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Home My WebLink About221-0231. 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 Rev. Circ . Jet Pump 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? Yes No 9. Property Designation (Lease Number): 10. Field: 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 17,630' N/A Casing Collapse Conductor N/A Surface 4,760psi Surface 3,090psi Tieback 6,890psi Screens 9,020psi Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16. Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Hayden Moser Contact Email:Hayden.Moser@hilcorp.com Contact Phone:907-793-1231 Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng Wells Manager Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY MPU J-29A MILNE POINT Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 50-029-23688-01-00 147' 147' N/A MD Hilcorp Alaska LLC C.O. 477B TVD Burst 3,606' 17,630' 3,606' 1,087 Proposed Pools: SCHRADER BLUFF OIL AOGCC USE ONLY 3-1/2" 9.3 / L-80 / EUE-8rd 7,807' 12/25/2025 Subsequent Form Required: Suspension Expiration Date: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL025514, ADL025515, ADL025517 & ADL025906 3,682' 2,429' 9,073' Length 221-023 8,360' N/A N/A 6,870psi 5,750psi 2,113' 3,764' 4-1/2" 3,671' Size 3,795psi 147' 20" 9-5/8" 9-5/8" 2,429' 7-5/8" 6,750psi 6,889' BOT SLZXP LTP and N/A 8,347 MD/ 3,680 TVD and N/A 12,863' Perforation Depth MD (ft): 8,360' See Schematic 9,769' See Schematic Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143) Date: 2025.12.17 07:51:40 - 09'00' Taylor Wellman (2143) 325-766 By Grace Christianson at 8:25 am, Dec 17, 2025 10-404 * BOPE pressure test to 4000 psi. 24 hour notice to AOGCC for opportunity to witness. * Requires passing IC pressure test to 3500 psi. 30 minute charted test. * Approved for reverse circulating jet pump * SSV closure on poer fluid side will intiate closure within 2 minutes on SSV on production side and visa versa. * Compliance to CO 808 required. A.Dewhurst 17DEC25 MGR17DEC25JLC 12/17/2025 12/18/25 RWO Convert to JP Well: MPJ-29A Date: 12/15/2025 Well Name:MPU J-29A API Number:50-029-23688-01-00 Current Status:ESP Producer Rig:ASR 1 Estimated Start Date:12/25/2025 Estimated Duration:5 days Reg.Approval Reqd?Yes Date Reg. Approval Recvd:TBD Regulatory Contact:Tom Fouts Permit to Drill Number:221-023 First Call Engineer:Hayden Moser 479-899-8940 Second Call Engineer:Taylor Wellman 907-947-9533 Current Bottom Hole Pressure:1442 psi @ 3554 TVD SBHP 11/18/25 (7.8 ppg) Max. Anticipated Surface Pressure:1087 psi Gas Column Gradient (0.1 psi/ft) Min ID:2.750 @ 7765 3-1/2 XN Nipple Brief Well Summary and Objective J-29A was sidetracked and completed in 2021. It was initially lifted as an ESP producer. The ESP failed in November 2025. The objective of this program is to convert the well to a reverse-circulating jet pump producer. Notes on Well Condition New 7 5/8 installed during initial completion 2021 Proposed SSV Pilot Settings: o Power fluid SSV low pressure trip will be set to 50% of header pressure o Production SSV high pressure trip will be set to 1100 psi o Production SSV low pressure trip will set to 25% of flowing tubing pressure or 50% of first vessel pressure (whichever is greater) Pre-Rig Procedure (Non-Sundried steps) Slickline & Well Support 1. Clear and level pad area in front of well. Spot rig mats and containment. 2. MIRU SL. 3. Pull DPSOV from upper station and dummy off same. 4. Pull dummy from lower station. 5. RDMO SL. 6. RU Little Red Services. RU reverse out skid and 500 bbl returns tank. 7.Bullhead a diesel spear down the tbg and IA to clean up heavy oil from the well. 8. Circulate at least one wellbore volume with produced water down tubing, taking returns up casing to 500 bbl returns tank. 9. RD Little Red Services and reverse out skid. 10. Set CTS BPV. ND Tree. NU BOPE. 11. NU BOPE house. Spot mud boat. Procedure (Sundried steps) RWO 12. MIRU ASR and ancillary equipment. 13. Check for pressure and if 0 psi set CTS plug. If needed, bleed off any residual pressure off tubing and casing. If needed, kill well w/ produced water prior to setting CTS. 14. Test BOPE to 250 psi Low/ 4,000 psi High, annular to 250 psi Low/ 2,500 psi High (hold each ram/valve and test for 5-min). Record accumulator pre-charge pressures and chart tests. a. Perform Test per ASR 1 BOP Test Procedure b. Notify AOGCC 24 hours in advance of BOP test. c. Confirm test pressures per the Sundry Conditions of approval. reverse-circulating jet pump producer RWO Convert to JP Well: MPJ-29A Date: 12/15/2025 d. Test VBR rams and annular on 2-7/8 and 4-1/2 test joints. e. Submit to AOGCC completed 10-424 form within 5 days of BOPE test. 15. Pull CTS plug. Bleed any pressure off casing to the returns tank. Pull CTS, lubricate if pressure expected. Kill well with produced water as needed. 16. MU landing joint or spear and BOLDS. 17. Rig up ESP spooler. 18. POOH with 3-1/2 tubing. a. PU weight was 78k SO was 52K. Blocks weighed 35k. 19. POOH and lay down the 3-1/2 ESP completion. a. Wash and inspect all joints for re-use. b. Keep gas lift mandrels and nipple for reuse. c. Make sure to account for all clamps below: i. 137 Canon Clamps ii. 1 Protectolizers iii. 5 Seal Clamps iv. 4 Pump Clamps 20. Make tandem csg scraper and test packer run per the BHA below. At +- 7850 MD, forward circulate a surfactant pill around to clean the wellbore. Set packer at +-7800 MD and pressure test IA to 3500 psig. a. 3 ½ workstring b. 7 5/8 test packer c. Casing Scraper d. Bit 21. PU new 4-1/2 Jet Pump Completion and RIH. Ensure there are enough joints of tbg below the packer to land the WLEG inside or below the LTP (+- 8,347 MD). Set packer at +-7800 MD, but ensure it is set at or above test packer run depth. Pin packer per vendor/OE direction, please note pinning shear release on tally and daily report. Install clamps on the TEC wire per vendor recommendations. Nom. Size ~Length Item Lb/ft Material 4.5 10WLEG Pup Joint (+-8,347 MD)12.6 L-80 4.5 Joints 12.6 13Cr 4.5 10'Pup Joint 12.6 13Cr 4.5 XN Nip with RHC profile 12.6 9Cr 4.5 10'Pup Joint 12.6 13Cr 4.5 10'Pup Joint 12.6 13Cr 4.5 7 5/8 X 4-1/2 Packer Set +-7800' MD 12.6 L-80 4.5 10'Pup Joint 12.6 13Cr 4.5 10'Pup Joint 12.6 13Cr 4.5 BHPG 12.6 L-80 4.5 10'Pup Joint 12.6 13Cr 4.5 10'Pup Joint 12.6 13Cr 4.5 Sliding Sleeve 12.6 9Cr 4.5 10'Pup Joint 12.6 L-80 4.5 Joints 12.6 L-80 4.5 Space out PUPS 12.6 L-80 4.5 1 Joint 12.6 L-80 4.5 PUP 12.6 L-80 RWO Convert to JP Well: MPJ-29A Date: 12/15/2025 4.5 Tubing Hanger 12.6 L-80 22. Space out and land the hanger. a. Note PU and SO weights on tally. 23. RILDS and lay down landing joint. 24. Circulate and spot a 50 bbl pill of corrosion inhibited 1% KCl prior to setting packer. 25. Drop ball and rod and complete loading tubing with FP and hydraulically set the packer as per Vendor setting procedure. 26. Bleed off the tubing to 2500psi. Perform MIT-IA to 3500 psig for 30 minutes. 27. Set CTS. 28. RDMO ASR. Post-Rig Procedure: 1. RD mud boat. RD BOPE house. Move to next well location. 2. RU crane. ND BOPE. 3. NU 4-1/16 tree and tubing head adapter. 4. Test both tree and tubing hanger void to 500psi low/5,000psi high. Pull CTS. 5. MIRU SL. 6. Open sliding sleeve. 7. RIH and pull ball & rod and RHC plug. 8. Install JP. 9. RD crane. Move 500 bbl returns tank and rig mats to next well location. 10. Turn well over to production Attachments: 1. Current Wellbore Schematic 2. Proposed Wellbore Schematic 3. BOP Schematic Charted and recorded. - mgr _____________________________________________________________________________________ Revised By: TDF 7/14/2023 SCHEMATIC Milne Point Unit Well: MPU J-29A Last Completed: 5/23/2021 PTD: 221-023 TD =17,630(MD) /TD=3,606 (TVD) 20 Orig. KB Elev.: 60.20 / GL Elev.: 33.70 7-5/8 9/10 13 4/5 18 9-5/8 1 2 3 See Screen/ Solid Liner Detail PBTD =12,861 (MD) / PBTD=3,671 (TVD) 9-5/8 ES Cementer @ 2,406 MD 6/7/8 4-1/2 Shoe @ 12,861 11 14 12 15/16 17 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20" Conductor 129.5 / X52 / Weld N/A Surface 147 N/A 9-5/8" Surface 47 / L-80 / TXP 8.681 Surface 2,429 0.0758 9-5/8 Surface 40 / L-80 / TXP 8.835 2,429 9,073 0.0732 7-5/8 Tieback 29.7 / L-80 / Hyd 521 6.875 Surface 8,360 0.0459 4-1/2 Liner 13.5 / L-80 / Hyd 625 3.920 8,347 12,863 .0149 TUBING DETAIL 3-1/2" Tubing 9.3# / L-80 / EUE 8rd 2.992 Surface 7,907 0.0087 OPEN HOLE / CEMENT DETAIL Driven 20 12-1/4"Stg 1 Lead 1015 sx / Tail 400 sx Stg 2 Lead 730 sx / Tail 270 sx 8-1/2 Cementless Screened Liner WELL INCLINATION DETAIL A KOP @ 9073 Max Hole Angle = 97 deg @ 9680 TREE & WELLHEAD Tree Cameron 3-1/8" 5M w/ 3-1/8 5M Cameron Wing Wellhead Cameron 11 5K x Slip-lock bottom w/ (2) 2-1/16 5K outs GENERAL WELL INFO API: 50-029-23688-01-00 Drilled and Completed by Doyon 14 1/11/21 A Sidetrack (Innovation): 5/23/2021 JEWELRY DETAIL No. Top MD Item ID 1 126 3-1/2 x 1 GLM w/ Dummy 2.907 2 7,645 3-1/2 x 1 GLM Dummy Valve w/ BK Latch 2.907 3 7,765 XN Nipple 2.813 Profile, 2.75 No Go 2.760 4 7,807 Discharge Head: 400 Mach B/O 3.5 EUE 5 7,808 Zenith Ported Sub: Press Port 400P 6 7,855 Pump: 400PMSXD 24 GINPPSH H6 STD PNT 7 7,865 Gas Separator: 538GSTHVEV H6 STD PNT WC ENH 8 7,871 Intake 9 7,872 Upper Tandem Seal: GSBDB H6 SB/AB PFSA 10 7,879 Lower Tandem Seal: GSBDB H6 SB/AB PFSA 11 7,886 Motor: 562XP 250 HP / 2505V / 61A 12 7,902 Motor Gauge: Zenith E7 13 7,905 Centralizer: P/N C63569: Bottom @7,907 MD 14 8,347 7 x 9-5/8 SLZXP Liner top packer (3,680 TVD) 6.160 15 8,349 Locator Sub, 7 TC-II Box x Box 6.180 16 8,350 Bullet Seals (TBSA), Mule Shoe (4 1 holes) 6.180 17 8,457 Bowen HP casing patch 3.820 18 12,861 Shoe 4-1/2 250 SCREENS LINER DETAIL Jts Top (MD) Top (TVD) Btm (MD) Btm (TVD) 19 8543 3702 9335 3798 4 9418 3802 9583 3799 5 9748 3783 9958 3769 3 10038 3767 10164 3765 56 10491 3759 12822 3674 PERMAFROST DETAIL Bottom = 2,161 MD / 1,955 TVD _____________________________________________________________________________________ Revised By: HTM 12/16/2023 PROPOSED Milne Point Unit Well: MPU J-29A Last Completed: 5/23/2021 PTD: 221-023 TD =17,630(MD) /TD=3,606 (TVD) 20 Orig. KB Elev.: 60.20 / GL Elev.: 33.70 7-5/8 9 5 9-5/8 4 1 2 3 See Screen/ Solid Liner Detail PBTD =12,861 (MD) / PBTD=3,671 (TVD) 9-5/8ES Cementer @ 2,406 MD 4-1/2 Shoe @ 12,861 6 15/16 7 &8 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20" Conductor 129.5 / X52 / Weld N/A Surface 147 N/A 9-5/8" Surface 47 / L-80 / TXP 8.681 Surface 2,429 0.0758 9-5/8 Surface 40 / L-80 / TXP 8.835 2,429 9,073 0.0732 7-5/8 Tieback 29.7 / L-80 / Hyd 521 6.875 Surface 8,360 0.0459 4-1/2 Liner 13.5 / L-80 / Hyd 625 3.920 8,347 12,863 .0149 TUBING DETAIL 4-1/2" Tubing 12.6 / L-80 / TXP BTC 3.958 Surface ±7,620 0.0152 4-1/2" Tubing 12.6 / 13Cr / JFE 3.958 ±7,620 ±8,347 0.0152 OPEN HOLE / CEMENT DETAIL Driven 20 12-1/4"Stg 1 Lead 1015 sx / Tail 400 sx Stg 2 Lead 730 sx / Tail 270 sx 8-1/2 Cementless Screened Liner WELL INCLINATION DETAIL A KOP @ 9073 Max Hole Angle = 97 deg @ 9680 TREE & WELLHEAD Tree Cameron 3-1/8" 5M w/ 3-1/8 5M Cameron Wing Wellhead Cameron 11 5K x Slip-lock bottom w/ (2) 2-1/16 5K outs GENERAL WELL INFO API: 50-029-23688-01-00 Drilled and Completed by Doyon 14 1/11/21 A Sidetrack (Innovation): 5/23/2021 JEWELRY DETAIL No. Top MD Item ID 1 ±7,620 Sliding Sleeve 2 ±7,680 BHP 3 ±7,800 7-5/8 x 4-1/2 Packer 4 ±7,862 4-1/2 XN Nipple 5 ±8,345 WLEG Btm @ ±8,347 6 8,347 7 x 9-5/8 SLZXP Liner top packer (3,680 TVD) 6.160 7 8,349 Locator Sub, 7 TC-II Box x Box 6.180 8 8,350 Bullet Seals (TBSA), Mule Shoe (4 1 holes) 6.180 9 8,457 Bowen HP casing patch 3.820 4-1/2 250 SCREENS LINER DETAIL Jts Top (MD) Top (TVD) Btm (MD) Btm (TVD) 19 8543 3702 9335 3798 4 9418 3802 9583 3799 5 9748 3783 9958 3769 3 10038 3767 10164 3765 56 10491 3759 12822 3674 PERMAFROST DETAIL Bottom = 2,161 MD / 1,955 TVD Milne Point ASR Rig 1 BOPE 2025 Updated 7/31/2025 11 BOPE 4.48' 4.54' 2.00' INTEGRATED 4.30'INTEGRATED 11" - 5000 2-7/8" x 5" VBR Blind11'- 5000 DSA, 11 5M X 7 1/16 5M (If Needed) 2 1/16 5M Kill Line Valves 2 1/16 5M Choke Line Valves HCRManualManualManual Stripping Head Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 08/24/2023 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20230824 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# KBU 14-6Y 50133205720000 207149 8/10/2023 YELLOW JACKET GPT/Plug/Perf KBU 14-6Y 50133205720000 207149 8/12/2023 YELLOW JACKET GPT/Plug/Perf KBU 14-6Y 50133205720000 207149 8/17/2023 YELLOW JACKET GPT/Plug/Perf KBU 22-06 50133205500000 205054 8/3/2023 YELLOW JACKET Gamma Ray KBU 22-06 50133205500000 205054 8/6/2023 YELLOW JACKET Gamma Ray KBU 22-06 50133205500000 205054 8/11/2023 YELLOW JACKET GPT/Plug/Perf MPU J-29A 50029236880100 221023 8/19/2023 READ Caliper Survey PBU S-42A 50029226620100 215055 8/11/2023 READ MAPP PBU PSI-09 50029230950000 202124 7/28/2023 HALLIBURTON WFL-TMD3D Please include current contact information if different from above. T37955 T37955 T37955 T37956 T37956 T37956 T37957 T37958 T37959 8/28/2023 MPU J-29A 50029236880100 221023 8/19/2023 READ Caliper Survey Kayla Junke Digitally signed by Kayla Junke Date: 2023.08.28 15:49:42 -08'00' 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 Jet Pump 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? Yes No 9. Property Designation (Lease Number): 10. Field: 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 17,630'N/A Casing Collapse Conductor N/A Surface 4,760psi Surface 3,090psi Tieback 4,790psi Screens 8,540psi Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16. Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Brian Glasheen Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng MILNE POINT SCHRADER BLUFF OIL N/A 3,606' 12,861' 3,761' 1,154 N/A Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY MILNE PT UNIT J-29A AOGCC USE ONLY Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): 8/8/2023 Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL025514, ADL025515, ADL025517 & ADL025906 220-070 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 50-029-23688-00-00 Hilcorp Alaska LLC C.O. 477.05 Length Size Proposed Pools: 147' 147' 9.3 / L-80 / EUE-8rd TVD Burst 7,907' 9,020psi MD N/A 6,890psi 6,870psi 5,750psi 2,113' 3,764' 3,682' 2,429' 9,073' 147' 20" 9-5/8" 9-5/8" 2,429' 7-5/8"8,360' 6,644' 8,360' See Schematic 4,516' See Schematic 3-1/2" 3,671'4-1/2" BOT SLZXP LTP and N/A 8,347' MD/ 3,680 TVD and N/A Brian.Glasheen@hilcorp.com 907-564-5277 12,863' Perforation Depth MD (ft): No Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 8:14 am, Jul 17, 2023 323-401 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143) Date: 2023.07.14 15:37:03 - 08'00' Taylor Wellman (2143) 221-023 01 * BOPE pressure test to 2500 psi. * Approved for a reverse circulating jet pump. * IA SSV high pressure trip pressure not to exceed 3000 psi. IA low pressure trip pressure not to be lower than 1500 psi. * Production tubing SSV low pressure trip not to be lower than 75 psi. Production tubing high pressure trip not to exceed 650 psi. * SSV closure on IA will intiate closure within 2 minutes on SSV on production tubing and visa versa. DSR-7/19/23 10-404 1,154 MDG 7/17/2023MGR17JULY23GCW 07/20/2023 Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2023.07.20 19:22:12 -05'00' RBDMS JSB 072523 Convert to Reverse Circulating JP Well: MPJ-29A PTD: 221023 Well Name:MPU J-29A API Number:500292368801 Current Status:ESP producer Rig:ASR 1 Estimated Start Date:8/8/ 2023 Estimated Duration:5 days Reg.Approval Req’d? Yes Date Reg. Approval Rec’vd:TBD Regulatory Contact:Tom Fouts Permit to Drill Number:221023 First Call Engineer:Brian Glasheen 907-545-1144 (M) Second Call Engineer:Taylor Wellman 907-947-9533 AFE Number:232-00927 Current Bottom Hole Pressure:1508 psi @ 3541’ TVD 8.2 PPGE | Gauge 07/6/23 Maximum Expected BHP:1508 psi @ 3541’ TVD 8.2 PPGE Max. Anticipated Surface Pressure:1154 psi Gas Column Gradient (0.1 psi/ft) Min ID:2.75” @ 7765’ XN Nipple Brief Well Summary MPU J-29A was drilled and completed in the Schrader Bluff N-sands in 2021. The well was completed as a single lateral with 250-micron screens and an ESP artificial lift completion. The wells ESP is under performing and requires a RWO to recomplete the well as a reverse circulating jet pump to achieve target FBHP. Objective The primary objective of the RWO is to Pull ESP and complete as a reverse circulating Jet pump producer. Planned SSV Pilot Settings x Power fluid SSV high pressure trip will not exceed 3000 psi x Power fluid SSV low pressure trip will be set to 50 percent of header pressure x Production SSV high pressure trip not to exceed 650 psi x Production SSV low pressure trip not to be below 75 psi Non-Sundried Work: Pre-Rig Procedure: 1) OA integrity Test. PPPOT-T to 5000 psi. PPPOT-IC to 3500 psi. Function all LDS Slickline- 2) Displace TBG to hot fluid. 3) RIH and Pull DMY GLV in St1.Leave open. 4) Pull LGLV in st 2 126’ MD and set DMY. 5) Run Tubing Caliper to assess tubing condition. Well Support- 1. Clear and level pad area in front of well. Spot rig mats and containment. 2. RU Little Red Services. RU reverse out skid and 500 bbl returns tank. 3. Pressure test lines to 3,000 psi. 4. Circulate at least one wellbore volume with 8.5 ppg KCL down tubing, taking returns up casing to 500 bbl returns tank. Heat fluids to help with thick crude prior to circulating. Convert to Reverse Circulating JP Well: MPJ-29A PTD: 221023 a. If returns are not seen, after attempting circulation down the tubing, bullhead and load the tubing and IA. 5. RD Little Red Services and reverse out skid. 6. RU crane. Set CTS BPV. ND Tree. NU BOPE. RD Crane. 7. NU BOPE house. Spot mud boat. Brief RWO Procedure Sundry work: 8. MIRU Hilcorp ASR #1 WO Rig, ancillary equipment, and lines. 9. Check for pressure. If needed, bleed off any residual pressure off tubing and casing. If needed, kill well w/ 8.5 KCL prior to setting CTS Plug. Set CTS Plug. 10. Test BOPE to 250 psi Low/ 2,500 psi High, annular to 250 psi Low/ 2,500 psi High (hold each ram/valve and test for 5-min). Record accumulator pre-charge pressures and chart tests. a. Perform Test per ASR 1 BOP Test Procedure b. Notify AOGCC 24 hours in advance of BOP test. c. Confirm test pressures per the Sundry Conditions of approval. d. Test VBR rams on 3-1/2’’ and 4-1/2” test joints. e. Submit to AOGCC completed 10-424 form within 5 days of BOPE test. 11. Contingency: (If the tubing hanger won’t pressure test due to either a penetrator leak or the BPV profile is eroded and/or corroded and BPV cannot be set with tree on.) a. Notify Operations Engineer (Hilcorp), Mr. Mel Rixse (AOGCC) and Mr. Jim Regg (AOGCC) via email explaining the wellhead situation prior to performing the rolling test. AOGCC may elect to send an inspector to witness test. b. With stack out of the test path, test choke manifold per standard procedure c. Conduct a rolling test: Test the rams and annular with the pump continuing to pump, (monitor the surface equipment for leaks to ensure that the fluid is going down-hole and not leaking anywhere at surface.) d. Hold a constant pressure on the equipment and monitor the fluid/pump rate into the well. Record the pumping rate and pressure. e. Once the BOP ram and annular tests are completed, test the remainder of the system following the normal test procedure (floor valves, gas detection, etc.) f. Record and report this test with notes in the remarks column that the tubing hanger/BPV profile / penetrator wouldn’t hold pressure and rolling test was performed on BOP Equipment and list items, pressures and rates. 12. Bleed any pressure off tubing and casing to the returns tank. Pull CTS, lubricate if pressure expected. Kill well with KCL water as needed. 13. MU landing joint or spear and BOLDS. 14. Well is a live well and hole fill needs to be managed the entire job. If well will hold a column of fluid establish hole fill rate to see fluid at surface at all times, If well will not surface fluid due to low bottom hole pressure maintain a hole fill and double pipe displacement when POOH. 15. Attempt to pull tubing. a. PU weight 2021 RWO was 74k SO was 52K b. Do not exceed 80 percent of 3-1/2” tubing. 16. Recover the tubing hanger. Contingency (If a rolling test was conducted): MU new hanger or test plug to the completion tubing. Re-land hanger (or test plug) in tubing head. Test BOPE per standard procedure. 17. POOH and lay down the 3-1/2’’ tubing. Rig up spooler for ESP cable. a. Inspect the Tubing and place good joints into inventory. Review caliper and ask OE joints to keep. b. Plan to keep all equipment for future re-use. c. Make sure to account for all clamps below: i. 137 CC, ii. 1 MC, iii. 1 Protectralizers iv. 5 SC v. 4 PC Convert to Reverse Circulating JP Well: MPJ-29A PTD: 221023 18. Assuming ESP had no over pull when POOH. (If indication of pulling heavy consider running a casing scraper run.) 19. PU new 4-1/2’’ Jet Pump Completion and RIH. Colors indicate assemblies to be bucked up prior to RWO. Nom. Size ~Length Item Lb/ft Material Notes 4-1/2''10'WLEG/ Mule shoe 12.6 L-80 Place WLEG in LTP at 8347' MD 4-1/2''Joints 12.6 L-80 4-1/2''10'Pup Joint 12.6 L-80 4-1/2''3'4 1/2'' XN Nip with RHC 12.6 L-80 ~7563’ MD 4-1/2''10'Pup Joint 12.6 L-80 4-1/2''40 1 joint 12.6 L-80 4-1/2''10'Pup Joint 12.6 L-80 4-1/2'' 7”-5/8 X 4-1/2” Packer 12.6 L-80 Tri point packer ~Set ~7500' MD 4-1/2''10'Pup Joint 12.6 L-80 4-1/2'' 40 1 joint 12.6 L-80 4-1/2''10'Pup Joint 12.6 L-80 4-1/2''BHP Gauge 12.6 L-80 4-1/2''10'Pup Joint 12.6 L-80 4-1/2'' 40 1 joint 12.6 L-80 4-1/2''10'Pup Joint 12.6 L-80 4-1/2''Hal Sliding sleeve with one section of ports blanked off for tech wire 12.6 L-80 4-1/2''10'Pup Joint 12.6 L-80 4-1/2''Joints 12.6 L-80 4-1/2''Space out PUPS 12.6 L-80 4-1/2'' 1 joint 12.6 L-80 4-1/2''PUP 12.6 L-80 4-1/2''Tubing Hanger 12.6 L-80 20. Space out and land the hanger. a. Use caution not to Damage BHPG Cable while landing the hanger. b. Note PU (Pick Up) and SO (Slack Off) weights on tally. 21. RILDS. Lay down landing joint. 22. Pump 60 bbls 1% KCL with 1% by volume Corrosion inhibitor down the IA. Taking returns up TBG. a. This is to protect the area between the packer and Sliding Sleeve. While taking returns up the TBG 23. Pump an additional 85 bbls of 1% KCL followed by 52 bbls of diesel freeze protect down the IA to land inhibitor between Sliding Sleeve and the packer while taking returns up the TBG. 24. Swap to pumping down the TBG taking to formation and Pump 30 bbls of FP. 25. Drop ball and rod and complete loading tubing with FP and hydraulically set the packer as per Vendor setting procedure. Convert to Reverse Circulating JP Well: MPJ-29A PTD: 221023 26. Pressure up and test the tubing to 3000 psi for MIT-T. Bleed off the tubing. Test the IA to 3000 psi for MIT-IA (J Pad power fluid header pressure 2600 psi) . Record and notate all pressure tests (30 minutes) on chart. 27. Set CTS. 28. RDMO ASR. Post-Rig Procedure: 1. RD mud boat. RD BOPE house. Move to next well location. 2. RU crane. ND BOPE. 3. NU tree and tubing head adapter. 4. Test both tree and tubing hanger void to 500psi low/5,000psi high. 5. Pull CTS. 6. RD crane. Move 500 bbl returns tank and rig mats to next well location. 7. Replace gauge(s) if removed. 8. Turn well over to production. RU well house and flowlines for a Jet Pump completion. Post Rig Work Slickline 1. Spot Slickline unit and RU. 2. Pressure test lubricator to 300psi low and 2,800psi high. 3. Pull Ball and rod 4. Pull RHC profile 5. Shift Sliding Sleeve open 6. Set 13B Jet pump in Sliding sleeve. Attachments: 1. Well Schematic Current 2. Well schematic Proposed 3. BOP Drawing _____________________________________________________________________________________ Revised By: TDF 7/14/2023 SCHEMATIC Milne Point Unit Well: MPU J-29A Last Completed: 5/23/2021 PTD: 221-023 TD =17,630’(MD) /TD=3,606’ (TVD) 20” Orig. KB Elev.: 60.20’ / GL Elev.: 33.70’ 7-5/8” 9/10 13 4/5 18 9-5/8” 1 2 3 See Screen/ Solid Liner Detail PBTD =12,861’ (MD) / PBTD= 3,671’ (TVD) 9-5/8” ‘ES’ Cementer @ 2,406’ MD 6/7/8 4-1/2” Shoe @ 12,861’ 11 14 12 15/16 17 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20" Conductor 129.5 / X52 / Weld N/A Surface 147’ N/A 9-5/8" Surface 47 / L-80 / TXP 8.681 Surface 2,429’ 0.0758 9-5/8” Surface 40 / L-80 / TXP 8.835 2,429’ 9,073’ 0.0732 7-5/8” Tieback 29.7 / L-80 / Hyd 521 6.875 Surface 8,360’ 0.0459 4-1/2” Liner 13.5 / L-80 / Hyd 625 3.920 8,347’ 12,863’ .0149 TUBING DETAIL 3-1/2" Tubing 9.3# / L-80 / EUE 8rd 2.992 Surface 7,907’ 0.0087 OPEN HOLE / CEMENT DETAIL Driven 20” 12-1/4"Stg 1 Lead – 1015 sx / Tail – 400 sx Stg 2 Lead – 730 sx / Tail 270 sx 8-1/2” Cementless Screened Liner WELL INCLINATION DETAIL A KOP @ 9073’ Max Hole Angle = 97 deg @ 9680’ TREE & WELLHEAD Tree Cameron 3-1/8" 5M w/ 3-1/8” 5M Cameron Wing Wellhead Cameron 11” 5K x Slip-lock bottom w/ (2) 2-1/16” 5K outs GENERAL WELL INFO API: 50-029-23688-01-00 Drilled and Completed by Doyon 14 1/11/21 A Sidetrack (Innovation): 5/23/2021 JEWELRY DETAIL No. Top MD Item ID 1 126’ 3-1/2” x 1” GLM w/ Dummy 2.907” 2 7,645’ 3-1/2” x 1” GLM Dummy Valve w/ BK Latch 2.907” 3 7,765’ XN Nipple 2.813” Profile, 2.75” No Go 2.760” 4 7,807’ Discharge Head: 400 Mach B/O 3.5 EUE 5 7,808’ Zenith Ported Sub: Press Port 400P 6 7,855’ Pump: 400PMSXD 24 GINPPSH H6 STD PNT 7 7,865’ Gas Separator: 538GSTHVEV H6 STD PNT WC ENH 8 7,871’ Intake 9 7,872’ Upper Tandem Seal: GSBDB H6 SB/AB PFSA 10 7,879’ Lower Tandem Seal: GSBDB H6 SB/AB PFSA 11 7,886’ Motor: 562XP – 250 HP / 2505V / 61A 12 7,902’ Motor Gauge: Zenith E7 13 7,905’ Centralizer: P/N C63569: Bottom @7,907’ MD 14 8,347’ 7” x 9-5/8” SLZXP Liner top packer (3,680’ TVD) 6.160” 15 8,349’ Locator Sub, 7” TC-II Box x Box 6.180” 16 8,350’ Bullet Seals (TBSA), Mule Shoe (4 – 1” holes) 6.180” 17 8,457’ Bowen HP casing patch 3.820” 18 12,861’ Shoe 4-1/2” 250ђ SCREENS LINER DETAIL Jts Top (MD) Top (TVD) Btm (MD) Btm (TVD) 19 8543’ 3702’ 9335’ 3798’ 4 9418’ 3802’ 9583’ 3799’ 5 9748’ 3783 9958’ 3769’ 3 10038’ 3767’ 10164’ 3765’ 56 10491’ 3759’ 12822’ 3674’ PERMAFROST DETAIL Bottom = 2,161’ MD / 1,955 TVD _____________________________________________________________________________________ Revised By: TDF 7/14/2023 PROPOSED Milne Point Unit Well: MPU J-29A Last Completed: 5/23/2021 PTD: 221-023 TD =17,630’ (MD) / TD=3,606’ (TVD) 20” Orig. KB Elev.: 60.20’ / GL Elev.: 33.70’ 7-5/8” 9 5 9-5/8” 4 1 2 3 See Screen/ Solid Liner Detail PBTD =12,861’ (MD) / PBTD=3,671’ (TVD) 9-5/8” ‘ES’ Cementer @ 2,406’ MD 4-1/2” Shoe @ 12,861’ 6 15/16 7 & 8 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20" Conductor 129.5 / X52 / Weld N/A Surface 147’ N/A 9-5/8" Surface 47 / L-80 / TXP 8.681 Surface 2,429’ 0.0758 9-5/8” Surface 40 / L-80 / TXP 8.835 2,429’ 9,073’ 0.0732 7-5/8” Tieback 29.7 / L-80 / Hyd 521 6.875 Surface 8,360’ 0.0459 4-1/2” Liner 13.5 / L-80 / Hyd 625 3.920 8,347’ 12,863’ .0149 TUBING DETAIL 4-1/2" Tubing 12.6 / L-80 / EUE 8rd 3.958 Surface ±8,347’ 0.0152 OPEN HOLE / CEMENT DETAIL Driven 20” 12-1/4"Stg 1 Lead – 1015 sx / Tail – 400 sx Stg 2 Lead – 730 sx / Tail 270 sx 8-1/2” Cementless Screened Liner WELL INCLINATION DETAIL A KOP @ 9073’ Max Hole Angle = 97 deg @ 9680’ TREE & WELLHEAD Tree Cameron 3-1/8" 5M w/ 3-1/8” 5M Cameron Wing Wellhead Cameron 11” 5K x Slip-lock bottom w/ (2) 2-1/16” 5K outs GENERAL WELL INFO API: 50-029-23688-01-00 Drilled and Completed by Doyon 14 1/11/21 A Sidetrack (Innovation): 5/23/2021 JEWELRY DETAIL No. Top MD Item ID 1 ±7,420’ Sliding Sleeve 2 ±7,480’ BHP 3 ±7,500’ 7-5/8” x 4-1/2” Packer 4 ±7,563 4-1/2” XN Nipple w/ RHC Plug 5 ±8,345’ WLEG – Btm @ ±8,347’ 6 8,347’ 7” x 9-5/8” SLZXP Liner top packer (3,680’ TVD) 6.160” 7 8,349’ Locator Sub, 7” TC-II Box x Box 6.180” 8 8,350’ Bullet Seals (TBSA), Mule Shoe (4 – 1” holes) 6.180” 9 8,457’ Bowen HP casing patch 3.820” 4-1/2” 250ђ SCREENS LINER DETAIL Jts Top (MD) Top (TVD) Btm (MD) Btm (TVD) 19 8543’ 3702’ 9335’ 3798’ 4 9418’ 3802’ 9583’ 3799’ 5 9748’ 3783 9958’ 3769’ 3 10038’ 3767’ 10164’ 3765’ 56 10491’ 3759’ 12822’ 3674’ PERMAFROST DETAIL Bottom = 2,161’ MD / 1,955 TVD Updated 8/11/2020 Milne Point ASR Rig 1 BOPE 2023 11” BOPE 4.48' 4.54' 2.00' CIW-U 4.30'Hydril GK 11" - 5000 VBR or Pipe Rams Blind11'’- 5000 DSA, 11 5M X 7 1/16 5M (If Needed) 2 1/16 5M Kill Line Valves 2 1/16 5M Choke Line Valves HCRManualManualHCR Stripping Head 2-7/8” x 5” VBR DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-23688-01-00Well Name/No. MILNE PT UNIT J-29ACompletion Status1-OILCompletion Date5/23/2021Permit to Drill2210230Operator Hilcorp Alaska, LLCMD17630TVD3606Current Status1-OIL7/12/2021UICNoWell Log Information:DigitalMed/FrmtReceivedStart StopOH /CHCommentsLogMediaRunNoElectr DatasetNumberNameIntervalList of Logs Obtained:ROP, ABR, DGR, ADR MD & TVDNoNoYesMud Log Samples Directional SurveyREQUIRED INFORMATION(from Master Well Data/Logs)DATA INFORMATIONLog/DataTypeLogScaleDF5/24/20219060 17630 Electronic Data Set, Filename: MPU J-29A LWD Final.las35158EDDigital DataDF5/24/20219075 17592 Electronic Data Set, Filename: MPU J-29A ADR Quadrants All Curves.las35158EDDigital DataDF5/24/2021 Electronic File: MPU J-29A LWD Final MD.cgm35158EDDigital DataDF5/24/2021 Electronic File: MPU J-29A LWD Final TVD.cgm35158EDDigital DataDF5/24/2021 Electronic File: MPU J-29A_Definitive Survey Report.pdf35158EDDigital DataDF5/24/2021 Electronic File: MPU J-29A_DSR.txt35158EDDigital DataDF5/24/2021 Electronic File: MPU J-29A_GIS.txt35158EDDigital DataDF5/24/2021 Electronic File: MPU J-29A_Plan.pdf35158EDDigital DataDF5/24/2021 Electronic File: MPU J-29A_VSec.pdf35158EDDigital DataDF5/24/2021 Electronic File: MPU J-29A LWD Final MD.emf35158EDDigital DataDF5/24/2021 Electronic File: MPU J-29A LWD Final TVD.emf35158EDDigital DataDF5/24/2021 Electronic File: MPU_J-29A_Geosteering.dlis35158EDDigital DataDF5/24/2021 Electronic File: MPU_J-29A_Geosteering.ver35158EDDigital DataDF5/24/2021 Electronic File: MPU J-29A LWD Final MD.pdf35158EDDigital DataDF5/24/2021 Electronic File: MPU J-29A LWD Final TVD.pdf35158EDDigital DataDF5/24/2021 Electronic File: MPU J-29A LWD Final MD.tif35158EDDigital DataDF5/24/2021 Electronic File: MPU J-29A LWD Final TVD.tif35158EDDigital DataDF5/24/2021 Electronic File: EMFView3_1.zip35158EDDigital DataDF5/24/2021 Electronic File: Readme.txt35158EDDigital DataMonday, July 12, 2021AOGCCPage 1 of 3MPU J-29A LWDFinal.las DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-23688-01-00Well Name/No. MILNE PT UNIT J-29ACompletion Status1-OILCompletion Date5/23/2021Permit to Drill2210230Operator Hilcorp Alaska, LLCMD17630TVD3606Current Status1-OIL7/12/2021UICNoWell Cores/Samples Information:ReceivedStart Stop CommentsTotalBoxesSample SetNumberNameIntervalINFORMATION RECEIVEDCompletion ReportProduction Test InformationGeologic Markers/TopsY Y / NAYComments: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:5/23/2021Release Date:4/14/20210 0 2210230 MILNE PT UNIT J-29A LOG HEADERS35158LogLog Header Scans0 0 2210230 MILNE PT UNIT J-29A LOG HEADERS35159LogLog Header ScansDF5/24/2021 Electronic File: MPU J-29A Geosteering End of Well Report.pdf35159EDDigital DataDF5/24/2021 Electronic File: MPU J-29A Geoteering EOW Plot.emf35159EDDigital DataDF5/24/2021 Electronic File: MPU J-29A Geoteering EOW Plot.pdf35159EDDigital DataDF5/24/2021 Electronic File: MPU J-29A Geoteering EOW Plot.tif35159EDDigital DataDF5/24/2021 Electronic File: MPU J-29A Post-Well Geosteering X-Section Summary.pdf35159EDDigital DataMonday, July 12, 2021AOGCCPage 2 of 3 DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-23688-01-00Well Name/No. MILNE PT UNIT J-29ACompletion Status1-OILCompletion Date5/23/2021Permit to Drill2210230Operator Hilcorp Alaska, LLCMD17630TVD3606Current Status1-OIL7/12/2021UICNoCompliance Reviewed By:Date:Monday, July 12, 2021AOGCCPage 3 of 3M. Guhl 7/12/2021 1a. Well Status:Oil SPLUG Other Abandoned Suspended 1b. Well Class: 20AAC 25.105 20AAC 25.110 Development Exploratory GINJ WINJ WDSPL No. of Completions: _1 Service Stratigraphic Test 2. Operator Name: 6. Date Comp., Susp., or 14. Permit to Drill Number / Sundry: Aband.: 3. Address: 7. Date Spudded: 15. API Number: 4a. Location of Well (Governmental Section): 8. Date TD Reached: 16. Well Name and Number: Surface: Top of Productive Interval: 9. Ref Elevations: KB: 17. Field / Pool(s): GL: 33.7' BF: Total Depth: 10. Plug Back Depth MD/TVD: 18. Property Designation: 4b. Location of Well (State Base Plane Coordinates, NAD 27): 11. Total Depth MD/TVD: 19. DNR Approval Number: Surface: x- y- Zone- 4 TPI: x- y- Zone- 4 12. SSSV Depth MD/TVD: 20. Thickness of Permafrost MD/TVD: Total Depth: x- y- Zone- 4 5. Directional or Inclination Survey: Yes (attached) No 13. Water Depth, if Offshore: 21. Re-drill/Lateral Top Window MD/TVD: Submit electronic information per 20 AAC 25.050 (ft MSL) 22.Logs Obtained: 23. BOTTOM 20" X-52 147' L-80 2,117' L-80 3,764' 7-5/8" L-80 3,682' 4-1/2" L-80 3,671' 24. Open to production or injection? Yes No 25. 26. Was hydraulic fracturing used during completion? Yes No DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 27. Date First Production: Method of Operation (Flowing, gas lift, etc.): Hours Tested: Production for Gas-MCF: Test Period Casing Press: Calculated Gas-MCF: Oil Gravity - API (corr): Press. 24-Hour Rate 9-5/8"12-1/4" ACID, FRACTURE, CEMENT SQUEEZE, ETC. CASING, LINER AND CEMENTING RECORD List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data within 90 days of completion, Uncemented TiebackTieback TUBING RECORD Uncemented Screen Liner Liner Top Packer 7,907'3-1/2" 9.3# L-80 SIZEIf Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number; Date Perfd): 8,347' 12,863' Stg 2 L - 730 sx / T - 270 sx 3,680' Driven 13.5# Surface 2,429' Stg 1 L - 1015 sx / T - 400sx 8-1/2" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG Hilcorp Alaska, LLC WAG Gas 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 5/23/2021 2670' FSL, 3383' FEL, Sec. 28, T13N, R10E, UM, AK 643' FSL, 2249' FEL, Sec. 24, T13N, R09E, UM, AK 221-023 Milne Point Field / Schrader Bluff Oil Pool 60.3' 12,861' / 3,671' HOLE SIZE AMOUNT PULLED 50-029-23688-01-00 MPU J-29A 551934 6015068 921' FSL, 953' FWL, Sec. 20, T13N, R10E, UM, AK CEMENTING RECORD 6018557 SETTING DEPTH TVD 6018232 BOTTOM TOP Surface Surface CASING WT. PER FT.GRADE 29.7# 545678 537247 TOP SETTING DEPTH MD Surface Surface Per 20 AAC 25.283 (i)(2) attach electronic information 40# 8,360' 2,117' Surface DEPTH SET (MD) 8,347' / 3,680' PACKER SET (MD/TVD) 129.5# 47# 147' 2,429' 9,073' Gas-Oil Ratio:Choke Size:Water-Bbl: PRODUCTION TEST Not on Production Date of Test: Flow Tubing Oil-Bbl: suspension, or abandonment, whichever occurs first. Types of logs to be listed include, but are not limited to: mud log, spontaneous potential, gamma ray, caliper, resistivity, porosity, magnetic resonance, dipmeter, formation tester, temperature, cement evaluation, casing collar locator, jewelry, and perforation record. Acronyms may be used. Attach a separate page if necessary N/A ***Please see Schematic for Detail*** ROP, ABR, DGR, ADR MD & TVD Sr Res EngSr Pet GeoSr Pet Eng Oil-Bbl: Water-Bbl: 5/13/2021 5/8/2021 ADL 025906, 025517, 025515 & 025514 88-005 2,125' / 1,930' 9,073' / 3,764'N/A None 17,630' / 3,606' Form 10-407 Revised 3/2020 Submit within 30 days of Completion, Suspension, or Abandonment By Samantha Carlisle at 8:58 am, Jun 22, 2021 RBDMS HEW 6/28/2021 Completion Date 5/23/2021 HEW G DSR-6/28/21 SFD 6/29/2021 MGR07JUL2021 DLB 06/28/2021 Conventional Core(s): Yes No Sidewall Cores: 30. MD TVD Top of Productive Interval 9125' 3773' 9125' 3773' SB NB 9125' 3773' 31. List of Attachments: 32. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Name: Joe Lastufka Contact Email:joseph.lastufka@hilcorp.com Authorized Contact Phone: 777-8400 General: Item 1a: Item 1b: Item 4b: Item 9: Item 15: Item 19: Item 20: Item 22: Item 23: Item 24: Item 27: Item 28: Item 30: Item 31: If Yes, list formations and intervals cored (MD/TVD, From/To), and summarize lithology and presence of oil, gas or water (submit separate pages with this form, if needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071. Authorized Name: Monty Myers Authorized Title: Drilling Manager Permafrost - Base 29. GEOLOGIC MARKERS (List all formations and markers encountered): FORMATION TESTS Permafrost - Top Schrader Bluff NB This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed. All laboratory analytical reports regarding samples or tests from a well must be submitted to the AOGCC, no matter when the analyses are conducted. Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, core analysis, paleontological report, production or well test results, per 20 AAC 25.070. Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. TPI (Top of Producing Interval). Yes No Well tested? Yes No 28. CORE DATA If yes, list intervals and formations tested, briefly summarizing test results. Attach separate pages to this form, if needed, and submit detailed test information, including reports, per 20 AAC 25.071. NAME Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data within 90 days of completion, suspension, or abandonment, whichever occurs first. Well Class - Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Formation at total depth: LOT / FIT Data Sheet, Drilling and Completion Reports, Definitive Directional Survey, Wellbore Schematic Signature w/Date: Report the Division of Oil & Gas / Division of Mining Land and Water: Plan of Operations (LO/Region YY-123), Land Use Permit (LAS 12345), and/or Easement (ADL 123456) number. INSTRUCTIONS The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and other tests as required including, but not limited to: core analysis, paleontological report, production or well test results. Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29. Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity, permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology. Form 10-407 Revised 3/2020 Submit within 30 days of Completion, Suspension, or Abandonment 6.22.2021Digitally 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: 2021.06.22 08:54:31 -08'00' Monty M Myers _____________________________________________________________________________________ Revised By: JNL 6/16/2021 SCHEMATIC Milne Point Unit Well: MPU J-29A Last Completed: 5/23/2021 PTD: 221-023 TD =17,630’(MD) /TD=3,606’ (TVD) 20” Orig. KB Elev.: 60.20’ / GL Elev.: 33.70’ 7-5/8” 9/10 13 4/5 18 9-5/8” 1 2 3 See Screen/ Solid Liner Detail PBTD =12,861’ (MD) / PBTD= 3,671’ (TVD) 9-5/8” ‘ES’ Cementer @ 2,406’ MD 6/7/8 4-1/2” Shoe @ 12,861’ 11 14 12 15/16 17 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20" Conductor 129.5 / X52 / Weld N/A Surface 147’ N/A 9-5/8" Surface 47 / L-80 / TXP 8.681 Surface 2,429’ 0.0758 9-5/8” Surface 40 / L-80 / TXP 8.835 2,429’ 9,073’ 0.0732 7-5/8” Tieback 29.7 / L-80 / Hyd 521 6.875 Surface 8,360’ 0.0459 4-1/2” Liner 13.5 / L-80 / Hyd 625 3.920 8,347’ 12,863’ .0149 TUBING DETAIL 3-1/2" Tubing 9.3# / L-80 / EUE 8rd 2.992 Surface 7,907’ 0.0087 OPEN HOLE / CEMENT DETAIL Driven 20” 12-1/4"Stg 1 Lead – 1015 sx / Tail – 400 sx Stg 2 Lead – 730 sx / Tail 270 sx 8-1/2” Cementless Screened Liner WELL INCLINATION DETAIL A KOP @ 9073’ Max Hole Angle = 97 deg @ 9680’ TREE & WELLHEAD Tree Cameron 3-1/8" 5M w/ 3-1/8” 5M Cameron Wing Wellhead Cameron 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs GENERAL WELL INFO API: 50-029-23688-01-00 Drilled and Completed by Doyon 14 1/11/21 A Sidetrack (Innovation): 5/23/2021 JEWELRY DETAIL No. Top MD Item ID 1 126’ 3-1/2” x 1” GLM w/ DPSOV 2.907” 2 7,645’ 3-1/2” x 1” GLM Dummy Valve w/ BK Latch 2.907” 3 7,765’ XN Nipple 2.813” Profile, 2.75” No Go 2.760” 4 7,807’ Discharge Head: 400 Mach B/O 3.5 EUE 5 7,808’ Zenith Ported Sub: Press Port 400P 6 7,855’ Pump: 400PMSXD 24 GINPPSH H6 STD PNT 7 7,865’ Gas Separator: 538GSTHVEV H6 STD PNT WC ENH 8 7,871’ Intake 9 7,872’ Upper Tandem Seal: GSBDB H6 SB/AB PFSA 10 7,879’ Lower Tandem Seal: GSBDB H6 SB/AB PFSA 11 7,886’ Motor: 562XP – 250 HP / 2505V / 61A 12 7,902’ Motor Gauge: Zenith E7 13 7,905’ Centralizer: P/N C63569: Bottom @7,907’ MD 14 8,347’ 7” x 9-5/8” SLZXP Liner top packer (3,680’ TVD) 6.160” 15 8,349’ Locator Sub, 7” TC-II Box x Box 6.180” 16 8,350’ Bullet Seals (TBSA), Mule Shoe (4 – 1” holes) 6.180” 17 8,457’ Bowen HP casing patch 3.820” 18 12,861’ Shoe 4-1/2” 250ђ SCREENS LINER DETAIL Jts Top (MD) Top (TVD) Btm (MD) Btm (TVD) 19 8543’ 3702’ 9335’ 3798’ 4 9418’ 3802’ 9583’ 3799’ 5 9748’ 3783 9958’ 3769’ 3 10038’ 3767’ 10164’ 3765’ 56 10491’ 3759’ 12822’ 3674’ PERMAFROST DETAIL Bottom = 2,161’ MD / 1,955 TVD D = 1 7,630’7 12,861’ TOWS 9,073' MD 9-5/8" shoe @ 9,318' MD CASING AND LEAK-OFF FRACTURE TESTS Well Name:MPU J-29A Date:5/8/2021 Csg Size/Wt/Grade:9.625"40# x 47#, L-80 Supervisor:Yessak/Montgue Csg Setting Depth:9093 TMD 3768 TVD Mud Weight:10.05 ppg LOT / FIT Press =392 psi . LOT / FIT =12.05 ppg Hole Depth =9113 md Fluid Pumped=1.1 Bbls Volume Back =1.0 bbls Estimated Pump Output:0.062 Barrels/Stroke LOT / FIT DATA CASING TEST DATA Enter Strokes Enter Pressure Enter Strokes Enter Pressure Here Here Here Here ->00 ->00 ->20 ->221 ->433 ->6125 ->685 ->12 343 ->8 139 ->18 552 ->10 190 ->20 635 ->12 242 ->30 1006 ->14 289 ->40 1415 ->16 339 ->44 1580 ->18 392 -> -> -> -> -> -> -> -> -> Enter Holding Enter Holding Enter Holding Enter Holding Time Here Pressure Here Time Here Pressure Here ->0 392 ->0 1580 ->0.25 361 ->2 1575 ->0.5 354 ->4 1571 ->0.75 351 ->6 1568 ->1 347 ->8 1566 ->1.5 339 ->10 1565 ->2 334 ->12 1565 ->3 326 ->14 1565 ->4 318 ->15 1565 ->5 312 -> ->6 306 -> ->7 300 -> ->8 295 -> ->9 289 -> ->10 285 -> -> 024 6 8 10 12 14 16 18 0 2 6 12 18 20 30 40 44 0 100 200 300 400 500 600 700 800 900 1000 1100 1200 1300 1400 1500 1600 1700 1800 1900 2000 2100 2200 2300 2400 2500 2600 2700 2800 2900 3000 0 1020304050Pressure (psi)Strokes (# of) LOT / FIT DATA CASING TEST DATA Pressure (psi) 392361354351347339334326318312306300295289285 1580 1575 1571 1568 1566 1565 1565 15651565 0 100 200 300 400 500 600 700 800 900 1000 1100 1200 1300 1400 1500 1600 1700 1800 1900 2000 2100 2200 2300 2400 2500 2600 2700 2800 2900 3000 0 5 10 15 20 25 30 35Pressure (psi)Time (Minutes) LOT / FIT DATA CASING TEST DATA Activity Date Ops Summary 5/8/2021 RIH with whipstock assembly on 5" drill pipe from 6766' to 7084'. RIH with 4 stds 6 1/4'' DCs to 7330' then 10 stds 5'' HWDP to 7670', continue RIH with stds 5'' DP to 9035', M/U std 128 and top drive. Correct displacement TIH. Sim Ops: load and process 5" drill pipe in pipe shed.,Break circulation, pump 415 gpm, 1020 psi. Work pipe 30' orienting WS 45 deg left, M/U single, continue to pump 415 gpm, verify 45 deg left. RIH tag BP @ 9104', continue to S/O setting 13k shearing anchor pin, P/U to 170k, P/U additional 2', set down confirm anchor set. Work pipe attempting to shear bolt PU 150K and SO to 30k. PU 170K, SO 83K. Note: Seen a fair amount of sand and crude oil @ BU, Max gas 521u,Pump and spot 40 bbl 7% NXS lube pill on backside, 415 gpm, 1020 psi. With pump off work pipe several more times setting down 10k and PU to 185k, P/U 40' to 8924', establish rotation 15 rpm @ 9500 free torque, L/D single M/U std and TD. Top WS @ 9073.02',Establish parameters, wash down tagging top of whipstock @ 9073', TOW. Mill 8.5" window in 9-5/8" casing T/ 9093' BOW and 20' of new hole to 9113' at 415 gpm, 1020 psi, 80 rpm, 9-13k tq, 2-5k wt on mill. Seeing a good amount of metal at shakers and on magnets. Pump 40 bbl hi vis sweep @ 9079' (20% increase), 9091'(20% increase), and 9110' (no increase). All sweeps back on time; increase in metal, some cement.,Circulate hole clean while working mills though window. Work through 3.5X with rotary/pumps, without rotary, and without rotary pumps 2-3K drag as bottom mill exits window. Flow check well, static. Max gas 130u. PU 160k, SO 102k, ROT 126K,Rig up and perform FIT. Flood and purge lines. Shut UPR's, Perform FIT to 12.0 ppg EMW with 10.05 ppg drilling fluid. Pumped 1.1 bbls, bled back 1.0 bbls. Blow down choke and kill lines.,Monitor well, static. POOH from 9073' to 8760', no indication of swabbing. Pump dry job. Continue to POOH to 7655'. PUW 162K, SOW 105K. Calculated displacement.,Cont. to POOH from 7655' to 62' with milling assembly, laying down drill collars. Calculated displacement observed.,L/D BHA; TM collar, DM collar, float sub, watermelon mill, flex joint, Tri-mill. Starter mill 1/8" under gauge, middle mill 1/16" under gauge, top mill in gauge.,Clean and clear rig floor. Pull wear ring.,Final report for Pre-Drill WBS. Swap to Drilling. Daily disposal to G&I 57 bbls, total= 1583 bbls. Daily water from 6 mile lake 80 bbls total= 1660 bbls. Daily Metal 145 lbs, total= 145 lbs. Daily fluid lost 0 bbls, total= 508 bbls. 50-029--23688-00-00API #: Well Name: Field: County/State: MP J-29 Milne Point Hilcorp Energy Company Composite Report , Alaska Activity Date Ops Summary 5/9/2021 M/U Flush tool, jet the BOP stack, L/D flush tool, re-install 9'' ID wear bushing, RI4LDS PJSM, Load rig floor with BHA components. P/U M/U 8.5" PDC SK616M- J1D Bit 6X13 (0.7777 TFA), NRP, Geo Pilot,, ADR, 8.375" ILS, DGR, PWD, DM, TM HOC, FS (piston / Non Ported), Plug in and initialize tools. Simops: PT MPD lines to 300 and 1400 psi, blow down same. M/U 8.375" Integral Blade, FS, (piston / Non Ported), NMFC, corrosion ring, NMFC, 4 JTS 5'' HWDP, Jar, 3 jts 5'' HWDP= 404.57. Shallow pulse test MWD, BD TD. Drift, P/U and single in the hole with 5'' DP f/ 404' to 2513', fill DP, break in geo pilot seals, continue to single in to 8987', fill DP every 2500'. PUW 160K, SOW 80K Hang blocks. Slip and cut 75' of drill line. Check air gap on brakes, good. Service rig: grease crown, blocks, top drive, washpipe, drawworks, iron roughneck, spinners, cobra heads. check oil on top drive. Inspect welds on top drive cradle. Perform derrick inspection. Drain stack, remove clamp and pull trip nipple. Install MPD bearing. Flood lines and inspect - good. P/U stand and RIH to 9050'. Displace to 8.9 ppg Baradril-N, pump high vis spacer followed by Baradril-N at 500 gpm, 1660 psi. Obtain new parameters/SPR's. PUW 140K, SOW 58K, ROT 95K, 500 gpm, 1565 psi. clean ECD 10.3 ppg EMW. Wash down at 205 gpm to 9113'. Observe 3-5K drag through window with 10K bobble. Drill 8-1/2" lateral from 9113' to 9620' (Total = 507', AROP =85 fph) at 400 gpm, 1310 psi, WOB 8-12K, 120 rpms, 14-15Kft-lbs, max gas 1674U, ECD 10.5 ppg EMW with 8.9 ppg mud. PUW 142K, SOW62K, ROTW 95K. First clean survey at 9424'. Acquired NB sands at 9125', exited bottom at 9,243'. Geo-Pilot has been 100% deflected at 30L (~3°/100' DLS) to build angle to reacquire sands and gain separation for anti-collision as we approach MP J-29 at 9998' 118' Drilled into NB sand, 339' drilled out of zone. Distance to WP05 at 9615'MD: 23.38', 8.23' Low, 21.89' Right Daily disposal to G&I 1057 bbls, total= 2640 bbls. Daily water from 6 mile lake 160 bbls total= 1820 bbls. Daily Metal 5 lbs, total= 150 lbs. Daily fluid lost Production interval 0 bbls, total= 0 bbls. Fluid lost on Pre-Drill = 508 bbls. 5/10/2021 Drill 8-1/2" production hole f/ 9620' t/ 10129' MD / 3769' TVD (509' drilled) 84.8'/hr AROP. 500 GPM, 1830 PSI, 120 RPM, 16-17K TQ, 4-9K WOB. MW 9 PPG / vis 49 / ECD 11, max gas 1764u. 140K PU / 56K SO / 90K ROT. MPD hold 150 psi on connections, 150 psi back pressure drlg. Target 96 deg, Back in the NB sand @ 9798' MD, ( 555' out of zone ) target 91-92 deg. Increase lube from 1.5 to 2% adding 4 drums NXS lube lowering tq f/ 17-18k to 14-15k Drill 8-1/2" hole f/ 10129' t/ 10725' MD (596' drilled) 99.3'/hr AROP. 400 GPM, 1400 PSI, 140 RPM, 11-12K TQ, 5-15K WOB. MW 9 PPG / vis 47 / ECD 11.2, max gas 1864u. 139K PU / 57K SO / 90K ROT. MPD hold 250 psi on connections, 165 psi back pressure drlg. Pump 40 bbl hi vis sweep @ 10500', back on time w/ 100% increase. Drill in NB sand, target 91-92 deg Drill 8-1/2" hole f/ 10725' t/ 11400' MD (675' drilled) 112.5'/hr AROP. 400 GPM, 1375 PSI, 140 RPM, 11-12K TQ, 5-15K WOB. MW 9 PPG / vis 47 / ECD 11.1, max gas 1444u. 141K PU / 57K SO / 91K ROT. MPD hold 250 psi on connections, 150 psi back pressure drlg. Drill 8-1/2" hole f/ 11400' t/ 11874' MD (474' drilled) 79'/hr AROP. 350 GPM, 1200 PSI, 90 RPM, 9-10K TQ, 6-12K WOB. MW 9 PPG / vis 47 / ECD 10.9, max gas 1645u. 144K PU / 54K SO / 91K ROT. MPD hold 250 psi on connections, 150 psi back pressure drlg. At 11,509' start 3.5°/100 plan turn with 100% deflected at 70R, increasing to 85R with only 1.98° turn and 2.5° drop rate. Discuss projection with HES/town, continue drilling ahead on a survey to survey basis. Survey at 11,712' shows 4.2°/100 (stand drilled with slower ROP to clean well at ~80 fph) slowed ROP to 80fph at 11,655' to 11,716', with heavy sand and gas causing mud to go over the shakers. Exited NB sand at 11,717'. Total footage drilled in NB sand= 2037', total footage drilled out of zone 820'. Distance to WP05 at 11,776'MD: 26.61', 21.68' High, 15.42' Left Daily disposal to G&I 1197 bbls, total= 3837 bbls. Daily water from 6 mile lake 1040 bbls total= 2860 bbls. Daily Metal 60 lbs, total= 210 lbs. Daily fluid lost Production interval 0 bbls, total= 0 bbls. Fluid lost on Pre-Drill = 508 bbls. 5/11/2021 Drill 8-1/2" hole f/ 11874' t/ 12099' MD (225' drilled) 90'/hr AROP. 375 GPM, 1240 PSI, 110 RPM, 11-12K TQ, 7K WOB. MW 8.9 PPG / vis 44 / ECD 10.9, max gas 958u. 146K PU / 54K SO / 91K ROT. MPD hold 250 psi on connections, 150 psi back pressure drlg. NC top logged @ 11,943’ md / 3,733’ tvd, build and turn as we can, currently getting 3-4 deg doglegs while out of zone, target 96 deg. During connection at 12035' 2 floats not holding @ BHA, circulate 377 gpm, 1250 psi, work pipe, mix and pump 30 bbl, 30 ppb walnut sweep around successfully clearing debri in floats. Drill 8-1/2" hole f/ 12099' t/ 12300' MD (201' drilled) 80.4'/hr AROP. 400 GPM, 1240 PSI, 130 RPM, 12-13K TQ, 7-15K WOB. MW 8.9+ PPG / vis 45 / ECD 11, max gas 1135u. 151K PU / 52K SO / 93K ROT. MPD hold 250 psi on connections, 150 psi back pressure drlg. Pump 40 bbl hi vis sweep @ 12250', back 25 bbls late with 10% increase. Continue to build and turn targeting 96 deg, NC base logged @ 12,210‘ md / 3,729’ tvd. Note: periodically mix and pump 30 bbl, 30 ppb walnut sweep around to clear debris from floats Drill 8-1/2" hole f/ 12300' t/ 12801' MD (501' drilled) 83.5'/hr AROP. 450 GPM, 1660 PSI, 130 RPM, 12-13K TQ, 5-15K WOB. MW 9 PPG / vis 44 / ECD 11,3 max gas 822U. 140K PU / 49K SO / 90K ROT. MPD hold 250 psi on connections, 130 psi back pressure drlg. Crossed fault at 12,459' with 20' DTE throw. Drill 8-1/2" hole f/ 12801' t/ 13341' MD (540' drilled) 90'/hr AROP. 430 GPM, 1700 PSI, 130 RPM, 14-15K TQ, 10-17K WOB. MW 9.05 PPG / vis 46 / ECD 11,4 max gas 1224U. 145K PU / 91K ROT, lost SOW at 13,119'. MPD hold 250 psi on connections, 130 psi back pressure drlg. Reacquired NB sands at 12,841'. Drill 8-1/2" hole f/ 13341' t/ 13893' MD (552' drilled) 92'/hr AROP. 475 GPM, 1970 PSI, 120RPM, 16-17K TQ, 7-12K WOB. MW 9.05 PPG / vis 46 / 11.8 ppg ECD max gas 1127. 151K PU / N/A SO / 83K ROT, lost SOW at 13,119'. MPD hold 250 psi on connections, 130 psi back pressure drlg. Pumped two 5% Drill n Slide water sweeps to clean float due to leaking. First one 5 bbls, unsuccessful, second 12 bbls - floats holding. Crossed fault at 13,573 with 12' DTE throw from NB sand to NB clay. Reacquired NB sands at 13,714' Total footage drilled in NB sands = 2861', footage out of zone 1846'. Drilled 5 concretions for a total thickness of 13' (0.3% of the lateral). Two faults have been crossed in the lateral: 12,459', 13,573'. Distance to WP#05 at survey 13,682': 11', 10' high, 4' left Daily disposal to G&I 1254 bbls, total= 5091 bbls. Daily water from 6 mile lake 960 bbls total= 3820 bbls. Daily water from Duck lake 300 bb s total= 300 bbls. Daily Metal 35 lbs, total= 245 lbs. Daily fluid lost Production interval 0 bbls, total= 0 bbls. Fluid lost on Pre-Drill = 508 bbls. Well Name: Field: County/State: MP J-29A Milne Point Hilcorp Energy Company Composite Report , Alaska 50-029-23688-01-00API #: 5/12/2021 Drill 8-1/2" hole f/ 13,893 t/ 14,451' MD (558' drilled) 93'/hr AROP. 400 GPM, 1610 PSI, 120RPM, 17-18K TQ, 10K WOB. MW 9.1 PPG / vis 46 / 11.6 ppg ECD max gas 1848. 149K PU / N/A SO / 83K ROT MPD hold 250 psi on connections, 115 psi back pressure drlg. Drill in the NB sand, target 93 deg. Pump 40 bbl Hi Vis Sweep, 50% increase at shakers, back 25 bbls late. Fault 5 at 14,314' 12' DTE in NB Clay. Fault 6 at 14,370' 6' DTE in NB Clay Drill 8-1/2" hole f/ 14,451 t/ 14,834' MD (383' drilled) 64/hr AROP. 440 GPM, 1845 PSI, 120-130 RPM, 20-21K TQ, 10-17K WOB. MW 9.2 PPG / vis 46 / 11.6 ppg ECD max gas 718. 148K PU / N/A SO / 85K ROT MPD hold 250 psi on connections, 0 psi back pressure drlg starting @ 14,575'. Control Drill & CBUx2 @ 75'-125 FPH f/14,703' - 14,834' to mitigate high ECD's. Start @ 12.0 end @ 11.8 ECD. Back in NB Sand at 14,757' MD. Cont Drill 8.5" Production Hole F/ 14,834' to 15,375' MD ( 3,556' TVD) Total 541’ (AROP 90.2’) 390-430 GPM/ MPD 382-420, 1,895 PSI, 80-120 RPM, TRQ on 20-21K, TRQ off 18-20K, WOB 10-18K. ECD 11.9. Max Gas 1126U. P/U 154K, SLK 35K, ROT 86K. Increase lube 0.5% at 15,265' MD Reduced TRQ F/ 21.5K to 18K. Adjusting flow and ROP rates to control ECD's <12 ECD. Encountered close approach M-19 @ 15,573' MS 199' CC. MPD 0 PSI dynamic, static 250 PSI 10.5 EMW static. SPR at 15,023' MD.. Cont Drill 8.5" Production Hole F/ 15,375' to 15,860' MD ( 3,548' TVD) Total 485’ (AROP 80.9’) 390-420 GPM/ MPD 378-405, 1,750 PSI, 80-120 RPM, TRQ on 18-19K, TRQ off 16-17K, WOB 5-20 K. ECD 11.8. Max Gas 1552U. P/U 167K, SLK 35K, ROT 68K. Cont undulate in N Sand as per Geo. Adjusting paramters to control ECD's <12 ECD. MPD 0 PSI dynamic, static 250 PSI 10.5 EMW static. SPR at 15,532' MD.. Total footage drilled in NB sands = 4,418', footage out of zone 2,289'. Drilled 14 concretions for a total thickness of 75' (1.1% of the lateral). 4 faults crossed in the lateral: 12,459', 13,573', 14,314, 14,370'. Distance to WP#05: 9.66', 50.83' high, 24.1' left Daily disposal to G&I 1212 bbls, total= 6303 bbls. Daily water from 6 mile lake 880 bbls total= 4700 bbls. Daily water from Duck lake 0 bb s total= 300 bbls. Daily Metal 20 lbs, total= 265 lbs. Daily fluid lost Production interval 0 bbls, total= 0 bbls. Fluid lost on Pre-Drill = 508 bbls. 5/13/2021 Cont Drill 8.5" Production Hole F/ 15,860' to 16,485' MD ( 3,550' TVD) Total 625’ (AROP 104’) 390-450 GPM/ MPD 378-434, 1,940 PSI, 80-120 RPM, TRQ on 19- 20K, TRQ off 17-18K, WOB 10-15K. ECD 11.8. Max Gas 1587U. P/U 158K, SLK 35K, ROT 84K. Cont undulate in N Sand as per Geo. Cont Drill 8.5" Production Hole F/ 16,485' to 17,060' MD ( 3537' TVD) Total 575’ (AROP 96’) 490 GPM/ MPD 472 , 2,365 PSI, 80-120 RPM, TRQ on 20-21K, TRQ off 18-19K, WOB 10-18K. ECD 11.98. Max Gas 1524U. P/U 164K, SLK 35K, ROT 85K. Cont undulate in N Sand as per Geo. Cont Drill 8.5" Production Hole F/ 17,060' to 17,312' MD ( 3553' TVD) Total 252’ (AROP 42’) 460 GPM/ MPD 450 , 2,141 PSI, 80-120 RPM, TRQ on 20-21K, TRQ off 17-20K, WOB 10-20K. ECD 11.5. Max Gas 1566U. P/U 160K, SLK 35K, ROT 85K. Mob and process extra D.P. F/ D Pad. At 17058' decision was made to start dropping inclination to 83° for geological exploration. As soon as we started to make the drop the assembly started having a hard time drilling down across the sand. F/ 17,150’ to 17,208’ MD encountering concretions. At 17184' geo requested to drop to 80°. Attempted to turn down W/ 90 % deflection adjusting parameters and sending GeoPilot to home to be able to transition to 80° called by Geo. WOB 5-20K 80-120 rpm, 400-450 GPM, TRQ on 24-25K TRQ off 19-20K ROP 1-15 fph. Cont Drill 8.5" Production Hole F/ 17,312' to TD 17,630' MD ( 3,605' TVD) Total 318’ (AROP 70.6’) 450 GPM/ MPD 433 , 2,125 PSI, 100 RPM, TRQ on 21-22K, TRQ off 20-21K, WOB 5-10K. ECD 11.8. Max Gas 857U. P/U 182K, SLK 35K, ROT 85K. Drill to TD as per Geo. Perform final survey and send to home. Close approach to M-43 PB 3 at 17,448’ MD 33’ CC. Perform clean up cycles. Pump tandem 45 bbl 8.7 ppg 36 vis, 40 bbl 10.6 ppg 130 Vis. BROOH F/ 17,630' to 17,565' MD. 450 GPM/ MPD 433 , 2,100 PSI, 120 RPM, TRQ 19.5- 20.5K,. ECD 11.7. Max Gas 753U. P/U 182K, SLK 35K, ROT 85K. Total footage drilled in NB sands = 5,848', footage out of zone 2,689'. Drilled 20 concretions for a total thickness of 122' (1.5% of the lateral). 4 faults crossed in the lateral: 12,459', 13,573', 14,314, 14,370'. Distance to WP#05: 275.91', 238.94' high, 137.96' left Daily disposal to G&I 1373 bbls, total= 7,676 bbls. Daily water from 6 mile lake 1,280 bbls total= 5980 bbls. Daily water from Duck lake 0 bb s total= 300 bbls. Daily Metal 10 lbs, total= 275 lbs. Daily fluid lost Production interval 0 bbls, total= 0 bbls. Fluid lost on Pre-Drill = 508 bbls. 5/14/2021 Cont circ. 4X BU while back reaming BU per stand to 17,124’ MD. 500 GPM/ MPD 489, 2,400 PSI, 120 RPM TRQ 19-21K, ECD 12. Tandem sweep back 50 bbls late W/ 25% increase at shakers. Dynamic loss 20 bbls. SIMOPS trouble shoot DSU on Drawworks and C/O DSU #2 due to blower fan failure. PJSM Rot & Rec F/ 17,120’ to 17,055’ MD Perform displacement F/ 9.2 ppg BaraDril to 9.3 ppg QuickDril. Pump 3 ea 40 bbls SAPP pil W/ 20 bbls 9.3 QuickDrill in-between. Chase W/ 9.3 ppg QuckDrill 1.5% Lubricated Brine at 9 bpm 1020 PSI 110 RPM TRQ 22K. Max Gas 819u. SAPP Pills 125 bbls late. Dynamic loss rate 10 bph. PJSM Take returns back to pit 5. Off load mud F/ pits. Take on new QuickDril to pits. Cont Rot Rec 375 GPM/ MPD 321 1,020 PSI 100 RPM TRQ 25K Max Gas 817u. P/U 193K SLK 35K ROT 88K. SPR at 17,055’ MD. Monitor well, open MPD choke and flow decrease to 40 gpm after 5 min. Shut in MPD choke press built built to 105 psi over 5 min. PJSM BROOH F/ 17,055’ to 16,930’ MD. Full open choke returns at connection deceasing to 40 gpm. 400 GPM/ MPD 381 1,330 PSI 100 RPM TRQ 26K P/U 193K SLK 88K Circ and perform PST. Suction Pit 6.8, 7.2, 7.1 avg 6.79 pass, Flowline 6.9, 7.1, 7.3 avg 7.1 pass, 400 GPM/ MPD 381 1,330 PSI 100 RPM TRQ 26K. Max Gas 1,312u. PJSM BROOH F/ 16,930’ to 16,000’ MD 400 GPM/ MPD 350 1,300 PSI 120 RPM TRQ 25-28K P/U 190K SLK 35K ROT 88K Max Gas 283u. Closing MPD Choke 105 PSI static. Pull Speed 25-40 fpm. Dynamic losses 5-10 bph. Cont BROOH F/ 16,000 to 13,900’ MD 400 GPM/ MPD 350 1,220 PSI 120 RPM TRQ 25-28K 11.1 ECD P/U 190K SLK 35K ROT 88K Max Gas 756u. Closing MPD Choke 105 PSI static. Pull Speed 5-35 fpm. At 14,200’ MD saw increased TRQ F/ 25 to >27K. Increased lubes 0.5% to 2%. F/ 14,075’ MD encountered intermittent TRQ stalls (28.8K) 5-10K over pull W/ little pack off. At 13,933’ working pipe W/ TRQ stall and 40K over pull slight packing off to free pipe. At 13,907’ same stand worked same. Reamed stand back down W/ out issue. Ream back up at 13,933’ seeing TRQ stall prior to any over pull. Work same. Dropped rabbit on stand 237. Lost 63 bbls during BROOH. Dynamic losses 5-10 bph. PJSM Cont working tight hole at 13,933’ seeing TRQ stall (28.8K) prior to any over pull. Working up to 48K over pull W/ no packing off to get passed. Same issue at 13,907’ MD. L/D top jnt stand 213. Cont back reaming using TRQ 28-28.5K pull speed 1-5 fpm. Added 0.5% lubes total 2.5%. No issue packing off F/ 13,880’ to 13,651’ MD. Fault #6 at 14,370’, #5 at 14,314’ MD. Out of zone F/ 13,714 to 13,573’ MD no real geological reason for hole condition. At 13,651’ MD trq fell to 23K with Fault #4 at 13,573’ MD no real reason for trq to fall off. Cont BROOH F/ 13,651’ to 12,953’ MD 400 GPM/ MPD 374 1,220 PSI 120-135 RPM TRQ 19-21K P/U 187K SLK 35K ROT 103K Max Gas 1356u. At 12,948’ encountered packing off with no sign of trq or over pull. Seeing ballooning back. Able to Circ at 300 GPM 810 psi with no dynamic losses. At 12,953’ MD work on getting floats to hold cycling pumps. Daily disposal to G&I 2988 bbls, total= 10664 bbls. Daily water from 6 mile lake 800 bbls total= 6780 bbls. Daily water from Duck lake 0 bb s total= 300 bbls. Daily Metal 5 lbs, total= 280 lbs. Daily fluid lost Production interval 172 bbls, total= 172 bbls. Fluid lost on Pre-Drill = 508 bbls. 5/15/2021 Cont. BROOH F/ 12953' to 11116' MD, 400 gpm, 1050 psi, 120 rpm, 19-21k tq, rot 90k observed 4-7k tq and pressure spikes from 12578' to 12260' MD, slowed down to 5-8 fpm and pumped 2 bu while pulling slow, @ 12260' md was able to pull 30-50 fpm with no issues, PU 157K SLK 60K 25 bbl lost. Cont. BROOH F/11,116' to 9,400' MD 400 GPM 1050 PSI 120 RPM 19-28K TRQ, ROT 90k, observed 4-7K TRQ and pressure spikes @ 9850' MD W/ loss of returns, slowed down to 3 FPM and Circ 1 BU while pulling slow, Max Gas - 1337u. At 9,500 MD slowed rotary to 30 RPM TRQ 22k. At 9,400' MD stopped rotary and pulled jars thru - once jars in window Cont rotary at 30 rpm to 9,200' MD. Pulled remaining BHA thru w/out rotary seeing 10-20k overpull drag to 9,010' MD. BROOH at 50 ft/min or as hole dictated, trap 160 psi during connections, once in casing bleed off wellbore press for 5min and shut in for 5 min 3x, 120psi, 105 psi, 95 psi, co man decide to WT up to 9.8 ppg MW. Lost 133 bbls. PJSM Pump low 8.8 ppg 30 vis & high WT 10.3 ppg 125 vis sweeps followed by weighting up pit 5 and downhole fluid to 9.85 ppg. Max Gas 326u BGG 32u after WT up. Sweeps came back on time w/ 10% inc in cuttings, monitor well 10 min flow back 4.7 bbs. shut in MPD for 5 min press built F/ 17 psi to 73 psi. open MPD monitor well 10 min flow 3.9 bbls. shut in MPD 5 min built F/ 16.4 to 68 psi. open MPD monitor flow 10 min 2.8 bbls trending down. Well appears to be ballooning. PST Flowline 9.02, 9.12, 8.96 avg 9.03. Suction 9.9, 9.9, 9.85 avg 9.88. PJSM Remove RCD head. Back out grey clamp, pull riser and RCD bearing. Remove RCD bearing w/ beyond pulling tool. Install trip nipple. Cont monitor well ballooning initial flow 26.2 bph slowing to 16.8 bph. PJSM Rack back two stands F/ 9,090' to 8,964' MD. P/U 191K SLK 66K. P/U M/U Model B RetrievOmatic 9 5/8 packer (40 & 47#) as per baker rep onsite. Verify pin set 3 pins and check die blocks for setting. RIH W/ 1 stand to 75' and attempt to set W/ ¾ & 4 ea ½ LH turns working F/ 200K P/U slack to 47K multiple times. Pull out of hole and check packer blocks od, good. Set packer for 1/2 turn left hand. RIH and was able to set at 65'. Back out running tool 9 turns and L/D. PT packer to 500 psi for 5 min, good. Monitor well ballooning slowing to 13.7 bph. PJSM P/U 5” D.P. M/U wear ring puller. BOLDS pull wear bushing. P/U M/U Johnny Wacker and clean stack. 625 GPM, 140 PSI. Set Test Plug. PJSM R/U M/U 5" TIW, 5" Dart to 5" test jnt. R/U hp test equip. M/U test sub to top drive. PJSM Test W/ 5” test jnt to 250 PSI low and 3000 PSI high 5/5 min on chart. Test Annular, Mez Kill, CMV 11-15, 5" Dart, Upper IBOP. Witnessed by AOGCC Rep Adam Earle. PJSM Cont BOPE test W/ 3.5" & 5" to 300 PSI low and 3,000 PSI high for 5/5 Min. Tested Choke Manifold 1-10, 5" TIW, lower IBOP, HCR and manual Choke and Kill, manual and Super Choke to 1,600 PSI, Upper and lower VRB Rams (2.875" X 5.5") Blind Rams & Annular. Test H2S 10-20 ppm, LEL 20-40%, PVT high/ low level alarms. Checked PVT sensors and return flow. Koomey draw drown Initial System 2,900 PSI, Manifold 1,250 PSI, Annular 1,300 PSI, after System 1,400 PSI, Man 1,375 PSI, Annular 1,275 PSI. 200 PSI increase 28 Sec, full charge 108 sec. Nitrogen 6 bottle average 2,358 PSI. Witnessed by AOGCC Rep Adam Earl. PJSM R/D Test Equip. Pull test plug and set wear ring. PJSM M/U TIW to stand. M/U Baker X/O Twin Thread Over Shoot as per Baker rep onsite. Screw into RetriveOmatic W/ 22 turns engaging equalizer. Open TIW no Press. Close Annular. P/U to release packer. P/U WT 200K. Monitor choke 33 psi. Bleed down, shut back in 5 min build 27 PSI. Open choke for 10 min initial flow rate 20 bph tapering down to 8.4 bph. Shut in choke for 5 min Press built to 20 PSI. Open Choke and Annular seeing slight flow. Turn string 1 turn to set packer to run position. Pull packer out of hole and lay down. Swabbing while pulling packer. P/U 200K SLK 56K Kelly up and CBU stage up F/ 166 GPM 270 PSI to 247 GPM 410 PSI. Daily disposal to G&I 798 bbls, total= 11462 bbls. Daily water from 6 mile lake 720 bbls total= 7500 bbls. Daily water from Duck lake 0 bb s total= 300 bbls. Daily Metal 10 lbs, total= 290 lbs. Daily fluid lost Production interval 158 bbls, total= 330 bbls. Fluid lost on Pre-Drill = 508 bbls. 5/16/2021 Continue to circulate weighting up from 9.8 ppg to 10 ppg, 240 GPM, 1080 PSI. Max gas @ 120u. Monitor well on TT observe ballooning. Finger print Flow and Gain on TT for 1 hour. Start 14.5 BPH diminishing to 5.4 BPH and falling. Bled total of 11 bbls back. RIH from 8891' to 9050'. (23' above TOW) P/U 203K, S/O 49K. Circulate STS @ 335 GPM, 760 PSI. Max Gas @ 80u @ BU, Treat light spot in to 10 ppg. Monitor Well on TT finger printing flow and gain on TT. Start 13.9 BPH, diminishing to 4.7 in 1 hour and falling. Bled back 10.7 bbls. POOH on elevators L/D DP from 9050 to 8660'. Well swabbing at 10 to 5 fpm pulling speed. See 10.4 bbl gain. Order out 290 bbls 11.0 ppg NaCl/ NaBr Pump Out of hole from 8660 to 8032' up into Tanagent section of casing. 4 bpm, 250 psi, 1.5 bbl loss from calculated displacement pumping out of hole. Pulling speed 60fpm, P/U 150-200K, S/O 55K Attempt to POOH on elevators L/D DP from 8032' to 7715'. Well swabbing at 10 to 5 fpm pulling speed. See 10.4 bbl gain. P/U 195K, S/O 55K. Pump Out of hole standing back DP from 7715' to 5425'. P/U 145K SLK 62K. Monitor Well on TT finger printing flow and gain on TT. Start 13.2 BPH, diminishing to 1.2 in 20 min. Bled back 3.7 bbls in 30 min. CBU F/ 5,452' to 5,394' MD L/D 1 jnt 5" D.P. 450 GPM 1,100 PSI 35 RPM TRQ 10.2-10.9K, FO 53% P/U 151K SLK 61K ROT 92K. Max Gas 12u. Lost 3 bbls. Cont to see swabbing and flow ~7.5 bph. Cont pump out L/D 5" D.P. F/ 5,394' to 3,900' MD. Staging pumps up F/ 1.6 to 4 BPM 250 PSI for displacement and swabbing. Pull speed 30 ft/min. Gain 9 bbls over displacement. Gained a total of 36 bbls for 12 hours. P/U 120K SLK 70K. Cont pump out L/D 5" D.P. F/ 3,900' to 2,946' MD. pump 4 BPM 250 PSI for displacement and swabbing. Pull speed 30 ft/ min. Calc Disp. P/U 120K SLK 70K. Monitor Well on TT finger printing flow and gain on TT. Start 4.8 BPH, diminishing to 3.6 BPH in 40 min. Bled back 2.5 bbls in 40 min. CBU at 450 GPM 965 PSI Max Gas 12u. PJSM Spot weighted 45 bbl 11 ppg NaCl/ NaBr pill off Vac Truck 5 BPM 150 PSI chase W/ 41.6 bbls 10 ppg QuickDril. Monitor Well on TT finger printing flow and gain on TT. Start 1.8 BPH, diminishing to 1.6 BPH in 20 min. Bled back .4 bbls in 20 min. POOH on elevators L/D 5" D.P. F/ 2,946' to 2,533' MD to get above first weighted pill. Seeing minimal swabbing. P/U 96K SLK 80K. Lost 1 bbl. Monitor Well on TT finger printing flow and gain on TT. Start 2.28 BPH, diminishing to 1.56 BPH in 30 min. Bled back .69 bbls in 30 min. Decision was made to spot another pill. Daily disposal to G&I 159 bbls, total= 11621 bbls. Daily water from 6 mile lake 80 bbls total= 7580 bbls. Daily water from Duck lake 0 bb s total= 300 bbls. Daily Metal 0 lbs, total= 290 lbs. Daily fluid lost Production interval 15 bbls, total= 345 bbls. Fluid lost on Pre-Drill = 508 bbls. 5/17/2021 Parked 2553’. Pump 95 bbls of 11 ppg Bromide at 5 bpm, 185 psi, spotting 50 bbls in annulus, shut down and monitor well with 3.5 bph loss rate. Chase Bromide with 10 bbls 10 ppg Quick Drill brine to clear surface lines. POOH on elevators L/D DP from 2533’ to 404’. Rack back 3 tds of 5” HWDP and L/D Jars and single to 156’. Disp Calc 23 bbls, Actual 30 bbls, 7 bbl loss. L/D 2 NM Flex Collars, 2 floats and IBS, recover drift in first float sub. Perform Down Load MWD. L/D TM/DM & ADR assy. Break Bit NRP and L/D Geo Pilot. Bit Grade:3-5-BT-A-X-I-WT-TD Clean and clear rig floor. Stage completion tools and equipment on floor. Rig up to run lower production screen completion. PJSM Service rig. Grease crown, TD, Spinners, Iron roughneck and blocks. Upper section Derrick inspection. PJSM P/U R/U Weatherford handling 4.5" Equip. Power Tongs, air slips, 125T elevators. SIMOPS load shed W/ remaining 4.5" slick jnts. PJSM P/U Eccentric Shoe jnt 2 ea cent 4 ea stop rings 10' F/ ends. Cont RIH W/ Baker 250u micron screens W/ 1 cent mid jnt & 4.5" 13.5# L-80 W625 Liner as per tally to 8,177' MD. TRQ 9.6K. No losses. P/U 125K SLK 60K. Correct count left over pipe. 65 screens, 22 slicks. PJSM C/O elevators to 5". P/U M/U SLZXP Liner Top Packer as per Baker Rep onsite. Verify DG Slips 9 ea 7/16" shear 44.1K, HST 6 ea 1/2" shear 1,986 psi Neutralizer 11 ea 1/2" 3,296 PSI. RIH 1 satnd Pump at 2 bpm 50 PSI good. Monitor well TT 1.6 bph flow back. L/D Weatherford Equip. Cont RIH W/ 5" D.P. F/ Derrick F/ 8,882' to 9,006' MD (TOW 9,073' MD) Attempt to rotate 10 RPM TRQ stall set 8.5K, stall when pipe not moving. P/U 135K SLK 58K. Calc 7 bbls, Actual 10 bbls, gain 3 bbls. Cont RIH W/ 5" D.P. to 9,006' to 9,108' MD (14 Stands). Cont Single in hole W/ 5" HWDP F/ 9,108' to 12,858' MD. (2.75" Drift) Initial running speed 90 ft/min. Seeing 10-20K drag. P/U 135K SLK 82K. At 11,750' MD set down to 38K string WT. Adjusted running speed to 25 ft/min 7-9K drag F/ 11,950' to 12,240' MD. String weight decreasing at 12,240' W/ 20-30K drag, SLK 48K. Out of zone at 11,723'- 11,945', 12,459-12841' MD. Calc 67 bbls, actual 64 bbls Lost 3 bbls. At 12,858' MD made hook lost down weight. Work pipe W/ string weight. F/ 12,858' to P/U 256K. At 12,858' MD made hook lost down weight. F/ 12,858' to 12,893' MD Working pipe 280K to block weight (35K) . Wrap 5K TRQ into string could not transfer TRQ down. Broke over at 270K P/U 260K. Decision was made POOH. Pump 10 bbl 11 ppg Dry Job. Blow down. SIMOPS prep for laying down. PJSM Cont POOH L/D 5" HWDP F/ 12,831' to 12,340' MD. Found well swabbing while POOH. At 12,340' MD Encountered tight spot. Work string up to 310K SLK to block weight (35K) W/ 4' of free travel. Put 5 wraps into string 7K TRQ stall. Work TRQ down W/ 310K & Block Weight (35K). Pump out of hole at 2 bpm 30 ft/min. L/D 5" HWDP F/ 12,309' to 11,878' MD. Tight spots at 12,186', 12,125' 12,080’ MD using TRQ limit 7K stall, Work string F/ 281K to 49K. Rack back jnts 124-123, 105-106, 98-99. Well appears to be flowing ~2.5 BPH. Daily disposal to G&I 45 bbls, total= 11666 bbls. Daily water from 6 mile lake 80 bbls total= 7580 bbls. Daily water from Duck lake 0 bb s total= 300 bbls. Daily Metal 0 lbs, total= 290 lbs. Daily fluid lost Production interval 10 bbls, total= 355 bbls. Fluid lost on Pre-Drill = 508 bbls. 5/18/2021 Cont POOH F/ 11,878’ to 10,880’ MD working interment tight spots W/ 7K TRQ stall & 40K over (P/U 240K) W/ no drag down (SLK 50-60K). At 11,017’ Circ depth of ~3,000’ MD Pump 70 bbl 11.2 ppg NaCl/NaBr chase W/ 10 ppg QuickDril. Spotting 45 bbls on the beck side. Pulled on elevators 10-15 ft/min W/ no swabbing. F/ 11,017’ to 10,880’ MD seeing tight spots 40’ apart maybe due centralizers at window. Working tight spot at 10,880’ MD W/ 85K over (P/U 200K) no drag down W/ 7K TRQ stall. P/U Single for longer stroke. Cont work pipe F/ 10,900’ to 10,880’ MD. P/U 200K SLK 80K. Cont work tight spot at 10,850' MD. Working 75K over (P/U 190K) W/ 8K Trq stall. P/U 1 stand 5" HWDP and able to go down to 10,987' MD without seeing any WT bobble at centralizer down hole through window. P/U hang up at 10,962' MD centralizer in window. Pulled 80% tubing tensile strength to 340K string WT. No success. P/U 190 SLK 90K. No losses. Decision was made to RIH and release of SLZXP. PJSM RIH W/ 5" HWDP and 5" D.P. F/ Derrick F/ 10,850' to 12,500' MD. No losses. P/U 240k SLK 50K. At 12 612' MD attempt to release F/ SLZXP 2X. Cont RIH W/ 5" D.P. F/ Derrick F/ 12,500' to 12,863' MD. Release from SLZXP. Work in 2.5 wraps LH W/ 6K TRQ stall, work string 5-7' P/U 180 SLK 35K. Work in 2 more .5 wraps (3.5 total LH) Work string SLZXP released HRD-E. SLK to 18K collapse dog sub. Lost 85K string WT. P/U 165K. Shoe at 12,863' MD TOL 4,657' MD. Rack Back two stands to 4,537' MD. PJSM Prep for L/D D.P. Monitor Well on TT finger printing flow and gain on TT. Start 8.35 BPH, diminishing to 0.36 BPH in 30 min. Bled back .49 bbls in 30 min. POOH L/D 5" D.P. & 5" HWDP F/ 4,537' to running tool. Lost 2 bbls. Running tool HRD-E sheared, pusher tool looked good as per Baker Rep. PJSM Service rig. Grease crown, spinners, Iron Roughneck, TD, Service skate, check oil in TD, Perform Derrick inspection. PJSM M/U Johnny Whacker RIH W/ 5" HWDP (3) and 5" D.P. (23) to 1,646' MD. P/U 55K SLK 55K. SIMOPS Process 2 7/8" D.P. in Pipe Shed. PJSM Cut and slip drilling line Accum TM 1079 TM. Hang blocks. Cut 14 wraps (88') Left on spool 2632'. TRQ Dead Man 85 ft/lb. Unhang blocks and calibrate blocks. Monitor well TT Lost 1 bbl. Static loss rate ~0.5 bph. PJSM POOH L/D 5" D.P. & 5" HWDP F/ 1,646' MD. No losses. PJSM P/U 2 7/8" test jnt. Drain Stack. Pull wear ring and set test plug. PJSM R/U test Equip. Fill Stack purge air. Test W/ 2 7/8" test jnt Annular, Upper & Lower VBR's (2.875" X 5.5") 250 / 3000 PSI 5 min on chart. Daily disposal to G&I 0 bbls, total= 11666 bbls. Daily water from 6 mile lake 0 bbls total= 7580 bbls. Daily water from Duck lake 0 bb s total= 300 bbls. Daily Metal 0 lbs, total= 290 lbs. Daily fluid lost Production interval 0 bbls, total= 355 bbls. Fluid lost on Pre-Drill = 508 bbls. 5/19/2021 Cont test 2 7/8” Annular, upper & lower VBR’s (2.875” X 5.5”) 250/ 3000 psi 5 min ea on chart. R/D test Equip. Pull test plug and set wear ring. (9 1/16” ID 10 ¾” OD 38” Lth) PJSM P/U Baker and Weatherford Equip. X/O’s, Motor, cutter, power tongs & 2 7/8” handling Equip. PJSM P/U 2 7/8” 10.4# S-135 HT Pac jnt, M/U 3.125” Multi String Cutter, X/O, Motor, FS, Circ Sub, XO to 48’ MD as per Baker Rep onsite. PJSM SIH W/ 2 7/8” 10.4# S-135 HT Pac F/ 48’ to 3,784’ MD TRQ 5350 ft/lb. Fill W/ fill up line every 20 jnts. Run speed 90 ft/min as per Baker Rep. P/U 60K SLK 48K. Calc Disp. PJSM P/U 3.5” D.P. and build 3.885” grapple, ITCO Spear, 2 ea ext, 5.625” OD No/Go, 1 jnt 3.5” D.P., 6.625” OD bumper sub and Circ Sub as per Baker Rep. Tape spear in place. Monitor well TT. No losses. No/Go to cutter 3,796.32’. PJSM Cont RIH W/ 5” D.P. F/ 3,841’ to 8,463’ MD. Entered SLZXP and 4.5” liner W/ 2 7/8” W/O issue. Fill every 5 stands W/ fill up hose. Calc Disp. P/U 133K SLK 66K. PJSM Clean P/U 133K SLK 66K. Tag No/Go at 8,463’ MD cutter depth, spear at 4,667’ MD W/ 10K down (SW 56K). Pull to 186K fish engaged. SLK down to 56K and pull to 186K 10K over Calc neutral WT W/4.5” liner (176K). Break circ at 25 gpm 300 psi F/O 29%. Inc at 5 min 42 gpm 450 psi F/O 35%, 10 min inc 62 gpm ICP 670 psi FCP 650 psi F/O 38.6% String WT 182K, 25 min 84 gpm ICP 1,010 psi FCP 958 psi F/O 42% WT 178K, 15 min 104 gpm ICP 1,325 psi FCP 1,121 psi F/O 43.7% cut liner WT drop F/ 175K to 162K lost 13K. Shut down. Max Gas 93u. Pumped 88 bbls, lost 5.4 bbls. Pull 177K calc string WT. Monitor well for 30 min initial flow .56 bph, static after 10 min, slight seepage loss at 30 min. PJSM POOH on elevators racking back in derrick F/ 8,463’ to 6,257’ MD. Pull speed 15-25 fpm to control swabbing. Initial drag 7-12K slowing to 2-4K around 7,200’ MD. P/U 134K. Swabbed 0.8 bbls for trip. Cont POOH on elevators racking back in derrick F/ 6,257’ to 4,350’ MD. Pull speed 25 fpm to control swabbing. Drag 2-4K P/U 134K. Stopped at 5,462’ MD SLZXP at 1,633’ MD monitor well 10 min, seepage loss. Stop at 4,350’ MD MLZXP at 521’ MD. Stop to monitor well after 7 min DS appears to be flowing. Rack back 1 stand F/ 4,350’ to 4,287’ MD. Monitor well 30 min, static. DS flow slowing to static. Appears to be air, pumped 10 bbls short from full DS volume while cutting 4.5” Liner. Cont POOH F/ 4,287’ to 3,956’ MD. Pull speed 25 fpm. 1K drag. P/U 108K Calc Disp for POOH. Rack 2 stands F/ 3,956’ to 3,842’ MD. L/D Circ Sub, Bumper Sub. M/U 5” D.P. working single. C/O split bushing to solid bushing. Cont monitor well TT, static. Daily disposal to G&I 50 bbls, total= 11766 bbls. Daily water from 6 mile lake 0 bbls total= 7580 bbls. Daily water from Duck lake 0 bb s total= 300 bbls. Daily Metal 2 lbs, total= 292 lbs. Daily fluid lost Production interval 0 bbls, total= 355 bbls. Fluid lost on Pre-Drill = 508 bbls. 5/20/2021 Monitor well (very slight losses ~1/2 bph static loss rate) prior to laying down spear assy. Attempt to work spear free with 1x right hand turn in down motion but unable to pull free from XO jt below SLZXP. Multiple attempts with no success. Establish right hand rotation @ 2-4 rpm, 1.5k free tq (limit set @ 3k tq). Continually work up eventually freeing grapple (3.885"). L/D spear assy. Grapple was failed in two pieces. All components accounted for. M/U backup spear assy w/ safety jt and stage same in shed. C/O handling equipment and R/U for handling 2-7/8" inner string. PJSM, POOH laying down 120 jts 2-7/8" HT PAC dp F/ 3750' to BHI MTR/Cutter BHA. 61k up, 59k dn. Calculated displacement for trip. B/O and L/D Extreme mtr w/ BHI multi string cutter (cutter looked to be in good shape). L/D BHI false table and handling equipment. M/U XO w/ TIW for laying down 4.5" 625W. Mob protectors to floor. M/U LRT for handling packer assy and L/D same. Prep tongs to L/D 4.5" liner. L/D 4.5” Screens / blanks as per running tally. L/D 92 jnts & Cut jnt 3.21’. P/U 77K. Lost 15 bbls. PJSM L/D 2 7/8” handling Equip. Break down 2 7/8” spear safety jnt & L/D. L/D all fishing subs, X/O’s & Weatherford job box. P/U M/U Baker Bowen HP Csg Patch 9.44’ Lng, (3.87’ to Packer Protector, 4.81’ to No.Go) 2 jnts RR 4.5” 13.5 # L-80 W625 (41.25’ & 40.49’) & 7” X 9.625” SLZXP 9 ea 7/16” Shear DG, 6 ea 1/2” Shear HST 3,296 PSI Neutralizer 38.81’ (129.99’) As per Baker Rep on site. W626 TRQ 9.6K. PJSM RIH SLZXP 1 stand 5” D.P. to 191’ MD. Circ at 4 bpm 200 psi. Blow down. L/D Weatherford power tongs. Cont RIH W/ 5” D.P. F/ derrick F/ 191’ to 1,464’ MD. Max run speed 90 ft/min. Lost 3 bbls. Cont RIH W/ 5” D.P. F/ derrick F/ 1,464’ to 8,853’ MD. Break Circ 2 bpm 155 psi. 10 RPM 14.5K TRQ. Max run speed 90 ft/min. Fill every 1,200’. P/U 166K SLK 65K ROT 107K Lost 9 bbls. Pick up working single. Slack down to 8,465’ MD. (EST TOF 8,463’) Pull 20K over (SW 186K), Set down 10K (SW51K) Pull 20K over (SW 186K) Set down 15K (SW 46K) Pull 50K over (SW 216K) Set down 15K (SW 46K) Fish latched. P/U to 100K. Drop 1.5” OD Phenolic Ball. Pull to 176K (10K over) and pump at 3 bpm 255 psi. Daily disposal to G&I 10 bbls, total= 11776 bbls. Daily water from 6 mile lake 0 bbls total= 7580 bbls. Daily water from Duck lake 0 bb s total= 300 bbls. Daily Metal 0 lbs, total= 292 lbs. Daily fluid lost Production interval 21 bbls, total= 376 bbls. Fluid lost on Pre-Drill = 508 bbls. 5/21/2021 Pressure up on dp to 3000 psi (3/4 bpm) with 10 min hold with string in tension @ 176k (10k over). Observe psi jump @ 1850 psi indicating packer set. Attempt to pressure up to ~4200 psi but flatlined @ 3500 psi with test pump. Psi up on IA and test SLZXP packer assy 1500 psi w/ 10 min hold (good) TOL @ 8347' MD. P/U out of top of liner w/ free wt 167k up. LPOOH to 8240' MD. CBU 1.2x staging up to 6 bpm, 1100 psi. Did see high pressure (3500 psi @ 2 bpm) initially but gradually decreased as continued pumping. 15 bbl loss. 43u BGG with no increase @ btms up. Monitor well. Initial flow @ 3.4 bph trending down to static over 30 min. Grease traveling equipment and pipe handling equipment. Pump dry job and B/D TDS. POOH laying down 5" drill pipe F/ 8240' - T/ surface. B/O and L/D LRT. 3 bbl loss for trip. 153k up, 62k dn @ 8240' MD. Last drilling report. See completion report for further details. Daily disposal to G&I 424 bbls, total= 12,150 bbls. Daily water from 6 mile lake 0 bbls total= 7580 bbls. Daily water from Duck lake 0 bb s total= 300 bbls. Daily Metal 0 lbs, total= 292 lbs. Daily fluid lost Production interval 26 bbls, total= 402 bbls. Fluid lost on Pre-Drill = 508 bbls. Activity Date Ops Summary 5/21/2021 PJSM Pull wear ring and set test plug. Close blinds and bleed off Koomey. LOTO, C/U Upper VBRS (2.875" X 5.5") to 7.625" solid body rams. Energize Koomey & open blinds. M/U side entry & 5" TIW #2 to 7.625" test Jnt. Shell test to 3,000 psi, door seal leaked. Tighten. Test good.,PJSM Test 7.625" upper solid body rams to 250/ 3,000 PSI 5 min on chart. Good.,PJSM Break down test Equip. L/D. Pull test plug.,PJSM C/O elevators to 7.625" slip elevators. P/U R/U 7.625" handling equip. Slips, air slips, dog collar and power tongs. Load 7.625" 29.7# L-80 W521 in pipe shed. 225 jnts on location.,PJSM P/U M/U Baker 7.625" Tie Back Seal assy as per Baker Rep onsite. RIH W/ 7.625" 29.7 # L-80 W521 to 1,600' MD. Flowing over while RIH at ~360' MD. Control run speed 75-25 ft/min to mitigate. P/U 71K SLK 68K. TRQ 12K due to RR.,PJSM Service skate due broken buggy chain plate. Remove and replace broken bolts.,Cont RIH W/ 7.625" 29.7 # L-80 W521 to 1,600' to 2,493' MD. Cont to flow over, control run speed 75-15 ft/min to mitigate. P/U 82K SLK 74K. TRQ 12K due to RR. Lost 6 bbls.,Cont RIH W/ 7.625" 29.7 # L-80 W521 to 2,493' to 7,028' MD. Cont to flow over, control run speed 60-10 ft/min to mitigate. P/U 169K SLK 76K. TRQ 12K due to RR. Lost 18 bbls.,Daily disposal to G&I 424 bbls, total= 12,150 bbls. Daily water from 6 mile lake 0 bbls total= 7580 bbls. Daily water from Duck lake 0 bb s total= 300 bbls. Daily Metal 0 lbs, total= 292 lbs. Daily fluid lost Production interval 26 bbls, total= 402 bbls. Fluid lost on Pre-Drill = 508 bbls. 5/22/2021 Cont RIH F/ 7028' - T/ tag depth 8359.63' MD. 7.625" Tieback 29.7 # L-80 W521 . Control run speed 60-10 ft/min to mitigate running over top of string. P/U 195K SLK 72K. TRQ 12K due to RR.,Reduce annular psi to ~500 psi. Close annular and psi up annulus to 200 psi to ensure seals fully engaged (good test). L/D Jt 207. M/U 4.88' pup below jt #206, M/U hanger and landing jt. Landout w/ 37k on hanger, 1.81' off no go. Psi up 200 psi and strip up dumping psi once 1" ports exposed on bullet seal assy.,R/U and reverse circulate down 7-5/8" x 9-5/8" annulus w/ 120 bbls 10.2 CI brine followed by 45 bbls diesel (Freeze protect). 2.5 bpm, 180 ICP, 390 FCP. 3 bbl loss.,Strip down and landout hanger (37k string wt). Bleed off psi, Saw slight flow initially and trended to static over 15 min. B/O landing joint. Install packoff assy. RILDS. Test hanger void 500/5000 psi w/ 5/10 min hold (test good).,R/U and P/T 7-5/8" x 9-5/8" annulus to 1000 psi w/ 30 min hold, Chart and record same. .75 bbls pumped, .75 bbls bled back. Test good, R/D test equipment.,C/O handling equipment on floor. R/U power tongs. Unload shed and load ESP components. 249 total jts 3.5" in shed. Mob cannon clamps to rig floor. Mob centrilift job box to floor. Hang ESP sheave in derrick and run ESP through sheave. Work on spooler camera, unable to fix.,PJSM P/U M/U as per Centerlift. P/U 5.85" Centralizer, Zenith Gauge, MTR 562XP 250 HP, Upper and lower Tandem Seals. Prime W/ oil and purge air. P/U Intake, Gas Sep, install 3/8" Cap line & test, good. Pump through Cap line, good. P/.U 2 ea PMP 400 MSXD 134 Flex H6. M/U Zenith Ported Sub & Discharge Head. Install MLE and perform MLE splice to ESP Cable. Test, good. Installed 5 pump clamps, 4 Seal Clamps, 1 Protectorizer.,Clean clear rig floor F/ ESP Splice. L/D Centerlift tools and splice table. R/U Weatherford power tongs.,PJSM RIH W/ RR 3.5" 9.3# L-80 EUE F/ 100' to 2,022' MD Install XN, GLM (Dummy) and CC as per tally. TRQ 3.2K. Test ESP every 2,000'. P/U 50K SLK 45K. No losses.,Daily disposal to G&I 275 bbls, total= 12,425 bbls. Daily water from 6 mile lake 0 bbls total= 7580 bbls. Daily water from Duck lake 0 bb s total= 300 bbls. Daily Metal 0 lbs, total= 292 lbs. Daily fluid lost Production interval 32 bbls, total= 434 bbls. Fluid lost on Pre-Drill = 508 bbls. 5/23/2021 Continue RIH W/ RR 3.5" 9.3# L-80 EUE F/ 2022'' to 6302' MD w/ ESP and control line. Install CC as per tally. TRQ 3.2K. Test ESP every 2,000'. P/U 74K SLK 50K. No losses.,Continue RIH W/ RR 3.5" 9.3# L-80 EUE F/ 6302' to 7875' MD w/ ESP and control line. Install CC as per tally. TRQ 3.2K. Test ESP every 2,000'. P/U 78K SLK 52K. No losses. Total 137 CC, 1 ea Protectolizer, 1 MC. 5 SC, 4 PC. (Total of 249 jts).,Final check on ESP cable prior to terminating (test good). M/U eccentric 3.5" tbg hanger (3.5" TCII top). Terminate ESP cable to penetrator and install same. Terminate control line to hanger assy. Install debris covers on top side ports of hanger. S/O and landout hanger on depth with 52k dn (17k string wt on hanger). RILDS, Set BPV. Final set depth 7906.93' MD.,M/U Johnny Wacker and pump 140° F soapy corrosion inhibited brine through stack. Flush all surface Equip same.,PJSM Remove riser & install RCD cap. Break and suspend RCD. Remove choke and kill lines. Break DSA bolts. Bleed down Koomey. Remove Koomey lines. Rack back Stack on pedestal. Remove DSA. Lower RCD and remove. SIMOPS Lay Herculite and mat boards at S-45. Clean Pits. Unhang rig tongs.,PJSM NOS rep install CTS plug into BPV. N/U dry hole tree. Test void 500 psi 5 min, 5,000 psi 10 min. Test Tree 500 psi 5 min & 5,000 psi 10 min. Remove CTS and leave BPV. SIMOPS Clean pits, handling Equip on rig floor.,PJSM Prep for moving rig. Bridle up. Cont cleaning pits. L/D handling Equip. Prep to scope down derrick. Remove Spinner Assy F/ carriage. Scope down derrick. Release rig at 06:00.,Daily disposal to G&I 563 bbls, total= 12,988 bbls. Daily water from 6 mile lake 80 bbls total= 7660 bbls. Daily water from Duck lake 0 bb s total= 300 bbls. Daily Metal 0 lbs, total= 292 lbs. Daily fluid lost Production interval 0 bbls, total= 434 bbls. Fluid lost on Pre-Drill = 508 bbls. 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B0:',)5066DJ B0:',)5066DJ B0:',)5066DJ B0:',)5066DJ B0:',)5066DJ B0:',)5066DJ B0:',)5066DJ B0:',)5066DJ B0:',)5066DJ B0:',)5066DJ B0:',)5066DJ B0:',)5066DJ 352-(&7('WR7' $SSURYHG%\&KHFNHG%\'DWH $0 &203$66%XLOG(3DJH Chelsea Wright Digitally signed by Chelsea Wright Date: 2021.05.17 08:45:54 -08'00'Benjamin Hand Digitally signed by Benjamin Hand Date: 2021.05.17 14:18:26 -08'00' David Douglas Hilcorp Alaska, LLC Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or fax to 907 777-8510. Received By: Date: Date: 5/24/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU J-29A (PTD 221-023) FINAL LWD FORMATION EVALUATION LOGS (05/08/2021 to 05/14/2021) •ABG, DGR, ADR, Horizontal Presentation (2” & 5” MD/TVD Color Logs) •Final Definitive Directional Survey SFTP Transfer - Data Folders: Please include current contact information if different from above. 05/24/2021 PTD: 2210230 E-Set: 35158 David Douglas Hilcorp Alaska, LLC Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or fax to 907 777-8510. Received By: Date: Date: 05/24/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU J-29A (PTD 221-023) FINAL EOW REPORT – GEOSTEERING LOGS (05/09/2021 to 05/14/2021) SFTP Transfer - Data Folders: Please include current contact information if different from above. PTD: 2210230 E-Set: 35159 05/24/2021 STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION Reviewed By: P.I. Supry "Z% 7t74 BOPE Test Report for: MILNE PT UNIT J -29A Comm Contractor/Rig No.: Hilcorp Innovation PTD#: 2210230 DATE: 5/16/2021 Inspector Adam Earl Insp Source Operator: Hilcorp Alaska, LLC Operator Rep: James Lott Rig Rep: M. Courson Inspector Type Operation: DRILL Sundry No:: Test Pressures: Inspection No: bopAGE210518203643 Rams: Annular: Valves: NIASP: Type Test: BIWKLY 250/3000 " 250/3000 ' 250/3000 - 1546 - Related Insp No: TEST DATA MISC. INSPECTIONS: MUD SYSTEM: P/F ACCUMULATOR SYSTEM: _1 - P " P/F I - Visual Alarm Ball Type Time/Pressure P/F Location Gen.: P " Trip Tank P P " System Pressure 2900 P Housekeeping: -P Pit Level Indicators P" _ P Pressure After Closure 1400 _ _ P PTD On Location P Flow Indicator P P 200 PSI Attained 28 - P - Standing Order Posted P " Meth Gas Detector P P Full Pressure Attained 108 P Well Sign P H2S Gas Detector P P Blind Switch Covers: - -- __ P Drl. Rig P _" MS Mise 0 NA Nitgn. Bottles (avg): 0(&, 2358 -_ P Hazard Sec. P - Kill Line Valves 2. 31/8--- ACC Mise 0 -NA Misc NA NA BOP Misc 0 NA FLOOR SAFTY VALVES: Number of Failures: 0 Remarks: Good test BOP STACK: Quantity P/F Upper Kelly _1 - P " Lower Kelly I - -P Ball Type _ 1 _- P " Inside BOP 1 P FSV Misc 0 NA Number of Failures: 0 Remarks: Good test BOP STACK: CHOKE MANIFOLD: Quantity Size P/F Quantity P/F Stripper 0 _ NA_ No. Valves 15 P Annular Preventer 1 135/8 - P Manual Chokes 1 P #1 Rams 1 2 7/8 X 51/2 P Hydraulic Chokes 1 P #2 Rams 1 blind - P CH Misc 0 NA #3 Rams 1- 2 7/8-X 5 1/2 P #4 Rams NA_ _0 _ _ INSIDE REEL VALVES: #5 Rams 0 NA #6 Rams 0 NA (Valid for Coil Rigs Only) Choke Ln. Valves 1 73 1/8 P = Quantity P/F HCR Valves 2 3 1/8 p Inside Reel Valves 0 -__ - Kill Line Valves 2. 31/8--- P Check Valve 0 NA BOP Misc 0 NA ✓ Toct D.C..Itc Test Time 3.5 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, Schrader Bluff Oil Pool, MPU J-29A Hilcorp Alaska, LLC Permit to Drill Number: 221-023 Surface Location: 2670' FSL, 3383' FEL, Sec 28, T13N, R10E, UM, AK Bottomhole Location: 699' FSL, 2576' FWL, Sec 24, T13N, R9E, UM, AK Dear Mr. Myers: Enclosed is the approved application for the permit to drill the above referenced 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 April, 2021. 14 Jeremy M. Price Digitally signed by Jeremy M. Price Date: 2021.04.14 13:04:43 -08'00' 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: 17,901' TVD: 3,567' 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): 60.2' 15. Distance to Nearest Well Open Surface: x-551934 y- 6015068 Zone-4 33.7' to Same Pool: 524' 16. Deviated wells: Kickoff depth: 9115 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 96 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD 8-1/2" 4-1/2" 13.5# L-80 Hydril625 8,951' 8,950' 3,749' 17,901' 3,567' 19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Junk (measured): Mpme TVD 147' 3,786' 3,784' 3,648' - 3,566' 9,327' - 17,882' 3,786' - 3,566' 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: 50-029-23688 Date: Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales: Samples req'd: Yes No Mud log req'd: Yes No H2S measures: Yes No Directional svy req'd: Yes No Spacing exception req'd: Yes No Inclination-only svy req'd: Yes No Post initial injection MIT req'd: Yes No APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Sr Pet Eng Sr Pet Geo Sr Res Eng GL / BF Elevation above MSL (ft): Stg 2 L - 730 sx / T - 270 sx Uncemented Screen Liner See cover letter for other requirements.-01-00 Perforation Depth MD (ft): 8,152' - 17,921' 21. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. 9,165' 9,769' 9,165'7-5/8" Commission Use Only Perforation Depth TVD (ft): 3,566' Stg 1 L - 1015 sx / T - 400 sx Effect. Depth MD (ft): Authorized Signature: 4-1/2" Uncemented Tieback Uncemented Screen Liner Tieback Liner 9,318' Driven 147' 9,318'9-5/8"Surface Conductor/Structural 20"147' 17,291'3,566' LengthCasing None Total Depth MD (ft): Total Depth TVD (ft): Cement Quantity, c.f. or sacks Cement Volume MDSize Plugs (measured): (including stage data) Effect. Depth TVD (ft): 17,291' STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 1546 938' FNL, 1223' FWL, Sec 20, T13N, R10E, UM, AK 699' FSL, 2576' FWL, Sec 24, T13N, R9E, UM, AK 88-005 10219 674' MPU J-29A Milne Point Unit Schrader Bluff Oil Pool 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 Hilcorp Alaska, LLC 2670' FSL, 3383' FEL, Sec 28, T13N, R10E, UM, AK ADL 025906, 025517, 025515 & 025514 022224484 5/1/2021 Authorized Name: Monty Myers Authorized Title: Drilling Manager Nathan Sperry nathan.sperry@hilcorp.com 777-8450 18. Casing Program: Top - Setting Depth - BottomSpecifications 1923 Form 10-401 Revised 3/2020 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g) 4.7.2021 By Samantha Carlisle at 11:38 am, Apr 07, 2021 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: 2021.04.07 11:13:26 -08'00' Monty M Myers X DSR-4/7/21 X 221-023 X X X DLB 04/08/2021 X DLB XBOPE test to 3000 psi. Annular to 2500 psi. MGR13APR2021 4/14/21 4/14/21Jeremy M. Price Digitally signed by Jeremy M. Price Date: 2021.04.14 13:05:12 -08'00' Milne Point Unit (MPU) J-29A Drilling Program Version 1 March 18, 2021 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 Wellbore Schematics .................................................................................................................. 6 7.0 Drilling / Completion Summary ................................................................................................ 8 8.0 Mandatory Regulatory Compliance / Notifications .................................................................. 9 9.0 MIRU ....................................................................................................................................... 11 10.0 Pull 3-1/2” Upper Completion ................................................................................................. 12 11.0 Pull 7-5/8” Tieback .................................................................................................................. 13 12.0 Mill 8-1/2” Window and FIT ................................................................................................... 14 13.0 Drill 8-1/2” Production Hole Section ....................................................................................... 17 14.0 Run 4-1/2” Screened Liner ...................................................................................................... 21 15.0 Run 7-5/8” Tieback .................................................................................................................. 25 16.0 Run 3-1/2” ESP Completion .................................................................................................... 28 17.0 Innovation BOP Schematic ...................................................................................................... 30 18.0 Wellhead Schematic ................................................................................................................. 31 19.0 Formation Information ............................................................................................................ 32 20.0 Anticipated Drilling Hazards .................................................................................................. 33 21.0 Innovation Layout.................................................................................................................... 35 22.0 FIT Procedure .......................................................................................................................... 36 23.0 Innovation Choke Manifold Schematic ................................................................................... 37 24.0 Casing Design Information ...................................................................................................... 38 25.0 8-1/2” Hole Section MASP ....................................................................................................... 39 26.0 Spider Plot (NAD 27) (Governmental Sections) ...................................................................... 40 27.0 Surface Plat (As Built) (NAD 27) ............................................................................................. 41 Page 2 Version 1 March 2021 Milne Point Unit J-29A Drilling Procedure 1.0 Well Summary Well MPU J-29A Pad Milne Point “J” Pad Planned Completion Type ESP Target Reservoir(s) Schrader Bluff NB Sand Planned Well TD, MD / TVD 17,901’ MD / 3,575’ TVD PBTD, MD / TVD 17,901’ MD / 3,575’ TVD Surface Location (Governmental) 2609' FNL, 1896' FWL, Sec 28, T13N, R10E, UM, AK Surface Location (NAD 27 –Zone 4) X= 551934, Y= 6015068 Top of Productive Horizon (Governmental) 938' FSL, 1223' FWL, Sec 20, T13N, R10E, UM, AK TPH Location (NAD 27) X= 545847 Y= 6018575 BHL (Governmental) 699' FSL, 2576' FWL, Sec 24, T13N, R9E, UM, AK BHL (NAD 27) X= 536919, Y=6018286 Maximum Anticipated Pressure (Surface) 1,546 psig Maximum Anticipated Pressure (Downhole/Reservoir) 1,923 psig Work String 5” 19.5# S-135 NC 50 KB Elevation above MSL: 26.5 ft + 33.0 ft = 59.5 ft GL Elevation above MSL: 33.0 ft BOP Equipment 13-5/8” x 5M Annular, (3) ea 13-5/8” x 5M Rams Page 3 Version 1 March 2021 Milne Point Unit J-29A Drilling Procedure 2.0 Management of Change Information Page 4 Version 1 March 2021 Milne Point Unit J-29A 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-52Weld 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 Tieback 7-5/8” 6.875”6.750”7.625 29.7 L-80 Hyd 521 6,890 4,790 683 8-1/2”4-1/2” Screens 3.920 3.795 4.714 13.5 L-80 Hydril 625 9,020 8,540 279 4.0 Drill Pipe Information: Hole Section OD (in) ID (in)TJ ID (in) TJ OD (in) Wt (#/ft) Grade Conn M/U (Min) M/U (Max) Tension (k-lbs) 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 Version 1 March 2021 Milne Point Unit J-29A Drilling Procedure 5.0 Internal Reporting Requirements 6.1 Fill out daily drilling report and cost report on Wellez. x Report covers operations from 6am to 6am x Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left of the data entry area – this will not save the data entered, and will navigate to another data entry tab. x Ensure time entry adds up to 24 hours total. x Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. x Enter the MD and TVD depths EVERY DAY whether you are making hole or not. 6.2 Afternoon Updates x Submit a short operations update each work day to mmyers@hilcorp.com, pmazzolini@hilcorp.com ,nathan.sperry@hilcorp.com,jengel@hilcorp.com and joseph.lastufka@hilcorp.com 6.3 Intranet Home Page Morning Update x Submit a short operations update each morning by 7am on the company intranet homepage. On weekend and holidays, ensure to have this update in before 5am. 6.4 EHS Incident Reporting x Health and safety: Notify EHS field coordinator. x Environmental: Drilling Environmental coordinator x Notify Drlg Manager & Drlg Engineer x Submit Hilcorp Incident report to contacts above within 24 hrs 6.5 Casing Tally x Send final “As-Run” Casing tally to nathan.sperry@hilcorp.com and joseph.lastufka@hilcorp.com 6.6 Casing and Cement report x Send casing and cement report for each string of casing to nathan.sperry@hilcorp.com and joseph.lastufka@hilcorp.com 6.7 Hilcorp Milne Point Contact List: Title Name Work Phone Cell Phone Email Drilling Manager Monty Myers 907.777.8431 907.538.1168 mmyers@hilcorp.com Drilling Engineer 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 Seth Nolan 907.777.8308 907.519.8225 snolan@hilcorp.com Res. Engineer Reid Edwards 907.777.8421 907.250.5081 reedwards@hilcorp.com Drlg Environmental Coord Keegan Fleming 907.777.8477 907.350.9439 kfleming@hilcorp.com Safety Manager Carl Jones 907.777.8327 907.382.4336 cajones@hilcorp.com Drilling Tech Joe Lastufka 907.777.8400 907.227.8496 Joseph.Lastufka@hilcorp.com Page 6 Version 1 March 2021 Milne Point Unit J-29A Drilling Procedure 6.0 Wellbore Schematics Page 7 Version 1 March 2021 Milne Point Unit J-29A Drilling Procedure BBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBB ĚŝƚĞĚǇ͗:E>ϭͬϮϲͬϮϬϮϭ ^,Dd/ DŝůŶĞWŽŝŶƚhŶŝƚ tĞůů͗DWh:ͲϮϵ >ĂƐƚŽŵƉůĞƚĞĚ͗ϭͬϭϭͬϮϭ Wd͗ϮϮϬͲϬϳϬ dсϭϳ͕ϵϮϭ͛;DͿͬdсϯ͕ϱϲϱ͛;dsͿ ϮϬ͟ KƌŝŐ͘<ůĞǀ͗͘ϲϴ͘Ϭϴ͛ͬ'>ůĞǀ͗͘ϯϯ͘ϳϬ͛ ϳͲϱͬϴ͟ ϵͲϱͬϴ͟ 6HH 6FUHHQ 6ROLG /LQHU 'HWDLO Wdсϭϳ͕ϵϮϭ͛;DͿͬWdсϯ͕ϱϲϱ͛;dsͿ ´µ(6¶ &HPHQWHU# ¶0' ϰͲϭͬϮ͟ ^ŚŽĞΛ ϭϳ͕ϵϭϵ͛ ϮͲϳͬϴ͟ ^/E'd/> ^ŝǌĞ dǇƉĞ tƚͬ'ƌĂĚĞͬŽŶŶ / dŽƉ ƚŵ W& ϮϬΗ ŽŶĚƵĐƚŽƌ ϭϮϵ͘ϱͬyϱϮͬtĞůĚ Eͬ ^ƵƌĨĂĐĞ ϭϰϳ͛ Eͬ ϵͲϱͬϴΗ ^ƵƌĨĂĐĞ ϰϳͬ>ͲϴϬͬdyW ϴ͘ϲϴϭ ^ƵƌĨĂĐĞ Ϯ͕ϰϮϵ͛ Ϭ͘Ϭϳϱϴ ϵͲϱͬϴ͟ ^ƵƌĨĂĐĞ ϰϬͬ>ͲϴϬͬdyW ϴ͘ϴϯϱ Ϯ͕ϰϮϵ͛ ϵ͕ϯϭϴ͛ Ϭ͘ϬϳϯϮ ϳͲϱͬϴ͟ dŝĞďĂĐŬ Ϯϵ͘ϳͬ>ͲϴϬͬ,ǇĚϱϮϭ ϲ͘ϴϳϱ ^ƵƌĨĂĐĞ ϵ͕ϭϲϱ͛ Ϭ͘Ϭϰϱϵ ϰͲϭͬϮ͟ >ŝŶĞƌϮϱϬђ^ĐƌĞĞŶƐ ϭϯ͘ϱͬ>ͲϴϬͬ,ǇĚϲϮϱ ϯ͘ϵϮϬ ϵ͕ϭϱϮ͛ ϭϳ͕ϵϮϭ͛ ͘Ϭϭϰϵ dh/E'd/> ϯͲϭͬϮΗ dƵďŝŶŐ ϵ͘ϯͬ>ͲϴϬͬhͲϴƌĚ Ϯ͘ϵϵϮ ^ƵƌĨĂĐĞ ϳ͕ϴϵϴ͛ Ϭ͘ϬϬϴϳ KWE,K>ͬDEdd/> ƌŝǀĞŶϮϬ͟ ϭϮͲϭͬϰΗ^ƚŐϭ>ĞĂĚʹϭϬϭϱƐǆͬdĂŝůʹϰϬϬƐǆ ^ƚŐϮ>ĞĂĚʹϳϯϬƐǆͬdĂŝůϮϳϬƐǆ ϴͲϭͬϮ͟ ĞŵĞŶƚůĞƐƐ^ĐƌĞĞŶĞĚ>ŝŶĞƌ t>>/E>/Ed/KEd/> <KWΛϯϯϯ͛ DĂǆ,ŽůĞŶŐůĞсϵϲΣΛϭϮ͕ϲϮϬ͛D dZΘt>>, dƌĞĞ ĂŵĞƌŽŶϯͲϭͬϴΗϱDǁͬϯͲϭͬϴ͟ϱDĂŵĞƌŽŶtŝŶŐ tĞůůŚĞĂĚ ĂŵĞƌŽŶϭϭ͟ϱ<ǆƐůŝƉůŽĐŬďŽƚƚŽŵǁͬ;ϮͿϮͲϭͬϭϲ͟ϱ<ŽƵƚƐ 'EZ>t>>/E&K W/͗ϱϬͲϬϮϵͲϮϯϲϴϴͲϬϬͲϬϬ ŽŵƉůĞƚŝŽŶĂƚĞ͗ϭͬϭϭͬϮϭ ϰͲϭͬϮ͟^K>/>/EZd/> :ƚƐdŽƉ ;DͿ dŽƉ ;dsͿ ƚŵ ;DͿ ƚŵ ;dsͿ ϰ ϵ͕ϭϳϴ͛ ϯ͕ϳϴϱ͛ ϵ͕ϯϮϳ͛ ϯ͕ϳϴϲ͛ :t>Zzd/> EŽ͘ dŽƉD /ƚĞŵ / ϭ ϭϯϱ͛ ϯͲϭͬϮ͟ǆϭ͟'>DǁͬW^Ks Ϯ͘ϵϬϳ͟ Ϯ ϳ͕ϲϱϰ͛ ϯͲϭͬϮ͟ǆϭ͟'>DƵŵŵǇsĂůǀĞǁͬ<>ĂƚĐŚ Ϯ͘ϵϬϳ͟ ϯ ϳ͕ϳϳϰ͛ yEEŝƉƉůĞ͕Ϯ͘ϴϭϯ͟WƌŽĨŝůĞ͕Ϯ͘ϳϱ͟EŽ'Ž Ϯ͘ϳϲϬ͟ ϰ ϳ͕ϴϭϲ͛ ŝƐĐŚĂƌŐĞ,ĞĂĚ͗ͬKWDWϱϭϯϯͲϭͬϮǆϴh ϱ ϳ͕ϴϭϳ͛ ĞŶŝƚŚWŽƌƚĞĚ^Ƶď͗WƌĞƐƐWŽƌƚϱϭϯͬϱϯϴW ϲ ϳ͕ϴϭϳ͛ WƵŵƉ͗ϱϯϴWD^yϮϳ&ůĞǆϮϳϭϯϱ&Z,ϲ ϳ ϳ͕ϴϰϱ͛ 'ĂƐ^ĞƉĂƌĂƚŽƌ͗ϱϯϴ'^d,ss,ϲ ϴ ϳ͕ϴϱϭ͛ hƉƉĞƌdĂŶĚĞŵ^ĞĂů͗'^,ϲ^ͬW&^ ϵ ϳ͕ϴϱϴ͛ >ŽǁĞƌdĂŶĚĞŵ^ĞĂů͗'^,ϲ^ͬW&^ ϭϬ ϳ͕ϴϲϰ͛ DŽƚŽƌ͗ϱϲϮyWʹϰϱϬ,Wͬϯϭϯϱsͬϴϴ ϭϭ ϳ͕ϴϵϯ͛ DŽƚŽƌ'ĂƵŐĞ͗ĞŶŝƚŚϳ ϭϮ ϳ͕ϴϵϲ͛ ĞŶƚƌĂůŝǌĞƌ͗ŽƚƚŽŵΛϳ͕ϴϵϴ͛D ϭϯ ϵ͕ϭϱϮ͛ Kd^>yW>dWͬ>ŝŶĞƌ,ĂŶŐĞƌϳ͟ǆϵͲϱͬϴ͟;ϯ͕ϳϴϯ͛dsͿϲ͘ϭϵϬ͟ ϭϰ ϵ͕ϭϱϰ͛ >ŽĐĂƚŽƌ^Ƶď͕ϳ͟dyWŽǆǆŽǆ ϲ͘ϭϴϬ͟ ϭϱ ϵ͕ϭϳϯ͛ ϳ͟,ϱϲϯǆϰ͘ϱ͟d^,ϲϮϱyK ϯ͘ϴϰϬ͟ ϭϲ ϭϳ͕ϵϭϵ͛ ^ŚŽĞ ϯ͘ϵϱϬ͟ ϰͲϭͬϮ͟^ZE^>/EZd/> :ƚƐdŽƉ ;DͿ dŽƉ ;dsͿ ƚŵ ;DͿ ƚŵ ;dsͿ ϮϬϳ ϵ͕ϯϮϳ͛ ϯ͕ϳϴϲ͛ ϭϳ͕ϴϴϮ͛ ϯ͕ϱϲϲ͛ Current Well Page 8 Version 1 March 2021 Milne Point Unit J-29A Drilling Procedure 7.0 Drilling / Completion Summary MPU J-29A is a sidetrack producer planned to be drilled in the Schrader Bluff NB sand. J-29A is part of a multi well program targeting the Schrader Bluff sand on J-Pad. This is a re-drill due to a suspected liner failure on the original J-29 well. An 8-1/2” lateral section will be drilled off of a 9-5/8” whipstock with the KOP at ~9,100’ MD. A 4-1/2” screen liner will be run in the open hole section and the well produced with an ESP upper completion. Innovation will be used to drill and complete the wellbore Drilling operations are expected to commence approximately April 28th, 2021, pending rig schedule. The whipstock will be set below the top of the Schrader Bluff such that this is an in-zone sidetrack. All cuttings & mud generated during drilling operations will be hauled to the Milne Point “B” pad G&I facility. General sequence of operations (will commence following operations detailed on sundry application): 1. MIRU, test BOPE 2. Circulate out freeze protect 3. Pull 3-1/2” Upper Completion 4. Pull 7-5/8” tieback 5. If necessary, perform cleanout run 6. RIH and set 9-5/8” CIBP 7. Run 9-5/8” whipstock, mill window 8. Drill 8-1/2” lateral to well TD 9. Run 4-1/2” production liner 10. Run 7-5/8” tieback 11. Run Upper Completion 12. ND BOP, NU Tree, RDMO Reservoir Evaluation Plan: 1. Production Hole: No mud logging. Wellsite geologist. LWD: GR + ADR (For geo-steering) PTD 221-023 Sundry for abandonment 321-169 Page 9 Version 1 March 2021 Milne Point Unit J-29A Drilling Procedure 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the below AOGCC regulations. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. x BOP’s shall be tested at 1 week intervals prior to initiating window milling and 2 week intervals during the drilling and completion of MPU J-29A thereafter. Provide AOGCC 24 hrs notice prior to testing BOPs. x The initial test of BOP equipment will be to 250/3000 psi & subsequent tests of the BOP equipment will be to 250/3000 psi for 5/5 min (annular to 50% rated WP, 2500 psi on the high test for initial and subsequent tests).Confirm that these test pressures match those specified on the APD. x If the BOP is used to shut in on the well in a well control situation, notify AOGCC and test all BOP components utilized for well control prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP test. x All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid program and drilling fluid system”. x All AOGCC regulations within 20 AAC 25.035 “Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements”. x Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office. x Casing pressure test criteria in 20 AAC 25.030 (e) Casing and Cementing,“A casing pressure test must be performed if BOPE is to be installed on a casing. The casing must be tested to hold a minimum surface pressure equal to 50 percent of the casing internal yield pressure. The test pressure must show stabilizing pressure and may not decline more than 10 percent within 30 minutes. The results of this test and any subsequent tests of the casing must be recorded as required by 20 AAC 25.070(1)”. AOGCC Regulation Variance Requests: x There are no variance requests at this time. Page 10 Version 1 March 2021 Milne Point Unit J-29A Drilling Procedure Summary of BOP Equipment and Test Requirements Hole Section Equipment Test Pressure (psi) 8-1/2” x 13-5/8” x 5M Control Technology Inc Annular BOP x 13-5/8” x 5M Control Technology Inc Double Gate o Blind ram in btm cavity x Mud cross w/ 3” x 5M side outlets x 13-5/8” x 5M Control Technology Single ram x 3-1/8” x 5M Choke Line x 3-1/8” x 5M Kill line x 3-1/8” x 5M Choke manifold x Standpipe, floor valves, etc Initial Test: 250/3,000 Subsequent Tests: 250/3,000 Primary closing unit: Control Technology Inc. (CTI), 6 station, 3,000 psi, 220 gallon accumulator unit. Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is an electric triplex pump on a different electrical circuit 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 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 11 Version 1 March 2021 Milne Point Unit J-29A Drilling Procedure 9.0 MIRU All the work up through laying down the milling assembly will be on the PRE AFE code. There is restricted communication to the lateral due to fill. This is an in-zone sidetrack to replace the failed liner. The existing lateral will be isolated via a plug set above the liner top. Operational Steps: 9.1 Ensure Sundry, PTD, and drilling program are posted in the rig office and on the rig floor. 9.2 Level pad and ensure enough room for layout of rig footprint and R/U. 9.3 Ensure rig mats cover entire footprint of rig. 9.4 MIRU Innovation. Ensure rig is centered over the wellhead to prevent any wear to BOPE or wellhead. 9.5 N/U 13-5/8” x 5M BOP as follows: x BOP configuration from top down: 13-5/8” x 5M annular / 13-5/8” x 5M double gate / 13- 5/8” x 5M mud cross / 13-5/8” x 5M single gate x Double gate ram should be dressed with 2-7/8” x 5” VBRs in top cavity,blind ram in bottom cavity. x Single ram can be dressed with 7-5/8” FBRs x N/U bell nipple, install flowline. x Install (1) manual valve & HCR valve on kill side of mud cross. (Manual valve closest to mud cross). x Install (1) manual valve on choke side of mud cross. Install an HRC outside of the manual valve 9.6 Test BOP to 250/3000 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min. x Install test dart in BPV. x Test VBR’s with 3-1/2” and 5” test joints x Test FBR’s with 7-5/8” test joint 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 9.7 R/D BOP test equipment. Pull test dart and BPV. Page 12 Version 1 March 2021 Milne Point Unit J-29A Drilling Procedure 10.0 Pull 3-1/2” Upper Completion Notes: x Upper completion was installed by Doyon 14 in January 2021 using a 33.1’ air gap (per tally). There is a 6.6’ shift to our 26.5’ Innovation air gap. hank x Recent attempts to establish communication with the reservoir have had mixed results. On 3/23/2021, service coil was unable to circulate to surface inside the tubing but was able to bullhead into the formation. Slickline had no trouble running to 7654’ MD the following day. x On 3/24/2021, slickline reported a fluid level at 1,406’ MD and pulled the lowermost DGLV from Station 1 (7654’ D14 MD). Station 2 (135’ MD) has a one way valve from the IA to the tbg. x Slickline bailing runs recovered a sandy/heavy oil mixture from the tubing on 3/21/2021. Operational Steps: 10.1 RU to circulate the well to seawater. Flowcheck and be prepared to swap to 10.0ppg KCl/NaCl brine if necessary. x The tubing has 60/40 freeze protect and the IA has diesel freeze protect. x Service coil filled the well with freeze protect and slickline found the fluid level at 1,406’ MD the next day so the well may not support a full column of 10.0ppg brine despite the 9.8ppg pore pressure prediction. 10.2 RU ESP spooler and associated equipment in preparation for pulling the upper completion. 10.3 Back out lock down screws. 10.4 Pull tubing hanger with landing joint/XO to the floor. Have appropriate protectors ready. 10.5 Note and record PU weight required to pull the tubing from cut. Final PU/SO weight from Doyon 14 was 95k / 60k. 10.6 Pull and lay down the tubing. The plan is to re-run this completion after sidetracking (confirm w/ Operations Engineer). Repeat from the abandonment Sundry Page 13 Version 1 March 2021 Milne Point Unit J-29A Drilling Procedure 11.0 Pull 7-5/8” Tieback Operational Steps: 11.1 Ensure 7-5/8” x 9-5/8” annulus is bled to zero. Bleed each tour. 11.2 Ensure annulus is circulating clean prior to laying down 7-5/8” tieback. 130 bbls of inhibited brine and 41 bbls of diesel are in the annulus. 11.3 Verify LD screws are free. Pull packoff. PU landing joint recover the casing hanger. 11.4 Pull hanger with landing joint/XO to the floor. x Note and record PU weight required to pull the casing. x Doyon 14 landed the hanger with 185k PU weight / 105k SO weight on 1/9/2021. x Circulate at least 1.5X BU and pump at least one high vis sweep surface to surface to clean out 11.5 Pull and lay down the casing. 11.6 Run wear ring. 11.7 If necessary, MU cleanout BHA w/ 8-1/2” bit and RIH to the liner top. CBU as necessary to ensure casing is clean. 11.8 MU a 9-5/8” CIBP on 5” DP and RIH to set it within a couple of feet of the top of the liner. Perform assurance test on the CIBP to 1500 psi for 10 minutes. Repeat from the abandonment Sundry Page 14 Version 1 March 2021 Milne Point Unit J-29A Drilling Procedure 12.0 Mill 8-1/2” Window and FIT Note: All following operations will be covered under the PTD for J-29A 12.1 Whipstock Set Depth Information: x The top ~2,400’ of 9-5/8” is 47# x Top of Schrader Bluff is 8,978’ MD Innovation RKB (8,984’ D14 RKB) x Planned TOW: ~9,114’ MD (may need to shift closer to collar to accommodate CIBP) x Collars should be at 9,066’ and 9,108’ and 9,150’ Innovation RKB x Top of baffle adapter is 9,150’ MD Innovation RKB (9,156’ D14 RKB) x Top of liner is at 9,145’ Innovation RKB (9,151’ D14 RKB) x Whipstock is the Wellbore Integrity Solutions Trackmaster Elite x Verify shear bolt strength with WIS rep. 12.2 MU 8-1/2” mill/whipstock assembly as per fishing rep’s tally x Ensure magnets are in trough, under shakers, and flow area to capture metal shavings circulated 12.3 Install MWD. Rack back mill assembly. 12.4 Verify offset between MWD and whipstock tray, witnessed by Drilling Supervisor, MWD/DD and fishing rep. Document and record offset in well file. 12.5 Slowly run in the hole as per fishing rep. Run extremely slow through the BOP & wear bushing to prevent damaging the shear bolt. 12.6 Run in hole at 1 ½ to 2 minutes per double, or as per fishing rep. Ensure work string is stationary prior to setting the slips, and removed slowly as well. These precautions are to avoid weakening the shear bolt and prematurely setting the anchor. 12.7 Stop at least 30-45’ above planned set depth and obtain survey with MWD. 12.8 Milling fluid will be 10.0-10.2 ppg viscosified fluid (Baradrill-N or brine). 12.9 With the bottom of the whipstock 30 – 45’ above the set depth, work torque out of string, measure and record P/U and S/O weights. Obtain good survey to orient whipstock face. 12.10 Orient whipstock to desired direction by turning DP in ¼ round increments. P/U and S/O on DP to work all torque out after oriented. Target orientation is 60q ROHS. Repeat from the abandonment Sundry Page 15 Version 1 March 2021 Milne Point Unit J-29A Drilling Procedure 12.11 Whipstock Orientation Diagram: Desired orientation of the whipstock face is 60R. Acceptable range is between 30R and 60R Hole Angle at window interval (9,122’ MD) is ~81°, Azimuth 267°. 12.12 Once whipstock is in desired orientation, set WS per fishing rep. 12.13 P/U 5-7K maximum overpull to verify anchor is set. The window mill can then be sheared off by slacking off weight on the whipstock shear bolt. 12.14 P/U 5-10’ above top of whipstock. 12.15 CBU and confirm consistent MW in/out x Ensure Mud properties are sufficient for transporting metal cuttings x Visc: 40-60, YP: 18-20 12.16 Record P/U, S/O weights, and free rotation. Slack off to top of whipstock and with light weight and low torque. Mill window as per fishing rep. Utilize 4 ditch magnets on the surface to catch metal cuttings. Pump high visc sweeps as necessary. 12.17 If possible, install catch trays in shaker underflow chute to help catch metal cuttings. 12.18 Clean catch trays and ditch magnets frequently while milling window. 12.19 Mill window until the uppermost mill has passed across the entire tray. Dress and polish window as needed. 12.20 With upper mill at the end of the tray, this will drill ~ 20’ of new hole. 12.21 After window is milled and before POOH, shut down pumps and work milling assembly through window watching for drag. Dress and polish window as needed. After reaming, shut off pumps and rotary (if hole conditions allow) and pass through window checking for drag. 12.22 Circulate bottoms up until even MW in/out and hole is clean of metal shavings. Reduce mud properties for drilling. 12.23 Pull back into 9-5/8” casing and perform FIT to 12.0 ppg EMW. Chart Test. 60R 30R Repeat from the abandonment Sundry Start of relevant steps for PTD. Page 16 Version 1 March 2021 Milne Point Unit J-29A Drilling Procedure 12.24 Flowcheck. POOH & LD milling BHA. Gauge mills for wear. 12.25 PU stack washer and wash BOPE stack. Function all rams to clear any potential milling debris. Page 17 Version 1 March 2021 Milne Point Unit J-29A Drilling Procedure 13.0 Drill 8-1/2” Production Hole Section The following work will be on the DRILLING AFE code. 13.1 PU 8-1/2” directional BHA. 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 Ensure MWD is RU and operational. 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, DS50 & NC50. x Run a ported float in the production hole section. Schrader Bluff Bit Jetting Recommendation Formation Jetting TFA NB 6 x 14 0.902 OA 6 x 13 0.778 OB 6 x 13 0.778 13.2 8-1/2” 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 Solids Concentration: It is imperative that the solids concentration be kept low while drilling the production hole section. Keep the shaker screen size optimized and fluid running to near the end of the shakers. It is okay if the shakers run slightly wet to ensure we are running the finest screens possible. x Rheology: Keep viscosifier additions to an absolute minimum (N-VIS). Data suggests excessive viscosifier concentrations can decrease return permeability. Do not pump high vis sweeps, instead use tandem sweeps. Ensure 6 rpm is > 8-1/2” (hole diameter) for sufficient hole cleaning 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. Page 18 Version 1 March 2021 Milne Point Unit J-29A Drilling Procedure System Type:8.9 – 10.0 ppg Baradrill-N drilling fluid Properties: Section Density Plastic Viscosity Yield Point Total Solids MBT HPHT Production 8.9-10.0 15-25 20-25 <10% <7 <11.0 System Formulation: Baradrill-N Product Concentration Water KCL KOH N-VIS DEXTRID LT BARACARB 5 BARACARB 25 BARACARB 50 BARACOR 700 BARASCAV D X-CIDE 207 0.955 bbl 11 ppb 0.1 ppb 1.0 – 1.5 ppb 5 ppb 4 ppb 4 ppb 2 ppb 1.0 ppb 0.5 ppb 0.015 ppb 13.3 TIH with 8-1/2” directional assembly to bottom. 13.4 Install MPD RCD. 13.5 Begin drilling 8-1/2” hole section, on-bottom staging technique: x Use reduced parameters per Halliburton DD until BHA is clear of the whipstock. x After BHA clears whipstock, begin drilling with 100 - 120 RPMs at bit. Allow WOB to stabilize at 5-8K. x Slowly begin bringing up rpms, monitoring stick slip and BHA vibrations x If BHA begins to show excessive vibrations / whirl / stick slip, it may be necessary to PU off bottom and restart on bottom staging technique. If stick slip continues, consider adding 0.5% lubes 13.6 Drill 8-1/2” hole section to section TD per Geologist and Drilling Engineer. x Flow Rate: 350-550 GPM, target min. AV’s 200 FPM, 385 GPM x RPM: 120+ 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 Take MWD surveys every stand, can be taken more frequently if deemed necessary, ex: concretion deflection x Monitor Torque and Drag with pumps on every 5 stands NOTE: EMW required = 8.5 - 9.8 ppg in Schrader NB. DLB Page 19 Version 1 March 2021 Milne Point Unit J-29A Drilling Procedure 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 Use ADR to stay in section. Reservoir plan is to stay in NB/NC sand. x Limit maximum instantaneous ROP to < 250 FPH. The sands will drill faster than this, but when concretions are hit when drilling this fast, cutter damage can occur. x Target ROP is as fast as we can clean the hole without having to backream connections x Schrader Bluff Concretions: 5-10% of lateral x MPD will be utilized to monitor pressure build up on connections. x 8-1/2” Lateral A/C: x M-43 has a 0.411 CF. M-43 is an active producer from the NB sands. A collision would result in drilling through an uncompleted section of M-43 (i.e. open hole in the rock below the shoetrack). Slight lost circulation might occur and there is no HSSE risk. x M-43PB3 has a 0.518 CF. This is an open hole PB. No risk. x J-29 has a 0.602 CF. There is no HSSE risk. The risk is financial (bit trip, OH sidetrack). 13.7 Reference:Halliburton has a procedure for Schrader OH sidetracks based on lessons learned and best practices. Ensure the DD is referencing their procedure. x Patience is key! Getting kicked off too quickly might have been the cause of failed liner runs on past wells. x If a known fault is coming up, put a slight “kick-off ramp” in wellbore ahead of the fault so we have a nice place to low side. x Attempt to lowside in a fast drilling interval where the wellbore is headed up.NOTE: In Nb sand wells, it helps to pick a siltier section to help mitigate junction collapse. x Orient TF to low side and dig a trough with high flowrates for the first 30 feet, working string back and forth. Trough for approximately 30 minutes. x Time drill at 4 to 6 feet per hour with high flow rates. Gradually increase ROP as the openhole sidetrack is achieved. 13.8 At TD, CBU (minimum 4X at 200 ft/min AV (385+ GPM) and rotation (120+ RPM). Pump tandem sweeps if needed. x Rack back a stand at each bottoms up and reciprocate a full stand in between (while circulating the BU). Keep the pipe moving while pumping. x Monitor BU for increase in cuttings, cuttings in laterals come back in waves and not a consistent stream, circulate more if necessary x If seepage losses are seen while drilling, consider reducing MW at TD to 9.0 ppg minimum 13.9 Mix and pump 40 bbl 10 ppb SAPP pill. Line up to a closed loop system and circulate three SAP pills with 50 bbl in between. Displace out SAP pills. Monitor shakers for returns of mud filter cake and calcium carbonate. Circulate the well clean. x Losses during the cleanup of the wellbore are a good indication that the mud filter cake is being removed, including an increase in the loss rate. Page 20 Version 1 March 2021 Milne Point Unit J-29A Drilling Procedure 13.10 Displace 1.5 OH + Liner volume with viscosified brine. x Proposed brine blend (aiming for an 8 on the 6 RPM reading) - KCl: 7.1bbp for 2% NaCl: 60.9 ppg for 9.4 ppg Lotorq: 1.5% Lube 776: 1.5% Soda Ash: as needed for 9.5pH Busan 1060: 0.42 ppb Flo-Vis Plus: 1.25 ppb x Monitor well for loss rate and contact Drilling Engineer and/or Ops Engineer if further discussion needed prior to BROOH. 13.11 Monitor the returned fluids carefully while displacing to brine. After 1 (or more if needed) BU, Perform production screen test (PST). The brine has been properly conditioned when it will pass the production screen test (x3 350 ml samples passing through the screen in the same amount of time which will indicate no plugging of the screen). Reference PST Test Procedure 13.12 BROOH with the drilling assembly to the 9-5/8” casing shoe x Circulate at full drill rate (less if losses are seen, 350 GPM). x Rotate at maximum rpm that can be sustained. x Pulling speed 5 – 10 min/stand (slip to slip time, not including connections), adjust as dictated by hole conditions. x If back reaming operations are commenced, continue back reaming to the shoe 13.13 If abnormal pressure has been observed in the lateral, utilize MPD to close on connections while BROOH. 13.14 CBU minimum two times at 9-5/8” shoe and clean casing with high vis sweeps. 13.15 Monitor well for flow / monitor for pressure build up with MPD. Increase fluid weight if necessary. x Wellbore breathing has been seen on past MPU SB wells. Perform extended flow checks to determine if well is breathing, treat all flow as an influx until proven otherwise 13.16 POOH and LD BHA. 13.17 Rabbit DP on TOOH, ensure rabbit diameter is sufficient for future ball drops. 13.18 Only LWD open hole logs are planned for the hole section (GR + Res). There will not be any additional logging runs conducted. Page 21 Version 1 March 2021 Milne Point Unit J-29A Drilling Procedure 14.0 Run 4-1/2” Screened Liner NOTE: If an open hole sidetrack was performed, drop the centralizers on the lowermost 2-3 joints and run them slick. 14.1 Confirm VBR’s have been tested on 3-1/2” and 5” test joints to 250/3,000 psi. 14.2 Well control preparedness: In the event of an influx of formation fluids while running the 4- 1/2” production screens, the following well control response procedure will be followed: x PU & MU the 5” safety joint (with 4-1/2” crossover installed on bottom, TIW valve in open position on top, 4-1/2” handling joint above TIW). This joint shall be fully MU and available prior to running the first joint of 4-1/2” screen. x Slack off and position the 5” DP across the BOP, shut in ram or annular on 5” DP. Close TIW valve. x Proceed with well kill operations. 14.3 RU 4-1/2” screen running equipment. x Ensure 4-1/2” x NC-50 crossover is on rig floor and MU to FOSV. x Ensure all casing has been drifted on the deck prior to running. x Be sure to count the total # of joints on the deck before running. x Keep hole covered while RU casing tools. x Record OD’s, ID’s, lengths, SN’s of all components w/ vendor & model info. 14.4 Run 4-1/2” screen production liner – Reference screen handling and running procedure. x Use Best O Life 2000 AG thread compound. Dope pin end only with paint brush. Wipe off excess. Thread compound will plug the screens. x Utilize a collar clamp until weight is sufficient to keep slips set properly. x Run packoff and float shoe on bottom. x 4-1/2” Screens should auto –fill, top off with completion brine if needed x Swell packers will not be required on this completion unless the well is drilled out of zone x If needed, install swell packers as per the lower completion tally. x Remove protective packaging on swell packers just prior to picking up x Do not place tongs or slips on the packer element 4-1/2”, 13.5 #, L-80, Hydril 625 Torque OD Minimum Optimum Operating Torque 4-1/2” 8,000 ft-lbs 9,600 ft-lbs 12,800 ft-lbs Page 22 Version 1 March 2021 Milne Point Unit J-29A Drilling Procedure 14.5 Ensure to run enough liner to provide for approx 150’ overlap inside 9-5/8” casing. Ensure hanger/packer will not be set in a 9-5/8” connection. 7.6 AOGCC regulations require a minimum 100’ overlap between the inner and outer strings as per 20 AAC 25.030(d)(6). Do not place liner hanger/packer across 9-5/8” connection. Page 23 Version 1 March 2021 Milne Point Unit J-29A Drilling Procedure 14.6 Before picking up Baker SLZXP liner hanger / packer assembly, count the # of joints on the pipe deck to make sure it coincides with the pipe tally. 14.7 MU Baker SLZXP liner top packer to 4-1/2” liner. 14.8 Note: PU, SO, ROT and torque of liner. Run liner in the hole one stand and pump through liner hanger to ensure a clear flow path exists. 14.9 RIH with liner on utilizing ALL 5” HWDP available (and 5” DP to make up the difference) no faster than 30 ft/min – this is to prevent buckling the liner and drill string and weight transfer to get liner to bottom with minimal rotation. Watch displacement carefully and avoid surging the hole or buckling the liner. Slow down running speed if necessary. x Ensure 5” HWDP has been drifted 14.10 Slow in and out of slips. Ensure accurate slack off data is gathered during RIH. Record shoe depth + SO depth every stand. Record torque value if it becomes necessary to rotate the string to bottom. 14.11 Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10, & 20 RPM. 14.12 If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensure shoe enters correct hole. 14.13 TIH deeper than planned setting depth. Last motion of the liner should be up to ensure it is set in tension. 14.14 Rig up to pump down the work string with the rig pumps. 14.15 Break circulation. Begin circulating at ~1 BPM and monitor pump pressures. Do not exceed 1,600 psi while circulating.Pusher tool is set at 2,100 psi with 5% shear screws but it should be discussed before exceeding 1,600 psi. Note all losses. Confirm all pressures with Baker. 14.16 Prior to setting the hanger and packer, double check all pipe tallies and record amount of drill pipe left on location. Ensure all numbers coincide with proper setting depth of liner hanger. 14.17 Shut down pumps. Drop setting ball (ball seat now located in HRDE setting tool and not at the WIV) down the workstring and pump slowly (1-2 BPM). Slow pump before the ball seats. Do not allow ball to slam into ball seat. 14.18 Continue pressuring up to 2,700 psi to set the SLZXP liner hanger/packer. Hold for 5 minutes. Slack off 20K lbs on the SLZXP liner hanger/packer to ensure the HRDE setting tool is in compression for release from the SLZXP liner hanger/packer. Continue pressuring up 4,500 psi to release the HRDE running tool. Page 24 Version 1 March 2021 Milne Point Unit J-29A Drilling Procedure 14.19 Bleed DP pressure to 0 psi. Pick up to expose rotating dog sub and set down 50K without pulling sleeve packoff. Pick back up without pulling sleeve packoff, begin rotating at 10-20 RPM and set down 50K again. 14.20 PU to neutral weight, close BOP and test annulus to 1,500 psi for 10 minutes charted. 14.21 Bleed off pressure and open BOPE. Pickup to verify that the HRD setting tool has released. If packer did not test, rotating dog sub can be used to set packer. If running tool cannot be hydraulically released, apply LH torque to mechanically release the setting tool. 14.22 PU pulling running tool free of the packer and displace with at max rate to wash the liner top. Pump sweeps as needed. 14.23 POOH. LD and inspect running tools. If setting of liner hanger/packer proceeded as planned, LD DP and HWDP on the TOOH. 14.24 PU remaining drillpipe from the derrick and RIH to LDDP. If needed, perform cleanout run to PBR. Note: Once running tool is LD, swap to the completion AFE. Page 25 Version 1 March 2021 Milne Point Unit J-29A Drilling Procedure 15.0 Run 7-5/8” Tieback 15.1 RU and pull wear bushing. Get an accurate measurement of RKB to tubing hanger load shoulder to be used for tie-back space out calculation. 15.2 If not already installed, close blinds and install 7-5/8” FBR’s. Test with 7-5/8” test joint to 250/3,000 psi. Open blinds/drain stack. Monitor the well at the annulus valve. 15.3 RU 7-5/8” casing handling equipment. x Ensure XO to DP made up to FOSV and ready on rig floor. x Rig up computer torque monitoring service. x String should stay full while running, RU fill up line and check as appropriate. 15.4 PU 7-5/8” hanger and make a dummy run. 15.5 PU 7-5/8” tieback seal assembly and set in rotary table. Ensure seal assembly has (4) 1” holes above the first seal. These holes will be used to spot diesel freeze protect in the 9-5/8” x 7-5/8” annulus. 15.6 M/U first joint of 7-5/8” to seal assembly. 15.7 Run 7-5/8”, 29.7#, L-80, H521 tieback to position seal assembly two joints above tieback sleeve. Record up & down weights. 7-5/8” 29.7# H521 MU Torque OD Minimum Optimum Maximum Yield Torque 7-5/8” 8,100 10,400 14,700 53,000 Page 26 Version 1 March 2021 Milne Point Unit J-29A Drilling Procedure 15.8 MU 7-5/8” to DP crossover. 15.9 MU stand of DP to string, and MU top drive. 15.10 Break circulation at 1 BPM and begin lowering string. 15.11 Note seal assembly entering tieback sleeve with a pressure increase, stop pumping and bleed off pressure, leave standpipe bleed off valve open. Page 27 Version 1 March 2021 Milne Point Unit J-29A Drilling Procedure 15.12 Continue lowering string and land out on no-go. Set down 5 – 10K and mark the pipe as “NO- GO DEPTH”. 15.13 PU string & remove unnecessary 7-5/8” joints. 15.14 Space out with pups as needed to leave the no-go 1ft above fully no-go position when the casing hanger is landed. Ensure one full joint is below the casing hanger. 15.15 PU and MU the 7-5/8” casing hanger with landing joint. 15.16 Ensure circulation is possible through 7-5/8” string. 15.17 RU and circulation corrosion inhibited brine in the 9-5/8” x 7-5/8” annulus. 15.18 With seals stabbed into the tieback sleeve, spot diesel freeze protection from ~2,500’ TVD to surface in 9-5/8” x 7-5/8” annulus by reverse circulating through the holes in the seal assembly. Ensure annular pressure are limited to prevent collapse of the 7-5/8” casing (verify collapse pressure of the 7-5/8” tieback assembly). 15.19 SO and land hanger. Confirm the hanger has seated properly in the wellhead. Make note of actual weight on the hanger in the morning report. 15.20 Back out landing joint. MU packoff running tool and install packoff on bottom of landing joint. Set tubing hanger packoff and RILDS. PT void to 3,000 psi for 10 minutes. 15.21 R/D casing running tools. 15.22 PT 9-5/8” x 7-5/8” annulus to 1,000 psi for 30 minutes charted. e Page 28 Version 1 March 2021 Milne Point Unit J-29A Drilling Procedure 16.0 Run 3-1/2” ESP Completion 16.1 RU spooler with ESP power cable and heat trace. 16.2 Verify the ESP components as per Centrilift. Verify that the length of the motor lead flat cable will place the splice between the discharge head and the 10’ handling pup collar. A Centrilift rep shall be on the rig floor at all times during the running of the ESP. 16.3 Makeup new ESP assembly with new motor lead extension, seal section and motor. 16.4 Run the 3-1/2” ESP Completion as noted below. 16.5 M/U ESP assy and RIH to setting depth. Confirm tally with Operations Engineer i. Ensure appropriate well control crossovers on rig floor and ready. ii. Monitor displacement from wellbore while RIH. x Centrilift ESP Assembly with bottom of assembly @ predetermined depth x 10’ 3-1/2” 9.3#, L-80 Pup Joint x 1 joint 3-1/2” 9.3#, L-80 EUE 8rd tubing x 3-1/2” “XN” nipple (2.813” packing bore / 2.750” No-Go ID) x 3 joints 3-1/2” 9.3#, L-80 EUE 8rd tubing x 10’ 3-1/2” 9.3#, L-80 Pup Joint x GLM 3-1/2” x 1” GLM w/ dummy installed x 10’ 3-1/2” 9.3#, L-80 Pup Joint x 3-1/2” 9.3#, L-80 EUE 8rd tubing x 10’ 3-1/2” 9.3#, L-80 Pup Joint x GLM 3-1/2” x 1” w/ SO @ ~140’ MD x 10’ 3-1/2” 9.3#, L-80 Pup Joint x 3 joints 3-1/2” 9.3#, L-80 EUE 8rd tubing x Tubing Hanger o Check the conductivity of electric cable every 2,000’ and every new splice while running in hole. o The make-up torque values for 3-1/2” L-80 9.3# EUE 8rd tubing are: Casing OD Minimum Optimum Maximum Operating Torque 2.875” 2,350 ft-lbs 3,130 ft-lbs 3,910 ft-lbs Page 29 Version 1 March 2021 Milne Point Unit J-29A Drilling Procedure 16.6 Fill tubing while splicing cable, mid-cable splices and tubing hanger splices. After tubing is full, break circulation by pumping 10 bbls down the tubing to clear any debris. 16.7 Record PU and SO weights before landing hanger. Note PU and SO weights on tally along with band/clamp summary. 16.8 MU tubing hanger and landing joint. Splice ESP power cable and terminate control lines. Test cable. Install a brass-shipping cap on the ESP penetrator. 16.9 Land tubing with extreme care to minimize damaging the ESP penetrator, pigtail and alignment pin. 16.10 RILDS and test hanger. LD landing joint. 16.11 Install BPV and N/D BOP. 16.12 N/U tree / adapter and tree. Test tubing hanger void to 500 psi low / 5000 psi high. Terminate the cap strings. 16.13 Circulate diesel freeze protection down 3-1/2” x 7-5/8” annulus (Volume should equal capacity of tubing to 2500’ + tubing annulus to 2500’). Connect IA to tree and allow diesel freeze protect to “U-tube” into position. Note – this may be done post-rig. 16.14 Pull BPV. Set TWC. Test tree to 250 psi low / 5000 psi high. Pull TWC. Set BPV. 16.15 Prepare to hand over well to production. Ensure necessary forms filled out and well handed over with valve alignment as per operations personnel. 16.16 RDMO Innovation Assure done before freezing can occur. Page 30 Version 1 March 2021 Milne Point Unit J-29A Drilling Procedure 17.0 Innovation BOP Schematic Typical Ram Configuration or 7-5/8" for tie-back Page 31 Version 1 March 2021 Milne Point Unit J-29A Drilling Procedure 18.0 Wellhead Schematic FMC Gen 5 Typical 2-7/8” Page 32 Version 1 March 2021 Milne Point Unit J-29A Drilling Procedure 19.0 Formation Information MPU J Pad Data Sheet Page 33 Version 1 March 2021 Milne Point Unit J-29A Drilling Procedure 20.0 Anticipated Drilling Hazards Window Exit: Tracking Casing The KOP is cemented. The risk of tracking casing is low. Production Hole Sections: Hole Cleaning: Maintain rheology of mud system. Sweep hole with low-vis water sweeps. Ensure shakers are set up with appropriate screens to maximize solids removal efficiency. Run centrifuge continuously. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Maintain circulation rate of > 300 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. Faulting: There is at least (1) fault that will be crossed while drilling the well. There could be others and the throw of these faults is not well understood at this point in time. When a known fault is coming up, ensure to put a “ramp” in the wellbore to aid in kicking off (low siding) later. Once a fault is crossed, we’ll need to either drill up or down to get a look at the LWD log and determine the throw and then replan the wellbore. H2S: Treat every hole section as though it has the potential for H2S. J-pad does not have a history of high H2S. J-10 had a sample measure at 10 ppm in 2009 which was the highest sample measurement recorded for any J-pad well. 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 abnormal. Utilize MPD to mitigate any abnormal pressure seen. Page 34 Version 1 March 2021 Milne Point Unit J-29A Drilling Procedure 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 M-43 has a 0.411 CF. M-43 is an active producer from the NB sands. A collision would result in drilling through an uncompleted section of M-43 (i.e. open hole in the rock below the shoetrack). Slight lost circulation might occur and there is no HSSE risk. x M-43PB3 has a 0.518 CF. This is an open hole PB. No risk. x J-29 has a 0.602 CF. There is no HSSE risk. The risk is financial (bit trip, OH sidetrack). Page 35 Version 1 March 2021 Milne Point Unit J-29A Drilling Procedure 21.0 Innovation Layout Page 36 Version 1 March 2021 Milne Point Unit J-29A Drilling Procedure 22.0 FIT Procedure Formation Integrity Test (FIT) and Leak-Off Test (LOT) Procedures Procedure for FIT: 1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe). 2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe. 3. Close the blowout preventer (ram or annular). 4. Pump down the drill stem at 1/4 to 1/2 bpm. 5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe. 6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes. Record time vs. pressure in 1-minute intervals. 7. Bleed the pressure off and record the fluid volume recovered. The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick tolerance in case well control measures are required. Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid; at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure monitored as with an FIT. Page 37 Version 1 March 2021 Milne Point Unit J-29A Drilling Procedure 23.0 Innovation Choke Manifold Schematic Page 38 Version 1 March 2021 Milne Point Unit J-29A Drilling Procedure 24.0 Casing Design Information Page 39 Version 1 March 2021 Milne Point Unit J-29A Drilling Procedure 25.0 8-1/2” Hole Section MASP Page 40 Version 1 March 2021 Milne Point Unit J-29A Drilling Procedure 26.0 Spider Plot (NAD 27) (Governmental Sections) Page 41 Version 1 March 2021 Milne Point Unit J-29A Drilling Procedure 27.0 Surface Plat (As Built) (NAD 27) 6WDQGDUG3URSRVDO5HSRUW 0DUFK 3ODQ038-$ZS +LOFRUS$ODVND//& 0LOQH3RLQW 03W-3DG 3ODQ038- 3ODQ038-$ 075015002250300037504500True Vertical Depth (1500 usft/in)6000 6750 7500 8250 9000 9750 10500 11250 12000 12750 13500 14250 15000 15750 16500 17250 18000 18750 19500 20250Vertical Section at 282.50° (1500 usft/in)MPU J-29A wp01 CP1MPU J-29A wp01 CP2MPU J-29A wp01 CP3MPU J-29A wp01 CP4MPU J-29A wp01 CP5MPU J-29A wp01 CP6MPU J-29A wp01 CP7MPU J-29A wp01 CP8MPU J-29A wp01 CP98000850090009500 10000 10500 11000 11500 12000 12500 13000 13500 14000 14500 15000 15500 16000 16500 17000 17500 1 792 1MPU J-299 5/8" TOW4 1/2" x 8 1/2"95001000010500110001150012000125001300013500140001450015000155001600016500170001750017901MPU J-29A wp03KOP: Start Dir 9º/100' : 9114.12' MD, 3771.25'TVD : 60° RT TFEnd Dir : 9131.12' MD, 3774' TVDStart Dir 4.5º/100' : 9161.12' MD, 3778.65'TVDStart Dir 2º/100' : 9436.12' MD, 3792.77'TVDEnd Dir : 9499.13' MD, 3789.43' TVDStart Dir 2º/100' : 9951.49' MD, 3765.34'TVDEnd Dir : 10402.87' MD, 3751.21' TVDStart Dir 2º/100' : 10773.22' MD, 3745.21'TVDEnd Dir : 11396.37' MD, 3733.33' TVDStart Dir 2º/100' : 11896.37' MD, 3722.42'TVDEnd Dir : 12211.87' MD, 3703.25' TVDFAULT #2Start Dir 2º/100' : 12555.14' MD, 3669.07'TVDEnd Dir : 12877.53' MD, 3654.33' TVDStart Dir 2º/100' : 13220.87' MD, 3657.73'TVDEnd Dir : 13468.36' MD, 3651.92' TVDFAULT #3Start Dir 2º/100' : 13692.27' MD, 3643.95'TVDEnd Dir : 14240.21' MD, 3627.25' TVDFAULT #4Start Dir 2º/100' : 14410.21' MD, 3615.99'TVDStart Dir 4.23º/100' : 14550.26' MD, 3610.12'TVDEnd Dir : 14736.6' MD, 3608.21' TVDFAULT #5Start Dir 2º/100' : 15100.58' MD, 3607.12'TVDEnd Dir : 15578.94' MD, 3605.65' TVDStart Dir 1º/100' : 16700.09' MD, 3602.12'TVDEnd Dir : 17178.84' MD, 3592.84' TVDM-43 Pass byM-43PB3 Pass byTotal Depth : 17900.77' MD, 3567.12' TVDSCHRADER NBHilcorp Alaska, LLCCalculation Method:Minimum CurvatureError System:ISCWSAScan Method: Closest Approach 3DError Surface: Ellipsoid SeparationWarning Method: Error RatioWELL DETAILS: Plan: MPU J-2933.70+N/-S +E/-W NorthingEastingLatittudeLongitude0.000.006015068.010551934.08070° 27' 6.8690 N149° 34' 34.5117 WSURVEY PROGRAMDate: 2021-03-19T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool232.32 1364.73 MPU J-29 Gyro MWD Tie-on (MPU J-29) 3_Gyro-MWD90+Sag1418.54 9114.12 MPU J-29 Surface MWD+IFR2+MS+Sag (MPU J-29) 3_MWD+IFR2+MS+Sag9114.12 9500.00 MPU J-29A wp03 (Plan: MPU J-29A) 3_MWD_Interp Azi+Sag9500.00 17900.77 MPU J-29A wp03 (Plan: MPU J-29A) 3_MWD+IFR2+MS+SagFORMATION TOP DETAILSTVDPath TVDssPath MDPath Formation3771.20 3711.00 9113.84 SCHRADER NBREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU J-29, True NorthVertical (TVD) Reference:MPU J-29A As- Built RKB @ 60.20usftMeasured Depth Reference:MPU J-29A As- Built RKB @ 60.20usftCalculation Method:Minimum CurvatureProject:Milne PointSite:M Pt J PadWell:Plan: MPU J-29Wellbore:Plan: MPU J-29ADesign:MPU J-29A wp03CASING DETAILSTVD TVDSS MD SizeName3771.40 3711.20 9115.00 9-5/8 9 5/8" TOW3567.12 3506.92 17900.77 4-1/2 4 1/2" x 8 1/2"SECTION DETAILSSec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation1 9114.12 80.31 265.48 3771.25 3532.69 -6240.94 0.00 0.00 6857.44 KOP: Start Dir 9º/100' : 9114.12' MD, 3771.25'TVD : 60° RT2 9131.12 81.07 266.83 3774.00 3531.56 -6257.68 9.00 60.00 6873.53 End Dir : 9131.12' MD, 3774' TVD3 9161.12 81.07 266.83 3778.65 3529.92 -6287.27 0.00 0.00 6902.07 Start Dir 4.5º/100' : 9161.12' MD, 3778.65'TVD4 9436.12 93.03 270.01 3792.77 3522.40 -6561.27 4.50 15.00 7167.95 Start Dir 2º/100' : 9436.12' MD, 3792.77'TVD5 9499.13 93.05 271.27 3789.43 3523.11 -6624.18 2.00 89.12 7229.53 End Dir : 9499.13' MD, 3789.43' TVD6 9951.49 93.05 271.27 3765.34 3533.15 -7075.79 0.00 0.00 7672.61 Start Dir 2º/100' : 9951.49' MD, 3765.34'TVD7 10091.76 92.00 268.67 3759.16 3533.08 -7215.91 2.00 -111.96 7809.40 MPU J-29A wp01 CP18 10402.87 90.93 262.54 3751.21 3509.25 -7525.85 2.00 -99.84 8106.84 End Dir : 10402.87' MD, 3751.21' TVD9 10773.22 90.93 262.54 3745.21 3461.16 -7893.02 0.00 0.00 8454.91 Start Dir 2º/100' : 10773.22' MD, 3745.21'TVD10 11396.37 91.25 275.00 3733.33 3447.81 -8514.68 2.00 88.40 9058.96 End Dir : 11396.37' MD, 3733.33' TVD11 11896.37 91.25 275.00 3722.42 3491.37 -9012.66 0.00 0.00 9554.57 MPU J-29A wp01 CP2 Start Dir 2º/100' : 11896.37' MD, 3722.42'TVD12 12211.87 95.72 270.53 3703.25 3506.59 -9327.05 2.00 -44.85 9864.81 End Dir : 12211.87' MD, 3703.25' TVD13 12555.14 95.72 270.53 3669.07 3509.76 -9668.60 0.00 0.00 10198.95 Start Dir 2º/100' : 12555.14' MD, 3669.07'TVD14 12699.22 93.00 271.50 3658.12 3512.31 -9812.23 2.00 160.39 10339.73 MPU J-29A wp01 CP315 12877.53 89.43 271.51 3654.33 3516.99 -9990.40 2.00 179.89 10514.69 End Dir : 12877.53' MD, 3654.33' TVD16 13220.87 89.43 271.51 3657.73 3526.01 -10333.61 0.00 0.00 10851.73 Start Dir 2º/100' : 13220.87' MD, 3657.73'TVD17 13349.20 92.00 271.45 3656.12 3529.32 -10461.88 2.00 -1.26 10977.67 MPU J-29A wp01 CP418 13468.36 92.04 273.83 3651.92 3534.81 -10580.83 2.00 89.02 11094.99 End Dir : 13468.36' MD, 3651.92' TVD19 13692.27 92.04 273.83 3643.95 3549.78 -10804.09 0.00 0.00 11316.20 Start Dir 2º/100' : 13692.27' MD, 3643.95'TVD20 14100.16 91.00 265.74 3633.12 3548.26 -11211.49 2.00 -97.20 11713.62 MPU J-29A wp01 CP521 14240.21 93.80 265.73 3627.25 3537.86 -11351.01 2.00 -0.14 11847.59 End Dir : 14240.21' MD, 3627.25' TVD22 14410.21 93.80 265.73 3615.99 3525.23 -11520.17 0.00 0.00 12010.02 Start Dir 2º/100' : 14410.21' MD, 3615.99'TVD23 14550.26 91.00 265.74 3610.12 3514.83 -11659.69 2.00 179.86 12143.98 MPU J-29A wp01 CP6 Start Dir 4.23º/100' : 14550.26' MD, 3610.12'TVD24 14736.60 90.17 257.90 3608.21 3488.34 -11843.99 4.23 -95.98 12318.19 End Dir : 14736.6' MD, 3608.21' TVD25 15100.58 90.17 257.90 3607.12 3412.05 -12199.88 0.00 0.00 12649.13 MPU J-29A wp01 CP7 Start Dir 2º/100' : 15100.58' MD, 3607.12'TVD26 15578.94 90.18 267.47 3605.65 3351.21 -12673.79 2.00 89.93 13098.66 End Dir : 15578.94' MD, 3605.65' TVD27 16700.09 90.18 267.47 3602.12 3301.68 -13793.84 0.00 0.00 14181.46 MPU J-29A wp01 CP8 Start Dir 1º/100' : 16700.09' MD, 3602.12'TVD28 17178.84 92.04 271.88 3592.84 3298.95 -14272.35 1.00 67.09 14648.05 End Dir : 17178.84' MD, 3592.84' TVD29 17900.77 92.04 271.88 3567.12 3322.62 -14993.44 0.00 0.00 15357.18 MPU J-29A wp01 CP9 Total Depth : 17900.77' MD, 3567.12' TVD 7001400210028003500420049005600630070007700South(-)/North(+) (1050 usft/in)-15400 -14700 -14000 -13300 -12600 -11900 -11200 -10500 -9800 -9100 -8400 -7700 -7000 -6300 -5600West(-)/East(+) (1050 usft/in)MPU J-29A wp01 CP9MPU J-29A wp01 CP8MPU J-29A wp01 CP7MPU J-29A wp01 CP6MPU J-29A wp01 CP5MPU J-29A wp01 CP4MPU J-29A wp01 CP3MPU J-29A wp01 CP2MPU J-29A wp01 CP13 7 5 0 355 8 MPU J-293567MPU J-29A wp03KOP: Start Dir 9º/100' : 9114.12' MD, 3771.25'TVD : 60° RT TFEnd Dir : 9131.12' MD, 3774' TVDStart Dir 4.5º/100' : 9161.12' MD, 3778.65'TVDStart Dir 2º/100' : 9436.12' MD, 3792.77'TVDEnd Dir : 9499.13' MD, 3789.43' TVDStart Dir 2º/100' : 9951.49' MD, 3765.34'TVDEnd Dir : 10402.87' MD, 3751.21' TVDStart Dir 2º/100' : 10773.22' MD, 3745.21'TVDEnd Dir : 11396.37' MD, 3733.33' TVDStart Dir 2º/100' : 11896.37' MD, 3722.42'TVDEnd Dir : 12211.87' MD, 3703.25' TVDFAULT #2Start Dir 2º/100' : 12555.14' MD, 3669.07'TVDEnd Dir : 12877.53' MD, 3654.33' TVDStart Dir 2º/100' : 13220.87' MD, 3657.73'TVDEnd Dir : 13468.36' MD, 3651.92' TVDFAULT #3Start Dir 2º/100' : 13692.27' MD, 3643.95'TVDEnd Dir : 14240.21' MD, 3627.25' TVDFAULT #4Start Dir 2º/100' : 14410.21' MD, 3615.99'TVDStart Dir 4.23º/100' : 14550.26' MD, 3610.12'TVDEnd Dir : 14736.6' MD, 3608.21' TVDFAULT #5Start Dir 2º/100' : 15100.58' MD, 3607.12'TVDEnd Dir : 15578.94' MD, 3605.65' TVDStart Dir 1º/100' : 16700.09' MD, 3602.12'TVDEnd Dir : 17178.84' MD, 3592.84' TVDM-43 Pass byM-43PB3 Pass byTotal Depth : 17900.77' MD, 3567.12' TVDProject: Milne PointSite: M Pt J PadWell: Plan: MPU J-29Wellbore: Plan: MPU J-29APlan: MPU J-29A wp03WELL DETAILS: Plan: MPU J-2933.70+N/-S +E/-W Northing Easting Latittude Longitude0.000.006015068.010551934.08070° 27' 6.8690 N149° 34' 34.5117 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU J-29, True NorthVertical (TVD) Reference: MPU J-29A As- Built RKB @ 60.20usftMeasured Depth Reference:MPU J-29A As- Built RKB @ 60.20usftCalculation Method:Minimum CurvatureCASING DETAILSTVD TVDSS MD Size Name3771.40 3711.20 9115.00 9-5/8 9 5/8" TOW3567.12 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0.001.002.003.004.00Separation Factor9500 9975 10450 10925 11400 11875 12350 12825 13300 13775 14250 14725 15200 15675 16150 16625 17100 17575 18050Measured Depth (950 usft/in)MPJ-24MPJ-24AMPJ-24L1PB1MPJ-24L1PB2MPU J-30MPU J-29MPU J-31i wp02MPU M-14MPU M-15iMPU M-16MPU M-17iMPU M-18MPU M-18PB2MPU M-19iMPU M-34MPU M-35iMPU M-43MPU M-43PB2MPU M-43PB3No-Go Zone - Stop DrillingCollision Avoidance Req.Collision Risk Procedures Req.WELL DETAILS:Plan: MPU J-29 NAD 1927 (NADCON CONUS)Alaska Zone 0433.70+N/-S +E/-W Northing EastingLatittudeLongitude0.000.006015068.010551934.08070° 27' 6.8690 N149° 34' 34.5117 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU J-29, True NorthVertical (TVD) Reference:MPU J-29A As- Built RKB @ 60.20usftMeasured Depth Reference:MPU J-29A As- Built RKB @ 60.20usftCalculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2021-03-19T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool232.32 1364.73 MPU J-29 Gyro MWD Tie-on (MPU J-29) 3_Gyro-MWD90+Sag1418.54 9114.12 MPU J-29 Surface MWD+IFR2+MS+Sag (MPU J-29) 3_MWD+IFR2+MS+Sag9114.12 9500.00 MPU J-29A wp03 (Plan: MPU J-29A) 3_MWD_Interp Azi+Sag9500.00 17900.77 MPU J-29A wp03 (Plan: MPU J-29A) 3_MWD+IFR2+MS+Sag0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)9500 9975 10450 10925 11400 11875 12350 12825 13300 13775 14250 14725 15200 15675 16150 16625 17100 17575 18050Measured Depth (950 usft/in)MPU J-29NO GLOBAL FILTER: Using user defined selection & filtering criteria9114.12 To 17900.77Project: Milne PointSite: M Pt J PadWell: Plan: MPU J-29Wellbore: Plan: MPU J-29APlan: MPU J-29A wp03CASING DETAILSTVD TVDSS MD Size Name3771.40 3711.20 9115.00 9-5/8 9 5/8" TOW3567.12 3506.92 17900.77 4-1/2 4 1/2" x 8 1/2" 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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PriceDigitally signed by Jeremy M. Price Date: 2021.04.14 13:06:56 -08'00'