 01 :30 1.50 PERFOB P OTHCMP Trip out, lay down 2 1/16" pipe Wellbore losses 5 bbls/hr 01 :30 - 03:30 2.00 PERFOB P OTHCMP PJSM, lay down guns Well bore losses 5 bbls/hr 03:30 - 04:30 1.00 PERFOB P OTHCMP Lay down 2 1/16" pipe Wellbore losses 5 bbls/hr 04:30 - 06:00 1.50 PERFOB P OTHCMP Lay down guns, 100 % fired Wellbore losses 5 bbls/hr 06:00 - 07:00 1.00 PERFOB P OTHCMP Clear and clean rig floor Wellbore losses at 5 bbls/hr 07:00 - 08:30 1.50 RUNCOMP RUNCMP RIH 35 stands of 4" DP, 3262' Wellbores losees at 2 bbls/hr 08:30 - 09:00 0.50 RUNCOMP RUNCMP Move HWDP from one of the derrick to other side Well bore losses at 5 bbls/hr 09:00 - 09:30 0.50 RUNCOMP RUNCMP PJSM, slip and cut 98' of drilling line Well bore losses at 5 bbls/hr 09:30 - 10:00 0.50 RUNCOMP RUNCMP Service top drive Wellbore losses at 5 bbls/hr 10:00 - 12:30 2.50 RUNCOMP RUNCMP Trip out, lay down 105 its 4" DP Well bore losses at 5 bbls/hr 12:30 - 13:00 0.50 RUNCOMP RUNCMP Pull wear bushing 13:00 - 14:30 1.50 RUNCOMP RUNCMP Make dummy run with tubing hanger, rig to run tubing 14:30 - 00:00 9.50 RUNCOMP RUNCMP Run 3 1/2" completion string Well bore losses at 3 bbls/hr 6/17/2004 00:00 - 01 :00 1.00 RUNCOrvP RUNCMP RIH wI completion string, 9060' Wellbore losses at 3 bbls/hr running tubing, Well bore losses at 5 bbls/hr static 01 :00 - 01 :30 0.50 RUNCOMP RUNCMP Lay down 4 jts 3 1/3" tubing, pick up 4 pup its for space out 01 :30 - 02:00 0.50 RUNCOrvP RUNCMP MU 4 1/2" XIO and it of tubing to tubing hanger, 02:00 - 03:00 1.00 RUNCOrvP RUNCMP Land hanger, run in LDS 03:00 - 04:30 1.50 RUNCOrvP RUNCMP Rig up, reverse circulate 124 bbls of clean inhibited 9.0 ppg brine, 7" x 31/2" annulus, chase with 129 bbls brine 04:30 - 05:00 0.50 RUNCOrvP RUNCMP Drop ball, lay down landing jt 05:00 - 05:30 0.50 RUNCOrvP RUNCMP Set Baker packer with 4200 psi, hold tubing for 30 minutes, charted, 05:30 - 06:00 0.50 RUNCOrvP RUNCMP Test packer, pump down annulus, annulus I tubing equalized 06:00 - 06:30 0.50 RUNCOrvP RUNCMP Re-test packer, annulus I tubing equalized 06:30 - 07:00 0.50 RUNCOrvP RUNCMP Set TWC wI DSM and test on top to 1000 psi, blow down kill line 07:00 - 08:30 1.50 RUNCOrvP RUNCMP Pull mouse hole, drain BOP stack, Pull riser, turn buckles, cIa bales 08:30 - 09:30 1.00 RUNCOMP RUNCMP ND BOPs, set back on rack 09:30 - 13:00 3.50 RUNCOMP RUNCMP NU adapter flange and tree 13:00 - 13:30 0.50 RUNCOMP RUNCMP Pressure test adapter flange to 5000 psi for 10 minutes, test tree to 250 I 5000 psi 13:30 - 14:30 1.00 RUNCOMP RUNCMP RU DSM to pull TWC, RD same 14:30 - 17:30 3.00 RUNCOMN DFAL RUNCMP RU schlumberger slickline unit, test extension, lubricator to 1 000 psi 17:30 - 20:30 3.00 RUNCOMN DFAL RUNCMP Run # 1, set X lock catcher at 8996' 20:30 - 21 :30 1.00 RUNCOMN DFAL RUNCMP Run # 2, run in to pull DCR shear valve, miss-run 21 :30 - 22:00 0.50 RUNCOMN DFAL RUNCMP Redress pulling tool 22:00 - 00:00 2.00 RUNCOMN DFAL RUNCMP Run # 3, run in to pull DCR shear valve, pulled valve Printed: 6/22/2004 10: 14:03 AM e e Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: V-02 V-02 DRILL+COMPLETE NABORS ALASKA DRILLING I NABORS 9ES Start: 5/17/2004 Rig Release: 6/18/2004 Rig Number: Spud Date: 5/18/2004 End: 6/18/2004 6/18/2004 00:00 - 01 :00 1.00 RUNCOfv1\l DFAL RUNCMP Run # 4, run in to set new DCR valve 01 :00 - 02:30 1.50 RUNCOfv1\l DFAL RUNCMP RD slickline, place tools to side on rig floor. RU to pressure test tubing, annulus 02:30 - 03:00 0.50 RUNCOfv1\l DFAL RUNCMP Pressure test tubing to 4200 psi for 30 minutes, charted Bleed down to 2500 psi, 03:00 - 03:30 0.50 RUNCOfv1\l DFAL RUNCMP Pressure test annulus to 3500 psi, charted 03:30 - 04:00 0.50 RUNCOfv1\l DFAL RUNCMP Bleed down all pressure, pump down annulus, shear DCR valve at 2500 psi 04:00 - 06:30 2.50 RUNCOfv1\l DFAL RUNCMP Rig up slickline, Run # 5, run in to retrieve X lock catcher at 8996', 06:30 - 07:30 1.00 RUNCOfv1\l DFAL RUNCMP RD slickline, clear floor 07:30 - 08:00 0.50 WHSUR P OTHCMP RU hot oil lines to freeze protect 08:00 - 10:00 2.00 WHSUR P OTHCMP Pump 77 bbls diesel down annulus at 3 bpm 300-500 psi Allow to U-tube 10:00 - 11 :00 1.00 WHSUR P OTHCMP Install BPV w/DSM, lubricator, test to 1000 psi from below, RD same 11 :00 - 12:00 1.00 WHSUR P OTHCMP RD lines and install VR plugs in outer annulus and inner annulus ports, secure tree and cellar RIG RELEASED AT 12:00 HRS Printed: 6/22/2004 10:14:03 AM V-02 Survey Report lum rger Report Date: 11-Jun-04 Survey I DLS Computation Method: Minimum Curvature I Lubinski Client: BP Exploration Alaska Vertical Section Azimuth: 300.000' Field: Prudhoe Bay Unit - WOA Vertical Section Origin: N 0.000 ft, E 0.000 ft Structure I Slot: V-Pad I Plan V-02 (N-I) TVD Reference Datum: Rotary Table Well: V-02 TVD Reference Elevation: 81.6 ft relative to MSL Borehole: V-02 Sea Bed I Ground Level Elevation: 53.10 ft relative to MSL UWUAPI#: 500292320900 Magnetic Declination: 24.97' Survey Name I Date: V-021 June 11, 2004 Total Field Strength: 57567.990 nT Tort I AHD I 0011 ERD ratio: 442.999' 17302.51 ftl 6.734 I 0.810 Magnetic Dip: 80.82' Grid Coordinata Systam: NAD27 Alaska State Planes, Zone 04, US Feet Declination Date: 21-May-04 Location Lat/Long: N 70.32798975, W 149.26606211 Magnetic Declination Model: BGGM 2003 Location Grid N/E YIX: N 5970077.630 ftUS, E 590496.880 ftUS North Reference: True North e Grid Convergence Angle: +0.69110597' Total Carr Mag North -> True North: +24.97' Grid Scale Factor: 0.99990930 Local Coordinates Referenced To: Well Head I Comments Measured Inclination I Azimuth I Sub-Sea TVD I TVD Vertical I Along Hole I NS EW I DLS I Build Rate I Walk Rate I Northing Easting Latitude Longitude Survey Tool Depth Section Departure Model (It) (deg) (dog ) (It) (It) (It) (It) (It) (It) (degf100 It) (deg/·IOO It) (dogf100 It) (ltUS) (ltUS) RTE 0.00 0.00 0.00 -81.60 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 5970077.63 590496.88 N 70.32798975 W 149.26606211 BP _UNKNOWN Gyro 100.00 0.19 310.67 18.40 100.00 0.16 0.17 0.11 -0.13 0.19 0.19 0.00 5970077.74 590496.75 N 70.32799004 W 149.26606313 BP _GYD GC MS 200.00 0.39 297.91 118.40 200.00 0.67 0.67 0.38 -0.55 0.21 0.20 -12.76 5970078.00 590496.32 N 70.32799077 W 149.26606659 BP _GYD GC MS 300.00 1.44 229.88 218.39 299.99 1.43 2.14 -0.27 -1.81 1.34 1.05 -68.03 5970077 .33 590495.07 N 70.32798900 W 149.26607682 BP _GYD GC MS 400.00 1.81 220.92 318.35 399.95 2.16 4.97 -2.28 -3.81 0.45 0.37 -8.96 5970075.31 590493.10 N 70.32798353 W 149.26609300 BP _GYD GC MS 500.00 3.03 179.58 418.26 499.86 1.12 9.02 -6.11 -4.82 2.05 1.22 -41.34 5970071.46 590492.13 N 70.32797304 W 149.26610124 BP _GYD GC MS 600.00 3.82 173.71 518.08 599.68 -2.19 14.99 -12.07 -4.44 0.86 0.79 -5.87 5970065.51 590492.59 N 70.32795678 W 149.26609812 BP _GYD GC MS 700.00 4.64 176.81 617.81 699.41 -6.37 22.36 -19.42 -3.85 0.85 0.82 3.10 5970058.17 590493.26 N 70.32793670 W 149.26609333 BP _GYD GC MS 800.00 5.73 178.84 717.40 799.00 -11.17 31.40 -28.45 -3.52 1.11 1.09 2.03 5970049.14 590493.70 N 70.32791203 W 149.26609069 BP _GYD GC MS Last Gyro Survey 900.00 7.13 184.58 816.77 898.37 -16.42 42.59 -39.63 -3.92 1.54 1.40 5.74 5970037.96 590493.44 N 70.32788149 W 149.26609389 BP _GYD GC MS MWD 948.98 7.38 183.45 865.36 946.96 -19.13 48.78 -45.80 -4.35 0.59 0.51 -2.31 5970031 .79 590493.08 N 70.32786464 W 149.26609739 BP _MWD+IFR+MS 1 039.40 6.23 177.75 955.14 1036.74 -24.34 59.48 -56.50 -4.51 1.47 -1.27 -6.30 5970021 .09 590493.05 N 70.32783541 W 149.26609866 BP _MWD+IFR+MS 1132.35 4.41 175.49 1047.68 1129.28 -29.06 68.10 -65.10 -4.03 1.97 -1.96 -2.43 5970012.49 590493.64 N 70.32781191 W 149.26609478 BP _MWD+IFR+MS 1224.72 2.68 168.13 1139.87 1221.47 -32.51 73.80 -70.75 -3.30 1.93 -1.87 -7.97 5970006.85 590494.43 N 70.32779646 W 149.26608891 BP _MWD+IFR+MS 1316.97 2.41 164.43 1232.03 1313.63 -35.34 77.90 -74.73 -2.34 0.34 -0.29 -4.01 5970002.88 590495.44 N 70.32778559 W 149.26608109 BP _MWD+I~. 1411.66 2.12 161.54 1326.65 1408.25 -38.07 81.64 -78.31 -1.25 0.33 -0.31 -3.05 5969999.32 590496.57 N 70.32777581 W 149.26607226 BP _MWD+IF 1505.35 0.78 169.64 1420.31 1501.91 -39.78 84.00 -80.58 -0.59 1.44 -1.43 8.65 5969997.05 590497.26 N 70.32776961 W 149.26606688 BP _MWD+IFR+MS 1598.26 0.55 159.03 1513.21 1594.81 -40.54 85.08 -81.62 -0.31 0.28 -0.25 -11.42 5969996.02 590497.55 N 70.32776677 W 149.26606467 BP _MWD+IFR+MS 1691.55 0.66 157.34 1606.50 1688.10 -41.31 86.06 -82.53 0.05 0.12 0.12 -1.81 5969995.11 590497.93 N 70.32776427 W 149.26606169 BP_MWD+IFR+MS 1784.29 0.90 176.80 1699.23 1780.83 -42.14 87.32 -83.75 0.30 0.38 0.26 20.98 5969993.89 590498.19 N 70.32776094 W 149.26605969 BP _MWD+IFR+MS 1877.84 0.92 172.89 1792.77 1874.37 -42.99 88.80 -85.23 0.43 0.07 0.02 -4.18 5969992.42 590498.34 N 70.32775690 W 149.26605860 BP _MWD+IFR+MS 1971.89 0.96 171.53 1886.80 1968.40 -43.94 90.34 ·86.76 0.64 0.05 0.04 -1.45 5969990.89 590498.57 N 70.32775272 W 149.26605691 BP _MWD+IFR+MS 2066.14 0.92 157.68 1981.04 2062.64 -45.03 91.88 -88.24 1.05 0.24 -0.04 -14.69 5969989.41 590498.99 N 70.32774868 W 149.26605363 BP _MWD+IFR+MS 2160.47 0.78 158.11 2075.36 2156.96 -46.13 93.28 -89.54 1.57 0.15 -0.15 0.46 5969988.12 590499.53 N 70.32774514 W 149.26604936 BP _MWD+IFR+MS 2253.39 0.77 146.34 2168.27 2249.87 -47.19 94.53 -90.65 2.15 0.17 -0.01 -12.67 5969987.03 590500.13 N 70.32774211 W 149.26604464 BP _MWD+IFR+MS 2346.50 0.88 151.11 2261.37 2342.97 ·48.36 95.87 ·91.79 2.85 0.14 0.12 5.12 5969985.89 590500.83 N 70.32773898 W 149.26603903 BP _MWD+IFR+MS 2439.88 0.96 148.55 2354.74 2436.34 -49.66 97.37 -93.09 3.60 0.10 0.09 -2.74 5969984.60 590501.60 N 70.32773544 W 149.26603291 BP _MWD+IFR+MS 2533.34 0.83 141.48 2448.19 2529.79 -50.98 98.83 -94.28 4.43 0.18 -0.14 -7.56 5969983.41 590502.45 N 70.32773217 W 149.26602618 BP _MWD+IFR+MS 2626.29 0.98 136.56 2541.13 2622.73 -52.37 100.30 -95.39 5.40 0.18 0.16 -5.29 5969982.32 590503.43 N 70.32772915 W 149.26601835 BP _MWD+IFR+MS SurveyEditor Ver 3.1 RT-SP3.03-HF4.00 Bld( d031 rt-546 ) Plan V-02 (N-I)\V-02\V-02\V-02 Generated 7/15/2004 2:26 PM Page 1 of 7 Comments Measured I Inclination I Azimuth I Sub-Sea TVD I TVD Vertical I Along Hole I NS EW I DLS I Build Aate I Walk Aate I Northing Easting Latitude Longitude Survey Tool Depth Section Departure Model (II) (deg) (deg) (II) (II) (II) (II) (II) (II) (degl100ll) (degl100ll) (degl100ll) (IIUS) (IIUS) 2667.92 0.86 141.44 2582.75 2664.35 -53.00 100.97 -95.89 5.84 0.34 -0.29 11.72 5969981.82 590503.87 N 70.32772778 W 149.26601478 BP _MWD+IFR+MS 2811.48 0.57 127.76 2726.30 2807.90 -54.71 102.75 -97.17 7.07 0.23 -0.20 -9.53 5969980.56 590505.12 N 70.32772429 W 149.26600476 BP _MWD+IFR+MS 2905.59 0.51 136.05 2820.41 2902.01 -55.58 103.63 -97.76 7.73 0.10 -0.06 8.81 5969979.98 590505.79 N 70.32772268 W 149.26599940 BP _MWD+IFR+MS 2997.98 0.65 147.39 2912.79 2994.39 -56.44 104.57 -98.50 8.30 0.20 0.15 12.27 5969979.25 590506.37 N 70.32772066 W 149.26599480 BP _MWD+IFR+MS 3091.79 0.73 159.54 3006.59 3088.19 -57.37 105.69 -99.51 8.80 0.18 0.09 12.95 5969978.25 590506.88 N 70.32771791 W 149.26599078 BP _MWD+IFR+MS 3183.63 0.61 152.57 3098.43 3180.03 -58.23 106.77 -100.49 9.23 0.16 -0.13 -7.59 5969977.27 590507.32 N 70.32771523 W 149.26598729 BP _MWD+IFR+MS 3277.03 0.43 141.14 3191.82 3273.42 -58.98 107.61 -101.20 9.68 0.22 -0.19 -12.24 5969976.56 590507.78 N 70.32771328 W 149.26598365 BP _MWD+IFR+MS 3371.99 0.19 119.31 3286.78 3368.38 -59.47 108.12 -101.56 10.04 0.28 -0.25 -22.99 5969976.21 590508.14 N 70.32771231 W 149.26598073 BP _MWD+IFR+MS 3465.93 1.71 349.80 3380.71 3462.31 -58.72 1 09.46 -100.25 9.92 1.96 1.62 -137.86 5969977.51 590508.01 N 70.32771587 W 149.26598164 BP _MWD+IFR+MS 3558.85 1.62 352.60 3473.59 3555.19 -57.03 112.16 -97.59 9.51 0.13 -0.10 3.01 5969980.18 590507.57 N 70.32772315 W 149.26598500 BP _MWD+IFR+MS 3651.87 1.62 349.24 3566.57 3648.17 -55.37 114.79 -94.99 9.10 0.10 0.00 -3.61 5969982.77 590507.12 N 70.32773024 W 149.26598836 BP _MWD+IFR+MS 3744.71 1.77 348.22 3659.37 3740.97 -53.56 117.54 -92.30 8.56 0.16 0.16 -1.10 5969985.45 590506.55 N 70.32773760 W 149.26599272 BP _MWD+.S 3837.54 1.32 350.57 3752.17 3833.77 -51.93 120.04 -89.84 8.09 0.49 -0.48 2.53 5969987.90 590506.05 N 70.32774432 W 149.26599652 BP MWD+ S 3932.87 0.93 43.47 3847.48 3929.08 -51.41 121.79 -88.19 8.44 1.11 -0.41 55.49 5969989.55 590506.38 N 70.32774881 W 149.26599366 BP _MWD+IF +MS 4026.10 0.94 45.03 3940.70 4022.30 -51.78 123.31 -87.10 9.50 0.03 0.01 1.67 5969990.65 590507.43 N 70.32775179 W 149.26598505 BP _MWD+IFR+MS 4118.54 0.97 54.31 4033.13 4114.73 -52.30 124.85 -86.11 10.68 0.17 0.03 10.04 5969991.66 590508.59 N 70.32775450 W 149.26597555 BP _MWD+IFR+MS 4212.85 1.08 55.97 4127.42 4209.02 -53.02 126.53 -85.15 12.06 0.12 0.12 1.76 5969992.64 590509.97 N 70.32775713 W 149.26596432 BP _MWD+IFR+MS 4305.69 0.82 46.80 4220.25 4301.85 -53.59 128.07 -84.20 13.27 0.32 -0.28 -9.88 5969993.60 590511.16 N 70.32775971 W 149.26595451 BP _MWD+IFR+MS 4399.59 0.48 30.73 4314.14 4395.74 -53.79 129.13 -83.41 13.96 0.41 -0.36 -17.11 5969994.41 590511.84 N 70.32776189 W 149.26594891 BP _MWD+IFR+MS 4493.41 0.65 52.28 4407.96 4489.56 -54.00 130.04 -82.74 14.58 0.29 0.18 22.97 5969995.08 590512.46 N 70.32776370 W 149.26594387 BP _MWD+IFR+MS 4587.41 0.69 48.54 4501.95 4583.55 -54.38 131.14 -82.04 15.43 0.06 0.04 -3.98 5969995.79 590513.30 N 70.32776562 W 149.26593701 BP _MWD+IFR+MS 4680.57 0.63 41.28 4595.11 4676.71 -54.66 132.21 -81.29 16.19 0.11 -0.06 -7.79 5969996.55 590514.04 N 70.32776768 W 149.26593086 BP _MWD+IFR+MS 4771.88 0.58 31.86 4686.41 4768.01 -54.77 133.17 -80.52 16.76 0.12 -0.05 -10.32 5969997.33 590514.61 N 70.32776979 W 149.26592620 BP _MWD+IFR+MS 4866.44 0.54 29.42 4780.97 4862.57 -54.79 134.10 -79.72 17.23 0.05 -0.04 -2.58 5969998.13 590515.07 N 70.32777196 W 149.26592237 BP _MWD+IFR+MS 4960.23 0.64 29.37 4874.75 4956.35 -54.77 135.06 -78.88 17.71 0.11 0.11 -0.05 5969998.98 590515.54 N 70.32777425 W 149.26591853 BP _MWD+IFR+MS 5053.09 0.65 24.91 4967.61 5049.21 -54.72 136.11 -77.95 18.18 0.06 0.01 -4.80 5969999.91 590516.00 N 70.32777679 W 149.26591467 BP _MWD+IFR+MS 5147.33 0.70 9.74 5061.84 5143.44 -54.48 137.21 -76.90 18.51 0.20 0.05 -16.10 5970000.97 590516.31 N 70.32777967 W 149.26591205 BP _MWD+IFR+MS 5240.27 0.79 26.45 5154.77 5236.37 -54.24 138.41 -75.77 18.89 0.25 0.10 17.98 5970002.11 590516.68 N 70.32778277 W 149.26590896 BP _MWD+IFR+MS 5333.96 0.73 31.31 5248.45 5330.05 -54.21 139.65 -74.68 19.49 0.09 -0.06 5.19 5970003.20 590517.26 N 70.32778574 W 149.26590411 BP _MWD+IFR+MS 5427.54 0.73 18.28 5342.03 5423.63 -54.11 140.84 -73.60 19.98 0.18 0.00 -13.92 5970004.28 590517.75 N 70.32778868 W 149.26590008 BP _MWD+IFR+MS 5519.42 0.63 11.29 5433.90 5515.50 -53.82 141.93 -72.55 20.26 0.14 -0.11 -7.61 5970005.34 590518.02 N 70.32779155 W 149.26589779 BP _MWD+IFR+MS 5613.24 0.85 11.90 5527.71 5609.31 -53.44 143.14 -71.36 20.51 0.23 0.23 0.65 5970006.53 590518.25 N 70.32779479 W 149.26589581 BP_MWD+I. 5707.26 0.83 13.65 5621.72 5703.32 -53.03 144.52 -70.02 20.81 0.03 -0.02 1.86 5970007.87 590518.53 N 70.32779846 W 149.26589334 BP MWD+I 5800.04 0.82 21.32 5714.49 5796.09 -52.75 145.85 -68.75 21.21 0.12 -0.01 8.27 5970009.15 590518.92 N 70.32780193 W 149.26589010 BP _MWD+IFR+ S 5892.84 0.49 10.02 5807.29 5888.89 -52.51 146.91 -67.74 21.52 0.38 -0.36 -12.18 5970010.16 590519.22 N 70.32780469 W 149.26588758 BP _MWD+IFR+MS 5987.68 0.44 9.56 5902.12 5983.72 -52.24 147.68 -66.98 21.65 0.05 -0.05 -0.49 5970010.92 590519.34 N 70.32780676 W 149.26588652 BP _MWD+IFR+MS 6081.15 0.39 12.36 5995.59 6077.19 -52.02 148.36 -66.32 21.78 0.06 -0.05 3.00 5970011.59 590519.46 N 70.32780858 W 149.26588548 BP _MWD+IFR+MS 6174.26 0.30 10.52 6088.70 6170.30 -51.84 148.92 -65.77 21.89 0.10 -0.10 -1.98 5970012.14 590519.56 N 70.32781008 W 149.26588457 BP _MWD+IFR+MS 6267.24 0.18 347.38 6181.68 6263.28 -51.66 149.30 -65.38 21.91 0.16 -0.13 -24.89 5970012.52 590519.57 N 70.32781112 W 149.26588447 BP _MWD+IFR+MS 6360.94 1.57 220.18 6275.37 6356.97 -51.34 150.54 -66.22 21.05 1.80 1.48 -135.75 5970011.67 590518.72 N 70.32780884 W 149.26589144 BP _MWD+IFR+MS 6454.12 2.43 217.61 6368.49 6450.09 -50.85 153.79 -68.76 19.02 0.93 0.92 -2.76 5970009.11 590516.72 N 70.32780190 W 149.26590790 BP _MWD+IFR+MS 6546.83 2.09 222.00 6461.13 6542.73 -50.24 157.45 -71.58 16.69 0.41 -0.37 4.74 5970006.27 590514.43 N 70.32779421 W 149.26592680 BP _MWD+IFR+MS 6639.72 1.97 227.62 6553.96 6635.56 -49.40 160.73 -73.91 14.37 0.25 -0.13 6.05 5970003.91 590512.14 N 70.32778783 W 149.26594555 BP _MWD+IFR+MS 6734.05 1.65 228.24 6648.24 6729.84 -48.49 163.71 -75.91 12.16 0.34 -0.34 0.66 5970001.88 590509.96 N 70.32778238 W 149.26596348 BP _MWD+IFR+MS 6826.10 3.97 250.40 6740.18 6821.78 -46.01 168.18 -77.86 8.17 2.74 2.52 24.07 5969999.88 590505.99 N 70.32777704 W 149.26599584 BP _MWD+IFR+MS 6920.65 6.52 255.51 6834.32 6915.92 -40.06 176.81 -80.30 -0.11 2.74 2.70 5.40 5969997.34 590497.74 N 70.32777037 W 149.26606300 BP _MWD+IFR+MS SurveyEditor Ver 3.1 RT-SP3.03-HF4.00 Bld( d031 rt-546 ) Plan V-02 (N-I)\V-02\V-02\V-02 Generated 7/15/2004 2:26 PM Page 2 of 7 Comments Measured I Inclination I Azimuth I Sub-Sea TVD I TVD Vertical I Along Hole I NS EW I DLS I Build Rate I Walk Rate I Northing Easting Latitude Longitude Survey Tool Depth Section Departure Model (II) (deg ) (deg) (II) (II) (II) (II) (II) (II) (degl100 II) (degl100 II) (degl100 II) (IIUS) (IIUS) 7013.49 9.25 254.78 6926.28 7007.88 -31.04 189.55 -83.58 -12.42 2.94 2.94 -0.79 5969993.91 590485.47 N 70.32776142 W 149.26616279 BP _MWD+IFR+MS 7106.82 15.33 262.55 7017.43 7099.03 -15.94 209.38 -87.15 -31.91 6.74 6.51 8.33 5969990.11 590466.03 N 70.32775166 W 149.26632084 BP _MWD+IFR+MS 7199.99 19.29 264.50 7106.37 7187.97 6.37 237.09 -90.22 -59.45 4.30 4.25 2.09 5969986.70 590438.53 N 70.32774326 W 149.26654417 BP _MWD+IFR+MS 7293.67 23.67 264.55 7193.52 7275.12 34.30 271.39 -93.50 -93.59 4.68 4.68 0.05 5969983.02 590404.44 N 70.32773433 W 149.26682100 BP _MWD+IFR+MS 7385.84 28.88 267.36 7276.14 7357.74 68.14 312.17 -96.28 -134.27 5.81 5.65 3.05 5969979.75 590363.80 N 70.32772672 W 149.26715089 BP _MWD+IFR+MS 7478.91 35.11 268.93 7355.03 7436.63 110.03 361.46 -97.82 -183.53 6.75 6.69 1.69 5969977.62 590314.56 N 70.32772252 W 149.26755035 BP _MWD+IFR+MS 7573.17 38.96 269.07 7430.26 7511.86 158.69 418.22 -98.80 -240.28 4.09 4.08 0.15 5969975.94 590257.83 N 70.32771981 W 149.26801056 BP _MWD+IFR+MS 7665.97 41.34 268.34 7501.19 7582.79 209.81 478.05 -100.17 -300.10 2.61 2.56 -0.79 5969973.86 590198.04 N 70.32771609 W 149.26849561 BP _MWD+IFR+MS 7759.37 42.56 268.02 7570.66 7652.26 262.86 540.48 -102.15 -362.50 1.33 1.31 -0.34 5969971.12 590135.67 N 70.32771066 W 149.26900164 BP _MWD+IFR+MS 7855.69 43.33 267.58 7641.16 7722.76 318.39 606.11 -104.67 -428.08 0.86 0.80 -0.46 5969967.81 590070.14 N 70.32770376 W 149.26953337 BP _MWD+IFR+MS 7947.78 44.02 266.01 7707.77 7789.37 371.59 669.70 -108.23 -491.57 1.40 0.75 -1.70 5969963.49 590006.70 N 70.32769402 W 149.27004820 BP _MWD+IFR+MS 8041 .85 43.91 263.98 7775.48 7857.08 425.08 735.00 -113.93 -556.61 1.50 -0.12 -2.16 5969957.01 589941.73 N 70.32767845 W 149.27057569 BP _MWD+IFR+MS 8136.50 43.19 264.14 7844.08 7925.68 477.88 800.21 -120.68 -621.48 0.77 -0.76 0.17 5969949.48 589876.96 N 70.32766000 W 149.27110164 BP_MWD+.S 8230.50 42.27 262.89 7913.13 7994.73 529.16 863.99 -127.87 -684.85 1.33 -0.98 -1.33 5969941 .52 589813.69 N 70.32764032 W 149.27161552 BP _MWD+ S 8322.58 43.33 259.75 7980.70 8062.30 577.97 926.55 -137.33 -746.68 2.59 1.15 -3.41 5969931 .32 589751.98 N 70.32761447 W 149.27211687 BP _MWD+I S 8414.87 43.40 258.56 8047.79 8129.39 625.91 989.92 -149.25 -808.91 0.89 0.08 -1.29 5969918.64 589689.90 N 70.32758188 W 149.27262153 BP _MWD+IFR+MS 8507.30 43.09 259.20 8115.12 8196.72 673.62 1053.24 -161.47 -871.05 0.58 -0.34 0.69 5969905.68 589627.92 N 70.32754849 W 149.27312537 BP _MWD+IFR+MS 8601 .55 43.83 260.95 8183.54 8265.14 723.33 1118.07 -172.63 -934.90 1.50 0.79 1.86 5969893.75 589564.21 N 70.32751797 W 149.27364315 BP _MWD+IFR+MS 8692.81 43.69 264.23 8249.46 8331.06 773.45 1181.18 -180.77 -997.48 2.49 -0.15 3.59 5969884.85 589501 .75 N 70.32749571 W 149.27415055 BP _MWD+IFR+MS 8785.95 42.23 264.53 8317.62 8399.22 825.05 1244.65 -186.99 -1060.64 1.58 -1.57 0.32 5969877.88 589438.67 N 70.32747870 W 149.27466276 BP _MWD+IFR+MS 8878.61 42.43 263.77 8386.12 8467.72 875.62 1307.05 -193.35 -1122.71 0.59 0.22 -0.82 5969870.77 589376.68 N 70.32746129 W 149.27516608 BP _MWD+IFR+MS 8973.36 43.69 264.75 8455.35 8536.95 928.13 1371.74 -199.82 -1187.08 1.51 1.33 1.03 5969863.53 589312.41 N 70.32744361 W 149.27568800 BP _MWD+IFR+MS 9068.07 41.58 265.36 8525.02 8606.62 980.71 1435.88 -205.35 -1250.99 2.27 -2.23 0.64 5969857.22 589248.58 N 70.32742846 W 149.27620620 BP _MWD+I FR+MS 9161.46 40.19 265.93 8595.62 8677 .22 1031.17 1497.01 -210.00 -1311.93 1.54 -1.49 0.61 5969851 .84 589187.70 N 70.32741574 W 149.27670042 BP _MWD+IFR+MS MWD Dee!. Corr. Only 9208.89 40.20 267.33 8631 .85 8713.45 1056.73 1527.62 -211.80 -1342.49 1.91 0.02 2.95 5969849.68 589157.17 N 70.32741081 W 149.27694819 BP _MWD 9270.62 40.02 268.28 8679.07 8760.67 1090.39 1567.39 -213.32 -1382.23 1.03 -0.29 1.54 5969847.67 589117.45 N 70.32740662 W 149.27727043 BP _MWD+IFR+MS 9305.04 44.12 272.16 8704.62 8786.22 1110.41 1 590.44 -213.20 -1405.28 14.10 11.91 11.27 5969847.51 589094.40 N 70.32740694 W 149.27745733 BP _MWD+IFR+MS 9337.64 46.12 277.40 8727.63 8809.23 1131.30 1613.53 -211.26 -1428.28 12.93 6.14 16.07 5969849.18 589071.38 N 70.32741223 W 149.27764384 BP _MWD+IFR+MS 9363.96 46.80 282.06 8745.76 8827.36 1149.19 1632.60 -208.03 -1447.07 13.09 2.58 17.70 5969852.18 589052.55 N 70.32742104 W 149.27779624 BP _MWD+IFR+MS 9396.95 48.76 288.13 8767.94 8849.54 1172.78 1657.02 -201.66 -1470.63 14.86 5.94 18.40 5969858.27 589028.92 N 70.32743844 W 149.27798731 BP _MWD+IFR+MS 9427.98 52.42 291.53 8787.64 8869.24 1196.37 1680.99 -193.51 -1493.17 14.52 11.79 10.96 5969866.14 589006.29 N 70.32746069 W 149.27817007 BP _MWD+IFR+MS 9455.95 56.13 294.15 8803.97 8885.57 1218.89 1703.69 -184.69 -1514.09 15.29 13.26 9.37 5969874.71 588985.27 N 70.32748478 W 149.27833968 BP _MWD+IFR+MS 9487.91 59.13 296.82 8821.08 8902.68 1245.80 1730.68 -173.07 -1538.44 11.74 9.39 8.35 5969886.04 588960.78 N 70.32751651 W 149.27853720 BP _MWD+I. 9518.98 60.76 298.39 8836.64 8918.24 1272.66 1757.57 -160.60 -1562.27 6.83 5.25 5.05 5969898.21 588936.80 N 70.32755055 W 149.27873044 BP MWD+I 9549.97 61.66 301.91 8851.57 8933.17 1299.82 1784.73 -146.96 -1585.75 10.37 2.90 11.36 5969911.57 588913.17 N 70.32758780 W 149.27892084 BP _MWD+IF S 9581.04 62.86 301.67 8866.03 8947.63 1327.30 1812.23 -132.48 -1609.12 3.92 3.86 -0.77 5969925.77 588889.62 N 70.32762736 W 149.27911040 BP _MWD+IFR+MS 9612.35 65.55 302.77 8879.66 8961.26 1355.47 1840.42 -117.45 -1632.97 9.16 8.59 3.51 5969940.51 588865.60 N 70.32766841 W 149.27930378 BP _MWD+IFR+MS 9643.54 67.93 . 303.10 8891 .97 8973.57 1384.08 1869.07 -101.87 -1657.01 7.69 7.63 1.06 5969955.79 588841.37 N 70.32771096 W 149.27949881 BP _MWD+IFR+MS 9674.88 71.56 306.05 8902.82 8984.42 1413.38 1898.47 -85.18 -1681.21 14.56 11.58 9.41 5969972 .19 588816.97 N 70.32775653 W 149.27969505 BP _MWD+IFR+MS 9706.15 74.19 306.21 8912.03 8993.63 1443.09 1928.35 -67.56 -1705.35 8.42 8.41 0.51 5969989.51 588792.63 N 70.32780465 W 149.27989079 BP _MWD+IFR+MS 9736.68 76.78 308.19 8919.68 9001.28 1472.41 1957.90 -49.69 -1728.88 10.55 8.48 6.49 5970007.09 588768.88 N 70.32785345 W 149.28008168 BP _MWD+IFR+MS 9768.04 80.39 307.10 8925.89 9007.49 1502.87 1988.63 -30.92 -1753.22 12.00 11.51 -3.48 5970025.57 588744.32 N 70.32790471 W 149.28027907 BP _MWD+IFR+MS 9799.66 84.99 308.40 8929.91 9011.51 1533.94 2019.99 -11.73 -1778.01 15.11 14.55 4.11 5970044.46 588719.31 N 70.32795714 W 149.28048013 BP _MWD+IFR+MS 9831.33 88.54 310.02 8931.70 9013.30 1565.14 2051.60 8.26 -1802.50 12.32 11.21 5.12 5970064.15 588694.58 N 70.32801172 W 149.28067880 BP _MWD+IFR+MS 9862.04 90.86 307.32 8931.86 9013.46 1595.50 2082.31 27.45 -1826.48 11.59 7.55 -8.79 5970083.04 588670.38 N 70.32806412 W 149.28087323 BP _MWD+IFR+MS 9892.93 95.54 306.36 8930.13 9011.73 1626.11 2113.14 45.93 -1851.15 15.47 15.15 -3.11 5970101.23 588645.48 N 70.32811461 W 149.28107337 BP _MWD+IFR+MS 9923.75 96.48 307.21 8926.91 9008.51 1656.55 2143.79 64.29 -1875.70 4.10 3.05 2.76 5970119.28 588620.72 N 70.32816473 W 149.28127246 BP _MWD+IFR+MS SurveyEditor Ver 3.1 RT-SP3.03-HF4.00 Bld( d031 rt-546 ) Plan V-02 (N-I)\V-02\V-02\V-02 Generated 7/15/2004 2:26 PM Page 3 of 7 Comments Measured I Inclination I Azimuth I Sub-Sea TVD I TVD Vertical I Along Hole I NS EW I DLS I Build Rate I Walk Rate I Northing Easting Latitude Longitude Survey Tool Depth Section Departure Model (It) (deg) (deg ) (It) (It) (It) (It) (It) (It) (degJ100It) (degI1001t) (degJ1001t) (ltUS) (ltUS) 9954.24 96.47 306.47 8923.47 9005.07 1686.63 2174.09 82.45 -1899.94 2.41 -0.03 -2.43 5970137.15 588596.26 N 70.32821434 W 149.28146911 BP _MWD+IFR+MS 9985.97 95.66 307.76 8920.12 9001.72 1717.93 2205.64 101.49 -1925.10 4.78 -2.55 4.07 5970155.88 588570.87 N 70.32826633 W 149.28167318 BP _MWD+IFR+MS 10016.47 95.60 305.49 8917.12 8998.72 1748.08 2235.99 119.60 -1949.46 7.41 -0.20 -7.44 5970173.69 588546.30 N 70.32831578 W 149.28187074 BP _MWD+IFR+MS 10047.51 94.89 304.45 8914.29 8995.89 1778.88 2266.90 137.31 -1974.79 4.05 -2.29 -3.35 5970191.10 588520.76 N 70.32836416 W 149.28207618 BP _MWD+IFR+MS 10079.19 95.10 303.21 8911.53 8993.13 1810.36 2298.46 154.88 -2001.01 3.96 0.66 -3.91 5970208.35 588494.34 N 70.32841214 W 149.28228881 BP _MWD+IFR+MS 10109.56 92.36 303.14 8909.55 8991.15 1840.62 2328.77 171.46 -2026.37 9.03 -9.02 -0.23 5970224.63 588468.78 N 70.32845742 W 149.28249452 BP _MWD+IFR+MS 10140.73 91.53 303.25 8908.49 8990.09 1871.72 2359.92 188.52 -2052.44 2.69 -2.66 0.35 5970241.36 588442.51 N 70.32850400 W 149.28270596 BP _MWD+IFR+MS 10172.02 91.79 302.25 8907.59 8989.19 1902.96 2391 .20 205.44 -2078.74 3.30 0.83 -3.20 5970257.96 588416.00 N 70.32855020 W 149.28291930 BP _MWD+IFR+MS 10203.04 92.19 304.20 8906.51 8988.11 1933.91 2422.20 222.42 -2104.68 6.41 1.29 6.29 5970274.63 588389.87 N 70.32859659 W 149.28312964 BP _MWD+IFR+MS 10233.07 92.06 305.00 8905.40 8987.00 1963.83 2452.21 239.46 -2129.38 2.70 -0.43 2.66 5970291 .37 588364.97 N 70.32864312 W 149.28332999 BP _MWD+IFR+MS 10265.52 91.99 304.29 8904.25 8985.85 1996.15 2484.64 257.90 -2156.06 2.20 -0.22 -2.19 5970309.48 588338.07 N 70.32869346 W 149.28354638 BP _MWD+IFR+MS 10297.57 91.83 302.51 8903.18 8984.78 2028.13 2516.67 275.53 -2182.80 5.57 -0.50 -5.55 5970326.79 588311.12 N 70.32874161 W 149.28376328 BP _MWD+IFR+MS 10330.91 92.26 303.26 8901.99 8983.59 2061.40 2549.99 293.62 -2210.78 2.59 1.29 2.25 5970344.54 588282.93 N 70.32879101 W 149.28399022 BP _MWD+I.S 10362.24 93.56 305.58 8900.40 8982.00 2092.59 2581.28 311.31 -2236.59 8.48 4.15 7.40 5970361.91 588256.91 N 70.32883930 W 149.28419956 BP _MWD+I S 10390.31 93.33 304.11 8898.71 8980.31 2120.51 2609.29 327.32 -2259.58 5.29 -0.82 -5.24 5970377 .64 588233.72 N 70.32888302 W 149.28438607 BP _MWD+IFR+MS 10424.88 93.39 303.83 8896.69 8978.29 2154.94 2643.81 346.60 -2288.20 0.83 0.17 -0.81 5970396.57 588204.88 N 70.32893568 W 149.28461822 BP _MWD+IFR+MS 10455.25 93.74 304.12 8894.80 8976.40 2185.18 2674.12 363.54 -2313.34 1.50 1.15 0.95 5970413.21 588179.54 N 70.32898193 W 149.28482210 BP _MWD+IFR+MS 10483.20 94.21 306.42 8892.86 8974.46 2212.94 2702.00 379.64 -2336.10 8.38 1.68 8.23 5970429.03 588156.59 N 70.32902589 W 149.28500674 BP _MWD+IFR+MS 10514.64 94.24 303.93 8890.55 8972.15 2244.17 2733.35 397.70 -2361.73 7.90 0.10 -7.92 5970446.78 588130.75 N 70.32907521 W 149.28521461 BP _MWD+IFR+MS 10545.60 94.43 303.86 8888.21 8969.81 2274.97 2764.23 414.91 -2387.35 0.65 0.61 -0.23 5970463.68 588104.92 N 70.32912222 W 149.28542246 BP _MWD+IFR+MS 10576.79 93.86 304.52 8885.95 8967.55 2305.99 2795.33 432.40 -2413.09 2.79 -1.83 2.12 5970480.85 588078.98 N 70.32916996 W 149.28563118 BP _MWD+IFR+MS 10611.28 93.79 305.28 8883.65 8965.25 2340.28 2829.75 452.08 -2441.31 2.21 -0.20 2.20 5970500.20 588050.52 N 70.32922372 W 149.28586012 BP _MWD+IFR+MS 10642.42 93.54 303.01 8881.66 8963.26 2371.27 2860.82 469.53 -2467.03 7.32 -0.80 -7.29 5970517.32 588024.60 N 70.32927135 W 149.28606872 BP _MWD+IFR+MS 10670.45 93.51 303.16 8879.94 8961.54 2399.21 2888.80 484.80 -2490.47 0.54 -0.11 0.54 5970532.31 588000.98 N 70.32931305 W 149.28625886 BP _MWD+IFR+MS 10712.88 93.51 306.30 8877.34 8958.94 2441.41 2931.15 508.92 -2525.27 7.39 0.00 7.40 5970556.01 587965.89 N 70.32937892 W 149.28654115 BP _MWD+IFR+MS 10744.00 91.73 308.27 8875.92 8957.52 2472.24 2962.24 527.75 -2550.00 8.53 -5.72 6.33 5970574.54 587940.94 N 70.32943034 W 149.28674177 BP _MWD+IFR+MS 10775.21 89.56 310.29 8875.56 8957.16 2503.04 2993.44 547.51 -2574.16 9.50 -6.95 6.47 5970594.00 587916.55 N 70.32948429 W 149.28693770 BP _MWD+IFR+MS 10806.63 88.81 310.31 8876.01 8957.61 2533.95 3024.86 567.83 -2598.12 2.39 -2.39 0.06 5970614.03 587892.35 N 70.32953978 W 149.28713207 BP _MWD+IFR+MS 10837.27 87.96 308.65 8876.87 8958.47 2564.16 3055.49 587.30 -2621.75 6.08 -2.77 -5.42 5970633.21 587868.48 N 70.32959296 W 149.28732383 BP _MWD+IFR+MS 10868.60 87.84 308.28 8878.02 8959.62 2595.12 3086.80 606.78 -2646.27 1.24 -0.38 -1.18 5970652.39 587843.73 N 70.32964614 W 149.28752269 BP _MWD+IFR+MS 10899.62 87.26 309.37 8879.35 8960.95 2625.75 3117.79 626.21 -2670.41 3.98 -1.87 3.51 5970671 .53 587819.36 N 70.32969920 W 149.28771855 BP _MWD+IFR+MS 10931.53 86.98 308.71 8880.95 8962.55 2657.22 3149.66 646.28 -2695.17 2.24 -0.88 -2.07 5970691.30 587794.36 N 70.32975401 W 149.28791936 BP _MWD+IFR+MS 10962.20 87.09 308.47 8882.54 8964.14 2687.51 3180.29 665.38 -2719.11 0.86 0.36 -0.78 5970710.11 587770.20 N 70.32980618 W 149.28811356 BP MWD+I~. 10993.68 86.73 307.46 8884.24 8965.84 2718.64 3211.72 684.72 -2743.89 3.40 -1.14 -3.21 5970729.15 587745.19 N 70.32985898 W 149.28831459 BP _MWD+IF S 11024.72 87.26 306.78 8885.86 8967.46 2749.40 3242.72 703.43 -2768.60 2.78 1.71 -2.19 5970747.55 587720.25 N 70.32991006 W 149.28851510 BP_MWD+IFR+MS 11056.06 88.40 308.50 8887.05 8968.65 2780.43 3274.03 722.55 -2793.40 6.58 3.64 5.49 5970766.37 587695.23 N 70.32996228 W 149.28871626 BP _MWD+IFR+MS 11086.75 89.52 307.10 8887.61 8969.21 2810.83 3304.72 741.36 -2817.65 5.84 3.65 -4.56 5970784.88 587670.76 N 70.33001363 W 149.28891294 BP _MWD+IFR+MS 11117.87 89.96 307.36 8887.75 8969.35 2841.71 3335.84 760.19 -2842.43 1.64 1.41 0.84 5970803.41 587645.76 N 70.33006505 W 149.28911395 BP _MWD+IFR+MS 11148.78 90.37 307.91 8887.66 8969.26 2872.34 3366.75 779.06 -2866.90 2.22 1.33 1.78 5970821.99 587621.05 N 70.33011658 W 149.28931252 BP _MWD+IFR+MS 11179.02 90.58 308.93 8887.41 8969.01 2902.25 3396.99 797.85 -2890.59 3.44 0.69 3.37 5970840.49 587597.14 N 70.33016789 W 149.28950471 BP _MWD+IFR+MS 11210.72 89.41 308.75 8887.41 8969.01 2933.58 3428.69 817.73 -2915.29 3.73 -3.69 -0.57 5970860.07 587572.21 N 70.33022218 W 149.28970501 BP _MWD+IFR+MS 11241.30 87.82 308.84 8888.15 8969.75 2963.79 3459.26 836.89 -2939.11 5.21 -5.20 0.29 5970878.93 587548.16 N 70.33027448 W 149.28989830 BP _MWD+IFR+MS 11273.54 87.76 309.06 8889.39 8970.99 2995.61 3491.47 857.14 -2964.17 0.71 -0.19 0.68 5970898.88 587522.87 N 70.33032978 W 149.29010156 BP _MWD+IFR+MS 11304.55 89.27 309.69 8890.20 8971.80 3026.20 3522.47 876.80 -2988.13 5.28 4.87 2.03 5970918.25 587498.67 N 70.33038348 W 149.29029595 BP _MWD+IFR+MS 11338.61 90.24 310.41 8890.34 8971.94 3059.73 3556.53 898.72 -3014.20 3.55 2.85 2.11 5970939.85 587472.34 N 70.33044332 W 149.29050747 BP _MWD+IFR+MS 11370.03 90.03 310.08 8890.27 8971.87 3090.65 3587.95 919.02 -3038.18 1.24 -0.67 -1.05 5970959.85 587448.12 N 70.33049875 W 149.29070204 BP _MWD+IFR+MS 11397.59 91.20 309.15 8889.97 8971.57 3117.82 3615.51 936.59 -3059.41 5.42 4.25 -3.37 5970977.17 587426.68 N 70.33054673 W 149.29087426 BP _MWD+IFR+MS SurveyEditor Ver 3.1 RT-SP3.03-HF4.00 Bld( d031 rt-546 ) Plan V-02 (N-I)W-02W-02W-02 Generated 7/15/2004 2:26 PM Page 4 of 7 Comments Measured I Inclination I Azimuth I Sub-Sea TVD I TVD Vertical I Along Hole I NS EW I DLS I Build Rate I Walk Rate I Northing Easting Latitude Longitude Survey Tool Depth Section Departure Model (II) (dog ) (deg) (II) (II) (II) (II) (II) (II) (dog/1001l) (degl100ll) (dogI1001l) (IIUS) (IIUS) 11432.21 91.45 309.00 8889.17 8970.77 3152.00 3650.12 958.41 -3086.28 0.84 0.72 -0.43 5970998.65 587399.55 N 70.33060630 W 149.29109224 BP _MWD+IFR+MS 11463.92 91.00 308.21 8888.49 8970.09 3183.35 3681.82 978.19 -3111.05 2.87 -1.42 -2.49 5971018.13 587374.54 N 70.33066031 W 149.29129323 BP _MWD+IFR+MS 11491.05 90.86 307.83 8888.05 8969.65 3210.21 3708.95 994.89 -3132.42 1.49 -0.52 -1.40 5971034.58 587352.98 N 70.33070593 W 149.29146660 BP _MWD+IFR+MS 11526.24 90.96 306.74 8887.49 8969.09 3245.11 3744.13 1016.21 -3160.42 3.11 0.28 -3.10 5971055.55 587324.73 N 70.33076413 W 149.29169372 BP _MWD+IFR+MS 11557.41 90.54 306.24 8887.09 8968.69 3276.07 3775.30 1034.74 -3185.48 2.09 -1.35 -1.60 5971073.78 587299.45 N 70.33081473 W 149.29189700 BP _MWD+IFR+MS 11584.83 90.75 306.77 8886.78 8968.38 3303.32 3802.72 1051.05 -3207.51 2.08 0.77 1.93 5971089.83 587277.22 N 70.33085927 W 149.29207580 BP _MWD+IFR+MS 11619.12 90.79 305.99 8886.32 8967.92 3337.39 3837.01 1071.39 -3235.12 2.28 0.12 -2.27 5971109.83 587249.37 N 70.33091479 W 149.29229974 BP _MWD+IFR+MS 11647.29 90.43 305.97 8886.02 8967.62 3365.41 3865.17 1087.94 -3257.91 1.28 ·1.28 -0.07 5971126.10 587226.38 N 70.33095998 W 149.29248467 BP _MWD+IFR+MS 11679.08 90.90 306.12 8885.65 8967.25 3397.02 3896.96 1106.64 -3283.62 1.55 1.48 0.47 5971144.49 587200.46 N 70.33101105 W 149.29269319 BP _MWD+IFR+MS 11712.99 90.79 306.30 8885.15 8966.75 3430.72 3930.87 1126.67 -3310.97 0.62 -0.32 0.53 5971164.19 587172.87 N 70.33106573 W 149.29291514 BP _MWD+IFR+MS 11744.22 91.20 306.72 8884.61 8966.21 3461.75 3962.09 1145.25 -3336.07 1.88 1.31 1.34 5971182.46 587147.55 N 70.33111646 W 149.29311875 BP _MWD+IFR+MS 11772.89 91.33 306.48 8883.97 8965.57 3490.22 3990.76 1162.34 -3359.08 0.95 0.45 -0.84 5971199.27 587124.34 N 70.3311.6312 W 149.29330544 BP_MWD+.S 11803.18 91.21 306.46 8883.30 8964.90 3520.31 4021.04 1180.34 -3383.43 0.40 -0.40 -0.07 5971216.97 587099.77 N 70.33121226 W 149.29350301 BP _MWD+ S 11834.31 91.13 305.74 8882.67 8964.27 3551 .26 4052.16 1198.68 -3408.58 2.33 -0.26 -2.31 5971235.00 587074.41 N 70.33126233 W 149.29370703 BP _MWD+I S 11865.28 90.61 305.33 8882.20 8963.80 3582.08 4083.13 1216.68 -3433.78 2.14 -1.68 -1.32 5971252.69 587048.99 N 70.33131146 W 149.29391148 BP _MWD+IFR+MS 11895.29 90.64 306.11 8881.87 8963.47 3611.94 4113.14 1234.20 -3458.14 2.60 0.10 2.60 5971269.92 587024.42 N 70.33135929 W 149.29410913 BP _MWD+IFR+MS 11927.06 90.56 308.00 8881.54 8963.14 3643.46 4144.91 1253.34 -3483.49 5.95 -0.25 5.95 5971288.75 586998.85 N 70.33141156 W 149.29431482 BP _MWD+IFR+MS 11958.28 90.07 306.95 8881.36 8962.96 3674.42 4176.13 1272.33 -3508.27 3.71 -1.57 -3.36 5971307.44 586973.84 N 70.33146342 W 149.29451584 BP _MWD+IFR+MS 11992.36 89.94 306.21 8881.36 8962.96 3708.27 4210.21 1292.64 -3535.64 2.20 -0.38 -2.17 5971327.42 586946.24 N 70.33151886 W 149.29473787 BP _MWD+IFR+MS 12020.40 89.79 306.46 8881.43 8963.03 3736.14 4238.25 1309.26 -3558.23 1.04 -0.53 0.89 5971343.76 586923.45 N 70.33156422 W 149.29492114 BP _MWD+IFR+MS 12051.73 89.19 305.87 8881.71 8963.31 3767.29 4269.57 1327.74 -3583.52 2.69 -1.92 -1.88 5971361.93 586897.94 N 70.33161470 W 149.29512634 BP _MWD+IFR+MS 12080.01 88.62 304.57 8882.25 8963.85 3795.45 4297.85 1344.05 -3606.62 5.02 -2.02 -4.60 5971377.96 586874.65 N 70.33165921 W 149.29531374 BP _MWD+IFR+MS 12104.39 88.00 302.88 8882.97 8964.57 3819.76 4322.22 1357.58 -3626.88 7.38 -2.54 -6.93 5971391 .24 586854.22 N 70.33169615 W 149.29547817 BP _MWD+IFR+MS 12135.71 88.89 305.00 8883.82 8965.42 3851.00 4353.53 1375.06 -3652.86 7.34 2.84 6.77 5971408.41 586828.04 N 70.33174386 W 149.29568890 BP _MWD+IFR+MS 12165.97 89.11 309.23 8884.34 8965.94 3881.01 4383.78 1393.31 -3676.98 14.00 0.73 13.98 5971426.36 586803.71 N 70.33179370 W 149.29588460 BP _MWD+IFR+MS 12197.33 88.29 313.23 8885.06 8966.66 3911.76 4415.13 1413.97 -3700.55 13.02 -2.61 12.75 5971446.74 586779.89 N 70.33185010 W 149.29607588 BP _MWD+IFR+MS 12229.07 88.26 316.65 8886.01 8967.61 3942.41 4446.86 1436.38 -3723.00 10.77 -0.09 10.77 5971468.87 586757.17 N 70.33191129 W 149.29625809 BP _MWD+IFR+MS 12260.75 86.67 320.91 8887.41 8969.01 3972.36 4478.51 1460.18 -3743.85 14.34 -5.02 13.45 5971492.41 586736.03 N 70.33197628 W 149.29642729 BP _MWD+IFR+MS 12291.45 86.57 323.82 8889.22 8970.82 4000.70 4509.15 1484.44 -3762.57 9.47 -0.33 9.48 5971516.45 586717.03 N 70.33204255 W 149.29657916 BP _MWD+IFR+MS 12322.63 87.98 327.36 8890.71 8972.31 4028.78 4540.30 1510.13 -3780.16 12.21 4.52 11.35 5971541.92 586699.13 N 70.33211270 W 149.29672198 BP _MWD+IFR+MS 12355.73 88.32 331.13 8891.78 8973.38 4057.64 4573.38 1538.56 ·3797.08 11.43 1.03 11.39 5971570.14 586681.87 N 70.33219034 W 149.29685929 BP _MWD+IFR+MS 12387.42 89.39 334.76 8892.41 8974.01 4084.23 4605.06 1566.77 -3811.49 11.94 3.38 11.45 5971598.17 586667.13 N 70.33226739 W 149.29697626 BP _MWD+I~. 12416.30 90.17 337.88 8892.52 8974.12 4107.49 4633.94 1593.21 -3823.08 11.14 2.70 10.80 5971624.47 586655.21 N 70.33233962 W 149.29707044 BP MWD+IF 12449.78 88.99 342.05 8892.77 8974.37 4133.15 4667.42 1624.66 -3834.55 12.94 -3.52 12.45 5971655.77 586643.37 N 70.33242551 W 149.29716357 BP _MWD+IF S 12480.54 90.01 344.66 8893.03 8974.63 4155.51 4698.18 1654.13 -3843.36 9.11 3.32 8.49 5971685.13 586634.21 N 70.33250600 W 149.29723515 BP _MWD+IFR+MS 12510.23 91.69 348.81 8892.59 8974.19 4175.85 4727.87 1683.01 -3850.17 15.08 5.66 13.98 5971713.93 586627.05 N 70.33258490 W 149.29729051 BP _MWD+IFR+MS 12540.72 91.46 353.44 8891 .75 8973.35 4194.98 4758.34 1713.12 -3854.87 15.20 -0.75 15.19 5971743.97 586621.99 N 70.33266714 W 149.29732876 BP _MWD+IFR+MS 12571.17 90.82 356.14 8891.15 8972.75 4212.53 4788.79 1743.43 -3857.63 9.11 -2.10 8.87 5971774.25 586618.86 N 70.33274996 W 149.29735131 BP_MWD+IFR+MS 12603.31 90.10 359.13 8890.89 8972.49 4229.73 4820.93 1775.54 -3858.96 9.57 -2.24 9.30 5971806.34 586617.14 N 70.33283767 W 149.29736220 BP _MWD+IFR+MS 12635.10 88.33 3.08 8891 .33 8972.93 4245.09 4852.71 1807.32 -3858.35 13.61 -5.57 12.43 5971838.11 586617.37 N 70.33292447 W 149.29735736 BP _MWD+IFR+MS 12665.89 87.86 4.93 8892.35 8973.95 4258.57 4883.48 1838.01 -3856.20 6.20 -1.53 6.01 5971868.83 586619.15 N 70.33300834 W 149.29734006 BP _MWD+IFR+MS 12696.53 88.55 7.49 8893.31 8974.91 4270.93 4914.11 1868.46 -3852.89 8.65 2.25 8.35 5971899.31 586622.1 0 N 70.33309151 W 149.29731331 BP _MWD+IFR+MS 12727.18 87.82 13.79 8894.28 8975.88 4281.08 4944.74 1898.55 -3847.23 20.68 -2.38 20.56 5971929.46 586627.39 N 70.33317373 W 149.29726759 BP _MWD+IFR+MS 12757.83 88.24 14.22 8895.34 8976.94 4289.52 4975.38 1928.27 -3839.82 1.96 1.37 1.40 5971959.27 586634.44 N 70.33325493 W 149.29720758 BP _MWD+IFR+MS 12789.97 89.43 17.33 8895.99 8977 .59 4297.41 5007.51 1959.19 -3831.09 10.36 3.70 9.68 5971990.29 586642.80 N 70.33333941 W 149.29713686 BP _MWD+IFR+MS 12819.40 90.30 20.61 8896.06 8977.66 4303.04 5036.94 1987.02 -3821.52 11.53 2.96 11.14 5972018.23 586652.03 N 70.33341545 W 149.29705939 BP _MWD+IFR+MS SurveyEditor Ver 3.1 RT-SP3.03-HF4.00 Bld( d031 rt·546 ) Plan V-02 (N-I)\V-02\V-02\V-02 Generated 7/15/20042:26 PM Page 5 of 7 Comments Measured I Inclination I Azimuth I Sub·Sea TVD I TVD Vertical I Along Hole I NS EW I DLS I Build Rate I Walk Rate I Northing Easting Latitude Longitude Survey Tool Depth Section Departure Model (it) (deg) (deg) (it) (it) (it) (it) (it) (it) (degl100it) (degI100it) (deg/100it) (itUS) (itUS) 12851.09 89.46 23.84 8896.12 8977.72 4307.33 5068.63 2016.35 -3809.54 10.53 -2.65 10.19 5972047.70 586663.66 N 70.33349560 W 149.29696230 BP _MWD+IFR+MS 12882.07 89.10 26.80 8896.51 8978.11 4309.85 5099.61 2044.35 -3796.29 9.62 -1.16 9.55 5972075.85 586676.56 N 70.33357210 W 149.29685496 BP _MWD+IFR+MS 12913.60 88.89 31.25 8897.07 8978.67 4310.39 5131.13 2071 .90 -3781.00 14.13 -0.67 14.11 5972103.59 586691 .52 N 70.33364741 W 149.29673104 BP _MWD+IFR+MS 12944.12 88.89 33.11 8897.66 8979.26 4309.23 5161.64 2097.73 -3764.75 6.09 0.00 6.09 5972129.61 586707.46 N 70.33371799 W 149.29659933 BP _MWD+IFR+MS 12975.49 89.10 36.21 8898.21 8979.81 4306.68 5193.01 2123.53 -3746.91 9.90 0.67 9.88 5972155.61 586724.98 N 70.33378849 W 149.29645476 BP _MWD+IFR+MS 13005.86 90.33 40.04 8898.36 8979.96 4302.39 5223.38 2147.41 -3728.16 13.25 4.05 12.61 5972179.72 586743.43 N 70.33385377 W 149.29630280 BP _MWD+IFR+MS 13037.37 89.27 43.58 8898.47 8980.07 4295.94 5254.89 2170.89 -3707.16 11.73 -3.36 11.23 5972203.45 586764.15 N 70.33391794 W 149.29613254 BP _MWD+IFR+MS 13067.91 88.23 46.66 8899.14 8980.74 4287.98 5285.42 2192.44 -3685.53 10.64 -3.41 10.09 5972225.25 586785.52 N 70.33397682 W 149.29595716 BP _MWD+IFR+MS 13099.89 89.17 51.11 8899.86 8981 .46 4277.63 5317.39 2213.45 -3661 .45 14.22 2.94 13.92 5972246.56 586809.34 N 70.33403427 W 149.29576191 BP _MWD+IFR+MS 13130.55 90.12 54.17 8900.05 8981.65 4265.83 5348.05 2232.06 -3637.08 10.45 3.10 9.98 5972265.45 586833.48 N 70.33408513 W 149.29556434 BP _MWD+IFR+MS 13160.97 89.68 58.03 8900.11 8981.71 4252.45 5378.47 2249.02 -3611.84 12.77 -1.45 12.69 5972282.72 586858.51 N 70.33413150 W 149.29535964 BP _MWD+IFR+MS 13191.64 90.26 62.04 8900.12 8981.72 4237.11 5409.14 2264.33 -3585.27 13.21 1.89 13.07 5972298.35 586884.89 N 70.33417338 W 149.29514421 BP _MWD+IFR+MS 13222.71 91.26 65.62 8899.71 8981.31 4219.81 5440.21 2278.03 -3557.40 11.96 3.22 11.52 5972312.38 586912.60 N 70.33421084 W 149.29491813 BP_MWD+I. 13255.02 90.63 69.23 8899.18 8980.78 4200.18 5472.51 2290.43 -3527.57 11.34 -1.95 11.17 5972325.14 586942.27 N 70.33424475 W 149.29467626 BP MWD+I 13288.61 90.33 72.78 8898.89 8980.49 4178.15 5506.10 2301.36 -3495.82 10.61 -0.89 10.57 5972336.45 586973.89 N 70.33427466 W 149.29441871 BP _MWD+IF S 13320.30 90.12 77.81 8898.77 8980.37 4155.63 5537.79 2309.41 -3465.17 15.89 -0.66 15.87 5972344.86 587004.43 N 70.33429666 W 149.29417019 BP _MWD+IFR+MS 13348.79 90.19 81.40 8898.69 8980.29 4133.94 5566.28 2314.55 -3437.16 12.60 0.25 12.60 5972350.34 587032.38 N 70.33431074 W 149.29394294 BP _MWD+IFR+MS 13382.41 91.57 84.14 8898.18 8979.78 4107.18 5599.90 2318.78 -3403.81 9.12 4.10 8.15 5972354.97 587065.67 N 70.33432234 W 149.29367247 BP _MWD+IFR+MS 13414.11 92.01 85.23 8897.19 8978.79 4081.32 5631.58 2321.71 -3372.26 3.71 1.39 3.44 5972358.29 587097.17 N 70.33433040 W 149.29341658 BP _MWD+IFR+MS 13442.02 91.95 84.59 8896.22 8977.82 4058.50 5659.47 2324.19 -3344.48 2.30 -0.22 -2.29 5972361.09 587124.92 N 70.33433719 W 149.29319123 BP _MWD+IFR+MS 13474.61 91.05 85.54 8895.37 8976.97 4031.79 5692.05 2326.99 -3312.02 4.01 -2.76 2.91 5972364.29 587157.34 N 70.33434489 W 149.29292795 BP _MWD+IFR+MS 13505.98 91.18 86.12 8894.76 8976.36 4005.84 5723.42 2329.27 -3280.74 1.89 0.41 1.85 5972366.95 587188.59 N 70.33435115 W 149.29267422 BP _MWD+IFR+MS 13535.76 91.61 85.58 8894.03 8975.63 3981.20 5753.19 2331.42 -3251.05 2.32 1.44 -1.81 5972369.46 587218.25 N 70.33435708 W 149.29243338 BP _MWD+IFR+MS 13569.08 92.10 84.69 8892.95 8974.55 3953.88 5786.49 2334.25 -3217.87 3.05 1.47 -2.67 5972372.68 587251.39 N 70.33436483 W 149.29216422 BP _MWD+IFR+MS 13600.76 91.75 85.99 8891.89 8973.49 3927.84 5818.15 2336.82 -3186.31 4.25 -1.10 4.10 5972375.63 587282.91 N 70.33437189 W 149.29190826 BP _MWD+IFR+MS 13628.58 88.61 86.01 8891.80 8973.40 3904.78 5845.97 2338.76 -3158.56 11.29 -11.29 0.07 5972377.91 587310.63 N 70.33437723 W 149.29168318 BP _MWD+IFR+MS 13661.33 87.86 86.68 8892.81 8974.41 3877.53 5878.70 2340.85 -3125.89 3.07 -2.29 2.05 5972380.39 587343.27 N 70.33438297 W 149.29141820 BP _MWD+IFR+MS 13692.70 88.16 85.57 8893.90 8975.50 3851.50 5910.05 2342.97 -3094.62 3.66 0.96 -3.54 5972382.88 587374.52 N 70.33438879 W 149.29116448 BP _MWD+IFR+MS 13722.38 90.06 86.80 8894.36 8975.96 3826.84 5939.73 2344.94 -3065.01 7.63 6.40 4.14 5972385.22 587404.10 N 70.33439422 W 149.29092431 BP _MWD+IFR+MS 13751.19 90.05 86.86 8894.33 8975.93 3802.73 5968.54 2346.53 -3036.24 0.21 -0.03 0.21 5972387.16 587432.84 N 70.33439860 W 149.29069098 BP _MWD+IFR+MS 13782.97 90.51 86.97 8894.18 8975.78 3776.10 6000.32 2348.24 -3004.51 1.49 1.45 0.35 5972389.25 587464.55 N 70.33440331 W 149.29043358 BP _MWD+IFR+MS 13814.02 90.86 86.90 8893.81 8975.41 3750.08 6031.37 2349.90 -2973.51 1.15 1.13 -0.23 5972391.28 587495.53 N 70.33440788 W 149.29018210 BP _MWD+IFR+MS 13844.99 90.97 86.90 8893.31 8974.91 3724.14 6062.33 2351.58 -2942.58 0.36 0.36 0.00 5972393.33 587526.42 N 70.33441248 W 149.28993128 BP_MWD+I. 13876.66 90.75 86.39 8892.84 8974.44 3697.69 6094.00 2353.43 -2910.97 1.75 -0.69 -1.61 5972395.56 587558.01 N 70.33441758 W 149.28967486 BP MWD+I 13908.16 91.13 86.70 8892.32 8973.92 3671.41 6125.50 2355.33 -2879.53 1.56 1.21 0.98 5972397.84 587589.42 N 70.33442280 W 149.28941985 BP_MWD+IFR S 13939.95 90.96 85.07 8891.74 8973.34 3645.10 6157.28 2357.61 -2847.83 5.15 -0.53 -5.13 5972400.50 587621.09 N 70.33442906 W 149.28916270 BP _MWD+IFR+MS 13970.98 90.72 85.77 8891.29 8972.89 3619.55 6188.31 2360.09 -2816.90 2.38 -0.77 2.26 5972403.35 587651 .98 N 70.33443586 W 149.28891184 BP _MWD+IFR+MS 14003.12 90.97 86.20 8890.81 8972.41 3592.92 6220.44 2362.34 -2784.85 1.55 0.78 1.34 5972405.99 587684.00 N 70.33444204 W 149.28865181 BP_MWD+IFR+MS 14036.00 91.66 89.13 8890.06 8971.66 3565.15 6253.31 2363.68 -2752.01 9.15 2.10 8.91 5972407.72 587716.82 N 70.33444573 W 149.28838542 BP _MWD+IFR+MS 14067.77 91.93 89.07 8889.06 8970.66 3537.90 6285.07 2364.18 -2720.26 0.87 0.85 -0.19 5972408.61 587748.56 N 70.33444713 W 149.28812788 BP _MWD+IFR+MS 14096.87 92.34 88.42 8887.98 8969.58 3513.04 6314.15 2364.81 -2691.18 2.64 1.41 -2.23 5972409.59 587777.62 N 70.33444890 W 149.28789205 BP _MWD+IFR+MS 14128.57 92.36 89.44 8886.68 8968.28 3485.91 6345.82 2365.40 -2659.52 3.22 0.06 3.22 5972410.57 587809.28 N 70.33445054 W 149.28763517 BP _MWD+IFR+MS 14160.76 92.63 88.28 8885.28 8966.88 3458.39 6377.98 2366.04 -2627.36 3.70 0.84 -3.60 5972411.59 587841.41 N 70.33445232 W 149.28737437 BP _MWD+IFR+MS 14190.80 91.21 88.42 8884.27 8965.87 3432.83 6408.00 2366.91 -2597.35 4.75 -4.73 0.47 5972412.82 587871.41 N 70.33445471 W 149.28713094 BP _MWD+IFR+MS 14220.95 90.91 86.84 8883.71 8965.31 3407.37 6438.15 2368.15 -2567.24 5.33 -0.99 -5.24 5972414.43 587901.51 N 70.33445815 W 149.28688664 BP _MWD+IFR+MS 14252.54 90.75 88.05 8883.26 8964.86 3380.75 6469.73 2369.56 -2535.68 3.86 -0.51 3.83 5972416.22 587933.04 N 70.33446202 W 149.28663068 BP _MWD+IFR+MS 14283.70 91.26 88.26 8882.71 8964.31 3354.28 6500.89 2370.57 -2504.54 1.77 1.64 0.67 5972417.60 587964.16 N 70.33446479 W 149.28637809 BP _MWD+IFR+MS SurveyEditor Ver 3.1 RT-SP3.03-HF4.00 Bld( d031 11-546 ) Plan V-02 (N-I)\V-02\V-02\V-02 Generated 7/15/2004 2:26 PM Page 6 of 7 Comments Measured I Inclination I Azimuth I Sub-Sea TVD I TVD Vertical I Along Hole I NS EW I DLS I Build Rate I Walk Rate I Northing Easting Latitude Longitude Survey Tool Depth Section Departure Model (ft) (deg) (deg) (ft) (ft) (ft) (ft) (ft) (ft) (degl100 ft) (degl100 ft) (degl100 ft) (ftUS) (ftUS) 14314.17 91.65 87.85 8881.94 8963.54 3328.43 6531.35 2371.60 -2474.10 1.86 1.28 -1.35 5972419.00 587994.59 N 70.33446764 W 149.28613116 BP_MWD+IFR+MS 14345.90 91.60 88.02 8881.04 8962.64 3301 .55 6563.07 2372.74 -2442.40 0.56 -0.16 0.54 5972420.52 588026.26 N 70.33447079 W 149.28587405 BP _MWD+IFR+MS 14377.07 91.53 88.26 8880.18 8961.78 3275.09 6594.23 2373.75 -2411.26 0.80 -0.22 0.77 5972421.91 588057.39 N 70.33447358 W 149.28562144 BP _MWD+IFR+MS 14408.45 91.27 89.76 8879.42 8961.02 3248.20 6625.60 2374.30 -2379.90 4.85 -0.83 4.78 5972422.83 588088.74 N 70.33447509 W 149.28536702 BP _MWD+IFR+MS 14440.14 91.49 89.40 8878.65 8960.25 3220.88 6657.28 2374.53 -2348.22 1.33 0.69 -1.14 5972423.44 588120.41 N 70.33447575 W 149.28511005 BP _MWD+IFR+MS 14471.06 91.73 90.04 8877.79 8959.39 3194.19 6688.18 2374.68 -2317.31 2.21 0.78 2.07 5972423.97 588151.31 N 70.33447619 W 149.28485934 BP _MWD+IFR+MS 14501.23 92.03 90.37 8876.80 8958.40 3168.02 6718.34 2374.57 -2287.15 1.48 0.99 1.09 5972424.22 588181.46 N 70.33447592 W 149.28461473 BP _MWD+IFR+MS 14532.37 91.76 90.29 8875.77 8957.37 3140.98 6749.46 2374.39 -2256.03 0.90 -0.87 -0.26 5972424.42 588212.58 N 70.33447546 W 149.28436228 BP _MWD+IFR+MS 14563.47 90.73 90.54 8875.09 8956.69 3113.94 6780.55 2374.17 -2224.94 3.41 -3.31 0.80 5972424.57 588243.67 N 70.33447487 W 149.28411008 BP _MWD+IFR+MS 14594.70 90.58 91.68 8874.73 8956.33 3086.60 6811.78 2373.56 -2193.72 3.68 -0.48 3.65 5972424.34 588274.90 N 70.33447324 W 149.28385682 BP _MWD+IFR+MS 14626.14 90.87 90.85 8874.34 8955.94 3059.03 6843.22 2372.87 -2162.29 2.80 0.92 -2.64 5972424.03 588306.33 N 70.33447137 W 149.28360188 BP _MWD+IFR+MS 14655.77 91.33 89.72 8873.77 8955.37 3033.30 6872.84 2372.72 -2132.67 4.12 1.55 -3.81 5972424.24 588335.95 N 70.33447099 W 149.28336158 BP _MWD+IFR+MS 14688.21 90.97 90.85 8873.12 8954.72 3005.14 6905.28 2372.56 -2100.23 3.66 -1.11 3.48 5972424.47 588368.38 N 70.33447058 W 149.28309849 BP_MWD+I.S 14720.97 91.10 90.79 8872.52 8954.12 2976.54 6938.03 2372.09 -2067.48 0.44 0.40 -0.18 5972424.39 588401.13 N 70.33446932 W 149.28283283 BP _MWD+I S 14750.43 90.83 90.92 8872.03 8953.63 2950.81 6967.49 2371.65 -2038.03 1.02 -0.92 0.44 5972424.31 588430.58 N 70.33446814 W 149.28259392 BP _MWD+IFR+MS 14783.93 90.84 89.53 8871.54 8953.14 2921.74 7000.98 2371.52 -2004.54 4.15 0.03 -4.15 5972424.58 588464.07 N 70.33446781 W 149.28232221 BP _MWD+IFR+MS 14814.92 91.01 90.35 8871 .04 8952.64 2894.92 7031.97 2371.55 -1973.55 2.70 0.55 2.65 5972424.99 588495.05 N 70.33446792 W 149.28207087 BP _MWD+IFR+MS 14842.77 91.22 90.55 8870.50 8952.10 2870.70 7059.81 2371 .33 -1945.71 1.04 0.75 0.72 5972425.10 588522.90 N 70.33446734 W 149.28184501 BP _MWD+IFR+MS 14876.31 91.35 90.81 8869.75 8951.35 2841 .46 7093.35 2370.94 -1912.18 0.87 0.39 0.78 5972425.11 588556.42 N 70.33446628 W 149.28157303 BP _MWD+IFR+MS 14907.42 91.52 91.73 8868.97 8950.57 2814.19 7124.45 2370.25 -1881.08 3.01 0.55 2.96 5972424.80 588587.52 N 70.33446441 W 149.28132082 BP _MWD+IFR+MS 14935.90 91.88 91.63 8868.12 8949.72 2789.13 7152.91 2369.41 -1852.63 1.31 1.26 -0.35 5972424.31 588615.98 N 70.33446215 W 149.28108999 BP _MWD+IFR+MS 14966.83 91.86 91.16 8867.11 8948.71 2761.99 7183.83 2368.66 -1821.72 1.52 -0.06 -1.52 5972423.93 588646.89 N 70.33446012 W 149.28083931 BP _MWD+IFR+MS 14998.58 93.74 92.63 8865.56 8947.16 2734.02 7215.54 2367.61 -1790.03 7.51 5.92 4.63 5972423.26 588678.59 N 70.33445728 W 149.28058223 BP _MWD+IFR+MS 15028.59 96.00 95.10 8863.01 8944.61 2707.18 7245.44 2365.60 -1760.20 11.13 7.53 8.23 5972421.61 588708.44 N 70.33445179 W 149.28034026 BP _MWD+IFR+MS Last Corrected MWD 15046.17 96.21 94.92 8861.14 8942.74 2691.33 7262.92 2364.07 -1742.79 1.57 1.19 -1.02 5972420.29 588725.87 N 70.33444763 W 149.28019901 BP _MWD+IFR+MS TO (Exptrapolated) 15086.00 96.21 94.92 8856.83 8938.43 2655.47 7302.51 2360.67 -1703.34 0.00 0.00 0.00 5972417.37 588765.35 N 70.33443838 W 149.27987899 BP _BLIND Survey Type: Definitive Survey NOTES: GVD GC MS - ( Gyrodata - gyro compassing mls -- Older Gyrodata gyro multishots-plus all battery/memory tool surveys (RGS-BT). Replaces ex-BP "Gyrodata multishot into open hole" model. ) MWD + IFR + MS - ( In-field referenced MWD with mult-station analysis and correction applied in post-processing.) Surveys from 11834.31 to 12080.01 have SAG corrections added. LeQal Description: NorthinQ (V) [ftUS] EastinQ eX) [ftUS] e Surface: 4831 FSL 1804 FELS11 T11N R11E UM 5970077.63 590496.88 BHL: 1911 FSL 3505 FEL S2 T11N R11 E UM 5972417.37 588765.35 SurveyEditor Ver 3.1 RT-SP3.03-HF4.00 Bld( d031 rt-546 ) Plan V-02 (N-I)\V-02\V-02\V-02 Generated 7/15/2004 2:26 PM Page 7 of 7 KB. ELEV = -BF~ELBI-; Rop;--- .. ...~=,~-<. ^~..... .~x A!1.9.I~ = Datum MD = [i3tüm T\Tò = e 81.60' .. ,., '_""~_H~ 53.1' "'~-,,~~~ 6720' ~w .~._~~_~< 9.'!_~()924' SS I 9-5/8" CSG, 40#, L-80, ID= 8.835" H 2712' I 3.5" L-80, 9..2 Ibltt, IBT-M Tubhg, 0= 2.9.9.2' H 9051' I Minimum ID = 2.725" XN Nip (@ 9040') I 9.-5/8" HOWCO C5'v1ENlER, 10= 6.276" H 4989' I 4.5"WLEG,ID=3.9.58" H 9064' I 7" CSG, 26#, L-80, 0.0383 bpf, ID=6.276"H 9255' ÆRFORA nON SlJv1MARY RB= LOG: SWS RES-fiR 6/10/2004 ANGLEA T TOP PffiF: 9.3° Note: Refer to Productbn œ for historical perf data Stè:E SPF INlERv'AL OpnlSqz DATE 2.5" 4 10,410'-10,560' Opn 6/1512004 2.5" 4 10,610'-10,820' Opn 6/1512004 2.5" 4 10,9.30'-11,110' Opn 6/1512004 2.5" 4 11,200'-11,370' Opn 6/1512004 2.5" 4 11,410'-11,630' Opn 6/1512004 2.5" 4 11,680'-12,160' Opn 6/1512004 2.5" 4 13,480'-13,580' Opn 6/1512004 2.5" 4 13,650'-13,750' Opn 6/1512004 2.5" 4 13,9.50'-14,060' Opn 6/1512004 2.5" 4 14,650'-14,780' Opn 6/1512004 2.5" 4 14,9.20'-14,9.85' Opn 6/1512004 DAlE 05104102 06/17/04 COMrvENTS FROPOSED COMPLETION RNAL COrvPLEIlON REV BY JS TA -- V-02 SAÆTY NOTES: r-J I p H9.-5/8" TAM Port Collar H3-1/2" HES X Nippple, ID= 2.813" 980' 1933' ~--1 .. ST GA S LIFT MA NDRELS MD TVD OBI TYÆ VLV LATCH FDRT DATE 8 2012' 2009.' 1° rvMG Dum RK 06/17/04 7 3288' 3284' 0" rvMG Dum RK õ6i17iõ4 6 4177' 4173' 1° rvMG OCR ~P õ6i17iõ4 - 5 5105' 5101' 1° rvMG Dum RK 06/17/04 - 4 5780' 5774' 1° rvMG Dum RK 06/17/04 - 3 639.2' 8388' Z' fvMG Dum RK 06/17/04 2 69.86' 69.80' 8° fVI\/IG Dum RK 06/17/04 1 889.3' 8478' 42° rvMG Dum RK 06/17/04 -~ ~ I J H3-112" X Nþple (2.813" 0) 8982' 8993' HBaker Premier Packer, 7' x 3-112" :8: 9019' H3-112" X Nþple (2.813" 0) H3-1/2" XN Nipple (2.725" 10) ~J Cr -- . . 9040' 9054' HZXP5"X 7' Liner top Packer l w/12'TiebaCkSleeve ... ------I 10,700' HRATag20'Marker..bint 12,135' H RA Tag 20' fv1arker ..bint 13,565' HRATagMarkerJoint 14,996' I I 4-1/2", L-80, 12.6#, IBT-MOD H 15,084' I DATE FRLDHOE BA Y UNIT W8..L V-02 PERMIT No: 204-077 API No: 50-029.-23209. SEC 11, T11N, R11E, 4831' NSL & 1804' WEL BP Exploration (Alaska) RBI BY CO rvM ENTS . . Schlumberger Drilling & Measurements MWD/LWD Log Product Delivery Customer BP Exploration (Alaska) Inc. Dispatched To: Robin Deason Well No V-02 Date Dispatched: 16-May-04 Installation/Rig Nabors 9ES Dispatched By: Rose Data No Of Prints No of Floppies Surveys 2 Received By: Please sign and return to: James H. Johnson BP Exploration (Alaska) Inc. Petrotechnical Data Center (LR2-1) 900 E. Benson Blvd. Anchorage, Alaska 99508 Fax: 907 -564-4005 e-mail address:johnsojh@bp.com LWD Log DeliveryV1.1, 10-02-03 Schlumberger Private 2ðÝ-c?77 SCHLUMBERGER Survey report Client. ....... ..... ......: BP Ecploration (Alaska) Inc. Field.. ....... ...........: Prudhoe Bay - West End Well.....................: V-02 API number........ .......: 50-029-23209-00 Engineer. ................: St Amour/Perdomo Rig:...... ........ .......: Nabors 9ES STATE: . . . . . . . . . . . . . . . . . . .: Alaska ----- Survey calculation methods------------- Method for positions... ..: Minimum curvature Method for DLS. ....... ...: Mason & Taylor ----- Depth reference ----------------------- Permanent datum.. ........: Mean Sea Level Depth reference... .......: Driller's Pipe Tally GL above permanent.......: 53.10 ft KB above permanent.......: N/A Top Drive DF above permanent. ......: 81.60 ft ----- Vertical section origin---------------- Latitude (+N/S-) .........: 0.00 ft Departure (+E/W-) ........: 0.00 ft ----- Platform reference point--------------- Latitude (+N/S-) ...... ...: -999.25 ft Departure (+E/W-) ... .....: -999.25 ft Azimuth from rotary table to target: 300.00 degrees Il-Jun-2004 09:32:25 Spud date. . . . . . . . . . . . . . . . : Last survey date.... .....: Total accepted surveys...: MD of first survey.......: MD of last survey..... ...: Page 1 of 11 18-May-2004 Il-Jun-04 288 o . 00 ft 15086.00 ft . ----- Geomagnetic data ---------------------- Magnetic model. ..........: BGGM version 2003 Magnetic date.. ..........: 21-May-2004 Magnetic field strength..: 1151.34 HCNT Magnetic dec (+E/W-). ....: 24.97 degrees Magnetic dip.............: 80.82 degrees ----- MWD survey Reference Reference G... ...........: Reference H...... ........: Reference Dip.. ..........: Tolerance of G. ..........: Tolerance of H. ..........: Tolerance of Dip.........: Criteria --------- 1002.68 mGal 1151. 34 HCNT 80.82 degrees (+/-) 2.50 mGal (+ / -) 6. 00 HCNT (+/-) 0.45 degrees . ----- Corrections --------------------------- Magnetic dec (+E/W-) .....: 24.97 degrees Grid convergence (+E/W-).: 0.00 degrees Total az corr (+E/W-). ...: 24.97 degrees (Total az corr = magnetic dec - grid conv) Survey Correction Type...: I=Sag Corrected Inclination M=Schlumberger Magnetic Correction S=Shell Magnetic Correction F=Failed Axis Correction R=Magnetic Resonance Tool Correction D=Dmag Magnetic Correction ¿<Ot..¡-o77 SCHLUMBERGER Survey Report 11-Jun-2004 09:32:25 Page 2 of 11 -------- ------ ------- ------ -------- -------- ---------------- --------------- ------ -------- ------ ------- ------ -------- -------- ---------------- --------------- ------ Seq Measured Incl Azimuth Course TVD Vertical Displ Displ Total At DLS Srvy Tool # depth angle angle length depth section +N/s- +E/w- displ Azim (degl tool Corr (ft) (deg) (deg) (ft) (ft) (ft) (ft) (ft) (ft) (deg) 100f) type (deg) -------- ------ ------- ------ -------- -------- ---------------- --------------- ------ -------- ------ ------- ------ -------- -------- ---------------- --------------- ------ 1 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 TIP None 2 100.00 0.19 310.67 100.00 100.00 0.16 0.11 -0.13 0.17 310.67 0.19 GYD-GD-SS 3 200.00 0.39 297.91 100.00 200.00 0.67 0.38 -0.55 0.67 304.21 0.21 GYD-GD-SS 4 300.00 1.44 229.88 100.00 299.99 1.43 -0.27 -1. 81 1. 83 261.38 1.34 GYD-GD-SS 5 400.00 1. 81 220.92 100.00 399.95 2.16 -2.28 -3.81 4.44 239.12 0.45 GYD-GD-SS 6 500.00 3.03 179.58 100.00 499.86 1.12 -6.11 -4.82 7.79 218.27 2.05 GYD-GD-SS . 7 600.00 3.82 173.71 100.00 599.68 -2.19 -12.07 -4.44 12.86 200.20 0.86 GYD-GD-SS 8 700.00 4.64 176.81 100.00 699.41 -6.37 -19.42 -3.85 19.80 191. 21 0.85 GYD-GD-SS 9 800.00 5.73 178 . 84 100.00 799.00 -11.17 -28.45 -3.52 28.67 187.06 1.11 GYD-GD-SS 10 900.00 7.13 184.58 100.00 898.37 -16.42 -39.63 -3.92 39.82 185.65 1.54 GYD-GD-SS 11 948.98 7.38 183.45 48.98 946.96 -19.13 -45.80 -4.35 46.00 185.43 0.59 MWD IFR MS - 12 1039.40 6.23 177.75 90.42 1036.74 -24.34 -56.50 -4.51 56.68 184.56 1.47 MWD IFR MS 13 1132.35 4.41 175.49 92.95 1129.28 -29.06 -65.10 -4.03 65.22 183.54 1.97 MWD IFR MS - 14 1224.72 2.68 168.13 92.37 1221.47 -32.51 -70.75 -3.30 70.83 182.67 1. 93 MWD IFR MS 15 1316.97 2.41 164.43 92.25 1313.63 -35.34 -74.73 -2.34 74.77 181. 79 0.34 MWD IFR MS 16 1411. 66 2.12 161. 54 94.69 1408.25 -38.07 -78.31 -1. 25 78.32 180.92 0.33 MWD IFR MS - 17 1505.35 0.78 169.64 93.69 1501.91 -39.78 -80.58 -0.59 80.58 180.42 1.44 MWD IFR MS - 18 1598.26 0.55 159.03 92.91 1594.81 -40.54 -81.62 -0.31 81. 62 180.22 0.28 MWD IFR MS - 19 1691. 55 0.66 157.34 93.29 1688.10 -41.31 -82.53 0.05 82.53 179.96 0.12 MWD IFR MS - 20 1784.29 0.90 176.80 92.74 1780.83 -42.14 -83.75 0.30 83.75 179.80 0.38 MWD IFR MS 21 1877.84 0.92 172.89 93.55 1874.37 -42.99 -85.23 0.43 85.23 179.71 0.07 MWD IFR MS . 22 1971.89 0.96 171.53 94.05 1968.40 -43.94 -86.76 0.64 86.76 179.58 0.05 MWD IFR MS 23 2066.14 0.92 157.68 94.25 2062.64 -45.03 -88.24 1. 05 88.25 179.32 0.24 MWD IFR MS - 24 2160.47 0.78 158.11 94.33 2156.96 -46.13 -89.54 1. 57 89.55 178.99 0.15 MWD IFR MS - 25 2253.39 0.77 146.34 92.92 2249.87 -47.19 -90.65 2.15 90.67 178.64 0.17 MWD IFR MS 26 2346.50 0.88 151.11 93.11 2342.97 -48.36 -91.79 2.85 91.84 178.22 0.14 MWD IFR MS 27 2439.88 0.96 148.55 93.38 2436.34 -49.66 -93.09 3.60 93.16 177.78 0.10 MWD IFR MS - 28 2533.34 0.83 141. 48 93.46 2529.79 -50.98 -94.28 4.43 94.39 177.31 0.18 MWD IFR MS 29 2626.29 0.98 136.56 92.95 2622.73 -52.37 -95.39 5.40 95.54 176.76 0.18 MWD IFR MS 30 2667.92 0.86 141. 44 41.63 2664.35 -53.00 -95.89 5.84 96.07 176.52 0.34 MWD IFR MS SCHLUMBERGER Survey Report 11-Jun-2004 09:32:25 Page 3 of 11 -------- ------ ------- ------ -------- -------- ---------------- --------------- ------ -------- ------ ------- ------ -------- -------- ---------------- --------------- ------ Seq Measured Incl Azimuth Course TVD Vertical Displ Displ Total At DLS Srvy Tool # depth angle angle length depth section +N/S- +E/W- displ Azim (deg/ tool Corr (ft) (deg) (deg) (ft) (ft) (ft) (ft) (ft) (ft) (deg) 100f) type (deg) -------- ------ ------- ------ -------- -------- ---------------- --------------- ------ -------- ------ ------- ------ -------- -------- ---------------- --------------- ------ 31 2811.48 0.57 127.76 143.56 2807.90 - 54.71 -97.17 7.07 97.43 175.84 0.23 MWD IFR MS - 32 2905.59 0.51 136.05 94.11 2902.01 -55.58 -97.76 7.73 98.06 175.48 0.10 MWD IFR MS - 33 2997.98 0.65 147.39 92 .39 2994.39 -56.44 -98.50 8.30 98.85 175.18 0.20 MWD IFR MS 34 3091.79 0.73 159.54 93.81 3088.19 -57.37 -99.51 8.80 99.89 174.95 0.18 MWD IFR MS 35 3183.63 0.61 152.57 91. 84 3180.03 -58.23 -100.49 9.23 100.91 174.75 0.16 MWD IFR MS 36 3277.03 0.43 141.14 93.40 3273.42 -58.98 -101.20 9.68 101. 66 174.54 0.22 MWD IFR MS . - 37 3371.99 0.19 119.31 94.96 3368.38 -59.47 -101.56 10.04 102.05 174.36 0.28 MWD IFR MS - 38 3465.93 1. 71 349.80 93.94 3462.31 -58.72 -100.25 9.92 100.74 174.35 1.96 MWD IFR MS 39 3558.85 1. 62 352.60 92.92 3555.19 -57.03 -97.59 9.51 98.05 174.43 0.13 MWD IFR MS 40 3651.87 1. 62 349.24 93.02 3648.17 -55.37 -94.99 9.10 95.42 174.53 0.10 MWD IFR MS 41 3744.71 1. 77 348.22 92.84 3740.97 -53.56 -92.30 8.56 92.69 174.70 0.16 MWD IFR MS 42 3837.54 1.32 350.57 92.83 3833.77 -51. 93 -89.84 8.09 90.20 174.85 0.49 MWD IFR MS 43 3932.87 0.93 43.47 95.33 3929.08 -51. 41 -88.19 8.44 88.60 174.53 1.11 MWD IFR MS - 44 4026.10 0.94 45.03 93.23 4022.30 -51.78 -87.10 9.50 87.62 173.77 0.03 MWD IFR MS - 45 4118.54 0.97 54.31 92.44 4114.73 -52.30 -86.11 10.68 86.77 172.93 0.17 MWD IFR MS 46 4212.85 1. 08 55.97 94.31 4209.02 -53.02 -85.15 12.06 86.00 171. 94 0.12 MWD IFR MS 47 4305.69 0.82 46.80 92.84 4301.85 -53.59 -84.20 13 .27 85.24 171. 04 0.32 MWD IFR MS 48 4399.59 0.48 30.73 93.90 4395.74 -53.79 -83.41 13.96 84.57 170.50 0.41 MWD IFR MS - 49 4493.41 0.65 52.28 93.82 4489.56 -54.00 -82.74 14.58 84.02 170.01 0.29 MWD IFR MS - 50 4587.41 0.69 48.54 94.00 4583.55 -54.38 -82.04 15.43 83.48 169.35 0.06 MWD IFR MS 51 4680.57 0.63 41. 28 93.16 4676.71 -54.66 -81. 29 16.19 82.88 168.74 0.11 MWD IFR MS . 52 4771.88 0.58 31. 86 91. 31 4768.01 -54.77 -80.52 16.76 82.24 168.24 0.12 MWD IFR MS 53 4866.44 0.54 29.42 94.56 4862.57 -54.79 -79.72 17.23 81. 56 167.80 0.05 MWD IFR MS 54 4960.23 0.64 29.37 93.79 4956.35 -54.77 -78.88 17.71 80.84 167.35 0.11 MWD IFR MS - 55 5053.09 0.65 24.91 92.86 5049.21 -54.72 -77.95 18.18 80.04 166.87 0.06 MWD IFR MS 56 5147.33 0.70 9.74 94.24 5143.44 -54.48 -76.90 18.51 79.09 166.47 0.20 MWD IFR MS - 57 5240.27 0.79 26.45 92.94 5236.37 -54.24 -75.77 18.89 78.08 166.00 0.25 MWD IFR MS 58 5333.96 0.73 31. 31 93.69 5330.05 -54.21 -74.68 19.49 77 .18 165.38 0.09 MWD IFR MS 59 5427.54 0.73 18.28 93.58 5423.63 - 54.11 -73.60 19.98 76.27 164.81 0.18 MWD IFR MS - 60 5519.42 0.63 11.29 91.88 5515.50 -53.82 -72.55 20.26 75.33 164.39 0.14 MWD IFR MS SCHLUMBERGER Survey Report 11-Jun-2004 09:32:25 Page 4 of 11 -------- ------ ------- ------ -------- -------- ---------------- --------------- ------ -------- ------ ------- ------ -------- -------- ---------------- --------------- ------ Seq Measured Incl Azimuth Course TVD Vertical Displ Displ Total At DLS Srvy Tool # depth angle angle length depth section +N/S- +E/W- displ Azim (deg/ tool Corr (ft) (de g) (deg) (ft) (ft) (ft) (ft) (ft) (ft) (deg) 100f) type (deg) -------- ------ ------- ------ -------- -------- ---------------- --------------- ------ -------- ------ ------- ------ -------- -------- ---------------- --------------- ------ 61 5613.24 0.85 11.90 93.82 5609.31 -53.44 -71.36 20.51 74.25 163.97 0.23 MWD IFR MS - 62 5707.26 0.83 13 .65 94.02 5703.32 -53.03 -70.02 20.81 73.05 163.45 0.03 MWD IFR MS - 63 5800.04 0.82 21. 32 92.78 5796.09 -52.75 -68.75 21. 21 71.95 162.85 0.12 MWD IFR MS - 64 5892.84 0.49 10.02 92.80 5888.88 -52.51 -67.74 21. 52 71.08 162.37 0.38 MWD IFR MS - 65 5987.68 0.44 9.56 94.84 5983.72 -52.24 -66.98 21. 65 70.39 162.08 0.05 MWD IFR MS 66 6081.15 0.39 12.36 93.47 6077.19 -52.02 -66.32 21.78 69.80 161.82 0.06 MWD IFR MS . 67 6174.26 0.30 10.52 93.11 6170.30 -51. 84 -65.77 21.89 69.32 161. 59 0.10 MWD IFR MS 68 6267.24 0.18 347.38 92.98 6263.28 -51.66 -65.38 21. 91 68.96 161. 48 0.16 MWD IFR MS - 69 6360.94 1.57 220.18 93.70 6356.96 -51.34 -66.22 21. 05 69.49 162.37 1. 80 MWD IFR MS 70 6454.12 2.43 217.61 93.18 6450.09 -50.85 -68.76 19.02 71. 34 164.54 0.93 MWD IFR MS 71 6546.83 2.09 222.00 92.71 6542.73 -50.24 -71.58 16.69 73.49 166.88 0.41 MWD IFR MS - 72 6639.72 1. 97 227.62 92.89 6635.56 -49.40 -73.91 14.37 75.29 168.99 0.25 MWD IFR MS 73 6734.05 1. 65 228.24 94.33 6729.84 -48.49 -75.91 12.16 76.88 170.90 0.34 MWD IFR MS 74 6826.10 3.97 250.40 92.05 6821.77 -46.01 -77.86 8.17 78.29 174.01 2.74 MWD IFR MS 75 6920.65 6.52 255.51 94.55 6915.92 -40.06 -80.30 -0.11 80.30 180.08 2.74 MWD IFR MS 76 7013.49 9.25 254.78 92.84 7007.88 -31. 04 -83.58 -12.42 84.50 188.45 2.94 MWD IFR MS 77 7106.82 15.33 262.55 93.33 7099.03 -15.94 -87.15 -31.91 92.81 200.11 6.74 MWD IFR MS 78 7199.99 19.29 264.50 93.17 7187.96 6.37 -90.22 -59.45 108.05 213.38 4.30 MWD IFR MS 79 7293.67 23.67 264.55 93.68 7275.11 34.30 -93.50 -93.59 132.29 225.03 4.68 MWD IFR MS 80 7385.84 28.88 267.36 92.17 7357.74 68.14 -96.28 -134.27 165.22 234.36 5.81 MWD IFR MS 81 7478.91 35.11 268.93 93.07 7436.63 110.03 -97.82 -183.53 207.97 241.94 6.75 MWD IFR MS . 82 7573.17 38.96 269.07 94.26 7511.86 158.69 -98.80 -240.28 259.80 247.65 4.09 MWD IFR MS 83 7665.97 41.34 268.34 92.80 7582.79 209.81 -100.17 -300.10 316.37 251. 54 2.61 MWD IFR MS 84 7759.37 42.56 268.02 93.40 7652.25 262.86 -102.15 -362.50 376.62 254.26 1. 33 MWD IFR MS - 85 7855.69 43.33 267.58 96.32 7722.76 318.39 -104.67 -428.08 440.69 256.26 0.86 MWD IFR MS 86 7947.78 44.02 266.01 92.09 7789.37 371.59 -108.23 -491.57 503.34 257.58 1.40 MWD IFR MS - 87 8041.85 43.91 263.98 94.07 7857.08 425.08 -113.93 -556.61 568.15 258.43 1.50 MWD IFR MS - 88 8136.50 43.19 264.14 94.65 7925.68 477.88 -120.68 -621.48 633.08 259.01 0.77 MWD IFR MS 89 8230.50 42.27 262.89 94.00 7994.73 529.16 -127.87 -684.85 696.68 259.42 1.33 MWD IFR MS 90 8322.58 43.33 259.75 92.08 8062.30 577.98 -137.33 -746.68 759.20 259.58 2.59 MWD IFR MS SCHLUMBERGER Survey Report 11-Jun-2004 09:32:25 Page 5 of 11 -------- ------ ------- ------ -------- -------- ---------------- ---------------- ------ -------- ------ ------- ------ --------- -------- ---------------- --------------- ------ Seq Measured Incl Azimuth Course TVD Vertical Displ Displ Total At DLS Srvy Tool # depth angle angle length depth section +N/S- +E/W- displ Azim (deg/ tool Corr (ft) (deg) (deg) (ft) (ft) (ft) (ft) (ft) (ft) (deg) 100f) type (deg) -------- ------ ------- ------ -------- -------- ------------------ --------------- ------ -------- ------ ------- ------ -------- -------- ---------------- --------------- ------- 91 8414.87 43.40 258.56 92 .29 8129.39 625.91 -149.25 -808.91 822.57 259.55 0.89 MWD IFR MS - 92 8507.30 43.09 259.20 92.43 8196.72 673.62 -161.47 -871.05 885.89 259.50 0.58 MWD IFR MS - 93 8601.55 43.83 260.95 94.25 8265.13 723.33 -172.63 -934.90 950.71 259.54 1. 50 MWD IFR MS - 94 8692.81 43.69 264.23 91. 26 8331.05 773.45 -180.77 -997.48 1013.73 259.73 2.49 MWD IFR MS - 95 8785.95 42.23 264.53 93.14 8399.21 825.05 -186.99 -1060.64 1077.00 260.00 1. 58 MWD IFR MS 96 8878.61 42.43 263.77 92.66 8467.72 875.62 -193.35 -1122.71 1139.24 260.23 0.59 MWD IFR MS . 97 8973.36 43.69 264.75 94.75 8536.94 928.13 -199.82 -1187.08 1203.78 260.45 1. 51 MWD IFR MS 98 9068.07 41. 58 265.36 94.71 8606.62 980.71 -205.35 -1250.99 1267.73 260.68 2.27 MWD IFR MS 99 9161. 46 40.19 265.93 93.39 8677.22 1031.17 -210.00 -1311.93 1328.64 260.91 1.54 MWD IFR MS 100 9208.89 40.20 267.33 47.43 8713.45 1056.73 -211.80 -1342.49 1359.10 261.03 1. 91 MWD None 101 9270.62 40.02 268.28 61. 73 8760.66 1090.39 -213.32 -1382.23 1398.60 261. 23 1. 03 MWD IFR MS - 102 9305.04 44.12 272 .16 34.42 8786.21 1110.41 -213.20 -1405.28 1421. 36 261.37 14.10 MWD IFR MS - 103 9337.64 46.12 277.40 32.60 8809.22 1131. 30 -211.26 -1428.28 1443.82 261. 59 12.93 MWD IFR MS 104 9363.96 46.80 282.06 26.32 8827.36 1149.19 -208.03 -1447.07 1461. 95 261. 82 13.09 MWD IFR MS 105 9396.95 48.76 288.13 32.99 8849.54 1172.78 -201.66 -1470.64 1484.40 262.19 14.86 MWD IFR MS 106 9427.98 52.42 291. 53 31.03 8869.24 1196.37 -193.51 -1493.17 1505.66 262.62 14.52 MWD IFR MS - 107 9455.95 56.13 294.15 27.97 8885.57 1218.89 -184.69 -1514.09 1525.31 263.05 15.29 MWD IFR MS - 108 9487.91. 59.13 296 . 82 31.96 8902.68 1245.80 -173.07 -1538.44 1548.15 263.58 11.74 MWD IFR MS 109 9518.98 60.76 298.39 31.07 8918.24 1272.67 -160.60 -1562.27 1570.50 264.13 6.83 MWD IFR MS 110 9549.97 61. 66 301. 91 30.99 8933.17 1299.82 -146.96 -1585.75 1592.54 264.71 10.37 MWD IFR MS 111 9581. 04 62.86 301. 67 31.07 8947.63 1327.30 -132.48 -1609.12 1614.57 265.29 3.92 MWD IFR MS . - ll2 9612.35 65.55 302.77 31.31 8961. 25 1355.47 -1l7.45 -1632.97 1637.18 265.89 9.16 MWD IFR MS ll3 9643.54 67.93 303.10 31.19 8973.57 1384.08 -101.87 -1657.01 1660.14 266.48 7.69 MWD IFR MS ll4 9674.88 71. 56 306.05 31. 34 8984.42 1413.38 -85.18 -1681.21 1683.37 267.10 14.56 MWD IFR MS - ll5 9706.15 74.19 306.21 31. 27 8993.63 1443.09 -67.56 -1705.35 1706.68 267.73 8.42 MWD IFR MS ll6 9736.68 76.78 308.19 30.53 9001.28 1472.41 -49.69 -1728.88 1729.60 268.35 10.55 MWD IFR MS - ll7 9768.04 80.39 307.10 31. 36 9007.49 1502.87 -30.92 -1753.22 1753.49 268.99 12.00 MWD IFR MS 118 9799.66 84.99 308.40 31.62 90ll.51 1533.94 -11.73 -1778.01 1778.05 269.62 15.11 MWD IFR MS 119 9831.33 88.54 310.02 31. 67 9013.29 1565.14 8.26 -1802.50 1802.52 270.26 12.32 MWD IFR MS - 120 9862.04 90.86 307.32 30.71 9013.46 1595.50 27.45 -1826.48 1826.68 270.86 11.59 MWD IFR MS SCHLUMBERGER Survey Report 11-Jun-2004 09:32:25 Page 6 of 11 -------- ------ ------- ------ -------- -------- ---------------- --------------- ------ -------- ------ ------- ------ -------- -------- ---------------- --------------- ------ Seq Measured Incl Azimuth Course TVD Vertical Displ Displ Total At DLS Srvy Tool # depth angle angle length depth section +N/S- +E/W- displ Azim (deg/ tool Corr (ft) (deg) (deg) (ft) (ft) (ft) (ft) (ft) (ft) (deg) 100f) type (de g) -------- ------ ------- ------ -------- -------- ---------------- --------------- ------ -------- ------ ------- ------ -------- -------- ---------------- --------------- ------ 121 9892.93 95.54 306.36 30.89 9011.73 1626.11 45.93 -1851.15 1851.72 271. 42 15.47 MWD IFR MS - 122 9923.75 96.48 307.21 30.82 9008.51 1656.55 64.29 -1875.70 1876.80 271.96 4.10 MWD IFR MS 123 9954.24 96.47 306.47 30.49 9005.07 1686.63 82.45 -1899.95 1901.73 272.48 2.41 MWD IFR MS - 124 9985.97 95.66 307.76 31.73 9001.71 1717.93 101.49 -1925.10 1927.78 273.02 4.78 MWD IFR MS - 125 10016.47 95.60 305.49 30.50 8998.72 1748.08 119.60 -1949.46 1953.13 273.51 7.41 MWD IFR MS 126 10047.51 94.89 304.45 31.04 8995.88 1778.88 137.31 -1974.79 1979.56 273.98 4.05 MWD IFR MS . 127 10079.19 95.10 303.21 31.68 8993.13 1810.37 154.88 -2001.01 2006.99 274.43 3.96 MWD IFR MS - 128 10109.56 92.36 303.14 30.37 8991.15 1840.62 171.46 -2026.37 2033.61 274.84 9.03 MWD IFR MS - 129 10140.73 91. 53 303.25 31.17 8990.09 1871.72 188.52 -2052.44 2061.08 275.25 2.69 MWD IFR MS 130 10172.02 91.79 302.25 31. 29 8989.19 1902.96 205.44 -2078.74 2088.87 275.64 3.30 MWD IFR MS 131 10203.04 92 .19 304.20 31. 02 8988.11 1933.92 222.42 -2104.68 2116.40 276.03 6.41 MWD IFR MS 132 10233.07 92.06 305.00 30.03 8987.00 1963.83 239.46 -2129.38 2142.80 276.42 2.70 MWD IFR MS - 133 10265.52 91.99 304.29 32.45 8985.85 1996 .15 257.90 -2156.06 2171. 43 276.82 2.20 MWD IFR MS 134 10297.57 91. 83 302.51 32.05 8984.78 2028.13 275.53 -2182.80 2200.12 277.19 5.57 MWD IFR MS 135 10330.91 92.26 303.26 33.34 8983.59 2061. 40 293.62 -2210.78 2230.19 277 . 57 2.59 MWD IFR MS 136 10362.24 93.56 305.58 31. 33 8982.00 2092.60 311.31 -2236.59 2258.15 277.92 8.48 MWD IFR MS - 137 10390.31 93.33 304 . 11 28.07 8980.31 2120.51 327.32 -2259.58 2283.17 278.24 5.29 MWD IFR MS 138 10424.88 93.39 303.83 34.57 8978.29 2154.94 346.60 -2288.20 2314.30 278.61 0.83 MWD IFR MS 139 10455.25 93.74 304.12 30.37 8976.40 2185.18 363.54 -2313.34 2341.73 278.93 1. 50 MWD IFR MS - 140 10483.20 94.21 306.42 27.95 8974.46 2212.94 379.64 -2336.10 2366.75 279.23 8.38 MWD IFR MS 141 10514.64 94.24 303.93 31. 44 8972.15 2244.17 397.70 -2361.73 2394.98 279.56 7.90 MWD IFR MS . 142 10545.60 94.43 303.86 30.96 8969.81 2274.97 414.91 -2387.35 2423.14 279.86 0.65 MWD IFR MS - 143 10576.79 93.86 304.52 31.19 8967.55 2305.99 432.40 -2413.09 2451. 52 280.16 2.79 MWD IFR MS 144 10611.28 93.79 305.28 34.49 8965.25 2340.28 452.08 -2441.31 2482.82 280.49 2.21 MWD IFR MS 145 10642.42 93.54 303.01 31. 14 8963.26 2371.27 469.53 -2467.03 2511.31 280.78 7.32 MWD IFR MS 146 10670.45 93.51 303.16 28.03 8961. 54 2399.21 484.80 -2490.47 2537.22 281. 02 0.54 MWD IFR MS - 147 10712.88 93.51 306.30 42.43 8958.94 2441. 41 508.92 -2525.27 2576.04 281. 39 7.39 MWD IFR MS - 148 10744.00 91.73 308.27 31. 12 8957.51 2472.24 527.75 -2550.00 2604.04 281.69 8.53 MWD IFR MS - 149 10775.21 89.56 310.29 31. 21 8957.16 2503.04 547.51 -2574.16 2631.74 282.01 9.50 MWD IFR MS 150 10806.63 88.81 310.31 31. 42 8957.61 2533.95 567.83 -2598.12 2659.44 282.33 2.39 MWD IFR MS SCHLUMBERGER Survey Report 11-Jun-2004 09:32:25 Page 7 of 11 -------- ------ ------- ------ -------- -------- ---------------- --------------- ------ -------- ------ ------- ------ -------- -------- ---------------- --------------- ------ Seq Measured Incl Azimuth Course TVD Vertical Displ Displ Total At DLS Srvy Tool # depth angle angle length depth section +N/s- +E/w- displ Azim (degl tool Corr (ft) (deg) (deg) (ft) (ft) (ft) (ft) (ft) (ft) (deg) 100f) type (deg) -------- ------ ------- ------ -------- -------- ---------------- --------------- ------ -------- ------ ------- ------ -------- -------- ---------------- --------------- ------ 151 10837.27 87.96 308.65 30.64 8958.47 2564.16 587.30 -2621.75 2686.73 282.63 6.08 MWD IFR MS - 152 10868.60 87.84 308.28 31. 33 8959.62 2595.13 606.78 -2646.27 2714.94 282.91 1.24 MWD IFR MS - 153 10899.62 87.26 309.37 31.02 8960.95 2625.75 626.21 -2670.41 2742.85 283.20 3.98 MWD IFR MS - 154 10931.53 86.98 308.71 31.91 8962.55 2657.22 646.28 -2695.17 2771.57 283.48 2.24 MWD IFR MS 155 10962.20 87.09 308.47 30.67 8964.14 2687.51 665.39 -2719.11 2799.34 283.75 0.86 MWD IFR MS 156 10993.68 86.73 307.46 31. 48 8965.83 2718.64 684.72 -2743.89 2828.03 284.01 3.40 MWD IFR MS . 157 11024.72 87.26 306.78 31. 04 8967.46 2749.40 703.43 -2768.61 2856.57 284.26 2.78 MWD IFR MS - 158 11056.06 88.40 308.50 31. 34 8968.65 2780.44 722.55 -2793.40 2885.34 284.50 6.58 MWD IFR MS - 159 11086.75 89.52 307.10 30.69 8969.21 2810.84 741.36 -2817.65 2913.55 284.74 5.84 MWD IFR MS - 160 11117.87 89.96 307.36 31.12 8969.35 2841.71 760.19 -2842.43 2942.32 284.97 1. 64 MWD IFR MS 161 11148.78 90.37 307.91 30.91 8969.26 2872.34 779.06 -2866.90 2970.87 285.20 2.22 MWD IFR MS 162 11179.02 90.58 308.93 30.24 8969.01 2902.26 797.85 -2890.60 2998.68 285.43 3.44 MWD IFR MS 163 11210.72 89.41 308.75 31. 70 8969.01 2933.58 817.73 -2915.29 3027.80 285.67 3.73 MWD IFR MS - 164 11241. 30 87.82 308.84 30.58 8969.75 2963.79 836.89 -2939.11 3055.94 285.89 5.21 MWD IFR MS - 165 11273.54 87.76 309.06 32.24 8970.99 2995.61 857.14 -2964.17 3085.61 286.13 0.71 MWD IFR MS 166 11304.55 89.27 309.69 31.01 8971.80 3026.20 876.80 -2988.13 3114.11 286.35 5.28 MWD IFR MS 167 11338.61 90.24 310.41 34.06 8971. 94 3059.73 898.72 -3014.20 3145.33 286.60 3.55 MWD IFR MS - 168 11370.03 90.03 310.08 31.42 8971.87 3090.65 919.02 -3038.18 3174.14 286.83 1.24 MWD IFR MS 169 11397.59 91. 20 309.15 27.56 8971.57 3117.82 936.59 -3059.41 3199.56 287.02 5.42 MWD IFR MS 170 11432.21 91. 45 309.00 34.62 8970.77 3152.00 958.41 -3086.28 3231.67 287.25 0.84 MWD IFR MS 171 11463.92 91.00 308.21 31.71 8970.09 3183.35 978.19 -3111.06 3261.21 287.45 2.87 MWD IFR MS . 172 11491.05 90.86 307.83 27.13 8969.65 3210.21 994.89 -3132.43 3286.62 287.62 1.49 MWD IFR MS 173 11526.24 90.96 306.74 35.19 8969.09 3245.11 1016.21 -3160.42 3319.78 287.82 3.11 MWD IFR MS 174 11557.41 90.54 306.24 31.17 8968.69 3276.08 1034.74 -3185.48 3349.32 288.00 2.09 MWD IFR MS - 175 11584.83 90.75 306.77 27.42 8968.38 3303.32 1051.05 -3207.52 3375.33 288.14 2.08 MWD IFR MS 176 11619.12 90.79 305.99 34.29 8967.92 3337.39 1071.39 -3235.12 3407.91 288.32 2.28 MWD IFR MS - 177 11647.29 90.43 305.97 28.17 8967.62 3365.41 1087.94 -3257.91 3434.77 288.47 1.28 MWD IFR MS - 178 11679.08 90.90 306.12 31. 79 8967.25 3397.02 1106.64 -3283.62 3465.08 288.62 1.55 MWD IFR MS 179 11712.99 90.79 306.30 33.91 8966.75 3430.73 1126.67 -3310.97 3497 . 42 288.79 0.62 MWD IFR MS 180 11744.22 91. 20 306.72 31. 23 8966.21 3461.75 1145.25 -3336.07 3527.18 288.95 1. 88 MWD IFR MS SCHLUMBERGER Survey Report 11-Jun-2004 09:32:25 Page 8 of 11 -------- ------ ------- ------ -------- -------- ---------------- --------------- ------ -------- ------ ------- ------ -------- -------- ---------------- --------------- ------ Seq Measured Incl Azimuth Course TVD Vertical Displ Displ Total At DLS Srvy Tool # depth angle angle length depth section +N/S- +E/W- displ Azim (deg/ tool Corr (ft) (deg) (deg) (ft) (ft) (ft) (ft) (ft) (ft) (deg) 100f) type (deg) -------- ------ ------- ------ -------- -------- ---------------- --------------- ------ -------- ------ ------- ------ -------- -------- ---------------- --------------- ------ 181 11772.89 91.33 306.48 28.67 8965.57 3490.22 1162.34 -3359.08 3554.50 289.09 0.95 MWD IFR MS 182 11803.18 91. 21 306.46 30.29 8964.90 3520.31 1180.34 -3383.43 3583.41 289.23 0.40 MWD IFR MS 183 11834.31 91.13 305.74 31.13 8964.27 3551.26 1198.68 -3408.58 3613.21 289.38 2.33 MWD SAG 184 11865.28 90.61 305.33 30.97 8963.79 3582.08 1216.68 -3433.78 3642.96 289.51 2.14 MWD SAG 185 11895.29 90.64 306.11 30.01 8963.47 3611.94 1234.20 -3458.14 3671.78 289.64 2.60 MWD SAG 186 11927.06 90.56 308.00 31.77 8963.13 3643.47 1253.34 -3483.50 3702.11 289.79 5.95 MWD SAG . 187 11958.28 90.07 306.95 31. 22 8962.96 3674.42 1272.33 -3508.27 3731.86 289.93 3.71 MWD SAG 188 11992.36 89.94 306.21 34.08 8962.96 3708.28 1292.64 -3535.64 3764.53 290.08 2.20 MWD SAG 189 12020.40 89.79 306.46 28.04 8963.03 3736.14 1309.26 -3558.23 3791. 46 290.20 1. 04 MWD SAG - 190 12051.73 89.19 305.87 31.33 8963.31 3767.29 1327.74 -3583.52 3821.59 290.33 2.69 MWD SAG 191 12080.01 88.62 304.57 28.28 8963.85 3795.45 1344.05 -3606.62 3848.92 290.44 5.02 MWD SAG 192 12104.39 88.00 302.88 24.38 8964.56 3819.76 1357.58 -3626.88 3872.64 290.52 7.38 MWD IFR MS 193 12135.71 88.89 305.00 31.32 8965.41 3851. 00 1375.06 -3652.86 3903.09 290.63 7.34 MWD IFR MS - 194 12165.97 89.11 309.23 30.26 8965.94 3881.01 1393.31 -3676.98 3932.11 290.75 14.00 MWD IFR MS 195 12197.33 88.29 313.23 31. 36 8966.65 3911.76 1413 . 97 -3700.55 3961.49 290.91 13.02 MWD IFR MS 196 12229.07 88.26 316.65 31.74 8967.61 3942.41 1436.38 -3723.01 3990.48 291.10 10.77 MWD IFR MS - 197 12260.75 86.67 320.91 31. 68 8969.01 3972.36 1460.18 -3743.86 4018.53 291. 31 14.34 MWD IFR MS - 198 12291. 45 86.57 323.82 30.70 8970.82 4000.70 1484.44 -3762.57 4044.81 291. 53 9.47 MWD IFR MS - 199 12322.63 87.98 327.36 31.18 8972.30 4028.78 1510.13 -3780.16 4070.64 291. 78 12.21 MWD IFR MS - 200 12355.73 88.32 331. 13 33.10 8973.37 4057.65 1538.56 -3797.08 4096.95 292.06 11.43 MWD IFR MS 201 12387.42 89.39 334.76 31.69 8974.01 4084.23 1566.77 -3811.49 4120.95 292.35 11. 94 MWD IFR MS . - 202 12416.30 90.17 337.88 28.88 8974.12 4107.50 1593.21 -3823.08 4141.78 292.62 11.14 MWD IFR MS - 203 12449.78 88.99 342.05 33.48 8974.36 4133.15 1624.66 -3834.55 4164.53 292.96 12.94 MWD IFR MS - 204 12480.54 90.01 344.66 30.76 8974.63 4155.51 1654.13 -3843.36 4184.20 293.29 9.11 MWD IFR MS 205 12510.23 91. 69 348.81 29.69 8974.19 4175.85 1683.02 -3850.17 4201. 95 293.61 15.08 MWD IFR MS 206 12540.72 91. 46 353.44 30.49 8973.35 4194.98 1713.12 -3854.87 4218.39 293.96 15.20 MWD IFR MS - 207 12571.17 90.82 356.14 30.45 8972.75 4212.53 1743.44 -3857.64 4233.31 294.32 9.11 MWD IFR MS 208 12603.31 90.10 359.13 32.14 8972.49 4229.73 1775.54 -3858.96 4247.84 294.71 9.57 MWD IFR MS - 209 12635.10 88.33 3.08 31. 79 8972.93 4245.09 1807.32 -3858.35 4260.66 295.10 13.61 MWD IFR MS 210 12665.89 87.86 4.93 30.79 8973.95 4258.57 1838.01 -3856.20 4271.83 295.48 6.20 MWD IFR MS SCHLUMBERGER Survey Report 11-Jun-2004 09:32:25 Page 9 of 11 -------- ------ ------- ------ -------- -------- ---------------- --------------- ------ -------- ------ ------- ------ -------- -------- ---------------- --------------- ------ Seq Measured Incl Azimuth Course TVD Vertical Displ Displ Total At DLS Srvy Tool # depth angle angle length depth section +N/S- +E/W- displ Azim (deg/ tool Carr (ft) (deg) (deg) (ft) (ft) (ft) (ft) (ft) (ft) (deg) 100f) type (deg) -------- ------ ------- ------ -------- -------- ---------------- --------------- ------ -------- ------ ------- ------ -------- -------- ---------------- --------------- ------ 211 12696.53 88.55 7.49 30.64 8974.91 4270.93 1868.46 -3852.89 4282.04 295.87 8.65 MWD IFR MS - 212 12727.18 87.82 13.79 30.65 8975.88 4281.08 1898.55 -3847.23 4290.19 296.27 20.68 MWD IFR MS 213 12757.83 88.24 14.22 30.65 8976.93 4289.52 1928.27 -3839.82 4296.80 296.66 1.96 MWD IFR MS 214 12789.97 89.43 17.33 32.14 8977.59 4297.41 1959.19 -3831.09 4302.98 297.08 10.36 MWD IFR MS 215 12819.40 90.30 20.61 29.43 8977.66 4303.04 1987.02 -3821.52 4307.23 297.47 11.53 MWD IFR MS 216 12851.09 89.46 23.84 31.69 8977.72 4307.33 2016.35 -3809.54 4310.25 297.89 10.53 MWD IFR MS . - 217 12882.07 89.10 26.80 30.98 8978.11 4309.86 2044.35 -3796.29 4311. 75 298.30 9.62 MWD IFR MS - 218 12913.60 88.89 31. 25 31.53 8978.67 4310.39 2071.90 -3781.00 4311.47 298.72 14.13 MWD IFR MS - 219 12944.12 88.89 33.11 30.52 8979.26 4309.23 2097.73 -3764.75 4309.73 299.13 6.09 MWD IFR MS - 220 12975.49 89.10 36.21 31. 37 8979.81 4306.68 2123.53 -3746.91 4306.82 299.54 9.90 MWD IFR MS 221 13005.86 90.33 40.04 30.37 8979.96 4302.39 2147.41 -3728.17 4302.39 299.94 13 .25 MWD IFR MS 222 13037.37 89.27 43.58 31. 51 8980.07 4295.94 2170.89 -3707.16 4296.03 300.35 11.73 MWD IFR MS 223 13067.91 88.23 46.66 30.54 8980.74 4287.98 2192.44 -3685.53 4288.35 300.75 10.64 MWD IFR MS - 224 13099.89 89.17 51.11 31.98 8981.46 4277.64 2213.45 -3661.45 4278.50 301.15 14.22 MWD IFR MS - 225 13130.55 90.12 54.17 30.66 8981.65 4265.83 2232.06 -3637.08 4267.37 301. 54 10.45 MWD IFR MS 226 13160.97 89.68 58.03 30.42 8981.71 4252.45 2249.02 -3611.84 4254.82 301.91 12.77 MWD IFR MS - 227 13191. 64 90.26 62.04 30.67 8981.72 4237.11 2264.33 -3585.28 4240.45 302.28 13 .21 MWD IFR MS - 228 13222.71 91. 26 65.62 31. 07 8981.31 4219.81 2278.03 -3557.40 4224.28 302.63 11.96 MWD IFR MS 229 13255.02 90.63 69.23 32.31 8980.78 4200.18 2290.43 -3527.57 4205.93 303.00 11.34 MWD IFR MS 230 13288.61 90.33 72.78 33.59 8980.49 4178.15 2301.36 -3495.82 4185.33 303.36 10.61 MWD IFR MS 231 13320.30 90.12 77.81 31. 69 8980.37 4155.63 2309.41 -3465.18 4164.23 303.68 15.89 MWD IFR MS . - 232 13348.79 90.19 81. 40 28.49 8980.29 4133.94 2314.55 -3437.16 4143.81 303.96 12.60 MWD IFR MS 233 13382.41 91. 57 84.14 33.62 8979.78 4107.18 2318.78 -3403.81 4118.58 304.26 9.12 MWD IFR MS 234 13414.11 92.01 85.23 31. 70 8978.79 4081. 32 2321. 71 -3372.26 4094.21 304.55 3.71 MWD IFR MS 235 13442.02 91. 95 84.59 27.91 8977.82 4058.50 2324.19 -3344.48 4072.76 304.80 2.30 MWD IFR MS 236 13474.61 91. 05 85.54 32.59 8976.97 4031.79 2326.99 -3312.02 4047.76 305.09 4.01 MWD IFR MS - 237 13505.98 91.18 86.12 31.37 8976.36 4005.84 2329.27 -3280.74 4023.53 305.37 1. 89 MWD IFR MS - 238 13535.76 91.61 85.58 29.78 8975.63 3981.20 2331.42 -3251.05 4000.61 305.65 2.32 MWD IFR MS 239 13569.08 92.10 84.69 33.32 8974.55 3953.88 2334.25 -3217.87 3975.35 305.96 3.05 MWD IFR MS - 240 13600.76 91.75 85.99 31. 68 8973.49 3927.84 2336.82 -3186.31 3951.37 306.26 4.25 MWD IFR MS SCHLUMBERGER Survey Report II-Jun-2004 09:32:25 Page 10 of 11 -------- ------ ------- ------ -------- -------- ---------------- --------------- ------ -------- ------ ------- ------ -------- -------- ---------------- --------------- ------ Seq Measured Incl Azimuth Course TVD Vertical Displ Displ Total At DLS Srvy Tool # depth angle angle length depth section +N/S- +E/W- displ Azim (deg/ tool Corr (ft) (deg) (deg) (ft) (ft) (ft) (ft) (ft) (ft) (deg) 100f) type (deg) -------- ------ ------- ------ -------- -------- ---------------- --------------- ------ -------- ------ ------- ------ -------- -------- ---------------- --------------- ------ 241 13628.58 88.61 86.01 27.82 8973.40 3904.78 2338.76 -3158.56 3930.18 306.52 11.29 MWD IFR MS - 242 13661.33 87.86 86.68 32.75 8974.41 3877.53 2340.85 -3125.90 3905.23 306.83 3.07 MWD IFR MS 243 13692.70 88.16 85.57 31.37 8975.50 3851.50 2342.97 -3094.62 3881.51 307.13 3.66 MWD IFR MS 244 13722.38 90.06 86.80 29.68 8975.96 3826.84 2344.94 -3065.01 3859.15 307.42 7.63 MWD IFR MS - 245 13751.19 90.05 86.86 28.81 8975.94 3802.73 2346.53 -3036.24 3837.31 307.70 0.21 MWD IFR MS 246 13782.97 90.51 86.97 31.78 8975.78 3776.10 2348.24 -3004.51 3813.31 308.01 1.49 MWD IFR MS . - 247 13814.02 90.86 86.90 31.05 8975.41 3750.08 2349.90 -2973.51 3789.96 308.32 1.15 MWD IFR MS - 248 13844.99 90.97 86.90 30.97 8974.92 3724.14 2351.58 -2942.58 3766.79 308.63 0.36 MWD IFR MS - 249 13876.66 90.75 86.39 31. 67 8974.44 3697.69 2353.43 -2910.97 3743.31 308.95 1. 75 MWD IFR MS - 250 13908.16 91.13 86.70 31.50 8973.92 3671. 41 2355.33 -2879.53 3720.12 309.28 1. 56 MWD IFR MS 251 13939.95 90.96 85.07 31.79 8973.34 3645.10 2357.61 -2847.83 3697.09 309.62 5.15 MWD IFR MS 252 13970.98 90.72 85.77 31. 03 8972.89 3619.55 2360.09 -2816.90 3674.91 309.96 2.38 MWD IFR MS 253 14003.12 90.97 86.20 32.14 8972.41 3592.92 2362.34 -2784.85 3651.85 310.31 1.55 MWD IFR MS 254 14036.00 91.66 89.13 32.88 8971. 66 3565.15 2363.68 -2752.01 3627.74 310.66 9.15 MWD IFR MS - 255 14067.77 91.93 89.07 31.77 8970.66 3537.90 2364.18 -2720.26 3604.04 310.99 0.87 MWD IFR MS 256 14096.87 92.34 88.42 29.10 8969.58 3513.04 2364.81 -2691.18 3582.57 311.31 2.64 MWD IFR MS - 257 14128.57 92.36 89.44 31.70 8968.28 3485.91 2365.40 -2659.52 3559.24 311.65 3.22 MWD IFR MS - 258 14160.76 92.63 88.28 32.19 8966.88 3458.39 2366.04 -2627.36 3535.71 312.00 3.70 MWD IFR MS - 259 14190.80 91. 21 88.42 30.04 8965.87 3432.83 2366.91 -2597.35 3514.04 312.34 4.75 MWD IFR MS 260 14220.95 90.91 86.84 30.15 8965.31 3407.37 2368.16 -2567.24 3492.69 312.69 5.33 MWD IFR MS 261 14252.54 90.75 88.05 31. 59 8964.86 3380.75 2369.56 -2535.68 3470.52 313.06 3.86 MWD IFR MS . 262 14283.70 91. 26 88.26 31.16 8964.31 3354.28 2370.57 -2504.54 3448.52 313.43 1. 77 MWD IFR MS 263 14314.17 91.65 87.85 30.47 8963.54 3328.43 2371.60 -2474.10 3427.19 313.79 1. 86 MWD IFR MS 264 14345.90 91. 60 88.02 31. 73 8962.64 3301.55 2372.74 -2442.40 3405.18 314.17 0.56 MWD IFR MS - 265 14377.07 91.53 88.26 31.17 8961. 79 3275.09 2373.75 -2411.26 3383.62 314.55 0.80 MWD IFR MS 266 14408.45 91. 27 89.76 31. 38 8961.02 3248.20 2374.30 -2379.90 3361.72 314.93 4.85 MWD IFR MS - 267 14440.14 91. 49 89.40 31. 69 8960.26 3220.88 2374.53 -2348.22 3339.54 315.32 1.33 MWD IFR MS - 268 14471.06 91.73 90.04 30.92 8959.39 3194.19 2374.68 -2317.31 3317.99 315.70 2.21 MWD IFR MS - 269 14501. 23 92.03 90.37 30.17 8958.40 3168.02 2374.57 -2287.16 3296.92 316.07 1.48 MWD IFR MS 270 14532.37 91.76 90.29 31.14 8957.37 3140.98 2374.39 -2256.03 3275.28 316.46 0.90 MWD IFR MS SCHLUMBERGER Survey Report 11-Jun-2004 09:32:25 Page 11 of 11 -------- ------ ------- ------ --------- -------- ---------------- --------------- ------ -------- ------ ------- ------ --------- -------- ----------------- --------------- ------ Seq Measured Incl Azimuth Course TVD Vertical Displ Displ Total At DLS Srvy Tool # depth angle angle length depth section +N/S- +E/W- displ Azim (deg/ tool Corr (ft) (deg) (deg) (ft) (ft) (ft) (ft) (ft) (ft) (deg) 100f) type (deg) -------- ------ -------- ------ -------- -------- ---------------- --------------- ----- ------ -------- ------ --------- ------ --------- -------- ------------------ --------------- ------ 271 14563.47 90.73 90.54 31.10 8956.69 3113.94 2374.17 -2224.94 3253.77 316.86 3.41 MWD IFR MS 272 14594.70 90.58 91.68 31. 23 8956.33 3086.60 2373.56 -2193.72 3232.06 317.25 3.68 MWD IFR MS 273 14626.14 90.87 90.85 31. 44 8955.94 3059.03 2372.87 -2162.29 3210.30 317.66 2.80 MWD IFR MS 274 14655.77 91.33 89.72 29.63 8955.37 3033.30 2372.72 -2132.67 3190.31 318.05 4.12 MWD IFR MS 275 14688.21 90.97 90.85 32.44 8954.72 3005.14 2372.56 -2100.24 3168.60 318.48 3.66 MWD IFR MS 276 14720.97 91.10 90.79 32.76 8954.13 2976.54 2372.09 -2067.48 3146.63 318.93 0.44 MWD IFR MS . - 277 14750.43 90.83 90.92 29.46 8953.63 2950.81 2371.65 -2038.03 3127.03 319.33 1. 02 MWD IFR MS - 278 14783.93 90.84 89.53 33.50 8953.14 2921.74 2371.52 -2004.54 3105.20 319.79 4.15 MWD IFR MS 279 14814.92 91.01 90.35 30.99 8952.64 2894.92 2371.55 -1973.55 3085.31 320.23 2.70 MWD IFR MS 280 14842.77 91.22 90.55 27.85 8952.10 2870.70 2371.33 -1945.71 3067.41 320.63 1. 04 MWD IFR MS 281 14876.31 91.35 90.81 33.54 8951.35 2841.46 2370.94 -1912.18 3045.94 321.11 0.87 MWD IFR MS - 282 14907.42 91. 52 91. 73 31.11 8950.57 2814.19 2370.25 -1881.09 3025.98 321.56 3.01 MWD IFR MS 283 14935.90 91. 88 91.63 28.48 8949.72 2789.13 2369.41 -1852.63 3007.71 321.98 1.31 MWD IFR MS - 284 14966.83 91. 86 91. 16 30.93 8948.71 2761.99 2368.66 -1821.73 2988.18 322.44 1.52 MWD IFR MS - 285 14998.58 93.74 92.63 31.75 8947.16 2734.02 2367.61 -1790.03 2968.13 322.91 7.51 MWD IFR MS 286 15028.59 96.00 95.10 30.01 8944.61 2707.18 2365.60 -1760.20 2948.62 323.35 11.13 MWD IFR MS 287 15046.17 96 .21 94.92 17.58 8942.74 2691.33 2364.07 -1742.79 2937.03 323.60 1. 57 MWD IFR MS 288 15086.00 96 .21 94.92 39.83 8938.44 2655.47 2360.67 -1703.34 2911.04 324.19 0.00 projection to TD [(c)2004 IDEAL ID8_1C_02J . . F-'''·'''"~-; ir ! ;:;;c lJ . , ! ; ,£ FRANK H. MURKOWSKI, GOVERNOR AI4ASKA. OIL AlQ) GAS ¡ CONSERVATION COMMISSION I 333 W. 7'" AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Bill Isaacson Senior Drilling Engineer BP Exploration (Alaska) Inc. P.O. box 196612 Anchorage, Alaska 99519-6612 Re: Prudhoe Bay V -02 BP Exploration (Alaska) Inc. Permit No: 204-077 Surface Location: 4831' NSL, 1804' WEL, SEC. 11, T11N, R11E, UM Bottomhole Location: 1970' NSL, 3400' WEL, SEe. 02, T11N, RIlE, UM Dear Mr. Isaacson: Enclosed is the approved application for permit to drill the above referenced development well. This permit to drill does not exempt you from obtaining additional permits or approvals required by law from other governmental agencies, and does not authorize conducting drilling operations until all other required permits 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 terms and conditions of this permit may result in the revocation or suspension of the permit. Please provide at least twenty-four (24) hours notice for a representative of the Commission to 'tness any required test. Contact the Commission's North Slope petroleuar ~ 65 07 (pager). ~r:. No~ ~'-./ BY ORDER P! THE COMMISSION DA TED this-'.f- day of May, 2004 cc: Department ofFish & Game, Habitat Section w/o encl. Department of Environmental Conservation w/o encl. II Drill 0 Redrill 1 a. Type of work 0 Re-Entry 2. Operator Name: BP Exploration (Alaska) Inc. 3. Address: P.O. Box 196612, Anchorage, Alaska 99519-6612 4a. Location of Well (Governmental Section): Surface: 4831' NSL, 1804' WEL, SEC. 11, T11N, R11E, UM Top of Productive Horizon: 4661' NSL, 3409' WEL, SEC. 11, T11 N, R11 E, UM Total Depth: 1970' NSL, 3400' WEL, SEC. 02, T11N, R11E, UM 4b. Location of Well (State Base Plane Coordinates): Surface: x- 590497 y- 5970078 Zone- ASP4 16. Deviated Wells: Kickoff Depth 18. Casjngprogram Size Casinç¡ 20" 9-5/8" 300 ft Hole 42" 12-1/4" 8-314" 6-1/8" 7" 4-1/2" Weiç¡ht 91.5# 40# 26# 12.6# v.J61r s ¡ 41/2.004 I STATE OF ALASKA . ALASKA L AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 MC 25.005 1b. Current Well Class 0 Exploratory II Development Oil 0 Multiple Zone o Stratigraphic Test 0 Service 0 Development Gas 0 Single Zone 5. Bond: a Blanket 0 Single Well 11. Well Name and Number: Bond No. 2S100302630-277 PBU V-02 6. Proposed Depth: 12. Field I Pool(s): MD 15183 TVD 8935 Prudhoe Bay Field I Prudhoe Bay 7. Property Designation: Pool ADL 028240 8. Land Use Permit: 13. Approximate Spud Date: May 14,2004 / 14. Distance to Nearest Property: 8175' 9. Acres in Property: 2560 Maximum Hole Angle 96° 10. KB Elevation Plan RKB 15. Distance to Nearest Well Within Pool (Height above GL): 82.5 feet WKUPST-01 is 4400' away 17. Maximum Anticipated Pressures in psig (see 20 MC 25;935) Downhole: 3950 psig Surface: 3075 psig Setting Depth. Qual'!titY~fÇement Topi. i Bottom (c.f.orsacks) MD TVD MD TVD (includinç¡ staç¡e data) Surface Surface 110' 110' 260 sx Arctic Set (Approx.) Surface Surface 2736' 2733' 462 sx Permafrost II, 203 sx 'G' / Surface Surface 9281' 8779' 315 sx LiteCrete, 200 sx 'G', / 9060' 8621' 15183' 8935' 525 sx Class 'G' / Grade H-40 L-80 L-80 L-80 Couplinç¡ Weld BTC BTC-M IBT-M Lenç¡th 80' 2736' 9210' 6123' PRESENT WELL CONDITION SUMMARY (To be completed for RédrillAND Re-entry.Qperations) . Total Depth MD (ft): Total Depth TVD (ft): I Plugs (measured): Effective Depth MD (ft): I Effective Depth TVD Junk (measured): Structural Conductor Surface Intermediate Production Liner Perforation Depth MD (ft): perfOration Depth TVD (ft): a Drilling Program 0 Time vs Depth Plot o Seabed Report a Drilling Fluid Program 20. Attachments a Filing Fee, $100 0 BOP Sketch a Property Plat 0 Diverter Sketch 21. Verbal Approval: Commission Representative: 22. I hereby certify that the foregoing is true and correct to the best of my knowledge. Printed Name Bill Isaacson Title Senior Drilling Engineer Phone 564-5521 Date !S Is / 0 ~\ o Shallow Hazard Analysis a 20 MC 25.050 Requirements Date.: Contact Jim Smith, 564-5773 Prepared By Name/Number: Terrie Hubble, 564-4628 Permit To Drill API Number: 3 q Number: 2e>7'-o?Z 50- 02-'7'- 2.. 2- C> / Conditions of Approval: ~;:~~:n R;~~::dMeRe CAAf~~ Other: Rst ßop E 3'5"vo pSi) Q ey ~IO~ '$10. MAY 0 6 2004 Alaska Oil & Gas Cons. Commission BY ORDER OF &fttd Anchorage 0 R· I C I N ATtE COMMISSION Date b v¡ . 1-\ L. u it In Duplicate Permit Date: Mud Log Required I Directional Survey Required {.?OO. See cover letter for other requirements D Yes ~NO ~Yes 0 No . . IWell Name: V-02 I Drill and Complete Plan Summary Type of Well (service 1 producer 1 injector): I Producer Surface Location: X = 590,496.88' Y = 5,970,077.63' As-Built 4831' FSL, 1804' FEL, Sec. 11, T11N, R11E Target 1 Ivishak X = 588,894' Y = 5,969,889' 8873'TVDss 4661' FSL, 3409' FEL, Sec. 11, T11 N, R11 E Bottom Hole Location: X = 588,869' Y = 5,972,477' 1970'FSL, 3401' FEL , Sec. 2, T11 N, R11 E AFE Number: 1 PBD4P2220 I I Rig: I Nabors 9ES ~ Estimated Start Date: 15/14/04 I Operatin~ days to complete: 134.25 MD: 115183' I I TVD: 18935' I I BF/MS: 154' 1 I RKB: 182.5' Well Design (conventional, slim hole, etc.): I Ultra Slimhole (Iongstring) Objective: I Ivishak Zone 4B Mud Program: 12 1j;¡" Surface Hole (0-2736'): Fresh Water Surface Hole Mud Initial Base PF to top SV SV toTD Densitv (ppg) 8.5 - 9.2 9.0 - 9.5 9.5 - 9.6 Viscosity (seconds) 250-300 250-200 200 Yield Point (lb/100ff) 50 - 70 30 - 45 30 - 40 APIFL (mls/30min) NC-8 <10 <10 PH 8.5 - 9.5 8.5- 9.5 8.5 - 9.5 8 3,4" Production Hole (2736' - 9283'): LSND Interval Density Funnel Vis YP PV pH API MBT (ppg) Filtrate Upper 9.0-9.6 38-50 25-35 12 - 18 9.0-9.5 4-6 <20 Interval Top of HRZ ¿;p 38-50 24-32 12-18 9.0-9.5 3.0-4.5 <15 Kingak to TD :~~/ 38-50 24-32 12-18 9.0-9.5 3.0-4.5 <15 61/8" Production Hole (9283' - 15183'): Interval Density Low Shear YP (ppg) Rate vis PV Solids Free FloPro pH API Filtrate Ivishak 9.0 >40000 35-45 8-15 9.0-9.5 4-6 V-02 Permit application Page 1 . . Hydraulics: Surface Hole: 12-1/4" Interval Pump Drill AV Pump PSI ECD Nozzles TFA GPM Pipe (fpm) ppg-emw (in2) 0-1,800' 550 4" 15.7# 110 1800 18-18-1 8-14 xx 1,800' -2, 736' 600 4" 15.7# 120 2550 9.9 18-18-18-14 Intermediate Hole: 8 %" Interval Pump Drill Pipe AV (fpm) Pump PSI ECD ppg- Nozzles TFA GPM emw ~ (in2) 2736' - 9210' 600 4" 15.7# 240 3800 11.5 ~ 6 x 15 xx Production Hole: 6 1/8" Interval Pump Drill Pipe AV (fpm) Pump PSI ECD ppg- Nozzles TFA GPM emw " (in2) 9210' -15183' 270-300 4" 15.7# 300 3500 11.5/ xx .451 Di rectional: Ver. I Anadrill KOP: 300'(nudge), 6720' (build) Maximum Hole Angle: Close Approach Wells: Production Hole Logging 96deg near TD of horizontal section All wells pass major risk criteria. V-104 and V-107 are 15" center to,.-- down to 400' IFR-MS corrected surveys will be used for survey validation. GyroData will be needed for surface hole close approaches. Drilling: Dir / GR Open Hole: None Cased Hole: None Drilling: Dir/RES/GR Real Time w/PWD Open Hole: None Cased Hole: None Drilling: Dir/RES/GR with AIM Real Time w/PWD Open Hole: None Cased Hole: None Surface hole logging Intermediate Logging V-02 Permit application Page 2 Formation Markers: Formation Tops SV5 SV4 Base Permafrost SV3 SV2 SV1 9-5/8" surface csg UG4A UG3 V-Pad Fault UG1 Ugnu Ma Schrader Na Schrader Oa Schrader Obf Base CM2 (Colville) CM1 (Colville) THRZ BHRZ (Kalubik) TKUP LCU (Kuparuk B) Miluveach Kingak Shale Sag River 7" Casing Point Shublik Eileen TSAD (target) TD . MDbkb 1630 1760 1785 2160 2305 2640 2735 2975 3310 3515 3670 4210 4265 4375 4800 5054 5733 6283 6575 6615 6745 6931 7527 9282 9282 9325 9507 9564 15183 TVDss 1545 1675 1700 2075 2220 2555 2650 2890 3225 3430 3585 4125 4180 4290 4715 4969 5648 6198 6490 6530 6660 6845 7400 8697 8700 8728 8844 8873 8853 . Estimated pore pressure, PPG 8.8 ppg EMW 8.8 ppg EMW 8.8 ppg EMW, gas hydrates likely 8.8 ppg EMW, gas hydrates likely 8.8 ppg EMW, gas hydrates likely 8.4 ppg EMW 8.7 ppg EMW 8.6 ppg EMW 8.7 ppg EMW 8.7 ppg EMW 8.6 ppg EMW 8.6 ppg EMW 8.6 ppg EMW 8.6 ppg EMW 8.6 ppg EMW 8.6 ppg EMW 6.5 ppg EMW is possible in Kup C sands 9.8 ppg EMW 9.8 ppg EMW 8.5 ppg EMW 8.7 ppg EMW 1(1· ~ 8.7 ppg EMW 8.7 ppg EMW 8.7 ppg EMW CasingITubing Pro~ ram: Hole Csgl WtlFt Grade Conn Length Top Btm Size Tbg O.D. ./ / MDrrVD MDrrVD bkb 42" Insulated 20" 91.5# H-40 WLD 80' GL 110/110 121,4" 9 5/8" 40# L-80 BTC 2736' GL 2736'/2733 8%" 7" 26# L-80 BTC-M 9210' GL 9281 '/8779' 6-1/8" 4 }2" 12.6# L-80 IBT-M 6123' 9060'/8621 ' 15183'/8935' Tubing 3-1/2" 9.3# L-80 IBT-M 9060' GL 9060'/8670' CasingITubing Design Ratings: Csgrrbg WtlFt Grade Conn Burst Collapse Tension Insulated 20" 91.5# H-40 WLD psi psi #M 9 5/8" 40# L-80 BTC 5750 3090 916 7" 26# L-80 BTC-M 7240 5410 604 4 }2" 12.6# L-80 IBT-M 8440 7500 288 3-1/2" 9.3 L-80 IBT-M 10160 10530 159 V-02 Permit application Page 3 . . Integrity Testing: Test Point Depth Surface Gasing Shoe 20' min from surface shoe Test Type Leak Off Test EMW 12.0 ppg EMW Target Cement Calculations: The following surface cement calculations are based upon a single stage job without a TAM port collar. Casing Size 19-5/8" Surface I Basis: lead: Based on 100' of conductor, 1685' of annulus in the permafrost @ 225% excess and 450' of open hole from top of tail slurry to base permafrost @ 30% excess. lead TOG: To surface Tail: Based on 500' MD/TVD open hole volume + 30% excess + 80' shoe track volume. Tail TOG: At -2235' MD I Total Cement Volume: Lead Shoe at 2735'MD/<') 365 bbl I 2050fe l~kS of OS Permafrost II at 10.7 ppg and 4.44 d/sk,..........--; 42.4 bbl I 238 fe IÇg93"sks of OS 'G' at 15.8 ppg and 1.17 dIsk. Tail The 7" production casing job assumes a two stage job due to the requirement for cement to 500' above the Ugnu Ma sand. Casing Size 17" Production Longstring 1 Basis: Stage 1: Based on TOC at 5600'MO (1015' above top of Kuparuk) + 30% excess + 80' shoe. (Plan 3182' of lead and 500' of tail) Cement Placement: From shoe at 9282'MO to 5600' ~) Total Cement Volume: Lead 110.2 bbls 1619 'fe I~Y~ks LiteCRETE at 12.0 ppg Stage 1 and 2.46 dIsk. T0...B_~ad at 5600'MO Tail 20.5 bbls I 115 fe ~sks of OS Premium "G" with latex at 15.8 ppg and 1.16 dIsk. Top tail at 8782'MO Basis: I Stage 2: Based on TOC 500' above top of Ugnu Ma formation + 30% excess Placement: From stage collar at 5000'MO to 371 O~ Total Cement Volume: Lead 27.5 bbls I 155 fe(1 ~sks of OS LiteCRETE at 12.0 ppg Stage 2 and 2.46 dIsk TOp ,!~ad at 371 O'MO Tail 20.5 bbls I 115 ft~ ¿,1Óo/sks of OS Premium "G" 15.8 ppg and 1.16 d/sPTop Tail at 4500'MO Casing Size 14-1/2" Production Liner I Basis: Tail: Based on fillup from 4-1/2" shoe at 15183' to 7" shoe at 9282' of open hole volume + 40% excess + 150' of liner lap in 7", plus 200' excess above TOl with DP in hole, plus 80' shoe track volume. TOG: At 9132' MD (TOl) I Total Cement Volume: Tail ~.... 1146.8 bbl I 824ft~ lþ25fiks of OS G plus latex plus silica at 15.8 ppg and 1 (Sz:Cf/sk. V-02 Permit application Page 4 . . Well Control: Surface hole will be drilled with diverter. The intermediate hole, well control equipment consisting of 5000 psi working pressure pipe rams(2), blind/shear rams, and annular preventer will be installed and is capable of handling maximum potential surface pressures. Based upon the need to test the production casing to 3500 psi the BOP equipment will be tested to ./ 3500 psi and the tests will be conducted on a 14 day frequency. Diverter, BOPE and drilling fluid system schematics on file with the AOGCC. Production Interval- · Maximum anticipated BHP: · Maximum surface pressure: 3950 psi @ -8697' TVDss - Sag River 3075 psi @ surface ,r (based on BHP and a full column of gas from TD @ 0.10 psi/ft) · Planned BOP test pressure: · Planned completion fluid: ppg diesel 3500 psi / Filtered seawater with 2% KCL with corrosion inhibitor / 6.8 Nearest wells into the Ivishak: WKUPST-01 (P&A) at 4400', V-03 at 5400', Z-10 at 7600'. Nearest boundary: 8175' SW to the PBU boundary Disposal: · No annular disposal in this well. · Cuttings Handling: Cuttings generated from drilling operations will be hauled to grind and inject at DS-04. · Fluid Handling: Haul all drilling and completion fluids and other Class II wastes to DS- 04 for disposal. Haul all Class I wastes to Pad 3 for disposal. V-02 Scope of Work Pre-Rig Work: 1. Weld an FMC landing ring for the FMC Ultra slimhole wellhead on the conductor. 2. If necessary, level the pad and prepare location for rig move. 3. Ensure any required plugs and 1 or well shut-ins have been accomplished in nearby wells for rig move and close approach concerns. Rig Operations: / 1. MIRU Nabors 9ES 2. Nipple up diverter spool and riser. Function test diverter. PU 4" DP as required and stand back in /' derrick. 3. MU 12 W' drilling assembly with MWD/GR and directionally drill surface hole to approximately 2,735' ...-/ MD 12,732' TVD. The actual surface hole TD will be +1-100' TVD below the top of the SV1 sand. 4. Run and cement the 9-%", 40# L-80 surface casing back to surface. A TAM port collar will only be ~ utilized as a contingency if surface hole drilling conditions warrant. 5. ND diverter and riser and NU casing 1 tubing head. NU BOPE and test to 3,500 psi. ",/ 6. MU 8-3,4" directional drilling assembly with MWD/GR/RES/PWD and a "ghost reamer" near the top of the HWDP section. RIH to float collar. Test the 9-%" casing to 3,500 psi for 30 minutes. V-02 Permit application Page 5 . . 7. Drill out shoe track. Circulate and condition mud. Displace well to new LSND drilling fluid at 9.0 ppg. / Drill 20' of new formation below rathole and perform an LOT. 8. Drill to +1-100' above the HRZ, ensure mud is in condition at 10.3 ppg. Hold the pre-reservoir meeting highlighting kick tolerance and detection. Drill to +1-100' above the Kingak and weight up the mud to 10.8 ppg. Perform a 10 stand short trip in conjunction with the weight up to ensure there is time to condition the mud. Directionally drill ahead to TD building angle and direction to the Top SAG at 9,282' MD 1 8,779' TVD (prognosed). TD is based on providing 5 - 10' of rathole below the float shoe after running casing. 9. POOH. Standing back the 4" drillpipe. Spot G-Seal at 10#/bbl across the UGNU/Schrader sands ~ Retrieve bowl protector. 10. MU and run 7" 26# L-80 BTCM Schrader Ma (3,710' MD) (approx. 5000'MD on 11. Freeze protect 7" x 9-%" annulus with dead crude to 2,200' TVD. 12. PU 6-%" cleanout BHA and drill up and continue RIH to the // float collar picking up 4" DP as required. to 3,500 psi for 30 minutes. 13. Drill out shoe track. Circulate and condition mud. well to new drilling fluid. Drill ./ 20' of new formation below rathole and perform an POOH for directional BHA. 14. PU 6-%" directional assembly with MWD/GR/RES/AIM/PWD and TIH. Directionally drill ahead to TD geosteering through Zone 4B to TD at 15,183' MD, 8,935' TVD (prognosed). / 15. Perform wiper trip, circulate and condition mud and POH. Lay down excess drillpipe. 16. MU and run 4-W' 12.6# L-80 BTC-M solid liner to TD and cement. Bump plug with perf pill. 17. PU off liner hanger and circulate and condition mud. Displace over to seawater with 2% KCL. 18. PU 2.5" Halliburton Millennium perforation assembly, perf -2,250' out of -5,900' of liner in new hole. /' POH, LD per guns. Note: It is planned in the AFE to make two perforation runs. The 2nd run will utilize a 7" packer. 19. MU 3-"W' 9.2# L-80 completion assembly and RIH. See completion schematic and Baker ,,/ recommendation for details. 20. Land tubing hanger and test hanger pack-off to 5,000 psi. 21. Reverse in seawater with Corexit and 2% KCL to protect the annulus. /" 22. Drop RHC ball and rod and set packer as per Baker recommendation and test tubing to 3,500 psi and annulus to 3,500 psi. Shear DCK valve. 23. Install two-way check and test to 1,000 psi. Nipple down the BOPE. Nipple up and test the tree to 5,000 psi. 24. Pull two-way check. Freeze protect the well to 2,200' TVD. 25. Install BPV. Secure the well and rig down 1 move off N-9ES. in two the /"'" /' /" Post-Riq Work: 1. MIRU slickline. Pull the ball and rod 1 RHC plug. 2. Pull out DCK shear valve, install GL V in all of the other mandrels. V-02 Permit application Page 6 . . V-02 Hazards and Contingencies Job 1: MIRU Hazards and Contingencies / ~ V-Pad is...QQldesignated as an H2S site. None of the current producers on V-Pad have indicated the presence of H2S. As a precaution however Standard Operating Procedures for H2S precautions should be followed at all times. ~ There is two wells directly adjacent to V-02. The V-107 is 15' to the east, the V-104 is 15' to the west. Surface shut-in and bleed off of gas-lift gas will be required on the adjacent wells during move-in and out. ~ Check the landing ring height on V-02. The BOP nipple up may need review for space out. ~ The AOGCC will not support a diverter dispensation on V pad. We will need to use a diverter for the surface hole drilling. ~ Critical concerns for drilling on V pad due to the abundance of hydrates and some free gas in the surface hole interval are: Monitoring the hole, checking connections, importance of maintaining mud properties (including pre-treating with DrillTreat for Hydrates), focus on avoiding swabbing situations, importance of not loading up the hole (hole cleaning), evacuation drills, muster areas, etc. should be topics for discussion and actions. Job 2: Drillinq Surface Hole ~ No faults are expected in the surface hole interval. ~ There are two close approach issues in the surface hole. The closest existing wells,V-104 and the V-107 (both 15' center-center from surface to -400' MD) will require a down hole shut in, gas lift bled off until new well is 500' below close approach. ~ A GyroData survey will be utilized while drilling the surface hole until clear of magnetic intereference. ~ Gas hydrates have been observed in wells drilled on V-pad. These were encountered near the base of permafrost to TD in the SV1 sand. Hydrates will be treated at surface with appropriate mud products and adjustment of drilling parameters. Refer to MI mud recommendation Job 3: Install surface Casinq Hazards and Contingencies ~ It is critical that cement is circulated to surface for well integrity. 225% excess cement through the / permafrost zone (and 30% excess below the permafrost) is planned. A 9-5/8" port collar will be positioned at ±1 OOO'MD to allow remedial cementing only if significant hole washout is evident. ~ "Annular Pumping Away" criteria for future permitting approval for annular injection. 1. Pipe reciprocation during cement displacement 2. Cement - Top of tail >500' TVD above shoe using 30% excess. 3. Casing Shoe Set approximately 100'TVD below SV-1 sand. 9-58", 40#, L-80, BTC 100% 80% Collapse 3090 psi 2472 psi Burst 5750 psi 4600 psi Tensile 916,000 Ib 732,800 Ib ID 8.835" 8.679" drift Make-up Torque To Position V-02 Permit application Page 7 . . Job 4: Drillinq Intermediate Hole Hazards and Contingencies );- V-02 should cross several faults in the intermediate hole inteNal. The first is in the Ugnu (3516'MD/3430'TVDss). This fault has been penetrated by 6 previous wells without difficulty. The second fault is in the Kingak (7750'TVDss). It has been penetrated by two previous wells without major problems. The third fault presents the highest risk and has not been previously penetrated. It is expected in the Kingak JC at 8350'TVDss. The primary risk is that the fault may have introduced fracturing into the Shublik and could cause lost circulation. Management of ECD limitations and preparations for losses are the primary contingencies. Consult the Lost Circulation Decision Tree regarding LCM treatments and procedures prior to drilling the fault. );- KICK TOLERANCE: In the case scenario of 8.7 ppg pore pressure at the Sag River depth prior to running 7" casing, gauge hole, a fracture~n of 12.0 ppg at the surface casing shoe, 10.8 ppg mud in the hole the kick tolerance· 72 s. An accurate LOT will be required as well as heightened awareness for kick det on. Contact Drilling Manager if LOT is less than 11.8 ppg. >- There are no "close approach" issues with the production hole inteNal of V-02. Job 6: Case & Cement Intermediate Hole Hazards and Contingencies );- A lead and tail slurry (lead LiteCRETE at 12.0 ppg and 15.8 ppg latex tail) will be used from TD to 500' above the Ugnu Ma. );- Ensure the Schrader cement has reached a compressive strength of 500 psi prior to freeze protecting. After freeze protecting the 7" x 9-5/8" casing outer annulus with xxx bbls of dead crude (2200'TVD), the hydrostatic pressure will be 8.0 ppg vs 8.5 ppg EMW of the formation pressure immediately below the shoe. To prevent this underbalance problem, pump 10 bbl of 10.5 ppg mud ahead of the dead crude, that will produce a slight overbalance to the formation pressure. Record formation breakdown pressure when pumping into the annulus, report this in the morning report. );- Ensure a minimum hydrostatic equivalent of 10.8 ppg on the formation during pumping of cement pre flushes/chemical washes. Losses of hole integrity and packing off has resulted from a reduction in hydrostatic pressure while pumping spacers and flushes. );- Considerable losses during running and cementing the 7" longstring has been experienced on some offset wells. A casing running program will be issued detailing circulating points and running speed. In addition a LCM pill composed of "G-Seal" will be placed across the Schrader and Ugnu to help arrest mud dehydration. );- Change to 7" casing rams and test the doors prior to picking up the casing string. 7",26#, L-80, BTC-mod 100% 80% Collapse 5410 psi 4328 psi Burst 7240 psi 5792 psi Tensile 604,000 Ib 483,200 Ib ID 6.276" 6.151" drift Make-up Torque To Position V-02 Permit application Page 8 . . Job 7: Drill 6-1/8" Production Hole Hazards and Contingencies ~ Lost circulation from fractures in the Shublik. Maintain offset from faulting as developed in the directional program, stay on the program line through the Shublik. ~ Lost circulation from potential faulting in the Ivishak. Stay close to the directional program line in the drilling polygon to avoid faulting. ~ Solids buildup in the mud. Use the solids control van if necessary to supplement the rig solids removal equipment. A solids free FloPro system is recommended for this interval so that fluids can be centrifuged. Job 9: Case and Cement Production Hole Hazards and Contingencies ~ Excess drag for running the production liner. Maintain as smooth a wellbore as possible. Job 10: DPC Perforate Well .Job 12: Run Completion Hazards and Contingencies ~ Watch hole fill closely and verify proper safety valves are on the rig floor while running this completion. ~ Shear valves have been failing at lower than the 2500 psi differential pressure. When testing the annulus maintain no more than a 1500 psi differential: 2000 psi tubing pressure, 3500 psi annulus pressure. Avoid cycling pressure (pumping up and bleeding off) prior to activating shear valve as this is thought to cause shearing at lower pressures. Job 13: ND/NUlRelease RiCl Hazards and Contingencies ~ No hazards specific to this well have been identified for this phase of the well construction. Reference RPs .:. Freeze Protection of Inner Annulus Post Rig work: 1. 2. RU wireline and pull rod and ball from RHC profile install dummy GLM in place of DCK V-02 Permit application Page 9 . . V-02 Well Summary of DrillinÇJ Hazards POST THIS NOTICE IN THE DOGHOUSE Surface Hole Section: · Gas hydrates may be encountered near the base of the Permafrost at 1800' MD and near the TD hole section through the SV sands. · Gravel beds below the Permafrost will tend to slough in when aerated (hydrate cut) mud is being circulated out. Ensure adequate mud viscosity is maintained to avoid stuck pipe situations. Intermediate Hole Section: · There are three faults expected in the intermediate hole section. Maintenance of the mud system and close watch of ECD will help minimize risk. · The intermediate hole section will be drilled with a recommended mud weight of 10.3 ppg to ensure shale stability in the HRZ shale · The mud weight will be increased to 10.8 ppg prior to the Kingak to stabilize the shale. · Tight hole, hole packing-off, and lost returns have been encountered in previous wells on this pad. Pipe sticking tendency is possible if the HRZ or Kingak shales gives problems. Back reaming at connections and good hole cleaning practices and close monitoring of PWD data will contribute to favorable hole conditions. Production Hole Section: . Potential for drilling into faults if the wellbore deviates far from plan. · Premature bit failure in the hard intervals of Zone 4. HYDROGEN SULFIDE - H2S · This drill-site not ~Signated as an H2S drill site. Recent wells test do not indicate the presence of H2S. As a precaution, Standard Operating Procedures for H2S precautions should be followed at all times. CONSULT THE V-PAD DATA SHEET AND THE WELL PLAN FOR ADDITIONAL INFORMATION V-02 Permit application Page 10 V-02 (P8) Proposal Schlumberger Report Date: May 4, 2004 Survey / DLS Computation Method: Minimum Curvature I Lubinski Client: BP Exploration Alaska Vertical Section Azimuth: 300.000' Field: Prudhoe Bay Unit - WOA study Vertical Section Origin: N 0.000 ft, E 0,000 ft Structure I Slot: V-Pad I Plan Y-02 (N-I) II!!III!! TVD Reference Datum: KB Well: PlanY-02(N-I) F sibl I TVD Reference Elevation: 81.60 ft relative to MSL Borehole: Plan Y-02 e8 Sea Bed / Ground Level Elevation: 53.10 ft relative to MSL UWUAPI#: 50029 Magnetic Declination: 24.962' Survey Name / Date: Y-02 (P8) I May 4, 2004 Total Field Strength: 57566.503 nT Torti AHD 10011 ERD ratio: 291.241' /7304.13 ft/6.554I 0.818 Magnetic Dip: 80.816' Grid Coordinate System: NAD27 Alaska State Planes, Zone 04, US Feet Declination Date: May 31, 2004 Location Lat/Long: N 70.32798975, W 149.26606211 Magnetic Declination Model: BGGM 2003 . Location Grid N/E YIX: N 5970077.630 ftUS, E 590496.880 ftUS North Reference: True North Grid Convergence Angle: ->D.69110597· Total Corr Mag North·> True North: +24.962' Grid Scale Factor: 0.99990930 Local Coordinates Referenced To: Well Head I Comments Measured I Inclination I Azimuth I Sub-Sea TVD I TVD Vertical I Along Hole I NS EW I DLS I Tool Face I Build Rate I Walk Rate I Northing Easting Latitude Longitude Depth Section Departure (It) (deg) (deg) (It) (It) (It) (It) (It) (It) (deg/100 It) (deg) (deg/100 It) (deg/100 It) (ltUS) (ftUS) RTE 0.00 0.00 180.00 -81.60 0.00 0.00 0,00 0,00 0.00 0.00 180.00M 0.00 0.00 5970077.63 590496.88 N 70.32798975 W 149.26606211 KOP Bid 1.5/100 300.00 0.00 180.00 218.40 300.00 0.00 0.00 0.00 0.00 0,00 180.00M 0.00 0.00 5970077.63 590496.88 N 70.32798975 W 149.26606211 400.00 1.50 180.00 318.39 399.99 -0.65 1.31 -1.31 0.00 1.50 180.00M 1.50 0.00 5970076.32 590496.90 N 70.32798617 W 149.26606211 500.00 3.00 180.00 418.31 499.91 -2.62 5.23 -5.23 0,00 1.50 180.00M 1.50 0.00 5970072.40 590496.94 N 70.32797545 W 149,26606211 600.00 4.50 180.00 518.09 599.69 -5.89 11.77 -11.77 0.00 1.50 180.00M 1.50 0.00 5970065.86 590497.02 N 70.32795758 W 149.26606211 700.00 6.00 180.00 617.67 699.27 -10.46 20.92 -20.92 0,00 1.50 O.OOG 1.50 0.00 5970056.71 590497.13 N 70.32793258 W 149.26606211 End Bid 800.00 7.50 180.00 716.97 798.57 -16.34 32.68 -32.68 0.00 1.50 O.OOG 1.50 0.00 5970044.96 590497.27 N 70.32790047 W 149,26606211 Drp 1.5/100 900.00 7.50 180.00 816.12 897.72 -22.87 45.73 -45.73 0.00 0.00 180.00G 0.00 0.00 5970031,91 590497.43 N 70.32786482 W 149,26606211 1000.00 6.00 180.00 915.42 997.02 -28.74 57.48 -57.48 0,00 1,50 180.00G -1.50 0.00 5970020.16 590497.57 N 70.32783271 W 149.26606211 1100.00 4.50 180.00 1015.00 1096.60 -33.32 66.63 -66.63 0.00 1,50 180,00M -1.50 0.00 5970011.01 590497.68 N 70.32780771 W 149.26606211 1200.00 3.00 180.00 1114.78 1196.38 -36.59 73.17 -73.17 0.00 1.50 180.00M -1.50 0.00 5970004.47 590497.76 N 70,32778984 W 149.26606211 1300.00 1,50 180.00 1214.70 1296.30 -38.55 77.10 -77.10 0.00 1.50 -90.00M -1.50 0.00 5970000.54 590497.81 N 70,32777912 W 149.26606211 End Drp 1400.00 0.00 270.00 1314.69 1396.29 -39.20 78.41 -78.41 0.00 1.50 -95.53M -1.50 0.00 5969999.23 590497.83 N 70.32777554 W 149.2660. SV5 1630.31 0.00 264.47 1545.00 1626.60 -39.20 78.41 -78.41 0.00 0.00 -95.53M 0.00 0.00 5969999.23 590497.83 N 70.32777554 W 149.2660 SV4 1760.31 0.00 264.47 1675.00 1756.60 -39.20 78.41 -78.41 0.00 0.00 -95.53M 0.00 0.00 5969999.23 590497.83 N 70.32777554 W 149.2660 Base Perm 1785.31 0.00 264.47 1700.00 1781.60 -39.20 78.41 -78.41 0.00 0.00 -95.53M 0.00 0.00 5969999.23 590497.83 N 70.32777554 W 149.26606211 SV3 2160.31 0.00 264.47 2075.00 2156.60 -39.20 78.41 -78.41 0.00 0.00 -95.53M 0.00 0.00 5969999.23 590497.83 N 70.32777554 W 149.26606211 SV2 2305.31 0.00 264.47 2220.00 2301.60 -39.20 78.41 -78.41 0.00 0.00 -95.53M 0.00 0.00 5969999.23 590497.83 N 70.32777554 W 149.26606211 SV1 2640.31 0.00 264.47 2555.00 2636.60 -39.20 78.41 -78.41 0.00 0.00 -95.53M 0.00 0.00 5969999.23 590497.83 N 70.32777554 W 149.26606211 9-518" Csg PI 2735.31 0.00 264.47 2650.00 2731.60 -39.20 78.41 -78.41 0.00 0.00 -95.53M 0.00 0.00 5969999.23 590497.83 N 70.32777554 W 149.26606211 UG4 2945.31 0.00 264.47 2860.00 2941.60 -39.20 78.41 -78.41 0.00 0.00 -95.53M 0.00 0.00 5969999.23 590497.83 N 70.32777554 W 149.26606211 UG4A 2975.31 0.00 264.4 7 2890.00 2971.60 -39.20 78.41 -78.41 0.00 0.00 -95.53M 0.00 0.00 5969999.23 590497.83 N 70.32777554 W 149.26606211 UG3 3310.31 0.00 264.47 3225.00 3306.60 -39.20 78.41 -78.41 0.00 0.00 -95.53M 0.00 0.00 5969999.23 590497.83 N 70.32777554 W 149.26606211 V Pad Fault 3515.31 0.00 264.47 3430.00 3511.60 -39.20 78.41 -78.41 0.00 0.00 -95.53M 0.00 0.00 5969999.23 590497.83 N 70.32777554 W 149.26606211 UG1 3670.31 0.00 264.47 3585.00 3666.60 -39.20 78.41 -78.41 0.00 0.00 -95.53M 0.00 0.00 5969999.23 590497.83 N 70.32777554 W 149.26606211 Ma 4210.31 0.00 264.47 4125.00 4206.60 -39.20 78.41 -78.41 0.00 0.00 -95.53M 0.00 0.00 5969999.23 590497.83 N 70.32777554 W 149.26606211 Na 4265.31 0.00 264.47 4180.00 4261.60 -39.20 78.41 -78.41 0.00 0.00 -95.53M 0.00 0.00 5969999.23 590497.83 N 70.32777554 W 149.26606211 OA 4375.31 0.00 264.47 4290.00 4371.60 -39.20 78.41 -78.41 0.00 0.00 -95.53M 0.00 0.00 5969999.23 590497.83 N 70.32777554 W 149.26606211 OBf Base 4800.31 0.00 264.47 4715.00 4796.60 -39.20 78.41 -78.41 0.00 0.00 -95.53M 0.00 0.00 5969999.23 590497.83 N 70.32777554 W 149.26606211 CM2 5054.31 0.00 264.4 7 4969.00 5050.60 -39.20 78.41 -78.41 0.00 0.00 -95.53M 0.00 0.00 5969999.23 590497.83 N 70.32777554 W 149.26606211 WellDesign Ver 3.1 RT-SP3.03-HF4.00 Bld( d031 rt-546 ) Plan V-02 (N-I)\Plan V-02 (N-I)\Plan V-02\V-02 (P8) Generated 5/4/2004 11:45 AM Page 1 of 3 Comments Measured I Inclination I Azimuth I Su b·Sea TVD I TVD Vertical I Along Hole I NS EW I DLS I Tool Face I Build Rate I Walk Rate I Northing Easting Latitude Longitude Depth Section Departu re (It) (deg) (deg) (It) (It) (It) (It) (It) (It) (deg/100 It) (deg) (deg/100 It) (deg/100 It) (ltUS) (ltUS) CM1 5733.31 0.00 264.47 5648.00 5729.60 -39.20 78.41 -78.41 0.00 0.00 -95.53M 0.00 0.00 5969999.23 590497.83 N 70.32777554 W 149.26606211 Top HRZ 6283.31 0.00 264.47 6198.00 6279.60 -39.20 78.41 -78.41 0.00 0.00 -95.53M 0.00 0.00 5969999.23 590497.83 N 70.32777554 W 149.26606211 Base HRZ 6575.31 0.00 264.47 6490.00 6571.60 -39.20 78.41 -78.41 0.00 0.00 -95.53M 0.00 0.00 5969999.23 590497.83 N 70.32777554 W 149.26606211 Top Kuparuk 6615.31 0.00 264.4 7 6530.00 6611.60 -39.20 78.41 -78.41 0.00 0.00 -95.53M 0.00 0.00 5969999.23 590497.83 N 70.32777554 W 149.26606211 KOP Bid 4/100 6720.00 0.00 264.47 6634.69 6716.29 -39.20 78.41 -78.41 0.00 0.00 -95.53M 0.00 0.00 5969999.23 590497.83 N 70.32777554 W 149.26606211 LCU 6745.31 1.01 264.47 6660.00 6741.60 -39.02 78.63 -78.43 -0.22 4.00 -95.53M 4.00 0.00 5969999.21 590497.60 N 70.32777548 W 149.26606392 6800.00 3.20 264.47 6714.65 6796.25 -37.39 80.64 -78.62 -2.22 4.00 -95.53M 4.00 0.00 5969998.99 590495.61 N 70.32777495 W 149.26608014 6900.00 7.20 264.47 6814.22 6895.82 -30.01 89.70 -79.50 -11.24 4.00 O.OOG 4.00 0.00 5969998.01 590486.60 N 70.32777257 W 149.26615328 TMLV 6931.07 8.44 264.47 6845.00 6926.60 -26.57 93.93 - 79.90 -15.45 4.00 O.OOG 4.00 0.00 5969997.55 590482.40 N 70.32777146 W 149.26618741 7000.00 11.20 264.47 6912.91 6994.51 -17.00 105.68 -81.04 -27.15 4.00 O.OOG 4.00 0.00 5969996.28 590470.71 N 70.32776837 W 149.26628230 7100.00 15.20 264.47 7010.25 7091.85 1.58 128.52 -83.23 -49.88 4.00 O.OOG 4.00 0.00 5969993.81 590448.01 N 70.32776236 W 149.266. 7200.00 19.20 264.4 7 7105.76 7187.36 25.64 158.08 -86.08 -79.30 4.00 O.OOG 4.00 0.00 5969990.61 590418.63 N 70.32775458 W 149.266 7300.00 23.20 264.47 7198.97 7280.57 55.06 194.24 -89.56 -115.29 4.00 O.OOG 4.00 0.00 5969986.69 590382.69 N 70.32774507 W 149.26699 02 7400.00 27.20 264.47 7289.44 7371.04 89.71 236.80 -93.66 -157.66 4.00 O.OOG 4.00 0.00 5969982.08 590340.37 N 70.32773387 W 149.26734061 7500.00 31.20 264.47 7376.71 7458.31 129.41 285.58 -98.36 -206.21 4.00 O.OOG 4.00 0.00 5969976.80 590291.89 N 70.32772104 W 149.26773429 Top Kingak 7527.39 32.30 264.47 7400.00 7481.60 141.14 299.99 -99.75 -220.56 4.00 O.OOG 4.00 0.00 5969975.24 590277.56 N 70.32771724 W 149.26785061 7600.00 35.20 264.47 7460.37 7541.97 173.96 340.33 -103.63 -260.70 4.00 O.OOG 4.00 0.00 5969970.87 590237.4 7 N 70.32770663 W 149.26817616 7700.00 39.20 264.47 7540.01 7621.61 223.16 400.78 -109.45 -320.87 4.00 O.OOG 4.00 0.00 5969964.33 590177.38 N 70.32769072 W 149.26866404 TJF 7759.07 41.56 264.47 7585.00 7666.60 254.30 439.04 -113.13 -358.96 4.00 O.OOG 4.00 0.00 5969960.19 590139.34 N 70.32768065 W 149.26897291 End Bid 7797.62 43.10 264.47 7613.49 7695.09 275.43 465.00 -115.63 -384.80 4.00 O.OOG 4.00 0.00 5969957.37 590113.54 N 70.32767382 W 149.26918242 Fault Crossing 7984.58 43.10 264.4 7 7750.00 7831.60 379.41 592.75 -127.94 -511.96 0.00 O.OOG 0.00 0.00 5969943.54 589986.54 N 70.32764019 W 149.27021361 TJE 8340.70 43.10 264.47 8010.00 8091.60 577.45 836.07 -151.37 -754.18 0.00 O.OOG 0.00 0.00 5969917.19 589744.65 N 70.32757613 W 149.27217768 TJD 8511.90 43.10 264.47 8135.00 8216.60 672.67 953.05 -162.63 -870.63 0.00 O.OOG 0.00 0.00 5969904.53 589628.36 N 70.32754532 W 149.27312194 Fault Crossing 8806.38 43.10 264.47 8350.00 8431.60 836.44 1154.26 -182.01 -1070.92 0.00 O.OOG 0.00 0.00 5969882.74 589428.34 N 70.32749231 W 149.27474606 TJC 8963.89 43.10 264.47 8465.00 8546.60 924.03 1261.88 -192.37 -1178.05 0.00 O.OOG 0.00 0.00 5969871.08 589321.35 N 70.32746396 W 149.27561477 TJa 9066.62 43.10 264.47 8540.00 8621.60 981.16 1332.08 -199.13 -1247.92 0.00 O.OOG 0.00 0.00 5969863.48 589251.57 N 70.32744546 W 149.27618133 TJA 9162.49 43.10 264.47 8610.00 8691.60 1034.48 1397.58 -205.44 -1313.13 0.00 O.OOG 0.00 0.00 5969856.39 589186.45 N 70.32742820 W 149.27671010 Top Sag River 9281.65 43.10 264.47 8697.00 8778.60 1100.75 1479.00 -213.28 -1394.18 0.00 O.OOG 0.00 0.00 5969847.57 589105.51 N 70.32740674 W 149.27736730 7" Csg pt 9281.79 43.10 264.47 8697.10 8778.70 1100.83 1479.10 -213.29 -1394.27 0.00 O.OOG 0.00 0.00 5969847.56 589105.41 N 70.32740671 W 149.27736806 Cry 12/100 9300.53 43.10 264.47 8710.78 8792.38 1111.25 1491.90 -214.52 -1407.01 0.00 64.87G 0.00 0.00 5969846.18 589092.69 N 70.32740334 W 149.27747139 Shublik A 9324.36 44.38 268.18 8728.00 8809.60 1124.96 1508.37 -215.57 -1423.45 12.00 62.19G 5.35 15.54 5969844.93 589076.26 N 70.32740046 W 149.2776. 9400.00 49.13 278.81 8779.88 8861 .48 1174.21 1563.38 -212.02 -1478.27 12.00 54.89G 6.29 14.06 5969847.81 589021.41 N 70.32741012 W 149.27804 ShuB 9428.26 51.14 282.37 8798.00 8879.60 1194.66 1585.07 -208.03 -1499.58 12.00 52.60G 7.10 12.61 5969851.55 589000.06 N 70.32742103 W 149.27822203 ShuC 9454.31 53.08 285.48 8814.00 8895.60 1214.41 1605.62 -203.07 -1519.53 12.00 50.70G 7.45 11.92 5969856.26 588980.05 N 70.32743455 W 149.27838378 ShuD 9469.50 54.25 287.22 8823.00 8904.60 1226.30 1617.86 -199.63 -1531.27 12JY 49.67G 7.69 11.44 5969859.57 588968.27 N 70.32744395 W 149.27847898 9500.00 56.66 290.56 8840.30 8921.90 1250.95 1642.98 -191.49 -1555.03 12.00 47.77G 7.92 10.95 5969867.42 588944.42 N 70.32746618 W 149.27867167 TIEL 9506.79 57.21 291.27 8844.00 8925.60 1256.57 1648.67 -189.46 -1560.34 12.00 47.38G 8.10 10.57 5969869.38 588939.08 N 70.32747172 W 149.27871475 Target I Cry 12/100 9564.09 62.00 297.00 8873.00 8954.60 1305.69 1698.07 -169.21 -1605.38 12.00 27.55G 8.35 9.99 5969889.09 588893.81 N 70.32752701 W 149.27908000 TSAD 9564.11 62.00 297.00 8873.01 8954.61 1305.72 1698.09 -169.20 -1605.40 12.00 27.55G 10.64 6.29 5969889.09 588893.79 N 70.32752704 W 149.27908014 9600.00 65.84 299.18 8888.79 8970.39 1337.93 1730.31 -154.02 -1633.82 12.00 26.59G 10.69 6.08 5969903.93 588865.18 N 70.32756850 W 149.27931067 9700.00 76.66 304.67 8920.91 9002.51 1432.37 1824.86 -103.91 -1713.96 12.00 24.82G 10.82 5.49 5969953.06 588784.46 N 70.32770533 W 149.27996056 9800.00 87.59 309.68 8934.60 9016.20 1530.47 1923.76 -44.12 -1792.70 12.00 24.13G 10.93 5.01 5970011.90 588705.01 N 70.32786864 W 149.28059922 90' pt 9822.00 90.00 310.76 8935.06 9016.66 1552.11 1945.76 -29.92 -1809.49 12.00 24.11G 10.95 4.90 5970025.90 588688.05 N 70.32790742 W 149.28073542 End Cry 9869.82 95.23 313.11 8932.88 9014.48 1598.83 1993.51 2.00 -1845.02 12.00 O.OOG 10.95 4.91 5970057.37 588652.14 N 70.32799458 W 149.28102355 Cry 6/100 9988.47 95.23 313.11 8922.06 9003.66 1713.90 2111.67 82.74 -1931.27 0.00 -143.59G 0.00 0.00 5970137.07 588564.93 N 70.32821512 W 149.28172313 10000.00 94.68 312.70 8921.06 9002.66 1725.10 2123.15 90.57 -1939.69 6.00 -143.62G -4.83 -3.57 5970144.79 588556.42 N 70.32823648 W 149.28179140 Well Design Ver 3.1RT-SP3.03-HF4.00 Bld( d031rt-546) Plan V-02 (N-I)\Plan V-02 (N-I)\Plan V-02\V-02 (P8) Generated 5/4/2004 11 :45 AM Page 2 of 3 Comments Measured I Inclination I Azimuth I Sub-Sea TVD I TVD Vertical I Along Hole I NS EW I DLS I Tool Face I Build Rate I Walk Rate I Northing Easting Latitude Longitude Depth Section Departure (It) (deg) (deg) (It) (It) (It) (It) (It) (It) (deg/100 It) (deg) (deg/100 It) (deg/100ft) (ftUS) (ftUS) Target 2 10014.02 94.00 312.20 8920.00 9001.60 1738.75 2137.13 100.00 -1950.00 6.00 -142.25G -4.83 -3.57 5970154.10 588546.00 N 70.32826225 W 149.28187506 End Cry 10052.47 92.17 310.79 8917.93 8999.53 1776.37 2175.53 125.44 -1978.76 6.00 O.OOG -4.75 -3.67 5970179.18 588516.94 N 70.32833172 W 149.28210832 Cry 6/100 10503.10 92.17 310.79 8900.83 8982.43 2218.72 2625.83 419.60 -2319.71 0.00 -105.10G 0.00 0.00 5970469.18 588172.50 N 70.32913508 W 149.28487388 Target 3 10527.03 91.80 309.40 8900.00 8981.60 2242.27 2649.75 435.00 -2338.00 6.00 -106.71G -1.57 -5.80 5970484.36 588154.02 N 70.32917714 W 149.28502227 End Cry 10536.69 91.63 308.84 8899.71 8981.31 2251.80 2659.41 441.09 -2345.49 6.00 O.OOG -1.73 -5.75 5970490.36 588146.46 N 70.32919378 W 149.28508304 Cry 6/100 11455.11 91.63 308.84 8873.53 8955.13 3158.93 3577.45 1016.90 -3060.51 0.00 -136.59G 0.00 0.00 5971057.45 587424.61 N 70.33076613 W 149.29088346 Target 4 11492.58 90.00 307.30 8873.00 8954.60 3196.02 3614.92 1040.00 -3090.00 6.00 -137.22G -4.36 -4.12 5971080.19 587394.85 N 70.33082920 W 149.29112269 11500.00 89.67 307.00 8873.02 8954.62 3203.38 3622.34 1044.48 -3095.92 6.00 -137.22G -4.40 -4.07 5971084.60 587388.88 N 70.33084144 W 149.29117069 End Cry 11523.53 88.64 306.04 8873.37 8954.97 3226.76 3645.87 1058.49 -3114.83 6.00 O.OOG -4.40 -4.08 5971098.37 587369.80 N 70.33087968 W 149.29132411 Cry 13/100 12179.51 88.64 306.04 8888.97 8970.57 3878.92 4301,66 1444.31 -3645.12 0.00 88.60G 0.00 0.00 5971477.73 586834.94 N 70.33193305 W 149.29562642 12200.00 88,70 308.70 8889.45 8971.05 3899.23 4322.15 1456.74 -3661.39 13.00 88.54G 0.32 13.00 5971489.97 586818.52 N 70.33196699 W 149.29575847 12300.00 89.06 321.70 8891.41 8973.01 3995.50 4422.13 1527.53 -3731.69 13.00 88.29G 0.36 13.00 5971559.90 586747.38 N 70.33216029 W 149.296. 12400.00 89.47 334,69 8892.69 8974.29 4083.44 4522.12 1612.33 -3784.28 13.00 88.12G 0.41 12.99 5971644.05 586693.78 N 70.33239188 W 149.296 Target 5 12440.84 89.65 340.00 8893.00 8974.60 4115,90 4562.96 1650.00 -3800.00 13.00 89.56G 0.43 12.99 5971681.53 586677.61 N 70.33249478 W 149.29688 45 12500,00 89,71 347.69 8893.33 8974.93 4158.53 4622.12 1706.78 -3816.45 13.00 89.52G 0.11 13.00 5971738.10 586660.48 N 70.33264988 W 149.29701709 End Cry 12585.48 89.81 358.80 8893.69 8975.29 4209.60 4707.59 1791.54 -3826.48 13.00 O.OOG 0.12 13,00 5971822.72 586649.42 N 70.33288141 W 149.29709884 Cry 13/100 12689.51 89.81 358.80 8894.03 8975.63 4263.48 4811.62 1895.54 -3828.66 0.00 89.44G 0.00 0.00 5971926.68 586646.00 N 70.33316553 W 149.29711690 12700.00 89.82 0.17 8894.06 8975.66 4268.81 4822.11 1906.03 -3828.75 13.00 89.43G 0.13 13.00 5971937.17 586645.77 N 70.33319419 W 149.29711770 12800.00 89.96 13.17 8894.25 8975.85 4308.33 4922.11 2005.14 -3817.17 13.00 89.41 G 0.13 13.00 5972036.40 586656.16 N 70.33346497 W 149.29702415 12900.00 90.09 26.17 8894.21 8975.81 4326.23 5022.11 2099.11 -3783.59 13.00 89.41G 0.13 13.00 5972130.76 586688.60 N 70.33372172 W 149.29675215 Target 6 12983.35 90.20 37.00 8894.00 8975.60 4323.94 5105.46 2170.00 -3740.00 13.00 89.54G 0.13 13.00 5972202.16 586731.33 N 70.33391546 W 149.29639890 13000.00 90.22 39.17 8893.94 8975.54 4321.59 5122.11 2183.11 -3729.73 13.00 89.55G 0.10 13.00 5972215.39 586741.44 N 70.33395128 W 149.29631563 13100.00 90.31 52.16 8893.4 7 8975.07 4294.65 5222.11 2252.84 -3658.36 13.00 89.61G 0.10 13.00 5972285.98 586811.96 N 70.33414189 W 149.29573697 13200.00 90.39 65.16 8892.85 8974.45 4246.79 5322.11 2304,74 -3573.13 13.00 89.69G 0.08 13.00 5972338.89 586896.55 N 70.33428377 W 149.29504583 13300.00 90.46 78,17 8892.11 8973.71 4180.45 5422.11 2336.12 -3478.41 13.00 89.78G 0.06 13.00 5972371.42 586990.87 N 70.33436964 W 149.29427764 13400.00 90.49 91.17 8891.28 8972.88 4099.05 5522.10 2345.40 -3379.06 13.00 89.89G 0.04 13.00 5972381.89 587090.09 N 70.33439511 W 149.29347179 End Cry 13400.61 90.49 91.25 8891.27 8972.87 4098.51 5522.71 2345.39 -3378.44 13.00 O.OOG 0.02 13.00 5972381.88 587090.71 N 70.33439507 W 149.29346680 Cry 13/100 13646.85 90.49 91.25 8889.16 8970.76 3882.65 5768.94 2340.04 -3132.28 0.00 -88.52G 0.00 0.00 5972379.50 587336.90 N 70.33438075 W 149.29146995 Target 7 13664.13 90.55 89.00 8889.00 8970.60 3867.67 5786.22 2340.00 -3115.00 13.00 -87.56G 0.33 -13.00 5972379.67 587354.17 N 70.33438066 W 149.29132982 End Cry 13679.58 90.64 86.99 8888.84 8970.44 3854.57 5801.67 2340.54 -3099.56 13.00 O.OOG 0.55 -12.99 5972380.40 587369.60 N 70.33438216 W 149.29120457 Cry 6/100 14933.97 90.64 86.99 8874.93 8956.53 2802.69 7055.99 2406.34 -1846.97 0.00 0.69G 0.00 0.00 5972461.30 588621.19 N 70.33456304 W 149.2810_ Target 8 14985.06 93.70 87.03 8873.00 8954.60 2759.88 7107.03 2409.00 -1796.00 6.00 0.52G 6.00 0.07 5972464.57 588672. 12 N 70.33457034 W 149.2806 15000.00 94.60 87.04 8871.92 8953.52 2747.38 7121.93 2409.77 -1781.12 6.00 0.52G 6.00 0.05 5972465.52 588687.00 N 70.33457246 W 149.28050 v End Cry 15023.73 ,96.02 87.05 8869.72 8951.32 2727.55 7145.56 2410.99 -1757.52 6.00 O.OOG 6.00 0.05 5972467.02 588710.57 N 70.33457580 W 149.28031857 TO 1 4-112" Lnr 15183.18 / 96.02 87.05 8853.00 8934.60 2594.49 7304.13 2419.15 -1599.16 0.00 O.OOG 0.00 0.00 5972477.09 588868.81 N 70.33459819 W 149.27903401 LeQal Description: NorthinQ (YI ¡ftUSI EastinQ (XI ¡ftUSI Surface: 4831 FSL 1804 FEL S11 T11N R11E UM 5970077.63 590496.88 Target 1: 4661 FSL 3410 FEL S11 T11N R11E UM 5969889.09 588893.81 Target 2: 4930 FSL 3754 FEL S11 T11N R11E UM 5970154.10 588546.00 Target 3: 5265 FSL 4142 FEL S11 T11 N R11 E UM 5970484.36 588154.02 Target 4 : 590 FSL4893 FELS2T11N R11EUM 5971080.19 587394.85 Target 5: 1200 FSL 323 FEL S3 T11N R11E UM 5971681.53 586677. 61 Target 6: 1720 FSL 262 FEL S3 T11 N R11 E UM 5972202.16 586731.33 Target 7: 1890 FSL 4917 FEL S2 T11N R11E UM 5972379.67 587354.17 Target 8: 1959 FSL 3598 FEL S2 T11N R11E UM 5972464.57 588672. 12 TD/BHL: 1970 FSL3401 FELS2T11NR11EUM 5972477.09 588868.81 WellDesign Ver 3.1 RT-SP3.03-HF4.00 Bld( d031 rt-546 ) Plan V-02 (N-I)\Plan V-02 (N-I)\Plan V-02\V-02 (P8) Generated 5/4/2004 11 :45 AM Page 3 of 3 . . Schlumberger WELL V-02 (P8) FIELD Prudhoe Bay Unit - WOA STRUCTURE V-Pad Magnetic Parameters Model' BGGM 2003 Dip: 80.816' MagDe<::: +24.962" Data: May31,2004 F$ 57566.5 fiT Surfaœlocation Lat; N701940.763 Lon: W1491557.824 NAD27 Alaska State Pl3nes, Zor\é 04, US Feet Northir!g 5970077.63ftUS GridConv: +0.69110597" Easling 590496.88/tUS Scale Fact 0.9999093033 Mi&Cellaoeous Slot: PlanV-02(N-I} P~n V..QZ(PB) TVD Ref: KB (81.60 ft above MSL) $!Vy Date: May 04, 2004 o 1200 2400 3600 4800 _KOP Bid 1.51100 1200 1.5/100 1200 Drp 2400 2400 PI "'"' 3600 3600 ;2 Õ 0 N ~ ê = ~ 11 4800 4800 ( ) ëõ ü (/) 0 > I- 6000 '..H'............... 6000 7200 7200 8400 8400 o 1200 2400 3600 4800 Vertical Section (ft) Azim = 300°, Scale = 1 (in):1200(ft) Origin = 0 N/-S, 0 EI-W V-02 (P8) Proposal Schlumberger Report Date: May 4, 2004 Survey / DLS Computation Method: Minimum Curvature I Lubinski Client: BP Exploration Alaska Vertical Section Azimuth: 90.000' Field: Prudhoe Bay Unit - WOA study Vertical Section Origin: N 0.000 ft, E 0.000 ft Structure / Slot: V-Pad I Plan Y-02 (N-I) IS I IS ty ND Reference Datum: KB Well: PlanV-02(N-I) slbl I ND Reference Elevation: 81.60 ft relative to MSL Borehole: Plan Y-02 Fea Sea Bed I Ground Level Elevation: 53.10 ft relative to MSL UWUAPI#: 50029 Magnetic Declination: 24.962' Survey Name I Date: Y-02 (P8) / May 4, 2004 Total Field Strength: 57566.503 n T Tort I AHD / DDI / ERD ratio: 291.241' /7304.13 fIl6.554/ 0.818 Magnetic Dip: 80.816' Grid Coordinate System: NAD27 Alaska State Planes, Zone 04, US Feet Declination Date: May 31 , 2004 . Location Lat/Long: N 70.32798975, W 149.26606211 Magnetic Declination Model: BGGM 2003 Location Grid N/E Y/X: N 5970077.630 ftUS, E 590496.880 ftUS North Reference: True North Grid Convergence Angle: -t{).69110597' Total Carr Mag North·) True North: +24.962' Grid Scale Factor: 0.99990930 Local Coordinates Referenced To: Well Head Comments Measured Inclination I Azimuth I Sub·Sea TVD I ND Vertical I Along Hole I NS EW I DLS I Tool Face I Build Rate I Walk Rate I Northing Easting Latitude Longitude Depth Section Departure (It) (deg) (deg) (It) (It) (It) (It) (It) (It) (deg/100 ft) (deg) (deg/100 ft) (deg/100ft) (ftUS) (ftUS) Cry 13/100 12179.51 88.64 306.04 8888.97 8970.57 -3645.12 4301.66 1444.31 -3645.12 0.00 88.60G 0.00 0.00 5971477.73 586834.94 N 70.33193305 W 149.29562642 12200.00 88.70 308.70 8889.45 8971.05 -3661.39 4322.15 1456.74 -3661.39 13.00 88.54G 0.32 13.00 5971489.97 586818.52 N 70.33196699 W 149.29575847 12300.00 89.06 321.70 8891.41 8973.01 -3731.69 4422.13 1527.53 -3731.69 13.00 88.29G 0.36 13.00 5971559.90 586747.38 N 70.33216029 W 149.29632892 12400.00 89.4 7 334.69 8892.69 8974.29 -3784.28 4522.12 1612.33 -3784.28 13.00 88.12G 0.41 12.99 5971644.05 586693.78 N 70.33239188 W 149.29675576 Target 5 12440.84 89.65 340.00 8893.00 8974.60 -3800.00 4562.96 1650.00 -3800.00 13.00 89.56G 0.43 12.99 5971681.53 586677.61 N 70.33249478 W 149.29688345 12500.00 89.71 347.69 8893.33 8974.93 -3816.45 4622.12 1706.78 -3816.45 13.00 89.52G 0.11 13.00 5971738.10 586660.48 N 70.33264988 W 149.29701709 End Cry 12585.48 89.81 358.80 8893.69 8975.29 -3826.48 4707.59 1791.54 -3826.48 13.00 O.OOG 0.12 13.00 5971822.72 586649.42 N 70.33288141 W 149.29709884 Cry 13/100 12689.51 89.81 358.80 8894.03 8975.63 -3828.66 4811.62 1895.54 -3828.66 0.00 89.44G 0.00 0.00 5971926.68 586646.00 N 70.33316553 W 149.29711690 12700.00 89.82 0.17 8894.06 8975.66 -3828.75 4822.11 1906.03 -3828.75 13.00 89.43G 0.13 13.00 5971937.17 586645.77 N 70.33319419 W 149.29711770 12800.00 89.96 13.17 8894.25 8975.85 -3817.17 4922.11 2005.14 -3817.17 13.00 89.41 G 0.13 13.00 5972036.40 586656.16 N 70.33346497 W 149.29702415 12900.00 90.09 26.17 8894.21 8975.81 -3783.59 5022.11 2099.11 -3783.59 13.00 89.41 G 0.13 13.00 5972130.76 586688.60 N 70.33372172 W 149.29675215 Target 6 12983.35 90.20 37.00 8894.00 8975.60 -3740.00 5105.46 2170.00 -3740.00 13.00 89.54G 0.13 13.00 5972202.16 586731.33 N 70.33391546 W 149.29639890 13000.00 90.22 39.17 8893.94 8975.54 -3729.73 5122.11 2183.11 -3729.73 13.00 89.55G 0.10 13.00 5972215.39 586741.44 N 70.33395128 W 149.2963. 13100.00 90.31 52.16 8893.47 8975.07 -3658.36 5222.11 2252.84 -3658.36 13.00 89.61G 0.10 13.00 5972285.98 586811.96 N 70.33414189 W 149.2957 13200.00 90.39 65.16 8892.85 8974.45 -3573.13 5322.11 2304.74 -3573.13 13.00 89.69G 0.08 13.00 5972338.89 586896.55 N 70.33428377 W 149.29504583 13300.00 90.46 78.17 8892.11 8973.71 -3478.41 5422.11 2336.12 -3478.41 13.00 89.78G 0.06 13.00 5972371.42 586990.87 N 70.33436964 W 149.29427764 13400.00 90.49 91.17 8891.28 8972.88 -3379.06 5522.10 2345.40 -3379.06 13.00 89.89G 0.04 13.00 5972381.89 587090.09 N 70.33439511 W 149.29347179 End Cry 13400.61 90.49 91.25 8891.27 8972.87 -3378.44 5522.71 2345.39 -3378.44 13.00 O.OOG 0.02 13.00 5972381.88 587090.71 N 70.33439507 W 149.29346680 Cry 13/100 13646.85 90.49 91.25 8889.16 8970.76 -3132.28 5768.94 2340.04 -3132.28 0.00 -88.52G 0.00 0.00 5972379.50 587336.90 N 70.33438075 W 149.29146995 Target 7 13664.13 90.55 89.00 8889.00 8970.60 -3115.00 5786.22 2340.00 -3115.00 13.00 -87.56G 0.33 -13.00 5972379.67 587354.17 N 70.33438066 W 149.29132982 End Cry 13679.58 90.64 86.99 8888.84 8970.44 -3099.56 5801.67 2340.54 -3099.56 13.00 O.OOG 0.55 -12.99 5972380.40 587369.60 N 70.33438216 W 149.29120457 Cry 6/100 14933.97 90.64 86.99 8874.93 8956.53 -1846.97 7055.99 2406.34 -1846.97 0.00 0.69G 0.00 0.00 5972461.30 588621.19 N 70.33456304 W 149.28104417 Target 8 14985.06 93.70 87.03 8873.00 8954.60 -1796.00 7107.03 2409.00 -1796.00 6.00 0.52G 6.00 0.07 5972464.57 588672.12 N 70.33457034 W 149.28063072 15000.00 94.60 87.04 8871.92 8953.52 -1781.12 7121.93 2409.77 -1781.12 6.00 0.52G 6.00 0.05 5972465.52 588687.00 N 70.33457246 W 149.28050998 End Cry 15023.73 96.02 87.05 8869.72 8951.32 -1757.52 7145.56 2410.99 -1757.52 6.00 O.OOG 6.00 0.05 5972467.02 588710.57 N 70.33457580 W 149.28031857 TO /4-1/2" Lnr 15183.18 96.02 87.05 8853.00 8934.60 -1599.16 7304.13 2419.15 -1599.16 0.00 O.OOG 0.00 0.00 5972477.09 588868.81 N 70.33459819 W 149.27903401 WellDesign Ver 3.1RT-SP3.03-HF4.00 Bld( d031rt-546) Plan V-02 (N-I)\Plan V-02 (N-I)\Plan V-02\V-02 (P8) Generated 5/4/2004 11 :50 AM Page 1 of 1 e- O' o <:? "2 = ~ II ( ) -¡¡¡ (.) (/) o ¡::: Schlumberger WElL FIELD Prudhoe Bay Unit - WOA STRUCTURE V-Pad V-02 (P8) MagnelicParametsrIi Model' 6GGM 2003 Surface LocaliOfl Lat' N701940.763 Lon: W1491557.824 NAD27 Alaska State Planes, Zone 04, US Feet Nurthing: 5970077.63ftUS GridCorw: +0.69110597' Easting 590496.88 flUS Scale Fact: 0.9999093033 MisceHaneous $101 PlanV-02(N-I) Plar1: V-02(P8) Dip 60.816' MagOec; +24.962' Date: May 31,2Q04 F$: 57566.5nT TVDRef: KB(81.60flaboveMSL) SNyDale: May04,2004 -3900 -3600 -3300 -3000 -2700 -2400 -2100 -1800 -1500 . 8400 , . . .n."....",,,.,,,,....,,..,,.,,'-,,,....,"..,,,,...,,,.....',,....,,....",...."....",....,....,,,....,"......... ,,,,.,,,,..,,,,,,,,,, _..",,,,,,,,,..., . . , .n........,........··..,....,,,......, "...,,,'..,,....,..........",. ,'.'",....,"...", 8400 8700 ''/' "n...,.,..."."" ,.....,..."'~..". ,..",...,,,.,..,,, ..."....,,}, ...,.....,...",,,^..,... ""'^^'! '''''''''''''''''''''^,' 8700 '''~, ''''''''''''''H'·.'''''' ..""~'^' 9000 ::~t.::¡;;.:;:::::J;~;;.::<:=:::!:::=.S;_L~1~;:.:::::::·:::1::·:·· ... ::::f·:::·:::::: .::)J:.:·::::i~;;,;;\;~~~~~~::,;J.~¡- ..'l:j ~~~~~F~~~: t:: ~~~~~~~: ~~::rj:~: ~~~~~:: ~;:~~::~~~:;~~~~~I~;: ~ :~~~;~:: ~m~:~f;;~;· ~:~~~:~: ~~~~~~~ ,; ~~:~r~::~ :~~~~~:- ~: :~~~~:: ~.: ~~~~:~:: ~~:~~: ~ '~~:~:~~' :~::~~:~ :~: :~:~~: ~ ,~:~~t ~~~;:sió~~: ~~~~ ~ "~~t:]".. .."f'...m..""..'I"".."...."m"...··"·L'~J' .."':~':~j\\~'~.~~" ...""."......"...." '...."'¡- ,,,,,.,,.. . ....." ·~~IJ'\~ 61:~~··'" ..."t" r - "." "....;"'... .,. ,.",,,. "~~':r:;'~~·;'~;;~~ : Target 6 : ~... Target 7 : : : r I : End Cry PO" PI > ~ : , ; ~ ~ Target 3 ' Target 2 nd Cry ~ e 9000 9300 . . . ~ ,,,...,.,..,,,,,..,,,...,......,.,....,,,,,..,,,...,,,,.,,,.,..,,...,,,·'·'..··'..'[·"·'...."·'''··''....'''·'··''''··1'·'..·''..··'·'·..''·"."... ,.......",..,........,.·'....0:;..................,. 9300 ..,,,,,,,..... ......."",...",,,.,,,.,,..,,.,....,. ,.,..·4,,··,·..··..·« "..,....."..,.."."." -3900 -3600 -3300 -3000 -2700 -2400 -2100 Vertical Section (ft) Azim = 90°, Scale = 1(in):300(ft) Origin = 0 N/-S, 0 E/-W -1800 -1500 2500 2000 ^ 1500 ^ ^ z 42' 0 0 'R ~ ~ II 1000 Q) TI CIJ CIJ v v v 500 WELL FIELD Prudhoe Bay Unit - WOA STRUCTURE V-Pad V-02 (P8) MagneticParametars Model: BGGM20Q3 $uñaooLocalion [.at N70194O.763 W1491557.824 NAD27 Alaska State Planes, Zone 04, US Feel Northing: 5910077.63ftUS GridCooV: +0.69110597" Easting" 590496.88ftUS Scale Fac:t: 0.9999093033 Mi!)(:(ll!anoous $10\ Plan V-02 (N.I) Plan: V..oZ(P8) Dip: 80.816' Mag De(:" +24.962" Data" May31,2004 FS: 57566.5nT -4000 -3500 -3000 -2500 -2000 -1500 o -4000 -3500 -3000 -2500 -2000 -1500 <<< W Scale'" 1 (in):500(ft) E >>> Schlumberger TVD Ref: KB (81.60 It above MSL) SrqDate: May04,2004 -1000 ~~ ~þ}- ! -1000 -500 o 2500 . 2000 1500 1000 . 500 o '\ Fault Bid -500 o . . Schlum berger Anticollision Report NO GLOBAL SCAN: Using user defined selection & scan criteria Interpolation Method: MD Interval: 25.00 ft Depth Range: 28.50 to 15183.18 ft Maximum Radius: 10000.00 ft Reference: Error Modet: Scan Method: Error Surface: Principal Plan & PLANNED PROGRAM ISCWSA Ellipse Trav Cylinder North Ellipse Survey Program for Definitive Wetlpath Date: 5/7/2001 Validated: No Planned From To Survey ft ft 28.50 1000.00 1000.00 7500.00 1000.00 15183.18 Versiou: 9 Toolcode Tool Name Planned: Plan #8 V2 Planned: Plan #8 V2 Planned: Plan #8 V2 GYD-GC-SS MWD+IFR:AK MWD+IFR+MS Gyrodata gyro single shots MWD + IFR [Alaska] MWD + IFR + Multi Station Summary PB V Pad Plan V-01 (S-N) Plan V-01 V10 Plan: PI 662.96 650.00 216.13 11.52 204.62 Pass: Major Risk PB V Pad Plan V-110 (N-V) Plan V-11 0 V1 Plan: PI 373.46 375.00 235.50 6.15 229.35 Pass: Major Risk PB V Pad Plan V-110 (N-V) Plan V-110PB1 V3 Plan: 373.46 375.00 235.50 6.15 229.35 Pass: Major Risk PB V Pad Plan V-112 (S-A) Plan V-112 V1 Plan: PI 536.53 525.00 217.18 9.15 208.03 Pass: Major Risk PB V Pad Plan V-118 (N-X) Plan V-118 V3 Plan: PI 348.66 350.00 265.43 5.40 260.03 Pass: Major Risk PB V Pad Plan V-203 (N-A) Plan V-203 VO Plan: V 425.47 425.00 120.83 8.22 112.61 Pass: Major Risk PB V Pad Plan V-204 (S-H) Plan V-204 OBd V1 Plan 1122.15 1125.00 35.60 17.69 17.91 Pass: Major Risk PB V Pad Plan V-204 (S-H) Plan V-204L 1 OBb V1 PI 1122.15 1125.00 35.60 17.69 17.91 Pass: Major Risk PB V Pad Plan V-204 (S-H) Plan V-204L2 OBa V1 PI 1122.15 1125.00 35.60 17.69 17.91 Pass: Major Risk PB V Pad Plan V-204 (S-H) Plan V-204L3 OA V1 Pia 1122.15 1125.00 35.60 17.69 17.91 Pass: Major Risk PB V Pad Plan V-205 (S-P) Plan V-205 V2 Plan: PI 532.51 525.00 232.64 9.09 223.55 Pass: Major Risk PB V Pad Plan V-206 (S-S) Plan V-206 V1 Plan: PI 454.25 450.00 263.03 7.63 255.39 Pass: Major Risk PB V Pad Plan V-21 0 (N-G) - w Plan V-21 0 V2 Plan: PI 473.99 475.00 29.67 7.61 22.06 Pass: Major Risk PB V Pad Plan V-211 (N-C) - w Plan V-211 V1 Plan: V 500.21 500.00 89.72 9.73 79.98 Pass: Major Risk PB V Pad Plan V-211 (S-Q) - s Plan V-211 V1 Plan: PI 774.83 775.00 226.20 13.91 212.29 Pass: Major Risk PB V Pad Plan V-212 (S-D) Plan V-212 VO Plan: V 2028.31 2025.00 118.13 31.23 86.90 Pass: Major Risk PB V Pad Plan V-213 (S-W) Plan V-213 V2 Plan: PI 916.66 925.00 287.16 15.73 271.42 Pass: Major Risk PB V Pad Plan V-213 (S-W) Plan V-213PB1 V2 Plan: 916.66 925.00 287.16 15.73 271.42 Pass: Major Risk PB V Pad Plan V-213 (S-W) Plan V-213PB2 V1 Plan: 916.66 925.00 287.16 15.73 271.42 Pass: Major Risk PB V Pad Plan V-214 (N-R) Plan V-214 V3 Plan: V 546.80 550.00 177 .27 9.80 167.47 Pass: Major Risk PB V Pad Plan V-216 (N-T) Plan V-216 V4 Plan: PI 397.74 400.00 206.11 6.39 199.72 Pass: Major Risk PB V Pad Plan V-2a06 (N-M) Plan V-2a06 VO Plan: V 473.11 475.00 101.11 9.25 91.86 Pass: Major Risk PB V Pad Plan V-3a06 (S-U) Plan V-3a06 V1 Plan: P 556.55 550.00 284.66 10.74 273.92 Pass: Major Risk PB V Pad V-03 V-03 V7 2977.84 2975.00 267.74 36.64 231.10 Pass: Major Risk PB V Pad V-100 V-100 V7 2901.37 2900.00 258.07 36.54 221.52 Pass: Major Risk PB V Pad V-101 V-101 V7 549.48 550.00 72.32 8.34 63.98 Pass: Major Risk PB V Pad V-102 V-102 V5 548.25 550.00 47.52 9.72 37.80 Pass: Major Risk PB V Pad V-103 V-103 V6 471.30 475.00 192.37 7.34 185.03 Pass: Major Risk PB V Pad V-104 V-104 V13 449.27 450.00 16.48 6.63 9.85 Pass: Major Risk PB V Pad V-105 V-105 V13 448.26 450.00 116.22 6.75 109.4 7 Pass: Major Risk PB V Pad V-106 V-106 V10 545.65 550.00 165.29 7.78 157.50 Pass: Major Risk PB V Pad V-107 V-107 V5 474.25 475.00 17.51 6.72 10.79 Pass: Major Risk PB V Pad V-108 V-108 V7 249.28 250.00 107.23 3.49 103.74 Pass: Major Risk PB V Pad V-109 V-109 V2 2024.70 2025.00 78.10 25.70 52.40 Pass: Major Risk PB V Pad V-109 V-109PB1 V5 2024.70 2025.00 78.10 25.70 52.40 Pass: Major Risk PB V Pad V-109 V-109PB2 V2 2024.70 2025.00 78.10 25.70 52.40 Pass: Major Risk PB V Pad V-111 V-111 V25 2848.66 2850.00 180.00 36.20 143.80 Pass: Major Risk PB V Pad V-111 V-111 PB1 V8 4473.39 4475.00 178.42 45.43 132.99 Pass: Major Risk PB V Pad V-111 V-111PB2 V2 4473.39 4475.00 178.42 45.43 132.99 Pass: Major Risk PB V Pad V-111 V-111PB3 V6 2848.66 2850.00 180.00 36.20 143.80 Pass: Major Risk PB V Pad V-113 V-113 V6 1130.14 1125.08 136.15 17.50 118.65 Pass: Major Risk PB V Pad V-114 V-114 V5 457.37 450.00 186.80 7.00 179.79 Pass: Major Risk PB V Pad V-114 V-114AV4 457.37 450.00 186.80 7.00 179.79 Pass: Major Risk PB V Pad V-114 V-114APB1 V4 457.37 450.00 186.80 7.00 179.79 Pass: Major Risk PB V Pad V-114 V-114APB2V2 457.37 450.00 186.80 7.00 179.79 Pass: Major Risk PB V Pad V-115 V-115V5 350.50 350.00 322.42 5.00 317.42 Pass: Major Risk PB V Pad V-115 V-115PB1 V4 350.50 350.00 322.42 5.00 317.42 Pass: Major Risk PB V Pad V-117 V-117V9 375.26 375.00 273.55 5.70 267.85 Pass: Major Risk PB V Pad V-117 V-117PB1 V6 375.26 375.00 273.55 5.70 267.85 Pass: Major Risk . . Schlumberger Anticollision Report Summary PB V Pad V-117 V-117PB2 V6 375.26 375.00 273.55 5.70 267.85 Pass: Major Risk PB V Pad V-119 V-119V13 1015.75 1000.00 134.77 15.82 118.94 Pass: Major Risk PB V Pad V-201 V-201 V8 472.43 475.00 29.70 6.98 22.72 Pass: Major Risk PB V Pad V-202 V-202 V9 799.96 800.00 42.33 12.94 29.40 Pass: Major Risk PB V Pad V-202 V-202L 1 V5 799.96 800.00 42.33 12.94 29.40 Pass: Major Risk PB V Pad V-202 V-202L2 V5 799.96 800.00 42.33 12.94 29.40 Pass: Major Risk Field: Prudhoe Bay Site: PB V Pad Well: Plan V-02 (N-I) Wellpath: Plan V-02 -0 ~~ 27 V-I02 (V-102) Plan V-210 (N-G) - was V-~~(WZW)) 22 -294 ··200 Plan V-211 (N-C) - was V-208 (Plan V-211) . ·····100 Plan V-211 (S-Q) - status unknown (Plan V-211) 11'1í\" V';¡H (N~XI'\ò'll V-..\t) V-108 (V-108) 1\ 90V-109 (V-109fB2) Plan V-3a06 (S-U) (Plan V-3a06) . 100 Plan V-206 (S-S) (Plan V-206) 200 -294 Travelling Cylinder Azimuth (TFO+AZI) [deg] vs Centre to Centre Separation [100ft/in] # . V-02 Proposed Completion I . // TREE: FMC 4-1/16" 5M WELLHEAD: FMC Gen 5 System 11", 5M csg.head wIT' mandrel hanger & packoff 11" x 11", 5M, tbg spool wI 11" x 4-1/2" tubing hanger, XO to 3-1/2" tbg 11" X 4-1/16" Adaptor Flange 3-1/2" 'X' Landing Nipple with 2.813" seal bore. I 2200' I 3-1/2" Camco Gas Lift Mandrels with handling pups installed. GAS LIFT MANDRELS rvÐ Size 9-5/8", 40#/ft, L-80, BTC I 2735' I ~ 10. / # 8 7 6 5 4 3 2 1 2000 1.5" 3300 1.5" 4200 1.5" 5100 1.5" 5800 1 .5" 6400 1.5" 7000 1.5" TBD (1 jt 1.5" above pkr) PRODUCTION TUBING DETAILS 3-1/2", 9.20 I bItt, L-80,IBTM DrifUID : 2.867" I 2.992" Valve Type DV DV DV DV DV DV DV DCK-1 Shear BAKER 5" x 7" Baker Liner Tie Back Sleeve ZXP Liner Top Packer 'HMC' Hydraulic Liner Hanger 3-1/2" 'X' Landing Nipple with 2.813" seal bore. 7" x 3-1/2" Baker 'Premier' Production Packer 3-1/2" 'X' Landing Nipple with 2.813" seal bore. 3-1/2" 'XN' Landing Nipple with 2.725" seal bore. I 9132' I 3-1/2" Mule-Shoe Guide spaced-out into 4-1/2" liner tie-back sleeve. I 9282' I 7",26 #/ft, L80, BTCM 4-1/2" 12.6 #Ift, L-80, IBTM I 15,183' I Date 5/4/04 Rev By Comments Jim Smith / Proposed Completion RA Tag RA Tag WELL: V-02 API NO: SO-029-XXXXX-OO TERRIE L HUBBLE BP EXPLORATION AK INC PO BOX 196612 MB 7-5 ANCHORAGE, AK 99519-6612 89-6/1252 102 "Mastercard Check" DATE OS·03-0c.¡ 6~?¿r~~~~~~;-/ ~C~$ ,00. ~ULLARS First ~onal Bank Alaska Anchorage, AK 99501 MEMO V,O(;( ~~ R4~ I: ~ 2 5 2000bOI:~~ ~~lllb 2 2 711' ~ SSb"· 0 ~O 2 . . . . TRANSMIT AL LETTER CHECK LIST CIRCLE APPROPRIATE LETTERIP ARAGRAPHS TO BE INCLUDED IN TRANSMITTAL LETTER WELL NAME PTD# Development Service CHECK WHAT APPLIES ADD~ONS (OPTIONS) MULTI LATERAL (If API number last two (2) digits are between 6.0-69) Exploration Stratigraphic "CLUE" Tbe permit is for a new well bore segment of existing weD . Permit No, API No. Production.sbould continue to be reported as a function ·of tbe original API number. stated above. HOLE In accordance witb 2.0 AAC 25..0.05(1), an records, data and logs acquired for tbe pilot bole must be clearly differentiated in botb name (name on permit plus PH) and API Dumber (5.0 7.0/8.0) from records, data and logs acquired for well (name on permit). PILOT (PH) SPACING EXCEPTION DRY DITCH SAMPLE The permit is approved subject ·to full compliance with 2.0 AAC 25..055. Approval to perforate and produce is contingent upon issuance of a conservation order approving a spacing exception. (Company Name) assumes tbe JiabiUty of any protest to the spacing . exception tbat may occur. AU dry ditch sample sets submitted to tbe Commission must be in no greater ·tban 3D' sample intervals from below tbe permafrost or from where samples are first caugbt and ].0' sample intervals tbrough target zones. . . o o Well bore seg Annular Disposal On Program DEV On/Off Shore Q Field & Pool PRUDHOE BAY, PRUDHOE OIL - 640150 Well Name: PRUDHOE BAY UN PBU V-02 PTD#: 2040770 Company BP EXPLORATION (ALASKA) INC nitial ClasslType DEV /1-0IL GeoArea Unit Administration 1 P~rlTJitfee attached . - - - - - - - - - - - - - - - - Y~s - - - - ~ - - - - - - - -- - - - - 2 Lease number .apRrORriate. . . . . . . . . . . . . . . - - - - - - . . . . . . . .Yes - - - - - - - - - - - - - - - - - - - - 3 .U.nique weltn.a!11~.a[1d oumb.er . . . . . . . . . . . . . . . . . . . . . . ........ Y~s - - - - - - - - - - - - - - - - - - - - - - - * - 4 Wen IQcat~d tn.a. d.efinedpool - - - - - - -- - - - - - - - - - - Y~s - - - - - - - - - - - - - 5 WelUQcated proper .distance from driJling unit boundary. . . . . . . Y~s - - -- - - - - - - - - 6 Wenlocat~d proper .distance from other wells. . . . . - - - - - . . . . . . . .Yes - - - - - - - - - - - 7 .S.u{fiçienLacreage.ayailable in.drilJiOQ unjL - - - - - - - Yes - - - - - - - . . . 8 If.deviated, .is.wellbore plaUncJuded . . . - - - - - - - - Yes - - - - - - - - - - - - - - - - - - - - - - - - - 9 .Operator onl}' affected party. . . . . . . . . . . . . . . . . . . Yes - - - - - - - - - - - - - - - 10 .Oper.ator bas.appropriate.bond inJorce . . . . . . . . . . . . . . . . . ........ Y~s - - - - - - - - - - - - - - - - - - - - - - - -- 11 P~rlTJit c.an be issu.ed witbout co.nservation order. - - - - - - .. Y~s - - - - - - - - - - - - - - - - - - - Appr Date 12 P~rlTJit ca[1 be issu.ed without ac:llTJinistratÎ\le.approval . . . . . . . . - - - - - - Y~s - - - - - - - - - - - - - - - - - - - -- RPC 5/6/2004 13 Can permit be approved before 15-day wait Yes 14 WeJI locat~d within area and strata .authorized by lojectioo Ord~r # (put 10# in.com!11.eots). (For .NA - - - - - - - - - - - - - - - - - - 15 All wel!s.wit!1inJl4.mite.area.of reyiew id~otlfied (Fonervjc.ewell only). . . . . . . . . . . . . . . .NA - - - - - - - - - - - - - - - - - - - - - - - -- 16 Pre-produced i[1jector; duration.of pre-production I~ss t!1an:3 months (For.service well only) . NA - - -- - - - - - - - - - - - - - 17 ACMP Fïndjngof Con.sißtency.h.as bee]l.Îssued. for. tbis project ...NA - - - - - - - - - - - - - - - - Engineering 18 .C.onductor striI1Q.PJov\ded . - - - - - - - - - - - - - - - -- · . . .Y~$ - - - - - - - - - - - - - - - - 19 .S.urfacecasing.protects all known USDWs . . .Y~s - - - - - - - - - - - - - - - 20 .CMT v.ol. ad~qu.ateto çirculate.on.cond.uctor. &. su.rf.Cßg . . . . . .Yes . . . Mequate excess. . - - - - - - 21 .CMT vol ad~qu.ateto tie-in long .stri[1g to.surf çsQ. . . . . . . . . . . . No - - -- - - - - - . . - - - - 22 .CMT will Coyera]l know.n .pro.ductiYe bori;!:on.s. . . . Yes - - - - - - - - - - - - - - - - - 23 Casing desig[1s adeç¡ua.te for C,.T~ B.&.Rermafr.ost Yes - - - - - - - - - - - - - - - - - 24 .Adequatetankage.oJ re.serve pit. . . . . . . . . . . . · . . .Y~$ · . . . . Nab.ors.9E$, . - - - - - - - - 25 If are-drill. has.a.tO-403 for abandonment be~n apPJoved . . . . NA . New welt . . . - - - - - - - - - - 26 .Mequate.IIIlellbore sepªratjonproposed. . . . . . . . . . . . . . . . . . . · . . .Y~s - - - - - - - - - - - - - - - - - - - - - - - -- 27 Ifdiverter req.uired, dQes it meet regulations. . . .. . - - - - - - Y~s - - - - - - - - - - - - - - - - - - - - - - - - - Appr Date 28 .Drilliog fluid. (lrogram schematic.&. eq.uip listadequate. . . . . . . .Y~s · . . . . Mªx MW.10c8ppg. . . . . . . . . WGA 5/6/2004 29 .BOPEs, do they meet. regulation. - - - - - - - - -- - - - - - - - - Y~s - - - - - - - - - - - - - - - - - - - - - 30 BOPE.press rating appropriate; .test to (put psig in.comments) ... Y~s · . . . . Test t.o .3500 RS¡.MS~ :30.75 psi.. 31 .C.hokemanifold cOlTJplies. w/APIR~-5:3 (May 64). . . - - - - - - - Yes 32 Work will occur withoutoperatjonsbutdown. . . . . - - - - - - - - Y~s - - - - - - - 33 Is presence. Qf H2S gas. probable. - - - - - - - - - - - - - - - -- No - - - - - 34 Mecba.nicalconditlo[1 o{ wells within .A.OR yerifiec:l (for.s.erviçe welJ only) ... .NA - - - - - - - - - Geology 35 Permit can be issu.ed wlo. hyd(ogen sulfide meas.u(es No - - - - - - 36 .DatapJeseoted on potential oveJRressur~ .zoneß. . NA - - - - - - - - - Appr Date 37 .S~ismicanalysjs. Qf sballow gas.zooes. . . . . . . . NA - - - - - - RPC 5/6/2004 38 .Seabed .conditioo survey -<if off-shore) . . . . . . . . NA - - - -- 39 . Conta.ct namelp!1Ol1eJorlllleekly progressreRorts [I ..NA - - - - - - - - - Geologic Date: Engineering Date Daœ ~y Commissioner Commissioner: DT~ 6/(/4- ./
