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Home My WebLink About220-049 Hilcorp Alaska, LLC Post Office Box 244027 Anchorage, AK 99524-4027 3800 Centerpoint Drive Suite 1400 Anchorage, AK 99503 Phone: 907/777-8547 September 29, 2023 Mr. Mel Rixse Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 Re: Milne Point Conductor Annulus Corrosion Inhibitor Treatments 6/9 to 9/27/2023 Dear Mr. Rixse, Enclosed please a copy of a spreadsheet with a list of thirteen Milne Point wells that were treated with corrosion inhibiting casing filler in the surface casing by conductor annulus. The heavier than water “grease-like” filler displaces water to prevent external casing corrosion that could result in a surface casing leak. The attached spreadsheets include the well names, field, API and PTD numbers, treatment dates and volumes. If you have any additional questions, please contact me at 907-777-8406 or dhorner@hilcorp.com. Sincerely, Darci Horner Regulatory Tech Hilcorp Alaska, LLC Digitally signed by Darci Horner (c-100048) DN: cn=Darci Horner (c-100048) Date: 2023.09.29 09:45:20 - 08'00' Darci Horner (c-100048) Well Field API PTD Initial Top of Cement (ft.) Volume of Cement Pumped (bbls) Final Top of Cement (ft.) Cement Pump Date Corrosion Inhibitor Fill Volume (gal) Final CI Top (ft.) Corrosion Inhibitor Treatment Date Comments MPB-35 MPU 50029237240000 2220850 14' 0 14' N/A 50 surface 9/27/2023 Drilled Sept/Oct 2022. MPB-39 MPU 50029237470000 2230120 1'6" 0 1'6" N/A 10 surface 6/10/2023 Drilled Mar 2023. MPI-20 MPU 50029236790000 2200490 10' 1 1 7/2/2023 5 surface 9/27/2023 Completed Apr 8, 2021. MPI-29 MPU 50029237080000 2220060 6' 0.5 3 7/2/2023 15 surfce 9/27/2023 Drilled in March 2022. Completeted on 4/30/22. MPL-60 MPU 50029236780000 2200480 1' 0 1' N/A 10 surface 6/26/2023 Drilled in 2020. MPL-62 MPU 50029236850000 2200590 1' 0 1' N/A 10 surface 6/26/2023 Drilled in 2020. MPM-13 MPU 50029236380000 2190870 20' 3.5 2' 8/2/2023 10 surface 9/27/2023 Drilled in 2019. MPM-27 MPU 50029237160000 2220490 2' 0 2' N/A 20 surface 6/11/2023 Monobore. Drilled June 2022. MPM-30 MPU 50029237300000 2221180 1' 0 1' N/A 10 surface 6/11/2023 Drilled in Oct 2022. MPM-43 MPU 50029236710000 2200200 1' 0 1' N/A 10 surface 6/11/2023 Drilled in 2020. MPM-62 MPU 50029237440000 2230060 1' 0 1' N/A 10 surface 6/11/2023 Completed May 2023. MPS-45 MPU 50029236930000 2210420 1' 0 1' N/A 10 surface 6/12/2023 Drilled in June 2021. MPS-47 MPU 50029236960000 2210470 4' 0 4' N/A 20 surface 6/12/2023 Drilled in August 2021. Notes: The 4" conductor outlets are any where from 1 to 3' down from the top of the conductor Surface Casing by Conductor Annulus Cement Top Job and Fill Coat Corrosion Inhibitor (CI) Applications Cement to surface means cement is up to the 4" outlets below the wellhead. From the 4" outlets up to the top of conductor was filled with Fill Coat #7 Initial top of cement footage measurement was taken from the 4" outlet down to the TOC RBDMS JSB 100323 MPI-20 MPU 50029236790000 2200490 10'1 1 7/2/2023 5 surface 9/27/2023 Completed Apr 8, 2021. 1. Operations Abandon Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Suspend Perforate Other Stimulate Alter Casing Change Approved Program Plug for Redrill Perforate New Pool Repair Well Re-enter Susp Well Other: ______________________ 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 5121'feet None feet true vertical 4024'feet None feet Effective Depth measured 5009'feet None feet true vertical 4024'feet feet Perforation depth Measured depth None feet True Vertical depth feet Tubing (size, grade, measured and true vertical depth)2241' 2237' Packers and SSSV (type, measured and true vertical depth)None 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 13. Prior to well operation: Subsequent to operation: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Contact Name: Authorized Title: Drilling Manager Contact Email: Contact Phone: WINJ WAG Water-Bbl MD 107' 5111' TVD Oil-Bbl measured true vertical Packer 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 3. Address: 4. Well Class Before Work: N/A Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure MPU I-20 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 220-049 50-029-23679-00-00 3-1/2" 9.3# L-80 Kill String Plugs Junk measured ADL 025906 & 315848 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 320-306 Size 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) Gas-Mcf Authorized Signature with date: Authorized Name: Monty Myers Liner 5. Permit to Drill Number: Milne Point Field, Schrader Bluff Oil PoolROP, AGR, ABG, DGR, EWR, ADR MD & TVD measured Conductor Surface Intermediate Production Casing Structural 20" 9-5/8" Length 80' 5111' 107' 4024' Burst 6870 / 5750 Hilcorp Alaska LLC 2. Operator Name Senior Engineer:Senior Res. Engineer: Collapse 4760 / 3090 Joe Engel joseph.engel@hilcorp.com t Fra O g g g l O g 6. A G L PG , R Form 10-404 Revised 3/2020 Submit Within 30 days of Operations 7.29.20 By Jody Colombie at 4:41 pm, Jul 29, 2020 Digitally signed by Monty M Myers DN: cn=Monty M Myers, c=US, o=Hilcorp Alaska, LLC, ou=Technical Services - AK Drilling, email=mmyers@hilcorp.com Reason: I am approving this document Date: 2020.07.29 15:30:42 -08'00' Monty M Myers DSR-7/29/2020 SFD 7/30/2020MGR30JUL2021 RBDMS HEW 7/30/2020 Activity Date Ops Summary 6/12/2020 Had to replace Master Valve packing on tree. Test 500 PSI 5 min 5,000 PSI 15 min. Pull CTS and leave BPV in. SIMOPS Prep Pipe Shed for move. Remove allen bolts on rotary table cover. Start breaking down interconnects. Lay Herculite and matts on I-20. Cont cleaning pits. Install Starter Head on I-20;Remove rotary table motor. Bridal up. Prep Mods for moving.;Peak on location at 14:00. PJSM Scope down Derrick. Blow down steam and H2O. Finish cleaning pits. Jack up Mods.;PJSM Stage Pipe Shed, Cattle Chute, Mud and Gen Mod around pad. Start walking Sub off I-36.;Walk Sub down to I-20. Spot and shim over I-20. Spot Cattle Chute and Pipe Shed.;Daily fluid hauled to G&I bbls total = 0 bbls Daily metal recovered 0 lbs, total = 0 lbs Daily water hauled from L Pad Lake 0 bbls total = 0 bbls Fluid lost surface hole = 0 bbls 6/13/2020 PJSM, Finish spotting pipe shed, spot, shim and set Mud and Motor Mods. Spot Beyond shack. Hook up all interconnects. SimOps: Finish C/O oil in Drawworks.;Plug in and swap to Gen Power @ 10:00. Safe out all walkways, stairways and roof tops. Scope up Derrick, plug in and remove Bridal line sheave pins. Begin working on rig acceptance check list.;PJSM, Bridal Down, Hang Rig Tongs, Continue to work on rig acceptance Items.;PJSM Set Diverter Stack on Tee. Trq all bolts to Starter Head. Install Bell Nipple, riser and center Stack. Test gas detection system H2S 10-20 PPM, LEL 20-40%. Diverter test witness waived by Bob Noble via Phone call @ 16:00 hrs.;PJSM INstall Knife Valve and 16" Diverter sections to edge of pad and wait till OPS is done with Crane. SIMOPS Take on 400 bbl 8.8 ppg Spud Mud to Pits. Install 5" Hydraulic Elevators. Install short mouse hole in Rotary Table and press up on Annulus. to secure. Rig accepted at 21:30.;PJSM P/U M/U 5" 19.5# NC59 S-135 D.P. with mouse hole racking back in Derrick. Drift 3.125" OD.;PJSM Use crane to install last section of Diverter line.;PJSM P/U M/U 5" 19.5# NC59 S-135 D.P. with mouse hole racking back in Derrick. Drift 3.125" OD. Made up 79 stands total. 9 Stands 5" HWDP and Jars.;PJSM Perform Diverter test. Annular closed 10 sec, Knife open 6 sec. Accumulator test System start 3,050 PSI after 1,950 PSI, 200 PSI inc 15 sec full 58 sec. Nitrogen 5 bottle ave 2,383 PSI. Tested PVT and alarms. Witnessed waived by Bob Noble.;PJSM P/U and stage BHA components on rig floor and Pipe Shed.;Daily fluid hauled to G&I bbls total = 0 bbls Daily metal recovered 0 lbs, total = 0 lbs Daily water hauled from L Pad Lake 130 bbls total = 130 bbls Fluid lost surface hole = 0 bbls 6/14/2020 Pre-Spud meeting. Discussed upcoming task and hazards associated with. P/U M/U 12.25" Baker KYMERA Bit, 8" SperryDrill 1.5° Motor, 8" X/O and 1 stand 5" HWDP.;Pressure test HP Mud Lines to 3000 psi. Test good.;PJSM, Soft tag @ 107'. DRL ahead and displace t/8.8 ppg spud mud. Encounter hard spot @ 143', ROP slowed to 10 fpm with 8K WOB and erratic pipe bounce. POOH & check bit for junk damage. Bit good. Balled up with clay and large rocks. RIH and continue to drill ahead to 218', adjusting parameters as;needed to drill hard spot. See gravels and clay at shakers. GPM 400-450, SPP 450-550, RPM 40, Tq 1.5 to 2.5k, WOB 6-10, PUW 46k, SOW 47k, Rot 46k. CBU x2.;PJSM, POOH on elevators to surface w/o issues. Pump and jet flow line through bleeder.;PJSM, M/Remaining BHA as per sperry: DM, EWR, TM, UBHO, Up load MWD tool, orient UBHO to motor hi side. MWD off set 253/811 x 360 =112.3°;PJSM Rot & Slide 12.25" Surface F/ 218' to 485' MD Total 267' (AROP 66.7'). 470 GPM, 930 PSI, 60 RPM, TRQ 1.5-2.5K, WOB 6-10K, P/U 58K SLK 61K ROT 61K. MWD getting clean surveys while drilling. Gyro at 279' & 379' MD correlated to MWD surveys.. Paralleled MPU I-19 at 13 feet down to 379';started to getting to 18.5' by 508' MD. Back ream 20' at connection.;Cont Rot & Slide 12.25" Surface F/ 485' to 992' MD. Total 507' (AROP 84.5'). 500 GPM, 1,360 PSI, 80 RPM, TRQ 2.8K, WOB 8K, P/U 74K SLK 79K ROT 76K. Gyro at 466' & 566' MD correlated to MWD, first kept MWD survey at 509.48'.. Released Gyro at 738' MD. R/D Gyro Sheave.;Lost Canrig F/ 20:23 to 21:34 and 22:17 to 22:43.Over heating as per Canrig, keep cool W/ fan. Back ream 20' at connection.;Cont Rot & Slide 12.25" Surface F/ 992' to 1,498' MD. Total 506' (AROP 84.3'). 500 GPM, 1,475 PSI, 80 RPM, TRQ 3K, WOB 5-14K, P/U 87K SLK 89K ROT 88K. at 1,283' kicking off there needing 4°/100' to build to 5° and continue to hold 5°/100. Back ream 30' at connection.;Rot Hrs 7.38 Slide Hrs 2.36 Distance to WP #6 3.1', 2.3' High, 2.19' Left;Daily fluid hauled to G&I 570 bbls total = 570 bbls Daily metal recovered 0 lbs, total = 0 lbs Daily water hauled from L Pad Lake 1,040 bbls total = 1,170 bbls Fluid lost surface hole = 0 bbls 6/15/2020 Cont Rot & Slide 12.25" Surface F/ 1,498' to 2,134' MD (2,129' TVD). Total 636' (AROP 106'). 500 GPM, 1,385 PSI, 80 RPM, TRQ 3K, WOB 8-12K, ECD 9.93 Max Gas 866U. P/U 97K SLK 97K ROT 98K. Back ream 30' at connection. Perma Frost Base 1,783' MD 1,781' TVD Hold 5.0°/100;Cont Rot & Slide 12.25" Surface F/ 2,134' to 2,833' MD (2,825' TVD). Total 699' (AROP 116.5'). 500 GPM, 1,450 PSI, 80 RPM, TRQ 3.2K, WOB 4K, ECD 10.05 Max Gas 1,252U. P/U 114K SLK 107K ROT 111K. Back ream 60' at connection. 5°/100 tangent 189.51° azi to 2,440' MD. Build 4°/100 at 2,515' MD;Cont Rot & Slide 12.25" Surface F/ 2,833' to 3,400' MD (3,325' TVD). Total 567' (AROP 84.5'). 500 GPM, 1,700 PSI, 80 RPM, TRQ 5.7K, WOB 8-12K, ECD 10.18 Max Gas 562U. P/U 125K SLK 111K ROT 119K. Back ream 60' at connection. Cont 4°/100 build turn to 3,128' MD. Cont Build turn.;Cont Rot & Slide 12.25" Surface F/ 3,400' to 3,791' MD (3,634' TVD). Total 391' (AROP 65.1'). 500 GPM, 1,710 PSI, 80 RPM, TRQ 6.1K, WOB 6- 16K, ECD 10.0 Max Gas 721U. P/U 130K SLK 115K ROT 123K. Back ream 60' at connection. Cont Build turn 4°/100.;Rot Hrs 7.36 Slide Hrs 6.63 Distance to WP #6 5.26', 5.1' High, 1.3' Left;Daily fluid hauled to G&I 1,197 bbls total = 1,767 bbls Daily metal recovered 0 lbs, total = 0 lbs Daily water hauled from L Pad Lake 1,170 bbls total = 2,340 bbls Fluid lost surface hole = 0 bbls 6/16/2020 Cont Rot & Slide 12.25" Surface F/ 3,791' to 4,123' MD (3,838' TVD). Total 332' (AROP 60.4'). 500 GPM, 1,750 PSI, 80 RPM, TRQ 7.5K, WOB 10-15K, ECD 9.85 Max Gas 989U. P/U 135K SLK 113K ROT 125K. Back ream 60' at connection. Cont Build turn 4°/100.;MP #1 Pod 4, Wear Plate weeping F/ tattle tail.Rack back 1 stand to 4,108' MD.;PJSM Rot & Rec F/ 4,108 to 4,045' MD 310 GPM, 720 PSI. C/O Wear Plate MP #1 Pod 4. Go back to bottom, no fill.;Cont Rot & Slide 12.25" Surface F/ 4,123' to 4,600' MD (3,998' TVD). Total 477' (AROP 79.5'). 500 GPM, 1,650 PSI, 80 RPM, TRQ 8.2K, WOB 14K, ECD 10.1 Max Gas 619U. P/U 133K SLK 107K ROT 121K. Back ream 60' at connection. Cont Build turn 4°/100. At 13:30 Lost 400 RPM off MWD pulser;and 250 PSI off stand pipe Press. Cont drilling ahead with intermittent gains in Press and pulser RPM. No continual loss to suspect wash out. Adjusted pumps checking Press does appear to be a pump issue.;At ~4,488' MD Fault: May change after seeing RM logs. Looks like faulted from below OA-Sand to just above it. Estimated 43' through DTN.;Cont Rot & Slide 12.25" Surface F/ 4,600' to 5,012' MD (4,022' TVD). Total 412' (AROP 68.7'). 500 GPM, 1,610 PSI, 80 RPM, TRQ 5-10K, WOB 14-26K, ECD 10.23 Max Gas 1,412U. P/U 124K SLK 105K ROT 115K. Back ream 60' at connection. Cont Build turn 4°/100. Broke through W/ max 32K at 5,057' .;Cont Rot & Slide 12.25" Surface F/ 5,012' to TD 5,121' MD (4,023' TVD). Total 109' (AROP 36.4'). 500 GPM, 1,450 PSI, 80 RPM, TRQ 5-9K, WOB 8-35K, ECD 9.91 Max Gas 1,118U. P/U 128K SLK 102K ROT 114K. Back ream 60' at connection. Geo called for 90°-90.5° by TD 5,121' MD.;Slide as needed. 4°/100 90.5° at TD. Encountered multiple hard spots causing stalls. Obtain final survey on bottom 5,121' MD 90.14° Inc 356.29° Azi Monitor well 10 min, static.;PJSM BROOH F/ 5,121' to 4,934' MD. 500 GPM, 1,400 PSI, 80 RPM, TRQ 6.2K, P/U 127K, SLK 103K, ROT 114K. Pull 35 ft/min. No issues.;PJSM Rot and Rec F/ 4,934' to 4,865' MD Pump 43 bbl HI Vis sweep. 540 GPM, 1,675 PSI, 80 RPM, 6.9K TRQ, ECD 9.82, Max Gas 817U, BGG 265U , P/U 127K SLK 102K ROT 115K Sweep back on time W/ 10% increase at Shakers.;PJSM RIH on elevators F/ 4,865' to 5,121' MD. Washed down last stand 550 GPM, 1,740 PSI. No Fill. Monitor well, static. P/U 126K, SLK 102K.;PJSM BROOH F/ 5,121' to 4,934' MD 550 GPM, 1,750 PSI, 80 RPM, TRQ 6K, ECD 9.83, Max Gas 517U P/U 126K, SLK 102K, ROT 115K. Pull speed 10-20 ft/min.;Rot Hrs 4.7 Slide Hrs 7.91 Distance to WP #6 6.89', 4.1' Low, 5.6' Right Fault at ~4,488' MD 43' DTN Total number hard spots drilled = 13;Daily fluid hauled to G&I 855 bbls total = 2,622 bbls Daily metal recovered 0 lbs, total = 0 lbs Daily water hauled from L Pad Lake 1,040 bbls total = 3,380 bbls Fluid lost surface hole = 0 bbls 50-029-23679-00-00API #: Well Name: Field: County/State: MP I-20 Milne Point Hilcorp Energy Company Composite Report , Alaska 6/14/2020Spud Date: 6/17/2020 Continue BROOH F/ 4934' - T/ 2010' MD. 500 gpm, 1420 psi, 80 rpm. Reduced rpms to 60 from 2900' to 2000' MD. 2.8k tq, 30-40 fpm pulling speed. No hole issues. Dusted MW up from 9.4 to 9.5 on the fly while backreaming due to gas bumps from time to time while BROOH (max gas 599u, BGG 30u).;Continue BROOH F/ 2010' - T/ 738' MD. 450 gpm, 1100 psi, 40 rpm, 2k tq, 10.2 ECD's. 83k up/dn. 30-40 fpm pulling speed without issue. Continue adding water 10 bph to help manages mud properties (Hi Vis out ~150). Hole never unloaded throughout backreaming operations.;Monitored well @ HWDP (738' MD). Well static. POOH on elevators F/ 738 to 8" tools racking back HWDP w/ jars. Pulled clean with slight 3-4k drag. Calc displacement. 74k up/dn.;PJSM, L/D XO sub, 3 flex NM DC's, download MWD, M/O and L/D MWD tools. Drain and flush mtr. B/O and L/D mtr and bit. Bit grade (PDC)= 2,3,CT,A,X,I BU,TD. Bit grade (Cone) = 1,1,WT,A,E,I,BU,TD. Clean and clear tools from floor. Slight wear/damage on top leading edge ILS stab and mtr stab.;PJSM Service rig. Grease Crown & Blocks. Open coffin Top Drive and clean oil and look for leaks, none. Must only leak while spinning or using pipe handler.;PJSM M/U Volant to Top Drive as per Weatherford. Install Weatherford bail ext and 9 5/8" Elevators. Bring up and R/U Power Tongs. Stage 69 Centralizers on rig floor.;PJSM P/U M/U 9 5/8" Shoe Track and Backer Loc. Drop By Pass as per Halliburton rep onsite witnessed by Co Rep. Check floats, good. Trq 40# 9 5/8" 21K.;RIH W/ 9 5/8" Csg 40# TXP BTC F/ 162' to 1,200' MD. P/U 70, SLK 64K. Install solid spring Centralizers as per tally. Trq 40# 21K. RIH at 90 ft/min. Lost 4 bbls. Fill every 5 jnts and top off every 10 Jnts.;PJSM Cont RIH W/ 9 5/8" Csg 40# TXP BTC F/ 1,200' to 1,996' MD. P/U 85K, SLK 75K. Saw 20K bobbles F/ 1,825' to 1,927' MD. Install solid spring Centralizers as per tally. Trq 21K. RIH at 90 ft/min. Lost 4 bbls. Fill every 5 jnts and top off every 10 Jnt;PJSM Break Circ CBU Rec F/ 1,996' to 1,956' MD. Stage pumps up to 4 bpm 145 PSI, Max Gas 489U. Minimal increase seen at Shakers.;Cont RIH W/ 9 5/8" Csg 40# TXP BTC F/ 1,996' to 4,253' MD. P/U 210K, SLK 187K. Install Centralizers as per tally. Trq 40# 21K Trq 47# 23.8K. P/U M/U ES Cementer as per Halliburton 6 ea Shear Pins. RIH at 90 ft/min. Lost 23.5 bbls. Fill every 5 jnts and top off every 10 Jnt;Daily fluid hauled to G&I 974 bbls total = 3,596 bbls Daily metal recovered 0 lbs, total = 0 lbs Daily water hauled from L Pad Lake 650 bbls total = 4,030 bbls Fluid lost surface hole = 27.5 bbls 6/18/2020 Continue run 9-5/8" (40#&47#) TXP BTC casing as per detail F/ 4253' - T/ 5109' MD (126 total jts). 24k tq on 47# connections. 30-45 fpm running speed. 28 bbls loss for total trip. 75 bow spring centralizers, 14 stop rings.;Rot/Recip pipe while conditioning mud - F/ 5070' - T/ 5109' MD. Stage up to 7 bpm, 195 psi final, 56% flow (YP 17, 9.4 ppg MW, 65 vis) 5-10 rpm, 16.1k tq (tq limit set @ 18k). 207k up, 147k dn, 165k rot.;PJSM, R/U cmt line to Volant CRT. Break circulation 6 bpm, 400 psi, 54% flow, 143k dn, 207k up. Perform 1st stage cmt job -;Wet lines w/ 5 bbls H2O. P/T lines 1070 psi low / 4134 psi high (test good). Pump 55 bbls 10# spacer (5# poly flake, 4# red dye in first 10bbls), 4.2 bpm 251 psi Drop btm bypass plug. 161 bbls 12# type I/II Lead cmt (2.349 yld) 385sxs, 6 bpm, 512 psi.;82 bbls 15.8# Tail cmt (1.151 yld) 400 sxs, 4 bpm Drop top shutoff plug. HES pump 20 bbls H2O, 4 bpm 585 psi. Rig disp MP#2 - 205.4 bbls 9.4 spud mud, 7 bpm, 370 psi icp 4.5 bpm fcp 230 psi HES- 70 bbls 9.4 ppg tuned spacer, 4.5 bpm, 222 psi;Rig disp 80.6 bbls 9.4 spud mud, 4.5 bpm, 567 psi. Slowed last 10 bbls to 3 bpm, FCP 711 psi. Bumped @ 4614 stks (373.4 bbls calc / 376 bbls act). Psi up to 1225 psi w/ 3 min hold. Bled back 3 bbls, floats held. CIP @ 13:43 hr.Full returns thru out job. Rot/Recip until 240 bbls displaced.;Psi up @ 3 bpm. Observed good indication of stg tool shifting @ 2970 psi. Stg up to 5. bpm, 340 psi, 48% flow. Overboard 60 bbls spacer, 34 bbls green cmt, 14 bbls contaminated mud before taking returns back to pits. Flush surface equipment, Cont circ. Prep for 2nd stg. Circ @ 6 bpm 380 psi.;PJSM Halliburton pump 5 bbls H2O, tested lines to 1,290 PSI bleeding off. Halliburton found greased 1" plu valve. Cont PT and still leaking. Shut in cement line and retest, good. C/O Lo Trq on cement hose. Re test low kick out 1,252 PSI and high 3,536 PSI, good.;Pump 2nd stage cement job as follows: 59 bbls 10# Tuned spacer w/ 4# red dye & .5 lb/bbl poly flake (1st 10 bbls) 4 BPM ICP 203 PSI FCP 280 PSI. 272 bbls 10.7# ArticCem Lead cmt, 2.944 yld, 5 bpm, ICP 304 PSI FCP 477 PSI PSI. 54 bbls 15.8# Premium G Tail cmt, 1.169 yld, 4 bpm, ICP 636 PSI FCP 502;Drop closing plug. Displace w/ 20 bbls H2O (HES) then turn over to rig. Rig disp w/ 118.3 bbls 9.4# spud mud, 7.5 bpm, 650 PSI slowing to 4 bpm 767 PSI at 100 bbls away. Reduced rate last 10 bbls to 3 bpm, FCP 740 psi. Bump plug with 138.3 bbls actual / 139 bbls calculated.;Cont. Press up stage tool shifted at 1,700 PSI, held 2,310 PSI for 3 minutes, stage tool, good. CIP @ 23:43 hrs. Full returns throughout job. Saw contaminated spacer 60 bbls early at shakers. Good 10.7 ppg cement seen at shakers at 257 bbls Lead Cement away. Dumped 226 bbls of cement at surface.;PJSM Drain stack, flush with black water x3. R/D cement line and Volant. Pump through cement line to bleeder with black water. B/D cement line and top drive. Bleed down accumulator an disconnect knife valve. Re-Energize accumulator. Fill stack with black water and cycle. Suck out 9 5/8" Csg.;PJSM Drain Stack and clean cellar box. Pull Mouse hole. Hook up bridge cranes to Stack and unchain. Blow down and remove hole fill line. Remove Diverter section. Deflate 20" airboot. Break bolts and lift Stack. Center 9 5/8" Csg and set emergency slips as per NOS. 113K on slips. Set Stack down.;Break nuts off Diverter Tee and DSA. Lift Stack. Make rough cut on 9 5/8" Csg as per NOS. Set Stack back down and hot bolt. SIMOPS haul mud F/ Pits and clean. Pull inspection covers and inspect flow line. Crane off Diverter sections, twin towers and matt boards.;Daily fluid hauled to G&I 947 bbls total = 4,543 bbls Daily metal recovered 0 lbs, total = 0 lbs Daily water hauled from L Pad Lake 780 bbls total = 4,810 bbls Total Fluid lost surface hole = 28 bbls 6/19/2020 PJSM, L/D 26.95' cut joint (2' stickup). M/U and johnny whack BOP's. B/O and L/D same. Continue offload excess fluid in pits, clean same. Bring on Sea water.;Drain stack, N/D riser, knife valve and stack. Remove speed head from conductor, separate DSA, clean and demob from cellar. Dress 9-5/8" stump. Install 5M FMC sliplock wellhead (tq 400 ft/lbs). Test void 500/3800 psi w/ 5/10 min hold (test good - witnessed). N/U tubing spool. Tq flanges.;PJSM, Install DSA, Set stack. Tq flanges. Hook up choke and kill lines. 4pt and center stack. Install riser. Obtain RKB measurements - LLDS = 24.30', ULDS = 22.07'. Rewrap svc loop with protective shielding. Svc crown and choke manifold.;PJSM M/U Test Sub to Top Drive. M/U Head Pin to 3.5" Test Jnt L/D. M/U Dart, TIW, side entry to 5" Test Jnt. M/U 10.25" test plug and set. Flood lines and purge air F/ system. Perform shell test 3,000 PSI, good.;PJSM Perform BOPE test W/ 3.5" & 5" to 250 PSI low and 3,000 PSI high for 5 Min. Tested Choke Manifold 1-15, 5" Dart, 5" TIW, Upper and lower IBOP, Mez Kill, HCR and manual Choke and Kill, manual and Super Choke to 1,500 PSI W/ MP,;Upper and lower VRB Rams (2,875" X 5.5") Blind Rams, Koomey draw drown Initial System 3,100 PSI, Manifold 1,350 PSI, after System 1,450 PSI, Man 1,450 PSI, 200 PSI increase 25 Sec, full charge 98 sec. Nitrogen 6 bottle average 2,341 PSI.;Test H2S 10-20 ppm, LEL 20-40%, PVT high/ low level alarms. Witnessed by AOGCC Rep Guy Cook.;PJSM Break down test Jnts and testing Equip. Blow down Choke manifold and lines. Pull Test Plug and install 38" Wear Ring. ID 9" OD 10 3/4";PJSM P/U M/U Used 8.5" Smith XP+ Tri Cone, 6 3/4" Terraforce Lobe 6.7 - 6 stg 1.5° Motor and 6 3/4" Float Sub (Solid Float) 34.94' as per DD Rep.;PJSM P/U M/U 5" HWDP to BHA and tag at 58' 3K. Picked up and saw cement on Bit. RIH and washed down F/ 58' to 98' MD. 250 GPM 195 PSI through cement without issue. Cont RIH on Elevators F/ 98' to 1,803' MD. Wash down F/ 1,803' through cement stringers and tag cement at 1,890' MD. 300 GPM;455 PSI WOB 2K P/U 86K SLK 86K.;PJSM Drill Cement F/ 1,890' to top of plug at 1,898' MD. 210 GPM, 575 PSI, 60 RPM, WOB 6-12K.P/U 87K SLK 87K ROT 87K. Pass through ES on depth at 1,900' MD multiple times F/ 1,870' to 1,906' MD W/O pumps and rotary, no issue. Catching plug rubber at Shakers. Chase plug W/ drilling parameters;F/ 1, 906' to 2,121' spudding down on plug to get it broke up successfully. P/U 91K SLK 88K ROT 88K;PJSM RIH on elevators W/ 5" D.P. F/ 2,121' to 4,664' MD. P/U 134K SLK 91K.;PJSM Fiil string and wash down F/ 4,664' to 4,769' MD. 400 GPM, 890 PSI P/U 134K SLK 91K.;Daily fluid hauled to G&I 1,097 bbls total = 5,640 bbls Daily metal recovered 0 lbs, total = 0 lbs Daily water hauled from L Pad Lake 520 bbls total = 5,330 bbls Total Fluid lost surface hole = 28 bbls 6/20/2020 Wash down w/ 8.5" cleanout assy F/ 4769' - T/ 4974' MD. CBU @ 400 gpm, 890 psi, 20 rpm, 7.5k tq. 137k up, 88k dn.;R/U test equipment. Test 9-5/8" (47#/40#) TXP BTC, L-80 casing @ 4974' MD / 4023' TVD w/ 9.4 MW to 2500 psi w/ 30 min hold (chart and record same). 3.5 bbls pumped, 3.3 bbls bled back. 2603 psi initial, 2598 psi @ 15 min, 2596 @ 30 min.;PJSM, Displace wellbore to 8.4 corrosion inhibited seawater. Pump 60 bbls spacer then chased w/ seawater dumping 450 bbls total to cleanup. 415 gpm, 485 psi, 22 rpm, 7.8k tq. 144k up, 96k dn, 115k rot. Flow check (static).;Pump dry job. B/D TDS. POOH laying down all 5" dp, HWDP, jars, DC, Mtr and bit. Bit grade - 1,1,W T,A,E,I,NO,TD. Calculated displacement for trip.;M/U wear bushing setting tool RIH and engage wear bushing, ROLDS. Pull and L/D wear bushing. Mob Weatherford equipment to floor. R/U double stack power tongs, C/O elevators F/ 3.5" (75T). R/U air slips and inspect all equipment (good). Load 3.5" kill string in shed. Clean and prep floor.;PJSM RIH 9.3# L-80 EUE 3.5" Kill String as per tally. M/U Landing Jnt and land string at 2,241' MD. TRQ 3.2 K. P/U 53K SLK 55K. 20K on Hanger.;PJSM PSJM P/U 2' unseat Hanger. Perform Freeze Protect W/ 140 bbls Diesel down tubing taking returns down drag chain. 5 bpm ICP 250 PSI FCP 160 PSI. Pump 5 bbls Seawater down tubing and land Hanger. RILDS. Set BPV.;PJSM Suck out Stack F/ rig floor W/ Vac Truck. Flush all surace lines W/ H20 and Con Det. SIMOPS Prep for N/D BOP.;PJSM Finish flushing surface lines and BOP. Blow down surface Equip. Suck out stack W/ Vac Truck. SIMOPS Pull Seawater F/ Pits.;PJSM Remove Riser. Install air boot. Remove hole fill line. Remove Choke and Kill lines. Break BOP nuts and rack back BOP on pedestal and secure. Remove 11" X 13 5/8" DSA. SIMOPS Flush all lines in pits and MP's. Begin cleaning pits. Bring Dry Hole Tree into cellar.;PJSM Clean Hanger and install CTS on BPV. P/U Dry Hole Tree and M/U to well head. Remove companion flange and install flange/ gauge as per NOS Rep onsite. SIMOPS Cont cleaning pits. Work on MP EAM'S and begin going through pumps.;PJSM Test Void 500 low and 5,000 high 5/15 min, Started testing Tree and found leaking fitting on test hose. Replace fitting. SIMOPS Cont cleaning pits. and MP inspection.;Daily fluid hauled to G&I 870 bbls total = 6,510 bbls Daily metal recovered 0 lbs, total = 0 lbs Daily water hauled from L Pad Lake 0 bbls total = 5,330 bbls Total Fluid lost surface hole = 28 bbls 6/21/2020 PJSM Test Dry Hole Tree 500 low 5,000 high 5/15 min, good. Pull CTS and leave BPV.;06:30 12:00 PJSM Finish cleaning pits. Replace suction rubber and unclog gun lines. Install Rotary Table motor. Test motor. Clean and clear drain system under rig floor. Cont inspection on MP’S. Clean out Y-Strainers and magnets on both MP’s. C/O 3 liner and wear plates on MP #2.;Prep pad to move camp and shop. Work on top drive 6 month EAM. Check J Box found little oil. Tighten leaky fittings behind coffin lid. Move camp and shop this evening due to close proximity of upcoming wells.;12:00 18:00 PJSM Cont working on MP’s. Replace drag chain bearing. Check tire press on Mods. Remove wash pipe and brakes from top drive for inspection. Remove broken roller on spinners. Add Nitrogen to Top Drive accumulator. P/U 20’ pup and hang blocks.;Complete monthly crown and block sheave wobble. Move camp to far side of location to make room for the rig. Installed conductor on I-37.Installing I-38 conductor.;Cut and slip drilling line 69’ (11 wraps) 37,985 accumulated TM. 562’ left on spool. Calibrate Block height. Check Brake air gaps.;Cont working on MP’s. Press wash top drive and Derrick. Replace washed out valves in pits. Prep Shop to move. R/D Geo Spam for servicing and swap out W/ Spare. Finish assembling MP #2.;PJSM Finish taking a part MP #1 and replace 1 liner and wear plate. Cont Press washing Derrick. Cont prep Shop for move. Stage Break Shack and Enviro Vac to grade I-09. Press wash outside walls around rig. Preform EAM’s on cold starts. Prep Derrick for scoping down. Disconnect Mezz interconnects.;Blow down H2O. Conductor operations suspended due to Vib over heating and needing oil change. Start dirt work for I-09.;Daily fluid hauled to G&I 415 bbls total = 6,925 bbls Daily metal recovered 0 lbs, total = 0 lbs Daily water hauled from L Pad Lake 85 bbls total = 5,415 bbls Total Fluid lost surface hole = 28 bbls 6/22/2020 Lift stairways. Remove cuttings box, Enviro-Vac, Break shack and stage. Remove mats to allow Roads and Pads to dress location in front of I-09. Set containment and mats around I-09 cellar. Set mats to walk rig down well row. Secure well and release from I-20. Peak on location 11:00 am;Last report, moving to I-20.;Daily fluid hauled to G&I 47 bbls total = 6,972 bbls Daily metal recovered 0 lbs, total = 0 lbs Daily water hauled from L Pad Lake bbls total = 5,415 bbls Total Fluid lost surface hole = 28 bbls 17 June, 2020 Milne Point M Pt I Pad MPU I-20 500292367900 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt I Pad Halliburton Definitive Survey Report Well: Wellbore: Rig: MPU I-20 MPU I-20 Survey Calculation Method:Minimum Curvature MPU I-20 Actual RKB @ 60.15usft Design:MPU I-20 Database:NORTH US + CANADA MD Reference:MPU I-20 Actual RKB @ 60.15usft North Reference: Well Rig: MPU I-20 True Map System: Geo Datum: Project Map Zone: System Datum:US State Plane 1927 (Exact solution) NAD 1927 (NADCON CONUS) Milne Point, ACT, MILNE POINT Alaska Zone 04 Mean Sea Level Using Well Reference Point Using geodetic scale factor Well Well Position Longitude: Latitude: Easting: Northing: usft +E/-W +N/-S Position Uncertainty usft usft usftGround Level: Rig: MPU I-20 usft usft 0.00 0.00 6,009,436.15 551,863.83 33.40Wellhead Elevation:33.70 usft0.50 70° 26' 11.482 N 149° 34' 37.726 W Wellbore Declination (°) Field Strength (nT) Sample Date Dip Angle (°) MPU I-20 Model NameMagnetics IFR 7/1/2020 15.92 80.86 57,381.00000000 Phase:Version: Audit Notes: Design MPU I-20 1.0 ACTUAL Vertical Section: Depth From (TVD) (usft) +N/-S (usft) Direction (°) +E/-W (usft) Tie On Depth:26.45 6.600.000.0026.45 From (usft) Survey Program DescriptionTool NameSurvey (Wellbore) To (usft) Date 6/17/2020 Survey Date 3_Gyro-GC_Csg H049Gb: North seeking on wireline in casing100.00 466.00 MPU I-20 E-Line Gyro (MPU I-20)06/09/2020 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sa509.48 5,082.85 MPU I-20 MWD+IFR2+MS+Sag (1) (MPU 06/15/2020 MD (usft) Inc (°) Azi (°) +E/-W (usft) +N/-S (usft) Survey TVD (usft) TVDSS (usft) Map Northing (ft) Map Easting (ft) Vertical Section (ft) DLS (°/100')Survey Tool Name 26.45 0.00 0.00 26.45 0.00 0.00-33.70 6,009,436.15 551,863.83 0.00 0.00 UNDEFINED 100.00 0.33 172.33 100.00 -0.21 0.0339.85 6,009,435.94 551,863.86 0.45 -0.21 3_Gyro-GC_Csg (1) 191.00 0.55 168.19 191.00 -0.90 0.15130.85 6,009,435.25 551,863.99 0.24 -0.87 3_Gyro-GC_Csg (1) 279.00 0.49 159.68 278.99 -1.66 0.37218.84 6,009,434.49 551,864.21 0.11 -1.61 3_Gyro-GC_Csg (1) 379.00 0.60 144.27 378.99 -2.49 0.82318.84 6,009,433.67 551,864.67 0.18 -2.38 3_Gyro-GC_Csg (1) 466.00 0.19 116.25 465.99 -2.92 1.22405.84 6,009,433.24 551,865.07 0.51 -2.76 3_Gyro-GC_Csg (1) 509.48 0.48 106.91 509.47 -3.01 1.46449.32 6,009,433.15 551,865.31 0.68 -2.82 3_MWD+IFR2+MS+Sag (2) 571.37 0.52 86.66 571.35 -3.07 1.99511.20 6,009,433.10 551,865.84 0.29 -2.82 3_MWD+IFR2+MS+Sag (2) 633.60 0.64 89.37 633.58 -3.05 2.62573.43 6,009,433.12 551,866.47 0.20 -2.73 3_MWD+IFR2+MS+Sag (2) 695.63 0.53 93.90 695.61 -3.06 3.25635.46 6,009,433.11 551,867.10 0.19 -2.67 3_MWD+IFR2+MS+Sag (2) 760.43 0.52 81.41 760.40 -3.04 3.84700.25 6,009,433.14 551,867.69 0.18 -2.58 3_MWD+IFR2+MS+Sag (2) 823.60 0.57 83.40 823.57 -2.96 4.43763.42 6,009,433.22 551,868.28 0.08 -2.43 3_MWD+IFR2+MS+Sag (2) 887.02 0.65 107.54 886.99 -3.03 5.09826.84 6,009,433.15 551,868.94 0.42 -2.43 3_MWD+IFR2+MS+Sag (2) 6/17/2020 12:10:03PM 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 Halliburton Definitive Survey Report Well: Wellbore: Rig: MPU I-20 MPU I-20 Survey Calculation Method:Minimum Curvature MPU I-20 Actual RKB @ 60.15usft Design:MPU I-20 Database:NORTH US + CANADA MD Reference:MPU I-20 Actual RKB @ 60.15usft North Reference: Well Rig: MPU I-20 True MD (usft) Inc (°) Azi (°) +E/-W (usft) +N/-S (usft) Survey TVD (usft) TVDSS (usft) Map Northing (ft) Map Easting (ft) Vertical Section (ft) DLS (°/100')Survey Tool Name 950.71 0.77 306.07 950.68 -2.89 5.09890.53 6,009,433.30 551,868.94 2.20 -2.28 3_MWD+IFR2+MS+Sag (2) 1,014.50 1.47 306.86 1,014.45 -2.15 4.09954.30 6,009,434.03 551,867.93 1.10 -1.66 3_MWD+IFR2+MS+Sag (2) 1,077.87 0.99 339.46 1,077.81 -1.15 3.251,017.66 6,009,435.03 551,867.08 1.31 -0.76 3_MWD+IFR2+MS+Sag (2) 1,141.45 0.74 338.71 1,141.38 -0.25 2.901,081.23 6,009,435.92 551,866.74 0.39 0.09 3_MWD+IFR2+MS+Sag (2) 1,205.07 0.66 319.98 1,205.00 0.41 2.521,144.85 6,009,436.58 551,866.35 0.38 0.70 3_MWD+IFR2+MS+Sag (2) 1,267.61 0.96 194.97 1,267.53 0.18 2.151,207.38 6,009,436.35 551,865.98 2.31 0.43 3_MWD+IFR2+MS+Sag (2) 1,332.42 2.82 186.78 1,332.31 -1.92 1.821,272.16 6,009,434.24 551,865.67 2.89 -1.70 3_MWD+IFR2+MS+Sag (2) 1,396.27 3.71 185.39 1,396.05 -5.54 1.441,335.90 6,009,430.62 551,865.31 1.40 -5.34 3_MWD+IFR2+MS+Sag (2) 1,459.20 5.27 186.81 1,458.79 -10.44 0.911,398.64 6,009,425.72 551,864.81 2.49 -10.26 3_MWD+IFR2+MS+Sag (2) 1,522.94 6.65 191.22 1,522.18 -16.96 -0.161,462.03 6,009,419.19 551,863.79 2.28 -16.87 3_MWD+IFR2+MS+Sag (2) 1,587.34 6.56 191.31 1,586.15 -24.23 -1.601,526.00 6,009,411.91 551,862.40 0.14 -24.25 3_MWD+IFR2+MS+Sag (2) 1,651.53 6.29 191.10 1,649.94 -31.27 -3.001,589.79 6,009,404.86 551,861.05 0.42 -31.41 3_MWD+IFR2+MS+Sag (2) 1,714.45 6.56 193.08 1,712.47 -38.16 -4.481,652.32 6,009,397.97 551,859.62 0.56 -38.42 3_MWD+IFR2+MS+Sag (2) 1,776.66 6.38 194.01 1,774.28 -44.97 -6.121,714.13 6,009,391.14 551,858.03 0.33 -45.38 3_MWD+IFR2+MS+Sag (2) 1,841.29 6.31 196.15 1,838.51 -51.87 -7.971,778.36 6,009,384.23 551,856.22 0.38 -52.44 3_MWD+IFR2+MS+Sag (2) 1,904.99 5.55 192.28 1,901.87 -58.24 -9.601,841.72 6,009,377.85 551,854.63 1.35 -58.96 3_MWD+IFR2+MS+Sag (2) 1,968.64 5.42 193.59 1,965.23 -64.17 -10.961,905.08 6,009,371.91 551,853.31 0.28 -65.01 3_MWD+IFR2+MS+Sag (2) 2,032.29 5.08 191.44 2,028.61 -69.85 -12.231,968.46 6,009,366.22 551,852.09 0.62 -70.80 3_MWD+IFR2+MS+Sag (2) 2,095.81 4.83 195.77 2,091.90 -75.18 -13.512,031.75 6,009,360.88 551,850.84 0.71 -76.24 3_MWD+IFR2+MS+Sag (2) 2,159.51 4.64 193.05 2,155.38 -80.27 -14.822,095.23 6,009,355.78 551,849.57 0.46 -81.45 3_MWD+IFR2+MS+Sag (2) 2,223.18 5.08 188.43 2,218.82 -85.57 -15.822,158.67 6,009,350.48 551,848.61 0.92 -86.82 3_MWD+IFR2+MS+Sag (2) 2,286.71 5.47 189.98 2,282.08 -91.34 -16.762,221.93 6,009,344.71 551,847.71 0.65 -92.66 3_MWD+IFR2+MS+Sag (2) 2,349.98 5.59 188.45 2,345.06 -97.35 -17.732,284.91 6,009,338.68 551,846.78 0.30 -98.75 3_MWD+IFR2+MS+Sag (2) 2,413.49 4.70 196.92 2,408.31 -102.90 -18.942,348.16 6,009,333.13 551,845.60 1.84 -104.40 3_MWD+IFR2+MS+Sag (2) 2,476.73 2.93 210.82 2,471.41 -106.77 -20.532,411.26 6,009,329.25 551,844.05 3.14 -108.42 3_MWD+IFR2+MS+Sag (2) 2,540.57 1.79 253.64 2,535.20 -108.45 -22.322,475.05 6,009,327.55 551,842.27 3.17 -110.30 3_MWD+IFR2+MS+Sag (2) 2,604.48 2.65 318.19 2,599.07 -107.63 -24.262,538.92 6,009,328.36 551,840.32 3.88 -109.71 3_MWD+IFR2+MS+Sag (2) 2,668.44 4.65 334.61 2,662.90 -104.19 -26.362,602.75 6,009,331.79 551,838.20 3.50 -106.53 3_MWD+IFR2+MS+Sag (2) 2,731.77 7.35 341.84 2,725.88 -98.02 -28.722,665.73 6,009,337.94 551,835.79 4.42 -100.67 3_MWD+IFR2+MS+Sag (2) 2,795.31 9.91 346.46 2,788.69 -88.84 -31.272,728.54 6,009,347.10 551,833.18 4.17 -91.84 3_MWD+IFR2+MS+Sag (2) 2,858.95 12.42 350.32 2,851.12 -76.77 -33.702,790.97 6,009,359.16 551,830.66 4.11 -80.13 3_MWD+IFR2+MS+Sag (2) 2,921.49 14.98 352.18 2,911.88 -62.13 -35.932,851.73 6,009,373.78 551,828.33 4.15 -65.85 3_MWD+IFR2+MS+Sag (2) 2,986.73 17.29 351.37 2,974.55 -44.19 -38.542,914.40 6,009,391.70 551,825.61 3.56 -48.32 3_MWD+IFR2+MS+Sag (2) 3,049.36 19.88 351.00 3,033.90 -24.46 -41.602,973.75 6,009,411.40 551,822.41 4.14 -29.08 3_MWD+IFR2+MS+Sag (2) 3,113.42 22.62 351.82 3,093.60 -1.51 -45.063,033.45 6,009,434.33 551,818.79 4.30 -6.68 3_MWD+IFR2+MS+Sag (2) 3,177.48 25.84 351.83 3,152.01 24.51 -48.793,091.86 6,009,460.32 551,814.87 5.03 18.74 3_MWD+IFR2+MS+Sag (2) 3,241.07 29.33 352.92 3,208.37 53.69 -52.683,148.22 6,009,489.47 551,810.78 5.55 47.28 3_MWD+IFR2+MS+Sag (2) 3,302.53 31.14 353.34 3,261.46 84.42 -56.383,201.31 6,009,520.17 551,806.87 2.97 77.38 3_MWD+IFR2+MS+Sag (2) 3,367.20 33.69 354.13 3,316.05 118.88 -60.163,255.90 6,009,554.59 551,802.85 4.00 111.17 3_MWD+IFR2+MS+Sag (2) 3,429.56 35.95 354.59 3,367.24 154.31 -63.653,307.09 6,009,590.00 551,799.11 3.65 145.97 3_MWD+IFR2+MS+Sag (2) 6/17/2020 12:10:03PM 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 Halliburton Definitive Survey Report Well: Wellbore: Rig: MPU I-20 MPU I-20 Survey Calculation Method:Minimum Curvature MPU I-20 Actual RKB @ 60.15usft Design:MPU I-20 Database:NORTH US + CANADA MD Reference:MPU I-20 Actual RKB @ 60.15usft North Reference: Well Rig: MPU I-20 True MD (usft) Inc (°) Azi (°) +E/-W (usft) +N/-S (usft) Survey TVD (usft) TVDSS (usft) Map Northing (ft) Map Easting (ft) Vertical Section (ft) DLS (°/100')Survey Tool Name 3,494.72 37.70 355.65 3,419.40 193.22 -66.973,359.25 6,009,628.88 551,795.53 2.86 184.24 3_MWD+IFR2+MS+Sag (2) 3,558.41 39.49 355.76 3,469.18 232.84 -69.943,409.03 6,009,668.47 551,792.28 2.81 223.26 3_MWD+IFR2+MS+Sag (2) 3,621.91 42.10 355.48 3,517.25 274.20 -73.113,457.10 6,009,709.81 551,788.82 4.12 263.98 3_MWD+IFR2+MS+Sag (2) 3,685.67 45.26 354.52 3,563.35 318.06 -76.963,503.20 6,009,753.64 551,784.67 5.06 307.11 3_MWD+IFR2+MS+Sag (2) 3,749.16 46.38 355.22 3,607.60 363.41 -81.033,547.45 6,009,798.95 551,780.28 1.93 351.69 3_MWD+IFR2+MS+Sag (2) 3,812.51 46.21 354.85 3,651.37 409.03 -84.993,591.22 6,009,844.54 551,776.00 0.50 396.55 3_MWD+IFR2+MS+Sag (2) 3,876.07 47.93 354.38 3,694.66 455.36 -89.363,634.51 6,009,890.84 551,771.31 2.76 442.07 3_MWD+IFR2+MS+Sag (2) 3,940.14 50.66 354.24 3,736.44 503.69 -94.183,676.29 6,009,939.12 551,766.16 4.26 489.53 3_MWD+IFR2+MS+Sag (2) 4,003.17 54.23 353.98 3,774.85 553.39 -99.313,714.70 6,009,988.78 551,760.69 5.67 538.30 3_MWD+IFR2+MS+Sag (2) 4,066.62 58.20 354.03 3,810.13 605.82 -104.813,749.98 6,010,041.17 551,754.82 6.26 589.76 3_MWD+IFR2+MS+Sag (2) 4,130.62 62.77 353.36 3,841.65 661.16 -110.943,781.50 6,010,096.46 551,748.31 7.20 644.03 3_MWD+IFR2+MS+Sag (2) 4,193.49 65.48 353.39 3,869.08 717.35 -117.463,808.93 6,010,152.59 551,741.39 4.31 699.09 3_MWD+IFR2+MS+Sag (2) 4,255.95 69.43 354.15 3,893.03 774.68 -123.723,832.88 6,010,209.88 551,734.74 6.42 755.33 3_MWD+IFR2+MS+Sag (2) 4,321.20 73.19 353.51 3,913.93 836.12 -130.363,853.78 6,010,271.26 551,727.67 5.84 815.60 3_MWD+IFR2+MS+Sag (2) 4,384.29 74.29 354.07 3,931.60 896.33 -136.913,871.45 6,010,331.42 551,720.70 1.94 874.65 3_MWD+IFR2+MS+Sag (2) 4,448.40 76.67 355.50 3,947.67 958.13 -142.553,887.52 6,010,393.17 551,714.64 4.29 935.40 3_MWD+IFR2+MS+Sag (2) 4,511.96 78.00 355.16 3,961.61 1,019.94 -147.603,901.46 6,010,454.94 551,709.16 2.16 996.21 3_MWD+IFR2+MS+Sag (2) 4,574.76 79.88 356.23 3,973.65 1,081.39 -152.223,913.50 6,010,516.35 551,704.11 3.43 1,056.73 3_MWD+IFR2+MS+Sag (2) 4,638.30 82.66 356.67 3,983.30 1,144.07 -156.113,923.15 6,010,579.00 551,699.78 4.43 1,118.55 3_MWD+IFR2+MS+Sag (2) 4,702.61 83.99 356.02 3,990.77 1,207.81 -160.183,930.62 6,010,642.70 551,695.27 2.30 1,181.40 3_MWD+IFR2+MS+Sag (2) 4,766.27 83.25 356.59 3,997.85 1,270.95 -164.263,937.70 6,010,705.80 551,690.75 1.46 1,243.64 3_MWD+IFR2+MS+Sag (2) 4,829.85 84.88 355.56 4,004.42 1,334.03 -168.593,944.27 6,010,768.85 551,685.99 3.03 1,305.82 3_MWD+IFR2+MS+Sag (2) 4,893.60 84.76 355.83 4,010.18 1,397.34 -173.353,950.03 6,010,832.12 551,680.78 0.46 1,368.16 3_MWD+IFR2+MS+Sag (2) 4,956.70 84.25 356.50 4,016.22 1,460.01 -177.563,956.07 6,010,894.75 551,676.14 1.33 1,429.93 3_MWD+IFR2+MS+Sag (2) 5,019.50 86.88 355.77 4,021.07 1,522.48 -181.783,960.92 6,010,957.18 551,671.49 4.35 1,491.49 3_MWD+IFR2+MS+Sag (2) 5,082.85 89.07 356.29 4,023.31 1,585.63 -186.163,963.16 6,011,020.29 551,666.67 3.55 1,553.73 3_MWD+IFR2+MS+Sag (2) 5,121.00 89.07 356.29 4,023.93 1,623.70 -188.633,963.78 6,011,058.34 551,663.94 0.00 1,591.26 PROJECTED to TD Approved By:Checked By:Date: 6/17/2020 12:10:03PM COMPASS 5000.15 Build 91E Page 4 Chelsea Wright Digitally signed by Chelsea Wright Date: 2020.06.17 09:13:09 -08'00' _____________________________________________________________________________________ Edited By: JNL 7-17-2020 MPU I-20 Schematic Milne Point Unit Well: MPU I-20 Last Completed: Future PTD: 220-049 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20" Conductor 129.5# / X56 / Weld N/A Surface 107’ N/A 9-5/8" Surface 47 / L-80 / TXP 8.679 Surface 1,883’ 0.0758 9-5/8” Surface 40 / L-80 / TXP 8.525 1,883’ 5,111’ 0.0758 TUBING DETAIL 3-1/2" Kill String 9.3 / L-80 / EUE-8rd 2.992 Surface 2,241’ 0.0087 OPEN HOLE / CEMENT DETAIL Conductor ±270 ft3 12-1/4" Stg 1 – Lead – 385 sx / Tail – 400 sx Stg 2 – Lead – 510 sx / Tail – 270 sx 8-1/2” FUTURE WELL INCLINATION DETAIL KOP @ 1300’ Max Hole Angle = 89 TREE & WELLHEAD Tree Cameron 3 1/8" 5M w/ 4-1/16” 5M Cameron Wing Wellhead Cameron 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs GENERAL WELL INFO API: 50-029-23679-00-00 Completion Date: Operations Shutdown JEWELRY DETAIL No. Top MD Item ID 1 2,209’ 3-1/2” Mule Shoe 2.992” DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-23679-00-00Well Name/No. MILNE PT UNIT I-20Completion Status1-OILCompletion Date4/8/2021Permit to Drill2200490Operator Hilcorp Alaska, LLCMD11800TVD4122Current 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/DataTypeLogScaleDF4/9/2021 Electronic File: MPU I-20 EOW Geosteering Log.emf34958EDDigital DataDF4/9/2021 Electronic File: MPU I-20 EOW Geosteering Log.pdf34958EDDigital DataDF4/9/2021 Electronic File: MPU I-20 EOW Geosteering Log.tiff34958EDDigital DataDF4/9/2021 Electronic File: MPU I-20 EOW Geosteering Report Rev1.pdf34958EDDigital DataDF4/9/2021 Electronic File: MPU I-20 Post-Well Geosteering X-Section Summary.pdf34958EDDigital DataDF4/9/2021105 11800 Electronic Data Set, Filename: MPU I-20 LWD Final.las34959EDDigital DataDF4/9/20215103 11762 Electronic Data Set, Filename: MPU I-20 ADR Quadrants All Curves.las34959EDDigital DataDF4/9/2021 Electronic File: MPU I-20 LWD Final MD.cgm34959EDDigital DataDF4/9/2021 Electronic File: MPU I-20 LWD Final TVD.cgm34959EDDigital DataDF4/9/2021 Electronic File: MPU I-20 Surveys.xlsx34959EDDigital DataDF4/9/2021 Electronic File: MPU I-20_Definitive Survey Report.pdf34959EDDigital DataDF4/9/2021 Electronic File: MPU I-20_Definitive Survey Report.txt34959EDDigital DataDF4/9/2021 Electronic File: MPU I-20_GIS.txt34959EDDigital DataDF4/9/2021 Electronic File: MPU I-20_Plan.pdf34959EDDigital DataDF4/9/2021 Electronic File: MPU I-20_VSec.pdf34959EDDigital DataMonday, June 28, 2021AOGCCPage 1 of 3MPU I-20 LWD Final.las DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-23679-00-00Well Name/No. MILNE PT UNIT I-20Completion Status1-OILCompletion Date4/8/2021Permit to Drill2200490Operator Hilcorp Alaska, LLCMD11800TVD4122Current Status1-OIL6/28/2021UICNoWell Cores/Samples Information:ReceivedStart Stop CommentsTotalBoxesSample SetNumberNameIntervalINFORMATION RECEIVEDCompletion ReportProduction Test InformationGeologic Markers/TopsY Y / NAYComments:Mud Logs, Image Files, Digital DataComposite Logs, Image, Data Files Cuttings SamplesY / NAYY / NADirectional / Inclination DataMechanical Integrity Test InformationDaily Operations SummaryYY / NAYCore ChipsCore PhotographsLaboratory AnalysesY / NAY / NAY / NACOMPLIANCE HISTORYDate CommentsDescriptionCompletion Date:4/8/2021Release Date:6/11/2020DF4/9/2021 Electronic File: MPU I-20 LWD Final MD.emf34959EDDigital DataDF4/9/2021 Electronic File: MPU I-20 LWD Final TVD.emf34959EDDigital DataDF4/9/2021 Electronic File: MPU_I-20_Geosteering.dlis34959EDDigital DataDF4/9/2021 Electronic File: MPU_I-20_Geosteering.ver34959EDDigital DataDF4/9/2021 Electronic File: MPU I-20 LWD Final MD.pdf34959EDDigital DataDF4/9/2021 Electronic File: MPU I-20 LWD Final TVD.pdf34959EDDigital DataDF4/9/2021 Electronic File: MPU I-20 LWD Final MD.tif34959EDDigital DataDF4/9/2021 Electronic File: MPU I-20 LWD Final TVD.tif34959EDDigital Data0 0 2200490 MILNE PT UNIT I-20 LOG HEADERS34959EDLog Header ScansMonday, June 28, 2021AOGCCPage 2 of 3 DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-23679-00-00Well Name/No. MILNE PT UNIT I-20Completion Status1-OILCompletion Date4/8/2021Permit to Drill2200490Operator Hilcorp Alaska, LLCMD11800TVD4122Current Status1-OIL6/28/2021UICNoCompliance Reviewed By:Date:Monday, June 28, 2021AOGCCPage 3 of 3M. Guhl 6/28/2021 1.Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: ___________________ 2.Operator Name:4.Current Well Class:5.Permit to Drill Number: Exploratory Development 3.Address:Stratigraphic Service 6.API Number: 7.If perforating:8.W ell Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception?Yes No 9.Property Designation (Lease Number):10. Field/Pool(s): 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 5121'None Casing Collapse Structural Conductor Surface 4760 / 3090 Intermediate Production Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments:Proposal Summary Wellbore schematic 13.Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14.Estimated Date for 15.Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16.Verbal Approval:Date:GAS WAG GSTOR SPLUG Commission Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Date: Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng 17.I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Signature: 6/22/2020 3-1/2" 9.3# None Authorized Title: Drilling Manager Authorized Name: Monty Myers Perforation Depth MD (ft): None Perforation Depth TVD (ft):Tubing Size: 20" 9-5/8" 80 5111 MD 6870 / 5750 107' 4024' 107' 5111' Milne Point Field, Schrader Bluff Oil Pool MPU I-20 PRESENT WELL CONDITION SUMMARY L-80 Kill String TVD Burst 2241' STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL 025906, 315848 220-049 3800 Centerpoint Drive, Suite 1400, Acnhorage, AK 99503 50-029-23679-00-00 Hilcorp Alaska, LLC COMMISSION USE ONLY Tubing Grade:Tubing MD (ft): Joe Lastufka joseph.lastufka@hilcorp.com 4024'5009'4024'None Length Size m n P 66 t _ s Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. 7.20.2020 By Jody Colombie at 8:41 am, Jul 20, 2020 320-306 Digitally signed by Monty M Myers DN: cn=Monty M Myers, c=US, o=Hilcorp Alaska, LLC, ou=Technical Services - AK Drilling, email=mmyers@hilcorp.com Reason: I am approving this document Date: 2020.07.20 06:56:00 -08'00' Monty M Myers DSR-7/20/2020 DLB 07/20/2020 X MGR20JUL20 10-404 Comm. 7/21/2020 JLC 7/20/2020 RBDMS HEW 7/24/2020 Well Update Well: MPU I-20 Date: 7/17/20 Well Name: MPU I-20 API Number: 50-029-23679-00-00 Current Status: RDMO Estimated Start Date: 6/22/2020 Rig: Innovation Reg. Approval Req’d? 10-403: Ops Shutdown Date Reg. Approval Rec’vd: Regulatory Contact: Joe Lastufka 227-8496 Permit to Drill Number: 220-049 First Call Engineer: Joe Engel (907) 777-8395 (O) (805)235-6265 (M) Brief Well Summary: MPU I-20 (PTD #220-049) was planned to be drilled and completed with a slotted liner. After spudding on 6/14/20, it was decided to use a screen completion due to MBEs in other OA wells. We released from the well on 6/22/20 due to lack of availability of completion screens. It was left as cemented, pressure tested surface casing with a kill string. We have 100% intention to come back and drill lateral once screens come in and rig schedule allows. Notes Regarding Wellbore: x 12-1/4” drilled to 5121’ MD x No Hydrocarbon bearing zone had been penetrated in this hole section Work performed: x 9-5/8” 47#/40# L-80 set at 5111’ x Cemented Stg 1: 385 sx / 400 sx, Stg 2: 510 sx, 270 sx x Run 3.5” killstring t/ 2,241’ MD. Attachments 1. Actual Schematic _____________________________________________________________________________________ Edited By: JNL 7-17-2020 MPU I-20 Schematic Milne Point Unit Well: MPU I-20 Last Completed: Future PTD: 220-049 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20" Conductor 129.5# / X56 / Weld N/A Surface 107’ N/A 9-5/8" Surface 47 / L-80 / TXP 8.679 Surface 1,883’ 0.0758 9-5/8” Surface 40 / L-80 / TXP 8.525 1,883’ 5,111’ 0.0758 TUBING DETAIL 3-1/2" Kill String 9.3 / L-80 / EUE-8rd 2.992 Surface 2,241’ 0.0087 OPEN HOLE / CEMENT DETAIL Conductor ±270 ft3 12-1/4" Stg 1 – Lead – 385 sx / Tail – 400 sx Stg 2 – Lead – 510 sx / Tail – 270 sx 8-1/2” FUTURE WELL INCLINATION DETAIL KOP @ 1300’ Max Hole Angle = 89 TREE & WELLHEAD Tree Cameron 3 1/8" 5M w/ 4-1/16” 5M Cameron Wing Wellhead Cameron 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs GENERAL WELL INFO API: 50-029-23679-00-00 Completion Date: Operations Shutdown JEWELRY DETAIL No. Top MD Item ID 1 2,209’ 3-1/2” Mule Shoe 2.992” 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signed by Benjamin Hand Date: 2021.04.05 09:35:51 -08'00' 1.Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: ___________________ 2.Operator Name:4.Current Well Class:5.Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating:8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception?Yes No 9.Property Designation (Lease Number):10.Field/Pool(s): 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 5121'None Casing Collapse Structural Conductor Surface 4760 / 3090 Intermediate Production Liner (FISH) Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13.Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14.Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date:GAS WAG GSTOR SPLUG Commission Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Date: Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by:COMMISSIONER THE COMMISSION Date: Comm.Comm.Sr Pet Eng Sr Pet Geo Sr Res Eng 17.I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Signature: March 20, 2021 3-1/2" 9.3# None Authorized Title: Drilling Manager Authorized Name: Monty Myers Perforation Depth MD (ft): None Perforation Depth TVD (ft): Tubing Size: 20" 9-5/8" 80' 5111' MD 6870 / 5750 107' 4024' 107' 5111' Milne Point Field, Schrader Bluff Oil Pool MPU I-20 PRESENT WELL CONDITION SUMMARY L-80 Kill String TVD Burst 2241' STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL 025906, 315848 220-049 3800 Centerpoint Drive, Suite 1400, Acnhorage, AK 99503 50-029-23679-00-00 Hilcorp Alaska, LLC COMMISSION USE ONLY Tubing Grade:Tubing MD (ft): Joe Engel jengel@hilcorp.com 777-8395 4024' 5009' 4024' None Length Size ory Statu Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. Change Slotted to Screen Liner on Approved PTD 2.24.2021 By Samantha Carlisle at 9:38 pm, Feb 24, 2021 321-096 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: 2021.02.24 17:43:51 -09'00' Monty M Myers BOPE test to 3000 psi. Annular to 2500 psi. MGR25FEB21 DSR-2/25/21 Single 10-407 for all drilling and completion on PTD 220-049 DLB 02/25/2021 X Com m. 2/26/21 dts 2/26/2021 JLC 2/26/2021 RBDMS HEW 2/26/2021 Milne Point Unit (MPU) I-20 Drilling Program Version 2 2/23/2021 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 Test BOPE ................................................................................................................. 10 10.0 Pull 3-1/2” Tubing .................................................................................................................... 11 11.0 Drill 8-1/2” Hole Section .......................................................................................................... 12 12.0 Run 4-1/2” Screened Liner ...................................................................................................... 17 13.0 Run 7-5/8” Tieback .................................................................................................................. 21 14.0 Run Upper Completion - ESP ................................................................................................. 24 15.0 Innovation Rig Diverter Schematic ......................................................................................... 27 16.0 Innovation Rig BOP Schematic ............................................................................................... 28 17.0 Wellhead Schematic ................................................................................................................. 29 18.0 Days Vs Depth .......................................................................................................................... 30 19.0 Formation Tops & Information............................................................................................... 31 20.0 Anticipated Drilling Hazards .................................................................................................. 32 21.0 Innovation Rig Layout ............................................................................................................. 35 22.0 FIT Procedure .......................................................................................................................... 36 23.0 Innovation Rig Choke Manifold Schematic ............................................................................ 37 24.0 Casing Design ........................................................................................................................... 38 25.0 8-1/2” Hole Section MASP ....................................................................................................... 39 26.0 Spider Plot (NAD 27) (Governmental Sections) ...................................................................... 40 27.0 Surface Plat (As Built) (NAD 27) ............................................................................................. 41 Page 2 Milne Point Unit I-20 SB Producer Drilling Procedure 1.0 Well Summary Well MPU I-20 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 16,103’ MD / 4,310’ TVD PBTD, MD / TVD 16,103’ MD / 4,310’ TVD Surface Location (Governmental) 2319' FSL, 3507' FEL, Sec 33, T13N, R10E, UM, AK Surface Location (NAD 27) X= 551863, Y=6009436 Top of Productive Horizon (Governmental)1448' FNL, 1589' FWL, Sec 33, T13N, R10E, UM, AK TPH Location (NAD 27) X= 551665 Y= 6010947 BHL (Governmental) 966' FNL, 2630' FEL, Sec 21, T13N, R10E, UM, AK BHL (NAD 27) X= 552621, Y=6021995 AFE Number AFE Drilling Days 21 AFE Completion Days 3 Maximum Anticipated Pressure (Surface) 1404 psig Maximum Anticipated Pressure (Downhole/Reservoir) 1764 psig Work String 5” 19.5# S-135 NC 50 Innovation KB Elevation above MSL: 26.5 ft + 33.4 ft = 59.9 ft GL Elevation above MSL: 33.4 ft BOP Equipment 13-5/8” x 5M Annular, (3) ea 13-5/8” x 5M Rams Page 3 Milne Point Unit I-20 SB Producer Drilling Procedure 2.0 Management of Change Information Page 4 Milne Point Unit I-20 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-52Weld 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-20 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, jengel@hilcorp.com and cdinger@hilcorp.com 5.3 Intranet Home Page Morning Update x Submit a short operations update each morning by 7am on the company intranet homepage. On weekend and holidays, ensure to have this update in before 5am. 5.4 EHS Incident Reporting x Health and Safety: Notify EHS field coordinator. x Environmental: Drilling Environmental Coordinator x Notify Drilling Manager & Drilling Engineer on all incidents x Submit Hilcorp Incident report to contacts above within 24 hrs 5.5 Casing Tally x Send final “As-Run” Casing tally to mmyers@hilcorp,com jengel@hilcorp.com and cdinger@hilcorp.com 5.6 Casing and Cement report x Send casing and cement report for each string of casing to mmyers@hilcorp.com jengel@hilcorp.com and cdinger@hilcorp.com 5.7 Hilcorp Milne Point Contact List: Title Name Work Phone Cell Phone Email Drilling Manager Monty Myers 907.777.8431 907.538.1168 mmyers@hilcorp.com Drilling Engineer Joe Engel 907.777.8395 805.235.6265 jengel@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-20 SB Producer Drilling Procedure 6.0 Planned Wellbore Schematic Page 7 Milne Point Unit I-20 SB Producer Drilling Procedure 7.0 Drilling / Completion Summary MPU I-20 is a grassroots producer planned to be drilled in the Schrader Bluff OB sand. I-20 is part of a multi well program targeting the Schrader Bluff sand on I-Pad The directional plan is a catenary well path build, 12.25” hole with 9-5/8” surface casing set into the top of the Schrader Bluff Ob 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 resume approximately March 20, 2021, pending rig schedule. Surface casing was run to 5,111’ MD and cemented to surface via a 2 stage primary cement job. A 3-1/2” kill string was installed and the drilling operation was suspended due to waiting on lower completion equipment. 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. NU 13-5/8” 5M BOP & Test 3. Pull kill string 4. Drill 8-1/2” lateral to well TD. 5. Run 4-1/2” production liner 6. Run 7-5/8” tieback 7. Run Upper Completion 8. N/D BOP, N/U Tree, RDMO Reservoir Evaluation Plan: 1. Surface hole: No mud logging. On Site geologist. LWD: GR + Res 2. Production Hole: No mud logging. Wellsite geologist. LWD: GR + ADR (For geo-steering) Page 8 Milne Point Unit I-20 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-20. Ensure to provide AOGCC 24 hrs notice prior to testing BOPs. x The initial test of BOP equipment will be to 250/3000 psi & subsequent tests of the BOP equipment will be to 250/3000 psi for 5/5 min (annular to 50% rated WP, 2500 psi on the high test for initial and subsequent tests).Confirm that these test pressures match those specified on the APD. x If the BOP is used to shut in on the well in a well control situation 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-20 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: 250/3000 Subsequent Tests: 250/3000 Primary closing unit: Control Technology Inc. (CTI), 6 station, 3000 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 Test/Inspection notification standardization format:http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) Page 10 Milne Point Unit I-20 SB Producer Drilling Procedure 9.0 R/U and Test BOPE 9.1 Ensure PTD and drilling program are posted in the rig office and on the rig floor. 9.2 Level pad and ensure enough room for layout of rig footprint and R/U. 9.3 Rig mat footprint of rig. 9.4 MIRU Innovation. Ensure rig is centered over conductor to prevent any wear to BOPE or wellhead. 9.5 Ensure BPV and test dart are installed. ND dryhole tree. 9.6 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 3-1/2” x 5” VBRs in top cavity,blind ram in bottom cavity. x Single ram can be dressed with 3-1/2” x 5” VBRs x NU bell nipple, install flowline. x Install (1) manual valve & HCR valve on kill side of mud cross. (Manual valve closest to mud cross). x Install (1) manual valve on choke side of mud cross. Install an HRC outside of the manual valve 9.7 Test BOP to 250/3000 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min. x Test with 3-1/2” and 5” test joints x Confirm test pressures with PTD x Ensure to monitor side outlet valves and annulus valve pressure gauges to ensure no pressure is trapped underneath test plug x Once BOPE test is complete, send a copy of the test report to town engineer and drilling tech 9.8 RD BOP test equipment. Pull test dart and BPV. Page 11 Milne Point Unit I-20 SB Producer Drilling Procedure 10.0 Pull 3-1/2” Tubing 10.1 RU to circulate out freeze protect fluid and circ out same. 10.2 PU landing joint or spear and recover the tubing hanger. 10.3 Back out lock down screws. 10.4 Pull tubing hanger with landing joint/XO to the floor. Have appropriate protectors ready. 10.5 The tubing is expected to be in good condition. 10.6 Note and record PU weight required to pull the tubing. 10.7 Circulate at least 1x BU after pulling the hanger to the floor. 10.8 Pull and lay down the tubing. Page 12 Milne Point Unit I-20 SB Producer Drilling Procedure 11.0 Drill 8-1/2” Hole Section 11.1 Mix 8.9 ppg Baradrill-N fluid for production hole. 11.2 Set wearbushing in wellhead. 11.3 If needed, rack back as much 5” DP in derrick as possible to be used while drilling the hole section. 11.4 Ensure 5” liners in mud pumps. 11.5 MU 8.5” Cleanout BHA (Milltooth Bit & 1.22° PDM) 11.6 TIH to TOC above the baffle adapter. Note depth TOC tagged on morning report. 11.7 RU and test casing to 2500 psi / 30 min. Ensure to record volume / pressure (every ¼ bbl) and plot on FIT graph. AOGCC reg is 50% of burst = 5750 / 2 = ~2875 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. 11.8 Drill out shoe track and 20’ of new formation. 11.9 CBU and condition mud for FIT. 11.10 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. 11.11 POOH and LD cleanout BHA 11.12 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. Page 13 Milne Point Unit I-20 SB Producer Drilling Procedure 11.13 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 11.14 TIH with 8-1/2” directional assembly to bottom Page 14 Milne Point Unit I-20 SB Producer Drilling Procedure 11.15 Install MPD RCD 11.16 Displace wellbore to 8.9 ppg Baradrill-N drilling fluid 11.17 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 11.18 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 OB 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 OB 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 is a long term shut in well. Coil tubing will cement and abandon the lateral prior to drilling I-20. The only risk is damage to the bit. 11.19 Reference: Open hole sidetracking practice: x If a known fault is coming up, put a slight “kick-off ramp” in wellbore ahead of the fault so we have a nice place to low side. x Attempt to lowside in a fast drilling interval where the wellbore is headed up. x Orient TF to low side and dig a trough with high flowrates for the first 10 ft, working string back and forth. Trough for ~30 min. Page 15 Milne Point Unit I-20 SB Producer Drilling Procedure x Time drill at 4 to 6 feet per hour with high flow rates. Gradually increase ROP as the openhole sidetrack is achieved. 11.20 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 11.21 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. 11.22 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. 11.23 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 11.24 If abnormal pressure has been observed in the lateral, utilize MPD to close on connections while BROOH. 11.25 CBU minimum two times at 9-5/8” shoe and clean casing with high vis sweeps. Page 16 Milne Point Unit I-20 SB Producer Drilling Procedure 11.26 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. 11.27 POOH and LD BHA. 11.28 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 17 Milne Point Unit I-20 SB Producer Drilling Procedure 12.0 Run 4-1/2” Screened Liner 12.1 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. 12.2 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. 12.3 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 18 Milne Point Unit I-20 SB Producer Drilling Procedure Page 19 Milne Point Unit I-20 SB Producer Drilling Procedure 12.6. 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. 12.7. 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. 12.8. M/U Baker SLZXP liner top packer to 4-1/2” liner. 12.9. 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. 12.10. RIH with liner on 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 (confirm HWDP requirement with drilling engineer). 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. 12.11. 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. 12.12. Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10, & 20 RPM. 12.13. If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensure shoe enters correct hole. 12.14. TIH deeper than planned setting depth. Last motion of the liner should be up to ensure it is set in tension. 12.15. Rig up to pump down the work string with the rig pumps. 12.16. 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 12.17. 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 20 Milne Point Unit I-20 SB Producer Drilling Procedure 12.18. 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. 12.19. 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. 12.20. 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. 12.21. PU to neutral weight, close BOP and test annulus to 1,500 psi for 10 minutes charted. 12.22. 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. 12.23. PU pulling running tool free of the packer and displace with at max rate to wash the liner top. Pump sweeps as needed. 12.24. 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 21 Milne Point Unit I-20 SB Producer Drilling Procedure 13.0 Run 7-5/8” Tieback 13.1 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. 13.2 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. 13.3 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. 13.4 MU first joint of 7-5/8” to seal assy. 13.5 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 22 Milne Point Unit I-20 SB Producer Drilling Procedure 13.6 MU 7-5/8” to DP crossover. 13.7 MU stand of DP to string, and MU top drive. 13.8 Break circulation at 1 BPM and begin lowering string. 13.9 Note seal assembly entering tieback sleeve with a pressure increase, stop pumping and bleed off pressure. Leave standpipe bleed off valve open. 13.10 Continue lowering string and land out on no-go. Set down 5 – 10K and mark the pipe as “NO- GO DEPTH”. 13.11 PU string & remove unnecessary 7-5/8” joints. Page 23 Milne Point Unit I-20 SB Producer Drilling Procedure 13.12 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. 13.13 PU and MU the 7-5/8” casing hanger. 13.14 Ensure circulation is possible through 7-5/8” string. 13.15 RU and circulation corrosion inhibited brine in the 9-5/8” x 7-5/8” annulus. 13.16 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). 13.17 SO and land hanger. Confirm hanger has seated properly in wellhead. Make note of actual weight on hanger on morning report. 13.18 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. 13.19 RD casing running tools. 13.20 PT 9-5/8” x 7-5/8” annulus to 1,000 psi for 30 minutes charted. Page 24 Milne Point Unit I-20 SB Producer Drilling Procedure 14.0 Run Upper Completion - ESP 14.1 RU spooler with ESP power cable and heat trace. 14.2 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. 14.3 Makeup new ESP assembly with new motor lead extension, seal section and motor. 14.4 Run the 3-1/2” ESP Completion as noted below. The completion includes two 3/8” capillary tube from surface to the centralizer on the motor. The capillary tube will be secured to the tubing with Cannon clamps. Function test the capillary tube every ~2,000’ by pumping ~2 gallons of hydraulic oil through the check valves. Record the pressure at each testing point Page 25 Milne Point Unit I-20 SB Producer Drilling Procedure 14.5 M/U ESP assy and RIH to setting depth. Confirm tally with Operations Engineer i. Ensure appropriate well control crossovers on rig floor and ready. ii. Monitor displacement from wellbore while RIH. x Centrilift ESP Assembly with bottom of assembly @ predetermined depth x 10’ 3-1/2” 9.3#, L-80 Pup Joint x 1 joint 3-1/2” 9.3#, L-80 EUE 8rd tubing x 3-1/2” “XN” nipple (2.813” packing bore / 2.75” No-Go ID) x 3 joints 3-1/2” 9.3#, L-80 EUE 8rd tubing x 10’ 3-1/2” 9.3#, L-80 Pup Joint x GLM 3-1/2” x 1” GLM w/ dummy installed x 10’ 3-1/2” 9.3#, L-80 Pup Joint x 3-1/2” 9.3#, L-80 EUE 8rd tubing x 10’ 3-1/2” 9.3#, L-80 Pup Joint x GLM 3-1/2” x 1” w/ SO @ ~140’ MD x 10’ 3-1/2” 9.3#, L-80 Pup Joint x 3 joints 3-1/2” 9.3#, L-80 EUE 8rd tubing x Tubing Hanger o Check the conductivity of electric cable every 2,000’ and every new splice while running in hole. o Use Cannon clamps on every joint to secure the capillary tube. o The make up torque values for 3-1/2” L-80 9.3# EUE 8rd tubing are: Minimum: 2350 ft-lb, Optimum: 3100 ft-lb, and maximum: 3910 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, psi. 14.6 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. 14.7 Record PU and SO weights before landing hanger. Note PU and SO weights on tally along with band/clamp summary. 14.8 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. 14.9 Land tubing with extreme care to minimize damaging the ESP penetrator, pigtail and alignment pin. 14.10 RILDS and test hanger. LD landing joint. 14.11 Install BPV and N/D BOP. Page 26 Milne Point Unit I-20 SB Producer Drilling Procedure 14.12 N/U tree / adapter and tree. Test tubing hanger void to 500 psi low / 5000 psi high. Terminate the cap strings. 14.13 Circulate diesel freeze protection down 3-1/2” x 7-5/8” annulus (Volume should equal capacity of tubing to 2500’ + tubing annulus to 2500’). Connect IA to tree and allow diesel freeze protect to “U- tube” into position. Note – this may be done post-rig. 14.14 Pull BPV. Set TWC. Test tree to 250 psi low / 5000 psi high. Pull TWC. Set BPV. 14.15 Prepare to hand over well to production. Ensure necessary forms filled out and well handed over with valve alignment as per operations personnel. 14.16 RDMO Innovation Page 27 Milne Point Unit I-20 SB Producer Drilling Procedure 15.0 Innovation Rig Diverter Schematic Page 28 Milne Point Unit I-20 SB Producer Drilling Procedure 16.0 Innovation Rig BOP Schematic Page 29 Milne Point Unit I-20 SB Producer Drilling Procedure 17.0 Wellhead Schematic Page 30 Milne Point Unit I-20 SB Producer Drilling Procedure 18.0 Days Vs Depth Page 31 Milne Point Unit I-20 SB Producer Drilling Procedure 19.0 Formation Tops & Information Page 32 Milne Point Unit I-20 SB Producer Drilling Procedure 20.0 Anticipated Drilling Hazards 12-1/4” Hole Section: Lost Circulation Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Gas Hydrates Gas hyrates have not been seen on Moose pad. However, be prepared for them. Remember that hydrate gas behave differently from a gas sand. Additional fluid density will not prevent influx of gas hydrates, but can help control the breakout at surface. Once a gas hydrate has been disturbed the gas will come out of the hole. Drill through the hydrate section as quickly as possible while minimizing gas belching. Minimize circulation time while drilling through the hydrate zone. Excessive circulation will accelerate formation thawing which can increase the amount of hydrates released into the wellbore. Keep the mud circulation temperature as cold as possible. Weigh mud with both a pressurized and non-pressurized mud scale. The non-pressurized scale will reflect the actual mud cut weight. Add 1.0 – 2.0 ppb Lecithin to the system to help thin the mud and release the gas. Isolate/dump contaminated fluid to remove hydrates from the system. Hole Cleaning: Maintain rheology of mud system. Sweep hole with high viscosity sweeps as necessary. Optimize solids control equipment to maintain density, sand content, and reduce the waste stream. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to avoid washing out a particular section of the hole. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Anti-Collison: 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 Page 33 Milne Point Unit I-20 SB Producer Drilling Procedure Wellbore stability (Permafrost, running sands and gravel, conductor broaching): Washouts in the permafrost can be severe if the string is left circulating across it for extended periods of time. Keep mud as cool as possible by taking on cold water and diluting often. High TOH and RIH speeds can aggravate fragile shale/coal formations due to the pressure variations between surge and swab. Bring the pumps on slowly after connections. Monitor conductor for any signs of broaching. Maintain mud parameters and increase MW to combat running sands and gravel formations. H2S: Treat every hole section as though it has the potential for H2S. No H2S events have been documented on drill wells on this pad. 1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Page 34 Milne Point Unit I-20 SB Producer Drilling Procedure 8-1/2” Hole Section: Hole Cleaning: Maintain rheology of mud system. Sweep hole with low-vis water sweeps. Ensure shakers are set up with appropriate screens to maximize solids removal efficiency. Run centrifuge continuously. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Maintain circulation rate of > 300 gpm Lost Circulation: Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Faulting: There is at least (1) fault that will be crossed while drilling the well. There could be others and the throw of these faults is not well understood at this point in time. When a known fault is coming up, ensure to put a “ramp” in the wellbore to aid in kicking off (low siding) later. Once a fault is crossed, we’ll need to either drill up or down to get a look at the LWD log and determine the throw and then replan the wellbore. H2S: Treat every hole section as though it has the potential for H2S. 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 is a long term shut in well. Coil tubing will cement and abandon the lateral prior to drilling I-20. The only risk is damage to the bit. Page 35 Milne Point Unit I-20 SB Producer Drilling Procedure 21.0 Innovation Rig Layout Page 36 Milne Point Unit I-20 SB Producer Drilling Procedure 22.0 FIT Procedure Formation Integrity Test (FIT) and Leak-Off Test (LOT) Procedures Procedure for FIT: 1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe). 2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe. 3. Close the blowout preventer (ram or annular). 4. Pump down the drill stem at 1/4 to 1/2 bpm. 5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe. 6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes. Record time vs. pressure in 1-minute intervals. 7. Bleed the pressure off and record the fluid volume recovered. The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick tolerance in case well control measures are required. Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid; at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure monitored as with an FIT. Ensure that casing test and subsequent FIT tests are recorded on the same chart. Document incremental volume pumped and returned during test. Page 37 Milne Point Unit I-20 SB Producer Drilling Procedure 23.0 Innovation Rig Choke Manifold Schematic Page 38 Milne Point Unit I-20 SB Producer Drilling Procedure 24.0 Casing Design Page 39 Milne Point Unit I-20 SB Producer Drilling Procedure 25.0 8-1/2” Hole Section MASP Page 40 Milne Point Unit I-20 SB Producer Drilling Procedure 26.0 Spider Plot (NAD 27) (Governmental Sections) Page 41 Milne Point Unit I-20 SB Producer Drilling Procedure 27.0 Surface Plat (As Built) (NAD 27) 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: 04/09/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU I-20 (PTD 220-049) FINAL EOW REPORT – GEOSTEERING LOGS (03/21/2021 to 04/03/2021) SFTP Transfer - Data Folders: Please include current contact information if different from above. PTD: 2200490 E-Set: 34958 Received by the AOGCC 04/09/2021 04/12/2021 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: 04/09/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU I-20 (PTD 220-049) FINAL LWD FORMATION EVALUATION LOGS (06/14/2020 to 04/03/2021) •EWR-M5, AGR, ABG, DGR, ADR, Horizontal Presentation (2” & 5” MD/TVD Color Logs) •Final Definitive Directional Survey SFTP Transfer - Data Folders: Please include current contact information if different from above. PTD: 2200490 E-Set: 34959 Received by the AOGCC 04/09/2021 04/09/2021 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-20 Hilcorp Alaska, LLC Permit to Drill Number: 220-049 Surface Location: 2319' FSL, 3507' FEL, Sec 33, T13N, R10E, UM, AK Bottomhole Location: 966' FNL, 2630' FEL, Sec 21, T13N, R10E, UM, AK Dear Mr. Myers: Enclosed is the approved application for the permit to drill the above referenced development well. Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Jeremy M. Price Chair DATED this ___ day of June, 2020. y JMPi 11 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: 16,103' TVD: 4,310' 4a. Location of Well (Governmental Section):7. Property Designation: Surface: Top of Productive Horizon:8. DNR Approval Number: 13. Approximate Spud Date: Total Depth:9. Acres in Property: 14. Distance to Nearest Property: 4b. Location of Well (State Base Plane Coordinates - NAD 27):10. KB Elevation above MSL (ft): 60.2' 15. Distance to Nearest Well Open Surface: x-551863 y- 6009436 Zone-4 33.7' to Same Pool: 160' to MPU J-01A 16. Deviated wells:Kickoff depth: 1,300 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 89 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD Cond 20" 129.5# X-56 Weld 107' Surface Surface 107' 107' 47# L-80 TXP 2,000' Surface Surface 2,000' 1,998' 40# L-80 TXP 2,987' 2,000' 1,998' 4,987' 4,010' 8-1/2" 6-5/8" 20# L-80 Hyd 563 11,266' 4,837' 3,997' 16,103' 4,310' Tieback 7-5/8" 29.7# L-80 Hyd 521 4,837' Surface Surface 4,837' 3,997' 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 3832' to nearest unit boundary 6/14/2020 Authorized Name: Monty Myers Authorized Title: Drilling Manager Joe Engel jengel@hilcorp.com 777-8395 18. Casing Program:Top - Setting Depth - BottomSpecifications MPU I-20 Milne Point Field Schrader Bluff Oil Pool 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 Hilcorp Alaska, LLC 2319' FSL, 3507' FEL, Sec 33, T13N, R10E, UM, AK ADL025906, ADL315848 022224484 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 Stg 2 L - 1937 ft3 / T - 314 ft3 1404 1448' FNL, 1589' FWL, Sec 33, T13N, R10E, UM, AK 966' FNL, 2630' FEL, Sec 21, T13N, R10E, UM, AK LONS 88-004 3840 1764 Total Depth MD (ft):Total Depth TVD (ft): Cement Quantity, c.f. or sacks Cement Volume MDSize Plugs (measured): (including stage data) Driven Stg 1 L - 606 ft3 / T - 458 ft3 Effect. Depth TVD (ft): Conductor/Structural LengthCasing Intermediate Cementless Slotted Liner Tieback Assembly Effect. Depth MD (ft): Authorized Signature: Production Liner Commission Use Only 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. Surface Perforation Depth TVD (ft): GL / BF Elevation above MSL (ft): 6/1/2020 12-1/4"9-5/8" s N ype of W L l R L 1b S Class: os N s No s N o D s s s D 84 o well is p G S S 20 S S S s No s No S G y E S s No s Form 10-401 Revised 3/2020 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g) By Samantha Carlisle at 11:44 am, Jun 01, 2020 Digitally signed by Monty M Myers DN: cn=Monty M Myers, c=US, o=Hilcorp Alaska, LLC, ou=Technical Services - AK Drilling, email=mmyers@hilcorp.com Reason: I am approving this document Date: 2020.06.01 11:35:24 -08'00' Monty M Myers X 220-049 029-23679-00-00 X X X X X X DSR-6/1/2020DLB 06/02/2020 *3000 psi BOPE test gls 6/11/20 Development - Oil 2020 6/11/2020 6/11/2020 Milne Point Unit (MPU) I-20 Drilling Program Version 1 5/28/2020 Table of Contents 1.0 Well Summary ...................................................................................................................... 2 2.0 Management of Change Information .................................................................................... 3 3.0 Tubular Program: ................................................................................................................ 4 4.0 Drill Pipe Information: ......................................................................................................... 4 5.0 Internal Reporting Requirements ......................................................................................... 5 6.0 Planned Wellbore Schematic ................................................................................................ 6 7.0 Drilling / Completion Summary ............................................................................................ 7 8.0 Mandatory Regulatory Compliance / Notifications ............................................................... 8 9.0 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 6-5/8” Slotted 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 .............................................................................................. 47 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-20 SB Producer Drilling Procedure 1.0 Well Summary Well MPU I-20 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 16,103’ MD / 4,310’ TVD PBTD, MD / TVD 16,93’ MD / 4,310’ TVD Surface Location (Governmental) 2319' FSL, 3507' FEL, Sec 33, T13N, R10E, UM, AK Surface Location (NAD 27) X= 551863, Y= 6009436 Top of Productive Horizon (Governmental) 1448' FNL, 1589' FWL, Sec 33, T13N, R10E, UM, AK TPH Location (NAD 27) X= 551665 Y= 6010947 BHL (Governmental) 966' FNL, 2630' FEL, Sec 21, T13N, R10E, UM, AK BHL (NAD 27) X= 552621, Y= 6021995 AFE Number AFE Drilling Days 21 AFE Completion Days 3 AFE Drilling Amount $3,630,471 AFE Completion Amount $2,545,618 AFE Facility Amount $391,000 Maximum Anticipated Pressure (Surface) 1404 psig Maximum Anticipated Pressure (Downhole/Reservoir) 1764 psig Work String 5” 19.5# S-135 NC 50 Innovation KB Elevation above MSL: 26.5 ft + 33.4 ft = 59.9 ft GL Elevation above MSL: 33.4 ft BOP Equipment 13-5/8” x 5M Annular, (3) ea 13-5/8” x 5M Rams Page 3 Milne Point Unit I-20 SB Producer Drilling Procedure 2.0 Management of Change Information Page 4 Milne Point Unit I-20 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” 6-5/8” Slotted 6.049 5.924 7.390 20 L-80 Hydril 563 6,090 3,470 459 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-20 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, jengel@hilcorp.com and cdinger@hilcorp.com 5.3 Intranet Home Page Morning Update x Submit a short operations update each morning by 7am on the company intranet homepage. On weekend and holidays, ensure to have this update in before 5am. 5.4 EHS Incident Reporting x Health and Safety: Notify EHS field coordinator. x Environmental: Drilling Environmental Coordinator x Notify Drilling Manager & Drilling Engineer on all incidents x Submit Hilcorp Incident report to contacts above within 24 hrs 5.5 Casing Tally x Send final “As -Run” Casing tally to mmyers@hilcorp,com jengel@hilcorp.com and cdinger@hilcorp.com 5.6 Casing and Cement report x Send casing and cement report for each string of casing to mmyers@hilcorp.com jengel@hilcorp.com and cdinger@hilcorp.com 5.7 Hilcorp Milne Point Contact List: Title Name Work Phone Cell Phone Email Drilling Manager Monty Myers 907.777.8431 907.538.1168 mmyers@hilcorp.com Drilling Engineer Joe Engel 907.777.8395 805.235.6265 jengel@hilcorp.com Completion Engineer Ian Toomey 907.777.8434 907.903-3987 itoomey@hilcorp.com Geologist Kevin Eastham 907.777.8316 907.360.5087 keastham@hilcorp.com Reservoir Engineer Reid Edwards 907.777.8421 907.250.5081 reedwards@hilcorp.com Drilling Env. Coordinator Keegan Fleming 907.777.8477 907.350.9439 kfleming@hilcorp.com EHS Manager Carl Jones 907.777.8327 907.382.4336 cajones@hilcorp.com Drilling Tech Cody Dinger 907.777.8389 509.768.8196 cdinger@hilcorp.com Page 6 Milne Point Unit I-20 SB Producer Drilling Procedure 6.0 Planned Wellbore Schematic Page 7 Milne Point Unit I-20 SB Producer Drilling Procedure 7.0 Drilling / Completion Summary MPU I-20 is a grassroots producer planned to be drilled in the Schrader Bluff OB sand. I-20 is part of a multi well program targeting the Schrader Bluff sand on I-Pad The directional plan is a catenary well path build, 12.25” hole with 9-5/8” surface casing set into the top of the Schrader Bluff Ob sand. An 8.5” lateral section will then be drilled. A 6-5/8” 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 June 14, 2020, pending rig schedule. Surface casing will be run to 4,983’ MD / 4,010’ 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 6-5/8 ” 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) Page 8 Milne Point Unit I-20 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-20. Ensure to provide AOGCC 24 hrs notice prior to testing BOPs. x The initial test of BOP equipment will be to 250/3000 psi & subsequent tests of the BOP equipment will be to 250/3000 psi for 5/5 min (annular to 50% rated WP, 2500 psi on the high test for initial and subsequent tests). Confirm that these test pressures match those specified on the APD. x If the BOP is used to shut in on the well in a well control situation 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-20 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: 250/3000 Subsequent Tests: 250/3000 Primary closing unit: Control Technology Inc. (CTI), 6 station, 3000 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 / Ema il: jim.regg@alaska.gov Guy Schwartz / Petroleum Engineer / (O): 907-793-1226 / (C): 907-301-4533 / Ema il: guy.schwartz@alaska.gov Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Ema il: Victoria.loepp@alaska.gov Mel Rixse / Petroleum Engineer / (O): 907-793-1231 / (C): 907-223-3605 / Ema il: melvin.rixse@alaska.gov Primary Contact for Opportunity to witness: AOGCC.Inspectors@alaska.gov Test/Inspection notification standardization format: http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) Page 10 Milne Point Unit I-20 SB Producer Drilling Procedure 9.0 R/U and Preparatory Work 9.1 I-20 will utiliz e 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 (<80q F). 9.10 Ensure 5 ” liners in mud pumps. x White Star Quattro 1300 Hp mud pumps are rated at 4097 psi, 381 gpm @ 140 spm @ 96.5% volumetric efficiency. Ensure 5” liners in mud pumps. Page 11 Milne Point Unit I-20 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. Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens prior to annular closure. 10.3 Ensure to set up a clearly marked “warning zone” is established on each side and ahead of the vent line tip. “Warning Zone” must include: x A prohibition on vehicle parking x A prohibition on ignition sources or running equipment x A prohibition on staged equipment or materials x Restriction of traffic to essential foot or vehicle traffic only. N/U 13-5/8” CTI BOP stack in diverter configuration Notify AOGCC. Function test diverter Page 12 Milne Point Unit I-20 SB Producer Drilling Procedure 10.4 Rig & Diverter Orientation: x May change on location Page 13 Milne Point Unit I-20 SB Producer Drilling Procedure 11.0 Drill 12-1/4 ” Hole Section 11.1 P/U 12-1/4” directional drilling ass embly: 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. Hydraulics calculations and recommended TFA is attached below. 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 OB 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 Enginee r. 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 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 2100- 2400’ TVD (just below permafrost). Be prepared for hydrates: Drill string will be 5” 19.5# S-135. x Page 14 Milne Point Unit I-20 SB Producer Drilling Procedure x Gas hydrates can be identified by the gas detector and a decrease in MW or ECD x Monitor returns for hydrates, checking pressurized & non-pressurized scales x Do not stop to circulate out gas hydrates – this will only exacerbate the problem by washing out additional permafrost. Attempt to control drill (150 fph MAX) through the zone completely and efficiently to mitigate the hydrate issue. Flowrates can also be reduced to prevent mud from belching over the bell nipple. 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 thro ughout 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). Note: EMW needed is 8.46 ppg. DLB Page 15 Milne Point Unit I-20 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 t/ bottom, proceed to BROOH t/ 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. 8.8 – 9.8 y Page 16 Milne Point Unit I-20 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 r unning if the CRT is not used. x Ensure all casing has been drifted to 8.75” on the location prior to running. x Top 2000’ 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 g Top 2000’ of casing 47# drift 8.525” Page 17 Milne Point Unit I-20 SB Producer Drilling Procedure 12.5 Float equipment and Stage tool equipment drawings: 2500 Page 18 Milne Point Unit I-20 SB Producer Drilling Procedure 12.6 Continue running 9-5/8 ” surface casing x Fill casing while r unning 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 t/ ~ 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). (Halliburton ESIPC with packer element may be used). x Install centralizers over couplings on 5 joints below and 10 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. x ESIPC: Ensure tool is pinned properly. ESIPC packer to inflate at ~ 2080 psi, and the tool to open at ~ 3000 psi. Reference ESIPC Procedure. 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 Install the Halliburton Type H ES-II Stage tool so that it is positioned at least 100’ TVD below yp the permafrost (~ 2,500’ MD). ( Page 19 Milne Point Unit I-20 SB Producer Drilling Procedure Page 20 Milne Point Unit I-20 SB Producer Drilling Procedure 12.8 Continue running 9-5/8” surface casing x Centralizers: 1 centralizer every 3 rd joint to 200’ from surface x Fill casing while r unning 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 2000’ of 9-5/8” will be 47#, from 2000’ to Surface x Ensure drifted to 8.525” The last 2000’ of 9-5/8” will be 47#, fro m 2000’ to Sur face tapered 9 5/8" casing Page 21 Milne Point Unit I-20 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-20 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: Section Calculation Vol (bbl) Vol (ft3) 12-1/4" OH x 9-5/8" Casing (3,987' - 2500') x .0558 bpf x 1.3 = 107.9 605.6 Total Lead 107.9 605.6 12-1/4" OH x 9-5/8" Casing (4,987' - 3,987') x .0558 bpf x 1.3 = 72.5 407 9-5/8" Shoe Track 120' x .0758 bpf = 9.1 51.09 Total Tail 81.6 458LeadTail 394 sx 257 sx Drop bottom plug (flexible bypass plug)– HEC rep to witness. – Page 23 Milne Point Unit I-20 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: 4,867’ x .0758 bpf = 368.9bbls 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 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 pg , p ppg( pg) spotting water across the HEC stage cementer. gp p p p p accurate using 0.0625 bps (5” liners) for the Quattro pump output. To operate the stage tool g hydraulically, the Page 24 Milne Point Unit I-20 SB Producer Drilling Procedure cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held, this is to ensure the stage tool is not prematurely opened. 13.16 Increase pressure to 3300 psi to 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. Increase pressure to 3300 psi to open circulating ports in stage collar. open ES Page 25 Milne Point Unit I-20 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 2 nd 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 bro ught to surface. However cement will continue to be pumped until clean spacer is observed at surface. Estimated 2nd Stage Total Cement Volume: Section Calculation Vol (bbl) Vol (ft3) 20" Conductor x 9-5/8" Casing (110') x .26 bpf x 1 = 28.6 161 12-1/4" OH x 9-5/8" Casing (2000' - 110') x .0558 bpf x 3 = 316.4 1776.3 Total Lead 345 1937 12-1/4" OH x 9-5/8" Casing (2500' - 2000') x .0558 bpf x 2 = 55.8 314 Total Tail 55.8 314LeadTail Cement Slurry Design (2nd stage cement job): Lead Slurry Tail Slurry System Permafrost L Density 10.7 lb/gal 15.8 lb/gal Yield 4.41 ft3/sk 1.17 ft3/sk Mixed Water 22.02 gal/sk 5.08 gal/sk 440 sx 270sx Page 26 Milne Point Unit I-20 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 1000 –1500 psi to ensure stage tool closes. Follow instructions of Halliburton personnel. Bleed off pressure and check to ensure stage tool has closed. Slips will be set as per plan to allow full a nnulus 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 a. Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid b. Note if casing is reciprocated or rotated during the job c. Calculated volume of displacement , actual displacement volume, whether plug bumped & bump pressure, do floats hold d. Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure e. Note if pre flush or cement returns at surface & volume f. Note time cement in place g. Note calculated top of cement h. Add any comments which would describe the success or problems during the cement job Send final “As-Run” casing tally & casing and cement report to jengel@hilcorp.com and cdinger@hilcorp.com This will be included with the EOW documentation that goes to the AOGCC. Make initial cut on 9-5/8” final joint. 6 Displacement calculation:p 2500’ x .0758 bpf = 190 bbls mud Install 9-5/8” wellhead. install wellhead Page 27 Milne Point Unit I-20 SB Producer Drilling Procedure 14.0 ND Diverter, NU BOPE, & Test 14.1 ND the diverter T, knife gate, diverter line & N U 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 3-1/2” x 5” VBRs in top cavity, blind ram in bottom cavity. x Single ram can be dressed with 3-1/2” x 5” VBRs or 6-5/8” 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 250/3000 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min. x Test 5” test joints 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. initial BOPE Test Test BOP to 250/3000 psi for 5/5 min. Page 28 Milne Point Unit I-20 SB Producer Drilling Procedure 15.0 Drill 8-1/2” Hole Section 15.1 MU 8.5” Cleanout BHA (Milltooth Bit & 1.22° PDM) x Consider drilling out stage tool with RSS BHA 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 2500 psi / 30 min. Ensure to record volume / pressure (every ¼ bbl) and plot on FIT graph. AOGCC reg is 50% of burst = 5750 / 2 = ~2875 psi, but max test pressure on the well is 2,500 psi as per AOGCC. Document incremental volume pumped (and subsequent pressure) and volume returned. Ensure rams are used to test casing as per AOGCC Industry Guidance Bulletin 17-001. 15.5 Drill out shoe track and 20’ of new formation. 15.6 CBU and condition mud for FIT. 15.7 Conduct FIT to 12.0 ppg EMW. Chart Test. Ensure test is recorded on same chart as FIT. Document incremental volume pumped (and subsequent pressure) and volume returned. 15.8 POOH and LD cleanout BHA 15.9 PU 8-1/2” directional BHA. x Ensure BHA components have been inspected previously. x Drift and caliper all components before MU. Visually verify no debris inside components that cannot be drifted. x Ensure TF offset is measured accurately and entered correctly into the MWD software. x Ensure MWD is RU and operational. x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. x Drill string will be 5” 19.5# S-135 DS50 & NC50. x Run a ported float in the production hole section. 15.10 8-1/2” hole section mud program summary: x Density: Weighting material to be used for the hole section will be calcium carbonate. Additional calcium carbonate will be on location to weight up the active system (1) ppg above highest anticipated MW. FIT RU and test casing to 2500 psi / 30 min. MIT casing 2500 psi Conduct FIT to 12.0 ppg EMW. Page 29 Milne Point Unit I-20 SB Producer Drilling Procedure 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 thro ughout 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 Note: EMW needed is 8.46 ppg. DLB 8 .9-9.5 y Page 30 Milne Point Unit I-20 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 st opping 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 OB 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 OB 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 is a long term shut in well. Coil tubing will cement and abandon the lateral prior to drilling I-20. The only risk is damage to the bit. 15.15 Reference: Open hole sidetracking practice: x If a known fault is coming up, put a slight “kick-off ramp”in wellbore ahead of the fault so we have a nice place to low side. x Attempt to lowside in a fast drilling interval where the wellbore is headed up. x Orient TF to low side and dig a trough with high flowrates for the first 10 ft, working string back and forth. Trough for ~30 min. MPD will be utilized to monitor pressure build up on connections. MPD equipment will be used for drilling lateral J-01/01A is a long term shut in well. Coil tubing will cement and abandon the lateral Install MPD R CD see sundry 320-080 Page 31 Milne Point Unit I-20 SB Producer Drilling Procedure 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. 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. Page 32 Milne Point Unit I-20 SB Producer Drilling Procedure 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-20 SB Producer Drilling Procedure 16.0 Run 6-5/8” Slotted Liner 16.1 Well control preparedness : In the event of an influx of formation fluids while running the 6- 5/8” pre drilled liner, the following well control response procedure will be followed: x P/U & M/U the 5” safety joint (with 6-5/8” crossover installed on bottom, TIW valve in open position on top, 6-5/8” handling joint above TIW). This joint shall be fully M/U and available prior to running the first joint of 6-5/8” 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 6-5/8” liner running equipment. x Ensure 6-5/8” 20# Hydril 563 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 6-5/8” slotted 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 6-5/8” slotted liner will auto –fill x 6-5/8” 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 6-5/8” 20 # Hydril 563 Torque OD Minimum Optimum Maximum Yield Torque 6-5/8 5,900 ft-lbs 7,100 ft-lbs 10,300 ft-lbs 36,000 ft-lbs Well control preparednes s : Page 34 Milne Point Unit I-20 SB Producer Drilling Procedure Page 35 Milne Point Unit I-20 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 6-5/8” 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 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-20 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 t op. 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. 16.25. MU 3-1/2” wash tool and RIH with remaining DP out of derrick to liner top. 16.26. Wash through liner top at max rate and circulate hole clean. Pump sweeps around. Displace well to clean filtered brine after no solids are returned. 16.27. POOH and LD remaining 5” HWDP MU 3-1/2” wash t ool and RIH with remaining test liner packer o 1 ,500 psi for 10 minutes Continue pressuring up to 2,700 psi to set the SLZXP liner hanger/packer. Page 37 Milne Point Unit I-20 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 CO rams and test gg Install 7-5/8” solid body casing rams in the upper p yg ram cavity. RU testing equipment. PT to 250/3,000 psi with 7-5/8” test joint. Page 38 Milne Point Unit I-20 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-20 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” tie back 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. PT 9-5/8” x 7-5/8” annulus to 1,000 psi for 30 minutes charted. MIT-OA RU and circulation corrosion inhibited brine in the 9-5/8” x 7-5/8” annulus. Page 40 Milne Point Unit I-20 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. The completion includes two 3/8” capillary tube from surface to the centralizer on the motor. The capillary tube will be secured to the tubing with Cannon clamps. Function test the capillary tube every ~2,000’ by pumping ~2 gallons of hydraulic oil through the check valves. Record the pressure at each testing point 18.5 M/U ESP assy and RIH to setting depth. Confirm tally with Operations Engineer i. Ensure appropriate well control crossovers on rig floor and ready. ii. Monitor displacement from wellbore while RIH. x Centrilift ESP Assembly with bottom of assembly @ predetermined depth x 10’ 3-1/2”9.3#, L-80 Pup Joint x 1 joint 3-1/2”9.3#, L-80 EUE 8rd tubing x 3-1/2” “XN” nipple (2.813” packing bore / 2.75” No -Go ID) x 3 joints 3-1/2” 9.3#, L-80 EUE 8rd tubing x 10’ 3-1/2”9.3#, L-80 Pup Joint x GLM 3-1/2” x 1” GLM w/ dummy installed x 10’ 3-1/2”9.3#, L-80 Pup Joint x 3-1/2” 9.3#, L-80 EUE 8rd tubing x 10’ 3-1/2”9.3#, L-80 Pup Joint x GLM 3-1/2” x 1” w/ SO @ ~140’ MD x 10’ 3-1/2”9.3#, L-80 Pup Joint x 3 joints 3-1/2” 9.3#, L-80 EUE 8rd tubing x Tubing Hanger o Check the conductivity of electric cable every 2,000’ and every new splice while running in hole. o Use Cannon clamps on every joint to secure the capillary tube. o The make up torque values for 3-1/2” L-80 9.3# EUE 8rd tubing are: Run the 3-1/2” ESP Completion as noted ” Page 41 Milne Point Unit I-20 SB Producer Drilling Procedure Minimum: 2350 ft-lb, Optimum: 3100 ft-lb, and maximum: 3910 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, psi. 18.6 Fill tubing while splicing cable, mid-cable splices and tubing hanger splices. After tubing is full, break circulation by pumping 10 bbls down the tubing to clear any debris. 18.7 Record PU and SO weights before landing hanger. Note PU and SO weights on tally along with band/clamp summary. 18.8 MU tubing hanger and landing joint. Splice ESP power cable and terminate control lines. Test cable. Install a brass-shipping cap on the ESP penetrator. 18.9 Land tubing with extreme care to minimize damaging the ESP penetrator, pigtail and alignment pin. 18.10 RILDS and test hanger. LD landing joint. 18.11 Install BPV and N/D BOP. 18.12 N/U tree / adapter and tree. Test tubing hanger void to 500 psi low / 5000 psi high. Terminate the cap strings. 18.13 Circulate diesel freeze protection down 3-1/2” x 7-5/8” annulus (Volume should equal capacity of tubing to 2500’ + tubing annulus to 2500’). Connect IA to tree and allow diesel freeze protect to “U-tube” into position. Note – this may be done post-rig. 18.14 Pull BPV. Set TWC. Test tree to 250 psi low / 5000 psi high. Pull TWC. Set BPV. 18.15 Prepare to hand over well to production. Ensure necessary forms filled out and well handed over with valve alignment as per operations personnel. 18.16 RDMO Innovation Install BPV and N/D BOP. Page 42 Milne Point Unit I-20 SB Producer Drilling Procedure 19.0 Innovation Rig Diverter Schematic Page 43 Milne Point Unit I-20 SB Producer Drilling Procedure 20.0 Innovation Rig BOP Schematic VBR VBR BLIND Page 44 Milne Point Unit I-20 SB Producer Drilling Procedure 21.0 Wellhead Schematic Page 45 Milne Point Unit I-20 SB Producer Drilling Procedure 22.0 Days Vs Depth Page 46 Milne Point Unit I-20 SB Producer Drilling Procedure 23.0 Formation Tops & Information Page 47 Milne Point Unit I-20 SB Producer Drilling Procedure 24.0 Anticipated Drilling Hazards 12-1/4” Hole Section: Lost Circulation Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Gas Hydrates Gas hyrates have not been seen on Moose pad. However, be prepared for them. Remember that hydrate gas behave differently from a gas sand. Additional fluid density will not prevent influx of gas hydrates, but can help control the breakout at surface. Once a gas hydrate has been disturbed the gas will come out of the hole. Drill thro ugh the hydrate section as quickly as possible while minimizing gas belching. Minimize circulation time while drilling through the hydrate zone. Excessive circulation will a ccelerate formation thawing which can increase the amount of hydrates released into the wellbore. Keep the mud circulation temperature as cold as possible. Weigh mud with both a pressurized and non-pressurized mud scale. The non-pressurized scale will reflect the actual mud cut weight. Add 1.0 – 2.0 ppb Lecithin to the system to help thin the mud and release the gas. Isolate/dump contaminated fluid to remove hydrates from the system. Hole Cleaning: Maintain rheology of mud system. Sweep hole with high viscosity sweeps as necessary. Optimize solids control equipment to maintain density, sand content, and reduce the waste stream. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to avoid washing out a particular section of the hole. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Anti-Collison: 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 : Anti-Collisoon: Page 48 Milne Point Unit I-20 SB Producer Drilling Procedure Wellbore stability (Permafrost, running sands and gravel, conductor broaching): Washouts in the permafrost can be severe if the string is left circulating across it for extended periods of time. Keep mud as cool as possible by taking on cold water and diluting often. High TOH and RIH speeds can aggravate fragile shale/coal formations due to the pressure variations between surge and swab. Bring the pumps on slowly after connections. Monitor conductor for any signs of broaching. Maintain mud parameters and increase MW to combat running sands and gravel formations. H2S: Treat every hole section as though it has the potential for H2S. No H2S events have been documented on drill wells on this pad. 1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Page 49 Milne Point Unit I-20 SB Producer Drilling Procedure 8-1/2” Hole Section: Hole Cleaning: Maintain rheology of mud system. Sweep hole with low-vis water sweeps. Ensure shakers are set up with appropriate screens to maximize solids removal efficiency. Run centrifuge continuously. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Maintain circulation rate of > 300 gpm Lost Circulation: Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Faulting: There is at least (1) fault that will be crossed while drilling the well. There could be others and the throw of these faults is not well understood at this point in time. When a known fault is coming up, ensure to put a “ramp” in the wellbore to aid in kicking off (low siding) later. Once a fault is crossed, we’ll need to either drill up or down to get a look at the LWD log and determine the throw and then replan the wellbore. H2S: Treat every hole section as though it has the potential for H2S. No H2S events have been documented on drill wells on this pad. 1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Abnormal Pressures and Temperatures: Reservoir pressures are expected to be normal. Abnormal (offset injection) pressure has been seen on M- Pad. Utilize MPD to mitigate any abnormal pressure seen. Page 50 Milne Point Unit I-20 SB Producer Drilling Procedure Anti-Collision Take directional surveys every stand, take additional surveys if necessary. Continuously monitor drilling parameters for signs of magnetic interference with another well. Reference A/C report in directional plan. Well Specific AC: x J-01/01A is a long term shut in well. Coil tubing will cement and abandon the lateral prior to drilling I-20. The only risk is damage to the bit. J-01/01A is a long term shut in well. Coil tubing will cement and abandon the lateral prior to drilling I-20. The only risk is damage to the bit. gg J-01 A has approved sundry to P &A. per 320-080 Page 51 Milne Point Unit I-20 SB Producer Drilling Procedure 25.0 Innovation Rig Layout Page 52 Milne Point Unit I-20 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-20 SB Producer Drilling Procedure 27.0 Innovation Rig Choke Manifold Schematic Page 54 Milne Point Unit I-20 SB Producer Drilling Procedure 28.0 Casing Design 12-1/4"Mud Density:9.2 ppg 8-1/2"Mud Density:9.2 ppg Mud Density: 1404 psi (see attached M ASP determination & calculation) 1404 psi (see attached M ASP determination & calculation) Collapse Calculation: Section Calculation 1 Normal gradient external stress (0.494 psi/ft) and the casing evacuated for the internal stress 1234 9-5/8"6-5/8" 04,987 04,010 4,987 16,103 4,010 4,310 4,987 11,116 40 20 L-80 L-80 DWC H563 199,480 222,320 199,480 222,320 916 459 4.59 2.06 1,981 2,129 3,090 3,470 1.56 1.63 1,404 1,404 5,750 6,090 4.10 4.34 Calculation & Casing Design Factors Calculation/Specification Casing OD Bottom (MD) Bottom (TVD) Top (MD) MASP: Drilling Mode MASP: Hole Size DATE: 5.28.2020 WELL: MPU I-20 Collapse Resistance w/o tension (Psi) Worst case safety factor (Burst) MASP: Production Mode Minimum Yield (psi) Weight (ppf) MASP (psi) Worst Case Safety Factor (Tension) Collapse Pressure at bottom (Psi) Worst Case Safety Factor (Collapse) Length Top (TVD) Tension at Top of Section (lbs) Grade Connection Weight w/o Bouyancy Factor (lbs) Min strength Tension (1000 lbs) DESIGN BY: Joe Engel Hole Size Casing Section Design Criteria: Hole Size (SLOTTED LINER) 4.10 1.56 4.59 Page 55 Milne Point Unit I-20 SB Producer Drilling Procedure 29.0 8-1/2” Hole Section MASP MD TVD Planned Top: 4987 4010 Planned TD: 16103 4310 Anticipated Formations and Pressures: Formation TVD TVDss Est Pressure Oil/Gas/Wet PPG Grad Schrader Bluff OB Sand 4,010 3,968 1764 Oil 8.46 0.440 Offset Well Mud Densities Well MW range Top (TVD) Bottom (TVD) Date M-35 8.8-9.2 Surface 3943 2020 M-34 8.8-9.1 Surface 3900 2020 J-23 9.1 Surface 3864 2000 Assumptions: 1. Field test data suggests the Fracture Gradient in the Schrader Bluff is btwn 11.5 and 15 ppg EMW. 3. Calculations assume full evacuation of wellbore to gas Fracture Pressure at 9-5/8" shoe considering a full column of gas from shoe to surface: 4010 (ft) x 0.78(psi/ft)= 3128 3128(psi) - [0.1(psi/ft)*4010(ft)]= 2726 psi MASP from pore pressure (complete evacuation of wellbore to gas from Schrader Bluff NB sand) 4010 (ft) x 0.45(psi/ft)= 1805.0 psi 1805(psi) - 0.1(psi/ft)*4010(ft) 1404.0 psi Summary: 1. MASP while drilling 8-1/2" production hole is governed by pore pressure and evacuation of entire wellbore to gas at 0.1 psi/ft. 2. Maximum planned mud density for the 8-1/2" hole section is 9.5 ppg. Maximum Anticipated Surface Pressure Calculation 8-1/2" Hole Section MPU I-20 Milne Point Unit MASP calc OK Page 56 Milne Point Unit I-20 SB Producer Drilling Procedure 30.0 Spider Plot (NAD 27) (Governmental Sections) Page 57 Milne Point Unit I-20 SB Producer Drilling Procedure 31.0 Surface Plat (As Built) (NAD 27) 22 May, 2020 Plan: MPU I-20 wp06 Milne Point M Pt I Pad Plan: MPU I-20 MPU I-20 0750150022503000375045005250True Vertical Depth (1500 usft/in)-750 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750 10500 11250 12000 12750 13500 14250Vertical Section at 6.60° (1500 usft/in)MPI-Winchester wp02 CP1MPI-Winchester wp02 HeelMPI-Winchester wp02 CP2MPI-Winchester wp02 Toe9 5/8" x 12 1/4"6 5/8" x 8 1/2"500100015002000250030003500400045005000 5500 6000 6500 7000 7500 8000 8500 9000 9500 10000 10500 11000 11500 12000 12500 13000 13500 14000 1450015000155001600016103MPU I-20 wp06Start Dir 4º/100' : 1300' MD, 1300'TVDEnd Dir : 1425.72' MD, 1425.55' TVDStartDir4º/100':2439.94'MD,2435.87'TVDEndDir:4686.66'MD,3984.05'TVDStartDir2.5º/100':4986.66'MD,4010.2'TVDEndDir:5334.38'MD,4029'TVDStartDir3º/100':8649.32'MD,4097.88'TVDEndDir:8785.14'MD,4100.2'TVDStartDir3º/100':13241.46'MD,4160.2'TVDEndDir:13317.51'MD,4162.72'TVDHilcorp Alaska, LLCCalculation Method:Minimum CurvatureError System:ISCWSAScan Method: Closest Approach 3DError Surface: Pedal CurveWarning Method: Error RatioWELL DETAILS: Plan: MPU I-2033.40+N/-S +E/-WNorthingEastingLatittudeLongitude0.000.00 6009436.15551863.83 70° 26' 11.482 N 149° 34' 37.726 WSURVEY PROGRAMDate: 2020-05-15T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool26.50 700.00 MPU I-20 wp06 (MPU I-20) 3_Gyro-GC_Csg700.00 4986.66 MPU I-20 wp06 (MPU I-20) 3_MWD+IFR2+MS+Sag4986.66 16103.18 MPU I-20 wp06 (MPU I-20) 3_MWD+IFR2+MS+SagFORMATION TOP DETAILSNo formation data is availableREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU I-20, True NorthVertical (TVD) Reference:MPU I-20 as-built RKB @ 60.20usft (Original Well Elev)Measured Depth Reference:MPU I-20 as-built RKB @ 60.20usft (Original Well Elev)Calculation Method:Minimum CurvatureProject:Milne PointSite:M Pt I PadWell:Plan: MPU I-20Wellbore:MPU I-20Design:MPU I-20 wp06CASING DETAILSTVD TVDSS MD SizeName4010.20 3950.00 4986.66 9-5/8 9 5/8" x 12 1/4"4310.20 4250.00 16103.45 6-5/8 6 5/8" x 8 1/2"SECTION DETAILSSec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation1 26.50 0.00 0.00 26.50 0.00 0.00 0.00 0.00 0.002 1300.00 0.00 0.00 1300.00 0.00 0.00 0.00 0.00 0.00 Start Dir 4º/100' : 1300' MD, 1300'TVD3 1425.72 5.03 189.51 1425.55 -5.44 -0.91 4.00 189.51 -5.51 End Dir : 1425.72' MD, 1425.55' TVD4 2439.94 5.03 189.51 2435.87 -93.12 -15.60 0.00 0.00 -94.29 Start Dir 4º/100' : 2439.94' MD, 2435.87'TVD5 4686.66 85.00 355.00 3984.05 1201.61 -160.38 4.00 165.55 1175.21 End Dir : 4686.66' MD, 3984.05' TVD6 4986.66 85.00 355.00 4010.20 1499.33 -186.43 0.00 0.00 1467.96 MPI-Winchester wp02 Heel Start Dir 2.5º/100' : 4986.66' MD, 4010.2'TVD7 5334.38 88.81 2.83 4029.00 1846.14 -192.96 2.50 64.26 1811.73 End Dir : 5334.38' MD, 4029' TVD8 8649.32 88.81 2.83 4097.88 5156.33 -29.52 0.00 0.00 5118.77 Start Dir 3º/100' : 8649.32' MD, 4097.88'TVD9 8785.14 89.23 6.88 4100.20 5291.62 -18.04 3.00 84.11 5254.47 MPI-Winchester wp02 CP1 End Dir : 8785.14' MD, 4100.2' TVD10 13241.46 89.23 6.88 4160.20 9715.44 515.79 0.00 0.00 9710.34 MPI-Winchester wp02 CP2 Start Dir 3º/100' : 13241.46' MD, 4160.2'TVD11 13317.51 86.97 6.60 4162.72 9790.91 524.71 3.00 -173.01 9786.34 End Dir : 13317.51' MD, 4162.72' TVD12 16103.45 86.97 6.60 4310.20 12554.50 844.57 0.00 0.00 12568.37 MPI-Winchester wp02 Toe Total Depth : 16103.45' MD, 4310.2' TVD 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750 10500 11250 12000 12750 South(-)/North(+) (1500 usft/in)-2250 -1500 -750 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 West(-)/East(+) (1500 usft/in) MPI-Winchester wp02 Toe MPI-Winchester wp02 CP2 MPI-Winchester wp02 Heel MPI-Winchester wp02 CP1 9 5/8" x 12 1/4" 6 5/8" x 8 1/2" 2500 3 0 0 0 3 5 0 0 3 7 5 0 4 0 0 0 4250 4310 MPU I-20 wp06 Start Dir 4º/100' : 1300' MD, 1300'TVD End Dir : 1425.72' MD, 1425.55' TVD Start Dir 4º/100' : 2439.94' MD, 2435.87'TVD End Dir : 4686.66' MD, 3984.05' TVD Start Dir 2.5º/100' : 4986.66' MD, 4010.2'TVD End Dir : 5334.38' MD, 4029' TVD Start Dir 3º/100' : 8649.32' MD, 4097.88'TVD End Dir : 8785.14' MD, 4100.2' TVD Start Dir 3º/100' : 13241.46' MD, 4160.2'TVD End Dir : 13317.51' MD, 4162.72' TVD CASING DETAILS TVD TVDSS MD Size Name 4010.20 3950.00 4986.66 9-5/8 9 5/8" x 12 1/4" 4310.20 4250.00 16103.45 6-5/8 6 5/8" x 8 1/2" Project: Milne Point Site: M Pt I Pad Well: Plan: MPU I-20 Wellbore: MPU I-20 Plan: MPU I-20 wp06 WELL DETAILS: Plan: MPU I-20 33.40+N/-S +E/-W Northing Easting Latittude Longitude0.00 0.00 6009436.15 551863.83 70° 26' 11.482 N 149° 34' 37.726 W REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Plan: MPU I-20, True North Vertical (TVD) Reference:MPU I-20 as-built RKB @ 60.20usft (Original Well Elev) Measured Depth Reference:MPU I-20 as-built RKB @ 60.20usft (Original Well Elev) Calculation Method:Minimum Curvature Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt I Pad Halliburton Standard Proposal Report Well: Wellbore: Plan: MPU I-20 MPU I-20 Survey Calculation Method:Minimum Curvature MPU I-20 as-built RKB @ 60.20usft (Original We Design:MPU I-20 wp06 Database:NORTH US + CANADA MD Reference:MPU I-20 as-built RKB @ 60.20usft (Original We North Reference: Well Plan: MPU I-20 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 6,008,388.01 550,245.83 0.00 70° 26' 1.282 N 149° 35' 25.422 W Well Well Position Longitude: Latitude: Easting: Northing: usft +E/-W +N/-S Position Uncertainty usft usft usftGround Level: Plan: MPU I-20 usft usft 0.00 0.00 6,009,436.15 551,863.83 33.40Wellhead Elevation:33.70 usft0.50 70° 26' 11.482 N 149° 34' 37.726 W Wellbore Declination (°) Field Strength (nT) Sample Date Dip Angle (°) MPU I-20 Model NameMagnetics BGGM2020 7/15/2020 15.93 80.84 57,374.17069665 Phase:Version: Audit Notes: Design MPU I-20 wp06 PLAN Vertical Section: Depth From (TVD) (usft) +N/-S (usft) Direction (°) +E/-W (usft) Tie On Depth:26.50 6.600.000.0026.50 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 0.000.000.000.000.000.0026.500.000.0026.50 -33.70 0.000.000.000.000.000.001,300.000.000.001,300.00 1,239.80 189.510.004.004.00-0.91-5.441,425.55189.515.031,425.72 1,365.35 0.000.000.000.00-15.60-93.122,435.87189.515.032,439.94 2,375.67 165.557.373.564.00-160.381,201.613,984.05355.0085.004,686.66 3,923.85 0.000.000.000.00-186.431,499.334,010.20355.0085.004,986.66 3,950.00 64.262.251.102.50-192.961,846.144,029.002.8388.815,334.38 3,968.80 0.000.000.000.00-29.525,156.334,097.882.8388.818,649.32 4,037.68 84.112.980.313.00-18.045,291.624,100.206.8889.238,785.14 4,040.00 0.000.000.000.00515.799,715.444,160.206.8889.2313,241.46 4,100.00 -173.01-0.37-2.983.00524.719,790.914,162.726.6086.9713,317.51 4,102.52 0.000.000.000.00844.5712,554.504,310.206.6086.9716,103.45 4,250.00 5/22/2020 12:13:03PM 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 Halliburton Standard Proposal Report Well: Wellbore: Plan: MPU I-20 MPU I-20 Survey Calculation Method:Minimum Curvature MPU I-20 as-built RKB @ 60.20usft (Original We Design:MPU I-20 wp06 Database:NORTH US + CANADA MD Reference:MPU I-20 as-built RKB @ 60.20usft (Original We North Reference: Well Plan: MPU I-20 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 -33.70 Vert Section 26.50 0.00 26.50 0.00 0.000.00 551,863.836,009,436.15-33.70 0.00 0.00 100.00 0.00 100.00 0.00 0.000.00 551,863.836,009,436.1539.80 0.00 0.00 200.00 0.00 200.00 0.00 0.000.00 551,863.836,009,436.15139.80 0.00 0.00 300.00 0.00 300.00 0.00 0.000.00 551,863.836,009,436.15239.80 0.00 0.00 400.00 0.00 400.00 0.00 0.000.00 551,863.836,009,436.15339.80 0.00 0.00 500.00 0.00 500.00 0.00 0.000.00 551,863.836,009,436.15439.80 0.00 0.00 600.00 0.00 600.00 0.00 0.000.00 551,863.836,009,436.15539.80 0.00 0.00 700.00 0.00 700.00 0.00 0.000.00 551,863.836,009,436.15639.80 0.00 0.00 800.00 0.00 800.00 0.00 0.000.00 551,863.836,009,436.15739.80 0.00 0.00 900.00 0.00 900.00 0.00 0.000.00 551,863.836,009,436.15839.80 0.00 0.00 1,000.00 0.00 1,000.00 0.00 0.000.00 551,863.836,009,436.15939.80 0.00 0.00 1,100.00 0.00 1,100.00 0.00 0.000.00 551,863.836,009,436.151,039.80 0.00 0.00 1,200.00 0.00 1,200.00 0.00 0.000.00 551,863.836,009,436.151,139.80 0.00 0.00 1,300.00 0.00 1,300.00 0.00 0.000.00 551,863.836,009,436.151,239.80 0.00 0.00 Start Dir 4º/100' : 1300' MD, 1300'TVD 1,400.00 4.00 1,399.92 -3.44 -0.58189.51 551,863.286,009,432.711,339.72 4.00 -3.48 1,425.72 5.03 1,425.56 -5.44 -0.91189.51 551,862.966,009,430.711,365.36 4.00 -5.51 End Dir : 1425.72' MD, 1425.55' TVD 1,500.00 5.03 1,499.55 -11.86 -1.99189.51 551,861.936,009,424.281,439.35 0.00 -12.01 1,600.00 5.03 1,599.17 -20.50 -3.44189.51 551,860.546,009,415.621,538.97 0.00 -20.76 1,700.00 5.03 1,698.78 -29.15 -4.88189.51 551,859.156,009,406.971,638.58 0.00 -29.52 1,800.00 5.03 1,798.40 -37.79 -6.33189.51 551,857.766,009,398.321,738.20 0.00 -38.27 1,900.00 5.03 1,898.01 -46.44 -7.78189.51 551,856.376,009,389.661,837.81 0.00 -47.03 2,000.00 5.03 1,997.63 -55.08 -9.23189.51 551,854.996,009,381.011,937.43 0.00 -55.78 2,100.00 5.03 2,097.24 -63.73 -10.68189.51 551,853.606,009,372.362,037.04 0.00 -64.53 2,200.00 5.03 2,196.86 -72.37 -12.12189.51 551,852.216,009,363.702,136.66 0.00 -73.29 2,300.00 5.03 2,296.47 -81.02 -13.57189.51 551,850.826,009,355.052,236.27 0.00 -82.04 2,400.00 5.03 2,396.09 -89.66 -15.02189.51 551,849.436,009,346.392,335.89 0.00 -90.80 2,439.94 5.03 2,435.87 -93.12 -15.60189.51 551,848.886,009,342.942,375.67 0.00 -94.29 Start Dir 4º/100' : 2439.94' MD, 2435.87'TVD 2,500.00 2.77 2,495.79 -97.06 -16.58202.02 551,847.936,009,338.992,435.59 4.00 -98.32 2,600.00 1.98 2,595.75 -98.06 -18.69315.83 551,845.836,009,337.982,535.55 4.00 -99.55 2,700.00 5.67 2,695.51 -92.11 -21.39342.38 551,843.086,009,343.912,635.31 4.00 -93.95 2,800.00 9.61 2,794.60 -79.23 -24.67347.69 551,839.726,009,356.762,734.40 4.00 -81.54 2,900.00 13.59 2,892.54 -59.50 -28.51349.92 551,835.746,009,376.462,832.34 4.00 -62.38 3,000.00 17.58 2,988.85 -33.00 -32.89351.15 551,831.186,009,402.922,928.65 4.00 -36.57 3,100.00 21.57 3,083.05 0.13 -37.79351.94 551,826.046,009,436.013,022.85 4.00 -4.22 3,200.00 25.56 3,174.69 39.73 -43.19352.49 551,820.376,009,475.573,114.49 4.00 34.50 3,300.00 29.56 3,263.33 85.61 -49.07352.90 551,814.186,009,521.413,203.13 4.00 79.40 3,400.00 33.55 3,348.53 137.55 -55.38353.22 551,807.506,009,573.303,288.33 4.00 130.27 3,500.00 37.55 3,429.87 195.29 -62.11353.48 551,800.376,009,630.983,369.67 4.00 186.86 3,600.00 41.55 3,506.96 258.55 -69.21353.69 551,792.836,009,694.193,446.76 4.00 248.88 3,700.00 45.55 3,579.43 327.03 -76.66353.88 551,784.906,009,762.603,519.23 4.00 316.05 3,800.00 49.54 3,646.92 400.38 -84.42354.04 551,776.636,009,835.903,586.72 4.00 388.03 3,900.00 53.54 3,709.10 478.26 -92.45354.18 551,768.066,009,913.713,648.90 4.00 464.47 5/22/2020 12:13:03PM 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 Halliburton Standard Proposal Report Well: Wellbore: Plan: MPU I-20 MPU I-20 Survey Calculation Method:Minimum Curvature MPU I-20 as-built RKB @ 60.20usft (Original We Design:MPU I-20 wp06 Database:NORTH US + CANADA MD Reference:MPU I-20 as-built RKB @ 60.20usft (Original We North Reference: Well Plan: MPU I-20 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 3,705.47 Vert Section 4,000.00 57.54 3,765.67 560.28 -100.71354.31 551,759.236,009,995.673,705.47 4.00 545.00 4,100.00 61.54 3,816.35 646.05 -109.16354.43 551,750.196,010,081.363,756.15 4.00 629.22 4,200.00 65.54 3,860.90 735.14 -117.76354.54 551,740.976,010,170.383,800.70 4.00 716.73 4,300.00 69.54 3,899.10 827.12 -126.47354.64 551,731.626,010,262.303,838.90 4.00 807.11 4,400.00 73.54 3,930.76 921.55 -135.25354.74 551,722.196,010,356.653,870.56 4.00 899.90 4,500.00 77.54 3,955.73 1,017.96 -144.05354.83 551,712.726,010,452.993,895.53 4.00 994.66 4,600.00 81.53 3,973.89 1,115.89 -152.82354.92 551,703.276,010,550.843,913.69 4.00 1,090.93 4,686.66 85.00 3,984.05 1,201.60 -160.38355.00 551,695.116,010,636.493,923.85 4.00 1,175.21 End Dir : 4686.66' MD, 3984.05' TVD 4,700.00 85.00 3,985.22 1,214.84 -161.54355.00 551,693.866,010,649.723,925.02 0.00 1,188.22 4,800.00 85.00 3,993.93 1,314.08 -170.22355.00 551,684.496,010,748.893,933.73 0.00 1,285.81 4,900.00 85.00 4,002.65 1,413.32 -178.90355.00 551,675.126,010,848.063,942.45 0.00 1,383.39 4,986.66 85.00 4,010.20 1,499.32 -186.43355.00 551,667.006,010,934.003,950.00 0.00 1,467.96 Start Dir 2.5º/100' : 4986.66' MD, 4010.2'TVD - 9 5/8" x 12 1/4" 5,000.00 85.14 4,011.35 1,512.57 -187.55355.30 551,665.786,010,947.233,951.15 2.50 1,480.99 5,100.00 86.23 4,018.86 1,612.08 -193.76357.56 551,658.896,011,046.693,958.66 2.50 1,579.13 5,200.00 87.33 4,024.47 1,711.89 -196.05359.81 551,655.906,011,146.473,964.27 2.50 1,678.01 5,300.00 88.43 4,028.17 1,811.80 -194.432.05 551,656.836,011,246.383,967.97 2.50 1,777.45 5,334.38 88.81 4,029.00 1,846.14 -192.962.83 551,658.056,011,280.723,968.80 2.50 1,811.73 End Dir : 5334.38' MD, 4029' TVD 5,400.00 88.81 4,030.36 1,911.67 -189.732.83 551,660.836,011,346.263,970.16 0.00 1,877.19 5,500.00 88.81 4,032.44 2,011.52 -184.802.83 551,665.076,011,446.143,972.24 0.00 1,976.95 5,600.00 88.81 4,034.52 2,111.38 -179.872.83 551,669.306,011,546.023,974.32 0.00 2,076.71 5,700.00 88.81 4,036.60 2,211.24 -174.942.83 551,673.546,011,645.903,976.40 0.00 2,176.47 5,800.00 88.81 4,038.68 2,311.09 -170.012.83 551,677.776,011,745.783,978.48 0.00 2,276.24 5,900.00 88.81 4,040.75 2,410.95 -165.082.83 551,682.016,011,845.663,980.55 0.00 2,376.00 6,000.00 88.81 4,042.83 2,510.81 -160.152.83 551,686.256,011,945.543,982.63 0.00 2,475.76 6,100.00 88.81 4,044.91 2,610.66 -155.212.83 551,690.486,012,045.423,984.71 0.00 2,575.52 6,200.00 88.81 4,046.99 2,710.52 -150.282.83 551,694.726,012,145.303,986.79 0.00 2,675.28 6,300.00 88.81 4,049.06 2,810.38 -145.352.83 551,698.956,012,245.183,988.86 0.00 2,775.04 6,400.00 88.81 4,051.14 2,910.23 -140.422.83 551,703.196,012,345.053,990.94 0.00 2,874.81 6,500.00 88.81 4,053.22 3,010.09 -135.492.83 551,707.426,012,444.933,993.02 0.00 2,974.57 6,600.00 88.81 4,055.30 3,109.95 -130.562.83 551,711.666,012,544.813,995.10 0.00 3,074.33 6,700.00 88.81 4,057.37 3,209.80 -125.632.83 551,715.896,012,644.693,997.17 0.00 3,174.09 6,800.00 88.81 4,059.45 3,309.66 -120.702.83 551,720.136,012,744.573,999.25 0.00 3,273.85 6,900.00 88.81 4,061.53 3,409.52 -115.772.83 551,724.366,012,844.454,001.33 0.00 3,373.61 7,000.00 88.81 4,063.61 3,509.37 -110.842.83 551,728.606,012,944.334,003.41 0.00 3,473.38 7,100.00 88.81 4,065.69 3,609.23 -105.912.83 551,732.836,013,044.214,005.49 0.00 3,573.14 7,200.00 88.81 4,067.76 3,709.09 -100.982.83 551,737.076,013,144.094,007.56 0.00 3,672.90 7,300.00 88.81 4,069.84 3,808.94 -96.052.83 551,741.316,013,243.964,009.64 0.00 3,772.66 7,400.00 88.81 4,071.92 3,908.80 -91.122.83 551,745.546,013,343.844,011.72 0.00 3,872.42 7,500.00 88.81 4,074.00 4,008.66 -86.192.83 551,749.786,013,443.724,013.80 0.00 3,972.18 7,600.00 88.81 4,076.07 4,108.51 -81.262.83 551,754.016,013,543.604,015.87 0.00 4,071.95 7,700.00 88.81 4,078.15 4,208.37 -76.332.83 551,758.256,013,643.484,017.95 0.00 4,171.71 7,800.00 88.81 4,080.23 4,308.23 -71.402.83 551,762.486,013,743.364,020.03 0.00 4,271.47 5/22/2020 12:13:03PM 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 Halliburton Standard Proposal Report Well: Wellbore: Plan: MPU I-20 MPU I-20 Survey Calculation Method:Minimum Curvature MPU I-20 as-built RKB @ 60.20usft (Original We Design:MPU I-20 wp06 Database:NORTH US + CANADA MD Reference:MPU I-20 as-built RKB @ 60.20usft (Original We North Reference: Well Plan: MPU I-20 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 4,022.11 Vert Section 7,900.00 88.81 4,082.31 4,408.08 -66.472.83 551,766.726,013,843.244,022.11 0.00 4,371.23 8,000.00 88.81 4,084.38 4,507.94 -61.542.83 551,770.956,013,943.124,024.18 0.00 4,470.99 8,100.00 88.81 4,086.46 4,607.80 -56.612.83 551,775.196,014,043.004,026.26 0.00 4,570.75 8,200.00 88.81 4,088.54 4,707.65 -51.682.83 551,779.426,014,142.884,028.34 0.00 4,670.52 8,300.00 88.81 4,090.62 4,807.51 -46.752.83 551,783.666,014,242.754,030.42 0.00 4,770.28 8,400.00 88.81 4,092.70 4,907.37 -41.822.83 551,787.906,014,342.634,032.50 0.00 4,870.04 8,500.00 88.81 4,094.77 5,007.23 -36.892.83 551,792.136,014,442.514,034.57 0.00 4,969.80 8,600.00 88.81 4,096.85 5,107.08 -31.962.83 551,796.376,014,542.394,036.65 0.00 5,069.56 8,649.32 88.81 4,097.88 5,156.33 -29.522.83 551,798.456,014,591.654,037.68 0.00 5,118.77 Start Dir 3º/100' : 8649.32' MD, 4097.88'TVD 8,700.00 88.97 4,098.86 5,206.90 -26.364.34 551,801.276,014,642.244,038.66 3.00 5,169.36 8,785.14 89.23 4,100.20 5,291.62 -18.046.88 551,809.006,014,727.004,040.00 3.00 5,254.47 End Dir : 8785.14' MD, 4100.2' TVD 8,800.00 89.23 4,100.40 5,306.37 -16.266.88 551,810.686,014,741.764,040.20 0.00 5,269.33 8,900.00 89.23 4,101.74 5,405.64 -4.286.88 551,821.966,014,841.104,041.54 0.00 5,369.32 9,000.00 89.23 4,103.09 5,504.91 7.706.88 551,833.256,014,940.454,042.89 0.00 5,469.31 9,100.00 89.23 4,104.43 5,604.18 19.686.88 551,844.546,015,039.794,044.23 0.00 5,569.30 9,200.00 89.23 4,105.78 5,703.45 31.666.88 551,855.826,015,139.134,045.58 0.00 5,669.29 9,300.00 89.23 4,107.12 5,802.72 43.636.88 551,867.116,015,238.474,046.92 0.00 5,769.28 9,400.00 89.23 4,108.46 5,901.99 55.616.88 551,878.396,015,337.824,048.26 0.00 5,869.27 9,500.00 89.23 4,109.81 6,001.26 67.596.88 551,889.686,015,437.164,049.61 0.00 5,969.26 9,600.00 89.23 4,111.15 6,100.54 79.576.88 551,900.976,015,536.504,050.95 0.00 6,069.25 9,700.00 89.23 4,112.49 6,199.81 91.546.88 551,912.256,015,635.844,052.29 0.00 6,169.24 9,800.00 89.23 4,113.84 6,299.08 103.526.88 551,923.546,015,735.184,053.64 0.00 6,269.23 9,900.00 89.23 4,115.18 6,398.35 115.506.88 551,934.836,015,834.534,054.98 0.00 6,369.22 10,000.00 89.23 4,116.53 6,497.62 127.486.88 551,946.116,015,933.874,056.33 0.00 6,469.21 10,100.00 89.23 4,117.87 6,596.89 139.466.88 551,957.406,016,033.214,057.67 0.00 6,569.20 10,200.00 89.23 4,119.21 6,696.16 151.436.88 551,968.686,016,132.554,059.01 0.00 6,669.19 10,300.00 89.23 4,120.56 6,795.43 163.416.88 551,979.976,016,231.904,060.36 0.00 6,769.18 10,400.00 89.23 4,121.90 6,894.70 175.396.88 551,991.266,016,331.244,061.70 0.00 6,869.17 10,500.00 89.23 4,123.25 6,993.97 187.376.88 552,002.546,016,430.584,063.05 0.00 6,969.16 10,600.00 89.23 4,124.59 7,093.24 199.356.88 552,013.836,016,529.924,064.39 0.00 7,069.15 10,700.00 89.23 4,125.93 7,192.52 211.326.88 552,025.126,016,629.264,065.73 0.00 7,169.14 10,800.00 89.23 4,127.28 7,291.79 223.306.88 552,036.406,016,728.614,067.08 0.00 7,269.13 10,900.00 89.23 4,128.62 7,391.06 235.286.88 552,047.696,016,827.954,068.42 0.00 7,369.12 11,000.00 89.23 4,129.96 7,490.33 247.266.88 552,058.976,016,927.294,069.76 0.00 7,469.11 11,100.00 89.23 4,131.31 7,589.60 259.246.88 552,070.266,017,026.634,071.11 0.00 7,569.10 11,200.00 89.23 4,132.65 7,688.87 271.216.88 552,081.556,017,125.984,072.45 0.00 7,669.09 11,300.00 89.23 4,134.00 7,788.14 283.196.88 552,092.836,017,225.324,073.80 0.00 7,769.08 11,400.00 89.23 4,135.34 7,887.41 295.176.88 552,104.126,017,324.664,075.14 0.00 7,869.07 11,500.00 89.23 4,136.68 7,986.68 307.156.88 552,115.406,017,424.004,076.48 0.00 7,969.06 11,600.00 89.23 4,138.03 8,085.95 319.136.88 552,126.696,017,523.344,077.83 0.00 8,069.05 11,700.00 89.23 4,139.37 8,185.23 331.106.88 552,137.986,017,622.694,079.17 0.00 8,169.04 11,800.00 89.23 4,140.72 8,284.50 343.086.88 552,149.266,017,722.034,080.52 0.00 8,269.03 11,900.00 89.23 4,142.06 8,383.77 355.066.88 552,160.556,017,821.374,081.86 0.00 8,369.02 5/22/2020 12:13:03PM 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 Halliburton Standard Proposal Report Well: Wellbore: Plan: MPU I-20 MPU I-20 Survey Calculation Method:Minimum Curvature MPU I-20 as-built RKB @ 60.20usft (Original We Design:MPU I-20 wp06 Database:NORTH US + CANADA MD Reference:MPU I-20 as-built RKB @ 60.20usft (Original We North Reference: Well Plan: MPU I-20 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 4,083.20 Vert Section 12,000.00 89.23 4,143.40 8,483.04 367.046.88 552,171.846,017,920.714,083.20 0.00 8,469.01 12,100.00 89.23 4,144.75 8,582.31 379.026.88 552,183.126,018,020.064,084.55 0.00 8,569.00 12,200.00 89.23 4,146.09 8,681.58 390.996.88 552,194.416,018,119.404,085.89 0.00 8,668.99 12,300.00 89.23 4,147.43 8,780.85 402.976.88 552,205.696,018,218.744,087.23 0.00 8,768.97 12,400.00 89.23 4,148.78 8,880.12 414.956.88 552,216.986,018,318.084,088.58 0.00 8,868.96 12,500.00 89.23 4,150.12 8,979.39 426.936.88 552,228.276,018,417.424,089.92 0.00 8,968.95 12,600.00 89.23 4,151.47 9,078.66 438.916.88 552,239.556,018,516.774,091.27 0.00 9,068.94 12,700.00 89.23 4,152.81 9,177.93 450.886.88 552,250.846,018,616.114,092.61 0.00 9,168.93 12,800.00 89.23 4,154.15 9,277.21 462.866.88 552,262.136,018,715.454,093.95 0.00 9,268.92 12,900.00 89.23 4,155.50 9,376.48 474.846.88 552,273.416,018,814.794,095.30 0.00 9,368.91 13,000.00 89.23 4,156.84 9,475.75 486.826.88 552,284.706,018,914.144,096.64 0.00 9,468.90 13,100.00 89.23 4,158.19 9,575.02 498.796.88 552,295.986,019,013.484,097.99 0.00 9,568.89 13,200.00 89.23 4,159.53 9,674.29 510.776.88 552,307.276,019,112.824,099.33 0.00 9,668.88 13,241.46 89.23 4,160.09 9,715.45 515.746.88 552,311.956,019,154.014,099.89 0.00 9,710.34 Start Dir 3º/100' : 13241.46' MD, 4160.2'TVD 13,300.00 87.49 4,161.88 9,773.55 522.696.67 552,318.506,019,212.154,101.68 3.00 9,768.85 13,317.51 86.97 4,162.72 9,790.92 524.716.60 552,320.406,019,229.534,102.52 3.00 9,786.34 End Dir : 13317.51' MD, 4162.72' TVD 13,400.00 86.97 4,167.09 9,872.75 534.186.60 552,329.306,019,311.414,106.89 0.00 9,868.71 13,500.00 86.97 4,172.38 9,971.94 545.666.60 552,340.096,019,410.684,112.18 0.00 9,968.57 13,600.00 86.97 4,177.68 10,071.14 557.146.60 552,350.886,019,509.954,117.48 0.00 10,068.43 13,700.00 86.97 4,182.97 10,170.34 568.636.60 552,361.676,019,609.214,122.77 0.00 10,168.29 13,800.00 86.97 4,188.27 10,269.54 580.116.60 552,372.466,019,708.484,128.07 0.00 10,268.15 13,900.00 86.97 4,193.56 10,368.73 591.596.60 552,383.256,019,807.744,133.36 0.00 10,368.01 14,000.00 86.97 4,198.85 10,467.93 603.076.60 552,394.046,019,907.014,138.65 0.00 10,467.87 14,100.00 86.97 4,204.15 10,567.13 614.556.60 552,404.836,020,006.274,143.95 0.00 10,567.73 14,200.00 86.97 4,209.44 10,666.33 626.036.60 552,415.626,020,105.544,149.24 0.00 10,667.59 14,300.00 86.97 4,214.73 10,765.52 637.516.60 552,426.416,020,204.804,154.53 0.00 10,767.45 14,400.00 86.97 4,220.03 10,864.72 648.996.60 552,437.206,020,304.074,159.83 0.00 10,867.31 14,500.00 86.97 4,225.32 10,963.92 660.486.60 552,447.996,020,403.334,165.12 0.00 10,967.17 14,600.00 86.97 4,230.61 11,063.12 671.966.60 552,458.786,020,502.604,170.41 0.00 11,067.03 14,700.00 86.97 4,235.91 11,162.31 683.446.60 552,469.576,020,601.864,175.71 0.00 11,166.89 14,800.00 86.97 4,241.20 11,261.51 694.926.60 552,480.366,020,701.134,181.00 0.00 11,266.75 14,900.00 86.97 4,246.49 11,360.71 706.406.60 552,491.156,020,800.404,186.29 0.00 11,366.61 15,000.00 86.97 4,251.79 11,459.91 717.886.60 552,501.946,020,899.664,191.59 0.00 11,466.47 15,100.00 86.97 4,257.08 11,559.10 729.366.60 552,512.736,020,998.934,196.88 0.00 11,566.33 15,200.00 86.97 4,262.38 11,658.30 740.846.60 552,523.526,021,098.194,202.18 0.00 11,666.19 15,300.00 86.97 4,267.67 11,757.50 752.336.60 552,534.316,021,197.464,207.47 0.00 11,766.05 15,400.00 86.97 4,272.96 11,856.70 763.816.60 552,545.106,021,296.724,212.76 0.00 11,865.91 15,500.00 86.97 4,278.26 11,955.89 775.296.60 552,555.896,021,395.994,218.06 0.00 11,965.77 15,600.00 86.97 4,283.55 12,055.09 786.776.60 552,566.686,021,495.254,223.35 0.00 12,065.63 15,700.00 86.97 4,288.84 12,154.29 798.256.60 552,577.476,021,594.524,228.64 0.00 12,165.49 15,800.00 86.97 4,294.14 12,253.49 809.736.60 552,588.266,021,693.784,233.94 0.00 12,265.35 15,900.00 86.97 4,299.43 12,352.69 821.216.60 552,599.056,021,793.054,239.23 0.00 12,365.21 16,000.00 86.97 4,304.72 12,451.88 832.696.60 552,609.846,021,892.314,244.52 0.00 12,465.07 5/22/2020 12:13:03PM 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 Halliburton Standard Proposal Report Well: Wellbore: Plan: MPU I-20 MPU I-20 Survey Calculation Method:Minimum Curvature MPU I-20 as-built RKB @ 60.20usft (Original We Design:MPU I-20 wp06 Database:NORTH US + CANADA MD Reference:MPU I-20 as-built RKB @ 60.20usft (Original We North Reference: Well Plan: MPU I-20 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 4,250.00 Vert Section 16,103.45 86.97 4,310.20 12,554.50 844.576.60 552,621.006,021,995.004,250.00 0.00 12,568.37 Total Depth : 16103.45' MD, 4310.2' TVD Target Name - hit/miss target - Shape TVD (usft) Northing (usft) Easting (usft) +N/-S (usft) +E/-W (usft) Tar gets Dip Angle (°) Dip Dir. (°) MPI-Winchester wp02 Heel 4,010.20 6,010,934.00 551,667.001,499.33 -186.430.00 0.00 -plan hits target center - Circle (radius 30.00) MPI-Winchester wp02 Toe 4,310.20 6,021,995.00 552,621.0012,554.50 844.570.00 0.00 -plan hits target center - Point MPI-Winchester wp02 CP1 4,100.20 6,014,727.00 551,809.005,291.62 -18.040.00 0.00 -plan hits target center - Point MPI-Winchester wp02 CP2 4,160.20 6,019,154.00 552,312.009,715.44 515.790.00 0.00 -plan misses target center by 0.12usft at 13241.46usft MD (4160.09 TVD, 9715.45 N, 515.74 E) - Point Vertical Depth (usft) Measured Depth (usft) Casing Diameter (") Hole Diameter (")Name Casing Points 9 5/8" x 12 1/4"4,010.204,986.66 9-5/8 12-1/4 6 5/8" x 8 1/2"4,310.2016,103.45 6-5/8 8-1/2 Measured Depth (usft) Vertical Depth (usft) +E/-W (usft) +N/-S (usft) Local Coordinates Comment Plan Annotations 1,300.00 1,300.00 0.00 0.00 Start Dir 4º/100' : 1300' MD, 1300'TVD 1,425.72 1,425.56 -5.44 -0.91 End Dir : 1425.72' MD, 1425.55' TVD 2,439.94 2,435.87 -93.12 -15.60 Start Dir 4º/100' : 2439.94' MD, 2435.87'TVD 4,686.66 3,984.05 1,201.60 -160.38 End Dir : 4686.66' MD, 3984.05' TVD 4,986.66 4,010.20 1,499.32 -186.43 Start Dir 2.5º/100' : 4986.66' MD, 4010.2'TVD 5,334.38 4,029.00 1,846.14 -192.96 End Dir : 5334.38' MD, 4029' TVD 8,649.32 4,097.88 5,156.33 -29.52 Start Dir 3º/100' : 8649.32' MD, 4097.88'TVD 8,785.14 4,100.20 5,291.62 -18.04 End Dir : 8785.14' MD, 4100.2' TVD 13,241.46 4,160.09 9,715.45 515.74 Start Dir 3º/100' : 13241.46' MD, 4160.2'TVD 13,317.51 4,162.72 9,790.92 524.71 End Dir : 13317.51' MD, 4162.72' TVD 16,103.45 4,310.20 12,554.50 844.57 Total Depth : 16103.45' MD, 4310.2' TVD 5/22/2020 12:13:03PM COMPASS 5000.15 Build 91E Page 7 22 May, 2020Milne PointM Pt I PadPlan: MPU I-20MPU I-20MPU I-20 wp06Reference Design: M Pt I Pad - Plan: MPU I-20 - MPU I-20 - MPU I-20 wp06Closest Approach 3D Proximity Scan on Current Survey Data (North Reference)Well Coordinates: 6,009,436.15 N, 551,863.83 E (70° 26' 11.48" N, 149° 34' 37.73" W)Datum Height: MPU I-20 as-built RKB @ 60.20usft (Original Well Elev)Scan Range: 26.50 to 4,986.66 usft. Measured Depth.Geodetic Scale Factor AppliedVersion: 5000.15 Build: 91EScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftNO GLOBAL FILTER: Using user defined selection & filtering criteriaScan Type:Scan Type:25.000-4986ftScan Range: 26.50 to 4,986.66 usft. Measured Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU I-20 - MPU I-20 wp06Comparison 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: 26.50 to 4,986.66 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (North Reference)Reference Design: M Pt I Pad - Plan: MPU I-20 - MPU I-20 - MPU I-20 wp06MeasuredDepth(usft)Summary Based on MinimumSeparation WarningM Pt I PadMPI-01 - MPI-01 - MPI-0169.22 1,243.44 58.67 1,277.40 6.5621,243.44Ellipse Separation Pass - MPI-01 - MPI-01 - MPI-0170.65 1,276.50 59.82 1,307.20 6.5241,276.50Clearance Factor Pass - MPI-02 - MPI-02 - MPI-02128.70 1,361.86 117.00 1,405.81 10.9961,361.86Ellipse Separation Pass - MPI-02 - MPI-02 - MPI-02130.38 1,401.50 118.27 1,441.08 10.7691,401.50Clearance Factor Pass - MPI-03 - MPI-03 - MPI-03267.81 1,079.41 258.72 1,105.89 29.4791,079.41Centre Distance Pass - MPI-03 - MPI-03 - MPI-03267.95 1,101.50 258.68 1,126.05 28.8811,101.50Ellipse Separation Pass - MPI-03 - MPI-03 - MPI-03314.62 1,476.50 302.26 1,451.56 25.4531,476.50Clearance Factor Pass - MPI-05 - MPI-05 - MPI-0527.07 1,923.62 10.76 1,970.08 1.6601,923.62Centre Distance Pass - MPI-05 - MPI-05 - MPI-0527.10 1,926.50 10.68 1,972.58 1.6501,926.50Clearance Factor Pass - MPI-07 - MPI-07 - MPI-07163.66 3,620.93 138.03 3,554.27 6.3853,620.93Clearance Factor Pass - MPI-09 - MPI-09 - MPI-09206.85 738.70 200.52 743.00 32.711738.70Centre Distance Pass - MPI-09 - MPI-09 - MPI-09206.87 751.50 200.51 754.99 32.489751.50Ellipse Separation Pass - MPI-09 - MPI-09 - MPI-091,552.14 4,986.66 1,493.53 3,519.63 26.4824,986.66Clearance Factor Pass - MPI-10 - MPI-10 - MPI-10152.58 511.16 148.38 513.50 36.326511.16Centre Distance Pass - MPI-10 - MPI-10 - MPI-10152.65 526.50 148.34 527.52 35.410526.50Ellipse Separation Pass - MPI-10 - MPI-10 - MPI-10182.22 1,051.50 174.38 1,029.61 23.2501,051.50Clearance Factor Pass - MPI-15 - MPI-15 - MPI-1582.47 1,136.14 74.30 1,148.77 10.0861,136.14Ellipse Separation Pass - MPI-15 - MPI-15 - MPI-1584.01 1,176.50 75.41 1,184.89 9.7741,176.50Clearance Factor Pass - MPI-15 - MPI-15L1 - MPI-15L182.47 1,136.14 74.30 1,148.77 10.0861,136.14Ellipse Separation Pass - MPI-15 - MPI-15L1 - MPI-15L184.01 1,176.50 75.41 1,184.89 9.7741,176.50Clearance Factor Pass - MPI-15 - MPI-15PB1 - MPI-15PB182.47 1,136.14 74.30 1,148.77 10.0861,136.14Ellipse Separation Pass - MPI-15 - MPI-15PB1 - MPI-15PB184.01 1,176.50 75.41 1,184.89 9.7741,176.50Clearance Factor Pass - MPI-16 - MPI-16 - MPI-16104.51 101.50 102.66 109.65 56.627101.50Centre Distance Pass - MPI-16 - MPI-16 - MPI-16104.86 226.50 102.18 234.00 39.013226.50Ellipse Separation Pass - MPI-16 - MPI-16 - MPI-16125.54 726.50 119.05 725.83 19.349726.50Clearance Factor Pass - MPI-17 - MPI-17 - MPI-1772.24 316.80 68.42 324.96 18.934316.80Centre Distance Pass - MPI-17 - MPI-17 - MPI-1772.63 376.50 68.17 383.64 16.279376.50Ellipse Separation Pass - MPI-17 - MPI-17 - MPI-1780.26 576.50 74.19 580.20 13.214576.50Clearance Factor Pass - 22 May, 2020-12:27COMPASSPage 2 of 7 Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU I-20 - MPU I-20 wp06Comparison 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: 26.50 to 4,986.66 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (North Reference)Reference Design: M Pt I Pad - Plan: MPU I-20 - MPU I-20 - MPU I-20 wp06MeasuredDepth(usft)Summary Based on MinimumSeparation WarningMPI-17 - MPI-17L1 - MPI-17L172.24 316.80 68.42 324.96 18.934316.80Centre Distance Pass - MPI-17 - MPI-17L1 - MPI-17L172.63 376.50 68.17 383.64 16.279376.50Ellipse Separation Pass - MPI-17 - MPI-17L1 - MPI-17L180.26 576.50 74.19 580.20 13.214576.50Clearance Factor Pass - MPI-17 - MPI-17L1PB1 - MPI-17L1PB172.24 316.80 68.42 324.96 18.934316.80Centre Distance Pass - MPI-17 - MPI-17L1PB1 - MPI-17L1PB172.63 376.50 68.17 383.64 16.279376.50Ellipse Separation Pass - MPI-17 - MPI-17L1PB1 - MPI-17L1PB180.26 576.50 74.19 580.20 13.214576.50Clearance Factor Pass - MPI-17 - MPI-17L2 - MPI-17L272.24 316.80 68.42 324.96 18.934316.80Centre Distance Pass - MPI-17 - MPI-17L2 - MPI-17L272.63 376.50 68.17 383.64 16.279376.50Ellipse Separation Pass - MPI-17 - MPI-17L2 - MPI-17L280.26 576.50 74.19 580.20 13.214576.50Clearance Factor Pass - MPI-18 - MPI-18 - MPI-1842.05 488.29 37.53 491.52 9.310488.29Centre Distance Pass - MPI-18 - MPI-18 - MPI-1842.34 551.50 37.33 554.48 8.458551.50Ellipse Separation Pass - MPI-18 - MPI-18 - MPI-1846.99 701.50 40.82 703.17 7.611701.50Clearance Factor Pass - MPI-19 - MPI-19 - MPI-1911.57 365.05 7.91 374.00 3.166365.05Centre Distance Pass - MPI-19 - MPI-19 - MPI-1911.74 401.50 7.81 410.37 2.987401.50Ellipse Separation Pass - MPI-19 - MPI-19 - MPI-1912.10 426.50 7.98 435.29 2.936426.50Clearance Factor Pass - MPI-19 - MPI-19L1 - MPI-19L111.57 365.05 7.91 374.00 3.166365.05Centre Distance Pass - MPI-19 - MPI-19L1 - MPI-19L111.74 401.50 7.81 410.37 2.987401.50Ellipse Separation Pass - MPI-19 - MPI-19L1 - MPI-19L112.10 426.50 7.98 435.29 2.936426.50Clearance Factor Pass - MPI-19 - MPI-19PB1 - MPI-19PB111.57 365.05 7.91 374.00 3.166365.05Centre Distance Pass - MPI-19 - MPI-19PB1 - MPI-19PB111.74 401.50 7.81 410.37 2.987401.50Ellipse Separation Pass - MPI-19 - MPI-19PB1 - MPI-19PB112.10 426.50 7.98 435.29 2.936426.50Clearance Factor Pass - MPI-19 - MPI-19PB2 - MPI-19PB211.57 365.05 7.91 374.00 3.166365.05Centre Distance Pass - MPI-19 - MPI-19PB2 - MPI-19PB211.74 401.50 7.81 410.37 2.987401.50Ellipse Separation Pass - MPI-19 - MPI-19PB2 - MPI-19PB212.10 426.50 7.98 435.29 2.936426.50Clearance Factor Pass - MPU I-35i - MPU I-35i - MPU I-35i53.61 915.40 47.73 915.59 9.127915.40Centre Distance Pass - MPU I-35i - MPU I-35i - MPU I-35i53.63 926.50 47.71 926.45 9.049926.50Ellipse Separation Pass - MPU I-35i - MPU I-35i - MPU I-35i333.09 4,986.66 290.19 4,851.29 7.7634,986.66Clearance Factor Pass - Plan: MPU I-21i - MPU I-21 - MPU I-21i wp0589.92 277.07 87.36 277.07 35.109277.07Ellipse Separation Pass - Plan: MPU I-21i - MPU I-21 - MPU I-21i wp05854.35 4,986.66 804.73 5,313.46 17.2174,986.66Clearance Factor Pass - Plan: MPU I-22 - MPU I-22 - MPU I-22 wp03204.14 327.60 201.36 328.40 73.423327.60Centre Distance Pass - 22 May, 2020-12:27COMPASSPage 3 of 7 Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU I-20 - MPU I-20 wp06Comparison 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: 26.50 to 4,986.66 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (North Reference)Reference Design: M Pt I Pad - Plan: MPU I-20 - MPU I-20 - MPU I-20 wp06MeasuredDepth(usft)Summary Based on MinimumSeparation WarningPlan: MPU I-22 - MPU I-22 - MPU I-22 wp03204.16 351.50 201.27 351.73 70.739351.50Ellipse Separation Pass - Plan: MPU I-22 - MPU I-22 - MPU I-22 wp031,775.94 4,986.66 1,724.13 5,810.39 34.2734,986.66Clearance Factor Pass - Plan: MPU I-27 - MPU I-27 - MPU I-27 wp0430.17 1,030.17 24.60 1,030.07 5.4181,030.17Centre Distance Pass - Plan: MPU I-27 - MPU I-27 - MPU I-27 wp0430.17 1,051.50 24.53 1,051.39 5.3531,051.50Ellipse Separation Pass - Plan: MPU I-27 - MPU I-27 - MPU I-27 wp04187.18 4,986.66 136.67 5,128.48 3.7064,986.66Clearance Factor Pass - Plan: MPU I-28i - MPU I-28 - MPU I-28i wp03120.26 280.32 117.69 279.82 46.704280.32Centre Distance Pass - Plan: MPU I-28i - MPU I-28 - MPU I-28i wp03120.33 326.50 117.55 325.38 43.388326.50Ellipse Separation Pass - Plan: MPU I-28i - MPU I-28 - MPU I-28i wp031,077.44 4,986.66 1,028.22 5,236.71 21.8884,986.66Clearance Factor Pass - Plan: MPU I-29 - MPU I-29 - MPU I-29 wp03146.58 230.25 144.20 229.95 61.750230.25Centre Distance Pass - Plan: MPU I-29 - MPU I-29 - MPU I-29 wp03146.63 276.50 144.07 275.62 57.326276.50Ellipse Separation Pass - Plan: MPU I-29 - MPU I-29 - MPU I-29 wp03171.77 701.50 167.13 676.77 37.075701.50Clearance Factor Pass - Rig: MPU I-36 - MPU I-36 - MPU I-36 wp07174.84 278.42 172.27 278.32 68.120278.42Centre Distance Pass - Rig: MPU I-36 - MPU I-36 - MPU I-36 wp07174.88 301.50 172.22 300.00 65.703301.50Ellipse Separation Pass - Rig: MPU I-36 - MPU I-36 - MPU I-36 wp071,313.06 4,986.66 1,261.23 5,349.73 25.3354,986.66Clearance Factor Pass - Rig: MPU I-36 - MPU I-36 - MPU I-36174.84 80.17 172.89 80.07 89.65380.17Centre Distance Pass - Rig: MPU I-36 - MPU I-36 - MPU I-36174.84 101.50 172.86 100.00 88.083101.50Ellipse Separation Pass - Rig: MPU I-36 - MPU I-36 - MPU I-36231.28 251.50 227.18 100.00 56.492251.50Clearance Factor Pass - M Pt J PadMPJ-03 - MPJ-03 - MPJ-031,124.51 4,986.66 1,059.82 5,448.00 17.3834,986.66Clearance Factor Pass - Survey tool programFrom(usft)To(usft)Survey/Plan Survey Tool26.50 700.00 MPU I-20 wp06 3_Gyro-GC_Csg700.00 4,986.66 MPU I-20 wp06 3_MWD+IFR2+MS+Sag4,986.66 16,103.18 MPU I-20 wp06 3_MWD+IFR2+MS+Sag22 May, 2020-12:27COMPASSPage 4 of 7 Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU I-20 - MPU I-20 wp06Ellipse 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 May, 2020-12:27COMPASSPage 5 of 7 0.001.002.003.004.00Separation Factor0 275 550 825 1100 1375 1650 1925 2200 2475 2750 3025 3300 3575 3850 4125 4400 4675 4950 5225Measured Depth (550 usft/in)MPI-19MPU I-27 wp04No-Go Zone - Stop DrillingCollision Avoidance Req.Collision Risk Procedures Req.NOERRORSWELL DETAILS:Plan: MPU I-20 NAD 1927 (NADCON CONUS)Alaska Zone 0433.40+N/-S +E/-W Northing Easting Latittude Longitude0.000.006009436.15551863.8370° 26' 11.482 N149° 34' 37.726 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU I-20, True NorthVertical (TVD) Reference:MPU I-20 as-built RKB @ 60.20usft (Original Well Elev)Measured Depth Reference:MPU I-20 as-built RKB @ 60.20usft (Original Well Elev)Calculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2020-05-15T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool26.50 700.00 MPU I-20 wp06 (MPU I-20) 3_Gyro-GC_Csg700.00 4986.66 MPU I-20 wp06 (MPU I-20) 3_MWD+IFR2+MS+Sag4986.66 16103.18 MPU I-20 wp06 (MPU I-20) 3_MWD+IFR2+MS+Sag0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)0 275 550 825 1100 1375 1650 1925 2200 2475 2750 3025 3300 3575 3850 4125 4400 4675 4950 5225Measured Depth (550 usft/in)MPI-10MPI-15MPI-16MPI-17MPI-18MPI-19MPU I-35iMPU I-21i wp05MPU I-28i wp03MPU I-29 wp03MPU I-27 wp04NO GLOBAL FILTER: Using user defined selection & filtering criteria26.50 To 16103.45Project: Milne PointSite: M Pt I PadWell: Plan: MPU I-20Wellbore: MPU I-20Plan: MPU I-20 wp06Ladder / S.F. Plots1 of 2CASING DETAILSTVD TVDSS MD Size Name4010.20 3950.00 4986.66 9-5/8 9 5/8" x 12 1/4"4310.20 4250.00 16103.45 6-5/8 6 5/8" x 8 1/2" 22 May, 2020Milne PointM Pt I PadPlan: MPU I-20MPU I-20MPU I-20 wp06Reference Design: M Pt I Pad - Plan: MPU I-20 - MPU I-20 - MPU I-20 wp06Closest Approach 3D Proximity Scan on Current Survey Data (North Reference)Well Coordinates: 6,009,436.15 N, 551,863.83 E (70° 26' 11.48" N, 149° 34' 37.73" W)Datum Height: MPU I-20 as-built RKB @ 60.20usft (Original Well Elev)Scan Range: 4,986.66 to 16,103.45 usft. Measured Depth.Geodetic Scale Factor AppliedVersion: 5000.15 Build: 91EScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftNO GLOBAL FILTER: Using user defined selection & filtering criteriaScan Type:Scan Type:25.00Scan Range: 4,986.66 to 16,103.45 usft. Measured Depth.4986- 16103 FT Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU I-20 - MPU I-20 wp06Comparison 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: 4,986.66 to 16,103.45 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (North Reference)Reference Design: M Pt I Pad - Plan: MPU I-20 - MPU I-20 - MPU I-20 wp06MeasuredDepth(usft)Summary Based on MinimumSeparation WarningM Pt G PadMPG-14 - MPG-14L1 - MPG-14L11,385.95 12,178.43 1,226.07 7,475.74 8.66912,178.43Centre Distance Pass - MPG-14 - MPG-14L1 - MPG-14L11,386.18 12,211.66 1,225.46 7,502.22 8.62412,211.66Ellipse Separation Pass - MPG-14 - MPG-14L1 - MPG-14L11,770.30 14,411.66 1,530.28 9,400.00 7.37614,411.66Clearance Factor Pass - MPG-15 - MPG-15 - MPG-151,528.41 15,536.66 1,065.35 9,846.30 3.30115,536.66Clearance Factor Pass - MPG-15 - MPG-15 - MPG-151,513.13 15,661.66 1,057.70 9,846.30 3.32215,661.66Ellipse Separation Pass - MPG-15 - MPG-15 - MPG-151,508.08 15,785.14 1,063.26 9,846.30 3.39015,785.14Centre Distance Pass - MPG-17 - MPG-17 - MPG-171,250.96 8,811.66 1,062.65 6,578.00 6.6438,811.66Clearance Factor Pass - MPG-17 - MPG-17 - MPG-171,072.71 9,336.66 943.16 6,578.00 8.2809,336.66Ellipse Separation Pass - MPG-17 - MPG-17 - MPG-171,064.57 9,468.62 950.20 6,578.00 9.3099,468.62Centre Distance Pass - M Pt H PadMPH-18 - MPH-18 - MPH-18829.51 8,511.66 555.44 8,631.34 3.0278,511.66Clearance Factor Pass - MPH-18 - MPH-18 - MPH-18826.31 8,536.66 554.32 8,639.00 3.0388,536.66Ellipse Separation Pass - MPH-18 - MPH-18 - MPH-18820.86 8,631.43 568.49 8,639.00 3.2538,631.43Centre Distance Pass - MPH-18 - MPH-18L1 - MPH-18L1843.98 7,561.66 614.21 7,769.15 3.6737,561.66Clearance Factor Pass - MPH-18 - MPH-18L1 - MPH-18L1799.04 7,811.66 589.11 7,865.25 3.8067,811.66Ellipse Separation Pass - MPH-18 - MPH-18L1 - MPH-18L1793.29 7,942.76 597.14 7,916.57 4.0447,942.76Centre Distance Pass - MPH-18 - MPH-18L2 - MPH-18L2752.75 8,586.66 522.51 8,630.00 3.2698,586.66Clearance Factor Pass - MPH-18 - MPH-18L2 - MPH-18L2752.23 8,614.52 527.30 8,630.00 3.3448,614.52Centre Distance Pass - M Pt I PadMPI-07 - MPI-07 - MPI-071,244.31 4,986.66 1,215.03 4,052.13 42.4994,986.66Clearance Factor Pass - MPI-09 - MPI-09 - MPI-091,552.14 4,986.66 1,493.53 3,519.63 26.4824,986.66Ellipse Separation Pass - MPI-09 - MPI-09 - MPI-091,799.16 5,836.66 1,695.12 4,140.47 17.2935,836.66Clearance Factor Pass - MPI-19 - MPI-19 - MPI-19834.88 8,970.04 696.04 7,794.10 6.0138,970.04Centre Distance Pass - MPI-19 - MPI-19 - MPI-19835.68 9,036.66 695.11 7,840.65 5.9459,036.66Ellipse Separation Pass - MPI-19 - MPI-19 - MPI-191,012.33 11,011.66 804.59 9,720.00 4.87311,011.66Clearance Factor Pass - MPI-19 - MPI-19L1 - MPI-19L1825.83 8,899.66 687.94 7,718.20 5.9898,899.66Centre Distance Pass - 22 May, 2020-12:30COMPASSPage 2 of 7 Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU I-20 - MPU I-20 wp06Comparison 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: 4,986.66 to 16,103.45 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (North Reference)Reference Design: M Pt I Pad - Plan: MPU I-20 - MPU I-20 - MPU I-20 wp06MeasuredDepth(usft)Summary Based on MinimumSeparation WarningMPI-19 - MPI-19L1 - MPI-19L1827.04 8,961.66 687.23 7,746.91 5.9168,961.66Ellipse Separation Pass - MPI-19 - MPI-19L1 - MPI-19L11,018.26 10,511.66 832.71 9,179.50 5.48810,511.66Clearance Factor Pass - MPI-19 - MPI-19PB1 - MPI-19PB1816.25 8,974.25 660.06 7,799.00 5.2268,974.25Centre Distance Pass - MPI-19 - MPI-19PB1 - MPI-19PB1817.11 9,011.66 659.66 7,799.00 5.1909,011.66Ellipse Separation Pass - MPI-19 - MPI-19PB1 - MPI-19PB1820.92 9,061.66 662.27 7,799.00 5.1749,061.66Clearance Factor Pass - MPI-19 - MPI-19PB2 - MPI-19PB2822.21 9,154.30 679.21 7,978.59 5.7509,154.30Centre Distance Pass - MPI-19 - MPI-19PB2 - MPI-19PB2823.57 9,236.66 678.24 8,035.61 5.6679,236.66Ellipse Separation Pass - MPI-19 - MPI-19PB2 - MPI-19PB2900.96 9,861.66 725.38 8,532.00 5.1319,861.66Clearance Factor Pass - MPU I-35i - MPU I-35i - MPU I-35i222.7613,278.3427.4913,130.001.14113,278.34Centre DistancePass - MPU I-35i - MPU I-35i - MPU I-35i222.9313,286.6627.4113,130.001.14013,286.66Clearance FactorPass - Plan: MPU I-21i - MPU I-21 - MPU I-21i wp05784.41 13,532.39 525.35 13,921.62 3.02813,532.39Centre Distance Pass - Plan: MPU I-21i - MPU I-21 - MPU I-21i wp05784.96 13,561.66 525.18 13,921.62 3.02213,561.66Clearance Factor Pass - Plan: MPU I-22 - MPU I-22 - MPU I-22 wp031,491.28 13,586.96 1,230.97 14,570.85 5.72913,586.96Centre Distance Pass - Plan: MPU I-22 - MPU I-22 - MPU I-22 wp031,491.48 13,611.66 1,230.64 14,570.85 5.71813,611.66Ellipse Separation Pass - Plan: MPU I-22 - MPU I-22 - MPU I-22 wp031,494.60 13,686.66 1,232.55 14,570.85 5.70313,686.66Clearance Factor Pass - Plan: MPU I-28i - MPU I-28 - MPU I-28i wp03691.68 14,987.86 399.37 15,276.27 2.36614,987.86Centre Distance Pass - Plan: MPU I-28i - MPU I-28 - MPU I-28i wp03692.09 15,011.66 399.30 15,276.27 2.36415,011.66Clearance Factor Pass - Plan: MPU I-29 - MPU I-29 - MPU I-29 wp031,356.49 15,113.99 1,056.77 16,125.49 4.52615,113.99Centre Distance Pass - Plan: MPU I-29 - MPU I-29 - MPU I-29 wp031,356.68 15,136.66 1,056.50 16,125.49 4.52015,136.66Ellipse Separation Pass - Plan: MPU I-29 - MPU I-29 - MPU I-29 wp031,358.43 15,186.66 1,057.54 16,125.49 4.51515,186.66Clearance Factor Pass - Rig: MPU I-36 - MPU I-36 - MPU I-36 wp07939.22 14,993.05 652.94 15,467.77 3.28114,993.05Centre Distance Pass - Rig: MPU I-36 - MPU I-36 - MPU I-36 wp07939.40 15,011.66 652.75 15,467.77 3.27715,011.66Ellipse Separation Pass - Rig: MPU I-36 - MPU I-36 - MPU I-36 wp07940.23 15,036.66 653.23 15,467.77 3.27615,036.66Clearance Factor Pass - M Pt J PadMPJ-01 - MPJ-01 - MPJ-0137.4110,060.47-73.744,307.220.33710,060.47Centre DistanceFAIL - MPJ-01 - MPJ-01 - MPJ-0137.4210,061.66-73.934,307.640.33610,061.66Clearance FactorFAIL - MPJ-01 - MPJ-01A - MPJ-01A171.9413,796.28-90.308,034.000.65613,796.28Clearance FactorFAIL - MPJ-01 - MPJ-01AL1 - MPJ-01AL1167.1312,985.08-48.277,335.780.77612,985.08Centre DistanceFAIL - MPJ-01 - MPJ-01AL1 - MPJ-01AL1167.5713,011.66-49.187,356.820.77313,011.66Clearance FactorFAIL - 22 May, 2020-12:30COMPASSPage 3 of 7Per sundry 320-080J-01ISP&A'dgls Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU I-20 - MPU I-20 wp06Comparison 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: 4,986.66 to 16,103.45 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (North Reference)Reference Design: M Pt I Pad - Plan: MPU I-20 - MPU I-20 - MPU I-20 wp06MeasuredDepth(usft)Summary Based on MinimumSeparation WarningMPJ-03 - MPJ-03 - MPJ-03273.12 6,236.66 160.00 5,124.86 2.4146,236.66Clearance Factor Pass - MPJ-03 - MPJ-03 - MPJ-03271.47 6,261.66 159.58 5,107.85 2.4266,261.66Ellipse Separation Pass - MPJ-03 - MPJ-03 - MPJ-03271.04 6,282.59 160.52 5,093.69 2.4526,282.59Centre Distance Pass - MPJ-05 - MPJ-05 - MPJ-051,119.33 9,479.34 1,032.14 3,781.69 12.8379,479.34Centre Distance Pass - MPJ-05 - MPJ-05 - MPJ-051,119.54 9,486.92 1,031.53 3,800.00 12.7209,486.92Ellipse Separation Pass - MPJ-05 - MPJ-05 - MPJ-051,140.18 9,711.66 1,048.71 3,850.59 12.4659,711.66Clearance Factor Pass - MPJ-06 - MPJ-06 - MPJ-06390.24 10,102.99 266.43 4,458.60 3.15210,102.99Centre Distance Pass - MPJ-06 - MPJ-06 - MPJ-06392.85 10,161.66 263.91 4,496.61 3.04710,161.66Ellipse Separation Pass - MPJ-06 - MPJ-06 - MPJ-06399.17 10,211.66 267.09 4,528.54 3.02210,211.66Clearance Factor Pass - MPJ-08 - MPJ-08 - MPJ-08862.70 9,826.23 784.84 3,824.25 11.0819,826.23Centre Distance Pass - MPJ-08 - MPJ-08 - MPJ-08866.99 9,936.66 780.58 3,888.42 10.0339,936.66Ellipse Separation Pass - MPJ-08 - MPJ-08 - MPJ-081,806.41 14,361.66 1,464.90 8,427.78 5.29014,361.66Clearance Factor Pass - MPJ-08 - MPJ-08A - MPJ-08A862.70 9,826.23 784.84 3,825.05 11.0819,826.23Centre Distance Pass - MPJ-08 - MPJ-08A - MPJ-08A866.99 9,936.66 780.58 3,889.22 10.0339,936.66Ellipse Separation Pass - MPJ-08 - MPJ-08A - MPJ-08A1,318.60 11,111.66 1,157.53 4,720.50 8.18611,111.66Clearance Factor Pass - MPJ-10 - MPJ-10 - MPJ-101,121.86 10,494.49 995.89 4,254.54 8.90610,494.49Centre Distance Pass - MPJ-10 - MPJ-10 - MPJ-101,122.59 10,536.66 995.17 4,265.01 8.81010,536.66Ellipse Separation Pass - MPJ-10 - MPJ-10 - MPJ-101,145.89 10,736.66 1,013.24 4,320.52 8.63810,736.66Clearance Factor Pass - MPJ-11 - MPJ-11 - MPJ-11379.56 11,950.82 247.17 5,312.00 2.86711,950.82Centre Distance Pass - MPJ-11 - MPJ-11 - MPJ-11380.27 11,986.66 245.72 5,339.50 2.82611,986.66Ellipse Separation Pass - MPJ-11 - MPJ-11 - MPJ-11383.55 12,036.66 246.72 5,378.57 2.80312,036.66Clearance Factor Pass - MPJ-12 - MPJ-12 - MPJ-12458.71 10,565.76 319.30 4,533.71 3.29010,565.76Centre Distance Pass - MPJ-12 - MPJ-12 - MPJ-12459.05 10,586.66 319.24 4,544.95 3.28310,586.66Clearance Factor Pass - MPJ-13 - MPJ-13 - MPJ-131,113.99 11,270.00 946.22 5,000.56 6.64011,270.00Centre Distance Pass - MPJ-13 - MPJ-13 - MPJ-131,115.62 11,361.66 944.00 5,070.11 6.50111,361.66Ellipse Separation Pass - MPJ-13 - MPJ-13 - MPJ-131,143.83 11,636.66 964.31 5,249.37 6.37211,636.66Clearance Factor Pass - MPJ-16 - MPJ-16 - MPJ-16941.22 12,306.31 716.79 5,869.89 4.19412,306.31Centre Distance Pass - MPJ-16 - MPJ-16 - MPJ-16944.96 12,486.66 709.26 6,018.77 4.00912,486.66Ellipse Separation Pass - MPJ-16 - MPJ-16 - MPJ-16978.11 12,786.66 728.19 6,247.94 3.91412,786.66Clearance Factor Pass - MPJ-25 - MPJ-25 - MPJ-25936.06 9,694.91 858.44 3,749.05 12.0599,694.91Centre Distance Pass - 22 May, 2020-12:30COMPASSPage 4 of 7 Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU I-20 - MPU I-20 wp06Comparison 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: 4,986.66 to 16,103.45 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (North Reference)Reference Design: M Pt I Pad - Plan: MPU I-20 - MPU I-20 - MPU I-20 wp06MeasuredDepth(usft)Summary Based on MinimumSeparation WarningMPJ-25 - MPJ-25 - MPJ-25936.94 9,736.66 857.30 3,758.19 11.7659,736.66Ellipse Separation Pass - MPJ-25 - MPJ-25 - MPJ-251,001.39 10,061.66 909.06 3,827.31 10.84610,061.66Clearance Factor Pass - MPJ-25 - MPJ-25PB1 - MPJ-25PB1936.06 9,694.91 858.44 3,749.05 12.0599,694.91Centre Distance Pass - MPJ-25 - MPJ-25PB1 - MPJ-25PB1936.94 9,736.66 857.30 3,758.19 11.7659,736.66Ellipse Separation Pass - MPJ-25 - MPJ-25PB1 - MPJ-25PB11,001.39 10,061.66 909.06 3,827.31 10.84610,061.66Clearance Factor Pass - Survey tool programFrom(usft)To(usft)Survey/Plan Survey Tool26.50 700.00 MPU I-20 wp06 3_Gyro-GC_Csg700.00 4,986.66 MPU I-20 wp06 3_MWD+IFR2+MS+Sag4,986.66 16,103.18 MPU I-20 wp06 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 May, 2020-12:30COMPASSPage 5 of 7 WELL DETAILS:Plan: MPU I-20 NAD 1927 (NADCON CONUS)Alaska Zone 0433.40+N/-S +E/-W Northing Easting Latittude Longitude0.000.006009436.15551863.83 70° 26' 11.482 N149° 34' 37.726 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU I-20, True NorthVertical (TVD) Reference:MPU I-20 as-built RKB @ 60.20usft (Original Well Elev)Measured Depth Reference:MPU I-20 as-built RKB @ 60.20usft (Original Well Elev)Calculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2020-05-15T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool26.50 700.00 MPU I-20 wp06 (MPU I-20) 3_Gyro-GC_Csg700.00 4986.66 MPU I-20 wp06 (MPU I-20) 3_MWD+IFR2+MS+Sag4986.66 16103.18 MPU I-20 wp06 (MPU I-20) 3_MWD+IFR2+MS+Sag0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)4800 5400 6000 6600 7200 7800 8400 9000 9600 10200 10800 11400 12000 12600 13200 13800 14400 15000 15600 16200Measured Depth (1200 usft/in)MPJ-01NO GLOBAL FILTER: Using user defined selection & filtering criteria26.50 To 16103.45Project: Milne PointSite: M Pt I PadWell: Plan: MPU I-20Wellbore: MPU I-20Plan: MPU I-20 wp06Ladder / S.F. Plots2 of 2CASING DETAILSTVD TVDSS MD Size Name4010.20 3950.00 4986.66 9-5/8 9 5/8" x 12 1/4"4310.20 4250.00 16103.45 6-5/8 6 5/8" x 8 1/2"0.001.002.003.004.00Separation Factor4800 5400 6000 6600 7200 7800 8400 9000 9600 10200 10800 11400 12000 12600 13200 13800 14400 15000 15600 16200Measured Depth (1200 usft/in)MPJ-01No-Go Zone - Stop DrillingCollision Avoidance Req.Collision Risk Procedures Req.NOERRORS WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name:MILNE PT UNIT I-20Initial Class/TypeDEV / PENDGeoArea890Unit11328On/Off ShoreOnProgramDEVField & PoolWell bore segAnnular DisposalPTD#:2200490MILNE POINT, SCHRADER BLFF OIL - 525140NA1 Permit fee attachedYes2 Lease number appropriateYes3 Unique well name and numberYes4 Well located in a defined poolYes5 Well located proper distance from drilling unit boundaryYes6 Well located proper distance from other wellsYes7 Sufficient acreage available in drilling unitYes8 If deviated, is wellbore plat includedYes9 Operator only affected partyYes10 Operator has appropriate bond in forceYes11 Permit can be issued without conservation orderYes12 Permit can be issued without administrative approvalYes13 Can permit be approved before 15-day waitNA14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (For NA15 All wells within 1/4 mile area of review identified (For service well only)NA16 Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes 20 " conductor set at 107 ft (note: crude oil at 100ft from I-10 LDL in 2013)18 Conductor string providedNA19 Surface casing protects all known USDWsYes using 2 stage cement … ES at 2500 ft20 CMT vol adequate to circulate on conductor & surf csgNo lateral will have slotted liner21 CMT vol adequate to tie-in long string to surf csgYes22 CMT will cover all known productive horizonsYes BTC calculations are provided. Meet industry standards23 Casing designs adequate for C, T, B & permafrostYes Rig has steel tanks. All waste to be transported to approved disposal well.24 Adequate tankage or reserve pitNA25 If a re-drill, has a 10-403 for abandonment been approvedYes J-01A close crossing but will be P & A before drilling I-2026 Adequate wellbore separation proposedYes 16" diverter …. Map of layout is provided.27 If diverter required, does it meet regulationsYes Max form. Pressure = 1764 psi (8.5 ppg EMW ) will drill with 8.9- 9.5 ppg mud … MPD also used.28 Drilling fluid program schematic & equip list adequateYes Inno rig has 13 5/8" BOPE29 BOPEs, do they meet regulationYes MASP= 1400 psi Will test BOPE to 3000 psi30 BOPE press rating appropriate; test to (put psig in comments)Yes31 Choke manifold complies w/API RP-53 (May 84)Yes32 Work will occur without operation shutdownNo not expected to see H2S but rig has H2S sensors and alarms33 Is presence of H2S gas probableNA34 Mechanical condition of wells within AOR verified (For service well only)Yes H2S not anticipated from drilling of offset wells; however, rig has H2S sensors and alarms.35 Permit can be issued w/o hydrogen sulfide measuresYes Per Skip Coyner, BP on 7/22/04: No H2S known in Schrader Bluff reservoirs at I- or J-Pads.36 Data presented on potential overpressure zonesNA37 Seismic analysis of shallow gas zonesNA38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprDLBDate6/2/2020ApprGLSDate6/11/2020ApprDLBDate6/2/2020AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDate47lb/ft casing used in first 2000 ft. J-01A will be P &A d per sundry 320-080 before I -20 is drilled. Gls