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Home My WebLink About218-072Nolan 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: 11/07/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20251107 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# BRU 212-26 50283201820000 220058 9/20/2025 AK E-LINE Perf BRU 212-35 50283100270000 162018 10/12/2025 AK E-LINE TubingPuncher BRU 234-27 50283202070000 225065 7/17/1905 AK E-LINE CBL-02-October BRU 234-27 50283202070000 225065 10/6/2025 AK E-LINE CIBP/Perf GP 42-23RD 50733201140100 195145 10/26/2025 AK E-LINE TubingPunch GP ST 42-23RD 50733201140100 195145 10/9/2025 AK E-LINE JetCut MPL-54 50029236070000 218066 10/16/2025 READ CaliperSurvey MPL-57 50029236090000 218072 10/27/2025 READ CaliperSurvey MPU B-21 50029215350000 186023 10/25/2025 AK E-LINE RBP NCIU A-07 50883200270000 169058 10/10/2025 AK E-LINE JetCut NCIU A-17A 50883201880100 225089 10/10/2025 AK E-LINE Perf NCIU A-17A 50883201880100 225089 10/14/2025 AK E-LINE Perf PBU 01-10A 50029201690200 225055 8/29/2025 HALLIBURTON RBT PBU 05-11A 50029202520100 196097 10/11/2025 BAKER RPM PBU 05-31B 50029221590200 210085 10/14/2025 BAKER SPN PBU F-06B 50029200970200 225054 9/27/2025 BAKER MRPM PBU F-42A 50029221080100 207093 10/27/2025 BAKER RPM PBU H-07B 50029202420200 225064 9/29/2025 BAKER MRPM PBU L5-27 50029236270000 219046 10/7/2025 BAKER SPN PBU Q-06A 50029203460100 198090 8/22/2025 YELLOWJACKET SCBL SD-06 50133205820000 208160 7/23/2025 YELLOWJACKET GPT-PERF SRU 222-33 50133207150000 223100 7/15/2025 YELLOWJACKET PERF Please include current contact information if different from above. T41066 T41067 T41068 T41068 T41069 T41069 T41070 T41071 T41072 T41073 T41074 T41074 T41075 T41076 T41077 T41078 T41079 T41080 T41081 T41082 T41083 T41084 MPL-57 50029236090000 218072 10/27/2025 READ CaliperSurvey Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.11.07 15:03:51 -09'00' 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): 13,941' N/A Casing Collapse Conductor N/A Surface 3,090psi Tieback 4,790psi 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-57 MILNE POINT SCHRADER BLUFF OIL N/A 3,699' 13,926' 3,700' 813 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): 10/26/2025 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0025509 & ADL0025515 218-072 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 50-029-23609-00-00 Hilcorp Alaska LLC C.O. 477B Length Size Proposed Pools: 114' 114' 12.6 / L-80 /BTC TVD Burst 6,257' MD N/A 9,020psi 5,750psi 6,890psi 3,939' 3,942' 3,699' 6,715' 6,536' 114' 16" 9-5/8" 7-5/8"" 6,715' 4-1/2"7,404' 6,536' Perforation Depth MD (ft): 13,931' See Schematic See Schematic 4-1/2" VCT PHP. ISO & BOT SLZXP LTP and N/A 6,134 MD / 3,848 TVD & 6,527 MD / 3,941 TVD and N/A Ryan Lewis ryan.lewis@hilcorp.com 303-906-5178 3-1/2" 9.2 / L-80 / EUE-8rd 5,711' Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143) Date: 2025.10.15 12:26:41 - 08'00' Taylor Wellman (2143) 325-632 * BOPE test to 2000 psi. 24 hour notice to AOGCC. DSR-10/15/25A.Dewhurst 15OCT25 10-404 MGR15OCT25 10/23/25 By Grace Christianson at 1:19 pm, Oct 23, 2025 Well: MPL-57 PTD: 218-072 API: 50-029-23609-00-00 Well Name:MPL-57 API Number:50-029-23609-00-00 Current Status:Shut-in ESP Rig:ASR #1 Estimated Start Date:10/26/25 Estimated Duration:4 days Regulatory Contact:Tom Fouts Permit to Drill Number:218-072 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: 1,163 psi @ 3,498 TVD L-54 DH Gauge 8/28/24 | 6.4 EMW, 6.9 KWF Max Potential Surface Pressure: 813 psi Gas Column Gradient (0.1 psi/ft) Max Angle:61° at 4,563 MD Brief Well Summary: MPL-57 is an online Schrader producer with a lateral drilled in the NB sand. MPL-57 was drilled in 2018. The reservoir completion is a fine mesh screen completion. While on ESP lift from 2022 to 2023 the flowing bottom hole pressure steadily climbed while on ESP production. An elective ESP swap was performed in March of 2023 due to belief the pump had worn out. The newly installed ESP was put on production but shorted out after 3 weeks of production. Long ESP lead times lead to working over the well to a jet pump completion. The jet pump completion successfully draws down the well but the mixture of cold power fluid and viscous oil creates emulsions that upset the oil separation processes. The well was converted back to ESP in 2023. The ESP ran for 2 years and failed electrically. Objectives: Pull failed ESP completion, run an ESP Notes Regarding Wellbore Condition: - 7 casing test to 3,000 psi on 5/20/2023 at 6,375 MD. 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 5,488 MD and leave open. 4. Pull GLV and set dummy valve in upper GLM at 192 MD. 5. Run SBHPS. We will use the updated data to determine KWF. There is no reason to believe this well will require an ESP packer but will confirm with data. 6. Caliper from the discharge head to surface. 7. 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. Well: MPL-57 PTD: 218-072 API: 50-029-23609-00-00 5. Circulate at least one wellbore volume with produced water down tubing, taking returns up casing to 500 barrel returns tank. Bullhead down tbg and IA taking returns to formation as needed to establish and maintain a full column of produced water. 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/ 2,000 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 VBR rams on 3-1/2 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 Summit 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 Gen 5, 11" x 3-1/2" EUE Box top & bottom. CIW H BPVT. b. 2023 tubing PU weight on ASR recorded as 52 kip. Slack off weight recorded as 26 kip. c. 3-1/2 L-80 EUE yield is 207 kip. 8. Confirm hanger free, lay down tubing hanger. 9. POOH and lay down the 3-1/2 tubing. a. Use caliper results to determine what can be re-used. Confirm with OE. 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: 100 ii. Splice Clamp: 1 iii. Motor clamp: 3 iv. Seal clamp: 4 v. Pump clamp: 3 Well: MPL-57 PTD: 218-072 API: 50-029-23609-00-00 10. Lay Down ESP. Collect any solids sample and get them to chemical guys Cole or Mitch for analysis. Make sure the ESP tech posts all pictures to the Summit folder on ESP Central. 3-1/2 ESP Completion: 11. RIH with used 3-1/2 9.3# L-80 ESP completion to +/- 5,700 and obtain string weights. a. Run a cap string 3/8, confirm with Justin Bailey based on clamps. b. Check electrical continuity every 1000. c. Note PU and SO weights on tally. d. 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 4.5 2 Intake Sensor 30 5.62 17 Motor - XXXHP 80 5.2 7 Lower Tandem Seal 38 5.2 7 Upper Tandem Seal 38 5.2 3 INTAKE GPXARCINT FER H6 35 5.38 10 PUMP 45 1 Ported Discharge Head 13 L-80 2-7/8" 10 3-1/2" EUE 8rd Pup Jt 6.5 L-80 2-7/8" 30 3-1/2" EUE 8rd L-80 6.5 L-80 2-7/8"10 3-1/2" EUE 8rd Pup Jt 6.5 L-80 2-7/8"2 XN-nipple 2.81" No-Go 6.5 L-80 2-7/8"10 3-1/2" EUE 8rd Pup Jt 6.5 L-80 2-7/8" 30 3-1/2" EUE 8rd Jt 6.5 L-80 2-7/8"10 3-1/2" EUE 8rd Pup Jt 6.5 L-80 2-7/8"8 3-1/2" x 1" GLM, DV installed 6.5 L-80 2-7/8"10 3-1/2" EUE 8rd Pup Jt 6.5 L-80 2-7/8" ~5,270 3-1/2" EUE 8rd Jt 6.5 L-80 2-7/8"10 3-1/2" EUE 8rd Pup Jt 6.5 L-80 2-7/8"8 3-1/2" x 1" GLM, 1/4" OV 6.5 L-80 ~200 MD 2-7/8"10 3-1/2" EUE 8rd Pup Jt 6.5 L-80 2-7/8" 150 3-1/2" 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. Well: MPL-57 PTD: 218-072 API: 50-029-23609-00-00 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. 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. 11 Double BOPE Schematic _____________________________________________________________________________________ Revised By: TDF 10/20/2023 SCHEMATIC Milne Point Unit Well: MPU L-57 Last Completed: 10/11/2023 PTD: 218-072 TD =13,941(MD) /TD =3,699 (TVD) 4& 5 16 Orig. KB Elev.: 34.1 / GL Elev.: 15.2 7-5/8 10 11 & 12 7 19 9-5/8 1 2 3 20 Tubing Cut @ 6,091 ELMD 9/27/2023 See Screen/ Solid Liner Detail PBTD =13,926 (MD) /PBTD =3,700 (TVD) 9-5/8 ES Cementer @ 2,447 MD 8 & 9 4-1/2 Shoe @ 13,931 13 14 18 3-1/2 6 16& 17 15 4-1/2 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 16" Conductor 164 / A53B / Weld N/A Surface 114 N/A 9-5/8" Surface 40 / L-80 / TXP 8.835 Surface 6,715 0.0758 7-5/8 Tieback 29.7 / L-80 / Hyd 521/Vam STL 6.875 Surface 6,536 0.0459 4-1/2 Liner 250 Screens 13.5 / L-80 / Hyd 625 3.920 6,527 13,931 .0149 TUBING DETAIL 3-1/2" Tubing 9.2 / L-80 / EUE-8rd 2.992 Surface 5,711 0.0087 3/8 Cap String 3/8 Stainless Steel N/A Surface 5,711 N/A OPEN HOLE / CEMENT DETAIL Conductor ±270 ft3 12-1/4"Stg 1 Lead - 562 sx / Tail 400 sx Stg 2 Lead 378 sx / Tail 270 sx Class G (250 bbls to surface) 8-1/2 Cementless Screens Liner in 8-1/2 hole WELL INCLINATION DETAIL KOP @ 543 Max Hole Angle = 94.47° @ 13,941 MD TREE & WELLHEAD Tree Cameron 2-9/16" 5M Wellhead FMC Gen V 4-1/2 SOLID LINER DETAIL Jts Top (MD) Top (TVD) Btm (MD) Btm (TVD) 4 6,555 3,943 6,720 3,939 JEWELRY DETAIL No. Top MD Item ID 1 192 GLM #2: 3-1/2 x 1 KBMM W/ DPSOV Orifice Valve 2.992 2 5,488 GLM #1: 3-1/2 x 1 w/ Dummy 2.992 3 5,575 XN Nipple:2.81 No-go 2.81 4 5,626 Discharge Head: Bolt on,3 1/2" 8rd, 400X,416 SS - 5 5,627 Discharge Adapter: Vigilant, 3 1/2 SS - 6 5,628 Pump: 538 Series,114 stage SJ2800, 7/8 Inconel Shaft - 7 5,651 Gas Separator: 538, TDM, H2X,SS,INC,D15 - 8 5,659 Upper Tandem Seal: 513 SERIES, BPBSL, INCONEL SHAFT, A/R - 9 5,667 Lower Tandem Seal: 513 SERIES, BPBSL, INCONEL SHAFT, A/R - 10 5,676 Motor: 562, KMS2,500HP,4160V,74A,16R,316SHB - 11 5,707 Motor Gauge: ACE SEN 177C, 8KPSI, SS, 2XPRES, 2XTEMP, 2XVIB - 12 5,709 Centralizer: Bottom @ ±5,711- 13 6,134 7-5/8" X 4.5" VCT PHP. ISO Packer 3.958 14 6,192 XN Nipple w/ RHC Installed-3.813 NoGo 3.813 15 6,491 4-1/2" WLEG Btm @ 6,5273.958 16 6,527 BOT SLZXP LTP / Liner Hanger 7 x 9-5/8(TVD 3,942)6.190 17 6,536 7-5/8 Tieback Assy. 6.151 18 6,549 7 H563 x 4.5 Hyd 625 XO 3.850 19 13,895 4-1/2 Drillable Packoff Sub 2.390 20 13,926 WIV Valve LTC BxB (1 Ball on Seat/Closed) - 4-1/2 SCREEN LINER DETAIL Jts Type Top (MD) Top (TVD)Btm (MD) Btm (TVD) 79 Bkr Xcluder 6,720 3,939 9,792 3,831 96 Halliburton 9,972 3,831 13,851 3,705 GENERAL WELL INFO API: 50-029-23609-00-00 Completion Date: 7/28/18 ESP Swap by ASR#1 3-15-2023 Conv. To Rev Circ Jet Pump by ASR#1 5/24/2023 Conv. To ESP by ASR - 10/11/2023 _____________________________________________________________________________________ Revised By: TDF 10/20/2023 PROPOSED Milne Point Unit Well: MPU L-57 Last Completed: 10/11/2023 PTD: 218-072 \ TD =13,941(MD) /TD =3,699 (TVD) 4 & 5 16 Orig. KB Elev.: 34.1 / GL Elev.: 15.2 7-5/8 10 11 & 12 7 19 9-5/8 1 2 3 20 Tubing Cut @ 6,091 ELMD 9/27/2023 See Screen/ Solid Liner Detail PBTD =13,926 (MD) /PBTD =3,700 (TVD) 9-5/8 ES Cementer @ 2,447 MD 8 & 9 4-1/2 Shoe @ 13,931 13 14 18 3-1/2 6 16 & 17 15 4-1/2 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 16" Conductor 164 / A53B / Weld N/A Surface 114 N/A 9-5/8" Surface 40 / L-80 / TXP 8.835 Surface 6,715 0.0758 7-5/8 Tieback 29.7 / L-80 / Hyd 521/Vam STL 6.875 Surface 6,536 0.0459 4-1/2 Liner 250 Screens 13.5 / L-80 / Hyd 625 3.920 6,527 13,931 .0149 TUBING DETAIL 3-1/2" Tubing 9.2 / L-80 / EUE-8rd 2.992 Surface ±5,700 0.0087 3/8 Cap String 3/8 Stainless Steel N/A Surface ±5,700 N/A OPEN HOLE / CEMENT DETAIL Conductor ±270 ft3 12-1/4"Stg 1 Lead - 562 sx / Tail 400 sx Stg 2 Lead 378 sx / Tail 270 sx Class G (250 bbls to surface) 8-1/2 Cementless Screens Liner in 8-1/2 hole WELL INCLINATION DETAIL KOP @ 543 Max Hole Angle = 94.47° @ 13,941 MD TREE & WELLHEAD Tree Cameron 2-9/16" 5M Wellhead FMC Gen V 4-1/2 SOLID LINER DETAIL Jts Top (MD) Top (TVD) Btm (MD) Btm (TVD) 4 6,555 3,943 6,720 3,939 JEWELRY DETAIL No. Top MD Item ID 1 ±200 GLM #2: 3-1/2 x 1 w/ ¼ OV Orifice Valve 2.992 2 ±X,XXX GLM #1: 3-1/2 x 1 w/ DV Installed 2.992 3 ±X,XXX XN Nipple: 2.81 No-go 2.81 4 ±X,XXX Ported Discharge Head: - 5 ±X,XXX Pump: - 6 ±X,XXX Intake: - 7 ±X,XXX Gas Separator: - 8 ±X,XXX Upper Tandem Seal: - 9 ±X,XXX Lower Tandem Seal: - 10 ±X,XXX Motor: - 11 ±X,XXX Intake Sensor: - 12 ±X,XXX Centralizer: Bottom @ ±5,700 - 13 6,134 7-5/8" X 4.5" VCT PHP. ISO Packer 3.958 14 6,192 XN Nipple w/ RHC Installed-3.813 NoGo 3.813 15 6,491 4-1/2" WLEG Btm @ 6,5273.958 16 6,527 BOT SLZXP LTP / Liner Hanger 7 x 9-5/8(TVD 3,942)6.190 17 6,536 7-5/8 Tieback Assy. 6.151 18 6,549 7 H563 x 4.5 Hyd 625 XO 3.850 19 13,895 4-1/2 Drillable Packoff Sub 2.390 20 13,926 WIV Valve LTC BxB (1 Ball on Seat/Closed) - 4-1/2 SCREEN LINER DETAIL Jts Type Top (MD) Top (TVD)Btm (MD) Btm (TVD) 79 Bkr Xcluder 6,720 3,939 9,792 3,831 96 Halliburton 9,972 3,831 13,851 3,705 GENERAL WELL INFO API: 50-029-23609-00-00 Completion Date: 7/28/18 ESP Swap by ASR#1 3-15-2023 Conv. To Rev Circ Jet Pump by ASR#1 5/24/2023 Conv. To ESP by ASR - 10/11/2023 Milne Point ASR Rig 1 BOPE 2025 Updated 7/31/2025 11 BOPE 4.48' 4.54' 2.00' INTEGRATED 4.30'INTEGRATED 11" - 5000 2-7/8" x 5" VBR Blind11'- 5000 DSA, 11 5M X 7 1/16 5M (If Needed) 2 1/16 5M Kill Line Valves 2 1/16 5M Choke Line Valves HCRManualManualManual Stripping Head 1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Install Whipstock Perforate Other Stimulate Alter Casing Cut Tubing Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: Convert to ESP 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 13,941 feet N/A feet true vertical 3,699 feet N/A feet Effective Depth measured 13,926 feet 6,134 & 6,527 feet true vertical 3,700 feet 3,848 & 3,941 feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet 3-1/2" 9.2 / L-80 / EUE-8rd 5,711' 3,643' Tubing (size, grade, measured and true vertical depth)4-1/2"12.6 / L-80 /BTC 6,257' 3,889' VCT PHP. ISO Packer 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: 8,540psi 5,750psi 6,890psi 9,020psi 6,536' 3,942' Burst N/A Collapse N/A 3,090psi 4,790psi 7,404' Casing Conductor 3,699'13,931' 6,536' 6,715'Surface Tieback Liner 16" 9-5/8" 7-5/8"" 114' 6,715' measured TVD 4-1/2" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 218-072 50-029-23609-00-00 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-57 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) 618 Gas-Mcf MD 114' 480 Size 114' 3,939' 780 220169 145 38134 408 323-466 Sr Pet Eng: Sr Pet Geo: Sr Res Eng: WINJ WAG 11 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 PL G 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 2:36 pm, Oct 30, 2023 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143) Date: 2023.10.30 11:35:23 - 08'00' Taylor Wellman (2143) RBDMS JSB 110823 WCB 5-10-2024 DSR-11/2/23 _____________________________________________________________________________________ Revised By: TDF 10/20/2023 SCHEMATIC Milne Point Unit Well: MPU L-57 Last Completed: 10/11/2023 PTD: 218-072 TD =13,941’(MD) /TD =3,699’ (TVD) 4& 5 16” Orig. KB Elev.: 34.1’ / GL Elev.: 15.2’ 7-5/8” 10 11 & 12 7 19 9-5/8” 1 2 3 20 Tubing Cut @ 6,091 ELMD 9/27/2023 See Screen/ Solid Liner Detail PBTD =13,926’ (MD) / PBTD = 3,700’ (TVD) 9-5/8” ‘ES’ Cementer @ 2,447’ MD 8 & 9 4-1/2” Shoe @ 13,931’ 13 14 18 3-1/2” 6 16 & 17 15 4-1/2” CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 16" Conductor 164 / A53B / Weld N/A Surface 114’ N/A 9-5/8" Surface 40 / L-80 / TXP 8.835 Surface 6,715’ 0.0758 7-5/8” Tieback 29.7 / L-80 / Hyd 521/Vam STL 6.875 Surface 6,536’ 0.0459 4-1/2” Liner 250ђ Screens 13.5 / L-80 / Hyd 625 3.920 6,527’ 13,931’ .0149 TUBING DETAIL 3-1/2" Tubing 9.2 / L-80 / EUE-8rd 2.992 Surface 5,711’ 0.0087 3/8” Cap String 3/8” Stainless Steel N/A Surface 5,711’ N/A OPEN HOLE / CEMENT DETAIL Conductor ±270 ft3 12-1/4"Stg 1 – Lead - 562 sx / Tail – 400 sx Stg 2 – Lead – 378 sx / Tail – 270 sx Class G (250 bbls to surface) 8-1/2” Cementless Screens Liner in 8-1/2” hole WELL INCLINATION DETAIL KOP @ 543’ Max Hole Angle = 94.47° @ 13,941’ MD TREE & WELLHEAD Tree Cameron 2-9/16" 5M Wellhead FMC Gen V 4-1/2” SOLID LINER DETAIL Jts Top (MD) Top (TVD) Btm (MD) Btm (TVD) 4 6,555’ 3,943’ 6,720’ 3,939’ JEWELRY DETAIL No. Top MD Item ID 1 192’ GLM #2: 3-1/2” x 1” KBMM W/ DPSOV Orifice Valve 2.992” 2 5,488’ GLM #1: 3-1/2” x 1” w/ Dummy 2.992” 3 5,575’ XN Nipple:2.81” No-go 2.81” 4 5,626’ Discharge Head: Bolt on,3 1/2" 8rd, 400X,416 SS - 5 5,627’ Discharge Adapter: Vigilant, 3 1/2 SS - 6 5,628’ Pump: 538 Series,114 stage SJ2800, 7/8 Inconel Shaft - 7 5,651’ Gas Separator: 538, TDM, H2X,SS,INC,D15 - 8 5,659’ Upper Tandem Seal: 513 SERIES, BPBSL, INCONEL SHAFT, A/R - 9 5,667’ Lower Tandem Seal: 513 SERIES, BPBSL, INCONEL SHAFT, A/R - 10 5,676’ Motor: 562, KMS2,500HP,4160V,74A,16R,316SHB - 11 5,707’ Motor Gauge: ACE SEN 177C, 8KPSI, SS, 2XPRES, 2XTEMP, 2XVIB - 12 5,709’ Centralizer: Bottom @ ±5,711’- 13 6,134’ 7-5/8" X 4.5" VCT PHP. ISO Packer 3.958” 14 6,192’ XN Nipple w/ RHC Installed-3.813 NoGo 3.813” 15 6,491’ 4-1/2" WLEG –Btm @ 6,527’3.958” 16 6,527’ BOT SLZXP LTP / Liner Hanger 7” x 9-5/8”(TVD 3,942’)6.190” 17 6,536’ 7-5/8” Tieback Assy. 6.151” 18 6,549’ 7” H563 x 4.5” Hyd 625 XO 3.850” 19 13,895’ 4-1/2” Drillable Packoff Sub 2.390” 20 13,926’ WIV Valve LTC BxB (1” Ball on Seat/Closed) - 4-1/2” SCREEN LINER DETAIL Jts Type Top (MD) Top (TVD)Btm (MD) Btm (TVD) 79 Bkr Xcluder 6,720’ 3,939’ 9,792’ 3,831’ 96 Halliburton 9,972’ 3,831’ 13,851’ 3,705’ GENERAL WELL INFO API: 50-029-23609-00-00 Completion Date: 7/28/18 ESP Swap by ASR#1 – 3-15-2023 Conv. To Rev Circ Jet Pump by ASR#1 – 5/24/2023 Conv. To ESP by ASR - 10/11/2023 Well Name Rig API Number Well Permit Number Start Date End Date MP L-57 ASR 50-029-23609-00-00 218-072 10/8/2023 10/11/2023 10/6/2023 - Friday No operations to report. 10/4/2023 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary No operations to report. 10/5/2023 - Thursday No operations to report. Continue to POOH F/1,696' T/ surface W/ 4-1/2" completion, pumping double displacement. 80 CC and a 4.40' cut piece as last jt. Swap over handling equipment on rig floor. Move company man office and change house. Spot in ESP spooler. Run ropes through sheave. Load pipe shed W/ 3-1/2" EUE pipe. Hold pre job W/ ESP reps. Pull ESP cable and cap line to rig floor. P/U M/U ESP equipment as per the ESP reps. RIH with ESP pump assy on 3.5'' tbg F/85' T/1,105' installing Cross clamps every other jt pumping double displacement every 15 jts. RIH with ESP pump assy on 3.5'' tbg F/1,105' T/3,220" installing Cross clamps every other jt pumping double displacement every 15 jts. No operations to report. 10/7/2023 - Saturday Continue testing BOPs 250 low 2500 high each test 5mins as per approved sundry. Troubleshoot Test for HCR. Function HCR. grease HCR. Test no good. Mobilize new HCR valve to location. Take of HCR hose. Pull off cushion "T". Remove HCR. Swap Hydraulic fittings on valve. Install new valve cushion "t" and hose. Charge Koomey. Function test new HCR valve. Fill stack with test fluid. Continue testing BOPs as per approved sundry. LD Testing Equip and BD all surface lines. Pull hanger to rig floor came unseated @ 57K no over pull. POOH LD 4.5'' TBG F/~6,091' T/5,785' run tec line over sheave to the spooler. Replace make and break selector on power tong. POOH 4.5'' tbg F/5,785' T/1,696' Double displacement while POOH. 10/10/2023 - Tuesday 10/8/2023 - Sunday Rig accepted @ 23:30. BOPE Test as per sundry 250psi low and 2500psi high 5 mins each test. AGOCC rep Bob Noble waived witness for test. 10/9/2023 - Monday Well Name Rig API Number Well Permit Number Start Date End Date MP L-57 ASR 50-029-23609-00-00 218-072 10/8/2023 10/11/2023 10/13/2023 - Friday No operations to report. 10/11/2023 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary Continue RIH W/ 3-1/2 EUE and ESP F/3,220' T/ 5,677'. Checking cable and cap line every 1,000'. P/U M/U hanger, screw in landing JT. Splice ESP cable & cap line through hanger. Check ESP cable & attach electrical umbilical. Land hanger/ P/U wt = 52K S/O wt = 26K, RILDS. Set BPV. Remove well equipment from rig floor. Rig released at 18:00 10/11/2023. WELLHEAD: M/U hanger to landing joint then P/U and M/U to string, land hanger to RKB and RILDS, Set BPV S/B for RDMO, N/U tree/adapter test tubing hanger void/adapter to 500 low and 5000 high 5/10 minutes test good, Pulled BPV secured well. 10/12/2023 - Thursday No operations to report. No operations to report. No operations to report. 10/14/2023 - Saturday No operations to report. 10/17/2023 - Tuesday 10/15/2023 - Sunday No operations to report. 10/16/2023 - Monday 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: 10/04/2023 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20231004 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# IRU 41-01 50283200880000 192109 9/17/2023 HALLIBURTON Coilflag KBU 32-06 50133206580000 216137 9/8/2023 HALLIBURTON PPROF LRU C-02 50283201900000 223057 9/13/2023 HALLIBURTON RBT MPU E-37 50029236160000 218158 9/24/2023 READ Caliper Survey MPU F-53A 50029225780100 213136 9/27/2023 READ Caliper Survey MPU F-79 50029228130000 197180 9/26/2023 READ Caliper Survey MPU L-57 50029236090000 218072 9/26/2023 READ Caliper Survey MPU S-06 50029231630000 203109 9/29/2023 READ Caliper Survey MPU B-32 50029235700000 216151 9/12/2023 HALLIBURTON Perf TBU K-09 50733201100000 1068038 10/1/2023 READ Caliper Survey Please include current contact information if different from above. T38028 T38029 T38030 T38031 T38032 T38033 T38034 T38035 T38036 T38037 10/4/2023 MPU L-57 50029236090000 218072 9/26/2023 READ Caliper Survey Kayla Junke Digitally signed by Kayla Junke Date: 2023.10.04 13:03:04 -08'00' 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Cut Tubing Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: Convert to ESP 2.Operator Name: 4.Current Well Class:5.Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating:8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception? Yes No 9.Property Designation (Lease Number):10.Field: Current Pools: 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 13,941'N/A Casing Collapse Conductor N/A Surface 3,090psi Tieback 4,790psi 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: Operations Manager Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: AOGCC USE ONLY scott.pessetto@hilcorp.com 907-564-4373 Scott Pessetto Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): Tubing Size: 12.6 / L-80 /BTC 6,527' 9/6/2023 VCT PHP. ISO & BOT SLZXP Packer and N/A 6,134 MD/ 3,848 TVD & 6,527 MD/ 3,942 TVD and N/A See Schematic See Schematic 4-1/2" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0025509 & ADL0025515 218-072 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 50-029-23609-00-00 Hilcorp Alaska LLC SCHRADER BLUFF OIL N/A C.O. 477.05 MILNE PT UNIT L-57 Length Size Proposed Pools: 114' 114' TVD Burst PRESENT WELL CONDITION SUMMARY 3,699' 13,926' 3,700' 1,062 N/A 114' 16" MILNE POINT MD N/A 9,020psi 5,750psi 6,890psi 3,939' 3,942' 3,699' 6,715' 6,536' 13,931' 9-5/8" 7-5/8"" 6,715' 6,536' Perforation Depth MD (ft): 4-1/2"7,404' Form 10-403 Revised 10/2022 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 3:01 pm, Aug 16, 2023 323-466 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143) Date: 2023.08.16 14:04:34 - 08'00' Taylor Wellman (2143) DSR-8/18/23 10-404 MGR30AUG23 1,062 * BOPE test to 2500 psi. MDG 8/23/2023*&:JLC 8/31/2023 08/31/23 RBDMS JSB 090523 Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2023.08.31 16:03:16 -08'00' Well: MPL-57 PTD: 218-072 API: 50-029-23609-00-00 Well Name:MPL-57 API Number:50-029-23609-00-00 Current Status:Shut-in Producer Rig:ASR #1 Estimated Start Date:9/6/2023 Estimated Duration:5 days Regulatory Contact:Tom Fouts Permit to Drill Number:218-072 First Call Engineer:Scott Pessetto (907) 564-4373 (O) (801) 822-2203 (M) Second Call Engineer:Taylor Wellman (907) 777-8449 (O) (907) 947-9533 (M) Current Bottom Hole Pressure: 1,444 psi @ 3,824’ TVD Downhole Gauge |7.3 PPGE Max Potential Surface Pressure: 1,062 psi Gas Column Gradient (0.1 psi/ft) Max Angle:61° @ 2,100’ MD Brief Well Summary: MPL-57 is an online Schrader producer with a lateral drilled in the NB sand. MPL-57 was drilled in 2018. The reservoir completion is a fine mesh screen completion. While on ESP lift from 2022 to 2023 the flowing bottom hole pressure steadily climbed while on ESP production. An elective ESP swap was performed in March of 2023 due to belief the pump had worn out. The newly installed ESP was put on production but shorted out after 3 weeks of production. Long ESP lead times lead to working over the well to a jet pump completion. The jet pump completion successfully draws down the well but the mixture of cold power fluid and viscous oil creates emulsions that upset the oil separation processes. To reduce process upsets, Hilcorp would like to return MPL- 57 to ESP lift. Objectives: Pull 4-1/2” jet pump completion, run new ESP completion on 3-1/2” tubing. Notes Regarding Wellbore Condition: - Last 7-5/8” casing test was to 3,000 psi at 6,375’ MD on 5/19/2023. Pre-Rig Procedure Slickline (Non-sundried Work) 1. RU slickline, pressure test PCE to 250psi low / 2,500psi high. 2. Pull jet pump from sliding sleeve at 6,052’ MD. a. Leave sleeve open 3. Run caliper from tubing tail to surface. 4. RDMO. E-Line (Non-sundried Work) 1. RU E-line, pressure test PCE to 250 psi low / 2,500 psi high. 2. RIH with mechanical cutter. 3. Cut 5’ below top of first full joint above production packer. ~6,091’ 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. Well: MPL-57 PTD: 218-072 API: 50-029-23609-00-00 4. Pressure test lines to 3,000 psi. 5. Circulate at least one wellbore volume with source 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 1. MIRU Hilcorp ASR #1 WO Rig, ancillary equipment, and lines to 500 bbl 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 3-1/2” and 4-1/2” test joints. 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. RU spooler to handle gauge TEC line. 6. MU landing joint or spear, BOLDS, PU on the tubing hanger. a. Tubing hanger is a FMC Gen 5 11” x 4-1/2”, 4-1/2” TXP box top. b. PU weight ASR1: 60kip. c. SO weight ASR1: 33kip. 7. Confirm hanger free, lay down tubing hanger. 8. POOH and lay down the 4-1/2” tubing. Number all joints. a. Keep all good 4-1/2” tubing joints. Trash visibly bad joints. b. Keep gauge carrier, sliding sleeve c. Note any sand or scale inside or on the outside of the tubing. d. Look for over-torqued connections from previous tubing runs, trash these joints. e. Clamp Totals i. Cross Collar clamos: 80 9. RIH with new 3-1/2” 9.2# L-80 ESP completion to +/- 5,700’ and obtain string weights. a. Check electrical continuity every 1000’. b. Note PU and SO weights on tally. c. Install ESP clamps per ESP toolhand, and cross coupling clamps every other joint Well: MPL-57 PTD: 218-072 API: 50-029-23609-00-00 d. Run single 3/8” cap string the length of the completion, clamping with cable. Nom. (OD)Length Item Lb/ft Material Notes 5.85 2 Centralizer 4 ~5,700’ 4.5 2 Intake Sensor 30 5.62 34 Motor 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 45 1 Ported Discharge Head 13 L-80 3-1/2" 10 3-1/2" EUE 8rd Pup Jt 9.2 L-80 3-1/2" 30 3-1/2" EUE 8rd L-80 9.2 L-80 3-1/2”10 3-1/2" EUE 8rd Pup Jt 9.2 L-80 3-1/2”2 3-1/2” XN-nipple 9.2 L-80 3-1/2”10 3-1/2" EUE 8rd Pup Jt 9.2 L-80 3-1/2” 60 3-1/2" EUE 8rd Jt 9.2 L-80 3-1/2”10 3-1/2" EUE 8rd Pup Jt 9.2 L-80 3-1/2”"8 3-1/2" x 1" GLM, DV installed 9.2 L-80 3-1/2"10 3-1/2" EUE 8rd Pup Jt 9.2 L-80 3-1/2” 5,040 3-1/2" EUE 8rd Jt 9.2 L-80 3-1/2”10 3-1/2" EUE 8rd Pup Jt 9.2 L-80 3-1/2”8 3-1/2" x 1" GLM, 1/4" OV 9.2 L-80 ~200 MD 3-1/2”10 3-1/2" EUE 8rd Pup Jt 9.2 L-80 3-1/2” 150 3-1/2" EUE 8rd Jt 9.2 L-80 3-1/2” 10 Space out pup 9.2 L-80 3-1/2” 30 Tubing Hanger with full joint 9.2 L-80 10. Land tubing hanger. Use extra caution to not damage cable. 11. Lay down landing joint. 12. Set BPV. 13. 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. Well: MPL-57 PTD: 218-072 API: 50-029-23609-00-00 Attachments: 1. Current Wellbore Schematic 2. Proposed Wellbore Schematic 3. BOPE Schematic _____________________________________________________________________________________ Revised By: TDF 6/16/2023 SCHEMATIC Milne Point Unit Well: MPU L-57 Last Completed: 5/21/2023 PTD: 218-072 TD =13,941’(MD) /TD =3,699’ (TVD) 16” Orig. KB Elev.: 34.1’ / GL Elev.: 15.2’ 7-5/8” 4 9 9-5/8” 1 2 3 10 See Screen/ Solid Liner Detail PBTD =13,926’ (MD) / PBTD = 3,700’ (TVD) 9-5/8” ‘ES’ Cementer @ 2,447’ MD 4-1/2” Shoe @ 13,931’ 6 7 8 5 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 16" Conductor 164 / A53B / Weld N/A Surface 114’ N/A 9-5/8" Surface 40 / L-80 / TXP 8.835 Surface 6,715’ 0.0758 7-5/8” Tieback 29.7 / L-80 / Hyd 521/Vam STL 6.875 Surface 6,536’ 0.0459 4-1/2” Liner 250ђ Screens 13.5 / L-80 / Hyd 625 3.920 6,527’ 13,931’ .0149 TUBING DETAIL 4-1/2" Tubing 12.6 / L-80 /BTC 3.958 Surface 6,527’ 0.0152 OPEN HOLE / CEMENT DETAIL Conductor ±270 ft3 12-1/4"Stg 1 – Lead - 562 sx / Tail – 400 sx Stg 2 – Lead – 378 sx / Tail – 270 sx Class G (250 bbls to surface) 8-1/2” Cementless Screens Liner in 8-1/2” hole WELL INCLINATION DETAIL KOP @ 543’ Max Hole Angle = 94.47° @ 13,941’ MD TREE & WELLHEAD Tree Cameron 2-9/16" 5M Wellhead FMC Gen V GENERAL WELL INFO API: 50-029-23609-00-00 Completion Date: 7/28/18 ESP Swap by ASR#1 – 3-15-2023 Conv. To Rev Circ Jet Pump by ASR#1 – 5/24/2023 4-1/2” SOLID LINER DETAIL Jts Top (MD) Top (TVD) Btm (MD) Btm (TVD) 4 6,555’ 3,943’ 6,720’ 3,939’ JEWELRY DETAIL No. Top MD Item ID 1 6,052’ 4-1/2" Sliding Sleeve - 3.813” X 3.958” 2 6,073’ Baker Zenith Gauge Carrier 3.865” 3 6,134’ 7-5/8" X 4.5" VCT PHP. ISO Packer 3.958” 4 6,192’ XN Nipple w/ RHC Installed-3.813 NoGo 3.813” 5 6,491’ 4-1/2" WLEG –Btm @ 6,527’3.958” 6 6,527’ BOT SLZXP LTP / Liner Hanger 7” x 9-5/8”(TVD 3,942’)6.190” 7 6,536’ 7-5/8” Tieback Assy. 6.151” 8 6,549’ 7” H563 x 4.5” Hyd 625 XO 3.850” 9 13,895’ 4-1/2” Drillable Packoff Sub 2.390” 10 13,926’ WIV Valve LTC BxB (1” Ball on Seat/Closed) - 4-1/2” SCREEN LINER DETAIL Jts Type Top (MD)Top (TVD) Btm (MD) Btm (TVD) 79 Bkr Xcluder 6,720’ 3,939’ 9,792’ 3,831’ 96 Halliburton 9,972’ 3,831’ 13,851’ 3,705’ _____________________________________________________________________________________ Revised By: TDF 8/11/2023 PROPOSED Milne Point Unit Well: MPU L-57 Last Completed: 7/28/18 PTD: 218-072 TD =13,941’ (MD) / TD =3,699’ (TVD) 4 16” Orig. KB Elev.: 34.1’ / GL Elev.: 15.2’ 7-5/8” 7 8/9 1 0 4 16 9-5/8” 1 2 3 17 See Screen/ Solid Liner Detail PBTD =13,926’ (MD) / PBTD =3,700’ (TVD) 9-5/8” ‘ES’ Cementer @ 2,447’ MD 5/6 4-1/2” Shoe @ 13,931’ 11 13 1214 15 2-7/8” 11111111122222222222222 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 16" Conductor 164 / A53B / Weld N/A Surface 114’ N/A 9-5/8" Surface 40 / L-80 / TXP 8.835 Surface 6,715’ 0.0758 7-5/8” Tieback 29.7 / L-80 / Hyd 521/Vam STL 6.875 Surface 6,536’ 0.0459 4-1/2” Liner 250ђ Screens 13.5 / L-80 / Hyd 625 3.920 6,527’ 13,931’ .0149 TUBING DETAIL 3-1/2" Tubing 9.2 / L-80 / EUE-8rd 2.992 Surface ±5,700’ 0.0087 3/8” Cap String 3/8” Stainless Steel N/A Surface ±5,700’ N/A OPEN HOLE / CEMENT DETAIL Conductor ±270 ft3 12-1/4"Stg 1 – Lead - 562 sx / Tail – 400 sx Stg 2 – Lead – 378 sx / Tail – 270 sx Class G (250 bbls to surface) 8-1/2” Cementless Screens Liner in 8-1/2” hole WELL INCLINATION DETAIL KOP @ 543’ Max Hole Angle = 94.47° @ 13,941’ MD TREE & WELLHEAD Tree Cameron 2-9/16" 5M Wellhead FMC Gen V 4-1/2” SOLID LINER DETAIL Jts Top (MD) Top (TVD) Btm (MD) Btm (TVD) 4 6,555’ 3,943’ 6,720’ 3,939’ JEWELRY DETAIL No. Top MD Item ID 1 ±200’ GLM: 3-1/2” x 1” Side Pocket w/ DPSOV 2.347” 2 ±X,XXX’ GLM w/Dummy: 3-1/2” x 1”2.347” 3 ±X,XXX’ XN Nipple, 2.666” no go 2.205” 4 ±X,XXX’ Discharge Head: 5 ±X,XXX’ Upper Tandem Pump: 6 ±X,XXX’ Lower Tandem 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’ Sensor, Zenith 12 ±X,XXX’ Centralizer: Bottom @ ±5,700’ 13 6,527’ BOT SLZXP LTP / Liner Hanger 7” x 9-5/8”(TVD 3,942’) 6.190” 14 6,536’ 7-5/8” Tieback Assy. 6.151” 15 6,549’ 7” H563 x 4.5” Hyd 625 XO 3.850” 16 13,895’ 4-1/2” Drillable Packoff Sub 2.390” 17 13,926’ WIV Valve LTC BxB (1” Ball on Seat/Closed) - 4-1/2” SCREEN LINER DETAIL Jts Type Top (MD)Top (TVD) Btm (MD) Btm (TVD) 79 Bkr Xcluder 6,720’ 3,939’ 9,792’ 3,831’ 96 Halliburton 9,972’ 3,831’ 13,851’ 3,705’ GENERAL WELL INFO API: 50-029-23609-00-00 Completion Date: 7/28/18 ESP Swap by ASR#1 – 3-15-2023 Conv. To Rev Circ Jet Pump by ASR#1 – 5/24/2023 Updated 8/11/2020 Milne Point ASR Rig 1 BOPE 2022 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 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: Conv. To Rev. Circ Jet Pump 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 13,941 feet N/A feet true vertical 3,699 feet N/A feet Effective Depth measured 13,926 feet 6,134 & 6,527 feet true vertical 3,700 feet 3,848 & 3,941 feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth)4-1/2" 12.6 / L-80 /BTC 6,527' 3,941' VCT PHP. ISO Packer 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: 8,540psi 5,750psi 6,890psi 9,020psi 6,536' 3,942' Burst N/A Collapse N/A 3,090psi 4,790psi 7,404' Casing Conductor 3,699'13,931' 6,536' 6,715'Surface Tieback Liner 16" 9-5/8" 7-5/8"" 114' 6,715' measured TVD 4-1/2" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 218-072 50-029-23609-00-00 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-57 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) 530 Gas-Mcf MD 114' 240 Size 114' 3,939' 158 1877168 572 232179 357 323-256 Sr Pet Eng: Sr Pet Geo: Sr Res Eng: WINJ WAG 140 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. N/A Scott Pessetto scott.pessetto@hilcorp.com 907-564-4373 ffft t t s s PL G 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 11:16 am, Jun 20, 2023 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143) Date: 2023.06.20 10:19:51 - 08'00' Taylor Wellman (2143) DSR-6/21/23WCB 2-29-2024` _____________________________________________________________________________________ Revised By: TDF 6/16/2023 SCHEMATIC Milne Point Unit Well: MPU L-57 Last Completed: 5/21/2023 PTD: 218-072 TD =13,941’(MD) /TD =3,699’ (TVD) 16” Orig. KB Elev.: 34.1’ / GL Elev.: 15.2’ 7-5/8” 4 9 9-5/8” 1 2 3 10 See Screen/ Solid Liner Detail PBTD =13,926’ (MD) / PBTD = 3,700’ (TVD) 9-5/8” ‘ES’ Cementer @ 2,447’ MD 4-1/2” Shoe @ 13,931’ 6 7 8 5 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 16" Conductor 164 / A53B / Weld N/A Surface 114’ N/A 9-5/8" Surface 40 / L-80 / TXP 8.835 Surface 6,715’ 0.0758 7-5/8” Tieback 29.7 / L-80 / Hyd 521/Vam STL 6.875 Surface 6,536’ 0.0459 4-1/2” Liner 250ђ Screens 13.5 / L-80 / Hyd 625 3.920 6,527’ 13,931’ .0149 TUBING DETAIL 4-1/2" Tubing 12.6 / L-80 /BTC 3.958 Surface 6,527’ 0.0152 OPEN HOLE / CEMENT DETAIL Conductor ±270 ft3 12-1/4"Stg 1 – Lead - 562 sx / Tail – 400 sx Stg 2 – Lead – 378 sx / Tail – 270 sx Class G (250 bbls to surface) 8-1/2” Cementless Screens Liner in 8-1/2” hole WELL INCLINATION DETAIL KOP @ 543’ Max Hole Angle = 94.47° @ 13,941’ MD TREE & WELLHEAD Tree Cameron 2-9/16" 5M Wellhead FMC Gen V GENERAL WELL INFO API: 50-029-23609-00-00 Completion Date: 7/28/18 ESP Swap by ASR#1 – 3-15-2023 Conv. To Rev Circ Jet Pump by ASR#1 – 5/24/2023 4-1/2” SOLID LINER DETAIL Jts Top (MD) Top (TVD) Btm (MD) Btm (TVD) 4 6,555’ 3,943’ 6,720’ 3,939’ JEWELRY DETAIL No. Top MD Item ID 1 6,052’ 4-1/2" Sliding Sleeve - 3.813” X 3.958” 2 6,073’ Baker Zenith Gauge Carrier 3.865” 3 6,134’ 7-5/8" X 4.5" VCT PHP. ISO Packer 3.958” 4 6,192’ XN Nipple w/ RHC Installed-3.813 NoGo 3.813” 5 6,491’ 4-1/2" WLEG –Btm @ 6,527’3.958” 6 6,527’ BOT SLZXP LTP / Liner Hanger 7” x 9-5/8”(TVD 3,942’)6.190” 7 6,536’ 7-5/8” Tieback Assy. 6.151” 8 6,549’ 7” H563 x 4.5” Hyd 625 XO 3.850” 9 13,895’ 4-1/2” Drillable Packoff Sub 2.390” 10 13,926’ WIV Valve LTC BxB (1” Ball on Seat/Closed) - 4-1/2” SCREEN LINER DETAIL Jts Type Top (MD)Top (TVD) Btm (MD) Btm (TVD) 79 Bkr Xcluder 6,720’ 3,939’ 9,792’ 3,831’ 96 Halliburton 9,972’ 3,831’ 13,851’ 3,705’ Well Name Rig API Number Well Permit Number Start Date End Date MP L-57 Slickline & LRS 50-029-23609-00-00 218-072 4/26/2023 5/24/2023 No operations to report. No operations to report. 4/29/2023 - Saturday No operations to report. 5/2/2023 - Tuesday 4/30/2023 - Sunday No operations to report. 5/1/2023 - Monday 4/28/2023 - Friday WELL S/I ON ARRIVAL. DRIFTED TBG W/ 2.70" CENT & 1-3/4" SAMPLE BAILER TO 3500' SLM, TOOLS FALLING SLOWLY. PULLED BEK-DPSOV FROM ST#1 @ 139' MD. SET BK-DGLV IN ST#1 @ 139' MD. LRS DISPLACED TBG W/ 55 BBLS OF PRODUCED WATER & DIESEL FREEZE PROTECT. DRIFTED TBG W/ 2.70" CENT & 1-3/4" SAMPLE BAILER, TAGGED ESP @ 5410' SLM.(no sample). PULLED BK-DGLV FROM ST#2 @ 5250'MD. >>>>>POCKET LEFT OPEN<<<<<. WELL S/I ON DEPARTURE, PAD-OP NOTIFIED OF WELL STATUS. 4/26/2023 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary T/I/O=163/173/0 MIT-OA Passed to 1592 psi. Pressured up OA to 1631 psi with 2.25 bbls diesel. 1st 15 min OA lost 33 psi. 2nd 15 min OA lost 6 psi for a total loss of 39 psi in 30 min. Bled OA to 0 psi and recovered 2.4 bbls. Final Whps=163/173/0 4/27/2023 - Thursday No operations to report. Well Name Rig API Number Well Permit Number Start Date End Date MP L-57 LRS & ASR 50-029-23609-00-00 218-072 4/26/2023 5/24/2023 Accept rig @ 22:00 hrs. Perform shell test of BOP's -test failed, Leaking out of weep hole on pit side of pipe rams. Blow down stack and open pipe ram door. Remove ram and replace mud seal. No operations to report. 5/13/2023 - Saturday WELLHEAD: Well kill complete, set 3" CTS bpv w/ T bar. ND tree/adapter, install CTS plug, R54 gasket and plug CL port. Check lift threads 3 1/2" TC11 8 1/2 turns. Set and NU BOP stack. 5/16/2023 - Tuesday 5/14/2023 - Sunday T/I/O = 157/200/0 Well Kill PRWO, Pumped 20 bbls hot diesel down Tubing taking returns up IA to tank, Pumped 580 bbls water down Tubing taking returns up IA into tank, Freeze Protect all surface lines with 60/40 FWP = 0/0/0. 5/15/2023 - Monday 5/12/2023 - Friday No operations to report. 5/10/2023 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary No operations to report. 5/11/2023 - Thursday No operations to report. Well Name Rig API Number Well Permit Number Start Date End Date MP L-57 LRS & ASR 50-029-23609-00-00 218-072 4/26/2023 5/24/2023 Continue RIH w/ 4-1/2 completion jewelry backer install tech wire on gauge. Continue RIH w/ 4-1/2 completion to 1,400'. Toolpusher noticed pipe still had storage compound on threads. decision was made to POOH and clean all threads. POOH to to WLEG. Clean threads on all jewelry and pipe in pipe shed. P/U 4-1/2 completion and jewelry. RIH to jt 23. Found multiple bad joint. replaced joint and collar on the joint in the hole on 2 joints. Continue to RIH w/ 4-1/2 completion taking extra time to clean threads. RIH to to 2,641. 5/20/2023 - Saturday WELLHEAD: MU 4-1/2" 563 lift and LJ to tbg hgr, PU and MU to comp.string. Run 1/4'" tech line through bottom of hgr cut 10 ft long and wrap around hgr nech. Five ft into profile RKB 18.40, RILDS, RIG pump and drop ball/rod/test. Set 4" bpv, RD. BOP stack pulled, clean tbg hgr void and term. 1/4" tech line through tbg spool. Install RX54 gasket, SBMS metal seal and land tree/adapter. Torque to spec and test 500/5000 (PASS). Pull Bpv with dry rod, all valves in correct position tree cap with manifold installed. 5/21/2023 - Sunday Continue RIH w/ 4-1/2 completion checking tech wire every 1000' from 2,724' to 4,372'. taking time to clean threads on pin and box ends. Service rig, check fluid levels and grease tongs and carriage. Continue RIH w/ 4-1/2 completion checking tech wire every 1000' from 4,372' to 6,535' RKB with 5K, confirm tag 2 times. L/D 1 jt and P/U space out pups and hanger. Terminate tech wire and land hanger (dn wt 33K, up wt 60K) EOT @ 6,527' OKB. 80 clamps ran. RILD's and R/U lines to spot corrosion inhibitor. Pump 25 bbls of 1% CI source water and spot in place with 105 bbls of source water. 3.5BPM/125 psi. Install landing jt. and drop ball and rod. Fill tubing. Service rig and check fluid levels. Set packer and perform MIT tubing to 3800 psi for 30 min. Bleed down tubing to 1000 psi. Fill annulus and perform MIT IA to 3000 psi for 30 min. Bleed off pressures. Pull landing jt and install BPV. Clear rig floor, Blow down all mud lines, clear pipe shed. and begin rigging down equipment, Prep to move rig. Rig released at 06:00 hrs. 5/22/2023 - Monday 5/19/2023 - Friday Continue POOH w/ 3-1/2 workstring and scraper from 2,527 to surface. L/d scraper. P/U test packer and handling pup. torque all XO'S and handling pup. RIH w/ 3-1/2 work string and test packer. Service rig and check fluid levels. Cont. RIH w/ 3-1/2 work string and test packer. Set packer @ 6375', fill hole and test casing to 3000 psi for 30 min. (good test). Release packer. POOH with test packer. Service rig and check fluid levels. Cont. POOH and L/D test packer. Clean and clear rig floor, Change out handling equipment. Prep completion equipment and load tubing into pipe shed. String tech wire and hang sheave. P/U and RIH with 4 1/2" 12.6# L-80 completion. 5/17/2023 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary Continue to repair BOP stack, service rig and check fluid levels. Test BOPE to 250 low / 2500 high for 5 min each. replaced valve #7. Perform Koomey draw down test. AOGCC waived witness - Guy Cook. Blow down BOPs and all mud lines. Pull CTS plug and BPV, install landing jt and BOLDS. Pull hanger to floor ( 52K up wt.). Cut cable and test ESP cable (grounded out) Prep to POOH with ESP completion. POOH with ESP and work cable through sheaves and to spooling unit. POOH with ESP. 5/18/2023 - Thursday Continue POOH w/ 3-1/2 EUE and ESP Completion. to discharge head. L/D ESP equipment as per Baker rep. Found evidence of arcing on motor lead. Motor lead was parted. Top pump was locked up. All clamps accounted for. Clean and clear rig floor. L/D elephant trunk and sheave. clear pipe shed of EUE and ESP equipment. load racks with work string.tally pipe. Swap over handling equipment. P/U M/U 7-5/8 scraper. RIH w/ 3-1/2 workstring and scraper from 5' to 2,927'. Found coolant leak on rig carrier engine, replaced pressure relief cap. Continue to TIH and tag packer at 6523', Reciprocated 6307 to 6387'. POOH f/ 6523' to 4489'. Service rig and check fluids. POOH f/ 4489' to 4230'. Founds overflow on carrier radiator full, remove extra fluid and replace thermostat. Cont. to POOH with scraper BHA. Continue POOH w/ 3-1/2 workstring and scraper from 2,527 to surface Continue POOH w/ 3-1/2 EUE and ESP Completion MU 4-1/2" 563 lift and LJ to tbg hgr Continue to RIH w/ 4-1/2 completion taking extra time to clean threads. RIH to to 2,641 Set packer @ 6375', Continue RIH w/ 4-1/2 completion to 1,400'. Set packer and perform MIT tubing to 3800 psi for 30 min. Bleed down tubing to 1000 psi. Fill annulus and perform MIT IA to 3000 psi for 30 min. Bleed off pressures. Pu Well Name Rig API Number Well Permit Number Start Date End Date MP L-57 LRS & ASR 50-029-23609-00-00 218-072 4/26/2023 5/24/2023 5/26/2023 - Friday No operations to report. 5/24/2023 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary SHIFT XD-SS OPEN AT 6,051' MD W/ 4-1/2" 42BO. PULL 4-1/2" RHC FROM XN-NIPPLE AT 6,191' MD. LRS PUMPED 10bbls DIESEL DOWN IA TO CONFIRM SLEEVE IS OPEN, 10bbls DIESEL DOWN TUBING. SET 3" JETPUMP (ratio: 12B) IN XD-SS AT 6,051' MD. WELL SHUT-IN ON DEPARTURE, PAD OP NOTIFIED. 5/25/2023 - Thursday No operations to report. No operations to report. No operations to report. 5/27/2023 - Saturday No operations to report. 5/30/2023 - Tuesday 5/28/2023 - Sunday No operations to report. 5/29/2023 - Monday PULL 4-1/2" RHC FROM XN-NIPPLE AT 6,191' MD 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: Conv. to Rev. Circ. Jet Pump 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address: Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception? Yes No 9. Property Designation (Lease Number): 10. Field: Current Pools: 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 13,941'N/A Casing Collapse Conductor N/A Surface 3,090psi Tieback 4,790psi 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: Operations Manager Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: AOGCC USE ONLY scott.pessetto@hilcorp.com 907-564-4373 Scott Pessetto Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): Tubing Size: 9.2# / L-80 / EUE 8rd 5,535' 4/27/2023 BOT SLZXP Packer and N/A 6,527 MD/ 3,942 TVD and N/A See Schematic See Schematic 3-1/2" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0025509 & ADL0025515 218-072 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 50-029-23609-00-00 Hilcorp Alaska LLC SCHRADER BLUFF OIL N/A C.O. 477.05 MILNE PT UNIT L-57 Length Size Proposed Pools: 114' 114' TVD Burst PRESENT WELL CONDITION SUMMARY 3,699' 13,926' 3,700' 1,057 N/A 114' 16" MILNE POINT MD N/A 9,020psi 5,750psi 6,890psi 3,939' 3,942' 3,699' 6,715' 6,536' 13,931' 9-5/8" 7-5/8"" 6,715' 6,536' Perforation Depth MD (ft): 4-1/2"7,404' Form 10-403 Revised 10/2022 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov 323-256 By Kayla Junke at 2:31 pm, Apr 25, 2023 Digitally signed by David Haakinson (3533) DN: cn=David Haakinson (3533), ou=Users Date: 2023.04.25 13:20:50 -08'00' David Haakinson (3533) *Approved for reverse circulation jet pump completion with 7" or 7-5/8" tie back, passing MIT-OA to 1500 psi and passing MIT-IA to maximum power fluid injection pressure. *IA SSV high pressure trip not to exceed 10% greater than expected maximum header injection pressure. * IA low pressure trip not to be lower than 50% of expected maximum header injection pressure. *Production tubing SSV not to be lower than 100 psi. *SSV closure on IA will intiate closure on SSV on production tubing and visa versa within 2 minutes. MGR04MAY23 BOPE pressure test to 2500 psi. SFD 4/25/2023 DSR-4/26/23 1,057 10-404 JLC 5/4/2023 05/04/2023 Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2023.05.04 13:46:26 -08'00' RBDMS JSB 050823 Well: MPL-57 PTD: 218-072 API: 50-029-23609-00-00 Well Name:MPL-57 API Number:50-029-23609-00-00 Current Status:Shut-in Producer Rig:ASR Estimated Start Date:4/27/2023 Estimated Duration:5 days Regulatory Contact:Tom Fouts Permit to Drill Number:218-072 First Call Engineer:Scott Pessetto (907) 564-4373 (O) (801) 822-2203 (M) Second Call Engineer:Taylor Wellman (907) 777-8449 (O) (907) 947-9533 (M) Current Bottom Hole Pressure: 1,409 psi @ 3,525’ TVD ESP Intake Sensor |7.7 PPGE Max Potential Surface Pressure: 1,057 psi Gas Column Gradient (0.1 psi/ft) Max Angle:61° @ 2,100’ MD Brief Well Summary: MPL-57 is an online Schrader producer with a lateral drilled in the NB sand. MPL-57 was drilled in 2018. The reservoir completion is a fine mesh screen completion. For the last two years the flowing bottom hole pressure has steadily climbed while on ESP production. An elective ESP swap was performed in March of 2023. In April 2023 the ESP failed due to an electrical ground at the ESP motor. Due to the short life of ESPs Hilcorp is requesting to convert this well to a jet pump producer. Objectives: Pull failed ESP completion, run new 4-1/2” reverse circulating jet pump completion. Notes Regarding Wellbore Condition: Pre-Rig Procedure Slickline 1. RU slickline, pressure test PCE to 250psi low / 2,500psi high. 2. Drift and tag with sample bailer. 3. Pull dummy valve from GLM at 5,250’ MD and leave open. 4. Pull GLV and set dummy valve in upper GLM at 139’ MD. 5. LRS perform MIT-OA to 1,500 psi to confirm initial casing integrity. 6. 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 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. Well: MPL-57 PTD: 218-072 API: 50-029-23609-00-00 Brief RWO Procedure 1. MIRU Hilcorp ASR #1 WO Rig, ancillary equipment, and lines to 500 bbl 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 3-1/2” and 4-1/2” test joints. 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 spooler to handle ESP cable and a 3/8” capillary string. a. Use extreme care in spooling the capillary string to promote reuse of the string. 7. MU landing joint or spear, BOLDS, PU on the tubing hanger. a. Tubing hanger is a FMC 11” 11” x 3-1/2”, TC-II 9.2 lb/ft Top and Btm CIW H BPV b. ESP completion PU weight was 50kip. SO was 25kip. 8. Confirm hanger free, lay down tubing hanger. 9. POOH and lay down the 3-1/2” tubing. Number all joints. a. Because tubing was run last month, keep all joints except visibly bad joints. Utilize in the next M-pad injector. 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. Look for over-torqued connections from previous tubing runs, trash these joints. e. Look for cable damage or signs of a reason for a motor short. f. Clamp Totals i. Canon Clamps: 98 ii. Motor Body Clamps: 2 iii. Seal Clamps: 4 iv. Pump Clamps: 6 10. Lay Down ESP. 11. Pressure test pulled 3/8” capillary tubing to 3500 psi. If PT passes, keep cap string. 12. PU and RIH with 7-5/8” casing scraper and muleshoe on 3-1/2” workstring to 6,527’. a. Reciprocate across planned packer set depth of ~6,369’ MD. 13. POOH with casing scraper while filling with 2x pipe displacement. 14. RIH with 7-5/8” test packer on 3-1/2” work string to 6,369’ MD. Well: MPL-57 PTD: 218-072 API: 50-029-23609-00-00 15. Test casing to 3,000 psi for 30 minutes. Contingency: If the 7-5/8” casing fails to pass a pressure test. Contingency steps in red. 16. Change out handling equipment, install casing crew tongs, and upper rams for 7-5/8” casing. 17. Perform BOP test on the 7-5/8” pipe rams on a 7-5/8” test joint to 500/ 2500 psi. 18. Install casing jacks on top of the BOP stack and function test. 19. Utilize casing jacks to unseat and pull the 7-5/8” casing. a. 2018 Installation i. PU Weight: 180K ii. SO Weight: 122K iii. Block Weight: 40K b. Use casing jacks to pull 7-5/8” casing until string weight is within limits of ASR i. Call out spider slips to allow pulls over 180K without crimping pipe c. Inspect and reuse 7” bullet seals if condition is good. 20. Swap pipe rams to 2-7/8” x 5” rams and test 3-1/2” test joint to 500/2,500 psi. 21. Make up clean out assembly to fluff and stuff casing. a. Rig up LRS and fluff fill pumping down workstring and then bullhead down annulus with LRS pushing fill into the liner. 22. If OA did not test during pre-ASR wellwork, pick up 7” seal assembly with 9-5/8” test packer and sting seals into SLZXP, load well, and PT 9-5/8” casing to 1,500 psi. a. If the test fails, an additional SLZXP will need to be stacked above the leak depth. 23. Swap pipe rams to 7” rams and test 7” test joint to 500 / 2,500 psi. 24. Run 7” casing with bullet seal assembly. Space out and PU to circulate in 1% KCl with corrosion inhibitor with a diesel freeze protect into the 7” x 9-5/8” annulus. 25. Land the 7” casing and pressure test the 7” x 9-5/8” annulus to 1,000 psi. 7-5/8” or 7” Casing Integrity Confirmed: 26. POOH of with test packer, while filling 2x pipe displacement. 27. RIH with new 4-1/2” 12.6# L-80 jet pump completion to +/- 6,527’ and obtain string weights. a. Note PU and SO on tally. b. Clamp TEC line first five joints from gauge and then every other joint. Nom. Size ~Length Item Lb/ft Material Notes 4-1/2”41 4-1/2" WLEG - Mule Shoe 12.6 L-80 Inside LTP tieback 4-1/2” 264 4-1/2" TXP 12.6 L-80 4-1/2”10 4-1/2' 12.6# TXP Pup Jt 12.6 L-80 4-1/2”2 XN Nipple - 3.75 NoGo 12.6 L-80 RHC Plug Installed 4-1/2”10 4-1/2' TXP Pup Jt 12.6 L-80 4-1/2” 41 4-1/2" TXP L-80 12.6 L-80 4-1/2”10 4-1/2' TXP Pup Jt 12.6 L-80 4-1/2”7 Hydraulic Set Packer 7-5/8" x 4-1/2"L-80 ~6,150’ 4-1/2”10 4-1/2' TXP Pup Jt 12.6 L-80 4-1/2” 41 4-1/2" TXP L-80 12.6 L-80 4-1/2”10 4-1/2' TXP Pup Jt 12.6 L-80 4-1/2”2 Baker Zenith Gauge Carrier L-80 or to maximum power fluid injection pressure whichever is greater. - mgr Well: MPL-57 PTD: 218-072 API: 50-029-23609-00-00 4-1/2”10 4-1/2' TXP Pup Jt 12.6 L-80 4-1/2”10 4-1/2' TXP Pup Jt 12.6 L-80 4-1/2”5 4-1/2" Sliding Sleeve - 3.813” X L-80 Blanked Port 4-1/2”10 4-1/2' TXP Pup Jt 12.6 L-80 4-1/2” ~6,000 4-1/2" TXP Joints 12.6 L-80 4-1/2” Hanger Pup 12.6 L-80 4-1/2” Tubing Hanger 12.6 L-80 28. Space out and make up tubing hanger. Terminate gauge TEC line to hanger. Test gauge. 29. Land tubing hanger. Use extra caution to not damage cable. RILDS. 30. Place 1% KCl inhibited fluid in the annulus below the sliding sleeve a. Annular volume packer to sliding sleeve : 5 bbls b. Displacement down annulus to place inhibited fluid: 164 bbls c. Confirm with Wells/OE that FP can be completed post-rig. 31. Drop ball and rod. Pump ball and rod to seat, taking returns to formation. 32. Pressure up and set packer per vendor instructions. 33. Perform 30 minute charted MIT-T to 3,000 psi. 34. Perform 30 minute charted MIT-IA to 3,000 psi. 35. Lay down landing joint. 36. Set BPV. 37. 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 SL and test PCE to 3,000 psi. 2. RIH and Retrieve Ball and Rod and RHC Plug. 3. Open sliding sleeve. 4. RIH W/ 12B Jet Pump and set. 5. RD SL Unit. 6. Turn Well over to production Attachments: 1. Current Wellbore Schematic or maximum power fluid injection pressure, whichever is greater. - mgr Well: MPL-57 PTD: 218-072 API: 50-029-23609-00-00 2. Proposed Wellbore Schematic 3. BOPE Schematic _____________________________________________________________________________________ Revised By: TDF 4/11/2023 SCHEMATIC Milne Point Unit Well: MPU L-57 Last Completed: 3/15/2023 PTD: 218-072 TD =13,941’(MD) /TD =3,699’ (TVD) 16” Orig. KB Elev.: 34.1’ / GL Elev.: 15.2’ 7-5/8” 9 10 & 11 12 4 18 9-5/8” 1 2 3 19 See Screen/ Solid Liner Detail PBTD =13,926’ (MD) / PBTD = 3,700’ (TVD) 9-5/8” ‘ES’ Cementer @ 2,447’ MD 6,7 & 8 4-1/2” Shoe @ 13,931’ 13 15 1416 17 2-7/8” 4&5 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 16" Conductor 164 / A53B / Weld N/A Surface 114’ N/A 9-5/8" Surface 40 / L-80 / TXP 8.835 Surface 6,715’ 0.0758 7-5/8” Tieback 29.7 / L-80 / Hyd 521/Vam STL 6.875 Surface 6,536’ 0.0459 4-1/2” Liner 250ђ Screens 13.5 / L-80 / Hyd 625 3.920 6,527’ 13,931’ .0149 TUBING DETAIL 3-1/2" Tubing 9.2 / L-80 / EUE-8rd 2.992 Surface ±5,535’ 0.0087 3/8” Cap String 3/8” Stainless Steel N/A Surface ±5,535’ N/A OPEN HOLE / CEMENT DETAIL Conductor ±270 ft3 12-1/4"Stg 1 – Lead - 562 sx / Tail – 400 sx Stg 2 – Lead – 378 sx / Tail – 270 sx Class G (250 bbls to surface) 8-1/2” Cementless Screens Liner in 8-1/2” hole WELL INCLINATION DETAIL KOP @ 543’ Max Hole Angle = 94.47° @ 13,941’ MD TREE & WELLHEAD Tree Cameron 2-9/16" 5M Wellhead FMC Gen V GENERAL WELL INFO API: 50-029-23609-00-00 Completion Date: 7/28/18 ESP Swap by ASR#1 – 3-15-2023 4-1/2” SOLID LINER DETAIL Jts Top (MD) Top (TVD) Btm (MD) Btm (TVD) 4 6,555’ 3,943’ 6,720’ 3,939’ JEWELRY DETAIL No. Top MD Item ID 1 139’ GLM, Camco, 3 1/2" x 1" KBMM with SOV installed 2.992” 2 5,250’ GLM, Camco, 3 1/2" x 1" KBMM with DV installed 2.992” 3 5,372’ Nipple, Halliburton, 2.313" XN profile (2.75" no-go) 2.750” 4 5,424.5’ Discharge Head: PMP 513 5 5,425’ Zenith Ported Sub: HEAD S/A B/O PRESS PORT 513/538 6 5,426’ Pump #3: 538MSXD FLEX27 82 FER H6 STD PNT 7 5,444’ Pump #2: 538MSXD FLEX27 135 FER H6 STD PNT 8 5,472 Pump #1: 538PMSXD 20 GINPSHH H6 STD PNT 9 5,482’ Gas Separator: 538GM2T HV E V X MT HS FER STD PN w/ Intake 10 5,488’ Upper Tandem Seal: GSB3DB FER HL SSCV H6 SB/SB CL-5E 11 5,495’ Lower Tandem Seal: GSB3DB FER HL SSCV H6 SB/SB CL-5E 12 5,502’ Motor: 562 XP 450/3135/88/18R 375/2615 FER 13 5,529’ Sensor, Zenith 14 5,532’ Centralizer: Bottom @ 5,535’ 15 6,527’ BOT SLZXP LTP / Liner Hanger 7” x 9-5/8”(TVD 3,942’)6.190” 16 6,536’ 7-5/8” Tieback Assy. 6.151” 17 6,549’ 7” H563 x 4.5” Hyd 625 XO 3.850” 18 13,895’ 4-1/2” Drillable Packoff Sub 2.390” 19 13,926’ WIV Valve LTC BxB (1” Ball on Seat/Closed) - 4-1/2” SCREEN LINER DETAIL Jts Type Top (MD)Top (TVD) Btm (MD) Btm (TVD) 79 Bkr Xcluder 6,720’ 3,939’ 9,792’ 3,831’ 96 Halliburton 9,972’ 3,831’ 13,851’ 3,705’ _____________________________________________________________________________________ Revised By: TDF 4/25/2023 PROPOSED Milne Point Unit Well: MPU L-57 Last Completed: 3/15/2023 PTD: 218-072 TD =13,941’(MD) /TD =3,699’ (TVD) 16” Orig. KB Elev.: 34.1’ / GL Elev.: 15.2’ 7-5/8” 9 10 & 11 124 9 9-5/8” 1 2 3 10 See Screen/ Solid Liner Detail PBTD =13,926’ (MD) / PBTD = 3,700’ (TVD) 9-5/8” ‘ES’ Cementer @ 2,447’ MD 4-1/2” Shoe @ 13,931’ 13 6 7 8 5 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 16" Conductor 164 / A53B / Weld N/A Surface 114’ N/A 9-5/8" Surface 40 / L-80 / TXP 8.835 Surface 6,715’ 0.0758 7-5/8” Tieback 29.7 / L-80 / Hyd 521/Vam STL 6.875 Surface 6,536’ 0.0459 4-1/2” Liner 250ђ Screens 13.5 / L-80 / Hyd 625 3.920 6,527’ 13,931’ .0149 TUBING DETAIL 4-1/2" Tubing 12.6 / L-80 / TXP 3.958 Surface ±6,527’ 0.0152 OPEN HOLE / CEMENT DETAIL Conductor ±270 ft3 12-1/4"Stg 1 – Lead - 562 sx / Tail – 400 sx Stg 2 – Lead – 378 sx / Tail – 270 sx Class G (250 bbls to surface) 8-1/2” Cementless Screens Liner in 8-1/2” hole WELL INCLINATION DETAIL KOP @ 543’ Max Hole Angle = 94.47° @ 13,941’ MD TREE & WELLHEAD Tree Cameron 2-9/16" 5M Wellhead FMC Gen V GENERAL WELL INFO API: 50-029-23609-00-00 Completion Date: 7/28/18 ESP Swap by ASR#1 – 3-15-2023 4-1/2” SOLID LINER DETAIL Jts Top (MD) Top (TVD) Btm (MD) Btm (TVD) 4 6,555’ 3,943’ 6,720’ 3,939’ JEWELRY DETAIL No. Top MD Item ID 1 ±6,062’4-1/2" Sliding Sleeve - 3.813” X 2 ±6,087’Baker Zenith Gauge Carrier 3 ±6,150’Hydraulic Set Packer 7-5/8" x 4-1/2" 4 ±6,208’XN Nipple - 3.75 NoGo 5 ±6,525 4-1/2" WLEG – Btm @ ±6,527 6 6,527’ BOT SLZXP LTP / Liner Hanger 7” x 9-5/8”(TVD 3,942’)6.190” 7 6,536’ 7-5/8” Tieback Assy. 6.151” 8 6,549’ 7” H563 x 4.5” Hyd 625 XO 3.850” 9 13,895’ 4-1/2” Drillable Packoff Sub 2.390” 10 13,926’ WIV Valve LTC BxB (1” Ball on Seat/Closed) - 4-1/2” SCREEN LINER DETAIL Jts Type Top (MD)Top (TVD) Btm (MD) Btm (TVD) 79 Bkr Xcluder 6,720’ 3,939’ 9,792’ 3,831’ 96 Halliburton 9,972’ 3,831’ 13,851’ 3,705’ or 7" -mgr Updated 8/11/2020 Milne Point ASR Rig 1 BOPE 2022 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 Kyle Wiseman Hilcorp Alaska, LLC Geo Tech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: Kyle.Wiseman@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 03/17/2023 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20230317 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# MPU L-57 50029236090000 218072 3/7/2023 READ CaliperSurvey SRU 23-33 50133101630000 161019 2/16/2023 AK E-LINE Jet Cut CLU-9 50133205440000 204161 2/24/2023 HALLIBURTON PPROF CLU-15 50133206870000 220003 2/26/2023 HALLIBURTON PPROF END 1-11 50029221070000 190157 2/19/2023 HALLIBURTON MFC END 1-11 50029221070000 190157 2/25/2023 HALLIBURTON PLUG-PERF KU 14X-06 50133203420000 181092 3/1/2023 HALLIBURTON LDL Please include current contact information if different from above. MPU L-57 50029236090000 218072 3/7/2023 READ CaliperSurvey STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION *All BOPE reports are due to the agency within 5 days of testing* Submit to:jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov Rig Owner:Rig No.:ASR 1 DATE:3/12/23 Rig Rep.:Rig Email: Operator: Operator Rep.:Op. Rep Email: Well Name:PTD #2180720 Sundry #323-127 Operation:Drilling:Workover:x Explor.: Test:Initial:x Weekly:Bi-Weekly:Other: Rams:250/5000 Annular:250/2500 Valves:250/2500 MASP:1057 MISC. INSPECTIONS:TEST DATA FLOOR SAFETY VALVES: Test Result/Type Test Result Quantity Test Result Housekeeping P Well Sign P Upper Kelly 1 P Permit On Location P Hazard Sec.P Lower Kelly 0 NA Standing Order Posted P Misc.NA Ball Type 1 P Test Fluid Water Inside BOP 1 P FSV Misc 0 NA BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm Stripper 0 NA Trip Tank NA NA Annular Preventer 1 11"P Pit Level Indicators P P #1 Rams 1 2-7/8" x 5" VBR P Flow Indicator P P #2 Rams 1 Blinds P Meth Gas Detector P P #3 Rams 0 NA H2S Gas Detector P P #4 Rams 0 NA MS Misc 0 NA #5 Rams 0 NA #6 Rams 0 NA ACCUMULATOR SYSTEM: Choke Ln. Valves 1 2 1/16"P Time/Pressure Test Result HCR Valves 1 2 1/16"P System Pressure (psi)2900 P Kill Line Valves 2 2 1/16"P Pressure After Closure (psi)1725 P Check Valve 0 NA 200 psi Attained (sec)17 P BOP Misc 0 NA Full Pressure Attained (sec)57 P Blind Switch Covers:All stations Yes CHOKE MANIFOLD:Bottle Precharge:P Quantity Test Result Nitgn. Bottles # & psi (Avg.):4 / 2,125 PSI P No. Valves 16 P ACC Misc 0 NA Manual Chokes 1 P Hydraulic Chokes 1 P Control System Response Time:Time (sec)Test Result CH Misc 0 NA Annular Preventer 22 P #1 Rams 6 P Coiled Tubing Only:#2 Rams 6 P Inside Reel valves 0 NA #3 Rams 0 NA #4 Rams 0 NA Test Results #5 Rams 0 NA #6 Rams 0 NA Number of Failures:0 Test Time:8.0 HCR Choke 2 P Repair or replacement of equipment will be made within days. HCR Kill 0 NA Remarks: AOGCC Inspection 24 hr Notice Yes Date/Time 3/10/23 07:00 Waived By Test Start Date/Time:3/12/2023 5:00 (date)(time)Witness Test Finish Date/Time:3/12/2023 13:00 BOPE Test Report Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Kam StJohn Hilcorp Tested rams at 5,000 psi high to proof test new stack componets, blinds & uppers. Precharge bottle psi = 1,000psi C.Pace / M. Boord Hilcorp Alaska LLC S.Heim / R. Gallen MPU L-57 Test Pressure (psi): askans-asr-toolpushers@hilcorp.co ans-asrwellsitemanagers@hilcorp Form 10-424 (Revised 08/2022)2023-0312_BOP_Hilcorp_ASR1_MPU_L-57         J. Regg; 6/14/2023 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 13,941 feet N/A feet true vertical 3,699 feet N/A feet Effective Depth measured 13,926 feet 6,257 feet true vertical 3,700 feet 3,942 feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth)3-1/2" 9.3# / L-80 / EUE 8rd Mod 5,535' 3,554' Packers and SSSV (type, measured and true vertical depth)BOT SLZXP N/A See Above N/A 12. Stimulation or cement squeeze summary: N/A Intervals treated (measured): Treatment descriptions including volumes used and final pressure: N/A 13a. Prior to well operation: Subsequent to operation: 13b. Pools active after work: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Authorized Name and Digital Signature with Date: Contact Name: Contact Email: Authorized Title: Operations Manager Contact Phone: 323-127 Sr Pet Eng: Sr Pet Geo: Sr Res Eng: WINJ WAG 6 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. N/A Scott Pessetto scott.pessetto@hilcorp.com 907-564-4373 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) 1107 Gas-Mcf MD 114' 440 Size 114' 3,939' 50 38065 88 30119 360 measured TVD 4-1/2" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 218-072 50-029-23609-00-00 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 3. Address: Hilcorp Alaska LLC N/A 5. Permit to Drill Number:2. Operator Name N 4. Well Class Before Work: ADL0025509 & ADL0025515 MILNE POINT / SCHRADER BLUFF OIL MILNE PT UNIT L-57 Plugs Junk measured Length 7,404' Casing Conductor 3,699'13,931' 6,536' 6,715'Surface Tieback Liner 16" 9-5/8" 7-5/8"" 114' 6,715' 8,540psi 5,750psi 6,890psi 9,020psi 6,536' 3,942' Burst N/A Collapse N/A 3,090psi 4,790psi Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov Digitally signed by David Haakinson (3533) DN: cn=David Haakinson (3533), ou=Users Date: 2023.04.11 17:17:49 -08'00' David Haakinson (3533) RBDMS JSB 041323 WCB 12-27-2023 218-072 323-127 MILNE PT UNIT L-57 DSR-4/13/23 _____________________________________________________________________________________ Revised By: TDF 4/11/2023 SCHEMATIC Milne Point Unit Well: MPU L-57 Last Completed: 3/15/2023 PTD: 218-072 TD =13,941’(MD) /TD =3,699’ (TVD) 16” Orig. KB Elev.: 34.1’ / GL Elev.: 15.2’ 7-5/8” 9 10 & 11 12 4 18 9-5/8” 1 2 3 19 See Screen/ Solid Liner Detail PBTD =13,926’ (MD) /PBTD =3,700’ (TVD) 9-5/8”‘ES’ Cementer @ 2,447’ MD 6,7 & 8 4-1/2” Shoe @ 13,931’ 13 15 1416 17 2-7/8” 4 &5 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 16" Conductor 164 / A53B / Weld N/A Surface 114’ N/A 9-5/8" Surface 40 / L-80 / TXP 8.835 Surface 6,715’ 0.0758 7-5/8” Tieback 29.7 / L-80 / Hyd 521/Vam STL 6.875 Surface 6,536’ 0.0459 4-1/2” Liner 250μ Screens 13.5 / L-80 / Hyd 625 3.920 6,527’ 13,931’ .0149 TUBING DETAIL 3-1/2" Tubing 9.2 / L-80 / EUE-8rd 2.992 Surface ±5,535’ 0.0087 3/8” Cap String 3/8” Stainless Steel N/A Surface ±5,535’ N/A OPEN HOLE / CEMENT DETAIL Conductor ±270 ft3 12-1/4"Stg 1 – Lead - 562 sx / Tail – 400 sx Stg 2 – Lead – 378 sx / Tail – 270 sx Class G (250 bbls to surface) 8-1/2” Cementless Screens Liner in 8-1/2” hole WELL INCLINATION DETAIL KOP @ 543’ Max Hole Angle = 94.47° @ 13,941’ MD TREE & WELLHEAD Tree Cameron 2-9/16" 5M Wellhead FMC Gen V GENERAL WELL INFO API: 50-029-23609-00-00 Completion Date: 7/28/18 ESP Swap by ASR#1 – 3-15-2023 4-1/2” SOLID LINER DETAIL Jts Top (MD) Top (TVD) Btm (MD) Btm (TVD) 4 6,555’ 3,943’ 6,720’ 3,939’ JEWELRY DETAIL No. Top MD Item ID 1 139’ GLM, Camco, 3 1/2" x 1" KBMM with SOV installed 2.992” 2 5,250’ GLM, Camco, 3 1/2" x 1" KBMM with DV installed 2.992” 3 5,372’ Nipple, Halliburton, 2.313" XN profile (2.75" no-go) 2.750” 4 5,424.5’ Discharge Head: PMP 513 5 5,425’ Zenith Ported Sub: HEAD S/A B/O PRESS PORT 513/538 6 5,426’ Pump #3: 538MSXD FLEX27 82 FER H6 STD PNT 7 5,444’ Pump #2: 538MSXD FLEX27 135 FER H6 STD PNT 8 5,472 Pump #1: 538PMSXD 20 GINPSHH H6 STD PNT 9 5,482’ Gas Separator: 538GM2T HV E V X MT HS FER STD PN w/ Intake 10 5,488’ Upper Tandem Seal: GSB3DB FER HL SSCV H6 SB/SB CL-5E 11 5,495’ Lower Tandem Seal: GSB3DB FER HL SSCV H6 SB/SB CL-5E 12 5,502’ Motor: 562 XP 450/3135/88/18R 375/2615 FER 13 5,529’ Sensor, Zenith 14 5,532’ Centralizer: Bottom @ 5,535’ 15 6,527’ BOT SLZXP LTP / Liner Hanger 7” x 9-5/8”(TVD 3,942’)6.190” 16 6,536’ 7-5/8” Tieback Assy. 6.151” 17 6,549’ 7” H563 x 4.5” Hyd 625 XO 3.850” 18 13,895’ 4-1/2” Drillable Packoff Sub 2.390” 19 13,926’ WIV Valve LTC BxB (1” Ball on Seat/Closed) - 4-1/2” SCREEN LINER DETAIL Jts Type Top (MD)Top (TVD) Btm (MD) Btm (TVD) 79 Bkr Xcluder 6,720’ 3,939’ 9,792’ 3,831’ 96 Halliburton 9,972’ 3,831’ 13,851’ 3,705’ Well Name Rig API Number Well Permit Number Start Date End Date MP L-57 ASR 50-029-23609-00-00 218-072 3/10/2023 3/16/2023 RIH on 3-1/2" 9.3# L-80 EUE W/ ESP completion. F/ 232' T/ 1,582' Fill at 3 BPH. Testing ESP cable every 1,000'. Used cap line damaged from pervious run. Bled off & splice cap line. Cap line splice at connection of JT # 45 & 46. Service Rig, check equip oil levels. RIH on 3-1/2" 9.3# L-80 EUE W/ ESP completion. F/ 1,582' T/ 2324' Fill at 3 BPH. Testing ESP cable every 1,000'. Change out ESP spooling unit w/ new spool. Perform reel to reel splice. Test cable & secure. ESP splice landing in middle of JT # 71. RIH on 3-1/2" 9.3# L-80 EUE W/ ESP completion. F/ 2,324 ' T/ 3,628' Fill at 3 BPH. Testing ESP cable every 1,000'. Used cap line damaged from pervious run. Bled off & splice cap line. Cap line splice 10' down on JT # 111. RIH on 3-1/2" 9.3# L-80 EUE W/ ESP completion. F/ 3,628' T/ 3,995' Fill at 3 BPH. Testing ESP cable every 1,000'. Service Rig, check equip oil levels. RIH on 3-1/2" 9.3# L-80 EUE W/ ESP completion. F/ 3,628' T/ 5,378' Fill at 3 BPH. Testing ESP cable every 1,000' Accept rig at 05:00 3-12-23. Test BOPE as per approve sundry. AOGCC waived witness. Test new stack components to 250 psi low then to 5,000 psi high for proof test & to sundry requirements of 2,500 psi high thereafter. Complete tests #1, 2. 3/11/2022 - Saturday Cont. T/ POOH w/ 2-7/8" 6.5# L-80 EUE ESP completion. F/ 2,225' T/ 96' Using double displacement fill. Service rig, check equip. oil levels. L/D ESP assy. as per ESP rep. DC head, 2x pumps, gas sep. , upper/lower tandem seals, motor, Zenith gauge, centralizer. Pump at 5 BPH. Clean & clear floor, due to heavy oil, extended clean up time. Prep for 3-1/2" ESP completion run, L/D containment hose from ESP sheave. Change over spooler. Run ESP cable & cap line over sheave. Load 3-1/2" tubing in pipeshed. Strap & tally. Filled hole w/ 40 bbls 8.4ppg source water. Indicating fluid level in well ~ 871'. P/U & M/U ESP as per ESP rep. Centralizer, Zenith gauge, MTR, LT & UT seals. Service rig, check equip. oil levels. Cont. T/ P/U & M/U ESP as per ESP rep. GS, 3x pumps, Zenith ported sub. Damaged pup during m/u to discharge head, discharge head gulled as well. with tongs. C/O pup & replace DC head. Fill at 5 BPH. RIH on 3-1/2" 9.3# L-80 EUE W/ ESP completion. F/ 121' T/ 232' Fill 5 BPH. 3/14/2023 - Tuesday 3/12/2023 - Sunday Test BOPE as per approve sundry. AOGCC waived witness. Test new stack components to 250 psi low then to 5,000 psi high for proof test & to sundry requirements of 2,500 psi high thereafter. Complete tests # 2 - 8. Service Rig, check oil in Equip. Performed Accumulator draw down. BOPE test complete. R/D & B/D testing Equipment. Prep for ESP pull, Hang ESP sheave w/ containment hose. Change handling equip. for 2-7/8". Fill gas buster w/ source water. IA static, Pull CTS & BPV. L/D running tool. P/U 2-7/8" landing JT, Engage hanger. BOLDS. Pull hanger hanger off seat w/ 38k P/U wt. B/O hanger & L/D. POOH w/ 2- 7/8" 6.5# L-80 EUE ESP completion. F/ 5.482' T/ 3.594' Using double displacement fill. Service Rig, check oil in Equip. Cont. T/ POOH w/ 2-7/8" 6.5# L-80 EUE ESP completion. F/ 5,482' T/ 2,225' Using double displacement fill. 3/13/2023 - Monday 3/10/2022 - Friday No operations to report. 3/8/2022 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary No operations to report. 3/9/2022 - Thursday No operations to report. Cont. T/ POOH w/ 2-7/8" 6.5# L-80 EUE ESP completion. F/ 2,225' T/ 96' Using double displacement fill RIH on 3-1/2" 9.3# L-80 EUE W/ ESP completion. F/ 1,582' T/ 2324' Fill at 3 BPH Test new stack components to 250 psi low then to 5,000 psi high for proof test & to sundry requirements of 2,500 psi high thereafter RIH on 3-1/2" 9.3# L-80 EUE W/ ESP completion. F/ 2,324 ' T/ 3,628' Fill at 3 BPH RIH on 3-1/2" 9.3# L-80 EUE W/ ESP completion. F/ 3,628' T/ 3,995' Fill at 3 BPH. RIH on 3-1/2" 9.3# L-80 EUE W/ ESP completion. F/ 232' T/ 1,582' Fill at 3 BPH Prep for 3-1/2" ESP completion run, L/D containment hose from ESP sheave. Change over spooler. Run ESP cable & cap line over sheave. Load 3-1/2" tubing in pipeshed. Strap & tally. Filled hole w/ 40 bbls 8.4ppg source water. Indicating fluid level in well ~ 871'. P/U & M/U ESP as per ESP rep. Centralizer, Zenith gauge, MTR, LT & UT seals. P/U 2-7/8" landing JT, Engage hanger. BOLDS. Pull hanger hanger off seat w/ 38k P/U wt. B/O hanger & L/D. POOH w/ 2- 7/8" 6.5# L-80 EUE ESP completion. F/ 5.482' T/ 3.594' Using double displacement fill. Service Rig, check oil in Equip. Cont. T/ POOH w/ 2-7/8" 6.5# L-80 EUE ESP completion. F/ 5,482' T/ 2,225' Using double displacement fill. RIH on 3-1/2" 9.3# L-80 EUE W/ ESP completion. F/ 3,628' T/ 5,378' Test BOPE as per approve sundry. AOGCC waived witness Well Name Rig API Number Well Permit Number Start Date End Date MP L-57 ASR 50-029-23609-00-00 218-072 3/10/2023 3/16/2023 3/17/2022 - Friday No operations to report. 3/15/2022 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary RIH w/3-1/2" ESP Completion f/5378' t/5534', maintaining 3bph hole fill w/8.7ppg Brine. PUW=50k;P/u Landing Jt and Hanger w/BPV installed. Make penetrator splice to cable and terminate 3/8" capstring to hanger. Final surface check good. Landed completion with 27k down on Hanger putting EOT @ 5534'. RILDS. R/d cable sheave and spooler. Blow lines dry. Rig released @ 12:00hrs. 3/16/2022 - Thursday Land tubing hanger to RKB 17.81' RILDS. Clean void, install seal subs, CTS plug, RX-54 gasket. Land adaptor and torque. install 1/2" nipple and needle valve for cap line. Test void 500/5 5K/10 Good test. Wells support test tree with Tri plex unit Good. Pull CTS plug and 3" BPV with dry rod, no issues. Secure well. No operations to report. No operations to report. 3/18/2022 - Saturday No operations to report. 3/21/2023 - Tuesday 3/19/2023 - Sunday No operations to report. 3/20/2023 - Monday Land tubing hanger to RIH w/3-1/2" ESP Completion f/5378' t/5534', maintaining 3bph hole fill w/8.7ppg Brine. PUW=50k;P/u Landing Jt and Hanger w/BPV installed. Make penetrator splice to cable and terminate 3/8" capstring to hanger. Final surface check good. Landed completion with 27k down on Hanger putting EOT @ 5534'. RILDS. 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: ESP Swap 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address: Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception? Yes No 9. Property Designation (Lease Number): 10. Field: Current Pools: 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 13,941'N/A Casing Collapse Conductor N/A Surface 3,090psi Tieback 4,790psi 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: Operations Manager Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng 9-5/8" 7-5/8"" 6,715' 6,536' Perforation Depth MD (ft): 4-1/2"7,404' MD N/A 9,020psi 5,750psi 6,890psi 3,939' 3,942' 3,699' 6,715' 6,536' 13,931' Length Size Proposed Pools: 114' 114' TVD Burst PRESENT WELL CONDITION SUMMARY 3,699' 13,926' 3,700' 1,057 N/A 114' 16" MILNE POINT STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0025509, ADL0025514 & ADL0025515 218-050 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 50-029-23609-00-00 Hilcorp Alaska LLC SCHRADER BLUFF OIL N/A C.O. 477.05 MILNE PT UNIT L-57 Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): Tubing Size: 6.5# / L-80 / EUE 8rd 5,483' 3/8/2023 BOT SLZXP Packer and N/A 6,527 MD/ 3,942 TVD and N/A See Schematic See Schematic 2-7/8" 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: AOGCC USE ONLY scott.pessetto@hilcorp.com 907-564-4373 Scott Pessetto Form 10-403 Revised 10/2022 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Samantha Carlisle at 1:14 pm, Mar 01, 2023 323-127 Digitally signed by David Haakinson (3533) DN: cn=David Haakinson (3533), ou=Users Date: 2023.03.01 13:09:14 -09'00' David Haakinson (3533) SFD 3/6/2023 1,057 MGR06MAR23 218-072 SFD 3/6/2023 SFD 3/6/2023 * BOPE test to 2500 psi. DSR-3/7/23 10-404 GCW 03/08/23JLC 3/8/2023 3/8/23 Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2023.03.08 14:56:33 -09'00' RBDMS JSB 030923 Well: MPL-57 PTD: 218-072 API: 50-029-23609-00-00 Well Name:MPL-57 API Number:50-029-23609-00-00 Current Status:Shut-in Producer Rig:ASR Estimated Start Date:3/8/2023 Estimated Duration:5 days Regulatory Contact:Tom Fouts Permit to Drill Number:218-072 First Call Engineer:Scott Pessetto (907) 564-4373 (O) (801) 822-2203 (M) Second Call Engineer:Taylor Wellman (907) 777-8449 (O) (907) 947-9533 (M) Current Bottom Hole Pressure: 1,409 psi @ 3,525’ TVD ESP Intake Sensor |7.7 PPGE Max Potential Surface Pressure: 1,057 psi Gas Column Gradient (0.1 psi/ft) Max Angle:61° @ 2,100’ MD Brief Well Summary: MPL-57 is an online Schrader producer with a lateral drilled in the NB sand. MPL-57 was drilled in 2018. The reservoir completion is a fine mesh screen completion. For the last two years the flowing bottom hole pressure has steadily climbed while on ESP production. It is believed the pump stages are worn. An elective ESP swap is planned to increase drawdown on the reservoir. Objectives: Pull failing ESP completion, run new ESP completion on 3-1/2” tubing. Notes Regarding Wellbore Condition: - Last 7-5/8” casing test was to 1,500 psi on 7/26/2018. Pre-Rig Procedure Slickline 1. RU slickline, pressure test PCE to 250psi low / 2,500psi high. 2. Drift and tag with sample bailer. 3. Set plug in XN at 5,343’, PT tubing to 2,000 psi. 4. Pull dummy valve from GLM at 5,222’ MD and leave open. 5. Pull GLV and set dummy valve in upper GLM at 140’ MD. 6. Caliper tubing for possible reuse. 7. 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 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. Well: MPL-57 PTD: 218-072 API: 50-029-23609-00-00 Brief RWO Procedure 1. MIRU Hilcorp ASR #1 WO Rig, ancillary equipment, and lines to 500 bbl 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. 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 and a dual 3/8” capillary string. a. Use extreme care in spooling the capillary string to promote reuse of the string. 7. MU landing joint or spear, BOLDS, PU on the tubing hanger. a. Tubing hanger is a FMC 11” 11” x 2-7/8”, Gen5 w/ 2-7/8” EUE top and bottom, with penetrations for ESP, heat trace, 2 - ¼” NPT, 1 – 3/8” cap line penetration. b. ESP completion PU weight was not recorded. PU weight should be < 50kip 8. Confirm hanger free, lay down tubing hanger. 9. POOH and lay down the 2-7/8” tubing. Number all joints. a. Based on caliper results, joints to be kept will be reported to rig. Trash visibly bad joints. 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. Look for over-torqued connections from previous tubing runs, trash these joints. e. Clamp Totals i. Canon Clamps: 177 ii. Motor Body Clamps: 4 iii. Seal Clamps: 4 iv. Pump Clamps: 18 10. Lay Down ESP. 11. Pressure test pulled 3/8” capillary tubing to 3500 psi. If PT passes, plan to re-run cap string. 12. RIH with new 3-1/2” 9.2# L-80 ESP completion to +/- 5,500’ 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 Well: MPL-57 PTD: 218-072 API: 50-029-23609-00-00 d. Run single 3/8” cap string the length of the completion, clamping with cable. Nom. (OD)Length Item Lb/ft Material Notes 5.85 2 Centralizer 4 4.5 2 Intake Sensor 30 5.62 34 Motor - 450HP 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 – 2 x 270-Flex-27 45 1 Ported Discharge Head 13 L-80 3-1/2" 10 3-1/2" EUE 8rd Pup Jt 9.2 L-80 3-1/2" 30 3-1/2" EUE 8rd L-80 9.2 L-80 3-1/2”10 3-1/2" EUE 8rd Pup Jt 9.2 L-80 3-1/2”2 3-1/2” XN-nipple 9.2 L-80 3-1/2”10 3-1/2" EUE 8rd Pup Jt 9.2 L-80 3-1/2” 60 3-1/2" EUE 8rd Jt 9.2 L-80 3-1/2”10 3-1/2" EUE 8rd Pup Jt 9.2 L-80 3-1/2”"8 3-1/2" x 1" GLM, DV installed 9.2 L-80 3-1/2"10 3-1/2" EUE 8rd Pup Jt 9.2 L-80 3-1/2” 5,040 3-1/2" EUE 8rd Jt 9.2 L-80 3-1/2”10 3-1/2" EUE 8rd Pup Jt 9.2 L-80 3-1/2”8 3-1/2" x 1" GLM, 1/4" OV 9.2 L-80 ~200 MD 3-1/2”10 3-1/2" EUE 8rd Pup Jt 9.2 L-80 3-1/2” 150 3-1/2" EUE 8rd Jt 9.2 L-80 3-1/2” 10 Space out pup 9.2 L-80 3-1/2” 30 Tubing Hanger with full joint 9.2 L-80 13. Land tubing hanger. Use extra caution to not damage cable. 14. Lay down landing joint. 15. Set BPV. 16. 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. Well: MPL-57 PTD: 218-072 API: 50-029-23609-00-00 Attachments: 1. Current Wellbore Schematic 2. Proposed Wellbore Schematic 3. BOPE Schematic _____________________________________________________________________________________ Revised By: TDF 1/12/2023 SCHEMATIC Milne Point Unit Well: MPU L-57 Last Completed: 7/28/18 PTD: 218-072 TD =13,941’(MD) /TD =3,699’ (TVD) 4 16” Orig. KB Elev.: 34.1’ / GL Elev.: 15.2’ 7-5/8” 7 8/9 10 4 16 9-5/8” 1 2 3 17 See Screen/ Solid Liner Detail PBTD =13,926’ (MD) / PBTD =3,700’ (TVD) 9-5/8” ‘ES’ Cementer @ 2,447’ MD 5/6 4-1/2” Shoe @ 13,931’ 11 13 1214 15 2-7/8”CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 16" Conductor 164 / A53B / Weld N/A Surface 114’ N/A 9-5/8" Surface 40 / L-80 / TXP 8.835 Surface 6,715’ 0.0758 7-5/8” Tieback 29.7 / L-80 / Hyd 521/Vam STL 6.875 Surface 6,536’ 0.0459 4-1/2” Liner 250ђ Screens 13.5 / L-80 / Hyd 625 3.920 6,527’ 13,931’ .0149 TUBING DETAIL 2-7/8" Tubing 6.5 / L-80 / EUE-8rd 2.441 Surface 5,483’ 0.0058 3/8” Dual Cap String 3/8” Stainless Steel N/A Surface 5,483’ N/A OPEN HOLE / CEMENT DETAIL Conductor ±270 ft3 12-1/4"Stg 1 – Lead - 562 sx / Tail – 400 sx Stg 2 – Lead – 378 sx / Tail – 270 sx Class G (250 bbls to surface) 8-1/2” Cementless Screens Liner in 8-1/2” hole WELL INCLINATION DETAIL KOP @ 543’ Max Hole Angle = 94.47° @ 13,941’ MD TREE & WELLHEAD Tree Cameron 2-9/16" 5M Wellhead FMC Gen V GENERAL WELL INFO API: 50-029-23609-00-00 Completion Date: 7/28/18 4-1/2” SOLID LINER DETAIL Jts Top (MD) Top (TVD) Btm (MD) Btm (TVD) 4 6,555’ 3,943’ 6,720’ 3,939’ JEWELRY DETAIL No. Top MD Item ID 1 140’ GLM: 2-7/8” x 1” Side Pocket KPMG w/DPSOV 2.347” 2 5,222’ GLM w/Dummy: 2-7/8” x 1” 2.347” 3 5,343’ XN Nipple, 2.205” no go 2.205” 4 5,396’ Discharge Head: FPDIS 5 5,397’ Upper Tandem Pump: 134 STG FLEX 17.5 6 5,421’ Lower Tandem Pump: 134 STG FLEX 17.5 7 5,444’ Gas Separator: GRS FER N AR 8 5,447’ Upper Tandem Seal: GSB3DBUT SB/SB PFSA 9 5,454’ Lower Tandem Seal: GSB3DBUT SB/SB PFSA 10 5,461’ Motor: CL5 XP – 250hp / 2505V / 61A 11 5,478’ Sensor, Zenith 12 5,481’ Centralizer:Bottom @ 5,483’ 13 6,527’ BOT SLZXP LTP / Liner Hanger 7” x 9-5/8”(TVD 3,942’) 6.190” 14 6,536’ 7-5/8” Tieback Assy. 6.151” 15 6,549’ 7” H563 x 4.5” Hyd 625 XO 3.850” 16 13,895’ 4-1/2” Drillable Packoff Sub 2.390” 17 13,926’ WIV Valve LTC BxB (1” Ball on Seat/Closed) - 4-1/2” SCREEN LINER DETAIL Jts Type Top (MD)Top (TVD) Btm (MD) Btm (TVD) 79 Bkr Xcluder 6,720’ 3,939’ 9,792’ 3,831’ 96 Halliburton 9,972’ 3,831’ 13,851’ 3,705’ _____________________________________________________________________________________ Revised By: TDF 2/28/2023 PROPOSED Milne Point Unit Well: MPU L-57 Last Completed: 7/28/18 PTD: 218-072 TD =13,941’(MD) /TD =3,699’ (TVD) 4 16” Orig. KB Elev.: 34.1’ / GL Elev.: 15.2’ 7-5/8” 7 8/9 1 0 4 16 9-5/8” 1 2 3 17 See Screen/ Solid Liner Detail PBTD =13,926’ (MD) / PBTD = 3,700’ (TVD) 9-5/8” ‘ES’ Cementer @ 2,447’ MD 5/6 4-1/2” Shoe @ 13,931’ 11 13 1214 15 2-7/8”CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 16" Conductor 164 / A53B / Weld N/A Surface 114’ N/A 9-5/8" Surface 40 / L-80 / TXP 8.835 Surface 6,715’ 0.0758 7-5/8” Tieback 29.7 / L-80 / Hyd 521/Vam STL 6.875 Surface 6,536’ 0.0459 4-1/2” Liner 250ђ Screens 13.5 / L-80 / Hyd 625 3.920 6,527’ 13,931’ .0149 TUBING DETAIL 3-1/2" Tubing 9.2 / L-80 / EUE-8rd 2.992 Surface ±5,483’ 0.0087 3/8” Cap String 3/8” Stainless Steel N/A Surface ±5,483’ N/A OPEN HOLE / CEMENT DETAIL Conductor ±270 ft3 12-1/4"Stg 1 – Lead - 562 sx / Tail – 400 sx Stg 2 – Lead – 378 sx / Tail – 270 sx Class G (250 bbls to surface) 8-1/2” Cementless Screens Liner in 8-1/2” hole WELL INCLINATION DETAIL KOP @ 543’ Max Hole Angle = 94.47° @ 13,941’ MD TREE & WELLHEAD Tree Cameron 2-9/16" 5M Wellhead FMC Gen V GENERAL WELL INFO API: 50-029-23609-00-00 Completion Date: 7/28/18 4-1/2” SOLID LINER DETAIL Jts Top (MD) Top (TVD) Btm (MD) Btm (TVD) 4 6,555’ 3,943’ 6,720’ 3,939’ JEWELRY DETAIL No. Top MD Item ID 1 ±140’ GLM: 2-7/8” x 1” Side Pocket w/DPSOV 2.347” 2 ±5,222’ GLM w/Dummy: 2-7/8” x 1”2.347” 3 ±5,343’ XN Nipple, 2.205” no go 2.205” 4 ±5,396’ Discharge Head: 5 ±5,397’ Upper Tandem Pump: 6 ±5,421’ Lower Tandem Pump: 7 ±5,444’ Gas Separator: 8 ±5,447’ Upper Tandem Seal: 9 ±5,454’ Lower Tandem Seal: 10 ±5,461’ Motor: 11 ±5,478’ Sensor, Zenith 12 ±5,481’ Centralizer: Bottom @ ±5,483’ 13 6,527’ BOT SLZXP LTP / Liner Hanger 7” x 9-5/8”(TVD 3,942’) 6.190” 14 6,536’ 7-5/8” Tieback Assy. 6.151” 15 6,549’ 7” H563 x 4.5” Hyd 625 XO 3.850” 16 13,895’ 4-1/2” Drillable Packoff Sub 2.390” 17 13,926’ WIV Valve LTC BxB (1” Ball on Seat/Closed) - 4-1/2” SCREEN LINER DETAIL Jts Type Top (MD)Top (TVD) Btm (MD) Btm (TVD) 79 Bkr Xcluder 6,720’ 3,939’ 9,792’ 3,831’ 96 Halliburton 9,972’ 3,831’ 13,851’ 3,705’ Updated 8/11/2020 Milne Point ASR Rig 1 BOPE 2022 11” BOPE 4.48' 4.54' 2.00' CIW-U 4.30'Hydril GK 11" - 5000 VBR or Pipe Rams Blind11'’- 5000 DSA, 11 5M X 7 1/16 5M (If Needed) 2 1/16 5M Kill Line Valves 2 1/16 5M Choke Line Valves HCRManualManualHCR Stripping Head 2-7/8” x 5” VBR DATA SUBMITTAL COMPLIANCE REPORT 11/26/2018 Permit to Drill 2180720 Well Name/No. MILNE PT UNIT L-57 f7g1_' Operator HILCORP ALASKA LLC API No. 50-029-23609-00-00 MD 13941 TVD 3699 Completion Date 7/28/2018 11 Completion Status 1-0I1- Current Status 1-0I1- UIC No REQUIRED INFORMATION Mud Log No / Samples No ✓ Directional Survey Yes .i DATA INFORMATION List of Logs Obtained: ROP/ ABG/ DGR/ EWR/ ADR (from Master Well Data/Logs) Well Log Information: Log/ Electr Data Digital Dataset Log Log Run Interval OHI Type Med/Frmt Number Name Scale Media No Start Stop CH Received Comments Log C 29555 Log Header Scans 0 0 2180720 MILNE PT UNIT L-57 LOG HEADERS ED C 29555 Digital Data 100 13942 7/30/2018 Electronic Data Set, Filename: MPU L-57 DGR ABG EWR ADR.Ias ED C 29555 Digital Data 6700 13894 7/30/2018 Electronic Data Set, Filename: MPU L-57 ADR Quadrants All Curves.las ED C 29555 Digital Data 7/30/2018 Electronic File: MPU L-57 LWD FINAL MD.cgm ED C 29555 Digital Data 7/30/2018 Electronic File: MPU L-57 LWD FINAL TVD.cgm ED C 29555 Digital Data 7/30/2018 Electronic File: MPU L-57 - Definitive Survey.pdf ED C 29555 Digital Data 7/30/2018 Electronic File: MPU L-57.txt ED C 29555 Digital Data 7/30/2018 Electronic File: MPU L-57_GIS.TXT ED C 29555 Digital Data 7/30/2018 Electronic File: MPU L-57 LWD FINAL MD.emf ED C 29555 Digital Data 7/30/2018 Electronic File: MPU L-57 LWD FINAL TVD.emf ED C 29555 Digital Data 7/30/2018 Electronic File: MPU L-57 Geosteering.dlis ED C 29555 Digital Data 7/30/2018 Electronic File: MPU L-57 Geosteedng.ver ED C 29555 Digital Data 7/30/2018 Electronic File: MPU L-57 LWD FINAL MD.pdf ED C 29555 Digital Data 7/30/2018 Electronic File: MPU L-57 LWD FINAL TVD.pdf ED C 29555 Digital Data 7/30/2018 Electronic File: MPU L-57 LWD FINAL MD.tif ED C 29555 Digital Data 7/30/2018 Electronic File: MPU L-57 LWD FINAL TVD.tif I ED C 29556 Digital Data 100 13187 7/30/2018 Electronic Data Set, Filename: MPU L-57PB1 - DGR ABG EWR ADR.Ias ED C 29556 Digital Data 6700 13140 7/30/2018 Electronic Data Set, Filename: MPU L-57PBl ADR Quadrants All Curves.las AOGCC Pagel of 3 Monday, November 26, 2018 DATA SUBMITTAL COMPLIANCE REPORT 11/26/2018 Permit to Drill 2180720 Well Name/No. MILNE PT UNIT L-57 Operator HILCORP ALASKA LLC API No. 50-029-23609-00-00 MD 13941 TVD 3699 Completion Date 7/28/2018 Completion Status 1-0I1- Current Status 1 -OIL UIC No ED C 29556 Digital Data 7/30/2018 Electronic File: MPU L-57 PB1 LWD FINAL MD.cgm ED C 29556 Digital Data 7/30/2018 Electronic File: MPU L-57 PB1 LWD FINAL TVD.cgm ED C 29556 Digital Data 7/30/2018 Electronic File: MPU L-57PB1 - Definitive Survey.pdf ED C 29556 Digital Data 7/30/2018 Electronic File: MPU L-57PB1.txt ED C 29556 Digital Data 7/30/2018 Electronic File: MPU L-57PB1 GIS.TXT ED C 29556 Digital Data 7/30/2018 Electronic File: MPU L-57 PB1 LWD FINAL MD.emf ED C 29556 Digital Data 7/30/2018 Electronic File: MPU L-57 PB1 LWD FINAL TVD.emf ED C 29556 Digital Data 7/30/2018 Electronic File: MPU L-57PB1 Geosteering.dlis ED C 29556 Digital Data - 7/30/2018 Electronic File: MPU L-57PB1 Geosteering.ver ED C 29556 Digital Data 7/30/2018 Electronic File: MPU L-57 PB1 LWD FINAL MD.pdf ED C 29556 Digital Data 7/30/2018 Electronic File: MPU L-57 PB1 LWD FINAL TVD.pdf ED C 29556 Digital Data 7/30/2018 Electronic File: MPU L-57 PB1 LWD FINAL MD.tif ED C 29556 Digital Data 7/30/2018 Electronic File: MPU L-57 PBI LWD FINAL TVD.tif Log C 29556 Log Header Scans 0 0 2180720 MILNE PT UNIT L-57 PB1 LOG HEADERS Well CoresiSamples Information: Sample Interval Set Name Start Stop Sent Received Number Comments INFORMATION RECEIVED Completion Report OYDirectional / Inclination Data Mud Logs, Image Files, Digital Data Y / Core Chips Y/Production Test InformatioNA Mechanical Integrity Test Information Y / NA Composite Logs, Image, Data Files 0 Core Photographs Y1 Geologic Markers/Tops SY Daily Operations Summary oY Cuttings Samples Y t 1� Laboratory Analyses Y/ A AOGCC Page 2 of 3 Monday, November 26, 2018 DATA SUBMITTAL COMPLIANCE REPORT 11/26/2018 Permit to Drill 2180720 Well Name/No. MILNE PT UNIT L-57 Operator HILCORP ALASKA LLC MD 13941 TVD 3699 COMPLIANCE HISTORY Completion Date: 7/28/2018 Release Date: 7/2/2018 Description Comments: Compliance Reviewed _ Completion Date 7/28/2018 Date Completion Status 1-0I1 Comments Current Status 1-0I1- API No. 50.029.23609.00.00 UIC No Date________ .. AOG((Page 3 of 3 Monday, November 26, 2018 SC by Conductor Annulus Fill Coat Corrosion Inhibitor (Cl) Applications Well Field API PTD Treatment Date Cl Fill Volume (gal) Final Cl Top END 2-14 DIU 50029216390000 1861490 10/29/2018 12 sand from V to within 1', surface MPC-45 MPU 50029235790000 2170920 10/1/2018 2 surface MPC-46 MPU 50029235760000 2170520 10/1/2018 5 sand from 8'to within 1', surface MPC-47 MPU 50029235770000 2170770 10/1/2018 8 surface MPF-106 MPU 50029236000000 2180280 10/1/2018 2 surface MPF-107 MPU 50029235920000 2180010 10/1/2018 18 surface MPF-108 MPU 50029235980000 2180210 10/1/2018 3 sand from 4-1/2'to within 1', surface MPF-109 MPU 50029235960000 2180140 10/1/2018 15 surface MPF-110 MPU 50029235990000 2180220 10/1/2018 2 surface MPL-46 MPU 50029235510000 2151180 10/1/2018 30 surface MPL-47 MPU 50029235500001 2151170 10/1/2018 3 surface MPL-51 MPU 50029235870000 2171510 10/1/2018 4 surface MPL-52 MPU 50029235900000 2171740 10/1/2018 4 surface MPL-54 MPU 50029236070000 2180660 10/1/2018 6 surface MPL-56 MPU 50029236040000 218050 10/1/2018 2 surface MPL-57 MPU 50029236090000 2180720 10/1/2018 1 surface STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RECEIVED nlIt' WELL COMPLETION OR RECOMPLETION REPORf'Mb MG 1a. Well Status: Oil Gas ❑ SPLUG ❑ Other ❑ Abandoned ❑ Suspended 2Wc25.05 20AAC25.no GINJ ❑ WINJ ❑ WAGE] WDSPL ❑ No. of Completions: _ 1 1b. We Development `•' ClExploratory ❑ Service ❑ Stratigraphic Test ❑ 2. Operator Name: Hilcorp Alaska, LLC 6. Date Comp., Susp., or Abend.: 7/28/2018 14. Permit to Drill Number / Sundry: 3. Address: 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 7. Date Spudded: July 7, 2018 15. API Number: 50-029-23609-00-00 4a. Location of Well (Governmental Section): Surface: 3789' FSL, 5134' FEL, Sec 8, T13N, RI OE, UM, AK * Top of Productive Interval: 139' FNL, 2558' FEL, Sec 18, T13N, R10E, UM, AK Total Depth: 1884' FNL, 1131' FWL, Sec 19, T13N, R10E, UM, AK 8. Date TO Reached: July 20, 2018 16, Well Name and Number: MPU L-57 9. Ref Elevations: KB: 49.3' GL:15.2'. BF:15.2' • 17. Field / Pool(s): Milne Point Field Schrader Bluff Oil Pool 10. Plug Back Depth MD/TVD: 13,926' MD / 3,700' TVD . 18. Property Designation: ADL025509 / ADL025515 4b. Location of Well (State Base Plane Coordinates, NAD 27): Surface: x- 544742 ' y- 6031977 ' Zone- 4 TPI: x- 542075 y- 6028033 Zone- 4 Total Depth: x- 540611 y- 6021001 Zone- 4 11. Total Depth MD/TVD: 13,941' MD / 3,699' TVD- 19. DNR Approval Number: LONS 88-002 12. SSSV Depth MD/TVD: N/A 20. Thickness of Permafrost MD/TVD: 2,226' MD / 1,854' TVD 5. Directional or Inclination Survey: Yes(attached) No E]13. Submit electronic and printed information per 20 AAC 25.050 Water Depth, if Offshore: N/A (ft MSL) 21. Re-drill/Lateral Top Window MD/1VD: N/A - 22. Logs Obtained: List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data and printed logs within 90 days of completion, 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 ROP/ABG/DGR/EWR/ADR 2"/5" MD / PB1 ABG/DGR/EWR/ADR 2"/5" TVD / PB1 23. CASING, LINER AND CEMENTING RECORD CASING WT. PER FT GRADE SETTING DEPTH MD SETTING DEPTH TVD AMOUNT HOLE SIZE CEMENTING RECORD PULLED TOP BOTTOM TOP BOTTOM 16" 164# A53B Surface 114' Surface 114' 36" —270 ft3 9-5/8" 40# L-80 Surface 6,715' Surface 3,939' Stg 1 L - 562 sx / T - 400 sx 56 bbls 12-1/4" Stg 2 L - 378 sx / T - 270 sx 250 bbls 7-5/8" 29.7# L-80 Surface 6,536' Surface 3,942' Tieback Tieback Assy. 4-1/2" 13.5# L-80 6,527' 13,931' 3,942' 3,699' 8-1/2" Cementless Screen Liner 24. Open to production or injection? Yes Q No ❑ If Yes, list each interval open (MD/iVD of Top and Bottom; Perforation Size and Number; Date Perfd): ** Please see attached schematic for detail** 4-1/2" Screen Liner Run on 7/22/18 COMPLETION DATE !1;al r VERIFIED 25. TUBING RECORD SIZE DEPTH SET (MD) PACKER SET (MDTFVD) 2-7/8" 5,483' 6,527' MD / 3,942' TVD 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. Was hydraulic fracturing used during completion? Yes ❑ No Per 20 AAC 25.283 (i)(2) attach electronic and printed information DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 27. PRODUCTION TEST Date First Production: 8/3/2018 Method of Operation (Flowing, gas lift, etc.): ESP Date of Test: 813/2018 Hours Tested: 24 Production for Test Period Oil -Bbl: 203.7 Gas -MCF: 25.1 Water -Bbl: 685.8 Choke Size: N/A Gas -Oil Ratio: 123 Flow Tubing Press. 267 Casing Press: 120 Calculated 24 -Hour Rate J� Oil -Bbl: 203.7 Gas -MCF: 25.4 Water -Bbl: 685.8 Oil Gravity - API (corr): 12.7 Form 10-407 Revised 5/201 CONTINUED ON PAGE 2 _ / �.z 8•� �ubmi 0 GI[JIAL only^ RBDMS� AUG 2 2 2018 /Ti�i `CsIyZ�Z lllwl 28. CORE DATA Conventional Core(s): Yes ❑ No ❑� Sidewall Cores: Yes ❑ No ❑✓ - 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. 29. GEOLOGIC MARKERS (List all formations and markers encountered): 30. FORMATION TESTS NAME MD TVD Well tested? Yes ❑ No ❑� If yes, list intervals and formations tested, briefly summarizing test results. Permafrost - Top Permafrost - Base 2,226' 1,854' Attach separate pages to this form, if needed, and submit detailed test Top of Productive Interval 6,720' Schrader NB 3,939' information, including reports, per 20 AAC 25.071. SV5 1,531' 1,437' SV1 2,765' 2,131' Ugnu LA3 5,315' 3,443' Schrader NA 6,355' 3,914' Schrader NB 6,520' 3,940' Formation at total depth: Schrader NB 31. List of Attachments: Wellbore Schematic, Drilling and Completion Reports, Definitive Directional Surveys, Csg and Cmt Report 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, 32. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Authorized Name: Monty Myers Contact Name: Cody Dinger Authorized Title: D ling Manag Contact Email: Cdlll of hi1c r .0001 Authorized Contact Phone: 777-8389 S ignature: ate; Z'L / T INSTRUCTIONS General: 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. Item 1 a: Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item 1b: Well Class - Service wells: Gas Injection, Water Injection, Water -Alternating -Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Item 4b: TPI (Top of Producing Interval). Item 9: 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. Item 15: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Item 19: 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. Item 20: Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29. Item 22: Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data and printed logs within 90 days of completion, suspension, or abandonment, whichever occurs first. Item 23: Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. Item 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). Item 28: Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. 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. Item 30: Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Item 31: 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. Form 10-407 Revised 5/2017 Submit ORIGINAL Only LLC Ling. KB Elev.: 34.1' / GL Elev.: 152 TD =13,941' (MD) / TD = 3,699' (TVD) PBTD =13,926 (MD) / PBTD = 3,700' (TVD) SCHEMATIC TREE & WELLHEAD Tree Cameron 2-9/16" SM Wellhead FMCGenV OPEN HOLE / CEMENT DETAIL Milne Point Unit Well: MPU L-57 Last Completed: 7/28/18 PTD: 218-072 Conductor ±270k3 12-1/4" Stg 1 -Lead -562 sx/Tail-400 sx Top Stg 2 - Lead - 378 sx / Tail - 270 sx Class G (250 bbls to surface) 8-1/2" Cementless Screens Liner in 8-1/2" hole CASING DETAIL ze Type Wt/Grade/Conn ID Top Btm BPF 6" Conductor 164/A53B/Weld N/A Surface 114' N/A i/8" Surface 40/L-80/TXP 8.835 Surface 6,715' 0.0758 i/8" Tieback 29.7 / L-80 / Hyd 521/Vam STL 6.875 Surface 6,536' 0.0459 L/2" Liner 25011 Screens 13.5 / L-80 / Hyd 625 3.920 6,527' 13,931' .0149 TUBING DETAIL '/8" Tubing 6.5 / L-80 / EUE-8rd 2.441 Surface 5,483' 0.0058 T" Dual Cap String 3/8" N/A Surface 5,483' N/A WELL INCLINATION DETAIL KOP @ 543' Max Hole Angle = 94.47' @ 13,941' MD JEWELRY DETAIL No. Top MD Item ID 1 140' GLM: 2-7/9"x 1" Side Pocket KPMG w/DPSOV 2.347" 2 5,222' GLM w/Dummy: 2-7/8" x 1" 2.347" 3 5,343' XN Nipple, 2.205" no go 2.205" 4 5,396' Discharge Head: FPDIS 5 5,397' Upper Tandem Pump: 134 STG FLEX 17.5 6 5,421' Lower Tandem Pump: 134 STG FLEX 17.5 7 5,444' Gas Separator: GRS FER N AR 8 1 5,447' Upper Tandem Seal: GSB3DBUT SB/SB PFSA 9 5,454' Lower Tandem Seal: GSB30BUT SB/SB PFSA 10 5,461' Motor: CL5 XP- 250hp/ 2505V/ 61A 11 5,478' Sensor, zenith 12 5,481' Centralizer: Bottom @ 5,483' 13 6,527' BOT SLZXP LTP / Liner Hanger 7" x 9-5/8" (TVD 3,942') 6.190" 14 6,536' 7-5/8" Tieback Assy. 6.151" 15 6,549' 7" H563 x 4.5" Hyd 625 XO 3.850" 16 13,895' 4-1/2" Drillable Packoff Sub 2.390" 17 1 13,926' W IV Valve LTC BxB (1" Ball on Seat/Closed) - 1/2" SOLID LINER DETAIL byTop '4D) (TVD) Btm (MD) Btm (TVD) 555' 3,943' 6,720'1 3,939' 4-1/2" Screens LINER DETAIL Jts Type Top (TVD) Btm (MD) Btm (TVD) (Mp) 79 Bkr Xcluder 6,720' 3,939' 9,792' 3,831' 96 1 Halliburton 1 9,972' 3,831' 13,851' 1 3,705' GENERAL WELL INFO API: 50-029-23609-00-00 Completion Date: 7/28/18 Edited By: CJD 8-9-2018 n Well Name: MP L-57 Field: Milne Point County/State: Prudhoe Bay, Alaska (LAT/LONG): avation (RKB): 33.7 API #: 50-029-23609-00-00 Spud Date: 7/7/2018 Job Name: 1713441 D MPL-57 Drilling Contractor Doyon 14 APE #: AFF $ Hilcorp Energy Company Composite Report Activity Date „56 7/5/2018 Flush the pumps with fresh water and blow down Suck out the cellar box. Set the surface bag on the rig matt. Clean the rock washer and pits. RD and prep rig floor to skid. Submitted L-57 diverter est witness notification request to the AOGCC at 08:09 hours on 7/5/18.;PJSM. Skid the rig floor into moving position.;PJSM. Pull the rig off of well Lb4 and stage on rig matts at the edge of the pad.;Clean up around well L-54.;Turn off the power on the rig in order to change out the high line electrical breaker. Install the speed head, diverter tee and 4" conductor valves onto well L-57. SimOps: Wells support installed the floor kit around well L-54.;Wait for well support to install the production flow lines to well L-54. SimOps: General housekeeping around the rig. Continuator install the new high line electrical breaker. Turn the rig power on at 23:50 hours.;Confinue to wait for well support to install the production flow lines to well L- 54. Well support tested the new flow lines (good test). SimOps: Install diverter annular and knife valve. Stage the tree with tubing head adapter and casing head behind the well.;Set rig malts in front of the well.;Move the rig over well L-57 and center the rig. Shim up the rig and set dawn. 7/6/2018 Shim and level rig, skid rig floor into drilling position.;R/U utility lines to the rig floor, choke line, Mi line and beaver slide. Well support install VR plug on L-56 VA, remove valve and install blind flange on same due to tight clearance for diverter line. Spot the rock washer and cuttings box. Working on acceptance checklist. Rig accepted @ 10:30.;Rotate and Line up diverter tee, Wellhead rep RILDS on diverter head. R/U diverter lines. Attempt to put rig on highline power, continues to show 10 amps fault to ground, big improvement from before changing upper breaker , source 2nd 2000 amp 600v breaker to CIO lower breaker in panel.;Continue to NIU Diverter system, Check pits with 100 bible fresh water, circulate thru surface lines., Test mud pumps. Install counter weight on diverter. Load 5" DP into pipe shed, strap and tally same. Totco rep check PVT s Screen up shakers.;Move fluid around in the pits for Totoc rep. Service the rig floor and pipe shed equipment. Continue to load 5" DP (216 joints). Load 17 joints of 5" HWDP.;PJSM. PU and MU stands of 5" DP from stand #72 to #63.;Perform surface diverter test The state right to witness was waived by AOGCC inspector Matt Herrera via email on 7/6118 at 18:14 hours. Tests: Knife valve= 14 seconds and Annular= 28 seconds.;Accumulator Test: System pressure= 2975 psi Pressure after closure = 1800 psi 200 psi attained in 38 seconds Full pressure attained in 160 seconds Nitrogen Bottles - 6 at 2100 psi.;Continue to PU and MU stands of 5" DP from stand #63 to #1.;PU and MU stands of 5" HWDP from stand #5 to 7/7/2018 Continue to PU and MU stands of 5" HWDP from stand #2 to #1, PU and MU drilling jars with two joints of 5" HWDP;PJSM, Slip and cut 68' drilling line, re -set crown saver, Service drawworks and top drive. Inspect saver sub .;Change out saver sub and gripper dies. Load BHA into pipe shed. Note: Pad operator shut in L-56 for spudding well. Submit Diverter test form to AOGCC-;Calibrate blocks, clear rig floor for M/U BHA.;Hold Pre spud meeting with all parties involved. Review well control plan with well on diverter, discuss roles and responsibilities. Safe briefing area, wind direction ;Load BHA components to rig floor, PJSM, M/U 12 114" Kymera bit, 1.5 deg mud motor, XO and 1 std HWDP. WU top drive.;Flood lines and stack with water, check diverter system for leaks. Close SOP and test mud line from mud pump to top drive to 3000 psi, good. Testing mud line was last item on checklist.;Wash down f/ 65 pumping 350 gpm, 320 psi tag bttm @ 114' @ conductor set depth, spud well, drill 12-1/4" hole f/114 to 126', 30 rpm, no tq, Start displacing to 8.8 ppg spud mud. pull into conductor @ 9T ;Drill 12 1/4" hole from 126' to 219', 350 gpm, 400 psi, 30 rpm, no tq, 3-4k wob;Ream f/ 219' to 126'350 350 gpm, 400 psi. Kill pump, RIH to 219'. Rack 2 stds back. BDTO.;WU remaining BHA. MWD/LWD tools and scribe same, offset @ 220.72 deg. Up Load MWD tools. MU 3 NMDC's, BN XO, 1 std HWDP, Shallow pulse test. RU Gyro Tools and Sheave, take gyro survey. Finish MU drilling assembly.;Continue drilling surface hole from 219' to 455' at 400 GPM = 800 psi, 40 RPM= 1 K ft -lbs torque, WOB = 5K, ECD = 9.8, PU = 70K, SO = 70K & ROT = 70K. Total bit hours= 2.37 & total jar hours= O.;PJSM. PU, RIH and POOH with gyro survey.;Continue drilling surface hole from 455' to 1016' at 400 GPM = 800 psi, 40 RPM= 1 K ft -lbs torque, WOB = 5K, ECD = 9.8, PU = 70K, SO = 70K & ROT = 70K. Running gyro survey every 94'. At 1061' the last 3 gyro surveys came back clean. Put Gyro Data and Pollard E -line on standby.;Last survey at 63T MD, 637' TVD, 5.25" Inc, 248.24° Az. Distance to Well Plan #9 = 6.83' (6.80'1= and 0.4' left). After drilling past 500' the pad operator was notified so that well L-56 could be put back on production.;Hauled 0 bbls H2O from G&I (80 Degree) for total = 0 trials Hauled 150 bible H2O from L -Pad Lake for total = 150 bbls Hauled 300 bible H2O from B -Pad Creek for total = 300 Hauled 57 bbls cuttings to G&I for total = 57 bible Hauled 57 bbls cuttings to 1B WIF for total = 57 trials 7/8/2018 Drill 121/4" hole F/ 1016 - 711771'. 755') 125.8' AROP, release Gyro @ 1300', maintain 5 deg/ 100', 450 gpm, 1400 psi, 10-12k wob, 60 rpm, 4-6k tq PU/SO/ROT 97189/93. ECD 10.33, max gas 65u 9.1 MW / 180 vis Pump 35 bbl hi vis sweep @ 1625, back 400 stks early' w/ 100% Inc @ shakers.;Released Gyro Data and Pollard E -line at 1300'.;Drill 12 114" hole FI 1771'- T/ 2500' (1995' TVD). ( 729) 121.5' AROP', maintain 5 deg/ 100'to 2012', drill tangent @ 59 deg inc. 450 gpm, 1300 psi, 5-12k wob, 60 rpm, 4-6k tq PU1SO/ROT 112/81/95. ECD 10.36, max gas 238 units 9.2 MW / 216 vis.;Pump 30 bbl hi vis sweep @ 2200', sweep back 300 stks early w/ 100% inc @ shakers. Base of permafrost came in @ 2226'.;Drill 12-1/4" surface hole from 2500' to 3100' (2305' TVD). 600' drilled = 100'/hr AROP. Drilling tangent at 59° inclination. 555 GPM = 1660 psi, 70 RPM =71<ft-lbs torque, WOB = 7K. PU = 117K, SO = 85K & ROT = 98K. ECD =9.95. Max gas= 177 units. MW = 9.2 ppg with 151 vis.;Drill 12-114" surface hole from 3100' to 3882' (2675' TVD). 782' drilled=130.37hr AROP. Drilling tangent at 59° inclination. 550 GPM = 1703 psi, 85RPM = 9K ft -lbs torque, WOB = 5K. PU = 132K, SO= 89K& ROT= 107K. ECD = 10.13. Max gas= 177 units. MW = 9.3 ppg with 122 vis.;Last survey at 3807' MD, 2672' TVD, 58.64' Inc, 216.26° Az. Distance to Well Plan #9 = 4.68'(2.94' high and 3.64' righl).;Hauled 100 bible H2O from L -Pad Lake for total = 250 bbls Hauled 1350 bbls H2O from B -Pad Creek for total = 1650 Hauled 57 bible cuttings to G&I for total = 57 bbls Hauled 1673 bbls cuttings/liquids to 1B WIF for total = 1730 bible 7/9/2018 Drill 12-1/4" surface hole from 3882'to 4662' (3111' TVD). 780' drilled = 1307hr AROP. Drilling tangent at 59" inclination. 567 GPM = 2100 psi, 85 RPM = 10-13K ft-lbs torque, WOB = 10K. PU = 165K, SO = 85K & ROT = 116K. ECD = 10.1. Max gas = 153 units. MW = 9.2 ppg with 150 vis;AST = 1.02, ART = 5.52, ADT = 6.54. Total bit hours = 21.24 & total jar hours = 21.24. Pump 35 bbl hi vis sweep @ 4255' back 200 stks late w/ 50% increase at shaken,:Drill 12- 1/4" surface hole from 4662'to 5358' (3444' TVD). 696' drilled = 1167h AROP. Drilling tangent at 59° inclination. 561 GPM = 2300 psi, 80 RPM = 13-14K ft- Ibs torque, WOB = 12K. PU = 170K, SO = 95K & ROT = 118K. ECD = 10.62. Max gas= 196 units. MW= 9.2+ ppg with 127 vis.;Pump 35 bbl hi vis sweep at 4760' and 5260' sweep back on time w/ 40% increase at the shakers.;Drill 12-1/4" surface hole from 5358'to 5730' (3652' TVD). 372' drilled = 62' /hr AROP. Drilling tangent at 59° inclination. 550 GPM = 2000 psi, 80 RPM = 15K ft-lbs torque, WOB = 6K. PU = 190K, SO = 90K & ROT = 125K. ECD = 9.79. Max gas = 245 units. MW= 9.0 ppg with 67 vis.;At 5470'& 5643' getting thick crude over the shaker blinding them off. Racked back a stand and clean the screens. AST = 1.17, ART = 4.32, ADT = 5.49. Total slide = 7.79 & total rotate = 18.94. Total bit hours = 26.73 & total jar hours = 26.73.;Drill 12-1/4" surface hole from 5730' to 6130' (3846' TVD). 400' drilled = 66.7'/hr AROP. Drilling tangent at 59' inclination and start the build section at 6015'.;545 GPM = 2140 psi, 85 RPM = 20K ft-lbs torque, WOB = 1 OK. PU = 200K, SO = 90K & ROT = 130K. ECD = 9.6. Max gas = 149 units. MW = 9.1 ppg with 97 vis Pump 35 bbl hi vis sweep at 5934' sweep back on time w/ 75% increase at the shakers.;Last survey at 6070' MD, 3824' TVD, 65.93° Inc, 205.2° Az. Distance to Well Plan #9 = 4.27' (2.80' high and 3.22' right).;Hauled 0 bbls H2O from L-Pad Lake for total = 250 bible Hauled 2245 bbls H2O from B-Pad Creek for total = 3895 Hauled 5 bbls cuttings to G&I for total = 62 bbls Hauled 2191 bbls cuttings/liquids to 1 B WIF for total = 3921 bbls 7/10/2018 Drill 12-1/4" surface hole from 6130' to 6405' (3924' TVD). 275' drilled = 45.8'/hrAROP. Cont build 5 deg/100' 566 GPM = 2300 psi, 80 RPM= 19-201(ft-lbs torque, WOB = 10-17K. PU = 195K, SO = 85K & ROT= 125K. ECD = 10.24. Max gas= 122 units. MW = 9.2+ ppg with 95 vis.;Drill 12-1/4" surface hole from 6405' to 6725' @ TD (3938 TVD). 320' drilled = 58.2'/hr AROP. Land in NB sand @ 93 Inc. 500-566 GPM = 1850-2300 psi, 80 RPM= 16-19K ft-lbs torque, WOB=7-20K.PU=195K,SO=85K&ROT=122K. ECD=10. Maxgas=365units.;MWin=9.2ppgwith86vis/MWout=9.3ppgwfth350vis.AST= 2.15, ART = 1.30, ADT = 3.45. Total slide= 15.17 & total rotate= 22.83. Total bit hours = 38.00 & total jar hours = 38.00. Last survey @ 6687.60' MD / 3940.82' TVD, 93.61" Inc., 197.29° azm. 2.67' from wp09, 2.43' low, 1.12' Ieft.;Obtain final survey at TD. Perform 5 min. flow check -static. Back ream 3 stands F/ 6725'T/ 6490'.;Pump tandem sweeps - 40 bbl low vis then 35 bbl hi vis weighted (10.1 ppg). Circulate w/ 600 GPM, 2000 psi, 80 RPM, 16-18k torque. Sweeps were not seen at the shakers. Shut down, change shaker screens & clean underneath shakers. Thick mud & solids build up was causing losses to the rock washer.;Circulate until yield point reduced to 25 coming out. 28,781 total strokes pumped - 3.25 complete circulations. MW in 9.1 ppg w/ 40 vis. MW out 9.15 ppg w/ 56 vis.;Trip in hole from 6490' to 6729. No fill observed on bottom. Performed 5 min. flow check - static.;Back ream at 20'-35'/min. F/ 6725'T/ 2697'. 600 GPM, 1600-2000 psi, 80 RPM, 9-16k tq.;Hauled 0 bbls H2O from L-Pad Lake for total = 250 bbls Hauled 2125 bbis H2O from B-Pad Creek for total = 6020 Hauled 0 bible cuttings to G&I for total = 62 bbls Hauled 1787 bbls cutfings/liquids to 1B WIF for total = 5708 bbls 7/11/2018 Continue to BROOH at 20'-35'/min. F/ 2697'T/ 730' at HWDP. Note: Pull 2 stds slow below base permafrost f/ 2400' to 2250' CBU, no increase seen at shakers. 600 GPM, 1600-2000 psi, 80 RPM, 9-16k tq.;BROOH to 450' racking 3 stds of HWDP in drk. POOH on elevators, attemptto close bumper sub, M/U TD, w/ wt of TO cannot close bumper sub, L/D 2 jts HW and jars. Rack remaining HW in derrick. UD BHA V176'to 83', download MWD data. UD remainder BHA. Stab balled up w clay.;Bft grade= 2-2-BT-A-E-I-BU-TD. Note: 30 bbls over calculated displacement on trip out of hole.;Clear and clean rig floor, load out BHA.;R/U 9 5/8 casing handling equip, Install 16' bails, R/U Volant tool, dog bones and elevators, P/U mandrel hanger and landing jt, make hanger dummy run as per wellhead rep. 35.75 RKB, 6' stickup above table. UD landing jt and hanger. Monitor well, Static loss rate 3-4 bph.;M/U 9-5/8" 40# L-80 TXP-BTC casing shoe track to 171'. BakerLoc & torque connections to 20,960 ft/lbs. Check floats -good. 12-1/4" Expand-O-Lizer centralizers installed on: 2 ea. on shoejoint, 1 ea. on BakerLoc, float & baffle adapter joints. Static loss rale 3-4 bph.;Run 9-5/8" 40# L-80 TXP-BTC F/ 171'T/ 2430 ljoint #60) @ 20-40'/min. Torque connections to 20,960 ft/lbs. Fill on the fly & top off every 10 joint. 12-1/4" Expand-O-Lizer centralizers installed on every joint to #25 & every other to joint #57 Static+ dynamic losses 5-6 bph.;Circulate a bottoms up below the build & base of permafrost. Stage up in 112 bbl increments. 3.8 BPM 140 PSI while adding 120 BPH water to condition the mud. Stage up to 6 BPM, 160 PSI. Lost 15 bbls while circulating.;Run 9-5/8" 40# L-80 TXP-BTC F/ 2430'T/ 4201' ljoint#104) @ 30'/min. Torque connections to 20,960 ft/Ibs. Fill on the fly & top off every 10 joint. 12-1/4" Expand-O-Lizer centralizers installed on every other to joint #91 then every joint #101-103. Static + dynamic losses 5-6 bph.;215k PUW, 105k SOW. 45 bbis total downhole losses to now for casing run.; Hauled 0 bbis H2O from L-Pad Lake for total = 250 bbis Hauled 725 bbis H2O from B-Pad Creek for total = 6745 Hauled 0 bbis cuttings to G&I for total = 62 bbls Hauled 575 bbls cuttings/liquids to 1 B WIF for total = 6283 bbls Daily downhole losses = 75 bbls. Cumulative losses for interval = 75 bbls. 7/12/2018 Run 9-5/8" 40# L-80 TXP-BTC casing F/ 4201'T/4482' (joint #110) @ 30'/min. Torque connections to 20,960 ft/lbs. Fill on the fly & top off every 10 joinL;CBU @4482', stage pumps to 4 bpm, 110 psi, reciprocate pipe 30'. 7.2 bbl losses circulafing.;Continue to P/U 9 5/8 casing and RIH f/ 4482' to 4721' RIH 30 FPM, Fill on the fly and every 10 jts ran. @ 0840 hrs on it 116 found 8.65" x2" thick foam disc floating in top of casing after filling pipe.; Discuss options with town, decision made to circulate casing volume to ensure no restrictions or pressure increase. MN volante, stage pumps f/ 4 bpm to 6 bpm, 110/150 psi, 450 bbis @ 50 bbis over, no restrictions encountered. 10.5 bbl losses circulating.;Continue to RIH with 9 5/8 casing V 4761' to 5488' @it 131, fill on the fly, lop off every 5 its ren and circulate 20 bbis evry 10 its ran. P/U 265K, S/O 115K 4.2 bbis losses while running casing.;Conbnue to RIH with 9 5/8 casing V 5488' to 6609' @ jt 163, fill on the fly, top off every 5 its ran and circulate 20 bbls every 10 its ran. PIU 315K, S/O 120k.;M/U it 164, stage pump slowly and wash down 3 bpm, 180 psi f/ 66091 to 6643', continue to circulate working pipe slow, Conirm pipe count @ 10 jts.;M/U 29' DWC/C box x TXP pin XO joint, TO DWC/C connection to 30k Polbs. wash down XO 2 bpm, 80 psi. MN Mandrel hanger & landing it as per well head rep, R/D csg slip bowl, wash down 2 bpm landing out hanger, PIU 2'. 4 bph loss rate circulating.;Parked at 6713' Circulate and condition for cement job, stage pump to 6 bpm, 160 psi. Prepare for cement job: pre -treat mud K' in pit#5, off load excess mud volume, & R/U cement lines. All trucks returned from getting cleaned of drilling solids - Super Suckers were 1/4 to 1/2 full of 5 sand.;43 bbis losses since noon while running casing and circulating. Daily downhole losses= 93 bbls. Cumulative losses for the interval 168 bbls.;Land casing on mandrel hanger. Blow down the top drive. Break out Volant tool, inspect then re-engage casing. R/U cement lines to the Volant tool. PJSM with all parties involved.;Perform 1st surface cement job. Pump 5 bbls H2O & test cement lines to 1350 psi low/4350 psi high. Mix & pump 55 bbis 10.0 ppg Clean S Spacer @ 3 BPM, 170 PSI. 4# red dye & 5# Pol-E-Flake in 1st 10 bbls. Drop bypass plug.;Mix & pump 240 bbis / 562 sks of 12.0 ppg Type IM lead cement @ 4.7 BPM, 315 PSI. Mix & pump 82 bbis /400 sks of 15.8 ppg Premium G tail cement @ 4 BPM, 515 PSI. Drop shutoff plug. Pump 20 bbis 8.34 ppg fresh water @ 5.4 BPM, 277 PSI.;Displace w/ rig mud pumps @ 5 BPM, 160 PSI ICP, 890 PSI FCP. Pump 279 bbis of 9.25 ppg spud mud. Pump 35 bbis of 9.5 ppg Halliburton polymer spacer. Pump 162.6 bbls of 9.25 ppg spud mud. Bumped plug @ 4719 stks, 4749 arks calculated. CIP @ 02:23.;Obsewed 710 PSI lift pressure from 12.0 ppg lead cement. Observed 90 PSI lift pressure from 15.8 ppg tail cement. Pressure up 500 PSI over FCP to 1390 PSI. Hold for 5 min., bleed off & check floats - good. 109 bbis losses during the cement job.;lnflate Halliburton ESIPC - pressure up to 2080, 2180, 2250 then 2300 PSI, hold for 5 min. Shear ESIPC open at 2600 PSI.;Circulate out spacer & cement from 2447' @ 5 BPM, 1080 PSI. Cement observed at 800 strokes with 56 bbis 12.3 to 12.8 ppg cement returned to surface. Circulated a total of 2x bottoms up - 2710 strokes.;Flush surface lines & diverter stack with black water. Function annular with black water 2x & dump to the celler.;Hauled 0 bbls H2O from L -Pad Lake for total = 250 bbis Hauled 375 bbis H2O from B -Pad Creek for total = 7120 Hauled 650 bbis H2O from G&I Heated for total = 650 Hauled 0 bbis cuttings to G&I for total = 62 bbis Hauled 256 bbis cuttingsAiquids to 1 B WIF for total = 6539 bbls;Daily downhole losses = 202 bbls. Cumulative losses for interval = 277 bbls. ***Notified AOGCC inspector of upcoming BOP test at 22:37 on 12 July 2018."' 7/13/2018 Break out volante, clean and inspect cup, Circulate 5 bpm, 950 psi while prepping pits for 2nd stage cement iob, W/O vac trucks and SS to arrive back f/ unloading @ Kup 1-B WIP. PJSM for 2nd stage.;Begin pumping 2nd stage cement job as per program. Pump 5 bbls water & PT lines to 1000 psi low and 4000 psi high, good. Pump 54 bbis 10.0 ppg Clean Spacer.'Mix & pump 292 bbls, 378 sxs 10.7 ppg Permafrost L cement, 5 BPM, 750 PSI. Mix & pump 55.8 ^ bbis, 270 sxs 15.8 ppg Premium G cement, 4.5 BPM, 790 PSI. Drop closing plug. Pump 20 bbis water, 4.7 BPM, 480 PSI.;Usmg rig pump displace w/ 9.2 ppg spud mud, 5 BPM, ICP 430 PSI, FCP 880 PSI, slow pump to 2 bpm @ 145 bbls, at 164.4 bbl pressure to 1450 psi shift cementer tool closed, hold for 5 min, bleed off pressure, bled back .5 bbl CIP @ 13:05 hrs. 54 bbis spacer & 2SQ bbls good cmt returned to surface.;0 losses during the 2nd stage cement job.;Flush all surface equipment w/ black water. Function test annular w/ black water 3 times. Blow down cmt line. Back out and UD landing joint, R/D Volant & UD casing equipment. Sim ops: R/D diverter Iine.;N/D riser, bell nipple & knife valve. Set surface stack back on stump and break down same. Clean pits & empty pipe shed ;Hilcorp wellhead personnel installed FMC Gen 5 split wellhead, 11 "x13-5/8" 5M casing spool and SM tubing head. Pressure test wellhead metal to metal seal to 250 low/1000 high for 5 min. - good test. Rotate OA wing valve to proper orientation, install VR plug & test API ring seal to 51K - good test.;WU BOP stack, choke & kill lines, riser, flow line & turn buckles.;R/U to test BOP equipment. Install test plug & 5" test joint. Test joint too short due to shorter well head elevation. Remove test plug & test joint. Locate longer test joint. Install test plug & test joint. Perform BOP body test to 250 PSI low / 3000 PSI high - good test.;Test BOP equipment as per PTD requirements and Doyon procedure. AOGCC rep Austin McLeod waived witness to BOP test @ 18:22 hrs Test to 250 PSI low / 3000 PSI high. Tests held for 5 min. & charted. Testing continues into the next report, complete details will follow.;Hauled 0 bbls H2O from L -Pad Lake for total = 250 bbis Hauled 505 bbis H2O from B -Pad Creek for total = 7120 Hauled 535 bbls H2O from G&I Heated for total = 1185 /[\ Hauled 0 bbls cuttings to G&I for total = 62 bbls Hauled 378 bbls cultings/Iiquids to G&I DS4 = 378;Hauled 1576 bbis cuttingstliquids to 1 B WIF for total = 8115 bbis Daily downhole losses = 0 bbls. Cumulative losses for interval = 277 bbls. 7/14/2018 Continue to test ROPE. Test upper & lower 2-7/6'x 5" VBR rams and annular on 5" test joint. Test Choke valves, upper & lower BOP, dart valve, FOSV #1 & 2, manual & HCR choke & kill valves. Test blind rams, manual & hydraulic chokes.;All tests performed to 250 psi low/3000 psi high & held for 5 minutes ea. Chart all tests. Perform accumulator Test: Start: 3000 psi, after closure 1700 psi, 200 psi build 37 sec, full recovery 179 sec. N2 bottle avg 2100 psi Test gas, PVT and flow alarms.;R/D Test equipment, blow down TD, choke manifold and lines. Pull test plug, Install 9" ID wear bushing, RI4LDS.;CIon blind ram, Shut down gens and Put rig in blackout, Rig electrician C/O breaker, install 1600 amp 600v breaker, attempt to put on high -line power, continues to show 10 amps to ground, highline breaker stayed on, couldn't get breakers just installed to close. Put rig back on gen power.;Mobilize 11' bails to rig floor, install same. Load BHA#2 tools to rig floor.;PJSM, M/U cleanout BHA #2, 8 1/2' mill tooth bit, motor, NMFS, 6 its HWDP, Jars, 9its HWDP.;Single in the hole with 5" DS50 DP from pipe shed If 526 to 1534'.;Work on rig high line breakers. Found under voltage relay wired backwards. Re -wire correctly and put rig on high line power.;Trouble shoot SCR DC output. Unable to power draw work and mud pumps. Go back on rig power and still unable to provide DC output from SCR's. Place rig back on high line power and continue trouble shooting. Found two bad fuses and replaced, now fully operational.;Single in the hole with 5" DS50 DP from pipe shed f/ 1534' to 2415'.;Ream down from 2415' w/ 400 GPM, 640 PSI, 30 RPM, 3K TO. Cement stringers from 2422' took 3-5K weight & firmed up at 2437'. Observed cement & rubber back over the shakers. Drill ESIPC cementer F/ 2447' T/ 2448'w/ 51K WOB. Work down to 2477', then ream 3 times - clean.;Hauled 0 bbis H2O from L -Pad Lake for total = 250 bbis Hauled 250 bbis H2O from B -Pad Creek for total = 7370 Hauled 535 bbis H2O from G&I Heated for total = 1185 Hauled 0 bbis cuttings to G&I for total = 62 bbis Hauled 378 bbis cuttings/liquids to G&I DS4 = 378;Hauled 190 bbis cuttings/liquids to 1 B WIF for total = 8305 bits 7ll512018 Continue to single in with 5" DS50 DP F/ 2455' to 3358' (90 jts total).;Continue RIH w/ stds 5" DP f/ 3358' to 6545' just above Baffle adaptor at 6585' Correct displacement on TIH. PU/SO/ROT 225185/105.;CBU pumping 9.8 bpm, 840 psi, reciprocate pipe slow. Submit BOP test form to AOGCC.;M/U FOSV and head pin, fill lines, close UPR, pump down DP and kill line, Pressure test 9 5/8" csg to 2650 psi charted for 30 min. Bleed off pressure, open UPR. 5.5 bbis pumped, 5 bbls bled back. Blow down lines. B/O FOSV.;Wash down tagging CMT @ 6550' Cleanout cement, 9.3 bpm, 915 psi, 30 rpm, 3-12k woo, drill BA on depth @ 6584', drill FE and cement to 6715', cleanout rat hole to 6725'.;Pump 40 bbl spacer, displace to new 9 ppg flo-pro mud, 5.75 bpm , 500 psi, 40 rpm, increase rate as thick returns allow, 8.3 bpm, 650 psi. Drill 20 new formation to 6745', with 330 GPM, 700 PSI, 40 RPM, 14K TO, i OK WOB. Good 9 ppg in/out pull into shoe, Rack 1 std back.;Parked @ 6656', M/U FOSV and head pin, f11 lines, close UPR, pump down DP and kill line, Perform FIT to 12 ppg EMW using 9 ppg existing MW, apply 615 psi, good test. 1.4 bbis pumped, 1 bbl bled back, open UPR. Obtain SPR's & flow check - static. Blow-'down choke & kill lines and R/D test equipment.;POOH from 6656'to 526. Rack back HWDP & jars then UD 12 joints of 5" HWDP. Correct displacement for trip out of the hole. UD BHA #2 -bit 1-1-WT-A-E-1-NO-BHA. Clear the rig floor.;PJSM then M/U BHA #3: 8-112" PDC bit w/ Geo-Pilot, and MWD tools to 86'. Initialize MWD tools. PIU non-mag drill collars to 146'then TIH w/ 5" HWDP to 270'.;Single in w/ 5" NC-50 drill pipe F/ 270' T/ 1495'. Break-in Geo-Pilot seals & pulse test MWD -good. Continue to single in F/ 1495'T/ 3684' wfth correct displacement.;Hauled 150 bbis H2O from L-Pad Lake for total= 400 Hauled 50 bbis H2O from &Pad Creek for total= 7420 Hauled 0 bbis H2O from G&I Heated for total = 1185 Hauled 0 bbis cuttings to G&I for total = 62 bbls;Hauled 0 bbis cuttings/liquids to G&I DS4 = 378 Hauled 1063 bbls cuttings/liquids to 1 B WIF for total = 9368 bbis 711612018 Continue to single in w/ 5" NC50 DP F/ 3684'T/ 4414' (132 jts total) TIH w/ stds 5" DS50 DP to 6490' filling pipe every 2000'. Correct displacement on TIH.;PJSM, slip and cut 73' drilling line, service draworks and top drive, re-calibrate block height.;RIH f/ 6499to 6731', M/U top drive, 400 gpm, 980 psi, 60 rpm, take survey, wash and ream down to 6745' on bftm, no fill. Obtain SPR 1 & 2 MPs.;Drill 8-1/2" lateral F/ 6745' T/ 6914'(169), 84.5 AROP. 400 GPM, 1080 PSI, 80 RPM, 15K TQ, 12K WOB. PU/SO/ROT 185/75/115 Max gas 398u. MW 9 vis 44 ECD 9.7.;Drill 8-1/2" lateral F/ 6914' T/ 7150'(23G), 39.3 AROP. At 6919'the assembly was pushed up to 92.65° (15° dogleg over 10'), reamed with down deflection and reduced inclination to 90.7°. 400 GPM, 1080 PSI, 70 RPM, 15-16K TQ, 10-12K WOB. PU/SO/ROT 200/75/118 Max gas 439u MW 9.0 vis 10.0 ECO.;Drill 8-1 /2" lateral F/ 7150'T/ 7527'(377'), 62.8 AROP. 400 GPM, 1160 PSI, 60-100 RPM, 15-16K TQ, 10-13K WOB. PU/SO/ROT 205/70/115 Max gas 435u MW 9.0 vis 10.1 ECD. Crossed a fault at 7448' MD, 3 DTN throw, sand to sand.;Dri118-112" lateral F/ 7527' T/ 8106'(579'), 96.5 AROP. 400 GPM, 1180 PSI, 70-90 RPM, 15-16K TQ, 9K WOB. PU/SO/ROT 190/68/116 Max gas 727u MW 9.2 vis 10.1 ECD. Pumped tandem sweeps at 7943'w/ no increase observed at the shakem,;10 concretions have been drilled so far this lateral for a total footage of 25'(0.3%). Last survey @ 8060.46', 92.69° inc., 196.05' azm., 6.18' from plan, 3.95' low & 4.75' right. Hauled 0 bbls H2O from L-Pad Lake for total = 400 bbls Hauled 300 bbls H2O from B-Pad Creek for total = 7720;Hauled 0 We H2O from G&I Heated for total = 1185 Hauled 0 bbis cuttings to G&I for total = 62 bbis Hauled 0 bbis cuttings/liquids to G&I DS4 = 378 Hauled 52 bbis cuttings/liquids to I WIF for total = 9420 bbis 7/17/2018 Drill 8-1/2" lateml F/ 8106' T/ 8469' (363'), 60.5 AROP. 400 GPM, 1130 PSI, 80 RPM, 15K TO, 9K WOB. PU/SO/ROT 195/65/113 Max gas 702u MW 9.1+ vis 10.2 ECD. Backream 95' on connecbons.;Drill 8-1/2" lateral F/ 8469' T/9131'(662'), 110.3 AROP. 400 GPM, 1190 PSI, 100 RPM, 18-19K TQ, 11-13K WOB. PU/SO/ROT 215/NA/115 Max gas 727u MW 9.1 vis 10.4 ECD. Backream 95' on connections.;Drill 8-112" lateml F/ 9131' T/ 9695' (654'), 94 AROP. 400 GPM, 1260 PSI, 110 RPM, 19-20K TQ, 10-12K WOB. PU/SO/ROT 210/NA/110 Max gas 612u MW 9.1 vis 10.4 ECD Backream 95' on connections.;Drill 8-112" lateral F/ 9695' T/ 10140'(445'), 74.1 AROP. 450 GPM, 1400 PSI, 70-100 RPM, 21K TO. 10K WOB. PU/SO/ROT 2201NA/110 Max gas 855u MW 9.15 vis 10.7 ECD Backream 95' on connections.;Pumped 20 bbl low vis & 20 bbl 9.95 ppg weighted sweeps @ 9788'. Back on time wl 50% increase of cuttings observed. 38 concretions have been drilled so far this lateral for a total footage of 105' (3.2%). Survey @ 10042.51', 89.73° Inc., 186.17° zzm., 5.86' from plan, 5.68' low & 1.45' right.;Hauled 0 bbis H2O from L-Pad Lake for total = 400 bbis Hauled 300 bbis H2O from B-Pad Creek for total = 7720 Hauled 295 bbis H2O from 6 Mile for total = 295 Hauled 0 bbis H2O from G&I Heated for total = 1185 Hauled 0 bbis cuttings to G&I for total = 62 bbis;Hauled 0 bbis cuttings/liquids to G&I DS4 = 378 Hauled 578 bbls cutfings/liquids to 1 B WIF for total = 9998 bbis 7/18/2018 Drill 8-1/2" lateral F/ 10140'T/ 10662'(522'), 87 AROP. 400 GPM, 1290. PSI, 110 RPM, 22K TO, 7K W OB. PU/SO/ROT 213/NA/110 Max gas 1291 u MW 9.1 ECD 10.7. Backream 95' on connections. Pump tandem sweeps @ 10356 w/50% increase observed at shakers.;Drill 8-1/2" lateral F/ 10662' T/ 11301'(639'), 106.5 AROP. 400 GPM, 1220 PSI, 100 RPM, 25K TO. 7-11 K WOB. PU/SO/ROT 245/NA/110 Max gas 707u MW 9.1 ECD 10.7. Backream 95' on connections. Pump tandem sweeps @ 10921'w/ 25% increase observed at shakers.;Drill 8-1/2" lateral F/ 11301'T/ 11679'(396'), 66 AROP. 400 GPM,1310 PSI, 100-120 RPM, 25K TO, 9-15K WOB. PU/SO/ROT 238/NA/110 Max gas 770u MW 9.1 ECD 10.7. Backream 95' on conn. Pump tandem sweeps @ 11484'w/ 20% increase observed at shakers. Scraped the bottom of zone F/ 11604'T/ 11630'.;Drill 8-112" lateral FI 11679' T112337' (658'), 110 AROP. 400 GPM, 1270 PSI, 110 RPM, 25K TQ, 10-12K WOB. PU/SO/ROT 225/NA/108 Max gas 1633u MW 9.1 ECD 10.9. Backream 95' on connections. Pump tandem sweeps @ 11960'w/75% increase observed at shakers.;Last survey @ 12212.31', 91.74° inc., 193.30° azm., 13.49' from plan, 13.02' high &3.53' left. 53 concretions have been drilled so far this lateral for a total footage of 170' (3.1%). Daily losses to formation= 19 bbis seepage, Total for interval = 19 bbls.;Hauled 150 bbis H2O from L-Pad Lake for total = 550 bbis Hauled 0 bbls H2O from &Pad Creek for total= 7720 Hauled 180 bbis H2O from 6 Mile for total = 475 Hauled 0 bbls H2O from G&I Heated for total = 1185;Hauled 0 bbis cuttings to G&I for total = 62 bbis Hauled 0 bbis cutfings/liquids to G&I DS4 = 378 Hauled 578 bbis cultinas/liau cls to 1 R WIF for total = 10576 blor, Y �K 7/19/2018 Drill 8-12" lateral F/ 12337' T/ 12715'(378), 63 AROP. 400 GPM, 1378 PSI, 110 RPM, 25K TO, 10-12K WOB. PU/SO/ROT 2501NA/107 Max gas 1017u MW 9.1 ECD 11.1. Backream 95' on connections. Pump tandem sweeps @ 12526'w/25% increase observed at shakers.;Drill 8-1/2" lateral F/ 12715' T/ 13186' (471'), 63 AROP. 395 GPM, 1690 PSI, 110 RPM, 28K TQ, 8-16K WOB. PU/SO/ROT 260/NA/105 Max gas 244u MW 9.2 ECD 11.1. Backream 95' on connections. Pump tandem sweeps @ 12996'w/ 50% increase observed at shakers. Scraped the bottom F/ 12856' T/ 12884' (28').;Faulted out of zone at 13026', 10' DTS throw. The fault was crossed while drilling 2' above the base of the formation with a 94.06° Inc. to buildup. The throw placed us above the NB sand approximately 4' and it will take too long to turn back down so we elected to perform an openhole sidetrack.;BROOH F/ 13186' T/ 12968'w/ 400 GPM, 1460 PSI, 100 RPM, 24K TO. Trough 3x times F/ 12960' T/ 12990'w/ 100% deflection @ 150L toolface.;Drill 8-1/2" lateral F/ 12990'T/ 13186'(196),56 AROP. Time drilled F/ 12990'T/ 13013'. 400 GPM, 1520 PSI, 120 RPM, 26K TO, 1-5K WOB. PU/50/ROT 260/NA/104, Max gas 238u. MW 9.2, ECD 11.0.;Perf0rm check trip across sidetrack, lubricate out F/ 13186'T/ 12986'w/ 250 GPM. Lubricate down with 15 RPM (no slack off weight) F/ 12986,13092" Ream F/ 13092'T/ 13186', inclination showed BHA in the correct hole.;Drill 8-1/2" lateral F/ 13186'T/ 13469 (283'), 81 AROP, 400 GPM, 1500 PSI, 110 RPM, 27K TO. 5K WOB. PU/SOIROT 2651NA/106, Max gas 1566u. MW 9.15 ECD 11.0. Backream 95' on connections.;Last survey @ 13438.10', 91.76° inc., 193.78° azm., 9.34' from plan, 8.01' high, 4.81' right. 67 concretions have been drilled so far this lateral for a total footage of 238' (3.6%). Hauled 50 bible H2O from L -Pad Lake for total = 600 bbls Hauled 0 bible H2O from B -Pad Creek for total = 7720;Hauled 100 bbls H2O from 6 Mile for total = 575 Hauled 0 bbls H2O from G&I Heated for total = 1185 Hauled 0 bbls cuttings to G&I for total = 62 bbls Hauled 0 bbls cuttings/liquids to G&I DS4 = 378 Hauled 520 bbls cuttings/liquids to 18 WIF for total = 11096 bbls 7/20/2018 Drilled F/ 13469'T/ 13941'. 472'@ 78 FPH average. (TD @ 13941') 450 GPM, 2000 PSI, 110 RPM, 28K TO, 10-20 WOB MW 9.1 & 10.9 ECD Drilled out of zone @ 13886' @ 91.5 Deg & drilled ahead to 13941'. Brough INC up to 94 DEG & called TD 59' Short @ 13941'. Start adding 1 % Lube per circulation.;Started adding 1 % per circulation of lubes at 13750. TO 28k at start. 21K at TD with 1 % in. 67 concretions have been drilled this lateral for a total footage of 238' (3.3%). 97.94% of lateral drilled in zone.;Projection to TD, 13941', 94.47° mc., 191.02° azm., 13.59' from plan, 13.22' high, 3.13' left. Hauled 275 bbls H2O from L -Pad Lake for total = 875 bbls Hauled 0 bbis H2O from B -Pad Creek for total = 7720 bbls Hauled 200 bbls H2O from 6 Mile for total = 775 bbls;Hauled 0 bbls H2O from G&I Heated for total = 1185 bible Hauled 0 bbls cuttings to G&I for total = 62 bbls Hauled 0 bbls cuttings/liquids to G&I DS4 = 378 bbls Hauled 463 blots cuttings/iquids to 1 B WIF for total = 11559 bbls;Swap to Completion AFE & report at 12:00. Hilcorp Energy Company Composite Report Well Name: MP L-57 Field: Milne Point County/State: Prudhoe Bay, Alaska (LAT/LONG): avation (RKB): API #: 50-029-23609-00-00 Spud Date: 7/7/2018 Job Name: 1713441C MPL-57 Completion Contractor Doyon 14 AFE #: AFE $: MOW OND " Ops Summary 7 /2 012 01 8 Drilling report. AT TD TO at 21 K. at 130 RPM.,Circ Tandem sweep, 40 bbl High/Low sweep around at 450 GPM 130 RPMs. Starting ECDs 10.9 & after sweep to surface 10.6. Continue to add 1% Lube per circulation for a total of 2% Lube 776 & 2% Torque. Sweep brought back 0% increase in cuttings. Lower flow rate to 385 and screen up to 200s & 270s.,Lube blinding off shakers and having to lower flow rate to 338 GPM to keep fluid on the shakers. Slow RPMs from 130 to 40 at 3.5 him up. 22000 sks. After all 4% lubes in TO at 15K 40 RPMs. Continue to circ at 385- 335 GPM & 40 RPM 15 K tq. still fighting shakers with 200s & 270s on. Took screen test at 4 him ups. Failed going in and out. Pits and flow line. Failed at 37.09 sec on the first Iiter.,Continue to circ @ 260 GPM, 750 PSI, 40 RPM, 13K tq, still fighting shakers w/ 200s on scalpers & 270s on lowers. Test #2 @ 18:3014.61 BUS failed, sample taken below scalpers above shakers. Liter #1 = 24.33 sec., Liter #2 = 25.3 sec., Liter #3 = N/A Test #3 @ 20:40 / 5.95 BUS failed, sample taken below scalpers above shakers. Liter #1 = N/A sec., Liter #2 = N/A sec., Liter #3 = N/A.,Test #4 @ 20:30 / 7.32 BUS failed, sample taken below scalpers above shakers. Liter #1 = 13.68 sec., Liter #2 = 21.52 sec., Liter #3 = 32.21 sec. Test #5 @ 00:30 / 8.41 BUS failed, sample taken below scalpers above shakers. Liter #1 = N/A sec., Liter #2 = N/A sec., Liter #3 = N/A,Circulate @ 260-385 GPM w/ 40 RPM, lower flow rate to inspect/change shaker screens as needed. #2 shaker failed at 01:30, shaker screen support broke. Circulate @ 150-310 GPM w/ 40 RPM, lower flow rate to inspect/change shaker screens as needed. Out of 230 & 270 screens, started replacing with 200 screens.,Test #6 @ 01:30 18.95 BUS failed, sample taken from flow line. Liter #1 = 12.97 sec., Liter #2 = 14.56 sec., Liter 93 = 24.21 sec. Test #7 @ 03:30/ 10.05 BUS failed, sample taken from flow line. Liter #1 = 17.27 sec., Liter #2 = 37 sec., Liter #3 = 25.82 sec. Test #8 @ 05:00 / 11 BUS passed, sample taken from flow line. Liter #1 = 12.86 sec., Liter 92 = 13.12 sec., Liter #3 = 13.71 sec.,Perform flow check - slight breathing for 15 min. then static for another 10 min. PJSM for BROOH during flow check. 7/21/2018 BROOH F/ 13941'T/ 12908'. 300-385 GPM, 860-1150 PSI, 100 RPM, 15k TQ. Start 10 min/stand then increased to 5 min/stand. PUW/SO/ROT 165K/55KI110K., Perform check trip across sidetrack. TIH F112908' T 13088', then POOH F/ 13088' T/ 129087 PUW/SO/ROT 175K/75K/110K.,BROOH F/ 12908'T/ 6772'. 385 GPM, 1090 PSI, 100 RPM, 9-15K TO. 5 min/stand. 114K rotating weight. Lubricate into the shoe F/ 6772'T/ 6678' w/ 385 GPM, 810 PSI -Perform flow check, well static. Change screens on shakers, load brine into mud pit. Replace bolt on top drive shock pin & safety wire.,Pump 30 bbi high viscosity sweep to clean 9-5/8" casing @ 500 GPM. Shakers began running over at bottoms up, slow to 400 GPM, 880 PSI, 100 RPM, 5K TO, 115K ROT wt. Increase to 500 GPM, 1150'. Reciprocate F/ 6678' T/ 6585'. No noticeable increase wl sweep, but circulated another BU at full rate - shakers cleaned up. 9000 total strokes pumped, 2.7 bottoms up.,Pumped 30 bbl high viscosity spacer, displace 9.1 ppg Flo -Pro mud w/ 9.0 ppg brine w/ 4% Safe Lube. 7 BPM, 570 PSI. 100 RPM, 5K TO. Reciprocate F/ 6678' T/ 6586. Observed brine back on strokes and dumped 20 bbis of interface. 5069 sties pumped including the sweep.,Monitor well - static. Clean shakers & line up trip tank. Remove Sperry Geo -Span skid from the rig floor.,Slip and cut drilling line. Service top drive and blocks.,Drop 2.45" drift wl 100' wire tail on stand #68. POOH on elevators F/ 6678' T/ 5820'145K PU / 105K SO. 7/2 212 01 8 POOH on elevators F/ 5820'T/ 270'. Monitor well. UD HWDP & jars, Down load MWD.,UD HWOP & jars, Down load MWD. UD MWD & bit. Bit Grade- 1- 2 -CT -T -X -I -BT -TD. Clean and clear rig floor.,R/U to run 4.5" 250 Micron Hydril 625 L-80 13# screens . Test weatherford equipment.,PJSM, P/U baker shoe track assembly with W IV & Pack off. Run screens T/ 3960'. Run 96 HES 250 Micron screens with 7.5 OD centralizer Pre installed mid joint. Install one stop ring and centralizer on pin and from rig foor. 2 Per joint for all HES screens M/U all Hydril 625 connections to Optimum TO @ 9600 fUlbs.,Run 4-112" screens F/ 3960' T/ 7377'. Ran 79 Baker 250 Micron screens with one 7-1/4" centralizer & stop ring on each pin end and 4 blank joints. M/U all Hydril 625 connections to Optimum TQ @ 9600 ft/Ibs. PU/SO weight at shoe: 125KI90K - PIU SO weight at 737T: 126KI89K Set slips while in tension.,Total 4-1/2" liner components ran: 96 HES 250 Micron screens, 79 Baker 250 Micron screens and 5 blank joints. 50 centralizers, 7-112" x 4-112" 221 centralizers, 7-1/4" x 4-1/2" 367 stop rings.,R/D 5" drill pipe x 4-1/2" H625 safety joint. M/U 2-3/8"x7"X4-112" IF triple connect to FOSV & 2-3/8" lift sub. Mobilize 2-3/8" handling equipment to the rig floor & change out power tong dies to 2-3/8". R/U false rotary table. M/U mule shoe on 2-3/8" joint #1.,Run 2-3/8" PH -6 L-80 5.95# inner string T/ 4937', joint #158. Torque connections to 3050 ft/lbs. Drift on pipe skate w/ 1.69'.,Hauled 25 bbis H2O from L -Pad Lake for total = 900 bbls Hauled 0 bbls H2O from B -Pad Creek for total = 7720 bbis Hauled 25 bbis H2O from 6 Mile lake for total = 955 bbls Hauled 0 bbis H2O from G&I Heated for total = 1185 bbls,Hauled 0 bbis cuttings to G&I for total = 62 bbis Hauled 0 bbis cuttings/liquids to G&I DS4 = 378 bbis Hauled 1150 bbis cuttings/liquids to 1 B WIF for total = 13111 bbls 14 bbis daily downhole losses. 72 bbis total losses for interval. 7123/2018 Continue to P/U 2 3/8 inner string T/ 7357'. Tag no go. Space out with 10' pup placing slick stick T off of no ga. Change handling equipment to 5". P/U SLZXP packer assembly and M/U same. Final UP/DN of 2 318 65154K Final UP/DN with SLZXP & Liner 153/105K.,M/U first stand 5" DP & circ one innerstring volume. 2.4 BPM 1050 PSI. Circulating brine.,RIH F/ 7415' T/ 13916'. Filling pipe on the fly, Topping off every 5 and breaking circ every 10 stand with TD. RIH with no issues. Final UP/DN 175/60K. Wash down F/ 13916'T/ 13941' staging pumps up to 2.5 BPM. Tag btm 4' Deep. Reciprocate pipe while conducting PJSM for displacement., Displace to 9.0 2% KCI brine at 3 BPM 1750 PSI max. Pump 30 bbis viscosified brine sweep followed by 500 bbis 9.0 ppg 2%KCI brine. Pump 40 bbl SAPP pill, 50 bbis brine, 40 bbl SAPP pill, 50 bbis brine, 40 bbl SAPP pill continue w/ brine. Reciprocated pipe 90' until new brine to shoe then 30' w/ 170k up / 651k down. At 8447 strokes, slack off weight dropped below 50k.,SO to 13941' then PU to 13931' to place liner in tension w/ 167K hook load. Good brine returns @ 9487 silks, 105 bbls over calculated volume. Continue circulating SAPP pills around @ 3 BPM, 1700 PSI. Began dumping SAPP pills @ 14386 stks & return to pits @ 16564 stks.,Perform 2nd displacement with new 9.2% KCI brine 3 BPM, 1700 PSI. Pump 547.5 bbls 15420 stokes - 1.5 times open hole volume.,Hauled 50 bbis H2O from L -Pad Lake for total = 950 bbis Hauled 0 bbls H2O from B -Pad Creek for total = 7720 bbis Hauled 25 bbis H2O from 6 Mile lake for total = 980 bbls Hauled 0 bbls H2O from G&I Heated for total = 1185 bbls,Hauled 1063 bbis cuttings to G&I for total = 1125 bbls Hauled 0 bbis cuttings/liquids to G&I DS4 = 378 bbls Hauled 100 bbls cuttings/liquids to 1 B WIF for total = 13211 bbls 23 bbis daily downhole losses. 95 bbis total losses for interval. 7/24/2018 Drop the 1-1/4" setting ball and circulate to seat. Ball seated early at 1137 strokes. Pressured up to 1100 psi to close the WIV continue to pressure up to 2800 psi to set the SLZXP liner hanger/top packer and hold for 5 minutes. Walk the pressure up in 200 psi increments to 4150 psi to release the HRDE running tool. Saw good surface indications for tool setting and releasing. Liner Top set depth 6527'.,Verify testing RU. PT the liner top packer and 9-5/8" casing to 1500 psi for 10 minutes on a chart (good test). Bleed the pressure to 0 psi. Pull seals out of tool & check loss rate. Took 80 bbl to fill the hole. Static losses at 240 bbl per hr at 9.0 ppg 2% KCL., Discuss with town and decide to POOH giving the well double pipe displacement and 5 BBL every 10 Min while static. POOH laying down 5" DP from 13892' to 7414'.,Lay down liner running tool. RU power tongs to lay down 2-3/8" inner string. MU safety joint.,Attempt to fill backside with 50 bbis - no returns. POOH laying down 2-318" inner string. Double displace while POOH.,Rig down safety joint. Rig down Weatherford. C/O pipe handling equipment.,Make up clean out assembly. 3-1/2" wash tool and No -Go sub.,RIH with wash tool with DP from derrick to 6559', tag up with 10K down with NO-GO sub at 6527' (Liner top on depth). PUW 155K, SOW 105K.,Pick up above liner top to 6526', break circulation and stage up to 10 bpm = 360 psi. Reciprocate pipe across liner top/seal assembly setting depth (6527' to 6542'). Took 64 bbis to gain returns. CBU with 57% loss rate. Monitor well, fluid level dropping fast.,POOH laying down drill pipe from 6542' to 5151', filling double displacing., Hauled 365 bbis H2O from L -Pad Lake for total = 1315 bbis Hauled 0 bbis H2O from B -Pad Creek for total = 7720 bbis Hauled 0 bbis H2O from 6 Mile lake for total = 980 bbis Hauled 0 bbis H2O from G&I Heated for total = 1185 bbls,Hauled 0 bbls cuttings to G&I for total = 1125 bbls Hauled 0 bbis cuttings/liquids to G&I DS4 = 378 bbis Hauled 1340 bbis cuttings/liquids to 1 B WIF for total = 14551 bbis 616 bbis daily downhole losses. 711 bbis total losses for interval. 7/25/2018 Continue to POOH laying down 5" DP from 5151' to 2578' with cleanout assembly, filling double displacing.,TIH with 5" DP from the derrick from 2579 to 3313', filling double displacing.,Continue to POOH laying down 5" DP from 3313to cleanout assembly, filling double displacing. Lay down wash tool and no-go crossover., PJSM. Pull the wear ring and set the test plug with 7-5/8" test joint.,RU to OA, shot a fluid level in the 9-5/8" at 650' and RD fluid level shot equipment.,Change the UPR from 2-7/8" x 5" VBR's to 7-5/8" solid body rams. SimOps: Mobilize 7-518" power tongs, handling equipment and crossovers to the rig Floor. RU 7-5/8" power tongs and torque turn equipment., Rig up and test UPR's/Annular on 7-5/8" test joint 250/3000 psi. Initial lest failed. Pull test plug and reseat -tests good.,Rig down testing equipment. Pull test plug. M/U landing joint and hanger. Dummy run hanger, mark pipe., Finish rigging up casing tongs. C/O pipe handling equipment. M/U XO to FOSV. Continue filling hole with 20 bbls a/ 30 min.,PJSM. M/U Baker tieback seals. RIH with 7- 5/8" 29.7# L-80 Hydril 521 to 2987'. M/U Hydril 521 x VAM ST -L box. Continue to RIH with 7-518" tieback string to 5202', dog collar and torque turning every joint. Filling hole with 20 bbls every 30 minutes. 7/26/2018 Continue to RIH with 7-518" tie back string from 5202' to 6494'; dog collar and torque turn every joint. Filling the hole with 20 bbls every 30 minutes.,Engage the seal assembly into the tie back sleeve at 6527' to no-go at 653T with 10K down. Mark the pipe and lay down 2 joints.,MU 4.88' casing pup, full joint and mandrel casing hanger with landing joint.,Land the casing hanger (PU = 180K and SO = 122K). RU circulating equipment to reverse circulate. PU V to expose the ports in the tie back seal assembly. PJSM for revers circulating corrosion inhibited brine and diesel.,Reverse circulate 90 bbls of 8.8 ppg corrosion inhibited brine from a vac truck at 5 BPM followed by 50 bbis of diesel from LRS at 2 BPM . Land the mandrel casing hanger., RD the circulating equipment. Back out and lay down the landing joint.,MU the pack -off running tool to a joint of 5" DP and install the pack -off. RILDS. PT the pack -off to 500 psi for 5 minutes (good test) and 3000 psi for 10 minutes (good lest). Lay down pack -off running tool and 5" DP.,RU testing equipment. PT the 7-5/8" x 9-5/8" annulus (OA) with n diesel to 1500 psi for 30 minutes(good test). Bleed pressure to 0 psi and RD testing equipment.,Change the UPR from 7-5/8" solid body rams to 2-7/8" x 5" i \ VBR's.,Rig up and test UPR/LPR/Annular on 2-7/8" test joint 250/3000 psi -good. Fill hole with 15 bbls/30 minutes.,Rig down testing equipment. Puli test plug and L/D test joint. Bring up centrilift equipmenticlamps to rig floor., Hang sheave in derrick and feed capillary lines and ESP cable. Rig up power tongs. M/U XO to FOSV.,PJSM. Makeup ESP assy: centralizer, Zenith sensor, XP motor, lower and upper tandem seals, gas separator, pumps (2), discharge flange and head, 2-7/8" pup joint. Service motor and seals purging air and fill. Install check valves and chem injection cap line, install cap line for discharge pressure. Install motor lead fiat cable and test -good. Test Cap lines, check valves opened at 1500 psi. Continue RIH with ESP.,assembly clamping Cap lines and ESP cable. Clamp usage: 4 motor body clamps, 4 seal clamps, 18 pump clamps.,Continue to RIH with 2-718" ESP completion to 1360', installing cannon clamps on every joint. MEG testing ESP cable every 1000', testing capillary lines every 20001, filling hole with 15 bbl every 30 minutes., Hauled 100 bbls H2O from L - Pad Lake for total = 1490 bbls Hauled 0 bbis H2O from B -Pad Creek for total = 7720 bbis Hauled 0 bbis H2O from 6 Mile lake for total = 980 bbis Hauled 0 bbis H2O from G&I Heated for total = 1185 bbis, Hauled 0 bbls cuttings to G&I for total = 1125 bbls Hauled 0 bbls cuttings/liquids to G&I DS4 = 378 bbis Hauled 0 bbis cuttings/liquids to i B WIF for total = 14908 bbis 583 bbis daily downhole losses. 1939.5 bbls total losses for interval. 7/27/2018 Continue to R I H with 2-718" ESP completion from 1360' to 4000', installing cannon clamps on every joint, MEG testing ESP cable every 1000', testing capillary lines every 2000' and filling hole with 15 bbis every 30 minutes.,Continue to R I H with 2-7/8" ESP completion from 4000' to 5447', installing cannon clamps on every joint, MEG testing ESP cable every 1000', testing capillary lines every 2000' and filling hole with 15 bbls every 30 minutes. Total Cannon clamps used= 177 -Install TWC into the tubing hanger. MU the landing joint to the tubing hanger and MU the tubing hanger to the string.,MEG test ESP cable and test capillarylines. Cut the ESP cable, splice to the penetrator and MU penetrator to the tubing hanger. Terminate both 318" capillary lines and MU to the tubing hanger. Land tubing at 5482.63'.,Rig down and clear rig Floor of Weatherford and CentriliR tools and equipment., Pickup slack washing tool, wash stack. Flush out both mud pumps. Suck out stack. Blow down hole fill, choke and kill lines., Pull riser and remove bell nipple. Pickup and make up cap removal tool to top of BOP. Attempt to break cap, unable to. Steam cap and service break.,Open up ram doors, clean out cavities and shut ram doors., Hauled 0 bbis H2O from L - Pad Lake for total = 1490 bbis Hauled 0 bbis H2O from B -Pad Creek for total = 7720 bbls Hauled 0 bbis H2O from 6 Mile lake for total = 980 bbls Hauled 0 bbis H2O from G&I Heated for total = 1185 bbls,Hauled 0 bbls cuttings to G&I for total = 1125 bbls Hauled 0 bbis cuttings/liquids to G&I DS4 = 378 bible Hauled 225 bbis cuttings/liquids to 1B WIF for total = 15,133 bbis 275 bbis daily downhole losses. 2214.5 bbls total losses for interval. 7 /2 812 01 8 ND the BOP stack and rack back on the stump.,Clean the top of the tubing hanger. PU, orientate and NU the tree and tubing head adapter.,Centrilitt's had a good test on the ESP cable. PT the tubing hanger void to 250/5000 psi for 10 minutes each (good tests).,RU to test the tree with diesel. Had multiple fitting and test hose connections leaks. But still unable to get the tree to hold pressure. Drain the tree of diesel through the wing valve.,Pull the TWC, redress and re- install -Top off the tree with diesel and purge the air. PT the tree to 250/5000 psi for 5 minutes each (good test). Secure the tree and release Doyon 14 from well L-57 at 12:00 hours. Hilcorp Alaska, LLC Milne Point M Pt L Pad MPU L-57 50-029-23609-00 Sperry Drilling Definitive Survey Report 26 July, 2018 HALLIBURTON Sperry Drilling Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-ordinate Reference: Well MPU L-57 Project: Milne Point TVD Reference: MPU L-57 Actual RKB @ 49.30usft Site: M at L Pad MD Reference: MPU L-57 Actual RKB @ 49.30usft Well: MPU L-57 North Reference: True Wellbore: MPU L-57 Survey Calculation Method: Minimum Curvature Design: MPU L-57 Database: Sperry EDM - NORTH US+CANADA Project Milne Point, ACT, MILNE POINT Map System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level Geo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point Map Zone: Alaska Zone 04 Using geodetic scale factor Well MPU L-57 Well Position +N/S +E/ -W Position Uncertainty 0.00 usfl Northing: 0.00 usft Easting: 0.00 usft Wellhead Elevation: 6,031,977.71 usft Latitude: 544,742.15 usft Longitude: 15.30 usft Ground Level: 70' 29' 53.644 N 149' 38'2.769 W 15.30 usft Welihore MPU L57 Magnetics Model Name Sample Date Declination Dip Angle Field Strength con BGGM2018 7/20/2018 17.12 81.00 57,460 Map Vertical MD Inc Design MPU L-57 TVDSS +N/ -S +E/ -W Audit Notes: Easting DLS Section (usft) Version: 1.0 Phase: ACTUAL Tie On Depth: 12,967.49 (usft) Vertical Section: Depth From (TVD) +N/ S +E/ -W Direction (ft) Survey Tool Name 34.00 (usft) (usft) (usft) (') -15.30 0.00 34.00 0.00 0.00 201.24 0.00 0.00 UNDEFINED 100.00 0.25 18.82 100.00 � Survey Program Date 7/26/2018 0.05 6,031,977.85 544,742.20 From To 200.00 0.15 18.11 (usft) (usft) Survey (Wellbore) Tool Name Description Survey Date 100.00 731.00 North Seeking Gyro - SS (MPU L57PB1 2_Gyro-NS-GC_Drill collar H029Ga: North seeking single shot in drill collar 07/07/2018 788.00 6,687.60 MPL-57 MWD+IFR2+MS+sag(MPU L-57 2_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi -station analysis +sag 07/08/2018 6,739.75 12,967.49 MPL-57 MWD+IFR2+MS+sag (2) (MPU 2_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi -station analysis +sag 07/17/2018 12,990.00 13,908.46 MPL-57 MWD+IFR2+MS+sag(MPU L-57 2_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi -station analysis +sag 07/20/2018 Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/ -S +E/ -W Northing Easting DLS Section (usft) (°) (°) (usft] (usft) (usft) (usft) (ft) (ft) (-Maw) (ft) Survey Tool Name 34.00 000 0.00 34.00 -15.30 0.00 0.00 6,031,977.71 544,742.15 0.00 0.00 UNDEFINED 100.00 0.25 18.82 100.00 50.70 0.14 0.05 6,031,977.85 544,742.20 0.38 -0.14 2_Gyro-NS-GC_Dnllmllar(1) 200.00 0.15 18.11 200.00 150.70 0.47 0.16 6,031,978.18 544,742.30 0.10 -0.49 2_Gym-NS-GC_Drillmllar(i) 300.00 0.35 38.02 300.00 250.70 0.83 0.39 6,031,97&&1 544,742.53 0.22 -0.92 2_Gym-NS-GC_Dri1l collar(1) 357.50 0.61 36.66 357.50 308.20 1.22 0.68 6,031,978.93 544,742.82 045 -1.38 2_Gym-NS-GC_Drill collar (1) 448.00 0.24 147.44 447.99 398.69 1.44 1.07 6,031,979.16 544,743.21 0.81 -1.73 2_Gyro-NS-GC_Dnll collar (1) 543.00 1.83 220.43 542.98 493.68 0.12 0.19 6,031,977.83 544,742.34 1.87 -0.18 2_Gym-NS-GC_Drillcollar(1) 637.00 5.25 248.24 636.79 587.49 -2.62 4.78 6,031,975.06 544,737.39 3.97 4.17 2_Gyro-NS-GC_Dnllcollar(1) 731.00 10.91 257.51 729.82 680.52 -6.14 -17.47 6,031,971.47 544,724.72 6.16 12.05 2_Gyrc-NS-GC_Dnll collar f ) 788.00 14.21 251.47 785.45 736.15 -9.53 -29.37 6,031,968.00 544,712.84 6.22 19.52 2 MWD+IFR2+MS+Sag(2) 882.30 16.61 265.84 676.39 827.09 -14.19 -53.80 6,031,963.20 544,688.44 4.76 32.72 2_MWD+IFR2+MS+8eg(2) 726/2018 12:3520PM Page 2 COMPASS 5000.1 Build 81E Halliburton Definitive Survey Report Company: Project: Site: Well: Wellbore: Design: Hilcorp Alaska, LLC Milne Point M Pt L Pad MPU L-57 MPU L-57 MPU L-57 ---- Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Database: Well MPU L-57 MPU L-57 Actual RKB @ 49.30usft MPU L-57 Actual RKB @ 49.30usft True Minimum Curvature Sperry EDM - NORTH US+ CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +NIS +E/ -W Northing Easting DLS Section (usft) (°) (I (usft) (usft) (usft) (usft) (ft) (it) (•/100-) (ft) Survey Tool Name 976.91 19.53 260.80 966.33 917.03 -17.70 -8291 6,031,959.51 544,659.36 3.50 46.53 2_MWD+IFR2+MS+Sag(2) 1,070.91 24.04 255.73 1,053.60 1,004.30 -24.93 -116.99 6,031,952.07 544,625.32 5.19 65.62 2_MWD+IFR2+MS+Sag(2) 1,165.57 28.09 247.63 1,138.64 1,089.34 -38.18 -156.32 6,031,938.60 544,586.08 5.69 92.21 2_MWD+IFR2+MS+Sag(2) 1,259.87 30.80 245.04 1,220.76 1,171,46 56.82 -198.75 6,031,919.70 544,543.77 3.17 12496 2_MWD+IFR2+MS+Sag(2) 1,354.25 34.99 241.41 1,300.00 1,250.70 -79.98 -244.44 6,031,896.27 544,498.22 4.90 163.10 2_MWD+IFR2+MS+Sag(2) 1,448.58 39.39 23299 1,375.13 1,32583 -108.80 -293.60 6,031,867.15 544,449.24 5.15 207.77 2_MWD+IFR2+MS+Sag(2) 1,542.84 42.30 234.84 1,446.44 1,397.14 -142.93 -344.90 6,031,832.72 544,398.15 3.78 258.17 2MWD+IFR2+MS+Sag(2) 1,637.44 44.67 232.06 1,514.96 1,465.66 -181.79 -397.26 6,031,793.55 544,346.03 3.39 313.36 2_MWD+IFR2+MS+Sag(2) 1,731.55 49.97 228.81 1,578.63 1,529.33 -225.97 450.60 6,031,74906 544,292.96 5.98 373.86 2MWD+IFR2+MS+Sag(2) 1,824.89 50.83 226.77 1,638.13 1,588.83 -274.29 -503.86 6,031,700.42 544,240.00 1.92 438.19 2_MWD+IFR2+MS+Sag(2) 1,919.98 55.59 224.67 1,695.06 1,645.76 -327.46 -558.33 6,031,646.92 544,185.86 5.31 507.49 2_MWD+IFR2+MS+Sag(2) 2,013.92 57.55 220.83 1,746.83 1,697.53 -385.03 -611.50 6,031,589.04 544,133.04 4.00 580.41 2_MWD+IFR2+MS+Sag(2) 2,108.54 61.00 216.02 1,795.18 1,745.88 448.76 -661.98 6,031,525.02 544,082.95 5.69 658.09 2_MWD+IFR2+MS+Sag(2) 2,202.75 58.91 214.71 1,842.35 1,793.05 -515.25 -709.18 6,031,458.25 544,036.15 2.52 737.17 2_MWD+IFR2+MS+Sag(2) 2,297.33 59.52 215.20 1,890.76 1,841.46 -581.84 -755.73 6,031,391.39 543,990.01 0.78 816.10 2_MWD+IFR2+MS+Sag(2) 2,391.12 58.22 216.25 1,939.25 1,889.95 -647.02 -802.60 6,031,325.93 543,943.53 1.69 893.83 2_MWD+IFR2+MS+Sag(2) 2,486.41 60.19 215.14 1,988.03 1,938.73 -713.50 550.35 6,031,259.18 543,896.19 2.30 973.09 2_MWD+IFR2+MS+Sag(2) 2,580.89 59.72 214.25 2,035.34 1,98604 -780.74 596.91 6,031,191.66 543,850.05 0.96 1,052.63 2_MWD+IFR2+MS+Sag(2) 2,675.06 58.95 214.15 2,083.36 2,034.06 547.73 -942.44 6,031,124.40 543,804.82 0.82 1,131.57 2_MWD+IFR2+MS+Sag(2) 2,769.24 57.83 214.41 2,132.73 2,08343 -914.01 -98]61 6,031,057.87 543,760.16 1.21 1,209.70 2_MWD+IFR2+MS+Sag(2) 2,863.56 58.09 216.45 2,182.77 2,133.47 -979.15 -1,033.96 6,030,992.45 543,714.21 1.85 1,287.21 2 MWD+IFR2+MS+Sag(2) 2,956.61 57.27 215.92 2,232.52 2,183.22 -1,042.61 -1,080.38 6,030,928.72 543,668.17 1.00 1,363.18 2_MWD+IFR2+MS+Sag(2) 3,051.72 60.61 216.89 2,281.58 2,232.28 -1,108.17 -1,128.74 6,030,862.88 543,620.21 3.62 1,441.81 2_MWD+IFR2+MS+Sag(2) 3,147.19 60.00 217.48 2,328.88 2,27958 -1,174.24 -1,178.86 6,030,796.51 543,570.49 0.83 1,521.55 2_MWD+IFR2+MS+Sag(2) 3,241.20 59.31 217.68 2,376.37 2,327.07 -1,23853 -1,228.34 6,030,731.93 543,521.41 0.76 1,599.40 2_MWD+IFR2+MS+Sag(2) 3,335.96 58.49 218.17 2,425.32 2,376.02 -1,302.54 -1,278.21 6,030,667.63 543,471.93 0.97 1,677.12 2MWD+IFR2+MS+Sag(2) 3,430.25 57.84 218.75 2,47505 2,425.75 -1,365.27 4,328.03 6,030,604.61 543,422.49 0.87 1,753.64 2_MWD+IFR2+MS+Sag(2) 3,524.38 58.37 218.48 2,524.79 2,475.49 -1,428.57 -1,376.80 6,030,541.02 543,374.11 2.12 1,830.31 2_MWD+IFR2+MS+Sag(2) 3,619.03 58.04 216.73 2,574.66 2,52536 -1,493.15 -1,424.77 6,030,476.16 543,326.53 0.41 1,907.88 2_MWD+IFR2+MS+Sag(2) 3,713.56 59.52 216.03 2,623.66 2,574.36 -1,558.23 -1,472.71 6,030,410.79 543,278.99 1.69 1,985.91 2_MWD+IFR2+MS+Sag(2) 3,807.86 58.64 216.26 2,672.11 2,622.81 -1,623.56 -1,520.43 6,030,345.19 543,231.67 0.96 2,064.09 2 MWD+IFR2+MS+Sag(2) 3,901.91 5690 216.85 2,722.27 2,672.97 -1,687.47 -1,567.81 6,030,281.00 543,184.68 1.92 2,140.82 2MWD+IFR2+MS+Sag(2) 3,996.31 57.88 217.56 2,773.14 2,723.84 -1,750.80 -1,615.89 6,030,217.39 543,136.98 1.22 2,217.27 2_MWD+IFR2+MS+Sag(2) 4,091.08 59.24 215.66 2,822.58 2,773.28 -1,815.70 -1,664.10 6,030,152.20 543,089.17 2.23 2,295.23 2_MWD+IFR2+MS+Seg(2) 4,184.95 58.05 216.01 2,871.42 2,822.12 -1,880.69 -1,711.03 6,030,086.94 543,042.64 1.31 2,372.80 2_MWD+IFR2+MS+Sag(2) 4,279.84 58.28 216.19 2,921.47 2,672.17 -1,945.83 -1,758.53 6,030,021.52 542,995.54 0.29 2,450.72 2_MWD+IFR2+MS+Sag(2) 4,374.12 60.30 214.86 2,969.62 2,920.32 -2,011.80 -1,805.61 6,029,955.28 542,948.85 2.46 2,529.27 2_MWD+IFR2+MS+Sag(2) 4,468.60 60.18 214.94 3,016.52 2,967.22 -2,079.06 -1,852,54 6,029,887.74 542,902.34 0.15 2,608.97 2_MWD+IFR2+MS+Sag(2) 4,563.36 61.70 211.56 3,062.55 3,013.25 -2,148.33 -1,897.93 6,029,818.21 542,857.37 3.51 2,689.97 2_MWD+IFR2+MS+Sag(2) 4,657.26 59.66 206.71 3,108.55 3,059.25 -2,219.79 -1,937.80 6,029,746.52 542,817.93 5.00 2,771.02 2_MWD+IFR2+MS+Sag(2) 7/262018 12:35:20PM Page 3 COMPASS 5000.1 Build 81E Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt L Pad Well: MPU L-57 Wellbore: MPU L-57 Design: MPU L-57 Survey Halliburton Definitive Survey Report Local Co-ordinate Reference: TVD Reference: NO Reference: North Reference: Survey Calculation Method: Database: Well MPU L-57 MPU L-57 Actual RKB @ 49.30usft MPU L-57 Actual RKB @ 49.30usft True Minimum Curvature Sperry EDM - NORTH US + CANADA Map Map Vertical MD Inc Azi TVD TVDSS +NIS +E1 -W Northing Easting DLS Section (usft) C) V) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 4,751.17 58.84 204.25 3,156.57 3,107.27 -2,292.63 -1,972.52 6,029,673.47 542,783.65 2.41 2,851.49 2_MWD+IFR2+MS+Sag(2) 4,845.77 59.71 203.40 3,204.91 3,155.61 -2,367.02 -2,005.37 6,029,598.89 542,751.26 1.20 2,932.73 2_MWD+IFR2+MS+Sag(2) 4,939.83 59.43 204.09 3,252.55 3,203.25 -2,441.26 -2,038.03 6,029,52447 542,719.05 0.70 3,013.75 2_MWD+IFR2+MS+Sag(2) 5,033.41 59.35 204.56 3,300.20 3,250.90 -2,514.65 -2,071.20 6,02945088 542,686+32 0.44 3,094.18 2_MWD+IFR2+MS+Sag(2) 5,127.74 59.91 204.63 3,347.89 3,298.59 -2,588.65 -2,105.07 6,029,376.69 542,652.90 0.60 3,175.42 2_MWD+IFR2+MS+Sag(2) 5,222.40 59.24 206.09 3,395.83 3,346.53 -2,652.41 -2,14003 6,029,30233 542,618.39 1.51 3,256.83 2_MWD+IFR2+MS+Sag(2) 5,316.97 59.48 206.67 3,444.02 3,394.72 -2,735.30 -2,176.18 6,029,229.63 542,582.68 0.59 3,337.87 2_MWD+IFR2+MS+Sag(2) 5,411.84 59.88 207.05 3,491.92 3,442.62 -2,808.36 -2,213.18 6,029,156.35 542,546.13 0.55 3,419.37 2_MWD+IFR2+MS+Sag(2) 5,505.70 59.14 207.49 3,539.54 3,490.24 -2,880.25 -2,250.24 6,029,084.25 542,509.51 0.89 3,499.80 2_MWD+IFR2+MS+Sag(2) 5,600.17 60.07 207.70 3,587.34 3,538.04 -2,952.47 -2,287.99 6,029,011.81 542,472.20 1.00 3,580.79 2_MWD+IFR2+MS+Sag(2) 5,694.17 59.64 207.36 3,634.54 3,585.24 -3,024.55 -2,325.56 6.028.939.51 542,435.07 0.55 3,661.59 2_MWD+IFR2+MS+Sag(2) 5,788.53 58.41 205.69 3,683.11 3,633.81 -3,096.93 -2,361.69 6,028,866.93 542,399.37 2.00 3,742.14 2_MWD+IFR2+MS+Sag(2) 5,883.40 57.54 205.95 3,73342 3,684.12 -3,169.33 -2,396.72 6,028,794.32 542,364.78 0.95 3,822.31 2_MWD+IFR2+MS+Sag(2) 5,977.64 60.58 206.76 3,781.86 3,73256 -3,241.74 -2,432.61 6,028,721.70 542,329.33 3.31 3,902.81 2_MWD+IFR2+MS+Sag(2) 6,072.27 65.93 205.20 3,824.44 3,775.14 -3,317.69 -2,469.59 6,028,645.54 542,292.82 5.84 3,987.00 2_MWD+IFR2+MS+Sag(2) 6.166.01 69.56 204.86 3,859.93 3,810.63 -3,396.29 -2,506.29 6,028,566.73 542,256.60 3.89 4,073.55 2_MWD+IFR2+MS+Sag(2) 6,261.00 73.19 201.35 3,890.27 3,840.97 -3,479.07 -2,541.57 6,028,483.75 542,221.81 5.18 4,163.49 2_MWD+IFR2+MS+Sag(2) 6,355.24 77.44 198.51 3,914.16 3,864.86 -3,564.75 -2,57261 6,028,39].89 542,191.29 5.37 4,254.59 2_MWD+IFR2+MS+Sag(2) 6,449.87 80.58 19.79 3,932.20 3,862.90 -3,653.01 -2,601.54 6,028,309.47 542,162.89 3.40 4,347.34 2MWD+IFR2+MS+Sag(2) 6,544.36 86.42 198.99 3,942.89 3,893.59 -3,74205 -2,631.16 6,028,220.25 542,133.82 631 4,441.06 2_MWD+IFR2+MS+Sag(2) 6,638.53 92.78 197.07 3,943.55 3,894.25 -3,831.55 -2,660.28 6,028,130.59 542,105.24 7.05 4,535.03 2_MWD+IFR2+MS+Sag(2) 6,687+60 93.61 197.29 3,940.82 3,89152 -3,87835 -2,674.76 6,028,083.70 542,091.05 1.75 4,583.90 2_MWD+IFR2+MS+Sag(2) 6,739.75 93.32 197.01 3,937.66 3,888.36 -3,928.09 -2,690.11 6,028,033.88 542,07600 0.77 4,635.82 2_MWD+IFR2+MS+Sag(3) 6,834.78 9130 197.38 3,933.50 3,884.20 4,018.79 -2,718.17 6,027,943.03 542,048.48 1.75 4,730.52 2_MWD+IFR2+MS+Sag(3) 6,928.87 90.59 198.38 3.931.62 3,882.32 4.108.31 -2,747.05 6,027,853.34 542,020.14 1.59 4,824.43 2_MWD+IFR2+MS+Sag(3) 7,023.31 92.02 19855 3,929.47 3,880.17 4,197.86 -2,776.96 6,027,763.62 541,990.78 1.52 4,918.73 2_MWD+IFR2+MS+Sag(3) 7,118.17 92.32 198.02 3,925.88 3,876.58 4,287.87 -2,806.70 6,027,673.44 541,961.59 0.64 5,013.40 2_MWD+IFR2+MS+Sag(3) 7,213.36 92.51 198.26 3,921.87 3,872.57 4,378.75 -2,834.72 6,027,582.41 541,934.11 1.86 5,108.25 2_MWD+IFR2+MS+Sag(3) 7,308.00 92.20 194.32 3,91].98 3,868.68 4,469.96 -2,859.86 6,027,491.06 541,909.73 2.07 5,202.30 2_MWD+IFR2+MS+Sag(3) 7,400.35 94.00 194.75 3,912.98 3,863.68 4,559.22 -2,882.80 6,027,401.67 541,887.13 2.00 5,293.88 2_MWD+IFR2+MS+Sag(3) 7,494.95 91.76 194.34 3,908.23 3,858.93 4,650.66 -2,906.53 6,027,310.09 541,863.95 2.41 5,387.71 2_MWD+IFR2+MS+Sag(3) 7,591.18 91.33 196-71 3,905.64 3,856.34 4,743.34 -2,932.27 6,027,217.27 541,838.77 2.50 5,483.42 2_MWD+IFR2+MS+Sag(3) 7,683.13 91.40 195.47 3,903.45 3,854.15 4,831.66 -2,957.75 6,027,128.80 541,813.83 1.35 5,574.97 2_MWD+IFR2+MS+Sag(3) 7,777.48 91.64 196.40 3,900.94 3,851.64 4,922.35 -2,983.64 6,027,037.97 541,788.48 1.02 5,668.88 2 MWD+IFR2+MS+Sag(3) 7,872.04 92.07 195.73 3,897.88 3,848.58 -5,013.17 -3,009.79 6,026,947.00 541,762.88 0.84 5,763.01 2_MWD+IFR2+MS+Sag(3) 7,964.65 92.82 195.64 3,893.93 3,844.63 -5,102.25 -3,034.81 6,026,857.78 541,738.40 0.82 5,855.10 2_MWD+IFR2+MS+Sag(3) 8,060.46 92.69 196.05 3,889.33 3,840.03 -5,194.32 -3,060.94 6,026,765.57 541,712.83 0.45 5,950.37 2_MWD+IFR2+MS+Sag(3) 8,155.09 91.58 194.59 3,885.80 3,83650 -5,285.52 -3,085.92 6,026,674.23 541,688.40 1.94 6,44.43 2_MWD+IFR2+MS+Sag(3) 8,249.52 90.90 194.05 3,883.76 3,834.46 -5,376.99 -3,109.27 6,026,582.63 541,665.60 0.92 6,138.15 2_MWD+IFR2+MS+Sag(3) 8,343.85 90.34 192.76 3,882.74 3,833.44 -5,468.74 -3,131.14 6,026,490.75 541,644.29 1.49 6,231.59 2_MWD+IFR2+MS+Sag(3) 7/26.2018 12:35:20PM Page 4 COMPASS 5000.1 Build 81E Halliburton Definitive Survey Report Company: Project: Site: Well: Wellbore: Design: Hilcorp Alaska, LLC Milne Point M Pt L Pad MPU L-57 MPU L-57 MPU L-57 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Database: Well MPU L-57 MPU L-57 Actual RKB @ 49.30usft MPU L-57 Actual RKB @ 49.30usft True Minimum Curvature Sperry EDM - NORTH US + CANADA Survey Map Map vertical MD Inc Azi TVD TVDSS +NIS +E/ -W Northing Easting DLS Section Wait) (1) r) Cush) (usft) (usft) (usft) (ft) (ft) (°/1001 (ft) Survey Tool Name 8,438.25 92.27 192.14 3,880.59 3,63129 -5,560.89 -3,151.48 6,026,398.49 541,624.50 2.15 6,324.85 2MWD+IFR2+MS+Sag(3) 8,531.25 93.00 193.26 3,876.31 3,82].01 -5,651.52 3,171A1 6,026,307.75 541,604.63 1.44 6,416.72 2_MWD+IFR2+MS+Sag(3) 8,627.29 92.20 192.95 3,871.96 3,822.66 -5,744.96 -3,193.66 6,026,214.19 541,583.44 0.89 6,511.70 2_MWD+IFR2+MS+Sag(3) 8,719.13 92.01 192.87 3,868.58 3,819.28 -5,834.42 -3,214.17 6,026,124.62 541,563.48 0.22 6,602.51 2_MWD+IFR2+MS+Sag(3) 8,815.71 92.08 192.77 3,865.14 3,815.84 -5,926.53 -3,235.58 6,026,030.39 541,542.63 0.13 6,697.98 2_MWD+IFR2+MS+Sag(3) 8,909.73 92.45 191.14 3,861.42 3,812.12 -6,020.44 3,255.04 6,025,938.38 541,523.72 1.78 6,790.70 2_MWD+IFR2+MS+Sag(3) 9,003.63 91.39 190.51 3,858.27 3,80697 .6,112.61 3,272.67 6,025,846.11 541,506.66 1.31 6,883.00 2_MWD+IFR2+MS+Sag(3) 9.096.65 91.62 190.64 3,855.83 3,806.53 -6,204.02 -3,289.73 6,025,754.61 541,490.14 0.28 6,974.38 2_MWD+IFR2+MS+Sag(3) 9,190.04 92.20 191.34 3,652.72 3,803.42 -6,295.65 -3,307.53 6,025,662.88 541,472.90 0.97 7,066.23 2_MWD+IFR2+MS+Sag(3) 9,286.79 93.19 192.92 3,848.17 3,798.87 -6,390.13 -3,327.83 6,025,568.29 541,453.17 1.93 7,161.65 2_MWD+IFR2+MS+Sag(3) 9,381.50 92.32 191.80 3,843.62 3,794.32 -6,482.53 -3,348.08 6,025,475.77 541,433.48 1.50 7,255.11 2_MWD+IFR2+MS+Sag(3) 9,475.82 91.44 188.67 3,840.52 3,791.22 -6,575.29 -3,364.83 6,025,382.93 541,417.29 3.45 7,347.63 2_MWD+IFR2+MS+Sag(3) 9,570.17 92.01 186.37 3,837.68 3,788.38 6,668.78 3,377.17 6,025,289.37 541,405.51 2.51 7,439.24 2_MWD+IFR2+MS+Sag(3) 9,664.92 91.39 186.21 3,834.87 3,785.57 6,762.92 -3,387.55 6,025,195.19 541,395.70 0.68 7,530.74 2_MWO+IFR2+MS+Sag(3) 9,759.79 92.21 185.34 3,831.89 3,782.59 -6,857.26 3,397.09 6,025,100.80 541,386.73 1.26 7,622.13 2_MWD+IFR2+MS+Sag(3) 9,854.47 92.20 186.23 3,828.25 3,778.95 -6,951.38 3,406.62 6,025,006.63 541,377.76 0.94 7,713.32 2_MWD+IFR2+MS+Sag(3) 9,948.91 92.01 187.94 3,824.78 3,775.48 -7,045.04 3,418.26 6,024,912.91 541,366.69 1.82 7,804.83 2_MWD+IFR2+MS+Sag(3) 10,042.51 89.73 186.17 3,823.36 3,774.06 -7,137.91 -3,429.76 6,024,819.98 541,355.76 3.08 7,895.55 2_MWD+IFR2+MS+Sag(3) 10,136.78 90.22 184.91 3,823.40 3,774.10 -7,231.74 -3,438.86 6,024,726.11 541,347.22 1.43 7,986.30 2_MWD+IFR2+MS+Sag(3) 10,231.91 MAI 185.16 3,822.04 3,772.74 -7,326.49 -3,447.21 6,024,631.32 541,339.44 1.28 8,077.64 2_MWD+IFR2+MS+Sag(3) 10,325.36 91.50 185.57 3,819.67 3,770.37 -7,419.50 -3,455.94 6,024,538.27 541,331.27 0.45 8,167.50 2_MWD+IFR2+MS+Sag(3) 10,419.95 91.33 184.66 3,817.34 3,768.04 -7,513.68 -3,464.37 6,024,444.05 541,323.41 0.98 8,258.34 2_MWD+IFR2+MS+Sag(3) 10,514.72 91.72 184.88 3,814.81 3,765.51 -7,608.09 3,472.25 6,024,349.60 541,316.10 0.47 8,349.19 2_MWD+IFR2+MS+Sag(3) 10,609.11 93.08 185.76 3,810.86 3,761.56 -7,701.99 3,480.99 6,024,255.66 541,307.92 1.72 8,439.88 2_MWD+IFR2+MS+Sag(3) 10,702.47 91.74 185.97 3,806.94 3,757.64 -7,794.77 -3,490.52 6,024,162.83 541,298.95 1.45 8,529.81 2_MW0+IFR2+MS+Sag(3) 10,797.33 92.51 188.25 3,803.42 3,754.12 -7,886.83 -3,502.25 6,024,068.71 541,287.79 2.54 8,621.73 2_MWD+IFR2+MS+Sag(3) 10,892.21 92.01 190.16 3,799.68 3,750.38 -7,982.41 3,517.42 6,023,975.05 541,273.19 2.08 8,714.45 2_MWD+IFR2+MS+Sag(3) 10,986.55 91.48 192.22 3,796,80 3,747.50 -8,074.91 -3,535.72 6,023,882.45 541,255.45 2.25 8,807.30 2_MWD+IFR2+MS+Sag(3) 11,081.15 91.83 192.14 3,794.07 3,7"4 -8,167.34 -3,555.67 6,023,789.91 541,236.05 0.38 8,900.68 2_MWD+IFR2+MS+Sag(3) 11,175.58 89.65 190.67 3,792.85 3,743.55 -8,259.89 -3,574.34 6,023,697.26 541,217.94 2.78 8,993.70 2_MWD+IFR2+MS+Sag(3) 11,269.70 90.28 190.77 3,792.91 3,743.61 -8,352.37 -3,591.85 6,023,604.69 541,200.99 0.68 9,086.24 2_MWD+IFR2+MS+Sag(3) 11,363.17 92.52 193.30 3,790.62 3,741.32 -8,443.74 -3,611.33 6,023,513.21 541,182.07 3.61 9,178.47 2_MWD+IFR2+MS+Sag(3) 11,458.26 92.51 193.70 3,786.45 3,737.15 -8,536.12 -3,633.50 6,023,420.71 541,160.45 0.42 9,272.60 2_MWD+IFR2+MS+Sag(3) 11,552.69 91.99 193.04 3,782.74 3,733.44 -8,627.92 -3,655.32 6,023,328.79 541,139.19 0.89 9,366.07 2_MWD+IFR2+MS+Sag(3) 11,647.51 92.88 191.97 3,778.72 3,729.42 -8,720.40 3,675.83 6,023,236.19 541,119.23 1.47 9,459.70 2_MWD+IFR2+MS+Sag(3) 11,741.56 93.99 193.21 3,773.08 3,723.78 48,812.02 -3,696.30 6,023,144.46 541,099.32 1.77 9,552.51 2_MWD+IFR2+MS+Sag(3) 11,835.97 92.33 192.57 3,767.88 3,718.58 5,903.91 -3,717.32 6,023,052.46 541,078.85 1.88 9,645.77 2_MWD+IFR2+MS+Sag(3) 11,928.89 93.19 192.17 3,763.40 3,714.10 5,994.57 -3,737.21 6,022,961.69 541,059.52 1.02 9,737.47 2_MWD+IFR2+MS+Sag(3) 12,023.91 91.89 192.36 3,759.19 3,709.89 -9,087.32 -3,757.37 6,022,868.82 541,039.91 1.38 9,831.24 2_MWD+IFR2+MS+Sag(3) 12,117.78 91.35 191.97 3,756.54 3,70724 -9,179.05 3,777.14 6,022,776.99 541,020+69 0.71 9,923.89 2_MWD+IFR2+MS+Sag(3) 7/26/2018 12:35:20PM Page 5 COMPASS 5000.1 Build 81E Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-ordinate Reference: Well MPU L-57 Project: Milne Point TVD Reference: MPU L-57 Actual RKB @ 49.30usft Site: M Pt L Pad MD Reference: MPU L-57 Actual RKB @ 49.30usft Well: MPU L-57 North Reference: True Wellbore: MPU L-57 Survey Calculation Method: Minimum Curvature Design: MPU L-57 Database: Sperry EDM - NORTH US+CANADA Survey j Map Map Vertical MD Inc Azi TVD TVDSS +N/ -S +E/ -W Northing Easting DLS Section (usft) (°) (1) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 12,212.31 91.74 193.30 3,753.99 3,704.69 -9,271.25 -3,797.81 6,022,684.67 541,000.58 1.47 10,017.32 2_MWD+IFR2+MS+Sag(3) 12,307.33 92.68 194.14 3,750.32 3,701.02 -9,363.49 -3,820.33 6,022,592.31 540,978.62 1.33 10,111.45 2_MWD+IFR2+MS+Sag(3) 12,400.55 92.26 195.10 3,746.31 3,697.01 -9,453.61 -3,843.84 6,022,502.06 540,955.66 1.12 10,203.96 2_MWD+IFR2+MS+Sag(3) 12,495.10 91.70 193.89 3,74304 3,693.74 -9,54509 6,867.49 6,022,410.44 540,932.56 1.41 10,297.80 2_MWD+IFR2+MS+Sag(3) 12,58937 91.27 194.45 3,740.59 3,691.29 -9,636.85 -3,890.66 6,022,318.56 540,909.95 0.75 10,391.72 2_MWD+IFR2+MS+Sag(3) 12,684.45 90.08 193.16 3,73947 3,690.17 -9,728.79 -3,913.25 6,022,226 50 540,887.92 1.85 10,485.59 2_MWD+IFR2+MS+Sag(3) M 12,778.85 91.28 193.45 3,738.35 3,689.05 -9,820.64 -3,934.97 6,022,134.52 540,866.75 1.31 10,579.08 2_WD+IFR2+MS+Sag(3) 12,873.23 9326 193.89 3,734.61 3,685.31 -9,912.27 -3,957.26 6,022,042.76 540,845.02 2.15 10,672.56 2_MWD+IFR2+MS+Sag(3) 12,967.49 92.19 193.27 3,730.13 3,680.83 -10,003.79 J,978.36 6,021,951.12 540,823.46 1.31 10,765.87 2_MWD+IFR2+MS+Sag(3) 12,990.00 91.22 192.88 3,729.46 3,680.16 -10,02531 -3,984.45 6,021,929.18 540,818.51 4.64 10,788.14 2_MWD+IFR2+MS+Sag(4) 13,029.69 89.54 192.18 3,729.20 3,679.90 -10,064.65 -3,993.11 6,021,890.19 540,810.09 4.56 10,827.57 2_MWD+IFR2+MS+Sag(4) 13,061.01 89.33 192.69 3,729.50 3,680.20 -10,095.04 -3,999.81 6,021,859.77 540,803.57 1.77 10,858.32 2_MWD+IFR2+MS+Sag(4) 13,154.46 90.66 193.14 3,729.51 3,680.21 -10,186.12 4,020.69 6,021,768.57 540,783.23 1.50 10,950.79 2_MWD+IFR2+MS+Sag(4) 13,248.83 91.40 193.03 3,727.82 3,678.52 -10,278.02 4,042.06 6,021,676.55 540,762.43 0.79 11,044.19 2_MWD+IFR2+MS+Sag(4) 13,343.92 93.13 195.18 3,724.06 3,674.76 -10,370.17 3,065.21 6,021,584.28 540,739.83 2.90 11,138.46 2_MWD+IFR2+MS+Sag(4) 13,438.10 91.76 193.78 3,720.04 3,670.74 -10,461.27 3,088.73 6,021,493.04 540,716.86 2.08 11,231.89 2_MWD+IFR2+MS+Sag(4) 13,532.40 91.71 192.52 3,717.18 3,667.88 -10,553.05 -4,110.18 6,021,401.14 540695.97 1.34 11,325.21 2_MWD+IFR2+MS+Sag(4) 13,627.01 91.27 193.43 3,714.72 3,66542 -10,645.21 4.131.41 6,021,308.86 540.675.29 1.07 11,418.80 2_MWD+IFR2+MS+Sag(4) 13,721.55 92.30 192.83 3,711.78 3,662.48 -10,737.23 3,152.88 6,021,216.72 540,654.39 1.26 11,512.35 2_MWD+IFR2+MS+Sag (4) 13,815.83 93.00 191.51 3,70].42 3,658.12 -10,829.29 4,172.73 6,021,124.55 540,635.09 1.58 11,60535 2_MWD+IFR2+MS+Sag(4) 13,908.46 94.47 191.02 3,701.39 3,652.09 -10,919.94 3,190.79 6,021,033.81 540,617.58 1.67 11,696.38 2_MWD+IFR2+MS+Sag(4) 13,941.00 94.47 191.02 3,698.85 3,649.55 -10,95139 4,196.99 6,021,001.93 540,611.57 0.00 11,728.31 PROJECTEDto TD Checked By: Michael Calkins Approved By: Mitch Laird -- Date: 7/26/218 7262018 12:35:20PM Page 6 COMPASS 5000.1 Build 81E Hilcorp Alaska, LLC Milne Point M Pt L Pad MPU L-57PB1 50-029-23609-70 Sperry Drilling Definitive Survey Report 26 July, 2018 HALLIBURTON Sperry Drilling Halliburton Definitive Survey Report Company: Hiicorp Alaska, LLC Local Coordinate Reference: Well MPU L-57 Project: Milne Point TVD Reference: MPU L-57 Actual RKB @ 49.30usft Site: M Pt L Pad MD Reference: MPU L-57 Actual IRKS @ 49.30usft Well: MPU L-57 North Reference: True Wellbore: MPU L-57PB1 Survey Calculation Method: Minimum Curvature Design: MPU L-57PB1 Database: Sperry EDM - NORTH US + CANADA 'roject Milne Point, ACT, MILNE POINT dap System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level Seo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point dap Zone: Alaska Zone 04 Using geodetic scale factor Well MPU L57 From To Well Position +N/ -S 0.00 usft Northing: (usft) 6,031,977.71 usft Latitude: 70° 29'53,644 N Survey Date +E/ -W 0.00 usft Easting: 2_Gyro-NS-GC_Drill collar 544,742.15 usft Longitude: 149° 38'2+769 W Position Uncertainty 2_MWD+IFR2+MS+Sag 0.00 usft Wellhead Elevation: 15.30 usft Ground Level: 15.30 usft Wellbore MPU L-57PB1 07/17/2018 Map Vertical MD Magnetics Model Name Sample Date Declination +N/S Dip Angle Field Strength Easting DLS Section (usft) 0 (') (nn (usft) BGGM2018 7!7/2018 (usft) 17.14 81.00 57,461 (ft) Survey Tool Name 34.00 0.00 0.00 34.00 -15.30 0.00 Design MPU L-57PB1- 544,742.15 0.00 0.00 UNDEFINED 100.00 0.25 Audit Notes: 100.00 50.70 0.14 0.05 6,031,977.85 544,742.20 Version: 1.0 Phase: ACTUAL Tie On Depth: 34.00 200.00 Vertical Section: 0.47 Depth From (TVD) +N/S +El -W Direction 6.49 2_Gyro-NS-GC_Dnll collar (1) 300.00 0.35 (usft) (usft) (usft) (I 0.39 6,031,978.54 544,742.53 34.00 0.00 0.00 201.24 36.66 357.50 308.20 1.22 0.66 6,031,978.93 544,742.82 0.45 Survey Program Date 7/26/2018 From To (usft) (usft) Survey (Waltham) Tool Name Description Survey Date 100.00 731.00 North Seeking Gyro - SS (MPU L-57PB1 2_Gyro-NS-GC_Drill collar H029Ga: North seeking single shot in drill collar 07/07/2018 788.00 6,687.60 MPL-57 MWD+IFR2+MS+sag (MPU L-57 2_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi -station analysis + sag 07/08/2018 6,739.75 13,154.01 MPL-57 MWD+IFR2+MS+sag (2) (MPU 2_MWD+IFR2+MS+Sag A013Mb: IIFR dec&multi-station analysis +sag 07/17/2018 72152018 12:43:17PM Page 2 COMPASS 5000.1 Build 81E Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/S +E/ -W Northing Easting DLS Section (usft) 0 (1 (usft) (usft) (usft) (usft) (ft) (ft) (./100') (ft) Survey Tool Name 34.00 0.00 0.00 34.00 -15.30 0.00 0.00 6,031,977.71 544,742.15 0.00 0.00 UNDEFINED 100.00 0.25 18.82 100.00 50.70 0.14 0.05 6,031,977.85 544,742.20 0.38 6.14 2_Gyro-NS-GC_Drill collar (1) 200.00 0.15 18.11 200.00 150.70 0.47 0.16 6,031,978.18 544,742.30 0.10 6.49 2_Gyro-NS-GC_Dnll collar (1) 300.00 0.35 38.02 300.00 250.70 0.83 0.39 6,031,978.54 544,742.53 0.22 -0.92 2_Gyn NS-GC_Drill collar(1) 357.50 0.61 36.66 357.50 308.20 1.22 0.66 6,031,978.93 544,742.82 0.45 -1.38 2_Gyro-NS-GC_DnII collar (1) 448.00 0.24 147.44 447.99 398.69 1.44 1.07 6,031,979.16 544,743.21 0.81 -1.73 2_Gyro-NS-GC_Dnll collar (1) 543.00 1.83 220.43 542.98 493.68 0.12 0.19 6,031,977.83 544,742.34 1.87 -0.18 2_Gyro-NS-GC_Dnll collar (1) 637.00 5.25 248.24 63639 587.49 -2.62 4]8 6.031,975+06 544,737.39 3.97 4.17 2_Gyro-NS-GC_Dn1l collar (1) 731.00 10.91 257.51 729.82 680.52 6.14 -17.47 6,031,971.47 544,724.72 6.16 12.05 2_Gyro-NS-GC_Drilt far (1) 788.00 14.21 251.47 785.45 736.15 -9.53 -29.37 6,031,968.00 544,712.84 6.22 19.52 2_MWD+IFR2+MS+Seg(2) 882.30 16.61 265.84 876.39 827.09 -14.19 -53.80 6,031,963.20 544,688.44 4.76 32.72 2_MWD+IFR2+MS+Sag(2) 976.91 19.53 260.80 966.33 917D3 -17.70 62.91 6,031,959.51 544,659.36 3.50 46.53 2_MWD+IFR2+MS+Sag(2) 72152018 12:43:17PM Page 2 COMPASS 5000.1 Build 81E Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-ordinate Reference: Well MPU L-57 Project: Milne Paint TVD Reference: MPU L-57 Actual RKB @ 49.30usft Site: M Pt L Pad MD Reference: MPU L-57 Actual RKD @ 49.30usft Well: MPU L-57 North Reference: True Wellbore: MPU L-57PB7 Survey Calculation Method: Minimum Curvature Design: MPU L-57PB1 Database: Sperry EDM - NORTH US +CANADA Survey Map Map vertical MD Inc AZI TVD TVDSS +NIS +E/ -W Northing Easting DLS Section (usft) (1) (') (usft) (usft) (usft) (usft) (ft) (ft) (.1100') (ft) Survey Tool Name 1,070.91 24.04 255.73 1,053.60 1,004.30 -24.93 -116.99 6,031,952.07 544,625.32 5.19 65.62 2_MWD+IFR2+MS+Sag(2) 1,165.57 28.09 247.63 1,138.64 1,08934 -38.18 -156.32 6,031,938.60 544,586.08 5.69 92.21 2_MWD+IFR2+MS+Sag(2) 1,259.87 30.80 245.04 1,220.76 1,171.46 -56.82 -198.75 6,031,919.70 544,543.77 3.17 124.96 2_MWD+IFR2+M8+Sag(2) 1,354.25 34.99 241.41 1,30080 1,250.70 -79.98 -244.44 6,031,896.27 544,498.22 4.90 163.10 2_MWD+IFR2+MS+Sag(2) 1,448.58 39.39 237.99 1,375.13 1,325.83 -108.80 -293.60 6,031,867.15 544,449.24 5.15 207.77 2_MWD+IFR2+MS+Sag(2) 1,542.84 42.30 234.84 1,446.44 1,397.14 -142.93 -344.90 6,031,832.72 544,398.15 3.78 258.17 2_MWD+IFR2+MS+Sag(2) 1,637.44 44.87 232.06 1,514.96 1,465,66 -181.79-397.26 6,031,793.55 544,346.03 3.39 313.36 2_MWD+IFR2+MS+Sag(2) 1,731.55 49.97 228.81 1,578.63 1,529.33 -225.97 -450.60 6,031,749.06 544,292.96 5.98 373.86 2_MWD+IFR2+MS+Sag(2) 1,824.89 50.83 226.77 1,638.13 1,588.83 -274.29 -503.86 6,031,700.42 544,240.00 1.92 438.19 2_MWD+IFR2+MS+Sag(2) 1,919.98 55.59 224.67 1,695.06 1.645.76 -327.46 558.33 6,031,646+92 544,185.86 5.31 507.49 2_MWD+IFR2+MS+Sag(2) 2,013.92 57.55 220.83 1.746.83 1.697,53 -385.03 511.50 6,031,589.04 544,133.04 4.00 580.41 2_MWD+IFR2+MS+Sag(2) 2.108.54 61.00 216.02 1,795.18 1,745,88 -048.76 -661.98 6,031,525.02 544,082.95 5.69 658.09 2_MWD+IFR2+MS+Sag(2) 2,202.75 5891 214.71 1,842.35 1,793.05 -515.25 -709.18 6,031,458.25 544,036.15 2.52 737.17 2_MWD+IFR2+MS+Sag(2) 2,297.33 59.52 215.20 1,890.76 1,84146 -581.84 -755.73 6,031,391.39 543,990.01 0.78 816.10 2_MWD+IFR2+MS+Sag(2) 2,391.12 58.22 216.25 1,939.25 1,889.95 -647.02 -802.60 6,031,325.93 543,943.53 1.69 893.83 2_MWD+IFR2+MS+Sag(2) 2,486.41 60.19 215.14 1,988.03 1,93873 -713.50 -850.35 6,031,259.18 543,896.19 2.30 973.09 2_MWD+IFR2+MS+Sag(2) 2,580.89 59.72 214.25 2,035.34 1,986.04 -780.74 -896.91 6,031,191.66 543,850.05 0.96 1,052.63 2_MWD+IFR2+MS+Sag(2) 2,675.06 58.95 214.15 2,083.36 2,034.06 -847.73 -942.44 6,031,124.40 543,804.92 0.82 1,131.57 2_MWD+IFR2+MS+Sag(2) 2,769.24 57.83 214.41 2,132.73 2,083.43 -914.01 -987.61 6,031,057.87 543,760.16 1.21 1,209.70 2MWD+IFR2+MS+Sag(2) 2,863.56 58.09 216.45 2,182,T 2,133.47 -979.15 -1,033.96 6,030,992.45 543,714.21 1.85 1,287.21 2_MWD+IFR2+MS+Sag(2) 2,956.61 57.27 215.92 2,232.52 2,183.22 -1,042.61 -1,080.38 6,030,928.72 543,668.17 1.00 1,363.18 2_MWD+IFR2+MS+Sag(2) 3,051.72 60.61 216.89 2,281.58 2,232.28 -1,108.17 -1,128.74 6,030,862.88 543,620.21 3.62 1,441.81 2_MWD+IFR2+MS+Sag(2) 3,147.19 60.00 217.48 2,328.88 2,279.58 -1,174.24 -1,178.86 6,030,796.51 543,570.49 0.83 1,521.55 2_MWD+IFR2+MS+Sag(2) 3,24120 59.31 217.68 2,376.37 2,327.07 -1,238.53 -1,228.34 6,030,731.93 543,521.41 0.76 1,599.40 2_MWD+IFR2+MS+Sag(2) 3,335.96 58.49 218.17 2,425.32 2,376.02 -1,302.54 -1,278.21 6,030,667.63 543,471.93 0.97 1,677.12 2_MWD+IFR2+MS+Sag(2) 3,430.25 57.84 218.75 2,475.05 2,425.75 -1,365.27 -1,328.03 6,030,604.61 543,422.49 0.87 1,753.64 2_MWD+IFR2+MS+Sag(2) 3,524.38 58.37 216.48 2,524.79 2,475.49 -1,428.57 -1,376.80 6,030,541.02 543,374.11 2.12 1,830.31 2_MWD+IFR2+MS+Sag(2) 3,619.03 58.04 216.73 2,574.66 2,525.36 -1,493.15 -1,424.77 6,030,476.16 543,326.53 0.41 1,907.88 2_MWD+IFR2+MS+Sag(2) 3,713.56 59.52 216.03 2,623.66 2,574.36 -1,558.23 -1,472.]1 6,030,410.79 543,278.99 1.69 1,985.91 2_MWD+IFR2+MS+Sag(2) 3,807.86 58.64 216.26 2,672.11 2,622.81 -1,623.56 -1,520.43 6,030,345.19 543,231.67 0.96 2,064.09 2_MWD+IFR2+MS+Sag(2) 3,901.91 56.90 216.85 2,722.27 2,672.97 -1,687.47 -1,567.81 6,030,281.00 543,184.68 1.92 2,140.82 2_MWD+IFR2+MS+Sag(2) 3,996.31 57.88 217,56 2,773.14 2,723.84 -1,75080 -1,61589 6,030,217.39 543,136.98 1.22 2,217.27 2_MWD+IFR2+MS+Sag(2) 4,091.08 59.24 215.66 2,822.58 2,773.28 -1,815.70 -1,664.10 6,030,152.20 543,089.17 2.23 2,295.23 2_MWD+IFR2+MS+Sag(2) 4,184.95 58.05 216.01 2,871.42 2,822.12 -1,880.69 -1,711.03 6,030,086.94 543,042.64 1.31 2,372.80 2 MWD+IFR2+MS+Sag(2) 4,279.84 58.28 216.19 2,921.47 2,872.17 -1,945.83 -1,758.53 6,030,021.52 542,995.54 0.29 2,450.72 2_MWD+IFR2+MS+Sag(2) 4,374.12 60.30 214.86 2,969.62 2,920.32 -2,011.80 -1,805.61 6,029,955.28 542,948.85 2.46 2,529.27 2_MWD+IFR2+MS+Sag(2) 4,468.60 60.18 214.94 3,016.52 2,967.22 -2,079.06 -1,852.54 6,029,887.74 542,902.34 0.15 2,608.97 2_MWD+IFR2+MS+Sag (2) 4,563.36 61.70 211.56 3,062.55 3,013.25 -2,148.33 -1,897.93 6,029,818.21 542,857.37 3.51 2,689.97 2_MWD+1FR2+MS+Sag(2) 4,657.26 59.66 206.71 3,108.55 3,059.25 -2,219.79 -1,937.80 6,029,746.52 542,817.93 5.00 2,771.02 2_MWD+IFR2+MS+Sag(2) 4,751.17 58.84 204.25 3,156.57 3,107.27 -2,292.63 -1,972.52 6,029.673.47 542,783.65 2.41 2,851.49 2_MWD+IFR2+MS+Sag(2) 7/26/2018 12:43:17PM Page 3 COMPASS 5000.1 Build 81E Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Coardtnate Reference: Well MPU L-57 Project: Milne Point TVD Reference: MPU L-57 Actual RKB @ 49.30usft Sift: M Pt L Pad MD Reference: MPU L-57 Actual RKS @ 49.30usft Well: MPU L-57 North Reference: True Wellbore: MPU L-57PB7 Survey Calculation Method: Minimum Curvature Design: MPU L-57PB1 Database: Sperry EDM - NORTH US+CANADA Survey 7/2612018 12:43:17PM Page 4 COMPASS 5000.1 Build 81E Map Map Vertical MD Inc Azi TVD TVDSS +NIS +E/ -W Northing Easting DLS Section (usft) V) (') (ustt) (usft) (usft) (usft) (ft) (ft) (°/1001 (ft) Survey Tool Name 4,845.77 59.71 203.40 3,204.91 3,15561 -2,357.02 -2,005.37 6,029,598.89 542,751.26 1.20 2,932.73 2_MWO+IFR2+MS+Sag(2) 4,939.83 59.43 204.09 3,252.55 3,203.25 -2,441.26 -2,038.03 6,029,524.47 542,719.05 0.70 3,013.75 2 MWD+IFR2+MS+Sag(2) 5,033.41 59.35 204.56 3,300.20 3.250.90 -2,514.65 -2,071.20 6,029,450.88 542,686.32 0.44 3,094.18 2_MWD+IFR2+MS+Sag(2) 5,127.74 59.91 204.63 3,347.89 3,298.59 -2,588.65 -2,105.07 6,029,376.69 542,652.90 0.60 3,175.42 2_MWD+IFR2+MS+Sag(2) 5,222.40 59.24 206.09 3,395.83 3,346.53 -2,662.41 -2,140.03 6,029,302.73 542,618.39 1.51 3,256.83 2_MWD+IFR2+MS+Sag(2) 5,316.97 59.48 206.67 3,444.02 3,394.72 -2,735.30 -2,176.18 6,029,229.63 542,582.68 0.59 3,337.87 2_MWD+IFR2+MS+Sag(2) 5,411.84 59.88 207.05 3,491.92 3,44262 -2,808.36 -2,213.18 6,029,156.35 542,546.13 0.55 3,419.37 2 MWD+IFR2+MS+Sag(2) 5,505.70 59.14 207.49 3,539.54 3,490.24 -2,880.25 -2,250.24 6,029,084.25 542,509.51 0.89 3,499.80 2_MWD+IFR2+MS+Sag(2) 5,600.17 60.07 207.70 3,587.34 3,538.04 -2,952.47 -2,287.99 6,029,011.81 542,472.20 1.00 3,580.79 2_MWD+IFR2+MS+Sag(2) 5,694.17 59.64 207.36 3,634.54 3,585.24 ],024.55 -2,325.56 6,028,939.51 542,435.07 0.55 3,661.59 2_MWD+IFR2+MS+Sag (2) 5,788.53 58.41 205.69 3,683.11 3,633.81 43,096.93 -2,361.69 6,028,866.93 542,399.37 2.00 3,742.14 2_MWD+IFR2+MS+Sag(2) 5,883.40 57.54 205.95 3,733.42 3,684.12 -3,169.33 -2,396.72 6,028,794.32 542,364.78 0.95 3,822.31 2 MWD+IFR2+MS+Sag(2) 5,977.64 60.58 206.76 3,781.86 3,732.56 -3,241.74 -2,432.61 6,028,721.70 542,329.33 3.31 3,902.81 2_MWD+IFR2+MS+Sag(2) 6,072.27 65.93 205.20 3,824.44 3.775.14 -3,31169 -2,469.59 6,028,645.54 542,292.82 5-84 3,987.00 2_MWD+IFR2+MS+Sag(2) 6,166.01 69.55 204.86 3,859.93 3,810.63 -3,396.29 -2,506.29 6,028,566.73 542,256.60 3.89 4,073.55 2_MWD+IFR2+MS+Sag(2) 6,261.00 73.19 201.35 3,890.27 3,840.97 -3,479.07 -2,541.57 6,028,483.75 542,221.81 5.18 4,163.49 2_MWD+1FR2+MS+Sag(2) 6,355.24 77.44 198.51 3,914.16 3,864.86 -3,564.75 -2,572.61 6,028,397.89 542,191.29 5.37 4,254.59 2_MWD+IFR2+MS+Sag(2) 6,449.87 80.58 197.79 3,932.20 3,882.90 -3,653.01 -2,601.54 6,028,309.47 542,162.89 3.40 4,347.34 2_MWD+IFR2+MS+Sag(2) 6,544.36 86.42 198.99 3,942.89 3,893.58 -3,742.05 -2,631.16 6,028,220.25 542,133.82 6.31 4,441.06 2_MWD+IFR2+MS+Sag(2) 6,638.53 92.78 197.07 3,943.55 3,89425 -3,831.55 -2,660.28 6,028,130.59 542,105.24 7.05 4,535.03 2_MWD+IFR2+MS+Sag(2) 6,687.60 93.61 197.29 3,940.82 3,891.52 -3,878.35 -2,674.76 6,028,083.70 542,091.05 1.75 4,583.90 2_IWiD+IFR2+MS+Sag (2) 6,739.75 93.32 197.01 3,937.66 3,888.36 -3,928.09 -2,690.11 6,028,033.88 542,076.00 0.77 4,635.82 2_MWD+IFR2+MS+Sag(3) 6,834.78 91.70 197.38 3,933.50 3,884.20 -0,016.79 -2,718.17 6,027,943.03 542,048.48 1.75 4,730.52 2_MWD+IFR2+MS+Sag(3) 6,926.87 90.59 198.38 3,931.62 3,882.32 4,108.31 -2,747.05 6,027,853.34 542,020.14 1.59 4,824.43 2_MWD+IFR2+MS+Sag(3) 7,023.31 92.02 198.55 3,929.47 3,880.17 4,197.86 -2,776.96 6,027,76362 541,990.78 1.52 4,918.73 2_MWD+IFR2+MS+Sag(3) 7,118.17 92.32 198.02 3,925.88 3,876.58 4,287.87 -2,806]0 6,027,673.44 541,961.59 0.64 5,013.40 2_MWD+IFR2+MS+Sag(3) 7,213.36 92.51 196.26 3,921.87 3,872.57 4,378.75 -2,834.72 6,027,582.41 541,934.11 1.86 5,108.25 2_MWD+IFR2+MS+Sag(3) 7,308.00 92.20 194.32 3,917.98 3,868.68 4,469.96 -2,859.66 6,027,491.06 641,909.73 2.07 5,202.30 2_MWD+IFR2+MS+Ssg(3) 7,400.35 94.00 194.75 3,912.98 3,863.68 4,559.22 -2,882.80 6,027,401.67 541,887.13 2.00 5,293.68 2_MW0+IFR2+MS+Sag(3) 7,494.95 91.76 194.34 3,908.23 3,858.93 4,650.66 -2,906.53 6,027,310.09 541,863.95 2.41 5,387.71 2_MWD+IFR2+MS+Sag(3) 7,591.18 91.33 196.71 3,905.64 3,856.34 4,743.34 -2,932.27 6,027,217.27 541,838.77 2.50 5,483.42 2_MWD+IFR2+MS+Sag(3) 7,683.13 91.40 195.47 3,903.45 3.854.15 4,831.66 -2,957.75 6,027,128.80 541,813.83 1.35 5,574.97 2_MWD+IFR2+MS+Sag(3) 7,777.48 91.64 196.40 3,900.94 3,851.64 4,922.35 -2,983.64 6,027,037.97 541,788.48 1.02 5,668.88 2_MWD+IFR2+MS+Sag(3) 7,872.04 92.07 195.73 3,897.88 3,84858 -5,013.17 -3,009.79 6,026,947.00 541,762.88 0.84 5,763.01 2_MWD+IFR2+MS+Sag(3) 7,964.65 92.82 195.64 3,893.93 3,844.63 -5,102.25 -3,034.81 6,026,857]8 541,738.40 0.82 5,855.10 2_MWD+IFR2+MS+Sag(3) 8,060.46 92.69 196.05 3,889.33 3,840.03 -5,194.32 3,060.94 6,026,765.57 541,712.83 0.45 5,950.37 2_MWD+IFR2+MS+Sag(3) 8,155.09 91.58 194.59 3,88580 3,836.50 -5,285.52 -3,085.92 6,026,674.23 541,688.40 1.94 6,044.43 2_MWD+IFR2+MS+Sag(3) 8,249.52 90.90 194.05 3,883.76 3,834.46 -5,376.99 -3,109.27 6,026,582.63 541,66560 0.92 6,138.15 2_MWD+IFR2+MS+Sag(3) 8,34385 90.34 192.76 3,882.74 3,833.44 -5,468.74 -3,131.14 6,026,490.75 541,644.29 1.49 6,231.59 2_MWD+IFR2+MS+Sag(3) 8,438.25 92.27 192.14 3,880.59 3,831.29 -5,560.89 -3,151.48 6,026,398.49 541,624.50 2.15 6,324.85 2_MWD+IFR2+MS+Sag(3) 7/2612018 12:43:17PM Page 4 COMPASS 5000.1 Build 81E Halliburton Definitive Survey Report Company: Project: Site: Well: Wellbore: Design: Hilcorp Alaska, LLC Milne Point M Pt L Pad MPU L-57 MPU L-57PB7 MPU L-57PB1 Local Coordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Database: Well MPU L-57 MPU L57 Actual RKB @ 49.30usft MPU L-57 Actual RKB @ 49.30usft True Minimum Curvature Sperry EDM - NORTH US +CANADA Survey Map Map Vertical MD Inc Azi TVD NDSS +NIS +El -W Northing Easting DLS Section (usft) V) (°) (usft) (usft) (usft) (usft) (ft) (fl) (°/100') (ft) Survey Tool Name 8,531.25 93.00 193.26 3,876.31 3,827.01 -5,651.52 -3,171.91 6,026,307.75 541,604.63 1.44 6,416.72 2_MWD+IFR2+MS+Sag(3) 8,627.29 92.20 192.95 3,871.96 3,822.66 -5,744.96 -3,193+66 6,026,214.19 541,583.44 0.89 6,511.70 2_MWD+IFR2+MS+Sag(3) 8,719.13 92.01 192.87 3,868.58 3,819.28 -5,834.42 -3,214.17 6,026,124.62 541,563.48 0.22 6,602.51 2_MWD+IFR2+MS+Sag(3) 8,815.71 9208 192.77 3,865.14 3,815.84 -5,92853 -3,235.58 6,026,030.39 541,542.63 0.13 6,697.98 2_MWD+IFR2+MS+Sag(3) 8,909.73 92.45 191.14 3,861.42 3,812.12 4i,020.44 -3,255.04 6,025,938.38 541,523.72 1.78 6,790.70 2_MWD+IFR2+MS+Sag(3) 9,003.63 91.39 190.51 3,858.27 3,808.97 -6,112.61 3,27267 6,025,846.11 541,50666 1.31 6,88300 2_MWD+IFR2+MS+Sag(3) 9,096.65 91.62 190.64 3,855.83 3,806.53 -6,204.02 3,289.73 6,025,754.61 541,490.14 0.28 6,974.38 2_MWD+IFR2+MS+Sag(3) 9,190.04 92.20 191.34 3,852.72 3,803.42 -6,295.65 -3,307.53 6,025,682.88 541,472.90 0.97 7,066.23 2_MWD+IFR2+MS+Sag(3) 9,286.79 93.19 192.92 3,848.17 3,798.87 -6,390.13 -3,327.83 6,025,568.29 541,453.17 1.93 7,161.65 2_MWD+IFR2+MS+Sag(3) 9,381.50 92.32 191.80 3,843.62 3,794.32 -6,482.53 -3,348.08 6,025,475.77 541,433.48 1.50 7,255.11 2_MWD+IFR2+MS+Sag(3) 9,475.82 91.44 188.67 3,840.52 3,791.22 -6,575.29 -3,364.83 6,025,382.93 541,417.29 3.45 7,347.63 2_MWD+IFR2+MS+Sag(3) 9,570.17 92.01 186.37 3,837.68 3,788.38 -6,668.78 -3,377.17 6,025,289.37 541,405.51 2.51 7,439.24 2_MWD+IFR2+MS+Sag(3) 9,664.92 91.39 186.21 3,834.87 3,785.57 -6,762.92 -3,387.55 6,025,195.19 541,395.70 0.68 7,530.74 2_MWD+IFR2+MS+Sag(3) 9,759.79 92.21 185.34 3,831.89 3.782.59 -6,857.26 ],397.09 6,025,100.80 541,386.73 1.26 7,622.13 2_MWD+IFR2+MS+Sag(3) 9,854.47 92.20 18623 3,828.25 3,778.95 -6,951.38 3,406.62 6,025,006.63 541,377.76 0.94 7,713.32 2_MWD+IFR2+MS+Sag(3) 9,948.91 92.01 187.94 3,824.78 3,775.48 -7,045.04 -3,418.26 6,024,912.91 541,366.69 1.82 7,804.83 2_MWD+IFR2+MS+Ssg(3) 10,042.51 89.73 186.17 3,823.36 3,774.06 -7,137.91 3,429.76 6,024,819.98 541,355.76 3.08 7,895.55 2_MWD+IFR2+MS+Sag(3) 10,136.78 90.22 184.91 3,823.40 3,774.10 -7,23134 -3,43886 6,024,726.11 541,347.22 1.43 7,986.30 2_MWD+IFR2+MS+Sag(3) 10,231.91 91.41 185.16 3,822.04 3,772.74 -7,326.49 -3,447.21 6,024,631.32 541,339.44 1.28 8,077.64 2_MWD+IFR2+MS+Sag(3) 10,325.36 91.50 185.57 3,819.67 3.770.37 -7,419.50 -3,455.94 6,024,538.27 541,331.27 0.45 8.167.50 2_MWD+IFR2+MS+Sag(3) 10,419.95 91.33 184.66 3,817.34 3,76804 -7,513.68 -3,464.37 6,024,444.05 541,323.41 0.98 8,258.34 2_MWD+IFR2+MS+Sag(3) 10,514.72 91.72 184.88 3,814.81 3,765.51 -7,608.09 -3,472.25 6,024,349.60 541,316.10 0.47 8,349.19 2_MWD+IFR2+MS+Sag(3) 10,609.11 93.08 185.76 3,810.86 3,761.56 -7,701.99 -3,480.99 6.024.255.66 541,307.92 1.72 8,439.88 2_MWD+IFR2+MS+Sag(3) 10,702.47 91.74 185.97 3,806.94 3,757.64 -7,794.77 3,490.52 6,024,162.83 541,296.95 1.45 8,529.81 2_MWD+IFR2+MS+Sag(3) 10,797.33 92.51 188.25 3,803.42 3,754.12 -7,888.83 -3,502.25 6,024,068.71 541,287.79 2.54 8,621.73 2_MWD+IFR2+MS+Sag(3) 10,892.21 9201 190.16 3,799.68 3,750.38 -7,982.41 3,517.42 6,023,975.05 541,273.19 2.08 8,714.45 2_MWD+IFR2+MS+Sag(3) 10,966.55 91.48 192.22 3,796.80 3,747.50 -8,074.91 3,535.72 6,023,882.45 541,255.45 2.25 8,807.30 2_MWD+IFR2+MS+Sag(3) 11,081.15 91.83 192.14 3,794.07 3,744]7 -8,16TM -3,555.67 6,023,789.91 541,236.05 0.38 8,900.68 2_MWD+IFR2+MS+Sag(31 11,175.58 89.65 190.67 3,792.85 3,743.55 -8,259.89 3,574.34 6,023,697.26 541,217.94 2.78 8,993.70 2_MWD+IF112+MS+Sag(3) 11,269.70 90.28 190.77 3,792.91 3,743.61 41,352.37 -3,591.85 6,023,604.69 541,200.99 0.68 9,086.24 2_MWD+IFR2+MS+Sag(3) 11,363.17 92.52 193.30 3,790.62 3,74132 -8,443.74 -3,611.33 6,023,513.21 541,182.07 3.61 9,178.47 2_MWD+IFR2+MS+Sag(3) 11,458.26 92.51 193.70 3,786.45 3,737.15 -8,536.12 -3,633.50 6,023,420.71 541,160.45 0.42 9,272.60 2_MWD+IFR2+MS+Sag(3) 11,552.69 91.99 193.04 3,782.74 3,733.44 0,627.92 -3,655+32 6,023,328.79 541,139.19 0.89 9,366.07 2_MWD+IFR2+MS+Sag(3) 11,647.51 92.88 191.97 3,778.72 3,729.42 -8,720.40 3,675.83 6,023,236.19 541,119.23 1.47 9,459.70 2_MWD+IFR2+MS+Sag(3) 11,741.56 93.99 193.21 3,773.08 3,723.78 -8,812.02 -3,696.30 6,023,144.46 541,099.32 1.77 9,552.51 2_MWD+IFR2+MS+Sag(3) 11,835.97 92.33 192.57 3,767.88 3,718.58 -8,903.91 3,717.32 6,023,052.46 541,078.85 1.88 9,645.77 2_MWD+IFR2+MS+Sag(3) 11,928.89 93.19 192.17 3,763.40 3,714.10 -8,994.57 3,737.21 6,022,961.69 541,059.52 1.02 9,737.47 2_MWD+IFR2+MS+Sag(3) 12,023.91 91.89 19236 3,759.19 3,109.89 -9,087.32 3,757.37 6,022,868.82 541,039.91 1.38 9,831.24 2_MWD+IF112+MS+Sagl3) 12,117.78 91.35 191.97 3,756.54 3,707.24 -9,179.05 -3,777.14 6,022,776.99 541,020.69 0.71 9,923.89 2 MWD+IFR2+MS+Sag(3) 12,212.31 91.74 193.30 3,753.99 3,704.69 -9,271.25 -3,797.81 6,022,684.67 541,000.58 1.47 10,017.32 2_MWD+IFR2+MS+Sag(3) 72612018 12:43:17PM Page 5 COMPASS 5000.1 Build B1E Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt L Pad Well: MPU L-57 Wellbore: MPU L-57PB1 Design: MPU L-57PB1 Halliburton Definitive Survey Report Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Database: Well MPU L-57 MPU L-57 Actual RKB @ 49.30usft MPU L-57 Actual RKB @ 49.30usft True Minimum Curvature Speny EDM - NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +NIS +E/ -W Northing Easting OILS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/tool (ft) Survey Tool Name 12,307.33 92.68 194.14 3,750.32 3,701.02 -9,363.49 -3,820.33 6,022,592.31 540,978.62 1.33 10,111.45 2_MWD+IFR2+MS+Sag(3) 12,400.55 92.26 195.10 3,746.31 3,697.01 -9,453.61 x,843.84 6,022,502.06 540,955.66 1.12 10,203.96 2_MWD+IFR2+MS+Sag(3) 12,495.10 91.70 193.89 3,743.04 3,693.74 -9,545.09 x,867.49 6,022,410.44 540,932.56 1.41 10,297.80 2_MWD+IFR2+MS+Sag(3) 12,589.77 91.27 194.45 3,740.59 3,69129 -9,636.85 -3,890.66 6,022,318.56 540,909.95 0.75 10,391.72 2_MWD+IFR2+MS+Sag(3) 12,684.45 90.08 193.16 3,739.47 3,690.17 -9,728.79 -3,913.25 6,022,226.50 540,887.92 1.85 10,495.59 2_MWD+IFR2+MS+Sag(3) 12,778.85 91.28 193.45 3,738.35 3,689.05 -9,820.64 -3,934.97 6,022,134.52 540,866.75 1.31 10,579.08 2_MWD+IFR2+MS+Sag(3) 12,873.23 93.26 193.89 3,734.61 3,685.31 -9,912.27 -3,957.26 6,022,042.76 540,845.02 2.15 10,672.66 2_MWD+IFR2+10S+Sag(3) 12,967.49 92.19 193.27 3,730.13 3,680.83 -10,003.79 -3,979.36 6,021,951.12 540,823.46 1.31 10,765.87 2_MWD+IFR2+MS+Sag(3) 13,061.40 93.73 193.64 3,725.28 3,675.98 -10,095.00 4001.18 6,021,859.79 540,802.19 1.69 10,858.79 2_MWD+IFR2+MS+Sag(3) 13,154.01 94.06 192.29 3,718.99 3,669.69 -10,185.04 4.021.91 6,021,769.64 540,782.01 1.50 10,950.22 2_MWD+IFR2+MS+Sag(3) 13,186.00 94.06 192.29 3,716.73 3,667.43 -10,216.22 4,028.71 6,021,738.43 540,775.40 0.00 10,981.74 PROJECTEDto TD Checked By: Michael Calkins Approved Approved By: Mitch Laird - Date: 7/26/201 S 7/262018 12:43:17PM Page 6 COMPASS 5000.1 Build 81E N Nf/cory Energy Company CASING & CEMENTING REPORT Lease 8 Well No. Shoe @ 6714.95 MP L-57 Date Run 11,1ull County Prpdhoe Bay Slate ataska Su'. Yessak/ Demoski Jt, Component CASING RECORD M. Grade THD sadare �, Length TO 6,725.00 Shoe Depth: 6,71495 PBTD: 103/4 No. Jts. Delivered No. Jts. Run No. Jts. Resurrect Antelope Fig. Delivered Fig. Run Fig. Returned Lenge Measnemmn WAD Threads Ftg. Cut Jt Fig. Balance 40.0 RKB 3570 RKB WBHF RKBto CHF RKB WTHF Ceg M. On Hook: 115,000 Type Float Collar. Antelope No. H. to Run: 23.5 Call, W. On Slips: 75,000 Type of Sha.: gntalope Casing Crev: Weathertad Rotate Csg Yes X No Recip Csg _Yes X No Ft Min. 9.2 PPG Fluid Description: Spud Liner hanger Into(MakelModel): Liner hanger test pressure: Centralizer Placement: CEMENTING REPORT Unertop Pacal Yes No Floats Held X Yes No Shoe @ 6714.95 FC @ 6,uaiSS Casing (Or liter) Detail Selling Depths Jt, Component Size M. Grade THD Make Length Bottom Top 1 Shoe 103/4 50.0 Type: Type 1111 Lead Cement UP BTC Antelope 1.60 6,714.95 6,713.35 2 Casin 95/8 40.0 L-80 UP BTC Tubular Sol. 83.51 6,713.35 6,629.84 1 Float Collar 103/4 50.0 Density(ppg) ISO UP BTC Antelope 1.31 6,629.84 6,628.53 1 Casing 95/8 40.0 L-80 UP BTC Tubular5ol. 41.75 6,628.53 6,586.78 1 Baffle Adapter 103/4 50.0 Type: Spat MW Density (ring) UP BTC HES 1.48 6,586.78 6,585.30 102 Casing 95/8 40.0 L-80 UP BTC Tubular Sol. 4,112.13 6,585.30 2,473.17 1 Pup Joint 95/8 40.0 L-80 UP BTC Tubular $ol. 13.93 2,473.17 2,459.24 1 ESIPC 103/4 Type ESIPC Closure OK Yes Up BTC HES 11.87 2,459.24 2,447.37 1 Pup Joint 95/8 40.0 L-80 UP BTC Tubular Sol. 13.05 2,447.37 2,434.32 59 Casin 95/8 40.0 L-80 UP BTC Tubular Sol. 2,366.62 2,434.32 67.70 1 Casin XOJ.mt 95/8 40.0 L -BO DWUC Tubular Sol. 28.82 67.70 38.88 1 Pup loin[ 95/8 40.0 L-80 DWUC Tubular Sol. 2.15 36.88 36.73 1 Mandrel Hanger 95/8 Rate (bpm): Volume: Displacement: 0.98 36.73 35.75 RKB 9.2 Rate IbW): 5 Volume (actual / calculated): 184.4/186.1 FCP (psi): 880 Pump used for disp: Rig 35.75 35.75 Casing Roteted? Yes Ceg M. On Hook: 115,000 Type Float Collar. Antelope No. H. to Run: 23.5 Call, W. On Slips: 75,000 Type of Sha.: gntalope Casing Crev: Weathertad Rotate Csg Yes X No Recip Csg _Yes X No Ft Min. 9.2 PPG Fluid Description: Spud Liner hanger Into(MakelModel): Liner hanger test pressure: Centralizer Placement: CEMENTING REPORT Unertop Pacal Yes No Floats Held X Yes No Calculated Clint Vol @ 0%excess'. Cmt returned to surface', left in vrellbore: Shoe @ 6714.95 FC @ 6,uaiSS Top of Liner PreRush(Spacer) Type: Dean Spacer Density (on) 10 Volume pumped( BBB) 55 Lead Slurry Type: Type 1111 Lead Cement Seeks: 562 Yield: 239 Density (PPO) 12 Volume Pumped (BBLs) 240 Miring I Pumping Rate (bpm): 47 Tail Slurry a Type: Premium G Tail Cement Sacks: 400 Yield: 1.16 is Density(ppg) ISO Volume pumped(BBLs) 82 Mixirg/Pumping Rate(bpm): 4 Post Flush (Spacer) is as LL Type: Density(IPPS) Rate (bpm): Volume: Displacement: Type: Spat MW Density (ring) 925 Rate(bpm): 5 Volume (actual /calculated): 4]6.6/4]9.6 FCP(psit 890 Pump used for disp Rig Bump Plug? X Yes No Bump press 890 Casing Rotated? Yes X No Reciprocated? Yes X No % Returns during job 88 Cement returns to surface? X Yes No Spacer reluma? X Yes _ No Vol to Surf: 56 Cement In Face At 223 Date: 7/1V 018 Estimated TOC: 2,447 Method Used To Determine TOC: Stage Collan6urface Rehans Stage Collar@ 24237 Type ESIPC Closure OK Yes Preflush (Spacer) Type: Clean Spacer Density(ppg) 10 Volume Pumped (BB") 54 Lead Slurry Type: Permafrost L Cement Sacks: 378 Yield : 4.33 Density(ppg) 107 Volume purrped(Bi 292 Mixing/ Pumping Rate(bpm): 5 Tall Slurry Type: Premium G Cement Sacks: 270 Yield : 1.17 Density (PIPS) 15.8 Volume pumped (BBLs) 55.8 Mixing / Pumping Rate (bpm): 4.5 c Post Flush (Spacer) Type: Densiry (IPPS) Rate (bpm): Volume: Displacement: Type: Spud Mud Density (IPPS) 9.2 Rate IbW): 5 Volume (actual / calculated): 184.4/186.1 FCP (psi): 880 Pump used for disp: Rig Bump Plug? X Yes No Bump press 1450 Casing Roteted? Yes X No Remprocated? _Yes X No % Returns during job 10D Cement relam s to surface? X Yes _No Spacer returns? X Yes No Vol W Surf: 250 Cement In Place At 1305 Data 7/13/2018 Esgmated TOC: 0 Method Used! To Determine TOC: Cement to Surface Calculated Clint Vol @ 0%excess'. Cmt returned to surface', left in vrellbore: DATE: 7/27/2018 Debra Oudean Hilcorp Alaska, LLC AK_GeoTech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: doudean@hilcorp.com To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMITTA CD: Final Well Data Log Viewers 7/26/2018 7:13 PM File folder CGM 7/26/2018 7:13 PM File folder Definitive Survey 7/26/2018 7:13 PM File folder EMF 7/26/20187:13 PM File folder LAS 7/26/2018 7:13 PM File folder PDF 7/26/20187:13 PM File folder TIFF 7/2680187:13 PM File folder Please include current contact information if different from above. 21 8072 29555 IT (im wn bore RECEIVED JUL 30 2018 A®GCC Please acknowledgekoc*ipt by signing arW_yef6r_Ng one copy of this transmittal or FAX to 907 777.8510 Receivedayz--i� l//l/l/C\ / ` I Date: DATE: 7/27/2018 Debra Oudean Hilcorp Alaska, LLC AK_GeoTech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: doudean@hilcorp.com To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Ste 100 Anchorage, AK 99501 D. , CD: Final Well Data Log viewers 7/26/20137:13 PM FAe fo'der 1 eGM 7,126,12018 7,13 PO1. --de fo'der i Definitive Survey 7,26,20187:13 PM Tdefc'der I EMF 7126/20187:13 P;J P:e folder LAS 7/26,20187'.13, P61 :f:e Vdes PDF 7/26/201"0713 PM hiefo:der WF _J" 20187'.13=b; ,,l fn:e- Please include current contact information if different from above. 218072 29556 T _PIc5 fuck RECEIVED JUL 3 0 2018 A®GCC Please acknowledge f0c*ipt`by signing arid_r<5@r pg one copy of this transmittal or FAX to 907 777.8510 Received ey/-7� // // / " I Date: THE STATE °fALASKA GOVERNOR BILL WALKER Monty Myers Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.00gcc.olaska.gov Re: Milne Point Field, Schrader Bluff Oil Pool, MPU L-57 Hilcorp Alaska, LLC Permit to Drill Number: 218-072 Surface Location: 3789' FSL, 5134' FEL, SEC. 8, T13N, R10E, UM, AK Bottomhole Location: 1509' FML, 1216' FWL, SEC. 19, 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. Hollis S. French Chair �?X DATED this—day of July, 2018. STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 RECEIVED JUN 18 2018 1a. Type of Work: 1 b. Proposed Well Class: Exploratory - Gas Service - WAG Ll Service - Disp ❑ 1c. Specify if well is proposed for: Drill 0 • Lateral ❑ Stratigraphic Test ❑ Development - Oil Q • Service - Winj ❑ Single Zone ❑ Co a r� s Hydrates L]Redrill ❑ Reentry ❑ Exploratory - Oil F-1Development- Gas ❑ Service - Supply El Multiple Zone El Ge h jf�l a Gas ❑ 2. Operator Name: 5. Bond: Blanket Q • Single Well ❑ 11. Well Name and Number: Hilcorp Alaska, LLC Bond No. 022035244 • MPU L-57 ' 3. Address: 6. Proposed Depth: 12. Field/Pool(s): 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 MD: 13,549' TVD: 3,724' Milne Point Field Schrader Bluff Oil Pool ' 4a. Location of Well (Governmental Section): 7. Property Designation: Surface: 3789' FSL, 5134' FEL, Sec 8, T13N, R10E, UM, AK ADL025509, ADL025515 "NB" Sand Top of Productive Horizon: 8. DNR Approval Number: 13. Approximate Spud Date: 202' FNL, 2579' FEL, Sec 18, T13N, R10E, UM, AK LONS-88-002 7/9/2018 9. Acres in Property: 14. Distance to Nearest Property: Total Depth: 1509' FNL, 1216' FWL, Sec 19, T13N, R10E, UM, AK 5077 Acres 7,894' to nearest unit boundary 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 49 15. Distance to Nearest Well Open Surface: x- 544742 • y- 6031977 . Zone -4 GL / BF Elevation above MSL (ft): 15.3 to Same Pool: 570' to MPL-52 16. Deviated wells: Kickoff depth: 425 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 93 degrees Downhole: 1756 . Surface: 1380 , 18. Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks Hole Casing Weight Grade Coupling Length MD TVD MD TVD (including stage data) 36" 16" 164# A -53B Weld 80' Surface Surface 114' 114' —270 ft3 Stg 1 L - 1324 ft3 / T - 459 43 12-1/4" 9-5/8" 40# L-80 TXP 6,761' Surface Surface 6,761' 3,945' Stg 2 L - 1861 ft3 / T -314 ft3 N/A 7-5/8" 29.7# L-80 VAM/H521 6,616' Surface Surface 6,616' 3,932' Tieback Assy. 8-1/2" 4-1/2" 13.5# L-80 Hyd 625 6,938' 6,611' 3,932' 13,549' 3,724' Cementless Screens Liner 19. PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re -Entry Operations) Total Depth MD (ft): Total Depth TVD (ft): Plugs (measured): Effect. Depth MD (ft): Effect. Depth TVD (ft): Junk (measured): Casing Length Size Cement Volume MD TVD Conductor/Structural Surface Intermediate Production Liner Perforation Depth MD (ft):Perforation Depth TVD (ft): Hydraulic Fracture planned? Yes ❑ No 0 ' 20. Attachments: Property Plat O BOP Sketch v Drilling Program Time v. Depth Plot v Shallow Hazard Analysis Diverter Sketch B Seabed Report e Drilling Fluid Program e✓ 20 AAC 25.050 requirements e 21. Verbal Approval: Commission Representative: Date 22. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Name: Joe Engel Authorized Name: Monty Myers Contact Email: 'en el hilCof .Com Authorized Title: Drilling Manager Contact Phone: 777-8395 C__ Fo2 0AorJTY fl -It' Authorized Signature: Date: Commission Use Only Permit to Drill API Number: ,•q ,. ,I Permit �j' Approval See cover letter for other Number: L ! 0� (UCS [ l--L.��-.� Date: requirements. Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed metha a gas hydrates, or gas contained mshales: ff Other. 3 OD D $ L �% �-' Samples req'd: Yes ❑ No Mud log req'd: Yes []/No Uv H25 measures: Yes gNo,❑/ Directional svy req'd: Yes No❑ g/ � L.e� L /k,, .Ja Spacing exception req'd: Yes Ll No LI Inclination -only svy req'd: Yes ❑ No �� Post initial injection MIT req'd: Yes ❑ No ❑ i 1 APPROVED BY qI(-Ite) Approved by: COMMISSIONER THE COMMISSION to (C is p •fig pP P ( ) 1 K. o C1� ` L Form 10-401 Revises 5/eon This ermtt is valid for 24 months from the date of a royal er 20 AAC 25. 05 A a e n u Ik U Hilcorp a,y cmw y 6.18.2018 Commissioner Alaska Oil & Gas Conservation Commission 333 W. 7'h Avenue Anchorage, Alaska 99501 Re: Application for Permit to Drill MPU L-57 Dear Commissioner, Joe Engel Hilcorp Alaska, LLC Drilling Engineer P.O. Box 244027 Anchorage, AK 99524-4027 Tel 907 777 8395 Email: jengel@hilcorp.com Hilcorp Alaska, LLC hereby submits for review and approval for a Permit to Drill an onshore production well at Milne Point'L' Pad, well slot 57. Drilling operations are intended to commence approximately July 9th, 2018, pending rig schedule. MPU L-57 is a grassroots ESP producer planned to be drilled in the Schrader Bluff NB sand. L-57 is part of a six well program targeting the NB sand. The directional plan is a catenary wellpath build, 12.25" hole with 9-5/8" surface casing set into the top of the Schrader Bluff NB sand. An 8.5" lateral section will then be drilled. A 4.5" screen liner will be run in the open hole section and the well will be produced with an ESP assembly. Regarding the planned ESP completion, Hilcorp Alaska respectfully asks for a variance to CO 390A -4— Rule 3 requiring an ESP packer if the BHP gradient is greater than 8.55 ppg. The estimated reservoir pressure is 8.65 ppg EMW (1756 psi) at 3,903' TVDss, 20 psi above 8.55 ppg EMW (1736psi). Hilcorp calculates that the near wellbore bottom hole pressure will be below the 8.55 ppg gradient within one week of putting the well on production as calculated byp CMG reservoir model. Rnk The Doyon 14 will be used to drill and complete the wellbore. jz"4– 41 Please find attached the Form 10-401, Application For Permit to Drill per 20 AAC 25.005 (a) and the drilling program for MPU L-57, which includes information required by 20 AAC 25.005 (c). If you have any questions, or require further information, please do not hesitate to contact myself (Joe Engel) at 777-8395 or jengel@hilcorp.com or Monty Myers at 777-8431 or mmyers@hilcorp.com. Sincerely, J e ngel DO Ing Engineer Hilcorp Alaska, LLC Page 1 of 1 Hilcorp Alaska, LLC Milne Point Unit (MPU) L-57 Drilling Program Version 1 6.18.2018 n Hilcorp Ene Company Contents Milne Point L-57 SB NB Producer Drilling Procedure 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 R/U and Preparatory Work..........................................................................................................10 10.0 NIU 21-1/4" 2M Diverter Configuration.....................................................................................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.....................................................................................................21 14.0 BOPE N/U, Test and Wellhead Installation................................................................................26 15.0 Drill 8-1/2" Hole Section...............................................................................................................27 16.0 Run 4-1/2" Production Screen Liner (Lower Completion).......................................................31 17.0 Run 7-5/8" Tieback.......................................................................................................................37 18.0 Run ESP Assembly -Upper Completion....................................................................................41 19.0 RDMO............................................................................................................................................42 20.0 Doyon 14 Diverter Schematic.......................................................................................................43 21.0 Doyon 14 BOP Schematic.............................................................................................................44 22.0 Wellhead Schematic......................................................................................................................45 23.0 Days Vs Depth................................................................................................................................46 24.0 Formation Tops & Information...................................................................................................47 25.0 Anticipated Drilling Hazards.......................................................................................................48 26.0 Doyon 14 Layout............................................................................................................................50 27.0 FIT Procedure................................................................................................................................51 28.0 Doyon 14 Choke Manifold Schematic..........................................................................................52 29.0 Casing Design.................................................................................................................................53 30.0 8-1/2" Hole Section MASP............................................................................................................54 31.0 Spider Plot (NAD 27) (Governmental Sections).........................................................................55 32.0 Surface Plat (As Built) (NAD 27).................................................................................................56 33.0 Schrader Bluff NB Sand Offset MW vs MD Chart ....................................................................57 34.0 Drill Pipe Information 5" 19.5# 5-135 DS -50 & NC50...............................................................58 H Hilcorp E� C—Pw> 1.0 Well Summary Milne Point Unit L-57 SB NB Producer Drilling Procedure Well MPU L-57 Pad Milne Point "L" Pad Planned Completion Type ESP on 2-7/8" Production Tubing Target Reservoir(s) Schrader Bluff NB Sand Wellplan Version W 09 Planned Well TD, MD / TVD 13,549' MD / 3,724' TVD PBTD, MD / TVD 13,544' MD / 3,724' TVD Surface Location (Governmental) 3789' FSL, 5134' FEL, Sec 8, T13N, R10E, UM, AK - Surface Location (NAD 27) X= 544,742.15, Y= 6,031,977.71 - Top of Productive Horizon (Governmental) 202' FNL, 2579' FEL, Sec 18, T13N, R10E, UM, AK TPH Location (NAD 27) X= 542,055.5 1, Y= 6,027,970.89 BHL (Governmental) 1509' FNL, 1216' FWL, Sec 19, T13N, R10E, UM, AK BHL AD 27) X= 540,695, Y=6,021,377 AFE Number 1713441 AFE Drilling Das 17 days AFE Completion Das 8 days AFE Drilling Amount $3,799,349 AFE Completion Amount $2,435968 AFE Facility Amount $391,000 Maximum Anticipated Pressure (Surface) 1380 psig Maximum Anticipated Pressure Downhole/Reservoir 1756 psig Work String 5" 19.5# S-135 DS -50 & NC 50 (Weatherford Rental KB Elevation above MSL: 33.7 ft + 15.3 ft = 49.0 ft - GL Elevation above MSL: 15.3 ft BOP Equipment 13-5/8" x 5M Annular, (3) ea 13-5/8" x 5M Rams Page 2 Rev 0 May 2018 Milne Point Unit L-57 SB NB Producer Drilling Procedure 2.0 Management of Change Information H Hilcorp Alaska, LLCi1co? Changes to Approved Permit to Drill Date: 6/1412018 Subject: Changes to Approved Permit to Drill for MPU L-57 File #: MPU L-57 Drilling and Completion Program Any modifications to MPU L-57 Drilling & Completion Program will be documented and approved below. Changes to an approved APD will be communicated to and approved by the AOGCC. . Sec Page Date Procedure Change Approved Approved By By Approval: Drilling Manager Date Prepared: Drilling Engineer Date Page 3 Rev 0 May 2018 H Hilcorp Enc C.pmy 3.0 Tubular Program: Milne Point Unit L-57 SB NB Producer Drilling Procedure ole '(in) ID (in) Drift Conn Wt Grade Conn Burst Collapse Tension ction in OD in(#/ft) i ]Obs Cond 16" 15.25" - - - A-53 Weld 12-1/4" 9-5/8" 8.835" 8.679" 10.625" 40 L-80 TXP 5,750 3,090 916 Tieback 7-5/8" 6.875" 6.75" 7.625 29.7 L-80 vSMMS SS 61890 41790 683 Tieback 7-5/8" 6.875" 6.75" 7.947 29.7 L-80 H521 6,890 4,790 486 8-1/2" 4-1/2 3.920 3.795 4.714 13.5 L-80 H6255i1 8540 279 Screens 9020 4.0 Drill Pipe Information: All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery to TSA in Fairbanks). Page 4 Rev 0 May 2018 ff Hilcorp Enc C=n y 5.0 Internal Reporting Requirements Milne Point Unit L-57 SB NB Producer Drilling Procedure 5.1 Fill out daily drilling report and cost report on WellEz. • Report covers operations from 6am to 6am • 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. • Ensure time entry adds up to 24 hours total. • Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. • Enter the MD and TVD depths EVERY DAY whether you are making hole or not. 5.2 Detailed Daily Plan Forwards • Distributed to jenaelghilcop.com, mmyers@hilco!p.com hilcorp.com and pmazzolininhilcop.com 5.3 Afternoon Updates • Submit a short operations update each work day to pmazzolini@hilcorp.com, mmyers@hilcorp.com, jenizel@hilcgM.com and edinaer@hilco!p.com 5.4 Intranet Home Page Morning Update • Submit a short operations update each morning by lam on the company intranet homepage. On weekend and holidays, ensure to have this update in before 5am. 5.5 EHS Incident Reporting • Health and safety: Notify EHS field coordinator. • Environmental: Drilling Environmental coordinator • Notify Drilling Manager & Drilling Engineer • Submit Hilcorp Incident report to contacts above within 24 hrs 5.6 Casing Tally • Send final "As -Rud' Casing tally to iemeelQhilcorp.com and edinger@hilcorp.com 5.7 Casing and Cmt report • Send casing and cement report for each string of casing to pmazzolini cnie hilcorp.com, ienael@hilcoip.com and cdingerna hileorp.com 5.8 Hilcorp Milne Point Contact List: Title Name Work Phone Cell Phone Email Drilling Manager Monty Myers 907.777.8431 907.538.1168 mmyers@hilcorp.com Drilling Engineer Joe Engel 907.777.8395 805.235.6265 iengel@hilcorp.com Completion Engineer Paul Chan 907.777.8333 907.444.2881 pchan@hilcorp.com Geologist Kevin Eastham 907.777.8316 907.360.5087 keastham@hilcorp.com Reservoir Engineer Reid Edwards 907.777.8421 907.250.5081 reedwards@hilcorp.com Drlg Environmental Coord Keegan Fleming 907.777.8477 907.350.9439 kflemina@hilcorp.com EHS Manager Carl Jones 907.777.8327 1 907.382.4336 1 caiones@hilcorp.com Drilling Tech Cody Dinger 907.777.8389 1 509.768.8196 1 cdinaer@hilcorp.com Page 5 Rev 0 May 2018 H Hilcorp Euw company 6.0 Planned Wellbore Schematic Milne Point Unit L-57 SB NB Producer Drilling Procedure Milne Point Unit Well: MPU L-57 Proposed Schematic Last Completed: TBD ua.,..p ❑n -L:.. L". PTD: TBD ------------ ..........._____--_...- , Ong KBtlev.: 33.7/0. Dev.:1S3' - TREE &WELLHEAD TD=13—W (ND)/To= 3,724'(MI Pe1D=1$544' (MD)/ PBTD=3,744' QW) WELL INCLINATION DETAIL KDP @ ass' Mare" An8k=93.25 @ 6,966' MD OPEN HOLE /CEMENT DETAIL Cpnductor ±2]0 /t9 12-3/4' St81—teed-1324 R9/Tail-459 Ns Size 2—teed-186183 Tail -314N3 8-1 nes Screens tinerin S3/2'bold WELL INCLINATION DETAIL KDP @ ass' Mare" An8k=93.25 @ 6,966' MD CASING DETAIL' SID No. Top MD Size Type Wt/Grade/Conn ID Top Stm BPF 16' Conductor I 164/AS}B/WNd ii WA Surface 114' N/A 9-5/8' Surface I W/L-80/TXP 1 8.835 Surface 6,761' 0.0758 7-5/8' Tieback 1 29.7/L,00/ VAmSTLN521 1 6.875 1 5unace 1 6,616' 0.0459 4-1/2' Liner l50µ Screens 1 13.5/L-80/Hydrll 625 1 3.920 1 6,611' 1 13,545 .0149 55,875' Lower Tandem5eal NBIW DETAIL 10 .5,882' Motor 2-7/8- Tubing I 6.5/L-80/EUE-Brd 2.441 1 Surface I 15,907 I 0.0058 38' Dual Cap Strin 318" NA I surface I e5 OV I WA WELL INCLINATION DETAIL KDP @ ass' Mare" An8k=93.25 @ 6,966' MD ._..__..._..._.._.___.______-------- 4-1/2" SOLID LINER DETAIL 4-1/2" Screens LINER DETAIL Jb Top (MD) etm (MD) Rs Top (MD) Btm (MD) TBD TBD GENERAL WELL INFO API: T8D Com Ietlan Date: TBD Created By. CID 6-13-2018 Page 6 Rev 0 May 2018 JEWELRY DETAIL SID No. Top MD Nem 1 4135' GLM:2-7/8're r We Packet KPMMw/DKOV 2.347" 2 t5,40d GLMw/Uurrmy 2345 3 t5,75D M Nipple, 2.205' no go 2.205' 4 15,677 DisdlarBe Head 5 ±5,878' UPperTarMem Pump 6 }5,041' Lower Neydem 7 15,865' Gas Separator 8 55,868' Upper Tandem Seal 9 55,875' Lower Tandem5eal 10 .5,882' Motor 11 55,897 Sensor 12 ±5,900' Cermaluer: Bottom @ 5,900' 13 ±6,650' Boris PLTPader/liner HanBerYM9-5/8' 14 36,655' 7-51r Ti back Assy. 42.3�9W 15 16,6]5' Y H563 re 4.5" HRC L-80 XO 16 413,506' 4-1/2' Ddlfable PadoNSub 17 1 513,544' WIVVaIy LTC (1'Btllon SeaVaosed) ._..__..._..._.._.___.______-------- 4-1/2" SOLID LINER DETAIL 4-1/2" Screens LINER DETAIL Jb Top (MD) etm (MD) Rs Top (MD) Btm (MD) TBD TBD GENERAL WELL INFO API: T8D Com Ietlan Date: TBD Created By. CID 6-13-2018 Page 6 Rev 0 May 2018 H Hilcorp ens compvy 7.0 Drilling / Completion Summary Milne Point Unit L-57 5B NB Producer Drilling Procedure MPU L-57 is a grassroots ESP producer planned to be drilled in the Schrader Bluff NB sand. L-57 is part of a six well program targeting the NB sand. The directional plan is a catenary wellpath build, 12.25" hole with 9-5/8" surface casing set into the top of the Schrader Bluff NB sand. An 8.5" lateral section will then be drilled. A 4.5" screen liner will be run in the open hole section and the well will be produced with an ESP assembly. Drilling operations are expected to commence approximately July 9th, 2018. Doyon 14 will be used to drill and complete the wellbore. / Surface casing will be run to 6,761 MD / 3,945' 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, a Temp log will be run between 6 —18 hrs after CIP to determine TOC. 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. N/U & 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. N/D diverter, N/LJ & test 13-5/8" x 5M BOP. 5. Drill 8-1/2" lateral to well TD. Run 4-1/2" production screen liner 6. Run 7-5/8" tieback 7. Run production tubing 8. N/D BOP, N/U 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) Page 7 Rev 0 May 2018 H Hilcorp e� oompor Milne Point Unit L-57 SB NB 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. • BOPs shall be tested at (2) week intervals during the drilling and completion of MPU L-57. Ensure to provide AOGCC 24 hrs no ice prior to testing BOPs. • The initial test of BOP equipment will be to 250/3000 psi & subsequent tests of the BOP equipment will be to 250/3000 psi for 5/5 min (annular to 50% rated WP, 2500 psi on the high test for initial and subsequent tests). Confirm that these test pressures match those specified on the APD. • 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. • All AOGCC regulations within 20 AAC 25.033 "Primary well control for drilling: drilling fluid program and drilling fluid system". • 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 • Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office. AOGCC Regulation Variance Requests: Hilcorp Alaska respectfully asks for a variance to CO 390A Rule 3 requiring an ESP packer if the BHP gradient is greater than 8.55 ppg. The estimated reservoir pressure is 8.65 ppg EMW (1756 psi) at 3,903' TVDss, 20 psi above 8.55 ppg EMW (1736psi). Hilcorp calculates that the near wellbore bottom hole pressure will be below the 8.55 ppg gradient within one week of putting the well on production as calculated by a CMG reservoir model. /C --- Page 8 Rev 0 May 2018 n Hilcorp Encw campmy Summary of BOP Equipment and Test Requirements Milne Point Unit L-57 SB NB Producer Drilling Procedure Hole Section Equipment Test Pressure si 12 1/4" • 21-1/4" 2M Diverter w/ 16" Diverter Line Function Test Only • 13-5/8" x 5M Hydril "GK" Annular BOP • 13-5/8" x 5M Hydril MPL Double Gate Initial Test: 250/3000 o Blind ram in bum cavity • Mud cross w/ 3" x 5M side outlets 8-1/2" 13-5/8" x 5M Hydril MPL Single ram • 3-1/8" x 5M Choke Line Subsequent Tests: • 3-1/8" x 5M Kill line 250/3000 • 3-1/8" x 5M Choke manifold • Standpipe, floor valves, etc Primary closing unit: NL Shaffer, 6 station, 3000 psi, 180 gallon accumulator unit. Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is a 30:1 air pump, and emergency pressure is provided by bottled nitrogen. The remote closing operator panels are located in the doghouse and on accumulator unit. Required AOGCC Notifications: • Well control event (BOPS utilized to shut in the well to control influx of formation fluids). • 24 hours notice prior to spud. • 24 hours notice prior to testing BOPS. • 24 hours notice prior to casing running & cement operations. • Any other notifications required in APD. Regulatory Contact Information: AOGCC Jim Regg / AOGCC Inspector / (0): 907-793-1236 / Email: jim.re alaskagov Guy Schwartz / Petroleum Engineer / (0): 907-793-1226 / (C): 907-301-4533 / Email: guv.schwartzgalaska.gov Victoria Loepp / Petroleum Engineer / (0): 907-793-1247 / Email: Victoria. loel2l2@alaska.g_ov Mel Rixse / Petroleum Engineer / (0): 907-793-1231 / (C): 907-xxx-xxxx / Email: melvin.rixse@alaska.gov Primary Contact for Opportunity to witness: AOGCC.Inspectors@alaska.gov Test/Inspection notification standardization format: httn://doa.alaska.gov/ogc/forms/TestWitnessNotifhtml Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) Page 9 Rev 0 May 2018 H Hilcorp Enm Company 9.0 R/U and Preparatory Work Milne Point Unit 1-57 SB NB Producer Drilling Procedure 9.1 L-57 will utilize a newly set 16" 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" threaded nipples are installed on opposite sides of the conductor with ball valves on each nipple. These will be used to take cement returns to the cellar during the surface cmt job, and also to wash out the diverter and hanger in preparation for running the pack -off. 9.5 Level pad and ensure enough room for layout of rig footprint and R/U. 9.6 Rig mat over footprint of rig. 9.7 Confirm that the rig is over the appropriate well slot. 9.8 MIRU Doyon 14 9.9 Mud loggers WILL NOT be used on either hole section. ✓ 9.10 Mix spud mud for 12-1/4" surface hole section. Keep mud cool. 9.11 Set test plug in wellhead prior to N/U diverter to ensure nothing can fall into the wellbore if it is accidentally dropped. 9.12 Ensure 6" liners in mud pumps. • Continental EMSCO FB -1600 mud pumps are rated at 4665 psi, 462 gpm @ 110 spm @ 95% volumetric efficiency. Page 10 Rev 0 May 2018 H Hilcorp E� COMPwY 10.0 N/U 21-1/4" 2M Diverter Configuration Milne Point Unit L-57 SB NB Producer Drilling Procedure 10.1 N/U 21-1/4" Hydril MSP 2M diverter System (Diverter Schematic at See 19 at back of program). • N/U 16-3/4" 3M x 21-1/4" 2M DSA on 16-3/4" 3M wellhead. • N/U 21-1/4" diverter "T". • Knife gate, 16" diverter line. • Ensure diverter RX complies with AOGCC reg 20.AAC.25.035(C). • Diverter line must be 75 ft from nearest ignition source • 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: • A prohibition on vehicle parking A prohibition on ignition sources or running equipment A prohibition on staged equipment or materials Restriction of traffic to essential foot or vehicle traffic only. 10.4 Set wear bushing in wellhead. Page 11 Rev 0 May 2018 Milne Point Unit 0 L-57 SB NB Producer Drilling Procedure Hilcorp EnCm�r 10.5 Rig & Diverter Orientation (Approximate): ■a■aaaa■■■ G A4X 1D I'M L-53 + 55 + L-51 + 320 p c,a` c ni 14 W Radius Cleer of IOIiti4n Saurm —Divcrter Line MPU L -Pad • DnwIng Not to kale Page 12 Rev 0 May 2018 H Hilcorp E.c Camp 11.0 Drill 12-1/4" Hole Section Milne Point Unit L-57 SB NB Producer Drilling Procedure 11.1 PIU 12-1/4" directional drilling assembly: • Ensure BHA components have been inspected previously. • Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. • Ensure TF offset is measured accurately and entered correctly into the MWD software. • Ensure Gyro MWD is R/U and operational. Be sure to run a UBHO sub so that wireline orientation is possible if necessary. • Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. • Drill string will be 5" 19.5# S-135. • Run a solid float in the surface hole section. 11.2 5" Drill string, HWDP, and Jars will come from Weatherford. 11.3 Begin drilling out from 16" conductor at reduced flow rates to avoid broaching the conductor. 11.4 Drill 12-1/4" hole section to TD as per geologist and drilling engineer. • Monitor the area around the conductor for any signs of broaching. If broaching is observed, Stop drilling (or circulating) immediately notify Drilling Engineer. • Efforts should be made to minimize dog legs in the surface hole. ESP equipment can be damaged if ran through high dog legs. Keep DLS < 6 deg / 100. • Hold a pre -spud meeting with rig crews to discuss: • Conductor broaching ops and mitigation procedures. • Well control procedures and rig evacuation • Flow rates, hole cleaning, mud cooling, etc. • Pump sweeps and maintain mud rheology to ensure effective hole cleaning. • Keep mud as cool as possible to keep from washing out permafrost. • Pump at 400-600 gpm. Ensure shaker screens are set up to handle this flowrate. • Ensure to not out drill hole cleaning capacity, perform clean up cycles or reduce ROP if packoffs seen. • Keep swab and surge pressures low when tripping. • Ensure to leave a "Pump Tangent" section that is approx. 300' long in the directional plan. The ESP will need a straight section to sit. Target location of ESP pump tangent is 1000' MD and 200' TVD above target reservoir. • Ensure shale shakers are functioning properly. Check for holes in screens on connections. • Adjust MW as necessary to maintain hole stability, ensure MW is at a 9.2 minimum at TD. • TD the hole section just into the Schrader Bluff sand. Geologists and Drilling Engineers will help adjust well path to ensure well is landed correctly. • Take MWD surveys every stand drilled. - Page 13 Rev 0 May 2018 H Hilcorp Enc C=pmy Milne Point Unit L-57 SB NB Producer Drilling Procedure • Watch returns closely for signs of gas when near the base of the permafrost and circulate out all gas cut mud before continuing to drill. There have been no indications of hydrates on any of the "L" pad wells to date. • Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay balling. 11.5 12-1/4" hole mud program summary: • Density: Weighting material to be used for the hole section will be barite. Additional barite 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. • 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, and Toolpusher office • Rheology: Aquagel and viscosifier 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. • Fluid Loss: POLYPAC SUPREME should be used for filtrate control. Background LCM (5 ppb total) SAFECARB can be used in the system while drilling the surface interval to prevent losses and strengthen the wellbore. • Wellbore and mud stability: Additions of SCREENKLEEN 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 Busan 1060 MUST be made to control bacterial action. • 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). System Type: 8.8 — 9.2 ppg Pre -Hydrated Aquagel/freshwater spud mud Pro erfies: Section I Density Viscosity Plastic Viscosity Yield Point I API Fl. pH I Tem Surface 1 8.8-9.2.1 75-175 1 20-40 25-45 1 <10 8.5-9.0 1 <- 70 F Page 14 Rev 0 May 2018 n Hilcorp Encegr Cwpmy Milne Point Unit L-57 SB NB Producer Drilling Procedure Mud Formulation: Gel + FW Based Spud Mud Product- Surface hole Size Pkg ppb or (% liquids) M -I Gel 50 lb sx 25 Soda Ash 50 lb sx 0.25 Pol Pac Supreme UL 50 Ib sx 0.08 Caustic Soda 50 lb sx 0.1 SCREENCLEEN 55 gal dm 0.5 11.6 At TD; PU 2-3 stands off bottom, CBU, pump tandem sweeps and drop viscosity. 11.7 RIH t/ bottom, proceed to BROOH t/ HWDP • Pump at full drill rate (400-600 gpm), and maximize rotation. • Pull slowly, 5 —10 ft / minute. • Monitor well for any signs of packing off or losses. • Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay balling. • If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until parameters are restored. 11.8 TOOH and LD BHA 11.9 No open hole logging program planned. Page 15 Rev 0 May 2018 H Hilcorp Enc C=Wy 12.0 Run 9-5/8" Surface Casing 12.1 R/U and pull wear bushing. 12.2 Make a dummy run with the 9-5/8" casing hanger. Milne Point Unit L-57 SB NB Producer Drilling Procedure 12.3 R/U Weatherford 9-5/8" casing running equipment (CRT & Tongs) • Ensure 9-5/8" TXP x DS50 XO on rig floor and M/U to FOSV. • Use BOL 2000 thread compound. Dope pin end only w/ paintbrush. • R/U of CRT if hole conditions require. • R/U a fill up tool to fill casing while running if the CRT is not used. • Ensure all casing has been drifted to 8.75" on the location prior to running. • Be sure to count the total # of joints on the location before running. • Keep hole covered while R/U casing tools. • Record OD's, ID's, lengths, S/N's of all components w/ vendor & model info. 12.4 P/U shoe joint, visually verify no debris inside joint. 12.5 Continue M/U & thread locking 120' shoe track assembly consisting of: 9-5/8" Float Shoe 1 joint — 9-5/8" DWC, 2 Centralizers 10' from each end w/ stop rings 1 joint — 9-5/8" DWC, 1 Centralizer mid joint w/ stop ring 9-5/8" Float Collar w/ Stage Cementer Bypass Baffle 'Top Hat' 1 joint — 9-5/8" DWC, 1 Centralizer mid joint with stop ring 9-5/8" HES Baffle Adaptor • Ensure bypass baffle is correctly installed on top of float collar. Bypass Baffle This end up. nCD • Ensure proper operation of float equipment while picking up. • Ensure to record S/N's of all float equipment and stage tool components. Page 16 Rev 0 May 2018 Milne Point Unit L-57 SB NB Producer Drilling Procedure Hilcorp Energy Company 12.6 Float equipment and Stage tool equipment drawings: Type H ES Cementer Part No. SO No. 'losing Sleeve No. Shear Pins Dpening Sleeve No. Shear Pins ES Cementer Depth Baffle Adapter (if used) ID Depth Bypass or Shutoff Baffle ID Depth Float Collar Depth Float Shoe Depth Hole TD "Reference Casing Sales Manual SPLRQn S "A Nikorp ESTI Running Order O>erall Length B Shut Oa Plug Lim. 10 Ager Orillout C Battle Adapter Maa. T.1 00 D Bypass plug Openrn Seat 10 E Closing Seat ID Plug Set Part No. SO No. Opening Plug OD OD Shut-off Plug OD Bypass Plug cif used) OD Page 17 Rev 0 May 2018 a/ Nikorp ESTI Running Order ESTI Cementer Shut Oa Plug Battle Adapter Bypass plug C By pass Raffle finat Cog" float Shoe Page 17 Rev 0 May 2018 a/ H Hilcorp E.n C.m Milne Point Unit L-57 SB NB Producer Drilling Procedure 12.7 Continue running 9-5/8" surface casing • Fill casing while running using fill up line on rig floor. • Use BOL 2000 thread compound. Dope pin end only w/ paint brush. • Centralization: • 1 centralizer every ioint t/ — 1000' MD from shoe • 1 centralizer every 2 joints to 2,000' above shoe (Top of Ugnu) • Verify depth of lowest Ugnu water sand for isolation with Geologist • Utilize a collar clamp until weight is sufficient to keep slips set properly. • Break circulation prior to reaching the base of the permafrost if casing run indicates poor hole conditions. • 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. 12.8 Install the Halliburton Type H ES -II Stage tool so that it is positioned at least 100' TVD below the permafrost (— 2,500' MD). • Install centralizers over couplings on 5 joints below and 10 joints above stage tool Instal centralizers'/2 joints to base of conductor Do not place tongs on ES cementer, this can cause damaged to the tool. Ensure tool is pinned with 6 opening shear pins. This will allow the tool to open at 3300 psi. 9-5/8" 409 L-80 TXP Make Up Torques: Casing OD Min M/U Torque Max M/U Torque 9-5/8" 18,860 ft -lbs 23,060 ft -lbs Page 18 Rev 0 May 2018 Milne Point Unit L-57 SB NB Producer Drilling Procedure Hilcorp Ben, Company TXPO BTC m 01/22/2016 Outside Diameter 9.625 in. Min. Wall 87.5% Thickness {') Grade LBO low Type 1 Wall Thickness 0.395 is connection OD REGULAR Option COUPLING PIPE BOGY Body'. Red 1st Band: Red Grade LBO Type 1' Drift API Standard 1st Bi Brown 2nd Band: 2nd Band: - Brawn Type eesin0 3rd Band-- 3rd Band -- o 41h Band: - PIPE BODY DATA GEOMETRY Nominal OD 9625 in. Nmni(W Ws+ght 40lbst Rift 8.679 n. Nominal 91) 8135,n, Wall Tini 0.395 in. Plan End Npght 38.97 iti OD Tolerance AN PERFORMANCE Body Yield Strength 910:1DW Has Imemai 575D psi SMYS 80000 psi Collapse 3080 psi CONNECTION DATA GEOMETRY Connection OD 10.525 in. ,Coupling Ler>gP+ 10.825 n Connection ID &923 in, rho pLoss 4.891 in. Threads per in 5 Connection OD Option REGULAR PERFORMANCE Tension Effcmi 100.0% Joint Yeeld Strength 9161 Orleans! Pressure Capandry 5750.000 psi ba Canpresc--ion EFziercy 100% Compression Strength 916001 Mw Allowable Bending 39'/100ft lbs riemal Pressure Capacity 3090.000 psi MAKE-UP TORQUES 1.Iinimum 18860 ft -lbs Lpi 20980 Wine 8paznzan 23088 hob. OPERATION LIMIT TORQUES Operi Torque 35680 ft4bs Yield libi 4340011 Notes This connection is fully interchangeable with- TXPV BTC - 9.625 in. - 36 143.5 ! 47 153-51584 Ibsrft )11 Internal Pressure Capacity related to structural resistance only. Internal pressure leak resistance as per section 10.3 API 5C3 ! ISO 10400 - 2007. Page 19 Rev 0 May 2018 H Hilcorp Enn Cmc, Milne Point Unit L-57 SB NB Producer Drilling Procedure 12.9 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 12.10 Slow in and out of slips. 12.11 P/U landing joint and M/U 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. 12.12 Lower casing to setting depth. Confirm measurements. 12.13 Have slips staged in cellar, along with necessary equipment for the operation. 12.14 Circulate and condition mud through CRT. Reduce YP to < 20 to help ensure success of cement job. Ensure adequate amounts of cold M/U water are available to achieve this. If possible reciprocate casing string while conditioning mud. J Page 20 Rev 0 May 2018 N Hilcorp EMuC=PrW 13.0 Cement 9-5/8" Surface Casing Milne Point Unit L-57 SB NB Producer Drilling Procedure 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. • How to handle cement returns at surface. Ensure vac trucks are on standby and ready to assist. • Which pump will be utilized for displacement, and how fluid will be fed to displacement PUMP. • Ensure adequate amounts of water for mix fluid is heated and available in the water tanks. • 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 • Review test reports and ensure pump times are acceptable. • Conduct visual inspection of all iron 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 RX 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 I" 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. Y t5 � Estimated First Stage Total Cement Volume: Section: Calculation: Vol (BBLS) Vol (ft3) 12-1/4" OH x 9-5/8" Casing annulus: (5,751'- 2500') x .0558 bpf x 1.3 = 236 bbls 1324 ft3 Total LEAD: 236 bbls 1324 ft3 12-1/4" OH x 9-5/8" Casing (6,761'- 5,751') x.0558 bpf x 1.3 = 72.5 bbls 407.3 ft3 annulus: 9-5/8" Shoe track: 120 x .0758 bpf = 9.1 51.1 Total 15.8 ppg TAIL: 81.6 bbl 458.6 ft3 3') 7 3i`�v n Hilcorp E.c Company Cement Slurry Design: Milne Point Unit L-57 SB NB 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. 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 and ensure plug is bumped on strokes. To operate the stage tool hydraulically, the plug must be bumped. 13.11 Displacement calculation: 6,641' x.0758 bpf = 503.4 bbls If desired, 20 - 80 bbls of water can be left across stage tool to ensure proper operation once opened. 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, f4.5 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. Page 22 Rev 0 May 2018 J Lead Slurry Tail Slurry System ExtendaCEM rM System SwiftCEM '"' System (Hal Cern) Density 11.7 Ib/gal 15.8 Ib/gal Yield 4.298 ft3/sk 1.16 ft3/sk Mixed Water 21.13 gal/sk 5.04 gal/sk 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. 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 and ensure plug is bumped on strokes. To operate the stage tool hydraulically, the plug must be bumped. 13.11 Displacement calculation: 6,641' x.0758 bpf = 503.4 bbls If desired, 20 - 80 bbls of water can be left across stage tool to ensure proper operation once opened. 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, f4.5 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. Page 22 Rev 0 May 2018 J K Hilcorp Milne Point Unit L-57 SB NB Producer Drilling Procedure 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 3300 psi to oven 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. i 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 23 Rev 0 May 2018 H Hilcorp E. a C. , Second Stage Surface Cement Job: Milne Point Unit L-57 SB NB Producer Drilling Procedure 13.18 Prepare for the 2nd stage as necessary. Circulate until first stage reaches sufficient compressive strength as per UCA test chart. Hold pre job safety meeting. 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 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. Based upon first stage volume circulated back to surface and hole gauge sweeps, lead cement excess could be reduced to 150%. �p Estimated Second Stage Total Cement Volume: S Section: Calculation: Vol (BBLS) Vol (ft3) 16" Conductor x 9-5/8" (110') x .135 bpf x 1 = 14.8 bbls 83.6 ft3 casing annulus: Yield 4.3279 ft3/sk 1.39 ft3/sk 12-1/4" OH x 9-5/8" Casing (2000'- 110') x .0558 bpf x 3 = 316.4 bbls 1778 ft3 annulus: Total LEAD: 331.2 bbls 1861 ft3 12-1/4" OH x 9-5/8" Casing 2500'- 2000') x.0558 bpf x 2 = 55.8 314 ft3 annulus: Total TAIL: 55.8 bbls 1 314 ft3 Cement Slurry Design (2nd stage cement job): Lead Slurry Tail Slurry System Permafrost L Type 1/II Density 10.7 lb/gal 14.5 lb/gal Yield 4.3279 ft3/sk 1.39 ft3/sk Mixed Water 21.405 gal/sk 6.8 gal/sk n Hilcorp Enew Camµuy Milne Point Unit L-57 SB NB Producer Drilling Procedure 13.24 Continue pumping lead until uncontaminated spacer is seen at surface, then switch to tail. 13.25 After pumping cement, drop ES Cementer closing plug and displace cement with spud mud out of mud pits. 13.26 Displacement calculation: 4/ 2500' x.0758 bpf = 190 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 1000 — 1500 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 as per wellhead rep. 13.30 M/U pack -off running tool and pack -off to bottom of final joint. Set casing hanger packoff. Inject plastic packing element. Pressure test packoff. 13.31 Lay down cut joint and pack -off running tool. Ensure to report the following on wellez: • Pre flush type, volume (bbls) & weight (ppg) • Cement slurry type, lead or tail, volume & weight • Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration a. Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid b. Note if casing is reciprocated or rotated during the job c. Calculated volume of displacement, actual displacement volume, whether plug bumped & bump pressure, do floats hold d. Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure e. Note if pre flush or cement returns at surface & volume f. Note time cement in place g. Note calculated top of cement h. 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 jengelghilcorp.com and cdinger@hilcoW.com com This will be included with the EOW documentation that goes to the AOGCC. Page 25 Rev 0 May 2018 H Hilcorp Eve Czjx 14.0 14.1 14.2 n 14.3 Milne Point Unit L-57 SB NB Producer Drilling Procedure BOPE N/U, Test and Wellhead Installation N/D the diverter T, 16" knife gate, 16" diverter line & NIU l I" x 13-5/8" 5M casing spool. N/U 13-5/8" x 5M BOP as follows: • 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 • Double gate ram should be dressed with 2-7/8" x 5.5" VBRs in top cavity, blind ram in bottom cavity. • Single ram can be dressed with 2-7/8" x 5.5" VBRs or 5" Solid Body Rams • N/U bell nipple, install flowline. • Install (1) manual valve & HCR valve on kill side of mud cross. (Manual valve closest to mud cross). • Install (1) manual valve on choke side of mud cross. Install an HRC outside of the manual valve Run 5" BOP test assembly, land out test plug (if not installed previously). �1 14.4 Test BOP to 250/3000 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min • Confirm test pressures with PTD • Ensure to monitor side outlet valves and annulus valve pressure gauges to ensure no pressure is trapped underneath test plug • Once BOPE test is complete, send a copy of the test report to town engineer and drilling tech 14.5 R/D BOP test equipment 14.6 Dump and clean mud pits, send spud mud to G&I pad for injection. 14.7 Mix 8.9 ppg F1oPro fluid for production hole. 14.8 Set wear bushing in wellhead. 14.9 Rack back as much 5" DP in derrick as possible to be used while drilling the hole section. 14.10 Ensure 6" liners in mud pumps. Page 26 Rev 0 May 2018 H Hilcorp Ena Company 15.0 Drill 8-1/2" Hole Section 15.1 M/U 8.5" Cleanout BHA (Milltooth Bit & 1.220 PDM) Milne Point Unit L-57 SB NB Producer Drilling Procedure 15.2 TIH w/ 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 b f 1c adapter. Note depth TOC tagged on morning report. q!$" 0i-- 15.4 RX and test casing to 2500 psi / 30 min. Ensure to record volume / pressure and plot on FIT it- graph. AOGCC reg is 50% of burst = 6870 / 2 = —3500 psi, but max test pressure on the well is �y 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 ppg EMW. Chart Test. Ensure test is recorded on same chart as FIT. Document increment vo ume pumped (and subsequent pressure) and volume returned. 15.8 POOH & LD Cleanout BHA 15.9 P/U 8-1/2" directional BHA. • Ensure BHA components have been inspected previously. • Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. • Ensure TF offset is measured accurately and entered correctly into the MWD software. • Ensure MWD is R/U and operational. • Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. • Drill string will be 5" 19.5# 5-135 DS50 & NC50. • Run a ported float in the surface hole section. 15.10 8-1/2" hole section mud program summary: 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. Use appropriate SAFECARB blend on this well Page 27 Rev 0 May 2018 n Hilcotp Eos c2x Milne Point Unit L-57 SB NB Producer Drilling Procedure • Solids Concentration: It is imperative that the solids concentration be kept low while drilling the production hole section. Keep the shaker screen size optimized and fluid running to near the end of the shakers. It is okay if the shakers run slightly wet to ensure we are running the finest screens possible. • Rheology: Keep viscosifier additions to an absolute minimum. Data suggests excessive viscosifier concentrations can decrease return permeability. Do not pump high vis sweeps, instead use tandem sweeps. Ensure 6 rpm is > 8.5 (hole diameter) for sufficient hole cleaning • Run the centrifuge continuously while drilling the production hole, this will help with solids removal. • Dump and dilute as necessary to keep drilled solids to an absolute minimum. • 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 F1oPro drilling fluid Properties: Interval Density PV YP LSYP Total Solids MBT I HPHT I Hardness Production 8.9-9. 15-25 - ALAP 1 15-30 1 4-6 <10% <8 1 <11.0 I <100 Mud Formulation: FloPro 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 FLONIS PLUS 25 lb sx 0.7 KCI 50 lb sx 10.7 SMB 50 Ib 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 Page 28 Rev 0 May 2018 Milne Point Unit L-57 SB NB Producer Drilling Procedure Hilcorp E.c C.n 15.11 TIH w/ 8-1/2" directional assembly to bottom. 15.12 Begin drilling 8-1/2" hole section, on -bottom staging technique: • Tag bottom and begin drilling with 100 - 120 rpms at bit. Allow WOB to stabilize at 5-8k. • Slowly begin bringing up rpms, monitoring stick slip and BHA vibrations pulsed up real time. If BHA begins to show excessive vibrations / whirl / stick slip, it may be necessary to P/U off bottom and restart on bottom staging technique. 15.13 Drill 8-1/2" hole section to section TD per Geologist and Geosteer Engineer. • Flow Rate: 350-550 gpm, target AV's 200ft/min, 385 gpm • Watch for signs of formation washout/erosion due to high flow rate, ex: loss of directional control, housing roll, etc • RPM: 120+ • 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. • Keep pipe movement with pumps off slow, to keep swab and surge pressures low • Take MWD surveys every stand • Surveys can be taken more frequently if deemed necessary, ex: concretion deflection • Monitor Torque and Drag with pumps on every 5 stands • Monitor ECD trends, pump pressure, hook load for hole cleaning indication • 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. • Use ADR to stay in section. Ideally, we would like to stay in section 100% of the time and not to serpentine between the top and bottom of the sand • 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. • Pump High Weight High Vise/Low Weight Lo Vise Tandem sweeps every 500', or if needed • Schrader Bluff N Sand Concretions (% of total lateral footage): • L-53:3% • L-52:2% 15.14 Reference: Open hole sidetracking practice: • 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. • Attempt to lowside in a fast drilling interval where the wellbore is headed up. • Orient TF to low side and dig a trough with high flowrates for the first 10 ft, working string back and forth. Trough for approx. 30 min. • Time drill at 4 to 6 feet per hour with high flow rates. Gradually increase ROP as the openhole sidetrack is achieved. Page 29 Rev 0 May 2018 Milne Point Unit L-57 SB NB Producer Drilling Procedure 15.15 Begin screening up on the shakers 500 — 1000' before reaching TD. Also begin reducing mud weight to 9.0 ppg, if hole conditions allow. 15.16 At TD, CBU at least 4 times at 200 ft/min AV circulation rate (385 gpm) and rotation (120 rpm). As the NB sand is unconsolidated, it has been seen that higher flow rates have washed out the hole section and created more solids. Adjust pump rate as necessary to clean hole without generating more solids. Pump tandem sweeps if needed. Once well has TD'd the production lateral, swap to the completion AFE. 15.17 Monitor the returned fluids carefully while conditioning the mud. After 4 (or more) BU, Perform production screen test (PST). Reduce flow rate and RPM as per PST Test Procedure. The mud has been properly conditioned when the mud will pass the production screen test (3 one liter samples passing through the screen in the same amount of time which will indicate no plugging of the screen). Reference PST Test Procedure • SB NB sand screen completion require passing PST with 250µ coupons • Circulate and condition mud as much as needed to pass the production screen test 15.18 BROOH with the drilling assembly to the 9-5/8" casing shoe • Circulate at full drill rate (385 gpm max). • Rotate at maximum rpm that can be sustained. Limit pulling speed to 5 — 10 min/std (slip to slip time, not including connections). If backreaming operations are commenced, continue backreaming to the shoe 15.19 Ensure all mud pumped downhole passes production screen test prior to running screens. 15.20 CBU minimum two times at 9-5/8" shoe and clean casing with high vis sweeps. 15.21 Swap over to clean filtered brine in preparation for screens, (brine weight equal to mud weight at TD). Rotate and reciprocate as needed to ensure the mud is removed from the 9-5/8" casing. 15.22 Monitor well for flow. Increase brine weight if necessary 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 15.23 POOH and LD BHA. Rabbit DP on TOH, ensure rabbit diameter is sufficient for future ball drops. Only LWD open hole logs are planned for the hole section (GR + Res). There will not be any additional logging runs conducted. Page 30 Rev 0 May 2018 H Hilcorp E.a Company Milne Point Unit L-57 SB NB Producer Drilling Procedure 16.0 Run 4-1/2" Production Screen Liner (Lower Completion) 16.1. 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: • P/U & M/U the 5" safety joint (with 4-1/2" crossover installed on bottom, TIW valve in open son top, 4-1/2" handling joint above TIW). This joint shall be fully M/U and available prior to running the first joint of 4-1/2" screen. • 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. 16.2. 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: • PIU & M/U the 5" safety joint (with 4-1/2" x 2-3/8" triple connect c oy4r installed on bottom, TIW valve in open position on top, 2-3/8" h mg joint above TIW). M/U 2-3/8" and then 4-1/2" to triple connect. • This joint shall be fully M/U with crossovers prior to running the first joint of wash pipe. • 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. 16.3. R/U 4-1/2" screen running equipment. • Ensure 4-1/2" x DS -50 crossover is on rig floor and M/U to FOSV. • Ensure all casing has been drifted on the deck prior to running. • Be sure to count the total # of joints on the deck before running. Keep hole covered while R/U casing tools. Record OD's, ID's, lengths, S/N's of all components w/ vendor & model info. 16.4. Run 4-1/2" screen production liner — Reference screen handling and running procedure. • Use API Modified or "Best O Life 2000 AG" thread compound. Dope pin end only w/ paint brush. Wipe off excess. Thread compound will plug the screens. • Use Hydril 625 stabbing guide on screen joints • Utilize a collar clamp until weight is sufficient to keep slips set properly. • Run packoff and float shoe on bottom. • 4-1/2" Screens should auto —fill, top off with completion brine if needed • Swell packers will not be required on this completion unless the well is drilled out of zone Page 31 Rev 0 May 2018 n Hilcorp Encs Compmy Milne Point Unit L-57 SB NB Producer Drilling Procedure 4-r/2" Lower Completion Running Order • 4-'/2" Float Shoe, BTC box (Bakerlok all 4-%2" shoe track connections below the last semi- premium/premium connection) • 4-%2" WIV (wellbore isolation valve), BTC box x pin • 4-%2" spacer joint, —30 - 40', IBT-M box x BTC pin • 4-%2" Drillable Pac Off Sub, IBT-M box x pin • 5' 4.5" 13.5# Hydril 625 Box X 4.5" 12.6# IBT Pin crossover 1 joint 4-%2" 13.59/ft L-80 Hydril 625 Liner (optional) • 4-'/2" 13.5#/ft L-80 Hydril 625 Screens to 13,541' MD • Joints of 4-%2" 13.5#/ft Hydril 625 L-80 Liner (liner lap) as needed • 4'4.5" 13.5# Hydril 625 Box X Pin pup joint (safety joint) • 7" 26# HYD 563 Box x 4.5" 13.5# Hydril 625 Pin crossover • Baker SLZXP Liner Hanger/Liner Top Packer w/ 7" 26# Hydril 563 pin d-1 /2"" 14 4 # 1-9O Hydril 625 Tarnue OD Minimum Maximum Operafing OperatingTor ue 4.5" 8,000 ft -lbs 11,300 ft -lbs 1 11,300 ft -lbs Page 32 Rev 0 May 2018 Milne Point Unit L-57 SB NB Producer Drilling Procedure Hilcorp Erin Company Wedge 6250 m.aa 10/31/2017 FIFE BODY DATA Min. Wall 87.5% I Outside Diameter 4.500m. Thickness (')Grade L80 Nwninal W 4.500 in. Nominal Weight 13.50 tbst.. Type 1 7795 in. Wall Thickness 0.290 in Connection OD REGULAR CWPLNG PIPE BODY ODTolennce All Option Bay Red Weal RM Grade L80 Type V Drift AN Standard 1st Band: Brown 2nd Band: _ 307 x1@00 Ws Irl Veld 9020 psi 2nd Bah: - Brown Collapse 8540 psi 3rd Band: - 3rd Band: - CONNEf_TIUN DATA. Type Casing 4th Band - FIFE BODY DATA I GEOMETRY Nwninal W 4.500 in. Nominal Weight 13.50 tbst.. Drift 7795 in. Nonninal ID 3-920 n. Wall-Diirkness 0.290 in. Ptain End Weigh 13.05 III ODTolennce All PERFORMANCE Body Yield StrenOlh 307 x1@00 Ws Irl Veld 9020 psi sill NOW psi Collapse 8540 psi CONNEf_TIUN DATA. GEOMETRY Cavrectim+ W 4314 in Conneetien ID 3949 in. Makeup Loss 4930 in Threads Per in 3.59 Conneotion OD Option REGULAR PERFORMANCE Tension El 919% Join Yield Sinal 279.370.1000 Interns Pressure Capaelty 9020-000 Psi It,s Ccre,ri on E15denry 94.5% C:ompriel Sail 290.115.1000 Mac Alla Ie Bendkg 73.7 -MoD ft lbs Enemas Pressure Capacity 8540.ODO psi MAKE-UP TORQUES Minimum 8000 ft -lbs Opamum %Nft-lbs M... 12900 ft� OPERATION LIMIT TORQUES Operating Toil /2800 ft -Bs Yied Torque 15000 ftJ Page 33 Rev 0 May 2018 H Hilcorp ao« cam,—, MPU L-57 SB NB Producer Lower Completion Detail Milne Point Unit L-57 SB NB Producer Drilling Procedure Description Connection EEstyJoints / Est Length (ft) Est Top (MD) Liner Top Packer & Hanger 7" 26# 563 Pin 1 25 Crossover, 7" 26# x 4.5"13.5# 7" H563 box x 4.5" H625 pin 1 5 Pup Joint, 4.5" H625 bxp 1 5 Joints, 4.5" Blank (across liner lap) Hydril 625 3 120 250 micron Screens, 4.5" 13.5# L-80 Hydril 625 162 6741 Crossover, 4.5" Hydril 625 box x IBT pin 1 4 Pack Off Sub, 4-1/2" IBT 1 2 Joint, 4.5" 13.5# 1 B (B) x BTC (p) 1 35 WIV, 4-1/2" (BL Connection) BTC 1 3 Float Shoe, 4-1/2" (BL Connection) BTC 1 1.5 Note: Blank Pipe and Swell Packers may be ran if any out of zone excursion occur during lateral drilling 16.6. Pickup enough liner to provide for approximately 150' overlap inside 9-5/8" casing. • 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. R/U false rotary and run 2-3/8" 6.4 # Inner String • Drift 2-3/8" inner string with minimum 1.5" drift (WIV closing ball 1.25") Note: Once inner string in run and set inside packoff, displace 9-5/8" casing back to PST passed drilling mud with lubricants added. 16.8. 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. 16.9. M/U liner hanger/liner top packer to inner string and 4-1/2" liner. Fill liner tieback sleeve with "Pal mix", ensure mixture is thin enough to travel past the HRD tool and down to the packoff. Wait 30 min for mixture to set up. 16.10. Note PUW, SOW, ROT and torque. Run liner in the hole one stand and pump through liner hanger to ensure a clear flow path exists. 16.11. Displace 9-5/8" casing back to lubricated mud. 16.12. RIH w/ liner on DP no faster than 30 ft/min — this is to prevent buckling the liner and drill string. Watch displacement carefully and avoid surging the hole or buckling the liner. Slow down running speed if necessary. Page 34 Rev 0 May 2018 Milne Point Unit L-57 SB NB Producer Drilling Procedure 11C� 16.13. The screens and inner string will prevent the DP from auto filling. Fill DP with PST passed mud every 5 stands, more frequently if SOW trend indicates. 16.14. Slow in and out of slips. Ensure accurate slack off data is gathered during RIH. Record shoe depth + S/O depth every stand. Record torque value if it becomes necessary to rotate the string to bottom. 16.15. Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10, & 20 rpm 16.16. If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensure shoe enters correct hole. 16.17. TIH deeper than planned setting depth. Last motion of the liner should be up to ensure it is set in tension. 16.18. Rig up to pump down the work string with the rig pumps. NOTE: The wellbore will be swapped over to brine after the liner has reached TD to keep from plugging the screens with solids. The success of this well depends upon the screens not becoming plugged with solids. 16.19. Break circulation and begin displacing wellbore to 2% KCl/NaCl brine, ensure weight matches MW or previous brine weights. Begin circulating at —1 BPM and monitor pump pressures. Slowly bring rate up while swapping the lateral to brine. Pump train as follows: 20 bbl high vis sweep / 2 x OH volume brine / 40 bbl SAPP pill #1 / 50 bbl brine / 40 bbl SAPP pill 92 / 50 bbl brine / 40 bbl SAPP pill #3. 16.20. Ensure circulation pressures do not exceed set pressure for liner hanger pusher tool. 16.21. Monitor pump pressures closely and adjust pump rate if the well appears to be packing off at the swell packers (if run). Note all losses. Confirm all circulating pressures with Baker. Capture mud for reconditioning and reuse if possible 16.22. Monitor the returned fluids carefully during displacement. Perform production screen test (PST). The wellbore has been properly conditioned when the return fluid will pass the production screen test (3 one liter samples passing through the screen coupon in the same amount of time which will indicate no plugging of the screens). 16.23. Circulate out SAPP pills 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. Page 35 Rev 0 May 2018 Milne Point Unit L-57 SB NB Producer Drilling Procedure Hilcorp Evm CompW 16.24. Shut down pumps. Drop setting ball down the workstring and pump slowly (1-2 bpm). Slow pump before the ball seats. Do not allow ball to slam into ball seat. Pressure up to 1,500 psi to shift the wellbore isolation valve closed. 16.25. Continue pressuring up to 2700 psi to set the SLZXP liner hanger/packer. Hold for 5 minutes. Slack off 20K lbs on the SLZXP to ensure the HRDE setting tool is in compression for release from the SLZXP liner hanger/packer. Continue pressuring up to 4500 psi to activate the hydraulic pusher tool to set the SLZXP packer. This will also release the HRDE running tool. 16.26. Bleed DP pressure to zero, 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, 16.27. PU to neutral weight, close BOP and test annulus to 1500 psi for 10 min and chart record same. 16.28. 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. 16.29. P/U above liner top packer and displace well to completion fluid. 16.30. POOH, L/D and inspect running tools. If setting of liner hanger/packer proceeded as planned, LDDP on the TOH. L/D 2-3/8" inner string. Page 36 Rev 0 May 2018 Milne Point Unit L-57 SB N8 Producer Drilling Procedure Hilcorp � COMIAM 17.0 Run 7-5/8" Tieback 17.1 RIH with mule shoe on 5" DP to Liner Top and circulation Liner Top and SBE clean. POOH. 17.2 RAJ and pull wear bushing. Get an accurate measurement of RKB to tubing hanger load shoulder to be used for tic -back space out calculation. Install and test 7-5/8" (250/3000 psi) solid body casing rams. 17.2 R/U 7-5/8" casing handling equipment. • Ensure XO to DP made up to FOSV and ready on rig floor. Rig up computer torque monitoring service. String should stay full while running, r/u fill up line and check as appropriate. 17.3 P/U tieback seal assembly and set in rotary table. Ensure 7-5/8" seal assembly has x4 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. 17.4 M/U first joint of 7-5/8" to seal assy. 17.5 Run 7-5/8" 29.7# VAM STL SMLS /Hydril 521 tieback to position seal assy two joints above tieback sleeve. Record up & down weights. Use collar clamp of each joint Use stabbing guides Follow running procedure outlined above. Page 37 Rev 0 May 2018 Milne Point Unit L-57 SB NB Producer Drilling Procedure Hileorp am c.w> Technical Specifications Connection Type: Size(O.D.): ST -L Casing 7-518 in STANDARD Material L-80 Grade 80,000 Minimum Yield Strength (psi_) 95,000 Minimum Ultimate Strength (psi.) Weight (Wall): 29.70 IbIft (0.375 in) Pipe Dimensions 7.625 Nominal Pipe Body O.D. (in.) 6.875 Nominal Pipe Body I.D. (in-) 0.375 Nominal Wall Thickness (in.) 29.70 Nominal Weight (lbs.lft.) 29.06 Plain End Weight (lbs.lft.) 8.541 Nominal Pipe Body Area (sq. in.) Weight (Wall): 29.70 IbIft (0.375 in) Connection Performance Properties 444,000 (1) Joint Strength (lbs.) 527,000 (2) Reference Minimum Parting Load (lbs.) 10,910 Reference String Length (ft) 1.4 Design Factor 266,000 Compression Rating (lbs.) 4,790 Collapse Pressure Rating (psi.) 6,890 Internal Pressure Rating (psi.) 18.8 Maximum Uniaxial Bend Rating [degrees/100 ft] Recommended Torque Values 4,600 (3) Minimum Final Torque (ft -lbs.) 6,000 (3) Maximum Final Torque (ft -lbs.) Grade: L-80 -USA VA61 USA 4424 W. Sam Houston Pkwy. Sude 150 Houston. TX 77041 Phone: 713-479-3260 Fax 713-479-3234 E-mail: VAI1USAsalesAvam�Us8 corn Page 38 Rev 0 May 2018 Pipe Body Performance Properties 683,000 Minimum Pipe Body Yield Strength (Ibs.) 4,790 Minimum Collapse Pressure (psi.) 6,890 Minimum Internal Yield Pressure (psi.) 6,300 Hydrostatic Test Pressure (psi.) Connection Performance Properties 444,000 (1) Joint Strength (lbs.) 527,000 (2) Reference Minimum Parting Load (lbs.) 10,910 Reference String Length (ft) 1.4 Design Factor 266,000 Compression Rating (lbs.) 4,790 Collapse Pressure Rating (psi.) 6,890 Internal Pressure Rating (psi.) 18.8 Maximum Uniaxial Bend Rating [degrees/100 ft] Recommended Torque Values 4,600 (3) Minimum Final Torque (ft -lbs.) 6,000 (3) Maximum Final Torque (ft -lbs.) Grade: L-80 -USA VA61 USA 4424 W. Sam Houston Pkwy. Sude 150 Houston. TX 77041 Phone: 713-479-3260 Fax 713-479-3234 E-mail: VAI1USAsalesAvam�Us8 corn Page 38 Rev 0 May 2018 Connection Dimensions 7.625 Connection O.D. (in.) 6.782 Connection I.D. (in.) 6.750 Connection Drift Diameter (in.) 4.39 Make-up Loss (in.) 5.550 Critical Area (sq. in.) 65.0 Joint Efficiency (%) Connection Performance Properties 444,000 (1) Joint Strength (lbs.) 527,000 (2) Reference Minimum Parting Load (lbs.) 10,910 Reference String Length (ft) 1.4 Design Factor 266,000 Compression Rating (lbs.) 4,790 Collapse Pressure Rating (psi.) 6,890 Internal Pressure Rating (psi.) 18.8 Maximum Uniaxial Bend Rating [degrees/100 ft] Recommended Torque Values 4,600 (3) Minimum Final Torque (ft -lbs.) 6,000 (3) Maximum Final Torque (ft -lbs.) Grade: L-80 -USA VA61 USA 4424 W. Sam Houston Pkwy. Sude 150 Houston. TX 77041 Phone: 713-479-3260 Fax 713-479-3234 E-mail: VAI1USAsalesAvam�Us8 corn Page 38 Rev 0 May 2018 Milne Point Unit L-57 SB NB Producer Drilling Procedure Hilcorp Enmgy Cmnpmy Wedge 521® m.a, 0611512018 PERFORMANCE Body Yield Strength 683.[ WG lbs Internal Yield 6990 psi SMYS 80000 psi Collapse 1790 psi GEOMETRY I Connection OD 7.907 a Connection ID 6.800 in Mate -up Loss 3.700 in. Threads perm 3.28 Connection OD Option REGULAR PERFORMANCE Tension Egfi '[Amey 712% Joint Yield Strength 486296.1000 tntemal Pressura Capadly 6890.006 psi His Compression Erw^ency 87-5% Compression Strength 597.625 AGN Mac Allowable Bending 342 41100 It lbs -xemal Pressure Cape* 4790.000 psi MAKE-UP TORQUES Minimum 8400R4bs Optimum 10100 ftgbz Maumurn 14700 ft -as OPERATION LIMIT TORQUES Clerating Torque 35000 ft4bs Yatld Torque 53000 ft -lbs Page 39 Rev 0 May 2018 Min. Wail SZ5�6 Outside Diameter 7.625 in Thickness (') Grade LBO 40111115 Type Conrw otmnn4 D REGULAR Wall Thickness 0.375 in. COUPLING PIPE EODY 8ady: Red Is: Band: Red Grade 180 Type I' Drill API 9landartl let Band: Brawn 2nd Ban: 2nd Band:- Brawn Type Casing 3rd Band: - ?.d Ban: - 48t Bend: - PIPE BODY DATA GEOMETRY Nominal OD 7.625a Noinnal Weight 25306rs5t Drift 675 in. Nomnat 10 6.675 n. Wall Thiclmess 0.375 in. Plain End Might 29.061bsA OD Tok_mnm API PERFORMANCE Body Yield Strength 683.[ WG lbs Internal Yield 6990 psi SMYS 80000 psi Collapse 1790 psi GEOMETRY I Connection OD 7.907 a Connection ID 6.800 in Mate -up Loss 3.700 in. Threads perm 3.28 Connection OD Option REGULAR PERFORMANCE Tension Egfi '[Amey 712% Joint Yield Strength 486296.1000 tntemal Pressura Capadly 6890.006 psi His Compression Erw^ency 87-5% Compression Strength 597.625 AGN Mac Allowable Bending 342 41100 It lbs -xemal Pressure Cape* 4790.000 psi MAKE-UP TORQUES Minimum 8400R4bs Optimum 10100 ftgbz Maumurn 14700 ft -as OPERATION LIMIT TORQUES Clerating Torque 35000 ft4bs Yatld Torque 53000 ft -lbs Page 39 Rev 0 May 2018 Milne Point Unit L-57 SB NB Producer Grilling Procedure Hilcorp E� C-Iwy 17.6 M/U 7-5/8" to DP crossover. 17.7 M/U stand of DP to string, and M/U top drive. 17.8 Break circulation at 1 bpm and begin lowering string. 17.9 Note seal assembly entering tieback sleeve with a pressure increase, Stop pumping and bleed off pressure, leave standpipe bleed off valve open. 17.10 Continue lowering string and land out on no-go. Set down 5 — l0k lbs. Mark the pipe at this depth as "NO-GO DEPTH". 17.11 P/U string & remove unnecessary 7-5/8" joints. 17.12 P/U hanger assembly and space out. M/U (or L/D) necessary joints and pup joints to position seal assembly 1 ft above "NO-GO DEPTH" when tie -back hanger lands out in wellhead. 17.13 Ensure circulation is possible through 7-5/8" string. 17.14 RU and circulation corrosion inhibited brine in the 9-5/8" x 7-5/8" annulus. 17.15 With seals stabbed into SBE, Spot diesel freeze protection from 2500' to surface in 7-5/8" x 9- 5/8" annulus by reverse circulating through the holes in the seal assembly. 17.16 Slack off and land hanger. 17.17 Confirm hanger has seated properly in wellhead. Make note of actual weight on hanger on morning rpt. 17.18 Back out landing joint. M/U packoff running tool and install packoff on bottom of landing joint. Set pack off. RILDS. Test void to 500 psi low for 5 min / 3000 psi high for 10 min. 17.19 R/D casing running tools. \<, \P( 17.20 Test 7-5/8" x 9-5/8" production annulus to 1500 psi for 30 charted minutes after pressure has 17.21 Set test plug and change top rams from 7-5/8" to 2-7/8" x 5-1/2" VBR. Test annular and lower rams on 2-7/8" test joint: 250 psi low / 3000 psi high Page 40 Rev 0 May 2018 Milne Point Unit L-57 SB NB Producer Drilling Procedure Hilcorp gin COMvmr 18.0 Run ESP Assembly — Upper Completion 18.1 RU ESP power cable and 3/8" capillary string spoolers. The capillary strings should be filled with hydraulic fluid. 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 2-7/8" ESP Completion as noted below. The completion includes two 3/8" capillary tube from surface to the ESP assembly. 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. i. Ensure appropriate well control crossovers on rig floor and ready. ii. Monitor displacement from wellbore while RIH. • Centrilift ESP Assembly with bottom of assembly @ ±5,900' MD. ■ Note - ESP set depth to be confirmed after reviewing directional survey) • 10' 2-7/8" 6.54, L-80 Pup Joint • 1 joint 2-7/8" 6.5#, L-80 EUE 8rd tubing • 2-7/8" "XN" nipple @ ±5,750' MD (2.313" packing bore/ 2.205" No -Go ID) • 3 joints 2-7/8" 6.5#, L-80 EUE 8rd tubing • 10' 2-7/8" 6.5#, L-80 Pup Joint • GLM 2-7/8" x 1" GLM w/ dummy installed • 10' 2-7/8" 6.5#, L-80 Pup Joint • 2-7/8" 6.5#, L-80 EUE 8rd tubing • 10' 2-7/8" 6.59, L-80 Pup Joint • GLM 2-7/8" x l" w/ SO @ —140' MD • 10' 2-7/8" 6.5#, L-80 Pup Joint • 3 joints 2-7/8" 6.5#, L-80 EUE 8rd tubing • Tubing Hanger o Check the conductivity of electric cable every 1,000' and every new splice while running in hole. Page 41 Rev 0 May 2018 Milne Point Unit L-57 SB NB Producer Drilling Procedure Hilcotp Fn Co T o Function test the capillary tube every 2,000' when checking the conductivity of the electric cable. o Use Cannon clamps on every joint to secure the capillary tube. o The make up torque values for 2-7/8" L-80 6.5# EUE 8rd tubing are: Minimum: 1,730 ft -Ib, Optimum: 2,300 ft -lb, and maximum: 2,800 ft -lb. o The 2-7/8" L-80 6.5# EUE 8rd tubing performance properties are: Body Yield: 145,000#, Burst: 10,570 psi, Collapse: 11,160 psi. 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 2-7/8" 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. RDMO 19.0 RDMO 19.1 RDMO Doyon 14 Page 42 Rev 0 May 2018 Milne Point Unit L-57 SB NB Producer Drilling Procedure Hilcorp 20.0 Doyon 14 Diverter Schematic 21.114* 2M Pjw- 21-1:3'2At- Drvarn*'T' 21 -IW: Spacer Sp 1&3)4'3& 214 W2M M Page 43 Rev 0 May 2018 21.0 Doyon 14 BOP Schematic Kill Loe --_ Milne Point Unit L-57 SB NB Producer Drilling Procedure /VfVb x SM HCR hole Line II Cate Valve v6IZ- (/,s` Page 44 Rev 0 May 2019 Milne Point Unit L-57 SB NB Producer Drilling Procedure Hilcorp Enmgy Company 22.0 Wellhead Schematic l' 1 • 1 I IIrjCFlyjJ'{'II'Haelll K.3B: NVL f � OSB 4-n3f- V 1 f4� �91 Page 45 Rev 0 May 2018 Yl�Opq.It olfP 5(] f.0 'V icc. Irfr, Page 45 Rev 0 May 2018 Yl�Opq.It olfP 5(] i 'V icc. Irfr, Page 45 Rev 0 May 2018 Milne Point Unit L-57 SB NB Producer Drilling Procedure Hilcorp Enema Compmy 23.0 Days Vs Depth 0 2000 6000 J Q Q 8000 v � 10000 12000 MPU L-57 SB NB Producer Days vs Depth 14000 -- - - - — -- - 16000 II' 0 5 10 15 20 25 Days Page 46 Rev 0 May 2018 Milne Point Unit L-57 SB NB Producer Drilling Procedure Hilcorp Energy Compsoy 24.0 Formation Tops & Information MPU L-57 Formations (Wp09) MD (ft) TVDss (ft) TVD (ft) Formation Pressure (psi) SV5 1520 1392 1434 645.3 Base Permafrost 2240 1824 1866 839.7 SV1 2743 2083 2125 956.25 LA3 5304 3400 3442 1548.9 Schrader NA 6395 3870 3912 1760.4 Schrader NB 6761 3903 3945 1775.25 GENERALIZED GEOLOGICAL ss I I I GEOLOGICAL I COMMENTS TVD FM LRH DESCRIPTION UneormslldstM emrub sed4m sand and I all ow.1 are minor slletom. 17WM Base permafrost III I h`rsedr of sand, cars ead dltamma with... oral 2,00(r..Nngfreamin'aldol dim& cast. a LJS 6L15,ncking .1,11. 'A)'�W luff Schrader Bluff 6,000 caminwd Imwbeds of aaM, tiara and uhatorn i with sSands: eominued cpiore..ftZssaro mtan simadaGaoal.say mwsoml shows of Goa. Tracea.1 Pyrite at 11- 3100 It to ""ft )0' 9 Ugno. hrml1 Pmaible hyAarbne Hari ds54deB k'wry al at H-%00 It can Oe sticky and tight (1-41) 3,000' bSWconofMl l0mnt LdTamlLl.re ..pad I.Me Sd.da, el Ntaand. Nontwm areaM Schrader L -Pad Is dmo imciwe and wet. Bluff Clay htarbods batwaon 5000 and 4M It. tNMau easlre pond M shale below Sands C I xrr- A aasr sunt Y UGNU:earl.. of Gaare.ning upward sande a0hK are !Amen, asses W of: (fmm top to bete.) mane said for sand. 9hyaha1a Bass, developed lrd.rvmirq-I as yes UGNU Progress Into the L and M(dalrerf Ugn. and Schrader Blurt Pmaible hyd,..115ors limited Laandr b S w cameruf Milnedewlo Pmant NMham areais IASI doarol... and wet. -37W assns lAs,cl 'A)'�W luff Schrader Bluff 6,000 sSands: eominued cpiore..ftZssaro mtan simadaGaoal.say to ""ft )0' 9 Ugno. hrml1 Pmaible hyAarbne Hari ds54deB (OA) bSWconofMl l0mnt LdTamlLl.re ..pad I.Me Sd.da, el Ntaand. Nontwm areaM Schrader L -Pad Is dmo imciwe and wet. Bluff `a tNMau easlre pond M shale below Sands sd w. 61N08aaMbrlongx�athwala. I L NOTE: Sm intlivW ual Well Program for specific easing design, depths, sizes. weights, grades and mnneaions. IF SIGNIFICANT AMOUNTS OF GRAVEL ARE ENCOUNTERED WHEN DRILLING THE SURFACE HOLE, THE VISCOSITY OF THE MUD SYSTEM SHOULD IMMEDIATELY BE RAISED TO 150 SEC TO ENSURE EFFECTIVE HOLE CLEANING. .♦ No hydrates encountered on L -Pad drilled to date. Schrader Bluff: Possible lost circulation zone while drilling long strings and running casing. Recommend deep setting surface casing for Kuparuk long strings. Also, the Schrader Bluff sands area potential differential stuck pipe interval if left un -cased for Kuparuk long strings. Page 47 Rev 0 May 2018 N �11C�0� 25.0 Anticipated Drilling Hazards Milne Point Unit L-57 SB NB Producer Drilling Procedure 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 Historically, no gas hydrates have been seen on `L' Pad. Remember that hydrate gas behave differently from a gas sand. Additional fluid density will not prevent influx of gas hydrates. 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 DRILTREAT 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: There are a number of wells in close proximity. Take directional surveys every stand, take additional surveys if necessary. Continuously monitor proximity to offset wellbores and record any close approaches on AM report. Discuss offset wellbores with production foreman and consider shutting in adjacent wells if necessary. Monitor drilling parameters for signs of collision with another well. 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 btwn surge and swab. Bring the pumps on slowly after connections. Monitor conductor for any signs of broaching. Maintain mud parameters and increase MW to combat running sands and gravel formations. H2S: Treat every hole section as though it has the potential for 112S. No H2S events have been documented ✓ on drill wells on this pad. Page 48 Rev 0 May 2018 H Hilcorp En Company Milne Point Unit L-57 SB NB Producer Drilling Procedure 1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic 1-12S 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. 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 > 500 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: V 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 1-12S events have been documented on drill wells on this pad. 1. The AOGCC will be notified within 24 hours if 1-12S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic 1-12S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event 1-12S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Abnormal Pressures and Temperatures: There are no abnormal pressures or temperatures observed on this pad. Page 49 Rev 0 May 2018 Milne Point Unit L-57 SB NB Producer Drilling Procedure Hilcorp ac EvCompany O aenra .L TM ®o® N -I Page 50 Rev 0 May 2018 K Hilcorp E� CM4*y Milne Point Unit L-57 SB NB Producer Drilling Procedure 27.0 FIT Procedure Formation InteLyrity Test (FIT) and Leak -Off Test (LOT) Procedures Procedure for FIT: 1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe). 2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe. 3. Close the blowout preventer (ram or annular). 4. Pump down the drill stem at 1/4 to 1/2 bpm. 5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe. 6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes. Record time vs. pressure in 1 -minute intervals. 7. Bleed the pressure off and record the fluid volume recovered. The pre -determined surface pressure for each formation integrity test is based on achieving an EMW at least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick tolerance in case well control measures are required. Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of stopping at a pre -determined point, surface pressure is increased until the formation begins to take fluid; at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure monitored as with an FIT. Page 51 Rev 0 May 2018 CHOKE MANIFOLD RIG 14 LEGEND White Handled Valves Normally Open Red Handled Valves Normally Closed Date: 08-22-14 Rev.3 NOTES: 1) Valve A is a 3.1116" SM Remote Operated Hydraulic Choke Valve. 2) Valve B is a 3.118" SM Adjustable Choke Valve. 3) Valve 1 is a 2.1116" SM Manual Gate Valve. 4) Valves 2-14 are 3-118" SM Manual Gate Valves. Divert Line From BOP Divert Line To Mud/Gas Separator ►] Milne Point Unit L-57 SB NB Producer Drilling Procedure Hilcorp Ener®' Com? 29.0 Casing Design 11 Calculation & Casing Design Factors Hircorpp DATE: 611812018 WELL: MPU L-57 DESIGN BY: Joe Engel Hole Size 12-1/4" Hole Size 8-1/2" Hole Size Criteria: Mud Density: 9.2 ppg Mud Density: 9.2 ppg Mud Density: Drilling Mode MASP: 1380.5 psi (see attached MASP determination & calculation) MASP: Production Mode MASP: 1380.5 psi (see attached MASP determination & calculation) Collapse Calculation: Section Calculation 1 Normal gradient external stress (0.494 psi/t) and the casing evacuated for the internal stress Pale 53 Rev 0 May 2018 Casing Section Calculation/Specification 1 2 3 4 Casing OD 9-518" 4-1/T' Screens Top (MD) 0 6,611 Top (TVD) 0 3,945 Bottom (MD) 6,761 13,549 Bottom (TVD) 3,945 3,724 Length 6,761 6,938 Weight (ppf) 40 12.6 Grade L-80 LA0 Connection Tv H625 Weight w/o Bouyancy Factor (Ibs) 270,440 87,419 Tension at Top of Section (Ibs) 270,440 87,419 Min strength Tension (1000 Ibs) 916 279 Worst Case Safety Factor (Tension) 3.39 V 3.19 Collapse Pressure at bottom (Psi) 1,949 1,840 Collapse Resistance w/o tension (Psi) 3,090 8,540 Worst Case Safety Factor (Collapse) 1.59 4.84 MASP (psi) 1,381 1,384 Minimum Yield (psi)5,750 9,020 Worst case safety factor (Burst) 4.18 5.52 Pale 53 Rev 0 May 2018 H Hileorp Enc Company Milne Point Unit L-57 SB NB Producer Drilling Procedure 30.0 8-1/2" Hole Section MASP Maximum Anticipated Surface Pressure Calculation Hifc�r 8-1/2' Hole Section MPU L-57 Milne Point Unit MD TVD Planned Top: 6761 3945 Planned TD: 13549 3724 Anticipated Formations and Pressures: Formation TVD TVDss Est Pressure Oil/Gas/Wet PPG Grad Schrader Bluff NB Sand 1 3,945 3,903 1 1736 1 Oil 8.55 0.450 Offset Well Mud Densities Well MW ranee Ton fTVDI Bottom ITVDI nate MPU L-52 8.8-9.35 Surface 3952 2017 MPU L-51 8.9-9.3 surface 3930 2017 MPU L-53 9-9.25 Surface 3891 2717 MPUJ-27 9-9.3 Surface 3666 2015 MPUJ-28 9-9.3 Surface 3617 2015 MPI -19 9-9.3ppg Surface 4,079 2004 MPI -18 9 -SO ppg Surface 3,848 2011 MPI -17 9- 9.5 Surface 3,864 2004 Assumptions: 1. Field test data suggests the Fracture Gradient in the Schrader Bluff is btwn 11.5 and 15 ppg EMW. 2. Maximum planned mud density for the 8-1/2" hole section is 9.5 ppg. 3. Calculations assume full evacuation of wellbore to gas Fracture Pressure at 9-5/8" shoe considering a full column of gas from shoe to surface: 3945 (ft) x 0.78(psi/ft)= 3077.1 3077.1(psi) - ]0.1(psi/ft)'3945(ft)]= 2683 psi MASP from pore pressure (complete evacuation of wellbore to gas from Schrader Bluff NB sand) 3945(ft)x0.45(psi/ft)= 1775.3 si 1775.25(psi)-0.1(psi/ft)"3945(ft) 1380.8 psi Summary: 1. MASP while drilling 8-1/2' production hole is governed by pore pressure and evacuation of entire wellbore togas at 0.1 psi/ft. Page 54 Rev 0 May 2018 H Hil= Milne Point Unit L-57 SB NB Producer Drilling Procedure 31.0 Spider Plot (NAD 27) (Governmental Sections) MPU L-47 SHL ♦ADL025509 Sec. 12 ♦_ ADL388233 _ _ �'-' ♦\' j ` 1///� r �.•. `sir ' 1 r -1 ♦♦♦ 1 '•a" ✓'r �=13'1`♦ /1 9\ I 1 ♦` ��_ lig ) ® // 11 • X Er1301NT UNIT ' `♦ , r ` 'U013N0� % / r o "` ` U013NO10E` r -•: _,_ / 1 O I Sec ' / /r '' g Sec. 18 I~ 1 See. 17 . tfsol i o 1 ADL023374 r1 , ° "moi o° ADL025515 _ter 1 a 1 a a0 F � � 8 Legend ° • MPU L -57 -SHL X MPU LS7_TPH + MPU L-57_SHL Sec 24 24 a° Sec. 19 , d 011ier Surface Holes SSHLy 1633; + M19PU L-�7 13HL� s r CMrer 8ottam Holes (BHL) Other WNd Paths rt . z+ OOiI and Gas Unit Boundary I • Pad Pootp.t E Milne Point Unitj -��5,/71 Well G 1,000 2.000 MPL�.W .w mx: aneara '• g Feet Page 55 Rev 0 May 2018 Milne Point Unit L-57 SB NB Producer Drilling Procedure Hilcorp E>u,6Y camvm7 32.0 Surface Plat (As Built) (NAD 27) >6 I a1 , ,s in o I j I � 1 a I • I I n 7 U 14 1 n i B I w I m I n VIGNITY HAP NOTES- 1. ALASKA STATE PLANE COWLiNATES ARE ZONE 4, I FC.FND ♦ AS-EWLT CONDUCTOR �*LEA11v�" SURVEYOR'S CERTIFICATE X27. 2 9A515 OF LOCAM111 IS L-PAO MCNUMNITS L-1 ■ ENISTNG CONDUCTOR I CERTIFY MAT I AY NORM AND L-2 NO. SI PROPERLY RE L"D /JIp LICENSED WRL PSTATE LANG N 1 ELEVATION OARAI 0 m9M. GRAPHIC SCALE KA MI'IYO M ALASKA ANO IMAs ME STATE 4 EETDEDA ARE M& 3 RE p tY0 2aT Oro MIS AS -R.41 REPRESENTS A 91RKY A WAELN5 0.. 1 PAT WEAN SOAK FACTOR 6 TWea02a N=1750.02 Y BY YE CR LANCER MY pRECT SUP WSK*IVMAT .LLLME B. 041E Of SNRREri. OLTCBEA 6, 101>. IN RET } 014S A10 OMENAVT 7. AEEERDIDE Fl BDLNO R07 -OS POS. 48-54. 1 MCN - 200 R. CORRECTNAS K CCiDDER 9,1=17. LOCATED WITHIN PROTRACTED SEC- S. T. 13 N.. R. 10 E.. UMIAT MERIDIAN. AN. 5235' FEL Y. 6031919.76' N=1735.18' N70.29.53.0793" N70.49807758 151• 3732 FSL Ii-� Irm L-52 X=544548,93' } WI 49'38'05.5235' W149.63486764 32 u I -W - Y=6031906.80' N=1719.96' N70'29'52.9514" 1470.49804205 ■28 ■2B 3719' FSL 15.7' X-54465 ' 9 E- 1224.94' ■24 ■25 1 F / L-56 1 ■20 ■21 N70'29'53.7700' 1470.49826947 15.2' 3802• FSL 15.7, ■14 ■17 X-544734-66' 1335.24' / ■41 643 I - N=1734.93' N70'29'53.6435' N70.49823438 015 3789' FSL ,/ 1&r " -57Y=6031977.71' X=544742.15' E- 1334.81'" /I 13 ■ 5134' F ■ S 30 N=1719.80 N70'29'53.5191" 1470.49819976 i 3776' FSL L-PAD :94 I �• W14938*02.5253' W149.63403480 I 3 ■ ■ to I 16 ■ ■ 47 2 ■ 7 I ■ 13 ■ i b ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ qq 6 35 43a 5 37 11 m C i >6 I a1 , ,s in o I j I � 1 a I • I I n 7 U 14 1 n i B I w I m I n VIGNITY HAP NOTES- 1. ALASKA STATE PLANE COWLiNATES ARE ZONE 4, I FC.FND ♦ AS-EWLT CONDUCTOR �*LEA11v�" SURVEYOR'S CERTIFICATE X27. 2 9A515 OF LOCAM111 IS L-PAO MCNUMNITS L-1 ■ ENISTNG CONDUCTOR I CERTIFY MAT I AY NORM AND L-2 NO. SI PROPERLY RE L"D /JIp LICENSED WRL PSTATE LANG N 1 ELEVATION OARAI 0 m9M. GRAPHIC SCALE KA MI'IYO M ALASKA ANO IMAs ME STATE 4 EETDEDA ARE M& 3 RE p tY0 2aT Oro MIS AS -R.41 REPRESENTS A 91RKY A WAELN5 0.. 1 PAT WEAN SOAK FACTOR 6 TWea02a N=1750.02 Y BY YE CR LANCER MY pRECT SUP WSK*IVMAT .LLLME B. 041E Of SNRREri. OLTCBEA 6, 101>. IN RET } 014S A10 OMENAVT 7. AEEERDIDE Fl BDLNO R07 -OS POS. 48-54. 1 MCN - 200 R. CORRECTNAS K CCiDDER 9,1=17. LOCATED WITHIN PROTRACTED SEC- S. T. 13 N.. R. 10 E.. UMIAT MERIDIAN. AN. WELL A.S.P. PLANT GEODETIC GEODETIC CELLAR SECTION PAD NO. COORDINATES COORDINATES POSITION(OMS) POSITION(D.DD) BOX ELEV. OFFSETS ELEV. L-53 Y=6031932.37' N=1750.02 N70'29'53.20.38' N70.49811216 15.1' 3744 FSL 15.6' 544641.1 E. 1225.10' WI4938'05.7512" W149.63493088 5235' FEL Y. 6031919.76' N=1735.18' N70.29.53.0793" N70.49807758 151• 3732 FSL 15.7' L-52 X=544548,93' = 225.04' WI 49'38'05.5235' W149.63486764 5227' FEL L-51 Y=6031906.80' N=1719.96' N70'29'52.9514" 1470.49804205 15.3' 3719' FSL 15.7' X-54465 ' 9 E- 1224.94' W14 ' 5. 09' W149.63480301 1 F L-56 Y=6031990.50" N=1749.75 N70'29'53.7700' 1470.49826947 15.2' 3802• FSL 15.7, X-544734-66' 1335.24' W1 49 2.9871' W149.63416308 5141' FEL L - N=1734.93' N70'29'53.6435' N70.49823438 15.3' 3789' FSL ,/ 1&r " -57Y=6031977.71' X=544742.15' E- 1334.81'" WI49'3S*OZ7689' W149.63410246 5134' F Y=8031965.09' N=1719.80 N70'29'53.5191" 1470.49819976 18.4' 3776' FSL 15.8• L-54 =544750.50' = 1335.21' W14938*02.5253' W149.63403480 512Y FEL Hilcorp Alaska w m 11P11 L -PAD AS-BVILT CONDUCTOR ♦1•. aOC WFU.S 51-54. 56 A 57 Page 56 Rev 0 May 2018 H Hilcorp Milne Point Unit L-57 SB NB Producer Drilling Procedure 33.0 Schrader Bluff NB Sand Offset MW vs MD Chart 8.5 0 WLS p 8000 12000 m MPU L-57 SB NB Offset MW vs MD EMW, ppg 9.5 10.5 11.5 12.5 —J-27 (2015) —J-28 (2015) —L-53 (2017) —L-52 (2017)—L-51(2017) Page 57 Rev 0 May 2018 H Hilcorp Eaegy c.Wy Milne Point Unit L-57 SB NB Producer Drilling Procedure 34.0 Drill Pipe Information 5" 19.5# S-135 DS -50 & NC50 Drill Pipe Configuration Pipe Body OD + 5.000 Pipe Body Wall Thickness U^ 0.362 Pipe Body Gmde S-135 Drill Pipe Length (mi 3132 Raised Connection GPOS50 Tod Joint OD 6.625 Tod Joint ID ,e: 325D Pin Tog 9 Box Tong m: 12 Drill Pipe Performance Class Nominal Weight Designation Performance of Drill Pipe with Pipe Body at Drill Pipe Approximate Length 80 X Inspect on Class SmoothEdge Height (mi 3132 Raised tl11eia Opemoonal Max Tension Upset Type Toe. moor To ue a+m) man ow 5.125 Tension Only 0 560.800 uaxmum um 43,100 co-ou anxonn 39.600 410,500 rDi City (eemm 0.0169 10-01= 0.0172 Tension Only 0 560,800 15638 - wmee 32.100 1467,400 1 10.029 Pipe OD ss,o: wee: ow �..:ee.nar�Nm eea Connection Performance 80%inspection Class Nominal Weight Designation 19.50 Drill Pipe Approximate Length m131-5 SmoothEdge Height (mi 3132 Raised Tool Joint SMYS inn 120 000 Upset Type IEU Max Upset OD (DTE) ow 5.125 Friction Factor 11.0 .M Tae 'Pore/ mel. nY loi . Drill -Pipe Length Range2 GPDS50 t 6.825 mn OD X 3.250 (ro) ID ) 120,000 cos) -� Role Tne mxlm�m maxe+D Uryee:ndJn h ir{14e.fw Pogo.. nee is R.vrnce cannec�rn aaemmai lemic. a ruri Ra)- s+,rca enJnstsnoue e. gq�. Best Estimates Nominal 71,800 1250.080 fwnxTncmuml r•cn Cowrol roan �vraef usred Wei I t ansae 24.11 2329 'cement (Porn) 0.37 0.36 'cement (eec'n) 0 OW 0.0085 �Iy( 0.70 1 0.72 City (eemm 0.0169 10-01= 0.0172 Pon 17,105 nm 3.125 15638 Farm wigis az us amiwg. icgi 15,672 gm ngv.gra� b aiPo ncM nub menrm, o-nemm Noe watmc. g,n au,er roar, GPDS50 t 6.825 mn OD X 3.250 (ro) ID ) 120,000 cos) -� Role Tne mxlm�m maxe+D Uryee:ndJn h ir{14e.fw Pogo.. nee is R.vrnce cannec�rn aaemmai lemic. a ruri Ra)- s+,rca enJnstsnoue e. gq�. Nominal Tool Joint Torsional Strengm (rt-mr 71,800 1250.080 Tool Joint Tensile Strendh reel Elevator Shoulder Information Smooth Edge Height 3+32 Raised 560800 7 Box OD +�^ 6.812 Elevator Ca auty epi 1,856,800 58,100 Assum-45-219 "n ed Elevator Bore DiameterPoor: Pipe Body Slip Crushing Capacity ®TV Slip Crushing Capadty Assumed Sli Len th Transv rse Loatl Fact( PiDe Bodv Performance Tool Joint Dimensions Balanced OD oni 6.435 'e..ngn tPo�Jeml coer.Pi 5.930 P,eT.m Cbu inn' snmign Tem J[en oom MI5.93 cggnnngv Elevator OD 332 Raised 6.812 on) Pipe Body Configuration ( API Premium Class ar,.un�wa. ur cwsm v.+mmn srtecamv �ra.erP imam. 5 net OD 0.362 ret Wall S-135) Ominal 80 % Inspection Class I API Prtrnium Class 0 396.500 3%.500 rag: suognnc se msansxma mmam.mnsa+sr ,aemne: mmvxy oom MiP Fm m ne s'a aea' YAb n. 'sa b me np x*an am emmea ma Rami ynn mo n b rtew a -n sraawewsaemna'mre oc ngan aq mvsr, mengmia�rmrn ®v'ss.n ton mixeeao�e,w'.gxm.m'emgaem: ea:wrrmme:e ivurxtrernxamJom rmmmg. Pipe Body CoMguretion ( 5 no) OD 0.362 mJ Wall S-1135) Page 58 Rev 0 May 2018 Ntle: NOMNI Burt ovoAe� al RJ.n:e RBW car Poi. Nominal 80%Inspection Class APIPrertnan Class Pipe Tensile §tMa agr MAN 560800 560.800 Pipe Torsional strength +tins, 74,100 58,100 58,100 TJA'ipeBody Torsional Ratio 0.97 124 1.24 80% Pipe Torsional Strength 59300 46,500 46.500 Burst Pon 17,105 15,638 15638 collapse icgi 15,672 10.029 10.029 Pipe OD (no 5.000 4.855 4.855 Wait Thicimess 0.362 0290 0.290 Nominal Poe ID 4276 4276 4.276 Cross Sectional Area of PI Body(m2, f fi 4.154 4.154 Cross Sectional Area of OD ( 19.635 18.514 18.514 Cross Sectional Area of ID ie^3r 14.360 14.360 14.360 section Modulus W!15-708 4.476 14.476 Polar Section Modulus (m^3(11.415 18.953 18.953 Page 58 Rev 0 May 2018 Ntle: NOMNI Burt ovoAe� al RJ.n:e RBW car Poi. W Weatherford 5" 19.50 lb/ft S-135 w/ NC 50 6-5/8" OD x 3-1/4" ID Tool Joint Milne Point Unit L-57 SB NB Producer Drilling Procedure 500204050016200 DRILL PIPE SPECIFICATIONS Grade S-135 Connection NC 50 Interchangeable With 5' XH & 4-112' IF Upset Type IEU Nominal Weight per Foot 19.50 lbs Adjusted Weight With Tool Joint per Foot 23.08 lbs TOOL JOINT DATA Outside Diameter 6-5/8" Inside Diameter 3-1/4' API Drift 3-118' Rabbit OD, Suggested 3-1116" Minimum Make-up Torque 25.900 ft -lbs Maximum Recommend Make-up Torque 26.800 ft -lbs Torsional Yield Strength 51.700 ft -lbs Tensile Strength 1,269,000 IUs TUBE DATA New Premium Outside Diameter 5.000" 4.855' Inside Diameter 4.276" 4.276' Wall Thickness 0.362' 0.290' Cross Sectional Area 5.275 sq in 4.154 sq in Maximum Hook Load/Tensile Strength 712.000 lbs 560,800 lbs Slip Crushing /Slip Type (SDXL) 572.100 lbs 453,500 Itis Burst Pressure 17,100 psi 16,100 psi Collapse Pressure 15000 100 i Torsional Yield Strength 74.70b 8.1.000psb s Capacity W/ Tool Joint 0.726 US autt I 0.726 US al/ft Displacement W/ Tool Joint 0.353 US oaVft 1 0.322 US al/ft Excessive heat or pulling when tube is torqued can cause the maximum pull to decrease. Where possible all figures are obtained from OEM data source. NOTE: Weatherford in no way assumes responsibility or liability for any loss. damage or injury resulting from the use of the information listed above. All applications are for guidelines and the data described are at the user's own risk and are the user's responsibility. Page 59 Rev 0 May 2018 Hilcorp Alaska, LLC Milne Point M Pt L Pad Plan: MPU L-57 MPU L-57 Plan: MPU L-57 WP09 Standard Proposal Report 11 June, 2018 HALLIBURTON Sperry Grilling Services MALLIBURTON® REFERENCE INFORMATION COONiMk INrEI Ranarep.fannw: MP Plan MPI/ LS], TMe RKB Bperny Cnllling asured ep Reference'. MPUL-5Sw D14PMIm RKBQ,9.0QaR(D14RKBp MeasureC ad pw Relerenae: MPI/LS6 anis n14 Prtlim RKa®48 p]usfl(Dt4 RHBI CakuNl'mi MCMaU: Min'vnum CumWn Project: Milne Point Site: M Pt L Pad Well: Plan:MPUL-57 Wellbore: MPUL-57 Design.- MPU L-57 WPO9 IS., Maw. LLC CakuleWn M.. Mlnlmum OunaWre Oran Stare ISCWSA Seen Medved CJ�A,peah Ener SUFam: Elli all C.... 31) Wmmng Madead: Ena Ratio yi 750 0 N I SDO I] an y 2250 F 3800 Sec MD Inc Av WD +N/ -S +E/ -W 1 33.70 000 0.00 33.70 0.00 0.00 2425. W 0.90 8.88 425 AID 8.88 had 3 558.33 4.00 247.00 55823 -1.82 -4.28 4 758.33 12.00 247.00 756.12 -12.68 -29.88 5 099.00 1205 247.80 19087 -10.87 -37.86 8 97008 13.61 257.35 885.14 -20.72 5280 7 105000 22.61 257.35 1036.04 -32.96 -107.45 • 6 155000 42.79 23802 1455.88 -14501 -340.12 9 2012.42 59.00 218.50 1748.40 391.20 E82.]8 18 4500.00 5900 215.50 W2960 -210530 4871.03 11 4683.61 59.19 205.80 3124.10 -2239.84 -1952.33 12 5915.25 WAS 205.80 3754.88 -3192.27 -2412.73 13 6"9.33 85,08 198.58 3917.85 -3859.53 -.88.37 14 87/933 85.00 19850 3944.00 -3942.94 -2695.20 15 6966.41 93.27 195.08 3947.27 -4150.12 -2759.25 16 0161." 93.27 195.05 3879.00 5297.75 -3005.0 1] 8281.46 92.33 192.39 3873.13 5413.99 311485 1S 936785 92.33 192.39 382900 -6474.31 -334].51 19 9592.92 90.12 185.03 3823.00 -669624 3303.08 20 10700.06 90.72 185.83 3009 a8 -779] 5] 3485 49 21 10890.90 91.82 191.73 300493 -7993.96 -3525.01 22 1181504 91.62 191.73 377800 -8091.40 -3712.10 23 1187926 91.82 19335 37]].37 -8944.49 -3723.91 24 13549.14 91.02 193.35 3724 a1)-1053/.19 -411129 WELL DETAILS. Plan BPU Lb] G-nd Level: 15.30 .NIS Er -W Na"Ing Eateng Went. LangAu6e 000 .,On 6031971.]1 5H74215 70'2953.60N 149-W 2769W SECTION DETAILS ,195 "p UPDPTED FORMATKW TOP OETA0. Deng TFace V u Target Annotation pop 0000.00 130`v.W 15.75 SVS Dap oaD o90 1&1 212500 Sen Dir3•n00':r 3.00 247.00 3.25 1,5WM Zr�a IF6 M Ya ra rnpu 7 Start Dir 4-/100':: 4.00 0.00 22.65 tynu lA3 Stlrtader N4 End Dir : 75630' l 0.00 om 28.69 3896.00 Slee Dir 4.1100r:f 4.00 60,00 30.37 _- Stan Olr Yn(W: SW MD. MIS147VD Stan Din 5-1109: 5.00 0.00 69.54 394500 Start Din 4,511109 4So -08.01) MISS SertDir S -1101Y 1 5.00 -5321) 503.04 Endow : 201242' 0.00 9.00 264013 San Dir5°110(:4 5.00 -0155 2794.98 End Dir :468961' 0.00 0.00 3849.51 Stad Dlr51110P:f 5.01) -18.36 4353.01 End Dir :5449.33' 0.00 000 4651.52 MPL57 w,08 Heel Stan Dit 4011 OT:f 4.00 -17.70 4867.84 End on :6965.41' 0.00 0.00 8055.66 MPL-57 wp08 CP1 Star[Dir3-1100':f 3.00 105.16 6174.50 Callan :8201.45' 0.00 0.00 7247.25 MPL-57 apace CP2 SWn Dir 3-/1 WW :9 3.00 -103.64 746599 Shallow : 9592.92' Dao o.op 853423 MPL-57 Wp38 CP3 San Dr391W':1 3.00 81.31 872625 EMo4 :10898.9' 0.00 0.00 963222 MPL-57 wp38 CP4 Stan OW 3°110':1 3.00 82.90 9885.98 End Dir :11870.21 DOo 0.00 11340.11 MPL-57 wade had Taal Depth :1354 070' MD. 81 3]]9 VD NDd---smn DV Ynar'. 1ssa Mn. 1455.eB'IVD ,195 "p UPDPTED FORMATKW TOP OETA0. 6uPVEv tpOcpPM papa Fwm pan Te 5unylwn Taol /s TVDPate WDsaPeNMDPaM Formanm fired Or 3•/100:425 D. 11-14%00 g I\cit; d7 'P Bfi6e PefrllilNN S�OjPfiO3 130`v.W 15.75 SVS a FrC� awm nwrw 'e'lltcss /iTXy1Y - 6tM D,a-Hap' Me, 36 55 M0, 6.2 n 1&1 212500 1817 ad 2078 .00 .4075 274362 se BaP.-h'.PU SV1 o' Sae �Z04 ' 0", fi,A ' 1,5WM Zr�a IF6 M Ya ra rnpu 7 EnC ptr :75333 MDJ58RTN 344297 391297 33M 00 'Wed 5304.35 6335.& tynu lA3 Stlrtader N4 C ING OETMLS 500' SMrt01H11W 8WMD,]9S8TTVD 3945W 3896.00 6781.35 Sdasear NB TVD MD Nama 6125 _- Stan Olr Yn(W: SW MD. MIS147VD 394500 675135 . San .1211" "a _- - Saint Dir <511W: IM MD. 1Q' 04WD 372400 1350.14 41(0.817 N2 NDd---smn DV Ynar'. 1ssa Mn. 1455.eB'IVD ,195 "p y`A _---Endow 2Dh24TMD1748.4'TVD SVS- 1_" SMO '\J p \T \ O g I\cit; d7 'P Bfi6e PefrllilNN S�OjPfiO3 MO' �e \w SN^� 96 MO 1ha 5'('(1) d- H0''h 39\19 M`O 3r.A1S`IO _p ,�J O '3g1 4" ,j6W' 'Ile ,to �10 �' _�/j�OfiB,4l` a FrC� M15 .Z9\Z. 'i1 M0 3901 \.51• Bg 03110\` ea�140 30j3. By6I��n 0O' eSM 00. �M ' 3,((I .'010 SV1 s� 3P eo OM 1,801 .fiptdS, 38'4 .FAl Lal\(p ..rb aK MO. ds e\6\ p6 M0. ""0 0 1I'd, uOI MO. \\fi\h. 0� ), 1, 00 0'Lg\' N O4 .S .S'Ids \O" 14,15 `ql 0\ y l o' Sae �Z04 ' 0", fi,A ' spt 6V` E SPA soc' �' 911, r 040\1 �' y p py 'yg $ p p 50�� S 7VR09 $ q ' MPU LiU9nu X13549 3750b I :� SMeaer NA- a"e � 6enraGer NB _- m 012x81/Y� dW 1121. MPLbT x708 ON MPL57y08CP2 MPL-STxyI:9CP3 MA'S7MW6CP4 rygrL-5]rgO6 Tw 45901 i MPL67 ny201bN 1250 6000 6750 7500 8250 9000 9750 10500 11250 12000 12750 1350 14250 Vertical Section at 201.24° (1500 us1tAn) G_ WL -57 wp08 Heel 9 5/8" x 12 1/4" WL -57 wp08 CPI WL -57 wp08 CP2 FPL -57 wp08 CP3 FP457 wp08 CP4 WL -57 wp(8 Tae 41rz"x812" r WELL DEPAn : Plea: MPUI.57 Ground level: 15.30 +N/ -S +E/ -W Noshing Ewng lamerde Inngitude 0.00 0.00 603197771 544742.15 70° 29 53.644 N 149° 38'2,769 W REFERENCE INFORMATION conNinate (Wf7 Refemnm'. Well Plan: MPU L-57, Tree North Vedicnl (ND) Reference: MPU L -SB "05 D14 Prelim RKB ® 49110usfi (D14 RKB?) Measum l Deplh Reference: MPU L-50vry05 D14 Prelim RKB ®49.000sfl (014 RKB'/) Calwledon Me1h0J: Minimum Curvature S414, F o so'$ F4yA oijPo,. zs',yo '7� (�sO SrS�O� w M Mo try, S Pr:��// ,TssZ O& ZsPo FeyQf lsI/qy 001. I/ . PO/Zqz IS -0 32s0 ' Bran Dir illW: 4500' RID, 3029.61VD 35Po End Dir : 468361'MD,3124.1'TVD 25p Seen 350' Pump Tangent Hold S= Dir P/100': 5915.25' MD, 375486TVD End Dir :64493Y D.. 3917.85'TVD Sun Dir 4"/100': 6749 33' FD. 39449VD End Dir �6WAFMD,3947.27'TVD Start Dir 3°/100': 8 16 1 4P MD, 3879'1'VU End Dir : 8281 06' FD, 3873.13' TVD Stan Dir 3°/100': 9367.95' MD, 3829TVD End Dir : 9592.92' FID. 3823' TVD Sten Dir 3°/100' 10700.06' MD, 3809'I'VD End Dir : 108989' FID, 3804.93' TVD Slav Dir 3°/100: 11815.84' MD, 3P9 -I VD End Dir : 1187026' FD, P7J.37'TVD Total Deprh : 13549.14' FID, 3-/24' TVD -5250 -4500 -3750 -3000 -2250 -1500 -750 0 750 1500 2250 3000 3750 4500 West( -)/East(+) (1500 Dsf /in) T HALLIBURTON Project: Milne Point TVD Site: M Pt L Pad Well: Plan: MPU L-57 eP.•w o.mmR Name Wellbore: MPU L-57 ff 71 Plan: MPU L-57 WP09 G_ WL -57 wp08 Heel 9 5/8" x 12 1/4" WL -57 wp08 CPI WL -57 wp08 CP2 FPL -57 wp08 CP3 FP457 wp08 CP4 WL -57 wp(8 Tae 41rz"x812" r WELL DEPAn : Plea: MPUI.57 Ground level: 15.30 +N/ -S +E/ -W Noshing Ewng lamerde Inngitude 0.00 0.00 603197771 544742.15 70° 29 53.644 N 149° 38'2,769 W REFERENCE INFORMATION conNinate (Wf7 Refemnm'. Well Plan: MPU L-57, Tree North Vedicnl (ND) Reference: MPU L -SB "05 D14 Prelim RKB ® 49110usfi (D14 RKB?) Measum l Deplh Reference: MPU L-50vry05 D14 Prelim RKB ®49.000sfl (014 RKB'/) Calwledon Me1h0J: Minimum Curvature S414, F o so'$ F4yA oijPo,. zs',yo '7� (�sO SrS�O� w M Mo try, S Pr:��// ,TssZ O& ZsPo FeyQf lsI/qy 001. I/ . PO/Zqz IS -0 32s0 ' Bran Dir illW: 4500' RID, 3029.61VD 35Po End Dir : 468361'MD,3124.1'TVD 25p Seen 350' Pump Tangent Hold S= Dir P/100': 5915.25' MD, 375486TVD End Dir :64493Y D.. 3917.85'TVD Sun Dir 4"/100': 6749 33' FD. 39449VD End Dir �6WAFMD,3947.27'TVD Start Dir 3°/100': 8 16 1 4P MD, 3879'1'VU End Dir : 8281 06' FD, 3873.13' TVD Stan Dir 3°/100': 9367.95' MD, 3829TVD End Dir : 9592.92' FID. 3823' TVD Sten Dir 3°/100' 10700.06' MD, 3809'I'VD End Dir : 108989' FID, 3804.93' TVD Slav Dir 3°/100: 11815.84' MD, 3P9 -I VD End Dir : 1187026' FD, P7J.37'TVD Total Deprh : 13549.14' FID, 3-/24' TVD -5250 -4500 -3750 -3000 -2250 -1500 -750 0 750 1500 2250 3000 3750 4500 West( -)/East(+) (1500 Dsf /in) T CASNG DETAILS TVD TVDSS MD Size Name 3945.00 389600 6761.35 9-5/8 95/8"x121/4" 3724.00 3675.00 13549.14 4-1/2 412" x 8 1/2" G_ WL -57 wp08 Heel 9 5/8" x 12 1/4" WL -57 wp08 CPI WL -57 wp08 CP2 FPL -57 wp08 CP3 FP457 wp08 CP4 WL -57 wp(8 Tae 41rz"x812" r WELL DEPAn : Plea: MPUI.57 Ground level: 15.30 +N/ -S +E/ -W Noshing Ewng lamerde Inngitude 0.00 0.00 603197771 544742.15 70° 29 53.644 N 149° 38'2,769 W REFERENCE INFORMATION conNinate (Wf7 Refemnm'. Well Plan: MPU L-57, Tree North Vedicnl (ND) Reference: MPU L -SB "05 D14 Prelim RKB ® 49110usfi (D14 RKB?) Measum l Deplh Reference: MPU L-50vry05 D14 Prelim RKB ®49.000sfl (014 RKB'/) Calwledon Me1h0J: Minimum Curvature S414, F o so'$ F4yA oijPo,. zs',yo '7� (�sO SrS�O� w M Mo try, S Pr:��// ,TssZ O& ZsPo FeyQf lsI/qy 001. I/ . PO/Zqz IS -0 32s0 ' Bran Dir illW: 4500' RID, 3029.61VD 35Po End Dir : 468361'MD,3124.1'TVD 25p Seen 350' Pump Tangent Hold S= Dir P/100': 5915.25' MD, 375486TVD End Dir :64493Y D.. 3917.85'TVD Sun Dir 4"/100': 6749 33' FD. 39449VD End Dir �6WAFMD,3947.27'TVD Start Dir 3°/100': 8 16 1 4P MD, 3879'1'VU End Dir : 8281 06' FD, 3873.13' TVD Stan Dir 3°/100': 9367.95' MD, 3829TVD End Dir : 9592.92' FID. 3823' TVD Sten Dir 3°/100' 10700.06' MD, 3809'I'VD End Dir : 108989' FID, 3804.93' TVD Slav Dir 3°/100: 11815.84' MD, 3P9 -I VD End Dir : 1187026' FD, P7J.37'TVD Total Deprh : 13549.14' FID, 3-/24' TVD -5250 -4500 -3750 -3000 -2250 -1500 -750 0 750 1500 2250 3000 3750 4500 West( -)/East(+) (1500 Dsf /in) T HALLIBURTON Database: Sperry EDM - NORTH US+CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt L Pad Well: Plan: MPU L-57 Wellbore: MPU L-57 Design: MPU L-57 WP09 Project Halliburton Standard Proposal Report Local Corordinate Reference: Well Plan: MPU L-57 TVD Reference: MPU L-56 wp05 D14 Prelim RKB @ 49.00usft (D14 R MD Reference: MPU L-56 wp05 D14 Prelim RKB @ 49.01(D14 R North Reference: True Survey Calculation Method: Minimum Curvature Project Milne Point, ACT, MILNE POINT Map System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level Geo Datum: NAD 1927 (NADCON CONUS) - Using Well Reference Point Map Zone: Alaska Zone 04 Using geodetic scale factor Site M of L Pad, TR -13-10 Plan: MPU L-57 Site Position: Northing: 6,029,799.28usft Latitude: 70° 29' 32.230 N From: Map Easting: 544,529.55usft • Longitude: 149'38'9.412W Position Uncertainty: 0.00 usft Slot Radius: 0° Grid Convergence: 0.34 ° Well Plan: MPU L-57 Magnetics Model Name Sample Date Well Position +N/S 0.00 usft Northing: 6,031,977.71 usft Latitude: 70° 29'53.644 N 81.00 +1 0.00 usft Easting: 544,742.15 usfl Longitude: 149° 38'2.769 W Position Uncertainty 0.00 usft Wellhead Elevation: 15.30 usft Ground Level: 15.30 usft Wellbore MPU L-57 Magnetics Model Name Sample Date Declination C) Dip Angle BGGM2018 7/7/2018 17.14 81.00 Design MPU L-57 WP09 Audit Notes: Version: Phase: PLAN Tie On Depth: 33.70 Vertical Section: Depth From (TVD) +N1S +FJ -W Direction (usft) (usft) (usft) (°) 33.70 0.00 0.00 201.24 Field Strength (nT) 57,461 611112018 12:11:16PM Page 2 COMPASS 5000.1 Build SIE Halliburton H AL L I B U R TO N Standard Proposal Report Database: Sperry EDM - NORTH US + CANADA Local Co-ordinate Reference: Well Plan: MPU L-57 Company: Hiloorp Alaska, LLC TVD Reference: MPU L-56 wp05 D14 Prelim IRKS @ 49.00usft (D14 R Project: Milne Point MD Reference: MPU L-56 wp05 D14 Prelim IRKS @ 49.00usft (D14 R Site: M Pt L Pad North Reference: True Well: Plan: MPU L-57 Survey Calculation Method: Minimum Curvature Wellbore: MPU L-57 Depth Inclination Design: MPU L-57 WP09 System -NIS Plan Sections Measured Vertical TVD Dogleg Build Turn Depth Inclination Azimuth Depth System -NIS +El -W Rate Rate Rate Tool Face (usft) (') (I (usft) usft (usft) (usit) ('1100usft) (*Moousft) ('1100usft) (°) 33.70 0.00 0.00 33.70 -15.30 0.00 0.00 0.00 0.00 0.00 0.00 425.00 0.00 0.00 425.00 376.00 0.00 0.00 0.00 0.00 0.00 0.00 558.33 4.00 247.00 558.23 509.23 -1.82 -0.28 3.00 3.00 0.00 247.00 758.33 12.00 247.00 756.12 70712 -12.68 -29.88 4.00 4.00 0.00 0.00 800.00 12.00 247.00 796.87 74787 -16.07 -37.86 0.00 0.00 0.00 0.00 870.00 13.61 257.35 865.14 81614 -20.72 -52.60 4.00 2.31 14.79 60.00 1,050.00 22.61 257.35 1,036.04 98704 -32.96 -107.15 5.00 5.00 0.00 0.00 1,550.00 42.79 238.02 1,455.68 1,406.68 -145.41 -348.12 4.50 4.04 -3.87 -36.00 2,012.42 59.00 216.50 1,748.40 1,699.40 -391.26 -602.70 5.00 3.50 -4.65 -53.20 4,500.00 59.00 216.50 3,029.60 2,980.60 -2,105.30 -1,871.03 0.00 0.00 0.00 0.00 4,683.61 59.19 205.80 3,124.10 3,075.10 -2,239.84 -1,952.33 5.00 0.11 -5.83 -91.55 5,915.25 59.19 205.80 3,754.86 3,705.86 -3,192.27 -2,412.73 0.00 0.00 0.00 0.00 6,449.33 85.00 198.50 3,917.85 3,868.85 -3,659.53 -2,600.37 5.00 4.83 -1.37 -16.36 6,749.33 85.00 198.50 3,944.00 3,895.00 -3,942.94 -2,695.20 0.00 0.00 0.00 0.00 6,966.41 93.27 195.86 3,947.27 3,898.27 4,150.12 -2,759.25 4.00 3.81 -1.21 -17.70 8,161.44 93.27 195.86 3,879.00 3,830.00 -5,297.75 -3,085.40 0.00 0.00 0.00 0.00 8,281.46 92.33 192.39 3,873.13 3,824.13 -5,413.99 -3,114.65 3.00 -0.79 -2.90 -105.16 9,367.95 92.33 192.39 3,829.00 3,780.00 -6,474.31 -3,347.51 0.00 0.00 0.00 0.00 9,592.92 90.72 185.83 3,823.00 3,774.00 -6,696.24 -3,383.08 3.00 -0.71 -2.92 -103.64 10,700.06 90.72 185.83 3,809.00 3,760.00 -7,797.57 -3,495.49 0.00 0.00 0.00 0.00 10,898.90 91.62 191.73 3,804.93 3,755.93 -7,993.96 -3,525.81 3.00 0.45 2.97 81.31 11,815.84 91.62 191.73 3,779.00 3,730.00 -8,891.40 -3,712.10 0.00. 0.00 0.00 0.00 11,870.26 91.82 193.35 3,777.37 3,728.37 -8,944.49 -3,723.91 3.00 0.37 2.98 82.90 13,549.14 91.82 193.35 3,724.00 3,675.00 -10,577.19 -4,111.29 0.00 0.00 0.00 0.00 6111/2018 12:11:16PM Page 3 COMPASS 5000.1 Build 81E HALLIBURTON Halliburton Standard Proposal Report Database: Company: Project: Site: Well: Wellbore: Design: Sperry EDM - NORTH US + CANADA Hilmrp Alaska, LLC Milne Point M Pt L Pad Plan: MPU L-57 MPU L-57 MPU L-57 WP09 Local Co-ordinate Reference: Well Plan: MPU L-57 TVD Reference: MPU L-56 wp05 D14 MD Reference: MPU L-56 wp05 D14 North Reference: True Survey Calculation Method: Minimum Curvature Prelim RKB @ 49.00usft (D14 R Prelim RKB @ 49.00usft (014 R Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss -NIS +E7 -W Northing Easting DLS Vert Section (usft) (_) (^) (usft) Usti (usft) (usft) (usft) (usft) -15.30 33.70 0.00 0.00 33.70 -15.30 0.00 0.00 6,031,977.71 544,742.15 0.00 0.00 100.00 0.00 0.00 100.00 51.00 0.00 0.00 6,031,977.71 544,742.15 0.00 0.00 200.00 0.00 0.00 200.00 151.00 0.00 0.00 6,031,977.71 544,742.15 0.00 0.00 300.00 0.00 0.00 300.00 251.00 0.00 0.00 6,031,977.71 544,742.15 0.00 0.00 400.00 0.00 0.00 400.00 351.00 0.00 0.00 6,031,977.71 544,742.15 0.00 0.00 425.00 0.00 0.00 425.00 376.00 0.00 0.00 6,031,977.71 544,742.15 0.00 0.00 Start Dir 3-1100': 425' MD, 425'TVD 500.00 2.25 247.00 499.98 450.98 -0.58 -1.36 6,031,977.13 544,740.80 3.00 1.03 558.33 4.00 247.00 558.22 509.22 .1.82 4.28 6,031,975.87 544,737.88 3.00 3.25 Start Dir 4°1100' : 558.33' MD, 558.23'TVD 600.00 5.67 247.00 599.74 550.74 -3.19 -7.51 6,031,974.48 544,734.66 4.00 5.70 700.00 9.67 247.00 698.83 649.83 -8.40 -19.79 6,031,969.19 544,722.41 4.00 15.00 758.33 12.00 247.00 756.11 707.11 -12.68 -29.88 6,031,964.85 544,712.35 4.00 22.65 End Dir : 758.33' MD, 756.12' TVD 800.00 12.00 247.00 796.87 747.87 -16.07 -37.86 6,031,961.41 544,704.39 0.00 28.69 Start Dir4°1100' : 800' MD, 796.877VD 870.00 13.61 257.35 865.14 816.14 -20.72 -52.60 6,031,956.68 544,689.68 4.00 38.37 Start Dir 5°/100' : 870' MD, 865.147VD 900.00 15.11 257.35 894.20 845.20 -22.35 -59.86 6,031,955.01 544,682.43 5.00 42.52 1,000.00 20.11 257.35 989.48 940.48 -28.97 -89.38 6,031,948.21 544,652.96 5.00 59.38 1,050.00 22.61 257.35 1,036.04 987.04 -32.96 -107.15 6,031,944.11 544,635.21 5.00 69.54 Start Dir 4.5'/100': 1050' MD, 1036.04T/D 1,100.00 24.47 254.16 1,081.88 1,032.88 -37.89 -126.49 6,031,939.06 544,615.90 4.50 81.14 1 1,200.00 28.34 248.99 1,171.44 1,122.44 -52.06 -168.59 6,031,924.64 544,573.89 4.50 109.60 1,300.00 32.36 244.98 1,257.73 1,208.73 -71.90 -215.03 6,031,904.52 544,527.58 4.50 144.92 1,400.00 36.48 241.79 1,340.21 1,291.21 -97.28 -265.50 6,031,878.84 544,477.26 4.50 186.87 1,500.00 40.68 239.17 1,418.37 1,369.37 -128.06 -319.72 6,031,847.74 544,423.24 4.50 235.19 1,520.75 41.56 238.68 1,434.00 1,385.00 -135.10 -331.40 6,031,840.63 544,411.60 4.50 245.99 SV5 1,550.00 42.79 238.02 1,455.68 1,406.68 -145.41 -348.12 6,031,830.22 544,394.95 4.50 261.65 Start Dir 5°1100' : 1550' MD, 1455.68'TVD 1,600.00 44.33 235.15 1,491.91 1,442.91 -164.39 -376.87 6,031,811.07 544,366.32 5.00 289.76 1,700.00 47.59 229.88 1,561.44 1,512.44 -208.17 433.81 6,031,766.95 544,309.65 5.00 351.19 1,800.00 51.07 225.15 1,626.62 1,577.62 -259.43 -489.65 6,031,715.37 544,254.12 5.00 419.20 1,900.00 54.73 220.87 1,686.94 1,637.94 -317.77 -543.97 6,031,656.71 544,200.16 5.00 493.25 2,000.00 58.52 216.96 1,741.96 1,692.96 -382.75 -596.35 6,031,591.41 544,148.17 5.00 572.80 2,012.42 59.00 216.50 1,748.40 1,699.40 -391.26 -602.70 6,031,582.87 544,141.87 5.00 583.03 End Dir : 2012A2' MD,1748.4' TVD 2,100.00 59.00 216.50 1,793.51 1,744.51 -451.61 .647.36 6,031,522.26 544,097.59 0.00 655.46 2,200.00 59.00 216.50 1,845.01 1,796.01 -520.51 -698.34 6,031,453.05 544,047.02 0.00 738.15 2,240.75 59.00 216.50 1,866.00 1,817.00 -548.59 -719.12 6,031,424.86 544,026.42 0.00 771.85 Base Permafrost 2,300.00 59.00 216.50 1,896.52 1,847.52 .589.42 -749.33 6,031,383.85 543,996.46 0.00 820.85 2,400.00 59.00 216.50 1,948.02 1,899.02 -658.32 -800.32 6,031,314.65 543,945.89 0.00 903.54 2,500.00 59.00 216.50 1,999.52 1,950.52 -727.22 -851.30 6,031,245.45 543,895.32 0.00 986.24 611112018 12:11:16PM Page 4 COMPASS 5000.1 Build BIE Halliburton H A L L I B U R TO N Standard Proposal Report Database: Sperry EOM - NORTH US + CANADA Local Co-ordinate Reference: Well Plan: MPU L-57 Company: Hilcorp Alaska, LLC TVD Reference: MPU L-56 wp05 D14 Prelim RKB @ 49.00usft (D14 R Project: Milne Point MD Reference: MPU L-56 wp05 D14 Prelim RKB @ 49.00usft (D14 R Site: M Pt L Pad North Reference: True Well: Plan: MPU L-57 Survey Calculation Method: Minimum Curvature Wellborn: MPU L-57 Depth Inclination Azimuth Design: MPU L-57 WP09 +N/ -S +El -W Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth Noss +N/ -S +El -W Northing Easting DLS Vert Section (usft) (1) (1) (usft) usft (usft) (usft) (usft) (usft) 2,002.03 2,600.00 59.00 216.50 2,051.03 2,002.03 -796.13 -902.29 6,031,176.24 543,844.76 0.00 1,068.93 2,700.00 59.00 216.50 2,102.53 2,053.53 -865.03 -953.27 6,031,107.04 543,794.19 0.00 1,151.63 2,743.62 59.00 216.50 2,125.00 2,076.00 -895.09 -975.52 6,031,076.85 543,772.13 0.00 1,187.70 SVt 2,800.00 59.00 216.50 2,154.04 2,105.04 -933.94 -1,004.26 6,031,037.84 543,743.63 0.00 1,234.32 2,900.00 59.00 216.50 2,205.54 2,156.54 -1,002.84 -1,055.25 6,030,968.63 543,693.06 0.00 1,317.02 3,000.00 59.00 216.50 2,257.04 2,208.04 -1,071.74 -1,106.23 6,030,899.43 543,642.50 0.00 1,399.71 3,100.00 59.00 216.50 2,308.55 2,259.55 -1,140.65 -1,157.22 6,030,830.23 543,591.93 0.00 1,482.41 3,200.00 59.00 216.50 2,360.05 2,311.05 -1,209.55 -1,208.21 6,030,761.03 543,541.37 0.00 1,565.10 3,300.00 59.00 216.50 2,411.56 2,362.56 -1,278.46 -1,259.19 6,030,691.82 543,490.80 0.00 1,647.80 3,400.00 59.00 216.50 2,463.06 2,414.06 -1,347.36 -1,310.18 6,030,622.62 543,440.23 0.00 1,730.49 3,500.00 59.00 216.50 2,514.56 2,465.56 -1,416.26 -1,361.16 6,030,553.42 543,389.67 0.00 1,813.19 3,600.00 59.00 215.50 2,566.07 2,517.07 -1,485.17 -1,412.15 6,030,484.21 543,339.10 0.00 1,895.88 3,700.00 59.00 216.50 2,617.57 2,568.57 -1,554.07 -1,463.14 6,030,415.01 543,288.54 0.00 1,978.58 3,800.00 59.00 216.50 2,669.07 2,620.07 -1,622.98 -1,514.12 6,030,345.81 543,237.97 0.00 2,061.27 3,900.00 59.00 216.50 2,720.58 2,671.58 -1,691.88 -1,565.11 6,030,276.61 543,187.41 0.00 2,143.96 4,000.00 59.00 216.50 2,772.08 2,723.08 -1,760.78 -1,616.10 6,030,207.40 543,136.84 0.00 2,226.66 4,100.00 59.00 216.50 2,823.59 2,774.59 -1,829.69 -1,667.08 6,030,138.20 543,086.27 0.00 2,309.35 4,200.00 59.00 216.50 2,875.09 2,826.09 -1,898.59 .1,718.07 6,030,069.00 543,035.71 0.00 2,392.05 4,300.00 59.00 216.50 2,926.59 2,877.59 -1,967.50 -1,769.05 6,029,999.79 542,985.14 0.00 2,474.74 4,400.00 59.00 216.50 2,978.10 2,929.10 -2,036.40 -1,820.04 6,029,930.59 542,934.58 0.00 2,557.44 4,500.00 59.00 216.50 3,029.60 2,980.60 -2,105.30 -1,871.03 6,029,861.39 542,884.01 0.00 2,640.13 Start Dir 5°1100' : 4500' MD, 3029.67VD 4,600.00 59.00 210.67 3,081.14 3,032.14 -2,176.66 -1,918.41 6,029,789.75 542,837.07 5.00 2,723.81 4,683.61 59.19 205.80 3,124.10 3,075.10 -2,239.84 -1,952.33 6,029,726.38 542,803.53 5.00 2,794.99 End Dir : 4683.61' MD, 3124.1' TVD 4,700.00 59.19 205.80 3,132.50 3,083.50 -2,252.52 -1,958.45 6,029,713.67 542,797.48 0.00 2,809.02 4,800.00 59.19 205.80 3,183.71 3,134.71 -2,329.85 -1,995.83 6,029,636.12 542,760.57 0.00 2,894.64 4,900.00 59.19 205.80 3,234.92 3,185.92 -2,407.18 -2,033.22 6,029,558.58 542,723.66 0.00 2,980.26 5,000.00 59.19 205.80 3,286.13 3,237.13 -2,484.51 -2,070.60 6,029,481.03 542,686.75 0.00 3,065.88 5,100.00 59.19 205.80 3,337.35 3,288.35 -2,561.83 -2,107.98 6,029,403.48 542,649.84 0.00 3,151.50 5,200.00 59.19 205.80 3,388.56 3,339.56 -2,639.16 -2,145.36 6,029,325.94 542,612.93 0.00 3,237.11 5,300.00 59.19 205.80 3,439.77 3,390.77 -2,716.49 -2,182.74 6,029,248.39 542,576.01 0.00 3,322.73 5,304.35 59.19 205.80 3,442.00 3,393.00 -2,719.86 -2,184.36 6,029,245.02 542,574.41 0.00 3,326.46 Ugnu LA3 5,400.00 59.19 205.80 3,490.99 3,441.99 -2,793.82 -2,220.13 6,029,170.85 542,539.10 0.00 3,408.35 Start 350' Pump Tangent Hold 5,500.00 59.19 205.80 3,542.20 3,493.20 -2,871.15 -2,257.50 6,029,093.30 542,502.19 0.00 3,493.97 5,600.00 59.19 205.80 3,593.41 3,544.41 -2,948.48 -2,294.88 6,029,015.75 542,465.28 0.00 3,579.59 5,700.00 59.19 205.80 3,644.63 3,595.63 -3,025.81 -2,332.26 6,028,938.21 542,428.37 0.00 3,665.21 5,800.00 59.19 205.80 3,695.84 3,646.84 -3,103.14 -2,369.64 6,028,860.66 542,391.46 0.00 3,750.83 5,900.00 59.19 205.80 3,747.05 3,698.05 -3,180.47 -2,407.03 6,028,783.12 542,354.55 0.00 3,836.45 5,915.25 59.19 205.80 3,754.86 3,705.86 -3,192.27 -2,412.73 6,028,771.29 542,348.92 0.00 3,849.51 Start Dir 5.1100' : 5915.25' MD, 3754.86'TVD 6,000.00 63.27 204.46 3,795.64 3,746.64 -3,259.51 -2,444.25 6,028,703.86 542,317.80 5.00 3,923.61 611112018 12:11:16PM Page 5 COMPASS 5000.1 Build 81E HALLIBURTON Database: Sperry EDM - NORTH US+CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt L Pad Well: Plan: MPU L-57 Wellbore: MPU L-57 Design: MPU L-57 WP09 Planned Survey Measured Well Plan: MPU L-57 Vertical Depth Inclination Azimuth Depth (usft) (•) (1) (usft) 6,100.00 68.09 203.01 3,836.82 6,200.00 72.92 201.64 3,870.19 6,300.00 77.76 200.35 3,895.49 6,395.94 82.41 199.15 3,912.00 Schrader NA 3,821.19 -3,430.09 6,400.00 82.61 199.10 3,912.53 6,449.33 85.00 198.50 3,917.85 End Dir : 6449.33' MD, 3917.85' TVD 4,205.55 6,500.00 85.00 198.50 3,922.27 6,600.00 85.00 198.50 3,930.99 6,700.00 Mot) 198.50 3,939.70 6,749.33 85.00 198.50 3,944.00 Start Dir4°/100' : 6749.33' MD, 39"TVD 6,761.35 85.46 198.35 0 3,945.00 Schrader NB .9 5/8" x 12 114- 542,148.38 6,800.00 86.93 197.88 3,947.57 6,900.00 90.74 196.67 3,949.59 6,966.41 93.27 195.86 3,947.27 End Dir :6966.41' MD, 3947.27' TVD 4,602.44 7,000.00 93.27 195.86 3,945.35 7,100.00 93.27 195.86 3,939.63 7,200.00 93.27 195.86 3,933.92 7,300.00 93.27 195.86 3,928.21 7,400.00 93.27 195.86 3,922.50 7,500.00 93.27 195.86 3,916.78 7,600.00 93.27 195.86 3,911.07 7,700.00 93.27 195.86 3,905.36 7,800.00 93.27 195.86 3,899.65 7,900.00 93.27 195.86 3,893.93 8,000.00 93.27 195.86 3,888.22 8,100.00 93.27 195.86 3,882.51 8,161.44 93.27 195.86 3,879.00 Start Dir 31100' : 8161.44' MD, 38797VD 0.00 8,200.00 92.97 194.75 3,876.90 8,281.46 92.33 192.39 3,873.13 End Dir : 8281.46' MO, 3873.13' TVD 6,027,394.40 8,300.00 92.33 192.39 3,872.38 8,400.00 92.33 192.39 3,868.32 8,500.00 92.33 192.39 3,864.26 8,600.00 92.33 192.39 3,860.19 8,700.00 92.33 192.39 3,856.13 8,800.00 92.33 192.39 3,852.07 8,900.00 92.33 192.39 3,848.01 9,000.00 92.33 192.39 3,843.95 9,100.00 92.33 192.39 3,839.88 r Halliburton Standard Proposal Report Local Co-ordinate Reference: Well Plan: MPU L-57 TVD Reference: MPU L-56 wp05 D14 Prelim RKB @ 49.00usft (D14 R MD Reference: MPU L-56 wp05 D14 Prelim RKB @ 49.00usft (D14 R North Reference: True Survey Calculation Method: Minimum Curvature 611IM18 12:11:16PM Page 6 COMPASS 5000.1 Build 81E Map Map TVDss +N/ -S +PJ -W Northing Easting DLS Vert Section usft (usft) (usft) (usft) (usft) 3,787.82 3,787.82 -3,342.91 -2,480.90 6,028,620.25 542,281.66 5.00 4,014.62 3,821.19 -3,430.09 -2,516.68 6,028,532.87 542,246.41 5.00 4,108.83 3,846.49 -3,520.39 -2,551.32 6,028,442.37 542,212.31 5.00 4,205.55 3,863.00 -3,609.30 -2,583.24 6,028,353.27 542,180.93 5.00 4,299.99 3,863.53 -3,613.11 -2,584.56 6,028,349.46 542,179.63 5.00 4,304.02 3,868.85 -3,659.53 -2,600.37 6,028,302.95 542,164.11 5.00 4,353.01 3,873.27 -3,707.40 -2,616.38 6,028,254.99 542,148.38 0.00 4,403.43 3,881.99 .3,801.87 -2,647.99 6,028,160.34 542,117.35 0.00 4,502.94 3,890.70 -3,896.35 -2,679.60 6,028,065.69 542,086.31 0.00 4,602.44 3,895.00 -3,942.95 -2,695.20 6,028,019.00 542,071.00 0.00 4,651.53 3,896.00 -3,954.31 -2,698.98 6,028,007.61 542,OV.28 4.00 4,663.49 3,898.57 -3,990.96 -2,710.98 6,027,970.89 542,055.51 4.00 4,702.00 3,900.59 -4,086.41 -2,740.66 6,027,875.27 542,026.40 4.00 0 4,801.72 3,898.27 -4,150.12 -2,759.25 6,027,811.46 542,008.20 4.00 4,867.83 3,896.35 -4,182.38 -2,768.42 6,027,779.15 541,999.23 0.00 4,901.22 3,890.63 -4,278.41 -2,795.71 6,027,682.97 541,972.52 0.00 5,000.62 3,884.92 -4,374.45 -2,823.00 6,027,586.78 541,945.81 0.00 5,100.01 3,879.21 -4,470.48 -2,850.29 6,027,490.59 541,919.09 0.00 5,199.41 3,873.50 -4,566.51 -2,877.59 6,027,394.40 541,892.38 0.00 5,298.81 3,867.78 -4,662.55 -2,904.88 6,027,298.22 541,865.67 0.00 5,398.21 3,862.07 -4,758.58 -2,932.17 6,027,202.03 541,838.96 0.00 5,497.60 3,856.36 -4,854.62 -2,959.46 6,027,105.84 541,812.25 0.00 5,597.00 3,850.65 -4,950.65 -2,986.75 6,027,009.66 541,785.54 0.00 5,696.40 3,844.93 -5,046.68 -3,014.04 6,026,913.47 541,758.83 0.00 5,795.80 3,839.22 -5,142.72 -3,041.34 6,026,817.28 541,732.12 0.00 5,895.19 3,833.51 -5,238.75 -3,068.63 6,026,721.09 541,705.41 0.00 5,994.59 3,830.00 -5,297.75 -3,085.40 6,026,662.00 541,689.00 0.00 6,055.66 3,827.90 -5,334.89 -3,095.56 6,026,624.80 541,679.06 3.00 6,093.96 3,824.13 -5,413.99 -3,114.65 6,026,545.60 541,660.45 3.00 6,174.59 3,823.38 -5,432.08 -3,118.62 6,026,527.49 541,656.59 0.00 6,192.90 3,819.32 -5,529.67 -3,140.05 6,026,429.78 541,635.75 0.00 6,291.62 3,815.26 -5,627.26 -3,161.48 6,026,332.07 541,614.90 0.00 6,390.35 3,811.19 -5,724.86 -3,182.92 6,026,234.36 541,594.06 0.00 6,489.08 3,807.13 -5,822.45 -3,204.35 6,026,136.65 541,573.22 0.00 6,587.81 3,803.07 -5,920.04 -3,225.78 6,026,038.94 541,552.38 0.00 6,686.53 3,799.01 -6,017.63 -3,247.21 6,025,941.23 541,531.53 0.00 6,785.26 3,794.95 -6,115.22 -3,268.65 6,025,843.52 541,510.69 0.00 6,883.99 3,790.88 -6,212.81 -3,290.08 6,025,745.81 541,489.85 0.00 6,982.71 611IM18 12:11:16PM Page 6 COMPASS 5000.1 Build 81E Halliburton HALLI B U RTO N Standard Proposal Report Database: Sperry EDM - NORTH US + CANADA Local Comrdinate Reference: Well Plan: MPU L-57 Company: Hilcorp Alaska, LLC TVD Reference: MPU L-56 wp05 D14 Prelim IRKS @ 49.00usft (D14 R Project: Milne Point MD Reference: MPU L-56 wp05 D14 Prelim RKB @ 49.00usft (D14 R Site: M Pt L Pad North Reference: True Well: Plan: MPU L-57 Survey Calculation Method: Minimum Curvature Wellbore: MPU L-57 Map Design: MPU L-57 WP09 Depth Inclination Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/ -S +E/ -w Northing Easting DLS Vert Section (usft) (1 (°) (usft) usft (usft) (usft) (usft) (usft) 3,786.82 9,200.00 92.33 192.39 3,835.82 3,786.82 -6,310.41 -3,311.51 6,025,648.10 541,469.00 0.00 7,081.44 9,300.00 92.33 192.39 3,831.76 3,782.76 -6,408.00 -3,332.95 6,025,550.39 541,448.16 0.00 7,180.17 9,367.95 92.33 192.39 3,829.00 3,780.00 -6,474.31 -3,347.51 6,025,484.00 541,434.00 0.00 7,247.25 Start Dir 3°/100' : 9367.95' MD, 38297VD 9,400.00 92.10 191.45 3,827.76 3,778.76 -6,505.65 -3,354.12 6,025,452.63 541,427.57 3.00 7,278.85 9,500.00 91.39 188.54 3,824.72 3,775.72 -6,604.07 -3,371.47 6,025,354.11 541,410.83 3.00 7,376.88 9,592.92 90.72 185.83 3,823.00 3,774.00 -6,696.24 -3,383.08 6,025,261.88 541,399.77 3.00 7,466.99 End Dir : 9592.92' MD, 3823' TVD 9,600.00 90.72 185.83 3,822.91 3,773.91 -6,703.28 -3,383.80 6,025,254.84 541,399.09 0.00 7,473.81 9,700.00 90.72 185.83 3,821.65 3,772.65 -6,802.76 -3,393.95 6,025,155.31 541,389.54 0.00 7,570.21 9,800.00 90.72 185.83 3,820.38 3,771.38 -6,902.23 -3,404.10 6,025,055.79 541,379.99 0.00 7,666.60 9,900.00 90.72 185.83 3,819.12 3,770.12 -7,001.71 -3,414.26 6,024,956.26 541,370.43 0.00 7,763.00 10,000.00 90.72 185.83 3,817.85 3,768.85 -7,101.18 -3,424.41 6,024,856.74 541,360.88 0.00 7,859.40 10,100.00 90.72 185.83 3,816.59 3,767.59 -7,200.66 -3,434.56 6,024,757.21 541,351.33 0.00 7,955.79 10,200.00 90.72 185.83 3,815.32 3,766.32 -7,300.13 -3,444.72 6,024,657.69 541,341.77 0.00 8,052.19 10,300.00 90.72 185.83 3,814.06 3,765.06 -7,399.61 -3,454.87 6,024,558.16 541,332.22 0.00 8,148.58 10,400.00 90.72 185.83 3,812.79 3,763.79 -7,499.08 -3,465.02 6,024,458.64 541,322.67 0.00 8,244.98 10,500.00 90.72 185.83 3,811.53 3,762.53 -7,598.56 -3,475.18 6,024,359.11 541,313.11 0.00 8,341.38 10,600.00 90.72 185.83 3,810.27 3,761.27 -7,698.03 -3,485.33 6,024,259.59 541,303.56 0.00 8,437.77 10,700.00 90.72 185.83 3,809.00 3,760.00 -7,797.51 -3,495.48 6,024,160.06 541,294.01 0.00 8,534.17 10,700.06 90.72 185.83 3,809.00 3,760.00 -7,797.57 -3,495.49 6,024,160.00 541,294.00 0.00 8,534.22 Start Dir 3-1100': 10700.06' MD, 3809'TVD 10,800.00 91.18 188.79 3,807.34 3,758.34 -7,896.67 -3,508.20 6,024,060.84 541,281.89 3.00 8,631.20 10,898.90 91.62 191.73 3,804.93 3,755.93 -7,993.95 -3,525.81 6,023,963.46 541,264.87 3.00 8,728.25 End Dir :1089801110, 3804.93' TVD 10,900.00 91.62 191.73 3,804.90 3,755.90 -7,995.03 -3,526.03 6,023,962.38 541,264.65 0.01 8,729.33 11,000.00 91.62 191.73 3,802.07 3,753.07 -8,092.90 -3,546.35 6,023,864.40 541,244.92 0.00 8,827.92 11,100.00 91.62 191.73 3,799.24 3,750.24 -8,190.77 -3,566.67 6,023,766.42 541,225.20 0.00 8,926.50 11,200.00 91.62 191.73 3,796.41 3,747.41 -8,288.65 -3,586.98 6,023,668.43 541,205.47 0.00 9,025.09 11,300.00 91.62 191.73 3,793.59 3,744.59 -8,386.52 -3,607.30 6,023,570.45 541,185.75 0.00 9,123.67 11,400.00 91.62 191.73 3,790.76 3,741.76 -8,484.40 -3,627.62 6,023,472.46 541,166.02 0.00 9,222.26 11,500.00 91.62 191.73 3,787.93 3,738.93 -8,582.27 -3,647.93 6,023,374.48 541,146.30 0.00 9,320.84 11,600.00 91.62 191.73 3,785.10 3,736.10 -8,680.14 -3,668.25 6,023,276.49 541,126.57 0.00 9,419.43 11,700.00 91.62 191.73 3,782.28 3,733.28 -8,778.02 -3,688.56 6,023,178.51 541,106.85 0.00 9,518.02 11,800.00 91.62 191.73 3,779.45 3,730.45 -8,875.89 -3,708.88 6,023,080.52 541,087.13 0.00 9,616.60 11,815.84 91.62 191.73 3,779.00 3,730.00 -8,891.39 -3,712.10 6,023,065.00 541,084.00 0.00 9,632.22 Start Dir 3°/100' : 11815.84' MD, 377STM 11,870.26 91.82 193.35 3,777.37 3,728.37 -8,944.49 -3,723.91 6,023,011.84 541,072.51 3.00 9,685.98 End Dir : 11870.26' MD, 3777.37' TVD 11,900.00 91.82 193.35 3,776.42 3,727.42 -8,973.41 -3,730.77 6,022,982.88 541,065.83 0.00 9,715.43 12,000.00 91.82 193.35 3,773.24 3,724.24 -9,070.66 -3,753.84 6,022,885.50 541,043.34 0.00 9,814.43 12,100.00 91.82 193.35 3,770.06 3,721.06 -9,167.91 -3,776.92 6,022,788.13 541,020.85 0.00 9,913.43 12,200.00 91.82 193.35 3,766.88 3,717.88 -9,265.16 -3,799.99 6,022,690.75 540,998.37 0.00 10,012.43 12,300.00 91.82 193.35 3,763.71 3,714.71 -9,362.41 -3,823.07 6,022,593.37 540,975.88 0.00 10,111.44 12,400.00 91.82 193.35 3,760.53 3,711.53 -9,459.66 -3,846.14 6,022,496.00 540,953.40 0.00 10,210.44 611112018 12:11:16PM Page 7 COMPASS 5000.1 Build 81E HALLIBURTON Database: Sperry EDM - NORTH US+CANADA Company: Hilcerp Alaska, LLC Project: Milne Point Site: M Pt L Pad Well: Plan: MPU L-57 Wellbore: MPU L-57 Design: MPU L-57 WP09 Halliburton Standard Proposal Report Local Co-ordinate Reference: Well Plan: MPU L-57 TVD Reference: MPU L-56 wp05 D14 Prelim RKB @ 49.00usft (D14 R MD Reference: MPU L-56 wp05 D14 Prelim RKB @ 49.00usft (1314 R North Reference: True Survey Calculation Method: Minimum Curvature Planned Survey Map +N/ -S +E/ -W Northing Easting DLS Vert Section Measured (usft) 3,708.35 0.00 0.00 3,724.00 Vertical 540,930.91 0.00 10,309.44 Depth Inclination Azimuth Depth TVDss +N/ -S +i (usft) (°) 6,022,106.49 (°) (usft) usft (usft) (usft) 12,500.00 91.82 6,021,911.73 193.35 3,757.35 3,708.35 -9,556.91 -3,869.21 12,600.00 91.82 6,021,716.98 193.35 3,754.17 3,705.17 -9,654.16 -3,892.29 12,700.00 91.82 6,021,522.22 193.35 3,750.99 3,701.99 -9,751.41 3,915.36 12,800.00 91.82 6,021,377.00 193.35 3,747.81 3,698.81 -9,848.66 -3,938.44 12,900.00 91.82 193.35 3,744.63 3,695.63 .9,945.91 -3,961.51 13,000.00 91.82 193.35 3,741.46 3,692.46 -10,043.16 -3,984.58 13,100.00 91.82 193.35 3,738.28 3,689.28 -10,140.41 4,007.66 13,200.00 91.82 193.35 3,735.10 3,686.10 -10,237.66 -4,030.73 13,300.00 91.82 193.35 3,731.92 3,682.92 -10,334.91 -4,053.81 13,400.00 91.82 193.35 3,728.74 3,679.74 -10,432.16 -4,076.88 13,500.00 91.82 193.35 3,725.56 3,676.56 -10,529.40 -4,099.96 13,549.14 • 91.82 193.35 3,724.00 .3,675.00 -10,577.19 .4,111.29 Total Depth : 13549.14' MD, 3724' TVD Targets Target Name Map Map +N/ -S +E/ -W Northing Easting DLS Vert Section (usft) (usft) 3,708.35 0.00 0.00 3,724.00 6,022,398.62 540,930.91 0.00 10,309.44 6,022,301.24 540,908.42 0.00 10,408.44 6,022,203.86 540,885.94 0.00 10,507.45 6,022,106.49 540,863.45 0.00 10,606.45 6,022,009.11 540,840.97 0.00 10,705.45 6,021,911.73 540,818.48 0.00 10,804.45 6,021,814.36 540,795.99 0.00 10,903.46 6,021,716.98 540,773.51 0.00 11,002.46 6,021,619.60 540,751.02 0.00 11,101.46 6,021,522.22 540,728.53 0.00 11,200.46 6,021,424.85 540,706.05 0.00 11,299.47 6,021,377.00 540,695.00 0.00 11,348.11 -hitlmiss target Dlp Angle Dip Dir. TVD +N/ -S +E/ -W Northing -Shape (°) (°) (usft) (usft) (usft) (usft) MPL-57 wpD8 Toe 0.00 0.00 3,724.00 -10,577.19 4,111.29 6,021,377.00 - plan hits target center -Circle (radius 50.00) MPL-57 woos Heel 0.00 0.00 3,944.00 -3,942.94 -2,695.20 6,028,019.00 Easting (usft) 540,695.00 542,071.00 - plan hits target center - Circle (radius 50.00) MPL-57 woos CP2 0.00 0.00 3,829.00 -6,474.31 .3,347.51 6,025,484.00 541,434.00 - plan hits target center - Point MPL-57 woos Ci 0.00 0.00 3,879.00 -5,297.75 3,085.40 6,026,662.00 541,689.00 - plan hits target center - Point 'MPL-57 wp08 Ci 0.00 0.00 3,779.00 -8,891.40 -3,712.10 6,023,065.00 541,084.00 - plan hits target center - Point MPL-57 woos CP3 0.00 0.00 3,809.00 -7,797.57 -3,495.49 6,024,160.00 541,294.00 - plan hits target center Point Casing Points Measured Vertical Casing Hole Depth Depth Diameter Diameter (usft) (usft) Name 13,549.14 3,724.00 41/2"x81/2" - 4-1/2 - 8112 6,761.35 3,945.00 9518"x12114" 9-518 12-1/4 1 6/112018 12:11:16PM Page 8 COMPASS 5000.1 Build 81E HALLIBURTON Database: Sperry EDM - NORTH US +CANADA Company: Hileorp Alaska, LLC Project: Milne Point Site: M Pt L Pad Well: Plan: MPU L-57 Wellborn: MPU L-57 Design: MPU L-57 WP09 Formations Measured Depth (usft) 1,520.75 6,395.94 5,304.35 2,743.62 6,761.35 2,240.75 Plan Annotations Vertical Vertical Depth Depth SS (usft) 1,434.00 3,912.00 3,442.00 2,125.00 3,945.00 1,866.00 Local Co-ordinate Reference: TVD Reference: No Reference: North Reference: Survey Calculation Method: SV5 Schrader NA Ugnu LA3 SV1 Schrader NB Base Permafrost Name Halliburton Standard Proposal Report Well Plan: MPU L-57 MPU L-56 wp05 D14 Prelim RKB @ 49.00usft (D14 R MPU L-56 wp05 D14 Prelim RKB @ 49.00usft (D14 R True Minimum Curvature Lfthology Measured Vertical Local Coordinates Depth Depth +N/ -S +E/ -W (usft) (usft) (usft) (usft) Comment 425.00 425.00 0.00 0.00 Start Dir 3'/100'; 425' MD, 425'TVD 558.33 558.22 -1.82 -4.28 StartDir4°/100': 558.33'MD,558.23'ND 758.33 756.11 -12.68 -29.88 End Dir : 758.33' MD, 756.12' TVD 800.00 796.87 -16.07 -37.86 Start Dir 4°/100': 800'MD, 796.87'ND 870.00 865.14 -20.72 -52.60 Start Dir 5°/1001: 870'MD, 865.14'TVD 1,050.00 1,036.04 -32.96 -107.15 Start Dir4.5°/100': 1050'MD,1036.04'TVD 1,550.00 1,455.68 -145.41 -348.12 Start Dir 5°/100' : 1550' MD, 1455.68'TVD 2,012.42 1,748.40 -391.26 -602.70 End Dir : 2012.42' MD, 1748.4' TVD 4,500.00 3,029.60 -2,105.30 -1,871.03 Start Dir 5°/100': 4500'MD, 3029.67VD 4,683.61 3,124.10 -2,239.84 -1,952.33 End Dir :4683.61' MD, 3124.1' TVD 5,400.00 3,490.99 -2,793.82 -2,220.12 Start 350' Pump Tangent Hold 5,915.25 3,754.86 -3,192.27 -2,412.73 Start Dir 5°/100': 5915.25'MD, 3754.86'TVD 6,449.33 3,917.85 -3,659.53 -2,600.37 End Dir : 6449.33' MD, 3917.85' TVD 6,749.33 3,944.00 -3,942.95 -2,695.20 Start Dir 4°/100': 6749.33'MD, 3944'TVD 6,966.41 3,947.27 -4,150.12 -2,759.25 End Dir : 6966.41' MD, 3947.27' TVD 8,161.44 3,879.00 -5,297.75 -3,085.40 Start Dir 3-/100'; 8161.44' MD, 3879'TVD 8,281.46 3,873.13 -5,413.99 -3,114.65 End Dir : 8281.46' MD, 3873.13' TVD 9,367.95 3,829.00 -6,474.31 3,347.51 Start Dir 3°/100' : 9367.95' MD, 3829'TVD 9,592.92 3,823.00 -6,696.24 -3,383.08 End Dir : 9592.92' MD, 3823' TVD 10,700.06 3,809.00 -7,797.57 -3,495.49 Start Dir 3°/100' : 10700.06' MD, 3809'TVD 10,898.90 3,804.93 -7,993.95 -3,525.81 End Dir : 10898.9' MD, 3804.93' TVD 11,815.84 3,779.00 -8,891.39 -3,712.10 Start Dir 3-/100': 11815.84' MD, 3779'TVD 11,870.26 3,777.37 -8,944.49 -3,723.91 End Dir : 11870.26' MD, 3777.37' TVD 13,549.14 3,724.00 -10,577.19 -4,111.29 Total Depth: 13549.14' MD, 3724' TVD Dip Dip Direction (1) r) 0.00 0.00 0.00 0.00 0.00 61112018 12:11:16PM Page 9 COMPASS 5000.1 Build 81E Hilcorp Alaska, LLC Milne Point MPtLPad Plan: MPU L-57 MPU L-57 MPU L-57 WP09 Sperry Drilling Services Clearance Summary Anticollision Report 11 June, 2018 aeeert Approach 313 PmximNy Swn an Cunem survey Data (NOM Remrenw) Ralxenn Design: M IN L Pad - Plan: MPU LLT - MPU L3 -NPU LS/ WP09 Wall Coordinates: 8.031,9n.71 N, W,742.15 E [/0.29' OW N. 169.38OS/1'W) Datum NNghC MPU 148 wp05 D14 PMI. RKS ® a9.Mm11(o10 RKBi) Scan Range: 0.00 to 13.Re9.16 unit Measured! Depth. Swn Radhn Is 1,500.00 usB. Cleawnw Factor cutoff is Unllminad. Max Ellipse Sepan ion Is Unlimited �Sale Factor Applied Van.: 500D.1 Build: 81E Swn Type: Scan Type: 2500 r HALLIBURTON Sperry Drilling Servieee HALLIBURTON Anticollision Report for Plan: MPU L-57 - MPU L-57 WP09 Hilcorp Alaska, LLC Milne Point CtosestApproach 30 Proximity Scan on Current Survey Date (North Reference Reference Design. MPI LPad - Plan: MPU L -57 -MPU L57 -MPU L47W as Scom Range: 0.00 to 13,549.14 ustl Measured Depth. Scan Radius is 1,500.011 usn. Clearance Factor cutoff is Unlimited. Max Ellipse Separation is Unlimited Measured Minimum @Measured Ellipse QMeasured Clearanm summery Based on Sift Name Depth Distance Depth Separation Depth Factor Minimum Separation Warring Comparison Well Name - Wellbore Name - Design (usft) (usho lush) (ush) usB M PL F Pad MPU F -107 -MPU F-107(OAPmducar)-MPU F-107 5,519.34 739.98 5,519.34 63021 12,049.84 6.030 Centre Distance Pass- MPUF-107-MPU F-107(OA Producer) - MPU F-107 5,65800 748.93 5,650.00 624.60 12,112.04 6.024 Ellipse Separation Pass - MPU F -107 -MPU F -1 070A Producer) - MPU F-107 51950.00 832.60 5,950.00 670.87 12,244.64 5.416 Clearance Factor Pass - MPU F-108 - MPU F -I Oi-MPU PAN 6.202.44 24248 6,202.44 171.57 10,630.29 3.420 Canute Distance Pass - MPU F-108 - MPU F -108i -MPU F-108 6,275.00 251.48 8275.D0 157.58 10,672.11 2.678 Ellipse Separation Pass - MPU F-108 - MPU F -Inst -MPU F -too 6,350.00 27774 6,350.00 16594 10,712.26 2.484 Clearance Factor Pass- MPU F-109- MPU FA09(OA Producer) - MPU F-109 7,080.35 133.15 7,080.35 84.62 10,750.71 2.744 Centre Distance Pass - MPU F -109 -MPU F-109(OA Producer) - MPU F-109 7,200.00 15884 7,20000 6593 10,83282 1.710 Ellipse Separation pass - MPU F -109 -MPU F-109(OA Producer) - MPU F-109 7,225.D0 16949 7,225.00 68,48 10.849.52 1.678 Clearance Factor Pass - MPU F -110 -MPU F410i-MPU F-110 8,258.17 17307 8,250.17 121.0 11,201.28 3.330 Centre Distance Pass - MPU F -110 -MPU F -1101 -MPU F-110 8.37500 191.78 0.375.00 11206 11,28285 2.406 Ellipse Separetion Pass - MPU F -110 -MPU F -1101 -MPU F-110 8,450.00 221.17 8,450.00 121.92 11,332.88 2.229 Clearance Factor Pass - M Pt L Pad MPL-03 - MPL-03 - MPL-03 1,936.96 256.86 1,936.96 236.20 1,925.95 12,479 Clearance Factor Pass - MPL-I3-MPL-I3-MPL-13 1,49632 198.67 1,496.72 183.14 1,535.Es 12.795 Germs Distance Pass- MPL-I3-MPL-I3-MPLA3 1,50000 198.69 1,50000 10.07 1.538.11 12,726 Ellipse Seperston Pass- MPL-I3-MPL-I3-MPL-13 1,625.00 22(1.00 1,625.00 201.51 1,624.76 11442 Clearance Factor Pass - MPL-ifi-MPL46-MPL48 87152 132.41 871.52 120.10 069.44 10.758 Centra Distance Pass- MPL-16-MPL-ifi-MPL-16 875.00 132.44 875.00 12D.00 072.55 10.718 Ellipse Separation Pass- MPL-ifi-MPL-16-MPL-i6 92500 135.43 92500 122.50 916.03 10A73 Clearance Factor Pass- MPL-ifi-MPL-I6A-MPL-16A 871.52 132AI 871.52 120.10 869.44 10,758 Centre Distance Pass- MPL-16-MPL16A-MPL-16A 875.00 13244 87500 120.08 872.55 10.718 Ellipse SePamtion Pass- MPL-I6-MPL-I6A-MPL-16A 925.00 13543 925.00 122.50 918.03 10.473 Clearance Factor Pass - MPL-17-MPL-17-MPL-17 329.80 14823 329.80 144.17 331.81 36.544 Centre Distance Pass- MPL-17-MPL-17-MPL-17 450.00 148.92 450.00 143.40 450.15 26.995 Ellipse Separation Pass- MPL-17-MPL-17-MPL-17 900.00 18554 900.00 174.46 892.44 16743 Cleamnce Factor Pass - MPL-20 - MPL-20 - MPL-20 804.32 156.89 804.32 145.74 77477 14.075 Centre Olslal¢e Pass - 11 J 12018 - 11.59 Page 2 I COMPASS HALLIBURTON Anticollision Report for Plan: MPU L-57 - MPU L-57 WP09 Hilcorp Alaska, LLC Milne Point Closest Approach 3D Proximity Seen on Current Survey Data (North Reference) Reference Design: M Pt L Pad. Plan: MPU L-57 - MPU Ld -MPU L-57 WPOS Scan Range: 0.00 to 13,542.14 man. Measured Depth. Son Radius is 1,500.00 use. Clearance Fahr culottes Unlimited. Max Ellipse Separation is Unlimited Measured Minimum @Measured Ellipse @Measured Clearance Summary Eased on Site Name Depth Distarms Depth Separation Depth Factor Minimum Separation Wamin9 Comparison Well Name - Wellbore Name - Design (us%) (usfl (usR) (usft) USA, MPL-20 - MPL-20 - MPL-20 3,37500 18497 3,375.00 141.27 3,33855 4.232 Ellipse Separation pass - MPL-20-MPL-20-MPL-20 3,500.00 199.05 3.500.00 149.12 3,451.11 3.987 Clearance Factor Pass - MPL-2I-MPL-2I-MPL-21 33.70 119.87 33,70 118.96 30.90 130.937 Centre Distance Pass- MPL-2I-MPL-2I-MPL-21 500.00 121.36 500.00 114.42 49646 17,491 EIIIpse Separation Pass - MPL-21 - MPL-21 - MPL-21 82500 144.47 825.00 132.99 81331 12.587 Clearance Factor Pass - MPL-24-MPL-24-MPL-24 99117 91.39 993.17 77.58 99380 6665 Cenlre Distance Pass- MPL-24-MPL-24-MPL-24 1'000.00 9142 i,Wgial 77.65 1,00028 6,636 Ellipse Separation Pass- MPL-24-MPL-24-MPL-24 1,02500 92.24 1,025.00 70.34 1,023.73 6.635 Cie... Factor Fees - MPL-25-MPL-25-MPL-25 612.92 85.72 612.92 70.30 60239 11.559 Centre Distance Pass - MPL-25-MPL-25-MPL-25 650.00 85.94 650.00 70.07 63943 10.913 Ellipse Separation Pass - MPL-25-MPL-25-MPL-25 825.00 96.30 825.00 85.23 81295 9.556 Clearance Factor Pas3- MPL-28 - MPL-28 - MPL-28 1,04288 59.02 1,04288 44.93 1,035.04 4.190 Ellipse Separation Pass- MPL-28-MPL-20-MPL-28 1,05000 59.06 1,050.00 44.93 1,041.83 4.181 Clearance Factor Paes- MPL-28-MPL-28A-MPL-28A 1,042.88 59.112 1'042.88 44.93 1,035.04 4.190 Ellpse5e,mmon Pass - MPL-28-MPL-28A-MPL-20A 1,050.00 59.06 11050.00 44.93 1,041.83 4.181 Clearance Factor Pass- MPL-39-MPL-29-MPL-29 33.70 Was 33.70 50.97 36.69 65452 Cenlre Distance Pass- MPL-29-MPL-29-MPL-29 47500 62.73 47500 56.87 477.63 10.714 EIIiW Separation Pass- MPL-29-MPL-29-MPL-29 67500 7147 675.00 63.15 67573 8.594 Clearance Factor Pass - MPL32-MPL-32-MPL-32 1,625.84 84.17 1,62564 85.50 1,572.80 4.509 Ellipse Separator, Pasa- MPL-32-MPL-32-MPL32 1,650.00 84.40 1,650.00 65.50 1,59548 4.484 Clearance Factor Pass- MPL33-MPL33-MPL-33 632.53 26.05 632.53 17.91 635.62 3.002 Centre Distance Pass- MPL33-MPL33-MPL33 650.00 26.92 650.00 1733 653.15 2.929 Ellipse Separation Pass - MPL33 - MPL33 - MPL-33 70000 29.30 70000 18.41 702.97 2.860 Clearer. Factor Pass- MPL-34-MPL-34-MPL34 5,582.44 149.40 5,582.44 0554 5,846.76 2.338 Centre Distance pass - MPL-34-MPL-34-MPL-34 5,67500 154.65 5,675.00 78.30 5,930.86 2.026 Elipse Separation Pass - MPL-34 - MPL-34 - MPL34 5,725.00 161.62 5,725.00 00.34 5,975.04 1989 Clearance Factor Pass - MPL-35-MPL-35-MPL35 8,163.08 216.30 8,163.08 11875 7,777.13 2.240 Centre Distance pass - MPL-35-MPL-35-MPL-35 8,27500 224.66 8,275.00 108.66 7,87647 1837 Ellipse Separation Peas - MPL-35-MPL-35-MPL35 8,375.00 243.09 0,375.00 11405 7,95664 1878 dRience Factor Pass - MPL-35 - MPL-35A - MPL-35A 8,163.08 216.30 8.163.08 119.75 7,77793 2240 Centre Distance Paee- 11 d., 2018 - 11:59 Pepe 3 of 9 COMPASS HALLIBURTON Hilcorp Alaska, LLC Milne Point Anticollision Report for Plan: MPU L-57 - MPU L-57 WP09 Closest Approach 30 Proximity Scan an Cement Survey Data (North Reference) Reference Design: M Pt L Pad - Plan: MPU L-57 -MPU L47 - MPU L57 M09 Seen Range: 0.00 to 13,549.14 must. Measured Depth. Scan Radius is 1,500.00 usR. Clearance Facmrcubffls Unlimited. Mas Ellipse Separationis Unlimited Measured Minimum QMeasured Ellipse @Measured Clearance Summary Based on SIM Name Depth Distance Depth Separation Depth Factor Minimum Separa0on blaming Comparison Well Name - Wellbore Name - Design (usfl) lush) (usR) lush) usR MPL.S - MPL-35A - MPL-35A 8,27500 224.66 827500 100.66 7,879.27 1.937 Ellipse Separation Pass - MPL-35-MPL-35A-MPL-35A 8,375.00 243.09 8,375.00 114.05 7.967.44 1.878 Clearance Factor Pass - MPL-35-MPL-35APB1-MPL-35APBI 8,163.08 218.30 81163.08 11935 7,777.83 2.240 Centre Distance Pass - MPL-35 - MPL-35APW - MPL-35APB1 8,275.00 224.66 8,275.00 10866 7,879.27 1.937 Ellipse Separation Pass- MPL-35-MPLJSAP81-MPL-35APB1 8,375.00 24389 8,37500 11405 7,967.44 1.078 Clearance Factor Pass - MPL-35-MPL-35APB2-MPLa5APB2 8.163.08 216]0 8.163.08 119.75 7,777,93 2240 Gene Distance Pass- MPL-35-MPL-35AP82-MPL-35APB2 8,275.00 22466 8,27500 108.66 7,8799 1,937 Ellipse Separation Pass- MPL-35-MPL-35AP82-MPL-35APB2 8,375.00 243.89 0.375.00 114.05 7,967.44 1.878 Clearance Factpr Pass- MPL-35-MPL-35APB3-MPL-35APB3 0,16308 216.30 01163.08 119.75 7,7..93 2.240 Camra Distance Pass- MPL-35-MPL-35APB3-MPL-35APB3 8,27500 224.66 0,275.00 108.66 7,879.27 1837 Ellipse Separation Pass - MPL-35-MPL-35APB3-MPL-35APB3 0.37500 243.89 8,375.00 114.05 7,967.44 1.878 Clearance Factor Pass- MPLa6-MPL-36-MPL-36 4,65000 127.52 4,850.00 58.74 4.78.70 1.854 Clever. Factor Pass- MPLa6-MPL-36-MPL-36 4,675.00 12649 4,675.00 58.25 4,799.87 1.879 Ellipse Separation Pass - MPLJ - MPL-36 - MPL-36 4,72473 12114 4,724.73 62.43 4,842.39 2.053 Centre Distance Pass- MPL-3fi-MPLa6L1-MPL-361-1 4,650.00 127.52 4.650.00 5074 4,778.70 1.854 Clearance Factor Pass- MPL-36-MPLa6Ll-MPL-36L1 4,675.00 12649 4.675,00 50.25 4,799.07 1.079 Ellipse Separation Pass- MPL36-MPL-351-1-MPLa6L1 4,72473 121.74 4,724.73 62.43 4,842.39 2.053 Centre Distance Pass- MPL-36-MP1-36L1 PBI -MPL-36L1 PBI 4,650.00 12]52 4,650.00 5874 4,778.70 1.854 Clearance Factor Pass - MPL-3fi-MPL-3641 FBI -MPL-36L1 PBI 4,67500 12449 4,675.00 5&25 4,799.07 1.079 Ellipse Separation Pass - MPL-3fi-MPL-36L1 PBI - MPL-361-1 PBI 4,724.73 121.74 4,724.73 62.43 4,842.39 2.053 Cede Distance Pass - MPL-3fi-MPL-36PBI-MPL-36PBI 4,650.00 127.52 4,650.00 5874 4,778.70 1.854 Clearance Faclor Pass- MPL-3fi-MPL-36PBI-MPL-36PRI 4,675.00 124.49 4,67500 58.25 4,79907 1.079 Eftse Separation Pass- MPL-3fi-MPL-36PB1-MPL-36PBI 4,724.73 121.74 4,724.73 6263 4,842.39 2053 Centre Distance Pass- MPI-417-MPL-37-MPL-37 7,500.00 250.02 7,590.0 133.90 7488.36 2,153 Clearance Factor Pass- MPL-37-MPL-37-MPL-37 7.575.00 240.92 7,575.00 13040 7,555.27 2.182 Ellipse Separation Pass - MPLJ7 - MPL-37 - MPL-37 7,700.25 235.29 7,700.25 137.09 7,668.41 2.416 Came, Distance Pass - MPL-37 - MPL-37A - MPL-37A 7,50000 250.02 7,500.00 133.90 7,497.56 2.153 Ctearence Factor Pass- MP1-J7-MPL-37A-MPL-37A 7,575.00 240.92 7,57500 130.48 7,564.47 2.182 Ellipse Separation pass - MPLJ7 - MPL-37A - MPL-37A 7700.25 235.29 7,700.25 137.89 7,677.61 2.416 Centre Distance Pass- MPL-39-MPL-39-MPLag 4,020.60 286.3 4,020.60 24075 4.007.19 6.317 Centre Distance Pass - 11 Jur M, 2018 - 1158 Paga 4 of 9 COMPASS HALLIBURTON Anticollision Report for Plan: MPU L-57 - MPU L-57 WP09 Hilcorp Alaska, LLC Milne Point Closest Approach 30 Pmsimlty Bnn on Current Survey Date (North Reference) Reference Design: M Pt L Pad -Plan: MPU L47. MPU L47 - MPU L57 WP09 Scan Range: 0.00 to 13,549.14 usfl. Measured Depth. Sean Radius is 1,500.00 usfl. Clearance Factor cutoff Is Unlimited. Max Ellipse Separation M Ungraded Sea Name Measured Depth Minimum Distance @Measured Depth Ellipse Separation iga.teasured Depth Clearance Summary Based on Factor Minimum t' Wamin Pasta^ 9 Comparison Well Name -Weighers Name - Design (usN) (usfl) (ash) (usfl) usB MPL39-MPL-39-MPL-39 MPL39 - MPL-39 - MPL-39 MPL-43-MPL43-MPL43 MPL43-MPL43-MPL43 MPL43-MPL43-MPL43 4,125.00 4,425.00 447.32 52500 90000 28949 329.21 178.23 178.62 210.26 4,12500 4,425.00 447.32 52500 900.00 23173 262.46 172.54 172.12 198.94 4,104.51 4,305.34 449.72 527.58 899.54 5,593 Ellipse separation 4.932 Cleemnce Factor 31,332 Centre Datums 27461 Ellipse Separation 18.572 Clearares Fodor Pass - Pass- Pass- Pass - Pass - MPL43 - MPL43PB1 - MPL43PB1 MPL43-MPL43P01-MPL43PBI MPL43-MPL43PB1-MPL43PBI MPL45-MPL45-MPL45 MPL45- MPL45- MPL45 MPL45-MPL45-MPL45 447,32 52500 900.00 453.42 750.00 4,02500 178.23 178.62 210.26 232.45 233.25 1,492.47 447.32 525.00 900.00 453.42 75000 4,025.00 17233 171.91 198.73 227.15 224.38 1,41578 449.72 527.50 899.54 45386 735.88 3,687.04 30.190 Centre Distance 26.500 Ellipse Sepaafron 18.230 Clearance Factor 43.927 Centre Distance 26309 Ellipse Sepaation 19.461 Clearance Factor Pass - Pass- Pass- Pass - Pass - Pass- MPL48-MPL48-MPL48 MPL46-MPL48-MPL48 MPL48 - MPL48 - MPL48 MPL4B-MPL48PBI-MPL40P61 MPL48-MPL48PBI-MPL48P01 MPL48-MPL40PB1-MPL48PBI 33.70 5,100.00 5.250.00 5,137.85 5,15000 5.225.00 627,95 WAS 649.21 579.11 579.16 581.60 33.70 51100.00 5,250.00 5.137.85 5.150.00 5,22500 62204 559.91 565.59 408.54 48954 491.27 30.00 5,016.89 5,130ID 5,057.82 5,06553 5,124.19 600.853 Centre Distances 7.823 Ellipse Separation 7.764 Clearance Factor 6.466 Centra Distance 6,463 Ellipse Separation SAM Clearance Factor Pass- Pass - Pass - pass - Pass - Pass- MPL48-MPL-4BP02-MPL48PB2 MPL48-MPL40PB3-MPL48 PB3 MPL48-MPL48PB3-MPL48 PB3 MPL4B-MPL48PB3-MPL48 PB3 MPL-50-MPL-50-MPL-50 MPL-50-MPL-50-MPL-50 5.164.05 3370 5,100.00 5,250.00 170.41 7,800.00 M.70 627.95 64196 64921 625A3 62683 51fi4.05 33.70 5,1000(1 5,250.00 178.41 7,80000 488.54 627.04 559.91 56559 62255 48829 5,084.08 30.00 5,016.89 5,130.07 180.92 7,017.22 6.479 Clearance Factor 688.653 Centre Distanw 7.823 Ellipse Sepaation 7.764 Clearance Factor 217000 Centre Distance 4A60 Clasen Fader Pass - pass - Pass- PasS- Pass - Pass- MPU L31 -MPU L -5I -MPU L51 MPU L-51 - MPU L-51 - MPU L-51 MPU L -5I -MPU LSI - MPU L-51 MPU L -52 -MPU L -52 -MPU L-52 MPU L -52 -MPU L -52 -MPU L52 MPU L -52 -NPU L52 -MPU L52 62.67 250.00 13,549.14 2,009.28 2.07500 13.549.14 110.88 111.15 730.88 7603 77.71 790.13 62.67 250.00 13,549.14 2,00928 2,078.00 13,549.14 109.76 107.79 480.66 62A6 61.14 532.59 55.87 242.19 13,143.93 1,917,A 1,901.02 14,000.00 99,800 Centre Distance, 33.044 Ellipse Separation 2.921 Clearance Fapmr 5.604 Centre Dictate. 4.691 Ellipse Separation 3.068 Clearence Fodor Pass - Pass - Pass - Pass - Pass - Pass- MPU L33 -MPU L.53 -MPU L-53 33.70 110.75 33.70 109.84 26.50 121.454 Centre Dislance Pass - 11 June, 2010 - 11:59 Page 5 of9 COMPASS HALLIBURTON Anticollision Report for Plan: MPU L-57 - MPU L-57 WP09 Hilcorp Alaska, LLC Milne Point Closest Approach 30 Proximity Scan on Currant Survey Data North Reference) To sumey)Plan Survey Too] (--ft) (usft) Reference Design: MPI LPad - Plan: MPU L -57 -MPU L -57 -MPU L52 WP09 33.70 900.00 MPU L-57 WP09 2Gy-SR-GSS 90000 6,800.00 Soon Range: 0.00 to 13,549.14 usft. Measured Depth. 2_MWD+IFR2-MS-S, 6,800.00 13,54a14 MPU L-57 WP09 2 MWD*IFR2+MS-Sag Scan Radius Is 1,500.00 usft. Clearance Factor cutoff is Unliml.d. Max Ellipse Separation Is UnIImIMd Measured Minimum ®Measured Ellipse @Measured Clearance Summary Eased on Site Name Depth Distance DeptM1 Separation Depth Factor Minimum SepareBon Warning Comparison Well Name - Wellbore Name - Design htafo (usft) (usft) (--ft) usft MPU L -53 -MPU L -53 -MPU L53 200.00 11168 209011 10895 191.14 40909 Ellipse Seperntmn Pass - MPU L -53 -MPU L -53 -MPU L53 900.00 157.22 90000 145.75 042]2 13.713 Cloa2rce Factor Pass - MPU L-5fi-MPU L -56 -MPU L56 200.05 14.68 200.05 11.44 200.42 4.535 Centra Distance Pass - MPU L56 -MPU L56 -MPU L-56 300.00 1525 300.00 1027 300.13 3.063 Ellipse Separa0on Pass - MPU L56 -MPU L -56 -MPU L56 40000 18.57 40000 11.05 399,60 2.763 Clearance Factor Pass- PMn. MPU L41- MPU L41 - MPU L41 wp07 957.57 174.13 957.57 16040 974.86 12.680 Ellipse Separation Peso - Plan :MPU L41 -MPU L41 -MPU L41 wpW 1,000.00 175.37 1.00000 161.39 1.01424 12.543 Clearance Factor Pasa- PIan:MPU 455 -MPU L-55-MPL-55 wp06 425.00 210.32 425.00 204.94 427.00 39.134 Centre Distance Pass - Plan: MPU L -55 -MPU L-55-MPL-55 wp06 550.00 210.96 559.00 204.05 551.91 30.515 Ellipse Separation Pass - Plan :MPUL55-MPU L-55-MPL-55 wp06 925.00 235.09 92500 223.60 92026 20,459 Clearance Factor Pass- RIG: MPU L54 -MPU L -54 -MPU LS WP10 27500 15.13 275-00 1059 275.10 3.330 Centre Distance Pass - RIG :MPU L54 -MPU L -54 -MPU L-51 VAPID 40000 15.71 400.00 8.99 400.00 2336 Ellipse Separation Pess- RIG :MPU L54 -MPU L -54 -MPU L-54 WP10 45000 17.09 45000 9.50 44962 2.250 Clearance Factor Pass - Well #1 L-53 Row- Well #1- Well#2 Tangelo wp01 916.64 63.09 91664 51.66 912.81 5.522 Centre Distance Pass - Well #1_L53 Row- Well #1. Well 02 TaMels wp01 92500 63.13 925.00 51.63 920.93 5492 Ellipse Separation Pass - Well M1_L-53 Row- Well #1- Well #2 Targets wool 950.00 63.74 95000 52.04 945.22 5.450 Clearance Factor Pass - Survey tool program From To sumey)Plan Survey Too] (--ft) (usft) 33.70 900.00 MPU L-57 WP09 2Gy-SR-GSS 90000 6,800.00 MPU L-57 WP09 2_MWD+IFR2-MS-S, 6,800.00 13,54a14 MPU L-57 WP09 2 MWD*IFR2+MS-Sag if Jym, 2019 - 11:59 Page6of9 CG.MRASS HALLIBURTON Anticollision Report for Plan: MPU L-57 - MPU L-57 WP09 Ellipse tamer tetma are correlated across surrey tool tie -en points. Calculated ellipses Inceq to surface errors. Separation is the actual distance beRveen ellipsoids. Distance Belvreen tames is Me straight lire distance heWeen wellbore renins. Clearance Factor= Cheraw Behveen Pei / (Distance Betwreen pimples - Ellipse Sepam4on). Ap station coon inates vrere plCuleted using the Minimum Curvature method. Hilcorp Alaska, LLC Milne Point if iana. 2015 - 11:59 peps ]0/9 COMPASS iF1ALLIBIJRTON Project: Milne Point REFERENCE INFCRM4TbN WEIL pEtMSRen: FNU 45> NM I93]M/DCCti CONUS) NaYn lmeOl Site: MPtLPad Well: Plan: MPU L-57 e,.,xwi. rxrel xn.�.M.: w. rw.:MPU rs.Jm. w.n a°0 ��"°�po:RP"Im, Aalsieg 9'.aNni°pu nl en na cocoa 6wel. I53o +ws .Pr -w w�xg Fmine Luwxe to�ynw. Wellbore: MPU L-57 N„'> k ns,N�e .m .rv, r . wN sa0 aag 6g319nn w]4x.ls mxv s3_M4N 14V 3B 3]69w Plan: MPU L,57 WP03 SURVEY PROGMM GLOBAL FILTER: Usi rq user EefircE seaclion 6 "mnp ulleN CepN Fm m DePM To surveyNlen Tool 33]0 BOU 00 MPU LS7 WP09 2GyroSRGse BW 00 F800.00 MPU LS] W F09 2 MJYpIFR3+ILS Ms+sep ® Ladder/S.F. Plots 33.]0 TO 13569.14 CA DEER WN.00 1]549.14 MPU LS/WPo9 2MWD+IFR2.Ms+seg Typ TVp55 M1m Six Name 3945.0 1M OO 676135 9 -SN 959'' I2 W" 3]23.0 36!5.00 13549.14 4-U3 412''8 VT' 15000 o MPL 3611 Pt31 y ( �f 1 III o 012000 L - I, I M b5fi MPy 3QP81,-.-_ .. MPL d6 Y r o MPL2 MPL 36L1 I 9000 I M Not—,naZ7 MPL 29.' 1 MPU L 52 i .4PLa2 - rg¢t 1 MPL-36 - MPL-34 --- --_-- MPU F-109 U SO WP 0 MPL2'. O or 30 MP LSBL 33 % U 0.00 MPU L-SIYrP10 0 700 1400 210 2800 3500 4200 4900 5600 6300 7000 7700 8400 91W 9800 10500 1120D 11900 12600 13300 Measured Depth (1400 usfUin) 4.51 `o � 3.00 LL j I m Collision Risk Procedures R4, I j N 1.50 - Collision Awitlance Req. I I No -Go Zone - Slop Drilling 0.01 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750 10500 11250 12000 12750 13500 Measured Depth (1400 usft/in) Remark: AOGCC PTD No. 218-072 Coordinate Check 25 June 2018 INPUT Geographic, NAD27 OUTPUT State Plane, NAD27 5004 -Alaska 4, U.S. Feet MPU L-57 1/1 Latitude: 70 29 53.64400 Northing/Y: 6031977.735 Longitude: 149 38 02.76900 Easting/X: 544742.145 Convergence: 0 20 41.66493 Scale Factor: 0.999902274 Corpscon v6.0.1, U.S. Army Corps of Engineers TRANSMITTAL LETTER CHECKLIST WELL NAME: {w /� `._ — S 7 ZDevePTD: 0 72- Development lopment Service _ Exploratory _ Stratigraphic Test _ Non -Conventional FIELD: leu O Ti POOL: ��r` 1� ✓ �l�T� �i/ Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI The permit is for a new wellbore segment of existing well Permit LATERAL No. , API No. 50 - (If last two digits Production should continue to be reported as a function of the original in API number are API number stated above. between 60-69 In accordance with 20 AAC 25.005(1), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well Pilot Hole name ( PH) and API number (50- -� from records, data and logs acquired for well name on permit). The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce/inject is contingent upon issuance of a conservation Spacing Exception order approving a spacing exception. (Company Name) Operator assumes the liability of any protest to the spacing exception that may occur. All dry ditch sample sets submitted to the AOGCC must be in no greater Dry Ditch Sample than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. Please note the following special condition of this permit: production or production testing of coal bed methane is not allowed for Non -Conventional (name of well) until after (Company Name) has designed and Well implemented a water well testing program to provide baseline data on water quality and quantity. (Company Name) must contact the AOGCC to obtain advance approval of such water well testing program. 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 (Company Name) in the attached application, the following well logs are also required for this well: Well Logging Requirements 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. Revised 2/2015 POINT, SCHRADER BLFF OIL - Well Name: MILNE PT UNIT L-57 Program DEV _ __ _ Well bore seg ❑ PTD#:2180720 Company _HILCORP.ALA_S LLC Initial Class/Type DEV / PEND GeoArea 890 Unit 11328 On/Off Shore On A Administration 17 Nonconven, gas conforms to AS31,05,030G..1.A),Q.2,A-D) _ _ _ ........... . .... NA 1 Permit fee attached NA 2 Lease number appropriate... _ _ _ _ _ _ _ _ .. - _ - _ _ _ Yes _ Surface Location lies within ADL00255Q9; Top Prod Int & TO lie within ADL0025515. 3 Unique wellname and number - - - - - - - - - - - - - _ ...... - - - _ Yes 4 Well located ina. defined pool _ _ .. . ................... Yes _ _ _ _ _ Milne Point Schrader Bluff Oil Pool (525140), governed by CO 477, amended by CO 477.05, 5 Well located proper distance from drilling unit boundary_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ ____ Yes _ CO 477.05 specifies no restrictions as to well spacing except that no pay shall be opened 6 Well located proper distance from other wells__ _ _ _ _ _ _ _ _ _ _ _ _______ _ _ _ Yes _ _ in a well closer than 500 feet from the.exterior boundary of the affected area.. 7 Sufficient acreage. available in drilling unit _ _ .... ....... Yes Well bore will be more than 500 feet to the exterior boundary of the CO 477 area. 8 If deviated, is wellbore plat. included _ _ _ _ _ _ _ _ _ ...... Yes 9 Operator only affected party.. _ _ _ Yes 10 Operator has. appropriate bond in force _ _ _ Yes _ Appr Date 11 Permit can be issued without conservation order Yes 12 Permit can be issued without administrative approval _ _ _ Yes _ ID 6/25/2018 13 Can permit be approved before 15-daywait. _ _ _ _ _ _ _ _ _ Yes 14 Well located within area and strata authorized by Injection Order# (put 10# In. comments) (For NA 15 All wells within 114 mile area of review identified (For service well only) _ _ _ _ _ _ _ _ .. NA 16 Pre -produced injector. duration of pre production less than 3 months. (For service well only) _ _ NA 18 Conductor string. provided _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes _ _ _ _ 16" conductor setat 114k_ Engineering 19 Surface casing. protects all known USDWs _ _ ....... NA No aquifers_ permafrost area. 20 CMT vol adequate to circulate. on conductor & surf csg Yes _ 9 5/8". casing will be fully cemented.. ES cementer 21 CMT. vol adequate to tie-in long string to surf csg.. _ _ _ _ _ _ _ Yes 22 CMT. will cover all known productive horizons . . _ . . . . . . . _ _ _ _ _ Yes _ _ _ running slotted liner in the lateral. 23 Casing designs adequate for C, T, B 8. permafrost _ _ ..... _ Yes 24 Adequate tankage or reserve pit _ Yes _ _ _ Rig has steel pits. All waste to approved disposal wells. 25 If re -drill, has. a 10-403 for abandonment been approved _ _ _ _ _ NA _ _ grassroots well '.26 Adequate wellbore separation. proposed...... Yes No issues.... latest directional is WP 09 27 If diverter required, does it meet regulations _ _ _ _ _ _ _ Yes _ _ _ Using diverter to drill 12.25" hole.to SB sand._ ROPE thereafter... Appr Date I28 Drilling fluidprogram schematic & equip list adequate Yes _ Max form pressure =_1756 psi ( 8.65 ppg EMW ). will drill. with 8.9.-9.5 ppg mud GLS 6/29/2018 29 BOPEs,. do they meet regulation _ _ _ _ _ _ _ _ _ _ _ Yes 30 BOPE press rating appropriate; test to (put psig in comments). Yes _ Doyon 14 rig.... 31 Choke manifold complies w/API RP -53 (May 84)... _ _ _ _ _ _ Yes 32 Work will occur without operation shutdown_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ __ Yes 33 Js presence of H2S gas probable _ . . .......... _ _ _ Yes _ _ _ _ H2S on pad, 34 Mechanical condition of wells within AOR yerified (Foir service well only) _ _ _ _ _ _ _ _ _ _ NA ...... ... ........................ . ..... 35 Permit can be issued w/o hydrogen sulfide measures. _ No _ _ _ H2S not anticipated from drilling of offset wells; however, rig will have H2S sensors and alarms.. Geology 36 Datapresented on potential overpressure zones _ _ _ _ _ _ _ _ Yes _ _ _ _ Gas hydrates and geopressure not expected from drilling of offset wells, _ Appr Date 37 Seismic analysis of shallow ges_zones _ _ _ _ _ .. _ ... NA.. Operator's.planned. mud weights appear sufficient to control. expected formation pressures, _ SFD 6/25/2018 38 Seabed condition survay (if offshore) _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - - _ - NA 39 Contact name/phone for weekly. progress reports [exploratory only] _ _ _ _ _ .........NA Geologic Engineering Public Targeting SB NB sand Commissioner: Date: Commissioner: Date Commissioner Date k_]�) Irti 4�"kc'�. -4 lZ1,e,