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Home My WebLink About220-0661 Regg, James B (OGC) From:Brooks, Phoebe L (OGC) Sent:Wednesday, March 1, 2023 12:20 PM To:Alaska NS - ASR - Well Site Managers Cc:Regg, James B (OGC) Subject:RE: Weekly BOP test ASR MPU F-62 A Attachments:Hilcorp ASR 1 01-31-23.xlsx Attached is a revised report changing the report date to 1/31/23 (the day the test ended). Please update your copy. Thanks, Phoebe Phoebe Brooks Research Analyst Alaska Oil and Gas Conservation Commission Phone: 907‐793‐1242 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Phoebe Brooks at 907-793-1242 or phoebe.brooks@alaska.gov. From: Alaska NS ‐ ASR ‐ Well Site Managers <AlaskaNS‐ASRWellSiteManagers@hilcorp.com> Sent: Wednesday, February 1, 2023 6:30 AM To: Regg, James B (OGC) <jim.regg@alaska.gov>; DOA AOGCC Prudhoe Bay <doa.aogcc.prudhoe.bay@alaska.gov>; Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov> Subject: Weekly BOP test ASR MPU F‐62 A Thank you ASR DSM’s Hilcorp DSM: 907‐685‐1266 Hilcorp Alaska, LLC 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: 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. Milne Point Unit F-62APTD 2200660 STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION *All BOPE reports are due to the agency within 5 days of testing* Submit to:jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov Rig Owner:Rig No.:ASR 1 DATE:1/31/23 Rig Rep.:Rig Email: Operator: Operator Rep.:Op. Rep Email: Well Name:PTD #2200660 Sundry #322-682 Operation:Drilling:Workover:x Explor.: Test:Initial:Weekly:x Bi-Weekly:Other: Rams:250/3000 Annular:250/3000 Valves:250/3000 MASP:2569 MISC. INSPECTIONS:TEST DATA FLOOR SAFETY VALVES: Test Result/Type Test Result Quantity Test Result Housekeeping P Well Sign P Upper Kelly 1 P Permit On Location P Hazard Sec.P Lower Kelly 0 NA Standing Order Posted P Misc.NA Ball Type 1 P Test Fluid Water Inside BOP 1 P FSV Misc 0 NA BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm Stripper 0 NA Trip Tank NA NA Annular Preventer 1 11"P Pit Level Indicators P P #1 Rams 1 2 7/8" x 5"P Flow Indicator P P #2 Rams 1 Blinds P Meth Gas Detector P P #3 Rams 0 NA H2S Gas Detector P P #4 Rams 0 NA MS Misc 0 NA #5 Rams 0 NA #6 Rams 0 NA ACCUMULATOR SYSTEM: Choke Ln. Valves 1 2 1/16"P Time/Pressure Test Result HCR Valves 1 2 1/16"P System Pressure (psi)3000 P Kill Line Valves 2 2 1/16"P Pressure After Closure (psi)1750 P Check Valve 0 NA 200 psi Attained (sec)16 P BOP Misc 0 NA Full Pressure Attained (sec)60 P Blind Switch Covers:All stations Yes CHOKE MANIFOLD:Bottle Precharge:P Quantity Test Result Nitgn. Bottles # & psi (Avg.):4 / 2225 PSI P No. Valves 16 P ACC Misc 0 NA Manual Chokes 1 P Hydraulic Chokes 1 P Control System Response Time:Time (sec)Test Result CH Misc 0 NA Annular Preventer 14 P #1 Rams 7 P Coiled Tubing Only:#2 Rams 6 P Inside Reel valves 0 NA #3 Rams 0 NA #4 Rams 0 NA Test Results #5 Rams 0 NA #6 Rams 0 NA Number of Failures:0 Test Time:4.0 HCR Choke 2 P Repair or replacement of equipment will be made within days. HCR Kill 0 NA Remarks: AOGCC Inspection 24 hr Notice Yes Date/Time 1/29/23 05:58 Waived By Test Start Date/Time:1/31/2023 13:45 (date)(time)Witness Test Finish Date/Time:1/31/2023 17:45 BOPE Test Report Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Brian Bixby Hilcorp Tests preformed w/ 2-7/8" test joint on annular and VBRs 3.5" test joint on VBRs. Precharge on all bottles 1000psi. M. Boord / C. Pace Hilcorp Alaska LLC S.Hiem/ S. Menapace MPU F-62A Test Pressure (psi): askans-asr-toolpushers@hilcorp.co ans-asrwellsitemanagers@hilcorp Form 10-424 (Revised 08/2022)2023-0131_BOP_Hilcorp_ASR1_MPU_F-62A         J. Regg; 5/31/2023 1 Regg, James B (OGC) From:Brooks, Phoebe L (OGC) Sent:Monday, February 27, 2023 9:54 AM To:Alaska NS - ASR - Well Site Managers Cc:Regg, James B (OGC) Subject:RE: F-62A weekly BOPE test Attachments:Hilcorp ASR 1 01-23-23.xlsx Attached is a revised report changing the report date to the last day of testing (01/23/23). Please update your copy. Thank you, Phoebe Phoebe Brooks Research Analyst Alaska Oil and Gas Conservation Commission Phone: 907‐793‐1242 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Phoebe Brooks at 907-793-1242 or phoebe.brooks@alaska.gov. From: Alaska NS ‐ ASR ‐ Well Site Managers <AlaskaNS‐ASRWellSiteManagers@hilcorp.com> Sent: Wednesday, January 25, 2023 8:20 PM To: Regg, James B (OGC) <jim.regg@alaska.gov>; DOA AOGCC Prudhoe Bay <doa.aogcc.prudhoe.bay@alaska.gov>; Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov> Subject: F‐62A weekly BOPE test Thank you, Regards ASR DSM’s Hilcorp DSM: 907‐685‐1266 Hilcorp Alaska, LLC 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: 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. Milne Point Unit F-62APTD 2200660 STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION *All BOPE reports are due to the agency within 5 days of testing* Submit to:jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov Rig Owner:Rig No.:ASR 1 DATE:1/23/23 Rig Rep.:Rig Email: Operator: Operator Rep.:Op. Rep Email: Well Name:PTD #2200660 Sundry #322-682 Operation:Drilling:Workover:x Explor.: Test:Initial:Weekly:x Bi-Weekly:Other: Rams:250/3000 Annular:250/3000 Valves:250/3000 MASP:2569 MISC. INSPECTIONS:TEST DATA FLOOR SAFETY VALVES: Test Result/Type Test Result Quantity Test Result Housekeeping P Well Sign P Upper Kelly 1 P Permit On Location P Hazard Sec.P Lower Kelly 0 NA Standing Order Posted P Misc.NA Ball Type 1 P Test Fluid Water Inside BOP 1 P FSV Misc 0 NA BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm Stripper 0 NA Trip Tank NA NA Annular Preventer 1 11"FP Pit Level Indicators P P #1 Rams 1 2 7/8" x 5"P Flow Indicator P P #2 Rams 1 Blinds P Meth Gas Detector P P #3 Rams 0 NA H2S Gas Detector P P #4 Rams 0 NA MS Misc 0 NA #5 Rams 0 NA #6 Rams 0 NA ACCUMULATOR SYSTEM: Choke Ln. Valves 1 2 1/16"P Time/Pressure Test Result HCR Valves 1 2 1/16"P System Pressure (psi)3000 P Kill Line Valves 2 2 1/16"P Pressure After Closure (psi)1750 P Check Valve 0 NA 200 psi Attained (sec)10 P BOP Misc 0 NA Full Pressure Attained (sec)59 P Blind Switch Covers:All stations Yes CHOKE MANIFOLD:Bottle Precharge:P Quantity Test Result Nitgn. Bottles # & psi (Avg.):4 / 2212 PSI P No. Valves 16 P ACC Misc 0 NA Manual Chokes 1 P Hydraulic Chokes 1 P Control System Response Time:Time (sec)Test Result CH Misc 0 NA Annular Preventer 14 P #1 Rams 6 P Coiled Tubing Only:#2 Rams 5 P Inside Reel valves 0 NA #3 Rams 0 NA #4 Rams 0 NA Test Results #5 Rams 0 NA #6 Rams 0 NA Number of Failures:1 Test Time:13.0 HCR Choke 2 P Repair or replacement of equipment will be made within days. HCR Kill 0 NA Remarks: AOGCC Inspection 24 hr Notice Yes Date/Time 1/21/23 21:18 Waived By Test Start Date/Time:1/23/2023 9:30 (date)(time)Witness Test Finish Date/Time:1/23/2023 22:30 BOPE Test Report Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Austin McLeod Hilcorp Tests preformed w/ 2-7/8" & 3-1/2" test joints. Annular would not hold pressue. Change out annular rubber. test good Precharge on all bottles 1000psi. M.Boord / C. Greub Hilcorp Alaska LLC S.Hiem/ S. Menapace MPU F-62A Test Pressure (psi): askans-asr-toolpushers@hilcorp.co ans-asrwellsitemanagers@hilcorp Form 10-424 (Revised 08/2022)2023-0123_BOP_Hilcorp_ASR1_MPU-F-62A       J. Regg; 5/31/2023 1 Regg, James B (OGC) From:Brooks, Phoebe L (OGC) Sent:Wednesday, February 15, 2023 3:15 PM To:Russell Gallen - (C) Cc:Regg, James B (OGC) Subject:RE: F-62A weekly BOPE test Attachments:Hilcorp ASR 1 01-16-23.xlsx Russell, I changed the report date to reflect 1/16/23 (the end date of the test). Please update your copy. Thank you, Phoebe Phoebe Brooks Research Analyst Alaska Oil and Gas Conservation Commission Phone: 907‐793‐1242 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Phoebe Brooks at 907-793-1242 or phoebe.brooks@alaska.gov. From: Russell Gallen ‐ (C) <Russell.Gallen@hilcorp.com> Sent: Wednesday, January 18, 2023 2:27 AM To: Regg, James B (OGC) <jim.regg@alaska.gov>; DOA AOGCC Prudhoe Bay <doa.aogcc.prudhoe.bay@alaska.gov>; Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov> Cc: Alaska NS ‐ ASR ‐ Well Site Managers <AlaskaNS‐ASRWellSiteManagers@hilcorp.com> Subject: F‐62A weekly BOPE test Thank you, Regards, Russell Gallen ASR DSM, Mobile: 907-529-7202 Office: 907-685-1266 russell.gallen@hilcorp.com 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. Milne Point Unit F-62APTD 2200660 1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: ESP Swap Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number): 8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 10,112 feet N/A feet true vertical 7,445 feet N/A feet Effective Depth measured 10,010 feet 2,530 & 9,622 feet true vertical 7,350 feet 2,509 & 7,199 feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet 2-7/8"6.4 / L-80 / EUE 8rd 9,568' 6,939' Tubing (size, grade, measured and true vertical depth)4-1/2"13.5 / L-80 / Hyd 625 9,740' 7,099' Tri-Point&" x 2-7/8" Packers and SSSV (type, measured and true vertical depth)Kaer Premier N/A See Above N/A 12. Stimulation or cement squeeze summary: N/A Intervals treated (measured): Treatment descriptions including volumes used and final pressure: N/A 13a. Prior to well operation: Subsequent to operation: 13b. Pools active after work: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Authorized Name and Digital Signature with Date: Contact Name: Contact Email: Authorized Title: Operations Manager Contact Phone: 5,750psi 7,240psi10,093' 7,428' Burst N/A Collapse N/A 3,090psi 5,410psi Casing Conductor 10,093' 5,942'Surface Production 20" 9-5/8" 7" 112' 5,942' measured TVD STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 220-066 50-029-22609-01-00 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 3. Address: Hilcorp Alaska LLC N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: ADL025509 & ADL355018 Milne Point Unit / Kuparuk Oil Pool MP F-62A Plugs Junk measured Length measured true vertical Packer Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 293 Gas-Mcf MD 112' 0 Size 112' 4,484' 356 200162 0 00 352 322-682 Sr Pet Eng: Sr Pet Geo: Sr Res Eng: WINJ WAG 0 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. N/A Taylor Wellman twellman@hilcorp.com 907-777-8449 Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov By Samantha Carlisle at 10:19 am, Feb 15, 2023 Digitally signed by David Haakinson (3533) DN: cn=David Haakinson (3533), ou=Users Date: 2023.02.15 07:00:43 -09'00' David Haakinson (3533) RBDMS JSB 022123 MP F-62A Sundry Number WCB 1-13-2025 Milne Point Unit / Kuparuk Oil Pool ESP Swap 220-066 Pull Tubing 322-682 DSR-2/15/23 _____________________________________________________________________________________ Revised By: TDF 2/13/2023 SCHEMATIC Milne Point Unit Well: MPU F-62A Last Completed: 2/5/2023 PTD: 220-066 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20" Conductor 91.1 / NT80LHE / N/A N/A Surface 112’ 9-5/8" Surface 40 / L-80 / BTC 8.835 Surface 5,942’ 7" Production 26 / L-80 / BTC 6.276 Surface 10,093’ TUBING DETAIL 2-7/8” Tubing 6.4 / L-80 / EUE 8rd 2.441 Surface 9,568’ 4-1/2" Tubing 13.5 / L-80 / Hyd 625 3.920 9,605’ 9,740’ JEWELRY DETAIL No Depth Item 1 233’ Sta 2: GLM 2.875 x 1" w/ 0.25 OV 2 2,521’ Tubing Joint w/ Slim Hole Collar 3 2,530’ Tri-point 7"x 2-7/8" Ret. packer with vent valve 4 9,290’ Sta 1: GLM 2-7/8” x 1" w/ Dummy Valve 5 9,412’ 2-7/8” XN- Nipple: 2.205" ID no go RHC installed 6 9,455’ Ported Sub & Discharge Head: 7 9,456’ Pump #4: 400 PMSXD 098 FLEX17 H6 FER STF PN 8 9,474’ Pump #3: 400 PMSXD 134 FLEXER HF H6 FE 9 9,497’ Pump #2: 400 PMSXD 134 FLEXER HF H6 FE 10 9,521’ Pump #1: 400 PMSXD 024 GINPHL HS 41655 HB 11 9,531’ Intake & Gas Separator: 538 GM2T and Adapter 12 9,537’ UT Seal: GSB3DB FER HL SSCV H6 SB/SB CL-5E 13 9,544’ LT Seal : GSB3DB FER HL SSCV H6 SB/SB CL-5E 14 9,551’ Motor: 562 XP S CS 175/3180/34 Q7R FER 15 9,563’ Zenith Sensor w/ Centralizer – Btm @ 9,568’ 16 9,622’ Baker Premier Retrievable Packer 17 9,688’ 4-1/2” XN-Nipple (3.725” No-Go) 18 9,739’’ Mule Shoe – Btm at 9,740’ PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status Kuparuk C/B7 9,790’ 9,816’ 7,146’ 7,170’ 26 12-8-2020 OPEN Kuparuk B Silts 9,823’ 9,833' 7,175' 7,185' 10 1/15/2022 OPEN Kuparuk A2 9,879’ 9,889’ 7,228’ 7,237’ 10 11/19/2020 OPEN Kuparuk A1B 9,922’ 9,951’ 7,268’ 7,295’ 29 1/15/2022 OPEN Ref Log; 10/7/95 SBT / GR / CCL. 32 gm Alpha Jet charges (EHD-0.50”, TTP=32.0”) @ 135 / 45 deg. phasing OPEN HOLE / CEMENT DETAIL 20" 260 sx of Arcticset (Approx.) in 24” Hole 9-5/8" 1,160 sx PF “C”, 250 sx Class “G”, 250 sx PF ‘E in 12-1/4” Hole 7” 265 sx Class “G” 15.8 ppg in 8-1/2” Hole WELL INCLINATION DETAIL KOP @ 1,000 Max Hole Angle = 66 deg. Hole Angle through perforations = 42 deg. TREE & WELLHEAD Tree 4-1/16” – 5M Cameron NS Wellhead FMC 11” 5M FMC Gen 5 w/ 11” FMC Tubing Hanger, 3.5” NSCT Lift Threads and 3” CIW H BPV Profile Tubing Hanger 4-1/2” GENERAL WELL INFO API: 50-029-22609-01-00 Completed: 11/20/2020 – Doyon 14 Convert to ESP 1/24/2022 - ASR TD =10,112’ (MD) / TD = 7,445’(TVD) 20” Orig.DF Elev.: 45.70’/ GL Elev.: 12.0’ Nabors 22E 7” 5 9 12 13 16 9-5/8” 1 3 15 PBTD =10,010’ (MD) / PBTD = 7,350’(TVD) 4 10 & 11 Top of Tubing 9,605’MD 6, 7 & 8 14 2 Well Name Rig API Number Well Permit Number Start Date End Date MP F-62A ASR#1 50-029-22609-01-00 220-066 1/5/2023 2/5/2023 1/6/2022 - Friday Hook up kill & choke lines. Torque all connections on BOPE. Continue to offload trucks of rig equipment. Mobilize & spot in. Pusher trailer, Ops trailer & crew shack. Hook accumulator hoses to accumulator unit & pressured up. Small leak noticed at hinge pin, Continue rig up as yellow jacket repaired. Continue level rig prep to raise derrick. Adjust outriggers Purge air from system, Rig level. Raise derrick, knife up. Secure guy lines. Install Rack pins, Tongs & rack. Fill pit 4 w/ fresh water for testing. Discovered coolant leak on fitting, shut down rig engine for repair. Able to continue operations of winterization, Check IA slight pressure build, open to tiger tank. No fluid, pressure zero. Rig back in operation, completed tong rig up. Simops: Complete pump line tracing with heated glycol. Service rig, conduct fluid level checks. Install flow spool to stack, add additional spool. Bolt up & TQ. Install cellar drip pan to stack. Greased stack valves. Rig up stairs, and set up containment for catwalk. Simops: spot in ESP spooling for well work. Attack flow line to pits. Function test BOPE. Temperature check lines prep for testing . Kill line manual valve "inner" found to be free spinning. Prep for valve replacement. Replace kill line valve. Re-install kill line hose. Simops: Spot in cat walk. 1/4/2022 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary No operations to report. 1/5/2022 - Thursday Install carriage and tool carrier on to rig. Change out hydraulic jacks on rig. hook up all lines from tool carrier to carriage. install remote base system in PLC of rig. SIMOPS on F-62A, spot mud boat. Well Killed. N/D tree install CTS Plug and test to 5000 psi. Install BOP stack. Crane shut down ops due to wind. Torque up BOP on well. trouble shoot remote for rig. clean and organize tent;On wind hold for crane ops. Con't organization of x/o and equipment on A-pad. Load all rig equipment & move to F-pad. Finished service of rig. Wind speed sufficient to operate crane. Position crane on matting boards. Fly Cellar over BOPE & set. Fly rig floor onto cellar. Spot & install stairs to rig. Fly riser & flow line spools to rig floor. Mobilize pits to F- pad. Begin hooking up accumulator hoses. Fly tongs & handling equipment. Spot pits & attract stairs. Fly rig floor onto cellar. Spot & install stairs to rig. Function test BOPE Hook up kill & choke lines. Torque all connections on BOPE. Well Name Rig API Number Well Permit Number Start Date End Date MP F-62A ASR#1 50-029-22609-01-00 220-066 1/5/2023 2/5/2023 Hilcorp Alaska, LLC Weekly Operations Summary Finish torqueing up kill side. heat up and make up test mandrill. troubleshoot glycol heating unit. mobilize mag tech hand for glycol unit. hang sheave and elephant trunk. Work on rig acceptance check list. glycol unit rep found pump to be airlocked, got it going. function test BOPs found rams not fully closing. spoke to BOP rep and he advised to function couple times because new seals are in and might need to be broke in. after functioning a couple times rams fully closed. Rig accepted at 12:00;pick up test mandrill, lock rams. fill stack. Perform shell test. found leak on graylock in cellar. tightened. found leak on graylock on back of pits. tightened. found leak on lockdown screw. tightened. troubleshoot leaks. found leak on test pump pulsation dampener. changed out. continue troubleshooting leaks. found graylocks leaking on back of pits and in cellar. blow down and replace gaskets. Cont. isolating & pressure testing to determine main. leak path. After finding no further issues on surface equipment. Screwed in landing JT to protect BPV profile, dump 25 lbs of barite. on hanger. Allow to settle. Remove landing jt & test. Perform shell test to 3000 psi. Achieve passing test. Call out state rep. to witness. While awaiting AOGCC rep. Cir across top of well. to prevent freeze up & allow for expedited testing when ready. Work service loops to ensure proper tracking. Test BOPE as per approved Sundry. Testing witnessed by AOGCC rep. Kam St. John. Test t/ 250 psi low & 3000psi high for 5/5 charted mins. Rig service, hose clamp on glycol hose broken. All glycol contained in mud boat. Shut down rig & replace. Cont. repairing hose. Cont. Testing BOPE as per approved Sundry. Testing witnessed by AOGCC rep. Kam St. John. Test t/ 250 psi low & 3000psi high for 5/5 charted mins. On test #2. 1/7/2022 - Saturday 1/8/2023 - Sunday Continue testing BOPs as per approved sundry to 250 low / 3000 high with AOGCC witness. 1 Fail / Pass on valve C6 on the Choke manifold. Rig down test equipment. Blow down stack and all fluid lines. Adjust service loop hoses. install bales and elevators. run rope through sheave into spooler.. ship fresh water out of pits. Take on 9.4 Brine into pits. hook up pump lines for bull heading operations. P/U T-bar. pull CTS plug. stab into BPV. Pressure observed. fluid rising in the stack. decision was made to rig up lubricator. Mobilize lhaso apso and XO to rig. install XO. screw into hanger. hook up fluid lines and prep to pump once BPV is pulled. Pull BPV observed pressure on gauge ~ 45 psi w/ 9.25ppg Fluid returning to surface. Bullhead 9.4 ppg to perfs at 2.5BPM w/ 2000 psi. Pump a total of 100 bbls to over displace. Shut down line up pump line through choke manifold. Observe flow returning at 37 BPH. Cont, monitoring fluid return from gas buster. Return flow reducing over time. Flow slowed to 20 BPH. Then remaining constant. Shut in monitor pressure build to 115 psi on choke. Lubricator pressure gauge at 115psi. Decision made with OE to increase brine wt to 9.8 ppg NACL. Begin weighting up pits. Service rig. Perform fluid checks. During fluid checks, noticed rig 300k gen having belt issues. Shut down & observed belt thrown & hole in radiator. Ordered 9.8 ppg brine to be delivered to rig. Remove gen radiator. Attempt to procure 300k gen set. Pull BPV observed pressure on gauge ~ 45 psi w/ 9.25ppg Fluid returning to surface. Bullhead 9.4 ppg to perfs at 2.5BPM w/ 2000 psi. Pump a total of 100 bbls to over displace. Shut down line up pump line through choke manifold. Observe flow returning at 37 BPH. Cont, monitoring fluid return from gas buster. Return flow reducing over time. Flow slowed to 20 BPH. Then remaining constant. Shut in monitor pressure build to 115 psi on choke. Lubricator pressure gauge at 115psi. Decision made with OE to increase brine wt to 9.8 ppg NACL. function test BOPs found rams not fully closing. spoke to BOP rep and he advised to function couple times because new seals are in and might need to be broke in. after functioning a couple times rams fully closed. Test BOPE as per approved Sundry. Testing witnessed by AOGCC rep. Kam St. John. Test t/ 250 psi low & 3000psi high for 5/5 charted mins. Correct BOP test pressure per Sundry 322-682. -WCB Well Name Rig API Number Well Permit Number Start Date End Date MP F-62A ASR#1 50-029-22609-01-00 220-066 1/5/2023 2/5/2023 Hilcorp Alaska, LLC Weekly Operations Summary Pressure up down IA. to apply force on top of packer. Set hanger in bowl, Closed bag. Pump down IA to 2500 psi Hold for 5mins, bleed off, open bag. Work pipe in elevators to max of 129k. Work pipe F/ 40k to 129k. Marks indicate no increase in pipe movement up. With 100k pull in tension on string. Closed bag, pressure up down IA to apply force on top of packer. Pump down IA to 500 psi. Hold for 5mins, bleed off, open bag. Work pipe F/ 20k to 129k for ~ .5 hr. Marks indicate no increase in pipe movement up. With 100k pull in tension on string. Closed bag, pressure up down IA. To apply force on top packer. Pump down IA to 1000 psi. Hold for 5mins, bleed off, open bag. Work pipe F/ 20k to 129k. Marks indicate no increase in pipe movement up. Blow down pump lines. Work pipe in elevators to max of 129k. Work pipe F/ 40k to 129k for ~ 4 hrs. Marks indicate no increase in pipe movement up. AOGCC approval obtained. to split stack for access to packer. Vent valve control line. Land hanger RILDS, attempt to test IA. Fluid entering stack from below. hanger seal not holding. BOLDS, cont. to work pipe. Blow down pump lines Work pipe in elevators to max of 125k. Work pipe F/ 40k to 129k for ~ 6 hrs. Marks indicate no increase in pipe movement up. Mobilize E-line & fishing services. Fill tubing w/ 4 bbls , fluid level ~ 700';Work pipe in elevators to max of 125k. Work pipe F/ 40k to 125k for ~ 6 hrs. Marks indicate no increase in pipe movement up. Remove ESP spooling unit for E-line unit R/U. Mobilize E-line & fishing services. While waiting for 9.8 brine to arrive, Monitored well after bull heading 9.4 to perfs, sucked out pits of 9.4 with vac truck. continue to work on 300K and looking for spare. Brine arrived, attempted to pump straight from truck to pump but truck could not push enough. filled pits with 9.8 Brine. Hooked up spare 300K. Pump 100 bbls 9.8 Brine at 2.1 BPM at 2050 psi. shut down pumps and pressure went down to 1100psi immediately. After watching pressure bleed down to 250 psi opened up well for 5 min and closed it back in. new pressure was 160 psi. opened well back up and bled down for 20 min. bleeding at the rate of 20 BPH. shut in to monitor. Simops, weight up fluid from upright to 9.8;pressure came up to 70 psi and was dropping slowly. opened up well and started bleeding off. started at 20 BPH and slowly dropped to zero pressure, zero returns. checked pressure at lubricator and no pressure. started rigging down lubricator. Simops, weight up fluid from upright to 9.8;Rig down lubricator. pick up landing joint, install TIW. hook up hoses for pump ops. BOLDS. Attempt to pull hanger / packer free. pick up to 100k, work it from 0 to 100K 40X, work up to 115K. for an hour. spoke to Packer hand and OE and decided to go to 122K. Decision made to pump down tubing. to apply force under packer to hyd. assist. Pull in tension to 122K. Closed bag. Pump down tubing at 1.2 BPM for 1000 psi. Repeating 2x, made 5" up from initial mark. Bleed off & "dry pull" to 122K 47X;Decision made to pressure cycle on tubing. to apply force under packer for hyd. assist. Pull in tension to 122K. Closed bag. Pump down tubing at 1.2 BPM for 1000 psi. Repeating 42x, shut down pumps open bag. Dry pull to 122k 12x. Marks indicate no increase in pipe movement up. Decision made to pressure cycle on tubing to apply force under packer for hyd. assist. Pull in tension to 122K. Closed bag. Pump down tubing at 1.6 BPM for 1500 psi. Repeating 32x, shut down pumps open bag. Dry pull to 122k. Marks indicate no increase in pipe movement up. Service Rig, Perform fluid checks;Decision made to dry pull to max 122k. 1/10/2023 - Tuesday 1/9/2023 - Monday Attempt to pull hanger / packer free. pick up to 100k, work it from 0 to 100K 40X, work up to 115K. for an hour. spoke to Packer hand and OE and decided to go to 122K. Decision made to pump down tubing. to apply force under packer to hyd. assist. Pull in tension to 122K Closed bag. Pump down tubing at 1.2 BPM for 1000 psi. Repeating 2x, made 5" up from initial mark. Bleed off & "dry pull" to 122K 47X;Decision made to pressure cycle on tubing. to apply force under packer for hyd. assist. Pull in tension to 122K. Closed bag. Pump down tubing at 1.2 BPM for 1000 psi. Repeating 42x, shut down pumps open bag. Dry pull to 122k 12x. Marks indicate no increase in pipe movement up. Decision made to pressure cycle on tubing to apply force under packer for hyd. assist. Pull in tension to 122K. Closed bag. Pump down tubing at 1.6 BPM for 1500 psi. Repeating 32x, shut down pumps open bag. Dry pull to 122k. Marks indicate no increase in pipe movement up. Service Rig, Perform fluid checks;Decision made to dry pull to max 122k Marks indicate no increase in pipe movement up. Well Name Rig API Number Well Permit Number Start Date End Date MP F-62A ASR#1 50-029-22609-01-00 220-066 1/5/2023 2/5/2023 1/13/2022 - Friday R/U lubricator & E-line PCE. P/U & attach Wireline valves "BOPE". M/U grease head. M/U E-line Tools CH, WB, Eline JARS, CENT, EMA, CCL, CENT, 2" RCT, CENT. Test tools , arm RCT, Stab tools in well head M/U lubricator & RIH, Correlate to previous log w/ CCL After multiply attempts anchor set. Pull in tension. Verify cut to be at 2632.7'. Confirmed amp break & line wt jump. Attempt to POOH. E-line detained. Work free, POOH, At lube w/ tools, Check well pressure, static. Remove lube & reconfigure tools. RCT found to be damage in a way that indicates possible cut failure. RIH W/ E-line to confirm separation of tubing CH, WB 2x, CCL. Log area of cut. Collars still on depth w/ previous log. One anomaly deeper than cut depth. Inconsistent tubing cut suspected. POOH. At lube w/ tools, Check well pressure, static. Remove lube & reconfigure tool string to preform second cut. M/U CH, WB, Eline JARS, CENT, EMA, CENT 1- 11/16" RCT, CENT. Tools not testing correct, CCL issue, Reconfigure, test good & RIH. On depth correlate to previous log w/ CCL. After 3 attempts anchor set. Pull in tension. Verify cut to be at 2619.2'. Confirmed amp break & line wt jump. POOH. At lube w/ tools, Check well pressure, static. Remove lube & reconfigure tools to check separation. RCT fired & normal. RIH W/ E-line to confirm separation of tubing CH, WB 2x, CCL. Log area of cut. One anomaly at exact cut depth. Consistent with good tubing cut. POOH. At lube w/ tools, Check well pressure, static. Remove lube & L/D E-line tools. Begin R/D e-line equipment, R/D E-line PCEWireline BOPE. L/D lubricator, grease head & misc. Remove shooting flange f/ rig BOPE. Install spacer & flow spool. Line up pump lines & blow dw. L/D landing JT to hanger. Check IA pressure 0 PSI. R/U pumping lines. PJSM. Unseat hanger at 32k. In intervals work up to 75k P/U. Tubing cut at 2619.2'. 2-7/8" 6.5# L-80 tubing w/ ESP cbl = ~ 17k dry wt. Cont. t/ work pipe F/ 40k to 75k. No increase in pipe movement up. Fill tubing, 3.2 bbls to fill. Fluid level ~ 552'. Cont. to work pipe F/ 40k to 75k. 1/11/2022 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary Work pipe in elevators to max of 125k. Work pipe F/ 40k to 125k for 12 hrs. Marks indicate no increase in pipe movement up. Gather service reps. & OE in town to produce plan forward. Remove E-line unit & Prep to R/U S/L. Stage E-line tools & equipment on Pad. R/U SL unit & pressure control. RIH w/ DGLV. set in Sta #1 at 9,295'. POOH. RIH w/ cat standing valve Set in XN at 9,416', POOH. R/D S-line equip. Fill tubing & test cat standing valve & dummy in STA #1. Test to 1000 psi f/ 5 min . Good test. Service rig & remove S-line tools from floor. Nipple down flow & spacerspools in prep for shooting flange. Blow down all pump lines. Load lube in pits. Ensure pits equalized and even 9.8 ppg,PJSM w/ E-line crew. Rig up shooting flange & lubricator. 1/12/2022 - Thursday Complete R/U of E-line PCE. P/U E-line tubing punch tools. Test Lubricator to 1300 psi. Good test. RIH w/ tubing punch verify depth w/ CCL. Place tubing punch at 2,615 - 2,617'. Punch 4 SPF for a total of 8 SPF .25" dia. Bullhead 250 of 9.8ppg NXS lubricated brine. Pump at 2.5 BPM Initial Cir psi = 1,883 psi. Otis connections oring leaking. Shut down & tighten. Continue cir at 2 BPM w/ 1600 psi. Final circ psi at 2 BPM = 1750Psi. IA pressure increase during circulation F/ 0 psi to 625 psi during circ. Hanger seals damaged as indicated previously. Shut down & monitor flow back. Initial psi on pump 1750 psi reducing to 360 psi in 10 mins. Flow back to gas buster reducing. Monitor & time returns every 10 mins. Ensuring well "dying". Shut blinds cont. Monitoring well through choke line to gas buster. While monitoring well; R/D E-line PCE. Set back wireline BOPE on floor. Remove EL tools from rig floor, N/D shooting flange, N/U spacer & flow spool. Continue monitor well breathing on gas buster. Well static at ~ 21:00. Open blinds. Work pipe after circ of lubed brine. Work pipe in elevators F/ 40k to 129k for 1 hr. Marks indicate no increase in pipe movement up. R/U slick line on landing JT, side entry sub, TIW & x/o to 4" otis. M/U SL tools, secure grease head above. RIH w/ SL to retrieved cat standing valve via GS. On depth - 9,416' set down, P/U WT increase over P/U wt f/ 500 lbs to 1200 lbs. Fish on, POOH. Well static. Retrieve tool string & cat valve. Monitor well via side entry sub to gas buster. R/D SL tools & equipment. Fill tubing, 4 bbls T/ fill. Fluid level ~ 700' dw. R/U lubricator & E-line PCE. P/U & attach Wireline valves "BOPE". M/U grease head. M/U E-line Tools CH, WB, Eline JARS, CENT, EMA, CCL, CENT, 2" RCT, CENT. Test tools , arm RCT, Stab tools in well head M/U lubricator & RIH, Correlate to previous log w/ CCL After multiply attempts anchor set. Pull in tension. Verify cut to be at 2632.7'. Place tubing punch at 2,615 - 2,617 Complete R/U of E-line PCE Log area of cut. One anomaly at exact cut depth. Consistent with good tubing cut. POOH P/U E-line tubing punch tools. Inconsistent tubing cut suspected Tubing cut at 2619.2'. 2-7/8" 6.5# L-80 tubing w/ ESP cbl = ~ 17k dry wt. Cont. t/ work pipe F/ 40k to 75k. No increase in pipe movement up. Work pipe in elevators to max of 125k. Work pipe F/ 40k to 125k for 12 hrs. Marks indicate no increase in pipe movement up. Remove E-line unit & Prep to R/U S/L. Well Name Rig API Number Well Permit Number Start Date End Date MP F-62A ASR#1 50-029-22609-01-00 220-066 1/5/2023 2/5/2023 Hilcorp Alaska, LLC Weekly Operations Summary Cont to TIH with 5 1/2" WS to 2,572'. Attempt to latch into packer top with no success. 3 BPH loss rate. POOH and L/D BHA,Prep BHA. Clean and organize rig floor. M/U bent spear BHA,TIH with 3 1/2" WS tp 2,607nm p/u 32k, S/O 29k. Attempt to engage fish with no succes. R/U kelly hose and break circulation - Swivel packing leaking. Blow down kelly hose and repair swivel packing. Replaced proxy sensors. Service rig and check fluid levels. Break circulation and wash down on top of packer, attempt to engage fish with no success. Disconnect and blow down kelly hose. POOH with 3 1/2" ws, L/D fishing BHA. Cont. to work pipe F/ 40k to 70k. Spot E-line truck & trailer away from rig out on pad. Remove pipe shed from rig in prep for crane. Remove flow & spacer spools from annular. Set base plate for casing jacks on annular. Fly & R/U casing jacks. Serivce rig. Work pipe w/ casing jacks. Pull 70k W/ rig, take over w/ CJ. Pull up to 130k on tubing. Work pipe f/ 70k to 130k. Stretch in pipe not consistent. Gain 3", no shear release. Land hanger back on seat. N/D casing jacks w/ crane. N/U shooting flange. Install wireline BOPE. Remove elevators & bails. Fill tubing ~ 3 bbls f/ fill. Fluid level ~ 518',M/U E-line Tools CH, WB, Eline JARS, CENT, EMA, CCL, CENT, 1-11/16" RCT, CENT. Test tools , arm RCT,Stab tools in well head M/U lubricator & RIH. Correlate to previous log w/ CCL after multiply attempts anchor set. Anchor not setting correctly. Observed overpull, not in correct position. POOH. At lube w/ tools, Check well pressure, static. Remove lube, Remove RCT. Anchor found to be damage. Rebuild and test on surface. RIH w/ same E-line assy. Correlate to previous log w/ CCL. After multiply attempts anchor set. Anchor set at 2560' CCL. Pull in tension. Verify depth of cut to be at 2571.2' WLM. Fire RCT, Confirmed amp break & line wt jump. 600 lbs T/ 500 lbs. POOH. No change in IA PSI. At lube w/ tools, Check well pressure, static. Remove lube, L/D E-line tools. RCT fired & anchor intact. N/U spacer & Bell nipple. R/U 6" flow line. R/U cellar dip pan. TQ spools. Simops; R/U bails & elevators. Link tilt rams & hydraulics. P/U & M/U landing JT to hanger. M/U pump lines. P/U on string. WT increase to 30k, Hanger offseat. WT increase to 47k then dropping to 23k. Tubing CUT P/U wt = 23k S/O wt = 18k. Pump 3 bpm at 450 PSI. Returns 9.8 ppg after 42 bbls away. total bbls pump = 100 bbls. blow down & R/D lines. Remove Wireline BOPE F/ floor & all MISC. E-line tools. Rig up ESP Spooling unit. Prep to POOH w/ cut ESP completion. 1/14/2022 - Saturday P/U handling equipment & tools f/ fishing BHA. Thaw and drift DC's (full of ice and snow). Monitor well. P/U 5 3/4" overshot Fishing assembly, Service and grease rig equipment. Check all fluid levels. RIH with 3 1/2" WS and engage fish at 2,563'. Work and Jar to release packer f/ 40 t/ 100K overpull. Packer released after 30 jar hits. 1K additional string wt fill hole and monitor well - well static. POOH and L/D BHA. recovered 22' of cut jt and 14.9' pup jt. - No packer. Found pin end threads on pup jt stretched. Wait on fishing tools. Service and clean rig. Monitor well - 3 BHP loss rate. Load and prep BHA. M/U Spear Fishing BHA ( 2.399 grapple) t/ 329',TIH with 3 1/2" work string. 1/17/2023 - Tuesday 1/15/2023 - Sunday Pull Hanger T/ rig floor. De-complete hanger w. ESP rep. P/U wt = 23K. Losing 2 BPM. L/D hanger & attach ESP cable to sheave & spooler. Pull ESP to GLM. Tubing covered in crude. Circulate 15 BBLS to clean. Pump at 2 BPM 175PSI. POOH w/ 2- 7/8" 6.4# L-80 EUE. Cut ESP completion F/ 2571' T/ surface. Losing 3 BPH. Recover 84 full Jts & 7.95' cut joint. Match cut WLM. Clean & clear rig floor. Extend time due to oily completion. Prep to Test BOPE. Move fluid in pits take on fresh water. Test BOPE as per approve sundry 322-682. Witness waived by AOGCC rep. Test w/ 2-7/8" & 3-1/2" test joints. Test t/ 250 psi low & 3000 psi high. All tests recorded f/ 5/5 charted mins. Perform accumulator drawdown test. B/D all lines. F/ testing. P/U handling equipment & tools f/ fishing BHA. Line up all well control equipment for well ops. 1/16/2023 - Monday RIH w/ same E-line assy. Correlate to previous log w/ CCL. After multiply attempts anchor set. Anchor set at 2560' CCL. Pull in tension. Verify depth of cut to be at 2571.2' WLM. Fire RCT, Confirmed amp break & line wt jump. 600 lbs T/ 500 lbs. POOH. No change in IA PSI. At lube w/ tools, Check well pressure, static. Remove lube, L/D E-line tools. RCT fired & anchor intact. N/U spacer & Bell nipple. R/U 6" flow line. R/U cellar dip pan. TQ spools. Simops; R/U bails & elevators. Link tilt rams & hydraulics. P/U & M/U landing JT to hanger. M/U pump lines. P/U on string. WT increase to 30k, Hanger offseat. WT increase to 47k then dropping to 23k. Tubing CUT P/U wt = 23k S/O wt = 18k. Pump 3 bpm at 450 PSI. Returns 9.8 ppg after 42 bbls away. POOH with 3 1/2" ws, L/D fishing BHA RIH with 3 1/2" WS and engage fish at 2,563'. Work and Jar to release packer f/ 40 t/ 100K overpull. Packer released after 30 jar hits. 1K additional string wt fill hole and monitor well - well static. POOH and L/D BHA. recovered 22' of cut jt and 14.9' pup jt. - No packer. Found pin end threads on pup jt stretched. Wait on fishing tools. Service Cut ESP completion F/ 2571' T/ surface. Losing 3 BPH. Recover 84 full Jts & 7.95' cut joint. Well Name Rig API Number Well Permit Number Start Date End Date MP F-62A ASR#1 50-029-22609-01-00 220-066 1/5/2023 2/5/2023 P/U milling/cleanout BHA. Clean and clear rig floor. TIH with 3-1/2" WS to 2615'. R/U power swivel. P/U 33.5K, S/O 29.5K. Service rig and trouble shoot low rig amperage. Replace alternator on rig motor. Tag TOF @ 2639' establish circulation 3BPM@ 250 psi, work to clean up and mill f 2639' to 2644' 80 rpm/ 800 - 2k ft/lbs tq. work over fish multiple times. Circulate well clean 3 BPM/ 250 psi, R/D power swivel. POOH with 3-1/2" WS. * 21:00 hrs. - 24hr notice given to AOGCC of upcoming BOPE test. L/D BHA. M/U short catch overshot BHA. Service rig and check fluid levels. Cont. to M/U short catch BHA. RIH w 3- 1/2" WS to 2615' R/U power swivel. Attempt to wash and work over fish P/U - 33k, S/O - 29K 1BPM@ 120psi. Latch onto fish and gradually work to P/U of 70K when sudden drop off of wt to P/U of 34K, work back down with S/O of 28K. tag 1.5' higher with 15K. pull 1 jt. 1/21/2022 - Saturday 1/20/2022 - Friday Cont. to TIH to 2566'. R/U power swivel and establish parameters. P/U 32K, S/O 29K, 2 BPM/1150 psi, 5rpm/450ftlbs tq. Wash down and tag top of fish @ 2,641'. Attempt to engage fish with no success. Service rig and check fluid levels. Drop ball and shear out pump out sub at 1300psi. R/D power swivel. POOH with 3-1/2" WS f/ 2566' to 53'. L/D Spear fishing BHA. M/U overshot fishing BHA to 332'. RIH with 3-1/2" WS f/ 332' to 2615'. R/U power swivel and wash down to 2641'. P/U 33K, S/O 29K(pumps off) P/U 32K, S/O 28.5k(pumps on), 3 BPM @ 270psi. Attempt to engage fish with no success.. R/D power swivel and service rig, check fluid levels. POOH f/ 2615' to 332'. L/D Overshot BHA. 1/18/2022 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary Install 9" ID wear bushing and Run in 4 lock downs. M/U Burn shoe BHA. Early/extended crew change out due to rig move blockage of road. Cont. to M/U Burn shoe BHA to 343'. RIH w 3-1/2" WS to 2590' P/U 33k, S/O 29.5K. R/U power swivel and Vis up mud system to 40 sec PV. Break circulation at 3 BPM/ 350psi, work down to top of packer at 2599' and mill packer 80 rpm w/ 500 to 1800 ft/lbs tq. varied pump rates from 3 bpm to 1.5 bpm. Packer fell after milling to 2602.5'. chased packer to 2639' and gained 1k P/U wt.. R/D power swivel and monitor well - static. POOH w/ 3-1/2" WS to 343' P/U 34k, S/O 30k. L/D BHA. 1/19/2022 - Thursday Cont to lay down milling BHA, clean out junk baskets - no debris.. Clean and clear floor of 3rd party equipment.. Blow down pump lines and change out swivel packing on power swivel. M/U spear BHA to 330'. Service rig and check fluid levels. RIH with 3-1/2" WS to 2639'. Attempt to engage fish rotate pipe 1/4 turns to find bore. Tagged multiple times at 2639, last tag at 2643' with additional 5-800 lbs up wt. Pulled 1 jt and connection was wet. Drop ball and rod to open circ sub, Pressure up WS to 1400psi to shear. POOH f/ 2599' t/ 330'. L/D BHA. recovered ~25' of control line hanging from spear, 1 piece of metal fell of once spear entered BOP's and landed on top of wear bushing. Call out wireline with 2" magnet and wt bars. Fish 5"x 10" piece of metal from top of wear bushing. M/U spear fishing BHA. Repair power rig tongs. Cont. to M/U spear fishing BHA to 353'. RIH with 3-1/2" WS. Attempt to engage fish rotate pipe 1/4 turns to find bore. Tagged multiple times at 2639, last tag at 2643' with additional 5-800 lbs up wt. Pulled 1 jt and connection was wet. Drop ball and rod to open circ sub, Pressure up WS to 1400psi to shear. POOH f/ 2599' t/ 330'. L/D BHA. recovered ~25' of control line hanging from spear, 1 piece of metal fell of once spear entered BOP's and landed on top of wear bushing. Call out wireline with 2" magnet and wt bars. Fish 5"x 10" piece of metal from top of wear bushing. M/U spear fishing BHA. Repair power rig tongs. Cont. to M/U spear fishing BHA to 353'. RIH with 3-1/2" WS. Packer fell after milling to 2602.5'. chased packer to 2639' and gained 1k P/U wt Tag TOF @ 2639' establish circulation 3BPM@ 250 psi, work to clean up and mill f 2639' to 2644' 80 rpm/ 800 - 2k ft/lbs tq. work over fish multiple times. Circulate well clean 3 BPM/ 250 psi, R/D power swivel. POOH with 3-1/2" WS. * 21:00 hrs. - 24hr notice given to AOGCC of upcoming BOPE test. L/D BHA. M/U short catch overshot BHA. Service rig and check fluid levels. Cont. to M/U short catch BHA. RIH w 3- 1/2" WS to 2615' R/U power swivel. Attempt to wash and work over fish P/U - 33k, S/O - 29K 1BPM@ 120psi. Latch onto fish and gradually work to P/U of 70K when sudden drop off of wt to P/U of 34K, work back down with S/O of 28K. Well Name Rig API Number Well Permit Number Start Date End Date MP F-62A ASR#1 50-029-22609-01-00 220-066 1/5/2023 2/5/2023 Hilcorp Alaska, LLC Weekly Operations Summary RIH w/ WS to 2643'. Rig up swivel hose and swivel up. pop off on mud pump went off. blew down pop off line. replaced pins in pop off. started milling.. Milling w Burn shoe. made aprox. 24". after not making anymore decision was made to POOH. R/D power swivel and POOH f /2635' to 334' P/U 33K, S/O 29K. L/D BHA - recovered top element inside of mill shoe, and ~ 1 1/2 gal of metal from boot baskets. P/U short catch fishing BHA t/ 322'. RIH with 3-1/2" WS t/ 2645' and M/U power swivel P/U 33K, S/O 29K. Work over and engage fish. set dn 15K on fish, had 1K overpull for 2.5' on P/U. R/D power swivel and POOH with 3-1/2" WS to 322' P/U 33K, S/O 29K. L/D BHA and fish Flood stack and attempt to Shell test BOPE, found annular to be leaking. Cont to test remaining BOPE to 250 low/ 3000 high psi for 5 min each - UPR with 2 7/8" and 3-1/2" jt., LPR with 3-1/2" jt. R/D spools and bird bath on top of BOP's. Replace annular element and R/U spool and bird bath. Change oil, filters on carrier motor. Service rig, Change oil and filters on carrier motor. Replaced starter on Carrier motor. Test annular to 250 low/ 3000 high with 2 7/8" test jt, perform accumulator draw down test.. Blow down mud lines, pull test plug and install wear bushing. M/U burn shoe BHA to 344'. TIH w 3-1/2" WS. 1/24/2023 - Tuesday 1/22/2023 - Sunday R/D power swivel and blow down mud lines. POOH with 3-1/2" WS f/ 2598' t/ 332'. L/D BHA and break down overshot to remove fish. recovered vent valve and top 16" of packer body and 4'1" of inner penetrator sleeves.. Clean and clear rig floor, Check fluid levels and service rig repair service loop wrap. Replace Hyd pump on spooling unit and remove from location for repair. Perform weekly and monthly inspections of rig equipment. wait on slick line unit. R/U slick line unit. RIH with magnets (5 runs) to 2655' wlm. Recovered 11 lbs of metal shavings and 3 small pieces of metal. RIH with 3.8" LIB. no indents or impressions. RIH with 6" LIB. no indents or impressions. RIH with LDTT. LDTT with all pins intact. R/D slickline unit. Remove wear bushing, R/U and flush BOP stack. M/U and install test plug. Transfer vis brine in pits and take on 40bbls fresh water for testing. Grease mud cross valves and manifold valves. 1/23/2023 - Monday R/U slick line unit. RIH with magnets (5 runs) to 2655' wlm. Recovered 11 lbs of metal shavings and 3 small pieces of metal. RIH with 3.8" LIB. no indents or impressions. RIH with 6" LIB. no indents or impressions. POOH with 3-1/2" WS f/ 2598' t/ 332'. L/D BHA and break down overshot to remove fish. recovered vent valve and top 16" of packer body and 4'1" of inner penetrator sleeves Well Name Rig API Number Well Permit Number Start Date End Date MP F-62A ASR#1 50-029-22609-01-00 220-066 1/5/2023 2/5/2023 1/27/2022 - Friday P/U BHA, overshot, bumper sub and jars. 9 drill collars, and XO. to 318'. RIH to 2661'. up wt 33K dwn wt 29K. hook up kelly hose. swivel up and RIH to 2681' and engage fish. P/U to 40K and 5 K increments after that giving time for jars to bleed. after reaching 85K picked up to 97K and dropped weight. to original up weight. went back down and tagged same spot to engage fish. pick up with no overpull. Blow down lines and prep to POOH. Service rig and check fluid levels. POOH with 3 1/2" WS to 318'. L/D BHA - recover 1'5" of tubing and tubing collar. Break down BHA and prep mill shoe BHA. M/U 3 1/2" dress off/ clean out BHA to 41'. RIH with 3 1/2" WS to 2643', P/U pump jt and R/U power swivel. Wash down and tag TOF at 2681'. Mill/Clean up tubing stump to 2683.5' P/U - 26K, S/O - 24K, ROT - 23K, 3BPM/250PSI, off btm - 400 tq, on bottom - 1-2K tq., 50rpm, WOM 1-2K. R/D power swivel and POOH with 3 1/2" WS t/ 41'. L/D BHA. Prep and P/U fishing BHA. 1/25/2022 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary Finish laying down overshot BHA. found small piece of packer. Decision was made to run another burn shoe. P/U Burn shoe BHA. RIH w/ WS to 2616'. Make up kelly hose. pick up new joint and swivel in. RIH and tag 28' in on jt 58. @ 2644'. Mill down 8" pumping @ 1BPM 110psi. top drive stalled out. pick up and begin rotate and went down 3'. Pick up to connection overpulling 1-2K over, stop rotate, started coming back down and tagged 20' high. Laid joint down. pulled up 1 joint, came down and tagged 40' higher than last tag. work through spot back down. to original tag @2644'. decision was made to pulling out of hole. POOH with Burn shoe while pulling over 1-2 K over original up wt. L/D BHA, no fish recovered. Mill showed wear 18" above mill face. Change out mill shoe and P/U BHA. Service rig and check fluid levels. RIH with 3 1/2" WS to 2617' and R/U power swivel. Wash down and start milling @ 2648' P/U 32k, S/O 29K, 80rpm, 500 - 2K tq. 1-3BPM @ 120-250 psi, 3-5K WOM. 1/26/2022 - Thursday Wash down and start milling @ 2648' P/U 32k, S/O 29K, 80rpm, 500 - 2K tq. 1-3BPM @ 120-250 psi, 3-5K WOM. R/D power swivel and POOH f/ 2648 t/ 1135'. Service rigs and check fluid levels. POOH with 3 1/2" WS f/ 1135' to 322'. L/D Milling BHA - recovered packer/ pup jt, and 21' of cut jt. L/D fish and break down milling/fishing tools/ prep next BHA. P/U dress off BHA. RIH with 3 1/2" WS to 2643', R/U power swivel. Wash down and tag top of 2 7/8" tubing stump at 2676' mill/dress off tubing stump to 2680'. P/U 25k, S/O 21K, 30rpm, 500 - 1300 tq. 2BPM @ 150 psi, 1-3K WOM. R/D power swivel and POOH with 3 1/2" WS to 41'. L/D Dress off BHA. M/U fishing BHA. P/U M/U BHA jars 9 drill collars and drilling jars. RIH W/ 3-1/2 WS and overshot to 2664' make up kelly hose. up wt 34K dwn wt 29K. RIH and engage fish with overshot. pull up to 15K above up weight.. pick up in 5K increments to let jars bleed. pull up to 82K and lost overpull. went down in attempt to engage fish. no luck. Service rig, check fluid levels and perform derrick inspection. POOH w/ 3-1/2 WS from 2681' to 318'. L/D overshot BHA, recovered 3' of 2 7/8" tubing. Discuss plan forward with town, clean and organize pipe shed and rig floor. M/U mill shoe/clean out BHA t/ 325'. TIH with 3 1/2" WS to 2647' R/U power swivel. Wash and ream down to TOF at 2,682', mill and clean out around 2 7/8" tubing stump to 2683.5' 3BPM/250psi, 70rpm off bottom tq 500/ on bottom tq 800-2k tq, P/U and work over stump several times. Stop rotation and work over stump to 2688'. Circulate bottoms up 3 BPM/ 250psi. R/D power swivel and POOH with 3 1/2" WS to 325'. L/D BHA. P/U Dress off BHA. 1/28/2022 - Saturday L/D BHA - recover 1'5" of tubing and tubing collar Decision was made to run another burn shoe.Finish laying down overshot BHA. found small piece of packer. RIH with 3 1/2" WS to 2643', R/U power swivel. Wash down and tag top of 2 7/8" tubing stump at 2676' mill/dress off tubing stump to 2680'. L/D overshot BHA, recovered 3' of 2 7/8" tubing Wash down and tag TOF at 2681'. Mill/Clean up tubing stump to 2683.5' POOH with 3 1/2" WS f/ 1135' to 322'. L/D Milling BHA - recovered packer/ pup jt, and 21' of cut jt. Discuss plan forward with town, clean and organize pipe shed and rig floor. M/U mill shoe/clean out BHA t/ 325'. TIH with 3 1/2" WS to 2647' R/U power swivel. Wash and ream down to TOF at 2,682', mill and clean out around 2 7/8" tubing stump to 2683. Well Name Rig API Number Well Permit Number Start Date End Date MP F-62A ASR#1 50-029-22609-01-00 220-066 1/5/2023 2/5/2023 Hilcorp Alaska, LLC Weekly Operations Summary Continue to POOH w/ 2-7/8 EUE and ESP. Lay down ESP completion equipment as per baker rep. Pull wear ring, flush stack. set test plug, make up/ pick up test joints. flood stack. Test BOPE as per state approved sundry. All tests preformed 250 psi low. 3000 psi high for 5/5 charted mins. Perform accumulator drawdown. L/D testing equipment, secure safety valves on rig floor. Blow down & line up BOP equip. for ops. Rack & tally 116 JTS. Place BHA in order. P/U & M/U fishing clean out BHA. Mill, 2x boot baskets, Bit sub, 2x string magnets, LBS, Oil jar & XO. RIH w/ fishing clean out BHA. On 3-1/2" 9.5# workstring F/ 49' T/ 6,255'. Continue to work fish through wellhead. free fish and pull to floor. Clear and cut cable from top of fish. lay down BHA handling equipment off rig floor. run rope through sheave. prep to pull ESP. POOH with 2-7/8 EUE and ESP. tubing pulling wet. rig up to pump down tubing to clear circ path to help with fluid draining. pump 1 BPM @ 1100PSI. Continue to POOH w/ 2-7/8 EUE and ESP. 1/31/2023 - Tuesday 1/29/2023 - Sunday M/U dress off BHA. Dress off mill, boot baskets, bumper sub and jars, 9 drill collars. to 323'. RIH w/ WS to 2665'. hook up kelly hose, pick up next joint swivel up. Get parameters. up wt 34K dwn wt 30K. rt wt 31K. Rotate 30rpm pumping 1 BPM. dress off stump at 2683' pull up and swallow with no rotate. dress off looks good. Swivel out, rig down and blow down kelly hose. POOH from 2683' to 323'. L/D BHA 9 drill collars, jars and bumper sub, boot baskets. and dress off mill. P/U overshot fishing BHA to 326'. TIH with 3 1/2" WS t/ 2668' P/U 32K. S/O 29K. Work down and TOF @ 2683'. swallow 5' to 2688'. picked to 60K and allowed jars to bleed off. Continued to pick up to 105K and establish string and fish movement of 18'. Work string up and down thru tight spot. P/U 105K S/O 45K. POOH with 3 1/2" working pipe thru multiple tight spots (every ~40') with up to 20K overpulls. L/D BHA and work fish thru BOP stack. 1/30/2023 - Monday dress off stump at 2683' pull up and swallow with no rotate. dress off looks good. Swivel out, rig down and blow down kelly hose. POOH from 2683' to 323'. L/D BHA 9 drill collars, jars and bumper sub, boot baskets. and dress off mill. P/U overshot fishing BHA to 326'. TIH with 3 1/2" WS t/ 2668' P/U 32K. S/O 29K. Work down and TOF @ 2683'. swallow 5' to 2688'. picked to 60K and allowed jars to bleed off. Continued to pick up to 105K and establish string and fish movement of 18'. Work string up and down thru tight spot. P/U 105K S/O 45K. POOH with 3 1/2" working pipe thru multiple tight spots (every ~40') with up to 20K overpulls. L/D BHA and work fish thru BOP stack Continue to POOH w/ 2-7/8 EUE and ESP. Continue to work fish through wellhead. free fish and pull to floor. Clear and cut cable from top of fish. lay down BHA handling equipment off rig floor. run rope through sheave. prep to pull ESP. POOH with 2-7/8 EUE and ESP. tubing pulling wet. rig up to pump down tubing to clear circ path to help with fluid draining. pump 1 BPM @ 1100PSI Well Name Rig API Number Well Permit Number Start Date End Date MP F-62A ASR#1 50-029-22609-01-00 220-066 1/5/2023 2/5/2023 2/3/2022 - Friday pull wear ring. load pipe shed with 2-7/8 EUE and the ESP completion equipment. wrap up ESP equipment with heaters to warm up. bring sheave down to run pothead through and hang sheave. P/U ESP equipment and service motor and seals as per Baker rep. P/U pumps x4 & discharge head. Terminate MLE splice. RIH W/ 2-7/8" 6.4 # EUE ESP Completion. Applying a clamp every other JT. F/ 113' T / 4,903'. 2/1/2022 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary RIH from 6255' to 6895' fighting ice and snow. Rig service. troubleshoot skate. mobilize welder to location. remove skate from catwalk. welder fixed skate. installed skate function test. Continue RIH W/ 3.5 work string and fishing clean out assembly to 9577', Tag tubing stub at 9,590' w/ 13' ORKB diff = 9603' rig up kelly hose, line up to start pumping. Obtain parameters, at 3.5 BPM w/ 660 psi. P/U wt = 79k Rot wt = 62k w/ 2.5k TQ at 60 RPM. Rot & recip F/ 9600' T/ 9597' pump 123 bbls total. Retag tubing stump on same depth = 9,603' corrected. Displace well over to 9.8 ppg NACL brine. Take 9.8 vised brine returns to tiger tank. Pump 3.5 bpm w/ 700 psi. Use pits volume & upright tank. Pump a total of 335 bbls to tiger tank. Fill pits w/ remaining 9.8 brine. Monitor well (static). Blow down circ. lines, & R/D kelly line. Prep to POOH. POOH w/ fishing clean out BHA F/ 9603' T/ 8,056'. Fill well every 15 jts. Service rig Perform equip. fluid checks. Cont. POOH w/ fishing clean out BHA F/ 8,056' T/ 2,651'. Fill well every 15 jts. 2/2/2022 - Thursday POOH with 3.5 work string and fishing clean out assembly from 2651' to 49'. Lay down BHA. jars, bumper sub, magnets boot baskets and bit. clean and inspect magnets. clean boot baskets. decision was made to make magnet run with slickline. Rig up wireline w/ magnets for clean out run. Slick line made 4X runs to tubing stump @ 9635' WLM. Metal shaving diminishing after each run. R/D SL. Remove tools f/ rig floor. Prep to RIH W/ test packer. M/U AS1X test packer f/ 7" 26#. Function test. XO to 3-1/2" 9.5# workstring. RIH W/ 2,500' Stab TIW. Set test PKR at 2,500'. Fill lines & test IA to 1800 PSI f/ 15 charted mins. Good test. Unset PKR, RIH T/ 2700' Set test PKR. Fill lines & test IA to 2,000 PSI f/ 15 charted mins. Good test. Blow dwn test lines. Unset test packer. POOH w/ AS1X test PKR F/ 2,700' T/ surface. Inspect PKR, (good). Clean & clear floor. Remove all pipe f/ shed. Prep for ESP run. Continue to RIH with 2-7/8 EUE and ESP from 4,564' to 7,015'. testing ESP cable every 2,000'. Change elevators to pick up packer. PUP on top of packer was slim hole collar. P/U M/U D&L ESP Packer. Packer is pinned for 20K over pull. (4 screws). up wt @packer 46K. dwn wt 30K. Splice ESP through packer. Attract cap line to vent valve. Test vent valve. Vent starts opening at 2400 psi. Full open at 3400 psi. Hold 3,600 psi on cap line. while RIH. Cont. RIH with 2-7/8 EUE and ESP F/ 7,015' T/ 9,532'. testing ESP cable every 2,000'. P/U WT = 66k. S/O WT = 40k. P/U & M/U hanger & landing JT. Stab TIW. Terminate ESP cable to hanger. 2/4/2022 - Saturday No operations to report. 2/5/2023 - Sunday Baker finish ESP Hanger splice. terminate cap line and run through hanger. Land tubing hanger in bowl. 41K in hanger bowl. RILDS. Drop Ball and rod. rig up to set/ test packer and test backside. Pressure up on tubing to 3800 psi to set packer. hold for 30 charted min. good tubing test. Bleed off tubing to 1000 psi and shut in. Bleed off cap tube to vent valve closing vent valve. MIT IA to 1500 bringing pressure up slow and holing for 30 charted min. good test. Bleed off slow so as not to damage ESP cable/ connection. rig down testing equipment. blow lines dry. Rig up slickline. Slick line RIH and retrieve ball and rod from 9,413'. POOH. RIH and retrieve RHC. rig down slick line. pull landing joint. set BPV. Rig released. @ 18:00 2/6/2023 - Monday Baker finish ESP Hanger splice. terminate cap line and run through hanger. Land tubing hanger in bowl. It looks like the post-tubing swap MIT-IA was performed to only 1500 psi, not the 2500 psi that Sundry 322-682 specifies. -WCB Drop Ball and rod. rig up to set/ test packer and test backside. Pressure up on tubing to 3800 psi to set packer M/U hanger & landing JT. Stab TIW. Terminate ESP cable to hanger Continue to RIH with 2-7/8 EUE and ESP from 4,564' to 7,015'. testing ESP cable every 2,000' Prep to RIH W/ test packer. M/U AS1X test packer f/ 7" 26#. Function test. XO to 3-1/2" 9.5# workstring. RIH W/ 2,500' Stab TIW. Set test PKR at 2,500'. Fill lines & test IA to 1800 PSI f/ 15 charted mins. Good test. Unset PKR, RIH T/ 2700' Set test PKR. Fill lines & test IA to 2,000 PSI f/ 15 charted mins. Good test. Blow dwn test lines. Unset test packer. POOH Cont. RIH with 2-7/8 EUE and ESP F/ 7,015' T/ 9,532'. testing ESP cable every 2,000'. MIT IA to 1500 Displace well over to 9.8 ppg NACL brine. Take 9.8 vised brine returns to tiger tank. Pump 3.5 bpm w/ 700 psi. Use pits volume & upright tank. Pump a total of 335 bbls to tiger tank. Fill pits w/ remaining 9.8 brine. Monitor well (static). Continue RIH W/ 3.5 work string and fishing clean out assembly to 9577', Tag tubing stub at 9,590' Well Name Rig API Number Well Permit Number Start Date End Date MP F-62A ASR#1 50-029-22609-01-00 220-066 1/5/2023 2/5/2023 Hilcorp Alaska, LLC Weekly Operations Summary No operations to report. 2/7/2023 - Tuesday STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION *All BOPE reports are due to the agency within 5 days of testing* Submit to:jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov Rig Owner:Rig No.:ASR 1 DATE:1/16/23 Rig Rep.:Rig Email: Operator: Operator Rep.:Op. Rep Email: Well Name:PTD #2200660 Sundry #322-682 Operation:Drilling:Workover:x Explor.: Test:Initial:Weekly:x Bi-Weekly:Other: Rams:250/3000 Annular:250/3000 Valves:250/3000 MASP:2569 MISC. INSPECTIONS:TEST DATA FLOOR SAFETY VALVES: Test Result/Type Test Result Quantity Test Result Housekeeping P Well Sign P Upper Kelly 1 P Permit On Location P Hazard Sec.P Lower Kelly 0 NA Standing Order Posted P Misc.NA Ball Type 1 P Test Fluid Water Inside BOP 1 P FSV Misc 0 NA BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm Stripper 0 NA Trip Tank NA NA Annular Preventer 1 11"P Pit Level Indicators P P #1 Rams 1 2 7/8" x 5"P Flow Indicator P P #2 Rams 1 Blinds P Meth Gas Detector P P #3 Rams 0 NA H2S Gas Detector P P #4 Rams 0 NA MS Misc 0 NA #5 Rams 0 NA #6 Rams 0 NA ACCUMULATOR SYSTEM: Choke Ln. Valves 1 2 1/16"P Time/Pressure Test Result HCR Valves 1 2 1/16"P System Pressure (psi)3000 P Kill Line Valves 2 2 1/16"P Pressure After Closure (psi)1800 P Check Valve 0 NA 200 psi Attained (sec)12 P BOP Misc 0 NA Full Pressure Attained (sec)50 P Blind Switch Covers:All stations Yes CHOKE MANIFOLD:Bottle Precharge:P Quantity Test Result Nitgn. Bottles # & psi (Avg.):4 / 2225 PSI P No. Valves 16 P ACC Misc 0 NA Manual Chokes 1 P Hydraulic Chokes 1 P Control System Response Time:Time (sec)Test Result CH Misc 0 NA Annular Preventer 18 P #1 Rams 6 P Coiled Tubing Only:#2 Rams 6 P Inside Reel valves 0 NA #3 Rams 0 NA #4 Rams 0 NA Test Results #5 Rams 0 NA #6 Rams 0 NA Number of Failures:0 Test Time:6.5 HCR Choke 1 P Repair or replacement of equipment will be made within days. HCR Kill 0 NA Remarks: AOGCC Inspection 24 hr Notice Yes Date/Time 1/14/23 09:35 Waived By Test Start Date/Time:1/15/2023 22:00 (date)(time)Witness Test Finish Date/Time:1/16/2023 4:30 BOPE Test Report Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Guy Cook Hilcorp Tests preformed w/ 2-7/8" & 3-1/2" test joints.Chart shows on test #3 work air out of system on low tests, then tested good. Precharge on all bottles 1000psi. J.Werlinger/ C. Greub Hilcorp Alaska LLC S.Hiem/ R. Gallen MPU F-62A Test Pressure (psi): askans-asr-toolpushers@hilcorp.co ans-asrwellsitemanagers@hilcorp Form 10-424 (Revised 08/2022)2023-0116_BOP_Hilcorp_ASR1_MPU_F-62A           J. Regg; 5/26/2023 Kyle Wiseman Hilcorp Alaska, LLC Geo Tech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: Kyle.Wiseman@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 01/25/2023 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20230125 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# CLU 13 50133206460000 214171 1/6/2023 YELLOW JACKET PERF MPU F-62A 50029226090100 220066 1/12/2023 YELLOW JACKET RCT CUT SRU 224-10 50133101380100 222124 1/9/2023 YELLOW JACKET GPT-PERF Please include current contact information if different from above. By Meredith Guhl at 1:56 pm, Jan 25, 2023 T37470 T37471 T37472 MPU F-62A 50029226090100 220066 1/12/2023 YELLOW JACKET RCT CUT Meredith Guhl Digitally signed by Meredith Guhl Date: 2023.01.25 14:00:32 -09'00' STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report for: Reviewed By: P.I. Suprv Comm ________MILNE PT UNIT F-62A JBR 02/21/2023 MISC. INSPECTIONS: FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK: ACCUMULATOR SYSTEM:MUD SYSTEM: P/F P/F P/FP/FP/F Visual Alarm QuantityQuantity Time/Pressure SizeQuantity Number of Failures:1 Used 2-7/8" TJ. Had a coolant hose leak so some delay on testing as it was for their Hydraulics. 1 F/P on C6 choke manifold, grease test no good; replaced valve and passed. Accumulators 12 @ 1000 psi avg pre charge. Test Results TEST DATA Rig Rep:J. Werlinger/ C GreubOperator:Hilcorp Alaska, LLC Operator Rep:Aaron Haberthur/Russell Ga Rig Owner/Rig No.:Hilcorp ASR 1 PTD#:2200660 DATE:1/8/2023 Type Operation:WRKOV Annular: 250/3000Type Test:INIT Valves: 250/3000 Rams: 250/3000 Test Pressures:Inspection No:bopKPS230108111607 Inspector Kam StJohn Inspector Insp Source Related Insp No: INSIDE REEL VALVES: Quantity P/F (Valid for Coil Rigs Only) Remarks: Test Time 6.5 MASP: 2569 Sundry No: 322-682 Control System Response Time (sec) Time P/F Housekeeping:P PTD On Location P Standing Order Posted P Well Sign P Hazard Sec.P Test Fluid W Misc NA Upper Kelly 1 P Lower Kelly 0 NA Ball Type 1 P Inside BOP 1 P FSV Misc 0 NA 16 FPNo. Valves 1 PManual Chokes 1 PHydraulic Chokes 0 NACH Misc Stripper 0 NA Annular Preventer 1 11"P #1 Rams 1 2-7/8" X 5" V P #2 Rams 1 Blinds P #3 Rams 0 NA #4 Rams 0 NA #5 Rams 0 NA #6 Rams 0 NA Choke Ln. Valves 1 2-1/16"P HCR Valves 1 2-1/16"P Kill Line Valves 2 2-1/16"P Check Valve 0 NA BOP Misc 0 NA System Pressure P3000 Pressure After Closure P1800 200 PSI Attained P13 Full Pressure Attained P52 Blind Switch Covers:PAll Stations Bottle precharge P Nitgn Btls# &psi (avg)P4@2237 ACC Misc NA0 NA NATrip Tank P PPit Level Indicators P PFlow Indicator P PMeth Gas Detector P PH2S Gas Detector NA NAMS Misc Inside Reel Valves 0 NA Annular Preventer P19 #1 Rams P6 #2 Rams P6 #3 Rams NA0 #4 Rams NA0 #5 Rams NA0 #6 Rams NA0 HCR Choke P1 HCR Kill NA0 Used 2-7/8" TJ. Had a coolant hose leak so some delay on testing as it was for their Hydraulics. 1 F/P on C6 choke manifold, 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: ESP Swap 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address: Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception? Yes No 9. Property Designation (Lease Number): 10. Field: Current Pools: 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 10,112'N/A Casing Collapse Conductor N/A Surface 3,090psi Production 5,410psi Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16. Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng See Schematic 12/6/2022 Tripoint Ret. & Baker Premier Ret. and N/A 2,607' MD/ 2,518 TVD & 9,622 MD / 6,989 TVD and N/A 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: AOGCC USE ONLY todd.sidoti@hilcorp.com 777-8443 Todd Sidoti Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): Tubing Size: 13.5" / L-80 / Hyd 625 9,740'See Schematic 4-1/2" 2-7/8" 6.4 / L-80 / EUE 8rd 9,560' STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL025509 & ADL355018 220-066 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 50-029-22609-01-00 Hilcorp Alaska LLC Kuparuk Oil Pool N/A C.O. 432E MP F-62A Length Size Proposed Pools: 112' 112' TVD Burst PRESENT WELL CONDITION SUMMARY 7,445' 2,356' 7,350' 1,926 N/A 112' 20" Milne Point Unit MD N/A 5,750psi 7,240psi 4,484' 7,428' 5,942' 10,093' Perforation Depth MD (ft): 9-5/8" 7" 5,942' 10,093' Form 10-403 Revised 10/2022 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov Digitally signed by David Haakinson (3533) DN: cn=David Haakinson (3533), ou=Users Date: 2022.12.01 09:12:14 -09'00' David Haakinson (3533) SFD 12/1/2022 10-404 2569 MGR08DEC2022 BOPE test to 3000 psi. Annular to 2500 psi. DSR-12/1/22JLC 12/8/2022 Gregory Wilson Digitally signed by Gregory Wilson Date: 2022.12.09 15:45:37 -09'00' RBDMS JSB 121222 ESP Swap Well: MPU F-62A Date: 11/30/2022 Well Name:MPU F-62A API Number:50-029-22609-01-00 Current Status:Oil Well [Failed ESP]Pad:F-Pad Estimated Start Date:December 15, 2022 Rig:ASR 1 Yes Regulatory Contact:Tom Fouts Permit to Drill Number:220-066 First Call Engineer:Taylor Wellman (907) 777-8449 (O)(907) 947-9533 (M) Second Call Engineer:Todd Sidoti (907) 777-8443 (O)(907) 632-4113 (M) Current Bottom Hole Pressure: 3,253 psi @ 6,840 (F-62A SBHPS 11/30/22 / 9.14 ppg EMW) Maximum Expected BHP: 3,253 (F-62A SBHPS 11/30/22 / 9.14 ppg EMW) MPSP: 1,926 psi (0.1 psi/ft gradient to surface) Brief Well Summary: MPU F-62A was drilled and completed as a Kuparuk A and C sand producer in Q4 2020. A fracture stimulation of the A-sand was completed in December 2020 and the well was produced as a reverse circulating jet pump producer. The tubing developed leaks and a workover in January 2022 was performed and the well was converted to an ESP producer. During a power bump and hard shutdown in October 2022 the ESP failed electrically downhole. Notes Regarding Wellbore Condition A passing CMIT- Tx down . Objective: Pull failed ESP / Run new ESP Completion Pre-Rig Procedure: 1. Clear and level pad area in front of well. Spot rig mats and containment. 2. RD well house and flowlines. Clear and level area around well. 3. RU Little Red Services. RU reverse out skid and 500 bbl returns tank. 4. Pressure test lines to 3,000 psi. 5. Circulate at least one wellbore volume with produced water down tubing, taking returns up IA to 500 bbl returns tank. 6. Confirm well is dead. Contact the operations engineer if freeze protection is needed depending on ASR arrival. 7. RD Little Red Services and reverse out skid. 8. Set BPV. ND tree. Brief RWO Procedure: 1. MIRU ASR, ancillary equipment and lines. 2. Check for pressure and if 0 psi. If needed, bleed off any residual pressure off tubing and casing. If needed, kill well w/ produced water or source water. Set CTS Plug. December 6, 2022 2569 psi mgr / 9.14 ppg EMW) ESP Swap Well: MPU F-62A Date: 11/30/2022 3. NU BOPE. 4. Test BOP to 250/2,500 psi for 5/5 min. Test annular to 250/2,500 psi for 5/5 min. a. Notify the AOGCC 24 hours in advance of BOP test. b. Test upper 2-7/8 5 2-7/8 and 3- test joints. c. Confirm test pressures with Approved Sundry. d. Ensure to monitor side outlet valves and annulus valve pressure gauges to ensure no pressure is trapped underneath test plug. e. Once BOPE test is complete, send a copy of the test report (10-424 form) to AOGCC and town engineer. 5. Bleed any pressure off casing to the returns tank. Pull CTS plug and BPV. Kill well with produced water or source water as needed. 6. MU landing joint or spear and PU on the tubing hanger. a. Wait 30 minutes after releasing packer to allow element to relax prior to pulling. b. The current completion was landed with PUW of 77K and 34K slack off wt. c. RU spooler to be able to handle an ESP cable and control line. 7. Recover the tubing hanger. 8. POOH and lay down the 2-7/8 Number all joints. Tubing will be re-ran unless damage or other observations are seen while pulling. Lay down failed ESP. a. A caliper run on 10/12/2022 indicated all joints to have penetrations <18%. b. Continue to load well during POOH to minimize chances for well to swap. c. Pull out all visually bad joints and mark for disposal. d. Look for over-torqued connections from previous tubing runs and junk them. e. All clamps and jewelry will be cleaned and put into inventory for re-use. f. All cable is to be salvaged and sent to Baker for inspection and testing for possible re-use. 166 Cross collar clamps 7 Protectolizer Clamps 3 Pump Bands 9. RU dual spooling units (ESP cable, control line for packer vent) and run new 2-7/8 ESP Completion. a. b. Make sure control line is full of hydraulic fluid when calling it out. c. Test vent valve when packer is made up to control line at surface. Risk assess if pressure under BPV. Lubricate BPV if necessary. mgr 3000 ESP Swap Well: MPU F-62A Date: 11/30/2022 Nom. Size ~Length Item Lb/ft Material Notes 5-5/8'' 102' Baker ESP Assembly 2-7/8'' 10' Pup Joint 6.4 L-80 2-7/8'' 1 joint 6.4 L-80 2-7/8'' 10' Pup Joint 6.4 L-80 2-7/8'' XN Nip with RHC profile 6.4 L-80 RHC Plug Installed 2-7/8'' 10' Pup Joint 6.4 L-80 2-7/8'' 3 joints 6.4 L-80 2-7/8'' 10' Pup Joint 6.4 L-80 2-7/8'' 2 7/8" Side-pocket GLM 6.4 L-80 Dummy GLV Installed 2-7/8'' 10' Pup Joint 6.4 L-80 2-7/8'' Joints 6.4 L-80 2-7/8'' 10' Pup Joint 6.4 L-80 2-7/8'' - 6.4 L-80 Tripoint vented set ±2600' MD 2-7/8'' 10' Pup Joint 6.4 L-80 2-7/8'' Joints 6.4 L-80 2-7/8'' 10' Pup Joint 6.4 L-80 2-7/8'' 2 7/8" Side-pocket GLM 6.4 L-80 OV installed 2-7/8'' 10' Pup Joint 6.4 L-80 2-7/8'' Joints 6.4 L-80 2-7/8'' Pup Joint 6.4 L-80 2-7/8'' Tubing Hanger 6.4 L-80 10. Terminate control line and ESP cable. Land hanger and RILDS. Lay down landing joint. Note PU and SO weights on tally. 11. Drop ball and rod and hydraulically set the packer as per manufacturers setting procedure. 12. Perform MIT-T to 3000 psi for 30 minutes charted. 13. Perform MIT-IA to 1500 psi for 30 minutes charted. 14. Set BPV. 15. RDMO ASR. Post-Rig Procedure (Non-Sundried steps): Well Support 1. RD mud boat. Move to next well location. 2. RU crane. ND BOPE. Set CTS plug. 3. NU tree and tubing head adapter. 4. Test both tree and tubing hanger void to 500psi low/5,000psi high. 5. Pull CTS plug & BPV. ESP Swap Well: MPU F-62A Date: 11/30/2022 6. RD crane. Move 500 bbl returns tank and rig mats to next well location. 7. Replace gauge(s) if removed. 8. Turn well over to production. RU well house and flowlines. Slickline 1. MIRU slickline. 2. Pressure test lubricator to 300psi low and 2,800psi high. 3. Pull ball and rod. 4. Pull RHC plug. RDMO. Attachments: 1. As-built Schematic 2. Proposed Schematic 3. BOPE Schematic _____________________________________________________________________________________ Revised By: TDF 10/13/2022 SCHEMATIC Milne Point Unit Well: MPU F-62A Last Completed: 1/24/2022 PTD: 220-066 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20" Conductor 91.1 / NT80LHE / N/A N/A Surface 112’ 9-5/8" Surface 40 / L-80 / BTC 8.835 Surface 5,942’ 7" Production 26 / L-80 / BTC 6.276 Surface 10,093’ TUBING DETAIL 2-7/8” Tubing 6.4 / L-80 / EUE 8rd 2.441 Surface 9,560’ 4-1/2" Tubing 13.5 / L-80 / Hyd 625 3.920 9,605’ 9,740’ JEWELRY DETAIL No Depth Item 1 195’ Sta 2: GLM 2.875 x 1" w/ 0.25 OV 2 2,607’ Tri-point 7"x 2 7/8" Ret. packer with vent valve 3 9,295’ Sta 1: GLM 2-7/8” x 1" w/ Dummy Valve 4 9,416’ 2-7/8” XN- Nipple (2.313” No-Go ID) 5 9,467’ Discharge Head: 538PMSXD FLEX27 82 FER H6 6 9,469’ Pump #3: PMP 538PMSXD FLEX27 82 FER H6 7 9,486’ Pump #2: 538PMSXD FLEX27 82 FER H6 8 9,504’ Pump #1: 538PMSXD 20 GINPSHH H6 9 9,514’ Gas Separator: 538GSTHVEVX MT H6 FER 10 9,519’ Upper Tandem Seal Section: GSBDB H6 SB/AB PFSA 11 9,526’ Lower Tandem Seal Section: GSBDB H6 SB/AB PFSA 12 9,533’ Motor: 562XP 350/2440/88_292/2030 14R 13 9,555’ Motor Gauge w/ Centralizer – Btm @ 9,560’ 14 9,622’ Baker Premier Retrievable Packer 15 9,688’ 4-1/2” XN-Nipple (3.725” No-Go) 16 9,739’’ Mule Shoe – Btm at 9,740’ PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status Kuparuk C/B7 9,790’ 9,816’ 7,146’ 7,170’ 26 12-8-2020 OPEN Kuparuk B Silts 9,823’ 9,833' 7,175' 7,185' 10 1/15/2022 OPEN Kuparuk A2 9,879’ 9,889’ 7,228’ 7,237’ 10 11/19/2020 OPEN Kuparuk A1B 9,922’ 9,951’ 7,268’ 7,295’ 29 1/15/2022 OPEN Ref Log; 10/7/95 SBT / GR / CCL. 32 gm Alpha Jet charges (EHD-0.50”, TTP=32.0”) @ 135 / 45 deg. phasing OPEN HOLE / CEMENT DETAIL 20" 260 sx of Arcticset (Approx.) in 24” Hole 9-5/8" 1,160 sx PF “C”, 250 sx Class “G”, 250 sx PF ‘E in 12-1/4” Hole 7” 265 sx Class “G” 15.8 ppg in 8-1/2” Hole WELL INCLINATION DETAIL KOP @ 1,000 Max Hole Angle = 66 deg. Hole Angle through perforations = 42 deg. TREE & WELLHEAD Tree 4-1/16” – 5M Cameron NS Wellhead FMC 11” 5M FMC Gen 5 w/ 11” FMC Tubing Hanger, 3.5” NSCT Lift Threads and 3” CIW H BPV Profile Tubing Hanger 4-1/2” GENERAL WELL INFO API: 50-029-22609-01-00 Completed: 11/20/2020 – Doyon 14 Convert to ESP 1/24/2022 - ASR TD =10,112’(MD) / TD = 7,445’(TVD) 20” Orig.DF Elev.: 45.70’/ GL Elev.: 12.0’ Nabors 22E 7” 5 9 12 13 16 9-5/8” 1 3 15 PBTD =10,010’ (MD) / PBTD = 7,350’(TVD) 4 10 &11 Top of Tubing 9,605’MD 6, 7 & 8 14 2 _____________________________________________________________________________________ Revised By: TDF 11/30/2022 PROPOSED Milne Point Unit Well: MPU F-62A Last Completed: 1/24/2022 PTD: 220-066 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20" Conductor 91.1 / NT80LHE / N/A N/A Surface 112’ 9-5/8" Surface 40 / L-80 / BTC 8.835 Surface 5,942’ 7" Production 26 / L-80 / BTC 6.276 Surface 10,093’ TUBING DETAIL 2-7/8” Tubing 6.4 / L-80 / EUE 8rd 2.441 Surface ±9,560’ 4-1/2" Tubing 13.5 / L-80 / Hyd 625 3.920 9,605’ 9,740’ JEWELRY DETAIL No Depth Item 1 ±195’ Sta 2: GLM 2.875 x 1" w/ 0.25 OV 2 ±2,607’ Tri-point 7"x 2 7/8" Ret. packer with vent valve 3 ±9,295’ Sta 1: GLM 2-7/8” x 1" w/ Dummy Valve 4 ±9,416’ 2-7/8” XN- Nipple (2.313” No-Go ID) 5 ±9,467’ Discharge Head: 6 ±9,469’ Pump #3: 7 ±9,486’ Pump #2: 8 ±9,504’ Pump #1: 9 ±9,514’ Gas Separator: 10 ±9,519’ Upper Tandem Seal Section: 11 ±9,526’ Lower Tandem Seal Section: 12 ±9,533’ Motor: 13 ±9,555’ Motor Gauge w/ Centralizer – Btm @ ±9,560’ 14 9,622’ Baker Premier Retrievable Packer 15 9,688’ 4-1/2” XN-Nipple (3.725” No-Go) 16 9,739’’ Mule Shoe – Btm at 9,740’ PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status Kuparuk C/B7 9,790’ 9,816’ 7,146’ 7,170’ 26 12-8-2020 OPEN Kuparuk B Silts 9,823’ 9,833' 7,175' 7,185' 10 1/15/2022 OPEN Kuparuk A2 9,879’ 9,889’ 7,228’ 7,237’ 10 11/19/2020 OPEN Kuparuk A1B 9,922’ 9,951’ 7,268’ 7,295’ 29 1/15/2022 OPEN Ref Log; 10/7/95 SBT / GR / CCL. 32 gm Alpha Jet charges (EHD-0.50”, TTP=32.0”) @ 135 / 45 deg. phasing OPEN HOLE / CEMENT DETAIL 20" 260 sx of Arcticset (Approx.) in 24” Hole 9-5/8" 1,160 sx PF “C”, 250 sx Class “G”, 250 sx PF ‘E in 12-1/4” Hole 7” 265 sx Class “G” 15.8 ppg in 8-1/2” Hole WELL INCLINATION DETAIL KOP @ 1,000 Max Hole Angle = 66 deg. Hole Angle through perforations = 42 deg. TREE & WELLHEAD Tree 4-1/16” – 5M Cameron NS Wellhead FMC 11” 5M FMC Gen 5 w/ 11” FMC Tubing Hanger, 3.5” NSCT Lift Threads and 3” CIW H BPV Profile Tubing Hanger 4-1/2” GENERAL WELL INFO API: 50-029-22609-01-00 Completed: 11/20/2020 – Doyon 14 Convert to ESP 1/24/2022 - ASR TD =10,112’(MD) / TD = 7,445’(TVD) 20” Orig.DF Elev.: 45.70’/ GL Elev.: 12.0’ Nabors 22E 7” 5 9 12 13 16 9-5/8” 1 3 15 PBTD =10,010’ (MD) / PBTD = 7,350’(TVD) 4 10 &11 Top of Tubing 9,605’MD 6, 7 & 8 14 2 Updated 8/11/2020 Milne Point ASR Rig 1 BOPE 2022 11” BOPE 4.4 8' 4.5 4' 2.00' CIW-U 4 30'Hydril GK4.30'4.30' 11" - 5000 VBR or Pipe Rams Blin d11'’- 5000 DSA, 11 5M X 7 1/16 5M (If Needed) 2 1/16 5M Kill Line Valves 2 1/16 5M Choke Line Valves HCRManualManualHCR Stripping Head 2VBVBBRBR7/8” x 5” VBRRorPipeRamsRorPipeRams Kyle Wiseman Hilcorp Alaska, LLC Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: Kyle.Wiseman@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 11/4/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20221104 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# MPU H-18 50029232240000 204174 10/2/2022 READ COILFLAG MPU F-01 50029225520000 195045 10/9/2022 READ CaliperSurvey MPU F-62A 50029226090100 220066 10/12/2022 READ CaliperSurvey MPU B-35 50029237240000 222085 10/17/2022 READ CaliperSurvey Please include current contact information if different from above. T37230 T37231 T27239 T37232 MPU F-62A 50029226090100 220066 10/12/2022 READ CaliperSurvey Kayla Junke Digitally signed by Kayla Junke Date: 2022.11.07 16:21:15 -09'00' Kaitlyn Barcelona Hilcorp North Slope, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 564-4389 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: DATE: 2/15/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU F-62A (PTD 220-066) Jet Cut 01/20/2022 Please include current contact information if different from above. 37' (6HW Received By: 02/15/2022 By Abby Bell at 11:42 am, Feb 15, 2022 Kaitlyn Barcelona Hilcorp North Slope, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 564-4389 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: DATE: 1/31/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU F-62A (PTD 220-066) Perf 01/15/2022 Please include current contact information if different from above. 37' (6HW Received By: 02/07/2022 By Abby Bell at 3:46 pm, Feb 04, 2022 CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Rixse, Melvin G (OGC) To:AOGCC Records (CED sponsored) Subject:FW: MPU F-62A (PTD 220-066) Approved Sundry 321-597: Updated BHP and Plans to Run ESP Packer Date:Tuesday, January 25, 2022 7:18:37 PM From: Rixse, Melvin G (OGC) Sent: Sunday, January 16, 2022 10:02 PM To: Taylor Wellman <twellman@hilcorp.com> Subject: Re: MPU F-62A (PTD 220-066) Approved Sundry 321-597: Updated BHP and Plans to Run ESP Packer Taylor, Approved for the changes you listed. Mel Rixse On Jan 16, 2022, at 8:21 PM, Taylor Wellman <twellman@hilcorp.com> wrote: Mel, We have recently gotten an updated BHP from the downhole gauge installed in MPU F- 62A and determined that the reservoir pressure has increased above an 8.55ppg gradient. The updated BHP is: Current BHP: 3,403psi @ 6,940’ tvd (Downhole Gauge Pressure Reading – 9.43ppg MWE) MPSP: 2,709ps (Gas Column Gradient -0.1psi/ft) As per the COA’s written and as it will change some aspects to the workover, we are notifying you of this development. The changes to the workover are as follows: Increase the BOP High Test pressure to 2,800psi Increase the KWF to be used to 9.6ppg Proposed ESP completion to be run to include an ESP packer set at ±2,600’ md If you see any issue with this course of action please let me know or if you would like any additional information this can be provided as well. Thank you, Taylor Taylor Wellman Hilcorp Alaska, LLC – Ops Engineer: Milne Point Office: (907) 777-8449 Cell: (907) 947-9533 Email: twellman@hilcorp.com 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: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Rixse, Melvin G (OGC) To:Taylor Wellman Cc:AOGCC Records (CED sponsored) Subject:20220113 0813 APPROVAL CANCEL REVISION 2 - REVERT TO ORIGINAL Sundry 321-597 MPU F-62A (PTD 220- 066) Date:Thursday, January 13, 2022 8:15:53 AM Taylor, Hilcorp is approved to cancel sundry revision 2 and revert to the original approved Sundry 321-597 as you described below. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-223-3605 Cell CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). From: Taylor Wellman <twellman@hilcorp.com> Sent: Wednesday, January 12, 2022 4:15 PM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Subject: RE: [EXTERNAL] 20220107 1355 APPROVAL REVISION 2 Sundry 321-597 MPU F-62A (PTD 220-066) Mel, I’m extremely sorry to ask for another revision/reverting to previous version on this well. The decomplete of the well had been stalled out and I didn’t feel that we would be able to pull the nipple reducer without the use of coil (which you are well aware of the status there). We gave it one more attempt with SL and were recover the nipple reducer from the well through the swedged out collapse point. With that we will be able to perform the perfs pre-rig. I would like to revert to the originally approved sundry 321-597 as our baseplan for operations. We will use the corrected tubing cut depth as you noted on the approved sundry. If you see any issue with this or would like me to send a copy of this across please let me know. Thank you, 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. Taylor Taylor Wellman Hilcorp Alaska, LLC – Ops Engineer: Milne Point Office: (907) 777-8449 Cell: (907) 947-9533 Email: twellman@hilcorp.com From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Sent: Friday, January 7, 2022 2:01 PM To: Taylor Wellman <twellman@hilcorp.com> Subject: [EXTERNAL] 20220107 1355 APPROVAL REVISION 2 Sundry 321-597 MPU F-62A (PTD 220- 066) Taylor, Hilcorp is approved perform work under Sundry 321-597 Revision 2 as per the attached document. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-223-3605 Cell CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). From: Taylor Wellman <twellman@hilcorp.com> Sent: Thursday, January 6, 2022 9:32 PM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Subject: RE: [EXTERNAL] FW: MPU F-62A (PTD 220-066) Approved Sundry 321-597 Procedural Reordering of Steps Mel, Thank you for call to talk about this well. Enclosed is the revised procedure with the steps outlined below included. Please let me know if you there is any wording there that needs to be amended. Thank you, Taylor Taylor Wellman Hilcorp Alaska, LLC – Ops Engineer: Milne Point Office: (907) 777-8449 Cell: (907) 947-9533 Email: twellman@hilcorp.com From: Taylor Wellman Sent: Wednesday, January 5, 2022 4:57 PM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Subject: RE: [EXTERNAL] FW: MPU F-62A (PTD 220-066) Approved Sundry 321-597 Procedural Reordering of Steps Mel, Thank you for the review and call on this. While reviewing all the details on this portion of the procedure with the field crews we came up with an alternative which should provide additional risk reduction for this specific well and scope of work. Landing the workstring on a hanger and then bolt a shooting flange on top of the BOP’s vs. closing the bag and the pipe rams. Landing will allow us to install a BPV and conversion plug (making the BPV into a TWC) to test the wireline PCE against. At the risk of overcommunicating one other piece I wanted to highlight was the PCE that I would like to plan for the EL portion. PCE in order of bottom up: ASR BOP Stack, Shooting Flange/riser, wireline valves, short section of lubricator, head catcher for toolstring, packoff. The lubricator section is not planned to be long enough for the full recovery of the toolstring if there is pressure seen from the new perfs. The reasoning is that the ASR mast height limits the amount of lubricator able to be used else requiring a crane to hold the lubricator above the rig. If there is an increased reservoir pressure from the new perforations: This will be observed by monitoring the IA pressure (direct TxIA communication through ported holes just above the overshot). All pressure will be within a pressure tested system to 2,500psi. Primary way to regain fluid barrier: Circulate in a higher fluid weight until the well is dead. Fluid path is down tbg and up the IA, thru ported holes just above overshot. Toolstring location during pumping can either be out of the tubing tail (limited risk of pumping tools off of weak point) or with the toolstring caught in the head catcher (also preventing pumping breaking the weakpoint). If there was another leak/circumstance that could not be isolated by the wireline valves, we can use the blind rams to close on the wire and then continue with circulating well is dead. Once well is confirmed dead, we will break at the quick test union and recover the toolstring 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. and RD EL. If you have any questions on this course of action please let me know and don’t hesitate to call. Thank you, Taylor Taylor Wellman Hilcorp Alaska, LLC – Ops Engineer: Milne Point Office: (907) 777-8449 Cell: (907) 947-9533 Email: twellman@hilcorp.com From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Sent: Saturday, January 1, 2022 12:28 PM To: Taylor Wellman <twellman@hilcorp.com> Subject: [EXTERNAL] FW: MPU F-62A (PTD 220-066) Approved Sundry 321-597 Procedural Reordering of Steps Taylor, Revision 1 (attached) is approved. As discussed on the phone, drill pipe will have pressure containment with the annular and pipe rams closed when working through drill pipe with slickline and eline. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-223-3605 Cell CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). From: Taylor Wellman <twellman@hilcorp.com> Sent: Saturday, January 1, 2022 8:57 AM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Subject: MPU F-62A (PTD 220-066) Approved Sundry 321-597 Procedural Reordering of Steps Mel, For well MPU F-62A there is a workover planned to add perforations to the well and convert from a jet pump well to an ESP producer. This work is approved under Sundry 321-597. The decomplete of the well has been complicated due to partially collapsed tubing and trying to retrieve a nipple reducer from the well. Our attempts to recover with slickline have stalled out. With that I would like to re-order the steps in the procedure to move the fishing of the nipple reducer and perforating pre-rig to do this with the rig on the well. The reasoning is that the rig needs to pull the tubing (with the partially collapsed section) to be able to access this section of the well. Note the revised procedure includes the comments you previously wrote the approved sundry (thank you for the depth on tbg cut location). If you see any issue with this course of action please let me know and I can provide additional details or whatever is needed. Thank you, Taylor Taylor Wellman Hilcorp Alaska, LLC – Ops Engineer: Milne Point Office: (907) 777-8449 Cell: (907) 947-9533 Email: twellman@hilcorp.com The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 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 responsibilityis 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: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Rixse, Melvin G (OGC) To:Taylor Wellman Subject:20220107 1355 APPROVAL REVISION 2 Sundry 321-597 MPU F-62A (PTD 220-066) Date:Friday, January 7, 2022 2:00:44 PM Attachments:MPU F-62A Conv JP to ESP Rev 01-06-2022.docx Taylor, Hilcorp is approved perform work under Sundry 321-597 Revision 2 as per the attached document. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-223-3605 Cell CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). From: Taylor Wellman <twellman@hilcorp.com> Sent: Thursday, January 6, 2022 9:32 PM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Subject: RE: [EXTERNAL] FW: MPU F-62A (PTD 220-066) Approved Sundry 321-597 Procedural Reordering of Steps Mel, Thank you for call to talk about this well. Enclosed is the revised procedure with the steps outlined below included. Please let me know if you there is any wording there that needs to be amended. Thank you, Taylor Taylor Wellman Hilcorp Alaska, LLC – Ops Engineer: Milne Point Office: (907) 777-8449 Cell: (907) 947-9533 Email: twellman@hilcorp.com From: Taylor Wellman Sent: Wednesday, January 5, 2022 4:57 PM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Subject: RE: [EXTERNAL] FW: MPU F-62A (PTD 220-066) Approved Sundry 321-597 Procedural Reordering of Steps Mel, Thank you for the review and call on this. While reviewing all the details on this portion of the procedure with the field crews we came up with an alternative which should provide additional risk reduction for this specific well and scope of work. Landing the workstring on a hanger and then bolt a shooting flange on top of the BOP’s vs. closing the bag and the pipe rams. Landing will allow us to install a BPV and conversion plug (making the BPV into a TWC) to test the wireline PCE against. At the risk of overcommunicating one other piece I wanted to highlight was the PCE that I would like to plan for the EL portion. PCE in order of bottom up: ASR BOP Stack, Shooting Flange/riser, wireline valves, short section of lubricator, head catcher for toolstring, packoff. The lubricator section is not planned to be long enough for the full recovery of the toolstring if there is pressure seen from the new perfs. The reasoning is that the ASR mast height limits the amount of lubricator able to be used else requiring a crane to hold the lubricator above the rig. If there is an increased reservoir pressure from the new perforations: This will be observed by monitoring the IA pressure (direct TxIA communication through ported holes just above the overshot). All pressure will be within a pressure tested system to 2,500psi. Primary way to regain fluid barrier: Circulate in a higher fluid weight until the well is dead. Fluid path is down tbg and up the IA, thru ported holes just above overshot. Toolstring location during pumping can either be out of the tubing tail (limited risk of pumping tools off of weak point) or with the toolstring caught in the head catcher (also preventing pumping breaking the weakpoint). If there was another leak/circumstance that could not be isolated by the wireline valves, we can use the blind rams to close on the wire and then continue with circulating well is dead. Once well is confirmed dead, we will break at the quick test union and recover the toolstring and RD EL. If you have any questions on this course of action please let me know and don’t hesitate to call. Thank you, Taylor Taylor Wellman Hilcorp Alaska, LLC – Ops Engineer: Milne Point 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. Office: (907) 777-8449 Cell: (907) 947-9533 Email: twellman@hilcorp.com From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Sent: Saturday, January 1, 2022 12:28 PM To: Taylor Wellman <twellman@hilcorp.com> Subject: [EXTERNAL] FW: MPU F-62A (PTD 220-066) Approved Sundry 321-597 Procedural Reordering of Steps Taylor, Revision 1 (attached) is approved. As discussed on the phone, drill pipe will have pressure containment with the annular and pipe rams closed when working through drill pipe with slickline and eline. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-223-3605 Cell CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). From: Taylor Wellman <twellman@hilcorp.com> Sent: Saturday, January 1, 2022 8:57 AM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Subject: MPU F-62A (PTD 220-066) Approved Sundry 321-597 Procedural Reordering of Steps Mel, For well MPU F-62A there is a workover planned to add perforations to the well and convert from a jet pump well to an ESP producer. This work is approved under Sundry 321-597. The decomplete of the well has been complicated due to partially collapsed tubing and trying to retrieve a nipple reducer from the well. Our attempts to recover with slickline have stalled out. With that I would like to re-order the steps in the procedure to move the fishing of the nipple reducer and perforating pre-rig to do this with the rig on the well. The reasoning is that the rig needs to pull the tubing (with the partially collapsed section) to be able to access this section of the well. Note the revised procedure includes the comments you previously wrote the approved sundry (thank you for the depth on tbg cut location). If you see any issue with this course of action please let me know and I can provide additional details or whatever is needed. Thank you, Taylor Taylor Wellman Hilcorp Alaska, LLC – Ops Engineer: Milne Point Office: (907) 777-8449 Cell: (907) 947-9533 Email: twellman@hilcorp.com The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 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. Convert JP to ESP Well: MPU F-62A Revision – 01/06/2022 Date: 11/15/2021 Well Name: MPU F-62A API Number: 50-029-22609-01-00 Current Status: Oil Well [Tbg Leaks] Pad: F-Pad Estimated Start Date: November 28, 2021 Rig: ASR 1 Reg. Approval Req’d? Yes Date Reg. Approval Rec’vd: Regulatory Contact: Tom Fouts Permit to Drill Number: 220-066 First Call Engineer: Taylor Wellman (907) 777-8449 (O) (907) 947-9533 (M) Second Call Engineer: David Gorm (907) 777-8333 (O) (505) 215-2819 (M) Current Bottom Hole Pressure: 2,936 psi @ 6,940 TVD Downhole Gauge (11/11/2021) | 8.14 PPG Maximum Expected BHP: 3,050 psi @ 6,940’ TVD Normally pressured Kup Bsilts/A1B adperfs | 8.45 PPG MPSP: 2,356 psi Gas Column Gradient (0.1 psi/ft) Brief Well Summary: MPU F-62A was drilled and completed as a Kuparuk A and C sand producer in Q4 2020. A fracture stimulation of the A-sand was completed in December 2020 and the well has been producing as a jet pump producer. On 9/20/2021, the well was shut in after the power fluid rate was found to be increasing. Subsequent testing identified a leak in the tubing. A patch was set across this hole and the well returned to production for 3 days before another hole formed. A caliper indicates that corrosion has led to high wall loss and multiple penetrations in the tubing. A workover to convert the well to ESP production is being planned. Notes Regarding Wellbore Condition • CO 390A: A packer is not required on this ESP completion as the current reservoir pressure of 8.2 ppg and the anticipated additional perfs in the are normally pressured at 8.45 ppg EMW. Both are less than 8.55 ppg EMW. • A passing C-MITIA to 3,500 psig was completed on 9/24/2021 confirming integrity of the 7” IA and production packer. • A caliper run on 11/10/2021 indicates multiple holes, multiple joints with 30-40% wall loss and one spot of partially collapsed tubing. The tubing has been swedged out to ~3.80” ID. • The tubing patch was pulled from 5,396’-5,434’ md. The nipple reducer from 9,559’ md had the lock opened and then pushed down to sit on the XN nipple at 9,688’ md. • Offset Injector Support o L-15: Shut in Objective: 1. Add Perforations to the Kuparuk Bsilts and the A1B. 2. Cut the tubing above the packer and recover all tubing. 3. Run new ESP completion. Convert JP to ESP Well: MPU F-62A Revision – 01/06/2022 Date: 11/15/2021 Pre-Rig Procedure: 1. RU EL and pressure test PCE to 250psi low / 2,500psi high. 2. RIH w/ jet cutter and cut tubing at ±9,608’ md (1st full joint above the packer). a. Reference: Tubing tally dated 11/20/2020. b. XN nipple at 9,688’ md may be used for correlation. c. Before leaving location, confirm that Baker Centrilift can reconnect to the DH gauge and confirm BHP. If not, a BHP run may be required based on timing between now and the rig arrival. Contact Operations Engineer with results to see if a higher MPSP is observed. 3. Clear and level pad area in front of well. Spot rig mats and containment. 4. RD well house and flowlines. Clear and level area around well. 5. RU Little Red Services. RU reverse out skid and 500 bbl returns tank. 6. Pressure test lines to 3,000 psi. 7. Circulate at least one wellbore volume with 3% KCl water down tubing, taking returns up casing to 500 bbl returns tank. a. Partial returns will probably be seen. After attempting circulation down the tubing, load the IA. 8. Confirm well is dead. Contact the operations engineer if freeze protection is needed depending on ASR arrival. 9. RD Little Red Services and reverse out skid. 10. RU crane. Set BPV. ND Tree. NU BOPE. RD Crane. 11. NU BOPE house. Spot mud boat. Brief RWO Procedure: 12. MIRU Hilcorp ASR #1 WO Rig, ancillary equipment and lines. 13. Check for pressure and if 0 psi pull BPV. If needed, bleed off any residual pressure off tubing and casing. If needed, kill well w/ 3% KCl prior to pulling BPV. Set plug to convert BPV to TWC. 14. Test BOPE to 250 psi Low/ 2,500 psi High, annular to 250 psi Low/ 2,500 psi High (hold each ram/valve and test for 5-min). Record accumulator pre-charge pressures and chart tests. a. Perform Test per ASR 1 BOP Test Procedure b. Notify AOGCC 24 hours in advance of BOP test. c. Confirm test pressures per the Sundry Conditions of approval. d. Test VBR rams on 2-7/8” and 4-1/2” test joints. e. Submit to AOGCC completed 10-424 form within 5 days of BOPE test. 15. Contingency: (If the tubing hanger won’t pressure test due to either a penetrator leak or the BPV profile is eroded and/or corroded and BPV cannot be set with tree on.) a. Notify Operations Engineer (Hilcorp), Mr. Mel Rixse (AOGCC) and Mr. Jim Regg (AOGCC) via email explaining the wellhead situation prior to performing the rolling test. AOGCC may elect to send an inspector to witness test. b. With stack out of the test path, test choke manifold per standard procedure c. Conduct a rolling test: Test the rams and annular with the pump continuing to pump, (monitor the surface equipment for leaks to ensure that the fluid is going down-hole and not leaking anywhere at surface.) Convert JP to ESP Well: MPU F-62A Revision – 01/06/2022 Date: 11/15/2021 d. Hold a constant pressure on the equipment and monitor the fluid/pump rate into the well. Record the pumping rate and pressure. e. Once the BOP ram and annular tests are completed, test the remainder of the system following the normal test procedure (floor valves, gas detection, etc.) f. Record and report this test with notes in the remarks column that the tubing hanger/BPV profile / penetrator wouldn’t hold pressure and rolling test was performed on BOP Equipment and list items, pressures and rates. 16. Bleed any pressure off casing to the returns tank. Pull plug and BPV. Kill well with 3% KCl as needed. 17. RU spooling unit for Techwire. MU landing joint and recover the tubing hanger. a. The PU weight during the 2020 completion was 142k lbs (block wt = 40k lbs). Slack off weight = 102k lbs and 62k lbs set on the hanger. b. If needed, circulate (long or reverse) pill with lubricant prior to laying down the tubing hanger. Contingency (If a rolling test was conducted): MU new hanger or test plug to the completion tubing. Re-land hanger (or test plug) in tubing head. Test BOPE per standard procedure. 18. POOH and lay down the 4-1/2” tubing. Number all joints. a. All joints are to be junked except the following: 40, 80, 100, and 220. Sections of these joints are to be cut and saved for chemical analysis to confirm hypothesized corrosion mechanism. b. Note that casing crew will be required for pulling the 4-1/2” completion. The torque values for 4-1/2” Hyd 625 are: 8,000 min/9,600 opt/12,000 max ft/lb for makeup. c. 125 Cannon Cross Collar Clamps were installed with the completion for the Techwire for the downhole gauges. 19. PU 4-1/2” workstring and TIH to overshot tbg stub at 9,608’ md. 20. Land 4-1/2” workstring in tubing hanger and RIH LDS. 21. RU shooting flange to the top of the annular. Set BPV and set CTS plug. 22. RU SL and pressure test PCE to 250psi low / 2,500psi high. 23. Pull CTS plug and BPV. 24. RIH and retrieve the nipple reducer sitting on the XN nipple at 9,688’ md. a. The lock has been opened and pushed down to sit on the XN nipple. 25. RD SL and RU EL. Set BPV and CTS plug and pressure test PCE to 250psi low / 2,500psi high. 26. Pull CTS plug and BPV. 27. MU 2-7/8”-3-1/8”, 6-12spf guns and perforate as per the following table: Zone Sand Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Kuparuk B silts ±9,823’ ±9,833' ±7,175' ±7,185' 10' Kuparuk A1B ±9,922’ ±9,951' ±7,268’ ±7,295' 29' a. Monitor well and check for if WHP is 0psi and current KWF is sufficient. i. If WHP is 0psi, RD EL and remove shooting flange. Convert JP to ESP Well: MPU F-62A Revision – 01/06/2022 Date: 11/15/2021 ii. If needed, circulate in new KWF down tubing and up IA until well is dead and RD EL. EL toolstring to be located either below tubing tail or held in head catcher during circulation to prevent breaking weakpoint due to pumping operation. 28. Back out LDS, pull hanger to floor and TOOH w/ and lay down the 4-1/2” workstring. 29. PU new ESP and RIH on 2-7/8” 6.5# L-80 tubing. Check electrical connections every 2,000’ a. Base of ESP at ± 9,550’ MD a. Chemical injection diffuser along the centralizer. b. 1 joints of 2-7/8”, 6.5#, L-80, EUE 8rd tubing c. 2-7/8” XN (2.205” No-Go) Nipple d. 3-4 joints of 2-7/8”, 6.5#, L-80, EUE 8rd tubing e. Lower 2-7/8”x 1” Side-pocket GLM with Dummy GLV f. Mulitple joints 2-7/8”, 6.5#, L-80, EUE 8rd tubing g. Upper 2-7/8”x 1” Side-pocket GLM @ ± 200’ MD with 0.25” OV h. ± 5 joints 2-7/8”, 6.5#, L-80, EUE 8rd tubing 30. Land tubing hanger (Caution not to Damage Cable while landing the hanger). Lay down landing joint. Note PU (Pick Up) and SO (Slack Off) weights on tally. 31. Set BPV. Post-Rig Procedure: 1. RD mud boat. RD BOPE house. Move to next well location. 2. RU crane. ND BOPE. 3. NU existing 2-9/16” 5,000# tree/adapter flange. Test tubing hanger void to 500 psi low/5,000 psi high. Pull BPV. 4. RD crane. Move 500 bbl returns tank and rig mats to next well location. 5. Replace gauge(s) if removed. 6. Turn well over to production. RU well house and flowlines. Attachments: 1. As-built Schematic 2. Proposed Schematic 3. BOPE Schematic CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Rixse, Melvin G (OGC) To:AOGCC Records (CED sponsored) Subject:20211208 1615 APPROVAL (PTD220-066) Modification to Sundry 321-597 MPU F-62A (PTD 220-066) Approved Sundry #321-597: Adding CT Steps Date:Wednesday, December 8, 2021 4:16:17 PM From: Rixse, Melvin G (OGC) Sent: Wednesday, December 8, 2021 4:16 PM To: Taylor Wellman <twellman@hilcorp.com> Subject: 20211208 1615 APPROVAL (PTD220-066) Modification to Sundry 321-597 MPU F-62A (PTD 220-066) Approved Sundry #321-597: Adding CT Steps Taylor, The work description you described below is adequate. Hilcorp is approved to rig up service coil and operate as you described below. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-223-3605 Cell CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). From: Taylor Wellman <twellman@hilcorp.com> Sent: Wednesday, December 8, 2021 2:32 PM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Subject: MPU F-62A (PTD 220-066) Approved Sundry #321-597: Adding CT Steps Mel, MPU F-62A is a jet pump well that is slated for workover to convert from Jet Pump to ESP with the approved sundry 321-597. The well has a partially collapsed tubing that was swedged out to 3.80”. It was enough to pull the patch through with slickline but the nipple reducer is proving to be slightly more difficult. I would like to use CT to fish and potentially use a tapered and string mill to open up the tubing to remove the nipple reducer. This might entail a permanent modification but the well already has multiple tubing leaks and the addition of coil tubing should not change the integrity of the well. I wanted to ask if you’d like to see a change to the sundry, if an email is sufficient or if there is another path you’d like to see. I’m good with any way to proceed but wanted to overcommunicate. Proposed steps are outlined below to be added at the beginning of the sundry: 1. RU CT unit and spot auxiliary equipment. 2. Pressure test BOPE to 3,500 psi Hi 250 Low, 10 min High, 5 min Low each test. a. If within the standard 7-day test BOPE test period for Milne Point, a full body test and function test of the rams is sufficient. b. Each subsequent test of the lubricator will be to 3,500 psi Hi 250 Low to confirm no leaks. 3. MU 4” GS BHA and RIH. Latch in to nipple reducer at 9,559’ md and retrieve. a. While RIH make multiple passes through the swedged restriction area at 5,197’ to ensure free passage. b. If unable to work nipple reducer back through restriction RIH and pump to release from reducer and move into the contingency runs below. c. Contingency Runs: i. Venturi basket for tubing patch elements left in hole. ii. Motor and 3.815” tapered mill and string mill to open up partially collapsed area at 5,197’ md. 4. RD CT Unit. Thank you, Taylor Taylor Wellman Hilcorp Alaska, LLC – Ops Engineer: Milne Point Office: (907) 777-8449 Cell: (907) 947-9533 Email: twellman@hilcorp.com 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. 1. Operations Abandon Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Suspend Perforate Other Stimulate Alter Casing Change Approved Program Plug for Redrill Perforate New Pool Repair Well Re-enter Susp Well Other: Pull Tubing Patch Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number): 8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071):10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 10,112'feet N/A feet true vertical 7,445'feet N/A feet Effective Depth measured 10,010'feet 9,622 feet true vertical 7,350'feet 6,989 feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth)4-1/2" 13.5" / L-80 9,740' 7,099' Baker Premier 9,622 MD Packers and SSSV (type, measured and true vertical depth)Retrievable N/A 6,989 TVD N/A 12. Stimulation or cement squeeze summary: N/A Intervals treated (measured): Treatment descriptions including volumes used and final pressure: N/A 13. Prior to well operation: Subsequent to operation: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Contact Name: Contact Email: Authorized Title:Operations Manager Contact Phone: N/A Sr Pet Eng: Sr Pet Geo: Sr Res Eng: Authorized Name and Digital Signature with Date: WINJ WAG 0 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 0 0 Taylor Wellman twellman@hilcorp.com 907-777-8449 0 550 Representative Daily Average Production or Injection Data Casing Pressure Tubing PressureGas-Mcf MD 112' 5,942' TVD Conductor Surface Production 0 0 0 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 400 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 220-066 50-029-22609-01-00 N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: ADL025509 & ADL355018 Milne Point Unit / Kuparuk Oil Pool Hilcorp Alaska LLC 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 3. Address: MP F-62A N/A Length 112' 5,942' Size 20" 9-5/8" 10,093'5,410psi N/A 5,750psi 7,240psi7,428'10,093'7" measuredPlugs Junk measured measured true vertical Packer Burst Collapse N/A 3,090psi Casing 112' 4,484' Form 10-404 Revised 10/2021 Submit Within 30 days of Operations By Meredith Guhl at 7:36 am, Dec 10, 2021 Digitally signed by David Haakinson (3533) DN: cn=David Haakinson (3533), ou=Users Date: 2021.12.09 15:50:49 -09'00' David Haakinson (3533) MGR31DEC2021 RBDMS HEW 12/13/2021 SFD 12/15/2021 DSR-12/10/21 Well Name Rig API Number Well Permit Number Start Date End Date MP F-62A Eline/ Slickline 50-029-22609-01-00 220-066 11/25/2021 11/26/2021 No operations to report. No operations to report. 11/27/2021 - Saturday No operations to report. 11/30/2021 - Tuesday 11/28/2021 - Sunday No operations to report. 11/29/2021 - Monday 11/26/2021 - Friday WELL S/I ON ARRIVAL, DSO NOTIFIED, PT PCE 250L/2,500H. (pull patch). RAN 4-1/2" GS (5/16" brass) & LATCHED PATCH @ 5,395' SLM, HIT UP FOR 45min. RAN 4-1/2" GS (5/16" brass) & LATCHED PATCH @ 5,395' SLM, HIT UP FOR 55min. RAN 4-1/2" GS LATCH PATCH @ 5,395' SLM, HIT UP 60MIN. RAN 4-1/2" GS LATCH PATCH @ 5,395' SLM, HIT UP 55MIN. RIG UP BRAIDED LINE. PULLED 44' BAKER PATCH FROM 5,356' BLM, MISSING 1 FULL ELEMENT FROM BOTH UPPER & LOWER PACK OFFS. 11/24/2021 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary No operations to report. 11/25/2021 - Thursday WELL S/I ON ARRIVAL, DSO NOTIFIED, PT PCE 250L/2,500H. (pull patch). RAN 4-1/2" GS (5/16" brass) & LATCH PATCH @ 5,395' SLM, GS SHEARED AFTER 12min. RAN 4-1/2" GS (3/8" brass) & LATCH PATCH @ 5,395' SLM, HIT UP FOR 1hr, HIT DOWN FOR 1.5hrs TO SHEAR GS W/ NO LUCK, LRS PUMPED FLUID TO ASSIST JARING DOWN, HIT DOWN 15 TIMES & COME FREE, GS SHEARED, OJ'S GASED UP. RAN 4-1/2" GS (5/16" brass) LATCHED PATCH @ 5,395' SLM, HIT UP FOR 45min W/ OJ'S @ 2,000lbs, RUN CONTINUED ON 11-26-21. Kaitlyn Barcelona Hilcorp North Slope, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: DATE: 11/29/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU F-62A (PTD 220-066) Multi-Finger Caliper 11/10/2021 Please include current contact information if different from above. 37' (6HW Received By: 11/29/2021 By Abby Bell at 4:24 pm, Nov 29, 2021 Kaitlyn Barcelona Hilcorp North Slope, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: DATE: 11/19/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU F-62A (PTD 220-066) Gamma Ray/CCL 11/03/2021 Please include current contact information if different from above. 37' (6HW Received By: 11/22/2021 By Abby Bell at 12:30 pm, Nov 22, 2021 1.Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: Convert to ESP 2.Operator Name:4.Current Well Class:5.Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating:8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception?Yes No 9.Property Designation (Lease Number):10.Field/Pool(s): 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 10,112'N/A Casing Collapse Conductor N/A Surface 3,090psi Production 5,410psi Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13.Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14.Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date:GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by:COMMISSIONER THE AOGCC Date: Comm.Comm.Sr Pet Eng Sr Pet Geo Sr Res Eng 10,093' Perforation Depth MD (ft): 112'20" 9-5/8" 7" 5,942'5,942' 10,093' Length Size 112'112' 13.5" / L-80 / Hyd 625 TVD Burst 9,740' MD N/A 5,750psi 7,240psi 4,484' 7,428' PRESENT WELL CONDITION SUMMARY STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL025509 & ADL355018 220-066 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 50-029-22609-01-00 Hilcorp Alaska LLC MP F-62A Milne Point Unit / Kuparuk Oil Pool C.O. 432D Tubing Grade:Tubing MD (ft):Perforation Depth TVD (ft): Tubing Size: Baker Premier Retrievable and N/A 9,622 MD / 6,989 TVD and N/A See Schematic See Schematic 11/28/2021 4-1/2" 17.I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: AOGCC USE ONLY Operations Manager Taylor Wellman twellman@hilcorp.com 907-777-8449 7,445' 2,356' 7,350' 2,256 N/A ry Statu Form 10-403 Revised 10/2021 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 9:07 am, Nov 19, 2021 321-597 Digitally signed by David Haakinson (3533) DN: cn=David Haakinson (3533), ou=Users Date: 2021.11.19 08:33:41 -09'00' David Haakinson (3533) BOPE test to 2500 psi. SFD 11/19/2021MGR21NOV21 10-404 DSR-11/22/21 2,256 dts 11/24/2021 11/24/21 Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2021.11.24 08:54:07 -09'00' RBDMS HEW 11/24/2021 Convert JP to ESP Well: MPU F-62A Date: 11/15/2021 Well Name:MPU F-62A API Number:50-029-22609-01-00 Current Status:Oil Well [Tbg Leaks]Pad:F-Pad Estimated Start Date:November 28, 2021 Rig:ASR 1 Reg. Approval Req’d?Yes Date Reg. Approval Rec’vd: Regulatory Contact:Tom Fouts Permit to Drill Number:220-066 First Call Engineer:Taylor Wellman (907) 777-8449 (O) (907) 947-9533 (M) Second Call Engineer:David Gorm (907) 777-8333 (O) (505) 215-2819 (M) Current Bottom Hole Pressure: 2,936 psi @ 6,940 TVD Downhole Gauge (11/11/2021) |8.14 PPG Maximum Expected BHP:3,050 psi @ 6,940’ TVD Normally pressured Kup Bsilts/A1B adperfs | 8.45 PPG MPSP:2,356 psi Gas Column Gradient (0.1 psi/ft) Brief Well Summary: MPU F-62A was drilled and completed as a Kuparuk A and C sand producer in Q4 2020. A fracture stimulation of the A-sand was completed in December 2020 and the well has been producing as a jet pump producer. On 9/20/2021, the well was shut in after the power fluid rate was found to be increasing. Subsequent testing identified a leak in the tubing. A patch was set across this hole and the well returned to production for 3 days before another hole formed. A caliper indicates that corrosion has led to high wall loss and multiple penetrations in the tubing. A workover to convert the well to ESP production is being planned. Notes Regarding Wellbore Condition x CO 390A: A packer is not required on this ESP completion as the current reservoir pressure of 8.2 ppg and the anticipated additional perfs in the are normally pressured at 8.45 ppg EMW. Both are less than 8.55 ppg EMW. x A passing C-MITIA to 3,500 psig was completed on 9/24/2021 confirming integrity of the 7” IA and production packer. x A caliper run on 11/10/2021 indicates multiple holes, multiple joints with 30-40% wall loss and one spot of partially collapsed tubing. The tubing has been swedged out to ~3.80” ID. x The tubing patch and the nipple reducer will be pulled from 5,396’-5,434’ md and 9,559’ md respectively before the work proposed. x Offset Injector Support o L-15: Shut in Objective: 1. Add Perforations to the Kuparuk Bsilts and the A1B. 2. Cut the tubing above the packer and recover all tubing. 3. Run new ESP completion. s | Downhole Gauge (11/11/2021) |8.14 PPG Convert JP to ESP Well: MPU F-62A Date: 11/15/2021 Pre-Rig Procedure: 1. RU EL and pressure test PCE to 250psi low / 3,000psi high. 2. MU 2-7/8”-3-1/8”, 6-12spf guns and perforate as per the following table: Zone Sand Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Kuparuk B silts ±9,823’ ±9,833' ±7,175' ±7,185' 10' Kuparuk A1B ±9,922’ ±9,951' ±7,268’ ±7,295' 29' 3. RIH w/ jet cutter and cut tubing at ±9,624’ md (1 st full joint above the packer). a. Reference: Tubing tally dated 11/20/2020. b. XN nipple at 9,688’ md may be used for correlation. c. Before leaving location, confirm that Baker Centrilift can reconnect to the DH gauge and confirm BHP. If not, a BHP run may be required based on timing between now and the rig arrival. Contact Operations Engineer with results to see if a higher MPSP is observed. 4. Clear and level pad area in front of well. Spot rig mats and containment. 5. RD well house and flowlines. Clear and level area around well. 6. RU Little Red Services. RU reverse out skid and 500 bbl returns tank. 7. Pressure test lines to 3,000 psi. 8. Circulate at least one wellbore volume with 3% KCl water down tubing, taking returns up casing to 500 bbl returns tank. a. Partial returns will probably be seen. After attempting circulation down the tubing, load the IA. 9. Confirm well is dead. Contact the operations engineer if freeze protection is needed depending on ASR arrival. 10. RD Little Red Services and reverse out skid. 11. RU crane. Set BPV. ND Tree. NU BOPE. RD Crane. 12. NU BOPE house. Spot mud boat. Brief RWO Procedure: 13. MIRU Hilcorp ASR #1 WO Rig, ancillary equipment and lines. 14. Check for pressure and if 0 psi pull BPV. If needed, bleed off any residual pressure off tubing and casing. If needed, kill well w/ 3% KCl prior to pulling BPV. Set plug to convert BPV to TWC. 15. Test BOPE to 250 psi Low/ 2,500 psi High, annular to 250 psi Low/ 2,500 psi High (hold each ram/valve and test for 5-min). Record accumulator pre-charge pressures and chart tests. a. Perform Test per ASR 1 BOP Test Procedure b. Notify AOGCC 24 hours in advance of BOP test. c. Confirm test pressures per the Sundry Conditions of approval. d. Test VBR rams on 2-7/8” and 4-1/2” test joints. e. Submit to AOGCC completed 10-424 form within 5 days of BOPE test. 16. Contingency: (If the tubing hanger won’t pressure test due to either a penetrator leak or the BPV profile is eroded and/or corroded and BPV cannot be set with tree on.) Double check existing packer depth. If MPSP >8.55 ppg, notify AOGCC. Schematic shows packer at 9,622' MD. Assure cut above the existing packer. Convert JP to ESP Well: MPU F-62A Date: 11/15/2021 a. Notify Operations Engineer (Hilcorp), Mr. Mel Rixse (AOGCC) and Mr. Jim Regg (AOGCC) via email explaining the wellhead situation prior to performing the rolling test. AOGCC may elect to send an inspector to witness test. b. With stack out of the test path, test choke manifold per standard procedure c. Conduct a rolling test: Test the rams and annular with the pump continuing to pump, (monitor the surface equipment for leaks to ensure that the fluid is going down-hole and not leaking anywhere at surface.) d. Hold a constant pressure on the equipment and monitor the fluid/pump rate into the well. Record the pumping rate and pressure. e. Once the BOP ram and annular tests are completed, test the remainder of the system following the normal test procedure (floor valves, gas detection, etc.) f. Record and report this test with notes in the remarks column that the tubing hanger/BPV profile / penetrator wouldn’t hold pressure and rolling test was performed on BOP Equipment and list items, pressures and rates. 17. Bleed any pressure off casing to the returns tank. Pull plug and BPV. Kill well with 3% KCl as needed. 18. RU spooling unit for Techwire. MU landing joint and recover the tubing hanger. a. The PU weight during the 2020 completion was 142k lbs (block wt = 40k lbs). Slack off weight = 102k lbs and 62k lbs set on the hanger. b. If needed, circulate (long or reverse) pill with lubricant prior to laying down the tubing hanger. Contingency (If a rolling test was conducted): MU new hanger or test plug to the completion tubing. Re-land hanger (or test plug) in tubing head. Test BOPE per standard procedure. 19. POOH and lay down the 4-1/2” tubing. Number all joints. a. All joints are to be junked except the following: 40, 80, 100, and 220. Sections of these joints are to be cut and saved for chemical analysis to confirm hypothesized corrosion mechanism. b. Note that casing crew will be required for pulling the 4-1/2” completion. The torque values for 4-1/2” Hyd 625 are: 8,000 min/9,600 opt/12,000 max ft/lb for makeup. c. 125 Cannon Cross Collar Clamps were installed with the completion for the Techwire for the downhole gauges. 20. PU new ESP and RIH on 2-7/8” 6.5# L-80 tubing. Check electrical connections every 2,000’ a. Base of ESP at ± 9,550’ MD a. Chemical injection diffuser along the centralizer. b. 1 joints of 2-7/8”, 6.5#, L-80, EUE 8rd tubing c. 2-7/8” XN (2.205” No-Go) Nipple d. 3-4 joints of 2-7/8”, 6.5#, L-80, EUE 8rd tubing e. Lower 2-7/8”x 1” Side-pocket GLM with Dummy GLV f. Mulitple joints 2-7/8”, 6.5#, L-80, EUE 8rd tubing g. Upper 2-7/8”x 1” Side-pocket GLM @ ± 200’ MD with 0.25” OV h. ± 5 joints 2-7/8”, 6.5#, L-80, EUE 8rd tubing 21. Land tubing hanger (Caution not to Damage Cable while landing the hanger). Lay down landing joint. Note PU (Pick Up) and SO (Slack Off) weights on tally. Convert JP to ESP Well: MPU F-62A Date: 11/15/2021 22. Set BPV. Post-Rig Procedure: 1. RD mud boat. RD BOPE house. Move to next well location. 2. RU crane. ND BOPE. 3. NU existing 2-9/16” 5,000# tree/adapter flange. Test tubing hanger void to 500 psi low/5,000 psi high. Pull BPV. 4. RD crane. Move 500 bbl returns tank and rig mats to next well location. 5. Replace gauge(s) if removed. 6. Turn well over to production. RU well house and flowlines. Attachments: 1. As-built Schematic 2. Proposed Schematic 3. BOPE Schematic _____________________________________________________________________________________ Revised By: TDF 11/12/2021 SCHEMATIC Milne Point Unit Well: MPU F-62A Last Completed: 11/20/20 PTD: 220-066 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20" Conductor 91.1 / NT80LHE / N/A N/A Surface 112’ 9-5/8" Surface 40 / L-80 / BTC 8.835 Surface 5,942’ 7" Production 26 / L-80 / BTC 6.276 Surface 10,093’ TUBING DETAIL 4-1/2" Tubing 13.5 / L-80 / Hyd 625 3.920 Surface 9,740’ JEWELRY DETAIL No Depth Item 1 9,550’ Zenith Discharge Pressure Gauge 29,559’Sliding Sleeve 2 7/8” reducing sleeve (2.313 ID) 11A JP 10-24-21 3 9,569’ Zenith Lower Suction Gauge 4 9,622’ Baker Premier Retrievable Packer 5 9,688’ 4-1/2” XN-Nipple (3.725” No-Go) PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status Kuparuk A2 9,879’ 9,889’ 7,228’ 7,237’ 10 11/19/2020 OPEN Kuparuk C/B7 9790 9816 7146 7170 26 12-8-2020 OPEN Ref Log; 10/7/95 SBT / GR / CCL. 32 gm Alpha Jet charges (EHD-0.50”, TTP=32.0”) @ 135 / 45 deg. phasing OPEN HOLE / CEMENT DETAIL 20" 260 sx of Arcticset (Approx.) in 24” Hole 9-5/8" 1,160 sx PF “C”, 250 sx Class “G”, 250 sx PF ‘E in 12-1/4” Hole 7” 265 sx Class “G” 15.8 ppg in 8-1/2” Hole WELL INCLINATION DETAIL KOP @ 1,000 Max Hole Angle = 66 deg. Hole Angle through perforations = 42 deg. TREE & WELLHEAD Tree 4-1/16” – 5M Cameron NS Wellhead FMC 11” 5M FMC Gen 5 w/ 11” FMC Tubing Hanger, 3.5” NSCT Lift Threads and 3” CIW H BPV Profile Tubing Hanger 4-1/2” GENERAL WELL INFO API: 50-029-22609-01-00 Completed: 11/20/2020 – Doyon 14 TD =10,112’ (MD) / TD = 7,445’(TVD) 20” Orig.DF Elev.: 45.70’/ GL Elev.: 12.0’ Nabors 22E 7” 4 9-5/8” 1 2 PBTD =10,010’ (MD) / PBTD = 7,350’(TVD) 3 Tubing Leak @ 5,417’ MD Patch set 11-3-21 45 FloGuard Baker patch. Top @ 5396’ ELMD OAL-43.10’ Min ID 2.45” Partially collapsed tubing @ 5,195’- ID= 3.45” 5 6 _____________________________________________________________________________________ Revised By: TDF 11/12/2021 PROPOSED Milne Point Unit Well: MPU F-62A Last Completed: 11/20/20 PTD: 220-066 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20" Conductor 91.1 / NT80LHE / N/A N/A Surface 112’ 9-5/8" Surface 40 / L-80 / BTC 8.835 Surface 5,942’ 7" Production 26 / L-80 / BTC 6.276 Surface 10,093’ TUBING DETAIL 2-7/8” Tubing 6.4 / L-80 / EUE 8rd 2.441 Surface ±9,550’ 4-1/2" Tubing 13.5 / L-80 / Hyd 625 3.920 ±9,602’ 9,740’ JEWELRY DETAIL No Depth Item 1 ±180’ Sta 2: GLM 2.875 x 1" w/ 0.25 OV 2 ±9,360’ Sta 1: GLM 2.875 x 1" w/ Dummy Valve 3 ±9,380’ 2-7/8” XN- Nipple (2.205” No-Go ID) 4 ±9,410 Discharge Head: 5 ±9,420’ Pump: 6 ±9,440’ Gas Separator: 7 ±9,450’ UT Seal Section: 8 ±9,480’ LT Seal Section: 9 ±9,510’ Motor: 10 ±9,548’ Motor Gauge w/ Centralizer – Btm @ ±9,550’ 11 9,622’ Baker Premier Retrievable Packer 12 9,688’ 4-1/2” XN-Nipple (3.725” No-Go) 13 9,739’’ Mule Shoe –Btm at 9,740’ PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status Kuparuk C/B7 9,790’ 9,816’ 7,146’ 7,170’ 26 12-8-2020 OPEN Kuparuk B Silts ±9,823’ ±9,833' ±7,175' ±7,185' ±10 Future Future Kuparuk A2 9,879’ 9,889’ 7,228’ 7,237’ 10 11/19/2020 OPEN Kuparuk A1B 9,922’ 9,951’ 7,268’ 7,295’ ±29 Future Future Ref Log; 10/7/95 SBT / GR / CCL. 32 gm Alpha Jet charges (EHD-0.50”, TTP=32.0”) @ 135 / 45 deg. phasing OPEN HOLE / CEMENT DETAIL 20" 260 sx of Arcticset (Approx.) in 24” Hole 9-5/8" 1,160 sx PF “C”, 250 sx Class “G”, 250 sx PF ‘E in 12-1/4” Hole 7” 265 sx Class “G” 15.8 ppg in 8-1/2” Hole WELL INCLINATION DETAIL KOP @ 1,000 Max Hole Angle = 66 deg. Hole Angle through perforations = 42 deg. TREE & WELLHEAD Tree 4-1/16” – 5M Cameron NS Wellhead FMC 11” 5M FMC Gen 5 w/ 11” FMC Tubing Hanger, 3.5” NSCT Lift Threads and 3” CIW H BPV Profile Tubing Hanger 4-1/2” GENERAL WELL INFO API: 50-029-22609-01-00 Completed: 11/20/2020 – Doyon 14 TD =10,112’ (MD) / TD = 7,445’(TVD) 20” Orig.DF Elev.: 45.70’/ GL Elev.: 12.0’ Nabors 22E 7” 4 6 9 10 13 9-5/8” 1 2 12 PBTD =10,010’ (MD) / PBTD = 7,350’(TVD) 3 7 &8 5 11 Milne Point ASR Rig 1 BOPE BOPE ~4.48' ~4.54' 2.00' 5000# 2-7/8" x 5" VBR 5000#Blind DSA, 11 5M X 7 1/16 5M (If Needed) 2 1/16 5M Kill Line Valves 2 1/16 5M Choke Line Valves HCRManualManualManual Stripping Head 1. Operations Abandon Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Suspend Perforate Other Stimulate Alter Casing Change Approved Program Plug for Redrill Perforate New Pool Repair Well Re-enter Susp Well Other: Set Tubing Patch Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number): 8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071):10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 10,112'feet N/A feet true vertical 7,445'feet N/A feet Effective Depth measured 10,010'feet 9,622 feet true vertical 7,350'feet 6,989 feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth)4-1/2" 13.5" / L-80 9,740' 7,099' Baker Premier 9,622 MD Packers and SSSV (type, measured and true vertical depth)Retrievable N/A 6,989 TVD N/A 12. Stimulation or cement squeeze summary: N/A Intervals treated (measured): Treatment descriptions including volumes used and final pressure: N/A 13. Prior to well operation: Subsequent to operation: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Contact Name: Contact Email: Authorized Title:Operations Manager Contact Phone: 321-511 Sr Pet Eng: Sr Pet Geo: Sr Res Eng: Authorized Name and Digital Signature with Date: WINJ WAG 0 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 0 81 Taylor Wellman twellman@hilcorp.com 907-777-8449 measured true vertical Packer Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure 0120 0 12 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf MD 112' 5,942' 51 TVD STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 220-066 50-029-22609-01-00 N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: ADL025509 & ADL355018 Milne Point Unit / Kuparuk Oil Pool Hilcorp Alaska LLC 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 3. Address: MP F-62A measuredPlugs Junk measured N/A Length 112' 5,942' Size Conductor Surface 20" 9-5/8" Production 10,093' Casing 112' 4,484' 7,428'10,093'7"5,410psi N/A 5,750psi 7,240psi Burst Collapse N/A 3,090psi Form 10-404 Revised 10/2021 Submit Within 30 days of Operations By Samantha Carlisle at 9:18 am, Nov 16, 2021 Digitally signed by David Haakinson (3533) DN: cn=David Haakinson (3533), ou=Users Date: 2021.11.16 09:01:09 -09'00' David Haakinson (3533) MGR28DEC2021 DSR-11/16/21 RBDMS HEW 11/18/2021 SFD 11/17/2021 Well Name Rig API Number Well Permit Number Start Date End Date MP F-62A Eline/ Slickline 50-029-22609-01-00 220-066 11/3/2021 11/3/2021 No operations to report. No operations to report. 11/6/2021 - Saturday No operations to report. 11/9/2021 - Tuesday 11/7/2021 - Sunday No operations to report. 11/8/2021 - Monday 11/5/2021 - Friday No operations to report. 11/3/2021 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary Well Shut in upon Arrival. PT 200psi Low / 2,500psi High. Make up Gun Gamma, Baker 10 setting tool and Baker one trip patch. Correlated to HES LDL dated 9-25-21 pull into setting depth unable to get Baker 10 tool to fire. pooh w/ patch. XO from the gun gamma to setting tool shorted out, C/O and make up patch. Correlated to HES LDL log dated 9-25-21, Set Baker 45KB one trip patch @ 5,395.6' ELMD (Top ME @ 5,397.1'ELMD, BTM ME @ 5,434' ELMD) OAL 43.10' Min ID 2.40", Max OD 3.70". RDMO turn well over to pad op to POP. 11/4/2021 - Thursday No operations to report. _____________________________________________________________________________________ Revised By: TDF 11/12/2021 SCHEMATIC Milne Point Unit Well: MPU F-62A Last Completed: 11/20/20 PTD: 220-066 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20" Conductor 91.1 / NT80LHE / N/A N/A Surface 112’ 9-5/8" Surface 40 / L-80 / BTC 8.835 Surface 5,942’ 7" Production 26 / L-80 / BTC 6.276 Surface 10,093’ TUBING DETAIL 4-1/2" Tubing 13.5 / L-80 / Hyd 625 3.920 Surface 9,740’ JEWELRY DETAIL No Depth Item 1 9,550’ Zenith Discharge Pressure Gauge 29,559’Sliding Sleeve 2 7/8” reducing sleeve (2.313 ID) 11A JP 10-24-21 3 9,569’ Zenith Lower Suction Gauge 4 9,622’ Baker Premier Retrievable Packer 5 9,688’ 4-1/2” XN-Nipple (3.725” No-Go) PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status Kuparuk A2 9,879’ 9,889’ 7,228’ 7,237’ 10 11/19/2020 OPEN Kuparuk C/B7 9790 9816 7146 7170 26 12-8-2020 OPEN Ref Log; 10/7/95 SBT / GR / CCL. 32 gm Alpha Jet charges (EHD-0.50”, TTP=32.0”) @ 135 / 45 deg. phasing OPEN HOLE / CEMENT DETAIL 20" 260 sx of Arcticset (Approx.) in 24” Hole 9-5/8" 1,160 sx PF “C”, 250 sx Class “G”, 250 sx PF ‘E in 12-1/4” Hole 7” 265 sx Class “G” 15.8 ppg in 8-1/2” Hole WELL INCLINATION DETAIL KOP @ 1,000 Max Hole Angle = 66 deg. Hole Angle through perforations = 42 deg. TREE & WELLHEAD Tree 4-1/16” – 5M Cameron NS Wellhead FMC 11” 5M FMC Gen 5 w/ 11” FMC Tubing Hanger, 3.5” NSCT Lift Threads and 3” CIW H BPV Profile Tubing Hanger 4-1/2” GENERAL WELL INFO API: 50-029-22609-01-00 Completed: 11/20/2020 – Doyon 14 TD =10,112’ (MD) / TD = 7,445’(TVD) 20” Orig.DF Elev.: 45.70’/ GL Elev.: 12.0’ Nabors 22E 7” 4 9-5/8” 1 2 PBTD =10,010’ (MD) / PBTD = 7,350’(TVD) 3 Tubing Leak @ 5,417’ MD Patch set 11-3-21 45 FloGuard Baker patch. Top @ 5396’ ELMD OAL-43.10’ Min ID 2.45” Partially collapsed tubing @ 5,195’- ID= 3.45” 5 6 Kaitlyn Barcelona Hilcorp North Slope, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: DATE: 10/20/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU F-62A (PTD 220-066) Leak Detection Log 09/25/2021 Please include current contact information if different from above. 37' (6HW Received By: 10/25/2021 By Abby Bell at 12:16 pm, Oct 25, 2021 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: Set Tubing Patch 2.Operator Name:4.Current Well Class:5.Permit to Drill Number: Exploratory Development 3.Address:Stratigraphic Service 6. API Number: 7. If perforating:8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception?Yes No 9.Property Designation (Lease Number):10.Field/Pool(s): 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 10,093'N/A Casing Collapse Conductor N/A Surface 3,090psi Production 5,410psi Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13.Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14.Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16.Verbal Approval:Date:GAS WAG GSTOR SPLUG Commission Representative: GINJ Op Shutdown Abandoned Chad Helgeson Contact Name: Operations Manager Contact Email:dhaakinson@hilcorp.com Contact Phone: 777-8343 Date: Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng 220-066 David Haakinson COMMISSION USE ONLY Authorized Name: Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): Tubing Size: PRESENT WELL CONDITION SUMMARY STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL025509 & ADL355018 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 50-029-22609-01-00 Hilcorp Alaska LLC Length Size 7,428' 10,010' 7,350' 2,256 N/A Milne Point Unit / Kuparuk Oil Pool 112' 112' 13.5" / L-80 / Hyd 625 TVD Burst 9,740' MD N/A 5,750psi 7,240psi 4,484' 7,428' 5,942' 10,093' See Schematic 112' 20" 9-5/8" 7" 5,942' 10,093' Authorized Signature: 10/10/2021 4-1/2" Perforation Depth MD (ft): See Schematic MP F-62A C.O. 432D Baker Premier Retrievable and N/A 9,622 MD / 6,989 TVD and N/A Authorized Title: 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. ory Statu Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Meredith Guhl at 2:41 pm, Sep 28, 2021 321-511 Chad Helgeson (1517) 2021.09.28 14:19:47 - 08'00' DLB X DSR-9/28/21DLB 09/28/2021 10,112' DLB 7,445' TVD 10-404 MGR30SEP2021 dts 9/30/2021 JLC 10/1/2021 Jeremy Price Digitally signed by Jeremy Price Date: 2021.10.01 11:30:53 -08'00' RBDMS HEW 10/1/2021 Tubing Patch Well: MPU F-62A Date: 09-28-2021 Well Name:MPU F-62A API Number: 50-029-22609-01-00 Current Status:Shut In- JP Producer Pad:F-Pad Estimated Start Date:October 10th, 2021 Wellwork unit:SL/EL Reg. Approval Req’d?Yes Date Reg. Approval Rec’vd: Regulatory Contact:Tom Fouts Permit to Drill Number:220-066 First Call Engineer:David Haakinson (907) 777-8343 (O) (307) 660-4999 (M) Second Call Engineer:David Gorm (907) 777-8333 (O) (505) 215-2819 AFE Number:Job Type:Tubing Patch Current Bottom Hole Pressure: 2,874 psi @ 6,940 TVD Downhole Gauge (9/28/2021) |7.96 PPG Maximum Expected BHP:2,950 psi @ 6,940’ TVD 30-day PBU |8.17 PPG MPSP:2,256 psi Gas Column Gradient (0.1 psi/ft) Max Inclination 66° @ 4,314’ MD MIN ID:3.725” XN Nipple Brief Well Summary: MPU F-62A was drilled and completed as a Kuparuk A and C sand producer in Q4 2020. A fracture stimulation of the A-sand was completed in December 2020 and the well has been producing as a jet pump producer. On 9/20/2021, the well was shut in after the power fluid rate was found to be increasing. Subsequent testing has found a tubing leak in the well that must be repaired Notes Regarding Wellbore Condition x Well was SI on 9/20/2020 due to an increase of power fluid rate jumping from 2,500 to 4,000 BWPD. x A passing C-MITIA to 3,500 psig was completed on 9/24/2021 confirming integrity of the 7” IA and production packer. x A Leak Detect log run on 9/25/2021 identified a single tubing leak at or near a tubing collar at 5,417’ MD. x CAT-SV stuck in XN-Nipple @ 9,688’ MD. Objective: x Pull CAT-SV x Set 2.313” Jet Pump Reducer Sleeve x Set tubing patch (Sundry Approval Required) Procedure Slickline 1. MIRU SL. PT lubricator to 200 psig low / 2,500 psig high. 2. RU LRS for pump support. 3. MU jars and fish CAT-SV from XN-Nipple @ 9,688’ MD. 4. Brush and Flush tubing at patch setting interval (±50’ up/down from 5,417’ MD). 5. Confirm XD Sleeve @ 9,559’ MD is in the open position. 6. Set 3.813” x 2.313” Reducing Sleeve across the Sliding Sleeve @ 9,559’ MD. a. Ensure the sliding sleeve is in the open position. Tubing Patch Well: MPU F-62A Date: 09-28-2021 7. Set 2.313” Size 11A jet pump in the 2.313” lock @ ~9,559’ MD. 8. RDMO Slickline. E-line 9. MIRU E-line. PT PCE to 200 psig low / 2,500 psig high. a. Correlate to SL Memory Spinner/GR/CCL log dated 9-25-2021. 10. Set lower patch packer mid-element @ 5,434’ MD. Slickline 11. MIRU Slickline. PT PCE to 200 psig low/ 2,500 psig high. 12. Set stinger and spacer pipe and top patch packer element with top packer element at 5,404’ MD. 13. Set 4.5” tubing stop on top of patch at @ 5,404’ MD. 14. RDMO Slickline. 15. Bring well online and confirm proper IA pressure build-up and a stabilized power fluid rate of ~2400 BWPD with a size 11A jet pump. Attachments: 1) Current Schematic 2) Proposed Schematic _____________________________________________________________________________________ Revised By: TDF 2/18/2021 SCHEMATIC Milne Point Unit Well: MPU F-62A Last Completed: 11/20/20 PTD: 220-066 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20" Conductor 91.1 / NT80LHE / N/A N/A Surface 112’ 9-5/8" Surface 40 / L-80 / BTC 8.835 Surface 5,942’ 7" Production 26 / L-80 / BTC 6.276 Surface 10,093’ TUBING DETAIL 4-1/2" Tubing 13.5 / L-80 / Hyd 625 3.920 Surface 9,740’ JEWELRY DETAIL No Depth Item 1 9,550’ Zenith Discharge Pressure Gauge 2 9,559’ Sliding Sleeve 11A pump set 12-09-20 3 9,569’ Zenith Lower Suction Gauge 4 9,622’ Baker Premier Retrievable Packer 5 9,688’ 4-1/2” XN-Nipple (3.725” No-Go) 6 9,740’ WLEG PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status Kuparuk A2 9,879’ 9,889’ 7,228’ 7,237’ 10 11/19/2020 OPEN Kuparuk C/B7 9790 9816 7146 7170 26 12-8-2020 OPEN Ref Log; 10/7/95 SBT / GR / CCL. 32 gm Alpha Jet charges (EHD-0.50”, TTP=32.0”) @ 135 / 45 deg. phasing OPEN HOLE / CEMENT DETAIL 20" 260 sx of Arcticset (Approx.) in 24” Hole 9-5/8" 1,160 sx PF “C”, 250 sx Class “G”, 250 sx PF ‘E in 12-1/4” Hole 7” 265 sx Class “G” 15.8 ppg in 8-1/2” Hole WELL INCLINATION DETAIL KOP @ 1,000 Max Hole Angle = 66 deg. Hole Angle through perforations = 42 deg. TREE & WELLHEAD Tree 4-1/16” – 5M Cameron NS Wellhead FMC 11” 5M FMC Gen 5 w/ 11” FMC Tubing Hanger, 3.5” NSCT Lift Threads and 3” CIW H BPV Profile Tubing Hanger 4-1/2” GENERAL WELL INFO API: 50-029-22609-01-00 Completed: 11/20/2020 – Doyon 14 TD =10,093’ (MD) / TD = 7,428’(TVD) 20” Orig.DF Elev.: 45.70’/ GL Elev.: 12.0’ Nabors 22E 7” 4 9-5/8” 1 2 PBTD =10,010’ (MD) / PBTD = 7,350’(TVD) 3 Tubing Leak @ 5,417’ MD 5 6 _____________________________________________________________________________________ Revised By: TDF 9/28/2021 PROPOSED Milne Point Unit Well: MPU F-62A Last Completed: 11/20/20 PTD: 220-066 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20" Conductor 91.1 / NT80LHE / N/A N/A Surface 112’ 9-5/8" Surface 40 / L-80 / BTC 8.835 Surface 5,942’ 7" Production 26 / L-80 / BTC 6.276 Surface 10,093’ TUBING DETAIL 4-1/2" Tubing 13.5 / L-80 / Hyd 625 3.920 Surface 9,740’ JEWELRY DETAIL No Depth Item 1 ±5,404’ Upper Patch Packer 2 ±5,434’ Lower Patch Packer 3 9,550’ Zenith Discharge Pressure Gauge 4 9,559’ Sliding Sleeve w/ 2.313” Reducer - 11A pump set 12-09-20 5 9,569’ Zenith Lower Suction Gauge 6 9,622’ Baker Premier Retrievable Packer 7 9,688’ 4-1/2” XN-Nipple (3.725” No-Go) 8 9,740’ WLEG PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status Kuparuk A2 9,879’ 9,889’ 7,228’ 7,237’ 10 11/19/2020 OPEN Kuparuk C/B7 9790 9816 7146 7170 26 12-8-2020 OPEN Ref Log; 10/7/95 SBT / GR / CCL. 32 gm Alpha Jet charges (EHD-0.50”, TTP=32.0”) @ 135 / 45 deg. phasing OPEN HOLE / CEMENT DETAIL 20" 260 sx of Arcticset (Approx.) in 24” Hole 9-5/8" 1,160 sx PF “C”, 250 sx Class “G”, 250 sx PF ‘E in 12-1/4” Hole 7” 265 sx Class “G” 15.8 ppg in 8-1/2” Hole WELL INCLINATION DETAIL KOP @ 1,000 Max Hole Angle = 66 deg. Hole Angle through perforations = 42 deg. TREE & WELLHEAD Tree 4-1/16” – 5M Cameron NS Wellhead FMC 11” 5M FMC Gen 5 w/ 11” FMC Tubing Hanger, 3.5” NSCT Lift Threads and 3” CIW H BPV Profile Tubing Hanger 4-1/2” GENERAL WELL INFO API: 50-029-22609-01-00 Completed: 11/20/2020 – Doyon 14 TD =10,093’ (MD) / TD = 7,428’(TVD) 20” Orig.DF Elev.: 45.70’/ GL Elev.: 12.0’ Nabors 22E 7” 6 9-5/8” 3 4 PBTD =10,010’ (MD) / PBTD = 7,350’(TVD) 5 Tubing Leak @ 5,417’ MD 7 8 1 2 THE STATE °'ALASKA August 2, 2021 GOVERNOR MIKE DUNLEAVY Mr. Chad Helgeson Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 RE: No -Flow Verification Milne Point Unit F -62A PTD 2200660 Dear Mr. Helgeson: Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.00gcc.olaska.gov On May 16, 2021 an Alaska Oil and Gas Conservation Commission (AOGCC) Petroleum Inspector witnessed a no -flow test of Milne Point Unit F -62A. The AOGCC Inspector confirmed that the proper test equipment was rigged up to evaluate Milne Point Unit F -62A. The test methodology used by Hilcorp Alaska LLC (Hilcorp) was designed to demonstrate the well was incapable of unassisted flow of hydrocarbons to surface as allowed by 20 AAC 25.265(l)(1)(A): "the measured liquid production is not greater than 6.3 gallons per hour, and the measured gas production is not greater than 900 standard cubic feet per hour". The well performance was monitored for approximately 3 hours consisting of 1 -hour pressure build up periods followed by 15 -minute flow monitoring checks. Measured gas rates were less than 900 standard cubic feet per hour and there was no liquid flow to surface during the no -flow test. A subsurface safety valve is not required to be installed in this well based on the no -flow test result. A fail-safe automatic surface safety valve system capable of preventing uncontrolled flow must be maintained in proper working condition as required in 20 AAC 25.265. The subsurface safety valve must be returned to service if Milne Point Unit F -62A demonstrates an ability to flow unassisted to surface. Any cleanout, perforating or other stimulation work in this well will necessitate a subsequent no flow test. Sincerely, James B. Reggligitlly signed by James B. Reg Datea202708.0309:37:33-08' 009 James B. Regg Petroleum Inspection Supervisor ecc: P. Brooks AOGCC Inspectors MEMORANDUM TO: Jim Regg Q«j 7(;ni 7tZ( P. I. Supervisor FROM: Guy Cook Petroleum Inspector State of Alaska Alaska Oil and Gas Conservation Commission DATE: 5/16/2021 SUBJECT: No Flow Test MPU F -62A Hilcorp Alaska LLC PTD 2200660 - 5/15/2021: 1 arrived on location and met with Derick Weglin and David Gorm with Hilcorp. We discussed the job and walked down the rig up. I asked Mr. Weglin to provide me with information about the supporting injectors for this well and whether they were online or shut-in. I also asked for an explanation, if a supporting injector was shut- in, as to why and when it had been taken offline. I was informed MPU F -62A is supported by one injector that was online and had been since January of this year. The supporting injector is MPU L-15 (PTD 1940620). While walking down the rig up and discussing the job with both Derick Weglin and David Gorm I noticed the IA was not set up to bleed with the tubing. I called Inspection Supervisor Jim Regg to confirm the IA needed to be included in the bleed and then instructed Mr. Weglin to change their rig up to include the IA in the no -flow test. After approximately 2 hours of waiting for the rig up to be completed, Mr. Weglin approached me and asked to postpone the test until 5/16/2021 so they could locate the parts and fittings needed to complete the rig up. I left location to return the following day. During the time we were discussing the job and waiting for the rig up to come together I approached Mr. Gorm with questions about the well. I asked when the well was last brought onto production and when the wells SVS system had been tested. I also asked why Hilcorp had chosen to do the no -flow test now instead of an earlier date that was closer when the well was placed on production. And lastly, I inquired if Hilcorp had submitted for a variance to operate the well without a subsurface safety valve. Mr. Gorm contacted me later in the day via phone answering when the well was brought on and when the safety valve system had first been tested. He then told me he would not be able to get the answers for the other two questions for me until he had contacted the engineer that had previously worked with the well. He did not provide the name of the engineer. I asked him to state all this in an email and send it to me and Mr. Jim Regg which he did later in the day. 5/16/2021: 1 arrived on location and met with Mr. Weglin and William Kruskie with Hilcorp. We quickly discussed the job and walked down the rig up to confirm it was complete and correct. The IA was now included in the no -flow test and the rig up was correct. The no -flow test was started. - 2021-0516_No-Flow_MPU_F-62A_gc.docx Page 1 of 4 While bleeding the well after the second hour it became clear that the flow meter had an issue. There are two indicating needles on the meter, one for the current flow and one for the maximum amount of flow that has gone through the meter on each bleed down. The needle for the maximum amount of flow is reset and zeroed before each bleed down. The problem was that the two needles were getting stuck together stopping the current flow needle to not fall back to zero until it pulled free of the other. As a result, during the first bleed down period the gas flow rate did not fall until after 5 minutes. The problem was noticed during the second bleed down period and I separated the 2 , needles during the first 5 minutes of bleeding. I then moved the maximum flow indicator needle out of the way to stop the issue from occurring again. As you can see below, the well never exceeded 900 scf/hr on the flow meter and — pressures bled to zero within 10 minutes. There was no fluid produced from the well during the entire testing process. The data below suggests that the well will not flow to - surface without artificial lift. The following table shows test details: Time Pressures' (psi) Flow Rate Gas — scf/hr Liquid — al/hr Remarks 08:36 0/0/0 --- --- Shut in well. 08:50 0/.5/0 --- --- 09:05 0/.5/0 --- --- 09:20 0/.5/0 --- --- 09:35 0/0/0 500 0 Oen well to bleed. 09:40 0/1/0 500 0 Bleed well. 09:45 0/0/0 0 0 Bleed well. 09:45 0/0/0 Well was shut in. 10:00 0/.5/0 --- --- 10:15 0/.5/0 --- --- 10:30 0/1/0 --- --- 10:45 0/1/0 700 0 Oen well to bleed. 10:50 0/.5/0 200 0 Bleed well. 10:55 0/0/0 0 0 Bleed well. - 10:55 0/0/0 --- --- Shut in well. 11:10 0/.5/0 --- --- 11:25 0/1/0 --- --- 11:40 0/1/0 --- --- 11:55 0/1.5/0 900 0 Oen well to bleed. 12:00 0/.5/0 350 0 Bleed well. - 12:05 1 0/0/0 0 0 Bleed well. ' Pressures are T/IA/OA 2 Gas flow not to exceed 900 scf/hr; Liquid flow not to exceed 6.3 gal/hr Attachments: Photos; Calibration Reports for Test Instruments 2021-0516_No-Flow_MPU _F -62A gc.docx Page 2 of 4 Q N U- M a U) CD F- 3: 3 O LL O Z 0 0 U C� L Q U N U) Q � N C � U U O 0 � O Q -0 N a cn O O N 6 LJ. to O C N C C C C C E m �V •;�i� �c W 'n 2 Q c 4' O _ C N O %Qrnci m �co.owoU.0W wN v o CO U C N i`Z3 . O y E U 0 -O W .O ami E E E N t N CO o. 5 I cEY1 Vcaog' a y U - 6 L y O u a m a Q 6:2 V E c N ?6' c "'a.5 o r a W dad y O y E d y c g_ O 4 dy rt rr8� 5 #?;� m L _ pct 0.4'rnnss- ;fie, x I A kk CC TcE3 $ Ei cCm mo$ Soca' 0^lQ o, O ac_v sc E'm o�v3�ea Tr��TFL>xs m 's U_ >X=.5 d F- DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-22609-01-00Well Name/No. MILNE PT UNIT F-62ACompletion Status1-OILCompletion Date12/3/2020Permit to Drill2200660Operator Hilcorp Alaska, LLCMD10112TVD7445Current Status1-OIL2/25/2021UICNoWell Log Information:DigitalMed/FrmtReceivedStart StopOH /CHCommentsLogMediaRunNoElectr DatasetNumberNameIntervalList of Logs Obtained:ROP, ABG, PCG, ADR, ALD, CTN MD & TVD, Cement EvaluationNoNoYesMud Log Samples Directional SurveyREQUIRED INFORMATION(from Master Well Data/Logs)DATA INFORMATIONLog/DataTypeLogScaleDF12/14/20205940 10112 Electronic Data Set, Filename: MPU F-62A LWD Final.las34377EDDigital DataDF12/14/2020 Electronic File: MPU F-62A LWD Final MD.cgm34377EDDigital DataDF12/14/2020 Electronic File: MPU F-62A LWD Final TVD.cgm34377EDDigital DataDF12/14/2020 Electronic File: MPU F-62A - Definitive Survey Report.pdf34377EDDigital DataDF12/14/2020 Electronic File: MPU F-62A Surveys.xlsx34377EDDigital DataDF12/14/2020 Electronic File: MPU F-62A_GEO.txt34377EDDigital DataDF12/14/2020 Electronic File: MPU F-62A_GIS.txt34377EDDigital DataDF12/14/2020 Electronic File: MPU F-62A LWD Final MD.emf34377EDDigital DataDF12/14/2020 Electronic File: MPU F-62A LWD Final TVD.emf34377EDDigital DataDF12/14/2020 Electronic File: MPU F-62A LWD Final MD.pdf34377EDDigital DataDF12/14/2020 Electronic File: MPU F-62A LWD Final TVD.pdf34377EDDigital DataDF12/14/2020 Electronic File: MPU F-62A LWD Final MD.tif34377EDDigital DataDF12/14/2020 Electronic File: MPU F-62A LWD Final TVD.tif34377EDDigital DataDF12/14/2020 Electronic File: EMFView3_1.zip34377EDDigital DataDF12/14/2020 Electronic File: Readme.txt34377EDDigital Data0 0 2200660 MILNE PT UNIT F-62A LOG HEADERS34377LogLog Header ScansDF12/16/202010014 8295 Electronic Data Set, Filename: MPU_F-62A_RBT_17NOV20_Main.las34399EDDigital DataDF12/16/202010010 9766 Electronic Data Set, Filename: MPU_F-62A_RBT_17NOV20_Repeat.las34399EDDigital DataThursday, February 25, 2021AOGCCPage 1 of 3MPU F-62A LWD Final.las DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-22609-01-00Well Name/No. MILNE PT UNIT F-62ACompletion Status1-OILCompletion Date12/3/2020Permit to Drill2200660Operator Hilcorp Alaska, LLCMD10112TVD7445Current Status1-OIL2/25/2021UICNoWell Cores/Samples Information:ReceivedStart Stop CommentsTotalBoxesSample SetNumberNameIntervalINFORMATION RECEIVEDDF12/16/2020 Electronic File: MPU_F-62A_RBT_17NOV20.pdf34399EDDigital DataDF12/16/2020 Electronic File: MPU_F-62A_RBT_17NOV20_img.tiff34399EDDigital DataDF12/16/2020 Electronic File: MPU_F-62A_RBT_17NOV20_Main.dlis34399EDDigital DataDF12/16/2020 Electronic File: MPU_F-62A_RBT_17NOV20_Repeat.dlis34399EDDigital Data0 0 2200660 MILNE PT UNIT F-62A LOG HEADERS34399LogLog Header Scans0 0 2200660 MILNE PT UNIT F-62A LOG HEADERS34400LogLog Header ScansDF12/16/2020 Electronic File: MPF-62A Treatment Report 03-Dec-2020.pdf34400EDDigital DataDF12/16/2020 Electronic File: MPU F-62A Frac Focus Hilcorp Alaska LLC Submittal.pdf34400EDDigital DataDF12/22/202010014 8295 Electronic Data Set, Filename: MPU_F-62A_RCBL_17NOV20_Main.las34445EDDigital DataDF12/22/202010010 9766 Electronic Data Set, Filename: MPU_F-62A_RCBL_17NOV20_Repeat.las34445EDDigital DataDF12/22/2020 Electronic File: MPU_F-62A_RCBL_17NOV20.pdf34445EDDigital DataDF12/22/2020 Electronic File: MPU_F-62A_RCBL_17NOV20_img.tiff34445EDDigital DataDF12/22/2020 Electronic File: MPU_F-62A_RCBL_17NOV20_Main.dlis34445EDDigital DataDF12/22/2020 Electronic File: MPU_F-62A_RCBL_17NOV20_Repeat.dlis34445EDDigital Data0 0 2200660 MILNE PT UNIT F-62A LOG HEADERS34445LogLog Header ScansThursday, February 25, 2021AOGCCPage 2 of 3 DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-22609-01-00Well Name/No. MILNE PT UNIT F-62ACompletion Status1-OILCompletion Date12/3/2020Permit to Drill2200660Operator Hilcorp Alaska, LLCMD10112TVD7445Current Status1-OIL2/25/2021UICNoCompletion ReportProduction Test InformationGeologic Markers/TopsY Y / NAYComments:Compliance Reviewed By:Date:Mud Logs, Image Files, Digital DataComposite Logs, Image, Data Files Cuttings SamplesY / NAYY / NADirectional / Inclination DataMechanical Integrity Test InformationDaily Operations SummaryYY / NAYCore ChipsCore PhotographsLaboratory AnalysesY / NAY / NAY / NACOMPLIANCE HISTORYDate CommentsDescriptionCompletion Date: 12/3/2020Release Date:10/5/2020Thursday, February 25, 2021AOGCCPage 3 of 3M. Guhl 2/25/2021 Samuel Gebert Hilcorp Alaska, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: sam.gebert@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: Date: DATE: 12/21/2020 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU F-62A (PTD 220-066) RCBL Radial Cement Bond Log 11/17/2020 Please include current contact information if different from above. PTD: 2200660 E-Set: 34445 Received by the AOGCC 12/22/2020 Abby Bell 12/23/2020 David Douglas Hilcorp Alaska, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or fax to 907 777-8510. Received By: Date: Date: 12/16/2020 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU F-62A (PTD 220-066) FINAL FRAC REPORTS (12-03-2020) Folder Contents: Received by the AOGCC 12/16/2020 PTD: 2200660 E-Set: 34400 Abby Bell 12/16/2020 Samuel Gebert Hilcorp Alaska, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: sam.gebert@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: Date: DATE: 12/15/2020 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU F-62A (PTD 220-066) Radial Bond Tool 11/17/2020 Please include current contact information if different from above. Received by the AOGCC 12/16/2020 PTD: 2200660 E-Set: 34399 Abby Bell 12/16/2020 1a. Well Status:Oil SPLUG Other Abandoned Suspended 1b. Well Class: 20AAC 25.105 20AAC 25.110 Development Exploratory GINJ WINJ WDSPL No. of Completions: _1 Service Stratigraphic Test 2. Operator Name: 6. Date Comp., Susp., or 14. Permit to Drill Number / Sundry: Aband.: 3. Address: 7. Date Spudded: 15. API Number: 4a. Location of Well (Governmental Section): 8. Date TD Reached: 16. Well Name and Number: Surface: Top of Productive Interval: 9. Ref Elevations: KB: 17. Field / Pool(s): GL: 12.0' BF: Total Depth: 10. Plug Back Depth MD/TVD: 18. Property Designation: 4b. Location of Well (State Base Plane Coordinates, NAD 27): 11. Total Depth MD/TVD: 19. DNR Approval Number: Surface: x- y- Zone- 4 TPI: x- y- Zone- 4 12. SSSV Depth MD/TVD: 20. Thickness of Permafrost MD/TVD: Total Depth: x- y- Zone- 4 5. Directional or Inclination Survey: Yes (attached) No 13. Water Depth, if Offshore: 21. Re-drill/Lateral Top Window MD/TVD: Submit electronic information per 20 AAC 25.050 (ft MSL) 22.Logs Obtained: 23. BOTTOM 20" H-40 112' 9-5/8" L-80 4485' 7" L-80 7428' 24. Open to production or injection? Yes No 25. 26. Was hydraulic fracturing used during completion? Yes No DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 27. Date First Production: Method of Operation (Flowing, gas lift, etc.): Hours Tested: Production for Gas-MCF: Test Period Casing Press: Calculated Gas-MCF: Oil Gravity - API (corr): Press. 24-Hour Rate ACID, FRACTURE, CEMENT SQUEEZE, ETC. CASING, LINER AND CEMENTING RECORD List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data within 90 days of completion, TUBING RECORD 9740'4-1/2" 13.5# L-80 SIZEIf Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number; Date Perfd): 265 sx Class 'G' 30" Surface 5942' 1160 sx PF 'C', 250 sx 'G', 250 sx PF 'E' 260 sx Arctic Set (Approx.) STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG Hilcorp Alaska, LLC WAG Gas 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 12/3/2020 2141' FSL, 2627' FEL, Sec. 06, T13N, R10E, UM, AK 2331' FSL, 2414' FEL, Sec. 31, T14N, R10E, UM, AK 220-066 / 320-463 Milne Point Field, Kuparuk Oil Pool 45.12' 10010' / 7350' HOLE SIZE AMOUNT PULLED 50-029-22609-01-00 MPU F-62A 541935 6035593 2216' FSL, 2420' FEL, Sec. 31, T14N, R10E, UM, AK CEMENTING RECORD 6040948 SETTING DEPTH TVD 6041064 BOTTOM TOP 8-1/2" Surface 12-1/4"Surface CASING WT. PER FT.GRADE 542090 542096 TOP SETTING DEPTH MD Surface Per 20 AAC 25.283 (i)(2) attach electronic information 26# Surface DEPTH SET (MD) 9622' / 6989' PACKER SET (MD/TVD) 91.1# 40# 112' Surface 10093' Gas-Oil Ratio:Choke Size: 9879' - 9889' 228,375 lbs Proppant Water-Bbl: PRODUCTION TEST Not on Production Date of Test: Flow Tubing Oil-Bbl: suspension, or abandonment, whichever occurs first. Types of logs to be listed include, but are not limited to: mud log, spontaneous potential, gamma ray, caliper, resistivity, porosity, magnetic resonance, dipmeter, formation tester, temperature, cement evaluation, casing collar locator, jewelry, and perforation record. Acronyms may be used. Attach a separate page if necessary N/A 3-3/8" Gun Diameter, 6 spf 11/18/2020 & 12/8/2020 9790' - 9816' 7145' - 7170' 9879' - 9889' 7228' - 7237' ROP, ABG, PCG, ADR, ALD, CTN MD & TVD, Cement Evaluation Sr Res EngSr Pet GeoSr Pet Eng Oil-Bbl: Water-Bbl: 11/13/2020 11/9/2020 ADL 025509 & 355018 94-019 1800' (Approx.) 5942' / 4485'N/A None 10112' / 7445' Form 10-407 Revised 3/2020 Submit within 30 days of Completion, Suspension, or Abandonment By Samantha Carlisle at 2:50 pm, Dec 15, 2020 Completion Date 12/3/2020 HEW RBDMS HEW 12/17/2020 GSFD 12/22/2020 CDW 12/28/2020 DSR-2/25/21MGR25FEB2021 Conventional Core(s): Yes No Sidewall Cores: 30. MD TVD Top of Productive Interval 9790' 7145' 6318' 4667' 9523' 6896' 9627' 6994' 9790' 7145' 9799' 7154' 9853' 7204' 9964' 7307' Base Kup 9964' 7307' 31. List of Attachments: 32. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Name: Joe Lastufka Contact Email:joseph.lastufka@hilcorp.com Authorized Contact Phone: 777-8400 General: Item 1a: Item 1b: Item 4b: Item 9: Item 15: Item 19: Item 20: Item 22: Item 23: Item 24: Item 27: Item 28: Item 30: Item 31: If Yes, list formations and intervals cored (MD/TVD, From/To), and summarize lithology and presence of oil, gas or water (submit separate pages with this form, if needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071. Authorized Name: Monty Myers Authorized Title: Drilling Manager Kuparuk B Kuparuk A Permafrost - Base 29. GEOLOGIC MARKERS (List all formations and markers encountered): FORMATION TESTS Permafrost - Top Kuparuk C Colville Mudstone Kalubik This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed. All laboratory analytical reports regarding samples or tests from a well must be submitted to the AOGCC, no matter when the analyses are conducted. Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, core analysis, paleontological report, production or well test results, per 20 AAC 25.070. 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. TPI (Top of Producing Interval). Yes No Well tested? Yes No 28. CORE DATA If yes, list intervals and formations tested, briefly summarizing test results. Attach separate pages to this form, if needed, and submit detailed test information, including reports, per 20 AAC 25.071. NAME 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. Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data within 90 days of completion, suspension, or abandonment, whichever occurs first. Well Class - Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Formation at total depth: Kuparuk D LOT / FIT Data Sheet, Drilling and Completion Reports, Definitive Directional Survey, Csg and Cmt Report, Wellbore Schematic, Frac Focus and Vendor Report Signature w/Date: Report the Division of Oil & Gas / Division of Mining Land and Water: Plan of Operations (LO/Region YY-123), Land Use Permit (LAS 12345), and/or Easement (ADL 123456) number. INSTRUCTIONS The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). Base Kuparuk Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and other tests as required including, but not limited to: core analysis, paleontological report, production or well test results. Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29. Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. 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). Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity, permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology. Form 10-407 Revised 3/2020 Submit within 30 days of Completion, Suspension, or Abandonment 12.15.2020Digitally signed by Monty M Myers DN: cn=Monty M Myers, c=US, o=Hilcorp Alaska, LLC, ou=Technical Services - AK Drilling, email=mmyers@hilcorp.com Reason: I am approving this document Date: 2020.12.15 14:42:18 -09'00' Monty M Myers _____________________________________________________________________________________ Revised By: JNL 12/3/2020 SCHEMATIC Milne Point Unit Well: MPU F-62A Last Completed: 11/22/2020 PTD: 220-066 WINDOW DETAIL Top of Window – 5942’ (TVD 4484’) Bottom of Window – 5954’ Inclination 63.58 deg CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20" Conductor 91.1 / NT80LHE / N/A N/A Surface 112’ 9-5/8" Surface 40 / L-80 / BTC 8.835 Surface 5,942’ 7" Production 26 / L-80 / BTC 6.276 Surface 10,093’ TUBING DETAIL 4-1/2" Tubing 13.5 / L-80 / Hyd 625 3.795 Surface 9,740’ JEWELRY DETAIL No Depth Item 1 9,550’ Zenith 4-1/2” C6 Gauge Carrier Sub 2 9,559’ HES XD Sliding Sleeve 3 9,569’ Zenith 4-1/2” Ported Pressure Sub 4 9,622 4-1/2” x 7” Premier Production Packer 5 9,688’ 4-1/2” XN-Nipple w/ 3.725” No-Go Packing Bore w/ RHC 6 9,740’ WLEG PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status Kuparuk C 9,790’ 9,799’ 7,145’ 7,154’ 9 12/8/2020 Open Kuparuk B6 9,799’ 9,816’ 7,154’ 7,170’ 17 12/8/2020 Open Kuparuk A2 9,879’ 9,889’ 7,228’ 7,237’ 10 11/18/2020 Open OPEN HOLE / CEMENT DETAIL 30" 260 sx of Arcticset (Approx.) 12-1/4" 1,160 sx PF ‘C’, 250 sx Class ‘G’, 250 sx PF ‘E’ 8-1/2” 265 sx Class ‘G’ WELL INCLINATION DETAIL KOP @ 1,000 Max Hole Angle = 66 deg. Hole Angle through perforations = 22 deg. TREE & WELLHEAD Tree 4-1/16” – 5M Cameron NS Wellhead FMC 11” 5M FMC Gen 5 w/ 11” FMC Tubing Hanger, 3.5” NSCT Lift Threads and 3” CIW H BPV Profile Tubing Hanger 4-1/2” Tubing Hanger GENERAL WELL INFO API: 50-029-22609-01-00 Completed: 11/22/2020 Frac Completed (A2): 12/3/2020 Kuparuk C/B perforated: 12/8/2020 TD =10,112’ (MD) / TD = 7,445’(TVD) 20” Orig.DF Elev.: 45.12’/ GL Elev.: 12.0’ Doyon 14 7” 6 5 4 9-5/8” 1 2 PBTD =10,010’ (MD) / PBTD = 7,350’(TVD) 3 TOC on 7"- CBL 8910' MD MPF-62 TOWS 5942'MD Activity Date Ops Summary 11/4/2020 On MPU L-21A, please see M-21A report for details. 15:27 Nov 4 - Provided 24 hour BOP test notification to the AOGCC. 18:48 Nov 4 - AOGCC inspector Adam Earl waived the right to witness BOP testing Install rear booster tires. Install front booster tire frame and tires. Prepare for rig move to F-pad. Notified pad operator and security of rig move. Move rig from L-pad to F-pad. Remove front and rear booster tires. Move rig around the pad, pull onto F-62A. Spot and level the rig. 11/5/2020 Skid rig floor into drilling position and slide conveyor into normal position. Spot service buildings and trailers. The electrician powered up the top drive. M/U 3 joints of 5" drill pipe, hang stand to verify plumb over the rotary table - good. Rig up. Weld ladder in mud pit #1. Load 290 bbls of 9.5 ppg brine into the pits. Pull BPV, top of cement is 10,801'. Tubing & IA were pressure tested to 2500 PSI pre-rig. Secure well. Spot and R/U rockwasher. Spot 500 bbl flow back tank. Completed rig acceptance checklist - rig accepted at 15:00. Remove check valve on tubing wing. Rig up lines to circulate well to flow back tank. Load 290 bbls of 9.5 ppg brine into the upright tanks. Clear rig floor of 4" handling equipment and remove XT-39 saver sub. PJSM for displacement. *** Rig on high line power at 16:20 *** Pressure test lines to flow back tank to 300 PSI low / 1000 PSI high. Circulate through 3.5" tubing cut at 10,775'. Pump 290 bbls of heated seawater with Deep Clean detergent, 4.5 BPM, 1690 PSI. Pump 30 bbl high vis spacer followed by 473.9 bbls of 9.5 ppg brine, 4.5 BPM, 1770 PSI. Flow check-static Install BPV. Pressure test hanger void to 5000 PSI – good. N/D tree as per Hilcorp wellhead rep. Install test dart in BPV. Verify lifting threads in hanger are good - 3-1/2" NSCT XO made up 7.5 turns. N/U BOP stack and install kill line. Remove upper 2-3/8" solid rams from upper rams. Remove 2-7/8"x5" VBR rams from lower rams and install in upper rams. Install 4-1/2" x 7" VBR rams in lower rams. Sim-ops: welder had to shorten trip nipple 1' due to well elevation Install trip nipple. Install 5" donut test joint and R/U BOP test equipment. Fill stack with water and purge lines. 11/6/2020 R/U BOP test equipment. Flood and purge lines. Shell test 13-5/8" 5M BOP's and choke. Leak on OTECO flange on choke line. Replace and retest (good). Test BOP equipment as per PTD and Hilcorp requirements. AOGCC inspector Adam Earl waived witness at 18:48 on 4 Nov 2020. Test against test dart installed BPV in 7" hanger. All tests performed with fresh water. Test held for 5 min each and charted. Annular tested to 250 PSI low / 2500 PSI high. All other tests performed to 250 PSI low / 4500 PSI high. 1) Upper 2-7/8" x 5" VBR on 5" test joint, choke valves 1, 12, 13, 14, kill Demco, 5" dart & upper IBOP. 2) Choke valves 9, 11, kill HCR, 5" FOSV #1 & lower IBOP. 3) Choke valves 5, 8, 10, kill manual, 3.5" dart 4) Choke valves 4, 6, 7 & 3.5" FOSV. 5) Choke valve 2. 6) Choke HCR. 7) Upper 2-7/8" x 5" VBR on 3.5" test joint & choke manual. 8) Annular on 3.5" test joint. 9) Blind rams & choke valve 3. 10) Super choke A. 11) Manual choke B. 12) Lower 4.5" x 7" VBR on 4.5" test jt. 13) Lower 4.5" x 7" VBR on 7" test jt Accumulator: 3025 PSI system pressure, 1625 PSI after closure, 200 PSI recovery = 38 sec, full recovery = 191 sec. Six nitrogen bottle average 2041 PSI. BOP functioned from both primary & remote controls. No failures. R/D test equipment and blow down top drive, choke and kill lines. Pull test dart & BPV. Install 3.5" NSCT landing joint. Check IA for pressure (static). BOLDS, unseat hanger 97k clean and pull hanger to the rig floor. L/D landing joint & hanger. M/U XO to FOSV, change elevators & R/U casing equipment while monitoring well (static). POOH laying down 3.5# 9.3# L-80 EUE tubing f/ 10775'. Laid down 341 full joints (10,562.42'), cut joint (12.89'), hanger & pups (4.56') + Doyon 14 RKB (30.85') = 10610.72' tubing cut measurement vs. 10,775 slickline measurement. 20:00 - 15 PSI on OA, bleed to 0. 03:00 - 0 PSI on OA. L/D 3.5" casing equipment. Mobilize 7" casing equipment to the rig floor. PJSM. Spot Alaska E-line truck. R/U sheave & wireline hanging on elevators. R/U 5" donut test joint, FOSV, XO and pump in sub. 11/7/2020 Clean and clear rig floor. R/D and L/D 3.5" handling equipment. Stg 7" handling equipment on floor. P./U 5" donut test joint and feed rope socket thru w/ psi control equipment on top. Ak E-line dress tool w/ 5.75" jet cutter, GR, CCL w/ (2) ea. bow spring roller centralizers. Set 5" and close upper pipe rams. flood stack and lubricator. P/T to 500 (c/o plug vavle then tested good). RIH with Jet cutter on E-line to 6246' ELM. Logged up locating collars and identifying 9-5/8 shoe presumably w/ significant Gamma shift. Correlate and adjust ELM for tally. Put cutter on depth @ 6025' ELM. Call clear and fire same. Good indication of fire on rig floor. 7" on vac, OA 400 psi. Pump down kill line taking returns out OA back to flowback tank. Establish circ @ 1.5 bpm, 40 psi. Pump 230 bbls heated seawater w/ deep clean. Shut down monitor well - 200 psi on 7", 0 psi on annulus. Cont pumping a total of 290 seawater, 30 bbls hi vis spacer then disp entire well 9.5 ppg brine. Pull 5" riser, FOSV, XO, pump in sub & grease head. Hoist e-line to the rig floor - weight was lower than expected. E-line CCL, gamma ray, XO, centralizer, bottom sub, firing head & jet cutter were missing (8.95'). Threaded section backed off or parted. R/D e-line. Drain stack, blow down choke and kill lines. Monitor OA - static. M/U pack-off running tool on 5" drill pipe & pup joint. Engage pack-off and BOLDS. Pull pack-off with 12K initial then 2K seal drag. L/D pack-off (in good condition). L/D running tool, 5" drill pipe & pup joint. C/O elevators to 7". P/U 7" landing joint and M/U to hanger ACME thread with 5-3/4 LH turns. P/U to 175K (calculated PU), then pull 225K (1.5' stretch), 250K (2'), 275K (2.5') & 300K (3') working each 3 times with no success. M/U top drive to landing joint. Pull 325K (4' stretch) 3 times. Casing pulled free at 340K (180K overpull). Verify free with 160K PU / 130K SO. Hoist hanger to the rig floor. L/D hanger & landing joint. Perform derrick inspection after pulling on casing. L/D 7" 26# L-80 BTC casing f/ 5982'. Laid down 148 full joints (5962.49') + cut joint (19.91') + RKB, pack-off, hanger, pup (39.95') = 6022.35' casing cut depth vs. 6025' ELM. 7/8" of the circumference was not cut w/ the Jet Cutter. 180K overpull parted it. R/D & L/D casing equipment, hanger, pack-off. Install 9-1/16" I.D. long wear bushing in tubing spool. Mobilize Yellow Jacket BHA components to the rig floor for both the casing scraper and CIBP runs. PJSM. P/U 5" drill pipe (drift w/ 3.15), M/U 7"x8-5/16" starter mill, double pin XO, 9-5/8" casing scraper, bit sub & 8-5/16" string mill to 14.96'. Daily losses = 0 bbls, Cumulative losses = 0 bbls Total. H20 from 6-Mile: 0 bbls Daily / 560 bbls Total. H2O from G&I Source Water: 0 bbls Daily / 0 bbls Total. Recycle to ORT: 300 bbls Daily / 525 bbls Total. Cuttings/mud/cement to MPU G&I: 575 bbls Daily / 1,265 bbls Total. 50-029-22609-01-00API #: Well Name: Field: County/State: MP F-62A Milne Point Hilcorp Energy Company Composite Report , Alaska 11/8/2020 RIH w/ 9-5/8" scraper / cleanout assy (14.96' total length) to 6021' picking up 190 jts of 5" DP. Drift 3.15". Hole took proper displacement. Tag TOF @ 6021' 2x w/ 5k dn (6025' ELM). 150k up, 115k dn. L/D single. CBU @ 6011' MD. Pump @ 10 bpm, 470 psi, 21% flow out. Saw trace of crude and fine sand @ btms up. Gas climbed to ~300u then dropped off and shakers cleaned up. Circulated a total of 460 bbls. Flood Beyond MPD lines. Pressure test MPD lines and choke 250 / 1500 psi w/ 5 min hold on each (test good). PJSM, Cut and slip 73' drilling line. Svc and inspect line wt sensor, saver sub, brakes and traveling equipment. Monitor well via trip tank (static). POOH F/ 6011' - T/ 14' racking back 5" dp in derrick. L/D 9-5/8" casing scraper assembly. Note: 10 missing cuttings and 5 chipped on gauge of starter mill. Will pick-up back up starter mill on whipstock run. M/U 9-5/8" CIBP, running tool & XO to 6.07'. RIH with CIBP on 5" drill pipe f/ 6' t/ 5960', 148K PU / 120K SO. Pump fluid through mud pump pop-off lines. #1 good but #2 didn't release until 2000 PSI & held 1800 PSI while pumping 3 SPM indicating restriction. Isolate #2 pump to troubleshoot. Pressure test mud lines to 4000 PSI - good test. *** Remove & inspect pop-off. Found rubber in pop-off. Replaced *** Drop 1-1/4" phenolic ball and allow to free fall for 20 min. Pump 2.2 BPM, 70 PSI. Ball on seat at 469 strokes. Pressure up to 2120 PSI and observe slips set as pressure dropped to 1820 PSI. Bleed off pressure. P/U to 200K (50K over) w/ 2.4' of travel. Hold for 5 min to set element. S/O to 149K. Turn string 11 turns to the right to release. P/U with 147K, verified release. Rack back stand to 5907'. Blow down top drive. Top of bridge plug at 5960'. Rig up to test casing. Pump down drill pipe and kill line against closed upper 2-7/8" x 5" VBR on 5" drill pipe. Hold 2900 PSI for 30 minutes on chart - good test. R/D test equipment and blow down lines. PJSM w/ Doyon, M-I & DSM. Pumped 25 bbl high vis spacer and displace wellbore with 422 bbls of 9.5 ppg LSND mud, 8 BPM, 260 PSI. Dumped 8.5 bbls interface before returning back to the pits. Flow check - static. Blow down top drive. POOH f/ 5907' t/ 2384'. Pipe was pulling wet, pumped dry job at 5022' and blew down top drive. Daily losses = 0 bbls, Cumulative losses = 0 bbls Total. H20 from 6-Mile: 100 bbls Daily / 660 bbls Total. H2O from G&I Source Water: 0 bbls Daily / 0 bbls Total. Recycle to ORT: 0 bbls Daily / 525 bbls Total. Cuttings/mud/cement to MPU G&I: 0 bbls Daily / 1,265 bbls Total. 11/9/2020 POOH w/ CIBP running tool f/ 2384' t/ 3' and laydown the running tool. Mobilize BHA components to the rig floor. M/U starter mill (7" x 8-5/8" O.D.), watermelon mill (8-5/8" O.D.), 31.75' 5" drill pipe joint, MWD DM & TM collars and float sub to 59.23'. Shallow pulse test MWD at 425 GPM, 700 PSI - good test. Blow down top drive. P/U Yellow Jacket 9-5/8" whipstock slide w/ bottom trip anchor (3° slide - 12' length). M/U to mills with 35K shear bolt. Perform MWD offset - 338/476*360=255.63°. RIH w/ whipstock assembly to 77.74'. Single in the hole w/ 17 joints of 5" HWDP f/ 77' t/ 604'. TIH out of the derrick w/ 5" drill pipe f/ 604' t/5917'. Fill pipe every 2000', 75'min running speed. 150K PU / 115K SO. Orient whipstock 42°R with 460 GPM, 960 PSI. Slack off from 5917' and tag CIBP on depth at 5960' with 10K to set anchor. Continue to slack off, 35K shear bolt released at 38K. Mill window in 9-5/8" casing from 5942' to 5960' as per Yellow Jacket, 505 GPM, 1125 PSI, 90-130 RPM, 6-9K TQ, 5-20K WOB. Place full gauge watermelon mill just off whipstock slide. TOW at 5942' MD / 4485' TVD and BOW at 5954' MD / 4490' TVD. Pumped high vis sweeps at 5949' and 5960' - no increase of cuttings observed. 70# of metal recovered. Dress window from 5960' to 5940' three times w/ no torque or drag observed. Slack off with no rotation from 5940' to 5960' - no drag observed. 450 GPM, 1000 PSI, 110 RPM, 6K TQ. Drill 8-1/2" hole f/ 5960' t/ 5982' (22' drilled, 5.5'/hr AROP), 450 GPM, 940 PSI, 120 RPM, 8K TQ, 25K WOB w/ mills. 28' drilled f/the bottom of the window, 23' of gauge hole. ROP slowed to 3 FPH, changed parameters from 450-550 GPM, 940-1300 PSI, 95-125 RPM, 6-8K TQ & 10-35K WOB w/ no improvement Pump 15 bbls high vis sweep - no increase observed. Dress window with watermelon mill f/ 5960' t/ 5940', 480 GPM, 1100 PSI, 120 RPM, 6K TQ - to drag or torque observed. Work through with no pumps or rotation - no drag observed. 148K PU / 130K SO. Rack back stand to 5917'. 89# total metal recovered. Blow down top drive & R/U to test. Attempt FIT to 13.0 ppg. Close upper pipe rams on 5" drill pipe then pump down drill pipe and kill line. 9-5/8" shoe at 5954' MD / 4490' TVD. 9.6 ppg MW in/out. Leaked off at 687 PSI for 12.5 ppg EMW. Repeat test with same results. POOH from 5917' to 5430' with good displacement. Pump dry job and blow down the top drive. . Daily losses = 0 bbls, Cumulative losses = 0 bbls Total. H20 from 6-Mile: 0 bbls Daily / 660 bbls Total. H2O from G&I Source Water: 0 bbls Daily / 0 bbls Total. Recycle to ORT: 0 bbls Daily / 525 bbls Total. Cuttings/mud/cement to MPU G&I: 632 bbls Daily / 1,897 bbls Total. 11/10/2020 Continue POOH with 8.5” milling assembly f/ 5430’ t/ surface. Rack DP & HWDP in Derrick, L/D milling assembly. Mills 1/8” under gauge. M/U stack washing tool, flush Stack & Clear mill components from rig floor. M/U 8.5” kick-off BHA, NOV PDC, StrataForce mud motor with 1.5° bend, DM collar,TM collar & float sub, 9x HWDP, Jars & 8x HWDP. Shallow pulse test MWD - Good. RIH f/ 611’ t/ 4611’ picking up 5” DP singles from shed. PU = 139k, SO = 120k. TIH with stands from Derrick f/ 4611’ t/ 5943’. PU = 145k, SO = 127k Orient TF t/ 40° R HS. RIH t/ BOW with no pumps, assembly took 5k wt. Work string 1x – clean. Engage pumps and wash down t/ 5982’. 400 GPM, 1120 psi. Drill 8.5" hole f/ 5982’ t/ 6133' (4568' TVD) 151 drilled, 100’/hr AROP. 500 GPM, 1630 psi, 60 RPM, 8k Tq, 7k WOB. MW in/out 9.6/9.65, vis in/out 46/46. Max gas 33u. 149k PU / 120k SO / 132k ROT. The Raw survey @ 6094.5' with 60.91° inc & 355.78° az, showing mag interference. Projected separation from parent wellbore @ 6133' is 20.65' Circulate hole clean w/ bottoms up, Rot & Recip f/ 6133’ t/ 6039’. Obtain SPR’s. Monitor well - Static. POOH f/ 6133’ t/ 5938’, correct displacement. Observe 5-10k drag pulling BHA through window. Pump dry job & B/D TopDrive. POOH on elevators f/ 5938’, rack back all DP, HWDP & Jars. L/D MWD tools & Motor. Bit grade = 1-1-CT-G-X-I-NO-BHA. Clear and clean rig floor. PJSM. M/U 8-1/2" NOV SK616M-J1D bit, 7600 Geo-Pilot, MWD w/ ADR, ILS, DGR, PWD, DM, ALD, CTN & TM collars, float sub, to 115’. Test & initialize MWD tools. Shallow hole test MWD M/U 8-3/8” IBS & NM Pony Collar. PJSM & Load Sources then M/U remaining BHA w/ NOV 8-1/2”x9-7/8” under-reamer, NM Pony Collar, & 2x float subs t/ 167'. RIH w/ HWDP & jars to 552' TIH on 5" Drill pipe f/ 552' t/ 2630'. Hole taking proper displacement. Fill pipe & Break in RSS Seals Daily losses = 0 bbls, Cumulative losses = 0 bbls Total. H20 from 6-Mile: 115 bbls Daily / 775 bbls Total. H2O from G&I Source Water: 0 bbls Daily / 0 bbls Total. Recycle to ORT: 0 bbls Daily / 525 bbls Total. Cuttings/mud/cement to MPU G&I: 114 bbls Daily / 2,011 bbls Total. 11/11/2020 Continue TIH wtih 8.5''x9.875'' RSS drilling assembly f/ 2630' t/ 5864’. Fill pipe every 2000’ Service Drawworks, Iron Roughneck and TopDrive. RIH f/ 5864’ t/ 6133’. See 15-20k drag with BHA going down through window, no overpull when worked back up. Flow 100 GPM, 200 psi washing down t/ 6100’ then ream to bottom w/ 60 RPM, 5k Tq, 477 GPM – 1580 psi. Drill 8.5" hole f/ 6133’ t/ 6186’ 477 GPM, 1580 psi. 85 RPM, 9k Tq. Drop 1.375" ball to engage under reamer. P/U to 6174’ bit depth, (6029’ reamer blade depth), and pump down activation ball at 400 GPM See 100 psi pressure drop & 10k spike in Tq, indicating under-reamer opened. Ream down 5’ f/ 6174’ t/ 6179’. Pull back up with no ROT & Pulled 10k @ 6174’. Reamer open. Good Drill 8.5"x9.875” hole f/ 6186’ t/ 6293' (4573' TVD) 107' drilled, 80.45/hr AROP. 560 GPM, 1830 psi, 120 RPM, 9k Tq, 15k WOB. MW in/out 9.5/9.5, vis in/out 44/47. ECD 10.51, Max gas 64u. 160k PU / 118k SO / 139k ROT. Shakers blinding off. Screen down f/ 170’s to 140’s, Recip pipe f/ 6280’ t/ 6269’ flow @ 125 gpm until cleaned up. Drill 8.5"x9.875” hole f/ 6293’ t/ 6904' (5041' TVD) 611' drilled, 111’/hr AROP. 550 GPM, 1900 psi, 120 RPM, 11k Tq, 15k WOB. MW in/out 9.5/9.5, vis in/out 42/45. ECD 10.51, Max gas 125u. 183k PU / 129k SO / 154k ROT. Drop & Turn t/ 6700' targeting 5° DLR. Hold 47.92° inc, 19.95° az tangent f/ 6700' Drill 8.5"x9.875” hole f/ 6904’ t/ 7390' (5364' TVD) 486' drilled, 81’/hr AROP. 550 GPM, 2090 psi, 120 RPM, 11k Tq, 18k WOB. MW in/out 9.5/9.5, vis in/out 42/45. ECD 10.68, Max gas 152u. 185k PU / 132k SO / 154k ROT. Hold 47.92° inc, 19.95° az tangent Drill 8.5"x9.875” hole f/ 7390’ t/ 8043' (5802' TVD) 653' drilled, 109’/hr AROP. 600 GPM, 2730 psi, 150 RPM, 12k Tq, 24k WOB. MW in/out 9.5/9.5, vis in/out 62/100. ECD 11.66, Max gas 65u. 185k PU / 145k SO / 152k ROT Pump Low Vis/Weight, High Vis/Weight Tandem sweeps @ 7485’. Back on time w/ 20% increase in cuttings return. Hold 47.92° inc, 19.95° az tangent. Last survey @ 7892.07' MD / 5700.38' TVD, 47.95° inc, 19.55° azm, 2.56' from plan, 1.68' high & 1.94' right. Daily losses = 0 bbls, Cumulative losses = 0 bbls Total. H20 from 6-Mile: 610 bbls Daily / 1,385 bbls Total. H2O from G&I Source Water: 0 bbls Daily / 0 bbls Total. Recycle to ORT: 0 bbls Daily / 525 bbls Total. Cuttings/mud/cement to MPU G&I: 689 bbls Daily / 2,700 bbls Total. 11/12/2020 Drill 8.5"x9.875” hole f/ 8043’ t/ 8552' (6142' TVD) 509' drilled, 85’/hr AROP. 590 GPM, 2730 psi, 150 RPM, 15k Tq, 25k WOB. MW in/out 9.4/9.5, vis in/out 57/105. ECD 11.15, Max gas 65u. 205k PU / 140k SO / 161k ROT. Hold 47.92° inc, 19.95° az tangent Drill 8.5"x9.875” hole f/ 8552’ t/ 8913' (6388' TVD) 361' drilled, 90’/hr AROP. 580 GPM, 2840 psi, 150 RPM, 15k Tq, 23k WOB. MW in/out 9.5/9.5, vis in/out 105/300. ECD 11.87, Max gas 72u. 228k PU / 132k SO / 167k ROT. Hold 47.92° inc, 19.95° az tangent t/ 8911’ then start 5° DLR Drop & Turn. Mud Vis climbed to 245 & ECDs spiked to 11.9 ppg due to high clay concentrations in system. causing flocculation when KCl added. Start control drilling @ 75’/hr, adding 70 BPH H2O & treating mud to work ECDs down. Circ and condition mud, drop ECD’s from 11.87 to 11.33 ppg. 530 GPM – 2710 psi, 60 RPM – 20k Tq. Recip pipe f/ 8911’ t/ 8813’. SimOps: Prep pits and trucks for dump & dilute. Drill 8.5"x9.875” hole f/ 8913’ t/ 8940' (6406' TVD) 37' drilled, 75’/hr AROP. 550 GPM, 2792 psi, 160 RPM, 19k Tq, 25k WOB. MW in/out 9.4/9.5, vis in/out 152/300. ECD 11.91, Max gas 66u. ECD’s spike back up to 11.91 ppg once new cuttings introduced to system. Circ and condition mud, drop ECD’s from 11.91 to 11.05 ppg. 450 GPM – 2710 psi, 30 RPM – 14k Tq. Recip pipe f/ 8940’ t/ 8807’. Continue prep pits and trucks for dump & dilute. PJSM. Install split bushings & Remove trip nipple. Install MPD rotary head. Break in RCD bearing @ 1/2 BPM, 340 /830 psi Stage pumps up f/ 350 GPM–1590 psi t/ 575 GPM–2830 psi, 11.22 ppg ECD. Rot & Recip f/ 8940’ t/ 8907’, 30 RPM – 15k Tq. Cont treat mud. Finish Prep for dump and dilution Drill 8.5"x9.875” hole f/ 8940’ t/ 9196' (6604' TVD) 256' drilled, 64’/hr AROP. 600 GPM, 2890 psi, 150 RPM, 17k Tq, 22k WOB. MW in/out 9.5/9.5, vis in/out 50/57. ECD 11.15, Max gas 125u. 235k PU / 145k SO / 175k ROT. Perform dump & dilute, 490 bbls whole mud, w/ black products, @ 8970’. Continue 5° DLR Drop & Turn. MPD full open while drilling. Shut in during conn to observe any pressure increase. No increase observed. Drill 8.5"x9.875” hole f/ 9196’ t/ 9542' (6917' TVD) 346' drilled, 58’/hr AROP. 600 GPM, 2980 psi, 150 RPM, 18k Tq, 24k WOB. MW in/out 9.5/9.55, vis in/out 54/74. ECD 11.29. Max gas 95u. 245k PU / 145k SO / 181k ROT Hold 21° inc, tangent. Last survey @ 9412.37' MD / 6794.94' TVD, 23.27° inc, 10.23° azm, 2.56' from plan, 1.68' high & 1.94' right. MPD full open while drilling, Target 560 psi on connection to achieve a 11.1 ppg EMW Daily losses = 0 bbls, Cumulative losses = 0 bbls Total. H20 from 6-Mile: 1710 bbls Daily / 3,065 bbls Total. H2O from G&I Source Water: 0 bbls Daily / 0 bbls Total. Recycle to ORT: 0 bbls Daily / 525 bbls Total. Cuttings/mud/cement to MPU G&I: 2,103 bbls Daily / 4,803 bbls Total. 11/13/2020 Drill 8.5"x9.875” hole f/ 9543’ t/ 9909' (7257' TVD) 366’ drilled, 61’/hr AROP. 590 GPM, 3030 psi, 150 RPM, 19k Tq, 23k WOB. MW in/out 9.5/9.6, vis in/out 52/68. ECD 11.44 max gas 460u. 250k PU / 150k SO / 195k ROT. Hold 21° inc, tangent MPD full open while drilling, Trap 577 psi on connection to maintain a 11.1 ppg EMW at the Kalubik. Top of Kalubik logged @ 9523'. Top of Kup D Shale @ 9627'. Top of Kup C Sand @ 9790'. Top of Kup A Sand @ 9853' Drill 8.5"x9.875” hole f/ 9909’ t/ 10112' (7445' TVD) 203’ drilled, 45’/hr AROP. 600 GPM, 3060 psi, 120 RPM, 23k Tq, 16k WOB. MW in/out 9.4/9.6, vis in/out 46/65. ECD 11.13 max gas 551u. 270k PU / 155k SO / 197k ROT. Hold 21° inc, tangent to TD MPD full open while drilling, Trap 577 psi on connection to maintain a 11.1 ppg EMW at the Kalubik. Top of Miluveach logged @ 9964'. Final survey @ 10042.52' MD / 7380.48' TVD, 21.27° inc, 358.86° azm, 6.59' from plan, 0.72' high & 6.55' right. L/D single to mousehole. Drop 1 7/8" closing ball to close reamer. Pump down at 430 GPM- 1800 psi. Observed pressure increase to 1900 psi then fall back to 1800 psi indicating ball seat and shift. Shut pumps down for 2 min to let reamer blades relax. Pump tandem sweep. Low wt low vis/ high wt High vis. Pump around at 615 GPM – 3080 psi. Rot 120 RPM – 23k Tq, & Recip 90’, Max gas = 915u. Sweep brought back minimal increase, came back on time. Weight up to 10.5 ppg. Hold back pressure following MPD pressure schedule. 10.5 ppg in and out @1.5x circulations. Initial flow @ 550 GPM - ECD 10.97, Final flow @ 400 GPM - ECD 11.72 ppg Rot 60 RPM, work pipe 90’. Build and spot 65 bbls liner running pill: 1.5% LoTorq, 6 PPB Asphasol & Resinex. 400 GPM, 1730 psi. 40 RPM, 17k Tq. P/U single from mousehole & rack 1 stand back. MPD trap 200 psi, monitor pressure for build - No increase. Line up Rig pump to MPD lines. Blow down Topdrive. Stage pump up to 200 GPM, 700 psi POOH on elevators 20-45'/min f/ 10053' t/ 5866’. MPD holding 220 psi static / 490 psi dynamic backpressure on Well Following schedule, dynamic pressure reduced t/ 370 psi by window @ 5954’. Hole took calculated fill. Constant drag swings of 10-25k from 10053’ to 8226’ then smoothing out with 5-15k swings to the window. See 15-25k overpull with BHA: under-reamer, stabilizers and wear-bands coming through window. Circulate casing clean with 2x BU. 500 GPM, 2000 psi. 20 RPM, 7k Tq. 11.85 ppg ECD. Reciprocate string 90’. No losses. Monitor Well – Static. B/D TopDrive, Line up Rig pump to MPD. Stage pump up to 200 GPM, 500 psi POOH on elevators 60-90’/min f/ 5866' t/ 2535'. MPD holding CBHP w/220 psi static & 480-290 psi dynamic backpressure on Well as per schedule. No losses on TOH. Daily losses = 0 bbls, Cumulative losses = 0 bbls Total. H20 from 6-Mile: 910 bbls Daily / 4,005 bbls Total. H2O from G&I Source Water: 0 bbls Daily / 0 bbls Total. Recycle to ORT: 0 bbls Daily / 525 bbls Total. Cuttings/mud/cement to MPU G&I: 908 bbls Daily / 5,711 bbls Total. 11/14/2020 POOH on elevators 60-90’/min f/ 2535' t/ 821’. MPD holding CBHP w/220 psi static & 290 psi dynamic backpressure on Well. Calculated 13 bbls loss while TOH. Drain riser and Monitor Well. Breathing at 1.6 BPH slowing to .7 BPH in 45 min. Rig down MPD RCD and install trip nipple. Well stayed at .7 BPH while rigging down. Flowed back 1.9 bbl total. Discuss options with town engineer and decision made to RIH to 2000’. Wt up and place a 13.0 PPG mud cap. Trip in hole f/ 821' t/ 2155'. Monitor well at MPD head while prep pits to weight up system. Continued returns at 0.7 BPH rate. Weight up system f/ 10.5 ppg t/13.0 ppg spotting cap from 2155’ to surface. 5.5x circulations @ 5 BPM – ICP 300 psi, FCP 560 psi. 20 RPM – 1k Tq. Recip string 60’ Blow down TopDrive, Monitor well – Static. POOH f/ 2155’ t/ surface. Rack DP, HWDP & Jars in Derrick. L/D BHA. Bit Graded: 1-2-CT-G-X-I-NO-TD. Under-Reamer showed little to no wear. Observed 2x ~1/8" grooves scored in the DM Collar, Abrasive Wear on lower side of wear bands on the PWD-ADR-DGR Collar Clear & Clean rig floor. Pull wear bushing. Perform Dummy run w/ 7” hanger. Wellhead Rep verify good landing. Mobilize and R/U 7" casing equipment to rig floor. M/U Volant CRT & R/U strap tongs. M/U XO to FOSV. Monitoring well via trip tank. -Static- PJSM. M/U 7” shoe track & check floats. Run 7” 26#, L-80 TXP BTC casing f/ 120’ t/ 2270'’. Start 60’/min max running speed, reducing to 45’/min at 1500’ & 30'/min @ 1750'. Tq casing w/ Volant CRT to 15,000 ft/lbs. Filling pipe on the fly, top off every 10 jts. Install 2x 7”x8.25” OMD 4RIB SS Cent each jt to #1-3, then 1 cent each jt #5-26. Getting calculated displacement back. 85k PU / 84k SO Daily losses = 10 bbls, Cumulative losses = 10 bbls Total. H20 from 6-Mile: 110 bbls Daily / 4,115 bbls Total. H2O from G&I Source Water: 0 bbls Daily / 0 bbls Total. Recycle to ORT: 0 bbls Daily / 525 bbls Total. Cuttings/mud/cement to MPU G&I: 92 bbls Daily / 5,803 bbls Total. 11/15/2020 Run 7” 26#, L-80 TXP BTC casing f/ 2270’ t/ 5905’. 45-60’/min running speed. Tq casing w/ Volant CRT to 15,000 ft/lbs. Filling pipe on the fly, top off every 10 jts. 145k PU / 110k SO Circ and condition mud. Stage pump up t/ 6 BPM - 380 psi. Circulate until mud even in and out. 2x BU pumped. Mud wt in/out – 10.5 ppg, Vis in/out 45/45. 147k PU / 120k SO / 135k ROT @ 10 RPM - 5k Tq Run 7” 26#, L-80 TXP BTC casing f/ 5905’ t/ 8230’. 45-60’/min running speed. Tq casing w/ Volant CRT to 15,000 ft/lbs. Filling pipe on the fly, top off every 10 jts & circulate 1 jt down for 5 min every 20 jts. Start to lose mud dynamically, not getting back displacement returns. 220k PU / 120k SO Attempt to establish circulation. Pump 1 BPM – 700 psi. Work string 30’. No success at regaining circulation, 20 bbls loss while pumping and working pipe. Run 7” 26#, L-80 TXP BTC casing f/ 8230’ t/ 10012’. 45-60’/min running speed. Tq casing w/ Volant CRT to 15,000 ft/lbs. Filling pipe on the fly, top off every 10 jts Stage up pumps to 2 BPM. Wash down f/ 10012' t/ 10080'. UP/DN 300k/140k. M/U hanger& landing joint at 10053’. Tag fill @ 10080’. Over pull 50k coming out of fill. Work string several times 125k to 350k, before establish free slack off and pick at 140k/300k Work string down, washing @ 2.5 BPM 650 psi, no returns. Land hanger at planned depth. 10092’. Reciprocate pipe F/ 10092' T/ 10072' Pump 1-2 BPM. No Returns. PJSM with HES, Shut down pumps. Pumped total of 62 bbls. Break out Volant & R/U cmt lines with wash up line. Attempt to circ while HES batches up spacer. Stage up to 5 BPM–870 psi, no returns. 45 bbls pumped. Work pipe 20' 310k PU/ 130k SO Line up to HES. Pump 5 bbls water. Test lines to 1000/3000 psi. Good. Line up and pump and mix and pump 60 bbls 11.5 ppg tuned spacer, 4 BPM. Drop btm plug. Mix and pump 54 bbl 15.8 ppg Class G cmt. 265 sks, 3.88 BPM. Flush cmt lines from cmt unit to pits. Drop top plug. HES pump 10 bbls H2O to launch plug. Displace with rig, 10.5 ppg brine with .06% Safe lube for CBL & Gun runs. Displace at 5 BPM until the last 20 bbl. Slow pumps to 3 BPM. Land hanger. Bump plug on calculated strokes. 3690 strokes. 372.69 bbl. CIP at 03:53 Hold 500 over bump pressure. 1530 psi. Final lift pressure 1030 psi. Check floats. Good. Total losses during the cmt job 520 bbls. Reciprocated pipe 20' during the cmt job until the last 20 bbls of displacement. No returns throughout job. TOC calculated at 9248’ Blow down lines. L/D Landing jt & R/D 7” handling equipment. M/U Pack-Off running tool & seat on hanger. RILDS & Test void 500 psi/5min, 5000psi/10min - Good Daily losses (Midnight) = 162 bbls, Cumulative losses = 162 bbls Total. H20 from 6-Mile: 195 bbls Daily / 4,310 bbls Total. H2O from G&I Source Water: 150 bbls Daily / 150 bbls Total. Recycle to ORT: 0 bbls Daily / 525 bbls Total. Cuttings/mud/cement to MPU G&I: 340 bbls Daily / 6,143 bbls Total. 11/16/2020 Swapped to completions AFE @ 06:00. Activity Date Ops Summary 11/16/2020 L/D Pack-Off running tool. Clean and clear rig floor of 7" casing handling equipment.,Cut and slip 73' drilling line. Calibrate blocks.,Service Rig: TopDrive, Drawworks & Iron Roughneck.,Install mousehole in rotary table, Lay down 6 stands 5" HWDP, Jars & 105 Stands 5" Drill Pipe from Derrick. Remove mousehole from rotary table. Clean and clear rig floor and install 7.5" ID Wear Ring.,Rig up test equipment, Close Blind Rams, purge air from pumps and lines. Test casing 7" casing t/ 4000 psi. Bleed pressure down. 4.0 bbls pumped, 4.0 bbls returned. Good test. Rig down test equipment. Blow down. Mobilize 4" handling equipment and floor valves to rig floor.,PJSM with rig and HES wireline crew. R/U HES E-Line for logging run. RIH with CBL, CCL/GR correlation logging tools. SimOps: Pump 63 bbls freeze protect 7’’ X 9 5/8 while logging. ICP 650 psi @ 1 BPM, FCP 1380 psi @ 1 BPM, test 4” FOSV & Dart Valve,Daily losses (Midnight) = 627 bbls, Cumulative losses = 789 bbls Total. H20 from 6-Mile: 225 bbls Daily / 4,535 bbls Total. H2O from G&I Source Water: 0 bbls Daily / 150 bbls Total. Recycle to ORT: 0 bbls Daily / 525 bbls Total. Cuttings/mud/cement to MPU G&I: 447 bbls Daily / 6,590 bbls Total. 11/17/2020 Perform CBL, CCL/GR correlation log. Log f/ 10002’ t/ 8300’. Logged top of cmt at 8910’. POOH and rig down HES E-Line. SimOps: Finish testing 4” FOSV & Dart Valve. 250/4000 psi, 5 min each test.,Mobilize Perf guns, firing head and xo’s to rig floor. Hold PJSM with Pollard, HES and rig crew.,M/U 10’ 3-3/8” 6 SPF 60 deg phasing perf guns, firing head and xo to 4” XT39 t/ 16'. Pick up 2 jts 4” DP, 4.49’ pup jt and RIH picking up 4” DP from shed t/ 1444',Continue to RIH with 3 3/8'' perf gun singling in on 4'' DP f/ 1444'. Tag PBTD at 10006' with 5K. P/U t/ 9999’, L/D 1 joint DP. 200K PUW / 110K SO.,Rig up HES wireline with GR/CCL and RIH. Log f/ 9964' t/ 9496'. Discuss logs with Town Engineer. Decision made to put Perf guns on depth and re-log to ensure accuracy.,Pull up hole, laying down 4 jts drillpipe f/ 9999' t/ 9876'. Space out with 15.63' pup jt, setting string in tension on drillpipe depth at 9889.73'.,Wireline log with GR/CCL f/ 9860' t/ 9470'. Discuss logs with Town Engineer. 4' correction calculated. POOH and rig down HES E-Line.,Rig up 4" FOSV, side entry sub & 10' pup joint.,Fluid U-Tubing out drillpipe. Pick string up 4' setting perf guns on correlated depth. Line up to side entry sub from cement line and circulate a S/S volume. Stage pumps up f/ 2 BPM - 220 psi t/ 7 BPM - 1200 psi. Brine Wt 10.5 ppg in/out,H20 from 6-Mile: 25 bbls Daily / 4,560 bbls Total. H2O from G&I Source Water: 0 bbls Daily / 150 bbls Total. Recycle to ORT: 0 bbls Daily / 525 bbls Total. Cuttings/mud/cement to MPU G&I: 50 bbls Daily / 6,640 bbls Total. 11/18/2020 Parked on correlated depth with 3 3/8'' perf guns with top shot @ 9879', continues to U-tube out DP at 10.3 ppg, circulate down DP at 7 bpm, 1200 psi dusting up light spots until a good 10.5 ppg brine in and out. Flow check well, static,Drop 1 3/8'' steel ball down DP, close bag, circulate 2.5 bpm, 190 psi with returns out choke, ball on seat at 207 stks, pressure to 1890 psi firing perf gun on depth, top shot @ 9879' & bottom shot @ 9888.84'. P/U 15' above perf parking at 9875', monitor well, static.,With bag closed CBU, stage pump to 6 bpm, 1000 psi with returns out choke via gas buster. At BU take 30 bbls of fluid contaminated with crude oil to rock washer until clean, divert back to pits. Shut down pump,,Monitor well thru gas buster, dead, open bag, DP U-tubing with 10.4 ppg out of DP, Circulate DP volume at 7 bpm, 1200 psi until even 10.5 ppg in/out, shut down pump. Monitor well, static, R/D circulating equipment, blow down lines.,TOOH L/D 4'' drill pipe from 9875' to surface. Inspect and lay down 10' perf gun section. Confirmed all shots fired.. 2 bbl loss on trip out of hole,Pull wear bushing. Drain and flush stack. Clear & clean rig floor.,R/U 4-1/2" handling equipment. Mobilize Tec wire to floor. Monitor on trip tank. Record 0.5 bbl gain. Shut hole fill off and monitor well. Breathing back at 1.5 BPH. Seeing 9.5 ppg crude cut fluid at possum belly.,Rig up 4" handling equipment and RIH with 4" drillpipe t/ 945'. Install FOSV and circulating head pin. 1.5 bbls total breath back,Rig up to cement line to head pin. Circulate 5 BPM - 150 psi while weight up brine t/ 11.5 ppg. Spot 11.5 ppg cap from 945' to surface. Take initial 15 bbls of fluid contaminated with crude oil to rock washer until clean. Max gas - 33u,Monitor well at trip tank for 30 min. Initial returns @ 0.3 BPH leveling off 0.7 BPH after 20 min. SimOps: Continue mobilize 4.5" Centrilift tools to rig floor.,RIH with 4" drillpipe f/ 945' t/ 2016'. M/U FOSV and circulating head pin. Monitor Well at Trip tank while rig up to circulate. Observe returns @ 0.7 BPH. H20 from 6-Mile: 50 bbls Daily / 4,610 bbls Total. H2O from G&I Source Water: 0 bbls Daily / 150 bbls Total. Recycle to ORT: 0 bbls Daily / 525 bbls Total. Cuttings/mud/cement to MPU G&I: 0 bbls Daily / 6,640 bbls Total. 11/19/2020 With string parked @ 2016' MD, establish circulation @ 2 BPM – 40 psi. Due to crude contamination in returns, decision made to circulate through choke as precaution. Shut down pumps, close bag and line up to circulate through gas buster while weight up 11.5 ppg in/out. 2 BPM – 70 psi. Max gas of 94u.,Monitor Well. Returns @ 0.1 BPH. Rig down circulating equipment.,Continue to single in with 4" drill pipe f/ 2016' t/ 4547'. 4.5 bbl gain over calculated hole fill. Note: 10.3 ppg return fluid,Due to crude contamination in returns- close bag and line up to circulate through gas buster while weighting up 11.5 ppg in/out. 2 BPM – 95 psi. Max gas of 34u. 10 bbls crude contaminated brine sent to rockwasher.,Monitor the well, slight flow going static in 10 min, open bag, monitor for another 10 min, well is static. R/D circ hose, pup jt and FOSV, BD lines,Continue to single in with 4" drill pipe f/ 4547' t/ 9790'. P/U 185k, S/O 112k,Install FOSV and circulating head pin. Rig up to pump down drillpipe from cement line, close annular and open up to take returns through gas buster. Circulate @ 2 BPM, 110 psi while weight up system to even 11.5 ppg in/out. Gas up to 820u with 65 bbls pumped and peak @ 885 units with bottoms up & 10.4 ppg brine return.,Shut down and monitor well. - Static. Drain gas buster & blow down choke manifold while monitoring.,Circulate bottoms up @ 6 BPM. No increase in gas or reduction in brine wt with bottoms up. Shut pumps down and fluid U-tubing up drill string. Circulate drillpipe volume 2x to balance system. Monitor well at trip tank while rig down cement hoses and blow down. - Well static. Remove FOSV,POOH laying down 4" drillpipe to shed f/ 9790' t/ 7992'. Hole take calculated fill. P/U 180k , S/O 112k,Service TopDrive, Roughneck & Drawworks. Monitor Well at trip tank. - Static,POOH laying down 4" drillpipe to shed f/ 7992' t/ 6949'. Hole take calculated fill. H20 from 6-Mile: 30 bbls Daily / 4,640 bbls Total. H2O from G&I Source Water: 0 bbls Daily / 150 bbls Total. Recycle to ORT: 0 bbls Daily / 525 bbls Total. Cuttings/mud/cement to MPU G&I: 74 bbls Daily / 6,714 bbls Total. 50-029-22609-01-00API #: Well Name: Field: County/State: MP F-62A Milne Point Hilcorp Energy Company Composite Report , Alaska 11/20/2020 POOH laying down 4" drillpipe to shed f/ 6949' t/ 2368'. Hole taking calculated fill on TOOH.,Monitor well, C/O hydraulic hose on SD-80,Continue TOOH L/D 4'' drill pipe f/ 2368' to surface. Note: flow check the well at 500', static. Correct displacement on trip out,R/U BOP test equipment, install test plug and 4.5 test joint, flood stack and lines with water, perform shell test to 4000 psi, good,Test BOP equipment as per PTD and Hilcorp requirements. AOGCC inspector Austin McLeod on location to witness test. All tests performed with fresh water against test plug. Test held for 5 min each and charted. Annular tested to 250 PSI low / 2500 PSI high. All other tests performed to 250 PSI low / 4000 PSI high.,1) Annular on 4.5" test joint. 2) Upper 2-7/8" x 5" VBR on 4.5" test joint, choke valves 1, 12, 13, 14, kill Demco & upper IBOP. 3) Choke valves 9, 11, kill HCR & lower IBOP. 4) Choke valves 5, 8, 10, kill manual, 4" FOSV #1. 5) Choke valves 4, 6, 7 & 4" FOSV #2. 6) Choke valve 2 & 4” Dart Valve. 7) Choke HCR & 3.5” FOSV. 8) Choke manual & 3.5” Dart Valve,9) Lower 4.5" x 7" VBR on 4.5" test jt. 10) Blind rams & choke valve 3. 11) Super choke A & Manual choke B. Gas Alarms Tested. Accumulator: 3000 PSI system pressure, 1675 PSI after closure, 200 PSI recovery = 33 sec, full recovery = 228 sec. Six nitrogen bottle average 2179 PSI. BOP functioned from both primary & remote controls. No failures.,R/D test equipment and blow down top drive, choke and kill lines. Pull test plug.,R/U 4.5” handling equipment. M/U FOSV t/ XO & verify make up on jt.,PJSM. P/U WLEG shoe jt, Verify ball and rod seat on RHC & M/U XN nipple, jt 4.5” tubing, Baker Premier Packer and jt 4.5” tubing to 162’. M/U Baker Zenith gauge carrier, HES XD Sliding sleeve, XO’s & ported pressure sub assembly.,Verify OD’s & SN’s. The pressure ported sub OD measures 6.875” and serial number not match spec sheet. Discover that wrong pressure ported sub was sent from CENtrilift to machine shop when assembly M/U. Correct sub found in CENtrilift shop and mobilize to rig.,Attempt to break out pressure ported sub with casing tongs with no success due to wrong collar and sub sizing for tong set up, cannot break with rig tongs without risking damage to tubing. Lay down gauge carrier assembly and send to machine shop with correct pressure ported sub to be made up. Monitor well on trip tank, 1 bbl Loss recorded. Service rig, prep moving system for Rig move & perform general housekeeping. H20 from 6-Mile: 90 bbls Daily / 4,730 bbls Total. H2O from G&I Source Water: 0 bbls Daily / 150 bbls Total. Recycle to ORT: 0 bbls Daily / 525 bbls Total. Cuttings/mud/cement to MPU G&I: 0 bbls Daily / 6,714 bbls Total. 11/21/2020 Gauge carrier assy arrived with correct pressure ported sub bucked up from baker machine at 06:30, Load into the pipe shed and mobilize to the rig floor,M/U Baker Zenith gauge carrier, HES XD Sliding sleeve, XO’s & ported pressure sub assembly. Install control line f/ ported pressure sub to gauge carrier, test same, terminate 1/4'' tech wire,,Drift, P/U and RIH w/ 4.5" 13.5# L-80 Hyd 625 Frac string f/ 197' to 2886', torque to optimum @ 9600 ft/lbs. Install 1 cannon clamp on every jt for 1st 5 joints, then on every other joint. Test tech wire at 1000'. PU 65K, SO 65K. No loss / No Gain on trip in hole,Continue to P/U and RIH w/ 4.5" 13.5# L-80 Hyd 625 Frac string f/ 2886' to 9704', torque to 9600 ft/lbs. Install 1 cannon clamp every other jt, test tech wire every 2000'. No Gain/Loss while running 4.5" string.,C/O elevators, P/U joint of 4” XT39 Drill Pipe and M/U crossovers to 4.5” Hyd 563. M/U Hanger & Terminate TEC wire. Drain stack. RIH and land 4-1/2” tubing on Hanger. 142k PU / 102k SOW. 62k on Hanger. RILDS. Total of 257 jts, 4.5" 13.5# L-80 Hyd 625 Tubing ran putting WLEG @ 9739.83’. Total 125 cannon clamps installed.,Rig up to reverse circulate down IA, taking returns up tubing. Test lines. Hold PJSM, Reverse circulate 135 bbls 10.5 ppg CIB & 45 bbls diesel, freeze protect to 2500'. 3 BPM, ICP 570 psi, FCP 980 psi @ 1.8 BPM. Max Gas - 703u,Shut in IA. Monitor at tubing. Static. Drop 1.88" Ball and rod. Let free fall for 15 min. Engage pumps to set Baker Premier Packer @ 1 BPM. Pressure to 1750 psi, 1.8 bbls, and see indication of 1st shear. Continue pressure up and see indication of 2nd shear @ 2500 psi, 2.3 bbls. Pressure to 3500 psi, 2.7 bbls and hold for 10 min- good. Bleed off pressures. Packer set @ 9622',Line up test equipment, lines and gauges to test Tubing and IA. Test tubing t/ 4100 psi, 30 charted minutes- good. Bleed pressure down to 1550 psi and trap. Test IA t/ 4400 psi, 30 charted minutes - good. Tubing pressure increase to 2800 psi and held. Bleed off pressures and rig down test equipment.,Back out joint from hanger, break out XO’s. L/D joint. Make up T-Bar & Install BPV.,Rig down circulating equipment and blow down lines. PJSM & Nipple down BOPE. H20 from 6-Mile: 50 bbls Daily / 4,780 bbls Total. H2O from G&I Source Water: 0 bbls Daily / 150 bbls Total. Recycle to ORT: 0 bbls Daily / 525 bbls Total. Cuttings/mud/cement to MPU G&I: 0 bbls Daily / 6,714 bbls Total. 11/22/2020 Remove trip nipple, N/D BOPs, set stack on stump . Flush lines and clean in pits,Cleanup wellhead, terminate tech wire thru tbg spool. NU adaptor flange, WHR test hanger void to 500 psi for 5 min, 5000 psi for 10 min, good, install BPV dart. N/U tree. Centrilft take final readings, 4130.1 tbg psi/ 4134.01 ann psi/ Tbg temp 159.9,/ann temp 160.2,/ Vx 0.203/ Vz 0.225/ Vt 20.1. Continue to flush lines and clean in pits, clear rig floor,R/U and test tree with diesel to 250 psi low and 5000 psi high 5 min each, good,,WHR pull dart and BPV., with the test pump using diesel, attempt to test tubing, pressure to 4400 psi while monitoring I/A, the I/A building to 2200 psi, communication w/ I/A,,Troubleshoot I/A pressure increase, bleed off tbg to 0 psi, I/A held 2200 psi, bleed off I/A, Discuss options with town team, WHR re-test hanger void to 5000 psi, good. pressure up tbg to 2500 psi with I/A increasing to 1600 psi. Bleed off tbg, to 0 psi, I/A holding at 1150 psi, Pressure up I/A to 2450 psi, tubing increasing to 950 psi, Notify town team of results. Bleed off tbg and I/A, Secure tree,Decision made to RDMO and have well support run diagnostics to detect where communication is located. R/D test equipment, flush and blow down lines, finish cleaning pits. Release rig at 18:00,See MPU I-40 Drilling report for details. Well Name Rig API Number Well Permit Number Start Date End Date MP F-62A Frac/ CTU/ SL 50-029-22609-01-00 220-066 12/3/2020 12/9/2020 12/4/2020 - Friday No operations to report. 12/2/2020 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary No operations to report. 12/3/2020 - Thursday Frac Assist (Pressure test surface lines 250/4,000psi) Rigged up to IA pumped 3.75bbls DSL Hold 3,000 PSI for FRAC. Bleed IA down w/ 3 bbls Dsl returned. Spot support equipment and remainder of frac equipment. TBT. LRS pressure tested IA lines to 4000 psi. PRV’s set & tested to 3,900 psi. SLB pressure test treating line w/Diesel to 8,000 psi. Pump single stage Frac as follows: Data Fac Pump YF120F, 301 bbls, ISIP, 2,600 psi, Closure 2,100 psi. 49% eff, Estimated Frac Grad. PAD stage 357 bbls YF128FlexD 28# (cross-link gel) No C-Lite. 1PPA – 8 PPA, 1,527 BBLs YF128FlexD (Carbo bond Lite 16/20. Flush stage with water 101 bbls. Did not Screenout , total ~228,375 lbs of proppent behind pipe- 99%. Secure well, FP surface lines. Hand over to MPU slick line for D&T. WELL S/I ON ARRIVAL, R/U & PT PCE 250L/2,500H. DRIFT TBG WITH 3.30" G-RING TO ~9,500' SLM (no spangs at 9,500' SLM, unable to make depth 10,000' SLM). RDMO, CLOSE PERMIT W/PAD-OP. T/I/O = 1,100/174/0 psi. Rig up Pollard E-Line Unit. Stab onto well to pressure test low 300psi, high 3,000psi. Crane and PCE to hoist HES perf guns. Run 1: Perf depth of 9,803' - 9,816', 14.4' CCL offset to top shot, CCL depth 9,788.6'. T/I/O = 1100/174/0 psi. Run 2: Perf depth of 9,790' - 9,803', 14.4' CCL offset to top shot, CCL depth 9,775.6'. T/I/O = 1,100/174/0 psi. . RDMO. Freeze Protect Tbg (Post Frac)(Pressure test surface lines 250/4,000psi) Pump 0.85 bbls down Tbg (Locked up). Bleed Tbg down to 2,000 psi per WSM w/ 0.5 bbls Dsl returned. 12/5/2020 - Saturday No operations to report. 12/8/2020 - Tuesday 12/6/2020 - Sunday CTU #6 2.00" CT 0.156 Wall. Continue MIRU. Test BOPE. MU Nozzle BHA and RIH, tag top of fill at 9,510' start FCO. BHP is equivalent to 11.3 ppg, hold 1,100psi and monitor out rate watching for increase or decrease in rate. Close to perf interval we started losing fluid and backed off the WHP as we were pushing fluid away, held out rate as close to 1:1 as we could. Cleaned out to PBTD at 9,997' CTMD. POOH chasing bottoms up pill. Pump pill for tangent section (6,300'-4,100') and POOH chasing pills. Freeze Protect well from 2,500' TVD to surface with diesel. At surface the well was shut in with 1,207psi WHP. One pick BOP's off the well, install night cap, PT tree cap to 250 low and 4k high. Well secured, return in the AM to RDMO, CTU #6 going back to GPB. 12/7/2020 - Monday Well Name Rig API Number Well Permit Number Start Date End Date MP F-62A Frac/ CTU/ SL 50-029-22609-01-00 220-066 12/3/2020 12/9/2020 12/11/2020 - Friday No operations to report. 12/9/2020 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary WELL S/I ON ARRIVAL, OPEN PERMIT W/PAD-OP, PT PCE 250L/2,500H. MAKE 2 RUNS WITH SWARF MAGNETS UNABLE TO PASS 4250' SLM (no SWARF recovered). RUN 5' x 3" DRIVE DOWN BAILER (mule shoe ball) TO 9,750' SLM (no restrictions). RUN 4-1/2" 42-BO (keys down) TO XD-SS AT 9,554' SLM/ 9,559' MD AND SHIFT OPEN. SET 3"JET PUMP (serial# HC-00018, ratio: 11A, sec lock, screen, OAL=70") IN XD-SS AT 9,554' SLM/ 9,559' MD. RDMO, CLOSE PERMIT W/PAD-OP. 12/10/2020 - Thursday No operations to report. No operations to report. No operations to report. 12/12/2020 - Saturday No operations to report. 12/15/2020 - Tuesday 12/13/2020 - Sunday No operations to report. 12/14/2020 - Monday CASING AND LEAK-OFF FRACTURE TESTS Well Name:MPU F-62A Date: Csg Size/Wt/Grade:9-5/8" 40# L-80 BTC Supervisor:Demoski Csg Setting Depth:5954 TMD 4490 TVD Mud Weight:9.6 ppg LOT / FIT Press =624 psi . LOT / FIT =12.27 ppg Hole Depth =5982 md Fluid Pumped=1.4 Bbls Volume Back =1.0 bbls Estimated Pump Output:0.101 Barrels/Stroke LOT / FIT DATA CASING TEST DATA Enter Strokes Enter Pressure Enter Strokes Enter Pressure Here Here Here Here ->048 ->00 ->191 ->5315 ->2 151 ->10 725 ->3 209 ->15 1132 ->4 292 ->20 1466 ->5 362 ->25 1903 ->6 429 ->30 2266 ->7 510 ->35 2668 ->8 574 ->36 2724 ->9 624 ->37 2825 ->10 659 ->38 2898 ->11 687 ->39 2991 ->12 691 ->40 3053 ->13 688 -> Enter Holding 0 Enter Holding Enter Holding Time Here 0 Time Here Pressure Here ->0 613 ->0 3053 ->1 589 ->5 3037 ->2 579 ->10 3031 ->3 572 ->15 3027 ->4 568 ->20 3022 ->5 563 ->25 3019 ->6 560 ->26 3019 ->7 558 ->27 3018 ->8 555 ->28 3018 ->9 553 ->29 3017 ->10 553 ->30 3017 ->11 -> ->12 -> ->13 -> ->14 ->15 ->16 11/9/2020 0 100 200 300 400 500 600 700 800 900 1000 1100 1200 1300 1400 1500 1600 1700 1800 1900 2000 2100 2200 2300 2400 2500 2600 2700 2800 2900 3000 0 1020304050Pressure (psi)Strokes (# of) LOT/FIT Casing Test 613589579572568563560558555553553 3053 3037 3031 3027 3022 301930193018301830173017 0 100 200 300 400 500 600 700 800 900 1000 1100 1200 1300 1400 1500 1600 1700 1800 1900 2000 2100 2200 2300 2400 2500 2600 2700 2800 2900 3000 3100 0 5 10 15 20 25 30 35Pressure (psi)Time (Minutes) LOT / FIT DATA CASING TEST DATA TD Shoe Depth: PBTD: No. Jts. Returned RKB RKB to BHF RKB to THF Jts. 1 1 1 243 1 1 Yes X No X Yes No Fluid Description: Liner hanger Info (Make/Model): Liner top Packer?: Yes X No Liner hanger test pressure:X Yes No Centralizer Placement: Preflush (Spacer) Type: Density (ppg) Volume pumped (BBLs) Lead Slurry Type:Sacks: Yield: Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Tail Slurry Type:Sacks: Yield: Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Post Flush (Spacer) Type: Density (ppg) Rate (bpm): Volume: Displacement: Type: Density (ppg) Rate (bpm): Volume (actual / calculated): FCP (psi): Pump used for disp:X Yes No Casing Rotated? Yes X No Reciprocated?X Yes No % Returns during job Cement returns to surface? Yes X No Spacer returns? Yes X No Vol to Surf: Cement In Place At: Date: Estimated TOC: Method Used To Determine TOC: Preflush (Spacer) Type: Density (ppg) Volume pumped (BBLs) Lead Slurry Type:Sacks: Yield: Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Tail Slurry Type:Sacks: Yield: Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Post Flush (Spacer) Type: Density (ppg) Rate (bpm): Volume: Displacement: Type: Density (ppg) Rate (bpm): Volume (actual / calculated): FCP (psi): Pump used for disp:Yes No Casing Rotated? Yes No Reciprocated? Yes No % Returns during job Cement returns to surface? Yes No Spacer returns? Yes No Vol to Surf: Cement In Place At: Date: Estimated TOC: Method Used To Determine TOC: Post Job Calculations: Calculated Cmt Vol @ 0% excess: Total Volume cmt Pumped: Cmt returned to surface: Calculated cement left in wellbore: OH volume Calculated: OH volume actual: Actual % Washout: Casing (Or Liner) Detail Shoe 7 33.5934.09SECOND STAGERotate Csg Recip Csg Ft. Min. PPG10.5 Shoe @ 10090.7 FC @ Top of Liner10,010.40 Floats Held 37.84 54 054 5000 % KCl NaCl/NaBr bri CASING RECORD County State Alaska Supv.S. Sunderland / J. Vanderpool Hilcorp Energy Company CASING & CEMENTING REPORT Lease & Well No.MP F-62A Date Run 15-Nov-20 Setting Depths Component Size Wt. Grade THD Make Length Bottom Top TXP BTC 2.00 10,092.70 10,090.70 Csg Wt. On Hook:135,000 Type Float Collar: No. Hrs to Run: 10.5 5 1030 Bump Plug?FIRST STAGE11.5Tuned Spacer 60 / 372.69/372.99 1530 0 Rig Bump press Cement Bond Logs Bump Plug? 3:53 11/16/2020 8,910 10,092.7010,112.00 10,010.00 CEMENTING REPORT Csg Wt. On Slips: KCl NaCl/NaBr Brine Stage Collar @ Bump press Closure OK 15.8 54 33.75 33.10 RKB to CHF 30.85 Type of Shoe: Casing Crew:Doyon No. Jts. Delivered No. Jts. Run Length Measurements W/O Threads Ftg. Delivered Ftg. Run Ftg. Returned Ftg. Cut Jt. Ftg. Balance FMC/Fluted Casing www.wellez.net WellEz Information Management LLC ver_04818br Type Two 7"x8.25" OMD 4RIB SPLIT SPIRAL CENTRALIZER with stop rings top and bottom, each jt #1-3 One 7"x8.25" OMD 4RIB SPLIT SPIRAL CENTRALIZER each jt #5-26 Casing 7 26.0 L-80 TXP BTC Tenaris 79.00 10,090.70 10,011.70 Float Collar 7 26.0 L-80 TXP BTC 1.30 10,011.70 10,010.40 Casing 7 26.0 L-80 TXP BTC Tenaris 9,973.48 10,010.40 36.92 7" Hanger Pup 7 26.0 L-80 TXP BTC Tenaris 2.93 36.92 33.99 7" Casing Hanger 7 26.0 L-80 TXP BTC Tenaris 0.24 33.99 33.75 Pack-off 0.65 33.75 33.10 PREM G 265 1.15 3.88 8,910 Hydraulic Fracturing Fluid Product Component Information DisclosureHydraulic Fracturing Fluid Composition:Job Start Date:12/3/2020Job End Date:12/3/2020State:AlaskaCounty:Beechey PointAPI Number:50-029-22609-01-00Operator Name:Hilcorp Alaska, LLCWell Name and Number:MPU F-62ALatitude:70.50794000Longitude:-149.65675000Datum:NAD83Federal Well:NOIndian Well:NOTrue Vertical Depth:7,228Total Base Water Volume (gal):80,238Total Base Non Water Volume:0Trade NameSupplierPurposeIngredientsChemicalAbstractServiceNumber(CAS #)MaximumIngredientConcentrationin Additive (% by mass)**MaximumIngredientConcentrationin HF Fluid (% by mass)**CommentsWater (Fluid)SchlumbergerN/AWater (Including Mix Water Supplied by Client)*7732-18-572.94495J218SchlumbergerBreaker J218Listed Below F103SchlumbergerSurfactantListed BelowJ604†SchlumbergerCrosslinker J604Listed BelowJ580SchlumbergerGel J580Listed BelowL071SchlumbergerClay Control AgentListed BelowS123SchlumbergerActivatorListed BelowW054SchlumbergerDemulsifierListed BelowS526-1620SchlumbergerPropping AgentListed BelowM002SchlumbergerAdditiveListed BelowL065SchlumbergerScale Inhibitor Listed BelowM275SchlumbergerBactericideListed BelowJ475SchlumbergerBreaker J475Listed BelowM117SchlumbergerClay Control AgentListed BelowCeramic materials and wares, chemicals66402-68-492.2371924.95481Potassium chloride (impurity)7447-40-74.744931.28374Guar gum9000-30-00.871550.235802-hydroxy-N,N,N-trimethylethanaminiumchloride67-48-10.460180.12450Sodium hydroxide (impurity)1310-73-20.451240.12208Methanol67-56-10.337460.09130Diammoniumperoxidisulphate7727-54-00.135270.03660PROPAN-2-OL67-63-00.115820.03134Ethylene Glycol107-21-10.080440.021762-Propenoic acid, polymer with sodium phosphinate129898-01-70.061240.01657Alcohols, c11-15-secondary, ethoxylated68131-40-80.061200.01656Oxirane, Methyl-, polymer with Oxirane9003-11-60.060250.01630Items above are Trade Names with the exception of Base Water . Items below are the individual ingredients. 2-butoxyethanol111-76-20.052020.01407Ethoxylated C11 Alcohol34398-01-10.047780.01293Ethoxylated propoxylated 4-nonylphenol-formaldehyde resin30846-35-60.044610.01207Alcohols, C7-9-iso-, C8-rich, ethoxylated78330-19-50.041160.01114Alcohols, C9-11-iso-, C10-rich, ethoxylated78330-20-80.038430.01040Vinylidenechloride/methylacrylatecopolymer25038-72-60.027410.00741Alcohol, C11-14, ethoxylated78330-21-90.026730.00723Ethoxylated Alcohol68131-39-50.025930.00702Ulexite1319-33-10.025860.00700Poly(oxy-1,2-ethanediyl),a-hydro-w-hydroxy- Ethane-1,2-diol, ethoxylated25322-68-30.013090.00354Sodium chloride7647-14-50.012370.00335N,N-Dimethyl-N-dodecylbenzylaminium chloride139-07-10.009210.00249Solvent naphtha (petroleum), heavy arom.64742-94-50.008670.00235Calcium Chloride10043-52-40.006250.001692-Propen-1-aminium,N,N-dimethyl-N-2-propen-1-yl-, chloride (1:1), homopolymer26062-79-30.006240.00169Diatomaceous earth, calcined91053-39-30.006040.00163Undecanol112-42-50.004160.00113Benzenemethanaminium, N,N-dimethyl-N tetradecyl-, chloride139-08-20.003150.00085Sodium Tetraborate Decahydrate1303-96-40.002860.00077Non-crystalline silica (impurity)7631-86-90.002180.00059 * 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%*** If you are calculating a percentage of total ingredients do not add the water volume below the green line to the water volume above the green lineNote: 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)Magnesium nitrate10377-60-30.001210.00033Naphthalene (Impurity)91-20-30.001030.00028Magnesium silicate hydrate (talc)14807-96-60.000840.00023Potassium oleate143-18-00.000790.000215-chloro-2-methyl-4-isothiazolin-3-one and 2-methyl-4-isothiazolin-3-one55965-84-90.000720.00020Acetic acid, potassium salt127-08-20.000700.00019but-2-enedioic acid110-17-80.000680.00018Benzenemethanaminium, N-hexadecylN,N dimethyl-,chloride122-18-90.000670.000181,2,4 Trimethylbenzene (impurity)95-63-60.000670.000182,2''-oxydiethanol(impurity)111-46-60.000660.00018Magnesium chloride7786-30-30.000600.00016poly(tetrafluoroethylene)9002-84-00.000360.00010Cristobalite14464-46-10.000120.00003Quartz, Crystalline silica14808-60-70.000120.00003Diutan gum125005-87-00.000030.00001Diutan595585-15-20.000030.00001Acetic acid (impurity)64-19-70.000030.00001 Schlumberger-Private Pressure (All Zones) Initial Wellhead Pressure (psi) 24 Surface Shut in Pressure(psi) 2,920 Injection Surface ISIP (psi) 2,600 Final Surface ISIP (psi) 3,117 Treatment Totals (All Zones As Per FracCAT) Total Slurry Pumped (Water+Adds+Proppant) (bbls) 2,356.9 Total YF128FlexD Past Wellhead (bbls) 1,639.9 Total WF128 Past Wellhead (bbls) 57.5 Total Neat Water Past Wellhead (bbls) 101.3 Total WF120 Past Wellhead (bbls) 249.3 Total Freeze Protect Pumped (bbls) 53.2 Total 16/20 CarboBond Lite Pumped (lbs.) 229,080 Total 16/20 CarboBond Lite in Formation (lbs.) 228,375 Total Chemical Additives Invoiced Past WH Invoiced Past WH J580 (lbs) 2170 2170 J604 (gal) 169 169 L071 (gal) 166 166 M002 (lbs) 63 63 F103 (gal) 86 86 J134 (lbs) 2 0 J475 (lbs) 385 385 M275 (lbs) 30 25 J218 (lbs) 22 22 S123 (gal) 304 304 L065 (gal) 82 82 W054 (gal) 205 205 Schlumberger-Private 13:24:15 13:32:35 13:40:55 13:49:15 13:57:35 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 7000 8000 9000 Tr. Press - psi0 5 10 15 20 25 30 35 40 Slurry Rate - bbl/min0 2 4 6 8 10 12 14 16 18 20 Prop Con - PPATr. Press BHP Annulus Press Slurry Rate Prop Con BH Prop Con Pressure Test © Schlumberger 1994-2016 Hilcorp Alaska LLC MPF-62A 12-03-2020 Schlumberger-Private 14:03:55 14:33:05 15:02:15 15:31:25 16:00:35 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 7000 Tr. Press - psi0 10 20 30 40 Slurry Rate - bbl/min0 2 4 6 8 10 12 14 16 18 20 Prop Con - PPATr. Press BHP Annulus Press Slurry Rate Prop Con BH Prop ConFP Displace DataFrac DataFrac © Schlumberger 1994-2016 Hilcorp Alaska LLC MPF-62A 12-03-2020 Schlumberger-Private 16:05:40 16:30:40 16:55:40 17:20:40 17:45:40 Time - hh:mm:ss 0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000 Tr. Press - psi0 10 20 30 40 Slurry Rate - bbl/min0 2 4 6 8 10 12 14 16 18 20 Prop Con - PPATr. Press BHP Annulus Press Slurry Rate Prop Con BH Prop Con On Freeze Protect Main Treatment © Schlumberger 1994-2016 Hilcorp Alaska LLC MPF-62A 12-03-2020 Schlumberger-Private Schlumberger-Private Schlumberger-Private Schlumberger-Private Schlumberger-Private 14:06:29 14:14:49 14:23:09 14:31:29 14:39:49 Time - hh:mm:ss 0 10 20 30 40 Slurry Rate - bbl/min0 2 4 6 8 10 12 Liquid Additives - gal/mgal0 2 4 6 8 10 12 14 16 J218, J475 CONC - lb/mgalSLUR_RATE CFLD_RATE J604_CONC S123_CONC F103_CONC L071_CONC L065_CONC W054_CONC J218_CONC J475_CONC DataFrac: Additives © Schlumberger 1994-2016 Hilcorp Alaska LLC MPF-62A 12-03-2020 Schlumberger-Private 16:06:51 16:31:51 16:56:51 17:21:51 17:46:51 Time - hh:mm:ss 0 10 20 30 40 Slurry Rate - bbl/min0 2 4 6 8 10 12 Liquid Additives - gal/mgal0 2 4 6 8 10 12 14 16 J218, J475 CONC - lb/mgalSLUR_RATE CFLD_RATE J604_CONC S123_CONC F103_CONC L071_CONC L065_CONC W054_CONC J218_CONC J475_CONC Main Treatment: Additives © Schlumberger 1994-2016 Hilcorp Alaska LLC MPF-62A 12-03-2020 !" !"#"$ !"%#&' ()') "*+ + &$ + ,- + + .+ .+ ! 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!/$+"" ! #$%&'() 0+! +*+,!- * ! +! #$%&'() / + . , ! 6 8 : 678 ; 678 435&. 6 8 45& 6 8 ,- 6 8 ,- 6 8 ! /0 68 ! 30 68 - 68 675<8 , < /90(/7 &'(</ )0()' &7'(7' & /''(9/ )79(<' 9'/(/9 7&7 '&<(00 '& 7)7('9 )( & /''(/< 9>.-5 -- 81 4 / 79 (< &7(& )9('9 &0&(9) ' 7)0(/' ) )() & /()/ 7&7 ))(& '& 7 0(&' (9 ' 7)/()) 9>.-5 -- 81 4 / ) 0(/< 9'(0' ))(' '&/() ' 70'()/ )99(/) '7&(7& 7&7 <(09 '& 79/(/) '(70 ' 70(0 9>.-5 -- 81 4 / (&9 9 (&9 )7(<0 0(90 ' ) 0()) )&&( '< ( ' 7&7 0 7(07 '& 7&/(/9 9('& ' ) /(7) 9>.-5 -- 81 4 / 9)0( <() )7(' 07/('/ ' )0&( 0 )'9()' &(&0 7&7 00(/7 '& 7'<('/ &('9 ' )0(&' 9>.-5 -- 81 4 / &) (90 9( 0 )7( 9 0/&(/) ' )&(& )7('0 0&/(0/ 7&7 <7<(9 '& 7'(0< '() ' )0(70 9>.-5 -- 81 4 / '70(< )(/' ) (' <<9(7 ' '7() )0(<9 <90(/7 7&7 <&&(9 '& 70 (<9 )(/ ' '9( 9>.-5 -- 81 4 / 79()7 )(7' /(< /0)(< ' <&(<' )0&() / (' 7&7 <0<('/ '& 70/(&) )(&< ' <0(0 9>.-5 -- 81 4 / /<(&) )(0/ <(0 0 77(&7 ' 9)/( ) )<7()<0 7)'( < 7&7 /) (/< '& 7<&(0/ 7(<' ' 9 ( ' 9>.-5 -- 81 4 / 0/&(< )(0' /(</ 0 )&/(<) ' 9'&(&& )<'(/0 )7&(/ 7&7 /&<( & '& 7/7(9< 7(&& ' 9'0(0 9>.-5 -- 81 4 / <</(</ )(0 '(<& 0 9<( & ' 9</(9< )/7(0/0 )/9() 7&7 /<9( 7 '& 7/'(7) )('< ' 9/ (0' 9>.-5 -- 81 4 / /<9(/ 7(/< 9'/(</ 0 9 '(<' ' & 9('0 )/ ('90 <7(09 7&) 7)0(&7 '& 7/('' (&' ' & (/< 9>.-5 -- 81 4 )7 7& (' )( 0 9'<(< 0 9<7(&< ' &&&(0 )/ (970 99'(9 7&) 79<('7 '& 7/( 7 7(<7 ' &&<(70 9>.-5 -- 81 4 )7 )) (77 )( 0 9'<(< 0 &&'( 9 ' &/(<0 )/)(<70 &77()) 7&) 79(/ '& 7/'(' 7(77 ' &09( 9 +D2,2, $@E$@ @ Benjamin Hand Digitally signed by Benjamin Hand Date: 2020.11.18 13:11:32 -09'00'Tyler Marr Digitally signed by Tyler Marr Date: 2020.11.20 13:59:24 -07'00' David Douglas Hilcorp Alaska, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or fax to 907 777-8510. Received By: Date: Date: 12/11/2020 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU F-62A (PTD 220-066) FINAL LWD FORMATION EVALUATION LOGS (11/09/2020 to 11/13/2020) •DGR, AGB, ADR, ALD, CTN (2” & 5” MD / TVD Color Logs) •Final Definitive Directional Survey SFTP Transfer - Data Folders: PTD: 2200660 E-Set: 34377 Received by the AOGCC 12/14/2020 Abby Bell 12/14/2020 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: 2. Operator Name:4. Current Well Class:5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception?Yes No 9. Property Designation (Lease Number):10. Field/Pool(s): 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): ±10,097'N/A Casing Collapse Conductor N/A Surface 3,090psi Production 5,410psi Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date:GAS WAG GSTOR SPLUG Commission Representative: GINJ Op Shutdown Abandoned Chad Helgeson Contact Name: Operations Manager Contact Email:dhaakinson@hilcorp.com Contact Phone: 777-8343 Date: Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng MP F-62A C.O. 432D Retrievable Packer and N/A ±9,624 MD / ±6,981 TVD Authorized Title: 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Signature: 11/22/2020 4-1/2" Perforation Depth MD (ft): See Schematic See Schematic ±112' 20" 9-5/8" 7" ±6,059' ±10,097' Perforation Depth TVD (ft): 5,750psi 7,240psi ±4,511' ±7,423' ±6,059' ±10,097' N/A Milne Point Unit / Kuparuk Oil Pool ±112' ±112' 12.6# / L-80 / Hydril 625 TVD Burst ±9,700' MD N/A Length Size ±7,423' ±10,097' ±10,097' 7,500 (GORV Set) PRESENT WELL CONDITION SUMMARY STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL025509 & ADL355018 220-066 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 50-029-22609-01-00 Hilcorp Alaska LLC Tubing Grade: Tubing MD (ft): David Haakinson COMMISSION USE ONLY Authorized Name: Tubing Size: ory Statu Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 10:05 am, Oct 28, 2020 320-463 Chad A Helgeson 2020.10.28 09:55:16 -08'00' pumping DSR-10/28/2020 2624 with col of gas CDW 11/5/2020 10-407 (final well report) A sand Frac SFD 11/07/2020MGR25NOV20Comm q 11/25/2020 dts 11/25/2020 JLC 11/25/2020 RBDMS HEW 11/27/2020 October 27, 2020 Jeremy Price, Chair Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 RE: Hydraulic Fracturing Application, Milne Point Unit, MP F-62A Dear Commissioner Price, Hilcorp Alaska, LLC (“Hilcorp”), as Operator of the Milne Point Unit, herein submits its application to fracture stimulate MP F-62A. Please do not hesitate to contact David Haakinson at 907-777-8343 should you have any questions regarding this application. Sincerely, Chad Helgeson, Operations Manager HILCORP ALASKA, LLC Enclosures: Form 10-403 Sundry Attachments Post Office Box 244027 Anchorage, AK 99524-4027 3800 Centerpoint Drive Suite 1400 Anchorage, AK 99503 David Haakinson Operations Engineer (907)777-8343 Chad A Helgeson 2020.10.28 09:56:31 -08'00' 20 AAC 25.283 (a)(1) Affidavit Affidavit stating that all owners, landowners, surface owners, and operators within a one-half mile radius of the current or proposed wellbore trajectory have been provided a notice of operations that is in compliance with 20 AAC 25.283 (a)(1) 20 AAC 25.283 (a)(2) A Plat (A) Showing The Well Location; (B) Identifying each Water Well, if any, Located within a One-Half Mile Radius of the Well's Surface Location; and Wells within ½ mile Well Name PTD Annulus Integrity MPU F-62A 220-066 9-5/8”casing tested to 3,000 psi on 10/31/95 before drill-out of shoe. Planned passing MIT-T to 4,400 psi Planned passing MIT-IA to 4,000 psi MPU F-33A 201-062 MIT-IA (7” casing) on 4/25/14 passed to 3,000 psi MIT-OA on 3/2/14 passed to 2,000 psi MPU F-69 195-125 MIT-IA (7” casing to 9,600’ MD) on 2/9/96 passed to 1,500 psi MPU F-73A 200-198 MIT-IA on3/29/18 passed to 3,797 psi MPU L-15 194-062 MIT-IA on1/14/18 passed to 2,400 psi MPU L-24 195-070 MIT-IA on9/7/2020 passed to 2,959 psi Completion Detail API Well No Permit Well Current Status Zonal isolation (method) 50-029-22609-01-00 220-006 F-62A Jet Pump Producer – Kuparuk Oil Pool 7” production casing: Plan to pump 57.6 bbls / 278 sxs of 15.8 ppg Class G cement with plug bump and MIT of casing to ±3,000 psi. An additional MIT-IA of the 4-1/2” x 7” annulus will be pressure tested to 4,000 psi after production packer set. A CBL will be run and results will be provided prior to proceeding to frac. 50-029-22689-01-00 201-062 F-33A Suspended – Sag River Oil Pool Pumped 123 bbls / 600 sxs of 15.8 ppg Class G cement. 10% returns during job. Plug bumped, floats held and MIT casing to 3,500psi good on 8/5/96. 7” casing was isolated with EZSV Cement Retainer set at 7,002’ MD on 4/25/14 SFD 11/4/2020Operator-estimated TOC = 8,675' MD 4-1/2" tubing 7" x 4-1/2" 50-029-22586-00-00 195-125 F-69 Shut In ESP Producer – Kuparuk Oil Pool 7” casing was run to 10,408’ MD, cemented with 51 bbls / 240 sxs of 15.8 ppg Class G with partial returns during job, bumped plug and floats held. MIT casing to 3,500 psi good on 9/11/95. 50-029-22744-01-00 200-198 F-73A Jet Pump Producer – Kuparuk Oil Pool 7” casing was run to 11,080’ MD, and cemented with 61 bbls / 300 sxs of 15.8 ppg Class G. No returns during job, bumped plug. MIT casing to 3,500 psi good on 3/8/97. 4-1/2” liner was run to 12,696’ MD and cemented with 60 bbls / 380 sx Class G cement. Plug bumped, floats held and MIT casing to 3,500 psi good on 12/30/2000. 50-029-22473-00-00 194-062 L-15 Injector – Kuparuk Oil Pool 7” casing was run to 14,064’ MD, and cemented with 44 bbls of 15.8 ppg cement, plug bumped, floats held and no returns during job. A second stage cement job of 46 bbls of Class E lead followed by 7 bbls of Class G tail cement was pumped through ES stage tool. Plug bumped. MIT casing to 3,500 psi good on 6/17/94. A CBL was completed on 6/19/94 with a logged TOC at 12,650’ MD. 50-029-22560-00-00 195-070 L-24 Injector – Kuparuk Oil Pool 7” casing was run to 12,793’ MD and cemented with 47 bbls / 230sxs of 15.8 ppg Class G cement. Plug bumped and floats held. MIT casing to 3,500 psi good on 5/30/95 A CBL was completed on 5/31/95 with a logged TOC at 12,020’ MD. SFD 11/4/2020 Operator-estimated TOC = 9,332' MD SFD 11/4/2020 Operator-estimated TOC = 8,936' MD SFD 11/4/2020 Operator-estimated TOC = 8,675' MD (C)Identifying for all Well Types each Well Penetration Well API PTD Pool Type Status MPF-01 50029225520000 1950450 KR 1-OIL Producing MPF-02 50029226730000 1960700 TER WSW Producing MPF-05 50029227620000 1970740 KR 1-OIL Shut In MPF-06 50029226390000 1960020 KR 1-OIL Producing MPF-09 50029227730000 1971040 KR 1-OIL Shut In MPF-10 50029226790000 1960940 KR WAG Shut In MPF-13 50029225490000 1950270 KR PWI Injecting MPF-14 50029226360000 1952120 KR 1-OIL Producing MPF-17 50029228230000 1971960 KR WAG Shut In MPF-18 50029226810000 1961000 KR 1-OIL Shut In MPF-21 50029226940000 1961350 TER WSW Producing MPF-22 50029226320000 1952010 KR 1-OIL Producing MPF-25 50029225460000 1950160 KR 1-OIL Producing MPF-26 50029227670000 1970840 KR WAG Shut In MPF-29 50029226880000 1961170 KR 1-OIL Shut In MPF-30A 50029226230100 2131880 KR WAG Injecting MPF-33A 50029226890100 2010620 SR Suspended Suspended MPF-34 50029228240000 1971970 KR 1-OIL Shut In MPF-37 50029225480000 1950250 KR 1-OIL Shut In MPF-38 50029226140000 1951680 KR 1-OIL Producing MPF-41 50029227700000 1970950 KR Suspended Suspended MPF-42 50029227410000 1970200 KR WAG Shut In MPF-45 50029225560000 1950580 KR 1-OIL Producing MPF-46 50029224500000 1940270 KR WAG Shut In MPF-49 50029227320000 1970030 KR WAG Shut In MPF-50 50029227560000 1970580 KR 1-OIL Producing MPF-53A 50029225780100 2131360 KR 1-OIL Producing MPF-54 50029227260000 1961920 KR 1-OIL Producing MPF-57A 50029227470100 2031670 KR 1-OIL Shut In MPF-58 50029227060000 1961560 TER WSW Shut In MPF-61 50029225820000 1951170 KR 1-OIL Shut In MPF-62 50029226090000 1951610 KR WAG Shut In MPF-65 50029227520000 1970490 KR 1-OIL Producing MPF-66A 50029226970100 1961620 KR 1-OIL Producing MPF-69 50029225860000 1951250 KR 1-OIL Shut In MPF-70A 50029226030100 2131690 KR WAG Injecting MPF-73A 50029227440100 2001980 KR 1-OIL Producing MPF-74A 50029226820100 2131890 KR WAG Injecting MPF-77 50029225940000 1951360 TER WSW Producing MPF-78A 50029225990100 2131760 KR 1-OIL Shut In MPF-79 50029228130000 1971800 KR 1-OIL Producing MPF-80 50029229280000 1982170 KR Suspended Suspended MPF-81 50029229590000 2000660 KR 1-OIL Producing MPF-82A 50029229710100 2091350 KR WAG Injecting MPF-83 50029229630000 2000930 KR WAG Shut In MPF-84B 50029229310200 2001760 KR WAG Injecting MPF-85 50029229360000 1982500 KR WAG Injecting MPF-86 50029230180000 2010870 KR 1-OIL Producing MPF-87A 50029231840100 2032130 KR 1-OIL Producing MPF-88 50029231850000 2031930 KR WAG Injecting MPF-89 50029232680000 2050900 KR WAG Shut In MPF-90 50029230510000 2012110 KR WAG Shut In MPF-91 50029232710000 2051100 KR WAG Injecting MPF-92 50029229240000 1981930 KR WAG Injecting MPF-93 50029232660000 2050870 KR 1-OIL Producing MPF-94 50029230400000 2011700 KR 1-OIL Producing MPF-95 50029229180000 1981790 KR WAG Injecting MPF-96 50029234060000 2081860 KR 1-OIL Shut In MPF-99 50029233320000 2061560 KR WAG Injecting MPF-106 50029236000000 2180280 SB PWI Injecting MPF-107 50029235920000 2180010 SB 1-OIL Producing MPF-108 50029235980000 2180210 SB PWI Injecting MPF-109 50029235960000 2180140 SB 1-OIL Producing MPF-110 50029235990000 2180220 SB PWI Injecting MPF-116 50029236500000 2191330 KR 1-OIL Producing 20 AAC 25.283 (a)(3) Identification of Freshwater Aquifers There are no underground sources of drinking water within a one-half mile radius of the current wellbore trajectory. Any and all freshwater aquifers lying below the Milne Point Unit are exempted aquifers under Aquifer Exemption Order 2 (AEO-2). See the Conclusion of AEO-2, which states that “The portions of freshwater aquifers lying directly below Milne Point Unit qualify as exempt freshwater aquifers under 20 AAC 25.440.” 20 AAC 25.283 (a)(4) Baseline Water Well Sampling There are no water wells located within one-half mile radius of the current wellbore trajectory. A water sampling program is not required. Four active water supply wells are located within 1/2 mile of the surface location of MPU F-62A; however, all of these wells lie more than 3/4 mile from the planned fracturing interval. AEO 2 exempts freshwater aquifers beneath F-Pad. Water sampling program not required. SFD 10/29\/2020 20 AAC 25.283 (a)(5) Detailed Casing and Cementing Information The 9-5/8” 40#/ft L-80 BTC surface casing set below the Schrader Bluff sands at 6,059’ MD on 10/30/1995. A cement job of 1160 sxs / 448 bbls of 12.0 ppg Class E followed by a 250 sxs / 51 bbls of Class G cement was pumped with good returns a small amount of cement to surface. A second stage cement job of 250 sxs / 42 bbls was pumped through an ES stage tool with good circulation of cement to surface. The 9-5/8” surface casing was mechanical integrity tested to 3,000 psi on 10/31/95. 7” 26#/ft L-80 TXP-BTC production casing shoe is planned to be set at ±10,097’ MD and cemented. After set, a planned 58 bbls of 15.8 ppg Class G cement accounting for 40% open-hole excess will be pumped with planned wiper plug bump, targeting a minimum 500’ of cement above the Kuparuk sands. A CBL will be run on the 7” casing post cementing. Detailed Casing Information Size Type Wt/ Grade/ Conn Pipe Body Yield (lbs) Collapse Pressure (psi) Internal Yield Pressure (psi) Conductor (Existing) N/A N/A N/A N/A 9-5/8"Surface (Existing)40# / L-80 / BTC 916,000 3,090 5,750 7” Production 26# / L-80 / TXP-BTC 604,000 5,410 7,240 Detailed Tubing Information 4-1/2” Tubing 13.5# / L-80 / Hydril 625 288,000 8,540 9,020 No stage tool in AOGCC records. Surface cement all circulated through shoe. Required top job. 20 AAC 25.283 (a)(6) Assessment of Each Casing and Cementing Operation Performed to Construct or Repair the Well The 9-5/8” 40#/ft L-80 BTC surface casing set below the Schrader Bluff sands at 6,059’ MD on 10/30/1995. A cement job of 1160 sxs / 448 bbls of 12.0 ppg Class C followed by a 250 sxs / 51 bbls of Class G cement was pumped with good returns a small amount of cement to surface. A second stage cement job of 250 sxs / 42 bbls was pumped through an ES stage tool with good circulation of cement to surface. The 9-5/8” surface casing was mechanical integrity tested to 3,000 psi on 10/31/1995. The existing F-62 9-5/8” cemented surface casing string is planned for sidetrack at ±5,942’ MD, below the deepest hydrocarbon bearing Schrader Bluff sand at 5,365’ MD. The new sidetracked well (F-62A) 7” 26#/ft L-80 TXP-BTC production casing shoe is planned to be set at ±10,097’ MD, below the Kuparuk A- Sand formation and run to surface. A single stage 58 bbls 15.8 ppg Class G cement job is planned for pumping with 40% OH excess to target a TOC with a minimum 500’ above the top of the Kuparuk Formation. The cementing procedure calls for the plugs to bump on calculated displacement. A 7” CBL log will be run after cement is placed and submitted after completing the logging run post- rig. Received at AOGCC XX-November-2020 20 AAC 25.283 (a)(7) Plans to Pressure-Test the Casings and Tubing Installed in the Well The 9-5/8” casing pressure tested to 3,000 psi for 30 minutes on October 31, 1995 prior to drilling out the casing shoe. The 4-1/2” tubing will be pressure tested to 4,400 psi for 30 minutes. The 4-1/2” x 7” annulus will be pressure tested to 4,000 psi for 30 minutes. 20 AAC 25.283 (a)(8) Pressure Ratings and Schematics for the Wellbore, Wellhead, BOPE, and Treating Head Size Weight #/ft Grade API Collapse Pressure (psi) API Internal Yield Pressure (psi) 9-5/8" 40 L-80 3,090 5,750 7" 26 L-80 5,410 7,240 4-1/2” 13.5 L-80 8,540 9,020 Treating Head 15M Wellhead 5M BOPE N/A See As-Built Schematic on final page 5M Wellhead 15M Treating Head (Frac Sleeve) 20 AAC 25.283 (a)(9) Data for the Fracturing Zone and Confining Zones (A) a lithologic description of each zone; (B) the geological name of each zone; (C) the measured depth and true vertical depth of each zone; (D) the measured thickness and true vertical thickness of each zone; and (E)the estimated fracture pressure for each zone; The Kuparuk formation is a Cretaceous-aged, fine-grained marine sandstone. The productive Kuparuk interval in the F-62A area consists of the Kuparuk C, Kuparuk B, and Kuparuk A sands. Formation tops and TVT numbers for the productive intervals are listed in the table below: Well Surface MD TVD TVT F-62A KUPARUK C 9,788’ 7,130’ 3’ F-62A KUPARUK B 9,792’ 7,133’ 60’ F-62A KUPARUK A3 9,855’ 7,193’ 16’ F-62A KUPARUK A2 9,872’ 7,209’ 26’ F-62A KUPARUK A1 9,900’ 7,234’ 60’ F-62A KUPARUK A BASE 9,964’ 7,295’ The estimated fracture gradient for the Kuparuk interval is 0.65-0.68 psi/ft. The overlying confining zone consists of ~2,000’ TVT of Kuparuk D, Kalubik, HRZ shale and Colville siltstones and shales. The estimated fracture gradient for the Kalubik/Hrz is 0.75-0.82 psi/ft. The underlying confining zone consists of ~3,000’ TVT the Milluveach and Kingak shales. The estimated fracture gradient for the Milluveach shale is 0.8-0.82 psi/ft. Formation tops and TVT for the overlaying shale intervals Kuparuk D, Kalubik and Colville and the underlying shale interval Milluveach are listed in the table below: Well Surface MD TVD TVT F-62A Colville 6,338’ 4,664’ 2,200’ F-62A KALUBIK 9,503’ 6,864’ 181’ F-62A KUP_D 9,697’ 7,046’ 105’ F-62A MILLUVEACH / KINGAK 9,964’ 7,295’ over 3,000’ 20 AAC 25.283 (a)(10) The Location, the Orientation, and a Report on the Mechanical Condition of Each Well that May Transect the Confining Zones MP F-33A: 7” casing set across the Kuparuk sands and cemented with 123 bbls / 600 sxs of 15.8 ppg Class G cement. 10% returns were observed during the job. The wiper plug bumped, floats held and MIT casing to 3,500 psi passed on 8/5/96. The 7” casing was isolated with an EZSV cement retainer set at 7,002’ MD on 4/25/14. MP F-69: 7” casing set across the Kuparuk sands and cemented with 51 bbls / 240 sxs of 15.8 ppg Class G cement. Bumped plug and floats held. MIT of the casing to 3,500 psi passed on 9/11/95. MP F-73A: 7” casing set across the Kuparuk sands and cemented with 61bbls / 300 sxs of 15.8 ppg Class G cement. Plug bumped, floats held and MIT casing to 3,500 psi good on 3/8/97. MP L-15: 7” casing set across the Kuparuk sands and cemented with 44 bbls of 15.8 ppg Class G cement. Bottom wiper plug bumped and the floats held. A second stage cement of 46 bbls of 15.8 ppg Class E cement was followed by 7 bbls of 15.8 ppg Class G cement pumped through ES stage tool. The wiper plug bumped and an MIT of the casing to 3,500 psi passed on 6/17/94. A cement bond log was completed on 6/19/1994 with a TOC measured at 12,650’ MD. MP L-24: 7” casing set across the Kuparuk sands and cemented with 47 bbls / 230 sxs of 15.8 ppg Class G cement. The wiper plug bumped and the floats held. A MIT of the casing to 3,500 psig was good on 5/30/1995. A cement bond log was run on 5/31/1995 with a logged TOC at 12,020’ MD. (Top of Kup C sand at 10,634' MD. SFD 11/2/2020) (Top of Kup A3 sand at 13,708' MD. SFD 11/2/2020) (Top of Kup A sand at 9,933' MD. SFD 11/2/2020) (Top of Kup C sand at 9,374' MD in original wellbore F-33. SFD 11/2/2020) TOC measured at 12,650’ MD. Redacted M.Guhl 2/25/2021 20 AAC 25.283 (a)(12) Proposed Hydraulic Fracturing Program On Rig Operations (In Reference to MPU F-62A PTD #220-066) : 1. RU E-Line and PT PCE to 3,000 psi (Cemented, pressure tested, and unperforated/fully isolated wellbore). a. MPSP is 2,624 psi based on estimated Kuparuk reservoir pressure estimate of 3,337 psig at 7,130’ TVD and assuming a 0.1 psi/ft gas gradient. 2. Perform CBL of 7” casing from PBTD at ±10,097’ MD to ±9,000’ MD or indicated top of cement. 3. POOH and make up perforating BHA. a. Confirm final depths with Perf Sheet. b. 10’ gun: 3-3/8” OD Titan EXP EquaFrac Charges. 6 SPF/ 60 deg Phase. c. Obtain Correlation Log: MPU F-62A Open Hole MWD logs 4. Perforate the Kuparuk A sand formation from ±9,855’ - ±9,865’ MD. a. Log Jewelry Log of GR/CCL from ±10,050’ – 9,600’ MD. i. Locate any short joints if run. 5. POOH and LD perforating gun. a. Document condition of fired gun including any damage or un-fired charges. 6. RDMO E-Line. Post Rig Operations: 7. RU SL and PCE. PT to 250 psi L / 3000 psi H. 8. Pull Ball & Rod from RHC Plug set in XN Nipple @ ±9,667’ MD 9. Pull RHC Plug set in XN Nipple @ ±9,667’ MD 10. RIH and drift to PBTD at ±10,097’ MD 11. PT IA to 4,000 psig to ensure sliding sleeve remains closed. 12. RD SL. 13. MIRU frac fleet. MIRU frac and slop tanks. MIRU all ancillary support equipment. 14. Fill frac tanks with water. a. Utilize PBU hot water plant water. b. Heat water as needed, targeting 80°F for the fracture treatment. 15. Lay all hardline and manifolds. Install pressure monitoring equipment on wellhead and tree. Monitor 7” x 4-1/2” annulus pressure during DFIT and fracture stimulation. RU flowmeter if performing forced closure on tank return line. CBL to AOGCC for review. 16. RU hardline from 9-5/8” x 7” annulus to tank and shall be left open to atmosphere during the stimulation job. 17. RU 15K tree saver and hard line. 18. Pressure test all high pressure treating lines to 8,000 psi. 19. Set the GORV (gas operated relief valve) at ±7,500 psi. Set the staggered pump kick-out at 7,200 psig. 20. Pressurize annulus to 3,500 psi. Set annular PRV at 3,900 psi full open, 3,600 psi crack pressure. 21. Prepare frac fleet to pump. 22. Pump Kuparuk A sand DFIT and analyze the results to obtain fluid loss coefficients. Adjust fracture treatment design. 23. Fracture stimulate Kuparuk A sand with 16/20 mesh resin coated proppant in cross-linked gel. See “Pump Schedule” for proposed design. 24. Displace with freeze protect fluid. Under-displace by ±3 bbls. Do not over displace. 25. Shut well in. Perform forced closure (optional). 26. RD tree saver. 27. RU Slickline and pressure test PCE to 500 psi above shut in WHP. 28. Perform drift and tag to PBTD of ±10,097’ MD. 29. Contingency: If tag depth is above the Kuparuk A sand perforations, rig up CT for a fill cleanout. a. MIRU CT Unit with 2” coiled tubing. b. Perform BOPE test to 3,000 psig H / 250 psig L. c. MU 2” CT with CTC, CTC disconnect, DBCV, and 2” cleanout jet swirl nozzle. d. RIH and if any weight stacking occurs, begin FCO. e. Establish returns rate upon circulation. i. If necessary, begin nitrogen lift and adjust nitrogen rate as necessary to establish no less than 80% returns rate. f. Perform FCO to PBTD of ±10,097’. i. Pump frequent 3-5 bbl high LSRV gel sweeps as necessary. Monitor pill returns for sweep efficiency. ii. Take no more than 150’ bites once fill is tagged. g. POOH, washing to surface. h. RDMO CT and nitrogen units. 30. MIRU E-line Unit a. PT PCE to 3,000 psi H / 250 psi L. 31. Perforate the Kuparuk C and B7 sand formation from ±9,788’ - ±9,828’ MD. a. Confirm final depths with Perf Sheet post drilling. t annular PRV = 3900 psi GORV = 7500 psi b. Log Jewelry Log of GR/CCL from ±10,050’ – ±9,600’ MD (above the 4-1/2” SSD). c. Perf Charges: 3-1/8” OD, 60 deg phasing, 6 spf. d. Correlation Log: MPU F-62A Open Hole MWD logs or Kuparuk A sand perf/jewelry log. 32. RDMO E-Line Unit 33. RU Slickline Unit. a. PT PCE to 3,000 psi H / 250 psi L. 34. Shift SSD open at ±9,578’ MD. 35. Set jet pump in SSD at ±9,578’ MD. 36. RD Slickline unit. 37. Bring well online with jet pump and ‘reverse flow jet pump’ to flow back well to portable test separator as needed to clean up frac. 38. Turn well over to operations. With all personnel at the well site. 20 AAC 25.283 (a)(12) (A) Estimated Total Volumes Planned 20 AAC 25.283 (a)(12) (B) Trade Name, Generic Name, and Purpose of each Base Fluid and Additive to be Used; 20 AAC 25.283 (a)(12) (C) Chemical Ingredient Name of, and the Chemical Abstracts Service (CAS) Registry Number Assigned to, each Base Fluid and Additive to be used; 20 AAC 25.283 (a)(12) (D) Estimated Weight or Volume of each Inert Substance, including a Proppant or other Substance injected 20 AAC 25.283 (a)(12) (E) Maximum Anticipated Treating Pressure and Information Sufficient to Support a Determination that the Well is Appropriately Constructed for the Proposed Hydraulic Fracturing Program. The 4-1/2 “production tubing will be tested to 4,400 psi for 30 minutes, and the 4-1/2” x 7” production casing will be tested to 4,000 psi for 30 minutes prior to the fracture stimulation. The maximum surface differential pressure the tubing will be subjected to will be 4,000 psi (7,500 psi GORV maximum pressure setting – 3,500 psi of pressure on the casing x tubing annulus). The calculated maximum treating pressure is 6,590 psi for the Kuparuk A sand fracture stimulation. The tubing will be tested to 4,400 psig to exceed 110 percent of the maximum differential (7,500 – 3,500) x 1.1 = 4,400 psig. 20 AAC 25.283 (a)(12) (F)Designed Height And Length Of Each Proposed Fracture (i) the calculated measured depth and true vertical depth of the top of the fracture: Kuparuk A Sand: 9,851’ MD / 7,193’ TVD (ii) a description of each method and assumption used to determine designed fracture height and length: The MP F-62A fracture stimulation was modeled using the FracCADE program. Kuparuk A Sand propped half length: 177.9’ 20 AAC 25.283 (a)(13) Description of the Plan for Post-Fracture Wellbore Cleanup and Fluid Recovery through to Production Operations The well will be cleaned up through a portable separation system. Gas will be rerouted to the production system while fluids will be produced to tanks while high solids concentrations are evident by shakeout analysis. Once solids and emulsion percentages allow, the well will be turned over to the Milne Point central processing facility. In the event of a frac screen-out, coiled tubing operations will be utilized to clean-out the 7” casing to PBTD. 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Hole Angle through perforations = 42 deg. TREE & WELLHEAD Tree 4-1/16” – 5M Cameron NS Wellhead FMC 11” 5M FMC Gen 5 w/ 11” FMC Tubing Hanger, 3.5” NSCT Lift Threads and 3” CIW H BPV Profile Tubing Hanger 4-1/2” Tubing Hanger GENERAL WELL INFO API: 50-029-22609-01-00 Completed: 11/20/2020 – Doyon 14 Top of cement on 7" casing (from CBL) ~ 8790' MD As-built 1 Davies, Stephen F (CED) From:David Haakinson <dhaakinson@hilcorp.com> Sent:Wednesday, November 4, 2020 10:21 AM To:Davies, Stephen F (CED) Cc:Rixse, Melvin G (CED) Subject:RE: [EXTERNAL] MPU F-62A (220-066; Sundry 320-463) - Request Hi Steve, Please see the updated calculations that assume a 30% wash‐out as requested. Well Estimated TOC F‐33A 8,675' F‐69 8,936' F‐73A 9,332' David Haakinson Operations Engineer | North Slope Asset Team Hilcorp Alaska, LLC Office: (907) 777-8343 | Cell: (307) 660-4999 dhaakinson@hilcorp.com From: Davies, Stephen F (CED) [mailto:steve.davies@alaska.gov] Sent: Wednesday, November 4, 2020 9:24 AM To: David Haakinson <dhaakinson@hilcorp.com> Cc: Rixse, Melvin G (CED) <melvin.rixse@alaska.gov> Subject: RE: [EXTERNAL] MPU F‐62A (220‐066; Sundry 320‐463) ‐ Request David, Apologies. I just read your email in detail. It’s AOGCC’s long‐time policy to estimate TOC assuming 30% wash out rather than gauge hole. Sorry, I thought 30% washout was an industry standard or I would have specified that the first time. Could you please re‐do your TOC estimations assuming 30% washout? Thanks again and stay safe, Steve Davies Alaska Oil and Gas Conservation Commission (AOGCC) CONFIDENTIALITY NOTICE: This e‐mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e‐mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907‐793‐1224 or steve.davies@alaska.gov. From: David Haakinson <dhaakinson@hilcorp.com> Sent: Tuesday, November 3, 2020 3:39 PM To: Davies, Stephen F (CED) <steve.davies@alaska.gov> Subject: RE: [EXTERNAL] MPU F‐62A (220‐066; Sundry 320‐463) ‐ Request 2 Hi Steve, Below are the estimated TOC for the three requested wells assuming a gauge 8‐1/2” hole and no losses. No bond logs were run on these three wells. Well Estimated TOC F‐33A 7,094' F‐69 8,305' F‐73A 8,583' David Haakinson Operations Engineer | North Slope Asset Team Hilcorp Alaska, LLC Office: (907) 777-8343 | Cell: (307) 660-4999 dhaakinson@hilcorp.com From: Davies, Stephen F (CED) [mailto:steve.davies@alaska.gov] Sent: Monday, November 2, 2020 3:25 PM To: David Haakinson <dhaakinson@hilcorp.com> Subject: RE: [EXTERNAL] MPU F‐62A (220‐066; Sundry 320‐463) ‐ Request David, Could Hilcorp please provide the estimated tops of cement for the 7” casing set in nearby wells F‐33A, F‐69 and F‐73A? Thanks and stay safe, Steve Davies AOGCC CONFIDENTIALITY NOTICE: This e‐mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e‐mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907‐793‐1224 or steve.davies@alaska.gov. From: David Haakinson <dhaakinson@hilcorp.com> Sent: Monday, November 2, 2020 12:56 PM To: Davies, Stephen F (CED) <steve.davies@alaska.gov> Subject: RE: [EXTERNAL] MPU F‐62A (220‐066; Sundry 320‐463) ‐ Request Hi Steve, The drilling rig will be moving over F‐62A tomorrow and we should have logs available towards the end of next week. I will set a reminder and send to you as soon as possible. Take care, 3 David Haakinson Operations Engineer | North Slope Asset Team Hilcorp Alaska, LLC Office: (907) 777-8343 | Cell: (307) 660-4999 dhaakinson@hilcorp.com From: Davies, Stephen F (CED) [mailto:steve.davies@alaska.gov] Sent: Monday, November 2, 2020 12:30 PM To: David Haakinson <dhaakinson@hilcorp.com> Subject: [EXTERNAL] MPU F‐62A (220‐066; Sundry 320‐463) ‐ Request David, I’m reviewing Hilcorp’s application to frac the MPU F‐62A well. Please forward to me a copy of the digital well log data (field files are fine) for F‐62A as soon as it is available. Gamma ray, resistivity and porosity curves (if available) in .las or ASCII tab‐delimited table format are appreciated. Thanks and stay safe, Steve Davies Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission (AOGCC) CONFIDENTIALITY NOTICE: This e‐mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e‐mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907‐793‐1224 or steve.davies@alaska.gov. 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. 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, Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Monty M. Myers Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Milne Point Field, Kuparuk Oil Pool, MPU F-62A Hilcorp Alaska, LLC Permit to Drill Number: 220-066 Surface Location: 2141’ FSL, 2627’ FEL, Sec. 06, T13N, R10E, UM, AK Bottomhole Location: 2419’ FSL, 2419’ FEL, Sec. 31, T14E, R10E, UM, AK Dear Mr. Myers: Enclosed is the approved application for the permit to 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 AOGCC 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 AOGCC 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 an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Jeremy M. Price Chair DATED this ___ day of October 2020. JMPi 5 N 1a. Type of Work:1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp 1c. Specify if well is proposed for: Drill Lateral Stratigraphic Test Development - Oil Service - Winj Single Zone Coalbed Gas Gas Hydrates Redrill Reentry Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal Shale Gas 2. Operator Name:5. Bond: Blanket Single Well 11. Well Name and Number: Bond No. 3. Address:6. Proposed Depth: 12. Field/Pool(s): MD: 14,338' TVD: 3,509' 4a. Location of Well (Governmental Section):7. Property Designation: Surface: Top of Productive Horizon:8. DNR Approval Number: 13. Approximate Spud Date: Total Depth:9. Acres in Property: 14. Distance to Nearest Property: 4b. Location of Well (State Base Plane Coordinates - NAD 27):10. KB Elevation above MSL (ft): 45.70' 15. Distance to Nearest Well Open Surface: x-541935 y- 6035593 Zone-4 12.00' to Same Pool: 622' 16. Deviated wells: Kickoff depth: 6000 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 65 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD 8-1/2"x9-7/8"7" 26# L-80 Hyd TXP 10,097' Surface Surface 10,097' 7,423' 19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Junk (measured): None TVD 112' 4511' 7561' 11365 - 11565 7167 - 7317 Hydraulic Fracture planned?Yes No 20. Attachments:Property Plat BOP Sketch Drilling Program Time v. Depth Plot Shallow Hazard Analysis Diverter Sketch Seabed Report Drilling Fluid Program 20 AAC 25.050 requirements Contact Name: Contact Email: Contact Phone: Date: Permit to Drill API Number: Permit Approval Number:Date: 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 in shales: Samples req'd: Yes No Mud log req'd: Yes No H2S measures: Yes No Directional svy req'd: Yes No Spacing exception req'd: Yes No Inclination-only svy req'd: Yes No Post initial injection MIT req'd: Yes No APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Sr Pet Eng Sr Pet Geo Sr Res Eng GL / BF Elevation above MSL (ft): 279 sx Class 'G' 50-029-22609-01-00 See cover letter for other requirements. Perforation Depth MD (ft): 21. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. 11877'11877'7" Commission Use Only Perforation Depth TVD (ft): 7472 1160 sx PF 'C', 250 sx 'G', 250 sx PF 'E Effect. Depth MD (ft): Authorized Signature: 361 sx Class 'G'Production Liner Intermediate 6059' 260 sx Arctic Set (Approx.)112' 6059'9-5/8"Surface Conductor/Structural 20"112' 11910 7587 LengthCasing None Total Depth MD (ft):Total Depth TVD (ft): Cement Quantity, c.f. or sacks Cement Volume MDSize Plugs (measured): (including stage data) Effect. Depth TVD (ft): 11765 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 2706 2179' FSL, 2427' FEL, Sec. 31, T14N, R10E, UM, AK 2419' FSL, 2419' FEL, Sec. 31, T14E, 10E, UM, AK 94-019 7616 11668 MPU F-62A Milne Point Unit Kuparuk Oil Pool 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 Hilcorp Alaska, LLC 2141' FSL, 2627' FEL, Sec. 06, T13N, R10E, UM, AK ADL355018 & 025509 022224484 10/15/2020 Authorized Name: Monty Myers Authorized Title: Drilling Manager Nathan Sperry nathan.sperry@hilcorp.com 777-8450 18. Casing Program:Top - Setting Depth - BottomSpecifications 3473 s N ype o W L l R b S Cass os N s No s N o D s s s D 84 o esp G S S 20 SS S s No s No S G y E S s No s Form 10-401 Revised 3/2020 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g) 9.28.2020 By Samantha Carlisle at 10:55 am, Sep 28, 2020 Digitally signed by Monty M Myers DN: cn=Monty M Myers, c=US, o=Hilcorp Alaska, LLC, ou=Technical Services - AK Drilling, email=mmyers@hilcorp.com Reason: I am approving this document Date: 2020.09.28 10:04:23 -08'00' Monty M Myers 220-066 Separate fracturing sundry to be submitted and approved before POP. CBL to AOGCC. 10,097' 7,423' BOPE test to 4000 psi. Annular to 2500 psi. DSR-9/29/2020MGR02OCT2020 SFD 9/28/2020 SFD 9/28/2020 24 hour notice. GR02O0020220002020CT2020 10/5/2020 50-029-22609-01-00 10/5/2020 N PLB 10/08/20 Milne Point Unit (MPU) F-62A Drilling Program Version 1 September 8, 2020 Table of Contents 1.0 Well Summary ................................................................................................................................. 2 2.0 Management of Change Information ............................................................................................ 3 3.0 Tubular Program ............................................................................................................................ 4 4.0 Drill Pipe Information .................................................................................................................... 4 5.0 Casing Inspection ............................................................................................................................ 4 6.0 Internal Reporting Requirements ................................................................................................. 5 7.0 Wellbore Schematics ....................................................................................................................... 6 8.0 Drilling / Completion Summary .................................................................................................... 7 9.0 Mandatory Regulatory Compliance / Notifications ..................................................................... 8 10.0 R/U and Test BOPE ...................................................................................................................... 10 11.0 Pull 3-1/2” Tubing ......................................................................................................................... 11 12.0 Cut and Pull 7” Casing ................................................................................................................. 12 13.0 Mill 8-1/2” Window and Kick Off ............................................................................................... 13 14.0 Production Hole Section Summary ............................................................................................. 16 15.0 Drill 8-1/2” x 9-7/8” Production Hole Section ............................................................................ 17 16.0 Run 7” Casing ............................................................................................................................... 20 17.0 Cement 7” Casing ......................................................................................................................... 23 18.0 Run 4-1/2” Frac String ................................................................................................................. 25 19.0 Doyon 14 BOP Schematic ............................................................................................................. 27 20.0 Wellhead Schematic ...................................................................................................................... 28 21.0 Days Vs Depth ............................................................................................................................... 29 22.0 Formation Tops & Information ................................................................................................... 30 23.0 Anticipated Drilling Hazards ....................................................................................................... 32 24.0 Doyon 14 Layout ........................................................................................................................... 34 25.0 FIT Procedure ............................................................................................................................... 35 26.0 Doyon 14 Choke Manifold Schematic ......................................................................................... 36 27.0 Casing Design Information .......................................................................................................... 37 28.0 8-1/2” x 9-7/8” Hole Section MASP ............................................................................................. 38 29.0 Spider Plot (NAD 27) (Governmental Sections) ......................................................................... 39 30.0 Surface Plat (As Built) (NAD 27) ................................................................................................. 40 Page 2 Version 1 July 2020 Milne Point Unit F-62A Drilling Procedure 1.0 Well Summary Well MPU F-62A Pad Milne Point “F” Pad Planned Completion Type 7” Cemented Casing Target Reservoir(s) Kuparuk A Wellplan 1 Planned Well TD, MD / TVD 10,098’ MD / 7,424’ TVD PBTD, MD / TVD ±10,018 MD / 7,349’ TVD Surface Location (Governmental) 2141' FSL, 2532' FWL, Sec 6, T13N, R10E, UM, AK Surface Location (NAD 27 – Zone 4) X=541,934.7 Y=6,035,593.4 Top of Productive Horizon (Governmental) 2179' FSL, 2427' FEL, Sec 31, T14N, R10E, UM, AK TPH Location (NAD 27) X=542,083.5, Y=6,040,911.5 BHL (Governmental) 2321' FSL, 2419' FEL, Sec 31, T14N, R10E, UM, AK BHL (NAD 27) X=542,090.5, Y=6,041,053.7 AFE Drilling Days 13 Days AFE Completion Days 3 Days Maximum Anticipated Pressure (Surface) 2,706 psi Maximum Anticipated Pressure (Downhole/Reservoir) 3,473 psi (9.0 ppg EMW) Work String 5” 19.5# S-135 NC-50, DS-50 KB Elevation above MSL: 33.7 ft + 12.0 ft = 45.7 ft GL Elevation above MSL: 12.0 ft BOP Equipment 13-5/8” x 5M Annular, (3) ea 13-5/8” x 5M Rams 2,627 FEL SFD 9/28/2020 2,706 psi Page 3 Version 1 July 2020 Milne Point Unit F-62A Drilling Procedure 2.0 Management of Change Information Page 4 Version 1 July 2020 Milne Point Unit F-62A Drilling Procedure 3.0 Tubular Program Hole Section OD (in) ID (in) Drift (in) Conn OD (in) Wt (#/ft) Grade Conn Burst (psi) Collapse (psi) Tension (k-lbs) 8-1/2” x 9- 7/8” 7” 6.276 6.151 7.656 26 L-80 HYD TXP 7240 5410 604 Upper Completion 4.5” 3.920 3.795 4.714 13.5 L-80 Hyd 625 9020 8540 279 4.0 Drill Pipe Information Hole Section OD (in) ID (in) TJ ID (in) TJ OD (in) Wt (#/ft) Grade Conn M/U (Min) M/U (Max) Tension* (k-lbs) 8-1/2” x 9-7/8” 5” 4.276” 3.25” 6.625” 19.5 S-135 NC50 31,032 34,136 560klb *Tension Rating Based on Premium Pipe 5.0 Casing Inspection All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery). Page 5 Version 1 July 2020 Milne Point Unit F-62A Drilling Procedure 6.0 Internal Reporting Requirements 6.1 Fill out daily drilling report and cost report on Wellez. x Report covers operations from 6am to 6am x Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left of the data entry area – this will not save the data entered, and will navigate to another data entry tab. x Ensure time entry adds up to 24 hours total. x Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. x Enter the MD and TVD depths EVERY DAY whether you are making hole or not. 6.2 Afternoon Updates x Submit a short operations update each work day to mmyers@hilcorp.com, pmazzolini@hilcorp.com , nathan.sperry@hilcorp.com, jengel@hilcorp.com and joseph.lastufka@hilcorp.com 6.3 Intranet Home Page Morning Update x Submit a short operations update each morning by 7am on the company intranet homepage. On weekend and holidays, ensure to have this update in before 5am. 6.4 EHS Incident Reporting x Health and safety: Notify EHS field coordinator. x Environmental: Drilling Environmental coordinator x Notify Drlg Manager & Drlg Engineer x Submit Hilcorp Incident report to contacts above within 24 hrs 6.5 Casing Tally x Send final “As-Run” Casing tally to nathan.sperry@hilcorp.com and joseph.lastufka@hilcorp.com 6.6 Casing and Cement report x Send casing and cement report for each string of casing to nathan.sperry@hilcorp.com and joseph.lastufka@hilcorp.com 6.7 Hilcorp Milne Point Contact List: Title Name Work Phone Cell Phone Email Drilling Manager Monty Myers 907.777.8431 907.538.1168 mmyers@hilcorp.com Drilling Engineer Joe Engel 907.777.8395 805.235.6265 jengel@hilcorp.com Drilling Engineer Nathan Sperry 907-777-8450 907.301.8996 nathan.sperry@hilcorp.com Completion Engineer Ian Toomey 907.777.8434 907.903.3987 itoomey@hilcorp.com Geologist Radu Girbacea 907.777.8324 907.230.9490 rgirbacea@hilcorp.com Reservoir Engineer Daniel Taylor 907.777.8319 907.947.8051 dtaylor@hilcorp.com Drlg Environmental Coord Keegan Fleming 907.777.8477 907.350.9439 kfleming@hilcorp.com Safety Manager Carl Jones 907.777.8327 907.382.4336 cajones@hilcorp.com Drilling Tech Cody Dinger 907.777.8389 509.768.8196 cdinger@hilcorp.com Drilling Tech Joe Lastufka 907.777.8400 907.227.8496 Joseph.Lastufka@hilcorp.com Page 6 Version 1 July 2020 Milne Point Unit F-62A Drilling Procedure 7.0 Wellbore Schematics Page 7 Version 1 July 2020 Milne Point Unit F-62A Drilling Procedure 8.0 Drilling / Completion Summary MPU F-62A is a sidetrack producing well targeting the Kuparuk River Pool, located on Milne Point ‘F-Pad’. The directional plan is a single string slant well with the kick off point at ~6,000’ MD. Maximum hole angle is ~65 degrees. Drilling operations are expected to commence approximately October 15th, 2020, pending rig schedule. Production casing will be 7” 26# L-80 cemented casing run to 10,119’ MD / 7,423’ TVD. The well will be perforated post-rig. Doyon 14 will leave the well with the casing cemented and a frac string installed. A separate sundry will be submitted for P&A operations and completion operations on F-62A. All waste & mud generated during drilling operations will be hauled to the Milne Point G&I facility located on “B” pad. General sequence of operations: 1. MIRU Doyon 14 2. N/U 13-5/8” x 5M BOPE and test 3. Pull 3-1/2” tubing from cut 4. Cut and pull 7” casing. 5. Set 9-5/8” WS and mill 8-1/2” window 6. Contingency: Drill with kickoff (motor) assembly until sufficient separation achieved 7. Drill 8-1/2” x 9-7/8” hole with RSS to TD 8. Run and cement 7” production casing 9. Run 4-1/2” Frac String 10. N/D BOP, N/U Tree, RDMO Reservoir Evaluation Plan: 1. Production Hole: No mud logging. LWD: GR + Res . Eline: Run CBL/GR/CCL. Page 8 Version 1 July 2020 Milne Point Unit F-62A Drilling Procedure 9.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the below AOGCC regulations. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. x BOP’s shall be tested at 1 week intervals prior to initiating window milling and 2 week intervals during the drilling and completion of MPU F-62A thereafter. Provide AOGCC 24 hrs notice prior to testing BOPs. x The initial test of BOP equipment will be to 250/4000 psi & subsequent tests of the BOP equipment will be to 250/4000 psi for 5/5 min (annular to 50% rated WP, 2500 psi on the high test for initial and subsequent tests). Confirm that these test pressures match those specified on the APD. x If the BOP is used to shut in on the well in a well control situation, notify AOGCC and test all BOP components utilized for well control prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP test. x All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid program and drilling fluid system”. x All AOGCC regulations within 20 AAC 25.035 “Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements”. x Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office. AOGCC Regulation Variance Requests: x There are no variance requests at this time. Page 9 Version 1 July 2020 Milne Point Unit F-62A Drilling Procedure Summary of BOP Equipment and Test Requirements Hole Section Equipment Test Pressure (psi) 8-1/2” x 9-7/8” x 13-5/8” x 5M Hydril “GK” Annular BOP x 13-5/8” x 5M Hydril MPL Double Gate o Blind ram in btm cavity x Mud cross w/ 3” x 5M side outlets x 13-5/8” x 5M Hydril MPL Single ram x 3-1/8” x 5M Choke Line x 3-1/8” x 5M Kill line x 3-1/8” x 5M Choke manifold x Standpipe, floor valves, etc Initial Test: 250/4000 Subsequent Tests: 250/4000 Primary closing unit: NL Shaffer, 6 station, 3000 psi, 180 gallon accumulator unit. Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is a 30:1 air pump, and emergency pressure is provided by bottled nitrogen. The remote closing operator panels are located in the doghouse and on accumulator unit. Required AOGCC Notifications: x Well control event (BOPs utilized to shut in the well to control influx of formation fluids). x 24 hours notice prior to spud. x 24 hours notice prior to testing BOPs. x 24 hours notice prior to casing running & cement operations. x Any other notifications required in APD. Regulatory Contact Information: AOGCC Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email: jim.regg@alaska.gov Guy Schwartz / Petroleum Engineer / (O): 907-793-1226 / (C): 907-301-4533 / Email: guy.schwartz@alaska.gov Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Email: Victoria.loepp@alaska.gov Mel Rixse / Petroleum Engineer / (O): 907-793-1231 / (C): 907-223-3605 / Email: melvin.rixse@alaska.gov Primary Contact for Opportunity to witness: AOGCC.Inspectors@alaska.gov Test/Inspection notification standardization format: http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) Page 10 Version 1 July 2020 Milne Point Unit F-62A Drilling Procedure 10.0 R/U and Test BOPE 10.1 Reservoir abandonment was completed pre-rig via a separate Sundry. 10.2 Ensure Sundry, PTD, and drilling program are posted in the rig office and on the rig floor. 10.3 Level pad and ensure enough room for layout of rig footprint and R/U. 10.4 Ensure rig mats cover entire footprint of rig. 10.5 MIRU Doyon 14. Ensure rig is centered over the wellhead to prevent any wear to BOPE or wellhead. 10.6 Mud loggers will not be used on F-62A. 10.7 N/U 13-5/8” x 5M BOP as follows: x BOP configuration from top down: 13-5/8” x 5M annular / 13-5/8” x 5M double gate / 13- 5/8” x 5M mud cross / 13-5/8” x 5M single gate x Double gate ram should be dressed with 2-7/8” x 5” VBRs in top cavity, blind ram in bottom cavity. x Single ram can be dressed with 4-1/2” x 7” VBRs x N/U bell nipple, install flowline. x Install (1) manual valve & HCR valve on kill side of mud cross. (Manual valve closest to mud cross). x Install (1) manual valve on choke side of mud cross. Install an HRC outside of the manual valve 10.8 Run BOP test plug. 10.9 Test BOP to 250/4000 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min. x Test upper VBR’s with 3 -1/2” and 5” test joints x Test lower VBR’s with 4-1/2” and 7” test joints x Confirm test pressures with PTD x Ensure to monitor side outlet valves and annulus valve pressure gauges to ensure no pressure is trapped underneath test plug x Once BOPE test is complete, send a copy of the test report to town engineer and drilling tech 10.10 R/D BOP test equipment. Pull test plug. Set wearbushing in wellhead. 10.11 Mix 9.5 ppg LSND fluid for production hole. 10.12 If needed, rack back as much 5” DP in derrick as possible to be used while drilling the hole section. 10.13 Ensure 6-1/2” liners in mud pumps. Page 11 Version 1 July 2020 Milne Point Unit F-62A Drilling Procedure 11.0 Pull 3-1/2” Tubing 11.1 PU landing joint or spear and recover the tubing hanger. 11.2 Back out lock down screws. 11.3 Pull tubing hanger with landing joint/XO to the floor. 11.4 The tubing is expected to be in good condition. 11.5 Note and record PU weight required to pull the tubing from cut. 11.6 The expected weight of the string in a vertical hole filled with seawater is 83,500 lbs (assumes 10,300’ cut depth). 11.7 Circulate at least 1.5x BU after pulling the hanger to the floor. If desired, circulate a soap sweep surface-to-surface to clean the tubing. Displace to 9.5ppg fluid through tubing cut to minimize fluid swapping later in the well. 11.8 Pull and lay down the tubing from the jet cut. Page 12 Version 1 July 2020 Milne Point Unit F-62A Drilling Procedure 12.0 Cut and Pull 7” Casing Note: The Nabors 27E RKB was 35.8’. There is a 2.1’ shift to our Doyon 14 measurement of 33.7’ RKB. Ensure fishing rep and company man review parent tallies and agree on cut depth. 12.1 MU cutter assembly per fishing rep. 12.2 RIH to ~6,025’ MD cut depth (note TOWS depth will be ~5,942’ MD ref. Doyon 14 RKB). 6,025’ should be 10’ above the collar between joints 144 and 145. Space out per the tally. Cut casing per fishing rep. 12.3 POOH and LD cutting assembly. 12.4 PU landing joint or spear and recover the casing hanger. 12.5 Back out lock down screws. 12.6 Pull hanger with landing joint/XO to the floor. 12.7 Note and record PU weight required to pull the tubing from cut. 12.8 The expected weight of the string in a vertical hole filled with seawater is ~137klbs (assumes 6,025’ cut depth). 12.9 Circulate at least 1.5x BU after pulling the hanger to the floor. If desired, circulate a soap sweep surface-to-surface to clean the tubing. 12.10 Pull and lay down the casing from the cut. 12.11 Run wear ring. 12.12 Contingency: PU 5” drill pipe and RIH with clean-out assembly and clean-out the well to the top of the tubing stub. The decision will be based on the casing condition, how the casing pulled, etc. If no cleanout run is needed, skip to section 13. 12.13 When on bottom circulate at max rate at least 1X BU or until returns are clean. Pump high vis sweep if necessary. Displace to milling fluid. 12.14 POOH with clean-out assembly Page 13 Version 1 July 2020 Milne Point Unit F-62A Drilling Procedure 13.0 Mill 8-1/2” Window and Kick Off Note: All following operations will be covered under by the PTD for F-62A 13.1 Whipstock Set Depth Information: x Planned TOW: ~5,942’ MD x First full joint above the shoetrack is 5,932’ to 5,972’. x Deepest hydrocarbon bearing sand in 9-5/8” casing hole section is the Schrader Bluff OBD at 5,365’ MD x Whipstock is a hydraulic set system and depth control will be per the tallies. 13.2 MU 8-1/2” mill/whipstock assembly as per fishing rep’s tally x Make up HWDP, storing magnets, and float sub x Ensure magnets are in trough, under shakers and flow area to capture metal shavings circulated 13.3 Install MWD. Rack back mill assembly. x Ensure a dedicated MWD is available for orientation of the whipstock 13.4 Verify offset between MWD and whipstock tray, witnessed by Drilling Supervisor, MWD/DD and fishing rep. Document and record offset in well file. 13.5 Slowly run in the hole as per fishing rep. Run extremely slow through the BOP & wear bushing to prevent damaging the shear bolt. 13.6 Run in hole at 1 ½ to 2 minutes per stand, or as per fishing rep. Ensure work string is stationary prior to setting the slips, and removed slowly as well. These precautions are to avoid weakening the shear bolt and prematurely setting the anchor. 13.7 Shallow test MWD 13.8 Stop at least 30-45’ above planned set depth and obtain survey with MWD. 13.9 Milling fluid will be 9.5 ppg LSND 13.10 With the bottom of the whipstock 30 – 45’ above the set depth, work torque out of string, measure and record P/U and S/O weights. Obtain good survey to orient whipstock face. 13.11 Orient whipstock to desired direction by turning DP in ¼ round increments. P/U and S/O on DP to work all torque out after oriented. (Being careful not to set trip anchor). Target orientation is 60q ROHS. Page 14 Version 1 July 2020 Milne Point Unit F-62A Drilling Procedure 13.12 Whipstock Orientation Diagram: Desired orientation of the whipstock face is 60R. Acceptable range is between 30R and 60R Hole Angle at window interval (6,000’ MD) is ~64°, Azimuth 346°. 13.13 Once whipstock is in desired orientation, set WS per fishing rep. 13.14 Pressure up per rep to set hydraulic set whipstock per YJOS rep (verify pressure and shear values with YJOS rep), P/U 5-7K maximum overpull to verify anchor is set. The window mill can then be sheared off by slacking off weight on the whipstock shear bolt. (35k shear value, verify after whipstock is picked up). 13.15 P/U 5-10’ above top of whipstock. 13.16 CBU and confirm 9.5 ppg MW in/out x Ensure Mud properties are sufficient for transporting metal cuttings x Visc: 40-60, YP: 18-20 13.17 Record P/U, S/O weights, and free rotation. Slack off to top of whipstock and with light weight and low torque. Mill window as per fishing rep. Utilize 4 ditch magnets on the surface to catch metal cuttings. Pump high visc sweeps as necessary. 13.18 If possible, install catch trays in shaker underflow chute to help catch metal cuttings. 13.19 Clean catch trays and ditch magnets frequently while milling window. 13.20 Mill window until the uppermost mill has passed across the entire tray. Dress and polish window as needed. 13.21 With upper mill at the end of the tray, this will drill ~ 20’ of new hole. 60R 30R Page 15 Version 1 July 2020 Milne Point Unit F-62A Drilling Procedure 13.22 After window is milled and before POOH, shut down pumps and work milling assembly through window watching for drag. Dress and polish window as needed. After reaming, shut off pumps and rotary (if hole conditions allow) and pass through window checking for drag. 13.23 Circulate bottoms up until even MW in/out and hole is clean of metal shavings. Reduce mud properties for drilling. 13.24 Pull back into 9-5/8” casing and perform FIT t/ 13.0 ppg EMW. Chart Test. 13.25 POOH & LD milling BHA. Gauge mills for wear. 13.26 PU stack washer and wash BOPE stack. Function all rams to clear any potential milling debris. FIT digital data to AOGCC. Page 16 Version 1 July 2020 Milne Point Unit F-62A Drilling Procedure 14.0 Production Hole Section Summary This is a single section 8-1/2” x 9-7/8” hole kicked off from cemented pipe in the Colville and TD’d in the Kuparuk. The Kuparuk pore pressure is expected to be 9.0 ppg EMW. Maintaining CBHP will be critical for maintaining HRZ and Kalubik stability. Note: Managed Pressure Drilling will be used in this hole section. Prior to drilling, verify all rig crew member are familiar with operation. If needed, install RCD bearing element and perform practice connections to familiarize crews with its operations. Page 17 Version 1 July 2020 Milne Point Unit F-62A Drilling Procedure 15.0 Drill 8-1/2” x 9-7/8” Production Hole Section 15.1 PU 8-1/2” kickoff assembly. x Ensure BHA components have been inspected previously. x Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. x Ensure TF offset is measured accurately and entered correctly into the MWD software. x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. x Workstring will be 5”. 15.2 8-1/2” x 9-7/8” hole mud program summary: x Density: The Kuparuk reservoir pressure is expected to be 9.0 ppg. 9.5 ppg MW will be used. Additional barite will be on location to weight up the active system (1) ppg above highest anticipated MW. x Solids Concentration: It is imperative that the solids concentration be kept low while drilling the production hole section. Keep the shaker screen size optimized and fluid running to near the end of the shakers. It is okay if the shakers run slightly wet to ensure we are running the finest screens possible. x Inhibition: 3% KCl will be used for inhibition. Watch MBT levels, dilute as necessary to maintain. Increase KCl % if needed x Run the centrifuge continuously while drilling the production hole, this will help with solids removal and minimize sand content and LGS to maintain fluid properties and quality of the mud system. x PVT will be used throughout the drilling phase. Remote monitoring stations will be available at the driller’s console, Co Man office, & Toolpusher office. System Type: 9.0 - 10.5ppg 3% KCl Inhibited LSND WBM Properties: Section Density Viscosity PV Yield Point Total Solids MBT pH 8-1/2” x 9-7/8” 9.0 -10.5 75-175 15-25 15-25 <10% < 7 8.5 – 9.0 15.3 TIH w/ 8-1/2” kickoff assembly on 5” DP to above window. Shallow test MWD and LWD on trip in. 15.4 Ensure even 9.5 ppg MW in and out. Note: MPD is NOT needed for drilling with the motor assembly. 15.5 Drill 8-1/2” hole section with kickoff assembly at least until we have confirmed we have separation from the old wellbore and we have enough footage to ‘bury’ the underreamer in the open hole. TOOH. Page 18 Version 1 July 2020 Milne Point Unit F-62A Drilling Procedure 15.6 P/U 8-1/2” x 9-7/8” RSS Directional BHA x Ensure BHA components have been inspected previously. x Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. x Ensure TF offset is measured accurately and entered correctly into the MWD software. x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. x Run x2 Solid Plunger Floats for MPD 15.7 Drill 8-1/2” x 9-7/8” hole section to ~300’ above the Kalubik. x Flow Rate: 525-620 gpm (Target 200 ft/min AV) x RPM: 120 – for hole cleaning. x WOB as needed x Take MWD surveys every stand drilled. x Kuparuk PP estimate is 9.0 ppg. Good drilling and tripping practices are vital for avoidance of differential sticking and HRZ/Kalubik stability. x Watch for fluid losses while drilling through Kuparuk. 15.8 Install MPD Element x Ensure rig crew is familiar with MPD connection operations x Ensure max pressure relief settings are set correction to ensure no wellbore damage is created x Increase black products in the mud per MI. 15.9 Drill 8-1/2” x 9-7/8” hole section to section TD per Geologist and Drilling Engineer. x Flow Rate: 525-620 gpm (Target 200 ft/min AV) x RPM: 120 – for hole cleaning x WOB as needed x Target ECD and CBHP: 11.3 EMW +/- 5% x Utilize MPD to maintain CBHP (constant bottom hole pressure) on connections, following annular pressure ramp schedule x This will reduce the pumps on/ pumps off pressure cycles on shales x Slow ramp pumps on/off on each connection x Smooth connections are more important that connection time x Monitor connections for losses, adjust as necessary x Take MWD surveys every stand drilled. x Kuparuk PP estimate is 9.0 ppg. Good drilling and tripping practices are vital for avoidance of differential sticking and HRZ/Kalubik stability. x Watch for fluid losses while drilling through Kuparuk. 15.10 At TD, circulate a minimum of 2X BU x Drop the ball and close the AnderReamer per the NOV rep. x Circulate at full drill rate while rotating at 120 rpm’s x Only if necessary, perform short trip to 9-5/8” window following the pressure schedule to maintain CBHP at the base of the HRZ. Page 19 Version 1 July 2020 Milne Point Unit F-62A Drilling Procedure x We can slowly rack back a couple of stands while performing the BU circulations. x Attempt to pull through the Kalubik on elevators to the window. Only initiate backreaming if necessary. x Circulate a minimum of 1.5X BU at the window prior to TIH on elevators. 15.11 If backreaming is necessary: x Circulate at max rate while maintaining drilling ECD’s x Perform CBHP connections x Rotate at maximum rpm that can be sustained. x Limit pulling speed to 5 – 10 min/std (slip to slip time, not including connections). x If backreaming operations are commenced, continue backreaming to the window and circ at least a b/u once at the window. 15.12 At TD, circulate at least 2X BU. Observe well for flow, weight up to 10.5 ppg prior to TOOH 15.13 TOOH with the drilling assembly to 9-5/8” window while offsetting swab with MPD x Follow tripping schedule, matching string speed and annular pressure x Rack back DP while TOOH, Do not lay down drill pipe. This is to minimize open hole time before casing is on bottom. 15.14 CBU at 9-5/8” window 15.15 Continue TOOH to HWDP/ BHA, offsetting swab with MPD 15.16 Pull RCD bearing element at HWDP 15.17 L/D 8-1/2” x 9-7/8” BHA 15.18 No additional logs are planned for the 8-1/2” x 9-7/8” hole section. Page 20 Version 1 July 2020 Milne Point Unit F-62A Drilling Procedure 16.0 Run 7” Casing 16.1 Ensure rams have been tested on 7” test joint prior to running casing. 16.2 Ensure wear bushing is pulled from wellhead. 16.3 R/U 7” casing running equipment. x Ensure 7” TXP crossover is on rig floor and M/U to FOSV. x Ensure all casing has been drifted prior to running. x Be sure to count the total # of joints before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 16.4 Run 7” casing per tally. x Dope pin end only w/ paint brush. x Utilize a collar clamp until weight is sufficient to keep slips set properly. x Run 1 centralizer per joint to the planned TOC x MU shoetrack and check floats. 7” 26ppf L-80 TXP Torque OD Minimum/Maximum Optimum Operating Torque 7” 13,280 / 16,230 ft-lbs 14,750 ft-lbs 20,000 ft-lbs Page 21 Version 1 July 2020 Milne Point Unit F-62A Drilling Procedure Page 22 Version 1 July 2020 Milne Point Unit F-62A Drilling Procedure 16.5 RIH casing. Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 16.6 Obtain up and down weights of the casing before entering open hole. Record rotating torque at 10, 20, & 30 rpm. 16.7 RIH to TD as per running schedule. Monitor run for losses. Page 23 Version 1 July 2020 Milne Point Unit F-62A Drilling Procedure 17.0 Cement 7” Casing 17.1 Circulate and condition mud for cement job. x Break circulation slowly and stage up rate with reciprocation. x Circulate minimum 1.5X BU to condition hole and mud for cement job. 17.2 Hold pre job safety meeting over upcoming casing cementing operations. Make room in pits for volume gained during cement job. Ensure adequate displacement volume is available. x Discuss pumps for displacement x Positions and expectations of all personnel involved in cement operations, have one hand in the pits specifically for strapping pits and recording volume returned. 17.3 The 7” casing cement job will be a single stag, 2 plug job. 17.4 RU cement head and cementing lines. 17.5 Pump 5 bbls fresh water. Pressure test surface cement lines to 4000 psi. 17.6 Pump 60 bbls of 11.5 ppg spacer. Drop bottom plug. 17.7 Pump 15.8 ppg Class G Single Stage Slurry as per below calculations, 40% OH Excess: x Minimum TOC is 500’ above the Kuparuk. x Ensure cement slurry thickening time accounts for 30 min shutdown time for setting and releasing from liner hanger / packer. And compressive strength sufficient for perforation. Section: Calculation Vol (bbls) Vol (ft3) 9.875" OH x 7” Casing: (10,097’-150’– 9,947’+500’) x 0.0471 bpf 35.5 199.4 8.5” OH x 7” Casing 150’ x 0.0226 bpf 3.4 19.0 OH Excess (35.5 + 3.4) x 0.4 15.6 87.3 7” Shoe Track: 80’ x 0.038 bpf 3.1 17.2 Total Volume: 57.6 322.9 Cement Slurry System G Density 15.8 ppg Yield 1.16 ft3/sk Mixed Water 4.972 gal/sk 17.8 Drop top wiper plug and displace with drilling mud. x Target max displacement rates to not exceed drilling ECD’s x Slow pumps enough to check for casing wiper plug shear release Top of Kup 9697' Page 24 Version 1 July 2020 Milne Point Unit F-62A Drilling Procedure 17.9 Continue displacing cement until casing wiper plug bumps, or displacement volume has been pumped. Do not displace by more than ½ the shoetrack volume if the plug does not bump on calculated displacement. Ensure to report the following on wellez: x Pre flush type, volume (bbls) & weight (ppg) x Cement slurry type, lead or tail, volume & weight x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid x Note if casing is reciprocated or rotated during the job x Calculated volume of displacement , actual displacement volume, whether plug bumped & bump pressure, do floats hold x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure x Note time cement in place x Note calculated top of cement x Add any comments which would describe the success or problems during the cement job Send final “As-Run” casing tally & casing and cement report to nathan.sperry@hilcorp.com, itoomey@hilcorp.com, and joseph.lastufka@hilcorp.com. This will be included with the EOW documentation that goes to the AOGCC. 18.0 Eline GR/CCL/CBL. Logs to AOGCC before fracturing. Page 25 Version 1 July 2020 Milne Point Unit F-62A Drilling Procedure 18.0 Run 4-1/2” Frac String 18.1 M/U frac string and RIH to setting depth. x Ensure wear bushing is pulled. x Ensure 4-½” L-80 13.5ppf Hyd 625 x NC-50 crossover is on rig floor and M/U to FOSV. x Ensure all tubing has been drifted in the pipe shed prior to running. x Be sure to count the total # of joints in the pipe shed before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. x Monitor displacement from wellbore while RIH. 4-1/2” 13.5# L-80 Hyd 625 Casing OD Minimum Optimum Maximum Operating Torque 4.5” 8,000 ft-lbs 9,600 ft-lbs 12,800 ft-lbs Verify running order with Ops Engineer. Nom. Size Item Lb/ft Notes WLEG 4.5” 15' Pup Joint 13.5 4.5” 30’ Joint 13.5 4.5” 15' Pup Joint 13.5 4.5” “X” nipple, 3.813” 13.5 4.5” 15' Pup Joint 13.5 4.5” 30’ Joint 13.5 4.5” 15' Pup Joint 13.5 XO 4-1/2” x 7” Prod Packer 4.5” 15’ Pup Joint 13.5 XO 4.5” 30’ Joint 13.5 4.5” 15' Pup Joint 13.5 XO Durasleeve, SSD 3.813 seal bore ID, X Nipple Profile 4.5” 15’ Pup Joint 13.5 XO 4.5” 30’ Joint 13.5 4.5” 15' Pup Joint 13.5 4.5” Gauge Carrier Assembly 13.5 4.5” 15’ Pup Joint 13.5 4.5” 30’ Joints as needed 13.5 Tubing Hanger 18.2 Space out the completion. Place all space out pups below the first full joint of the completion. 18.3 Makeup the tubing hanger and landing joint and land same. 18.4 Reverse circulate the well with brine and 1% corrosion inhibitor. 18.5 Freeze protect the tubing and IA to ~2500’ MD with diesel. Page 26 Version 1 July 2020 Milne Point Unit F-62A Drilling Procedure 18.6 Land hanger. RILDs and test hanger. 18.7 Set the production packer per the completion rep. 18.8 Pressure test the tubing to 2500 psi for 30 charted minutes. 18.9 Pressure test the annulus to 2500 psi for 30 charted minutes. 18.10 Set TWC. ND BOPE and NU adapter flange and tree. 18.11 Test tree to 5000 psi. 18.12 Secure the tree and cellar. 18.13 RDMO Doyon 14 A separate sundry will be submitted for completion operations. Page 27 Version 1 July 2020 Milne Point Unit F-62A Drilling Procedure 19.0 Doyon 14 BOP Schematic Typical Ram Configuration Page 28 Version 1 July 2020 Milne Point Unit F-62A Drilling Procedure 20.0 Wellhead Schematic FMC Gen 5 Typical 2-7/8” Page 29 Version 1 July 2020 Milne Point Unit F-62A Drilling Procedure 21.0 Days Vs Depth Page 30 Version 1 July 2020 Milne Point Unit F-62A Drilling Procedure 22.0 Formation Tops & Information Page 31 Version 1 July 2020 Milne Point Unit F-62A Drilling Procedure MPU F Pad Data Sheet Page 32 Version 1 July 2020 Milne Point Unit F-62A Drilling Procedure 23.0 Anticipated Drilling Hazards Decomplete: Failed C&P: The tubing will be cut pre-rig. We will cut and pull the 7” from inside 9-5/8” cased hole to minimize the risk of failing to pull the 7”. Window Exit: Tracking Casing The KOP is cemented. The risk of tracking casing is low. Production Hole Sections: Hole Cleaning: Maintain rheology of mud system. Sweep hole with low-vis water sweeps. Ensure shakers are set up with appropriate screens to maximize solids removal efficiency. Run centrifuge continuously. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Maintain circulation rate with AV of 200 ft/min. Lost Circulation: Lost circulation has been seen in the Colville formation at EMW exceeding ~ 12.0 ppg. Monitor ECDs during production section to ensure ECDs stay below 12.0. Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Wellbore Stability: This well will drill through historically trouble shales, HRZ & Kalubik. Maintain sufficient MW for stability and utilize MPD to maintain constant bottom hole pressure to mitigate on/off pressure cycles. Use MPD to offset swab effect while TOOH. Follow tripping in hole schedule to manage surge pressures on shales. The well will be underreamed to 9-7/8” as well. Anti-Collision: This well has no close approaches on the planned wellpath. Monitor MWD survey for magnetic interference while drilling ahead. Faulting: There are no known faults in the hole section. H2S: Treat every hole section as though it has the potential for H2S. H2S events have typically been minor from F-pad Kuparuk wells. The majority of pad sample data is less than 10 ppm. F-69 had one sample reading of 47. The next highest reading was 32 on F-53. yp y F-69 had one samplepp jyp p reading of 47. The next highest reading was 32 on F-53. Page 33 Version 1 July 2020 Milne Point Unit F-62A Drilling Procedure 1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Page 34 Version 1 July 2020 Milne Point Unit F-62A Drilling Procedure 24.0 Doyon 14 Layout Page 35 Version 1 July 2020 Milne Point Unit F-62A Drilling Procedure 25.0 FIT Procedure Formation Integrity Test (FIT) and Leak-Off Test (LOT) Procedures Procedure for FIT: 1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe). 2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe. 3. Close the blowout preventer (ram or annular). 4. Pump down the drill stem at 1/4 to 1/2 bpm. 5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe. 6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes. Record time vs. pressure in 1-minute intervals. 7. Bleed the pressure off and record the fluid volume recovered. The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick tolerance in case well control measures are required. Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid; at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure monitored as with an FIT. Page 36 Version 1 July 2020 Milne Point Unit F-62A Drilling Procedure 26.0 Doyon 14 Choke Manifold Schematic Page 37 Version 1 July 2020 Milne Point Unit F-62A Drilling Procedure 27.0 Casing Design Information Page 38 Version 1 July 2020 Milne Point Unit F-62A Drilling Procedure 28.0 8-1/2” x 9-7/8” Hole Section MASP Page 39 Version 1 July 2020 Milne Point Unit F-62A Drilling Procedure 29.0 Spider Plot (NAD 27) (Governmental Sections) Page 40 Version 1 July 2020 Milne Point Unit F-62A Drilling Procedure 30.0 Surface Plat (As Built) (NAD 27) !!" 3200373342674800533358676400693374678000True Vertical Depth (800 usft/in)1600 2133 2667 3200 3733 4267 4800 5333 5867 6400 6933 7467 8000 8533 9067Vertical Section at 1.96° (800 usft/in)MPF-62A wp01 Tgt1MPF-629 5/8"4 1/2" x 6 1/8"50005500600065007000750080008500900095001000010097MPF-62Awp01Start Dir 12.3º/100' : 6000' MD, 4510.45'TVD : 60° RT TFEnd Dir : 6017' MD, 4517.82' TVDStart Dir 5º/100' : 6047' MD, 4530.58'TVDEnd Dir : 6697.46' MD, 4896.69' TVDStart Dir 5º/100' : 8908.22' MD, 6378.16'TVDEnd Dir : 9474.84' MD, 6842' TVDTotal Depth : 10097.33' MD, 7423.14' TVDKLBKLGMKUP_DKUP_CKUP_B6KUP_A3KUP_A2KUP_A1KUP_A_BASEWELL DETAILS: MPF-62 NAD 1927 (NADCON CONUS) Alaska Zone 04Ground Level:12.00+N/-S +E/-W Northing EastingLatittude Longitude0.00 0.00 6035593.36 541934.6770° 30' 29.367 N 149° 39' 24.820 WCASING DETAILSTVDTVDSSMD Size Name4535.72 4490.026059.00 9-5/8 9 5/8"7423.14 7377.4410097.334-1/2 4 1/2" x 6 1/8"FORMATION TOP DETAILSTVDPath TVDssPath MDPath Formation6863.75 6818.05 9498.14 KLB6878.75 6833.05 9514.21 KLGM7045.75 7000.05 9693.09 KUP_D7129.75 7084.05 9783.06 KUP_C7132.75 7087.05 9786.28 KUP_B67192.75 7147.05 9850.55 KUP_A37208.75 7163.05 9867.68 KUP_A27233.75 7188.05 9894.46 KUP_A17294.75 7249.05 9959.80 KUP_A_BASEProject: Milne PointSite: M Pt F PadWell: MPF-62Wellbore: MPF-62ADesign: MPF-62A wp01SURVEY PROGRAMDate: 2020-08-28T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool114.95 6000.00 GYD Gyro (MPF-62)3_Gyro-CT_pre-1998_Pipe6000.00 6300.00 MPF-62A wp01 (MPF-62A) 3_MWD_Interp Azi+Sag6300.00 10097.27 MPF-62A wp01 (MPF-62A) 3_MWD+IFR2+MS+SagSECTION DETAILSSec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation1 6000.00 63.78 344.14 4510.45 2821.25 -466.04 0.00 0.00 2803.69 Start Dir 12.3º/100' : 6000' MD, 4510.45'TVD : 60° RT TF2 6017.00 64.84 346.15 4517.82 2836.06 -469.97 12.30 60.00 2818.35 End Dir : 6017' MD, 4517.82' TVD3 6047.00 64.84 346.15 4530.58 2862.42 -476.47 0.00 0.00 2844.48 Start Dir 5º/100' : 6047' MD, 4530.58'TVD4 6697.46 47.92 19.95 4896.69 3389.37 -464.27 5.00 129.82 3371.53 End Dir : 6697.46' MD, 4896.69' TVD5 8908.22 47.92 19.95 6378.16 4931.85 95.59 0.00 0.00 4932.24 Start Dir 5º/100' : 8908.22' MD, 6378.16'TVD6 9474.84 21.00 3.12 6842.00 5237.15 174.48 5.00 -167.37 5240.05 End Dir : 9474.84' MD, 6842' TVD710014.38 21.00 3.12 7345.70 5430.21 185.00 0.00 0.00 5433.36 MPF-62A wp01 Tgt1810097.33 21.00 3.12 7423.14 5459.90 186.62 0.00 0.00 5463.08 Total Depth : 10097.33' MD, 7423.14' TVD 2667 2933 3200 3467 3733 4000 4267 4533 4800 5067 5333 5600 5867 6133 South(-)/North(+) (400 usft/in)-1600 -1333 -1067 -800 -533 -267 0 267 533 800 1067 West(-)/East(+) (400 usft/in) MPF-62A wp01 Tgt1 MPF-62 9 5/8" 4 1/2" x 6 1/8" 4 5 0 0 4750 5000 5250 5500 5750 6000 6250 6500 6750 7000 7250 7423 MPF-62A wp01 Start Dir 12.3º/100' : 6000' MD, 4510.45'TVD : 60° RT TF End Dir : 6017' MD, 4517.82' TVD Start Dir 5º/100' : 6047' MD, 4530.58'TVD End Dir : 6697.46' MD, 4896.69' TVD Start Dir 5º/100' : 8908.22' MD, 6378.16'TVD End Dir : 9474.84' MD, 6842' TVD Total Depth : 10097.33' MD, 7423.14' TVD Project: Milne Point Site: M Pt F Pad Well: MPF-62 Wellbore: MPF-62A Plan: MPF-62A wp01 WELL DETAILS: MPF-62 Ground Level: 12.00 +N/-S +E/-W Northing Easting Latittude Longitude 0.00 0.00 6035593.36 541934.67 70° 30' 29.367 N 149° 39' 24.820 W REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well MPF-62, True North Vertical (TVD) Reference:MPF-62A @ 45.70usft Measured Depth Reference:MPF-62A @ 45.70usft Calculation Method:Minimum Curvature CASING DETAILS TVD TVDSS MD Size Name 4535.72 4490.02 6059.00 9-5/8 9 5/8" 7423.14 7377.44 10097.33 4-1/2 4 1/2" x 6 1/8" 2667 2933 3200 3467 3733 4000 4267 4533 4800 5067 5333 5600 5867 6133 South(-)/North(+) (400 usft/in)-1600 -1333 -1067 -800 -533 -267 0 267 533 800 1067 West(-)/East(+) (400 usft/in) MPF-62A wp01 Tgt1 3 0 0 0 3 2 5 0 3 50 0 3 7 5 0 4 0 0 0 4 2 5 0 MPF-93L1-02 3 0 0 0 3 2 5 0 3 50 0 3 7 5 0 4 0 0 0 4 2 5 0 MPF-93 3 0 0 0 3 2 5 0 3 50 0 3 7 5 0 4 0 0 0 4 2 5 0 MPF-93L1-01 3 0 0 0 3 2 5 0 3 50 0 3 7 5 0 4 0 0 0 4 2 5 0 MPF-93L1 3750 4000 4250 MPF-74 3750 4000 4250 MPF-74A 3750 4000 4250 MPF-74APB1 4 0 0 0 MPF-29 3 7 5 0 4 0 0 0 4 2 5 0 MPF-30 3 7 5 0 4 0 0 0 4 2 5 0 MPF-30A 3 2 5 0 MPF-42 4500 47 5 0 50 0 0 525 0 5500 5 750 6000 6250 6500 67 5 0 7 0 0 0 7 2 5 0 7 4 62 MPF-69 MPF-17 3 2 5 0 3500 3750 4000 MPF-92 3500 3750 4000 4250 4500 MPF-34 4250 4500 4750 MPF-61 3 5 0 0 3 7 5 0 4 0 0 0 MPF-54 4750 5000 5250 5500 MPF-73A 4750 5000 5250 5500 MPF-73A 4750 5000 5250 5500 MPF-73 4750 5000 5250 5500 MPF-73APB1 3 5 0 0 3 7 5 0 MPF-50 4 5 0 0 4 7 5 0 5 0 0 0 5 2 5 0 5 5 0 0 5 7 5 0 6 0 0 0 6 2 5 0 MPF-62 3750 4000 4250 4500 4750 MPF-78A 3750 4000 4250 4500 4750 MPF-78APB1 3750 4000 4250 4500 4750 MPF-78AL1 3750 4000 4250 4500 4750 MPF-78AL2 3750 4000 4250 4500 4750 MPF-78 3750 4000 4250 4500 4750 5000 5250 MPF-53AL1 3750 4000 4250 4500 4750 5000 5250 MPF-53A 3750 4000 4250 4500 4750 5000 5250 MPF-53 4000 4250 4421MPF-53PB1 3750 4000 4250 4500 4750 5000 5250 MPF-53AL2 3250 3500 3750 4000 MPF-95 3000 3250 3500 3750 MPF-94 42 50 4 5 0 0 4 7 50 5000 MPF-70A 42 50 4 5 0 0 4 7 50 5000 MPF-70 42 50 4 5 0 0 4 7 50 5000 MPF-70AL1 4 2 5 0 4 5 0 0 MPF-37 3 7 5 0 4 0 0 0 4 2 5 0 4 5 0 0 MPF-38 3 5 0 0 3 7 5 0 MPF-22 4 2 5 0 4 5 0 0 4 7 5 0 5 0 0 0 5 2 5 0 MPF-45 6000 6250 6500 6750 7 0 0 0 7 2 5 0 7 5 0 0 7 7 5 0 8 0 0 0 8 2 5 0 8 5 0 0 8 7 5 0 MPF-33 6000 6250 6500 6750 7 0 0 0 7 2 5 0 7 5 0 0 7 7 5 0 8 0 0 0 8 2 5 0 8 5 0 0 8 7 5 0 MPF-33A 6 2 5 0 6 5 0 0 6 7 5 0 7 0 0 0 7 2 5 0 7 5 0 0 7 7 1 0 MPL-24 5250550057506000625065006750MPL-15 9 5/8" 4 1/2" x 6 1/8" 4 5 0 0 4750 5000 5250 5500 5750 6000 6250 6500 6750 7000 7250 7423 MPF-62A wp01 Project: Milne Point Site: M Pt F Pad Well: MPF-62 Wellbore: MPF-62A Plan: MPF-62A wp01 # " $ % ! 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'- &.4 - &.8 ') & ;0 &&;0+4 ; 1 (!0%#30** &0 ')0 )*'+ ,'-)&.&'( ! ! ! $% ')- &. : /### %! !!### "! !!### !!### !! - &.?- &. ,B ,? &' (& & ) &*%&+ ,- . ) &*%-+/- - ."! 0! !!!1 2' ! !3 1 ! 4) !! 1 !! !1 5 ! 6%! $) 5!78%! $) 5!"! 9%! $) !!3! .3 ! 4) )4 !! !) 1 1! .3 0101 2 1 03 0.001.503.004.50Separation Factor6000 6300 6600 6900 7200 7500 7800 8100 8400 8700 9000 9300 9600 9900 10200 10500 10800 11100Measured DepthMPF-69MPF-62MPL-24MPL-15No-Go Zone - Stop DrillingCollision Avoidance Req.Collision Risk Procedures Req.NOERRORSWELL DETAILS:MPF-62 NAD 1927 (NADCON CONUS)Alaska Zone 04Ground Level: 12.00+N/-S +E/-W Northing EastingLatittudeLongitude0.000.006035593.36 541934.67 70° 30' 29.367 N 149° 39' 24.820 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well MPF-62, True NorthVertical (TVD) Reference:MPF-62A @ 45.70usftMeasured Depth Reference:MPF-62A @ 45.70usftCalculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2020-08-28T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool114.95 6000.00 GYD Gyro (MPF-62) 3_Gyro-CT_pre-1998_Pipe6000.00 6300.00 MPF-62A wp01 (MPF-62A) 3_MWD_Interp Azi+Sag6300.00 10097.27 MPF-62A wp01 (MPF-62A) 3_MWD+IFR2+MS+Sag0.0030.0060.0090.00120.00150.00Centre to Centre Separation (50.00 usft/in)6000 6300 6600 6900 7200 7500 7800 8100 8400 8700 9000 9300 9600 9900 10200 10500 10800 11100Measured DepthNO GLOBAL FILTER: Using user defined selection & filtering criteria6000.00 To 10097.33Project: Milne PointSite: M Pt F PadWell: MPF-62Wellbore: MPF-62APlan: MPF-62A wp01Ladder / S.F. PlotsCASING DETAILSTVD TVDSS MD Size Name4535.72 4490.02 6059.00 9-5/8 9 5/8"7423.14 7377.44 10097.33 4-1/2 4 1/2" x 6 1/8" 1 Davies, Stephen F (CED) From:Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Sent:Monday, September 28, 2020 11:46 AM To:Davies, Stephen F (CED) Subject:RE: [EXTERNAL] RE: MPU F-62A 10-401 Permit to Drill Steve, Correct. Sorry about that! TD: 10097’ MD / 7423’ TVD Thanks, Joe Lastufka Sr. Drilling Technologist Hilcorp North Slope, LLC Office: (907)777-8400, Cell:(907)227-8496 From: Davies, Stephen F (CED) [mailto:steve.davies@alaska.gov] Sent: Monday, September 28, 2020 11:34 AM To: Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Subject: [EXTERNAL] RE: MPU F‐62A 10‐401 Permit to Drill Hi Joe, Hilcorp’s PTD application form for F‐62A indicates the total depth of the well is 14,338’ MD / 3509’ TVD, but the directional survey indicates the TD is 10,097.33’ MD / 7423.14’ TVD and production casing setting depth is listed as 10,097’ MD. I’m assuming that the 10,097’ MD value is correct? Right? Thanks and stay safe, Steve Davies Alaska Oil and Gas Conservation Commission (AOGCC) CONFIDENTIALITY NOTICE: This e‐mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e‐mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907‐793‐1224 or steve.davies@alaska.gov. From: Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Sent: Monday, September 28, 2020 10:49 AM To: AOGCC Permitting (CED sponsored) <aogcc.permitting@alaska.gov> Cc: Davies, Stephen F (CED) <steve.davies@alaska.gov>; Boyer, David L (CED) <david.boyer2@alaska.gov> Subject: MPU F‐62A 10‐401 Permit to Drill Hello, 2 Please see attached for electronic distribution of MPU F‐62A Permit to Drill. Please let me know if you have any questions. Thanks! Thanks, Joe Lastufka Sr. Drilling Technologist Hilcorp North Slope, LLC Office: (907)777-8400, Cell:(907)227-8496 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. 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Seamount, Jr.Digitally signed by Daniel T. Seamount, Jr. Date: 2020.10.05 10:20:47 -08'00'JMP10/5/2020JLC 10/5/2020