The URL can be used to link to this page

Home My WebLink About209-0957. 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 E-09C Recomplete to Brookian Hilcorp North Slope, LLC 3800 Centerpoint Dr, Suite 1400, Anchorage, AK 99503 209-095 50-029-20466-03-00 13217 Intermediate Liner Liner Liner Liner 8987 10181 852 1068 504 3765 9422 9-5/8" 7" 5" 3-1/2" x 3-3/16" 2-3/8" 7743 32 - 10213 9717 - 10569 9539 - 10607 10103 - 10607 9452 - 13217 32 - 8386 7983 - 8667 7838 - 8696 8298 - 8696 7767 - 8987 13178 4760 7020 7250 10530 11780 9422 6870 8160 8290 10160 11200 9036 - 9041 3-1/2" 9.2#, 4-1/2" 12.6# L-80 31 - 8943, 9409 - 9542 7441 - 7445 Surface 2638 13-3/8" 33 - 2671 33 - 2671 5380 2670 4-1/2" HES TNT Packer 9495, 7802 8777, 9495 7245, 7802 Torin Roschinger Operations Manager Finn Oestgaard finn.oestgaard@hilcorp.com 907-564-5026 PRUDHOE BAY, Prudhoe Oil, Brookian Undefined 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 0028304 31 - 7370, 7733 - 7840 9422 - 10600'MD 17-bbls 15.8-ppg Class G cement, 2000-psi final squeeze pressure. 69 Well Not Online 5759 4 1650 0 2020 0 324-707, 325-309 13b. Pools active after work:Prudhoe Oil, Brookian Undefined Oil 4-1/2" TIW HBBP Packer 8777, 7245 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 No SSSV Installed By Grace Christianson at 3:43 pm, Jul 18, 2025 Digitally signed by Torin Roschinger (4662) DN: cn=Torin Roschinger (4662) Date: 2025.07.18 12:17:12 - 08'00' Torin Roschinger (4662) DSR-7/21/25JJL 8/12/25 RBDMS JSB 072525 ACTIVITY DATE SUMMARY 4/20/2025 ***WELL S/I ON ARRIVAL*** (rwo capital) RAN 3.79" GAUGE RING TO 4-1/2" EVOTRIEVE AT 9,431' MD (all clear) EQUALIZED & PULLED 4-1/2" EVOTRIEVE AT 9,431' MD ***CONTINUED ON 4/21/25 WSR*** 4/21/2025 ***CONTINUED FROM 4/20/25 WSR*** (rwo capital) RAN 3.72" CENT, 2' x 1-7/8" STEM, 3.79" CENT & BULL NOSE TO DEPLOYMENT SLEEVE AT 9,452' MD ***WELL LEFT S/I ON DEPARTURE*** 4/27/2025 ***WELL S/I ON ARRIVAL*** MIRU HES ELINE PT 300 PSI LOW, 3000 PSI HIGH CCL TO CENTER RETAINER: 14.4' CCL STOP DEPTH: 9425.6' SET 4 1/2" POPPER STYLE-COMPOSITE RETAINER @ 9440' LOG CORRELATED TO SLB MEMORY LOG DATED: 20-NOV-2009 RDMO HES ELINE - JOB COMPLETE ***WELL S/I ON DEPARTURE*** 5/7/2025 T/I/O 0/25/0 (TFS unit 1 perform Injectivity step test) Performed an injectivity test of 5 bpm at 2450 psi. Final WHPS 0/75/0 5/13/2025 T/I/O=130/209/0, LRS unit 70,(RWO CAPITAL) Reservoir P&A. Pumped 5 bbls 60/40 down TBG for meth spear, Haliburton pumped 186 bbls fresh water. HES then pumped 20 bbls of 15.8 ppg Class G cement, followed by 2 bbls fresh water, Drop landing ball, followed by two wiper balls. Pumped 110 bbls diesel down TBG to displace cement. Reached max of 3,000 psi with 110 bbls of diesel away, we were 32.5 bbls short of full tubing displacement to cement retainer at 9,440' MD. 142.5 bbls of diesel was full tubing displacement. Estimated TOC is ~7,420' MD, the target was 9,440' MD. Pumped 1.1 BBLS DSL down the IA to bring IS pressure up to 2021 PSI. Pumped .25 BBLS Diesel down the TBG to pressure it up to 3523 PSI for CMIT-TxIA. 15 min test TBG/IA lost 28/4 PSI. WSL passed on this is good, bleed TBG/IA down to 2000 PSI. Got back 1 BBL. FWHP's= 1981/1961/0 DSO notified of well status and informed town wanted PCC to monitor pressures. 5/28/2025 LRS CTU #2 1.75" CT 0.156"WT HT-110 Job Objective: Mill Cement and Cem Retainer, Set Cem Retainer, P&A MIRU and make up 2-7/8" YJ milling BHA with 3.80" PDC mill. Tag cement at 7215' CTM. Begin milling at 2.2 bpm averaging 65 fph ROP. Utilize ARS for fluids management. ***Continue on 5-29-25 WSR*** Daily Report of Well Operations PBU E-09C Daily Report of Well Operations PBU E-09C 5/29/2025 LRS CTU #2 1.75"CT 0.156"WT HT-110 Job Objective: Mill Cement and Cem Retainer, Set Cem Retainer, P&A Continue milling at 2.2bpm utilizing the ARS for fluid management. Milled cement from 7506'ctm - 8650'ctm. POOH to check tools, reload fluids. After ~ 2500bbls of circulation, the ARS struggled to maintain adequate suction pressure / discharge rate, heavy solids accumulation in the Weir tank, offload to clean, trucking unable to keep up with demand. POOH to check tools, re-load fluids, clean the weir tank, troubleshoot the ARS. ***Continue on 5-30-25 WSR*** 5/30/2025 LRS CTU #2 1.75"CT 0.156"WT HT-110 Job Objective: Mill Cement and Cem Retainer, Set Cem Retainer, P&A Break down YJ milling BHA and remove cement cuttings from the weir tank. Perform weekly BOP test. Stab on with BOP's and function test. RIH with 2-7/8" YJ milling BHA with 3.80" PDC mill. Tag cement top 8658'ctm, CT pump tractor down for sheared coolant sensor, required regen, and sheared burst disk on triplex pump. Resume milling cement at 8658'ctm - 9250'ctm utilizing the ARS for fluids management. ***Continue on 5-31-25 WSR*** 5/31/2025 LRS CTU #2 1.75"CT 0.156"WT HT-110 Job Objective: Mill Cement and Cem Retainer, Set Cem Retainer, P&A Continue milling cement from 9250' CTm - 9458' CTM. Tag the cement retainer at 9458' CTM / 9440' MD. Pump final 15 BBL Powervis sweep and chase OOH at 80%. Swap to 3-1/8" venturi junk basket with 3.80" burnshoe (2.375" ID) and RBIH. Mill the retainer at 9468' CTM / 9440' MD, and push down to the deployment sleeve at 9452' MD. POOH and recover 4" rubber chunk, venturi screen packed with retainer pieces. Make up and RIH with 2-1/8" motor, 2-5/8" venturi junk basket, 2.75" burn shoe. Corrected depth at the green flag, Tag deployment sleeve at 9455'md, roll pump and work into deployment sleeve, tag debris at 9461.2'md, mill to 9462.9'md, stall motor and become bit stuck. Work stuck pipe, circulate 10bbls Powervis sweep down ct. spot powervis around milling tools and jar free, pooh circulating powervis to surface. ***Continue on 06-01-25 WSR*** 6/1/2025 LRS CTU #2 1.75"CT 0.156"WT HT-110 Job Objective: Mill Cement and Cem Retainer, Set Cem Retainer, P&A Continue POOH chasing powervis to surface, FP ct w/ diesel. B/D venturi/mule shoe and recover the core of the cement retainer, 2 chunks of plug, and cement debris. RIH with 2-5/8"venturi / 2.69" mule shoe, correct depth at green flag, tag deployment sleeve at 9452'md, try to work into sleeve dry and pumping, unable to work in, POOH. Add an indexing tool above the venturi and RBIH. Tie-in to the flag, bobble through the deployment sleeve at 9452'md, and venturi down to ~ 9460'md. POOH Recover 1 cup cement sheath 1"-2" pieces. RIH w/ YJ 1.69" milling assembly w/ 1.80" junk mill. Correct depth at green flag. Tag deployment sleeve at 9452'md, roll motor into sleeve, proceed to tag at 9459.7'md. Mill obstruction at 9459.1'. Hard milling from 9459.1'-9459.3'md, then proceed down to 9459.8. ***Continue on 6-2-25 WSR*** Daily Report of Well Operations PBU E-09C 6/2/2025 LRS CTU #2 1.75"CT 0.156"WT HT-110 Job Objective: Mill Cement and Cem Retainer, Set Cem Retainer, P&A Continue milling w/ YJ 1-11/16" milling assembly and 1.80" junk mill to 9472' md. Pump 2 x 5 bbl Powervis sweeps off bottom and chase OOH. Open circ sub w/ 7/16" ball, and circulate all powervis OOH. Injectivity test: 0.6 bpm @ 2430 psi w/ KCL. FP CT w/ diesel, FP tubing w/ diesel to 2500'. Recover 7/16" ball. RDMO and head to DS11-06. ***Job Incomplete / CTU #1 w/ 1.5" CT will be returning*** 6/4/2025 LRS CTU #1 - 1.50" Blue Coil Job Objective: FCO liner, Cement P&A MIRU CTU. ...Continued on WSR 6-5-25... 6/5/2025 LRS CTU #1 - 1.50" Blue Coil ***Cont. from WSR 6-4-25*** Job Objective: FCO liner, Cement P&A Complete Weekly BOP test. M/U YJ milling BHA w/1.80" 4 blade flat bottom junk mill. RIH and tag lightly at 9566. Start milling with frequent gel sweeps and clean out to 13150' CTMD without losing returns. Encountered motor work at 9616, 11540' and 12580'. Pump gel sweep off bottom and chase out of hole, ...Continued on WSR 6-6-25... 6/6/2025 LRS CTU #1 - 1.50" Blue Coil ***Cont. from WSR 6-5-25*** Job Objective: FCO liner, Cement P&A Chase gel out of liner and open circ sub to increase rate and bypass MM. Perform injectivity test - 2055 psi at 0.24 bpm, 2235 psi at 0.4 bpm, 2915 psi at 0.8 bpm. Make up cementing BHA with 1.75" BDJSN. RIH, drift down to 10,700'. SLB pump crew delayed due to cement job on rig, decision to POOH and head to LRS shop to replace injector hydraulic pumps. FP well to 2,000' with diesel (31 bbls) RDMO CTU ...Job incomplete.... 6/7/2025 LRS CTU #1 - 1.50" Blue Coil Job Objective: FCO liner, Cement P&A Leave LRS yard and travel to location. Begin rigging up CTU. ...Continued on WSR 6-8-25... 6/8/2025 LRS CTU #1 - 1.50" Blue Coil ***Cont. from WSR 6-7-25*** Job Objective: FCO liner, Cement P&A Rig up CTU. Make up cementing BHA with 1.75" BDJSN. Tag cement bridges at 9543 and 9700, unable to jet through. POOH M/U YJ milling BHA w/1.80" junk mill. RIH and dry tag at top of liner at 9453' CTMD. Clean out with no noticeable motor work down to 10900'. Pump gel sweep and chase out of hole. Pump additional gel sweep at top of liner and open circ sub for increased rate. ...Continued on WSR 6-9-25.... 6/9/2025 LRS CTU #1 - 1.50" Blue Coil Job Objective: FCO, Cement P&A POOH with 1.69" milling BHA with 1.77" mill, chasing gel sweep. Make up cementing BHA with 1.75" BDJSN and RIH. Tag liner top at the 9453' CTMD but able to enter while pumping. Drift to 10800' CTMD. Lay in 17bbls 15.8bbls class G cement from10600' up to 8650', Squeeze 2.3bbls down liner for a bottom of 11190' MD. Hold 2000psi squeeze pressure for 30 min w/47psi loss. bleed down WHP and clean out to 9400' TOC and chase OOH reciprocating across all jewelry. FP cap well with 38bbls diesel. Circulate drift ball at surface. RDMO ***Job Complete*** Daily Report of Well Operations PBU E-09C 6/12/2025 T/I/O= 154/72/1 AOGCC CMIT Tx IA PASSED to 3745 psi (AOGCC Witnessed by Inspector Guy Cook) Pumped 8.3 bbls to T/IA to achieve test pressure of 3798/3803 psi. T/IA lost 45/44 1st 15 mins and 17/14 2nd 15 mins for a total loss of 62/58 in 30 min test. Bled back 8.3 bbls of diesel. DSO notified upon departure, FWHP= 759/764/2 6/12/2025 ***WELL S/I ON ARRIVAL*** TAGGED CEMENT WITH 3.50" CENT, 2-1/2" SAMPLE BAILER @ 9,396' SLM AOGCC (GUY COOK) WITNESS TAGGED CEMENT WITH 3" SAMPLE BAILER @ 9,395' SLM LRS PERFORMED PASSING AOGCC (GUY COOK) WITNESSED CMIT T x IA TO 3,500psi RAN 3' x 1.75" STEM w/ 3.725" CENT TO TOC AT 9,395' SLM ***WELL LEFT S/I DEPARTURE, PAD-OP NOTIFIED OF STATUS*** 6/15/2025 ***WELL SI ON ARRIVAL*** (TUBING CUT) MIRU AK ELINE FUNCTION WLVS, PT 250/3000PSI LOG CORRELATED TO TUBING SUMMARY DATED 13-JAN-1995. TAG CEMENT PLUG AT 9422'. TUBING CUT AT 9409'. CCL STOP: 9400' CCL-CUT: 9' WELL LEFT SI ON DEPARTURE RDMO ***JOB COMPLETED** 6/19/2025 T/I/O= 249/315/0 (RWO CAPITAL) **Circ-Out** Pumped 100 bbls of 9.1 ppg Brine, followed by 102 bbls DeepClean down TBG, taking returns out IA to E-100 FL. Soak for 30 minutes. Pumped 787 bbls 9.1 ppg Brine followed by 134 bbls of Diesel to freeze protect TxIA (U-tube). FWHPs= 245/240/8 6/22/2025 T/I/O=0/0/0 Set 4" H TWC #MP4--10. Remove upper tree and install tree cap bonett onto master vavle. P/T tree cap against the TWC to 300 low, 5000 high (Passed) RDMO ***JOB COMPLETE*** 6/28/2025 Cont to move rig and spot same over well, scope up derrick and work on acceptance checklist 6/29/2025 Cont to MIRU, Accept rig at 03:30 hrs, displace well to 9.3 ppg brine, N/D tree, N/U BOPE. Test BOPE to 250 low/3500 high for 5 min each with 3 1/2" and 4 1/2" test jts per sundry perform Koomey draw down test - AOGCC waived witness (Kam StJohn) 6/30/2025 ***START E-LINE WSR*** MIRU HES REPAIR LOGGER RU RCBL FREE PIPE CALIBRAITON AT 1000' RIH TO 9100' REPEAT PASS AT 9100' TO 8900' RIH TO 9400' LOG TO 2000' TOC AT 2200' RD HES AND STANDBY FOR TCP CORRELATION ***CONTINUED ON 1-JUL-2025 WSR*** 6/30/2025 Test BOPE to 250 low/3500 high for 5 min each with 4 1/2" test jts per sundry - AOGCC waived witness (Kam StJohn), Pull hanger and L/D completion, R/U E-line and CBL log well, R/D E-line, Install Wear bushing Daily Report of Well Operations PBU E-09C 6/30/2025 T/I/O=0/0/0 Pull 4" CIW H TWC, stand by for rig to rock out fluid, set 4" CTS BPV, nipple down THA, cut & cap (2) 1/4" control lines, clean void, install CTS plug, install new BX-160, make up 4-1/4" TDS test sub to hanger lift threads9+ RH, test against CTS BPV 3500 psi, threads leaked, bleed off, tighten more w/ chain tongs, try test again, threads still leaking, bleed off, rig down test equip., function tubing hanger lock down screws one at a time, all functioned to 3-1/8" clear bowl or more, four of them were extremely tight, stand by for BOP nipple up, pull CTS plug & BPV, make up landing joint to hanger, back out lock down screws, pull hanger to rig floor, cut (2) 1/4" control lines below hanger & cap them, stand by for completion. 7/1/2025 Cont. single in hole, pump sweep and POOH and L/D BHA, P/U perf gun assy. and TIH, R/U E-line and correlate guns to depth 7/1/2025 ***CONTINUED FROM 30-JUN WSR*** CHECK EQUIPMENT RU HES RIH WITH TTTC CORRELATE TO TECLOG GR TOP OF PUP LOCATED AT 9091' SEND LOGS FOR CONFIRMATION ***CONTINUED ON 2-JUL WSR*** 7/2/2025 ***Cont. WSR From 7-1-25*** Confirm correlation, POOH and R/D E-Line Space out, drop ball and fire guns POOH L/D DP to 4644' Cut and slip drilling line L/D remaining DP and guns R/U TRS and RIH as per tally T/7168' ***Cont. WSR on 7-3-25*** 7/2/2025 ***CONTINUED FROM 1-JUL WSR*** STANDBY FOR TOWN CONFIRMATION TIE IN CONFIRMED BY TOWN POOH RDMO HES ***END WSR** 7/3/2025 ***Cont. WSR From 7-2-25*** Cont. running 3-1/2" completion and land out. R/U and circulate out gas through super choke. Reverse circ CI-brine Drop ball n rod, set packer and MIT-T/I/A N/D BOPE ***Cont. WSR on 7-4-25*** 7/4/2025 T/I/O=320/400/0. Post RWO. Set 4" "H" BPV #710 @105". LTT Passed. Made c/o with night shift. RD Temp SV and RU 4" CIW upper tree. Installed production piping and tree wotk platforms. Set floor kit and wellhouse. RU CIW lubricator and tooling to tree. PT upper tree against MV to 300/5000 psi. Passed. Pulled 4" TWC #710 @ 145". RD lubricator and installed tree cap. ***Job Complete*** Final WHP's 320/400/0. 7/4/2025 LRS 46. Assist I-Rig w/ Freeze Protect (RWO CAPITAL) Pumped 175 bbls Diesel into IA. Pad-Op notified upon LRS departure. Daily Report of Well Operations PBU E-09C 7/4/2025 T/I/O=0/0/0 Msake up hanger to tubing string, run in hole, confirm landed through IA valve, run in upper LDS, torque to 500 ft/lbs, stand by for rig to circ out gas, set 4" H TWC, stand by for BOP nipple down, clean hanger neck, ring groove, TWC profile, install new BX- 160, grease hanger neck OD, pick up THA, inspect ID & DX seal that was still in there from last well, make up THA to tubing head, stand by for nippole up w/ Sweeney, test hanger void 500 psi/5 min., 5000 psi/10 min., good tests, bleed off, stand by for rig to tree test, good test, bleed off psi, pull TWC, RDMO. 7/4/2025 ***Cont. WSR from 7-3-25*** N/U Tree and adapter PT void and tree to 5000 psi Pull TWC and freeze protect well Secure cellar and RDMO ***Final WSR work complete*** 7/7/2025 ***WELL S/I ON ARRIVAL*** SET BAITED 2" GUTTED JD ASSEMBLY ON B&R AT 8,833' MD PULLED DGLV FROM ST #3 @ 6,173' MD PULLED SOV FROM ST #4 @ 3,383' MD SET RK-DGLV'S IN ST #4 (3,383' MD) & ST #3 (6,173' MD) PULLED BAITED B&R & RHC BODY FROM 8,833' MD ***WELL S/I ON DEPARTURE*** 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 E-09C Hilcorp North Slope, LLC 3800 Centerpoint Dr, Suite 1400, Anchorage, AK 99503 209-095 50-029-20466-03-00 13217 Intermediate Liner Liner Liner Liner 8987 10181 852 1068 504 3765 9422 9-5/8" 7" 5" 3-1/2" x 3-3/16" 2-3/8" 7743 32 - 10213 9717 - 10569 9539 - 10607 10103 - 10607 9452 - 13217 32 - 8386 7983 - 8667 7838 - 8696 8298 - 8696 7767 - 8987 13178 4760 7020 7250 10530 11780 9422 6870 8160 8290 10160 11200 9036 - 9041 3-1/2" 9.2#, 4-1/2" 12.6# L-80 31 - 8943, 9409 - 9542 7441 - 7445 Surface 2638 13-3/8" 33 - 2671 33 - 2671 5380 2670 4-1/2" HES TNT Packer 9495, 7802 8777, 9495 7245, 7802 Torin Roschinger Operations Manager Leif Knatterud leif.knatterud@hilcorp.com 9075644667 PRUDHOE BAY 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 0028304 31 - 7369, 7733 - 7840 Perforations 9036 - 9041 See attached report 69 1326 5759 6123 4 168 1650 1450 2050 1000 325-426 13b. Pools active after work:Brookian Undefined Oil Pool 4-1/2" TIW HBBP Packer 8777, 7245 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 1:34 pm, Sep 03, 2025 Digitally signed by Torin Roschinger (4662) DN: cn=Torin Roschinger (4662) Date: 2025.09.03 12:16:26 - 08'00' Torin Roschinger (4662) CDW 09/03/2025 J.Lau 11/4/25 DSR-9/11/25 RBDMS JSB 091225 ACTIVITY DATE SUMMARY 8/6/2025 ***WELL S/I ON ARRIVAL*** RAN 3-1/2" BRUSH & 2.79" GAUGE RING TO 8,883' MD RAN 2.70" CENTRALIZER & TUBING END LOCATOR FOR DEPTH CONTROL. TUBING TAIL @ 8,922' SLM/ 8,943' MD SET 3-1/2" SLIP STOP CATCHER @ 8,906' SLM PULLED RK-DGLV FROM ST #1 @ 8,884' MD SET RK-SPMG (CONNECT TIME 13:27) IN ST#1 @ 8,884' MD PULLED 3-1/2" SLIP STOP FROM 8,906' SLM ***WELL S/I ON DEPARTURE*** 8/9/2025 DAILY SUMMARY MIRU remaining SLB Frac Equipment & Treating Iron, Oil States Tree Saver, LRS backside pump. Pressure test treating lines and tree saver to 8500 psi. Function test pressure safety systems. LRS pressure up IA to 3100 psi. Pump DeFit with 20 bbl 30# linear gel at 10 bpm. Saw Break over at ~3400 psi. SD & monitor closure. 6 min closure time. Pump Steprate/ Step down Test per OE design stepping up to 24 bpm w/ Max Pressure 5660 psi. SD monitor closure. 7 closure time. LRS FP well with 23 bbl diesel. Total 155 BBLS of 30# linear Gell pumped ***Job In Progress *** 8/9/2025 LRS 72 Assist SLB Frac (FRACTURING). Held 3000 psi on the IA during the data frac. Freeze protected the TBG with 20 bbls of diesel. 8/10/2025 LRS 46. Assist Frac T/I/O = 700/70/0 (FRACTURING) Pump 11.5 bbls 15% HCL acid down TBG followed by 4.6 bbls FW for flush. Frac in control of well upon departure. Pad op notified upon completion. FWHPs = 3000/3000/0 8/10/2025 LRS 72 Assist frac with holding backside pressure (FRACTURING). Freeze protect the TBG with 23 bbls of diesel. Final T/I/O= 1806/261/0 Daily Report of Well Operations PBU E-09C Daily Report of Well Operations PBU E-09C 8/10/2025 DAILY SUMMARY SLB Frac - Job ScopeHydraulic Frac: Prime up, PT treating lines. Test Kick outs. RU Acid shower trailer to LRS. Verify IA Pump & OA Bleed line. Pump Hydraulic Frac: Open well with 616 Initial WHP. Pump 12 bbls 15% HCL Followed by Frac. Pad 61 bbls 10# Linear Gel at 15 BPM. Pad 200 bbls 30# Linear Gel @ 13-27 bpm. Max 5560 psi , Pad XL 205 bbls at 30 bpm, Max psi 5686 psi. Total 466 bbls Pad. Pump Frac at 30 bpm. Stage from 0.5- 6.5 PPA, Max Treating Psi-6585 psi. Flush, 89 bbl 30# linear gel. Hard shut down performed. Final surface shut in pressure 4794 psi. ISIP-1760 psi Monitor closure. LRS Freeze protect with 23 bbl diesel. Shut in well. Final pressure before shut in 1630 psi. SLB clean up lines and start Rig down. Well support assist Tress saver with removal of OSES Tree saver. Well secure and Pad op notified of well head configuration. RDMO Frac Equipment. 2160 bbls of slurry pumped. 224,580 lbs 20/40 Prop behind pipe. 0.5 ppg 20/40 CarboLite, 51 bbl 30# XL. 1.0 ppg 20/40 CarboLite, 104 bbl 30# XL. 2.0 ppg 20/40 CarboLite, 122 bbl 30# XL. 3.0 ppg 20/40 CarboLite, 217 bbl 30# XL. 3.5 ppg 20/40 CarboLite, 139 bbl 30# XL. 4.0 ppg 20/40 CarboLite, 147 bbl 30# XL. 4.5 ppg 20/40 CarboLite, 122 bbl 30# XL. 5.0 ppg 20/40 CarboLite, 177 bbl 30# XL. 5.5 ppg 20/40 CarboLite, 247 bbl 30# XL. 6.0 ppg 20/40 CarboLite, 175 bbl 30# XL. 6.5 ppg 20/40 CarboLite, 80 bbl 30# XL. ***Job Complete *** 8/12/2025 ***WELL S/I ON ARRIVAL*** MADE MULTIPLE 3-1/2" BRUSH AND G-RING RUNS TO 8925'SLM ***CONTINUE ON 8/13/2025*** 8/13/2025 ***CONTINUE FROM 8/12/2025*** SET 3-1/2" X - CATCHER @8754'MD PULL 1.5" DGLV FROM STA 3 @6173'MD PULL 1.5" DGLV FROM STA 4 @ 3383' MD SET 1.5" GLV IN STA 4 @ 3383' MD SET 1.5" GLV IN STA 3 @ 6173' MD PULL X CATCHER FROM 8754' MD SET SLIP STOP CATCHER @ 8902' MD PULLED AND RESET IN KIND NEW1.5" SPG FROM STA 1 @ 8833' MD. PULLED SS-CATCHER FROM 8902' MD, JOB COMPLETE RDMO. **** WELL LEFT S/I ON DEPARTURE **** 8/14/2025 **** WSR CONT FROM 8/13/25 **** UNIT# 60 R/D, TRAVEL FROM E-PAD TO WLB AND SHOP. **** END TICKET *** 8/14/2025 LRS WTU # 6 Begin WSR on 08/14/25 IL E-09/E-34. New well POP, Unit move, RU, PT Continue WSR on 08/15/25 8/15/2025 LRS WTU # 6 Continue WSR from 08/14/25 IL E-09/OL E-34. New well POP Continue WSR on 08/16/25 8/16/2025 LRS WTU # 6 Continue WSR from 08/15/25 IL E-09/OL E-34. New Well, Continue Flowing Continue WSR on 08/17/25 -6585 Daily Report of Well Operations PBU E-09C 8/17/2025 LRS WTU # 6 Continue WSR from 08/16/25 IL E-09/OL E-34. New Well, Continue Flowing, 8 Hr PBWT Continue WSR on 08/18/25 8/18/2025 LRS WTU # 6 Continue WSR from 08/17/25 IL E-09/OL E-34. New Well, Continue Flowing, Continue WSR on 08/19/25 8/19/2025 LRS WTU # 6 Continue WSR from 08/18/25 IL E-09/OL E-34. New Well, Continue Flowing, Continue WSR on 08/20/25 8/20/2025 LRS WTU # 6 Continue WSR from 08/19/25 IL E-09/OL E-34. New Well, Continue Flowing, 8 hr PBWT, Continue WSR on 08/21/25 8/21/2025 LRS WTU # 6 Continue WSR from 08/20/25 IL E-09/OL E-34. New Well, Continue Flowing Begin 8 Hr PBWT, Continue WSR on 08/22/25 8/22/2025 LRS WTU # 6 Continue WSR from 08/21/25 IL E-09/OL E-34. New Well, Continue Flowing, Finish 8 Hr PBWT, RDMO, END WSR on 08/22/25 8/23/2025 Freeze Protect Flowline (FRACTURING) Pumped 6 BBLS 60/40 to Freeze Protect the flowline to the platform from well E-34. Pumped 9 BBLS 60/40 and 108 BBLS down the Flowline on E-10 for Freeze Protect. FracCAT Treatment Report Well : E-09 C Field : Prudhoe Bay Formation : Brookian Well Location : Greater Prudhoe Bay State : Alaska Country : United States Prepared for Client : Hilcorp Client Rep : Leif Knatterud Date Prepared : 08/10/25 Prepared by Name : Alena Lutskaia Division : Schlumberger Phone : 630-780-0058 Pressure (All Zones) Initial Wellhead Pressure on Day 1 (psi)576 SRT Shut in Pressure(psi)3,761 Initial Wellhead Pressure on Day 2 (psi)616 SRT Surface ISIP (psi)3,315 Final Surface Shut in Pressure (psi)4,794 Maximum Treating Pressure (psi)6,585 Final Surface ISIP (psi)1,760 Treatment Totals (All Zones As Per FracCAT) Total Slurry Pumped (Water+Adds+Proppant) (bbl)2,315.3 Total 20/40 CarboLite Proppant Pumped per Load Tickets (lb) 224,580 Total YF130ST Past Wellhead (bbl)1,556.8 Total Proppant in Formation (lb)224,580 Total WF130 Past Wellhead (bbl) 445.0 Total Freeze Protect Past Wellhead (bbl) Pumped by LRS 23.0 Total WF110 Past Wellhead (bbl)60.4 Total Water Past Wellhead (bbl)5.0 Total 15% HCl Past Wellhead (bbl)12.0 Chemical Additives Mixed / Used Past WH Chemical Additives Mixed / Used Past WH J580 (lb)3,009 2,859 M275 (lb)36.0 33.9 F103 (gal)86 86 J218 (lbs)55 55 L065 (gal)89 89 J475 (lb)468 468 J532 (gal)196 196 J134 (lb)18 0 D206 (gal)1.0 1.0 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 est imate 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 whe reby 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: E-09 C Formation: Brookian District: AKA Country: United States Day 1 Summary On August 09, 2025 SLB performed a DFIT and SRT tests on E-09C. The day started with the crew arriving on location at 6am. Equipment was started and allowed to warm up. Then, SLB performed the pressure tests, bucket checks on all liquid additive systems and the dry add feeders on the POD. The safety meeting was held at 13:10, and gel was mixed after before meeting. Gel viscosity was confirmed and the treatment began at 13:37. The day’s schedule consisted of pumping a DFIT followed by 30 min SD and SRT followed by 30 min SD. Then Data was analyzed, and ReDesign was provided to SLB with some changes. Back at the base SLB operators mixed the 504 gallons of 15% HCl. The below graphs and tables will summarize the day’s activities: 13:33:51 13:47:11 14:00:31 14:13:51 14:27:11 14:40:31 14:53:51 15:07:11 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 Tr. Press - psi0 5 10 15 20 25 30 Slurry Rate - bbl/min0 2 4 6 8 10 12 14 Prop Con - PPATreating Pressure Annulus Pressure BHP Slurry Rate Prop Con BH Prop Con PRC Plot Hilcorp E-09C (DFIT, SRT) 08/09/2025 DFIT SRT Open well Client: Hilcorp Well: E-09 C Formation: Brookian District: AKA 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 DFIT 20.8 8.2 3.3 WF130 874 0 0 0 2 SRT 134.4 17.2 11.4 WF130 5643 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 DFIT 8.2 10.0 3475 4047 574 2 SRT 17.2 25.0 4452 5677 753 As Measured Totals Slurry (bbl) Pump Time (min) Clean Fluid (gal) Proppant (lb) 155.2 14.8 6517 0 Average Treating Pressure:4323 psi Maximum Treating Pressure:5677 psi Minimum Treating Pressure:574 psi Average Injection Rate:16.0 bbl/min Maximum Injection Rate:25.0 bbl/min Average Horsepower:1820.6 hhp Maximum Horsepower:3455.3 hhp Maximum Prop Concentration:0.0 PPA Client: Hilcorp Well: E-09 C Formation: Brookian District: AKA 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 12:25:13 Priming Pumps 55 13 0.0 5.4 0.0 2 12:44:23 Low Pressure Test 2422 14 0.0 0.0 0.0 3 12:52:32 High Pressure Test 8553 15 0.0 0.0 0.0 4 12:56:21 Good Test 8494 14 0.0 0.0 0.0 5 13:01:50 Good Check Valve Test 4951 14 0.0 0.0 0.0 6 13:03:00 Mixing 30# Gel 549 14 0.0 0.0 0.0 7 13:05:00 Safety Meeting 549 14 0.0 0.0 0.0 8 13:32:35 Bumping up IA Pressure 571 1699 0.0 0.0 0.0 9 13:32:37 Radio Check 571 1699 0.0 0.0 0.0 10 13:36:37 Open Well 563 1680 0.0 0.0 0.0 11 13:37:39 Start DFIT Automatically 572 1676 0.0 0.0 0.0 12 13:37:39 Start DF Automatically 572 1676 0.0 0.0 0.0 13 13:37:39 Start Stage Automatically 572 1676 0.0 0.0 0.0 14 13:37:44 Started Pumping 572 1676 0.0 0.0 0.0 15 13:41:13 Stopped Pumping 1877 2586 20.8 3.2 0.0 16 14:16:00 Radio Check 759 2278 20.8 0.0 0.0 17 14:17:53 Started Pumping 752 2278 20.8 0.0 0.0 18 14:17:55 Start Step Rate Test Manually 753 2278 20.8 0.0 0.0 19 14:25:35 Stage at Perfs: DFIT 4712 3090 94.2 22.4 0.0 20 14:26:27 Stage at Perfs: Step Rate Test 5607 3083 115.2 25.0 0.0 21 14:29:29 Stopped Pumping 3085 3084 155.2 1.3 0.0 22 14:29:55 Monitor Pressure Decline 1896 3068 155.2 0.0 0.0 23 15:13:35 Bleeding down IA 782 2809 155.2 0.0 0.0 24 15:17:10 Closed valve on 4" manifold 741 1332 155.2 0.0 0.0 25 15:19:25 Bleed Off Pumps 728 707 155.2 27.2 0.0 26 15:19:37 Fanning Out Pumps 726 662 155.2 27.2 0.0 27 15:36:55 LRS Will Pump Freeze Protect 701 287 155.2 0.0 0.0 3084 3083 Client: Hilcorp Well: E-09 C Formation: Brookian District: AKA Country: United States Day 2 Summary On August 10, 2025 SLB performed a hydraulic proppant fracturing treatment on E-09C. The day started with the crew arriving on location at 6 am. Equipment was started and allowed to warm up. Crew primed up pump and Pressure tested them. At 9:33 the well was open and then acid was pumped at 9:35 by LRS, which followed by 5bbl of Water Flush and SD. The Main Frac Job started with LG PAD 10# and LG PAD 30#, once confirmed the response of the formation to the 30# gel then staged over to XL PAD. Every PPA step was extended in order to see the pressure behavior once each PPA hit the perforation. While pumping 1.0 PPA step there was an issue with holding constant concentration due to wet proppant. Treating pressure was increasing at every proppant getting into formation. The max PPA that was placed into the formation was 6.5 PPA. Once finished pumping flush then hard SD was performed with ISIP = 1,760 psi. A total of 224,580 pounds of proppant were pumped in 2,160.1 bbl of slurry. 224,580 pounds of proppant were placed into formation. Well was freeze protected by LRS with 23bbl of FP. The below graphs and tables will summarize the day’s activities: 09:28:48 09:45:28 10:02:08 10:18:48 10:35:28 10:52:08 11:08:48 11:25:28 11:42:08 11:58:48 12:15:28 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 7000 Tr. Press - psi0 5 10 15 20 25 30 35 Slurry Rate - bbl/min0 1 2 3 4 5 6 7 8 9 10 Prop Con - PPATreating Pressure Annulus Pressure BHP Slurry Rate Prop Con BH Prop Con PRC Plot Hilcorp E-09C Prop Frac Job 08/10/2025 Pumping Acid + Water Flush Open well LRS pumping FP Wet sand Client: Hilcorp Well: E-09 C Formation: Brookian District: AKA 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 Acid 15% HCl 12 1 12 15% HCl 504 0 0 0 2 Water Fush 5 1 5 Water 210 0 0 0 3 PAD 10# LG 60.7 12.9 5.3 WF110 2537 0 0 0 4 PAD 30# LG 200 27.8 7.4 WF130 8390 0 0 0 5 PAD XL 205.2 30.1 6.8 YF130ST 8620 0 0 0 6 0.5 PPA 51.1 29.9 1.7 YF130ST 2112 CarboLite 20/40 0.6 0.4 792 7 1.0 PPA 104.4 30 3.5 YF130ST 4214 CarboLite 20/40 1.3 0.9 3895 8 2.0 PPA 122.7 30 4.1 YF130ST 4747 CarboLite 20/40 2.1 1.9 9237 9 3.0 PPA 217.8 30.1 7.2 YF130ST 8087 CarboLite 20/40 3.1 3 24060 10 3.5 PPA 139.6 30.1 4.6 YF130ST 5083 CarboLite 20/40 3.6 3.5 17692 11 4.0 PPA 147.7 30.1 4.9 YF130ST 5276 CarboLite 20/40 4.1 4 21001 12 4.5 PPA 122.7 30.2 4.1 YF130ST 4303 CarboLite 20/40 4.6 4.5 19276 13 5.0 PPA 177.9 30.1 5.9 YF130ST 6125 CarboLite 20/40 5.1 5 30550 14 5.5 PPA 247.4 30 8.3 YF130ST 8360 CarboLite 20/40 5.6 5.5 46022 15 6.0 PPA 175.4 30.1 5.8 YF130ST 5827 CarboLite 20/40 6.1 6 34936 16 6.5 PPA 80.4 30 2.7 YF130ST 2633 CarboLite 20/40 6.6 6.4 17119 17 LG Flush 90.1 29.9 3 WF130 3782 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 Acid 15% HCl 1.0 1.0 3621 3805 687 2 Water Fush 1.0 1.0 3608 3617 3594 3 PAD 10# LG 12.9 15.2 5975 6585 1541 4 PAD 30# LG 27.8 30.2 5560 6242 4631 5 PAD XL 30.1 30.5 5479 5685 5248 6 0.5 PPA 29.9 30.1 5637 5654 5606 7 1.0 PPA 30.0 30.4 5383 5598 5224 8 2.0 PPA 30.0 30.1 5320 5503 5169 9 3.0 PPA 30.1 30.3 5235 5336 5103 10 3.5 PPA 30.1 30.3 5157 5261 5100 11 4.0 PPA 30.1 30.3 4866 5110 4599 12 4.5 PPA 30.2 30.4 4491 4597 4389 13 5.0 PPA 30.1 30.4 4338 4517 4174 14 5.5 PPA 30.0 30.2 4639 5000 4265 15 6.0 PPA 30.1 30.3 4300 4469 4214 16 6.5 PPA 30.0 30.1 4670 5002 4469 17 LG Flush 29.9 30.5 5055 5239 1505 6585 Client: Hilcorp Well: E-09 C Formation: Brookian District: AKA Country: United States As Measured Totals Slurry (bbl) Pump Time (min) Clean Fluid (gal) Proppant (lb) 2160.1 75.4 1924.0 224580 Average Treating Pressure:5009 psi Maximum Treating Pressure:6585 psi Minimum Treating Pressure:1505 psi Average Injection Rate:29.4 bbl/min Maximum Injection Rate:30.5 bbl/min Average Horsepower:3592.4 hhp Maximum Horsepower:4265.7 hhp Maximum Prop Concentration:6.6 PPA Job Messages Message Log #Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop. Conc. (PPA) 1 7:37:24 Priming Pumps 52 3 0.0 5.4 0.0 2 8:04:35 Low Pressure Test 1237 2 0.0 0.0 0.0 3 8:07:10 Mid Pressure Test 5142 2 0.0 0.0 0.0 4 8:09:22 High Pressure Test 8502 1 0.0 0.0 0.0 5 8:13:12 Test good 3296 1 0.0 0.0 0.0 6 8:14:09 Mixing 50bbl of 10# gel 1041 1 0.0 0.0 0.0 7 8:43:49 10#gel 71degF 6cP 1019 74 0.0 0.0 0.0 8 8:44:10 30#gel 78degF 27cP 1019 74 0.0 0.0 0.0 9 8:52:50 Safety Meeting 1011 72 0.0 0.0 0.0 10 9:28:24 Radio Check 993 66 0.0 0.0 0.0 11 9:30:04 Priming up Acid Tube to LRS pump 992 66 0.0 0.0 0.0 12 9:30:18 Checking eye-wash station 992 66 0.0 0.0 0.0 13 9:33:05 Open Well 616 65 0.0 0.0 0.0 14 9:35:51 LRS Started pumping Acid 870 176 0.0 0.0 0.0 15 9:36:04 Bumping up IA pressure 1047 392 0.0 0.0 0.0 16 9:37:05 pumping Acid @ 1bpm 1851 2197 0.0 0.0 0.0 17 9:39:16 corrected 5K sensor settings 3626 2467 0.0 0.0 0.0 18 9:47:33 Finish pumping 12bbl of 15%HCl 3635 3014 0.0 0.0 0.0 19 9:47:46 Swapped to water to Flush lines 3632 3016 0.0 0.0 0.0 20 9:52:29 LRS finished pumping 3328 3018 0.0 0.0 0.0 21 9:57:24 Radio Check 1688 2980 0.0 0.0 0.0 22 9:59:01 Start PAD 10#LG Automatically 1553 2976 0.0 0.0 0.0 23 9:59:01 Start PropFrac Automatically 1553 2976 0.0 0.0 0.0 24 9:59:01 Start MJ Automatically 1553 2976 0.0 0.0 0.0 25 9:59:07 Started Pumping 1548 2976 0.0 0.0 0.0 26 10:04:40 Start PAD 30# LG Manually 5997 3162 60.7 15.3 0.0 27 10:06:27 Stage at Perfs: PAD 10#LG 5128 3192 94.5 24.0 0.0 28 10:08:33 Stage at Perfs: PAD 30# LG 5778 3186 154.9 30.2 0.0 29 10:12:05 Start PAD XL Automatically 5361 3183 261.0 30.2 0.0 30 10:15:12 Stage at Perfs: PAD XL 5427 3182 355.3 30.0 0.0 31 10:18:53 Start 0.5 PPA Manually 5653 3181 465.9 30.1 0.0 32 10:18:53 Started Pumping Prop 5653 3181 465.9 30.1 0.0 33 10:20:36 Start 1 PPA Automatically 5582 3182 517.2 30.1 0.5 34 10:22:02 Stage at Perfs: 0.5 PPA 5409 3184 560.1 30.1 1.2 6585 5997 8 3162 Client: Hilcorp Well: E-09 C Formation: Brookian District: AKA Country: United States Message Log #Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop. Conc. (PPA) 35 10:23:44 Stage at Perfs: 1 PPA 5236 3180 611.3 30.1 1.0 36 10:24:05 Start 2 PPA Automatically 5279 3179 621.8 30.0 1.0 37 10:24:22 Extended 2 PPA step 5317 3177 630.3 30.1 1.8 38 10:27:14 Stage at Perfs: 2 PPA 5203 3183 716.2 29.9 2.0 39 10:28:10 Start 3 PPA Manually 5227 3184 744.2 30.0 2.0 40 10:28:19 Extended 3 PPA step 5226 3182 748.7 29.8 2.2 41 10:31:18 Stage at Perfs: 3 PPA 5101 3180 838.5 30.2 3.0 42 10:40:02 Start 4 PPA Manually 5105 3180 1101.6 30.3 3.5 43 10:40:05 Extended 4 PPA step 5101 3182 1103.1 30.2 3.5 44 10:43:10 Stage at Perfs: 4 PPA 4707 3177 1196.1 30.1 4.0 45 10:44:56 Start 4.5 PPA Manually 4594 3183 1249.3 30.1 4.0 46 10:44:59 Extended 4.5 PPA step 4607 3182 1250.8 30.0 4.1 47 10:48:04 Stage at Perfs: 4.5 PPA 4415 3178 1343.7 30.1 4.4 48 10:49:00 Start 5 PPA Manually 4436 3181 1372.0 30.2 4.6 49 10:49:04 Extended 5 PPA step 4447 3181 1374.0 30.2 4.6 50 10:52:08 Stage at Perfs: 5 PPA 4172 3175 1466.4 30.2 5.1 51 10:54:55 Start 5.5 PPA Manually 4409 3179 1549.9 30.0 5.1 52 10:54:57 Extended 5.5 PPA step 4414 3179 1550.9 30.2 5.1 53 10:58:04 Stage at Perfs: 5.5 PPA 4620 3179 1644.4 30.0 5.4 54 11:03:10 Start 6 PPA Manually 4235 3175 1797.2 30.2 5.5 55 11:03:12 Extended 6 PPA step 4244 3175 1798.2 30.1 5.5 56 11:06:18 Stage at Perfs: 6 PPA 4316 3181 1891.4 29.9 6.0 57 11:09:00 Start 6.5 PPA Manually 4475 3177 1972.6 30.0 6.1 58 11:11:41 Start LG Flush Manually 5095 3177 2053.1 30.1 3.8 59 11:11:44 Stopped Pumping Prop 5146 3176 2054.6 30.2 3.1 60 11:12:09 Stage at Perfs: 6.5 PPA 5102 3175 2067.2 29.8 0.0 61 11:14:43 Stopped Pumping 1384 3116 2143.2 19.0 0.0 62 11:52:59 LRS Bleeding down IA 1596 541 2143.2 0.0 0.0 63 12:13:33 LRS Started pumping Freeze Protect @ 0.4bpm 1613 510 2143.2 0.0 0.0 64 12:13:42 LRS finished pumping 23 bbl of Freeze Protect 1757 292 2143.2 0.0 0.0 65 13:14:42 Close Well 0 277 2143.2 0.0 0.0 66 13:20:12 Emptied PCM to the Bleed off tank 0 271 2143.2 0.0 0.0 67 13:25:12 Fanning out pumps 0 268 2143.2 0.0 0.0 Hydraulic Fracturing Fluid Product Component Information Disclosure Job Start Date: 08/09/2025 Job End Date: 08/10/2025 State: Alaska County: Beechey Point API Number: 50-029-20466-03-00 Operator Name: Hilcorp Alaska, LLC Well Name and Number: E-09C Latitude: 70.342717 Longitude: -148.668563 Datum: NAD83 Federal Well: NO Indian Well: NO True Vertical Depth: 7440.84 Total Base Water Volume (gal)*: 86732 Total Base Non Water Volume: 0 Water Source Percent Surface Water, > 1000TDS 100.00% Hydraulic Fracturing Fluid Composition: Trade Name Supplier Purpose Ingredients Chemical Abstract Service Number (CAS #) Maximum Ingredient Concentration in Additive (% by mass)** Maximum Ingredient Concentration in HF Fluid (% by mass)** Comments A264A Schlumberger Corrosion Inhibitor A264A D206 Schlumberger Antifoam Agent F103 Schlumberger Surfactant Fluid Schlumberger N/A H036 Schlumberger Acid J218 Schlumberger Breaker J218 J475 Schlumberger Breaker J475 J532 Schlumberger Crosslinker J580 Schlumberger Gel J580 L058 Schlumberger Iron Control Agent L058 L065 Schlumberger Scale Inhibitor M275 Schlumberger Bactericide S522- 2040 Schlumberger Propping Agent W054 Schlumberger Demulsifier Items above are Trade Names. Items below are the individual ingredients. Water (Including Mix Water Supplied by Client)*7732-18-5 0.00000 75.86362 None Ceramic materials and wares, chemicals 66402-68-4 97.52271 23.53845 None Guar gum 9000-30-0 1.23840 0.29891 None Hydrochloric acid 7647-01-0 0.28010 0.06761 None Diammonium peroxodisulphate 7727-54-0 0.18646 0.04501 None 1, 2, 3 - Propanetriol 56-81-5 0.17565 0.04240 None Sodium tetraborate decahydrate 1303-96-4 0.14343 0.03462 None Ethylene Glycol 107-21-1 0.07548 0.01822 None 2-Propenoic acid, polymer with sodium phosphinate 129898-01-7 0.07053 0.01702 None Propan-2-ol 67-63-0 0.05913 0.01427 None 2-butoxyethanol 111-76-2 0.05908 0.01426 None Ethoxylated C11 Alcohol 34398-01-1 0.05427 0.01310 None Vinylidene chloride/methylacrylate copolymer 25038-72-6 0.03861 0.00932 None Ethoxylated Alcohol 68131-39-5 0.02945 0.00711 None Sodium chloride 7647-14-5 0.01411 0.00340 None Methanol 67-56-1 0.00967 0.00233 None Diatomaceous earth, calcined 91053-39-3 0.00736 0.00178 None Calcium chloride 10043-52-4 0.00724 0.00175 None 1-undecanol (impurity) 112-42-5 0.00473 0.00114 None Sodium erythorbate 6381-77-7 0.00347 0.00084 None Silicon Dioxide (Impurity) 7631-86-9 0.00310 0.00075 None Reaction product of: acetophenone, formaldehyde, cyclohexylamine, methanol and acetic acid 224635-63-6 0.00179 0.00043 None Magnesium nitrate 10377-60-3 0.00147 0.00036 None Magnesium silicate hydrate (talc)14807-96-6 0.00102 0.00025 None poly(tetrafluoroethylene) 9002-84-0 0.00102 0.00025 None Cinnamaldehyde 104-55-2 0.00099 0.00024 None Oxirane, Methyl-, polymer with Oxirane 9003-11-6 0.00095 0.00023 None 5-chloro-2-methyl-4- isothiazolin-3-one and 2- methyl-4-isothiazolin-3-one 55965-84-9 0.00088 0.00021 None 2,2''-oxydiethanol (impurity) 111-46-6 0.00076 0.00018 None Alcohol, C9-C11, Ethoxylated 68439-46-3 0.00075 0.00018 None Magnesium chloride 7786-30-3 0.00074 0.00018 None Ethoxylated propoxylated 4- nonylphenol-formaldehyde resin 30846-35-6 0.00070 0.00017 None Alcohols, C7-9-iso-, C8-rich, ethoxylated 78330-19-5 0.00065 0.00016 None Alcohols, C9-11-iso-, C10-rich, ethoxylated 78330-20-8 0.00061 0.00015 None Dimethyl siloxanes and silicones 63148-62-9 0.00057 0.00014 None Alcohols, C10-16, ethoxylated 68002-97-1 0.00050 0.00012 None Alcohol, C11-14, ethoxylated 78330-21-9 0.00042 0.00010 None Sodium hydroxide (impurity) 1310-73-2 0.00038 0.00009 None Siloxanes and silicones, dimethyl, reaction products with silica 67762-90-7 0.00036 0.00009 None Potassium chloride (impurity) 7447-40-7 0.00038 0.00009 None Acetic acid, potassium salt (impurity)127-08-2 0.00019 0.00005 None Poly(oxy-1,2-ethanediyl),a- hydro-w-hydroxy- Ethane-1,2- diol, ethoxylated 25322-68-3 0.00022 0.00005 None Acetic acid (impurity) 64-19-7 0.00022 0.00005 None Acetophenone 98-86-2 0.00019 0.00005 None N,N-Dimethyl-N-dodecyl benzylaminium chloride 139-07-1 0.00015 0.00004 None Cristobalite 14464-46-1 0.00015 0.00004 None Quartz, Crystalline silica 14808-60-7 0.00015 0.00004 None Amines, tallow alkyl, ethoxylated 61791-26-2 0.00015 0.00004 None Formaldehyde (impurity) 50-00-0 0.00012 0.00003 None Solvent naphtha (petroleum), heavy arom.64742-94-5 0.00014 0.00003 None Sorbitan stearate 1338-41-6 0.00007 0.00002 None 2-Propen-1-aminium, N,N- dimethyl-N-2-propen-1-yl-, chloride (1:1), homopolymer 26062-79-3 0.00010 0.00002 None Benzenemethanaminium, N,N- dimethyl-N tetradecyl-, chloride 139-08-2 0.00005 0.00001 None 2-Propenoic acid, 2-ethylhexyl ester, polymer with 2- hydroxyethyl 2-propenoate 36089-45-9 0.00004 0.00001 None Fatty acids, C18-unsatd., dimers, ethoxylated propoxylated 68308-89-4 0.00004 0.00001 None Siloxanes and Silicones, di-Me, 3-hydroxypropyl Me, ethoxylated propoxylated 68937-55-3 0.00004 0.00001 None * Total Water Volume sources may include various types of water including fresh water, produced water, and recycled water ** Information is based on the maximum potential for concentration and thus the total may be over 100% Note: For Field Development Products (products that begin with FDP), MSDS level only information has been provided. Ingredient information for chemicals subject to 29 CFR 1910.1200(i) and Appendix D are obtained from suppliers Material Safety Data Sheets (MSDS) Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 7/23/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20250723 Well API #PTD #Log Date Log Company AOGCC ESet # END 1-25A 50029217220100 197075 6/19/2025 HALLIBURTON T40691 KU 41-08 50133207170000 224005 6/30/2025 AK E-LINE T40692 MPU F-05 50029227620000 197074 7/1/2025 READ T40693 MPU J-02 50029220710000 190096 5/21/2025 YELLOWJACKET T40694 MPU R-106 50029238160000 225033 6/8/2025 HALLIBURTON T40695 MPU R-107 50029238190000 225049 7/11/2025 YELLOWJACKET T40696 ODSK-41 50703205850000 208147 6/13/2025 HALLIBURTON T40697 ODSN-02 50703206710000 213046 6/13/2025 HALLIBURTON T40698 ODSN-16 50703206200000 210053 6/14/2025 HALLIBURTON T40699 ODSN-17 50703206220000 210093 6/14/2025 HALLIBURTON T40700 ODSN-24 50703206620000 212178 6/15/2025 HALLIBURTON T40701 ODSN-28 50703206760000 213148 6/17/2025 HALLIBURTON T40702 ODSN-36 50703205610000 207182 6/12/2025 HALLIBURTON T40703 PBU 07-23C 50029216350300 225043 7/4/2025 HALLIBURTON T40704 PBU 14-18C 50029205510300 225040 6/25/2025 HALLIBURTON T40705 PBU 15-33C 50029224480300 216075 7/3/2025 HALLIBURTON T40706 PBU C-30A 50029217770100 208169 7/1/2025 HALLIBURTON T40707 PBU E-09C 50029204660300 209095 6/30/2025 HALLIBURTON T40708 PBU F-38B 50029220930300 225029 6/12/2025 HALLIBURTON T40709 PBU GNI-02A 50029228510100 206119 7/4/2025 HALLIBURTON T40710 PBU GNI-02A 50029228510100 206119 7/3/2025 HALLIBURTON T40710 PBU GNI-04 50029233670000 207117 6/27/2025 HALLIBURTON T40711 PBU GNI-04 50029233670000 207117 6/27/2025 HALLIBURTON T40711 PBU J-07C 50029202410300 225026 5/30/2025 HALLIBURTON T40712 PBU L-105 50029230750000 202058 6/24/2025 YELLOWJACKET T40713 PBU L-108 50029230900000 202109 6/23/2025 YELLOWJACKET T40714 PBU NK-25 50029227600000 197068 6/5/2025 YELLOWJACKET T40715 PBU P2-06 50029223880000 193103 6/19/2025 HALLIBURTON T40716 PBU S-104 50029229880000 200196 6/21/2025 YELLOWJACKET T40717 PBU E-09C 50029204660300 209095 6/30/2025 HALLIBURTON Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.07.28 09:54:00 -08'00' Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: PCU-05 50283202030000 225037 7/3/2025 YELLOWJACKET T40718 TBU D-08RD 50733201070100 174003 6/4/2025 READ T40719 Please include current contact information if different from above. Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.07.28 09:53:40 -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 perfs require a spacing exception due to property boundaries?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 ServiceDevelopmentStratigraphicExploratory Authorized Name and Digital Signature with Date: Authorized Title: Contact Name: Contact Email: Contact Phone: AOGCC USE ONLY Commission Representative: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Location ClearanceMechanical Integrity TestBOP TestPlug Integrity Other Conditions of Approval: Post Initial Injection MIT Req'd?Yes No Subsequent Form Required: Approved By:Date: APPROVED BY THE AOGCCCOMMISSIONER PBU E-09C Hilcorp North Slope, LLC 3800 Centerpoint Dr, Suite 1400, Anchorage, AK 99503 209-095 50-029-20466-03-00 Statewide ADL 0028304 13217 Intermediate Liner Liner Liner Liner 8987 10181 852 1068 504 3765 9422 9-5/8" 7" 5" 3-1/2" x 3-3/16" 2-3/8" 7743 32 - 10213 9717 - 10569 9539 - 10607 10103 - 10607 9452 - 13217 2424 32 - 8386 7983 - 8667 7838 - 8696 8298 - 8696 7767 - 8987 13178 4760 7020 7250 10530 11780 9422 6870 8160 8290 10160 11200 9036 - 9041 3-1/2" 9.2#, 4-1/2" 12.6# L-80 31 - 8943, 9409 - 95427441 - 7445 Surface 2638 13-3/8" 33 - 2671 33 - 2671 5380 2670 4-1/2" HES TNT Packer 4-1/2" TIW HBBP Packer 8777, 7245 9495, 7802 Date: Torin Roschinger Operations Manager Leif Knatterud leif.knatterud@hilcorp.com 907-564-4667 PRUDHOE BAY 8/1/2025 Current Pools: Prudhoe Oil, Brookian Undefined Proposed Pools: Prudhoe Oil, Brookian Suspension Expiration Date: 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 06/2023 Approved application is valid for 12 months from the date of approval.Submit PDF to aogcc.permitting@alaska.gov No SSSV Installed By Grace Christianson at 1:46 pm, Jul 18, 2025 Digitally signed by Torin Roschinger (4662) DN: cn=Torin Roschinger (4662) Date: 2025.07.18 12:18:52 - 08'00' Torin Roschinger (4662) 325-426 8/1/2025 JJL 7/21/25 10-404 CDW 07/22/2025 DSR-7/18/25 Include a PRV on OA or hold an open bleed on OA during fracture treatment. A.Dewhurst 23JUL25JLC 7/23/2025 Gregory C. Wilson Digitally signed by Gregory C. Wilson Date: 2025.07.23 14:35:27 -08'00'07/23/25 RBDMS JSB 072425 FRAC – Brookian UHRC Well: E-09C PTD: 209-095 API: 50-029-20466-03 Well Name:E-09C Permit to Drill:209095 Current Status:Operable, Producer API Number:50-029-20466-03 Estimated Start Date:August 1, 2025 Estimated Duration:7days Rig:Frac, coil, slickline, test Regulatory Contact:Abbie Barker Sundry Number: First Call Engineer:Leif Knatterud (907) 564-4667 (O)(432) 227-4342 (M) Second Call Engineer:Tyson Shriver (907) 564-4542 (O)(406) 690-6385 (M) Current Bottom Hole Pressure:3091 psi @ 6668’ TVDss From C-18B Max Anticipated Surface Pressure:2424 psi Based on 0.1 psi/ft gas gradient Brookian KWF: 8.91 ppg Last SI WHP:400 psi (07/07/2025) Min ID:3.81” @ 2493’, 9623’ X nipples Max Angle:49 deg @ 1560’ MD Brief Well Summary: A reservoir P&A was completed in June 2025. Slickline tagged TOC at 9,396’ and performed a passing CMIT T x IA to 3,500 psi. In July 2025, a RWO pulled compromised tubing, perforated Brookian Interval, and run new 3-1/2” tubing. A MIT-T passed to 4,754 psi and an MIT-IA passed to 3,665 psi. Objective: Frac Brookian sands in E-09C POP via Poorboy gas lift to clean up well Swap to N2 lift to obtain CoreLab fluid samples Current Status: Operable Well Completion Information: Wellhead: McEvoy, 13-5/8” x 3-1/2” tubing hanger Recent Integrity: ¾07/03/2025 – MIT-T Passed to 4754 psi ¾07/03/2025 – MIT-IA Passed to 3665 psi ¾06/12/2025 - CMIT T x IA Passed to 3736 psi ¾03/10/2025 – PPPOT-IC Passed to 3500 psi ¾10/30/2024– PPPOT-T Passed to 5000 psi Slickline 1. Install BHPG in Station 1 Frac 1. Spot water tanks and fill with fresh water a. Heat water to 90 degF b. Minimum pumping temp for water: 80 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 FRAC – Brookian UHRC Well: E-09C PTD: 209-095 API: 50-029-20466-03 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 i. Effects depend on the solids that are dissolved in the fluid. 3. RU and set tree saver 4. RU SLB Frac 5. Ensure frac fluid QAQC has been agreed on with OE 6. Perform pressure tests prior to performing hydraulic fracture stimulation. a. Pressure test surface lines and tree saver to 8,500 psi. b. Pressure test pump kick outs to 6,750 psi. c. Pressure test IA Pop-Off system to ensure functioning properly. IA Pop-Offs to be set at 3,480 psi. d. Bring IA pressure up and hold at 3,480 psi. 7. Pump the hydraulic fracture stimulation per the proposed pump schedule below. Maximum allowable treating pressure is 7,500 psi. 8. RDMO SLB frac and flowback equipment Pump Schedule ťÍČôώϭ >īŪĖî ťÍČô ŘĺŕώĺĲ ϼŕŕÍϽ ÍťôώϼæŕıϽ «ĺīŪıôώϼææīŜϽ Ūıώ«ĺīŪıô ϼææīŜϽ ŘĺŕŕÍĲťώbÍıô ŘĺŕŕÍĲť ϼϭϽ ŪıώŘĺŕŕÍĲť ϼϭϽ ͐ >®ώſϯώîîŜ IĲĤôèťĖĺĲώôŜť ͑͑ ͐͑ ͐͑ ͑ēŪťîĺſĲ ͒ ͒͏ϭώ³ϱ[ĖĲħ Íî ͓͑ ͔͖͒ ͕͒͘ ͓ ͒͏ϭώ³ϱ[ĖĲħ >īÍť ͐ ͓͑ ͕͒ ͓͏͔ ͑͏ϯ͓͏ώÍŘæĺ[Ėťô ͔͐͏͏ ͔͐͏͏ ͔ ͒͏ϭώ³ϱ[ĖĲħ >īÍť ͑ ͓͑ ͓͗ ͓͔͑ ͑͏ϯ͓͏ώÍŘæĺ[Ėťô ͓͏͏͏ ͔͔͏͏ ͕ ͒͏ϭώ³ϱ[ĖĲħ >īÍť ͒ ͓͑ ͕͏ ͔͐͑ ͑͏ϯ͓͏ώÍŘæĺ[Ėťô ͖͔͏͏ ͐͒͏͏͏ ͖ ͒͏ϭώ³ϱ[ĖĲħ >īÍť ͒ϟ͔ ͓͑ ͕͔ ͔͖͖ ͑͏ϯ͓͏ώÍŘæĺ[Ėťô ͕͔͑͘ ͕͔͑͑͑ ͗ ͒͏ϭώ³ϱ[ĖĲħ >īÍť ͓ ͓͑ ͖͐ ͕͓͘ ͑͏ϯ͓͏ώÍŘæĺ[Ėťô ͐͑͏͏͏ ͓͕͔͒͑ ͘ ͒͏ϭώ³ϱ[ĖĲħ >īÍť ͓ϟ͔ ͓͑ ͗͒ ͖͒͑ ͑͏ϯ͓͏ώÍŘæĺ[Ėťô ͔͖͔͐͏ ͔͏͖͔͒ ͐͏ ͒͏ϭώ³ϱ[ĖĲħ >īÍť ͔ ͓͑ ͔͘ ͖͗͑ ͑͏ϯ͓͏ώÍŘæĺ[Ėťô ͑͏͏͏͏ ͖͏͖͔͒ ͐͐ ͒͏ϭώ³ϱ[ĖĲħ >īÍť ͔ϟ͔ ͓͑ ͐͏͖ ͔͒͘ ͑͏ϯ͓͏ώÍŘæĺ[Ėťô ͓͖͔͑͏ ͔͔͐͑͘ ͐͑ ͒͏ϭώ³ϱ[ĖĲħ >īÍť ͕ ͓͑ ͐͏͖ ͐͏͓͑ ͑͏ϯ͓͏ώÍŘæĺ[Ėťô ͖͑͏͏͏ ͔͐͑͑͐͑ ͐͒ ͒͏ϭώ³ϱ[ĖĲħ >īÍť ͕ϟ͔ ͓͑ ͐͐͘ ͕͐͐͐ ͑͏ϯ͓͏ώÍŘæĺ[Ėťô ͔͒͑͏͏ ͔͓͕͔͐͑ ͓͐ ͒͏ϭώ³ϱ[ĖĲħ >īÍť ͖ ͓͑ ͗͒ ͓͓͐͑ ͑͏ϯ͓͏ώÍŘæĺ[Ėťô ͓͔͑͏͏ ͖͔͐͐͑͘ ͔͐ ͒͏ϭώ³ϱ[ĖĲħ >īÍť ͖ϟ͔ ͓͑ ͖͐ ͔͐͒͐ ͑͏ϯ͓͏ώÍŘæĺ[Ėťô ͔͑͑͏͏ ͑͏͕͔͐͑ ͕͐ ͒͏ϭώ³ϱ[ĖĲħ >īÍť ͗ ͓͑ ͖͐ ͖͐͒͗ ͑͏ϯ͓͏ώÍŘæĺ[Ėťô ͓͑͏͏͏ ͔͕͔͑͑͑ ͐͘ >®ώſϯώîîŜ >īŪŜē ͓͑ ͐͐͒ ͔͐͏͏ ͑͏ "ĖôŜôī >ŘôôƏôώŘĺťôèť ͔ ͒͏ ͔͐͒͏ FRAC – Brookian UHRC Well: E-09C PTD: 209-095 API: 50-029-20466-03 Pressures MIT-T 4,754 psi MIT-IA 3,665 psi Maximum Anticipated Treating Pressure:4,600 psi @ 26 BPM IA Pop-off Set Pressure (~95% of MIT-IA):3,480 psi IA Minimum Hold Pressure (POP-off – 300 psi):3,180 psi Maximum Allowable Treating Pressure (MATP = Ann hold +MIT-T/1.1): 7,500 psi w/ 3,180 psi on IA Stagger Pump Kickouts Between 90 – 95% of MATP:6,750 psi – 7,125 psi N2 POP-off set pressure (MATP):7,500 psi Treating Line Test Pressure (MATP + 1000 psi):8,500 psi OA Pressure:Maintain open bleed on OA Max Anticipated Proppant Loading:8 PPA Coil 1. Contingent Post Frac FCO Slickline 1. Install LGLVs 2. Swap out BHPG Testers: 1. MIRU per flowback diagram below, pressure test 2. E-34 to be used for PBGL a. Ensure welltest of E-34 is obtain within 24 hours of E-09 POP i. Ensure WHP ~1800 psi, about what our gas lift kick off pressure is going to be ii. Subtraction method of E-34 gas rate to be used to determine E-09 gas lift rate b. Obtain gas and oil samples of E-34 at some point during flowback (+/- 1 day) i. Adam Lewis on slope to help sampling ii. PBU lab to analyze for gas composition and route oil samples to KRU lab for oil composition 1. PBU Lab: 659-5649 2. PBU lab is fully informed of the job objectives. PBU will obtain oil and gas samples and forward oil samples to KRU 3. POP the well to ASRC with 0.5 MMSCFD lift gas at minimum choke until on orifice GLV. a. Please attempt to POP without stacking the well out first b. Observe drop in gas rate via E-34 in test separator c. Start new E-34 well test after Popping E-09 d. Strap on flowmeter to be used if possible/accurate e. Flow to tanks until FOC 4. Adjust GL rate as necessary to eliminate slugging. If the initial returns meet the shake-outs and the returned fluid/solids management guidelines, begin taking returns to the flowline. a. If at any point, solids are >1%, divert returns to flowback tanks. 5. Limit flow to 500 bpd 6. If solids are < 1%, after 2 wellbore volumes (170 bbls) increase the production rate to 750 BLPD. a. Beanup program can be modified, work with OE 7. Flow bottoms up and sample for solids production. If solids are still below 1%, increase flow to 1000 BFPD. Maximum Anticipated Treating Pressure:4,600 psi @ 26 BPM IA Pop-off Set Pressure (~95% of MIT-IA):3,480 psi IA Minimum Hold Pressure (POP-off – 300 psi):3,180 psi Maximum Allowable Treating Pressure (MATP =7,500 psi w/ 3,180 psi on IA Ann hold +MIT-T/1.1): Stagger Pump Kickouts Between 90 – 95% of MATP:6,750 psi – 7,125 psi N2 POP-off set pressure (MATP):7,500 psi Treating Line Test Pressure (MATP + 1000 psi):8,500 psi OA Pressure:Maintain Pressures differ from Section 12 on page 27 CDW 07/22/2025 FRAC – Brookian UHRC Well: E-09C PTD: 209-095 API: 50-029-20466-03 8. 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. 9. Once at FOC, stabilize the well for 4 hrs. Obtain an 8 hr welltest. 10. Once cleanup is called, coordinate with PBU lab to obtain daily produced gas and oil samples a. PBU lab to analyze for gas composition and route oil samples to KRU lab for oil composition 11. Obtain shakeouts for WCUT, BS&W and API at minimum every 4hrs and note results in test report 12. After initial welltest obtained while on PBGL, swap to N2 lift a. Per RU diagram below b. Once finished with PBGL, E-34 can come out of test at the plant 13. Continue to flow the well ~1 day on N2 taking regular 8 hour well tests 14. After ~1 day of flow on N2 and agreed on with OE/Adam Lewis, call Corelab to location to obtain fluid samples: a. Jason Peltier: 337-258-3682 b. Sample produced fluids: 3 sets of oil and accompanying gas samples at 3 separate times (prefer +6hrs apart) i. DO NOT inject any fluids (chemicals, water, diesel, etc….) into the well or flowlines for time equivalent to at least 10 separator volumes prior to sampling (prefer >24hrs). ii. Ensure wells artificial lift is stable and producing GOR is stable (+6hrs) during sampling iii. Samples should be taken from the appropriate leg of the separator train as close to the vessel as possible. Avoid locations downstream of devices that cause large pressure drop especially for the gas samples. iv. Utilize pre-evacuated cylinders for gas samples, Draeger tubes for CO2 and H2S, and water-filled cylinders for oil samples (these are all Corelab provided). Drain 5-10% of the liquid volume (i.e. remaining water volume) from liquid cylinders post filling to create gas- cap. 15. Once all samples are taken, a final 8 hour piggyback test will be obtained to vet the pad separator to Little Red’s test sep 16. After piggyback test is obtained, perform hard SI of well. SI N2 followed by immediate closure of wing valve. Do not inject anything down tubing or OA. 17. 7-10 day PBU 18. Return well to PBGL. a. Slickline to follow up and pull gauges after ~ 1 month flow. Key Contacts: Company Contact Phone HES N2 Walter Bates 661-754-4052 CoreLab Jason Peltier 337-839-3682 Hilcorp Slickline TBD TBD Hilcorp Testers TBD TBD Hilcorp OE Leif Knatterud 432-227-4342 Hilcorp RE/Geo Adam Lewis 225-205-5081 Attachments – x Current Wellbore Schematic x Frac RU Diagram x Flowback RU Diagram x Reference Log for Brookian Perforations x Sundry Revision Change Form FRAC – Brookian UHRC Well: E-09C PTD: 209-095 API: 50-029-20466-03 Current Wellbore Schematic: FRAC – Brookian UHRC Well: E-09C PTD: 209-095 API: 50-029-20466-03 Frac RU Diagram FRAC – Brookian UHRC Well: E-09C PTD: 209-095 API: 50-029-20466-03 Flowback RU Diagram: E-34 E-34 FRAC – Brookian UHRC Well: E-09C PTD: 209-095 API: 50-029-20466-03 Reference Log for Brookian Perforations: FRAC – Brookian UHRCWell: E-09CPTD: 209-095API: 50-029-20466-03Sundry Revision Change Form:Changes to Approved Sundry ProcedureDate:Subject:Sundry #:Any modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to theAOGCC by the “first call” engineer. AOGCC written approval of the change is required before implementing the change.StepPageDateProcedure ChangeHNSPreparedBy(Initials)HNSApprovedBy(Initials)AOGCC WrittenApprovalReceived (Personand Date)Approval:Operations Manager DatePrepared:Operations Engineer Date E-09C Fracture Stimulation PTD: 209-095 Page 1 Date: July 11, 2025 Subject: E-09C Fracture Stimulation From: Leif Knatterud O: (907) 564-4667 C: (432) 227-4342 To: AOGCC Estimated Start Date: 8/1/2025 Attached is Hilcorp’s proposal and supporting documents to perform a fracture stimulation on well E- 09C (PTD #209-095) in the Brookian reservoir of the Prudhoe Bay Unit. The objective of this program is to perform a single stage fracture stimulation to the existing Brookian perforations to improve well performance. E-09C was recently recompleted as a Brookian producer, previously an Ivishak producer. The Ivishak perforations were plugged on 6/9/2025 with cement filling the Ivishak production liner. Isolation from the Ivishak was demonstrated with a state witnessed passing CMIT on 6/12/2025. The Brookian interval was recompleted and perforated on 07/01/2025. 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 Leif Knatterud. E-09C Fracture Stimulation PTD: 209-095 Page 2 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 E-09C Fracture Stimulation PTD: 209-095 Page 3 SIGNED AFFIDAVIT: E-09C Fracture Stimulation PTD: 209-095 Page 4 COPY OF NOTIFICATION SENT VIA EMAIL: E-09C Fracture Stimulation PTD: 209-095 Page 5 SECTION 2 - PLAT IDENTIFYING ALL WELLS WITHIN ½ MILE (20 AAC 25.283, a, 2): Plat of wells within one-half mile of E-09C trajectory. E-09C Fracture Stimulation PTD: 209-095 Page 6 LIST OF WELLS IN PLAT WITHIN ½ MILES ON SURFACE (20 AAC 25.283, a, 2, C): ®϶ba( ®([[϶[ ®([[϶ ®϶ba( ®([[϶[ ®([[϶ ®϶ba(®([[϶[ ®([[϶ (ϱ͏͐ "(« æÍĲîĺĲôî Xϱ͏͒͐ "(« īŪČČôîώÍèħώ>ĺŘώôîŘĖīī (ϱ͑͒ "(« æÍĲîĺĲôî (ϱ͏͐ "(« æÍĲîĺĲôî Xϱ͏͒͑ "(« īŪČČôîώÍèħώ>ĺŘώôîŘĖīī (ϱ͑͒ "(« æÍĲîĺĲôî (ϱ͏͐ "(« iĖīώŘĺîŪèôŘώēŪťϱIĲ Xϱ͏͒͐ "(« īŪČČôîώÍèħώ>ĺŘώôîŘĖīī (ϱ͑͒ "(« æÍĲîĺĲôî (ϱ͏͐͐ "(« īŪČČôîώÍèħώ>ĺŘώôîŘĖīī Xϱ͏͑ "(« æÍĲîĺĲôî (ϱ͑͒ "(« iĖīώŘĺîŪèôŘώēŪťϱIĲ (ϱ͏͑ "(« æÍĲîĺĲôî Xϱ͏͑ "(« æÍĲîĺĲôî (ϱ͑͒͐ "(« īŪČČôîώÍèħώ>ĺŘώôîŘĖīī (ϱ͏͑ "(« æÍĲîĺĲôî Xϱ͏͑ "(« æÍĲîĺĲôî (ϱ͑͒͐ "(« īŪČČôîώÍèħώ>ĺŘώôîŘĖīī (ϱ͏͑ "(« iĖīώŘĺîŪèôŘώēŪťϱIĲ Xϱ͏͑" "(« iĖīώŘĺîŪèôŘώēŪťϱIĲ (ϱ͑͒͑"(« īŪČČôîώÍèħώ>ĺŘώôîŘĖīī (ϱ͏͑͐ "(« īŪČČôîώÍèħώ>ĺŘώôîŘĖīī Xϱ͏͑"͐ "(« īŪČČôîώÍèħώ>ĺŘώôîŘĖīī Xϱ͐͐ "(« æÍĲîĺĲôî (ϱ͏͒ "(« æÍĲîĺĲôî Xϱ͏͓ "(« æÍĲîĺĲôî Xϱ͐͐ "(« iĖīώŘĺîŪèôŘώ>īĺſĖĲČ (ϱ͏͒ "(« iĖīώŘĺîŪèôŘώēŪťϱIĲ Xϱ͏͓ "(« æÍĲîĺĲôî (ϱ͓͑ "(« æÍĲîĺĲôî (ϱ͏͓ "(« æÍĲîĺĲôî Xϱ͏͓ "(« æÍĲîĺĲôî (ϱ͓͑ "(« æÍĲîĺĲôî (ϱ͏͓ "(« iĖīώŘĺîŪèôŘώēŪťϱIĲ Xϱ͏͓ "(« iĖīώŘĺîŪèôŘώ>īĺſĖĲČ (ϱ͓͑ "(« iĖīώŘĺîŪèôŘώēŪťϱIĲ (ϱ͏͔ "(« æÍĲîĺĲôî Xϱ͏͓͐ "(« īŪČČôîώÍèħώ>ĺŘώôîŘĖīī (ϱ͓͑͐ "(« īŪČČôîώÍèħώ>ĺŘώôîŘĖīī (ϱ͏͔ "(« æÍĲîĺĲôî Xϱ͏͓͑ "(« īŪČČôîώÍèħώ>ĺŘώôîŘĖīī (ϱ͓͑͑ "(«īŪČČôîώÍèħώ>ĺŘώôîŘĖīī (ϱ͏͔ "(« æÍĲîĺĲôî Xϱ͏͓͒ "(« īŪČČôîώÍèħώ>ĺŘώôîŘĖīī (ϱ͔͑ "(« æÍĲîĺĲôî (ϱ͏͔ "(« iĖīώŘĺîŪèôŘώēŪťϱIĲ Xϱ͏͓͐ "(« īŪČČôîώÍèħώ>ĺŘώôîŘĖīī (ϱ͔͑ "(« iĖīώŘĺîŪèôŘώēŪťϱIĲ (ϱ͏͔͐ "(« īŪČČôîώÍèħώ>ĺŘώôîŘĖīī Xϱ͏͓͑ "(« īŪČČôîώÍèħώ>ĺŘώôîŘĖīī (ϱ͔͑͐ "(« īŪČČôîώÍèħώ>ĺŘώôîŘĖīī (ϱ͏͕ "(« æÍĲîĺĲôî Xϱ͏͕ "(« æÍĲîĺĲôî (ϱ͔͑͑ "(« īŪČČôîώÍèħώ>ĺŘώôîŘĖīī (ϱ͏͕ "(« iĖīώŘĺîŪèôŘώēŪťϱIĲ Xϱ͏͕ "(« æÍĲîĺĲôî (ϱ͔͑͐ "(« īŪČČôîώÍèħώ>ĺŘώôîŘĖīī (ϱ͏͖ "(« æÍĲîĺĲôî Xϱ͏͕ "(« æÍĲîĺĲôî (ϱ͕͑ "(« æÍĲîĺĲôî (ϱ͏͖ "(« æÍĲîĺĲôî Xϱ͏͕ "(« æÍĲîĺĲôî (ϱ͕͑ "(« æÍĲîĺĲôî (ϱ͏͖ "(« iĖīώŘĺîŪèôŘώēŪťϱIĲ Xϱ͏͕" "(« iĖīώŘĺîŪèôŘώēŪťϱIĲ (ϱ͕͑ "(« iĖīώŘĺîŪèôŘώ>īĺſĖĲČ (ϱ͏͖͐ "(« īŪČČôîώÍèħώ>ĺŘώôîŘĖīī Xϱ͏͕͐ "(« īŪČČôîώÍèħώ>ĺŘώôîŘĖīī (ϱ͒͑ "(« æÍĲîĺĲôî (ϱ͏͖͑ "(« īŪČČôîώÍèħώ>ĺŘώôîŘĖīī Xϱ͏͖ "(« æÍĲîĺĲôî (ϱ͒͑ "(« æÍĲîĺĲôî (ϱ͏͗ "(« æÍĲîĺĲôî Xϱ͏͖ "(« æÍĲîĺĲôî (ϱ͒͑ "(« iĖīώŘĺîŪèôŘώēŪťϱIĲ (ϱ͏͗ "(« æÍĲîĺĲôî Xϱ͏͖ "(« æÍĲîĺĲôî (ϱ͒͑͐ "(« īŪČČôîώÍèħώ>ĺŘώôîŘĖīī (ϱ͏͗ "(« iĖīώŘĺîŪèôŘώ>īĺſĖĲČ Xϱ͏͖ "(« æÍĲîĺĲôî (ϱ͒͑͐ "(« īŪČČôîώÍèħώ>ĺŘώôîŘĖīī (ϱ͏͗͐ "(« īŪČČôîώÍèħώ>ĺŘώôîŘĖīī Xϱ͏͖" "(« æÍĲîĺĲôî (ϱ͒͐ "(« æÍĲîĺĲôî (ϱ͏͘ "(« æÍĲîĺĲôî Xϱ͏͖( "(« æÍĲîĺĲôî (ϱ͒͐ "(« iĖīώŘĺîŪèôŘώēŪťϱIĲ (ϱ͏͘ "(« æÍĲîĺĲôî Xϱ͏͖> "(« iĖīώŘĺîŪèôŘώēŪťϱIĲ (ϱ͒͒ "(« æÍĲîĺĲôî (ϱ͏͘ "(« æÍĲîĺĲôî Xϱ͏͖͐ "(« īŪČČôîώÍèħώ>ĺŘώôîŘĖīī (ϱ͒͒ "(« æÍĲîĺĲôî (ϱ͏͘ "(« iĖīώŘĺîŪèôŘώēŪťϱIĲ Xϱ͏͖͑ "(« īŪČČôîώÍèħώ>ĺŘώôîŘĖīī (ϱ͒͒ "(« iĖīώŘĺîŪèôŘώēŪťϱIĲ (ϱ͏͐͘ "(« īŪČČôîώÍèħώ>ĺŘώôîŘĖīī Xϱ͏͖"͐ "(« īŪČČôîώÍèħώ>ĺŘώôîŘĖīī Xϱ͕͐ "(« æÍĲîĺĲôî (ϱ͏͐͘ "(« īŪČČôîώÍèħώ>ĺŘώôîŘĖīī Xϱ͏͖(͐ "(« īŪČČôîώÍèħώ>ĺŘώôîŘĖīī Xϱ͕͐ "(« iĖīώŘĺîŪèôŘώēŪťϱIĲ (ϱ͖͐ "(« æÍĲîĺĲôî Xϱ͏͗ "(« æÍĲîĺĲôî Xϱ͕͐[͐ "(« iĖīώ®ôīī (ϱ͖͐ "(« iĖīώŘĺîŪèôŘώēŪťϱIĲ Xϱ͏͗ "(« æÍĲîĺĲôî Xϱ͕͐[͑ "(« iĖīώŘĺîŪèôŘώ>īĺſĖĲČ (ϱ͐͐ "(« æÍĲîĺĲôî Xϱ͏͗ "(« iĖīώŘĺîŪèôŘώēŪťϱIĲ (ϱ͓͒ "(« æÍĲîĺĲôî (ϱ͐͐ "(« æÍĲîĺĲôî Xϱ͏͔ "(« æÍĲîĺĲôî (ϱ͓͒ "(« iĖīώŘĺîŪèôŘώēŪťϱIĲ (ϱ͐͐ "(« iĖīώŘĺîŪèôŘώ>īĺſĖĲČ Xϱ͏͔ "(« æÍĲîĺĲôî (ϱ͓͒[͐ "(« æÍĲîĺĲôî (ϱ͐͐[͐ "(« iĖīώŘĺîŪèôŘώ>īĺſĖĲČ Xϱ͏͔ "(« æÍĲîĺĲôî Xϱ͐͘ "(« æÍĲîĺĲôî (ϱ͐͐[͐ϱ͏͐ "(« iĖīώŘĺîŪèôŘώēŪťϱIĲ Xϱ͏͔ "(« æÍĲîĺĲôî Xϱ͐͘ "(« æÍĲî ĺĲôî (ϱ͐͐͐ "(« īŪČČôîώÍèħώ>ĺŘώôîŘĖīī Xϱ͏͔" "(« iĖīώŘĺîŪèôŘώēŪťϱIĲ Xϱ͐͘ "(« æÍĲîĺĲôî (ϱ͐͐[͐͐ "(« īŪČČôîώÍèħώ>ĺŘώôîŘĖīī Xϱ͏͔͐ "(« īŪČČôîώÍèħώ>ĺŘώôîŘĖīī Xϱ͐͘ "(« iĖīώŘĺîŪèôŘώ>īĺſĖĲČ (ϱ͐͐[͐͑ "(« īŪČČôîώÍèħώ>ĺŘώôîŘĖīī Xϱ͏͔"͐ "(« īŪČČôîώÍèħώ>ĺŘώôîŘĖīī Xϱ͐͘[͐ "(« æÍĲîĺĲôî (ϱ͕͐ "(« æÍĲîĺĲôî Xϱ͏͔"͑ "(« īŪČČôîώÍèħώ>ĺŘώôîŘĖīī Xϱ͐͐͘ "(« īŪČČôîώÍèħώ>ĺŘώôîŘĖīī (ϱ͕͐ "(« iĖīώŘĺîŪèôŘώ>īĺſĖĲČ Xϱ͏͘ "(« æÍĲîĺĲôî Xϱ͖͐ "(« æÍĲîĺĲôî (ϱ͕͐͐ "(« īŪČČôîώÍèħώ>ĺŘώôîŘĖīī Xϱ͏͘ "(« æÍĲîĺĲôî Xϱ͖͐ "(« æÍĲîĺĲôî (ϱ͐͘ "(« æÍĲîĺĲôî Xϱ͏͘ "(« æÍĲîĺĲôî Xϱ͖͒͐ "(« iĖīώŘĺîŪèôŘώēŪťϱIĲ (ϱ͐͘ "(« æÍĲîĺĲôî Xϱ͏͘ "(« iĖīώŘĺîŪèôŘώēŪťϱIĲ Xϱ͖͐͐ "(« īŪČČôîώÍèħώ>ĺŘώôîŘĖīī (ϱ͐͘ "(« æÍĲîĺĲôî Xϱ͏͐͘ "(« īŪČČôîώÍèħώ>ĺŘώôîŘĖīī Xϱ͖͐͑ "(« īŪČČôîώÍèħώ>ĺŘώôîŘĖīī (ϱ͐͘ "(« iĖīώŘĺîŪèôŘώēŪťϱIĲ Xϱ͏͐͘ "(« īŪČČôîώÍèħώ>ĺŘώôîŘĖīī Xϱ͖͐͐ "(« īŪČČôîώÍèħώ>ĺŘώôîŘĖīī (ϱ͑͏ "(« æÍĲîĺĲôî (ϱ͑͘ "(« æÍĲîĺĲôî Xϱ͖͐͑ "(« īŪČČôîώÍèħώ>ĺŘώôîŘĖīī (ϱ͑͏ "(« æÍĲîĺĲôî (ϱ͑͘ "(« iĖīώŘĺîŪèôŘώēŪťϱIĲ Xϱ͑͏ "(« æÍĲîĺĲôî (ϱ͑͏ "(« æÍĲîĺĲôî Xϱ͓͐ "(« æÍĲîĺĲôî Xϱ͑͏ "(« æÍĲîĺĲôî (ϱ͑͏ "(« iĖīώŘĺîŪèôŘώ>īĺſĖĲČ Xϱ͓͐ "(« iĖīώŘĺîŪèôŘώ>īĺſĖĲČ Xϱ͑͏ "(«æÍĲîĺĲôî (ϱ͑͐ "(« æÍĲîĺĲôî (ϱ͑͗ "(« æÍĲîĺĲôî Xϱ͑͏ "(« iĖīώŘĺîŪèôŘώēŪťϱIĲ (ϱ͑͐ "(« æÍĲîĺĲôî (ϱ͑͗ "(« æÍĲîĺĲôî Xϱ͑͏͐ "(« īŪČČôîώÍèħώ>ĺŘώôîŘĖīī (ϱ͑͐ "(« iĖīώŘĺîŪèôŘώēŪťϱIĲ (ϱ͑͗͐ "(« īŪČČôîώÍèħώ>ĺŘώôîŘĖīī Xϱ͑͏͐ "(« īŪČČôîώÍèħώ>ĺŘώôîŘĖīī (ϱ͐͏ "(« æÍĲîĺĲôî Xϱ͐͒ "(« æÍĲîĺĲôî (ϱ͔͒ "(« æÍĲîĺĲôî (ϱ͐͏ "(« æÍĲîĺĲôî Xϱ͐͑ "(« æÍĲîĺĲôî (ϱ͔͒ "(« æÍĲîĺĲôî (ϱ͐͏ "(« iĖīώŘĺîŪèôŘώēŪťϱIĲ Xϱ͐͑ "(« æÍĲîĺĲôî (ϱ͔͒ "(« æÍĲîĺĲôî (ϱ͐͗ "(« æÍĲîĺĲôî Xϱ͐͑ "(« æÍĲîĺĲôî (ϱ͔͒ "(« ŪŜŕôĲîôî (ϱ͐͗ "(« æÍĲîĺĲôî Xϱ͐͑ "(« æÍĲîĺĲôî (ϱ͔͒͐ "(« īŪČČôîώÍèħώ>ĺŘώôîŘĖīī (ϱ͐͗ "(« ŪŜŕôĲîôî Xϱ͐͑" "(« iĖīώŘĺîŪèôŘώ>īĺſĖĲČ (ϱ͕͒ "(« æÍĲîĺĲôî (ϱ͔͐ "(« æÍĲîĺĲôî Xϱ͐͑͐ "(« īŪČČôîώÍèħώ>ĺŘώôîŘĖīī (ϱ͕͒ "(« æÍĲîĺĲôî (ϱ͔͐ "(« æÍĲîĺĲôî Xϱ͐͑͐ "(« īŪČČôîώÍèħώ>ĺŘώôîŘĖīī (ϱ͕͒ "(« iĖīώŘĺîŪèôŘώēŪťϱIĲ (ϱ͔͐ "(« æÍĲîĺĲôî Xϱ͐͑͑ "(« īŪČČôîώÍèħώ>ĺŘώôîŘĖīī (ϱ͖͒ "(« æÍĲîĺĲôî (ϱ͔͐ "(« æÍĲîĺĲôî Xϱ͐͑"͐ "(« īŪČČôîώÍèħώ>ĺŘώôîŘĖīī (ϱ͖͒ "(« iĖīώŘĺîŪèôŘώēŪťϱIĲ (ϱ͔͐" "(« æÍĲîĺĲôî Xϱ͐͑"͑ "(« īŪČČôîώÍèħώ>ĺŘώôîŘĖīī (ϱ͖͒[͐ "(« iĖīώŘĺîŪèôŘώ>īĺſĖĲČ (ϱ͔͐( "(« iĖīώŘĺîŪèôŘώēŪťϱIĲ Xϱ͐͑"͒ "(« īŪČČôîώÍèħώ>ĺŘώôîŘĖīī (ϱ͖͒͐ "(« īŪČČôîώÍèħώ>ĺŘώôîŘĖīī (ϱ͔͐͐ "(« īŪČČôîώÍèħώ>ĺŘώôîŘĖīī Xϱ͐͑"͓ "(« īŪČČôîώÍèħώ>ĺŘώôîŘĖīī (ϱ͖͒͐ "(« īŪČČôîώÍèħώ>ĺŘώôîŘĖīī (ϱ͔͐͑ "(« īŪČČôîώÍèħώ>ĺŘώôîŘĖīī (ϱ͖͑ "(« æÍĲîĺĲôî (ϱ͒͗ "(« iĖīώŘĺîŪèôŘώ>īĺſĖĲČ (ϱ͔͐͐ "(« īŪČČôîώÍèħώ>ĺŘώôîŘĖīī (ϱ͖͑ "(« iĖīώŘĺîŪèôŘώ>īĺſĖĲČ (ϱ͒͗͐ "(« īŪČČôîώÍèħώ>ĺŘώôîŘĖīī (ϱ͐͑ "(« æÍĲîĺĲôî Xϱ͐͏ "(« æÍĲîĺĲôî (ϱ͒͗͑ "(« īŪČČôîώÍèħώ>ĺŘώôîŘĖīī (ϱ͐͑ "(« iĖīώŘĺîŪèôŘώēŪťϱIĲ Xϱ͐͏ "(« æÍĲîĺĲôî (ϱ͒͘ "(« æÍĲîĺĲôî (ϱ͐͒ "(« æÍĲîĺĲôî Xϱ͐͏ "(« æÍĲîĺĲôî (ϱ͒͘ "(« iĖīώŘĺîŪèôŘώēŪťϱIĲ (ϱ͐͒ "(« iĖīώŘĺîŪèôŘώ>īĺſĖĲČ Xϱ͐͏ "(« æÍĲîĺĲôî (ϱ͐͏͏ (« æÍĲîĺĲôî (ϱ͓͐ "(« æÍĲîĺĲôî Xϱ͐͏" "(« iĖīώŘĺîŪèôŘώēŪťϱIĲ (ϱ͐͏͏ "(« iĖīώŘĺîŪèôŘώēŪťϱIĲ (ϱ͓͐ "(« iĖīώŘĺîŪèôŘώēŪťϱIĲ Xϱ͐͏͐ "(« īŪČČôîώÍèħώ>ĺŘώôîŘĖīī (ϱ͐͏͐ "(« iĖīώŘĺîŪèôŘώ>īĺſĖĲČ Xϱ͏͐ "(« iĖīώŘĺîŪèôŘώēŪťϱIĲ Xϱ͐͏͑ "(« īŪČČôîώÍèħώ>ĺŘώôîŘĖīī (ϱ͐͏͑ "(« iĖīώŘĺîŪèôŘώēŪťϱIĲ Xϱ͏͑ "(« æÍĲîĺĲôî Xϱ͐͏͒ "(« īŪČČôîώÍèħώ>ĺŘώôîŘĖīī (ϱ͐͏͒ (« ®ÍťôŘώIĲĤôèťĺŘώIĲĤôèťĖĲČ Xϱ͏͒ "(« æÍĲîĺĲôî Xϱ͐͏͐ "(« īŪČČôîώÍèħώ>ĺŘώôîŘĖīī (ϱ͐͏͒͐ («īŪČČôîώÍèħώ>ĺŘώôîŘĖīī Xϱ͏͒ "(« æÍĲîĺĲôî Xϱ͐͏"͐ "(« īŪČČôîώÍèħώ>ĺŘώôîŘĖīī (ϱ͐͏͓ (« ®ÍťôŘώIĲĤôèťĺŘώēŪťϱIĲ Xϱ͏͒ "(« iĖīώŘĺîŪèôŘώēŪťϱIĲ Xϱ͑͐ "(« iĖīώŘĺîŪèôŘώēŪťϱIĲ E-09C Fracture Stimulation PTD: 209-095 Page 7 SECTION 3 - EXEMPTION FOR FRESWATER AQUIFERS (20 AAC 25.283, a, 3): Well E-09C 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. E-09C Fracture Stimulation PTD: 209-095 Page 8 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. E-09C Fracture Stimulation PTD: 209-095 Page 9 SECTION 5 - DETAILED CEMENTING AND CASING INFORMATION (20 AAC 25.283, a, 5): All casing is cemented and tested in accordance with 20 AAC 25.030, g when completed. See wellbore schematic for casing details: E-09C Fracture Stimulation PTD: 209-095 Page 10 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: Annular Cement: 9-5/8” Casing: The original completion documents indicate that the primary cement job on the 9-5/8” casing went as planned. 259 bbls of cement was pumped providing an estimated cement top of 6968’ behind the 9-5/8” casing including 30% washout. No losses were noted during the cement job. Cement was verified with a RCBL on June, 30th 2025. Cement top was determined to be 7,060’. 7” Liner: Cemented with 45 bbls of Class G cement, 40% excess. Pressure tested to 3000 psi. Estimated TOC – at liner lap – 9717’. 5” Liner: Cemented with 49 bbls of Class G cement, 30% excess. Pressure tested to 3500 psi. Estimated TOC – at liner lap – 9,553’. E-09B 3-1/2” x 3-3/16” x 2-7/8” Liner: 2002 sidetrack exited parent bore at 10,688’, not affecting isolation behind 9-5/8” casing. E-09C 2-3/8” Liner: 2009 sidetrack exited parent bore at 10,613’, not affecting isolation behind 9-5/8” casing. Ivishak Reservoir Abandonment – 2-3/8” – 4-1/2” Cement plug: Laid in 17bbls 15.8bbls class G cement from 10,600' up to 8650', Squeeze 2.3bbls down liner for a bottom of 11190' MD. Hold 2000psi squeeze pressure for 30 min w/47psi loss. Bleed down WHP and cleaned out to 9400' TOC. 7,060’. 6968’ E-09C Fracture Stimulation PTD: 209-095 Page 11 SECTION 7 - PRESSURE TEST INFORMATION AND PLANS TO PRESSURE TEST CASINGS AND TUBING INSTALLED IN THE WELL (20 AAC 25.283, a, 7): On 6/15/2025, the production casing was pressure tested to 3736 psi with a passing CMIT-TxIA. Post RWO, the tubing was pressure tested to 4,754 psi with a MIT-T and the IA was pressure tested to 3,665 psi with a MIT-IA. 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. Anticipated Pressures: MIT-T 4,754 psi MIT-IA 3,665 psi Maximum Anticipated Treating Pressure:4,600 psi @ 26 BPM IA Pop-off Set Pressure (~95% of MIT-IA):3,480 psi IA Minimum Hold Pressure (POP-off – 300 psi):3,180 psi Maximum Allowable Treating Pressure (MATP = Ann hold + MIT-T/1.1): 7,500 psi w/ 3,180 psi on IA Stagger Pump Kickouts Between 90 – 95% of MATP:6,750 psi – 7,125 psi N2 POP-off set pressure (MATP):7,500 psi Treating Line Test Pressure (MATP + 1000 psi):8,500 psi OA Pressure:Maintain open bleed on OA Max Anticipated Proppant Loading:8 PPA Maximum Anticipated Treating Pressure:4,600 psi @ 26 BPM IA Pop-off Set Pressure (~95% of MIT-IA):3,480 psi IA Minimum Hold Pressure (POP-off – 300 psi):3,180 psi Maximum Allowable Treating Pressure (MATP =7,500 psi w/ 3,180 psi on IA Ann hold + MIT-T/1.1): Stagger Pump Kickouts Between 90 – 95% of MATP:6,750 psi – 7,125 psi N2 POP-off set pressure (MATP):7,500 psi Treating Line Test Pressure (MATP + 1000 psi):8,500 psi OA Pressure:Maintain open Pressure information differs from Section 12. CDW 07/22/2025 E-09C Fracture Stimulation PTD: 209-095 Page 12 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 13-3/8” Surface Casing 72#L-80 5,380 2,670 9-5/8” Surface Casing 47#L-80 6,870 4,760 4-1/2” CutLiner 12.6#L-80 8,430 7,500 3-1/2” Production Tubing 9.2#L-80 10,160 10,540 Wellhead McEvoy manufactured wellhead, rated to 5,000 psi. Tubing head adaptor: 13-5/8" 5,000 psi x 4-1/16" 5,000 psi Tubing Spool: 13-5/8” 5,000psi w/ 3-1/8” side outlets Casing Spool: 13-5/8” 5,000psi w/ 3-1/8” side outlets Tree: CIW 4-1/16” 5,000psi -A 10,000-psi rated TreeSaver will be used during the fracturing operation. 9-5/8" below packer open to frac pressure without IA backpressure. CDW 07/21/2025 6,870 E-09C Fracture Stimulation PTD: 209-095 Page 13 SECTION 9 - DATA FOR FRACTURING ZONE AND CONFINING ZONES (20 AAC 25.283, a, 9): *Depths are taken from E-09. >ĺŘıÍťĖĺĲ [ĖťēĺīĺČƅ a"ώĺŕ a" ĺťťĺı «"ŜŜώĺŕ «"ŜŜ ĺťťĺı «"ŜŜ ēĖèħĲôŜŜ «"ŜŜ aĖîŕĺĖĲť ϼ"ÍťŪıϽ >ŘÍèώ@ŘÍî ϼIϯ>Ͻ èēŘÍîôŘώīŪċċ ÍĲîŜťĺĲô ͖͏͕͓ ͖͗͒͗ ͔͕͗͘ ͕͔͓͐ ͔͕͔͑͗͑͏ ͏ϟ͖͖͐ ŕŕôŘώÍĲĲĖĲČ ĖīťŜťĺĲôώϯώÍĲîŜťĺĲô ͖͗͒͗ ͖͓͗͘ ͕͔͓͐ ͖͕͐͘ ͕͕͔͔͗͑͗ ͏ϟ͓͗͒ ÍĲĲĖĲČώēÍīô ēÍīô ͖͓͗͘ ͓͗͗͘ ͖͕͐͘ ͖͑͒͗ ͓͖͖͑͑͐ ͏ϟ͖͓͘ [ĺſôŘώÍĲĲĖĲČώϼiæĤôèťĖŽôϽ ĖīťŜťĺĲôώϯώÍĲîŜťĺĲô ͓͗͗͘ ͐͑͘͏ ͖͑͒͗ ͖͓͓͓ ͑͏͕͖͓͒͐ ͏ϟ͖͔͓ FŪôώēÍīô ēÍīô ͐͑͘͏ ͑͗͑͘ ͖͓͓͓ ͖͔͖͏ ͕͖͔͐͑͏͖ ͏ϟ͓͘͘ F¾ēÍīô ͑͗͑͘ ͔͔͐͘ ͖͔͖͏ ͖͖͗͘ ͖͕͑͐͗͘͏ ͏ϟ͐͘͏ [ώϯώXIb@X ēÍīô ͔͔͐͘ ͐͏͓͑͘ ͖͖͗͘ ͓͔͗͘ ͖͏͕͓͗͐͑ ͏ϟ͓͗͘ I«IFX ÍĲîŜťĺĲô ͐͏͓͑͘ ͐͏͗͒͘ ͓͔͗͘ ͕͕͗͗ ͖͕͒͐͗͗͐ ͏ϟ͕͗͘ E-09C Fracture Stimulation PTD: 209-095 Page 14 SECTION 10 – LOCATION, ORIENTATION, AND A REPORT ON MECHANICAL CONDITION OF EACH WELL THAT MAY TRANSECT CONFINING ZONE (20 AAC 25.283, a, 10): Fault #1 is located within 1/2 mile of the proposed E-09C frac. E-09 frac length estimates are around 175'. Stress orientation is assumed to be N-S based on offset Pt. McIntyre data to the north. The plat shows the location and orientation of each well that transects the confining zone within a ½ mile radius. 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. Fault #1 E-09C Fracture StimulationPTD: 209-095Page 15Casing and Cement assessments for all wells that transect the confining zone (AOR):bÍıô" I"ĖŜťÍĲèôώϯťÍťŪŜĺŕώĺċώÍĲĲĖĲČĺŕôťϏώϼa"ϽĺŕώĺċώÍĲĲĖĲČĺŕôťώϼ«"ŜŜϽiώϼa"Ͻ iώϼ«"ŜŜϽ ¾ĺĲÍīώIŜĺīÍťĖĺĲ ĺııôĲťŜ(ϱ͏͔͖͕͐ϱ͏͔͐ ͔͏ϱ͏͑͘ϱ͑͏͖͐͘ϱ͏͏ϱ͏͏ ͑͏͓͗ДώϯώЭ ͗͏͏͐ϟ͐͘ ϱ͖͑͐͏ϟ͒͒ ͓͖͐͒Д ϱ͓͏͕͐Д īĺŜôî"ĖŘôèťĖĺĲÍīīƅώîŘĖīīôîώ͐͑ϱ͐ϯ͓Гώēĺīôώťĺώ͘Ϡ͏͕͔ДϟώÍĲώ͖͓͐ώĤťŜώ͘ϱ͔ϯ͗Гώ͓͖ϭώbϱ͗͏ώæŪťťŘôŜŜώèÍŜĖĲČώťĺώ͘Ϡ͏͔͖ДώſĖťēώώÍťώ͑Ϡ͐͏͖ДϟώôıôĲťôîώſĖťēώ͑Ϡ͏͐͏èŪϟώ>ťϟώèôıôĲťϟώiώŽĺīŪıôťŘĖèÍīīƅώèÍīèŪīÍťôîώſĖťēώ͒͏҇ώſÍŜēώĺŪťϟ(ϱ͏͔͐͘͘ϱ͏͒͏ ͔͏ϱ͏͑͘ϱ͑͏͖͐͘ϱ͏͐ϱ͏͏ ͑͏͓͗ДώϯώЭ ͗͏͏͐ϟ͐͘ ϱ͖͑͐͏ϟ͒͒ ͓͖͐͒Д ϱ͓͏͕͐Д īĺŜôî(ϱ͏͔ώôƄèĖťôîώ(ϱ͏͔ώÍťώ͘Ϡ͕͐͘ДϠώæôīĺſώÍĲĲĖĲČϠώĲĺťώÍċċôèťĖĲČώĖŜĺīÍťĖĺĲæôēĖĲîώ͘ϱ͔ϯ͗ЋώèÍŜĖĲČϟ(ϱ͏͔͑͏͘ϱ͏͑͐ ͔͏ϱ͏͑͘ϱ͑͏͖͐͘ϱ͏͑ϱ͏͏ ͑͏͒͐ДώϯώЭ ͔͗͐͐ϟ͕͗ ϱ͖͑͒͘ϟ͒͗ ͕͓͕͘Д ϱ͔͔͑͘Д īĺŜôî(ϱ͏͔ώſÍŜώXiώÍťώ͔Ϡ͔͏͏ДώſĖťēώ͗ϟ͔Гώēĺīôϟώ͖ДώèÍŜĖĲČώſÍŜώīÍĲîôîώÍťώ͘Ϡ͕͖͏Дa"ώϼϱ͗Ϡ͗͏͏ώ«"ŜŜϽϟώIťώſÍŜώèôıôĲťôîώſĖťēώ͕͖ææīŜώĺċώ͐͐ϟ͏ŕŕČώīôÍîώÍĲî͒͒ææīŜώĺċώ͔͐ϟ͗ώťÍĖīϟώ>ŪīīώŘôťŪŘĲŜώîŪŘĖĲČώĤĺæϟώiώŽĺīŪıôťŘĖèÍīīƅèÍīèŪīÍťôîώſĖťēώ͒͏҇ώſÍŜēώĺŪťϟ(ϱ͏͔͓͑͐ϱ͓͐͐ ͔͏ϱ͏͑͘ϱ͑͏͖͐͘ϱ͏͒ϱ͏͏ ͑͏͒͐ДώϯώŘĺîŪèôŘ ͕͗͐͐ϟ͒͗ ϱ͖͑͒͘ϟ͕͒ ͕͓͕͘Д ϱ͔͔͑͘Д īĺŜôî(ϱ͏͔ώôƄèĖťôîώ(ϱ͏͔ώÍťώ͐͏Ϡ͏͘͘ДϠώæôīĺſώÍĲĲĖĲČϠώĲĺťώÍċċôèťĖĲČώĖŜĺīÍťĖĺĲæôēĖĲîώ͖ЋώèÍŜĖĲČϟ(ϱ͐͐͐͗͏ϱ͏͔͓ ͔͏ϱ͏͑͘ϱ͑͏͓͖͔ϱ͏͏ϱ͏͏ ͑͐͑͗ДώϯώЭ ͕͖͗͗ϟ͏͗ ϱ͖͓͐͐ϟ͖͑ ͕͔͓͑Д ϱ͕͓͕͓Д īĺŜôî"ĖŘôèťĖĺĲÍīīƅώîŘĖīīôîώ͐͑ϱ͐ϯ͓Гώēĺīôώťĺώ͐͏Ϡ͖͔͐ДϟώÍĲώ͕͕͑ώĤťŜώ͘ϱ͔ϯ͗Гώ͓͖ϭώ[ϱ͗͏ώæŪťťŘôŜŜώèÍŜĖĲČώťĺώ͐͏Ϡ͕͖͐ДϟώôıôĲťôîώſĖťēώ͐Ϡ͓͔͏ώèŪϟώ>ťϟώèôıôĲťϟiώŽĺīŪıôťŘĖèÍīīƅώèÍīèŪīÍťôîώſĖťēώ͒͏҇ώſÍŜēώĺŪťϟ(ϱ͖͐͐͐͘ϱ͖͐͑ ͔͏ϱ͏͑͘ϱ͑͏͓͖͔ϱ͏͐ϱ͏͏ ͑͐͑͗ДώϯώЭ ͕͓͗͘ϟ͗͗ ϱ͖͓͐͐ϟ͖͑ ͕͔͓͑Д ϱ͕͓͕͓Д īĺŜôî(ϱ͐͐ώôƄèĖťôîώ(ϱ͏͔ώÍťώ͗Ϡ͖͗͑ДϠώæôīĺſώÍĲĲĖĲČϠώĲĺťώÍċċôèťĖĲČώĖŜĺīÍťĖĺĲæôēĖĲîώ͘ϱ͔ϯ͗ЋώèÍŜĖĲČϟ(ϱ͖͐͐͗͏ϱ͏͓͗ ͔͏ϱ͏͑͘ϱ͑͏͓͖͏ϱ͏͏ϱ͏͏ ͑͐͒͘ДώϯώЭ ͖͓͖͗ϟ͓͑ ϱ͖͏͘͘ϟ͔͓ ͖͏͗͐Д ϱ͔Ϡ͕͒͘ДīĺŜôî"ĖŘôèťĖĺĲÍīīƅώîŘĖīīôîώ͐͑ϱ͐ϯ͓Гώēĺīôώťĺώ͐͏Ϡ͒͗͏ДϟώÍĲώ͖͑͑ώĤťŜώ͘ϱ͔ϯ͗Гώ͓͖ϭώ[ϱ͗͏ώæŪťťŘôŜŜώèÍŜĖĲČώťĺώ͐͏Ϡ͖͒͒ДϟώôıôĲťôîώſĖťēώ͐Ϡ͔͏͏ώèŪϟώ>ťϟώèôıôĲťϟiώŽĺīŪıôťŘĖèÍīīƅώèÍīèŪīÍťôîώſĖťēώ͒͏҇ώſÍŜēώĺŪťϟ(ϱ͖͐͑͏͓ϱ͑͏͓ ͔͏ϱ͏͑͘ϱ͑͏͓͖͏ϱ͏͐ϱ͏͏ ͑͐͒͘ДώϯώŘĺîŪèôŘ ͖͓͖͗ϟ͒͘ ϱ͖͏͘͘ϟ͔͔ ͖͏͗͐Д ϱ͔Ϡ͕͒͘Д īĺŜôî(ϱ͖͐ώôƄèĖťôîώ(ϱ͖͐ώÍťώ͐͏Ϡ͘͏͖ДϠώæôīĺſώÍĲĲĖĲČϠώĲĺťώÍċċôèťĖĲČώĖŜĺīÍťĖĺĲæôēĖĲîώ͘ϱ͔ϯ͗ЋώèÍŜĖĲČϟXϱ͐͏͖͐͗ϱ͓͐͐ ͔͏ϱ͏͑͘ϱ͖͕͑͐͑ϱ͏͏ϱ͏͏ ͓͕͑ДώϯώЭ ͖͔͒͘ϟ͐͒ ϱ͖͔͑͐ϟ͐͗ ͔Ϡ͑͐͑Д ͓Ϡ͔͑͘Д īĺŜôî"ĖŘôèťĖĺĲÍīīƅώîŘĖīīôîώ͐͑ϱ͐ϯ͓Гώēĺīôώťĺώ͘Ϡ͓͔͗ДϟώÍĲώ͓͑͑ώĤťŜώ͘ϱ͔ϯ͗Гώ͓͖ϭώ[ϱ͗͏æŪťťŘôŜŜώèÍŜĖĲČώťĺώ͘Ϡ͓͖͘ДϟώôıôĲťôîώſĖťēώ͐Ϡ͖͒͘ώèŪϟώ>ťϟώèôıôĲťϟώiŽĺīŪıôťŘĖèÍīīƅώèÍīèŪīÍťôîώſĖťēώ͒͏҇ώſÍŜēώĺŪťϟXϱ͐͏͑͏͐ϱ͏͔͗ ͔͏ϱ͏͑͘ϱ͖͕͑͐͑ϱ͏͐ϱ͏͏ ͓͕͑ДώϯώЭ ͖͔͒͘ϟ͐͒ ϱ͖͔͑͐ϟ͐͗ ͔Ϡ͑͐͑Д ͓Ϡ͔͑͘Д īĺŜôîXϱ͐͏ώôƄèĖťôîώXϱ͐͏ώÍťώ͘Ϡ͔͕͘ДϠώæôīĺſώÍĲĲĖĲČϠώĲĺťώÍċċôèťĖĲČώĖŜĺīÍťĖĺĲæôēĖĲîώ͘ϱ͔ϯ͗ЋώèÍŜĖĲČϟXϱ͐͏͑͏͒ϱ͓͔͐ ͔͏ϱ͏͑͘ϱ͖͕͑͐͑ϱ͏͑ϱ͏͏ ͓͕͑ДώϯώЭ ͖͔͒͘ϟ͐͒ ϱ͖͔͑͐ϟ͐͗ ͔Ϡ͑͐͑Д ͓Ϡ͔͑͘Д īĺŜôîXϱ͐͏ώôƄèĖťôîώXϱ͐͏ώÍťώ͘Ϡ͕͐͘ДϠώæôīĺſώÍĲĲĖĲČϠώĲĺťώÍċċôèťĖĲČώĖŜĺīÍťĖĺĲæôēĖĲîώ͘ϱ͔ϯ͗ЋώèÍŜĖĲČϟƄèƄèƄèƄèƄèƄè E-09C Fracture Stimulation PTD: 209-095 Page 16 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 indicated that there is one mapped fault that transects the Lower Brookian interval and enter the confining sone within the ½ mile radius of the production and confining zone trajectory of the E-09C well. Fracture gradients within the confining zones above and below (Middle and Upper Canning above, HRZ below) will not be exceeded during the fracture stimulation and would therefore confine injected fluids to the undefined pool. The wellbore trajectory is a near vertical (sub 40 degrees) well through the lower Brookian. Maximum stress direction is estimated to be due North, based on Point McIntyre data. The fracs should not reach any mapped faults. The frac is 850’ away from fault #1. The maximum anticipated fracture half length of 175 is short of these distances. Half-length is modeled using hydraulic fracture modeling software and is corroborated by what has been seen in other frac treatments in analogous intervals. The frac stage should have sufficient offset to fault #1 and should not intersect. If a sudden drop in treating pressure or increase in pump rate is seen during the stimulation that cannot be explained by fluids pumped or annular pressure monitoring, pumping operations will stop until a plan forward and explanation can be put forth. >ÍŪīť ēŘĺſ "ĖŘôèťĖĺĲ ŕîſÍŘîŜ ôŘıĖĲÍťĖĺĲ "ĺſĲſÍŘîŜ ôŘıĖĲÍťĖĺĲ >ÍŪīťώϭ͐ ͖͔ϱ͐͏͏Д "b ŕŕôŘώÍĲĲĖĲČ ÍŜôıôĲť s E-09C Fracture Stimulation PTD: 209-095 Page 17 SECTION 12 – PROPOSED HYDRAULIC FRACTURING PROGRAM (20 AAC 25.283, a, 12): Proposed Procedure: 1. Conduct safety meeting, inspect location, and review 10-403. 2. Ensure all pre-frac well work has been completed, and the tubing & IA are freeze protected. 3. MIRU frac equipment and associated frac tanks. 4. Pressure test surface lines to at least 8,115 psi. 5. Test IA Pop-off system to ensure functioning properly. IA Pop-off to be set at 3,325 psi. 6. Bring IA pressure up to a hold pressure of 3,025 psi. 7. Pump the fracture stimulation per the proposed pump schedule below. Maximum allowable treating pressure is 7,115 psi. 8. RDMO frac equipment. Ensure tubing is freeze protected. 9. Return the well to production / flowback post slickline gas lift and contingent coiled tubing cleanout. Fracture Stimulation Pump Schedule: There are twooverpressure 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) 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. ťÍČôώϭ >īŪĖî ťÍČô ŘĺŕώĺĲ ϼŕŕÍϽ ÍťôώϼæŕıϽ «ĺīŪıôώϼææīŜϽ Ūıώ«ĺīŪıô ϼææīŜϽ ŘĺŕŕÍĲťώbÍıô ŘĺŕŕÍĲť ϼϭϽ ŪıώŘĺŕŕÍĲť ϼϭϽ ͐ >®ώſϯώîîŜ IĲĤôèťĖĺĲώôŜť ͑͑ ͐͑ ͐͑ ͑ēŪťîĺſĲ ͒ èĖî èĖî ͓͑ ͐͑ ͓͑ ͓ ͒͏ϭώ³ϱ[ĖĲħ Íî ͓͑ ͔͖͒ ͒͗͐ ͔ ͒͏ϭώ³ϱ[ĖĲħ >īÍť ͐ ͓͑ ͕͒ ͓͖͐ ͑͏ϯ͓͏ώÍŘæĺ[Ėťô ͔͐͏͏ ͔͐͏͏ ͕ ͒͏ϭώ³ϱ[ĖĲħ >īÍť ͑ ͓͑ ͓͗ ͓͕͓ ͑͏ϯ͓͏ώÍŘæĺ[Ėťô ͓͏͏͏ ͔͔͏͏ ͖ ͒͏ϭώ³ϱ[ĖĲħ >īÍť ͒ ͓͑ ͕͏ ͔͓͑ ͑͏ϯ͓͏ώÍŘæĺ[Ėťô ͖͔͏͏ ͐͒͏͏͏ ͗ ͒͏ϭώ³ϱ[ĖĲħ >īÍť ͒ϟ͔ ͓͑ ͕͔ ͔͗͘ ͑͏ϯ͓͏ώÍŘæĺ[Ėťô ͕͔͑͘ ͕͔͑͑͑ ͘ ͒͏ϭώ³ϱ[ĖĲħ >īÍť ͓ ͓͑ ͖͐ ͕͕͐ ͑͏ϯ͓͏ώÍŘæĺ[Ėťô ͐͑͏͏͏ ͓͕͔͒͑ ͐͏ ͒͏ϭώ³ϱ[ĖĲħ >īÍť ͓ϟ͔ ͓͑ ͗͒ ͖͓͓ ͑͏ϯ͓͏ώÍŘæĺ[Ėťô ͔͖͔͐͏ ͔͏͖͔͒ ͐͐ ͒͏ϭώ³ϱ[ĖĲħ >īÍť ͔ ͓͑ ͔͘ ͗͒͘ ͑͏ϯ͓͏ώÍŘæĺ[Ėťô ͑͏͏͏͏ ͖͏͖͔͒ ͐͑ ͒͏ϭώ³ϱ[ĖĲħ >īÍť ͔ϟ͔ ͓͑ ͐͏͖ ͓͖͘ ͑͏ϯ͓͏ώÍŘæĺ[Ėťô ͓͖͔͑͏ ͔͔͐͑͘ ͐͒ ͒͏ϭώ³ϱ[ĖĲħ >īÍť ͕ ͓͑ ͐͏͖ ͐͏͔͓ ͑͏ϯ͓͏ώÍŘæĺ[Ėťô ͖͑͏͏͏ ͔͐͑͑͐͑ ͓͐ ͒͏ϭώ³ϱ[ĖĲħ >īÍť ͕ϟ͔ ͓͑ ͐͐͘ ͖͐͐͒ ͑͏ϯ͓͏ώÍŘæĺ[Ėťô ͔͒͑͏͏ ͔͓͕͔͐͑ ͔͐ ͒͏ϭώ³ϱ[ĖĲħ >īÍť ͖ ͓͑ ͗͒ ͔͕͐͑ ͑͏ϯ͓͏ώÍŘæĺ[Ėťô ͓͔͑͏͏ ͖͔͐͐͑͘ ͕͐ ͒͏ϭώ³ϱ[ĖĲħ >īÍť ͖ϟ͔ ͓͑ ͖͐ ͖͐͒͑ ͑͏ϯ͓͏ώÍŘæĺ[Ėťô ͔͑͑͏͏ ͑͏͕͔͐͑ ͖͐ ͒͏ϭώ³ϱ[ĖĲħ >īÍť ͗ ͓͑ ͖͐ ͐͒͘͘ ͑͏ϯ͓͏ώÍŘæĺ[Ėťô ͓͑͏͏͏ ͔͕͔͑͑͑ ͐͗ >®ώſϯώîîŜ >īŪŜē ͓͑ ͐͐͒ ͔͐͐͑ ͐͘ "ĖôŜôī >ŘôôƏôώŘĺťôèť ͔ ͒͏ ͔͓͐͑ 7,115 3,325 3,025 Pressures differ from frac summary on pages 3 and 4 and Section 7. CDW 07/22/2025 E-09C Fracture Stimulation PTD: 209-095 Page 18 Frac Dimensions: Frac #MD Location, ft TVDss top, ft TVDss Bottom, ft Frac Half-Length, ft 1 9,040’-9,050’~-7,155 ~-7,525 ~175’ Frac Modelling: Maximum Anticipated Treating Pressure: ~4,600 psi Surface pressure and fracture dimensions were modeled using E-09 logs Disclaimer Notice: This model was generated using commercially available modeling 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. 4,600 psi E-09C Fracture Stimulation PTD: 209-095 Page 19 Pre-Job Anticipated Chemicals to be pumped: E-09C Fracture Stimulation PTD: 209-095 Page 20 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 a portable well test separator. All liquids will be captured and either sent to production facilities or diverted to flowback tanks if solids percentage becomes too high for our production facility 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 0.5% solids, at which time the produced fluids meet the GC1 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 GC1 processing will be hauled to another facility’s slop tank 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. 1 Dewhurst, Andrew D (OGC) From:Leif Knatterud <Leif.Knatterud@hilcorp.com> Sent:Wednesday, 23 July, 2025 09:27 To:Dewhurst, Andrew D (OGC) Cc:Lau, Jack J (OGC); Wallace, Chris D (OGC); Benjamin Siks Subject:RE: [EXTERNAL] PBU E-09C Frac Sundry (325-426): Questions Follow Up Flag:Follow up Flag Status:Flagged Good morning Andy, See the response from Ben below. Please let us know if you have any further questions. Thanks, Leif Knatterud 432-227-4342 From: Benjamin Siks <bsiks@hilcorp.com> Sent: Wednesday, July 23, 2025 8:39 AM To: Leif Knatterud <Leif.Knatterud@hilcorp.com> Subject: RE: [EXTERNAL] PBU E-09C Frac Sundry (325-426): Questions x Would you double-check to see if the PBU K-09/B/B/BPB1 wellbores are within the ½-mile radius? x The K-09/B/PB1 wells do not penetrate the objective lower Brookian sands within the ½ radius of the proposed E-09C frac. K-09/B/PB1 are all just outside the of radius at the lower Brookian shown by the blue circles on the map below. The lateral K-09C goes into the ½ radius, but at the much much deeper Ivishak level. Zoomed in map provided below: 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. 2 x x Does Fault #1 intersect the PBU E-09 wellpath at any point? x The original wellbore E-09 does cross Fault #1 at ~10054’ MD (-8197’ TVdss) in the Kingak C shales. This is approximately 650’ TVDss below our objective lower Brookian sands. x How were the frac gradients estimated for the conƱning zones? x The frac gradients were estimated for the conƱning zones using the following workƲow (adopted from legacy BP work) 3 o 1. Calculate the Overburden Curves – Utilizing oƯset well RHOB, a TVDss datum and a constant of 0.4335 to calculate the Overburden stress. This is then converted to a PSI/Ft for OVB gradients (0.95 to 1.09) o 2. Look at oƯset wells, mud logs, any historic data in the area, we see everything is at a hydrostatic gradient, so we can then calculate the pore pressure (TVDss datum * 0.44 psi/ft). o 3. Next we will need a Poisson ratio. This was derived from oƯset sonic logs, oƯset mechanical core studies (Schrader bluƯ), or back calculations from LOT/FITs. A sense check on what ratios to expect with facies. Consolidation also plays a key role. o o 4. Utilizing all this information, we use Eaton’s Fracture Gradient Equation. This is the legacy BP workƲow for fracture gradient estimation. This will give us our pressure, then we can convert it to a gradient using our depth datum. 4 o From: Leif Knatterud <leif.knatterud@hilcorp.com> Sent: Wednesday, July 23, 2025 6:35 AM To: Benjamin Siks <bsiks@hilcorp.com> Subject: FW: [EXTERNAL] PBU E-09C Frac Sundry (325-426): Questions Good morning sir. Could you please help me out with these. Thanks, Leif Knatterud 432-227-4342 From: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Sent: Tuesday, July 22, 2025 6:02 PM To: Leif Knatterud <leif.knatterud@hilcorp.com> Cc: Wallace, Chris D (OGC) <chris.wallace@alaska.gov>; Lau, Jack J (OGC) <jack.lau@alaska.gov> Subject: [EXTERNAL] PBU E-09C Frac Sundry (325-426): Questions Leif, I am completing my review of the PBU E-09C frac sundry and have a few questions: x Would you double-check to see if the PBU K-09/B/B/BPB1 wellbores are within the ½-mile radius? x Does Fault #1 intersect the PBU E-09 wellpath at any point? CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. 5 x How were the frac gradients estimated for the conƱning zones? Thanks, Andy Andrew Dewhurst Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission 333 W. 7th Ave, Anchorage, AK 99501 andrew.dewhurst@alaska.gov Direct: (907) 793-1254 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. 20 AAC 25.283 Hydraulic Fracturing Application – Checklist PBU E-09C (PTD No. 209-095; Sundry No. 325-426) Paragraph Sub-Paragraph Section Complete? AOGCC Page 1 July 23, 2025 (a) Application for Sundry Approval (a)(1) Affidavit Provided with application. A.Dewhurst 22JUL25 (a)(2) Plat Provided with application. A.Dewhurst 22JUL25 (a)(2)(A) Well location Provided with application. PBU E-09C lies in Section 6 of T11N, R14E, UM. A.Dewhurst 22JUL25 (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 October 24, 2024), there are no wells are used for drinking water purposes are known to lie within ½ mile of the surface location of PBU E-09C. There are no subsurface water rights or temporary subsurface water rights within 17 miles of the surface location of PBU E-09C. A.Dewhurst 22JUL25 (a)(2)(C) Identify all well types within ½ mile List of wells provided with application. A.Dewhurst 22JUL25 (a)(3) Freshwater aquifers: geological name; measured and true vertical depth None. PBU E-09C is located within the West Operating Area of Prudhoe Bay. According to Aquifer Exemption Order 1, the freshwater aquifers are exempt. A.Dewhurst 22JUL25 (a)(4) Baseline water sampling plan None required. A.Dewhurst 22JUL25 (a)(5) Casing and cementing information Provided with application. Schematic provided. CDW 07/22/2025 (a)(6) Casing and cementing operation assessment This well has multiple deep sidetracks that have been plugged back. Relevant casing is original 9-5/8” and perforations at 9036-9041 ft 13-3/8” casing cemented with no losses. 497 bbl pumped, cement calc back to surface. CDW 07/22/2025 20 AAC 25.283 Hydraulic Fracturing Application – Checklist PBU E-09C (PTD No. 209-095; Sundry No. 325-426) Paragraph Sub-Paragraph Section Complete? AOGCC Page 2 July 23, 2025 9-5/8” casing cemented 2 stage, with RCBL (6/30/2025) run showed TOC of 7060 ft MD. Tubing packer set at 8777 ft. (a)(6)(A) Casing cemented below lowermost freshwater aquifer and conforms to 20 AAC 25.030 Only exempt freshwater aquifers. (See Section (a)(3), above.) A.Dewhurst 22JUL25 (a)(6)( B) Each hydrocarbon zone is isolated Yes: Surface 13-3/8” casing was set at 2671’ MD and cemented. 497 bbl pumped, no losses. Sag River and Ivishak hydrocarbon zones are isolated by a reservoir abandonment plug. The targeted Brookian hydrocarbon zone is isolated by the 9-5/8” casing cement and verified by CBL. CDW 07/22/2025 A.Dewhurst 22JUL25 (a)(7) Pressure test: information and pressure-test plans for casing and tubing installed in well Provided with application. 3665 psi MITIA, 4754 psi MITT. CDW 07/22/2025 (a)(8) Pressure ratings and schematics: wellbore, wellhead, BOPE, treating head Provided with application. 10K psi tree saver max. frac. Pressure 4600 psi with MAWP 7500 (7115 psi) psi. Pump knock out 6750-7125 psi., lines test 8115 psi minimum. CDW 07/22/2025 (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: Colville mudstones, shales, and siltstones that have an aggregate thickness of 724’ true vertical thickness (TVT) with an estimated fracture gradient of 0.84 to 0.97 psi/ft. Fracturing Zone: Lower Canning sandstone consisting of ~200’ thick zone of sandstones and siltstones with an estimated fracture gradient of 0.75 psi/ft. A.Dewhurst 22JUL25 20 AAC 25.283 Hydraulic Fracturing Application – Checklist PBU E-09C (PTD No. 209-095; Sundry No. 325-426) Paragraph Sub-Paragraph Section Complete? AOGCC Page 3 July 23, 2025 Lower confining zone: Hue and HRZ shales with an aggregate TVT of 345’. Fracture gradient expected to range from 0.91 to 0.95 psi/ft. Specific depths are provided in the application. (a)(10) Location, orientation, report on mechanical condition of each well that may transect the confining zones and sufficient information to determine wells will not interfere with containment of hydraulic fracturing fluid within ½ mile of the proposed wellbore trajectory It is highly unlikely that any of the wells or wellbores within a ½-mile radius will interfere with hydraulic fracturing fluids from this operation because of cement isolation and / or separation distance. Hilcorp has identified (and platted) 251 wells (including sidetracks and plug backs) and identified 11 wells that transect the confining zone within ½ mile of PBU E-09C. For these 11 wells (including sidetracks and plug backs), Hilcorp has provided a cementing review including TOC (CBL log or volumetric assumptions) and zonal isolation. AOGCC has reviewed a subset of these wells and concurs. CDW 07/22/2025 A.Dewhurst 23JUL25 (a)(11) Faults and fractures, Sufficient information to determine no interference with containment of the hydraulic fracturing fluid within ½ mile of the proposed wellbore trajectory One fault: The operator has identified one fault within a ½-mile radius of PBU E-09C. This fault lies approximately 850’ from the proposed fracturing interval, and the modeled half-length of the induced fracture is 175’. It is unlikely that this fault 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. A.Dewhurst 23JUL25 (a)(12) Proposed program for fracturing operation Provided with application. CDW 07/22/2025 (a)(12)(A) Estimated volume Provided with application. 1542 bbl total dirty vol. 225K lb total proppant CDW 07/22/2025 (a)(12)(B) Additives: names, purposes, concentrations Provided with application. CDW 07/22/2025 20 AAC 25.283 Hydraulic Fracturing Application – Checklist PBU E-09C (PTD No. 209-095; Sundry No. 325-426) Paragraph Sub-Paragraph Section Complete? AOGCC Page 4 July 23, 2025 (a)(12)(C) Chemical name and CAS number of each Provided with application. SLB disclosure provided. CDW 07/22/2025 (a)(12)(D) Inert substances, weight or volume of each Provided with application. CDW 07/22/2025 (a)(12)(E) Maximum treating pressure with supporting info to determine appropriateness for program Simulation shows max surface treating pressure 4600 psi. Max. 7500 psi allowable treating pressure. Max pressure is 6750-7125 pump trips. With 3180 psi back pressure IA (IA popoff set 3480 psi), max tubing differential should be 4320 psi. CDW 07/22/2025 (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 175’ according to the Operator’s computer simulation. Anticipated height of the induced fractures will be 370’ so induced fractures may penetrate a short distance into the overlying confining Canning confining layer. It may also penetrate into, but not through, the underlying HRZ shale that provides lower confinement. A.Dewhurst 23JUL25 (a)(13) Proposed program for post-fracturing well cleanup and fluid recovery Well cleanout and flowback procedure provided with application. No disposal identified, but PBU goes to GNI. CDW 07/22/2025 (b)Testing of casing or intermediate casing Tested >110% of max anticipated pressure 3025 psi back pressure( or 3180 psi) test to 3665 psi, popoff set as 3325 (or 3480 psi). CDW 07/22/2025 (c) Fracturing string (c)(1) Packer >100’ below TOC of production or intermediate casing Tubing packer set at 8777 ft. 9-5/8” casing cemented with RCBL (6/30/2025) run showed TOC of 7060 ft MD. CDW 07/22/2025 (c)(2) Tested >110% of max anticipated pressure differential Tubing test of 4754 psi. Max pressure differential is estimated as 1475 psi (7500 with 3180 psi backpressure) so test satisfies 110%. CDW 07/22/2025 (d) Pressure relief valve Line pressure <= test pressure, remotely controlled shut-in device 8115 psi line pressure test, pump knock out 6750-7125 psi. IA PRV set as 3325 psi or 3480 psi. CDW 07/22/2025 20 AAC 25.283 Hydraulic Fracturing Application – Checklist PBU E-09C (PTD No. 209-095; Sundry No. 325-426) Paragraph Sub-Paragraph Section Complete? AOGCC Page 5 July 23, 2025 (e) Confinement Frac fluids confined to approved formations Provided with application. CDW 07/22/2025 (f) Surface casing pressures Monitored with gauge and pressure relief device IA PRV set at 3325 psi or 3480 psi. Surface annulus open. Frac pressures continuously monitored. CDW 07/22/2025 (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 07/22/2025 (g)(1) Notify AOGCC within 24 hours (g)(2) Corrective action or surveillance (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). ADD 22JUL25 (k) Confidential information Clearly marked and specific facts supporting nondisclosure Non-confidential well. ADD 22JUL25 (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. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Lau, Jack J (OGC) To:AOGCC Records (CED sponsored) Subject:FW: E-09C RBT Cement Log (209-095) Sundry 325-309 Date:Tuesday, July 1, 2025 9:35:30 AM Attachments:E09_RCBL_30JUNE2025.pdf Log Attached From: Finn Oestgaard - (C) <Finn.Oestgaard@hilcorp.com> Sent: Tuesday, July 1, 2025 8:50 AM To: Lau, Jack J (OGC) <jack.lau@alaska.gov> Subject: E-09C RBT Cement Log Morning Jack, Here’s our RBT Log for E-09C. Looks like we have decent cement up to ~8,200’, mediocre/poor up to 7,224’, and decent up to TOC @ 7,060’ I picked our TOC based off of a 70% bond cutoff Let me know if you’d like to discuss. Thanks, Finn Finn Oestgaard GBP GC1 Operations Engineer D,E,F,G,K,P,Y pads 907-564-5026 office 907-350-8420 mobile The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 3 m0n orn-o0 03 �0700,;70 0 r o V ;U = c n o " m 3 et 3 o x 3 _. m m p� x 0 a 0 �a M M c _ N = m Company HILCORP NORTH SLOPE, LLC. z m�am m�� Z�r3 �>•o� ? T i ` '�<Ln.mn�3 �n�c r0. y m Well E-09C O d Field PRUDHOE BAY N3 >--iw 3 a T T 3 = 3 County N. SLOPE State AK r r W o n a 2 n 0 3 o v n TI n - W o N K p C d O 3 ^ N Z N t D t 0 0 W N C > O O A O A O W N Z m O O" �_ T p n tp 0 fD O O O_ C Z W W = o `G 13 3 w v cn� r- CDI V N W N o rn „N z Z -a m 2 r O s N W M cnm C z ^ O ^ O W O 0C)O T N ' Z CD O MM T TV 2 < S fD L rn fD 0'< (N c I0 �� W N T f 0 2 O as=�`0` a o D w 00 n 3 Ill �7 U) 0 G<0 O 9n jCD .r o o A V O N. C O _ 0 W cn Cn O D r Z r 0 o C� Z (n rom G)o,T. TV r m (n(n cc" T1� �, 0��.-U�� "T m rT1W M O 1 �1 3 o D rn w rn m 5 r M a a � z o o `' z o Z M co r n z m 2 V O D W W � � S <<< Fold Here >>> HALLIBURTON DOES NOT GUARANTEE THE ACCURACY OF ANY INTERPRETATION OF THE LOG DATA, CONVERSION OF LOG DATA TO PHYSICAL ROCK PARAMETERS OR RECOMMENDATIONS WHICH MAY BE GIVEN BY HALLIBURTON PERSONNEL OR WHICH APPEAR ON THE LOG OR IN ANY OTHER FORM. ANY USER OF SUCH DATA, INTERPRETATIONS, CONVERSIONS, OR RECOMMENDATIONS AGREES THAT HALLIBURTON IS NOT RESPONSIBLE EXCEPT WHERE DUE TO GROSS NEGLIGENCE OR WILLFUL MISCONDUCT, FOR ANY LOSS, DAMAGES, OR EXPENSES RESULTING FROM THE USE THEREOF. Comments LOG TIED INTO TECHLOG GAMMA RAY FROM 27-JUN-2025 FREE PIPE CALIBRATION @ 1000' REPEAT PASS FROM 91 00'TO 8900' 4.5" PULLED BY RIG Current Wellbore Schematic: as of 5/15/2025 TTEE= 4"5M(7W VE LHEAD= ACRATOR= NINL KB. HE HAKERC 60.03' KOP= 30.76' 10860' Mat Angb = Dabm MD= 95' Q13075' 10849' OabmTVD= Bw SS RWO — Brookian UHRC Well: E-09C PTD:209095 API: 50-029-20466-03 E 09C L!R"WELL ANGLE> 701 @ ID955'—OlaG WELL &ES09A & E-09B NOT SHOWN BEOW WHPSTOCK"'06119109: X NP @ 9519' f1.AMAGID IX98NG 2002 MILLING OPS. 13-3tr=72M, L-80, D=1234-r 2671' " -, Calculated TOC from volumetrics "7,434 IV Calculated lead cement from volumetrics-8,750 Minimum ID=1.876" @ 9463' LBR PLUG HOLDER BUSHING OF 5' LNt OF 7" LNt -9800' &Sl8' CSG, 4711, L-80. D=8.88' 10213' 7" 1-K 29M, L-80, A371 W. D= 6.164' 10909' R 8.81M, L-911 STL, .W87 W, 1)=2997 10808' " 3-3Mr WHIWO0K(89✓23169) 10818' ' RA TAG (11111AM 1061V ' PEIRMTDN SLRWRY Rff LOG: MGM GR0OJNN0- ON 1121109 A NGLE AT TOP PEZF: 84- 012160 Note: Refer to Production OB for historical pert data SIZE SK NIHNAL OpnlSgz SHOT SOZ 1.56 6 11/50-11630 S 111211D903118113 1.56 5 11810-12020 S 11121Po903118113 1,56 6 12160-12280 0 1121109 1.56 6 12400-12860 0 11r211o9 1.56 6 12900-12960 0 11r21M19 1.56 6 13050 -13190 OIC 110109 11211NR)11:AJ AS UI; 11 -V; 2083- —j4-12'OTIS SSSV NP(9-CFq, D=3.813- ST MD ND MVITYPEI VLV LATC4ORT P DATE 3 4384 4263 36 hE2 OM1r RM 0 11M821 2 82M 070 44 M3t f1M1/ FN 0 1222121 1 9413 7736 37 hHt RM 0 01I19/95 L:aIj GMT RErANF3t (r IrSLV. D=3.OP SEAL ASSY, 1)=3.94' 1BPFKR D= 4.ODO' R, 1)=3.813' j BW H4-1Ir2-W.EG,D=3.958"I f3ADTT NOT LOOC� i 10103' 3.70" NUt DEPLOYMENT SLV, 10=31 10112' 3-1rr HEs XN Nip. D=2.75P MLLOLfT WINDOW (E-D9C) 10fi0T - 10612' Fvoww--�3-12-x3-vi6'Xo.D=2.786- 2-318' LNt, 4.7M, L-80, .0039 bpf, D=1.992' H1321T --Y PRLC DE BAY LW WE.L: E09C Pam No: rtO90850 AR No: 50029-20466-03-00 SEC 6, T11N R14E 243 FML & 5DO' FEL COMVENTS DEl"HCOR43m" 00(1111821) PLUG & RLUFBO DYH (12 .EDEVO PLUG (WAO) HALL OIDPCMl-FLER Fiborp North Slope, LLC a 44W 411,10 ri :LI qmw Li Adulp _qw OLIMI�mim�MLWL Database File e-09—rcbl-30jun25-db Dataset Pathname .. Presentation. ... :00-0 d by Depth CCL Amplitude Amplitude MIN Sector Amplitude , Ilmmlllm mmm"mmmmmmmm ��M ommm mmm � mm1/lm mmmmmmmmmmmmmmm W ammmm mmmmmmmmmmmmmmm W mmmmm1fmm11 m MMMMMEMMMMMMMMM W t\mmmmmmm111m MMMMMEMMMMMMMMM W W 11mmmm111mm111m MMMMMEMMMMMMMMM 1mmmmmmmmfllm MMMMMEMMMMMMMMM 7W IEMMWMaW 11 MMMMMEMMMMMMMMM � W1MMMMMM 11 mmmmmi■mmmmmmmmm "MMMMMMM111M mmmmmimmmmmmmmmm M W mmmmm1fmm111m MMMMMI■MM ■mmmmmmm111m MMMMMI■MW W mmmmmmmmitlm MMMMMI■MM�� mmmmmlfmm111m MMMMMI■MW�� ■1MMMMMMM111M MMMMMIMMMM�� ummmmummillm mmmmmmmmmmmmmmm MMMMMOMM"lm mmmrmmmmmmmmmm 1UMMMMlM mmmmmmmmmmmmmm 1mmmmm11m�111� mmmma1•mmmmmmmmm \\MMMMMMMIIIM mmmmmommmmmmmmm ■immmmmmm111m mmmmEjmmmmmmmmmm flmmmmllfmm111m mmmmm1mmmmmmmmmm r1mmmmmmmitIm mmmmff1mmm�� w7mmmmmmm111m mmmmommmm�� 11mmmmmmm{IIm mmmmmommmmmmmm M 1MMW rimmmmmmm111m mmmml1mmmmmmmm M ■1mmmm1lm U mmmmmimmmmmmmm M nimmmm17mm111m MMMMEMMMMMMMM M s1mmmmmmmi11m MMMMEMMMMMMMM M a1mmmmmmm111m mmmmmmmmmmmmm M� /AMMMMI MMIIIM mmmmmummmmmmmmm� immmmmIttmmlllm mmmmm •mmmmmmmm lmmmmmmmmuii iiiw iiiiiiiiiEEC Sensor Offset (ft) Schematic Description ft O.D. (in) Weight(lb -Length CHD-1-7/16 (12345678) 128 1.44 1.50 Monocable Head Assembly swivel -Evans 2.00 1.69 5.00 1 11/16" Evans Swivel CCL GR 23.76 21.50 NWT-1-11/16" 1.6875" WEIGHT BAR NWT-1-11/16" 1.6875" WEIGHT BAR NWT-2.0" 2.0" WEIGHT BAR TTTCU-002 (12146420) Through Tubing Telemetry Cartridge - Ultrawire AUH-001 (214834) Adaptor Ultrawire/Halliburton TT_KNUCKLE-1-11/16" 1-11/16" TT KNUCKLE JOINT TT_KNUCKLE-1-11/16" -1-11/16" TT KNUCKLE JOINT PRC-065 (11581478) 4 ARM- Production Roller Centraliser 7.00 5.00 5.00 7.65 0.38 1.00 1.00 3.00 1.69 1.69 2.00 1.69 1.69 1.69 1.69 2.75 84.00 84.00 120.00 37.70 3.00 1.00 1.00 13.00 CBLTEMP 8.45 RBT-004 (12192807) 9.48 3.13 140.00 WVF3FT 8.45 Radial Bond Tool (UW 3 1/8) 20K Rated WVF5FT 7.45 CBLTEMP 3.32 PRC-065 (12210331) 3.00 2.75 13.00 4 ARM- Production Roller Centraliser LLMTEN 0.00 BUL-SNDX (10000766) 0.32 1.69 1.50 SNDX TERM - 5/8" SR Dataset: e-09_rcbl_30jun25.db: field/well/runl/pass8 Total length: 46.11 ft Total weight: 504.70 lb O.D.: 3.13 in Company HILCORP NORTH SLOPE, LLC. Well E-09C Field PRUDHOE BAY County N. SLOPE state AK RADIAL CEMENT HALLIBURTOP, BOND LOG CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Lau, Jack J (OGC) To:AOGCC Records (CED sponsored) Subject:FW: E-09C RBT Cement Log (209-095) Sundry 325-309 Date:Tuesday, July 1, 2025 9:34:51 AM From: Lau, Jack J (OGC) Sent: Tuesday, July 1, 2025 9:32 AM To: Finn Oestgaard - (C) <Finn.Oestgaard@hilcorp.com> Subject: RE: E-09C RBT Cement Log Finn, I agree the CBL shows satisfactory cement isolation behind the 9-5/8” above the proposed perfs. Jack From: Finn Oestgaard - (C) <Finn.Oestgaard@hilcorp.com> Sent: Tuesday, July 1, 2025 8:50 AM To: Lau, Jack J (OGC) <jack.lau@alaska.gov> Subject: E-09C RBT Cement Log Morning Jack, Here’s our RBT Log for E-09C. Looks like we have decent cement up to ~8,200’, mediocre/poor up to 7,224’, and decent up to TOC @ 7,060’ I picked our TOC based off of a 70% bond cutoff Let me know if you’d like to discuss. Thanks, Finn Finn Oestgaard GBP GC1 Operations Engineer D,E,F,G,K,P,Y pads 907-564-5026 office 907-350-8420 mobile The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Lau, Jack J (OGC) To:AOGCC Records (CED sponsored) Subject:FW: E-09CPerf interval shift (209-095) Sundry 325-309 Date:Tuesday, July 1, 2025 9:34:40 AM Attachments:image001.png From: Lau, Jack J (OGC) Sent: Tuesday, July 1, 2025 9:33 AM To: 'Finn Oestgaard - (C)' <Finn.Oestgaard@hilcorp.com> Subject: RE: E-09CPerf interval shift The slight shift in perf depth requested below is approved. Jack From: Finn Oestgaard - (C) <Finn.Oestgaard@hilcorp.com> Sent: Tuesday, July 1, 2025 8:55 AM To: Lau, Jack J (OGC) <jack.lau@alaska.gov> Subject: E-09CPerf interval shift Hi Jack, Wanted to notify you of our final perf interval for E-09C, we are interested in shifting slighty above original interval & perforating a 5’ interval from 9,036’-9,041’. The initial perf interval in the Sundry was described as below: Please let me know if you’d like to discuss. Thanks! Finn Finn Oestgaard GBP GC1 Operations Engineer D,E,F,G,K,P,Y pads 907-564-5026 office 907-350-8420 mobile The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entitynamed 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'sphone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onwardtransmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by thecompany in this regard and the recipient should carry out such virus and other checks as it considers appropriate. MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg DATE: P.I. Supervisor SUBJECT: FROM: Petroleum Inspector Section:6 Township:11N Range:14E Meridian:Umiat Drilling Rig:Rig Elevation:Total Depth:13217 ft MD Lease No.:ADL0028304 Operator Rep:Suspend:P&A:X Surface:13 3/8"O.D. Shoe@ 2671 Feet Csg Cut@ Feet Intermediate:9 5/8"O.D. Shoe@ 10213 Feet Csg Cut@ Feet Liner:7"O.D. Shoe@ 10569 Feet Csg Cut@ Feet Liner:5"O.D. Shoe@ 10607 Feet Csg Cut@ Feet Liner:3 1/2" x 3 3/16"O.D. Shoe@ 10607 Feet Csg Cut@ Feet Liner:2 3/8"O.D. Shoe@ 13217 Feet Tbg Cut@ Feet Tubing:4 1/2"O.D. Tail@ 9542 Feet Type Plug Founded on Depth (Btm)Depth (Top)MW Above Verified Perforation Retainer 9440 ft 9395 ft 15.8 ppg Wireline tag Initial 15 min 30 min 45 min Result Tubing 3798 3753 3736 IA 3803 3759 3745 OA 5 3 4 Initial 15 min 30 min 45 min Result Tubing IA OA Remarks: Attachments: Max Dickerman Casing/Tubing Data (depths are MD): Plugging Data (depths are MD): Pollard Wireline ran 150 pound tool string with a 2-1/8 inch drive down bailer. Wireline tagged the cement at 9395 ft MD and a good small sample of good cured cement was attained in the bailer. 45 feet of cement on top of the retainer (25 ft required). 8.3 bbls was pumped in and returned during the CMIT. June 12, 2025 Guy Cook Well Bore Plug & Abandonment PBU E-09C Hilcorp North Slope LLC. PTD 2090950; Sundry 325-309 None Test Data: P Casing Removal: rev. 3-24-2022 2025-0612_Plug_Verification_PBU_E-09A_gc                   CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Lau, Jack J (OGC) To:Finn Oestgaard - (C) Subject:RE: E-09 Cement Job path forward Sundry 325-309 (209-095) Date:Monday, June 9, 2025 12:14:00 PM Attachments:image001.png Sounds good. Thanks for the update Finn. Jack From: Finn Oestgaard - (C) <Finn.Oestgaard@hilcorp.com> Sent: Friday, June 6, 2025 1:44 PM To: Lau, Jack J (OGC) <jack.lau@alaska.gov> Subject: E-09 Cement Job path forward Sundry 325-309 Hi Jack, tried to call, left a message. Following up with this email. E-09C – The RWO/Recomplete to the Brookian where the well previously locked up on us before the cement reached the retainer during our Ivishak res abndn and we submitted a Change Request Sundry 325-309. So we got back on the well with coil & milled out 1,300’ of cement in the tubing and retainer set @ 9,425, recovered the retainer core in the top of liner along with some other debris with 1.75” coil. Still no injectivity so brought out a 1.5” coil unit and ran a motor mill w/ gel sweeps to 13,150’ still 1:1 returns… Pulled up into the tubing for an injectivity test 0.24 BPM @ 2055 psi & 0.4 bpm @ 2235 psi. After much discussion with the field and other ops engineers, we feel the most effective way to get a reservoir abandonment is forego the retainer and lay cement in. Our plan is to lay in cement from 10,600 to a target TOC of 9,400 for the Ivishak abandonment. The top of the Ivishak pool is @ 10,394’. The base of where we start laying in @ 10,600’ gives us 200’ of assurance that we’ve cemented the base of the Kingak (confining zone for Ivishak) & our target TOC is above previous (coil & fullbore) retainer target set depths. Here’s a graphic of the well: Please let me know if you would like to discuss at all, Thank you! Finn Finn Oestgaard GBP GC1 Operations Engineer D,E,F,G,K,P,Y pads 907-564-5026 office 907-350-8420 mobile The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 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 perfs require a spacing exception due to property boundaries?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 ServiceDevelopmentStratigraphicExploratory Authorized Name and Digital Signature with Date: Authorized Title: Contact Name: Contact Email: Contact Phone: AOGCC USE ONLY Commission Representative: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Location ClearanceMechanical Integrity TestBOP TestPlug Integrity Other Conditions of Approval: Post Initial Injection MIT Req'd?Yes No Subsequent Form Required: Approved By:Date: APPROVED BY THE AOGCCCOMMISSIONER PBU E-09C Recomplete to Brookian Hilcorp North Slope, LLC 3800 Centerpoint Dr, Suite 1400, Anchorage, AK 99503 209-095 50-029-20466-03-00 Statewide ADL 0028304 13217 Intermediate Liner Liner Liner Liner 8987 10181 852 1068 504 3765 7434 9-5/8" 7" 5" 3-1/2" x 3-3/16" 2-3/8" 6298 32 - 10213 9717 - 10569 9539 - 10607 10103 - 10607 9452 - 13217 2370 32 - 8386 7983 - 8667 7838 - 8696 8298 - 8696 7767 - 8987 13178 4760 7020 7250 10530 11780 7434, 9431 6870 8160 8290 10160 11200 12160 - 13190 4-1/2" 12.6# L-80 31 - 95428988 - 8986 Surface 2638 13-3/8" 33 - 2671 33 - 2671 5380 2670 4-1/2" TIW HBBP Packer No SSSV Installed 9495, 7802 Date: Torin Roschinger Operations Manager Finn Oestgaard finn.oestgaard@hilcorp.com (907) 564-5026 PRUDHOE BAY 5/19/25 Current Pools: PRUDHOE OIL Proposed Pools: Prudhoe Oil, Brookian Undefined Oil Suspension Expiration Date: 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 06/2023 Approved application is valid for 12 months from the date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 1:16 pm, May 16, 2025 Digitally signed by Torin Roschinger (4662) DN: cn=Torin Roschinger (4662) Date: 2025.05.16 11:55:58 - 08'00' Torin Roschinger (4662) 325-309 Confirm TOC in 9-5/8" casing via CBL with AOGCC prior to perforation. Perforate New Pool A.Dewhurst 19MAY25 Brookian Undefined Oil AOGCC witnessed BOP Test to 3500 psi, Annular to 2500 psi. AOGCC witnessed tag and MIT-TxIA. If CBL indicates TOC behind 9-5/8" casing is deeper than 8500' MD then gain approval from AOGCC before proceeding. 10-404 X X X JJL 5/28/25 DSR-5/28/25*&: 5/28/2025 Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.05.28 16:05:57 -08'00' RBDMS JSB 052925 RWO – Brookian UHRC Well: E-09C PTD:209095 API: 50-029-20466-03 Well Name:E-09C Rig:CDR2 or Innovation Current Status:NotOperable, Producer API Number:50-029-20466-03 Estimated Start Date:In Progress Estimated Duration:7days Regulatory Contact:Abbie Barker Sundry Number:324-707, TBD First Call Engineer:Finn Oestgaard (907) 564-5026 (O)(907) 350-8420 (M) Second Call Engineer:Leif Knatterud (432) 227-4342 (M) Program Revision:1 Current Bottom Hole Pressure:3250 psi @ 8,800’ TVDss Res Estimate from Offsets Max Ivishak Anticipated Surface Pressure:2,370 psi Based on 0.1 psi/ft gas gradient Anticipated Brookian BHP:3500 psi@ 7400’TVDss Based on estimated offset/regional data Post Brookian Perf KWF: 9.1 ppg Last SI WHP:2,300 psi 12/17/2021 Min ID:1.875” @ 9,463’ MD liner top –milled out bushing Max Angle:95 deg @ 13,075’ MD Brief Well Summary: E-09C is a Not Operable natural flow Ivishak producer. The Ivishak interval is no longer competitive and would not support a tubing swap RWO. A reservoir abandonment of the Ivishak interval will be placed. This wellbore will be recompleted up-hole to a Brookian interval. Fullbore attempted the cement squeeze, however the tubing locked up leaving 1300’ of cement in tubing. Coil to mill out the cement and retainer, set a new retainer and perform reservoir abandon plug. Objective: Secure and perform pre-RWO integrity test. Place cement for an Ivishak reservoir abandonment. Cut and pull the 4-1/2” tubing. Log cement top behind the 9-5/8” casing to confirm TOC (TOC estimate detailed below in Ivishak Abandonment section). Perforate the Brookian sands, 9,046’-9,076’. Run 3-1/2” completion. Post RWO the new Brookian interval will be flow tested. A frac to stimulate the Brookian formation will take place after the flow test. A separate sundry request will be submitted for the fracture stimulation. Current Status: Not Operable, TxIA communication – tubing leaks at 5,062’, 5,121’, and 5,688’. Well Completion Information: Wellhead: McEvoy, 13-5/8” x 4-1/16” THA Recent Integrity: ¾6/6/19 – TIOs indicate TxIA leak when well was shut in ¾07/15/2020 – LDL found 3 tubing leaks ¾12/21/21 – Set Evotrieve tubing plug at 9431’ in the 4-1/2” tubing and a CMIT-TxIA passed to 2500 psi. ¾12/10/24 – CMIT-TxIA passed to 3500 psi. Ivishak Abandonment: The Ivishak liner has no future utility, and the plan is to place a reservoir cementplug pre-RWO. The top of the Ivishak pool is 10,394’ MD/8,530’ TVDss. Revision 1 – 5/15/2025 All changes in Red from original – FEO 5/15/25 RWO – Brookian UHRC Well: E-09C PTD:209095 API: 50-029-20466-03 Annular Cement: 9-5/8” Casing: The original completion documents indicate that the primary cement job on the 9-5/8” casing went as planned. 259 bbls of cement was pumped providing an estimated cement top of 6968’ behind the 9-5/8” casing including 30% washout. No losses were noted during the cement job. This TOC will be verified during the RWO via cement bond log after the 4-1/2” completion is pulled. 7” Liner: Cemented with 45 bbls of Class G cement, 40% excess. Pressure tested to 3000 psi. Estimated TOC – at liner lap – 9717’. 5” Liner: Cemented with 49 bbls of Class G cement, 30% excess. Pressure tested to 3500 psi. Estimated TOC – at liner lap – 9,553’. E-09B 3-1/2” x 3-3/16” x 2-7/8” Liner: Cemented with 25 bbls of cement, 40% excess. Liner lap pressure tested to 2200 psi. TOC at liner lap, 10,103’ – verified with SCMT run on 7/1/09. E-09C 2-3/8” Liner: Cemented liner with 18 bbls of 15.8 Class G. Pressure test liner lap to 2000 psi. Estimated TOC @ 9800’ MD with 30% excess. RWO Procedural Steps: Wellhead 1. PPPOT-T to 5,000 psi, PPPOT-IC to 3,500 psi. 2. Function tubing lockdown screws. Replace as needed. Slickline 1. Pull Evotrieve from 9431’. 2. Drift for retainer down to top of 2-3/8” liner. 3. RDMO All subsequent work pending sundry approval E-Line 1. Set 4-1/2” Ball-drop cement retainer @ 9,440’ ME (set in the full joint below the 10’ pup below GLM #1– reference attached tubing tally of 6/10/2021). Note: Retainer supplied by Northern Solutions; contact Carl Diller @ (907) 258-6679. Fullbore 2. Pump Ivishak reservoir cement plug as follows down the tubing. Max tubing pressure 3000 psi. ¾186 bbls FW, SW, or 1% KCL (1.2 x Wellbore volume). ¾20 bbls 15.8 ppg Class G cement (~5 bbls excess volume to fill all liner and tubing below the retainer) ¾2 bbls FW spacer ¾Landing-Ball followed by two Foam-Balls ¾142.5 bbls heated 70 deg-F diesel - Slow Pump rate to minimum for last 5 bbls to seat Ball. Bump Ball with ~500 psi of excess pressure. ¾RDMO and wait on cement Retainer set 4/27/25 Fullbore attempted to cement however tubing locked up 5/13/25 Evotrieve pulled 4/20/25 PPOT-T & PPOT-IC both PASSED 3/10/25 RWO – Brookian UHRC Well: E-09C PTD:209095 API: 50-029-20466-03 Coil 1. Mill out ~1,300’ cement left in tubing on 5/15/25 & retainer @ 9,440’ - Volumetrics estimate TOC @ 7,434’ & leading edge @ 8,750’ - Once retainer has been milled, tag TOL & flag pipe for setting retainer 2. Perform Injectivity test @ 3 BPM & 5 BPM – Do not exceed 3000 psi 3. Load tubing with 120 bls of diesel (8,000’ md) 4. Set 1 trip cement retainer @ 9435’ & PT CT x TxI to 1000 psi to ensure retainer is holding. 5. Pump Ivishak Reservoir Abandon per following schedule: a. Meth spear b. 30 bbl FW spacer/confirm injectivity with FW - WSL discretion to adjust volume if needed If injectivity is < 2 BPM contact OE c. 20 bbls of 15.8 ppg Glass G cement 5 bbls excess to wellbore volume below retainer BHT = 185 F d. Displacement volume Fullbore 3. MIT-TxIA to 3500 psi target pressure, 3800 psi max pressure (AOGCC witnessed). Slickline 4. Tag TOC (AOGCC witnessed). 5. Drift for Eline jet-cut. Adjust Eline tubing cut depth as necessary depending on TOC tag. E-Line & Fullbore 1. Jet cut tubing at 9425’ MD or as deep as possible. Reference SLB Memory CNL 11/20/09. 2. Circulate out well to 9.1 brine (add Barakleen to brine to help clean pipe) with diesel freeze protect on tubing and IA. a. After full circ, shutdown and wait ~3 hrs and circ additional 9.1 ppg brine to remove additional crude. DHD 1. Bleed WHP’s to 0 psi. Valve Shop 1. Set and test TWC (Cameron Type H 4”). RWO 1. MIRU workover rig. 2. Nipple down tree and tubing head adapter. Inspect landing threads. 3. NU BOPE configuration top down: Annular, 3-1/2” x 6” VBRs, blind/shear rams and integral flow cross. 4. 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). a. Record accumulator pre-charge pressures and chart tests. b. Notify AOGCC 24 hrs in advance of BOP test. c. Confirm test pressures per the Sundry Conditions of approval. d. Test the 3-1/2” x 6” VBRs with 3-1/2” and 4-1/2” test joint. e. Test the annular with 3-1/2” test joint. f. Submit a completed 10-424 form to the AOGCC within 5 days of BOPE test. 5. RU and pull TWC. RU lubricator if pressure is present. 6. Rock out crude/diesel freeze protect with 9.1 ppg brine. RWO – Brookian UHRC Well: E-09C PTD:209095 API: 50-029-20466-03 7. MU landing joint or spear, BOLDS and pull hanger to the floor. Circulate bottoms up with 9.1 ppg brine. a. Expected PU weight in 9.1 ppg brine = 103k lbs. b. Tensile strength of 4-1/2”, 12.6# = 208.7k lbs. 8. Pull existing 4-1/2” tubing from cut. a. Take pictures of the tubing cut that is pulled out and put in the well file. 9. RU EL and complete the following scope of work. a. Run HES RBTand confirm TOC – log from ~9400’ to 2000’. b. Send CBL data to the AOGCC. 10. Perforating Operations a. MU 30’ of guns on workstring with a short joint for tying in above guns b. RIH and use Eline to correlate and tie-in. Adjust and confirm depths as needed. i. Perforate 9,046’-9,076’ per the corrected RBT log. ii. Send to Ben Siks and Michael Hibbert for confirmation. c. After shooting guns PUH ~50’, circulate bottoms up, shutdown pumps and monitor pressures to determine if the well pressure increased. Determine if new KWF needs to be determined. Pump new KWF around if needed. Perform no flow test as needed. 11. Run 3-1/2” gas lifted tubing string as per draft tally. Confirm final tally with OE prior to running. a. Torque turn connections. b. 1 of the 4 GLMs is to be installed below the production packer to allow for downhole memory gauges to be run during the frac and flowback. 12. Land hanger and reverse in corrosion inhibited 1% KCl or seawater. 13. Drop ball and rod and pressure up to set packers. 14. Perform MIT-T to 4,500 psi (higher test pressure to confirm integrity for subsequent frac). 15. Bleed off tubing pressure to 2,000 psi and MIT-IA to 3,500 psi for 30 charted minutes. 16. Bleed down IA to 2,500 psi after passing MIT-IA. 17. Once IA is bled down to 2,500 psi, bleed off tubing pressure to shear out valve in the top GLM. FP tubing and IA with diesel to 2,500’ MD. 18. Set TWC and ND BOPE. 19. NU tree and tubing head adapter. 20. Test both tree and tubing hanger void to 500 psi low / 5,000 psi high. 21. RDMO workover rig. Valve Shop 1. Pull TWC. Slickline 1. Pull shear-out valve, run KO GLV design. 2. Pull B&R and RHC profile. 3. Run memory gauge in bottom GLM Portable Testers 1. Post RWO flowback. Slickline 1. Pull downhole memory gauge 2. Drift and tag. Collect a sample if possible. 3. Run a downhole shut-in device for a pressure buildup if deemed necessary. RWO – Brookian UHRC Well: E-09C PTD:209095 API: 50-029-20466-03 Attachments – x Current Wellbore Schematic & Proposed Wellbore Schematic x Existing 4-1/2” Tubing Tally x Tie-In Log For Tubing Cut x BOP Schematic x Reference Log for Brookian Perforations x Sundry Revision Change Form RWO – Brookian UHRC Well: E-09C PTD:209095 API: 50-029-20466-03 Current Wellbore Schematic: as of 5/15/2025 Calculated lead cement from volumetrics ~8,750 Calculated TOC from volumetrics ~7,434 RWO – Brookian UHRC Well: E-09C PTD:209095 API: 50-029-20466-03 Proposed Wellbore Schematic: NOTE: Nothing was changed on the proposed schematic for Revision1, it was just red font in original submission – FEO 5/15/2025 RWO – Brookian UHRC Well: E-09C PTD:209095 API: 50-029-20466-03 Existing 4-1/2” Tubing Tally RWO – Brookian UHRC Well: E-09C PTD:209095 API: 50-029-20466-03 Tie-In Log For Tubing Cut RWO – Brookian UHRC Well: E-09C PTD:209095 API: 50-029-20466-03 Coil 1-trip Cement Retainer Set at 9,435’ Jet Cut 4-1/2” @ ~9425’ or as deep as possible RWO – Brookian UHRC Well: E-09C PTD:209095 API: 50-029-20466-03 CDR2 BOP Schematic: Innovation BOP Stack: RWO – Brookian UHRC Well: E-09C PTD:209095 API: 50-029-20466-03 Reference Log for Brookian Perforations: RWO – Brookian UHRC Well: E-09C PTD:209095 API: 50-029-20466-03 Sundry Revision Change Form: Changes to Approved Sundry Procedure Date: 5/15/2025 Subject: Service Coil additional scope for Ivishak Res Abndn Sundry #: 324-707 Any modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to the AOGCC by the “first call” engineer. AOGCC written approval of the change is required before implementing the change. Step Page Date Procedure Change HNS Prepared By (Initials) HNS Approved By (Initials) AOGCC Written Approval Received (Person and Date) 5 2/3 5/15/25 Service Coil to mill cement in tubing & pump Ivishak Res Abndn F.O.T.R. Approval: Operations Manager Date Prepared: Operations Engineer Date CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Lau, Jack J (OGC) To:AOGCC Records (CED sponsored) Subject:FW: E-09C (209-095) Reservoir Cement Plug question Date:Thursday, May 15, 2025 9:07:48 AM Attachments:image001.png From: Lau, Jack J (OGC) Sent: Thursday, May 15, 2025 8:53 AM To: Finn Oestgaard - (C) <Finn.Oestgaard@hilcorp.com> Subject: RE: E-09C Reservoir Cement Plug question Morning Finn, 1. Yes, please submit a 10-403 for Change of Approved Program. The coil cement retainer is a more reliable option in my opinion. Easiest way is to edit your original program showing what has been completed in a unique font/color, strike through what you are changing, and add your new steps with a unique font/color. That way we can process it quickly. 2. You will still need an AOGCC witnessed Tag and PT per the res P&A regs. 3. This is the 3rd fullbore cement retainer reported to me since 12/24. Give me a buzz, Jack From: Finn Oestgaard - (C) <Finn.Oestgaard@hilcorp.com> Sent: Wednesday, May 14, 2025 5:43 PM To: Lau, Jack J (OGC) <jack.lau@alaska.gov> Subject: E-09C Reservoir Cement Plug question Hi Jack E-09C is RWO to recomplete the well from the Ivishak to the Brookian under Sundry 324-707. Yesterday evening during our Reservoir Abandon of the Ivishak the well locked up while pumping cement leaving 20 bbls in the tubing resulting in ~1,316’ of cement in the tubing from 7,434’ – 8,750’ (volumetric calc’s). As to why the well locked up, I’m scratching my head a little bit, cement didn’t even reach the retainer yet, it was only seeing the FW pumped prior. We confirmed injectivity prior to the cement job and looking through historical interventions there’s no notes of any kind of build on the tubing walls or anything recovered in sample bailers. No obvious smoking guns at this point. Here’s what we pumped prior to lock up: 186 bbls FW 20 bbls 15.8 Cement 2 bbls FW Ball Launch 111 bbls of Diesel then the well locked up. After lock up we bumped pressures up and the well passed a CMIT-TxI. We plan on going in there with coil to mill the cement and retainer and open up our tubing for another attempt. While we have coil on the well I’d prefer to set a retainer with coil and pump the reservoir cement plug with coil vs. another fullbore attempt. I’d use the same cement volumes as in the sundry and subsequent AOGCC witnessed CMIT. Do not think the SL tag is necessary if pumping with coil, was going to remove that. Wanted to touch base and ask how you’d like to proceed? If filling out the Sundry Revision Change Form with the suggested steps above work? First time navigating something like this, wanted to touch base before officially submitting anything. The rig is scheduled for mid June for the workover/recomplete. Let me know if you want to discuss at all over the phone. Thanks! Finn Finn Oestgaard GBP GC1 & GC3 Operations Engineer A,B,C,D,E,F,G,K,P,X,Y pads 907-564-5026 office 907-350-8420 mobile The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. PBU E-09C Hilcorp North Slope, LLC 3800 Centerpoint Dr, Suite 1400, Anchorage, AK 99503 209-095 50-029-20466-03-00 Statewide ADL 0028304 13217 8987 10181 852 1068 504 3765 9431 9-5/8" 7" 5" 3-1/2" x 3-3/16" 2-3/8" 7751 32 - 10213 9717 - 10569 9539 - 10607 10103 - 10607 9452 - 13217 2370 32 - 8386 7983 - 8667 7838 - 8696 8298 - 8696 7767 - 8987 131789431 6870 8160 8290 10160 11200 12160 - 13190 4-1/2" 12.6# L-80 31 - 95428988 - 8986 2638 13-3/8" 33 - 2671 33 - 2671 5380 4-1/2" TIW HBBP Packer No SSSV Installed 9495, 7802 Aras Worthington for Torin Roschinger Operations Manager Michael Hibbert michael.hibbert@hilcorp.com 907-903-5990 PRUDHOE BAY 12/23/2024 PRUDHOE OIL ,Brookian Undefined oil STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 Digitally signed by Aras Worthington (4643) DN: cn=Aras Worthington (4643) Date: 2024.12.18 10:41:01 - 09'00' Aras Worthington (4643) By Grace Christianson at 11:18 am, Dec 18, 2024 324-707 AOGCC witnessed BOP Test to 3500 psi, Annular to 2500 psi. AOGCC witnessed tag and MIT-TxIA. If CBL indicates TOC behind 9-5/8" casing is deeper than 8500' MD then gain approval from AOGCC before proceeding. SFD 12/19/2024JJL 12/19/24 X 10-404 XX DSR-12/20/24JLC 12/20/2024 Gregory C. Wilson Digitally signed by Gregory C. Wilson Date: 2024.12.22 08:29:13 -09'00'12/22/24 RBDMS JSB 122424 RWO – Brookian UHRC Well: E-09C PTD: 209095 API: 50-029-20466-03 Well Name:E-09C Rig:CDR2 or Innovation Current Status:Not Operable, Producer API Number:50-029-20466-03 Estimated Start Date:January 1, 2025 Estimated Duration:7days Regulatory Contact:Abbie Barker Sundry Number: First Call Engineer:Michael Hibbert (907) 903-5990 (M) Second Call Engineer:Aras Worthington (907) 564-4763 (O) (907) 440-7692 (M) Program Revision:0 Current Bottom Hole Pressure:3250 psi @ 8,800’ TVDss Res Estimate from Offsets Max Ivishak Anticipated Surface Pressure:2,370 psi Based on 0.1 psi/ft gas gradient Anticipated Brookian BHP:3500 psi @ 7400’TVDss Based on estimated offset/regional data Post Brookian Perf KWF: 9.1 ppg Last SI WHP:2,300 psi 12/17/2021 Min ID:1.875” @ 9,463’ MD liner top – milled out bushing Max Angle:95 deg @ 13,075’ MD Brief Well Summary: E-09C is a Not Operable natural flow Ivishak producer. The Ivishak interval is no longer competitive and would not support a tubing swap RWO. A reservoir abandonment of the Ivishak interval will be placed. This wellbore will be recompleted up-hole to a Brookian interval. Objective: Secure and perform pre-RWO integrity test. Place cement for an Ivishak reservoir abandonment. Cut and pull the 4-1/2” tubing. Log cement top behind the 9-5/8” casing to confirm TOC (TOC estimate detailed below in Ivishak Abandonment section). Perforate the Brookian sands, 9,046’-9,076’. Run 3-1/2” completion. Post RWO the new Brookian interval will be flow tested. A frac to stimulate the Brookian formation will take place after the flow test. A separate sundry request will be submitted for the fracture stimulation. Current Status: Not Operable, TxIA communication – tubing leaks at 5,062’, 5,121’, and 5,688’. Well Completion Information: Wellhead: McEvoy, 13-5/8” x 4-1/16” THA Recent Integrity: 6/6/19 – TIOs indicate TxIA leak when well was shut in 07/15/2020 – LDL found 3 tubing leaks 12/21/21 – Set Evotrieve tubing plug at 9431’ in the 4-1/2” tubing and a CMIT-TxIA passed to 2500 psi. 12/10/24 – CMIT-TxIA passed to 3500 psi. Ivishak Abandonment: The Ivishak liner has no future utility, and the plan is to place a reservoir cement plug pre-RWO. The top of the Ivishak pool is 10,394’ MD/8,530’ TVDss. Annular Cement: 9-5/8” Casing: The original completion documents indicate that the primary cement job on the 9-5/8” casing went as planned. 259 bbls of cement was pumped providing an estimated cement top of 6968’ behind the 9-5/8” casing including 30% washout. No losses were noted during the cement job. This TOC will be verified during the RWO via cement bond log after the 4-1/2” completion is pulled. RWO – Brookian UHRC Well: E-09C PTD: 209095 API: 50-029-20466-03 7” Liner: Cemented with 45 bbls of Class G cement, 40% excess. Pressure tested to 3000 psi. Estimated TOC– at liner lap – 9717’. 5” Liner: Cemented with 49 bbls of Class G cement, 30% excess. Pressure tested to 3500 psi. Estimated TOC– at liner lap – 9,553’. E-09B 3-1/2” x 3-3/16” x 2-7/8” Liner: Cemented with 25 bbls of cement, 40% excess. Liner lap pressure tested to 2200 psi. TOC at liner lap, 10,103’ – verified with SCMT run on 7/1/09. E-09C 2-3/8” Liner: Cemented liner with 18 bbls of 15.8 Class G. Pressure test liner lap to 2000 psi. Estimated TOC @ 9800’ MD with 30% excess. RWO Procedural Steps: Wellhead 1. PPPOT-T to 5,000 psi, PPPOT-IC to 3,500 psi. 2. Function tubing lockdown screws. Replace as needed. Slickline 1. Pull Evotrieve from 9431’. 2. Drift for retainer down to top of 2-3/8” liner. 3. RDMO All subsequent work pending sundry approval E-Line 1. Set 4-1/2” Ball-drop cement retainer @ 9,440’ ME (set in the full joint below the 10’ pup below GLM #1– reference attached tubing tally of 6/10/2021). Note: Retainer supplied by Northern Solutions; contact Carl Diller @ (907) 258-6679. Fullbore 2. Pump Ivishak reservoir cement plug as follows down the tubing. Max tubing pressure 3000 psi. 186 bbls FW, SW, or 1% KCL (1.2 x Wellbore volume). 20 bbls 15.8 ppg Class G cement (~5 bbls excess volume to fill all liner and tubing below the retainer) 2 bbls FW spacer Landing-Ball followed by two Foam-Balls 142.5 bbls heated 70 deg-F diesel - Slow Pump rate to minimum for last 5 bbls to seat Ball. Bump Ball with ~500 psi of excess pressure. RDMO and wait on cement Fullbore 3. MIT-TxIA to 3500 psi target pressure, 3800 psi max pressure (AOGCC witnessed). Slickline 4. Tag TOC (AOGCC witnessed). 5. Drift for Eline jet-cut. Adjust Eline tubing cut depth as necessary depending on TOC tag. RWO – Brookian UHRC Well: E-09C PTD: 209095 API: 50-029-20466-03 E-Line & Fullbore 1. Jet cut tubing at 9425’ MD or as deep as possible. Reference SLB Memory CNL 11/20/09. 2. Circulate out well to 9.1 brine (add Barakleen to brine to help clean pipe) with diesel freeze protect on tubing and IA. a. After full circ, shutdown and wait ~3 hrs and circ additional 9.1 ppg brine to remove additional crude. DHD 1. Bleed WHP’s to 0 psi. Valve Shop 1. Set and test TWC (Cameron Type H 4”). RWO 1. MIRU workover rig. 2. Nipple down tree and tubing head adapter. Inspect landing threads. 3. NU BOPE configuration top down: Annular, 3-1/2” x 6” VBRs, blind/shear rams and integral flow cross. 4. 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). a. Record accumulator pre-charge pressures and chart tests. b. Notify AOGCC 24 hrs in advance of BOP test. c. Confirm test pressures per the Sundry Conditions of approval. d. Test the 3-1/2” x 6” VBRs with 3-1/2” and 4-1/2” test joint. e. Test the annular with 3-1/2” test joint. f. Submit a completed 10-424 form to the AOGCC within 5 days of BOPE test. 5. RU and pull TWC. RU lubricator if pressure is present. 6. Rock out crude/diesel freeze protect with 9.1 ppg brine. 7. MU landing joint or spear, BOLDS and pull hanger to the floor. Circulate bottoms up with 9.1 ppg brine. a. Expected PU weight in 9.1 ppg brine = 103k lbs. b. Tensile strength of 4-1/2”, 12.6# = 208.7k lbs. 8. Pull existing 4-1/2” tubing from cut. a. Take pictures of the tubing cut that is pulled out and put in the well file. 9. RU EL and complete the following scope of work. a. Run HES RBT and confirm TOC – log from ~9400’ to 2000’. b. Send CBL data to the AOGCC. 10. Perforating Operations a. MU 30’ of guns on workstring with a short joint for tying in above guns b. RIH and use Eline to correlate and tie-in. Adjust and confirm depths as needed. i. Perforate 9,046’-9,076’ per the corrected RBT log. ii. Send to Ben Siks and Michael Hibbert for confirmation. c. After shooting guns PUH ~50’, circulate bottoms up, shutdown pumps and monitor pressures to determine if the well pressure increased. Determine if new KWF needs to be determined. Pump new KWF around if needed. Perform no flow test as needed. 11. Run 3-1/2” gas lifted tubing string as per draft tally. Confirm final tally with OE prior to running. a. Torque turn connections. b. 1 of the 4 GLMs is to be installed below the production packer to allow for downhole memory gauges to be run during the frac and flowback. 12. Land hanger and reverse in corrosion inhibited 1% KCl or seawater. 13. Drop ball and rod and pressure up to set packers. 14. Perform MIT-T to 4,500 psi (higher test pressure to confirm integrity for subsequent frac). Per Hibbert, annular will be shut during perforating If CBL indicates TOC behind 9-5/8" casing is deeper than 8500' MD then gain approval from AOGCC before proceeding. - JJL RWO – Brookian UHRC Well: E-09C PTD: 209095 API: 50-029-20466-03 15. Bleed off tubing pressure to 2,000 psi and MIT-IA to 3,500 psi for 30 charted minutes. 16. Bleed down IA to 2,500 psi after passing MIT-IA. 17. Once IA is bled down to 2,500 psi, bleed off tubing pressure to shear out valve in the top GLM. FP tubing and IA with diesel to 2,500’ MD. 18. Set TWC and ND BOPE. 19. NU tree and tubing head adapter. 20. Test both tree and tubing hanger void to 500 psi low / 5,000 psi high. 21. RDMO workover rig. Valve Shop 1. Pull TWC. Slickline 1. Pull shear-out valve, run KO GLV design. 2. Pull B&R and RHC profile. 3. Run memory gauge in bottom GLM Portable Testers 1. Post RWO flowback. Slickline 1. Pull downhole memory gauge 2. Drift and tag. Collect a sample if possible. 3. Run a downhole shut-in device for a pressure buildup if deemed necessary. Attachments – Current Wellbore Schematic & Proposed Wellbore Schematic Existing 4-1/2” Tubing Tally Tie-In Log For Tubing Cut BOP Schematic Reference Log for Brookian Perforations Sundry Revision Change Form RWO – Brookian UHRC Well: E-09C PTD: 209095 API: 50-029-20466-03 Current Wellbore Schematic: RWO – Brookian UHRC Well: E-09C PTD: 209095 API: 50-029-20466-03 Proposed Wellbore Schematic: RWO – Brookian UHRC Well: E-09C PTD: 209095 API: 50-029-20466-03 Existing 4-1/2” Tubing Tally RWO – Brookian UHRC Well: E-09C PTD: 209095 API: 50-029-20466-03 Tie-In Log For Tubing Cut RWO – Brookian UHRC Well: E-09C PTD: 209095 API: 50-029-20466-03 Ball Drop Cement Retainer Set at 9,440’ Jet Cut 4-1/2” @ ~9425’ or as deep as possible RWO – Brookian UHRC Well: E-09C PTD: 209095 API: 50-029-20466-03 CDR2 BOP Schematic: Innovation BOP Stack: RWO – Brookian UHRC Well: E-09C PTD: 209095 API: 50-029-20466-03 Reference Log for Brookian Perforations: RWO – Brookian UHRC Well: E-09C PTD: 209095 API: 50-029-20466-03 Sundry Revision Change Form: Changes to Approved Sundry Procedure Date: Subject: Sundry #: Any modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to the AOGCC by the “first call” engineer. AOGCC written approval of the change is required before implementing the change. Step Page Date Procedure Change HNS Prepared By (Initials) HNS Approved By (Initials) AOGCC Written Approval Received (Person and Date) Approval: Operations Manager Date Prepared: Operations Engineer Date 1 Christianson, Grace K (OGC) From:Michael Hibbert <michael.hibbert@hilcorp.com> Sent:Thursday, December 19, 2024 9:49 AM To:Lau, Jack J (OGC) Cc:Rixse, Melvin G (OGC); Dewhurst, Andrew D (OGC); Roby, David S (OGC) Subject:RE: [EXTERNAL] Perforating Question: PBU E-09C (PTD 209-095) Sundry 324-692 Yes, shut in during perforating. -Michael From: Lau, Jack J (OGC) <jack.lau@alaska.gov> Sent: Thursday, December 19, 2024 9:40 AM To: Michael Hibbert <michael.hibbert@hilcorp.com> Cc: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Roby, David S (OGC) <dave.roby@alaska.gov> Subject: Re: [EXTERNAL] Perforating Question: PBU E-09C (PTD 209-095) Sundry 324-692 Thanks Michael. For clarity the annular will be shut in during perforating? Jack From: Michael Hibbert <michael.hibbert@hilcorp.com> Sent: Thursday, December 19, 2024 8:42 AM To: Lau, Jack J (OGC) <jack.lau@alaska.gov> Cc: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Roby, David S (OGC) <dave.roby@alaska.gov> Subject: RE: [EXTERNAL] Perforating Question: PBU E-09C (PTD 209-095) Sundry 324-692 Jack, Yes, we will shut the annular, circulate a bottoms up after perforating, and then shutdown and monitor for pressure and weight up if necessary. This is the same process we followed on C-18 that was executed in October of 2024. We predict being overbalanced, but will be fully prepared to weight up as needed. -Michael From: Lau, Jack J (OGC) <jack.lau@alaska.gov> Sent: Wednesday, December 18, 2024 3:28 PM To: Michael Hibbert <michael.hibbert@hilcorp.com > Cc: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. 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. 2 Roby, David S (OGC) <dave.roby@alaska.gov> Subject: [EXTERNAL] Perforating Question: PBU E-09C (PTD 209-095) Sundry 324-692 Michael – Do you plan to shut the annular or pipe ram before perforating and circulate ball down through choke? If not, how do you plan to perf to mitigate risk perforating a relatively unknown zone? Jack From: Lau, Jack J (OGC) Sent: Tuesday, December 10, 2024 12:52 PM To: michael.hibbert@hilcorp.com Cc: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Christianson, Grace K (OGC) <grace.christianson@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Roby, David S (OGC) <dave.roby@alaska.gov> Subject: PBU E-09C (PTD 209-095) Sundry 324-692 Michael – Your sundry application 324-692 does not meet the plugging requirements set in 20 AAC 25.112. Please resubmit a revision that complies with the aforementioned. Thanks Jack Lau Senior Petroleum Engineer Alaska Oil and Gas Conservation Commission (907) 793-1244 Office (907) 227-2760 Cell 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. 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. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. 3 • • Image Project Well History File Cover Page XHVZE This page identifies those items that were not scanned during the initial production scanning phase. They are available in the original file, may be scanned during a special rescan activity or are viewable by direct inspection of the file. c,09 - Q_9,c Well History File Identifier Organizing (done) ❑ Two -sided I Ill ❑ Rescan Needed II1111111111111 RESC DIGITAL DATA OVERSIZED (Scannable) o r Items: ❑ Dis ettes, No. ❑ Maps: / C Grey Items: �� Other, No/Type: c � N0. 9- ❑ Other Items Scannable by a Large Scanner ❑ Poor Quality Originals: OVERSIZED (Non - Scannable) ❑ Other: ❑ Logs of various kinds: NOTES: ❑ Other:: �, BY: Maria Date: a f J /s/ ri P Project Proofing 111 111111 II li 1 I BY: dIE Date: a fa 1 / /s/ f Scanning Preparation x 30 = (00 + _ 7 = TOTAL PAGES b9 (Count does not include cover sheet ) 14/1 BY: Date: �� l ` /s/ Production Scanning III 1111111111 III I Stage 1 Page Count from Scanned File: D (Count does include cover heet) Page Count Matches Number in Scanning Pre aration: V YES NO BY: OEM Date: 40/3 a3 / / /s/ rvi, f Stage 1 If NO in stage 1, page(s) discrepancies were found: YES NO t BY: Maria Date: Is/ Scanning is complete at this point unless rescanning is required. III 1E11111 11'1) ReScanned 1111111111111111111 BY: Maria Date: /s/ Comments about this file: Quality Checked 13111111111N 10/6/2005 Well History File Cover Page.doc STATE OF ALASKA • AOKA OIL AND GAS CONSERVATION COMMION REPORT OF SUNDRY WELL OPERATIONS 1. Operations Abandon U Repair Well U Plug Perforations Li Perforate U Other L._/1 C ement'Squeeze Performed: Alter Casing ❑ Pull Tubing❑ Stimulate - Frac ❑ Waiver ❑ Time ExtensionD Change Approved Program ❑ Operat. Shutdown❑ Stimulate - Other ❑ Re -enter Suspended WeII❑ 2. Operator 4. Well Class Before Work: 5. Permit to Drill Number: Name: BP Exploration (Alaska), Inc Development 61 Exploratory ❑ 209 -095 -0 3. Address: P.O. Box 196612 Stratigraphic❑ Service ❑ 6. API Number: Anchorage, AK 99519 -6612 - 50- 029 - 20466 -03 -00 7. Property Designation (Lease Number): 8. Well Name and Number: ADL0028304 ' PBU E -09C 9. Logs (List logs and submit electronic and printed data per 20AAC25.071): 10. Field /Pool(s): r To Be Submitted PRUDHOE BAY, PRUDHOE OIL 11. Present Well Condition Summary: Total Depth measured 13217 feet Plugs measured None feet true vertical 8986 feet Junk measured 13178 feet Effective Depth measured 12110 feet Packer measured See Attachment feet true vertical 8981.24 feet true vertical See Attachment feet Casing Length Size MD TVD Burst Collapse Structural None None None None None None Conductor 81 20" 91.5# H -40 34 - 115 34 - 115 1490 470 Surface 2638 13 -3/8" 72# L -80 33 - 2671 33 - 2670.9 4930 2670 Intermediate None None None None None None Production 10181 9 -5/8" 47# L -80 32 - 10213 32 - 8386.49 6870 4760 Liner See Attachment See Attachment See Attachment See Attachment See Attachment See Attachment Perforation depth Measured depth 11450 - 11630 feet 11810 - 12020 feet 12160 - 12280 feet 12400 - 12860 feet 12900 - 12960 feet 13050 - 13190 feet True Vertical depth 8934.58 - 8944.86 feet 8949.32 - 8969.37 feet 8987.93 - 8992.59 feet 8991.64 - 8994.7 feet 8993.79 - 8991.96 feet 8991.71 - 8985.62 feet Tubing (size, grade, measured and true vertical depth) 4 -1/2" 12.6# L -80 31 - 9542 31 - 7840.41 Packers and SSSV (type, measured and true vertical depth) See Attachment See Attachment See Attachment Packer None None None SSSV 12. Stimulation or cement squeeze summary: Intervals treated (measured): �Q Treatment descriptions including volumes used and final pressure: SCANNED APR 2013 13. Representative Daily Average Production or Injection Data Oil -Bbl Gas -Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: 370 24288 6 0 968 Subsequent to operation: 1182 16147 51 0 850 14. Attachments: 15. Well Class after work: Copies of Logs and Surveys Run ExploratorE❑ Development Is " Service ❑ Stratigraphic ❑ Daily Report of Well Operations X 16. Well Status after work: Oil -. Q Gas ❑ WDSPI.0 GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP ❑ SPLUGO 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: N/A Contact Nita Summerhays Email Nita.Summerhaysc BP.com Printed Name Nita Summerhays Title Petrotechnical Data Technician Signature _ Phone 564-4035 Date 4/11/2013 9 G //, /, ' ■ �� x/5,3 flMS APR 12 20' 1L V Form 10 -404 Revised 10/2012 Submit Original Only • • Daily Report of Well Operations ADL0028304 ACTIVITYDATE 1 SUMMARY ** *WELL FLOWING ON ARRIVAL ** *(pre coil sqz -crete /organoseal, cibp) DRIFT TO DEV W/ 1.805" SWAGE @ 10,825' SLM. SET WHIDDON C -SUB ON DEP SLEEVE © 9,434' SLM/ 9,452' MD. PULLED STA #2 LGLV @ 8,251' SLM/ 8,264' MD. PULLED STA #3 LGLV @ 4,368' SLM/ 4,384' MD. 1/9/2013 * * *CONT OF 1/10/13 WSR * ** 1/9/2013 'Fluid support T /I /0= 2349/2367/0 Assist slickline MIT -IA * *PASSED ** to 2500 psi. Pumped 5 bbl neat spear followed by 530 bbls crude down IA. Pumped 16 bbls crude down IA to reach test pressure. 15 min IA lost 85 psi. 30 min IA lost 33 psi. Total loss of 118 psi in 30 mins. Bled IAP back to 4 psi. Bled back -8 bbls. Freeze protect flowline with 10 bbls of neat 1/10/2013 methanol. SSL still on well at LRS departure. FWHP= 2088/5/0 * * *CONT FROM 1/9/13 WSR * ** SET DGLV IN STA #3 © 4368' SLM/ 4384' MD LRS LOAD IA. SET DGLV IN STA #2 © 8251' SLM/8264' MD LRS MIT -IA TO 2500 PSI (PASS). PULL 4 -1/2" WHIDDON CATCHER FROM 9434' SLM. 1/10/2013 ** *WELL TURNED OVER TO DSO * ** CT -8 1 1/2" Scope of Work: Drift/acid, injectivety test, tog, CIBP, Organoseal Cmt. Move from DS6, meet w /Pad Op sign permits, PJSM begin RU. Double barrier test good, Function test BOP's. PT choke trl vlvs, 3 leaking, grease crew to service. MU 1.85" drift assembly 9.26', OAL. PT PCE & WH. Grease crew serviced vlv's, PT good. Injection test, no WHP © 2 BPM, RIH w /drift Noz. sat down @ 13113'ctm bottom perf is 13190'md, call pad engineer to discuss tag depth, descison made to continue with acid steps. 3/14/2013 »Job in progress« CT -8 1 1/2" Scope of Work: Drift/acid, injectivety test, log, CIBP, Organoseal Cmt. hold safety meeting with slb pumpers. pump 48 bbls HCL, 48 bbls HFL( Mud Acid) while reciprocating across perfs, , over flush tbng. POOH Will C/O perfs w/1.75" milling assembly, per discussion w /APE. MU 1.74" parabolic milling assembly, OAL 11.89'. RIH for dry tag, taking wgt @ 13,199', (mech 13185). Clean out with 1.74" mill to 13,193' appears to be spinning on plug. wgt back CTD. Flag @ 13,163' CTD. POOH. break down tools, make up logging BHA, CTC 1.68" ', MHA/DFC Discon (9/16" ball), 1.75" kj, 1.69 MBH, UMT, GR, CCL. OAL= 11.65'. Cont'd on 3 -16 -13 WSR « <JOB IN PROGRESS »> 3/15/2013 • • Daily Report of Well Operations ADL0028304 CT -8 1 1/2" Scope of Work: Drift/acid, injectivety test, log, CIBP, Organoseal Cmt. Run memory GR /CCL to 13064'ctm, log up to 12,000' ctm, paint flag continue logging to 9200'ctm, pooh. Pop off, Check logging data. Good data, -5' correction. Weekly BOP test cxompleted. MU WFT CBP /setting assembly, PT RIH. Good indication at surface, Set WFT CBP @ 12110'. (center element), set 3K down POOH. continue on 3 -17 -13 wsr 3/16/2013 « <JOB IN PROGRESS »> CT -8 1 1/2" Scope of Work: Drift/acid, injectivety test, log, CIBP, Organoseal Cmt. continue with injectivity test. MU BOT milling assembly to push CBP to bottom, RIH. Reflag pipe & RIH. Tagged CBP @ 12,109'. Est injection rate of 0.5 BPM @ 2900 psi. Call Town for plan forward, will proceed w /Cmt job w/o Org /Seal Gel spacer, cmt only. Mobilize SWS crew. OOH w /Milling assembly, pop off. Make upBHA = 1.5" ctc, 2ea 1.5" stingers, 1.5" bdjsn. OAL = 8' rih to 9451' ctm, circ tubing to diesel. Continue on 3- 18-13 wsr 3/17/2013 »job in progress« CT -8 1 1/2" Scope of Work: Drift/acid, injectivety test, log, CIBP, Organoseal Cmt. Lay in 20 bbls squeeze CRETE, line up to back side and begin squeeze. Displace /squeeze —8 bbl's behind pipe, had 3000 psi squeeze, held 30 minutes. Jet out cmt down to CBP, 12,115' wgt back CTD. Leave Pwr. Visc across perfs, POOH jetting jewelry. FP Tbg w /Meth to 2500'. RDMOL. 3/18/2013 « <First Stage of Job Complete »> T /1 /0= 0/0/0. Temp= SI PT Tubing ( post squeeze) Pressure up on cement squeeze to 1000 psi. Attempt 3 pressure test. Average psi loss =155 psi. Re- pressure tbg w/ .1 bbl neat meth each time. Bleed tbg pressure down to 0 psi. FWHP = 0/0/0. IA & OA OTG. Wing & swab 3/20/2013 closed. SSV& master valve open. CT -8 1 1/2" Scope of Work: mill CBP. Riging up. 3/20/2013 » job in progress« CT -8 1 1/2 ", Scope of Work: mill CBP. RIH w/ BHA = CTC 1.50" x .19', DBPV 1.69" x 1.5', hyd jar 1.69" x 6.66', DISCO (1/2" ball) 1.69" x 1.36', DCV (3/8" ball) 1.69" x .92', agitator 1.69" x 3.04', mud motor 1.69" x 7.64', parabolic mill 1.74" x .62'. OAL = 21.93'. Tag plug at 12078. milled plug and pushed to 13,157'. Mill plugged off. start puh. pop burst disc. FP coil. pooh. RIH w/ BHA; = CTC 1.50" x .19', DBPV 1.69" x 1.5', hyd jar 1.69" x 6.66', DISCO (1/2" ball) 1.69" x 1.36', 1.74" crossover, 1.74" nozzle (oal= 10.87') 3/21/2013 * *Job continued on WSR 03- 22 -13 ** • • Daily Report of Well Operations ADL0028304 Continued from WSR 03- 21 -13. CTU 8 w/ 1.5" CT. Scope mill CIBP. cont RIH w /BHA; = CTC 1.50" x .19', DBPV 1.69" x 1.5', hyd jar 1.69" x 6.66', DISCO (1/2" ball) 1.69" x 1.36', 1.74" crossover, 1.74" nozzle (oal= 10.87') to 13188'. Come online down coil and chase returns to surface.Freeze protect to 2500 with 60/40 meth. 3/22/2013 * *job complete** ** *WELL S/I ON ARRIVAL * ** (pre -coil- squeeze - crete /organoseal /cibp) R/U SWCP 4518 3/22/2013 * * *CONT ON 03/23/13 WSR * ** * * *CONT FROM 03/22/13 WSR * ** (pre- coil - squeeze- crete /organoseal /cibp) SET 4 -1/2" WHIDDON C. SUB ON DEP SLEEVE @ 9436' SLM (9452' MD) PULLED ST #2 RM -DGLV @ 8264' MD, ST #3 RM -DGLV @ 4384' MD SET ST #3 RM -LGLV @ 4369' SLM (4384' MD) & ST #2 RM -OGLV @ 8253' SLM ( 8264' MD) PULLED 4 -1/2" WHIDDON C. SUB FROM 9436' SLM 3/23/2013 ** *WELL LEFT S/I ON DEPARTURE, PAD OP NOTIFIED * ** FLUIDS PUMPED BBLS 123 DIESEL 72 METH 546 CRUDE 386 3% NH4CL 68 1% SLK KCL /SL 231 60/40 METH 349 1% KCL 20 SQUEEZE CRETE 26 GEL 1821 TOTAL Casing / Tubing Attachment ADL0028304 Casing Length Size MD TVD Burst Collapse CONDUCTOR 81 20" 91.5# H -40 34 - 115 34 - 115 1490 470 LINER 3765 2 -3/8" 4.7# L -80 9452 - 13217 7767.41 - 8986.5 11200 11780 LINER 1135 5" 15# 13CR80 9553 - 10688 7849.37 - 8757.45 8290 7250 LINER 852 7" 29# L -80 9717 - 10569 7983.42 - 8666.6 8160 7020 LINER 505 3 -1/2" 8.81# L -80 10103 - 10608 8297.79 - 8696.51 LINER 4 3- 3/16" 6.2# L -80 10608 - 10612 8696.51 - 8699.49 PRODUCTION 10181 9 -5/8" 47# L -80 32 - 10213 32 - 8386.49 6870 4760 • SURFACE 2638 13 -3/8" 72# L -80 33 - 2671 33 - 2670.9 4930 2670 TUBING 9511 4 -1/2" 12.6# L -80 31 - 9542 31 - 7840.41 8430 7500 • • • Packers and SSV's Attachment ADL0028304 SW Name Type MD TVD Depscription E -09C PACKER 2620 2554.9 E -09C PACKER 9495 7737.19 TREE = 4 " 5M CM SA TPS: 4-112" CHROMENPPLES & 5" CHROME V t HEAD = .. CM/ • L L ANGLE> 70° @ 10955""ORIG WBJ. & E.09A ACTUATOR = BAKER C E-09C & E-0913 NOT SHOWN BELOW WMPSTOCK "°06/19/09: X INITIAL KB. ELE 60.03' MP @ 9519' DAMAGED DURING 2002 MILLING OPS - BE 8.5/ = 30.76' WONT HOLD PRESSL)REw/PLUG SET. KOP= 10680' I 2083' 1- 14 -1/2" OTTS SSSV NP(9 -CR), D= 3.813" I Max Angle = 95° @13075' Datum RD= 10849' 1. 2620' 9-51$" DV PKR Caftan ND = 8800' SS 113-3/8" CSG,72#, L-80, D = 12.347" H 2671' - ■ GAS LFT MANDRELS ST MD TVD DEV TYPE VLV LATCH PORT DATE 3 4384 4263 36 Miff DOME RM 16 03/23/13 L 2 8264 6870 44 MER SO RM 20 03/23/13 1 9413 7736 37 MER DMY RM 0 01/19195 Minimum ID =1.875" @ 9463' 9452' 23/8" DEPLOYMENT SLV, D= 3.00" 1 LBR PLUG HOLDER BUSHING ______.---1 9463' HLBR PLUG HOLDER BUSHINGMLL ®TO1.875' I 1 4 -1/2" I-EB X NP 8 D = 3.813° 8483' (-CW. 9494' H" ANCHOR LATCH SEAL ASSY, D = 3.94" 1 9496' H9-5/8" X 4-1/2' TtW HBBP PKR, D = 4.000' 1 I I 1 9519' H4 -12" FES X NP (9 -CR), D= 3.813" I ' y I 9530' 14112" FES XN Imo' (9-CR) MLLED TO 3.80" (0829/02) 1 41/2" T8G, 12.6#, L-80, .0152 bpf, D = 3.953" H 9542' .I 9J42' 1 41/2" W IEG, D= 3.958" 1 (TOP OF 5 "LNR 9553' I HEJiUTT NOT LOGGED ITOP OF 7" LNR H 971T I ITOC H -980o' • '4 ; F 4/ 1 10103' 1-13.70" BKR DEPLOY RENT SLV , D = 3.00" 1 1 • • ► " ' 10117 --13-1/2" HES XN NP, ID= 2.750" 1 1 1 9-5/8" CSG, 47 #, L-80, D = 8.68" _1-1 10213' - ■ • ■ , 17" LW, 29#, L-80, .0371 bpf, D = 6.184" H 10569' ► • ► • 1 MLLOUT'1*1DOW (E-09C) 10607' - 10612' 1 3-12" LNR, 8.81 #, L -80 SIL, .0087 bpf, D = 2.992" H 10608' ' 1 4 13 -3/16" WHPSTOCK (0923/09) H 10613' / 1 • I 10608' H 3 -12" -1/16' X0, D= 2.786" 1 (RA TAG (11/11/09) H 10613' 15" LNR, 15#, 13CR, .0188 bpf, D = 4.408" H 10688' PERFORATION StJJ kRY REF LOG: MUM GR/C(:UM CL ON 11/21/09 ' e"" ANGLE AT TOP PERF: 84° @ 12160' Note afar to ban DB for historical pert data r 13178' CTMD -� ISFt M-.LED 8 ` -. tRF 14'TB AL " Opn/Sq V SHOT` ' ■.. E) SQZ 1 RJSF CBP i 1.56 6 11450 -11630 S 11/21/09 03/18/13 Iki lioto, (03/21/13) .56 6 11810 12020 S 11/21/09 03/18/13 1.• 121.'- ;' a '.4 ii 1.56 6 12400 - 12860 0 11/21/09 % 1.56 6 12900 -12960 0 11/21/09 1.56 6 13050 - 13190 0/C 11/21/09 1 PBTD H 13202' I ,i•D 12 -3/8' L•R, 4.7 #, L -80, .0039 bpf, D = 1.992" H 13217* 1 DATE REV BY CO/AMC-5 DATE REV BY COM4BJTS PRUDHOE BAY UNT 05/80 ORIGINAL COMPLETION 01/23/13 CJWJMD GLV CIO (01/10/13) WELL E-09C 01/13/95 DFF SIDETRACK (E -09A) 04/11/13 F8S/JMD SET CBR'SOZ FERFS (03/18/13) F8 IT Pb: 2090950 09/08/02 DAC/FOC CTD SIDETRACK (E•09B) 04/11/13 KJB/JMD PALLED & FtSF133 CBP (0321/13) AR ND: 50 -029- 20466-03 -00 11/22/09 NORDIC 1 CTD SIDETRACK (609C) 04/11/13 GJB/JMD GLV CIO (03/23/13) SEC 6, T11N, R14E, 243' FN:. & 500' Fa. 11/27/09 QAV /SV GLV CIO 02/15/10 CWJMD DRLG DRAFT CORRECTIONS BP Exploration (Alaska) DATE: 23- Aug -12 Stephanie Pacillo TRANS#: 6044 Data Delivery Services Technician ."' 4� IVIaka na K Bender Schiumberger Oilfield Services -I. Natural Resources Technician II WIRELIKE ■ l r 2525 Gamhell St, Ste. 400 / Al- 1s14.µ1 011 & C; Colific;? WitIC:I1 CoIllttria'sirA `� �:., s W '1�'.. I': `i l', ,;t ilk i (1O {-.:I'!'1 i - .i uir : !'.� ' ,',(j i Anchorage, AK 99503 .., ':Office: (907) 273 -1770 EL 3 ` 'T ERvicg, ' , ' S OH RESER CNl. ;MEJwH WO DESCRIPTIONS DATE- ': 0/W r NAME ORDER# DIST DIST DIST DIST LOGGED. PRINTS PRINTS G -25B BAUJ -00145 X MEMORY IPROF 25- Jul -12 1 1 CD • E -09C 6C00 -00024 X PPROF /IPROF MCNL 12- Jul -12 1 1 CD G -04B C600 -00025 X MEMORY PPROF /IPROF MCNL 10- Jul -12 1 1 CD K -10C BAUJ -00138 X MEMORY PPROF W/ GHOST 29- Jun -12 1 1 CD V -202 C600 -00031 X MEMORY LDL 22- Jul -12 1 1 CD Z -06A C5XI -00016 X MEMORY PPROF 13- Jul -12 1 1 CD W -02A C5XI -00018 X MEMORY LEAK DETECTION 15- Jul -12 1 1 CD 14 -33A C5XI -00006 X MEMORY PPROF 13- Jun -12 1 1 CD 05 -23B BAUJ -00140 X MEMORY PPROF W/ GHOST 3-Jul -12 1 1 CD H -09 C2JC -00027 X IPROF 23- Jun -12 1 1 CD MPS -01B BZ81 -00021 X PDC CORRELATION 9- Jul -12 1 1 CD MPS -01B BZ81 -00021 X USIT 11- Jul -12 1 1 CD 05 -22B BCRC -00196 X MEMORY PPROF 9- Jul -12 1 1 CD P1 -05 BYS4 -00048 X XFLOW W/ IBP SET RECORD 20- Jun -12 1 1 CD L1 -09 fBVYC -00041 X PPROF 16- Jul -12 1 1 CD L1 -21 APBSURVE X PPROF 26- Jun -12 1 1 CD AS N -12 APBSURVEEL _ X _ _ PPROF _ 19- Jul -12 1 1 CD _ 05 -22B BCRC -00196 X MEMORY PPROF W/ GHOST 9- Jul -12 1 1 CD 18 -25A 11996389 X SCMT 13- Mar -08 1 1 CD G -25B BAUJ -00145 X MEMORY PPROF W/ GHOST 24- Jul -12 1 1 CD Z -13A BAUJ -00142 X MEMORY LEAK DETECTION 7- Jul -12 1 1 CD X ) /./ Please return a signed copy to: Please return a signed copy BP PDC LR2 -1 DCS 2525 Gambell St, Suite 400 900 E Benson Blvd SCANNED �VI Anchorage AK 99503 Anchorage AK 99508 N A ,.- a ..... (.ft DATA SUBMITTAL COMPLIANCE REPORT 2/16/2011 Permit to Drill 2090950 Well Name /No. PRUDHOE BAY UNIT E -09C Operator BP EXPLORATION (ALASKA) INC API No. 50- 029 - 20466 -03 -00 MD 13217 TVD 8987 Completion Date 11/22/2009 Completion Status 1 -OIL Current Status 1 -OIL UIC N REQUIRED INFORMATION Mud Log No Samples No Directional Survey Yes DATA INFORMATION • Types Electric or Other Logs Run: MWD DIR, GR, RES / GR, GR / CCL / CNL (data taken from Logs Portion of Master Well Data Maint Well Log Information: Log/ Electr Data Digital Dataset Log Log Run Interval OH / Ty. - MedlFrmt Number Name Scale Media No Start Stop CH Received Comments P' og Neutron 5 Blu 9300 13177 Case 6/11/2010 MCNL, GR, CCL, TNN, TNF D C Lis 19732 �Jeutron 9296 13176 Case 6/11/2010 LIS Veri, GR, CNT D C Asc Directional Survey 10645 12020 Open PB1 'pt Directional Survey 10645 12020 Open PB1 • C Asc Directional Survey 11059 13217 Open pt Directional Survey 11059 13217 Open 'pt LIS Verification 10367 13207 Open 1/18/2011 LIS Veri, GR, ROP, RAD, RAS, RPD, RPS D C Lis 20647' nduction /Resistivity 10367 13207 Open 1/18/2011 LIS Veri, GR, ROP, RAD, RAS, RPD, RPS . og Induction /Resistivity 25 Cot 10610 13217 Open 1/18/2011 MD MPR, GR ,Log Induction /Resistivity 5 Col 10610 13217 Open 1/18/2011 TVD MPR, GR og Gamma Ray 25 Col 10610 13217 Open 1/18/2011 MD GR og Gamma Ray 5 Col 10360 13210 Open 1/18/2011 Depth Shift Monitor Plot Rpt LIS Verification 10397 12020 Open 2/3/2011 PB1 LIS Veri, GR, ROP, RAD, RAS, RPD, RPS D C Lis 20700 'LIS Verification 10397 12020 Open 2/3/2011 PB1 LIS Veri, GR, ROP, RAD, RAS, RPD, RPS - Induction /Resistivity 25 Blu 10613 12020 Open 2/3/2011 PB1 MD MPR, GR DATA SUBMITTAL COMPLIANCE REPORT 2/16/2011 Permit to Drill 2090950 Well Name /No. PRUDHOE BAY UNIT E -09C Operator BP EXPLORATION (ALASKA) INC API No. 50- 029 - 20466 -03 -00 MD 13217 TVD 8987 Completion Date 11/22/2009 Completion Status 1-OIL Current Status 1 -OIL UIC N `-°9 Induction /Resistivity 5 Blu 10613 12020 Open 2/3/2011 PB1 ND MPR, GR , 4L g Induction /Resistivity 25 Blu 10613 12020 Open 2/3/2011 PB1 MD GR -K°g Gamma Ray 5 Blu 10367 11990 Open 2/3/2011 PB1 Depth Shift Monitor Well Cores/Samples Information: Sample Interval Set Name Start Stop Sent Received Number Comments ADDITIONAL INFORMA J,ON Well Cored? / N Daily History Received? Chips Received? Y Formation Tops Y N Analysis Y / N Received? Comments: Compliance Reviewed By: r .mi , filri Date: _..__.,) _ 1:!_/_.._.._. J__2 I_ I II ,, INTEQ Log & Data Transmittal Form To: State of Alaska -AOGCC 333 W. 7 Ave. Suite 100 Anchorage, Alaska 99501 Attention: Christine Mahnken Reference: E -09C Contains the following: �C 1 LDWG Compact Disc (Includes Graphic Image files) 1 LDWG lister summary 1 color print — GR Directional Measured Depth Log (to follow) I 1 color print — MPR/Directional TVD Log (to follow) 1 color print — MPR/Directional Measured Depth Log (to follow) LAC Job #: 2862351 tC Sent by: Debbie Hoke Date: 1113/2 i L,E1VED Received by: Date: JAN 1 `' 2011 Alaska Oil 8, Gas Cons. Commission PLEASE ACKNOWLEDGE RECEIPT BY SIGNINChitaliKURNING OR FAXING YOUR COPY FAX: (907) 267 -6623 Baker Hughes INTEQ (P'l —043 >j -b(,L( 2 7260 Homer Drive BAKER Anchorage, Alaska 99518 NIMES Direct: (907) 267 -6612 INTEQ FAX: (907) 267 -6623 • /ARM WGI4ES Baker Atlas PRINT DISTRIBUTION LIST COMPANY BP EXPLORATION (ALASKA) INC COUNTY NORTH SLOPE BOROUGH WELL NAME E -09C STATE ALASKA FIELD PRUDHOE BAY UNIT DATE 1/13/2011 THIS DISTRIBUTION LIST AUTHORIZED BY: DEBBIE HOKE SO #: 2862351 Copies of Copies Digital Copies of Copies Digital Each Log of Film Data Each Log of Film Data 2 Company BP EXPLORATION (ALASKA) INC 1 Company DNR - DIVISION OF OIL & GAS Person PETROTECHNICAL DATA CENTER Person CORAZON MANAOIS Address LR2 -1 Address 550 WEST 7TH AVE 900 E BENSON BLVD. SUITE 800 ANCHORAGE, AK 99508 ANCHORAGE, AK 99501 1 Company EXXON MOBIL PRODUCTION CO Company Person FILE ROOM Person Address 800 BELL STREET Address EMB GSC 3082A HOUSTON, TX 77002 1 Company STATE OF ALASKA - AOGCC Company Person CHRISTINE MAHNKEN Person Address 333 W. 7TH AVE Address SUITE 100 ANCHORAGE, AK 99501 Company Company Person Person Address Address Company Company Person Person Address Address Data Disseminated By: BAKER ATLAS -PDC 17015 Aldine Westfield, Houston, Texas 77073 This Distribution List Completed By: REC EIVED JA.N i 2011 aka Oil & Gas Cons. Commission Page 1 of 1 06/08/10 Schfmnherger NO. 5538 Alaska Data & Consulting Services Company: State of Alaska 2525 Gambell Street, Suite 400 Alaska Oil & Gas Cons Comm Anchorage, AK 99503-2838 Attn: Christine Mahnken ATTN: Beth 333 West 7th Ave, Suite 100 Anchorage, AK 99501 I I Well Job * Log Description - - Date BL Color CD E -058 BD88 -00015 MEM PROD PROFILE tj�if: 05/20/10 1 'j%�LVi 1 V -220 BCUE -00019 MEM INJECTION PROF! E � • �, • 05 /1 6 /10 1 jiir�.�r 1 ,. E -09C AXBD -00062 MCNL TiL��►y�i _ �' �%' 1 D -13A BBUO -00008 RST )(1n - , 03/09/10 1 /9 �C , 1 - 09 -44A 10AKAO043 OH MWD WD EDIT „ a 03/09/10 1 1 09- 44APB1 10AKA0043 OH MWD/LWD EDIT . - - 03/08/10 2 • " 1 17 -12A O9AKAOO79 OH MWD/LWD EDIT . .-," 03/10/10 2 _Jr, 1 PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING ONE COPY EACH TO: BP Exploration (Alaska) Inc. Alaska Data & Consulting Services Petrol Bhnisal Data Center LR2 -1 2525 Gambol) Street, Suite 400 900 E. Benson Blvd. Anchorage, AK 99503 -2838 / / , f ` ,.SUN t i Linn r , <d Gum. ;. C..r oa6'ddmi sf 1 Anchofs,14';' } • STATE OF ALASKA • Hit, 14 2009 ALASKA OIL AND GAS CONSERVATION COMMISSION ld {,: t Gas L ens. Commission WELL COMPLETION OR RECOMPLETION REPORT AND LOS$ I Drags la. Well Status: ® Oil ❑ Gas ❑ SPLUG ❑ Plugged ❑ Abandoned ❑ Suspended 1b. Well Class: 2OAAC 25.105 2OAAC 25. 110 ® Development ❑ Exploratory ❑ GINJ ❑ WINJ ❑ WAG ❑ WDSPL ❑ Other No. of Completions One ❑ Service ❑ Stratigraphic 2. Operator Name: 5. Date Comp., Susp., or Aband.: 12. Permit to Drill Number: BP Exploration (Alaska) Inc. 11/22/2009 209 - 095 3. Address: 6. Date Spudded: 13. API Number: P.O. Box 196612, Anchorage, Alaska 99519 -6612 11/11/2009 50 - 029 - 20466 - - 4a. Location of Well (Govemmental Section): 7. Date T.D. Reached: 14. Well Name and Number: Surface: 11/18/2009 PBU E-09C 243' FNL, 500' FEL, SEC. 06, T11 N, R14E, UM 8. KB (ft above MSL): 65.01' 15. Field / Pool(s): Top of Productive Horizon: 1132' FNL, 4295' FWL, SEC. 05, T11 N, R14E, UM GL (ft above MSL): 30.16' Prudhoe Bay Field / Prudhoe Bay Total Depth: 9. Plug Back Depth (MD +TVD): Oil Pool 2010' FNL, 2210' FWL, SEC. 05, T11 N, R14E, UM 13202' 8986' 4b. Location of Well (State Base Plane Coordinates, NAD 27): 10. Total Depth (MD +TVD): 16. Property Designation: Surface: x- 664447 y- 5976820 Zone- ASP4 13217' 8987' ADL 028304 TPI: x- 669264 y- 5976039 Zone- ASP4 11. SSSV Depth (MD +TVD): 17. Land Use Permit: Total Depth: x- 667202 Y 5975115 Zone- ASP4 None 18. Directional Survey: Yes ❑ No 19. Water depth, if offshore: 20. Thickness of Permafrost (TVD): (Submit electronic and printed information per 20 AAC 25.050) N/A ft MSL 1900' (Approx.) 21. Logs Obtained (List all logs here and submit electronic and printed information per 20 AAC 25.071): 22. Re -Drill /Lateral Top Window MD/TVD: MWD DIR, GR, RES / GR, GR / CCL / CNL 10613' 8700' 23. CASING, LINER AND CEMENTING RECORD SETTING DEPTH MD SETTING DEPTH TVD HOLE AMOUNT CASING WT. PER FT. GRADE TOP BOTTOM To BOTTOM SIZE CEMENTING RECORD PULLED See Attached 24. Open to production or injection? ® Yes ❑ No 25. TUBING RECORD If Yes, list each interval open SIZE DEPTH SET (MD) PACKER SET (MD / TVD) (MD +TVD of Top & Bottom; Perforation Size and Number): 1.56" Gun Diameter, 6 spf 4 -1/2 ", 12.6#, L -80 9542' 9495 / 7802' MD TVD MD TVD _ 11450' - 11630' 8935' - 8945' 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. 11810' - 12020' 8949' - 8969' 12160' - 12280' 8988' - 8993' . DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 12400' - 12860' 8992' - 8995' 2100' Freeze Protected with McOH 12900' - 12960' 8994' - 8992' 13050' - 13190' 8992' - 8986' 27. PRODUCTION TEST Date First Production: Method of Operation (Flowing, Gas Lift, etc.): December 1, 2009 Flowing Date of Test: Hours Tested: Production For OIL -BBL: GAS-MCF: WATER-BBL: CHOKE SIZE: GAS -OIL RATIO: 12/9/2009 6 Test Period ♦ 314 5,289 10 96 16,843 Flow Tubing Casing Press: Calculated OIL-BBL: GAS -MCF: WATER -BBL: OIL GRAVITY -API (CORR): Press. 800 1,100 24 -Hour Rate ♦ 1,256 21,155 38 27 28. CORE DATA Conventional Core(s) Acquired? ❑ Yes No Sidewall Core(s) Acquired? ❑ Yes ® No If Yes to either question, list formations and intervals cored (MD+TVD of top and bottom of each), and summarize lithology and presence of oil, gas or water (submit separate sheets with this form, if needed). Submit detailed descriptions, core chips, photographs and laboratory analytical results per 20 AAC 250.071. r61 . - 3.3 I /G C�3fR le °f#Utd € None re Rfl1�tsji,_ _- Form 10-407 Revised 07/2009 CONTINUED 0 RE E 3 I G�� %B: only 29. GEOLOGIC MARKERS (List all formations and mrs encountered): 411 0ORMATION TESTS NAME MD TVD Well Tested? ❑ Yes ® No Permafrost Top If yes, list intervals and formations tested, briefly summarizing test Permafrost Base results. Attach separate sheets to this form, if needed, and submit detailed test information per 20 AAC 25.071. 22TS 10652' 8730' None 21 TS / Zone 2A 10708' 8772' Zone 1B 10808' 8839' TDF / Zone 1A 10878' 8883' Zone 1 A (invert) / Base Zone 1B 13053' 8992' Formation at Total Depth (Name): Zone 1B (From Base) 13053' 8992' 31. List of Attachments: Summary of Daily Drilling Reports, Well Schematic Diagram, Surveys 32. I hereby certify that the foregoing is true and correct to the best of my knowledge. � '27,1 /c Signed: Terrie Hubble , I ll ' 'j 1 ' Title: Drilling Technologist Date: PBU E 209 - 095 Prepared By Name/Number Terrie Hubble, 564 -4628 Well Number Permit No. / Approval No. Drilling Engineer: Cody Hinchman, 564 -4468 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. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed. Item la: Classification of Service Wells: Gas Injection, Water Injection, Water - Alternating -Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item 4b: TPI (Top of Producing Interval). Item 8: The Kelly Bushing and Ground Level elevation in feet above mean sea level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 13: The API number reported to AOGCC must be 14 digits (ex: 50-029- 20123 -00 -00). Item 20: Report true vertical thickness of permafrost in Box 20. Provide MD and TVD for the top and base of permafrost in Box 28. Item 23: Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool. Item 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut -In, or Other (explain). Item 28: Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Submit detailed description and analytical laboratory information required by 20 AAC 25.071. Item 30: Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Form 10-407 Revised 07/2009 Submit Original Only • ! WELL NAME: E -09C 23. Attachment - Casing, Liner and Cementing Record Casing Setting Depth MD Setting Depth TVD Hole Size Wt. Per Ft. Grade Top Bottom Top Bottom Size Cementing Record 20" x 30" Insulated Conductor Surface 110' Surface 110' 36" 11.8 cu yds Arcticset 13 -3/8" 72# L -80 Surface 2671' Surface 2671' 17 -1/2" 2790 cu ft Arcticset 11 9 -5/8" 47# L -80 Surface 10213' Surface 8386' 12 -1/4" 1455 cu ft Class 'G', 130 cu ft Arcticset 7" 29# L -80 9717' 10558' 7983' 8658' 8-1/2" 253 cu ft Class 'G' 5" 15# 13Cr80 9553' 10613' 7849' 8700' 6" 286 cu ft Class 'G' 3-1/2" x 3- 3/16" 9.3# / 6.2# L -80 10103 10613' 8298' 8700' 3 -3/4" 140 cu ft Class 'G' 2 -3/8" 4.7# L -80 9452' 13217' 7767' 8987' 3" 101 cu ft Class 'G' I rJD0w • • • BP EXPLORATION Page 1 of 14 Operations Summary Report Legal Well Name: E -09 Common Well Name: E -09 Spud Date: 5/4/1980 Event Name: REENTER +COMPLETE Start: 11/7/2009 End: 11/22/2009 Contractor Name: NORDIC CALISTA Rig Release: 11/22/2009 Rig Name: NORDIC 1 Rig Number: N1 Date From To Hours Task Code NPT Phase Description of Operations 11/7/2009 13:30 - 00:00 10.50 MOB P PRE MOVE RIG FROM DS 18 -11A TO E -09C 11/8/2009 00:00 - 00:30 0.50 MOB P PRE MOVE RIG FROM 18 -11A TO E -09C 00:30 - 16:30 16.00 MOB N PRE TIRE RUPTURED ON THE DRILLER'S SIDE REAR, INNER TIRE. RIG IS LOCATED ON K PAD ROAD 300 YARDS FROM THE E PAD ENTRANCE. C/O TIRE. C/O STEERING LINK BUSHING. WARM UP DRIVE SYSTEM 16:30 - 19:30 3.00 MOB N PRE WAIT ON SECURITY. 19:30 - 20:30 1.00 MOB N PRE SAFETY MEETING, RE: MOVE TO E- PAD COMPLETE MOVE TO E -PAD & LINE UP ON THE WELL SAFETY MEETING, RE: MOVE OVER THE WELL BACK OVER THE WELL 20:30 - 00:00 3.50 RIGU N PRE * * * * * * ** *ACCEPT RIG @ 20:30 * * * * * * * * * * ** SPOT CUTTING BOX, SPOT SAT CAMP, SPOT TIGER TANK & RU HARDLINE, NU BOP 11/9/2009 00:00 - 01:00 1.00 BOPSUF P PRE NI l ROP RFBUILD BOP KILL LINE VALVE 01:00 - 08:30 7.50 BOPSUF P PRE PRESSURE TEST BOPE. WITNESS WAIVED BY BOB NOBEL, AOGCC TEST VALVES TO 3500 PSI, ANNULAR TO 2500 PSI. 08:30 - 14:45 6.25 STWHIP P WEXIT CIRCULATE MEOH FROM CT. RU AND PUMP SLACK INTO CT.@ 2.7 bpm 4600 psi. CUT 330" OF CT. INSTALL CTC & PULL TEST TO 30k. Head up Baker. 14:45 - 15:00 0.25 RIGU P PRE PJSM FOR PICKING UP OF LUBRICATOR AND PULLING BPV. 15:00 - 16:15 1.25 RIGU P PRE PU LUBRICATOR. TEST LUBRICATOR TO 1000 PSI. PULL BPV. CLOSE MASTER. LD LUBRICATOR 16:15 - 16:40 0.42 STWHIP P WEXIT SAFETY MEETING, RE: PU MILLING BHA 16:40 - 18:00 1.33 STWHIP P WEXIT PU WINDOW MILLING BHA W/ COILTRAK, 2 -1/8" EXTREME MOTOR, 2.74" DIAMOND STRING MILL, & 2.74" WINDOW MILL. OAL= 47.65' OPEN EDC, PUMP 1.5 BPM FOR 40 BBLS TO PUMP SLACK FORWARD. 18:00 - 19:30 1.50 STWHIP P WEXIT RIH TO 6180' 19:30 - 20:15 0.75 STWHIP N HMAN WEXIT POH FOR 2.7" SPIRAL CENTRALIZER & 2 JTS 2 -1/6" CSH 20:15 - 20:30 0.25 STWHIP N HMAN WEXIT SAFETY MEETING, RE: BHA CHANGE 20:30 - 21:30 1.00 STWHIP N HMAN WEXIT UD COILTRAK PU 2.7" SPIRAL CENTRALIZER & 2 JTS 2- 1/16" CSH PU COILTRAK 21:30 - 22:40 1.17 STWHIP N HMAN WEXIT RIH WINDOW MILLING BHA TO 6180'. 22:40 - 23:30 0.83 STWHIP P WEXIT RIH 23:30 - 00:00 0.50 STWHIP P WEXIT LOG TIE -IN 11/10/2009 00:00 - 00:20 0.33 STWHIP P WEXIT LOG TIE -IN, -9' CORRECTION 00:20 - 01:00 0.67 STWHIP P WEXIT PU WEIGHT = 33K# RIH. DRY TAG TOWS @ 10610', PU 20', FS = 2330 PSI @ 1.61 BPM BEGIN TIME MILLING 01:00 - 02:10 1.17 STWHIP P WEXIT GAS IN THE RETURNS PUH, OPEN EDC, CIRCULATE OUT GAS @ 2.2 BPM. PUMP 140 BBL TO CLEAN UP GAS (120 BBL CALC. HOLE VOL) Printed: 12/10/2009 11:15:44 AM BP EXPLORATION Page 2 of 14 Operations Summary Report Legal Well Name: E -09 Common Well Name: E -09 Spud Date: 5/4/1980 Event Name: REENTER +COMPLETE Start: 11/7/2009 End: 11/22/2009 Contractor Name: NORDIC CALISTA Rig Release: 11/22/2009 Rig Name: NORDIC 1 Rig Number: N1 Date From - To Hours Task Code NPT Phase Description of Operations 11/10/2009 01:00 - 02:10 1.17 STWHIP P WEXIT CLOSE EDC 02:10 - 06:00 3.83 STWHIP P WEXIT FS = 2930 © 1.63 BPM RIH TO 10606'. TIME MILL AHEAD. PINCH POINT = 10607.6'. DEPTH /CIRC PSI /DHWOB 10607.80', 3050PSI, 0.85K# 10607.85', 3025PSI, 0.83K# 10608.00', 3080PSI, 1.22K# 10608.10', 3120PSI, 1.42K# 10608.30', 3080PSI, 1.52K# 10608.60', 3120PSI, 1.84K# 10608.70', 3260PSI, 2.20K# 10608.80', 3285PSI, 2.31K# 06:00 - 12:00 6.00 STWHIP P WEXIT 10609.10' 3278 PSI, 2.70K# 10609.20' 3252 PSI, 2.70K# 10609.40' 3252 PSI, 2.70K# 10609.80' 3230 PSI, 3.19K# 10610.00' 3230 PSI, 3.41K# 10610.50' 3212 PSI, 3.62K# 10610.90' 3240 PSI, 3.62K# 12:00 - 17:00 5.00 STWHIP P WEXIT MILL 2.74" DUAL EXIT LOWSIDE WINDOW THRU 3- 3/16" AND 5" LINERS. 1 -2K WOB, 2950 -3500 PSI, 1/4 -1/2" FPH, FIRST STALL AT 10,612.3'. PROBABLE EXIT POINT. TIME MILL NEXT 1.7' AT 1 FPH TO REAM WINDOW AREA. MILLED TO 10613.5'. 17:00 - 21:15 4.25 STWHIP P WEXIT MILL 10' FORMATION TO 10623'. 3K WOB, 7 FPH. 1.6 BPM, 2950 -3400 PSI. START MUD SWAP, REAM WINDOW 2X. 21:15 - 22:10 0.92 STWHIP N DPRB WEXIT STUCK © 10606' ON SECOND BACKREAM THROUGH WINDOW. HUNG UP ON THE BIT AT THE TOP OF THE WINDOW. LOOKED LIKE MOTOR WORK BUT TURNED INTO A SLOW MOTOR STALL. NORMAL PU WT = 33.5K# DOWN ON PUMPS. PU TO 10K# OVER PU WT. NEUTRAL WT, PUMPS ON, PRESSURE UP TO 3800 PSI. DOWN ON PUMPS. STACK 4.2K# DHWOB. GO TO NEUTRAL WT. RAMP PUMPS TO 4000 PSI 5 TIMES. OPEN EDC, PUMP 2.2 BPM, WORK PIPE BETWEEN 7K# OVER PULL & 3.5K# DHWOB, 8 TIMES. GO TO NEUTRAL WT, CLOSE EDC. STACK 8K# DHWOB & POP FREE. RIH TO 10720'. 22:10 - 00:00 1.83 STWHIP P WEXIT BACK REAM THROUGH WINDOW AT 0.2 FPM CLEANING UP WINDOW. REAM DOWN & UP TWICE MORE PUMPS OFF, RIH DRY THROUGH WINDOW. WINDOW IS CLEAN. 11/11/2009 00:00 - 01:15 1.25 STWHIP P WEXIT POH 01:15 - 01:30 0.25 STWHIP P WEXIT SAFETY MEETING, RE: BHA CHANGE 01:30 - 03:15 1.75 DRILL P PROD1 UD MILLING BHA. MILL GAUGED 2.71" NO GO & STRING REAMER 2.73" NO GO. TEST COILTRAK AT SURFACE PU DRLG BHA Printed: 12/10/2009 11:15:44 AM BP EXPLORATION Page 3 of 14. Operations Summary Report Legal Well Name: E -09 Common Well Name: E -09 Spud Date: 5/4/1980 Event Name: REENTER +COMPLETE Start: 11/7/2009 End: 11/22/2009 Contractor Name: NORDIC CALIST A Rig Release: 11/22/2009 Rig Name: NORDIC 1 Rig Number: N1 Date From To Hours Task Code NPT Phase Description of Operations 11/11/2009 03:15 - 05:00 1.75 DRILL P PROD1 RIH DRLG BHA WITH 2.5 DEG AKO & HYC TREX BIT 05:00 - 05:20 0.33 DRILL P PROD1 LOG TIE -IN, -10' CORRECTION 05:20 - 07:20 2.00 DRILL P PROD1 RIH, TAG BOTTOM CP 10623'. DRILL BUILD SECTION IN ZONE 2B 1.7 BPM IN / 1.7 BPM OUT @ 2750 PSI, FS =2480 PSI 1.5K# DHWOB, 60 FPH, 150R TF, 41 DEG INC IA =140 PSI, OA =0 PSI, PVT= 341 BBL LOCATE RA TAG AT 10,613.2'. TOP OF WINDOW AND WHIPSTOCK AT 10,608'. BOTTOM OF WINDOW AT 10,614'. DRILLED TO 10702'. 07:20 - 10:30 3.17 DRILL P PROD1 DRILL ZONE 2 TURN SECTION. 1.6 BPM, 2300 -2700 PSI, 130 R TF, 2.2K WOB, 50 FPH, DRILLED TO 10800'. 10:30 - 10:50 0.33 DRILL P PROD1 CLEAN WIPER TRIP TO WINDOW. RIH CLEAN TO BOTTOM. 10:50 - 13:15 2.42 DRILL P PROD1 DRILL ZONE 2 TURN SECTION. 1.6 BPM, 2300 -2700 PSI, 90 R TF, 1 -2K WOB, 30 -50 FPH, DRILLED TO 10864' 13:15 - 15:00 1.75 DRILL N DPRB PROD1 POH FOR LESS BEND ON MOTOR, GETTING 50 DEG DLS AND NEED 35 DLS. PULL CLEAN THRU WINDOW. OPEN EDC. POH WHILE CIRC AT 1.8 BPM, 2000 PSI. 15:00 - 15:15 0.25 DRILL N DPRB PROD1 SAFETY MEETING. REVIEW PROCEDURE, HAZARDS AND MITIGATION FOR CHANGING DRILLING BHA. 15:15 - 16:00 0.75 DRILL N DPRB PROD1 UO COILTRAK BHA #3. 16:00 - 16:45 0.75 DRILL P PROD1 SAFETY MEETING WITH NORDIC, NALCO, BP, MI AND ORBIS. 16:45 - 17:15 0.50 DRILL N DPRB PROD1 M/U COILTRAK BUILD BHA #4 WITH 1.9 DEG MOTOR AND RE -BUILD HYC T -REX BIT #2. 17:15 - 19:10 1.92 DRILL N DPRB PROD1 RIH WITH DRILLING BHA #4. CIRC AT 0.3 BPM, 850 PSI. 19:10 - 19:25 0.25 DRILL N DPRB PROD1 LOG TIE -IN, -12' CORRECTION 19:25 - 19:55 0.50 DRILL N RREP PROD1 SLOW DRIP FOUND ON THE HARDLINE IN THE REELHOUSE. SHUT DOWN THE PUMPS, PULL UP INTO CASED HOLE. CHANGEOUT SEAL ON 1/4 TURN BALL VALVE. 19:55 - 23:00 3.08 DRILL P PROD1 RIH TO TD. WORK DOWN THROUGH HIGH DOGLEG SECTION. DRILL BUILD SECTION IN ZONE 2 FROM 10864' 1.7 BPM IN / 1.7 BPM OUT @ 2800 -3100 PSI, FS =2560 PSI 1.0K -2.5K# DHWOB, 20 -100 FPH, 30L -30R TF, 61 -71 DEG INC IA =200 PSI, OA =60 PSI, PVT= 336 BBL DRILL TO 11000'. END OF BUILD SECTION. 23:00 - 00:00 1.00 DRILL P PROD1 POH FOR LATERAL BHA 11/12/2009 00:00 - 01:00 1.00 DRILL P PROD1 POH FOR LATERAL DRILLING BHA 01:00 - 01:15 0.25 DRILL P PROD1 SAFETY MEETING, RE: BHA CHANGE 01:15 - 02:15 1.00 DRILL P PROD1 UD BUILD BHA PU RES TOOL, 1.1 DEG AKO MTR, & HCC BIT 02:15 - 04:10 1.92 DRILL P PROD1 RIH 04:10 - 05:25 1.25 DRILL P PROD1 LOG TIE -IN, -16' CORRECTION, RIH TO TD MAD PASS FROM TD TO WINDOW, RIH CLEAN TO BOTTOM. Printed: 12/10/2009 11:15:44 AM • BP EXPLORATION Page 4 of 14 Operations Summary Report Legal Well Name: E -09 Common Well Name: E -09 Spud Date: 5/4/1980 Event Name: REENTER +COMPLETE Start: 11/7/2009 End: 11/22/2009 Contractor Name: NORDIC CALISTA Rig Release: 11/22/2009 Rig Name: NORDIC 1 Rig Number: N1 Date From - To Hours Task Code NPT Phase Description of Operations 11/12/2009 05:25 - 07:15 1.83 DRILL P PROD1 DRILL ZONE 1A LATERAL FROM 11,000' 1.6 BPM IN / 1.6 BPM OUT @ 2600 -2700 PSI, FS =2430 PSI 2.0K# DHWOB, 100 FPH, 90R TF, 86 DEG INC IA =170, OA =75, PVT =330, ECD =9.42 DRILLED TO 11,150'. 07:15 - 08:00 0.75 DRILL P PROD1 WIPER TRIP TO WINDOW. CLEAN HOLE. RIH CLEAN TO BOTTOM. 08:00 - 10:15 2.25 DRILL P PROD1 DRILL Z1A LATERAL. 1.6 BPM, 2350 -3100 PSI, 2 -3K WOB, 85 R TF, 90 FPH, 9.5 ECD, 91 DEG INCL, DRILLED TO 11300'. 10:15 - 10:45 0.50 DRILL P PROD1 WIPER TRIP TO WINDOW. CLEAN HOLE. RIH CLEAN TO BOTTOM. 10:45 - 11:05 0.33 DRILL P PROD1 DRILL Z1A LATERAL. 1.6 BPM, 2350 -3100 PSI, 2 -3K WOB, 5 R TF, 90 FPH, 9.5 ECD, 88 DEG INCL, DRILLING HIGHSIDE AND STILL LOOSING INCL. DRILLED TO 11,335'. 11:05 - 13:00 1.92 DRILL N DPRB PROD1 POH FOR STRONGER BEND MOTOR TO BUILD INCL. PULL CLEAN THRU WINDOW. OPEN EDC. POH. 13:00 - 13:15 0.25 DRILL N DPRB PROD1 SAFETY MEETING. REIVEW PROCEDURE, HAZARDS AND MITIGATION FOR CHANGING BHA. 13:15 - 15:00 1.75 DRILL N DPRB PROD1 CHECK LAST 130' OF COIL FOR WEAR. NO WEAR. UO BHA. ADJUST MOTOR TO 1.5 DEG BEND. M/U RE -BUILD HYC BC BIT #4. 15:00 - 16:50 1.83 DRILL N DPRB PROD1 RIH WITH COILTRAK / RES LAT BHA #6, CIRC 0.2 BPM, 950 PSI. 16:50 - 17:10 0.33 DRILL N DPRB PROD1 LOG GR TIE -IN AT RA TAG. -14' CTD. 17:10 - 17:30 0.33 DRILL N DPRB PROD1 RIH CLEAN TO BOTTOM. 17:30 - 19:20 1.83 DRILL P PROD1 DRILL Z1A LATERAL. 1.6 BPM, 2400 -3100 PSI, 2 -3K WOB, 10 R TF, 80 FPH, 9.5 ECD, DRILL TO 11,500' 19:20 - 20:20 1.00 DRILL P PROD1 WIPER TO WINDOW 20:20 - 22:15 1.92 DRILL P PROD1 DRILL Z1A LATERAL 1.6/1.6 BPM @ 2700 -2800 PSI, FS =2400 PSI 1.5K -2.0K# DHWOB, 100 FPH, 92 DEG INC IA =250, OA =225, PVT =336, ECD =9.6 DRILL TO 11,650' 22:15 - 23:30 1.25 DRILL P PROD1 WIPER TO WINDOW 23:30 - 00:00 0.50 DRILL P PROD1 DRILL Z1A LATERAL 1.6/1.6 BPM @ 2750 -2850 PSI, FS =2400 PSI 1.5K #DHWOB, 20 -100 FPH, 91 -86 DEG INC IA =280, OA =310, PVT =330, ECD =9.7 DRILL TO 11,660' 11/13/2009 00:00 - 01:30 1.50 DRILL P PROD1 DRILL Z1A LATERAL FROM 11,660' 1.6/1.6 BPM CO 2750 -2850 PSI, FS =2400 PSI 1.5K# DHWOB, 100 FPH, 88 -83 DEG INC IA =280, OA =310, PVT =325, ECD =9.7 DRILL TO 11,800' 01:30 - 02:30 1.00 DRILL P PROD1 WIPER TO WINDOW 02:30 - 02:40 0.17 DRILL P PROD1 LOG TIE -IN, +2' CORRECTION 02:40 - 03:15 0.58 DRILL P PROD1 FAULTED UP INTO ZONE 1B AND NOW HAVE A CLOSE APPROACH WITH WELL K -19A. CALL TOWN TO ENSURE WE CAN PROCEED ON THE PRESENT COURSE WHICH WILL TAKE US 17' TVD ABOVE THE K -19A WELL PATH. Printed: 12/10/2009 11:15:44 AM • BP EXPLORATION Page 5 of 14 Operations Summary Report Legal Well Name: E -09 Common Well Name: E -09 Spud Date: 5/4/1980 Event Name: REENTER +COMPLETE Start: 11/7/2009 End: 11/22/2009 Contractor Name: NORDIC CALISTA Rig Release: 11/22/2009 Rig Name: NORDIC 1 Rig Number: N1 Date From - To Hours Task Code NPT Phase Description of Operations 11/13/2009 02:40 - 03:15 0.58 DRILL P PROD1 RECEIVED THE OK FROM TOWN TO PROCEED. 03:15 - 03:50 0.58 DRILL P PROD1 WIPER TO TD 03:50 - 05:25 1.58 DRILL P PROD1 DRILL LATERAL IN ZONE 1 B. 1.6/1.6 BPM @ 2700 -2850 PSI, FS =2500 PSI 1.0K -1.5K# DHWOB, 100 -120 FPH, 83 -86 DEG INC IA =280, 0A =330, PVT =321, ECD =9.7 DRILL TO 11,950' 05:25 - 06:50 1.42 DRILL P PROD1 WIPER TO WINDOW, CLEAN HOLE UP AND DOWN. 06:50 - 07:20 0.50 DRILL P PROD1 MAD PASS WITH RES FROM 11630-11740'. 07:20 - 08:00 0.67 DRILL P PROD1 DRILLED TO 12016'. GEO CALLED TD FOR OPENHOLE SIDETRACK. 08:00 - 09:00 1.00 DRILL C PROD1 WIPER TRIP WHILE PREPARING FOR FLUID SWAP. 09:00 - 09:30 0.50 DRILL C PROD1 SWAP TO NEW GEOVIS FROM 12016'. 09:30 - 11:45 2.25 DRILL C PROD1 POH WHILE SWAPPING WELL TO NEW GEOVIS. 1.6 BPM, 2750 PSI. PULL CLEAN THRU WINDOW. OPEN EDC, POH. CIRC 2.2 BPM, 2600 PSI. 11:45 - 12:00 0.25 DRILL C PROD1 SAFETY MEETING. REVIEW PROCEDURE, HAZARDS AND MITIGATION FOR L/O DRILLING BHA 12:00 - 12:45 0.75 DRILL C PROD1 UO COILTRAK RES BHA. 12:45 - 13:00 0.25 DRILL C PROD1 SAFETY MEETING. REVIEW PROCEDURE, HAZARDS AND MITIGATION FOR M/U BTT AL BILLETT AND COILTRAK BHA 13:00 - 14:00 1.00 DRILL C PROD1 M/U 2.63" BTT AL BILLETT AND COILTRAK BHA OAL = 69.59' 14:00 - 16:15 2.25 DRILL C PROD1 RIH WITH BILLETT BHA # 7. OPEN EDC. CIRC AT 0.2 BPM UP WT AT 10600' = 31K. DWN WT = 17K WENT THRU WINDOW CLEAN. 16:15 - 16:30 0.25 DRILL C PROD1 LOG GR TIE -IN, -9' CTD. 16:30 - 17:00 0.50 DRILL C PROD1 RIH CLEAN TO SETTING DEPTH. POSITION TOP OF AL BILLETT AT 11,090' WITH A 5 DEG ROHS TF. SET BILLETT AT 4000 PSI SHEAR PRESS. STACK 3K WT ON BILLET. OK 17:00 - 18:45 1.75 DRILL C PROD1 POH CLEAN TO THE WINDOW. POH THRU WINDOW CLEAN. OPEN EDC. POH WHILE CIRC 2.2 BPM AT 2600 PSI. 18:45 - 19:00 0.25 DRILL C PROD1 SAFETY MEETING, RE: BHA CHANGE 19:00 - 21:00 2.00 DRILL C PROD1 UD AL BILLET SETTING TOOLS TEST COILTRAK TOOLS PU DRILLING BHA 21:00 - 23:00 2.00 DRILL C PROD1 RIH DRILLING BHA WITH 1.5 DEG AKO MOTOR & RERUN HYC BIT 23:00 - 23:15 0.25 DRILL C PROD1 LOG TIE -IN, -11' CORRECTION 23:15 - 00:00 0.75 DRILL C PROD1 RIH,TAG TOP OF BILLET @ 11,090', PUMPS OFF 11/14/2009 00:00 - 06:00 6.00 DRILL C PROD1 TAG BILLET @ 11,090' PUMPS OFF PU TO 11080', PUMPS ON 1.5 BPM @ 2370 PSI, PU WT= 30.8K# TIME MILL FROM 11.088' @ 1 FPH, 20 ROHS TF STALL AT 11,090'. PU TO 11,085'. TIME MILL FROM 11,089' @ 1 FPH, 20 ROHS TF STALL AT 11,089.9'. PU TO 11,082'. Printed: 12/10/2009 11:15:44 AM • • • BP EXPLORATION Page 6 of 14 Operations Summary Report Legal Well Name: E -09 Common Well Name: E -09 Spud Date: 5/4/1980 Event Name: REENTER +COMPLETE Start: 11/7/2009 End: 11/22/2009 Contractor Name: NORDIC CALISTA Rig Release: 11/22/2009 Rig Name: NORDIC 1 Rig Number: N1 Date From - To Hours Task Code NPT Phase Description of Operations 11/14/2009 00:00 - 06:00 6.00 DRILL C PROD1 TIME MILL FROM 11,089' @ 1 FPH, 20 ROHS TF TIME MILL FROM 11,089.6' @ 0.5 FPH, 20 ROHS TF STALL AT 11,090.45'. PU TO 11,082'. TIME MILL FROM 11,089.5' 0 1 FPH, 20 ROHS TF. SLOW TO 0.5 FPH AT 11,090' 06:00 - 07:30 1.50 DRILL C PROD1 TIME DRILL TO 11090.4'. 5 STALLS AT THIS DEPTH. NOT ABLE TO TIME DRILL, STICK/SLIP GOING ON WHERE WOB COMES UP QUICK AND STALLS. 07:30 - 10:00 2.50 DRILL C PROD1 DRILL DOWN AT 8 FPH, TRY TO KEEP COIL SLIDING. 1.6 BPM, 2460 PSI, 3 STALLS AT 11090'. FINALLY DRILLED OFF WOB AND MOTOR WORK WITHOUT A STALL. TIME DRILL AGAIN AT 11090.5'. 1 FPH DRILLED TO 11093' 10:00 - 12:00 2.00 DRILL C PROD1 DRILL OHST OFF OF BILLETT AT 8 FPH TO 11094', 30 R TF. DRILL AT 20 FPH, 30R TF, TO 11100'. DRILL 30 FPH, 7OR TF TO 11,110'. BACK REAM OHST AT 30R. CLEAN, RIH CLEAN, NO PUMP BACK REAM OHST AT 80R. CLEAN, RIH CLEAN, NO PUMP BACK REAM OHST AT 30L, CLEAN, RIH CLEAN, NO PUMP 12:00 - 14:00 2.00 DRILL C PROD1 DRILL Z1A LAT, 1.6 BPM, 2500 -2900 PSI, 2K WOB, 8OR TF, 50 -80 FPH, 9.4 ECD. Drilled to 11200'. 14:00 - 14:45 0.75 DRILL C PROD1 DRILL Z1A LAT, 1.6 BPM, 2500 -3000 PSI, 2 -3K WOB, 110R TF, 50 -80 FPH, 9.5 ECD. DRILLED TO 11250' 14:45 - 15:30 0.75 DRILL C PROD1 WIPER TRIP TO WINDOW. CLEAN HOLE. RIH CLEAN TO BOTTOM. 15:30 - 16:45 1.25 DRILL C PROD1 DRILL Z1A LAT, 1.6 BPM, 2550 -3000 PSI, 1 -2K WOB, 110R TF, 50 -80 FPH, 9.5 ECD. DRILLED TO 11350'. 16:45 - 17:30 0.75 DRILL C PROD1 DRILL Z1A LAT, 1.6 BPM, 2550 -3000 PSI, 1 -2K WOB, 11OR TF, 50 -80 FPH, 9.5 ECD. DRILLED TO 11400'. 17:30 - 18:30 1.00 DRILL C PROD1 WIPER TRIP TO WINDOW. CLEAN HOLE. RIH CLEAN TO BOTTOM. 18:30 - 20:45 2.25 DRILL C PROD1 DRILL Z1A LAT 1.6 IN /1.6 OUT BPM CO 3000 PSI, FS =2600 2.0K -2.5K# DHWOB, 60 -80 FPH, 90L -120L TF, IA =265, OA =355, PVT =313, ECD =9.6 DRILL TO 11550' 20:45 - 21:20 0.58 DRILL C PROD1 WIPER TO WINDOW 21:20 - 21:30 0.17 DRILL C PROD1 LOG TIE -IN, +2.5' 21:30 - 22:00 0.50 DRILL C PROD1 WIPER TO TD 22:00 - 00:00 2.00 DRILL C PROD1 DRILL Z1A LATERAL 1.5/1.5 BPM © 2850 -2900 PSI, FS =2600 2.0K# DHWOB, 80 FPH, 11OR TF IA =255, OA =350, PVT =310, ECD =9.6 DRILL TO 11,660' 11/15/2009 00:00 - 00:30 0.50 DRILL C PROD1 DRILL Z1A LATERAL TO 11700' 00:30 - 02:00 1.50 DRILL C PROD1 WIPER TO WINDOW 02:00 - 04:30 2.50 DRILL C PROD1 DRILL Z1A LATERAL Printed: 12/10/2009 11:15:44 AM • BP EXPLORATION Page 7 of 14 Operations Summary Report Legal Well Name: E -09 Common Well Name: E -09 Spud Date: 5/4/1980 Event Name: REENTER +COMPLETE Start: 11/7/2009 End: 11/22/2009 Contractor Name: NORDIC CALISTA Rig Release: 11/22/2009 Rig Name: NORDIC 1 Rig Number: N1 Date From - To Hours Task Code NPT Phase Description of Operations 11/15/2009 02:00 - 04:30 2.50 DRILL C PROD1 1.6 IN / 1.6 OUT BPM @ 2850 -2950 PSI, FS =2600 PSI 1.5K -2.0K# DHWOB, 30 -100 FPH, 60L -120L TF IA =275, OA =375, PVT =302, ECD =9.7 DRILL TO 11,850' 04:30 - 05:45 1.25 DRILL C PROD1 WIPER TO WINDOW 05:45 - 07:45 2.00 DRILL C PROD1 DRILL Z1A LATERAL 1.6/1.6 BPM © 3000 PSI, FS =2600 PSI 1.3K# DHWOB, 110 FPH, 12OR TF IA =290, OA =410, PVT =304, ECD =9.7 DRILLING CLEAN SAND .IY DRILLED TO 12,021' 07:45 - 08:20 0.58 DRILL P PROD1 WIPER TRIP TO WINDOW. CLEAN HOLE. 08:20 - 08:40 0.33 DRILL P PROD1 LOG GR TIE -IN AT RA TAG. +3' CORRECTION 08:40 - 09:15 0.58 DRILL P PROD1 RIH CLEAN TO BOTTOM. OHST IS CLEAN. RIH TO 11150'. BHI COILTRAK SURFACE INFORMATION FAILED. 09:15 - 10:45 1.50 DRILL N SFAL PROD1 POH TO ABOVE WINDOW WHILE REPAIRING DATA PROBLEM. CHECK TIE -IN TO CONFIRM DEPTH CONTROL. ON DEPTH WITH RA. RIH AGAIN TO 11150' 10:45 - 11:15 0.50 DRILL P PROD1 RIH CLEAN TO BOTTOM. 11:15 - 13:15 2.00 DRILL P PROD1 DRILL Z1A LAT IN GOOD SAND. 1.6 BPM, 2680 -3100 PSI, 100L TF, 83 DEG INCL, 1K WOB, 90 FPH, 9.7 ECD, STACKING WT. SWAP TO NEW GEOVIS, 1030' ON THIS MUD SYSTEM. DRILLED TO 12121'. 13:15 - 14:00 0.75 DRILL P PROD1 DRILL Z1A LAT. 1.6 BPM, 2680 -3100 PSI, 100L TF, 60 FPH DRILLED TO 12151 14:00 - 15:30 1.50 DRILL P PROD1 WIPER TRIP TO WINDOW. CLEAN HOLE. RIH CLEAN TO BOTTOM. 15:30 - 18:10 2.67 DRILL P PROD1 DRILL Z1A LAT. 1.6 BPM, 2550 -3200 PSI, 70R TF, 60 -90 FPH, 89 DEG INCL, 9.7 ECD, STACKING WT +1 K TO DRILL, DRILLED TO 12300'. 18:10 - 20:30 2.33 DRILL P PROD1 WIPER TRIP TO WINDOW. CLEAN HOLE. RIH CLEAN TO BOTTOM. 20:30 - 00:00 3.50 DRILL P PROD1 DRILL Z1A LATERAL 1.5/1.5 BPM © 2650 -2700 PSI, FS =2600 PSI 0.8K -1.5K# DHWOB, 20 -40 FPH, 90L TF, 92 -96 DEG INC IA =380, OA =300, PVT =315, ECD =9.7 DRILL TO 12375'. LOW WEIGHT TRANSFER, STACKING 7K# TO DRILL. 11/16/2009 00:00 - 00:30 0.50 DRILL P PROD1 DRILL ZONE 1A LATERAL FROM 12,375' STACKING 7K# CT WT AT SURFACE WITH 0.5K# DHWOB AND 10 TO 60 FPH ROP. PULL FOR AGITATOR & TO CHECK THE BIT 00:30 - 03:15 2.75 DRILL P PROD1 POH 03:15 - 03:30 0.25 DRILL P PROD1 SAFETY MEETING, RE: BHA CHANGE 03:30 - 03:50 0.33 DRILL P PROD1 S/B COILTRAK, UD MOTOR BIT GRADED 3,1 -BT 03:50 - 04:00 0.17 BOPSUF P PROD1 FUNCTION TEST BOPE ACTUATE LOWER 2" COMBI, 2 -3/8" COMBI, UPPER 2" COMBI, BLIND /SHEAR RAMS, ANNULAR PREVENTER, & Printed: 12/10/2009 11:15:44 AM • BP EXPLORATION Page 8 of 14 Operations Summary Report Legal Well Name: E -09 Common Well Name: E -09 Spud Date: 5/4/1980 Event Name: REENTER +COMPLETE Start: 11/7/2009 End: 11/22/2009 Contractor Name: NORDIC CALISTA Rig Release: 11/22/2009 Rig Name: NORDIC 1 Rig Number: N1 Date From - To Hours Task Code NPT Phase Description of Operations 11/16/2009 03:50 - 04:00 0.17 BOPSUF P PROD1 CHOKE LINE HCR VALVE. 04:00 - 05:00 1.00 DRILL P PROD1 pt AGITATOR 1 3 IDFC, AKO MOTOR & NFW HYC TRFX BC BIT. 05:00 - 06:45 1.75 DRILL P PROD1 RIH DRLG BHA, TEST AGITATOR @ 300', RIH. 06:45 - 07:10 0.42 DRILL P PROD1 LOG GR TIE -IN AT RA TAG, -8' CORRECTION. 07:10 - 07:40 0.50 DRILL P PROD1 RIH CLEAN TO BOTTOM, 1.3 BPM, 2850 PSI 07:40 - 10:00 2.33 DRILL P PROD1 DRILL Z1A LAT W/ RES TOOL. 1.5 BPM, 3400 -3900 PSI, 2K WOB, 80L TF, 90 INCL, DRILLED TO 12487'. 10:00 - 12:00 2.00 DRILL N DFAL PROD1 BHI ORIENTER FAILED. POH TO CHANGE BHA. PULL CLEAN THRU OHST AND WINDOW. OPEN EDC. CIRC 2.3 BPM, 2900 PSI. POH. 12:00 - 12:15 0.25 DRILL N DFAL PROD1 SAFETY MEETING. REVIEW PROCEDURE, HAZARDS AND MITIGATION FOR CHANGING BHA. 12:15 - 14:30 2.25 DRILL N DFAL PROD1 LAY OUT BHA, BIT GRADED AT 1,1,1. M/U COILTRAK / RES LAT BHA #10 WITH 1.3 DEG MOTOR AND RE -RUN HYC TREX BC BIT #7. 14:30 - 16:50 2.33 DRILL N DFAL PROD1 RIH WITH LAT / RES BHA #10, CIRC 0.2 BPM. 16:50 - 17:15 0.42 DRILL N DFAL PROD1 LOG GR TIE -IN AT RA TAG. -13.5' CORRECTION. 17:15 - 18:00 0.75 DRILL N DFAL PROD1 RIH TO BOTTOM, CIRC 1.5 BPM, 3300 PSI. 18:00 - 20:30 2.50 DRILL P PROD1 DRILL Z1A LAT FROM 12,487' 1.5/1.5 BPM @ 3250 -3800 PSI, FS =3200 PSI 1.0K -2.0K# DHWOB, 60 -100 FPH, 89 -86 DEG INCL, 90L TF IAP =280, OAP =5, PVT =307, ECD =9.9 DRILL TO 12642' 20:30 - 20:40 0.17 DRILL N STUC PROD1 DROP PUMP RATE TO 1.2 BPM FOR SURVEY & BECOME DIFFERENTIALLY STUCK PICK UP TO 60K# CT WT THREE TIMES (NORMAL PICK UP WEIGHT 33.5K #) AND POP FREE ON THE THIRD PULL WITH NO PUMPS. 20:40 - 22:00 1.33 DRILL P PROD1 WIPER TRIP TO WINDOW 22:00 - 22:30 0.50 DRILL N STUC PROD1 LOG TIE -IN, +9' 22:30 - 23:30 1.00 DRILL P PROD1 WIPER TO TD, SET DOWN 3X FROM 12,100 TO 12,340'. 23:30 - 00:00 0.50 DRILL N STUC PROD1 DRILL THEN BECAME DIFFERENTIALLY STUCK AT 12,630'. PULL TO 60K# CT WT SEVERAL TIMES. ORDER MINERAL OIL. 11/17/2009 00:00 - 01:00 1.00 DRILL N STUC PROD1 DIFFERENTIALLY STUCK OFF BOTTOM. HOT CAN ROTATE & WOB IS UNCHANGED. STUCK ABOVE THE BHA. MINERAL OIL ORDERED. PUMP NEW MUD FROM PILL PIT. RELAX PIPE. WORK PIPE FREE. 01:00 - 02:00 1.00 DRILL P PROD1 SHORT WIPER TO CLEAN UP THE BOTTOM OF THE HOLE. MOTOR WORK AT THE 12,050' SHALE. 02:00 - 04:00 2.00 DRILL P PROD1 DRILL ZONE 1A LATERAL FROM 12,646' 1.6 BPM IN / 1.6 BPM OUT @ 3600 -3900 PSI 1.0K -2.0K# DHWOB, 80 -120 FPH, 88 DEG INCL IA =320, OA =100, PVT =298, ECD =9.9 DRILL TO 12,800' 04:00 - 05:30 1.50 DRILL P PROD1 WIPER TO WINDOW 05:30 - 05:45 0.25 DRILL P PROD1 LOG TIE -IN, -1.5' 05:45 - 07:00 1.25 DRILL P PROD1 WIPER TO TD, CLEAN HOLE. ORDERED NEW GEOVIS FROM MI PLANT. 07:00 - 08:45 1.75 DRILL P PROD1 DRILL Z1A LAT, 1.5 BPM, 3280 -3800 PSI, 80R TF, 87 DEG Printed: 12/10/2009 11:15:44 AM • • BP EXPLORATION Page 9 of 14 Operations Summary Report Legal Well Name: E -09 Common Well Name: E -09 Spud Date: 5/4/1980 Event Name: REENTER +COMPLETE Start: 11/7/2009 End: 11/22/2009 Contractor Name: NORDIC CALISTA Rig Release: 11/22/2009 Rig Name: NORDIC 1 Rig Number: N1 Date From - To Hours Task Code NPT Phase > Description of Operations 11/17/2009 07:00 - 08:45 1.75 DRILL P PROD1 INCL, 1 -2L WOB, 90 -130 FPH, 10.0 ECD. STACKING WT. OVERPULL TO 60K. DRILLED TO 12879'. 08:45 - 11:35 2.83 DRILL P PROD1 WIPER TRIP TO WINDOW. 34K UP WT, CLEAN HOLE. RIH CLEAN TO BOTTOM. 11:35 - 14:00 2.42 DRILL P PROD1 DRILL Z1A LAT, 1.6 BPM, 3400 -3800 PSI, 80L TF, 89 DEG INCL, 1 -2L WOB, 30 FPH, 9.8 ECD. SWAP TO NEW GEOVIS AT 12880'. DRILLED TO 13,000' 14:00 - 16:30 2.50 DRILL P PROD1 WIPER TRIP TO WINDOW. CLEAN HOLE. RIH. REAM SHALE AT 12960'. RIH TO BOTTOM. 16:30 - 18:30 2.00 DRILL P PROD1 DRILL Z1A LAT, 1.6 BPM, 3200 -3600 PSI, 100L TF, 90 DEG INCL, 1 -2L WOB, 60 FPH, 9.8 ECD. DRILLED TO 13108'. 18:30 - 19:40 1.17 DRILL P PROD1 CONTINUE DRILLING Z1A LATERAL, PAST 13100 FT REDUCE INC TO 90 DEG TO STAY IN SAND. DRILL TO 13150 FT. 19:40 - 22:40 3.00 DRILL P PROD1 WIPER TRIP FROM 13150 FT TO WINDOW. PULL THROUGH WINDOW AND CLEAN 5" BACK TO 9500 FT. 22:40 - 00:00 1.33 DRILL P PROD1 LOG TIE -IN, CORRECT +9 FT. RIH TO BOTTOM. REAM THROUGH SHALES 12880 -12900 FT, AND 12960 FT. 11/18/2009 00:00 - 00:30 0.50 DRILL P PROD1 CONTINUE WIPER TRIP BACK TO BOTTOM. 00:30 - 01:40 1.17 DRILL P PROD1 DRILL FROM 13150 FT. REDUCE INC FURTHER TO 87 DEG TO STAY IN GOOD SAND. 1.54 / 1.54 BPM @ 3100 -3500 PSI. ROP IS 80 -100 FT /HR INITIALLY WITH 1 -2 KLBS DWOB. AFTER 13200 FT FREQUENT PICKUPS WITH OVERPULL, DIFFICULT GETTING BACK TO BOTTOM. CALL TD AT 13218 FT. '(� 01:40 - 06:00 4.33 DRILL P PROD1 WIPER TRIP BACK TO WINDOW AND TIE -IN LOG. CORRECT +3.5 FT. RIH TO BOTTOM. STACK WT 12870 FT AND 12960 FT. TAG FINAL TD AT 13217 FT, 2 TIMES. 06:00 - 10:00 4.00 DRILL P PROD1 REAM SHALES FROM 12800 - 13100'. RIH TO TD. BACK REAM TO 12800'. REAM SHALES UP /DOWN 4 TIMES FROM 12800 - 13100'. HOLE IN GOOD CONDITION. 10:00 - 15:00 5.00 DRILL P PROD1 POH FROM TD WHILE LAYING IN NEW GEOVIS LINER PILL WITH 3 PPB BEADS. UPWT =34K. DWNWT =11K OPEN EDC ABOVE WINDOW. CIRC 2.5 BPM, WASH 5" LINER UP /DWN. POH WITH DRILLING BHA. FLAG COIL AT 9300' AND 6600' EOP. POH CIRC AT 2.5 BPM. 15:00 - 15:15 0.25 DRILL P PROD1 SAFETY MEETING. REVIEW PROCEDURE, HAZARDS AND MITIGATION FOR LAYING OUT THE DRILLING BHA AND PUMPING OUT E -LINE SLACK. 15:15 - 16:30 1.25 DRILL P PROD1 LAY OUT DRILLING BHA. REMOVE UQC. M/U 1 JT 2- 1/16" CSH. 16:30 - 18:00 1.50 CASE P RUNPRD PUMP OUT E -LINE SLACK AT 3.7 BPM AT 4200 PSI, 3 TIMES. Printed: 12/10/2009 11:15:44 AM • BP EXPLORATION Page 10 of 14 Operations Summary Report Legal Well Name: E -09 Common Well Name: E -09 Spud Date: 5/4/1980 Event Name: REENTER +COMPLETE Start: 11/7/2009 End: 11/22/2009 Contractor Name: NORDIC CALISTA Rig Release: 11/22/2009 Rig Name: NORDIC 1 Rig Number: N1 Date From - To Hours Task Code NPT Phase Description of Operations 11/18/2009 16:30 - 18:00 1.50 CASE P RUNPRD CUT OFF 262' OF E -LINE. CUT OFF 18 FT OF COIL. 18:00 - 19:20 1.33 CASE P RUNPRD CREW CHANGE. DISCUSS INCIDENT ON NGI PAD, AND BP EXPECTATIONS FOR CONTROL OF WORK AT THE RIG AND WORKING ALONE. 19:20 - 19:35 0.25 CASE P RUNPRD SAFETY MEETING. PJSM FOR INSTALLING AND TESTING CT CONNECTOR. 19:35 - 20:00 0.42 CASE P RUNPRD INSTALL CT CONNECTOR, PULL TEST TO 35K AND PT TO 3500 PSI. 20:00 - 21:00 1.00 CASE P RUNPRD PREP RIG FLOOR FOR RUNNING LINER. 21:00 - 21:15 0.25 CASE P RUNPRD SAFETY MEETING. PJSM FOR RUNNING LINER. 21:15 - 00:00 2.75 CASE P RUNPRD RUN LINER AS PER PROGRAM. INDEXING GUIDE SHOE, 2 FLOATS, LANDING COLLAR, STAGE COLLAR, 15 JTS SLICK AND 101 JTS WITH CEMENTRALIZERS, DEPLOYMENT SLEEVE WITH 4" GS, SELRT AND 6 JTS 2.06 CSH. BHA OAL = 3955.82 FT 11/19/2009 00:00 - 00:15 0.25 CASE P RUNPRD CONTINUE RUNNING LINER AS PER PROGRAM. 00:15 - 00:30 0.25 CASE P RUNPRD KICK WHILE TRIPPING DRILL AND REVIEW. GOOD RESPONSE BY CREWS. 00:30 - 05:30 5.00 CASE P RUNPRD CONTINUE RUNNING LINER. FILL LINER WITH WATER MIDWAY THROUGH AND AFTER THE CSH. 05:30 - 05:50 0.33 CASE P RUNPRD PICK UP INJECTOR AND REMOVE LEGS. M/U QUICK CONNECT. M/U CT RISER 05:50 - 06:30 0.67 CASE P RUNPRD PUMP 20 BBLS AT SURFACE TO DISPLACE WATER. 06:30 - 08:15 1.75 CASE P RUNPRD RIH WITH 2 -3/8" LINER AND SELRT. LINER LENGTH = 3764.55' LINER BHA OAL = 3955.2'. RIH, CIRC 0.2 BPM, 1100 PSI UP WT AT 10500 =37K, DWN WT = 17K. CORRECT CTD TO FLAG AT 10538'. -17' CORRECTION. 08:15 - 09:00 0.75 CASE P RUNPRD RIH CLEAN THRU WINDOW. RIH AT 60 FPM, CIRC 2.1 BPM. DWN WT = 16K AT 11200' DWN WT = 11K AT 12800' SET DOWN FULL WT IN SHALE AT 12869'. PICK UP AND RIH AGAIN. RAN THRU SHALES OK, SOME DRAG, NO MORE SET DOWNS. LAND LINER ON DEPTH AT TD AT 13.217. 09:00 - 09:15 0.25 CASE P RUNPRD PICK UP TO POSITION BALL DROP, UP WT = 43K. SAFETY MEETING. REVIEW PROCEDURE, HAZARDS, MITIGATION AND LOCKOUT /TAG OUT FOR DROPPING THE 5/8" STEEL BALL. 09:15 - 10:00 0.75 CASE P RUNPRD LAUNCH 5/8" STEEL BALL WITH 2000 PSI, HEARD BALL ROLLING IN COIL. RIH BACK TO TD WITH LINER. LANDED LINER AT TD. CIRC BALL AT 1.5 BPM, 2700 PSI, FULL RETURNS. SLOW PUMP TO 0.8 BPM, 2000 PSI AT 28 BBLS. BALL ON SEAT AT 31.3 BBLS, SHEARED AT 4400 PSI. PICK UP CLEAN FROM LINER AT 21 K. 10:00 - 14:30 4.50 CEMT P RUNPRD CLEAN PITS AND CIRC WELL TO DOUBLE SLICK, 2% KCL WATER. Printed: 12/10/2009 11:15:44 AM BP EXPLORATION Page 11 of 14 Operations Summary Report Legal Well Name: E -09 Common Well Name: E -09 Spud Date: 5/4/1980 Event Name: REENTER +COMPLETE Start: 11/7/2009 End: 11/22/2009 Contractor Name: NORDIC CALISTA Rig Release: 11/22/2009 Rig Name: NORDIC 1 Rig Number: N1 Date From - To Hours Task Code NPT Phase Description of Operations 11/19/2009 10:00 - 14:30 4.50 CEMT P RUNPRD 1.8 BPM, 1650 PSI. PJSM BEFORE SPOTTING SWS CEMENTING EQUIPMENT. RIG UP CEMENTERS WHILE FINISH SWAPPING FLUID. 14:30 - 15:00 0.50 CEMT P RUNPRD SAFETY MEETING. REVIEW PROCEDURE, HAZARDS AND MITIGATION FOR PUMPING LINER CEMENT JOB WITH SWS. 15:00 - 17:15 2.25 CEMT P RUNPRD CIRC 1.8 BPM, 1520 PSI WHILE BATCHING UP CEMENT. CEMENT AT WT AT 1600 HRS. CLEAR ICE PLUG IN CEMENT LINE. PRESSURE TEST CEMENT LINE TO 5500 PSI. 17:15 - 18:30 1.25 CEMT P RUNPRD STAGE 18.0 BBL, 15.8 PPG, G CEMENT 10 BBL CMT, 1.6 BPM, 3000 PSI, 15 BBL CMT, 1.4 BPM, 3100 PSI. 18 BBL CMT, 1.3 BPM, 2900 PSI, STOP PUMP. ISOLATE COIL. PURGE CEMENT LINE WITH 2# BIOZAN. BLOW DOWN CMT LINE DISPLACE CEMENT WITH 2# BIOZAN. 10 BBL DISPL, 1.9 BPM, 3800 PSI, FULL RETURNS. 20 BBL DISPL, 1.8 BPM, 2800 PSI, FULL RETURNS 30 BBL DISPL, 1.8 BPM, 2660 PSI, FULL RETURNS 36.1 BBL DISPL, ZERO OUT, CEMENT AT SHOE. 37.6 BBL DISPL, STOP PUMP, 2 BBL CMT LEFT IN COIL. STOP PUMP, BLEED PRESS, PICK UP 13' FROM FREE POINT, 25K UP WT. CLOSE CHOKE, SIDE EXHAUST 5 BBLS, 2 BBL CMT, 3 BBL BIOZAN. OPEN CHOKE. RIH, STACK 10K, SAME DEPTH. ZERO IN TOTAL. LINER CAP = 14.5 BBL PRESS UP AND SHEAR LWP AT 3300 PSI. 5 BBL DISPL, 1.6 BPM, 3400 PSI, FULL RETURNS, 10 BBL DISPL, 1.3 BPM, 3400 PSI, FULL RETURNS, 13 BBL DISPL, 1.1 BPM, 3480 PSI, 5% FLUID LOSS 14 BBL DISPL, 1.0 BPM, 3000 PSI, 5% FLUID LOSS BUMPED PLUG WITH 3300 PSI AT 14.7 BBL DISPL. 15 BBL CEMENT ON RETURNS TOTAL. FULL RETURNS. HOLD PRESS TIGHT. BLEED OFF. CHECK FLOATS. OK. CEMENT JOB WENT WELL. FULL RETURNS. STING OUT OF LINER. CIRC 2 BBL BIO AT 1 BPM 18:30 - 20:15 1.75 CEMT P RUNPRD POH WITH CEMENTING BHA. CIRC 0.6 BPM, 0.2 BPM RETURNS TO KEEP HOLE FULL. 20:15 - 20:30 0.25 CEMT P RUNPRD TAG STRIPPER. SAFETY MEETING. PJSM FOR UD LINER RUNNING TOOLS. 20:30 - 21:30 1.00 CEMT P RUNPRD UD 6 JTS PH6 AND LINER RUNNING TOOLS. RECOVER 5/8" STEEL BALL. LOAD OUT LINER RUNNING TOOLS. 21:30 - 22:15 0.75 CEMT P RUNPRD GREASE BLOCKS. PREP FLOOR FOR RUNNING 1" CSH. 22:15 - 22:30 0.25 EVAL P LOWER1 SAFETY MEETING. PJSM FOR RUNNING LINER CLEANOUT BHA. 22:30 - 00:00 1.50 EVAL P LOWER1 M/U LINER CLEANOUT BHA. 1.87" MILL, 1.69" XTREME, 1/2" CIRC SUB, 5/8" DISCONNECT, 126 JTS OF 1" CSH, 3/4" DISCONNECT, Printed: 12/10/2009 11•15:44 AM • • M BP EXPLORATION Page 12 of 14 Operations Summary Report Legal Well Name: E -09 Common Well Name: E -09 Spud Date: 5/4/1980 Event Name: REENTER +COMPLETE Start: 11/7/2009 End: 11/22/2009 Contractor Name: NORDIC CALISTA Rig Release: 11/22/2009 Rig Name: NORDIC 1 Rig Number: N1 Date From - To Hours Task Code NPT Phase Description of Operations 11/19/2009 22:30 - 00:00 1.50 EVAL P LOWER1 DBPV, 2 JTS 2.06" CSH, BTT QUICK CONNECT. BHA OAL = 3946.32 FT. CEMENT IS AT 500 PSI COMPRESSIVE STRENGTH AT 23:00. 11/20/2009 00:00 - 03:00 3.00 EVAL P LOWER1 CONTINUE M/U BHA #12 FOR LINER CLEANOUT. 03:00 - 03:30 0.50 EVAL P LOWER1 PICK UP INJECTOR AND M/U QUICK CONNECT. M/U CT RISER. 03:30 - 04:50 1.33 EVAL P LOWER1 RIH. 04:50 - 07:00 2.17 EVAL P LOWER1 TAG AT 9452 FT. PICK UP AND INCREASE RATE TO 0.93 BPM @ 2370 PSI FS. TAG LIGHTLY AT 9450.4 FT AND STALL. START TIME MILLING FROM 9449.5 FT. MILLED TO 9451 FT. BACK REAM, REAM DOWN, NO MOTOR WORK. PROFIT F IS MII 1 Fn OUT TO 1 R75" 07:00 - 08:45 1.75 EVAL P LOWER1 RIH WITH MILL / MOTOR, 1.1 BPM, 2900 PSI, 43 FPM. RIH CI FAN TO PRTD TA(, PBTD AT 13.188' 08:45 - 11:30 2.75 EVAL P LOWER1 POH WHILE CIRC NEW SLICK KCL WATER TO CLEAN HOLE. CIRC 1.0 BPM, 2400 PSI. 11:30 - 11:45 0.25 EVAL P LOWER1 SAFETY MEETING. REVIEW PROCEDURE, HAZARDS AND MITIGATION FOR STANDING BACK CSH WORKSTRING. 11:45 - 14:45 3.00 EVAL P LOWER1 STANDBACK 63 STDS OF 1" CSH. LAY OUT MOTOR AND MILL. 14:45 - 15:00 0.25 EVAL P LOWER1 SAFETY MEETING. REVIEW PROCEDURE, HAZARDS AND MITIGATION FOR M/U SWS MCNUGR/CCL LOGGING BHA. 15:00 - 19:00 4.00 EVAL P LOWER1 M/U SWS MCNL, PORTED XO, HYD DISC, 63 STDS 1" CSH, MHA, 2 JTS CSH, QUICK CONNECT AND CTC. BHA OAL = 3959.04' M/U QUICK CONNECT AND CT RISER. 19:00 - 20:15 1.25 EVAL P LOWER1 SYNCHRONIZE DEPTH WITH SLB LOGGER THEN RIH. 20:15 - 22:30 2.25 EVAL P LOWER1 LOG MCNL DOWN AT 30 FT /MIN FROM 9400 FT. TAG LIGHTLY AT 13185 FT, 2 TIMES. 22:30 - 23:30 1.00 EVAL P LOWER1 LOG UP AT 60 FT /MIN, LAY IN PERF PILL. 23:30 - 00:00 0.50 EVAL P LOWER1 POOH 11/21/2009 00:00 - 01:00 1.00 EVAL P LOWER1 CONTINUE POOH. 01:00 - 01:15 0.25 EVAL P LOWER1 SAFETY MEETING. PJSM FOR STANDING BACK CSH. 01:15 - 04:00 2.75 EVAL P LOWER1 UD 2 JTS 2.06 CSH AND STAND BACK 62 STDS OF 1" CSH. 04:00 - 04:15 0.25 EVAL P LOWER1 SAFETY MEETING. PJSM TO DISCUSS HAZARDS AND MITIGATIONS FOR UD LOGGING SOURCE. 04:15 - 04:40 0.42 EVAL P LOWER1 PULL REMAINING STAND, LID LOGGING TOOLS AND DOWNLOAD DATA. FIND PBTD AT 13189 FT. 04:40 - 05:30 0.83 EVAL P LOWER1 P/U INJECTOR, M/U SWIZZLE STICK. JET BOP STACK. 05:30 - 06:10 0.67 EVAL P LOWER1 SET INJECTOR BACK ON ITS LEGS. VAC STACK OUT TO CHANGE OUT 5 FT RISER FOR A 3 FT ONE. PRESS TEST RISER WITH 3500 PSI. 06:10 - 07:00 0.83 EVAL P LOWER1 TEST LINER LAP TO 2000 PSI. 0 MIN 2051 PSI Printed: 12/10/2009 11:15:44 AM • BP EXPLORATION Page 13 of 14 Operations Summary Report Legal Well Name: E -09 Common Well Name: E -09 Spud Date: 5/4/1980 Event Name: REENTER +COMPLETE Start: 11/7/2009 End: 11/22/2009 Contractor Name: NORDIC CALISTA Rig Release: 11/22/2009 Rig Name: NORDIC 1 Rig Number: N1 Date From - To Hours Task Code NPT Phase Description of Operations 11/21/2009 06:10 - 07:00 0.83 EVAL P LOWER1 5 MIN 2043 PSI 10 MIN 2040 PSI 15 MIN 2036 PSI 20 MIN 2032 PSI 25 MIN 2029 PSI 30 MIN 2025 PSI GOOD TEST. CLOSE SWAB AND PT CT RISER SECTION TO 3000 PSI. 07:00 - 07:30 0.50 PERFOB P LOWER1 CREW CHANGE AND SAFETY MEETING. REVIEW PROCEDURE, HAZARDS AND MITIGATION FOR RUNNING SWS PERF GUNS. 07:30 - 12:20 4.83 PERFOB P LOWER1 M/U SWS 1.56 ". PJ PERF GUNS LOADED AT 6 SPF. 82 GUNS AND BLANKS AND E -FIRE FIRING HEAD. 12:30 - 14:45 2.25 PERFOB P LOWER1 RIH WITH 35 STDS 1" CSH, HYD DISC, CHECKS, 2 JTS CSH, QICK CONN AND CTC. PERF BHA OAL = 3975.2'. 14:45 - 16:45 2.00 PERFOB P LOWER1 RIH WITH SWS 1.56" PERFORATING BHA #14. CIRC 0.2 BPM, 300 PSI. RIH AT 90 FPM, SLOW TO 60 FPM INSIDE LINER. 16 K DOWN WT, TAG PBTD AT 13,194'. CORRECT TO PBTD OF 13,189.3' FROM MCNUGR. UP WT = 34K. POSITION BOTTOM SHOT AT PBTD. 16:45 - 18:00 1.25 PERFOB P LOWER1 PRACTICE PUMP CYCLES TO CONTROL PUMP RATES CORRECTLY. PUMP 0.25 BPM, 0.75 PBM, STOP PUMP. PUMP 0.5 BPM, 1.0 BPM, 0.5 BPM, 1.0 BPM, 0.5 BPM, 1.0 BPM, 0.5 BPM, 1.0 BPM STOP PUMP. GUNS DID NOT FIRE. CYCLE PUMP AGAIN TO FIRE GUNS. CYCLE 0.4, 1.0 BPM FOUR TIMES. GUNS DID NOT FIRE. REPEAT CYCLE A THIRD TIME. CYCLE 0.5 TO 1.1 BPM, FOUR TIMES, DROPPED PUMP TO 0.3 BPM, GUNS FIRED AT 65 SEC. GOOD SHOT DETECTION. LOST RETURNS FOR 2 BBLS. 18:00 - 19:45 1.75 PERFOB P LOWER1 POH WITH FIRED PERF GUNS. 35K UP WT. CIRC 0.8 BPM, 2100 PSI, FLOW CHECK AT TOP OF LINER. NO FLOW. POH. FLOW CHECK AT SURFACE. 19:45 - 20:00 0.25 PERFOB P LOWER1 SAFETY MEETING. PJSM TO DISCUSS HAZARDS AND MITIGATIONS FOR STAND BACK CSH. 20:00 - 20:30 0.50 PERFOB P LOWER1 TAG STRIPPER AND SHUT DOWN PUMP, MONITOR WELL. 20:30 - 22:30 2.00 PERFOB P LOWER1 FILL WELL WITH 0.2 BBLS THEN POP OFF. UD 2 JTS 2.06" CSH AND STAND BACK 35 STDS 1" CSH. 22:30 - 22:45 0.25 PERFOB P LOWER1 FILL WELL WITH 2.5 BBLS. SAFETY MEETING. PJSM FOR UD SPENT PERF GUNS. 22:45 - 00:00 1.25 PERFOB P LOWER1 UD 82 PERF GUNS. ALL SHOTS FIRED THAT WERE SUPPOSED TO. 11/22/2009 00:00 - 00:15 0.25 PERFOB P LOWER1 SAFETY JOINT DRILL AND REVIEW WITH CREW. GOOD RESPONSE. 00:15 - 04:30 4.25 PERFOB P LOWER1 CONTINUE UD SPENT PERF GUNS. Printed: 12/10/2009 11:15:44 AM • • BP EXPLORATION Page 14 of 14 Operations Summary Report Legal Well Name: E -09 Common Well Name: E -09 Spud Date: 5/4/1980 Event Name: REENTER +COMPLETE Start: 11/7/2009 End: 11/22/2009 Contractor Name: NORDIC CALISTA Rig Release: 11/22/2009 Rig Name: NORDIC 1 Rig Number: N1 Date From - To Hours Task Code NPT Phase Description of Operations 11/22/2009 04:30 - 05:00 0.50 PERFOB P LOWER1 OFFLOAD SPENT PERF GUNS AND RUNNING TOOLS. PREP RIG FLOOR FOR RUNNING FREEZE PROTECT BHA. 05:00 - 05:45 0.75 WHSUR P POST M/U FREEZE PROTECT NOZZLE WITH DBPV. M/U CT RISER TO WELL. 05:45 - 07:45 2.00 WHSUR P POST RIH TO 2100' AND FREEZE PROTECT TUBING WITH MEOH. POH. 07:45 - 08:15 0.50 WHSUR P POST SAFETY MEETING. REVIEW PROCEDURE, HAZARDS AND MITIGATION FOR SETTING BP VALVE AND GREASING TREE WITH GREASE CREW. 08:15 - 08:45 0.50 WHSUR P POST SET BACK PRESSURE VALVE AND GREASE TREE WITH GREASE CREW. FUNCTION VALVES WHILE GREASING. 08:45 - 09:00 0.25 RIGD P POST SAFETY MEETING. REVIEW PROCEDURE, HAZARDS AND MITIGATION FOR BLOWING DOWN COIL WITH N2. 09:00 - 11:00 2.00 RIGD P POST PRESS TEST N2 LINE. BLOWDOWN COIL AT 1800 CFM AT 2000 PSI. BLEED DOWN PRESS TO TIGER TANK. 11:00 - 11:15 0.25 RIGD P POST SAFETY MEETING. REVIEW PROCEDURE, HAZARDS AND MITIGATION FOR PULLING COIL STUB BACK TO REEL FOR REEL SWAP. 11:15 - 14:00 2.75 RIGD P POST INSTALL INTERNAL GRAPPLE, PULL TEST AND PULL COIL STUB BACK TO REEL AND SECURE IT. CLEAN RIG PITS. 14:00 - 16:00 2.00 RIGD P POST CUT AND SLIP DRILL LINE. 16:00 - 16:30 0.50 RIGD P POST SAFETY MEETING. REVIEW PROCEDURE, HAZARDS AND MITIGATION FOR SWAPPING REELS. 16:30 - 18:00 1.50 RIGD P POST OPEN BOMBAY DOOR. LOWER REEL TO TRAILER AND SECURE IT. BACK IN NEW 2" E -COIL REEL AND PICK UP WITH CRANE. 18:00 - 19:30 1.50 RIGD P POST RELEASE BRIDAL LINE FROM BLOCK. PUT FARR TONGS BACK INTO STABBING BOX. 19:30 - 20:00 0.50 RIGD P POST VACUUM FLUID OUT OF STACK PRIOR TO N/D BOPS. VERIFY STACK IS EMPTY ALL THE WAY DOWN TO BPV, THEN SHUT IN MASTER AND SWAB VALVE. 20:00 - 20:15 0.25 RIGD P POST SAFETY MEETING. REVIEW HAZARDS, MITIGATIONS AND PROCEDURES FOR N/D BOPS. 20:15 - 22:00 1.75 RIGD P POST N/D BOPS AND INSTALL TREE CAP. PT TREE CAP WITH DIESEL TO 3500 PSI, GOOD. TREE IS LEFT WITH DIESEL ON TOP OF SWAB, EMPTY FROM SWAB DOWN TO BPV. RELEASE RIG AT 22:00. ALL FURTHER DATA ON WELL 01 -19B. AFTER MIDNIGHT MOVE RIG FROM E PAD TO K PAD RD TO WEST DOCK RD TO DS -01. ESTIMATED TIME TO MOVE IS 12 HRS. Printed: 12/10/2009 11:15:44 AM • • ■air BAKER HUGHES INTEQ North America - ALASKA - BP Prudhoe Bay PB E Pad E -09 - Slot 09 E -09C Design: E -09C Survey Report - Geographic 20 November, 2009 0 bp 131111 • • BAKER ' HUGHES Survey Report - Geographic 0 bp INTEQ Company: North America - ALASKA - BP Local Co- ordinate Reference: Well E -09 - Slot 09 Project Prudhoe Bay TVD Reference: E -09A @ 65.01ft (E -09A Rig 65.01') Site: PB E Pad MD Reference: E -09A © 65.01ft (E -09A Rig 65.01') Well: E -09 North Reference: True Welibore: E -09C Survey Calculation Method: Minimum Curvature Design: E -09C Database: EDM .16 - Anc Prod - WH24P Project Prudhoe Bay, North Slope, UNITED STATES Map System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level Geo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point Map Zone: Alaska Zone 04 Using geodetic scale factor Site PB E Pad, TR -11 -14 Site Position: Northing: 5,973,160.88ft Latitude: 70° 19' 59.134 N From: Map Easting: 662,538.97ft Longitude: 148° 40' 53.054 W Position Uncertainty: 0.00 ft Slot Radius: 0.000 in Grid Convergence: 1.24 ° Well E -09 API No 500292046600 Well Position +N / -S 0.00 ft Northing: 5,976,820.00 ft Latitude: 70° 20' 34.706 N +E / -W 0.00 ft Easting: 664,447.00 ft Longitude: 148° 39' 55.005 W Position Uncertainty 0.00 ft Wellhead Elevation: ft Ground Level: 0.00 ft Wellbore E -09C API No 500292046603 Magnetics Model Name Sample Date Declination Dip Angle Field Strength O (°) (nT) BGGM2009 11/16/2009 22.46 80.96 57,680 Design E -09C Audit Notes: Version: 1.0 Phase: ACTUAL Tie On Depth: 11,059.71 Vertical Section: Depth From (TVD) +N/-5 +El-W Direction (ft) (ft) (ft) (0) 35.01 0.00 0.00 122.98 Survey Program Date: 11/20/2009 From To (ft) (ft) Survey (Welibore) Tool Name Description 104.71 10,563.00 1 : Sperry-Sun BOSS gyro multi (E -09) BOSS -GYRO Sperry-Sun BOSS gyro multishot 10,612.71 11,059.71 MWD (E- 09CPB1) MWD MWD - Standard 11,059.71 13,217.00 MWD (E -09C) MWD MWD - Standard 9 1120/2009 10:30:27AM Page 2 COMPASS 2003.16 Build 71 B �%au • 0 • Survey Report - Geographic bP INTEQ Company: North America - ALASKA - BP Local Co- ordinate Reference: Well E -09 - Slot 09 Project Prudhoe Bay WD Reference: E - 09A @ 65.01ft (E -09A Rig 65.01) Site PB E Pad MD Reference: E - 09A @ 65.01ft (E -09A Rig 65.01) Well: E - 09 North Reference: True Wellbore: E - 09C Survey Calculation Method: Minimum Curvature Design: E - 09C Database: EDM .16 - Anc Prod - WH24P Survey Measured Vertical Map Map Depth Inclination Azimuth Depth +N /-S +E/ -W Northing Easting (ft) ( °) (°) (ft) (ft) (ft) (ft) (ft) Latitude Longitude 11,059.71 88.31 231.88 8,929.90 - 1,003.17 4,675.52 5,975,919.70 669,143.07 70 °20' 24.825 N 148° 37' 38.432 W 11,090.00 89.22 235.39 8,930.55 - 1,021.12 4,651.14 5,975,901.22 669,119.09 70° 20' 24.649 N 148° 37' 39.145 W KOP 11,123.16 92.58 241.96 8,930.03 - 1,038.34 4,622.84 5,975,883.38 669,091.18 70° 20' 24.480 N 148° 37' 39.972 W 11,154.62 93.50 247.59 8,928.36 - 1,051.73 4,594.43 5,975,869.38 669,063.07 70° 20' 24.348 N 148° 37' 40.802 W 11,187.92 94.33 254.51 8,926.08 - 1,062.51 4,563.03 5,975,857.91 669,031.92 70° 20' 24.242 N 148° 37' 41.719 W 11,220.32 89.20 259.57 8,925.08 - 1,069.77 4,531.49 5,975,849.96 669,000.55 70° 20' 24.171 N 148° 37 42.640 W 1 11,245.00 87.54 265.56 8,925.79 - 1,072.96 4,507.04 5,975,846.24 668,976.17 70° 20' 24.140 N 148° 37' 43.355 W 11,275.08 87.82 271.49 8,927.01 - 1,073.73 4,477.00 5,975,844.81 668,946.17 70° 20' 24.133 N 148° 37' 44.232 W 11,305.26 89.63 279.27 8,927.68 - 1,070.90 4,446.99 5,975,846.97 668,916.10 70° 20' 24.161 N 148° 37' 45.109 W 1 11,334.98 86.87 281.91 8,928.59 - 1,065.45 4,417.79 5,975,851.79 668,886.79 70° 20' 24.214 N 148° 37' 45.961 WI 11,364.84 89.26 279.76 8,929.59 - 1,059.84 4,388.49 5,975,856.75 668,857.37 70° 20' 24.270 N 148° 37' 46.817 W 11,394.86 87.18 275.98 8,930.53 - 1,055.73 4,358.77 5,975,860.21 668,827.58 70° 20' 24.310 N 148° 37' 47.685 W 1 11,424.84 86.50 270.82 8,932.18 - 1,053.95 4,328.90 5,975,861.33 668,797.68 70° 20' 24.328 N 148° 37' 48.558 WI 11,454.94 89.82 266.18 8,933.15 - 1,054.74 4,298.84 5,975,859.88 668,767.64 70° 20' 24.320 N 148° 37' 49.436 W 11,484.88 87.36 259.46 8,933.88 - 1,058.48 4,269.16 5,975,855.49 668,738.05 70° 20' 24.284 N 148° 37' 50.303 W 11,514.96 88.16 254.97 8,935.06 - 1,065.13 4,239.86 5,975,848.20 668,708.91 70° 20' 24.219 N 148° 37' 51.159 W 11,544.78 87.42 250.89 8,936.21 - 1,073.87 4,211.38 5,975,838.84 668,680.63 70° 20' 24.133 N 148° 37' 51.991 W 11,574.80 85.61 255.67 8,938.04 - 1,082.49 4,182.69 5,975,829.59 668,652.14 70° 20' 24.048 N 148° 37' 52.829 W 11,604.88 84.00 261.28 8,940.76 - 1,088.48 4,153.35 5,975,822.96 668,622.94 70° 20' 23.989 N 148° 37' 53.686 WI 11,634.64 84.01 260.13 8,943.87 - 1,093.26 4,124.14 5,975,817.55 668,593.84 70° 20' 23.943 N 148° 37' 54.539 W I 11,664.76 85.54 256.86 8,946.61 - 1,099.24 4,094.76 5,975,810.92 668,564.60 70° 20' 23.884 N 148° 37' 55.398 WI 11,694.74 88.31 251.29 8,948.22 - 1,107.45 4,065.98 5,975,802.08 668,536.01 70° 20' 23.803 N 148° 37' 56.238 W 11,730.56 90.92 243.88 8,948.46 - 1,121.10 4,032.90 5,975,787.71 668,503.24 70° 20' 23.669 N 148° 37' 57.205 W 11,754.94 90.77 239.62 8,948.11 - 1,132.64 4,011.43 5,975,775.71 668,482.03 70° 20' 23.556 N 148° 37' 57.832 W 11,785.20 90.28 232.76 8,947.83 - 1,149.46 3,986.30 5,975,758.33 668,457.28 70° 20' 23.391 N 148° 37' 58.567 W1 11,817.50 89.45 225.82 8,947.90 - 1,170.52 3,961.83 5,975,736.75 668,433.28 70° 20' 23.184 N 148° 37' 59.282 W', 11,845.08 88.04 221.97 8,948.51 - 1,190.38 3,942.72 5,975,716.47 668,414.61 70° 20' 22.988 N 148° 37' 59.840 W 1 11,875.12 85.76 225.61 8,950.13 - 1,212.03 3,921.97 5,975,694.37 668,394.34 70° 20' 22.776 N 148° 38' 0.447 W 11,905.00 83.85 231.41 8,952.84 - 1,231.74 3,899.69 5,975,674.19 668,372.50 70° 20' 22.582 N 148° 38' 1.098 W 11,935.20 82.05 236.33 8,956.55 - 1,249.41 3,875.49 5,975,655.99 668,348.69 70° 20' 22.408 N 148° 38' 1.805 W 11,965.02 82.36 242.89 8,960.60 - 1,264.34 3,850.02 5,975,640.50 668,323.56 70° 20' 22.261 N 148° 38' 2.549 W 11,989.96 82.20 247.80 8,963.95 - 1,274.65 3,827.57 5,975,629.71 668,301.34 70° 20' 22.160 N 148° 38' 3.205 W 12,019.88 82.70 243.59 8,967.88 - 1,286.85 3,800.54 5,975,616.91 668,274.59 70° 20' 22.040 N 148° 38' 3.995 W 12,049.84 82.82 238.97 8,971.66 - 1,301.13 3,774.48 5,975,602.07 668,248.85 70° 20' 21.900 N 148° 38' 4.756 W 12,079.80 82.27 233.14 8,975.55 - 1,317.71 3,749.85 5,975,584.95 668,224.59 70° 20' 21.737 N 148° 38' 5.476 W' 12,110.54 81.68 229.97 8,979.84 - 1,336.64 3,726.01 5,975,565.51 668,201.18 70° 20' 21.551 N 148° 38' 6.172 W': 12,140.12 81.92 235.06 8,984.07 - 1,354.45 3,702.79 5,975,547.20 668,178.35 70° 20' 21.376 N 148° 38' 6.851 W', 12,170.04 85.48 238.83 8,987.35 - 1,370.66 3,677.87 5,975,530.44 668,153.79 70° 20' 21.217 N 148° 38' 7.579 W 12,199.68 88.31 242.79 8,988.96 - 1,385.09 3,652.04 5,975,515.45 668,128.29 70° 20' 21.075 N 148° 38' 8.334 W' 12,229.82 87.61 248.02 8,990.03 - 1,397.62 3,624.66 5,975,502.32 668,101.19 70° 20' 20.952 N 148° 38' 9.133 W 12,259.82 89.36 252.99 8,990.82 - 1,407.62 3,596.40 5,975,491.70 668,073.16 70° 20' 20.853 N 148° 38' 9.959 W 12,289.56 88.74 259.11 8,991.32 - 1,414.79 3,567.55 5,975,483.91 668,044.48 70° 20' 20.783 N 148° 38' 10.802 WI 12,321.90 90.43 255.20 8,991.55 - 1,421.98 3,536.03 5,975,476.03 668,013.13 70° 20' 20.713 N 148° 38' 11.722 W1 12,357.54 91.69 250.33 8,990.89 - 1,432.53 3,502.01 5,975,464.73 667,979.35 70° 20' 20.609 N 148° 38' 12.716 W 12,401.92 90.21 246.25 8,990.15 - 1,448.94 3,460.79 5,975,447.42 667,938.50 70° 20' 20.448 N 148° 38' 13.920 W 12,468.80 88.96 237.84 8,990.64 - 1,480.26 3,401.77 5,975,414.81 667,880.19 70° 20' 20.140 N 148° 38' 15.645 W 12,496.44 90.37 236.42 8,990.80 - 1,495.26 3,378.56 5,975,399.31 667,857.31 70° 20' 19.993 N 148° 38' 16.323 W 12,526.88 94.57 237.04 8,989.49 - 1,511.94 3,353.14 5,975,382.08 667,832.26 70° 20' 19.829 N 148° 38' 17.066 W 12,560.16 94.82 242.37 8,986.76 - 1,528.67 3,324.51 5,975,364.73 667,804.01 70° 20' 19.664 N 148° 38' 17.902 W 1 12,595.54 91.20 246.48 8,984.91 - 1,543.91 3,292.65 5,975,348.79 667,772.50 70° 20' 19.514 N 148° 38' 18.833 W 12,624.50 88.16 248.45 8,985.07 - 1,555.01 3,265.91 5,975,337.11 667,746.00 70° 20' 19.405 N 148° 38' 19.614 W 12,660.70 87.70 245.28 8,986.38 - 1,569.22 3,232.64 5,975,322.17 667,713.06 70° 20' 19.266 N 148° 38' 20.586 W 12,694.66 88.28 240.22 8,987.57 - 1,584.76 3,202.48 5,975,305.98 667,683.25 70° 20' 19.113 N 148° 38' 21.467 W, 12,726.26 89.02 235.49 8,988.31 - 1,601.56 3,175.74 5,975,288.60 667,656.89 70° 20' 18.948 N 148° 38' 22.248 W 11/20/2009 1 0:30:27AM Page 3 COMPASS 2003.16 Build 71 BAKER HUGHES Survey Report - Geographic 0 bp INTEQ Company: North America - ALASKA - BP Local Co - ordinate Reference: Well E -09 - Slot 09 Project: Prudhoe Bay TVD Reference: E -09A © 65.01ft (E -09A Rig 65.01) Site: PB E Pad MD Reference: E -09A © 65.01ft (E -09A Rig 65.01') Well: E - 09 North Reference: True Welibore: E - 09C Survey Calculation Method: Minimum Curvature Design: E - 09C Database: EDM .16 - Anc Prod - WH24P Survey Measured Vertical Map Map Depth Inclination Azimuth Depth +N /-S +E / -W Northing Easting (ft) ( °) ( °) (ft) (ft) (ft) (ft) (ft) Latitude Longitude 12,765.48 88.19 243.64 8,989.27 - 1,621.41 3,141.96 5,975,268.02 667,623.56 70° 20' 18.753 N 148° 38' 23.235 W 12,798.98 86.56 249.08 8,990.80 - 1,634.82 3,111.32 5,975,253.93 667,593.22 70° 20' 18.621 N 148° 38' 24.130 W 12,828.20 87.08 253.49 8,992.43 - 1,644.18 3,083.70 5,975,243.97 667,565.80 70° 20' 18.529 N 148° 38' 24.937 W 12,858.62 89.91 258.46 8,993.23 - 1,651.55 3,054.20 5,975,235.96 667,536.48 70° 20' 18.457 N 148° 38' 25.799 W 12,890.56 92.12 264.15 8,992.66 - 1,656.37 3,022.65 5,975,230.45 667,505.05 70° 20' 18.410 N 148° 38' 26.720 W 12,916.76 91.75 264.49 8,991.77 - 1,658.96 2,996.60 5,975,227.28 667,479.06 70° 20' 18.384 N 148° 38' 27.481 W' 12,949.92 91.78 260.62 8,990.75 - 1,663.26 2,963.74 5,975,222.27 667,446.30 70° 20' 18.342 N 148° 38' 28.441 W 12,983.86 89.94 256.36 8,990.24 - 1,670.03 2,930.49 5,975,214.77 667,413.22 70° 20' 18.276 N 148° 38' 29.412 W 13,015.56 89.02 252.67 8,990.53 - 1,678.49 2,899.95 5,975,205.64 667,382.87 70° 20' 18.193 N 148° 38' 30.304 W 13,046.16 91.63 250.19 8,990.36 - 1,688.23 2,870.95 5,975,195.27 667,354.09 70° 20' 18.097 N 148° 38' 31.152 W 13,075.16 94.92 247.68 8,988.70 - 1,698.63 2,843.94 5,975,184.27 667,327.31 70° 20' 17.995 N 148° 38' 31.941 W 13,126.48 93.93 243.57 8,984.74 - 1,719.75 2,797.34 5,975,162.15 667,281.20 70° 20' 17.787 N 148° 38' 33.302 W 13,160.36 90.46 240.86 8,983.44 - 1,735.53 2,767.40 5,975,145.72 667,251.61 70° 20' 17.632 N 148° 38' 34.177 W 13,173.28 88.13 239.36 8,983.60 - 1,741.96 2,756.20 5,975,139.03 667,240.55 70° 20' 17.569 N 148° 38' 34.504 W1 13,217.00 88.13 239.36 8,985.03 - 1,764.23 2,718.60 5,975,115.95 667,203.46 70° 20' 17.350 N 148° 38' 35.602 W TD - 2 3/8" Casing Points Measured Vertical Casing Hole Depth Depth Diameter Diameter (ft) (ft) Name (in) (in) 10,217.71 8,390.29 9 5/8" 9.625 12.250 2,675.71 2,675.61 13 3/8" 13.375 17.500 13,217.00 8,985.03 2 3/8" 2.375 3.000 Design Annotations Measured Vertical Local Coordinates Depth Depth +NI-S +E / -W (ft) < (ft) (ft) (ft) Comment 11,090.00 8,930.55 - 1,021.12 4,651.14 KOP 13,217.00 8,985.03 - 1,764.23 2,718.60 TD Checked By: Approved By: Date: 11/20/2009 1 0:30:27AM Page 4 COMPASS 2003.16 Build 71 • • Mau BAKER S 1NTEQ North America - ALASKA - BP Prudhoe Bay PB E Pad E -09 - Slot 09 E- 09CPB1 Design: E- 09CPB1 Survey Report - Geographic 20 November, 2009 � bp num • • BAKER HUGHES Survey Report - Geographic 0 bP 1NTEQ Company: North America - ALASKA - BP Local Co- ordinate Reference: Well E -09 - Slot 09 Project: Prudhoe Bay TVD Reference: E -09A @ 65.01ft (E -09A Rig 65.01') Site: PB E Pad MD Reference: E -09A @ 65.01ft (E -09A Rig 65.01') Well: E -09 North Reference: True Wellbore: E- 09CPB1 Survey Calculation Method: Minimum Curvature Design: E- 09CPB1 Database EDM .16 - Anc Prod - WH24P Project Prudhoe Bay, North Slope, UNITED STATES Map System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level Geo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point Map Zone: Alaska Zone 04 Using geodetic scale factor Site PB E Pad, TR -11 -14 Site Position: Northing: 5,973,160.88 ft Latitude: 70° 19' 59.134 N From: Map Easting: 662,538.97ft Longitude: 148° 40' 53.054 W Position Uncertainty: 0.00 ft Slot Radius: 0.000 in Grid Convergence: 1.24 ° Well E -09 API No 500292046600 Well Position +N / -S 0.00 ft Northing: 5,976,820.00 ft Latitude: 70° 20' 34.706 N +E / -W 0.00 ft Easting: 664,447.00 ft Longitude: 148° 39' 55.005 W I Position Uncertainty 0.00 ft Wellhead Elevation: ft Ground Level: 0.00 ft Wellbore - E- 09CPB1 API No 500292046671 Magnetics Model Name Sample Date Declination Dip Angle Field Strength ( °) ( °) (nT) BGGM2009 11/20/2009 22.45 80.96 57,680 Design E- 09CPB1 Audit Notes: Version: 1.0 Phase: ACTUAL Tie On Depth: 10,563.00 Vertical Section: Depth From (TVD) +N /-S +E / -W Direction (ft) (ft) (it) (°) 35.01 0.00 0.00 109.74 Survey Program Date: 11/20/2009 From To (ft) (ft) Survey (Wellbore) Tool Name Description I 104.71 10,563.00 1 : Sperry-Sun BOSS gyro multi (E -09) BOSS -GYRO Sperry-Sun BOSS gyro multishot 10,612.71 12,020.71 MWD (E- 09CPB1) MWD MWD - Standard 11/20/2009 10 :27 :45AM Page 2 COMPASS 2003.16 Build 71 N. iii r • • B=11 S Survey Report - Geographic 0 bP 1NTEQ Company: North America - ALASKA - BP Local Co - ordinate Reference: Well E -09 - Slot 09 Project: Prudhoe Bay TVD Reference: E -09A © 65.01ft (E -09A Rig 65.01') Site: PB E Pad MD Reference: E -09A @ 65.01ft (E -09A Rig 65.01') Well: E - 09 North Reference: True Welibore: E - 09CPB1 Survey Calculation Method: Minimum Curvature Design: E 09CPB1 Database: EDM .16 - Anc Prod - WH24P Survey Measured Vertical Map Map Depth Inclination Azimuth - Depth +N / -S +E/-W Northing Easting (ft) (^) (^) (ft) (ft) (ft) (ft) (ft) Latitude Longitude 10,654.01 38.21 122.26 8,730.34 - 753.65 4,817.02 5,976,172.25 669,279.06 70° 20' 27.279 N 148° 37' 34.294 W 10,683.79 43.52 139.02 8,752.92 - 766.35 4,831.59 5,976,159.87 669,293.90 70° 20' 27.154 N 148° 37' 33.869 W 10,714.23 43.02 155.47 8,775.15 - 783.77 4,842.81 5,976,142.71 669,305.50 70° 20' 26.982 N 148° 37' 33.541 W 10,743.83 46.51 169.46 8,796.22 - 803.56 4,848.98 5,976,123.05 669,312.11 70° 20' 26.787 N 148° 37' 33.361 W 10,773.93 51.55 188.47 8,816.05 - 826.09 4,849.25 5,976,100.54 669,312.86 70° 20' 26.566 N 148° 37' 33.354 W 10,803.95 50.43 206.80 8,835.04 - 848.16 4,842.26 5,976,078.32 669,306.36 70° 20' 26.349 N 148° 37' 33.559 W 10,833.83 52.18 228.49 8,853.86 - 866.39 4,828.13 5,976,059.79 669,292.64 70° 20' 26.170 N 148° 37' 33.972 W 10,866.69 49.74 237.73 8,874.58 - 881.71 4,807.78 5,976,044.03 669,272.63 70° 20' 26.019 N 148° 37' 34.567 W 10,897.95 56.92 229.74 8,893.26 - 896.57 4,787.65 5,976,028.72 669,252.83 70° 20' 25.873 N 148° 37' 35.155 W 10,926.03 63.43 222.82 8,907.23 - 913.42 4,770.10 5,976,011.50 669,235.66 70° 20' 25.707 N 148° 37' 35.668 W 10,954.91 71.98 226.00 8,918.18 - 932.47 4,751.41 5,975,992.04 669,217.39 70° 20' 25.520 N 148° 37' 36.214 W ! 10,978.55 79.61 225.55 8,923.98 - 948.45 4,735.00 5,975,975.71 669,201.34 70° 20' 25.363 N 148° 37' 36.694 W'I 11,006.63 86.53 225.30 8,927.36 - 968.00 4,715.16 5,975,955.73 669,181.93 70° 20' 25.171 N 148° 37' 37.274 W l 11,033.27 87.11 228.26 8,928.84 - 986.21 4,695.78 5,975,937.10 669,162.95 70° 20' 24.992 N 148° 37' 37.840 W 11,059.71 88.31 231.88 8,929.90 - 1,003.17 4,675.52 5,975,919.70 669,143.07 70° 20' 24.825 N 148° 37' 38.432 W 11,089.85 90.28 235.65 8,930.27 - 1,020.98 4,651.22 5,975,901.37 669,119.17 70° 20' 24.650 N 148° 37' 39.142 W 11,130.15 90.43 240.05 8,930.02 - 1,042.41 4,617.11 5,975,879.19 669,085.54 70° 20' 24.440 N 148° 37' 40.139 W 11,160.69 91.90 244.28 8,929.40 - 1,056.67 4,590.11 5,975,864.34 669,058.87 70° 20' 24.300 N 148° 37' 40.928 W 11,189.65 92.24 248.09 8,928.35 - 1,068.35 4,563.64 5,975,852.08 669,032.66 70° 20' 24.185 N 148° 37 41.701 W 11,219.55 92.18 252.49 8,927.20 - 1,078.43 4,535.52 5,975,841.40 669,004.77 70° 20' 24.086 N 148° 37' 42.523 W 11,249.55 90.03 255.67 8,926.62 - 1,086.65 4,506.68 5,975,832.54 668,976.12 70° 20' 24.005 N 148° 37' 43.365 W 11,279.69 89.75 259.65 8,926.68 - 1,093.09 4,477.24 5,975,825.46 668,946.83 70° 20' 23.942 N 148° 37' 44.225 W 11,310.29 87.97 259.93 8,927.28 - 1,098.51 4,447.13 5,975,819.38 668,916.85 70° 20' 23.889 N 148° 37' 45.105 W 11,339.75 88.68 261.81 8,928.15 - 1,103.19 4,418.06 5,975,814.07 668,887.89 70° 20' 23.843 N 148° 37' 45.954 W 11,369.65 91.17 266.14 8,928.18 - 1,106.32 4,388.34 5,975,810.28 668,858.24 70° 20' 23.813 N 148° 37' 46.823 W I 11,399.71 90.74 270.30 8,927.68 - 1,107.26 4,358.30 5,975,808.69 668,828.24 70° 20' 23.804 N 148° 37' 47.700 W 11,429.69 88.68 274.24 8,927.84 - 1,106.07 4,328.35 5,975,809.22 668,798.27 70° 20' 23.815 N 148° 37' 48.575 W 11,459.65 89.45 275.78 8,928.32 - 1,103.45 4,298.51 5,975,811.18 668,768.38 70° 20' 23.841 N 148° 37' 49.446 W 11,489.33 90.21 270.03 8,928.41 - 1,101.95 4,268.88 5,975,812.03 668,738.73 70° 20' 23.856 N 148° 37' 50.312 W 11,519.71 90.43 263.81 8,928.24 - 1,103.58 4,238.56 5,975,809.73 668,708.46 70° 20' 23.840 N 148° 37' 51.197 W 11,549.77 92.09 258.94 8,927.58 - 1,108.09 4,208.86 5,975,804.58 668,678.86 70° 20' 23.796 N 148° 37' 52.065 W 11,579.61 92.39 253.63 8,926.41 - 1,115.15 4,179.90 5,975,796.88 668,650.07 70° 20' 23.727 N 148° 37' 52.911 W 11,609.67 92.21 248.30 8,925.21 - 1,124.95 4,151.52 5,975,786.47 668,621.91 70° 20' 23.631 N 148° 37' 53.740 W 11,639.55 91.63 243.12 8,924.20 - 1,137.23 4,124.31 5,975,773.59 668,594.98 70° 20' 23.510 N 148° 37' 54.535 W 11,669.61 91.57 237.16 8,923.36 - 1,152.18 4,098.26 5,975,758.07 668,569.26 70° 20' 23.363 N 148° 37' 55.296 W 11,699.55 91.26 231.98 8,922.62 - 1,169.53 4,073.88 5,975,740.20 668,545.27 70° 20' 23.193 N 148° 37' 56.009 W 11,729.65 89.79 225.47 8,922.35 - 1,189.37 4,051.27 5,975,719.86 668,523.11 70° 20' 22.998 N 148° 37' 56.669 W 11,759.61 85.91 222.73 8,923.47 - 1,210.86 4,030.45 5,975,697.92 668,502.76 70° 20' 22.786 N 148° 37' 57.278 W 11,791.29 82.68 225.83 8,926.62 - 1,233.43 4,008.44 5,975,674.88 668,481.26 70° 20' 22.565 N 148° 37' 57.921 W 11,819.81 84.06 227.09 8,929.92 - 1,252.94 3,987.91 5,975,654.92 668,461.16 70° 20' 22.373 N 148° 37' 58.521 W 11,849.99 85.02 221.09 8,932.79 - 1,274.51 3,967.02 5,975,632.90 668,440.74 70° 20' 22.161 N 148° 37' 59.132 W 11,879.87 85.17 223.06 8,935.34 - 1,296.61 3,947.07 5,975,610.37 668,421.28 70° 20' 21.944 N 148° 37' 59.715 W 11,909.87 84.25 229.16 8,938.11 - 1,317.31 3,925.55 5,975,589.21 668,400.23 70° 20' 21.740 N 148° 38' 0.344 W 11,939.91 83.86 235.42 8,941.23 - 1,335.57 3,901.93 5,975,570.43 668,377.01 70° 20' 21.561 N 148° 38' 1.034 W 11,983.07 83.47 242.08 8,946.00 - 1,357.82 3,865.28 5,975,547.39 668,340.86 70° 20' 21.342 N 148° 38' 2.105 W% 12,020.71 83.47 242.08 8,950.28 - 1,375.33 3,832.23 5,975,529.16 668,308.21 70° 20' 21.170 N 148° 38' 3.070 W TD 1 11/20/2009 10 Page 3 COMPASS 2003.16 Build 71 d�� • BW Survey Report - Geographic bP INTEQ Company: North America - ALASKA - BP Local Co- ordinate Reference: Well E-09 - Slot 09 Project: Prudhoe Bay TVD Reference: E -09A @ 65.01ft (E -09A Rig 65.01) Site: PB E Pad MD Reference: E -09A @ 65.01ft (E -09A Rig 65.01') Well: E -09 North Reference: True Wellbore: E- 09CPB1 Survey Calculation Method: Minimum Curvature Design E- 09CPB1 Database: EDM .16 - Anc Prod - WH24P Casing Points Measured Vertical Casing Hole Depth Depth Diameter Diameter (ft) (ft) Name (in) (in) 2,675.71 2,675.61 13 3/8" 13.375 17.500 10,217.71 8,390.29 9 5/8" 9.625 12.250 Design Annotations Measured Vertical Local Coordinates Depth Depth +NI -S +EI-W (ft) (ft) (ft) (ft) Comment 10,563.01 8,661.11 - 739.37 4,760.17 TIP 10,612.71 8,698.55 - 744.83 4,792.39 KOP 12,020.71 8,950.28 - 1,375.33 3,832.23 TD Checked By: Approved By: Date: 11/20/2009 10 :27 :45AM Page 4 COMPASS 2003.16 Build 71 TREE = 4" 5M CIW WELLHEAD = 13-5/8" MCEVOY • SAF TES: >70° @ 10 955' ACTUATOR = BAKER E _p 9 KB. ELEV = 65.01' BF. ELEV = 30.76' KOP= 10680' DRLG DRAFT Max Angle = 95 cr 13075' I 2083' H4 -1/2" OTIS SSSV NIP, ID = 3.813" Datum MD = 10939' Datum TVD = 8800' SS 113 -3/8" CSG,72 #, L -80, ID = 12.347" H 2671' HAr I 2620' H 9 -5/8" DV PKR GAS LIFT MANDRELS ST MD TVO DEV TYPE VLV LATCH PORT DATE Minimum ID = 1.875" @ 9463' 3 4384 4198 36 MER DMY RM 0 06/12/07 2 8264 6805 44 MER DMY RM 0 06/12/07 SELRT BUSHING MILLED OUT 1 9413 7671 37 MER DMY RA 0 09/08/02 9452' -- I2 -3/8" DEPLOYMENT SLV, IO = 3.00" ■ — I 9483' H4 -1/2" OTIS X NIP, ID = 3.813" I s S I 9495 I-I -1/2" TM/ HBBP PKR, ID = 4.32" I I I I 9519' I - - 1/2" OTIS X NIP, ID = 3.813" I ' ' I 9530' I— 4 -1/2" OTIS XN NIP, ID = 3.80" (MILLED 08/29/02) I 4-1/2" TBG, 12.6 #, L -80, .0152 bpf, ID = 3.953" H 9542' F-----mr/ I 9542' H 4 -1/2" WLEG, ID = 3.958" I I TOP OF 5" LNR I 3' Mil I H ELMD TT NOT LOGGED I ITOPOF 7" LNR H 9717' I 9 -5/8" CSG, 47 #, L -80, ID = 8.68" H 10213' I3 -1/2" LNR, 8.81 #, L -80, .0087 bpf, ID = 2.992" H 10608' I I 10103' H 4" BKR DEPLOYMENT SLV, ID = 3.00" I ■ • I 10113' h 3 -112" HES XN NIP, ID = 2.750" I MILL OUT WINDOW 10558' - 10569' 1 1 1 17" LNR, 29 #, L -80, .0371 bpf, ID = 6.184" I—I 10569' I 1 I 3 - 3116" monobore w hipstock I-I 10613' I MILL OUT WINDOW 10607' - 10612' '` MILL OUT WINDOW 10681' - 10688' I 10608' H3-1/2" X 3-1/16" XO, ID = 2.800" I 15" LNR, 15 #, 13 -CR, .0188 bpf, ID = 4.408" I—I 10688' I ` fol. 6r lcn�v PERFORATION SUMMARY 1 . d /. i REF LOG: MEM GRICCL /MNCL ON 11/21/09 I ANGLE AT TOP PERF: 90 @a 11450' Note: Refer to Production DB for historical perf data 2)- SIZE SPF INTERVAL Opn /Sqz DATE 1.56 6 11450 - 11630 0 11/21/09 1.56 6 11810 - 12020 0 11/21/09 1.56 6 12160 - 12280 O 11/21/09 1.56 6 12400 - 12860 0 11/21/09 1.56 6 12900 - 12960 0 11/21/09 I PBTD I-I 13202' �■∎• w 1.56 6 13050 - 13190 0 11/21/09 -v- 12-3/8" LNR, 4.7 #, L -80, .0039bpf, ID= 1.99" II 13217' DATE REV BY COMMENTS DATE REV BY COMMENTS PRUDHOE BAY UNIT 05/80 ORIGINAL COMPLETION WELL: E 09C 01/13/95 DFF SIDETRACK (E -09A) PERM No: 09/08/02 DAC /KK CTD SIDETRACK (E -09B) API No: 50- 029 - 20466 -03 11/22/09 NORDIC/ CTD SIDETRACK (E -09C) SEC 6, T11N, R14E, 243.18' FNL & 500.01' FEL 11/25/09 SV DRLG HO CORRECTIONS BP Exploration (Alaska) ill • 2 Kil It 1 ! If A 1 l ,,,,),) i A / SEAN PARNELL, GOVERNOR ALASKA OIL AND GAS / 333 W. 7th AVENUE, SUITE 100 CONSERVATION COMMISSION ANCHORAGE, ALASKA 99501 -3539 PHONE (907) 279 -1433 FAX (907) 276-7542 John McMullen Engineering Team Leader BP Exploration (Alaska) Inc. P.Q. Box 196612 Anchorage, AK 99519 -6612 Re: Prudhoe Bay Field, Prudhoe Bay Oil Pool, PBU E -09C BP Exploration (Alaska) Inc. Permit No: 209 -095 Surface Location: 243' SNL, 500' FEL, SEC. 06, T11N, R 14E, UM Bottomhole Location: 2080' SNL, 2183' FWL, SEC. 05, T11N, R14E, UM Dear Mr. McMullen: Enclosed is the approved application for permit to re -drill the above referenced development well. This permit to drill does not exempt you from obtaining additional permits or an approval 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. When providing notice for a representative of the Commission to witness any required test, contact the Commission's petroleum field inspector at (907) 659 -3607 (pager). erel , ...V i Daniel T. Seamount, Jr. "�' Chair DATED thi day of September, 2009 cc: Department of Fish 86 Game, Habitat Section w/o encl. Department of Environmental Conservation w/o encl. STATE OF ALASKA ALASI IL AND GAS CONSERVATION COMMI•N ; � 3 4 ), , r 1'o?'! s 1: PERMIT TO DRILL 20 AAC 25.005 , la. Type of work 1 b. Current Well Class ❑ Exploratory /A ❑ Development Gas lc. Specify if well is proposed for: ® ❑ Drill Redd!' ervice .PP' ❑ Multiple Zone ❑ Coalbed Methane ❑ Gas Hydrates ❑ Re -Entry ❑ Stratigraphic Test Development Oil ❑ Single Zone ❑ Shale Gas 2. Operator Name: 5. Bond: ® Blanket ❑ Single Well 11. Well Name and Number: BP Exploration (Alaska) Inc. Bond No. 6194193 PBU E - 09C 3. Address: 6. Proposed Depth: 12. Field / Pool(s): P.O. Box 196612, Anchorage, Alaska 99519 -6612 MD 13300' ND 8933' ss Prudhoe Bay Field / Prudhoe Bay 4a. Location of Well (Governmental Section): 7. Property Designation: Oil Pool Surface: ADL 028304 243' SNL, 500' FEL, SEC. 06, T11N, R14E, UM Top of Productive Horizon: 8. Land Use Permit: 13. Approximate Spud Date: 1021' SNL, 4479' EWL, SEC. 05, T11N, R14E, UM November 15, 2009 Total Depth: 9. Acres in Property: 14. Distance to Nearest Property: 2080' SNL, 2183' FWL, SEC. 05, T11N, R14E, UM 2560 7400' 4b. Location of Well (State Base Plane Coordinates): 10. KB Elevation 15. Distance to Nearest Well Within Pool: Surface: x- 664447 y- 5976820 Zone -ASP4 (Height above GL): 65.01 feet 900' 16. Deviated Wells: Kickoff Depth: 10644 feet 17. Maximum Anticipated Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 90 degrees Downhole: 3027 Surface: 2147 18. Casino Proaram: I Specifications Too - Settino Depth Bottom Quantity of Cement c.f. or sacks Hole Casing Weight Grade Coupling Length MD ND MD ND (including stage data) 3" 2 -3/8" 4.7# L -80 STL 3100' 10200' 8376' 13300' 8933' ss 67 cu ft Class 'G' 19. PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re -entry Operations) Total Depth MD (ft): Total Depth ND (ft): Plugs (measured): Effective Depth MD (ft): Effective Depth ND (ft): Junk (measured): 12725 8883 None 12687 8883 Unknown Casing Length Size Cement Volume MD ND Conductor / Structural 110' 20" x 30" 11.8 cu vds Arcticset 110' 110' Surface 2671' 13 -3/8" 2790 cu ft Arcticset II 2671' 2671' Intermediate Production 10213' 9 -5/8" 1455 cu ft Class 'G'. 130 cu ft AS 10213' 8386' Liner 841' 7" 253 cu ft Class 'G' 9717' - 10558' 7983' - 8658' Liner 1127' 5" 286 cu ft Class 'G' 9553' - 10680' 7849' - 8747' Liner 2622' 3- 3/16" x 2 -7/8" 140 cu ft Class 'G' 10103' - 12725' 8298' - 8882' Perforation Depth MD (ft): 11590' - 12680' Perforation Depth ND (ft): 8912' - 8883' 20. Attachments ❑ Filing Fee, $100 0 BOP Sketch ® Drilling Program ❑ Time vs Depth Plot ❑ Shallow Hazard Analysis ❑ Property Plat ❑ Diverter Sketch ❑ Seabed Report 0 Drilling Fluid Program 0 20 AAC 25.050 Requirements 21. Verbal Approval: Commission Representative: Date: 22. I hereby certify that the foregoing is true and correct. Contact Cody Hinchman, 564 - 4468 Printed Name John ' Mul - n Title Enn ineering Team Leader Prepared By Name /Number Signature —., ; - { / - -1--- Phone 564 -4711 Date c/ / ,' Sondra Stewman, 564 -4750 Commission Use Onl Permit To Drill API Number: Permit Approva See cover letter for Number: o?090AF 50 - 029 - 20466 - - Date: °' \'i � Q (2 \ I other reauirements Conditions of Approval: If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained shales: Id No O i,z, Sa 130p 'tiffs Samples Req'd: ❑,Yes [ja No Mud Log Req'd: 0 Yes I No Ann* / C \ H Measures: Yes ❑ No Directional Survey Req'd: Yes ❑ No Other: Z.5 0 0 �o SL /`� n K 'Ta' J APPROVED BY THE COMMISSION / 7 7 / Date , ' ---- �" COMMISSIONER Form 10-401 Revised 12/2005 ORIGINAL Submit I uplicate 4-3 -o9 � I • S � bp BPXA Prudhoe Bay E -09C CTD Sidetrack To: Tom Maunder Petroleum Engineer Alaska Oil & Gas Conservation Commission From: Cody Hinchman CTD Engineer Date: August 25, 2009 I I Re: PBU E -09C Permit to Drill Permit to Drill approval is requested for a horizontal sidetrack from the E -09B well. Well History E -09B was drilled as a horizontal CST in the western area of K -pad targeting the Z1 AB sands. The well was completed in December 2002 and was twinned with E -08A, which was sidetracked at the same time. It was expected that these two wells would be similar in rates and pressures and that they could flow together. E -09B could not compete and was shut in to allow the twin to produce in HP. The well under performed compared to what was expected. It was thought that this might have been a result of the well having an excessively long shut -in time post drilling. An acid stimulation job was completed in October 2003 in an attempt to clean up any flow pro or drilling fluids that never had a chance to flow. No appreciable difference was noticed in the production. In May 2004, 140' of Z1A add perfs were shot in an attempt to increase production rates. These perforations proved to be ineffective and added little value. In May 2005, 35' of end of life Z1 B add perfs were shot in the heel of the well to access any remaining value. These perforations provided a brief oil buzz but quickly declined to the wells normal rates within a one month period. At the wells most recent production rates, the GOR is well above marginal allowing no on -time for the well. In June 2007, the well was CTD screened. A slickline drift with a roller stem made it to 11,124' SLM with no problems and an empty sample bailer. While pulling station #2 at 8,264' MD, three kick springs were noted to be lost downhole. Their depth and location are unknown. A caliper on 6/11/07 found all tubulars in good condition with no significant wall penetrations. On 6/12/07, an MIT -OA passed to 2000 psi and an MIT -IA passed to 3000 psi. In June 2009, the well received another CTD screen. It passed an MIT -T to 3000 psi, an MIT -IA to 3000 psi, and an MIT -OA to 2000 psi. A PPPOT -T passed to 5000 psi and a PPPOT -IC passed to 3500 psi. A slickline drift reached 10,965' SLM and attempted to fish the three kick springs left in the hole. They were unsuccessful and never encountered the kick springs. On their final run in hole, a swage was run to deviation too ensure the kick springs were pushed below the kick off point for the sidetrack. To determine whether or not this would be a tiny tools ST, an SCMT was run on 7/2/09. It found the cement up to the liner top at approximately 10,130' MD, eliminating the possibilities of a big coil ST. At current operating conditions the well is uncompetitive and has had no significant on -time since 2005 due to high GOR. Reason for PTD Request - Your approval is requested to drill a coil sidetrack from the E -09B well. This horizontal sidetrack will target reserves in ZN 1 A Ivishak and access new reserves in ZN1 B. • CTD Sidetrack Summary • • Pre -Rig Work Summary: (The pre CTD work is slated to begin about September 15, 2009.) 1. W PT Master & Swab valve to 4500 psi. Drawdown test MV and SV to 0 psi 2. W Function LDS 3. W PPPOT -T 4. S Dummy all GLM's 5. S Drift with Baker dummy 3- 3/16')WS and tag cross -over at 10,736'. 6. E Set Baker 3- 3/16" Packer WS with top at 10,624'. . _ "3OZ 7. W MIT -IA to 3000 psi, OA to 2000 psi. 8. W Set BPV 9. 0 Bleed T, IA, gas lift and production flowlines down to zero and blind flange. /_ 10.0 Remove S- Riser, Remove wellhouse, level pad. Rig Sidetrack Operations: (Scheduled to begin on November 15, 2009 using Nordic rig 1) 1. MIRU Nordic Rig 1 2. NU 7- 1/16" CT Drilling BOPE and test. v 3. Pull BPV. p r D 4. Mill a 2.74" window at 10,624'. 0.201 -°q'‘ 5. Drill build /turn section of the E -09C lateral with 2.70 "x3.0" bi- center bit and land well. 6. Drill lateral section to 13,300' MD. 7. Run and cement a 2 -3/8" L -80 solid liner string. 8. Make a cleanout run with mill and motor. 9. Make a logging run with a SWS GR -CNL logging tool. 10. Make a perforating run with 1.56" OD pert guns. 11. Set LTP if needed. 12. Circulate well to KWF brine. FP well to 2000' with diesel. 13. Set BPV. ND 7- 1/16" stack. FP tree and PT tree cap to 3500 psi. 14. RDMO Nordic 1. Post -Rig Work: 1. Re- install wellhouse and FL's. 2. Pull BPV. 3. Run live gas lift design. 4. POP Well Mud Program: • Well kill: 8.4 ppg brine. • Milling /drilling: 8.6 ppg Flo Pro or biozan for milling, new 8.6 ppg Flo Pro for drilling. Disposal: • All drilling and completion fluids and all other Class II wastes will go to Grind & Inject. • All Class I wastes will go to Pad 3 for disposal. Hole size: 2.70" x 3.0" (bi- center bits used) Casing Program: A solid /cemented liner • 2 -3/8 ", L -80 4.70# STL Solid Liner 10,200' and - 13,300' and • A minimum of 12 bbls 15.8 ppg cement will be used for liner cementing. (Assuming 3.0" bit size and TD 13,300', with 20% excess in the open hole interval) • TOC planned at 10,200' (TOL) Existing casing/tubing Information 13 -3/8 ", L -80 72 #, Burst 5380, Collapse 2670 psi 9 5/8 ", L -80 47 #, Burst 6870, Collapse 4750 psi 7 ", L -80 29 #, Burst 8160, Collapse 7030 psi 5 ", 13 -CR 15 #, Burst 8290, Collapse 7250 psi 4-1/2", L -80 12.6 #, Burst 7500, Collapse 8430 psi 3 -1/2 ", L -80 8.81 #, Burst 10,160, Collapse 10,540 3- 3/16 ", L -80, 6.2 #, Burst 10,160, Collapse 10,540 psi 2 -7/8 ", L -80, 6.16 #, Burst 10,570, Collapse 11,170 psi • Well Control: • BOP diagram is attached. • 2" coil will be used to drill the laterals • Pipe rams, blind rams and the CT pack off will be pressure tested to 250 psi and to 3500 psi. • The annular preventer will be tested to 250 psi and 2500 psi. Directional • See attached directional plans. Maximum planned hole angle on the E -09C lateral is 90.02 deg @12,621'. • Magnetic and inclination surveys will be taken every 30 ft. No gyro will be run. • Distance to nearest property — 7,400' (North). • Distance to nearest well in pool is 900' SE to well K- 19AL1. Logging • MWD directional and Gamma Ray will be run over all of the open hole sections. • Gamma Ray, CCL and CNL will be run after the lateral is cased. Hazards • The maximum H2S concentration on the E -09B well is 8 ppm recorded on 03/28/2008. • The maximum H2S concentration on the pad is on well E -102 at 120 ppm on 09/16/2008. o E -pad H2S values typically <10ppm o E -102 is two wellhouses away from E -09 Reservoir Pressure .� • The reservoir pressure on E -09B was last recorded at 3,027 psi at 8,800' TVDSS in June 2006. (6.62 ppg equivalent). • Max. expected surface pressure with gas (0.10 psi /ft) to surface is 2,147 psi. Cody Hinchman CTD Engineer CC: Well File Sondra Stewman/Terrie Hubble • TREE= � " �� E-09B SAFETY NOTES: CHROMELNR WELLHEAD = 13.5/8" MCEVOY .06/19109 • X NIPPLE@ 9519' DAMAGED DUISNG 2002 ACTUATOR= BAKER MILLING OPERATIONS • WILL NOT HOLD PRESSURE KB. ELEV = 65.01' w/PLUG SET BF. ELEV - 30.76' KOP = 10680' 1 2083' H4.112' OTIS SSSV NP, ID= 3.813" I Mu Angle = 97 @1171 • DaEwn MD = 10939' Deign TVD = 8800' SS ■ 2620' 9-5/8" DV PKR 113.318' CSG,72#,1.80, ID= 12.34r H 2611' 1 GAS UFT MANDRELS ST MO TVD DEV TYPE VLV LATCH PORT DATE Minimum ID = 2.372" 10737' 3 4384 4198 36 WER DMY RM 0 06/12/07 2 8264 6805 44 MER DMY RM 0 08/121.17 TOP OF 2- 718" TUBING 1 9413 7671 37 MER DMY RA 0 09108002 I I I 9483' H4-1/7 OTIS X MP, D= 3.813" I ' { 9495. H4- 1/2'TNIIHBBPPKR,D =4.32" I I I I 9519' 1-14-1/7 OTIS X NP, D= 3.813' I ' 95W' 114-1/7 OTIS XNNP, ID =3.80' (MLLED08/29/02) 'SEE SAFETY NOTE 4.1t7 TBG,12.6#, L -80, .0152 tpf, D = 3.953' H 9542' I i \ I 9542' H4 -112' WLEG, D = 3.958" 1 ITOP OF 5' LW H 9553' I I HELMD TT NOT LOGGED ITOPOF7'LNR 97'1 'UNKNOWN }tet THREE KICK SPRNGS(06/12'07) I I 10103' H4' BKRDEPLOY *NT SLV, D =3.00" , I 9-5/8' CSG, 470,1-80, D = 8.66" H 10213' I---A I L I 10113' H 1 / 2 0 : 2 . 7 58 ' I 3.1/2" LNR 8.81 #, L-80, .0087 b pr, D = 2. 992" 10608' ) 10608' 3-112' X 3.1116" X0, D =2.800' 1 4 1� O NLL OUT WNDOW 10681' - 10688' 14 / • /,/.4 r LW, 29#, 1-80,0371 bpf, D = 6.184" 11 10898' r r t r r ~� 10736' H3 -316 - X 2 -78' X0, ID= 2.380' 1 111111) ►111111 I5" Lift 15#,13 -CR, .01.. bpf, D =4.408' 11995' PBTD 12687 I 4 40, PERFORATION SUMMARY REF LOG: MEM GR/CCUMNCL ON 09/07/02 13 -3/16' LNR, 6.2#, L -80, .0076 bpf, D =HOD" 10735' I ANGLE AT TOP PIN: 65 @ 10937' Note: Refer b Production DB for hisbricaI perf data 12- 718" LNR, 6.16#, L-80, .0058 bpf , D =2.441° 1 5' SIZE SPF NTERVAL Opn/Sgz DATE SE PAGE 2 TREE= 4" 5M CM/ III WELLHEAD = 3.5/8" MCEVOY E - V a C SAFE' NOTES: 5" CHROMELNR ACTUATOR = -- BAKER KB ELEV= 65.01' Pr - _ -` --- detrack BF. ELEV = 30.76' KOP = 10680' Max Angle = 97 011711 O 2083' H4 -1/2" OTIS SSSV NIP, ID= 3.813" Datu MD = 10939' L] Datum TVD = 8800' SS 2620' —19 -518" DV PKR I 13 -3/8" CSG,72#, L -80, 0 = 12.347" H 2671' GAS LIFT MANDRELS ST MD TVD DEV TYPE VLV LATCH PORT DATE 3 4384 4198 36 MER OMY RM 0 06/12/07 Minimum ID =1.995" @ 10200' J 2 8264 6805 44 M@2 DMY RM 0 06112/07 1 9413 7871 37 MER DMY RA 0 09/08/02 TOP OF 2 -3/8" LINER ' ' 9483' H4 -112" OTIS X NP, 0 = 3.813" I —' 9495' I — 4-1/2" TNV HBBP FKR, ID = 4 32' I I I i 9519' H4- 112" OTIS X NP, 0 - 3.813" I I I __ 9530' I 4 - 112" OTIS XN NP 11= 3 R0" (MILLED 08/29/02) 1 4 -1/2" TBG. 12.6 *, L- 80..0152 Dpf, ID= 3.953" I—I 9542' . / \ E 9542" —14 -1/2" WLEG, 0= 3.958" I TOP OF 5 "LNR H 9553' I H ELMD TT NOT LOGGED I ITOP 7" LNR H 9717' I 10103' H BKR DEPLOYMENT SIN, 0 =3 00" I I 9 - 518" CSG, 474, L -80, 0 = 8.68" H 10213' I 1 I L. 1 10113' H3 -1n" HES XN NP, ID = 2.750" I 3 -1/2" LNR. 8.8 4 I - nnai bnf 0 = 2 - 105694 I - nnai bnf 0 = 2 992" + 36 0 10200' Top of 2-3/8" Aver deployment sleeve TSGR 10420' I ►� /, I7" LNR, 29*. L -80, .0371 bpf. 0= 6.184" H 10569' I3 -3/16" monobare w hipstock H 10624' I \ 10608' H3-1/2" X 3-1/16° XO, ID = 2.800" I /Cr f« kZ.c —'` ° 39 MILL OUT WO+DOVV 10681' - 10688' 1 I 5 " LNR, 15a, 13-C R, .0188 bpi, 0=4 408" H 10688' I \ 13 - 3/16" LW, 6.2 *, L -80. 0076 bpf, ID= 2100" H 10735' I- -----' I 2 -316" L-60 uner, (2.a [rented 8 Pe/n.1 13300' III I2 - 718" LNR 6 16#, L -80 0058 bpf, ID = 2,441" H 12725' iii DATE REV BY CONVENTS DATE REV BY CCOMENTS PRLIDHOE BAY UNIT 05/80 ORIGINAL COMPLETION 06/27 /07' RCT/SV Mil XN NIPPLE (08/29/02) WELL E -09 01/13/98 DFF SIDETRACK (E -09A) 06127109 'MBfTLM X NIFRE DAMAGED PERMIT No. 09/08/02 DAC/KK CTD SIDETRACK (E -09B) 08/11/09 MSE PROPOSEDCTDSDETRACK API No 50- 029 - 20466 -0 5/27 -28/04 BJMcN/KK ADPERFS SEC 6. T11 N. R14E 243 18' FM. & 500.01' FEL 05/21 /05 WJWPJC PERFORATIONS 06/27/07 GFITLH GLV C/O (06/12/07) & FISH BP Exploration (Alaska) Rig FIoo Top of Lubricator — Rilloor to Top of Bag Well E -09C 2.25 N 9.23 1 1 _ 9.23 i 4_______, i 1111111111 Lubricator ID = 6.375" with 6" Otis Unions Hydril Annular 1 7 1/16" Annular x 5000 psi 5.00 ♦ r_. 4 7 1/16" 5000 psi, RX - 46 Blind Shears l - _ 12.65 14---- TOT 13.56 ` 2" Combi's TOT I 7 1/16" 5000 psi RX -46 1 21/16 "5000 psi ,R24 1 � — �,- Mud Cross �_ i 1 M IMudcross I HCR 14.89 HCR – 1 I Choke Line I i- Kill Line ` l u 1/2' 16.10 `A— 23/8" x 3 ' E 1 2 1/16" 5000 psi , RX -24 Variable Ram - r 2 Comb! + i — 16.66 14--- III TOT 7 1/16" 5000 psi (RX - 46) ~— 7 1/16" X 3 1/8" Flanged Adapter 20.04 ■ • Swab Valve Tree Size 4 1/16" i I Flow Tee I I Flow Line I —• I 22.88 i • 0 _ SSV J MIM , • 24.86 I e Master Valve I 1 Ea d DZE 26.68 Lock Down Screws I 31.00 1 _ Ground Level BAKER U S 1NTEQ . North America - ALASKA - BP Prudhoe Bay PB E Pad E -09 - Slot 09 Plan 3, E -09C Plan: Plan #3 Baker Hughes INTEQ Planning Report 26 August, 2009 bp .., 0 ......., ,, Fake Baker Hughes INTEQ Planning Report 0 bp INTEQ Company North America - ALASKA - BP Local Co - ordinate Referen Well E -09 - Slot 09 Project* Prudhoe Bay a' TVD Reference Mean Sea Level Site PB E Pad , MD Reference : E -09A @ 65.01 ft (E -09A Rig 65.01') Well, > E -09 ::North Referen True 1A(etibore l Plan 3, E -09C Survey Calculation Meu od; Minimum Curvature Design: Plan #3 Database* - Anc Prod - WH24P '^ EDM .16 Project :, Prudhoe Bay, North Slope, UNITED STATES Map System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level Geo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point Map Zone: Alaska Zone 04 Using geodetic scale factor PB E Pad, TR-11 -14.._ Site Position: Northing: 5,973,160.88 ft Latitude: 70° 19' 59.134 N From: Map Easting: 662,538.97 ft Longitude: 148° 40' 53.054 W Position Uncertainty: 0.00 ft Slot Radius: 0.000 in Grid Convergence: 1.24 ° Well .. i E -09 - Slot 09, E -09 Well Position +NI -S 0.00 ft Northing: 5,976,820.00 ft Latitude: 70° 20' 34.706 N +E/ -W 0.00 ft Easting: 664,447.00 ft Longitude: 148° 39' 55.005 W Position Uncertainty 0.00 ft Wellhead Elevation: ft Ground Level: 0.00 ft , ; lbore Plan 3, E-09C .., Magnetics Model Name' : Sample Date Declination Dip Angle F ield. Strength:.. ..: !"} E "t EnT) BGGM2009 8/26/2009 22.57 80.96 57,674 Deslgrf Plan #3 Audit Notes: Version: Phase: PLAN Tie On Depth: 10,563.00 Vertical S ection De th From D +NI-S +lri Vir Direction p EN � (ft} Ett ERf (`) -30.00 0.00 0.00 225.00 8/26/2009 3:14:44PM Page 2 COMPASS 2003.16 Build 71 I FA RI I l'itillins Baker Hughes INTEQ Planning Report 0 bP INTiiCQ Company: North America - ALASKA - BP Local Ca-ord ate Reference :a:, Well E -09 - Slot 09 proJec{r Prudhoe Bay < 7Vo Reference Mean Sea Level ite ;:S: PE E Pad j E -09A @ 65.01ft (E -09A Rig 65.01') C Welt ; E -09 Noirtl► Rnterene True Nleiibore Plan 3, E -09C Survey Calculation il�ethod Minimum Curvature Design Plan #3 Database EDM .16 Anc Prod WH24P Survey Tool Pirogram Date 8/26/2009 Front To {ft {ft) . Sur (Wellbore).: Tool Name Descripti 104.71 10,563.00 1 : Sperry-Sun BOSS gyro multi (E -09) BOSS -GYRO Sperry-Sun BOSS gyro multishot 10,682.50 10,563.00 2 : MWD - Standard (E- 09APB1) MWD MWD - Standard 10,563.00 13,300.00 Plan #3 (Plan 3, E -09C) MWD MWD - Standard Planned Survey MD> Inc Azi TVDSS = N1S EM Northin#� Fasting DLeg Y ec TFace (ft) ' ( °) . °) ( (ft) (ft) , , : (ft) (ft) : .. ( ° 1100ft) , ` (ft : (') 10,563.00 37.85 105.51 8,596.87 - 740.49 4,758.90 5,976,184.13 669,220.67 0.00 - 2,841.44 0.00 TIP 10,600.00 41.19 99.32 8,625.41 - 745.50 4,781.88 5,976,179.62 669,243.75 13.96 - 2,854.15 -52.11 10,624.00 43.52 95.74 8,643.15 - 747.61 4,797.90 5,976,177.87 669,259.81 13.96 - 2,863.99 -47.33 KOP 10,644.00 41.72 95.74 8,657.87 - 748.96 4,811.38 5,976,176.81 669,273.31 9.00 - 2,872.56 180.00 End of 9 Deg /100' DLS 10,674.00 32.97 105.38 8,681.71 - 752.14 4,829.23 5,976,174.03 669,291.23 35.00 - 2,882.94 150.00 4 10,700.00 29.38 121.59 8,704.00 - 757.36 4,841.51 5,976,169.07 669,303.62 35.00 - 2,887.93 120.00 10,744.00 28.81 153.56 8,742.68 - 772.60 4,855.51 5,976,154.14 669,317.95 35.00 - 2,887.05 106.1 5 10,780.00 31.22 178.45 8,773.97 - 789.77 4,859.64 5,976,137.08 669,322.45 35.00 - 2,877.83 90.00 6 10,800.00 35.20 189.00 8,790.71 - 800.65 4,858.88 5,976,126.17 669,321.93 35.00 - 2,869.60 60.00 10,810.00 37.48 193.48 8,798.77 - 806.46 4,857.72 5,976,120.34 669,320.90 35.00 - 2,864.67 51.16 7 10,900.00 66.34 210.05 8,853.94 - 870.38 4,829.99 5,976,055.84 669,294.58 35.00 - 2,799.87 30.00 10,971.19 90.00 218.10 8,868.45 - 927.51 4,791.09 5,975,997.87 669,256.94 35.00 - 2,731.96 19.40 8 11,000.00 90.00 228.18 8,868.45 - 948.51 4,771.41 5,975,976.45 669,237.74 35.00 - 2,703.20 90.00 8/26/2009 3 :14:44PM Page 3 COMPASS 2003.16 Build 71 / /.ik/ s Baker Hughes INTEQ Planning Report bp INTEQ ompany ; ,. North America - ALASKA - BP .ocal Go•ordtnate Reference . Well E -09 - Slot 09 Project Prudhoe Bay . D R erence Mean Sea Level lY �( $tg PB E Pad Reference E -09A @ 65.01ft (E -09A Rig 65.01') Weli, E -09 _` n Nor h Reference :. True Plan 3, E -09C Su Vffeiltxfre rv ey,Calculation lYlethod Minimum Curvature Desgn Plan #3 D - atattase EDM .16 Anc Prod WH24P , Planned.. Survey, llllt3 I Azi T,YDSS N/S EMVY Northingg; Fasting; ` DLeg Y Se TFace: (ftf _...,.. E °�f ( °j . ..... tti ,w ,.. ... (ft? (ft) (tt� °/1 t: 4 C } .. 11,071.19 90.00 253.10 8,868.45 - 983.14 4,09.85 5,975,940.48 669,176.96 35.00 - 2,635.18 90.00 End of 35 Deg /100' DLS 11,100.00 90.00 256.55 8,868.45 - 990.68 4,682.05 5,975,932.33 669,149.33 12.00 - 2,610.19 90.00 11,200.00 90.00 268.55 8,868.45 - 1,003.62 4,583.07 5,975,917.23 669,050.67 12.00 - 2,531.06 90.00 11,221.19 90.00 271.10 8,868.45 - 1,003.68 4,561.89 5,975,916.70 669,029.49 12.00 - 2,516.03 90.00 10 11,300.00 88.20 261.81 8,869.69 - 1,008.55 4,483.33 5,975,910.11 668,951.06 12.00 - 2,457.04 - 101.00 11,400.00 86.00 250.00 8,874.76 - 1,032.81 4,386.64 5,975,883.73 668,854.93 12.00 - 2,371.51 - 100.85 11,421.19 85.55 247.49 8,876.33 - 1,040.47 4,366.95 5,975,875.64 668,835.41 12.00 - 2,352.17 - 100.25 11 11,500.00 85.77 256.97 8,882.30 - 1,064.43 4,292.19 5,975,850.05 668,761.21 12.00 - 2,282.38 89.00 11,521.19 85.85 259.52 8,883.85 - 1,068.73 4,271.51 5,975,845.29 668,740.63 12.00 - 2,264.70 88.28 12 11,600.00 85.91 250.04 8,889.52 - 1,089.35 4,195.74 5,975,823.02 668,665.34 12.00 - 2,196.55 -90.00 11,700.00 86.14 238.01 8,896.48 - 1,132.96 4,106.23 5,975,777.46 668,576.81 12.00 - 2,102.42 -89.32 11,771.19 86.41 229.45 8,901.11 - 1,174.95 4,049.01 5,975,734.23 668,520.52 12.00 - 2,032.27 -88.48 13 11,800.00 86.45 232.92 8,902.90 - 1,192.97 4,026.61 5,975,715.73 668,498.52 12.00 - 2,003.69 89.540 11,900.00 86.67 244.94 8,908.93 - 1,244.39 3,941.26 5,975,662.45 668,414.34 12.00 - 1,906.98 89.28 12,000.00 87.05 256.95 8,914.42 - 1,276.93 3,847.06 5,975,627.86 668,320.88 12.00 - 1,817.36 88.56 12,021.19 87.14 259.49 8,915.50 - 1,281.24 3,826.35 5,975,623.08 668,300.26 12.00 - 1,799.66 87.90 14 12,100.00 87.18 250.03 8,919.41 - 1,301.91 3,750.49 5,975,600.76 668,224.88 12.00 - 1,731.40 -90.00 12,121.19 87.20 247.48 8,920.45 - 1,309.58 3,730.76 5,975,592.66 668,205.33 12.00 - 1,712.03 -89.53 15 12,200.00 87.24 238.01 8,924.28 - 1,345.59 3,660.86 5,975,555.13 668,136.24 12.00 - 1,637.15 -90.00 12,221.19 87.27 235.47 8,925.29 - 1,357.19 3,643.17 5,975,543.14 668,118.81 12.00 - 1,616.43 -89.54 16 8/26/2009 3:14:44PM Page 4 COMPASS 2003.16 Build 71 VrkU Wins Baker Hughes INTEQ Planning Report 0 bp ' INTEQ ompany North America - ALASKA - BP 1.efidat Chi- ordinate 4 eference' Well E -09 - Slot 09 Project Prudhoe Bay ND Reference Mean Sea Level Site; PB E Pad ,. MD Reference E -09A @ 65.01 ft (E -09A Rig 65.01') :!.,:: Yfreli E -09 : North Reference �.., True Yllalfbare Plan 3, E -09C Survey Calculation Method , Minimum Curvature Design Plan #3 Database` EDM .16 - Anc Prod - WH24P Planned Survey MD in+c; AzE TVD SS N/S 51W Northing' > Fasting > Dl eg , Y Sec : TIace r . 4ft' ... (°t. t , ( ....... ' 1t) =(ft). :" (R) ..,..: (ft) °t11 oaft . _ (ft :. t , 12,300.00 87.96 244.91 8,928.58 - 1,396.30 3,574.92 5,975,502.55 668,051.44 12.00 - 1,540.52 86.00 12,400.00 88.92 256.87 8,931.32 - 1,428.96 3,480.64 5,975,467.83 667,957.91 12.00 - 1,450.76 85.61 12,421.19 89.13 259.41 8,931.68 - 1,433.32 3,459.91 5,975,463.02 667,937.28 12.00 - 1,433.02 85.28 17 12,500.00 89.47 249.96 8,932.65 - 1,454.11 3,383.99 5,975,440.57 667,861.84 12.00 - 1,364.63 -88.00 12,600.00 89.92 237.96 8,933.19 - 1,497.93 3,294.31 5,975,394.79 667,773.14 12.00 - 1,270.23 -87.88 12,621.19 90.02 235.42 8,933.20 - 1,509.57 3,276.60 5,975,382.77 667,755.70 12.00 - 1,249.48 -87.82 18 12,700.00 90.01 244.88 8,933.18 - 1,548.75 3,208.32 5,975,342.11 667,688.30 12.00 - 1,173.50 90.00 12,800.00 90.01 256.88 8,933.15 - 1,581.44 3,114.01 5,975,307.35 667,594.73 12.00 - 1,083.69 90.00 12,801.19 90.01 257.02 8,933.15 - 1,581.71 3,112.85 5,975,307.06 667,593.58 12.00 - 1,082.68 90.01 19 12,900.00 90.01 245.17 8,933.13 - 1,613.67 3,019.54 5,975,273.06 667,501.00 12.00 - 994.10 -90.00 13,000.00 90.01 233.17 8,933.11 - 1,664.83 2,933.83 5,975,220.04 667,416.44 12.00 - 897.32 -90.00 13,001.19 90.01 233.02 8,933.11 - 1,665.55 2,932.88 5,975,219.30 667,415.51 12.00 - 896.14 -90.01 20 13,100.00 90.01 244.88 8,933.08 - 1,716.42 2,848.38 5,975,166.59 667,332.14 12.00 - 800.41 90.0 13,101.19 90.01 245.02 8,933.08 - 1,716.92 2,847.30 5,975,166.06 667,331.08 12.00 - 799.30 90.00 21 13,200.00 90.01 233.17 8,933.06 - 1,767.59 2,762.67 5,975,113.56 667,247.59 12.00 - 703.63 -90.00 13,300.00 90.01 221.17 8,933.04 - 1,835.45 2,689.47 5,975,044.11 667,175.90 12.00 - 603.89 -90.00 TD 8/26/2009 3 :14 :44PM Page 5 COMPASS 2003.16 Build 71 Valli Baker Hughes INTEQ Planning Report 0 bp INTEQ Company North America - ALASKA - BP , L ocal004..ardinate Reference , Well E -09 - Slot 09 i' ject. Prudhoe Bay TVD Reference Mean Sea Level site PB E Pad MD Reference E -09A @ 65.01 ft (E -09A Rig 65.01') Weft" E -09 North Reference True t(Its11bore Plan 3, E -09C Survey (akulation Method Minimum Curvature Design Plan #3 Database} EDM .16 Anc Prod WH24P T'� Target N ame htttmtss target Dip Angle Dip Dir TVD ;:' > +Nt-s :: +Ei w Northing seating , E -09C Fault 1 0.00 0.00 0.00 - 2,095.51 1,862.61 5,974,766.00 666,355.00 70° 20' 14.094 N 148° 39' 0.606 W • - plan misses target center by 8975.00ft at 13300.00ft MD (8933.04 ND, - 1835.45 N, 2689.47 E) - Polygon Point 1 0.00 - 2,095.51 1,862.61 5,974,766.00 666,355.00 Point 2 0.00 - 1,278.91 2,621.76 5,975,599.00 667,096.00 Point 3 0.00 - 1,053.82 3,395.93 5,975,841.00 667,865.00 Point 4 0.00 - 280.60 4,992.39 5,976,649.00 669,444.00 Point 5 0.00 - 1,053.82 3,395.93 5,975,841.00 667,865.00 Point 6 0.00 - 1,278.91 2,621.76 5,975,599.00 667,096.00 E -09C Target 1 0.00 0.00 8,868.00 - 985.95 4,542.78 5,975,934.00 669,010.00 70° 20' 24.996 N 148° 37' 42.309 W - plan misses target center by 17.76ft at 11239.17ft MD (8868.51 TVD, - 1003.67 N, 4543.90 E) - Point E -09C Target 3 0.00 0.00 8,933.00 - 1,526.55 3,194.51 5,975,364.00 667,674.00 70° 20' 19.686 N 148° 38' 21.699 W - plan misses target center by 26.07ft at 12705.79ft MD (8933.18 ND, - 1551.18 N, 3203.06 E) - Point E -09C Polygon 0.00 0.00 0.00 - 649.69 4,809.24 5,976,276.00 669,269.00 70° 20' 28.301 N 148° 37' 34.519 W - plan misses target center by 8597.49ft at 10563.00ft MD (8596.87 TVD, - 740.49 N, 4758.90 E) - Polygon Point 1 0.00 - 649.69 4,809.24 5,976,276.00 669,269.00 • Point 2 0.00 - 881.76 5,037.22 5,976,049.00 669,502.00 Point 3 0.00 - 1,606.99 3,441.82 5,975,289.00 667,923.00 Point4 0.00 - 1,725.23 3,086.11 5,975,163.00 667,570.00 Point 5 0.00 - 2,211.18 2,484.27 5,974,664.00 666,979.00 Point 6 0.00 - 2,075.52 2,274.18 5,974,795.00 666,766.00 Point 7 0.00 - 1,574.39 2,822.34 5,975,308.00 667,303.00 Point 8 0.00 - 1,475.51 3,193.62 5,975,415.00 667,672.00 E -09C Fault 4 0.00 0.00 0.00 - 1,746.99 3,211.68 5,975,144.00 667,696.00 70° 20' 17.518 N 148° 38' 21.201 W - plan misses target center by 8792.78ft at 10563.00ft MD (8596.87 TVD, - 740.49 N, 4758.90 E) - Polygon Point 1 0.00 - 1,746.99 3,211.68 5,975,144.00 667,696.00 Point2 0.00 - 2,098.59 4,191.27 5,974,814.00 668,683.00 E -09C Target 2 0.00 0.00 8,920.00 - 1,301.64 3,703.60 5,975,600.00 668,178.00 70° 20' 21.895 N 148° 38' 6.826 W - plan misses target center by 18.30ft at 12141.68ft MD (8921.45 ND, - 1317.82 N, 3712.03 E) 8/26/2009 3:14:44PM Page 6 COMPASS 2003.16 Build 71 a tinius Baker Hughes INTEQ Planning Report bp INTEQ Company North America ALASKA BP t.ocal Coordinate Reference Well E -09 - Slot 09 Prudhoe Bay PnoJ � '1'1/p Reference Mean Sea Level Site PB E Pad ' MD Reference E -09A @ 65.01ft (E -09A Rig 65.01') iil Well E-09 North Reference: True Weilbore, ' Plan 3, E -09C Survey Calculation Method Minimum Curvature Design Plan #3 Database EDM .16 - Anc Prod - WH24P - Point E -09C Fault 2 0.00 0.00 0.00 - 1,369.62 3,199.95 5,975,521.00 667,676.00 70° 20' 21.229 N 148° 38' 21.538 W - plan misses target center by 8759.69ft at 10563.00ft MD (8596.87 ND, - 740.49 N, 4758.90 E) - Polygon Point 1 0.00 - 1,369.62 3,199.95 5,975,521.00 667,676.00 Point2 0.00 - 1,066.69 3,526.70 5,975,831.00 667,996.00 E -09C Fault 3 0.00 0.00 0.00 - 1,469.55 4,016.01 5,975,439.00 668,494.00 70° 20' 20.242 N 148° 37' 57.704 W - plan misses target center by 8659.65ft at 10563.00ft MD (8596.87 ND, - 740.49 N, 4758.90 E) - Polygon Point 1 0.00 - 1,469.55 4,016.01 5,975,439.00 668,494.00 Point 2 0.00 - 1,083.28 5,148.83 5,975,850.00 669,618.00 E -09C Target 4 0.00 0.00 8,933.00 - 1,948.13 2,577.07 5,974,929.00 667,066.00 70° 20' 15.542 N 148° 38' 39.738 W - plan misses target center by 159.16ft at 13300.00ft MD (8933.04 ND, - 1835.45 N, 2689.47 E) - Point Ca g Poin Measured Vertical : Casin Hole i Depth Depth : " Diameter Diamete . a . Ift . (f� .., .. . , . Name.. _. (In) l n 2 ,675.71 2 ,610.60 13 3 /8" 13.375 17.500 13,300.00 8,933.04 2 -3/8" 2.375 3.000 10,217.71 8,325.28 9 5/8" 9.625 12.250 • 8/26/2009 3:14:44PM Page 7 COMPASS 2003.16 Build 71 FAiiu Was Baker Hughes INTEQ Planning Report bp INTEQ 6htpany# North America - ALASKA BP Ltfaal Co- ordinate Reforen1ce Well E -09 - Slot 09 pro4ectt Prudhoe Bay NO Reference " Mean Sea Level S PB E Pad MD Re rettca ' E -09A @ 65.01ft (E -09A Rig 65.01') ,',.--:! Weli; E 09 Ntrrth.Reference '' True } Wefibete Plan 3, E -09C SUnrey Calculation Method .Minimum Curvature Design Plan #3 Database EDM .16 Anc Prod - WH24P P lan Ainn tatians Measured Vertical L:ccal Coordinates ; :, Depth Depth +N/-S ! 4E! W .... _.. {ft). ... (ft)' Ca mm e 10,563.00 8,596.87 - 740. 4,758.90 TIP 10,624.00 8,643.15 - 747.61 4,797.90 KOP 10,644.00 8,657.87 - 748.96 4,811.38 End of 9 Deg /100' DLS 10,674.00 8,681.71 - 752.14 4,829.23 4 10,744.00 8,742.68 - 772.60 4,855.51 5 10,780.00 8,773.97 - 789.77 4,859.64 6 10,810.00 8,798.77 - 806.46 4,857.72 7 10,971.19 8,868.45 - 927.51 4,791.09 8 11,071.19 8,868.45 - 983.14 4,709.85 End of 35 Deg /100' DLS 11,221.19 8,868.45 - 1,003.68 4,561.89 10 11,421.19 8,876.33 - 1,040.47 4,366.95 11 11,521.19 8,883.85 - 1,068.73 4,271.51 12 11,771.19 8,901.11 - 1,174.95 4,049.01 13 12,021.19 8,915.50 - 1,281.24 3,826.35 14 12,121.19 8,920.45 - 1,309.58 3,730.76 15 12,221.19 8,925.29 - 1,357.19 3,643.17 16 12,421.19 8,931.68 - 1,433.32 3,459.91 17 12,621.19 8,933.20 - 1,509.57 3,276.60 18 12,801.19 8,933.15 - 1,581.71 3,112.85 19 13,001.19 8,933.11 - 1,665.55 2,932.88 20 13,101.19 8,933.08 - 1,716.92 2,847.30 21 13,300.00 8,933.04 - 1,835.45 2,689.47 TD I Checked By: Approved By: Date: 8/26/2009 3:14:44PM Page 8 COMPASS 2003.16 Build 71 Anm u Nu9 T,ueNoM 22.56° WELLBORE DETAILS: Plan 3, E-09C REFERENCE INFORMATION EMI Prudhoe Bay gnetic Site: PB E Pad Coadne6(NIE)Rekrence: WetE- 09- SIot09,TnreNoM LIMES Magnetic Field Parent Wellbore: E- 09APB1 0 bp Well: E -09 Strength: 57604.1anT Veffical(TVD)Relerence: Mean Sea Level Dip Angle: 80.0 Tie on MD: 10563.00 Section ) Wellbore: Plan 3, E -09C p 9 (VS)Rekrence: Sbt- 09(000N,O.00E P lan: Plan 03(E-081PIan3,E4MC) Model. 12 5 Measured Depth Reference: E-09A (g 65.01ft(E-09A Rig 6501') Calculzton Method: MhimumCurvature 1NTEQ 400 200 WELL DETAILS: E -09 Ground Level: 0.00 0 +NI -S +E/ -W Northing Easting Latittude Longitude Slot 0.00 0.00 5976820.00 664447.00 70° 20' 34.706 N 148° 39' 55.005 W 09 -211 ■ ■ ■ ■ ■.��■ SECTIONOETALS ANNOTATIONS -400 Sec MD Inc 1 4049 +E/-W D Tfaoa VSec Target Annotation =■..,� KOP E -09 iiim 1 10563.00 37.85 105.51 8596.87 59687 - 740.49 4758.90 0.00 .00 0.00 - 2841.44 2 10624.00 43.52 95.74 8643.15 - 747.61 4797.90 13.96 -52.11 - 2863.99 TIP -61 1 3 10644.00 41.72 95.74 6657.87 - 748.96 4811.38 9.00 180.00 - 2872.56 End of 9 D 100' DLS ■■■aMP:� E- O9/L' -09 4 10674.00 32.97 105.38 8681.71 - 752.14 4829.23 35.00 150.00 - 2682.94 -800 . 5 10744.00 28.81 153.56 8742.68 - 772.60 4855.51 35.00 120.00 - 2887.05 4 E-09C Fault 2 r 11 6 10780.00 3122 178.45 8773.97 - 789.77 4859.64 35.00 90.00 - 2877.83 5 ;.�� an I 7 10810.00 3748 193.48 8798.77 - 806.46 4857.72 35.00 60.00 - 2864.67 rte�r'' 8 1071.19 90.00 218.10 886845 -927.51 4791.09 35.00 30.00 -2731.96 8 N -1000 , - NN.��. • . r l s. • 9 11071.19 90.00 253.10 8868.45 - 983.74 4 4709.85 35.00 90.00 -2635.18 10 11221.19 90.00 271.10 8868.45 - 1003.68 4561.89 12.00 90.00 - 2516.03 8 --1201 / ' / r 11 11421.19 85.55 247.49 8876.33 -104047 4366.95 12.00 259.00 - 2352.17 End of 35 Deg /100' DLS 1 ' � mil 12 11521.19 85.85 259.52 8883.85 - 1068.73 4271.51 12.00 89.00 - 2264.70 10 G -14,1: E-09C T; et 3 � � �� ' � 13 11771.19 86.41 229.45 8901.11 -1174.95 4049.01 2 12.00 270.00 -203227 1 1 E ,,, , 1 15 II.■ III 12021.19 87.14 7.14 259.49 891515.50 0 - 128124 38826.335 5 12.00 89.50 - 0322 1 2 �C - 15 12121.19 8720 24748 8920.45 -1309.58 3730.76 12.00 270.00 -1712.03 1 4 ` r , - -1611 ��r.N■ 16 122221.19 8727 235.47 892529 -1357.19 3643.17 12.00 270.00 - 1616.43 14 r TI 17 12421.19 89.13 259.41 8931.68 - 1433.32 3459.91 12.00 86.00 - 1433.02 1 5 p -181 I 18 12621.19 90.02 235.42 893320 -1509.57 3276.60 12.00 272.00 -1249.48 16 N _ ■ ■ ■ ■-- 19 12801.19 90.01 257.02 8933.15 - 15811.71 1 3111285 12.00 90.00 - 1082.68 1 7 20 13001.19 90.01 233.02 8933.11 - 1665.55 2932.88 12.00 270.00 -896.14 -2111 21 13101.19 90.01 245.02 8933.08 - 1716.92 2847.30 12.00 90.00 - 799.30 1 8 IVO 22 13300.00 90.01 221.17 8933.04 - 1835.45 268947 12.00 270.00 - 603.89 19 20 -2200 a .ee I,,Iel.14 21 .E -0901an 3, 4-09C 8933.04 13300.00 TD -2400 -2600 2200 2400 2600 2800 3000 3200 3400 3600 3800 4000 4200 4400 4600 4800 5000 5200 5400 5600 5800 West( - )/East( +) (200 ft/in) , 8471 8541 ■■■.■■■■ ■■■■ ■■■■■■ ■■ ■■ ■ ■■■ ■■■■■■■■■ ■ ■ ■■ 86 1Ea■■■ ■■■■■■■■■■■■■■■■■■■.■■■■■■■■■■■ :6:51 ■ JJ 162■■■■ ■■■ ■ ■ ■ ■ ■.•••••••••••■ ■ ■ ■. ■ ■■■ ■■ • 1 PI;.. �il.■ ■■■■■■■■■■■■■■■■■■■■■■■■■■■■■■■ '.�-+ L��.■■■■ E o9cI ■■■■■■■■■■■■■■■■■■■■■■■■■■■■.■ A 8891 � � PI MI.....••■ ■ ■ ■. II ° 6 961 ■ E -09/ �� ■,.� ■. ■ ■■ ■■:..= . ■. ■ ■�.v■.�� ..� ®■• � ■■ ■■ll■u■ ■t■■■■■■■ii■ ■■■l■•■■i•ii . lam F m ■■■■■ .■■■■■■■■■■■■■■■■■■■■■■■■■■■■■■ m 9171 ■■.■■■■■ ■■■■■■■■■ ■ ■ ■■■■■.. ■ ■■ ■ ■■■■■ ■■ ■■ r ■■■■■■■■ ■■■■■■■■ ■■ ■ ■ ■■■■■■■■■■■■■■■■■■■ m 9241 ■■■■■■■■ ■■ ■ ■ ■ ■■■■ ■ ■ ■ ■■■■■ ■ ■ ■ ■- ■■■ ■ ■ ■ ■ ■■ -2940 -2870 -2800 -2730 -2660 -2590 -2520 -2450 -2380 -2310 -2240 -2170 -2100 -2030 -1960 -1890 -1820 -1750 -1680 -1610 -1540 -1470 -1400 -1330 -1260 -1190 -1120 -1050 -980 -910 -840 -770 -700 -630 -560 -490 -420 -350 -280 Vertical Section at 225.00° (70 Olin) ' • A...uem Tr. Ns. WELLBORE DETAILS: Plan 3, E -09C REFERENCE INFORMATION MI Project: Prudhoe Bay Maaneacnorc 22.56 EMI Site: PB E Pad Coar3eab(WE)Reference: E E- 09- Sbt09,Trce Nadh M Jnetlev Parent Welbore: E- 09APB7 Well: E -09 suength 51614.1anT Vertical(TVD)Reference: E- 09A@ 65.01RIE -09ARg65.01') 0 b „ Wellbore: Plan 3,E -09C PIan: op a eo sa° Tie on MD: 10563.00 ,(VS)Reference: Slot- 09(0.00N, O.00E) MAU N Plan #3 (E -09YPIan 3, E-09C) Del. 6/26/2005 Model. eG . 80.%1 Measured Depth Reference: E- 09A @65.01R(E -09ARg65.01') CabulOon Medvd: MinmumCurcabre 1NTEQ _ID ■ i - 10, < j ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■1 .21 r ■_■ �i�YiliiiiiB�■� ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■1 -301 • _ ..■■M�iiiiiii ■ ■\N ■ ■ ■ ■ ■ ■ ■EM ■ ■ ■ ■1 -000 ■: \ 1111 ■ \ ■ ■ ■ ■ ■ ■��■■ ■ ■1 =..1..._i_. -09, 1 /11 -5 ■ ■ ■■ ■■ ■11_:11 ■ ■\► E ■11U ■■■ ■•11 ■rp-- ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■PA■■■11 ■lIn1111M111 • SOI 1111■■ ■ ■ ■ ■� /■ ■ ■ ■�■■E LI��i _901 '. 1111■ 1111■ / . ■■.! ■\!ii►�.1 r iiipl ■■U!!■ not : i _ ,.1111..,. ■ ■,a. 1 ©�I ■�./ ■�►111�A/�� % ■ ■ ■� ■1 ▪ -1300 I■ � L;.:� = ■;.;,.., =; ■111111.■, O .14Y 1. 11 , .II%i iI ii,,. ■Y',I'`' . ■ ■ ■1 .1511 ■, /,;., / ■ ■ /. ■ ■ ■ ■ ■,.' ■..1 -1600 • ■ '; IM /..'. ■ ■ ■ ■■ ■ ■ ■ ■ ■MMINI \', 11 �I■■NI■■■■■■■■■■■ ■■■11■ ■ ■ ■1 • 1700'. / /►I■■■■ ■ ■ ■ ■ ■ ■ ■Il ■ ■ ■: ■�'"• C2 f -1811 ,� I '1111 ■',,. ■1111■■■ ■11■■■■ 9AL 1 • -2600 _ � ■11■■■■\■S4. _2111 ■ ■ ■ ■ ■ ■ ■ ■,,`_ 1 Pill ;,. -2200 • D`� —_ •■■■■■■■■■■ ■■■■■■■■■■■�1 2311 ■ �• !I iuI uu uiir uiIlIIi ! \ \ ■ ■ ■ ■ ■ ■■■■11 nu sim11 ■\\ ■1 _2400 2511 2611■ ■ - E-09 A @ 65.01 ft (E • . Rig r. .01') -2700 1700 1800 1900 2000 2100 2200 2300 2400 2500 2600 2700 2800 2900 3000 3100 3200 3300 3400 F 3500 3600 3700 3800 3900 4000 4100 4 200 4 300 4400 4500 4 600 4700 4800 4 900 5000 5 ■ 1 r 1... i1'13400 West( - )/East( +) (100 ft/in) Project: Prudhoe Bay ANTI - COLLISION SETTINGS COMPANY 96311.8: N . nA.a:a- ALASKA - IP Ct Site: PB E Pad M O R T I O M E R I C A ISM. b y Well: E -09 Interpolation Method: MD, interval: 50.00 BAKER Depth Range From: 10563.00 To 13300.00 o" o.mh "11iNrmcuv °'n HUGHES W elibore: Plan 3, E.09C R Limited By: Centre Distance: 1526.50 E E ror w �, 84 Reference: Plan: Plan #3 (E- 09/Plan 3 E -09C) shat ei Plan: Plan d3 (E-09/Plan 3, E -09C) w ., e ra a MM6o4. 9ul.B.. 1NTEQ WELL DETAILS: E -09 Ground Level: 0.00 +WS +E/.W Northing Easting Latiltude Longtede Slot From Colour To MD 0.00 0.00 5976820.00 66444700 70 °20'34.708N 148 °39'55.005W 09 SECTION DETAILS See MD Inc AS TKD +WS +Fl -W vs. TFaco vs Target D 1 10563.00 37 85 105.51 9661 88 - 740.49 4758.90 0.00 0.00 -2841 44 2 10624 00 43 52 95.74 8708.16 - 747.61 4797 90 13.96 52.11 -2863 99 192 3 1064.00 41.72 95.74 8722.88 - 748.96 4811.38 9.00 180.00 - 287256 //� - - 4 1067400 3287 105.38 8]46.]2 - ]52.14 4829.23 35.00 150.00 - 288299 %� /' 2B 81 153 6 10780 00 31 22 178.45 8838 . 56 88069 ]72.60 35 . 00 12000 !iH 378 193.48 886 8 - 806.46 5 35 00 479 . ` 9000 218.10 89346 927.51 47919 35.00 90.00 253.10 89346 - 983.14 47095 35.00 160 - ` 1 1 85 247.49 894336 1000.67 436195 12.00 59.00 2352.17 �� % � - - \�` \ 13 11771.19 B6 41 229 15 8966 12 - 1174.85 1019.01 12.00 IJ \ 11 11121.19 85.55 247.19 8941.34 - 1010.47 4 12.00 259.00 - 2352.17 85.45 2 87 . 14 2 87 20 2 8727 2.19 .. 99.13 2669 - 142 3459.91 12.00 jj ' 19 9002 .,19 90.01 - -7996 14 930 �W' 20 130 01.19 90.01 233.02 0990.12 - 1 1 665.55 2932.88 . 270.00 19. .716.92 ... - 79.30 /�' 112 \ \ \ \� ..4 \ \O , ✓}5 5 SURVEY PROGRAM / � �• - - 22 13300.00 90.01 221.17 8998 05 - 1835 45 26897 12.00 270.00 4303.89 \ \ \ \ \ \ \ \ \�\ �\ \ \\\\\ \`r 7t Dale: 2009 2 8T00:00:00 Validated: Yes Version: �, � sa;: 0 \\ ,�\ : , \ 111 � A \ \ \ \ \ \\ \ \ \ \ \\ \ \ \ \\\\ Depth From Depth To Survey /Plan Tool �� Q\ \ \ \ \° 1 \ \� \ \ \ \\ 104.71 10563.00 1 . SDer -Sun BOSS o muIIB YRO / '" 48 \\�\a \� \�o0`4` �11 l / (11111164" \ \ \ p \\ „1 Z, f ll / 1 1 1 1111�/ / 32 10 1..c ►11111 � I IIIIIIII] liidioi►►► ummm�LIA LEGEND IIIIIIIIIIIIIIIIII 271 0� �lllilh IIIIIIIIIIillilllllllil �� 2 »)))))))))))/11)71111111E9i3EII � �. 4. Em Etsemln _ I�iIII E -09/E 096 iiiiiiiiiiiii if E0 MAEVAV, 0� 0 86 ////////// 1oa . 12 120 \\ ` ` - -- 136 _ � �� \ � _ - 152 . '''.� \ � 168 � � ......... 21 1 ` ` 184 .. 150 � \` .... ...0.0 .200 .. .........v, 1 80 _ ...,n Travelling CylinderAzimuth (TFO +AZI) [e] vs Centre to Centre Separation [16 ft/in] �a • ■pair BAKER MONIES INTEQ North America - ALASKA - BP Prudhoe Bay PB E Pad E -09 Plan 3, E -09C Plan #3 Travelling Cylinder Report 26 August, 2009 a I O b p :iiiu • litnns Travelling Cylinder Report 0 bP INTEQ lyom pany North America - ALASKA - BP Local .Co- ordinate Referenc !Well E -09 - Slot 09 Ptoieet Prudho Bay fiVO Ref E -09A @ 65.01ft (E -09A Rig 65.01') Rel nt Site i PB E Pad i efe rerice: E -09A @ 65.01 ft (E -09A Rig 65.01') Site Error; 0.00ft N Reference :True Reference Well; E-09 Survey,;Calc ulation Method .., >' < Minimum Curvature Wen Eirro - 0.00ft Output:errors are at " 1.00 sigma Reference Wellbore. Plan 3, E -09C Database. ' EDM .16 - Ana Prod - WH24P Reference Desigq Plan #3 Offset TVti Reference.: Offset Datum Reronce Plan #3 Filter type: GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of refer( Interpolation Method: MD Interval 25.00ft Error Model: ISCWSA Depth Range: 10,563.00 to 13,300.00ft Scan Method: Tray. Cylinder North Results Limited by: Maximum center - center distance of 1,526.50ft Error Surface: Elliptical Conic 3ulveyTooi Fragrant Date 8/28/2009 Front To {ft) : (R) Survey (Weilbore) Tool Name Description 104.71 10,563.00 1 : Sperry-Sun BOSS gyro multi (E -09) BOSS -GYRO Sperry-Sun BOSS gyro multishot 10,682.50 10,563.00 2 : MWD - Standard (E- 09APB1) MWD MWD - Standard 10,563.00 13,300.00 Plan #3 (Plan 3, E -09C) MWD MWD - Standard Casing Points Measured. Vertical Casing Hole Depth Depth gl peter Diary eter . n irf 2,675.71 2,675.61 13 3/8" 13.375 17.500 13,300.00 8,998.05 2 -3/8" 2.375 3.000 10,217.71 8,390.29 9 5/8" 9.625 12.250 CC - Min centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation 8/26/2009 4:52:50PM Page 2 of 33 COMPASS 2003.16 Build 71 . . S Travelling Cylinder Report 0 bP 1NTEQ Company, North America - ALASKA BP Local Co ordinate Reference Well E -09 - Slot 09 Project Prudhoe Bay TVO ffeferonce E -09A @ 65.01ft (E-09A Rig 65.01') Refer tce Site; PB E Pad MD Re erencei E -09A @ 65.01ft (E -09A Rig 65.01') Site Error' 0.00ft North Reference True Reference Wetl E-09 Survey Method: Minimum Curvature Welt Ert Ott 0.00ft Output errors a 9 at " 1. 00 sigma Reference Wellbore; Plan 3, E -09C Database: EDM .16- Anc Prod - WH24P Reference Design Plan #3 Offset VD Reference ; Offset Datum , .„ Reference Offset Centre to No4o pi awable Measured' .' Measured .::Centre Distance De+tttatlon Warning Site Name Depth Depth Distance {ft} #rom Plate Offset Well Weilbore Design .. : (ft1 tft) ; . :: { PBEPad E -01 - E -01 - E -01 Out of range E -01 - E -01A - E -01A Out of range E -01 - E -01A - Plan #7 Out of range E -01 - E- 01APB1 - E- 01APB1 Out of range E -03 - E -03 - E -03 Out of range E -03 - E -03A - E -03A Out of range E -03 - E -03A - Plan #14 Out of range E -05 - E -05A - E -05A 12,763.51 10,225.00 1,020.47 1,123.61 - 103.05 FAIL - Major Risk E -05 - E- 05APB1 - E- 05APB1 12,766.29 10,175.00 928.39 1,127.84 - 199.33 FAIL - Major Risk E -05 - E -05B - E -05B 12,075.00 11,300.00 949.36 1,077.49 - 117.42 FAIL - Major Risk E -07 - E -07 - E -07 Out of range E -07 - E -07A - E -07A Out of range E -07 - E -07A - Plan #103 Out of range E -07 - E- 07APB1 - E- 07APB1 Out of range E -07 - E- 07APB2 - E- 07APB2 Out of range E -08 - E -08 - E -08 Out of range E -08 - E -08A - E -08A Out of range E-08 - E -08A - Plan #7 Out of range E -09 - E -09 - E -09 10,706.77 10,700.00 5.18 19.96 -12.09 FAIL - Major Risk E-09 - E -09A - E -09A 10,649.91 10,650.00 1.34 8.52 -4.17 FAIL - Major Risk E -09 - E- 09APB1 - E- 09APB1 10,649.91 10,650.00 1.34 8.21 -3.87 FAIL - Major Risk E-09 - E -09B - E -09B 10,649.91 10,650.00 1.34 15.44 -6.70 FAIL - Major Risk E -100 -E-100 - E -100 Out of range E -102 - E -102 - E -102 Out of range E -102 - E -102 - E -102 wp07 Out of range E -104 - E -104 - E -104 Out of range E -104 - E -104 - E -104 wp02 Out of range E -11 -E-11 -E-11 Out of range E -11 - E -11A - E -11A Out of range E -11 - E- 11APB1 - E- 11APB1 Out of range E -11 -E-11B -E -11 B Out of range E -11 - E -11 BL1 - E -11 BL1 Out of range E -11 - E -11 BL1 -01 - Aaron's Plan 07 -04 -2007 Out of range E -11 - E -11 BL1 -01 - E -11 BL1 -01 Out of range E -11 - E -11 BL1 PB1 - E -11 BL1 PB1 Out of range E -11 - E-1 1 BL1 PB1 - Plan #7 Out of range E -11 - E -11 BL1 PB2 - E -11 BL1 PB2 Out of range E -34 - E -34 - E -34 Out of range E -34 - E -34L1 - E -34L1 Out of range E -38 - E -38 - E -38 Out of range E -38PB1 - E -38PB1 - E -38PB1 Out of range E -38PB2 - E -38PB2 - E -38PB2 Out of range CC - Min centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation 8/26/2009 4:52:50PM Page 3 of 33 COMPASS 2003.16 Build 71 ■ » . MINI • • Travelling Cylinder Report 0 bP iNTEQ Company . North America - ALASKA - BP Local Co- ordinate Reference Well E -09 - Slot 09 Project Prudhoe Bay :' Reference: E -09A © 65.01ft (E -09A Rig 65.01') Reference Site PB E Pad MD Referencet�" ; E -09A @ 65.01ft (E -09A Rig 65.01') __ Site: Error : 0.00ft North Reference . : True Reference Weil E -09 Survey Calculation Method ' Minimum Curvature Weli.l`rror l 0.00ft Output errors are at : 1.00 sigma Ej Refenr:er Wetlborei Plan 3, E -09C Database ' EDM .16 - Anc Prod WH24P Refer Deaigrt Plan #3 OffsetTND Reference: :. Offset Datum Summary Reference Offset Centre to No-Go Allowable ,Measured !. :Measured . Centre Distance Deviation Wanting Site Alan Depth Depth . . pistal�tce (ft} fr Plan Offset e1 lellbore Deslgn (ft 1ft1 Eft) (ft) PB K Pad K -06 - K -06B - K -06B 10,730.00 11,011.00 945.35 878.09 109.48 Pass - Major Risk K -09 - K -09B - K -09B Out of range K -09 - K- 09BPB1 - K- 09BPB1 Out of range K -09 - K -09C - K -09C Out of range K -09 - K -09C - Plan #4 Out of range K -10 - K -10 - K -10 11,625.00 9,450.00 1,218.60 961.70 315.83 Pass - Major Risk K -10 - K -10A - K -10A 11,560.05 10,150.00 1,342.60 1,070.33 284.69 Pass - Major Risk K -10 - K- 10APB1 - K- 10APB1 11,609.32 9,975.00 1,228.44 996.53 244.75 Pass - Major Risk K -10 - K- 10APB2 - K- 10APB2 11,625.00 10,050.00 1,146.67 971.59 190.57 Pass - Major Risk K -10 - K- 10APB3 - K- 10APB3 11,625.00 9,450.00 1,218.60 961.81 315.72 Pass - Major Risk K -10 - K -10B - K -10B 11,625.00 9,450.00 1,218.60 961.81 315.72 Pass - Major Risk K -12 - K -12A - K -12A 11,054.88 10,950.00 1,192.80 793.32 414.01 Pass - Major Risk K -19 - K -19 - K -19 11,189.23 10,375.00 886.21 909.81 -19.58 FAIL - Major Risk K -19 - K -19A - K -19A 12,416.31 11,575.00 115.78 931.58 - 782.74 FAIL - Major Risk K -19 - K -19AL1 - K -19AL1 11,090.80 10,200.00 477.21 839.28 - 360.53 FAIL - Major Risk CC - Min centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation 8/26/2009 4:52 :50PM Page 4 of 33 COMPASS 2003.16 Build 71 • Page 1 of 1 Schwartz, Guy L (DOA) From: Hinchman, Cody [Cody.Hinchman @bp.com] Sent: Thursday, September 03, 2009 12:53 PM To: Schwartz, Guy L (DOA) r Pry .20 _ Subject: RE: E -09B P & A (PTD 202 -161) 63 10, Guy, I would like to verify that the Whipstock/Packer combo will be pressure tested to 2000 psi in order to isolate the perfs, prior to the E -09C CTD sidetrack. The projected path of E -09C will have a close approach to the K -19A wellbore (119' Ctr — Ctr). The K -19A ellbore will cross the E -09 wellbore at a measured depth of 11,575' in K -19A. All perforations below 10,960' MD in well K -19A are currently isolated by a CIBP. Due to the CIBP the HSE risk of an intersection of the two wellbores is minimal. I apologize this was not mentioned in the P & A sundry request and that I was not able to answer your questions right away. This is my first well as a new challenger here and I am working under the guidance of Greg Sarber. Cody Hinchman CTD Drilling Engineer BPXA Office: 907 - 564 -4468 Cell: 303 -319 -5472 Cody. Hinchman @bp.com From: Schwartz, Guy L (DOA) E mailto:guy.schwartz @alaska.gov] Sent: Thursday, September 03, 2009 10:49 AM To: Hinchman, Cody Cc: Maunder, Thomas E (DOA) Subject: E -09B P & A (PTD 202 -161) Cody, I was reviewing the P & A sundry request for E -09B and see we are using a Whipstock/Packer combo to isolate the perfs and set up for the CTD sidetrack. You do not mention pressure testing the WS /packer in the procedure. Can you verify that this will be done and to what pressure ?? A state witnessed test won't be required assuming the packer /whipstock holds as the liner will be fully cemented above this anyway. Also, in reviewing the Anti - collision data I saw that K -19A wellbore comes very close (115' Ctr -Ctr) to the projected path of E -09C. Looking at the Traveling cylinder though it looks even closer.... 24 feet !!! Am I reading this correctly ? ?? Is this wellbore abandoned already ?? Any mitigation concerns? Thanks in advance, Guy Schwartz Senior Petroleum Engineer AOGCC 793 -1226 9/3/2009 Alaska Department of Natural sources Land Administration System • Page 1 of/ \Alaska Mapper Land Records /Status Plats Recorder's Search State Cabins Natural Resources Alaska DNR Case Summary File Type: ADL File Number: 28304 1 Printable Case File Summary See Township, Range, Section and Acreage? New Search IJ Yes Q No LAS Menu l Case Abstract 1 Case Detail 1 Land Abstract File: ADL 28304 Map for Status Plat Updates As of 09/02/2009 Customer: 000107377 BP EXPLORATION (ALASKA) INC PO BOX 196612/900 E. BENSON BL ATTN: LAND MANAGER - ALASKA ANCHORAGE AK 995196612 Case Type: 784 OIL & GAS LEASE COMP DNR Unit: 780 OIL AND GAS File Location: DOG DIV OIL AND GAS Case Status: 35 ISSUED Status Date: 09/14/1965 Total Acres: 2469.000 Date Initiated: 05/28/1965 Office of Primary Responsibility: DOG DIV OIL AND GAS Last Transaction Date: 12/04/2006 Case Subtype: NS NORTH SLOPE Last Transaction: AA -NRB ASSIGNMENT APPROVED Meridian: U Township: 011N Range: 014E Section: 05 Section Acres: 640 Search Plats Meridian: U Township: O11N Range: 014E Section: 06 Section Acres: 593 Meridian: U Township: 011N Range: 014E Section: 07 Section Acres: 596 Meridian: U Township: O11N Range: 014E Section: 08 Section Acres: 640 Legal Description 05 -28 -1965 ** *SALE NOTICE LEGAL DESCRIPTION * ** C14 -125 11N 14E UM 5, 6, 7, 8 2469.00 U- 3- 7 End of Case Summary Last updated on 09/02/2009. http: / /dnr.alaska.gov /projects /las /Case_Summary.cfm ?FileType= ADL &FileNumber = 28304... 9/2/2009 • • TRANSMITTAL LETTER CHECKLIST WELL NAME AlS'.1/ e PTD# 0209 ✓/ Development Service Exploratory Stratigraphic Test Non - Conventional Well FIELD: C/ i/DE Zrod9 y POOL: /'.G y O/ Circle Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK ADD -ONS (OPTIONS) WHAT TEXT FOR APPROVAL LETTER APPLIES MULTI LATERAL The permit is for a new wellbore segment of existing well (If last two digits in Permit No. , API No. 50- - - API number are between 60 -69) Production should continue to be reported as a function of the original API number stated above. PILOT HOLE In accordance with 20 AAC 25.005(0, all records, data and logs acquired for the pilot hole must be clearly differentiated in both well name ( PH) and API number (50- - - ) from records, data and logs acquired for well SPACING The permit is approved subject to full compliance with 20 AAC EXCEPTION 25.055. Approval to perforate and produce / inject is contingent upon issuance of a conservation order approving a spacing exception. assumes the liability of any protest to the spacing exception that may occur. DRY DITCH All dry ditch sample sets submitted to the Commission must be in SAMPLE no greater than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. Non - Conventional Please note the following special condition of this permit: Well production or production testing of coal bed methane is not allowed for (name of well) until after (Company Name) has designed and implemented a water well testing program to provide baseline data on water quality and quantity. (Company Name) must contact the Commission to obtain advance approval of such water well testing program. Rev: 1/11/2008 RMIT. ECKLIST & Pool PRUDHOE BAY, PRUDHOE OIL - 640150 Well Name: PRUDHOE BAY UNIT E-09C Program DEV Well bore seg ❑ PTD#: 2090950 Company BP EXPLORATION (ALASKA) INC Initial Class /Type DEV / PEND GeoArea 890 Unit 11650 On /Off Shore On Annular Disposal ❑ Administration 1 Permit fee attached NA 2 Lease number appropriate Yes 3 Unique well name and number - Yes - i4 Well located in .a defined _pool Yes i5 Well located proper distance from drilling unit boundary Yes 1 6 Well located proper distance from other wells Yes 7 Sufficient acreage available in drilling unit Yes - 2560 acres. ■ 8 If deviated, is wellbore plat included Yes - . �9 Operator only affected party Yes 10 Operator has appropriate_ bond in force Yes Blanket Bond # 6194.193. 11 Permit can be issued without conservation order Yes - Appr Date 12 Permit can be issued without administrative approval - _ - Yes ACS 9/2/2009 13 Can permit be approved before 15 -day wait - - - Yes 14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (For NA • 15 All wells within 1/4 mile area of review identified (For service well only) - - _ NA 16 Pre - produced injector; duration of pre production less than 3 months (For service well only) NA 17 Nonconven. gas conforms to AS31.05.030(j,1.A),(j,2.A -D) - - - - NA 18 Conductor string provided NA Conductor set in E -09B. (PTD 202 -161) Engineering 19 Surface casing protects all known USDWs NA Surface Casing set in E -09B 20 CMT vol adequate to circulate on conductor & surf csg - NA Surface Casing cemented in E -096 21 CMT vol adequate to tie -in long string to surf csg NA 7" liner set at 9717' - 22 CMT will coverall known productive horizons - Yes 2 3/8 Liner to befully cemented to hanger. 23 Casing designs adequate for C, T, B & permafrost Yes 24 Adequate tankage_or reserve pit - - Yes . - _ - Rig equipped with Steel pits. 25 If a re -drill, has a 10 -403 for abandonment been approved - - - - Yes - 309 -302 26 Adequate wellbore separation proposed Yes Proximity analysis performed, K -19A 119' away. 27 If diverter required, does it meet regulations NA Wellhead in place already. BOP stack installed. Appr Date 28 Drilling fluid program schematic & equip list adequate Yes Maximum fm pressure= 3027 psi (6.62 ppg) Planned MW = 8.6 ppg GLS 9/3/2009 29 BOPEs, do they meet regulation Yes 30 BOPE press rating appropriate; test to (put psig in comments) - - Yes MASP = 2147 psi BOP test planned at 3500 psi ill 31 Choke manifold complies w /API RP -53 (May 84) Yes 1 32 Work will occur without operation shutdown Yes - 33 Is presence of H2S gas probable Yes - - - - H2S presentonE pad . Rig has sensors and alarms. Mud should preclude H2S on rig. 34 Mechanical_condition of wells within AOR verified (For service well only) NA 35 Permit con be issued w/o hydrogen sulfide measures _ - No Max level H2S on Pad for well E -102 was 1.20ppm (9/16/08). Geology 36 Data presented on potential overpressure zones - NA Appr Date 37 Seismic analysis of shallow gas zones NA ACS 9/2/2009 38 Seabed condition survey (if off - shore) NA 39 Contact name /phone for weekly progress reports [exploratory only] No Geologic Engineering Commissioner: Date: Date e Commissioner: ��oner Dat 9.— ,......e, I , Well History File APPENDIX Information of detailed nature that is not particularly germane to the Well Permitting Process but is part of the history file. To improve the readability of the Well History file and to simplify finding information, information of this nature is accumulated at the end of the file under APPENDIX. No special effort has been made to chronologically organize this category of information. tapescan.txt * * ** REEL HEADER * * ** MWD 11 /01 /10 BHI 01 LIS Customer Format Tape * * ** TAPE HEADER * * ** MWD 09/11/18 2862351 01 2.375" CTK * ** LIS COMMENT RECORD * ** Remark File version 1.000 1111111,11111111111 Extract File: ldwg.las version Information VERS. 1.20: CWLS log ASCII Standard - VERSION 1.20 WRAP. NO: One line per frame well Information Block #MNEM.UNIT Data Type Information STRT.FT 10367.5000: Starting Depth STOP.FT 13207.5000: Ending Depth STEP.FT 0.5000: Level Spacing NULL. - 999.2500: Absent value COMP. COMPANY: BP Exploration (Alaska), Inc. WELL. WELL: E -09C FLD . FIELD: Prudhoe Bay Unit LOC . LOCATION: 70 deg 20' 34.706 "N 148 deg 39' 55.005 "W CNTY. COUNTY: North Slope Borough STAT. STATE: Alaska SRVC. SERVICE COMPANY: Baker Hughes INTEQ TOOL. TOOL NAME & TYPE: 2.375" CTK DATE. LOG DATE: 18 Nov 2009 API . API NUMBER: 500292046603 —Parameter Information Block #MNEM.UNIT value Description SECT. 06 Section TOWN.N T11N Township RANG. R14E Range PDAT. MSL Permanent Datum EPD .F 0 Elevation Of Perm. Datum LMF . DF Log Measured from FAPD.F 65.01 Feet Above Perm. Datum DMF . DF Drilling Measured From EKB .F 0 Elevation of Kelly Bushing EDF .F 65.01 Elevation of Derrick Floor EGL .F 0 Elevation of Ground Level Page 1 009 -095 Oda 4a- !II 411 tapescan.txt CASE.F N/A Casing Depth OS1 . DIRECTIONAL Other Services Line 1 —Remarks (1) All depths are Measured Depths (MD) unless otherwise noted. (2) All depths are Bit Depths unless otherwise noted. (3) All True vertical Depths (TVDss) are subsea corrected. (4) All Formation Evaluation data is realtime data. (5) Baker Hughes INTEQ utilized CoilTrak downhole tools and the Advantage surface system to log this well.. (6) Tools ran in the string included Casing Collar Locator, an Electrical Disconnect and Circulating Sub, a Drilling Performance Sub (Inner and Outer Downhole Pressure, vibration and Downhole weight on Bit), a Directional and Gamma sub, and a Hydraulic orienting Sub with a Near Bit Inclination Sensor. (7) Data presented here is final and has been depth adjusted to a Primary Depth Control (PDC) log provided by Schlumberger GR CNL dated 20 Nov 2009 per Doug Stoner with BP Exploration (Alaska), Inc. (8) The sidetrack was drilled from E - 09C through a milled window in a 4 1/2 inch liner. Top of window 10316 ft.MD (8635.2 ft.TVDSS) Bottom of window 10619 ft.MD (8639.7 ft.TVDSS) (9) Tied to E -09 at 10563 feet MD (8494.0 feet TVDSS). (10) The interval from 13177 ft to 13217 ft MD (8920.0 ft. to 8922.0 ft. TVDSS) was not logged due to sensor to bit offset at well TD. MNEMONICS: GRAX -> Gamma Ray [MWD] (MWD -API units) ROP AVG - Rate of Penetration, feet /hour RACLX -> Resistivity (AT)(LS)400kHz- Compensated Borehole Corrected (OHMM) RACHX -> Resistivity (AT)(LS)2MHz- Compensated Borehole Corrected (OHMM) RPCLX -> Resistivity (PD)(LS)400kHz- Compensated Borehole Corrected (OHMM) RPCHX -> Resistivity (PD)(LS)2MHz- Compensated Borehole Corrected (OHMM) TVDSS - True vertical Depth (Subsea) CURVE SHIFT DATA BASELINE, MEASURED, DISPLACEMENT 10373.1, 10377.8, ! 4.72168 10375.7, 10380.5, ! 4.7207 10380.3, 10384.4, ! 4.10449 10386.2, 10390.5, ! 4.31055 10397.1, 10402.4, ! 5.33691 10404.1, 10408.6, ! 4.51562 10407.6, 10412.5, ! 4.92578 10412.5, 10417.2, ! 4.7207 10415.4, 10420.3, ! 4.92676 10424.2, 10428.1, ! 3.90039 10426.6, 10430.5, ! 3.90039 10430.3, 10434.4, ! 4.10449 10611.5, 10611.1, ! - 0.411133 10615, 10615.4, ! 0.410156 10619.3, 10619.9, ! 0.615234 10621.8, 10621.5, ! - 0.205078 10625, 10625, ! 0 10632, 10631.8, ! - 0.205078 10639.4, 10638.2, ! - 1.23145 10642.1, 10641.5, ! - 0.616211 10654.4, 10653.8, ! - 0.615234 10664.2, 10661.8, ! - 2.46289 10668.1, 10665.4, ! - 2.66797 10674.1, 10672.8, ! - 1.23145 10675.9, 10675.7, ! - 0.205078 Page 2 • tapescan.txt 10681.7, 10680.8, ! - 0.820312 10686.8, 10686, ! - 0.821289 10694.6, 10695, ! 0.410156 10700.5, 10700.1, ! - 0.411133 10703, 10702.8, ! - 0.205078 10706.5, 10706.7, ! 0.205078 10709.5, 10709.1, ! - 0.411133 10714, 10713.4, ! - 0.616211 10719.1, 10719.3, ! 0.205078 10722.1, 10721.6, ! - 0.411133 10724.3, 10724.1, ! - 0.206055 10726, 10726.4, ! 0.410156 10729, 10730.5, . 1.43652 10734.6, 10735.2, ! 0.615234 10739.1, 10739.5, ! 0.411133 10746.9, 10746.5, ! - 0.410156 10751.2, 10750.8, ! - 0.410156 10755.3, 10755.1, ! - 0.206055 10758, 10756.9, ! - 1.02637 10767.4, 10766.2, ! - 1.23145 10769.3, 10768.6, ! - 0.616211 10772.1, 10771.7, ! - 0.410156 10775.8, 10775.6, ! - 0.206055 10779.3, 10779.9, ! 0.615234 10789.5, 10789.1, ! - 0.411133 10791.1, 10791.3, ! 0.205078 10795.7, 10795.4, ! - 0.205078 10802, 10802, ! 0 10813.1, 10812.5, ! - 0.615234 10833.2, 10834.1, ! 0.821289 10838, 10838.8, ! 0.821289 10845.2, 10844.9, ! - 0.205078 10852.7, 10850.5, ! - 2.25781 10858.9, 10856.4, ! - 2.46289 10860, 10859.2, ! - 0.821289 10867.6, 10867.2, ! - 0.410156 10873.5, 10873.3, ! - 0.206055 10875.4, 10875.4, ! 0 10878.9, 10879.1, ! 0.205078 10881.5, 10880.9, ! - 0.616211 10883.4, 10884, ! 0.616211 10888.1, 10888.1, ! 0 10897.6, 10896.9, ! - 0.616211 10901.5, 10901.3, ! - 0.205078 10903.9, 10903.5, ! - 0.410156 10906.6, 10907.2, ! 0.615234 10909.4, 10909.6, ! 0.205078 10915.6, 10914.4, ! - 1.23145 10920.9, 10918.9, ! - 2.05273 10923.6, 10922.8, ! - 0.820312 10927.7, 10926.3, ! - 1.43652 10934.5, 10933, ! - 1.43652 10937.6, 10937.4, ! - 0.206055 10944.7, 10944.9, ! 0.205078 10947.2, 10947.4, ! 0.205078 10959.3, 10957.7, ! - 1.64258 10981, 10978.7, ! - 2.25781 10998.8, 10998.2, ! - 0.616211 11004.8, 11005.9, ! 1.02539 11014.5, 11015.9, ! 1.43652 11018, 11020.3, ! 2.25781 11022.9, 11024, ! 1.02637 11034, 11032.4, ! - 1.64258 Page 3 • tapescan.txt 11037.1, 11036.5, ! - 0.615234 11041.8, 11041.4, ! - 0.411133 11046.7, 11046.7, ! 0 11054.7, 11056.4, ! 1.6416 11068, 11065.8, ! - 2.25781 11077.9, 11075.8, ! - 2.05176 11082, 11079.1, ! - 2.87305 11087.6, 11084.7, ! - 2.87305 11105.7, 11104.6, ! - 1.02637 11110.2, 11109.1, ! - 1.02637 11121.9, 11119.4, ! - 2.46289 11127.4, 11124.3, ! - 3.07812 11134.2, 11133, ! - 1.23145 11138.5, 11137.5, ! - 1.02637 11147.1, 11146.3, ! - 0.820312 11157.8, 11155.9, ! - 1.84766 11167.7, 11165.4, ! - 2.25781 11178, 11174.9, ! - 3.0791 11186.2, 11183.1, ! - 3.07812 11189.9, 11188.2, ! - 1.6416 11199.8, 11197.9, ! - 1.84766 11231.4, 11232.6, ! 1.23145 11254.2, 11251.9, ! - 2.25781 11256, 11254, ! - 2.05273 11260.8, 11260.3, ! - 0.410156 11288.5, 11287.9, ! - 0.616211 11295.7, 11294.4, ! - 1.23145 11321, 11321.2, ! 0.205078 11331.3, 11331.7, ! 0.410156 11344.2, 11344.2, ! 0 11349.1, 11348.5, ! - 0.615234 11355.2, 11354.2, ! - 1.02637 11371.9, 11370.2, ! - 1.6416 11378.6, 11376.4, ! - 2.25781 11382.4, 11382.2, ! - 0.205078 11392.9, 11389.8, ! - 3.0791 11399.3, 11395.8, ! - 3.48926 11437.9, 11434.2, ! - 3.69531 11537, 11534.8, ! - 2.25781 11586.9, 11581.5, ! - 5.33594 11597.1, 11590, ! - 7.18359 11601.7, 11596.5, ! - 5.13086 11625.4, 11618.7, ! - 6.77344 11632.6, 11625.9, ! - 6.77344 11636.9, 11629.8, ! - 7.18359 11641.7, 11638, ! - 3.69434 11647.6, 11643.9, ! - 3.69434 11657.3, 11652.8, ! - 4.51562 11665.3, 11659.8, ! - 5.54102 11683.5, 11681.2, ! - 2.25781 11705.9, 11702.8, ! - 3.07812 11724.3, 11722.3, ! - 2.05273 11729.7, 11727, ! - 2.66797 11734.4, 11730.5, ! - 3.89941 11748.5, 11746.4, ! - 2.05273 11765.7, 11763.9, ! - 1.84766 11768.6, 11766.6, ! - 2.05176 11782.4, 11779.1, ! - 3.28418 11799.5, 11795.8, ! - 3.69434 11801, 11797.5, ! - 3.48926 11812.3, 11809.6, ! - 2.66797 11817.2, 11814.3, ! - 2.87305 11834.5, 11833.5, ! - 1.02637 Page 4 • tapescan.txt 11859.7, 11856, ! - 3.69434 11864, 11860.8, ! - 3.28418 11887.4, 11884.7, ! - 2.66797 11896, 11893.3, ! - 2.66797 11953.5, 11948.5, ! - 4.92578 12004.6, 12000.1, ! - 4.51465 12008.9, 12004.4, ! - 4.51562 12015.7, 12011.6, ! - 4.10547 12030.3, 12025.6, ! - 4.7207 12046.8, 12040.2, ! - 6.56836 12052.7, 12045.7, ! - 6.97852 12058, 12051.1, ! - 6.97852 12061.1, 12053.5, ! - 7.59375 12068.5, 12061.1, ! - 7.38965 12078.4, 12071, ! - 7.38867 12079.8, 12072.9, ! - 6.97949 12085.4, 12076.8, ! - 8.62012 12087.8, 12080, ! - 7.7998 12091.9, 12084.6, ! - 7.38867 12097.1, 12089.9, ! - 7.18359 12103.9, 12096.3, ! - 7.59375 12108.2, 12101.2, ! - 6.97852 12118, 12110.7, ! - 7.38965 12127.3, 12120.7, ! - 6.56836 12130.6, 12124.4, ! - 6.1582 12140.5, 12134.7, ! - 5.74707 12145, 12138.6, ! - 6.36328 12155.4, 12149.3, ! - 6.15723 12164.9, 12160.5, ! - 4.30957 12193.4, 12188, ! - 5.33594 12219, 12213, ! - 5.95215 12233.1, 12229, ! - 4.10449 12240.1, 12235.8, ! - 4.31055 12283.1, 12278.5, ! - 4.51562 12292.3, 12287.2, ! - 5.13184 12306.3, 12301.5, ! - 4.7207 12317.6, 12313.3, ! - 4.31055 12323.9, 12318.8, ! - 5.13086 12336.3, 12329.7, ! - 6.56836 12342.8, 12336.1, ! - 6.77344 12347.5, 12342.2, ! - 5.33691 12358.4, 12351.4, ! - 6.97852 12362.9, 12355.7, ! - 7.18359 12378.3, 12370.3, ! - 8.00488 12380.8, 12372.4, ! - 8.41602 12395.6, 12386.8, ! - 8.82617 12412.4, 12406.1, ! - 6.3623 12419, 12411.8, ! - 7.18359 12435.8, 12427.4, ! - 8.41504 12458.2, 12449.2, ! - 9.03125 12465.8, 12457.4, ! - 8.41602 12477.9, 12468.1, ! - 9.85254 12487.4, 12476.9, ! - 10.4678 12488.8, 12479.2, ! - 9.64746 12504.8, 12498, ! - 6.77344 12530.7, 12523.9, ! - 6.77344 12540.1, 12532.9, ! - 7.18457 12549.1, 12542.8, ! - 6.3623 12558.3, 12551.1, ! - 7.18359 12564.4, 12557.8, ! - 6.56738 12572.7, 12568.6, ! - 4.10547 12576.4, 12572.1, ! - 4.31055 12588.1, 12583.4, ! - 4.72168 Page 5 • • tapescan.txt 12591.2, 12586.7, ! - 4.51562 12610.9, 12605.6, ! - 5.33594 12623.4, 12617.7, ! - 5.74707 12639.4, 12633.2, ! - 6.15723 12659.4, 12652.8, ! - 6.56738 12664.9, 12659.2, ! - 5.74707 12671.1, 12667, ! - 4.10547 12677.6, 12672.9, ! - 4.7207 12685.2, 12679.5, ! - 5.74707 12694.9, 12687.9, ! - 6.97852 12700, 12694.7, ! - 5.33691 12704.4, 12698.8, ! - 5.54102 12709.9, 12705, ! - 4.92578 12718.1, 12713.4, ! - 4.72168 12724.1, 12718.9, ! - 5.13184 12729.2, 12725.5, ! - 3.69434 12736.2, 12733.3, ! - 2.87305 12741.3, 12738, ! - 3.28418 12744.8, 12740.9, ! - 3.90039 12748.1, 12744.8, ! - 3.28418 12758.2, 12754.7, ! - 3.48926 12765.9, 12763.3, ! - 2.66797 12792.9, 12788.4, ! - 4.51562 12810, 12802.8, ! - 7.18457 12821.7, 12814.5, ! - 7.18359 12840.5, 12831.9, ! - 8.62109 12856.2, 12848.4, ! - 7.7998 12861.9, 12853.9, ! - 8.00488 12864.9, 12857.5, ! - 7.38867 12870, 12863.2, ! - 6.77344 12875.1, 12869, ! - 6.15723 12879.2, 12874.1, ! - 5.13184 12884.6, 12878.2, ! - 6.36328 12888.5, 12881.9, ! - 6.56836 12891.9, 12885, ! - 6.97852 12897.1, 12890.5, ! - 6.56836 12906.9, 12901.6, ! - 5.33594 12918.6, 12910.6, ! - 8.00488 12930.3, 12922.5, ! - 7.7998 12934.4, 12926.6, ! - 7.7998 12946.5, 12937.7, ! - 8.82617 12955.1, 12947.3, ! - 7.79883 12959.3, 12950.9, ! - 8.41602 12996.8, 12987.9, ! - 8.82617 13000.7, 12992, ! - 8.62012 13018.1, 13009.7, ! - 8.41602 13024.7, 13015.4, ! - 9.23633 13028.8, 13019.3, ! - 9.44141 13038, 13027.2, ! - 10.8789 13052.6, 13042.2, ! - 10.4678 13054.9, 13044.8, ! - 10.0566 13058.8, 13050, ! - 8.82617 13098.3, 13086.8, ! - 11.4941 13107.3, 13097, ! - 10.2627 13110.2, 13099.9, ! - 10.2627 13117.5, 13109.9, ! - 7.59473 13124.3, 13115.3, ! - 9.03125 13126.3, 13117.5, ! - 8.8252 13128.6, 13119.6, ! - 9.03027 13132.5, 13123.3, ! - 9.23633 13138.3, 13129.2, ! - 9.03125 13147.9, 13137.8, ! - 10.0576 13153.6, 13142.3, ! - 11.2891 Page 6 • • tapescan.txt 13164.3, 13152.4, ! - 11.9053 13171.3, 13159.6, ! - 11.6992 EOZ END ! BASE CURVE: GROH, OFFSET CURVE: GRAX Tape subfile: 1 353 records... Minimum record length: 10 bytes Maximum record length: 132 bytes * * ** FILE HEADER * * ** MWD .001 1024 * ** LIS COMMENT RECORD * ** IIMMMMIIIIIIIIIIMMI Remark File Version 1.000 The data presented here is final and has been depth adjusted to a Primary Depth Control (PDC) log provided by Schlumberger GR CNL dated 20 Nov 2009 per Doug Stoner with BP Exploration (Alaska), Inc. * FORMAT RECORD (TYPE# 64) Data record type is: 0 Datum Frame Size is: 28 bytes Logging direction is down (value= 255) Optical Log Depth Scale Units: Feet Frame spacing: 0.500000 Frame spacing units: [F ] Number of frames per record is: 36 One depth per frame (value= 0) Datum specification Block Sub -type is: 1 FRAME SPACE = 0.500 * F ONE DEPTH PER FRAME Tape depth ID: F 6 Curves: Name Tool Code Samples Units size Length 1 GR MWD 68 1 AAPI 4 4 2 ROP MWD 68 1 F /HR 4 4 3 RAD MWD 68 1 OHMM 4 4 4 RAS MWD 68 1 OHMM 4 4 5 RPD MWD 68 1 OHMM 4 4 6 RPS MWD 68 1 OHMM 4 4 24 Page 7 • • tapescan.txt Total Data Records: 158 Tape File start Depth = 10367.500000 Tape File End Depth = 13207.500000 Tape File Level Spacing = 0.500000 Tape File Depth Units = feet * * ** FILE TRAILER * * ** Tape subfile: 2 171 records... Minimum record length: 54 bytes Maximum record length: 4124 bytes * * ** FILE HEADER * * ** MWD .002 1024 * ** LIS COMMENT RECORD * ** 111 1 1 111 1111111 Remark File version 1.000 This file contains the raw - unedited field MWD data. * FORMAT RECORD (TYPE# 64) Data record type is: 0 Datum Frame size is: 28 bytes Logging direction is down (value= 255) Optical Log Depth Scale units: Feet Frame spacing: 0.250000 Frame spacing units: [F ] Number of frames per record is: 36 one depth per frame (value= 0) Datum Specification Block Sub -type is: 1 FRAME SPACE = 0.250 * F ONE DEPTH PER FRAME Tape depth ID: F 6 Curves: Name Tool Code samples units Size Length 1 GR MWD 68 1 AAPI 4 4 2 ROP MWD 68 1 F /HR 4 4 3 RAD MWD 68 1 OHMM 4 4 4 RAS MWD 68 1 OHMM 4 4 5 RPD MWD 68 1 OHMM 4 4 6 RPS MWD 68 1 OHMM 4 4 24 Page 8 i i tapescan.txt Total Data Records: 318 Tape File Start Depth = 10363.000000 Tape File End Depth = 13218.750000 Tape File Level spacing = 0.250000 Tape File Depth units = feet * * ** FILE TRAILER * * ** Tape Subfile: 3 331 records... Minimum record length: 54 bytes Maximum record length: 4124 bytes * * ** TAPE TRAILER * * ** MWD 09/11/18 2862351 01 * * ** REEL TRAILER * * ** MWD 11/01/10 BHI 01 Tape subfile: 4 2 records... Minimum record length: 132 bytes Maximum record length: 132 bytes 0 Tape Subfile 1 is type: LIS 0 Tape Subfile 2 is type: LIS DEPTH GR ROP RAD RAS RPD RPS 10367.5000 - 999.2500 - 999.2500 - 999.2500 - 999.2500 - 999.2500 - 999.2500 10368.0000 - 999.2500 - 999.2500 - 999.2500 - 999.2500 - 999.2500 - 999.2500 13207.5000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 Page 9 . 4 tapescan.txt Tape File Start Depth = 10367.500000 Tape File End Depth = 13207.500000 Tape File Level Spacing = 0.500000 Tape File Depth units = feet 0 Tape Subfile 3 is type: LIS DEPTH GR ROP RAD RAS RPD RPS 10363.0000 - 999.2500 - 999.2500 - 999.2500 - 999.2500 - 999.2500 - 999.2500 10363.2500 - 999.2500 - 999.2500 - 999.2500 - 999.2500 - 999.2500 - 999.2500 13218.7500 - 999.2500 - 999.2500 - 999.2500 - 999.2500 - 999.2500 - 999.2500 Tape File start Depth = 10363.000000 Tape File End Depth = 13218.750000 Tape File Level Spacing = 0.250000 Tape File Depth units = feet 0 Tape Subfile 4 is type: LIS Page 10