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Home My WebLink About221-013Nolan Vlahovich Hilcorp Alaska, LLC Geo Tech 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: 06/21/2023 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20230421 Well API #PTD #Log Date Log Company Log Type BCU 19RD 50133205790100 219188 5/11/2023 AK E-LINE PPROF MPU I-27 50029236920000 221013 3/23/2023 HALLIBURTON Tubing Punch-Cut MPU J-05 50029221960000 191095 3/25/2023 HALLIBURTON Tubing Punch-Cut MPU L-36 50029227940000 197148 3/14/2023 HALLIBURTON MFC24 Please include current contact information if different from above. T37778 T37779 T37780 T37781 MPU I-27 50029236920000 221013 3/23/2023 HALLIBURTON Tubing Punch-Cut Kayla Junke Digitally signed by Kayla Junke Date: 2023.06.21 13:55:21 -08'00' Kyle Wiseman Hilcorp Alaska, LLC Geo Tech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: Kyle.Wiseman@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 04/14/2023 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20230414 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# MPF-81 50029229590000 200066 3/29/2023 READ CaliperSurvey MPI-04A 50029220680100 201092 4/2/2023 READ CaliperSurvey MPI-27 50029236920000 221013 4/2/2023 READ CaliperSurvey MPI-27 50029236920000 221013 3/20/2023 READ CaliperSurvey MPL-12 50029223340000 193011 4/2/2023 READ CaliperSurvey MPU I-27 50029236920000 221013 3/23/2023 READ LeakPointSurvey PBU 09-23A 50029210660100 198044 3/28/2023 READ MultipleArrayProductionProfile PBU L-112A 50029231290100 222138 3/27/2023 READ MemoryRadialCementBondLog END 1-11 50029221070000 190157 3/19/2023 AK E-LINE Perf END 1-29 50029216690000 186181 2/9/2023 AK E-LINE Perf NCI A-08 50883200280000 169063 3/20/2023 AK E-LINE Perf BCU 19RD 50133205790100 219188 4/4/2023 AK E-LINE PPROF SRU 224-10 50133101380100 222124 3/31/2023 AK E-LINE CIBP_GPT_Perf SRU 224-10 50133101380100 222124 4/3/2023 AK E-LINE GPT_Perf SRU 231-33 50133101630100 223008 3/29/2023 AK E-LINE GPT Please include current contact information if different from above. T37595 T37596 T37599 T37599 T37597 T37599 T37598 T37601 T37603 T37600 T37602 T37594 T37604 T37604 T37605 MPI-27 50029236920000 221013 4/2/2023 READ CaliperSurvey MPI-27 50029236920000 221013 3/20/2023 READ CaliperSurvey MPU I-27 50029236920000 221013 3/23/2023 READ LeakPointSurvey Kayla Junke Digitally signed by Kayla Junke Date: 2023.04.17 14:10:44 -08'00' 1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Repair Casing Performed: Install Whipstock Perforate Other Stimulate Alter Casing Tubing Cut Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: Complete 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 14,497 feet N/A feet true vertical 4,140 feet N/A feet Effective Depth measured 14,495 feet feet true vertical 4,140 feet 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 / Hydril 521 4,130' 3,787' 7" x 4-1/2" Hydratrieve 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: Wells Manager Contact Phone: Sr Pet Eng: Sr Pet Geo: Sr Res Eng: WINJ WAG 3,999, 4,164 & 4,782 3,721, 3,802 & 3,944 603 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 323-167 N/A Brian Glasheen Brian.Glasheen@hilcorp.com 907-564-5277 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 814 3393 298 3393292 1147 3060 292 measured true vertical Packer Representative Daily Average Production or Injection Data Casing Pressure Tubing PressureGas-Mcf MD 147' Size 147' 1,920' Length Liner 4,789' STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 221-013 50-029-23692-00-00 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 3. Address: Hilcorp Alaska LLC 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: ADL0025906 & ADL0315848 MILNE POINT / SCHRADER BLUFF OIL MILNE PT UNIT I-27 Plugs Junk measured measured N/A Casing Conductor 3,802' 4,140' 4,789' 14,497' 3,010' 1,949'Surface Surface Inermediate 20" 9-5/8" 9-5/8" 147' TVD 1,949' 5,410psi 8,540psi 6,870psi 5,750psi 7,240psi 6,020psi 4,959' 3,954' 3,090psi 9,715' 7" 4-1/2" Burst N/A Collapse N/A 4,760psi PL G Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov By Kayla Junke at 12:53 pm, May 03, 2023 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143) Date: 2023.05.03 10:44:11 - 08'00' Taylor Wellman (2143) DSR-5/9/23 RBDMS JSB 050423 WCB 1-5-2024 _____________________________________________________________________________________ Revised By: TDF 5/1/2023 SCHEMATIC Milne Point Unit Well: MPU I-27 Last Completed: 4/6/2023 PTD: 221-013 TD =14,497’(MD) / TD =4,140’(TVD) 6 20” Orig. KB Elev.: 60.25’ / GL Elev.: 33.80’ 7” 8 11 2 9 9-5/8”10 1 3 Tubing Cut @ 4,118’ 3/25/2023 See Screen/ Solid Liner Detail PBTD =14,495’(MD)/ PBTD = 4,140’(TVD) 9-5/8” ‘ES’ Cementer @ 1,967’ MD 7 4-1/2” Shoe @ 14,497’ 4 5 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20" Conductor 129.5 / X52 / Weld N/A Surface 147’ N/A 9-5/8" Surface 47 / L-80 / TXP 8.681 Surface 1,949’ 0.0732 9-5/8” Surface 40 / L-80 / TXP 8.835 1,949’ 4,959’ 0.0758 7” Tieback 26 / L-80 / TXP 6.276 Surface 4,789’ 0.0383 4-1/2” Liner 250ђ Screens 13.5 / L-80 / Hyd 625 3.920 4,782’ 14,497’ .0149 TUBING DETAIL 4-1/2" Tubing 12.6 / L-80 / Hydril 521 3.958” Surface 4,130’ 0.0152 OPEN HOLE / CEMENT DETAIL Conductor Driven 20” 12-1/4"Stg 1 Lead – 350 sx / Tail – 400 sx Stg 2 Lead – 114 sx / Tail 270 sx 8-1/2” Cementless Screened Liner WELL INCLINATION DETAIL KOP @ 180’ Max Hole Angle = 94° @ 9,407’ MD TREE & WELLHEAD Tree Cameron 3-1/8" 5M w/ 3-1/8” 5M Cameron Wing Wellhead Cameron 11” 5K w/ 4-1/2” Atlas Bradford TC-II 12.6# top & bottom Tbg Hanger GENERAL WELL INFO API: 50-029-23692-00-00 Completion Date: 4/29/2021 Completed by ASR – 4/6/2023 JEWELRY DETAIL No. Top MD Item ID 1 4,096’ HES XD Sliding Sleeve – 3 Ports Plugged 3.813” 2 4,102’ Gauge Mandrel 3.865” 3 3,999’ 7" x 4-1/2" Hydratrieve Packer (50k Shear Release) Tripoint 3.875” 4 4,063’ 4-1/2" Nipple,3.813” X profile, TXP-BTC (RHC-M installed)3.813” 5 4,119’ Non sealing Tubing Overshot – Btm @ 4,130’4.700” 6 4,164’ Baker Premier Packer 3.890” 7 4,234’ XN Nipple, 2.75” ID 3.725” 8 4,766’ WLEG – Bottom @ 4,796’ 3.958” 9 4,782’ SLZXP Liner Top Packer (3,944’ TVD) 6.160” 10 4,803’ 7” H563 x 4.5” TSH 625 XO 3.840” 11 14,495’ Shoe 3.950” 4-1/2”SCREENS LINER DETAIL Jts Top (MD) Top (TVD) Btm (MD) Btm (TVD) 67 4971’ 3954’ 7717’ 3995’ 31 8073’ 4035’ 9322’ 4042’ 118 9638’ 4027’ 14464’ 4138’ Well Name Rig API Number Well Permit Number Start Date End Date MP I-27 Slickline 50-029-23692-00-00 221-013 3/20/2023 4/9/2023 FINISH RCH 40 ARM CALIPER LOGGING FROM 4,640 TO SURFACE (good data). BRING PF ON-LINE @ 2000 bwpd, DISPLACE WELL W/ 72 BBLS PRODUCED WATER. BRUSH AND FLUSH FROM SURFACE TO 4,650' SLM. SET 4-1/2" CAT-STANDING VLV ON XN-NIP @ 4,234' MD. BRING ON PF TO FILL TBG (see log). LRS - CONDUCTS PASSING MIT-T TO 3500 PSI (see lrs log). LRS - CONDUCTS PASSING CMIT- IA x OA (see lrs log). PULL 4-1/2" CAT-STANDING VLV IN XN-NIP @ 4,234' MD. RAN 42BO SHIFTING TOOL (keys dwn to open), S/D & SHIFT XD-SS @ 4,096' MD (pin slightly worked, not sheared) No operations to report. 3/18/2022 - Saturday WELL S/I ON ARRIVAL***(C/O JET PUMP, CMIT x IA/OA). PULL 3" JET PUMP (sn: HC-00033) FROM XD-SS @ 4,096' MD RAN 42BO (keys up) CLOSE XD-SS @ 4,096' MD (10 passes ss-closed, see log). DRIFT TBG W/ 3.25" CENT, DEVIATE OUT AT 4,610'' SLM. RAN READ CASED HOLE 40 ARM CALIPER FROM 4,640' SLM TO SURFACE. 3/21/2023 - Tuesday 3/19/2023 - Sunday No operations to report. 3/20/2023 - Monday 3/17/2022 - Friday No operations to report. 3/15/2022 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary No operations to report. 3/16/2022 - Thursday No operations to report. LRS - CONDUCTS PASSING CMIT- IA x OA Well Name Rig API Number Well Permit Number Start Date End Date MP I-27 SL & Eline 50-029-23692-00-00 221-013 3/20/2023 4/9/2023 3/24/2022 - Friday PT 250L/2500H. LOG READ ACOUSTIC LEAK DETECT LOG FROM SURFACE TO 4200'. FOUND A LEAK AT 4096' AT THE SLEEVE. UNABLE TO FIND IA LEAK. PUNCH TUBING FROM 4175'-4180' USING 2", 4 SPF, 0 DEG PHASED HSC LOADED W/ 7GR CHARGES. CCL TO TOP SHOT OFFSET: 4.5'. CCL STOP DEPTH: 4170.5'. CORRELATED TO TUBING TALLY RECORD. T/I/O= 440/220/67 (Pre RWO) MIT-IA to 3500 psi Failed. Pumped 44 bbls diesel down IA to fluid pack, pressured IA to 3505 psi with 1.7 bbls diesel. OA slowly gained pressure. IA lost 585 psi in 5 min. OA gained 182 psi. Pumped .65 bbls diesel and got .03 bpm @ 2500 psi LLO. Pumped 22.8 bbls diesel down IA taking returns up OA to tank for E-line LDL. Final Whps=470/960/940. 3/22/2022 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary No operations to report. 3/23/2022 - Thursday ATTEMPT TO LOG READ ARCHER ACOUSTIC LEAK DETECT LOG. UNABLE TO ACTIVATE THE LEAK WHEM PUMPING DOWN THE OA, INTO THE IA AND TAKING RETURNS TO FORMATION. DECSION MADE TO RIG DOWN TO ALLOW SLICKLINE TO CLOSE THE SLEEVE. WILL RETURN TO LOG READ ARCHER LEAK DETECT LOG. WELL SECURE AND TURNED OVER TO S/L. T/I/O= 350/190/17 Assist E-line with LDL. Pressured up OA to 1500 psi and maintained pressures while E-line logged with 21.1 bbls diesel. MIT-OA PASSED to 1714 psi. Pressured up OA to 1736 psi with .3 bbls diesel. 1st 15 min OA lost 18 psi. 2nd 15 min OA lost 4 psi for a total loss of 22 psi in 30 min. Bled back 1.5 bbls. Final Whp's=365/200/30. SHIFT XD-SS CLOSED AT 4,096' MD W/ 4-1/2" 42BO. No operations to report. CUT TUBING AT 4118' WITH WELLTEC MECHANICAL CUTTER. CCL TO CUTTER OFFSET: 18.4'. CCL STOP DEPTH: 4099.6'. WELL LEFT S/I ON DEPARTURE, SECURED AND TURNED OVER TO DSO. T/I/O=660/58/54 Well Kill/freeze protect (Pre RWO) Pumped 72 bbls of 120* Produced water and 44 bbls of 40* diesel down IA up TBG taking returns to production. Pumped 63 bbls of 120* produced water and 38 bbls of 40* diesel down TBG. BPV set. Pumped 2 bbls 60/40 down PFL. Lat shut and bled to 0 psi. Pumped 4 bbls of 90* diesel down Prod Lat. Lat closed and bled to 0 psi. Pumped 4 bbls of 90* diesel down Test Lat. Lat 3/25/2022 - Saturday No operations to report. 3/28/2023 - Tuesday 3/26/2023 - Sunday No operations to report. 3/27/2023 - Monday LOG READ ACOUSTIC LEAK DETECT LOG FROM SURFACE TO 4200'. FOUND A LEAK AT 4096' AT THE SLEEVE. UNABLE TO FIND IA LEAK. Well Name Rig API Number Well Permit Number Start Date End Date MP I-27 Nordic #3 50-029-23692-00-00 221-013 3/21/2023 4/9/2023 TOH w/YJ 7" test packer while laying down 4" DP sideways. L/D test packer. Pulled 7" packoff. R/U GBR to pull 7" casing. M/U landing joint & pulled 7" casing hanger to floor, 149k to release. Lay down hanger. Begin pulling 7" 26# BTC casing laying down, inspecting to re-run. BH 50 bbls down 7" casing every 15 joints. CHF on 9-5/8" 150 bph. Joint # 17 (leak point). C/O joints # 17 - 21. Adjust run tally. Continue TIH w/7" 26# casing as per program. Spill on rig floor from U-tube. Wellhead: Pull 4" H CST BPV, rig circed well, set BPV back in well, Nipple down tree and adapter, installed CTS plug, Nipple up BOPs and test, Pull CTS, Circ well and pull BPV, BOLDS and pull tubing hanger. Continue installing 7" rams in stack. Finish N/U choke / kill lines. Fill stack. Shell test BOP stack. Saw small amount of residual gas on IA during shell test, bullhead 150 bbls of source water down IA. Flow check, well on Vac. Continue. Complete sucessful shell test. BOP testing as per sundry w/4", 4- 1/2", and 7" test joints. 250 low / 2500 High. Perform Koomy draw down. Test PVT, Fire and Gas Alarms. Notification of BOPE Test was given at 05:00 3/30/2023. Waived witness (Bob Noble). Load & strap remaining 4" DP. BOP test completed. BH 150 bbls of source water down IA. Pull CTS. R/U to pull tubing. 4/1/2022 - Saturday Continue TIH w/YJ 7" test packer on 4" DP. Set packer and test 7" casing @ 500', 1000', 1500, and 2800' with no communication w/OA. RIH and tag tubing stub at 4124', 5k down. Set test packer COE at 4,117'. Pressure up 7" to 1650 psi. Observed immediate tracking on the OA from 300 psi. to 900 psi. SD pump. Bleed 7" psi to 550 psi. Pressure stabilized at 900 on OA & 575 psi on IA. Appears to be one way leak IA x OA. PUH and set packer 3,930' and test 7" casing to 3000 psi, no communication to OA. Leak depth = 3,930' - 4,117'. Discuss plan forward w/OE. TIH & set packer at 4,074'. Test 7" casing to 2000 psi for 30 minutes, no communication to OA. Leak depth = Joint # 17 @ 4,094.85'. Slip & cut drill line. 4/4/2023 - Tuesday 4/2/2023 - Sunday Pulled BPV. MU landing joint. BOLDS. Pulled hanger to floor, PUW 89k, Block Wt 36k, String weight = 53k. CHF @ 1.25 bpm or 75 bph. Nordic 3 unable to break out Hydril 521 tubing, wrong backup dies. GBR on location. Pull & L/D 4-1/2" Hydril 521 tubing, recovered 100 full joints & 56 OTC Canon Clamps. MIRU HES Slickline. Logged 7" casing w/Read 40 arm extended reach caliper from 4,139' slm to surface @ 50 fpm. Verify good data. TIH w/YJ 7" test packer on 4" DP. 4/3/2023 - Monday 3/31/2022 - Friday Continue spotting rig over MPI-27. Jack up rig and set last rig mats. Shim rig. Continue rigging up Nordic 3. Set cuttings tank. R/U flow back tank to cellar. Set 400 bbl uprights next to pits. Load pits w/600 bbls of source water. Build berm around cellar. Bleed IA 500 psi to 180 psi. R/U to BH kill well. BH 150 bbls of source water down IA. Pulled BPV w/hydraulic lubricator and BH 150 bbls of source water down tubing @ 4 bpm / 0 psi. Set BPV. N/D wellhead and set CTS in BPV. Begin N/U BOP stack. Begin loading 4" drill pipe on DS pipe shed. 3/29/2022 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary No operations to report. 3/30/2022 - Thursday No operations to report. Pulled 7" packoff. R/U GBR to pull 7" casing. M/U landing joint & pulled 7" casing hanger to floor, 149k to release. Lay down hanger. Begin pulling 7" 26# BTC casing laying down, inspecting to re-run. BH 50 bbls down 7" casing every 15 joints. CHF on 9-5/8" 150 bph. Joint # 17 (leak point). C/O joints # 17 - 21. Adjust run tally. Continue TIH w/7" 26# casing as per program Set test packer COE at 4,117'. Pressure up 7" to 1650 psi. Observed immediate tracking on the OA from 300 psi. to 900 psi PUH and set packer 3,930' and test 7" casing to 3000 psi, no communication to OA. Leak depth = 3,930' - 4,117'. Discuss plan forward w/OE. TIH & set packer at 4,074'. Test 7" casing to 2000 psi for 30 minutes, no communication to OA. Leak depth = Joint # 17 @ 4,094.85 Pulled BPV. MU landing joint. BOLDS. Pulled hanger to floor, PUW 89k, Block Wt 36k, String weight = 53k. CHF @ 1.25 bpm or 75 bph. Nordic 3 unable to break out Hydril 521 tubing, wrong backup dies. GBR on location. Pull & L/D 4-1/2" Hydril 521 tubing, recovered 100 full joints & 56 OTC Canon Clamps Well Name Rig API Number Well Permit Number Start Date End Date MP I-27 Nordic #3 50-029-23692-00-00 221-013 3/21/2023 4/9/2023 No operations to report. WELL SHUT-IN ON ARRIVAL. UNABLE TO PASS THRU TUBING HANGAR AT -.5' SLM W/ 4-1/2" 42BO (metal marks on key). UNABLE TO PASS THRU TUBING HANGAR AT -.5' SLM W/ 3.60" BELL GUIDE (metal marks on btm of bell guide). PULL BALL & ROD FROM 4,062' MD (ran 2.60" bell guide, 2.0" jus). RAN 3.80" LIB TO 10' SLM (bobble thru tubing hangar), HALF MOON IMPRESSION ON EDGE OF LIB. SHIFT XD-SS AT 3,885' MD W/ 4-1/2" 42BO. PULL 4-1/2" RHC FROM X-NIPPLE AT 4,062' MD. SET 3" JETPUMP (serial - BP-1017, ratio: 13C) IN XD-SS AT 3,885' MD. WELL SHUT-IN ON DEPARTURE, PAD OP NOTIFIED. 4/8/2022 - Saturday No operations to report. 4/11/2023 - Tuesday 4/9/2023 - Sunday MPU Well Support tied well into process post RWO/Casing Repair. PT'd all surface lines and handed it over to I&E Group. Wellhead serviced. 4/10/2023 - Monday 4/7/2022 - Friday MIT-IA to 3700 psi for 30 minutes, 1st 15 minute loss 30 psi, 2nd 15 minute loss 14 psi. MIT-IA passed first attempt. Bleed pressures to zero. L/D landing joint and R/D test equipment. Set BPV. R/D GBR tongs. Blow down top drive & surface lines. Empty pits. N/D BOP stack. N/U tree. Terminate I-wire through tree and test. Test hanger void 500 psi / 5000 psi. Pulled BPV. RDMO Nordic 3. 4/5/2022 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary Continue pulling 7" 26# casing string. At Joint # 17 in slips. C/O joints # 17 - 21. Adjust run tally. Continue TIH w/7" 26# casing as per program. BH 50 bbls of source water down 7" casing every 15-20 joints in hole. P/U space out pups and 7" casing hanger. Pumped 200 bbls of CI brine followed by 60 bbls of diesel down 9-5/8" casing. Land 7" casing hanger, PUW 170k, SOW 125 k, Blk Wt 36k. MIT-OA to 3000 psi, lost 125 psi first 15 min, lost 40 psi the second 15 min. MIT passed. Set 7" pack off. Test pack off to 3500 psi for 30 min. Good test. 4/6/2022 - Thursday Crane pick centrilift spooler to rig floor. R/U GBR TTS. Test TIW to 2500 psi, charted. TIH w/4-1/2" Hydril 521 completion as per run tally. BH 50 bbls down 4-1/2" tubing every 20 joints. P/U joint # 100 and tagged 4-1/2" tubing stub. See both shear studs and No-go on stub. L/D joints 100 & 99. M/U space out pups = 14.49'. M/U hanger & terminate I-wire through hanger. Test I-wire. Land hanger placing overshot No-go 4.23' off tubing stub. RILDS. Pumped 20 bbls of CI brine down IA followed by 55 bbls of source water. Drop Roller Ball & Rod (1-3/8" FN). Pressure up tubing to 4000 psi and set 7" x 4-1/2" Hydratrieve Packer. MIT-Tbg to 3975 psi for 30 minutes. 15 minute loss 180 psi, 2nd 15 minute loss 60 psi. MIT-T passed. SET 3" JETPUM PULL BALL & ROD FROM 4,062' MD Continue TIH w/7" 26# casing as per program. BH 50 bbls of source water down 7" casing every 15-20 joints in hole. P/U space out pups and 7" casing hanger TIH w/4-1/2" Hydril 521 completion as per run tally. BH 50 bbls down 4-1/2" tubing every 20 joints. P/U joint # 100 and tagged 4-1/2" tubing stub. See both shear studs and No-go on stub. L/D joints 100 & 99. M/U space out pups = 14.49'. M/U hanger & terminate I-wire through hanger. Test I-wire. Land hanger placing overshot No-go 4.23' off tubing stub. RILDS. Pumped 20 bbls of CI brine down IA followed by 55 bbls of source water. Drop Roller Ball & Rod (1-3/8" FN). Pressure up tubing to 4000 psi and set 7" x 4-1/2" Hydratrieve Packer. MIT-Tbg to 3975 psi for 30 minutes. 15 minute loss 180 psi, 2nd 15 minute loss 60 psi. MIT-T passed. MIT-IA to 3700 psi for 30 minutes, 1st 15 minute loss 30 psi, 2nd 15 minute loss 14 psi. MIT-IA passed first attempt I_C_lĲH}ĲCOCI¢Ĳ CîI¢ĲHNOĲCUkĲCIĲjHUIl¥öC_NHUĲjHNIINHUĲ *\ãåĲ*gĲ*\Ĳ !cĲqĲ4X $,Ĳ ĲRK Ĳ mĲ Ĳ 4; Ĳ 4Ĳ Ĳ Ĳ RAĲ (Ĳ Ĳ Ĳ!,Ĳ !,ĲĲ ĲąĲ4 Ĳ RĲĄĲ Ĳ 42Ĳ Ĳ; Ĳ $ Ĳ Ĳ ( Ĳ Ĳ & (AĲ ĲĲ; Ĳ Ĳ . ĲĲ Ĳ, Ĳ Ĳ$ JĲ::Ĳ 7u ÀĲ ā' Ĳ &&21 1 $ KĲ 'Ĳ ?Ĳ$3Ĳ, 16ĲĲĲ ĲĲ$KĲ$ìĲ .1 .2& 2&1? &22 + 3qĲRA 6Ĳ; ĲĲĲ, ;Ĳ4 ĲĲ 'Ĳ(LĲ' ĲY Ĳ ĲĲ Ĳ h j[H[Ĳ{{[]z ; Ĳ ĲRA ĲXĲĲ Ĳuh o Ĳ Ĳ ú NOUlĲñ_Ĳ¨UN_ĲÏÉ{Ĳ ĝĲ AĲ<: Ĳ,= m Ĳ Ĳ Ĳ Ĳ Ĳ CkO]]zÛ]×ĲÄĲCkO]ÓÐzĲ /3:7Ĳ(3!Ĳ Ijéôkl¥ĲO¨}}ĲHNOĲ Ĳ - -- - ! ĲĲ/Ĳ<F= Ĳ ! ĲĲ!BĲ<F= Ĳ 7°'ĲĲ/ Ĳ 7°'ĲĲ!B Ĳ /Ĳ< = Ĳ Ĳ</= Ĳ JĲ</= Ĳ +#Ĳ #Ĳ .#Ĳ #Ĳ 16Ĳ ÍáĲ >$Ĳ ( #- #)- ,- - -*'()-$!!%(- Ĳ +#Ĳ &ZĲ +#Ĳ +#Ĳ >$Ĳ >$Ĳ ¾Ĳ #Ĳ 2.>6ZĲ #Ĳ &#Ĳ ?6+ Ĳ +? Ĳ ¾Ĳ 1#Ĳ 2.>6ZĲ . #Ĳ 1 .#Ĳ .+. Ĳ 1 Ĳ Ĳ +6 #Ĳ +ZĲ +6 #Ĳ 16&#Ĳ +& Ĳ . Ĳ :Ĳ +.#Ĳ 2>&ZĲ +#Ĳ #Ĳ ?& Ĳ 6. Ĳ RAĲĲ/Ĳ<F= Ĳ RAĲĲ!BĲ<F= Ĳ w !,Ĳ Ĳ w !,Ĳ@K Ĳ w !,Ĳ/Ĳ<F= Ĳ ĲĲ ĲĲ 2>&# &?ÃĲ:26Ĳ!©Ĳ ?#Ĳ JK ĲĲBĲ!c Ĳ J ĲĲBĲ/Ĳ<F=ĲĲ!BĲ<F= Ĳ ^JĲĲĲ:ù©Ĳ:Ĳ!ĲĲĲ ?Ĳ/>Ĳ16&Ĳ!BĲĲ+6&Ĳ/>Ĳ1 Ĳ!BĲĲĲ & $ ĲĲ ; ,Ĳ Ĳ 1Ĳ; Ĳ ĲFĲL ĲYJ ă Ĳ(K ĲĕKĲ ^(ĲJĲ 7u AĲ KĲ ' Ĳ ğĲ 7 ĲĲq.Ĳ; Ĳ ĲFĲL ĲYJ Ĳ Ĳ(A 1>&?>&&1Ĳ (3:Ĳ ;3Ĳ ;:Ĳ Ĳ ? B, Ĳ$L' Ĳ Ĳ @$Ĳ ;$@Ĳ @!(4Ĳ :õ@Ĳ $(@Ĳ4 ' Ĳ @3Ĳ (Ĳ»YĲ $,Ĳ ÑÙĲnĲ5")"vĲ8"ĘEģĲ5VĲ5"ĲE-)"Q-bQĲĲ)"Ĳ Vb%Ĳ5"Ĳ)-8"%)"ĲV)-ĂĲ 5")"bĲ900Ĳb-Ĳ"Ĳ%"V"%ĲE)-WĲ95-Ĳ)-)Ĳ9)"bĲV)-V0 $ĲĲĲ ħĨÜÝĩĪÌīĬĭÞĮ §Ģs¹¼ ĲLĲYĲ Ĳ ÇĲÈĲįĲ İðıĲý¸§ûs¹¼Ĳ÷®ssĐ¸Ĳ çĜ®ßĲ $Ĳ! Ĳ (A Ĳ/Ĳ Ĳ Ĳ ^Ĳ@ Ĳ Ĳ7 Ĳ ½³ª·[µªę²·Ď²³µ¬º½ē[¬ºďĲ Ĳ Ĳ +2.?2.&++Ĳ - -- ĲqĲ»' Ĳ ĖĆĲ$(@Ĳ ĲAĲĲL 'ĲÀĲY Ĳ Ĳ, Ĳ Ĳ3cĲ ^(Ĳ! Ĳ / Ĳ3cĲ! Ĳ :Ĳ Ĳ ( Ĳ S¤PĲĲĲ*g\GĲ ĲSĲ`8ĲĲ*GĲäĲ*g*GGÅ%ÆĲ '%Ĳ95ĲW%ĲêPĲMĲPP~ĲĲ)'%Ĳ-ĲP¤PĲ95Ĳ)-%8Ĳ8Ċ)Ĳ 88W'"%ĲpvĲ0%QĲ0"'"Ĳ SĲi'"%ĲE)Ĳ'Ĳ880QĲĲWĲ ĦĲ niĲDD`Ĳ5Q5Ĳ ))ĲĲ)ĲĲĲ"ġ8"%ĲWĲ5ĲGĲEĲ --%Ĳ%vĲĲ9ĲE0%Ĳ-ĲĲ SĲ niĲ09ĲĲĲĲĲĲpĲ09Ĳ5ĲgGĲEĲ-%Ĳ"%vĲĲ9ĲE0%ĲĲ" SĲ P%ĲQĲDD`Ĳ0-9ĲĲĲĲĲp"Ĳ09Ĳ5Ĳ\\ĲĲ SĲ DD`Ĳ80ĲĲniĲ900ĲĲ80-Ĳ95Ĳ*ĲWĲEĲDD`ĲĲ %8ĲpQĲ%Ĳ 'Ĳ' Ĳ3 Ĳ3ĉĲ/3!Ĳ4X#hĲ o Ĳ Ĳ Ĳ7uĲ4XLhĲ o Ĳ Ĳ , XĲmĲ4XėĀ Ĳ ´±´¿«¶¶ÁĲtr±ĒaþĲüÁĲëattraĲíxĲ æćđračĔĠtċrĲ $4(B7Ĳ^oĲ $L'Ĳ,c Ĳ «¿a|eefxfxee Ø|f|fÚÊĚĤĥĲ (//33(74Ĳ ! 7 $(@Ĳ Ĳ Ĳ ¡ĲĲ~øĲGMT**T*MĲ ÂĲĲ7£è¦Ò£â¦ÔĲ ĲĲ@Ĳ ï~Ĳ MT**T*G*MĲ ¡Ĳ4 Ĳ7Ĳ Dò2MT**T*MĲ dËÖdÕĲó¯ĞĈě¯ÿĲdÎydyy %%&$+-%%! ) $#-+! -$&--"$#)(-&$"-)-$-%%&$+!-,ĲmĲĲà Č'Ĳ RBDMS JSB 032323 1 Regg, James B (OGC) From:Jerimiah Galloway <Jerimiah.Galloway@hilcorp.com> Sent:Saturday, March 18, 2023 9:02 AM To:Regg, James B (OGC); Wallace, Chris D (OGC); David Haakinson; Taylor Wellman Subject:NOT OPERABLE: Producer MPI-27 (PTD# 221-013) OA Exceeded MOASP Mr. Regg, Jet producer MPI 27 (PTD# 221 013) exceeded OA MOASP to 3200 psi on 3/18/2022. While performing daily inspections, the operator identified the OA pressure had climbed to 3200 psi (matching power fluid pressure). Immediate actions were taken to shut in the well and alleviate the pressure. After shutting the well in, OA and IA pressures tracked down to 0 psi. There were no previous indications of prior pressure communication. The well is now classified as NOT OPERABLE as a diagnostic and repair plan is evaluated. Plan Forward 1. PPPOT T/IC Complete Passed 2. Freeze protect well In progress. 3. Eng to evaluate repairs Jerimiah Galloway MPU/Islands Well Integrity Engineer Email: jerimiah.galloway@hilcorp.com O: (907)564 5005 C: (828)553 2537 CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. After shutting the well in,OA and IA pressures tracked down to 0 psi. MPU I-27 (PTD 2210130) TIO Pressures DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-23692-00-00Well Name/No. MILNE PT UNIT I-27Completion Status1-OILCompletion Date4/29/2021Permit to Drill2210130Operator Hilcorp Alaska, LLCMD14497TVD4140Current Status1-OIL6/28/2021UICNoWell 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/DataTypeLogScaleDF4/30/2021 Electronic File: MPU I-27 Geosteering End of Well Plot.emf35065EDDigital DataDF4/30/2021 Electronic File: MPU I-27 Geosteering End of Well Report.docx35065EDDigital DataDF4/30/2021 Electronic File: MPU I-27 Geosteering End of Well Report.pdf35065EDDigital DataDF4/30/2021 Electronic File: MPU I-27 Geosterring End of Well plot.pdf35065EDDigital DataDF4/30/2021 Electronic File: MPU I-27 Geosterring End of Well plot.tif35065EDDigital DataDF4/30/2021 Electronic File: MPU I-27 Post-Well Geosteering X-Section Summary.pdf35065EDDigital Data0 0 2210130 MILNE PT UNIT I-27 LOG HEADERS35065LogLog Header Scans0 0 2210130 MILNE PT UNIT I-27 LOG HEADERS35066LogLog Header ScansDF4/30/2021135 14498 Electronic Data Set, Filename: MPU I-27 LWD Final.las35066EDDigital DataDF4/30/20214940 14460 Electronic Data Set, Filename: MPU I-27 ADR Quadrants All Curves.las35066EDDigital DataDF4/30/2021 Electronic File: MPU I-27 LWD Final MD.cgm35066EDDigital DataDF4/30/2021 Electronic File: MPU I-27 LWD Final TVD.cgm35066EDDigital DataDF4/30/2021 Electronic File: MPU I-27_Definitive Survey Report.pdf35066EDDigital DataDF4/30/2021 Electronic File: MPU I-27_Definitive Survey Report.txt35066EDDigital DataDF4/30/2021 Electronic File: MPU I-27_GIS.txt35066EDDigital DataMonday, June 28, 2021AOGCCPage 1 of 3MPU I-27 LWD Final.las DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-23692-00-00Well Name/No. MILNE PT UNIT I-27Completion Status1-OILCompletion Date4/29/2021Permit to Drill2210130Operator Hilcorp Alaska, LLCMD14497TVD4140Current Status1-OIL6/28/2021UICNoWell Cores/Samples Information:ReceivedStart Stop CommentsTotalBoxesSample SetNumberNameIntervalINFORMATION RECEIVEDCompletion ReportProduction Test InformationGeologic Markers/TopsY Y / NAYMud 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:4/29/2021Release Date:2/8/2021DF4/30/2021 Electronic File: MPU I-27_Plan.pdf35066EDDigital DataDF4/30/2021 Electronic File: MPU I-27_Surveys.xlsx35066EDDigital DataDF4/30/2021 Electronic File: MPU I-27_VSec.pdf35066EDDigital DataDF4/30/2021 Electronic File: MPU I-27 LWD Final MD.emf35066EDDigital DataDF4/30/2021 Electronic File: MPU I-27 LWD Final TVD.emf35066EDDigital DataDF4/30/2021 Electronic File: MPU_I-27_Geosteering.dlis35066EDDigital DataDF4/30/2021 Electronic File: MPU_I-27_Geosteering.ver35066EDDigital DataDF4/30/2021 Electronic File: MPU I-27 LWD Final MD.pdf35066EDDigital DataDF4/30/2021 Electronic File: MPU I-27 LWD Final TVD.pdf35066EDDigital DataDF4/30/2021 Electronic File: MPU I-27 LWD Final MD.tif35066EDDigital DataDF4/30/2021 Electronic File: MPU I-27 LWD Final TVD.tif35066EDDigital DataMonday, June 28, 2021AOGCCPage 2 of 3 DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-23692-00-00Well Name/No. MILNE PT UNIT I-27Completion Status1-OILCompletion Date4/29/2021Permit to Drill2210130Operator Hilcorp Alaska, LLCMD14497TVD4140Current Status1-OIL6/28/2021UICNoComments:Compliance Reviewed By:Date:Monday, June 28, 2021AOGCCPage 3 of 3M.Guhl6/28/2021 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: 33.8' BF: Total Depth: 10. Plug Back Depth MD/TVD: 18. Property Designation: 4b. Location of Well (State Base Plane Coordinates, NAD 27): 11. Total Depth MD/TVD: 19. DNR Approval Number: Surface: x- y- Zone- 4 TPI: x- y- Zone- 4 12. SSSV Depth MD/TVD: 20. Thickness of Permafrost MD/TVD: Total Depth: x- y- Zone- 4 5. Directional or Inclination Survey: Yes (attached) No 13. Water Depth, if Offshore: 21. Re-drill/Lateral Top Window MD/TVD: Submit electronic information per 20 AAC 25.050 (ft MSL) 22.Logs Obtained: 23. BOTTOM 20" X-52 147' L-80 1,920' L-80 3,954' 7" L-80 3,802' 4-1/2" L-80 4,140' 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 4,796'4-1/2" 12.6# L-80 SIZEIf Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number; Date Perfd): 14,497' Stg 2 L - 114 sx / T - 270 sx 3,944 Surface Driven 13.5# Surface 1,949' Stg 1 L - 350 sx / 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 4/29/2021 2321' FSL, 3537' FEL, Sec. 33, T13N, R10E, UM, AK 2534' FSL, 2391' FWL, Sec. 21, T13N, R10E, UM, AK 221-013 Milne Point Field, Schrader Bluff Oil Pool 60.25' 14,495' / 4,140' HOLE SIZE AMOUNT PULLED 33.8' 50-029-23692-00-00 MPU I-27 551834 6009437 2488' FNL, 1314' FWL, Sec. 33, T13N, R10E, UM, AK CEMENTING RECORD 6009906 SETTING DEPTH TVD 6020214 BOTTOM TOP Surface Surface CASING WT. PER FT.GRADE 26# 551401 552379 TOP SETTING DEPTH MD Surface Per 20 AAC 25.283 (i)(2) attach electronic information 40# 4,789' 1,920' Surface DEPTH SET (MD) 4,164' / 3,802' PACKER SET (MD/TVD) 4,782' 129.5# 47# 147' 1,949' 4,959' Gas-Oil Ratio:Choke Size:Water-Bbl: PRODUCTION TEST Not on Production Date of Test: Flow Tubing Oil-Bbl: suspension, or abandonment, whichever occurs first. Types of logs to be listed include, but are not limited to: mud log, spontaneous potential, gamma ray, caliper, resistivity, porosity, magnetic resonance, dipmeter, formation tester, temperature, cement evaluation, casing collar locator, jewelry, and perforation record. Acronyms may be used. Attach a separate page if necessary N/A 4-1/2" Screen Liner 4/27/2021 4971' - 7717' 3954' - 3995' 8073' - 9322' 4035' - 4042' 9638' - 14464' 4027' - 4138' ROP, AGR, ABG, DGR, EWR, ADR MD & TVD Sr Res EngSr Pet GeoSr Pet Eng Oil-Bbl: Water-Bbl: 4/24/2021 4/14/2021 ADL 025906 & 315848 88-004 1768' / 1758' N/AN/A None 14,497' / 4,140' Form 10-407 Revised 3/2020 Submit within 30 days of Completion, Suspension, or Abandonment By Samantha Carlisle at 12:34 pm, May 24, 2021 GRBDMS HEW 6/7/2021 SFD 5/24/2021 Completion Date 4/29/2021 HEW DSR-5/24/21MGR28JUN2021 Conventional Core(s): Yes No Sidewall Cores: 30. MD TVD 37' 37' 1805' 1785' Top of Productive Interval 4124' 3784' 1317' 1316' 2042' 2008' 3364' 3260' 4064' 3755' 4124' 3784' SB NB 4124' 3784' 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: FORMATION TESTS Permafrost - Top 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. LOT / FIT Data Sheet, Drilling and Completion Reports, Definitive Directional Survey, Csg and Cmt Report, Wellbore Schematic Signature w/Date: 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 at total depth: Ugnu LA3 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 Schrader Bluff NA SV5 SV1 The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). 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 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). Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). 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. 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. 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. Form 10-407 Revised 3/2020 Submit within 30 days of Completion, Suspension, or Abandonment 5.24.2021Digitally 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: 2021.05.24 10:25:00 -08'00' Monty M Myers _____________________________________________________________________________________ Edited By: JNL 5/20/2021 SCHEMATIC Milne Point Unit Well: MPU I-27 Last Completed: 4/29/2021 PTD: 221-013 TD =14,497’(MD) / TD =4,140’(TVD) 4 20” Orig. KB Elev.: 60.25’ / GL Elev.: 33.80’ 7” 6 9 4 7 9-5/8”8 1 2 3 See Screen/ Solid Liner Detail PBTD = 14,495’(MD) / PBTD = 4,140’(TVD) 9-5/8” ‘ES’ Cementer @ 1,967’ MD 5 4-1/2” Shoe @ 14,497’ CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20" Conductor 129.5 / X52 / Weld N/A Surface 147’ N/A 9-5/8" Surface 47 / L-80 / TXP 8.681 Surface 1,949’ 0.0732 9-5/8” Surface 40 / L-80 / TXP 8.835 1,949’ 4,959’ 0.0758 7” Tieback 26 / L-80 / TXP 6.875 Surface 4,789’ 0.0459 4-1/2” Liner 250ђ Screens 13.5 / L-80 / Hyd 625 3.920 4,782’ 14,497’ .0149 TUBING DETAIL 4-1/2" Tubing 12.6 / L-80 / TXP 3.958” Surface 4,796’ 0.0152 OPEN HOLE / CEMENT DETAIL Conductor Driven 20” 12-1/4"Stg 1 Lead – 350 sx / Tail – 400 sx Stg 2 Lead – 114 sx / Tail 270 sx 8-1/2” Cementless Screened Liner WELL INCLINATION DETAIL KOP @ 180’ Max Hole Angle = 94° @ 9,407’ MD TREE & WELLHEAD Tree Cameron 3-1/8" 5M w/ 3-1/8” 5M Cameron Wing Wellhead Cameron 11” 5K w/ 4-1/2” Atlas Bradford TC-II 12.6# top & bottom Tbg Hanger GENERAL WELL INFO API: 50-029-23692-00-00 Completion Date: 4/29/2021 JEWELRY DETAIL No. Top MD Item ID 1 4,089’ Baker Gauge Carrier 3.890” 2 4,096’ Haliburton X-Line Sliding Sleeve 3.790” 3 4,102’ Baker Ported Sub 3.950” 4 4,164’ Baker Premier Packer 3.890” 5 4,234’ XN Nipple, 2.75” ID 3.725” 6 4,766’ WLEG – Bottom @ 4,796’ 3.958” 7 4,782’ SLZXP Liner Top Packer (3,944’ TVD) 6.160” 8 4,803’ 7” H563 x 4.5” TSH 625 XO 3.840” 9 14,495’ Shoe 3.950” 4-1/2”SCREENS LINER DETAIL Jts Top (MD) Top (TVD) Btm (MD) Btm (TVD) 67 4971’ 3954’ 7717’ 3995’ 31 8073’ 4035’ 9322’ 4042’ 118 9638’ 4027’ 14464’ 4138’ CASING AND LEAK-OFF FRACTURE TESTS Well Name:MPU I-27 Date:4/20/2021 Csg Size/Wt/Grade:9.625 40#/47# L-80 Supervisor:Lott / Amend Csg Setting Depth:4,958 3,954 TVD Mud Weight:8.9 ppg LOT / FIT Press =637 psi LOT / FIT =12.00 ppg Hole Depth =4980 md Fluid Pumped=1.1 Bbls Volume Back =0.8 bbls Estimated Pump Output:0.062 Barrels/Stroke LOT / FIT DATA CASING TEST DATA Enter Strokes Enter Pressure Enter Strokes Enter Pressure Here Here Here Here ->238 ->00 ->497 ->230 ->6185 ->6123 ->8284 ->12 341 ->10 373 ->18 554 ->12 455 ->20 633 ->14 515 ->30 1001 ->16 587 ->40 1413 ->19 660 ->50 1839 -> ->60 2279 -> ->65 2518 -> ->69 2700 -> -> -> -> Enter Holding Enter Holding Enter Holding Time Here Pressure Here Time Here Pressure Here ->0660 ->02700 ->1583 ->52685 ->2560 ->10 2677 ->3538 ->15 2670 ->4523 ->20 2664 ->5510 ->25 2659 ->6500 ->30 2653 ->7493 -> ->8484 -> ->9477 -> ->10 471 -> -> -> -> -> -> -> 2 4 6 8 10 12 14 16 19 0 2 6 12 18 20 30 40 50 60 65 69 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 3100 3200 3300 3400 3500 3600 3700 3800 3900 4000 0 1020304050607080Pressure (psi)Strokes (# of) LOT / FIT DATA CASING TEST DATA 660 583560538523510500493484477471 2700 2685 2677 2670 2664 2659 2653 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 3100 3200 3300 3400 3500 3600 3700 3800 3900 4000 0 5 10 15 20 25 30Pressure (psi)Time (Minutes) LOT / FIT DATA CASING TEST DATA Activity Date Ops Summary 4/14/2021 Finish installing diverter line W/ crane. Fix Hydraulic C/O filter on top drive. Take on spud mud to pits. SIMOPS clean water tank. Rig accepted at 09:00. PJSM Perform Diverter test. Annular close 12 sec, knife open at 10 sec. Draw down Initial Accum 3,000 psi, final 1,950 psi, 200 psi 15 sec full 57 sec. 6 bottle Nitrogen avg 2,366 psi. Tag fill at 37' MD. Test H2S 10-20 ppm, LEL 20-40%, PVT high/ low level alarms. Checked PVT sensors and return flow Witnessed waived by AOGCC Matt Herrera. PJSM Install mouse hole in rotary table and close bag. P/U M/U 190 jnts (95 stands) 5" 19.5# S-135 NC50 D.P. racking back in derrick. (drift 3.125") 9 stands 5" HWDP & Jars. (drift 2.75") L/D mouse hole and install short mouse hole. Install koomey lines. to knife valve. High line power at 10:30. PJSM Service rig. Grease crown, blocks, top drive, wash pipe, Iron Roughneck and handling Equip. Check welds on cradle, good. Check top drive oil. PJSM Stage TM, DM, GWD, X/O's and lift sub on rig floor. C/U Elevators. R/U tongs. Held Pre Spud meeting with all parties. Discuss broaching, well control, rig evacuation, gas hydrates and muster area. Informed pad ops of operations. P/U M/U 12.25" Kymera Bit 3 X 14, 3 X 13 jets (0.8399 TFA) 8" TerraForce 4/5 5.3 stage 1.5° Motor and 1 stand 5" HWDP. PJSM Prime MP W/ H2O and fill hole. Check for leaks, good. PT mud lines and Geo Span to 3,000 PSI, good, Tag at 37' MD. Swap to 8.8 ppg Spud Mud, Clean out 20" Conductor to 147' MD. Cont drilling ahead F/ 147' to 220' MD. 400 GPM, 470 PSI, 40 RPM, TRQ 1K, P/U 45K SLK 46K ROT 45K. WOB 2K. Drill at 125-150 FPH ROP due to flow line intermittent packing off. Vis 270+. PJSM BROOH F/ 220' to 99' MD. 400 GPM 430 PSI 40 RPM TRQ 750 ft/lb. POOH on elevators F/ 99' to surface. Blow down top drive. PJSM Inspect Bit and Motor, good. P/U M/U 8" GWD, 8" DM and 8" EWR-M5 as per Sperry DD & MWD to 87' MD. Perform RFO MWD 4.25 / 8.05 = 190.06°. GWD 6.74 / 8.05 = 304.4° witnessed by Co Rep & Gyro Data. Held Pre Spud meeting at pre tour meeting. PJSM Cont P/U 8" TM to 97'. Download MWD. Cont P/U 8" NM FC and 1 stand 5"49.3# S-135 NC50 HWDP washed down to 220' W/ no fill. PJSM Drill 12.25" Surface F/ 220' to 653' MD ( 653' TVD) Total 432’ (AROP 96’) 400-500 GPM 1,250 PSI, 50 RPM, TRQ on 2-3K, TRQ off 1K, WOB 4-8K. F/O 56% P/U 66K, SLK 70K, ROT 69K. Max Gas 21U. Taking Gyro surveys every stand. Back ream 30'. Jet flow line continuously. Distance to WP 08: 5.78' 5.76' High 0.48' Right Daily Disposal to G&I 114 bbls, total = 114 bbls. Daily Water from 6 mile lake 560 bbls, total = 720 bbls. Daily Metal: 0 lb. Total Metal 0 lb. Daily Mud lost to formation 0 bbls, total = 0 bbls. 4/15/2021 Drill 12.25" Surface F/ 653' to 1352' MD ( 1,350' TVD) Total 697’ (AROP 116’) 500 GPM 1,380 PSI, 50-60 RPM, TRQ on 4K, TRQ off 2K, WOB 6-10K. F/O 56% P/U 79K, SLK 81K, ROT 81K. Max Gas 91U. Taking Gyro surveys every stand. Back ream 30'. Jet flow line continuously. Observe clean survey and quit using GYRO @ 1185' Gyro Depth. SIMOPS process 9.625" Csg in pipe shed. Start 3°/100 build at 1,100' MD. Slide Rot 12.25" Surface F/ 1352' to 1,940' MD ( 1,907' TVD) Total 588,’ (AROP 98’) 500 GPM 1,300 PSI, 50-60 RPM, TRQ on 3-4K, TRQ off 2K, WOB 6-10K. F/O 56% P/U 91K, SLK 90K, ROT 93K. Max Gas 1,531U. T Back ream 60'. Jet flow line continuously. Ended 3°/ 100 build at 1,667' MD. Logged base @ permafrost @ 1,811' MD, 1,790' TVD Slide Rot 12.25" Surface F/ 1,940' to 2,559' MD ( 2,493' TVD) Total 619,’ (AROP 103.2’) 500 GPM 1,470 PSI, 60 RPM, TRQ on 3.5K, TRQ off 2.8K, WOB 5-15K. F/O 57% P/U 102K, SLK 100K, ROT 102K. Max Gas 2,040U. Back ream 60'. Jet flow as needed. Start 4°/ 100 build at 2,300' MD. "Slide Rot 12.25"" Surface F/ 2,559' to 3,080' MD ( 3,007' TVD) Total 521,’ (AROP 86.8’) 500 GPM 1,500 PSI, 60 RPM, TRQ on 5K, TRQ off 4.5K, WOB 4-13K. F/O 56% P/U 118K, SLK 103K, ROT 112K. Max Gas 550U. Back ream 60'. Jet flow as needed. Cont 4°/ 100 build. Rot Hrs 7.55. Slid Hrs 5.48" Distance to WP 06: 14.04' 13.98' High 1.28' Left Daily Disposal to G&I 1140 bbls, total = 1254 bbls. Daily Water from 6 mile lake 960 bbls, total = 1680 bbls. Daily Metal: 0 lb. Total Metal 0 lb. Daily Mud lost to formation 0 bbls, total = 0 bbls. 4/16/2021 Slide Rot 12.25 Surface F/ 3,080' to 3,639' MD ( 3,483' TVD) Total 559,’ (AROP 93’) 500 GPM 1,580 PSI, 80 RPM, TRQ on 7K, TRQ off 6-7K, WOB 8-15K. F/O 56% ECD 9.54. P/U 133K, SLK 107K, ROT 119K. Max Gas 605U. Back ream 60'. Jet flow as needed. Cont 4°/ 100 build Slide Rot 12.25 Surface F/ 3,639' to 4,100' MD ( 3,773' TVD) Total 461,’ (AROP 76.9’) 500 GPM 1,600 PSI, 80 RPM, TRQ on 8.3K, TRQ off 7.5K, WOB 8-18K. F/O 54% ECD 9.48. P/U 138K, SLK 108K, ROT 122K. Max Gas 1646U. Back ream 60'. Jet flow as needed. Cont 4°/ 100 build Slide Rot 12.25 Surface F/ 4,100' to 4,531' MD ( 3,914' TVD) Total 431,’ (AROP 71.9’) 550 GPM 1,900 PSI, 80 RPM, TRQ on 8K, TRQ off 7.5K, WOB 8-18K. F/O 59% ECD 9.95. P/U 138K, SLK 108K, ROT 122K. Max Gas 1816U. Back ream 60'. Jet flow as needed. Cont 4°/ 100 build Slide Rot 12.25 Surface F/ 4,531' to 4,910' MD ( 3,953' TVD) Total 379’ (AROP 63.2’) 550 GPM 2,100 PSI, 80 RPM, TRQ on 9-10K, TRQ off 9K, WOB 9-16K. F/O 59% ECD 10.2. P/U 127K, SLK 95K, ROT 112K. Max Gas 1,356U. Back ream 60'. Jet flow as needed.. End 4°/ 100 build at 4,750' MD and start pump tangent. Crossed Fault1 at ~4,571' MD ~41' DTN. Rot Hrs 14.67. Sld Hrs 10.29 Distance to WP 06: 8.57' 0.30' Low 8.56' Right Daily Disposal to G&I 1202 bbls, total = 2456 bbls. Daily Water from 6 mile lake 1040 bbls, total = 2720 bbls. Daily Metal: 0 lb. Total Metal 0 lb. Daily Mud lost to formation 0 bbls, total = 0 bbls. 4/17/2021 Slide Rot 12.25 Surface F/ 4,910' to TD 4,960' MD ( 3,954' TVD) Total 40’ (AROP 80’) 550 GPM 2,000 PSI, 80 RPM, TRQ on 8.9K, TRQ off 8K, WOB 2-7K. F/O 59% ECD 10.08. P/U 127K, SLK 95K, ROT 112K. Max Gas 1,684U. Back ream 60'. Jet flow as needed. TD called by Geo, BROOH F/ 4,960' to 4,785' MD drilling parameters. ROT & Rec CBU 2X 550 GPM, 1,780 PSI, 60 RPM, TRQ 7K. Pumped 40 bbl Hi Vis sweep 25% increase, 20 bbls late. Max Gas 1,422u. PJSM RIH F/ 4,785' to 4,960' MD. Washed down last 60' no fill. PJSM L/D single joint of stand 67 to alternate gyro surveys. BROOH F/ 4,960' to 3,832' MD. 550 GPM 1,700 PSI 60 RPM 6-8K TRQ pull speed 30-40 ft/min. Max Gas 415u. P/U 109K SLK 144K. PJSM Cont BROOH F/ 3,832' to 1,900' MD. 550 GPM 1,700 PSI 60 RPM 6-8 TRQ pull speed 30-40 ft/min. Performed clean up cycle at 1,900' MD till shakers clean. Max Gas 1,323u. Initial ECD 10.17 to 9.78. Cont BROOH F/ 1,900' to 700' MD 450 GPM 960 PSI 60 RPM 1.3K TRQ pull speed 40 ft/min.P/U 82K SLK 85K. Lost 38 bbls during BROOH. POOH on elevators F/ 700' MD racking back 9 stands of 5" HWDP and Jars. L/D NM DC. Plug in and read MWD tool. L/D remaining BHA as per DD & MWD. Bit Grade 2-2-BT-A-E-I-CT-TD. Clean and clear rig floor. BHA had a lot of clay balled up. Static loss ~2.5 bph lost 11 bbls. PJSM Bring and R/U Weatherford 9 5/8" Csg Equip and M/U top drive to Volant. Install 6' bail extension and 9.625" 250T side door elevators. Verify count 9 5/8" Csg 135 ea and 69 ea Centralizers. Static loss ~2.5 bph. lost 2.5 bbls. PJSM P/U M/U 9.625" 40# L-80 TPC BTC Shoe Jnt Bow Spring Cent 2 ea 10' F/ end, Slick Jnt 1 ea Cent, FC 1 ea Cent, Drop ByPass Baffle witnessed Halliburton and Co Rep. Fill and check floats, good. P/U BFA 1 ea Cent and 1 jnt W/ 1 ea Cent to 208' MD. BakerLoc Shoe Track. TRQ 21K P/U 41K SLK 41K. PJSM Cont RIH 9.625" 40# L-80 TPC BTC F/ 208' to 2,685 ' MD. Running speed 45 ft/min. Fill every Jnt, top off 5th & break Circ every 10 jnts. TRQ 21K. Install Bow Spring Centralizers as per Tally. CBU at 2,009' MD stage up to 6 bpm 90 PSI. P/U 125K SLK 94K. Lost 11 bbls. Crossed Fault1 at 4,571' MD 41' DTN. Rot Hrs 0.89. Sld Hrs 0.51 Distance to WP 06: 4.54' 0.88' Low 4.45' Right Daily Disposal to G&I 1202 bbls, total = 2456 bbls. Daily Water from 6 mile lake 1040 bbls, total = 2720 bbls. Daily Metal: 0 lb. Total Metal 0 lb. Daily Mud lost to formation 0 bbls, total = 0 bbls. 4/14/2021Spud Date: Well Name: Field: County/State: MP I-27 Milne Point Hilcorp Energy Company Composite Report , Alaska 50-029-23692-00-00API #: 4/18/2021 Cont RIH 9.625" 40# L-80 TPC BTC F/ 2,685' to 4952' MD. Running speed 30-45 ft/min. Fill every Jnt, top off 5th & break Circ every 10 jnts. TRQ 21K. Install Bow Spring Centralizers as per Tally. At 4952' P/U and wash down 15' and tag btm @ 4960' w/4 BPM/175 PSI. PU 215K, SO 138K. Circulate and condition mud for Cement Job staging pumps to 250 GPM/370 PSI. Reciprocate 60' rotating 3 RPM/15K Tq PU 211K, SO 140K, Rotate 171K. Shut down Pump. BDTD. M/U cement lines to Valont Swivel. HES PT lines 1000/4000 psi - good. Batch up Tuned Spacer. Pump 1st stage cement job as follows: 60 bbls 10 ppg Tuned spacer w/ 4# red dye & 5 lb/bbl poly flake (1st 10 bbls). Drop bypass plug. 152 bbls 12 ppg Lead cmt, 2.347 yld, 5 bpm, 440 PSI. 87 bbls 15.8 ppg Tail cmt, 1.167 yld, 3 bpm, 430 PSI. Drop shutoff plug. Displace w/ 20 bbls H2O (HES) 5 bpm 360 PSI then turn over to rig. Rig disp w/ 187 bbls 9.4 ppg spud mud, 7 bpm, 400 PSI. HES disp 80 bbls 10.0 ppg spacer, 4 bpm 380 PSI. . Rig disp 77.9 bbls 9.4 ppg spud mud 5 bpm, 906 PSI. Reduced rate last 20 bbls to 3 bpm, FCP 780 PSI. Bump plug Press up to 1300 PSI with 365 bbls actual / 362 bbls calculated. Held pressure for 5 minutes, check floats, good. CIP 15:30 hrs. Full returns throughout job. Pump at 3 bpm Press up to 1800 psi and open Stage Tool. 9.625" Csg shoe at 4958.5' MD 1.5' off bottom. Circulate hole clean staging up to 6 bpm, ICP 1060 psi. Dump all spacer and contaminated cement at surface. Brought 47 bbls green Cmt to surface. Dump total of 235 bbls. Shut down after 6 X BU. Flush flow line & Stack W/ black water work Annular. Cont Circ at 6 bpm, 480 PSI. No losses. SIMOPS Haul excess surface mud away and prep for second stage cement job. PJSM Cont circ and prepping pits and trucks for second stage. Set slips and break out and M/U Volant to ensure functioning correctly. PJSM, Wet lines w/ 5 bbls H2O (HES) Pump 2nd stage cement job as follows: 60 bbls 10 ppg Tuned spacer w/ 4# red dye & 5 lb/bbl poly flake (1st 10 bbls). 295 bbls 10.7 ppg Lead cmt, 2.944 yld, 5 bpm, 712 PSI. 56 bbls 15.8 ppg Tail cmt, 1.169 yld, 3.5 bpm, 484 PSI. Drop closing plug. Displace w/ 20 bbls H2O (HES) 5 bpm 325 PSI then turn over to rig. Rig disp w/ 123.5 bbls / Calc 124.7 bbls 9.3 ppg spud mud, 5 bpm, 873 PSI. Reduced rate last 10 bbls to 3 bpm, FCP 616 PSI. ES Cementer shifted shut at 1,640 PSI. Held pressure for 5 minutes, check floats - good. CIP 04:20 hrs. Full returns throughout job. Saw spacer at surface 60 bbls early. Dumped 255 bbls of green cement. PJSM Flush surface Equip W/ black water. Clean out 9.625" Csg to be cut. Haul off excess surface mud and cleaning pits. Breaking bolts for the Diverter Tee. Daily Disposal to G&I 1281 bbls, total = 3259 bbls. Daily Water from 6 mile lake 710 bbls, total = 4150 bbls. Daily Metal: 0 lb. Total Metal 0 lb. Daily Mud lost to formation 31 bbls, total = 91 bbls. 4/19/2021 PJSM Cont rigging down Diverter Tee. Break bolts on speed head DSA and P/U stack to set 9.625" emergency slips. Set emergency slips as per NOS rep onsite. (WT in slips 140K) Welder cut 9 5/8" Csg. Set stack back down and 4 bolt flange. L/D 15.57' Pup and 18.88' cut joint. PJSM R/D Weatherford Csg tongs, elevators, bail ext and Volant. SIMOPS clean Pits. PJSM P/U & Johnny Whack stack and flush with black water. Function Annular, jet flow line and blow down. L/D Johnny Whacker. PJSM Drain stack and pull riser. Remove knife valve. Unseat speed head & set back down. Rack back stack and pull diverter Tee. SIMOPS Cont cleaning pits. PJSM Dress 9.625" Csg and install lower well head. Test slip lock 3,800 psi for 10 min, good. Install lower test plug and upper well head. PJSM Install 11" X 13.625" DSA. P/U and suspend Beyond RCD head. Remove bell nipple F/ stack and clean bolt holes. Set stack on DSA. Install 11" studs on top of stack. Set RCD on top of stack. Install drip pan and MPD hard lines. Install choke & kill lines. Center and chain off stack. Leave RCD cap in and flood H2O through kill line. PT MPD Equip 250 psi/ 1,250 pdi for 5 min, good. Bleed off remove RCD cap and install riser. SIMOPS Clean pits. PJSM R/U Test Equip. M/U 5" Dart, 5" TIW, side entry to 5" test jnt. Flood stack. Install test sub in top drive. Perform shell test. found 5" Dart leaking. C/O 5" Dart, good shell test. Rebuild 5" Dart. SIMOPS take on 8.8 ppg BaraDril N to pits. PJSM Perform BOP test W/ 5" test Jnt 250/ 3,000 psi 5 min on chart. Test Annular, Mez Kill, Upper and Lower IBOP, 5" TIW, 5" Dart, CMV 4-15, Upper VRB's (2.875" X 5.5") , Kill HCR, Manual Kill. Test H2S 10-20 ppm, LEL 20-40%, PVT high/ low level alarms. Checked PVT sensors and return flow. Witnessed waived by AOGCC Rep Bob Noble. SIMOPS Cont take on 8.8 ppg BaraDril N to pits. PJSM Cont testing BOPE. Testing W/ 5" D.P. Lower VBR's (2.875" X 5.5"), Test W/ 4.5" test Jnt 5" Dart, 2 nd 5" TIW, Annular, Upper & lower VBR's (2.875" X 5.5") Choke HCR & manual, CMV 1-3, Manual & Super Choke 1,600 psi. Koomey draw drown Initial System 3,000 PSI, Manifold 1,400 PSI, Annular 1,400 PSI, after System 1,500 PSI, Man 1,475 PSI, Annular 1,475 PSI. 200 PSI increase 22 Sec, full charge 90 sec. Nitrogen 6 bottle average 2,287 PSI. PJSM Pull test plu and install wear ring (9 1/16" ID 10 3/4" OD 38" Lng) Break down test jnt and L/D. Blow down CM and lines. PJSM P/U RCD and clean clamp due to leaking. Re install, good. PJSM P/U M/U 8.5" Clean Out BHA 8.5" RR SLB XR- CPS Tri (0.7455 TFA) 6.75" Terraforce 1.5° motor, FS and 5" HWDP to 595' MD. Daily Disposal to G&I 1264 bbls, total = 4523 bbls. Daily Water from 6 mile lake 480 bbls, total = 4630 bbls. Daily Metal: 0 lb. Total Metal 0 lb. Daily Mud lost to formation 0 bbls, total = 91 bbls. 4/20/2021 Cont single in hole BHA 2 W/ 5" 19.5# S-135 NC50 F/ 595 to 1,929' MD. Wash down F/ 1,929' to TOC 1,958' MD 3 bpm 130 PSI. Tag 5K 2X. Drill out cement and ES Cementer F/ 1,958' to 1,971' MD. 450 gpm 830 psi 40 rpm trq 2-3K wob 2.5k. Tagged ES on depth 1,969' MD. Chased plug F/ 1,971' to 2,025' MD. Blow down. Cont single in hole BHA 2 W/ 5" 19.5# S-135 NC50 F/ 2,025' to 4,727' MD. Wash down F/ 4,727' to TOC 4,757' MD 450 gpm 1,040 psi 30 rpm 8.5K trq P/U 149k SLK 84K PJS Rot Rec F/ 4,757' to 4,697' MD 450 gpm 900 psi 30 rpm 9K trq adjusting pump rate due clabbered mud. Circ surf to surf. PJSM R/U test Equip. Flood choke manifold and lines. Press test 9.625" Csg to 2,700 psi for 30 min on chart, good. Pump 4.4 bbls bled 4.2 bbls. PJSM Drill cement & Shoe Track F/ 4,757' to 4,960' MD BFA (4,836' MD) , FC (4,877' MD) & Shoe (4,969' MD) on depth. 450 gpm 950 psi 40 rpm trq 9k wob 6k RF 50%. P/U 148k SLK 88K ROT 110k. Dump green cement as per Mud Engineer. Ream through all jewelry 3X no issues. PJSM Displace well to 8.9 ppg BaraDril while drilling 20' of new hole F/ 4,960' to 4,980' MD (3,954' tvd) 450 gpm 950 psi 40 rpm trq 9k wob 6k RF 50%. P/U 148k SLK 88K ROT 110k. SPR's Monitor well 10 min, static. Rack back 1 stand to 4,915' MD. PJSM R/U test Equip. Flood surface lines. Perform FIT 12 emw 637 psi on chart. Pump 1.1 bbls bled 0.8 bbls. Blow down and R/D. PJSM POOH elevators racking back in derrick F/ 4,915' to BHA. No losses. PJSM Rack back 1 stand 5" HWDP & Jars. L/D remaining HWDP. L/D Motor & 8.5" tri Cone Bit. Bit Grade 1-1-WT-A-E-I-NO-BHA. Clean and clear rig floor. PJSM Load rig floor with BHA components. P/U M/U 8.5" PDC SK616M-J1D Bit 6X13 (0.7777 TFA), 8.5" NRP, 7.625" GeoPilot 7600 XL, 6.75" ADR, 8.375" ILS, 6.75" DGR, 6.75" PWD, 6.75" DM, 6.75" TM HOC, 6.75" FS (Plunger/ Non Ported) 8.375" Integral Blade (corrosion ring) 6.65" Filter Sub, 6.75" StartaStar, 8.375" Welded Blade Stab, 6.75" FS (Plunger/ non ported) 2 ea 5" HWDP, 6.75" SLB Jars 7 1 ea 5"HWDP. Total 259.86'. Downloaded as per MWD. Shallow pulse test tools, good. Break in GeoPilot & check new Geo Span, good. PJSM Single in hole 5" 19.5# S- 135 NC50 D.P. F/ 260' to 4,900'' MD. P/U 130K SLK 95K. PJSM Cut and slip drilling line. Hang blocks. Cit 11 wraps (69') Accum 917 TM. 2,895' left on spool. Un hang blocks & calibrate blocks. Daily Disposal to G&I 1078 bbls, total = 5601 bbls. Daily Water from 6 mile lake 330 bbls, total = 4960 bbls. Daily Metal: 4 lb. Total Metal 4 lb. Daily Mud lost to formation 0 bbls, total = 0 bbls. 4/21/2021 PJSM Drain stack, remove grey clamp and pull trip riser. P/U stand and install RCD bearing as per Beyond rep onsite. RIH install bearing and grey clamp as per Beyond rep onsite. Cont RIH F/ Derrick 5" D.P. F/ 4,900' to 4,980' md. Pump through MPD equip and check for leaks, good. Clean ecd 9.61 emw. SPR's 4980' md. Drill 8.5" production hole F/ 4,980' to 5,470' md ( 3,953' tvd) Total 490’ (AROP 122.5’) 500 gpm/ mpd 490, 1,380 psi, 120 rpm, trq on 9-10k, trq off 8-9k, wob 4-10k. ecd 10.06. Max Gas 2429u. p/u 132k, slk 80k, rot 102k. mpd 100% open. Undulating through OA1 - OA 3 as per Geo. Cont 8.5" Production Hole F/ 5,470' to 6,270' MD ( 3,964' TVD) Total 800’ (AROP 133.3’) 500 GPM/ MPD 490, 1,520 PSI, 120 RPM, TRQ on 8-11K, TRQ off 8-9K, WOB 4-12K. ECD 10.4. Max Gas 1869U. P/U 127K, SLK 82K, ROT 97K. MPD 100% open. Back ream 30'. Checked flow at connection W/ MPD, static. Cont 8.5" Production Hole F/ 6,270 to 7,000' MD ( 3,971' TVD) Total 730’ (AROP 121.6’) 500 GPM/ MPD 488, 1,520 PSI, 80-120 RPM, TRQ on 8-11.5K, TRQ off 10-11.5K, WOB 4-14K. ECD 10.24. Max Gas 2462U. P/U 151K, SLK 68K, ROT 99K. MPD 100% open. Back ream 30' Close approach MP J-03 6,470' MD SF 1.09 CC 126'. Check flow at connection W/ MPD, static. Adjusting RPM 80-120 due to surface wobble. Increase ludes F/ 2% to 2.5%. SPR at 6,551' MD. Cont 8.5" Production Hole F/ 7,000' to 7,721' MD ( 3,992' TVD) Total 721’ (AROP 120.2’) 500 GPM/ MPD 485, 1,640 PSI, 120 RPM, TRQ on 8-10K, TRQ off 7-8K, WOB 4-12K. ECD 10.45. Max Gas 2037U. P/U 133K, SLK 79K, ROT 100K. MPD 100% open. Back ream 30'. SPR at 7,506' MD. Distance to WP06: 28.62' 21.71' Low 18.64' Right 13 concretions for a total thickness of 80' (3.0% of the lateral). Total footage OA-1 742', OA-2 346', OA-3 1,584' OA-4 27', OA Total 2,672' Daily Disposal to G&I 684 bbls, total = 6285 bbls. Daily Water from 6 mile lake 680 bbls, total = 5640 bbls. Daily Metal: 5 lb. Total Metal 9 lb. Daily Mud lost to formation 0 bbls, total = 0 bbls. 4/22/2021 Cont drlg 8.5" Production Hole F/ 7721' to 8521' MD ( 4055' TVD) Total 800’ (AROP 134’) 500 GPM, 1840 PSI, 120 RPM, TRQ on 10-12K, TRQ off 10K, WOB 5- 12K. 11.1 EMW. Max Gas 1978u. P/U 146K, S/O 70K, ROT 100K. MPD 100% open. B/R full stands. No losses to formation, 250 max ROP Re-entered OA1 sand @ 7955' MD (~53' DTN throw). Cont drlg 8.5" Production Hole F/ 8521' to 9321' MD ( 4040' TVD) Total 800’ (AROP 134’) 500 GPM, 1950 PSI, 120 RPM, TRQ on 11-13K, TRQ off 12K, WOB 5-18K. 11.3 EMW. Max Gas 1964u. P/U 138K, S/O 62K, ROT 101K. MPD 100% open. B/R full stands. No losses to formation, 250 max ROP Cont 8.5" Production Hole F/ 9,321' to 10,115' MD ( 4,025' TVD) Total 794’ (AROP 132.4’) 500- 550 GPM/ MPD 532, 2,390 PSI, 125 RPM, TRQ on 10- 12K, TRQ off 10-11.5K, WOB 6-16K. ECD 11.58. Max Gas 1950U. P/U 140K, SLK 61K, ROT 99K. MPD 100% open. Back ream 60'. Cont undulate in OA Sand as per Geo, Fault #2 9,326’ MD 43’ DTS. Back in the OA Sand at 9,543’ MD. Dumped and dilute 200 bls at 9,984' MD due to MBT. Adjust flow as shakers allow. Max ROP 250. Cont 8.5" Production Hole F/ 10,115' to 10,747' MD ( 4,035' TVD) Total 632’ (AROP 105’) 500 GPM/ MPD 481, 2,070 PSI, 120 RPM, TRQ on 12-15K, TRQ off 11K, WOB 4-14K. ECD 11.3. Max Gas 1758U. P/U 147K, SLK 50K, ROT 96K. MPD 100% open. Back ream 60'. Max ROP 250. No losses. Slow to 100 FPH F/ 10,145' to 10,295' due to close approach MP J-01 at 10,218' MD SF 0.098 CC 10.74'. Magnetic interference at 10,233' MD. Performed clean up cycle 3X BU initial 11.27 ECD after 11.01 ECD Distance to WP06: 2.02' 2.01' High 0.15' Left Fault #1 7,723' MD 53' DTN, Fault #3 9,326' MD 43' DTS. 25 concretions for a total thickness of 188' (3.4% of the lateral). Total footage OA-1 1,416', OA-2 651', OA-3 2,985' OA-4 27', OA Total 5,052'. Out of zone 530' Daily Disposal to G&I 1028 bbls, total = 7313 bbls. Daily Water from 6 mile lake 900 bbls, total = 6540 bbls. Daily Metal: 5 lb. Total Metal 9 lb. Daily Mud lost to formation 0 bbls, total = 0 bbls. 4/23/2021 Cont 8.5" Production Hole F/ 10747' to 11447' MD ( 4,035' TVD) Total 700’ (AROP 117’) 500 GPM/ MPD 481, 2260 PSI, 120 RPM, TRQ on 13.5K, TRQ off 12K, WOB 6-10K. ECD 11.56. Max Gas 1523u. P/U 155K, SLK N/A, ROT 95K. MPD 100% open. Back ream 60'. Lost dn wt @ 10,700' MD. Max ROP 250. No losses. Cont 8.5" Production Hole F/ 11447' to 12200' MD ( 4,062' TVD) Total 753’ (AROP 125.5’) 500 GPM/ MPD 478, 2380 PSI, 80-120 RPM, TRQ on 13-15K, TRQ off 14-15K, WOB 8-18K. ECD 11.9. Max Gas 1735u. P/U 152K, SLK N/A, ROT 94K. MPD 100% open. Back ream 60'. Max ROP 250. No losses. Cont 8.5" Production Hole F/ 12,200' to 12,720' MD (4,075' TVD) Total 520’ (AROP 86.7’) 500 GPM/ MPD 477, 2,300 PSI, 80-120 RPM, TRQ on 14-15.5K, TRQ off 13.5- 15K, WOB 8-16K. ECD 11.65. Max Gas 1707U. P/U 158K, SLK 35K, ROT 98K. MPD 100% open. Back ream 60' Perform clean up ROP 125 fph F/ 12,200' to 12,400' MD drop F/ 11.91 to 11.18 ECD. Max ROP 225. Cont 8.5" Production Hole F/ 12,720' to 13,226' MD (4,070' TVD) Total 506’ (AROP 84.4’) 475 GPM/ MPD 453, 2,220 PSI, 120 RPM, TRQ on 14-15K, TRQ off 14K, WOB 5-10K. ECD 11.56. Max Gas 1585U. P/U 142K, SLK 35K, ROT 95K. MPD 100% open. Back ream 60' PJSM Rot Rec F/ 13,226' to 13,166' MD Change out MP #2 Pod 1 liner. 257 GPM/ MPD 243 1,075 PSI 120 RPM TRQ 13.5K. Perform clean up ROP 125 fph F/ 12,840' to 13,030' MD drop F/ 11.8 to 11.7 ECD. Adjusting flow rate F/ 500 to 475 GPM & ROP to control ECD's. Max ROP 175 Distance to WP06: 34.63' 34.44' High 3.68' Left Fault #1 7,723' MD 53' DTN, Fault #3 9,326' MD 43' DTS. 38 concretions for a total thickness of 268' (3.3% of the lateral). Total footage OA-1 2,236', OA-2 1,021', OA-3 4,333' OA-4 92', OA Total 7,682'. Out of zone 540' Daily Disposal to G&I 855 bbls, total = 8168 bbls. Daily Water from 6 mile lake 880 bbls, total = 7420 bbls. Daily Metal: 10 lb. Total Metal 19 lb. Daily Mud lost to formation 0 bbls, total = 0 bbls. 4/24/2021 PJSM Cont Change out MP #2 Pod 1 liner. Rot Rec F/ 13,226' to 13,166' MD257 GPM/ MPD 243 1,075 PSI 120 RPM TRQ 13.5K. No losses Cont 8.5" Production Hole F/ 13,226' to 13,670' MD (4,086' TVD) Total 444’ (AROP 80.7’) 475 GPM/ MPD 453, 2,280 PSI, 120 RPM, TRQ on 14-15K, TRQ off 14K, WOB 7- 12K. ECD 11.71. Max Gas 1241U. P/U 148K, SLK 35K, ROT 95K. MPD 100% open. Back ream 60'. Max ROP 175. No losses. Build LCM Pill. Close approach MP I-25i at 13,475' MD CC 120.44' SF 0.891. Cont 8.5" Production Hole F/ 13670' to 14239' MD ( 4,123' TVD) Total 569’ (AROP 94.8’) 475 GPM/ MPD 449, 2280 PSI, 100 RPM, TRQ on 15-16K, TRQ off 15-16K, WOB 5-7K. ECD 12.09. Max Gas 1250u. P/U 163K, SLK 35, ROT 93K. MPD 100% open. Back ream 60'. Max ROP 175. No losses. At 14,239' encountered hard spot WOB 14K and once through encountered 50% losses. Reduced flow rate F/ 470 to 300 GPM / MPD 185 GPM dynamic loss rate 178 bph, 1,200 PSI 80 RPM TRQ 17.1K. W/ 60% returns. Pump 50 bbl 50 ppb (25 ppb ea Baracarb 5 & 25) Cont drill F/ 14,239’ to 14,241’ MD. BROOH stand laying LCM pill in open hole. Reduced pump rate F/ 300 to 250 GPM/ MPD 190 GPM 1,080 PSI 76% returns. Pump 2nd 50 bbl 50 ppb (25 ppb ea Baracarb 5 & 25) 275 GPM/ MPD 201 GPM dynamic loss rate 100 bph 73% returns. Shut down rotary W/ 375 GPM/ MPD 315 GPM 84% returns. Spot LCM pill on bottom. Make connection. Seeing ballooning pumps off. Total lost 306 bbls. Increase BG Baracarb F/ 12 ppb to 17 ppd. Running water at 40-50 bph and off load 220 bbls old mud F/ vac truck. Max Gas 971U. Cont 8.5" Production Hole F/ 14241' to TD 14497' MD ( 4,140' TVD) Total 256’ (AROP 85.3’) 388 GPM/ MPD 246- 326, 1,680 PSI, 80 RPM, TRQ on 15-16K, TRQ off 15-16K, WOB 5-12K. ECD 11.23. Max Gas 970u. P/U 163K, SLK 35, ROT 98K. MPD 100% open. Back ream 20'. Max ROP 150. SPR. Take surveys prior to connections Initial returns after connections 66% increasing to 84% by end of stand drilled down. Dynamic losses ~90 bph slowing to 60 bph while drilling and ballooning at connection. Take final survey at TD 14,497' 4,140' TVD 86.56° Inc 6.38° Az and send GeoPilot to home. Rot Rec F/ 14,497' to 14,435' MD 388 GPM/ MPD 338, 1,620 PSI, 100 RPM, TRQ 15.5K, ECD 11.14. Max Gas 1017u. Pump 40 bbl 8.8 ppg 33 vis & 40 bbl 9.25 ppg 86 vis sweeps. Dynamic loss rate 60 bph. Cont Rot Rec F/ 14,497' to 14,435' MD 380 GPM/ MPD 358, 1,540 PSI, 100 RPM, TRQ 16K, ECD 10.92. Max Gas 1185u. Pump 40 bbl 8.8 ppg 33 vis & 40 bbl 9.25 ppg 86 vis sweeps back 31 bbls late W/ 10% increase. Max Gas first BU 1,185u dropped to 161U BGG. CBU 4X. P/U 176K SLK 35K ROT 105K Dynamic loss slowed F/ 60 to ~25 bph. SIMOPS Prep pits and stage trucks for displacement. Lost 128 bbls. Displace well F/ 9.1 ppg BaraDril to 9.3 ppg QuickDril. Cont Rot Rec F/ 14,497' to 14,435' MD Stage pumps up 350 GPM/ MPD 346, 950 PSI, 100 RPM, TRQ 17-18K, ECD 10.27. BGG 147u. Pump SAPP Train 40 bbl SAPP Pill 20 bbl QuickDrill 3X chase W/ 9.3 ppg QuickDril. Taking returns down drag chain. Distance to WP06: 11.18' 11.06' High 1.62' Right Fault #1 7,723' MD 53' DTN, Fault #3 9,326' MD 43' DTS. 44 concretions for a total thickness of 316' (3.3% of the lateral). Total footage OA- 1 3,202', OA-2 1,120', OA-3 4,585' OA-4 92', OA Total 8,999'. Out of zone 540' Daily Disposal to G&I 684 bbls, total = 7997 bbls. Daily Water from 6 mile lake 1040 bbls, total = 8460 bbls. Daily Metal: 5 lb. Total Metal 24 lb. Daily Mud lost to formation 576 bbls, total = 576 bbls. 4/25/2021 Continue displacing 9.2 Baradril with 9.3 ppg Quikdril brine (lubricated). 350 gpm, 950 psi, 120 rpm, 16k tq, 10.5 ECD. 180k up, No dn wt. Shakers dressed with 200's. 30-50 BPH dynamic loss rate @ 350 gpm flow in. BROOH F/ 14497' - T/ 13542' MD. 350 gpm, 1020 psi, 120 rpm, 15k tq off, 10.5 ECD. 5-15 fpm pulling speed. 26 bph loss rate. BROOH F/ 13542' - T/ 10472' MD. 350-450 gpm, 1000-1300 psi, 75-90% returns, 120 rpm, 15k tq off, Maintain 10.5 ECD max with increased pump rate. 5-35 fpm pulling speed as hole allows. No trouble spots encountered. 59 bbl loss Cont BROOH F/ 10,472' to 7,700' MD. 425-450 GPM/ MPD 410-430, 1,090-1,300 PSI 120 RPM TRQ 9-13K. P/U 138K SLK 75K ROT 107K. Max Gas 670u. Pull speed 8-40 ft/min as hole dictates. Encountered tight spots (Fault #2 9,336' MD) 9,450' to 9,350' MD (Fault 1 7,723' MD) 8,048'to 7,705' ream tight areas. 1.5 BU F/9,336' to 9,096' MD 8 ft/min same parameters ECD F/ 10.62 to 10.23. Max Gas 670u . Lost 76 bbls. Cont BROOH F/ 7,700' to 5,282' MD. 425-450 GPM/410-430 MPD 1,050 PSI 120 RPM TRQ 6K.-7 ECD 10.23 P/U 126K SLK 96K ROT 105K. Max Gas 1739u. Pull speed 8-35 ft/min as hole dictates. Encountered tight spots 7,615' & 5,786' MD ream tight areas. Lost 71 BBls. 1.5 BU F/7,618' to 7,423' 8 ft/min same parameters ECD F/ 10.49 to 10.24. Max Gas 541u. 1.5 BU 5,786' to 5,556' MD 8 ft/min same parameters ECD F/ 10.58 to 10.24. Max Gas 1739u. Encountered intermittent pack off/ pressure spikes F 5,530' to 5,282' MD. Daily Disposal to G&I 2400 bbls, total = 11,252 bbls. Daily Water from 6 mile lake 240 bbls, total = 8700 bbls. Daily Metal: 4 lb. Total Metal 28 lb. Daily Mud lost to formation 332 bbls, total = 908 bbls. 4/26/2021 Continue BROOH F/ 5285' - T/ 4957' MD. 425 gpm, 990 psi, 80-120 rpm, 5k tq, 120k up, 102k dn, 106k rot. Pulled into shoe clean without issue. 5 BPH dynamic loss rate, 2 BPH static loss rate. Circulate and condition mud @ 4957' MD (Rot/Recip). 500 gpm, 1060 psi, 40 rpm, 5k tq. Pump 40 bbl hi vis sweep w/ 10% increase, on time. Obtain passing PST In/Out mud. Shakers screened to 200's. Service rig. Grease traveling equipment. Perform Derrick inspection Monitor well (breathing). Initial rate 4.2 BPH trending down to static over 20 min. Pull RCD bearing and install trip nipple as per Beyond MPD rep. 2-4 BPH static loss rate. Pump dry job, B/D TDS. POOH laying down 5" dp F/ 4957' - T/ BHA. L/D HWDP, Flex DC's. L/D HWDP, Flex DC's. Download MWD recorded data. L/D remaining BHA components. Damaged ILS. Bit graded 2,2,BT,A,X,I,WT,TD. PJSM Lay out running order in pipe shed. R/D 5" elevators to 4.5" 125T slip elevators. P/U and R/U Weatherford 4.5" handling Equip. R/U double stack power tongs. Static loss rate 4 bph. PJSM RIH Innovex Eccentric shoe jnt (2 ea Cent, 4 ea SR) Exclude2000 100 Micron Screens ( 1ea Cent, 2 ea SR) W/ 4.5" 13.5# L-80 W625 Liner to 6,940' MD. TRQ 9.6K At 4,935' MD P/U 97K SLK 88K. Calc 35 bbls, Actual 26 bbls lost 9 bbls. C/O Weatherford Power Tongs due to safety latch broke. PJSM Cont RIH 4.5" 13.5# L-80 W625 Liner to F/ 6,940' to 9,689' MD. TRQ 9.6K At 4,935' MD P/U 108K SLK 72K. Calc 15 bbls, Actual 13 bbls lost 2 bbls. PJSM P/U M/U SLZXP 7" X 9.625" Liner Top Packer/Hanger as per Baker rep onsite. HST 7 ea 1/2" 13 shear screws 3,296 PSI, HRD-E 6 ea 1/4" 20 2,856 PSI DG Slips 9 ea 7/16" shear screws. RIH W/ 3 jnts 5" 49.9# NC50 HWDP to 9,814' MD. Break Circ 2 BPM 80 PSI, 4 bpm 285 PSI. P/U 116K SLK 80K SIMOPS L/D Weatherford 4.5" handling Equip & Power Tongs. Load and process 5" HWDP in pipe shed. PJSM Single in hole 4.5" Liner W/ 5" 49.9# NC50 HWDP to F/ 9,814' to 12,502' MD. P/U 187K SLK 135K. Running speed 60 ft/min as hole dictates. Calc 41 bbls actual 32 bbls lost 9 bbls. Daily Disposal to G&I 228 bbls, total = 11,480 bbls. Daily Water from 6 mile lake 80 bbls, total = 8780 bbls. Daily Metal: 0 lb. Total Metal 28 lb. Daily Mud lost to formation 120 bbls, total = 1,028 bbls. 4/27/2021 Continue single in hole 4.5" Liner W/ 5" NC50, S-135, 49.5# HWDP to F/ 12,502' to final depth 14,497' MD (152 total jts / Drift 2.75"). P/U 225K SLK 165K. Running speed 60 ft/min as hole dictates. 12 bbl loss. Tagged btm 2x with 5k set dn @ 14,497' MD. . Break circulation @ 1 bpm, 135 psi. Inc to 3 bpm, 320 psi. Drop 29/32" phenolic setting ball and pump down same 3 bpm decreasing to 2 bpm @ 500 stks. Ball on seat @ 506 stks / 610 stks calc. Psi up to 2700 psi and hold 5 min. Continue psi up to 3500 psi with good shift @ 3210 psi (Set pkr). S/O to 140k then P/U 1' w/ free pipe @ 203' (liner released). PSI up with test pump and shift circ sub / burst sub @ 5000 psi with good pressure drop to zero. TOL @ 4781.85' MD (177' liner lap). R/U and test packer via IA 9-5/8" x 5" DP. 1500 psi w/ 10 min hold, chart and record same. Good test. Bleed off and R/D test equipment. P/U and clear packoff cup on liner running tool. Establish circulation. CBU 1x @ 10 bpm, 895 psi. Monitor well (static). Pump dry job. B/D TDS, choke & kill, choke manifold. Dress floor for laying down drill pipe. Saw 1615u gas @ btms up dropping back to 40u bgg. Grease traveling equipment. Install new hydraulic fittings for elevators and R/U same. Function hydraulic elevators (good). POOH laying down 5" HWDP F/ 4750' to surface. B/O and L/D LRT. Showed circ sub and burst disc blew. 15 bbl loss for trip. LRT showed good indication of proper set. Last drilling report for MPU I-27. Daily Disposal to G&I 0 bbls, total = 11,480 bbls. Daily Water from 6 mile lake 80 bbls, total = 8860 bbls. Daily Metal: 0 lb. Total Metal 28 lb. Daily Mud lost to formation 65 bbls, total = 1,093 bbls. Activity Date Ops Summary 4/27/2021 PJSM P/I M/U 3.5" shoe W/ 8.5" NoGo Assy. RIH 5" D.P. F/ derrick to 4,750' MD. Wash down 2 bpm 70 psi F/ 4,750' to tag TOL at 4,782' MD 7K 2X and see 50 PSI increase. Lost 5 bbls.P/U 112K SLK 103K.,Wash up to 4,760' MD increase pump rate to 11 bpm 350 psi CBU. RF 52% Max Gas 183U. No losses. Pump 20 bbl Dry Job (Inhibited) Blow down. Well static.,PJSM Laid down 140 jnts 5" D.P. F/ derrick to pipe shed. Lost 14 bbls.,PJSM Cont POOH laid down 208 jnts 5" D.P. F/ derrick to pipe shed. L/D NoGo running tool. Found damage on end of 3.5" mule. Looks to have tagged on liner top. Lost 24 bbls.,Drain stack. Pull wear ring and set test plug.,Daily Disposal to G&I 0 bbls, total = 11,480 bbls. Daily Water from 6 mile lake 0 bbls, total = 8860 bbls. Daily Metal: 0 lb. Total Metal 28 lb. Daily Mud lost to formation 42 bbls, total = 1,135 bbls. 4/28/2021 Close blind rams. Bleed down accumulator. C/O top rams from 2-7/8" x 5.5" VBR's to 7" solid body.,Set test plug, floor lines. Test UPR's with 7" test joint 250/3000 psi - good. R/D testing equipment, blow down lines.,Rig up to RIH with 7" tie back string, C/O pipe handling equipment, rig up power tongs. Static loss rate 4.8 BPH. M/U Baker bullet seal assembly. RIH with 7", 26# TXP, L-80 tie back assembly as per tally to NO-GO depth of 4781'. PUW 123K, SOW 107K.,PT seals to 1500 psi to ensure seals are effective - good. Space out tie back string 1.17' off No-Go. M/U hanger and landing joint. Land hanger.,Close annular and pressure up backside to 500 psi, strip out until observe pressure bleed off. Reverse circulate 100 bbls corrosion inhibited brine followed by 70 bbls diesel for freeze protect at 6 bpm, 300 psi. Strip in and land hanger. Remove landing joint. Blow down mud manifold, drain stack.,M/U packoff running tool and pack off. Set packoff. RILDS. Test packoff 500/5000 psi 10 min each - good. PT 9-5/8"x7" annulus to 1000 psi for 30 minutes - good. Pumped 32 gallons, 30 gallons returned. SimOps: Process 4.5" tubing. C/O pipe handling equipment.,Rig up to RIH with 4-1/2" Jet pump completions. Bring cannon clamps to rig floor, Baker job box, rig up clamp tool and pin driver. Bring up TEC wire spool and hange sheave.,RIH with 4-1/2", 12.6#, L-80, 521W jet pump upper completion as per tally to 1240'. TQ connections to 4700 ft-lbs. Install TEC wire on gauge and run cannon clamps every joint for first 10 joints then every other joint. PUW 45K, SOW 45K. Test TEC wire every 1000'.,Cont. to RIH with 4-1/2", 12.6#, L-80, 521W jet pump upper completion as per tally from 1240'. TQ connections to 4700 ft-lbs. Run cannon clamps every other joint, total of 56 cannon clamps. PUW 82K, SOW 69K, 34K on hanger. Test TEC wire every 1000'. M/U hanger and feed TEC wire through. Land tubing at 4795.68'. RILDS.,Rig up and reverse circulate 40 bbls corrosion inhibited fluid at 3 bpm 160 psi..,Daily Disposal to G&I 347 bbls, total = 11,827 bbls. Daily Water from 6 mile lake 80 bbls, total = 8940 bbls. Daily Metal: 0 lb. Total Metal 28 lb. Daily Mud lost to formation 63 bbls, total = 1,156 bbls. 4/29/2021 F/P 4.5"x7" IA w/ 50 bbls diesel @ 3 bpm, 145 ICP, 445 FCP.,Drop 1-7/8" ball and rod (1.20" FN). Psi up on 4.5" tubing 3500 psi (saw packer debris shift and packer set @ 2700 psi). Pressure test tbg 3500 psi w/ 30 min hold. Chart and record same (test good). Bleed tbg dn to 2000 psi. Pressure test IA to 3500 psi w/ 30 min hold (test good). Equalize and bleed IA,Tbg to zero. R/D test equipment.,Set BPV, Flush and drain surface equipment. B/D all lines and prep for N/D. N/D choke and kill lines. Remove drip pan, trip nipple and 4 bolt flanges. Unflange and rack back BOP's on pedestal with RCD head still nippled up. Tear down mud pumps and inspect. Prep pumps and surface equipment for rig move. Clean pits. Load shed 290 jts DP.,Install tree as per Wellhead rep. Test hanger void 500/5000 psi w/ 5/15 min hold (test good). Install CTS and test tree 500/5000 psi with 5/15 min hold (test good). Remove CTS and BPV. Shut all valves and secure well. Install tree cap and gauge. Bridal up for scoping derrick.,Clean cellar. Cont. cleaning pits. Load and tally drill pipe in shed. Freeze protect test pump. Break interconnect lines other than air, steam, water. Scope derrick down. Blow down water and steam. Break apart interconnects. Remove berming around cuttings box. Secure stairs. Set herculite on J-29,NES trucks on location at 00:00. Jack up, hook up and mobilize pipe shed from I pad to J-pad. Set rig mats. Split remaining rig modules on I pad. Mobilize Gen Mod, and mud Mod to J pad and stage. Walk sub base off I-27. Turn sub base and install rear tires. Final report for MP I-27,Daily Disposal to G&I 489 bbls, total = 12,316 bbls. Daily Water from 6 mile lake 160 bbls, total = 9100 bbls. Daily Metal: 0 lb. Total Metal 28 lb. Daily Mud lost to formation 13 bbls, total = 1,169 bbls. 4/14/2021Spud Date: Well Name: Field: County/State: MP I-27 Milne Point Hilcorp Energy Company Composite Report , Alaska 50-029-23692-00-00API #: TD Shoe Depth: PBTD: No. Jts. Returned RKB RKB to BHF RKB to THF Jts. 2 3 71 48 X Yes No X Yes No 6.35 Fluid Description: Liner hanger Info (Make/Model): Liner top Packer?: Yes X No Liner hanger test pressure:X Yes No Centralizer Placement: Preflush (Spacer) Type: Density (ppg) Volume pumped (BBLs) Lead Slurry Type:Sacks: Yield: Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Tail Slurry Type:Sacks: Yield: Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Post Flush (Spacer) Type: Density (ppg) Rate (bpm): Volume: Displacement: Type: Density (ppg) Rate (bpm): Volume (actual / calculated): FCP (psi): Pump used for disp:X Yes No Casing Rotated?X Yes No Reciprocated?X Yes No % Returns during job Cement returns to surface?X Yes No Spacer returns?X Yes No Vol to Surf: Cement In Place At: Date: Estimated TOC: Method Used To Determine TOC: Preflush (Spacer) Type: Density (ppg) Volume pumped (BBLs) Lead Slurry Type:Sacks: Yield: Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Tail Slurry Type:Sacks: Yield: Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Post Flush (Spacer) Type: Density (ppg) Rate (bpm): Volume: Displacement: Type: Density (ppg) Rate (bpm): Volume (actual / calculated): FCP (psi): Pump used for disp:X Yes No Casing Rotated? Yes X No Reciprocated? Yes X No % Returns during job Cement returns to surface?X Yes No Spacer returns?X Yes 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 Float Shoe 10 3/4 288317SECOND STAGE2 4:20 Rotate Csg Recip Csg Ft. Min. PPG9.3 Shoe @ 4958.5 FC @ Top of Liner4,876.04 Floats Held 30 590 302 288 Spud Mud CASING RECORD County State Alaska Supv.J. Lott / O Amend Hilcorp Energy Company CASING & CEMENTING REPORT Lease & Well No.MP I-27 Date Run 17-Apr-21 Setting Depths Component Size Wt. Grade THD Make Length Bottom Top TCP BTC Innovex 1.57 4,958.50 4,956.93 Csg Wt. On Hook:195,000 Type Float Collar:Innovex Conventional No. Hrs to Run:13 9.3 5 1600 10 10.7 61 5 100 775 Bump Plug?FIRST STAGE10Tuned Spacer/ Red Dye 66 15.8 610 3.5 9.3 5 143.5/144.7 367/362 1250 47 1 15.8 87 Bump press Volume Bump Plug? 17:25 4/18/2021 1,967 1967.45 4,958.504,960.00 CEMENTING REPORT Csg Wt. On Slips:140,000 Spud Mud Tuned Spacer/ Red Dye 114 2.94 Stage Collar @ 60 Bump press 100 295 ES Cementer Closure OK 56 12 152 26.30 RKB to CHF Type of Shoe:Innovex Ported Bullnos Casing Crew:Weatherford No. Jts. Delivered 134 No. Jts. Run 121 13 Length Measurements W/O Threads Ftg. Delivered 5,494.00 Ftg. Run 4,961.00 Ftg. Returned 533.00 Ftg. Cut Jt.34.45 Ftg. Balance www.wellez.net WellEz Information Management LLC ver_04818br 3 ArcticCem HGS4000s Type Bow Spring Centralizer Shoe Jnt 2 ea 10 F/ ends, Slick Jnt 1 ea, FC Jnt 1 ea, BFA Jnt 1 ea. Every jnt for 21 Jnts.12 ea every other jnt. 6 ea every third Jnt. 6 before and 6 after ES. 9.625 CSG 9 5/8 40.0 L-80 TCP BTC Tenaris 79.64 4,956.93 4,877.29 Float Collar 10 3/4 TCP BTC Innovex 1.25 4,877.29 4,876.04 9.625 CSG 9 5/8 40.0 L-80 TCP BTC Tenaris 40.02 4,876.04 4,836.02 Baffle Adapter 10 3/4 TCP BTC Halliburton 1.31 4,836.02 4,834.71 9.625 CSG 9 5/8 40.0 L-80 TCP BTC Tenaris 2,845.32 4,834.71 1,989.39 Pup 9 5/8 40.0 L-80 TCP BTC Tenaris 18.20 1,989.39 1,971.19 ES Cementer 11 3/4 TCP BTC Halliburton 3.74 1,971.19 1,967.45 Pup 9 5/8 40.0 L-80 TCP BTC Tenaris 18.57 1,967.45 1,948.88 9.625 CSG 9 5/8 47.0 L-80 TCP BTC Tenaris 1,958.29 1,948.88 Type I/II 350 2.35 Premium G 400 1.17 5 Premium G 270 1.17 4/19/2021 0 Sped Mud 0 1,967 X X 'HILQLWLYH6XUYH\5HSRUW $SULO +LOFRUS$ODVND//& 0LOQH3RLQW 03W,3DG 038, 3URMHFW &RPSDQ\ /RFDO&RRUGLQDWH5HIHUHQFH 79'5HIHUHQFH 6LWH +LOFRUS$ODVND//& 0LOQH3RLQW 03W,3DG 'HILQLWLYH6XUYH\5HSRUW :HOO :HOOERUH 038, 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helsea Wright Digitally signed by Chelsea Wright Date: 2021.04.26 09:01:55 -08'00' Benjamin Hand Digitally signed by Benjamin Hand Date: 2021.04.26 11:11:00 -08'00' David Douglas Hilcorp Alaska, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or fax to 907 777-8510. Received By: Date: Date: 04/30/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU I-27 (PTD 221-013) FINAL LWD FORMATION EVALUATION LOGS (04/14/2021 to 04/24/2021) •ROP, AGR, DGR, ABG, EWR-M5, ADR, Horizontal Presentation (2” & 5” MD/TVD Color Logs) •Final Definitive Directional Survey SFTP Transfer - Data Folders: Please include current contact information if different from above. PTD: 2210130 E-Set: 35066 Received by the AOGCC 04/30/2021 05/03/2021 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: 04/30/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU I-27 (PTD 221-013) FINAL EOW REPORT – GEOSTEERING LOGS (04/21/2021 to 04/24/2021) SFTP Transfer - Data Folders: Please include current contact information if different from above. PTD: 2210130 E-Set: 35065 Received by the AOGCC 04/30/2021 05/03/2021 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-27 Hilcorp Alaska, LLC Permit to Drill Number: 221-013 Surface Location: 2321' FSL, 3537' FEL, Sec. 33, T13N, R10E, UM, AK Bottomhole Location: 2340' FNL, 2439' FWL, Sec. 21, T13N, R10E, UM, AK Dear Mr. Myers: Enclosed is the approved application for the permit to drill the above referenced 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 February, 2021. y, i 8 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: 14,858' TVD: 4,160' 4a. Location of Well (Governmental Section): 7. Property Designation: Surface: Top of Productive Horizon: 8. DNR Approval Number: 13. Approximate Spud Date: Total Depth: 9. Acres in Property: 14. Distance to Nearest Property: 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 60.1' 15. Distance to Nearest Well Open Surface: x-551834 y- 6009437 Zone-4 33.8' to Same Pool: ~110' 16. Deviated wells: Kickoff depth: 1100 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 91 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD Driven 20" 129.5# X-52 114' Surface Surface 147' 147' 47# L-80 TXP 2,440' Surface Surface 2,440' 2,405' 40# L-80 TXP 2,553' 2,440' 2,405' 4,993' 3,980' Tieback 7-5/8" 29.7# L-80 Hyd 521 4,843' Surface Surface 4,843' 3,968' 8-1/2" 4-1/2" 13.5# L-80 Hyd 625 10,015' 4,843' 3,968' 14,858' 4,160' 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 Cementless Screen Liner Stg 1 L - 259 sx / T - 395 sx12-1/4" 9-5/8"Stg 2 L - 439 sx / T - 268 sx GL / BF Elevation above MSL (ft): Tieback Assy. 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): Authorized Signature: Production Liner Intermediate Surface Conductor/Structural LengthCasing Total Depth MD (ft): Total Depth TVD (ft): Cement Quantity, c.f. or sacks Cement Volume MDSize Plugs (measured): (including stage data) Effect. Depth TVD (ft):Effect. Depth MD (ft): STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 1333 2444' FNL, 1352' FWL, Sec. 33, T13N, R10E, UM, AK 2340' FNL, 2439' FWL, Sec. 21, T13N, R10E, UM, AK 88-004 3840 2,836' MPU I-27 Milne Point Field Schrader Bluff Oil Pool 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 Hilcorp Alaska, LLC 2321' FSL, 3537' FEL, Sec. 33, T13N, R10E, UM, AK ADL 025906 & 315848 022224484 March 24, 2021 Authorized Name: Monty Myers Authorized Title: Drilling Manager Nathan Sperry nathan.sperry@hilcorp.com 777-8450 18. Casing Program: Top - Setting Depth - BottomSpecifications 1725 p Form 10-401 Revised 3/2020 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g) 2.3.2021 By Samantha Carlisle at 9:00 am, Feb 04, 2021 Digitally signed by Monty M Myers DN: cn=Monty M Myers, c=US, o=Hilcorp Alaska, LLC, ou=Technical Services - AK Drilling, email=mmyers@hilcorp.com Reason: I am approving this document Date: 2021.02.03 16:38:42 -09'00' Monty M Myers 221-013 50-029-23692-00-00 1333 DSR-2/4/21 BOPE test to 3000 psi. Annular to 2500 psi. MGR04FEB2021 SFD 2/8/20214FEB2021 2/8/21 2/8/2021 Milne Point Unit (MPU) I-27 Drilling Program Version 2 2/4/2021 Table of Contents 1.0 Well Summary ................................................................................................................................. 2 2.0 Management of Change Information ............................................................................................ 3 3.0 Tubular Program: ........................................................................................................................... 4 4.0 Drill Pipe Information: ................................................................................................................... 4 5.0 Internal Reporting Requirements ................................................................................................. 5 6.0 Planned Wellbore Schematic ......................................................................................................... 6 7.0 Drilling / Completion Summary .................................................................................................... 7 8.0 Mandatory Regulatory Compliance / Notifications ..................................................................... 8 9.0 R/U and Preparatory Work ......................................................................................................... 10 10.0 N/U 13-5/8” 5M 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 .................................................................................................. 27 15.0 Drill 8-1/2” Hole Section ............................................................................................................... 28 16.0 Run 4-1/2” Screened Liner ........................................................................................................... 33 17.0 Run 7-5/8” Tieback ....................................................................................................................... 37 18.0 Run Upper Completion - ESP ...................................................................................................... 40 19.0 Innovation Rig Diverter Schematic ............................................................................................. 42 20.0 Innovation Rig BOP Schematic ................................................................................................... 43 21.0 Wellhead Schematic ...................................................................................................................... 44 22.0 Days Vs Depth ............................................................................................................................... 45 23.0 Formation Tops & Information ................................................................................................... 46 24.0 Anticipated Drilling Hazards ....................................................................................................... 48 25.0 Innovation Rig Layout .................................................................................................................. 51 26.0 FIT Procedure ............................................................................................................................... 52 27.0 Innovation Rig Choke Manifold Schematic ................................................................................ 53 28.0 Casing Design ................................................................................................................................ 54 29.0 8-1/2” Hole Section MASP ........................................................................................................... 55 30.0 Spider Plot (NAD 27) (Governmental Sections) ......................................................................... 56 31.0 Surface Plat (As Built) (NAD 27) ................................................................................................. 57 Page 2 Milne Point Unit I-27 SB Producer Drilling Procedure 1.0 Well Summary Well MPU I-27 Pad Milne Point “I” Pad Planned Completion Type ESP on 3-1/2 tubing Target Reservoir(s) Schrader Bluff OB Sand Planned Well TD, MD / TVD 14,858’ MD / 4,160’ TVD PBTD, MD / TVD 14,858’ MD / 4,160’ TVD Surface Location (Governmental) 2321' FSL, 1743' FWL, Sec 33, T13N, R10E, UM, AK Surface Location (NAD 27) X= 551834, Y= 6009437 Top of Productive Horizon (Governmental) 2444' FNL, 1352' FWL, Sec 33, T13N, R10E, UM, AK TPH Location (NAD 27) X= 551438 Y= 6009950 BHL (Governmental) 2340' FNL, 2439' FWL, Sec 21, T13N, R10E, UM, AK BHL (NAD 27) X= 552423, Y= 6020619 AFE Number AFE Drilling Days 19 AFE Completion Days 3 AFE Drilling Amount AFE Completion Amount AFE Facility Amount Maximum Anticipated Pressure (Surface) 1333 psig Maximum Anticipated Pressure (Downhole/Reservoir) 1725 psig Work String 5” 19.5# S-135 NC 50 Innovation KB Elevation above MSL: 26.3 ft + 33.8 ft = 60.1 ft GL Elevation above MSL: 33.8 ft BOP Equipment 13-5/8” x 5M Annular, (3) ea 13-5/8” x 5M Rams Page 3 Milne Point Unit I-27 SB Producer Drilling Procedure 2.0 Management of Change Information Page 4 Milne Point Unit I-27 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 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” 6.75” 7.947” 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” 3.25” 6.625” 19.5 S-135 DS50 36,100 43,100 560klb 5” 4.276” 3.25” 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-27 SB Producer Drilling Procedure 5.0 Internal Reporting Requirements 5.1 Fill out daily drilling report and cost report on WellEz. x Report covers operations from 6am to 6am x Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left of the data entry area – this will not save the data entered, and will navigate to another data entry. x Ensure time entry adds up to 24 hours total. x Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. x Enter the MD and TVD depths EVERY DAY whether you are making hole or not. 5.2 Afternoon Updates x Submit a short operations update each work day to pmazzolini@hilcorp.com, mmyers@hilcorp, nathan.sperry@hilcorp.com, jengel@hilcorp.com and 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 Joe Engel 907.777.8395 805.235.6265 jengel@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 Rebecca Emerson 907.777.8491 907.590.0648 Rebecca.emerson@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-27 SB Producer Drilling Procedure 6.0 Planned Wellbore Schematic Page 7 Milne Point Unit I-27 SB Producer Drilling Procedure 7.0 Drilling / Completion Summary MPU I-27 is a grassroots producer planned to be drilled in the Schrader Bluff OA sand. I-27 is part of a multi well program targeting the Schrader Bluff sand on I-Pad The directional plan is a catenary well path build, 12-1/4” hole with 9-5/8” surface casing set into the top of the Schrader Bluff OA sand. An 8.5” lateral section will then be drilled. A 4-1/2” liner will be run in the open hole section and the well produced with an ESP assembly. The Innovation Rig will be used to drill and complete the wellbore. Drilling operations are expected to commence approximately March 24, 2021, pending rig schedule. Surface casing will be run to 4,858’ MD / 4,160’ 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 Innovation Rig to well site 2. N/U & Test 13-5/8” Diverter and 16” diverter line 3. Drill 12-1/4” hole to TD of surface hole section. Run and cement 9-5/8” surface casing 4. N/D diverter, N/U 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. N/D BOP, N/U Tree, RDMO Reservoir Evaluation Plan: 1. Surface hole: No mud logging. On Site geologist. LWD: GR + Res 2. Production Hole: No mud logging. On site geologist. LWD: GR + ADR (For geo-steering) 4,993' MD Page 8 Milne Point Unit I-27 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-27. 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-27 SB Producer Drilling Procedure Summary of Innovation BOP Equipment & Test Requirements Hole Section Equipment Test Pressure (psi) 12-1/4” x 13-5/8” 5M CTI Annular BOP w/ 16” diverter line Function Test Only 8-1/2” x 13-5/8” x 5M Control Technology Inc Annular BOP x 13-5/8” x 5M Control Technology Inc Double Gate o Blind ram in btm cavity x Mud cross w/ 3” x 5M side outlets x 13-5/8” x 5M Control Technology Single ram x 3-1/8” x 5M Choke Line x 3-1/8” x 5M Kill line x 3-1/8” x 5M Choke manifold x Standpipe, floor valves, etc Initial Test: 250/3,000 Subsequent Tests: 250/3,000 Primary closing unit: Control Technology Inc. (CTI), 6 station, 3,000 psi, 220 gallon accumulator unit. Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is an electric triplex pump on a different electrical circuit and emergency pressure is provided by bottled nitrogen. The remote closing operator panels are located in the doghouse and on accumulator unit. Required AOGCC Notifications: x Well control event (BOPs utilized to shut in the well to control influx of formation fluids). x 24 hours notice prior to spud. x 24 hours notice prior to testing BOPs. x 24 hours notice prior to casing running & cement operations. x Any other notifications required in APD. Regulatory Contact Information: AOGCC Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email: jim.regg@alaska.gov 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 TestoInspection 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-27 SB Producer Drilling Procedure 9.0 R/U and Preparatory Work 9.1 I-27 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 R/U. 9.6 Rig mat footprint of rig. 9.7 MIRU Innovation. 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 5” liners in mud pumps. x White Star Quattro 1,300 HP mud pumps are rated at 4,097 psi, 381 gpm @ 140 spm @ 96.5% volumetric efficiency. Page 11 Milne Point Unit I-27 SB Producer Drilling Procedure 10.0 N/U 13-5/8” 5M Diverter System 10.1 N/U 13-5/8” CTI BOP stack in diverter configuration (Diverter Schematic attached to program). x N/U 20” x 13-5/8” DSA x N/U 13 5/8”, 5M diverter “T”. x NU Knife gate & 16” diverter line. x Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C). x Diverter line must be 75 ft from nearest ignition source x Place drip berm at the end of diverter line. x Utilized extensions if needed. 10.2 Notify AOGCC. Function test diverter. x Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens prior to annular closure. x Ensure that the annular closes in less than 30 seconds (API Standard 64 3rd edition March 2018 section 12.6.2 for packing element ID less than or equal to 20”) 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-27 SB Producer Drilling Procedure 10.4 Rig & Diverter Orientation: x May change on location Page 13 Milne Point Unit I-27 SB Producer Drilling Procedure 11.0 Drill 12-1/4” Hole Section 11.1 P/U 12-1/4” directional drilling assembly: x Ensure BHA components have been inspected previously. x Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. x 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. x Drill string will be 5” 19.5# S-135. 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 OA 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 deg / 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 minimum at TD (pending MW increase due to hydrates). x Perform wireline gyros / GWD until clean MWD surveys are seen. Take MWD surveys every stand drilled. x Be prepared for gas hydrates. In MPU they have been encountered typically around 2,100- 2,400’ TVD (just below permafrost). Be prepared for hydrates: 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 Page 14 Milne Point Unit I-27 SB Producer Drilling Procedure 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. 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: PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, Toolpusher office, and mud loggers office. x Rheology: Aquagel and Barazan D+ should be used to maintain rheology. Begin system with a 75 YP but reduce this once clays are encountered. Maintain a minimum 25 YP at all times while drilling. Be prepared to increase the YP if hole cleaning becomes an issue. x Fluid Loss: DEXTRID and/or PAC L should be used for filtrate control. Background LCM (10 ppb total) BARACARBs/BAROFIBRE/STEELSEALs can be used in the system while drilling the surface interval to prevent losses and strengthen the wellbore. x Wellbore and mud stability: Additions of CON DET PRE-MIX/DRIL N SLIDE are recommended to reduce the incidence of bit balling and shaker blinding when penetrating the high-clay content sections of the Sagavanirktok and the heavy oil sections of the UGNU 4A. Maintain the pH in the 8.5 – 9.0 range with caustic soda. Daily additions of ALDACIDE G / X-CIDE 207 MUST be made to control bacterial action. x Casing Running: Reduce system YP with DESCO as required for running casing as allowed (do not jeopardize hole conditions). Run casing carefully to minimize surge and swab pressures. Reduce the system rheology once the casing is landed to a YP < 20 (check with the cementers to see what YP value they have targeted). Page 15 Milne Point Unit I-27 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 Concentration Fresh Water soda Ash AQUAGEL caustic soda BARAZAN D+ BAROID 41 PAC-L /DEXTRID LT ALDACIDE G 0.905 bbl 0.5 ppb 15 - 20 ppb 0.1 ppb (8.5 – 9.0 pH) as needed as required for 8.8 – 9.2 ppg if required for <10 FL 0.1 ppb 11.5 At TD; PU 2-3 stands off bottom, CBU, pump tandem sweeps and drop viscosity. 11.6 RIH to bottom, proceed to BROOH to HWDP x Pump at full drill rate (400-600 gpm), and maximize rotation. x Pull slowly, 5 – 10 ft / minute, adjust as dictated by hole conditions x Monitor well for any signs of packing off or losses. x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay balling. x If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until parameters are restored. 11.7 TOOH and LD BHA 11.8 No open hole logging program planned. Page 16 Milne Point Unit I-27 SB Producer Drilling Procedure 12.0 Run 9-5/8” Surface Casing 12.1 R/U and pull wearbushing. 12.2 R/U 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 R/U of CRT if hole conditions require. x R/U a fill up tool to fill casing while running if the CRT is not used. x Ensure all casing has been drifted to 8.75” on the location prior to running. x Top 2,000’ of casing 47# drift 8.525” x Be sure to count the total # of joints on the location before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 12.3 P/U shoe joint, visually verify no debris inside joint. 12.4 Continue M/U & 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 w/ 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 S/N’s of all float equipment and stage tool components. This end up. Bypass Baffle Page 17 Milne Point Unit I-27 SB Producer Drilling Procedure 12.5 Float equipment and Stage tool equipment drawings: Page 18 Milne Point Unit I-27 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 w/ paint brush. x Centralization: x 1 centralizer every joint to ~ 1000’ MD from shoe x 1 centralizer every 2 joints to ~2,000’ above shoe (Top of Lowest Ugnu) x 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 3300 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 Page 19 Milne Point Unit I-27 SB Producer Drilling Procedure Page 20 Milne Point Unit I-27 SB Producer Drilling Procedure 12.8 Continue running 9-5/8” surface casing x Centralizers: 1 centralizer every 3rd joint to 200’ from surface x Fill casing while running using fill up line on rig floor. x Use BOL 2000 thread compound. Dope pin end only w/ paint brush. x Centralization: o 1 centralizer every 2 joints to base of conductor 12.9 The last 2,000’ of 9-5/8” will be 47#, from 2,000’ to Surface x Ensure drifted to 8.525” 2,440' MD 2,440' MD Page 21 Milne Point Unit I-27 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 P/U landing joint and M/U to casing string. Position the casing shoe +/- 10’ from TD. Strap the landing joint prior to the casing job and mark the joint at (1) ft intervals to use as a reference when getting the casing on depth. 12.13 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 M/U water are available to achieve this. If possible reciprocate casing string while conditioning mud. Page 22 Milne Point Unit I-27 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 R/U 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: 259 sx 395 sx Page 23 Milne Point Unit I-27 SB Producer Drilling Procedure Cement Slurry Design (1st Stage Cement Job): 13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Watch reciprocation PU and SO weights, if the hole gets “sticky”, cease pipe reciprocation and continue with the cement job. 13.9 After pumping cement, drop top plug (Shutoff plug) and displace cement with spud mud out of mud pits, spotting water across the HEC stage cementer. x Ensure volumes pumped and volumes returned are documented and constant communication between mud pits, HEC Rep and HES Cementers during the entire job. 13.10 Ensure rig pump is used to displace cement. Displacement calculations have proven to be very accurate using 0.0625 bps (5” liners) for the Quattro pump output. To operate the stage tool hydraulically, the plug must be bumped. 13.11 Displacement calculation: 4,873’ x .0758 bpf = 364.3 bbls 80 bbls of tuned spacer to be left behind stage tool 13.12 Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any point during the job. Be prepared to pump out fluid from cellar. Have black water available to contaminate any cement seen at surface. 13.13 If plug is not bumped at calculated strokes, double check volumes and calculations. Over displace by no more than 50% of shoe track volume, ±4.5 bbls before consulting with Drilling Engineer. 13.14 If plug is not bumped, consult with Drilling Engineer. Ensure the free fall stage tool opening plug is available if needed. This is the back-up option to open the stage tool if the plugs are not bumped. 13.15 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held, this is to ensure the stage tool is not prematurely opened. 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 [(4993' - 120) - 2440) * 0.0758] + (2440 * .0732) = 363.0 bbls Page 24 Milne Point Unit I-27 SB Producer Drilling Procedure 13.16 Increase pressure to 3,300 psi to open circulating ports in stage collar. Slightly higher pressure may be necessary if TOC is above the stage tool. CBU and record any spacer or cement returns to surface and volume pumped to see the returns. Circulate until YP < 20 again in preparation for the 2nd stage of the cement job. 13.17 Be prepared for cement returns to surface. Dump cement returns in the cellar or open the shaker bypass line to the cuttings tank. Have black water available and vac trucks ready to assist. Ensure to flush out any rig components, hard lines and BOP stack that may have come in contact with the cement. Page 25 Milne Point Unit I-27 SB Producer Drilling Procedure Second Stage Surface Cement Job: 13.18 Prepare for the 2nd stage as necessary. Circulate until first stage reaches sufficient compressive strength. Try to maintain flow rate through stage tool until 2nd stage is ready. Hold pre-job safety meeting. x Past wells have seen pressure increase while circulating through stage tool after reduced rate 13.19 HEC representative to witness the loading of the ES cementer closing plug in the cementing head. 13.20 Fill surface lines with water and pressure test. 13.21 Pump remaining 60 bbls 10.5 ppg tuned spacer. 13.22 Mix and pump cmt per below recipe for the 2nd stage. 13.23 Cement volume based on annular volume + open hole excess (200% for lead and 100% for tail). Job will consist of lead & tail, TOC brought to surface. However cement will continue to be pumped until clean spacer is observed at surface. Estimated 2nd Stage Total Cement Volume: Cement Slurry Design (2nd stage cement job): Lead Slurry Tail Slurry System Permafrost L G 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 437 sx 267 sx Page 26 Milne Point Unit I-27 SB Producer Drilling Procedure 13.24 Continue pumping lead until uncontaminated spacer is seen at surface, then switch to tail. 13.25 After pumping cement, drop ES Cementer closing plug and displace cement with spud mud out of mud pits. 13.26 Displacement calculation: 2500’ x .0758 bpf = 190 bbls mud 13.27 Monitor returns closely while displacing cement. Adjust pump rate if necessary. Wellhead side outlet valve in cellar can be opened to take returns to cellar if required. Be prepared to pump out fluid from cellar. Have black water available to retard setting of cement. 13.28 Decide ahead of time what will be done with cement returns once they are at surface. We should circulate approximately 100 - 150 bbls of cement slurry to surface. 13.29 Land closing plug on stage collar and pressure up to 1,000 – 1,500 psi to ensure stage tool closes. Follow instructions of Halliburton personnel. Bleed off pressure and check to ensure stage tool has closed. Slips will be set as per plan to allow full annulus for returns during surface cement job. Set slips 13.30 Make initial cut on 9-5/8” final joint. L/D 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. ((2500 - 2440) * .0758) + (2440 * .0732) = 183.2 bbls Page 27 Milne Point Unit I-27 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 5-1/2” VBRs in top cavity, blind ram in bottom cavity. x Single ram can be dressed with 2-7/8” x 5-1/2” VBRs or 5” solid body rams x NU bell nipple, install flowline. x Install (1) manual valve & HCR valve on kill side of mud cross. (Manual valve closest to mud cross). x Install (1) manual valve on choke side of mud cross. Install an HRC outside of the manual valve 14.3 RU MPD RCD and related equipment 14.4 Run 5” BOP test plug 14.5 Test BOP to 250/3,000 psi for 5/5 min. Test annular to 250/2,500 psi for 5/5 min. x Test with 5” test joint and test VBR’s with 3-1/2” 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 Baradrill-N 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 5” liners in mud pumps. 24 hour notice to AOGCC Page 28 Milne Point Unit I-27 SB Producer Drilling Procedure 15.0 Drill 8-1/2” Hole Section 15.1 MU 8.5” Cleanout BHA (Milltooth Bit & 1.22° PDM) 15.2 TIH w/ 8-1/2” cleanout BHA to stage tool. Note depth TOC tagged on AM report. Drill out stage tool. 15.3 TIH to TOC above the baffle adapter. Note depth TOC tagged on morning report. 15.4 RU and test casing to 2,500 psi / 30 min. Ensure to record volume / pressure (every ¼ bbl) and plot on FIT graph. AOGCC reg is 50% of burst = 5,750 / 2 = ~2,875 psi, but max test pressure on the well is 2,500 psi as per AOGCC. Document incremental volume pumped (and subsequent pressure) and volume returned. Ensure rams are used to test casing as per AOGCC Industry Guidance Bulletin 17-001. 15.5 Drill out shoe track and 20’ of new formation. 15.6 CBU and condition mud for FIT. 15.7 Conduct FIT to 12.0 ppg EMW. Chart Test. Ensure test is recorded on same chart as FIT. Document incremental volume pumped (and subsequent pressure) and volume returned. 15.8 POOH and LD cleanout BHA 15.9 PU 8-1/2” directional BHA. x Ensure BHA components have been inspected previously. x Drift and caliper all components before MU. Visually verify no debris inside components that cannot be drifted. x Ensure TF offset is measured accurately and entered correctly into the MWD software. x Ensure MWD is RU and operational. x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. x Drill string will be 5” 19.5# S-135 DS50 & NC50. x Run a ported float in the production hole section. Schrader Bluff Bit Jetting Recommendation Formation Jetting TFA NB 6 x 14 0.902 OA 6 x 13 0.778 OB 6 x 13 0.778 FIT and casing test digital data to AOGCC. Page 29 Milne Point Unit I-27 SB Producer Drilling Procedure 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 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 > 8.5 (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 Baradrill-N 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 Concentration Water KCL KOH N-VIS DEXTRID LT BARACARB 5 BARACARB 25 BARACARB 50 BARACOR 700 BARASCAV D X-CIDE 207 0.955 bbl 11 ppb 0.1 ppb 1.0 – 1.5 ppb 5 ppb 4 ppb 4 ppb 2 ppb 1.0 ppb 0.5 ppb 0.015 ppb Page 30 Milne Point Unit I-27 SB Producer Drilling Procedure 15.11 TIH with 8-1/2” directional assembly to bottom 15.12 Install MPD RCD 15.13 Displace wellbore to 8.9 ppg Baradrill-N drilling fluid 15.14 Begin drilling 8-1/2” hole section, on-bottom staging technique: x Tag bottom and begin drilling with 100 - 120 rpms at bit. Allow WOB to stabilize at 5-8K. x Slowly begin bringing up rpms, monitoring stick slip and BHA vibrations x If BHA begins to show excessive vibrations / whirl / stick slip, it may be necessary to PU off bottom and restart on bottom staging technique. If stick slip continues, consider adding .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 ft/min, 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 OA 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 OA Concretions: 4-6% Historically x MPD will be utilized to monitor pressure build up on connections. x 8-1/2” Lateral A/C: x J-01/01A/01AL1 is a long term shut-in well. Coil tubing will cement and abandon the lateral prior to drilling I-27. The only risk is damage to the bit. x I-20 WP07 is the principal plan for the I-20 OB lateral to be drilled immediately prior to I-27. I-20 is planned as a Schrader producer. An effort will be made to steer around I-20 but the risk is damage to the bit and lost circulation. Page 31 Milne Point Unit I-27 SB Producer Drilling Procedure 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. 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 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. 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 (same as used on M-16, aiming for an 8 on the 6 RPM reading) - KCl: 7.1bbp for 2% NaCl: 60.9ppg for 9.4ppg Lotorq: 1.5% Lube 776: 1.5% Soda Ash: as needed for 9.5pH Busan 1060: 0.42ppb Flo-Vis Plus: 1.25ppb x Monitor well for loss rate and contact Drilling Engineer and/or Ops Engineer if further discussion needed prior to BROOH. Page 32 Milne Point Unit I-27 SB Producer Drilling Procedure 15.19 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 minimum). 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 backreaming operations are commenced, continue backreaming to the shoe 15.20 If abnormal pressure has been observed in the lateral, utilize MPD to close on connections while BROOH. 15.21 CBU minimum two times at 9-5/8” shoe and clean casing with high vis sweeps. 15.22 Monitor well for flow/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 the well is breathing, treat all flow as an influx until proven otherwise. 15.23 POOH and LD BHA. 15.24 Continue to POOH and stand back BHA if possible. Rabbit DP on TOOH, ensure rabbit diameter is sufficient for future ball drops. Only LWD open hole logs are planned for the hole section (GR + Res). There will not be any additional logging runs conducted. Page 33 Milne Point Unit I-27 SB Producer Drilling Procedure 16.0 Run 4-1/2” Screened Liner 16.1 Well control preparedness: In the event of an influx of formation fluids while running the 4- 1/2” screened liner, the following well control response procedure will be followed: x P/U & M/U 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 M/U and available prior to running the first joint of 4-1/2” Predrilled liner. x Slack off and with 5” DP across the BOP, shut in ram or annular on 5” DP. Close TIW. x Proceed with well kill operations. 16.2 R/U 4-1/2” liner running equipment. x Ensure 4-1/2” 13.5# Hydril 625 x DS-50 crossover is on rig floor and M/U 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 R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 16.3 Run 4-1/2” screened production liner x Use API Modified or “Best O Life 2000 AG” thread compound. Dope pin end only w/ paint brush. Wipe off excess. x Utilize a collar clamp until weight is sufficient to keep slips set properly. x Run round nose float shoe on bottom. x 4-1/2” screened liner will auto –fill x 4-1/2” Liner will be centralized with 1/joint free floating 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 Maximum 4-1/2 8,000 ft-lbs 9,600 ft-lbs 12,800 ft-lbs Page 34 Milne Point Unit I-27 SB Producer Drilling Procedure Page 35 Milne Point Unit I-27 SB Producer Drilling Procedure 16.6. Ensure to run enough liner to provide for approx 150’ overlap inside 9-5/8” casing. Ensure hanger/pkr will not be set in a 9-5/8” connection. x AOGCC regulations require a minimum 100’ overlap between the inner and outer strings as per 20 AAC 25.030(d)(6). Do not place liner hanger/packer across 9-5/8” connection. 16.7. Before picking up Baker SLZXP liner hanger / packer assy, count the # of joints on the pipe deck to make sure it coincides with the pipe tally. 16.8. M/U Baker SLZXP liner top packer to 4-1/2” liner. 16.9. 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. 16.10. RIH with liner on ALL 5” HWDP (if possible) 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. 16.11. 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. 16.12. Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10, & 20 RPM. 16.13. If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensure shoe enters correct hole. 16.14. TIH deeper than planned setting depth. Last motion of the liner should be up to ensure it is set in tension. 16.15. Rig up to pump down the work string with the rig pumps. 16.16. 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 16.17. Prior to setting the hanger and packer, double check all pipe tallies and record amount of drill pipe left on location. Ensure all numbers coincide with proper setting depth of liner hanger. Page 36 Milne Point Unit I-27 SB Producer Drilling Procedure 16.18. Shut down pumps. Drop setting ball (ball seat now located in HRDE setting tool and not at the WIV) down the workstring and pump slowly (1-2 BPM). Slow pump before the ball seats. Do not allow ball to slam into ball seat. 16.19. Continue pressuring up to 2,700 psi to set the SLZXP liner hanger/packer. Hold for 5 minutes. Slack off 20K lbs on the SZXP 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. 16.20. 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. 16.21. PU to neutral weight, close BOP and test annulus to 1,500 psi for 10 minutes charted. 16.22. 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. 16.23. PU pulling running tool free of the packer and displace with at max rate to wash the liner top. Pump sweeps as needed. 16.24. 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. Page 37 Milne Point Unit I-27 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. Install 7-5/8” solid body casing rams in the upper ram cavity. RU testing equipment. PT to 250/3,000 psi with 7-5/8” test joint. RD testing equipment. 17.2 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. 17.3 PU 7-5/8” tieback seal assembly and set in rotary table. Ensure 7-5/8” 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. 17.4 MU first joint of 7-5/8” to seal assy. 17.6 Run 7-5/8”, 29.7#, L-80 HYD 521 tieback to position seal assembly two joints above tieback sleeve. Record PU and SO weights. 7-5/8”, 29.7#, L-80, Hyd 521 = Casing OD Torque (Min) Torque (Opt) Torque (Max) Torque (Yield) 7-5/8” 8,400 ft-lbs 10,100 ft-lbs 14,700 ft-lbs 53,000 ft-lbs Page 38 Milne Point Unit I-27 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. 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. Page 39 Milne Point Unit I-27 SB Producer Drilling Procedure 17.13 Space out with pups as needed to leave the no-go 1 ft 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. 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 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 7-5/8” tieback seal assembly). 17.18 SO and land hanger. Confirm hanger has seated properly in wellhead. Make note of actual weight on hanger on morning report. 17.19 Back out the landing joint. MU packoff running tool and install packoff on bottom of landing joint. Set casing hanger packoff and RILDS. PT void to 3,000 psi for 10 minutes. 17.20 RD casing running tools. 17.21 PT 9-5/8” x 7-5/8” annulus to 1,000 psi for 30 minutes charted. Page 40 Milne Point Unit I-27 SB Producer Drilling Procedure 18.0 Run Upper Completion - ESP 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. 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 at predetermined depth x 10’ 3-1/2” 9.3#, L-80 Pup Joint x 1 joint 3-1/2” 9.3#, L-80 EUE 8rd tubing x 3-1/2” “XN” nipple (2.813” packing bore / 2.75” No-Go ID) x 3 joints 3-1/2” 9.3#, L-80 EUE 8rd tubing x 10’ 3-1/2” 9.3#, L-80 Pup Joint x GLM 3-1/2” x 1” GLM w/ dummy installed x 10’ 3-1/2” 9.3#, L-80 Pup Joint x 3-1/2” 9.3#, L-80 EUE 8rd tubing x 10’ 3-1/2” 9.3#, L-80 Pup Joint x GLM 3-1/2” x 1” w/ SO @ ~140’ MD x 10’ 3-1/2” 9.3#, L-80 Pup Joint x 3 joints 3-1/2” 9.3#, L-80 EUE 8rd tubing x Tubing Hanger o Check the conductivity of electric cable every 2,000’ and every new splice while running in hole. o Use Cannon clamps on every joint to secure the capillary tube. o The MU torque values for 3-1/2” L-80 9.3# EUE 8rd tubing are: Minimum: 2,350 ft-lb, Optimum: 3,100 ft-lb, and maximum: 3,910 ft-lb. o The 3-1/2” L-80 9.3# EUE 8rd tubing performance properties are: Body Yield: 159,000#, Burst: 10,160 psi, Collapse: 10,530 psi. Page 41 Milne Point Unit I-27 SB Producer Drilling Procedure 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 ND BOP. 18.12 NU tree / adapter and tree. Test tubing hanger void to 500/5,000 psi. 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 2,500’ + tubing annulus to 2,500’). 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 250/5,000 psi. 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 Innovation Page 42 Milne Point Unit I-27 SB Producer Drilling Procedure 19.0 Innovation Rig Diverter Schematic Page 43 Milne Point Unit I-27 SB Producer Drilling Procedure 20.0 Innovation Rig BOP Schematic Page 44 Milne Point Unit I-27 SB Producer Drilling Procedure 21.0 Wellhead Schematic Page 45 Milne Point Unit I-27 SB Producer Drilling Procedure 22.0 Days Vs Depth Page 46 Milne Point Unit I-27 SB Producer Drilling Procedure 23.0 Formation Tops & Information Page 47 Milne Point Unit I-27 SB Producer Drilling Procedure Page 48 Milne Point Unit I-27 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 been seen on I Pad on past wells (2002), but recent wells drilled on I pad (2019/2020) have not seen hydrates. 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. 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 ECD’s to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPM’s when CBU, and keep pipe moving to avoid washing out a particular section of the hole. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Anti-Collison: There are no known wells with a clearance factory <1.0. Take directional surveys every stand, take additional surveys if necessary. Continuously monitor proximity to offset wellbores and record any close approaches on AM report. Well Specific A/C: x There are no wells with a clearance factor of <1.0 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. Gas hyrates have been seen on I Pad on past wells Page 49 Milne Point Unit I-27 SB Producer Drilling Procedure H2S: Treat every hole section as though it has the potential for H2S. I-04A had a 36 ppm reading in 2012. The next highest reading was 3.2 ppm on I-15 in 2009. 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 50 Milne Point Unit I-27 SB Producer Drilling Procedure 8-1/2” Hole Section: Hole Cleaning: Maintain rheology of mud system. Sweep hole with low-vis water sweeps. Ensure shakers are set up with appropriate screens to maximize solids removal efficiency. Run centrifuge continuously. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Maintain circulation rate of > 300 gpm Lost Circulation: Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Faulting: There is at least (1) fault that will be crossed while drilling the well. There could be others and the throw of these faults is not well understood at this point in time. When a known fault is coming up, consider the need for a “ramp” in the wellbore to aid in kicking off (low siding) later. H2S: Treat every hole section as though it has the potential for H2S. I-04A had a 36 ppm reading in 2012. The next highest reading was 3.2 ppm on I-15 in 2009. 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. 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 AC: x J-01/01A/01AL1 is a long term shut-in well. Coil tubing will cement and abandon the lateral prior to drilling I-27. The only risk is damage to the bit. x I-20 WP07 is the principal plan for the I-20 OB lateral to be drilled immediately prior to I-27. I-20 is planned as a Schrader producer. An effort will be made to steer around I-20 but the risk is damage to the bit and lost circulation. Page 51 Milne Point Unit I-27 SB Producer Drilling Procedure 25.0 Innovation Rig Layout Page 52 Milne Point Unit I-27 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 53 Milne Point Unit I-27 SB Producer Drilling Procedure 27.0 Innovation Rig Choke Manifold Schematic Page 54 Milne Point Unit I-27 SB Producer Drilling Procedure 28.0 Casing Design Page 55 Milne Point Unit I-27 SB Producer Drilling Procedure 29.0 8-1/2” Hole Section MASP Page 56 Milne Point Unit I-27 SB Producer Drilling Procedure 30.0 Spider Plot (NAD 27) (Governmental Sections) Page 57 Milne Point Unit I-27 SB Producer Drilling Procedure 31.0 Surface Plat (As Built) (NAD 27) 22 January, 2021 Plan: MPU I-27 wp05 Milne Point M Pt I Pad Plan: MPU I-27 MPU I-27 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt I Pad Standard Proposal Report Well: Wellbore: Plan: MPU I-27 MPU I-27 Survey Calculation Method:Minimum Curvature MPU I-27 As-built RKB @ 60.10usft Design:MPU I-27 wp05 Database:NORTH US + CANADA MD Reference:MPU I-27 As-built RKB @ 60.10usft North Reference: Well Plan: MPU I-27 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 5.00 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-27, slot i-21 usft usft 0.00 0.00 6,009,437.370 551,833.690 33.80Wellhead Elevation:0.00 usft0.50 70° 26' 11.496 N 149° 34' 38.610 W Wellbore Declination (°) Field Strength (nT) Sample Date Dip Angle (°) MPU I-27 Model NameMagnetics BGGM2020 4/27/2021 15.57 80.80 57,338.09080511 Phase:Version: Audit Notes: Design MPU I-27 wp05 PLAN Vertical Section: Depth From (TVD) (usft) +N/-S (usft) Direction (°) +E/-W (usft) Tie On Depth:26.30 6.780.000.0026.30 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 0.000.000.000.000.000.0026.300.000.0026.30 -33.80 0.000.000.000.000.000.001,050.000.000.001,050.00 989.90 225.870.003.003.00-46.81-45.411,544.82225.8715.021,550.53 1,484.72 0.000.000.000.00-194.74-188.932,313.20225.8715.022,346.07 2,253.10 138.165.892.984.10-372.691,078.153,953.944.1385.004,693.00 3,893.84 0.000.000.000.00-351.171,376.243,980.094.1385.004,993.00 3,919.99 0.400.034.004.00-340.671,520.923,985.404.1790.815,138.22 3,925.30 0.000.000.000.00-187.853,616.743,955.744.1790.817,239.81 3,895.64 -167.17-0.56-2.442.50-176.333,796.323,960.093.1786.427,419.86 3,899.99 -126.80-2.01-1.502.50-174.363,837.073,962.862.3585.817,460.75 3,902.76 0.000.000.000.00-139.674,682.794,024.902.3585.818,309.45 3,964.80 53.582.011.492.50-110.014,992.004,035.098.6090.448,620.49 3,974.99 44.001.741.802.50-109.284,996.844,035.058.6990.538,625.39 3,974.95 0.000.000.000.0070.776,175.494,024.068.6990.539,817.76 3,963.96 -137.77-1.68-1.852.5086.026,287.794,025.096.7888.439,931.11 3,964.99 0.000.000.000.00667.5111,178.824,160.096.7888.4314,858.43 4,099.99 1/22/2021 5:46:03PM 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 Standard Proposal Report Well: Wellbore: Plan: MPU I-27 MPU I-27 Survey Calculation Method:Minimum Curvature MPU I-27 As-built RKB @ 60.10usft Design:MPU I-27 wp05 Database:NORTH US + CANADA MD Reference:MPU I-27 As-built RKB @ 60.10usft North Reference: Well Plan: MPU I-27 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 -33.80 Vert Section 26.30 0.00 26.30 0.00 0.000.00 551,833.6906,009,437.370-33.80 0.000 0.00 100.00 0.00 100.00 0.00 0.000.00 551,833.6906,009,437.37039.90 0.000 0.00 200.00 0.00 200.00 0.00 0.000.00 551,833.6906,009,437.370139.90 0.000 0.00 300.00 0.00 300.00 0.00 0.000.00 551,833.6906,009,437.370239.90 0.000 0.00 400.00 0.00 400.00 0.00 0.000.00 551,833.6906,009,437.370339.90 0.000 0.00 500.00 0.00 500.00 0.00 0.000.00 551,833.6906,009,437.370439.90 0.000 0.00 600.00 0.00 600.00 0.00 0.000.00 551,833.6906,009,437.370539.90 0.000 0.00 700.00 0.00 700.00 0.00 0.000.00 551,833.6906,009,437.370639.90 0.000 0.00 800.00 0.00 800.00 0.00 0.000.00 551,833.6906,009,437.370739.90 0.000 0.00 900.00 0.00 900.00 0.00 0.000.00 551,833.6906,009,437.370839.90 0.000 0.00 1,000.00 0.00 1,000.00 0.00 0.000.00 551,833.6906,009,437.370939.90 0.000 0.00 1,050.00 0.00 1,050.00 0.00 0.000.00 551,833.6906,009,437.370989.90 0.000 0.00 Start Dir 3º/100' : 1050' MD, 1050'TVD 1,100.00 1.50 1,099.99 -0.46 -0.47225.87 551,833.2236,009,436.9111,039.89 3.000 -0.51 1,200.00 4.50 1,199.85 -4.10 -4.23225.87 551,829.4936,009,433.2421,139.75 3.000 -4.57 1,300.00 7.50 1,299.29 -11.38 -11.73225.87 551,822.0436,009,425.9131,239.19 3.000 -12.68 1,349.32 8.98 1,348.10 -16.30 -16.80225.87 551,817.0056,009,420.9561,288.00 3.000 -18.17 BPRF 1,400.00 10.50 1,398.04 -22.27 -22.95225.87 551,810.8946,009,414.9441,337.94 3.000 -24.82 1,500.00 13.50 1,495.85 -36.74 -37.87225.87 551,796.0766,009,400.3671,435.75 3.000 -40.96 1,550.53 15.02 1,544.82 -45.41 -46.81225.87 551,787.2056,009,391.6401,484.72 3.000 -50.62 End Dir : 1550.53' MD, 1544.82' TVD 1,600.00 15.02 1,592.60 -54.33 -56.01225.87 551,778.0696,009,382.6521,532.50 0.000 -60.57 1,700.00 15.02 1,689.19 -72.38 -74.60225.87 551,759.6026,009,364.4851,629.09 0.000 -80.68 1,800.00 15.02 1,785.77 -90.42 -93.20225.87 551,741.1346,009,346.3171,725.67 0.000 -100.79 1,900.00 15.02 1,882.36 -108.46 -111.79225.87 551,722.6666,009,328.1491,822.26 0.000 -120.90 2,000.00 15.02 1,978.94 -126.50 -130.39225.87 551,704.1986,009,309.9811,918.84 0.000 -141.01 2,037.44 15.02 2,015.10 -133.25 -137.35225.87 551,697.2856,009,303.1801,955.00 0.000 -148.54 SV1 2,100.00 15.02 2,075.53 -144.54 -148.98225.87 551,685.7316,009,291.8132,015.43 0.000 -161.12 2,200.00 15.02 2,172.11 -162.58 -167.58225.87 551,667.2636,009,273.6452,112.01 0.000 -181.23 2,300.00 15.02 2,268.70 -180.62 -186.17225.87 551,648.7956,009,255.4772,208.60 0.000 -201.34 2,346.07 15.02 2,313.20 -188.93 -194.74225.87 551,640.2876,009,247.1072,253.10 0.000 -210.60 Start Dir 4.1º/100' : 2346.07' MD, 2313.2'TVD 2,400.00 13.45 2,365.47 -197.64 -204.71232.22 551,630.3776,009,238.3322,305.37 4.100 -220.43 2,500.00 11.12 2,463.20 -208.35 -222.87248.21 551,612.2996,009,227.4982,403.10 4.100 -233.20 2,600.00 9.99 2,561.55 -211.95 -240.51269.88 551,594.6876,009,223.7762,501.45 4.100 -238.86 2,700.00 10.45 2,660.00 -208.42 -257.54292.99 551,577.6316,009,227.1832,599.90 4.100 -237.37 2,800.00 12.33 2,758.06 -197.79 -273.88311.59 551,561.2176,009,237.7022,697.96 4.100 -228.74 2,900.00 15.10 2,855.22 -180.10 -289.45324.43 551,545.5316,009,255.2792,795.12 4.100 -213.01 3,000.00 18.36 2,950.99 -155.45 -304.15333.10 551,530.6526,009,279.8252,890.89 4.100 -190.27 3,052.02 20.18 3,000.10 -139.91 -311.44336.49 551,523.2576,009,295.3102,940.00 4.100 -175.70 UG_COAL1 3,100.00 21.90 3,044.88 -123.96 -317.93339.13 551,516.6576,009,311.2142,984.78 4.100 -160.63 3,200.00 25.60 3,136.40 -85.80 -330.71343.53 551,503.6176,009,349.2853,076.30 4.100 -124.24 1/22/2021 5:46:03PM 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 Standard Proposal Report Well: Wellbore: Plan: MPU I-27 MPU I-27 Survey Calculation Method:Minimum Curvature MPU I-27 As-built RKB @ 60.10usft Design:MPU I-27 wp05 Database:NORTH US + CANADA MD Reference:MPU I-27 As-built RKB @ 60.10usft North Reference: Well Plan: MPU I-27 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 3,164.99 Vert Section 3,300.00 29.40 3,225.09 -41.15 -342.42346.87 551,491.5996,009,393.8433,164.99 4.100 -81.29 3,400.00 33.27 3,310.49 9.74 -353.00349.50 551,480.6656,009,444.6603,250.39 4.100 -32.00 3,423.58 34.19 3,330.10 22.63 -355.33350.04 551,478.2506,009,457.5293,270.00 4.100 -19.48 LA3 3,500.00 37.18 3,392.16 66.63 -362.40351.63 551,470.8706,009,501.4763,332.06 4.100 23.38 3,600.00 41.12 3,469.70 129.22 -370.57353.41 551,462.2646,009,564.0003,409.60 4.100 84.57 3,700.00 45.09 3,542.69 197.19 -377.47354.94 551,454.8926,009,631.9133,482.59 4.100 151.25 3,717.68 45.79 3,555.10 209.74 -378.56355.18 551,453.7206,009,644.4573,495.00 4.100 163.58 UGNU MB 3,800.00 49.07 3,610.78 270.19 -383.07356.26 551,448.7926,009,704.8663,550.68 4.100 223.08 3,900.00 53.07 3,673.60 347.85 -387.33357.43 551,443.9946,009,782.4873,613.50 4.100 299.69 4,000.00 57.08 3,730.84 429.77 -390.23358.49 551,440.5236,009,864.3773,670.74 4.100 380.70 4,095.66 60.92 3,780.10 511.74 -391.72359.41 551,438.4616,009,946.3273,720.00 4.100 461.92 SB_NA 4,100.00 61.09 3,782.20 515.53 -391.76359.45 551,438.3976,009,950.1183,722.10 4.100 465.68 4,160.03 63.51 3,810.10 568.67 -392.01359.99 551,437.7726,010,003.2523,750.00 4.100 518.42 SB_NB 4,200.00 65.12 3,827.43 604.70 -391.910.34 551,437.6276,010,039.2713,767.33 4.100 554.20 4,300.00 69.14 3,866.28 696.81 -390.681.18 551,438.2166,010,131.3803,806.18 4.100 645.81 4,400.00 73.18 3,898.57 791.40 -388.071.97 551,440.1636,010,225.9723,838.47 4.100 740.05 4,482.32 76.50 3,920.10 870.77 -384.912.59 551,442.7766,010,305.3633,860.00 4.100 819.24 SB_OA (Heel) 4,500.00 77.21 3,924.12 887.97 -384.112.73 551,443.4566,010,322.5653,864.02 4.100 836.42 4,600.00 81.25 3,942.81 986.05 -378.803.46 551,448.0786,010,420.6633,882.71 4.100 934.43 4,625.00 82.25 3,946.40 1,010.74 -377.273.64 551,449.4396,010,445.3643,886.30 4.100 959.13 Fault #1 (40' Throw DTN) 4,693.00 85.00 3,953.94 1,078.16 -372.694.13 551,453.5516,010,512.8063,893.84 4.100 1,026.62 End Dir : 4693' MD, 3953.94' TVD 4,700.00 85.00 3,954.55 1,085.11 -372.194.13 551,454.0046,010,519.7643,894.45 0.000 1,033.58 4,800.00 85.00 3,963.27 1,184.47 -365.024.13 551,460.4886,010,619.1623,903.17 0.000 1,133.10 4,821.01 85.00 3,965.10 1,205.35 -363.514.13 551,461.8506,010,640.0433,905.00 0.000 1,154.00 SB_OA (Heel) 4,900.00 85.00 3,971.98 1,283.83 -357.844.13 551,466.9716,010,718.5613,911.88 0.000 1,232.61 4,993.00 85.00 3,980.09 1,376.24 -351.174.13 551,473.0006,010,811.0023,919.99 0.000 1,325.16 Start Dir 4º/100' : 4993' MD, 3980.09'TVD 4,993.34 85.01 3,980.12 1,376.58 -351.144.13 551,473.0226,010,811.3403,920.02 4.019 1,325.49 9 5/8" x 12 1/4" 5,000.00 85.28 3,980.68 1,383.20 -350.674.13 551,473.4546,010,817.9613,920.58 4.000 1,332.12 5,100.00 89.28 3,985.43 1,482.80 -343.454.16 551,479.9816,010,917.6053,925.33 4.000 1,431.89 5,138.22 90.81 3,985.40 1,520.92 -340.674.17 551,482.4926,010,955.7373,925.30 4.000 1,470.06 End Dir : 5138.22' MD, 3985.4' TVD 5,200.00 90.81 3,984.53 1,582.53 -336.184.17 551,486.5556,011,017.3713,924.43 0.000 1,531.77 5,300.00 90.81 3,983.11 1,682.25 -328.914.17 551,493.1336,011,117.1353,923.01 0.000 1,631.66 5,400.00 90.81 3,981.70 1,781.98 -321.634.17 551,499.7116,011,216.8993,921.60 0.000 1,731.55 5,500.00 90.81 3,980.29 1,881.71 -314.364.17 551,506.2896,011,316.6633,920.19 0.000 1,831.43 1/22/2021 5:46:03PM 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 Standard Proposal Report Well: Wellbore: Plan: MPU I-27 MPU I-27 Survey Calculation Method:Minimum Curvature MPU I-27 As-built RKB @ 60.10usft Design:MPU I-27 wp05 Database:NORTH US + CANADA MD Reference:MPU I-27 As-built RKB @ 60.10usft North Reference: Well Plan: MPU I-27 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 3,918.78 Vert Section 5,600.00 90.81 3,978.88 1,981.43 -307.094.17 551,512.8666,011,416.4263,918.78 0.000 1,931.32 5,700.00 90.81 3,977.47 2,081.16 -299.824.17 551,519.4446,011,516.1903,917.37 0.000 2,031.21 5,800.00 90.81 3,976.06 2,180.88 -292.554.17 551,526.0226,011,615.9543,915.96 0.000 2,131.09 5,900.00 90.81 3,974.65 2,280.61 -285.284.17 551,532.6006,011,715.7183,914.55 0.000 2,230.98 6,000.00 90.81 3,973.24 2,380.33 -278.004.17 551,539.1776,011,815.4813,913.14 0.000 2,330.86 6,100.00 90.81 3,971.82 2,480.06 -270.734.17 551,545.7556,011,915.2453,911.72 0.000 2,430.75 6,200.00 90.81 3,970.41 2,579.78 -263.464.17 551,552.3336,012,015.0093,910.31 0.000 2,530.64 6,300.00 90.81 3,969.00 2,679.51 -256.194.17 551,558.9116,012,114.7733,908.90 0.000 2,630.52 6,400.00 90.81 3,967.59 2,779.23 -248.924.17 551,565.4886,012,214.5363,907.49 0.000 2,730.41 6,500.00 90.81 3,966.18 2,878.96 -241.654.17 551,572.0666,012,314.3003,906.08 0.000 2,830.30 6,600.00 90.81 3,964.77 2,978.68 -234.374.17 551,578.6446,012,414.0643,904.67 0.000 2,930.18 6,700.00 90.81 3,963.36 3,078.41 -227.104.17 551,585.2216,012,513.8273,903.26 0.000 3,030.07 6,800.00 90.81 3,961.94 3,178.13 -219.834.17 551,591.7996,012,613.5913,901.84 0.000 3,129.96 6,900.00 90.81 3,960.53 3,277.86 -212.564.17 551,598.3776,012,713.3553,900.43 0.000 3,229.84 7,000.00 90.81 3,959.12 3,377.58 -205.294.17 551,604.9556,012,813.1193,899.02 0.000 3,329.73 7,100.00 90.81 3,957.71 3,477.31 -198.024.17 551,611.5326,012,912.8823,897.61 0.000 3,429.61 7,200.00 90.81 3,956.30 3,577.03 -190.744.17 551,618.1106,013,012.6463,896.20 0.000 3,529.50 7,239.81 90.81 3,955.74 3,616.74 -187.854.17 551,620.7296,013,052.3623,895.64 0.000 3,569.27 Start Dir 2.5º/100' : 7239.81' MD, 3955.74'TVD 7,300.00 89.34 3,955.66 3,676.78 -183.653.84 551,624.5136,013,112.4253,895.56 2.500 3,629.38 7,400.00 86.90 3,958.93 3,776.52 -177.443.28 551,630.0226,013,212.2023,898.83 2.500 3,729.16 7,419.86 86.42 3,960.09 3,796.32 -176.333.17 551,631.0006,013,232.0003,899.99 2.500 3,748.95 7,460.75 85.81 3,962.86 3,837.07 -174.362.35 551,632.6816,013,272.7593,902.76 2.500 3,789.65 End Dir : 7460.75' MD, 3962.86' TVD 7,500.00 85.81 3,965.73 3,876.18 -172.762.35 551,634.0136,013,311.8783,905.63 0.000 3,828.68 7,600.00 85.81 3,973.04 3,975.83 -168.672.35 551,637.4086,013,411.5433,912.94 0.000 3,928.11 7,700.00 85.81 3,980.35 4,075.47 -164.582.35 551,640.8036,013,511.2083,920.25 0.000 4,027.54 7,800.00 85.81 3,987.66 4,175.12 -160.502.35 551,644.1996,013,610.8733,927.56 0.000 4,126.98 7,900.00 85.81 3,994.97 4,274.77 -156.412.35 551,647.5946,013,710.5383,934.87 0.000 4,226.41 8,000.00 85.81 4,002.28 4,374.42 -152.322.35 551,650.9896,013,810.2033,942.18 0.000 4,325.85 8,100.00 85.81 4,009.59 4,474.07 -148.232.35 551,654.3846,013,909.8683,949.49 0.000 4,425.28 8,200.00 85.81 4,016.90 4,573.72 -144.142.35 551,657.7796,014,009.5333,956.80 0.000 4,524.72 8,309.45 85.81 4,024.90 4,682.78 -139.672.35 551,661.4946,014,118.6163,964.80 0.000 4,633.55 Start Dir 2.5º/100' : 8309.45' MD, 4024.9'TVD 8,400.00 87.15 4,030.46 4,773.01 -134.534.17 551,666.0096,014,208.8683,970.36 2.500 4,723.75 8,500.00 88.64 4,034.13 4,872.53 -125.516.18 551,674.3346,014,308.4353,974.03 2.500 4,823.64 8,600.00 90.13 4,035.19 4,971.73 -113.008.19 551,686.1506,014,407.7113,975.09 2.500 4,923.62 8,620.49 90.44 4,035.09 4,992.00 -110.018.60 551,689.0006,014,428.0003,974.99 2.500 4,944.10 8,625.39 90.53 4,035.05 4,996.84 -109.288.69 551,689.7036,014,432.8483,974.95 2.498 4,949.00 End Dir : 8625.39' MD, 4035.05' TVD 8,700.00 90.53 4,034.36 5,070.59 -98.018.69 551,700.4546,014,506.6693,974.26 0.000 5,023.56 8,800.00 90.53 4,033.44 5,169.44 -82.918.69 551,714.8656,014,605.6113,973.34 0.000 5,123.50 8,900.00 90.53 4,032.52 5,268.29 -67.818.69 551,729.2766,014,704.5533,972.42 0.000 5,223.44 9,000.00 90.53 4,031.60 5,367.14 -52.718.69 551,743.6876,014,803.4953,971.50 0.000 5,323.39 9,100.00 90.53 4,030.67 5,465.99 -37.618.69 551,758.0986,014,902.4383,970.57 0.000 5,423.33 1/22/2021 5:46:03PM 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 Standard Proposal Report Well: Wellbore: Plan: MPU I-27 MPU I-27 Survey Calculation Method:Minimum Curvature MPU I-27 As-built RKB @ 60.10usft Design:MPU I-27 wp05 Database:NORTH US + CANADA MD Reference:MPU I-27 As-built RKB @ 60.10usft North Reference: Well Plan: MPU I-27 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 3,969.65 Vert Section 9,200.00 90.53 4,029.75 5,564.84 -22.518.69 551,772.5096,015,001.3803,969.65 0.000 5,523.27 9,300.00 90.53 4,028.83 5,663.69 -7.418.69 551,786.9206,015,100.3223,968.73 0.000 5,623.21 9,400.00 90.53 4,027.91 5,762.54 7.698.69 551,801.3306,015,199.2643,967.81 0.000 5,723.15 9,500.00 90.53 4,026.99 5,861.39 22.798.69 551,815.7416,015,298.2063,966.89 0.000 5,823.09 9,600.00 90.53 4,026.07 5,960.24 37.898.69 551,830.1526,015,397.1483,965.97 0.000 5,923.03 9,700.00 90.53 4,025.14 6,059.09 52.998.69 551,844.5636,015,496.0903,965.04 0.000 6,022.97 9,800.00 90.53 4,024.22 6,157.93 68.098.69 551,858.9746,015,595.0323,964.12 0.000 6,122.91 9,817.76 90.53 4,024.06 6,175.49 70.778.69 551,861.5336,015,612.6043,963.96 0.000 6,140.66 Start Dir 2.5º/100' : 9817.76' MD, 4024.06'TVD 9,900.00 89.01 4,024.39 6,256.93 82.207.30 551,872.4026,015,694.1103,964.29 2.500 6,222.88 9,931.11 88.43 4,025.09 6,287.79 86.026.78 551,876.0006,015,725.0003,964.99 2.500 6,253.98 End Dir : 9931.11' MD, 4025.09' TVD 10,000.00 88.43 4,026.98 6,356.18 94.156.78 551,883.6546,015,793.4313,966.88 0.000 6,322.84 10,100.00 88.43 4,029.72 6,455.44 105.956.78 551,894.7646,015,892.7643,969.62 0.000 6,422.80 10,200.00 88.43 4,032.46 6,554.70 117.756.78 551,905.8746,015,992.0983,972.36 0.000 6,522.77 10,300.00 88.43 4,035.20 6,653.97 129.556.78 551,916.9846,016,091.4313,975.10 0.000 6,622.73 10,400.00 88.43 4,037.94 6,753.23 141.356.78 551,928.0946,016,190.7643,977.84 0.000 6,722.69 10,500.00 88.43 4,040.68 6,852.49 153.156.78 551,939.2046,016,290.0983,980.58 0.000 6,822.65 10,600.00 88.43 4,043.42 6,951.76 164.966.78 551,950.3146,016,389.4313,983.32 0.000 6,922.62 10,700.00 88.43 4,046.16 7,051.02 176.766.78 551,961.4246,016,488.7643,986.06 0.000 7,022.58 10,800.00 88.43 4,048.90 7,150.28 188.566.78 551,972.5346,016,588.0983,988.80 0.000 7,122.54 10,900.00 88.43 4,051.64 7,249.55 200.366.78 551,983.6446,016,687.4313,991.54 0.000 7,222.50 11,000.00 88.43 4,054.38 7,348.81 212.166.78 551,994.7546,016,786.7653,994.28 0.000 7,322.47 11,100.00 88.43 4,057.12 7,448.07 223.966.78 552,005.8646,016,886.0983,997.02 0.000 7,422.43 11,200.00 88.43 4,059.86 7,547.34 235.766.78 552,016.9746,016,985.4313,999.76 0.000 7,522.39 11,300.00 88.43 4,062.60 7,646.60 247.566.78 552,028.0846,017,084.7654,002.50 0.000 7,622.35 11,400.00 88.43 4,065.33 7,745.86 259.376.78 552,039.1946,017,184.0984,005.23 0.000 7,722.32 11,500.00 88.43 4,068.07 7,845.13 271.176.78 552,050.3046,017,283.4324,007.97 0.000 7,822.28 11,600.00 88.43 4,070.81 7,944.39 282.976.78 552,061.4146,017,382.7654,010.71 0.000 7,922.24 11,700.00 88.43 4,073.55 8,043.65 294.776.78 552,072.5246,017,482.0984,013.45 0.000 8,022.20 11,800.00 88.43 4,076.29 8,142.92 306.576.78 552,083.6346,017,581.4324,016.19 0.000 8,122.17 11,900.00 88.43 4,079.03 8,242.18 318.376.78 552,094.7446,017,680.7654,018.93 0.000 8,222.13 12,000.00 88.43 4,081.77 8,341.44 330.176.78 552,105.8556,017,780.0994,021.67 0.000 8,322.09 12,100.00 88.43 4,084.51 8,440.71 341.976.78 552,116.9656,017,879.4324,024.41 0.000 8,422.05 12,200.00 88.43 4,087.25 8,539.97 353.786.78 552,128.0756,017,978.7654,027.15 0.000 8,522.01 12,300.00 88.43 4,089.99 8,639.23 365.586.78 552,139.1856,018,078.0994,029.89 0.000 8,621.98 12,400.00 88.43 4,092.73 8,738.50 377.386.78 552,150.2956,018,177.4324,032.63 0.000 8,721.94 12,500.00 88.43 4,095.47 8,837.76 389.186.78 552,161.4056,018,276.7664,035.37 0.000 8,821.90 12,600.00 88.43 4,098.21 8,937.02 400.986.78 552,172.5156,018,376.0994,038.11 0.000 8,921.86 12,700.00 88.43 4,100.95 9,036.29 412.786.78 552,183.6256,018,475.4324,040.85 0.000 9,021.83 12,800.00 88.43 4,103.69 9,135.55 424.586.78 552,194.7356,018,574.7664,043.59 0.000 9,121.79 12,900.00 88.43 4,106.43 9,234.81 436.396.78 552,205.8456,018,674.0994,046.33 0.000 9,221.75 13,000.00 88.43 4,109.17 9,334.08 448.196.78 552,216.9556,018,773.4334,049.07 0.000 9,321.71 13,100.00 88.43 4,111.91 9,433.34 459.996.78 552,228.0656,018,872.7664,051.81 0.000 9,421.68 13,200.00 88.43 4,114.65 9,532.60 471.796.78 552,239.1756,018,972.0994,054.55 0.000 9,521.64 1/22/2021 5:46:03PM 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 Standard Proposal Report Well: Wellbore: Plan: MPU I-27 MPU I-27 Survey Calculation Method:Minimum Curvature MPU I-27 As-built RKB @ 60.10usft Design:MPU I-27 wp05 Database:NORTH US + CANADA MD Reference:MPU I-27 As-built RKB @ 60.10usft North Reference: Well Plan: MPU I-27 True Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Map Northing (usft) Map Easting (usft) +N/-S (usft) Planned Survey Vertical Depth (usft) TVDss usft DLS 4,057.29 Vert Section 13,300.00 88.43 4,117.39 9,631.87 483.596.78 552,250.2856,019,071.4334,057.29 0.000 9,621.60 13,400.00 88.43 4,120.13 9,731.13 495.396.78 552,261.3956,019,170.7664,060.03 0.000 9,721.56 13,500.00 88.43 4,122.87 9,830.40 507.196.78 552,272.5056,019,270.0994,062.77 0.000 9,821.53 13,600.00 88.43 4,125.61 9,929.66 518.996.78 552,283.6156,019,369.4334,065.51 0.000 9,921.49 13,700.00 88.43 4,128.35 10,028.92 530.806.78 552,294.7256,019,468.7664,068.25 0.000 10,021.45 13,800.00 88.43 4,131.09 10,128.19 542.606.78 552,305.8356,019,568.1004,070.99 0.000 10,121.41 13,900.00 88.43 4,133.83 10,227.45 554.406.78 552,316.9456,019,667.4334,073.73 0.000 10,221.38 14,000.00 88.43 4,136.57 10,326.71 566.206.78 552,328.0556,019,766.7664,076.47 0.000 10,321.34 14,100.00 88.43 4,139.31 10,425.98 578.006.78 552,339.1656,019,866.1004,079.21 0.000 10,421.30 14,200.00 88.43 4,142.05 10,525.24 589.806.78 552,350.2756,019,965.4334,081.95 0.000 10,521.26 14,300.00 88.43 4,144.79 10,624.50 601.606.78 552,361.3866,020,064.7674,084.69 0.000 10,621.23 14,400.00 88.43 4,147.53 10,723.77 613.406.78 552,372.4966,020,164.1004,087.43 0.000 10,721.19 14,500.00 88.43 4,150.27 10,823.03 625.216.78 552,383.6066,020,263.4334,090.17 0.000 10,821.15 14,600.00 88.43 4,153.01 10,922.29 637.016.78 552,394.7166,020,362.7674,092.91 0.000 10,921.11 14,700.00 88.43 4,155.75 11,021.56 648.816.78 552,405.8266,020,462.1004,095.65 0.000 11,021.08 14,800.00 88.43 4,158.49 11,120.82 660.616.78 552,416.9366,020,561.4344,098.39 0.000 11,121.04 14,858.43 88.43 4,160.09 11,178.82 667.516.78 552,423.4276,020,619.4744,099.99 0.000 11,179.45 Total Depth : 14858.43' MD, 4160.09' TVD - 4 1/2" x 8 1/2" 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-Ft Jackson wp02 Toe 4,160.09 6,020,625.000 552,424.00011,184.34 668.120.00 0.00 - plan misses target center by 5.56usft at 14858.43usft MD (4160.09 TVD, 11178.82 N, 667.51 E) - Point MPI-Ft Jackson wp02 CP2 4,035.09 6,014,428.000 551,689.0004,992.00 -110.010.00 0.00 - plan hits target center - Point MPI-Ft Jackson wp02 CP1 3,960.09 6,013,232.000 551,631.0003,796.32 -176.330.00 0.00 - plan hits target center - Point MPI-Ft Jackson wp02 Heel 3,980.09 6,010,811.000 551,473.0001,376.24 -351.170.00 0.00 - plan hits target center - Circle (radius 30.00) MPI-Ft Jackson wp02 CP3 4,025.09 6,015,725.000 551,876.0006,287.79 86.020.00 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"4,160.0914,858.43 4-1/2 8-1/2 9 5/8" x 12 1/4"3,980.124,993.34 9-5/8 12-1/4 1/22/2021 5:46:03PM 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 Standard Proposal Report Well: Wellbore: Plan: MPU I-27 MPU I-27 Survey Calculation Method:Minimum Curvature MPU I-27 As-built RKB @ 60.10usft Design:MPU I-27 wp05 Database:NORTH US + CANADA MD Reference:MPU I-27 As-built RKB @ 60.10usft North Reference: Well Plan: MPU I-27 True Measured Depth (usft) Vertical Depth (usft) Dip Direction (°)Name Lithology Dip (°) Formations Vertical Depth SS 4,821.01 3,965.10 SB_OA (Heel) 4,095.66 3,780.10 SB_NA 2,037.44 2,015.10 SV1 3,717.68 3,555.10 UGNU MB 4,482.32 3,920.10 SB_OA (Heel) 4,160.03 3,810.10 SB_NB 3,052.02 3,000.10 UG_COAL1 3,423.58 3,330.10 LA3 1,349.32 1,348.10 BPRF Measured Depth (usft) Vertical Depth (usft) +E/-W (usft) +N/-S (usft) Local Coordinates Comment Plan Annotations 1,050.00 1,050.00 0.00 0.00 Start Dir 3º/100' : 1050' MD, 1050'TVD 1,550.53 1,544.82 -45.41 -46.81 End Dir : 1550.53' MD, 1544.82' TVD 2,346.07 2,313.20 -188.93 -194.74 Start Dir 4.1º/100' : 2346.07' MD, 2313.2'TVD 4,625.00 3,946.40 1,010.74 -377.27 Fault #1 (40' Throw DTN) 4,693.00 3,953.94 1,078.16 -372.69 End Dir : 4693' MD, 3953.94' TVD 4,993.00 3,980.09 1,376.24 -351.17 Start Dir 4º/100' : 4993' MD, 3980.09'TVD 5,138.22 3,985.40 1,520.92 -340.67 End Dir : 5138.22' MD, 3985.4' TVD 7,239.81 3,955.74 3,616.74 -187.85 Start Dir 2.5º/100' : 7239.81' MD, 3955.74'TVD 7,460.75 3,962.86 3,837.07 -174.36 End Dir : 7460.75' MD, 3962.86' TVD 8,309.45 4,024.90 4,682.78 -139.67 Start Dir 2.5º/100' : 8309.45' MD, 4024.9'TVD 8,625.39 4,035.05 4,996.84 -109.28 End Dir : 8625.39' MD, 4035.05' TVD 9,817.76 4,024.06 6,175.49 70.77 Start Dir 2.5º/100' : 9817.76' MD, 4024.06'TVD 9,931.11 4,025.09 6,287.79 86.02 End Dir : 9931.11' MD, 4025.09' TVD 14,858.43 4,160.09 11,178.82 667.51 Total Depth : 14858.43' MD, 4160.09' TVD 1/22/2021 5:46:03PM COMPASS 5000.15 Build 91E Page 8 22 January, 2021Milne PointM Pt I PadPlan: MPU I-27MPU I-27MPU I-27 wp05Reference Design: M Pt I Pad - Plan: MPU I-27 - MPU I-27 - MPU I-27 wp05Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Well Coordinates: 6,009,437.37 N, 551,833.69 E (70° 26' 11.50" N, 149° 34' 38.61" W)Datum Height: MPU I-27 As-built RKB @ 60.10usftScan Range: 26.30 to 4,993.00 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 usftGLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of referenceScan Type:Scan Type:25.00 Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU I-27 - MPU I-27 wp05Comparison 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: 26.30 to 4,993.00 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Reference Design: M Pt I Pad - Plan: MPU I-27 - MPU I-27 - MPU I-27 wp05MeasuredDepth(usft)Summary Based on MinimumSeparation WarningM Pt I PadMPI-01 - MPI-01 - MPI-01 53.92 1,198.14 42.46 1,223.87 4.7021,198.14Centre Distance Pass - MPI-01 - MPI-01 - MPI-0153.94 1,201.30 42.45 1,226.70 4.6931,201.30Clearance Factor Pass - MPI-02 - MPI-02 - MPI-02 115.83 1,283.11 103.44 1,317.53 9.3491,283.11Ellipse Separation Pass - MPI-02 - MPI-02 - MPI-02118.12 1,326.30 105.30 1,354.24 9.2101,326.30Clearance Factor Pass - MPI-03 - MPI-03 - MPI-03240.47 1,063.73 230.25 1,087.28 23.5311,063.73Centre Distance Pass - MPI-03 - MPI-03 - MPI-03240.87 1,126.30 230.03 1,143.85 22.2281,126.30Ellipse Separation Pass - MPI-03 - MPI-03 - MPI-03262.06 1,476.30 248.43 1,448.14 19.2241,476.30Clearance Factor Pass - MPI-04 - MPI-04 - MPI-04315.52 1,134.39 304.62 1,156.64 28.9381,134.39Centre Distance Pass - MPI-04 - MPI-04 - MPI-04315.57 1,151.30 304.50 1,172.12 28.5081,151.30Ellipse Separation Pass - MPI-04 - MPI-04 - MPI-041,091.43 4,993.00 1,037.94 4,052.65 20.4014,993.00Clearance Factor Pass - MPI-04 - MPI-04A - MPI-04A315.52 1,134.39 304.62 1,156.64 28.9381,134.39Centre Distance Pass - MPI-04 - MPI-04A - MPI-04A315.57 1,151.30 304.50 1,172.12 28.5081,151.30Ellipse Separation Pass - MPI-04 - MPI-04A - MPI-04A1,091.43 4,993.00 1,037.94 4,052.65 20.4014,993.00Clearance Factor Pass - MPI-04 - MPI-04AL1 - MPI-04AL1315.52 1,134.39 304.62 1,156.64 28.9381,134.39Centre Distance Pass - MPI-04 - MPI-04AL1 - MPI-04AL1315.57 1,151.30 304.50 1,172.12 28.5081,151.30Ellipse Separation Pass - MPI-04 - MPI-04AL1 - MPI-04AL11,091.43 4,993.00 1,037.94 4,052.65 20.4014,993.00Clearance Factor Pass - MPI-04 - MPI-04APB1 - MPI-04APB1315.52 1,134.39 304.62 1,156.64 28.9381,134.39Centre Distance Pass - MPI-04 - MPI-04APB1 - MPI-04APB1 315.57 1,151.30 304.50 1,172.12 28.5081,151.30Ellipse Separation Pass - MPI-04 - MPI-04APB1 - MPI-04APB1 1,091.43 4,993.00 1,037.94 4,052.65 20.4014,993.00Clearance Factor Pass - MPI-04 - MPI-04PB1 - MPI-04PB1315.52 1,134.39 304.62 1,156.64 28.9381,134.39Centre Distance Pass - MPI-04 - MPI-04PB1 - MPI-04PB1315.57 1,151.30 304.50 1,172.12 28.5081,151.30Ellipse Separation Pass - MPI-04 - MPI-04PB1 - MPI-04PB11,091.26 4,993.00 1,039.30 4,032.02 20.9994,993.00Clearance Factor Pass - MPI-05 - MPI-05 - MPI-05 63.15 1,677.52 49.58 1,699.32 4.6531,677.52Ellipse Separation Pass - MPI-05 - MPI-05 - MPI-0564.29 1,701.30 50.30 1,719.88 4.5951,701.30Clearance Factor Pass - MPI-09 - MPI-09 - MPI-09177.36 725.82 170.46 730.07 25.721725.82Centre Distance Pass - MPI-09 - MPI-09 - MPI-09177.48 751.30 170.45 754.09 25.247751.30Ellipse Separation Pass - MPI-09 - MPI-09 - MPI-09194.80 1,026.30 186.12 1,010.17 22.4611,026.30Clearance Factor Pass - MPI-10 - MPI-10 - MPI-10122.48 510.28 117.88 512.72 26.660510.28Centre Distance Pass - 22 January, 2021-17:49COMPASSPage 2 of 8 Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU I-27 - MPU I-27 wp05Comparison 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: 26.30 to 4,993.00 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Reference Design: M Pt I Pad - Plan: MPU I-27 - MPU I-27 - MPU I-27 wp05MeasuredDepth(usft)Summary Based on MinimumSeparation WarningMPI-10 - MPI-10 - MPI-10122.55 526.30 117.82 527.62 25.935526.30Ellipse Separation Pass - MPI-10 - MPI-10 - MPI-10 148.95 1,026.30 140.03 1,011.10 16.7001,026.30Clearance Factor Pass - MPI-15 - MPI-15 - MPI-1564.33 1,085.58 55.47 1,094.42 7.2591,085.58Centre Distance Pass - MPI-15 - MPI-15 - MPI-1564.44 1,101.30 55.42 1,109.44 7.1501,101.30Ellipse Separation Pass - MPI-15 - MPI-15 - MPI-1565.19 1,126.30 55.95 1,132.38 7.0541,126.30Clearance Factor Pass - MPI-15 - MPI-15L1 - MPI-15L164.33 1,085.58 55.47 1,094.42 7.2591,085.58Centre Distance Pass - MPI-15 - MPI-15L1 - MPI-15L164.44 1,101.30 55.42 1,109.44 7.1501,101.30Ellipse Separation Pass - MPI-15 - MPI-15L1 - MPI-15L165.19 1,126.30 55.95 1,132.38 7.0541,126.30Clearance Factor Pass - MPI-15 - MPI-15PB1 - MPI-15PB164.33 1,085.58 55.47 1,094.42 7.2591,085.58Centre Distance Pass - MPI-15 - MPI-15PB1 - MPI-15PB164.44 1,101.30 55.42 1,109.44 7.1501,101.30Ellipse Separation Pass - MPI-15 - MPI-15PB1 - MPI-15PB165.19 1,126.30 55.95 1,132.38 7.0541,126.30Clearance Factor Pass - MPI-16 - MPI-16 - MPI-1674.34 101.30 72.47 109.55 39.707101.30Centre Distance Pass - MPI-16 - MPI-16 - MPI-1674.71 226.30 71.89 234.06 26.465226.30Ellipse Separation Pass - MPI-16 - MPI-16 - MPI-1698.50 701.30 91.63 702.39 14.336701.30Clearance Factor Pass - MPI-17 - MPI-17 - MPI-1742.60 301.30 39.28 309.56 12.802301.30Centre Distance Pass - MPI-17 - MPI-17 - MPI-1742.64 326.30 39.11 334.42 12.067326.30Ellipse Separation Pass - MPI-17 - MPI-17 - MPI-17115.91 2,876.30 93.03 2,928.05 5.0662,876.30Clearance Factor Pass - MPI-17 - MPI-17L1 - MPI-17L142.60 301.30 39.28 309.56 12.802301.30Centre Distance Pass - MPI-17 - MPI-17L1 - MPI-17L142.64 326.30 39.11 334.42 12.067326.30Ellipse Separation Pass - MPI-17 - MPI-17L1 - MPI-17L1115.91 2,876.30 93.03 2,928.05 5.0662,876.30Clearance Factor Pass - MPI-17 - MPI-17L1PB1 - MPI-17L1PB142.60 301.30 39.28 309.56 12.802301.30Centre Distance Pass - MPI-17 - MPI-17L1PB1 - MPI-17L1PB142.64 326.30 39.11 334.42 12.067326.30Ellipse Separation Pass - MPI-17 - MPI-17L1PB1 - MPI-17L1PB1 115.91 2,876.30 93.03 2,928.05 5.0662,876.30Clearance Factor Pass - MPI-17 - MPI-17L2 - MPI-17L242.60 301.30 39.28 309.56 12.802301.30Centre Distance Pass - MPI-17 - MPI-17L2 - MPI-17L242.64 326.30 39.11 334.42 12.067326.30Ellipse Separation Pass - MPI-17 - MPI-17L2 - MPI-17L2115.91 2,876.30 93.03 2,928.05 5.0662,876.30Clearance Factor Pass - MPI-18 - MPI-18 - MPI-1812.48 394.83 8.39 398.00 3.048394.83Centre Distance Pass - MPI-18 - MPI-18 - MPI-1812.60 426.30 8.23 429.41 2.887426.30Ellipse Separation Pass - MPI-18 - MPI-18 - MPI-1813.37 476.30 8.58 479.28 2.791476.30Clearance Factor Pass - MPI-19 - MPI-19 - MPI-1916.07 26.30 14.22 35.30 8.70026.30Ellipse Separation Pass - 22 January, 2021-17:49COMPASSPage 3 of 8 Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU I-27 - MPU I-27 wp05Comparison 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: 26.30 to 4,993.00 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Reference Design: M Pt I Pad - Plan: MPU I-27 - MPU I-27 - MPU I-27 wp05MeasuredDepth(usft)Summary Based on MinimumSeparation WarningMPI-19 - MPI-19 - MPI-1922.27 526.30 16.98 534.85 4.203526.30Clearance Factor Pass - MPI-19 - MPI-19L1 - MPI-19L1 16.07 26.30 14.22 35.30 8.70026.30Ellipse Separation Pass - MPI-19 - MPI-19L1 - MPI-19L122.27 526.30 16.98 534.85 4.203526.30Clearance Factor Pass - MPI-19 - MPI-19PB1 - MPI-19PB116.07 26.30 14.22 35.30 8.70026.30Ellipse Separation Pass - MPI-19 - MPI-19PB1 - MPI-19PB122.27 526.30 16.98 534.85 4.203526.30Clearance Factor Pass - MPI-19 - MPI-19PB2 - MPI-19PB216.07 26.30 14.22 35.30 8.70026.30Ellipse Separation Pass - MPI-19 - MPI-19PB2 - MPI-19PB222.27 526.30 16.98 534.85 4.203526.30Clearance Factor Pass - MPU I-35i - MPU I-35i - MPU I-35i23.55 912.58 16.66 912.87 3.418912.58Centre Distance Pass - MPU I-35i - MPU I-35i - MPU I-35i23.59 926.30 16.61 926.45 3.378926.30Ellipse Separation Pass - MPU I-35i - MPU I-35i - MPU I-35i24.40 976.30 17.07 976.05 3.331976.30Clearance Factor Pass - MPU I-36 - MPU I-36 - MPU I-36144.60 113.33 142.59 113.42 71.794113.33Centre Distance Pass - MPU I-36 - MPU I-36 - MPU I-36145.27 301.30 142.48 300.48 52.027301.30Ellipse Separation Pass - MPU I-36 - MPU I-36 - MPU I-361,119.25 4,993.00 1,069.84 5,217.24 22.6504,993.00Clearance Factor Pass - MPU I-36 - MPU I-36PB1 - MPU I-36PB1144.60 113.33 142.59 113.42 71.794113.33Centre Distance Pass - MPU I-36 - MPU I-36PB1 - MPU I-36PB1145.27 301.30 142.48 300.48 52.027301.30Ellipse Separation Pass - MPU I-36 - MPU I-36PB1 - MPU I-36PB11,119.25 4,993.00 1,069.84 5,217.24 22.6504,993.00Clearance Factor Pass - MPU I-36 - MPU I-36PB2 - MPU I-36PB2144.60 113.33 142.59 113.42 71.794113.33Centre Distance Pass - MPU I-36 - MPU I-36PB2 - MPU I-36PB2145.27 301.30 142.48 300.48 52.027301.30Ellipse Separation Pass - MPU I-36 - MPU I-36PB2 - MPU I-36PB21,119.25 4,993.00 1,069.89 5,217.24 22.6754,993.00Clearance Factor Pass - MPU I-37i - MPU I-37i - MPU I-37i264.12 26.30 262.21 26.65 138.17726.30Centre Distance Pass - MPU I-37i - MPU I-37i - MPU I-37i264.56 226.30 262.10 225.43 107.814226.30Ellipse Separation Pass - MPU I-37i - MPU I-37i - MPU I-37i391.08 1,551.30 381.78 1,459.07 42.0591,551.30Clearance Factor Pass - Plan: MPI-07 - MPI-07 - MPI-07179.70 3,746.56 154.40 3,597.73 7.1023,746.56Centre Distance Pass - Plan: MPI-07 - MPI-07 - MPI-07179.73 3,751.30 154.35 3,600.97 7.0803,751.30Ellipse Separation Pass - Plan: MPI-07 - MPI-07 - MPI-07180.93 3,776.30 155.13 3,617.92 7.0133,776.30Clearance Factor Pass - Plan: MPI-07 - Plan: MPU I-07A - MPU I-07A wp05277.18 1,968.90 263.40 1,950.39 20.1181,968.90Centre Distance Pass - Plan: MPI-07 - Plan: MPU I-07A - MPU I-07A wp05277.20 1,976.30 263.38 1,956.75 20.0561,976.30Ellipse Separation Pass - Plan: MPI-07 - Plan: MPU I-07A - MPU I-07A wp05432.47 4,176.30 399.37 3,827.24 13.0664,176.30Clearance Factor Pass - Plan: MPU I-22 - MPU I-22 - MPU I-22 wp03173.97 327.53 170.96 328.43 57.776327.53Centre Distance Pass - Plan: MPU I-22 - MPU I-22 - MPU I-22 wp03173.99 351.30 170.85 351.72 55.431351.30Ellipse Separation Pass - 22 January, 2021-17:49COMPASSPage 4 of 8 Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU I-27 - MPU I-27 wp05Comparison 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: 26.30 to 4,993.00 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Reference Design: M Pt I Pad - Plan: MPU I-27 - MPU I-27 - MPU I-27 wp05MeasuredDepth(usft)Summary Based on MinimumSeparation WarningPlan: MPU I-22 - MPU I-22 - MPU I-22 wp03292.06 1,501.30 282.47 1,433.41 30.4601,501.30Clearance Factor Pass - Plan: MPU I-23i - MPU I-23i - MPU I-23i wp03 233.70 452.10 230.00 453.00 63.109452.10Centre Distance Pass - Plan: MPU I-23i - MPU I-23i - MPU I-23i wp03233.89 526.30 229.76 525.64 56.678526.30Ellipse Separation Pass - Plan: MPU I-23i - MPU I-23i - MPU I-23i wp03266.18 1,076.30 259.27 1,036.44 38.5581,076.30Clearance Factor Pass - Plan: MPU I-28i - MPU I-28 - MPU I-28i wp0590.09 279.93 87.33 280.13 32.648279.93Centre Distance Pass - Plan: MPU I-28i - MPU I-28 - MPU I-28i wp0590.16 326.30 87.16 326.02 30.027326.30Ellipse Separation Pass - Plan: MPU I-28i - MPU I-28 - MPU I-28i wp05119.55 1,126.30 111.86 1,114.74 15.5461,126.30Clearance Factor Pass - Plan: MPU I-29 - MPU I-29 - MPU I-29 wp03116.41 230.08 113.90 229.88 46.343230.08Centre Distance Pass - Plan: MPU I-29 - MPU I-29 - MPU I-29 wp03116.46 276.30 113.72 275.64 42.505276.30Ellipse Separation Pass - Plan: MPU I-29 - MPU I-29 - MPU I-29 wp03139.13 676.30 134.09 657.43 27.594676.30Clearance Factor Pass - Plan: MPU I-30i - MPU I-30i - MPU I-30i wp04203.95 229.66 201.44 230.56 81.207229.66Centre Distance Pass - Plan: MPU I-30i - MPU I-30i - MPU I-30i wp04204.03 276.30 201.29 275.95 74.462276.30Ellipse Separation Pass - Plan: MPU I-30i - MPU I-30i - MPU I-30i wp04260.42 851.30 254.36 800.00 42.964851.30Clearance Factor Pass - Rig: MPU I-20 - MPU I-20 - MPU I-2030.17 26.30 28.26 26.45 15.78326.30Centre Distance Pass - Rig: MPU I-20 - MPU I-20 - MPU I-2033.61 1,076.30 26.59 1,076.66 4.7881,076.30Ellipse Separation Pass - Rig: MPU I-20 - MPU I-20 - MPU I-20210.90 4,993.00 161.73 4,886.49 4.2904,993.00Clearance Factor Pass - Rig: MPU I-20 - MPU I-20 - MPU I-20 wp0730.17 26.30 28.26 26.50 15.78326.30Centre Distance Pass - Rig: MPU I-20 - MPU I-20 - MPU I-20 wp0733.61 1,076.30 26.59 1,076.71 4.7881,076.30Ellipse Separation Pass - Rig: MPU I-20 - MPU I-20 - MPU I-20 wp07210.90 4,993.00 161.73 4,886.54 4.2904,993.00Clearance Factor Pass - Rig: MPU I-21i - MPU I-21i - MPU I-21i59.65 218.22 57.15 218.33 23.853218.22Centre Distance Pass - Rig: MPU I-21i - MPU I-21i - MPU I-21i60.82 1,276.30 51.01 1,276.75 6.2031,276.30Ellipse Separation Pass - Rig: MPU I-21i - MPU I-21i - MPU I-21i61.28 1,301.30 51.34 1,300.59 6.1691,301.30Clearance Factor Pass - Rig: MPU I-21i - MPU I-21i - MPU I-21i wp12 53.76 1,324.76 43.44 1,324.09 5.2091,324.76Centre Distance Pass - Rig: MPU I-21i - MPU I-21i - MPU I-21i wp1253.76 1,326.30 43.43 1,325.55 5.2051,326.30Ellipse Separation Pass - Rig: MPU I-21i - MPU I-21i - MPU I-21i wp1254.18 1,351.30 43.75 1,349.10 5.1931,351.30Clearance Factor Pass - M Pt J PadMPJ-03 - MPJ-03 - MPJ-031,213.00 4,993.00 1,162.65 5,448.00 24.0914,993.00Clearance Factor Pass - 22 January, 2021-17:49COMPASSPage 5 of 8 Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU I-27 - MPU I-27 wp05Survey tool programFrom(usft)To(usft)Survey/Plan Survey Tool26.30 1,500.00 MPU I-27 wp05 3_Gyro-MWD90+Sag1,500.00 4,993.00 MPU I-27 wp05 3_MWD+IFR2+MS+Sag4,993.00 14,858.43 MPU I-27 wp05 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.22 January, 2021-17:49COMPASSPage 6 of 8 22 January, 2021Milne PointM Pt I PadPlan: MPU I-27MPU I-27MPU I-27 wp05Reference Design: M Pt I Pad - Plan: MPU I-27 - MPU I-27 - MPU I-27 wp05Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Well Coordinates: 6,009,437.37 N, 551,833.69 E (70° 26' 11.50" N, 149° 34' 38.61" W)Datum Height: MPU I-27 As-built RKB @ 60.10usftScan Range: 4,993.00 to 14,858.43 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 usftGLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of referenceScan Type:Scan Type:25.00 Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU I-27 - MPU I-27 wp05Comparison 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: 4,993.00 to 14,858.43 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Reference Design: M Pt I Pad - Plan: MPU I-27 - MPU I-27 - MPU I-27 wp05MeasuredDepth(usft)Summary Based on MinimumSeparation WarningM Pt G PadMPG-14 - MPG-14L1 - MPG-14L1 1,438.24 12,322.78 1,279.26 7,473.68 9.04612,322.78Centre Distance Pass - MPG-14 - MPG-14L1 - MPG-14L11,438.52 12,343.00 1,278.36 7,502.22 8.98212,343.00Ellipse Separation Pass - MPG-14 - MPG-14L1 - MPG-14L1 1,680.58 13,793.00 1,480.13 8,690.48 8.38413,793.00Clearance Factor Pass - MPG-17 - MPG-17 - MPG-171,375.97 8,868.00 1,193.67 6,578.00 7.5488,868.00Clearance Factor Pass - MPG-17 - MPG-17 - MPG-171,137.39 9,593.00 1,025.13 6,578.00 10.1329,593.00Ellipse Separation Pass - MPG-17 - MPG-17 - MPG-171,136.24 9,644.04 1,026.01 6,578.00 10.3089,644.04Centre Distance Pass - M Pt H PadMPH-18 - MPH-18 - MPH-18938.58 8,643.00 688.55 8,629.97 3.7548,643.00Clearance Factor Pass - MPH-18 - MPH-18 - MPH-18933.18 8,668.00 685.23 8,639.00 3.7648,668.00Ellipse Separation Pass - MPH-18 - MPH-18 - MPH-18913.39 8,859.19 711.89 8,639.00 4.5338,859.19Centre Distance Pass - MPH-18 - MPH-18L1 - MPH-18L11,025.61 7,493.00 795.26 7,722.64 4.4527,493.00Clearance Factor Pass - MPH-18 - MPH-18L1 - MPH-18L1912.74 8,818.00 715.34 8,589.18 4.6248,818.00Ellipse Separation Pass - MPH-18 - MPH-18L1 - MPH-18L1912.13 8,851.87 719.03 8,595.00 4.7248,851.87Centre Distance Pass - MPH-18 - MPH-18L2 - MPH-18L2837.88 8,718.00 621.30 8,630.00 3.8698,718.00Clearance Factor Pass - MPH-18 - MPH-18L2 - MPH-18L2 828.59 8,842.43 639.65 8,630.00 4.3868,842.43Centre Distance Pass - M Pt I PadMPI-04 - MPI-04 - MPI-041,087.83 5,113.93 1,031.40 4,121.89 19.2775,113.93Centre Distance Pass - MPI-04 - MPI-04 - MPI-041,088.07 5,143.00 1,031.04 4,132.42 19.0765,143.00Ellipse Separation Pass - MPI-04 - MPI-04 - MPI-04 1,123.63 5,418.00 1,061.88 4,217.71 18.1955,418.00Clearance Factor Pass - MPI-04 - MPI-04A - MPI-04A1,087.83 5,113.93 1,031.40 4,121.89 19.2775,113.93Centre Distance Pass - MPI-04 - MPI-04A - MPI-04A1,088.07 5,143.00 1,031.04 4,132.42 19.0765,143.00Ellipse Separation Pass - MPI-04 - MPI-04A - MPI-04A1,252.63 6,443.00 1,168.82 5,646.00 14.9466,443.00Clearance Factor Pass - MPI-04 - MPI-04AL1 - MPI-04AL11,061.33 6,081.11 982.38 5,483.40 13.4436,081.11Centre Distance Pass - MPI-04 - MPI-04AL1 - MPI-04AL11,061.49 6,093.00 982.31 5,486.61 13.4066,093.00Ellipse Separation Pass - MPI-04 - MPI-04AL1 - MPI-04AL11,082.00 6,318.00 998.88 5,565.00 13.0176,318.00Clearance Factor Pass - MPI-04 - MPI-04APB1 - MPI-04APB11,087.83 5,113.93 1,031.40 4,121.89 19.2775,113.93Centre Distance Pass - 22 January, 2021-17:52COMPASSPage 2 of 8 Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU I-27 - MPU I-27 wp05Comparison 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: 4,993.00 to 14,858.43 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Reference Design: M Pt I Pad - Plan: MPU I-27 - MPU I-27 - MPU I-27 wp05MeasuredDepth(usft)Summary Based on MinimumSeparation WarningMPI-04 - MPI-04APB1 - MPI-04APB11,088.07 5,143.00 1,031.04 4,132.42 19.0765,143.00Ellipse Separation Pass - MPI-04 - MPI-04APB1 - MPI-04APB1 1,327.21 6,568.00 1,227.81 5,627.00 13.3516,568.00Clearance Factor Pass - MPI-04 - MPI-04PB1 - MPI-04PB11,088.90 5,094.44 1,035.20 4,079.20 20.2775,094.44Centre Distance Pass - MPI-04 - MPI-04PB1 - MPI-04PB11,089.51 5,143.00 1,034.99 4,097.16 19.9835,143.00Ellipse Separation Pass - MPI-04 - MPI-04PB1 - MPI-04PB11,132.35 5,443.00 1,073.60 4,207.00 19.2725,443.00Clearance Factor Pass - MPI-09 - MPI-09 - MPI-091,397.90 4,993.00 1,348.16 3,540.91 28.1084,993.00Ellipse Separation Pass - MPI-09 - MPI-09 - MPI-091,677.09 6,018.00 1,567.97 4,262.13 15.3696,018.00Clearance Factor Pass - MPI-19 - MPI-19 - MPI-19766.11 8,938.18 632.65 7,640.00 5.7408,938.18Centre Distance Pass - MPI-19 - MPI-19 - MPI-19767.80 9,093.00 631.05 7,771.94 5.6159,093.00Ellipse Separation Pass - MPI-19 - MPI-19 - MPI-19961.44 11,143.00 754.29 9,720.00 4.64111,143.00Clearance Factor Pass - MPI-19 - MPI-19L1 - MPI-19L1751.03 9,005.32 615.38 7,700.55 5.5379,005.32Centre Distance Pass - MPI-19 - MPI-19L1 - MPI-19L1751.62 9,043.00 614.47 7,717.18 5.4809,043.00Ellipse Separation Pass - MPI-19 - MPI-19L1 - MPI-19L1956.24 10,593.00 772.24 9,141.65 5.19710,593.00Clearance Factor Pass - MPI-19 - MPI-19PB1 - MPI-19PB1748.66 9,096.56 594.97 7,799.00 4.8719,096.56Centre Distance Pass - MPI-19 - MPI-19PB1 - MPI-19PB1748.97 9,118.00 594.23 7,799.00 4.8409,118.00Ellipse Separation Pass - MPI-19 - MPI-19PB1 - MPI-19PB1754.85 9,193.00 597.61 7,799.00 4.8019,193.00Clearance Factor Pass - MPI-19 - MPI-19PB2 - MPI-19PB2760.18 9,207.86 621.62 7,910.24 5.4869,207.86Centre Distance Pass - MPI-19 - MPI-19PB2 - MPI-19PB2761.26 9,293.00 620.11 7,971.81 5.3939,293.00Ellipse Separation Pass - MPI-19 - MPI-19PB2 - MPI-19PB2853.34 9,993.00 678.83 8,532.00 4.8909,993.00Clearance Factor Pass - MPU I-35i - MPU I-35i - MPU I-35i129.13 9,164.48 73.78 8,857.97 2.3339,164.48Centre Distance Pass - MPU I-35i - MPU I-35i - MPU I-35i157.9013,427.6838.7613,130.001.32513,427.68Clearance FactorPass - MPU I-36 - MPU I-36 - MPU I-36986.53 13,950.91 738.67 14,265.00 3.98013,950.91Centre Distance Pass - MPU I-36 - MPU I-36 - MPU I-36986.68 13,968.00 738.40 14,265.00 3.97413,968.00Ellipse Separation Pass - MPU I-36 - MPU I-36 - MPU I-36987.43 13,993.00 738.72 14,265.00 3.97013,993.00Clearance Factor Pass - MPU I-36 - MPU I-36PB1 - MPU I-36PB11,048.04 8,438.58 931.20 8,710.04 8.9708,438.58Centre Distance Pass - MPU I-36 - MPU I-36PB1 - MPU I-36PB11,089.68 10,018.00 913.81 10,300.00 6.19610,018.00Ellipse Separation Pass - MPU I-36 - MPU I-36PB1 - MPU I-36PB11,091.83 10,068.00 915.10 10,300.00 6.17810,068.00Clearance Factor Pass - MPU I-36 - MPU I-36PB2 - MPU I-36PB21,045.13 9,052.37 918.04 9,385.19 8.2249,052.37Centre Distance Pass - MPU I-36 - MPU I-36PB2 - MPU I-36PB21,072.94 9,893.00 906.94 10,163.00 6.4639,893.00Ellipse Separation Pass - MPU I-36 - MPU I-36PB2 - MPU I-36PB21,075.88 9,943.00 908.97 10,163.00 6.4469,943.00Clearance Factor Pass - 22 January, 2021-17:52COMPASSPage 3 of 8 Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU I-27 - MPU I-27 wp05Comparison 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: 4,993.00 to 14,858.43 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Reference Design: M Pt I Pad - Plan: MPU I-27 - MPU I-27 - MPU I-27 wp05MeasuredDepth(usft)Summary Based on MinimumSeparation WarningMPU I-37i - MPU I-37i - MPU I-37i1,583.82 14,858.43 1,327.55 15,664.73 6.18014,858.43Clearance Factor Pass - Plan: MPI-07 - MPI-07 - MPI-07 1,133.48 4,993.00 1,106.62 4,018.31 42.2044,993.00Ellipse Separation Pass - Plan: MPI-07 - MPI-07 - MPI-071,157.84 5,018.00 1,129.25 4,020.64 40.5015,018.00Clearance Factor Pass - Plan: MPI-07 - Plan: MPU I-07A - MPU I-07A wp05912.59 4,993.00 875.43 4,212.26 24.5574,993.00Clearance Factor Pass - Plan: MPU I-22 - MPU I-22 - MPU I-22 wp031,440.27 13,729.23 1,180.64 14,568.95 5.54713,729.23Centre Distance Pass - Plan: MPU I-22 - MPU I-22 - MPU I-22 wp031,440.79 13,768.00 1,180.31 14,568.95 5.53113,768.00Ellipse Separation Pass - Plan: MPU I-22 - MPU I-22 - MPU I-22 wp031,443.01 13,818.00 1,181.75 14,568.95 5.52313,818.00Clearance Factor Pass - Plan: MPU I-28i - MPU I-28 - MPU I-28i wp05585.60 14,858.43 298.73 15,015.11 2.04114,858.43Clearance Factor Pass - Plan: MPU I-29 - MPU I-29 - MPU I-29 wp031,328.94 14,858.43 1,040.21 15,808.01 4.60314,858.43Clearance Factor Pass - Rig: MPU I-20 - MPU I-20 - MPU I-20179.09 5,243.00 112.59 5,121.00 2.6935,243.00Clearance Factor Pass - Rig: MPU I-20 - MPU I-20 - MPU I-20178.87 5,251.99 112.71 5,121.00 2.7045,251.99Centre Distance Pass - Rig: MPU I-20 - MPU I-20 - MPU I-20 wp0765.7913,416.84-49.8113,277.250.56913,416.84Clearance FactorFAIL - Rig: MPU I-21i - MPU I-21i - MPU I-21i696.83 4,993.00 634.44 5,775.00 11.1694,993.00Clearance Factor Pass - Rig: MPU I-21i - MPU I-21i - MPU I-21i wp12628.15 13,758.64 365.05 14,851.24 2.38813,758.64Centre Distance Pass - Rig: MPU I-21i - MPU I-21i - MPU I-21i wp12654.07 14,858.43 361.49 15,935.25 2.23614,858.43Clearance Factor Pass - M Pt J PadMPJ-01 - MPJ-01 - MPJ-019.3910,175.85-94.794,216.410.09010,175.85Clearance FactorFAIL - MPJ-01 - MPJ-01A - MPJ-01A112.9313,945.57-113.258,034.000.49913,945.57Clearance FactorFAIL - MPJ-01 - MPJ-01AL1 - MPJ-01AL1121.8513,135.64-17.987,337.500.87113,135.64Centre DistanceFAIL - MPJ-01 - MPJ-01AL1 - MPJ-01AL1124.0913,193.00-20.507,385.300.85813,193.00Clearance FactorFAIL - MPJ-03 - MPJ-03 - MPJ-03126.336,418.0016.065,064.311.1466,418.00Clearance FactorPass - MPJ-03 - MPJ-03 - MPJ-03123.066,458.4824.625,035.691.2506,458.48Centre DistancePass - MPJ-05 - MPJ-05 - MPJ-051,127.73 9,646.37 1,039.36 3,728.91 12.7629,646.37Centre Distance Pass - MPJ-05 - MPJ-05 - MPJ-051,127.91 9,668.00 1,039.09 3,734.99 12.6999,668.00Ellipse Separation Pass - MPJ-05 - MPJ-05 - MPJ-051,142.89 9,843.00 1,050.45 3,800.00 12.3639,843.00Clearance Factor Pass - MPJ-06 - MPJ-06 - MPJ-06324.61 10,179.91 208.29 4,347.43 2.79110,179.91Centre Distance Pass - MPJ-06 - MPJ-06 - MPJ-06327.93 10,243.00 203.35 4,392.28 2.63210,243.00Ellipse Separation Pass - MPJ-06 - MPJ-06 - MPJ-06335.12 10,293.00 206.39 4,427.81 2.60310,293.00Clearance Factor Pass - MPJ-08 - MPJ-08 - MPJ-08766.07 9,943.48 693.54 3,786.37 10.5629,943.48Centre Distance Pass - MPJ-08 - MPJ-08 - MPJ-08772.10 10,068.00 688.67 3,867.55 9.25510,068.00Ellipse Separation Pass - 22 January, 2021-17:52COMPASSPage 4 of 8 Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU I-27 - MPU I-27 wp05Comparison 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: 4,993.00 to 14,858.43 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Reference Design: M Pt I Pad - Plan: MPU I-27 - MPU I-27 - MPU I-27 wp05MeasuredDepth(usft)Summary Based on MinimumSeparation WarningMPJ-08 - MPJ-08 - MPJ-081,682.76 14,043.00 1,363.12 8,045.55 5.26514,043.00Clearance Factor Pass - MPJ-08 - MPJ-08A - MPJ-08A 766.07 9,943.48 693.54 3,787.17 10.5629,943.48Centre Distance Pass - MPJ-08 - MPJ-08A - MPJ-08A772.10 10,068.00 688.67 3,868.35 9.25510,068.00Ellipse Separation Pass - MPJ-08 - MPJ-08A - MPJ-08A1,254.36 11,243.00 1,094.43 4,712.45 7.84411,243.00Clearance Factor Pass - MPJ-10 - MPJ-10 - MPJ-101,140.04 10,609.40 1,015.68 4,173.82 9.16810,609.40Centre Distance Pass - MPJ-10 - MPJ-10 - MPJ-101,141.39 10,668.00 1,014.81 4,190.91 9.01710,668.00Ellipse Separation Pass - MPJ-10 - MPJ-10 - MPJ-101,161.49 10,843.00 1,030.11 4,237.06 8.84110,843.00Clearance Factor Pass - MPJ-11 - MPJ-11 - MPJ-11317.71 12,044.34 188.38 5,240.83 2.45712,044.34Centre Distance Pass - MPJ-11 - MPJ-11 - MPJ-11319.25 12,093.00 185.88 5,277.96 2.39412,093.00Ellipse Separation Pass - MPJ-11 - MPJ-11 - MPJ-11321.23 12,118.00 186.44 5,297.28 2.38312,118.00Clearance Factor Pass - MPJ-12 - MPJ-12 - MPJ-12502.00 10,664.76 364.58 4,441.95 3.65310,664.76Centre Distance Pass - MPJ-12 - MPJ-12 - MPJ-12502.01 10,668.00 364.51 4,443.60 3.65110,668.00Ellipse Separation Pass - MPJ-12 - MPJ-12 - MPJ-12502.58 10,693.00 364.61 4,456.32 3.64310,693.00Clearance Factor Pass - MPJ-13 - MPJ-13 - MPJ-131,152.52 11,338.77 988.29 4,897.58 7.01811,338.77Centre Distance Pass - MPJ-13 - MPJ-13 - MPJ-131,154.79 11,443.00 986.19 4,970.68 6.84911,443.00Ellipse Separation Pass - MPJ-13 - MPJ-13 - MPJ-131,174.44 11,668.00 998.55 5,127.83 6.67711,668.00Clearance Factor Pass - MPJ-16 - MPJ-16 - MPJ-16881.56 12,382.45 662.62 5,788.33 4.02712,382.45Centre Distance Pass - MPJ-16 - MPJ-16 - MPJ-16888.66 12,618.00 653.80 5,992.57 3.78412,618.00Ellipse Separation Pass - MPJ-16 - MPJ-16 - MPJ-16913.78 12,843.00 668.29 6,160.00 3.72212,843.00Clearance Factor Pass - MPJ-25 - MPJ-25 - MPJ-25843.21 9,825.94 767.49 3,716.57 11.1359,825.94Centre Distance Pass - MPJ-25 - MPJ-25 - MPJ-25844.21 9,868.00 766.44 3,723.94 10.8559,868.00Ellipse Separation Pass - MPJ-25 - MPJ-25 - MPJ-25897.01 10,143.00 807.70 3,788.07 10.04410,143.00Clearance Factor Pass - MPJ-25 - MPJ-25PB1 - MPJ-25PB1 843.21 9,825.94 767.49 3,716.57 11.1359,825.94Centre Distance Pass - MPJ-25 - MPJ-25PB1 - MPJ-25PB1844.21 9,868.00 766.44 3,723.94 10.8559,868.00Ellipse Separation Pass - MPJ-25 - MPJ-25PB1 - MPJ-25PB1897.01 10,143.00 807.70 3,788.07 10.04410,143.00Clearance Factor Pass - 22 January, 2021-17:52COMPASSPage 5 of 8 Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU I-27 - MPU I-27 wp05Survey tool programFrom(usft)To(usft)Survey/Plan Survey Tool26.30 1,500.00 MPU I-27 wp05 3_Gyro-MWD90+Sag1,500.00 4,993.00 MPU I-27 wp05 3_MWD+IFR2+MS+Sag4,993.00 14,858.43 MPU I-27 wp05 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.22 January, 2021-17:52COMPASSPage 6 of 8 1 Davies, Stephen F (CED) From:Nathan Sperry <Nathan.Sperry@hilcorp.com> Sent:Thursday, February 4, 2021 10:34 AM To:Davies, Stephen F (CED) Subject:RE: [EXTERNAL] MPU I-27 (PTD 221-013) - Question Hi Steve, Yes sir, see below. Sorry about that. Nate Sperry Drilling Engineer Hilcorp Alaska, LLC O: 907‐777‐8450 C: 907‐301‐8996 From: Davies, Stephen F (CED) [mailto:steve.davies@alaska.gov] Sent: Thursday, February 4, 2021 10:16 AM 2 To: Nathan Sperry <Nathan.Sperry@hilcorp.com> Subject: [EXTERNAL] MPU I‐27 (PTD 221‐013) ‐ Question Nathan, I’m reviewing Hilcorp’s application for a Permit to Drill for MPU I‐27, and I have a question: The Generalized Geological Information table provided on page 46 is for MPU S‐Pad, which is about 3 miles to the southeast. Is there a similar table for I‐Pad? Thanks and stay safe, Steve Davies Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission (AOGCC) CONFIDENTIALITY NOTICE: This e‐mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e‐mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907‐793‐1224 or steve.davies@alaska.gov. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 1 Davies, Stephen F (CED) From:Davies, Stephen F (CED) Sent:Thursday, February 4, 2021 10:34 AM To:Nathan Sperry (nathan.sperry@hilcorp.com) Subject:RE: MPU I-27 (PTD 221-013) - Question Nathan, Following up on the email below, the Anticipated Drilling Hazards section mentions on page 47: “Gas Hydrates have not been seen on Moose pad.”From page 49: “Abnormal (offset injection) pressure has been seen on M‐Pad.” To ensure that cut‐and‐paste errors have not been made, is everything discussed in this Anticipated Drilling Hazards section relevant to MPU I‐27? Have hydrates, overpressure, or H2S been encountered in other I‐Pad Schrader Bluff wells? If so, please explain the occurrences and discuss Hilcorp’s planned mitigation measures. Thanks and stay safe, Steve Davies Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission (AOGCC) CONFIDENTIALITY NOTICE: This e‐mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e‐mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907‐793‐1224 or steve.davies@alaska.gov. From: Davies, Stephen F (CED) Sent: Thursday, February 4, 2021 10:16 AM To: Nathan Sperry (nathan.sperry@hilcorp.com) <nathan.sperry@hilcorp.com> Subject: MPU I‐27 (PTD 221‐013) ‐ Question Nathan, I’m reviewing Hilcorp’s application for a Permit to Drill for MPU I‐27, and I have a question: The Generalized Geological Information table provided on page 46 is for MPU S‐Pad, which is about 3 miles to the southeast. Is there a similar table for I‐Pad? Thanks and stay safe, Steve Davies Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission (AOGCC) CONFIDENTIALITY NOTICE: This e‐mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e‐mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907‐793‐1224 or steve.davies@alaska.gov. 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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