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Home My WebLink About220-0591. 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: Install TTCPCP 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): 13,520'N/A Casing Collapse Conductor N/A Surface 4,760psi Surface 3,090psi Tieback 7,020psi Liner 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: Contact Email: Contact Phone: Authorized Title: Wells Manager 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 3,873' 13,520' 3,873' 1,241 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 L-62 AOGCC USE ONLY Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): 3/30/2025 Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0025509 & ADL0025515 220-059 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 50-029-23685-00-00 Hilcorp Alaska LLC C.O. 477.05 Length Size Proposed Pools: 130' 130' 6.5 / L-80 EUE 8rd TVD Burst 5,910' 9,020psi MD N/A 8,160psi 6,870psi 5,750psi 2,020' 3,998' 4,001' 2,625' 7,146' 130' 20" 9-5/8" 9-5/8" 2,625' 7-5/8"7,000' 4,521' 7,000' See Schematic 6,531' See Schematic 2-7/8" 3,873'4-1/2" DLESP Retrievable & BOT SLZXP LTP and N/A 1,993 MD/ 1,672 TVD & 6,989 MD/ 4,001 TVD and N/A Ryan Lewis ryan.lewis@hilcorp.com 303-906-5178 13,520' 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 2:21 pm, Mar 26, 2025 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143) Date: 2025.03.26 14:02:13 - 08'00' Taylor Wellman (2143) 325-174 DSR-4/2/25 10-404 *BOPE test to 2000 psi. SFD 3/27/2025MGR27MAR25*&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.04.03 10:48:01 -08'00'04/03/25 RBDMS JSB 040425 Well: MPL-62 PTD: 220-059 API: 50-029-23685-00-00 Well Name:MPL-62 API Number:50-029-23685-00-00 Current Status:Shut-in Producer Rig:ASR #1 Estimated Start Date:3/30/25 Estimated Duration:4days Regulatory Contact:Tom Fouts Permit to Drill Number:220-059 First Call Engineer:Ryan Lewis (303) 906-5178 (M) Second Call Engineer:Taylor Wellman (907) 777-8449 (O) (907) 947-9533 (M) Current Bottom Hole Pressure:1,613 psi @ 3,718’ TVD 3/18/2025 | 8.4 PPGE 8.7 KWF Max Potential Surface Pressure:1,241 psi Gas Column Gradient (0.1 psi/ft) Max Angle:68° Sail Angle from 5,835’ MD Brief Well Summary: MPU L-62 was drilled and completed as a Schrader Bluff producer with an ESP installed in September 2020. ESP replaced in March 2021 and March 2024. It runs in a slug flow regime and never lines out. This well makes heavy viscous Shrader oil that is more tailored to a successful PCP run. Objectives: Pull failed ESP, run TTCPCP with a permanent mag motor (PMM). Notes Regarding Wellbore Condition: - 9/5/20 Original completion 7-5/8” x 9-5/8” annulus test to 1,000 psi. - 3/28/24 IA packer test to 1,500 psi @ 1,993’ MD Pre-Rig Procedure (Non Sundried Work) Slickline –Obtain updated SBHPS 2 weeks prior to RWO 1. RU slickline, pressure test PCE to 250psi low / 2,500psi high. 2. Drift and tag with sample bailer. 3. Run SBHPS with 10 min stops @ 5,800’ & 4,800’ MD 4. RDMO. Pumping & Well Support 1. Clear and level pad area in front of well. Spot rig mats and containment. 2. RD well house and flowlines. Clear and level area around well. 3. RU Little Red Services. RU reverse out skid and 500 barrel returns tank. 4. Pressure test lines to 3,000 psi. 5. Circulate at least one wellbore volume with 9.1# brine down tubing, taking returns up casing to 500 barrel returns tank. 6. Confirm well is dead. Contact operations engineer if freeze protection is needed prior to ASR arrival. 7. RD Little Red Services and reverse out skid. 8. Set BPV. ND tree. NU BOPE. Brief RWO Procedure (Begin Sundried Work) Well: MPL-62 PTD: 220-059 API: 50-029-23685-00-00 1. MIRU Hilcorp ASR #1 WO Rig, ancillary equipment, and lines to 500 barrel returns tank. 2. Check for pressure and if 0 psi set CTS plug. If needed, bleed off any residual pressure off tubing and casing. a. If needed, kill well with 9.1# brine water prior to setting CTS. 3. Test BOPE to 250 psi low/ 2,000 psi high. Test annular to 250 psi low/ 2,000 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 the single ram on 2-3/8” test joints. e. Test VBR rams on 2-7/8” and 3-1/2” test joints. f. Submit to AOGCC completed 10-424 form within 5 days of BOPE test. 4. Bleed any pressure on casing to the returns tank. Pull CTS plug. Bleed any pressure off tubing to the returns tank. Kill well with 9.1# brine down as needed. Pull BPV. a. If indications show pressure underneath BPV, lubricate out BPV. 5. Call out Summit for ESP pull. 6. RU spoolers to handle ESP cable and packer vent line. 7. MU landing joint or spear, BOLDS, PU on the tubing hanger. a. Tubing hanger is an 11"x 2 7/8" Gen 5 HGR, 2 7/8'' EUE Top & BTM. b. 2024 tubing PU weight on ASR #1 recorded as 29 kip. Slack off weight recorded as 22 kip. c. The ESP packer is pinned to shear release at 20k overpull. Estimated PUW to release packer is ~49 Klbs. d. 2-7/8” L-80 EUE yield is 144 kip. 8. Confirm hanger free, lay down tubing hanger. 9. POOH and lay down the 2-7/8” tubing. Vent packer is at ~2,000’. a. Send tubing for inspection and reuse on a future well. b. Keep ported discharge head and centralizer for future use. c. Note any sand or scale inside or on the outside of the ESP on the morning report. d. Recorded Clamp Totals: i. Canon Clamps: 103 ii. Half Clamps =1 iii. Motor Clamps =4 iv. MLE Clamps = 1 v. Seal clamps = 4 vi. Pump Clamps: 3 10. Lay Down ESP. 11. PU 3.75” junk mill, 2.88” motor, 6,800’ of 2-3/8” PH-6 cross over to 6,900’ of 3-1/2” work string. TIH and cleanout to PBTD. 12. If needed, pump a 500 gal acetic acid pill around to clean up the polymer sludge in the wellbore. 13. Circulate 2x bottoms up at a minimum rate of 5 BPM. POOH. 14. MU PMM motor, seals and PCP landing BHA. Well: MPL-62 PTD: 220-059 API: 50-029-23685-00-00 a.PMM motors have the potential to generate power at the pump and communicate that back to surface. Confirm no current every time before working with the cable. If the PCP is installed there is potential for current at surface. We not plan to install the pumps until after the RWO so there will not be a hazard until the pumps are installed. b.Anyone working with the TTCPCP must understand the risks and be certified to work around PMM motors. 15. RIH with 3-1/2” 9.3# L-80 TTCPCP completion to +/- 5,900’ and obtain string weights. a. Check electrical continuity every 1000’. b. Note PU and SO weights on tally. c. Install ESP clamps per Summit, and cross coupling clamps every other joint d. Photograph vent packer prior to running in hole. Nom. Size Length Item Lb/ft Material Notes 5.85 2 Centralizer 4 ~5,900 4.5 2 Intake Sensor 30 4.5 34 PMM Motor - 42HP 80 5.13 7 Lower Tandem Seal 38 5.13 7 Upper Tandem Seal 38 3.5 8 PCP Receiving Base 52 3-1/2" 10 3-1/2" EUE 8rd Pup Jt 9.3 L-80 3-1/2" 30 3-1/2" EUE 8rd L-80 9.3 L-80 3-1/2"10 3-1/2" EUE 8rd Pup Jt 9.3 L-80 3-1/2"8 3-1/2" x 1" GLM, DV installed 9.3 L-80 3-1/2"10 3-1/2" EUE 8rd Pup Jt 9.3 L-80 3-1/2"~5,500 3-1/2" EUE 8rd Jt 9.3 L-80 3-1/2"10 3-1/2" EUE 8rd Pup Jt 9.3 L-80 3-1/2"8 3-1/2" x 1" GLM, DPSOV installed 9.3 L-80 ~200 MD 3-1/2"10 3-1/2" EUE 8rd Pup Jt 9.3 L-80 3-1/2"150 3-1/2" EUE 8rd Jt 9.3 L-80 3-1/2"10 Space out pup 9.3 L-80 3-1/2"30 Tubing Hanger with full joint L-80 16. Continue running ESP completion per plan. 17. PU and MU the 3-1/2” tubing hanger. Make final splice of the ESP cable to the penetrator. 18. Land tubing hanger, avoiding any damage to ESP cable. RILDS. Lay down landing joint. Note PU and SO weights on tally and in daily report. 19. Set BPV. 20. RDMO ASR. Post-Rig Procedure: Electrical Well: MPL-62 PTD: 220-059 API: 50-029-23685-00-00 1. The drive, transformer, and junction box all need to be labeled with warning signs that we have 2 sources of electricity, the grid and from downhole at the PMM. 2. A disconnect switch needs to be installed on the down stream side of the drive. Well Support 1. RD mud boat. RD BOPE house. Move to next well location. 2. RU crane. ND BOPE, set CTS plug, and NU tree. 3. Test tubing hanger void to 500 psi low/5,000 psi high. Pull CTS and BPV. 4. RD crane. Move 500 bbl returns tank and rig mats to next well location. 5. RU well house and flowlines. Slickline 1. RU slickline, pressure test PCE to 250psi low / 2,500psi high. 2. Drift and tag PCP receiving base. 3. RIH and set TTCPCP. Attachments: 1. Current Wellbore Schematic 2. Proposed Wellbore Schematic 3. BOPE Schematic _____________________________________________________________________________________ Revised By: TDF 4/3/2024 SCHEMATIC Milne Point Unit Well: MPU L-62 Last Completed: 3/28/2024 PTD: 220-059 TD =13,520’(MD) / TD =3,873’ (TVD) 6 20” Orig. KB Elev.: 50.41’ / GL Elev.: 17.1’ 7-5/8” 10 12 &13 14 4 19 9-5/8” 1 2 5 See Screen/ Solid Liner Detail PBTD =13,520’ (MD) / PBTD = 3,873’ (TVD) 9-5/8” ‘ES’ Cementer @ 2,645’ MD 8 &9 4-1/2” Shoe @ 13,520’ 16 15 17 18 3 4 7 11 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20" Conductor 129.5 / A53 / Weld N/A Surface 130’ N/A 9-5/8" Surface 47 / L-80 / TXP 8.681 Surface 2,625’ 0.0758 9-5/8” Surface 40 / L-80 / TXP 8.835 2,625’ 7,146’ 0.0732 7-5/8” Tieback 29.7 / L-80 / Hyd 521 6.875 Surface 7,000’ 0.0459 4-1/2” Liner 13.5 / L-80 / Hyd 625 3.920 6,989’ 13,520’ .0149 TUBING DETAIL 2-7/8" Tubing 6.5 / L-80 / EUE R2 2.441 Surface 5,910’ 0.0087 OPEN HOLE / CEMENT DETAIL 2” ±270 ft3 12- 1/4" Stg 1 – Lead – 635 sx / Tail – 400 sx Stg 2 – Lead – 780 sx / Tail – 288 sx 8-1/2” Cementless Screened Liner WELL INCLINATION DETAIL KOP @ 258’ Max Hole Angle = 95° @ 9,913’ MD TREE & WELLHEAD Tree Cameron 2-9/16" 5M w/ 4-1/16” 5M Cameron Wing Wellhead Cameron 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs GENERAL WELL INFO API: 50-029-23685-00-00 Completion Date: 9/7/2020 ESP Swap by ASR#1 3/28/2024 JEWELRY DETAIL No. Top MD Item ID 1 199’ Sta. 4: 2-7/8" x 1" GLM W/ BK-Dummy Valve 2.347” 2 1,929’ Sta. 3: 2-7/8" GLM W/ 1" BK-Dummy Valve 2.347” 3 1,993’ 7-5/8" x 3-1/2"x1.900" DLESP Retrievable Packer 2.957 4 2,052’ Sta. 2: 2-7/8" GLM W/ 1" BK-Dummy Valve 2.347” 5 2,111’ 2-7/8" X-Nipple 2.313" I.D. w/ RHC-M 2.313” 6 5,689’ Sta. 1: 2-7/8" GLM W/ 1" Dummy Valve 2.347” 7 5,779’ XN-Nipple 2.313"Profile, 2.205" No-Go 2.205” 8 5,832’ Ported Pressure Sub Adapter 9 5,833’ Discharge Head Bolt On 10 5,834’ Pump: 538,SJ1700,114S,INC,15,1:1AR,HTEM 11 5,857’ Intake Sub Assy: P/N 103005623 12 5,865’ Upper Tandem Seal: P/N 900566029 13 5,874’ Lower Tandem Seal: P/N 900566003 14 5,883’ Motor: 562/KMS2/360HP/3175V/70A 15 5,906’ Guage & Centralizer:Btm @ 5,910’ 16 6,989’ BOT SLZXP LTP / Liner Hanger 7” x 9-5/8” (4001’ TVD) 7.020” 17 6,989’ Locator Sub, 7” TXP Box x Box 6.170” 18 7,011’ 7” H563 x 4.5” TSH 625 XO 3.850” 19 13,520’ Shoe 3.950” 4-1/2” 250ђ SCREENSLINER DETAIL Jts Top (MD) Top (TVD) Btm (MD) Btm (TVD) 3 8207’ 3968’ 8334’ 3963’ 20 8458’ 3959’ 9268’ 3931’ 3 9430’ 3927’ 9549’ 3931’ 19 10041’ 3916’ 10817’ 3886’ 25 11141’ 3877’ 12187’ 3879’ 23 12516’ 3878’ 13477’ 3873’ _____________________________________________________________________________________ Revised By: TDF 3/26/2025 PROPOSED Milne Point Unit Well: MPU L-62 Last Completed: 3/28/2024 PTD: 220-059 TD =13,520’(MD) / TD =3,873’ (TVD) 20” Orig. KB Elev.: 50.41’ / GL Elev.: 17.1’ 7-5/8”9 & 10 11 16 9-5/8” 3 4 See Screen/ Solid Liner Detail PBTD =13,520’ (MD) / PBTD =3,873’ (TVD) 9-5/8” ‘ES’ Cementer @ 2,645’ MD 5, 6 & 7 4-1/2” Shoe @ 13,520’ 13 12 14 15 1 2 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20" Conductor 129.5 / A53 / Weld N/A Surface 130’ N/A 9-5/8" Surface 47 / L-80 / TXP 8.681 Surface 2,625’ 0.0758 9-5/8” Surface 40 / L-80 / TXP 8.835 2,625’ 7,146’ 0.0732 7-5/8” Tieback 29.7 / L-80 / Hyd 521 6.875 Surface 7,000’ 0.0459 4-1/2” Liner 13.5 / L-80 / Hyd 625 3.920 6,989’ 13,520’ .0149 TUBING DETAIL 3-1/2" Tubing 9.2 / L-80 / EUE 8rd 2.992 Surface ±5,900’ 0.0087 OPEN HOLE / CEMENT DETAIL 2” ±270 ft3 12- 1/4" Stg 1 –Lead –635 sx / Tail –400 sx Stg 2 – Lead – 780 sx / Tail – 288 sx 8-1/2” Cementless Screened Liner WELL INCLINATION DETAIL KOP @ 258’ Max Hole Angle = 95° @ 9,913’ MD TREE & WELLHEAD Tree Cameron 2-9/16" 5M w/ 4-1/16” 5M Cameron Wing Wellhead Cameron 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs GENERAL WELL INFO API: 50-029-23685-00-00 Completion Date: 9/7/2020 ESP Swap by ASR#1 3/28/2024 JEWELRY DETAIL No. Top MD Item ID 1 ±XXX’ 3-1/2" x 1" GLM, DV installed 2 ±X,XXX’ 3-1/2" x 1" GLM, DV installed 3 ±X,XXX’ D&D Packoff & Stinger assembly 4 ±X,XXX’ Pump, Discharge head, Hanger receptacle 5 ±X,XXX’ Pump 380 SXD 116-P18UT 6 ±X,XXX’ P2P Pump 380 SXD 116-Flex 17.5 7 ±X,XXX’ P2P Pump 380 SXD 116-Flex 17.5 8 ±X,XXX’Intake Sub Assy: 9 ±X,XXX’ Upper Tandem Seal: 10 ±X,XXX’ Lower Tandem Seal: 11 ±X,XXX’ Motor: 562/KMS2/360HP/3175V/70A 12 ±X,XXX’ Guage & Centralizer: Btm @ ±5,900’ 13 6,989’ BOT SLZXP LTP / Liner Hanger 7” x 9-5/8” (4001’ TVD) 7.020” 14 6,989’ Locator Sub, 7” TXP Box x Box 6.170” 15 7,011’ 7” H563 x 4.5” TSH 625 XO 3.850” 16 13,520’ Shoe 3.950” 4-1/2” 250ђ SCREENS LINER DETAIL Jts Top (MD) Top (TVD) Btm (MD) Btm (TVD) 3 8207’ 3968’ 8334’ 3963’ 20 8458’ 3959’ 9268’ 3931’ 3 9430’ 3927’ 9549’ 3931’ 19 10041’ 3916’ 10817’ 3886’ 25 11141’ 3877’ 12187’ 3879’ 23 12516’ 3878’ 13477’ 3873’ Updated 10/9/2024 11” BOPE INTEGRATED 11'’-5000 INTEGRATED 4.30'INTEGRATED 11" - 5000 2-7/8" x 5" VBR Blind 11'’- 5000 2 1/16 5M Kill Line Valves 2 1/16 5M Choke Line Valves HCRManualManual Stripping Head ManualManual 2-3/8" Pipe Ram Milne Point ASR 11” BOP w/ Jacks 05/17/2017 Milne Point ASR 11” BOP (Triple) 10/9/2024 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: Install TTCPCP 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): 13,520'N/A Casing Collapse Conductor N/A Surface 4,760psi Surface 3,090psi Tieback 7,020psi Liner 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: Contact Email: Contact Phone: Authorized Title: Wells Manager 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 DLESP Retrievable & BOT SLZXP LTP and N/A 1,993 MD/ 1,672 TVD & 6,989 MD/ 4,001 TVD and N/A Ryan Lewis ryan.lewis@hilcorp.com 303-906-5178 13,520' Perforation Depth MD (ft): 7,000' See Schematic 6,531' See Schematic 2-7/8" 3,873'4-1/2" 130' 20" 9-5/8" 9-5/8" 2,625' 7-5/8"7,000' 4,521' MD N/A 8,160psi 6,870psi 5,750psi 2,020' 3,998' 4,001' 2,625' 7,146' Length Size Proposed Pools: 130' 130' 6.5 / L-80 EUE 8rd TVD Burst 5,910' 9,020psi STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0025509 & ADL0025515 220-059 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 50-029-23685-00-00 Hilcorp Alaska LLC C.O. 477.05 AOGCC USE ONLY Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): 12/25/2024 Subsequent Form Required: 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 L-62 MILNE POINT SCHRADER BLUFF OIL N/A 3,873' 13,520' 3,873' 1,335 N/A 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 8:19 am, Oct 11, 2024 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143) Date: 2024.10.10 20:17:41 - 08'00' Taylor Wellman (2143) 324-592 DSR-10/14/24 10-404 SFD 10/27/2024MGR28OCT24 * BOPE test to 2000 psi. JLC 10/28/2024 Gregory Wilson Digitally signed by Gregory Wilson Date: 2024.10.29 03:27:28 -08'00'10/29/24 RBDMS JSB 102924 Well: MPL-62 PTD: 220-059 API: 50-029-23685-00-00 Well Name:MPL-62 API Number:50-029-23685-00-00 Current Status:Shut-in Producer Rig:ASR #1 Estimated Start Date:12/25/24 Estimated Duration:4 days Regulatory Contact:Tom Fouts Permit to Drill Number:220-059 First Call Engineer:Ryan Lewis (303) 906-5178 (M) Second Call Engineer:Taylor Wellman (907) 777-8449 (O) (907) 947-9533 (M) Current Bottom Hole Pressure: 1,707 psi @ 3,718’ TVD 7/14/2024 | 8.8 PPGE 9.1 KWF Max Potential Surface Pressure: 1,335 psi Gas Column Gradient (0.1 psi/ft) Max Angle:68° Sail Angle from 5,835’ MD Brief Well Summary: MPU L-62 was drilled and completed as a Schrader Bluff producer with an ESP installed in September 2020. ESP replaced in March 2021 and March 2024. It runs in a slug flow regime and never lines out. This well makes heavy viscous Shrader oil that is more tailored to a successful PCP run. Objectives: Pull failed ESP, run TTCPCP with a permanent mag motor (PMM). Notes Regarding Wellbore Condition: - 9/5/20 Original completion 7-5/8” x 9-5/8” annulus test to 1,000 psi. - 3/28/24 IA packer test to 1,500 psi @ 1,993’ MD Pre-Rig Procedure (Non Sundried Work) Slickline –Obtain updated SBHPS 2 weeks prior to RWO 1. RU slickline, pressure test PCE to 250psi low / 2,500psi high. 2. Drift and tag with sample bailer. 3. Run SBHPS with 10 min stops @ 5,800’ & 4,800’ MD 4. RDMO. Pumping & Well Support 1. Clear and level pad area in front of well. Spot rig mats and containment. 2. RD well house and flowlines. Clear and level area around well. 3. RU Little Red Services. RU reverse out skid and 500 barrel returns tank. 4. Pressure test lines to 3,000 psi. 5. Circulate at least one wellbore volume with 9.1# brine down tubing, taking returns up casing to 500 barrel returns tank. 6. Confirm well is dead. Contact operations engineer if freeze protection is needed prior to ASR arrival. 7. RD Little Red Services and reverse out skid. 8. Set BPV. ND tree. NU BOPE. Brief RWO Procedure (Begin Sundried Work) 8.8 PPGE 9.1 KWF 9.1# brine down tubing Well: MPL-62 PTD: 220-059 API: 50-029-23685-00-00 1. MIRU Hilcorp ASR #1 WO Rig, ancillary equipment, and lines to 500 barrel returns tank. 2. Check for pressure and if 0 psi set CTS plug. If needed, bleed off any residual pressure off tubing and casing. a. If needed, kill well with 9.1# brine water prior to setting CTS. 3. Test BOPE to 250 psi low/ 2,000 psi high. Test annular to 250 psi low/ 2,000 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 the single ram on 2-3/8” test joints. e. Test VBR rams on 2-7/8” and 3-1/2” test joints. f. Submit to AOGCC completed 10-424 form within 5 days of BOPE test. 4. Bleed any pressure on casing to the returns tank. Pull CTS plug. Bleed any pressure off tubing to the returns tank. Kill well with 9.1# brine down as needed. Pull BPV. a. If indications show pressure underneath BPV, lubricate out BPV. 5. Call out Summit for ESP pull. 6. RU spoolers to handle ESP cable and packer vent line. 7. MU landing joint or spear, BOLDS, PU on the tubing hanger. a. Tubing hanger is an 11"x 2 7/8" Gen 5 HGR, 2 7/8'' EUE Top & BTM. b. 2024 tubing PU weight on ASR #1 recorded as 29 kip. Slack off weight recorded as 22 kip. c. The ESP packer is pinned to shear release at 20k overpull. Estimated PUW to release packer is ~49 Klbs. d. 2-7/8” L-80 EUE yield is 144 kip. 8. Confirm hanger free, lay down tubing hanger. 9. POOH and lay down the 2-7/8” tubing. Vent packer is at ~2,000’. a. Send tubing for inspection and reuse on a future well. b. Keep ported discharge head and centralizer for future use. c. Note any sand or scale inside or on the outside of the ESP on the morning report. d. Recorded Clamp Totals: i. Canon Clamps: 103 ii. Half Clamps =1 iii. Motor Clamps =4 iv. MLE Clamps = 1 v. Seal clamps = 4 vi. Pump Clamps: 3 10. Lay Down ESP. 11. PU 3.75” junk mill, 2.88” motor, 6,800’ of 2-3/8” PH-6 cross over to 6,900’ of 3-1/2” work string. TIH and cleanout to PBTD. 12. If needed, pump a 500 gal acetic acid pill around to clean up the polymer sludge in the wellbore. 13. Circulate 2x bottoms up at a minimum rate of 5 BPM. POOH. 14. MU PMM motor, seals and PCP landing BHA. Test BOPE to 250 psi low/ 2,000 psi high. Test annular to 250 psi low/ 2,000 psi high Well: MPL-62 PTD: 220-059 API: 50-029-23685-00-00 a.PMM motors have the potential to generate power at the pump and communicate that back to surface. Confirm no current every time before working with the cable. If the PCP is installed there is potential for current at surface. We not plan to install the pumps until after the RWO so there will not be a hazard until the pumps are installed. b.Anyone working with the TTCPCP must understand the risks and be certified to work around PMM motors. 15. RIH with 3-1/2” 9.3# L-80 TTCPCP completion to +/- 5,900’ and obtain string weights. a. Check electrical continuity every 1000’. b. Note PU and SO weights on tally. c. Install ESP clamps per Summit, and cross coupling clamps every other joint d. Photograph vent packer prior to running in hole. 16. PU and MU Viking packer with Weatherford Vent Valves. Verify that there are 4-6 setting shear pins and confirm with OE number of release shear pins. Target release pins to shear at 18,900 pounds overpull. 17. Terminate the ESP cable and make up the ESP penetrator to the ESP cable. Ensure the 3/8” NPT control line feed thru port is dummied off. Nom. Size Length Item Lb/ft Material Notes 5.85 2 Centralizer 4 ~5,900 4.5 2 Intake Sensor 30 4.5 34 PMM Motor - 42HP 80 5.13 7 Lower Tandem Seal 38 5.13 7 Upper Tandem Seal 38 3.5 8 PCP Receiving Base 52 3-1/2" 10 3-1/2" EUE 8rd Pup Jt 9.3 L-80 3-1/2" 30 3-1/2" EUE 8rd L-80 9.3 L-80 3-1/2"10 3-1/2" EUE 8rd Pup Jt 9.3 L-80 3-1/2"8 3-1/2" x 1" GLM, DV installed 9.3 L-80 3-1/2"10 3-1/2" EUE 8rd Pup Jt 9.3 L-80 3-1/2" ~3,325 3-1/2"EUE 8rd Jt 9.3 L-80 3-1/2"10 3-1/2"EUE 8rd Pup Jt 9.3 L-80 3-1/2"2 3-1/2" X-nipple with RHC profile 9.3 L-80 3-1/2"10 3-1/2" EUE 8rd Pup Jt 9.3 L-80 3-1/2" 31 3-1/2" EUE 8rd Jt 9.3 L-80 3-1/2"10 3-1/2" EUE 8rd Pup Jt 9.3 L-80 3-1/2"8 3-1/2" x 1" GLM, DV installed 9.3 L-80 3-1/2"10 3-1/2" EUE 8rd Pup Jt 9.3 L-80 3-1/2" 31 3-1/2" EUE 8rd Jt 9.3 L-80 30 Packer, Viking ESP Retr. Vent ~2,200 MD Well: MPL-62 PTD: 220-059 API: 50-029-23685-00-00 3-1/2" 30 3-1/2" EUE 8rd Jt 9.3 L-80 3-1/2"10 3-1/2" EUE 8rd Pup Jt 9.3 L-80 3-1/2"8 3-1/2" x 1" GLM, DV installed 9.3 L-80 3-1/2"10 3-1/2" EUE 8rd Pup Jt 9.3 L-80 3-1/2"~2,000 3-1/2" EUE 8rd Jt 9.3 L-80 3-1/2"10 3-1/2" EUE 8rd Pup Jt 9.3 L-80 3-1/2"8 3-1/2" x 1" GLM, DV installed 9.3 L-80 ~200 MD 3-1/2"10 3-1/2" EUE 8rd Pup Jt 9.3 L-80 3-1/2"150 3-1/2" EUE 8rd Jt 9.3 L-80 3-1/2"10 Space out pup 9.3 L-80 3-1/2"30 Tubing Hanger with full joint L-80 18. Make up the control line to the dual vent valves. Pressure up on the control line to 5,000 psi and hold for 5 minutes checking for leaks (note the opening pressure in the daily report). Bleed the pressure to 500 psi and maintain 500 psi while running in hole. i. Periodically confirm control line is maintaining 500 psi. 19. Continue running ESP completion per plan. 20. PU and MU the 3-1/2” tubing hanger. Make final splice of the ESP cable to the penetrator. MU the control line to the tubing hanger and dummy off any additional control line ports if present. 21. Land tubing hanger, avoiding any damage to ESP cable or control line. RILDS. Lay down landing joint. Note PU and SO weights on tally and in daily report. 22. Drop ball and rod. 23. Pressure up on tubing to 4,000 psi and hold for 15 minutes to set the ESP packer. 24. Bleed tubing to 0 psi. 25. Pressure up on tubing to 4,000 psi and hold for 5 more minutes and then bleed to 0 psi. 26. Bleed packer control line to 0 psi, closing packer vent valves. 27. Slowly pressure up IA at 50 psi/min to 1,500 psi and hold for 30 minutes. Chart test. 28. Set BPV. 29. RDMO ASR. Post-Rig Procedure: Slickline: 1. RU slickline, pressure test PCE to 250psi low / 3,000psi high. 2. Pull ball and rod. 3. Pull RHC profile. 4. Pull DGLV and set GLSOV in upper GLM Sta #4 at ~200’ MD. 5. RDMO. Electrical 1. The drive, transformer, and junction box all need to be labeled with warning signs that we have 2 sources of electricity, the grid and from downhole at the PMM. 2. A disconnect switch needs to be installed on the down stream side of the drive. Well Support 1. RD mud boat. RD BOPE house. Move to next well location. 2. RU crane. ND BOPE, set CTS plug, and NU tree. Well: MPL-62 PTD: 220-059 API: 50-029-23685-00-00 3. Test tubing hanger void to 500 psi low/5,000 psi high. Pull CTS and BPV. 4. RD crane. Move 500 bbl returns tank and rig mats to next well location. 5. RU well house and flowlines. Slickline 1. RU slickline, pressure test PCE to 250psi low / 2,500psi high. 2. Drift and tag PCP receiving base. 3. RIH and set TTCPCP. Attachments: 1. Current Wellbore Schematic 2. Proposed Wellbore Schematic 3. BOPE Schematic _____________________________________________________________________________________ Revised By: TDF 4/3/2024 SCHEMATIC Milne Point Unit Well: MPU L-62 Last Completed: 3/28/2024 PTD: 220-059 TD =13,520’(MD) / TD =3,873’ (TVD) 6 20” Orig. KB Elev.: 50.41’ / GL Elev.: 17.1’ 7-5/8” 10 12 &13 14 4 19 9-5/8” 1 2 5 See Screen/ Solid Liner Detail PBTD =13,520’ (MD) / PBTD = 3,873’ (TVD) 9-5/8” ‘ES’ Cementer @ 2,645’ MD 8 &9 4-1/2” Shoe @ 13,520’ 16 15 17 18 3 4 7 11 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20" Conductor 129.5 / A53 / Weld N/A Surface 130’ N/A 9-5/8" Surface 47 / L-80 / TXP 8.681 Surface 2,625’ 0.0758 9-5/8” Surface 40 / L-80 / TXP 8.835 2,625’ 7,146’ 0.0732 7-5/8” Tieback 29.7 / L-80 / Hyd 521 6.875 Surface 7,000’ 0.0459 4-1/2” Liner 13.5 / L-80 / Hyd 625 3.920 6,989’ 13,520’ .0149 TUBING DETAIL 2-7/8" Tubing 6.5 / L-80 / EUE R2 2.441 Surface 5,910’ 0.0087 OPEN HOLE / CEMENT DETAIL 2” ±270 ft3 12- 1/4" Stg 1 – Lead – 635 sx / Tail – 400 sx Stg 2 – Lead – 780 sx / Tail – 288 sx 8-1/2” Cementless Screened Liner WELL INCLINATION DETAIL KOP @ 258’ Max Hole Angle = 95° @ 9,913’ MD TREE & WELLHEAD Tree Cameron 2-9/16" 5M w/ 4-1/16” 5M Cameron Wing Wellhead Cameron 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs GENERAL WELL INFO API: 50-029-23685-00-00 Completion Date: 9/7/2020 ESP Swap by ASR#1 3/28/2024 JEWELRY DETAIL No. Top MD Item ID 1 199’ Sta. 4: 2-7/8" x 1" GLM W/ BK-Dummy Valve 2.347” 2 1,929’ Sta. 3: 2-7/8" GLM W/ 1" BK-Dummy Valve 2.347” 3 1,993’ 7-5/8" x 3-1/2"x1.900" DLESP Retrievable Packer 2.957 4 2,052’ Sta. 2: 2-7/8" GLM W/ 1" BK-Dummy Valve 2.347” 5 2,111’ 2-7/8" X-Nipple 2.313" I.D. w/ RHC-M 2.313” 6 5,689’ Sta. 1: 2-7/8" GLM W/ 1" Dummy Valve 2.347” 7 5,779’ XN-Nipple 2.313"Profile, 2.205" No-Go 2.205” 8 5,832’ Ported Pressure Sub Adapter 9 5,833’ Discharge Head Bolt On 10 5,834’ Pump: 538,SJ1700,114S,INC,15,1:1AR,HTEM 11 5,857’ Intake Sub Assy: P/N 103005623 12 5,865’ Upper Tandem Seal: P/N 900566029 13 5,874’ Lower Tandem Seal: P/N 900566003 14 5,883’ Motor: 562/KMS2/360HP/3175V/70A 15 5,906’ Guage & Centralizer:Btm @ 5,910’ 16 6,989’ BOT SLZXP LTP / Liner Hanger 7” x 9-5/8” (4001’ TVD) 7.020” 17 6,989’ Locator Sub, 7” TXP Box x Box 6.170” 18 7,011’ 7” H563 x 4.5” TSH 625 XO 3.850” 19 13,520’ Shoe 3.950” 4-1/2” 250ђ SCREENSLINER DETAIL Jts Top (MD) Top (TVD) Btm (MD) Btm (TVD) 3 8207’ 3968’ 8334’ 3963’ 20 8458’ 3959’ 9268’ 3931’ 3 9430’ 3927’ 9549’ 3931’ 19 10041’ 3916’ 10817’ 3886’ 25 11141’ 3877’ 12187’ 3879’ 23 12516’ 3878’ 13477’ 3873’ _____________________________________________________________________________________ Revised By: TDF 9/10/2024 PROPOSED Milne Point Unit Well: MPU L-62 Last Completed: 3/28/2024 PTD: 220-059 TD =13,520’(MD) / TD =3,873’ (TVD) 20” Orig. KB Elev.: 50.41’ / GL Elev.: 17.1’ 7-5/8”13 & 14 15 12 20 9-5/8” 7 8 See Screen/ Solid Liner Detail PBTD =13,520’ (MD) / PBTD = 3,873’ (TVD) 9-5/8” ‘ES’ Cementer @ 2,645’ MD 9, 10 & 11 4-1/2” Shoe @ 13,520’ 17 16 18 19 1 3 2 4 5 6 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20" Conductor 129.5 / A53 / Weld N/A Surface 130’ N/A 9-5/8" Surface 47 / L-80 / TXP 8.681 Surface 2,625’ 0.0758 9-5/8” Surface 40 / L-80 / TXP 8.835 2,625’ 7,146’ 0.0732 7-5/8” Tieback 29.7 / L-80 / Hyd 521 6.875 Surface 7,000’ 0.0459 4-1/2” Liner 13.5 / L-80 / Hyd 625 3.920 6,989’ 13,520’ .0149 TUBING DETAIL 3-1/2" Tubing 9.2 / L-80 / EUE 8rd 2.992 Surface ±5,900’ 0.0087 OPEN HOLE / CEMENT DETAIL 2” ±270 ft3 12- 1/4" Stg 1 – Lead – 635 sx / Tail – 400 sx Stg 2 – Lead – 780 sx / Tail – 288 sx 8-1/2” Cementless Screened Liner WELL INCLINATION DETAIL KOP @ 258’ Max Hole Angle = 95° @ 9,913’ MD TREE & WELLHEAD Tree Cameron 2-9/16" 5M w/ 4-1/16” 5M Cameron Wing Wellhead Cameron 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs GENERAL WELL INFO API: 50-029-23685-00-00 Completion Date: 9/7/2020 ESP Swap by ASR#1 3/28/2024 JEWELRY DETAIL No. Top MD Item ID 1 ±XXX’ 3-1/2" x 1" GLM, DV installed 2 ±X,XXX’ 3-1/2" x 1" GLM, DV installed 3 ±X,XXX’ Packer, Viking ESP Retrievable Vent 4 ±X,XXX’ 3-1/2" x 1" GLM, DV installed 5 ±X,XXX’ 3-1/2” X-nipple with RHC profile 6 ±X,XXX’ 3-1/2" x 1" GLM, DV installed 7 ±X,XXX’ D&D Packoff & Stinger assembly 8 ±X,XXX’Pump, Discharge head, Hanger receptacle 9 ±X,XXX’ Pump 380 SXD 116-P18UT 10 ±X,XXX’ P2P Pump 380 SXD 116-Flex 17.5 11 ±X,XXX’ P2P Pump 380 SXD 116-Flex 17.5 12 ±X,XXX’ Intake Sub Assy: 13 ±X,XXX’ Upper Tandem Seal: 14 ±X,XXX’ Lower Tandem Seal: 15 ±X,XXX’ Motor: 562/KMS2/360HP/3175V/70A 16 ±X,XXX’ Guage & Centralizer: Btm @ ±5,900’ 17 6,989’ BOT SLZXP LTP / Liner Hanger 7” x 9-5/8” (4001’ TVD) 7.020” 18 6,989’ Locator Sub, 7” TXP Box x Box 6.170” 19 7,011’ 7” H563 x 4.5” TSH 625 XO 3.850” 20 13,520’ Shoe 3.950” 4-1/2” 250ђ SCREENSLINER DETAIL Jts Top (MD) Top (TVD) Btm (MD) Btm (TVD) 3 8207’ 3968’ 8334’ 3963’ 20 8458’ 3959’ 9268’ 3931’ 3 9430’ 3927’ 9549’ 3931’ 19 10041’ 3916’ 10817’ 3886’ 25 11141’ 3877’ 12187’ 3879’ 23 12516’ 3878’ 13477’ 3873’ Updated 10/9/2024 11” BOPE INTEGRATED 11'’-5000 INTEGRATED 4.30'INTEGRATED 11" - 5000 2-7/8" x 5" VBR Blind 11'’- 5000 2 1/16 5M Kill Line Valves 2 1/16 5M Choke Line Valves HCRManualManual Stripping Head ManualManual 2-3/8" Pipe Ram Milne Point ASR 11” BOP w/ Jacks 05/17/2017 Milne Point ASR 11” BOP (Triple) 10/9/2024 CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Alaska NS - ASR - Well Site Managers To:Alaska NS - ASR - Well Site Managers; Regg, James B (OGC); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (OGC) Subject:RE: MPL-62 Additional VBR Test Date:Wednesday, March 27, 2024 4:36:17 AM Attachments:MPL-62 3.5in VBR_v2.xlsx Please find attached revised report reflecting what was tested. Thank you, Mike Heinz-Brown | Milne Point | DSM | Hilcorp Alaska Rig Office: 907-685-1266 | Cell: 480-296-5214 From: Alaska NS - ASR - Well Site Managers Sent: Wednesday, March 27, 2024 1:39 AM To: jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov Cc: Alaska NS - ASR - Well Site Managers <AlaskaNS-ASRWellSiteManagers@hilcorp.com> Subject: MPL-62 Additional VBR Test Initially, the plan (Sundry) for this well included a Liner clean out. Based on calculations, this was not achievable. The revised plan was to pull/run 2-7/8” ESP completion only hence, only testing w/ 2- 7/8” mandrel. Once the failed ESP was recovered and fill was found inside, decision was made to perform a Casing clean out run. The VBRs was tested with 3-1/2” test mandrel prior to entering the wellbore with the work string. Please find attached documents as supporting documents. Thank you, Mike Heinz-Brown | Milne Point | DSM | Hilcorp Alaska Rig Office: 907-685-1266 | Cell: 480-296-5214 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 0LOQH3RLQW8QLW/ 37' STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION *All BOPE reports are due to the agency within 5 days of testing* SSu bmit to :jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov Rig Owner: Rig No.:ASR 1 DATE: 3/25/24 Rig Rep.: Rig Email: Operator: Operator Rep.: Op. Rep Email: Well Name:PTD #2200590 Sundry #324-157 Operation: Drilling: Workover: X Explor.: Test: Initial: Weekly: Bi-Weekly: Other: X Rams:250/2500 Annular:NT Valves:250/2500 MASP:1575 MISC. INSPECTIONS: TEST DATA FLOOR SAFETY VALVES: Test Result/Type Test Result Quantity Test Result Housekeeping P Well Sign P Upper Kelly 0NT Permit On Location P Hazard Sec.P Lower Kelly 0NA Standing Order Posted P Misc.NA Ball Type 1P Test Fluid Water Inside BOP 0NT FSV Misc 0NA BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm Stripper 0NATrip Tank NA NA Annular Preventer 0 11"NT Pit Level Indicators NT NT #1 Rams 1 2-7/8" x 5"P Flow Indicator NT NT #2 Rams 0 Blind NT Meth Gas Detector NT NT #3 Rams 0NAH2S Gas Detector NT NT #4 Rams 0NAMS Misc 0NA #5 Rams 0NA #6 Rams 0NAACCUMULATOR SYSTEM: Choke Ln. Valves 0 2-1/16"NT Time/Pressure Test Result HCR Valves 0 2-1/16"NT System Pressure (psi)0 NT Kill Line Valves 0 2-1/16"NT Pressure After Closure (psi)0 NT Check Valve 0NA200 psi Attained (sec)0 NT BOP Misc 0NAFull Pressure Attained (sec)0 NT Blind Switch Covers: All stations NA CHOKE MANIFOLD:Bottle Precharge:NT Quantity Test Result Nitgn. Bottles # & psi (Avg.): 0 NT No. Valves 1P ACC Misc 0NA Manual Chokes 0NT Hydraulic Chokes 0NT Control System Response Time:Time (sec) Test Result CH Misc 0NA Annular Preventer 0 NT #1 Rams 0 NT Coiled Tubing Only:#2 Rams 0 NT Inside Reel valves 0NA #3 Rams 0 NA #4 Rams 0 NA Test Results #5 Rams 0 NA #6 Rams 0 NA Number of Failures:0 Test Time:0.5 HCR Choke 0 NT Repair or replacement of equipment will be made within days. HCR Kill 0 NA Remarks: AOGCC Inspection 24 hr Notice Yes Date/Time 03/22/24 14:25 Waived By Test Start Date/Time:3/25/2024 23:00 (date) (time)Witness Test Finish Date/Time:3/25/2024 23:30 BOPE Test Report Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Brian Bixby Hilcorp Tested VBR w/ 3-1/2" Test Mandrel against test plug in hanger. C. Greub / M. Boord Hilcorp Alaska, LLC A. Haberthur / M.Heinz-Brown MPU L-62 Test Pressure (psi): askans-asr-toolpushers@hilcorp.c ans-asr-wellsitemanagers@hilcorp Form 10-424 (Revised 08/2022) 2024-0325_BOP_Hilcorp_ASR1_VBR_MPU_L-62 9 9 9 9 9 9 9 9 99 9 9 9 9 - 5HJJ #01&)JMDPSQ"43 7#35FTU .16- 15% CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Michael Heinz-Brown - (C) To:Regg, James B (OGC); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (OGC) Cc:Alaska NS - ASR - Well Site Managers Subject:MPL-62 Initial BOPE Test Date:Sunday, March 24, 2024 10:31:17 PM Attachments:MPL-62 (initial) BOPE.xlsx MPL-62 (initial) supporting docs.pdf Some people who received this message don't often get email from michael.heinzbrown@hilcorp.com. Learn why this is important Please find attached. Thank you, Mike Heinz-Brown | Milne Point | DSM | Hilcorp Alaska Rig Office: 907-685-1266 | Cell: 480-296-5214 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 0LOQH3RLQW8QLW/ 37' STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION *All BOPE reports are due to the agency within 5 days of testing* SSu bmitt to :jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov Rig Owner: Rig No.:ASR 1 DATE: 3/23/24 Rig Rep.: Rig Email: Operator: Operator Rep.: Op. Rep Email: Well Name:PTD #2200590 Sundry #324-157 Operation: Drilling: Workover: X Explor.: Test: Initial: X Weekly: Bi-Weekly: Other: Rams:250/2500 Annular:250/2500 Valves:250/2500 MASP:1575 MISC. INSPECTIONS: TEST DATA FLOOR SAFETY VALVES: Test Result/Type Test Result Quantity Test Result Housekeeping P Well Sign P Upper Kelly 1P Permit On Location P Hazard Sec.P Lower Kelly 0NA Standing Order Posted P Misc.NA Ball Type 2P Test Fluid Water Inside BOP 1P FSV Misc 0NA BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm Stripper 0NATrip Tank NA NA Annular Preventer 1 11"P Pit Level Indicators PP #1 Rams 1 2-7/8" x 5"P Flow Indicator PP #2 Rams 1 Blind FP Meth Gas Detector PP #3 Rams 0NAH2S Gas Detector PP #4 Rams 0NAMS Misc 0NA #5 Rams 0NA #6 Rams 0NAACCUMULATOR SYSTEM: Choke Ln. Valves 1 2-1/16"P Time/Pressure Test Result HCR Valves 1 2-1/16"P System Pressure (psi)3000 P Kill Line Valves 3 2-1/16"P Pressure After Closure (psi)1900 P Check Valve 0NA200 psi Attained (sec)18 P BOP Misc 0NAFull Pressure Attained (sec)57 P Blind Switch Covers: All stations Yes CHOKE MANIFOLD:Bottle Precharge:P Quantity Test Result Nitgn. Bottles # & psi (Avg.): 4 / 2312psi P No. Valves 16 P ACC Misc 0NA Manual Chokes 1P Hydraulic Chokes 1P Control System Response Time:Time (sec) Test Result CH Misc 0NA Annular Preventer 13 P #1 Rams 6 P Coiled Tubing Only:#2 Rams 6 P Inside Reel valves 0NA #3 Rams 0 NA #4 Rams 0 NA Test Results #5 Rams 0 NA #6 Rams 0 NA Number of Failures:1 Test Time:13.0 HCR Choke 1 P Repair or replacement of equipment will be made within days. HCR Kill 0 NA Remarks: AOGCC Inspection 24 hr Notice Yes Date/Time 03/22/24 14:25 Waived By Test Start Date/Time:3/23/2024 20:00 (date) (time)Witness Test Finish Date/Time:3/24/2024 9:00 BOPE Test Report Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Brian Bixby Hilcorp Tested w/ 2-7/8" Test Mandrel. F/P: Blind Rams leaked from Weep hole during HP test. Replaced mud seal, retesed good. Bottle Pre-Charge = 1016.66psi C. Greub / M. Boord Hilcorp Alaska, LLC A. Haberthur / M.Heinz-Brown MPU L-62 Test Pressure (psi): askans-asr-toolpushers@hilcorp.c ans-asr-wellsitemanagers@hilcorp Form 10-424 (Revised 08/2022) 2024-0323_BOP_Hilcorp_ASR1_MPU_L-62 9 9 9 9 9 9999 9 9 9 9 - 5HJJ 7HVW&KDUWDWWDFKHG FP Blind Rams leaked 9 9 9 9 9 %23(7HVW+LOFRUS$65 038*37' 9 %23(7HVW+LOFRUS$65 038*37' #01&5FTU)JMDPSQ"43 .16- 15% #01&5FTU)JMDPSQ"43 .16( 15% #01&5FTU)JMDPSQ"43 .16( 15% 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: 3/20/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20240320 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BCU 19RD 50133205790100 219188 2/2/2024 AK E-LINE Perf CLU 14 50133206840000 219078 12/11/2023 AK E-LINE Perf IRU 41-01 50283200880000 192109 11/15/2023 AK E-LINE PERF KBU 22-06Y 50133206500000 215044 12/29/2023 AK E-LINE PERF MPU C-14 50029213440000 185088 3/4/2024 AK E-LINE Whipstock MPU L-62 50029236850000 220059 3/3/2024 AK E-LINE TubingPunch NCIU A-17 50883201880000 223031 12/13/2024 AK E-LINE GPT /Plug /Perf Paxton 6 50133207070000 222054 2/27/2024 AK E-LINE Plug/Perf PBU BORE V-109 50029231200000 202202 2/13/2024 AK E-LINE TubingPunch Please include current contact information if different from above. T38657 T38658 T38659 T38660 T38661 T38662 T38663 T38664 T38665 MPU L-62 50029236850000 220059 3/3/2024 AK E-LINE TubingPunch Meredith Guhl Digitally signed by Meredith Guhl Date: 2024.03.21 13:14:02 -08'00' 1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: ESP Swap Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number): 8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 13,520 feet N/A feet true vertical 3,873 feet N/A feet Effective Depth measured 13,520 feet 1,993 & 6,989 feet true vertical 3,873 feet 1,672 & 4,001 feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth)2-7/8" 6.5# / L-80 / EUE R2 5,910' 3,759' DLESP Retrievable Packers and SSSV (type, measured and true vertical depth)BOT SLZXP LTP N/A See Above N/A 12. Stimulation or cement squeeze summary: N/A Intervals treated (measured): Treatment descriptions including volumes used and final pressure: N/A 13a. Prior to well operation: Subsequent to operation: 13b. Pools active after work: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Authorized Name and Digital Signature with Date: Contact Name: Contact Email: Authorized Title: Wells Manager Contact Phone: 7,020psi 8,540psi 6,870psi 5,750psi 8,160psi 9,020psi 7,146' 3,998' Burst N/A Collapse N/A 4,760psi 3,090psi Liner 7,000' 6,531' Casing Conductor 4,001' 3,873' 7,000' 13,520' 4,521' 2,625'Surface Surface Tieback 20" 9-5/8" 9-5/8" 130' 2,625' measured TVD 7-5/8" 4-1/2" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 220-059 50-029-23685-00-00 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 3. Address: Hilcorp Alaska LLC N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: ADL0025509 & ADL0025515 MILNE POINT / SCHRADER BLUFF OIL MILNE PT UNIT L-62 Plugs Junk measured Length measured true vertical Packer Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 131 Gas-Mcf MD 130' 540 Size 130' 2,020' 73 30042 0 3080 395 323-543 & 324-157 Sr Pet Eng: Sr Pet Geo: Sr Res Eng: WINJ WAG 0 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. N/A Ryan Lewis ryan.lewis@hilcorp.com 303-906-5178 Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov By Grace Christianson at 8:02 am, May 01, 2024 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143) Date: 2024.04.26 15:35:43 - 08'00' Taylor Wellman (2143) RBDMS JSB 05132024 WCB 7-30-2024 DSR-5/1/24 _____________________________________________________________________________________ Revised By: TDF 4/3/2024 SCHEMATIC Milne Point Unit Well: MPU L-62 Last Completed: 3/28/2024 PTD: 220-059 TD =13,520’(MD) / TD =3,873’ (TVD) 6 20” Orig. KB Elev.: 50.41’ / GL Elev.: 17.1’ 7-5/8” 10 12 &13 14 4 19 9-5/8” 1 2 5 See Screen/ Solid Liner Detail PBTD =13,520’ (MD) / PBTD = 3,873’ (TVD) 9-5/8” ‘ES’ Cementer @ 2,645’ MD 8 &9 4-1/2” Shoe @ 13,520’ 16 15 17 18 3 4 7 11 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20" Conductor 129.5 / A53 / Weld N/A Surface 130’ N/A 9-5/8" Surface 47 / L-80 / TXP 8.681 Surface 2,625’ 0.0758 9-5/8” Surface 40 / L-80 / TXP 8.835 2,625’ 7,146’ 0.0732 7-5/8” Tieback 29.7 / L-80 / Hyd 521 6.875 Surface 7,000’ 0.0459 4-1/2” Liner 13.5 / L-80 / Hyd 625 3.920 6,989’ 13,520’ .0149 TUBING DETAIL 2-7/8" Tubing 6.5 / L-80 / EUE R2 2.441 Surface 5,910’ 0.0087 OPEN HOLE / CEMENT DETAIL 2” ±270 ft3 12- 1/4" Stg 1 – Lead – 635 sx / Tail – 400 sx Stg 2 – Lead – 780 sx / Tail – 288 sx 8-1/2” Cementless Screened Liner WELL INCLINATION DETAIL KOP @ 258’ Max Hole Angle = 95° @ 9,913’ MD TREE & WELLHEAD Tree Cameron 2-9/16" 5M w/ 4-1/16” 5M Cameron Wing Wellhead Cameron 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs GENERAL WELL INFO API: 50-029-23685-00-00 Completion Date: 9/7/2020 ESP Swap by ASR#1 3/28/2024 JEWELRY DETAIL No. Top MD Item ID 1 199’ Sta. 4: 2-7/8" x 1" GLM W/ BK-Dummy Valve 2.347” 2 1,929’ Sta. 3: 2-7/8" GLM W/ 1" BK-Dummy Valve 2.347” 3 1,993’ 7-5/8" x 3-1/2"x1.900" DLESP Retrievable Packer 2.957 4 2,052’ Sta. 2: 2-7/8" GLM W/ 1" BK-Dummy Valve 2.347” 5 2,111’ 2-7/8" X-Nipple 2.313" I.D. w/ RHC-M 2.313” 6 5,689’ Sta. 1: 2-7/8" GLM W/ 1" Dummy Valve 2.347” 7 5,779’ XN-Nipple 2.313"Profile, 2.205" No-Go 2.205” 8 5,832’ Ported Pressure Sub Adapter 9 5,833’ Discharge Head Bolt On 10 5,834’ Pump: 538,SJ1700,114S,INC,15,1:1AR,HTEM 11 5,857’ Intake Sub Assy: P/N 103005623 12 5,865’ Upper Tandem Seal: P/N 900566029 13 5,874’ Lower Tandem Seal: P/N 900566003 14 5,883’ Motor: 562/KMS2/360HP/3175V/70A 15 5,906’ Guage & Centralizer:Btm @ 5,910’ 16 6,989’ BOT SLZXP LTP / Liner Hanger 7” x 9-5/8” (4001’ TVD) 7.020” 17 6,989’ Locator Sub, 7” TXP Box x Box 6.170” 18 7,011’ 7” H563 x 4.5” TSH 625 XO 3.850” 19 13,520’ Shoe 3.950” 4-1/2” 250ђ SCREENSLINER DETAIL Jts Top (MD) Top (TVD) Btm (MD) Btm (TVD) 3 8207’ 3968’ 8334’ 3963’ 20 8458’ 3959’ 9268’ 3931’ 3 9430’ 3927’ 9549’ 3931’ 19 10041’ 3916’ 10817’ 3886’ 25 11141’ 3877’ 12187’ 3879’ 23 12516’ 3878’ 13477’ 3873’ Well Name Rig API Number Well Permit Number Start Date End Date MP L-62 ASR#1 & SL 50-029-23685-00-00 220-059 3/23/2024 3/29/2024 PU/MU & RIH w/ BHA: 6.750" Mill, 2x Boot Baskets, 7-5/8" CSG Scraper, Oil Jars, 3x 4-1/4" Drill Collars T/ 6,977' MD Tag TOL W/ 5K down. PUW 50K SOW 25K. Bring pump on @ 2bpm - 150-225psi. Reverse circulate 2 bottoms up plus hourly loss rate for a total of 240bbls. Monitor well. POOH F/ 6,950' T/ 1,283' MD while maintaining 2x displacement. RU ASR-1. Bleed 195psi from IA to Tiger Tank (gas). Accept Rig 12:00. During shell test IA started flowing oil/gas. 30 psi on IA. Pump down tubing 2 BPM 300 psi. Shut down after returns cleaned up - 138bbls pumped, 57bbls returns, 10.3ppg. Monitor well - static. Begin testing BOPE 250/2500psi w/ 2-7/8" test mandrel. 3/23/2024 - Saturday Continue POOH F/ 494'. ESP Cable has multiple damaged sections from top of JT #179 down to MLE. Discharge head packed off. Intake screen packed off. N/U shooting flange. RU Slickline, test PCE to 500psi, RIH w/ 6.71" O.D. Junk Basket. Slickline unable to pass 2,600', bring pump on at 1.5bpm/60psi. Shut down after 20bbls away. Slickline POOH w/ tools. Swap to 6.10" O.D. J.Basket and RIH to 1,000' SLM, unable to pass. Decision made to POOH and RD S/L. ND Shooting Flange, NU Flow Spool and Riser. RU and test VBR w/ 3-1/2" test mandrel - Good test. 3/26/2024 - Tuesday 3/24/2024 - Sunday Continue testing BOPE 250/2500psi. Repair leaking Mud Seals on Blind Rams. Retest passed. Pull CTS, BPV. P/U M/U landing joint. BOLDS. Pull hanger to floor. Off seat 41K. PUW 43K. ESP cable grounded. POOH W/ 2-7/8 EUE and ESP F/ 5,909 T/494' MD while maintaining 2x displacement. 3/25/2024 - Monday 3/22/2024 - Friday No operations to report. 3/20/2024 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary No operations to report. 3/21/2024 - Thursday No operations to report. Begin testing BOPE 250/2500psi Continue testing BOPE 250/2500psi. Repair leaking Mud Seals on Blind Rams. Retest passed. Pull CTS, BPV. P/U M/U landing joint. BOLDS. Pull hanger to floor. Off seat 41K. PUW 43K. ESP cable grounded. POOH W/ 2-7/8 EUE and ESP F/ 5,909 T/494' MD while maintaining 2x displacement Well Name Rig API Number Well Permit Number Start Date End Date MP L-62 ASR, EL & SL 50-029-23685-00-00 220-059 3/23/2024 3/29/2024 3/29/2024 - Friday RIG-UP .125 CARBON WIRE. TS = 1.75" RS, 15' x 1-1/2" ROLLER STEM (2.0" whls), OJ, KJT LSS. STACK PCE AND TAKE CONTROL OF WIRE. PULL TREE CAPAND STAB ONTO WELLHEAD. PT PCE 350L / 3500H (Good). PULL BK-DGLV FROM ST #4 (200' md) AND RESET BEK-DPSOV. PULL BALL & ROD, 2-7/8" RHC FROM X-NIPPLE AT 2,111' MD. WELL SHUT-IN ON DEPARTURE, PAD OP NOTIFIED. 3/27/2024 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary Cont. POOH F/ 1,283' MD while maintaining 2x displacement. L/D clean out BHA, all components intact. Clear rig floor & prep for ESP completion run. P/U & M/U ESP assembly Cent., Sensor, MTR, upper & lower seals, intake, pump, & Discharge head. RIH w/ 2-7/8" 6.5# L-80 EUE, ESP completion T/ 3,096. 3/28/2024 - Thursday Cont. RIH w/ 2-7/8" 6.5# L-80 EUE, ESP completion. M/U ESP PKR & splice ESP cable through. Install cap line on vent valve & test to 5,00 psi (good). Hold 500 psi on cap line & RIH. M/U hanger & terminate ESP cable & cap line. Land hanger & RILDS Final end depth = 5,910'. Test ESP cable (good). Set ESP PKR. & MIT IA to 1500 psi (good Test) Pull landing joint & set BPV. WELLHEAD: LAND 2-7/8 TUBING HANGER, RILDS, INSTALL H-BPV, N/U Tree/ Adopter test void 500 low 5000 high 5/10 min test good. Pulled BPV and secure well. No operations to report. No operations to report. 3/30/2024 - Saturday No operations to report. 4/2/2024 - Tuesday 3/31/2024 - Sunday No operations to report. 4/1/2024 - Monday PULL BALL & ROD, 2-7/8" RHC FROM X-NIPPLE AT 2,111' MD Cont. POOH F/ 1,283' MD while maintaining 2x displacement RIH w/ 2-7/8" 6.5# L-80 EUE, ESP completion T/ 3,096. Cont. RIH w/ 2-7/8" 6.5# L-80 EUE, ESP completion. M/U ESP PKR & splice ESP cable through. Install cap line on vent valve & test to 5,00 psi (good). Hold 500 psi on cap line & RIH. M/U hanger & terminate ESP cable & cap line. Land hanger & RILDS Final end depth = 5,910'. Test ESP cable (good). Set ESP PKR. & MIT IA to 1500 psi (good Test) Pull landing joint & set BPV. WELLHEAD: LAND 2-7/8 TUBING HANGER, RILDS, INSTALL H-BPV, N/U Tree 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: ESP Swap 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? 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): 13,520' N/A Casing Collapse Conductor N/A Surface 4,760psi Surface 3,090psi Tieback 7,020psi Liner 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: Contact Email: Contact Phone: Authorized Title: Wells Manager 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 PT UNIT L-62 MILNE POINT SCHRADER BLUFF OIL N/A 3,873' 13,520' 3,873' 1,575 N/A Subsequent Form Required: 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 AOGCC USE ONLY Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): 3/19/2024 BOT SLZXP LTP and N/A STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0025509 & ADL0025515 220-059 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 50-029-23685-00-00 Hilcorp Alaska LLC C.O. 477.05 Length Size Proposed Pools: 130' 130' 6.5 / L-80 EUE 8rd TVD Burst 5,911' 9,020psi MD N/A 8,160psi 6,870psi 5,750psi 2,020' 3,998' 4,001' 2,625' 7,146' 130' 20" 9-5/8" 9-5/8" 2,625' 7-5/8"7,000' 4,521' 7,000' See Schematic 6,531' See Schematic 2-7/8" 3,873'4-1/2" 6,989 MD / 4,001 TVD and N/A Ryan Lewis ryan.lewis@hilcorp.com 303-906-5178 13,520' 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 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143) Date: 2024.03.14 11:08:04 - 08'00' Taylor Wellman (2143) By Grace Christianson at 12:57 pm, Mar 14, 2024 DSR-3/15/24 1,575 10-404 MGR22MAR24 * BOPE test to 2500 psi. SFD 3/22/2024JLC 3/22/2024 Well: MPL-62 PTD: 201-170 API: 50-029-23040-00-00 Well Name:MPL-62 API Number:50-029-23685-00-00 Current Status:Shut-in Producer Rig:ASR #1 Estimated Start Date:3/19/2024 Estimated Duration:7 days Regulatory Contact:Tom Fouts Permit to Drill Number:220-059 First Call Engineer:Ryan Lewis (303) 906-5178 (M) Second Call Engineer:Taylor Wellman (907) 777-8449 (O) (907) 947-9533 (M) Current Bottom Hole Pressure:1,967 psi @ 3,923 TVD 3/8/2024 | 9.7 PPGE 10.1 KWF Max Potential Surface Pressure: 1,575 psi Gas Column Gradient (0.1 psi/ft) Max Angle:68° Sail Angle from 5,835 MD Brief Well Summary: MPU L-62 was drilled, and completed as a Schrader Bluff producer with an ESP installed in September 2020. ESP replaced in March 2021. Objectives: Pull failed ESP, run new ESP completion. Notes Regarding Wellbore Condition: - Original completion 7-5/8 x 9-5/8 annulus test to 1,000 psi on 9/5/20. Pre-Rig Procedure (Non Sundried Work) Slickline 1. RU slickline, pressure test PCE to 250psi low / 2,500psi high. 2. Drift and tag with sample bailer. 3. Attempt to pull dummy valve from GLM at 5,679 MD and leave open. 4. Pull GLV and set dummy valve in upper GLM at 201 MD. 5. RDMO. Coiled Tubing (Contingency) 1. Pressure test PCE to 250 psi low / 2,500 psi high. 2. PU 1.75 jet nozzle. 3. Jet down to discharge head at 5,822 MD. 4. Following best practices in PE manual, pump gel sweeps to clean up tubing. 5. Chase gel out of hole. 6. PU tubing punch. 7. RIH and tag discharge head. 8. Pump down ball to fire tubing punch. 9. Confirm circulation by pumping down backside of coil. 10. Freeze protect tubing as POOH. 11. RDMO. Pumping & Well Support 1. Clear and level pad area in front of well. Spot rig mats and containment. 2. RD well house and flowlines. Clear and level area around well. Well: MPL-62 PTD: 201-170 API: 50-029-23040-00-00 3. RU Little Red Services. RU reverse out skid and 500 barrel returns tank. 4. Pressure test lines to 3,000 psi. 5. Circulate at least one wellbore volume with 10.1 KWF down tubing, taking returns up casing to 500 barrel returns tank. 6. Confirm well is dead. Contact operations engineer if freeze protection is needed prior to ASR arrival. 7. RD Little Red Services and reverse out skid. 8. Set BPV. ND tree. NU BOPE. Brief RWO Procedure (Begin Sundried Work) 1. MIRU Hilcorp ASR #1 WO Rig, ancillary equipment, and lines to 500 barrel returns tank. 2. Check for pressure and if 0 psi set CTS plug. If needed, bleed off any residual pressure off tubing and casing. a. If needed, kill well with produced water prior to setting CTS. 3. Test BOPE to 250 psi low/ 2,500 psi high. Test annular to 250 psi low/ 2,500 psi high (hold each ram/valve and test for 5-min). Record accumulator pre-charge pressures and chart tests. a. Perform test per ASR 1 BOP Test Procedure b. Notify AOGCC 24 hours in advance of BOP test. c. Confirm test pressures per the Sundry conditions of approval. d. Test VBR rams on 2-7/8 and 3-1/2 test joint. e. Test the 2-3/8 test joint on 2-3/8 solid ram. f. Submit to AOGCC completed 10-424 form within 5 days of BOPE test. 4. Bleed any pressure on casing to the returns tank. Pull CTS plug. Bleed any pressure off tubing to the returns tank. Kill well with 10.1 KWF as needed. Pull BPV. a. If indications show pressure underneath BPV, lubricate out BPV. 5. Call out Centrilift for ESP pull. 6. RU spoolers to handle ESP cable. 7. MU landing joint or spear, BOLDS, PU on the tubing hanger. a. Tubing hanger is an FMC 11 x 2-9/16, with 2-7/8 EUE thread. b. 2020 tubing PU weight on ASR #1 recorded as 75 kip. Slack off weight recorded as 60 kip. c. 2-7/8 L-80 EUE yield is 144 kip. 8. Confirm hanger free, lay down tubing hanger. 9. POOH and lay down the 2-7/8 tubing. a. Re-use all good tubing. b. Keep ported discharge head and centralizer for future use. c. Note any sand or scale inside or on the outside of the ESP on the morning report. d. Recorded Clamp Totals: i. Canon Clamps: 109 ii. Protectolizers: 9 iii. Pump Clamps: 6 Well: MPL-62 PTD: 201-170 API: 50-029-23040-00-00 10. Lay Down ESP. 11.MU/RIH with a 3.75 mill, 2.88motor, BPV, 6,700 of 2-3/8 PH-6 crossed over to 6,800 of 3-1/2 workstring 2-7/8 IF connections. 12.Cleanout to TD at 13,520, circulate 1.5x bottoms up with gel sweeps and POOH. 13. RIH with 2-7/8 6.5# L-80 ESP completion to +/- 5,909 and obtain string weights. a. Check electrical continuity every 1000. b. Note PU and SO weights on tally. c. Install ESP clamps per Summit, and cross coupling clamps every other joint. d. Photograph vent packer prior to running in hole. 14. PU and MU Viking packer. Verify that there are four (4) setting shear pins and confirm with OE number of release shear pins. Target release pins to shear at 20,000 pounds overpull. Nom. (OD)Length Item Lb/ft Material Notes 5.85 2 Centralizer 4 ~5,909 4.5 2 Intake Sensor 30 5.62 34 Motor 467HP 80 5.2 7 Lower Tandem Seal 38 5.2 7 Upper Tandem Seal 38 5.2 8 Gas Separator 52 5.38 ~57 Pump SJ1700 114 stage 45 1 Ported Discharge Head 13 L-80 2-7/8" 10 2-7/8" EUE 8rd Pup Jt 6.5 L-80 2-7/8" 30 2-7/8" EUE 8rd L-80 6.5 L-80 2-7/8"10 2-7/8" EUE 8rd Pup Jt 6.5 L-80 2-7/8"2 2-7/8 XN-nipple 2.313" / 2.205" No-Go 6.5 L-80 2-7/8"10 2-7/8" EUE 8rd Pup Jt 6.5 L-80 2-7/8" 60 2-7/8" EUE 8rd Jt 6.5 L-80 2-7/8"10 2-7/8" EUE 8rd Pup Jt 6.5 L-80 2-7/8"8 2-7/8" x 1" GLM, DV installed 6.5 L-80 2-7/8"10 2-7/8" EUE 8rd Pup Jt 6.5 L-80 2-7/8" ~3,500 2-7/8" EUE 8rd Jt 6.5 L-80 2-7/8"10 2-7/8" EUE 8rd Pup Jt 6.5 L-80 2-7/8"2 2-7/8 X-nipple with RHC profile 6.5 L-80 2-7/8"10 2-7/8" EUE 8rd Pup Jt 6.5 L-80 2-7/8" 31 2-7/8" EUE 8rd Jt 6.5 L-80 2-7/8"10 2-7/8" EUE 8rd Pup Jt 6.5 L-80 2-7/8"8 2-7/8" x 1" GLM, DV installed 6.5 L-80 2-7/8"10 2-7/8" EUE 8rd Pup Jt 6.5 L-80 2-7/8" 31 2-7/8" EUE 8rd Jt 6.5 L-80 30 Packer, Viking ESP Retr. Single Vent ~2,000 MD 2-7/8" 30 2-7/8" EUE 8rd Jt 6.5 L-80 Well: MPL-62 PTD: 201-170 API: 50-029-23040-00-00 2-7/8"10 2-7/8" EUE 8rd Pup Jt 6.5 L-80 2-7/8"8 2-7/8" x 1" GLM, DV installed 6.5 L-80 2-7/8"10 2-7/8" EUE 8rd Pup Jt 6.5 L-80 2-7/8" ~1,720 2-7/8" EUE 8rd Jt 6.5 L-80 2-7/8"10 2-7/8" EUE 8rd Pup Jt 6.5 L-80 2-7/8"8 2-7/8" x 1" GLM, DV installed 6.5 L-80 ~200 MD 2-7/8"10 2-7/8" EUE 8rd Pup Jt 6.5 L-80 2-7/8" 150 2-7/8" EUE 8rd Jt 6.5 L-80 2-7/8" 10 Space out pup 6.5 L-80 2-7/8" 30 Tubing Hanger with full joint 6.5 L-80 15. Terminate the ESP cable and make up the ESP penetrator to the ESP cable. Ensure the 3/8 NPT control line feed thru port is dummied off. 16. Make up the control line to the single vent valves. Pressure up on the control line to 5,000 psi and hold for 5 minutes checking for leaks (note the opening pressure in the daily report). Bleed the pressure to 500 psi and maintain 500 psi while running in hole. i. Periodically confirm control line is maintaining 500 psi. 17. Continue running ESP completion per plan. 18. PU and MU the 2-7/8 tubing hanger. Make final splice of the ESP cable to the penetrator. MU the control line to the tubing hanger and dummy off any additional control line ports if present. 19. Land tubing hanger, avoiding any damage to ESP cable or control line. RILDS. Lay down landing joint. Note PU and SO weights on tally and in daily report. 20. Drop ball and rod. 21. Pressure up on tubing to 4,000 psi and hold for 15 minutes to set the ESP packer. 22. Bleed tubing to 0 psi. 23. Pressure up on tubing to 4,000 psi and hold for 5 more minutes and then bleed to 0 psi. 24. Bleed packer control line to 0 psi, closing packer vent valves. 25. Slowly pressure up IA at 50 psi/min to 1,500 psi and hold for 30 minutes. Chart test. 26. Lay down landing joint. 27. Set BPV. 28. RDMO ASR. Post-Rig Procedure: Well Support 1. RD mud boat. RD BOPE house. Move to next well location. 2. RU crane. ND BOPE, set CTS plug, and NU tree. 3. Test tubing hanger void to 500 psi low/5,000 psi high. Pull CTS and BPV. 4. RD crane. Move 500 bbl returns tank and rig mats to next well location. 5. RU well house and flowlines. Slickline: 1. RU slickline, pressure test PCE to 250psi low / 4,000psi high. 2. Pull ball and rod. 3. Pull RHC profile. 4. Pull DGLV and set GLSOV in upper GLM at ~200 MD. 5. RDMO. Well: MPL-62 PTD: 201-170 API: 50-029-23040-00-00 Attachments: 1. Current Wellbore Schematic 2. Proposed Wellbore Schematic 3. Double BOPE Schematic _____________________________________________________________________________________ Revised By: DH 4/20/2021 SCHEMATIC Milne Point Unit Well: MPU L-62 Last Completed: 3/29/2021 PTD: 220-059 TD =13,520(MD) / TD =3,873 (TVD) 4 20 Orig. KB Elev.: 50.41 / GL Elev.: 17.1 7-5/8 7 8/ 9 10 4 16 9-5/8 1 2 3 See Screen/ Solid Liner Detail PBTD =13,520 (MD) / PBTD =3,873 (TVD) 9-5/8 ES Cementer @ 2,645 MD 5/ 6 4-1/2 Shoe @ 13,520 11 13 12 14 15 3-1/2CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20" Conductor 129.5 / A53 / Weld N/A Surface 130 N/A 9-5/8" Surface 47 / L-80 / TXP 8.681 Surface 2,625 0.0758 9-5/8 Surface 40 / L-80 / TXP 8.835 2,625 7,146 0.0732 7-5/8 Tieback 29.7 / L-80 / Hyd 521 6.875 Surface 7,000 0.0459 4-1/2 Liner 13.5 / L-80 / Hyd 625 3.920 6,989 13,520 .0149 TUBING DETAIL 2-7/8" Tubing 6.5 / L-80 / EUE-8rd 2.441 Surface 5,911 0.0087 OPEN HOLE / CEMENT DETAIL 2 ±270 ft3 12- 1/4" Stg 1 Lead 635 sx / Tail 400 sx Stg 2 Lead 780 sx / Tail 288 sx 8-1/2 Cementless Screened Liner WELL INCLINATION DETAIL KOP @ 258 Max Hole Angle = 95° @ 9,913 MD TREE & WELLHEAD Tree Cameron 2-9/16" 5M w/ 4-1/16 5M Cameron Wing Wellhead Cameron 11 5K x sliplock bottom w/ (2) 2-1/16 5K outs GENERAL WELL INFO API: 50-029-23685-00-00 Completion Date: 9/7/2020 JEWELRY DETAIL No. Top MD Item ID 1 201 Sta. 2: 2-7/8 Gas Lift Mandrel 2 5,679 Sta. 1: 2-7/8 Gas Lift Mandrel w/ 1 dummy valve 3 5,769 XN Nipple, 2.313 Profile, 2.205 No Go 2.313 4 5,822 Ported Pressure Sub Adapter 5 5,824 Upper Pump 6 5,846 Lower Pump 7 5,867 Gas Separator 8 5,872 Upper Tandem Seal 9 5,881 Lower Tandem Seal 10 5,890 Motor 11 5,907 Motor Gauge 12 5,909 Centralizer: Bottom @ 5,911 MD 13 6,989 BOT SLZXP LTP / Liner Hanger 7 x 9-5/8 (4001 TVD) 7.020 14 6,989 Locator Sub, 7 TXP Box x Box 6.170 15 7,011 7 H563 x 4.5 TSH 625 XO 3.850 16 13,520 Shoe 3.950 4-1/2 250 SCREENS LINER DETAIL Jts Top (MD) Top (TVD) Btm (MD) Btm (TVD) 3 8207 3968 8334 3963 20 8458 3959 9268 3931 3 9430 3927 9549 3931 19 10041 3916 10817 3886 25 11141 3877 12187 3879 23 12516 3878 13477 3873 _____________________________________________________________________________________ Revised By: TDF 3/11/2024 PROPOSED Milne Point Unit Well: MPU L-62 Last Completed: 3/29/2021 PTD: 220-059 TD =13,520(MD) / TD =3,873 (TVD) 6 20 Orig. KB Elev.: 50.41 / GL Elev.: 17.1 7-5/89 10 &11 12 4 18 9-5/8 1 2 5 See Screen/ Solid Liner Detail PBTD =13,520 (MD) / PBTD =3,873 (TVD) 9-5/8 ES Cementer @ 2,645 MD 7 &8 4-1/2 Shoe @ 13,520 13 15 14 16 17 3 4 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20" Conductor 129.5 / A53 / Weld N/A Surface 130 N/A 9-5/8" Surface 47 / L-80 / TXP 8.681 Surface 2,625 0.0758 9-5/8 Surface 40 / L-80 / TXP 8.835 2,625 7,146 0.0732 7-5/8 Tieback 29.7 / L-80 / Hyd 521 6.875 Surface 7,000 0.0459 4-1/2 Liner 13.5 / L-80 / Hyd 625 3.920 6,989 13,520 .0149 TUBING DETAIL 2-7/8" Tubing 6.5 / L-80 / EUE-8rd 2.441 Surface ±5,909 0.0087 OPEN HOLE / CEMENT DETAIL 2 ±270 ft3 12- 1/4" Stg 1 Lead 635 sx / Tail 400 sx Stg 2 Lead 780 sx / Tail 288 sx 8-1/2 Cementless Screened Liner WELL INCLINATION DETAIL KOP @ 258 Max Hole Angle = 95° @ 9,913 MD TREE & WELLHEAD Tree Cameron 2-9/16" 5M w/ 4-1/16 5M Cameron Wing Wellhead Cameron 11 5K x sliplock bottom w/ (2) 2-1/16 5K outs GENERAL WELL INFO API: 50-029-23685-00-00 Completion Date: 9/7/2020 JEWELRY DETAIL No. Top MD Item ID 1 ±200 Sta. 3: 2-7/8" x 1" GLM, 1/4" OV 2 ±X,XXX Sta. 2: 2-7/8" x 1" GLM, DV installed 3 ±X,XXX Viking ESP Retr. Single Vent Packer 4 ±X,XXX Sta. 1: 2-7/8" x 1" GLM, DV installed 5 ±X,XXX XN Nipple, 2.313 Profile, 2.205 No Go 2.313 6 ±X,XXX Ported Pressure Sub Adapter 7 ±X,XXX Upper Pump 8 ±X,XXX Lower Pump 9 ±X,XXX Gas Separator 10 ±X,XXX Upper Tandem Seal 11 ±X,XXX Lower Tandem Seal 12 ±X,XXX Motor 13 ±X,XXX Motor Gauge 14 ±X,XXX Centralizer: Bottom @ ±5,909 MD 15 6,989 BOT SLZXP LTP / Liner Hanger 7 x 9-5/8 (4001 TVD) 7.020 16 6,989 Locator Sub, 7 TXP Box x Box 6.170 17 7,011 7 H563 x 4.5 TSH 625 XO 3.850 18 13,520 Shoe 3.950 4-1/2 250 SCREENS LINER DETAIL Jts Top (MD) Top (TVD) Btm (MD) Btm (TVD) 3 8207 3968 8334 3963 20 8458 3959 9268 3931 3 9430 3927 9549 3931 19 10041 3916 10817 3886 25 11141 3877 12187 3879 23 12516 3878 13477 3873 Updated 2/20/2024 11 BOPE INTEGRATED11'-5000 INTEGRATED 4.30'INTEGRATED 11" - 5000 2-7/8" x 5" VBR Blind 11'- 5000 2 1/16 5M Kill Line Valves 2 1/16 5M Choke Line Valves HCRManualManual Stripping Head ManualManual 2-3/8" Pipe Ram Milne Point ASR 11 BOP w/ Jacks 05/17/2017 Milne Point ASR 11 BOP (Triple) 2/20/2024 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: ESP Swap 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? 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): 13,520' N/A Casing Collapse Conductor N/A Surface 4,760psi Surface 3,090psi Tieback 7,020psi Liner 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: Contact Email: Contact Phone: Authorized Title: Wells Manager 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 PT UNIT L-62 MILNE POINT SCHRADER BLUFF OIL N/A 3,873' 13,520' 3,873' 1,575 N/A Subsequent Form Required: 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 AOGCC USE ONLY Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): 3/19/2024 BOT SLZXP LTP and N/A STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0025509 & ADL0025515 220-059 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 50-029-23685-00-00 Hilcorp Alaska LLC C.O. 477.05 Length Size Proposed Pools: 130' 130' 6.5 / L-80 EUE 8rd TVD Burst 5,911' 9,020psi MD N/A 8,160psi 6,870psi 5,750psi 2,020' 3,998' 4,001' 2,625' 7,146' 130' 20" 9-5/8" 9-5/8" 2,625' 7-5/8"7,000' 4,521' 7,000' See Schematic 6,531' See Schematic 2-7/8" 3,873'4-1/2" 6,989 MD / 4,001 TVD and N/A Ryan Lewis ryan.lewis@hilcorp.com 303-906-5178 13,520' 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 9:50 am, Mar 12, 2024 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143) Date: 2024.03.11 14:50:08 - 08'00' Taylor Wellman (2143) A.Dewhurst 13MAR24 DSR-3/12/24 Well: MPL-62 PTD: 201-170 API: 50-029-23040-00-00 Well Name:MPL-62 API Number:50-029-23685-00-00 Current Status:Shut-in Producer Rig:ASR #1 Estimated Start Date:3/19/2024 Estimated Duration:7 days Regulatory Contact:Tom Fouts Permit to Drill Number:220-059 First Call Engineer:Ryan Lewis (303) 906-5178 (M) Second Call Engineer:Taylor Wellman (907) 777-8449 (O) (907) 947-9533 (M) Current Bottom Hole Pressure:1,967 psi @ 3,923 TVD 3/8/2024 | 9.7 PPGE 10.1 KWF Max Potential Surface Pressure: 1,575 psi Gas Column Gradient (0.1 psi/ft) Max Angle:68° Sail Angle from 5,835 MD Brief Well Summary: MPU L-62 was drilled, and completed as a Schrader Bluff producer with an ESP installed in September 2020. ESP replaced in March 2021. Objectives: Pull failed ESP, run new ESP completion. Notes Regarding Wellbore Condition: - Original completion 7-5/8 x 9-5/8 annulus test to 1,000 psi on 9/5/20. Pre-Rig Procedure (Non Sundried Work) Slickline 1. RU slickline, pressure test PCE to 250psi low / 2,500psi high. 2. Drift and tag with sample bailer. 3. Attempt to pull dummy valve from GLM at 5,679 MD and leave open. 4. Pull GLV and set dummy valve in upper GLM at 201 MD. 5. RDMO. Coiled Tubing (Contingency) 1. Pressure test PCE to 250 psi low / 2,500 psi high. 2. PU 1.75 jet nozzle. 3. Jet down to discharge head at 5,822 MD. 4. Following best practices in PE manual, pump gel sweeps to clean up tubing. 5. Chase gel out of hole. 6. PU tubing punch. 7. RIH and tag discharge head. 8. Pump down ball to fire tubing punch. 9. Confirm circulation by pumping down backside of coil. 10. Freeze protect tubing as POOH. 11. RDMO. Pumping & Well Support 1. Clear and level pad area in front of well. Spot rig mats and containment. 2. RD well house and flowlines. Clear and level area around well. Well: MPL-62 PTD: 201-170 API: 50-029-23040-00-00 3. RU Little Red Services. RU reverse out skid and 500 barrel returns tank. 4. Pressure test lines to 3,000 psi. 5. Circulate at least one wellbore volume with 10.1 KWF down tubing, taking returns up casing to 500 barrel returns tank. 6. Confirm well is dead. Contact operations engineer if freeze protection is needed prior to ASR arrival. 7. RD Little Red Services and reverse out skid. 8. Set BPV. ND tree. NU BOPE. Brief RWO Procedure (Begin Sundried Work) 1. MIRU Hilcorp ASR #1 WO Rig, ancillary equipment, and lines to 500 barrel returns tank. 2. Check for pressure and if 0 psi set CTS plug. If needed, bleed off any residual pressure off tubing and casing. a. If needed, kill well with produced water prior to setting CTS. 3. Test BOPE to 250 psi low/ 2,500 psi high. Test annular to 250 psi low/ 2,500 psi high (hold each ram/valve and test for 5-min). Record accumulator pre-charge pressures and chart tests. a. Perform test per ASR 1 BOP Test Procedure b. Notify AOGCC 24 hours in advance of BOP test. c. Confirm test pressures per the Sundry conditions of approval. d. Test VBR rams on 2-7/8 test joint. e. Submit to AOGCC completed 10-424 form within 5 days of BOPE test. 4. Bleed any pressure on casing to the returns tank. Pull CTS plug. Bleed any pressure off tubing to the returns tank. Kill well with 10.1 KWF as needed. Pull BPV. a. If indications show pressure underneath BPV, lubricate out BPV. 5. Call out Centrilift for ESP pull. 6. RU spoolers to handle ESP cable. 7. MU landing joint or spear, BOLDS, PU on the tubing hanger. a. Tubing hanger is an FMC 11 x 2-9/16, with 2-7/8 EUE thread. b. 2020 tubing PU weight on ASR #1 recorded as 75 kip. Slack off weight recorded as 60 kip. c. 2-7/8 L-80 EUE yield is 144 kip. 8. Confirm hanger free, lay down tubing hanger. 9. POOH and lay down the 2-7/8 tubing. a. Re-use all good tubing. b. Keep ported discharge head and centralizer for future use. c. Note any sand or scale inside or on the outside of the ESP on the morning report. d. Recorded Clamp Totals: i. Canon Clamps: 109 ii. Protectolizers: 9 iii. Pump Clamps: 6 10. Lay Down ESP. Well: MPL-62 PTD: 201-170 API: 50-029-23040-00-00 11.MU/RIH with a 3.75 mill, 2.88motor, BPV, 6,700 of 2-3/8 PH-6 crossed over to 6,800 of 3-1/2 workstring 2-7/8 IF connections. 12.Cleanout to TD at 13,520, circulate 1.5x bottoms up with gel sweeps and POOH. 13. RIH with 2-7/8 6.5# L-80 ESP completion to +/- 5,909 and obtain string weights. a. Check electrical continuity every 1000. b. Note PU and SO weights on tally. c. Install ESP clamps per Summit, and cross coupling clamps every other joint. d. Photograph vent packer prior to running in hole. 14. PU and MU Viking packer. Verify that there are four (4) setting shear pins and confirm with OE number of release shear pins. Target release pins to shear at 20,000 pounds overpull. Nom. (OD)Length Item Lb/ft Material Notes 5.85 2 Centralizer 4 ~5,909 4.5 2 Intake Sensor 30 5.62 34 Motor 467HP 80 5.2 7 Lower Tandem Seal 38 5.2 7 Upper Tandem Seal 38 5.2 8 Gas Separator 52 5.38 ~57 Pump SJ1700 114 stage 45 1 Ported Discharge Head 13 L-80 2-7/8" 10 2-7/8" EUE 8rd Pup Jt 6.5 L-80 2-7/8" 30 2-7/8" EUE 8rd L-80 6.5 L-80 2-7/8"10 2-7/8" EUE 8rd Pup Jt 6.5 L-80 2-7/8"2 2-7/8 XN-nipple 2.313" / 2.205" No-Go 6.5 L-80 2-7/8"10 2-7/8" EUE 8rd Pup Jt 6.5 L-80 2-7/8" 60 2-7/8" EUE 8rd Jt 6.5 L-80 2-7/8"10 2-7/8" EUE 8rd Pup Jt 6.5 L-80 2-7/8"8 2-7/8" x 1" GLM, DV installed 6.5 L-80 2-7/8"10 2-7/8" EUE 8rd Pup Jt 6.5 L-80 2-7/8" ~3,500 2-7/8" EUE 8rd Jt 6.5 L-80 2-7/8"10 2-7/8" EUE 8rd Pup Jt 6.5 L-80 2-7/8"2 2-7/8 X-nipple with RHC profile 6.5 L-80 2-7/8"10 2-7/8" EUE 8rd Pup Jt 6.5 L-80 2-7/8" 31 2-7/8" EUE 8rd Jt 6.5 L-80 2-7/8"10 2-7/8" EUE 8rd Pup Jt 6.5 L-80 2-7/8"8 2-7/8" x 1" GLM, DV installed 6.5 L-80 2-7/8"10 2-7/8" EUE 8rd Pup Jt 6.5 L-80 2-7/8" 31 2-7/8" EUE 8rd Jt 6.5 L-80 30 Packer, Viking ESP Retr. Single Vent ~2,000 MD 2-7/8" 30 2-7/8" EUE 8rd Jt 6.5 L-80 2-7/8"10 2-7/8" EUE 8rd Pup Jt 6.5 L-80 Well: MPL-62 PTD: 201-170 API: 50-029-23040-00-00 2-7/8"8 2-7/8" x 1" GLM, DV installed 6.5 L-80 2-7/8"10 2-7/8" EUE 8rd Pup Jt 6.5 L-80 2-7/8" ~1,720 2-7/8" EUE 8rd Jt 6.5 L-80 2-7/8"10 2-7/8" EUE 8rd Pup Jt 6.5 L-80 2-7/8"8 2-7/8" x 1" GLM, DV installed 6.5 L-80 ~200 MD 2-7/8"10 2-7/8" EUE 8rd Pup Jt 6.5 L-80 2-7/8" 150 2-7/8" EUE 8rd Jt 6.5 L-80 2-7/8" 10 Space out pup 6.5 L-80 2-7/8" 30 Tubing Hanger with full joint 6.5 L-80 15. Terminate the ESP cable and make up the ESP penetrator to the ESP cable. Ensure the 3/8 NPT control line feed thru port is dummied off. 16. Make up the control line to the single vent valves. Pressure up on the control line to 5,000 psi and hold for 5 minutes checking for leaks (note the opening pressure in the daily report). Bleed the pressure to 500 psi and maintain 500 psi while running in hole. i. Periodically confirm control line is maintaining 500 psi. 17. Continue running ESP completion per plan. 18. PU and MU the 2-7/8 tubing hanger. Make final splice of the ESP cable to the penetrator. MU the control line to the tubing hanger and dummy off any additional control line ports if present. 19. Land tubing hanger, avoiding any damage to ESP cable or control line. RILDS. Lay down landing joint. Note PU and SO weights on tally and in daily report. 20. Drop ball and rod. 21. Pressure up on tubing to 4,000 psi and hold for 15 minutes to set the ESP packer. 22. Bleed tubing to 0 psi. 23. Pressure up on tubing to 4,000 psi and hold for 5 more minutes and then bleed to 0 psi. 24. Bleed packer control line to 0 psi, closing packer vent valves. 25. Slowly pressure up IA at 50 psi/min to 1,500 psi and hold for 30 minutes. Chart test. 26. Lay down landing joint. 27. Set BPV. 28. RDMO ASR. Post-Rig Procedure: Well Support 1. RD mud boat. RD BOPE house. Move to next well location. 2. RU crane. ND BOPE, set CTS plug, and NU tree. 3. Test tubing hanger void to 500 psi low/5,000 psi high. Pull CTS and BPV. 4. RD crane. Move 500 bbl returns tank and rig mats to next well location. 5. RU well house and flowlines. Slickline: 1. RU slickline, pressure test PCE to 250psi low / 4,000psi high. 2. Pull ball and rod. 3. Pull RHC profile. 4. Pull DGLV and set GLSOV in upper GLM at ~200 MD. 5. RDMO. Well: MPL-62 PTD: 201-170 API: 50-029-23040-00-00 Attachments: 1. Current Wellbore Schematic 2. Proposed Wellbore Schematic 3. Double BOPE Schematic _____________________________________________________________________________________ Revised By: DH 4/20/2021 SCHEMATIC Milne Point Unit Well: MPU L-62 Last Completed: 3/29/2021 PTD: 220-059 TD =13,520(MD) / TD =3,873 (TVD) 4 20 Orig. KB Elev.: 50.41 / GL Elev.: 17.1 7-5/8 7 8/ 9 10 4 16 9-5/8 1 2 3 See Screen/ Solid Liner Detail PBTD =13,520 (MD) / PBTD =3,873 (TVD) 9-5/8 ES Cementer @ 2,645 MD 5/ 6 4-1/2 Shoe @ 13,520 11 13 12 14 15 3-1/2CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20" Conductor 129.5 / A53 / Weld N/A Surface 130 N/A 9-5/8" Surface 47 / L-80 / TXP 8.681 Surface 2,625 0.0758 9-5/8 Surface 40 / L-80 / TXP 8.835 2,625 7,146 0.0732 7-5/8 Tieback 29.7 / L-80 / Hyd 521 6.875 Surface 7,000 0.0459 4-1/2 Liner 13.5 / L-80 / Hyd 625 3.920 6,989 13,520 .0149 TUBING DETAIL 2-7/8" Tubing 6.5 / L-80 / EUE-8rd 2.441 Surface 5,911 0.0087 OPEN HOLE / CEMENT DETAIL 2 ±270 ft3 12- 1/4" Stg 1 Lead 635 sx / Tail 400 sx Stg 2 Lead 780 sx / Tail 288 sx 8-1/2 Cementless Screened Liner WELL INCLINATION DETAIL KOP @ 258 Max Hole Angle = 95° @ 9,913 MD TREE & WELLHEAD Tree Cameron 2-9/16" 5M w/ 4-1/16 5M Cameron Wing Wellhead Cameron 11 5K x sliplock bottom w/ (2) 2-1/16 5K outs GENERAL WELL INFO API: 50-029-23685-00-00 Completion Date: 9/7/2020 JEWELRY DETAIL No. Top MD Item ID 1 201 Sta. 2: 2-7/8 Gas Lift Mandrel 2 5,679 Sta. 1: 2-7/8 Gas Lift Mandrel w/ 1 dummy valve 3 5,769 XN Nipple, 2.313 Profile, 2.205 No Go 2.313 4 5,822 Ported Pressure Sub Adapter 5 5,824 Upper Pump 6 5,846 Lower Pump 7 5,867 Gas Separator 8 5,872 Upper Tandem Seal 9 5,881 Lower Tandem Seal 10 5,890 Motor 11 5,907 Motor Gauge 12 5,909 Centralizer: Bottom @ 5,911 MD 13 6,989 BOT SLZXP LTP / Liner Hanger 7 x 9-5/8 (4001 TVD) 7.020 14 6,989 Locator Sub, 7 TXP Box x Box 6.170 15 7,011 7 H563 x 4.5 TSH 625 XO 3.850 16 13,520 Shoe 3.950 4-1/2 250 SCREENS LINER DETAIL Jts Top (MD) Top (TVD) Btm (MD) Btm (TVD) 3 8207 3968 8334 3963 20 8458 3959 9268 3931 3 9430 3927 9549 3931 19 10041 3916 10817 3886 25 11141 3877 12187 3879 23 12516 3878 13477 3873 _____________________________________________________________________________________ Revised By: TDF 3/11/2024 PROPOSED Milne Point Unit Well: MPU L-62 Last Completed: 3/29/2021 PTD: 220-059 TD =13,520(MD) / TD =3,873 (TVD) 6 20 Orig. KB Elev.: 50.41 / GL Elev.: 17.1 7-5/89 10 &11 12 4 18 9-5/8 1 2 5 See Screen/ Solid Liner Detail PBTD =13,520 (MD) / PBTD =3,873 (TVD) 9-5/8 ES Cementer @ 2,645 MD 7 &8 4-1/2 Shoe @ 13,520 13 15 14 16 17 3 4 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20" Conductor 129.5 / A53 / Weld N/A Surface 130 N/A 9-5/8" Surface 47 / L-80 / TXP 8.681 Surface 2,625 0.0758 9-5/8 Surface 40 / L-80 / TXP 8.835 2,625 7,146 0.0732 7-5/8 Tieback 29.7 / L-80 / Hyd 521 6.875 Surface 7,000 0.0459 4-1/2 Liner 13.5 / L-80 / Hyd 625 3.920 6,989 13,520 .0149 TUBING DETAIL 2-7/8" Tubing 6.5 / L-80 / EUE-8rd 2.441 Surface ±5,909 0.0087 OPEN HOLE / CEMENT DETAIL 2 ±270 ft3 12- 1/4" Stg 1 Lead 635 sx / Tail 400 sx Stg 2 Lead 780 sx / Tail 288 sx 8-1/2 Cementless Screened Liner WELL INCLINATION DETAIL KOP @ 258 Max Hole Angle = 95° @ 9,913 MD TREE & WELLHEAD Tree Cameron 2-9/16" 5M w/ 4-1/16 5M Cameron Wing Wellhead Cameron 11 5K x sliplock bottom w/ (2) 2-1/16 5K outs GENERAL WELL INFO API: 50-029-23685-00-00 Completion Date: 9/7/2020 JEWELRY DETAIL No. Top MD Item ID 1 ±200 Sta. 3: 2-7/8" x 1" GLM, 1/4" OV 2 ±X,XXX Sta. 2: 2-7/8" x 1" GLM, DV installed 3 ±X,XXX Viking ESP Retr. Single Vent Packer 4 ±X,XXX Sta. 1: 2-7/8" x 1" GLM, DV installed 5 ±X,XXX XN Nipple, 2.313 Profile, 2.205 No Go 2.313 6 ±X,XXX Ported Pressure Sub Adapter 7 ±X,XXX Upper Pump 8 ±X,XXX Lower Pump 9 ±X,XXX Gas Separator 10 ±X,XXX Upper Tandem Seal 11 ±X,XXX Lower Tandem Seal 12 ±X,XXX Motor 13 ±X,XXX Motor Gauge 14 ±X,XXX Centralizer: Bottom @ ±5,909 MD 15 6,989 BOT SLZXP LTP / Liner Hanger 7 x 9-5/8 (4001 TVD) 7.020 16 6,989 Locator Sub, 7 TXP Box x Box 6.170 17 7,011 7 H563 x 4.5 TSH 625 XO 3.850 18 13,520 Shoe 3.950 4-1/2 250 SCREENS LINER DETAIL Jts Top (MD) Top (TVD) Btm (MD) Btm (TVD) 3 8207 3968 8334 3963 20 8458 3959 9268 3931 3 9430 3927 9549 3931 19 10041 3916 10817 3886 25 11141 3877 12187 3879 23 12516 3878 13477 3873 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 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: 11/01/2023 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20231101 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BRU 241-23 50283201910000 223061 10/10/2023 AK E-LINE Perf BRU 241-23 50283201910000 223061 10/21/2023 AK E-LINE Plug/Perf BRU 242-04 50283201640000 212041 10/13/2023 AK E-LINE Perf/PL KBU 43-07Y 50133206250000 214019 10/6/2023 AK E-LINE CIBP/Perf MPU L-62 50029236850000 220059 10/18/2023 HALLIBURTON MFC24 PBU 06-20B 50029207990200 223075 10/19/2023 HALLIBURTON RBT PBU W-26A 50029219640100 199081 12/16/2022 AK E-LINE CBL Please include current contact information if different from above. T38113 T38113 T38114 T38115 T38116 T38117 T38118 11/1/2023 MPU L-62 50029236850000 220059 10/18/2023 HALLIBURTON MFC24 Kayla Junke Digitally signed by Kayla Junke Date: 2023.11.01 14:36:12 -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: ESP Swap 2.Operator Name: 4.Current Well Class:5.Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? 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): 13,520'N/A Casing Collapse Conductor N/A Surface 4,760psi Surface 3,090psi Tieback 7,020psi Liner 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: Contact Email: Contact Phone: Authorized Title: Wells Manager 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 PT UNIT L-62 MILNE POINT SCHRADER BLUFF OIL N/A 3,873' 13,520' 3,873' 1,035 N/A Subsequent Form Required: 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 AOGCC USE ONLY Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): 10/17/2023 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0025509 & ADL0025515 220-059 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 50-029-23685-00-00 Hilcorp Alaska LLC C.O. 477.05 Length Size Proposed Pools: 130' 130' 6.5 / L-80 EUE 8rd TVD Burst 5,911' 9,020psi MD N/A 8,160psi 6,870psi 5,750psi 2,020' 3,998' 4,001' 2,625' 7,146' 3,873'4-1/2" 130' 20" 9-5/8" 9-5/8" 2,625' 7-5/8"7,000' 4,521' 13,520' Perforation Depth MD (ft): 7,000' See Schematic 6,531' See Schematic 2-7/8" BOT SLZXP LTP and N/A 6,989 MD / 4,001 TVD and N/A Ryan Lewis ryan.lewis@hilcorp.com 303-906-5178 No 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: 2023.10.04 14:01:51 - 08'00' Taylor Wellman (2143) 323-543 By Grace Christianson at 10:36 am, Oct 05, 2023 DSR-10/5/23SFD 10/6/2023MGR18OCT23 * BOPE test to 2500 psi. 10-404 JLC 10/19/2023 Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2023.10.19 11:44:09 -08'00'10/19/23 RBDMS JSB 102323 Well: MPL-62 PTD: 201-170 API: 50-029-23040-00-00 Well Name:MPL-62 API Number:50-029-23685-00-00 Current Status:Shut-in Producer Rig:ASR #1 Estimated Start Date:10/17/2023 Estimated Duration:7 days Regulatory Contact:Tom Fouts Permit to Drill Number:220-059 First Call Engineer:Ryan Lewis (303) 906-5178 (M) Second Call Engineer:Taylor Wellman (907) 777-8449 (O) (907) 947-9533 (M) Current Bottom Hole Pressure: 1,411 psi @ 3,760’ TVD 9/15/2023 |7.2 PPGE Max Potential Surface Pressure: 1,035 psi Gas Column Gradient (0.1 psi/ft) Max Angle:68° Sail Angle from 5,835’ MD Brief Well Summary: MPU L-62 was drilled, and completed as a Schrader Bluff producer with an ESP installed in September 2020. ESP replaced in March 2021. Objectives: Pull failed ESP, run new ESP completion. Notes Regarding Wellbore Condition: - Original completion 7-5/8” x 9-5/8” annulus test to 1,000 psi on 9/5/20. Pre-Rig Procedure (Non Sundried Work) Slickline 1. RU slickline, pressure test PCE to 250psi low / 2,500psi high. 2. Drift and tag with sample bailer. 3. Attempt to pull dummy valve from GLM at 5,679’ MD and leave open. 4. Pull GLV and set dummy valve in upper GLM at 201’ MD. 5. RDMO. Coiled Tubing (Contingency) 1. Pressure test PCE to 250 psi low / 2,500 psi high. 2. PU 1.75” jet nozzle. 3. Jet down to discharge head at 5,822’ MD. 4. Following best practices in PE manual, pump gel sweeps to clean up tubing. 5. Chase gel out of hole. 6. PU tubing punch. 7. RIH and tag discharge head. 8. Pump down ball to fire tubing punch. 9. Confirm circulation by pumping down backside of coil. 10. Freeze protect tubing as POOH. 11. RDMO. Pumping & Well Support 1. Clear and level pad area in front of well. Spot rig mats and containment. 2. RD well house and flowlines. Clear and level area around well. Well: MPL-62 PTD: 201-170 API: 50-029-23040-00-00 3. RU Little Red Services. RU reverse out skid and 500 barrel returns tank. 4. Pressure test lines to 3,000 psi. 5. Circulate at least one wellbore volume with produced water down tubing, taking returns up casing to 500 barrel returns tank. 6. Confirm well is dead. Contact operations engineer if freeze protection is needed prior to ASR arrival. 7. RD Little Red Services and reverse out skid. 8. Set BPV. ND tree. NU BOPE. Brief RWO Procedure (Begin Sundried Work) 1. MIRU Hilcorp ASR #1 WO Rig, ancillary equipment, and lines to 500 barrel returns tank. 2. Check for pressure and if 0 psi set CTS plug. If needed, bleed off any residual pressure off tubing and casing. a. If needed, kill well with produced water prior to setting CTS. 3. Test BOPE to 250 psi low/ 2,500 psi high. Test annular to 250 psi low/ 2,500 psi high (hold each ram/valve and test for 5-min). Record accumulator pre-charge pressures and chart tests. a. Perform test per ASR 1 BOP Test Procedure b. Notify AOGCC 24 hours in advance of BOP test. c. Confirm test pressures per the Sundry conditions of approval. d. Test VBR rams on 2-7/8” test joint. e. Submit to AOGCC completed 10-424 form within 5 days of BOPE test. 4. Bleed any pressure on casing to the returns tank. Pull CTS plug. Bleed any pressure off tubing to the returns tank. Kill well with produced water as needed. Pull BPV. a. If indications show pressure underneath BPV, lubricate out BPV. 5. Call out Centrilift for ESP pull. 6. RU spoolers to handle ESP cable. 7. MU landing joint or spear, BOLDS, PU on the tubing hanger. a. Tubing hanger is an FMC 11” x 2-9/16”, with 2-7/8” EUE thread. b. 2020 tubing PU weight on ASR #1 recorded as 75 kip. Slack off weight recorded as 60 kip. c. 2-7/8” L-80 EUE yield is 144 kip. 8. Confirm hanger free, lay down tubing hanger. 9. POOH and lay down the 2-7/8” tubing. a. Re-use all good tubing. b. Keep ported discharge head and centralizer for future use. c. Note any sand or scale inside or on the outside of the ESP on the morning report. d. Recorded Clamp Totals: i. Canon Clamps: 109 ii. Protectolizers: 9 iii. Pump Clamps: 6 10. Lay Down ESP. Well: MPL-62 PTD: 201-170 API: 50-029-23040-00-00 11. RIH with 2-7/8” 6.5# L-80 ESP completion to +/- 5,909’ and obtain string weights. a. Check electrical continuity every 1000’. b. Note PU and SO weights on tally. c. Install ESP clamps per Baker, and cross coupling clamps every other joint Nom. Size Length Item Lb/ft Material Notes 5.85 2 Centralizer 4 ~5,909 4.5 2 Intake Sensor 30 5.62 34 Motor - 467HP 80 5.2 7 Lower Tandem Seal 38 5.2 7 Upper Tandem Seal 38 5.2 8 Gas Separator 52 5.38 57 Pumps – SJ1700 45 1 Ported Discharge Head 13 L-80 2-7/8" 10 2-7/8" EUE 8rd Pup Jt 6.5 L-80 2-7/8" 30 2-7/8" EUE 8rd L-80 6.5 L-80 2-7/8"10 2-7/8" EUE 8rd Pup Jt 6.5 L-80 2-7/8"2 XN-nipple 2.313" / 2.505" No-Go 6.5 L-80 2-7/8"10 2-7/8" EUE 8rd Pup Jt 6.5 L-80 2-7/8" 60 2-7/8" EUE 8rd Jt 6.5 L-80 2-7/8"10 2-7/8" EUE 8rd Pup Jt 6.5 L-80 2-7/8"8 2-7/8" x 1" GLM, DV installed 6.5 L-80 2-7/8"10 2-7/8" EUE 8rd Pup Jt 6.5 L-80 2-7/8" 5,478 2-7/8" EUE 8rd Jt 6.5 L-80 2-7/8"10 2-7/8" EUE 8rd Pup Jt 6.5 L-80 2-7/8"8 2-7/8" x 1" GLM, 1/4" OV 6.5 L-80 ~200 MD 2-7/8"10 2-7/8" EUE 8rd Pup Jt 6.5 L-80 2-7/8" 150 2-7/8" EUE 8rd Jt 6.5 L-80 2-7/8" 10 Space out pup 6.5 L-80 2-7/8" 30 Tubing Hanger with full joint 6.5 L-80 12. Land tubing hanger. Use extra caution to not damage cable. 13. Lay down landing joint. 14. Set BPV. 15. RDMO ASR. Post-Rig Procedure: Well Support 1. RD mud boat. RD BOPE house. Move to next well location. 2. RU crane. ND BOPE, set CTS plug, and NU tree. Well: MPL-62 PTD: 201-170 API: 50-029-23040-00-00 3. Test tubing hanger void to 500 psi low/5,000 psi high. Pull CTS and BPV. 4. RD crane. Move 500 bbl returns tank and rig mats to next well location. 5. RU well house and flowlines. Attachments: 1. Current Wellbore Schematic 2. Proposed Wellbore Schematic 3. BOPE Schematic _____________________________________________________________________________________ Revised By: DH 4/20/2021 SCHEMATIC Milne Point Unit Well: MPU L-62 Last Completed: 3/29/2021 PTD: 220-059 TD =13,520’(MD) / TD =3,873’ (TVD) 4 20” Orig. KB Elev.: 50.41’ / GL Elev.: 17.1’ 7-5/8” 7 8/9 10 4 16 9-5/8” 1 2 3 See Screen/ Solid Liner Detail PBTD =13,520’ (MD) / PBTD = 3,873’ (TVD) 9-5/8” ‘ES’ Cementer @ 2,645’ MD 5/6 4-1/2” Shoe @ 13,520’ 11 13 12 14 15 3-1/2”CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20" Conductor 129.5 / A53 / Weld N/A Surface 130’ N/A 9-5/8" Surface 47 / L-80 / TXP 8.681 Surface 2,625’ 0.0758 9-5/8” Surface 40 / L-80 / TXP 8.835 2,625’ 7,146’ 0.0732 7-5/8” Tieback 29.7 / L-80 / Hyd 521 6.875 Surface 7,000’ 0.0459 4-1/2” Liner 13.5 / L-80 / Hyd 625 3.920 6,989’ 13,520’ .0149 TUBING DETAIL 2-7/8" Tubing 6.5 / L-80 / EUE-8rd 2.441 Surface 5,911’ 0.0087 OPEN HOLE / CEMENT DETAIL 2” ±270 ft3 12- 1/4" Stg 1 – Lead – 635 sx / Tail – 400 sx Stg 2 – Lead – 780 sx / Tail – 288 sx 8-1/2” Cementless Screened Liner WELL INCLINATION DETAIL KOP @ 258’ Max Hole Angle = 95° @ 9,913’ MD TREE & WELLHEAD Tree Cameron 2-9/16" 5M w/ 4-1/16” 5M Cameron Wing Wellhead Cameron 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs GENERAL WELL INFO API: 50-029-23685-00-00 Completion Date: 9/7/2020 JEWELRY DETAIL No. Top MD Item ID 1 201’ Sta. 2: 2-7/8” Gas Lift Mandrel 2 5,679’ Sta. 1: 2-7/8” Gas Lift Mandrel w/ 1” dummy valve 3 5,769’ XN Nipple, 2.313” Profile, 2.205” No Go 2.313” 4 5,822’ Ported Pressure Sub Adapter 5 5,824’ Upper Pump 6 5,846’ Lower Pump 7 5,867’ Gas Separator 8 5,872’ Upper Tandem Seal 9 5,881’ Lower Tandem Seal 10 5,890’ Motor 11 5,907’ Motor Gauge 12 5,909’ Centralizer: Bottom @ 5,911’ MD 13 6,989’ BOT SLZXP LTP / Liner Hanger 7” x 9-5/8” (4001’ TVD) 7.020” 14 6,989’ Locator Sub, 7” TXP Box x Box 6.170” 15 7,011’ 7” H563 x 4.5” TSH 625 XO 3.850” 16 13,520’ Shoe 3.950” 4-1/2” 250ђ SCREENS LINER DETAIL Jts Top (MD) Top (TVD) Btm (MD) Btm (TVD) 3 8207’ 3968’ 8334’ 3963’ 20 8458’ 3959’ 9268’ 3931’ 3 9430’ 3927’ 9549’ 3931’ 19 10041’ 3916’ 10817’ 3886’ 25 11141’ 3877’ 12187’ 3879’ 23 12516’ 3878’ 13477’ 3873’ _____________________________________________________________________________________ Revised By: DH 4/20/2021 PROPOSED Milne Point Unit Well: MPU L-62 Last Completed: 3/29/2021 PTD: 220-059 TD =13,520’(MD) / TD =3,873’ (TVD) 4 20” Orig. KB Elev.: 50.41’ / GL Elev.: 17.1’ 7-5/8” 7 8/9 10 4 16 9-5/8” 1 2 3 See Screen/ Solid Liner Detail PBTD =13,520’ (MD) / PBTD = 3,873’ (TVD) 9-5/8” ‘ES’ Cementer @ 2,645’ MD 5/6 4-1/2” Shoe @ 13,520’ 11 13 12 14 15 3-1/2”CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20" Conductor 129.5 / A53 / Weld N/A Surface 130’ N/A 9-5/8" Surface 47 / L-80 / TXP 8.681 Surface 2,625’ 0.0758 9-5/8” Surface 40 / L-80 / TXP 8.835 2,625’ 7,146’ 0.0732 7-5/8” Tieback 29.7 / L-80 / Hyd 521 6.875 Surface 7,000’ 0.0459 4-1/2” Liner 13.5 / L-80 / Hyd 625 3.920 6,989’ 13,520’ .0149 TUBING DETAIL 2-7/8" Tubing 6.5 / L-80 / EUE-8rd 2.441 Surface ±5,909’ 0.0087 OPEN HOLE / CEMENT DETAIL 2” ±270 ft3 12- 1/4" Stg 1 – Lead – 635 sx / Tail – 400 sx Stg 2 – Lead – 780 sx / Tail – 288 sx 8-1/2” Cementless Screened Liner WELL INCLINATION DETAIL KOP @ 258’ Max Hole Angle = 95° @ 9,913’ MD TREE & WELLHEAD Tree Cameron 2-9/16" 5M w/ 4-1/16” 5M Cameron Wing Wellhead Cameron 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs GENERAL WELL INFO API: 50-029-23685-00-00 Completion Date: 9/7/2020 JEWELRY DETAIL No. Top MD Item ID 1 ±200’ Sta. 2: 2-7/8" x 1" GLM, 1/4" OV 2 ±X,XXX’ Sta. 1: 2-7/8" x 1" GLM, DV installed 3 ±X,XXX’ XN Nipple, 2.313” Profile, 2.205” No Go 2.313” 4 ±X,XXX’ Ported Pressure Sub Adapter 5 ±X,XXX’ Upper Pump 6 ±X,XXX’ Lower Pump 7 ±X,XXX’ Gas Separator 8 ±X,XXX’ Upper Tandem Seal 9 ±X,XXX’ Lower Tandem Seal 10 ±X,XXX’ Motor 11 ±X,XXX’ Motor Gauge 12 ±X,XXX’ Centralizer: Bottom @ ±5,909’ MD 13 6,989’ BOT SLZXP LTP / Liner Hanger 7” x 9-5/8” (4001’ TVD) 7.020” 14 6,989’ Locator Sub, 7” TXP Box x Box 6.170” 15 7,011’ 7” H563 x 4.5” TSH 625 XO 3.850” 16 13,520’ Shoe 3.950” 4-1/2” 250ђ SCREENSLINER DETAIL Jts Top (MD) Top (TVD) Btm (MD) Btm (TVD) 3 8207’ 3968’ 8334’ 3963’ 20 8458’ 3959’ 9268’ 3931’ 3 9430’ 3927’ 9549’ 3931’ 19 10041’ 3916’ 10817’ 3886’ 25 11141’ 3877’ 12187’ 3879’ 23 12516’ 3878’ 13477’ 3873’ 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 Hilcorp Alaska, LLC Post Office Box 244027 Anchorage, AK 99524-4027 3800 Centerpoint Drive Suite 1400 Anchorage, AK 99503 Phone: 907/777-8547 September 29, 2023 Mr. Mel Rixse Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 Re: Milne Point Conductor Annulus Corrosion Inhibitor Treatments 6/9 to 9/27/2023 Dear Mr. Rixse, Enclosed please a copy of a spreadsheet with a list of thirteen Milne Point wells that were treated with corrosion inhibiting casing filler in the surface casing by conductor annulus. The heavier than water “grease-like” filler displaces water to prevent external casing corrosion that could result in a surface casing leak. The attached spreadsheets include the well names, field, API and PTD numbers, treatment dates and volumes. If you have any additional questions, please contact me at 907-777-8406 or dhorner@hilcorp.com. Sincerely, Darci Horner Regulatory Tech Hilcorp Alaska, LLC Digitally signed by Darci Horner (c-100048) DN: cn=Darci Horner (c-100048) Date: 2023.09.29 09:45:20 - 08'00' Darci Horner (c-100048) Well Field API PTD Initial Top of Cement (ft.) Volume of Cement Pumped (bbls) Final Top of Cement (ft.) Cement Pump Date Corrosion Inhibitor Fill Volume (gal) Final CI Top (ft.) Corrosion Inhibitor Treatment Date Comments MPB-35 MPU 50029237240000 2220850 14' 0 14' N/A 50 surface 9/27/2023 Drilled Sept/Oct 2022. MPB-39 MPU 50029237470000 2230120 1'6" 0 1'6" N/A 10 surface 6/10/2023 Drilled Mar 2023. MPI-20 MPU 50029236790000 2200490 10' 1 1 7/2/2023 5 surface 9/27/2023 Completed Apr 8, 2021. MPI-29 MPU 50029237080000 2220060 6' 0.5 3 7/2/2023 15 surfce 9/27/2023 Drilled in March 2022. Completeted on 4/30/22. MPL-60 MPU 50029236780000 2200480 1' 0 1' N/A 10 surface 6/26/2023 Drilled in 2020. MPL-62 MPU 50029236850000 2200590 1' 0 1' N/A 10 surface 6/26/2023 Drilled in 2020. MPM-13 MPU 50029236380000 2190870 20' 3.5 2' 8/2/2023 10 surface 9/27/2023 Drilled in 2019. MPM-27 MPU 50029237160000 2220490 2' 0 2' N/A 20 surface 6/11/2023 Monobore. Drilled June 2022. MPM-30 MPU 50029237300000 2221180 1' 0 1' N/A 10 surface 6/11/2023 Drilled in Oct 2022. MPM-43 MPU 50029236710000 2200200 1' 0 1' N/A 10 surface 6/11/2023 Drilled in 2020. MPM-62 MPU 50029237440000 2230060 1' 0 1' N/A 10 surface 6/11/2023 Completed May 2023. MPS-45 MPU 50029236930000 2210420 1' 0 1' N/A 10 surface 6/12/2023 Drilled in June 2021. MPS-47 MPU 50029236960000 2210470 4' 0 4' N/A 20 surface 6/12/2023 Drilled in August 2021. Notes: The 4" conductor outlets are any where from 1 to 3' down from the top of the conductor Surface Casing by Conductor Annulus Cement Top Job and Fill Coat Corrosion Inhibitor (CI) Applications Cement to surface means cement is up to the 4" outlets below the wellhead. From the 4" outlets up to the top of conductor was filled with Fill Coat #7 Initial top of cement footage measurement was taken from the 4" outlet down to the TOC RBDMS JSB 100323 MPL-62 MPU 50029236850000 2200590 1'0 1'N/A 10 surface 6/26/2023 Drilled in 2020. 1. Operations Abandon Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Suspend Perforate Other Stimulate Alter Casing Change Approved Program Plug for Redrill Perforate New Pool Repair Well Re-enter Susp Well Other: ESP Swap Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number): 8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071):10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 13,520 feet N/A feet true vertical 3,873 feet N/A feet Effective Depth measured 13,520 feet 6,989 feet true vertical 3,873 feet 4,001 feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth)2-7/8" 6.5# / L-80 / EUE 8rd 5,911' 3,760' Packers & SSSV (type, measured and true vertical depth)BOT SLZXP LTP N/A 6,989' 4,001' 12. Stimulation or cement squeeze summary: N/A Intervals treated (measured): Treatment descriptions including volumes used and final pressure: N/A 13. Prior to well operation: Subsequent to operation: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Chad Helgeson Contact Name: Authorized Title:Operations Manager Contact Email: Contact Phone: 8,540psi Hilcorp Alaska LLC 777-8333 2. Operator Name Senior Engineer: Senior Res. Engineer: Collapse N/A 4,760psi 3,090psi 7,020psi Burst N/A 6,870psi 5,750psi 8,160psi 20" 9-5/8" 9-5/8" 7-5/8" 9,020psi 2,020' 3,998' 4,001' 3,873' Length 130' 2,625' 4,521' Surface Surface N/A measured 7,000' 6,531' N/A Tieback Liner Casing Conductor Size 360 MILNE PT UNIT L-62 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 647 Gas-Mcf 400 Casing Pressure Tubing Pressure 15 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 321-143 389 Authorized Signature with date: Authorized Name: David Gorm dgorm@hilcorp.com STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 220-059 50-029-23685-00-00 Plugs ADL0025509 & ADL0025515 5. Permit to Drill Number: MILNE POINT / SCHRADER BLUFF OIL Junk measured 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 3. Address: 4. Well Class Before Work: 290 Representative Daily Average Production or Injection Data 40510 27 Oil-Bbl measured true vertical Packer 4-1/2" 7,000' 13,520' WINJ WAG 5 Water-Bbl MD 130' 2,625' 7,146' TVD 130' Form 10-404 Revised 3/2020 Submit Within 30 days of Operations By Samantha Carlisle at 2:02 pm, Apr 23, 2021 Chad Helgeson (1517) 2021.04.23 12:15:54 - 08'00' DSR-4/26/21 SFD 4/23/2021MGR30JUL2021 RBDMS HEW 4/23/2021 _____________________________________________________________________________________ Revised By: DH 4/20/2021 SCHEMATIC Milne Point Unit Well: MPU L-62 Last Completed: 3/29/2021 PTD: 220-059 TD =13,520’(MD) / TD =3,873’ (TVD) 4 20” Orig. KB Elev.: 50.41’ / GL Elev.: 17.1’ 7-5/8” 7 8/9 10 4 16 9-5/8” 1 2 3 See Screen/ Solid Liner Detail PBTD =13,520’ (MD) / PBTD =3,873’ (TVD) 9-5/8” ‘ES’ Cementer @ 2,645’ MD 5/6 4-1/2” Shoe @ 13,520’ 11 13 12 14 15 3-1/2”CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20" Conductor 129.5 / A53 / Weld N/A Surface 130’ N/A 9-5/8" Surface 47 / L-80 / TXP 8.681 Surface 2,625’ 0.0758 9-5/8” Surface 40 / L-80 / TXP 8.835 2,625’ 7,146’ 0.0732 7-5/8” Tieback 29.7 / L-80 / Hyd 521 6.875 Surface 7,000’ 0.0459 4-1/2” Liner 13.5 / L-80 / Hyd 625 3.920 6,989’ 13,520’ .0149 TUBING DETAIL 2-7/8" Tubing 6.5 / L-80 / EUE-8rd 2.441 Surface 5,911’ 0.0087 OPEN HOLE / CEMENT DETAIL 2” ±270 ft3 12- 1/4" Stg 1 – Lead – 635 sx / Tail – 400 sx Stg 2 – Lead – 780 sx / Tail – 288 sx 8-1/2” Cementless Screened Liner WELL INCLINATION DETAIL KOP @ 258’ Max Hole Angle = 95° @ 9,913’ MD TREE & WELLHEAD Tree Cameron 2-9/16" 5M w/ 4-1/16” 5M Cameron Wing Wellhead Cameron 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs GENERAL WELL INFO API: 50-029-23685-00-00 Completion Date: 9/7/2020 JEWELRY DETAIL No. Top MD Item ID 1 201’ Sta. 2: 2-7/8” Gas Lift Mandrel 2 5,679’ Sta. 1: 2-7/8” Gas Lift Mandrel w/ 1” dummy valve 3 5,769’ XN Nipple, 2.313” Profile, 2.205” No Go 2.313” 4 5,822’ Ported Pressure Sub Adapter 5 5,824’ Upper Pump 6 5,846’ Lower Pump 7 5,867’ Gas Separator 8 5,872’ Upper Tandem Seal 9 5,881’ Lower Tandem Seal 10 5,890’ Motor 11 5,907’ Motor Gauge 12 5,909’ Centralizer: Bottom @ 5,911’ MD 13 6,989’ BOT SLZXP LTP / Liner Hanger 7” x 9-5/8” (4001’ TVD) 7.020” 14 6,989’ Locator Sub, 7” TXP Box x Box 6.170” 15 7,011’ 7” H563 x 4.5” TSH 625 XO 3.850” 16 13,520’ Shoe 3.950” 4-1/2” 250ђ SCREENS LINER DETAIL Jts Top (MD) Top (TVD) Btm (MD) Btm (TVD) 3 8207’ 3968’ 8334’ 3963’ 20 8458’ 3959’ 9268’ 3931’ 3 9430’ 3927’ 9549’ 3931’ 19 10041’ 3916’ 10817’ 3886’ 25 11141’ 3877’ 12187’ 3879’ 23 12516’ 3878’ 13477’ 3873’ Well Name Rig API Number Well Permit Number Start Date End Date MP L-62 ASR 50-029-23685-00-00 220-059 3/25/2021 3/29/2021 3/26/2021 Held PJSM and discussed activitie. Continued MIRU ASR, spotted in rig and raised mast. Continued perform ground work around rig. Position carriage to install basket and bails. Crew found a coolant leak underneath the power pack. SD the rig and call VMS to repair, while VMS repaired coolant leak, final torque up on BOP Stack. Hooked up fire and gas. Spotted in rig pump and connected circulating lines, continued performing ground work and winterizing equipment. Repairs completed on coolant leak, installed the basket on top of the carriage. PU bails on the elevators and connected the hydraulics. Replaced the electrical service loop cable. Spotted and RU the glycol unit. Working on repairing the hydraulic service loop hose, Pre tour safety meeting. Install new electrical cable in service loop. Replace hydraulic line in service loop. Work carriage up and down and ensure service loops are correctly installed and will not catch on back of rack. Grease all choke valves. Find and cap all ports where can rig equipment was removed during maintenance. Fill stack. Perform shell test to 2,500 psi. Start BOPE test to 250 psi low and 2,500 psi high with 2-7/8" test joint . Through test #2 at time of report. Wellhead: Nipple down tree and adaptor, Set CTS Dart, install new R-54 API ring, ASR to move in Rig up. Hilcorp Alaska, LLC Weekly Operations Summary 3/25/2021 Crew Preparing ASR and associated equipment to move from A-pad to L-62. Spotted rig mats and Tiger tank and circ out manifold. S/I Tbg/IA/OA=356/342/0 . MIRU LRS pump truck, operator changed out. PT Lines to 250/2,500psi-good test. Bled IA and Tbg to 0psi. Returns all gas. Lined up to pump dn IA taking returns up tbg to tank. Fully open choke. Pumped 15bbls of 80 deg diesel @ 2bpm/0psi. Swapped to 80 deg 8.33 SW and increased rate to 3bpm/0psi. At 65 bbls away IA incresed to 40psi with no returns. At 150bbls away IA climb to 121psi, Tbg pressure inceased to 2psi slight blow at tank w/no returns. After 215 bbls away IA and Tbg when on Vac. SD Pump after 255 bbls away IA/TBG and vac. Lined up to pump dn tbg, taking returns up the IA. Fully open choke. Started pumping tbg @ .5 bpm pressure climb after 1bbl pumped away tbg pressure increased 1200psi. SD pump and investigated why we are seeing the pressure increase dn the tbg. Check all circulating and tree valves. Pumped thru circ maniflod to tank and all clear. Tried pumping down tbg again and observed same pressure increase. 5bpm/1200psi. Pumped away 3.5bbls SD pump and tbg went on a vac. Monitored well IA/Tbg on Vac. Discussed with town, possible issue with plugged off tbg. Decided to set BPV and try pumping dn tbg once hanger is removed. Set BPV, Freeze portest lines and RDMO LRS. Tbg/IA/OA= Vac/Vac/0. Safety meeting and Sundry review with both rig crews, blow down and break return lines to flowback tank. Move rig mats. Spot mud boat. Move ASR and associated equipment from A-Pad to L-62. Perform pre-site inspection and complete work permit. N/D Tree. N/U BOPE. Spot well hut and rig floor. Spot Pusher Shack, Co-Man Shack, and Doghouse. Well Name Rig API Number Well Permit Number Start Date End Date MP L-62 ASR 50-029-23685-00-00 220-059 3/25/2021 3/29/2021 Hilcorp Alaska, LLC Weekly Operations Summary Held PJSM and discussed daily activities to be preformed with crew. Continued testing BOPE per sundry as following: Annular 250-2500psi, Rams 250-2500psi, Valves 250-2500psi. Tested Fire&Gas and preformed the Koomey drawdown. 2- 7/8" test jt was used. No failures were recorded. AOGCC witness was waived by Bob Noble on 3/26/21 @ 5:55pm. Blow lines and stack dry, LD the BOPE testing equipment. Repaired hydraulic fitting leak underneath the back derrick manifold. Install protection wrap on the service loop hoses. Spotted in containment and pipe racks. Hung cable sheave and elephant trunk. Replace cap on oil filter for 100k generator. Pull Test Plug. Dry Rod into BPV and check Tubing pressure. Fluid in Stack drops out. Tubing pressure is 0 psi. Pull BPV. M/U 2-7/8" landing joint. IA pressure is 0 psi. BOLDS. Pull 45k-lbs. to free hanger. Pull Hanger to the Floor with 45k-lbs. Cut ESP Cable. Break and L/D Hanger. Hanger appears to be in good condition. Small amount of sand seen at top of Hanger. Wellhead Group to inspect Hanger closer in shop. Pull ESP cable over Sheave and to ESP Cable Spooler. POH w/ 2-7/8" ESP completion while laying down single joints and spooling ESP Cable. Tubing, GLMs and Clamps being inspected for reuse. Filling hole with double displacement 5bbls every 10jts out. Notice scale build up starting at joint 84 OOH (~2,600'). 100 joints OOH at time of report. 3/27/2021 Held PJSM, checked fluids and serviced rig and equipment as needed. Continue to RIH w/ Summit ESP completion on 2-7/8” tubing f/1250' t/hanger depth. Torque connecting @ 2,100 lbs/ft. Utilizing CC Clamps every other joint. Testing cable every 2000'. PU/MU landing jt and tbg hanger with BPV Installed. Cut cable and terminated penetrator to hanger. Final cable test were good. Landed completion with 22k down on hanger and RILDS. EOT @ 5,915'. Note: PUW 45k, SOW 22k. End of well work. Wellhead: Land Tubing hanger (P134137-0002) RILDS, nipple down BOPS move off rig, Nipple up tree adaptor, teste to 500 / 5000 psi for 10 mins, Pull BPV. RDMO. 3/28/2021 Held PJSM, checked fluids and serviced rig as needed. POH w/ 2-7/8" ESP completion while laying down single joints f/2,600' t/discharge head and spooling ESP Cable. Tubing, GLMs and clamps being inspected for reuse. Filling hole with double displacement 2bbls every 15 jts out. After LD bottom GLM tbg was wet mainly heavy oil with trace of light sand. RU mud bucket and LD the last 3 Joints and XN-Nipple. LD ESP assembly, top pump was frozen, middle and lower pump would turn but real gritty. Motor turn freely, seals and motor had formation clay caked on the outside and some scale build up around the pot Head. Motor gauge line was damaged. RD the elephant trunk. Swapped ESP spools. Offloaded and staged summit ESP equipment on the pipe racks. PU/MU and serviced new Summit ESP assembly. P/U 10' handling pup and M/U to discharge head. M/U joint #1. While RIH with joint #1, the armor on the motor lead was punctured by a crescent wrench while attempting to straighten the motor lead to the tubing for the banding process. Summit evaluated puncture and determined that puncture must be removed. Cut motor lead below puncture. Cut ESP cable above existing motor lead to ESP cable splice. Re-splice motor lead to ESP Cable. Test cable. Cable good. Continue to RIH w/ Summit ESP completion on 2- 7/8” tubing. Installing clamps on first 10 joints and every other joint thereafter. 36 jts in the hole at report time. 3/29/2021 1.Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: ESP Swap 2.Operator Name:4.Current Well Class:5.Permit to Drill Number: Exploratory Development 3.Address:Stratigraphic Service 6. API Number: 7. If perforating:8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception?Yes No 9.Property Designation (Lease Number):10.Field/Pool(s): 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 13,520'N/A Casing Collapse Conductor N/A Surface 4,760psi Surface 3,090psi Tieback 7,020psi Liner 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 Commission Representative: GINJ Op Shutdown Abandoned Chad Helgeson Contact Name: David Gorm Operations Manager Contact Email: Contact Phone: 777-8333 Date: Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by:COMMISSIONER THE COMMISSION Date: Comm.Comm.Sr Pet Eng Sr Pet Geo Sr Res Eng Tubing Grade:Tubing MD (ft): dgorm@hilcorp.com COMMISSION USE ONLY Authorized Name: PRESENT WELL CONDITION SUMMARY STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0025509 & ADL0025515 220-059 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 50-029-23685-00-00 Hilcorp Alaska LLC Length Size 3,873' 13,520' 3,873' 1,096 N/A MILNE POINT / SCHRADER BLUFF OIL 130' 130' 6.5 / L-80 EUE 8rd TVD Burst 5,934' 9,020psi MD N/A 8,160psi 6,870psi 5,750psi 2,020' 3,998' 4,001' 2,625' 7,146' 130' 20" 9-5/8" 9-5/8" 2,625' 7-5/8"7,000' 4,521' 3,873' Authorized Signature: 3/26/2021 2-7/8" Perforation Depth MD (ft): See Schematic See Schematic 4-1/2" Perforation Depth TVD (ft): Tubing Size: MILNE PT UNIT L-62 C.O. 477.05 BOT SLZXP LTP and N/A 6,989 MD / 4,001 TVD and N/A Authorized Title: 17.I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. 13,520' 7,000' 6,531' ory Statu Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 7:27 pm, Mar 22, 2021 321-143 Chad Helgeson (1517) 2021.03.22 15:38:16 - 08'00' DLB 03/23/2021 X DSR-3/23/21 10-403 BOPE Test to 2000 psi. MGR24MAR21Comm q 3/24/21 dts 3/24/2021 JLC 3/24/2021 10-404 RBDMS HEW 3/25/2021 ESP RWO Well: MP L-62 2021 ESP RWO Well Name:MPU L-62 API Number:50-029-23685-00 Current Status:SI Producer (Failed ESP)Pad:L-Pad Estimated Start Date:March 26th , 2021 Rig:ASR#1 Reg. Approval Req’d?Yes Date Reg. Approval Rec’vd: Regulatory Contact:Tom Fouts Permit to Drill Number:220-059 First Call Engineer:David Gorm (907) 777-8333 (O) (505) 215-2819 (M) Second Call Engineer:Ian Toomey (907) 777-8520 (O) (907) 903-3987 (M) AFE Number:Job Type:ESP RWO Current Bottom Hole Pressure: 1,484 psi @ 3,873’ TVD Estimated BHP 3/22/2021 7.4 ppg EMW Maximum Expected BHP:1,484 psi @ 3,873’ TVD MPSP:1096 psi (0.1 psi/ft gas gradient) Max Inclination:90° @ 6,989’ MD Horizontal @ 6,989’ MD Max Dogleg:5.4°/100’ @ 5,740’ TVD Brief Well Summary: MPU L-62 was drilled, and completed as a Schrader Bluff producer with an ESP installed in September 2020. Notes Regarding the Well & Design x 2021 ESP shorted to ground requiring workover. x Offset Injector Support o L-61 Objective: x Pull Failed ESP Completion x Run new ESP Completion Pre-Workover Prep Procedure: 1. RD well house and flowlines. Clear and level area around well. 2. RU Little Red Services Pump. Setup reverse out skid, returns tank, and additional upright tanks as needed. 3. Pressure test lines to 3,000 psi. 4. Review kill plan with Engineer based on current well conditions. 5. Pump 250 bbls of 8.3 ppg source water down the IA with the TBG open to the pit. 6. Pump 40 bbls of 8.3 ppg source water down tubing with the IA open to the pit. 7. Confirm well is dead. 8. RD Little Red Services Pump and reverse out skid. 9. Clear and level pad area in front of well. Spot rig mats and containment. 10. RU crane. Set BPV. ND Tree. NU 11” BOPE. RD crane. a. Make scribe mark on tree for orientation for re-installation. b. Function test all prior to arrival of AOGCC inspectors. 11. NU BOPE house. Spot mud boat Workover Procedure: ESP RWO Well: MP L-62 2021 ESP RWO 12. MIRU ASR #1 Workover rig, ancillary equipment and lines to returns tank. 13. Pull BPV after confirming zero surface wellhead pressure. If needed, bleed off any residual pressure off tubing and casing. If needed, kill well w/8.3 ppg source-water prior to pulling BPV. Set TWC. 14. Test BOPE to 250psi Low/ 2,000 psi High, annular to 250psi Low/ 2,000 psi High (hold each ram/valve and test for 5-min). Record accumulator pre-charge pressures and chart tests. a. Notify AOGCC 24 hrs in advance of BOP test. b. Confirm test pressures per the Sundry Conditions of approval. c. Test VBR rams on 2-7/8” test joint. d. Submit to AOGCC completed 10-424 form within 5 days of BOPE test. 15. Bleed any pressure off casing to returns tank. Pull TWC. 16. RU spooler to pull ESP Cable. 17. MU landing joint or spear and PU on the tubing hanger. a. PU weight estimated 85 Klbs. b. If needed, circulate (long or reverse) source-water, and/or baraclean pill prior to laying down the tubing hanger. 18. Recover the tubing hanger. a. Evaluate pulled tubing hanger for possible thread damage. If any damage is found, dispose of tubing hanger and contact well head specialist for replacement. b. Check the ESP Cable after the hanger is removed. If cable is grounded continue POH, if Cable tests good Contact Engineer on test results, option to re-land hanger. 19. POOH and lay down the 2-7/8” tubing and ESP completion. (plan to re-run same 2-7/8” TBG) a. Cable clamped every joint first 15 jts and every other joint after to surface. b. Inspect and re-use 2-7/8” TBG and clamps. c. Re-use all gas-lift mandrels and XN nipple. d. Dispose of ESP cable e. Prep ESP for DIFA (Dismantle Inspection and Failure Analysis). f. Note any sand, scale, or corrosion on the tubulars or ESP on the morning report. 20. PU new ESP and RIH on 2-7/8” 6.5# 8rd-EUE L-80 tubing. Set base of ESP assembly at ±5,933’ MD. a. Upper 2-7/8”x 1” Side-pocket GLM @ ±200’ MD with 0.25” OV b. 2-7/8” tubing c. Lower 2-7/8”x 1” Side-pocket GLM with Dummy GLV d. 1 joint of 2-7/8” tubing e. 2-7/8” XN (2.205” No-Go) Nipple f. 2-7/8” tubing g. Downhole gauge for discharge temperature and pressure. h. ESP (TBD) i. ESP (TBD) ESP RWO Well: MP L-62 2021 ESP RWO j. Tandem Gas Separator k. Motor l. Motor gauge m. Base of ESP centralizer @ ±5,933’ MD 21. Land tubing hanger. RILDS. Lay down landing joint. Note slack-off weight on tally. 22. Set BPV. Post-Rig Procedure: 23. RD mud boat. RD BOPE house. Move to next well location. 24. RU crane. ND BOPE. 25. NU existing tree. Test tubing hanger void to 500 psi low/5,000 psi high. 26. Pull BPV. 27. RD crane. Move returns tank and rig mats to next well location. 28. Replace gauge(s) if removed. 29. Turn well over to production. RU well house and flowlines. Attachments: 1. As-built Schematic 2. Proposed Schematic 3. BOPE Schematic 4. Blank RWO MOC Form _____________________________________________________________________________________ Revised By: TDF 3/22/2021 SCHEMATIC Milne Point Unit Well: MPU L-62 Last Completed: 9/7/2020 PTD: 220-059 TD =13,520’ (MD) / TD =3,873’ (TVD) 4 20” Orig. KB Elev.: 50.41’ / GL Elev.: 17.1’ 7-5/8” 8 9/10 11 4 17 9-5/8” 1 2 3 See Screen/ Solid Liner Detail PBTD = 13,520’ (MD) / PBTD = 3,873’ (TVD) 9-5/8” ‘ES’ Cementer @ 2,645’ MD 5/6/7 4-1/2” Shoe @ 13,520’ 12 14 13 15 16 3-1/2”CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20" Conductor 129.5 / A53 / Weld N/A Surface 130’ N/A 9-5/8" Surface 47 / L-80 / TXP 8.681 Surface 2,625’ 0.0758 9-5/8” Surface 40 / L-80 / TXP 8.835 2,625’ 7,146’ 0.0732 7-5/8” Tieback 29.7 / L-80 / Hyd 521 6.875 Surface 7,000’ 0.0459 4-1/2” Liner 13.5 / L-80 / Hyd 625 3.920 6,989’ 13,520’ .0149 TUBING DETAIL 2-7/8" Tubing 6.5 / L-80 / EUE-8rd 2.441 Surface 5,934’ 0.0087 OPEN HOLE / CEMENT DETAIL 2” ±270 ft3 12- 1/4" Stg 1 – Lead – 635 sx / Tail – 400 sx Stg 2 – Lead – 780 sx / Tail – 288 sx 8-1/2” Cementless Screened Liner WELL INCLINATION DETAIL KOP @ 258’ Max Hole Angle = 95° @ 9,913’ MD TREE & WELLHEAD Tree Cameron 2-9/16" 5M w/ 4-1/16” 5M Cameron Wing Wellhead Cameron 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs GENERAL WELL INFO API: 50-029-23685-00-00 Completion Date: 9/7/2020 JEWELRY DETAIL No. Top MD Item ID 1201’GLM w/ ¼” OV 2 5682’ 2-7/8” GLM w/ 1” Dummy Valve 3 5772’ XN Nipple, 2.313” Profile, 2.205” No Go 2.313” 4 5825’ Discharge Head: B/O PMP 400 2.88 X 8MD EUE 5 5826’ Upper Pump: 400PMSXD 134 Flex 17.5 H6 FER 6 5850’ Middle Pump: 400PMSXD 134 Flex 17.5 H6 FER 7 5873’ Lower Pump: 400PMSXD 134 Flex 17.5 H6 FER 8 5897’ Gas Separator: 538GSTHVEVX MT H6 FER STD PNT 9 5902’ Upper Tandem Seal: GSBDB H6 SB/AB PFSA 10 5909’ Lower Tandem Seal: GSBDB H6 SB/AB PFSA 11 5916’ Motor: 562SP – 200 HP 265V / 34A 12 5930’ Motor Gauge Zenith 13 5933’ Centralizer: Bottom @ 5934’ MD 14 6989’ BOT SLZXP LTP / Liner Hanger 7” x 9-5/8” (4001’ TVD) 7.020” 15 6989’ Locator Sub, 7” TXP Box x Box 6.170” 16 7011’ 7” H563 x 4.5” TSH 625 XO 3.850” 17 13520’ Shoe 3.950” 4-1/2” 250ђ SCREENS LINER DETAIL Jts Top (MD) Top (TVD) Btm (MD) Btm (TVD) 3 8207’ 3968’ 8334’ 3963’ 20 8458’ 3959’ 9268’ 3931’ 3 9430’ 3927’ 9549’ 3931’ 19 10041’ 3916’ 10817’ 3886’ 25 11141’ 3877’ 12187’ 3879’ 23 12516’ 3878’ 13477’ 3873’ _____________________________________________________________________________________ Revised By: TDF 3/22/2021 PROPOSED Milne Point Unit Well: MPU L-62 Last Completed: 9/7/2020 PTD: 220-059 TD =13,520’ (MD) / TD =3,873’ (TVD) 4 20” Orig. KB Elev.: 50.41’ / GL Elev.: 17.1’ 7-5/8” 8 9/10 11 4 17 9-5/8” 1 2 3 See Screen/ Solid Liner Detail PBTD = 13,520’ (MD) / PBTD = 3,873’ (TVD) 9-5/8” ‘ES’ Cementer @ 2,645’ MD 5/6/7 4-1/2” Shoe @ 13,520’ 12 14 13 15 16 3-1/2”CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20" Conductor 129.5 / A53 / Weld N/A Surface 130’ N/A 9-5/8" Surface 47 / L-80 / TXP 8.681 Surface 2,625’ 0.0758 9-5/8” Surface 40 / L-80 / TXP 8.835 2,625’ 7,146’ 0.0732 7-5/8” Tieback 29.7 / L-80 / Hyd 521 6.875 Surface 7,000’ 0.0459 4-1/2” Liner 13.5 / L-80 / Hyd 625 3.920 6,989’ 13,520’ .0149 TUBING DETAIL 2-7/8" Tubing 6.5 / L-80 / EUE-8rd 2.441 Surface 5,933’ 0.0087 OPEN HOLE / CEMENT DETAIL 2” ±270 ft3 12- 1/4" Stg 1 – Lead – 635 sx / Tail – 400 sx Stg 2 – Lead – 780 sx / Tail – 288 sx 8-1/2” Cementless Screened Liner WELL INCLINATION DETAIL KOP @ 258’ Max Hole Angle = 95° @ 9,913’ MD TREE & WELLHEAD Tree Cameron 2-9/16" 5M w/ 4-1/16” 5M Cameron Wing Wellhead Cameron 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs GENERAL WELL INFO API: 50-029-23685-00-00 Completion Date: 9/7/2020 JEWELRY DETAIL No. Top MD Item ID 1 ±200’ Sta. 2: GLM 2 ±5,682’ Sta. 1: GLM 3 ±5,772’ XN Nipple, 2.313” Profile, 2.205” No Go 2.313” 4 ±5,825’ Discharge Head: 5 ±5,826’ Upper Pump: 6 ±5,850’ Middle Pump: 7 ±5,873’ Lower Pump: 8 ±5,897’ Gas Separator 9 ±5,902’ Upper Tandem Seal: 10 ±5,909’ Lower Tandem Seal: 11 ±5,916’ Motor: 12 ±5,930’ Motor Gauge: 13 ±5,933’ Centralizer: Bottom @ ±5,933’ MD 14 6,989’ BOT SLZXP LTP / Liner Hanger 7” x 9-5/8” (4001’ TVD) 7.020” 15 6,989’ Locator Sub, 7” TXP Box x Box 6.170” 16 7,011’ 7” H563 x 4.5” TSH 625 XO 3.850” 17 13,520’ Shoe 3.950” 4-1/2” 250ђ SCREENS LINER DETAIL Jts Top (MD) Top (TVD) Btm (MD) Btm (TVD) 3 8207’ 3968’ 8334’ 3963’ 20 8458’ 3959’ 9268’ 3931’ 3 9430’ 3927’ 9549’ 3931’ 19 10041’ 3916’ 10817’ 3886’ 25 11141’ 3877’ 12187’ 3879’ 23 12516’ 3878’ 13477’ 3873’ Milne Point ASR Rig 1 BOPE BOPE ~4.48' ~4.54' 2.00' 5000# 2-7/8" x 5" VBR 5000#Blind DSA, 11 5M X 7 1/16 5M (If Needed) 2 1/16 5M Kill Line Valves 2 1/16 5M Choke Line Valves HCRManualManualManual Stripping Head Hilcorp Alaska, LLCHilcorp Alaska, LLCChanges to Approved Rig Work Over Sundry ProcedureDate: March 22nd, 2021Subject: Changes to Approved Sundry Procedure for Well MP L-62Sundry #: XXX-XXXAny modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to theAOGCC by the rig workover (RWO) “first call” engineer. AOGCC written approval of the change is required before implementing the change.Step Page Date Procedure ChangeHAKPreparedBy (Initials)HAKApprovedBy (Initials)AOGCC WrittenApproval Received(Person and Date)Approval:Operations Manager DatePrepared:Operations Engineer Date DATA SUBMITTAL COMPLIANCE REPORTAPI No.50-029-23685-00-00Well Name/No. MILNE PT UNIT L-62Completion Status1-OILCompletion Date9/7/2020Permit to Drill2200590OperatorHilcorp Alaska, LLCMD13520TVD3873Current Status1-OIL10/15/2020UICNoWell Log Information:DigitalMed/FrmtReceivedStart StopOH /CHCommentsLogMediaRunNoElectr DatasetNumberNameIntervalList of Logs Obtained:ROP, AGR, ABG, DGR, EWR, ADR MD & TVDNoNoYesMud Log Samples Directional SurveyREQUIRED INFORMATION(from Master Well Data/Logs)DATA INFORMATIONLog/DataTypeLogScaleDF10/5/2020128 13520 Electronic Data Set, Filename: MPU L-62 LWD Final.las34052EDDigital DataDF10/5/20207136 13482 Electronic Data Set, Filename: MPU L-62 ADR Quadrants All Curves.las34052EDDigital DataDF10/5/2020 Electronic File: MPU L-62 LWD Final MD.cgm34052EDDigital DataDF10/5/2020 Electronic File: MPU L-62 LWD FInal TVD.cgm34052EDDigital DataDF10/5/2020 Electronic File: MPU L-62 - Definitive Survey Report.pdf34052EDDigital DataDF10/5/2020 Electronic File: MPU L-62 Final Surveys.xlsx34052EDDigital DataDF10/5/2020 Electronic File: MPU L-62_DSR.txt34052EDDigital DataDF10/5/2020 Electronic File: MPU L-62_GIS.txt34052EDDigital DataDF10/5/2020 Electronic File: MPU L-62 LWD Final MD.emf34052EDDigital DataDF10/5/2020 Electronic File: MPU L-62 LWD Final TVD.emf34052EDDigital DataDF10/5/2020 Electronic File: MPU_L-62_Geosteering.dlis34052EDDigital DataDF10/5/2020 Electronic File: MPU_L-62_Geosteering.ver34052EDDigital DataDF10/5/2020 Electronic File: MPU L-62 LWD Final MD.pdf34052EDDigital DataDF10/5/2020 Electronic File: MPU L-62 LWD Final TVD.pdf34052EDDigital DataDF10/5/2020 Electronic File: MPU L-62 LWD Final MD.tif34052EDDigital DataDF10/5/2020 Electronic File: MPU L-62 LWD FInal TVD.tif34052EDDigital DataThursday, October 15, 2020AOGCCPage 1 of 2MPU L-62 LWDFinal.las DATA SUBMITTAL COMPLIANCE REPORTAPI No.50-029-23685-00-00Well Name/No. MILNE PT UNIT L-62Completion Status1-OILCompletion Date9/7/2020Permit to Drill2200590OperatorHilcorp Alaska, LLCMD13520TVD3873Current Status1-OIL10/15/2020UICNoWell Cores/Samples Information:ReceivedStart Stop CommentsSentSample SetNumberNameIntervalINFORMATION RECEIVEDCompletion ReportProduction Test InformationGeologic Markers/TopsY Y / NAYComments:Compliance Reviewed By:Date:Mud Logs, Image Files, Digital DataComposite Logs, Image, Data Files Cuttings SamplesY / NAYY / NADirectional / Inclination DataMechanical Integrity Test InformationDaily Operations SummaryYY / NAYCore ChipsCore PhotographsLaboratory AnalysesY / NAY / NAY / NACOMPLIANCE HISTORYDate CommentsDescriptionCompletion Date:9/7/2020Release Date:7/17/20200 0 2200590 MILNE PT UNIT L-62 LOG HEADERS34052LogLog Header ScansThursday, October 15, 2020AOGCCPage 2 of 2M. Guhl10/15/2020 David Douglas Hilcorp Alaska, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or fax to 907 777-8510. Received By: Date: DATE 10/05/2020 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU L-62 (PTD 220-059) FINAL LWD LOGS (02SEP2020): EWR-M5, AGR, ADR, DGR, ABG, WELLBORE_PROFILE (MD/TVD) AND DEFINITIVE DIRECTIONAL SURVEY Final CD Folders: Received by the AOGCC 10/05/2020 PTD: 2200590 E-Set: 34052 Abby Bell 10/06/2020 1a. Well Status:Oil SPLUG Other Abandoned Suspended 1b. Well Class: 20AAC 25.105 20AAC 25.110 Development Exploratory GINJ WINJ WDSPL No. of Completions: _1 Service Stratigraphic Test 2. Operator Name: 6. Date Comp., Susp., or 14. Permit to Drill Number / Sundry: Aband.: 3. Address: 7. Date Spudded: 15. API Number: 4a. Location of Well (Governmental Section): 8. Date TD Reached: 16. Well Name and Number: Surface: Top of Productive Interval: 9. Ref Elevations: KB: 17. Field / Pool(s): GL: 17.10' 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" A-53 130' L-80 2020' L-80 3998' 7-5/8" L-80 4001' 4-1/2" L-80 3873' 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 5934'2-7/8" 6.5# L-80 SIZEIf Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number; Date Perfd): 6989' 13520' Stg 2 L - 780 sx / T - 288 sx 4001' 42" 13.5# Surface 2625' Stg 1 L - 635 sx / T - 400 sx 8-1/2" ±270 ft3 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 9/7/2020 2031' FNL, 457' FWL, Sec. 08, T13N, R10E, UM, AK 2535' FSL, 388' FWL, Sec. 20, T13N, R10E, UM, AK 220-059 Milne Point Field, Schrader Bluff Oil Pool 50.41' 13520' / 3873' HOLE SIZE AMOUNT PULLED 17.10' 50-029-23685-00-00 MPU L-62 545058 6031439 1745' FNL, 1840' FWL, Sec. 17, T13N, R10E, UM, AK CEMENTING RECORD 6026455 SETTING DEPTH TVD 6020167 BOTTOM TOP Surface Surface CASING WT. PER FT.GRADE 29.7# 546489 545097 TOP SETTING DEPTH MD Surface Surface Per 20 AAC 25.283 (i)(2) attach electronic information 40# 7000' 2020' Surface DEPTH SET (MD) 6989' / 4001' PACKER SET (MD/TVD) 129.5# 47# 130' 2625' 7146' Gas-Oil Ratio:Choke Size:Water-Bbl: PRODUCTION TEST N/A 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 4-1/2" Screen Liner 9/3/2020 ***Please see attached Schematic for detail*** ROP, AGR, ABG, DGR, EWR, ADR MD & TVD Sr Res EngSr Pet GeoSr Pet Eng Oil-Bbl: Water-Bbl: 8/31/2020 8/20/2020 ADL 025509 & 025515 88-002 N/AN/A None 13520' / 3873' Form 10-407 Revised 3/2020 Submit within 30 days of Completion, Suspension, or Abandonment By Samantha Carlisle at 10:54 am, Sep 28, 2020 Completion Date 9/7/2020 MDG RBDMS 10/13/2020 MDG G DSR-10/14/2020DLB 10/13/2020 2489'/1947' MDG MGR15OCT2020 Conventional Core(s): Yes No Sidewall Cores: 30. MD TVD 20' 20' Top of Productive Interval 7105' 3999' 1591' 1437' 2868' 2148' 5280' 3479' 6602' 3963' 7105' 3999' SB NB 7105' 3999' 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 Ugnu LA3 Permafrost - Base 29. GEOLOGIC MARKERS (List all formations and markers encountered): FORMATION TESTS Permafrost - Top SV5 SV1 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. Schrader Bluff NB Formation at total depth: LOT / FIT Data Sheet, Drilling and Completion Reports, Definitive Directional Survey, Csg and Cmt Report, 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). Schrader Bluff NA 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 9.28.2020Digitally signed by Monty M Myers DN: cn=Monty M Myers, c=US, o=Hilcorp Alaska, LLC, ou=Technical Services - AK Drilling, email=mmyers@hilcorp.com Reason: I am approving this document Date: 2020.09.28 09:58:28 -08'00' Monty M Myers 2489'1947' MDG _____________________________________________________________________________________ Edited By: JNL 9-22-2020 Schematic Milne Point Unit Well: MPU L-62 Last Completed: 9/7/2020 PTD: 220-059 TD =13,520’ (MD) / TD =3,873’ (TVD) 4 20” Orig. KB Elev.: 50.41’ / GL Elev.: 17.1’ 7-5/8” 8 9/10 11 4 17 9-5/8” 1 2 3 See Screen/ Solid Liner Detail PBTD = 13,520’ (MD) / PBTD = 3,873’ (TVD) 9-5/8” ‘ES’ Cementer @ 2,645’ MD 5/6/7 4-1/2” Shoe @ 13,520’ 12 14 13 15 16 3-1/2” CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20" Conductor 129.5 / A53 / Weld N/A Surface 130’ N/A 9-5/8" Surface 47 / L-80 / TXP 8.681 Surface 2,625’ 0.0758 9-5/8” Surface 40 / L-80 / TXP 8.835 2,625’ 7,146’ 0.0732 7-5/8” Tieback 29.7 / L-80 / Hyd 521 6.875 Surface 7,000’ 0.0459 4-1/2” Liner 250ђ Screens 13.5 / L-80 / Hyd 625 3.920 6,989’ 13,520’ .0149 TUBING DETAIL 2-7/8" Tubing 6.5 / L-80 / EUE-8rd 2.441 Surface 5,934’ 0.0087 OPEN HOLE / CEMENT DETAIL 42” ±270 ft3 12-1/4"Stg 1 – Lead – 635 sx / Tail – 400 sx Stg 2 – Lead – 780 sx / Tail – 288 sx 8-1/2” Cementless Screened Liner WELL INCLINATION DETAIL KOP @ 258’ Max Hole Angle = 95° @ 9,913’ MD TREE & WELLHEAD Tree Cameron 2-9/16" 5M w/ 4-1/16” 5M Cameron Wing Wellhead Cameron 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs GENERAL WELL INFO API: 50-029-23685-00-00 Completion Date: 9/7/2020 4-1/2”SOLID LINER DETAIL Jts Top (MD) Top (TVD) Btm (MD) Btm (TVD) 29 7015’ 4001’ 8207’ 3968’ 3 8334’ 3963’ 8458’ 3959’ 4 9268’ 3931’ 9430’ 3927’ 12 9549’ 3931’ 10041’ 3916’ 8 10817’ 3886’ 11141’ 3877’ 8 12187’ 3879’ 12516’ 3878’ 1 13477’ 3875’ 13518’ 3873’ JEWELRY DETAIL No. Top MD Item ID 1201’GLM w/ ¼” OV 2 5682’ 2-7/8” GLM w/ 1” Dummy Valve 3 5772’ XN Nipple, 2.313” Profile, 2.205” No Go 2.313” 4 5825’ Discharge Head: B/O PMP 400 2.88 X 8MD EUE 5 5826’ Upper Pump: 400PMSXD 134 Flex 17.5 H6 FER 6 5850’ Middle Pump: 400PMSXD 134 Flex 17.5 H6 FER 7 5873’ Lower Pump: 400PMSXD 134 Flex 17.5 H6 FER 8 5897’ Gas Separator: 538GSTHVEVX MT H6 FER STD PNT 9 5902’ Upper Tandem Seal: GSBDB H6 SB/AB PFSA 10 5909’ Lower Tandem Seal: GSBDB H6 SB/AB PFSA 11 5916’ Motor: 562SP – 200 HP 265V / 34A 12 5930’ Motor Gauge Zenith 13 5933’ Centralizer: Bottom @ 5934’ MD 14 6989’ BOT SLZXP LTP / Liner Hanger 7” x 9-5/8” (4001’ TVD) 7.020” 15 6989’ Locator Sub, 7” TXP Box x Box 6.170” 16 7011’ 7” H563 x 4.5” TSH 625 XO 3.850” 17 13520’ Shoe 3.950” 4-1/2”SCREENS LINER DETAIL Jts Top (MD) Top (TVD) Btm (MD) Btm (TVD) 3 8207’ 3968’ 8334’ 3963’ 20 8458’ 3959’ 9268’ 3931’ 3 9430’ 3927’ 9549’ 3931’ 19 10041’ 3916’ 10817’ 3886’ 25 11141’ 3877’ 12187’ 3879’ 23 12516’ 3878’ 13477’ 3873’ CASING AND LEAK-OFF FRACTURE TESTS Well Name:MPU L-62 Date:8/28/2020 Csg Size/Wt/Grade:9.625"40# x 47#, L-80 Supervisor:Yessak/Vanderpool Csg Setting Depth:7146 TMD 3998 TVD Mud Weight:9.4 ppg LOT / FIT Press =540 psi . LOT / FIT =12.00 ppg Hole Depth =7174 md Fluid Pumped=1.7 Bbls Volume Back =1.6 bbls Estimated Pump Output:0.101 Barrels/Stroke LOT / FIT DATA CASING TEST DATA Enter Strokes Enter Pressure Enter Strokes Enter Pressure Here Here Here Here ->00 ->00 ->220 ->10 40 ->430 ->20 240 ->650 ->30 650 ->8 140 ->40 1040 ->10 230 ->50 1530 ->12 330 ->60 2080 ->14 450 ->70 2590 ->16 530 -> ->17 540 -> -> -> -> -> -> -> -> -> Enter Holding Enter Holding Enter Holding Enter Holding Time Here Pressure Here Time Here Pressure Here ->0 540 ->0 2590 ->1 500 ->5 2570 ->2 490 ->10 2560 ->3 480 ->15 2555 ->4 460 ->20 2550 ->5 450 ->25 2550 ->6 446 ->26 2550 ->7 435 ->27 2550 ->8 430 ->28 2550 ->9 425 ->29 2550 ->10 423 ->30 2550 ->11 421 -> ->12 420 -> ->13 418 -> ->14 417 ->15 416 ->16 415 0 2 4 6 8 10 12 14 16 17 0 10 20 30 40 50 60 70 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 01020Pressure (psi)Strokes (# of) LOT / FIT DATA CASING TEST DATA Pressure (psi) 540500490480460450446435430425423421420418417416415 2590 2570 2560 2555 2550 255025502550255025502550 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 8/19/2020 R/D on L-61. Rig released at 12:00. See L-61 completions report for details;PJSM, Skid rig floor into moving position, remove rockwasher. move Rig off L-61 and down the pad from the west end to the east end. Line up rig to spot over L-62;Pick surface annular preventer with cellar bridge cranes. Spot Rig over Well L-62 Skid rig floor into moving position. Hang stand of drill pipe in elevators to ensure rig was level and centered over well. Level and shim rig.;Make adjustments to Hi-Line breaker. Install all landings and handrails, ready beaverslide, P/U 22" surface riser. Hook up air, steam, water & high pressure mud lin es to the rig floor. Spot cuttings tank, fuel trailer, rock washer & all service buildings. Work on rig acceptance checklist.;N/U surface annular and diverter system. Spot water pump house,Slip and cut drlg line. C/O saver sub, inspect grabber dies, bring on Spud Mud to pits. Totco calibrate PVT system and flow sensor. Load BHA and HWDP in shed. Work on rig acceptance checklist. 8/20/2020 Finish rig acceptance checklist. R/U water pump house, Load BHA in shed strap and test, Process drill pipe. Perform diverter test & accumulator draw down, Trouble shoot hoses & knife valve. Good. AOGCC inspector Guy Cook waived witness of test at 15:11 on 8/19/20. ** Rig accepted at 12:00 ** Diverter test, 43 sec close time, 23 sec Knife valve open. 32 sec 200 PIS increase 141 sec full pressure, 6 nitrogen bottle avg 2125 PSI Vent line 310', 100' closest ignition source is a Production building light. Attempt to put rig on Hi-Line. Rig highline breaker will not close. P/U Motor and make up bit, Conduct Pre spud safety meeting. Flood stack and lines with H²0. Test lines to 3500 psi. No leaks. Swap to spud mud and drill out conductor F/ 60' - Ice and tag formation at 75'. Clean out conductor to 130' at 500 gpm 60 RPM. Drill 12-1/4" surface hole f/ 130' t/ 220' (220' TVD), 90' drilled, 180'/hr AROP. 500 GPM, 520 PSI, 40 RPM, 1K TQ, 1K WOB. MW 8.85 in / 8.9 out, vis 300+ in / 300+ out. 50K PU / 50K SO / 50K ROT. BROOH f/ 220' t/ 175', flow check static. POOH f/ 75' & inspect bit - good. PJSM for BHA. P/U MWD DM collar EWR M-5 Collar, ILS, TM Collar & UBHO sub to 88'. Initialize MWD tools. R/U gyro while plugged into MWD. Perform MWD offset (4.73/8.10*360=210.22°) & UBHO orientation. Continue to P/U three NMDC f/ 88' t/ 177'. M/U stand of HWDP & pulse test MWD. Wash down f/ 177' t/ 220'. Drill 12-1/4" surface hole f/ 220' t/ 250' (250' TVD) 30' drilled, 60'/hr AROP. 450 GPM, 830 PSI, 40 RPM, 1K TQ, 1-5K WOB. MW 8.9 in / 8.9 out, vis 300+ in / 300+ out. 59K PU / 62K SO / 58K ROT. Cuttings mostly large gravel #1 conveyor chain jumped Idler sprocket. Suspect large gravel seated in chain link rolled chain off sprocket. Relax sprocket and re-install chain. Adjust chain tension and test function. Good. Work string from 240' t/ 180' in staggered increments while working on conveyor. Drill 12-1/4" surface hole f/ 250' t/ 526' (525' TVD) 276' drilled, 92'/hr AROP. 450 GPM, 920 psi, 40 RPM, 3K TQ, 5-10K WOB. MW 8.9 in / 9 out, vis 210 in / 300 out, 9.5 ECD. 68k PU / 71k SO / 70k ROT. Gyro survey every stand, kickoff & target 3°/100' build. Gravel cleaning up by 280' Drill 12-1/4" surface hole f/ 526' t/ 1077' (1045' TVD) 551' drilled, 91.83'/hr AROP. 440 GPM, 1050 psi, 40 RPM, 8K TQ, 15-20K WOB. MW 9.1 in / 9.1 out, vis 250 in / 270 out, 10.03 ECD. 82k PU / 82k SO / 84k ROT. Start 4°/100' build @ 700’. Continue with gyro surveys each stand drilled, first clean MWD survey @ 888'. R/D and release Gyro @ 1019'. Last survey at 983.17' MD / 962.62' TVD, 26.33° inc, 152.45° azm, 3.78' from plan, 1.41' high and 3.51' right. No losses recorded on the day. H²O from L- Pad: 560 bbls Daily/ 560 bbls Total H²O from G&I Source Water: 0 bbls Daily / 0 bbls Total Cuttings/mud/cement to MPU G&I: 114 bbls Daily / 114 bbls Total 50-029-23685-00-00API #: Well Name: Field: County/State: MP L-62 Milne Point Hilcorp Energy Company Composite Report , Alaska 8/20/2020Spud Date: 8/21/2020 Drill 12-1/4" surface hole f/ 1077' t/ 2025', 948' drilled, 158'/hr AROP. 500 GPM, 1450 psi, 60 RPM, 5K TQ, 8-12K WOB. MW 9.2 in / 9.4 out, 10.4 ECD. 106k PU / 75k SO / 86k ROT. Continue w/ 4°/100’ build t/ 1783' then hold 56° tangent;Drill 12-1/4" surface hole f/ 2025' t/ 3285', (2380' TVD) 1260' drilled, 200.53'/hr AROP. 550 GPM, 1800 psi, 80 RPM, 7K TQ, 3-5K WOB. MW 9.3 in / 9.5 out, 10.6 ECD. 120k PU / 87k SO / 98k ROT. Continue hold 56° tangent’ Pump 30 bbls Hi-Vis sweep @ 2920’. Back on time with no increase;Last survey at 3171.01’ MD / 2315.66' TVD, 55.59° inc, 157.37° azm, 5.77' from plan, 5.60' high and 1.36' left. BOPF logged @ 2487' MD / 1944' TVD;While drilling @ 18:20, PFC in SCR room caught fire and rig power shut down Rig hands respond and extinguish fire. 18:23, Milne Point security notified that a fire on the rig had been extinguished. Fire response team dispatched Rig personnel muster at safe briefing area. All personnel accounted for;Notify Town and field management team of situation. 18:40, Fire Marshal and initial response team on location to assess situation 18:50, Remaining Fire response team with fire truck on location, standby;Clean SCR room to better assess damage. Start removing fire damaged equipment. Rig up air compressor to maintain Accumulator pressure. Seeing seepage losses at ~0.5 BPH, Rig up vac truck to hole fill line to maintain annulus volume.;Rig up Halliburton pump truck to circulate downhole via cement line. PJSM. PT lines to 1000 psi / 4000 psi. Good. Pump 1 BPM - 330 psi and establish returns. Increase flow t/ 2 BPM, pressure increase t/ 430 psi then drop to 330 psi indicating bit rotating. 5.75 bbls pumped.;Drain stack to cellar box and pump 9 bbls, filling riser to flow line. Stage rate up to 5 BPM - 650 psi.;Continue removing damaged equipment and cleaning SCR room. Drain stack to cellar box and circulate 10 bbls every hour. 5 BPM, 680 psi. Losses continue @ ~0.5 BPH;H2O from L-Pad: 1,520 bbls Daily/ 2,080 bbls Total H2O from G&I Source Water: 0 bbls Daily / 0 bbls Total Cuttings/mud/cement to MPU G&I: 1,554 bbls Daily / 1,668 bbls Total 8/22/2020 Continue cleaning SCR room and cabinets & remove damaged equipment, while waiting for parts. 1st breaker to arrive had different bolt pattern. Welder repair SCR cabinet door. Continue drain stack and circulate 10 bbls with HES cmt unit. @ 5 BPM, 625 psi every hour Losses at 0.5 BPH;8:55 Doyon camp alarm went off. Code 99 Red called out on radio. Personnel reported to primary muster area and all accounted for. Alarm panel showing H2S Sensor under camp. Check sensor and reading 0. Milne point emergency response on location and swept the camp. All clear called;Source proper breaker from other Doyon Rig. Continue prep cabinet and installing wiring shields. Install breaker and wiring. Install repaired cabinet door. Continue drain stack and circulate 10 bbls with HES cmt unit. @ 5 BPM, 625 psi every hour Losses at 0.5 BPH;Start #1 & 3 Rig generators. Warm to 160° and put Generators on-line. Power to the Rig @ 21:42 Check all Rig equipment to ensure powered up. Blow down HES and cement lines. Troubleshoot Mud Pump and Drawworks SCR’s. Change out fuses on SCR’s and power to Pumps and Drawworks restored.;Establish circulation and pump 50 bbls @ 220 GPM - 330 psi staging pumps up to 350 GPM – 690 psi Engage rotary and string stall immediately with 25k Tq. Release Tq and engage rotary several times with no success of breaking free.;Increase flow to 550 GPM – 1490 psi, engage rotary and slack off string to 75k, release torque and pull sting to 160k. Repeat multiple times with no success. Pumped 1.25x bottoms up then reduce flow rate t/ 350 GPM, 675 psi.;Work string 15 min, from 40-50k DN to 180-200k UP, jarring up with no success. Work string 40k DN-180k UP engaging rotary on downstroke, on the 5th repetition down the string broke free. Backream stand up at 540 GPM- 1500 psi, 70 RPM- 5k Tq. Pump 1x BU while backream std 2x;Reduce flow to 300 GPM, rotary to 40 RPM &work stand while troubleshooting no power to Rig gas alarm system. All other Rig systems and equipment operational. Power restored to alarm system.;Drill 12-1/4" surface hole f/ 3285' t/ 3971' (2759’ TVD), 686' drilled, 171.5'/hr AROP. 550 GPM, 2100 psi, 80RPM, 8k TQ, 5-10k WOB. MW 9.35 in / 9.4 out, Vis 150 in / 300 out 10.62 ECD. 135k PU / 85k SO / 106k ROT. Continue hold 56° tangent;Top Ugnu (MP_UG4) logged at 3373’ Last survey at 3837.16’ MD / 2682.19' TVD, 56.00° inc, 157.63° azm, 5.74' from plan, 5.74' high and 0.16' left.;Daily Losses = 6 bbls, Cumulative losses = 6 bbls H2O from L-Pad: 40 bbls Daily/ 2,120 bbls Total H2O from G&I Source Water: 0 bbls Daily / 0 bbls Total Cuttings/mud/cement to MPU G&I: 384 bbls Daily / 2,052 bbls Total 8/23/2020 Drill 12-1/4" surface hole f/ 3971' t/ 4897' (3260’ TVD), 926’ drilled, 154'/hr AROP. 560 GPM, 2270 psi, 80RPM, 10k TQ, 10k WOB. MW 9.4 in / 9.45 out, Vis 116 in / 300 out 10.68 ECD. 155k PU / 87k SO / 114k ROT. Max Gas – 155u Continue hold 56.6° tangent to 5399’ then start 4° build & turn;Pump 30 bbls Hi-Vis sweep @ 4066’ - Return was not recognized at surface;Drill 12-1/4" surface hole f/ 4897' t/ 5685' (3673’ TVD), 788’ drilled, 131'/hr AROP. 550 GPM, 2280 psi, 80RPM, 14k TQ, 15k WOB. MW 9.4 in / 9.45 out, Vis 116 in / 300 out 10.68 ECD. 175k PU / 92k SO / 124k ROT. Max Gas – 391u;Continue 4° build & turn Pump 30 bbls Hi-Vis sweep @ 5114’ – Return on time with 20% increase Pre-treat mud with 0.5% screenkleen @ 5500' and dress shakers down to 120's;Drill 12-1/4" surface hole f/ 5685' t/ 6200' (3866’ TVD), 515’ drilled, 86'/hr AROP. 550 GPM, 2020 psi, 80RPM, 17k TQ, 15k WOB. MW 9.3 in / 9.4 out, Vis 108 in / 160 out 10.13 ECD. 190k PU / 80k SO / 124k ROT. Max Gas – 192u Continue 4° build & turn;Pump 30 bbls Hi-Vis sweep @ 6066’ – Return on time with 10% increase Pump tangent from 5745’ to 6085’ (340’) w/ max DL of 1.16° Ugnu_MB sand logged at 5899' MD / 3755' TVD, No issues at shakers with the MB, maintain 0.5% screenkleen. Dress shakers back to 140's;Drill 12-1/4" surface hole f/ 6200' t/ 6732' (3980’ TVD), 532’ drilled, 89'/hr AROP. 550 GPM, 2100 psi, 80RPM, 15k TQ, 15k WOB. MW 9.3 in / 9.4 out, Vis 108 in / 160 out 10.13 ECD. 185k PU / 83k SO / 124k ROT. Max Gas – 170u Continue 4° build & turn;Last survey @ 6597.87' MD / 3962.58' TVD, 80.77° inc, 187.45° azm, 5.44’ from plan, 4.84’ high, 2.47' right.;H2O from L-Pad: 1,465 bbls Daily/ 3,585 bbls Total H2O from G&I Source Water: 0 bbls Daily / 0 bbls Total Cuttings/mud/cement to MPU G&I: 1,668 bbls Daily / 3,720 bbls Total 8/24/2020 Drill 12-1/4" hole f/ 6732' t/ 7154', at TD (3997’ TVD) Landed out @ 92.53 deg in th NB Sand 575 GPM, 2280 PSI, 80 RPM, 15k TQ, 15k WOB MW 9.45 ppg in / 9.55 ppg out, vis 86 in / 250 out, 10.4 ECD. Max Gas: 292u 170k PU / 79k SO / 116k ROT SB_NB Top @ 6827' MD / 3992' TVD;Take final survey= 1.36' above the line, 4.40' right. Pump Hi-Vis sweep w/ nut plug marker & circulate hole clean while BROOH f/ 7154’ t/ 6955'. 565 GPM, 2030 PSI, 80 RPM, 15K Tq, Sweep was not recognized at surface. Max Gas: 134u Treat mud while circulating with Final YP: 23;RIH on elevators f/ 6955’ t/ 7154’. Monitor well – Static.;BROOH f/ 7154' t/ 5515' at 5-10 min. stand, 500 GPM, 1450 PSI, 60 RPM, 15k TQ, slow down as needed to cleanup tight areas. 190k PU / 90k SO / 105k ROT, max gas 98u. Start seeing losses at 2.5 BPH;Continue BROOH f/ 5515' t/ 2642' at 5-10 min. stand, 500 GPM, 1290 psi, 60 RPM, 8k Tq, slow down as needed to cleanup tight areas. 190k PU / 90k SO / 105k ROT, max gas 98u. 2.5 BPH loss rate.;BROOH f/ 2642' t/ 832' at 5-10 min. stand, 500 GPM, 1260 psi, 60 RPM, 7k Tq, slow down as needed for any packing off or tight areas. Continue to Pull slow to permafrost at 2488’ for a bottoms up, no unloading observed. Max Gas: 128;Hole unloaded at 1550', slow to 150-380 GPM, cleaned up in 1430 strokes. Circulated 2x bottoms up while pulling f/ 832' t/ 736', no unloading observed. 38 bbls total loss BROOH;Performed 5 min. flow check - static. POOH on elevators racking back HWDP & jars f/ 736' t/ 177'. L/D XO, 3 NMDC & UBHO to 85'. Read MWD tools and continue laying down BHA t/ EWR-M5 Collar.;Daily Losses = 25 bbls, Cumulative Surface losses = 31 bbls H2O from L-Pad: 1,385 bbls Daily/ 4,970 bbls Total H2O from G&I Source Water: 0 bbls Daily / 0 bbls Total Cuttings/mud/cement to MPU G&I: 1,098 bbls Daily / 4,818 bbls Total 8/25/2020 L/D remaining BHA, 12 1/4'' bit grade = 1-1-ER-A-E-I-NO-TD, load out tools. Loss rate 3 bph;Clear rig floor, mobilize casing equipment to the rig floor. R/U 9-5/8" Volant CRT, spiders, bail extensions and elevators. PJSM for running casing. Monitor well-Static loss rate 3 bph;M/U and baker loc jt 9-5/8" shoe track, round nose float shoe, install top hat after M/U FC joint. Ensure proper float operation - good. M/U baffle adapter & joint #4 to 162'.;Torque all connections to 21,000 ft/lbs w/ Volant tool, Two 9-5/8"" x 12-1/4" centralizer & 4 stop rings on shoe joint, 1 free floating 9-5/8" x 12-1/4" bow spring centralizers on Baker-Loc joint 1 9-5/8" x 12-1/4" bow spring central w/ 2 stop rings on the float collar and baffle adapter joints.;Run 9-5/8" 40# L-80 TXP-BTC casing f/ 162' t/ 1292' @ jt 32. Torque to 21,000 ft/lbs w/ the Volant. Install 9-5/8" x 12-1/4" bow spring centralizers on jts #5-26 then every other joint. Fill casing on the fly & top off every 10 joints. 6-10 BPH loss rate;Continue to Run 9-5/8" 40# L-80 TXP-BTC casing f/ 1292' t/ 2605' @ jt 65. Torque to 21,000 ft/lbs w/ Volant. Install 9-5/8" x 12-1/4" bow spring centralizers on every other joint to 48, then 1 every 3rd jt, Fill casing on the fly & top off every 10 joints. 8-10 BPH loss rate;CBU f/ 2629' to 2645' staging pump to 6 bpm, 180 psi while working pipe down slow, 9-10 bph loss rate;Continue to Run 9-5/8" 40# L-80 TXP-BTC casing f/ 2645' t/ 4483' @ jt 112. Torque to 21,000 ft/lbs w/ Volant. Installing 1, 9-5/8" x 12-1/4" bow spring centralizer every 3rd jt, fill casing on the fly and top off every 10 jts;M/U ESC tool, pup jt w/ 9-5/8" x 12-1/4" bow spring centralizer above and below to 4520', verify 6 pins set @ 3300 psi. Baker-Loc connection at pup jts and first jt above.;Run 9-5/8" 47# L-80 TXP-BTC casing f/ 4520' t/ 7130' @ joint 177 (64 jts 47#). Tq to 24k ft/lbs with the Volant tool. M/U 20' pup, wash dn t/ 7146' Install 1 cent. each jt to 122 then every 3rd jt t/ #172 Fill casing on the fly & top off every 10 jts 116 bbl losses running casing PU 350k, SO 105k;Stage pump f/ 2 bpm, 490 psi, to 6 bpm, 360 psi. Start rotary w/ torque limit set at 20K, 5 RPM when reciprocating. Reciprocate 30', cementers rigging up. Condition mud to 17 YP for cement job. Circulated a total of 1.7x bottoms up. 300k PU / 125k SO 21 bbls loss while circulating.;R/U cement lines.C/O Volant cup. Pre-treat mud in pit #4. Continue circulating 6 BPM 240 psi. Spot all trucks into place and prep HES equipment.;PJSM. Pump 50 bbls of pre-treated mud, 6 BPM, 210 PSI. While HES batches up. Pump 5 bbls water. Pressure test lines to 1439 PSI low / 4148 PSI high. Bleed down and line up to well.;Daily Losses = 135 bbls, Cumulative Surface losses = 166 bbls H2O from L-Pad: 465 bbls Daily/ 5,435 bbls Total H2O from G&I Source Water: 400 bbls Daily / 400 bbls Total Cuttings/mud/cement to MPU G&I: 506 bbls Daily / 5,324 bbls Total 8/26/2020 1st stage. Mix and pump 58 bbl 10 ppg tuned spacer w/ 4# red dye & 5# Pol-E-Flake in 1st 10 bbls, 4.5 BPM, 300 psi. Drop Bypass bottom plug. Mix & Pump 265 bbl 12 ppg Extenda Cem Lead cmt (635 sx,), 5 BPM, 400 psi. Submit 24 hr BOP test notification Mix & Pump 82 bbl 15.8 ppg Premium G tail cmt (400 sx ) 4 BPM, 550 psi. Drop shutoff plug. Chase with 20 bbl fresh water. Rig displace with 302 bbl 9.5 ppg spud mud at 7 BPM, 220 psi. HES pump 80 bbl 9.4 ppg tuned spacer, 5 BPM, 200 psi. Displace 124 bbls w/ rig at 6 bpm, 550 psi 9.5 mud. 3080 stks Park w/ string in tension @ 7146', Seen polyflake at surface 311 bbls into displacing. Slow to 4 bpm on last 20 bbls, lift pressure 600 psi, FCP 740 psi. Bump plug @ 4217 strokes on calculated Pressure 500 psi over FCP @ 1250 psi, hold 5 min. Good. Bleed down, check floats- 1.9 bbls bled back, good. CIP @ 09:18 Pressure to 2850 psi shifting ESC open, Circulate hole clean through ES cementer at 2647' pumping 6 bpm, 1210 psi, 610 stks away spacer returns, 1300 stks away, very thick mud returns, slow to 1.5 bpm, 170 psi taking returns to rock washer, Total contaminated mud, interface and trace cement dumped to rock washer 350 bbls, then take clean mud to pits, pump total 2 BU after opening ESC. 76 bbl losses while cementing and displacing. Shut down pump, disconnect knife valve hyd line, drain stack and flush with black water, function annular, re-connect knife valve hyd. Continue to circ at 6 bpm, 700 psi while waiting on cmt and preparing for second stage. Hold PJSM with all parties involved. No losses while circulating. Break out volant, re-dope cup and clean dies, M/U same, Perform 2nd stage cement job, Pump 5 bbls fresh water. Mix & pump 55 bbls of 10 ppg Tuned Spacer at 4 BPM, 330 PSI (4# red dye & 5# Pol-E-Flake in 1st 10 bbls). Mix & pump 410 bbls of 10.7 ppg ArcticCem lead cement (780 sks, 2.944 ft^3/sk yield) at 5 BPM, 520 PSI. Mix & pump 60 bbls of 15.8 ppg Tail cement (288 sks, 1.169 ft^3/sk yield) at 4 BPM, 600 PSI. Drop closing plug. Pump 20 bbls fresh water at 7 BPM, 458 PSI. Displace w/ 9.4 ppg spud mud w/ rig pump at 6 BPM, 420 PSI ICP, Slow t/ 4 BPM final 10 bbls. 700 PSI FCP Bump plug at 1735 stks.(175 bbls) 11 stks over calc.. Pressure to 2000 psi, hold for 3 min. Good indication of ESC shift closed at 1950 psi. Bleed off pressure. 275 bbls Cmt to surface. CIP @ 19:48 Drain stack to the cellar. Disconnect knife valve accumulator lines. Function annular and flush w/ black water. Rig vac fluid out of casing to cellar level. Disconnect & begin N/D diverter line. Lay down 90’ mouse hole. Back out speed head LDS on diverter adapter, hoist stack. Install 9-5/8" casing slips and set with 100K on slips. Cut 9-5/8" casing (47# Jt 64 = 40.64' – 17.07' = 23.57' left in hole). Sim-ops: Rig up cellar trolly system, pull riser. Set stack down. N/D annular & diverter tee, remove from cellar. Sim-ops: clean pits, R/D and load out csg tools f/ Rig floor. Welder dress casing stump. Install and N/U FMC Gen5 SlipLock head & tubing spool Test void to 500psi – 5 min & 3800 psi – 10 min. Good test. Sim -Ops: Cont clean pits, Load out cement silos. N/U BOP stack. Daily Losses = 110 bbls, Cumulative Surface losses = 276 bbls H2O from L-Pad: 410 bbls Daily/ 5,845 bbls Total H2O from G&I Source Water: 620 bbls Daily / 1,020 bbls Total Cuttings/mud/cement to MPU G&I: 1,826 bbls Daily / 7,150 bbls Total 8/27/2020 Finish N/U BOPE, Install 90' mousehole. Finish cleaning pits. Install test plug,remove lower 3 1/2 x 6 VBR, install 2 7/8 x 5 VBRs PJSM, R/U BOP test equipment w/ 4 1/2'' test joint, flood stack and lines, perform BOP shell test to 250/3000 psi, good. L/D 4 1/2'' test jt, install 2 7/8'' test jt. Test BOP equipment to 250 PSI low / 3000 PSI high. Tests held for 5 min each & charted. AOGCC inspector A. McLeod on location to witness test. All tests performed with fresh water against a test plug. 1. Annular on 2 7/8" test joint, choke valves 1, 12, 13, 14, kill Demco & Lower IBOP 2. Lower 2 7/8'' x 5'' VBRs on 2 7/8'' test jt. Upper IBOP 3. Upper 4 1/2'' x 7'' VBRs on 4 1/2'' test jt. Choke valves 9, 11, HCR kill, 5'' dart valve #1 4. Lower 2 7/8'' x 5'' VBRs on 4 1/2'' test jt 5. Upper 4 1/2'' x 7'' VBRs on 5'' test jt. Choke valves 5, 8, 10. Manual kill valve, 5'' FOSV. 6. Choke valves 4, 6, 7, 5, FOSV 2 7. Choke valve 2, 3 1/2'' dart valve. 8. HCR Choke, 3 1/2'' FOSV. 9. Manual choke 10. Lower 2 7/8'' x 5'' VBRs on 5'' test jt. 11. Choke valve 3, blind rams 12. Super choke A 13. Manual choke B Test rig gas alarms. Perform Accumulator test: 3000 PSI sys pressure, 1700 PSI after closure, 200 PSI recovery in 38 sec, full recovery in 180 sec, 6 N2 bottle avg = 2091 PSI. 2-fail pass- hyd choke flange leaking, tighten and re-test, good, Rig gas alarm, loose power wire, tighten and re-test same, good. R/D test equipment, BD choke and lines. Pull test plug and Install 9'' ID wear bushing. Mobilize BHA components to rig floor. PJSM, P/U 8 1/2'' mill tooth bit, 1.5 deg mtr, run 2 stds 5'' HW, jar stand, 3 tds 5'' HW to 589'. TIH w/ 5" DP t/ 2493'. M/U top drive. Fill pipe and wash/ream down f/ 2493'. 320 GPM - 450 psi. 40 RPM - 4k Tq. Take 5k wt @ 2635' and tag up hard at 2640’. 110k PU, 73k SO, 86k ROT Drill cement, plug and ESC f/ 2640' to 2647', 450 GPM – 890 psi, 40 RPM – 5k Tq, 2-8K WOB. Ream 2 times down, pass thru w/ pumps off and no rotary, clean. Close upper pipe rams and PT casing t/ 1000 psi f/ 5 min. Good test. TIH w/ 5" drillpipe on elevators f/ 2681' t/ 4393'. Fill pipe and observe upper IBOP leaking at actuator stem. Grease valve, Troubleshoot and decision made change out both the upper and lower IBOPs RIH 1 std t/ 4488' while crew mobilize replacement valves to rig floor. Install FOSV & conduct PJSM. Change out Upper & Lower IBOPS. Rig up and pressure test valves to 250 psi / 3000 psi, 5 min each – charted. Rig down test equipment. TIH w/ 5" drillpipe on elevators f/ 4488' t/ 4963'. 175k P/U, 75k S/O H2O from L-Pad: 220 bbls Daily/ 6,065 bbls Total H2O from G&I Source Water: 620 bbls Daily / 1,020 bbls Total Cuttings/mud/cement to MPU G&I: 144 bbls Daily / 7,294 bbls Total 8/28/2020 TIH w/ 5" drillpipe on elevators f/ 4963' t/ 6966' just above the baffle adaptor, M/U TD;Circulate bottoms up 520 gpm, 1340 psi, 40 rpm, 18k torque, working pipe 60';PJSM, purge air from lines, Close UPRs, test 9 5/8'' to 2500 psi for 30 charted min, good test, bleed off pressure, Open UPRs. R/D test equip. 7 bbls pumped, 7 bbls bled back.;Wash down at 500 GPM - 1200 psi. Tag cement @ 7011' Drill 9-5/8"" shoe track w/ 500 GPM, 1250 PSI, 40 RPM, 17K TQ. Drill baffle adapter @ 7023’ w/ 5K WOB, Float collar @ 7064' w/ 5k. Drill shoe @ 7144’ w/ 5K WOB, then cleanout rathole to 7154'. All FE tagged on depth.;Reamed through baffle adapter, float collar and shoe 2x times each, pass through each with no rotary/pumps. Cement in shoe track drilled w/ 10k WOB;Drill 8-1/2"" production hole f/ 7154' t/ 7174', 500 GPM, 1460 PSI, 40 RPM, 18K TQ, 7-10K WOB. 210k PU 65k SO 115k ROT;Pump 30 bbl hi vis sweep around, pull into 9 5/8'' casing at 7125', circulate and condition 500 gpm, 1250 psi, 40 rpm, 17k torque, work pipe 30' until good 9.4 mw in/out. Sweep back on time w/ 10% increase, Max gas @ 110u Get new SPRs;R/U test equip, purge lines, close UPRs, perform FIT to 12 ppg EMW with existing 9.4 mud, apply 540 psi pumping down kill line and DP, chart same, good test, Bleed off pressure, open UPR. Monitor well, static;TOOH on elevators f/ 7125' to 6681', pump dry job, continue to TOOH to HW @ 589'. Hole took the calculated fill on TOH.;Monitor Well – Static. L/D excess HWDP, rack back jar stand, L/D motor and bit. Bit Grade = 1-1-NO-A-E-1-NO-BHA Clear and clean rig floor.;Clean flow line. Perform Derrick & Topdrive inspection. Install split master bushings and ready rig tongs & collar clamp.;PJSM. M/U 8-1/2" NOV SK616M-J1D bit, NBS, 7600 Geo-Pilot, MWD w/ ADR, ILS, DGR, PWD, DM & TM collars, 3-point string roller reamer and float sub to 91’. Test & initialize MWD tools. M/U 3 NMFCs & 2nd float sub t/ 183'. RIH w/ HWDP & jar stand to 276' Simops: Pressure test MPD lines to 250/ 1500 psi;M/U stand DP and TD, Pressure test Geo-Span to 2500 psi, shallow test MWD and lubricate RSS seals.;TIH to 6840' on stds 5” DP f/ Derrick. Fill pipe every 2000'. Single in hole t/ 7095’ with 5” DP f/ shed. Got the calculated displacement back while TIH 215k PU / 62k SO;PJSM, Remove trip nipple, install RCD bearing, no leaks.;H2O from L-Pad: 120 bbls Daily/ 6,185 bbls Total H2O from G&I Source Water: 620 bbls Daily / 1,020 bbls Total Cuttings/mud/cement to MPU G&I: 171 bbls Daily / 7,465 bbls Total 8/29/2020 RIH f/ 7129', exit shoe @ 7146', lost S/O wt @ 7155', wash and ream to bttm @ 7174', 225 gpm, 450 psi, 30 rpm, 20k tq. 215k PU, no S/O;Pump 30 bbl hi vis spacer then displace w/ 513 bbls new 8.8 ppg Flo-Pro mud w/ 1.5% screenkleen and .5% lube added, 345 gpm, 850 psi, 40 rpm, 19K TQ, w/ new mud out bit, finish displacing in casing f/ 7130' to 7100' working pipe 30'. Dump spud mud/interface to rock washer PU 160K, SO 90K, ROT 115K;PJSM, M/U FOSV, slip and cut 59' drilling line, re-calibrate block height, remove FOSV. SimOps: clean under shakers and pit 4 Monitor MPD for pressure build, none.;Get Parameters and new SPRs, wash to bttm;Drill 8-1/2" production hole f/ 7174' t/ 7793' (3994' TVD) 619' drilled, 88.4'/hr AROP. 550 GPM, 1910 PSI, 120 RPM, 12K TQ, 5-15K WOB. 8.9 ppg MW, 51 vis, 10.8 ECD, 201u max gas. 145K PU / 82K SO / 111K ROT.;Drilled into the NB_Clay f/ 7626' t/ 7798' (172') Holding 60 PSI on conn. w/ MPD, 60 PSI line restriction w/ choke open drilling. Drill in NB sand targeting 90- 91 deg.;Drill 8-1/2" lateral f/ 7793' t/ 8295' (3692’ TVD) 502' drilled , 83.66'/hr AROP 550 GPM, 2030 PSI, 120 RPM, 13k TQ, 15k WOB 9.0 ppg MW, 55 vis, 11.36 ECD, Max Gas 362u 140k PU / 80k SO / 107k ROT Pumped hi vis sweep at 7985', back on time with 10% increase Target 90-93° inc to maintain NB sand.;Drill 8-1/2” lateral f/ 8295' t/ 8915' (3946’ TVD) 620' drilled , 103.33'/hr AROP. 550 GPM, 1970 PSI, 120 RPM, 13k TQ, 5-15k WOB. 9.0 ppg MW, 50 vis, 11.00 ECD, Max Gas 476u. 140k PU / 80k SO / 105k ROT. Target 91.5-93° inc to maintain NB sand.;Last survey at 8676' MD / 3956.11' TVD, 90.88° inc, 191.93° azm, 2.38' from plan, 2.31' High and 0.56’ Left We have drilled 11 concretions for a total thickness of 50' (3% of the lateral).;Interval Daily (Midnight) Loss = 0 bbls, Cumulative losses = 0 bbls H2O from L-Pad: 290 bbls Daily/ 6,475 bbls Total H2O from G&I Source Water: 0 bbls Daily / 1,020 bbls Total Cuttings/mud/cement to MPU G&I: 979 bbls Daily / 8,444 bbls Total 8/30/2020 Drill 8-1/2” lateral f/ 8915' t/ 9411' (3926’ TVD) 496' drilled , 82.66'/hr AROP. 550 GPM, 1980 PSI, 120 RPM, 10k TQ, 7-15k WOB. 8.95 ppg MW, 44 vis, 10.79 ECD, Max Gas 455u. 140k PU / 78k SO / 106k ROT. Target 90-92.5° inc to maintain NB sand.;MPD holding 115 psi on connections, 65 psi line pressure drilling. Pump 30 bbl hi vis sweep @ 9030', back 100 stks late, 30% increase. Start dropping angle @ 9200' to look for higher quality pay.;Drill 8-1/2” lateral f/ 9411' t/10100' (3911’ TVD) 689' drilled , 114.83'/hr AROP. 550 GPM, 2240 PSI, 120 RPM, 14k TQ, 5-15k WOB. 9.1 ppg MW, 46 vis, 11.56 ECD, Max Gas 345u. 138k PU / 78k SO / 105k ROT.;Enter NB_Clay @ 9,654’, build to 93.5 deg to get back in sand Re-enter NB-Sand @ 9912', 258' drilling in clay below the NB_Sand Pumped 30 bbl hi vis sweep @ 9982'. Returned on time with 20% increase.;Drill 8-1/2” lateral f/ 10100' t/ 10789' (3946’ TVD) 689' drilled , 114.83'/hr AROP. 550 GPM, 2230 PSI, 120 RPM, 11k TQ, 5-15k WOB. 9.1 ppg MW, 45 vis, 11.31 ECD, max gas 482u. 145k PU / 72k SO / 110k ROT.;@ 10200’ drop angle t/ 90° looking for better pay in zone. Projected that wellbore close to the base of the NB_Sand @ 10600’, Increase trajectory to 94° searching for the top and effectively log full cross section of zone.;Drill 8-1/2” lateral f/ 10789' t/ 11455' (3874’ TVD) 666' drilled , 111'/hr AROP. 550 GPM, 2180 PSI, 120 RPM, 11k TQ, 5-15k WOB. 8.95 ppg MW, 52 vis, 11.22 ECD, max gas 427u. 150k PU / 63k SO / 104k ROT. MPD holding 180 psi on connections, 65 psi line pressure drilling.;Better quality sand observed @ 10850’. Drilled out the top of NB_Sand @ 10890’. Drop inc down to 90° and reacquire the NB_Sand at 11076’, 224’ drilled above the sand Pumped high vis sweep at 11124', back 200 stks late with 10% increase of cuttings. Perform 290 bbl whole mud dump & dilute @ 11124’;Last survey at 11339.23' MD / 3878.63' TVD, 91.13° inc, 191.84° azm, 6.98' from plan, 6.84' High and 1.37’ Right We have drilled 20 concretions for a total thickness of 80' (1.3% of the lateral).;Interval Daily (Midnight) Loss = 0 bbls, Cumulative losses = 0 bbls H2O from L-Pad: 1,250 bbls Daily/ 7,725 bbls Total H2O from G&I Source Water: 0 bbls Daily / 1,020 bbls Total Cuttings/mud/cement to MPU G&I: 1383 bbls Daily / 9,827 bbls Total 8/31/2020 Drill 8-1/2” lateral f/ 11455' t/ 11980' (3877’ TVD) 525' drilled , 87.5'/hr AROP. 550 GPM, 2270 PSI, 120 RPM, 12k TQ, 5-7k WOB. 8.95 ppg MW, 40 vis, 11.35 ECD, max gas 525u. 150k PU / 62k SO / 102k ROT. Drill in the NB sand targeting 89.5 deg;MPD holding 180 psi on connections, 65 psi line pressure drilling. Pump 30 bbl hi vis sweep @ 11989', back 300 stks late w/ 30% increase;Drill 8-1/2” lateral f/ 11980' t/12690' (3868’ TVD) 710' drilled , 118.33'/hr AROP. 550 GPM, 2360 PSI, 120 RPM, 14k TQ, 5-15k WOB. 8.95 ppg MW, 43 vis, 11.61 ECD, max gas 502u. 150k PU / 60k SO / 100k ROT. MPD holding 190 psi on connections, 65 psi line pressure drilling.;Perform 290 bbl whole mud dump and dilute @ 12266' Crossed fault 1 at 12197' with 6' throw DTN putting wellbore in the Clay below the NB_Sand, target 88 deg, Reacquired NB sand @ 12483'. Target 94 deg @ 12500'.;Drill 8-1/2” lateral f/ 12690' t/ 13172' (3877’ TVD) 482’ drilled , 80.33'/hr AROP. 500 GPM, 2160 PSI, 120 RPM, 15k TQ, 5-15k WOB. 9.0 ppg MW, 45 vis, 11.53 ECD, max gas 434u. 157k PU / 57k SO / 107k ROT. MPD holding 190 psi on connections, 65 psi line pressure drilling. Maintain the NB_Sand;Drill 8-1/2" lateral f/ 13172' t/ 13520' (3873' TVD) at TD in the NB-sand. 510 GPM, 2130 PSI, 120 RPM, 15k TQ, 5-15k WOB. 8.95 ppg MW, 45 vis, 11.43 ECD, 480u max gas. 175k PU / 57k SO / 107k ROT MPD holding 195 psi on connections, 65 psi line pressure drilling. Cont maintain the NB_Sand;Final survey places Wellbore 47.27' from plan at TD, 47.25' below & 1.29' right of plan 44 concretions were drilled for a total footage of 172’ (2.7%);Pump 30 bbl hi vis sweep, 550 gpm, 2400 psi, 110 rpm, 16k torque, Sweep back 600 stks late w/10% increase Continue circulating hole clean, 3 bottoms up pumped, rack std back each BU t/ 13340';Interval Daily (Midnight) Loss = 0 bbls, Cumulative losses = 0 bbls H2O from L-Pad: 1,310 bbls Daily/ 9,035 bbls Total H2O from G&I Source Water: 0 bbls Daily / 1,020 bbls Total Cuttings/mud/cement to MPU G&I: 2,404 bbls Daily / 12,231 bbls Total 9/1/2020 Continue circulating hole clean, 550 gpm, 2400 psi, 110 rpm, 16k torque, 4 BU total pumped, rack std back each BU t/ 13080' Ready pits;TIH to f/ 13080' to 13520'. M/U TD, no issues running.;Circulate 300 gpm, 1120 psi, 40 rpm, working pipe slow16k tq, Held PJSM for pumping SAPP treatment and displacing while W/O Vac truck to arrive back f/ G & I PU 165K, SO 55K, ROT 105;Ready pits, Pump SAPP pill treatment, 30 bbl hi vis spacer, 3- 20 bbl SAPP pills with 50 bbl seawater spacers, chase with 300 bbls seawater 7 bpm, 1090 psi, 40 rpm, 14-17k torque. Work string f/ 13520' to 13450';Pump 30 bbl hi vis spacer. Displace w/ 950 bbls 8.45 ppg, 3% lubed vissed brine 300 gpm, 900 PSI, Observe interface @ 14351 stls. Take lubricated brine back to pits @ 14846 stks, only 400 stks beyond calculated. Max gas 2036u 172K PU / 52K SO / 105K ROT w/ lubed brine;Monitor MPD for pressure build 3 times with the final building from 10 psi to 57 psi in 10 min. With 8.5 ppg brine and 57 psi = 8.7 ppg, with TM= 9 ppg KW brine;Continue to circulate 350 gpm, 900 psi, 30 rpm, 14k torque, perform PST, Brine going downhole = 3x 4.8 sec.Passing under shakers, 5.0, 4.9, 4.9 sec Possum belly returns failed;Record new parameters, SPRs for both mud pumps, service wash pipe.;BROOH pulling 5-10 min std f/ 13520' t/ 9507', 550 GPM, 1650 PSI, 110 RPM, 14K TQ, LD 5" DP utilizing the mousehole while BR. MPD holding 160 PSI on connections & 70 psi BR. ECD 10.6, max gas 218u. 165K PU / 75K SO / 114K ROT.;BROOH @ 5 min/std f/ 9507' t/ 7411', 550 GPM, 1550 PSI, 110 RPM, 11-12K TQ, LD 5" DP in the mousehole MPD holding 160 PSI on connections & 65 psi BR. ECD 10.46, max gas 310u Shakers running over f/ 9472' t/ 9110', pull slower & lower flow to 450 GPM 140K PU / 90K SO / 117K ROT 28.8 bbls losses BROOH;Daily losses = 48 bbls, Cumulative losses for lateral = 48 bbls H2O from L-Pad: 770 bbls Daily/ 9,805 bbls Total H2O from G&I Source Water: 0 bbls Daily / 1,020 bbls Total Cuttings/mud/cement to MPU G&I: 2,141 bbls Daily / 14,372 bbls Total 9/2/2020 BROOH @ 5 min/std f/ 7411' t/ 7346', 550 GPM, 1550 PSI, 110 RPM, 11-12K TQ, LD 5" DP in the mousehole, Pump out the last 200' pulling the BHA into the csg to 7119', note 25k overpull into the shoe. MPD holding 160 PSI on connections & 65 psi BR. ECD 10.4 32 bbl losses BROOH;Pump 30 bbl hi vis sweep around cleaning up the 9 5/8'' casing 550 gpm, 1500 psi, 50 rpm, 3-5k tq. CBU x2.5, sweep back on time w/ 30% increase. Perform passing PST with returns at possum belly, 5.2, 5.1 and 5.2 sec.;Monitor MPD for pressure for pressure build 4 times, with the final building from 10 psi to 30 psi in 10 min. With existing 9.2 brine wt, calculates to 9.4 ppg with trip margin.;Weight up mud pits f/ 9.2 ppg to 9.4 ppg then weight up on the fly, 9 bpm, 790 psi, 40 rpm, 4K TQ, with good 9.4 in/out shut down pumps. PU 135K, SO 95K, ROT 115K;Monitor well for 60 min, initially flowing 5 gpm, to no flow in 1 hr. PJSM, remove RCD, install trip nipple, no leaks. Record new SPRs;TOOH on elevators f/ 7129' to 6653', pump dry job, BD TD, Flush MPD lines with fresh water, continue TOOH L/D 5'' DP to 5733' Continue to separate joints DP for inspection.;Rig service, lube top drive and traveling blocks, lube draw works. service pipe skate.;Continue TOOH L/D 5'' DP f/ 5733' t/ 2655', 90K PU / 80K SO. Drop 2.45" OD drift on 100' of wire. Rack back 25 stands of 5" drill pipe f/ 2655' t/ 276'. Monitor well - slight losses. L/D BHA from 276'. Bit grade: 2-2-CT-N-X-I-NO-TD. Wear observed on In-Line Stab. 11.5 bbls losses for trip from shoe.;Clear rig floor & remove Sperry Geo-Span. Remove split bushings & install master bushings. Mobilize casing equipment to the rig floor.;R/U 4-1/2" casing equipment for screened liner. Doyon double stack tongs, 4-1/2" elevators & slips. M/U 4-1/2" H625 XO on FOSV. Load ODS pipe shed w/ 4-1/2" blank joints. Verify centralizer & stop ring count. PJSM for running liner. 1 BPH static loss rate.;M/U 4-1/2" solid eccentric bullnose shoe & solid shoe joint w/ two 7.25" O.D. centralizers & 4 stop rings to 43'. Run 4-1/2" 13.5# L-80 H625 screen liner completion as per tally f/ 43' t/ 3277'. Torque to 9600 ft/lbs w/ Doyon double stack tongs. Verified XO on FOSV M/U to joint #3.;Installed 4.5"x7.5" straight vane centralizer w/ stop ring on 16 solid joints, ran 44 RGL proMESH 250u screens w/ 7.5" OD centralizer & two stop rings per screen and ran 18 Petrogaurd 250u screens w/ 7.25" OD centralizer & two stop rings per screen to this depth. No losses running liner.;Daily losses = 21 bbls, Cumulative lateral losses = 69 bbls H2O from L-Pad: 310 bbls Daily/ 10,115 bbls Total H2O from G&I Source Water: 0 bbls Daily / 1,020 bbls Total Cuttings/mud/cement to MPU G&I: 342 bbls Daily / 14,714 bbls Total 9/3/2020 Run 4-1/2" 13.5# L-80 H625 screen liner completion as per tally f/ 3277' t/ 6505'. Torque to 9600 ft/lbs w/ Doyon double stack tongs. Installed 4.5"x7.5" straight vane centralizer w/ stop ring on solid joints.;Verify pipe count, 64 solid jts, with 62- 4.5"x7.5" centralizer w/ stop ring ran. 44 pro mesh screens w/ 7.5" OD centralizer & two stop rings per screen ran. 49 petrogaurd screens ran w/ 7.25" OD centralizer & two stop rings ran.;PJSM, C/O handling equipment to 5''. M/U Baker 7" x 9-5/8" SLZXP liner top packer assy to 6543' as per BOT rep, verify 9 pins w/ shear set @ 44100#, pusher tool 8 pins @ 2648 psi, M/U std DP and TD, pump 5 bbls at 3 bpm, 130 psi to ensure clear flow path.,;Set TD torque to 9600 ft/lbs, Record parameters, rotate 20 rpm, 5k torque. PU 113K, SO 86K;RIH with 4 1/2'' completion conveyed on 25 stands 5'' DP f/ 6638' to 8922', Record parameters before exiting shoe at 7146' Auto fill slow, fill on the fly and top off every 10 jts.;Continue to run 4 1/2'' completion at 50 fpm, single in the hole w/ 149 jts drifted 5'' HWDP & 1 5" drill pipe f/ 8922' to 13520'. Tag bottom w/ 8K. Fill on the fly and top every 10 jts. Correct displacement;Place liner in set position. Circulate a drill pipe volume at 4 BPM, 470 PSI ICP / 410 PSI FCP. Drop 29/32" phenolic ball & pump down w/ 24 bbl high vis sweep. Ball on seat @ 761 stks (41 stks early). Pressure up & set packer at 2660 PSI, continue to 3000 PSI & hold for 5 min.;S/O to 75K & verify set. Pressure up to 4240 PSI to release & shear. P/U to verify release, free travel at 220K. Close upper 4-1/2"x7" VBR on 5" drill pipe. Pressure up on annulus to 1650 PSI for 10 min on chart to test packer - good. Liner set @ 13520' / TOL @ 6989';P/U f/ 7019' out of pack-off t/ 7012'. L/D HWDP. Circualte @ 8 BPM, 830 PSI. Slowly P/U to 6979' & L/D 5" drill pipe single. Circulate casing clean @ 10 BPM, 1120 PSI, reciprocating f/ 6979' t/ 6937. Sweep back at 3250 stks w/ a moderate amount of sand & cleaned up @ 4550 stks, pumped a total 2x BU.;Pump 30 bbl high vis spacer & displace to clean 9.4 ppg 2% KCl/NaCl brine 7 BPM, 710 PSI ICP / 670 PSI FCP. Reciprocate pipe 60'. Spacer back at 4400 stks (4227 calc). Take returns to pits at 5050 stks. Circulated a total of 6000 stks. 9.4 ppg in / out. 215K PU / 165K SO.;Obtain slow pump rates. Perform 10 min. flow check - static. Blow down top drive & kill line. L/D single HWDP to 6948'.;Attempt to replace carriage roller on top drive carriage, will need to replace when out of the hole. Attempt to grease roller and get locked up roller to turn - unsuccessful. Grease top drive torque tube that roller contacts. 1 BPH losses.;POOH laying down 5" HWDP f/ 6948' t/ 3471'. 1 BPH losses.;Daily losses = 5 bbls (plus 321.9 bbls left behind liner), Cumulative lateral losses = 395.9 bbls H2O from L-Pad: 60 bbls Daily/ 10,175 bbls Total H2O from G&I Source Water: 0 bbls Daily / 1,020 bbls Total Cuttings/mud/cement to MPU G&I: 444 bbls Daily / 15,158 bbls Total Activity Date Ops Summary 9/4/2020 Continue POOH laying down 5" HWDP f/ 3471' t/ 2390 '. LD 5'' DP to surface, inspect and L/D running tool. 10 bbl losses TOOH Swap to completions AFE @ 06:00,Pull 9'' ID wear bushing, install test plug, PJSM, close blind ram, remove upper 4 1/2'' x 7'' VBRs and install 7 5/8'' rams. SimOps: C/O locked up carriage roller on TD. Monitor well @ annulus valve, 1 bph loss rate,Fill stack with water, PJSM, R/U test equipment and 7 5/8'' test joint, test 7 5/8'' ram to 250/3000 psi 5 min ea, chart test, good, R/D test equipment.,Drain stack, make 7 5/8'' hanger dummy run as per well head rep, 30.95' to LLDS,Clear the rig floor. R/U to run 7 5/8'' casing. C/O from 5'' to 7 5/8'' handling equipment, R/U power tongs, ready FOSV and XO. Hold PJSM.,P/U Baker bullet seal assy to 17'. Run 7-5/8" 29.7# L- 80 Hydril 521 liner as per tally. Torque to 10,100 ft/lbs with Doyon double stack tongs. No-go at 7000.79' w/ 5K, 38.42' in on joint #177. Observed 3K seal drag. Locator sub at 6991.18'. Close annular, pressure up to 400 PSI to verify seals - good. 7 bbls lost.,Space out: L/D joints #178, 177 & 176. M/U 2.62' pup joint and joint #176. M/U hanger & landing joint. Land 7-5/8" liner on hanger at 6999.51 (1.28' off no-go), observed 3K seal drag, 168K PU / 123K SO.,15 bbls daily losses, 410.9 bbls total losses for lateral H2O from L-Pad: 80 bbls Daily/ 10,255 bbls Total H2O from G&I Source Water: 0 bbls Daily / 1,020 bbls Total Cuttings/mud/cement to MPU G&I: 632 bbls Daily / 15,790 bbls Total 9/5/2020 R/U to reverse circulate, test lines.. Close annular. Pressure up on annulus to 300 psi and P/U until ports open and pressure dumps,PJSM- Pump and Spot Corrosion inhibited brine 91 bbl 9.4 PPG. Pump 46 bbl freeze protect diesel to 2300' while reversing circulating. Final circ pressure at 660 PSI @ 4 bpm. Strip through annular and close ports land hanger with 83k on hanger. 1.28' off no-go.,Bleed off back side and flow check. Both sides went static. Blow down surface lines to cuttings tank and pumps. Drain stack and blow down to cuttings tank. L/D 7 5/8'' landing joint, R/D floor circulating equipment. Change handling equipment to 5'',P/U 5'' joint and M/U pack off running tool and pack off. Run pack off as per weallhead rep with annulus open. RILDS, Test void to 500/5000 psi 5/10 min. each, good.,Test back side with diesel to 1000 PSI for 30 min. on chart - good. test. Bleed down. Blow down all lines from pump to cuttings box.,R/D and load out 7 5/8'' handling equipment, Load tools to rig floor, Monitor well, 1 bph loss rate.,R/U 2 7/8" handling equipment, PJSM Hang sheave in derrick, R/U ESP spooler unit, power up same, install ESP spool, pull cable over sheave, load pump and equipment into shed. ESP motor lead extension (MLE) damaged going over sheave.,Mobilize new MLE to rig. Centrilift splice new MLE on ESP cable. PJSM, P/U, assembly & service ESP assembly to 119'. Run one joint to 151' placing ESP in fluid. Check ESP cable - good. Installed 6 pump & 4 seal clamps, 1 seal, 1 motor & 3 pump protect-o-lizers. 1 BPH losses.,Run 2-7/8" L-80 6.5# EUE tubing f/ 151' t/ 1365'. Torque connections to 2250 ft/lbs with Doyon double stack tongs. Install Cannon clamps on 1st 10 joints then every other joint. Test ESP cable at 1000' - good.,Pin on Cannon clamp broke & air chisel marred joint #39. Remove broken pin & C/O joint #39.,Run 2-7/8" L-80 6.5# EUE tubing f/ 1365' t/ 3695'. Torque connections to 2250 ft/lbs with Doyon double stack tongs. Install cross coupler Cannon clamps on every other joint. Test ESP cable at 3000' - good. 3 bbls losses.,Daily losses: 11 bbls, Cumulative losses for lateral: 421.9 bbls H2O from L-Pad: 50 bbls Daily/ 10,305 bbls Total H2O from G&I Source Water: 0 bbls Daily / 1,020 bbls Total Cuttings/mud/cement to MPU G&I: 404 bbls Daily / 16,194 bbls Total 9/6/2020 Run 2-7/8" L-80 6.5# EUE tubing as per tally f/ 3695' t/ 5901'. Torque connections to 2250 ft/lbs with Doyon double stack tongs, Install cross coupler Cannon clamps on every other joint. Test ESP cable every 2000', - good. 6 bbls losses running tbg. Clean in pits.,M/U 2 7/8"x 11" tubing hanger and 2 7/8" landing joint.,Attempt to M/U penetrator, penetrator threads not M/U, lower coupling nut would only M/U 2 threads, Centrilift locating another penetrator, still would not M/U, get another hanger and C/O same. Install penetrator, good,Terminate ESP cable. Take final readings, M/U ESP umbilical cord, Drain BOP Stack & blow down surface lines. Land 2 7/8" tubing on hanger at 5934', RILDS, L/D landing joint, install BPV 181 joints tubing, 109 cannon clamps, 5 protectolizer clamps, 4 seal clamps and 6 pump clamps ran. 75K PU / 60K SO, 25K on hanger,PJSM, N/D BOPs, R/D ESP running equipment, R/D cable, sheave and spooling unit. Continue cleaning in pits,,PJSM. N/D trip nipple, kill line & MPD lines. Hoist stack, N/D MPD head & set stack on stump. Remove MPD head. Set stack back on wellhead. Sim-ops: Continue cleaning pits and clear rig floor of subs & equipment.,Remove UPR, LPR and blind rams from BOP cavities. Service break annular cap w/ potatoe masher. Sim-ops: Continue cleaning pits and clear rig floor of subs & equipment. Build 200 bbls Deep Clean pill in pit #5. Flush all pits, suction, hopper & gun lines, mud pumps & top drive w/ Deep Clean.,N/U adapter flange. Install test dart in BPV. N/U 2-9/16" Cameron 5K tree. Sim-ops: Finish flushing pits with Deep Clean. Flush choke, de-gasser and injection line.,Daily losses = 6 bbls, Cumulative lateral losses = 427.9 bbls H2O from L-Pad: 115 bbls Daily/ 10,420 bbls Total H2O from G&I Source Water: 290 bbls Daily / 1,310 bbls Total Cuttings/mud/cement to MPU G&I: 290 bbls Daily / 16,484 bbls Total 50-029-23685-00-00API #: Well Name: Field: County/State: MP L-62 Milne Point Hilcorp Energy Company Composite Report , Alaska 8/20/2020Spud Date: 9/7/2020 Wellhead rep test hanger void to 500/5000 psi 5/10 minutes each, R/U and test the tree with diesel to 250/5000 psi 5 minutes ea. R/D test equip. Pull BPV dart. Centrilift took final readings, Pi= 1789.3 psi, Pd= 1785.10, Ti= 76.6, Tm= 79.6, Vx= 0.007, Vz= 0.007, Vt= 120.9, Ma= 9.9 Flush choke, degasser and injection line. clean cellar box.,Install 4 1/16'' annulus valve. Clean the cellar box and tree. Welder cut off and cap mouse hole in cellar box, clean in the pits. R/D and move fuel trailer, remove lower torque ring on top drive. Lubricate derrick pins, clean and prep rock washer. Place rig mats at maintenance stage area.,Install gauges on the tree, secure the well and cellar, BD lines and R/D floor equipment PJSM, Skid the rig floor into move position. Perform the final clean in the pits and trip tank. Move the rock washer.,PJSM, jack up rig, move off well, move to rig maintenance stage area on far end of L- Pad, Remove mats from around L-62 Release rig at 18:00,Swap to rig maintenance AFE at 18:00 TD Shoe Depth: PBTD: No. Jts. Returned RKB RKB to BHF RKB to THF Jts. 1 2 1 1 1 109 1 1 1 63 1 X Yes No X Yes No Fluid Description: Liner hanger Info (Make/Model): Liner top Packer?: Yes No Liner hanger test pressure:X Yes No Centralizer Placement: Preflush (Spacer) Type: Density (ppg) Volume pumped (BBLs) Lead Slurry Type:Sacks: Yield: Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Tail Slurry Type:Sacks: Yield: Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Post Flush (Spacer) Type: Density (ppg) Rate (bpm): Volume: Displacement: Type: Density (ppg) Rate (bpm): Volume (actual / calculated): FCP (psi): Pump used for disp:X Yes No Casing Rotated?X Yes No Reciprocated?X Yes No % Returns during job Cement returns to surface?X Yes No Spacer returns?X Yes No Vol to Surf: Cement In Place At: Date: Estimated TOC: Method Used To Determine TOC: Preflush (Spacer) Type: Density (ppg) Volume pumped (BBLs) Lead Slurry Type:Sacks: Yield: Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Tail Slurry Type:Sacks: Yield: Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Post Flush (Spacer) Type: Density (ppg) Rate (bpm): Volume: Displacement: Type: Density (ppg) Rate (bpm): Volume (actual / calculated): FCP (psi): Pump used for disp:X Yes No Casing Rotated? Yes X No Reciprocated? Yes X No % Returns during job Cement returns to surface?X Yes No Spacer returns? Yes X No Vol to Surf: Cement In Place At: Date: Estimated TOC: Method Used To Determine TOC: Post Job Calculations: Calculated Cmt Vol @ 0% excess: Total Volume cmt Pumped: Cmt returned to surface: Calculated cement left in wellbore: OH volume Calculated: OH volume actual: Actual % Washout: 1.17 8/26/2020 34 Spud Mud Extenda Cem Lead 635 2.35 Premium G Tail 400 1.16 5.6 2,625.47 Casing 9 5/8 47.0 L-80 TXP BTC-SR Tenaris 2,569.71 2,625.47 55.76 2,647.89 2,645.06 Pup Joint 9 5/8 40.0 L-80 TXP BTC-SR Tenaris 19.59 2,645.06 14.60 2,662.49 2,647.89 ES II Cementer 10 3/4 TXP BTC-SR HES 2.83 Pup Joint 9 5/8 40.0 L-80 TXP BTC-SR Tenaris 7,023.20 Casing 9 5/8 40.0 L-80 TXP BTC-SR Tenaris 4,360.71 7,023.20 2,662.49 7,064.75 7,024.61 Baffle Adapter 10 3/4 TXP BTC-SR HES 1.41 7,024.61 1.33 7,066.08 7,064.75 Casing 9 5/8 40.0 L-80 TXP BTC-SR Tenaris 40.14 Float Collar 10 3/4 TXP BTC-SR Innovex 104 total 9-5/8"x12-1/4" bowspring centralizers ran. 2 on joint #1 with 4 stop rings. 1 free floating on joint #2. 1 each mid-joint on #3&4 wit 4 stop rings. 1 each free floating on joints #5 to 26. 1 each free floating every other joint #28 to 50. 1 each free floating every third joint #51 to 105. 1 each free floating on joint #108 to 112. 1 each on pup joint above and below ES cementer w/ 2 stop rings. 1 each free floating on joint #113 to 122. 1 each free floating every other joint #124 to 172 Casing 9 5/8 40.0 L-80 TXP BTC-SR Tenaris 78.32 7,144.40 7,066.08 www.wellez.net WellEz Information Management LLC ver_04818br 4 Ftg. Returned Ftg. Cut Jt. Ftg. Balance No. Jts. Delivered No. Jts. Run Length Measurements W/O Threads Ftg. Delivered Ftg. Run 33.31 RKB to CHF Type of Shoe:Innovex Casing Crew:Doyon 12 265 ESC II Closure OK 60 ArcticCem Type Premium G 288 Tuned Spacer 780 2.94 Stage Collar @ 55 Bump press 100 275 7,146.007,154.00 CEMENTING REPORT Csg Wt. On Slips:100,000 Spud Mud 9:18 8/26/2020 2,646 2645 15.8 82 Bump press Returns to surface Bump Plug? Y 4 9.4 6 175/174 426/426 1250 1 RigFIRST STAGE10Tuned Spacer 60 15.8 700 9.6 7 2000 10 10.7 410 5 92 720 Bump Plug? Csg Wt. On Hook:350,000 Type Float Collar:Innovex No. Hrs to Run:17.5 9 5/8 47.0 L-80 TXP BTC-SR Tenaris TXP BTC-SR Innovex 1.60 7,146.00 7,144.40 23.57 55.76 32.19 Setting Depths Component Size Wt. Grade THD Make Length Bottom Top Hilcorp Energy Company CASING & CEMENTING REPORT Lease & Well No.MP L-62 Date Run 25-Aug-20 CASING RECORD County State Alaska Supv.S. Sunderland / J. Vanderpool 7,065.00 Floats Held 428.5 817 276 542 Spud Mud Rotate Csg Recip Csg Ft. Min. PPG9.4 Shoe @ 7146 FC @ Top of Liner SECOND STAGERig 19:48 Returns to surface 391.5 500.1 27.7 Casing (Or Liner) Detail Shoe Cut Joint of Casing 10 3/4 Returns to surface Returns to surface ! "#$ %&$'% () ) #! ) *+ ) ) ,) ,) -!)!! 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"#$%&'() .) )*+,- * ) "#$%&'() /- ) . , 5 7 : 567 ; 567 324#, 5 7 3/4# 5 7 *+ 5 7 *+ 5 7 /-. 57 2. 57 + 57 564<=7 */ ( 998' % %('/) )%0'(% 8 %(') 8 &8)'8 ) %' /8 &8'0) & 9 ()%'8( %( 8&)'/ '/( 9 '/& 8>.-5< -- 71 4 ( /00'/) %%'%& )%9'() 8 8&9')( 8 )&8'8 ) %('%&8 %0'08 & 9 8(8'(/ %( 88)'% )'&( 0('( 8>.-5< -- 71 4 % &08'( %%')% )%9'9/ 8 8 '%& 8 )0'%( ) 98'))8 8) '&/ & 9 0&'(9 %( 8&') &'%% 9))'8 8>.-5< -- 71 4 % )9' 9 %%'0% )%9'9 8 ()' 0 8 (/'89 ) 8))' 98 8%'9 & 9 )/0'9 %( 89/' &'( 90'80 8>.-5< -- 71 4 % ('9( %')) )%/'(& 8 (0&'8 8 8 (')) ) 88/'9&8 ()/'/% & 9 ) 8' 9 %( ()9')/ &' /( '9/ 8>.-5< -- 71 4 % 8%/'8 %0'& )&')& 8 % '% 8 8/9'8( ) 80')98 (0 ')% & 9 &(/' %( (('& )')9 8 &&/')0 8>.-5< -- 71 4 % (%('/% )'8) ))')0 8 %0)'89 8 (0%'% ) 8/('8&8 % &'/0 & 0 /0 ')9 %( (08') ('% 8 &09'( 8>.-5< -- 71 4 % %(/' 8' )8'& 8 )%'() 8 %%%'8& ) ( &'&%8 %%'&& & 0 9/ '& %( (//'9( '/ 8 )%&'(( 8>.-5< -- 71 4 % (%'(9 ('(/ )'(8 8 %0'8 8 89'8) ) (( '0)8 &0' & 0 9&/'08 %( % 8'&& 8'(( 8 '8( 8>.-5< -- 71 4 % 0(&'/& 0'/) )0&'% 8 /')% 8 0 8'9% ) (&'&)8 (%'0( & 0 0 ('8) %( %(&'9) %'(& 8 8&%'99 8>.-5< -- 71 4 % 98('0( 9'&/ )0)'9& 8 08)'8& 8 9&/'98 ) (08' 98 9&'9/ & 0 89'( %( %%('& )')% 8 89'0 8>.-5< -- 71 4 % /8&' / 0'/( )0 ') 8 00'&0 8 9/0'%0 ) (9%'08 0)' & 0 %%&'00 %( %0'% &'8% 8 (/'%( 8>.-5< -- 71 4 & %'%( 9')& )0&'/( 8 9& '0 8 /9('/8 ) (/9'98 0% '8) & 0 (8'%& %( %9)'& )') 8 %%)'9 8>.-5< -- 71 4 ) &'(9 0'9 )08'/ 8 989'88 ( &0 ') ) %)&' %8 090'/ & 0 80'8( %( %/8')% '/ 8 8('8& 8>.-5< -- 71 4 )'9% /'9( )00'8/ 8 908')) ( ))'00 ) %)0'&)8 9 '0& & 0 9'0/ %( &&'(% 8'/& 8 0 &') 8>.-5< -- 71 4 8))'/ 0('8) )0/' % 8 /& ' / ( %)'/( ) %)/'88 9%)'99 & 0 )/'% %( &8'8 %'&0 8 9&0'(/ 8>.-5< -- 71 4 (&')% 00'8& )9)'9& 8 / %'(% ( 8(8'(/ ) %)9'098 90%'&( & 0 )&%')& %( &8'88 (')) 8 9/'/( 8>.-5< -- 71 4 %&)'% 09'% )9(' 8 /(%'88 ( (8') ) %)8'% 8 9/('/ & 0 &))'/ %( %/9'8 8' 8 /99'9/ 8>.-5< -- 71 4 %/0'90 9&'00 )90'(% 8 / '%( ( %8&'9 ) %&8'%)8 /) ')8 & /)0' %( %9/' & 8'& ( &98'&) 8>.-5< -- 71 4 / '0 9)'%% )9/'/9 8 /00')) ( 8'(% ) (9/'8 8 / '0& & 9 %'&& %( %0%'%0 '0 ( )0'(8 8>.-5< -- 71 4 099'80 9('/ )/('&8 8 /99'%9 ( 0)'8( ) (/'%%8 /89')0 & 08)'// %( %%'80 %'88 ( 0)'(& 8>.-5< -- 71 4 998'// 9%'% )/(' / 8 //'0( ( 9&9'0 ) ((' %8 /('88 & 8/'(9 %( %88'8 &'/) ( 8'( 8>.-5< -- 71 4 /0/'8% 9/'/ )/8'9& ( &&&'0 ( /&)')8 ) ( 8')88 /%&'8) & %('/% %( %))'&0 ('(& ( ()'99 8>.-5< -- 71 4 0 &0(') /&'(% )/8') ( &&&') ( //8' ( ) (&&'08 /%&' & & (%('0) %( (9/')0 &'98 ( %%'9 8>.-5< -- 71 4 0 )%'%( /8'09 )/('8% 8 //0' 8 % &9)'9( ) 809')8 /('9 & 8%'// %( (0'% 8'08 ( (0'/ 8>.-5< -- 7184 0 (0'0( / ' 8 )/8'( 8 // '/ % ))'% ) 8%9'998 /( '%) & 9' & %( ((9'() ')0 ( 08&'&8 8>.-5< -- 7184 0 8( '9 /&'/ )/8' 8 //&'%& % %8'/ ) 88'88 /(&'&/ & )/8'0 %( ( '0 )'8 ( 9 %'&0 8>.-5< -- 7184 0 (89'(8 /&'&) )/)'89 8 /9/'/ % 8(0' ) 8)%'/(8 /8/'%) & )&&' %( (&'& '(% ( / &'0 8>.-5< -- 7184 0 %88'09 9/'&/ )/&' ) 8 //&'0 % ((&'/) ) /9'&98 /(&' & &&'(0 %( 89/'8) )'% % &)%'/ 8>.-5< -- 7184 0 /') 9/'&/ )/)')9 8 // ')9 % %8('%9 ) 9&'8/8 /()'00 & % /) '0& %( 80 ')/ )'& % )))' 8>.-5< -- 7184 0 0 8'% /)'9 )/8'(8 8 //)'%% % '/8 ) &' %8 /()')( & % 9 &' ( %( 8% ') 8'8 % &%'08 8>.-5< -- 7184 0 9)/'(8 /8')& )/8'/9 8 /90'%% % 0)/'/& ) 80'%98 /80')( & % 0 0')% %( 88&'%& )'%/ % 8&)'() 8>.-5< -- 7184 0 /)('90 / '/) )/('% 8 /9 '%% % 9) ' % ) )('&)8 /8 ')( & % 8('0 %( 8&0'%& &'08 % 8/'/ 8>.-5< -- 7184 9 &)&'&9 / '0/ )/8'%0 8 /00'9) % /&('(0 ) )/&'988 / 0'(& & % %( '8 %( 9('99 )')( % (/)'0% 8>.-5< -- 7184 9 )&%')8 /8')& )/ '9( 8 /0 '/8 % //'99 ) )/')%8 / '% & % ((/'09 %( 8'0 &'98 % %9'9 8>.-5< -- 7184 9 &&'0) / '/9 )/ ' 8 /0'9 &9/'/0 ) )(9'&98 /)0'(% & % 8%'%0 %( (8' &' 8 % 9 ') 8>.-5< -- 7184 9 /%'8& /)')9 )/)') 8 /('(8 )9 '89 ) ) 9' )8 /)('& & % ('&% %( 8'/% ' & % 00'( 8>.-5< -- 7184 9 8/&'& / '8& )/ '%& 8 /)'%( 0%'%( ) )&9'8 8 /))')8 & % )0&'0/ %( &('8 )'%& % 90)'99 8>.-5< -- 7184 9 (9%'9 /)')9 )/)') 8 /%9'% 89'(0 ) &99'(08 /&9' ( & % &00'0( %( )9%'8% )'%& % /'/& 8>.-5< -- 7184 9 %9)'&) /&'%) )/ '&/ 8 /%0' ( ()'0 ) &9'/&8 /&'98 & ( /9('8% %( )'8( &'9 & ' ) 8>.-5< -- 7184 () ) #! ) *+ ) ) ,) ,) -!)!! 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enjamin Hand Digitally signed by Benjamin Hand Date: 2020.09.03 10:50:01 -08'00'Chelsea Wright Digitally signed by Chelsea Wright Date: 2020.09.04 07:38:35 -08'00' STATE OF ALASKA Reviewed By: J155r� OIL AND GAS CONSERVATION COMMISSION P.I. Supry 7Lit BOPE Test Report for: MILNE PT UNIT L-62 Comm Contractor/Rig No.: Doyon 14 PTDth 2200590 DATE: 8/27/2020 Inspector Austin McLeod Insp Source Operator: Hilcorp Alaska, LLC Operator Rep: Yessak/Vanderpool Rig Rep: Hansen/Carlo Inspector Type Operation: DRILL Sundry No: Test Pressures: Inspection No: bopSAM200828064422 Rams: Annular: Valves: MASP: Type Test: INIT 250/3000 250/3000 250/3000 1358 Related Insp No: TEST DATA MISC. INSPECTIONS: MUD SYSTEM: ACCUMULATOR SYSTEM: P/F Visual Alarm Time/Pressure P/F Location Gen.: - P __ Trip Tank P P - System Pressure 3100 P_ _- Housekeeping: P Pit Level Indicators P P Pressure After Closure 1700 P PTD On Location P Flow Indicator P P 200 PSI Attained 38 P ' Standing Order Posted P _ " Meth Gas Detector P FP Full Pressure Attained 180 P Well Sign P H2S Gas Detector P P Blind Switch Covers: All stations P Drl. Rig P MS Misc N_ A N_ _A Nitgn. Bottles (avg): _ 6(ai2091_ " P Hazard Sec. P ACC Misc 0 NA Misc NA FLOOR SAFTY VALVES: BOP STACK: CHOKE MANIFOLD: Quantity P/F Quantity Size P/F Quantity P/F Upper Kelly 1— - P - Stripper 0 NA No. Valves 14 P, Lower Kelly 1 _ _ P- Annular Preventer 1 13-5/8" — P - Manual Chokes 1 P, Ball Type - 3 -_- P--' #1 Rams l 4-1/2"x7" P_ Hydraulic Chokes 1 P " — Inside BOP 2 P 42 Rams I- Blinds P CH Misc 1 FP FSV Misc 0 NA #3 Rams I' 2-7/8"x5" ' P " #4 Rams 0 NA #5 Rams 0 - NA INSIDE REEL VALVES: #6 Rams 0 NA (Valid for Coil Rigs Only) Choke Ln. Valves I. 3-1/8" P - Quantity P/F HCR Valves 2 ' 3-1/8" P Inside Reel Valves 0 NA Kill Line Valves 2 '3-1/8" P Check Valve 0 NA BOP Misc 0 NA Number of Failures: 2 Test Results Test Time 6.5 Remarks: 2-7/8", 4-1/2" & 5" joints. 2-7/8" on annular. 4-1/2" & 5" on top vbes, all three joints on lower vbr's. Loose power wire is methane audible FP. Fixed and passed retest. CH misc is the lower flange on superchoke leaking while testing choke manifold valves. Tightened -passed. 1 Guhl, Meredith D (CED) From:Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Sent:Tuesday, October 13, 2020 1:59 PM To:Guhl, Meredith D (CED) Subject:RE: [EXTERNAL] MPU L-62 PTD 220-059, Permafrost base? Meredith, Sorry about that! Base of Permafrost: MD = 2489’ / TVD = 1947’ Thanks! Thanks, Joe Lastufka Sr. Drilling Technologist Hilcorp North Slope, LLC Office: (907)777-8400, Cell:(907)227-8496 From: Guhl, Meredith D (CED) <meredith.guhl@alaska.gov> Sent: Tuesday, October 13, 2020 1:40 PM To: Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Subject: [EXTERNAL] MPU L‐62 PTD 220‐059, Permafrost base? Hi Joe, For MPU L‐62, box 20 Thickness of Permafrost and box 29 Geologic markers Base of permafrost, no values are listed. Can you please provide so the 10‐407 form is complete? I will update form and attach your email, no need to resend form. Thank you, Meredith Meredith Guhl Petroleum Geology Assistant Alaska Oil and Gas Conservation Commission 333 W. 7th Ave, Anchorage, AK 99501 meredith.guhl@alaska.gov Direct: (907) 793‐1235 CONFIDENTIALITY NOTICE: This e‐mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e‐mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Meredith Guhl at 907‐793‐1235 or meredith.guhl@alaska.gov. 2 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 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 L-62 Hilcorp Alaska, LLC Permit to Drill Number: 220-059 Surface Location: 2031’ FNL, 457’ FWL, Sec. 8, T13N, R10E, UM, AK Bottomhole Location: 2347’ FNL, 346’ FWL, Sec. 20, T13N, R10E, UM, AK Dear Mr. Myers: Enclosed is the approved application for the permit to drill the above referenced development 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 July, 2020. y, i 17 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: 13,691' TVD: 3,820' 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): 50.2 15. Distance to Nearest Well Open Surface: x-5545058 y- 6031439 Zone-4 16.5 to Same Pool: 1520'' to MPU L-60 16. Deviated wells:Kickoff depth: 300 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 92 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD Conductor 20" 81# A-53 Weld 114' Surface Surface 114' 114' 9-5/8" 47# L-80 TXP 2,000' Surface Surface 2,000' 1,670' 9-5/8" 40# L-80 TXP 4868' 2,000' 1,670' 6,868' 3,990' 8-1/2" 4-1/2" 13.5# L-80 Hydril 625 6,973' 6,718' 3,978' 13,691' 3,820' Tieback 7-5/8" 29.7# L-80 Hydril 521 6,718' Surface Surface 6,718' 3,978' 19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Junk (measured): TVD Hydraulic Fracture planned?Yes No 20. Attachments:Property Plat BOP Sketch Drilling Program Time v. Depth Plot Shallow Hazard Analysis Diverter Sketch Seabed Report Drilling Fluid Program 20 AAC 25.050 requirements Contact Name: Contact Email: Contact Phone: Date: Permit to Drill API Number: Permit Approval Number:50- Date: Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales: Samples req'd: Yes No Mud log req'd: Yes No H2S measures: Yes No Directional svy req'd: Yes No Spacing exception req'd: Yes No Inclination-only svy req'd: Yes No Post initial injection MIT req'd: Yes No APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Sr Pet Eng Sr Pet Geo Sr Res Eng 12-1/4" 6046' to nearest unit boundary 6/10/2020 Authorized Name: Monty Myers Authorized Title: Drilling Manager Nathan Sperry nathan.sperry@hilcorp.com 301-8996 18. Casing Program:Top - Setting Depth - BottomSpecifications MPU L-62 Milne Point Field Schrader Bluff Oil Pool 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 Hilcorp Alaska, LLC 2031' FNL, 457' FWL, Sec 8, T13N, R10E, UM, AK ADL025509 / ADL025515 022224484 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 Stg 2 L - 1937 ft3 / T - 313 ft3 1358 1557' FNL, 1858' FWL, Sec. 17, T13N, R10E, UM, AK 2347' FNL, 346' FWL, Sec. 20, T13N, R10E, UM AK LONS 88-002 5077 1758 Total Depth MD (ft):Total Depth TVD (ft): Cement Quantity, c.f. or sacks Cement Volume MDSize Plugs (measured): (including stage data) ~270 ft3 Stg 1 L - 1371 ft3 / T - 458 ft3 Effect. Depth TVD (ft): Conductor/Structural Cementless Screen Liner Tieback Assy. Casing Intermediate Length Authorized Signature: Surface Production Liner See cover letter for other requirements. Perforation Depth MD (ft): 21. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Perforation Depth TVD (ft): Commission Use Only GL / BF Elevation above MSL (ft): Effect. Depth MD (ft): es N ype of W L l R L 1b S Class: os N es No s N o D s s s D 84 o : well is p G S S 20 S S S es No s No S G E S es No s Form 10-401 Revised 3/2020 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g) 7.14.2020 By Samantha Carlisle at 1:32 pm, Jul 14, 2020 Digitally signed by Monty M Myers DN: cn=Monty M Myers, c=US, o=Hilcorp Alaska, LLC, ou=Technical Services - AK Drilling, email=mmyers@hilcorp.com Reason: I am approving this document Date: 2020.07.14 10:24:57 -08'00' Monty M Myers 029-23685-00-00 X DLB 07/15/2020 220-059 Per Hilcorp X 08/15/2020 X X X X X DLB MGR15JUL2020 BOPE test to 3000 psi. Annular to 2500 psi. DSR-7/14/2020GR11111115JUL2020 7/17/2020 7/17/2020 Milne Point Unit (MPU) L-62 Drilling Program Version 1 7/13/2020 Table of Contents 1.0 Well Summary ................................................................................................................................. 2 2.0 Management of Change Information ............................................................................................ 3 3.0 Tubular Program: ........................................................................................................................... 4 4.0 Drill Pipe Information: ................................................................................................................... 4 5.0 Internal Reporting Requirements ................................................................................................. 5 6.0 Planned Wellbore Schematic ......................................................................................................... 6 7.0 Drilling / Completion Summary .................................................................................................... 7 8.0 Mandatory Regulatory Compliance / Notifications ..................................................................... 8 9.0 RU and Preparatory Work .......................................................................................................... 10 10.0 NU 21-1/4” 2M Diverter System .................................................................................................. 11 11.0 Drill 12-1/4” Hole Section ............................................................................................................. 13 12.0 Run 9-5/8” Surface Casing ........................................................................................................... 16 13.0 Cement 9-5/8” Surface Casing ..................................................................................................... 22 14.0 ND Diverter, NU BOPE, & Test .................................................................................................. 26 15.0 Drill 8-1/2” Hole Section ............................................................................................................... 27 16.0 Run 4-1/2” Screen Liner ............................................................................................................... 32 17.0 Run 7” Tieback ............................................................................................................................. 36 18.0 Run Upper Completion ................................................................................................................ 39 19.0 Doyon 14 Diverter Schematic ...................................................................................................... 41 20.0 Doyon 14 BOP Schematic ............................................................................................................. 42 21.0 Wellhead Schematic ...................................................................................................................... 43 22.0 Days Vs Depth ............................................................................................................................... 44 23.0 Formation Tops & Information ................................................................................................... 45 24.0 Anticipated Drilling Hazards ....................................................................................................... 46 25.0 Doyon 14 Layout ........................................................................................................................... 48 26.0 FIT Procedure ............................................................................................................................... 51 27.0 Doyon 14 Choke Manifold Schematic ......................................................................................... 52 28.0 Casing Design ................................................................................................................................ 53 29.0 8-1/2” Hole Section MASP ........................................................................................................... 54 30.0 Spider Plot (NAD 27) (Governmental Sections) ......................................................................... 55 31.0 Surface Plat (As Staked) (NAD 27) ............................................................................................. 56 32.0 Schrader Bluff Nb Sand Offset MW vs TVD Chart .................................................................. 57 Page 2 Milne Point Unit L-62 SB Producer Drilling Procedure 1.0 Well Summary Well MPU L-62 Pad Milne Point “L” Pad Planned Completion Type ESP on 3-1/2 tubing Target Reservoir(s) Schrader Bluff NB Sand Planned Well TD, MD / TVD 13,691’ MD / 3,820’ TVD PBTD, MD / TVD 13,689’ MD / 3,820’ TVD Surface Location (Governmental) 2031' FNL, 457' FWL, Sec 8, T13N, R10E, UM, AK Surface Location (NAD 27) X= 545058, Y= 6031439 Top of Productive Horizon (Governmental) 1557' FNL, 1858' FWL, Sec 17, T13N, R10E, UM, AK TPH Location (NAD 27) X= 546505 Y= 6026642 BHL (Governmental) 2347' FSL, 346' FWL, Sec 20, T13N, R10E, UM, AK BHL (NAD 27) X= 545057, Y= 6019979 AFE Number 2011922 AFE Drilling Days 18 AFE Completion Days 4 AFE Drilling Amount $3,306,774 AFE Completion Amount $2,515,326 AFE Facility Amount $363,930 Maximum Anticipated Pressure (Surface) 1,358 psig Maximum Anticipated Pressure (Downhole/Reservoir) 1,758 psig Work String 5” 19.5# S-135 NC 50 D14 KB Elevation above MSL: 33.7 ft + 16.5 ft = 50.2 ft GL Elevation above MSL: 16.5 ft BOP Equipment 13-5/8” x 5M Annular, (3) ea 13-5/8” x 5M Rams Page 3 Milne Point Unit L-62 SB Producer Drilling Procedure 2.0 Management of Change Information Page 4 Milne Point Unit L-62 SB Producer Drilling Procedure 3.0 Tubular Program: Hole Section OD (in) ID (in) Drift (in) Conn OD (in) Wt (#/ft) Grade Conn Burst (psi) Collapse (psi) Tension (k-lbs) Cond 20” 19.25” - - - X-52 Weld 12-1/4” 9-5/8” 8.835” 8.679” 10.625” 40.0 L-80 TXP 5,750 3,090 916 9-5/8” 8.681” 8.525” 10.625” 47 L-80 TXP 6,870 4,750 1,086 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 Milne Point Unit L-62 SB Producer Drilling Procedure 5.0 Internal Reporting Requirements 5.1 Fill out daily drilling report and cost report on WellEz. x Report covers operations from 6am to 6am x Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left of the data entry area – this will not save the data entered, and will navigate to another data entry. x Ensure time entry adds up to 24 hours total. x Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. x Enter the MD and TVD depths EVERY DAY whether you are making hole or not. 5.2 Afternoon Updates x Submit a short operations update each work day to pmazzolini@hilcorp.com, mmyers@hilcorp, nathan.sperry@hilcorp.com, jengel@hilcorp.com and cdinger@hilcorp.com 5.3 Intranet Home Page Morning Update x Submit a short operations update each morning by 7am on the company intranet homepage. On weekend and holidays, ensure to have this update in before 5am. 5.4 EHS Incident Reporting x Health and Safety: Notify EHS field coordinator. x Environmental: Drilling Environmental Coordinator x Notify Drilling Manager & Drilling Engineer on all incidents x Submit Hilcorp Incident report to contacts above within 24 hrs 5.5 Casing Tally x Send final “As-Run” Casing tally to mmyers@hilcorp,com jengel@hilcorp.com nathan.sperry@hilcorp.com, and cdinger@hilcorp.com 5.6 Casing and Cement report x Send casing and cement report for each string of casing to mmyers@hilcorp.com jengel@hilcorp.com nathan.sperry@hilcorp.com and cdinger@hilcorp.com 5.7 Hilcorp Milne Point Contact List: Title Name Work Phone Cell Phone Email Drilling Manager Monty Myers 907.777.8431 907.538.1168 mmyers@hilcorp.com Drilling Engineer Nate Sperry 907.777.8450 907-301-8996 nathan.sperry@hilcorp.com Completion Engineer Ian Toomey 907.777.8434 907.903.3987 itoomey@hilcorp.com Geologist Seth Nolan 907.777.8308 907.519.8225 snolan@hilcorp.com Reservoir Engineer Reid Edwards 907.777.8421 907.250.5081 reedwards@hilcorp.com Drilling Env. Coordinator Keegan Fleming 907.777.8477 907.350.9439 kfleming@hilcorp.com EHS Manager Carl Jones 907.777.8327 907.382.4336 cajones@hilcorp.com Drilling Tech Cody Dinger 907.777.8389 509.768.8196 cdinger@hilcorp.com Page 6 Milne Point Unit L-62 SB Producer Drilling Procedure 6.0 Planned Wellbore Schematic Page 7 Milne Point Unit L-62 SB Producer Drilling Procedure 7.0 Drilling / Completion Summary MPU L-62 is a grassroots producer planned to be drilled in the Schrader Bluff NB sand. L-62 is part of a multi well program targeting the Schrader Bluff sand on L-Pad. The directional plan is a horizontal well path with a 12-1/4” hole with 9-5/8” surface casing set into the top of the Schrader Bluff NB sand. An 8-1/2” lateral section will then be drilled. A 4-1/2” screen liner will be run in the open hole section and the well produced with an ESP assembly. The Doyon 14 will be used to drill and complete the wellbore Drilling operations are expected to commence approximately August 15, 2020, pending rig schedule. Surface casing will be run to 6,868’ MD / 3,990’ TVD and cemented to surface via a 2 stage primary cement job. Cement returns to surface will confirm TOC at surface. If cement returns to surface are not observed, necessary remedial action will then be discussed with AOGCC authorities. All cuttings & mud generated during drilling operations will be hauled to the Milne Point “B” pad G&I facility. General sequence of operations: 1. MIRU Doyon 14 to well site 2. NU & Test 21-1/4” Diverter and 16” diverter line 3. Drill 12-1/4” hole to TD of surface hole section. Run and cement 9-5/8” surface casing 4. ND diverter, NU wellhead, NU 13-5/8” 5M BOP & Test 5. Drill 8-1/2” lateral to well TD. 6. Run 6-5/8” production liner 7. Run 7-5/8” tieback 8. Run Upper Completion 9. ND BOP, NU Tree, RDMO Reservoir Evaluation Plan: 1. Surface hole: No mud logging. On Site geologist. LWD: GR + Res 2. Production Hole: No mud logging. On site geologist. LWD: GR + ADR (For geo-steering) 4-1/2" screens Page 8 Milne Point Unit L-62 SB Producer Drilling Procedure 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the all applicable AOGCC regulations, specific regulations are listed below. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. x BOPs shall be tested at (2) week intervals during the drilling and completion of MPU L-62. Ensure to provide AOGCC 24 hrs notice prior to testing BOPs. x The initial test of BOP equipment will be to 250/3,000 psi & subsequent tests of the BOP equipment will be to 250/3,000 psi for 5/5 min (annular to 50% rated WP, 2,500 psi on the high test for initial and subsequent tests). Confirm that these test pressures match those specified on the APD. x If the BOP is used to shut in on the well in a well control situation or control fluid flow from the well bore, AOGCC is to be notified and we must test all BOP components utilized for well control prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP test. x All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid program and drilling fluid system”. x All AOGCC regulations within 20 AAC 25.035 “Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements”. o Ensure the diverter vent line is at least 75’ away from potential ignition sources x Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office. AOGCC Regulation Variance Requests: No variances are requested at this time. Page 9 Milne Point Unit L-62 SB Producer Drilling Procedure Summary of Doyon 14 BOP Equipment & Test Requirements Hole Section Equipment Test Pressure (psi) 12 1/4” x 21-1/4” 2M Diverter w/ 16” Diverter Line Function Test Only For Reference x 13-5/8” x 5M Hydril “GK” Annular BOP x 13-5/8” x 5M Hydril MPL Double Gate o Blind ram in btm cavity x Mud cross w/ 3” x 5M side outlets x 13-5/8” x 5M Hydril MPL Single ram x 3-1/8” x 5M Choke Line x 3-1/8” x 5M Kill line x 3-1/8” x 5M Choke manifold x Standpipe, floor valves, etc N/A N/A Primary closing unit: NL Shaffer, 6 station, 3,000 psi, 180 gallon accumulator unit. Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is a 30:1 air pump, and emergency pressure is provided by bottled nitrogen. The remote closing operator panels are located in the doghouse and on accumulator unit. Required AOGCC Notifications: x Well control event (BOPs utilized to shut in the well to control influx of formation fluids). x 24 hours notice prior to spud. x 24 hours notice prior to testing BOPs. x 24 hours notice prior to casing running & cement operations. x Any other notifications required in APD. Regulatory Contact Information: AOGCC Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email: jim.regg@alaska.gov Guy Schwartz / Petroleum Engineer / (O): 907-793-1226 / (C): 907-301-4533 / Email: guy.schwartz@alaska.gov Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Email: Victoria.loepp@alaska.gov Mel Rixse / Petroleum Engineer / (O): 907-793-1231 / (C): 907-223-3605 / Email: melvin.rixse@alaska.gov Primary Contact for Opportunity to witness: AOGCC.Inspectors@alaska.gov Test/Inspection notification standardization format: http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) Page 10 Milne Point Unit L-62 SB Producer Drilling Procedure 9.0 RU and Preparatory Work 9.1 L-62 will utilize a newly set 20” conductor on L-Pad. Ensure to review attached surface plat and make sure rig is over appropriate conductor. 9.2 Ensure PTD and drilling program are posted in the rig office and on the rig floor. 9.3 Install landing ring. 9.4 Insure (2) 4” nipples are installed on opposite sides of the conductor with ball valves on each. 9.5 Level pad and ensure enough room for layout of rig footprint and RU. 9.6 Rig mat footprint of rig. 9.7 MIRU Doyon 14. Ensure rig is centered over conductor to prevent any wear to BOPE or wellhead. 9.8 Mud loggers WILL NOT be used on either hole section. 9.9 Mix spud mud for 12-1/4” surface hole section. Ensure mud temperatures are cool (<80qF). 9.10 Ensure 6” liners in mud pumps. x Continental EMSCO FB-1600 mud pumps are rated at 4,665 psi, 462 GPM @ 110 SPM @ 95% volumetric efficiency. Page 11 Milne Point Unit L-62 SB Producer Drilling Procedure 10.0 NU 21-1/4” 2M Diverter System 10.1 NU 21-1/4” Hydril MSP 2M Diverter System (Diverter Schematic attached to program). x NU 16-3/4” 3M x 21-1/4” 2M DSA on 16-3/4” 3M wellhead. x NU 21-1/4” diverter “T”. x Knife gate, 16” diverter line. x Ensure diverter RU complies with AOGCC reg 20.AAC.25.035(C). x Diverter line must be 75 feet from nearest ignition source x Place drip berm at the end of diverter line. 10.2 Notify AOGCC. Function test diverter. Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens prior to annular closure. 10.3 Ensure to set up a clearly marked “warning zone” is established on each side and ahead of the vent line tip. “Warning Zone” must include: x A prohibition on vehicle parking x A prohibition on ignition sources or running equipment x A prohibition on staged equipment or materials x Restriction of traffic to essential foot or vehicle traffic only. 24 hour notice to AOGCC to witness. Page 12 Milne Point Unit L-62 SB Producer Drilling Procedure 10.4 Rig & Diverter Orientation: x May change on location Page 13 Milne Point Unit L-62 SB Producer Drilling Procedure 11.0 Drill 12-1/4” Hole Section 11.1 PU 12-1/4” directional drilling assembly: x Ensure BHA components have been inspected previously. x Drift and caliper all components before MU. Visually verify no debris inside components that cannot be drifted. x Ensure TF offset is measured accurately and entered correctly into the MWD software. x Be sure to run a UBHO sub for wireline gyro x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. x Drill string will be 5”, 19.5#, S-135, NC50. x Run a solid float in the surface hole section. 11.2 Begin drilling out from 20” conductor at reduced flow rates to avoid broaching the conductor. x Consider using a trash bit to clean out conductor to mitigate potential damage from debris in conductor. 11.3 Drill 12-1/4” hole section to section TD, in the Schrader NB sand. Confirm this setting depth with the Geologist and Drilling Engineer while drilling the well. x Monitor the area around the conductor for any signs of broaching. If broaching is observed, Stop drilling (or circulating) immediately notify Drilling Engineer. x Efforts should be made to minimize dog legs in the surface hole. Keep DLS < 6°/ 100. x Hold a safety meeting with rig crews to discuss: x Conductor broaching ops and mitigation procedures. x Well control procedures and rig evacuation x Flow rates, hole cleaning, mud cooling, etc. x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Keep mud as cool as possible to keep from washing out permafrost. x Pump at 400-600 GPM. Monitor shakers closely to ensure shaker screens and return lines can handle the flow rate. x Ensure to not out drill hole cleaning capacity, perform clean up cycles or reduce ROP if packoffs, increase in pump pressure or changes in hookload are seen x Slow in/out of slips and while tripping to keep swab and surge pressures low x Ensure shakers are functioning properly. Check for holes in screens on connections. x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of pea gravel, clay balling or packing off. x Adjust MW and viscosity as necessary to maintain hole stability, ensure MW is at a 9.2 ppg minimum at TD (pending MW increase due to hydrates). x Perform wireline gyros until clean MWD surveys are seen. Take MWD surveys every stand drilled. x Gas hydrates have not been seen on L-Pad. However, be prepared for them. In MPU they have been encountered typically around 2,100-2,400’ TVD (just below permafrost). Be prepared for hydrates: Page 14 Milne Point Unit L-62 SB Producer Drilling Procedure x Gas hydrates can be identified by the gas detector and a decrease in MW or ECD x Monitor returns for hydrates, checking pressurized & non-pressurized scales x Do not stop to circulate out gas hydrates – this will only exacerbate the problem by washing out additional permafrost. Attempt to control drill (150 FPH MAX) through the zone completely and efficiently to mitigate the hydrate issue. Flowrates can also be reduced to prevent mud from belching over the bell nipple. Consider adding Lecithin to allow the gas to break out. x Gas hydrates are not a gas sand, once a hydrate is disturbed the gas will come out of the well. MW will not control gas hydrates, but will affect how gas breaks out at surface. x Surface Hole AC: x There are no wells with a clearance factor of <1.0 11.4 12-1/4” hole mud program summary: x Density: Weighting material to be used for the hole section will be barite. Additional barite or spike fluid will be on location to weight up the active system (1) ppg above highest anticipated MW. We will start with a simple gel + FW spud mud at 8.8 ppg and TD with 9.2+ ppg. Depth Interval MW (ppg) Surface – Base Permafrost 8.9+ Base Permafrost - TD 9.2+ (For Hydrates if need based on offset wells) MW can be cut once ~500’ below hydrate zone x PVT System: MD Totco PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, Toolpusher office, and mud loggers office. x Rheology: Aquagel and Barazan D+ should be used to maintain rheology. Begin system with a 75 YP but reduce this once clays are encountered. Maintain a minimum 25 YP at all times while drilling. Be prepared to increase the YP if hole cleaning becomes an issue. x Fluid Loss: DEXTRID and/or PAC L should be used for filtrate control. Background LCM (10 ppb total) BARACARBs/BAROFIBRE/STEELSEALs can be used in the system while drilling the surface interval to prevent losses and strengthen the wellbore. x Wellbore and mud stability: Additions of CON DET PRE-MIX/DRIL N SLIDE are recommended to reduce the incidence of bit balling and shaker blinding when penetrating the high-clay content sections of the Sagavanirktok and the heavy oil sections of the UGNU 4A. Maintain the pH in the 8.5 – 9.0 range with caustic soda. Daily additions of ALDACIDE G / X-CIDE 207 MUST be made to control bacterial action. x Casing Running: Reduce system YP with DESCO as required for running casing as allowed (do not jeopardize hole conditions). Run casing carefully to minimize surge and swab pressures. Reduce the system rheology once the casing is landed to a YP < 20 (check with the cementers to see what YP value they have targeted). Page 15 Milne Point Unit L-62 SB Producer Drilling Procedure System Type: 8.8 – 9.2 ppg Pre-Hydrated Aquagel/freshwater spud mud Properties: Section Density Viscosity Plastic Viscosity Yield Point API FL pH Temp Surface 8.8 – 9.8 75-175 20 - 40 25-45 <10 8.5 – 9.0 70 F System Formulation: Gel + FW spud mud Product- Surface hole Size Pkg ppb or (% liquids) M-I Gel 50 lb sx 25 Soda Ash 50 lb sx 0.25 PolyPac Supreme UL 50 lb sx 0.08 Caustic Soda 50 lb sx 0.1 SCREENCLEEN 55 gal dm 0.5 11.5 At TD; PU 2-3 stands off bottom, CBU, pump tandem sweeps and drop viscosity. 11.6 RIH to bottom, proceed to BROOH to HWDP x Pump at full drill rate (400-600 GPM), and maximize rotation. x Pull slowly, 5 – 10 ft/minute, adjust as dictated by hole conditions x Monitor well for any signs of packing off or losses. x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay balling. x If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until parameters are restored. 11.7 TOOH and LD BHA 11.8 No open hole logging program planned. Note: EMW minimum=8.46 ppg. DLB Page 16 Milne Point Unit L-62 SB Producer Drilling Procedure 12.0 Run 9-5/8” Surface Casing 12.1 RU and pull wearbushing. 12.2 RU Weatherford 9-5/8” casing running equipment (CRT & Tongs) x Ensure 9-5/8” TXP x DS50 XO on rig floor and M/U to FOSV. x Use BOL 2000 thread compound. Dope pin end only w/ paint brush. x RU of CRT if hole conditions require. x RU a fill up tool to fill casing while running if the CRT is not used. x Ensure all casing has been drifted to 8.750” on the location prior to running. x Top 2000’ of casing from surface 47# drift 8.525” min x Be sure to count the total # of joints on the location before running. x Keep hole covered while RU casing tools. x Record OD’s, ID’s, lengths, SN’s of all components with vendor & model info. 12.3 PU shoe joint, visually verify no debris inside joint. 12.4 Continue MU & thread locking 120’ shoe track assembly consisting of: 9-5/8” Float Shoe 1 joint – 9-5/8” TXP, 2 Centralizers 10’ from each end w/ stop rings 1 joint – 9-5/8” TXP, 1 Centralizer mid joint w/ stop ring 9-5/8” Float Collar with Stage Cementer Bypass Baffle ‘Top Hat’ 1 joint – 9-5/8” TXP, 1 Centralizer mid joint with stop ring 9-5/8” HES Baffle Adaptor x Ensure bypass baffle is correctly installed on top of float collar. x Ensure proper operation of float equipment while picking up. x Ensure to record SN’s of all float equipment and stage tool components. This end up. Bypass Baffle Page 17 Milne Point Unit L-62 SB Producer Drilling Procedure 12.5 Float equipment and stage tool equipment drawings: Page 18 Milne Point Unit L-62 SB Producer Drilling Procedure 12.6 Continue running 9-5/8” surface casing x Fill casing while running using fill up line on rig floor. x Use BOL 2000 thread compound. Dope pin end only with paint brush. x Centralization: Verify depth of lowest Ugnu water sand for isolation with Geologist x Utilize a collar clamp until weight is sufficient to keep slips set properly. x Break circulation prior to reaching the base of the permafrost if casing run indicates poor hole conditions. x Any packing off while running casing should be treated as a major problem. It is preferable to POH with casing and condition hole than to risk not getting cement returns to surface. 12.7 Install the Halliburton Type H ES-II Stage tool so that it is positioned at least 100’ TVD below the permafrost (~ 2,500’ MD). x Install centralizers over couplings on 5 joints below and 5 joints above stage tool. x Do not place tongs on ES cementer, this can cause damaged to the tool. x Ensure tool is pinned with 6 opening shear pins. This will allow the tool to open at 3,300 psi. 9-5/8” 40# L-80 TXP Make Up Torques: Casing OD Minimum Optimum Maximum 9-5/8” 18,860 ft-lbs 20,960 ft-lbs 23,060 ft-lbs 9-5/8” 47# L-80 TXP MUT: Casing OD Minimum Optimum Maximum 9-5/8” 21,440 ft-lbs 2,3820 ft-lbs 26,200 ft-lbs Depth Interval Centralization Shoe – 1000’ Above Shoe 1/joints 1000’ above Shoe – 2000’ above Shoe (Top of Ugnu) 1/ 2 joints Page 19 Milne Point Unit L-62 SB Producer Drilling Procedure Page 20 Milne Point Unit L-62 SB Producer Drilling Procedure 12.8 Continue running 9-5/8” surface casing x Fill casing while running using fill up line on rig floor. x Use BOL 2000 thread compound. Dope pin end only with paint brush. x Centralization: x 1 centralizer every 2 joints to base of conductor 12.9 The last 2000’ of 9-5/8” will be 47#, from 2000’ to Surface x Ensure drifted to 8.525” min Page 21 Milne Point Unit L-62 SB Producer Drilling Procedure 12.10 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 12.11 Slow in and out of slips. 12.12 PU landing joint and MU to casing string. Position the casing shoe ±10’ from TD. Strap the landing joint prior to the casing job and mark the joint at (1) ft intervals to use as a reference when getting the casing on depth. 12.13 Lower casing to setting depth. Confirm measurements. 12.14 Have slips staged in cellar, along with necessary equipment for the operation. 12.15 Circulate and condition mud through CRT. Reduce YP to < 20 to help ensure success of cement job. Ensure adequate amounts of cold MU water are available to achieve this. If possible reciprocate casing string while conditioning mud. Page 22 Milne Point Unit L-62 SB Producer Drilling Procedure 13.0 Cement 9-5/8” Surface Casing 13.1 Hold a pre-job safety meeting over the upcoming cement operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud & water can be delivered to the cementing unit at acceptable rates. x How to handle cement returns at surface. Ensure vac trucks are on standby and ready to assist. x Which pumps will be utilized for displacement and how fluid will be fed to displacement pump. x Ensure adequate amounts of water for mix fluid is heated and available in the water tanks. x Positions and expectations of personnel involved with the cementing operation. i. Extra hands in the pits to strap during the cement job to identify any losses x Review test reports and ensure pump times are acceptable. x Conduct visual inspection of all hard lines and connections used to route slurry to rig floor. 13.2 Document efficiency of all possible displacement pumps prior to cement job. 13.3 Flush through cement pump and treating iron from pump to rig floor to the shakers. This will help ensure any debris left in the cement pump or treating iron will not be pumped downhole. 13.4 RU cement line (if not already done so). Company Rep to witness loading of the top and bottom plugs to ensure done in correct order. 13.5 Fill surface cement lines with water and pressure test. 13.6 Pump remaining 60 bbls 10.5 ppg tuned spacer. 13.7 Drop bottom plug (flexible bypass plug) – HEC rep to witness. Mix and pump cement per below calculations for the 1st stage, confirm actual cement volumes with cementer after TD is reached. 13.8 Cement volume based on annular volume + 30% open hole excess. Job will consist of lead & tail, TOC brought to stage tool. Estimated 1st Stage Total Cement Volume: Cement Slurry Design (1st Stage Cement Job): Lead Slurry Tail Slurry Density 12.0 lb/gal 15.8 lb/gal Yield 2.35 ft3/sk 1.16 ft3/sk Mixed Water 13.92 gal/sk 4.98 gal/sk 394 sx 582 sx Page 23 Milne Point Unit L-62 SB Producer Drilling Procedure 13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Watch reciprocation PU and SO weights, if the hole gets “sticky”, cease pipe reciprocation and continue with the cement job. 13.9 After pumping cement, drop top plug (Shutoff plug) and displace cement with spud mud out of mud pits, spotting water across the HEC stage cementer. x Ensure volumes pumped and volumes returned are documented and constant communication between mud pits, HEC Rep and HES Cementers during the entire job. 13.10 Ensure rig pump is used to displace cement. Displacement calculations have proven to be very accurate using 0.0625 BPS (5” liners) for the Quattro pump output. To operate the stage tool hydraulically, the plug must be bumped. 13.11 Displacement calculation: 2,000’ x 0.0732 BPF + (6,868’ – 120’ - 2,000’) x .0758 BPF = 506.4 bbls 80 bbls of tuned spacer to be left behind stage tool 13.12 Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any point during the job. Be prepared to pump out fluid from cellar. Have black water available to contaminate any cement seen at surface. 13.13 If plug is not bumped at calculated strokes, double check volumes and calculations. Over displace by no more than 50% of shoe track volume, ±4.5 bbls before consulting with Drilling Engineer. 13.14 If plug is not bumped, consult with Drilling Engineer. Ensure the free fall stage tool opening plug is available if needed. This is the back-up option to open the stage tool if the plugs are not bumped. 13.15 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held, this is to ensure the stage tool is not prematurely opened. 13.16 Increase pressure to 3,300 psi to open circulating ports in stage collar. Slightly higher pressure may be necessary if TOC is above the stage tool. CBU and record any spacer or cement returns to surface and volume pumped to see the returns. Circulate until YP < 20 again in preparation for the 2nd stage of the cement job. 13.17 Be prepared for cement returns to surface. Dump cement returns in the cellar or open the shaker bypass line to the cuttings tank. Have black water available and vac trucks ready to assist. Ensure to flush out any rig components, hard lines and BOP stack that may have come in contact with the cement. Page 24 Milne Point Unit L-62 SB Producer Drilling Procedure Second Stage Surface Cement Job: 13.18 Prepare for the 2nd stage as necessary. Circulate until first stage reaches sufficient compressive strength. Try to maintain flow rate through stage tool until 2nd stage is ready. Hold pre-job safety meeting. x Past wells have seen pressure increase while circulating through stage tool after reduced rate 13.19 HEC representative to witness the loading of the ES cementer closing plug in the cementing head. 13.20 Fill surface lines with water and pressure test. 13.21 Pump remaining 60 bbls of 10.5 ppg tuned spacer. 13.22 Mix and pump cement per below recipe for the 2nd stage. 13.23 Cement volume based on annular volume + open hole excess (200% for lead and 100% for tail). Job will consist of lead & tail, TOC brought to surface. However cement will continue to be pumped until clean spacer is observed at surface. Estimated 2nd Stage Total Cement Volume: Cement Slurry Design (2nd stage cement job): 13.24 Continue pumping lead until uncontaminated spacer is seen at surface, then switch to tail. Lead Slurry Tail Slurry System Permafrost L Density 10.7 lb/gal 15.8 lb/gal Yield 4.41 ft3/sk 1.17 ft3/sk Mixed Water 22.02 gal/sk 5.08 gal/sk 270 sx 439 sx Page 25 Milne Point Unit L-62 SB Producer Drilling Procedure 13.25 After pumping cement, drop ES Cementer closing plug and displace cement with spud mud out of mud pits. 13.26 Displacement calculation: (2,500’ – 2,000’) x 0.0758 BPF + 2,000’ x 0.0732 = 184.3 bbls mud 13.27 Monitor returns closely while displacing cement. Adjust pump rate if necessary. Wellhead side outlet valve in cellar can be opened to take returns to cellar if required. Be prepared to pump out fluid from cellar. Have black water available to retard setting of cement. 13.28 Decide ahead of time what will be done with cement returns once they are at surface. We should circulate approximately 100 - 150 bbls of cement slurry to surface. 13.29 Land closing plug on stage collar and pressure up to 1,000 – 1,500 psi to ensure stage tool closes. Follow instructions of Halliburton personnel. Bleed off pressure and check to ensure stage tool has closed. Slips will be set as per plan to allow full annulus for returns during surface cement job. Set slips 13.30 Make initial cut on 9-5/8” final joint. LD cut joint. Make final cut on 9-5/8”. Dress off stump. Install 9-5/8” wellhead. If transition nipple is welded on, allow to cool as per schedule. Ensure to report the following on wellez: x Pre flush type, volume (bbls) & weight (ppg) x Cement slurry type, lead or tail, volume & weight x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid x Note if casing is reciprocated or rotated during the job x Calculated volume of displacement , actual displacement volume, whether plug bumped & bump pressure, do floats hold x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure x Note if pre flush or cement returns at surface & volume x Note time cement in place x Note calculated top of cement x Add any comments which would describe the success or problems during the cement job Send final “As-Run” casing tally & casing and cement report to nathan.sperry@hilcorp.com jengel@hilcorp.com and cdinger@hilcorp.com This will be included with the EOW documentation that goes to the AOGCC. Page 26 Milne Point Unit L-62 SB Producer Drilling Procedure 14.0 ND Diverter, NU BOPE, & Test 14.1 ND the diverter T, knife gate, diverter line & NU 11” x 13-5/8” 5M casing spool. 14.2 NU 13-5/8” x 5M BOP as follows: x BOP configuration from top down: 13-5/8” x 5M annular / 13-5/8” x 5M double gate / 13- 5/8” x 5M mud cross / 13-5/8” x 5M single gate x Double gate ram should be dressed with 2-7/8” x 5” VBRs in top cavity, blind ram in bottom cavity. x Single ram can be dressed with 4-1/2” x 7” VBRs x NU bell nipple, install flowline. x Install (1) manual valve & HCR valve on kill side of mud cross. (Manual valve closest to mud cross). x Install (1) manual valve on choke side of mud cross. Install an HRC outside of the manual valve 14.3 RU MPD RCD and related equipment. 14.4 Run 5” BOP test plug. 14.5 Test BOP to 250/3,000 psi for 5/5 min. Test annular to 250/2,500 psi for 5/5 min. x Test with 5” 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 14.6 RD BOP test equipment 14.7 Dump and clean mud pits, send spud mud to G&I pad for injection. 14.8 Mix 8.9 ppg FloPro fluid for production hole. 14.9 Set wearbushing in wellhead. 14.10 If needed, rack back as much 5” DP in derrick as possible to be used while drilling the hole section. 14.11 Ensure 6” liners in mud pumps. 24 hour notice to AOGCC. Page 27 Milne Point Unit L-62 SB Producer Drilling Procedure 15.0 Drill 8-1/2” Hole Section 15.1 MU 8-1/2” Cleanout BHA (Milltooth Bit & 1.22° PDM). x Decision may be made to drill out with RSS. If so MU RSS BHA 15.2 TIH with 8-1/2” cleanout BHA to stage tool. Note depth TOC tagged on AM report. Drill out stage tool. 15.3 TIH to TOC above the baffle adapter. Note depth TOC tagged on morning report. 15.4 RU and PT casing to 2,500 psi for 30 minutes charted. Ensure to record volume / pressure (every ¼ bbl) and plot on FIT graph. AOGCC reg is 50% of burst = 5,750 / 2 = ~2,875 psi, but max test pressure on the well is 2,500 psi as per AOGCC. Document incremental volume pumped (and subsequent pressure) and volume returned. Ensure rams are used to test casing as per AOGCC Industry Guidance Bulletin 17-001. 15.5 Drill out shoe track and 20’ of new formation. 15.6 CBU and condition mud for FIT. 15.7 Conduct FIT to 12.0 ppg EMW. Chart Test. Ensure test is recorded on same chart as FIT. Document incremental volume pumped (and subsequent pressure) and volume returned. 15.8 POOH and LD Cleanout BHA. 15.9 PU 8-1/2” 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. 15.10 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 FIT and casing test digital data to AOGCC. Page 28 Milne Point Unit L-62 SB Producer Drilling Procedure 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. System Type: 8.9 – 9.5 ppg FloPro drilling fluid Properties: Interval Density PV YP LSYP Total Solids MBT HPHT Hardness Production 8.9-9.5 15-25 - ALAP 15 - 30 4-6 <10% <8 <11.0 <100 System Formulation: Product- production Size Pkg ppb or (% liquids) Busan 1060 55 gal dm 0.095 FLOTROL 55 lb sx 6 CONQOR 404 WH (8.5 gal/100 bbls) 55 gal dm 0.2 FLO-VIS PLUS 25 lb sx 0.7 KCl 50 lb sx 10.7 SMB 50 lb sx 0.45 LOTORQ 55 gal dm 1.0 SAFE-CARB 10 (verify) 50 lb sx 10 SAFE-CARB 20 (verify) 50 lb sx 10 Soda Ash 50 lb sx 0.5 Note: EMW minimum=8.46 ppg. DLB Page 29 Milne Point Unit L-62 SB Producer Drilling Procedure 15.11 TIH with 8-1/2” directional assembly to bottom. 15.12 Install MPD RCD. 15.13 Displace wellbore to 8.9 ppg Flo Pro drilling fluid 15.14 Begin drilling 8-1/2” hole section, on-bottom staging technique: x Tag bottom and 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 15.14 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 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-11 has a 0.841 CF. M-11 is an injector drilled in the OA sands (different zone than our target). Geology will provide collision mitigation. x M-12 has a 0.838 CF. M-12 is an active producer from the OA sands (different zone than our target). Geology will provide collision mitigation. x M-12PB2 has a 0.794 CF. This is an open hole PB in a different zone. No risk. x M-13 has a 0.992 CF. M-13 is an active injector in the OA sands (different zone than our target). Geology will provide collision mitigation. 15.15 Reference: Open hole sidetracking practice: Page 30 Milne Point Unit L-62 SB Producer Drilling Procedure 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. x Orient TF to low side and dig a trough with high flowrates for the first 10 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. 15.16 At TD, CBU at least 4 times at 200 ft/min AV (385+ GPM) and rotation (120+ RPM). Pump tandem sweeps if needed 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 x Decision may be made to leave mud in the lateral and BROOH. This is TBD based upon hole conditions and M-44 results. 15.17 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. 15.18 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. 15.19 Monitor the returned fluids carefully while displacing to brine. After 4 (or more) 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 Page 31 Milne Point Unit L-62 SB Producer Drilling Procedure 15.20 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 15.21 If abnormal pressure has been observed in the lateral, utilize MPD to close on connections while BROOH. 15.22 CBU minimum two times at 9-5/8” shoe and clean casing with high vis sweeps. 15.23 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 15.24 POOH and LD BHA. 15.25 Continue to POOH and stand back BHA if possible. Rabbit DP on TOOH, ensure rabbit diameter is sufficient for future ball drops. 15.26 Only LWD open hole logs are planned for the hole section (GR + Res). There will not be any additional logging runs conducted. Page 32 Milne Point Unit L-62 SB Producer Drilling Procedure 16.0 Run 4-1/2” Screen Liner 16.1 Confirm VBR’s have been tested on 4-1/2” and 5” test joints to 250/3,000 psi. 16.2 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. 16.3 If an inner string is ran, Well control preparedness: In the event of an influx of formation fluids while running the 2-3/8” inner string inside the 4-1/2” production screens: x PU & MU the 5” safety joint (with 4-1/2” x 2-3/8” triple connect crossover installed on bottom, TIW valve in open position on top, 2-3/8” handling joint above TIW). MU 2-3/8” and then 4-1/2” to triple connect. x This joint shall be fully MU with crossovers prior to running the first joint of wash pipe. x Slack off and position the 5” DP across the BOP, shut in ram or annular on 5” DP. Close TIW valve. Proceed with well kill operations. 16.4 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. 16.5 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 Page 33 Milne Point Unit L-62 SB Producer Drilling Procedure 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 34 Milne Point Unit L-62 SB Producer Drilling Procedure 16.6. 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. x 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. 16.7. 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. 16.8. MU Baker SLZXP liner top packer to 4-1/2” liner. 16.9. Inner string may or not be ran, depending on out of zone excursion and condition of lateral. Have 2-3/8” inner string available if needed. 16.10. 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. 16.11. RIH with liner on ALL 5” HWDP 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 x There is no inner string planned to be run, as opposed to previous wells. The DP should auto fill. Monitor FL and if filling is required due to losses/surging. 16.12. 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. 16.13. Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10, & 20 RPM. 16.14. If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensure shoe enters correct hole. 16.15. TIH deeper than planned setting depth. Last motion of the liner should be up to ensure it is set in tension. 16.16. Rig up to pump down the work string with the rig pumps. 16.17. 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. Page 35 Milne Point Unit L-62 SB Producer Drilling Procedure 16.18. 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. 16.19. 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. 16.20. 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. 16.21. 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. 16.22. PU to neutral weight, close BOP and test annulus to 1,500 psi for 10 minutes charted. 16.23. 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. 16.24. PU pulling running tool free of the packer and displace with at max rate to wash the liner top. Pump sweeps as needed. 16.25. POOH. LD and inspect running tools. If setting of liner hanger/packer proceeded as planned, LD DP on the TOOH. Note: Once running tool is LD, swap to the completion AFE. 16.26. MU 3-1/2” wash tool and RIH with remaining DP out of derrick to liner top. 16.27. Wash through liner top at max rate and circulate hole clean. Pump sweeps around. Displace well to clean filtered brine after no solids are returned. 16.28. POOH and LD remaining 5” HWDP Page 36 Milne Point Unit L-62 SB Producer Drilling Procedure 17.0 Run 7-5/8” Tieback 17.1 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. 17.2 Confirm pipe rams been tested with 7-5/8” test joint to 250/3,000 psi. 17.3 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. 17.4 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. 17.5 M/U first joint of 7-5/8” to seal assembly. 17.6 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 37 Milne Point Unit L-62 SB Producer Drilling Procedure 17.7 MU 7-5/8” to DP crossover. 17.8 MU stand of DP to string, and MU top drive. 17.9 Break circulation at 1 BPM and begin lowering string. 17.10 Note seal assembly entering tieback sleeve with a pressure increase, stop pumping and bleed off pressure, leave standpipe bleed off valve open. Page 38 Milne Point Unit L-62 SB Producer Drilling Procedure 17.11 Continue lowering string and land out on no-go. Set down 5 – 10K and mark the pipe as “NO- GO DEPTH”. 17.12 PU string & remove unnecessary 7-5/8” joints. 17.13 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. 17.14 PU and MU the 7-5/8” casing hanger with landing joint. 17.15 Ensure circulation is possible through 7-5/8” string. 17.16 RU and circulation corrosion inhibited brine in the 9-5/8” x 7-5/8” annulus. 17.17 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). 17.18 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. 17.19 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. 17.20 R/D casing running tools. 17.21 PT 9-5/8” x 7-5/8” annulus to 1,000 psi for 30 minutes charted. Page 39 Milne Point Unit L-62 SB Producer Drilling Procedure 18.0 Run ESP Upper Completion 18.1 RU spooler with ESP power cable and heat trace. 18.2 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. 18.3 Makeup new ESP assembly with new motor lead extension, seal section and motor. 18.4 Run the 3-1/2” ESP Completion as noted below. The completion includes two 3/8” capillary tube from surface to the centralizer on the motor. The capillary tube will be secured to the tubing with Cannon clamps. Function test the capillary tube every ~2,000’ by pumping ~2 gallons of hydraulic oil through the check valves. Record the pressure at each testing point 18.5 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 / 2.75” 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 Use Cannon clamps on every joint to secure the capillary tube. o The make-up torque values for 3-1/2” L-80 9.3# EUE 8rd tubing are: Page 40 Milne Point Unit L-62 SB Producer Drilling Procedure Casing OD Minimum Optimum Maximum Operating Torque 3.5” 2,350 ft-lbs 3,130 ft-lbs 3,910 ft-lbs 18.6 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. 18.7 Record PU and SO weights before landing hanger. Note PU and SO weights on tally along with band/clamp summary. 18.8 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. 18.9 Land tubing with extreme care to minimize damaging the ESP penetrator, pigtail and alignment pin. 18.10 RILDS and test hanger. LD landing joint. 18.11 Install BPV and N/D BOP. 18.12 N/U tree / adapter and tree. Test tubing hanger void to 500 psi low / 5000 psi high. Terminate the cap strings. 18.13 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. 18.14 Pull BPV. Set TWC. Test tree to 250 psi low / 5000 psi high. Pull TWC. Set BPV. 18.15 Prepare to hand over well to production. Ensure necessary forms filled out and well handed over with valve alignment as per operations personnel. 18.16 RDMO Doyon 14 Page 41 Milne Point Unit L-62 SB Producer Drilling Procedure 19.0 Doyon 14 Diverter Schematic Page 42 Milne Point Unit L-62 SB Producer Drilling Procedure 20.0 Doyon 14 BOP Schematic Page 43 Milne Point Unit L-62 SB Producer Drilling Procedure 21.0 Wellhead Schematic Page 44 Milne Point Unit L-62 SB Producer Drilling Procedure 22.0 Days Vs Depth Page 45 Milne Point Unit L-62 SB Producer Drilling Procedure 23.0 Formation Tops & Information L-Pad Data Sheet Formation Description Page 46 Milne Point Unit L-62 SB Producer Drilling Procedure 24.0 Anticipated Drilling Hazards 12-1/4” Hole Section: Lost Circulation Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Gas Hydrates Gas hyrates have not been seen on Moose pad. However, be prepared for them. Remember that hydrate gas behave differently from a gas sand. Additional fluid density will not prevent influx of gas hydrates, but can help control the breakout at surface. Once a gas hydrate has been disturbed the gas will come out of the hole. Drill through the hydrate section as quickly as possible while minimizing gas belching. Minimize circulation time while drilling through the hydrate zone. Excessive circulation will accelerate formation thawing which can increase the amount of hydrates released into the wellbore. Keep the mud circulation temperature as cold as possible. Weigh mud with both a pressurized and non-pressurized mud scale. The non-pressurized scale will reflect the actual mud cut weight. Add 1.0 – 2.0 ppb Lecithin to the system to help thin the mud and release the gas. Isolate/dump contaminated fluid to remove hydrates from the system. Hole Cleaning: Maintain rheology of mud system. Sweep hole with high viscosity sweeps as necessary. Optimize solids control equipment to maintain density, sand content, and reduce the waste stream. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to avoid washing out a particular section of the hole. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Anti-Collison: Take directional surveys every stand, take additional surveys if necessary. Continuously monitor proximity to offset wellbores and record any close approaches on AM report. x There are no wells with a clearance factor <1.0 in the surface interval Wellbore stability (Permafrost, running sands and gravel, conductor broaching): Washouts in the permafrost can be severe if the string is left circulating across it for extended periods of time. Keep mud as cool as possible by taking on cold water and diluting often. High TOH and RIH speeds can aggravate fragile shale/coal formations due to the pressure variations between surge and swab. Bring the pumps on slowly after connections. Monitor conductor for any signs of broaching. Maintain mud parameters and increase MW to combat running sands and gravel formations. H2S: Page 47 Milne Point Unit L-62 SB Producer Drilling Procedure Treat every hole section as though it has the potential for H2S. No H2S events have been documented on drill wells on this pad. 1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Page 48 Milne Point Unit L-62 SB Producer Drilling Procedure 8-1/2” Hole Section: Hole Cleaning: Maintain rheology of mud system. Sweep hole with low-vis water sweeps. Ensure shakers are set up with appropriate screens to maximize solids removal efficiency. Run centrifuge continuously. Monitor 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. No H2S events have been documented on drill wells on this pad. 1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Abnormal Pressures and Temperatures: Reservoir pressures are expected to be normal. Abnormal (offset injection) pressure has been seen on M- Pad. Utilize MPD to mitigate any abnormal pressure seen. 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-11 has a 0.841 CF. M-11 is an injector drilled in the OA sands (different zone than our target). Geology will provide collision mitigation. Page 49 Milne Point Unit L-62 SB Producer Drilling Procedure x M-12 has a 0.838 CF. M-12 is an active producer from the OA sands (different zone than our target). Geology will provide collision mitigation. x M-12PB2 has a 0.794 CF. This is an open hole PB in a different zone. No risk. x M-13 has a 0.992 CF. M-13 is an active injector in the OA sands (different zone than our target). Geology will provide collision mitigation. Page 50 Milne Point Unit L-62 SB Producer Drilling Procedure 25.0 Doyon 14 Layout Page 51 Milne Point Unit L-62 SB Producer Drilling Procedure 26.0 FIT Procedure Formation Integrity Test (FIT) and Leak-Off Test (LOT) Procedures Procedure for FIT: 1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe). 2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe. 3. Close the blowout preventer (ram or annular). 4. Pump down the drill stem at 1/4 to 1/2 bpm. 5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe. 6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes. Record time vs. pressure in 1-minute intervals. 7. Bleed the pressure off and record the fluid volume recovered. The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick tolerance in case well control measures are required. Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid; at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure monitored as with an FIT. Ensure that casing test and subsequent FIT tests are recorded on the same chart. Document incremental volume pumped and returned during test. Page 52 Milne Point Unit L-62 SB Producer Drilling Procedure 27.0 Doyon 14 Choke Manifold Schematic Page 53 Milne Point Unit L-62 SB Producer Drilling Procedure 28.0 Casing Design Page 54 Milne Point Unit L-62 SB Producer Drilling Procedure 29.0 8-1/2” Hole Section MASP EMW minimum workup. DLB Page 55 Milne Point Unit L-62 SB Producer Drilling Procedure 30.0 Spider Plot (NAD 27) (Governmental Sections) Page 56 Milne Point Unit L-62 SB Producer Drilling Procedure 31.0 Surface Plat (As Staked) (NAD 27) Page 57 Milne Point Unit L-62 SB Producer Drilling Procedure 32.0 Schrader Bluff Nb Sand Offset MW vs TVD Chart 10 July, 2020 Plan: MPU L-62 wp07 Milne Point M Pt L Pad Plan: MPU L-62 MPU L-62 0750150022503000375045005250True Vertical Depth (1500 usft/in)-750 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750 10500 11250 12000 12750 13500 14250Vertical Section at 192.60° (1500 usft/in)MPI-L-62 wp01 HeelMPI-L-62 wp01 ToeMPI-L-62 wp06 Base Pump9 5/8" x 12 1/4"6 5/8" x 8 1/2"5001000150020002500300035004000450050005500600065007000750 0 8 0 00 85 0 0 900 0 95 00 10 0 00 1 0 50 0 11 0 0 0 11 5 0 0 12 0 00 12 5 00 13 0 00 13 50 0 1 3 6 9 1MPU L-62 wp07Start Dir 3º/100' : 250' MD, 250'TVDStart Dir 4º/100' : 635' MD, 632.4'TVDEnd Dir : 1782.63' MD, 1553.09' TVDStartDir4º/100':5523.87'MD,3565.81'TVDEndDir:5752.83'MD,3680.35'TVDStartofESPtangentEndofESPtangentStartDir4º/100':5902.83'MD,3749.4'TVDFault #1 (20' Throw, DTN)EndDir:6718.62'MD,3977.65'TVDStartDir2º/100':6867.97'MD,3990.2'TVDEndDir:7206.07'MD,3998.75'TVDStartDir2º/100':10706.07'MD,3881.48'TVDEndDir:10795.01'MD,3879.09'TVDTotalDepth:13690.71'MD,3820.2'TVDSV5BPRFUG3UG COAL 1UGNU LA3UGNU MBSCHRADER NASCHRADER NBHilcorp Alaska, LLCCalculation Method:Minimum CurvatureError System:ISCWSAScan Method: Closest Approach 3DError Surface: Pedal CurveWarning Method: Error RatioWELL DETAILS: Plan: MPU L-6216.50+N/-S +E/-WNorthingEastingLatittudeLongitude0.000.006031438.88545058.40 70° 29' 48.325 N 149° 37' 53.555 WSURVEY PROGRAMDate: 2020-05-06T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool33.10 900.00 MPU L-62 wp07 (MPU L-62) 3_Gyro-GC_Csg900.00 6867.97 MPU L-62 wp07 (MPU L-62) 3_MWD+IFR2+MS+Sag6867.97 13690.71 MPU L-62 wp07 (MPU L-62) 3_MWD+IFR2+MS+SagFORMATION TOP DETAILSTVDPath TVDssPath MDPath Formation1433.20 1383.00 1581.27 SV51908.20 1858.00 2442.72 BPRF2789.20 2739.00 4080.31 UG33097.20 3047.00 4652.82 UG COAL 13475.20 3425.00 5355.44 UGNU LA33752.20 3702.00 5908.93 UGNU MB3970.20 3920.00 6645.81 SCHRADER NA3995.20 3945.00 6937.45 SCHRADER NBREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU L-62, True NorthVertical (TVD) Reference:MPU L-62 As-built RKB @ 50.20usftMeasured Depth Reference:MPU L-62 As-built RKB @ 50.20usftCalculation Method:Minimum CurvatureProject:Milne PointSite:M Pt L PadWell:Plan: MPU L-62Wellbore:MPU L-62Design:MPU L-62 wp07CASING DETAILSTVD TVDSS MD SizeName3990.20 3940.00 6867.97 9-5/8 9 5/8" x 12 1/4"3820.20 3770.00 13690.71 6-5/8 6 5/8" x 8 1/2"SECTION DETAILSSec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation1 33.10 0.00 0.00 33.10 0.00 0.00 0.00 0.00 0.002 250.00 0.00 0.00 250.00 0.00 0.00 0.00 0.00 0.00 Start Dir 3º/100' : 250' MD, 250'TVD3 635.00 11.55 157.99 632.40 -35.86 14.49 3.00 157.99 31.83 Start Dir 4º/100' : 635' MD, 632.4'TVD4 1782.63 57.45 158.96 1553.09 -625.72 243.61 4.00 1.14 557.51 End Dir : 1782.63' MD, 1553.09' TVD5 5523.87 57.45 158.96 3565.81 -3569.13 1375.91 0.00 0.00 3183.03 Start Dir 4º/100' : 5523.87' MD, 3565.81'TVD6 5752.83 62.59 167.72 3680.35 -3758.90 1432.30 4.00 58.16 3355.93 End Dir : 5752.83' MD, 3680.35' TVD7 5902.83 62.59 167.72 3749.40 -3889.01 1460.62 0.00 0.00 3476.73 MPI-L-62 wp06 Base Pump End of ESP tangent8 6718.62 85.18 192.45 3977.65 -4660.71 1449.72 4.00 50.63 4232.22 End Dir : 6718.62' MD, 3977.65' TVD9 6867.97 85.18 192.45 3990.20 -4806.03 1417.63 0.00 0.00 4381.04 MPI-L-62 wp01 Heel Start Dir 2º/100' : 6867.97' MD, 3990.2'TVD10 7206.07 91.92 191.90 3998.75 -5136.22 1346.40 2.00 -4.67 4718.82 End Dir : 7206.07' MD, 3998.75' TVD11 10706.07 91.92 191.90 3881.48 -8559.08 625.09 0.00 0.00 8216.59 Start Dir 2º/100' : 10706.07' MD, 3881.48'TVD12 10795.01 91.17 193.51 3879.09 -8645.81 605.54 2.00 115.08 8305.50 End Dir : 10795.01' MD, 3879.09' TVD13 13690.71 91.17 193.51 3820.20 -11460.78 -70.88 0.00 0.00 11200.23 MPI-L-62 wp01 Toe Total Depth : 13690.71' MD, 3820.2' TVD -12000 -11250 -10500 -9750 -9000 -8250 -7500 -6750 -6000 -5250 -4500 -3750 -3000 -2250 -1500 -750 0 750 South(-)/North(+) (1500 usft/in)-3000 -2250 -1500 -750 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 West(-)/East(+) (1500 usft/in) MPI-L-62 wp06 Base Pump MPI-L-62 wp01 Toe MPI-L-62 wp01 Heel 9 5/8" x 12 1/4" 6 5/8" x 8 1/2" 1 0 0 0 1 5 0 0 1 7 5 0 2 0 0 0 2 2 5 0 2 5 0 0 2 7 5 0 3 0 0 0 3 2 5 0 3 5 0 0 37 5 0 4000 3820 MPUL-62wp07 Start Dir 3º/100' : 250' MD, 250'TVD Start Dir 4º/100' : 635' MD, 632.4'TVD End Dir : 1782.63' MD, 1553.09' TVD Start Dir 4º/100' : 5523.87' MD, 3565.81'TVD End Dir : 5752.83' MD, 3680.35' TVD Start of ESP tangent End of ESP tangent Start Dir 4º/100' : 5902.83' MD, 3749.4'TVD Fault #1 (20' Throw, DTN)End Dir : 6718.62' MD, 3977.65' TVD Start Dir 2º/100' : 6867.97' MD, 3990.2'TVD End Dir : 7206.07' MD, 3998.75' TVD Start Dir 2º/100' : 10706.07' MD, 3881.48'TVD End Dir : 10795.01' MD, 3879.09' TVD Total Depth : 13690.71' MD, 3820.2' TVD CASING DETAILS TVD TVDSS MD Size Name 3990.20 3940.00 6867.97 9-5/8 9 5/8" x 12 1/4" 3820.20 3770.00 13690.71 6-5/8 6 5/8" x 8 1/2" Project: Milne Point Site: M Pt L Pad Well: Plan: MPU L-62 Wellbore: MPU L-62 Plan: MPU L-62 wp07 WELL DETAILS: Plan: MPU L-62 16.50 +N/-S +E/-W Northing Easting Latittude Longitude 0.00 0.00 6031438.88 545058.40 70° 29' 48.325 N 149° 37' 53.555 W REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Plan: MPU L-62, True North Vertical (TVD) Reference:MPU L-62 As-built RKB @ 50.20usft Measured Depth Reference:MPU L-62 As-built RKB @ 50.20usft Calculation Method:Minimum Curvature Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt L Pad Halliburton Standard Proposal Report Well: Wellbore: Plan: MPU L-62 MPU L-62 Survey Calculation Method:Minimum Curvature MPU L-62 As-built RKB @ 50.20usft Design:MPU L-62 wp07 Database:NORTH US + CANADA MD Reference:MPU L-62 As-built RKB @ 50.20usft North Reference: Well Plan: MPU L-62 True Map System: Geo Datum: Project Map Zone: System Datum:US State Plane 1927 (Exact solution) NAD 1927 (NADCON CONUS) Milne Point, ACT, MILNE POINT Alaska Zone 04 Mean Sea Level Using Well Reference Point Using geodetic scale factor Site Position: From: Site Latitude: Longitude: Position Uncertainty: Northing: Easting: Grid Convergence: M Pt L Pad, TR-13-10 usft Map usft usft °0.34Slot Radius:"0 6,029,799.28 544,529.55 0.00 70° 29' 32.230 N 149° 38' 9.412 W Well Well Position Longitude: Latitude: Easting: Northing: usft +E/-W +N/-S Position Uncertainty usft usft usftGround Level: Plan: MPU L-62 usft usft 0.00 0.00 6,031,438.88 545,058.40 16.50Wellhead Elevation:17.10 usft0.50 70° 29' 48.325 N 149° 37' 53.555 W Wellbore Declination (°) Field Strength (nT) Sample Date Dip Angle (°) MPU L-62 Model NameMagnetics BGGM2020 11/6/2020 15.85 80.88 57,372.36068139 Phase:Version: Audit Notes: Design MPU L-62 wp07 PLAN Vertical Section: Depth From (TVD) (usft) +N/-S (usft) Direction (°) +E/-W (usft) Tie On Depth:33.10 192.600.000.0033.10 Inclination (°) Azimuth (°) +E/-W (usft) Tool Face (°) +N/-S (usft) Measured Depth (usft) Vertical Depth (usft) Dogleg Rate (°/100usft) Build Rate (°/100usft) Turn Rate (°/100usft) Plan Sections TVD System usft 0.000.000.000.000.000.0033.100.000.0033.10 -17.10 0.000.000.000.000.000.00250.000.000.00250.00 199.80 157.990.003.003.0014.49-35.86632.40157.9911.55635.00 582.20 1.140.084.004.00243.61-625.721,553.09158.9657.451,782.63 1,502.89 0.000.000.000.001,375.91-3,569.133,565.81158.9657.455,523.87 3,515.61 58.163.832.244.001,432.30-3,758.903,680.35167.7262.595,752.83 3,630.15 0.000.000.000.001,460.62-3,889.013,749.40167.7262.595,902.83 3,699.20 50.633.032.774.001,449.72-4,660.713,977.65192.4585.186,718.62 3,927.45 0.000.000.000.001,417.63-4,806.033,990.20192.4585.186,867.97 3,940.00 -4.67-0.161.992.001,346.40-5,136.223,998.75191.9091.927,206.07 3,948.55 0.000.000.000.00625.09-8,559.083,881.48191.9091.9210,706.07 3,831.28 115.081.81-0.852.00605.54-8,645.813,879.09193.5191.1710,795.01 3,828.89 0.000.000.000.00-70.88-11,460.783,820.20193.5191.1713,690.71 3,770.00 7/10/2020 2:30:32PM COMPASS 5000.15 Build 91E Page 2 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt L Pad Halliburton Standard Proposal Report Well: Wellbore: Plan: MPU L-62 MPU L-62 Survey Calculation Method:Minimum Curvature MPU L-62 As-built RKB @ 50.20usft Design:MPU L-62 wp07 Database:NORTH US + CANADA MD Reference:MPU L-62 As-built RKB @ 50.20usft North Reference: Well Plan: MPU L-62 True Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Map Northing (usft) Map Easting (usft) +N/-S (usft) Planned Survey Vertical Depth (usft) TVDss usft DLS -17.10 Vert Section 33.10 0.00 33.10 0.00 0.000.00 545,058.406,031,438.88-17.10 0.00 0.00 100.00 0.00 100.00 0.00 0.000.00 545,058.406,031,438.8849.80 0.00 0.00 200.00 0.00 200.00 0.00 0.000.00 545,058.406,031,438.88149.80 0.00 0.00 250.00 0.00 250.00 0.00 0.000.00 545,058.406,031,438.88199.80 0.00 0.00 Start Dir 3º/100' : 250' MD, 250'TVD 300.00 1.50 299.99 -0.61 0.25157.99 545,058.656,031,438.27249.79 3.00 0.54 400.00 4.50 399.85 -5.46 2.21157.99 545,060.646,031,433.44349.65 3.00 4.85 500.00 7.50 499.29 -15.15 6.12157.99 545,064.616,031,423.77449.09 3.00 13.45 600.00 10.50 598.04 -29.65 11.99157.99 545,070.566,031,409.31547.84 3.00 26.32 635.00 11.55 632.40 -35.86 14.49157.99 545,073.116,031,403.12582.20 3.00 31.83 Start Dir 4º/100' : 635' MD, 632.4'TVD 700.00 14.15 695.76 -49.27 19.88158.20 545,078.586,031,389.74645.56 4.00 43.74 800.00 18.15 791.80 -75.11 30.16158.41 545,089.016,031,363.96741.60 4.00 66.72 900.00 22.15 885.66 -107.15 42.79158.54 545,101.836,031,332.00835.46 4.00 95.23 1,000.00 26.15 976.89 -145.23 57.72158.64 545,116.996,031,294.02926.69 4.00 129.14 1,100.00 30.15 1,065.04 -189.17 74.87158.71 545,134.406,031,250.191,014.84 4.00 168.28 1,200.00 34.15 1,149.69 -238.75 94.15158.77 545,153.996,031,200.731,099.49 4.00 212.46 1,300.00 38.15 1,230.43 -293.73 115.49158.81 545,175.666,031,145.881,180.23 4.00 261.46 1,400.00 42.15 1,306.85 -353.84 138.77158.85 545,199.296,031,085.921,256.65 4.00 315.05 1,500.00 46.15 1,378.59 -418.80 163.87158.89 545,224.796,031,021.121,328.39 4.00 372.97 1,581.27 49.40 1,433.20 -474.94 185.53158.91 545,246.796,030,965.121,383.00 4.00 423.03 SV5 1,600.00 50.15 1,445.30 -488.28 190.68158.91 545,252.026,030,951.811,395.10 4.00 434.92 1,700.00 54.15 1,506.65 -561.94 219.06158.94 545,280.846,030,878.331,456.45 4.00 500.62 1,782.63 57.45 1,553.08 -625.72 243.61158.96 545,305.776,030,814.711,502.88 4.00 557.51 End Dir : 1782.63' MD, 1553.09' TVD 1,800.00 57.45 1,562.43 -639.38 248.87158.96 545,311.116,030,801.081,512.23 0.00 569.70 1,900.00 57.45 1,616.23 -718.06 279.13158.96 545,341.856,030,722.601,566.03 0.00 639.87 2,000.00 57.45 1,670.03 -796.73 309.40158.96 545,372.596,030,644.121,619.83 0.00 710.05 2,100.00 57.45 1,723.82 -875.41 339.66158.96 545,403.336,030,565.631,673.62 0.00 780.23 2,200.00 57.45 1,777.62 -954.08 369.93158.96 545,434.076,030,487.151,727.42 0.00 850.41 2,300.00 57.45 1,831.42 -1,032.76 400.19158.96 545,464.816,030,408.671,781.22 0.00 920.58 2,400.00 57.45 1,885.22 -1,111.43 430.46158.96 545,495.546,030,330.191,835.02 0.00 990.76 2,442.72 57.45 1,908.20 -1,145.04 443.39158.96 545,508.686,030,296.661,858.00 0.00 1,020.74 BPRF 2,500.00 57.45 1,939.02 -1,190.11 460.72158.96 545,526.286,030,251.711,888.82 0.00 1,060.94 2,600.00 57.45 1,992.82 -1,268.78 490.99158.96 545,557.026,030,173.221,942.62 0.00 1,131.12 2,700.00 57.45 2,046.61 -1,347.46 521.25158.96 545,587.766,030,094.741,996.41 0.00 1,201.30 2,800.00 57.45 2,100.41 -1,426.13 551.52158.96 545,618.506,030,016.262,050.21 0.00 1,271.47 2,900.00 57.45 2,154.21 -1,504.80 581.79158.96 545,649.246,029,937.782,104.01 0.00 1,341.65 3,000.00 57.45 2,208.01 -1,583.48 612.05158.96 545,679.986,029,859.292,157.81 0.00 1,411.83 3,100.00 57.45 2,261.81 -1,662.15 642.32158.96 545,710.726,029,780.812,211.61 0.00 1,482.01 3,200.00 57.45 2,315.61 -1,740.83 672.58158.96 545,741.466,029,702.332,265.41 0.00 1,552.19 3,300.00 57.45 2,369.41 -1,819.50 702.85158.96 545,772.196,029,623.852,319.21 0.00 1,622.36 3,400.00 57.45 2,423.20 -1,898.18 733.11158.96 545,802.936,029,545.372,373.00 0.00 1,692.54 7/10/2020 2:30:32PM COMPASS 5000.15 Build 91E Page 3 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt L Pad Halliburton Standard Proposal Report Well: Wellbore: Plan: MPU L-62 MPU L-62 Survey Calculation Method:Minimum Curvature MPU L-62 As-built RKB @ 50.20usft Design:MPU L-62 wp07 Database:NORTH US + CANADA MD Reference:MPU L-62 As-built RKB @ 50.20usft North Reference: Well Plan: MPU L-62 True Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Map Northing (usft) Map Easting (usft) +N/-S (usft) Planned Survey Vertical Depth (usft) TVDss usft DLS 2,426.80 Vert Section 3,500.00 57.45 2,477.00 -1,976.85 763.38158.96 545,833.676,029,466.882,426.80 0.00 1,762.72 3,600.00 57.45 2,530.80 -2,055.53 793.64158.96 545,864.416,029,388.402,480.60 0.00 1,832.90 3,700.00 57.45 2,584.60 -2,134.20 823.91158.96 545,895.156,029,309.922,534.40 0.00 1,903.07 3,800.00 57.45 2,638.40 -2,212.88 854.17158.96 545,925.896,029,231.442,588.20 0.00 1,973.25 3,900.00 57.45 2,692.20 -2,291.55 884.44158.96 545,956.636,029,152.952,642.00 0.00 2,043.43 4,000.00 57.45 2,746.00 -2,370.23 914.71158.96 545,987.376,029,074.472,695.80 0.00 2,113.61 4,080.31 57.45 2,789.20 -2,433.41 939.01158.96 546,012.056,029,011.442,739.00 0.00 2,169.97 UG3 4,100.00 57.45 2,799.79 -2,448.90 944.97158.96 546,018.116,028,995.992,749.59 0.00 2,183.79 4,200.00 57.45 2,853.59 -2,527.58 975.24158.96 546,048.846,028,917.512,803.39 0.00 2,253.96 4,300.00 57.45 2,907.39 -2,606.25 1,005.50158.96 546,079.586,028,839.032,857.19 0.00 2,324.14 4,400.00 57.45 2,961.19 -2,684.93 1,035.77158.96 546,110.326,028,760.542,910.99 0.00 2,394.32 4,500.00 57.45 3,014.99 -2,763.60 1,066.03158.96 546,141.066,028,682.062,964.79 0.00 2,464.50 4,600.00 57.45 3,068.79 -2,842.28 1,096.30158.96 546,171.806,028,603.583,018.59 0.00 2,534.67 4,652.82 57.45 3,097.20 -2,883.83 1,112.28158.96 546,188.036,028,562.133,047.00 0.00 2,571.74 UG COAL 1 4,700.00 57.45 3,122.58 -2,920.95 1,126.56158.96 546,202.546,028,525.103,072.38 0.00 2,604.85 4,800.00 57.45 3,176.38 -2,999.63 1,156.83158.96 546,233.286,028,446.613,126.18 0.00 2,675.03 4,900.00 57.45 3,230.18 -3,078.30 1,187.10158.96 546,264.026,028,368.133,179.98 0.00 2,745.21 5,000.00 57.45 3,283.98 -3,156.98 1,217.36158.96 546,294.756,028,289.653,233.78 0.00 2,815.39 5,100.00 57.45 3,337.78 -3,235.65 1,247.63158.96 546,325.496,028,211.173,287.58 0.00 2,885.56 5,200.00 57.45 3,391.58 -3,314.33 1,277.89158.96 546,356.236,028,132.693,341.38 0.00 2,955.74 5,300.00 57.45 3,445.38 -3,393.00 1,308.16158.96 546,386.976,028,054.203,395.18 0.00 3,025.92 5,355.44 57.45 3,475.20 -3,436.62 1,324.94158.96 546,404.016,028,010.693,425.00 0.00 3,064.82 UGNU LA3 5,400.00 57.45 3,499.17 -3,471.67 1,338.42158.96 546,417.716,027,975.723,448.97 0.00 3,096.10 5,500.00 57.45 3,552.97 -3,550.35 1,368.69158.96 546,448.456,027,897.243,502.77 0.00 3,166.28 5,523.87 57.45 3,565.81 -3,569.13 1,375.91158.96 546,455.796,027,878.503,515.61 0.00 3,183.03 Start Dir 4º/100' : 5523.87' MD, 3565.81'TVD 5,600.00 59.10 3,605.85 -3,630.15 1,397.55161.97 546,477.796,027,817.623,555.65 4.00 3,237.86 5,700.00 61.35 3,655.52 -3,713.51 1,421.61165.78 546,502.366,027,734.413,605.32 4.00 3,313.96 5,752.83 62.59 3,680.35 -3,758.90 1,432.30167.72 546,513.316,027,689.093,630.15 4.00 3,355.93 End Dir : 5752.83' MD, 3680.35' TVD 5,753.00 62.59 3,680.43 -3,759.05 1,432.33167.72 546,513.356,027,688.953,630.23 0.00 3,356.07 Start of ESP tangent 5,800.00 62.59 3,702.06 -3,799.82 1,441.20167.72 546,522.476,027,648.243,651.86 0.00 3,393.92 5,902.00 62.59 3,749.02 -3,888.30 1,460.46167.72 546,542.266,027,559.893,698.82 0.00 3,476.06 End of ESP tangent 5,902.83 62.59 3,749.40 -3,889.02 1,460.62167.72 546,542.426,027,559.173,699.20 0.00 3,476.73 Start Dir 4º/100' : 5902.83' MD, 3749.4'TVD 5,908.93 62.74 3,752.20 -3,894.31 1,461.76167.93 546,543.596,027,553.883,702.00 4.00 3,481.65 UGNU MB 6,000.00 65.09 3,792.24 -3,974.72 1,476.67171.03 546,558.996,027,473.573,742.04 4.00 3,556.87 6,100.00 67.75 3,832.25 -4,065.60 1,488.34174.30 546,571.216,027,382.773,782.05 4.00 3,643.02 7/10/2020 2:30:32PM COMPASS 5000.15 Build 91E Page 4 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt L Pad Halliburton Standard Proposal Report Well: Wellbore: Plan: MPU L-62 MPU L-62 Survey Calculation Method:Minimum Curvature MPU L-62 As-built RKB @ 50.20usft Design:MPU L-62 wp07 Database:NORTH US + CANADA MD Reference:MPU L-62 As-built RKB @ 50.20usft North Reference: Well Plan: MPU L-62 True Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Map Northing (usft) Map Easting (usft) +N/-S (usft) Planned Survey Vertical Depth (usft) TVDss usft DLS 3,795.04 Vert Section 6,135.00 68.69 3,845.24 -4,097.97 1,491.25175.42 546,574.316,027,350.423,795.04 4.00 3,673.97 Fault #1 (20' Throw, DTN) 6,200.00 70.46 3,867.93 -4,158.76 1,495.03177.45 546,578.476,027,289.673,817.73 4.00 3,732.47 6,300.00 73.22 3,899.10 -4,253.74 1,496.72180.49 546,580.736,027,194.703,848.90 4.00 3,824.80 6,400.00 76.03 3,925.60 -4,350.09 1,493.40183.44 546,577.996,027,098.353,875.40 4.00 3,919.55 6,500.00 78.88 3,947.32 -4,447.32 1,485.08186.32 546,570.266,027,001.083,897.12 4.00 4,016.26 6,600.00 81.75 3,964.15 -4,544.98 1,471.80189.15 546,557.586,026,903.353,913.95 4.00 4,114.46 6,645.81 83.07 3,970.20 -4,589.72 1,464.08190.43 546,550.136,026,858.563,920.00 4.00 4,159.81 SCHRADER NA 6,700.00 84.64 3,976.00 -4,642.58 1,453.63191.93 546,540.006,026,805.653,925.80 4.00 4,213.67 6,718.62 85.18 3,977.65 -4,660.70 1,449.72192.45 546,536.206,026,787.503,927.45 4.00 4,232.21 End Dir : 6718.62' MD, 3977.65' TVD 6,800.00 85.18 3,984.49 -4,739.89 1,432.24192.45 546,519.206,026,708.223,934.29 0.00 4,313.30 6,867.97 85.18 3,990.20 -4,806.03 1,417.63192.45 546,505.006,026,642.003,940.00 0.00 4,381.03 Start Dir 2º/100' : 6867.97' MD, 3990.2'TVD - 9 5/8" x 12 1/4" 6,900.00 85.82 3,992.71 -4,837.21 1,410.77192.40 546,498.326,026,610.783,942.51 2.00 4,412.96 6,937.45 86.57 3,995.20 -4,873.71 1,402.76192.34 546,490.546,026,574.243,945.00 2.00 4,450.33 SCHRADER NB 7,000.00 87.81 3,998.27 -4,934.75 1,389.47192.23 546,477.626,026,513.123,948.07 2.00 4,512.80 7,100.00 89.81 4,000.35 -5,032.49 1,368.42192.07 546,457.176,026,415.273,950.15 2.00 4,612.77 7,206.07 91.92 3,998.75 -5,136.23 1,346.40191.90 546,435.776,026,311.413,948.55 2.00 4,718.82 End Dir : 7206.07' MD, 3998.75' TVD 7,300.00 91.92 3,995.60 -5,228.08 1,327.04191.90 546,416.986,026,219.453,945.40 0.00 4,812.69 7,400.00 91.92 3,992.25 -5,325.88 1,306.43191.90 546,396.966,026,121.543,942.05 0.00 4,912.63 7,500.00 91.92 3,988.90 -5,423.68 1,285.82191.90 546,376.956,026,023.633,938.70 0.00 5,012.56 7,600.00 91.92 3,985.55 -5,521.47 1,265.21191.90 546,356.946,025,925.723,935.35 0.00 5,112.50 7,700.00 91.92 3,982.20 -5,619.27 1,244.61191.90 546,336.926,025,827.813,932.00 0.00 5,212.44 7,800.00 91.92 3,978.85 -5,717.06 1,224.00191.90 546,316.916,025,729.903,928.65 0.00 5,312.37 7,900.00 91.92 3,975.50 -5,814.86 1,203.39191.90 546,296.896,025,631.993,925.30 0.00 5,412.31 8,000.00 91.92 3,972.15 -5,912.66 1,182.78191.90 546,276.886,025,534.083,921.95 0.00 5,512.25 8,100.00 91.92 3,968.80 -6,010.45 1,162.17191.90 546,256.876,025,436.173,918.60 0.00 5,612.18 8,200.00 91.92 3,965.45 -6,108.25 1,141.56191.90 546,236.856,025,338.263,915.25 0.00 5,712.12 8,300.00 91.92 3,962.10 -6,206.04 1,120.95191.90 546,216.846,025,240.353,911.90 0.00 5,812.05 8,400.00 91.92 3,958.75 -6,303.84 1,100.34191.90 546,196.836,025,142.443,908.55 0.00 5,911.99 8,500.00 91.92 3,955.40 -6,401.64 1,079.74191.90 546,176.816,025,044.533,905.20 0.00 6,011.93 8,600.00 91.92 3,952.05 -6,499.43 1,059.13191.90 546,156.806,024,946.623,901.85 0.00 6,111.86 8,700.00 91.92 3,948.70 -6,597.23 1,038.52191.90 546,136.786,024,848.713,898.50 0.00 6,211.80 8,800.00 91.92 3,945.35 -6,695.02 1,017.91191.90 546,116.776,024,750.803,895.15 0.00 6,311.74 8,900.00 91.92 3,942.00 -6,792.82 997.30191.90 546,096.766,024,652.893,891.80 0.00 6,411.67 9,000.00 91.92 3,938.64 -6,890.62 976.69191.90 546,076.746,024,554.983,888.44 0.00 6,511.61 9,100.00 91.92 3,935.29 -6,988.41 956.08191.90 546,056.736,024,457.073,885.09 0.00 6,611.55 9,200.00 91.92 3,931.94 -7,086.21 935.47191.90 546,036.726,024,359.163,881.74 0.00 6,711.48 9,300.00 91.92 3,928.59 -7,184.00 914.86191.90 546,016.706,024,261.263,878.39 0.00 6,811.42 9,400.00 91.92 3,925.24 -7,281.80 894.26191.90 545,996.696,024,163.353,875.04 0.00 6,911.35 9,500.00 91.92 3,921.89 -7,379.60 873.65191.90 545,976.686,024,065.443,871.69 0.00 7,011.29 7/10/2020 2:30:32PM COMPASS 5000.15 Build 91E Page 5 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt L Pad Halliburton Standard Proposal Report Well: Wellbore: Plan: MPU L-62 MPU L-62 Survey Calculation Method:Minimum Curvature MPU L-62 As-built RKB @ 50.20usft Design:MPU L-62 wp07 Database:NORTH US + CANADA MD Reference:MPU L-62 As-built RKB @ 50.20usft North Reference: Well Plan: MPU L-62 True Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Map Northing (usft) Map Easting (usft) +N/-S (usft) Planned Survey Vertical Depth (usft) TVDss usft DLS 3,868.34 Vert Section 9,600.00 91.92 3,918.54 -7,477.39 853.04191.90 545,956.666,023,967.533,868.34 0.00 7,111.23 9,700.00 91.92 3,915.19 -7,575.19 832.43191.90 545,936.656,023,869.623,864.99 0.00 7,211.16 9,800.00 91.92 3,911.84 -7,672.98 811.82191.90 545,916.636,023,771.713,861.64 0.00 7,311.10 9,900.00 91.92 3,908.49 -7,770.78 791.21191.90 545,896.626,023,673.803,858.29 0.00 7,411.04 10,000.00 91.92 3,905.14 -7,868.58 770.60191.90 545,876.616,023,575.893,854.94 0.00 7,510.97 10,100.00 91.92 3,901.79 -7,966.37 749.99191.90 545,856.596,023,477.983,851.59 0.00 7,610.91 10,200.00 91.92 3,898.44 -8,064.17 729.38191.90 545,836.586,023,380.073,848.24 0.00 7,710.85 10,300.00 91.92 3,895.09 -8,161.96 708.78191.90 545,816.576,023,282.163,844.89 0.00 7,810.78 10,400.00 91.92 3,891.74 -8,259.76 688.17191.90 545,796.556,023,184.253,841.54 0.00 7,910.72 10,500.00 91.92 3,888.39 -8,357.56 667.56191.90 545,776.546,023,086.343,838.19 0.00 8,010.66 10,600.00 91.92 3,885.04 -8,455.35 646.95191.90 545,756.526,022,988.433,834.84 0.00 8,110.59 10,706.07 91.92 3,881.48 -8,559.08 625.09191.90 545,735.306,022,884.583,831.28 0.00 8,216.59 Start Dir 2º/100' : 10706.07' MD, 3881.48'TVD 10,795.01 91.17 3,879.09 -8,645.81 605.54193.51 545,716.276,022,797.743,828.89 2.00 8,305.50 End Dir : 10795.01' MD, 3879.09' TVD 10,800.00 91.17 3,878.99 -8,650.66 604.37193.51 545,715.136,022,792.893,828.79 0.00 8,310.49 10,900.00 91.17 3,876.96 -8,747.87 581.01193.51 545,692.376,022,695.543,826.76 0.00 8,410.45 11,000.00 91.17 3,874.92 -8,845.09 557.65193.51 545,669.606,022,598.203,824.72 0.00 8,510.42 11,100.00 91.17 3,872.89 -8,942.30 534.29193.51 545,646.836,022,500.863,822.69 0.00 8,610.39 11,200.00 91.17 3,870.85 -9,039.51 510.93193.51 545,624.066,022,403.523,820.65 0.00 8,710.35 11,300.00 91.17 3,868.82 -9,136.72 487.57193.51 545,601.306,022,306.173,818.62 0.00 8,810.32 11,400.00 91.17 3,866.79 -9,233.93 464.21193.51 545,578.536,022,208.833,816.59 0.00 8,910.29 11,500.00 91.17 3,864.75 -9,331.15 440.86193.51 545,555.766,022,111.493,814.55 0.00 9,010.25 11,600.00 91.17 3,862.72 -9,428.36 417.50193.51 545,533.006,022,014.153,812.52 0.00 9,110.22 11,700.00 91.17 3,860.69 -9,525.57 394.14193.51 545,510.236,021,916.803,810.49 0.00 9,210.19 11,800.00 91.17 3,858.65 -9,622.78 370.78193.51 545,487.466,021,819.463,808.45 0.00 9,310.15 11,900.00 91.17 3,856.62 -9,720.00 347.42193.51 545,464.696,021,722.123,806.42 0.00 9,410.12 12,000.00 91.17 3,854.58 -9,817.21 324.06193.51 545,441.936,021,624.783,804.38 0.00 9,510.09 12,100.00 91.17 3,852.55 -9,914.42 300.70193.51 545,419.166,021,527.433,802.35 0.00 9,610.05 12,200.00 91.17 3,850.52 -10,011.63 277.34193.51 545,396.396,021,430.093,800.32 0.00 9,710.02 12,300.00 91.17 3,848.48 -10,108.84 253.98193.51 545,373.636,021,332.753,798.28 0.00 9,809.99 12,400.00 91.17 3,846.45 -10,206.06 230.62193.51 545,350.866,021,235.413,796.25 0.00 9,909.95 12,500.00 91.17 3,844.42 -10,303.27 207.26193.51 545,328.096,021,138.063,794.22 0.00 10,009.92 12,600.00 91.17 3,842.38 -10,400.48 183.90193.51 545,305.326,021,040.723,792.18 0.00 10,109.89 12,700.00 91.17 3,840.35 -10,497.69 160.55193.51 545,282.566,020,943.383,790.15 0.00 10,209.85 12,800.00 91.17 3,838.31 -10,594.91 137.19193.51 545,259.796,020,846.043,788.11 0.00 10,309.82 12,900.00 91.17 3,836.28 -10,692.12 113.83193.51 545,237.026,020,748.693,786.08 0.00 10,409.79 13,000.00 91.17 3,834.25 -10,789.33 90.47193.51 545,214.256,020,651.353,784.05 0.00 10,509.75 13,100.00 91.17 3,832.21 -10,886.54 67.11193.51 545,191.496,020,554.013,782.01 0.00 10,609.72 13,200.00 91.17 3,830.18 -10,983.75 43.75193.51 545,168.726,020,456.673,779.98 0.00 10,709.69 13,300.00 91.17 3,828.15 -11,080.97 20.39193.51 545,145.956,020,359.323,777.95 0.00 10,809.65 13,400.00 91.17 3,826.11 -11,178.18 -2.97193.51 545,123.196,020,261.983,775.91 0.00 10,909.62 13,500.00 91.17 3,824.08 -11,275.39 -26.33193.51 545,100.426,020,164.643,773.88 0.00 11,009.59 13,600.00 91.17 3,822.04 -11,372.60 -49.69193.51 545,077.656,020,067.303,771.84 0.00 11,109.55 7/10/2020 2:30:32PM COMPASS 5000.15 Build 91E Page 6 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt L Pad Halliburton Standard Proposal Report Well: Wellbore: Plan: MPU L-62 MPU L-62 Survey Calculation Method:Minimum Curvature MPU L-62 As-built RKB @ 50.20usft Design:MPU L-62 wp07 Database:NORTH US + CANADA MD Reference:MPU L-62 As-built RKB @ 50.20usft North Reference: Well Plan: MPU L-62 True Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Map Northing (usft) Map Easting (usft) +N/-S (usft) Planned Survey Vertical Depth (usft) TVDss usft DLS 3,770.00 Vert Section 13,690.71 91.17 3,820.20 -11,460.78 -70.88193.51 545,057.006,019,979.003,770.00 0.00 11,200.23 Total Depth : 13690.71' MD, 3820.2' TVD Target Name - hit/miss target - Shape TVD (usft) Northing (usft) Easting (usft) +N/-S (usft) +E/-W (usft) Tar gets Dip Angle (°) Dip Dir. (°) MPI-L-62 wp06 Base Pump 3,749.40 6,027,559.17 546,542.42-3,889.01 1,460.620.00 0.00 -plan hits target center - Point MPI-L-62 wp01 Heel 3,990.20 6,026,642.00 546,505.00-4,806.03 1,417.630.00 0.00 -plan hits target center - Circle (radius 30.00) MPI-L-62 wp01 Toe 3,820.20 6,019,979.00 545,057.00-11,460.78 -70.880.00 0.00 -plan hits target center - Point Vertical Depth (usft) Measured Depth (usft) Casing Diameter (") Hole Diameter (")Name Casing Points 9 5/8" x 12 1/4"3,990.206,867.97 9-5/8 12-1/4 6 5/8" x 8 1/2"3,820.2013,690.71 6-5/8 8-1/2 Measured Depth (usft) Vertical Depth (usft) Dip Direction (°)Name Lithology Dip (°) Formations Vertical Depth SS 4,080.31 2,789.20 UG3 0.00 6,937.45 3,995.20 SCHRADER NB 0.00 4,652.82 3,097.20 UG COAL 1 0.00 2,442.72 1,908.20 BPRF 0.00 6,645.81 3,970.20 SCHRADER NA 0.00 5,908.93 3,752.20 UGNU MB 0.00 5,355.44 3,475.20 UGNU LA3 0.00 1,581.27 1,433.20 SV5 0.00 7/10/2020 2:30:32PM COMPASS 5000.15 Build 91E Page 7 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt L Pad Halliburton Standard Proposal Report Well: Wellbore: Plan: MPU L-62 MPU L-62 Survey Calculation Method:Minimum Curvature MPU L-62 As-built RKB @ 50.20usft Design:MPU L-62 wp07 Database:NORTH US + CANADA MD Reference:MPU L-62 As-built RKB @ 50.20usft North Reference: Well Plan: MPU L-62 True Measured Depth (usft) Vertical Depth (usft) +E/-W (usft) +N/-S (usft) Local Coordinates Comment Plan Annotations 250.00 250.00 0.00 0.00 Start Dir 3º/100' : 250' MD, 250'TVD 635.00 632.40 -35.86 14.49 Start Dir 4º/100' : 635' MD, 632.4'TVD 1,782.63 1,553.08 -625.72 243.61 End Dir : 1782.63' MD, 1553.09' TVD 5,523.87 3,565.81 -3,569.13 1,375.91 Start Dir 4º/100' : 5523.87' MD, 3565.81'TVD 5,752.83 3,680.35 -3,758.90 1,432.30 End Dir : 5752.83' MD, 3680.35' TVD 5,753.00 3,680.43 -3,759.05 1,432.33 Start of ESP tangent 5,902.00 3,749.02 -3,888.30 1,460.46 End of ESP tangent 5,902.83 3,749.40 -3,889.02 1,460.62 Start Dir 4º/100' : 5902.83' MD, 3749.4'TVD 6,135.00 3,845.24 -4,097.97 1,491.25 Fault #1 (20' Throw, DTN) 6,718.62 3,977.65 -4,660.70 1,449.72 End Dir : 6718.62' MD, 3977.65' TVD 6,867.97 3,990.20 -4,806.03 1,417.63 Start Dir 2º/100' : 6867.97' MD, 3990.2'TVD 7,206.07 3,998.75 -5,136.23 1,346.40 End Dir : 7206.07' MD, 3998.75' TVD 10,706.07 3,881.48 -8,559.08 625.09 Start Dir 2º/100' : 10706.07' MD, 3881.48'TVD 10,795.01 3,879.09 -8,645.81 605.54 End Dir : 10795.01' MD, 3879.09' TVD 13,690.71 3,820.20 -11,460.78 -70.88 Total Depth : 13690.71' MD, 3820.2' TVD 7/10/2020 2:30:32PM COMPASS 5000.15 Build 91E Page 8 10 July, 2020Milne PointM Pt L PadPlan: MPU L-62MPU L-62MPU L-62 wp07Reference Design: M Pt L Pad - Plan: MPU L-62 - MPU L-62 - MPU L-62 wp07Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Well Coordinates: 6,031,438.88 N, 545,058.40 E (70° 29' 48.33" N, 149° 37' 53.55" W)Datum Height: MPU L-62 As-built RKB @ 50.20usftScan Range: 33.10 to 6,867.97 usft. Measured Depth.Geodetic Scale Factor AppliedVersion: 5000.15 Build: 91EScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftNO GLOBAL FILTER: Using user defined selection & filtering criteriaScan Type:Scan Type:25.00 Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU L-62 - MPU L-62 wp07Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftSite NameScan Range: 33.10 to 6,867.97 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Reference Design: M Pt L Pad - Plan: MPU L-62 - MPU L-62 - MPU L-62 wp07MeasuredDepth(usft)Summary Based on MinimumSeparation WarningM Pt L PadMPL-02 - MPL-02 - MPL-02237.44 33.10 236.03 39.00 168.19833.10Centre Distance Pass - MPL-02 - MPL-02 - MPL-02237.80 308.10 234.73 313.68 77.439308.10Ellipse Separation Pass - MPL-02 - MPL-02 - MPL-02291.17 933.10 283.04 922.10 35.830933.10Clearance Factor Pass - MPL-02 - MPL-02A - MPL-02A237.44 33.10 236.03 39.00 168.19833.10Centre Distance Pass - MPL-02 - MPL-02A - MPL-02A237.80 308.10 234.73 313.68 77.439308.10Ellipse Separation Pass - MPL-02 - MPL-02A - MPL-02A291.17 933.10 283.04 922.10 35.830933.10Clearance Factor Pass - MPL-02 - MPL-02AL1 - MPL-02AL1237.44 33.10 236.03 39.00 168.19833.10Centre Distance Pass - MPL-02 - MPL-02AL1 - MPL-02AL1237.80 308.10 234.73 313.68 77.439308.10Ellipse Separation Pass - MPL-02 - MPL-02AL1 - MPL-02AL1291.17 933.10 283.04 922.10 35.830933.10Clearance Factor Pass - MPL-02 - MPL-02AL2 - MPL-02AL2237.44 33.10 236.03 39.00 168.19833.10Centre Distance Pass - MPL-02 - MPL-02AL2 - MPL-02AL2237.80 308.10 234.73 313.68 77.439308.10Ellipse Separation Pass - MPL-02 - MPL-02AL2 - MPL-02AL2291.17 933.10 283.04 922.10 35.830933.10Clearance Factor Pass - MPL-02 - MPL-02APB1 - MPL-02APB1237.44 33.10 236.03 39.00 168.19833.10Centre Distance Pass - MPL-02 - MPL-02APB1 - MPL-02APB1237.80 308.10 234.73 313.68 77.439308.10Ellipse Separation Pass - MPL-02 - MPL-02APB1 - MPL-02APB1291.17 933.10 283.04 922.10 35.830933.10Clearance Factor Pass - MPL-02 - MPL-02APB2 - MPL-02APB2237.44 33.10 236.03 39.00 168.19833.10Centre Distance Pass - MPL-02 - MPL-02APB2 - MPL-02APB2237.80 308.10 234.73 313.68 77.439308.10Ellipse Separation Pass - MPL-02 - MPL-02APB2 - MPL-02APB2291.17 933.10 283.04 922.10 35.830933.10Clearance Factor Pass - MPL-04 - MPL-04 - MPL-04103.71 33.10 102.30 39.00 73.46633.10Centre Distance Pass - MPL-04 - MPL-04 - MPL-04104.97 458.10 100.65 462.39 24.282458.10Ellipse Separation Pass - MPL-04 - MPL-04 - MPL-04118.39 683.10 112.27 678.47 19.333683.10Clearance Factor Pass - MPL-05 - MPL-05 - MPL-0544.10 33.10 42.69 39.00 31.24333.10Centre Distance Pass - MPL-05 - MPL-05 - MPL-0545.98 383.10 42.33 388.39 12.609383.10Ellipse Separation Pass - MPL-05 - MPL-05 - MPL-0552.16 558.10 47.11 561.61 10.336558.10Clearance Factor Pass - MPL-06 - MPL-06 - MPL-06161.67 722.42 155.24 731.16 25.168722.42Centre Distance Pass - MPL-06 - MPL-06 - MPL-06161.69 733.10 155.17 741.88 24.800733.10Ellipse Separation Pass - MPL-06 - MPL-06 - MPL-06172.86 908.10 164.81 911.65 21.489908.10Clearance Factor Pass - MPL-07 - MPL-07 - MPL-07211.14 33.10 209.57 39.00 134.66233.10Centre Distance Pass - 10 July, 2020-14:45COMPASSPage 2 of 8 Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU L-62 - MPU L-62 wp07Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftSite NameScan Range: 33.10 to 6,867.97 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Reference Design: M Pt L Pad - Plan: MPU L-62 - MPU L-62 - MPU L-62 wp07MeasuredDepth(usft)Summary Based on MinimumSeparation WarningMPL-07 - MPL-07 - MPL-07211.17 58.10 209.53 63.37 129.03558.10Ellipse Separation Pass - MPL-07 - MPL-07 - MPL-07282.53 758.10 276.02 722.20 43.403758.10Clearance Factor Pass - MPL-07 - MPL-07PB1 - MPL-07PB1211.14 33.10 209.57 39.00 134.66233.10Centre Distance Pass - MPL-07 - MPL-07PB1 - MPL-07PB1211.17 58.10 209.53 63.37 129.03558.10Ellipse Separation Pass - MPL-07 - MPL-07PB1 - MPL-07PB1282.53 758.10 276.02 722.20 43.403758.10Clearance Factor Pass - MPL-11 - MPL-11 - MPL-1116.25 33.10 14.68 34.00 10.36433.10Centre Distance Pass - MPL-11 - MPL-11 - MPL-1116.26 58.10 14.65 58.88 10.05958.10Ellipse Separation Pass - MPL-11 - MPL-11 - MPL-1119.82 383.10 16.76 383.56 6.467383.10Clearance Factor Pass - MPL-12 - MPL-12 - MPL-12218.77 331.33 215.18 332.48 61.027331.33Centre Distance Pass - MPL-12 - MPL-12 - MPL-12219.94 533.10 214.16 533.74 38.046533.10Ellipse Separation Pass - MPL-12 - MPL-12 - MPL-121,497.31 4,308.10 1,386.66 4,324.23 13.5324,308.10Clearance Factor Pass - MPL-35 - MPL-35 - MPL-35133.48 229.27 131.00 229.47 53.644229.27Centre Distance Pass - MPL-35 - MPL-35 - MPL-35134.43 508.10 129.83 504.59 29.214508.10Ellipse Separation Pass - MPL-35 - MPL-35 - MPL-35161.84 908.10 153.81 887.12 20.170908.10Clearance Factor Pass - MPL-35 - MPL-35A - MPL-35A133.48 229.27 131.00 230.27 53.644229.27Centre Distance Pass - MPL-35 - MPL-35A - MPL-35A134.43 508.10 129.83 505.39 29.214508.10Ellipse Separation Pass - MPL-35 - MPL-35A - MPL-35A161.84 908.10 153.81 887.92 20.170908.10Clearance Factor Pass - MPL-35 - MPL-35APB1 - MPL-35APB1133.48 229.27 131.00 230.27 53.644229.27Centre Distance Pass - MPL-35 - MPL-35APB1 - MPL-35APB1134.43 508.10 129.83 505.39 29.214508.10Ellipse Separation Pass - MPL-35 - MPL-35APB1 - MPL-35APB1161.84 908.10 153.81 887.92 20.170908.10Clearance Factor Pass - MPL-35 - MPL-35APB2 - MPL-35APB2133.48 229.27 131.00 230.27 53.644229.27Centre Distance Pass - MPL-35 - MPL-35APB2 - MPL-35APB2134.43 508.10 129.83 505.39 29.214508.10Ellipse Separation Pass - MPL-35 - MPL-35APB2 - MPL-35APB2161.84 908.10 153.81 887.92 20.170908.10Clearance Factor Pass - MPL-35 - MPL-35APB3 - MPL-35APB3133.48 229.27 131.00 230.27 53.644229.27Centre Distance Pass - MPL-35 - MPL-35APB3 - MPL-35APB3134.43 508.10 129.83 505.39 29.214508.10Ellipse Separation Pass - MPL-35 - MPL-35APB3 - MPL-35APB3161.84 908.10 153.81 887.92 20.170908.10Clearance Factor Pass - MPL-36 - MPL-36 - MPL-3673.90 220.61 71.36 220.66 29.156220.61Centre Distance Pass - MPL-36 - MPL-36 - MPL-3674.14 308.10 70.98 307.30 23.430308.10Ellipse Separation Pass - MPL-36 - MPL-36 - MPL-3688.62 633.10 82.90 626.21 15.491633.10Clearance Factor Pass - MPL-36 - MPL-36L1 - MPL-36L173.90 220.61 71.36 220.66 29.156220.61Centre Distance Pass - 10 July, 2020-14:45COMPASSPage 3 of 8 Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU L-62 - MPU L-62 wp07Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftSite NameScan Range: 33.10 to 6,867.97 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Reference Design: M Pt L Pad - Plan: MPU L-62 - MPU L-62 - MPU L-62 wp07MeasuredDepth(usft)Summary Based on MinimumSeparation WarningMPL-36 - MPL-36L1 - MPL-36L174.14 308.10 70.98 307.30 23.430308.10Ellipse Separation Pass - MPL-36 - MPL-36L1 - MPL-36L188.62 633.10 82.90 626.21 15.491633.10Clearance Factor Pass - MPL-36 - MPL-36L1 PB1 - MPL-36L1 PB173.90 220.61 71.36 220.66 29.156220.61Centre Distance Pass - MPL-36 - MPL-36L1 PB1 - MPL-36L1 PB174.14 308.10 70.98 307.30 23.430308.10Ellipse Separation Pass - MPL-36 - MPL-36L1 PB1 - MPL-36L1 PB188.62 633.10 82.90 626.21 15.491633.10Clearance Factor Pass - MPL-36 - MPL-36PB1 - MPL-36PB173.90 220.61 71.36 220.66 29.156220.61Centre Distance Pass - MPL-36 - MPL-36PB1 - MPL-36PB174.14 308.10 70.98 307.30 23.430308.10Ellipse Separation Pass - MPL-36 - MPL-36PB1 - MPL-36PB188.62 633.10 82.90 626.21 15.491633.10Clearance Factor Pass - MPL-37 - MPL-37 - MPL-3711.97 352.06 8.58 339.31 3.536352.06Centre Distance Pass - MPL-37 - MPL-37 - MPL-3712.09 383.10 8.47 370.27 3.339383.10Ellipse Separation Pass - MPL-37 - MPL-37 - MPL-3712.99 433.10 8.98 420.12 3.238433.10Clearance Factor Pass - MPL-37 - MPL-37A - MPL-37A11.97 352.06 8.58 348.51 3.536352.06Centre Distance Pass - MPL-37 - MPL-37A - MPL-37A12.09 383.10 8.47 379.47 3.339383.10Ellipse Separation Pass - MPL-37 - MPL-37A - MPL-37A12.99 433.10 8.98 429.32 3.238433.10Clearance Factor Pass - MPL-40 - MPL-40 - MPL-40221.34 33.10 219.92 33.49 156.64833.10Centre Distance Pass - MPL-40 - MPL-40 - MPL-40221.66 133.10 219.73 132.05 114.674133.10Ellipse Separation Pass - MPL-40 - MPL-40 - MPL-40273.90 908.10 265.89 864.59 34.233908.10Clearance Factor Pass - MPL-46 - MPL-46 - MPL-46105.14 33.10 103.73 30.40 74.38833.10Centre Distance Pass - MPL-46 - MPL-46 - MPL-46106.19 283.10 102.54 279.20 29.078283.10Ellipse Separation Pass - MPL-46 - MPL-46 - MPL-46287.19 6,658.10 178.49 9,353.16 2.6426,658.10Clearance Factor Pass - MPL-46 - MPL-46 PB1 - MPL-46 PB1105.14 33.10 103.73 30.40 74.38833.10Centre Distance Pass - MPL-46 - MPL-46 PB1 - MPL-46 PB1106.19 283.10 102.54 279.20 29.078283.10Ellipse Separation Pass - MPL-46 - MPL-46 PB1 - MPL-46 PB1287.19 6,658.10 178.32 9,353.16 2.6386,658.10Clearance Factor Pass - MPL-47 - MPL-47 - MPL-47222.99 465.74 217.11 483.96 37.900465.74Centre Distance Pass - MPL-47 - MPL-47 - MPL-47223.04 483.10 216.97 501.27 36.693483.10Ellipse Separation Pass - MPL-47 - MPL-47 - MPL-47283.21 983.10 271.33 1,008.28 23.824983.10Clearance Factor Pass - MPL-47 - MPL-47 PB1 - MPL-47 PB1222.99 465.74 217.11 483.96 37.900465.74Centre Distance Pass - MPL-47 - MPL-47 PB1 - MPL-47 PB1223.04 483.10 216.97 501.27 36.693483.10Ellipse Separation Pass - MPL-47 - MPL-47 PB1 - MPL-47 PB1283.21 983.10 271.33 1,008.28 23.824983.10Clearance Factor Pass - MPL-48 - MPL-48 - MPL-4875.56 33.10 74.15 30.40 53.45933.10Centre Distance Pass - 10 July, 2020-14:45COMPASSPage 4 of 8 Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU L-62 - MPU L-62 wp07Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftSite NameScan Range: 33.10 to 6,867.97 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Reference Design: M Pt L Pad - Plan: MPU L-62 - MPU L-62 - MPU L-62 wp07MeasuredDepth(usft)Summary Based on MinimumSeparation WarningMPL-48 - MPL-48 - MPL-4876.68 358.10 72.19 355.22 17.097358.10Ellipse Separation Pass - MPL-48 - MPL-48 - MPL-48666.56 6,867.97 541.30 9,779.58 5.3216,867.97Clearance Factor Pass - MPL-48 - MPL-48PB1 - MPL-48PB175.56 33.10 74.15 30.40 53.45933.10Centre Distance Pass - MPL-48 - MPL-48PB1 - MPL-48PB176.68 358.10 72.19 355.22 17.097358.10Ellipse Separation Pass - MPL-48 - MPL-48PB1 - MPL-48PB199.83 783.10 90.39 778.14 10.574783.10Clearance Factor Pass - MPL-48 - MPL-48PB2 - MPL-48PB275.56 33.10 74.15 30.40 53.45933.10Centre Distance Pass - MPL-48 - MPL-48PB2 - MPL-48PB276.68 358.10 72.19 355.22 17.097358.10Ellipse Separation Pass - MPL-48 - MPL-48PB2 - MPL-48PB299.83 783.10 90.39 778.14 10.574783.10Clearance Factor Pass - MPL-48 - MPL-48PB3 - MPL-48 PB375.56 33.10 74.15 30.40 53.45933.10Centre Distance Pass - MPL-48 - MPL-48PB3 - MPL-48 PB376.68 358.10 72.19 355.22 17.097358.10Ellipse Separation Pass - MPL-48 - MPL-48PB3 - MPL-48 PB3800.04 6,867.97 632.96 9,257.00 4.7896,867.97Clearance Factor Pass - MPL-49 - MPL-49 - MPL-49198.05 113.27 196.09 110.07 101.174113.27Centre Distance Pass - MPL-49 - MPL-49 - MPL-49198.54 258.10 195.09 253.68 57.592258.10Ellipse Separation Pass - MPL-49 - MPL-49 - MPL-49793.73 6,058.10 687.82 7,755.91 7.4956,058.10Clearance Factor Pass - MPL-50 - MPL-50 - MPL-5046.18 33.10 44.50 34.40 27.48533.10Centre Distance Pass - MPL-50 - MPL-50 - MPL-5049.99 892.46 41.65 906.67 5.996892.46Ellipse Separation Pass - MPL-50 - MPL-50 - MPL-5050.13 908.10 41.77 922.34 5.994908.10Clearance Factor Pass - MPU L-60 - MPU L-60 - MPU L-60117.12 344.47 114.35 344.01 42.299344.47Centre Distance Pass - MPU L-60 - MPU L-60 - MPU L-60117.19 383.10 114.25 381.70 39.749383.10Ellipse Separation Pass - MPU L-60 - MPU L-60 - MPU L-601,461.29 5,858.10 1,341.49 5,554.68 12.1985,858.10Clearance Factor Pass - MPU L-60 - MPU L-60PB1 - MPU L-60PB1117.12 344.47 114.35 344.01 42.299344.47Centre Distance Pass - MPU L-60 - MPU L-60PB1 - MPU L-60PB1117.19 383.10 114.25 381.70 39.749383.10Ellipse Separation Pass - MPU L-60 - MPU L-60PB1 - MPU L-60PB11,461.29 5,858.10 1,341.49 5,554.68 12.1985,858.10Clearance Factor Pass - MPU L-60 - MPU L-60PB2 - MPU L-60PB2117.12 344.47 114.35 344.01 42.299344.47Centre Distance Pass - MPU L-60 - MPU L-60PB2 - MPU L-60PB2117.19 383.10 114.25 381.70 39.749383.10Ellipse Separation Pass - MPU L-60 - MPU L-60PB2 - MPU L-60PB21,461.29 5,858.10 1,341.49 5,554.68 12.1985,858.10Clearance Factor Pass - MPU L-60 - MPU L-60PB3 - MPU L-60PB3117.12 344.47 114.35 344.01 42.299344.47Centre Distance Pass - MPU L-60 - MPU L-60PB3 - MPU L-60PB3117.19 383.10 114.25 381.70 39.749383.10Ellipse Separation Pass - MPU L-60 - MPU L-60PB3 - MPU L-60PB31,461.29 5,858.10 1,341.49 5,554.68 12.1985,858.10Clearance Factor Pass - Plan: MPU L-61i - MPU L-61i - MPU L-61i wp07489.37 233.10 487.00 231.80 206.163233.10Centre Distance Pass - 10 July, 2020-14:45COMPASSPage 5 of 8 Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU L-62 - MPU L-62 wp07Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftSite NameScan Range: 33.10 to 6,867.97 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Reference Design: M Pt L Pad - Plan: MPU L-62 - MPU L-62 - MPU L-62 wp07MeasuredDepth(usft)Summary Based on MinimumSeparation WarningPlan: MPU L-61i - MPU L-61i - MPU L-61i wp07532.86 4,333.10 462.48 5,198.14 7.5714,333.10Ellipse Separation Pass - Plan: MPU L-61i - MPU L-61i - MPU L-61i wp07789.40 6,858.10 642.65 7,439.18 5.3796,858.10Clearance Factor Pass - M Pt Moose PadSurvey tool programFrom(usft)To(usft)Survey/Plan Survey Tool33.10 900.00 MPU L-62 wp07 3_Gyro-GC_Csg900.00 6,867.97 MPU L-62 wp07 3_MWD+IFR2+MS+Sag6,867.97 13,690.71 MPU L-62 wp07 3_MWD+IFR2+MS+SagEllipse error terms are correlated across survey tool tie-on points.Separation is the actual distance between ellipsoids.Calculated ellipses incorporate surface errors.Clearance Factor = Distance Between Profiles / (Distance Between Profiles - Ellipse Separation).Distance Between centres is the straight line distance between wellbore centres.All station coordinates were calculated using the Minimum Curvature method.10 July, 2020-14:45COMPASSPage 6 of 8 0.001.002.003.004.00Separation Factor0 375 750 1125 1500 1875 2250 2625 3000 3375 3750 4125 4500 4875 5250 5625 6000 6375 6750 7125Measured Depth (750 usft/in)MPL-37MPL-46MPL-48No-Go Zone - Stop DrillingCollision Avoidance Req.Collision Risk Procedures Req.NOERRORSWELL DETAILS:Plan: MPU L-62 NAD 1927 (NADCON CONUS)Alaska Zone 0416.50+N/-S +E/-W Northing Easting Latittude Longitude0.000.006031438.88 545058.40 70° 29' 48.325 N149° 37' 53.555 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU L-62, True NorthVertical (TVD) Reference:MPU L-62 As-built RKB @ 50.20usftMeasured Depth Reference:MPU L-62 As-built RKB @ 50.20usftCalculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2020-05-06T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool33.10 900.00 MPU L-62 wp07 (MPU L-62) 3_Gyro-GC_Csg900.00 6867.97 MPU L-62 wp07 (MPU L-62) 3_MWD+IFR2+MS+Sag6867.97 13690.71 MPU L-62 wp07 (MPU L-62) 3_MWD+IFR2+MS+Sag0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)0 375 750 1125 1500 1875 2250 2625 3000 3375 3750 4125 4500 4875 5250 5625 6000 6375 6750 7125Measured Depth (750 usft/in)MPL-11MPL-04MPL-05MPL-50MPL-37MPL-36MPL-06MPL-46MPL-35MPU L-60MPL-48NO GLOBAL FILTER: Using user defined selection & filtering criteria33.10 To 13690.71Project: Milne PointSite: M Pt L PadWell: Plan: MPU L-62Wellbore: MPU L-62Plan: MPU L-62 wp07Ladder / S.F. Plots1 of 2CASING DETAILSTVD TVDSS MD Size Name3990.20 3940.00 6867.97 9-5/8 9 5/8" x 12 1/4"3820.20 3770.00 13690.71 6-5/8 6 5/8" x 8 1/2" 10 July, 2020Milne PointM Pt L PadPlan: MPU L-62MPU L-62MPU L-62 wp07Reference Design: M Pt L Pad - Plan: MPU L-62 - MPU L-62 - MPU L-62 wp07Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Well Coordinates: 6,031,438.88 N, 545,058.40 E (70° 29' 48.33" N, 149° 37' 53.55" W)Datum Height: MPU L-62 As-built RKB @ 50.20usftScan Range: 6,867.97 to 13,690.71 usft. Measured Depth.Geodetic Scale Factor AppliedVersion: 5000.15 Build: 91EScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftNO GLOBAL FILTER: Using user defined selection & filtering criteriaScan Type:Scan Type:25.00 Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU L-62 - MPU L-62 wp07Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftSite NameScan Range: 6,867.97 to 13,690.71 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Reference Design: M Pt L Pad - Plan: MPU L-62 - MPU L-62 - MPU L-62 wp07MeasuredDepth(usft)Summary Based on MinimumSeparation WarningM Pt L PadMPL-46 - MPL-46 - MPL-46436.05 6,867.97 298.57 9,447.07 3.1726,867.97Clearance Factor Pass - MPL-46 - MPL-46 PB1 - MPL-46 PB1436.05 6,867.97 298.40 9,447.07 3.1686,867.97Clearance Factor Pass - MPL-47 - MPL-47 - MPL-47170.50 8,633.74 119.11 10,798.89 3.3188,633.74Centre Distance Pass - MPL-47 - MPL-47 - MPL-47198.58 8,742.97 107.69 10,839.29 2.1858,742.97Ellipse Separation Pass - MPL-47 - MPL-47 - MPL-47225.95 8,792.97 117.00 10,857.57 2.0748,792.97Clearance Factor Pass - MPL-47 - MPL-47 PB1 - MPL-47 PB1170.50 8,633.74 118.94 10,798.89 3.3078,633.74Centre Distance Pass - MPL-47 - MPL-47 PB1 - MPL-47 PB1198.58 8,742.97 107.52 10,839.29 2.1818,742.97Ellipse Separation Pass - MPL-47 - MPL-47 PB1 - MPL-47 PB1225.95 8,792.97 116.83 10,857.57 2.0718,792.97Clearance Factor Pass - MPL-48 - MPL-48 - MPL-48120.41 7,551.96 77.86 10,000.54 2.8307,551.96Centre Distance Pass - MPL-48 - MPL-48 - MPL-48136.09 7,617.97 62.02 10,018.68 1.8377,617.97Ellipse Separation Pass - MPL-48 - MPL-48 - MPL-48164.10 7,667.97 68.20 10,032.26 1.7117,667.97Clearance Factor Pass - MPL-48 - MPL-48PB3 - MPL-48 PB3734.30 7,017.97 575.12 9,257.00 4.6137,017.97Clearance Factor Pass - MPL-48 - MPL-48PB3 - MPL-48 PB3694.19 7,192.97 550.70 9,257.00 4.8387,192.97Ellipse Separation Pass - MPL-48 - MPL-48PB3 - MPL-48 PB3690.66 7,262.75 554.97 9,257.00 5.0907,262.75Centre Distance Pass - MPL-49 - MPL-49 - MPL-491,423.22 6,867.97 1,298.50 8,034.29 11.4126,867.97Clearance Factor Pass - MPL-50 - MPL-50 - MPL-50170.38 9,820.71 111.19 11,952.79 2.8789,820.71Centre Distance Pass - MPL-50 - MPL-50 - MPL-50192.39 9,917.97 97.80 11,991.59 2.0349,917.97Ellipse Separation Pass - MPL-50 - MPL-50 - MPL-50232.49 9,992.97 109.04 12,020.91 1.8839,992.97Clearance Factor Pass - MPU L-60 - MPU L-60 - MPU L-601,387.36 13,690.71 1,121.33 13,150.00 5.21513,690.71Clearance Factor Pass - MPU L-60 - MPU L-60PB3 - MPU L-60PB31,436.36 13,690.71 1,187.62 13,099.28 5.77513,690.71Clearance Factor Pass - Plan: MPU L-61i - MPU L-61i - MPU L-61i wp07680.98 13,690.71 420.16 14,260.26 2.61113,690.71Clearance Factor Pass - M Pt Moose PadMPU M-10 - MPU M-10 - MPU M-10242.4310,492.9729.0115,082.001.13610,492.97Clearance FactorPass - MPU M-10 - MPU M-10 - MPU M-10230.0110,517.9728.2515,082.001.14010,517.97Ellipse SeparationPass - MPU M-10 - MPU M-10 - MPU M-10204.74 10,622.80 74.42 15,082.00 1.57110,622.80Centre Distance Pass - MPU M-10 - MPU M-10PB3 - MPU M-10PB3246.1110,492.9753.4815,154.531.27810,492.97Clearance FactorPass - MPU M-10 - MPU M-10PB3 - MPU M-10PB3230.7010,517.9750.3315,164.401.27910,517.97Ellipse SeparationPass - 10 July, 2020-14:46COMPASSPage 2 of 5 Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU L-62 - MPU L-62 wp07Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftSite NameScan Range: 6,867.97 to 13,690.71 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Reference Design: M Pt L Pad - Plan: MPU L-62 - MPU L-62 - MPU L-62 wp07MeasuredDepth(usft)Summary Based on MinimumSeparation WarningMPU M-10 - MPU M-10PB3 - MPU M-10PB3176.84 10,678.66 112.97 15,226.84 2.76910,678.66Centre Distance Pass - MPU M-11 - MPU M-11 - MPU M-11207.4511,392.97-39.1415,691.760.84111,392.97Clearance FactorFAIL - MPU M-11 - MPU M-11 - MPU M-11154.83 11,542.54 72.18 15,747.12 1.87311,542.54Centre Distance Pass - MPU M-12 - MPU M-12 - MPU M-12215.1012,292.97-41.7216,248.690.83812,292.97Clearance FactorFAIL - MPU M-12 - MPU M-12 - MPU M-12158.52 12,449.39 71.22 16,304.74 1.81612,449.39Centre Distance Pass - MPU M-12 - MPU M-12PB2 - MPU M-12PB2207.5512,292.97-53.9616,256.530.79412,292.97Clearance FactorFAIL - MPU M-12 - MPU M-12PB2 - MPU M-12PB2150.31 12,444.09 61.70 16,303.44 1.69612,444.09Centre Distance Pass - MPU M-13 - MPU M-13i - MPU M-13251.7613,167.97-1.9615,914.200.99213,167.97Clearance FactorFAIL - MPU M-13 - MPU M-13i - MPU M-13190.54 13,343.06 100.10 15,972.81 2.10713,343.06Centre Distance Pass - MPU M-14 - MPU M-14 - MPU M-14523.1113,690.71173.8016,127.401.49813,690.71Clearance FactorPass - MPU M-15i - MPU M-15 - MPU M-15i1,319.81 13,690.71 987.16 16,045.86 3.96813,690.71Clearance Factor Pass - Survey tool programFrom(usft)To(usft)Survey/Plan Survey Tool33.10 900.00 MPU L-62 wp07 3_Gyro-GC_Csg900.00 6,867.97 MPU L-62 wp07 3_MWD+IFR2+MS+Sag6,867.97 13,690.71 MPU L-62 wp07 3_MWD+IFR2+MS+SagEllipse error terms are correlated across survey tool tie-on points.Separation is the actual distance between ellipsoids.Calculated ellipses incorporate surface errors.Clearance Factor = Distance Between Profiles / (Distance Between Profiles - Ellipse Separation).Distance Between centres is the straight line distance between wellbore centres.All station coordinates were calculated using the Minimum Curvature method.10 July, 2020-14:46COMPASSPage 3 of 5 0.001.002.003.004.00Separation Factor6750 7125 7500 7875 8250 8625 9000 9375 9750 10125 10500 10875 11250 11625 12000 12375 12750 13125 13500Measured Depth (750 usft/in)MPL-46MPU M-10No-Go Zone - Stop DrillingCollision Avoidance Req.Collision Risk Procedures Req.WELL DETAILS:Plan: MPU L-62 NAD 1927 (NADCON CONUS)Alaska Zone 0416.50+N/-S +E/-W Northing Easting Latittude Longitude0.000.006031438.88545058.4070° 29' 48.325 N 149° 37' 53.555 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU L-62, True NorthVertical (TVD) Reference:MPU L-62 As-built RKB @ 50.20usftMeasured Depth Reference:MPU L-62 As-built RKB @ 50.20usftCalculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2020-05-06T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool33.10 900.00 MPU L-62 wp07 (MPU L-62) 3_Gyro-GC_Csg900.00 6867.97 MPU L-62 wp07 (MPU L-62) 3_MWD+IFR2+MS+Sag6867.97 13690.71 MPU L-62 wp07 (MPU L-62) 3_MWD+IFR2+MS+Sag0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)6750 7125 7500 7875 8250 8625 9000 9375 9750 10125 10500 10875 11250 11625 12000 12375 12750 13125 13500Measured Depth (750 usft/in)MPU M-12MPL-48NO GLOBAL FILTER: Using user defined selection & filtering criteria33.10 To 13690.71Project: Milne PointSite: M Pt L PadWell: Plan: MPU L-62Wellbore: MPU L-62Plan: MPU L-62 wp07Ladder / S.F. Plots2 of 2CASING DETAILSTVD TVDSS MD Size Name3990.20 3940.00 6867.97 9-5/8 9 5/8" x 12 1/4"3820.20 3770.00 13690.71 6-5/8 6 5/8" x 8 1/2" From:Joseph Lastufka To:Boyer, David L (CED) Cc:Nathan Sperry Subject:RE: [EXTERNAL] RE: MPU L-62 Directional Survey Date:Wednesday, July 15, 2020 10:18:39 AM Good catch! I’m certain we haven’t already spudded… Let’s use August 15th. Sorry about that! Thanks, Joe Lastufka Sr. Drilling Technologist Hilcorp North Slope, LLC Office: (907)777-8400, Cell:(907)227-8496 From: Boyer, David L (CED) [mailto:david.boyer2@alaska.gov] Sent: Wednesday, July 15, 2020 10:14 AM To: Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Subject: [EXTERNAL] RE: MPU L-62 Directional Survey Joe, In reviewing the L-62 401, a 06/10/20 spud date is listed. Without time travel, that is not going to happen. Do you or Nathan have a revised spud date for this well? Thanks, Dave B. AOGCC From: Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Sent: Wednesday, July 15, 2020 8:56 AM To: Boyer, David L (CED) <david.boyer2@alaska.gov> Subject: FW: MPU L-62 Directional Survey Dave, Sorry, looks like I sent the original to the wrong David Boyer! Thanks, Joe Lastufka Sr. Drilling Technologist Hilcorp North Slope, LLC Office: (907)777-8400, Cell:(907)227-8496 From: Joseph Lastufka Sent: Tuesday, July 14, 2020 11:57 AM To: 'steve.davies@alaska.gov' <steve.davies@alaska.gov>; 'david.boyer@alaska.gov' <david.boyer@alaska.gov> Subject: MPU L-62 Directional Survey Steve / Dave, This Permit to Drill was submitted today, please let me know if you have questions or need anything else. Thanks! Thanks, Joe Lastufka Sr. Drilling Technologist Hilcorp North Slope, LLC Office: (907)777-8400, Cell:(907)227-8496 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. 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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. MPU L-62 X Milne Point Unit Schrader Bluff Oil X X 220-059 WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name:MILNE PT UNIT L-62Initial Class/TypeDEV / PENDGeoArea890Unit11328On/Off ShoreOnProgramDEVField & PoolWell bore segAnnular DisposalPTD#:2200590MILNE POINT, SCHRADER BLFF OIL - 525140NA17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)NA1 Permit fee attachedYes2 Lease number appropriateYes3 Unique well name and numberYes4 Well located in a defined poolYes5 Well located proper distance from drilling unit boundaryYes6 Well located proper distance from other wellsYes7 Sufficient acreage available in drilling unitYes8 If deviated, is wellbore plat includedYes9 Operator only affected partyYes10 Operator has appropriate bond in forceYes11 Permit can be issued without conservation orderYes12 Permit can be issued without administrative approvalYes13 Can permit be approved before 15-day waitNA14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (ForNA15 All wells within 1/4 mile area of review identified (For service well only)NA16 Pre-produced injector: duration of pre-production less than 3 months (For service well only)Yes 20" conductor to 114'18 Conductor string providedYes Fully cemented. She set in SB sands19 Surface casing protects all known USDWsYes Fully cemented. Two stage job.20 CMT vol adequate to circulate on conductor & surf csgYes21 CMT vol adequate to tie-in long string to surf csgYes Surface casing shoe set in top of the SB Nb sands22 CMT will cover all known productive horizonsYes 47# L-80 9-5/8" to 2000', 40# L-80 9-5/8" to 6868'23 Casing designs adequate for C, T, B & permafrostYes Doyon 14 in ongoing operations24 Adequate tankage or reserve pitNA This is a gras roots well.25 If a re-drill, has a 10-403 for abandonment been approvedYes Close approaches to M-11, M-12 and M-13i in production zone. Utilize geosteering26 Adequate wellbore separation proposedYes 21-1/4" Diverter, 16" line27 If diverter required, does it meet regulationsYes All fluids overbalanced to pore pressure28 Drilling fluid program schematic & equip list adequateYes 1 annular, 3 ram stack with flow cross.29 BOPEs, do they meet regulationYes All equipment rated to 5000 psi30 BOPE press rating appropriate; test to (put psig in comments)Yes31 Choke manifold complies w/API RP-53 (May 84)Yes32 Work will occur without operation shutdownNo None expected at L pad33 Is presence of H2S gas probableNA This is a development well.34 Mechanical condition of wells within AOR verified (For service well only)Yes H2S not anticipated from drilling of offset wells; however, rig has H2S sensors and alarms.35 Permit can be issued w/o hydrogen sulfide measuresYes36 Data presented on potential overpressure zonesNA37 Seismic analysis of shallow gas zonesNA38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprDLBDate7/15/2020ApprMGRDate7/15/2020ApprDLBDate7/15/2020AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateJMP7/17/2020JLC 7/16/2020