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Home My WebLink About220-030MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Thursday, July 25, 2024 SUBJECT:Mechanical Integrity Tests TO: FROM:Josh Hunt P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL Hilcorp Alaska, LLC M-44 MILNE PT UNIT M-44 Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 07/25/2024 M-44 50-029-23673-00-00 220-030-0 W SPT 3791 2200300 1500 691 691 690 691 4YRTST P Josh Hunt 6/25/2024 This well is also a Monobore completion and has no OA. 30 MinPretestInitial15 Min Well Name Type Test Notes: Interval P/F Well Permit Number: Type Inj TVD PTD Test psi API Well Number Inspector Name:MILNE PT UNIT M-44 Inspection Date: Tubing OA Packer Depth 86 1764 1685 1663IA 45 Min 60 Min Rel Insp Num: Insp Num:mitJDH240625134045 BBL Pumped:2.7 BBL Returned:2.5 Thursday, July 25, 2024 Page 1 of 1             Kaitlyn Barcelona Hilcorp North Slope, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: DATE: 11/30/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU M-44 (PTD 220-030) EV Camera 11/18/2021 Please include current contact information if different from above. Received By: 11/30/2021 37' (6HW By Abby Bell at 2:33 pm, Nov 30, 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.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception?Yes No 9.Property Designation (Lease Number):10.Field/Pool(s): 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 13,194'N/A Casing Collapse Conductor N/A Surface 3,090psi Liner 8,540psi Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13.Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14.Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16.Verbal Approval:Date:GAS WAG GSTOR SPLUG Commission Representative: GINJ Op Shutdown Abandoned Chad Helgeson Contact Name: Operations Manager Contact Email:dhaakinson@hilcorp.com Contact Phone: 777-8343 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 10/16/2021 3-1/2" Perforation Depth MD (ft): See Schematic MILNE PT UNIT M-44 C.O. 477.05 7" x 9-5/8" SLZP LTP & Tendeka Swell Pkr and N/A 5,747 MD/ 3,791 TVD & 5,945 MD/ 3,803 TVD and N/A 5,918' 13,194' See Schematic 114'20" x 34" 9-5/8" 4-1/2" 5,918' 7,447' 9.3 / L-80 / EUE 8rd TVD Burst 5,876' MD N/A 5,750psi 9,020psi 3,802' 3,573' 3,573'1,460 N/A MILNE POINT / SCHRADER BLUFF OIL 114'114' STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0025514 & ADL0388235 220-030 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 50-029-23673-00-00 Hilcorp Alaska LLC Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): Tubing Size: PRESENT WELL CONDITION SUMMARY Length Size 3,573' 13,194' David Haakinson COMMISSION USE ONLY Authorized Name: Authorized Signature: Authorized Title: 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. ory Statu Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Meredith Guhl at 10:48 am, Sep 30, 2021 321-515 Digitally signed by David Haakinson (3533) DN: cn=David Haakinson (3533), ou=Users Date: 2021.09.30 09:48:18 -08'00' David Haakinson (3533) DLB 09/30/2021 DSR-9/30/21 10-404 CT extnd. MGR06OCT2021 X dts 10/6/2021 JLC 10/7/2021 Jeremy Price Digitally signed by Jeremy Price Date: 2021.10.07 09:20:43 -08'00' RBDMS HEW 10/7/2021 CT Perforate Well: MPU M-44 Date: 9/29/2021 Well Name:MPU M-44 API Number:50-029-23673-00-00 Current Status:Injector - Online Pad:M-Pad Estimated Start Date:October 16th, 2021 Rig:CT Reg. Approval Req’d?Yes Date Reg. Approval Rec’vd: Regulatory Contact:Darci Horner Permit to Drill Number:220-030 First Call Engineer:David Haakinson (907) 777-8343 (O) (307) 660-4999 (M) Second Call Engineer:David Gorm (907) 777-8333 (O) AFE Number:Job Type:Perforate Current Bottom Hole Pressure: 1,830 psi @ 3,700’ TVD Downhole Gauge |9.5 PPGE MPSP:1,460 psi @ 3,700’ TVD (0.1psi/ft gas gradient) Max Deviation:93° @ Various Lateral Depths Max Dogleg:5.7°/100ft @ 4,225’ MD Min ID:2.75” ID @ 4,974’ MD XN Nipple Brief Well Summary: M-44 is a Schrader NB injector drilled in May 2020 to support M-43 and M-45 producers. The injector is performing poorly with a normalized injectivity index at roughly 70% of the offset Schrader NB sand injectors. Objective: x Rig up coiled tubing and TCP to perforate solid liner to reduce skin factor and continue to test methodology of increasing injection in wells completed with ICDs. Thus far, Hilcorp has seen 60-90% increases in injectivity post perforating in the Schrader OA sand. o Targeting a 200- 300 BWPD injection increase to result in ~200 BOPD increase between M-43 and M-45. x Plan is to use Ballistic Time-Delay Fuse (BTDF) to initiate an on-time delay system to perforate eight intervals on a single CT run by moving the gunstring between the shots. This will require open-hole deployment of perf guns. Notes Regarding the Well & Design x IA was last pressure tested to 1,600 psi for 30 mins on 6/13/2020 x No well-work has been completed on the well post drilling. x Well is to be shut-in 7-days prior to CT work to confirm kill weight fluid order. Coil Tubing Perforating Procedure 1. MIRU Coiled Tubing Unit with 1.75” coiled tubing and spot ancillary equipment. 2. Pressure test BOPE to 3,500 psi Hi 250 Low, 10 min each test. a. Each subsequent test of the lubricator will be to 3,500 psi Hi 250 Low to confirm no leaks. b. No AOGCC notification required. c. Record BOPE test results on 10-424 form. d. If within the standard 7-day test BOPE test period for Milne Point, a full body test and function test of the rams is sufficient to meet weekly BOPE test requirement. 3. Document shut in tubing pressure. Bleed gas head off to tanks. 4. MU GR/CCL and drift assembly w/ circulating sub and 20’ of 2.3” OD spent perf guns. CT Perforate Well: MPU M-44 Date: 9/29/2021 5. Perform TIW valve stab drill with CT crew. 6. RIH to ~50’ past ICD #9 to 11,450’ MD or lockup depth. a. Pump safe-lube while RIH. b. Lock-up Depth modeled to be ~11,500’ MD with 1.75” coiled tubing. 7. Flag pipe for correlation. 8. Contact Engineer to review depth and planned perforation depths. 9. POOH to lateral KOP @ 5,950’ MD and confirm well is dead. Bleed any gas head pressure to return tank and document pressures for 15 minutes. 10. Circulate in kill weight fluid. Contact Engineer to confirm calculations for KWF. a. Current estimates are that the well can be killed with source water. 11. At surface, prepare for deployment of TCP guns. 12. Confirm well is dead. Bleed any pressure off to return tank. Kill well as needed. Maintain continuous hole fill taking returns to tank until lubricator connection is reestablished. 13. Monitor tankage and document with trip sheet. 14. Pickup safety joint and TIW valve and space out before MU guns. 15. Begin makeup of TCP guns and deployment bars per the outlined BHA below. Review well control steps with crew prior to breaking lubricator connection and commencing makeup of TCP gun string. Once the safety joint and TIW valve have been spaced out, keep the safety joint/TIW valve readily accessible near the working platform for quick deployment if necessary. a.Note: Gun lengths need to be verified and confirmed post drift and tie-in run with remaining BHA components. Contact Engineer to review BHA components. b. Guns are 6 SPF, 60-degree phasing. Equipment Length (ft) Top Depth (MD) Bottom Depth (MD) Top Depth (TVD) Bottom Depth (TVD) Sand Firing Head 3.65 Spacer 7 Perf Gun 10 10850 10860 3,801 3,801 Schrader NB Sand Deployment Bar 6.5 Deployment Bar 6.5 Perf Gun 10 10000 10010 3,793 3,793 Schrader NB Sand Deployment Bar 6.5 Deployment Bar 6.5 Perf Gun 10 9240 9250 3,789 3,789 Schrader NB Sand Deployment Bar 6.5 Perf Gun 10 8800 8810 3,781 3,781 Schrader NB Sand Deployment Bar 6.5 Deployment Bar 6.5 Perf Gun 10 8100 8110 3,756 3,756 Schrader NB Sand Deployment Bar 6.5 Perf Gun 10 7630 7640 3,741 3,741 Schrader NB Sand Deployment Bar 6.5 Deployment Bar 6.5 Perf Gun 10 6900 6910 3,712 3,712 Schrader NB Sand Deployment Bar 6.5 Deployment Bar 6.5 Perf Gun 10 6050 6060 3,681 3,681 Schrader NB Sand Total Length 168.65 850' Pick Up. Est. 11 min travel time 440' Pick Up. Estimate 6 min travel time. 470' Pick Up. Estimate 6 min travel time. 760' Pick Up. Estimate 10 minutes travel time. 850' Pick Up. Estimate 11 minutes travel time. 700' Pick Up. Estimate 9 minutes travel time. 730' Pick Up. Estimate 10 minutes travel time. CT Perforate Well: MPU M-44 Date: 9/29/2021 Note: Well temperature is estimated at 70 deg F. Delay fuses are temperature dependent and nominal burn time is estimated at 7.84 minutes per delay fuse at this temperature. Minimum time before picking up BHA above 6,050’ MD is after activating firing head is 7.84 minutes times the amount of deployment fuses in hole to ensure completion of maximum burn time of all delay fuses in the string. 16. Tie into flagged CT depth. Space out for bottom shot. 17. Once on depth. Confirm plan of operations and firing sequence with coil crew. 18. Pre-plan stop depths to account for space out of guns in BHA. Send to Engineer prior to dropping 1/2” activation ball. 19. Launch ½” ball to activate firing head. a.Note: Once ½” ball is launched and firing head is activated, there is no ability to stop the delay fuses from continuing. Indication of first zone will occur when shift of firing head is observed. b. A portable shot detection system needs to be used to detect gun activation. 20. Continue to observe weight indicator and pressure for other signs of gun activation. 21. Begin working up-hole for additional perforation depths. 22.If no indication is observed for a zone; stop and do not pick up past top perf depth of 6,050’ MD until full duration of delay period has elapsed from time of firing head activation. 23. POOH to KOP @ 5,950’ MD and stop to confirm that the well is dead. If any pressure builds, contact engineer and prepare to circulate KWF. 24. Continue to POOH and stop at surface to reconfirm well dead and hole full. 25. Complete No Flow Test for 15 minutes prior to pulling BHA through BOP stack. 26. Review well control steps with crew prior to breaking lubricator connection and commencing breakdown of TCP gun string. 27. Lay-down spent TCP guns and deployment bar sections. 28. RDMO CTU. 29. Do not freeze protect well. Bring well on injection. Attachments: 1. Current schematic 2. Proposed schematic 3. Coiled Tubing BOP Schematic 4. Equipment Layout Diagram 5. Standing Orders for Open Hole Well Control during Perf Gun Deployment Stab coil tubing injector w/ CT packoff. RIH. _____________________________________________________________________________________ Revised By: TDF 9/29/2021 SCHEMATIC Milne Point Unit Well: MPU M-44 PTD: 220-030 API: 50-029-23673-00-00 TD =13,194’ (MD) / TD =3,573’ (TVD) 20” Orig. KB Elev.: 59.3’/ GL Elev.: 25.1’ 3-1/2”2 9-5/8” 1 3/4 6 See Screen & Swell Packer Detail PBTD =13,194’ (MD) / PBTD =3,573’(TVD) 9-5/8” ‘ES’ Cementer @ 2,464’ MD 4-1/2” 5 CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF 20"x 34” Conductor (Insulated) 215.5 / X-52 / Weld N/A Surface 114’ N/A 9-5/8" Surface 40 / L-80 / TXP 8.679” Surface 5,918’ 0.0758 4-1/2” Liner 13.5 / L-80 / Hyd 625 3.795” 5,747’ 13,194’ 0.0149 TUBING DETAIL 3-1/2" Tubing 9.3 / L-80 / EUE 8RD 2.867” Surf 5,876’ 0.0870 JEWELRY DETAIL No Top MD Item ID Upper Completion 1 4,922’ 3-1/2” Gauge Mandrel w/ ¼” Wire 2.992” 2 4,974’ XN Landing Nipple w/ 2.813” Packing Bore 2.813” 3 5,747’ 8.25” No Go Locater Sub (1.80’ off No-go) 6.170” 4 5,757’ Bullet Seals – Mule Shoe Ports 1.86’ up from mule shoe 6.170” Lower Completion 5 5,747’ 7” x 9-5/8” SLZXP Liner Top Packer with 7.38” Seal Bore 6.180” 6 14,070’ Shoe 3.970” OPEN HOLE / CEMENT DETAIL 42" ±270 ft3 12-1/4"Stg 1 –Lead 460 sx / Tail 400 sx Stg 2 –Lead 877 sx / Tail 270 sx - 279 bbls returned to surface 8-1/2” Cementless Injection Liner in 8-1/2” hole WELL INCLINATION DETAIL KOP @ 234’ Hole Angle @ XN = 68° Hole Angle @ Liner Top = 84° Max Hole Angle = 96° TREE & WELLHEAD Tree Cameron 3 1/8" 5M w/ 3-1/8” 5M Cameron Wing Wellhead Cameron 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs Depth MD Depth TVD ICD/Swell Packer Detail 5,945’ 3,802’ Tendeka Water Swell Packer 6,001’ 3,802’ Screen, 250 micron, RGL pro-mesh, 4-1/2", 13.5#, L-80, Hydril 625 6,710’ 3,794’ Screen, 250 micron, RGL pro-mesh, 4-1/2", 13.5#, L-80, Hydril 625 7,296’ 3,797’ Screen, 250 micron, RGL pro-mesh, 4-1/2", 13.5#, L-80, Hydril 625 7,957’ 3,784’ Screen, 250 micron, RGL pro-mesh, 4-1/2", 13.5#, L-80, Hydril 625 8,615’ 3,759’ Screen, 250 micron, RGL pro-mesh, 4-1/2", 13.5#, L-80, Hydril 625 9,272’ 3,739’ Screen, 250 micron, RGL pro-mesh, 4-1/2", 13.5#, L-80, Hydril 625 10,020’ 3,710’ Screen, 250 micron, RGL pro-mesh, 4-1/2", 13.5#, L-80, Hydril 625 10,686’ 3,687’ Screen, 250 micron, RGL pro-mesh, 4-1/2", 13.5#, L-80, Hydril 625 11,384’ 3,660’ Screen, 250 micron, RGL pro-mesh, 4-1/2", 13.5#, L-80, Hydril 625 12,330’ 3,607’ Screen, 250 micron, RGL pro-mesh, 4-1/2", 13.5#, L-80, Hydril 625 13,026’ 3,577’ Screen, 250 micron, RGL pro-mesh, 4-1/2", 13.5#, L-80, Hydril 625 GENERAL WELL INFO API#: 50-029-23673-00-00 Completed by Doyon 14: 5/17/2020 _____________________________________________________________________________________ Revised By: TDF 9/29/2021 PROPOSED Milne Point Unit Well: MPU M-44 PTD: 220-030 API: 50-029-23673-00-00 TD = 13,194’(MD) / TD =3,573’(TVD) 20” Orig. KB Elev.: 59.3’/ GL Elev.: 25.1’ 3-1/2”2 9-5/8” 1 3/4 7 See Screen & Swell Packer Detail PBTD =13,194’ (MD) / PBTD =3,573’(TVD) 9-5/8” ‘ES’ Cementer @ 2,464’ MD 4-1/2” 5 6 CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF 20"x 34” Conductor (Insulated) 215.5 / X-52 / Weld N/A Surface 114’ N/A 9-5/8" Surface 40 / L-80 / TXP 8.679” Surface 5,918’ 0.0758 4-1/2” Liner 13.5 / L-80 / Hyd 625 3.795” 5,747’ 13,194’ 0.0149 TUBING DETAIL 3-1/2" Tubing 9.3 / L-80 / EUE 8RD 2.867” Surf 5,876’ 0.0870 JEWELRY DETAIL No Top MD Item ID Upper Completion 1 4,922’ 3-1/2” Gauge Mandrel w/ ¼” Wire 2.992” 2 4,974’ XN Landing Nipple w/ 2.813” Packing Bore 2.813” 3 5,747’ 8.25” No Go Locater Sub (1.80’ off No-go) 6.170” 4 5,757’ Bullet Seals – Mule Shoe Ports 1.86’ up from mule shoe 6.170” Lower Completion 5 5,747’ 7” x 9-5/8” SLZXP Liner Top Packer with 7.38” Seal Bore 6.180” 6 5,945’ Tendeka Water Swell Packer 7 14,070’ Shoe 3.970” OPEN HOLE / CEMENT DETAIL 42" ±270 ft3 12-1/4"Stg 1 –Lead 460 sx / Tail 400 sx Stg 2 –Lead 877 sx / Tail 270 sx - 279 bbls returned to surface 8-1/2” Cementless Injection Liner in 8-1/2” hole WELL INCLINATION DETAIL KOP @ 234’ Hole Angle @ XN = 68° Hole Angle @ Liner Top = 84° Max Hole Angle = 96° TREE & WELLHEAD Tree Cameron 3 1/8" 5M w/ 3-1/8” 5M Cameron Wing Wellhead Cameron 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs Depth MD Depth TVD ICD/Swell Packer Detail 6,001’ 3,802’ Screen, 250 micron, RGL pro-mesh, 4-1/2", 13.5#, L-80, Hydril 625 6,710’ 3,794’ Screen, 250 micron, RGL pro-mesh, 4-1/2", 13.5#, L-80, Hydril 625 7,296’ 3,797’ Screen, 250 micron, RGL pro-mesh, 4-1/2", 13.5#, L-80, Hydril 625 7,957’ 3,784’ Screen, 250 micron, RGL pro-mesh, 4-1/2", 13.5#, L-80, Hydril 625 8,615’ 3,759’ Screen, 250 micron, RGL pro-mesh, 4-1/2", 13.5#, L-80, Hydril 625 9,272’ 3,739’ Screen, 250 micron, RGL pro-mesh, 4-1/2", 13.5#, L-80, Hydril 625 10,020’ 3,710’ Screen, 250 micron, RGL pro-mesh, 4-1/2", 13.5#, L-80, Hydril 625 10,686’ 3,687’ Screen, 250 micron, RGL pro-mesh, 4-1/2", 13.5#, L-80, Hydril 625 11,384’ 3,660’ Screen, 250 micron, RGL pro-mesh, 4-1/2", 13.5#, L-80, Hydril 625 12,330’ 3,607’ Screen, 250 micron, RGL pro-mesh, 4-1/2", 13.5#, L-80, Hydril 625 13,026’ 3,577’ Screen, 250 micron, RGL pro-mesh, 4-1/2", 13.5#, L-80, Hydril 625 GENERAL WELL INFO API#: 50-029-23673-00-00 Completed by Doyon 14: 5/17/2020 PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status Schrader OA Sands ±6,050’ ±6,060’ ±3,801’ ±3,801’ ±10 Future Pending ±6,900’ ±6,910’ ±3,793’ ±3,794’ ±10 Future Pending ±7,630’ ±7,640’ ±3,789’ ±3,789’ ±10 Future Pending ±8,100’ ±8,110’ ±3,781’ ±3,781’ ±10 Future Pending ±8,800’ ±8,810’ ±3,756’ ±3,756’ ±10 Future Pending ±9,240’ ±9,250’ ±3,741’ ±3,740’ ±10 Future Pending ±10,000’ ±10,010’ ±3,712’ ±3,712’ ±10 Future Pending ±10,850’ ±10,860 ±3,681’ ±3,680’ ±10 Future Pending CT Perforate Well: MPU M-44 Date: 9/29/2021 CT Perforate Well: MPU M-44 Date: 9/29/2021 Equipment Layout Diagram CT Perforate Well: MPU M-44 Date: 9/29/2021 Standing Orders for Open Hole Well Control during Perf Gun Deployment Debra Oudean Hilcorp Alaska, LLC GeoTech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: doudean@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 Received By: Date: DATE 8/19/2020 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU M-44 (220-030) MPU M-44 Geosteering DGR/DGR PTD: 2200300 E-Set: 33673 Received by the AOGCC 08/19/2020 Abby Bell 08/19/2020 DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-23673-00-00Well Name/No. MILNE PT UNIT M-44Completion Status1WINJCompletion Date5/17/2020Permit to Drill2200300Operator Hilcorp Alaska, LLCMD13194TVD3573Current Status1WINJ7/22/2020UICYesWell Log Information:DigitalMed/FrmtReceivedStart StopOH /CHCommentsLogMediaRunNoElectr DatasetNumberNameIntervalList of Logs Obtained:ROP, DGR, AGR, ABG, ADR, EWR MD & TVD PB1NoNoYesMud Log Samples Directional SurveyREQUIRED INFORMATION(from Master Well Data/Logs)DATA INFORMATIONLog/DataTypeLogScaleDF7/20/2020112 13194 Electronic Data Set, Filename: MPU M-44 LWD Final.las33576EDDigital DataDF7/20/20205900 13156 Electronic Data Set, Filename: MPU M-44 ADR Quadrants All Curves.las33576EDDigital DataDF7/20/2020 Electronic File: MPU M-44 LWD Final MD.cgm33576EDDigital DataDF7/20/2020 Electronic File: MPU M-44 LWD Final TVD.cgm33576EDDigital DataDF7/20/2020 Electronic File: MPU M-44 Definitive Survey Report.pdf33576EDDigital DataDF7/20/2020 Electronic File: MPU M-44 Surveys.xlsx33576EDDigital DataDF7/20/2020 Electronic File: MPU M-44i_DSR.txt33576EDDigital DataDF7/20/2020 Electronic File: MPU M-44i_GIS.txt33576EDDigital DataDF7/20/2020 Electronic File: MPU M-44i_Plan.pdf33576EDDigital DataDF7/20/2020 Electronic File: MPU M-44i_VSec.pdf33576EDDigital DataDF7/20/2020 Electronic File: MPU M-44 LWD Final MD.emf33576EDDigital DataDF7/20/2020 Electronic File: MPU M-44 LWD Final TVD.emf33576EDDigital DataDF7/20/2020 Electronic File: MPU_M_44_Geosteering.dlis33576EDDigital DataDF7/20/2020 Electronic File: MPU_M_44_Geosteering.ver33576EDDigital DataDF7/20/2020 Electronic File: MPU M-44 LWD Final MD.pdf33576EDDigital DataDF7/20/2020 Electronic File: MPU M-44 LWD Final TVD.pdf33576EDDigital DataDF7/20/2020 Electronic File: MPU M-44 LWD Final MD.tif33576EDDigital DataDF7/20/2020 Electronic File: MPU M-44 LWD Final TVD.tif33576EDDigital Data0 0 2200300 MILNE PT UNIT M-44 LOG HEADERS33576LogLog Header ScansWednesday, July 22, 2020AOGCCPage 1 of 3MPU M-44 LWDFinal.las DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-23673-00-00Well Name/No. MILNE PT UNIT M-44Completion Status1WINJCompletion Date5/17/2020Permit to Drill2200300Operator Hilcorp Alaska, LLCMD13194TVD3573Current Status1WINJ7/22/2020UICYesWell Cores/Samples Information:ReceivedStart Stop CommentsSentSample SetNumberNameIntervalINFORMATION RECEIVED0 0 2200300 MILNE PT UNIT M-44 PB1 LOG HEADERS33577LogLog Header ScansDF7/20/2020112 10393 Electronic Data Set, Filename: MPU M-44 PB1 LWD Final.las33577EDDigital DataDF7/20/20205900 10354 Electronic Data Set, Filename: MPU M-44 PB1 ADR Quadrants All Curves.las33577EDDigital DataDF7/20/2020 Electronic File: MPU M-44 PB1 LWD Final MD.cgm33577EDDigital DataDF7/20/2020 Electronic File: MPU M-44 PB1 LWD Final TVD.cgm33577EDDigital DataDF7/20/2020 Electronic File: MPU M-44PB1 Definitive Survey Report.pdf33577EDDigital DataDF7/20/2020 Electronic File: MPU M-44PB1_DSR.txt33577EDDigital DataDF7/20/2020 Electronic File: MPU M-44PB1_GIS.txt33577EDDigital DataDF7/20/2020 Electronic File: MPU M-44 PB1 LWD Final MD.emf33577EDDigital DataDF7/20/2020 Electronic File: MPU M-44 PB1 LWD Final TVD.emf33577EDDigital DataDF7/20/2020 Electronic File: MPU_M_44 PB1_Geosteering.dlis33577EDDigital DataDF7/20/2020 Electronic File: MPU_M_44 PB1_Geosteering.ver33577EDDigital DataDF7/20/2020 Electronic File: MPU M-44 PB1 LWD Final MD.pdf33577EDDigital DataDF7/20/2020 Electronic File: MPU M-44 PB1 LWD Final TVD.pdf33577EDDigital DataDF7/20/2020 Electronic File: MPU M-44 PB1 LWD Final MD.tif33577EDDigital DataDF7/20/2020 Electronic File: MPU M-44 PB1 LWD Final 33577EDDigital DataWednesday, July 22, 2020AOGCCPage 2 of 3MPU M-44 PB1LWD Final.las DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-23673-00-00Well Name/No. MILNE PT UNIT M-44Completion Status1WINJCompletion Date5/17/2020Permit to Drill2200300Operator Hilcorp Alaska, LLCMD13194TVD3573Current Status1WINJ7/22/2020UICYesCompletion ReportProduction Test InformationGeologic Markers/TopsY Y / NAYComments:Compliance Reviewed By:Date:Mud Logs, Image Files, Digital DataComposite Logs, Image, Data Files Cuttings SamplesY / NAYY / NADirectional / Inclination DataMechanical Integrity Test InformationDaily Operations SummaryYY / NAYCore ChipsCore PhotographsLaboratory AnalysesY / NAY / NAY / NACOMPLIANCE HISTORYDate CommentsDescriptionCompletion Date: 5/17/2020Release Date:3/24/2020Wednesday, July 22, 2020AOGCCPage 3 of 3M. Guhl7/22/2020 Debra Oudean Hilcorp Alaska, LLC GeoTech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: doudean@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 Received By: Date: DATE 7/17/2020 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU M-44 (220-030) MPU M-44 & M-44 PB1 Received by the AOGCC 07/20/2020 PTD: 2200300 E-Set: 33577 Abby Bell 07/20/2020 Debra Oudean Hilcorp Alaska, LLC GeoTech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: doudean@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 Received By: Date: DATE 7/17/2020 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU M-44 (220-030) MPU M-44 & M-44 PB1 Received by the AOGCC 07/20/2020 PTD: 2200300 E-Set: 33576 Abby Bell 07/20/2020 MEMORANDUM TO: Jim Regg /J P.I. Supervisor FROM: Bob Noble Petroleum Inspector I Well Name MILNE PT UNIT M-44 IInsp Num: mitRCN200613132949 Rel Insp Num: NON -CONFIDENTIAL State of Alaska Alaska Oil and Gas Conservation Commission DATE: Monday, June 15, 2020 SUBJECT: Mechanical Integrity Tests Hilcorp Alaska, LLC M44 MILNE PT UNIT M44 Src: Inspector Reviewed By: ,, P.I. Supry 1l'�__ Comm API Well Number 50-029-23673-00-00 Inspector Name: Bob Noble Permit Number: 220-030-0 Inspection Date: 6/13/2020 . Packer Depth Well M44Type -[nj ' w +T� 3791 — a - PTD 220030o ' Type Test SPT Test psi 1'00 BBL Pumped: 2.8 BBL Returned: 2.8 Interval 1 INITAL P Notes: Pretest Initial 15 Min 30 Min 45 Min 60 Min Tubing leas 1244 1244 1243 ' jA 71 � - -' 1693 1626 1607 OA Monday, June 15, 2020 Page 1 of 1 1a. Well Status:Oil SPLUG Other Abandoned Suspended 1b. Well Class: 20AAC 25.105 20AAC 25.110 Development Exploratory GINJ WINJ WDSPL No. of Completions: _1 Service Stratigraphic Test 2. Operator Name: 6. Date Comp., Susp., or 14. Permit to Drill Number / Sundry: Aband.: 3. Address: 7. Date Spudded: 15. API Number: 4a. Location of Well (Governmental Section): 8. Date TD Reached: 16. Well Name and Number: Surface: Top of Productive Interval: 9. Ref Elevations: KB: 17. Field / Pool(s): GL:25.1' BF:25.1' Total Depth: 10. Plug Back Depth MD/TVD: 18. Property Designation: 4b. Location of Well (State Base Plane Coordinates, NAD 27): 11. Total Depth MD/TVD: 19. DNR Approval Number: Surface: x- y- Zone- 4 TPI: x- y- Zone- 4 12. SSSV Depth MD/TVD: 20. Thickness of Permafrost MD/TVD: Total Depth: x- y- Zone- 4 5. Directional or Inclination Survey: Yes (attached) No 13. Water Depth, if Offshore: 21. Re-drill/Lateral Top Window MD/TVD: Submit electronic information per 20 AAC 25.050 (ft MSL) 22. Logs Obtained: 23. BOTTOM 20" X-52 114' 4-1/2" L-80 3,573' 24. Open to production or injection? Yes No 25. 26. Was hydraulic fracturing used during completion? Yes No DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 27. Date First Production: Method of Operation (Flowing, gas lift, etc.): Hours Tested: Production for Gas-MCF: Test Period Casing Press: Calculated Gas-MCF: Oil Gravity - API (corr): Press. 24-Hour Rate ADL025514, ADL388235 LONS 16-004 2,254' MD / 1,900' TVD N/AN/A N/A 13,194' MD / 3,573' TVD Sr Res EngSr Pet GeoSr Pet Eng Oil-Bbl: Water-Bbl: Oil-Bbl: suspension, or abandonment, whichever occurs first. Types of logs to be listed include, but are not limited to: mud log, spontaneous potential, gamma ray, caliper, resistivity, porosity, magnetic resonance, dipmeter, formation tester, temperature, cement evaluation, casing collar locator, jewelry, and perforation record. Acronyms may be used. Attach a separate page if necessary N/A **Please see attached schematic for Screen(Injection Points) Detail** Liner run on 5/15/2020 ROP, DGR, AGR, ABG, ADR, EWR MD & TVD PB1 N/A Flow Tubing Gas-Oil Ratio:Choke Size:Water-Bbl: PRODUCTION TEST N/A Date of Test: Per 20 AAC 25.283 (i)(2) attach electronic information 13,194' 3,791' DEPTH SET (MD) 5,747' MD / 3,791' TVD PACKER SET (MD/TVD) CASING WT. PER FT.GRADE 13.5# 536757 536643 TOP SETTING DEPTH MD Surface 5,747' SETTING DEPTH TVD 6020377 BOTTOM TOP 279 bbls Surface114' HOLE SIZE AMOUNT PULLED 50-029-23673-00-00 MPU M-44 534143 6027889 648' FNL, 2590' FWL, Sec 13, T13N, R9E, UM, AK CEMENTING RECORD 6027497 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 5/17/2020 5036' FSL, 21' FEL, Sec 14, T13N, R9E, UM, AK 2488' FNL, 2439' FWL, Sec 24, T13N, R9E, UM, AK 220-030 Milne Point Field / Schrader Bluff Oil Pool 59.3' 13,194' MD / 3,573' TVD May 12, 2020 April 29, 2020 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG Hilcorp Alaska, LLC WAG Gas 42" Stg 1 L - 460 sx / T - 400 sx ±270 ft3215.5# Stg 2 L - 877 sx / T - 270 sx 12-1/4" Cementless Injection Liner w/ 250 micron screens 3-1/2" Tieback Tubing SIZEIf Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number; Date Perfd): ACID, FRACTURE, CEMENT SQUEEZE, ETC. CASING, LINER AND CEMENTING RECORD List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data within 90 days of completion, 8-1/2" TUBING RECORD 3,802' Liner Top Packer 5,757' 9-5/8" 40# L-80 Surface 5,918' Surface WINJ SPLUG Other Abandoned Suspended Stratigraphic Test No No (attached) No Form 10-407 Revised 3/2020 Submit within 30 days of Completion, Suspension, or Abandonment By Samantha Carlisle at 9:16 am, Jun 03, 2020 Completion Date 5/17/2020 HEW RBDMS HEW 6/3/2020 DSR-6/3/2020DLB 06/04/2020 gls 6/9/20 ServiceWINJ G Conventional Core(s): Yes No Sidewall Cores: 30. MD TVD 2,254' 1,900' Top of Productive Interval SB NB 6,001' 3,802' 1,470' 1,347' 2,311' 1,939' 4,240' 3,265' 5,563' 3,768' 5,850' 3,799' SB NB 31. List of Attachments: 32. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Name: Cody Dinger Contact Email:cdinger@hilcorp.com Authorized Contact Phone: 777-8389 General: Item 1a: Item 1b: Item 4b: Item 9: Item 15: Item 19: Item 20: Item 22: Item 23: Item 24: Item 27: Item 28: Item 30: Item 31: Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and other tests as required including, but not limited to: core analysis, paleontological report, production or well test results. Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29. Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity, permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology. The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data within 90 days of completion, suspension, or abandonment, whichever occurs first. Well Class - Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Formation at total depth: SB NA Wellbore Schematic, Drilling and Completion Reports, Definitive Directional Surveys, Csg and Cmt Report, OH ST Summary, FIT. Signature w/Date: Report the Division of Oil & Gas / Division of Mining Land and Water: Plan of Operations (LO/Region YY-123), Land Use Permit (LAS 12345), and/or Easement (ADL 123456) number. INSTRUCTIONS Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. TPI (Top of Producing Interval). Yes No Well tested? Yes No 28. CORE DATA If yes, list intervals and formations tested, briefly summarizing test results. Attach separate pages to this form, if needed, and submit detailed test information, including reports, per 20 AAC 25.071. NAME SB NB SV1 Ugnu LA3 SV5 This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed. All laboratory analytical reports regarding samples or tests from a well must be submitted to the AOGCC, no matter when the analyses are conducted. Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inc lination survey, core analysis, paleontological report, production or well test results, per 20 AAC 25.070. If Yes, list formations and intervals cored (MD/TVD, From/To), and summarize lithology and presence of oil, gas or water (submit separate pages with this form, if needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071. Authorized Name: Monty Myers Authorized Title: Drilling Manager Permafrost - Base 29. GEOLOGIC MARKERS (List all formations and markers encountered): FORMATION TESTS Permafrost - Top No NoSidewall Cores: Yes No Form 10-407 Revised 3/2020 Submit within 30 days of Completion, Suspension, or Abandonment 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: 2020.06.02 16:29:49 -08'00' Monty M Myers _____________________________________________________________________________________ Revised By: CJD 6/2/20 Schematic Milne Point Unit Well: MPU M-44 PTD: 220-030 API: 50-029-23673-00-00 Depth MD Depth TVD ICD/Swell Packer Detail See Page 2 CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF 20"x 34” Conductor (Insulated) 215.5 / X-52 / Weld N/A Surface 114’ N/A 9-5/8" Surface 40 / L-80 / TXP 8.679” Surface 5,918’ 0.0758 4-1/2” Liner 13.5 / L-80 / Hyd 625 3.795” 5,747’ 13,194’ 0.0149 TUBING DETAIL 3-1/2" Tubing 9.3 / L-80 / EUE 8RD 2.867” Surf 5,876’ 0.0870 JEWELRY DETAIL No Top MD Item ID Upper Completion 1 4,922’ 3-1/2” Gauge Mandrel w/ ¼” Wire 2.992” 2 4,974’ XN Landing Nipple w/ 2.813” Packing Bore 2.813” 3 5,747’ 8.25” No Go Locater Sub (1.80’ off No-go) 6.170” 4 5,757’ Bullet Seals – Mule Shoe Ports 1.86’ up from mule shoe 6.170” Lower Completion 5 5,747’ 7” x 9-5/8” SLZXP Liner Top Packer with 7.38” Seal Bore 6.180” 6 14,070’ Shoe 3.970” OPEN HOLE / CEMENT DETAIL 42" ±270 ft3 12-1/4" Stg 1 –Lead 460 sx / Tail 400 sx Stg 2 –Lead 877 sx / Tail 270 sx - 279 bbls returned to surface 8-1/2” Cementless Injection Liner in 8-1/2” hole WELL INCLINATION DETAIL KOP @ 234’ Hole Angle @ XN = 68° Hole Angle @ Liner Top = 84° Max Hole Angle = 96° TREE & WELLHEAD Tree Cameron 3 1/8" 5M w/ 3-1/8” 5M Cameron Wing Wellhead Cameron 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs GENERAL WELL INFO API#: 50-029-23673-00-00 Completed by Doyon 14: 5/17/2020 ICD and Swell packers Water Injector Depth MD Depth TVD ICD/Swell Packer Detail 5,945’ 3,802’ Tendeka Water Swell Packer 6,001’ 3,802’ Screen, 250 micron, RGL pro-mesh, 4-1/2", 13.5#, L-80, Hydril 625 6,710’ 3,794’ Screen, 250 micron, RGL pro-mesh, 4-1/2", 13.5#, L-80, Hydril 625 7,296’ 3,797’ Screen, 250 micron, RGL pro-mesh, 4-1/2", 13.5#, L-80, Hydril 625 7,957’ 3,784’ Screen, 250 micron, RGL pro-mesh, 4-1/2", 13.5#, L-80, Hydril 625 8,615’ 3,759’ Screen, 250 micron, RGL pro-mesh, 4-1/2", 13.5#, L-80, Hydril 625 9,272’ 3,739’ Screen, 250 micron, RGL pro-mesh, 4-1/2", 13.5#, L-80, Hydril 625 10,020’ 3,710’ Screen, 250 micron, RGL pro-mesh, 4-1/2", 13.5#, L-80, Hydril 625 10,686’ 3,687’ Screen, 250 micron, RGL pro-mesh, 4-1/2", 13.5#, L-80, Hydril 625 11,384’ 3,660’ Screen, 250 micron, RGL pro-mesh, 4-1/2", 13.5#, L-80, Hydril 625 12,330’ 3,607’ Screen, 250 micron, RGL pro-mesh, 4-1/2", 13.5#, L-80, Hydril 625 13,026’ 3,577’ Screen, 250 micron, RGL pro-mesh, 4-1/2", 13.5#, L-80, Hydril 625 Activity Date Ops Summary 4/28/2020 See MPU M-43 for previous activities;Jack up rig and move off M-43, Spot MPD shack and surface stack behind Well. Align rig to back over M-44. Shuffle rig mats into position. Inspect underside of rig support beams and arctic dump lines.;Move over M-44 and spot Rig. Skid rig floor into drilling position. Set surface Annular preventer on diverter Tee and nipple up same. SimOps: Spot service company buildings, transfer pump house and H²O tank. Install landings and secure entry & walk ways around rig. 4/29/2020 Work on rig acceptance checklist. Finish spot out buildings and power up same. Spot fuel trailer and rock washer. Work on N/U Diverter line. Put BHA in pipe shed & start testing, Load HWDP, Jars and NMFDC. Remove saver sub and upper IBOP;Cont. work on rig acceptance checklist. Finish N/U diverter line. Install new saver sub and upper IBOP. Perform Derrick inspection. Weld pit level indicator guide in pit #4. Well Head Rep test speed head seal, 600 psi for 10 min Install riser.;Power up Koomy. M/U stand of 5" HWDP and function test surface bag/knife valve. M/U and rack in Derrick 2 more stands 5" HWDP Rig on High Line power @ 15:30 Rig Accepted at 20:00.;Perform diverter function test with AOGCC rep Adam Earl to witness. Good test. Knife valve open in 16sec. Annular Closed in 36sec. Accumulator draw down- 2890 Starting pressure 2100 after shut in, 37 sec 200 psi Increase 135 sec full pressure. N2- 6 btls at 2166 psi average.;Continue build and rack back remaining 3 stands 5” HWDP and Jars.;Cut and slip 53' drilling line. Service Topdrive, Drawworks and Iron roughneck.;P/U BHA, Bit motor & one stand of HWDP. RIH and tag up at 90’. Pre spud meeting. Flood stack. Test lines to TopDrive IBOP. Good.;Spud well, clean out conductor t/ 114’ and drill to 124’ with H2O, displace to spud mud while drilling remaining Kelly down t/ 130’. Drill to 223', 430 GPM – 580 psi, 45 RPM – 2k Tq. Back ream out of hole one stand, pull next stand on elevators.;PJSM, M/U DM collar and scribe RFO from motor. Continue making up MWD tools and scribe to UBHO. Adjust UBHO to motor as per DD.;Plug in, Initialize and upload MWD tools. SimOps: R/U Scientific Gyro with Pollard E-Line;Daily losses = 0 bbls, cumulative losses = 0 bbls. Hauled 480 bbls H2O from L-Pad for total = 480 bbls 4/30/2020 Finish upload MWD and rig up Gyro, RIH with 3-NMFDCs, XO to 176.80', M/U Stand of HWDP and wash/ream down t/ 223’.;Drill 12-1/4" surface hole f/ 223' t/ 838', (826’ TVD) 615' drilled, 123’/hr AROP. 550 GPM, 1480 PSI, 60 RPM, 3K TQ, 10K WOB MW 9+ in / 9.1 out, vis 200 in / 300 out, 9.8 ECD. 80K PU / 85K SO / 80K ROT Kick off @ 268', build 3°/100', 4°/100 @ 550.;Gyro released at 517’. No magnetic interference was encountered in top hole section.;Drill 12-1/4" surface hole f/ 838' t/ 1585’, (1429’ TVD) 747’ drilled, 124’/hr AROP. 550 GPM, 1580 PSI, 60 RPM, 7K TQ, 5-15K WOB MW 9.1 in / 9.2 out, vis 153 in / 270 out, 10.3 ECD. 94K PU / 86K SO / 90K ROT Max Gas - 40u Continue 4° BUR t/ 1567’ where 48° inc tangent started.;Drill 12- 1/4" surface hole f/ 1585' t/ 1790’, (1547’ TVD) 205’ drilled, 68’/hr AROP. 560 GPM, 1610 PSI, 60 RPM, 6K TQ, 5-15K WOB MW 9.1 in / 9.3 out, vis 163 in / 300 out, 10.7 ECD. 103K PU / 85K SO / 92K ROT Max Gas - 46u Hold 48° Tangent.;Trouble shoot Mud Pump loss of suction and pressure. Pressure up against IBOP, holds pressure. Isolate individual pumps and attempt to establish circulation. Determine #1 Mud Pump has a washed valve.;Drill 12-1/4" surface hole f/ 1790' t/ 2010’, (1727’ TVD) 220’ drilled, 88’/hr AROP. 560 GPM, 1730 PSI, 60 RPM, 7K TQ, 5-15K WOB MW 9.3 in / 9.4 out, vis 141 in / 263 out, 10.4 ECD. 107K PU / 86K SO / 95K ROT Max Gas - 82u. Hold 48° Tangent.;C/O valves and seats in #1 MP. Drill with 1 pump @ 400 GPM, 840 psi . Both pumps online at 22:00.;Drill 12-1/4" surface hole f/ 2010' t/ 2897’, (2329’ TVD) 887’ drilled, 147.83’/hr AROP. 530 GPM, 1795 PSI, 60 RPM, 8K TQ, 15-17K WOB MW 9.3 in / 9.3 out, vis 92 in / 90 out, 10.97 ECD. 124K PU / 95K SO / 106K ROT Max Gas - 99u Hold 48° Tangent t/ 2830’, start build/turn at 4°/100’.;Base of Permafrost logged at 2254’ MD / 1900’ TVD. Last survey at 2796.44' MD / 2260.46' TVD, 47.70° inc, 47.29° azm, 20.25' from plan, 0.41' high and 20.25' right.;Daily losses = 0 bbls, cumulative losses = 0 bbls. Hauled 1510 bbls H2O from L-Pad for total = 1990 bbls Hauled 1440 bbls to MPU G&I cuttings/mud/cement for total = 1440 bbls 5/1/2020 Drill 12-1/4" surface hole f/ 2897' t/ 3692’, (2891’ TVD) 795’ drilled, 132.5’/hr AROP. 550 GPM, 2030 PSI, 60 RPM, 9K TQ, 13K WOB. MW 9.2 in / 9.2 out, vis 107 in / 145 out, 10.1 ECD. 143K PU / 103K SO / 123K ROT Max Gas - 48u. Continue target 4° DL for directional turn/build.;Drill 12-1/4" surface hole f/ 3692' t/ 4415’, (3373’ TVD) 723' drilled, 120.5’/hr AROP. 560GPM, 1960 PSI, 60 RPM, 12K TQ, 5-15K WOB MW 9.2 in / 9.2 out, vis 113 in / 174 out, 10.00 ECD. 166K PU / 102K SO / 125K ROT Max Gas - 99u.;Continue target 4° DL for directional turn/build. Start Pretreat system w/ 0.5% screenkleen @ 4000'. Pumped hi-vis sweep at 4043’. Back 200 stks late w/ 20% increase.;Drill 12-1/4" surface hole f/ 4415' t/ 5052’, (3658’ TVD) 637' drilled, 106.17’/hr AROP. 560GPM, 2140 PSI, 60 RPM, 14K TQ, 5-15K WOB. MW 9.3 in / 9.3 out, vis 93 in / 109 out, 10.20 ECD. 175K PU / 100K SO / 130K ROT Max Gas - 247u.;Continue target 4° DL for directional turn/build. Pumped hi-vis sweep at 5070’. Return was not identified at surface.;Drill 12- 1/4" surface hole f/ 5052' t/ 5596’, (3770’ TVD) 544’ drilled, 90.66’/hr AROP. 550 GPM, 2250 PSI, 60 RPM, 13K TQ, 15K WOB, MW 9.4+ in / 9.4+ out, vis 105 in / 195 out, 10.51 ECD. 175K PU / 90K SO / 120K ROT Max Gas - 125u,;Survey at 5271’ B total magnetic interference out of spec slightly. Survey at 5366’ shows interference little more out of spec. Discuss with survey management and well planner prior to drilling ahead. Closest well (M-11) @ 116’ CC at 159° HS TF. Survey at 5557' was clean of interference.;Top of Ugnu_MF @ 5096’ MD, 3672’ TVD. Last survey at 5557.08' MD / 3766.71' TVD, 81.85° inc, 167.57° azm, 7.70' from plan, 0.87' high and 7.65' left.;Daily losses = 0 bbls, cumulative losses = 0 bbls. Hauled 1260 bbls H2O from L-Pad for total = 3250 bbls Hauled 1901 bbls to MPU G&I cuttings/mud/cement for total = 3341 bbls n (LAT/LONG): evation (RKB): API #: Well Name: Field: County/State: MP M-44 Milne Point Hilcorp Energy Company Composite Report , Alaska Contractor AFE #: AFE $: 2010895D Job Name:2010895D MPU M-44 Drilling Spud Date: Initialize and upload MWD tools. ;Drill 12-1/4" surface hole f/ yg :30 Rig Accepted at 20:00.;Perform diverter function test with AOGCC rep Adam Earl to witness. Good pgpy 223' t/ 838', (826’ TVD) 615' drilled, Spud well 5/2/2020 Drill 12-1/4" surface hole f/ 5597' t/ 5920’ (3802’ TVD) 323' drilled, 71.78’/hr AROP. TD of surface hole section in SB_NB Sand. 550GPM, 2230 PSI, 60 RPM, 14K TQ, 15-20K WOB. MW 9.3 in / 9.4 out, vis 70 in / 220 out, 10.6 ECD. 176K PU / 86K SO / 120K ROT Max Gas - 215u.;Obtain final survey. Pump 30 bbl hi-vis sweep w/ nut plug marker Sweep back 600 stks late w/ 20% increase. BROOH f/ 5920’ t/ 5630’ while circ and cond. 550 GPM -1910 psi, 60 RPM – 13k Tq. Last survey at 5879.80' MD / 3801.16' TVD, 87.05° inc, 168.10° azm, 13.99' from plan, 13.38' low and 4.08' left.;Finished mud treatment with YP at 23. Perform 5 min. flow check - static. TIH t/ 5884’ on elevators then wash last single down to bottom at 5920’ 550 GPM, 1800 psi.;BROOH f/ 5920' t/ 3885' at 5-10 min stand, slow as needed to avoid any packing off issues, continue to treat mud 550 GPM, 1750 PSI, 80 RPM, 14 TQ, Correct displacement at this point. PU 160K, SO 96K.;BROOH f/ 3885' t/ 1791' at 5-10 min stand, slow as needed to avoid any packing off issues, continue to treat mud. 550 GPM, 1180 PSI, 80 RPM, 5k Tq, PU 127K, SO 85K.;Slow pulling speed t/ 10-20 min stand f/ 2200' t/ 1800' Intermittent ECD increases of 10.5-10.7 EMW & erratic torque swings. Start seeing dynamic losses at 15 BPH Increase in cuttings returns and thick mud @ 1920’ Total losses at this point = 61 bbls;BROOH f/ 1791' t/ 745 ' at 5-15 min stand, slow as needed to avoid any packing off issues, 550 GPM, 1330 PSI, 80 RPM, 7 Tq, Pulled the last stand DP slow to circ 2x BU, 75 bbls total loss on BROOH.;Monitor Well 5 min –static-, Blow down TopDrive POOH on elevators from 745', laying down excess HWDP & Jars t/ 177’ L/D three NMFDC to 87’. Read MWD tools. L/D remainder of BHA from 87'. Clear rig floor. Bit grade : 1-2- CT-T-F-I-NO-TD 10 bbls total lost on trip out. Static losses at 3 BPH.;Daily Loss (midnight) = 61 bbls, Cumulative losses = 61 bbls Hauled 1100 bbls H2O from L-Pad for total = 4350 bbls Hauled 922 bbl to MPU G&I cuttings/mud/cement for total = 4263 bbls 5/3/2020 R/U to run 9 5/8 casing with volant.;M/U 9 5/8 40# TXP shoe track. baker loc all connections. T/ 157'. Install Bypass baffle inside FC joint. Pump through float equipment to verify floats work. Good.;Run 9 5/8 40# TXP L-80 F/ 157' T/ 2760'. Torque up with Volant to 21,000. Tagged up at 1462' Hard. Worked through with out issue. Felt like it hung up at the well head.;Stage up pumps to 6 BPM 170 psi. Work pipe 40'. Circ 1.5 btm up. Lost of sand and silt back. Cleaned up good.;Continue to Run 9 5/8 40# TXP L-80 F/2760' T/ 3432'.;HES Inspect escmt tool. Good. Pinned with 6 pins. Baker loc pin and make up. Torque up with Volant to 21,000 Baker loc & M/U full joint above ES CMT tool and didn't make up all the way. Two threads off of mark. Bring TQ to 25K and turned 1/2 turn. Still 1/4 off of mark. Steam collar and break out;Collar dmg on ES CMT tool & starting threads on full joint. L/D ES CMT tool. Jt below tool box dmg also. L/D same. Make new tally and prep back-up ES CMT tool. M/U new tool and joints-good. Static Loss at 4 BPH. Pinhole found in Pill Pit. Empty pit & patch w/ Splash Zone 2 part epoxy.;Cont to Run 9 5/8 40# TXP L-80 F/3510' T/ 5920'. Tq conn to 21K ft/lbs w/ volant tool. Fill on the fly and top off every 10 jts. Tag bottom on depth, verified with pipe count in shed. 61 bbls lost during casing run. Total of 149 jts of casing, 79 each 9.625"x12.25" centralizers & 10 stop rings.;Stage up pumps to 6 BPM, 210 PSI. Engage rotary w/ 20K TQ limit 5 RPM while reciprocating pipe f/ 5919' t/ 5911'. Treat mud for cement job. Losing 4 BPH. Hold PJSM for 1st stage while circ & condition.;Blow down top drive. Cleaned and inspected Volant dies. R/U cement lines and blow air to cementers to verify lines clear while Halliburton batching up spacer.;Circ 6 BPM, 210 psi for 500 stks. Pressure test lines 1057 psi low / 4000 psihi. Mix & pump 60 bbls of 10 ppg Tuned Spacer @ 4.5 BPM, 165 PSI (4# red dye & 5# Pol-E-Flake in 1st 10 bbls). Drop bypass plug. Mix & pump 196 bbls 12 ppg Type I/II lead cmt (460 sks, 2.349 ft^3/sk yield) @5.2 BPM 300 psi.;Mix & pump 82 bbls 15.8 ppg Premium G tail cement (400 sks, 1.158 ft^3/sk yield) @ 3.5 BPM, 295 PSI. Drop shutoff plug. Pump 20 bbls water @ 6 BPM, 315 PSI. No losses during cementing recorded.;Daily losses (midnight) = 72 bbls, cumulative losses = 133 bbls. Hauled 280 bbls H2O from L-Pad for total = 4630 bbls Hauled 380 bbls Source Water from G&I for total = 380 bbls Hauled 865 bbls to MPU G&I cuttings/mud/cement for total = 5128 bbls 5/4/2020 Displace with Rig at 6 BPM 227.6 bbl (2204 Sks) . Swap to HES & Mix & pump 80 bbl Tuned spacer. Line up to rig and pump 3370 stks total. Bump on calculated strokes. Final circ psi @ 640 & hold 500 over. Cmt in place at 7:15. 11 bbl losses while pumping job. 9-5/8" Shoe @ 5918' MD / 3802' TVD.;Bleed off and check floats. Good. Pressure up to 2790 psi and cmt tool opened. Saw good indication on rig floor.;Displace out 60 bbl spacer and 40 bbl good cmt at 5 BPM. Dump total 260 bbl total. Got good mud back after 3000 strokes. Took returns to the pits.;Circ two btm up 390 bbl treating mud system. no issues. Shut down and flush all surface equipment. Cycle annular in black water three times and dump to cellar. Change out two hard to operate valves on the cmt manifold.;Continue to circulate at 6 bpm while filling water tanks and waiting on cmt.;PJSM, Second stage cmt job. Wait for HES to prime up. Blow line back to them with air. Continue to circulate while waiting on HES.;HES pump 5 bbl fresh water to test lines. Test lines to 1400 psi, bleeding off. Troubleshoot and grease valves in CMT unit. PT t/ 1400 psi and still bleeding off. Found pump failure in CMT unit. Blow down cement line and line up to circ w/ rig.;Continue to circulate at 6 bpm - 270 psi while waiting on replacement HES cement unit. Break out Volant. Clean, inspect and dope cup. Spot and rig up new cement unit.;Hold PJSM, HES pump 5 bbls fresh H²O. Test lines to 1400 & 4000 psi. Good test. Mix and pump 50 bbl 10 PPG Tuned Spacer with red die and Pol-E-Flake in 1st 10 bbls.;Mix & pump 460 bbls 10.7 ppg ArcticCem lead cement (877 sks 2.944^3/sk yield @ 5.0 BPM, 420 PSI. Spacer back @ 263 bbls lead pumped. Mix & pump 56.2 bbls 15.8 ppg Premium G tail cement (270 sks) 1.169^3/sk yield @ 4.5 BPM, 500 PSI. Drop closing plug. Pump 20 bbls of fresh water @ 5 BPM, 205 PSI.;Displace w/ 168 bbls 9.4 ppg mud with rig pump @ 6 BPM, 660 PSI. Slow to 3.0 BPM, 500 PSI for last 10 bbls. Bumped plug on calculated stks (1363 stks) Pressure up and close ES cementer at 1460 PSI CIP @ 23:17 107 bbls interface before good cement. 279 bbls of cement back to surface.;Open bleeder with no flow back, verified ES cementer closed. No losses recorded during cement job.;Drain stack. Disconnect knife valve accumulator lines. Flush stack w/ black water functioning annular 6 times. Vacuum mud out of casing prior, prep for cutting. Begin N/D diverter line.;Release air from air boot & hoist diverter stack. Install casing slips as per wellhead rep and set w/ 100K on slips. Cut 9-5/8" casing. L/D 29.96' cut joint.;Set diverter stack down. N/D flow nipple, riser and diverter stack.;Daily losses (midnight) = 9 bbls, Cumulative losses = 142 bbls. Hauled 190 bbls H2O from L-Pad for total = 4820 bbls Hauled 90 bbls Source Water from G&I for total = 470 bbls Hauled 1198 bbls to MPU G&I cuttings/mud/cement for total = 6326 bbls 5/5/2020 Finish N/D diverter stack, welder dress 9 5/8'' casing stump.;N/U T-103 nipple and casing spool. Test seal between nipple and 9 5/8'' casing to 2470 psi for 10 min. @ 80% 9 5/8'' collapse. Test casing spool and T-103 nipple to 500 psi for 5 min and 5000 psi for 10 min. SimOps,: clear rig floor.;Set stack on spool. N/U BOP stack, install kill line, turn buckles, trip nipple & accumulator lines. Flush and clean flowline. Install 90' mousehole. Sim-ops: clean pits, start loading pits w/ 8.8 ppg flow pro mud w/ 1% screen Kleen and .5% lubes.;R/U test equipment, Power up accumulator. Install test plug w/ 5'' test jt, flood stack, lines and gas buster.;Perform initial BOP testing as per AOGCC & PTD requirements. AOGCC inspector Brian Bixby waived witness of testing at 04:54 on 04 May 2020. All tests performed with fresh water, to 250 PSI low / 3000 PSI high, held for 5 min. each and charted. Rig Electrician tested Rig gas alarms.;1) Upper 4.5"x7" VBR on 5" test joint, choke valves 1, 12, 13, 14, kill line Demco & upper IBOP. 2) Choke valves 9, 11, HCR kill & lower IBOP. 3) Choke valves 5, 8, 10, manual kill & 5" FOSV #1. 4) Choke valves 4, 6, 7 & 5" FOSV #2. 5) Lower 3.5"x6" VBR on 5" test joint & 5" dart valve.;6) Upper 4.5"x7" VBR on 4.5" test joint, choke valve 2, 3.5" FOSV. 7) HCR choke.& 3.5" dart valve. 8) Annular on 3.5” test joint & manual choke 9) Lower 3.5"x6" VBR on 3.5" test joint. 10) Choke valve 3 & blind rams 11) Hydraulic choke "A" 12) Manual choke "B".;First Accumulator test: 2950 PSI system, 1650 PSI after closure, 200 PSI recovery in 54 sec., full recovery in 254 sec., 6 nitrogen bottle average = 2125 PSI. Trouble shoot excessive times and find Annular 4-way valve on manifold leaking.;C/O 4-Way Valve on Koomy and trouble shoot low oil flow/slow recovery time during accumulator test.;Sim-ops: Rig down test equipment on floor, pull test plug, drain stack & install 10” ID wear ring. Blow down choke and kill lines. Install MPD drip pan on stack. Prep pits and hopper room for FloPro displacement. Rig up Geo-Span. PT MPD & Injection lines to 250/3500 psi.;Start M/U BHA while working on accumulator pump. Hold PJSM, Pick up Geo-Pilot 76000 RSS and M/U 8-1/2" NOV SK616M-J1D PDC Bit. 1st stage pgg Cut 9-5/8" casing. L/D 29.96' cut j cmt surface casing ppg 279 bbls of cement back to surface.;O BOPE test ppg No losses during cementing pg p q p buster.;Perform initial BOP testing as per AOGCC & PTD requirements. 2nd stage R/U to run 9 5/88 casing with volant.;M/U 9 5/8 40# TXP shoe track. baker loc all connections. T/ 157'. Install Bypass baffle inside FC joint. Pump through pppy q . Tag bottom on depth, verified with pipe count in shed. 61 bbls lost during casing run. pp p g g y p gpp Hold PJSM for 1st stage while circ & condition.;Blow down top drive. Cleaned and inspected Volant dies.jg R/U cement lines and blow air to cementers to verify Finish N/D diverter stack, w pppp ;Mix & pump 460 bbls 10.7 ppg ArcticCem lead cement (877 sks 2.944^3/sk yield @kkp p p ppg (y@ 5.0 BPM, 420 PSI. Spacer back @ 263 bbls lead pumped. Mix & pump 56.2 bbls 15.8 ppg Premium G tail cement (270 sks) 1.169^3/sk yield @ 4.5 BPM, p @ pp pp ppg ( )y@ 500 PSI. Drop closing plug. Pump 20 bbls of fresh water @ 5 BPM, 205 PSI.;Displace w/ 168 bbls 9.4 ppg mud with rig pump @ 6 BPM, 660 PSI. 5/6/2020 Continue to troubleshoot slow recovery time from drawdown test, rebuild fluid end, found small piece of plastic from packing under suction valve seat, replace pistons and packing, recharge system.;Perform Accumulator test: 3000 PSI system pressure, 1650 PSI after closure, 200 PSI recovery in 41 sec., full recovery in 189 sec., good. 2-failures, annular 4 way valve leaking and slow recovery pressure on koomey pump.;M/U BHA 2, P/U 8 1/2'' bit, geo-pilot assy, M/U MWD tools and float sub to 86', attempt to initialize and test MWD tools, ADR failed, L/D same, P/U backup ADR, plug in, initialize and test same, good.;M/U 3 NMFCs, upper flt sub, HW jar std to 282', RIH w/ 1 std 5” DP to 377', Shallow pulse test MWD with 450 GPM, 720 PSI - good test. Pressure test Geo-Span to 3000 PSI. Blow down TD.;TIH on elevators w/ stds 5'' DP f/ 377' to 2281'.;Fill pipe, break in geo pilot seals. Wash and ream down f/ 2281' to 2451' 450 GPM- 950 psi, 60 RPM - 5k Tq. Tag up on cement w/ 5k Wt.;Cleanup cmt stringers, drill ESC and plugs on depth f/ 2463' to 2471' 500 gpm, 1100 psi, 60 rpm, 4k-6k tq. 3-5k WOB. PU 107K, SO 82K, ROT 94K. Reamed through ESC 3x,& work through with no pumps/rotary with no issues.;Attempt to RIH on elevator, seeing 5-15k drag and set down 15-25k. Wash and ream down t/ 2851', 500 GPM - 1150 psi, 60 RPM - 5k Tq.;Blow down TopDrive. TIH f/ 2851' t/ 5612'. Ran out of the derrick to 5517' then picked up singles out of the pipe shed to 5612'. 192 PU / 80K SO.;Wash down from 5612' with 450 GPM, 1250 psi . Taking wt at 5705' Wash and ream f/ 5705’ t/ 5775’. 460 GPM, 1250 psi. 40 RPM, 14k Tq Set down 25k Wt and string stalled at 5725’. See 30k overpull before breaking over. Feather through and no issues down t/ 5775’;CBU at 535 GPM, 1600 psi. 40 RPM, 14.5k Tq;Lay joint of DP down. Blow down top drive & rig up test equipment. Close upper 4-1/2"x7" VBR on 5" drill pipe. Pressure test casing to 2700 PSI for 30 min. on chart - good test. R/D test equipment & blow down lines.;Drill cement & float equipment f/ 5775' t/ 5918', 540 GPM, 1850 PSI, 50 RPM, 15K Tq, 5-15K WOB Drilled baffle adapter on depth @ 5797, float collar on depth @ 5836' & shoe on depth from 5916-5918’'. Clean out rat hole to 5920'. Reamed thru float equipment 3x times & worked 1x w/ no ROT.;Drill 20' of 8-1/2" hole f/ 5920' t/ 5940’, 20' drilled, 250'/hr AROP. 460 GPM, 1420 PSI, 50 RPM, 15K TQ, 5K WOB. 205k PU, 84k SO, 123k ROT;BROOH f/ 5940’ t/ 5894’, Rack a std Derrick Circulate a bottoms up, 530 GPM, 1640 PSI, 50 RPM, 15K TQ. Reciprocate f/ 5894' t/ 5800'. 210K PU / 75K SO. Blow down the top drive. 154 peak units of Gas seen w/ BU Monitor well - Static.;R/U test equipment & closed 4-1/2"x7" VBR on 5" pipe Performed 12.0 ppg EMW FIT at 5918' MD / 3802' TVD with 574 PSI applied with 9.1 ppg mud. Pump 1.2 bbls & bled back 1.2 bbls. R/D test equipment & blow down lines.;Interval Daily (Midnight) Loss = 0 bbls, Cumulative losses = 0 bbls Hauled 115 bbls H2O from L-Pad for total = 4935 bbls Hauled 0 bbls Source Water from G&I for total = 470 bbls Hauled 114 bbls to MPU G&I cuttings/mud/cement for total = 6440 bbls 5/7/2020 PJSM, Remove trip nipple, install MPD bearing, circulate thru MPD, no leaks.;PJSM for displacing, parked in casing @ 5890', pump 30 bbl hi vis spacer, displace with 450 bbls 8.8 ppg flo pro mud, 325 gpm, 700 psi, 40 rpm, 14.5k tq. with spacer at bit run to bttm, pull back into casing working pipe, dump spacer and spud mud returns to rock washer.;Park in 9 5/8'' casing at 5893', M/U FOSV, PJSM, slip and cut 33' drlg line. Inspect saver sub and grabber dies, service rig. Re-calibrate block height, L/D FOSV. Monitor MPD for pressure build, none. Simops: clean pit 4 and under shakers.;M/U stand DP and top drive, Get new parameters and SPRs, 423 gpm, 830 psi, 60 rpm, 13k torque, Survey, tag bottom. PU 175K, SO 90K, ROT 125K.;Drill 8-1/2" lateral f/ 5940' t/ 6553', 613' drilled , 94.3'/hr AROP. 410 - 476 GPM, 860-1060 PSI, 110 RPM, 14K TQ, 14-16K WOB. 8.7 ppg MW, 41 vis, 9.7 ECD, max gas 479u. 160K PU / 85K SO / 120K ROT.;At 6000' Increase screen kleen content in mud f/ 1% to 1.5%, maintain .5% lubes. At 6460' shakers blinding off, C/O back screens f/ 140s to 120s, rock wash f/ 120s to 80s, C/O geo span jet f/ 18 to 22 MPD holding 80 psi drlg, hold 160 psi during connections. Drill in NB sand, target 90.5°.;Drill 8-1/2" lateral f/ 6553' t/ 7289' (3798’ TVD)736' drilled , 122.66'/hr AROP. 400 GPM, 1020 PSI, 100 RPM, 11K TQ, 7K WOB. 8.8 ppg MW, 42 vis, 10.0 ECD, max gas 292u. 160K PU / 82K SO / 115K ROT.;MPD holding 160 PSI on connections. Full open w/ 40 psi line pressure while drilling. Backream 30' @ 400 GPM, 100 RPM. Pumped high vis sweep at 7030', back 150 stks late with 50% increase of cuttings.;Drill 8-1/2" lateral f/ 7289' t/ 7822' (3789’ TVD) 533' drilled , 88.83'/hr AROP. 400 GPM, 1060 PSI, 100 RPM, 12K TQ, 10K WOB. 8.9 ppg MW, 42 vis, 10.2 ECD, max gas 387u. 160K PU / 83K SO / 114K ROT.;Drilled into the NB Clays for 85’ f/ 7,393' t/ 7,478'. MPD holding 160 PSI on connections. 80 psi while drilling. Backream 30’ @ 400 GPM, 100 RPM.;Last survey at 7728.60' MD / 3788.25' TVD, 89.82° inc, 176.08° azm, 55.4' from plan, 46.10' low and 30.70' left. We have drilled 20 concretions for a total thickness of 75' (4.1% of the lateral).;Interval Daily (Midnight) Loss = 0 bbls, Cumulative losses = 0 bbls Hauled 615 bbls H2O from L-Pad for total = 5550 bbls Hauled 0 bbls Source Water from G&I for total = 470 bbls Hauled 1378 bbls to MPU G&I cuttings/mud/cement for total = 7818 bbls 5/8/2020 Drill 8-1/2" lateral f/ 7822' t/ 8542' (3762’ TVD) 720' drilled , 120'/hr AROP. 410 GPM, 1120 PSI, 100 RPM, 13K TQ, 5-15K WOB. 8.8 ppg MW, 42 vis, 10.73 ECD, max gas 312u. 155K PU / 70K SO / 115K ROT.;Pump 30 bbl hi vis sweep @ 7988', sweep back on time w/ 100% increase. MPD hold 160- 180 psi during connections and 125 psi drilling. Drill in the NB sand targeting 90-92 deg adjusting f/ formation dip. Put rig on Gen poewr @ 07:00.;Drill 8- 1/2" lateral f/ 8542' t/ 9196' (3743’ TVD) 654' drilled , 109'/hr AROP. 410 GPM, 1160 PSI, 100 RPM, 12K TQ, 5-15K WOB. 8.8 ppg MW, 42 vis, 10.7 ECD, max gas 337u. 160K PU / 67K SO / 115K ROT.;Pump 30 bbl hi vis sweep @ 9020', sweep back on time w/ 80% increase. MPD hold 200 psi during connections and 130 psi drilling. Drill in the NB sand targeting 90-92 deg adjusting f/ formation dip.;Drill 8-1/2" lateral f/ 9196' t/ 9731' (3717’ TVD) 535' drilled , 89'/hr AROP. 400 GPM, 1480 PSI, 100 RPM, 15K TQ, 5-15K WOB. 8.8 ppg MW, 39 vis, 10.7 ECD, max gas 319u. 155K PU / 70K SO / 110K ROT.;Pumped high vis sweep at 9796', back on time with 70% increase of cuttings. MPD hold 150 psi during connections and 130 psi drilling. Drilled through fault #1 at 9592’ - 15’ throw DTN – Puts wellbore into NB Clays Target 95-97° inclination building back up to NB Sands.;Drill 8-1/2" lateral f/ 9731' t/ 10032' (3683’ TVD) 535' drilled , 89'/hr AROP. 530 GPM, 2060 PSI, 100 RPM, 17K TQ, 25K WOB. 8.95 ppg MW, 40 vis, 10.86 ECD, max gas 336u. 160K PU / 65K SO / 100K ROT. Cont drill up section through NB Clay searching for NB sand.;Last survey at 9916.51' MD / 3698.50' TVD, 96.88° inc, 184.12° azm, 50.37' from plan, 48.64' low and 13.09' left. We have drilled 31 concretions for a total thickness of 110' (2.7% of the lateral).;Interval Daily (Midnight) Loss = 0 bbls, Cumulative losses = 0 bbls Hauled 600 bbls H2O from L-Pad for total = 6150 bbls Hauled 0 bbls Source Water from G&I for total = 470 bbls Hauled 917 bbls to MPU G&I cuttings/mud/cement for total = 8735 bbls FIT q 2700 PSI for 30 min. Drill 8-1/2" lateral f/ 7822' t/ 8542' (3762’ p Pressure test casing to pp Tag up on cement w/ 5k Wt.;Cleanup cmt stringers, MIT casing p@ ;Drill 20' of 8-1/2" hole f/ 5920' gp drill ESC and plugs on depth f/ 2463' pp Performed 12.0 ppg EMW FIT at 5918' MD / 3802' TVD 5/9/2020 Drill 8-1/2" lateral f/ 10032' t/ 10320' (3662’ TVD) 288' drilled , 48'/hr AROP. 480 GPM, 1810 PSI, 120 RPM, 17K TQ, 16K WOB. 9 ppg MW, 40 vis, 10.8 ECD, max gas 199u. 160K PU / 55K SO / 105K ROT.;Target 92 deg. Geo Later determined interpreted fault #1 different, entered the NA sand at 10050’, target 99 deg. MPD holding 150 psi during connections and 130 psi drilling.;Drill 8-1/2" lateral f/ 10320' t/ 10392' (3651’ TVD) 72' drilled, target 101 deg to confirm PB1 TD. 480 GPM, 1850 PSI, 100 RPM, 18K TQ, 15-20K WOB. 9 ppg MW, 41 vis, 10.92 ECD, max gas 129u. 165K PU / 60K SO / 114K ROT.;Take survey, BROOH 10 stands f/ 10392' to 9405', 450 gpm, 1650 psi, 80 rpm, 14k torque for open hole sidetrack to re-cross Fault #1 at 9680’ with a throw of ~5’ DTS. Last survey: 17.87’ below the line, 4.43’ left;Perform open hole sidetrack, deflect 100% lowside, trough f/ 9405' to 9425' 2x, 480 gpm, 1830 psi, 120 rpm, 14k tq. with 0.9 deg separation. Time drill @ 10 fph f/ 9425’ to 9440'.;ABI @ 9440' shows 91°, 2° below original wellbore angle of 92.96°. Turn TF t/ 130R, drill t/ 9445' then turn up t/ 90R Survey @ 9535' shows 4' of separation from PB Wellbore.;Drill 8-1/2" lateral f/ 9445' t/ 9575' (3734’ TVD) 130' drilled, 43’/hr AROP 410 GPM, 1290 PSI, 120 RPM, 16K TQ, 5-20K WOB. 9 ppg MW, 41 vis, 10.62 ECD, max gas 193u. 165K PU / 60K SO / 115K ROT. MPD holding 160 psi during connections and 130 psi drilling Drilled into NB clay @ 9485’.;Drill 8-1/2" lateral f/ 9575' t/ 10047' (3708’ TVD) 472' drilled, 78.66’/hr AROP 400 GPM, 1310 PSI, 120 RPM, 20K TQ, 25K WOB. 9.05 ppg MW, 40 vis, 10.78 ECD, max gas 428u. 160K PU / 60K SO / 105K ROT. MPD holding 175 psi during connections and 130 psi drilling.;Crossed fault #1 @ 9655’, 4’ DTS throw. Entered the NB sand at 9705’ Target 92.5° inc to maintain NB sand.;Last survey at 9914.64' MD / 3717' TVD, 92.91° inc, 186.07° azm, 66.47' from plan, 65.97' low and 8.16’ Right. We have drilled 35 concretions for a total thickness of 132' (3.3% of the lateral).;Interval Daily (Midnight) Loss = 0 bbls, Cumulative losses = 0 bbls Hauled 735 bbls H2O from L-Pad for total = 6885 bbls Hauled 0 bbls Source Water from G&I for total = 470 bbls Hauled 1041 bbls to MPU G&I cuttings/mud/cement for total = 9776 bbls 5/10/2020 Drill 8-1/2'' lateral f/ 10047' t/ 10480' (3694’ TVD) 433' drilled, 72.16’/hr AROP. 445 GPM, 1690 PSI, 120 RPM, 15K TQ, 15K W OB. 11 ppg MW, 40 vis, 11 ECD, max gas 410u. 160K PU / 60K SO / 105K ROT. MPD holding 160 psi during connections and 130 psi drilling.;At 10076' pump 30 bbl hi vis sweep, back on time w/ 50% increase. At 10105' perform 290 bbl dump/dilute w/ new 8.8 ppg FP mud lowering MBT f/ 6.8 to 5.5. Drill in the NB sand, target 92.5 deg. Note: reached depth of old wellbore of 10392' @ 10:10 am. Rig on high line power @ 11:15.;Drill 8-1/2'' lateral f/ 10480' t/ 11111' (3670’ TVD) 631' drilled, 105.16’/hr AROP 450 GPM, 1570 PSI, 120 RPM, 14K TQ, 5-20K WOB. 9 ppg MW, 42 vis, 11.23 ECD, max gas 315u. 160K PU / 55K SO / 110K ROT.;Pump 30 bbl hi vis sweep @ 11043', back on time w/ 30% increase. MPD holding 160 psi during connections and 130 psi drilling. Drill in NB sand, target 92 deg.;Drill 8-1/2'' lateral f/ 11111' t/ 11472' (3655’ TVD) 361' drilled, 60.2’/hr AROP 450 GPM, 1540 PSI, 120 RPM, 15K TQ, 5-20K WOB. 9.0 ppg MW, 40 vis, 11.08 ECD, max gas 344u. 165K PU / 48K SO / 111K ROT.;MPD holding 160 psi during connections and 130 psi drilling. Drill in NB Sand, Target 91.5° Hi-Line down @ 18:25 On Rig Gen power @ 18:30.;Drill 8-1/2'' lateral f/ 11472' t/ 11865' (3639’ TVD) 393' drilled, 65.5’/hr AROP 400 GPM, 1580 PSI, 100 RPM, 18K TQ, 20K WOB. 9.0 ppg MW, 40 vis, 10.79 ECD, max gas 311u. 167K PU / 45K SO / 105K ROT.;MPD holding 160 psi during connections and 90 psi drilling. At 11600' perform 290 bbl dump/dilute w/ new 8.8 ppg FP mud lowering MBT f/ 6.8 to 6.4. Entered the NB clay at 11547’. Build to 94.5° inc, reacquire the NB sand @ 11690'. Target 93.5°;Last survey at 11724.87’ MD / 3650.28' TVD, 94.28° inc, 183.84° azm, 55.88' from plan, 55.88' low and 0.10' right. We have drilled 64 concretions for a total thickness of 346' (5.9% of the lateral).;Interval Daily (Midnight) Loss = 0 bbls, Cumulative losses = 0 bbls Hauled 955 bbls H2O from L-Pad for total = 7840 bbls Hauled 0 bbls Source Water from G&I for total = 470 bbls;Hauled 979 bbls to MPU G&I cuttings/mud/cement for total = 10755 bbls Hauled 461 bbls to Kuparuk 1B cuttings/mud/cement for total = 461 bbls 5/11/2020 Drill 8-1/2'' lateral f/ 11865' t/ 12175' (3614’ TVD) 310' drilled, 51.6’/hr AROP. 400 GPM, 1490 PSI, 110 RPM, 19K TQ, 15-20K WOB. 9.0 ppg MW, 40 vis, 11 ECD, max gas 166u. 174K PU / 40K SO / 102K ROT. 12080' pump 30 bbl hi vis sweep, back 250 stks late w/ 50% increase.;Geo reports crossed Fault #2 at 11,850’ w/ a throw of 12’ DTN, moved the well path from base of NB-Sand to NB-Clays below, targeting 95°, crossed Fault #3 at 12,104’ w/ a throw of 6' DTS. That moved the bit from the clays below, into the NB-Sand, target 92 deg. Put Rig on high line power @ 09:00.;Drill 8-1/2'' lateral f/ 12174' t/ 12650' (3595’ TVD) 476' drilled, 79.3’/hr AROP. 410 GPM, 1350 PSI, 110 RPM, 19K TQ, 5-20K WOB. 8.9 ppg MW, 42 vis, 10.89 ECD, max gas 359u. 182K PU / 40K SO / 115K ROT.;Drill in the NB sand, target 92 deg. At 12225' perform 580 bbl dump/dilute w/ new 8.8 FP mud, lower MBT f/ 7.2 to 4. MPD holding 160 psi during connections and 90 psi drilling.;Drill 8-1/2'' lateral f/ 12650' t/12992' (3584’ TVD) 342' drilled, 57’/hr AROP 415 GPM, 1310 PSI, 120 RPM, 21K TQ,5-20K WOB. 8.9 ppg MW, 42 vis, 10.54 ECD, max gas 502u. 175K PU / 40K SO / 110K ROT. Cont drilling in NB sand target 92- 92.5° MPD holding 160 psi during connections and 90 psi drilling;Drill 8-1/2'' lateral f/ 12992' t/13126' (3569’ TVD) 134' drilled, 22.3’/hr AROP 420 GPM, 1320 PSI, 80 RPM, 17K TQ, 6-8K WOB. 8.9 ppg MW, 40 vis, 10.64 ECD, max gas 337u. 195K PU / no SO / 104K ROT. Cont drilling in NB sand target 92- 92.5° MPD holding 160 psi during connections and 90 psi drilling;Last survey at 12961.23' MD / 3584.19' TVD, 93.79° inc, 183.71° azm, 28.52’ from plan, 27.26' low and 8.40’ left. We have drilled 82 concretions for a total thickness of 537' (7.5% of the lateral).;Interval Daily Loss = 0 bbl, Cumulative losses = 0 bbl Hauled 910 bbls H²O from L-Pad for total = 8750 bbls Hauled 0 bbl Source H²O from G&I for total = 470 bbls Hauled 1943 bbls to MPU G&I cuttings/mud/cement for total = 12698 bbls Hauled 0 bbl to Kuparuk 1B cuttings/mud/cement for total = 461 bbls 5/12/2020 Drill 8-1/2'' lateral f/ 13126' t/13175' (3574’ TVD) 49' drilled, 8.1’/hr AROP. 430 GPM, 1410 PSI, 80 RPM, 20K TQ, 3-15K WOB. 8.9 ppg MW, 40 vis, 10.77 ECD, max gas 126u. 195K PU / no SO / 106K ROT.;Continue drilling in NB sand, drilling numerous concretions, attempting to target 91.5 deg, MPD holding 160 psi during connections and 90 psi drilling.;Drill 8-1/2'' lateral f/ 13175' t/13194' at TD (3573’ TVD) 19' drilled, 430 GPM, 1440 PSI, 100 RPM, 21K TQ, 5-10K WOB. 8.9 ppg MW, 40 vis, 10.76 ECD, max gas 35u. 195K PU / no SO / 105K ROT. MP in phase 2 conditions at 12:30.;Continue drilling thru numerous concretions, unable to build f/ 93.5 deg targeting 91.5 deg, decision from town to call TD 300' early. Obtain final survey: 23.67' below the line, 6.51' left.;Pump 30 bbl hi vis sweep, cleanup the wellbore, 450 gpm, 1560 psi, 100 rpm working pipe, sweep back 550 stks late w/ 10% increase, CBU x4 racking std back ea BU to 12937', MPU in phase 1 conditions at 17:00.;Ream to bottom (no slack off weight) f/ 12937' t/ 13194'. 300 GPM, 920 PSI, 80 RPM, 19K.;Pump 30 bbl high vis spacer, three 20 bbl SAPP pills separated by 50 bbls seawater then chased by 240 bbls seawater. Pump 30 bbl high vis spacer and then perform displacement with 924 bbls of 8.45 ppg viscosified lubricated 2% KCL/NaCL brine.;210 GPM, 590 PSI ICP / 710 PSI FCP, 80 RPM, 19K TQ initial, 13K TQ final. Spacer & brine back 42.6 bbls late. MPD initially holding 100 PSI back pressure w/ 8.95 ppg mud, increased to 180 PSI w/ 8.45 ppg brine. Reciprocate pipe 60'.;Take returns back to the pits, observing moderate sand load over 120 mesh shaker screens. 1st PST test packed off coupon in 8 sec. Allow shakers to clean up to background sand load, PST passed w/ 4.7, 4.83 & 4.92 sec. 70 bbls losses during displacement.;Perform pressure monitoring w/ MPD. Trap 100 PSI and built to 132 PSI in 5 min. Bleed off to 100 PSI and built to 135 PSI in 5 min. with 8.7 ppg brine out = 9.4 ppg EMW. Grease washpipe. Obtain new slow pump rates. 163K PU / 63K SO / 115K ROT with lubricated brine.;BROOH f/ 13194' t/ 11580' at 5-10 min/stand, 450 GPM, 1310 PSI, 100 RPM, 15K TQ. MPD maintaining 130 PSI while pumping = 10.4 ppg ECD & 180 PSI static = 9.6 ppg EMW. 12 bph loss rate, lower MPD to 100 PSI while pumping, = 10.3 ECD, still losing 12 bph.;70 bbls daily (midnight) losses, 70 bbls cumulative losses for lateral.;Hauled 545 bbls H2O from L-Pad for total = 9,535 bbls Hauled 0 bbls Source Water from G&I for total = 470 bbls Hauled 2,405 bbls to MPU G&I cuttings/mud/cement for total = 15,633 bbls Hauled 461 bbls to Kuparuk 1B cuttings/mud/cement for total = 461 bbls TD lateral gg pggg 2'' lateral f/ 13175' t/13194' at TD (3573’ TVD) 19' drilled, 430 GPM, 1440 PSI, 100 RPM, gp g p g 21K TQ, 5-10K WOB. 8.9 ppg MW, 40 vis, 10.76 ECD, 5/13/2020 BROOH f/ 11580' t/ 9893' at 5-10 min/stand slowing as needed for hole cleaning or packing off, 450 GPM, 1150 psi, 100 RPM, 14-15K TQ. L/D stands 5'' DP utilizing the mouse hole, sort DP due f/ inspection. MPD hold 100-110 psi BR and 180-200 psi during connections. Continue w/ 12 bph loss rate.;BROOH f/ 9893' t/ 5896' at 5-10 min/stand slowing down as needed for hole cleaning and sight packing off , 450 GPM, 1120 psi, 100 rpm, 11k TQ, L/D stds DP f/ mouse hole. Pump out last 2 stands f/ 6086' t/ 5896'. MPD hold 100-110 psi BR and 180-200 psi during connections.;Loss rate avg 6-10 bph. 147 bbls total lost while BROOH. Sort DP due f/ inspection. Jt #271 (HAK S/N 1121) - significant pitting on pin end tool jt and just above the tool jt.;Pump 30 bbl high vis sweep, back on time w/ 10% increase. Pumped additional 1300 strokes for sand to clean up on shakers. Shut down pumps & monitor pressure build with MPD chokes closed.;Initial 60 PSI trapped built quickly to 90 PSI then stabilized at 124 PSI after 20 min. 8.8 ppg fluid + 124 PSI @ 3802' TVD = 9.5 ppg EMW. Weight up mud pits to 9.2 ppg with oilfield salt while monitoring pressure.;Displace to 9.2 ppg viscosified/lubricated brine while weighting up the returned fluid on the fly in a circulation. 420 GPM, 860 PSI, 60 RPM, 4K TQ. MPD maintaining 115 PSI while circulating with 10.5 ECD. Continue to weight up on the fly to 9.7 ppg while adding oilfield salt until 9.7 ppg in & out.;MPD chokes full open while circulating with 10.6 ECD. 130K PU / 102K SO / 110K ROT.;MPD choke open w/ initial 5 GPM flow back which stopped in 3 min. Close choke, monitor pressure for 5 min. - no build Close 4" MPD line, open 2" bleeder &monitor for flow. Initial 1.2 bph flow, slowed to 0.16 bph in 5 min. then static after 10 min. Begin to slip & cut drilling line while monitoring.;Slip & cut 85' of drilling line. L/D FOSV and 5' pup joint which were installed during slip & c ut. Monitor well pressure with MPD shut in- no build.;PJSM. Remove MPD RCD and install trip nipple. Fill stack & check for leaks - none. Start hole fill pump.;POOH f/ 5896' t/ 4850' laying down 5" drill pipe. Mark and segregate drill pipe for inspection and hard band. 2.5 bph loss rate.;Daily (midnight) losses = 193.5 bbls, cumulative losses for lateral = 263.8 bbls.;Hauled 240 bbls H2O from L-Pad for total = 9,775 bbls Hauled 280 bbls Source Water from G&I for total = 750 bbls Hauled 171 bbls to MPU G&I cuttings/mud/cement for total = 15,804 bbls Hauled 461 bbls to Kuparuk 1B cuttings/mud/cement for total = 461 bbls 5/14/2020 TOOH on elevators f/ 4850' L/D 5" drill pipe to 2145', with 12 stands remaining, drop 2.44'' drift on wire, Rack drifted DP in the derrick to HWDP @ 282'. Mark and segregate drill pipe for inspection and hard band. 18 bbl losses TOOH f/ shoe.;Flow check before pulling BHA, static, L/D jar stand, float subs and NMFCs to 83', Recover drift on wire. Plug in and upload MWD. L/D remaining BHA. Bit grade= 3-5-BT-T-X-I-CT-TD ILS worn 7.0625'' OD f/ 8.37'' OD, NRP sleeve 3/16'' under gauge, all wear bands show excessive wear;Blow down choke, clear and clean rig floor, remove split bushings, install master bushing. Load tools to rig floor, R/U 4 1/2'' handling equipment and power tongs. Ready FOSV w/ 4 1/2'' H625 XO. Monitor well, 1.5 bph loss rate.;PJSM with all parties involved, P/U round nose flt shoe w/ XO jt and 1st blank jt. with two 7.1" centrralizers to 84', P/U and test run FOSV and XO. P/U and run 4 1/2'', 13.5#, L-80 H625 lower screen completion as per tally to 7419', 97K PU / 81K SO inside the 9-5/8" shoe 5898'.;Torque to optimum @ 9600 ft/lbs, On blank jts- install 1- 4 1/2'' x 7 1/4'' straight vane centralizer w/ 1- stop ring free floating on each joint- 167 total ea. 168 blank joints, 11 RGL pro-mesh screens and 1 Tendeka water swell packer ran. 1.5 bph loss rate 15.1 bbls lost running liner.;M/U Baker 7"x9-5/8" SLZXP liner top packer to 7458' then run one stand of 5" drill pipe to 7554'. Pump 8 bbls to ensure clear flow path through Baker tools, 3 BPM, 160 PSI. Obtain parameters: 106K PU / 80K SO / 88K ROT, 15 & 20 RPM both at 3.5K TQ.;Run 4-1/2" lower injection completion on 5" drill pipe from the derrick f/ 7554' t/ 841 0'. Single in the hole w/ 5" HWDP f/ 8410' t/ 10438' 175K PU / 118K SO. 2.5 bph losses.;Daily (midnight) losses = 34 bbls, cumulative losses for production = 297.8 bbls;Hauled 600 bbls H2O from L-Pad for total = 9,835 bbls Hauled 0 bbls Source Water from G&I for total = 750 bbls Hauled 92 bbls to MPU G&I cuttings/mud/cement for total = 15,86 bbls Hauled 0 bbls to Kuparuk 1B cuttings/mud/cement for total = 461 bbls 5/15/2020 Run 4-1/2" lower injection completion, Single in the hole w/ 5" HWDP f/ 10438' t/ 13118', M/U 5'' stand #11 Tag TD on depth @ 13194', set down 20k to verify TD. Drop 29/32'' phenolic ball, M/U top drive, PU to 250k putting string in tension. 250K PU / 150K SO. 32 bph losses.;R/U test pump and chart recorder. Pump down at 2 bpm, 230 psi. Ball on seat at 534 strokes. Pressure up to 2700 psi and set packer. Pressure to 3000 psi hold 5 min. Line up test pump Submitted 24 hr notification to AOGCC for upcoming pre injection MIT-IA - Witness waived by Austin McLeod.;Pressure up & neutralize pusher tool @ 4000 psi w/ test pump, shear circ sub and release HRDE at the same time. Bleed off shut in pump pressure and pick up 5’ to confirm release. Break over w/ 220K PU. S/O to 60k. Close UPR, test 9 5/8'' x packer to 1700 psi f/ 10 charted min, bleed off, open UPR.;PJSM, P/U 37' at 2' above TOL @ 5745', flush same, Pump 30 bbl hi vis spacer followed w/ 445 bbls clean 9.7 ppg PST passed brine 342 gpm, 1800 psi, w/ spacer 60' up backside, set stand in mousehole, cont to displace at 5700' working pipe 60', dump returns to rock wash until good clean 9.7 brine.;Flow check the well for 15 min, static, BD TD, L/D stand in mouse hole and derrick. TOOH f/ 5700' to 4944' L/D 5'' HWDP to pipe shed Loss rate 1 bph.;Skate counter weight cable failed, lock and tag out same, PJSM, remove old cable, spool on new cable, test run, good.;Continue to TOOH f/ 4944' to 998' L/D 5'' HWDP to pipe shed. Lay down 5" drill pipe f/ 998' t/ 41'. L/D liner running tool from 41', found rupture disc blown instead of circulating sub. 10.9 bbls total lost on trip out of the hole.;Drain BOP stack and pull wear bushing. Mobilize tubing hanger & 3.5" casing equipment to the rig floor. Perform dummy run with 3.5" hanger w/ 3.5" EUE landing joint. L/D hanger & landing joint. R/U casing tongs and TEC wire spooler. PJSM for running tubing. 1 bph losses.;P/U Baker 7" bullet seal assembly with no-go, XO and pup joint to 20'. Run 3-1/2" 9.3# L-80 EUE tubing as per tally. M/U XN nipple assy at 771' and Centrilift Zenith gauge assy at 824'. Install TEC wire & test gauge - good. Torque connections to 2900 ft/lbs w/ Doyon double stack tongs. 1 bph losses.;Continue to run 3-1/2" 9.3# L-80 EUE tubing as per tally f/ 824' t/ 2571' Install cross coupler Cannon clamp on first 10 joints above gauge carrier then every other joint. Torque connections to 2900 ft/lbs w/ Doyon double stack tongs. Test TEC wire every 1000' - good test. 1 bph losses.;Daily (midnight) losses = 31 bbls, cumulative production losses = 328.8 bbls.;H2O from L-Pad Lake: daily 60 bbls , total 9,895 bbls Source Water from G&I: daily 0 bbls , total 750 bbls Cuttings/mud/cement to MPU G&I: daily,237 bbls, total 17,133 bbls Cuttings/mud/cement to Kuparuk 1B: 0 bbls, 461 bbls g R/U 4 1/2'' handling equipment and power tongs. Ready gp g MPD hold 100-110 psi BR and 180-200 psi during Run liner Run 4-1/2" lower injection completion, Single Run tubing 31/2" gg p g g p Run 3-1/2" 9.3# L-80 EUE tubing as per tally. M/U XN nipple assy at 771' and Centrilift Zenith gauge assy attyg ppj gpy 824'. Install TEC wire & test gauge - good. Torque connections to 2900 ft/lbs w/ Doyon double Activity Date Ops Summary 5/16/2020 Continue to run 3-1/2" 9.3# L-80 EUE tubing as per tally f/ 2571' t/ 5718' at jt # 181, ( L/D joint 105 replacing w/ jt 198 due to damaged threads) Install cross coupler Cannon clamp on every other joint. Torque connections to 2900 ft/lbs Test TEC wire every 1000' - good test. 13 bph losses running tubing.,M/U jont 182 and 183, see seals entering TOL, No-go ont TOL @ 5750' tbg MD with mule shoe at 5759.32', close bag, apply 400 psi on annulus, verify seals engaged, bleed off pressure, open bag. PU 80k, SO 70k.,Space out as per Baker rep, L/D 3 jts 183, 182 and 181, M/U 6.08' pup jt, M/U jt 181, M/U Cameron hanger w/ pup 1.66'’ pup joint, 3 1/2'' landing joint, FOSV, side entry sub & pup joint to reverse circulate. Perform hanger penetration w/ tech cable. Take final readings- 1984.47 psi, Ann 1652.68 psi, Temp 74 deg.,Drain Stack, RIH and Land hanger, rig up cement hose to side entry sub, P/U 2', close annular & pressure up to 400 PSI. P/U until pressure dumps. 82 full Cannon clamps ran.,PJSM, Pressure test lines and reverse circulate 225 bbls of 9.6 ppg Conqor 303A inhibited brine at 5 BPM, 1060 PSI. Reverse circulate 160 bbls of diesel freeze protect at 4 bpm, 580 psi ICP, 820 psi FCP.,Slack off t/ 1’ above landing hanger, closing circ ports on bullet seal assembly. Bleed off trapped annulus pressure to cuttings tank. Blow down diesel in BOP stack to the cuttings tank. Land tubing hanger with 30K on hanger and run in lock down screws. EOP at 5757.78', locator sub 1.80' off no-go. Swap rig to gen power @ 17:30 *** Notified AOGCC of up coming diverter test on M-45 @ 18:37 on 16 May 2020 ***,Line up to perform IA MIT. While pressuring up, chart recorder flat lined at 1500 PSI w/ pump continuing up to 1800 PSI. Bleed off, pump up sensor & purge line. Observed stack had filled with diesel. Attempt to pressure up, leaking by hanger at 20 PSI. Empty BOP stack to vac truck. Remove lock down screw. Observe hanger 1" off seat. Back out all LDS. P/U 15K, S/O 5K, P/U 35K then while S/O hanger set on seat. RILDS.,Pressure test lines to 3000 PSI - good. Perform 2500 PSI MIT on 3-1/2" x 9-5/8" annulus for 30 minutes on chart - good test. AOGCC inspector Austin McLeod waived witness of IA MIT at 16:58 on 15 May 2020. Bleed off to cuttings tank.,L/D circulating subs, lines and landing joint. Blow down injection, kill and hole fill lines. Set BPV with tee bar.,Clear rig floor of casing equipment and TEC spooler. L/D 90' mousehole extension. L/D trip nipple. N/D BOP stack. break connections for 2' spacer spool and place on stump. Sim-ops: C/O ODS rig floor skid ram with crane. Level pad for M-45.,N/U adapter flange with Cameron tree attached. Feed Centrilift TEC wire through adapter flange & obtain final readings - intake 1749.45 psi, 70.6°F, discharge 1555.74 psi, 70.3°F, x = 0g, y = 0g. Sim- ops: Empty mud pits and rock washer. Move rock washer.,Daily (midnight) losses = 27 bbls, Cumulative production losses = 355.8 bbls. H2O from L-Pad Lake: Daily 65 bbls , Total 9,960 bbls Source Water from G&I: Daily 0 bbls, Total 750 bbls Cuttings/mud/cement to MPU G&I: Daily 264 bbls, Total 17,397 bbls Cuttings/mud/cement to Kuparuk 1B: Daily 0 bbls , Total 461 bbls 5/17/2020 Finish N/U the tree, Test hanger void to 500 PSI low for 5 min & 5000 PSI high for 10 min, good. Install the BPV dart, Test the tree with diesel to 250/5000 psi 5 min ea. Note: 2 fittings on test pump lines and flange on tree wing valve had slight leak, C/O fittings and tighten flange- good test.,Pull BPV dart. R/U and test lines. PJSM. Bullhead 23 bbls diesel down tubing through BPV @ 4 bpm. ICP 670 psi, 2.5 bpm FCP 1300 psi. freeze protect tbg to 2500'. Flush lines with water, blow down line to cuttings box, R/D same. Secure tree and cellar. Vac out cuttings box, Welder cut and cap mouse hole in cellar. Note: 630 psi under BPV. Rig released @ 12:00,Move rig off M-44 to M-45. See M-45 report for details.,Daily losses = 25 bbls, Cumulative production losses = 380.8 bbls H2O from L-Pad Lake: 0 bbls Daily/ 9,960 bbls total Source Water from G&I: 0 bbls Daily / 750 bbls Total Cuttings/mud/cement to MPU G&I: 465 bbls Daily / 17,862 bbls total Diesel Recycle to MPU – ORT: 200 bbls Daily / 200 bbls total Cuttings/mud/cement to Kuparuk 1B: 0 bbls Daily / 461 bbls total n (LAT/LONG): evation (RKB): API #: Well Name: Field: County/State: MP M-44 Milne Point Hilcorp Energy Company Composite Report , Alaska Contractor AFE #: AFE $: Job Name:2010895C MPU M-44 Completion Spud Date: MIT-IA Finish N/U the tree, gpp g g Bullhead 23 bbls diesel down tubing through BPV @ g Perform 2500 PSI MIT on 3-1/2" x 9-5/8" annulus for 30 minutes on chart - good M-44 Completion 15 May, 2020 Milne Point M Pt Moose Pad MPU M-44i 500292367300 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt Moose Pad Halliburton Definitive Survey Report Well: Wellbore: MPU M-44i MPU M-44i Survey Calculation Method:Minimum Curvature MPU M-44 Actual RKB @ 59.33usft Design:MPU M-44i Database:NORTH US + CANADA MD Reference:MPU M-44 Actual RKB @ 59.33usft North Reference: Well MPU M-44i True Map System: Geo Datum: Project Map Zone: System Datum:US State Plane 1927 (Exact solution) NAD 1927 (NADCON CONUS) Milne Point, ACT, MILNE POINT Alaska Zone 04 Mean Sea Level Using Well Reference Point Using geodetic scale factor Well Well Position Longitude: Latitude: Easting: Northing: usft +E/-W +N/-S Position Uncertainty usft usft usftGround Level: MPU M-44i, Slot 58 usft usft 0.00 0.00 6,027,889.70 534,143.85 25.10Wellhead Elevation:25.40 usft0.50 70° 29' 13.989 N 149° 43' 15.335 W Wellbore Declination (°) Field Strength (nT) Sample Date Dip Angle (°) MPU M-44i Model NameMagnetics IFR 4/10/2020 15.98 80.92 57,387.00000000 Phase:Version: Audit Notes: Design MPU M-44i 1.0 ACTUAL Vertical Section: Depth From (TVD) (usft) +N/-S (usft) Direction (°) +E/-W (usft) Tie On Depth:9,345.99 184.000.000.0033.93 From (usft) Survey Program DescriptionTool NameSurvey (Wellbore) To (usft) Date 5/12/2020 Survey Date 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sa181.69 5,879.80 MPU M-44PB1 MWD+IFR2+MS+Sag (M 03/26/2020 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sa5,951.52 9,345.99 MPU M-44PB1 MWD+IFR2+MS+Sag (2) 05/08/2020 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sa9,405.00 13,116.63 MPU M-44i MWD+IFR+MS+Sag (3) (MP 05/11/2020 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 33.93 0.00 0.00 33.93 0.00 0.00-25.40 6,027,889.70 534,143.85 0.00 0.00 UNDEFINED 181.69 0.92 33.10 181.68 0.99 0.65122.35 6,027,890.70 534,144.49 0.62 -1.04 3_MWD+IFR2+MS+Sag (1) 228.75 1.09 35.54 228.74 1.67 1.11169.41 6,027,891.38 534,144.96 0.37 -1.75 3_MWD+IFR2+MS+Sag (1) 322.76 3.76 26.88 322.65 5.15 3.03263.32 6,027,894.87 534,146.85 2.86 -5.35 3_MWD+IFR2+MS+Sag (1) 419.43 6.45 26.36 418.93 12.85 6.87359.60 6,027,902.58 534,150.66 2.78 -13.29 3_MWD+IFR2+MS+Sag (1) 517.30 8.80 33.66 515.93 24.00 13.46456.60 6,027,913.76 534,157.20 2.59 -24.89 3_MWD+IFR2+MS+Sag (1) 610.40 11.75 38.94 607.53 37.31 23.37548.20 6,027,927.11 534,167.05 3.32 -38.85 3_MWD+IFR2+MS+Sag (1) 703.15 15.03 44.41 697.75 53.25 37.73638.42 6,027,943.12 534,181.33 3.79 -55.75 3_MWD+IFR2+MS+Sag (1) 798.35 19.25 45.61 788.70 73.05 57.59729.37 6,027,963.01 534,201.10 4.45 -76.89 3_MWD+IFR2+MS+Sag (1) 893.64 23.29 44.78 877.48 97.43 82.09818.15 6,027,987.49 534,225.49 4.25 -102.91 3_MWD+IFR2+MS+Sag (1) 988.12 26.50 43.16 963.17 126.07 109.68903.84 6,028,016.26 534,252.94 3.47 -133.41 3_MWD+IFR2+MS+Sag (1) 1,083.70 30.13 45.22 1,047.31 158.53 141.30987.98 6,028,048.86 534,284.41 3.93 -168.00 3_MWD+IFR2+MS+Sag (1) 5/15/2020 4:49:07PM COMPASS 5000.15 Build 91E Page 2 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt Moose Pad Halliburton Definitive Survey Report Well: Wellbore: MPU M-44i MPU M-44i Survey Calculation Method:Minimum Curvature MPU M-44 Actual RKB @ 59.33usft Design:MPU M-44i Database:NORTH US + CANADA MD Reference:MPU M-44 Actual RKB @ 59.33usft North Reference: Well MPU M-44i True MD (usft) Inc (°) Azi (°) +E/-W (usft) +N/-S (usft) Survey TVD (usft) TVDSS (usft) Map Northing (ft) Map Easting (ft) Vertical Section (ft) DLS (°/100')Survey Tool Name 1,178.77 34.95 45.58 1,127.43 194.42 177.711,068.10 6,028,084.91 534,320.65 5.07 -206.34 3_MWD+IFR2+MS+Sag (1) 1,273.92 39.37 45.93 1,203.24 234.50 218.881,143.91 6,028,125.18 534,361.63 4.65 -249.20 3_MWD+IFR2+MS+Sag (1) 1,369.36 43.45 46.50 1,274.80 278.17 264.451,215.47 6,028,169.05 534,406.99 4.29 -295.94 3_MWD+IFR2+MS+Sag (1) 1,464.03 44.92 47.21 1,342.69 323.28 312.601,283.36 6,028,214.38 534,454.93 1.64 -344.30 3_MWD+IFR2+MS+Sag (1) 1,559.03 43.09 45.19 1,411.02 368.94 360.241,351.69 6,028,260.26 534,502.35 2.43 -393.17 3_MWD+IFR2+MS+Sag (1) 1,654.30 44.79 43.71 1,479.62 416.14 406.521,420.29 6,028,307.66 534,548.41 2.08 -443.48 3_MWD+IFR2+MS+Sag (1) 1,749.54 44.74 44.19 1,547.24 464.42 453.061,487.91 6,028,356.15 534,594.73 0.36 -494.90 3_MWD+IFR2+MS+Sag (1) 1,844.89 45.90 44.48 1,614.29 512.92 500.451,554.96 6,028,404.86 534,641.89 1.24 -546.58 3_MWD+IFR2+MS+Sag (1) 1,939.87 46.78 43.97 1,679.86 562.16 548.371,620.53 6,028,454.31 534,689.58 1.00 -599.04 3_MWD+IFR2+MS+Sag (1) 2,035.55 44.58 43.85 1,746.70 611.47 595.841,687.37 6,028,503.84 534,736.82 2.30 -651.54 3_MWD+IFR2+MS+Sag (1) 2,130.94 44.89 44.53 1,814.46 659.61 642.641,755.13 6,028,552.19 534,783.39 0.60 -702.83 3_MWD+IFR2+MS+Sag (1) 2,225.53 46.38 44.56 1,880.60 707.80 690.071,821.27 6,028,600.59 534,830.60 1.58 -754.21 3_MWD+IFR2+MS+Sag (1) 2,322.03 48.10 45.07 1,946.12 758.06 740.011,886.79 6,028,651.07 534,880.30 1.82 -807.83 3_MWD+IFR2+MS+Sag (1) 2,417.72 48.95 46.22 2,009.49 808.17 791.281,950.16 6,028,701.42 534,931.33 1.26 -861.40 3_MWD+IFR2+MS+Sag (1) 2,512.37 49.04 47.02 2,071.60 857.23 843.192,012.27 6,028,750.71 534,983.01 0.64 -913.96 3_MWD+IFR2+MS+Sag (1) 2,607.52 48.44 47.53 2,134.34 905.76 895.732,075.01 6,028,799.47 535,035.33 0.75 -966.04 3_MWD+IFR2+MS+Sag (1) 2,701.79 48.18 48.42 2,197.04 952.89 948.032,137.71 6,028,846.84 535,087.40 0.76 -1,016.70 3_MWD+IFR2+MS+Sag (1) 2,796.44 47.70 47.29 2,260.45 1,000.04 1,000.132,201.12 6,028,894.22 535,139.28 1.02 -1,067.37 3_MWD+IFR2+MS+Sag (1) 2,891.72 48.19 51.85 2,324.29 1,045.89 1,053.962,264.96 6,028,940.31 535,192.90 3.59 -1,116.86 3_MWD+IFR2+MS+Sag (1) 2,986.81 48.35 56.66 2,387.61 1,087.32 1,111.532,328.28 6,028,982.00 535,250.27 3.78 -1,162.20 3_MWD+IFR2+MS+Sag (1) 3,082.15 47.17 61.08 2,451.72 1,123.81 1,171.912,392.39 6,029,018.77 535,310.47 3.65 -1,202.82 3_MWD+IFR2+MS+Sag (1) 3,178.44 46.37 65.36 2,517.68 1,155.42 1,234.502,458.35 6,029,050.66 535,372.91 3.34 -1,238.72 3_MWD+IFR2+MS+Sag (1) 3,272.15 44.46 70.19 2,583.48 1,180.69 1,296.232,524.15 6,029,076.22 535,434.52 4.20 -1,268.24 3_MWD+IFR2+MS+Sag (1) 3,368.21 42.99 77.09 2,652.94 1,199.42 1,359.842,593.61 6,029,095.24 535,498.04 5.19 -1,291.36 3_MWD+IFR2+MS+Sag (1) 3,462.88 41.06 82.58 2,723.28 1,210.66 1,422.162,663.95 6,029,106.75 535,560.30 4.38 -1,306.91 3_MWD+IFR2+MS+Sag (1) 3,558.30 43.46 88.96 2,793.93 1,215.30 1,486.092,734.60 6,029,111.69 535,624.20 5.15 -1,316.00 3_MWD+IFR2+MS+Sag (1) 3,653.25 44.23 93.89 2,862.43 1,213.65 1,551.802,803.10 6,029,110.34 535,689.91 3.69 -1,318.94 3_MWD+IFR2+MS+Sag (1) 3,748.29 45.77 99.80 2,929.66 1,205.60 1,618.452,870.33 6,029,102.60 535,756.59 4.68 -1,315.56 3_MWD+IFR2+MS+Sag (1) 3,843.40 47.18 103.43 2,995.17 1,191.69 1,685.972,935.84 6,029,089.00 535,824.17 3.14 -1,306.40 3_MWD+IFR2+MS+Sag (1) 3,938.76 46.08 108.34 3,060.68 1,172.76 1,752.613,001.35 6,029,070.37 535,890.89 3.92 -1,292.16 3_MWD+IFR2+MS+Sag (1) 4,033.96 46.44 114.32 3,126.53 1,147.75 1,816.623,067.20 6,029,045.67 535,955.01 4.55 -1,271.68 3_MWD+IFR2+MS+Sag (1) 4,129.38 47.08 120.50 3,191.93 1,115.76 1,878.263,132.60 6,029,013.96 536,016.79 4.76 -1,244.07 3_MWD+IFR2+MS+Sag (1) 4,224.49 49.43 127.07 3,255.29 1,076.28 1,937.143,195.96 6,028,974.76 536,075.84 5.71 -1,208.79 3_MWD+IFR2+MS+Sag (1) 4,319.79 51.78 131.54 3,315.79 1,029.62 1,994.063,256.46 6,028,928.36 536,132.97 4.38 -1,166.21 3_MWD+IFR2+MS+Sag (1) 4,415.53 54.75 137.13 3,373.07 975.99 2,048.853,313.74 6,028,874.99 536,188.00 5.61 -1,116.53 3_MWD+IFR2+MS+Sag (1) 4,510.49 58.00 139.13 3,425.65 917.10 2,101.593,366.32 6,028,816.35 536,241.00 3.85 -1,061.47 3_MWD+IFR2+MS+Sag (1) 4,605.78 60.16 141.40 3,474.62 854.24 2,153.833,415.29 6,028,753.73 536,293.52 3.05 -1,002.40 3_MWD+IFR2+MS+Sag (1) 4,700.71 63.41 144.75 3,519.51 787.37 2,204.043,460.18 6,028,687.10 536,344.03 4.62 -939.19 3_MWD+IFR2+MS+Sag (1) 4,795.86 65.13 147.60 3,560.82 716.16 2,251.733,501.49 6,028,616.12 536,392.05 3.25 -871.49 3_MWD+IFR2+MS+Sag (1) 4,890.79 68.35 150.90 3,598.31 641.22 2,296.283,538.98 6,028,541.39 536,436.94 4.66 -799.84 3_MWD+IFR2+MS+Sag (1) 5/15/2020 4:49:07PM COMPASS 5000.15 Build 91E Page 3 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt Moose Pad Halliburton Definitive Survey Report Well: Wellbore: MPU M-44i MPU M-44i Survey Calculation Method:Minimum Curvature MPU M-44 Actual RKB @ 59.33usft Design:MPU M-44i Database:NORTH US + CANADA MD Reference:MPU M-44 Actual RKB @ 59.33usft North Reference: Well MPU M-44i True MD (usft) Inc (°) Azi (°) +E/-W (usft) +N/-S (usft) Survey TVD (usft) TVDSS (usft) Map Northing (ft) Map Easting (ft) Vertical Section (ft) DLS (°/100')Survey Tool Name 4,986.15 68.30 153.95 3,633.54 562.68 2,337.303,574.21 6,028,463.05 536,478.31 2.97 -724.35 3_MWD+IFR2+MS+Sag (1) 5,081.62 70.79 156.90 3,666.91 481.34 2,374.473,607.58 6,028,381.89 536,515.85 3.90 -645.80 3_MWD+IFR2+MS+Sag (1) 5,176.70 73.22 158.43 3,696.28 397.70 2,408.833,636.95 6,028,298.42 536,550.59 2.98 -564.76 3_MWD+IFR2+MS+Sag (1) 5,271.57 77.57 160.29 3,720.20 311.81 2,441.163,660.87 6,028,212.68 536,583.32 4.96 -481.34 3_MWD+IFR2+MS+Sag (1) 5,366.43 80.54 161.89 3,738.21 223.71 2,471.343,678.88 6,028,124.73 536,613.89 3.54 -395.56 3_MWD+IFR2+MS+Sag (1) 5,462.31 81.61 164.84 3,753.08 132.97 2,498.453,693.75 6,028,034.12 536,641.41 3.24 -306.93 3_MWD+IFR2+MS+Sag (1) 5,557.08 81.85 167.57 3,766.72 41.90 2,520.813,707.39 6,027,943.17 536,664.19 2.86 -217.64 3_MWD+IFR2+MS+Sag (1) 5,653.12 81.85 167.67 3,780.33 -50.96 2,541.193,721.00 6,027,850.41 536,684.99 0.10 -126.43 3_MWD+IFR2+MS+Sag (1) 5,747.99 84.78 168.50 3,791.38 -143.15 2,560.643,732.05 6,027,758.32 536,704.86 3.21 -35.82 3_MWD+IFR2+MS+Sag (1) 5,842.25 86.06 168.61 3,798.90 -235.23 2,579.283,739.57 6,027,666.33 536,723.93 1.36 54.74 3_MWD+IFR2+MS+Sag (1) 5,879.80 87.05 168.10 3,801.16 -271.94 2,586.853,741.83 6,027,629.66 536,731.66 2.96 90.83 3_MWD+IFR2+MS+Sag (1) 5,951.52 90.44 169.95 3,802.73 -342.32 2,600.493,743.40 6,027,559.35 536,745.63 5.38 160.09 3_MWD+IFR2+MS+Sag (2) 6,014.86 90.75 169.89 3,802.07 -404.68 2,611.583,742.74 6,027,497.05 536,757.00 0.50 221.52 3_MWD+IFR2+MS+Sag (2) 6,110.44 91.25 170.82 3,800.40 -498.89 2,627.593,741.07 6,027,402.92 536,773.44 1.10 314.39 3_MWD+IFR2+MS+Sag (2) 6,206.10 90.50 169.98 3,798.94 -593.20 2,643.543,739.61 6,027,308.70 536,789.83 1.18 407.35 3_MWD+IFR2+MS+Sag (2) 6,300.78 91.06 168.37 3,797.65 -686.19 2,661.323,738.32 6,027,215.81 536,808.03 1.80 498.87 3_MWD+IFR2+MS+Sag (2) 6,395.99 90.94 169.24 3,795.99 -779.57 2,679.803,736.66 6,027,122.52 536,826.94 0.92 590.74 3_MWD+IFR2+MS+Sag (2) 6,491.38 90.75 170.54 3,794.59 -873.47 2,696.553,735.26 6,027,028.71 536,844.11 1.38 683.24 3_MWD+IFR2+MS+Sag (2) 6,587.06 89.45 168.59 3,794.42 -967.56 2,713.873,735.09 6,026,934.71 536,861.87 2.45 775.89 3_MWD+IFR2+MS+Sag (2) 6,681.44 90.63 168.09 3,794.35 -1,059.99 2,732.953,735.02 6,026,842.37 536,881.37 1.36 866.76 3_MWD+IFR2+MS+Sag (2) 6,776.66 90.75 167.76 3,793.21 -1,153.09 2,752.873,733.88 6,026,749.37 536,901.71 0.37 958.25 3_MWD+IFR2+MS+Sag (2) 6,872.10 89.27 165.43 3,793.19 -1,245.92 2,774.993,733.86 6,026,656.65 536,924.26 2.89 1,049.32 3_MWD+IFR2+MS+Sag (2) 6,967.15 89.51 166.69 3,794.20 -1,338.17 2,797.893,734.87 6,026,564.52 536,947.57 1.35 1,139.74 3_MWD+IFR2+MS+Sag (2) 7,062.25 89.64 166.69 3,794.91 -1,430.71 2,819.783,735.58 6,026,472.09 536,969.89 0.14 1,230.53 3_MWD+IFR2+MS+Sag (2) 7,157.31 88.90 168.45 3,796.12 -1,523.53 2,840.243,736.79 6,026,379.37 536,990.77 2.01 1,321.69 3_MWD+IFR2+MS+Sag (2) 7,253.01 89.33 169.83 3,797.60 -1,617.50 2,858.273,738.27 6,026,285.50 537,009.23 1.51 1,414.18 3_MWD+IFR2+MS+Sag (2) 7,347.47 89.95 171.23 3,798.19 -1,710.67 2,873.813,738.86 6,026,192.41 537,025.20 1.62 1,506.04 3_MWD+IFR2+MS+Sag (2) 7,442.63 91.50 173.18 3,796.99 -1,804.94 2,886.713,737.66 6,026,098.21 537,038.53 2.62 1,599.17 3_MWD+IFR2+MS+Sag (2) 7,537.50 93.48 174.53 3,792.86 -1,899.17 2,896.863,733.53 6,026,004.04 537,049.11 2.53 1,692.46 3_MWD+IFR2+MS+Sag (2) 7,633.24 91.12 175.19 3,789.02 -1,994.44 2,905.433,729.69 6,025,908.82 537,058.11 2.56 1,786.91 3_MWD+IFR2+MS+Sag (2) 7,728.60 89.82 176.08 3,788.24 -2,089.51 2,912.683,728.91 6,025,813.79 537,065.81 1.65 1,881.24 3_MWD+IFR2+MS+Sag (2) 7,823.15 89.82 177.20 3,788.54 -2,183.90 2,918.233,729.21 6,025,719.44 537,071.78 1.18 1,975.01 3_MWD+IFR2+MS+Sag (2) 7,918.76 92.24 180.86 3,786.82 -2,279.46 2,919.843,727.49 6,025,623.90 537,073.84 4.59 2,070.23 3_MWD+IFR2+MS+Sag (2) 8,013.17 91.62 185.31 3,783.64 -2,373.65 2,914.773,724.31 6,025,529.69 537,069.20 4.76 2,164.55 3_MWD+IFR2+MS+Sag (2) 8,109.07 91.37 189.05 3,781.13 -2,468.75 2,902.793,721.80 6,025,434.54 537,057.65 3.91 2,260.25 3_MWD+IFR2+MS+Sag (2) 8,203.38 93.29 190.74 3,777.30 -2,561.57 2,886.603,717.97 6,025,341.66 537,041.89 2.71 2,353.97 3_MWD+IFR2+MS+Sag (2) 8,298.64 93.04 189.96 3,772.04 -2,655.14 2,869.513,712.71 6,025,248.02 537,025.23 0.86 2,448.50 3_MWD+IFR2+MS+Sag (2) 8,393.66 92.23 188.74 3,767.67 -2,748.80 2,854.093,708.34 6,025,154.31 537,010.24 1.54 2,543.01 3_MWD+IFR2+MS+Sag (2) 8,488.49 92.23 188.37 3,763.98 -2,842.50 2,839.993,704.65 6,025,060.55 536,996.58 0.39 2,637.47 3_MWD+IFR2+MS+Sag (2) 8,584.79 91.74 188.49 3,760.65 -2,937.70 2,825.883,701.32 6,024,965.29 536,982.91 0.52 2,733.42 3_MWD+IFR2+MS+Sag (2) 5/15/2020 4:49:07PM COMPASS 5000.15 Build 91E Page 4 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt Moose Pad Halliburton Definitive Survey Report Well: Wellbore: MPU M-44i MPU M-44i Survey Calculation Method:Minimum Curvature MPU M-44 Actual RKB @ 59.33usft Design:MPU M-44i Database:NORTH US + CANADA MD Reference:MPU M-44 Actual RKB @ 59.33usft North Reference: Well MPU M-44i True MD (usft) Inc (°) Azi (°) +E/-W (usft) +N/-S (usft) Survey TVD (usft) TVDSS (usft) Map Northing (ft) Map Easting (ft) Vertical Section (ft) DLS (°/100')Survey Tool Name 8,679.19 90.50 187.19 3,758.80 -3,031.20 2,813.013,699.47 6,024,871.75 536,970.47 1.90 2,827.59 3_MWD+IFR2+MS+Sag (2) 8,773.83 91.50 188.08 3,757.15 -3,124.98 2,800.443,697.82 6,024,777.92 536,958.33 1.41 2,922.02 3_MWD+IFR2+MS+Sag (2) 8,869.71 91.74 189.36 3,754.44 -3,219.71 2,785.913,695.11 6,024,683.13 536,944.23 1.36 3,017.54 3_MWD+IFR2+MS+Sag (2) 8,963.40 91.99 189.63 3,751.39 -3,312.07 2,770.463,692.06 6,024,590.71 536,929.21 0.39 3,110.75 3_MWD+IFR2+MS+Sag (2) 9,060.03 91.92 189.74 3,748.09 -3,407.27 2,754.213,688.76 6,024,495.45 536,913.40 0.13 3,206.84 3_MWD+IFR2+MS+Sag (2) 9,154.50 92.61 189.11 3,744.36 -3,500.39 2,738.763,685.03 6,024,402.27 536,898.38 0.99 3,300.82 3_MWD+IFR2+MS+Sag (2) 9,250.24 92.05 187.17 3,740.47 -3,595.08 2,725.213,681.14 6,024,307.52 536,885.27 2.11 3,396.22 3_MWD+IFR2+MS+Sag (2) 9,345.99 91.99 184.77 3,737.09 -3,690.25 2,715.263,677.76 6,024,212.32 536,875.75 2.51 3,491.85 3_MWD+IFR2+MS+Sag (2) 9,405.00 91.46 184.03 3,735.31 -3,749.05 2,710.733,675.98 6,024,153.50 536,871.50 1.54 3,550.83 3_MWD+IFR2+MS+Sag (3) 9,437.72 91.00 183.62 3,734.61 -3,781.69 2,708.553,675.28 6,024,120.85 536,869.47 1.88 3,583.54 3_MWD+IFR2+MS+Sag (3) 9,535.66 91.55 184.90 3,732.43 -3,879.34 2,701.283,673.10 6,024,023.19 536,862.64 1.42 3,681.46 3_MWD+IFR2+MS+Sag (3) 9,631.11 93.41 186.81 3,728.30 -3,974.19 2,691.553,668.97 6,023,928.30 536,853.35 2.79 3,776.76 3_MWD+IFR2+MS+Sag (3) 9,725.95 92.23 186.65 3,723.64 -4,068.26 2,680.453,664.31 6,023,834.19 536,842.69 1.26 3,871.37 3_MWD+IFR2+MS+Sag (3) 9,819.42 91.43 186.92 3,720.65 -4,161.03 2,669.423,661.32 6,023,741.38 536,832.08 0.90 3,964.68 3_MWD+IFR2+MS+Sag (3) 9,914.64 92.91 186.07 3,717.05 -4,255.57 2,658.653,657.72 6,023,646.80 536,821.75 1.79 4,059.74 3_MWD+IFR2+MS+Sag (3) 10,011.63 93.47 185.67 3,711.65 -4,351.90 2,648.753,652.32 6,023,550.44 536,812.29 0.71 4,156.53 3_MWD+IFR2+MS+Sag (3) 10,106.79 92.60 185.55 3,706.61 -4,446.47 2,639.463,647.28 6,023,455.83 536,803.43 0.92 4,251.52 3_MWD+IFR2+MS+Sag (3) 10,201.70 91.49 184.58 3,703.22 -4,540.95 2,631.093,643.89 6,023,361.33 536,795.49 1.55 4,346.35 3_MWD+IFR2+MS+Sag (3) 10,296.04 92.80 185.47 3,699.69 -4,634.85 2,622.833,640.36 6,023,267.39 536,787.67 1.68 4,440.60 3_MWD+IFR2+MS+Sag (3) 10,392.55 91.55 184.70 3,696.03 -4,730.91 2,614.283,636.70 6,023,171.31 536,779.56 1.52 4,537.02 3_MWD+IFR2+MS+Sag (3) 10,486.87 91.12 182.11 3,693.83 -4,825.03 2,608.683,634.50 6,023,077.17 536,774.40 2.78 4,631.31 3_MWD+IFR2+MS+Sag (3) 10,583.17 92.55 181.26 3,690.75 -4,921.24 2,605.853,631.42 6,022,980.96 536,772.01 1.73 4,727.47 3_MWD+IFR2+MS+Sag (3) 10,677.77 90.87 180.48 3,687.93 -5,015.78 2,604.423,628.60 6,022,886.42 536,771.01 1.96 4,821.89 3_MWD+IFR2+MS+Sag (3) 10,773.55 93.04 180.36 3,684.66 -5,111.50 2,603.713,625.33 6,022,790.71 536,770.74 2.27 4,917.42 3_MWD+IFR2+MS+Sag (3) 10,868.29 93.10 181.54 3,679.58 -5,206.09 2,602.153,620.25 6,022,696.13 536,769.61 1.25 5,011.89 3_MWD+IFR2+MS+Sag (3) 10,963.67 92.36 183.23 3,675.04 -5,301.27 2,598.183,615.71 6,022,600.94 536,766.08 1.93 5,107.12 3_MWD+IFR2+MS+Sag (3) 11,055.67 91.99 185.01 3,671.55 -5,392.96 2,591.583,612.22 6,022,509.22 536,759.90 1.97 5,199.05 3_MWD+IFR2+MS+Sag (3) 11,152.04 91.80 185.12 3,668.36 -5,488.90 2,583.073,609.03 6,022,413.25 536,751.84 0.23 5,295.35 3_MWD+IFR2+MS+Sag (3) 11,248.37 91.86 182.55 3,665.29 -5,584.96 2,576.633,605.96 6,022,317.18 536,745.84 2.67 5,391.62 3_MWD+IFR2+MS+Sag (3) 11,339.70 92.49 182.39 3,661.82 -5,676.14 2,572.703,602.49 6,022,225.99 536,742.33 0.71 5,482.85 3_MWD+IFR2+MS+Sag (3) 11,438.86 90.13 181.74 3,659.55 -5,775.20 2,569.133,600.22 6,022,126.92 536,739.21 2.47 5,581.92 3_MWD+IFR2+MS+Sag (3) 11,535.13 89.57 182.31 3,659.81 -5,871.41 2,565.733,600.48 6,022,030.71 536,736.25 0.83 5,678.13 3_MWD+IFR2+MS+Sag (3) 11,632.05 93.91 184.00 3,656.86 -5,968.11 2,560.403,597.53 6,021,933.99 536,731.37 4.80 5,774.97 3_MWD+IFR2+MS+Sag (3) 11,724.87 94.28 183.84 3,650.23 -6,060.48 2,554.073,590.90 6,021,841.61 536,725.46 0.43 5,867.55 3_MWD+IFR2+MS+Sag (3) 11,819.51 94.09 182.69 3,643.33 -6,154.71 2,548.693,584.00 6,021,747.36 536,720.52 1.23 5,961.93 3_MWD+IFR2+MS+Sag (3) 11,915.32 93.84 182.10 3,636.70 -6,250.21 2,544.703,577.37 6,021,651.86 536,716.96 0.67 6,057.47 3_MWD+IFR2+MS+Sag (3) 12,010.61 95.70 182.10 3,628.78 -6,345.10 2,541.223,569.45 6,021,556.96 536,713.92 1.95 6,152.38 3_MWD+IFR2+MS+Sag (3) 12,104.77 94.21 182.30 3,620.65 -6,438.84 2,537.623,561.32 6,021,463.22 536,710.75 1.60 6,246.14 3_MWD+IFR2+MS+Sag (3) 12,200.91 93.41 182.16 3,614.26 -6,534.69 2,533.893,554.93 6,021,367.35 536,707.46 0.84 6,342.02 3_MWD+IFR2+MS+Sag (3) 12,294.98 91.98 182.28 3,609.84 -6,628.58 2,530.253,550.51 6,021,273.46 536,704.25 1.53 6,435.94 3_MWD+IFR2+MS+Sag (3) 5/15/2020 4:49:07PM COMPASS 5000.15 Build 91E Page 5 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt Moose Pad Halliburton Definitive Survey Report Well: Wellbore: MPU M-44i MPU M-44i Survey Calculation Method:Minimum Curvature MPU M-44 Actual RKB @ 59.33usft Design:MPU M-44i Database:NORTH US + CANADA MD Reference:MPU M-44 Actual RKB @ 59.33usft North Reference: Well MPU M-44i True MD (usft) Inc (°) Azi (°) +E/-W (usft) +N/-S (usft) Survey TVD (usft) TVDSS (usft) Map Northing (ft) Map Easting (ft) Vertical Section (ft) DLS (°/100')Survey Tool Name 12,390.70 92.61 183.73 3,606.00 -6,724.09 2,525.233,546.67 6,021,177.93 536,699.67 1.65 6,531.56 3_MWD+IFR2+MS+Sag (3) 12,486.11 92.35 185.12 3,601.87 -6,819.13 2,517.883,542.54 6,021,082.88 536,692.76 1.48 6,626.88 3_MWD+IFR2+MS+Sag (3) 12,580.63 91.99 184.14 3,598.29 -6,913.27 2,510.253,538.96 6,020,988.71 536,685.57 1.10 6,721.32 3_MWD+IFR2+MS+Sag (3) 12,675.78 91.55 184.17 3,595.36 -7,008.12 2,503.363,536.03 6,020,893.83 536,679.11 0.46 6,816.43 3_MWD+IFR2+MS+Sag (3) 12,771.63 91.99 183.96 3,592.39 -7,103.69 2,496.573,533.06 6,020,798.25 536,672.76 0.51 6,912.23 3_MWD+IFR2+MS+Sag (3) 12,866.75 92.11 183.04 3,588.99 -7,198.57 2,490.773,529.66 6,020,703.35 536,667.39 0.97 7,007.29 3_MWD+IFR2+MS+Sag (3) 12,961.23 93.79 183.71 3,584.13 -7,292.76 2,485.213,524.80 6,020,609.15 536,662.27 1.91 7,101.63 3_MWD+IFR2+MS+Sag (3) 13,056.02 92.85 184.03 3,578.64 -7,387.17 2,478.833,519.31 6,020,514.72 536,656.32 1.05 7,196.26 3_MWD+IFR2+MS+Sag (3) 13,116.63 92.36 185.89 3,575.89 -7,447.49 2,473.593,516.56 6,020,454.38 536,651.36 3.17 7,256.80 3_MWD+IFR2+MS+Sag (3) 13,194.00 92.36 185.89 3,572.70 -7,524.38 2,465.663,513.37 6,020,377.46 536,643.78 0.00 7,334.06 PROJECTED to TD Approved By:Checked By:Date: 5/15/2020 4:49:07PM COMPASS 5000.15 Build 91E Page 6 Chelsea Wright Digitally signed by Chelsea Wright Date: 2020.05.15 13:52:10 -08'00' Benjamin Hand Digitally signed by Benjamin Hand Date: 2020.05.15 14:51:18 -08'00' 15 May, 2020 Milne Point M Pt Moose Pad MPU M-44PB1 500292367370 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt Moose Pad Halliburton Definitive Survey Report Well: Wellbore: MPU M-44i MPU M-44PB1 Survey Calculation Method:Minimum Curvature MPU M-44 Actual RKB @ 59.33usft Design:MPU M-44PB1 Database:NORTH US + CANADA MD Reference:MPU M-44 Actual RKB @ 59.33usft North Reference: Well MPU M-44i True Map System: Geo Datum: Project Map Zone: System Datum:US State Plane 1927 (Exact solution) NAD 1927 (NADCON CONUS) Milne Point, ACT, MILNE POINT Alaska Zone 04 Mean Sea Level Using Well Reference Point Using geodetic scale factor Well Well Position Longitude: Latitude: Easting: Northing: usft +E/-W +N/-S Position Uncertainty usft usft usftGround Level: MPU M-44i, Slot 58 usft usft 0.00 0.00 6,027,889.70 534,143.85 25.10Wellhead Elevation:25.40 usft0.50 70° 29' 13.989 N 149° 43' 15.335 W Wellbore Declination (°) Field Strength (nT) Sample Date Dip Angle (°) MPU M-44PB1 Model NameMagnetics IFR 4/10/2020 15.98 80.92 57,387.00000000 Phase:Version: Audit Notes: Design MPU M-44PB1 1.0 ACTUAL Vertical Section: Depth From (TVD) (usft) +N/-S (usft) Direction (°) +E/-W (usft) Tie On Depth:33.93 184.000.000.0033.93 From (usft) Survey Program DescriptionTool NameSurvey (Wellbore) To (usft) Date 5/11/2020 Survey Date 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sa181.69 5,879.80 MPU M-44PB1 MWD+IFR2+MS+Sag (M 03/26/2020 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sa5,951.52 10,323.36 MPU M-44PB1 MWD+IFR2+MS+Sag (2) 05/08/2020 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 33.93 0.00 0.00 33.93 0.00 0.00-25.40 6,027,889.70 534,143.85 0.00 0.00 UNDEFINED 181.69 0.92 33.10 181.68 0.99 0.65122.35 6,027,890.70 534,144.49 0.62 -1.04 3_MWD+IFR2+MS+Sag (1) 228.75 1.09 35.54 228.74 1.67 1.11169.41 6,027,891.38 534,144.96 0.37 -1.75 3_MWD+IFR2+MS+Sag (1) 322.76 3.76 26.88 322.65 5.15 3.03263.32 6,027,894.87 534,146.85 2.86 -5.35 3_MWD+IFR2+MS+Sag (1) 419.43 6.45 26.36 418.93 12.85 6.87359.60 6,027,902.58 534,150.66 2.78 -13.29 3_MWD+IFR2+MS+Sag (1) 517.30 8.80 33.66 515.93 24.00 13.46456.60 6,027,913.76 534,157.20 2.59 -24.89 3_MWD+IFR2+MS+Sag (1) 610.40 11.75 38.94 607.53 37.31 23.37548.20 6,027,927.11 534,167.05 3.32 -38.85 3_MWD+IFR2+MS+Sag (1) 703.15 15.03 44.41 697.75 53.25 37.73638.42 6,027,943.12 534,181.33 3.79 -55.75 3_MWD+IFR2+MS+Sag (1) 798.35 19.25 45.61 788.70 73.05 57.59729.37 6,027,963.01 534,201.10 4.45 -76.89 3_MWD+IFR2+MS+Sag (1) 893.64 23.29 44.78 877.48 97.43 82.09818.15 6,027,987.49 534,225.49 4.25 -102.91 3_MWD+IFR2+MS+Sag (1) 988.12 26.50 43.16 963.17 126.07 109.68903.84 6,028,016.26 534,252.94 3.47 -133.41 3_MWD+IFR2+MS+Sag (1) 1,083.70 30.13 45.22 1,047.31 158.53 141.30987.98 6,028,048.86 534,284.41 3.93 -168.00 3_MWD+IFR2+MS+Sag (1) 1,178.77 34.95 45.58 1,127.43 194.42 177.711,068.10 6,028,084.91 534,320.65 5.07 -206.34 3_MWD+IFR2+MS+Sag (1) 5/15/2020 4:50:09PM COMPASS 5000.15 Build 91E Page 2 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt Moose Pad Halliburton Definitive Survey Report Well: Wellbore: MPU M-44i MPU M-44PB1 Survey Calculation Method:Minimum Curvature MPU M-44 Actual RKB @ 59.33usft Design:MPU M-44PB1 Database:NORTH US + CANADA MD Reference:MPU M-44 Actual RKB @ 59.33usft North Reference: Well MPU M-44i True MD (usft) Inc (°) Azi (°) +E/-W (usft) +N/-S (usft) Survey TVD (usft) TVDSS (usft) Map Northing (ft) Map Easting (ft) Vertical Section (ft) DLS (°/100')Survey Tool Name 1,273.92 39.37 45.93 1,203.24 234.50 218.881,143.91 6,028,125.18 534,361.63 4.65 -249.20 3_MWD+IFR2+MS+Sag (1) 1,369.36 43.45 46.50 1,274.80 278.17 264.451,215.47 6,028,169.05 534,406.99 4.29 -295.94 3_MWD+IFR2+MS+Sag (1) 1,464.03 44.92 47.21 1,342.69 323.28 312.601,283.36 6,028,214.38 534,454.93 1.64 -344.30 3_MWD+IFR2+MS+Sag (1) 1,559.03 43.09 45.19 1,411.02 368.94 360.241,351.69 6,028,260.26 534,502.35 2.43 -393.17 3_MWD+IFR2+MS+Sag (1) 1,654.30 44.79 43.71 1,479.62 416.14 406.521,420.29 6,028,307.66 534,548.41 2.08 -443.48 3_MWD+IFR2+MS+Sag (1) 1,749.54 44.74 44.19 1,547.24 464.42 453.061,487.91 6,028,356.15 534,594.73 0.36 -494.90 3_MWD+IFR2+MS+Sag (1) 1,844.89 45.90 44.48 1,614.29 512.92 500.451,554.96 6,028,404.86 534,641.89 1.24 -546.58 3_MWD+IFR2+MS+Sag (1) 1,939.87 46.78 43.97 1,679.86 562.16 548.371,620.53 6,028,454.31 534,689.58 1.00 -599.04 3_MWD+IFR2+MS+Sag (1) 2,035.55 44.58 43.85 1,746.70 611.47 595.841,687.37 6,028,503.84 534,736.82 2.30 -651.54 3_MWD+IFR2+MS+Sag (1) 2,130.94 44.89 44.53 1,814.46 659.61 642.641,755.13 6,028,552.19 534,783.39 0.60 -702.83 3_MWD+IFR2+MS+Sag (1) 2,225.53 46.38 44.56 1,880.60 707.80 690.071,821.27 6,028,600.59 534,830.60 1.58 -754.21 3_MWD+IFR2+MS+Sag (1) 2,322.03 48.10 45.07 1,946.12 758.06 740.011,886.79 6,028,651.07 534,880.30 1.82 -807.83 3_MWD+IFR2+MS+Sag (1) 2,417.72 48.95 46.22 2,009.49 808.17 791.281,950.16 6,028,701.42 534,931.33 1.26 -861.40 3_MWD+IFR2+MS+Sag (1) 2,512.37 49.04 47.02 2,071.60 857.23 843.192,012.27 6,028,750.71 534,983.01 0.64 -913.96 3_MWD+IFR2+MS+Sag (1) 2,607.52 48.44 47.53 2,134.34 905.76 895.732,075.01 6,028,799.47 535,035.33 0.75 -966.04 3_MWD+IFR2+MS+Sag (1) 2,701.79 48.18 48.42 2,197.04 952.89 948.032,137.71 6,028,846.84 535,087.40 0.76 -1,016.70 3_MWD+IFR2+MS+Sag (1) 2,796.44 47.70 47.29 2,260.45 1,000.04 1,000.132,201.12 6,028,894.22 535,139.28 1.02 -1,067.37 3_MWD+IFR2+MS+Sag (1) 2,891.72 48.19 51.85 2,324.29 1,045.89 1,053.962,264.96 6,028,940.31 535,192.90 3.59 -1,116.86 3_MWD+IFR2+MS+Sag (1) 2,986.81 48.35 56.66 2,387.61 1,087.32 1,111.532,328.28 6,028,982.00 535,250.27 3.78 -1,162.20 3_MWD+IFR2+MS+Sag (1) 3,082.15 47.17 61.08 2,451.72 1,123.81 1,171.912,392.39 6,029,018.77 535,310.47 3.65 -1,202.82 3_MWD+IFR2+MS+Sag (1) 3,178.44 46.37 65.36 2,517.68 1,155.42 1,234.502,458.35 6,029,050.66 535,372.91 3.34 -1,238.72 3_MWD+IFR2+MS+Sag (1) 3,272.15 44.46 70.19 2,583.48 1,180.69 1,296.232,524.15 6,029,076.22 535,434.52 4.20 -1,268.24 3_MWD+IFR2+MS+Sag (1) 3,368.21 42.99 77.09 2,652.94 1,199.42 1,359.842,593.61 6,029,095.24 535,498.04 5.19 -1,291.36 3_MWD+IFR2+MS+Sag (1) 3,462.88 41.06 82.58 2,723.28 1,210.66 1,422.162,663.95 6,029,106.75 535,560.30 4.38 -1,306.91 3_MWD+IFR2+MS+Sag (1) 3,558.30 43.46 88.96 2,793.93 1,215.30 1,486.092,734.60 6,029,111.69 535,624.20 5.15 -1,316.00 3_MWD+IFR2+MS+Sag (1) 3,653.25 44.23 93.89 2,862.43 1,213.65 1,551.802,803.10 6,029,110.34 535,689.91 3.69 -1,318.94 3_MWD+IFR2+MS+Sag (1) 3,748.29 45.77 99.80 2,929.66 1,205.60 1,618.452,870.33 6,029,102.60 535,756.59 4.68 -1,315.56 3_MWD+IFR2+MS+Sag (1) 3,843.40 47.18 103.43 2,995.17 1,191.69 1,685.972,935.84 6,029,089.00 535,824.17 3.14 -1,306.40 3_MWD+IFR2+MS+Sag (1) 3,938.76 46.08 108.34 3,060.68 1,172.76 1,752.613,001.35 6,029,070.37 535,890.89 3.92 -1,292.16 3_MWD+IFR2+MS+Sag (1) 4,033.96 46.44 114.32 3,126.53 1,147.75 1,816.623,067.20 6,029,045.67 535,955.01 4.55 -1,271.68 3_MWD+IFR2+MS+Sag (1) 4,129.38 47.08 120.50 3,191.93 1,115.76 1,878.263,132.60 6,029,013.96 536,016.79 4.76 -1,244.07 3_MWD+IFR2+MS+Sag (1) 4,224.49 49.43 127.07 3,255.29 1,076.28 1,937.143,195.96 6,028,974.76 536,075.84 5.71 -1,208.79 3_MWD+IFR2+MS+Sag (1) 4,319.79 51.78 131.54 3,315.79 1,029.62 1,994.063,256.46 6,028,928.36 536,132.97 4.38 -1,166.21 3_MWD+IFR2+MS+Sag (1) 4,415.53 54.75 137.13 3,373.07 975.99 2,048.853,313.74 6,028,874.99 536,188.00 5.61 -1,116.53 3_MWD+IFR2+MS+Sag (1) 4,510.49 58.00 139.13 3,425.65 917.10 2,101.593,366.32 6,028,816.35 536,241.00 3.85 -1,061.47 3_MWD+IFR2+MS+Sag (1) 4,605.78 60.16 141.40 3,474.62 854.24 2,153.833,415.29 6,028,753.73 536,293.52 3.05 -1,002.40 3_MWD+IFR2+MS+Sag (1) 4,700.71 63.41 144.75 3,519.51 787.37 2,204.043,460.18 6,028,687.10 536,344.03 4.62 -939.19 3_MWD+IFR2+MS+Sag (1) 4,795.86 65.13 147.60 3,560.82 716.16 2,251.733,501.49 6,028,616.12 536,392.05 3.25 -871.49 3_MWD+IFR2+MS+Sag (1) 4,890.79 68.35 150.90 3,598.31 641.22 2,296.283,538.98 6,028,541.39 536,436.94 4.66 -799.84 3_MWD+IFR2+MS+Sag (1) 4,986.15 68.30 153.95 3,633.54 562.68 2,337.303,574.21 6,028,463.05 536,478.31 2.97 -724.35 3_MWD+IFR2+MS+Sag (1) 5/15/2020 4:50:09PM COMPASS 5000.15 Build 91E Page 3 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt Moose Pad Halliburton Definitive Survey Report Well: Wellbore: MPU M-44i MPU M-44PB1 Survey Calculation Method:Minimum Curvature MPU M-44 Actual RKB @ 59.33usft Design:MPU M-44PB1 Database:NORTH US + CANADA MD Reference:MPU M-44 Actual RKB @ 59.33usft North Reference: Well MPU M-44i 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 5,081.62 70.79 156.90 3,666.91 481.34 2,374.473,607.58 6,028,381.89 536,515.85 3.90 -645.80 3_MWD+IFR2+MS+Sag (1) 5,176.70 73.22 158.43 3,696.28 397.70 2,408.833,636.95 6,028,298.42 536,550.59 2.98 -564.76 3_MWD+IFR2+MS+Sag (1) 5,271.57 77.57 160.29 3,720.20 311.81 2,441.163,660.87 6,028,212.68 536,583.32 4.96 -481.34 3_MWD+IFR2+MS+Sag (1) 5,366.43 80.54 161.89 3,738.21 223.71 2,471.343,678.88 6,028,124.73 536,613.89 3.54 -395.56 3_MWD+IFR2+MS+Sag (1) 5,462.31 81.61 164.84 3,753.08 132.97 2,498.453,693.75 6,028,034.12 536,641.41 3.24 -306.93 3_MWD+IFR2+MS+Sag (1) 5,557.08 81.85 167.57 3,766.72 41.90 2,520.813,707.39 6,027,943.17 536,664.19 2.86 -217.64 3_MWD+IFR2+MS+Sag (1) 5,653.12 81.85 167.67 3,780.33 -50.96 2,541.193,721.00 6,027,850.41 536,684.99 0.10 -126.43 3_MWD+IFR2+MS+Sag (1) 5,747.99 84.78 168.50 3,791.38 -143.15 2,560.643,732.05 6,027,758.32 536,704.86 3.21 -35.82 3_MWD+IFR2+MS+Sag (1) 5,842.25 86.06 168.61 3,798.90 -235.23 2,579.283,739.57 6,027,666.33 536,723.93 1.36 54.74 3_MWD+IFR2+MS+Sag (1) 5,879.80 87.05 168.10 3,801.16 -271.94 2,586.853,741.83 6,027,629.66 536,731.66 2.96 90.83 3_MWD+IFR2+MS+Sag (1) 5,951.52 90.44 169.95 3,802.73 -342.32 2,600.493,743.40 6,027,559.35 536,745.63 5.38 160.09 3_MWD+IFR2+MS+Sag (2) 6,014.86 90.75 169.89 3,802.07 -404.68 2,611.583,742.74 6,027,497.05 536,757.00 0.50 221.52 3_MWD+IFR2+MS+Sag (2) 6,110.44 91.25 170.82 3,800.40 -498.89 2,627.593,741.07 6,027,402.92 536,773.44 1.10 314.39 3_MWD+IFR2+MS+Sag (2) 6,206.10 90.50 169.98 3,798.94 -593.20 2,643.543,739.61 6,027,308.70 536,789.83 1.18 407.35 3_MWD+IFR2+MS+Sag (2) 6,300.78 91.06 168.37 3,797.65 -686.19 2,661.323,738.32 6,027,215.81 536,808.03 1.80 498.87 3_MWD+IFR2+MS+Sag (2) 6,395.99 90.94 169.24 3,795.99 -779.57 2,679.803,736.66 6,027,122.52 536,826.94 0.92 590.74 3_MWD+IFR2+MS+Sag (2) 6,491.38 90.75 170.54 3,794.59 -873.47 2,696.553,735.26 6,027,028.71 536,844.11 1.38 683.24 3_MWD+IFR2+MS+Sag (2) 6,587.06 89.45 168.59 3,794.42 -967.56 2,713.873,735.09 6,026,934.71 536,861.87 2.45 775.89 3_MWD+IFR2+MS+Sag (2) 6,681.44 90.63 168.09 3,794.35 -1,059.99 2,732.953,735.02 6,026,842.37 536,881.37 1.36 866.76 3_MWD+IFR2+MS+Sag (2) 6,776.66 90.75 167.76 3,793.21 -1,153.09 2,752.873,733.88 6,026,749.37 536,901.71 0.37 958.25 3_MWD+IFR2+MS+Sag (2) 6,872.10 89.27 165.43 3,793.19 -1,245.92 2,774.993,733.86 6,026,656.65 536,924.26 2.89 1,049.32 3_MWD+IFR2+MS+Sag (2) 6,967.15 89.51 166.69 3,794.20 -1,338.17 2,797.893,734.87 6,026,564.52 536,947.57 1.35 1,139.74 3_MWD+IFR2+MS+Sag (2) 7,062.25 89.64 166.69 3,794.91 -1,430.71 2,819.783,735.58 6,026,472.09 536,969.89 0.14 1,230.53 3_MWD+IFR2+MS+Sag (2) 7,157.31 88.90 168.45 3,796.12 -1,523.53 2,840.243,736.79 6,026,379.37 536,990.77 2.01 1,321.69 3_MWD+IFR2+MS+Sag (2) 7,253.01 89.33 169.83 3,797.60 -1,617.50 2,858.273,738.27 6,026,285.50 537,009.23 1.51 1,414.18 3_MWD+IFR2+MS+Sag (2) 7,347.47 89.95 171.23 3,798.19 -1,710.67 2,873.813,738.86 6,026,192.41 537,025.20 1.62 1,506.04 3_MWD+IFR2+MS+Sag (2) 7,442.63 91.50 173.18 3,796.99 -1,804.94 2,886.713,737.66 6,026,098.21 537,038.53 2.62 1,599.17 3_MWD+IFR2+MS+Sag (2) 7,537.50 93.48 174.53 3,792.86 -1,899.17 2,896.863,733.53 6,026,004.04 537,049.11 2.53 1,692.46 3_MWD+IFR2+MS+Sag (2) 7,633.24 91.12 175.19 3,789.02 -1,994.44 2,905.433,729.69 6,025,908.82 537,058.11 2.56 1,786.91 3_MWD+IFR2+MS+Sag (2) 7,728.60 89.82 176.08 3,788.24 -2,089.51 2,912.683,728.91 6,025,813.79 537,065.81 1.65 1,881.24 3_MWD+IFR2+MS+Sag (2) 7,823.15 89.82 177.20 3,788.54 -2,183.90 2,918.233,729.21 6,025,719.44 537,071.78 1.18 1,975.01 3_MWD+IFR2+MS+Sag (2) 7,918.76 92.24 180.86 3,786.82 -2,279.46 2,919.843,727.49 6,025,623.90 537,073.84 4.59 2,070.23 3_MWD+IFR2+MS+Sag (2) 8,013.17 91.62 185.31 3,783.64 -2,373.65 2,914.773,724.31 6,025,529.69 537,069.20 4.76 2,164.55 3_MWD+IFR2+MS+Sag (2) 8,109.07 91.37 189.05 3,781.13 -2,468.75 2,902.793,721.80 6,025,434.54 537,057.65 3.91 2,260.25 3_MWD+IFR2+MS+Sag (2) 8,203.38 93.29 190.74 3,777.30 -2,561.57 2,886.603,717.97 6,025,341.66 537,041.89 2.71 2,353.97 3_MWD+IFR2+MS+Sag (2) 8,298.64 93.04 189.96 3,772.04 -2,655.14 2,869.513,712.71 6,025,248.02 537,025.23 0.86 2,448.50 3_MWD+IFR2+MS+Sag (2) 8,393.66 92.23 188.74 3,767.67 -2,748.80 2,854.093,708.34 6,025,154.31 537,010.24 1.54 2,543.01 3_MWD+IFR2+MS+Sag (2) 8,488.49 92.23 188.37 3,763.98 -2,842.50 2,839.993,704.65 6,025,060.55 536,996.58 0.39 2,637.47 3_MWD+IFR2+MS+Sag (2) 8,584.79 91.74 188.49 3,760.65 -2,937.70 2,825.883,701.32 6,024,965.29 536,982.91 0.52 2,733.42 3_MWD+IFR2+MS+Sag (2) 8,679.19 90.50 187.19 3,758.80 -3,031.20 2,813.013,699.47 6,024,871.75 536,970.47 1.90 2,827.59 3_MWD+IFR2+MS+Sag (2) 5/15/2020 4:50:09PM COMPASS 5000.15 Build 91E Page 4 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt Moose Pad Halliburton Definitive Survey Report Well: Wellbore: MPU M-44i MPU M-44PB1 Survey Calculation Method:Minimum Curvature MPU M-44 Actual RKB @ 59.33usft Design:MPU M-44PB1 Database:NORTH US + CANADA MD Reference:MPU M-44 Actual RKB @ 59.33usft North Reference: Well MPU M-44i True MD (usft) Inc (°) Azi (°) +E/-W (usft) +N/-S (usft) Survey TVD (usft) TVDSS (usft) Map Northing (ft) Map Easting (ft) Vertical Section (ft) DLS (°/100')Survey Tool Name 8,773.83 91.50 188.08 3,757.15 -3,124.98 2,800.443,697.82 6,024,777.92 536,958.33 1.41 2,922.02 3_MWD+IFR2+MS+Sag (2) 8,869.71 91.74 189.36 3,754.44 -3,219.71 2,785.913,695.11 6,024,683.13 536,944.23 1.36 3,017.54 3_MWD+IFR2+MS+Sag (2) 8,963.40 91.99 189.63 3,751.39 -3,312.07 2,770.463,692.06 6,024,590.71 536,929.21 0.39 3,110.75 3_MWD+IFR2+MS+Sag (2) 9,060.03 91.92 189.74 3,748.09 -3,407.27 2,754.213,688.76 6,024,495.45 536,913.40 0.13 3,206.84 3_MWD+IFR2+MS+Sag (2) 9,154.50 92.61 189.11 3,744.36 -3,500.39 2,738.763,685.03 6,024,402.27 536,898.38 0.99 3,300.82 3_MWD+IFR2+MS+Sag (2) 9,250.24 92.05 187.17 3,740.47 -3,595.08 2,725.213,681.14 6,024,307.52 536,885.27 2.11 3,396.22 3_MWD+IFR2+MS+Sag (2) 9,345.99 91.99 184.77 3,737.09 -3,690.25 2,715.263,677.76 6,024,212.32 536,875.75 2.51 3,491.85 3_MWD+IFR2+MS+Sag (2) 9,440.44 93.04 182.59 3,732.95 -3,784.40 2,709.203,673.62 6,024,118.15 536,870.13 2.56 3,586.20 3_MWD+IFR2+MS+Sag (2) 9,535.85 92.23 182.83 3,728.56 -3,879.60 2,704.703,669.23 6,024,022.94 536,866.06 0.89 3,681.48 3_MWD+IFR2+MS+Sag (2) 9,631.61 92.92 183.61 3,724.26 -3,975.12 2,699.323,664.93 6,023,927.41 536,861.13 1.09 3,777.14 3_MWD+IFR2+MS+Sag (2) 9,726.85 94.65 184.09 3,717.97 -4,069.93 2,692.943,658.64 6,023,832.58 536,855.18 1.88 3,872.17 3_MWD+IFR2+MS+Sag (2) 9,820.66 96.01 183.52 3,709.26 -4,163.13 2,686.743,649.93 6,023,739.36 536,849.41 1.57 3,965.57 3_MWD+IFR2+MS+Sag (2) 9,916.51 96.88 184.12 3,698.50 -4,258.16 2,680.403,639.17 6,023,644.31 536,843.50 1.10 4,060.81 3_MWD+IFR2+MS+Sag (2) 10,011.49 94.95 184.58 3,688.71 -4,352.35 2,673.233,629.38 6,023,550.09 536,836.77 2.09 4,155.28 3_MWD+IFR2+MS+Sag (2) 10,106.76 94.53 184.86 3,680.84 -4,446.98 2,665.423,621.51 6,023,455.45 536,829.39 0.53 4,250.21 3_MWD+IFR2+MS+Sag (2) 10,201.21 93.78 184.82 3,673.99 -4,540.84 2,657.473,614.66 6,023,361.55 536,821.88 0.80 4,344.40 3_MWD+IFR2+MS+Sag (2) 10,295.49 96.76 184.70 3,665.34 -4,634.39 2,649.683,606.01 6,023,267.98 536,814.52 3.16 4,438.27 3_MWD+IFR2+MS+Sag (2) 10,323.36 97.69 184.51 3,661.83 -4,661.95 2,647.463,602.50 6,023,240.41 536,812.43 3.40 4,465.91 3_MWD+IFR2+MS+Sag (2) 10,392.00 97.69 184.51 3,652.65 -4,729.76 2,642.113,593.32 6,023,172.59 536,807.39 0.00 4,533.93 PROJECTED to TD Approved By:Checked By:Date: 5/15/2020 4:50:09PM COMPASS 5000.15 Build 91E Page 5 Chelsea Wright Digitally signed by Chelsea Wright Date: 2020.05.15 13:53:27 -08'00' Benjamin Hand Digitally signed by Benjamin Hand Date: 2020.05.15 14:54:17 -08'00' TD Shoe Depth: PBTD: Jts. 1 2 1 1 1 84 1 1 1 61 1 X Yes No X Yes No Fluid Description: Liner hanger Info (Make/Model):Liner top Packer?: Yes No Liner hanger test pressure:X Yes No Centralizer Placement: Preflush (Spacer) Type: Density (ppg) Volume pumped (BBLs) Lead Slurry Type:Sacks: Yield: Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Tail Slurry Type:Sacks: Yield: Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Post Flush (Spacer) Type: Density (ppg)Rate (bpm):Volume: Displacement: Type: Density (ppg) Rate (bpm): Volume (actual / calculated): FCP (psi): Pump used for disp: X Yes No Casing Rotated?X Yes No Reciprocated?X Yes No % Returns during job Cement returns to surface?X Yes No Spacer returns?X Yes No Vol to Surf: Cement In Place At: Date: Estimated TOC: Method Used To Determine TOC: Preflush (Spacer) Type: Density (ppg) Volume pumped (BBLs) Lead Slurry Type:Sacks: Yield: Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Tail Slurry Type:Sacks: Yield: Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Post Flush (Spacer) Type: Density (ppg)Rate (bpm):Volume: Displacement: Type: Density (ppg) Rate (bpm): Volume (actual / calculated): FCP (psi): Pump used for disp: X Yes No Casing Rotated? Yes X No Reciprocated? Yes X No % Returns during job Cement returns to surface?X Yes No Spacer returns? Yes X No Vol to Surf: Cement In Place At: Date: Estimated TOC: Method Used To Determine TOC: Post Job Calculations: Calculated Cmt Vol @ 0% excess: Total Volume cmt Pumped: Cmt returned to surface: Calculated cement left in wellbore: OH volume Calculated: OH volume actual: Actual % Washout: Casing (Or Liner) Detail Shoe Cut Joint of Casing 10 3/4 50.0 454.9 37.7330.3SECOND STAGERig 23:17 Returns to surface Rotate Csg Recip Csg Ft. Min.PPG9.4 Shoe @ 5918 FC @ Top of Liner5,838.00 Floats Held 351.8 794 319 475 Spud Mud CASING RECORD County State Alaska Supv.S. Sunderland / J. Vanderpool Hilcorp Energy Company CASING & CEMENTING REPORT Lease & Well No.MP M-44 Date Run 3-May-20 Setting Depths Component Size Wt.Grade THD Make Length Bottom Top TXP BTC-SR Innovex 1.56 5,918.00 5,916.44 10.12 43.75 33.639 5/8 40.0 L-80 TXP BTC-SR Tenaris Csg Wt. On Hook:275,000 Type Float Collar:Innovex No. Hrs to Run:16.5 9.3 6 1490 10.7 460 5 99.9 650 Bump Plug?FIRST STAGE10Tuned Spacer 60 15.8 500 4.5 9.4 6 168/168 440.7/440.7 1150 40 Rig 15.8 82 Bump press Returns to surface Bump Plug? 7:15 5/5/2020 2,466 5,918.005,920.00 CEMENTING REPORT Csg Wt. On Slips:100,000 Spud Mud 877 2.94 Stage Collar @ Bump press 100 279 Closure OK 45010 56.2 12 196 Tuned Spacer Type of Shoe:Innovex Casing Crew:Doyon www.wellez.net WellEz Information Management LLC ver_04818br 4 ArcticCem Lead Cement Type 79total 9-5/8"x12-1/4" bowspring centralizers ran. 2 jit#1 ith4 t i 1f fl ti jit#21 h idjit #3&4 it4 t i Casing 9 5/8 40.0 L-80 TXP BTC-SR Tenaris 78.31 5,916.44 5,838.13 Float Collar 10 3/4 50.0 TXP BTC-SR Innovex 1.23 5,838.13 5,836.90 Casing 9 5/8 40.0 L-80 TXP BTC-SR Tenaris 37.83 5,836.90 5,799.07 Baffle Adapter 10 3/4 50.0 TXP BTC-SR HES 1.52 5,799.07 5,797.55 Casing 9 5/8 40.0 L-80 TXP BTC-SR Tenaris 3,311.76 5,797.55 2,485.79 Pup Joint 9 5/8 40.0 L-80 TXP BTC-SR Tenaris 19.08 2,485.79 2,466.71 ES II Cementer 10 3/4 TXP BTC-SR HES 2.82 2,466.71 2,463.89 Pup Joint 9 5/8 40.0 L-80 TXP BTC-SR Tenaris 19.08 2,463.89 2,444.81 Casing 9 5/8 40.0 L-80 TXP BTC-SR Tenaris 2,401.06 2,444.81 43.75 Lead Cement 460 2.35 Tail Cement 400 1.16 5 Premium G Tail 270 1.17 5/5/2020 36 Spud Mud FIT data was submitted ES II Cementer 10 3/4 TXP BTC-SR HES 2.82 2,466.71 2,463.89 Pup Joint gls ok PB1 TD 10,392' MD / 3,653' TVD KOP 9,405' MD / 3,734' TVD Date 5/9/2020 MPU M-43 OH Sidetrack Summary PTD: 220-030 / API: 50-029-23673-00-00 CASING AND LEAK-OFF FRACTURE TESTS Well Name:MM PU M-44 Date:5/7/2020 Csg Size/Wt/Grade:9.625"40#,L -80 Supervisor:Yes s ak /Van d er p o o l Csg Setting Depth:5918 TMD 3802 TVD Mud Weight:9.1 ppg LOT / FIT Press =574 psi LOT / FIT =12.00 p p g Hole Depth =5940 md Fluid Pumped=1.2 Bbls Volume Back =1.2 bbls Estimated Pump Output:0.101 Barrels/Stroke LOT / FIT DATA CASING TEST DATA Enter Strokes Enter Pressure Enter Strokes Enter Pressure Here HHere Here HHer e ->0 ->00 ->23 ->5 208 ->4 150 ->10 491 ->6 252 ->15 796 ->8 360 ->20 1064 ->10 462 ->25 1327 ->11 542 ->30 1604 ->12 598 ->35 1895 ->13 ->40 2252 ->14 ->45 2552 ->15 ->48 2710 ->16 -> ->18 -> ->-> Enter Holding Enter Holding Enter Holding Enter Holding Time Here Pressure Here Time Here Pressure Here ->0 590 ->0 2710 ->1 581 ->5 2700 ->2 570 ->10 2700 ->3 563 ->15 2695 ->4 555 ->20 2690 ->5 549 ->25 2680 ->6 545 ->26 2680 ->7 542 ->27 2680 ->8 540 ->28 2680 ->9 539 ->29 2680 ->10 538 ->30 2680 ->11 537 -> ->12 536 -> ->13 535 -> ->14 534 ->15 533 ->16 FIT data 2 4 6 8 10 11 12 0 5 10 15 20 25 30 35 40 45 48 0 100 200 300 400 500 600 700 800 900 1000 1100 1200 1300 1400 1500 1600 1700 1800 1900 2000 2100 2200 2300 2400 2500 2600 2700 2800 2900 3000 0 102030405060Pressure (psi)Strokes (# of) LOT / FIT DATA CASING TEST DATA 590581570563555549545542540539538537536535534533 2710 2700 2700 2695 2690 268026802680268026802680 0 100 200 300 400 500 600 700 800 900 1000 1100 1200 1300 1400 1500 1600 1700 1800 1900 2000 2100 2200 2300 2400 2500 2600 2700 2800 2900 3000 0 5 10 15 20 25 30 35Pressure (psi)Time (Minutes) LOT / FIT DATA CASING TEST DATA Contractor/Rig No.: Doyon 14 Operator: Hilcorp Alaska, LLC Well Class: DEV MISC. INSPECTIONS: P/F P/F Location Gen.: P " Housekeeping: P_ " Warning Sign P 24 hr Notice: P Well Sign: P Drlg. Rig. P_- Misc: NA GAS DETECTORS: Visual Alarm Methane: P P Hydrogen Sulfide: P P Gas Detectors Mise: _0 _ NA STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION Reviewed By: 1 P.I. So.,, J�j� 16l ZL7�U DIVERTER Test Report for: MILNE PT UNIT M-44 - Comm PTD#: 2200300 DATE: 4/29/2020 - Inspector Adam Earl Insp Source Operator Rep: Sunderland/Vanderpool Rig Rep: Rodland/Carlo Inspector Inspection No: divAGE200502155738 Related Insp No: TEST DATA MUD SYSTEM: P/F Visual Alarm Trip Tank: P - P Mud Pits: P P Flow Monitor: P P " Mud System Misc: __0 NA ACCUMULATOR SYSTEM: P/F Time/Pressure P/F Systems Pressure: 2890 P Pressure After Closure: 1600 P 200 psi Recharge Time: 41 P Full Recharge Time: 135 P Nitrogen Bottles (Number of): 6 - P Avg. Pressure: 2156 P ' Accumulator Misc: 0 NA DIVERTER SYSTEM: Size P/F Designed to Avoid Freeze-up? P Remote Operated Diverter? P No Threaded Connections? P Vent line Below Diverter? P " Diverter Size: 21.25 - P Hole Size: 12.25 " P Vent Line(s) Size: 16 P 37 Vent Line(s) Length: 337____- Closest Closest Ignition Source: 140 - P - Outlet from Rig Substructure: 280 _ P Vent Line(s) Anchored: P - Turns Targeted / Long Radius: P Divert Valve(s) Full Opening: P _ Valve(s) Auto & Simultaneous: P - Annular Closed Time: 36 P Knife Valve Open Time: 16 P Diverter Misc: 0 NA Number of Failures: 0 Test Time: I Remarks: 5" test joint 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 Myers Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Milne Point Field, Schrader Bluff Oil Pool, MPU M-44 Hilcorp Alaska, LLC Permit to Drill Number: 220-030 Surface Location: 5036’ FSL, 21’ FEL, SEC. 14, T13N, R9E, UM, AK Bottomhole Location: 621’ FSL, 2261’ FWL, SEC. 24, T13N, R9E, UM, AK Dear Mr. Myers: Enclosed is the approved application for the permit to drill the above referenced service 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 March, 2020. 24 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. W ell Name and Number: Bond No. 3. Address:6. Proposed Depth:12. Field/Pool(s): MD: 15,352'TVD: 3,559' 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): 58.8 15. Distance to Nearest Well Open Surface: x- 534143 y- 6027889 Zone-4 25.1 to Same Pool:130' to MPU M-12 16. Deviated wells:Kickoff depth: 280 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 96 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD Cond 20" - X52 Weld 114' Surface Surface 114' 114' 8-1/2" 4-1/2" 13.5# L-80 Hyd 625 9,658' 5,694' 3,773' 15,352' 3,559' Tieback 3-1/2" 9.3# L-80 EUE 8RD 5,694' Surface Surface 5,694' 3,773' 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 21. Verbal Approval: Commission Representative:Date 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: Other: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: MPU M-44 Milne Point Field Schrader Bluff Oil Pool 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 Hilcorp Alaska, LLC 5036' FSL, 21' FEL, Sec 14, T13N, R9E, UM, AK ADL025514 Authorized Name: Stg 2 - L - 1937 ft3 / T - 314 ft312-1/4"9-5/8"40# ~270 ft3 Stg 1 - L - 954 ft3 / T - 458 ft3 3,763'L-80 TXP 5,844' Cementless Injection Liner w Screens 022224484 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 1325 419' FNL, 2541' FWL, Sec 13, T13N, R9E, UM, AK 621' FSL, 2261' FWL, Sec 24, T13N, R9E, UM, AK LONS 16-004 2560 18. Casing Program:Top - Setting Depth - BottomSpecifications 1663 Total Depth MD (ft):Total Depth TVD (ft): Surface Surface 5,844' Tieback Cement Quantity, c.f. or sacks Cement Volume MDSize Plugs (measured): (including stage data) Effect. Depth TVD (ft): Conductor/Structural LengthCasing Production Liner Intermediate Commission Use Only See cover letter for other requirements. Perforation Depth MD (ft): Authorized Title: Authorized Signature: 22. 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): 621' to nearest unit boundary 4/2/2020 Monty Myers Drilling Manager Joe Engel jengel@hilcorp.com 777-8395 Effect. Depth MD (ft): es sss ss N ype of W L l R L 1b S Class: os N esssssss No oo oo s N ooooo D s s sD 84 o : well is p G S S 20 S S S es ssssssss No ooo oos No S G E S es ssssssss No ooooo s Form 10-401 Revised 5/2017 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g)Submit Form and Attachments in Duplicate Digitally signed by Cody Dinger DN: cn=Cody Dinger, ou=Users Date: 2020.03.18 19:07:40 - 05'00' Cody Dinger By Samantha Carlisle at 7:44 am, Mar 19, 2020 CDW 03/19/2020 220-030 , ADL0388235 50-029-23673-00-00 SFD 3/20/2020DSR-3/24/2020 * Submit FIT results to AOGCC with well report X NB/NC Sand *3000 psi BOPE Test ervice - WinjSeSS GLS 3/23/20 03/24/2020 Area of Review MPM-44 PTD API WELL STATUS Top of SB NB (MD) Top of SB NB (TVD) CBL Top of Cement (MD) CBL Top of Cement (TVD)Schrader NB status Zonal Isolation 183-182 50-029-21057-00-00 MPM-01 P&A'd 4419'3625'Surface Surface P&A'd Well P&A'd and sidetracked 218-165 50-029-23617-00-00 MPM-10 OA 5754'3836'Surface Surface Cased/Cemented Lateral in OA 219-010 50-029-23621-00-00 MPM-11 OA 4734'3789'Surface Surface Cased/Cemented Lateral in OA 218-176 50-029-23619-00-00 MPM-12 OA 4157'3747'Surface Surface Cased/Cemented Lateral in OA 219-087 50-029-23638-00-00 MPM-13 OA 4206'3716'Surface Surface Cased/Cemented Lateral in OA 219-040 50-029-23625-00-00 MPM-14 OA 4301'3713'Surface Surface Cased/Cemented Lateral in OA 219-141 50-029-23653-00-00 MPM-15 OA 4966'3675'Surface Surface Cased/Cemented Lateral in OA 219-061 50-029-23631-00-00 MPM-16 OA 5847'3653'Surface Surface Cased/Cemented Lateral in OA 219-125 50-029-23648-00-00 MPM-17 OA 6546'3612'Surface Surface Cased/Cemented Lateral in OA 219-070 50-029-23632-00-00 MPM-18 OA 7133'3533'Surface Surface Cased/Cemented Lateral in OA 219-154 50-029-23655-00-00 MPM-19 OA 8202'3580'Surface Surface Cased/Cemented Lateral in OA 219-193 50-029-23662-00-00 MPM-34 Oba 6144'3673'Surface Surface Cased/Cemented Lateral in Oba 220-005 50-029-23665-00-00 MPM-35 OBa 5537'3729'Surface Surface Cased/Cemented Lateral in Oba 220-020 50-029-23671-00-00 MPM-43 Current Drill - NB Lat ~4884'~4003'Surface Surface Will be open Open to injection support Area of Review MPM-44 PTD API WELL STATUS Top of SB NB (MD) Top of SB NB (TVD) CBL Top of Cement (MD) CBL Top of Cement (TVD)Schrader NB status Zonal Isolation 183-182 50-029-21057-00-00 MPM-01 P&A'd 4419' 3625' Surface Surface P&A'd Well P&A'd and sidetracked 218-165 50-029-23617-00-00 MPM-10 OA 5754' 3836' Surface Surface Cased/Cemented Lateral in OA 219-010 50-029-23621-00-00 MPM-11 OA 4734' 3789' Surface Surface Cased/Cemented Lateral in OA 218-176 50-029-23619-00-00 MPM-12 OA 4157' 3747' Surface Surface Cased/Cemented Lateral in OA 219-087 50-029-23638-00-00 MPM-13 OA 4206' 3716' Surface Surface Cased/Cemented Lateral in OA 219-040 50-029-23625-00-00 MPM-14 OA 4301' 3713' Surface Surface Cased/Cemented Lateral in OA 219-141 50-029-23653-00-00 MPM-15 OA 4966' 3675' Surface Surface Cased/Cemented Lateral in OA 219-061 50-029-23631-00-00 MPM-16 OA 5847' 3653' Surface Surface Cased/Cemented Lateral in OA 219-125 50-029-23648-00-00 MPM-17 OA 6546' 3612' Surface Surface Cased/Cemented Lateral in OA 219-070 50-029-23632-00-00 MPM-18 OA 7133' 3533' Surface Surface Cased/Cemented Lateral in OA 219-154 50-029-23655-00-00 MPM-19 OA 8202' 3580' Surface Surface Cased/Cemented Lateral in OA 219-193 50-029-23662-00-00 MPM-34 Oba 6144' 3673' Surface Surface Cased/Cemented Lateral in Oba 220-020 50-029-23665-00-00 MPM-35 OBa 5537' 3729' Surface Surface Cased/Cemented Lateral in Oba Superseded 3/19/2020 SFD 3/19/2020 M 1813 24 M-01 M-01A L32 L-34 L-20 LIVIANO 1 LIVIANO 1A PESADO 1 PESADO 1A 2-14A L-5 L-53 L-56 L-57 L-52 M-03 M-12 M-11 M-14 M-15 M-13 M-10 M-16 M-17 M-18 M-19 M-20 M-21 M-22 M-23 M-35 M-34 M-44 wp02 HILCORP ALASKA LLC MILNE POINT FIELD AOR MAP M-44 Injector (Proposed) FEET 0 1,000 2,000 POSTED WELL DATA Well Number WELL SYMBOLS Active Oil D&A INJ Well (Water Flood) P&A Oil SWD Injector Location Shut In INJ REMARKS Well Symbols at top of Schrader Bluff NB Sand. Black dash circle = 1320' radius from NB sand in heel and toe of proposed M-44 drill well. March 16, 2020 PETRA 3/16/2020 9:21:50 AM On behalf of keastham KUPARUK RIVER UNIT Laterals NW/SE are drilled M-44 lateral drilled in Schrader NC/NB sands in Schrader OA sands Milne Point Unit (MPU) M-44 Drilling Program Version 1 3/18/2020 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 21-1/4” 2M Diverter System ............................................................................................. 11 11.0 Drill 12-1/4” Hole Section ........................................................................................................ 13 12.0 Run 9-5/8” Surface Casing ...................................................................................................... 16 13.0 Cement 9-5/8” Surface Casing ................................................................................................. 21 14.0 BOP N/U and Test.................................................................................................................... 26 15.0 Drill 8-1/2” Hole Section .......................................................................................................... 27 16.0 Run 4-1/2” Injection Liner (Lower Completion) .................................................................... 31 17.0 Run 3-1/2” Tubing (Upper Completion) ................................................................................. 35 18.0 RDMO ...................................................................................................................................... 36 19.0 Doyon 14 Diverter Schematic .................................................................................................. 37 20.0 Doyon 14 BOP Schematic ........................................................................................................ 38 21.0 Wellhead Schematic ................................................................................................................. 39 22.0 Days Vs Depth .......................................................................................................................... 40 23.0 Formation Tops & Information............................................................................................... 41 24.0 Anticipated Drilling Hazards .................................................................................................. 42 25.0 Doyon 14 Layout ...................................................................................................................... 45 26.0 FIT Procedure .......................................................................................................................... 46 27.0 Doyon 14 Choke Manifold Schematic ..................................................................................... 47 28.0 Casing Design ........................................................................................................................... 48 29.0 8-1/2” Hole Section MASP ....................................................................................................... 49 30.0 Spider Plot (NAD 27) (Governmental Sections) ...................................................................... 50 31.0 Surface Plat (As Built) (NAD 27) ............................................................................................. 51 32.0 Schrader Bluff NB Sand Offset MW vs TVD Chart ............................................................... 52 Page 2 Milne Point Unit M-44 SB Injector Drilling Procedure 1.0 Well Summary Well MPU M-44 Pad Milne Point “M” Pad Planned Completion Type 3-1/2” Injection Tubing Target Reservoir(s) Schrader Bluff NB/NC Sand Planned Well TD, MD / TVD 15,351’ MD / 3,558’ TVD PBTD, MD / TVD 15,341’ MD / 3,558’ TVD Surface Location (Governmental) 5036' FSL, 21' FEL, Sec 14, T13N, R9E, UM, AK Surface Location (NAD 27) X= 534,143 Y= 6,027,889 Top of Productive Horizon (Governmental) 419' FNL, 2541' FWL, Sec 13, T13N, R9E, UM, AK TPH Location (NAD 27) X= 536,706 Y= 6,027,726 BHL (Governmental) 621' FSL, 2261' FWL, Sec 24, T13N, R9E, UM, AK BHL (NAD 27) X= 536,477 Y=6,018,206 AFE Number 2010895M (D,C,F) AFE Drilling Days 19 days AFE Completion Days 3 days AFE Drilling Amount $3,977,177 AFE Completion Amount $1,429,523 AFE Facility Amount $391,000 Maximum Anticipated Pressure (Surface) 1325 psig Maximum Anticipated Pressure (Downhole/Reservoir) 1663 psig Work String 5” 19.5# S-135 DS-50 & NC 50 KB Elevation above MSL: 33.7 ft + 25.1 ft = 58.8 ft GL Elevation above MSL: 25.1 ft BOP Equipment 13-5/8” x 5M Annular, (3) ea 13-5/8” x 5M Rams Page 3 Milne Point Unit M-44 SB Injector Drilling Procedure 2.0 Management of Change Information Page 4 Milne Point Unit M-44 SB Injector 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 8-1/2” 4-1/2” 3.96” 3.795” 4.714” 13.5 L-80 H625 9020 8540 279 Tubing 3-1/2” 2.992” 2.867” 4.500” 9.3 L-80 EUE 8RD 9289 7399 163 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 GPDS50 36,100 43,100 560klb 5” 4.276” 3.25” 6.625” 19.5 S-135 NC50 31,032 34,136 560klb All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery). Page 5 Milne Point Unit M-44 SB Injector 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 M-44 SB Injector Drilling Procedure 6.0 Planned Wellbore Schematic forwarded to AGOCC FIT data to be Swell packers + ICD's Page 7 Milne Point Unit M-44 SB Injector Drilling Procedure 7.0 Drilling / Completion Summary MPU M-44 is a grassroots injector planned to be drilled in the Schrader Bluff NB/NC sand. M-44 is part of a multi well program targeting the Schrader Bluff sand on M-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 NB/NC sand. An 8.5” lateral section will then be drilled. A 4-1/2” injection liner will be run in the open hole section. The Doyon 14 will be used to drill and complete the wellbore. Drilling operations are expected to commence approximately April 2, 2020, pending rig schedule. Surface casing will be run to 5,843 MD / 3,784’ TVD and cemented to surface via a 2 stage primary cement job. Cement returns to surface will confirm TOC at surface. If cement returns to surface are not observed, necessary remedial action will then be discussed with AOGCC authorities. All cuttings & mud generated during drilling operations will be hauled to the Milne Point “B” pad G&I facility. General sequence of operations: 1. MIRU Doyon 14 to well site 2. N/U & Test 21-1/4” Diverter and 16” diverter line 3. Drill 12-1/4” hole to TD of surface hole section. Run and cement 9-5/8” surface casing 4. N/D diverter, N/U & test 13-5/8” x 5M BOP. Install MPD Riser 5. Drill 8-1/2” lateral to well TD. Run 4-1/2” injection liner. 6. Run 3-1/2” tubing. 7. 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) No mud logging. No mud logging. gg g : GR + Res : GR + ADR MPU M-44 is a grassroots injector planned to be drilled in the Schrader Bluff NB/NC sand. Page 8 Milne Point Unit M-44 SB Injector 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 M-44. 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: Hilcorp Alaska LLC does not request any variances at this time. Page 9 Milne Point Unit M-44 SB Injector Drilling Procedure Summary of BOP Equipment & Notifications Hole Section Equipment Test Pressure (psi) 12 1/4” x 21-1/4” 2M Diverter w/ 16” Diverter Line Function Test Only 8-1/2” x 13-5/8” x 5M Hydril “GK” Annular BOP x 13-5/8” x 5M Hydril MPL Double Gate o Blind ram in btm cavity x Mud cross w/ 3” x 5M side outlets x 13-5/8” x 5M Hydril MPL Single ram x 3-1/8” x 5M Choke Line x 3-1/8” x 5M Kill line x 3-1/8” x 5M Choke manifold x Standpipe, floor valves, etc Initial Test: 250/3000 Subsequent Tests: 250/3000 Primary closing unit: NL Shaffer, 6 station, 3000 psi, 180 gallon accumulator unit. Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is a 30:1 air pump, and emergency pressure is provided by bottled nitrogen. The remote closing operator panels are located in the doghouse and on accumulator unit. Required AOGCC Notifications: 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 M-44 SB Injector Drilling Procedure 9.0 R/U and Preparatory Work 9.1 M-44 will utilize a newly set 20” conductor on M-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 Doyon 14. Ensure rig is centered over conductor to prevent any wear to BOPE or wellhead. 9.8 Mud loggers WILL NOT be used on either hole section. 9.9 Mix spud mud for 12-1/4” surface hole section. Ensure mud temperatures are cool (<80qF). 9.10 Ensure 6” liners in mud pumps. x Continental EMSCO FB-1600 mud pumps are rated at 4665 psi, 462 gpm @ 110 spm @ 95% volumetric efficiency. Page 11 Milne Point Unit M-44 SB Injector Drilling Procedure 10.0 N/U 21-1/4” 2M Diverter System 10.1 N/U 21-1/4” Hydril MSP 2M Diverter System (Diverter Schematic attached to program). x N/U 16-3/4” 3M x 21-1/4” 2M DSA on 16-3/4” 3M wellhead. x N/U 21-1/4” diverter “T”. x 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. 10.2 Notify AOGCC. Function test diverter. Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens prior to annular closure. 10.3 Ensure to set up a clearly marked “warning zone” is established on each side and ahead of the vent line tip. “Warning Zone” must include: x A prohibition on vehicle parking x A prohibition on ignition sources or running equipment x A prohibition on staged equipment or materials x Restriction of traffic to essential foot or vehicle traffic only. Page 12 Milne Point Unit M-44 SB Injector Drilling Procedure 10.4 Rig & Diverter Orientation: x May change on location Page 13 Milne Point Unit M-44 SB Injector Drilling Procedure 11.0 Drill 12-1/4” Hole Section 11.1 P/U 12-1/4” directional drilling assembly: x Ensure BHA components have been inspected previously. x Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. x Ensure TF offset is measured accurately and entered correctly into the MWD software. x Be sure to run a UBHO sub for wireline gyro x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. 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 NB sand. Confirm this setting depth with the Geologist and Drilling Engineer while drilling the well. x Monitor the area around the conductor for any signs of broaching. If broaching is observed, Stop drilling (or circulating) immediately notify Drilling Engineer. x Efforts should be made to minimize dog legs in the surface hole. Keep DLS < 6 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. MWD surveys every stand Page 14 Milne Point Unit M-44 SB Injector Drilling Procedure x Gas hydrates have not been seen on M-Pad. However, be prepared for them. In MPU they have been encountered typically around 2100-2400’ TVD (just below permafrost). Be prepared for hydrates: x Gas hydrates can be identified by the gas detector and a decrease in MW or ECD x Monitor returns for hydrates, checking pressurized & non-pressurized scales x Past wells on E pad have increased MW.After drilling through hydrate sands, MW was cut back to normal x Do not stop to circulate out gas hydrates – this will only exacerbate the problem by washing out additional permafrost. Attempt to control drill (150 fph MAX) through the zone completely and efficiently to mitigate the hydrate issue. Flowrates can also be reduced to prevent mud from belching over the bell nipple. Consider adding Lecithin to allow the gas to break out. x Gas hydrates are not a gas sand, once a hydrate is disturbed the gas will come out of the well. MW will not control gas hydrates, but will affect how gas breaks out at surface. x AC: There are no actual offset wells with a clearance factors <1.0 in the surface hole section 11.4 12-1/4” hole mud program summary: x Density: Weighting material to be used for the hole section will be barite. Additional barite or spike fluid will be on location to weight up the active system (1) ppg above highest anticipated MW. We will start with a simple gel + FW spud mud at 8.8 ppg and TD with 9.2+ ppg. Depth Interval MW (ppg) Surface – Base Permafrost 8.9+ Base Permafrost - TD 9.2+ (For Hydrates if need based on offset wells) MW can be cut once ~500’ below hydrate zone x PVT System: MD Totco PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, Toolpusher office, and mud loggers office. x Rheology: Aquagel and Barazan D+ should be used to maintain rheology. Begin system with a 75 YP but reduce this once clays are encountered. Maintain a minimum 25 YP at all times while drilling. Be prepared to increase the YP if hole cleaning becomes an issue. x Fluid Loss: DEXTRID and/or PAC L should be used for filtrate control. Background LCM (10 ppb total) BARACARBs/BAROFIBRE/STEELSEALs can be used in the system while drilling the surface interval to prevent losses and strengthen the wellbore. x Wellbore and mud stability: Additions of CON DET PRE-MIX/DRIL N SLIDE are recommended to reduce the incidence of bit balling and shaker blinding when penetrating the high-clay content sections of the Sagavanirktok and the heavy oil sections of the UGNU 4A. Maintain the pH in the 8.5 – 9.0 range with caustic soda. Daily additions of ALDACIDE G / X- CIDE 207 MUST be made to control bacterial action. Page 15 Milne Point Unit M-44 SB Injector Drilling Procedure 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). System Type: 8.8 – 9.2 ppg Pre-Hydrated Aquagel/freshwater spud mud Properties: Section Density Viscosity Plastic Viscosity Yield Point API FL pH Temp Surface 8.8 – 9.8 75-175 20 - 40 25-45 <10 8.5 – 9.0 70 F System Formulation: Gel + FW spud mud Product- Surface hole Size Pkg ppb or (% liquids) M-I Gel 50 lb sx 25 Soda Ash 50 lb sx 0.25 PolyPac Supreme UL 50 lb sx 0.08 Caustic Soda 50 lb sx 0.1 SCREENCLEEN 55 gal dm 0.5 11.5 At TD; PU 2-3 stands off bottom, CBU, pump tandem sweeps and drop viscosity. 11.6 RIH 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. 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 – 9.2 p– No open hole logging p Page 16 Milne Point Unit M-44 SB Injector Drilling Procedure 12.0 Run 9-5/8” Surface Casing 12.1 R/U and pull wearbushing. 12.2 R/U Weatherford 9-5/8” casing running equipment (CRT & Tongs) x Ensure 9-5/8” TXP x DS50 XO on rig floor and M/U to FOSV. x Use BOL 2000 thread compound. Dope pin end only w/ paint brush. x R/U of CRT if hole conditions require. x R/U a fill up tool to fill casing while running if the CRT is not used. x Ensure all casing has been drifted to 8.75” on the location prior to running. x Be sure to count the total # of joints on the location before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 12.3 P/U shoe joint, visually verify no debris inside joint. 12.4 Continue M/U & thread locking 120’ shoe track assembly consisting of: 9-5/8” Float Shoe 1 joint – 9-5/8” TXP, 2 Centralizers 10’ from each end w/ stop rings 1 joint – 9-5/8” TXP, 1 Centralizer mid joint w/ stop ring 9-5/8” Float Collar w/ Stage Cementer Bypass Baffle ‘Top Hat’ 1 joint – 9-5/8” TXP, 1 Centralizer mid joint with stop ring 9-5/8” HES Baffle Adaptor x Ensure bypass baffle is correctly installed on top of float collar. x Ensure proper operation of float equipment while picking up. x Ensure to record S/N’s of all float equipment and stage tool components. This end up. Bypass Baffle Page 17 Milne Point Unit M-44 SB Injector Drilling Procedure 12.5 Float equipment and Stage tool equipment drawings: 2500 ft Page 18 Milne Point Unit M-44 SB Injector Drilling Procedure 12.6 Continue running 9-5/8” surface casing x Fill casing while running using fill up line on rig floor. x Use BOL 2000 thread compound. Dope pin end only w/ paint brush. x Centralization: x 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 5 joints above stage tool. x Do not place tongs on ES cementer, this can cause damaged to the tool. x Ensure tool is pinned with 6 opening shear pins. This will allow the tool to open at 3300 psi. 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 Depth Interval Centralization Shoe – 1000’ Above Shoe 1/jt 1000’ above Shoe – 2000’ above Shoe (Top of Ugnu) 1/ 2 jts Page 19 Milne Point Unit M-44 SB Injector Drilling Procedure Page 20 Milne Point Unit M-44 SB Injector Drilling Procedure 12.8 Continue running 9-5/8” surface casing x Fill casing while running using fill up line on rig floor. x Use BOL 2000 thread compound. Dope pin end only w/ paint brush. x Centralization: o 1 centralizer every 2 joints to base of conductor 12.9 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 12.10 Slow in and out of slips. 12.11 P/U landing joint and M/U to casing string. Position the casing shoe +/- 10’ from TD. Strap the landing joint prior to the casing job and mark the joint at (1) ft intervals to use as a reference when getting the casing on depth. 12.12 Lower casing to setting depth. Confirm measurements. 12.13 Have slips staged in cellar, along with necessary equipment for the operation. 12.14 Circulate and condition mud through CRT. Reduce YP to < 20 to help ensure success of cement job. Ensure adequate amounts of cold M/U water are available to achieve this. If possible reciprocate casing string while conditioning mud. Page 21 Milne Point Unit M-44 SB Injector 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 (4,843' - 2500') x .0558 bpf x 1.3 = 170 954.3 Total Lead 170 954.3 12-1/4" OH x 9-5/8" Casing (5,843' - 4,843') 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 sacks sx405 Page 22 Milne Point Unit M-44 SB Injector 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. To operate the stage tool hydraulically, the plug must be bumped. 13.11 Displacement calculation: 5,723’ x .0758 bpf = 433.8 bbls 80 bbls of tuned spacer to be left behind stage tool, confirm spacer is compatible with cement behind stage tool & that sufficient spacer will be above the tool to exit when circulation is established. 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 Note: Lead Cement Viscosity to be lowered to prevent poor interface once stage tool is opened and cement is circulated to surface Page 23 Milne Point Unit M-44 SB Injector 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. Page 24 Milne Point Unit M-44 SB Injector Drilling Procedure Second Stage Surface Cement Job: 13.18 Prepare for the 2nd stage as necessary. Circulate until first stage reaches sufficient compressive strength. Hold pre-job safety meeting. 13.19 HEC representative to witness the loading of the ES cementer closing plug in the cementing head. 13.20 Fill surface lines with water and pressure test. 13.21 Pump remaining 60 bbls 10.5 ppg tuned spacer. 13.22 Mix and pump cmt per below recipe for the 2nd stage. 13.23 Cement volume based on annular volume + open hole excess (200% for lead and 100% for tail). Job will consist of lead & tail, TOC brought to surface. However cement will continue to be pumped until clean spacer is observed at surface. Estimated 2nd Stage Total Cement Volume: 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 270 sx 3x 2x 440 sx Page 25 Milne Point Unit M-44 SB Injector 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 annulus for returns during surface cement job. Set slips 13.30 Make initial cut on 9-5/8” final joint. L/D cut joint. Make final cut on 9-5/8”. Dress off stump. Install 9-5/8” wellhead. If transition nipple is welded on, allow to cool as per schedule. Ensure to report the following on wellez: x Pre flush type, volume (bbls) & weight (ppg) x Cement slurry type, lead or tail, volume & weight x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration 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. Page 26 Milne Point Unit M-44 SB Injector Drilling Procedure 14.0 BOP N/U and Test 14.1 N/D the diverter T, knife gate, diverter line & N/U 11” x 13-5/8” 5M casing spool. 14.2 N/U 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 4-1/2” x 7” VBRs in top cavity, blind ram in bottom cavity. x Single ram can be dressed with 3-1/2” x 6” VBRs x N/U 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 Run 5” BOP test plug 14.4 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 14.5 R/D BOP test equipment 14.6 Dump and clean mud pits, send spud mud to G&I pad for injection. 14.7 Mix 8.9 ppg FloPro fluid for production hole. 14.8 Set wearbushing in wellhead. 14.9 If needed, rack back as much 5” DP in derrick as possible to be used while drilling the hole section. 14.10 Ensure 6” liners in mud pumps. Page 27 Milne Point Unit M-44 SB Injector Drilling Procedure 15.0 Drill 8-1/2” Hole Section 15.1 M/U 8.5” Cleanout BHA (Milltooth Bit & 1.22° PDM) x Based on results from M-44, we may use the RSS BHA to drill out the shoe track 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 R/U 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 & LD Cleanout BHA 15.9 P/U 8-1/2” RSS directional BHA. 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 Ensure MWD is R/U 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. Use appropriate SAFECARB blend on this well Addit io na l calciu m car bonat e will be on locat ion to weight up the active system (1) ppg above highest ant icipated MW. - Submit FIT data with the 10-407 report. (gls) Page 28 Milne Point Unit M-44 SB Injector 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 throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, & Toolpusher office. System Type: 8.9 – 9.5 ppg FloPro drilling fluid Properties: Interval Density PV YP LSYP Total Solids MBT HPHT Hardness Production 8.9-9.5 15-25 - ALAP 15 - 30 4-6 <10% <8 <11.0 <100 System Formulation: Product- production Size Pkg ppb or (% liquids) Busan 1060 55 gal dm 0.095 FLOTROL 55 lb sx 6 CONQOR 404 WH (8.5 gal/100 bbls) 55 gal dm 0.2 FLO-VIS PLUS 25 lb sx 0.7 KCl 50 lb sx 10.7 SMB 50 lb sx 0.45 LOTORQ 55 gal dm 1.0 SAFE-CARB 10 (verify) 50 lb sx 10 SAFE-CARB 20 (verify) 50 lb sx 10 Soda Ash 50 lb sx 0.5 8.9-9.5 Page 29 Milne Point Unit M-44 SB Injector Drilling Procedure 15.11 TIH with 8-1/2” directional assembly to bottom 15.12 Displace wellbore to 8.9 ppg Flo Pro drilling fluid 15.13 Begin drilling 8.5” hole section, o n-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 P/U off bottom and restart on bottom staging technique. If stick slip continues, consider adding .5% lubes 15.14 Drill 8-1/2” hole section to section TD per Geologist and Drilling Engineer. x Flow Rate: 350-550 gpm, target min. AV’s 200 ft/min, 385 gpm x RPM: 120+ x Ensure shaker screens are set up to handle this flowrate. Ensure shakers are running slightly wet to maximize solids removal efficiency. Check for holes in screens on every connection. x Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low x Take MWD surveys every stand, can be taken more frequently if deemed necessary, ex: concretion deflection x Monitor Torque and Drag with pumps on every 5 stands x Monitor ECD, pump pressure & hookload trends for hole cleaning indication x Surveys can be taken more frequently if deemed necessary. x Good drilling and tripping practices are vital for avoidance of differential sticking. Make every effort to keep the drill string moving whenever possible and avoid stopping with the BHA across the sand for any extended period of time. x Use ADR to stay in section. Reservoir plan is to undulate between Schrader OA1 & OA3 lobes in 1000-1500’ MD increments, and keeping DLS <3° when moving between lobes 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 Watch for higher than expected pressure. MPD will be utilized to monitor pressure build up on connections x AC: x There are no offset wells that have a clearance factor of <1.0. x Schrader Bluff Concretions: 5-10% of lateral 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 approx. 30 min. s every stand, . MPD will be utilized NB and NC pp MWD surveys eves eve Page 30 Milne Point Unit M-44 SB Injector 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 Ensure mud has necessary lube % for running liner x If seepage losses are seen while drilling, consider reducing MW at TD to 9.0ppg minimum 15.17 Once hole is clean, displace to lubricated, viscosified 8.8 ppg 2% KCl brine. 15.18 Monitor the returned fluids carefully while conditioning the mud. After 4 (or more) BU, Perform production screen test (PST). The mud has been properly conditioned when the mud will pass the production screen test (x3 350ml samples passing through the screen in the same amount of time which will indicate no plugging of the screen). Reference PST Test Procedure x 250 Coupons x Circulate and condition mud as much as needed to pass the production screen test x If not passing after first test, call Completion Engineer 15.19 BROOH with the drilling assembly to the 9-5/8” casing shoe x Circulate at full drill rate (385 gpm max). x Rotate at maximum rpm that can be sustained. x Limit pulling speed to 5 – 10 min/std (slip to slip time, not including connections). x If backreaming operations are commenced, continue backreaming to the shoe 15.20 CBU minimum two times at 9-5/8” shoe and clean casing with high vis sweeps. 15.21 Monitor well for flow. Increase mud weight if necessary x Wellbore breathing has been seen on past MPU SB wells. Perform extended flow checks to determine if well is breathing, treat all flow as an influx until proven otherwise x If necessary, increase MW at shoe for any higher than expected pressure seen 15.22 POOH and LD BHA. Rabbit DP on TOH, ensure rabbit diameter is sufficient for future ball drops. 15.23 Continue to POH and stand back BHA if possible. Rabbit DP on TOH, ensure rabbit diameter is sufficient for future ball drops. Only LWD open hole logs are planned for the hole section (GR + Res). There will not be any additional logging runs conducted. n (GR + Re s). Page 31 Milne Point Unit M-44 SB Injector Drilling Procedure 16.0 Run 4-1/2” Injection Liner (Lower Completion) 16.1. Well control preparedness: In the event of an influx of formation fluids while running the 4- 1/2” injection liner with joints of screens, the following well control response procedure will be followed: x With a screen joint across the BOP: 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” liner. x With 4-1/2” solid joint across BOP: Slack off and position the 4-1/2” solid joint to MU the TIW valve. Shut in ram or annular on 4-1/2” solid joint. Close TIW valve. 16.2. Confirm VBR have been tested on 4-1/2” and 5” test joints to 250 psi low/3000 psi high. 16.3. R/U 4-1/2” liner running equipment. x Ensure 4-1/2” Hydril 625 x DS-50 crossover is on rig floor and M/U to FOSV. x Ensure the liner 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. 16.4. Run 4-1/2” injection liner. x Injection liner will be solid pipe and single screen joints spaced every ~ 800’. Confirm with OE x Use API Modified or “Best O Life 2000 AG” thread compound. Dope pin end only w/ paint brush. Wipe off excess. Thread compound can plug the screens x Utilize a collar clamp until weight is sufficient to keep slips set properly. x Use lift nubbins and stabbing guides for the liner run. x Fill 4-½” liner with PST passed mud (to keep from plugging ICDs with solids) x Install ICDs and swell packers as per the Running Order x (From Completion Engineer post TD). x Do not place tongs or slips on screen joints x Screen placement ±40’ x The Screen connection is 4-1/2” 13.5# Hydril 625 x If liner length exceeds surface casing length, ensure centralizers are placed 1/jt for each joint outside of the surface shoe. This is to mitigate difference sticking risk while running inner string. x Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10 and 20 rpm 4-1/2” 13.5# L-80 H625 Casing OD Minimum Optimum Maximum Operating Torque 4.5” 8,000 ft-lbs 9,600 ft-lbs 12,800 ft-lbs Page 32 Milne Point Unit M-44 SB Injector Drilling Procedure 16.6. Ensure that the liner top packer is set ~ 150’ MD above the 9-5/8” shoe. x AOGCC regulations require a minimum 100’ overlap between the inner and outer strings as per 20 AAC 25.030(d)(6). Ensure hanger/packer will not be set in a 9-5/8” connection. Page 33 Milne Point Unit M-44 SB Injector Drilling Procedure 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 inner string and 4-1/2” liner. Fill liner tieback sleeve with “Pal mix”, ensure mixture is thin enough to travel past the HRD tool and down to the packoff. Wait 30 min for mixture to set up. 16.9. Note weight of liner. Run liner in the hole one stand and pump through liner hanger to ensure a clear flow path exists. 16.10. RIH w/ liner on DP no faster than 30 ft/min – this is to prevent buckling the liner and drill string. Watch displacement carefully and avoid surging the hole or buckling the liner. Slow down running speed if necessary. 16.11. The liner and inner string will prevent the DP from auto filling. Fill DP every 5 stands, more frequently if SOW trend indicates. 16.12. Slow in and out of slips. Ensure accurate slack off data is gathered during RIH. Record shoe depth + S/O depth every stand. Record torque value if it becomes necessary to rotate the string to bottom. 16.13. 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. Prior to setting the hanger and packer, double check all pipe tallies and record amount of drill pipe left on location. Ensure all numbers coincide with proper setting depth of liner hanger. 16.17. Drop setting ball down the workstring and pump slowly (1-2 bpm). Slow pump before the ball seats. Do not allow ball to slam into ball seat. Pressure up to 1,500 psi to shift the wellbore isolation valve closed. 16.18. Continue pressuring up to 2700 psi to set the SLZXP liner hanger/packer. Hold for 5 minutes. Slack off 20K lbs on the ZXP to ensure the HRDE setting tool is in compression for release from the SLZXP liner hanger/packer. Continue pressuring up 4100 psi to neutralize and release running tools. 16.19. Bleed DP pressure to zero, Pick up to expose Rotating Dog Sub and set down 50k# without pulling sleeve packoff. Pick back up without pulling sleeve packoff, begin rotating at 10-20 rpm and set down 50k# again, 16.20. PU to neutral weight, close BOP and test annulus to 1500 psi for 10 min and chart record same. Page 34 Milne Point Unit M-44 SB Injector Drilling Procedure 16.21. 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. 16.22. With running tool line liner top, flush liner top at max rate 16.23. POOH, L/D and inspect running tools. If setting of liner hanger/packer proceeded as planned, LDDP on the TOH. 16.24. LD Remaining 5” DP. 16.25. Once running tools are L/D, Swap to Completion AFE. Page 35 Milne Point Unit M-44 SB Injector Drilling Procedure 17.0 Run 3-1/2” Tubing (Upper Completion) 17.1 Notify the AOGCC at least 24 hours in advance of the IA pressure test after running the completion as per 20 AAC 25.412 (e). Record pressure test on 10-426 form and email to wrivard@hilcorp.com for submission to AOGCC. 17.2 M/U injection assembly and RIH to setting depth. TIH no faster than 90 ft/min. x Ensure wear bushing is pulled. x Ensure 3-½” EUE 8RD x NC-50 crossover is on rig floor and M/U to FOSV. x Ensure all tubing has been drifted in the pipe shed prior to running. x Be sure to count the total # of joints in the pipe shed 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. x Monitor displacement from wellbore while RIH. 3-1/2” 9.3# L-80 EUE 8RD Casing OD Minimum Optimum Maximum Operating Torque 3.5” 2,350 ft-lbs 3,130 ft-lbs 3,910 ft-lbs 3-½” Upper Completion Running Order x 3-½” Baker Ported Bullet Nose seal (stung into the tie back receptacle) x 3 joints (minimum, more as needed) 3-½” 9.3#/ft, L-80 EUE 8RD tubing x 3-½” “XN” nipple at TBD x 3-½” 9.3#/ft, L-80 EUE 8RD tubing x 3-½” “X” nipple at TBD MD x 3-½” 9.3#/ft, L-80 EUE 8RD space out pups x 1 joint 3-½” 9.3#/ft, L-80 EUE 8RD tubing x Tubing hanger with 3-1/2” EUE 8RD pin down 17.3 Locate and no-go out the seal assembly. Close annular and test to 400 psi to confirm seals engaged. 17.4 Bleed pressure and open annular. Space out the completion (+/- 1’ to 2’ above No-Go). Place all space out pups below the first full joint of the completion. Page 36 Milne Point Unit M-44 SB Injector Drilling Procedure 17.5 Makeup the tubing hanger and landing joint. 17.6 RIH. Close annular and test to 400 – 500 psi to confirm seals are engaged. Bleed pressure down to 250 psi. PU until ports in seal assembly exposed. 17.7 Reverse circulate the well with brine and 1% corrosion inhibitor. 17.8 Freeze protect the tubing and IA to ~3000’ MD with ±210 bbl of diesel. 17.9 Land hanger. RILDs and test hanger. 17.10 Continue pressurizing the annulus to 2500 psi and test for 30 charted minutes. i. Note this test must be witnessed by the AOGCC representative. 17.11 Set BPV, ensure new body seals are installed each time. ND BOPE and NU adapter flange and tree. 17.12 Pull BPV. Set TWC. Test tree to 5000 psi. 17.13 Pull TWC. Set BPV. Bullhead tubing freeze protect. 17.14 Secure the tree and cellar. 18.0 RDMO 18. RDMO Doyon 14 Note this test must be witnessed by the AOGCC representative. Post injection Witnessed MIT-IA is required... gls Page 37 Milne Point Unit M-44 SB Injector Drilling Procedure 19.0 Doyon 14 Diverter Schematic Page 38 Milne Point Unit M-44 SB Injector Drilling Procedure 20.0 Doyon 14 BOP Schematic Page 39 Milne Point Unit M-44 SB Injector Drilling Procedure 21.0 Wellhead Schematic Page 40 Milne Point Unit M-44 SB Injector Drilling Procedure 22.0 Days Vs Depth Page 41 Milne Point Unit M-44 SB Injector Drilling Procedure 23.0 Formation Tops & Information L-Pad Data Sheet Formation Description (Closest & Most Analogous MPU Pad to Moose Pad) Page 42 Milne Point Unit M-44 SB Injector Drilling Procedure 24.0 Anticipated Drilling Hazards 12-1/4” Hole Section: Lost Circulation Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Gas Hydrates Gas hyrates have not been seen on Moose pad. However, be prepared for them. Remember that hydrate gas behave differently from a gas sand. Additional fluid density will not prevent influx of gas hydrates, but can help control the breakout at surface. Once a gas hydrate has been disturbed the gas will come out of the hole. Drill through the hydrate section as quickly as possible while minimizing gas belching. Minimize circulation time while drilling through the hydrate zone. Excessive circulation will accelerate formation thawing which can increase the amount of hydrates released into the wellbore. Keep the mud circulation temperature as cold as possible. Weigh mud with both a pressurized and non-pressurized mud scale. The non-pressurized scale will reflect the actual mud cut weight. Isolate/dump contaminated fluid to remove hydrates from the system. Hole Cleaning: Maintain rheology of mud system. Sweep hole with high viscosity sweeps as necessary. Optimize solids control equipment to maintain density, sand content, and reduce the waste stream. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to avoid washing out a particular section of the hole. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Anti-Collison: There are a number of wells in close proximity. Take directional surveys every stand, take additional surveys if necessary. Continuously monitor proximity to offset wellbores and record any close approaches on AM report. Discuss offset wellbores with production foreman and consider shutting in adjacent wells if necessary. Monitor drilling parameters for signs of collision with another well. Well specific A/C: x There are no wells with a clearance less than 1.0 Wellbore stability (Permafrost, running sands and gravel, conductor broaching): Washouts in the permafrost can be severe if the string is left circulating across it for extended periods of time. Keep mud as cool as possible by taking on cold water and diluting often. High TOH and RIH speeds can aggravate fragile shale/coal formations due to the pressure variations between surge and swab. Bring the pumps on slowly after connections. Monitor conductor for any signs of broaching. Maintain mud parameters and increase MW to combat running sands and gravel formations. 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. Ensure adequate amounts of LCM are available. , be prepared No H2S Page 43 Milne Point Unit M-44 SB Injector Drilling Procedure 1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic 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. H2S detection equipment Page 44 Milne Point Unit M-44 SB Injector Drilling Procedure 8-1/2” Hole Section: Hole Cleaning: Maintain rheology of mud system. Sweep hole with low-vis water sweeps. Ensure shakers are set up with appropriate screens to maximize solids removal efficiency. Run centrifuge continuously. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Maintain circulation rate of > 300 gpm Lost Circulation: Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Faulting: There is at least (1) fault that will be crossed while drilling the well. There could be others and the throw of these faults is not well understood at this point in time. When a known fault is coming up, ensure to put a “ramp” in the wellbore to aid in kicking off (low siding) later. Once a fault is crossed, we’ll need to either drill up or down to get a look at the LWD log and determine the throw and then replan the wellbore. H2S: Treat every hole section as though it has the potential for H2S. No H2S events have been documented on drill wells on this pad. 1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Abnormal Pressures and Temperatures: Reservoir pressures are expected to be normal. Abnormal (offset injection) pressure has been seen on M- Pad. Utilize MPD to mitigate any abnormal pressure seen. Anti-Collision Take directional surveys every stand, take additional surveys if necessary. Continuously monitor drilling parameters for signs of magnetic interference with another well. Reference A/C report in directional plan. There are no wells with a separation factor of <1. Well specific AC: x There are no wells with a clearance less than 1.0 fLCM a t (1) fault No H2S H2S detection equipment e expected to be normal. . Utilize MPD to mitigate any abnormal pressure every stand, directional surveys Page 45 Milne Point Unit M-44 SB Injector Drilling Procedure 25.0 Doyon 14 Layout Page 46 Milne Point Unit M-44 SB Injector 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 47 Milne Point Unit M-44 SB Injector Drilling Procedure 27.0 Doyon 14 Choke Manifold Schematic Page 48 Milne Point Unit M-44 SB Injector Drilling Procedure 28.0 Casing Design 12-1/4"Mud Density:9.2 ppg 8-1/2"Mud Density:9.2 ppg Mud Density: 1325 psi (see attached MASP determination & calculation) 1325 psi (see attached MASP 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"4-1/2" 0 5,843 0 3,784 5,843 15,351 3,784 3,558 5,843 9,508 40 12.6 L-80 L-80 DWC H625 233,720 119,801 233,720 119,801 916 279 3.92 2.33 1,869 1,758 3,090 8,540 1.65 4.86 1,325 1,325 5,750 9,020 4.34 6.81 Casing Section 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) Weight w/o Bouyancy Factor (lbs) Min strength Tension (1000 lbs) Grade Connection Calculation & Casing Design Factors Calculation/Specification Casing OD Bottom (MD) Bottom (TVD) Top (MD) MASP: Drilling Mode MASP: Hole Size DATE: 2.26.2020 WELL: MPU M-43 DESIGN BY: Joe Engel Hole Size Design Criteria: Hole Size 3.92 2.33 4.34 6.81 8,540 1.65 4.86 1,325 1,325 Page 49 Milne Point Unit M-44 SB Injector Drilling Procedure 29.0 8-1/2” Hole Section MASP MD TVD Planned Top: 5843 3784 Planned TD: 15351 3558 Anticipated Formations and Pressures: Formation TVD TVDss Est Pressure Oil/Gas/Wet PPG Grad Schrader Bluff NB Sand 3,784 3,742 1665 Oil 8.46 0.440 Offset Well Mud Densities Well MW range Top (TVD) Bottom (TVD) Date MPU L-52 8.8-9.35 Surface 3952 2017 MPU L-51 8.9-9.3 Surface 3930 2017 MPU L-53 9-9.25 Surface 3891 2017 MPU J-27 9-9.3 Surface 3666 2015 MPU J-28 9-9.3 Surface 3617 2015 MPI - 19 9 - 9.3 ppg Surface 4,079 2004 MPI - 18 9 - 10 ppg Surface 3,848 2011 MPI - 17 9 - 9.5 ppg Surface 3,864 2004 Assumptions: 1. Field test data suggests the Fracture Gradient in the Schrader Bluff is btwn 11.5 and 15 ppg EMW. 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: 3784 (ft) x 0.78(psi/ft)= 2951 2951(psi) - [0.1(psi/ft)*3784(ft)]= 2573 psi MASP from pore pressure (complete evacuation of wellbore to gas from Schrader Bluff NB sand) 3784 (ft) x 0.45(psi/ft)= 1702.0 psi 1702(psi) - 0.1(psi/ft)*3784(ft) 1325.0 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 M-43 Milne Point Unit 8.46 0.440 Page 50 Milne Point Unit M-44 SB Injector Drilling Procedure 30.0 Spider Plot (NAD 27) (Governmental Sections) Page 51 Milne Point Unit M-44 SB Injector Drilling Procedure 31.0 Surface Plat (As Built) (NAD 27) Page 52 Milne Point Unit M-44 SB Injector Drilling Procedure 32.0 Schrader Bluff NB Sand Offset MW vs TVD Chart This well 04 March, 2020 Plan: MPU M-44 wp02 Milne Point M Pt Moose Pad Plan: MPU M-44i - Slot 58 MPU M-44i 0 750 1500 2250 3000 3750 4500 5250True Vertical Depth (1500 usft/in)-1500 -750 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750 10500 11250 12000 12750 Vertical Section at 184.00° (1500 usft/in) MPU M-44 wp02 - Heel MPU M-44 wp02 - CP2 MPU M-44 wp02 - CP3 MPU M-44 wp02 - CP4 MPU M-44 wp02 - CP5 MPU M-44 wp02 - Toe 9 5/8" x 12 1/4" 4 1/2" x 8 1/2" 500 1000 1500 20 00 2 500 3000 3500 4 0 0 0 45005000550060006500700075008000850090009500100001050011000115001200012500130001350014000145001500015352MPU M-44 wp02 Start Dir 3º/100' : 280' MD, 280'TVD Start Dir 4º/100' : 550' MD, 549.1'TVD End Dir : 1566.81' MD, 1428.98' TVD StartDir4º/100':2770.23'MD, 2230.8'TVDEndDir :5543.54' MD, 3762.87'TVDStartDir4º/100':5843.54'MD, 3783.8'TVDEndDir :6139.31' MD, 3790.28'TVDStart Dir 4º/100' : 9155.81' MD, 3711.64'TVDEndDir : 9438.3' MD, 3697.07'TVDStartDir4º/100':9803.72'MD,3656.91'TVDEndDir :9935.93' MD, 3647.48'TVDStart Dir 4º/100' : 13119.02' MD,3552.47'TVDEndDir :13338.1' MD, 3562.63'TVDStartDir4º/100':13591.95'MD, 3593.72'TVDEndDir : 13812.07' MD, 3604.05'TVDTotal Depth:15351.84'MD,3558.8'TVDSV5 BPRF SV1 LA3 UGNU MB SB_NA SB_NB (heel) Hilcorp Alaska, LLC Calculation Method:Minimum Curvature Error System:ISCWSA Scan Method: Closest Approach 3D Error Surface: Pedal Curve Warning Method: Error Ratio WELL DETAILS: Plan: MPU M-44i - Slot 58 25.10 +N/-S +E/-W Northing Easting Latittude Longitude 0.00 0.00 6027889.70 534143.85 70° 29' 13.989 N 149° 43' 15.335 W SURVEY PROGRAM Date: 2019-12-11T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 33.40 800.00 MPU M-44 wp02 (MPU M-44i) 3_Gyro-GC_Csg 800.00 5843.54 MPU M-44 wp02 (MPU M-44i) 3_MWD+IFR2+MS+Sag 5843.54 15351.84 MPU M-44 wp02 (MPU M-44i) 3_MWD+IFR2+MS+Sag FORMATION TOP DETAILS TVDPath TVDssPath MDPath Formation 1343.80 1285.00 1444.65 SV5 1883.80 1825.00 2249.43 BPRF 1927.80 1869.00 2315.47 SV1 3219.80 3161.00 4154.34 LA3 3503.80 3445.00 4647.83 UGNU MB 3741.80 3683.00 5362.36 SB_NA 3779.80 3721.00 5786.19 SB_NB (heel)REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Plan: MPU M-44i - Slot 58, True North Vertical (TVD) Reference:MPU M-44 Planned RKB @ 58.80usft Measured Depth Reference:MPU M-44 Planned RKB @ 58.80usft Calculation Method:Minimum Curvature Project:Milne Point Site:M Pt Moose Pad Well:Plan: MPU M-44i - Slot 58 Wellbore:MPU M-44i Design:MPU M-44 wp02 CASING DETAILS TVD TVDSS MD Size Name 3783.80 3725.00 5843.54 9-5/8 9 5/8" x 12 1/4" 3558.80 3500.00 15351.84 4-1/2 4 1/2" x 8 1/2" SECTION DETAILS Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation 1 33.40 0.00 0.00 33.40 0.00 0.00 0.00 0.00 0.00 2 280.00 0.00 0.00 280.00 0.00 0.00 0.00 0.00 0.00 Start Dir 3º/100' : 280' MD, 280'TVD 3 550.00 8.10 30.00 549.10 16.50 9.53 3.00 30.00 -17.13 Start Dir 4º/100' : 550' MD, 549.1'TVD 4 750.00 15.55 45.05 744.76 47.69 35.58 4.00 30.00 -50.06 5 1566.81 48.22 44.43 1428.98 350.78 334.38 4.00 -0.85 -373.25 End Dir : 1566.81' MD, 1428.98' TVD 6 2770.23 48.22 44.43 2230.80 991.62 962.58 0.00 0.00 -1056.35 Start Dir 4º/100' : 2770.23' MD, 2230.8'TVD 7 5543.54 86.00 167.30 3762.87 74.42 2505.64 4.00 116.23 -249.02 End Dir : 5543.54' MD, 3762.87' TVD 8 5843.54 86.00 167.30 3783.80 -217.53 2571.43 0.00 0.00 37.62 MPU M-44 wp02 - Heel Start Dir 4º/100' : 5843.54' MD, 3783.8'TVD 9 6139.31 91.49 177.78 3790.28 -510.21 2609.72 4.00 62.53 326.92 End Dir : 6139.31' MD, 3790.28' TVD 10 9155.81 91.49 177.78 3711.64 -3523.43 2726.29 0.00 0.00 3324.67 Start Dir 4º/100' : 9155.81' MD, 3711.64'TVD 11 9355.38 93.00 185.63 3703.80 -3722.59 2720.36 4.00 78.99 3523.76 MPU M-44 wp02 - CP2 12 9438.30 96.31 185.85 3697.07 -3804.82 2712.09 4.00 3.81 3606.36 End Dir : 9438.3' MD, 3697.07' TVD 13 9803.72 96.31 185.85 3656.91 -4166.14 2675.06 0.00 0.00 3969.38 Start Dir 4º/100' : 9803.72' MD, 3656.91'TVD 14 9903.68 93.00 183.60 3648.80 -4265.41 2666.86 4.00 -145.76 4068.99 MPU M-44 wp02 - CP3 15 9935.93 91.71 183.59 3647.48 -4297.56 2664.84 4.00 -179.76 4101.20 End Dir : 9935.93' MD, 3647.48' TVD 16 13119.02 91.71 183.59 3552.47 -7472.98 2465.36 0.00 0.00 7282.80 Start Dir 4º/100' : 13119.02' MD, 3552.47'TVD 17 13237.15 87.00 183.97 3553.80 -7590.81 2457.57 4.00 175.44 7400.89 MPU M-44 wp02 - CP4 18 13338.10 82.96 183.83 3562.63 -7691.12 2450.74 4.00 -177.98 7501.43 End Dir : 13338.1' MD, 3562.63' TVD 19 13591.95 82.96 183.83 3593.72 -7942.49 2433.92 0.00 0.00 7753.36 Start Dir 4º/100' : 13591.95' MD, 3593.72'TVD 20 13719.96 88.00 184.76 3603.80 -8069.71 2424.37 4.00 10.51 7880.94 MPU M-44 wp02 - CP5 21 13812.07 91.68 184.76 3604.05 -8161.48 2416.72 4.00 0.07 7973.02 End Dir : 13812.07' MD, 3604.05' TVD 22 15351.84 91.68 184.76 3558.80 -9695.27 2288.89 0.00 0.00 9511.98 MPU M-44 wp02 - Toe Total Depth : 15351.84' MD, 3558.8' TVD -10500 -9750 -9000 -8250 -7500 -6750 -6000 -5250 -4500 -3750 -3000 -2250 -1500 -750 0 750 1500 2250 South(-)/North(+) (1500 usft/in)-6000 -5250 -4500 -3750 -3000 -2250 -1500 -750 0 750 1500 2250 3000 3750 4500 West(-)/East(+) (1500 usft/in) MPU M-44 wp02 - Toe MPU M-44 wp02 - CP5 MPU M-44 wp02 - CP4 MPU M-44 wp02 - CP3 MPU M-44 wp02 - CP2 MPU M-44 wp02 - Heel MPU 500' Buffer 9 5/8" x 12 1/4" 4 1/2" x 8 1/2" 1000 1500 2000 2 2 5 0 27503000325035003 7 5 0 3559 MPU M-44 wp02 Start Dir 3º/100' : 280' MD, 280'TVD Start Dir 4º/100' : 550' MD, 549.1'TVD End Dir : 1566.81' MD, 1428.98' TVD Start Dir 4º/100' : 2770.23' MD, 2230.8'TVD End Dir : 5543.54' MD, 3762.87' TVD Start Dir 4º/100' : 5843.54' MD, 3783.8'TVD End Dir : 6139.31' MD, 3790.28' TVD Start Dir 4º/100' : 9155.81' MD, 3711.64'TVD End Dir : 9438.3' MD, 3697.07' TVD Start Dir 4º/100' : 9803.72' MD, 3656.91'TVD End Dir : 9935.93' MD, 3647.48' TVD Start Dir 4º/100' : 13119.02' MD, 3552.47'TVD End Dir : 13338.1' MD, 3562.63' TVD Start Dir 4º/100' : 13591.95' MD, 3593.72'TVD End Dir : 13812.07' MD, 3604.05' TVD Total Depth : 15351.84' MD, 3558.8' TVD CASING DETAILS TVD TVDSS MD Size Name 3783.80 3725.00 5843.54 9-5/8 9 5/8" x 12 1/4" 3558.80 3500.00 15351.84 4-1/2 4 1/2" x 8 1/2" Project: Milne Point Site: M Pt Moose Pad Well: Plan: MPU M-44i - Slot 58 Wellbore: MPU M-44i Plan: MPU M-44 wp02 WELL DETAILS: Plan: MPU M-44i - Slot 58 25.10 +N/-S +E/-W Northing Easting Latittude Longitude 0.00 0.00 6027889.70 534143.85 70° 29' 13.989 N 149° 43' 15.335 W REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Plan: MPU M-44i - Slot 58, True North Vertical (TVD) Reference:MPU M-44 Planned RKB @ 58.80usft Measured Depth Reference:MPU M-44 Planned RKB @ 58.80usft Calculation Method:Minimum Curvature Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt Moose Pad Halliburton Standard Proposal Report Well: Wellbore: Plan: MPU M-44i - Slot 58 MPU M-44i Survey Calculation Method:Minimum Curvature MPU M-44 Planned RKB @ 58.80usft Design:MPU M-44 wp02 Database:NORTH US + CANADA MD Reference:MPU M-44 Planned RKB @ 58.80usft North Reference: Well Plan: MPU M-44i - Slot 58 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 Moose Pad usft Map usft usft °0.26Slot Radius:"13-3/16 6,027,877.65 533,363.92 5.00 70° 29' 13.905 N 149° 43' 38.286 W Well Well Position Longitude: Latitude: Easting: Northing: usft +E/-W +N/-S Position Uncertainty usft usft usftGround Level: Plan: MPU M-44i - Slot 58 usft usft 0.00 0.00 6,027,889.70 534,143.85 25.10Wellhead Elevation:25.40 usft0.50 70° 29' 13.989 N 149° 43' 15.335 W Wellbore Declination (°) Field Strength (nT) Sample Date Dip Angle (°) MPU M-44i Model NameMagnetics BGGM2019 4/14/2020 16.05 80.89 57,389.12196134 Phase:Version: Audit Notes: Design MPU M-44 wp02 PLAN Vertical Section: Depth From (TVD) (usft) +N/-S (usft) Direction (°) +E/-W (usft) Tie On Depth:33.40 184.000.000.0033.40 3/4/2020 5:45:10PM COMPASS 5000.15 Build 91E Page 2 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt Moose Pad Halliburton Standard Proposal Report Well: Wellbore: Plan: MPU M-44i - Slot 58 MPU M-44i Survey Calculation Method:Minimum Curvature MPU M-44 Planned RKB @ 58.80usft Design:MPU M-44 wp02 Database:NORTH US + CANADA MD Reference:MPU M-44 Planned RKB @ 58.80usft North Reference: Well Plan: MPU M-44i - Slot 58 True Inclination (°) Azimuth (°) +E/-W (usft) Tool Face (°) +N/-S (usft) Measured Depth (usft) Vertical Depth (usft) Dogleg Rate (°/100usft) Build Rate (°/100usft) Turn Rate (°/100usft) Plan Sections TVD System usft 0.000.000.000.000.000.0033.400.000.0033.40 -25.40 0.000.000.000.000.000.00280.000.000.00280.00 221.20 30.000.003.003.009.5316.50549.1030.008.10550.00 490.30 30.007.523.724.0035.5847.69744.7645.0515.55750.00 685.96 -0.85-0.084.004.00334.38350.781,428.9844.4348.221,566.81 1,370.18 0.000.000.000.00962.58991.622,230.8044.4348.222,770.23 2,172.00 116.234.431.364.002,505.6474.423,762.87167.3086.005,543.54 3,704.07 0.000.000.000.002,571.43-217.533,783.80167.3086.005,843.54 3,725.00 62.533.541.864.002,609.72-510.213,790.28177.7891.496,139.31 3,731.48 0.000.000.000.002,726.29-3,523.433,711.64177.7891.499,155.81 3,652.84 78.993.930.754.002,720.36-3,722.593,703.80185.6393.009,355.38 3,645.00 3.810.273.994.002,712.09-3,804.823,697.07185.8596.319,438.30 3,638.27 0.000.000.000.002,675.06-4,166.143,656.91185.8596.319,803.72 3,598.11 -145.76-2.25-3.314.002,666.86-4,265.413,648.80183.6093.009,903.68 3,590.00 -179.76-0.02-4.004.002,664.84-4,297.563,647.48183.5991.719,935.93 3,588.68 0.000.000.000.002,465.36-7,472.983,552.47183.5991.7113,119.02 3,493.67 175.440.32-3.994.002,457.57-7,590.813,553.80183.9787.0013,237.15 3,495.00 -177.98-0.14-4.004.002,450.74-7,691.123,562.63183.8382.9613,338.10 3,503.83 0.000.000.000.002,433.92-7,942.493,593.72183.8382.9613,591.95 3,534.92 10.510.733.934.002,424.37-8,069.713,603.80184.7688.0013,719.96 3,545.00 0.070.004.004.002,416.72-8,161.483,604.05184.7691.6813,812.07 3,545.25 0.000.000.000.002,288.89-9,695.273,558.80184.7691.6815,351.84 3,500.00 3/4/2020 5:45:10PM COMPASS 5000.15 Build 91E Page 3 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt Moose Pad Halliburton Standard Proposal Report Well: Wellbore: Plan: MPU M-44i - Slot 58 MPU M-44i Survey Calculation Method:Minimum Curvature MPU M-44 Planned RKB @ 58.80usft Design:MPU M-44 wp02 Database:NORTH US + CANADA MD Reference:MPU M-44 Planned RKB @ 58.80usft North Reference: Well Plan: MPU M-44i - Slot 58 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 -25.40 Vert Section 33.40 0.00 33.40 0.00 0.000.00 534,143.856,027,889.70-25.40 0.00 0.00 100.00 0.00 100.00 0.00 0.000.00 534,143.856,027,889.7041.20 0.00 0.00 200.00 0.00 200.00 0.00 0.000.00 534,143.856,027,889.70141.20 0.00 0.00 280.00 0.00 280.00 0.00 0.000.00 534,143.856,027,889.70221.20 0.00 0.00 Start Dir 3º/100' : 280' MD, 280'TVD 300.00 0.60 300.00 0.09 0.0530.00 534,143.906,027,889.79241.20 3.00 -0.09 400.00 3.60 399.92 3.26 1.8830.00 534,145.726,027,892.97341.12 3.00 -3.39 500.00 6.60 499.51 10.96 6.3330.00 534,150.136,027,900.69440.71 3.00 -11.38 550.00 8.10 549.10 16.50 9.5330.00 534,153.306,027,906.24490.30 3.00 -17.13 Start Dir 4º/100' : 550' MD, 549.1'TVD 600.00 9.88 598.49 23.03 13.8035.84 534,157.546,027,912.79539.69 4.00 -23.94 700.00 13.63 696.38 38.64 26.8442.82 534,170.516,027,928.45637.58 4.00 -40.41 750.00 15.55 744.76 47.69 35.5845.05 534,179.216,027,937.55685.96 4.00 -50.06 800.00 17.55 792.69 57.76 45.6544.95 534,189.236,027,947.67733.89 4.00 -60.81 900.00 21.55 886.91 81.47 69.2544.80 534,212.726,027,971.48828.11 4.00 -86.10 1,000.00 25.55 978.56 109.84 97.3744.70 534,240.716,027,999.97919.76 4.00 -116.36 1,100.00 29.55 1,067.21 142.72 129.8744.63 534,273.056,028,033.011,008.41 4.00 -151.44 1,200.00 33.55 1,152.41 179.97 166.6044.57 534,309.616,028,070.421,093.61 4.00 -191.16 1,300.00 37.55 1,233.76 221.40 207.3744.52 534,350.196,028,112.031,174.96 4.00 -235.32 1,400.00 41.55 1,310.85 266.80 251.9944.48 534,394.596,028,157.631,252.05 4.00 -283.73 1,444.65 43.33 1,343.80 288.30 273.1044.47 534,415.606,028,179.221,285.00 4.00 -306.65 SV5 1,500.00 45.55 1,383.32 315.96 300.2444.45 534,442.616,028,207.001,324.52 4.00 -336.13 1,566.81 48.22 1,428.98 350.78 334.3944.43 534,476.596,028,241.971,370.18 4.00 -373.25 End Dir : 1566.81' MD, 1428.98' TVD 1,600.00 48.22 1,451.09 368.45 351.7144.43 534,493.836,028,259.731,392.29 0.00 -392.09 1,700.00 48.22 1,517.72 421.70 403.9144.43 534,545.786,028,313.211,458.92 0.00 -448.85 1,800.00 48.22 1,584.35 474.95 456.1144.43 534,597.736,028,366.701,525.55 0.00 -505.61 1,900.00 48.22 1,650.98 528.21 508.3144.43 534,649.686,028,420.181,592.18 0.00 -562.38 2,000.00 48.22 1,717.61 581.46 560.5144.43 534,701.636,028,473.671,658.81 0.00 -619.14 2,100.00 48.22 1,784.23 634.71 612.7144.43 534,753.586,028,527.151,725.43 0.00 -675.90 2,200.00 48.22 1,850.86 687.96 664.9244.43 534,805.536,028,580.641,792.06 0.00 -732.67 2,249.43 48.22 1,883.80 714.29 690.7244.43 534,831.226,028,607.081,825.00 0.00 -760.73 BPRF 2,300.00 48.22 1,917.49 741.21 717.1244.43 534,857.496,028,634.121,858.69 0.00 -789.43 2,315.47 48.22 1,927.80 749.45 725.1944.43 534,865.526,028,642.401,869.00 0.00 -798.21 SV1 2,400.00 48.22 1,984.12 794.46 769.3244.43 534,909.446,028,687.611,925.32 0.00 -846.19 2,500.00 48.22 2,050.75 847.72 821.5244.43 534,961.396,028,741.091,991.95 0.00 -902.96 2,600.00 48.22 2,117.38 900.97 873.7244.43 535,013.346,028,794.582,058.58 0.00 -959.72 2,700.00 48.22 2,184.00 954.22 925.9244.43 535,065.296,028,848.072,125.20 0.00 -1,016.48 2,770.23 48.22 2,230.80 991.62 962.5844.43 535,101.776,028,885.632,172.00 0.00 -1,056.35 Start Dir 4º/100' : 2770.23' MD, 2230.8'TVD 2,800.00 47.70 2,250.73 1,007.21 978.2545.87 535,117.376,028,901.292,191.93 4.00 -1,073.00 2,900.00 46.10 2,319.08 1,055.70 1,032.7850.90 535,171.676,028,950.032,260.28 4.00 -1,125.18 3/4/2020 5:45:10PM COMPASS 5000.15 Build 91E Page 4 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt Moose Pad Halliburton Standard Proposal Report Well: Wellbore: Plan: MPU M-44i - Slot 58 MPU M-44i Survey Calculation Method:Minimum Curvature MPU M-44 Planned RKB @ 58.80usft Design:MPU M-44 wp02 Database:NORTH US + CANADA MD Reference:MPU M-44 Planned RKB @ 58.80usft North Reference: Well Plan: MPU M-44i - Slot 58 True Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Map Northing (usft) Map Easting (usft) +N/-S (usft) Planned Survey Vertical Depth (usft) TVDss usft DLS 2,330.49 Vert Section 3,000.00 44.74 2,389.29 1,098.04 1,090.0056.17 535,228.696,028,992.622,330.49 4.00 -1,171.40 3,100.00 43.62 2,461.04 1,134.00 1,149.6361.69 535,288.146,029,028.852,402.24 4.00 -1,211.43 3,200.00 42.78 2,533.96 1,163.42 1,211.3767.40 535,349.756,029,058.552,475.16 4.00 -1,245.09 3,300.00 42.24 2,607.70 1,186.15 1,274.9473.27 535,413.216,029,081.582,548.90 4.00 -1,272.20 3,400.00 42.00 2,681.91 1,202.09 1,340.0279.22 535,478.216,029,097.812,623.11 4.00 -1,292.64 3,500.00 42.06 2,756.22 1,211.15 1,406.2985.20 535,544.436,029,107.182,697.42 4.00 -1,306.30 3,600.00 42.44 2,830.27 1,213.30 1,473.4491.12 535,611.566,029,109.632,771.47 4.00 -1,313.12 3,700.00 43.12 2,903.69 1,208.51 1,541.1296.93 535,679.266,029,105.152,844.89 4.00 -1,313.07 3,800.00 44.08 2,976.14 1,196.82 1,609.02102.56 535,747.206,029,093.772,917.34 4.00 -1,306.14 3,900.00 45.30 3,047.26 1,178.27 1,676.80107.98 535,815.066,029,075.542,988.46 4.00 -1,292.37 4,000.00 46.77 3,116.70 1,152.97 1,744.14113.15 535,882.506,029,050.553,057.90 4.00 -1,271.83 4,100.00 48.47 3,184.12 1,121.03 1,810.70118.05 535,949.206,029,018.923,125.32 4.00 -1,244.61 4,154.34 49.47 3,219.80 1,100.95 1,846.42120.61 535,985.026,028,999.013,161.00 4.00 -1,227.07 LA3 4,200.00 50.36 3,249.20 1,082.62 1,876.15122.70 536,014.836,028,980.813,190.40 4.00 -1,210.85 4,300.00 52.42 3,311.62 1,037.91 1,940.19127.08 536,079.076,028,936.403,252.82 4.00 -1,170.72 4,400.00 54.64 3,371.07 987.12 2,002.50131.22 536,141.606,028,885.913,312.27 4.00 -1,124.40 4,500.00 56.99 3,427.27 930.51 2,062.78135.13 536,202.136,028,829.583,368.47 4.00 -1,072.13 4,600.00 59.46 3,479.93 868.34 2,120.72138.84 536,260.366,028,767.683,421.13 4.00 -1,014.16 4,647.83 60.68 3,503.80 836.74 2,147.53140.54 536,287.316,028,736.203,445.00 4.00 -984.50 UGNU MB 4,700.00 62.03 3,528.81 800.93 2,176.06142.36 536,316.006,028,700.533,470.01 4.00 -950.77 4,800.00 64.68 3,573.67 728.60 2,228.52145.71 536,368.786,028,628.453,514.87 4.00 -882.27 4,900.00 67.40 3,614.28 651.69 2,277.84148.91 536,418.456,028,551.783,555.48 4.00 -809.00 5,000.00 70.19 3,650.46 570.60 2,323.78151.99 536,464.766,028,470.903,591.66 4.00 -731.31 5,100.00 73.03 3,682.01 485.70 2,366.13154.96 536,507.496,028,386.213,623.21 4.00 -649.57 5,200.00 75.90 3,708.80 397.42 2,404.67157.85 536,546.436,028,298.123,650.00 4.00 -564.20 5,300.00 78.82 3,730.68 306.19 2,439.21160.66 536,581.396,028,207.053,671.88 4.00 -475.60 5,362.36 80.64 3,741.80 248.00 2,458.66162.38 536,601.106,028,148.963,683.00 4.00 -418.90 SB_NA 5,400.00 81.75 3,747.56 212.45 2,469.59163.41 536,612.206,028,113.463,688.76 4.00 -384.20 5,500.00 84.71 3,759.35 116.65 2,495.67166.13 536,638.716,028,017.793,700.55 4.00 -290.45 5,543.54 86.00 3,762.87 74.42 2,505.64167.30 536,648.876,027,975.613,704.07 4.00 -249.02 End Dir : 5543.54' MD, 3762.87' TVD 5,600.00 86.00 3,766.81 19.47 2,518.02167.30 536,661.516,027,920.733,708.01 0.00 -195.07 5,700.00 86.00 3,773.79 -77.84 2,539.95167.30 536,683.886,027,823.523,714.99 0.00 -99.52 5,786.19 86.00 3,779.80 -161.73 2,558.86167.30 536,703.176,027,739.743,721.00 0.00 -17.17 SB_NB (heel) 5,800.00 86.00 3,780.76 -175.16 2,561.88167.30 536,706.266,027,726.323,721.96 0.00 -3.97 5,843.54 86.00 3,783.80 -217.53 2,571.43167.30 536,716.006,027,684.003,725.00 0.00 37.63 Start Dir 4º/100' : 5843.54' MD, 3783.8'TVD - 9 5/8" x 12 1/4" 5,900.00 87.04 3,787.23 -272.71 2,582.86169.31 536,727.686,027,628.873,728.43 4.00 91.88 6,000.00 88.90 3,790.76 -371.42 2,598.35172.85 536,743.626,027,530.253,731.96 4.00 189.27 6,100.00 90.76 3,791.06 -470.96 2,607.72176.39 536,753.456,027,430.763,732.26 4.00 287.91 3/4/2020 5:45:10PM COMPASS 5000.15 Build 91E Page 5 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt Moose Pad Halliburton Standard Proposal Report Well: Wellbore: Plan: MPU M-44i - Slot 58 MPU M-44i Survey Calculation Method:Minimum Curvature MPU M-44 Planned RKB @ 58.80usft Design:MPU M-44 wp02 Database:NORTH US + CANADA MD Reference:MPU M-44 Planned RKB @ 58.80usft North Reference: Well Plan: MPU M-44i - Slot 58 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 3,731.48 Vert Section 6,139.31 91.49 3,790.28 -510.21 2,609.72177.78 536,755.626,027,391.523,731.48 4.00 326.93 End Dir : 6139.31' MD, 3790.28' TVD 6,200.00 91.49 3,788.70 -570.84 2,612.06177.78 536,758.256,027,330.923,729.90 0.00 387.24 6,300.00 91.49 3,786.09 -670.73 2,615.93177.78 536,762.576,027,231.053,727.29 0.00 486.62 6,400.00 91.49 3,783.49 -770.62 2,619.79177.78 536,766.896,027,131.193,724.69 0.00 585.99 6,500.00 91.49 3,780.88 -870.51 2,623.66177.78 536,771.216,027,031.333,722.08 0.00 685.37 6,600.00 91.49 3,778.27 -970.40 2,627.52177.78 536,775.546,026,931.473,719.47 0.00 784.75 6,700.00 91.49 3,775.66 -1,070.29 2,631.38177.78 536,779.866,026,831.603,716.86 0.00 884.13 6,800.00 91.49 3,773.06 -1,170.18 2,635.25177.78 536,784.186,026,731.743,714.26 0.00 983.51 6,900.00 91.49 3,770.45 -1,270.08 2,639.11177.78 536,788.516,026,631.883,711.65 0.00 1,082.89 7,000.00 91.49 3,767.84 -1,369.97 2,642.98177.78 536,792.836,026,532.023,709.04 0.00 1,182.26 7,100.00 91.49 3,765.24 -1,469.86 2,646.84177.78 536,797.156,026,432.153,706.44 0.00 1,281.64 7,200.00 91.49 3,762.63 -1,569.75 2,650.71177.78 536,801.476,026,332.293,703.83 0.00 1,381.02 7,300.00 91.49 3,760.02 -1,669.64 2,654.57177.78 536,805.806,026,232.433,701.22 0.00 1,480.40 7,400.00 91.49 3,757.41 -1,769.53 2,658.44177.78 536,810.126,026,132.573,698.61 0.00 1,579.78 7,500.00 91.49 3,754.81 -1,869.42 2,662.30177.78 536,814.446,026,032.703,696.01 0.00 1,679.16 7,600.00 91.49 3,752.20 -1,969.31 2,666.16177.78 536,818.766,025,932.843,693.40 0.00 1,778.54 7,700.00 91.49 3,749.59 -2,069.21 2,670.03177.78 536,823.096,025,832.983,690.79 0.00 1,877.91 7,800.00 91.49 3,746.99 -2,169.10 2,673.89177.78 536,827.416,025,733.113,688.19 0.00 1,977.29 7,900.00 91.49 3,744.38 -2,268.99 2,677.76177.78 536,831.736,025,633.253,685.58 0.00 2,076.67 8,000.00 91.49 3,741.77 -2,368.88 2,681.62177.78 536,836.056,025,533.393,682.97 0.00 2,176.05 8,100.00 91.49 3,739.16 -2,468.77 2,685.49177.78 536,840.386,025,433.533,680.36 0.00 2,275.43 8,200.00 91.49 3,736.56 -2,568.66 2,689.35177.78 536,844.706,025,333.663,677.76 0.00 2,374.81 8,300.00 91.49 3,733.95 -2,668.55 2,693.22177.78 536,849.026,025,233.803,675.15 0.00 2,474.18 8,400.00 91.49 3,731.34 -2,768.44 2,697.08177.78 536,853.346,025,133.943,672.54 0.00 2,573.56 8,500.00 91.49 3,728.73 -2,868.34 2,700.94177.78 536,857.676,025,034.083,669.93 0.00 2,672.94 8,600.00 91.49 3,726.13 -2,968.23 2,704.81177.78 536,861.996,024,934.213,667.33 0.00 2,772.32 8,700.00 91.49 3,723.52 -3,068.12 2,708.67177.78 536,866.316,024,834.353,664.72 0.00 2,871.70 8,800.00 91.49 3,720.91 -3,168.01 2,712.54177.78 536,870.636,024,734.493,662.11 0.00 2,971.08 8,900.00 91.49 3,718.31 -3,267.90 2,716.40177.78 536,874.966,024,634.633,659.51 0.00 3,070.45 9,000.00 91.49 3,715.70 -3,367.79 2,720.27177.78 536,879.286,024,534.763,656.90 0.00 3,169.83 9,100.00 91.49 3,713.09 -3,467.68 2,724.13177.78 536,883.606,024,434.903,654.29 0.00 3,269.21 9,155.81 91.49 3,711.64 -3,523.43 2,726.29177.78 536,886.016,024,379.173,652.84 0.00 3,324.67 Start Dir 4º/100' : 9155.81' MD, 3711.64'TVD 9,200.00 91.83 3,710.35 -3,567.59 2,727.33179.52 536,887.266,024,335.023,651.55 4.00 3,368.65 9,300.00 92.59 3,706.50 -3,667.46 2,724.74183.45 536,885.126,024,235.153,647.70 4.00 3,468.46 9,355.38 93.00 3,703.80 -3,722.59 2,720.36185.63 536,881.006,024,180.003,645.00 4.00 3,523.76 9,400.00 94.78 3,700.77 -3,766.90 2,715.94185.75 536,876.796,024,135.683,641.97 4.00 3,568.26 9,438.30 96.31 3,697.07 -3,804.82 2,712.09185.85 536,873.116,024,097.753,638.27 4.00 3,606.37 End Dir : 9438.3' MD, 3697.07' TVD 9,500.00 96.31 3,690.29 -3,865.83 2,705.84185.85 536,867.146,024,036.723,631.49 0.00 3,667.66 9,600.00 96.31 3,679.30 -3,964.70 2,695.71185.85 536,857.466,023,937.813,620.50 0.00 3,767.00 9,700.00 96.31 3,668.31 -4,063.58 2,685.57185.85 536,847.786,023,838.893,609.51 0.00 3,866.34 9,803.72 96.31 3,656.91 -4,166.13 2,675.06185.85 536,837.756,023,736.303,598.11 0.00 3,969.38 Start Dir 4º/100' : 9803.72' MD, 3656.91'TVD 3/4/2020 5:45:10PM COMPASS 5000.15 Build 91E Page 6 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt Moose Pad Halliburton Standard Proposal Report Well: Wellbore: Plan: MPU M-44i - Slot 58 MPU M-44i Survey Calculation Method:Minimum Curvature MPU M-44 Planned RKB @ 58.80usft Design:MPU M-44 wp02 Database:NORTH US + CANADA MD Reference:MPU M-44 Planned RKB @ 58.80usft North Reference: Well Plan: MPU M-44i - Slot 58 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 3,590.00 Vert Section 9,903.68 93.00 3,648.80 -4,265.41 2,666.86183.60 536,830.006,023,637.003,590.00 4.00 4,068.99 9,935.93 91.71 3,647.47 -4,297.56 2,664.84183.59 536,828.136,023,604.843,588.67 4.00 4,101.21 End Dir : 9935.93' MD, 3647.48' TVD 10,000.00 91.71 3,645.56 -4,361.48 2,660.82183.59 536,824.416,023,540.913,586.76 0.00 4,165.25 10,100.00 91.71 3,642.58 -4,461.24 2,654.56183.59 536,818.606,023,441.133,583.78 0.00 4,265.20 10,200.00 91.71 3,639.59 -4,561.00 2,648.29183.59 536,812.796,023,341.363,580.79 0.00 4,365.15 10,300.00 91.71 3,636.61 -4,660.76 2,642.02183.59 536,806.986,023,241.583,577.81 0.00 4,465.10 10,400.00 91.71 3,633.62 -4,760.51 2,635.76183.59 536,801.176,023,141.803,574.82 0.00 4,565.06 10,500.00 91.71 3,630.64 -4,860.27 2,629.49183.59 536,795.366,023,042.033,571.84 0.00 4,665.01 10,600.00 91.71 3,627.65 -4,960.03 2,623.22183.59 536,789.566,022,942.253,568.85 0.00 4,764.96 10,700.00 91.71 3,624.67 -5,059.79 2,616.96183.59 536,783.756,022,842.473,565.87 0.00 4,864.92 10,800.00 91.71 3,621.69 -5,159.55 2,610.69183.59 536,777.946,022,742.703,562.89 0.00 4,964.87 10,900.00 91.71 3,618.70 -5,259.31 2,604.42183.59 536,772.136,022,642.923,559.90 0.00 5,064.82 11,000.00 91.71 3,615.72 -5,359.07 2,598.16183.59 536,766.326,022,543.143,556.92 0.00 5,164.78 11,100.00 91.71 3,612.73 -5,458.83 2,591.89183.59 536,760.526,022,443.373,553.93 0.00 5,264.73 11,200.00 91.71 3,609.75 -5,558.59 2,585.62183.59 536,754.716,022,343.593,550.95 0.00 5,364.68 11,300.00 91.71 3,606.76 -5,658.34 2,579.36183.59 536,748.906,022,243.813,547.96 0.00 5,464.63 11,400.00 91.71 3,603.78 -5,758.10 2,573.09183.59 536,743.096,022,144.043,544.98 0.00 5,564.59 11,500.00 91.71 3,600.79 -5,857.86 2,566.82183.59 536,737.286,022,044.263,541.99 0.00 5,664.54 11,600.00 91.71 3,597.81 -5,957.62 2,560.56183.59 536,731.476,021,944.483,539.01 0.00 5,764.49 11,700.00 91.71 3,594.82 -6,057.38 2,554.29183.59 536,725.676,021,844.713,536.02 0.00 5,864.45 11,800.00 91.71 3,591.84 -6,157.14 2,548.02183.59 536,719.866,021,744.933,533.04 0.00 5,964.40 11,900.00 91.71 3,588.85 -6,256.90 2,541.75183.59 536,714.056,021,645.153,530.05 0.00 6,064.35 12,000.00 91.71 3,585.87 -6,356.66 2,535.49183.59 536,708.246,021,545.383,527.07 0.00 6,164.30 12,100.00 91.71 3,582.89 -6,456.41 2,529.22183.59 536,702.436,021,445.603,524.09 0.00 6,264.26 12,200.00 91.71 3,579.90 -6,556.17 2,522.95183.59 536,696.636,021,345.823,521.10 0.00 6,364.21 12,300.00 91.71 3,576.92 -6,655.93 2,516.69183.59 536,690.826,021,246.053,518.12 0.00 6,464.16 12,400.00 91.71 3,573.93 -6,755.69 2,510.42183.59 536,685.016,021,146.273,515.13 0.00 6,564.12 12,500.00 91.71 3,570.95 -6,855.45 2,504.15183.59 536,679.206,021,046.493,512.15 0.00 6,664.07 12,600.00 91.71 3,567.96 -6,955.21 2,497.89183.59 536,673.396,020,946.723,509.16 0.00 6,764.02 12,700.00 91.71 3,564.98 -7,054.97 2,491.62183.59 536,667.596,020,846.943,506.18 0.00 6,863.98 12,800.00 91.71 3,561.99 -7,154.73 2,485.35183.59 536,661.786,020,747.163,503.19 0.00 6,963.93 12,900.00 91.71 3,559.01 -7,254.48 2,479.09183.59 536,655.976,020,647.393,500.21 0.00 7,063.88 13,000.00 91.71 3,556.02 -7,354.24 2,472.82183.59 536,650.166,020,547.613,497.22 0.00 7,163.83 13,100.00 91.71 3,553.04 -7,454.00 2,466.55183.59 536,644.356,020,447.833,494.24 0.00 7,263.79 13,119.02 91.71 3,552.47 -7,472.98 2,465.36183.59 536,643.256,020,428.863,493.67 0.00 7,282.80 Start Dir 4º/100' : 13119.02' MD, 3552.47'TVD 13,200.00 88.48 3,552.34 -7,553.77 2,460.10183.85 536,638.366,020,348.043,493.54 4.00 7,363.77 13,237.15 87.00 3,553.80 -7,590.81 2,457.57183.97 536,636.006,020,311.003,495.00 4.00 7,400.89 13,300.00 84.49 3,558.46 -7,653.33 2,453.28183.88 536,632.006,020,248.463,499.66 4.00 7,463.56 13,338.10 82.96 3,562.63 -7,691.12 2,450.74183.83 536,629.636,020,210.673,503.83 4.00 7,501.43 End Dir : 13338.1' MD, 3562.63' TVD 13,400.00 82.96 3,570.21 -7,752.42 2,446.64183.83 536,625.816,020,149.363,511.41 0.00 7,562.86 13,500.00 82.96 3,582.46 -7,851.44 2,440.01183.83 536,619.646,020,050.323,523.66 0.00 7,662.11 3/4/2020 5:45:10PM COMPASS 5000.15 Build 91E Page 7 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt Moose Pad Halliburton Standard Proposal Report Well: Wellbore: Plan: MPU M-44i - Slot 58 MPU M-44i Survey Calculation Method:Minimum Curvature MPU M-44 Planned RKB @ 58.80usft Design:MPU M-44 wp02 Database:NORTH US + CANADA MD Reference:MPU M-44 Planned RKB @ 58.80usft North Reference: Well Plan: MPU M-44i - Slot 58 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 3,534.92 Vert Section 13,591.95 82.96 3,593.72 -7,942.50 2,433.92183.83 536,613.976,019,959.253,534.92 0.00 7,753.37 Start Dir 4º/100' : 13591.95' MD, 3593.72'TVD 13,600.00 83.28 3,594.68 -7,950.47 2,433.39183.89 536,613.476,019,951.273,535.88 4.00 7,761.36 13,700.00 87.21 3,602.97 -8,049.83 2,426.00184.62 536,606.546,019,851.883,544.17 4.00 7,860.99 13,719.96 88.00 3,603.80 -8,069.71 2,424.37184.76 536,605.006,019,832.003,545.00 4.00 7,880.94 13,800.00 91.20 3,604.36 -8,149.46 2,417.73184.76 536,598.726,019,752.233,545.56 4.00 7,960.95 13,812.07 91.68 3,604.05 -8,161.48 2,416.72184.76 536,597.786,019,740.203,545.25 4.00 7,973.02 End Dir : 13812.07' MD, 3604.05' TVD 13,900.00 91.68 3,601.47 -8,249.07 2,409.42184.76 536,590.886,019,652.593,542.67 0.00 8,060.90 14,000.00 91.68 3,598.53 -8,348.68 2,401.12184.76 536,583.046,019,552.953,539.73 0.00 8,160.85 14,100.00 91.68 3,595.59 -8,448.29 2,392.82184.76 536,575.196,019,453.313,536.79 0.00 8,260.80 14,200.00 91.68 3,592.65 -8,547.91 2,384.52184.76 536,567.356,019,353.673,533.85 0.00 8,360.75 14,300.00 91.68 3,589.71 -8,647.52 2,376.22184.76 536,559.506,019,254.043,530.91 0.00 8,460.70 14,400.00 91.68 3,586.77 -8,747.13 2,367.91184.76 536,551.666,019,154.403,527.97 0.00 8,560.64 14,500.00 91.68 3,583.84 -8,846.74 2,359.61184.76 536,543.826,019,054.763,525.04 0.00 8,660.59 14,600.00 91.68 3,580.90 -8,946.35 2,351.31184.76 536,535.976,018,955.123,522.10 0.00 8,760.54 14,700.00 91.68 3,577.96 -9,045.96 2,343.01184.76 536,528.136,018,855.483,519.16 0.00 8,860.49 14,800.00 91.68 3,575.02 -9,145.57 2,334.71184.76 536,520.296,018,755.843,516.22 0.00 8,960.43 14,900.00 91.68 3,572.08 -9,245.19 2,326.40184.76 536,512.446,018,656.203,513.28 0.00 9,060.38 15,000.00 91.68 3,569.14 -9,344.80 2,318.10184.76 536,504.606,018,556.573,510.34 0.00 9,160.33 15,100.00 91.68 3,566.20 -9,444.41 2,309.80184.76 536,496.756,018,456.933,507.40 0.00 9,260.28 15,200.00 91.68 3,563.26 -9,544.02 2,301.50184.76 536,488.916,018,357.293,504.46 0.00 9,360.23 15,300.00 91.68 3,560.32 -9,643.63 2,293.20184.76 536,481.076,018,257.653,501.52 0.00 9,460.17 15,351.84 91.68 3,558.80 -9,695.27 2,288.89184.76 536,477.006,018,206.003,500.00 0.00 9,511.98 Total Depth : 15351.84' MD, 3558.8' TVD 3/4/2020 5:45:10PM COMPASS 5000.15 Build 91E Page 8 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt Moose Pad Halliburton Standard Proposal Report Well: Wellbore: Plan: MPU M-44i - Slot 58 MPU M-44i Survey Calculation Method:Minimum Curvature MPU M-44 Planned RKB @ 58.80usft Design:MPU M-44 wp02 Database:NORTH US + CANADA MD Reference:MPU M-44 Planned RKB @ 58.80usft North Reference: Well Plan: MPU M-44i - Slot 58 True Target Name - hit/miss target - Shape TVD (usft) Northing (usft) Easting (usft) +N/-S (usft) +E/-W (usft) Tar gets Dip Angle (°) Dip Dir. (°) MPU M-44 wp02 - Toe 3,558.80 6,018,206.00 536,477.00-9,695.27 2,288.890.00 0.00 -plan hits target center - Point MPU M-44 wp02 - CP3 3,648.80 6,023,637.00 536,830.00-4,265.41 2,666.860.00 0.00 -plan hits target center - Point MPU M-44 wp02 - CP5 3,603.80 6,019,832.00 536,605.00-8,069.71 2,424.370.00 0.00 -plan hits target center - Point MPU M-44 wp02 - CP2 3,703.80 6,024,180.00 536,881.00-3,722.59 2,720.360.00 0.00 -plan hits target center - Point MPU M-44 wp02 - CP4 3,553.80 6,020,311.00 536,636.00-7,590.81 2,457.570.00 0.00 -plan hits target center - Point MPU M-44 wp02 - Heel 3,783.80 6,027,684.00 536,716.00-217.53 2,571.430.00 0.00 -plan hits target center - Circle (radius 30.00) Vertical Depth (usft) Measured Depth (usft) Casing Diameter (") Hole Diameter (")Name Casing Points 4 1/2" x 8 1/2"3,558.8015,351.84 4-1/2 8-1/2 9 5/8" x 12 1/4"3,783.805,843.54 9-5/8 12-1/4 Measured Depth (usft) Vertical Depth (usft) Dip Direction (°)Name Lithology Dip (°) Formations Vertical Depth SS 1,444.65 1,343.80 SV5 2,249.43 1,883.80 BPRF 2,315.47 1,927.80 SV1 4,154.34 3,219.80 LA3 4,647.83 3,503.80 UGNU MB 5,362.36 3,741.80 SB_NA 5,786.19 3,779.80 SB_NB (heel) 0.00 3/4/2020 5:45:10PM COMPASS 5000.15 Build 91E Page 9 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt Moose Pad Halliburton Standard Proposal Report Well: Wellbore: Plan: MPU M-44i - Slot 58 MPU M-44i Survey Calculation Method:Minimum Curvature MPU M-44 Planned RKB @ 58.80usft Design:MPU M-44 wp02 Database:NORTH US + CANADA MD Reference:MPU M-44 Planned RKB @ 58.80usft North Reference: Well Plan: MPU M-44i - Slot 58 True Measured Depth (usft) Vertical Depth (usft) +E/-W (usft) +N/-S (usft) Local Coordinates Comment Plan Annotations 280.00 280.00 0.00 0.00 Start Dir 3º/100' : 280' MD, 280'TVD 550.00 549.10 16.50 9.53 Start Dir 4º/100' : 550' MD, 549.1'TVD 1,566.81 1,428.98 350.78 334.39 End Dir : 1566.81' MD, 1428.98' TVD 2,770.23 2,230.80 991.62 962.58 Start Dir 4º/100' : 2770.23' MD, 2230.8'TVD 5,543.54 3,762.87 74.42 2,505.64 End Dir : 5543.54' MD, 3762.87' TVD 5,843.54 3,783.80 -217.53 2,571.43 Start Dir 4º/100' : 5843.54' MD, 3783.8'TVD 6,139.31 3,790.28 -510.21 2,609.72 End Dir : 6139.31' MD, 3790.28' TVD 9,155.81 3,711.64 -3,523.43 2,726.29 Start Dir 4º/100' : 9155.81' MD, 3711.64'TVD 9,438.30 3,697.07 -3,804.82 2,712.09 End Dir : 9438.3' MD, 3697.07' TVD 9,803.72 3,656.91 -4,166.13 2,675.06 Start Dir 4º/100' : 9803.72' MD, 3656.91'TVD 9,935.93 3,647.47 -4,297.56 2,664.84 End Dir : 9935.93' MD, 3647.48' TVD 13,119.02 3,552.47 -7,472.98 2,465.36 Start Dir 4º/100' : 13119.02' MD, 3552.47'TVD 13,338.10 3,562.63 -7,691.12 2,450.74 End Dir : 13338.1' MD, 3562.63' TVD 13,591.95 3,593.72 -7,942.50 2,433.92 Start Dir 4º/100' : 13591.95' MD, 3593.72'TVD 13,812.07 3,604.05 -8,161.48 2,416.72 End Dir : 13812.07' MD, 3604.05' TVD 15,351.84 3,558.80 -9,695.27 2,288.89 Total Depth : 15351.84' MD, 3558.8' TVD 3/4/2020 5:45:10PM COMPASS 5000.15 Build 91E Page 10 04 March, 2020 Milne Point M Pt Moose Pad Plan: MPU M-44i - Slot 58 MPU M-44i MPU M-44 wp02 Reference Design: M Pt Moose Pad - Plan: MPU M-44i - Slot 58 - MPU M-44i - MPU M-44 wp02 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Well Coordinates: 6,027,889.70 N, 534,143.85 E (70° 29' 13.99" N, 149° 43' 15.34" W) Datum Height: MPU M-44 Planned RKB @ 58.80usft Scan Range: 33.40 to 5,843.54 usft. Measured Depth. Geodetic Scale Factor Applied Version: 5000.15 Build: 91E Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usft NO GLOBAL FILTER: Using user defined selection & filtering criteriaScan Type: Scan Type:25.00 Milne Point Hilcorp Alaska, LLC Anticollision Report for Plan: MPU M-44i - Slot 58 - MPU M-44 wp02 Comparison Well Name - Wellbore Name - Design @Measured Depth (usft) Minimum Distance (usft) Ellipse Separation (usft) @Measured Depth usft Clearance Factor Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usft Site Name Scan Range: 33.40 to 5,843.54 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt Moose Pad - Plan: MPU M-44i - Slot 58 - MPU M-44i - MPU M-44 wp02 Measured Depth (usft) Summary Based on Minimum Separation Warning M Pt L Pad MPL-20 - MPL-20 - MPL-20 1,616.85 5,843.54 1,467.14 10,478.09 10.8005,843.54 Clearance Factor Pass - MPL-32 - MPL-32 - MPL-32 906.09 5,843.54 776.99 10,956.08 7.0195,843.54 Clearance Factor Pass - M Pt M Pad M Pt Moose Pad MPU M-10 - MPU M-10 - MPU M-10 28.83 362.34 25.99 363.16 10.144362.34 Centre Distance Pass - MPU M-10 - MPU M-10 - MPU M-10 29.05 433.40 25.79 434.69 8.894433.40 Ellipse Separation Pass - MPU M-10 - MPU M-10 - MPU M-10 31.73 733.40 26.63 738.95 6.221733.40 Clearance Factor Pass - MPU M-10 - MPU M-10PB1 - MPU M-10PB1 28.83 362.34 25.99 363.16 10.144362.34 Centre Distance Pass - MPU M-10 - MPU M-10PB1 - MPU M-10PB1 29.05 433.40 25.79 434.69 8.894433.40 Ellipse Separation Pass - MPU M-10 - MPU M-10PB1 - MPU M-10PB1 31.73 733.40 26.63 738.95 6.221733.40 Clearance Factor Pass - MPU M-10 - MPU M-10PB2 - MPU M-10PB2 28.83 362.34 25.99 363.16 10.144362.34 Centre Distance Pass - MPU M-10 - MPU M-10PB2 - MPU M-10PB2 29.05 433.40 25.79 434.69 8.894433.40 Ellipse Separation Pass - MPU M-10 - MPU M-10PB2 - MPU M-10PB2 31.73 733.40 26.63 738.95 6.221733.40 Clearance Factor Pass - MPU M-10 - MPU M-10PB3 - MPU M-10PB3 28.83 362.34 25.99 363.16 10.144362.34 Centre Distance Pass - MPU M-10 - MPU M-10PB3 - MPU M-10PB3 29.05 433.40 25.79 434.69 8.894433.40 Ellipse Separation Pass - MPU M-10 - MPU M-10PB3 - MPU M-10PB3 31.73 733.40 26.63 738.95 6.221733.40 Clearance Factor Pass - MPU M-11 - MPU M-11 - MPU M-11 112.31 5,283.40 71.68 4,814.04 2.7655,283.40 Ellipse Separation Pass - MPU M-11 - MPU M-11 - MPU M-11 106.73 5,332.44 73.41 4,850.72 3.2035,332.44 Centre Distance Pass - MPU M-11 - MPU M-11 - MPU M-11 141.74 5,458.40 81.81 4,942.49 2.3655,458.40 Clearance Factor Pass - MPU M-12 - MPU M-12 - MPU M-12 209.98 33.40 208.57 34.25 148.74833.40 Centre Distance Pass - MPU M-12 - MPU M-12 - MPU M-12 210.35 158.40 208.35 157.29 105.128158.40 Ellipse Separation Pass - MPU M-12 - MPU M-12 - MPU M-12 555.85 5,843.54 478.64 5,530.41 7.1995,843.54 Clearance Factor Pass - MPU M-12 - MPU M-12PB1 - MPU M-12PB1 209.98 33.40 208.57 34.25 148.74833.40 Centre Distance Pass - MPU M-12 - MPU M-12PB1 - MPU M-12PB1 210.35 158.40 208.35 157.29 105.128158.40 Ellipse Separation Pass - MPU M-12 - MPU M-12PB1 - MPU M-12PB1 704.90 5,683.40 619.26 5,107.00 8.2315,683.40 Clearance Factor Pass - MPU M-12 - MPU M-12PB2 - MPU M-12PB2 209.98 33.40 208.57 34.25 148.74833.40 Centre Distance Pass - 04 March, 2020 -17:49 COMPASSPage 2 of 8 Milne Point Hilcorp Alaska, LLC Anticollision Report for Plan: MPU M-44i - Slot 58 - MPU M-44 wp02 Comparison Well Name - Wellbore Name - Design @Measured Depth (usft) Minimum Distance (usft) Ellipse Separation (usft) @Measured Depth usft Clearance Factor Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usft Site Name Scan Range: 33.40 to 5,843.54 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt Moose Pad - Plan: MPU M-44i - Slot 58 - MPU M-44i - MPU M-44 wp02 Measured Depth (usft) Summary Based on Minimum Separation Warning MPU M-12 - MPU M-12PB2 - MPU M-12PB2 210.35 158.40 208.35 157.29 105.128158.40 Ellipse Separation Pass - MPU M-12 - MPU M-12PB2 - MPU M-12PB2 555.85 5,843.54 478.51 5,530.41 7.1875,843.54 Clearance Factor Pass - MPU M-13 - MPU M-13i - MPU M-13 193.43 299.92 191.01 301.87 79.787299.92 Centre Distance Pass - MPU M-13 - MPU M-13i - MPU M-13 193.45 308.40 190.98 310.35 78.213308.40 Ellipse Separation Pass - MPU M-13 - MPU M-13i - MPU M-13 1,285.19 5,843.54 1,197.21 4,861.58 14.6085,843.54 Clearance Factor Pass - MPU M-14 - MPU M-14 - MPU M-14 268.39 314.83 265.74 318.92 101.354314.83 Centre Distance Pass - MPU M-14 - MPU M-14 - MPU M-14 268.45 333.40 265.69 337.92 97.334333.40 Ellipse Separation Pass - MPU M-14 - MPU M-14 - MPU M-14 345.46 833.40 339.48 812.64 57.806833.40 Clearance Factor Pass - MPU M-15i - MPU M-15 - MPU M-15i 352.55 33.40 350.64 33.94 184.44033.40 Ellipse Separation Pass - MPU M-15i - MPU M-15 - MPU M-15i 451.16 883.40 445.00 863.35 73.225883.40 Clearance Factor Pass - MPU M-15i - MPU M-15PB1 - MPU M-15PB1 352.55 33.40 350.64 33.94 184.44033.40 Ellipse Separation Pass - MPU M-15i - MPU M-15PB1 - MPU M-15PB1 451.16 883.40 445.00 863.35 73.224883.40 Clearance Factor Pass - MPU M-16 - MPU M-16 - MPU M-16 437.82 33.40 436.41 34.18 310.14633.40 Centre Distance Pass - MPU M-16 - MPU M-16 - MPU M-16 437.86 58.40 436.41 57.06 300.47958.40 Ellipse Separation Pass - MPU M-16 - MPU M-16 - MPU M-16 557.92 958.40 551.54 926.78 87.518958.40 Clearance Factor Pass - MPU M-17i - MPU M-17i - MPU M-17i 524.90 33.40 523.49 34.00 371.83433.40 Centre Distance Pass - MPU M-17i - MPU M-17i - MPU M-17i 525.31 283.40 522.92 281.81 219.618283.40 Ellipse Separation Pass - MPU M-17i - MPU M-17i - MPU M-17i 687.04 1,058.40 680.01 996.01 97.6871,058.40 Clearance Factor Pass - MPU M-18 - MPU M-18 - MPU M-18 554.11 33.40 552.70 34.42 392.52533.40 Centre Distance Pass - MPU M-18 - MPU M-18 - MPU M-18 554.13 58.40 552.67 57.72 380.12558.40 Ellipse Separation Pass - MPU M-18 - MPU M-18 - MPU M-18 717.86 1,058.40 710.92 986.45 103.4411,058.40 Clearance Factor Pass - MPU M-18 - MPU M-18PB1 - MPU M-18PB1 554.11 33.40 552.70 34.42 392.52533.40 Centre Distance Pass - MPU M-18 - MPU M-18PB1 - MPU M-18PB1 554.13 58.40 552.67 57.72 380.12558.40 Ellipse Separation Pass - MPU M-18 - MPU M-18PB1 - MPU M-18PB1 717.86 1,058.40 710.92 986.45 103.4411,058.40 Clearance Factor Pass - MPU M-18 - MPU M-18PB2 - MPU M-18PB2 554.11 33.40 552.70 34.42 392.52533.40 Centre Distance Pass - MPU M-18 - MPU M-18PB2 - MPU M-18PB2 554.13 58.40 552.67 57.72 380.12558.40 Ellipse Separation Pass - MPU M-18 - MPU M-18PB2 - MPU M-18PB2 717.86 1,058.40 710.92 986.45 103.4411,058.40 Clearance Factor Pass - MPU M-19i - MPU M-19i - MPU M-19i 642.07 259.67 639.69 260.39 269.769259.67 Centre Distance Pass - MPU M-19i - MPU M-19i - MPU M-19i 642.08 283.40 639.59 283.68 257.879283.40 Ellipse Separation Pass - MPU M-19i - MPU M-19i - MPU M-19i 823.86 1,058.40 816.74 943.67 115.7971,058.40 Clearance Factor Pass - 04 March, 2020 -17:49 COMPASSPage 3 of 8 Milne Point Hilcorp Alaska, LLC Anticollision Report for Plan: MPU M-44i - Slot 58 - MPU M-44 wp02 Comparison Well Name - Wellbore Name - Design @Measured Depth (usft) Minimum Distance (usft) Ellipse Separation (usft) @Measured Depth usft Clearance Factor Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usft Site Name Scan Range: 33.40 to 5,843.54 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt Moose Pad - Plan: MPU M-44i - Slot 58 - MPU M-44i - MPU M-44 wp02 Measured Depth (usft) Summary Based on Minimum Separation Warning MPU M-19i - MPU M-19PB1 - MPU M-19PB1 642.07 259.67 639.69 260.39 269.769259.67 Centre Distance Pass - MPU M-19i - MPU M-19PB1 - MPU M-19PB1 642.08 283.40 639.59 283.68 257.879283.40 Ellipse Separation Pass - MPU M-19i - MPU M-19PB1 - MPU M-19PB1 823.86 1,058.40 816.74 943.67 115.7931,058.40 Clearance Factor Pass - MPU M-34 - MPU M-34 - MPU M-34 378.92 301.93 376.31 305.19 145.171301.93 Centre Distance Pass - MPU M-34 - MPU M-34 - MPU M-34 378.92 308.40 376.28 311.63 143.407308.40 Ellipse Separation Pass - MPU M-34 - MPU M-34 - MPU M-34 487.20 858.40 481.26 784.94 81.977858.40 Clearance Factor Pass - MPU M-35i - MPU M-35i - MPU M-35i 297.16 33.40 295.25 34.40 155.46533.40 Ellipse Separation Pass - MPU M-35i - MPU M-35i - MPU M-35i 401.37 833.40 395.52 793.67 68.615833.40 Clearance Factor Pass - MPU M-35i - MPU M-35PB1 - MPU M-35PB1 297.16 33.40 295.25 34.40 155.46533.40 Ellipse Separation Pass - MPU M-35i - MPU M-35PB1 - MPU M-35PB1 401.37 833.40 395.52 793.67 68.614833.40 Clearance Factor Pass - Plan: MPU M-27 - M-27 - M-27 wp02 152.90 258.40 150.30 238.60 58.747258.40 Centre Distance Pass - Plan: MPU M-27 - M-27 - M-27 wp02 152.91 283.40 150.17 263.60 55.984283.40 Ellipse Separation Pass - Plan: MPU M-27 - M-27 - M-27 wp02 559.87 4,883.40 511.05 4,924.07 11.4674,883.40 Clearance Factor Pass - Plan: MPU M-28i - M-28i - M-28i wp01 137.43 258.40 134.83 238.60 52.760258.40 Centre Distance Pass - Plan: MPU M-28i - M-28i - M-28i wp01 137.43 283.40 134.70 263.60 50.276283.40 Ellipse Separation Pass - Plan: MPU M-28i - M-28i - M-28i wp01 206.39 5,633.40 147.67 4,892.77 3.5155,633.40 Clearance Factor Pass - Plan: MPU M-29 - M-29 - M-29 wp02 127.26 258.40 124.66 238.60 48.823258.40 Centre Distance Pass - Plan: MPU M-29 - M-29 - M-29 wp02 127.27 283.40 124.53 263.60 46.521283.40 Ellipse Separation Pass - Plan: MPU M-29 - M-29 - M-29 wp02 1,197.20 5,308.40 1,125.13 6,697.71 16.6125,308.40 Clearance Factor Pass - Plan: MPU M-30i - M-30i - M-30i wp02 123.71 258.40 121.10 238.60 47.447258.40 Centre Distance Pass - Plan: MPU M-30i - M-30i - M-30i wp02 123.71 283.40 120.98 263.60 45.208283.40 Ellipse Separation Pass - Plan: MPU M-30i - M-30i - M-30i wp02 1,475.34 5,033.40 1,405.85 4,169.49 21.2315,033.40 Clearance Factor Pass - Plan: MPU M-43 - MPU M-43 - MPU M-43 wp04 64.26 1,091.78 58.06 1,127.22 10.3661,091.78 Centre Distance Pass - Plan: MPU M-43 - MPU M-43 - MPU M-43 wp04 64.33 1,108.40 58.01 1,144.29 10.1821,108.40 Ellipse Separation Pass - Plan: MPU M-43 - MPU M-43 - MPU M-43 wp04 99.15 1,433.40 87.10 1,473.07 8.2291,433.40 Clearance Factor Pass - Plan: MPU M-45 - MPU M-45 - MPU M-45 wp01 150.05 258.40 147.60 258.30 61.099258.40 Centre Distance Pass - Plan: MPU M-45 - MPU M-45 - MPU M-45 wp01 150.11 308.40 147.44 308.88 56.306308.40 Ellipse Separation Pass - Plan: MPU M-45 - MPU M-45 - MPU M-45 wp01 342.70 2,583.40 312.75 2,678.88 11.4412,583.40 Clearance Factor Pass - Proposal: MPU M-08DSW - McLaws - M-08DSW - Mc 760.06 258.40 757.61 254.30 310.398258.40 Centre Distance Pass - Proposal: MPU M-08DSW - McLaws - M-08DSW - Mc 760.32 558.40 756.27 628.59 187.305558.40 Ellipse Separation Pass - Proposal: MPU M-08DSW - McLaws - M-08DSW - Mc 1,049.66 1,458.40 1,037.95 1,414.93 89.7011,458.40 Clearance Factor Pass - 04 March, 2020 -17:49 COMPASSPage 4 of 8 Milne Point Hilcorp Alaska, LLC Anticollision Report for Plan: MPU M-44i - Slot 58 - MPU M-44 wp02 Comparison Well Name - Wellbore Name - Design @Measured Depth (usft) Minimum Distance (usft) Ellipse Separation (usft) @Measured Depth usft Clearance Factor Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usft Site Name Scan Range: 33.40 to 5,843.54 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt Moose Pad - Plan: MPU M-44i - Slot 58 - MPU M-44i - MPU M-44 wp02 Measured Depth (usft) Summary Based on Minimum Separation Warning Proposal: MPU M-09DSW - AP Hill - M-09DSW - AP H 595.14 5,808.40 520.21 5,622.92 7.9435,808.40 Clearance Factor Pass - Proposal: MPU M-09DSW - AP Hill - M-09DSW - AP H 571.14 5,843.54 499.45 5,635.74 7.9675,843.54 Ellipse Separation Pass - Slot 42 - Placeholder - Slot 42 - Placeholder - Slot 42 - 239.91 258.40 237.28 220.60 91.166258.40 Centre Distance Pass - Slot 42 - Placeholder - Slot 42 - Placeholder - Slot 42 - 240.01 308.40 237.12 270.60 82.985308.40 Ellipse Separation Pass - Slot 42 - Placeholder - Slot 42 - Placeholder - Slot 42 - 293.46 808.40 287.50 762.89 49.250808.40 Clearance Factor Pass - Slot 45 - Placeholder - Slot 45 - Placeholder - Slot 45- 218.31 258.40 215.67 220.60 82.824258.40 Centre Distance Pass - Slot 45 - Placeholder - Slot 45 - Placeholder - Slot 45- 218.31 283.40 215.54 245.60 78.964283.40 Ellipse Separation Pass - Slot 45 - Placeholder - Slot 45 - Placeholder - Slot 45- 284.51 783.40 278.72 739.03 49.115783.40 Clearance Factor Pass - Slot 46 - Placeholder - Slot 46 - Placeholder - Slot 46 - 179.87 258.40 177.24 220.60 68.351258.40 Centre Distance Pass - Slot 46 - Placeholder - Slot 46 - Placeholder - Slot 46 - 179.97 308.40 177.08 270.60 62.226308.40 Ellipse Separation Pass - Slot 46 - Placeholder - Slot 46 - Placeholder - Slot 46 - 228.32 783.40 222.51 739.03 39.316783.40 Clearance Factor Pass - Slot 49 - Placeholder - Slot 49 - Placeholder - Slot 49 - 172.25 258.40 169.62 220.60 65.303258.40 Centre Distance Pass - Slot 49 - Placeholder - Slot 49 - Placeholder - Slot 49 - 172.26 283.40 169.49 245.60 62.253283.40 Ellipse Separation Pass - Slot 49 - Placeholder - Slot 49 - Placeholder - Slot 49 - 233.64 758.40 228.00 715.05 41.467758.40 Clearance Factor Pass - Slot 54 - Placeholder - Slot 54 - Placeholder - Slot 54 - 59.86 258.40 57.23 220.60 22.746258.40 Centre Distance Pass - Slot 54 - Placeholder - Slot 54 - Placeholder - Slot 54 - 59.96 308.40 57.07 270.60 20.732308.40 Ellipse Separation Pass - Slot 54 - Placeholder - Slot 54 - Placeholder - Slot 54 - 72.02 558.40 67.65 519.61 16.498558.40 Clearance Factor Pass - Survey tool program From (usft) To (usft) Survey/Plan Survey Tool 33.40 800.00 MPU M-44 wp02 3_Gyro-GC_Csg 800.00 5,843.54 MPU M-44 wp02 3_MWD+IFR2+MS+Sag 5,843.54 15,351.84 MPU M-44 wp02 3_MWD+IFR2+MS+Sag 04 March, 2020 -17:49 COMPASSPage 5 of 8 Milne Point Hilcorp Alaska, LLC Anticollision Report for Plan: MPU M-44i - Slot 58 - MPU M-44 wp02 Ellipse 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. 04 March, 2020 -17:49 COMPASSPage 6 of 8 0.00 1.00 2.00 3.00 4.00 Separation Factor0 325 650 975 1300 1625 1950 2275 2600 2925 3250 3575 3900 4225 4550 4875 5200 5525 5850 6175 Measured Depth (650 usft/in) MPU M-11 MPU M-12 M-28i wp01 No-Go Zone - Stop Drilling Collision Avoidance Req. Collision Risk Procedures Req. WELL DETAILS:Plan: MPU M-44i - Slot 58 NAD 1927 (NADCON CONUS)Alaska Zone 04 25.10 +N/-S +E/-W Northing Easting Latittude Longitude 0.00 0.00 6027889.70 534143.85 70° 29' 13.989 N 149° 43' 15.335 W REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Plan: MPU M-44i - Slot 58, True North Vertical (TVD) Reference:MPU M-44 Planned RKB @ 58.80usft Measured Depth Reference:MPU M-44 Planned RKB @ 58.80usft Calculation Method:Minimum Curvature SURVEY PROGRAM Date: 2019-12-11T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 33.40 800.00 MPU M-44 wp02 (MPU M-44i) 3_Gyro-GC_Csg 800.00 5843.54 MPU M-44 wp02 (MPU M-44i) 3_MWD+IFR2+MS+Sag 5843.54 15351.84 MPU M-44 wp02 (MPU M-44i) 3_MWD+IFR2+MS+Sag 0.00 30.00 60.00 90.00 120.00 150.00 180.00 Centre to Centre Separation (60.00 usft/in)0 325 650 975 1300 1625 1950 2275 2600 2925 3250 3575 3900 4225 4550 4875 5200 5525 5850 6175 Measured Depth (650 usft/in) MPU M-10 MPU M-43 wp04 MPU M-45 wp01 Slot 54 - Placeholder NO GLOBAL FILTER: Using user defined selection & filtering criteria 33.40 To 15351.84 Project: Milne Point Site: M Pt Moose Pad Well: Plan: MPU M-44i - Slot 58 Wellbore: MPU M-44i Plan: MPU M-44 wp02 Ladder / S.F. Plots 1 of 2 CASING DETAILS TVD TVDSS MD Size Name 3783.80 3725.00 5843.54 9-5/8 9 5/8" x 12 1/4" 3558.80 3500.00 15351.84 4-1/2 4 1/2" x 8 1/2" 04 March, 2020 Milne Point M Pt Moose Pad Plan: MPU M-44i - Slot 58 MPU M-44i MPU M-44 wp02 Reference Design: M Pt Moose Pad - Plan: MPU M-44i - Slot 58 - MPU M-44i - MPU M-44 wp02 Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference) Well Coordinates: 6,027,889.70 N, 534,143.85 E (70° 29' 13.99" N, 149° 43' 15.34" W) Datum Height: MPU M-44 Planned RKB @ 58.80usft Scan Range: 5,843.54 to 15,351.84 usft. Measured Depth. Geodetic Scale Factor Applied Version: 5000.15 Build: 91E Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usft NO GLOBAL FILTER: Using user defined selection & filtering criteriaScan Type: Scan Type:25.00 Milne Point Hilcorp Alaska, LLC Anticollision Report for Plan: MPU M-44i - Slot 58 - MPU M-44 wp02 Comparison Well Name - Wellbore Name - Design @Measured Depth (usft) Minimum Distance (usft) Ellipse Separation (usft) @Measured Depth usft Clearance Factor Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usft Site Name Scan Range: 5,843.54 to 15,351.84 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference) Reference Design: M Pt Moose Pad - Plan: MPU M-44i - Slot 58 - MPU M-44i - MPU M-44 wp02 Measured Depth (usft) Summary Based on Minimum Separation Warning M Pt L Pad MPL-20 - MPL-20 - MPL-20 680.15 7,243.54 560.45 11,349.33 5.6827,243.54 Clearance Factor Pass - MPL-20 - MPL-20 - MPL-20 562.69 7,618.54 483.67 11,588.73 7.1217,618.54 Ellipse Separation Pass - MPL-20 - MPL-20 - MPL-20 556.79 7,715.14 486.92 11,640.04 7.9687,715.14 Centre Distance Pass - MPL-32 - MPL-32 - MPL-32 906.09 5,843.54 776.99 10,956.08 7.0195,843.54 Clearance Factor Pass - MPL-32 - MPL-32 - MPL-32 718.50 6,343.54 648.20 11,184.45 10.2216,343.54 Ellipse Separation Pass - MPL-32 - MPL-32 - MPL-32 712.43 6,450.24 652.80 11,237.42 11.9486,450.24 Centre Distance Pass - MPL-36 - MPL-36 - MPL-36 827.61 8,418.54 696.29 12,301.01 6.3038,418.54 Clearance Factor Pass - MPL-36 - MPL-36 - MPL-36 696.75 8,893.54 612.28 12,618.12 8.2488,893.54 Ellipse Separation Pass - MPL-36 - MPL-36 - MPL-36 690.48 9,012.86 617.21 12,692.29 9.4249,012.86 Centre Distance Pass - MPL-36 - MPL-36L1 - MPL-36L1 827.61 8,418.54 692.89 12,301.01 6.1438,418.54 Clearance Factor Pass - MPL-36 - MPL-36L1 - MPL-36L1 699.61 8,868.54 610.95 12,601.12 7.8918,868.54 Ellipse Separation Pass - MPL-36 - MPL-36L1 - MPL-36L1 690.48 9,012.86 616.73 12,692.29 9.3629,012.86 Centre Distance Pass - MPL-36 - MPL-36L1 PB1 - MPL-36L1 PB1 827.61 8,418.54 690.33 12,301.01 6.0298,418.54 Clearance Factor Pass - MPL-36 - MPL-36L1 PB1 - MPL-36L1 PB1 699.61 8,868.54 609.85 12,601.12 7.7948,868.54 Ellipse Separation Pass - MPL-36 - MPL-36L1 PB1 - MPL-36L1 PB1 690.48 9,012.86 616.35 12,692.29 9.3149,012.86 Centre Distance Pass - MPL-36 - MPL-36PB1 - MPL-36PB1 827.61 8,418.54 696.31 12,301.01 6.3038,418.54 Clearance Factor Pass - MPL-36 - MPL-36PB1 - MPL-36PB1 696.75 8,893.54 612.29 12,618.12 8.2498,893.54 Ellipse Separation Pass - MPL-36 - MPL-36PB1 - MPL-36PB1 690.48 9,012.86 617.22 12,692.29 9.4249,012.86 Centre Distance Pass - M Pt M Pad M-01 - M-01 - M-01 1,253.35 10,793.54 1,092.22 4,929.08 7.77810,793.54 Clearance Factor Pass - M-01 - M-01 - M-01 1,253.33 10,803.45 1,092.21 4,935.45 7.77910,803.45 Ellipse Separation Pass - M Pt Moose Pad MPU M-10 - MPU M-10 - MPU M-10 812.26 5,843.54 732.51 4,684.69 10.1855,843.54 Clearance Factor Pass - MPU M-10 - MPU M-10PB1 - MPU M-10PB1 812.26 5,843.54 732.50 4,684.69 10.1845,843.54 Clearance Factor Pass - MPU M-10 - MPU M-10PB2 - MPU M-10PB2 812.26 5,843.54 732.51 4,684.69 10.1845,843.54 Clearance Factor Pass - MPU M-10 - MPU M-10PB3 - MPU M-10PB3 812.26 5,843.54 732.51 4,684.69 10.1845,843.54 Clearance Factor Pass - 04 March, 2020 -17:50 COMPASSPage 2 of 7 Milne Point Hilcorp Alaska, LLC Anticollision Report for Plan: MPU M-44i - Slot 58 - MPU M-44 wp02 Comparison Well Name - Wellbore Name - Design @Measured Depth (usft) Minimum Distance (usft) Ellipse Separation (usft) @Measured Depth usft Clearance Factor Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usft Site Name Scan Range: 5,843.54 to 15,351.84 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference) Reference Design: M Pt Moose Pad - Plan: MPU M-44i - Slot 58 - MPU M-44i - MPU M-44 wp02 Measured Depth (usft) Summary Based on Minimum Separation Warning MPU M-11 - MPU M-11 - MPU M-11 390.06 5,843.54 304.57 5,258.23 4.5635,843.54 Clearance Factor Pass - MPU M-12 - MPU M-12 - MPU M-12 224.50 6,318.54 160.74 5,825.78 3.5216,318.54 Clearance Factor Pass - MPU M-12 - MPU M-12 - MPU M-12 182.60 6,418.54 137.80 5,880.03 4.0766,418.54 Ellipse Separation Pass - MPU M-12 - MPU M-12 - MPU M-12 172.23 6,491.09 142.55 5,918.81 5.8026,491.09 Centre Distance Pass - MPU M-12 - MPU M-12PB1 - MPU M-12PB1 671.86 5,843.54 594.12 5,107.00 8.6435,843.54 Clearance Factor Pass - MPU M-12 - MPU M-12PB1 - MPU M-12PB1 669.85 5,868.54 593.84 5,107.00 8.8125,868.54 Ellipse Separation Pass - MPU M-12 - MPU M-12PB1 - MPU M-12PB1 667.40 5,939.97 596.32 5,107.00 9.3905,939.97 Centre Distance Pass - MPU M-12 - MPU M-12PB2 - MPU M-12PB2 224.50 6,318.54 160.61 5,825.78 3.5146,318.54 Clearance Factor Pass - MPU M-12 - MPU M-12PB2 - MPU M-12PB2 182.60 6,418.54 137.67 5,880.03 4.0656,418.54 Ellipse Separation Pass - MPU M-12 - MPU M-12PB2 - MPU M-12PB2 172.23 6,491.09 142.42 5,918.81 5.7776,491.09 Centre Distance Pass - MPU M-13 - MPU M-13i - MPU M-13 199.84 7,293.54 127.67 5,745.07 2.7697,293.54 Clearance Factor Pass - MPU M-13 - MPU M-13i - MPU M-13 169.22 7,368.54 116.41 5,790.24 3.2047,368.54 Ellipse Separation Pass - MPU M-13 - MPU M-13i - MPU M-13 156.76 7,447.39 126.60 5,837.29 5.1977,447.39 Centre Distance Pass - MPU M-14 - MPU M-14 - MPU M-14 202.49 8,368.54 146.87 6,413.83 3.6418,368.54 Ellipse Separation Pass - MPU M-14 - MPU M-14 - MPU M-14 186.56 8,464.03 153.91 6,466.96 5.7148,464.03 Centre Distance Pass - MPU M-14 - MPU M-14 - MPU M-14 265.18 8,693.54 180.05 6,597.45 3.1158,693.54 Clearance Factor Pass - MPU M-15i - MPU M-15 - MPU M-15i 234.76 9,318.54 143.87 6,881.40 2.5839,318.54 Clearance Factor Pass - MPU M-15i - MPU M-15 - MPU M-15i 201.90 9,393.54 133.33 6,917.85 2.9449,393.54 Ellipse Separation Pass - MPU M-15i - MPU M-15 - MPU M-15i 189.92 9,470.14 147.40 6,955.42 4.4669,470.14 Centre Distance Pass - MPU M-15i - MPU M-15PB1 - MPU M-15PB1 214.07 9,318.54 121.82 6,886.60 2.3209,318.54 Clearance Factor Pass - MPU M-15i - MPU M-15PB1 - MPU M-15PB1 189.70 9,368.54 113.16 6,910.95 2.4789,368.54 Ellipse Separation Pass - MPU M-15i - MPU M-15PB1 - MPU M-15PB1 170.50 9,459.17 128.56 6,954.30 4.0659,459.17 Centre Distance Pass - MPU M-16 - MPU M-16 - MPU M-16 253.90 10,218.54 145.28 7,435.53 2.33810,218.54 Clearance Factor Pass - MPU M-16 - MPU M-16 - MPU M-16 218.24 10,293.54 131.04 7,472.71 2.50310,293.54 Ellipse Separation Pass - MPU M-16 - MPU M-16 - MPU M-16 194.36 10,412.33 145.77 7,535.51 4.00010,412.33 Centre Distance Pass - MPU M-17i - MPU M-17i - MPU M-17i 175.60 11,431.02 120.96 8,334.44 3.21411,431.02 Centre Distance Pass - MPU M-17i - MPU M-17i - MPU M-17i 199.12 11,543.54 105.59 8,396.79 2.12911,543.54 Ellipse Separation Pass - MPU M-17i - MPU M-17i - MPU M-17i 235.33 11,618.54 115.73 8,436.85 1.96811,618.54 Clearance Factor Pass - MPU M-18 - MPU M-18 - MPU M-18 222.15 12,218.54 92.72 9,091.51 1.71612,218.54 Clearance Factor Pass - MPU M-18 - MPU M-18 - MPU M-18 197.52 12,268.54 85.07 9,115.34 1.75612,268.54 Ellipse Separation Pass - MPU M-18 - MPU M-18 - MPU M-18 172.79 12,377.70 106.01 9,167.39 2.58712,377.70 Centre Distance Pass - 04 March, 2020 -17:50 COMPASSPage 3 of 7 Milne Point Hilcorp Alaska, LLC Anticollision Report for Plan: MPU M-44i - Slot 58 - MPU M-44 wp02 Comparison Well Name - Wellbore Name - Design @Measured Depth (usft) Minimum Distance (usft) Ellipse Separation (usft) @Measured Depth usft Clearance Factor Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usft Site Name Scan Range: 5,843.54 to 15,351.84 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference) Reference Design: M Pt Moose Pad - Plan: MPU M-44i - Slot 58 - MPU M-44i - MPU M-44 wp02 Measured Depth (usft) Summary Based on Minimum Separation Warning MPU M-18 - MPU M-18PB1 - MPU M-18PB1 222.15 12,218.54 92.58 9,091.51 1.71412,218.54 Clearance Factor Pass - MPU M-18 - MPU M-18PB1 - MPU M-18PB1 197.52 12,268.54 84.92 9,115.34 1.75412,268.54 Ellipse Separation Pass - MPU M-18 - MPU M-18PB1 - MPU M-18PB1 172.79 12,377.70 105.88 9,167.39 2.58212,377.70 Centre Distance Pass - MPU M-18 - MPU M-18PB2 - MPU M-18PB2 222.15 12,218.54 92.59 9,091.51 1.71512,218.54 Clearance Factor Pass - MPU M-18 - MPU M-18PB2 - MPU M-18PB2 197.52 12,268.54 84.94 9,115.34 1.75512,268.54 Ellipse Separation Pass - MPU M-18 - MPU M-18PB2 - MPU M-18PB2 172.79 12,377.70 105.88 9,167.39 2.58212,377.70 Centre Distance Pass - MPU M-19i - MPU M-19i - MPU M-19i 144.79 13,403.59 68.18 10,022.64 1.89013,403.59 Centre Distance Pass - MPU M-19i - MPU M-19i - MPU M-19i 165.06 13,493.54 39.65 10,063.89 1.31613,493.54 Ellipse Separation Pass - MPU M-19i - MPU M-19i - MPU M-19i 176.71 13,518.54 39.84 10,075.29 1.29113,518.54 Clearance Factor Pass - MPU M-19i - MPU M-19PB1 - MPU M-19PB1 144.79 13,403.59 67.96 10,022.64 1.88513,403.59 Centre Distance Pass - MPU M-19i - MPU M-19PB1 - MPU M-19PB1 165.06 13,493.54 39.40 10,063.89 1.31413,493.54 Ellipse Separation Pass - MPU M-19i - MPU M-19PB1 - MPU M-19PB1 176.71 13,518.54 39.59 10,075.29 1.28913,518.54 Clearance Factor Pass - MPU M-34 - MPU M-34 - MPU M-34 409.31 10,868.54 275.34 7,614.82 3.05510,868.54 Clearance Factor Pass - MPU M-34 - MPU M-34 - MPU M-34 326.38 11,143.54 241.41 7,846.38 3.84111,143.54 Ellipse Separation Pass - MPU M-34 - MPU M-34 - MPU M-34 308.31 11,316.10 253.22 7,979.10 5.59611,316.10 Centre Distance Pass - MPU M-35i - MPU M-35i - MPU M-35i 405.96 9,743.54 287.21 6,828.19 3.4199,743.54 Clearance Factor Pass - MPU M-35i - MPU M-35i - MPU M-35i 315.12 10,018.54 243.76 7,037.39 4.41610,018.54 Ellipse Separation Pass - MPU M-35i - MPU M-35i - MPU M-35i 298.33 10,169.41 252.51 7,149.56 6.51010,169.41 Centre Distance Pass - MPU M-35i - MPU M-35PB1 - MPU M-35PB1 330.83 9,893.54 213.84 6,954.00 2.8289,893.54 Clearance Factor Pass - MPU M-35i - MPU M-35PB1 - MPU M-35PB1 307.86 9,968.54 202.36 6,954.00 2.9189,968.54 Ellipse Separation Pass - MPU M-35i - MPU M-35PB1 - MPU M-35PB1 301.45 10,031.04 208.21 6,954.00 3.23310,031.04 Centre Distance Pass - Plan: MPU M-27 - M-27 - M-27 wp02 763.57 5,843.54 726.30 4,400.00 20.4855,843.54 Ellipse Separation Pass - Plan: MPU M-27 - M-27 - M-27 wp02 788.92 5,893.54 750.40 4,400.00 20.4785,893.54 Clearance Factor Pass - Plan: MPU M-28i - M-28i - M-28i wp01 310.11 5,843.54 239.71 4,769.06 4.4055,843.54 Clearance Factor Pass - Plan: MPU M-29 - M-29 - M-29 wp02 830.18 6,265.69 784.45 4,806.63 18.1516,265.69 Centre Distance Pass - Plan: MPU M-29 - M-29 - M-29 wp02 831.75 6,318.54 783.02 4,791.66 17.0666,318.54 Ellipse Separation Pass - Plan: MPU M-29 - M-29 - M-29 wp02 1,047.82 6,918.54 958.53 4,700.00 11.7356,918.54 Clearance Factor Pass - Plan: MPU M-30i - M-30i - M-30i wp02 1,109.41 6,124.10 1,068.89 4,554.42 27.3836,124.10 Centre Distance Pass - Plan: MPU M-30i - M-30i - M-30i wp02 1,110.28 6,168.54 1,067.85 4,559.18 26.1686,168.54 Ellipse Separation Pass - Plan: MPU M-30i - M-30i - M-30i wp02 1,437.58 7,043.54 1,344.30 4,651.36 15.4127,043.54 Clearance Factor Pass - 04 March, 2020 -17:50 COMPASSPage 4 of 7 Milne Point Hilcorp Alaska, LLC Anticollision Report for Plan: MPU M-44i - Slot 58 - MPU M-44 wp02 Comparison Well Name - Wellbore Name - Design @Measured Depth (usft) Minimum Distance (usft) Ellipse Separation (usft) @Measured Depth usft Clearance Factor Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usft Site Name Scan Range: 5,843.54 to 15,351.84 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference) Reference Design: M Pt Moose Pad - Plan: MPU M-44i - Slot 58 - MPU M-44i - MPU M-44 wp02 Measured Depth (usft) Summary Based on Minimum Separation Warning Plan: MPU M-43 - MPU M-43 - MPU M-43 wp04 915.17 13,670.66 683.99 14,245.89 3.95913,670.66 Centre Distance Pass - Plan: MPU M-43 - MPU M-43 - MPU M-43 wp04 927.27 15,318.54 649.95 15,860.31 3.34415,318.54 Ellipse Separation Pass - Plan: MPU M-43 - MPU M-43 - MPU M-43 wp04 929.31 15,351.84 650.74 15,860.31 3.33615,351.84 Clearance Factor Pass - Plan: MPU M-45 - MPU M-45 - MPU M-45 wp01 720.57 7,372.79 647.91 6,735.89 9.9177,372.79 Ellipse Separation Pass - Plan: MPU M-45 - MPU M-45 - MPU M-45 wp01 937.03 15,351.84 659.50 14,615.21 3.37615,351.84 Clearance Factor Pass - Proposal: MPU M-08DSW - McLaws - M-08DSW - Mc 938.09 8,393.54 813.07 5,800.00 7.5048,393.54 Clearance Factor Pass - Proposal: MPU M-08DSW - McLaws - M-08DSW - Mc 912.25 8,568.54 794.44 5,835.58 7.7438,568.54 Ellipse Separation Pass - Proposal: MPU M-08DSW - McLaws - M-08DSW - Mc 910.72 8,622.09 795.74 5,843.85 7.9218,622.09 Centre Distance Pass - Proposal: MPU M-09DSW - AP Hill - M-09DSW - AP H 432.19 6,206.01 379.73 5,711.10 8.2396,206.01 Centre Distance Pass - Proposal: MPU M-09DSW - AP Hill - M-09DSW - AP H 440.89 6,293.54 372.71 5,720.13 6.4666,293.54 Ellipse Separation Pass - Proposal: MPU M-09DSW - AP Hill - M-09DSW - AP H 532.60 6,518.54 428.87 5,742.52 5.1356,518.54 Clearance Factor Pass - Survey tool program From (usft) To (usft) Survey/Plan Survey Tool 33.40 800.00 MPU M-44 wp02 3_Gyro-GC_Csg 800.00 5,843.54 MPU M-44 wp02 3_MWD+IFR2+MS+Sag 5,843.54 15,351.84 MPU M-44 wp02 3_MWD+IFR2+MS+Sag Ellipse 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. 04 March, 2020 -17:50 COMPASSPage 5 of 7 0.00 1.00 2.00 3.00 4.00 Separation Factor5775 6300 6825 7350 7875 8400 8925 9450 9975 10500 11025 11550 12075 12600 13125 13650 14175 14700 15225 15750 Measured Depth (1050 usft/in) MPU M-17i MPU M-18 MPU M-19i No-Go Zone - Stop Drilling Collision Avoidance Req. Collision Risk Procedures Req. NOERRORS WELL DETAILS:Plan: MPU M-44i - Slot 58 NAD 1927 (NADCON CONUS)Alaska Zone 04 25.10 +N/-S +E/-W Northing Easting Latittude Longitude 0.00 0.00 6027889.70 534143.85 70° 29' 13.989 N 149° 43' 15.335 W REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Plan: MPU M-44i - Slot 58, True North Vertical (TVD) Reference:MPU M-44 Planned RKB @ 58.80usft Measured Depth Reference:MPU M-44 Planned RKB @ 58.80usft Calculation Method:Minimum Curvature SURVEY PROGRAM Date: 2019-12-11T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 33.40 800.00 MPU M-44 wp02 (MPU M-44i) 3_Gyro-GC_Csg 800.00 5843.54 MPU M-44 wp02 (MPU M-44i) 3_MWD+IFR2+MS+Sag 5843.54 15351.84 MPU M-44 wp02 (MPU M-44i) 3_MWD+IFR2+MS+Sag 0.00 30.00 60.00 90.00 120.00 150.00 180.00 Centre to Centre Separation (60.00 usft/in)5775 6300 6825 7350 7875 8400 8925 9450 9975 10500 11025 11550 12075 12600 13125 13650 14175 14700 15225 15750 Measured Depth (1050 usft/in) MPU M-13 NO GLOBAL FILTER: Using user defined selection & filtering criteria 33.40 To 15351.84 Project: Milne Point Site: M Pt Moose Pad Well: Plan: MPU M-44i - Slot 58 Wellbore: MPU M-44i Plan: MPU M-44 wp02 Ladder / S.F. Plots 2 of 2 CASING DETAILS TVD TVDSS MD Size Name 3783.80 3725.00 5843.54 9-5/8 9 5/8" x 12 1/4" 3558.80 3500.00 15351.84 4-1/2 4 1/2" x 8 1/2" 1 Davies, Stephen F (CED) From:Joseph Engel <jengel@hilcorp.com> Sent:Thursday, March 19, 2020 12:02 PM To:Davies, Stephen F (CED) Subject:RE: [EXTERNAL] MPU M-44 (PTD 220-030) - Question My apologies, Steve. As our development has moved from OA sand to different Schrader lobes, I have used the OA programs as a go‐by. The correct bullet should say:  Use ADR to stay in section. Reservoir plan is to undulate between Schrader NB and NC sands in 1000‐ 1500’ MD increments, and keeping DLS <3° when moving between lobes Please let me know if you have any other questions. Thank you for your time. -Joe Joe Engel | Drilling Engineer | Hilcorp Alaska, LLC 3800 Centerpoint Dr., Ste. 1400 | Anchorage | AK | 99503 Office: 907.777.8395 | Cell: 805.235.6265 From: Davies, Stephen F (CED) [mailto:steve.davies@alaska.gov] Sent: Thursday, March 19, 2020 10:25 AM To: Joseph Engel <jengel@hilcorp.com> Subject: [EXTERNAL] MPU M‐44 (PTD 220‐030) ‐ Question Joe, The description in the application states this is a Schrader Bluff NB/NC injector. The 10th bullet point in Section 15.14 on page 29 describes a plan to undulate between the OA1 and OA3 sand lobes. Please provide correct text for this bullet point. Regards, Steve Davies Alaska Oil and Gas Conservation Commission (AOGCC) CONFIDENTIALITY NOTICE: This e‐mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e‐mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907‐793‐1224 or steve.davies@alaska.gov. The information contained in this e-mail message is confidential information intended only for the use of the recipient(s) named above. In addition, this communication may be legally privileged. If the reader of this e-mail is not an intended recipient, you have received this e-mail in error and any review, dissemination, distribution or copying is strictly prohibited. If you have received this e-mail in error, please notify the sender immediately by return e-mail and permanently delete the copy you received. 2 While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 1 Davies, Stephen F (CED) From:Joseph Engel <jengel@hilcorp.com> Sent:Thursday, March 19, 2020 12:39 PM To:Davies, Stephen F (CED) Subject:RE: [EXTERNAL] RE: MPU M-44 (PTD 220-030) - Another Question Steve – All Moose Pad wells prior to M‐43/44 (target NB/NC sand) have been in the OA sand. On our offset well mud density charts, I put the most analogous and closest offset wells for the best information. Therefore we put NB offset well info for NB wells, OA for OA, etc. A development map below shows the proximity of L‐51/52/53 to the M‐43/44/45 well patterns (red box). Please let me know if this is sufficient. No worries on the string of emails, it actually helps me answer each question and not miss anything. Please let me know if you have any questions. Thank you for your time. ‐Joe 2 Joe Engel | Drilling Engineer | Hilcorp Alaska, LLC 3800 Centerpoint Dr., Ste. 1400 | Anchorage | AK | 99503 Office: 907.777.8395 | Cell: 805.235.6265 From: Davies, Stephen F (CED) [mailto:steve.davies@alaska.gov] Sent: Thursday, March 19, 2020 11:00 AM To: Joseph Engel <jengel@hilcorp.com> Subject: [EXTERNAL] RE: MPU M‐44 (PTD 220‐030) ‐ Another Question Joe, Could Hilcorp please update the Offset Well Mud Densities table on page 49 to include mud weights used to drill recent Moose Pad wells? 3 Apologies for the string of emails, I should have combined all of these into a single one. Thanks, Steve Davies Alaska Oil and Gas Conservation Commission (AOGCC) CONFIDENTIALITY NOTICE: This e‐mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e‐mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907‐793‐1224 or steve.davies@alaska.gov. From: Davies, Stephen F (CED) Sent: Thursday, March 19, 2020 10:35 AM To: Joe Engel <jengel@hilcorp.com> Subject: RE: MPU M‐44 (PTD 220‐030) ‐ Another Question Joe, Hilcorp has drilled several wells from Moose Pad at MPU, yet the Permit to Drill applications always include the Data Sheet Formation Description from L‐Pad. Has Hilcorp considered generating a new Data Sheet Formation Description incorporating drilling results from Moose Pad? Or are there no significant variations between the geological sections at Moose Pad and L Pad? Thanks, Steve Davies Alaska Oil and Gas Conservation Commission (AOGCC) CONFIDENTIALITY NOTICE: This e‐mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e‐mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907‐793‐1224 or steve.davies@alaska.gov. From: Davies, Stephen F (CED) Sent: Thursday, March 19, 2020 10:25 AM To: Joe Engel <jengel@hilcorp.com> Subject: MPU M‐44 (PTD 220‐030) ‐ Question Joe, The description in the application states this is a Schrader Bluff NB/NC injector. The 10th bullet point in Section 15.14 on page 29 describes a plan to undulate between the OA1 and OA3 sand lobes. Please provide correct text for this bullet point. Regards, Steve Davies Alaska Oil and Gas Conservation Commission (AOGCC) CONFIDENTIALITY NOTICE: This e‐mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e‐mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907‐793‐1224 or steve.davies@alaska.gov. 4 The information contained in this e-mail message is confidential information intended only for the use of the recipient(s) named above. In addition, this communication may be legally privileged. If the reader of this e-mail is not an intended recipient, you have received this e-mail in error and any review, dissemination, distribution or copying is strictly prohibited. If you have received this e-mail in error, please notify the sender immediately by return e-mail and permanently delete the copy you received. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 1 Davies, Stephen F (CED) From:Joseph Engel <jengel@hilcorp.com> Sent:Thursday, March 19, 2020 1:01 PM To:Davies, Stephen F (CED) Subject:RE: [EXTERNAL] RE: MPU M-44 (PTD 220-030) - Another Question Steve – There are no significant variations in the geology between L‐Pad and Moose pad. Please let me know if you have any other questions. Thank you for your time. ‐Joe Joe Engel | Drilling Engineer | Hilcorp Alaska, LLC 3800 Centerpoint Dr., Ste. 1400 | Anchorage | AK | 99503 Office: 907.777.8395 | Cell: 805.235.6265 From: Davies, Stephen F (CED) [mailto:steve.davies@alaska.gov] Sent: Thursday, March 19, 2020 10:35 AM To: Joseph Engel <jengel@hilcorp.com> Subject: [EXTERNAL] RE: MPU M‐44 (PTD 220‐030) ‐ Another Question Joe, Hilcorp has drilled several wells from Moose Pad at MPU, yet the Permit to Drill applications always include the Data Sheet Formation Description from L‐Pad. Has Hilcorp considered generating a new Data Sheet Formation Description incorporating drilling results from Moose Pad? Or are there no significant variations between the geological sections at Moose Pad and L Pad? Thanks, Steve Davies Alaska Oil and Gas Conservation Commission (AOGCC) CONFIDENTIALITY NOTICE: This e‐mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e‐mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907‐793‐1224 or steve.davies@alaska.gov. From: Davies, Stephen F (CED) Sent: Thursday, March 19, 2020 10:25 AM To: Joe Engel <jengel@hilcorp.com> Subject: MPU M‐44 (PTD 220‐030) ‐ Question Joe, 2 The description in the application states this is a Schrader Bluff NB/NC injector. The 10th bullet point in Section 15.14 on page 29 describes a plan to undulate between the OA1 and OA3 sand lobes. Please provide correct text for this bullet point. Regards, Steve Davies Alaska Oil and Gas Conservation Commission (AOGCC) CONFIDENTIALITY NOTICE: This e‐mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e‐mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907‐793‐1224 or steve.davies@alaska.gov. The information contained in this e-mail message is confidential information intended only for the use of the recipient(s) named above. In addition, this communication may be legally privileged. If the reader of this e-mail is not an intended recipient, you have received this e-mail in error and any review, dissemination, distribution or copying is strictly prohibited. If you have received this e-mail in error, please notify the sender immediately by return e-mail and permanently delete the copy you received. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 1 Davies, Stephen F (CED) From:Joseph Engel <jengel@hilcorp.com> Sent:Thursday, March 19, 2020 4:29 PM To:Davies, Stephen F (CED) Cc:Cody Dinger Subject:RE: [EXTERNAL] RE: MPU M-44 (PTD 220-030) - Another Question No problem, Steve. We are currently running surface casing on M‐43. M‐43 lateral will be open to injection support from M‐44. I will have Cody update the AOR and send it to you. M‐44 will not be preproduced. Let me know if you have any other questions. Thanks. ‐Joe Joe Engel | Drilling Engineer | Hilcorp Alaska, LLC 3800 Centerpoint Dr., Ste. 1400 | Anchorage | AK | 99503 Office: 907.777.8395 | Cell: 805.235.6265 From: Davies, Stephen F (CED) [mailto:steve.davies@alaska.gov] Sent: Thursday, March 19, 2020 3:09 PM To: Joseph Engel <jengel@hilcorp.com> Subject: RE: [EXTERNAL] RE: MPU M‐44 (PTD 220‐030) ‐ Another Question Joe, Thanks for your help. I notice that recently permitted well M‐43 also lies within the Area of Review. Have drilling operations begun in M‐ 43? If so, please provide isolation information for that well too. Will MPU M‐44 be pre‐produced for 1 month or longer, or will it be flowed back only briefly for clean up? Thanks, Steve Davies Alaska Oil and Gas Conservation Commission (AOGCC) CONFIDENTIALITY NOTICE: This e‐mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e‐mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907‐793‐1224 or steve.davies@alaska.gov. 2 From: Joseph Engel <jengel@hilcorp.com> Sent: Thursday, March 19, 2020 12:39 PM To: Davies, Stephen F (CED) <steve.davies@alaska.gov> Subject: RE: [EXTERNAL] RE: MPU M‐44 (PTD 220‐030) ‐ Another Question Steve – All Moose Pad wells prior to M‐43/44 (target NB/NC sand) have been in the OA sand. On our offset well mud density charts, I put the most analogous and closest offset wells for the best information. Therefore we put NB offset well info for NB wells, OA for OA, etc. A development map below shows the proximity of L‐51/52/53 to the M‐43/44/45 well patterns (red box). Please let me know if this is sufficient. No worries on the string of emails, it actually helps me answer each question and not miss anything. Please let me know if you have any questions. Thank you for your time. ‐Joe 3 Joe Engel | Drilling Engineer | Hilcorp Alaska, LLC 3800 Centerpoint Dr., Ste. 1400 | Anchorage | AK | 99503 Office: 907.777.8395 | Cell: 805.235.6265 From: Davies, Stephen F (CED) [mailto:steve.davies@alaska.gov] Sent: Thursday, March 19, 2020 11:00 AM To: Joseph Engel <jengel@hilcorp.com> Subject: [EXTERNAL] RE: MPU M‐44 (PTD 220‐030) ‐ Another Question Joe, Could Hilcorp please update the Offset Well Mud Densities table on page 49 to include mud weights used to drill recent Moose Pad wells? 4 Apologies for the string of emails, I should have combined all of these into a single one. Thanks, Steve Davies Alaska Oil and Gas Conservation Commission (AOGCC) CONFIDENTIALITY NOTICE: This e‐mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e‐mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907‐793‐1224 or steve.davies@alaska.gov. From: Davies, Stephen F (CED) Sent: Thursday, March 19, 2020 10:35 AM To: Joe Engel <jengel@hilcorp.com> Subject: RE: MPU M‐44 (PTD 220‐030) ‐ Another Question Joe, Hilcorp has drilled several wells from Moose Pad at MPU, yet the Permit to Drill applications always include the Data Sheet Formation Description from L‐Pad. Has Hilcorp considered generating a new Data Sheet Formation Description incorporating drilling results from Moose Pad? Or are there no significant variations between the geological sections at Moose Pad and L Pad? Thanks, Steve Davies Alaska Oil and Gas Conservation Commission (AOGCC) CONFIDENTIALITY NOTICE: This e‐mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e‐mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907‐793‐1224 or steve.davies@alaska.gov. From: Davies, Stephen F (CED) Sent: Thursday, March 19, 2020 10:25 AM To: Joe Engel <jengel@hilcorp.com> Subject: MPU M‐44 (PTD 220‐030) ‐ Question Joe, The description in the application states this is a Schrader Bluff NB/NC injector. The 10th bullet point in Section 15.14 on page 29 describes a plan to undulate between the OA1 and OA3 sand lobes. Please provide correct text for this bullet point. Regards, Steve Davies Alaska Oil and Gas Conservation Commission (AOGCC) CONFIDENTIALITY NOTICE: This e‐mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e‐mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907‐793‐1224 or steve.davies@alaska.gov. 5 The information contained in this e-mail message is confidential information intended only for the use of the recipient(s) named above. In addition, this communication may be legally privileged. If the reader of this e-mail is not an intended recipient, you have received this e-mail in error and any review, dissemination, distribution or copying is strictly prohibited. If you have received this e-mail in error, please notify the sender immediately by return e-mail and permanently delete the copy you received. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. Area of Review MPM-44 PTD API WELL STATUS Top of SB NB (MD) Top of SB NB (TVD) CBL Top of Cement (MD) CBL Top of Cement (TVD)Schrader NB status Zonal Isolation 183-182 50-029-21057-00-00 MPM-01 P&A'd 4419'3625'Surface Surface P&A'd Well P&A'd and sidetracked 218-165 50-029-23617-00-00 MPM-10 OA 5754'3836'Surface Surface Cased/Cemented Lateral in OA 219-010 50-029-23621-00-00 MPM-11 OA 4734'3789'Surface Surface Cased/Cemented Lateral in OA 218-176 50-029-23619-00-00 MPM-12 OA 4157'3747'Surface Surface Cased/Cemented Lateral in OA 219-087 50-029-23638-00-00 MPM-13 OA 4206'3716'Surface Surface Cased/Cemented Lateral in OA 219-040 50-029-23625-00-00 MPM-14 OA 4301'3713'Surface Surface Cased/Cemented Lateral in OA 219-141 50-029-23653-00-00 MPM-15 OA 4966'3675'Surface Surface Cased/Cemented Lateral in OA 219-061 50-029-23631-00-00 MPM-16 OA 5847'3653'Surface Surface Cased/Cemented Lateral in OA 219-125 50-029-23648-00-00 MPM-17 OA 6546'3612'Surface Surface Cased/Cemented Lateral in OA 219-070 50-029-23632-00-00 MPM-18 OA 7133'3533'Surface Surface Cased/Cemented Lateral in OA 219-154 50-029-23655-00-00 MPM-19 OA 8202'3580'Surface Surface Cased/Cemented Lateral in OA 219-193 50-029-23662-00-00 MPM-34 Oba 6144'3673'Surface Surface Cased/Cemented Lateral in Oba 220-005 50-029-23665-00-00 MPM-35 OBa 5537'3729'Surface Surface Cased/Cemented Lateral in Oba 220-020 50-029-23671-00-00 MPM-43 Current Drill - NB Lat ~4884'~4003'Surface Surface Will be open Open to injection support 1 Davies, Stephen F (CED) From:Cody Dinger <cdinger@hilcorp.com> Sent:Thursday, March 19, 2020 4:44 PM To:Joseph Engel; Davies, Stephen F (CED) Subject:RE: [EXTERNAL] RE: MPU M-44 (PTD 220-030) - Another Question Attachments:AOR for MPM-44 3-19-20.pdf Steve, Here is the updated AOR with the addition of MPU M‐43, I also corrected the PTD # for MPU M‐35. Thanks, Cody From: Joseph Engel Sent: Thursday, March 19, 2020 7:29 PM To: 'Davies, Stephen F (CED)' <steve.davies@alaska.gov> Cc: Cody Dinger <cdinger@hilcorp.com> Subject: RE: [EXTERNAL] RE: MPU M‐44 (PTD 220‐030) ‐ Another Question No problem, Steve. We are currently running surface casing on M‐43. M‐43 lateral will be open to injection support from M‐44. I will have Cody update the AOR and send it to you. M‐44 will not be preproduced. Let me know if you have any other questions. Thanks. ‐Joe Joe Engel | Drilling Engineer | Hilcorp Alaska, LLC 3800 Centerpoint Dr., Ste. 1400 | Anchorage | AK | 99503 Office: 907.777.8395 | Cell: 805.235.6265 From: Davies, Stephen F (CED) [mailto:steve.davies@alaska.gov] Sent: Thursday, March 19, 2020 3:09 PM To: Joseph Engel <jengel@hilcorp.com> Subject: RE: [EXTERNAL] RE: MPU M‐44 (PTD 220‐030) ‐ Another Question Joe, Thanks for your help. 2 I notice that recently permitted well M‐43 also lies within the Area of Review. Have drilling operations begun in M‐ 43? If so, please provide isolation information for that well too. Will MPU M‐44 be pre‐produced for 1 month or longer, or will it be flowed back only briefly for clean up? Thanks, Steve Davies Alaska Oil and Gas Conservation Commission (AOGCC) CONFIDENTIALITY NOTICE: This e‐mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e‐mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907‐793‐1224 or steve.davies@alaska.gov. From: Joseph Engel <jengel@hilcorp.com> Sent: Thursday, March 19, 2020 12:39 PM To: Davies, Stephen F (CED) <steve.davies@alaska.gov> Subject: RE: [EXTERNAL] RE: MPU M‐44 (PTD 220‐030) ‐ Another Question Steve – All Moose Pad wells prior to M‐43/44 (target NB/NC sand) have been in the OA sand. On our offset well mud density charts, I put the most analogous and closest offset wells for the best information. Therefore we put NB offset well info for NB wells, OA for OA, etc. A development map below shows the proximity of L‐51/52/53 to the M‐43/44/45 well patterns (red box). Please let me know if this is sufficient. No worries on the string of emails, it actually helps me answer each question and not miss anything. Please let me know if you have any questions. Thank you for your time. ‐Joe 3 Joe Engel | Drilling Engineer | Hilcorp Alaska, LLC 3800 Centerpoint Dr., Ste. 1400 | Anchorage | AK | 99503 Office: 907.777.8395 | Cell: 805.235.6265 From: Davies, Stephen F (CED) [mailto:steve.davies@alaska.gov] Sent: Thursday, March 19, 2020 11:00 AM To: Joseph Engel <jengel@hilcorp.com> Subject: [EXTERNAL] RE: MPU M‐44 (PTD 220‐030) ‐ Another Question Joe, Could Hilcorp please update the Offset Well Mud Densities table on page 49 to include mud weights used to drill recent Moose Pad wells? 4 Apologies for the string of emails, I should have combined all of these into a single one. Thanks, Steve Davies Alaska Oil and Gas Conservation Commission (AOGCC) CONFIDENTIALITY NOTICE: This e‐mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e‐mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907‐793‐1224 or steve.davies@alaska.gov. From: Davies, Stephen F (CED) Sent: Thursday, March 19, 2020 10:35 AM To: Joe Engel <jengel@hilcorp.com> Subject: RE: MPU M‐44 (PTD 220‐030) ‐ Another Question Joe, Hilcorp has drilled several wells from Moose Pad at MPU, yet the Permit to Drill applications always include the Data Sheet Formation Description from L‐Pad. Has Hilcorp considered generating a new Data Sheet Formation Description incorporating drilling results from Moose Pad? Or are there no significant variations between the geological sections at Moose Pad and L Pad? Thanks, Steve Davies Alaska Oil and Gas Conservation Commission (AOGCC) CONFIDENTIALITY NOTICE: This e‐mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e‐mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907‐793‐1224 or steve.davies@alaska.gov. From: Davies, Stephen F (CED) Sent: Thursday, March 19, 2020 10:25 AM To: Joe Engel <jengel@hilcorp.com> Subject: MPU M‐44 (PTD 220‐030) ‐ Question Joe, The description in the application states this is a Schrader Bluff NB/NC injector. The 10th bullet point in Section 15.14 on page 29 describes a plan to undulate between the OA1 and OA3 sand lobes. Please provide correct text for this bullet point. Regards, Steve Davies Alaska Oil and Gas Conservation Commission (AOGCC) CONFIDENTIALITY NOTICE: This e‐mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e‐mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907‐793‐1224 or steve.davies@alaska.gov. 5 The information contained in this e-mail message is confidential information intended only for the use of the recipient(s) named above. In addition, this communication may be legally privileged. If the reader of this e-mail is not an intended recipient, you have received this e-mail in error and any review, dissemination, distribution or copying is strictly prohibited. If you have received this e-mail in error, please notify the sender immediately by return e-mail and permanently delete the copy you received. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. WELL PERMIT CHECKLISTCompanyHilcorp Alaska LLCWell Name:MILNE PT UNIT M-44Initial Class/TypeSER / PENDGeoArea890Unit11328On/Off ShoreOnProgramSERField & PoolWell bore segAnnular DisposalPTD#:2200300MILNE POINT, SCHRADER BLFF OIL - 525140NA1 Permit fee attachedYesWell lies mostly within ADL 25514; a portion of the surface hole lies in ADL355235.2 Lease number appropriateYes3 Unique well name and numberYesMilne Point Schrader Bluff Oil Pool (525140), governed by CO 477, amended by CO 477.05.4 Well located in a defined poolYesCO 477.05 specifies: “There are no restrictions as to well spacing except that no pay shall5 Well located proper distance from drilling unit boundaryYesbe opened in a well closer than 500 feet from the exterior boundary of the affected area.”6 Well located proper distance from other wellsYesAs planned, well conforms to spacing requirements.7 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 waitYesArea Injection Order No. 10-B14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (ForYesMPU M-01. M-10, M-11, M-12, M-13, M-14, M15, M-16, M-17,15 All wells within 1/4 mile area of review identified (For service well only)NoM-18, M-19, M-34, M-35, M-4316 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)Yes20" conductor set at 114 ft.18 Conductor string providedNANo aquifers in area… permafrost area.19 Surface casing protects all known USDWsYes2 stage cement. ES at 2500 ft20 CMT vol adequate to circulate on conductor & surf csgYes9 5/8" casing will be set at 5844 ft MD. (3763 ft TVD)21 CMT vol adequate to tie-in long string to surf csgYesInjection lateral will have ICD and swell packers.22 CMT will cover all known productive horizonsYesBTC calcs are provided.23 Casing designs adequate for C, T, B & permafrostYesRig has steel pits.24 Adequate tankage or reserve pitNA25 If a re-drill, has a 10-403 for abandonment been approvedYesNo issues with close crossing… NC/B wells will overlay OA/B wells by about 100 TVD.26 Adequate wellbore separation proposedYes27 If diverter required, does it meet regulationsYesMax form pressure = 1663 psi ( 8.6 ppg EMW) will drill with 8.8 - 9.5 drilling mud ) MPD will be used also.28 Drilling fluid program schematic & equip list adequateYes29 BOPEs, do they meet regulationYesMASP = 1325 psi will test BOPE to 3000 psi ( annular to 2500 psi)30 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 shutdownNoH2S not expected but rig has sensors and alarms.33 Is presence of H2S gas probableYes1/4 Mile review completed. All wells in area are mechanically isolated.34 Mechanical condition of wells within AOR verified (For service well only)YesH2S not anticipated from drilling of offset wells; however, rig has H2S sensors and alarms.35 Permit can be issued w/o hydrogen sulfide measuresYesPlanned mud program appears adequate to control operator's forecast formation pressures.36 Data presented on potential overpressure zonesNAManaged Pressure Drilling will be used to monitor and mitigate any abnormal pressure encountered.37 Seismic analysis of shallow gas zonesNASome potential to encounter hydrates, wellbore breathing, and lost circulation. Mitigation38 Seabed condition survey (if off-shore)NAmeasures discussed on p. 42 to 44.39 Contact name/phone for weekly progress reports [exploratory only]ApprSFDDate3/20/2020ApprGLSDate3/23/2020ApprSFDDate3/19/2020AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateSchrader Bluff injector… Nc Nb sands are targeted. Operator to submit FIT data with 10-407 report. GlsJMP03/24/2020