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Home My WebLink About220-061MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Tuesday, April 22, 2025 SUBJECT:Mechanical Integrity Tests TO: FROM:Brian Bixby P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL Hilcorp Alaska, LLC L-63 MILNE PT UNIT L-63 Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 04/22/2025 L-63 50-029-23687-00-00 220-061-0 W SPT 6948 2200610 1737 1547 1548 1545 1545 87 365 344 332 4YRTST P Brian Bixby 3/15/2025 30 MinPretestInitial15 Min Well Name Type Test Notes: Interval P/F Well Permit Number: Type Inj TVD PTD Test psi API Well Number Inspector Name:MILNE PT UNIT L-63 Inspection Date: Tubing OA Packer Depth 93 2163 2097 2082IA 45 Min 60 Min Rel Insp Num: Insp Num:mitBDB250315153346 BBL Pumped:2.4 BBL Returned:2.4 Tuesday, April 22, 2025 Page 1 of 1            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: 12/30/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU L-63 (PTD 220-061) IPROF 12/11/2021 Please include current contact information if different from above. Received By: 01/03/2022 37' (6HW By Abby Bell at 9:44 am, Jan 03, 2022 MEMORANDUM TO: Jim Regg �,I 10( ZA!Z,( P.I. Supervisor ,I FROM: Adam Earl Petroleum Inspector Well Name MILNE PT UNIT L-63 Insp Num: mitAGE210221075045 Rel Insp Num: NON -CONFIDENTIAL State of Alaska Alaska Oil and Gas Conservation Commission DATE: Wednesday, March 3, 2021 SUBJECT: Mechanical Integrity Tests Hilcorp Alaska, LLC L-63 MILNE PT UNIT L-63 Sre: Inspector Reviewed Bp— P.I. Supry ._ 1 Comm API Well Number 50-029-23687-00-00 Inspector Name: Adam Earl Permit Number: 220-061-0 Inspection Date: 2/16/2021 ' Packer Depth Well Lia Type Inl N iTVD 6950 PTD 2200610 . Type Test SPT (Test psi 173s - 1313L Pumped: 2.7 - BBL Returned: 2.7 Interval _ OTHER P/F _ P Notes: Pre produced Injector. This test is pre-inject.MIT-IAS Pretest Initial 15 Min 30 Min 45 Min 60 Min abing 851 - 863- 859- 858 IA .. 33 2783 2737 - I 2722 OA 8 -244 203_ 185_-,.. Wednesday, Much 3, 2021 Page 1 01 1 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: Convert to Injector Hilcorp Alaska 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 9,184 feet N/A feet true vertical 7,420 feet N/A feet Effective Depth measured 9,093 feet 8,681 feet true vertical 7,335 feet 6,948 feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth)3-1/2" 9.3# / L-80 / EUE 8rd 8,784' 7,044' Packers and SSSV (type, measured and true vertical depth)FHL Retrievable 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 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: Chad Helgeson Contact Name: Authorized Title:Operations Manager Contact Email: Contact Phone: 2. Operator Name Senior Engineer: Senior Res. Engineer: Collapse N/A 8,675psi 8,525psi 6,151psi 8,835psi 8,681psi 6,276psi 20" 9-5/8" 9-5/8" 7" 1,960' Iproduction Casing Conductor Length 153' 2,163' 3,662' Burst N/A MPU L-63 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf 3,021 Casing Pressure Tubing Pressure 0 4,711' 7,411' 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 321-022 1,000 Authorized Signature with date: Authorized Name: David Haakinson 777-8343 dhaakinson@hilcorp.com 100 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 220-061 50-029-23687-00-00 Plugs ADL025509 5. Permit to Drill Number: 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 1,000 9,175' N/A measured Surface Surface true vertical Packer Milne Point Unit / Kuparuk Oil Pool Junk measured 5,856' TVD 3. Address: 4. Well Class Before Work: 198 Representative Daily Average Production or Injection Data 343243 Oil-Bbl measured 187' N/A Size 9,175' WINJ WAG 14 Water-Bbl MD 187' 2,163' PL G Form 10-404 Revised 3/2020 Submit Within 30 days of Operations By Samantha Carlisle at 9:14 am, Mar 02, 2021 Chad Helgeson (1517) 2021.03.01 15:43:36 - 09'00' DSR-3/2/21 SFD 3/2/2021MGR03MAR2021 RBDMS HEW 3/2/2021 _____________________________________________________________________________________ Revised By: DAH 03/01/21 SCHEMATIC Milne Point Unit Well: MPU L-63 PTD: 220-061 Last Completed: 10/16/2020 PERFORATION DETAIL KUP Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status C 8,814’ 8,827’ 7,072’ 7,085’ 13 10/13/2020 Open B6 8,827’ 8,884’ 7,085’ 7,138’ 57 10/13/2020 Open A3 8,920’ 8,941’ 7,172’ 7,192’ 21 10/12/2020 Open A2 8,941’ 8,971’ 7,192’ 7,220’ 30 10/12/2020 Open A1 8,971’ 9,005’ 7,220’ 7,252’ 34 10/12/2020 Open 9,010’ 9,026’ 7,257’ 7,272’ 16 10/12/2020 Open 3-1/8’, 6 SPF, 60° Phase, HSC GeoDynamics Basix 22.7g RDX CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20" Conductor 129 / X-52 / Weld N/A Surface 114’ N/A 9-5/8" Surface 47 / L-80 / TXP 8.681” Surface 2,215’ 0.0732 9-5/8" Surface 40 / L-80 / TXP 8.835” 2,215’ 5,858’ 0.0758 7” Production 26 / L-80 / BTC 6.276” Surface 9,175’ 0.0149 TUBING DETAIL 3-1/2” Tubing 9.3 / L-80 / EUE 8RD 2.992” Surf 8,784’ 0.0087 JEWELRY DETAIL No Top MD Item ID 1 8,626’ Sliding Sleeve, HES XD, 2.813” X (CLOSED) 2.813” 2 8,681’ FHL Retrievable Packer 2.910” 3 8,740’ Nipple, 2.813” XN (2.750” no-go) 2.750” 4 8,783’ WLEG (bottom at 8,784’) 2.992” OPEN HOLE / CEMENT DETAIL 42" ±270 ft3 12-1/4" Stg 1 –485 sx / Tail 400 sx Stg 2 –Lead 488 sx / Tail 270 sx 8-1/2” x 9-7/8” 255 sx WELL INCLINATION DETAIL KOP @ 260’ Hole Angle @ XN = 21° Max Hole Angle = 44° TREE & WELLHEAD Tree Cameron 3 1/8" 5M w/ 3-1/8” 5M Cameron Wing Wellhead FMC Gen 5 GENERAL WELL INFO API#: 50-029-23687-00-00 Completed by Doyon 14: 10/15/2020 Well Name Rig API Number Well Permit Number Start Date End Date MP L-63 Slickline 50-029-23687-00-00 220-061 1/29/2021 2/16/2021 1/29/2021 - Friday WELL FLOWING ON ARRIVAL, OPEN PERMIT W/PAD-OP & S/I WELL, PT PF HOSE & PCE 250L/3,500H. ATTEMPT TO PULL 3" JET PUMP FROM XD-SS AT 8,613' SLM/8,626' MD (unsuccessful). JET PUMP BLOWN OUT OF XD-SS WHILE LRS FREEZE PROTECT TBG WITH 25bbls 60/40. MAKE MULTIBLE ATTEMTS TO LATCH JET PUMP AT 8718' SLM (unsuccessful). MAKE MULTIBLE BAILER RUNS FROM 8,718' SLM TO 8,722' SLM (recovered ~1gal sandy/scale and ~2 cups fine sand). L/D FOR THE NIGHT, NOTIFY PAD-OP 1/27/2021 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary No operations to report. 1/28/2021 - Thursday No operations to report. No operations to report. WELL S/I ON ARRIVAL, OPEN PERMIT W/PAD-OP, PT PCE 250L/3,500H. MAKE MULTIBLE BAILER RUNS FROM 8,718' SLM TO 8,723' SLM (recovered 3gal sand). PULL 3" JET PUMP (serial# HC-0004, ratio: 11X) FROM XN-NIP AT 8,723' SLM/8,740' MD. L/D FOR THE NIGHT, NOTIFY PAD-OP. 1/30/2021 - Saturday No operations to report. 2/2/2021 - Tuesday 1/31/2021 - Sunday Assist Slickline (Convert to Inj) (Pressure test surface lines 250/4,000psi) Pump 182 bbls Corrosion water and 61 bbls Dsl down IA. Pump 3 bbls 60/40 down Prod Lat. Bleed Lat to zero. Pump 25 bbls 60/40 down Tbg. MIT-T to 3,500 psi (PASSED) Pump 0.85 bbls Dsl to reach test pressure. 1st 15 Min Tbg gained 64 psi. 2nd 15 Min Tbg gained 64 psi. Bleed Tbg down to 500 psi w/ 0.85 bbls Dsl returned. MIT-IA to 2,500 psi. (PASSED) Pump 2.75 bbls Dsl to reach test pressure. 1st 15 Min IA lost 46 psi. 2nd 15 Min IA gained 13 psi. Bleed IA down w/ 2.3 bbls Dsl returned. WELL S/I ON ARRIVAL, NOTIFY PAD-OP, PT PCE 250L/3,500H. DRIFT & TAG TD WITH 5' x2.5 " DRIVE DOWN BAILER (mule shoe bottom) AT 8,991' SLM/ 9,025' MD (bailer empty, 34' KB correction, 1' fill). LRS PUMP 183bbls 1% CORROSION INHIBITED SOURCE WATER & 61bbls DIESEL DOWN IA. SHIFT XD-SS CLOSED WITH 3-1/2" 42-BO AT 8,614' SLM/ 8,626' MD.SET CSV IN XN-NIP AT 8,731' SLM/8,740'MD, LRS MIT-T 3,500psi (pass, see LRS log), PULL CSV FROM XN-NIP. 2/1/2021 - Monday Well Name Rig API Number Well Permit Number Start Date End Date MP L-63 LRS 50-029-23687-00-00 220-061 1/29/2021 2/16/2021 2/12/2021 - Friday No operations to report. 2/10/2021 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary No operations to report. 2/11/2021 - Thursday No operations to report. AOGCC MITIA Pre-Injection - Passed. Witnessed by Adam Earl. Initial T/I/O = 851/33/8, Start T/I/O = 863/2,783/244, 15 Min T/I/O = 859/2,737/203, 30 Min T/I/O = 858/2,722/185. Pumped 2.7 bbls to pressure up and returned 2.7 while bleeding back No operations to report. 2/13/2021 - Saturday No operations to report. 2/16/2021 - Tuesday 2/14/2021 - Sunday No operations to report. 2/15/2021 - Monday 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 Injector 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): 9,184'N/A Casing Collapse Conductor N/A Surface 8,675psi Surface 8,525psi Production 6,151psi 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 COMMISSION USE ONLY Authorized Name: Authorized Signature: 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. STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL025509 220-061 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 Milne Point Unit / Kuparuk Oil Pool 50-029-23687-00-00 Hilcorp Alaska LLC Length Size 7,420' 9,093' 7,335' C.O. 432D PRESENT WELL CONDITION SUMMARY 2,481 TVD Burst 8,784' MD Tubing Size: 2,163' 9,175' 5,856' 4,711' N/A MPU L-63 187'187'N/A Tubing Grade: 8,835psi 6,276psi 1,960' 7,411' 8,681' MD / 6,948' TVD & N/A 153'20" 9-5/8" 7" 2,163' 9,175' 3,662'9-5/8" 9.3# / L-80 / EUE 8rd David Haakinson 2/1/2021 3-1/2" Perforation Depth MD (ft): See Schematic 8,681psi See Schematic Perforation Depth TVD (ft):Tubing MD (ft): FHL Retrievable & N/A ory Statu Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 2:37 pm, Jan 13, 2021 321-022 Chad Helgeson (1517) 2021.01.13 13:57:15 - 09'00' DSR-1/14/21 X DLB 01/13/2021 AOGCC 24 hour notification for opportunity to witness MIT-IA to 2500 psi before POI and after stabilized (within 14 days) of POI. MGR25JAN21 10-404 2,481 Comm. 1/25/21 dts 1/25/2021 JLC 1/25/2021 RBDMS HEW 1/27/2021 Convert to INJ Well: MPU L-63 Date: 01-11-2021 Well Name:MPU L-63 API Number:50-029-23687-00 Current Status:Jet Pump Prod - Online Pad:L-Pad Estimated Start Date:February 1st, 2021 Rig:N/A Reg. Approval Req’d?Yes Date Reg. Approval Rec’vd: Regulatory Contact:Tom Fouts Permit to Drill Number:220-061 First Call Engineer:David Haakinson (907) 777-8343 (O) (307) 660-4999 (M) Second Call Engineer:Ian Toomey (907) 903-3987 (M) AFE Number:Job Type:Convert to Water Injector Current Bottom Hole Pressure: 3,171 psi @ 6,900’ TVD (SBHPS 11/14/2020 | 8.83 ppg EMW) Maximum Expected BHP:3,171 psi @ 6,900’ TVD Reservoir pressure should have decreased further MPSP:2,481 psi (0.1 psi/ft gas gradient) Brief Well Summary: MPU L-63 was drilled and completed in the Kuparuk A and C sands in 2020. The well was originally planned as an injector, but after encountering a higher than anticipated reservoir pressure and high resistivities, the well was converted to a producer. Notes Regarding Wellbore Condition x 7” casing tested to 2,500 psi for 30 minutes down to the packer on 10/15/2020. x 3-1/2” tubing test to 3,400 psi for 30 min down to tubing tail plug on 10/15/2020. x Top of cement for 7” production casing is at 8,150’ MD, 664’ above top of Kuparuk sand. o The bond log was completed on 10/12/20. x Packer is 188’ from the Kuparuk River Oil Pool C-sand in accordance with 20AAC25.412(b). x The Sliding Sleeve will be closed prior to injection. AOR (status of wells within 1/4 mile radius of injection zone): API Well No Permit Well Current Status Top of Kup TOC Zonal isolation (method) 50-029-22030-00-00 190-039 MPU L-05 Kuparuk WINJ 9,803’ MD 7,133’ TVD 8,900’ MD 6,055’ TVD Open perforations in Kuparuk B&A Sands Objective: The purpose of this work/sundry is to convert this well from a Kuparuk producer to a Kuparuk water injector to provide waterflood support for offset producers MPU L-41 (PTD 218-104) and MPU L-43 (PTD 203-224). Wellwork Procedure: 1. MIRU Slickline Unit. 2. PT PCE to 200 psi L / 3000 psi H. 3. Pull jet pump from 2.813” sliding sleeve @ 8,626’ MD. Convert to INJ Well: MPU L-63 Date: 01-11-2021 4. MIRU LRS pump truck. 5. Pump 183 bbls of 1% corrosion inhibited source water followed by 61 bbls of diesel down the annulus. 6. Shift sleeve at 8,626’ MD to closed position. 7. Pressure Test 3-1/2” tubing to 3,500 psi for 30 minutes (charted) 8. Test 7” casing to 2,500 psi for 30 min (charted). a. Notify AOGCC Inspector at least 24 hours prior to conducting pre-injection MIT-IA. b. Record on 10-426 form. 9. Turn well over to operations for injection startup. 10. After stabilized injection within 14-days of uptime, conduct an MIT-IA to 2,500 psi. a. Notify AOGCC Inspector at least 24 hours prior to conducting MIT-IA. b. Record on 10-426 form. Attachments: 1. Proposed Schematic 2. Area of Review (AOR) Summary 3. Surface Owner Affidavit _____________________________________________________________________________________ Revised By: TDF 11/19/2020 PROPOSED Milne Point Unit Well: MPU L-63 PTD: 220-061 Last Completed: 10/16/2020 PERFORATION DETAIL KUP Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status C 8,814’ 8,827’ 7,072’ 7,085’ 13 10/13/2020 Open B6 8,827’ 8,884’ 7,085’ 7,138’ 57 10/13/2020 Open A3 8,920’ 8,941’ 7,172’ 7,192’ 21 10/12/2020 Open A2 8,941’ 8,971’ 7,192’ 7,220’ 30 10/12/2020 Open A1 8,971’ 9,005’ 7,220’ 7,252’ 34 10/12/2020 Open 9,010’ 9,026’ 7,257’ 7,272’ 16 10/12/2020 Open 3-1/8’, 6 SPF, 60° Phase, HSC GeoDynamics Basix 22.7g RDX TD =9,184’(MD) / TD =7,420’(TVD) 20” FISH: 3-1/8” Perf Guns (92.75’ Long) Orig. KB Elev.: 50.0’ / GL Elev.: 16.1’ 4 2 9-5/8” 1 3 PBTD =9,093’(MD) / PBTD =7,335’(TVD) 9-5/8” ‘ES’ Cementer @ 2,218’ MD 7” CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20" Conductor 129 / X-52 / Weld N/A Surface 114’ N/A 9-5/8" Surface 47 / L-80 / TXP 8.681” Surface 2,215’ 0.0732 9-5/8" Surface 40 / L-80 / TXP 8.835” 2,215’ 5,858’ 0.0758 7” Production 26 / L-80 / BTC 6.276” Surface 9,175’ 0.0149 TUBING DETAIL 3-1/2” Tubing 9.3 / L-80 / EUE 8RD 2.992” Surf 8,784’ 0.0087 JEWELRY DETAIL No Top MD Item ID 1 8,626’ Sliding Sleeve (Closed), HES XD, 2.813” X 2.813” 2 8,681’ FHL Retrievable Packer 2.910” 3 8,740’ Nipple, 2.813” XN (2.750” no-go) 2.750” 4 8,783’ WLEG (bottom at 8,784’) 2.992” OPEN HOLE / CEMENT DETAIL 42" ±270 ft3 12-1/4"Stg 1 –485 sx / Tail 400 sx Stg 2 –Lead 488 sx / Tail 270 sx 8-1/2” x 9-7/8” 255 sx WELL INCLINATION DETAIL KOP @ 260’ Hole Angle @ XN = 21° Max Hole Angle = 44° TREE & WELLHEAD Tree Cameron 3 1/8" 5M w/ 3-1/8” 5M Cameron Wing Wellhead FMC Gen 5 GENERAL WELL INFO API#: 50-029-23687-00-00 Completed by Doyon 14: 10/15/2020 SFD 1/15/2020 187 Area of Review Summary – Milne Point Unit L-63 (PTD 220-061) This Area of Review is required prior to the conversion of well MPU L-63 from a producer to a water injector. This AOR discusses wells with ¼ mile of the well’s entry point into the Kuparuk River Oil Pool C sand (top of the injection zone) to the bottom of MPU L-63 well bore completion. Figure 1: Map showing wells within ¼ mile radius from MPU L-63 The list of all operators and surface owners within ¼ mile of MPU L-63 is below: # Operators # Surface Owners 1 Hilcorp Alaska, LLC 1 Alaska Department of Natural Resources (ADNR) Table 1: List of operators and surface owners An affidavit has been submitted to the following operators and surface owners: # Operators # Surface Owners 1 N/A 1 Alaska Department of Natural Resources (ADNR) Table 2: List of operators and surface owners receiving an affidavit Injection well MPU L-05 (PTD 190-039) is the only well within a ¼ mile radius of the injection zone of MPU L-63, measured at 1,210’ away. MPU L-05 was drilled and completed as a Kuparuk producer in 1990. The top of Kuparuk sand is measured at 9,803’ MD, and a cement bond log run on 05/02/1990 indicates a top of cement at 8,160’ MD. In 2019, MPU L-05 was converted to injection to support MPU L-41 and MPU L-43. A passing MIT-IA for MPU L-05 was last completed to 1,756 psi on 8/1/19. API Well No Permit Well Current Status Top of Kup TOC Zonal isolation (method) 50-029-22030-00- 00 190- 039 MPU L- 05 Kuparuk WINJ 9,803’ MD 7,133’ TVD 8,160’ MD 6,055’ TVD Open perforations in Kuparuk B&A Sands Table 3: Distance and annulus integrity of wells within AOR Well MPU L-63 was drilled and completed in October 2020 with plans to complete as an injector. However, the Kuparuk sand resistivity was higher than anticipated and the well was completed as a producer for a planned short interval of production. A cement bond log was run on 10/12/2020 with a top of cement measured at 8,150’ MD. Passing mechanical integrity tests of the tubing and inner-annulus were completed on 10/12/21 with pressures at 3,400 psi and 2,500 psi respectively. L-63 was put on production with a measured reservoir pressure of 10.5 ppge. Recent well test data has indicated the oil rate has fallen from over 400 BOPD to approximately 200 BOPD, and now injection has been determined to be of higher value. The plan is to target injection sweep along the flanks of the fault block to the offset producers and bring the injection-withdrawl ratio of the fault block back to unity. The current reservoir pressure in MPU L-63 as of January 2021 is expected to be between 8.0 and 8.8 ppge, indicating depletion of the fault block. Once upon injection, MPU L-63 is anticipated to inject 1,000 to 1,500 BWPD of source water supplied by water source wells located on MPU F-Pad. Surface wellhead injection pressures are projected targeted at 1,800 to 2,400 psi. The incremental ultimate resource recovery is projected to be 980 MBO. DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-23687-00-00Well Name/No. MILNE PT UNIT L-63Completion Status1-OILCompletion Date10/15/2020Permit to Drill2200610Operator Hilcorp Alaska, LLCMD9184TVD7420Current Status1-OIL1/5/2021UICNoWell Log Information:DigitalMed/FrmtReceivedStart StopOH /CHCommentsLogMediaRunNoElectr DatasetNumberNameIntervalList of Logs Obtained:ROP, AGR, ABG, DGR, EWR, ADR MD & TVD, Cement EvaluationNoNoYesMud Log Samples Directional SurveyREQUIRED INFORMATION(from Master Well Data/Logs)DATA INFORMATIONLog/DataTypeLogScaleDF10/29/2020170 9184 Electronic Data Set, Filename: MPU L-63 LWD Final.las34144EDDigital DataDF10/29/2020 Electronic File: MPU L-63 LWD Final MD.cgm34144EDDigital DataDF10/29/2020 Electronic File: MPU L-63 LWD Final TVD.cgm34144EDDigital DataDF10/29/2020 Electronic File: MPU L-63 Definitive Surveys.xlsx34144EDDigital DataDF10/29/2020 Electronic File: MPU L-63_Definitive Survey Report.pdf34144EDDigital DataDF10/29/2020 Electronic File: MPU L-63_Definitive survey report.txt34144EDDigital DataDF10/29/2020 Electronic File: MPU L-63_GIS.txt34144EDDigital DataDF10/29/2020 Electronic File: MPU L-63_Plan.pdf34144EDDigital DataDF10/29/2020 Electronic File: MPU L-63_VSec.pdf34144EDDigital DataDF10/29/2020 Electronic File: MPU L-63 LWD Final MD.emf34144EDDigital DataDF10/29/2020 Electronic File: MPU L-63 LWD Final TVD.emf34144EDDigital DataDF10/29/2020 Electronic File: MPU L-63 LWD Final MD.pdf34144EDDigital DataDF10/29/2020 Electronic File: MPU L-63 LWD Final TVD.pdf34144EDDigital DataDF10/29/2020 Electronic File: MPU L-63 LWD Final MD.tif34144EDDigital DataDF10/29/2020 Electronic File: MPU L-63 LWD Final TVD.tif34144EDDigital DataDF10/29/2020 Electronic File: EMFView3_1.zip34144EDDigital DataDF10/29/2020 Electronic File: Readme.txt34144EDDigital Data0 0 2200610 MILNE PT UNIT L-63 LOG HEADERS34144LogLog Header ScansTuesday, January 5, 2021AOGCCPage 1 of 3MPU L-63 LWDFinal.las DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-23687-00-00Well Name/No. MILNE PT UNIT L-63Completion Status1-OILCompletion Date10/15/2020Permit to Drill2200610Operator Hilcorp Alaska, LLCMD9184TVD7420Current Status1-OIL1/5/2021UICNoDF12/22/20208865 8693 Electronic Data Set, Filename: MPU_L-63_PERF_12OCT20_8814-8884.las34442EDDigital DataDF12/22/20208953 8705 Electronic Data Set, Filename: MPU_L-63_PERF_12OCT20_8920-9026.las34442EDDigital DataDF12/22/20209080 7780 Electronic Data Set, Filename: MPU_L-63_PERF_12OCT20_CORRELATION 2.las34442EDDigital DataDF12/22/20208970 8596 Electronic Data Set, Filename: MPU_L-63_PERF_12OCT20_CORRELATION PASS GUN 1.las34442EDDigital DataDF12/22/20208891 8658 Electronic Data Set, Filename: MPU_L-63_PERF_12OCT20_CORRELATION PASS GUN 2.las34442EDDigital DataDF12/22/20208214 7793 Electronic Data Set, Filename: MPU_L-63_PERF_12OCT20_CORRELATION.las34442EDDigital DataDF12/22/2020 Electronic File: MPU_L-63_PERF_12OCT20.pdf34442EDDigital DataDF12/22/2020 Electronic File: MPU_L-63_PERF_12OCT20_img.tiff34442EDDigital Data0 0 2200610 MILNE PT UNIT L-63 LOG HEADERS34442LogLog Header Scans0 0 2200610 MILNE PT UNIT L-63 LOG HEADERS34443LogLog Header ScansDF12/22/20207530 7368 Electronic Data Set, Filename: MPU_L-63_RCBL_12OCT20_FreePipe.las34443EDDigital DataDF12/22/20209080 7780 Electronic Data Set, Filename: MPU_L-63_RCBL_12OCT20_Main.las34443EDDigital DataDF12/22/20208214 7793 Electronic Data Set, Filename: MPU_L-63_RCBL_12OCT20_Repeat.las34443EDDigital DataDF12/22/2020 Electronic File: MPU_L-63_RCBL_12OCT20.pdf34443EDDigital DataDF12/22/2020 Electronic File: MPU_L-63_RCBL_12OCT20_img.tiff34443EDDigital DataDF12/22/2020 Electronic File: MPU_L-63_RCBL_12OCT20_FreePipe.dlis34443EDDigital DataDF12/22/2020 Electronic File: MPU_L-63_RCBL_12OCT20_Main.dlis34443EDDigital DataDF12/22/2020 Electronic File: MPU_L-63_RCBL_12OCT20_Repeat.dlis34443EDDigital DataTuesday, January 5, 2021AOGCCPage 2 of 3 DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-23687-00-00Well Name/No. MILNE PT UNIT L-63Completion Status1-OILCompletion Date10/15/2020Permit to Drill2200610Operator Hilcorp Alaska, LLCMD9184TVD7420Current Status1-OIL1/5/2021UICNoWell Cores/Samples Information:ReceivedStart Stop CommentsTotalBoxesSample SetNumberNameIntervalINFORMATION RECEIVEDCompletion 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:10/15/2020Release Date:8/28/2020Tuesday, January 5, 2021AOGCCPage 3 of 3M. Guhl1/5/2021 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 L-63 (PTD 220-061) PERFORATING RECORD 10/12/2020 Please include current contact information if different from above. PTD: 2200610 E-Set: 34442 Received by the AOGCC 12/22/2020 Abby Bell 12/23/2020 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: 12/21/2020 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU L-63 (PTD 220-061) RCBL Radial Cement Bond Log 10/12/2020 Please include current contact information if different from above. PTD: 2200610 E-Set: 34443 Received by the AOGCC 12/22/2020 Abby Bell 12/23/2020 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: Produce Well Hilcorp Alaska 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 9,184 feet N/A feet true vertical 7,420 feet N/A feet Effective Depth measured 9,093 feet 8,681 feet true vertical 7,335 feet 6,948 feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth)3-1/2" 9.3# / L-80 / EUE 8rd 8,784' 7,044' Packers and SSSV (type, measured and true vertical depth)FHL Retrievable 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 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: Chad Helgeson Contact Name: Authorized Title:Operations Manager Contact Email: Contact Phone: WINJ WAG 0 Water-Bbl MD 187' 2,163' 5,856' TVD 187' 86 Oil-Bbl measured true vertical Packer 9,175' Junk measured 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 3. Address: 4. Well Class Before Work: 0 Representative Daily Average Production or Injection Data 00 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 220-061 50-029-23687-00-00 Plugs ADL025509 5. Permit to Drill Number: Milne Point Unit / Kuparuk Oil Pool 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 320-444 344 Authorized Signature with date: Authorized Name: Ian Toomey itoomey@hilcorp.com Size 450 MPU L-63 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 260 Gas-Mcf 0 Casing Pressure Tubing Pressure 13 N/A measured 9,175' N/A Iproduction Casing Conductor Length 153' 2,163' 3,662' Surface Surface 20" 9-5/8" 9-5/8" 7" 1,960' 4,711' 7,411' 8,525psi 6,151psi Burst N/A 8,835psi 8,681psi 6,276psi 777-8520 2. Operator Name Senior Engineer: Senior Res. Engineer: Collapse N/A 8,675psi PL G Form 10-404 Revised 3/2020 Submit Within 30 days of Operations By Samantha Carlisle at 9:42 am, Nov 25, 2020 Chad A Helgeson 2020.11.24 19:02:45 -06'00' RBDMS HEW 11/25/2020 SDF 11/30/2020DSR-11/25/2020MGR30NOV20 _____________________________________________________________________________________ Revised By: TDF 11/19/2020 SCHEMATIC Milne Point Unit Well: MPU L-63 PTD: 220-061 Last Completed: 10/16/2020 PERFORATION DETAIL KUP Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status C 8,814’ 8,827’ 7,072’ 7,085’ 13 10/13/2020 Open B6 8,827’ 8,884’ 7,085’ 7,138’ 57 10/13/2020 Open A3 8,920’ 8,941’ 7,172’ 7,192’ 21 10/12/2020 Open A2 8,941’ 8,971’ 7,192’ 7,220’ 30 10/12/2020 Open A1 8,971’ 9,005’ 7,220’ 7,252’ 34 10/12/2020 Open 9,010’ 9,026’ 7,257’ 7,272’ 16 10/12/2020 Open 3-1/8’, 6 SPF, 60° Phase, HSC GeoDynamics Basix 22.7g RDX TD =9,184’(MD) / TD =7,420’(TVD) 20” FISH: 3-1/8” Perf Guns (92.75’ Long) Orig. KB Elev.: 50.0’ / GL Elev.: 16.1’ 4 2 9-5/8” 1 3 PBTD =9,093’(MD) / PBTD =7,335’(TVD) 9-5/8” ‘ES’ Cementer @ 2,218’ MD 7” CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20" Conductor 129 / X-52 / Weld N/A Surface 114’ N/A 9-5/8" Surface 47 / L-80 / TXP 8.681” Surface 2,215’ 0.0732 9-5/8" Surface 40 / L-80 / TXP 8.835” 2,215’ 5,858’ 0.0758 7” Production 26 / L-80 / BTC 6.276” Surface 9,175’ 0.0149 TUBING DETAIL 3-1/2” Tubing 9.3 / L-80 / EUE 8RD 2.992” Surf 8,784’ 0.0087 JEWELRY DETAIL No Top MD Item ID 1 8,626’ Sliding Sleeve, HES XD, 2.813” X 2.813” 2 8,681’ FHL Retrievable Packer 2.910” 3 8,740’ Nipple, 2.813” XN (2.750” no-go) 2.750” 4 8,783’ WLEG (bottom at 8,784’) 2.992” OPEN HOLE / CEMENT DETAIL 42" ±270 ft3 12-1/4"Stg 1 –485 sx / Tail 400 sx Stg 2 –Lead 488 sx / Tail 270 sx 8-1/2” x 9-7/8” 255 sx WELL INCLINATION DETAIL KOP @ 260’ Hole Angle @ XN = 21° Max Hole Angle = 44° TREE & WELLHEAD Tree Cameron 3 1/8" 5M w/ 3-1/8” 5M Cameron Wing Wellhead FMC Gen 5 GENERAL WELL INFO API#: 50-029-23687-00-00 Completed by Doyon 14: 10/15/2020 Well Name Rig API Number Well Permit Number Start Date End Date MP L-63 Slick Line 50-029-23687-00-00 220-061 10/16/2020 10/16/2020 10/16/2020 - Friday RUN 3-1/2" 42BO (keys down to open) & SHIFT 3-1/2" XD SSD OPEN @ 8,618' SLM (8,626' MD). RUN 2.6" BELL GUIDE W/ 2" JUS (steel) TO PULL BALL & ROD @ 8,728' SLM (8,736' MD). PULL 3-1/2" RHC PLUG BODY IN XN-NIPPLE @ 8,733' SLM / 8,740' MD. SET 3" JET PUMP (SER #: HC-00020, RATIO 10X, FLOW THROUGH SUB, XO, DUAL SPARTEC GAUGES @ 5 MIN. INTERVALS, BATTERIES CONNECTED @ 4:34, OAL=101") IN XD SSD @8,618' SLM / 8,626' MD, GOOD SET. JOB COMPLETE, CLOSE PERMIT & NOTIFY PAD-OP WELL LEFT S/I UPON DEPARTURE. MPU Well Support Techs R/U power fluid line to IA. included in R/U flow meter, check valve, power fluid XV. R/u hardline form l-63 wing to L-25 tree cap. Also R/U hardline for the upcoming flowback. Pressure tested power fluid lines to 3,650 psi and all other piping to 3,150 psi. Freeze Protect Tbg (Post Rig) (Pressure test surface lines 250/2,500psi) Pump 30 bbls Dsl down Tbg. 10/14/2020 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary No operations to report. 10/15/2020 - Thursday No operations to report. No operations to report. 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FKULVZDOODFH#DODVNDJRY 1RWHV 1RWHV 1RWHV )RUP5HYLVHG0,7,$/ Contractor/Rig No.: Doyon 14 Operator: Hilcorp Alaska, LLC Well Class: DEV MISC. INSPECTIONS: GAS DETECTORS: Visual Alarm Methane: P - P Hydrogen Sulfide: P P Gas Detectors Misc: 0 NA -TATE OF ALASKA OIL ANN GAS CONSERVATION COMMISSION Reviewed prvBy'Z ..1 'll { � l Zz DIVERTER Test Report for: MILNE PT UNIT L-63 Comm PTD#: 2200610,' DATE: 9/27/2020 -' Inspector Adam Earl - Insp Source Operator Rep: Yessak/Demoski Rig Rep: Hansen/Carlo Inspector Inspection No: divAGE200930081206 Related Insp No: TEST DATA MUD SYSTEM: PIF Location Gen.: P Housekeeping: P _ Warning Sign P 24 hr Notice: P Well Sign: P,_ Drlg. Rig. P Misc: NA GAS DETECTORS: Visual Alarm Methane: P - P Hydrogen Sulfide: P P Gas Detectors Misc: 0 NA -TATE OF ALASKA OIL ANN GAS CONSERVATION COMMISSION Reviewed prvBy'Z ..1 'll { � l Zz DIVERTER Test Report for: MILNE PT UNIT L-63 Comm PTD#: 2200610,' DATE: 9/27/2020 -' Inspector Adam Earl - Insp Source Operator Rep: Yessak/Demoski Rig Rep: Hansen/Carlo Inspector Inspection No: divAGE200930081206 Related Insp No: TEST DATA MUD SYSTEM: PIF Visual Alarm Trip Tank: P P - Mud Pits: P P Flow Monitor: P _ - _ P Mud System Misc: 0 NA ACCUMULATOR SYSTEM: PIF Time/Pressure PIF Systems Pressure: 2950 - P Pressure After Closure: 1750 P 200 psi Recharge Time: 33 P ' Full Recharge Time: 168 P Nitrogen Bottles (Number of): 6 P ` Avg. Pressure: 2130 P Accumulator Misc: 0 NA DIVERTER SYSTEM: Size PIF Designed to Avoid Freeze-up? P Remote Operated Diverter? P No Threaded Connections? P Vent line Below Diverter?_ P Diverter Size: 21.25 P ' Hole Size: 12.25 P Vent Line(s) Size: 16 P Vent Line(s) Length: 257 P Closest Ignition Source: 76 P Outlet from Rig Substructure: 251 P Vent Line(s) Anchored: P Turns Targeted / Long Radius: P Divert Valve(s) Full Opening: P Valve(s) Auto & Simultaneous: P - Annular Closed Time: 32 P Knife Valve Open Time: 22 P Diverter Misc: 0 NA Number of Failures: 0 Test Time: 1.5 Remarks: 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 L-63 Hilcorp Alaska, LLC Permit to Drill Number: 220-061 Surface Location: 3699' FSL, 5079' FEL, Sec. 08, T13N, R10E, UM, AK Bottomhole Location: 1991' FNL, 1651' FWL, Sec. 05, T13N, R10E, UM, AK Dear Mr. Myers: Enclosed is the approved application for the permit to drill the above referenced service well. Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this 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 August, 2020. JMPi 28 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: 9159' TVD: 7396' 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): 49.2 15. Distance to Nearest Well Open Surface: x-544798 y- 6031889 Zone-4 15.5 to Same Pool: 1210' 16. Deviated wells: Kickoff depth: 300 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 42 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD 42" 20" 215" A-53 80' Surface Surface 114' 114' 9-5/8" 40# L-80 TXP 2500' Surface Surface 2500' 2213' 9-5/8" 47# L-80 TXP 2570' 2500' 2213' 5070' 4124' 8-1/2"x9-7/8"7" 26# L-80 TXP 9159' Surface Surface 9159' 7396' 19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Junk (measured): TVD 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:50- 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 9/8/2020 Authorized Name: Monty Myers Authorized Title: Drilling Manager Nathan Sperry nathan.sperry@hilcorp.com 18. Casing Program:Top - Setting Depth - BottomSpecifications 2308 MPU L-63 Milne Point Unit Kuparuk Oil Pool 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 Hilcorp Alaska, LLC 3699' FSL, 5079' FEL, Sec. 08, T13N, R10E, UM, AK ADL 025509 022224484 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 1568 2140' FNL, 1603' FWL, Sec. 05, T13N, R10E, UM, AK 1991' FNL, 1651' FWL, Sec. 05, T13N, R10E, UM, AK 88-002 2355 11446' 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): Surface Conductor/Structural LengthCasing Production Liner Commission Use Only Perforation Depth TVD (ft): Intermediate 12-1/4"Stg 1 L - 1937 ft3 / T - 313 ft3 Effect. Depth MD (ft): Authorized Signature: 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. GL / BF Elevation above MSL (ft): 330 ft3 ~270 ft3 Stg 1 L - 945 ft3 / T - 458 ft3 s N ype o l 1b 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) 8.11.2020 By Samantha Carlisle at 8:45 am, Aug 11, 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: 2020.08.11 08:10:21 -08'00' Monty M Myers 2nd 639 X DSR-8/11/2020 BOPE test to 3000 psi, Annular to 2500 psi. X X X DLB 08/11/2020 220-061 MGR26AUG2020 345 ft3 X 029-23687-00-00 X X Cement Bond Log to AOGCC before POI. AOGCC to witness MIT-IA to 2500 psi. 24 hour notice. 8/28/2020 8/28/2020 Area of Review MPL-63PTD API WELL STATUSTop of KupC (MD)Top of KupC (TVD)CBL Top ofCement(MD)CBL Top ofCement(TVD) Kuparuk C statusZonal Isolation190-039 50-029-22030-00-00 MPU L-05 Kuparuk B&A WINJ9803' 7133' 8900' 6551' Cased/CementedOpen Perforations B&A, Csands not open RedactedM. Guhl1/6/2021 Milne Point Unit (MPU) L-63 Drilling Program Version 1 8/05/2020 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 Internal Reporting Requirements ............................................................................................. 5 6.0 Planned Wellbore Schematic ..................................................................................................... 6 7.0 Drilling / Completion Summary ................................................................................................ 7 8.0 Mandatory Regulatory Compliance / Notifications .................................................................. 8 9.0 RU and Preparatory Work ...................................................................................................... 10 10.0 NU 21-1/4” 2M Diverter System .............................................................................................. 11 11.0 Drill 12-1/4” Hole Section ........................................................................................................ 13 12.0 Run 9-5/8” Surface Casing ...................................................................................................... 16 13.0 Cement 9-5/8” Surface Casing ................................................................................................. 22 14.0 ND Diverter, NU BOPE, & Test .............................................................................................. 26 15.0 Drill 8-1/2” x 9-7/8" Hole Section ............................................................................................ 27 16.0 Run and Cement 7” Casing ..................................................................................................... 31 17.0 E-line: GR/CCL/CBL, Perf Guns ............................................................................................ 36 18.0 Run 3-1/2” Tubing (Upper Completion) ................................................................................. 37 19.0 Doyon 14 Diverter Schematic .................................................................................................. 39 20.0 Doyon 14 BOP Schematic ........................................................................................................ 40 21.0 Wellhead Schematic ................................................................................................................. 41 22.0 Days Vs Depth .......................................................................................................................... 42 23.0 Formation Tops & Information............................................................................................... 43 24.0 Anticipated Drilling Hazards .................................................................................................. 44 25.0 Doyon 14 Layout ...................................................................................................................... 47 26.0 FIT Procedure .......................................................................................................................... 48 27.0 Doyon 14 Choke Manifold Schematic ..................................................................................... 49 28.0 Casing Design ........................................................................................................................... 50 29.0 8-1/2” x 9-7/8” Hole Section MASP ......................................................................................... 51 30.0 Spider Plot (NAD 27) (Governmental Sections) ...................................................................... 52 31.0 Surface Plat (As Staked) (NAD 27) ......................................................................................... 53 Page 2 Milne Point Unit L-63 Kuparuk Injector Drilling Procedure 1.0 Well Summary Well MPU L-63 Pad Milne Point “L” Pad Planned Completion Type 3-1/2” Injection String w/ Prod Packer Target Reservoir(s) Kuparuk Planned Well TD, MD / TVD 9,159’ MD / 7,396’ TVD PBTD, MD / TVD 9,079’ MD / 7,321’ TVD Surface Location (Governmental) 1580' FNL, 201' FWL, Sec 8, T13N, R10E, UM, AK Surface Location (NAD 27) X= 544798, Y= 6031889 Top of Productive Horizon (Governmental) 2140' FNL, 1603' FWL, Sec 5, T13N, R10E, UM, AK TPH Location (NAD 27) X= 546155 Y= 6036616 BHL (Governmental) 1991' FNL, 1651' FWL, Sec 5, T13N, R10E, UM, AK BHL (NAD 27) X= 546202, Y= 6036766 AFE Number 2013048 AFE Drilling Days 19 AFE Completion Days 2 AFE Drilling Amount $3,864,498 AFE Completion Amount $1,613,733 AFE Facilities Amount $200,000 Maximum Anticipated Pressure (Surface) 1,568 psig Maximum Anticipated Pressure (Downhole/Reservoir) 2,308 psig Work String 5” 19.5# S-135 NC 50 D14 KB Elevation above MSL: 33.7 ft + 15.5 ft = 49.2 ft GL Elevation above MSL: 15.5 ft BOP Equipment 13-5/8” x 5M Annular, (3) ea 13-5/8” x 5M Rams Subnormal prognosed. Page 3 Milne Point Unit L-63 Kuparuk Injector Drilling Procedure 2.0 Management of Change Information Page 4 Milne Point Unit L-63 Kuparuk Injector 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) Cond 20” 19.25” - - - X-52 Weld 12-1/4” 9-5/8” 8.835” 8.679” 10.625” 40.0 L-80 TXP 5,750 3,090 916 9-5/8” 8.681” 8.525” 10.625” 47 L-80 TXP 6,870 4,750 1,086 8-1/2” x 9-7/8” 7” 6.276” 6.151” 6.264 26 L-80 TXP 7,240 5,410 604 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) Surface & Production 5” 4.276” 3.250” 6.625” 19.5 S-135 DS50 36,100 43,100 560klb 5” 4.276” 3.250” 6.625” 19.5 S-135 NC50 30,730 34,136 560klb All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery). Page 5 Milne Point Unit L-63 Kuparuk Injector Drilling Procedure 5.0 Internal Reporting Requirements 5.1 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. 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. 5.2 Afternoon Updates x Submit a short operations update each work day to pmazzolini@hilcorp.com, mmyers@hilcorp, nathan.sperry@hilcorp.com, jengel@hilcorp.com and cdinger@hilcorp.com 5.3 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. 5.4 EHS Incident Reporting x Health and Safety: Notify EHS field coordinator. x Environmental: Drilling Environmental Coordinator x Notify Drilling Manager & Drilling Engineer on all incidents x Submit Hilcorp Incident report to contacts above within 24 hrs 5.5 Casing Tally x Send final “As-Run” Casing tally to mmyers@hilcorp,com nathan.sperry@hilcorp.com, and cdinger@hilcorp.com 5.6 Casing and Cement report x Send casing and cement report for each string of casing to mmyers@hilcorp.com nathan.sperry@hilcorp.com and cdinger@hilcorp.com 5.7 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 Nate 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 Drilling Env. Coordinator Keegan Fleming 907.777.8477 907.350.9439 kfleming@hilcorp.com EHS 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 Page 6 Milne Point Unit L-63 Kuparuk Injector Drilling Procedure 6.0 Planned Wellbore Schematic Page 7 Milne Point Unit L-63 Kuparuk Injector Drilling Procedure 7.0 Drilling / Completion Summary MPU L-63 is a grassroots injector planned to be drilled to the Kuparuk A sands. The directional plan is a slant well path with a 12-1/4” hole with 9-5/8” surface casing set below the lowermost hydrocarbon bearing Schrader Bluff sand. An 8-1/2” x 9-7/8” slant section will then be drilled. A 7 ” casing string will be run in the open hole section and cemented to at least 500’ above the TKUP. The Doyon 14 will be used to drill and complete the wellbore. Drilling operations are expected to commence approximately September 8, 2020, pending rig schedule. Surface casing will be run to 5,823’ MD / 4,699’ TVD and cemented to surface via a 2 stage primary cement job. Cement returns to surface will confirm TOC at surface. If cement returns to surface are not observed, necessary remedial action will then be discussed with AOGCC authorities. All cuttings & mud generated during drilling operations will be hauled to the Milne Point “B” pad G&I facility. General sequence of operations: 1. MIRU Doyon 14 to well site 2. NU & Test 21-1/4” Diverter and 16” diverter line 3. Drill 12-1/4” hole to TD of surface hole section. Run and c ement 9-5/8” surface casing 4. ND diverter, NU wellhead, NU 13-5/8” 5M BOP & test 5. Drill 8-1/2” x 9-7/8” production hole to well TD. 6. Run 7” production casing and cement. 7. Run CBL. 8. Perforate. 9. Run Upper Completion 10. ND BOP, NU Tree, RDMO Reservoir Evaluation Plan: 1. Surface hole: No mud logging. On Site geologist. LWD: GR + Res 2. Production Hole: No mud logging. On site geologist. LWD: GR + Res Page 8 Milne Point Unit L-63 Kuparuk Injector Drilling Procedure 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the all applicable AOGCC regulations, specific regulations are listed below. 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 BOPs shall be tested at (2) week intervals during the drilling and completion of MPU L-63. Ensure to provide AOGCC 24 hrs notice prior to testing BOPs. x The initial test of BOP equipment will be to 250/3,000 psi & subsequent tests of the BOP equipment will be to 250/3,000 psi for 5/5 min (annular to 50% rated WP, 2,500 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 or control fluid flow from the well bore, AOGCC is to be notified and we must 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”. o Ensure the diverter vent line is at least 75’ away from potential ignition sources x Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office. AOGCC Regulation Variance Requests: No variances are requested at this time. Page 9 Milne Point Unit L-63 Kuparuk Injector Drilling Procedure Summary of Doyon 14 BOP Equipment & Test Requirements Hole Section Equipment Test Pressure (psi) 12 1/4” x 21-1/4” 2M Diverter w/ 16” Diverter Line Function Test Only For Reference 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 N/A N/A Primary closing unit: NL Shaffer, 6 station, 3,000 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 Milne Point Unit L-63 Kuparuk Injector Drilling Procedure 9.0 RU and Preparatory Work 9.1 L-63 will utiliz e a newly set 20” conductor on L-Pad. Ensure to review attached surface plat and make sure rig is over appropriate conductor. 9.2 Ensure PTD and drilling program are posted in the rig office and on the rig floor. 9.3 Install landing ring. 9.4 Insure (2) 4” nipples are installed on opposite sides of the conductor with ball valves on each. 9.5 Level pad and ensure enough room for layout of rig footprint and RU. 9.6 Rig mat footprint of rig. 9.7 MIRU Doyon 14. Ensure rig is centered over conductor to prevent any wear to BOPE or wellhead. 9.8 Mud loggers WILL NOT be used on either hole section. 9.9 Mix spud mud for 12-1/4” surface hole section. Ensure mud temperatures are cool (<80qF). 9.10 Ensure 6-1/4” liners in mud pumps. x Continental EMSCO FB-1600 mud pumps are rated at 4,299 psi, 574 GPM @ 120 SPM @ 95% volumetric efficiency. Page 11 Milne Point Unit L-63 Kuparuk Injector Drilling Procedure 10.0 NU 21-1/4” 2M Diverter System 10.1 NU 21-1/4” Hydril MSP 2M Diverter System (Diverter Schematic attached to program). x NU 16-3/4” 3M x 21-1/4” 2M DSA on 16-3/4” 3M wellhead. x NU 21-1/4” diverter “T”. x Knife gate, 16” diverter line. x Ensure diverter RU complies with AOGCC reg 20.AAC.25.035(C). x Diverter line must be 75 feet from nearest ignition source x Place drip berm at the end of diverter line. 10.2 Notify AOGCC. Function test diverter. Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens prior to annular closure. 10.3 Ensure to set up a clearly marked “warning zone” is established on each side and ahead of the vent line tip. “Warning Zone” must include: x A prohibition on vehicle parking x A prohibition on ignition sources or running equipment x A prohibition on staged equipment or materials x Restriction of traffic to essential foot or vehicle traffic only. Page 12 Milne Point Unit L-63 Kuparuk Injector Drilling Procedure 10.4 Rig & Diverter Orientation: x May change on location Page 13 Milne Point Unit L-63 Kuparuk Injector Drilling Procedure 11.0 Drill 12-1/4” Hole Section 11.1 PU 12-1/4” directional drilling assembly: x Ensure BHA components have been inspected previously. x Drift and caliper all components before MU. 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 Be sure to run a UBHO sub for wireline gyro x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. x Drill string will be 5”, 19.5#, S-135, NC50. x Run a solid float in the surface hole section. 11.2 Begin drilling out from 20” conductor at reduced flow rates to avoid broaching the conductor. x Consider using a trash bit to clean out conductor to mitigate potential damage from debris in conductor. 11.3 Drill 12-1/4” hole section to section TD below the lowermost Schrader oil bearing sand. Confirm this setting depth with the Geologist and Drilling Engineer while drilling the well. x Monitor the area around the conductor for any signs of broaching. If broaching is observed, Stop drilling (or circulating) immediately notify Drilling Engineer. x Efforts should be made to minimize dog legs in the surface hole. Keep DLS < 6°/ 100. x Hold a safety meeting with rig crews to discuss: x Conductor broaching ops and mitigation procedures. x Well control procedures and rig evacuation x Flow rates, hole cleaning, mud cooling, etc. x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Keep mud as cool as possible to keep from washing out permafrost. x Pump at 400-600 GPM. Monitor shakers closely to ensure shaker screens and return lines can handle the flow rate. x Ensure to not out drill hole cleaning capacity, perform clean up cycles or reduce ROP if packoffs, increase in pump pressure or changes in hookload are seen x Slow in/out of slips and while tripping to keep swab and surge pressures low x Ensure shakers are functioning properly. Check for holes in screens on connections. x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of pea gravel, clay balling or packing off. x Adjust MW and viscosity as necessary to maintain hole stability, ensure MW is at a 9.2 ppg minimum at TD (pending MW increase due to hydrates). x Perform wireline gyros until clean MWD surveys are seen. Take MWD surveys every stand drilled. x Gas hydrates have not been seen on L-Pad. However, be prepared for them. In MPU they have been encountered typically around 2,100-2,400’ TVD (just below permafrost). Be prepared for hydrates: Page 14 Milne Point Unit L-63 Kuparuk Injector Drilling Procedure x Gas hydrates can be identified by the gas detector and a decrease in MW or ECD x Monitor returns for hydrates, checking pressurized & non-pressurized scales x Do not stop to circulate out gas hydrates – this will only exacerbate the problem by washing out additional permafrost. Attempt to control drill (150 FPH MAX) through the zone completely and efficiently to mitigate the hydrate issue. Flowrates can also be reduced to prevent mud from belching over the bell nipple. Consider adding Lecithin to allow the gas to break out. x Gas hydrates are not a gas sand, once a hydrate is disturbed the gas will come out of the well. MW will not control gas hydrates, but will affect how gas breaks out at surface. x Surface Hole AC: x There are no wells with a clearance factor of <1.0 11.4 12-1/4” hole mud program summary: x Density: Weighting material to be used for the hole section will be barite. Additional barite or spike fluid will be on location to weight up the active system (1) ppg above highest anticipated MW. We will start with a simple gel + FW spud mud at 8.8 ppg and TD with 9.2+ ppg. Depth Interval MW (ppg) Surface – Base Permafrost 8.9+ Base Permafrost - TD 9.2+ (For Hydrates if need based on offset wells) MW can be cut once ~500’ below hydrate zone x PVT System: MD Totco PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s conso le, Co Man office, Toolpusher office, and mud loggers office. x Rheology: Aquagel and Barazan D+ should be used to maintain rheology. Begin system with a 75 YP but reduce this once clays are encountered. Maintain a minimum 25 YP at all times while drilling. Be prepared to increase the YP if hole cleaning becomes an issue. x Fluid Loss: DEXTRID and/or PAC L should be used for filtrate control. Background LCM (10 ppb total) BARACARBs/BAROFIBRE/STEELSEALs can be used in the system while drilling the surface interval to prevent losses and strengthen the wellbore. x Wellbore and mud stability: Additions of CON DET PRE-MIX/DRIL N SLIDE are recommended to reduce the incidence of bit balling and shaker blinding when penetrating the high-clay content sections of the Sagavanirktok and the heavy oil sections of the UGNU 4A. Maintain the pH in the 8.5 – 9.0 range with caustic soda. Daily additions of ALDACIDE G / X-CIDE 207 MUST be made to control bacterial action. x Casing Running: Reduce system YP with DESCO as required for running casing as allowed (do not jeopardize hole conditions). Run casing carefully to minimize surge and swab pressures. Reduce the system rheology once the casing is landed to a YP < 20 (check with the cementers to see what YP value they have targeted). Note: Only 6.0 ppg EMW expected in Kuparuk reservoir. DLB Page 15 Milne Point Unit L-63 Kuparuk Injector Drilling Procedure System Type: 8.8 – 9.2 ppg Pre-Hydrated Aquagel/freshwater spud mud Properties: Section Density Viscosity Plastic Viscosity Yield Point API FL pH Temp Surface 8.8 – 9.8 75-175 20 - 40 25-45 <10 8.5 – 9.0 70 F System Formulation: Gel + FW spud mud Product- Surface hole Size Pkg ppb or (% liquids) M-I Gel 50 lb sx 25 Soda Ash 50 lb sx 0.25 PolyPac Supreme UL 50 lb sx 0.08 Caustic Soda 50 lb sx 0.1 SCREENCLEEN 55 gal dm 0.5 11.5 At TD; PU 2-3 stands off bottom, CBU, pump tandem sweeps and drop viscosity. 11.6 RIH to bottom, proceed to BROOH to HWDP x Pump at full drill rate (400-600 GPM), and maximize rotation. x Pull slowly, 5 – 10 ft/minute, adjust as dictated by hole conditions x Monitor well for any signs of packing off or losses. x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay balling. x If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until parameters are restored. 11.7 TOOH and LD BHA 11.8 No open hole logging program planned. Note: 8.46 ppg MWE expected in surface hole. DLB Page 16 Milne Point Unit L-63 Kuparuk Injector Drilling Procedure 12.0 Run 9-5/8” Surface Casing 12.1 RU and pull wearbushing. 12.2 RU Weatherford 9-5/8” casing running equipment (CRT & Tongs) x Ensure 9-5/8” TXP x DS50 XO on rig floor and M/U to FOSV. x Use BOL 2000 thread compound. Dope pin end only w/ paint brush. x RU of CRT if hole conditions require. x RU a fill up tool to fill casing while running if the CRT is not used. x Ensure all casing has been drifted to 8.750” on the location prior to running. x Top 2000’ of casing from surface 47# drift 8.525” min x Be sure to count the total # of joints on the location before running. x Keep hole covered while RU casing tools. x Record OD’s, ID’s, lengths, and SN’s of all components with vendor & model info. 12.3 PU shoe joint, visually verify no debris inside joint. 12.4 Continue MU & thread locking 120’ shoe track assembly consisting of: 9-5/8” Float Shoe 1 joint – 9-5/8” TXP, 2 Centralizers 10’ from each end w/ stop rings 1 joint – 9-5/8” TXP, 1 Centralizer mid joint w/ stop ring 9-5/8” Float Collar with Stage Cementer Bypass Baffle ‘Top Hat’ 1 joint – 9-5/8” TXP, 1 Centralizer mid joint with stop ring 9-5/8” HES Baffle Adaptor x Ensure bypass baffle is correctly installed on top of float collar. x Ensure proper operation of float equipment while picking up. x Ensure to record SN’s of all float equipment and stage tool components. This end up. Bypass Baffle 2500' of 47# noted on schematic. Page 17 Milne Point Unit L-63 Kuparuk Injector Drilling Procedure 12.5 Float equipment and stage tool equipment drawings: Page 18 Milne Point Unit L-63 Kuparuk Injector Drilling Procedure 12.6 Continue running 9-5/8” surface casing x Fill casing while running using fill up line on rig floor. x Use BOL 2000 thread compound. Dope pin end only with paint brush. x Centralization: Verify depth of lowest Ugnu water sand for isolation with Geologist x Utilize a collar clamp until weight is sufficient to keep slips set properly. x Break circulation prior to reaching the base of the permafrost if casing run indicates poor hole conditions. x Any packing off while running casing should be treated as a major problem. It is preferable to POH with casing and condition hole than to risk not getting cement returns to surface. 12.7 Install the Halliburton Type H ES-II Stage tool so that it is positioned at least 100’ TVD below the permafrost (~ 2,500’ MD). x Install centralizers over couplings on 5 joints below and 5 joints above stage tool. x Do not place tongs on ES cementer, this can cause damaged to the tool. x Ensure tool is pinned with 6 opening shear pins. This will allow the tool to open at 3,300 psi. 9-5/8” 40# L-80 TXP Make-Up Torques: Casing OD Minimum Optimum Maximum 9-5/8” 18,860 ft-lbs 20,960 ft-lbs 23,060 ft-lbs 9-5/8” 47# L-80 TXP MUT: Casing OD Minimum Optimum Maximum 9-5/8” 21,440 ft-lbs 2,3820 ft-lbs 26,200 ft-lbs Depth Interval Centralization Shoe – 1000’ Above Shoe 1/joints 1000’ above Shoe – 2000’ above Shoe 1/ 2 joints Page 19 Milne Point Unit L-63 Kuparuk Injector Drilling Procedure Page 20 Milne Point Unit L-63 Kuparuk Injector Drilling Procedure 12.8 Continue running 9-5/8” surface casing x Fill casing while running using fill up line on rig floor. x Use BOL 2000 thread compound. Dope pin end only with paint brush. x Centralization: x 1 centralizer every 2 joints to base of conductor 12.9 The last 2000’ of 9-5/8” will be 47#, from 2000’ to Surface x Ensure drifted to 8.525” min 47# from surface to 2500' MD (on 10-401) Page 21 Milne Point Unit L-63 Kuparuk Injector Drilling Procedure 12.10 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 12.11 Slow in and out of slips. 12.12 PU landing joint and MU to casing string. Position the casing shoe ±10’ from TD. Strap the landing joint prior to the casing job and mark the joint at (1) ft intervals to use as a reference when getting the casing on depth. 12.13 Lower casing to setting depth. Confirm measurements. 12.14 Have slips staged in cellar, along with necessary equipment for the operation. 12.15 Circulate and condition mud through CRT. Reduce YP to < 20 to help ensure success of cement job. Ensure adequate amounts of cold MU water are available to achieve this. If possible reciprocate casing string while conditioning mud. Page 22 Milne Point Unit L-63 Kuparuk Injector Drilling Procedure 13.0 Cement 9-5/8” Surface Casing 13.1 Hold a pre-job safety meeting over the upcoming cement operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud & water can be delivered to the cementing unit at acceptable rates. x How to handle cement returns at surface. Ensure vac trucks are on standby and ready to assist. x Which pumps will be utilized for displacement and how fluid will be fed to displacement pump. x Ensure adequate amounts of water for mix fluid is heated and available in the water tanks. x Positions and expectations of personnel involved with the cementing operation. i. Extra hands in the pits to strap during the cement job to identify any losses x Review test reports and ensure pump times are acceptable. x Conduct visual inspection of all hard lines and connections used to route slurry to rig floor. 13.2 Document efficiency of all possible displacement pumps prior to cement job. 13.3 Flush through cement pump and treating iron from pump to rig floor to the shakers. This will help ensure any debris left in the cement pump or treating iron will not be pumped downhole. 13.4 RU cement line (if not already done so). Company Rep to witness loading of the top and bottom plugs to ensure done in correct order. 13.5 Fill surface cement lines with water and pressure test. 13.6 Pump remaining 60 bbls 10.5 ppg tuned spacer. 13.7 Drop bottom plug (flexible bypass plug) – HEC rep to witness. Mix and pump cement per below calculations for the 1st stage, confirm actual cement volumes with cementer after TD is reached. 13.8 Cement volume based on annular volume + 30% open hole excess. Job will consist of lead & tail, TOC brought to stage tool. Cement calcs based on stage tool est. placement at 2,500’ MD. Estimated 1st Stage Total Cement Volume: Cement Slurry Design (1st Stage Cement Job): Lead Slurry Tail Slurry Density 12.0 lb/gal 15.8 lb/gal Yield 2.35 ft3/sk 1.16 ft3/sk Mixed Water 13.92 gal/sk 4.98 gal/sk 394 sx 5070' 113.9 639 ft3 128 sx Page 23 Milne Point Unit L-63 Kuparuk Injector Drilling Procedure 13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Watch reciprocation PU and SO weights, if the hole gets “sticky”, cease pipe reciprocation and continue with the cement job. 13.9 After pumping cement, drop top plug (Shutoff plug) and displace cement with spud mud out of mud pits, spotting water across the HEC stage cementer. x Ensure volumes pumped and volumes returned are documented and constant communication between mud pits, HEC Rep and HES Cementers during the entire job. 13.10 Ensure rig pump is used to displace cement. To operate the stage tool hydraulically, the plug must be bumped. 13.11 Displacement calculation: 2,000’ x 0.0732 BPF + (5,823’ – 120’ - 2,000’) x .0758 BPF = 427 bbls 80 bbls of tuned spacer to be left behind stage tool 13.12 Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any point during the job. Be prepared to pump out fluid from cellar. Have black water available to contaminate any cement seen at surface. 13.13 If plug is not bumped at calculated strokes, double check volumes and calculations. Over displace by no more than 50% of shoe track volume, ±4.5 bbls before consulting with Drilling Engineer. 13.14 If plug is not bumped, consult with Drilling Engineer. Ensure the free fall stage tool opening plug is available if needed. This is the back-up option to open the stage tool if the plugs are not bumped. 13.15 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held, this is to ensure the stage tool is not prematurely opened. 13.16 Increase pressure to 3,300 psi to open circulating ports in stage collar. Slightly higher pressure may be necessary if TOC is above the stage tool. CBU and record any spacer or cement returns to surface and volume pumped to see the returns. Circulate until YP < 20 again in preparation for the 2 nd stage of the cement job. 13.17 Be prepared for cement returns to surface. Dump cement returns in the cellar or open the shaker bypass line to the cuttings tank. Have black water available and vac trucks ready to assist. Ensure to flush out any rig components, hard lines and BOP stack that may have come in contact with the cement. (.07321 * 2500) + ((5070 -120 - 2500) * .0758) = 368 bbls Page 24 Milne Point Unit L-63 Kuparuk Injector Drilling Procedure Second Stage Surface Cement Job: 13.18 Prepare for the 2nd stage as necessary. Circulate until first stage reaches sufficient compressive strength. Try to maintain flow rate through stage tool until 2nd stage is ready. Hold pre-job safety meeting. x Past wells have seen pressure increase while circulating through stage tool after reduced rate 13.19 HEC representative to witness the loading of the ES cementer closing plug in the cementing head. 13.20 Fill surface lines with water and pressure test. 13.21 Pump remaining 60 bbls of 10.5 ppg tuned spacer. 13.22 Mix and pump cement per below recipe for the 2nd stage. 13.23 Cement volume based on annular volume + open hole excess (200% for lead and 100% for tail). Job will consist of lead & tail, TOC brought to surface. However cement will continue to be pumped until clean spacer is observed at surface. Estimated 2nd Stage Total Cement Volume: Cement Slurry Design (2nd stage cement job): 13.24 Continue pumping lead until uncontaminated spacer is seen at surface, then switch to tail. 13.25 After pumping cement, drop ES Cementer closing plug and displace cement with spud mud out of mud pits. 13.26 Displacement calculation: (2,500’ – 2,000’) x 0.0758 BPF + 2,000’ x 0.0732 = 184.3 bbls mud Lead Slurry Tail Slurry System Permafrost L Density 10.7 lb/gal 15.8 lb/gal Yield 4.41 ft3/sk 1.17 ft3/sk Mixed Water 22.02 gal/sk 5.08 gal/sk 71 sx 439 sx 2,500 183 bbls Page 25 Milne Point Unit L-63 Kuparuk Injector Drilling Procedure 13.27 Monitor returns closely while displacing cement. Adjust pump rate if necessary. Wellhead side outlet valve in cellar can be opened to take returns to cellar if required. Be prepared to pump out fluid from cellar. Have black water available to retard setting of cement. 13.28 Decide ahead of time what will be done with cement returns once they are at surface. We should circulate approximately 100 - 150 bbls of cement slurry to surface. 13.29 Land closing plug on stage collar and pressure up to 1,000 – 1,500 psi to ensure stage tool closes. Follow instructions of Halliburton personnel. Bleed off pressure and check to ensure stage tool has closed. Slips will be set as per plan to allow full annulus for returns during surface cement job. Set slips 13.30 Make initial cut on 9-5/8” final joint. LD cut joint. Make final cut on 9-5/8”. Dress off stump. Install 9-5/8” wellhead. If transition nipple is welded on, allow to cool as per schedule. 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 if pre flush or cement returns at surface & volume 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 and cdinger@hilcorp.com This will be included with the EOW documentation that goes to the AOGCC. Page 26 Milne Point Unit L-63 Kuparuk Injector Drilling Procedure 14.0 ND Diverter, NU BOPE, & Test 14.1 ND the diverter T, knife gate, diverter line & NU 11” x 13-5/8” 5M casing spool. 14.2 NU 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 NU 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 14.3 RU MPD RCD and related equipment. 14.4 Run 5” BOP test plug. 14.5 Test BOP to 250/3,000 psi for 5/5 min. Test annular to 250/2,500 psi for 5/5 min. x Test VBR’s with 3-1/2”, 5”, and 7” test joints (smallest and largest sized tubular, excluding BHA, to be run during that test cycle per AOGCC 20 AAC 25.035) 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 14.6 RD BOP test equipment 14.7 Dump and clean mud pits, send spud mud to G&I pad for injection. 14.8 Mix 9.5 ppg LSND fluid for production hole. 14.9 Set wearbushing in wellhead. 14.10 If needed, rack back as much 5” DP in derrick as possible to be used while drilling the hole section. 14.11 Ensure 6-1/4” liners in mud pumps. Page 27 Milne Point Unit L-63 Kuparuk Injector Drilling Procedure 15.0 Drill 8-1/2” x 9-7/8" Hole Section 15.1 MU 8-1/2” Cleanout BHA (Milltooth Bit & 1.22° PDM). x Decision may be made to drill out with RSS. If so MU, RSS BHA 15.2 TIH with 8-1/2” cleanout BHA to stage tool. Note depth TOC tagged on AM report. Drill out stage tool. 15.3 TIH to TOC above the baffle adapter. Note depth TOC tagged on morning report. 15.4 RU and PT casing to 2,500 psi for 30 minutes charted. Ensure to record volume / pressure (every ¼ bbl) and plot on FIT graph. AOGCC reg is 50% of burst = 5,750 / 2 = ~2,875 psi, but max test pressure on the well is 2,500 psi as per AOGCC. Document incremental volume pumped (and subsequent pressure) and volume returned. Ensure rams are used to test casing as per AOGCC Industry Guidance Bulletin 17-001. 15.5 Drill out shoe track and 20’ of new formation. 15.6 CBU and condition mud for FIT. 15.7 Conduct FIT to 12.0 ppg EMW. Chart Test. Ensure test is recorded on same chart as FIT. Document incremental volume pumped (and subsequent pressure) and volume returned. 15.8 POOH and LD Cleanout BHA. 15.9 PU 8-1/2” x 9-7/8” 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 RSS to have at bit Gamma for calling TD x Ensure MWD is R/U and operational. x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. x Drill pipe will be 5” 19.5# S -135, NC50 x Run x2 Solid Plunger Floats for MPD 15.10 8-1/2” x 9-7/8” hole section mud program summary: x Density: Weighting material to be used for the hole section will be calcium carbonate. Additional calcium carbonate will be on location to weight up the active system (1) ppg above highest anticipated MW. x Inhibition: 3% KCl will be used for handling clay cuttings. Watch MBT levels, dilute as necessary to maintain. Increase KCl % if necessary. FIT and casing test digital data to AOGCC. Page 28 Milne Point Unit L-63 Kuparuk Injector Drilling Procedure x Run the centrifuge continuously while drilling the production hole, this will help with solids removal. x Dump and dilute as necessary to keep drilled solids to an absolute minimum. x MD Totco PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, & Toolpusher office. System Type: 9.0– 10.8 ppg LSND WBM Properties: Interval Density PV YP LGS MBT HPHT pH Production 9.0-10.8 15-25 15 - 20 <6% <20 <11.0 9-10 15.11 TIH with 8-1/2” x 9-7/8” directional assembly to bottom. 15.12 Displace wellbore to 9.5ppg LSND. 15.14 Drill 8-1/2” x 9-7/8” hole section to 300’ above THRZ. x Ensure AnderReamer is clear of the shoe. Follow NOV procedure to activate AnderReamer and begin drilling. x Flow Rate: 525-574 GPM, target min. AV’s 200 FPM x RPM: 120-180 x Ensure shaker screens are set up to handle this flowrate. Ensure shakers are running slightly wet to maximize solids removal efficiency. Check for holes in screens on every connection. x Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low x Target ECD: 11.0ppg with a max of 11.3 ppg EMW x Take MWD surveys every stand. x Monitor Torque and Drag with pumps on every 5 stands x Monitor ECD, pump pressure & hookload trends for hole cleaning indication x Surveys can be taken more frequently if deemed necessary. x Good drilling and tripping practices are vital for avoidance of differential sticking. Make every effort to keep the drill string moving whenever possible and avoid stopping with the BHA across the sand for any extended period of time. x Limit maximum instantaneous ROP to < 300 FPH. x Target ROP is as fast as we can clean the hole without having to backream connections and maintain ECD’s at or below 11.3ppg x MPD will be utilized to monitor pressure build up on connections. x Production Hole A/C: x No wells have a clearance factor <1.0 12.17 CBU x2, perform short trip to shoe if necessary Note: Only 6.0 ppg MWE anticipated in Kuparuk production section. DLB Page 29 Milne Point Unit L-63 Kuparuk Injector Drilling Procedure x RPM: 120+ x Flow Rate: 525-574 GPM (200 ft/min Annular Velocity) x Alternate reciprocation depths to avoid troughing/ledging 12.18 Increase black products for shale stability. MW will remain at 9.5 ppg. If there is a need to change the density, discuss with drilling engineer. x If needed, increase MW with pre sheared spike fluid, in 0.3 ppg per circulation, this is to ensure no barite sag or uneven density 12.19 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 12.20 Drill 8-1/2” x 9-7/8” hole section to section TD per Geologist and Drilling Engineer. x Target ECD: 11.0ppg with max of 11.3 ppg EMW x Utilize MPD to maintain CBHP (constant bottom hole pressure) at the HRZ 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 losses on connections, reduce annular pressure if needed. x Pump tandem high visc high weight / low visc low weight sweeps to aid in hole cleaning, monitor ECD effect of sweeps x Take MWD surveys every stand x Monitor hole cleaning indicators: PUW, pump pressure and ECD. Backream connections if necessary x Ensure good communication with Geologist to call TD. x Ensure we can get perf guns to depth without drilling up the shoetrack. We can run a shortened shoetrack if necessary. 15.15 At TD, follow NOV procedure to drop ball to lock the AnderReamer closed and CBU at least 2 times at 200 ft/min AV and rotation (120+ RPM). Pump tandem sweeps if needed. x Monitor BU for increase in cuttings. Circulate more if necessary. 15.16 Weight up at TD for shale stability, ±10.5 ppg, maintaining maximum ECD of 11.3 ppg EMW x Perform weight up with pre-sheared spike fluid, weighting up with 0.3 ppg increments 15.17 Observe well for flow 15.18 TOOH while spotting casing running pill from TD to THRZ x 12ppb black product, graphite, 4% lube 15.19 TOOH with the drilling assembly t/ 9-5/8” Shoe, Offsetting Swab with MPD x Follow tripping schedule, matching string speed and annular pressure Page 30 Milne Point Unit L-63 Kuparuk Injector Drilling Procedure x Rack back DP while TOOH, Do not lay down drill pipe. This is to minimize open hole time before casing is on bottom. 15.20 If backreaming is necessary: x Circulate at max rate while maintaining drilling ECD’s (flow will be less due to 10.5 ppg MW) 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 shoe and circ at least a b/u once at the shoe. 15.21 CBU x2 at the shoe 15.22 Continue TOOH to HWDP/ BHA, offsetting swab with MPD 15.23 Pull RCD Bearing element 15.24 LD BHA Page 31 Milne Point Unit L-63 Kuparuk Injector Drilling Procedure 16.0 Run and Cement 7” Casing 16.1 Confirm VBR’s have been tested on 7” test joint to 250/3,000 psi. 16.2 Dummy run 7” hanger and check packoff to verify fit 16.3 R/U 7” casing running equipment. x Ensure 7” TXP (BTC Compatible) x NC50 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. x R/U CRT w/ cement swivel. 16.4 M/U & threadlock shoe track assy consisting of: x (1) Float shoe joint w/ float shoe bucked on. Install (2) centralizers over a stop ring at 10’ from each end. x (1) Baker locked joint. Install (1) centralizer mid joint over a stop ring x (1) Float collar joint w/ float collar bucked on pin end. Install (1) centralizer mid tube over a stop ring. x Ensure proper operation of float shoe and float collar. 16.5 Run 7” 26# L-80 TXP casing. x Fill casing while running using CRT or fill up line. x Use “BOL 2000” thread compound. Dope pin end only w/ paint brush. x Utilize a collar clamp until weight is sufficient to keep slips set properly. x Install centralizers on every joint to planned TOC (500’ above TKUP) 16.6 RIH following casing running schedule, keeping surge below max drilling ECD EMW x Circulate BU at shoe & ~ 300’ above HRZ to ensure mud is conditioned prior to RIH x Model circulation rates and do not exceed 11.3 ppg EMW ECD. This is both for losses at the Kuparuk and shale stability x Do not circulate from THRZ until casing is at TD 16.7 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. Slow in and out of slips. 16.8 Lower string to depth. MU hanger and landing joint. Casing will be set on depth with hanger. 16.9 Circulate and condition mud for cement job through CRT. Reduce the density to 9.5ppg and the YP to < 20 to help ensure success of cement job. Stage pumps up slowly starting at 1 bpm. Stage up in 0.5 to 1.0 bpm increments to cementing rate and circulate at least 1.5X BU prior to cementing. Page 32 Milne Point Unit L-63 Kuparuk Injector Drilling Procedure 16.10 After circulating, set string at setting depth. 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 33 Milne Point Unit L-63 Kuparuk Injector Drilling Procedure Page 34 Milne Point Unit L-63 Kuparuk Injector Drilling Procedure 16.11 Hold a pre-job safety meeting over the upcoming cement operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. x How to handle cement returns at surface (highly unlikely unless we have to circulate the cement completely out) x Which pump will be utilized for displacement and how fluid will be fed to displacement pump. x Positions and expectations of personnel involved with the cement operation. x Extra hands in the pits to strap during the cement job to identify any losses x Document efficiency of all possible displacement pumps prior to cement job. 16.12 7” cement job will be a single stage, single slurry job. 16.13 RU Cement lines to cement swivel on CRT. Plugs will be dropped manually. 16.14 Pump 5 bbls fresh water. Pressure test surface cement lines to 4000 psi. 16.15 Pump 11.5 ppg tuned spacer per Halliburton. 16.16 Drop bottom plug, Mix and pump slurry per below calculations, 40% OH excess volume: 13.11 Cement volume based on annular volume + 50% open hole excess. Slurry Information Cement Slurry System G Density 14.0 lb/gal Yield 1.52 ft3/sk Mixed Water 7.74 gal/sk Section: Calculation: Vol (bbls) Vol (ft3) 9.875" OH x 7” Casing: (9117’-150’– 8695’+500’) x 0.0471 bpf 36.4 204.1 8.5” OH x 7” Casing 150’ x 0.0226 bpf 3.4 19.0 OH Excess (36.4 + 3.4) x 0.4 15.9 89.2 7” Shoe Track: 80’ x 0.038 bpf 3.1 17.2 Total Volume: 58.7 330 38.3 9159' 93.6 214.8 345.3 38.3 61.5 16.7 227 sx Page 35 Milne Point Unit L-63 Kuparuk Injector Drilling Procedure 16.17 After pumping cement, drop top plug and displace cement with 9.5ppg clean brine. Use rig pumps for displacement. Ensure to have a good baseline measurement for pump displacement ahead of time. Displacement calcs: x Pump the job per Halliburton’s pump schedule x Displacement: 9,037’ x 0.0383 bpf = 345.8 bbls 16.18 Reciprocate casing during cement job. If pipe movement gets sticky, land casing hanger. 16.19 Monitor returns closely while displacing cement. Ensure pits are strapped every 10 bbls of displacement and communicated with Co Rep. If losses are seen, let DSM know and possibly reduce pump rate. 16.20 Do not over displace by more than ½ shoe track volume. 16.21 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement develops 100 psi compressive strength. x If this is the case, monitor the pressure on the casing and do not let it exceed 500 psi over the final pump pressure. 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 Returns details (percentages, variations in percentages including timing). Final circulating pressure x Note if pre flush or cement returns at surface & volume 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 and cdinger@hilcorp.com. This will be included with the EOW documentation that goes to the AOGCC. 16.22 R/D cementing equipment. Flush out wellhead with FW. 16.23 Test void to 250/4000 psi for 10 min. 16.24 After cement has developed 500 psi compressive strength, freeze protect 9-5/8” x 7” annulus 16.25 Lay down 5” DP. There are no plans to make a cleanout run so long as the plug bumped. (9159'-80') * 0.0383 = 347.7 bbls Page 36 Milne Point Unit L-63 Kuparuk Injector Drilling Procedure 17.0 E-line: GR/CCL/CBL, Perf Guns 17.1 RU E-line. PU and MU CBL/GR/CCL tool string. RIH, tag TOC/PBTD and POOH logging CBL/GR/CCL (use open hole MWD log for correlation). x Ensure TOC logged at least 500’ above TKUP. x Communicate CBL results to drilling engineer and ops engineer. 17.2 MU perf gun assembly to be conveyed on e-line (gun length will be determined by Geo & Ops Engineer after drilling the reservoir). 17.3 TIH with perf guns. Correlate and perforate per Hilcorp geologist, OE, and Halliburton. 17.4 POOH and RD E-line per Halliburton. CBL to AOGCC. Page 37 Milne Point Unit L-63 Kuparuk Injector Drilling Procedure 18.0 Run 3-1/2” Tubing (Upper Completion) 18.1 Notify the AOGCC at least 24 hours in advance of the IA pressure test after running the completion as per 20 AAC 25.412 (e). Record pressure test on 10-426 form and email to wrivard@hilcorp.com for submission to AOGCC. 18.2 M/U injection assembly and RIH to setting depth. TIH no faster than 90 ft/min. x Ensure wear bushing is pulled. x Ensure 3-½” EUE 8RD 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. 3-1/2” 9.3# L-80 EUE 8RD Casing OD Minimum Optimum Maximum Operating Torque 3.5” 2,350 ft-lbs 3,130 ft-lbs 3,910 ft-lbs Verify running order with Ops Engineer. Nom. Size Item Lb/ft Notes 3.5” WLEG 9.3 Baker-Lock 3.5” 15' Pup Joint 9.3 Baker-Lock 3.5” “XN” nipple, 3.813” 9.3 Baker-Lock, with RHC plug 3.5” 15' Pup Joint 9.3 Baker-Lock 3.5” 40’ Joint 9.3 Baker-Lock 3.5” 15' Pup Joint 9.3 Baker-Lock 7” x 3.5” Production Packer 9.3 Baker-Lock 3.5” 15’ Pup Joint 9.3 3.5” 40’ Joint 9.3 Baker-Lock 3.5” 15' Pup Joint 9.3 3.5” “X” nipple, 3.813” ID 9.3 3.5” 15’ Pup Joint 9.3 3.5” 40’ Joints as needed 9.3 13” x 3.5” Tubing Hanger 18.3 Space out the completion. Place all space out pups below the first full joint of the completion. Page 38 Milne Point Unit L-63 Kuparuk Injector Drilling Procedure 18.4 Makeup the tubing hanger and landing joint. 18.5 Reverse circulate the well with brine and 1% corrosion inhibitor. 18.6 Freeze protect the tubing and IA to ~2500’ MD with diesel. 18.7 Land hanger. RILDs and test hanger. 18.8 Set the production packer. 18.9 Pressure test the tubing to 2500 psi for 30 charted minutes. 18.10 Pressure test the annulus to 2500 psi for 30 charted minutes. i. Note this test must be witnessed by the AOGCC representative. 18.11 Set TWC. ND BOPE and NU adapter flange and tree. 18.12 Test tree to 5000 psi. 18.13 Secure the tree and cellar. 18.14 RDMO Doyon 14 The packer must be placed within 200 feet measured depth above the top of the perforations, unless AOGCC approves a different placement depth as the commission considers appropriate given the thickness and depth of the confining zone. Page 39 Milne Point Unit L-63 Kuparuk Injector Drilling Procedure 19.0 Doyon 14 Diverter Schematic Page 40 Milne Point Unit L-63 Kuparuk Injector Drilling Procedure 20.0 Doyon 14 BOP Schematic Page 41 Milne Point Unit L-63 Kuparuk Injector Drilling Procedure 21.0 Wellhead Schematic Page 42 Milne Point Unit L-63 Kuparuk Injector Drilling Procedure 22.0 Days Vs Depth Page 43 Milne Point Unit L-63 Kuparuk Injector Drilling Procedure 23.0 Formation Tops & Information Page 44 Milne Point Unit L-63 Kuparuk Injector Drilling Procedure L-Pad Data Sheet Formation Description 24.0 Anticipated Drilling Hazards 12-1/4” Hole Section: Lost Circulation 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. Gas Hydrates Gas hydrates have not been encountered on L-pad to date. Remember that hydrate gas behave differently from a gas sand. Additional fluid density will not prevent influx of gas hydrates, but can help control the breakout at surface. Once a gas hydrate has been disturbed the gas will come out of the hole. Drill Page 45 Milne Point Unit L-63 Kuparuk Injector Drilling Procedure through the hydrate section as quickly as possible while minimizing gas belching. Minimize circulation time while drilling through the hydrate zone. Excessive circulation will accelerate formation thawing which can increase the amount of hydrates released into the wellbore. Keep the mud circulation temperature as cold as possible. Weigh mud with both a pressurized and non-pressurized mud scale. The non-pressurized scale will reflect the actual mud cut weight. Add 1.0 – 2.0 ppb Lecithin to the system to help thin the mud and release the gas. Isolate/dump contaminated fluid to remove hydrates from the system. Hole Cleaning: Maintain rheology of mud system. Sweep hole with high viscosity sweeps as necessary. Optimize solids control equipment to maintain density, sand content, and reduce the waste stream. 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 hole. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Anti-Collison: Take directional surveys every stand, take additional surveys if necessary. Continuously monitor proximity to offset wellbores and record any close approaches on AM report. x There are no wells with a clearance factor <1.0 in the surface interval Wellbore stability (Permafrost, running sands and gravel, conductor broaching): Washouts in the permafrost can be severe if the string is left circulating across it for extended periods of time. Keep mud as cool as possible by taking on cold water and diluting often. High TOH and RIH speeds can aggravate fragile shale/coal formations due to the pressure variations between surge and swab. Bring the pumps on slowly after connections. Monitor conductor for any signs of broaching. Maintain mud parameters and increase MW to combat running sands and gravel formations. H2S: Treat every hole section as though it has the potential for H2S. No H2S events have been documented on drill wells on this pad. 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 46 Milne Point Unit L-63 Kuparuk Injector Drilling Procedure 8-1/2” x 9-7/8” Hole Section: 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 ECD’s to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPM ’s 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 of >550 gpm Lost Circulation: 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. The Kuparuk fracture gradient is predicted to be 11.4ppg. Faulting: There are no planned fault crossings. H2S: Treat every hole section as though it has the potential for H2S. No H2S events have been documented on drill wells on this pad. 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. Abnormal Pressures and Temperatures: Reservoir pressures are expected to be subnormal. Abnormal pressures are possible but highly unlikely. Anti-Collision Take directional surveys every stand, take additional surveys if necessary. Continuously monitor drilling parameters for signs of magnetic interference with another well. Reference A/C report in directional plan. Well Specific: x There are no wells with a clearance facter <1 for the production hole. Page 47 Milne Point Unit L-63 Kuparuk Injector Drilling Procedure 25.0 Doyon 14 Layout Page 48 Milne Point Unit L-63 Kuparuk Injector Drilling Procedure 26.0 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. Ensure that casing test and subsequent FIT tests are recorded on the same chart. Document incremental volume pumped and returned during test. Page 49 Milne Point Unit L-63 Kuparuk Injector Drilling Procedure 27.0 Doyon 14 Choke Manifold Schematic Page 50 Milne Point Unit L-63 Kuparuk Injector Drilling Procedure 28.0 Casing Design Page 51 Milne Point Unit L-63 Kuparuk Injector Drilling Procedure 29.0 8-1/2” x 9-7/8” Hole Section MASP Page 52 Milne Point Unit L-63 Kuparuk Injector Drilling Procedure 30.0 Spider Plot (NAD 27) (Governmental Sections) Page 53 Milne Point Unit L-63 Kuparuk Injector Drilling Procedure 31.0 Surface Plat (As Staked) (NAD 27) 04 August, 2020 Plan: MPU L-63 wp02a Milne Point M Pt L Pad Plan: MPU L-63 MPU L-63 -750 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250True Vertical Depth (1500 usft/in)-750 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 Vertical Section at 16.40° (1500 usft/in) MPF-97 Mouse Trap wp05 tgt1 13 3/8" x 17 1/2" 9 5/8" x 12 1/4" 7" x 8 1/2" 5 0 0 1 0 0 0 1 5 0 0 2000250030003500400045005000550060006500700075008 0 0 08 5 0 0 9 0 0 0 9 1 5 9 MPU L-63 wp02a Start Dir 3º/100' : 250' MD, 250'TVD Start Dir 4º/100' : 475' MD, 474.48'TVD End Dir : 1075' MD, 1039.06' TVD Start Dir 4º/100' : 1875' MD, 1728.06'TVD End Dir : 2197.39' MD, 1987.96' TVD Start Dir 4º/100' : 7751.82' MD, 6121.65'TVD End Dir : 8299.53' MD, 6588.5' TVD Total Depth : 9158.99' MD, 7396.12' TVD SV6 BPRF UG4 LA3 SB_NA SB_NB SB_OA SB_OB Colville HRZ KLB KLGM KUP_D KUP_C KUP_B7 KUP_A3 KUP_A2 KUP_A1 KUP_A_BASE Hilcorp Alaska, LLC Calculation Method:Minimum Curvature Error System:ISCWSA Scan Method: Closest Approach 3D Error Surface: Ellipsoid Separation Warning Method: Error Ratio WELL DETAILS: Plan: MPU L-63 15.50 +N/-S +E/-W Northing Easting Latittude Longitude 0.00 0.00 6031888.82 544797.93 70° 29' 52.766 N 149° 38' 1.142 W SURVEY PROGRAM Date: 2020-07-30T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 33.70 800.00 MPU L-63 wp02a (MPU L-63) 3_Gyro-GC_Csg 800.00 5840.88 MPU L-63 wp02a (MPU L-63) 3_MWD+IFR2+MS+Sag 5840.88 9158.99 MPU L-63 wp02a (MPU L-63) 3_MWD+IFR2+MS+Sag FORMATION TOP DETAILS TVDPath TVDssPath MDPath Formation 984.88 935.68 1012.87 SV6 1849.20 1800.00 2019.51 BPRF 2445.93 2396.73 2812.77 UG4 3567.56 3518.36 4319.90 LA3 4124.44 4075.24 5068.18 SB_NA 4150.33 4101.13 5102.96 SB_NB 4274.36 4225.16 5269.62 SB_OA 4375.03 4325.83 5404.89 SB_OB 4712.37 4663.17 5858.18 Colville 6660.53 6611.33 8376.19 HRZ 6758.18 6708.98 8480.10 KLB 6831.68 6782.48 8558.32 KLGM 7006.63 6957.43 8744.50 KUP_D 7096.85 7047.65 8840.51 KUP_C 7108.19 7058.99 8852.58 KUP_B7 7192.08 7142.88 8941.85 KUP_A3 7210.25 7161.05 8961.19 KUP_A2 7236.73 7187.53 8989.36 KUP_A1 7284.02 7234.82 9039.69 KUP_A_BASE REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Plan: MPU L-63, True North Vertical (TVD) Reference:WELL @ 49.20usft (Original Well Elev) Measured Depth Reference:WELL @ 49.20usft (Original Well Elev) Calculation Method:Minimum Curvature Project:Milne Point Site:M Pt L Pad Well:Plan: MPU L-63 Wellbore:MPU L-63 Design:MPU L-63 wp02a CASING DETAILS TVD TVDSS MD Size Name 114.00 64.80 114.00 13-3/8 13 3/8" x 17 1/2" 4699.50 4650.30 5840.88 9-5/8 9 5/8" x 12 1/4" 7396.13 7346.93 9158.99 7 7" x 8 1/2" SECTION DETAILS Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation 1 33.70 0.00 0.00 33.70 0.00 0.00 0.00 0.00 0.00 2 250.00 0.00 0.00 250.00 0.00 0.00 0.00 0.00 0.00 Start Dir 3º/100' : 250' MD, 250'TVD 3 475.00 6.75 20.00 474.48 12.44 4.53 3.00 20.00 13.21 Start Dir 4º/100' : 475' MD, 474.48'TVD 4 1075.00 30.54 7.25 1039.06 199.55 36.30 4.00 -16.00 201.68 End Dir : 1075' MD, 1039.06' TVD 5 1875.00 30.54 7.25 1728.06 602.83 87.64 0.00 0.00 603.04 Start Dir 4º/100' : 1875' MD, 1728.06'TVD 6 2197.39 41.91 17.68 1987.96 787.45 130.88 4.00 32.81 792.35 End Dir : 2197.39' MD, 1987.96' TVD 7 7751.82 41.91 17.68 6121.65 4322.14 1257.92 0.00 0.00 4501.45 Start Dir 4º/100' : 7751.82' MD, 6121.65'TVD 8 8299.53 20.00 17.84 6588.50 4588.83 1343.22 4.00 179.86 4781.38 End Dir : 8299.53' MD, 6588.5' TVD 9 8908.99 20.00 17.84 7161.20 4787.25 1407.08 0.00 0.00 4989.76 MPF-97 Mouse Trap wp05 tgt1 10 9158.99 20.00 17.84 7396.12 4868.65 1433.28 0.00 0.00 5075.24 Total Depth : 9158.99' MD, 7396.12' TVD 0 300 600 900 1200 1500 1800 2100 2400 2700 3000 3300 3600 3900 4200 4500 4800 South(-)/North(+) (600 usft/in)-1200 -900 -600 -300 0 300 600 900 1200 1500 1800 2100 2400 2700 West(-)/East(+) (600 usft/in) MPF-97 Mouse Trap wp05 tgt1 13 3/8" x 17 1/2" 9 5/8" x 12 1/4" 7" x 8 1/2" 750 1000 1250 1500 1750 2000 2250 2500 2750 3000 3250 3500 3750 4000 4250 4500 4750 5000 5250 5500 5750 6000 6250 6500 7000 7396 MPU L-63 wp02a Start Dir 3º/100' : 250' MD, 250'TVD Start Dir 4º/100' : 475' MD, 474.48'TVD End Dir : 1075' MD, 1039.06' TVD End Dir : 2197.39' MD, 1987.96' TVD Start Dir 4º/100' : 7751.82' MD, 6121.65'TVD End Dir : 8299.53' MD, 6588.5' TVD Total Depth : 9158.99' MD, 7396.12' TVD CASING DETAILS TVD TVDSS MD Size Name 114.00 64.80 114.00 13-3/8 13 3/8" x 17 1/2" 4699.50 4650.30 5840.88 9-5/8 9 5/8" x 12 1/4" 7396.13 7346.93 9158.99 7 7" x 8 1/2" Project: Milne Point Site: M Pt L Pad Well: Plan: MPU L-63 Wellbore: MPU L-63 Plan: MPU L-63 wp02a WELL DETAILS: Plan: MPU L-63 15.50 +N/-S +E/-W Northing Easting Latittude Longitude 0.00 0.00 6031888.82 544797.93 70° 29' 52.766 N 149° 38' 1.142 W REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Plan: MPU L-63, True North Vertical (TVD) Reference:WELL @ 49.20usft (Original Well Elev) Measured Depth Reference:WELL @ 49.20usft (Original Well Elev) Calculation Method:Minimum Curvature Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt L Pad Halliburton Standard Proposal Report Well: Wellbore: Plan: MPU L-63 MPU L-63 Survey Calculation Method:Minimum Curvature WELL @ 49.20usft (Original Well Elev) Design:MPU L-63 wp02a Database:NORTH US + CANADA MD Reference:WELL @ 49.20usft (Original Well Elev) North Reference: Well Plan: MPU L-63 True Map System: Geo Datum: Project Map Zone: System Datum:US State Plane 1927 (Exact solution) NAD 1927 (NADCON CONUS) Milne Point, ACT, MILNE POINT Alaska Zone 04 Mean Sea Level Using Well Reference Point Using geodetic scale factor Site Position: From: Site Latitude: Longitude: Position Uncertainty: Northing: Easting: Grid Convergence: M Pt L Pad, TR-13-10 usft Map usft usft °0.34Slot Radius:"0 6,029,799.28 544,529.55 0.00 70° 29' 32.230 N 149° 38' 9.412 W Well Well Position Longitude: Latitude: Easting: Northing: usft +E/-W +N/-S Position Uncertainty usft usft usftGround Level: Plan: MPU L-63 usft usft 0.00 0.00 6,031,888.82 544,797.93 15.50Wellhead Elevation:usft0.50 70° 29' 52.766 N 149° 38' 1.142 W Wellbore Declination (°) Field Strength (nT) Sample Date Dip Angle (°) MPU L-63 Model NameMagnetics BGGM2020 10/30/2020 15.86 80.88 57,373.28518352 Phase:Version: Audit Notes: Design MPU L-63 wp02a PLAN Vertical Section: Depth From (TVD) (usft) +N/-S (usft) Direction (°) +E/-W (usft) Tie On Depth:33.70 16.400.000.0033.70 Inclination (°) Azimuth (°) +E/-W (usft) Tool Face (°) +N/-S (usft) Measured Depth (usft) Vertical Depth (usft) Dogleg Rate (°/100usft) Build Rate (°/100usft) Turn Rate (°/100usft) Plan Sections TVD System usft 0.000.000.000.000.000.0033.700.000.0033.70 -15.50 0.000.000.000.000.000.00250.000.000.00250.00 200.80 20.000.003.003.004.5312.44474.4820.006.75475.00 425.28 -16.00-2.123.974.0036.30199.551,039.067.2530.541,075.00 989.86 0.000.000.000.0087.64602.831,728.067.2530.541,875.00 1,678.86 32.813.243.534.00130.88787.451,987.9617.6841.912,197.39 1,938.76 0.000.000.000.001,257.924,322.146,121.6517.6841.917,751.82 6,072.45 179.860.03-4.004.001,343.224,588.836,588.5017.8420.008,299.53 6,539.30 0.000.000.000.001,407.084,787.257,161.2017.8420.008,908.99 7,112.00 0.000.000.000.001,433.284,868.657,396.1217.8420.009,158.99 7,346.92 8/4/2020 4:53:53PM COMPASS 5000.15 Build 91E Page 2 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt L Pad Halliburton Standard Proposal Report Well: Wellbore: Plan: MPU L-63 MPU L-63 Survey Calculation Method:Minimum Curvature WELL @ 49.20usft (Original Well Elev) Design:MPU L-63 wp02a Database:NORTH US + CANADA MD Reference:WELL @ 49.20usft (Original Well Elev) North Reference: Well Plan: MPU L-63 True Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Map Northing (usft) Map Easting (usft) +N/-S (usft) Planned Survey Vertical Depth (usft) TVDss usft DLS -15.50 Vert Section 33.70 0.00 33.70 0.00 0.000.00 544,797.936,031,888.82-15.50 0.00 0.00 100.00 0.00 100.00 0.00 0.000.00 544,797.936,031,888.8250.80 0.00 0.00 114.00 0.00 114.00 0.00 0.000.00 544,797.936,031,888.8264.80 0.00 0.00 13 3/8" x 17 1/2" 200.00 0.00 200.00 0.00 0.000.00 544,797.936,031,888.82150.80 0.00 0.00 250.00 0.00 250.00 0.00 0.000.00 544,797.936,031,888.82200.80 0.00 0.00 Start Dir 3º/100' : 250' MD, 250'TVD 300.00 1.50 299.99 0.61 0.2220.00 544,798.156,031,889.44250.79 3.00 0.65 400.00 4.50 399.85 5.53 2.0120.00 544,799.916,031,894.36350.65 3.00 5.88 475.00 6.75 474.48 12.44 4.5320.00 544,802.386,031,901.29425.28 3.00 13.21 Start Dir 4º/100' : 475' MD, 474.48'TVD 500.00 7.72 499.28 15.42 5.5517.95 544,803.386,031,904.27450.08 4.00 16.36 600.00 11.64 597.84 31.63 9.9113.16 544,807.656,031,920.51548.64 4.00 33.14 700.00 15.60 695.01 54.67 14.7310.77 544,812.326,031,943.57645.81 4.00 56.60 800.00 19.58 790.32 84.42 19.969.34 544,817.386,031,973.35741.12 4.00 86.62 900.00 23.56 883.30 120.74 25.598.37 544,822.796,032,009.70834.10 4.00 123.05 1,000.00 27.55 973.50 163.45 31.587.67 544,828.526,032,052.44924.30 4.00 165.71 1,012.87 28.06 984.88 169.40 32.387.59 544,829.296,032,058.39935.68 4.00 171.65 SV6 1,075.00 30.54 1,039.06 199.55 36.307.25 544,833.036,032,088.56989.86 4.00 201.68 End Dir : 1075' MD, 1039.06' TVD 1,100.00 30.54 1,060.59 212.15 37.917.25 544,834.566,032,101.171,011.39 0.00 214.22 1,200.00 30.54 1,146.71 262.56 44.337.25 544,840.676,032,151.621,097.51 0.00 264.39 1,300.00 30.54 1,232.84 312.97 50.747.25 544,846.786,032,202.061,183.64 0.00 314.56 1,400.00 30.54 1,318.97 363.38 57.167.25 544,852.896,032,252.501,269.77 0.00 364.73 1,500.00 30.54 1,405.09 413.79 63.587.25 544,859.016,032,302.951,355.89 0.00 414.90 1,600.00 30.54 1,491.22 464.20 69.997.25 544,865.126,032,353.391,442.02 0.00 465.07 1,700.00 30.54 1,577.34 514.61 76.417.25 544,871.236,032,403.831,528.14 0.00 515.24 1,800.00 30.54 1,663.47 565.02 82.837.25 544,877.346,032,454.271,614.27 0.00 565.41 1,875.00 30.54 1,728.06 602.83 87.647.25 544,881.936,032,492.111,678.86 0.00 603.04 Start Dir 4º/100' : 1875' MD, 1728.06'TVD 1,900.00 31.39 1,749.50 615.57 89.388.29 544,883.596,032,504.861,700.30 4.00 615.76 2,000.00 34.84 1,833.26 669.30 99.0812.00 544,892.976,032,558.641,784.06 4.00 670.04 2,019.51 35.52 1,849.20 680.28 101.4812.64 544,895.306,032,569.631,800.00 4.00 681.25 BPRF 2,100.00 38.39 1,913.52 727.24 113.1115.10 544,906.656,032,616.661,864.32 4.00 729.58 2,197.39 41.91 1,987.96 787.45 130.8817.68 544,924.046,032,676.961,938.76 4.00 792.35 End Dir : 2197.39' MD, 1987.96' TVD 2,200.00 41.91 1,989.90 789.11 131.4117.68 544,924.566,032,678.631,940.70 0.00 794.10 2,300.00 41.91 2,064.32 852.74 151.7017.68 544,944.476,032,742.382,015.12 0.00 860.87 2,400.00 41.91 2,138.74 916.38 171.9917.68 544,964.376,032,806.132,089.54 0.00 927.65 2,500.00 41.91 2,213.16 980.02 192.2817.68 544,984.286,032,869.882,163.96 0.00 994.43 2,600.00 41.91 2,287.59 1,043.66 212.5717.68 545,004.186,032,933.642,238.39 0.00 1,061.21 2,700.00 41.91 2,362.01 1,107.29 232.8617.68 545,024.096,032,997.392,312.81 0.00 1,127.98 2,800.00 41.91 2,436.43 1,170.93 253.1517.68 545,043.996,033,061.142,387.23 0.00 1,194.76 8/4/2020 4:53:53PM COMPASS 5000.15 Build 91E Page 3 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt L Pad Halliburton Standard Proposal Report Well: Wellbore: Plan: MPU L-63 MPU L-63 Survey Calculation Method:Minimum Curvature WELL @ 49.20usft (Original Well Elev) Design:MPU L-63 wp02a Database:NORTH US + CANADA MD Reference:WELL @ 49.20usft (Original Well Elev) North Reference: Well Plan: MPU L-63 True Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Map Northing (usft) Map Easting (usft) +N/-S (usft) Planned Survey Vertical Depth (usft) TVDss usft DLS 2,396.73 Vert Section 2,812.77 41.91 2,445.93 1,179.06 255.7417.68 545,046.546,033,069.282,396.73 0.00 1,203.29 UG4 2,900.00 41.91 2,510.85 1,234.57 273.4417.68 545,063.906,033,124.892,461.65 0.00 1,261.54 3,000.00 41.91 2,585.27 1,298.21 293.7317.68 545,083.806,033,188.652,536.07 0.00 1,328.31 3,100.00 41.91 2,659.69 1,361.84 314.0217.68 545,103.716,033,252.402,610.49 0.00 1,395.09 3,200.00 41.91 2,734.11 1,425.48 334.3117.68 545,123.616,033,316.152,684.91 0.00 1,461.87 3,300.00 41.91 2,808.54 1,489.12 354.6117.68 545,143.526,033,379.902,759.34 0.00 1,528.65 3,400.00 41.91 2,882.96 1,552.76 374.9017.68 545,163.426,033,443.652,833.76 0.00 1,595.42 3,500.00 41.91 2,957.38 1,616.39 395.1917.68 545,183.336,033,507.412,908.18 0.00 1,662.20 3,600.00 41.91 3,031.80 1,680.03 415.4817.68 545,203.236,033,571.162,982.60 0.00 1,728.98 3,700.00 41.91 3,106.22 1,743.67 435.7717.68 545,223.146,033,634.913,057.02 0.00 1,795.76 3,800.00 41.91 3,180.64 1,807.30 456.0617.68 545,243.046,033,698.663,131.44 0.00 1,862.53 3,900.00 41.91 3,255.07 1,870.94 476.3517.68 545,262.956,033,762.423,205.87 0.00 1,929.31 4,000.00 41.91 3,329.49 1,934.58 496.6417.68 545,282.856,033,826.173,280.29 0.00 1,996.09 4,100.00 41.91 3,403.91 1,998.22 516.9317.68 545,302.766,033,889.923,354.71 0.00 2,062.86 4,200.00 41.91 3,478.33 2,061.85 537.2217.68 545,322.666,033,953.673,429.13 0.00 2,129.64 4,300.00 41.91 3,552.75 2,125.49 557.5117.68 545,342.576,034,017.433,503.55 0.00 2,196.42 4,319.90 41.91 3,567.56 2,138.15 561.5517.68 545,346.536,034,030.113,518.36 0.00 2,209.71 LA3 4,400.00 41.91 3,627.17 2,189.13 577.8117.68 545,362.476,034,081.183,577.97 0.00 2,263.20 4,500.00 41.91 3,701.59 2,252.77 598.1017.68 545,382.386,034,144.933,652.39 0.00 2,329.97 4,600.00 41.91 3,776.02 2,316.40 618.3917.68 545,402.296,034,208.683,726.82 0.00 2,396.75 4,700.00 41.91 3,850.44 2,380.04 638.6817.68 545,422.196,034,272.433,801.24 0.00 2,463.53 4,800.00 41.91 3,924.86 2,443.68 658.9717.68 545,442.106,034,336.193,875.66 0.00 2,530.30 4,900.00 41.91 3,999.28 2,507.32 679.2617.68 545,462.006,034,399.943,950.08 0.00 2,597.08 5,000.00 41.91 4,073.70 2,570.95 699.5517.68 545,481.916,034,463.694,024.50 0.00 2,663.86 5,068.18 41.91 4,124.44 2,614.34 713.3817.68 545,495.486,034,507.154,075.24 0.00 2,709.39 SB_NA 5,100.00 41.91 4,148.12 2,634.59 719.8417.68 545,501.816,034,527.444,098.92 0.00 2,730.64 5,102.96 41.91 4,150.33 2,636.48 720.4417.68 545,502.406,034,529.334,101.13 0.00 2,732.62 SB_NB 5,200.00 41.91 4,222.55 2,698.23 740.1317.68 545,521.726,034,591.204,173.35 0.00 2,797.41 5,269.62 41.91 4,274.36 2,742.53 754.2617.68 545,535.576,034,635.584,225.16 0.00 2,843.91 SB_OA 5,300.00 41.91 4,296.97 2,761.87 760.4217.68 545,541.626,034,654.954,247.77 0.00 2,864.19 5,400.00 41.91 4,371.39 2,825.50 780.7117.68 545,561.536,034,718.704,322.19 0.00 2,930.97 5,404.89 41.91 4,375.03 2,828.62 781.7117.68 545,562.506,034,721.824,325.83 0.00 2,934.24 SB_OB 5,500.00 41.91 4,445.81 2,889.14 801.0117.68 545,581.436,034,782.454,396.61 0.00 2,997.75 5,600.00 41.91 4,520.23 2,952.78 821.3017.68 545,601.346,034,846.204,471.03 0.00 3,064.52 5,700.00 41.91 4,594.65 3,016.41 841.5917.68 545,621.246,034,909.964,545.45 0.00 3,131.30 5,800.00 41.91 4,669.07 3,080.05 861.8817.68 545,641.156,034,973.714,619.87 0.00 3,198.08 5,840.88 41.91 4,699.50 3,106.07 870.1717.68 545,649.286,034,999.774,650.30 0.00 3,225.38 9 5/8" x 12 1/4" 8/4/2020 4:53:53PM COMPASS 5000.15 Build 91E Page 4 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt L Pad Halliburton Standard Proposal Report Well: Wellbore: Plan: MPU L-63 MPU L-63 Survey Calculation Method:Minimum Curvature WELL @ 49.20usft (Original Well Elev) Design:MPU L-63 wp02a Database:NORTH US + CANADA MD Reference:WELL @ 49.20usft (Original Well Elev) North Reference: Well Plan: MPU L-63 True Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Map Northing (usft) Map Easting (usft) +N/-S (usft) Planned Survey Vertical Depth (usft) TVDss usft DLS 4,663.17 Vert Section 5,858.18 41.91 4,712.37 3,117.07 873.6817.68 545,652.736,035,010.804,663.17 0.00 3,236.93 Colville 5,900.00 41.91 4,743.50 3,143.69 882.1717.68 545,661.056,035,037.464,694.30 0.00 3,264.85 6,000.00 41.91 4,817.92 3,207.33 902.4617.68 545,680.966,035,101.214,768.72 0.00 3,331.63 6,100.00 41.91 4,892.34 3,270.96 922.7517.68 545,700.866,035,164.974,843.14 0.00 3,398.41 6,200.00 41.91 4,966.76 3,334.60 943.0417.68 545,720.776,035,228.724,917.56 0.00 3,465.19 6,300.00 41.91 5,041.18 3,398.24 963.3317.68 545,740.676,035,292.474,991.98 0.00 3,531.96 6,400.00 41.91 5,115.60 3,461.88 983.6217.68 545,760.586,035,356.225,066.40 0.00 3,598.74 6,500.00 41.91 5,190.03 3,525.51 1,003.9117.68 545,780.486,035,419.975,140.83 0.00 3,665.52 6,600.00 41.91 5,264.45 3,589.15 1,024.2117.68 545,800.396,035,483.735,215.25 0.00 3,732.30 6,700.00 41.91 5,338.87 3,652.79 1,044.5017.68 545,820.296,035,547.485,289.67 0.00 3,799.07 6,800.00 41.91 5,413.29 3,716.43 1,064.7917.68 545,840.206,035,611.235,364.09 0.00 3,865.85 6,900.00 41.91 5,487.71 3,780.06 1,085.0817.68 545,860.106,035,674.985,438.51 0.00 3,932.63 7,000.00 41.91 5,562.13 3,843.70 1,105.3717.68 545,880.016,035,738.745,512.93 0.00 3,999.40 7,100.00 41.91 5,636.55 3,907.34 1,125.6617.68 545,899.916,035,802.495,587.35 0.00 4,066.18 7,200.00 41.91 5,710.98 3,970.97 1,145.9517.68 545,919.826,035,866.245,661.78 0.00 4,132.96 7,300.00 41.91 5,785.40 4,034.61 1,166.2417.68 545,939.726,035,929.995,736.20 0.00 4,199.74 7,400.00 41.91 5,859.82 4,098.25 1,186.5317.68 545,959.636,035,993.755,810.62 0.00 4,266.51 7,500.00 41.91 5,934.24 4,161.89 1,206.8217.68 545,979.536,036,057.505,885.04 0.00 4,333.29 7,600.00 41.91 6,008.66 4,225.52 1,227.1117.68 545,999.446,036,121.255,959.46 0.00 4,400.07 7,700.00 41.91 6,083.08 4,289.16 1,247.4017.68 546,019.346,036,185.006,033.88 0.00 4,466.85 7,751.82 41.91 6,121.65 4,322.14 1,257.9217.68 546,029.666,036,218.046,072.45 0.00 4,501.45 Start Dir 4º/100' : 7751.82' MD, 6121.65'TVD 7,800.00 39.98 6,158.04 4,352.22 1,267.5117.69 546,039.076,036,248.176,108.84 4.00 4,533.01 7,900.00 35.98 6,236.85 4,410.83 1,286.2217.71 546,057.426,036,306.896,187.65 4.00 4,594.53 8,000.00 31.98 6,319.75 4,464.06 1,303.2317.73 546,074.106,036,360.226,270.55 4.00 4,650.39 8,100.00 27.98 6,406.35 4,511.65 1,318.4517.76 546,089.046,036,407.896,357.15 4.00 4,700.34 8,200.00 23.98 6,496.23 4,553.36 1,331.8217.79 546,102.166,036,449.676,447.03 4.00 4,744.13 8,299.53 20.00 6,588.50 4,588.83 1,343.2217.84 546,113.346,036,485.216,539.30 4.00 4,781.38 End Dir : 8299.53' MD, 6588.5' TVD 8,376.19 20.00 6,660.53 4,613.79 1,351.2617.84 546,121.226,036,510.226,611.33 0.00 4,807.59 HRZ 8,400.00 20.00 6,682.91 4,621.54 1,353.7517.84 546,123.676,036,517.986,633.71 0.00 4,815.73 8,480.10 20.00 6,758.18 4,647.62 1,362.1517.84 546,131.916,036,544.116,708.98 0.00 4,843.12 KLB 8,500.00 20.00 6,776.88 4,654.10 1,364.2317.84 546,133.956,036,550.606,727.68 0.00 4,849.92 8,558.32 20.00 6,831.68 4,673.09 1,370.3417.84 546,139.956,036,569.626,782.48 0.00 4,869.86 KLGM 8,600.00 20.00 6,870.85 4,686.66 1,374.7117.84 546,144.236,036,583.226,821.65 0.00 4,884.11 8,700.00 20.00 6,964.82 4,719.21 1,385.1917.84 546,154.516,036,615.836,915.62 0.00 4,918.30 8,744.50 20.00 7,006.63 4,733.70 1,389.8517.84 546,159.096,036,630.356,957.43 0.00 4,933.52 KUP_D 8,800.00 20.00 7,058.79 4,751.77 1,395.6617.84 546,164.806,036,648.457,009.59 0.00 4,952.49 8,840.51 20.00 7,096.85 4,764.96 1,399.9117.84 546,168.966,036,661.667,047.65 0.00 4,966.34 KUP_C 8/4/2020 4:53:53PM COMPASS 5000.15 Build 91E Page 5 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt L Pad Halliburton Standard Proposal Report Well: Wellbore: Plan: MPU L-63 MPU L-63 Survey Calculation Method:Minimum Curvature WELL @ 49.20usft (Original Well Elev) Design:MPU L-63 wp02a Database:NORTH US + CANADA MD Reference:WELL @ 49.20usft (Original Well Elev) North Reference: Well Plan: MPU L-63 True Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Map Northing (usft) Map Easting (usft) +N/-S (usft) Planned Survey Vertical Depth (usft) TVDss usft DLS 7,058.99 Vert Section 8,852.58 20.00 7,108.19 4,768.89 1,401.1717.84 546,170.206,036,665.607,058.99 0.00 4,970.47 KUP_B7 8,908.99 20.00 7,161.20 4,787.25 1,407.0817.84 546,176.006,036,684.007,112.00 0.00 4,989.76 8,941.85 20.00 7,192.08 4,797.95 1,410.5317.84 546,179.386,036,694.727,142.88 0.00 5,000.99 KUP_A3 8,961.19 20.00 7,210.25 4,804.25 1,412.5517.84 546,181.376,036,701.037,161.05 0.00 5,007.61 KUP_A2 8,989.36 20.00 7,236.73 4,813.42 1,415.5117.84 546,184.266,036,710.227,187.53 0.00 5,017.24 KUP_A1 9,000.00 20.00 7,246.72 4,816.89 1,416.6217.84 546,185.366,036,713.697,197.52 0.00 5,020.88 9,039.69 20.00 7,284.02 4,829.81 1,420.7817.84 546,189.446,036,726.637,234.82 0.00 5,034.45 KUP_A_BASE 9,100.00 20.00 7,340.69 4,849.44 1,427.1017.84 546,195.646,036,746.307,291.49 0.00 5,055.07 9,158.99 20.00 7,396.12 4,868.65 1,433.2817.84 546,201.706,036,765.547,346.92 0.00 5,075.24 Total Depth : 9158.99' MD, 7396.12' TVD Target Name - hit/miss target - Shape TVD (usft) Northing (usft) Easting (usft) +N/-S (usft) +E/-W (usft) Tar gets Dip Angle (°) Dip Dir. (°) MPF-97 Mouse Trap wp05 tgt1 7,161.20 6,036,684.00 546,176.004,787.25 1,407.080.00 0.00 -plan hits target center - Circle (radius 30.00) Vertical Depth (usft) Measured Depth (usft) Casing Diameter (") Hole Diameter (")Name Casing Points 13 3/8" x 17 1/2"114.00114.00 13-3/8 17-1/2 9 5/8" x 12 1/4"4,699.505,840.88 9-5/8 12-1/4 7" x 8 1/2"7,396.139,158.99 78-1/2 8/4/2020 4:53:53PM COMPASS 5000.15 Build 91E Page 6 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt L Pad Halliburton Standard Proposal Report Well: Wellbore: Plan: MPU L-63 MPU L-63 Survey Calculation Method:Minimum Curvature WELL @ 49.20usft (Original Well Elev) Design:MPU L-63 wp02a Database:NORTH US + CANADA MD Reference:WELL @ 49.20usft (Original Well Elev) North Reference: Well Plan: MPU L-63 True Measured Depth (usft) Vertical Depth (usft) Dip Direction (°)Name Lithology Dip (°) Formations Vertical Depth SS 8,852.58 7,108.19 KUP_B7 8,941.85 7,192.08 KUP_A3 4,319.90 3,567.56 LA3 8,376.19 6,660.53 HRZ 8,480.10 6,758.18 KLB 1,012.87 984.88 SV6 5,404.89 4,375.03 SB_OB 8,961.19 7,210.25 KUP_A2 5,858.18 4,712.37 Colville 5,269.62 4,274.36 SB_OA 8,558.32 6,831.68 KLGM 5,102.96 4,150.33 SB_NB 9,039.69 7,284.02 KUP_A_BASE 2,812.77 2,445.93 UG4 8,744.50 7,006.63 KUP_D 2,019.51 1,849.20 BPRF 5,068.18 4,124.44 SB_NA 8,840.51 7,096.85 KUP_C 8,989.36 7,236.73 KUP_A1 Measured Depth (usft) Vertical Depth (usft) +E/-W (usft) +N/-S (usft) Local Coordinates Comment Plan Annotations 250.00 250.00 0.00 0.00 Start Dir 3º/100' : 250' MD, 250'TVD 475.00 474.48 12.44 4.53 Start Dir 4º/100' : 475' MD, 474.48'TVD 1,075.00 1,039.06 199.55 36.30 End Dir : 1075' MD, 1039.06' TVD 1,875.00 1,728.06 602.83 87.64 Start Dir 4º/100' : 1875' MD, 1728.06'TVD 2,197.39 1,987.96 787.45 130.88 End Dir : 2197.39' MD, 1987.96' TVD 7,751.82 6,121.65 4,322.14 1,257.92 Start Dir 4º/100' : 7751.82' MD, 6121.65'TVD 8,299.53 6,588.50 4,588.83 1,343.22 End Dir : 8299.53' MD, 6588.5' TVD 9,158.99 7,396.12 4,868.65 1,433.28 Total Depth : 9158.99' MD, 7396.12' TVD 8/4/2020 4:53:53PM COMPASS 5000.15 Build 91E Page 7 04 August, 2020Milne PointM Pt L PadPlan: MPU L-63MPU L-63MPU L-63 wp02aReference Design: M Pt L Pad - Plan: MPU L-63 - MPU L-63 - MPU L-63 wp02aClosest Approach 3D Proximity Scan on Current Survey Data (North Reference)Well Coordinates: 6,031,888.82 N, 544,797.93 E (70° 29' 52.77" N, 149° 38' 01.14" W)Datum Height: WELL @ 49.20usft (Original Well Elev)Scan Range: 0.00 to 9,158.99 usft. Measured Depth.Geodetic Scale Factor AppliedVersion: 5000.15 Build: 91EScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftNO GLOBAL FILTER: Using user defined selection & filtering criteriaScan Type:Scan Type:25.00 Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU L-63 - MPU L-63 wp02aComparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftSite NameScan Range: 0.00 to 9,158.99 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (North Reference)Reference Design: M Pt L Pad - Plan: MPU L-63 - MPU L-63 - MPU L-63 wp02aMeasuredDepth(usft)Summary Based on MinimumSeparation WarningM Pt F PadPlan : MPU F-97 - MPU F-97 - MPU F-97 wp03724.80 8,300.00 637.79 8,018.97 8.3308,300.00Clearance Factor Pass - Plan : MPU F-97 - MPU F-97 - MPU F-97 wp03697.56 8,650.00 617.00 8,329.74 8.6598,650.00Ellipse Separation Pass - Plan : MPU F-97 - MPU F-97 - MPU F-97 wp03697.04 8,702.63 617.52 8,374.98 8.7668,702.63Centre Distance Pass - M Pt L PadMPL-05 - MPL-05 - MPL-05496.83 4,634.93 429.13 5,132.80 7.3384,634.93Centre Distance Pass - MPL-05 - MPL-05 - MPL-05498.48 4,725.00 427.79 5,206.70 7.0514,725.00Ellipse Separation Pass - MPL-05 - MPL-05 - MPL-05606.44 6,550.00 477.69 7,011.95 4.7106,550.00Clearance Factor Pass - MPL-14 - MPL-14 - MPL-14288.99 3,285.87 244.37 3,455.67 6.4773,285.87Ellipse Separation Pass - MPL-14 - MPL-14 - MPL-14289.04 3,300.00 244.38 3,468.44 6.4713,300.00Clearance Factor Pass - MPL-16 - MPL-16 - MPL-16117.82 263.01 115.08 266.30 43.059263.01Centre Distance Pass - MPL-16 - MPL-16 - MPL-16117.85 275.00 115.03 278.31 41.728275.00Ellipse Separation Pass - MPL-16 - MPL-16 - MPL-16378.35 2,150.00 354.65 2,195.94 15.9652,150.00Clearance Factor Pass - MPL-16 - MPL-16A - MPL-16A117.82 263.01 115.08 260.51 43.059263.01Centre Distance Pass - MPL-16 - MPL-16A - MPL-16A117.85 275.00 115.03 272.52 41.728275.00Ellipse Separation Pass - MPL-16 - MPL-16A - MPL-16A378.35 2,150.00 354.65 2,190.15 15.9652,150.00Clearance Factor Pass - MPL-17 - MPL-17 - MPL-1743.62 275.55 41.23 277.73 18.260275.55Ellipse Separation Pass - MPL-17 - MPL-17 - MPL-1751.45 450.00 48.03 450.73 15.042450.00Clearance Factor Pass - MPL-20 - MPL-20 - MPL-20109.84 255.98 107.15 256.92 40.875255.98Centre Distance Pass - MPL-20 - MPL-20 - MPL-20109.93 275.00 107.11 275.79 38.908275.00Ellipse Separation Pass - MPL-20 - MPL-20 - MPL-20146.31 600.00 140.98 591.12 27.434600.00Clearance Factor Pass - MPL-24 - MPL-24 - MPL-24110.56 260.35 107.74 263.15 39.113260.35Centre Distance Pass - MPL-24 - MPL-24 - MPL-24110.60 275.00 107.67 277.82 37.693275.00Ellipse Separation Pass - MPL-24 - MPL-24 - MPL-241,492.69 5,125.00 1,416.08 5,035.38 19.4855,125.00Clearance Factor Pass - MPL-25 - MPL-25 - MPL-2514.24 425.27 11.02 421.69 4.423425.27Ellipse Separation Pass - MPL-25 - MPL-25 - MPL-25197.80 3,575.00 122.48 3,784.77 2.6263,575.00Clearance Factor Pass - MPL-28 - MPL-28 - MPL-28116.59 296.25 113.50 298.32 37.700296.25Centre Distance Pass - MPL-28 - MPL-28 - MPL-28116.72 325.00 113.41 326.90 35.290325.00Ellipse Separation Pass - 04 August, 2020-16:55COMPASSPage 2 of 7 Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU L-63 - MPU L-63 wp02aComparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftSite NameScan Range: 0.00 to 9,158.99 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (North Reference)Reference Design: M Pt L Pad - Plan: MPU L-63 - MPU L-63 - MPU L-63 wp02aMeasuredDepth(usft)Summary Based on MinimumSeparation WarningMPL-28 - MPL-28 - MPL-28157.72 750.00 150.99 741.05 23.427750.00Clearance Factor Pass - MPL-28 - MPL-28A - MPL-28A116.59 296.25 113.50 298.32 37.700296.25Centre Distance Pass - MPL-28 - MPL-28A - MPL-28A116.72 325.00 113.41 326.90 35.290325.00Ellipse Separation Pass - MPL-28 - MPL-28A - MPL-28A157.72 750.00 150.99 741.05 23.427750.00Clearance Factor Pass - MPL-29 - MPL-29 - MPL-2926.65 632.75 22.02 633.73 5.755632.75Ellipse Separation Pass - MPL-29 - MPL-29 - MPL-2926.87 650.00 22.12 650.69 5.659650.00Clearance Factor Pass - MPL-32 - MPL-32 - MPL-32133.30 226.43 130.73 227.73 51.808226.43Centre Distance Pass - MPL-32 - MPL-32 - MPL-32133.42 275.00 130.49 275.91 45.678275.00Ellipse Separation Pass - MPL-32 - MPL-32 - MPL-32171.81 675.00 165.76 654.72 28.418675.00Clearance Factor Pass - MPL-33 - MPL-33 - MPL-3363.18 638.82 57.40 633.44 10.926638.82Centre Distance Pass - MPL-33 - MPL-33 - MPL-3363.23 650.00 57.35 644.13 10.755650.00Ellipse Separation Pass - MPL-33 - MPL-33 - MPL-3368.52 750.00 61.75 739.94 10.124750.00Clearance Factor Pass - MPL-43 - MPL-43 - MPL-4374.08 266.25 71.33 268.25 26.938266.25Centre Distance Pass - MPL-43 - MPL-43 - MPL-4381.25 2,400.00 52.62 2,475.35 2.8382,400.00Ellipse Separation Pass - MPL-43 - MPL-43 - MPL-43100.15 2,500.00 60.40 2,567.70 2.5192,500.00Clearance Factor Pass - MPL-43 - MPL-43PB1 - MPL-43PB174.08 266.25 71.33 268.25 26.938266.25Centre Distance Pass - MPL-43 - MPL-43PB1 - MPL-43PB181.25 2,400.00 52.62 2,475.35 2.8382,400.00Ellipse Separation Pass - MPL-43 - MPL-43PB1 - MPL-43PB1100.15 2,500.00 60.40 2,567.70 2.5192,500.00Clearance Factor Pass - MPL-45 - MPL-45 - MPL-45149.88 282.18 147.71 286.06 69.325282.18Centre Distance Pass - MPL-45 - MPL-45 - MPL-45149.95 300.00 147.69 303.97 66.209300.00Ellipse Separation Pass - MPL-45 - MPL-45 - MPL-45196.66 650.00 192.29 640.20 44.963650.00Clearance Factor Pass - MPU L-41 - MPU L-41 - MPU L-4171.85 2,968.39 36.22 3,207.43 2.0162,968.39Centre Distance Pass - MPU L-41 - MPU L-41 - MPU L-4171.88 2,975.00 36.15 3,213.71 2.0112,975.00Clearance Factor Pass - MPU L-41 - MPU L-41PB1 - MPU L-41PB171.85 2,968.39 36.21 3,207.43 2.0162,968.39Centre Distance Pass - MPU L-41 - MPU L-41PB1 - MPU L-41PB171.88 2,975.00 36.14 3,213.71 2.0112,975.00Clearance Factor Pass - MPU L-51 - MPU L-51 - MPU L-51141.88 228.23 139.77 221.23 67.345228.23Centre Distance Pass - MPU L-51 - MPU L-51 - MPU L-51141.93 250.00 139.72 242.24 64.409250.00Ellipse Separation Pass - MPU L-51 - MPU L-51 - MPU L-51183.20 650.00 178.88 612.72 42.450650.00Clearance Factor Pass - MPU L-52 - MPU L-52 - MPU L-52150.52 338.29 147.91 332.70 57.862338.29Centre Distance Pass - MPU L-52 - MPU L-52 - MPU L-52150.62 375.00 147.84 369.10 54.118375.00Ellipse Separation Pass - 04 August, 2020-16:55COMPASSPage 3 of 7 Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU L-63 - MPU L-63 wp02aComparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftSite NameScan Range: 0.00 to 9,158.99 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (North Reference)Reference Design: M Pt L Pad - Plan: MPU L-63 - MPU L-63 - MPU L-63 wp02aMeasuredDepth(usft)Summary Based on MinimumSeparation WarningMPU L-52 - MPU L-52 - MPU L-52184.80 750.00 179.92 717.00 37.836750.00Clearance Factor Pass - MPU L-53 - MPU L-53 - MPU L-53162.76 33.70 161.13 26.50 99.82933.70Centre Distance Pass - MPU L-53 - MPU L-53 - MPU L-53162.91 100.00 161.01 91.91 85.693100.00Ellipse Separation Pass - MPU L-53 - MPU L-53 - MPU L-53217.37 700.00 211.80 648.76 39.010700.00Clearance Factor Pass - MPU L-54 - MPU L-54 - MPU L-5473.91 598.47 69.84 597.13 18.158598.47Centre Distance Pass - MPU L-54 - MPU L-54 - MPU L-5473.91 600.00 69.83 598.62 18.118600.00Ellipse Separation Pass - MPU L-54 - MPU L-54 - MPU L-5476.88 675.00 72.34 670.87 16.947675.00Clearance Factor Pass - MPU L-55 - MPU L-55 - MPU L-55103.21 301.51 100.79 303.70 42.693301.51Centre Distance Pass - MPU L-55 - MPU L-55 - MPU L-55103.28 325.00 100.74 327.38 40.743325.00Ellipse Separation Pass - MPU L-55 - MPU L-55 - MPU L-55272.90 1,550.00 260.25 1,565.37 21.5821,550.00Clearance Factor Pass - MPU L-56 - MPU L-56 - MPU L-56118.28 553.10 111.68 544.44 17.918553.10Centre Distance Pass - MPU L-56 - MPU L-56 - MPU L-56118.44 575.00 111.59 564.38 17.308575.00Ellipse Separation Pass - MPU L-56 - MPU L-56 - MPU L-56128.13 700.00 119.91 673.96 15.595700.00Clearance Factor Pass - MPU L-57 - MPU L-57 - MPU L-5785.08 663.45 80.73 653.80 19.561663.45Ellipse Separation Pass - MPU L-57 - MPU L-57 - MPU L-5788.49 725.00 83.76 707.14 18.695725.00Clearance Factor Pass - MPU L-57 - MPU L-57PB1 - MPU L-57PB185.08 663.45 80.73 653.80 19.561663.45Ellipse Separation Pass - MPU L-57 - MPU L-57PB1 - MPU L-57PB188.49 725.00 83.76 707.14 18.695725.00Clearance Factor Pass - MPU L-59i - MPU L-59i - MPU L-59i174.15 33.70 172.02 33.80 81.75233.70Ellipse Separation Pass - MPU L-59i - MPU L-59i - MPU L-59i215.02 750.00 210.04 712.20 43.182750.00Clearance Factor Pass - MPU L-59i - MPU L-59PB1 - MPU L-59PB1174.15 33.70 172.02 33.80 81.75233.70Ellipse Separation Pass - MPU L-59i - MPU L-59PB1 - MPU L-59PB1215.02 750.00 210.04 712.20 43.182750.00Clearance Factor Pass - MPU L-61i - MPU L-61i - MPU L-61i30.05 266.02 27.61 266.54 12.338266.02Centre Distance Pass - MPU L-61i - MPU L-61i - MPU L-61i30.06 275.00 27.59 275.53 12.161275.00Ellipse Separation Pass - MPU L-61i - MPU L-61i - MPU L-61i33.43 400.00 30.40 400.22 11.018400.00Clearance Factor Pass - MPU L-61i - MPU L-61PB1 - MPU L-61PB130.05 266.02 27.61 266.54 12.338266.02Centre Distance Pass - MPU L-61i - MPU L-61PB1 - MPU L-61PB130.06 275.00 27.59 275.53 12.161275.00Ellipse Separation Pass - MPU L-61i - MPU L-61PB1 - MPU L-61PB133.43 400.00 30.40 400.22 11.018400.00Clearance Factor Pass - Plan: MPL-21 - MPL-21 - MPL-2114.93 33.70 13.29 30.70 9.13733.70Centre Distance Pass - Plan: MPL-21 - MPL-21 - MPL-2115.42 275.00 12.61 271.97 5.496275.00Ellipse Separation Pass - Plan: MPL-21 - MPL-21 - MPL-2117.16 350.00 13.79 346.91 5.091350.00Clearance Factor Pass - 04 August, 2020-16:55COMPASSPage 4 of 7 Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU L-63 - MPU L-63 wp02aComparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftSite NameScan Range: 0.00 to 9,158.99 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (North Reference)Reference Design: M Pt L Pad - Plan: MPU L-63 - MPU L-63 - MPU L-63 wp02aMeasuredDepth(usft)Summary Based on MinimumSeparation WarningPlan: MPL-21 - MPU L-21A - MPU L-21A wp06A14.93 33.70 13.29 34.90 9.13733.70Centre Distance Pass - Plan: MPL-21 - MPU L-21A - MPU L-21A wp06A15.42 275.00 12.61 276.17 5.496275.00Ellipse Separation Pass - Plan: MPL-21 - MPU L-21A - MPU L-21A wp06A17.16 350.00 13.79 351.11 5.091350.00Clearance Factor Pass - Plan: MPU L-58 - MPU L-58 - MPU L-58 wp05155.26 250.00 151.58 250.10 42.200250.00Centre Distance Pass - Plan: MPU L-58 - MPU L-58 - MPU L-58 wp05155.42 275.00 151.48 275.10 39.413275.00Ellipse Separation Pass - Plan: MPU L-58 - MPU L-58 - MPU L-58 wp05874.41 9,158.99 753.12 9,223.05 7.2099,158.99Clearance Factor Pass - Survey tool programFrom(usft)To(usft)Survey/Plan Survey Tool33.70 800.00 MPU L-63 wp02a 3_Gyro-GC_Csg800.00 5,840.88 MPU L-63 wp02a 3_MWD+IFR2+MS+Sag5,840.88 9,158.99 MPU L-63 wp02a 3_MWD+IFR2+MS+SagEllipse error terms are correlated across survey tool tie-on points.Separation is the actual distance between ellipsoids.Calculated ellipses incorporate surface errors.Clearance Factor = Distance Between Profiles / (Distance Between Profiles - Ellipse Separation).Distance Between centres is the straight line distance between wellbore centres.All station coordinates were calculated using the Minimum Curvature method.04 August, 2020-16:55COMPASSPage 5 of 7 0.001.503.004.50Separation Factor0 550 1100 1650 2200 2750 3300 3850 4400 4950 5500 6050 6600 7150 7700 8250 8800 9350 9900 10450Measured DepthMPL-05MPL-43MPL-25MPU L-41No-Go Zone - Stop DrillingCollision Avoidance Req.Collision Risk Procedures Req.NOERRORSWELL DETAILS:Plan: MPU L-63 NAD 1927 (NADCON CONUS)Alaska Zone 0415.50+N/-S +E/-W Northing Easting Latittude Longitude0.000.006031888.82544797.93 70° 29' 52.766 N 149° 38' 1.142 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU L-63, True NorthVertical (TVD) Reference:WELL @ 49.20usft (Original Well Elev)Measured Depth Reference:WELL @ 49.20usft (Original Well Elev)Calculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2020-07-30T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool33.70 800.00 MPU L-63 wp02a (MPU L-63) 3_Gyro-GC_Csg800.00 5840.88 MPU L-63 wp02a (MPU L-63) 3_MWD+IFR2+MS+Sag5840.88 9158.99 MPU L-63 wp02a (MPU L-63) 3_MWD+IFR2+MS+Sag0.0035.0070.00105.00140.00175.00Centre to Centre Separation (60.00 usft/in)0 550 1100 1650 2200 2750 3300 3850 4400 4950 5500 6050 6600 7150 7700 8250 8800 9350 9900 10450Measured DepthMPL-21MPU L-21A wp06AMPL-33MPU L-57MPU L-55MPL-43MPL-43MPU L-61iMPU L-54MPL-25MPL-17MPL-29MPU L-41NO GLOBAL FILTER: Using user defined selection & filtering criteria33.70 To 9158.99Project: Milne PointSite: M Pt L PadWell: Plan: MPU L-63Wellbore: MPU L-63Plan: MPU L-63 wp02aCASING DETAILSTVD TVDSS MD Size Name114.00 64.80 114.00 13-3/8 13 3/8" x 17 1/2"4699.50 4650.30 5840.88 9-5/8 9 5/8" x 12 1/4"7396.13 7346.93 9158.99 7 7" x 8 1/2" _____________________________________________________________________________________ Revised By: JNL 7/21/20 PROPOSED SCHEMATIC Milne Point Unit Well: MPU L-63 PTD: TBD API: TBD PERFORATION DETAIL Sands Top (MD) Btm (MD)Top (TVD) Btm (TVD) FT Date Status TBD CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF 20" Conductor 129 / X-52 / Weld N/A Surface 114’ N/A 9-5/8" Surface 47 / L-80 / TXP 8.525” Surface 2,500’ 0.0732 9-5/8" Surface 40 / L-80 / TXP 8.679” 2,500’ 5,070’ 0.0758 7” Production 26 / L-80 / BTC 3.795” Surface 9,159’ 0.0149 TUBING DETAIL 3-1/2" Tubing 9.3 / L-80 / EUE 8RD 2.867” Surf 8,700’ 0.0087 JEWELRY DETAIL No Top MD Item ID Upper Completion 1 TBD 3-1/2” Gauge Mandrel w/ ¼” Wire 2.992” 2 TBD Production Packer X.XXX” 3 TBD Nipple, XN X.XXX” 4 TBD WLEG X.XXX” OPEN HOLE / CEMENT DETAIL 42" ±270 ft3 12-1/4" Stg 1 –Lead 945 ft3 / Tail 458 ft3 Stg 2 –Lead 1937 ft3 / Tail 313 ft3 8-1/2” x 9-7/8” 330 ft3 WELL INCLINATION DETAIL KOP @ 300’ Hole Angle @ XN = TBD° Max Hole Angle = 42° TREE & WELLHEAD Tree Cameron 3 1/8" 5M w/ 3-1/8” 5M Cameron Wing Wellhead FMC Gen 5 GENERAL WELL INFO API#: TBD Completed by Doyon 14: Future Revised 2/2015 TRANSMITTAL LETTER CHECKLIST WELL NAME: ______________________________________ PTD: _____________________________________________ ___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional FIELD: ____________________________ POOL: ______________________________________ Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI LATERAL (If last two digits in API number are between 60-69) The permit is for a new wellbore segment of existing well Permit No. _____________, API No. 50-_______________________. Production should continue to be reported as a function of the original API number stated above. Pilot Hole In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well name (_______________________PH) and API number (50-_____________________) from records, data and logs acquired for well (name on permit). Spacing Exception The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce/inject is contingent upon issuance of a conservation order approving a spacing exception. (_____________________________) as Operator assumes the liability of any protest to the spacing exception that may occur. Dry Ditch Sample All dry ditch sample sets submitted to the AOGCC must be in no greater than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. Non- Conventional Well Please note the following special condition of this permit: Production or production testing of coal bed methane is not allowed for well ( ) until after ( ) has designed and implemented a water well testing program to provide baseline data on water quality and quantity. (________________________) must contact the AOGCC to obtain advance approval of such water well testing program. Well Logging Requirements Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by (_______________________________) in the attached application, the following well logs are also required for this well: Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. 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