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Home My WebLink About220-0711. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Install Whipstock Perforate Other Stimulate Cut Tubing Change Approved Program 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 17,221 feet N/A feet true vertical 3,911 feet N/A feet Effective Depth measured 17,221 feet 7,289' & 8,196'feet true vertical 3,911 feet 3,538' & 3,766'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 7,192' 3,506' Perm. TNT Packers and SSSV (type, measured and true vertical depth)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: Operations Manager Contact Phone: 4,790psi 8,540psi 6,870psi 5,750psi 6,890psi 9,020psi 8,368' 3,772' Burst N/A Collapse N/A 4,760psi 3,090psi Liner 8,207' 9,025' Casing Conductor 3,767' 3,911' 8,207' 17,221' 5,887' 2,481'Surface Surface Tieback 20" 9-5/8" 9-5/8" 169' 2,481' measured TVD 7-5/8" 4-1/2" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 220-071 50-029-23689-00-00 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: ADL025515, ADL0025517 & ADL0025906 MILNE POINT / SCHRADER BLUFF OIL MILNE PT UNIT I-40 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) 181 Gas-Mcf MD 169' 3,245 Size 169' 1,916' 834 320133 770 285923 272 324-038 Sr Pet Eng: Sr Pet Geo: Sr Res Eng: WINJ WAG 306 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. N/A Todd Sidoti todd.sidoti@hilcorp.com 907-777-8443 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 2:46 pm, Aug 13, 2024 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143) Date: 2024.08.13 13:42:04 - 08'00' Taylor Wellman (2143) DSR-8/21/24 RBDMS JSB 082224 _____________________________________________________________________________________ Revised By: TDF 8/9/2024 SCHEMATIC Milne Point Unit Well: MPU I-40 Last Completed: 7/10/2024 PTD: 220-071 TD =17,221’(MD) / TD =3,911’ (TVD) 20” Orig. KB Elev.: 68.20’ / GL Elev.: 33.6’ 7-5/8” 13 15 17 9-5/8” 2 5 & 6 10 Tubing Cut @ 7,244’’ See Screen Liner Detail PBTD =17,221’ (MD) / PBTD = 3,911’ (TVD) 9-5/8” ‘ES’ Cementer @ 2,481’ MD 4-1/2” Shoe @ 17,221’ 14 16 12 8&9 11 1 3 4 7 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20" Conductor 129.5 / X52 / Weld N/A Surface 169’ N/A 9-5/8" Surface 47 / L-80 / TXP 8.681 Surface 2,481’ 0.0758 9-5/8” Surface 40 / L-80 / TXP 8.835 2,481’ 8,368’ 0.0732 7-5/8” Tieback 29.7 / L-80 / Hyd 521 6.875 Surface 8,207’ 0.0459 4-1/2” Liner 250ђ Screens 13.5 / L-80 / Hyd 625 3.920 8,196’ 17,221’.0149 TUBING DETAIL 3-1/2" Tubing 9.3# / L-80 / EUE 8rd 2.992 Surface 7,192’ 0.0087 4-1/2" Tubing 12.6# / L-80 / TXPM 3.958 7,244’ 8,204’ 0.0152 OPEN HOLE / CEMENT DETAIL 20” Driven 12-1/4"Stg 1 Lead – 950 sx / Tail – 400 sx Stg 2 Lead – 690 sx / Tail – 270 sx 8-1/2” Cementless Screened Liner WELL INCLINATION DETAIL KOP @ 334’ Max Hole Angle = 96° @ 10,678’ MD TREE & WELLHEAD Tree Cameron 2-9/16" 5M w/ 4-1/16” 5M Cameron Wing Wellhead Cameron 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs GENERAL WELL INFO API: 50-029-23689-00-00 Drilled & completed by Doyon 14 - 12/17/2020 Convert to JP by ASR#1 – 4/2/2024 Convert to ESP by ASR#1 –7/10/2024 JEWELRY DETAIL No. Top MD Item ID 1 173’ 3-1/2" x 1" GLM w/ BEK-DPSOV 2 6,988’ 3-1/2" x 1" Patco GLM W/ BK-DGLV 3 7,049’ XN-Nipple 2.813" Profile,2.750" No-Go 4 7,102’ Discharge Sub w/ Bolt On Discharge: 400X, 416 SS 5 7,104’ Pump #2: 400, SF3550,72S, INC,15,1:1AR, SHB, TS3 6 7,126’ Pump #1: 400, SFNPSH78,57S,15,1:1AR, SHB, TS3 7 7,148’ Intake: GS,400, TDM, H2X, SS, INC, D15 8 7,153’ Upper Tandem Seal: 400 Series, BPBSL, Inconel Shaft, UT, SLUB, HD 9 7,151’ Lower Tandem Seal: 400 Series, BPBSL, Inconel Shaft, SLUB, HD 10 7,169’ Motor: 456 series, FMS2, 150HP/2460/43, 10 Rotor 11 7,187’ BHI Zenith Gauge and Cetralizer –Btm @ 7,192’ 12 7,289’ 7-5/8” x 4-1/2” Permanent Packer, Halliburton TNT 3.856” 13 7,356’ XN Nipple, 3.813” Profile, 3.750” No Go 3.750” 14 8,174’ WLEG – Bottom @ 8,204’ 3.958” 15 8,196’ BOT SLZXP LTP / Liner Hanger 7” x 9-5/8” 3,766’ TVD 6.190” 16 8,217’ 7” H563 x 4.5” TSH 625 XO 3.850” 17 17,219’ Shoe 3.950” 4-1/2” SCREEN LINER DETAIL Jts Top (MD) Top (TVD) Btm (MD) Btm (TVD) 9 8374’ 3772’ 8754’ 3773’ 2 9041’ 3789’ 9125’ 3793’ 12 9285’ 3798’ 9791’ 3793’ 1 9911’ 3798’ 9953’ 3801’ 2 10158’ 3816’ 10242’ 3822’ 2 10437’ 3835’ 10521’ 3837’ 3 10846’ 3816’ 10969’ 3809’ 1 11269’ 3805’ 11311’ 3805’ 6 11758’ 3815’ 12010’ 3808’ 12 12310’ 3823’ 12815’ 3842’ 19 12851’ 3844’ 13651’ 3871’ 83 13688’ 3875’ 17184’ 3911’ Well Name Rig API Number Well Permit Number Start Date End Date MP I-40 ASR#1 & WH 50-029-23689-00-00 220071 7/7/2024 7/10/2024 7/5/2024 - Friday No operations to report. 7/3/2024 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary No operations to report. 7/4/2024 - Thursday No operations to report. Continue POOH w/ Slickline and Caliper in 7-5/8" CSG, download data - good. RU to run 3-1/2" ESP. PU/MU Summit motor, seals, pumps and service. Maintain 10bbl/hr hole fill. RIH w/ 3-1/2",9.3#,L, EUE R2 (USED) TBG, Summit ESP completion @ 60fpm testing ESP electrical systems every 1000' - T/ 6,389'. No operations to report. 7/6/2024 - Saturday POOH w/ 4-1/2",12.6#,L, TXP-BTC SR Jet Pump completion F/ 7,244' to surface pumping 2x displacement. Slickline RIH to TBG stub @ 7,251' SLM (E-Line MD= 7,244') with 6.70" Junk Basket - recovered 4.50" x 2" Name Plate from ESP & 5" of TEC. 2nd Junk Basket run - empty. Caliper 7-5/8" CSG from TBG stub. 7/9/2024 - Tuesday 7/7/2024 - Sunday MIRU ASR-1. Test BOPE 250/2500psi as per Sundry. Work up to 88K (23K overpull) TBG free at 65K PUW. LD Hanger. Establish losses at16bbls/hr. WELLHEAD: BOP test complete, pull CTS plug and Bpv with T bar.. MU 4 1/2 TC11 LJ to tbg hgr, BOLDS and pull to floor BO and lay down. Will be running 3 1/2 ESP hgr. 7/8/2024 - Monday Well Name Rig API Number Well Permit Number Start Date End Date MP I-40 ASR#1 & WH 50-029-23689-00-00 220071 7/7/2024 7/10/2024 No operations to report. No operations to report. 7/13/2024 - Saturday No operations to report. 7/16/2024 - Tuesday 7/14/2024 - Sunday No operations to report. 7/15/2024 - Monday 7/12/2024 - Friday No operations to report. 7/10/2024 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary Continue RIH w/ 3-1/2",9.3#,L, EUE R2 (USED) TBG, Summit ESP completion @ 60fpm testing ESP electrical systems every 1000' - F/ 6,389'. Splice at 624' test - good. P/U M/U landing JT and hanger. Align penetrator. Summit perform hanger splice - Cable tested good. Install ESP ambilical cord. Land hanger with BPV installed. Once landed, good cable test. RILDS. Pick HCR choke/kill lines, ND BOP stack. Install production tree and torque. BPV pulled, test void 500/5000psi - good. ESP final tests through tree - good. 7/11/2024 - Thursday No operations to report. 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: 7/30/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20240730 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BCU 14B 50133205390200 222057 5/22/2024 YELLOW JACKET PERF BCU 14B 50133205390200 222057 6/11/2024 YELLOW JACKET GPT-PLUG-PERF BCU 19RD 50133205790100 219188 7/17/2024 AK E-LINE Perf BRU 222-26 50283201950000 224035 7/1/2024 AK E-LINE CBL BRU 222-26 50283201950000 224035 7/11/2024 AK E-LINE PressureTemp CLU 16 50133207200000 224021 5/16/2024 YELLOW JACKET SCBL CLU 16 50133207200000 224021 5/31/2024 YELLOW JACKET SCBL END 2-14 50029216390000 186149 5/9/2024 YELLOW JACKET PLUG KU 33-08 50133207180000 224008 5/9/2024 YELLOW JACKET GPT-PLUG-PERF MPU H-08B 5.00292E+13 201047 7/14/2024 READ CaliperSurvey MPU I-40 50029236890000 220071 7/6/2024 AK E-LINE TubingCut MPU R-101 50029237930000 224078 7/16/2024 YELLOW JACKET SCBL MPU S-17 50029231150000 202173 7/12/2024 AK E-LINE TubingCut MPU S-17 5.00292E+13 202173 7/18/2024 READ CaliperSurvey PBU NK-43 50029229980000 201001 6/11/2024 YELLOW JACKET PL PBU PTM P1-13 50029223720000 193074 7/4/2024 YELLOW JACKET PL Pearl 11 50133207120000 223032 7/10/2024 AK E-LINE Plug/Perf Please include current contact information if different from above. T39310 T39310T T39311T T39312T T39312 T39313 T39313 T39314 T39315 T39316 T39317 T39318 T39319 T39319 T39320 T39321 T39322 MPU I-40 50029236890000 220071 7/6/2024 AK E-LINE TubingCut Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.07.30 13:09:33 -08'00' 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: 7/12/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20240712 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# MPU B-24 50029226420000 196009 7/8/2024 READ Caliper Survey MPU I-40 50029236890000 220071 7/4/2024 READ Caliper Survey MPU I-40 50029236890000 220071 7/9/2024 READ Caliper Survey PCU 2 50283200229000 179009 7/8/2024 AK E-LINE Tubing cut Revision Explanation: There are additional images added to the final report and a few new .las files. In the Emeraude folder there are 2 new .las files and in the Field Data folder the RIH and POOH are new .las files Please include current contact information if different from above. T39179 T39180 T39180 T39181 MPU I-40 50029236890000 220071 7/4/2024 READ Caliper Survey MPU I-40 50029236890000 220071 7/9/2024 READ Caliper Survey Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.07.15 10:32:44 -08'00' 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Tubing Cut Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: Convert to ESP 2.Operator Name: 4.Current Well Class:5.Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating:8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9.Property Designation (Lease Number):10.Field: 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 17,221'N/A Casing Collapse Conductor N/A Surface 4,760psi Surface 3,090psi Tieback 4,790psi Screened Liner N/A Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14.Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16.Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Brian Glasheen Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng Milne Point Schrader Bluff Oil N/A 3,911' 17,221' 3,911' 1,004 N/A Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY MPU I-40 AOGCC USE ONLY Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): 2/15/2023 Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL025515, ADL025517 & ADL025906 220-071 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 50-029-23689-00-00 Hilcorp Alaska LLC C.O. 477.05 Length Size Proposed Pools: 169' 169' 12.6# / L-80 / TXPM TVD Burst 8,204' N/A MD N/A 6,890psi 6,870psi 5,750psi 1,916' 3,772' 3,767' 2,481' 8,368' 169' 20" 9-5/8" 9-5/8" 2,481' 7-5/8"8,207' 5,887' 8,207' See Schematic 9,025' See Schematic 4-1/2" 3,911'4-1/2" 7-5/8" x 4-1/2" Perm. & BOT SLZXP LTP and N/A 7,289 MD/ 3,538 TVD & 8,196MD/ 3,766 TVD and N/A Brian.Glasheen@hilcorp.com 907-564-5277 17,221' Perforation Depth MD (ft): No Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov Wells Manager By Grace Christianson at 7:59 am, Jan 26, 2024 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143) Date: 2024.01.25 16:11:34 - 09'00' Taylor Wellman (2143) 324-038 DSR-1/26/24 10-404 02FEB SFD 1/31/2024 1,004 * BOPE pressure test to 2500 psi. MGR02FEB24JLC 2/5/2024 2/5/24Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2024.02.05 14:39:45 -09'00' RBDMS JSB 081224 Convert to ESP Well: MPU I-40 Date: 01/18/2024 Well Name:MPU I-40 API Number:50-029-23689-00-00 Current Status:JP Oil well Pad:I-Pad Estimated Start Date:02/15/2024 Rig:ASR #1 Reg. Approval Req’d?Yes Date Reg. Approval Rec’vd: Regulatory Contact:Tom Fouts Permit to Drill Number:220-071 First Call Engineer:Brian Glasheen 907-545-1144 Second Call Engineer: AFE Number:TBD Job Type:Convert to ESP Gauge Pressure:1,249 psi at 3,490’ TVD |EMW = 6.9 ppg Maximum Expected BHP:1,381 psi at 3,772’ TVD |EMW = 7.1 ppg MPSP:1,004 psi Gas Column Gradient = 0.1 psi/ft Brief Well Summary: Well I-40 was drilled by Doyon 14 as a Schrader Bluff NB sand producer. With new development planned at I pad requiring more power fluid than capacity allows, I-40 was selected to convert to ESP. I-40 has a known fluid rate and BHFP target to stay above to minimize sand production. I-40 also lacks a BHPG to monitor JP wear causing missed opportunity to optimize production. Converting to ESP will allow constant monitoring of production and ensure the well is optimized on a daily basis. Notes Regarding the Well & Design o DD Packoff above JP Objective: x Pull JP Completion x Run new 4-1/2” ESP completion. Non Sundry work: SL 1. Pull DD pack off and JP 2. Leave SS open for circulation 3. Caliper well from deviation to surface 4. Set TTP in XN at 7356’ MD and CMIT TXIA to 1500 psi for ESP casing test. 5. Pull TTP at 7356’MD. EL 1. RIH with well tec cutter and cut tubing at 7242’ MD. ( 5’ below full joint 22 on TT below.) Convert to ESP Well: MPU I-40 Date: 01/18/2024 Pre-Rig Procedure: 1. Clear and level pad area in front of well. Spot rig mats and containment. 2. RU Little Red Services. RU reverse out skid and 500 bbl returns tank. 3. Pressure test lines to 3,000 psi. 4. Circulate at least one wellbore volume with 8.4 ppg produced water or source water down tubing, taking returns up casing to 500 bbl returns tank. Heat fluids to help with thick crude prior to circulating. 5. If returns are not seen, after attempting circulation down the tubing, bullhead and load the tubing, IA and OA. 6. RD Little Red Services and reverse out skid. 7. RU crane. Set CTS BPV. ND Tree. NU BOPE. RD Crane. 8. NU BOPE house. Spot mud boat. Item Jt Description ID " OD " LENGTH Total TOP BTM. (in) (in) (ft) Length (ft) (ft) 1 4.5" TXPM, L=80 , 12.6# ,WLEG 3.958 5.000 29.95 1.50 8,174.43 8,204.38 2 1 4.5" TXPM, L=80 , 12.6#3.958 5.000 38.92 40.42 8,135.51 8,174.43 3 2 4.5" TXPM, L=80 , 12.6#3.958 5.000 40.62 81.04 8,094.89 8,135.51 4 3 4.5" TXPM, L=80 , 12.6#3.958 5.000 40.7 121.74 8,054.19 8,094.89 5 4 4.5" TXPM, L=80 , 12.6#3.958 5.000 40.69 162.43 8,013.50 8,054.19 6 5 4.5" TXPM, L=80 , 12.6#3.958 5.000 40.59 203.02 7,972.91 8,013.50 7 6 4.5" TXPM, L=80 , 12.6#3.958 5.000 40.65 243.67 7,932.26 7,972.91 8 7 4.5" TXPM, L=80 , 12.6#3.958 5.000 40.7 284.37 7,891.56 7,932.26 9 8 4.5" TXPM, L=80 , 12.6#3.958 5.000 40.57 324.94 7,850.99 7,891.56 10 9 4.5" TXPM, L=80 , 12.6#3.958 5.000 39.85 364.79 7,811.14 7,850.99 11 10 4.5" TXPM, L=80 , 12.6#3.958 5.000 40.58 405.37 7,770.56 7,811.14 12 11 4.5" TXPM, L=80 , 12.6#3.958 5.000 39.85 445.22 7,730.71 7,770.56 13 12 4.5" TXPM, L=80 , 12.6#3.958 5.000 40.58 485.80 7,690.13 7,730.71 14 13 4.5" TXPM, L=80 , 12.6#3.958 5.000 40.42 526.22 7,649.71 7,690.13 15 14 4.5" TXPM, L=80 , 12.6#3.958 5.000 40.65 566.87 7,609.06 7,649.71 16 15 4.5" TXPM, L=80 , 12.6#3.958 5.000 40.03 606.90 7,569.03 7,609.06 17 16 4.5" TXPM, L=80 , 12.6#3.958 5.000 39.2 646.10 7,529.83 7,569.03 18 17 4.5" TXPM, L=80 , 12.6#3.958 5.000 40.41 686.51 7,489.42 7,529.83 19 18 4.5" TXPM, L=80 , 12.6#3.958 5.000 40.99 727.50 7,448.43 7,489.42 20 19 4.5" TXPM, L=80 , 12.6#3.958 5.000 40.91 768.41 7,407.52 7,448.43 21 20 4.5" TXPM, L=80 , 12.6#3.958 5.000 40.59 809.00 7,366.93 7,407.52 22 4.5" TXPM, L-80, 12.6#,Pup Joint 3.958 5.000 9.39 818.39 7,357.54 7,366.93 23 4.5" HES XN-Nipple 9Cr 3.750 5.006 1.66 820.05 7,355.88 7,357.54 24 4.5" TXPM, L-80, 12.6#,Pup Joint 3.958 5.000 9.42 829.47 7,346.46 7,355.88 25 21 4.5" TXPM, L=80 , 12.6#3.958 5.000 40.95 870.42 7,305.51 7,346.46 26 4.5" TXPM, L-80, 12.6#,Pup Joint 3.958 5.000 9.88 880.30 7,295.63 7,305.51 27 4.5" TXPM, L-80, 12.6#,Crossover 3.958 5.260 1.23 881.53 7,294.40 7,295.63 28 7-5/8" x 4-1/2" TNT Packer 3.856 6.375 5.46 886.99 7,288.94 7,294.40 29 4.5" TXPM, L-80, 12.6#,Crossover 3.958 4.959 1.3 888.29 7,287.64 7,288.94 30 4.5" TXPM, L-80, 12.6#,Pup Joint 3.958 5.000 9.83 898.12 7,277.81 7,287.64 31 22 4.5" TXPM, L=80 , 12.6#3.958 5.000 40.09 938.21 7,237.72 7,277.81 32 4.5" TXPM, L-80, 12.6#,Pup Joint 3.958 5.000 5.71 943.92 7,232.01 7,237.72 33 4.5" TXPM, L-80, 12.6#,Crossover 3.958 5.000 1.1 945.02 7,230.91 7,232.01 34 4-1/2", L-80, 12.6#, Intake Ported Pressure Sub 3.958 5.925 1.24 946.26 7,229.67 7,230.91 35 4.5" TXPM, L-80, 12.6#,Crossover 3.958 5.000 1.28 947.54 7,228.39 7,229.67 38 4-1/2", L-80, 12.6#, Sliding Sleeve 3.813 5.600 4.25 951.79 7,224.14 7,228.39 39 4.5" TXPM, L-80, 12.6#,Crossover 3.958 5.000 1.3 953.09 7,222.84 7,224.14 42 4-1/2", L-80, 12.6#, Zenith C6 Gauge Carrier 3.958 5.965 5.75 958.84 7,217.09 7,222.84 43 4.5" TXPM, L-80, 12.6#,Crossover 3.958 5.000 1.23 960.07 7,215.86 7,217.09 44 4.5" TXPM, L-80, 12.6#,Pup Joint 3.958 5.000 5.85 965.92 7,210.01 7,215.86 45 23 4.5" TXPM, L=80 , 12.6#3.958 5.000 39.72 1,005.64 7,170.29 7,210.01 Convert to ESP Well: MPU I-40 Date: 01/18/2024 RWO Procedure (Sundry Required): 1. MIRU Hilcorp ASR #1 WO Rig, ancillary equipment, and lines. 2. Check for pressure. If needed, bleed off any residual pressure off tubing and casing. If needed, kill well w/ 8.4 produced water/ Source water prior to setting CTS Plug. Set CTS Plug. 3. Test BOPE to 250 psi Low/ 2,500 psi High, annular to 250 psi Low/ 2,500 psi High (hold each ram/valve and test for 5-min). Record accumulator pre-charge pressures and chart tests. a. Perform Test per ASR 1 BOP Test Procedure b. Notify AOGCC 24 hours in advance of BOP test. c. Confirm test pressures per the Sundry Conditions of approval. d. Test VBR rams on 4-1/2’’ test joints. e. Submit to AOGCC completed 10-424 form within 5 days of BOPE test. 4.Contingency: (If the tubing hanger won’t pressure test due to either a penetrator leak or the BPV profile is eroded and/or corroded and BPV cannot be set with tree on.) a. Notify Operations Engineer (Hilcorp), Mr. Mel Rixse (AOGCC) and Mr. Jim Regg (AOGCC) via email explaining the wellhead situation prior to performing the rolling test. AOGCC may elect to send an inspector to witness test. b. With stack out of the test path, test choke manifold per standard procedure c. Conduct a rolling test: Test the rams and annular with the pump continuing to pump, (monitor the surface equipment for leaks to ensure that the fluid is going down-hole and not leaking anywhere at surface.) d. Hold a constant pressure on the equipment and monitor the fluid/pump rate into the well. Record the pumping rate and pressure. e. Once the BOP ram and annular tests are completed, test the remainder of the system following the normal test procedure (floor valves, gas detection, etc.) f. Record and report this test with notes in the remarks column that the tubing hanger/BPV profile / penetrator wouldn’t hold pressure and rolling test was performed on BOP Equipment and list items, pressures and rates. 5. Bleed any pressure off tubing and casing to the returns tank. Pull CTS, lubricate if pressure expected. Kill well as needed. 6. MU landing joint or spear and BOLDS. 7. Attempt to pull tubing. a. PU weight 2021 RWO was 65k SO was 31K b. Do not exceed 80 percent of 4-1/2” tubing. 8. Recover the tubing hanger. 9.Contingency (If a rolling test was conducted): MU new hanger or test plug to the completion tubing. Re- land hanger (or test plug) in tubing head. Test BOPE per standard procedure. 10. POOH and lay down the 4-1/2’’ tubing. Rig up spooler for TEC cable. a. Inspect the Tubing and discard all bad tubing off site. Review caliper and ask OE joints to keep. b. Plan to reuse all tubing (Pending Caliper results) c. Make sure to account for all clamps below: i. 92 clamps 11. PU new ESP and RIH on 4-1/2’’ tubing. Set base of ESP assembly at ± 7200 MD (42’ from tubing cut). Colors indicate assemblies to be bucked up prior to RWO. Nom. Size ~Length Item Lb/ft Material Notes Convert to ESP Well: MPU I-40 Date: 01/18/2024 4- 1/2''Centralizer ~7200 MD 12.6 L-80 4- 1/2''Sensor, Zenith 12.6 L-80 Baker 4- 1/2''Motor 12.6 L-80 Summit 4- 1/2''Lower Tandem Seal 12.6 L-80 Summit 4- 1/2''Upper Tandem Seal 12.6 L-80 Summit 4- 1/2''Gas Avoider 12.6 L-80 Summit 4- 1/2''Gas Seperator 12.6 L-80 Summit 4- 1/2''Pump 12.6 L-80 Summit 4- 1/2''Pump 12.6 L-80 Summit 4- 1/2''Zenith Ported Sub Press Port 12.6 L-80 Baker 4- 1/2'' 1 joint 12.6 L-80 4- 1/2''10'Pup Joint 12.6 L-80 4- 1/2''4-1/2' XN nip 12.6 L-80 4- 1/2''10'Pup Joint 12.6 L-80 4- 1/2''Joints 12.6 L-80 4- 1/2''Space out PUPS 12.6 L-80 4- 1/2'' 1 joint 12.6 L-80 4- 1/2''PUP 12.6 L-80 4- 1/2''Tubing Hanger 12.6 L-80 12. PU and MU the tubing hanger with landing joint. Make the final splice of the ESP cable to the penetrator. Plug off any additional control line ports if present. 13. Land the tubing hanger and RILDS (Caution do not damage the Cable when landing). Lay down landing joint. Note Pick-up and slack-off weights on tally. 14. Set TWC. 15. RDMO ASR. Post-Rig Procedure: 1. RD mud boat. RD BOPE house. Move to next well location. 2. RU crane. ND BOPE. 3. NU the tubing head adapter and tree. Test tubing hanger void and tree to 500 psi low/5,000 psi high. 4. Pull TWC. 5. RD crane. Move returns tank and rig mats to next well location. Convert to ESP Well: MPU I-40 Date: 01/18/2024 6. Replace gauge(s) if removed. 7. Turn well over to production. RU well house and flowlines. Attachments: 1. As-built Schematic 2. Proposed Schematic 3. BOP stack sketch _____________________________________________________________________________________ RevisedBy: NLW 12-23-21 SCHEMATIC Milne Point Unit Well: MPU I-40 Last Completed: 4/1/2021 PTD: 220-071 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20"Conductor 129.5 / X52 / Weld N/A Surface 169’N/A 9-5/8"Surface 47 / L-80 / TXP 8.681 Surface 2,481’0.0758 9-5/8”Surface 40 / L-80 / TXP 8.835 2,481’8,368’0.0732 7-5/8”Tieback 29.7 / L-80 / Hyd 521 6.875 Surface 8,207’0.0459 4-1/2”Liner 250ђ Screens 13.5 / L-80 / Hyd 625 3.920 8,196’17,221’.0149 TUBING DETAIL 4-1/2"Tubing 12.6# / L-80 / TXPM 3.958 Surface 8,204’0.0152 OPEN HOLE / CEMENT DETAIL 20”Driven 12-1/4"Stg 1 Lead – 950 sx/ Tail – 400 sx Stg 2 Lead – 690 sx/ Tail – 270 sx 8-1/2”Cementless ScreenedLiner WELL INCLINATION DETAIL KOP @ 334’ Max Hole Angle = 96° @ 10,678’ MD TREE & WELLHEAD Tree Cameron 2-9/16" 5M w/ 4-1/16” 5M Cameron Wing Wellhead Cameron 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs GENERAL WELL INFO API: 50-029-23689-00-00 Completion Date: 12/17/2020 JEWELRY DETAIL No.Top MD Item ID 1 30’11” x 4-1/2” Tubing Hanger 3.958” 2 7,217’Zenith C6 Gauge Carrier 3.958” 3 7,224’Sliding Sleeve (13C JP, Packoff Stinger (OAL= 304”), Slip Stop (OAL = 21”) 12-22-21 3.813” 4 7,230’Ported Pressure Sub 3.958” 5 7,289’7-5/8” x 4-1/2” Permanent Packer, Halliburton TNT 3.856” 6 7,356’XN Nipple, 3.813” Profile, 3.750” No Go 3.750” 7 8,174’WLEG – Bottom @ 8,204’3.958” 8 8,196’BOT SLZXP LTP / Liner Hanger 7” x 9-5/8” 3,766’ TVD 6.190” 9 8,217’7” H563 x 4.5” TSH 625 XO 3.850” 10 17 219’Shoe 3 950” 4-1/2” SCREEN LINER DETAIL Jts Top (MD) Top (TVD) Btm (MD) Btm (TVD) 9 8374’3772’8754’3773’ 2 9041’3789’9125’3793’ 12 9285’3798’9791’3793’ 1 9911’3798’9953’3801’ 2 10158’3816’10242’3822’ 2 10437’3835’10521’3837’ 3 10846’3816’10969’3809’ 1 11269’3805’11311’3805’ 6 11758’3815’12010’3808’ 12 12310’3823’12815’3842’ 19 12851’3844’13651’3871’ 83 13688’3875’17184’3911’ _____________________________________________________________________________________ Revised By: TDF 1/23/2024 PROPOSED Milne Point Unit Well: MPU I-40 Last Completed: 4/1/2021 PTD: 220-071 TD =17,221’(MD) / TD =3,911’ (TVD) 20” Orig. KB Elev.: 68.20’ / GL Elev.: 33.6’ 7-5/8” 12 14 16 9-5/8” 2 3 & 4 9 Tubing Cut @ ± 7,242’’ See Screen/ Solid Liner Detail PBTD =17,221’ (MD) / PBTD = 3,911’ (TVD) 9-5/8” ‘ES’ Cementer @ 2,481’ MD 4-1/2” Shoe @ 17,221’ 13 15 11 5&6 7 &8 10 1 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20" Conductor 129.5 / X52 / Weld N/A Surface 169’ N/A 9-5/8" Surface 47 / L-80 / TXP 8.681 Surface 2,481’ 0.0758 9-5/8” Surface 40 / L-80 / TXP 8.835 2,481’ 8,368’ 0.0732 7-5/8” Tieback 29.7 / L-80 / Hyd 521 6.875 Surface 8,207’ 0.0459 4-1/2” Liner 250ђ Screens 13.5 / L-80 / Hyd 625 3.920 8,196’ 17,221’.0149 TUBING DETAIL 4-1/2" Tubing 12.6# / L-80 / TXPM 3.958 Surface ±7,200’ 0.0152 4-1/2" Tubing 12.6# / L-80 / TXPM 3.958 ±7,242’8,204’ 0.0152 OPEN HOLE / CEMENT DETAIL 20” Driven 12-1/4"Stg 1 Lead – 950 sx / Tail – 400 sx Stg 2 Lead – 690 sx / Tail – 270 sx 8-1/2” Cementless Screened Liner WELL INCLINATION DETAIL KOP @ 334’ Max Hole Angle = 96° @ 10,678’ MD TREE & WELLHEAD Tree Cameron 2-9/16" 5M w/ 4-1/16” 5M Cameron Wing Wellhead Cameron 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs GENERAL WELL INFO API: 50-029-23689-00-00 Completion Date: 12/17/2020 JEWELRY DETAIL No. Top MD Item ID 1 ±X,XXX’ 4-1/2” XN – Nipple -ID=3.725” 2 ±X,XXX’ Zenith Ported Sub Press Port 3 ±X,XXX’ Pump 4 ±X,XXX’ Pump 5 ±X,XXX’ Gas Separator 6 ±X,XXX’ Gas Avoider 7 ±X,XXX’ Upper Tandem Seal 8 ±X,XXX’ Lower Tandem Seal 9 ±X,XXX’ Motor 10 ±X,XXX’ Sensor and Cetralizer – Btn @ ±7,200’ 11 7,289’ 7-5/8” x 4-1/2” Permanent Packer, Halliburton TNT 3.856” 12 7,356’ XN Nipple, 3.813” Profile, 3.750” No Go 3.750” 13 8,174’ WLEG – Bottom @ 8,204’ 3.958” 14 8,196’ BOT SLZXP LTP / Liner Hanger 7” x 9-5/8” 3,766’ TVD 6.190” 15 8,217’ 7” H563 x 4.5” TSH 625 XO 3.850” 16 17,219’ Shoe 3.950” 4-1/2” SCREEN LINER DETAIL Jts Top (MD) Top (TVD) Btm (MD) Btm (TVD) 9 8374’ 3772’ 8754’ 3773’ 2 9041’ 3789’ 9125’ 3793’ 12 9285’ 3798’ 9791’ 3793’ 1 9911’ 3798’ 9953’ 3801’ 2 10158’ 3816’ 10242’ 3822’ 2 10437’ 3835’ 10521’ 3837’ 3 10846’ 3816’ 10969’ 3809’ 1 11269’ 3805’ 11311’ 3805’ 6 11758’ 3815’ 12010’ 3808’ 12 12310’ 3823’ 12815’ 3842’ 19 12851’ 3844’ 13651’ 3871’ 83 13688’ 3875’ 17184’ 3911’ Milne Point ASR Rig 1 BOPE 2023 11” BOPE 4.48' 4.54' 2.00' CIW-U 4.30' Hydril GK 11" - 5000 VBR or Pipe Rams Blind11'’- 5000 DSA, 11 5M X 7 1/16 5M (If Needed) 2 1/16 5M Kill Line Valves 2 1/16 5M Choke Line Valves HCRManualManualHCR Stripping Head 2-7/8” x 5” VBR David G Dempsey Hilcorp Alaska, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: David.Dempsey2@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 564-4422 Received By: Date: DATE: 06/18/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU I-40 (PTD 220-071) Leak Detection Log 05/30/2021 Please include current contact information if different from above. Received By: 06/18/2021 37' (6HW By Abby Bell at 3:02 pm, Jun 18, 2021 Samuel Gebert Hilcorp Alaska, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: sam.gebert@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: Date: DATE: 05/06/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU I-40 (PTD 220-071) Leak Detection Log 04/05/2021 Please include current contact information if different from above. PTD: 2200710 E-Set: 35102 Received by the AOGCC 05/06/2021 05/06/2021 1. Operations Abandon Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Suspend Perforate Other Stimulate Alter Casing Change Approved Program Plug for Redrill Perforate New Pool Repair Well Re-enter Susp Well Other: Convert to JP Hilcorp Alaska Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number): 8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071):10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 17,221 feet N/A feet true vertical 3,911 feet N/A feet Effective Depth measured 17,221 feet 7,289' & 8,196'feet true vertical 3,911 feet 3,538' & 3,766'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 / TXPM 8,204' 3,767' Packers and SSSV (type, measured and true vertical depth)Permanent TNT & 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 13. Prior to well operation: Subsequent to operation: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Chad Helgeson Contact Name: Authorized Title:Operations Manager Contact Email: Contact Phone:777-8520 2. Operator Name Senior Engineer: Senior Res. Engineer: Collapse N/A 4,760psi 3,911' Burst N/A 6,870psi 5,750psi 6,890psi7-5/8" 1,916' 3,772' 3,767' 3,090psi 4,790psi 2,481' 5,887' Surface Surface 20" 9-5/8" 9-5/8" measured 8,207' 9,025' N/A Tieback Liner Casing Conductor Length 2,429 MILNE PT UNIT I-40 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 1,030 Gas-Mcf 300 Casing Pressure Tubing Pressure 137 N/A 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 321-139 261 Authorized Signature with date: Authorized Name: Ian Toomey itoomey@hilcorp.com STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 220-071 50-029-23689-00-00 Plugs ADL025515, ADL0025517 & ADL0025906 5. Permit to Drill Number: MILNE POINT / SCHRADER BLUFF OIL Junk measured 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 3. Address: 4. Well Class Before Work: 487 Representative Daily Average Production or Injection Data 283199 Oil-Bbl measured true vertical Packer 4-1/2" 8,207' 17,221' Size 169' WINJ WAG 69 Water-Bbl MD 169' 2,481' 8,368' TVD 169' 787 Form 10-404 Revised 3/2020 Submit Within 30 days of Operations By Grace Salazar at 2:20 pm, Apr 22, 2021 Chad Helgeson (1517) 2021.04.22 13:26:52 - 08'00' DSR-4/22/21 RBDMS HEW 4/23/2021 SFD 4/22/2021MGR30JUL2021 _____________________________________________________________________________________ Revised By: DH 4/22/2021 SCHEMATIC Milne Point Unit Well: MPU I-40 Last Completed: 4/1/2021 PTD: 220-071 TD =17,221’ (MD) / TD =3,911’ (TVD) 20” Orig. KB Elev.: 68.20’ / GL Elev.: 33.6’ 7-5/8” 6 8 4 10 9-5/8 ” 1 2 3 See Screen/ Solid Liner Detail PBTD =17,221’ (MD) / PBTD =3,911’ (TVD) 9-5/8” ‘ES’ Cementer @ 2,481’ MD 4-1/2” Shoe @ 17,221’ 7 9 5 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20" Conductor 129.5 / X52 / Weld N/A Surface 169’ N/A 9-5/8" Surface 47 / L-80 / TXP 8.681 Surface 2,481’ 0.0758 9-5/8” Surface 40 / L-80 / TXP 8.835 2,481’ 8,368’ 0.0732 7-5/8” Tieback 29.7 / L-80 / Hyd 521 6.875 Surface 8,207’ 0.0459 4-1/2” Liner 250ђ Screens 13.5 / L-80 / Hyd 625 3.920 8,196’ 17,221’ .0149 TUBING DETAIL 4-1/2" Tubing 12.6# / L-80 / TXPM 3.958 Surface 8,204’ 0.0152 OPEN HOLE / CEMENT DETAIL 20” Driven 12-1/4"Stg 1 Lead – 950 sx / Tail – 400 sx Stg 2 Lead – 690 sx / Tail – 270 sx 8-1/2” Cementless Screened Liner WELL INCLINATION DETAIL KOP @ 334’ Max Hole Angle = 96° @ 10,678’ MD TREE & WELLHEAD Tree Cameron 2-9/16" 5M w/ 4-1/16” 5M Cameron Wing Wellhead Cameron 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs GENERAL WELL INFO API: 50-029-23689-00-00 Completion Date: 12/17/2020 JEWELRY DETAIL No. Top MD Item ID 1 30’ 11” x 4-1/2” Tubing Hanger 3.958” 2 7,217’ Zenith C6 Gauge Carrier 3.958” 3 7,224’ Sliding Sleeve 3.813” 4 7,230’ Ported Pressure Sub 3.958” 5 7,289’ 7-5/8” x 4-1/2” Permanent Packer, Halliburton TNT 3.856” 6 7,356’ XN Nipple, 3.813” Profile, 3.750” No Go 3.750” 7 8,174’ WLEG – Bottom @ 8,204’ 3.958” 8 8,196’ BOT SLZXP LTP / Liner Hanger 7” x 9-5/8” 3,766’ TVD 6.190” 9 8,217’ 7” H563 x 4.5” TSH 625 XO 3.850” 10 17,219’ Shoe 3.950” 4-1/2” SCREEN LINER DETAIL Jts Top (MD) Top (TVD) Btm (MD) Btm (TVD) 9 8374’ 3772’ 8754’ 3773’ 2 9041’ 3789’ 9125’ 3793’ 12 9285’ 3798’ 9791’ 3793’ 1 9911’ 3798’ 9953’ 3801’ 2 10158’ 3816’ 10242’ 3822’ 2 10437’ 3835’ 10521’ 3837’ 3 10846’ 3816’ 10969’ 3809’ 1 11269’ 3805’ 11311’ 3805’ 6 11758’ 3815’ 12010’ 3808’ 12 12310’ 3823’ 12815’ 3842’ 19 12851’ 3844’ 13651’ 3871’ 83 13688’ 3875’ 17184’ 3911’ Well Name Rig API Number Well Permit Number Start Date End Date MP I-40 ASR 50-029-23689-00-00 220-071 3/29/2021 4/2/2021 PJSM and discussed daily activities. NU 11" BOP Stack, MU Koomey hoses, fly on rig floor and stairs. RDMO crane. Set pusher shack and camps. Final torque on BOP stack. Spotted in ASR and raised mast, secured the rack pins. Organized rig floor. Hooked up Kill/Choke lines. Spotted in rig pump and glycol unit, began ground work. Hooked up circulating lines and began winterized lines and equipment as needed. Crew having to shovel drifts due to the high winds. Hooked up and tested Fire&Gas. Held PJSM and review sundry with crew. Connect glycol unit. Winterized lines and equipment. Spot jet heaters. Spot spooler. Heat BOPE Stack. Function test BOP rams. Clear snow drifts. FIll Stack. P/U 3-1/2" test joint. Open IA. IA is blowing air. IA stops blowing through needle valve after 5 minutes. Baker connects spooler. Perform shell Test to 250 psi low and 2,500 psi high. Perform BOPE test per Sundry to 250 psi low and 2,500 psi high with 3-1/2" and 4-1/2" test joints. 11" BOP configuration : Annular, 2-7/8" x 5" VBRs, blinds, mud cross. Perform accumulator test. Zero failures during BOPE Test. Test witnessed waived by AOGCC Brian Bixby. Blow down lines. Close IA. IA was static for full 3.5 hours of BOPE Test. Lay down containment. Spot cat walk. R/U cat walk. Spot pipe racks. R/U Sheave. R/U elephant trunk. R/U to pull 3-1/2" completion. Pull CTS test plug. Dry rod into BPV and check pressure in tubing. No pressure. Pull BPV. Fluid fell out on the stack. P/U 3-1/2" landing joint. M/U crossovers to 3-1/2" landing joint and make up to hanger. M/U TIW. Check IA pressure. IA = 0 gauge psi but did have a slight blow of gas and bled off in 5mins BOLDS. Wellhead: Nipple down tree and adaptor, Set CTS Dart, install new R-54 API ring, ASR to move in Rig up and pull hanger. Load fluids for well kill. Rig up LRS. Pressure test lines to 250 psi low and 2,500 psi high. Bleed gas on IA from 851 psi to 0 psi over 20 minutes. Tubing at 0 psi. Reverse circulate 10 bbls of 100 degree diesel down IA at 1 BPM while taking returns out the tubing and to the tiger tank. Get immediate returns to the tank. Fluid is energized and smells of diesel. T/I/O = 58/60/0. Swap to source water and increase rate to 5 BPM while reverse circulating and taking returns out the tubing to tiger tank. Returns are mostly gas with little fluid. T/I/O = 36/36/0. Lose returns at approxiametly 120 bbls pumped away. Got 65 bbls back in tiger tank. T/I/O = 0/56/5. Continue to reverse circulate until vac truck driver indicates he has less fluid onboard than originally thought. Only 60 bbls left on truck. Stop pumping. IA goes on a vac. A total of 210 bbls pumped down IA. T/I/O = 0/0/7. Bullhead remaining volume on truck (48 bbls) down tubing at 5 BPM. T/I/O = 38/2/6. Caught fluid in tubing at 27 bbls bullheaded down tubing. Truck empty at 48 bbls away. Shut down. T/I/O = vac/17/0. Pump 1 bbl of 60/40 down IA. Pump 1 bbl of 60/40 down Tubing. T/I/O. vac/vac/6. Neither IA or tubing fully swept with source water during this job. Install 3" BPV. T/I/O = BPV/vac/6. Mobe equipment from L-pad. Inspected pad. Laided containment and spotted in mud boat and pits. Continued hauling equipment From L-pad. Began crane work, fly on well cellar, NU PT and ND BOP's. Continue off load and spotting equipment. Slickline: WELL S/I ON ARRIVAL, OPEN PERMIT W/PAD-OP, PT PCE 250L/2500H. LRS PUMP 70bbls HOT DIESEL DOWN TBG. PULL BK-DGLV FROM STA#1 AT 6873' SLM. 3/30/2021 3/29/2021 Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MP I-40 ASR 50-029-23689-00-00 220-071 3/29/2021 4/2/2021 Hilcorp Alaska, LLC Weekly Operations Summary 4/1/2021 Held PJSM. RIH w/ 4-1/2" completion: WLEG, 20 Joints of 4.5" TXPM 12.6#, L-80 tubing, XN Nipple ID 3,725 (w/RHCP Installed), 1 Joints of TXPM 12.6#, L-80 tubing, TNT packer assembly, 1 joint of TXPM 12.6#, L-80 tubing. PU/MU ported sub, sliding sleeve and gauge carrier assembly. Terminated tec wire and tested. RIH with 4-1/2" jet pump completion on TXPM 12.6#, L-80 tubing, spooling Tec Wire and clamping the first 5 joints then every other joint after. Tested Tech every 1000'. Filling hole 10bph with 8.33 source water. Drift Tbg w/3.85" Plug. MU torque 6000 lbs/ft, PUW 65k-lbs./ SOW 31k- lbs. PU/MU landing jt and tbg hanger. Make final Tec wire splice. Land completion with 1K down on hanger. RILDS. Putting EOT @ 8,205'md. Pump 130 bbls down of corrossion inhibited source water down IA at 4 BPM and 200 psi. Pump 65 bbls of diesel down IA at 4 BPM and 200 psi w/ LRS. Pump38 bbls of diesel at 3 BPM and 150 psi down tubing. Drop 1-7/8" ball and rod. Pressure up on tubing to 3,500 psi. See packer start to set at 1,800 psi. See packer fully set at 2,900 psi. Fill tubing with 11 bbls of source water. Pressure test tubing to 3,500 psi for 30 charted minutes. Tubing bleeds off at 100 psi/min. Attempt multiple times. Tubing continues to bleed off at 100 psi/ min. Systematically search for potential leaks paths. Identify and fix two small leaks/drips. Pressure up on tubing again and see same identical 100 psi/min bleed off. Fill IA with 16 bbls and pressure up to 800 psi. IA bleeds off at 50 psi/min. Close IA valve and test against it. Good test against IA valve. All surface valves are good. Pressure up IA to 800 psi and see same 50 psi/min bleed off. See bubbles in the stack. Bleed IA to 0 psi. Bubbles in stack stop. Pressure up IA again and see bubbles in BOP stack immediately. Call wellhead rep. Advised to tighten LDS. Tighten LDS and repeat 800 psi test of IA three times over. Each time the bubbling in the BOP stack lessens but unable to stop the leak. Wellhead rep enroute to troubleshoot. Perform CMIT TxIA to 3500 psi for 15 minutes. Pass. Drain BOPE Stack empty. Pressure IA up to 800 psi and physically and definitely see fluid come up tubing. Mobilize SL to attempt to close the sliding sleeve. 3/31/2021 Held PJSM, Checked fluids and serviced rig as needed. P/U 3-1/2" Landing Joint. M/U Crossovers to 3-1/2" landing joint and make up to hanger. M/U TIW. BOLDS and pulled hanger off seat to the floor. PUW 56k. De-completed hanger and LD hanger. Cable check showing balanced with a phase short. LD 2 joints and pulled cable thru sheave to spooler. Filled IA 50 bbls of 8.3 SW with baraklean added. Monitored well IA/Tbg static. POOH with 3-1/2" ESP Completion f/7144' md t/4,766' md laying down 73 joints. Filling hole with 5bbls of 8.3 source water every 15 joints out. Tubing, clamps, jewelry and cable pulling out clean. Crew eat lunch. Continued POH with 3-1/2" ESP completion from 4,776'. Filling hole 2.5bbls every 15 joints out. NOTE: ESP Cable blowout seen above where ESP Cable connects to motorlead. Offloaded and inventoried jet pump completion jewelry and 4-1/2" tubing. 91 bbls lost as of 1800-hrs. L/D ESP. Close blind rams. R/D 3-1/2" and R/U 4-1/2" tubing handling equipment. Remove ESP Spooler. Spot TEC wire spooler w/ air compressor. Load 3-1/2" EUE tubing into pipe tub. Load and strap 4-1/2" TXPM, L-80, 12.6# tubing. QC completion running tally with engineer. R/D sheave and elephant trunk. Fill hole with 40 bbls (10 bbls/hr) over previous 4 hours. LEL alarm goes off in pits. Close super choke. Check IA needle valve. Well is blowing gas. Bleed off to the tiger tank and monitor well. Well is static for 15 minutes. Close valve to tiger tank to see if well pressures up. After 5 minutes, open to tiger tank and well is blowing gas once again. Pressure bleeds off in 20 seconds. Repeat same process again with same results. Monitor well. Monitor well. Pressure at 3 psi after 15 minutes. Pressure at 5 psi after 30 minutes. Pressure at 8 psi after one hour. Attempt to bullhead down well but pump will not throttle up. Apply heat and troubleshoot. Bullhead 100 bbls down well at 4 BPM and 200 psi. Shut down and monitor for 30 minutes. Well on vac. Open Blind Rams. RIH w/ 4-1/2" completion: WLEG, 20 Joints of TXPM 12.6#, L-80 Tubing. Well Name Rig API Number Well Permit Number Start Date End Date MP I-40 ASR 50-029-23689-00-00 220-071 3/29/2021 4/2/2021 Hilcorp Alaska, LLC Weekly Operations Summary 4/2/2021 PJSM and discussed plan forward. Waiting on HAL SL to arrive. Checked fluids and serviced rig. Nipple down 11" flow spool. Nipple up the 11"x7-1/16" shooting flange. MIRU HAL SL Unit. RIH w/QC, 3.7" CENT. 3'x1-7/8" ST, 42BO (keys Up) through sliding sleeve @ 7,225'. Pulled into sleeve and jarred once to close. Ran through sleeve 4 time to confirm closed. POOH. Checked tool and pin was not speared, could see the tool engaged the sleeve. SL on stand by waiting results of the MIT. Closed blinds and pressured up tbg to 3,700 psi with IA open. Observed 100psi/min drop. Pressured up several times with the same results. Bled off tbg and circulated through stack to ensure no trapped air in system. Pressured up on tbg to 3,500psi. Same result 100psi/min drop with fluid returning from the IA. Closed IA for 5 mins and the tbg pressure decreased to 30psi/min. Bleed off pressure. Discussed plan forward with town. CMIT TxIA to 3,800psi. Charted for 30mins. First 15mins pressured drop 200psi and 100psi the last 15mins. Bled off Pressure. RIH w/QC,3.7" CENT. 3'x1-7/8" ST, 42BO (keys down). Unable to RIH past 5834'. Discuss plan forward with Wells Foreman and Operations Engineer. Decision made to POOH w/QC, 3.7" CENT. 3'x1-7/8" ST, 42BO. POOH w/slickline, OOH w/slickline. RDMO HAL SL Unit. Done with well work. Set BPV. ND BOPE. NU Tree and test hanger to 500/5000 psi. Pass. Pull BPV. Continue RDMO. RDMO - ASR off well. 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: Convert to JP 2. Operator Name:4. Current Well Class:5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception?Yes No 9.Property Designation (Lease Number):10.Field/Pool(s): 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 17,221'N/A Casing Collapse Conductor N/A Surface 4,760psi Surface 3,090psi Tieback 4,790psi Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14.Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date:GAS WAG GSTOR SPLUG Commission Representative: GINJ Op Shutdown Abandoned Chad Helgeson Contact Name:Ian Toomey Operations Manager Contact Email:itoomey@hilcorp.com Contact Phone: 777-8520 Date: Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng Tubing MD (ft):Perforation Depth TVD (ft): COMMISSION USE ONLY Authorized Name: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL025515, ADL025517 & ADL025906 220-071 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 50-029-23689-00-00 Milne Point Field / Schrader Bluff Oil Pool Hilcorp Alaska LLC Length Size 3,911' 17,221' 3,911' MD C.O. 477.05 PRESENT WELL CONDITION SUMMARY 1,004 N/A MPU I-40 169'169' 9.3 / L-80 / EUE-8rd TVD Burst 8,120' N/A 6,890psi 6,870psi 5,750psi 1,916' 3,772' 3,767' 2,481' 8,368' 4-1/2" 169'20" 9-5/8" 9-5/8" 2,481' 7-5/8"8,207' 5,887' Authorized Signature: 4/1/2021 3-1/2" Perforation Depth MD (ft): See Schematic See Schematic BOT SLZXP LTP and N/A 8,196 MD/ 3,766 TVD and N/A Authorized Title: 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. 17,221' 8,207' 9,025' 3,911' Tubing Size:Tubing Grade: ory Statu Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 2:57 pm, Mar 17, 2021 321-139 Chad Helgeson (1517) 2021.03.17 12:48:08 - 08'00' DLB 03/17/2021 DSR-3/17/21 10-404 MGR19MAR21 X BOPE Test to 2500 PSI. Comm 3/19/21 dts 3/19/2021 JLC 3/19/2021 RBDMS HEW 3/19/2021 Convert to JP Well: MPU I-40 Date: 3/15/21 Well Name:MPU I-40 API Number:50-029-23689-00-00 Current Status:SI Oil Well (failed ESP)Pad:I-Pad Estimated Start Date:April 1 st, 2021 Rig:ASR #1 Reg. Approval Req’d?Yes Date Reg. Approval Rec’vd: Regulatory Contact:Tom Fouts Permit to Drill Number:220-071 First Call Engineer:Ian Toomey (907) 777-8434 (O) (907) 903-3987 (M) Second Call Engineer:David Gorm (907) 777-8333 (O) (505) 215-2819 (M) AFE Number:TBD Job Type:Convert to JP Gauge Pressure:1,249 psi at 3,490’ TVD |EMW = 6.9 ppg Maximum Expected BHP:1,381 psi at 3,772’ TVD |EMW = 7.1 ppg MPSP:1,004 psi Gas Column Gradient = 0.1 psi/ft Max Inclination: +75° from 7,609’ MD to TD Max Dogleg:6.7°/100ft at 8,085’ MD Tree:Cameron 3-1/8” 5M Wellhead:FMC, 11” 5M, Gen 5 Tubing Hanger Lift threads:3-1/2” TC-II top & bottom BPV Profile:3” CIW Type H Brief Well Summary: Well I-40 was drilled by Doyon 14 as a Schrader Bluff NB sand producer. This ESP failed on February 15th, 2021 and was SI. Notes Regarding the Well & Design x 7-5/8” x 9-5/8” annulus MIT to 1,000 psi passed on 12/16/2021 with 9.2 ppg brine & diesel. x Offset Injector Support o I-39: SI on 2/18/2020 Objective: x Pull 3-1/2” ESP completion. x Run new 4-1/2” JP completion. Pre-Rig Procedure: 1. Kill the well with 8.3 ppg source water (volumes: tubing = 60 bbls & IA = 234 bbls). 2. Observe the well for flow for 30 minutes to confirm the well is static or taking fluid. 3. RD well house and flowlines. Clear and level area around the well. 4. RU a crane. Set 3” BPV. ND Tree. Inspect the lift threads on the tubing hanger. Install the plug off tool into the BPV. 5. NU BOPE. RD the crane. 6. NU BOPE house. Spot mud boat. Convert to JP Well: MPU I-40 Date: 3/15/21 RWO Procedure: 7. MIRU Hilcorp ASR #1, ancillary equipment and lines to returns tank. 8. Test BOPE to 250/2,500 psi and annular to 250/2,500 psi. a. Notify the AOGCC 24 hours in advance of BOP test. b. Confirm test pressures per the Sundry Conditions of approval. c. Test VBR’s and annular with 3-1/2” & 4-1/2” test joints. d. Submit to AOGCC completed 10-424 form within 5 days of BOPE test. Contingency: If BOPE test fails a. Notify Operations Engineer (Hilcorp), Mr. Mel Rixse (AOGCC) and Mr. Jim Regg (AOGCC) via email explaining the wellhead situation prior to performing the rolling test. AOGCC may elect to send an inspector to witness test if test witness was waived. b. With stack out of the test path, test choke manifold per standard procedure c. Conduct a rolling test: Test the rams and annular with the pump continuing to pump, (monitor the surface equipment for leaks to ensure that the fluid is going down-hole and not leaking anywhere at surface.) d. Hold a constant pressure on the equipment and monitor the fluid/pump rate into the well. Record the pumping rate and pressure. e. Once the BOP ram and annular tests are completed, test the remainder of the system following the normal test procedure (floor valves, gas detection, etc.) f. Record and report this test with notes in the remarks column that the tubing hanger/BPV profile / penetrator wouldn’t hold pressure and rolling test was performed on BOP Equipment and list items, pressures and rates. 9. RU to pull 3-1/2” ESP completion. 10. Pull plug off tool, check for pressure under the BPV, if needed kill the well with KWF and pull the BPV. 11. MU the landing joint to the tubing hanger, BOLDS and unseat the tubing hanger. a. String PU = 95K and SO = 62K when landed by Doyon 14 (block weight = 40K) in 9.2 ppg brine. 12. Pull the hanger to the rig floor. Lay down the landing joint and tubing hanger. RU to pull ESP cable over sheaves to spooling units. a. Inspect the tubing hanger and note any corrosion or damage. Contingency (If a rolling test was conducted): MU new hanger or test plug to the completion tubing. Re-land hanger or test plug in tubing head. Test BOPE per standard procedure and sundry. 13. POOH laying down the 3-1/2” tubing spooling ESP cable and removing all jewelry as it presents itself a. Note any corrosion, sand, scale, damage or over torqued connections on the tubing with associated depths and ESP components on the morning report. Equipment Disposition Tubing hanger Clean, dope and restock Tubing & Pup joints Clean, dope and restock Gaslift Mandrels/Nipple Clean, dope and restock ESP equipment/Power Cable Centrilift to take possession for inspection and teardown Protectorlizer (3)Clean and restock Seal Clamps (4)Clean and restock Convert to JP Well: MPU I-40 Date: 3/15/21 Pump Clamps (1)Clean and restock Cannon clamps (120)Clean and restock 14. RD ESP pulling equipment. 15. RU to run 4-1/2” completion. 16. PU and MU the following completion. a. WLEG/Mule shoe (~8,210’) b. XX joints, 4-1/2”, 12.6#, L-80, TXPM c. Nipple, 3.813” XN profile (3.750” no-go), 4-1/2”, TXPM (RHC plug body installed), with 10’ handling pups d. 1 joint, 4-1/2”, 12.6#, L-80, TXPM e. Pup joint, 1 joint, 4-1/2”, 12.6#, L-80, TXPM f. Crossover, 4-1/2” Vam Top Box x 4-1/2” TXP Pin g. Permanent Packer, Halliburton TNT, 4-1/2”, 12.6#, L-80 Vam Top (setting depth ~7,400’) h. Crossover, 4-1/2” TXPM Box x 4-1/2” Vam Top Pin i. Pup joint, 4-1/2”, 12.6#, L-80, TXPM j. 1 joint, 4-1/2”, 12.6#, L-80, TXPM k. Pup joint, 4-1/2”, 12.6#, L-80, TXPM l. Crossover, 4-1/2” EUE 8rd Box x 4-1/2” TXP Pin m. Ported Pressure Sub, 4-1/2”, 12.6#, L-80, EUE 8rd n. Crossover, 4-1/2” TXPM Box x 4-1/2” EUE 8rd Pin o. Pup joint, 4-1/2”, 12.6#, L-80, TXPM p. Crossover, 4-1/2” H521 Box x 4-1/2” TXP Pin q. Sliding Sleeve, 4-1/2”, 12.6#, L-80 Hydril 521 r. Crossover, 4-1/2” TXPM Box x 4-1/2” H521 Pin s. Pup joint, 4-1/2”, 12.6#, L-80, TXPM t. Crossover, 4-1/2” EUE 8rd Box x 4-1/2” TXP Pin u. Gauge Carrier, 4-1/2”, 12.6#, L-80, EUE 8rd v. Crossover, 4-1/2” TXPM Box x 4-1/2” EUE 8rd Pin w. Pup joint, 4-1/2”, 12.6#, L-80, TXPM x. XXX joints, 4-1/2”, 12.6#, L-80, TXPM 17. PU and MU the 4-1/2” tubing hanger. Make final splice of the TEC wire and ensure any unused control line ports are dummied off. 18. Land tubing hanger and RILDS. Lay down landing joint. Record PU and SO weights on the tally and WellEZ. 19. Set 4” HP BPV. 20. ND BOPE. Install the plug off tool. 21. NU the tubing head adapter and NU 4-1/16” 5M tree. 22. PT the tubing hanger void to 500/5,000 psi. PT the tree to 250/5,000 psi. 23. Pull the plug off tool and BPV. Convert to JP Well: MPU I-40 Date: 3/15/21 24. Reverse circulate the well over to corrosion inhibited source water follow by diesel freeze protect to 2,500’ MD. 25. Drop the ball & rod. 26. Pressure up on the tubing to 3,500 psi to set the packer. PT the tubing to 3,500 psi for 30 minutes (charted). 27. Bleed the tubing pressure to 2,000 psi and PT the IA to 3,500 psi for 30 minutes (charted). Bleed both the IA and tubing to 0 psi. 28. Turn well over to production via handover form. Post-Rig Procedure: 29. RU slickline. 30. Shift sliding sleeve open. 31. Pull the ball & rod and RHC plug body. 32. Install the JP. 33. RD slickline. Attachments: 1. As-built Schematic 2. Proposed Schematic 3. BOP stack sketch 4. Blank RWO MOC Form _____________________________________________________________________________________ Revised By: TDF 3/1/2021 SCHEMATIC Milne Point Unit Well: MPU I-40 Last Completed: 12/17/2020 PTD: 220-071 TD = 17,221’(MD) / TD =3,911’ (TVD) 4/5 20” Orig. KB Elev.: 68.20’ / GL Elev.: 33.6’ 7-5/8” 9 10 11 4 17 9-5/8 ” 1 2 3 See Screen/ Solid Liner Detail PBTD = 17,221’ (MD) / PBTD =3,911’ (TVD) 9-5/8” ‘ES’ Cementer @ 2,481’ MD 6/7/8 4-1/2” Shoe @ 17,221’ 12/13 15 14 16 3-1/2”CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20" Conductor 129.5 / X52 / Weld N/A Surface 169’ N/A 9-5/8" Surface 47 / L-80 / TXP 8.681 Surface 2,481’ 0.0758 9-5/8” Surface 40 / L-80 / TXP 8.835 2,481’ 8,368’ 0.0732 7-5/8” Tieback 29.7 / L-80 / Hyd 521 6.875 Surface 8,207’ 0.0459 4-1/2” Liner 250ђ Screens 13.5 / L-80 / Hyd 625 3.920 8,196’ 17,221’ .0149 TUBING DETAIL 3-1/2" Tubing 9.3 / L-80 / EUE-8rd 2.441 Surface 8,120’ 0.0087 OPEN HOLE / CEMENT DETAIL 20” Driven 12-1/4"Stg 1 Lead – 950 sx / Tail – 400 sx Stg 2 Lead – 690 sx / Tail – 270 sx 8-1/2” Cementless Screened Liner WELL INCLINATION DETAIL KOP @ 334’ Max Hole Angle = 96° @ 10,678’ MD TREE & WELLHEAD Tree Cameron 2-9/16" 5M w/ 4-1/16” 5M Cameron Wing Wellhead Cameron 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs GENERAL WELL INFO API: 50-029-23689-00-00 Completion Date: 12/17/2020 JEWELRY DETAIL No. Top MD Item ID 1136’GLM w/(Dummy set 2/13/21)2.909” 2 6,882’ 3-1/2” GLM w/ 1” Dummy Valve 2.907” 3 7,003’ XN Nipple, 2.313” Profile, 2.75” No Go 2.760” 4 7,057’ Discharge Head: B/O PMP 513 3.5X 8MD EUE 5 7,057’ Zenith Ported Sub: Press Port 513/538P 6 7,058’ Upper Pump: 538PMSXD 066 Flex 47H6 7 7,074’ Middle Pump: 538PMSXD 068 G31 M FER 8 7,087’ Lower Pump: 538PMSXD 20 GINPSHH H6 9 7,097’ Gas Separator: 538GSTHVEV H6 STD PNT WC ENH 10 7,102’ Upper Tandem Seal: GSBDB H6 SB/AB PFSA 11 7,109’ Lower Tandem Seal: GSBDB H6 SB/AB PFSA 12 7,116’ Motor: 562XP – 400 HP 2785V / 88A 13 7,142’ Motor Gauge Zenith PT00752 14 7,144’ Centralizer: Bottom @ 7146’ MD 15 8,196’ BOT SLZXP LTP / Liner Hanger 7” x 9-5/8” (TBD TVD) 6.190” 16 8,217’ 7” H563 x 4.5” TSH 625 XO 3.850” 17 17,219’ Shoe 3.950” 4-1/2”SCREENS LINER DETAIL Jts Top (MD) Top (TVD) Btm (MD) Btm (TVD) 9 8374’ 3772’ 8754’ 3773’ 2 9041’ 3789’ 9125’ 3793’ 12 9285’ 3798’ 9791’ 3793’ 1 9911’ 3798’ 9953’ 3801’ 2 10158’ 3816’ 10242’ 3822’ 2 10437’ 3835’ 10521’ 3837’ 3 10846’ 3816’ 10969’ 3809’ 1 11269’ 3805’ 11311’ 3805’ 6 11758’ 3815’ 12010’ 3808’ 12 12310’ 3823’ 12815’ 3842’ 19 12851’ 3844’ 13651’ 3871’ 83 13688’ 3875’ 17184’ 3911’ _____________________________________________________________________________________ Revised By: TDF 3/15/2021 PROPOSED Milne Point Unit Well: MPU I-40 Last Completed: 12/17/2020 PTD: 220-071 TD = 17,221’(MD) / TD =3,911’ (TVD) 20” Orig. KB Elev.: 68.20’ / GL Elev.: 33.6’ 7-5/8” 6 8 4 10 9-5/8” 1 2 3 See Screen/ Solid Liner Detail PBTD =17,221’ (MD) /PBTD =3,911’ (TVD) 9-5/8” ‘ES’ Cementer @ 2,481’ MD 4-1/2” Shoe @ 17,221’ 7 9 5 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20" Conductor 129.5 / X52 / Weld N/A Surface 169’ N/A 9-5/8" Surface 47 / L-80 / TXP 8.681 Surface 2,481’ 0.0758 9-5/8” Surface 40 / L-80 / TXP 8.835 2,481’ 8,368’ 0.0732 7-5/8” Tieback 29.7 / L-80 / Hyd 521 6.875 Surface 8,207’ 0.0459 4-1/2” Liner 250ђ Screens 13.5 / L-80 / Hyd 625 3.920 8,196’ 17,221’ .0149 TUBING DETAIL 4-1/2" Tubing 12.6# / L-80 / TXPM 3.958 Surface ±8,210’ 0.0152 OPEN HOLE / CEMENT DETAIL 20” Driven 12-1/4"Stg 1 Lead – 950 sx / Tail – 400 sx Stg 2 Lead – 690 sx / Tail – 270 sx 8-1/2” Cementless Screened Liner WELL INCLINATION DETAIL KOP @ 334’ Max Hole Angle = 96° @ 10,678’ MD TREE & WELLHEAD Tree Cameron 2-9/16" 5M w/ 4-1/16” 5M Cameron Wing Wellhead Cameron 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs GENERAL WELL INFO API: 50-029-23689-00-00 Completion Date: 12/17/2020 JEWELRY DETAIL No. Top MD Item ID 1 24’ Tubing Hanger 3.950” 2 ±7,320’ Gauge Carrier 3.958” 3 ±7,330’ Sliding Sleeve 3.813” 4 ±7,340’ Ported Pressure Sub 3.958” 5 ±7,400’ Permanent Packer, Halliburton TNT 3.856” 6 ±8,158’ XN Nipple, 3.813” Profile, 3.750” No Go 3.750” 7 ±8,208’ WLEG – Bottom @ 8,210’ 3.958” 8 8,196’ BOT SLZXP LTP / Liner Hanger 7” x 9-5/8” 3,766’ TVD 6.190” 9 8,217’ 7” H563 x 4.5” TSH 625 XO 3.850” 10 17,219’ Shoe 3.950” 4-1/2” SCREEN LINER DETAIL Jts Top (MD) Top (TVD) Btm (MD) Btm (TVD) 9 8374’ 3772’ 8754’ 3773’ 2 9041’ 3789’ 9125’ 3793’ 12 9285’ 3798’ 9791’ 3793’ 1 9911’ 3798’ 9953’ 3801’ 2 10158’ 3816’ 10242’ 3822’ 2 10437’ 3835’ 10521’ 3837’ 3 10846’ 3816’ 10969’ 3809’ 1 11269’ 3805’ 11311’ 3805’ 6 11758’ 3815’ 12010’ 3808’ 12 12310’ 3823’ 12815’ 3842’ 19 12851’ 3844’ 13651’ 3871’ 83 13688’ 3875’ 17184’ 3911’ Milne Point ASR Rig 1 BOPE BOPE ~4.48' ~4.54' 2.00' 5000# 2-7/8" x 5" VBR 5000#Blind DSA, 11 5M X 7 1/16 5M (If Needed) 2 1/16 5M Kill Line Valves 2 1/16 5M Choke Line Valves HCRManualManualManual Stripping Head DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-23689-00-00Well Name/No. MILNE PT UNIT I-40Completion Status1-OILCompletion Date12/17/2020Permit to Drill2200710Operator Hilcorp Alaska, LLCMD17221TVD3911Current Status1-OIL2/25/2021UICNoWell Log Information:DigitalMed/FrmtReceivedStart StopOH /CHCommentsLogMediaRunNoElectr DatasetNumberNameIntervalList of Logs Obtained:ROP, AGR, ABG, DGR, EWR, ADR MD & TVDNoNoYesMud Log Samples Directional SurveyREQUIRED INFORMATION(from Master Well Data/Logs)DATA INFORMATIONLog/DataTypeLogScaleDF12/23/2020158 17221 Electronic Data Set, Filename: MPU I-40 LWD Final.las34464EDDigital DataDF12/23/20208358 17186 Electronic Data Set, Filename: MPU I-40 ADR Quadrants All Curves.las34464EDDigital DataDF12/23/2020 Electronic File: MPU I-40 LWD Final MD.cgm34464EDDigital DataDF12/23/2020 Electronic File: MPU I-40 LWD Final TVD.cgm34464EDDigital DataDF12/23/2020 Electronic File: MPU I-40_Definitive Survey Report.pdf34464EDDigital DataDF12/23/2020 Electronic File: MPU I-40_Definitive Survey Report.txt34464EDDigital DataDF12/23/2020 Electronic File: MPU I-40_Definitive Surveys.xlsx34464EDDigital DataDF12/23/2020 Electronic File: MPU I-40_GIS.txt34464EDDigital DataDF12/23/2020 Electronic File: MPU I-40 LWD Final MD.emf34464EDDigital DataDF12/23/2020 Electronic File: MPU I-40 LWD Final TVD.emf34464EDDigital DataDF12/23/2020 Electronic File: MPU_I-40_Geosteering.dlis34464EDDigital DataDF12/23/2020 Electronic File: MPU_I-40_Geosteering.ver34464EDDigital DataDF12/23/2020 Electronic File: MPU I-40 LWD Final MD.pdf34464EDDigital DataDF12/23/2020 Electronic File: MPU I-40 LWD Final TVD.pdf34464EDDigital DataDF12/23/2020 Electronic File: MPU I-40 LWD Final MD.tif34464EDDigital DataDF12/23/2020 Electronic File: MPU I-40 LWD Final TVD.tif34464EDDigital Data0 0 2200710 MILNE PT UNIT I-40 LOG HEADERS34464LogLog Header ScansDF1/6/2021 Electronic File: MPU I-40 EOW Geosteering Log.emf34520EDDigital DataThursday, February 25, 2021AOGCCPage 1 of 3MPU I-40 LWDFinal.las DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-23689-00-00Well Name/No. MILNE PT UNIT I-40Completion Status1-OILCompletion Date12/17/2020Permit to Drill2200710Operator Hilcorp Alaska, LLCMD17221TVD3911Current Status1-OIL2/25/2021UICNoWell Cores/Samples Information:ReceivedStart Stop CommentsTotalBoxesSample SetNumberNameIntervalINFORMATION RECEIVEDCompletion ReportProduction Test InformationGeologic Markers/TopsY Y / NAYComments:Mud Logs, Image Files, Digital DataComposite Logs, Image, Data Files Cuttings SamplesY / NAYY / NADirectional / Inclination DataMechanical Integrity Test InformationDaily Operations SummaryYY / NAYCore ChipsCore PhotographsLaboratory AnalysesY / NAY / NAY / NACOMPLIANCE HISTORYDate CommentsDescriptionCompletion Date:12/17/2020Release Date:10/27/2020DF1/6/2021 Electronic File: MPU I-40 EOW Geosteering Log.pdf34520EDDigital DataDF1/6/2021 Electronic File: MPU I-40 EOW Geosteering Log.tif34520EDDigital DataDF1/6/2021 Electronic File: MPU I-40 Geosteering End of Well Report.pdf34520EDDigital DataDF1/6/2021 Electronic File: MPU I-40 Post-Well Geosteering X-Section Summary.pdf34520EDDigital DataDF1/6/2021 Electronic File: MPU I-40 Post-Well Geosteering X-Section Summary.pptx34520EDDigital Data0 0 2200710 MILNE PT UNIT I-40 LOG HEADERS34520LogLog Header ScansThursday, February 25, 2021AOGCCPage 2 of 3 DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-23689-00-00Well Name/No. MILNE PT UNIT I-40Completion Status1-OILCompletion Date12/17/2020Permit to Drill2200710Operator Hilcorp Alaska, LLCMD17221TVD3911Current Status1-OIL2/25/2021UICNoCompliance Reviewed By:Date:Thursday, February 25, 2021AOGCCPage 3 of 3M. Guhl2/25/2021 1a. Well Status:Oil SPLUG Other Abandoned Suspended 1b. Well Class: 20AAC 25.105 20AAC 25.110 Development Exploratory GINJ WINJ WDSPL No. of Completions: _1 Service Stratigraphic Test 2. Operator Name: 6. Date Comp., Susp., or 14. Permit to Drill Number / Sundry: Aband.: 3. Address: 7. Date Spudded: 15. API Number: 4a. Location of Well (Governmental Section): 8. Date TD Reached: 16. Well Name and Number: Surface: Top of Productive Interval: 9. Ref Elevations: KB: 17. Field / Pool(s): GL: 33.6' BF: Total Depth: 10. Plug Back Depth MD/TVD: 18. Property Designation: 4b. Location of Well (State Base Plane Coordinates, NAD 27): 11. Total Depth MD/TVD: 19. DNR Approval Number: Surface: x- y- Zone- 4 TPI: x- y- Zone- 4 12. SSSV Depth MD/TVD: 20. Thickness of Permafrost MD/TVD: Total Depth: x- y- Zone- 4 5. Directional or Inclination Survey: Yes (attached) No 13. Water Depth, if Offshore: 21. Re-drill/Lateral Top Window MD/TVD: Submit electronic information per 20 AAC 25.050 (ft MSL) 22.Logs Obtained: 23. BOTTOM 20" X-52 169' L-80 1916' L-80 3772' 7-5/8" L-80 3767' 4-1/2" L-80 3911' 24. Open to production or injection? Yes No 25. 26. Was hydraulic fracturing used during completion? Yes No DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 27. Date First Production: Method of Operation (Flowing, gas lift, etc.): Hours Tested: Production for Gas-MCF: Test Period Casing Press: Calculated Gas-MCF: Oil Gravity - API (corr): Press. 24-Hour Rate 9-5/8"12-1/4" ACID, FRACTURE, CEMENT SQUEEZE, ETC. CASING, LINER AND CEMENTING RECORD List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data within 90 days of completion, Uncemented TiebackTieback TUBING RECORD Uncemented Screen Liner Liner Top Packer 8120'3-1/2" 9.3# L-80 SIZEIf Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number; Date Perfd): 8196' 17221' Stg 2 L - 690 sx / T - 270 sx 3766' Driven 13.5# Surface 2481' Stg 1 L - 950sx / T - 400 sx 8-1/2" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG Hilcorp Alaska, LLC WAG Gas 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 12/17/2020 2342' FSL, 3951' FEL, Sec. 33, T13N, R10E, UM, AK 2270' FSL, 2048' FEL, Sec. 20, T13N, R10E, UM, AK 220-071 Milne Point Field, Schrader Bluff Oil Pool 68.2' 17,221' / 3,911' HOLE SIZE AMOUNT PULLED 33.6' 50-029-23689-00-00 MPU I-40 551420 6009456 1066' FNL, 1210' FWL, Sec. 32, T13N, R10E, UM, AK CEMENTING RECORD 6011292 SETTING DEPTH TVD 6019920 BOTTOM TOP Surface Surface CASING WT. PER FT.GRADE 29.7# 546003 547943 TOP SETTING DEPTH MD Surface Surface Per 20 AAC 25.283 (i)(2) attach electronic information 40# 8207' 1916' Surface DEPTH SET (MD) 8196' / 3766' PACKER SET (MD/TVD) 129.5# 47# 169' 2481' 8368' Gas-Oil Ratio:Choke Size:Water-Bbl: PRODUCTION TEST N/A Date of Test: Flow Tubing Oil-Bbl: suspension, or abandonment, whichever occurs first. Types of logs to be listed include, but are not limited to: mud log, spontaneous potential, gamma ray, caliper, resistivity, porosity, magnetic resonance, dipmeter, formation tester, temperature, cement evaluation, casing collar locator, jewelry, and perforation record. Acronyms may be used. Attach a separate page if necessary N/A ***Please see attached Schematic for detail*** ROP, AGR, ABG, DGR, EWR, ADR MD & TVD Sr Res EngSr Pet GeoSr Pet Eng Oil-Bbl: Water-Bbl: 12/9/2020 11/25/2020 ADL 025906, 025517 & 025515 88-004 2168' / 1773' N/AN/A None 17,221' / 3,911' Form 10-407 Revised 3/2020 Submit within 30 days of Completion, Suspension, or Abandonment By Samantha Carlisle at 9:56 am, Jan 15, 2021 RBDMS HEW 1/25/2021 Completion Date 12/17/2020 HEW Liner set on 12/12/2020 GDLB 01/26/2021 DSR-2/25/21MGR24FEB2021 Conventional Core(s): Yes No Sidewall Cores: 30. MD TVD 36' 36' 2204' 1809' Top of Productive Interval 8309' 3771' 1445' 1353' 2641' 1971' 6424' 3246' 7986' 3742' 8309' 3771' SB NB 8309' 3771' 31. List of Attachments: 32. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Name: Joe Lastufka Contact Email:joseph.lastufka@hilcorp.com Authorized Contact Phone: 777-8400 General: Item 1a: Item 1b: Item 4b: Item 9: Item 15: Item 19: Item 20: Item 22: Item 23: Item 24: Item 27: Item 28: Item 30: Item 31: If Yes, list formations and intervals cored (MD/TVD, From/To), and summarize lithology and presence of oil, gas or water (submit separate pages with this form, if needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071. Authorized Name: Monty Myers Authorized Title: Drilling Manager Schrader Bluff NB Permafrost - Base 29. GEOLOGIC MARKERS (List all formations and markers encountered): FORMATION TESTS Permafrost - Top Schrader Bluff NA SV5 SV1 This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed. All laboratory analytical reports regarding samples or tests from a well must be submitted to the AOGCC, no matter when the analyses are conducted. Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, core analysis, paleontological report, production or well test results, per 20 AAC 25.070. Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. TPI (Top of Producing Interval). Yes No Well tested? Yes No 28. CORE DATA If yes, list intervals and formations tested, briefly summarizing test results. Attach separate pages to this form, if needed, and submit detailed test information, including reports, per 20 AAC 25.071. NAME Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data within 90 days of completion, suspension, or abandonment, whichever occurs first. Well Class - Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Formation at total depth: Ugnu LA3 LOT / FIT Data Sheet, Drilling and Completion Reports, Definitive Directional Survey, Csg and CMT Report, Wellbore Schematic Signature w/Date: Report the Division of Oil & Gas / Division of Mining Land and Water: Plan of Operations (LO/Region YY-123), Land Use Permit (LAS 12345), and/or Easement (ADL 123456) number. INSTRUCTIONS The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and other tests as required including, but not limited to: core analysis, paleontological report, production or well test results. Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29. Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity, permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology. Form 10-407 Revised 3/2020 Submit within 30 days of Completion, Suspension, or Abandonment 1.15.2021Digitally signed by Monty M Myers DN: cn=Monty M Myers, c=US, o=Hilcorp Alaska, LLC, ou=Technical Services - AK Drilling, email=mmyers@hilcorp.com Reason: I am approving this document Date: 2021.01.15 08:59:40 -09'00' Monty M Myers _____________________________________________________________________________________ Page 1 of 2 Edited By: JNL 1/12/2021 SCHEMATIC Milne Point Unit Well: MPU I-40 Last Completed: 12/17/2020 PTD: 220-071 TD =17,221’(MD) / TD =3,911’ (TVD) 4/5 20” Orig. KB Elev.: 68.20’ / GL Elev.: 33.6’ 7-5/8” 9 10 11 4 17 9-5/8” 1 2 3 See Screen/ Solid Liner Detail PBTD =17,221’ (MD) / PBTD = 3,911’ (TVD) 9-5/8” ‘ES’ Cementer @ 2,481’ MD 6/7/8 4-1/2” Shoe @ 17,221’ 12/13 15 14 16 2-7/8” CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20" Conductor 129.5 / X52 / Weld N/A Surface 169’ N/A 9-5/8" Surface 47 / L-80 / TXP 8.681 Surface 2,481’ 0.0758 9-5/8” Surface 40 / L-80 / TXP 8.835 2,481’ 8,368’ 0.0732 7-5/8” Tieback 29.7 / L-80 / Hyd 521 6.875 Surface 8,207’ 0.0459 4-1/2” Liner 250ђ Screens 13.5 / L-80 / Hyd 625 3.920 8,196’ 17,221’ .0149 TUBING DETAIL 3-1/2" Tubing 9.3 / L-80 / EUE-8rd 2.441 Surface 8,120’ 0.0087 OPEN HOLE / CEMENT DETAIL 20” Driven 12-1/4"Stg 1 Lead – 950 sx / Tail – 400 sx Stg 2 Lead – 690 sx / Tail – 270 sx 8-1/2” Cementless Screened Liner WELL INCLINATION DETAIL KOP @ 334’ Max Hole Angle = 96° @ 10,678’ MD TREE & WELLHEAD Tree Cameron 2-9/16" 5M w/ 4-1/16” 5M Cameron Wing Wellhead Cameron 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs GENERAL WELL INFO API: 50-029-23689-00-00 Completion Date: 12/17/2020 JEWELRY DETAIL No. Top MD Item ID 1 136’ GLM w/ ¼” DPSOV 2.909” 2 6882’ 3-1/2” GLM w/ 1” Dummy Valve 2.907” 3 7003’ XN Nipple, 2.313” Profile, 2.75” No Go 2.760” 4 7057’ Discharge Head: B/O PMP 513 3.5X 8MD EUE 5 7057’ Zenith Ported Sub: Press Port 513/538P 6 7058’ Upper Pump: 538PMSXD 066 Flex 47H6 7 7074’ Middle Pump: 538PMSXD 068 G31 M FER 8 7087’ Lower Pump: 538PMSXD 20 GINPSHH H6 9 7097’ Gas Separator: 538GSTHVEV H6 STD PNT WC ENH 10 7102’ Upper Tandem Seal: GSBDB H6 SB/AB PFSA 11 7109’ Lower Tandem Seal: GSBDB H6 SB/AB PFSA 12 7116’ Motor: 562XP – 400 HP 2785V / 88A 13 7142’ Motor Gauge Zenith PT00752 14 7144’ Centralizer: Bottom @ 7146’ MD 15 8196’ BOT SLZXP LTP / Liner Hanger 7” x 9-5/8” (TBD TVD) 6.190” 16 8217’ 7” H563 x 4.5” TSH 625 XO 3.850” 17 17219’ Shoe 3.950” CASING AND LEAK-OFF FRACTURE TESTS Well Name:MPU I-40 Date:12/3/2020 Csg Size/Wt/Grade:9.625"40# x 47#, L-80 Supervisor:Sunderland/Demoski Csg Setting Depth:8368 TMD 3771.9 TVD Mud Weight:9.3 ppg LOT / FIT Press =530 psi . LOT / FIT =12.00 ppg Hole Depth =6375 md Fluid Pumped=1.3 Bbls Volume Back =1.3 bbls Estimated Pump Output:0.101 Barrels/Stroke LOT / FIT DATA CASING TEST DATA Enter Strokes Enter Pressure Enter Strokes Enter Pressure Here Here Here Here ->00 ->00 ->131 ->4150 ->2 138 ->10 389 ->3 170 ->16 677 ->4 200 ->20 839 ->5 231 ->25 1046 ->6 263 ->30 1248 ->7 301 ->35 1461 ->8 352 ->40 1698 ->9 390 ->45 1911 ->10 429 ->50 2150 ->11 494 ->55 2395 ->12 539 ->60 2633 ->13 574 ->64 2797 Enter Holding Enter Holding Enter Holding Enter Holding Time Here Pressure Here Time Here Pressure Here ->0 574 ->0 2797 ->1 569 ->5 2791 ->2 566 ->10 2785 ->3 561 ->15 2779 ->4 557 ->20 2776 ->5 554 ->25 2772 ->6 551 ->26 2771 ->7 547 ->27 2770 ->8 545 ->28 2770 ->9 544 ->29 2769 ->10 543 ->30 2768 ->11 543 -> ->12 543 -> -> -> -> -> -> 0 1 2 3 4 5 6 7 8 9 10 11 1213 0 4 10 16 20 25 30 35 40 45 50 55 60 64 0 100 200 300 400 500 600 700 800 900 1000 1100 1200 1300 1400 1500 1600 1700 1800 1900 2000 2100 2200 2300 2400 2500 2600 2700 2800 2900 3000 0 10203040506070Pressure (psi)Strokes (# of) LOT / FIT DATA CASING TEST DATA Pressure (psi) 574569566561557554551547545544543543543 2797 2791 2785 2779 2776 277227712770277027692768 0 100 200 300 400 500 600 700 800 900 1000 1100 1200 1300 1400 1500 1600 1700 1800 1900 2000 2100 2200 2300 2400 2500 2600 2700 2800 2900 3000 0 5 10 15 20 25 30 35Pressure (psi)Time (Minutes) LOT / FIT DATA CASING TEST DATA Activity Date Ops Summary 11/22/2020 See F-62A completions report for details. PJSM. R/D peripheral equipment. Demob rockwasher, 3rd party shacks. Skid floor into rig move position. RDMO of F- 62A. Walk sub off well and around well row staged to exit pad. Remove BOPE Stack from Cellar. Install rear booster tires and move Rig off F Pad Move Rig from F pad to L pad. Stage at entrance for Crew changes. 11/23/2020 With rig staged at L-Pad entrance, wait on crew change, inspect rig move system Move rig from L-pad, turn right onto Milne Point spine intersection at 4.7 miles, turn right onto G-H and I pad access road at 6.2 miles. Remove bull rails as needed, mat all pipe line crossings Move rig to I-Pad, pass G-H Pad, turn left onto I-Pad access road arriving at I-Pad, 10.3 mile rig move Pull onto I-40 side of pad, turn rig around to back over well, remove front and rear boosters, remove front booster brace. Install staircase at back end of Rig. Set BOP stack on pedestal in cellar and secure. Hang surface Annular preventer from Cellar bridge cranes. Spot rig over I-40. Sim and level rig. Spot service/support buildings Build containment for cuttings tank. PJSM, Skid rig to drill position. Secure roof landings and handrails. Spot cuttings tank and rock washer. Hook up service lines to rig floor, get steam going. Re-Shim pipeshed ODS to level. Spot fuel tank. Work on acceptance checklist. 11/24/2020 R/U rig floor service lines, high pressure mud lines, with joint 5'' DP check rig level, good. Hoist diverter stack and tee, Mobilize 21 1/4'' diverter spool to cellar. Start offloading 8.8 ppg spud mud to the pits. Work on acceptance checklist. N/U 21 1/4'' x 15'' long spool on conductor flange due to diverter tee height so diverter line will clear ground level after leveling the pad, N/U Diverter and tee, R/U diverter line. Put rig on Hi Line @ 13:50 Change out saver sub and grabber dies, IT get comms up and running. Drain rig water tank, welder repair pinhole leak in same. Load BHA in shed. Rebuild 4'' demco valves on mud pumps. Load 580 bbls spud mud into pits. Rig electrician test rig gas alarms. Continue to work on acceptance checklist Continue to N/U diverter line. Continue to work on rig acceptance checklist. C/O top drive saver sub. Install 90' mousehole. Load 5" HWDP & jars into the pipe shed. Slip and cut 46' of drilling line. Service and inspect drawworks. Service top drive. Finished repair of rig water tank. Rig accepted at 22:00. Clear the rig floor of 4" handling equipment. Mobilize 5" handling equipment and BHA components to the rig floor. P/U 17 joints of 5" HWDP and jars, racking back 6 stands in the derrick. Function test annular on 5" HWDP: 24 sec. knife valve open time, 31 sec. annular close time. Accumulator test: 2875 PSI system pressure, 1750 PSI after closure, 200 PSI recovery 40 sec. full recovery 166 sec. 6 bottle nitrogen avg 2150 PSI. 177.5' total length of diverter line, 170' from sub-structure & 82' from closest ignition point. Test notification made at 22:01 on 22 Nov 2020. AOGCC inspector Robert Noble waived witness of testing at 18:40 on 23 Nov 2020. M/U 12-1/4" Kymera K5M633X bit, 8" mud motor, XO sub to 35'. M/U stand of 5" HWDP. Pre-spud meeting w/ Doyon, M-I, Sperry, Peak, GyroData and DSM on rig floor while maintaining social distancing. Discuss hazards, evacuation procedures & safe briefing areas. Notify pad operator of spud. Flood lines w/ water & pressure test to 3500 PSI - good. Verify PVT levels, G/L & flow alarms. Displace water w/ spud mud. Tag fill in driven conductor at 58. Clean out conductor from 58' to 101', 450 GPM, 550 PSI, 30 RPM, 2K TQ, 2K WOB. 49K PU / 50K SO / 50K ROT. MW 8.8 in / 8.9 out, vis 140 in / 200 out. Observe sand and gravel over the shakers. #2 conveyor stalled. Stop reaming and shut down pumps. Service rig while investigating conveyor. Blow down top drive. Conveyor chain paddles were contacting angle iron cross member at the rock washer end of the conveyor. Cross member non-structural support for cover. Cut out angle iron as per Doyon toolpusher. Test run conveyor - good. H20 from 6-Mile: 410 bbls Daily / 410 bbls Total. H20 from Lake 2: 290 bbls Daily / 290 bbls Total. Cuttings/mud/cement to MPU G&I: 0 bbls Daily / 10 bbls Total. 11/25/2020 Continue to clean out 20'' conductor from 101' to 169', 450 GPM, 550 PSI, 30 RPM, 2K TQ, 2K WOB. 49K PU / 50K SO / 50K ROT. Drill 12-1/4" surface hole f/ 169' t/ 219' (219' TVD), 105' drilled, 105'/hr AROP. 450 GPM, 550 PSI, 30 RPM, 1-2K TQ, 1-2K WOB. 50K PU / 50K SO / 50K ROT. BROOH f/ 219' t/ 169' two times, flow check- static. BD TD. POOH f/ 169' & inspect bit - good. PJSM for BHA. P/U GWD, EWR, ILS, DM and TM collars, UBHO sub to 101'. Perform offsets & UBHO orientation, Initialize MWD tools, cannot read resistivity tool, troubleshoot same, L/D EWR-M5, M/U backup tool. Re-do offsets, DM-mtr offset = 162.71 deg, DM-GWD offset= 222.13 deg, Initialize MWD tools. MPU in Phase 2 weather at 12:54. Having trouble with the hi speed com board talking to backup MWD tool, troubleshoot same, try with another laptop with old software. No success. Decided to pump through the tool string to warm up the tools. M/U stand of 5" drill pipe w/ XO to MWD toolstring. Pump 180 GPM, 190 PSI. Rack back stand & blow down top drive. Pumping warmed up tool about 4°. Successfully initialized the tools. Carry scribe line and orient UBHO sub. M/U three non-mag flex drill collars to 188'. M/U stand of HWDP and pulse test MWD tools 450 GPM, 855 PSI - good. Ream to bottom with 40 RPM and resume drilling. Drill 12-1/4"" surface hole f/ 219' t/ 444' (444' TVD) 225' drilled, 90'/hr AROP. 450 GPM, 980 PSI, 40 RPM, 2K TQ, 2K WOB. MW 9.1 in / 9.15 out, vis 295 in / 300+ out, 9.98 ECD. 60K PU / 65K SO / 63K ROT. Begin planned 3°/100' build at 281'. Drill 12-1/4"" surface hole f/ 444' t/ 996' (977' TVD) 552' drilled, 92'/hr AROP. 490 GPM, 1290 PSI, 40 RPM, 4K TQ, 5-10K WOB. MW 9.2 in / 9.3 out, vis 300+ in / 300+ out, 9.95 ECD. 80K PU / 80K SO / 80K ROT. Begin planned 4°/100' build & turn at 550'. Installed gas detector in possum belly at 850'. Last survey at 896.77' MD / 885.08' TVD, 20.00° inc, 233.33° azm, 9.90' from plan, 3.25' low, 9.35' right. MPU at Phase 1 weather at 5:53. Losses: 0 bbls Daily / 0 bbls Total. H20 from 6-Mile: 325 bbls Daily / 735 bbls Total. H20 from Lake 2: 290 bbls Daily / 290 bbls Total. Cuttings/mud/cement to MPU G&I: 285 bbls Daily / 295 bbls Total. 11/26/2020 Drill 12-1/4'' surface hole f/ 996' t/ 1602' (1470' TVD) 606' drilled, 101'/hr AROP. 500 GPM, 1600 PSI, 40 RPM, 5-6K TQ, 10K WOB. MW 9.3 in / 9.35 out, vis 200 in / 250 out, 10.1 ECD, max gas 33u. 95K PU / 86K SO / 88K ROT. Build 4 deg/100' Drill 12-1/4'' surface hole f/ 1602' t/ 2300' (1847' TVD) 698' drilled, 116.3'/hr AROP. 500 GPM, 1500 PSI, 60 RPM, 7K TQ, 5-12K WOB. MW 9.4 in / 9.6 out, vis 132 in / 221 out, 10.25 ECD. 103K PU / 80K SO / 88K ROT. BOPF came in at 2204' MD 1807' TVD with max gas 220u. Hold 4 deg/100' Drill 12-1/4'' surface hole f/ 2300' t/ 3030' (2103' TVD) 730' drilled, 121.67'/hr AROP. 500 GPM, 1630 PSI, 60 RPM, 7K TQ, 5-12K WOB. MW 9.4 in / 9.4 out, vis 163 in / 154 out, 10.13 ECD, max gas 673u. 105K PU / 75K SO / 86K ROT. Hold 4°/100' to EOB @ 2328' then hold 69° tangent Pumped sweep @ 2553', back on time w/ 10% increase. Drill 12-1/4'' surface hole f/ 3030' t/ 3695' (2337' TVD) 665' drilled, 110.83'/hr AROP. 500 GPM, 1710 PSI, 60 RPM, 8K TQ, 6-14K WOB. MW 9.5 in / 9.6 out, vis 125 in / 290 out, 10.69 ECD, max gas 157u. 106K PU / 78K SO / 91K ROT. Pumped sweep @ 3085', back 200 stks late w/ 10% increase, sweep @ 3530', back on time w/ 25% increase. Survey @ 3560.13' MD / 2290.01' TVD, 68.63° inc, 266.28° azm, 3.79' from plan, 2.68' high & 2.67' left. Losses: 0 bbls Daily / 0 bbls Total. H20 from 6-Mile: 1180 bbls Daily / 1915 bbls Total. H20 from Lake 2: 870 bbls Daily / 1160 bbls Total. Cuttings/mud/cement to MPU G&I: 1720 bbls Daily / 2015 bbls Total. Well Name: Field: MP I-40 Milne Point Hilcorp Energy Company Composite Report 11/25/2020Spud Date: 11/27/2020 Drill 12-1/4'' surface hole f/ 3695' t/ 4457' (2611' TVD) 762' drilled, 127'/hr AROP. 550 GPM, 1890 PSI, 80 RPM, 10K TQ, 5-10K WOB. MW 9.4 in / 9.45 out, vis 78 in / 115 out, 9.94 ECD, max gas 157u. 125K PU / 75K SO / 95K ROT. Hold 69 deg tangent to 4047', target 71 deg Pump 30 bbl hi vis sweep @ 4197', back on time with no increase. UG3 came in at 4340' md, 2574' tvd. At 4400' Screen up shakers f/ 140s to 170s Drill 12-1/4'' surface hole f/ 4457' t/ 5218' (2845' TVD) 761' drilled, 126.83'/hr AROP. 550 GPM, 2270 PSI, 80 RPM, 14K TQ, 15K WOB. MW 9.3 in / 9.5 out, vis 82 in / 200 out, 10.1 ECD, max gas 156u. 135K PU / 74K SO / 100K ROT. Hold 71° tangent. Drill 12-1/4'' surface hole f/ 5218' t/ 5840' (3052' TVD) 622' drilled, 103.67'/hr AROP. 545 GPM, 2090 PSI, 80 RPM, 14K TQ, 14K WOB. MW 9.3 in / 9.35 out, vis 74 in / 137 out, 10.07 ECD, max gas 132u. 157K PU / 72K SO / 105K ROT. Pump sweep at 5218' back on time w/ 30% increase. Hold 71° tangent to 5690', then start planned 4°/100' turn. Drill 12-1/4'' surface hole f/ 5840' t/ 6329' (3224' TVD) 489' drilled, 81.5'/hr AROP. 540 GPM, 2000 PSI, 80 RPM, 16K TQ, 14-21K WOB. MW 9.3 in / 9.3 out, vis 98 in / 131 out, 10.27 ECD, max gas 156u. 169K PU / 68K SO / 107K ROT. Added 0.5% ScreenKleen at 6040'. Last survey @ 6226.68' MD / 3185.24' TVD, 68.07° inc, 296.95° azm, 5.18' from plan, 3.12' high & 4.13' left. Losses: 0 bbks Daily / 0 bbls Total. H20 from 6- Mile: 1600 bbls Daily / 3515 bbls Total. H20 from Lake 2: 225 bbls Daily / 1385 bbls Total. Cuttings/mud/cement to MPU G&I: 1549 bbls Daily / 3564 bbls Total. 11/28/2020 Drill 12-1/4'' surface hole f/ 6329' t/ 6837' (3402' TVD) 508' drilled, 84.6'/hr AROP. 450-550 GPM, 2180 PSI, 80 RPM, 16K TQ, 16K WOB. MW 9.3 in / out, vis 76 in / 99 out, 9.93 ECD, max gas 218u. 172K PU / 79K SO / 115K ROT. Turn 4°/100' Sweep pumped at 6340', back strung out with no increase. At 6680' traces of oil at shakers, by 6800' shakers blinding off w/ heavy oil, screen down to 140s and lower to 450 gpm, 1590 psi, recycle the mud from rock wash across shakers. Ugnu LA3 top logged in at 6424' MD Drill 12-1/4'' surface hole f/ 6837' t/ 7410' (3596' TVD) 573' drilled, 95.5'/hr AROP. 550 GPM, 2320 PSI, 80 RPM, 18K TQ, 10-15K WOB. MW 9.4 in / 9.4 out, vis 63 in / 93 out, 10.0 ECD, max gas 1150u. 185K PU / 75K SO / 120K ROT. Continue to turn 4°/100' to 7077' then hold 71° tangent Ugnu MB sand logged at 7070' MD. Continue to deal with shakers blinding off with heavy oil from LC sand, recycle mud from rock wash back across shakers, screen down to 100s /60s, increase screen kleen to 1% and flow rate to 550 gpm, At 7405' seen 1005u gas from drilling the MD2 sand. Pump tangent from 7078' to 7376'. Drill 12-1/4'' surface hole f/ 7410' t/ 7694' (3676' TVD) 284' drilled, 47.33'/hr AROP. 550 GPM, 2320 PSI, 80 RPM, 18-20K TQ, 15-20K WOB. MW 9.4 in / 9.5 out, vis 73 in / 120 out, 10.09 ECD, max gas 734u. 185K PU / 65K SO / 115K ROT. Began 4.5°/100' build & turn at 7408'. Losing mud over the shakers, shut down & install 80 mesh screens on shakers at 7493'. Pump high vis sweep at 7493', 300 stokes late, 10% increase. Drill 12-1/4'' surface hole f/ 7694' t/ 8075' (3777' TVD) 381' drilled, 63.5'/hr AROP. 540 GPM, 2300 PSI, 80 RPM, 18K TQ, 18K WOB. MW 9.4 in / 9.4 out, vis 87 in / 116 out, 10.02 ECD, max gas 339u. 195K PU / 66K SO / 120K ROT. Entered Schrader Bluff at 7986' MD Last survey at 7939.75' MD / 3747.44' TVD, 75.54° inc, 5.96° azm, 14.36' from plan, 13.08' low and 5.91' left. Losses: 0 bbls Daily / 0 bbls Total. H20 from 6-Mile: 1385 bbls Daily / 4900 bbls Total. H20 from Lake 2: 300 bbls Daily / 1685 bbls Total. Cuttings/mud/cement to MPU G&I: 1524 bbls Daily / 5088 bbls Total. 11/29/2020 Drill 12-1/4'' surface hole f/ 8075' t/ 8375' (3785' TVD) landing out in the NB sand @ 91°, TD surface section. 544 GPM, 2280 PSI, 80 RPM, 20K TQ, 22K WOB. MW 9.4 in / 9.4 out, vis 63 in / 99 out, 10.15 ECD, max gas 187u. 190K PU / 66K SO / 117K ROT. NB sand top logged at 8309' md, 3786' tvd. Pump 30 bbl hi vis sweep with 6 ppb nut plug added, 550 gpm, 2340 psi, 80 rpm, 20k tq cleanup the wellbore, back on time, no increase. circulate 1 .5 BU racking a stand back each BU to 8265', Lower YP from 26 to 19. Final survey: 4.32' below the line, 10.29' left. Orient high side, Run back to bottom on elevators. 20 minutes to downlink Gyro for BR, Flow check, well is static. BROOH pulling 5-10 min stand f/ 8375' to 4363', 550 gpm, 1800-2240 psi, 80 rpm, 15-20k tq. 119K PU / 75K SO / 108K ROT, max gas 95u. Observed pack-off at 5700', slack-off and ream through again without issue, pull next stand slow. Treat mud while BR. BROOH pulling 5-10 min stand f/ 4363' t/ 1488', 550 GPM, 1580-1800 PSI, 80 RPM, 6-15 TQ. Increase viscosity at base of permafrost to 90-100. 110K PU / 76K SO / 90K ROT, max gas 35u. 14.9 bbls lost while BROOH. Losses: 6 bbls Daily (midnight) / 6 bbls Total. H20 from 6-Mile: 1165 bbls Daily / 6065 bbls Total. H20 from Lake 2: 0 bbls Daily / 1685 bbls Total. Cuttings/mud/cement to MPU G&I: 1140 bbls Daily / 6228 bbls Total. 11/30/2020 BROOH pulling 5-10 min stand f/ 1488' t/ 749' to the HWDP. The hole unloaded at 810', pull slow and allow to cleanup. 550 GPM, 1580-1400 PSI, 80 RPM, 2-8 TQ. 13.2 bbls losses BROOH. Attempt to pull on elevators, 10k overpull , BROOH out from 749' to 550' pumping 550 gpm, 1400 psi, 80 rpm. Attempt to pull on elevators, swabbing. Pump out at 300 gpm to 285', Flow check well, static. BD TD, Pull on elevators to 191', L/D 3 flex collars to 102', Plug in-read MWD tools. L/D remaining BHA form 102' , 12-1/4'' Bit grade= 1-2-CT-T-E-2-WT-TD, ILS under cut from BR, mtr stab had excessive wear and 1/4'' under gauge. Load out tools, clean rig floor. Mobilize 9-5/8'' casing tools to rig floor, R/U Volante, bail extensions, single joint elevators and slips, Ready FOSV and XO. Monitor well, 3 bph loss rate PJSM, M/U 9-5/8" shoe track: round nose float shoe, Baker lock joint, install top hat after M/U FC joint. Ensure proper float operation - good. M/U baffle adapter & joint #4 to 165' Torque all connections to 21,000 ft/lbs w/ Volant tool, Two 9-5/8" x 12-1/4" centralizer & 4 stop rings on shoe joint, 1 free floating centralizer on Baker-Loc joint, 1 centrailizer w/ 2 stop rings on the float collar and baffle adapter joints. Run 9-5/8" 40# L-80 TXP-BTC casing f/ 165' t/ 2783' . Torque to 21,000 ft/lbs with the Volant tool. Install 9-5/8" x 12-1/4" bow spring centralizers on jts #5-26 then every other joint to jt 51 then every third joint. Fill casing on the fly & top off every 10 joints. Stage up to 6 BPM, 200 PSI and circulate a bottoms up while reciprocating 30'. 135K PU / 86K SO, MW 9.55 in / 9.7 out, vis 100 in / 210 out. Run 9-5/8" 40# L-80 TXP-BTC casing f/ 2783' t/ 5619' . Torque to 21,000 ft/lbs with the Volant tool. Install 9-5/8" x 12-1/4" bow spring centralizers on every third joint. Fill casing on the fly & top off every 10 joints. 71.2 bbls lost for casing run to this point. Stage up to 6 BPM, 300 PSI and circulate a bottoms up while reciprocating 30'. 212K PU / 70K SO, MW 9.4 in / 9.6 out, vis 85 in / 171 out. Losses: 63 bbls Daily (midnight), 69 bblsTotal. H20 from 6-Mile: 925 bbls Daily / 6990 bbls Total. H2O from G&I Source Water: 100 bbls Daily / 100 bbls Total. H20 from Lake 2: 0 bbls Daily / 1685 bbls Total. Cuttings/mud/cement to MPU G&I: 741 bbls Daily / 6969 bbls Total. 12/1/2020 Finish circulating a bottoms up at 6 BPM, 300 PSI while reciprocating 30'. 212K PU / 70K SO, MW 9.4 in / 9.6 out, vis 85 in / 171 out. No losses while circulating. Run 9-5/8" 40# L-80 TXP-BTC casing f/ 5619' t/ 8370'. Torque to 21,000 ft/lbs with the Volant tool. Install 9-5/8" x 12-1/4" bow spring centralizers on every third joint to joint #141, then every joint to #151. Installed ES cementer between joints #146 & 147, thread lock both connections. One centralizer & 2 stop rings installed on each pup joint above and below the ES cementer. Begin 9-5/8" 47# L-80 TXP-BTC casing on joint #147, torque to 24,000 ft/lbs with the Volant tool. Install centralizers every 3rd joint f/ #154 to #202. Fill casing on the fly & top off every 10 joints. 206 total joints ran, 146 each 40# and 60 each 47#. 97 total 9-5/8" x 12- 1/4" bow spring centralizers ran and 12 stop rings. 98.7 bbls total lost while running casing. Provided BOP test notification to the AOGCC @ 11:48 on 1 Dec 2020. Circulate and condition the mud prior to the cement job. 6 BPM, 590 ICP / 480 FCP, 5 RPM, 20K TQ. Reciprocate 24' f/ 8368' t/ 8344'. 275K PU / 60K SO. MW 9.45 in / 9.6 out, vis 65 in / 153 out. 3.8 bbls lost. PJSM for cement job. Blow down top drive. R/U cement lines. Establish circulate at 6 BPM, 460 PSI. Pump 50 bbls SAPP pre-treated 9.4 ppg spud. Perform 1st stage cement job. HES fill lines with 5 bbls fresh water. PT lines to 1000 PSI low / 4500 PSI high. Pump 60 bbls 10 ppg Tuned Spacer w/ red dye & 5# Pol-E-Flake in 1st 10 bbls, 3 BPM, 250 PSI. Drop bypass plug. Mix & pump 397 bbls 12.0 ppg Type I/II cement 2.347 ft^3/sk yield, 950 sks, 4.5 BPM, 300 PSI. Mix & pump 82 bbls 15.8 ppg Premium G cement 1.153 ft^3/sk yield, 400 sks, 4.5 BPM, 330 PSI, drop shutoff plug. Pump 20 bbls of fresh water with Halliburton at 6.5 BPM, 450 PSI. Displace w/ 9.4 ppg spud mud Displace w/ 406.7 bbls, 7 BPM, 570 PSI, Halliburton pumped 80 bbls 9.4 ppg Tuned Spacer, 5.7 BPM, 750 PSI, then finish w/ 109.38 bbls, 8.0 BPM, 640 PSI from rig. Slowed to 3 BPM, 820 PSI for last 10 bbls, bumped plug at 5109 stks (2.72 bbls early) & pressure up to 1250 PSI & hold for 3 min. 8 bbls lost. CIP at 19:24 Bleed off pressure and check floats. Observe slight flow back @ 0.5 BPH. Pressure up to 1400 PSI and hold for 1 min. Bleed off & still observe 0.5 BPM flow back. Suspect ES cementer partially opened. Pressure up to open ES cementer. At 1800 PSI observed circulation, cementer was pinned for 3300 PSI. Pump through ES cementer: 4.7 BPM, 1020 PSI. Increase to 5.4 BPM, 950 PSI then final 6.0 BPM, 1070 PSI. Observe interface back at 1750 strokes, good cement from 2750 strokes to 3250 strokes. Take returns to the pits at 3350 strokes. 50 bbls of cement & 111 bbls of interface dumped to rock washer. Continue to circulate through ES cementer at 6.0 BPM, thick returns at 7150 stks, slow to 5.5 BPM, 600 PSI. Cleaned up by 8150 stks, increase to 6 BPM. Shut down at 9910 stks, 3x bottoms up. No losses. Drain stack & flush with black water. Disconnection knife valve accumulator lines. Function and flush annular 2x with black water. Re-connection accumulator lines. Clean out 4" conductor drain valves. Clean & inspect the Volant tool. B/D top drive. Stage up pumps to 6 BPM, 630 PSI ICP / 440 PSI FCP. Continue to circulate through the ES cementer @ 2481' while hauling off cement and mud returns. Prepare the mud pits for 2nd stage cement job. Haul 500 bbls 80° heated water. PJSM for cement job. Shut down rig pumps & line up cementers. No losses. Perform 2nd stage cement job. Flood lines w/ 5 bbls water. Mix & pump 60 bbls of of 10.0 ppg Tuned Spacer 4.1 BPM, 360 PSI. Mix & pump 365 bbls of 10.7 ppg ArcticCem Lead Cement 2.944 ft^3/sk yield, 690 sks, 6.5 BPM, 1050 PSI. Observed good cement back @ 316 bbls & begin batching tail @ 343 bbls. Observed. Mix & pump 56 bbls of 15.8 ppg Premium G Tail Cement 1.169 ft^3/sk yield, 3.3 BPM, 510 PSI. Drop closing plug. HES pump 20 bbls water, 7 BPM, 760 PSI. Displace w/ 9.4 ppg spud mud @ 6 BPM, 260 PSI ICP / 910 PSI FCP. Slow to 3 BPM, 540 PSI for last 10 bbls. Lost returns last 10 bbls pumped. Bump plug at 1620 stks (1.62 bbls late). Pressure up and observe ES cementer close at 1800 PSI. CIP at 05:13. 289 bbls of cement to surface and 87 bbls of interface. Awaiting final volumes from trucks & rock washer. Drain cement from the diverter stack to the cellar and flush with black water. Function annular 4x times. Losses: 59.8 bbls Daily / 128.8 bbls Total. H20 from 6-Mile: 325 bbls Daily / 7315 bbls Total. H2O from G&I Source Water: 460 bbls Daily / 560 bbls Total. H20 from Lake 2: 0 bbls Daily / 1685 bbls Total. Cuttings/mud/cement to MPU G&I: 1347 bbls Daily / 8316 bbls Total. 12/2/2020 R/D Doyon Volant CRT, B/D hoses, vacuum out mud from casing joint prior to cut, de-energize accumulator and L/D mouseholes. Sim-ops: clean pits. Hoist surface diverter, set casing in tension and wellhead representative installed casing slips. Set casing with 100K on slips. Doyon welder cut casing 31" above slips. L/D cut joint: 19.31' cut joint length. Continue to clear casing equipment and L/D surface riser. Remove 16" diverter line. N/D 20" ann ular. Set up cart & track assembly. Remove annular & diverter tee from the cellar. R/D diverter line. Sim-ops: clean pits and process 4.5" screems. Doyon welder perform final prep on 9-5/8" casing cut. Mobilize wellhead equipment into the cellar. Install FMC Sliplock head, casing and tubing spools. Pressure test to 250 PSI low for 5 min & 3800 PSI high for 10 min. N/U BOP stack and install choke and kill lines. N/U riser. Remove lower 4-1/2"x7" VBR and install 2-7/8"x5" VBR. Mobilize 3.5" & 5" test joints, test plug and wear bushing to the rig floor. Install both mouseholes. Install test plug and 3.5" test joint. R/U test equipment. Flood lines and perform BOP shell test - good. No failures. Perform BOP test as per Hilcorp and PTD requirements. AOGCC inspector Guy Cook waived the right to witness at 13:40 on 1 Dec 2020. All tests performed with fresh water against a test plug. All tests performed to 250 PSI low / 3000 PSI high and held for 5 min. and charted. Test gas alarms and PVT. 1) Annular on 3.5" test joint, choke valves #1, 12, 13, 14, kill Demco & 5" dart valve. 2) 2-7/8" x 5" upper VBR on 3.5" test joint, choke valves #9, 11, kill HCR & 5" FOSV #1. 3) 2-7/8" x 5" lower VBR on 3.5" test joint & 5" FOSV #2 4) 2-7/8" x 5" upper VBR on 5" test joint, choke valves #5, 8, 10, kill manual & 3.5" dart valve. 5) Choke valves #4, 6, 7 & 3.5" FOSV. 6) Choke valve #2. 7) Choke HCR & upper IBOP. 8) Manual choke & lower IBOP. 9) 2-7/8" x 5" lower VBR on 5" test joint. 10) Choke valve 3 & blind rams. 11) Manual choke B 12) Super choke A. Accumulator test: System pressure 3000 PSI, After closure 1625 PSI, 200 PSI recovery 43 sec, full recovery 189 sec, 6 nitrogen bottle average 2198 PSI. Drain stack, blow down lines, R/D test equipment, pull test plug and L/D test joint. Install 9-3/16" I.D. wear bushing. Inspect top drive saver sub and grabber dies. Saver sub threads worn. Install new saver sub Losses: 10 bbls Daily / 138.8 bbls Total. H20 from 6- Mile: 310 bbls Daily / 7625 bbls Total. H2O from G&I Source Water: 400 bbls Daily / 960 bbls Total. H20 from Lake 2: 0 bbls Daily / 1685 bbls Total. Cuttings/mud/cement to MPU G&I: 934 bbls Daily / 9250 bbls Total. 12/3/2020 Finish changing out top drive saver sub. Inspected grabber dies - good. Skid conveyor #2 into normal position. L/D test joints and install mousehole. Mobilize BHA components to the rig floor. M/U 8-1/2" Smith XR+ rerun bit, 6-3/4" mud motor with 1.5° AKO and float sub to 35'. TIH w/ HWDP to 593'. TIH on 5" drill pipe from the derrick to 1078'. 75K PU / 61K SOW. Perform unannounced rig evacuation drill. Well secure in 1 min 35 sec and all personnel accounted for at muster area in 4 min 45 sec. Perform After Action Review w/ DSM, Doyon tool pusher and rig crew. TIH on 5" drill pipe from the derrick f/ 1078' t/ 2397'. 93K PU / 63K SO. Service rig and inspect the top drive. Repair rig: weld wear plate on #2 conveyor and install new sprocket. Sim-ops: Process 4.5" production screens, inspect ST-80, dilute mud in pit #4. Install MPD lines. TIH f/ 2400' t/ 2475'. Est. parameters: 450 GPM, 950 PSI, 40 RPM, 5K TQ, 100K PU / 75K SO / 90K ROT. Ream f/ 2480 and tag ES cementer on depth. Drill ES cementer f/ 2480' t/ 2482' with 5-6K WOB & ream to 2495'. Ream 3x times then trip through clean with no pumps or rotary. 95K PU / 75K SO. TIH on 5" drill pipe from the derrick f/ 2495' t/ 6750', 175K PU / no SO / 115K ROT. Ran out of slack off weight due to casing drag. Wash & ream f/ 6750' t/ 7921', 300 GPM, 820 PSI, 40 RPM, 23-25K TQ, 115K ROT. Perform unannounced rig evacuation drill. Well secure in 2 min 27 sec and all personnel accounted for at muster area in 5 min 53 sec. Perform After Action Review w/ DSM, Doyon tool pusher and rig crew. Wash & ream f/ 7921' t/ 8235', 300 GPM, 820 PSI, 40 RPM, 23-25K TQ. Tagged cement at 8235' with 5K. Rack stand back to 8206' then circulate the wellbore clean w/ 450 GPM, 1460 PSI, 30 RPM, 16-23K TQ, 115K ROT. Blow down top drive & R/U to pressure test 9-5/8" casing. Flood lines. Pressure test casing to 2500 PSI for 30 min. - good test. Bleed off pressure, blow down and R/D test equipment. 6.5 bbls pumped / 6.5 bbls bled back. Wash & ream f/ 8206' t/ 8242' tagging the baffle adapter on depth. Drill shoe track f/ 8242' t/ 8368' w/ 450 GPM, 1480 PSI, 40 RPM, 23K TQ, 5-10K WOB. Float collar on depth at 8283'. Ream float collar & baffle adapter 2x. Drilled shoe on depth at 8366' t/ 8368' then clean out rathole to 8375' Drill 20' of new formation f/ 8375' t/ 8395', 450 GPM, 1710 PSI, 40 RPM, 22K TQ, 15K WOB. Pump a 30 bbl high vis sweep and circulate the hole clean, 475 GPM, 1620 PSI, 40 RPM, 15-23K TQ. Reciprocate f/ 8395' t/ 8297'. Sweep back on time with a 30% increase. 225K PU / no SO / 115K ROT. MW 9.3 in / 9.3 out, vis 60 in / 52out. Rack back stand to 8301'. Blow down top drive. R/U test equipment. Perform FIT to 12.0 ppg at 8368' MD / 3772' TVD with 9.3 ppg mud with 530 PSI. 1.3 bbls pumped / 1.3 bbls back. R/D test equipment & blow down lines. POOH on elevators f/ 8301' t/ 7635'. Weather conditions worsened, Milne Point called Phase 3 conditions at 05:08. Discuss with personnel emergency travel only. Will trip back to the shoe and wait on weather. Discuss with crew to use extreme caution and work safely while reaching a point too shut down. Trip in the hole to 8301'. Install FOSV and monitor well with the hole fill pump. Losses: 0 bbls Daily / 138.8 bbls Total. H20 from 6-Mile: 0 bbls Daily / 7,625 bbls Total. H2O from G&I Source Water: 0 bbls Daily / 960 bbls Total. H20 from Lake 2: 0 bbls Daily / 1,685 bbls Total. Cuttings/mud/cement to MPU G&I: 171 bbls Daily / 9,421 bbls Total. 12/4/2020 Phase 3 weather, wait on weather. Monitor well at 8301' on the trip tank - no losses. Rig crews work on general housekeeping, no at risk work. Incoming Doyon crew made it to Deadhorse, outgoing crew weathered in at rig. Mud had been sitting for 24 hour. Circulate surface to surface to condition the mud. 450 GPM, 1300 PSI, 30 RPM, 23-25K, 265K PU / 50K SO / 120K ROT. Reciprocate 60-90'. MW 9.2 in / 9.3 out, vis 44 in / 72 out. Continue to wait on Phase 3 weather. Monitor well at 8301' on the trip tank - no losses. Rig crews work on general housekeeping, no at risk work. Weather conditions upgraded to Phase 1 at 04:33. PJSM for trip out of the hole. POOH f/ 8301' t/ 7826'. Slow pulling speed to 20'/min as needed due to casing drag. 265K PU / 50K SO / 120K ROT. Good displacement for 1st 5 stands. Pump dry job and blow down the top drive. Losses: 0 bbls Daily, 138.8 bbls Total. H20 from 6- Mile: 25 bbls Daily / 7,650 bbls Total. H2O from G&I Source Water: 0 bbls Daily / 960 bbls Total. H20 from Lake 2: 0 bbls Daily / 1,685 bbls Total. Cuttings/mud/cement to MPU G&I: 176 bbls Daily / 9,592 bbls Total. 12/5/2020 POOH f/ 7826' t/ 593'. L/D excess HWDP from 593 and rack back one stand HWDP w/ jars. Break bit and L/D mud motor. Bit graded 1-1-WT-A-E-I-NO-BHA. Clear rig floor. No losses. M/U 8-1/2" Geo-Pilot assembly with ADR, DGR, PWD & directional MWD sensors to 94'. P/U 3 NMDC to 188' then TIH w/ stand of HWDP/jars to 282'. Break in Geo-Pilot seals 10, 20 & 30 RPM and pulse test MWD 450 GPM, 1000 PSI - good test. TIH f/ 282' t/ 8085' from the derrick, 265K PU / 57K SO. 2nd shallow pulse test MWD @ 2184', 450 GPM, 1000 PSI - good test. Fill pipe every 2000'. P/U 5" drill pipe singles f/ 8085' t/ 8368', 275K PU / 49K SOW, drift with 2.60". No losses. PJSM. Remove trip nipple and install Beyond MPD. PJSM for displacement. Flood MPD lines & establish circulation. Pump 25 bbls high vis spacer then displace with 575 bbls of 8.8 ppg Flo-Pro NT. Inital 8 BPM, 1020 PSI, slowed to 6 BPM, 660 PSI for rock washer, 30 RPM, 21K initial TQ, 16K after new mud with 0.5% 776 lube. Reciprocate 60' in casing. Blow down top drive, L/D single & install FOSV. Slip & cut 66' of drilling line & service rig. Monitor well w/ shut MPD choke - no pressure build in 15 min. Circulate through MPD lines. Check crown-o-matic - good. M/U stand in the mousehole. Break circulation & obtain new slow pump rates. Wash to bottom f/ 8368' t/ 8395'. Drill 8-1/2" production hole f/ 8395' t/ 8584' MD / 3774' TVD (189' drilled) 75.6'/hr AROP. 500 GPM, 1660 PSI, 120 RPM, 11K TQ, 11-12K WOB. MW in 8.85 / out 8.85, vis in 54 / out 55, ECD 10.73, max gas 125u. 145K PU / 70K SO / 105K ROT. Last survey at 8487.10' MD / 3775' TVD, 90.01° inc, 4.73° azm, 17.52' from plan, 12.27' high and 12.5' right. 6 concretions have been drilled so far in the lateral, for a total footage of 25’ (14.1% of the lateral). Losses: 0 bbls Daily / 138.8 bbls Total. H20 from 6-Mile: 2200 bbls Daily / 8,150 bbls Total. H2O from G&I Source Water: 0 bbls Daily / 960 bbls Total. H20 from Lake 2: 0 bbls Daily / 1,685 bbls Total. Cuttings/mud/cement to MPU G&I: 689 bbls Daily / 10,281 bbls Total. 12/6/2020 Drill 8-1/2" production lateral f/ 8584' t/ 9035' (3793' TVD) 451' drilled, 75.17'/hr AROP. 510 GPM, 1700 PSI, 120 RPM, 14K TQ, 15K WOB. 8.9 ppg MW, 45 vis, 10.7 ECD, 459u max gas. 150K PU / 79K SO / 104K ROT. NB-sand base at 8752', NC-sand top at 8880' and NC-sand base at 8904'. Encountered predicted fault #2 at 8920' with 60' DTN throw to NA-sand. Drill 8-1/2" production lateral f/ 9035' t/ 9702' (3791' TVD) 667' drilled, 111.17'/hr AROP. 490 GPM, 1800 PSI, 120 RPM, 14K TQ, 10K WOB. 8.85 ppg MW, 46 vis, 11.05 ECD, 915u max gas. 147K PU / 70K SO / 100K ROT. High vis sweep @ 9128 back on time w/ 20% increase. NB-sand top at 9250'. Drill 8-1/2" production lateral f/ 9702' t/ 10273' (3823' TVD) 571' drilled, 95.17'/hr AROP. 500 GPM, 2000 PSI, 120 RPM, 13K TQ, 15K WOB. 8.8 ppg MW, 45 vis, 11.46 ECD, 641u max gas. 142K PU / 73K SO / 100K ROT. NB-sand base at 9775', NC-sand top at 9908' and NC-sand base at 9946'. Fault #3 at 10035' with 82' DTN throw from ND-clay to Ugnu MF. Steer down at 86°. High vis sweep @ 10177' back on time w/ 25% increase. Drill 8-1/2" production lateral f/ 10273' t/ 10843' (3803' TVD) 570' drilled, 95'/hr AROP. 490 GPM, 1940 PSI, 120 RPM, 13-15K TQ, 10-14K WOB. 9.0 ppg MW, 45 vis, 11.45 ECD, 672u max gas. 135K PU / 72K SO / 100K ROT. Entered NA-sand @10113'. Encountered fault #4 @ 10290' w/ 4' DTN throw to NA-clay. Entered NB sand @ 10415'. Perform 130 bbl new mud dilution at 10345'. 3AM mud check MBT = 6.6. 38 concretions have been drilled so far in the lateral, for a total footage of 151’ (6.3% of the lateral). Last survey at 10677.69' MD / 3830.99' TVD, 96.06° inc, 4.50° azm, 21.23' from plan, 19.52' low and 8.36' right. Losses: 0 bbls Daily / 138.8 bbls Total. H20 from 6-Mile: 745 bbls Daily / 8,895 bbls Total. H2O from G&I Source Water: 0 bbls Daily / 960 bbls Total. H20 from Lake 2: 0 bbls Daily / 1,685 bbls Total. Cuttings/mud/cement to MPU G&I: 884 bbls Daily / 11,165 bbls Total. 12/7/2020 Drill 8-1/2" production lateral f/ 10843' t/ 10985' (3813' TVD) 142' drilled, 94.67'/hr AROP. 490 GPM, 2030 PSI, 120 RPM, 13K TQ, 10K WOB. 9.05 ppg MW, 44 vis, 11.54 ECD, 702u max gas. 136K PU / 75K SO / 99K ROT. Drill out of NB-sand into NA-clay at 10963' Lost network communication, troubleshoot network communications. Remote geologist and geosteering unable to get data from rig. Drill 8-1/2" production lateral f/ 10985' t/ 11317' (3802' TVD) 332' drilled, 83'/hr AROP. 500 GPM, 2090 PSI, 120 RPM, 13K TQ, 11K WOB. 9.0 ppg MW, 44 vis, 11.8 ECD, 450u max gas. 145K PU / 65K SO / 95K ROT. High vis sweep @ 11225' on time w/ 50% increase. Fault #7 logged at 11140' w/ 22' DTS throw, faulted from NA-clay to NB-clay. Entered NB-sand base at 11189'. Drill 8-1/2" production lateral f/ 11317' t/ 11876' (3805' TVD) 559' drilled, 93.17'/hr AROP. 500 GPM, 2110 PSI, 120 RPM, 13K TQ, 14K WOB. 9.0 ppg MW, 45 vis, 10.75 ECD, 400u max gas. 144K PU / 67K SO / 95K ROT. High vis sweep at 11699' on time w/ 25% increase. Encountered fault #8 at 11450' w/ 6' DTN throw, faulted from NB-sand to NB-clay. Entered NB-sand at 11760'. Drill 8-1/2" production lateral f/ 11876' t/ 12269' (3820' TVD) 393' drilled, 65.5'/hr AROP. 485 GPM, 2260 PSI, 120 RPM, 13K TQ, 22K WOB. 8.95 ppg MW, 44 vis, 10.89 ECD, 369u max gas. 145K PU / 63K SO / 96K ROT. High vis sweep at 12175' 200 strokes late w/ 25% increase. Exited out the top of the NB-sand at 12,000'. Drill 8-1/2" production lateral f/ 12269' t/ 12936' (3844' TVD) 667' drilled, 111.17'/hr AROP. 498 GPM, 2060 PSI, 120 RPM, 13K TQ, 15K WOB. 8.9 ppg MW, 39 vis, 11.06 ECD, 1106u max gas. 150K PU / 65K SO / 101K ROT. Preform 580 BBL new mud dilution at 12285' reduced ECD from 11.8 to 11.1. Re-entered NB-sand @ 12,289'. Closest approach to J-26 @ 12,646' of 1.18' between centers. 60 concretions have been drilled so far in the lateral, for a total footage of 286’. Survey @ 12,772' seeing external magnetic interference. MPD chokes full open while drilling, closed on connections, built max 15 PSI. Last survey at 12675.60' MD / 3838.62' TVD, 88.78° inc, 18.68° azm, 7.34' from plan, 0.62' high, 7.31' right. Losses: 0 bbls Daily / 138.8 bbls Total. H20 from 6-Mile: 1,125 bbls Daily / 10,020 bbls Total. H2O from G&I Source Water: 0 bbls Daily / 960 bbls Total. H20 from Lake 2: 0 bbls Daily / 1,685 bbls Total. Cuttings/mud/cement to MPU G&I: 1,652 bbls Daily / 12,817 bbls Total. 12/8/2020 Drill 8.5" production lateral f/ 12937’ t/ 13603' (3870' TVD) 666’ drilled, 111’/hr AROP. 500 GPM, 2050 psi, 120 RPM, 15k Tq, 6k WOB. 8.95 ppg MW, 40 vis, 11.41 ECD,1008u Max gas. 160k PU / 50k SO / 100k ROT. Maintain the NB sand. 3-5 BPH losses. Hi Vis Sweep @ 13127’, Back on time w/ 50% increase in returns. Drill 8.5" production lateral f/ 13603’ t/ 14430' (3889' TVD) 827’ drilled, 138’/hr AROP. 500 GPM, 2110 psi, 120 RPM, 16k Tq, 7k WOB. 8.8 ppg MW, 40 vis, 11.36 ECD, 613u Max gas. 172k PU / 0k SO / 97k ROT. 5-9 BPH losses Maintain the NB sand. Perform 290 bbls whole mud dilution @ 13830’, reduced MBT f/ 6.75 t/ 5.25. Hi Vis Sweep @ 14367’, Back on time w/ 25% increase in returns. Drill 8.5" production lateral f/ 14430’ t/ 15317' (3907' TVD) 887’ drilled, 148’/hr AROP. 500 GPM, 2220 psi, 120 RPM, 18k Tq, 7k WOB. 8.9 ppg MW, 41 vis, 11.47 ECD, 495u Max gas. 177k PU / 0k SO / 99k ROT. Maintain the NB sand. 3-8 BPH losses. Closest approach to J-25 @ 14,962' of 43.06' between centers. No magnetic interference seen. Drill 8.5" production lateral f/ 15317’ t/ 15756' (3908' TVD) 439’ drilled, 146’/hr AROP. 500 GPM, 2250 psi, 120 RPM, 18k Tq, 8k WOB. 9.0 ppg MW, 39 vis, 11.45 ECD, 584u Max gas. 177k PU / 0k SO / 99k ROT. MWD Primary computer crash. Restart systems. Drill 8.5" production lateral f/ 15756’ t/ 15984' (3908' TVD) 228’ drilled, 114’/hr AROP. 500 GPM, 2250 psi, 120 RPM, 18k Tq, 8k WOB. 9.0 ppg MW, 39 vis, 11.62 ECD, 583u Max gas. 183k PU / 0k SO / 102k ROT. Hi Vis Sweep @ 15412’, Back on time w/ 50% increase in returns. 82 concretions have been drilled so far in the lateral, for a total footage of 345 (4.6% of the lateral). MPD chokes full open while drilling, closed on connections, built max 40 PSI. Last survey at 15818.43' MD / 3908.84' TVD, 89.58° inc, 14.86° azm, 13.14' from plan, 9.15' low, 9.43' right. Daily (midnight) loss = 143 bbl, Cumulative loss = 143 bbl. H20 from 6-Mile: 840 bbls Daily / 10,860 bbls Total. H2O from G&I Source Water: 0 bbls Daily / 960 bbls Total. H20 from Lake 2: 0 bbls Daily / 1,685 bbls Total. Cuttings/mud/cement to MPU G&I: 1,313 bbls Daily / 14,130 bbls Total. 12/9/2020 Drill 8-1/2'' lateral f/ 15984' t/ 16570' at TD (3911’ TVD) 586' drilled, 98’/hr AROP. 490 GPM, 2140 PSI, 120 RPM, 19K TQ, 6K WOB. 9.0 ppg MW, 39 vis, 11.44 ECD, max gas 614u. 175K PU / 40 SO / 101K ROT. 3 BPH losses. Hi Vis Sweep @ 16459’, Back on time w/ 100% increase. Drill 8-1/2'' lateral f/ 16570' t/ 17221' at TD (3911’ TVD) 651' drilled, 145’/hr AROP. 500 GPM, 2380 PSI, 120 RPM, 20K TQ, 17K WOB. 8.9 ppg MW, 41 vis, 11.62 ECD, max gas 691u. 195K PU / 40 SO / 102K ROT. TD called from town at 17221’ prior to drilling through projected fault @ 17300’. Obtain final MWD survey. 26.98' high and 0.47' right. 93 concretions were drilled for a total footage of 385’ (4.3%) of the lateral. Pump 30 bbl hi vis sweep, cleanup the wellbore, 500 gpm, 2350 psi, 120 rpm working pipe, sweep back 300 stks late w/ no increase, CBU x4 racking std back ea BU to 16842’ Ream to bottom (no slack off weight) f/ 16842' t/ 17221'. 365 GPM, 1290 PSI, 60 RPM, 20K. PJSM. Pump 30 bbl high vis spacer, three 20 bbl SAPP pills separated by 50 bbls seawater then chased by 300 bbls seawater. Pump 30 bbl high vis spacer and then perform displacement with 1236 bbls of 8.45 ppg viscosified lubricated 2% KCL/NaCL brine. 264 GPM, 875 PSI ICP / 720 PSI FCP, 60 RPM, 22K TQ initial, 13K TQ final. Spacer & brine back 40 bbls late with 90 bbls of interface. Reciprocate pipe 94'. Take returns back to the pits, observing moderate sand load over 230/200 mesh shaker screens. Start both centrifuges and continue circulate 500 gpm 1650 psi, 30 RPM 13k Tq. Reciprocate pipe 94' and rack stand back with bottoms up. Losses @ 10 BPH Interval Daily (Midnight) Loss= 98 bbls/Cumulative losses=241 bbls. H20 from 6-Mile: 685 bbls Daily / 11,545 bbls Total. H2O from G&I Source Water: 0 bbls Daily / 960 bbls Total. H20 from Lake 2: 0 bbls Daily / 1,685 bbls Total. Cuttings/mud/cement to MPU G&I: 991 bbls Daily / 15,121 bbls Total. 12/10/2020 PST passed w/ 3 @ 3.5 sec. RIH f/ 17126’ t/ 17221’. Perform pressure monitoring w/ MPD. Trap 100 psi and dropped to 84 psi in 5 min. Bleed off to 23 PSI and built to 35 PSI in 5 min. Obtain new slow pump rates. 175k PU / 40k SO / 111k ROT with lubricated brine. BROOH f/ 17221' t/ 14652' at 5-10 min/stand, 500 GPM, 1600 PSI, 120 RPM, 20K Tq. MPD full open choke while pumping = 10.06-10.31 ppg ECD & 180 PSI static = 9.4 ppg EMW. L/D stands 5'' DP utilizing the mouse hole, sort DP due f/ inspection. 25 bbl total losses while BROOH BROOH f/ 14652' t/ 11882' at 5-10 min/stand slowing as needed for hole cleaning, 500 GPM, 1380 psi, 120 RPM, 18K Tq. MPD full open choke while BR and 180 psi during connections. L/D stands 5'' DP utilizing the mouse hole, sort DP due f/ inspection. 60 bbl total losses while BROOH BROOH f/ 11882' t/ 8371' at 5-10 min/stand slowing down as needed for hole cleaning, 500 GPM, 1340 psi, Reduce RPM t/ 40 while pulling BHA into shoe. MPD full open choke while BR and 170 psi during connections Start to see increase in sand and silt returns @ 10890’ and remained constant while pulling to the shoe. Work through tight spot at 10468’ 2x. 119 total bbls loss during BROOH. Pump 30 bbl high vis sweep, back on time w/ minimal increase. Pumped total 3x BU for sand to clean up on shakers. Monitor pressure build with MPD chokes closed. Initial build t/ 47 psi in 5 min. Bleed down and build to 34 psi in 5 min. Final bleed and build to 23 psi in 5 min. 8.9 ppg fluid + 23 PSI @ 3772’ TVD = 9.0 ppg EMW. Spot 9.2 ppg viscosified/lubricated brine from shoe to surface. 485 GPM, 1250 PSI, 30 RPM, 5K TQ. Reciprocate string 94'. MPD full open choke while circulating, 10.25 ECD. Interval Daily (Midnight) Loss= 123 bbls/Cumulative losses=364 bbls. H20 from 6-Mile: 250 bbls Daily / 11,795 bbls Total. H2O from G&I Source Water: 150 bbls Daily / 1,110 bbls Total. H20 from Lake 2: 0 bbls Daily / 1,685 bbls Total. Cuttings/mud/cement to MPU G&I: 2,194 bbls Daily / 17,315 bbls Total. 12/11/2020 Shut pumps down and monitor for flow at possum belly. Initial flow after blowing down Topdrive, @ 0.5 bph. Close 4" MPD line, open 2" bleeder & monitor for flow, static in 10 min. Hold PJSM on removing RCD bearing while monitoring. Remove MPD RCD, install trip nipple & check for leaks. Hold PJSM with Rig Crew. Clean and disinfect whole Rig due to one of the Rig personnel testing positive for Covid-19. Monitor Well on at trip tank – 4 BPH loss rate. Pump dry job, Blow down TopDrive. Install wiper rubber and air slips. TOOH on elevators f/ 8371'. L/D 5" drill pipe to 2182’'. Drop 2.34'' drift on wire, Rack 20 stds drifted DP in the derrick to HWDP @ 282'. Mark and segregate drill pipe for inspection and hard band. Flow check before pulling BHA, static, L/D jar stand, float subs and NMFCs to 94'. Recover drift on wire. Download MWD data. L/D remaining BHA. Bit grade= 1-1-CT-A-X-I-NO-TD. 38 bbl losses TOOH f/ shoe Clear and clean rig floor. Remove split bushings, install master bushing. Load tools to rig floor. Finish loading 4-1/2” liner in shed. R/U 4 1/2'' handling equipment and power tongs. Ready Safety joint in shed. Losses @ 3 BPH Hold PJSM on picking up/running liner. P/U round nose shoe w/ XO jt, and run 4-1/2'', 13.5#, L-80 H625 lower screen completion as per tally to 415'. Torque to 9600 ft/lb with Doyon double stack tongs. Daily (midnight) loss = 62 bbl, Cumulative loss = 426 bbl. H20 from 6-Mile: 240 bbls Daily / 12,035 bbls Total. H2O from G&I Source Water: 0 bbls Daily / 1,110 bbls Total. H20 from Lake 2: 0 bbls Daily / 1,685 bbls Total. Cuttings/mud/cement to MPU G&I: 114 bbls Daily / 17,757 bbls Total. 12/12/2020 Run 4-1/2'', 13.5#, L-80 H625 lower screen completion as per tally to 4573'. Torque to optimum @ 9600 ft/lbs. 84K PU / 74K SO Continue to run 4-1/2'', 13.5#, L- 80 H625 lower screen completion as per tally to 8999'. 106K PU / 75K SO inside the 9-5/8" shoe 8368'. Torque to optimum @ 9600 ft/lbs, On blank jts- install 1- 4 1/2'' x 7 1/4'' straight vane centralizer w/ 1- stop ring free floating on each joint. 67 blank joints, 152 Halliburton 250 micron screens. 3 bph loss rate, 26 bbls lost running liner. M/U Baker 7"x9-5/8" SLZXP liner top packer to 9037 then run one stand of 5" drill pipe to 9132'. Pump 10 bbls to ensure clear flow path through Baker tools, 3 BPM, 130 PSI. Obtain parameters: 112K PU / 80K SO Run 4-1/2" lower production completion on 5" drill pipe from the derrick f/ 9132' t/ 9319'. Single in the hole w/ 5" HWDP f/ 9319' t/ 13149'. 2.4” drift used for HWDP. 215K PU / 125K SO. 2 bph losses. Run 4-1/2" production liner to 17221’. Single in the hole w/ 5" HWDP f/ 13149' t/ 15614'. RIH with stands 5” DP from derrick & Tag btm at 17221'. Set liner in tension. Drop 0.906" ball. 255K PU / 112K SO. Pump ball down and land on seat at 74.74 bbl. Pressure up and saw pusher tool activate at 2500 psi. Hold 3K for 5 min. Slack off and set HRD-E in compression. Pressure up to 4050 with mud pumps, shear neutralizer tool & release HRD-E. Pressure bled to 0. P/U & verify free, Good. Blow down TopDrive. Daily (midnight) loss = 62 bbl, Cumulative loss = 488 bbl. H20 from 6-Mile: 35 bbls Daily / 12,070 bbls Total. H2O from G&I Source Water: 0 bbls Daily / 1,110 bbls Total. H20 from Lake 2: 0 bbls Daily / 1,685 bbls Total. Cuttings/mud/cement to MPU G&I: 57 bbls Daily / 17,531 bbls Total. 12/13/2020 R/U test equipment and test LTP to 1500 psi for 10 min, Good. Top of liner set @ 8195.51'. Bleed off pressure, blow down ckoke and kill lines. Pump at 2 bpm & pull out of liner top. Hold 300-500 psi while pulling out. Bring pumps to 10 bpm when pressure dumped. Circ out sweep and two btm up total, 14.28 bpm 2460 psi. Got sand back with sweep. Lay down 10’ pup jt. t/ 8147’. 200k PU / 140k SO Displace the well to clean 9.2ppg brine at 7 bpm, 990 psi. Monitor Well, slight losses Cut and slip 99' Drilling Line. Service Rig, and calibrate blocks. POOH, L/D DP f/ 8145’ t/ 6623’ & L/D HWDP F/ 6623’ T/ 295'. Lay down 9 jts DP & liner running tool. Rupture disk was blown. Ball on set. Orifice back pressure sub and guide nozzle missing from bottom of circulation sub, 1.65' total length left in hole. Total of 23 bbls loss during TOH Drain BOP stack and pull wear bushing. Perform dummy run w/ 7-5/8" hanger. WH Tech verify. Break down safety joint and lay down both mouseholes. M/U 7-5/8” test joint and plug, set in hole. C/O upper 2-7/8”x5” VBR to 7-5/8” SBR Change to Completions AFE @ 00:00. See MPU I-40 completions report for details Daily (midnight) loss = 59 bbl, Cumulative loss = 573 bbl. H20 from 6-Mile: 0 bbls Daily / 12,035 bbls Total. H2O from G&I Source Water: 0 bbls Daily / 1,110 bbls Total. H20 from Lake 2: 0 bbls Daily / 1,685 bbls Total. Cuttings/mud/cement to MPU G&I: 662 bbls Daily / 18,193 bbls Total. Activity Date Ops Summary 12/13/2020 Refer to last drilling report for details.,C/O upper 2-7/8”x5” VBR to 7-5/8” SBR. Rig up to test rams. C/O seal on test joint & Test upper rams t/ 250/3000 psi, 5 min each. Rig down test equipment and blow down. Install Wear bushing. SimOps: Load and process 5” drillpipe for clean-out run.,Mobilize Baker fishing tools to rig floor. Strap and tally same. Finish loading 5" DP in shed and process to be picked up.,M/U Baker 5-3/4" reverse circulating junk basket w/ 6" head, 9.75' pup jt & XO to 4-1/2" IF. RIH with Baker fishing assembly picking up 5" DP from pipe shed t/ 208'. 45k PU / 45k SO. 2 BPH loss rate.,Daily (midnight) loss = 59 bbl, Cumulative loss = 573 bbl. H20 from 6-Mile: 0 bbls Daily / 12,035 bbls Total. H2O from G&I Source Water: 0 bbls Daily / 1,110 bbls Total. H20 from Lake 2: 0 bbls Daily / 1,685 bbls Total. Cuttings/mud/cement to MPU G&I: 662 bbls Daily / 18,193 bbls Total. 12/14/2020 RIH with Baker 5-3/4" reverse circulating junk basket assembly picking up 5" DP from pipe shed F/ 208' T/ 8133'. 45k PU / 45k SO. 2 BPH loss rate.,Establish parameters at 1500, 2000 & 2500 psi. 523 GPM, 620 GPM & 690 GPM. UP/DN 135/90. Drop .91" phenolic ball and pump down. Ball on seat 13 bbl early. 300 psi gain in pressure at 290 GPM. Take permeators. 1500 psi @ 380 GPM, 2000 psi @ 460 psi, and 2500 @ 502 PSI. Wash and ream down at 20 RPM 6K TQ & 502 GPM @ 2500 psi. Tag 4.5" XO in liner top 6' high. Same as stretch when we set the liner. Work through 4 times.,L/D single 5" drill pipe. Pump Dry job, Blow down TopDrive. POOH F/ 8195' T/ Fishing assembly, standing back 5'' DP. 2 BPH losses.,Break down reverse circulating junk basket and retrieve fish. Both the orifice backpressure sub and guide nozzle recovered. Make RCJB back up and lay down remaining Baker fishing tools.,Clear and clean rig floor, prep pipe shed for laying down DP. Remove wear bushing.,L/D 86 stands 5” DP stands from Derrick via 90’ mouse hole. Monitor well on trip tank. 2 BPH loss rate.,Daily (midnight) loss = 40 bbl, Cumulative loss = 613 bbl. H20 from 6-Mile: 0 bbls Daily / 12,035 bbls Total. H2O from G&I Source Water: 0 bbls Daily / 1,110 bbls Total. H20 from Lake 2: 0 bbls Daily / 1,685 bbls Total. Cuttings/mud/cement to MPU G&I: 332 bbls Daily / 18,525 bbls Total. 12/15/2020 Continue to L/D remaining 20 stands 5” DP from Derrick via 90’ mouse hole, for a total of 86 stands. Monitor well on trip tank. 2 BPH loss rate.,Load tools to rig floor, R/U 7 5/8'' handling equipment, power tongs, ready FOSV and XO,PJSM. P/U Baker bullet seal assy w/ 8.25" O.D. locator to 17'. Run 7-5/8" 29.7# L-80 Hydril 521 tie back f/ 17' t/ 8173’ at jt #204. Torque to 10100 ft/lbs with Doyon casing double stack tongs. Loss rate 2-2.5 bph running liner. PU 175K, SO 112K,M/U jt #205', S/O see seals entering TOL @ 8200', no go out 3.53’ deep @ 8208.63' setting down 10k. P/U 3' and close bag, pressure up backside to 250 psi to verify seals engaged, bleed off pressure, open bag. L/D jts 205, 204, and 203. Space out with full jts. 216 & 217. M/U pup, hanger & landing joint, land on hanger at 8206.89' (1.74' off no-go).,R/U to reverse circulate. M/U XO, FOSV, side entry sub & 10' pup joint. Test lines. Close annular & pressure up to 250 PSI. P/U, observe pressure bleed off through circulation ports.,Reverse circulate 125 bbls corrosion inhibited 9.2 ppg brine @ 4 BPM, 680 PSI. Pump through injection line to the OA taking returns out of the 7-5/8" liner. Blow down lines and mud pumps. Line up to pump diesel freeze protect.,Reverse circulate 42 bbls diesel freeze protect from vac truck 3 bpm, 540 psi freeze protecting 9 5/8'' x 7-5/8'' annulus to 2500'. Land hanger w/ 70k on Hanger,Bleed down to cuttings box and verify seals engaged. Good. Back side dead. Blow down lines and mud pumps.,Rig ULSD in gallons: 0 rec'd, 1097 used, 7752 on hand. Daily (midnight) losses = 46 bbls, Cumulative losses for production lateral = 659 bbls. H20 from 6-Mile: 0 bbls Daily / 12,035 bbls Total. H2O from G&I Source Water: 0 bbls Daily / 1,110 bbls Total. H20 from Lake 2: 0 bbls Daily / 1,685 bbls Total. Recycle to ORT: 0 bbls Daily / 0 bbls Total. Cuttings/mud/cement to MPU G&I: bbls Daily / 18,525 bbls Total. 12/16/2020 R/D reverse circulating lines, L/D landing jt, M/U running tool and install pack off as per WHR, RILDS, L/D running tool, test pack off to 500 psi for 5 min, 5000 psi for 10 min, good,R/U and test 9 5/8'' x 7 5/8'' annulus to 1000 psi for 30 charted minutes, good test, bleed off pressure, Blow down and R/D lines.,PJSM, R/U ESP spooler, Doyon 3.5 handling equipment and baker ESP equipment. Hang sheave in derrick, String ESP cable and secure at rig floor. Hold PJSM for running ESP completion, review well control procedure. Monitor well with trip tank, 2 bph static loss rate,P/U, M/U & service ESP/Motor and seal assy. Connect ESP cable, 100' control line discharge, to motor and gauge assembly. Install 3 bolt on clamps to motor assy connections, 4 seal & 1 cannon clamps. Perform tests on ESP cable. Good test. M/U last Centrilift pump, P/U and install 8 pump clamps onto the pump assy.,RIH with ESP on 3-1/2" 9.3# L-80 EUE Tubing f/ 99' to 3987'. Torque to 3200 ft/lbs, Install cannon clamp every connection for first 10 jts. Install cannon clamp every other connection from jt #10 and above & below GLM body. Test cable connection every 1000’. Losses @ 2 BPH,RIH with ESP on 3-1/2" 9.3# L-80 EUE Tubing f/ 3987' to 7113'. Torque to 3200 ft/lbs, Install cannon clamp every other connection. 120 total cross cannon clamps run. Test cable connection every 2000’. 95k PU / 62k SO. Losses @ 2 BPH,Verify tubing count in pipe shed. Install BPV in Hanger on Rig Floor. Rig up landing joint with cross overs to Hanger and M/U to tubing.,Daily (midnight) loss = 40 bbl, Cumulative loss = 613 bbl. H20 from 6-Mile: 0 bbls Daily / 12,035 bbls Total. H2O from G&I Source Water: 0 bbls Daily / 1,110 bbls Total. H20 from Lake 2: 0 bbls Daily / 1,685 bbls Total. Cuttings/mud/cement to MPU G&I: 139 bbls Daily / 18,664 bbls Total. 12/17/2020 Centrilift terminate ESP cable to tbg hanger, meg test cable, good, drain stack, land hanger with 22k on hanger with EOP @ 7146.30', RILDS as per WHR, L/D landing joint. Offload and clean in pits. Loss rate 1.5 bph,R/D 3 1/2'' handling equipment, load out centrilift tools. PJSM, pull riser, mousehole and remove drip pan. N/D BOPE, hoist stack and set on stump. Continue to clean in pits.,Load tree into cellar, WHR install dart in BPV. N/U tree and adaptor, WHR test hanger void to 500 psi for 5 min, 5000 psi for 10 min, good. Centrilift take final readings. 3.0 phase to phase, 4.32 phase to grnd, 1608 BHP, 71 deg, 1606 discharge psi, .003 vib, 121 v. 9.9 amps. Put rig on gen power @ 13:40,R/U test equipment, test tree with diesel to 250 /5000 psi 5 min each, good, WHR pull BPV and dart. R/D test equipment. R/U to reverse circulate,,PJSM, attempt to test surface lines, 3'' demco valve 20 on stand pipe not holding when purging lines with diesel, drain line and rebuild valve,,Pump 84 bbls diesel down I/A, ICP 2 bpm, 170 psi – FCP 2 bpm, 390 psi. Bullhead 22 bbls diesel down tubing, ICP 1 bpm, 600 psi. FCP 0.5 bpm, 940 psi. Secure tree, Flush and blow down lines. Rig down. Cut and cap 90' mousehole in Cellar. Release Rig at 00:00,See MPU J-29 Drilling report for details.,Daily (midnight) loss = 13 bbl, Cumulative loss = 626 bbl. H20 from 6-Mile: 0 bbls Daily / 12,035 bbls Total. H2O from G&I Source Water: 0 bbls Daily / 1,110 bbls Total. H20 from Lake 2: 0 bbls Daily / 1,685 bbls Total. Cuttings/mud/cement to MPU G&I: 389 bbls Daily / 19,053 bbls Total. Well Name: Field: MP I-40 Milne Point Hilcorp Energy Company Composite Report 11/25/2020Spud Date: 10 December, 2020 Milne Point M Pt I Pad MPU I-40 Seven Pines 500292368900 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt I Pad Halliburton Definitive Survey Report Well: Wellbore: MPU I-40 MPU I-40 Survey Calculation Method:Minimum Curvature MPU I-40 Actual RKB @ 68.20usft (Doyon 14) Design:MPU I-40 Database:NORTH US + CANADA MD Reference:MPU I-40 Actual RKB @ 68.20usft (Doyon 14) North Reference: Well MPU I-40 True Map System: Geo Datum: Project Map Zone: System Datum:US State Plane 1927 (Exact solution) NAD 1927 (NADCON CONUS) Milne Point, ACT, MILNE POINT Alaska Zone 04 Mean Sea Level Using Well Reference Point Using geodetic scale factor Well Well Position Longitude: Latitude: Easting: Northing: usft +E/-W +N/-S Position Uncertainty usft usft usftGround Level: MPU I-40 usft usft 0.00 0.00 6,009,456.070 551,419.680 33.60Wellhead Elevation:33.60 usft0.50 70° 26' 11.708 N 149° 34' 50.758 W Wellbore Declination (°) Field Strength (nT) Sample Date Dip Angle (°) MPU I-40 Model NameMagnetics IFR 12/12/2020 15.71 80.84 57,360.90000000 Phase:Version: Audit Notes: Design MPU I-40 1.0 ACTUAL Vertical Section: Depth From (TVD) (usft) +N/-S (usft) Direction (°) +E/-W (usft) Tie On Depth:34.60 15.000.000.0034.60 From (usft) Survey Program DescriptionTool NameSurvey (Wellbore) To (usft) Date 12/10/2020 Survey Date 3_Gyro-MWD90+Sag H065Ga: UNVALIDATED : based on GYD_GW165.46 707.10 MPU I-40 Gyro-MWD90+Sag - Gyrodata 11/18/2020 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sa756.38 8,290.63 MPU I-40 Surface MWD+IFR2+MS+Sag 11/18/2020 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sa8,387.51 17,151.14 MPU I-40 Production MWD+IFR2+MS+S 12/01/2020 MD (usft) Inc (°) Azi (°) +E/-W (usft) +N/-S (usft) Survey TVD (usft) TVDSS (usft) Map Northing (ft) Map Easting (ft) Vertical Section (ft) DLS (°/100')Survey Tool Name 34.60 0.00 0.00 34.60 0.00 0.00-33.60 6,009,456.07 551,419.68 0.00 0.00 UNDEFINED 165.46 0.44 340.47 165.46 0.47 -0.1797.26 6,009,456.54 551,419.51 0.34 0.41 3_Gyro-MWD90+Sag (1) 241.49 0.18 296.77 241.49 0.80 -0.37173.29 6,009,456.87 551,419.30 0.44 0.68 3_Gyro-MWD90+Sag (1) 333.72 1.94 178.18 333.70 -0.69 -0.45265.50 6,009,455.37 551,419.23 2.20 -0.79 3_Gyro-MWD90+Sag (1) 425.22 3.33 204.79 425.10 -4.65 -1.52356.90 6,009,451.41 551,418.20 1.99 -4.89 3_Gyro-MWD90+Sag (1) 518.98 6.41 223.82 518.52 -10.90 -6.28450.32 6,009,445.12 551,413.47 3.67 -12.16 3_Gyro-MWD90+Sag (1) 614.73 9.94 227.17 613.28 -20.38 -16.05545.08 6,009,435.58 551,403.77 3.72 -23.84 3_Gyro-MWD90+Sag (1) 707.10 13.73 233.86 703.68 -32.27 -30.75635.48 6,009,423.59 551,389.15 4.36 -39.13 3_Gyro-MWD90+Sag (1) 756.38 15.56 230.13 751.36 -39.96 -40.55683.16 6,009,415.84 551,379.41 4.17 -49.09 3_MWD+IFR2+MS+Sag (2) 851.39 17.66 229.98 842.40 -57.39 -61.37774.20 6,009,398.26 551,358.71 2.21 -71.32 3_MWD+IFR2+MS+Sag (2) 946.55 21.80 234.46 931.96 -76.96 -86.81863.76 6,009,378.52 551,333.41 4.63 -96.80 3_MWD+IFR2+MS+Sag (2) 1,041.79 27.14 236.30 1,018.61 -99.31 -119.30950.41 6,009,355.95 551,301.08 5.66 -126.80 3_MWD+IFR2+MS+Sag (2) 12/10/2020 12:00:59PM COMPASS 5000.15 Build 91E Page 2 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt I Pad Halliburton Definitive Survey Report Well: Wellbore: MPU I-40 MPU I-40 Survey Calculation Method:Minimum Curvature MPU I-40 Actual RKB @ 68.20usft (Doyon 14) Design:MPU I-40 Database:NORTH US + CANADA MD Reference:MPU I-40 Actual RKB @ 68.20usft (Doyon 14) North Reference: Well MPU I-40 True MD (usft) Inc (°) Azi (°) +E/-W (usft) +N/-S (usft) Survey TVD (usft) TVDSS (usft) Map Northing (ft) Map Easting (ft) Vertical Section (ft) DLS (°/100')Survey Tool Name 1,136.79 30.57 239.14 1,101.81 -123.73 -158.071,033.61 6,009,331.27 551,262.48 3.89 -160.42 3_MWD+IFR2+MS+Sag (2) 1,230.90 33.34 245.79 1,181.68 -146.62 -202.221,113.48 6,009,308.08 551,218.49 4.75 -193.96 3_MWD+IFR2+MS+Sag (2) 1,327.37 36.70 252.22 1,260.70 -166.31 -253.881,192.50 6,009,288.03 551,166.98 5.17 -226.35 3_MWD+IFR2+MS+Sag (2) 1,422.56 39.60 257.53 1,335.57 -181.55 -310.621,267.37 6,009,272.40 551,110.35 4.60 -255.76 3_MWD+IFR2+MS+Sag (2) 1,517.57 42.39 259.90 1,407.28 -193.71 -371.731,339.08 6,009,259.82 551,049.33 3.36 -283.32 3_MWD+IFR2+MS+Sag (2) 1,612.73 46.36 262.07 1,475.28 -204.09 -437.441,407.08 6,009,248.99 550,983.69 4.47 -310.36 3_MWD+IFR2+MS+Sag (2) 1,707.99 50.43 263.95 1,538.53 -212.72 -508.131,470.33 6,009,239.87 550,913.08 4.52 -336.99 3_MWD+IFR2+MS+Sag (2) 1,803.57 54.83 267.00 1,596.53 -218.65 -583.821,528.33 6,009,233.42 550,837.43 5.25 -362.31 3_MWD+IFR2+MS+Sag (2) 1,897.85 55.88 268.01 1,650.13 -222.03 -661.311,581.93 6,009,229.51 550,759.98 1.42 -385.62 3_MWD+IFR2+MS+Sag (2) 1,993.87 57.33 268.68 1,702.98 -224.34 -741.441,634.78 6,009,226.65 550,679.88 1.62 -408.59 3_MWD+IFR2+MS+Sag (2) 2,087.97 59.63 269.31 1,752.17 -225.74 -821.641,683.97 6,009,224.69 550,599.70 2.51 -430.70 3_MWD+IFR2+MS+Sag (2) 2,183.30 60.84 268.84 1,799.50 -227.08 -904.381,731.30 6,009,222.79 550,516.98 1.34 -453.41 3_MWD+IFR2+MS+Sag (2) 2,278.36 65.30 269.70 1,842.54 -228.14 -989.101,774.34 6,009,221.14 550,432.27 4.76 -476.37 3_MWD+IFR2+MS+Sag (2) 2,373.24 69.59 270.12 1,878.92 -228.28 -1,076.701,810.72 6,009,220.40 550,344.68 4.54 -499.17 3_MWD+IFR2+MS+Sag (2) 2,467.05 69.97 270.89 1,911.35 -227.50 -1,164.731,843.15 6,009,220.57 550,256.66 0.87 -521.20 3_MWD+IFR2+MS+Sag (2) 2,564.02 70.20 272.05 1,944.38 -225.16 -1,255.871,876.18 6,009,222.28 550,165.52 1.15 -542.53 3_MWD+IFR2+MS+Sag (2) 2,657.28 69.27 272.93 1,976.68 -221.36 -1,343.271,908.48 6,009,225.48 550,078.10 1.33 -561.48 3_MWD+IFR2+MS+Sag (2) 2,754.18 69.57 272.87 2,010.74 -216.77 -1,433.871,942.54 6,009,229.44 549,987.48 0.31 -580.50 3_MWD+IFR2+MS+Sag (2) 2,849.34 70.22 273.47 2,043.45 -211.83 -1,523.091,975.25 6,009,233.77 549,898.23 0.90 -598.82 3_MWD+IFR2+MS+Sag (2) 2,944.46 70.69 274.30 2,075.28 -205.75 -1,612.522,007.08 6,009,239.22 549,808.77 0.96 -616.10 3_MWD+IFR2+MS+Sag (2) 3,039.43 70.88 272.52 2,106.53 -200.42 -1,702.042,038.33 6,009,243.94 549,719.23 1.78 -634.11 3_MWD+IFR2+MS+Sag (2) 3,134.23 70.83 270.08 2,137.63 -198.39 -1,791.572,069.43 6,009,245.35 549,629.70 2.43 -655.32 3_MWD+IFR2+MS+Sag (2) 3,229.47 69.56 268.15 2,169.90 -199.77 -1,881.162,101.70 6,009,243.36 549,540.13 2.33 -679.84 3_MWD+IFR2+MS+Sag (2) 3,324.75 68.52 267.45 2,203.98 -203.18 -1,970.062,135.78 6,009,239.33 549,451.26 1.29 -706.15 3_MWD+IFR2+MS+Sag (2) 3,419.29 67.79 268.87 2,239.16 -206.00 -2,057.772,170.96 6,009,235.91 549,363.58 1.59 -731.57 3_MWD+IFR2+MS+Sag (2) 3,514.75 68.54 268.56 2,274.67 -207.99 -2,146.352,206.47 6,009,233.31 549,275.02 0.84 -756.42 3_MWD+IFR2+MS+Sag (2) 3,610.16 68.25 270.43 2,309.80 -208.77 -2,235.052,241.60 6,009,231.91 549,186.34 1.85 -780.13 3_MWD+IFR2+MS+Sag (2) 3,704.83 67.78 273.09 2,345.25 -206.08 -2,322.792,277.05 6,009,234.00 549,098.59 2.65 -800.24 3_MWD+IFR2+MS+Sag (2) 3,800.12 68.35 273.95 2,380.84 -200.65 -2,411.012,312.64 6,009,238.82 549,010.34 1.03 -817.83 3_MWD+IFR2+MS+Sag (2) 3,895.22 69.54 274.21 2,415.01 -194.34 -2,499.532,346.81 6,009,244.53 548,921.79 1.28 -834.64 3_MWD+IFR2+MS+Sag (2) 3,991.05 69.97 272.50 2,448.17 -189.08 -2,589.292,379.97 6,009,249.17 548,832.01 1.73 -852.79 3_MWD+IFR2+MS+Sag (2) 4,087.08 69.46 272.76 2,481.46 -184.94 -2,679.272,413.26 6,009,252.68 548,742.01 0.59 -872.09 3_MWD+IFR2+MS+Sag (2) 4,181.29 68.91 273.36 2,514.94 -180.24 -2,767.202,446.74 6,009,256.77 548,654.06 0.83 -890.31 3_MWD+IFR2+MS+Sag (2) 4,276.43 69.10 274.25 2,549.03 -174.35 -2,855.832,480.83 6,009,262.05 548,565.40 0.90 -907.55 3_MWD+IFR2+MS+Sag (2) 4,372.22 71.58 275.30 2,581.26 -166.83 -2,945.712,513.06 6,009,268.95 548,475.48 2.79 -923.56 3_MWD+IFR2+MS+Sag (2) 4,467.63 72.37 276.37 2,610.78 -157.61 -3,035.972,542.58 6,009,277.55 548,385.17 1.35 -938.00 3_MWD+IFR2+MS+Sag (2) 4,561.93 71.60 277.34 2,639.94 -146.91 -3,125.002,571.74 6,009,287.64 548,296.07 1.27 -950.71 3_MWD+IFR2+MS+Sag (2) 4,657.51 72.91 278.10 2,669.07 -134.68 -3,215.202,600.87 6,009,299.24 548,205.79 1.57 -962.24 3_MWD+IFR2+MS+Sag (2) 4,752.59 74.09 278.69 2,696.08 -121.37 -3,305.392,627.88 6,009,311.93 548,115.53 1.38 -972.73 3_MWD+IFR2+MS+Sag (2) 4,847.68 73.04 278.86 2,722.98 -107.45 -3,395.532,654.78 6,009,325.22 548,025.31 1.12 -982.62 3_MWD+IFR2+MS+Sag (2) 12/10/2020 12:00:59PM COMPASS 5000.15 Build 91E Page 3 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt I Pad Halliburton Definitive Survey Report Well: Wellbore: MPU I-40 MPU I-40 Survey Calculation Method:Minimum Curvature MPU I-40 Actual RKB @ 68.20usft (Doyon 14) Design:MPU I-40 Database:NORTH US + CANADA MD Reference:MPU I-40 Actual RKB @ 68.20usft (Doyon 14) North Reference: Well MPU I-40 True MD (usft) Inc (°) Azi (°) +E/-W (usft) +N/-S (usft) Survey TVD (usft) TVDSS (usft) Map Northing (ft) Map Easting (ft) Vertical Section (ft) DLS (°/100')Survey Tool Name 4,943.24 73.40 277.99 2,750.57 -94.05 -3,486.032,682.37 6,009,338.00 547,934.72 0.95 -993.09 3_MWD+IFR2+MS+Sag (2) 5,036.84 71.42 277.81 2,778.85 -81.79 -3,574.402,710.65 6,009,349.65 547,846.28 2.12 -1,004.12 3_MWD+IFR2+MS+Sag (2) 5,133.16 70.80 277.33 2,810.04 -69.78 -3,664.742,741.84 6,009,361.03 547,755.87 0.80 -1,015.91 3_MWD+IFR2+MS+Sag (2) 5,228.74 71.78 277.61 2,840.70 -58.01 -3,754.502,772.50 6,009,372.18 547,666.04 1.06 -1,027.77 3_MWD+IFR2+MS+Sag (2) 5,323.94 71.63 277.52 2,870.58 -46.11 -3,844.102,802.38 6,009,383.46 547,576.36 0.18 -1,039.46 3_MWD+IFR2+MS+Sag (2) 5,417.93 71.54 277.57 2,900.27 -34.40 -3,932.502,832.07 6,009,394.56 547,487.89 0.11 -1,051.03 3_MWD+IFR2+MS+Sag (2) 5,515.07 70.71 278.35 2,931.70 -21.67 -4,023.532,863.50 6,009,406.66 547,396.78 1.14 -1,062.30 3_MWD+IFR2+MS+Sag (2) 5,610.24 69.94 278.80 2,963.74 -8.31 -4,112.142,895.54 6,009,419.41 547,308.09 0.92 -1,072.33 3_MWD+IFR2+MS+Sag (2) 5,705.01 71.27 279.63 2,995.21 6.00 -4,200.382,927.01 6,009,433.12 547,219.77 1.63 -1,081.34 3_MWD+IFR2+MS+Sag (2) 5,800.14 71.70 281.93 3,025.42 22.88 -4,288.992,957.22 6,009,449.38 547,131.05 2.34 -1,087.97 3_MWD+IFR2+MS+Sag (2) 5,895.87 70.82 285.12 3,056.19 44.07 -4,377.112,987.99 6,009,469.96 547,042.79 3.29 -1,090.31 3_MWD+IFR2+MS+Sag (2) 5,991.05 69.82 288.45 3,088.25 69.94 -4,462.903,020.05 6,009,495.23 546,956.84 3.46 -1,087.53 3_MWD+IFR2+MS+Sag (2) 6,086.14 69.20 292.68 3,121.55 101.21 -4,546.283,053.35 6,009,525.93 546,873.25 4.22 -1,078.90 3_MWD+IFR2+MS+Sag (2) 6,181.30 68.44 297.21 3,155.94 138.61 -4,626.713,087.74 6,009,562.77 546,792.57 4.51 -1,063.59 3_MWD+IFR2+MS+Sag (2) 6,276.98 68.14 301.35 3,191.35 182.07 -4,704.233,123.15 6,009,605.69 546,714.77 4.03 -1,041.67 3_MWD+IFR2+MS+Sag (2) 6,372.34 68.24 305.68 3,226.79 230.94 -4,778.023,158.59 6,009,654.05 546,640.65 4.22 -1,013.57 3_MWD+IFR2+MS+Sag (2) 6,467.08 68.99 310.34 3,261.35 285.26 -4,847.493,193.15 6,009,707.87 546,570.81 4.65 -979.09 3_MWD+IFR2+MS+Sag (2) 6,562.20 70.65 314.49 3,294.18 345.47 -4,913.383,225.98 6,009,767.63 546,504.52 4.45 -937.98 3_MWD+IFR2+MS+Sag (2) 6,657.08 69.71 318.99 3,326.36 410.45 -4,974.533,258.16 6,009,832.17 546,442.92 4.57 -891.04 3_MWD+IFR2+MS+Sag (2) 6,748.98 69.63 323.96 3,358.31 477.84 -5,028.193,290.11 6,009,899.18 546,388.80 5.07 -839.84 3_MWD+IFR2+MS+Sag (2) 6,847.31 69.36 328.72 3,392.77 554.47 -5,079.223,324.57 6,009,975.45 546,337.25 4.54 -779.03 3_MWD+IFR2+MS+Sag (2) 6,942.46 70.48 332.89 3,425.45 632.46 -5,122.793,357.25 6,010,053.14 546,293.15 4.28 -714.96 3_MWD+IFR2+MS+Sag (2) 7,037.68 70.98 334.87 3,456.88 713.16 -5,162.363,388.68 6,010,133.56 546,253.03 2.03 -647.25 3_MWD+IFR2+MS+Sag (2) 7,132.65 71.73 334.86 3,487.24 794.63 -5,200.583,419.04 6,010,214.75 546,214.25 0.79 -578.46 3_MWD+IFR2+MS+Sag (2) 7,227.76 71.08 335.63 3,517.57 876.49 -5,238.333,449.37 6,010,296.34 546,175.94 1.03 -509.16 3_MWD+IFR2+MS+Sag (2) 7,323.65 70.37 336.55 3,549.22 959.23 -5,275.013,481.02 6,010,378.82 546,138.69 1.17 -438.73 3_MWD+IFR2+MS+Sag (2) 7,417.96 70.55 338.47 3,580.77 1,041.35 -5,309.013,512.57 6,010,460.69 546,104.13 1.93 -368.21 3_MWD+IFR2+MS+Sag (2) 7,513.47 72.99 340.83 3,610.65 1,126.39 -5,340.543,542.45 6,010,545.51 546,072.02 3.47 -294.22 3_MWD+IFR2+MS+Sag (2) 7,609.10 75.18 344.03 3,636.88 1,214.05 -5,368.283,568.68 6,010,632.97 546,043.68 3.95 -216.73 3_MWD+IFR2+MS+Sag (2) 7,704.18 73.23 347.69 3,662.76 1,302.75 -5,390.643,594.56 6,010,721.49 546,020.71 4.23 -136.84 3_MWD+IFR2+MS+Sag (2) 7,798.86 72.29 352.32 3,690.84 1,391.77 -5,406.343,622.64 6,010,810.40 546,004.40 4.77 -54.92 3_MWD+IFR2+MS+Sag (2) 7,894.37 73.32 355.94 3,719.08 1,482.51 -5,415.663,650.88 6,010,901.07 545,994.46 3.78 30.32 3_MWD+IFR2+MS+Sag (2) 7,990.02 77.65 359.47 3,743.06 1,575.00 -5,419.343,674.86 6,010,993.52 545,990.14 5.77 118.70 3_MWD+IFR2+MS+Sag (2) 8,085.16 83.49 2.01 3,758.64 1,668.80 -5,418.113,690.44 6,011,087.31 545,990.72 6.68 209.62 3_MWD+IFR2+MS+Sag (2) 8,180.54 88.07 4.40 3,765.66 1,763.74 -5,412.783,697.46 6,011,182.28 545,995.39 5.41 302.71 3_MWD+IFR2+MS+Sag (2) 8,275.35 87.21 4.79 3,769.56 1,858.16 -5,405.203,701.36 6,011,276.74 546,002.33 1.00 395.88 3_MWD+IFR2+MS+Sag (2) 8,290.63 87.40 4.53 3,770.28 1,873.37 -5,403.963,702.08 6,011,291.96 546,003.46 2.11 410.89 3_MWD+IFR2+MS+Sag (2) 8,387.51 90.45 5.30 3,772.10 1,969.87 -5,395.663,703.90 6,011,388.50 546,011.09 3.25 506.25 3_MWD+IFR2+MS+Sag (3) 8,487.10 90.01 4.73 3,771.70 2,069.07 -5,386.953,703.50 6,011,487.76 546,019.11 0.72 604.33 3_MWD+IFR2+MS+Sag (3) 8,584.98 90.45 4.09 3,771.31 2,166.66 -5,379.433,703.11 6,011,585.39 546,025.97 0.79 700.54 3_MWD+IFR2+MS+Sag (3) 12/10/2020 12:00:59PM COMPASS 5000.15 Build 91E Page 4 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt I Pad Halliburton Definitive Survey Report Well: Wellbore: MPU I-40 MPU I-40 Survey Calculation Method:Minimum Curvature MPU I-40 Actual RKB @ 68.20usft (Doyon 14) Design:MPU I-40 Database:NORTH US + CANADA MD Reference:MPU I-40 Actual RKB @ 68.20usft (Doyon 14) North Reference: Well MPU I-40 True MD (usft) Inc (°) Azi (°) +E/-W (usft) +N/-S (usft) Survey TVD (usft) TVDSS (usft) Map Northing (ft) Map Easting (ft) Vertical Section (ft) DLS (°/100')Survey Tool Name 8,680.20 89.70 3.15 3,771.18 2,261.69 -5,373.413,702.98 6,011,680.44 546,031.32 1.26 793.88 3_MWD+IFR2+MS+Sag (3) 8,775.65 87.17 2.53 3,773.79 2,356.98 -5,368.693,705.59 6,011,775.75 546,035.39 2.73 887.15 3_MWD+IFR2+MS+Sag (3) 8,870.34 86.00 2.35 3,779.43 2,451.41 -5,364.663,711.23 6,011,870.20 546,038.77 1.25 979.41 3_MWD+IFR2+MS+Sag (3) 8,966.39 87.11 2.41 3,785.20 2,547.21 -5,360.683,717.00 6,011,966.01 546,042.09 1.16 1,072.97 3_MWD+IFR2+MS+Sag (3) 9,061.85 87.23 2.27 3,789.91 2,642.47 -5,356.793,721.71 6,012,061.29 546,045.32 0.19 1,165.99 3_MWD+IFR2+MS+Sag (3) 9,156.83 87.85 1.47 3,793.99 2,737.31 -5,353.693,725.79 6,012,156.14 546,047.76 1.07 1,258.40 3_MWD+IFR2+MS+Sag (3) 9,251.70 87.61 0.75 3,797.75 2,832.09 -5,351.863,729.55 6,012,250.92 546,048.95 0.80 1,350.43 3_MWD+IFR2+MS+Sag (3) 9,347.06 90.64 1.45 3,799.20 2,927.41 -5,350.033,731.00 6,012,346.24 546,050.12 3.26 1,442.97 3_MWD+IFR2+MS+Sag (3) 9,442.23 91.99 1.57 3,797.02 3,022.52 -5,347.523,728.82 6,012,441.36 546,051.97 1.42 1,535.49 3_MWD+IFR2+MS+Sag (3) 9,537.85 91.49 1.93 3,794.12 3,118.05 -5,344.603,725.92 6,012,536.90 546,054.23 0.64 1,628.52 3_MWD+IFR2+MS+Sag (3) 9,632.83 89.82 0.42 3,793.03 3,213.00 -5,342.653,724.83 6,012,631.85 546,055.52 2.37 1,720.74 3_MWD+IFR2+MS+Sag (3) 9,727.71 90.14 0.46 3,793.06 3,307.87 -5,341.923,724.86 6,012,726.72 546,055.60 0.34 1,812.57 3_MWD+IFR2+MS+Sag (3) 9,823.03 89.15 0.26 3,793.65 3,403.19 -5,341.323,725.45 6,012,822.02 546,055.54 1.06 1,904.79 3_MWD+IFR2+MS+Sag (3) 9,917.49 85.50 0.34 3,798.06 3,497.53 -5,340.833,729.86 6,012,916.36 546,055.38 3.86 1,996.04 3_MWD+IFR2+MS+Sag (3) 10,012.96 85.81 0.18 3,805.29 3,592.72 -5,340.403,737.09 6,013,011.54 546,055.16 0.37 2,088.11 3_MWD+IFR2+MS+Sag (3) 10,108.06 85.94 0.60 3,812.14 3,687.57 -5,339.753,743.94 6,013,106.39 546,055.15 0.46 2,179.89 3_MWD+IFR2+MS+Sag (3) 10,203.53 86.06 2.50 3,818.80 3,782.77 -5,337.183,750.60 6,013,201.59 546,057.07 1.99 2,272.51 3_MWD+IFR2+MS+Sag (3) 10,297.93 85.81 3.51 3,825.49 3,876.80 -5,332.243,757.29 6,013,295.65 546,061.36 1.10 2,364.62 3_MWD+IFR2+MS+Sag (3) 10,394.25 86.06 4.13 3,832.32 3,972.67 -5,325.843,764.12 6,013,391.54 546,067.10 0.69 2,458.87 3_MWD+IFR2+MS+Sag (3) 10,490.18 88.04 4.46 3,837.25 4,068.20 -5,318.673,769.05 6,013,487.11 546,073.61 2.09 2,553.00 3_MWD+IFR2+MS+Sag (3) 10,583.62 91.75 4.31 3,837.42 4,161.35 -5,311.523,769.22 6,013,580.30 546,080.11 3.97 2,644.83 3_MWD+IFR2+MS+Sag (3) 10,677.67 96.08 4.50 3,831.00 4,254.88 -5,304.323,762.80 6,013,673.87 546,086.67 4.61 2,737.04 3_MWD+IFR2+MS+Sag (3) 10,772.12 94.64 3.74 3,822.18 4,348.67 -5,297.563,753.98 6,013,767.69 546,092.78 1.72 2,829.38 3_MWD+IFR2+MS+Sag (3) 10,867.47 94.64 3.42 3,814.47 4,443.52 -5,291.633,746.27 6,013,862.57 546,098.06 0.33 2,922.54 3_MWD+IFR2+MS+Sag (3) 10,964.47 91.43 2.65 3,809.33 4,540.24 -5,286.503,741.13 6,013,959.31 546,102.52 3.40 3,017.28 3_MWD+IFR2+MS+Sag (3) 11,057.44 89.76 3.52 3,808.37 4,633.06 -5,281.503,740.17 6,014,052.16 546,106.88 2.03 3,108.24 3_MWD+IFR2+MS+Sag (3) 11,153.92 90.82 5.17 3,807.88 4,729.26 -5,274.193,739.68 6,014,148.40 546,113.52 2.03 3,203.05 3_MWD+IFR2+MS+Sag (3) 11,249.65 92.11 6.70 3,805.43 4,824.44 -5,264.293,737.23 6,014,243.63 546,122.76 2.09 3,297.55 3_MWD+IFR2+MS+Sag (3) 11,345.22 88.53 8.33 3,804.90 4,919.17 -5,251.803,736.70 6,014,338.44 546,134.60 4.12 3,392.29 3_MWD+IFR2+MS+Sag (3) 11,440.52 87.17 10.75 3,808.47 5,013.07 -5,236.023,740.27 6,014,432.44 546,149.74 2.91 3,487.08 3_MWD+IFR2+MS+Sag (3) 11,532.29 87.24 14.12 3,812.95 5,102.57 -5,216.283,744.75 6,014,522.06 546,168.85 3.67 3,578.63 3_MWD+IFR2+MS+Sag (3) 11,627.00 88.53 16.91 3,816.45 5,193.76 -5,190.973,748.25 6,014,613.41 546,193.53 3.24 3,673.26 3_MWD+IFR2+MS+Sag (3) 11,724.42 91.69 19.09 3,816.26 5,286.39 -5,160.873,748.06 6,014,706.24 546,222.99 3.94 3,770.53 3_MWD+IFR2+MS+Sag (3) 11,819.08 93.60 19.52 3,811.89 5,375.63 -5,129.613,743.69 6,014,795.69 546,253.63 2.07 3,864.82 3_MWD+IFR2+MS+Sag (3) 11,914.30 90.99 20.04 3,808.08 5,465.15 -5,097.413,739.88 6,014,885.42 546,285.20 2.79 3,959.62 3_MWD+IFR2+MS+Sag (3) 12,009.18 89.58 20.04 3,807.61 5,554.28 -5,064.903,739.41 6,014,974.77 546,317.10 1.49 4,054.13 3_MWD+IFR2+MS+Sag (3) 12,104.71 87.73 21.43 3,809.85 5,643.60 -5,031.093,741.65 6,015,064.30 546,350.29 2.42 4,149.15 3_MWD+IFR2+MS+Sag (3) 12,199.60 86.49 22.58 3,814.63 5,731.46 -4,995.593,746.43 6,015,152.40 546,385.18 1.78 4,243.21 3_MWD+IFR2+MS+Sag (3) 12,293.76 84.95 24.16 3,821.66 5,817.65 -4,958.343,753.46 6,015,238.83 546,421.83 2.34 4,336.10 3_MWD+IFR2+MS+Sag (3) 12,389.49 88.23 23.54 3,827.35 5,905.04 -4,919.713,759.15 6,015,326.48 546,459.85 3.49 4,430.51 3_MWD+IFR2+MS+Sag (3) 12/10/2020 12:00:59PM COMPASS 5000.15 Build 91E Page 5 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt I Pad Halliburton Definitive Survey Report Well: Wellbore: MPU I-40 MPU I-40 Survey Calculation Method:Minimum Curvature MPU I-40 Actual RKB @ 68.20usft (Doyon 14) Design:MPU I-40 Database:NORTH US + CANADA MD Reference:MPU I-40 Actual RKB @ 68.20usft (Doyon 14) North Reference: Well MPU I-40 True MD (usft) Inc (°) Azi (°) +E/-W (usft) +N/-S (usft) Survey TVD (usft) TVDSS (usft) Map Northing (ft) Map Easting (ft) Vertical Section (ft) DLS (°/100')Survey Tool Name 12,485.73 87.67 22.03 3,830.80 5,993.71 -4,882.463,762.60 6,015,415.39 546,496.49 1.67 4,525.80 3_MWD+IFR2+MS+Sag (3) 12,580.90 87.05 20.29 3,835.18 6,082.36 -4,848.153,766.98 6,015,504.27 546,530.19 1.94 4,620.32 3_MWD+IFR2+MS+Sag (3) 12,675.60 88.78 18.68 3,838.63 6,171.57 -4,816.583,770.43 6,015,593.69 546,561.13 2.49 4,714.66 3_MWD+IFR2+MS+Sag (3) 12,772.20 88.78 17.74 3,840.68 6,263.31 -4,786.403,772.48 6,015,685.63 546,590.68 0.97 4,811.08 3_MWD+IFR2+MS+Sag (3) 12,867.59 86.49 16.81 3,844.62 6,354.31 -4,758.103,776.42 6,015,776.82 546,618.35 2.59 4,906.31 3_MWD+IFR2+MS+Sag (3) 12,961.57 88.16 17.20 3,849.00 6,444.08 -4,730.653,780.80 6,015,866.76 546,645.18 1.82 5,000.13 3_MWD+IFR2+MS+Sag (3) 13,058.36 87.79 16.66 3,852.42 6,536.62 -4,702.483,784.22 6,015,959.48 546,672.70 0.68 5,096.80 3_MWD+IFR2+MS+Sag (3) 13,153.94 87.98 15.62 3,855.95 6,628.37 -4,675.933,787.75 6,016,051.40 546,698.62 1.11 5,192.30 3_MWD+IFR2+MS+Sag (3) 13,247.36 88.47 17.08 3,858.85 6,717.97 -4,649.643,790.65 6,016,141.17 546,724.28 1.65 5,285.64 3_MWD+IFR2+MS+Sag (3) 13,344.55 87.36 18.03 3,862.38 6,810.57 -4,620.353,794.18 6,016,233.96 546,752.94 1.50 5,382.67 3_MWD+IFR2+MS+Sag (3) 13,439.50 87.85 19.42 3,866.35 6,900.41 -4,589.903,798.15 6,016,324.00 546,782.77 1.55 5,477.33 3_MWD+IFR2+MS+Sag (3) 13,534.84 88.23 21.44 3,869.61 6,989.70 -4,556.643,801.41 6,016,413.51 546,815.41 2.15 5,572.18 3_MWD+IFR2+MS+Sag (3) 13,629.82 87.85 19.70 3,872.86 7,078.56 -4,523.293,804.66 6,016,502.60 546,848.14 1.87 5,666.66 3_MWD+IFR2+MS+Sag (3) 13,725.08 87.48 19.09 3,876.74 7,168.34 -4,491.683,808.54 6,016,592.58 546,879.13 0.75 5,761.56 3_MWD+IFR2+MS+Sag (3) 13,819.97 87.73 19.41 3,880.71 7,257.85 -4,460.423,812.51 6,016,682.29 546,909.76 0.43 5,856.10 3_MWD+IFR2+MS+Sag (3) 13,915.00 88.10 19.20 3,884.16 7,347.48 -4,429.033,815.96 6,016,772.13 546,940.54 0.45 5,950.80 3_MWD+IFR2+MS+Sag (3) 14,010.66 88.35 18.74 3,887.13 7,437.90 -4,397.943,818.93 6,016,862.75 546,970.99 0.55 6,046.19 3_MWD+IFR2+MS+Sag (3) 14,105.25 88.47 19.31 3,889.75 7,527.29 -4,367.123,821.55 6,016,952.34 547,001.19 0.62 6,140.51 3_MWD+IFR2+MS+Sag (3) 14,201.06 89.21 17.82 3,891.69 7,618.09 -4,336.633,823.49 6,017,043.34 547,031.06 1.74 6,236.11 3_MWD+IFR2+MS+Sag (3) 14,296.09 90.38 18.47 3,892.03 7,708.39 -4,307.033,823.83 6,017,133.84 547,060.03 1.41 6,330.99 3_MWD+IFR2+MS+Sag (3) 14,390.94 89.64 18.45 3,892.01 7,798.36 -4,277.003,823.81 6,017,224.00 547,089.44 0.78 6,425.67 3_MWD+IFR2+MS+Sag (3) 14,485.30 89.09 18.57 3,893.06 7,887.83 -4,247.043,824.86 6,017,313.67 547,118.77 0.60 6,519.84 3_MWD+IFR2+MS+Sag (3) 14,580.76 89.95 19.50 3,893.86 7,978.07 -4,215.913,825.66 6,017,404.11 547,149.28 1.33 6,615.06 3_MWD+IFR2+MS+Sag (3) 14,675.74 89.83 19.80 3,894.04 8,067.52 -4,183.973,825.84 6,017,493.77 547,180.60 0.34 6,709.73 3_MWD+IFR2+MS+Sag (3) 14,772.38 89.09 18.48 3,894.95 8,158.81 -4,152.293,826.75 6,017,585.27 547,211.65 1.57 6,806.11 3_MWD+IFR2+MS+Sag (3) 14,867.22 88.66 17.58 3,896.81 8,248.97 -4,122.943,828.61 6,017,675.62 547,240.37 1.05 6,900.80 3_MWD+IFR2+MS+Sag (3) 14,962.65 88.35 17.92 3,899.30 8,339.83 -4,093.863,831.10 6,017,766.67 547,268.82 0.48 6,996.09 3_MWD+IFR2+MS+Sag (3) 15,057.82 88.35 20.13 3,902.05 8,429.76 -4,062.853,833.85 6,017,856.80 547,299.21 2.32 7,090.98 3_MWD+IFR2+MS+Sag (3) 15,153.06 89.03 19.93 3,904.22 8,519.21 -4,030.243,836.02 6,017,946.47 547,331.20 0.74 7,185.82 3_MWD+IFR2+MS+Sag (3) 15,247.89 89.58 21.37 3,905.37 8,607.94 -3,996.803,837.17 6,018,035.42 547,364.02 1.63 7,280.18 3_MWD+IFR2+MS+Sag (3) 15,343.03 91.00 21.75 3,904.89 8,696.42 -3,961.843,836.69 6,018,124.13 547,398.37 1.55 7,374.70 3_MWD+IFR2+MS+Sag (3) 15,438.85 89.52 20.16 3,904.46 8,785.90 -3,927.573,836.26 6,018,213.83 547,432.01 2.27 7,469.99 3_MWD+IFR2+MS+Sag (3) 15,533.98 89.21 16.82 3,905.51 8,876.10 -3,897.413,837.31 6,018,304.23 547,461.55 3.53 7,564.93 3_MWD+IFR2+MS+Sag (3) 15,629.87 89.27 13.87 3,906.78 8,968.55 -3,872.043,838.58 6,018,396.84 547,486.28 3.08 7,660.80 3_MWD+IFR2+MS+Sag (3) 15,722.99 89.33 14.85 3,907.92 9,058.75 -3,848.943,839.72 6,018,487.19 547,508.75 1.05 7,753.90 3_MWD+IFR2+MS+Sag (3) 15,818.43 89.58 14.86 3,908.83 9,151.00 -3,824.483,840.63 6,018,579.60 547,532.58 0.26 7,849.34 3_MWD+IFR2+MS+Sag (3) 15,914.65 89.27 15.07 3,909.79 9,243.95 -3,799.633,841.59 6,018,672.71 547,556.78 0.39 7,945.55 3_MWD+IFR2+MS+Sag (3) 16,008.09 90.63 17.80 3,909.88 9,333.56 -3,773.203,841.68 6,018,762.49 547,582.59 3.26 8,038.95 3_MWD+IFR2+MS+Sag (3) 16,105.37 89.09 18.04 3,910.11 9,426.12 -3,743.273,841.91 6,018,855.24 547,611.88 1.60 8,136.10 3_MWD+IFR2+MS+Sag (3) 16,200.51 88.78 18.37 3,911.88 9,516.48 -3,713.553,843.68 6,018,945.80 547,640.97 0.48 8,231.08 3_MWD+IFR2+MS+Sag (3) 12/10/2020 12:00:59PM COMPASS 5000.15 Build 91E Page 6 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt I Pad Halliburton Definitive Survey Report Well: Wellbore: MPU I-40 MPU I-40 Survey Calculation Method:Minimum Curvature MPU I-40 Actual RKB @ 68.20usft (Doyon 14) Design:MPU I-40 Database:NORTH US + CANADA MD Reference:MPU I-40 Actual RKB @ 68.20usft (Doyon 14) North Reference: Well MPU I-40 True MD (usft) Inc (°) Azi (°) +E/-W (usft) +N/-S (usft) Survey TVD (usft) TVDSS (usft) Map Northing (ft) Map Easting (ft) Vertical Section (ft) DLS (°/100')Survey Tool Name 16,295.05 89.15 18.11 3,913.59 9,606.26 -3,683.963,845.39 6,019,035.77 547,669.94 0.48 8,325.45 3_MWD+IFR2+MS+Sag (3) 16,391.02 89.83 18.48 3,914.44 9,697.37 -3,653.843,846.24 6,019,127.08 547,699.43 0.81 8,421.26 3_MWD+IFR2+MS+Sag (3) 16,486.01 90.88 18.05 3,913.86 9,787.57 -3,624.073,845.66 6,019,217.47 547,728.57 1.19 8,516.09 3_MWD+IFR2+MS+Sag (3) 16,581.03 90.07 18.50 3,913.07 9,877.79 -3,594.273,844.87 6,019,307.89 547,757.74 0.98 8,610.95 3_MWD+IFR2+MS+Sag (3) 16,676.31 90.57 17.96 3,912.54 9,968.29 -3,564.473,844.34 6,019,398.58 547,786.92 0.77 8,706.08 3_MWD+IFR2+MS+Sag (3) 16,771.70 90.07 17.06 3,912.00 10,059.26 -3,535.773,843.80 6,019,489.74 547,814.99 1.08 8,801.37 3_MWD+IFR2+MS+Sag (3) 16,866.31 91.13 17.21 3,911.01 10,149.66 -3,507.903,842.81 6,019,580.32 547,842.24 1.13 8,895.91 3_MWD+IFR2+MS+Sag (3) 16,961.21 91.68 17.44 3,908.69 10,240.23 -3,479.643,840.49 6,019,671.07 547,869.86 0.63 8,990.70 3_MWD+IFR2+MS+Sag (3) 17,056.41 88.59 16.90 3,908.46 10,331.17 -3,451.543,840.26 6,019,762.20 547,897.33 3.29 9,085.82 3_MWD+IFR2+MS+Sag (3) 17,151.14 89.09 16.37 3,910.38 10,421.92 -3,424.433,842.18 6,019,853.12 547,923.81 0.77 9,180.49 3_MWD+IFR2+MS+Sag (3) 17,221.00 89.09 16.37 3,911.49 10,488.94 -3,404.743,843.29 6,019,920.27 547,943.04 0.00 9,250.33 PROJECTED to TD Approved By:Checked By:Date: 12/10/2020 12:00:59PM COMPASS 5000.15 Build 91E Page 7 Chelsea Wright Digitally signed by Chelsea Wright Date: 2020.12.10 09:04:08 -09'00' Benjamin Hand Digitally signed by Benjamin Hand Date: 2020.12.11 13:07:41 -09'00' TD Shoe Depth: PBTD: No. Jts. Returned RKB RKB to BHF RKB to THF Jts. 1 2 1 1 1 143 1 1 1 59 1 X Yes No X Yes No 30 Fluid Description: Liner hanger Info (Make/Model): Liner top Packer?: Yes No Liner hanger test pressure:X Yes No Centralizer Placement: Preflush (Spacer) Type: Density (ppg) Volume pumped (BBLs) Lead Slurry Type:Sacks: Yield: Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Tail Slurry Type:Sacks: Yield: Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Post Flush (Spacer) Type: Density (ppg) Rate (bpm): Volume: Displacement: Type: Density (ppg) Rate (bpm): Volume (actual / calculated): FCP (psi): Pump used for disp:X Yes No Casing Rotated? Yes X No Reciprocated? Yes X No % Returns during job Cement returns to surface?X Yes No Spacer returns?X Yes No Vol to Surf: Cement In Place At: Date: Estimated TOC: Method Used To Determine TOC: Preflush (Spacer) Type: Density (ppg) Volume pumped (BBLs) Lead Slurry Type:Sacks: Yield: Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Tail Slurry Type:Sacks: Yield: Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Post Flush (Spacer) Type: Density (ppg) Rate (bpm): Volume: Displacement: Type: Density (ppg) Rate (bpm): Volume (actual / calculated): FCP (psi): Pump used for disp:X Yes No Casing Rotated? Yes X No Reciprocated? Yes X No % Returns during job Cement returns to surface?X Yes No Spacer returns? Yes X No Vol to Surf: Cement In Place At: Date: Estimated TOC: Method Used To Determine TOC: Post Job Calculations: Calculated Cmt Vol @ 0% excess: Total Volume cmt Pumped: Cmt returned to surface: Calculated cement left in wellbore: OH volume Calculated: OH volume actual: Actual % Washout: Casing (Or Liner) Detail Shoe Casing Cut Joint 10 3/4 50.0 509.95 5483.8SECOND STAGERig 5:13 Returns to surface Rotate Csg Recip Csg Ft. Min. PPG9.4 Shoe @ 8368 FC @ Top of Liner8,242.81 Floats Held 535.85 900 339 561 Spud Mud CASING RECORD County State Supv.D. Yessak / C. Demoski Hilcorp Energy Company CASING & CEMENTING REPORT Lease & Well No.MP I-40 Date Run 30-Nov-20 Setting Depths Component Size Wt. Grade THD Make Length Bottom Top TXP BTC-SR Innovex 1.60 8,368.00 8,366.40 19.31 54.299 5/8 47.0 L-80 TXP BTC-SR Tenaris Csg Wt. On Hook:270,000 Type Float Collar:Innovex No. Hrs to Run:22 9.4 7 1800 10 10.7 365 6.5 99 570 Bump Plug?FIRST STAGE10Tuned Spacer 60 15.8 540 3.3 9.4 6 163.62/162 616.08/618.66 1250 50 Rig 15.8 82 Bump press Circulate out cement Bump Plug? Y 19:24 12/1/2020 2,482 2481.89 8,368.008,375.00 CEMENTING REPORT Csg Wt. On Slips:100,000 Spud Mud Tuned Spacer 690 2.94 Stage Collar @ 60 Bump press 99 289 ES Cementer Closure OK 56 12 397 34.60 RKB to CHF Type of Shoe:Innovex Casing Crew:Doyon No. Jts. Delivered 244 No. Jts. Run 206 38 Length Measurements W/O Threads Ftg. Delivered Ftg. Run Ftg. Returned Ftg. Cut Jt. Ftg. Balance www.wellez.net WellEz Information Management LLC ver_04818br 4.5 ArcticCem Lead Type 9-5/8" x 12-1/2" bow spring centralizers: /#ff# #& Casing 9 5/8 40.0 L-80 TXP BTC-SR Tenaris 81.77 8,366.40 8,284.63 Float Collar 10 3/4 50.0 TXP BTC-SR Innovex 1.30 8,284.63 8,283.33 Casing 9 5/8 40.0 L-80 TXP BTC-SR Tenaris 39.11 8,283.33 8,244.22 Baffle Adapter 10 3/4 50.0 TXP BTC-SR HES 1.41 8,244.22 8,242.81 Casing 9 5/8 40.0 L-80 TXP BTC-SR Tenaris 5,742.19 8,242.81 2,500.62 Pup Joint 9 5/8 40.0 L-80 TXP BTC-SR Tenaris 18.73 2,500.62 2,481.89 ES Cementer 10 3/4 TXP BTC-SR HES 3.73 2,481.89 2,478.16 Pup Joint 9 5/8 40.0 L-80 TXP BTC-SR Tenaris 17.61 2,478.16 2,460.55 Casing 9 5/8 47.0 L-80 TXP BTC-SR Tenaris 2,406.26 2,460.55 54.29 Type I/II Cement 950 2.35 Premium G 400 1.15 4.5 Premium G Tail 270 1.17 12/2/2020 38 Spud Mud 2,482 38 Solid / Slotted Liner Detail/ Page 2 of 2 Edited By: JNL 1/12/2021 GENERAL WELL INFO API: 50-029-23689-00-00 Completion Date: 12/17/2020 4-1/2”SOLID LINER DETAIL Jts Top (MD) Top (TVD) Btm (MD) Btm (TVD) 4 8221’ 3767’ 8374’ 3772’ 7 8754’ 3773’ 9041’ 3789’ 4 9125’ 3793’ 9285’ 3798’ 3 9791’ 3793’ 9911’ 3798’ 5 9953’ 3801’ 10158’ 3816’ 5 10242’ 3822’ 10437’ 3835’ 9 10521’ 3837’ 10846’ 3816’ 8 10969’ 3809’ 11269’ 3805’ 12 11311’ 3805’ 11758’ 3815’ 8 12010’ 3808’ 12310’ 3823’ 1 12815’ 3842’ 12851’ 3844’ 1 13561’ 3871’ 13688’ 3875’ 2 17184’ 3911’ 17221’ 3911’ 4-1/2”SCREENS LINER DETAIL Jts Top (MD) Top (TVD) Btm (MD) Btm (TVD) 9 8374’ 3772’ 8754’ 3773’ 2 9041’ 3789’ 9125’ 3793’ 12 9285’ 3798’ 9791’ 3793’ 1 9911’ 3798’ 9953’ 3801’ 2 10158’ 3816’ 10242’ 3822’ 2 10437’ 3835’ 10521’ 3837’ 3 10846’ 3816’ 10969’ 3809’ 1 11269’ 3805’ 11311’ 3805’ 6 11758’ 3815’ 12010’ 3808’ 12 12310’ 3823’ 12815’ 3842’ 19 12851’ 3844’ 13651’ 3871’ 83 13688’ 3875’ 17184’ 3911’ David Douglas Hilcorp Alaska, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or fax to 907 777-8510. Received By: Date: Date: 01/06/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU I-40 (PTD 220-071) FINAL GEOSTEERING LOGS, EOW REPORTS (05DEC2020 to 09DEC2020) SFTP Transferred - Files: Please include current contact information if different from above. PTD: 2200710 E-Set: 34520 Received by the AOGCC 01/06/2021 Abby Bell 01/06/2021 David Douglas Hilcorp Alaska, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or fax to 907 777-8510. Received By: Date: Date: 12/23/2020 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU I-40 (PTD 220-071) FINAL LWD FORMATION EVALUATION LOGS (11/25/2020 to 12/09/2020) •DGR, AGR, ABG, ADR, EWR-M5, Wellbore Profile (2” & 5” MD/TVD Color Logs) •Final Definitive Directional Survey SFTP Transfer - Data Folders: Please include current contact information if different from above. PTD: 2200710 E-Set: 34464 Received by the AOGCC 12/23/2020 Abby Bell 12/23/2020 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Monty M Myers Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Milne Point Field, Schrader Bluff Oil Pool, MPU I-40 Hilcorp Alaska, LLC Permit to Drill Number: 220-071 Surface Location: 2342' FSL, 3951' FEL, Sec. 33, T13N, R10E, UM, AK Bottomhole Location: 1533' FNL, 1567' FEL, Sec. 20, T13N, R10E, UM, AK Dear Mr. Myers: Enclosed is the approved application for the permit to drill the above referenced development well. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Jeremy M. Price Chair DATED this ___ day of October, 2020. y, JMPi 27 1a. Type of Work:1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp 1c. Specify if well is proposed for: Drill Lateral Stratigraphic Test Development - Oil Service - Winj Single Zone Coalbed Gas Gas Hydrates Redrill Reentry Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal Shale Gas 2. Operator Name:5. Bond: Blanket Single Well 11. Well Name and Number: Bond No. 3. Address:6. Proposed Depth: 12. Field/Pool(s): MD: 18,856' TVD: 3,982' 4a. Location of Well (Governmental Section):7. Property Designation: Surface: Top of Productive Horizon:8. DNR Approval Number: 13. Approximate Spud Date: Total Depth:9. Acres in Property: 14. Distance to Nearest Property: 4b. Location of Well (State Base Plane Coordinates - NAD 27):10. KB Elevation above MSL (ft): 67.3 15. Distance to Nearest Well Open Surface: x-551420 y- 6009456 Zone-4 33.6 to Same Pool: 400' 16. Deviated wells:Kickoff depth: 400 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 90 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD 42" 20" 129.5# X-52 80' Surface Surface 110' 110' 47# L-80 TXP 2240' Surface Surface 2240' 1816' 40# L-80 TXP 5973' 2240' 1816' 8413' 3787' Tieback 7-5/8" 29.7# L-80 Hyd 521 8163' Surface Surface 8163' 3760' 8-1/2" 4-1/2" 13.5# L-80 Hyd 625 10693' 8163' 3760' 18856' 3982' 19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Junk (measured): TVD Hydraulic Fracture planned?Yes No 20. Attachments:Property Plat BOP Sketch Drilling Program Time v. Depth Plot Shallow Hazard Analysis Diverter Sketch Seabed Report Drilling Fluid Program 20 AAC 25.050 requirements Contact Name: Contact Email: Contact Phone: Date: Permit to Drill API Number: Permit Approval Number:50- Date: Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales: Samples req'd: Yes No Mud log req'd: Yes No H2S measures: Yes No Directional svy req'd: Yes No Spacing exception req'd: Yes No Inclination-only svy req'd: Yes No Post initial injection MIT req'd: Yes No APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Sr Pet Eng Sr Pet Geo Sr Res Eng November 15, 2020 Authorized Name: Monty Myers Authorized Title: Drilling Manager Nathan Sperry nathan.sperry@hilcorp.com 18. Casing Program:Top - Setting Depth - BottomSpecifications 1752 MPU I-40 Milne Point Field Schrader Bluff Oil Pool 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 Hilcorp Alaska, LLC 2342' FSL, 3951' FEL, Sec. 33, T13N, R10E, UM, AK ADL 025906, 025517 & 025515 022224484 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 1354 1643' FNL, 1188' FWL, Sec. 32, T13N, R10E, UM, AK 1533' FNL, 1567' FEL, Sec. 20, T13N, R10E, UM, AK 88-004 7659 3636' Cement Quantity, c.f. or sacks Cement Volume MDSize Plugs (measured): (including stage data) Effect. Depth TVD (ft):Effect. Depth MD (ft): LengthCasing Total Depth MD (ft):Total Depth TVD (ft): Surface Conductor/Structural Authorized Signature: Production Liner Intermediate See cover letter for other requirements. Perforation Depth MD (ft): 21. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Commission Use Only Perforation Depth TVD (ft): 12-1/4"9-5/8"Stg 2 L - 1935 ft3 / T - 313 ft3 GL / BF Elevation above MSL (ft): Uncemented Tieback Uncemented Screen Liner ~270 ft3 Stg 1 L - 2248 ft3 / T - 458 ft3 ess Type of W L rilllll R L 1b l S l Class: t et a e, g NoNoNooNo bed s sae esss es NoNNoo s s NoNNNooo No D sss ssss s D e ll M etettttttttte NNNoo No essssss::: es for: tesees y if well is aas G t teses ss S S 20 S S S esss es NNNNNoooo No s NoNNoNoNoN al S aaass G ryy E l S essss esss NNNNNNNoooo ooo NNNooo esss oo Form 10-401 Revised 3/2020 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g) 10.23.2020 By Samantha Carlisle at 8:24 am, Oct 26, 2020 Digitally signed by Monty M Myers DN: cn=Monty M Myers, c=US, o=Hilcorp Alaska, LLC, ou=Technical Services - AK Drilling, email=mmyers@hilcorp.com Reason: I am approving this document Date: 2020.10.23 16:03:55 -08'00' Monty M Myers 2440' 1889' DSR-10/27/2020 50-029-23689-00-00 BOPE test to 3000 psi. MGR26OCT2020 220-071 2440 2440 1889 SFD 10/26/2020 275 10/27/2020 10/27/2020 Milne Point Unit (MPU) I-40 Drilling Program Version 1 10/23/2020 Table of Contents 1.0 Well Summary ........................................................................................................................... 2 2.0 Management of Change Information ........................................................................................ 3 3.0 Tubular Program:...................................................................................................................... 4 4.0 Drill Pipe Information: .............................................................................................................. 4 5.0 Internal Reporting Requirements ............................................................................................. 5 6.0 Planned Wellbore Schematic ..................................................................................................... 6 7.0 Drilling / Completion Summary ................................................................................................ 7 8.0 Mandatory Regulatory Compliance / Notifications .................................................................. 8 9.0 RU and Preparatory Work ...................................................................................................... 10 10.0 NU 21-1/4” 2M Diverter System .............................................................................................. 11 11.0 Drill 12-1/4” Hole Section ........................................................................................................ 13 12.0 Run 9-5/8” Surface Casing ...................................................................................................... 16 13.0 Cement 9-5/8” Surface Casing ................................................................................................. 22 14.0 ND Diverter, NU BOPE, & Test .............................................................................................. 26 15.0 Drill 8-1/2” Hole Section .......................................................................................................... 27 16.0 Run 4-1/2” Screen Liner .......................................................................................................... 32 17.0 Run 7-5/8” Tieback .................................................................................................................. 36 18.0 Run ESP Upper Completion .................................................................................................... 39 19.0 Doyon 14 Diverter Schematic .................................................................................................. 41 20.0 Doyon 14 BOP Schematic ........................................................................................................ 42 21.0 Wellhead Schematic ................................................................................................................. 43 22.0 Days Vs Depth .......................................................................................................................... 44 23.0 Formation Tops & Information............................................................................................... 45 24.0 Anticipated Drilling Hazards .................................................................................................. 46 25.0 Doyon 14 Layout ...................................................................................................................... 50 26.0 FIT Procedure .......................................................................................................................... 51 27.0 Doyon 14 Choke Manifold Schematic ..................................................................................... 52 28.0 Casing Design ........................................................................................................................... 53 29.0 8-1/2” Hole Section MASP ....................................................................................................... 54 30.0 Spider Plot (NAD 27) (Governmental Sections) ...................................................................... 55 31.0 Surface Plat (As Staked) (NAD 27) ......................................................................................... 56 32.0 Schrader Bluff Nb Sand Offset MW vs TVD Chart ............................................................... 57 Page 2 Milne Point Unit I-40 SB Producer Drilling Procedure 1.0 Well Summary Well MPU I-40 Pad Milne Point “I” Pad Planned Completion Type ESP on 3-1/2 tubing Target Reservoir(s) Schrader Bluff NB Sand Planned Well TD, MD / TVD 19,856’ MD / 3,982’ TVD PBTD, MD / TVD 19,736’ MD / 3,980’ TVD Surface Location (Governmental) 2342' FSL, 1329' FWL, Sec 33, T13N, R10E, UM, AK Surface Location (NAD 27) X= 551420, Y= 6009456 Top of Productive Horizon (Governmental) 1643' FNL, 1188' FWL, Sec 32, T13N, R10E, UM, AK TPH Location (NAD 27) X= 545988 Y= 6010715 BHL (Governmental) 1533' FNL, 1567' FEL, Sec 20, T13N, R10E, UM, AK BHL (NAD 27) X= 548410, Y= 6021400 AFE Drilling Days 20 AFE Completion Days 4 Maximum Anticipated Pressure (Surface) 1,354 psig Maximum Anticipated Pressure (Downhole/Reservoir) 1,752 psig Work String 5” 19.5# S-135 NC 50 D14 KB Elevation above MSL: 33.7 ft + 33.6 ft = 67.3 ft GL Elevation above MSL: 33.6 ft BOP Equipment 13-5/8” x 5M Annular, (3) ea 13-5/8” x 5M Rams 18,73618,856 Page 3 Milne Point Unit I-40 SB Producer Drilling Procedure 2.0 Management of Change Information Page 4 Milne Point Unit I-40 SB Producer Drilling Procedure 3.0 Tubular Program: Hole Section OD (in) ID (in) Drift (in) Conn OD (in) Wt (#/ft) Grade Conn Burst (psi) Collapse (psi) Tension (k-lbs) Cond 20” 19.25” - - - X-52 Weld 12-1/4” 9-5/8” 8.835” 8.679” 10.625” 40.0 L-80 TXP 5,750 3,090 916 9-5/8” 8.681” 8.525” 10.625” 47 L-80 TXP 6,870 4,750 1,086 Tieback 7-5/8” 6.875” 6.750” 7.625 29.7 L-80 Hyd 521 6,890 4,790 683 8-1/2” 4-1/2” Screens 3.920 3.795 4.714 13.5 L-80 Hydril 625 9,020 8,540 279 4.0 Drill Pipe Information: Hole Section OD (in) ID (in) TJ ID (in) TJ OD (in) Wt (#/ft) Grade Conn M/U (Min) M/U (Max) Tension (k-lbs) Surface & Production 5” 4.276” 3.250” 6.625” 19.5 S-135 DS50 36,100 43,100 560klb 5” 4.276” 3.250” 6.625” 19.5 S-135 NC50 30,730 34,136 560klb All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery). Page 5 Milne Point Unit I-40 SB Producer Drilling Procedure 5.0 Internal Reporting Requirements 5.1 Fill out daily drilling report and cost report on WellEz. x Report covers operations from 6am to 6am x Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left of the data entry area – this will not save the data entered, and will navigate to another data entry. x Ensure time entry adds up to 24 hours total. x Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. x Enter the MD and TVD depths EVERY DAY whether you are making hole or not. 5.2 Afternoon Updates x Submit a short operations update each work day to pmazzolini@hilcorp.com, mmyers@hilcorp, nathan.sperry@hilcorp.com, and Joseph.Lastufka@Hilcorp.com 5.3 Intranet Home Page Morning Update x Submit a short operations update each morning by 7am on the company intranet homepage. On weekend and holidays, ensure to have this update in before 5am. 5.4 EHS Incident Reporting x Health and Safety: Notify EHS field coordinator. x Environmental: Drilling Environmental Coordinator x Notify Drilling Manager & Drilling Engineer on all incidents x Submit Hilcorp Incident report to contacts above within 24 hrs 5.5 Casing Tally x Send final “As-Run” Casing tally to mmyers@hilcorp,com nathan.sperry@hilcorp.com, and Joseph.Lastufka@hilcorp.com 5.6 Casing and Cement report x Send casing and cement report for each string of casing to mmyers@hilcorp.com, nathan.sperry@hilcorp.com and Joseph.Lastufka@hilcorp.com 5.7 Hilcorp Milne Point Contact List: Title Name Work Phone Cell Phone Email Drilling Manager Monty Myers 907.777.8431 907.538.1168 mmyers@hilcorp.com Drilling Engineer Nate Sperry 907.777.8450 907-301-8996 nathan.sperry@hilcorp.com Completion Engineer Ian Toomey 907.777.8434 907.903.3987 itoomey@hilcorp.com Geologist Seth Nolan 907.777.8308 907.519.8225 snolan@hilcorp.com Reservoir Engineer Reid Edwards 907.777.8421 907.250.5081 reedwards@hilcorp.com Drilling Env. Coordinator Keegan Fleming 907.777.8477 907.350.9439 kfleming@hilcorp.com EHS Manager Carl Jones 907.777.8327 907.382.4336 cajones@hilcorp.com Drilling Tech Joe Lastufka 907.777.8400 907.227.8496 Joseph.Lastufka@hilcorp.com Page 6 Milne Point Unit I-40 SB Producer Drilling Procedure 6.0 Planned Wellbore Schematic Page 7 Milne Point Unit I-40 SB Producer Drilling Procedure 7.0 Drilling / Completion Summary MPU I-40 is a grassroots producer planned to be drilled in the Schrader Bluff NB sand. I-40 is part of a multi well program targeting the Schrader Bluff sand on I-pad. The directional plan is a horizontal well path with a 12-1/4” hole with 9-5/8” surface casing set into the top of the Schrader Bluff NB sand. An 8-1/2” lateral section will be drilled. A 4-1/2” screen liner will be run in the open hole section and the well produced with an ESP assembly. The Doyon 14 will be used to drill and complete the wellbore Drilling operations are expected to commence approximately November 15th, 2020, pending rig schedule. Surface casing will be run to 8,413’ MD / 3,787’ TVD and cemented to surface via a 2 stage primary cement job. Cement returns to surface will confirm TOC at surface. If cement returns to surface are not observed, necessary remedial action will then be discussed with AOGCC authorities. All cuttings & mud generated during drilling operations will be hauled to the Milne Point “B” pad G&I facility. General sequence of operations: 1. MIRU Doyon 14 to well site 2. NU & Test 21-1/4” Diverter and 16” diverter line 3. Drill 12-1/4” hole to TD of surface hole section. Run and cement 9-5/8” surface casing 4. ND diverter, NU wellhead, NU 13-5/8” 5M BOP & Test 5. Drill 8-1/2” lateral to well TD. 6. Run 4-1/2” production liner 7. Run 7-5/8” tieback 8. Run Upper Completion 9. ND BOP, NU Tree, RDMO Reservoir Evaluation Plan: 1. Surface hole: No mud logging. On Site geologist. LWD: GR + Res 2. Production Hole: No mud logging. On site geologist. LWD: GR + ADR (For geo-steering) 24 hour notice to AOGCC to witness. 24 hour notice to AOGCC to witness diverter test. Page 8 Milne Point Unit I-40 SB Producer Drilling Procedure 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the all applicable AOGCC regulations, specific regulations are listed below. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. x BOPs shall be tested at (2) week intervals during the drilling and completion of MPU I-40. Ensure to provide AOGCC 24 hrs notice prior to testing BOPs. x The initial test of BOP equipment will be to 250/3,000 psi & subsequent tests of the BOP equipment will be to 250/3,000 psi for 5/5 min (annular to 50% rated WP, 2,500 psi on the high test for initial and subsequent tests). Confirm that these test pressures match those specified on the APD. x If the BOP is used to shut in on the well in a well control situation or control fluid flow from the well bore, AOGCC is to be notified and we must test all BOP components utilized for well control prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP test. x All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid program and drilling fluid system”. x All AOGCC regulations within 20 AAC 25.035 “Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements”. o Ensure the diverter vent line is at least 75’ away from potential ignition sources x Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office. AOGCC Regulation Variance Requests: No variances are requested at this time. Page 9 Milne Point Unit I-40 SB Producer Drilling Procedure Summary of Doyon 14 BOP Equipment & Test Requirements Hole Section Equipment Test Pressure (psi) 12 1/4” x 21-1/4” 2M Diverter w/ 16” Diverter Line Function Test Only For Reference x 13-5/8” x 5M Hydril “GK” Annular BOP x 13-5/8” x 5M Hydril MPL Double Gate o Blind ram in btm cavity x Mud cross w/ 3” x 5M side outlets x 13-5/8” x 5M Hydril MPL Single ram x 3-1/8” x 5M Choke Line x 3-1/8” x 5M Kill line x 3-1/8” x 5M Choke manifold x Standpipe, floor valves, etc N/A N/A Primary closing unit: NL Shaffer, 6 station, 3,000 psi, 180 gallon accumulator unit. Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is a 30:1 air pump, and emergency pressure is provided by bottled nitrogen. The remote closing operator panels are located in the doghouse and on accumulator unit. Required AOGCC Notifications: x Well control event (BOPs utilized to shut in the well to control influx of formation fluids). x 24 hours notice prior to spud. x 24 hours notice prior to testing BOPs. x 24 hours notice prior to casing running & cement operations. x Any other notifications required in APD. Regulatory Contact Information: AOGCC Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email: jim.regg@alaska.gov Guy Schwartz / Petroleum Engineer / (O): 907-793-1226 / (C): 907-301-4533 / Email: guy.schwartz@alaska.gov Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Email: Victoria.loepp@alaska.gov Mel Rixse / Petroleum Engineer / (O): 907-793-1231 / (C): 907-223-3605 / Email: melvin.rixse@alaska.gov Primary Contact for Opportunity to witness: AOGCC.Inspectors@alaska.gov Test/Inspection notification standardization format: http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) Page 10 Milne Point Unit I-40 SB Producer Drilling Procedure 9.0 RU and Preparatory Work 9.1 I-40 will utilize a newly set 20” conductor on I-pad. Ensure to review attached surface plat and make sure rig is over appropriate conductor. 9.2 Ensure PTD and drilling program are posted in the rig office and on the rig floor. 9.3 Install landing ring. 9.4 Insure (2) 4” nipples are installed on opposite sides of the conductor with ball valves on each. 9.5 Level pad and ensure enough room for layout of rig footprint and RU. 9.6 Rig mat footprint of rig. 9.7 MIRU Doyon 14. Ensure rig is centered over conductor to prevent any wear to BOPE or wellhead. 9.8 Mud loggers WILL NOT be used on either hole section. 9.9 Mix spud mud for 12-1/4” surface hole section. Ensure mud temperatures are cool (<80qF). 9.10 Ensure 6” liners in mud pumps. x Continental EMSCO FB-1600 mud pumps are rated at 4,665 psi, 462 GPM @ 110 SPM @ 95% volumetric efficiency. Page 11 Milne Point Unit I-40 SB Producer Drilling Procedure 10.0 NU 21-1/4” 2M Diverter System 10.1 NU 21-1/4” Hydril MSP 2M Diverter System (Diverter Schematic attached to program). x NU 16-3/4” 3M x 21-1/4” 2M DSA on 16-3/4” 3M wellhead. x NU 21-1/4” diverter “T”. x Knife gate, 16” diverter line. x Ensure diverter RU complies with AOGCC reg 20.AAC.25.035(C). x Diverter line must be 75 feet from nearest ignition source x Place drip berm at the end of diverter line. 10.2 Notify AOGCC. Function test diverter. Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens prior to annular closure. 10.3 Ensure to set up a clearly marked “warning zone” is established on each side and ahead of the vent line tip. “Warning Zone” must include: x A prohibition on vehicle parking x A prohibition on ignition sources or running equipment x A prohibition on staged equipment or materials x Restriction of traffic to essential foot or vehicle traffic only. Page 12 Milne Point Unit I-40 SB Producer Drilling Procedure 10.4 Rig & Diverter Orientation: x May change on location Page 13 Milne Point Unit I-40 SB Producer Drilling Procedure 11.0 Drill 12-1/4” Hole Section 11.1 PU 12-1/4” directional drilling assembly: x Ensure BHA components have been inspected previously. x Drift and caliper all components before MU. Visually verify no debris inside components that cannot be drifted. x Ensure TF offset is measured accurately and entered correctly into the MWD software. x Be sure to run a UBHO sub for wireline gyro x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. x Drill string will be 5”, 19.5#, S-135, NC50. x Run a solid float in the surface hole section. 11.2 Begin drilling out from 20” conductor at reduced flow rates to avoid broaching the conductor. x Consider using a trash bit to clean out conductor to mitigate potential damage from debris in conductor. 11.3 Drill 12-1/4” hole section to section TD, in the Schrader NB sand. Confirm this setting depth with the Geologist and Drilling Engineer while drilling the well. x Monitor the area around the conductor for any signs of broaching. If broaching is observed, Stop drilling (or circulating) immediately notify Drilling Engineer. x Efforts should be made to minimize dog legs in the surface hole. Keep DLS < 6°/ 100. x Hold a safety meeting with rig crews to discuss: x Conductor broaching ops and mitigation procedures. x Well control procedures and rig evacuation x Flow rates, hole cleaning, mud cooling, etc. x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Keep mud as cool as possible to keep from washing out permafrost. x Pump at 400-600 GPM. Monitor shakers closely to ensure shaker screens and return lines can handle the flow rate. x Ensure to not out drill hole cleaning capacity, perform clean up cycles or reduce ROP if packoffs, increase in pump pressure or changes in hookload are seen x Slow in/out of slips and while tripping to keep swab and surge pressures low x Ensure shakers are functioning properly. Check for holes in screens on connections. x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of pea gravel, clay balling or packing off. x Adjust MW and viscosity as necessary to maintain hole stability, ensure MW is at a 9.2 ppg minimum at TD (pending MW increase due to hydrates). x Perform wireline gyros until clean MWD surveys are seen. Take MWD surveys every stand drilled. x Gas hydrates have not been seen on I-pad. However, be prepared for them. In MPU they have been encountered typically around 2,100-2,400’ TVD (just below permafrost). Be prepared for hydrates: Page 14 Milne Point Unit I-40 SB Producer Drilling Procedure x Gas hydrates can be identified by the gas detector and a decrease in MW or ECD x Monitor returns for hydrates, checking pressurized & non-pressurized scales x Do not stop to circulate out gas hydrates – this will only exacerbate the problem by washing out additional permafrost. Attempt to control drill (150 FPH MAX) through the zone completely and efficiently to mitigate the hydrate issue. Flowrates can also be reduced to prevent mud from belching over the bell nipple. Consider adding Lecithin to allow the gas to break out. x Gas hydrates are not a gas sand, once a hydrate is disturbed the gas will come out of the well. MW will not control gas hydrates, but will affect how gas breaks out at surface. x Surface Hole AC: x There are no wells with a clearance factor of <1.0 11.4 12-1/4” hole mud program summary: x Density: Weighting material to be used for the hole section will be barite. Additional barite or spike fluid will be on location to weight up the active system (1) ppg above highest anticipated MW. We will start with a simple gel + FW spud mud at 8.8 ppg and TD with 9.2+ ppg. Depth Interval MW (ppg) Surface – Base Permafrost 8.9+ Base Permafrost - TD 9.2+ (For Hydrates if need based on offset wells) MW can be cut once ~500’ below hydrate zone x PVT System: MD Totco PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, and Toolpusher office. x Rheology: Aquagel and Barazan D+ should be used to maintain rheology. Begin system with a 75 YP but reduce this once clays are encountered. Maintain a minimum 25 YP at all times while drilling. Be prepared to increase the YP if hole cleaning becomes an issue. x Fluid Loss: DEXTRID and/or PAC L should be used for filtrate control. Background LCM (10 ppb total) BARACARBs/BAROFIBRE/STEELSEALs can be used in the system while drilling the surface interval to prevent losses and strengthen the wellbore. x Wellbore and mud stability: Additions of CON DET PRE-MIX/DRIL N SLIDE are recommended to reduce the incidence of bit balling and shaker blinding when penetrating the high-clay content sections of the Sagavanirktok and the heavy oil sections of the UGNU 4A. Maintain the pH in the 8.5 – 9.0 range with caustic soda. Daily additions of ALDACIDE G / X-CIDE 207 MUST be made to control bacterial action. x Casing Running: Reduce system YP with DESCO as required for running casing as allowed (do not jeopardize hole conditions). Run casing carefully to minimize surge and swab pressures. Reduce the system rheology once the casing is landed to a YP < 20 (check with the cementers to see what YP value they have targeted). Page 15 Milne Point Unit I-40 SB Producer Drilling Procedure System Type: 8.8 – 9.2 ppg Pre-Hydrated Aquagel/freshwater spud mud Properties: Section Density Viscosity Plastic Viscosity Yield Point API FL pH Temp Surface 8.8 – 9.8 75-175 20 - 40 25-45 <10 8.5 – 9.0 70 F System Formulation: Gel + FW spud mud Product- Surface hole Size Pkg ppb or (% liquids) M-I Gel 50 lb sx 25 Soda Ash 50 lb sx 0.25 PolyPac Supreme UL 50 lb sx 0.08 Caustic Soda 50 lb sx 0.1 SCREENCLEEN 55 gal dm 0.5 11.5 At TD, CBU and condition the mud until the hole is clean while BROOH. Rack back stands but do not trip to bottom until the hole is clean. 11.6 Once the hole is clean, RIH to bottom, proceed to BROOH to HWDP x Pump at full drill rate (400-600 GPM), and maximize rotation. x Pull slowly, 5 – 10 ft/minute, adjust as dictated by hole conditions x Monitor well for any signs of packing off or losses. x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay balling. x If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until parameters are restored. 11.7 TOOH and LD BHA Page 16 Milne Point Unit I-40 SB Producer Drilling Procedure 12.0 Run 9-5/8” Surface Casing 12.1 RU and pull wearbushing. 12.2 RU Weatherford 9-5/8” casing running equipment (CRT & Tongs) x Ensure 9-5/8” TXP x DS50 XO on rig floor and M/U to FOSV. x Use BOL 2000 thread compound. Dope pin end only w/ paint brush. x RU of CRT if hole conditions require. x RU a fill up tool to fill casing while running if the CRT is not used. x Ensure all casing has been drifted to 8.750” on the location prior to running. x Top 2000’ of casing from surface 47# drift 8.525” min x Be sure to count the total # of joints on the location before running. x Keep hole covered while RU casing tools. x Record OD’s, ID’s, lengths, and SN’s of all components with vendor & model info. 12.3 PU shoe joint, visually verify no debris inside joint. 12.4 Continue MU & thread locking 120’ shoe track assembly consisting of: 9-5/8” Float Shoe 1 joint – 9-5/8” TXP, 2 Centralizers 10’ from each end w/ stop rings 1 joint – 9-5/8” TXP, 1 Centralizer mid joint w/ stop ring 9-5/8” Float Collar with Stage Cementer Bypass Baffle ‘Top Hat’ 1 joint – 9-5/8” TXP, 1 Centralizer mid joint with stop ring 9-5/8” HES Baffle Adaptor x Ensure bypass baffle is correctly installed on top of float collar. x Ensure proper operation of float equipment while picking up. x Ensure to record SN’s of all float equipment and stage tool components. This end up. Bypass Baffle 2440' Page 17 Milne Point Unit I-40 SB Producer Drilling Procedure 12.5 Float equipment and stage tool equipment drawings: Page 18 Milne Point Unit I-40 SB Producer Drilling Procedure 12.6 Continue running 9-5/8” surface casing x Fill casing while running using fill up line on rig floor. x Use BOL 2000 thread compound. Dope pin end only with paint brush. x Centralization: Verify depth of lowest Ugnu water sand for isolation with Geologist x Utilize a collar clamp until weight is sufficient to keep slips set properly. x Break circulation prior to reaching the base of the permafrost if casing run indicates poor hole conditions. x Any packing off while running casing should be treated as a major problem. It is preferable to POH with casing and condition hole than to risk not getting cement returns to surface. 12.7 Install the Halliburton Type H ES-II Stage tool so that it is positioned at least 100’ TVD below the permafrost (~ 2,500’ MD). x Install centralizers over couplings on 5 joints below and 5 joints above stage tool. x Do not place tongs on ES cementer, this can cause damaged to the tool. x Ensure tool is pinned with 6 opening shear pins. This will allow the tool to open at 3,300 psi. 9-5/8” 40# L-80 TXP Make Up Torques: Casing OD Minimum Optimum Maximum 9-5/8” 18,860 ft-lbs 20,960 ft-lbs 23,060 ft-lbs 9-5/8” 47# L-80 TXP MUT: Casing OD Minimum Optimum Maximum 9-5/8” 21,440 ft-lbs 2,3820 ft-lbs 26,200 ft-lbs Depth Interval Centralization Shoe – 1000’ Above Shoe 1/joints 1000’ above Shoe – 2000’ above Shoe (Top of Ugnu) 1/ 2 joints SFD 10/26/2020 Prognosis on p. 45 indicates base permafrost at 2180' MD. Page 19 Milne Point Unit I-40 SB Producer Drilling Procedure Page 20 Milne Point Unit I-40 SB Producer Drilling Procedure 12.8 Continue running 9-5/8” surface casing x Fill casing while running using fill up line on rig floor. x Use BOL 2000 thread compound. Dope pin end only with paint brush. x Centralization: x 1 centralizer every 2 joints to base of conductor 12.9 The last ~2000’ of 9-5/8” will be 47#, from 2000’ to Surface x Ensure drifted to 8.525” min 2440' Page 21 Milne Point Unit I-40 SB Producer Drilling Procedure 12.10 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 12.11 Slow in and out of slips. 12.12 PU landing joint and MU to casing string. Position the casing shoe ±10’ from TD. Strap the landing joint prior to the casing job and mark the joint at (1) ft intervals to use as a reference when getting the casing on depth. 12.13 Lower casing to setting depth. Confirm measurements. 12.14 Have slips staged in cellar, along with necessary equipment for the operation. 12.15 Circulate and condition mud through CRT. Reduce YP to < 20 to help ensure success of cement job. Ensure adequate amounts of cold MU water are available to achieve this. If possible reciprocate casing string while conditioning mud. Page 22 Milne Point Unit I-40 SB Producer Drilling Procedure 13.0 Cement 9-5/8” Surface Casing 13.1 Hold a pre-job safety meeting over the upcoming cement operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud & water can be delivered to the cementing unit at acceptable rates. x How to handle cement returns at surface. Ensure vac trucks are on standby and ready to assist. x Which pumps will be utilized for displacement and how fluid will be fed to displacement pump. x Ensure adequate amounts of water for mix fluid is heated and available in the water tanks. x Positions and expectations of personnel involved with the cementing operation. i. Extra hands in the pits to strap during the cement job to identify any losses x Review test reports and ensure pump times are acceptable. x Conduct visual inspection of all hard lines and connections used to route slurry to rig floor. 13.2 Document efficiency of all possible displacement pumps prior to cement job. 13.3 Flush through cement pump and treating iron from pump to rig floor to the shakers. This will help ensure any debris left in the cement pump or treating iron will not be pumped downhole. 13.4 RU cement line (if not already done so). Company Rep to witness loading of the top and bottom plugs to ensure done in correct order. 13.5 Fill surface cement lines with water and pressure test. 13.6 Pump remaining 60 bbls 10.5 ppg tuned spacer. 13.7 Drop bottom plug (flexible bypass plug) – HEC rep to witness. Mix and pump cement per below calculations for the 1st stage, confirm actual cement volumes with cementer after TD is reached. 13.8 Cement volume based on annular volume + 30% open hole excess. Job will consist of lead & tail, TOC brought to stage tool. Estimated 1st Stage Total Cement Volume: Cement Slurry Design (1st Stage Cement Job): Lead Slurry Tail Slurry Density 12.0 lb/gal 15.8 lb/gal Yield 2.35 ft3/sk 1.16 ft3/sk Mixed Water 13.92 gal/sk 4.98 gal/sk Page 23 Milne Point Unit I-40 SB Producer Drilling Procedure 13.9 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. 13.10 After pumping cement, drop top plug (Shutoff plug) and displace cement with spud mud out of mud pits, spotting water across the HEC stage cementer. x Ensure volumes pumped and volumes returned are documented and constant communication between mud pits, HEC Rep and HES Cementers during the entire job. 13.11 Ensure rig pump is used to displace cement. Displacement calculations have proven to be very accurate using 0.0625 BPS (5” liners) for the Quattro pump output. To operate the stage tool hydraulically, the plug must be bumped. 13.12 Displacement calculation: 2,000’ x 0.0732 BPF + (8,412’ – 120’ - 2,000’) x .0758 BPF = 623.5 bbls 80 bbls of tuned spacer to be left behind stage tool 13.13 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. 13.14 If plug is not bumped at calculated strokes, double check volumes and calculations. Over displace by no more than 50% of shoe track volume, ±4.5 bbls before consulting with Drilling Engineer. 13.15 If plug is not bumped, consult with Drilling Engineer. Ensure the free fall stage tool opening plug is available if needed. This is the back-up option to open the stage tool if the plugs are not bumped. 13.16 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. 13.17 Increase pressure to 3,300 psi to open circulating ports in stage collar. Slightly higher pressure may be necessary if TOC is above the stage tool. CBU and record any spacer or cement returns to surface and volume pumped to see the returns. Circulate until YP < 20 again in preparation for the 2nd stage of the cement job. 13.18 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. 2440 440 622 Page 24 Milne Point Unit I-40 SB Producer Drilling Procedure Second Stage Surface Cement Job: 13.19 Prepare for the 2nd stage as necessary. Circulate until first stage reaches sufficient compressive strength. Try to maintain flow rate through stage tool until 2nd stage is ready. Hold pre-job safety meeting. x Past wells have seen pressure increase while circulating through stage tool after reduced rate 13.20 HEC representative to witness the loading of the ES cementer closing plug in the cementing head. 13.21 Fill surface lines with water and pressure test. 13.22 Pump remaining 60 bbls of 10.5 ppg tuned spacer. 13.23 Mix and pump cement per below recipe for the 2nd stage. 13.24 Cement volume based on annular volume + open hole excess (200% for lead and 100% for tail). Job will consist of lead & tail, TOC brought to surface. However cement will continue to be pumped until clean spacer is observed at surface. Estimated 2nd Stage Total Cement Volume: Cement Slurry Design (2nd stage cement job): 13.25 Continue pumping lead until uncontaminated spacer is seen at surface, then switch to tail. 13.26 After pumping cement, drop ES Cementer closing plug and displace cement with spud mud out of mud pits. 13.27 Displacement calculation: (2,500’ – 2,000’) x 0.0758 BPF + 2,000’ x 0.0732 = 184.3 bbls mud Lead Slurry Tail Slurry System Permafrost L Density 10.7 lb/gal 15.8 lb/gal Yield 4.41 ft3/sk 1.17 ft3/sk Mixed Water 22.02 gal/sk 5.08 gal/sk 24 hour notice to AOGCC to witness. 2440'49 275 2440 * .0732 = 178.6 bbls Page 25 Milne Point Unit I-40 SB Producer Drilling Procedure 13.28 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. 13.29 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. 13.30 Land closing plug on stage collar and pressure up to 1,000 – 1,500 psi to ensure stage tool closes. Follow instructions of Halliburton personnel. Bleed off pressure and check to ensure stage tool has closed. Slips will be set as per plan to allow full annulus for returns during surface cement job. Set slips 13.31 Make initial cut on 9-5/8” final joint. LD cut joint. Make final cut on 9-5/8”. Dress off stump. Install 9-5/8” wellhead. If transition nipple is welded on, allow to cool as per schedule. Ensure to report the following on wellez: x Pre flush type, volume (bbls) & weight (ppg) x Cement slurry type, lead or tail, volume & weight x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid x Note if casing is reciprocated or rotated during the job x Calculated volume of displacement , actual displacement volume, whether plug bumped & bump pressure, do floats hold x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure x Note if pre flush or cement returns at surface & volume x Note time cement in place x Note calculated top of cement x Add any comments which would describe the success or problems during the cement job Send final “As-Run” casing tally & casing and cement report to nathan.sperry@hilcorp.com and joseph.lastufka@hilcorp.com This will be included with the EOW documentation that goes to the AOGCC. Page 26 Milne Point Unit I-40 SB Producer Drilling Procedure 14.0 ND Diverter, NU BOPE, & Test 14.1 ND the diverter T, knife gate, diverter line & NU 11” x 13-5/8” 5M casing spool. 14.2 NU 13-5/8” x 5M BOP as follows: x BOP configuration from top down: 13-5/8” x 5M annular / 13-5/8” x 5M double gate / 13- 5/8” x 5M mud cross / 13-5/8” x 5M single gate x Double gate ram should be dressed with 2-7/8” x 5” VBRs in top cavity, blind ram in bottom cavity. x Single ram can be dressed with 2-7/8” x 5” VBRs x NU bell nipple, install flowline. x Install (1) manual valve & HCR valve on kill side of mud cross. (Manual valve closest to mud cross). x Install (1) manual valve on choke side of mud cross. Install an HRC outside of the manual valve 14.3 RU MPD RCD and related equipment. 14.4 Run 5” BOP test plug. 14.5 Test BOP to 250/3,000 psi for 5/5 min. Test annular to 250/2,500 psi for 5/5 min. x Test with 3-1/2” and 5” test joint x Confirm test pressures with PTD x Ensure to monitor side outlet valves and annulus valve pressure gauges to ensure no pressure is trapped underneath test plug x Once BOPE test is complete, send a copy of the test report to town engineer and drilling tech 14.6 RD BOP test equipment 14.7 Dump and clean mud pits, send spud mud to G&I pad for injection. 14.8 Mix 8.9 ppg FloPro fluid for production hole. 14.9 Set wearbushing in wellhead. 14.10 If needed, rack back as much 5” DP in derrick as possible to be used while drilling the hole section. 14.11 Ensure 6” liners in mud pumps. 24 hour notice to AOGCC for opportunity to witness. Page 27 Milne Point Unit I-40 SB Producer Drilling Procedure 15.0 Drill 8-1/2” Hole Section 15.1 MU 8-1/2” Cleanout BHA (Milltooth Bit & 1.22° PDM). 15.2 TIH with 8-1/2” cleanout BHA to stage tool. Note depth TOC tagged on AM report. Drill out stage tool. 15.3 TIH to TOC above the baffle adapter. Note depth TOC tagged on morning report. 15.4 RU and PT casing to 2,500 psi for 30 minutes charted. Ensure to record volume / pressure (every ¼ bbl) and plot on FIT graph. AOGCC reg is 50% of burst = 5,750 / 2 = ~2,875 psi, but max test pressure on the well is 2,500 psi as per AOGCC. Document incremental volume pumped (and subsequent pressure) and volume returned. Ensure rams are used to test casing as per AOGCC Industry Guidance Bulletin 17-001. 15.5 Drill out shoe track and 20’ of new formation. 15.6 CBU and condition mud for FIT. Pump at least one high vis sweep at maximum rate to surface to clean up debris. 15.7 Conduct FIT to 12.0 ppg EMW. Chart Test. Ensure test is recorded on same chart as FIT. Document incremental volume pumped (and subsequent pressure) and volume returned. 15.8 POOH and LD Cleanout BHA. 15.9 PU 8-1/2” directional BHA. x Ensure BHA components have been inspected previously. x Drift and caliper all components before MU. Visually verify no debris inside components that cannot be drifted. x Ensure TF offset is measured accurately and entered correctly into the MWD software. x Ensure MWD is RU and operational. x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. x Drill string will be 5”, 19.5#, S-135, DS50 & NC50. x Run a ported float in the production hole section. 15.10 8-1/2” hole section mud program summary: x Density: Weighting material to be used for the hole section will be calcium carbonate. Additional calcium carbonate will be on location to weight up the active system (1) ppg above highest anticipated MW. x Solids Concentration: It is imperative that the solids concentration be kept low while drilling the production hole section. Keep the shaker screen size optimized and fluid running Casing test and FIT digital data to AOGCC. Page 28 Milne Point Unit I-40 SB Producer Drilling Procedure to near the end of the shakers. It is okay if the shakers run slightly wet to ensure we are running the finest screens possible. x Rheology: Keep viscosifier additions to an absolute minimum (N-VIS). Data suggests excessive viscosifier concentrations can decrease return permeability. Do not pump high vis sweeps, instead use tandem sweeps. Ensure 6 rpm is > 8-1/2” (hole diameter) for sufficient hole cleaning x Run the centrifuge continuously while drilling the production hole, this will help with solids removal. x Dump and dilute as necessary to keep drilled solids to an absolute minimum. x MD Totco PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, & Toolpusher office. System Type: 8.9 – 9.5 ppg FloPro drilling fluid Properties: Interval Density PV YP LSYP Total Solids MBT HPHT Hardness Production 8.9-9.5 15-25 - ALAP 15 - 30 4-6 <10% <8 <11.0 <100 System Formulation: Product- production Size Pkg ppb or (% liquids) Busan 1060 55 gal dm 0.095 FLOTROL 55 lb sx 6 CONQOR 404 WH (8.5 gal/100 bbls) 55 gal dm 0.2 FLO-VIS PLUS 25 lb sx 0.7 KCl 50 lb sx 10.7 SMB 50 lb sx 0.45 LOTORQ 55 gal dm 1.0 SAFE-CARB 10 (verify) 50 lb sx 10 SAFE-CARB 20 (verify) 50 lb sx 10 Soda Ash 50 lb sx 0.5 15.11 TIH with 8-1/2” directional assembly to bottom. 15.12 Install MPD RCD. 15.13 Displace wellbore to 8.9 ppg Flo Pro drilling fluid Page 29 Milne Point Unit I-40 SB Producer Drilling Procedure 15.14 Begin drilling 8-1/2” hole section, on-bottom staging technique: x Tag bottom and begin drilling with 100 - 120 RPMs at bit. Allow WOB to stabilize at 5-8K. x Slowly begin bringing up rpms, monitoring stick slip and BHA vibrations x If BHA begins to show excessive vibrations / whirl / stick slip, it may be necessary to PU off bottom and restart on bottom staging technique. If stick slip continues, consider adding 0.5% lubes 15.14 Drill 8-1/2” hole section to section TD per Geologist and Drilling Engineer. x Flow Rate: 350-550 GPM, target min. AV’s 200 FPM, 385 GPM x RPM: 120+ x Ensure shaker screens are set up to handle this flowrate. Ensure shakers are running slightly wet to maximize solids removal efficiency. Check for holes in screens on every connection. x Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low x Take MWD surveys every stand, can be taken more frequently if deemed necessary, ex: concretion deflection x Monitor Torque and Drag with pumps on every 5 stands x Monitor ECD, pump pressure & hookload trends for hole cleaning indication x Surveys can be taken more frequently if deemed necessary. x Good drilling and tripping practices are vital for avoidance of differential sticking. Make every effort to keep the drill string moving whenever possible and avoid stopping with the BHA across the sand for any extended period of time. x Use ADR to stay in section. Reservoir plan is to stay in NB/NC sand. x Limit maximum instantaneous ROP to < 250 FPH. The sands will drill faster than this, but when concretions are hit when drilling this fast, cutter damage can occur. x Target ROP is as fast as we can clean the hole without having to backream connections x Schrader Bluff Concretions: 5-10% of lateral x MPD will be utilized to monitor pressure build up on connections. x 8-1/2” Lateral A/C: x J-25 has a 0.097 CF. J-25 was a SB NB Producer and was abandoned as part of the I-pad redevelopment. There is no HSSE risk. x J-26 has a 0.019 CF. J-26 was a OA (J-26L2), OB (J-26L1), and NB (J-26) producer. Only the J-26 lateral has a CF <1. This lateral has been P&A’d with cement. There is no HSSE risk. x J-26PB2 has a 0.370 CF. This is an open hole PB. No risk. 15.15 Reference: Halliburton has a procedure for Schrader OH sidetracks based on lessons learned and best practices. Ensure the DD is referencing their procedure. x Patience is key! Getting kicked off too quickly might have been the cause of failed liner runs on past wells. x If a known fault is coming up, put a slight “kick-off ramp” in wellbore ahead of the fault so we have a nice place to low side. x Attempt to lowside in a fast drilling interval where the wellbore is headed up. NOTE: In Nb sand wells, it helps to pick a siltier section to help mitigate junction collapse. Page 30 Milne Point Unit I-40 SB Producer Drilling Procedure x Orient TF to low side and dig a trough with high flowrates for the first 30 feet, working string back and forth. Trough for approximately 30 minutes. x Time drill at 4 to 6 feet per hour with high flow rates. Gradually increase ROP as the openhole sidetrack is achieved. 15.16 At TD, CBU at least 4 times at 200 ft/min AV (385+ GPM) and rotation (120+ RPM). Pump tandem sweeps if needed. x Rack back a stand at each bottoms up and reciprocate a full stand in between (while circulating the BU). Keep the pipe moving while pumping. x Monitor BU for increase in cuttings, cuttings in laterals come back in waves and not a consistent stream, circulate more if necessary x If seepage losses are seen while drilling, consider reducing MW at TD to 9.0 ppg minimum 15.17 Mix and pump 40 bbl 10 ppb SAPP pill. Line up to a closed loop system and circulate three SAP pills with 50 bbl in between. Displace out SAP pills. Monitor shakers for returns of mud filter cake and calcium carbonate. Circulate the well clean. x Losses during the cleanup of the wellbore are a good indication that the mud filter cake is being removed, including an increase in the loss rate. 15.18 Displace 1.5 OH + Liner volume with viscosified brine. x Proposed brine blend (aiming for an 8 on the 6 RPM reading) - KCl: 7.1bbp for 2% NaCl: 60.9 ppg for 9.4 ppg Lotorq: 1.5% Lube 776: 1.5% Soda Ash: as needed for 9.5pH Busan 1060: 0.42 ppb Flo-Vis Plus: 1.25 ppb x Monitor well for loss rate and contact Drilling Engineer and/or Ops Engineer if further discussion needed prior to BROOH. 15.19 Monitor the returned fluids carefully while displacing to brine. After 4 (or more) BU, Perform production screen test (PST). The brine has been properly conditioned when it will pass the production screen test (x3 350 ml samples passing through the screen in the same amount of time which will indicate no plugging of the screen). Reference PST Test Procedure 15.20 BROOH with the drilling assembly to the 9-5/8” casing shoe x Circulate at full drill rate (less if losses are seen, 350 GPM). Page 31 Milne Point Unit I-40 SB Producer Drilling Procedure x Rotate at maximum rpm that can be sustained. x Pulling speed 5 – 10 min/stand (slip to slip time, not including connections), adjust as dictated by hole conditions. x If back reaming operations are commenced, continue back reaming to the shoe 15.21 If abnormal pressure has been observed in the lateral, utilize MPD to close on connections while BROOH. 15.22 CBU minimum two times at 9-5/8” shoe and clean casing with high vis sweeps. 15.23 Monitor well for flow / monitor for pressure build up with MPD. Increase fluid weight if necessary x Wellbore breathing has been seen on past MPU SB wells. Perform extended flow checks to determine if well is breathing, treat all flow as an influx until proven otherwise 15.24 POOH and LD BHA. 15.25 Continue to POOH and stand back BHA if possible. Rabbit DP on TOOH, ensure rabbit diameter is sufficient for future ball drops. 15.26 Only LWD open hole logs are planned for the hole section (GR + Res). There will not be any additional logging runs conducted. Page 32 Milne Point Unit I-40 SB Producer Drilling Procedure 16.0 Run 4-1/2” Screen Liner NOTE: If an open hole sidetrack was performed, drop the centralizers on the lowermost 2-3 joints and run them slick. 16.1 Confirm VBR’s have been tested on 3-1/2” and 5” test joints to 250/3,000 psi. 16.2 Well control preparedness: In the event of an influx of formation fluids while running the 4- 1/2” production screens, the following well control response procedure will be followed: x PU & MU the 5” safety joint (with 4-1/2” crossover installed on bottom, TIW valve in open position on top, 4-1/2” handling joint above TIW). This joint shall be fully MU and available prior to running the first joint of 4-1/2” screen. x Slack off and position the 5” DP across the BOP, shut in ram or annular on 5” DP. Close TIW valve. x Proceed with well kill operations. 16.3 RU 4-1/2” screen running equipment. x Ensure 4-1/2” x NC-50 crossover is on rig floor and MU to FOSV. x Ensure all casing has been drifted on the deck prior to running. x Be sure to count the total # of joints on the deck before running. x Keep hole covered while RU casing tools. x Record OD’s, ID’s, lengths, SN’s of all components w/ vendor & model info. 16.4 Run 4-1/2” screen production liner – Reference screen handling and running procedure. x Use Best O Life 2000 AG thread compound. Dope pin end only with paint brush. Wipe off excess. Thread compound will plug the screens. x Utilize a collar clamp until weight is sufficient to keep slips set properly. x Run packoff and float shoe on bottom. x 4-1/2” Screens should auto –fill, top off with completion brine if needed x Swell packers will not be required on this completion unless the well is drilled out of zone x If needed, install swell packers as per the lower completion tally. x Remove protective packaging on swell packers just prior to picking up x Do not place tongs or slips on the packer element 4-1/2”, 13.5 #, L-80, Hydril 625 Torque OD Minimum Optimum Operating Torque 4-1/2” 8,000 ft-lbs 9,600 ft-lbs 12,800 ft-lbs Page 33 Milne Point Unit I-40 SB Producer Drilling Procedure 16.6. Ensure to run enough liner to provide for approx 150’ overlap inside 9-5/8” casing. Ensure hanger/packer will not be set in a 9-5/8” connection. x AOGCC regulations require a minimum 100’ overlap between the inner and outer strings as per 20 AAC 25.030(d)(6). Do not place liner hanger/packer across 9-5/8” connection. Page 34 Milne Point Unit I-40 SB Producer Drilling Procedure 16.7. Before picking up Baker SLZXP liner hanger / packer assembly, count the # of joints on the pipe deck to make sure it coincides with the pipe tally. 16.8. MU Baker SLZXP liner top packer to 4-1/2” liner. 16.9. Inner string may or may not be run, depending on out of zone excursion and condition of lateral. Have 2-3/8” inner string available if needed. 16.10. Note: PU, SO, ROT and torque of liner. Run liner in the hole one stand and pump through liner hanger to ensure a clear flow path exists. 16.11. RIH with liner on ALL 5” HWDP no faster than 30 ft/min – this is to prevent buckling the liner and drill string and weight transfer to get liner to bottom with minimal rotation. Watch displacement carefully and avoid surging the hole or buckling the liner. Slow down running speed if necessary. x Ensure 5” HWDP has been drifted x There is no inner string planned to be run, as opposed to previous wells. The DP should auto fill. Monitor FL and if filling is required due to losses/surging. 16.12. Slow in and out of slips. Ensure accurate slack off data is gathered during RIH. Record shoe depth + SO depth every stand. Record torque value if it becomes necessary to rotate the string to bottom. 16.13. Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10, & 20 RPM. 16.14. If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensure shoe enters correct hole. 16.15. TIH deeper than planned setting depth. Last motion of the liner should be up to ensure it is set in tension. 16.16. Rig up to pump down the work string with the rig pumps. 16.17. Break circulation. Begin circulating at ~1 BPM and monitor pump pressures. Do not exceed 1,600 psi while circulating. Pusher tool is set at 2,100 psi with 5% shear screws but it should be discussed before exceeding 1,600 psi. Note all losses. Confirm all pressures with Baker. 16.18. Prior to setting the hanger and packer, double check all pipe tallies and record amount of drill pipe left on location. Ensure all numbers coincide with proper setting depth of liner hanger. 16.19. Shut down pumps. Drop setting ball (ball seat now located in HRDE setting tool and not at the WIV) down the workstring and pump slowly (1-2 BPM). Slow pump before the ball seats. Do not allow ball to slam into ball seat. Page 35 Milne Point Unit I-40 SB Producer Drilling Procedure 16.20. Continue pressuring up to 2,700 psi to set the SLZXP liner hanger/packer. Hold for 5 minutes. Slack off 20K lbs on the SLZXP liner hanger/packer to ensure the HRDE setting tool is in compression for release from the SLZXP liner hanger/packer. Continue pressuring up 4,500 psi to release the HRDE running tool. 16.21. Bleed DP pressure to 0 psi. Pick up to expose rotating dog sub and set down 50K without pulling sleeve packoff. Pick back up without pulling sleeve packoff, begin rotating at 10-20 RPM and set down 50K again. 16.22. PU to neutral weight, close BOP and test annulus to 1,500 psi for 10 minutes charted. 16.23. Bleed off pressure and open BOPE. Pickup to verify that the HRD setting tool has released. If packer did not test, rotating dog sub can be used to set packer. If running tool cannot be hydraulically released, apply LH torque to mechanically release the setting tool. 16.24. PU pulling running tool free of the packer and displace with at max rate to wash the liner top. Pump sweeps as needed. 16.25. POOH. LD and inspect running tools. If setting of liner hanger/packer proceeded as planned, LD DP on the TOOH. Note: Once running tool is LD, swap to the completion AFE. 16.26. MU 3-1/2” wash tool and RIH with remaining DP out of derrick to liner top. 16.27. Wash through liner top at max rate and circulate hole clean. Pump sweeps around. Displace well to clean filtered brine after no solids are returned. 16.28. POOH and LD remaining 5” HWDP Page 36 Milne Point Unit I-40 SB Producer Drilling Procedure 17.0 Run 7-5/8” Tieback 17.1 RU and pull wear bushing. Get an accurate measurement of RKB to tubing hanger load shoulder to be used for tie-back space out calculation. 17.2 Close blinds. Install 7-5/8” FBR’s. Test with 7-5/8” test joint to 250/3,000 psi. Open blinds/drain stack. Monitor the well at the annulus valve. 17.3 RU 7-5/8” casing handling equipment. x Ensure XO to DP made up to FOSV and ready on rig floor. x Rig up computer torque monitoring service. x String should stay full while running, RU fill up line and check as appropriate. 17.4 PU 7-5/8” hanger and make a dummy run. 17.5 PU 7-5/8” tieback seal assembly and set in rotary table. Ensure seal assembly has (4) 1” holes above the first seal. These holes will be used to spot diesel freeze protect in the 9-5/8” x 7-5/8” annulus. 17.6 M/U first joint of 7-5/8” to seal assembly. 17.6 Run 7-5/8”, 29.7#, L-80, H521 tieback to position seal assembly two joints above tieback sleeve. Record up & down weights. 7-5/8” 29.7# H521 MU Torque OD Minimum Optimum Maximum Yield Torque 7-5/8” 8,100 10,400 14,700 53,000 Page 37 Milne Point Unit I-40 SB Producer Drilling Procedure 17.7 MU 7-5/8” to DP crossover. 17.8 MU stand of DP to string, and MU top drive. 17.9 Break circulation at 1 BPM and begin lowering string. 17.10 Note seal assembly entering tieback sleeve with a pressure increase, stop pumping and bleed off pressure, leave standpipe bleed off valve open. Page 38 Milne Point Unit I-40 SB Producer Drilling Procedure 17.11 Continue lowering string and land out on no-go. Set down 5 – 10K and mark the pipe as “NO- GO DEPTH”. 17.12 PU string & remove unnecessary 7-5/8” joints. 17.13 Space out with pups as needed to leave the no-go 1ft above fully no-go position when the casing hanger is landed. Ensure one full joint is below the casing hanger. 17.14 PU and MU the 7-5/8” casing hanger with landing joint. 17.15 Ensure circulation is possible through 7-5/8” string. 17.16 RU and circulation corrosion inhibited brine in the 9-5/8” x 7-5/8” annulus. 17.17 With seals stabbed into the tieback sleeve, spot diesel freeze protection from ~2,500’ TVD to surface in 9-5/8” x 7-5/8” annulus by reverse circulating through the holes in the seal assembly. Ensure annular pressure are limited to prevent collapse of the 7-5/8” casing (verify collapse pressure of the 7-5/8” tieback assembly). 17.18 SO and land hanger. Confirm the hanger has seated properly in the wellhead. Make note of actual weight on the hanger in the morning report. 17.19 Back out landing joint. MU packoff running tool and install packoff on bottom of landing joint. Set tubing hanger packoff and RILDS. PT void to 3,000 psi for 10 minutes. 17.20 R/D casing running tools. 17.21 PT 9-5/8” x 7-5/8” annulus to 1,000 psi for 30 minutes charted. Page 39 Milne Point Unit I-40 SB Producer Drilling Procedure 18.0 Run ESP Upper Completion 18.1 RU spooler with ESP power cable and heat trace. 18.2 Verify the ESP components as per Centrilift. Verify that the length of the motor lead flat cable will place the splice between the discharge head and the 10’ handling pup collar. A Centrilift rep shall be on the rig floor at all times during the running of the ESP. 18.3 Makeup new ESP assembly with new motor lead extension, seal section and motor. 18.4 Run the 3-1/2” ESP Completion as noted below. The completion includes two 3/8” capillary tube from surface to the centralizer on the motor. The capillary tube will be secured to the tubing with Cannon clamps. Function test the capillary tube every ~2,000’ by pumping ~2 gallons of hydraulic oil through the check valves. Record the pressure at each testing point 18.5 M/U ESP assy and RIH to setting depth. Confirm tally with Operations Engineer i. Ensure appropriate well control crossovers on rig floor and ready. ii. Monitor displacement from wellbore while RIH. x Centrilift ESP Assembly with bottom of assembly @ predetermined depth x 10’ 3-1/2” 9.3#, L-80 Pup Joint x 1 joint 3-1/2” 9.3#, L-80 EUE 8rd tubing x 3-1/2” “XN” nipple (2.313” packing bore / 2.205” No-Go ID) x 3 joints 3-1/2” 9.3#, L-80 EUE 8rd tubing x 10’ 3-1/2” 9.3#, L-80 Pup Joint x GLM 3-1/2” x 1” GLM w/ dummy installed x 10’ 3-1/2” 9.3#, L-80 Pup Joint x 3-1/2” 9.3#, L-80 EUE 8rd tubing x 10’ 3-1/2” 9.3#, L-80 Pup Joint x GLM 3-1/2” x 1” w/ SO @ ~140’ MD x 10’ 3-1/2” 9.3#, L-80 Pup Joint x 3 joints 3-1/2” 9.3#, L-80 EUE 8rd tubing x Tubing Hanger o Check the conductivity of electric cable every 2,000’ and every new splice while running in hole. o Use Cannon clamps on every joint to secure the capillary tube. o The make-up torque values for 3-1/2” L-80 9.3# EUE 8rd tubing are: Page 40 Milne Point Unit I-40 SB Producer Drilling Procedure Casing OD Minimum Optimum Maximum Operating Torque 3.5” 2,350 ft-lbs 3,130 ft-lbs 3,910 ft-lbs 18.6 Fill tubing while splicing cable, mid-cable splices and tubing hanger splices. After tubing is full, break circulation by pumping 10 bbls down the tubing to clear any debris. 18.7 Record PU and SO weights before landing hanger. Note PU and SO weights on tally along with band/clamp summary. 18.8 MU tubing hanger and landing joint. Splice ESP power cable and terminate control lines. Test cable. Install a brass-shipping cap on the ESP penetrator. 18.9 Land tubing with extreme care to minimize damaging the ESP penetrator, pigtail and alignment pin. 18.10 RILDS and test hanger. LD landing joint. 18.11 Install BPV and N/D BOP. 18.12 N/U tree / adapter and tree. Test tubing hanger void to 500 psi low / 5000 psi high. Terminate the cap strings. 18.13 Circulate diesel freeze protection down 3-1/2” x 7-5/8” annulus (Volume should equal capacity of tubing to 2500’ + tubing annulus to 2500’). Connect IA to tree and allow diesel freeze protect to “U-tube” into position. Note – this may be done post-rig. 18.14 Pull BPV. Set TWC. Test tree to 250 psi low / 5000 psi high. Pull TWC. Set BPV. 18.15 Prepare to hand over well to production. Ensure necessary forms filled out and well handed over with valve alignment as per operations personnel. 18.16 RDMO Doyon 14 Page 41 Milne Point Unit I-40 SB Producer Drilling Procedure 19.0 Doyon 14 Diverter Schematic Page 42 Milne Point Unit I-40 SB Producer Drilling Procedure 20.0 Doyon 14 BOP Schematic 2-7/8” x 5” VBR 2-7/8” x 5” VBR Page 43 Milne Point Unit I-40 SB Producer Drilling Procedure 21.0 Wellhead Schematic Page 44 Milne Point Unit I-40 SB Producer Drilling Procedure 22.0 Days Vs Depth Page 45 Milne Point Unit I-40 SB Producer Drilling Procedure 23.0 Formation Tops & Information I-pad Data Sheet Formation Description Page 46 Milne Point Unit I-40 SB Producer Drilling Procedure 24.0 Anticipated Drilling Hazards 12-1/4” Hole Section: Lost Circulation Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Gas Hydrates Gas hyrates have not been seen on Moose pad. However, be prepared for them. Remember that hydrate gas behave differently from a gas sand. Additional fluid density will not prevent influx of gas hydrates, but can help control the breakout at surface. Once a gas hydrate has been disturbed the gas will come out of the hole. Drill through the hydrate section as quickly as possible while minimizing gas belching. Minimize circulation time while drilling through the hydrate zone. Excessive circulation will accelerate formation thawing which can increase the amount of hydrates released into the wellbore. Keep the mud circulation temperature as cold as possible. Weigh mud with both a pressurized and non-pressurized mud scale. The non-pressurized scale will reflect the actual mud cut weight. Add 1.0 – 2.0 ppb Lecithin to the system to help thin the mud and release the gas. Isolate/dump contaminated fluid to remove hydrates from the system. Hole Cleaning: Maintain rheology of mud system. Sweep hole with high viscosity sweeps as necessary. Optimize solids control equipment to maintain density, sand content, and reduce the waste stream. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to avoid washing out a particular section of the hole. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Anti-Collison: Take directional surveys every stand, take additional surveys if necessary. Continuously monitor proximity to offset wellbores and record any close approaches on AM report. x There are no wells with a clearance factor <1.0 in the surface interval Wellbore stability (Permafrost, running sands and gravel, conductor broaching): Washouts in the permafrost can be severe if the string is left circulating across it for extended periods of time. Keep mud as cool as possible by taking on cold water and diluting often. High TOH and RIH speeds can aggravate fragile shale/coal formations due to the pressure variations between surge and swab. Bring the pumps on slowly after connections. Monitor conductor for any signs of broaching. Maintain mud parameters and increase MW to combat running sands and gravel formations. SFD 10/26/2020 Page 47 Milne Point Unit I-40 SB Producer Drilling Procedure H2S: Treat every hole section as though it has the potential for H2S. 1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Page 48 Milne Point Unit I-40 SB Producer Drilling Procedure 8-1/2” Hole Section: Hole Cleaning: Maintain rheology of mud system. Sweep hole with low-vis water sweeps. Ensure shakers are set up with appropriate screens to maximize solids removal efficiency. Run centrifuge continuously. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Maintain circulation rate of > 300 gpm Lost Circulation: Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Faulting: There is at least (3) faults 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 re- plan the wellbore. H2S: Treat every hole section as though it has the potential for H2S. I-pad does not have a history of high H2S. I-04A had a sample measure at 36 ppm in 2012 which was the highest sample measurement recorded for any I-pad well. 1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Abnormal Pressures and Temperatures: Reservoir pressures are expected to be normal. Utilize MPD to mitigate any abnormal pressure seen. g at least (3) faults that will be crossed w p Reservoir pressures are expected to be normal. Page 49 Milne Point Unit I-40 SB Producer Drilling Procedure Anti-Collision Take directional surveys every stand, take additional surveys if necessary. Continuously monitor drilling parameters for signs of magnetic interference with another well. Reference A/C report in directional plan. Well Specific: x J-25 has a 0.097 CF. J-25 was a SB NB Producer and was abandoned as part of the I-pad redevelopment. There is no HSSE risk. x J-26 has a 0.019 CF. J-26 was a OA (J-26L2), OB (J-26L1), and NB (J-26) producer. Only the J-26 lateral has a CF <1. This lateral has been P&A’d with cement. There is no HSSE risk. x J-26PB2 has a 0.370 CF. This is an open hole PB. No risk. Page 50 Milne Point Unit I-40 SB Producer Drilling Procedure 25.0 Doyon 14 Layout Page 51 Milne Point Unit I-40 SB Producer Drilling Procedure 26.0 FIT Procedure Formation Integrity Test (FIT) and Leak-Off Test (LOT) Procedures Procedure for FIT: 1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe). 2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe. 3. Close the blowout preventer (ram or annular). 4. Pump down the drill stem at 1/4 to 1/2 bpm. 5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe. 6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes. Record time vs. pressure in 1-minute intervals. 7. Bleed the pressure off and record the fluid volume recovered. The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick tolerance in case well control measures are required. Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid; at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure monitored as with an FIT. Ensure that casing test and subsequent FIT tests are recorded on the same chart. Document incremental volume pumped and returned during test. Page 52 Milne Point Unit I-40 SB Producer Drilling Procedure 27.0 Doyon 14 Choke Manifold Schematic Page 53 Milne Point Unit I-40 SB Producer Drilling Procedure 28.0 Casing Design Page 54 Milne Point Unit I-40 SB Producer Drilling Procedure 29.0 8-1/2” Hole Section MASP Page 55 Milne Point Unit I-40 SB Producer Drilling Procedure 30.0 Spider Plot (NAD 27) (Governmental Sections) Page 56 Milne Point Unit I-40 SB Producer Drilling Procedure 31.0 Surface Plat (As Staked) (NAD 27) Page 57 Milne Point Unit I-40 SB Producer Drilling Procedure 32.0 Schrader Bluff Nb Sand Offset MW vs TVD Chart SDF 10/26/2020 MD (ft) This well 19 October, 2020 Plan: MPU I-40 wp11 Milne Point M Pt I Pad Plan: MPU I-40 MPU I-40 075015002250300037504500True Vertical Depth (1500 usft/in)-1500 -750 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750 10500 11250 12000 12750 13500Vertical Section at 15.00° (1500 usft/in)MPI-Seven Pines wp08 HeelMPI-Seven Pines wp02 CP1MPI-Seven Pines wp10 ToeMPI-Seven Pines wp02 CP29 5/8" x 12 1/4"4 1/2" x 8 1/2"500100015002000250030003500400045005000550065007000750080008500 9000 9500 100 00 105 00 11 0 0 0 11 5 00 12000 12 500 13000 13 500 14 000 1450 0 15000 1550 0 1600 0 165 00 17000 17500 18000 1850 0 1885 6MPU I-40 wp11Start Dir 3º/100' : 280' MD, 280'TVDStart Dir 4º/100' : 550' MD, 549.1'TVDEnd Dir : 2236.36' MD, 1815.81' TVDStart Dir 4º/100' : 4047.64' MD, 2464.92'TVDEnd Dir : 4187.13' MD, 2512.54' TVDStart Dir 4º/100' : 5689.57' MD, 2999.21'TVDEndDir :7077.46' MD, 3488.83'TVDSTARTESPTANGENTENDESPTANGENTStartDir4.5º/100':7375.46'MD, 3585.85'TVDEndDir :8092.29' MD, 3752.56'TVDStartDir4.5º/100':8106.14'MD, 3754.32'TVDEndDir :8187.78' MD, 3763.78'TVDStartDir2º/100':8412.78'MD,3787.3'TVDEnd Dir :8699.11' MD,3802.97' TVDStartDir2º/100':10890.68'MD, 3813.58'TVDEnd Dir: 11710.87'MD,3823.48'TVDStartDir2º/100':14736.64'MD, 3866.38'TVDEndDir : 14799.08' MD, 3867.65'TVDTotal Depth:18855.66'MD,3982.3'TVDHilcorp Alaska, LLCCalculation Method:Minimum CurvatureError System:ISCWSAScan Method: Closest Approach 3DError Surface: Ellipsoid SeparationWarning Method: Error RatioWELL DETAILS: Plan: MPU I-4033.60+N/-S +E/-WNorthingEastingLatittudeLongitude0.000.00 6009456.070551419.680 70° 26' 11.708 N 149° 34' 50.758 WSURVEY PROGRAMDate: 2020-07-06T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool33.70 900.00 MPU I-40 wp11 (MPU I-40) 3_Gyro-GC_Csg900.00 8412.78 MPU I-40 wp11 (MPU I-40) 3_MWD+IFR2+MS+Sag8412.78 18855.66 MPU I-40 wp11 (MPU I-40) 3_MWD+IFR2+MS+SagFORMATION TOP DETAILSNo formation data is availableREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU I-40, True NorthVertical (TVD) Reference:MPU I-40 Doyon 14 As-built RKB @ 67.30usftMeasured Depth Reference:MPU I-40 Doyon 14 As-built RKB @ 67.30usftCalculation Method:Minimum CurvatureProject:Milne PointSite:M Pt I PadWell:Plan: MPU I-40Wellbore:MPU I-40Design:MPU I-40 wp11CASING DETAILSTVD TVDSS MD SizeName3787.30 3720.00 8412.78 9-5/8 9 5/8" x 12 1/4"3982.30 3915.00 18855.66 4-1/2 4 1/2" x 8 1/2"SECTION DETAILSSec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation1 33.70 0.00 0.00 33.70 0.00 0.00 0.00 0.00 0.002 280.00 0.00 0.00 280.00 0.00 0.00 0.00 0.00 0.00 Start Dir 3º/100' : 280' MD, 280'TVD3 550.00 8.10 210.00 549.10 -16.50 -9.53 3.00 210.00 -18.40 Start Dir 4º/100' : 550' MD, 549.1'TVD4 950.00 23.09 233.77 933.58 -87.74 -87.41 4.00 35.00 -107.375 2236.36 69.00 270.50 1815.81 -242.13 -950.12 4.00 45.55 -479.79 End Dir : 2236.36' MD, 1815.81' TVD6 4047.64 69.00 270.50 2464.92 -227.37 -2641.03 0.00 0.00 -903.17 Start Dir 4º/100' : 4047.64' MD, 2464.92'TVD7 4187.13 71.10 276.00 2512.54 -219.90 -2771.87 4.00 68.85 -929.82 End Dir : 4187.13' MD, 2512.54' TVD8 5689.57 71.10 276.00 2999.21 -71.32 -4185.52 0.00 0.00 -1152.18 Start Dir 4º/100' : 5689.57' MD, 2999.21'TVD9 7077.46 71.00 335.00 3488.83 649.25 -5196.08 4.00 100.50 -717.72 End Dir : 7077.46' MD, 3488.83' TVD10 7375.46 71.00 335.00 3585.85 904.61 -5315.16 0.00 0.00 -501.87 Start Dir 4.5º/100' : 7375.46' MD, 3585.85'TVD11 8092.29 82.69 5.96 3752.56 1583.36 -5424.39 4.50 72.93 125.47 End Dir : 8092.29' MD, 3752.56' TVD12 8106.14 82.69 5.96 3754.32 1597.02 -5422.96 0.00 0.00 139.04 Start Dir 4.5º/100' : 8106.14' MD, 3754.32'TVD13 8187.78 84.00 2.50 3763.78 1677.88 -5416.99 4.50 -69.36 218.69 End Dir : 8187.78' MD, 3763.78' TVD14 8412.78 84.00 2.50 3787.30 1901.44 -5407.22 0.00 0.00 437.15 MPI-Seven Pines wp08 Heel Start Dir 2º/100' : 8412.78' MD, 3787.3'TVD15 8699.11 89.72 2.29 3802.97 2186.97 -5395.29 2.00 -2.13 716.04 End Dir : 8699.11' MD, 3802.97' TVD16 10890.68 89.72 2.29 3813.58 4376.76 -5307.83 0.00 0.00 2853.86 Start Dir 2º/100' : 10890.68' MD, 3813.58'TVD17 11277.26 89.18 10.00 3817.29 4760.81 -5266.49 2.00 94.06 3235.52 MPI-Seven Pines wp02 CP118 11710.87 89.19 18.67 3823.48 5180.48 -5159.24 2.00 90.01 3668.65 End Dir : 11710.87' MD, 3823.48' TVD19 14736.64 89.19 18.67 3866.38 8046.68 -4190.58 0.00 0.00 6687.90 Start Dir 2º/100' : 14736.64' MD, 3866.38'TVD20 14785.10 88.66 17.86 3867.29 8092.69 -4175.39 2.00 -122.99 6736.27 MPI-Seven Pines wp02 CP221 14799.08 88.38 17.86 3867.65 8105.99 -4171.11 2.00 -179.82 6750.22 End Dir : 14799.08' MD, 3867.65' TVD22 18855.66 88.38 17.86 3982.30 11965.56 -2927.54 0.00 0.00 10800.14 MPI-Seven Pines wp10 Toe Total Depth : 18855.66' MD, 3982.3' TVD -750 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750 10500 11250 12000 South(-)/North(+) (1500 usft/in)-7500 -6750 -6000 -5250 -4500 -3750 -3000 -2250 -1500 -750 0 750 1500 2250 West(-)/East(+) (1500 usft/in) MPI-Seven Pines wp02 CP2 MPI-Seven Pines wp10 Toe MPI-Seven Pines wp02 CP1 MPI-Seven Pines wp08 Heel 9 5/8" x 12 1/4" 4 1/2" x 8 1/2" 250 1 0 0 015 0017502000225025002750300032503 5 0 0 3750 3982 MPU I-40 wp11 Start Dir 3º/100' : 280' MD, 280'TVD Start Dir 4º/100' : 550' MD, 549.1'TVD End Dir : 2236.36' MD, 1815.81' TVD Start Dir 4º/100' : 4047.64' MD, 2464.92'TVD End Dir : 4187.13' MD, 2512.54' TVD Start Dir 4º/100' : 5689.57' MD, 2999.21'TVD End Dir : 7077.46' MD, 3488.83' TVD END ESP TANGENT Start Dir 4.5º/100' : 7375.46' MD, 3585.85'TVD End Dir : 8092.29' MD, 3752.56' TVD Start Dir 4.5º/100' : 8106.14' MD, 3754.32'TVD End Dir : 8187.78' MD, 3763.78' TVD Start Dir 2º/100' : 8412.78' MD, 3787.3'TVD End Dir : 8699.11' MD, 3802.97' TVD Start Dir 2º/100' : 10890.68' MD, 3813.58'TVD End Dir : 11710.87' MD, 3823.48' TVD Start Dir 2º/100' : 14736.64' MD, 3866.38'TVD End Dir : 14799.08' MD, 3867.65' TVD Total Depth : 18855.66' MD, 3982.3' TVD CASING DETAILS TVD TVDSS MD Size Name 3787.30 3720.00 8412.78 9-5/8 9 5/8" x 12 1/4" 3982.30 3915.00 18855.66 4-1/2 4 1/2" x 8 1/2" Project: Milne Point Site: M Pt I Pad Well: Plan: MPU I-40 Wellbore: MPU I-40 Plan: MPU I-40 wp11 WELL DETAILS: Plan: MPU I-40 33.60 +N/-S +E/-W Northing Easting Latittude Longitude 0.00 0.00 6009456.070 551419.680 70° 26' 11.708 N 149° 34' 50.758 W REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Plan: MPU I-40, True North Vertical (TVD) Reference:MPU I-40 Doyon 14 As-built RKB @ 67.30usft Measured Depth Reference:MPU I-40 Doyon 14 As-built RKB @ 67.30usft Calculation Method:Minimum Curvature Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt I Pad Halliburton Standard Proposal Report Well: Wellbore: Plan: MPU I-40 MPU I-40 Survey Calculation Method:Minimum Curvature MPU I-40 Doyon 14 As-built RKB @ 67.30usft Design:MPU I-40 wp11 Database:NORTH US + CANADA MD Reference:MPU I-40 Doyon 14 As-built RKB @ 67.30usft North Reference: Well Plan: MPU I-40 True Map System: Geo Datum: Project Map Zone: System Datum:US State Plane 1927 (Exact solution) NAD 1927 (NADCON CONUS) Milne Point, ACT, MILNE POINT Alaska Zone 04 Mean Sea Level Using Well Reference Point Using geodetic scale factor Site Position: From: Site Latitude: Longitude: Position Uncertainty: Northing: Easting: Grid Convergence: M Pt I Pad, TR-13-10 usft Map usft usft °0.39Slot Radius:"0 6,008,388.010 550,245.830 0.00 70° 26' 1.282 N 149° 35' 25.422 W Well Well Position Longitude: Latitude: Easting: Northing: usft +E/-W +N/-S Position Uncertainty usft usft usftGround Level: Plan: MPU I-40 usft usft 0.00 0.00 6,009,456.070 551,419.680 33.60Wellhead Elevation:33.60 usft0.50 70° 26' 11.708 N 149° 34' 50.758 W Wellbore Declination (°) Field Strength (nT) Sample Date Dip Angle (°) MPU I-40 Model NameMagnetics BGGM2020 9/6/2020 15.86 80.83 57,367.53619380 Phase:Version: Audit Notes: Design MPU I-40 wp11 PLAN Vertical Section: Depth From (TVD) (usft) +N/-S (usft) Direction (°) +E/-W (usft) Tie On Depth:33.70 15.000.000.0033.70 10/19/2020 2:03:54PM COMPASS 5000.15 Build 91E Page 2 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt I Pad Halliburton Standard Proposal Report Well: Wellbore: Plan: MPU I-40 MPU I-40 Survey Calculation Method:Minimum Curvature MPU I-40 Doyon 14 As-built RKB @ 67.30usft Design:MPU I-40 wp11 Database:NORTH US + CANADA MD Reference:MPU I-40 Doyon 14 As-built RKB @ 67.30usft North Reference: Well Plan: MPU I-40 True Inclination (°) Azimuth (°) +E/-W (usft) Tool Face (°) +N/-S (usft) Measured Depth (usft) Vertical Depth (usft) Dogleg Rate (°/100usft) Build Rate (°/100usft) Turn Rate (°/100usft) Plan Sections TVD System usft 0.000.000.000.000.000.0033.700.000.0033.70 -33.60 0.000.000.000.000.000.00280.000.000.00280.00 212.70 210.000.003.003.00-9.53-16.50549.10210.008.10550.00 481.80 35.005.943.754.00-87.41-87.74933.58233.7723.09950.00 866.28 45.552.863.574.00-950.12-242.131,815.81270.5069.002,236.36 1,748.51 0.000.000.000.00-2,641.03-227.372,464.92270.5069.004,047.64 2,397.62 68.853.941.514.00-2,771.87-219.902,512.54276.0071.104,187.13 2,445.24 0.000.000.000.00-4,185.52-71.322,999.21276.0071.105,689.57 2,931.91 100.504.25-0.014.00-5,196.08649.253,488.83335.0071.007,077.46 3,421.53 0.000.000.000.00-5,315.16904.613,585.85335.0071.007,375.46 3,518.55 72.934.321.634.50-5,424.391,583.363,752.565.9682.698,092.29 3,685.26 0.000.000.000.00-5,422.961,597.023,754.325.9682.698,106.14 3,687.02 -69.36-4.231.604.50-5,416.991,677.883,763.782.5084.008,187.78 3,696.48 0.000.000.000.00-5,407.221,901.443,787.302.5084.008,412.78 3,720.00 -2.13-0.072.002.00-5,395.292,186.973,802.972.2989.728,699.11 3,735.67 0.000.000.000.00-5,307.834,376.763,813.582.2989.7210,890.68 3,746.28 94.062.00-0.142.00-5,266.494,760.813,817.2910.0089.1811,277.26 3,749.99 90.012.000.002.00-5,159.245,180.483,823.4818.6789.1911,710.87 3,756.18 0.000.000.000.00-4,190.588,046.683,866.3818.6789.1914,736.64 3,799.08 -122.99-1.68-1.092.00-4,175.398,092.693,867.2917.8688.6614,785.10 3,799.99 -179.82-0.01-2.002.00-4,171.118,105.993,867.6517.8688.3814,799.08 3,800.35 0.000.000.000.00-2,927.5411,965.563,982.3017.8688.3818,855.66 3,915.00 10/19/2020 2:03:54PM COMPASS 5000.15 Build 91E Page 3 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt I Pad Halliburton Standard Proposal Report Well: Wellbore: Plan: MPU I-40 MPU I-40 Survey Calculation Method:Minimum Curvature MPU I-40 Doyon 14 As-built RKB @ 67.30usft Design:MPU I-40 wp11 Database:NORTH US + CANADA MD Reference:MPU I-40 Doyon 14 As-built RKB @ 67.30usft North Reference: Well Plan: MPU I-40 True Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Map Northing (usft) Map Easting (usft) +N/-S (usft) Planned Survey Vertical Depth (usft) TVDss usft DLS -33.60 Vert Section 33.70 0.00 33.70 0.00 0.000.00 551,419.6806,009,456.070-33.60 0.000 0.00 100.00 0.00 100.00 0.00 0.000.00 551,419.6806,009,456.07032.70 0.000 0.00 200.00 0.00 200.00 0.00 0.000.00 551,419.6806,009,456.070132.70 0.000 0.00 280.00 0.00 280.00 0.00 0.000.00 551,419.6806,009,456.070212.70 0.000 0.00 Start Dir 3º/100' : 280' MD, 280'TVD 300.00 0.60 300.00 -0.09 -0.05210.00 551,419.6286,009,455.979232.70 3.000 -0.10 400.00 3.60 399.92 -3.26 -1.88210.00 551,417.8186,009,452.794332.62 3.000 -3.64 500.00 6.60 499.51 -10.96 -6.33210.00 551,413.4286,009,445.066432.21 3.000 -12.23 550.00 8.10 549.10 -16.50 -9.53210.00 551,410.2686,009,439.506481.80 3.000 -18.40 Start Dir 4º/100' : 550' MD, 549.1'TVD 600.00 9.81 598.49 -22.96 -13.84216.75 551,406.0046,009,433.014531.19 4.000 -25.76 700.00 13.46 696.43 -38.03 -27.15224.93 551,392.7916,009,417.856629.13 4.000 -43.76 800.00 17.27 792.84 -55.89 -46.68229.61 551,373.3876,009,399.860725.54 4.000 -66.07 900.00 21.14 887.26 -76.47 -72.33232.63 551,347.8886,009,379.115819.96 4.000 -92.58 950.00 23.09 933.58 -87.74 -87.41233.77 551,332.8906,009,367.742866.28 4.000 -107.37 1,000.00 24.53 979.32 -99.16 -104.04237.21 551,316.3326,009,356.209912.02 4.000 -122.71 1,100.00 27.61 1,069.15 -120.92 -142.17243.03 551,278.3636,009,334.1881,001.85 4.000 -153.59 1,200.00 30.89 1,156.40 -141.16 -186.59247.74 551,234.0816,009,313.6461,089.10 4.000 -184.64 1,300.00 34.30 1,240.65 -159.77 -237.11251.62 551,183.7016,009,294.6831,173.35 4.000 -215.70 1,400.00 37.82 1,321.48 -176.67 -293.46254.86 551,127.4686,009,277.3931,254.18 4.000 -246.61 1,500.00 41.41 1,398.51 -191.78 -355.39257.62 551,065.6586,009,261.8601,331.21 4.000 -277.23 1,600.00 45.06 1,471.36 -205.02 -422.57260.01 550,998.5706,009,248.1581,404.06 4.000 -307.41 1,700.00 48.76 1,539.67 -216.33 -494.70262.11 550,926.5336,009,236.3561,472.37 4.000 -337.00 1,800.00 52.48 1,603.11 -225.65 -571.41263.99 550,849.8956,009,226.5091,535.81 4.000 -365.85 1,900.00 56.24 1,661.37 -232.93 -652.33265.68 550,769.0326,009,218.6671,594.07 4.000 -393.83 2,000.00 60.01 1,714.17 -238.15 -737.07267.24 550,684.3376,009,212.8681,646.87 4.000 -420.80 2,100.00 63.81 1,761.24 -241.27 -825.22268.68 550,596.2236,009,209.1391,693.94 4.000 -446.63 2,200.00 67.61 1,802.37 -242.28 -916.34270.03 550,505.1186,009,207.4991,735.07 4.000 -471.19 2,236.36 69.00 1,815.81 -242.13 -950.13270.50 550,471.3386,009,207.4231,748.51 4.000 -479.79 End Dir : 2236.36' MD, 1815.81' TVD 2,300.00 69.00 1,838.62 -241.61 -1,009.54270.50 550,411.9316,009,207.5321,771.32 0.000 -494.66 2,400.00 69.00 1,874.46 -240.79 -1,102.89270.50 550,318.5826,009,207.7031,807.16 0.000 -518.04 2,500.00 69.00 1,910.29 -239.98 -1,196.25270.50 550,225.2336,009,207.8741,842.99 0.000 -541.41 2,600.00 69.00 1,946.13 -239.16 -1,289.60270.50 550,131.8846,009,208.0451,878.83 0.000 -564.79 2,700.00 69.00 1,981.97 -238.35 -1,382.95270.50 550,038.5356,009,208.2161,914.67 0.000 -588.16 2,800.00 69.00 2,017.80 -237.53 -1,476.31270.50 549,945.1876,009,208.3871,950.50 0.000 -611.54 2,900.00 69.00 2,053.64 -236.72 -1,569.66270.50 549,851.8386,009,208.5581,986.34 0.000 -634.91 3,000.00 69.00 2,089.48 -235.90 -1,663.02270.50 549,758.4896,009,208.7292,022.18 0.000 -658.29 3,100.00 69.00 2,125.31 -235.09 -1,756.37270.50 549,665.1406,009,208.9002,058.01 0.000 -681.66 3,200.00 69.00 2,161.15 -234.28 -1,849.73270.50 549,571.7916,009,209.0712,093.85 0.000 -705.04 3,300.00 69.00 2,196.99 -233.46 -1,943.08270.50 549,478.4426,009,209.2422,129.69 0.000 -728.41 3,400.00 69.00 2,232.82 -232.65 -2,036.44270.50 549,385.0946,009,209.4132,165.52 0.000 -751.79 3,500.00 69.00 2,268.66 -231.83 -2,129.79270.50 549,291.7456,009,209.5842,201.36 0.000 -775.16 3,600.00 69.00 2,304.50 -231.02 -2,223.15270.50 549,198.3966,009,209.7552,237.20 0.000 -798.54 3,700.00 69.00 2,340.33 -230.20 -2,316.50270.50 549,105.0476,009,209.9262,273.03 0.000 -821.91 10/19/2020 2:03:54PM COMPASS 5000.15 Build 91E Page 4 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt I Pad Halliburton Standard Proposal Report Well: Wellbore: Plan: MPU I-40 MPU I-40 Survey Calculation Method:Minimum Curvature MPU I-40 Doyon 14 As-built RKB @ 67.30usft Design:MPU I-40 wp11 Database:NORTH US + CANADA MD Reference:MPU I-40 Doyon 14 As-built RKB @ 67.30usft North Reference: Well Plan: MPU I-40 True Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Map Northing (usft) Map Easting (usft) +N/-S (usft) Planned Survey Vertical Depth (usft) TVDss usft DLS 2,308.87 Vert Section 3,800.00 69.00 2,376.17 -229.39 -2,409.85270.50 549,011.6986,009,210.0972,308.87 0.000 -845.29 3,900.00 69.00 2,412.01 -228.57 -2,503.21270.50 548,918.3496,009,210.2682,344.71 0.000 -868.66 4,000.00 69.00 2,447.84 -227.76 -2,596.56270.50 548,825.0016,009,210.4392,380.54 0.000 -892.04 4,047.64 69.00 2,464.92 -227.37 -2,641.04270.50 548,780.5296,009,210.5202,397.62 0.000 -903.17 Start Dir 4º/100' : 4047.64' MD, 2464.92'TVD 4,100.00 69.77 2,483.36 -226.05 -2,690.02272.58 548,731.5416,009,211.5022,416.06 4.000 -914.58 4,187.13 71.10 2,512.54 -219.90 -2,771.87276.00 548,649.6576,009,217.0892,445.24 4.000 -929.82 End Dir : 4187.13' MD, 2512.54' TVD 4,200.00 71.10 2,516.71 -218.63 -2,783.98276.00 548,637.5406,009,218.2782,449.41 0.000 -931.72 4,300.00 71.10 2,549.10 -208.74 -2,878.07276.00 548,543.3936,009,227.5182,481.80 0.000 -946.52 4,400.00 71.10 2,581.49 -198.85 -2,972.16276.00 548,449.2466,009,236.7572,514.19 0.000 -961.32 4,500.00 71.10 2,613.88 -188.96 -3,066.25276.00 548,355.0996,009,245.9972,546.58 0.000 -976.12 4,600.00 71.10 2,646.28 -179.07 -3,160.34276.00 548,260.9526,009,255.2362,578.98 0.000 -990.92 4,700.00 71.10 2,678.67 -169.18 -3,254.43276.00 548,166.8056,009,264.4752,611.37 0.000 -1,005.72 4,800.00 71.10 2,711.06 -159.29 -3,348.53276.00 548,072.6586,009,273.7152,643.76 0.000 -1,020.52 4,900.00 71.10 2,743.45 -149.40 -3,442.62276.00 547,978.5106,009,282.9542,676.15 0.000 -1,035.32 5,000.00 71.10 2,775.84 -139.51 -3,536.71276.00 547,884.3636,009,292.1942,708.54 0.000 -1,050.12 5,100.00 71.10 2,808.24 -129.62 -3,630.80276.00 547,790.2166,009,301.4332,740.94 0.000 -1,064.92 5,200.00 71.10 2,840.63 -119.73 -3,724.89276.00 547,696.0696,009,310.6732,773.33 0.000 -1,079.72 5,300.00 71.10 2,873.02 -109.84 -3,818.98276.00 547,601.9226,009,319.9122,805.72 0.000 -1,094.52 5,400.00 71.10 2,905.41 -99.95 -3,913.07276.00 547,507.7756,009,329.1512,838.11 0.000 -1,109.32 5,500.00 71.10 2,937.80 -90.06 -4,007.16276.00 547,413.6286,009,338.3912,870.50 0.000 -1,124.12 5,600.00 71.10 2,970.19 -80.18 -4,101.25276.00 547,319.4816,009,347.6302,902.89 0.000 -1,138.92 5,689.57 71.10 2,999.21 -71.32 -4,185.52276.00 547,235.1536,009,355.9062,931.91 0.000 -1,152.18 Start Dir 4º/100' : 5689.57' MD, 2999.21'TVD 5,700.00 71.02 3,002.59 -70.25 -4,195.33276.43 547,225.3406,009,356.9072,935.29 4.002 -1,153.69 5,800.00 70.35 3,035.68 -56.27 -4,288.64280.61 547,131.9486,009,370.2382,968.38 4.000 -1,164.34 5,900.00 69.78 3,069.79 -35.59 -4,380.31284.82 547,040.1406,009,390.2873,002.49 4.000 -1,168.09 6,000.00 69.30 3,104.76 -8.30 -4,469.92289.06 546,950.3626,009,416.9563,037.46 4.000 -1,164.92 6,100.00 68.93 3,140.41 25.47 -4,557.00293.33 546,863.0516,009,450.1163,073.11 4.000 -1,154.84 6,200.00 68.67 3,176.59 65.54 -4,641.15297.61 546,778.6346,009,489.6053,109.29 4.000 -1,137.91 6,300.00 68.52 3,213.10 111.73 -4,721.96301.90 546,697.5216,009,535.2303,145.80 4.000 -1,114.21 6,400.00 68.47 3,249.78 163.80 -4,799.02306.20 546,620.1076,009,586.7693,182.48 4.000 -1,083.86 6,500.00 68.54 3,286.44 221.52 -4,871.97310.50 546,546.7706,009,643.9713,219.14 4.000 -1,046.99 6,600.00 68.71 3,322.90 284.58 -4,940.45314.79 546,477.8676,009,706.5583,255.60 4.000 -1,003.80 6,700.00 69.00 3,358.99 352.70 -5,004.12319.07 546,413.7346,009,774.2243,291.69 4.000 -954.48 6,800.00 69.39 3,394.53 425.52 -5,062.68323.33 546,354.6836,009,846.6403,327.23 4.000 -899.29 6,900.00 69.88 3,429.35 502.71 -5,115.83327.56 546,301.0016,009,923.4533,362.05 4.000 -838.49 7,000.00 70.47 3,463.27 583.89 -5,163.33331.77 546,252.9516,010,004.2893,395.97 4.000 -772.38 7,077.46 71.00 3,488.83 649.25 -5,196.08335.00 546,219.7516,010,069.4203,421.53 4.000 -717.72 End Dir : 7077.46' MD, 3488.83' TVD 7,078.00 71.00 3,489.01 649.71 -5,196.30335.00 546,219.5326,010,069.8813,421.71 0.000 -717.33 START ESP TANGENT 7,100.00 71.00 3,496.17 668.57 -5,205.09335.00 546,210.6126,010,088.6703,428.87 0.000 -701.39 7,200.00 71.00 3,528.73 754.26 -5,245.05335.00 546,170.0676,010,174.0783,461.43 0.000 -628.96 10/19/2020 2:03:54PM COMPASS 5000.15 Build 91E Page 5 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt I Pad Halliburton Standard Proposal Report Well: Wellbore: Plan: MPU I-40 MPU I-40 Survey Calculation Method:Minimum Curvature MPU I-40 Doyon 14 As-built RKB @ 67.30usft Design:MPU I-40 wp11 Database:NORTH US + CANADA MD Reference:MPU I-40 Doyon 14 As-built RKB @ 67.30usft North Reference: Well Plan: MPU I-40 True Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Map Northing (usft) Map Easting (usft) +N/-S (usft) Planned Survey Vertical Depth (usft) TVDss usft DLS 3,493.99 Vert Section 7,300.00 71.00 3,561.29 839.95 -5,285.01335.00 546,129.5226,010,259.4853,493.99 0.000 -556.53 7,374.00 71.00 3,585.38 903.36 -5,314.58335.00 546,099.5186,010,322.6863,518.08 0.000 -502.93 END ESP TANGENT 7,375.46 71.00 3,585.85 904.62 -5,315.16335.00 546,098.9266,010,323.9333,518.55 0.000 -501.87 Start Dir 4.5º/100' : 7375.46' MD, 3585.85'TVD 7,400.00 71.33 3,593.78 925.76 -5,324.77336.11 546,089.1726,010,345.0083,526.48 4.500 -483.94 7,500.00 72.73 3,624.65 1,014.15 -5,359.82340.61 546,053.5186,010,433.1503,557.35 4.500 -407.63 7,600.00 74.23 3,653.10 1,105.72 -5,388.11345.04 546,024.6006,010,524.5143,585.80 4.500 -326.50 7,700.00 75.81 3,678.96 1,199.90 -5,409.46349.40 546,002.5986,010,618.5373,611.66 4.500 -241.05 7,800.00 77.48 3,702.06 1,296.12 -5,423.75353.69 545,987.6466,010,714.6393,634.76 4.500 -151.82 7,900.00 79.21 3,722.27 1,393.77 -5,430.89357.93 545,979.8376,010,812.2283,654.97 4.500 -59.34 8,000.00 81.00 3,739.46 1,492.25 -5,430.832.13 545,979.2196,010,910.7013,672.16 4.500 35.80 8,092.29 82.69 3,752.56 1,583.36 -5,424.395.96 545,985.0346,011,001.8433,685.26 4.500 125.47 End Dir : 8092.29' MD, 3752.56' TVD 8,106.14 82.69 3,754.32 1,597.02 -5,422.965.96 545,986.3656,011,015.5153,687.02 0.000 139.04 Start Dir 4.5º/100' : 8106.14' MD, 3754.32'TVD 8,187.78 84.00 3,763.78 1,677.88 -5,416.992.50 545,991.7826,011,096.4013,696.48 4.500 218.69 End Dir : 8187.78' MD, 3763.78' TVD 8,200.00 84.00 3,765.06 1,690.02 -5,416.462.50 545,992.2286,011,108.5453,697.76 0.001 230.55 8,300.00 84.00 3,775.51 1,789.38 -5,412.122.50 545,995.8816,011,207.9213,708.21 0.000 327.65 8,400.00 84.00 3,785.96 1,888.74 -5,407.782.50 545,999.5336,011,307.2963,718.66 0.000 424.74 8,412.78 84.00 3,787.30 1,901.43 -5,407.222.50 546,000.0006,011,319.9963,720.00 0.000 437.15 Start Dir 2º/100' : 8412.78' MD, 3787.3'TVD - 9 5/8" x 12 1/4" 8,500.00 85.74 3,795.10 1,988.22 -5,403.482.43 546,003.1416,011,406.7983,727.80 2.000 521.95 8,600.00 87.74 3,800.78 2,087.97 -5,399.312.36 546,006.6296,011,506.5613,733.48 2.000 619.38 8,699.11 89.72 3,802.97 2,186.97 -5,395.292.29 546,009.9646,011,605.5763,735.67 2.000 716.04 End Dir : 8699.11' MD, 3802.97' TVD 8,800.00 89.72 3,803.46 2,287.77 -5,391.262.29 546,013.2946,011,706.4003,736.16 0.000 814.46 8,900.00 89.72 3,803.94 2,387.69 -5,387.272.29 546,016.5966,011,806.3353,736.64 0.000 912.01 9,000.00 89.72 3,804.43 2,487.61 -5,383.282.29 546,019.8976,011,906.2693,737.13 0.000 1,009.55 9,100.00 89.72 3,804.91 2,587.53 -5,379.292.29 546,023.1996,012,006.2043,737.61 0.000 1,107.10 9,200.00 89.72 3,805.40 2,687.45 -5,375.302.29 546,026.5006,012,106.1393,738.10 0.000 1,204.65 9,300.00 89.72 3,805.88 2,787.37 -5,371.312.29 546,029.8016,012,206.0733,738.58 0.000 1,302.19 9,400.00 89.72 3,806.36 2,887.29 -5,367.322.29 546,033.1036,012,306.0083,739.06 0.000 1,399.74 9,500.00 89.72 3,806.85 2,987.21 -5,363.332.29 546,036.4046,012,405.9423,739.55 0.000 1,497.29 9,600.00 89.72 3,807.33 3,087.13 -5,359.342.29 546,039.7056,012,505.8773,740.03 0.000 1,594.84 9,700.00 89.72 3,807.82 3,187.05 -5,355.352.29 546,043.0076,012,605.8123,740.52 0.000 1,692.38 9,800.00 89.72 3,808.30 3,286.97 -5,351.362.29 546,046.3086,012,705.7463,741.00 0.000 1,789.93 9,900.00 89.72 3,808.79 3,386.88 -5,347.372.29 546,049.6106,012,805.6813,741.49 0.000 1,887.48 10,000.00 89.72 3,809.27 3,486.80 -5,343.382.29 546,052.9116,012,905.6163,741.97 0.000 1,985.03 10,100.00 89.72 3,809.75 3,586.72 -5,339.392.29 546,056.2126,013,005.5503,742.45 0.000 2,082.57 10,200.00 89.72 3,810.24 3,686.64 -5,335.392.29 546,059.5146,013,105.4853,742.94 0.000 2,180.12 10,300.00 89.72 3,810.72 3,786.56 -5,331.402.29 546,062.8156,013,205.4193,743.42 0.000 2,277.67 10,400.00 89.72 3,811.21 3,886.48 -5,327.412.29 546,066.1166,013,305.3543,743.91 0.000 2,375.22 10,500.00 89.72 3,811.69 3,986.40 -5,323.422.29 546,069.4186,013,405.2893,744.39 0.000 2,472.76 10/19/2020 2:03:54PM COMPASS 5000.15 Build 91E Page 6 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt I Pad Halliburton Standard Proposal Report Well: Wellbore: Plan: MPU I-40 MPU I-40 Survey Calculation Method:Minimum Curvature MPU I-40 Doyon 14 As-built RKB @ 67.30usft Design:MPU I-40 wp11 Database:NORTH US + CANADA MD Reference:MPU I-40 Doyon 14 As-built RKB @ 67.30usft North Reference: Well Plan: MPU I-40 True Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Map Northing (usft) Map Easting (usft) +N/-S (usft) Planned Survey Vertical Depth (usft) TVDss usft DLS 3,744.87 Vert Section 10,600.00 89.72 3,812.17 4,086.32 -5,319.432.29 546,072.7196,013,505.2233,744.87 0.000 2,570.31 10,700.00 89.72 3,812.66 4,186.24 -5,315.442.29 546,076.0206,013,605.1583,745.36 0.000 2,667.86 10,800.00 89.72 3,813.14 4,286.16 -5,311.452.29 546,079.3226,013,705.0923,745.84 0.000 2,765.41 10,890.68 89.72 3,813.58 4,376.76 -5,307.832.29 546,082.3166,013,795.7133,746.28 0.000 2,853.86 Start Dir 2º/100' : 10890.68' MD, 3813.58'TVD 10,900.00 89.71 3,813.63 4,386.08 -5,307.442.47 546,082.6386,013,805.0263,746.33 2.000 2,862.96 11,000.00 89.57 3,814.26 4,485.89 -5,301.394.47 546,088.0036,013,904.8663,746.96 2.000 2,960.93 11,100.00 89.43 3,815.14 4,585.42 -5,291.876.46 546,096.8396,014,004.4563,747.84 2.000 3,059.54 11,200.00 89.29 3,816.26 4,684.56 -5,278.888.46 546,109.1386,014,103.6753,748.96 2.000 3,158.67 11,277.26 89.18 3,817.29 4,760.81 -5,266.4910.00 546,121.0006,014,180.0003,749.99 2.000 3,235.52 11,300.00 89.18 3,817.62 4,783.19 -5,262.4610.45 546,124.8836,014,202.4043,750.32 2.000 3,258.18 11,400.00 89.18 3,819.05 4,881.18 -5,242.6012.46 546,144.0626,014,300.5223,751.75 2.000 3,357.98 11,500.00 89.18 3,820.48 4,978.42 -5,219.3414.46 546,166.6536,014,397.9113,753.18 2.000 3,457.93 11,600.00 89.18 3,821.90 5,074.79 -5,192.6916.46 546,192.6316,014,494.4523,754.60 2.000 3,557.91 11,700.00 89.19 3,823.32 5,170.17 -5,162.7018.46 546,221.9626,014,590.0283,756.02 2.000 3,657.80 11,710.87 89.19 3,823.48 5,180.48 -5,159.2418.67 546,225.3506,014,600.3543,756.18 2.000 3,668.65 End Dir : 11710.87' MD, 3823.48' TVD 11,800.00 89.19 3,824.74 5,264.91 -5,130.7018.67 546,253.2996,014,684.9703,757.44 0.000 3,757.59 11,900.00 89.19 3,826.16 5,359.63 -5,098.6918.67 546,284.6556,014,779.9063,758.86 0.000 3,857.37 12,000.00 89.19 3,827.58 5,454.36 -5,066.6818.67 546,316.0126,014,874.8423,760.28 0.000 3,957.15 12,100.00 89.19 3,829.00 5,549.09 -5,034.6618.67 546,347.3696,014,969.7773,761.70 0.000 4,056.94 12,200.00 89.19 3,830.41 5,643.81 -5,002.6518.67 546,378.7266,015,064.7133,763.11 0.000 4,156.72 12,300.00 89.19 3,831.83 5,738.54 -4,970.6418.67 546,410.0826,015,159.6493,764.53 0.000 4,256.51 12,400.00 89.19 3,833.25 5,833.27 -4,938.6218.67 546,441.4396,015,254.5853,765.95 0.000 4,356.29 12,500.00 89.19 3,834.67 5,927.99 -4,906.6118.67 546,472.7966,015,349.5213,767.37 0.000 4,456.08 12,600.00 89.19 3,836.09 6,022.72 -4,874.6018.67 546,504.1536,015,444.4563,768.79 0.000 4,555.86 12,700.00 89.19 3,837.50 6,117.45 -4,842.5818.67 546,535.5096,015,539.3923,770.20 0.000 4,655.65 12,800.00 89.19 3,838.92 6,212.17 -4,810.5718.67 546,566.8666,015,634.3283,771.62 0.000 4,755.43 12,900.00 89.19 3,840.34 6,306.90 -4,778.5518.67 546,598.2236,015,729.2643,773.04 0.000 4,855.22 13,000.00 89.19 3,841.76 6,401.63 -4,746.5418.67 546,629.5796,015,824.2003,774.46 0.000 4,955.00 13,100.00 89.19 3,843.17 6,496.35 -4,714.5318.67 546,660.9366,015,919.1353,775.87 0.000 5,054.78 13,200.00 89.19 3,844.59 6,591.08 -4,682.5118.67 546,692.2936,016,014.0713,777.29 0.000 5,154.57 13,300.00 89.19 3,846.01 6,685.81 -4,650.5018.67 546,723.6506,016,109.0073,778.71 0.000 5,254.35 13,400.00 89.19 3,847.43 6,780.53 -4,618.4918.67 546,755.0066,016,203.9433,780.13 0.000 5,354.14 13,500.00 89.19 3,848.85 6,875.26 -4,586.4718.67 546,786.3636,016,298.8793,781.55 0.000 5,453.92 13,600.00 89.19 3,850.26 6,969.98 -4,554.4618.67 546,817.7206,016,393.8143,782.96 0.000 5,553.71 13,700.00 89.19 3,851.68 7,064.71 -4,522.4518.67 546,849.0776,016,488.7503,784.38 0.000 5,653.49 13,800.00 89.19 3,853.10 7,159.44 -4,490.4318.67 546,880.4336,016,583.6863,785.80 0.000 5,753.28 13,900.00 89.19 3,854.52 7,254.16 -4,458.4218.67 546,911.7906,016,678.6223,787.22 0.000 5,853.06 14,000.00 89.19 3,855.94 7,348.89 -4,426.4018.67 546,943.1476,016,773.5583,788.64 0.000 5,952.85 14,100.00 89.19 3,857.35 7,443.62 -4,394.3918.67 546,974.5046,016,868.4933,790.05 0.000 6,052.63 14,200.00 89.19 3,858.77 7,538.34 -4,362.3818.67 547,005.8606,016,963.4293,791.47 0.000 6,152.41 14,300.00 89.19 3,860.19 7,633.07 -4,330.3618.67 547,037.2176,017,058.3653,792.89 0.000 6,252.20 14,400.00 89.19 3,861.61 7,727.80 -4,298.3518.67 547,068.5746,017,153.3013,794.31 0.000 6,351.98 14,500.00 89.19 3,863.02 7,822.52 -4,266.3418.67 547,099.9306,017,248.2373,795.72 0.000 6,451.77 10/19/2020 2:03:54PM COMPASS 5000.15 Build 91E Page 7 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt I Pad Halliburton Standard Proposal Report Well: Wellbore: Plan: MPU I-40 MPU I-40 Survey Calculation Method:Minimum Curvature MPU I-40 Doyon 14 As-built RKB @ 67.30usft Design:MPU I-40 wp11 Database:NORTH US + CANADA MD Reference:MPU I-40 Doyon 14 As-built RKB @ 67.30usft North Reference: Well Plan: MPU I-40 True Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Map Northing (usft) Map Easting (usft) +N/-S (usft) Planned Survey Vertical Depth (usft) TVDss usft DLS 3,797.14 Vert Section 14,600.00 89.19 3,864.44 7,917.25 -4,234.3218.67 547,131.2876,017,343.1723,797.14 0.000 6,551.55 14,700.00 89.19 3,865.86 8,011.98 -4,202.3118.67 547,162.6446,017,438.1083,798.56 0.000 6,651.34 14,736.64 89.19 3,866.38 8,046.68 -4,190.5818.67 547,174.1336,017,472.8933,799.08 0.000 6,687.90 Start Dir 2º/100' : 14736.64' MD, 3866.38'TVD 14,785.10 88.66 3,867.29 8,092.69 -4,175.3917.86 547,189.0006,017,519.0003,799.99 2.000 6,736.27 14,799.08 88.38 3,867.65 8,106.00 -4,171.1117.86 547,193.1946,017,532.3313,800.35 1.999 6,750.23 End Dir : 14799.08' MD, 3867.65' TVD 14,900.00 88.38 3,870.50 8,202.01 -4,140.1717.86 547,223.4666,017,628.5513,803.20 0.000 6,850.98 15,000.00 88.38 3,873.33 8,297.16 -4,109.5117.86 547,253.4626,017,723.8943,806.03 0.000 6,950.82 15,100.00 88.38 3,876.16 8,392.30 -4,078.8617.86 547,283.4586,017,819.2383,808.86 0.000 7,050.65 15,200.00 88.38 3,878.98 8,487.44 -4,048.2017.86 547,313.4546,017,914.5813,811.68 0.000 7,150.49 15,300.00 88.38 3,881.81 8,582.59 -4,017.5517.86 547,343.4506,018,009.9243,814.51 0.000 7,250.33 15,400.00 88.38 3,884.63 8,677.73 -3,986.8917.86 547,373.4456,018,105.2673,817.33 0.000 7,350.16 15,500.00 88.38 3,887.46 8,772.87 -3,956.2417.86 547,403.4416,018,200.6103,820.16 0.000 7,450.00 15,600.00 88.38 3,890.29 8,868.02 -3,925.5817.86 547,433.4376,018,295.9543,822.99 0.000 7,549.83 15,700.00 88.38 3,893.11 8,963.16 -3,894.9317.86 547,463.4336,018,391.2973,825.81 0.000 7,649.67 15,800.00 88.38 3,895.94 9,058.30 -3,864.2717.86 547,493.4296,018,486.6403,828.64 0.000 7,749.50 15,900.00 88.38 3,898.77 9,153.45 -3,833.6117.86 547,523.4256,018,581.9833,831.47 0.000 7,849.34 16,000.00 88.38 3,901.59 9,248.59 -3,802.9617.86 547,553.4216,018,677.3263,834.29 0.000 7,949.17 16,100.00 88.38 3,904.42 9,343.73 -3,772.3017.86 547,583.4176,018,772.6693,837.12 0.000 8,049.01 16,200.00 88.38 3,907.24 9,438.88 -3,741.6517.86 547,613.4126,018,868.0133,839.94 0.000 8,148.85 16,300.00 88.38 3,910.07 9,534.02 -3,710.9917.86 547,643.4086,018,963.3563,842.77 0.000 8,248.68 16,400.00 88.38 3,912.90 9,629.16 -3,680.3417.86 547,673.4046,019,058.6993,845.60 0.000 8,348.52 16,500.00 88.38 3,915.72 9,724.31 -3,649.6817.86 547,703.4006,019,154.0423,848.42 0.000 8,448.35 16,600.00 88.38 3,918.55 9,819.45 -3,619.0317.86 547,733.3966,019,249.3853,851.25 0.000 8,548.19 16,700.00 88.38 3,921.38 9,914.59 -3,588.3717.86 547,763.3926,019,344.7283,854.08 0.000 8,648.02 16,800.00 88.38 3,924.20 10,009.74 -3,557.7117.86 547,793.3886,019,440.0723,856.90 0.000 8,747.86 16,900.00 88.38 3,927.03 10,104.88 -3,527.0617.86 547,823.3846,019,535.4153,859.73 0.000 8,847.70 17,000.00 88.38 3,929.85 10,200.02 -3,496.4017.86 547,853.3796,019,630.7583,862.55 0.000 8,947.53 17,100.00 88.38 3,932.68 10,295.17 -3,465.7517.86 547,883.3756,019,726.1013,865.38 0.000 9,047.37 17,200.00 88.38 3,935.51 10,390.31 -3,435.0917.86 547,913.3716,019,821.4443,868.21 0.000 9,147.20 17,300.00 88.38 3,938.33 10,485.45 -3,404.4417.86 547,943.3676,019,916.7883,871.03 0.000 9,247.04 17,400.00 88.38 3,941.16 10,580.60 -3,373.7817.86 547,973.3636,020,012.1313,873.86 0.000 9,346.87 17,500.00 88.38 3,943.99 10,675.74 -3,343.1317.86 548,003.3596,020,107.4743,876.69 0.000 9,446.71 17,600.00 88.38 3,946.81 10,770.88 -3,312.4717.86 548,033.3556,020,202.8173,879.51 0.000 9,546.54 17,700.00 88.38 3,949.64 10,866.03 -3,281.8217.86 548,063.3516,020,298.1603,882.34 0.000 9,646.38 17,800.00 88.38 3,952.46 10,961.17 -3,251.1617.86 548,093.3466,020,393.5033,885.16 0.000 9,746.22 17,900.00 88.38 3,955.29 11,056.31 -3,220.5017.86 548,123.3426,020,488.8473,887.99 0.000 9,846.05 18,000.00 88.38 3,958.12 11,151.46 -3,189.8517.86 548,153.3386,020,584.1903,890.82 0.000 9,945.89 18,100.00 88.38 3,960.94 11,246.60 -3,159.1917.86 548,183.3346,020,679.5333,893.64 0.000 10,045.72 18,200.00 88.38 3,963.77 11,341.74 -3,128.5417.86 548,213.3306,020,774.8763,896.47 0.000 10,145.56 18,300.00 88.38 3,966.60 11,436.89 -3,097.8817.86 548,243.3266,020,870.2193,899.30 0.000 10,245.39 18,400.00 88.38 3,969.42 11,532.03 -3,067.2317.86 548,273.3226,020,965.5623,902.12 0.000 10,345.23 18,500.00 88.38 3,972.25 11,627.17 -3,036.5717.86 548,303.3186,021,060.9063,904.95 0.000 10,445.07 18,600.00 88.38 3,975.07 11,722.32 -3,005.9217.86 548,333.3146,021,156.2493,907.77 0.000 10,544.90 10/19/2020 2:03:54PM COMPASS 5000.15 Build 91E Page 8 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt I Pad Halliburton Standard Proposal Report Well: Wellbore: Plan: MPU I-40 MPU I-40 Survey Calculation Method:Minimum Curvature MPU I-40 Doyon 14 As-built RKB @ 67.30usft Design:MPU I-40 wp11 Database:NORTH US + CANADA MD Reference:MPU I-40 Doyon 14 As-built RKB @ 67.30usft North Reference: Well Plan: MPU I-40 True Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Map Northing (usft) Map Easting (usft) +N/-S (usft) Planned Survey Vertical Depth (usft) TVDss usft DLS 3,910.60 Vert Section 18,700.00 88.38 3,977.90 11,817.46 -2,975.2617.86 548,363.3096,021,251.5923,910.60 0.000 10,644.74 18,800.00 88.38 3,980.73 11,912.60 -2,944.6017.86 548,393.3056,021,346.9353,913.43 0.000 10,744.57 18,855.66 88.38 3,982.30 11,965.56 -2,927.5417.86 548,410.0006,021,400.0003,915.00 0.000 10,800.14 Total Depth : 18855.66' MD, 3982.3' TVD Target Name - hit/miss target - Shape TVD (usft) Northing (usft) Easting (usft) +N/-S (usft) +E/-W (usft) Tar gets Dip Angle (°) Dip Dir. (°) MPI-Seven Pines wp10 Toe 3,982.30 6,021,400.000 548,410.00011,965.56 -2,927.540.00 0.00 -plan hits target center - Point MPI-Seven Pines wp02 CP1 3,817.29 6,014,180.000 546,121.0004,760.81 -5,266.490.00 0.00 -plan hits target center - Point MPI-Seven Pines wp08 Heel 3,787.30 6,011,320.000 546,000.0001,901.44 -5,407.220.00 0.00 -plan hits target center - Circle (radius 30.00) MPI-Seven Pines wp02 CP2 3,867.29 6,017,519.000 547,189.0008,092.69 -4,175.390.00 0.00 -plan hits target center - Point Vertical Depth (usft) Measured Depth (usft) Casing Diameter (") Hole Diameter (")Name Casing Points 4 1/2" x 8 1/2"3,982.3018,855.66 4-1/2 8-1/2 9 5/8" x 12 1/4"3,787.308,412.78 9-5/8 12-1/4 10/19/2020 2:03:54PM COMPASS 5000.15 Build 91E Page 9 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt I Pad Halliburton Standard Proposal Report Well: Wellbore: Plan: MPU I-40 MPU I-40 Survey Calculation Method:Minimum Curvature MPU I-40 Doyon 14 As-built RKB @ 67.30usft Design:MPU I-40 wp11 Database:NORTH US + CANADA MD Reference:MPU I-40 Doyon 14 As-built RKB @ 67.30usft North Reference: Well Plan: MPU I-40 True Measured Depth (usft) Vertical Depth (usft) +E/-W (usft) +N/-S (usft) Local Coordinates Comment Plan Annotations 280.00 280.00 0.00 0.00 Start Dir 3º/100' : 280' MD, 280'TVD 550.00 549.10 -16.50 -9.53 Start Dir 4º/100' : 550' MD, 549.1'TVD 2,236.36 1,815.81 -242.13 -950.13 End Dir : 2236.36' MD, 1815.81' TVD 4,047.64 2,464.92 -227.37 -2,641.04 Start Dir 4º/100' : 4047.64' MD, 2464.92'TVD 4,187.13 2,512.54 -219.90 -2,771.87 End Dir : 4187.13' MD, 2512.54' TVD 5,689.57 2,999.21 -71.32 -4,185.52 Start Dir 4º/100' : 5689.57' MD, 2999.21'TVD 7,077.46 3,488.83 649.25 -5,196.08 End Dir : 7077.46' MD, 3488.83' TVD 7,078.00 3,489.01 649.71 -5,196.30 START ESP TANGENT 7,374.00 3,585.38 903.36 -5,314.58 END ESP TANGENT 7,375.46 3,585.85 904.62 -5,315.16 Start Dir 4.5º/100' : 7375.46' MD, 3585.85'TVD 8,092.29 3,752.56 1,583.36 -5,424.39 End Dir : 8092.29' MD, 3752.56' TVD 8,106.14 3,754.32 1,597.02 -5,422.96 Start Dir 4.5º/100' : 8106.14' MD, 3754.32'TVD 8,187.78 3,763.78 1,677.88 -5,416.99 End Dir : 8187.78' MD, 3763.78' TVD 8,412.78 3,787.30 1,901.43 -5,407.22 Start Dir 2º/100' : 8412.78' MD, 3787.3'TVD 8,699.11 3,802.97 2,186.97 -5,395.29 End Dir : 8699.11' MD, 3802.97' TVD 10,890.68 3,813.58 4,376.76 -5,307.83 Start Dir 2º/100' : 10890.68' MD, 3813.58'TVD 11,710.87 3,823.48 5,180.48 -5,159.24 End Dir : 11710.87' MD, 3823.48' TVD 14,736.64 3,866.38 8,046.68 -4,190.58 Start Dir 2º/100' : 14736.64' MD, 3866.38'TVD 14,799.08 3,867.65 8,106.00 -4,171.11 End Dir : 14799.08' MD, 3867.65' TVD 18,855.66 3,982.30 11,965.56 -2,927.54 Total Depth : 18855.66' MD, 3982.3' TVD 10/19/2020 2:03:54PM COMPASS 5000.15 Build 91E Page 10 19 October, 2020Milne PointM Pt I PadPlan: MPU I-40MPU I-40MPU I-40 wp11Reference Design: M Pt I Pad - Plan: MPU I-40 - MPU I-40 - MPU I-40 wp11Closest Approach 3D Proximity Scan on Current Survey Data (North Reference)Well Coordinates: 6,009,456.07 N, 551,419.68 E (70° 26' 11.71" N, 149° 34' 50.76" W)Datum Height: MPU I-40 Doyon 14 As-built RKB @ 67.30usftScan Range: 33.70 to 8,412.78 usft. Measured Depth.Geodetic Scale Factor AppliedVersion: 5000.15 Build: 91EScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftNO GLOBAL FILTER: Using user defined selection & filtering criteriaScan Type:Scan Type:25.00 Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU I-40 - MPU I-40 wp11Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftSite NameScan Range: 33.70 to 8,412.78 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (North Reference)Reference Design: M Pt I Pad - Plan: MPU I-40 - MPU I-40 - MPU I-40 wp11MeasuredDepth(usft)Summary Based on MinimumSeparation WarningM Pt I PadMPI-02 - MPI-02 - MPI-02195.62 285.69 192.72 288.65 67.411285.69Centre Distance Pass - MPI-02 - MPI-02 - MPI-02195.69 308.70 192.62 311.63 63.710308.70Ellipse Separation Pass - MPI-02 - MPI-02 - MPI-02246.94 733.70 240.61 707.84 39.035733.70Clearance Factor Pass - MPI-03 - MPI-03 - MPI-03135.69 33.70 134.12 36.39 86.41333.70Centre Distance Pass - MPI-03 - MPI-03 - MPI-03135.72 58.70 134.08 61.06 82.78258.70Ellipse Separation Pass - MPI-03 - MPI-03 - MPI-03178.86 708.70 172.62 696.90 28.648708.70Clearance Factor Pass - MPI-04 - MPI-04 - MPI-0474.94 33.70 73.37 36.40 47.72433.70Centre Distance Pass - MPI-04 - MPI-04 - MPI-0475.69 283.70 72.81 285.99 26.247283.70Ellipse Separation Pass - MPI-04 - MPI-04 - MPI-0490.91 558.70 85.90 556.64 18.142558.70Clearance Factor Pass - MPI-04 - MPI-04A - MPI-04A74.94 33.70 73.37 36.40 47.72433.70Centre Distance Pass - MPI-04 - MPI-04A - MPI-04A75.69 283.70 72.81 285.99 26.247283.70Ellipse Separation Pass - MPI-04 - MPI-04A - MPI-04A90.91 558.70 85.90 556.64 18.142558.70Clearance Factor Pass - MPI-04 - MPI-04AL1 - MPI-04AL174.94 33.70 73.37 36.40 47.72433.70Centre Distance Pass - MPI-04 - MPI-04AL1 - MPI-04AL175.69 283.70 72.81 285.99 26.247283.70Ellipse Separation Pass - MPI-04 - MPI-04AL1 - MPI-04AL190.91 558.70 85.90 556.64 18.142558.70Clearance Factor Pass - MPI-04 - MPI-04APB1 - MPI-04APB174.94 33.70 73.37 36.40 47.72433.70Centre Distance Pass - MPI-04 - MPI-04APB1 - MPI-04APB175.69 283.70 72.81 285.99 26.247283.70Ellipse Separation Pass - MPI-04 - MPI-04APB1 - MPI-04APB190.91 558.70 85.90 556.64 18.142558.70Clearance Factor Pass - MPI-04 - MPI-04PB1 - MPI-04PB174.94 33.70 73.37 36.40 47.72433.70Centre Distance Pass - MPI-04 - MPI-04PB1 - MPI-04PB175.69 283.70 72.81 285.99 26.247283.70Ellipse Separation Pass - MPI-04 - MPI-04PB1 - MPI-04PB190.91 558.70 85.90 556.64 18.142558.70Clearance Factor Pass - MPI-05 - MPI-05 - MPI-05165.57 283.70 163.13 280.51 67.782283.70Centre Distance Pass - MPI-05 - MPI-05 - MPI-05165.65 308.70 163.06 305.58 64.102308.70Ellipse Separation Pass - MPI-05 - MPI-05 - MPI-05208.13 758.70 202.76 746.84 38.754758.70Clearance Factor Pass - MPI-06 - MPI-06 - MPI-06105.01 291.20 102.09 288.28 35.934291.20Centre Distance Pass - MPI-06 - MPI-06 - MPI-06105.22 333.70 101.98 330.78 32.490333.70Ellipse Separation Pass - MPI-06 - MPI-06 - MPI-061,493.38 4,483.70 1,406.05 4,833.60 17.1014,483.70Clearance Factor Pass - MPI-07 - MPI-07 - MPI-0745.17 190.73 43.06 187.43 21.368190.73Centre Distance Pass - 19 October, 2020-14:05COMPASSPage 2 of 8 Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU I-40 - MPU I-40 wp11Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftSite NameScan Range: 33.70 to 8,412.78 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (North Reference)Reference Design: M Pt I Pad - Plan: MPU I-40 - MPU I-40 - MPU I-40 wp11MeasuredDepth(usft)Summary Based on MinimumSeparation WarningMPI-07 - MPI-07 - MPI-0745.29 233.70 42.95 230.16 19.368233.70Ellipse Separation Pass - MPI-07 - MPI-07 - MPI-0755.40 508.70 51.44 504.25 14.001508.70Clearance Factor Pass - MPI-08 - MPI-08 - MPI-0812.15 353.80 9.23 350.59 4.163353.80Centre Distance Pass - MPI-08 - MPI-08 - MPI-0812.15 358.70 9.21 355.50 4.124358.70Ellipse Separation Pass - MPI-08 - MPI-08 - MPI-0812.73 408.70 9.49 405.47 3.928408.70Clearance Factor Pass - MPI-09 - MPI-09 - MPI-09224.82 180.02 222.39 174.97 92.596180.02Centre Distance Pass - MPI-09 - MPI-09 - MPI-09225.39 283.70 221.89 276.15 64.299283.70Ellipse Separation Pass - MPI-09 - MPI-09 - MPI-091,487.48 2,683.70 1,451.50 2,373.81 41.3372,683.70Clearance Factor Pass - MPI-10 - MPI-10 - MPI-10285.37 33.70 283.52 27.75 154.75833.70Centre Distance Pass - MPI-10 - MPI-10 - MPI-10326.51 4,633.70 279.19 5,196.70 6.8994,633.70Ellipse Separation Pass - MPI-10 - MPI-10 - MPI-10635.55 6,633.70 344.98 7,094.37 2.1876,633.70Clearance Factor Pass - MPI-11 - MPI-11 - MPI-1111.29 487.50 7.72 483.19 3.162487.50Ellipse Separation Pass - MPI-11 - MPI-11 - MPI-11267.694,433.7074.064,637.881.3834,433.70Clearance FactorPass - MPI-11 - MPI-11L1 - MPI-11L111.29 487.50 7.72 483.19 3.162487.50Ellipse Separation Pass - MPI-11 - MPI-11L1 - MPI-11L1267.694,433.7074.064,637.881.3834,433.70Clearance FactorPass - MPI-12 - MPI-12 - MPI-1235.03 544.21 30.06 539.50 7.052544.21Ellipse Separation Pass - MPI-12 - MPI-12 - MPI-12522.90 6,583.70 256.22 6,855.63 1.9616,583.70Clearance Factor Pass - MPI-12 - MPI-12L1 - MPI-12L135.03 544.21 30.06 539.50 7.052544.21Ellipse Separation Pass - MPI-12 - MPI-12L1 - MPI-12L1522.90 6,583.70 256.57 6,855.63 1.9636,583.70Clearance Factor Pass - MPI-12 - MPI-12PB1 - MPI-12PB135.03 544.21 30.06 539.50 7.052544.21Ellipse Separation Pass - MPI-12 - MPI-12PB1 - MPI-12PB1522.90 6,583.70 255.72 6,855.63 1.9576,583.70Clearance Factor Pass - MPI-13 - MPI-13 - MPI-1373.09 498.47 69.65 492.69 21.264498.47Centre Distance Pass - MPI-13 - MPI-13 - MPI-13184.114,333.702.434,508.591.0134,333.70Clearance FactorPass - MPI-14 - MPI-14 - MPI-14104.03 232.41 101.46 233.27 40.537232.41Centre Distance Pass - MPI-14 - MPI-14 - MPI-14104.49 483.70 100.07 480.32 23.592483.70Ellipse Separation Pass - MPI-14 - MPI-14 - MPI-14716.36 8,412.78 545.41 7,741.11 4.1908,412.78Clearance Factor Pass - MPI-14 - MPI-14L1 - MPI-14L1104.03 232.41 101.46 233.27 40.537232.41Centre Distance Pass - MPI-14 - MPI-14L1 - MPI-14L1104.49 483.70 100.07 480.32 23.592483.70Ellipse Separation Pass - MPI-14 - MPI-14L1 - MPI-14L1715.12 8,412.78 545.22 7,753.78 4.2098,412.78Clearance Factor Pass - MPI-14 - MPI-14L2 - MPI-14L2104.03 232.41 101.46 233.27 40.537232.41Centre Distance Pass - 19 October, 2020-14:05COMPASSPage 3 of 8 Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU I-40 - MPU I-40 wp11Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftSite NameScan Range: 33.70 to 8,412.78 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (North Reference)Reference Design: M Pt I Pad - Plan: MPU I-40 - MPU I-40 - MPU I-40 wp11MeasuredDepth(usft)Summary Based on MinimumSeparation WarningMPI-14 - MPI-14L2 - MPI-14L2104.49 483.70 100.07 480.32 23.592483.70Ellipse Separation Pass - MPI-14 - MPI-14L2 - MPI-14L2742.11 8,412.78 588.94 7,697.34 4.8458,412.78Clearance Factor Pass - MPI-14 - MPI-14L2PB1 - MPI-14L2PB1104.03 232.41 101.46 233.27 40.537232.41Centre Distance Pass - MPI-14 - MPI-14L2PB1 - MPI-14L2PB1104.49 483.70 100.07 480.32 23.592483.70Ellipse Separation Pass - MPI-14 - MPI-14L2PB1 - MPI-14L2PB1845.42 8,083.70 669.60 7,391.00 4.8088,083.70Clearance Factor Pass - MPI-14 - MPI-14L2PB2 - MPI-14L2PB2104.03 232.41 101.46 233.27 40.537232.41Centre Distance Pass - MPI-14 - MPI-14L2PB2 - MPI-14L2PB2104.49 483.70 100.07 480.32 23.592483.70Ellipse Separation Pass - MPI-14 - MPI-14L2PB2 - MPI-14L2PB2742.11 8,412.78 588.66 7,697.34 4.8368,412.78Clearance Factor Pass - MPI-14 - MPI-14PB1 - MPI-14PB1104.03 232.41 101.46 233.27 40.537232.41Centre Distance Pass - MPI-14 - MPI-14PB1 - MPI-14PB1104.49 483.70 100.07 480.32 23.592483.70Ellipse Separation Pass - MPI-14 - MPI-14PB1 - MPI-14PB1714.94 8,412.78 534.70 7,769.76 3.9678,412.78Clearance Factor Pass - MPI-14 - MPI-14PB2 - MPI-14PB2104.03 232.41 101.46 233.27 40.537232.41Centre Distance Pass - MPI-14 - MPI-14PB2 - MPI-14PB2104.49 483.70 100.07 480.32 23.592483.70Ellipse Separation Pass - MPI-14 - MPI-14PB2 - MPI-14PB2716.36 8,412.78 545.28 7,741.11 4.1878,412.78Clearance Factor Pass - MPI-17 - MPI-17 - MPI-17174.54 7,397.63 108.50 8,889.90 2.6437,397.63Centre Distance Pass - MPI-17 - MPI-17 - MPI-17317.587,683.7052.849,027.211.2007,683.70Ellipse SeparationPass - MPI-17 - MPI-17 - MPI-17337.887,708.7054.249,036.881.1917,708.70Clearance FactorPass - MPI-17 - MPI-17L1 - MPI-17L1347.97 7,466.23 278.60 8,905.45 5.0167,466.23Centre Distance Pass - MPI-17 - MPI-17L1 - MPI-17L1420.88 7,708.70 241.82 9,005.06 2.3517,708.70Ellipse Separation Pass - MPI-17 - MPI-17L1 - MPI-17L1503.45 7,833.70 264.41 9,040.64 2.1067,833.70Clearance Factor Pass - MPI-17 - MPI-17L2 - MPI-17L2307.45 7,430.25 229.15 8,871.81 3.9277,430.25Centre Distance Pass - MPI-17 - MPI-17L2 - MPI-17L2412.29 7,733.70 177.41 9,036.49 1.7557,733.70Ellipse Separation Pass - MPI-17 - MPI-17L2 - MPI-17L2483.99 7,833.70 190.60 9,072.69 1.6507,833.70Clearance Factor Pass - MPI-19 - MPI-19L1 - MPI-19L1430.54 33.70 428.69 34.30 233.48833.70Ellipse Separation Pass - MPI-19 - MPI-19L1 - MPI-19L1532.80 983.70 524.46 981.36 63.856983.70Clearance Factor Pass - MPU I-37i - MPU I-37i - MPU I-37i149.52 316.26 146.86 310.71 56.190316.26Centre Distance Pass - MPU I-37i - MPU I-37i - MPU I-37i149.55 333.70 146.81 328.28 54.612333.70Ellipse Separation Pass - MPU I-37i - MPU I-37i - MPU I-37i1,447.64 4,233.70 1,405.01 4,004.05 33.9604,233.70Clearance Factor Pass - MPU I-37i - MPU I-37PB1 - MPU I-37PB1149.52 316.26 146.86 310.71 56.190316.26Centre Distance Pass - MPU I-37i - MPU I-37PB1 - MPU I-37PB1149.55 333.70 146.81 328.28 54.612333.70Ellipse Separation Pass - 19 October, 2020-14:05COMPASSPage 4 of 8 Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU I-40 - MPU I-40 wp11Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftSite NameScan Range: 33.70 to 8,412.78 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (North Reference)Reference Design: M Pt I Pad - Plan: MPU I-40 - MPU I-40 - MPU I-40 wp11MeasuredDepth(usft)Summary Based on MinimumSeparation WarningMPU I-37i - MPU I-37PB1 - MPU I-37PB11,447.64 4,233.70 1,405.01 4,004.05 33.9574,233.70Clearance Factor Pass - MPU I-38 - MPU I-38 - MPU I-3888.44 313.40 85.82 307.23 33.755313.40Centre Distance Pass - MPU I-38 - MPU I-38 - MPU I-3888.49 333.70 85.78 327.53 32.664333.70Ellipse Separation Pass - MPU I-38 - MPU I-38 - MPU I-38222.30 2,083.70 210.71 2,208.07 19.1752,083.70Clearance Factor Pass - MPU I-38 - MPU I-38PB1 - MPU I-38PB188.44 313.40 85.82 307.23 33.755313.40Centre Distance Pass - MPU I-38 - MPU I-38PB1 - MPU I-38PB188.49 333.70 85.78 327.53 32.664333.70Ellipse Separation Pass - MPU I-38 - MPU I-38PB1 - MPU I-38PB1222.30 2,083.70 210.71 2,208.07 19.1752,083.70Clearance Factor Pass - MPU I-38 - MPU I-38PB2 - MPU I-38PB288.44 313.40 85.82 307.23 33.755313.40Centre Distance Pass - MPU I-38 - MPU I-38PB2 - MPU I-38PB288.49 333.70 85.78 327.53 32.664333.70Ellipse Separation Pass - MPU I-38 - MPU I-38PB2 - MPU I-38PB2222.30 2,083.70 210.71 2,208.07 19.1752,083.70Clearance Factor Pass - MPU I-39i - MPU I-39i - MPU I-39i28.28 350.30 25.40 343.93 9.847350.30Centre Distance Pass - MPU I-39i - MPU I-39i - MPU I-39i28.29 358.70 25.37 352.32 9.696358.70Ellipse Separation Pass - MPU I-39i - MPU I-39i - MPU I-39i698.25 4,283.70 592.65 4,199.90 6.6124,283.70Clearance Factor Pass - Plan: MPU I-22 - MPU I-22 - MPU I-22 wp03240.50 258.70 238.05 252.40 97.821258.70Centre Distance Pass - Plan: MPU I-22 - MPU I-22 - MPU I-22 wp03240.60 308.70 237.94 302.40 90.211308.70Ellipse Separation Pass - Plan: MPU I-22 - MPU I-22 - MPU I-22 wp03276.78 933.70 270.96 968.87 47.564933.70Clearance Factor Pass - Plan: MPU I-23i - MPU I-23i - MPU I-23i wp03180.77 258.70 178.31 252.40 73.526258.70Centre Distance Pass - Plan: MPU I-23i - MPU I-23i - MPU I-23i wp03180.87 308.70 178.20 302.40 67.815308.70Ellipse Separation Pass - Plan: MPU I-23i - MPU I-23i - MPU I-23i wp03963.41 2,683.70 934.14 2,816.93 32.9152,683.70Clearance Factor Pass - Plan: MPU I-24 - MPU I-24 - MPU I-24 wp02119.43 427.05 116.19 425.87 36.832427.05Centre Distance Pass - Plan: MPU I-24 - MPU I-24 - MPU I-24 wp02119.56 458.70 116.15 457.98 35.075458.70Ellipse Separation Pass - Plan: MPU I-24 - MPU I-24 - MPU I-24 wp02605.24 2,683.70 566.75 2,778.50 15.7262,683.70Clearance Factor Pass - Plan: MPU I-25i - MPU I-25i - MPU I-25i wp0426.67 481.75 23.18 474.79 7.630481.75Centre Distance Pass - Plan: MPU I-25i - MPU I-25i - MPU I-25i wp0426.67 483.70 23.17 476.71 7.608483.70Ellipse Separation Pass - Plan: MPU I-25i - MPU I-25i - MPU I-25i wp0427.01 508.70 23.37 501.22 7.427508.70Clearance Factor Pass - Plan: MPU I-26 - MPU I-26 - MPU I-26 wp0688.90 365.51 86.12 357.44 31.912365.51Centre Distance Pass - Plan: MPU I-26 - MPU I-26 - MPU I-26 wp0688.95 383.70 86.08 374.81 30.941383.70Ellipse Separation Pass - Plan: MPU I-26 - MPU I-26 - MPU I-26 wp06589.53 5,658.70 435.43 5,464.88 3.8265,658.70Clearance Factor Pass - Plan: MPU I-30i - MPU I-30i - MPU I-30i wp04208.26 583.67 204.15 595.00 50.707583.67Centre Distance Pass - Plan: MPU I-30i - MPU I-30i - MPU I-30i wp04208.35 608.70 204.09 621.69 48.864608.70Ellipse Separation Pass - Plan: MPU I-30i - MPU I-30i - MPU I-30i wp04250.55 1,783.70 235.95 1,938.51 17.1581,783.70Clearance Factor Pass - 19 October, 2020-14:05COMPASSPage 5 of 8 Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU I-40 - MPU I-40 wp11Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftSite NameScan Range: 33.70 to 8,412.78 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (North Reference)Reference Design: M Pt I Pad - Plan: MPU I-40 - MPU I-40 - MPU I-40 wp11MeasuredDepth(usft)Summary Based on MinimumSeparation WarningPlan: MPU I-31 - MPU I-31 - MPU I-31 wp0360.08 236.98 57.71 230.68 25.311236.98Centre Distance Pass - Plan: MPU I-31 - MPU I-31 - MPU I-31 wp0360.09 283.70 57.53 277.35 23.468283.70Ellipse Separation Pass - Plan: MPU I-31 - MPU I-31 - MPU I-31 wp03144.38 2,133.70 130.77 2,208.97 10.6062,133.70Clearance Factor Pass - Plan: MPU I-32i - MPU I-32i - MPU I-32i wp0547.50 804.58 42.09 791.74 8.768804.58Centre Distance Pass - Plan: MPU I-32i - MPU I-32i - MPU I-32i wp0547.51 808.70 42.06 795.74 8.726808.70Ellipse Separation Pass - Plan: MPU I-32i - MPU I-32i - MPU I-32i wp05158.78 2,333.70 128.59 2,312.30 5.2602,333.70Clearance Factor Pass - Plan: MPU I-33 - MPU I-33 - MPU I-33 wp05124.50 293.76 121.90 287.05 47.843293.76Centre Distance Pass - Plan: MPU I-33 - MPU I-33 - MPU I-33 wp05374.24 5,958.70 206.26 5,700.00 2.2285,958.70Clearance Factor Pass - Plan: MPU I-33 - MPU I-33 - MPU I-33 wp05173.33 8,412.78 110.90 7,862.77 2.7768,412.78Ellipse Separation Pass - M Pt J PadM Pt L PadSurvey tool programFrom(usft)To(usft)Survey/Plan Survey Tool33.70 900.00 MPU I-40 wp11 3_Gyro-GC_Csg900.00 8,412.78 MPU I-40 wp11 3_MWD+IFR2+MS+Sag8,412.78 18,855.66 MPU I-40 wp11 3_MWD+IFR2+MS+SagEllipse error terms are correlated across survey tool tie-on points.Separation is the actual distance between ellipsoids.Calculated ellipses incorporate surface errors.Clearance Factor = Distance Between Profiles / (Distance Between Profiles - Ellipse Separation).Distance Between centres is the straight line distance between wellbore centres.All station coordinates were calculated using the Minimum Curvature method.19 October, 2020-14:05COMPASSPage 6 of 8 0.001.002.003.004.00Separation Factor0 450 900 1350 1800 2250 2700 3150 3600 4050 4500 4950 5400 5850 6300 6750 7200 7650 8100 8550Measured Depth (900 usft/in)No-Go Zone - Stop DrillingCollision Avoidance Req.Collision Risk Procedures Req.NOERRORSWELL DETAILS:Plan: MPU I-40 NAD 1927 (NADCON CONUS)Alaska Zone 0433.60+N/-S +E/-W Northing Easting Latittude Longitude0.000.006009456.070 551419.680 70° 26' 11.708 N149° 34' 50.758 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU I-40, True NorthVertical (TVD) Reference:MPU I-40 Doyon 14 As-built RKB @ 67.30usftMeasured Depth Reference:MPU I-40 Doyon 14 As-built RKB @ 67.30usftCalculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2020-07-06T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool33.70 900.00 MPU I-40 wp11 (MPU I-40) 3_Gyro-GC_Csg900.00 8412.78 MPU I-40 wp11 (MPU I-40) 3_MWD+IFR2+MS+Sag8412.78 18855.66 MPU I-40 wp11 (MPU I-40) 3_MWD+IFR2+MS+Sag0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)0 450 900 1350 1800 2250 2700 3150 3600 4050 4500 4950 5400 5850 6300 6750 7200 7650 8100 8550Measured Depth (900 usft/in)MPI-05MPU I-25i wp04MPU I-37iMPI-03MPI-07MPU I-32i wp05MPI-04MPU I-31 wp03MPI-14MPU I-39iMPI-13MPU I-26 wp06MPI-06MPU I-38MPI-11MPI-08NO GLOBAL FILTER: Using user defined selection & filtering criteria33.70 To 18855.66Project: Milne PointSite: M Pt I PadWell: Plan: MPU I-40Wellbore: MPU I-40Plan: MPU I-40 wp11Ladder / S.F. Plots1 of 2CASING DETAILSTVD TVDSS MD Size Name3787.30 3720.00 8412.78 9-5/8 9 5/8" x 12 1/4"3982.30 3915.00 18855.66 4-1/2 4 1/2" x 8 1/2" 19 October, 2020Milne PointM Pt I PadPlan: MPU I-40MPU I-40MPU I-40 wp11Reference Design: M Pt I Pad - Plan: MPU I-40 - MPU I-40 - MPU I-40 wp11Closest Approach 3D Proximity Scan on Current Survey Data (North Reference)Well Coordinates: 6,009,456.07 N, 551,419.68 E (70° 26' 11.71" N, 149° 34' 50.76" W)Datum Height: MPU I-40 Doyon 14 As-built RKB @ 67.30usftScan Range: 8,412.78 to 18,855.66 usft. Measured Depth.Geodetic Scale Factor AppliedVersion: 5000.15 Build: 91EScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftNO GLOBAL FILTER: Using user defined selection & filtering criteriaScan Type:Scan Type:25.00 Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU I-40 - MPU I-40 wp11Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftSite NameScan Range: 8,412.78 to 18,855.66 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (North Reference)Reference Design: M Pt I Pad - Plan: MPU I-40 - MPU I-40 - MPU I-40 wp11MeasuredDepth(usft)Summary Based on MinimumSeparation WarningM Pt I PadMPI-12 - MPI-12 - MPI-121,225.43 8,412.78 901.03 7,562.67 3.7788,412.78Clearance Factor Pass - MPI-12 - MPI-12L1 - MPI-12L11,225.43 8,412.78 901.58 7,562.67 3.7848,412.78Clearance Factor Pass - MPI-12 - MPI-12PB1 - MPI-12PB11,225.43 8,412.78 900.32 7,562.67 3.7698,412.78Clearance Factor Pass - MPI-14 - MPI-14 - MPI-14446.18 9,412.78 325.18 8,534.45 3.6879,412.78Ellipse Separation Pass - MPI-14 - MPI-14 - MPI-14443.77 9,491.95 327.09 8,586.65 3.8039,491.95Centre Distance Pass - MPI-14 - MPI-14 - MPI-14553.44 10,762.78 387.38 9,861.05 3.33310,762.78Clearance Factor Pass - MPI-14 - MPI-14L1 - MPI-14L1471.15 9,505.68 349.80 8,580.44 3.8839,505.68Centre Distance Pass - MPI-14 - MPI-14L1 - MPI-14L1472.18 9,662.78 346.52 8,732.58 3.7589,662.78Ellipse Separation Pass - MPI-14 - MPI-14L1 - MPI-14L1545.61 10,862.78 369.10 9,910.00 3.09110,862.78Clearance Factor Pass - MPI-14 - MPI-14L2 - MPI-14L2388.31 9,887.78 252.21 8,946.77 2.8539,887.78Ellipse Separation Pass - MPI-14 - MPI-14L2 - MPI-14L2387.97 9,919.59 252.61 8,970.67 2.8669,919.59Centre Distance Pass - MPI-14 - MPI-14L2 - MPI-14L2467.24 10,762.78 301.80 9,768.00 2.82410,762.78Clearance Factor Pass - MPI-14 - MPI-14L2PB1 - MPI-14L2PB1777.30 8,412.78 658.62 7,391.00 6.5508,412.78Clearance Factor Pass - MPI-14 - MPI-14L2PB2 - MPI-14L2PB2388.31 9,887.78 251.92 8,946.77 2.8479,887.78Ellipse Separation Pass - MPI-14 - MPI-14L2PB2 - MPI-14L2PB2387.97 9,919.59 252.33 8,970.67 2.8609,919.59Centre Distance Pass - MPI-14 - MPI-14L2PB2 - MPI-14L2PB2456.01 10,612.78 283.37 9,594.00 2.64110,612.78Clearance Factor Pass - MPI-14 - MPI-14PB1 - MPI-14PB1436.89 9,212.78 268.23 8,427.00 2.5909,212.78Clearance Factor Pass - MPI-14 - MPI-14PB1 - MPI-14PB1420.70 9,330.62 287.27 8,427.00 3.1539,330.62Centre Distance Pass - MPI-14 - MPI-14PB2 - MPI-14PB2450.19 9,424.45 333.78 8,518.62 3.8679,424.45Centre Distance Pass - MPI-14 - MPI-14PB2 - MPI-14PB2468.70 10,337.78 300.48 9,450.00 2.78610,337.78Clearance Factor Pass - MPI-17 - MPI-17 - MPI-171,012.02 8,412.78 678.02 9,152.04 3.0308,412.78Clearance Factor Pass - MPI-17 - MPI-17L1 - MPI-17L11,025.67 8,412.78 720.72 9,116.84 3.3638,412.78Clearance Factor Pass - MPI-17 - MPI-17L2 - MPI-17L21,013.76 8,412.78 643.23 9,189.44 2.7368,412.78Clearance Factor Pass - MPI-19 - MPI-19L1 - MPI-19L11,438.90 14,687.78 1,186.85 12,225.00 5.70914,687.78Clearance Factor Pass - MPI-19 - MPI-19L1 - MPI-19L11,298.65 15,212.78 1,092.95 12,225.00 6.31315,212.78Ellipse Separation Pass - MPI-19 - MPI-19L1 - MPI-19L11,294.71 15,313.78 1,097.33 12,225.00 6.55915,313.78Centre Distance Pass - MPU I-39i - MPU I-39i - MPU I-39i924.81 15,120.20 743.65 13,342.81 5.10515,120.20Centre Distance Pass - MPU I-39i - MPU I-39i - MPU I-39i977.76 18,766.77 689.39 16,994.00 3.39118,766.77Clearance Factor Pass - 19 October, 2020-14:07COMPASSPage 2 of 8 Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU I-40 - MPU I-40 wp11Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftSite NameScan Range: 8,412.78 to 18,855.66 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (North Reference)Reference Design: M Pt I Pad - Plan: MPU I-40 - MPU I-40 - MPU I-40 wp11MeasuredDepth(usft)Summary Based on MinimumSeparation WarningPlan: MPU I-24 - MPU I-24 - MPU I-24 wp021,467.90 17,737.78 1,188.40 15,403.63 5.25217,737.78Clearance Factor Pass - Plan: MPU I-24 - MPU I-24 - MPU I-24 wp021,465.80 17,787.78 1,187.42 15,403.63 5.26617,787.78Ellipse Separation Pass - Plan: MPU I-24 - MPU I-24 - MPU I-24 wp021,465.33 17,824.57 1,187.88 15,403.63 5.28117,824.57Centre Distance Pass - Plan: MPU I-25i - MPU I-25i - MPU I-25i wp04818.95 17,662.78 577.71 15,878.22 3.39517,662.78Clearance Factor Pass - Plan: MPU I-25i - MPU I-25i - MPU I-25i wp04818.16 17,698.84 578.66 15,880.73 3.41617,698.84Centre Distance Pass - Plan: MPU I-26 - MPU I-26 - MPU I-26 wp06201.98 13,510.89 124.37 12,688.80 2.60313,510.89Centre Distance Pass - Plan: MPU I-26 - MPU I-26 - MPU I-26 wp06201.98 13,512.78 124.37 12,690.64 2.60313,512.78Ellipse Separation Pass - Plan: MPU I-26 - MPU I-26 - MPU I-26 wp06288.86 17,462.78 135.03 16,628.00 1.87817,462.78Clearance Factor Pass - Plan: MPU I-31 - MPU I-31 - MPU I-31 wp031,349.36 18,855.66 1,064.09 17,008.11 4.73018,855.66Clearance Factor Pass - Plan: MPU I-32i - MPU I-32i - MPU I-32i wp05781.61 18,855.66 509.13 17,510.41 2.86818,855.66Clearance Factor Pass - Plan: MPU I-33 - MPU I-33 - MPU I-33 wp05148.55 13,516.59 69.55 12,951.90 1.88013,516.59Centre Distance Pass - Plan: MPU I-33 - MPU I-33 - MPU I-33 wp05193.69 18,855.66 66.40 18,288.27 1.52218,855.66Clearance Factor Pass - M Pt J PadMPJ-08 - MPJ-08A - MPJ-08A523.37 14,712.78 276.68 8,495.00 2.12214,712.78Clearance Factor Pass - MPJ-08 - MPJ-08A - MPJ-08A336.57 15,062.78 217.71 8,495.00 2.83215,062.78Ellipse Separation Pass - MPJ-08 - MPJ-08A - MPJ-08A332.11 15,117.36 218.67 8,495.00 2.92715,117.36Centre Distance Pass - MPJ-09 - MPJ-09A - MPJ-09A397.08 14,087.78 166.06 8,235.00 1.71914,087.78Clearance Factor Pass - MPJ-09 - MPJ-09A - MPJ-09A218.17 14,419.56 121.38 8,235.00 2.25414,419.56Ellipse Separation Pass - MPJ-17 - MPJ-17 - MPJ-17959.07 13,137.43 852.28 6,725.00 8.98213,137.43Centre Distance Pass - MPJ-17 - MPJ-17 - MPJ-17967.22 13,262.78 848.27 6,725.00 8.13113,262.78Ellipse Separation Pass - MPJ-17 - MPJ-17 - MPJ-171,315.46 14,037.78 1,061.49 6,725.00 5.18014,037.78Clearance Factor Pass - MPJ-18 - MPJ-18 - MPJ-18635.06 16,387.78 306.22 8,013.32 1.93116,387.78Clearance Factor Pass - MPJ-18 - MPJ-18 - MPJ-18516.51 16,612.78 275.74 8,143.85 2.14516,612.78Ellipse Separation Pass - MPJ-18 - MPJ-18 - MPJ-18441.04 16,929.82 309.83 8,306.87 3.36116,929.82Centre Distance Pass - MPJ-19 - MPJ-19 - MPJ-19932.49 13,987.78 751.17 7,440.68 5.14313,987.78Clearance Factor Pass - MPJ-19 - MPJ-19 - MPJ-19676.15 14,587.78 591.06 7,582.06 7.94714,587.78Ellipse Separation Pass - MPJ-19 - MPJ-19 - MPJ-19673.15 14,653.58 592.27 7,598.48 8.32314,653.58Centre Distance Pass - MPJ-20 - MPJ-20 - MPJ-20145.7411,904.5645.967,734.381.46111,904.56Centre DistancePass - MPJ-20 - MPJ-20 - MPJ-20252.5712,112.788.827,706.401.03612,112.78Ellipse SeparationPass - MPJ-20 - MPJ-20 - MPJ-20273.1812,137.789.327,703.081.03512,137.78Clearance FactorPass - 19 October, 2020-14:07COMPASSPage 3 of 8 Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU I-40 - MPU I-40 wp11Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftSite NameScan Range: 8,412.78 to 18,855.66 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (North Reference)Reference Design: M Pt I Pad - Plan: MPU I-40 - MPU I-40 - MPU I-40 wp11MeasuredDepth(usft)Summary Based on MinimumSeparation WarningMPJ-20 - MPJ-20A - MPJ-20A1,020.74 10,987.78 774.16 7,505.74 4.14010,987.78Clearance Factor Pass - MPJ-20 - MPJ-20A - MPJ-20A648.76 11,737.78 576.02 7,664.35 8.91911,737.78Ellipse Separation Pass - MPJ-20 - MPJ-20A - MPJ-20A646.56 11,792.02 576.46 7,673.55 9.22411,792.02Centre Distance Pass - MPJ-23 - MPJ-23 - MPJ-23718.71 11,737.78 421.35 7,419.20 2.41711,737.78Clearance Factor Pass - MPJ-23 - MPJ-23 - MPJ-23461.97 12,162.78 342.02 7,312.58 3.85112,162.78Ellipse Separation Pass - MPJ-23 - MPJ-23 - MPJ-23432.22 12,331.76 347.93 7,270.20 5.12812,331.76Centre Distance Pass - MPJ-23 - MPJ-23A - MPJ-23A738.15 11,712.78 424.11 7,433.55 2.35011,712.78Clearance Factor Pass - MPJ-23 - MPJ-23A - MPJ-23A461.97 12,162.78 341.24 7,320.08 3.82712,162.78Ellipse Separation Pass - MPJ-23 - MPJ-23A - MPJ-23A432.22 12,331.76 347.88 7,277.70 5.12512,331.76Centre Distance Pass - MPJ-23 - MPJ-23L1 - MPJ-23L1718.71 11,737.78 421.35 7,419.20 2.41711,737.78Clearance Factor Pass - MPJ-23 - MPJ-23L1 - MPJ-23L1461.97 12,162.78 342.02 7,312.58 3.85112,162.78Ellipse Separation Pass - MPJ-23 - MPJ-23L1 - MPJ-23L1432.22 12,331.76 347.93 7,270.20 5.12812,331.76Centre Distance Pass - MPJ-24 - MPJ-24A - MPJ-24A417.47 14,187.27 330.47 6,989.11 4.79914,187.27Ellipse Separation Pass - MPJ-24 - MPJ-24A - MPJ-24A729.84 14,787.78 434.98 7,044.22 2.47514,787.78Clearance Factor Pass - MPJ-24 - MPJ-24L1 - MPJ-24L1417.47 14,187.27 330.47 6,992.82 4.79914,187.27Ellipse Separation Pass - MPJ-24 - MPJ-24L1 - MPJ-24L1729.84 14,787.78 438.28 7,047.93 2.50314,787.78Clearance Factor Pass - MPJ-24 - MPJ-24L1PB1 - MPJ-24L1PB1417.47 14,187.27 330.47 6,992.82 4.79914,187.27Ellipse Separation Pass - MPJ-24 - MPJ-24L1PB1 - MPJ-24L1PB1729.84 14,787.78 438.02 7,047.93 2.50114,787.78Clearance Factor Pass - MPJ-24 - MPJ-24L1PB2 - MPJ-24L1PB2417.47 14,187.27 330.47 6,992.82 4.79914,187.27Ellipse Separation Pass - MPJ-24 - MPJ-24L1PB2 - MPJ-24L1PB2729.84 14,787.78 438.29 7,047.93 2.50314,787.78Clearance Factor Pass - MPJ-24 - MPU J-24 - MPJ-24417.47 14,187.27 330.47 6,992.82 4.79914,187.27Ellipse Separation Pass - MPJ-24 - MPU J-24 - MPJ-24729.84 14,787.78 438.29 7,047.93 2.50314,787.78Clearance Factor Pass - MPJ-25 - MPJ-25 - MPJ-2576.7114,937.78-293.528,343.970.20714,937.78Ellipse SeparationFAIL - MPJ-25 - MPJ-25 - MPJ-2510.2815,013.89-95.448,348.000.09715,013.89Clearance FactorFAIL - MPJ-26 - MPJ-26 - MPJ-262.5812,737.78-108.498,595.680.02312,737.78Ellipse SeparationFAIL - MPJ-26 - MPJ-26 - MPJ-261.3312,741.82-67.908,599.070.01912,741.82Clearance FactorFAIL - MPJ-26 - MPJ-26L1 - MPJ-26L1195.14 12,836.79 118.14 8,670.00 2.53412,836.79Centre Distance Pass - MPJ-26 - MPJ-26L1 - MPJ-26L1196.86 12,862.78 117.95 8,670.00 2.49512,862.78Ellipse Separation Pass - MPJ-26 - MPJ-26L1 - MPJ-26L1401.58 13,187.78 164.46 8,670.00 1.69413,187.78Clearance Factor Pass - MPJ-26 - MPJ-26L2 - MPJ-26L2149.76 12,845.52 66.73 8,535.00 1.80412,845.52Centre Distance Pass - 19 October, 2020-14:07COMPASSPage 4 of 8 Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU I-40 - MPU I-40 wp11Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftSite NameScan Range: 8,412.78 to 18,855.66 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (North Reference)Reference Design: M Pt I Pad - Plan: MPU I-40 - MPU I-40 - MPU I-40 wp11MeasuredDepth(usft)Summary Based on MinimumSeparation WarningMPJ-26 - MPJ-26L2 - MPJ-26L2150.76 12,862.78 66.51 8,535.00 1.78912,862.78Ellipse Separation Pass - MPJ-26 - MPJ-26L2 - MPJ-26L2306.3613,112.7890.818,535.001.42113,112.78Clearance FactorPass - MPJ-26 - MPJ-26PB1 - MPJ-26PB1355.89 12,385.96 227.65 8,074.00 2.77512,385.96Centre Distance Pass - MPJ-26 - MPJ-26PB1 - MPJ-26PB1377.81 12,512.78 220.20 8,074.00 2.39712,512.78Ellipse Separation Pass - MPJ-26 - MPJ-26PB1 - MPJ-26PB1518.31 12,762.78 260.42 8,074.00 2.01012,762.78Clearance Factor Pass - MPJ-26 - MPJ-26PB2 - MPJ-26PB233.7012,713.87-57.358,562.000.37012,713.87Clearance FactorFAIL - MPJ-26 - MPJ-26PB2 - MPJ-26PB2104.4812,812.78-97.718,562.000.51712,812.78Ellipse SeparationFAIL - MPJ-27 - MPJ-27 - MPJ-27628.97 12,662.78 438.27 7,377.19 3.29812,662.78Clearance Factor Pass - MPJ-27 - MPJ-27 - MPJ-27408.62 13,112.78 336.00 7,335.40 5.62713,112.78Ellipse Separation Pass - MPJ-27 - MPJ-27 - MPJ-27407.41 13,144.32 336.53 7,332.30 5.74813,144.32Centre Distance Pass - MPJ-28 - MPJ-28 - MPJ-28618.63 11,212.78 430.92 7,761.14 3.29611,212.78Clearance Factor Pass - MPJ-28 - MPJ-28 - MPJ-28414.73 11,612.78 340.40 7,702.12 5.58011,612.78Ellipse Separation Pass - MPJ-28 - MPJ-28 - MPJ-28410.59 11,671.32 342.38 7,689.49 6.01911,671.32Centre Distance Pass - Plan: MPU J-29 - MPU J-29 - MPU J-29 wp06472.12 15,288.10 396.09 7,314.22 6.20915,288.10Centre Distance Pass - Plan: MPU J-29 - MPU J-29 - MPU J-29 wp06472.74 15,312.78 395.77 7,319.12 6.14215,312.78Ellipse Separation Pass - Plan: MPU J-29 - MPU J-29 - MPU J-29 wp06698.09 15,812.78 511.49 7,418.45 3.74115,812.78Clearance Factor Pass - Plan: MPU J-30i - MPU J-30i - MPU J-30i wp06551.28 15,837.44 472.24 7,378.32 6.97415,837.44Centre Distance Pass - Plan: MPU J-30i - MPU J-30i - MPU J-30i wp06553.40 15,887.78 471.29 7,392.34 6.74015,887.78Ellipse Separation Pass - Plan: MPU J-30i - MPU J-30i - MPU J-30i wp06797.73 16,437.78 604.32 7,545.49 4.12416,437.78Clearance Factor Pass - M Pt L Pad19 October, 2020-14:07COMPASSPage 5 of 8 Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU I-40 - MPU I-40 wp11Survey tool programFrom(usft)To(usft)Survey/Plan Survey Tool33.70 900.00 MPU I-40 wp11 3_Gyro-GC_Csg900.00 8,412.78 MPU I-40 wp11 3_MWD+IFR2+MS+Sag8,412.78 18,855.66 MPU I-40 wp11 3_MWD+IFR2+MS+SagEllipse error terms are correlated across survey tool tie-on points.Separation is the actual distance between ellipsoids.Calculated ellipses incorporate surface errors.Clearance Factor = Distance Between Profiles / (Distance Between Profiles - Ellipse Separation).Distance Between centres is the straight line distance between wellbore centres.All station coordinates were calculated using the Minimum Curvature method.19 October, 2020-14:07COMPASSPage 6 of 8 0.001.002.003.004.00Separation Factor8800 9350 9900 10450 11000 11550 12100 12650 13200 13750 14300 14850 15400 15950 16500 17050 17600 18150 18700Measured Depth (1100 usft/in)MPI-12PB1MPU I-39iMPJ-28MPU J-29 wp06No-Go Zone - Stop DrillingCollision Avoidance Req.Collision Risk Procedures Req.WELL DETAILS:Plan: MPU I-40 NAD 1927 (NADCON CONUS)Alaska Zone 0433.60+N/-S +E/-W Northing Easting Latittude Longitude0.000.006009456.070551419.68070° 26' 11.708 N149° 34' 50.758 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU I-40, True NorthVertical (TVD) Reference:MPU I-40 Doyon 14 As-built RKB @ 67.30usftMeasured Depth Reference:MPU I-40 Doyon 14 As-built RKB @ 67.30usftCalculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2020-07-06T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool33.70 900.00 MPU I-40 wp11 (MPU I-40) 3_Gyro-GC_Csg900.00 8412.78 MPU I-40 wp11 (MPU I-40) 3_MWD+IFR2+MS+Sag8412.78 18855.66 MPU I-40 wp11 (MPU I-40) 3_MWD+IFR2+MS+Sag0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)8800 9350 9900 10450 11000 11550 12100 12650 13200 13750 14300 14850 15400 15950 16500 17050 17600 18150 18700Measured Depth (1100 usft/in)MPJ-26MPJ-25NO GLOBAL FILTER: Using user defined selection & filtering criteria33.70 To 18855.66Project: Milne PointSite: M Pt I PadWell: Plan: MPU I-40Wellbore: MPU I-40Plan: MPU I-40 wp11Ladder / S.F. Plots2 of 2CASING DETAILSTVD TVDSS MD Size Name3787.30 3720.00 8412.78 9-5/8 9 5/8" x 12 1/4"3982.30 3915.00 18855.66 4-1/2 4 1/2" x 8 1/2" Revised 2/2015 TRANSMITTAL LETTER CHECKLIST WELL NAME: ______________________________________ PTD: _____________________________________________ ___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional FIELD: ____________________________ POOL: ______________________________________ Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI LATERAL (If last two digits in API number are between 60-69) The permit is for a new wellbore segment of existing well Permit No. _____________, API No. 50-_______________________. Production should continue to be reported as a function of the original API number stated above. Pilot Hole In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well name (_______________________PH) and API number (50-_____________________) from records, data and logs acquired for well (name on permit). Spacing Exception The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce/inject is contingent upon issuance of a conservation order approving a spacing exception. (_____________________________) as Operator assumes the liability of any protest to the spacing exception that may occur. Dry Ditch Sample All dry ditch sample sets submitted to the AOGCC must be in no greater than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. Non- Conventional Well Please note the following special condition of this permit: Production or production testing of coal bed methane is not allowed for well ( ) until after ( ) has designed and implemented a water well testing program to provide baseline data on water quality and quantity. (________________________) must contact the AOGCC to obtain advance approval of such water well testing program. Well Logging Requirements Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by (_______________________________) in the attached application, the following well logs are also required for this well: Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. 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