The URL can be used to link to this page

Home My WebLink About219-010MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Friday, November 24, 2023 SUBJECT:Mechanical Integrity Tests TO: FROM:Guy Cook P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL Hilcorp Alaska, LLC M-11 MILNE PT UNIT M-11 Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 11/24/2023 M-11 50-029-23621-00-00 219-010-0 W SPT 3928 2190100 1500 690 689 685 688 4YRTST P Guy Cook 10/10/2023 Testing completed with a Little Red Services pump truck and calibrated gauges. Mono-bore 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-11 Inspection Date: Tubing OA Packer Depth 194 1703 1619 1591IA 45 Min 60 Min Rel Insp Num: Insp Num:mitGDC231009152204 BBL Pumped:2 BBL Returned:2 Friday, November 24, 2023 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: 10/14/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU M-11 (PTD 219-010) Coil 08/03/2021 Please include current contact information if different from above. 37' (6HW Received By: 10/14/2021 By Abby Bell at 3:05 pm, Oct 14, 2021 1. Operations Abandon Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Suspend Perforate Other Stimulate Alter Casing Change Approved Program Plug for Redrill Perforate New Pool Repair Well Re-enter Susp Well Other: Conformance Treatment Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number): 8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071):10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 16,070 feet N/A feet true vertical 4,041 feet N/A feet Effective Depth measured 16,050 feet 5,233 feet true vertical 4,040 feet 3,928 feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth)3-1/2" 9.2# / L-80 / EUE 8rd 5,252' 3,930' Packers and SSSV (type, measured and true vertical depth)ZXP LTP N/A See Above N/A 12. Stimulation or cement squeeze summary: N/A Intervals treated (measured): Treatment descriptions including volumes used and final pressure: N/A 13. Prior to well operation: Subsequent to operation: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Authorized Name Contact Name: Authorized Title: Contact Email: Contact Phone: Operations Manager Chad Helgeson WINJ WAG 0 Water-Bbl MD 114' 5,393' 16,055' TVD 114' measured true vertical Packer Size N/A Casing Conductor Junk measured 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 3. Address: 4. Well Class Before Work: 0 Representative Daily Average Production or Injection Data 698626 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 219-010 50-029-23621-00-00 Plugs ADL025514, ADL388235 & ADL025515 5. Permit to Drill Number: Milne Point Field / Schrader Bluff Oil Pool 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 321-351 690 Authorized Signature with date: David Haakinson dhaakinson@hilcorp.com 0 Milne Point Unit M-11 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf 0 Casing Pressure Tubing Pressure 0 N/A measured 1,655 Length 114' 5,393' 10,822' Surface Liner Oil-Bbl 9,020psi 777-8343 20" 9-5/8" 4-1/2" 3,941' 4,041' 8,540psi Hilcorp Alaska LLC 2. Operator Name Senior Engineer: Senior Res. Engineer: Collapse N/A 3,090psi Burst N/A 5,750psi Form 10-404 Revised 3/2020 Submit Within 30 days of Operations By Samantha Carlisle at 12:24 pm, Aug 26, 2021 Digitally signed by Chad Helgeson (1517) DN: cn=Chad Helgeson (1517), ou=Users Date: 2021.08.26 10:29:44 -08'00' Chad Helgeson (1517) DSR-8/26/21 RBDMS HEW 8/26/2021 MGR01SEP2021 SFD 8/27/2021 Well Name Rig API Number Well Permit Number Start Date End Date MP M-11 Coil 50-029-23621-00-00 219-010 8/4/2021 8/4/2021 No operations to report. No operations to report. 8/7/2021 - Saturday No operations to report. 8/10/2021 - Tuesday 8/8/2021 - Sunday No operations to report. 8/9/2021 - Monday 8/6/2021 - Friday No operations to report. 8/4/2021 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary Coiled tubing deployed perforating. Perforate the following intervals: 12645' - 12655, 11790' - 11800', 11025' - 11035', 10420' - 10430', 9905' - 9915'. Guns used were 2.0" 6spf 2006PJ Omega. All shots fired. Initial static loss rate with 9.2 ppg brine was .1 bpm. Post perforating static loss rate with 9.2 ppg brine was 1 bpm. Secure well and notify operations that well is ready to be brought back on injection. 8/5/2021 - Thursday No operations to report. _____________________________________________________________________________________ Revised By: DH 8/10/2021 PROPOSED Milne Point Unit Well: MPU M-11 PTD: 219-010 API: 50-029-23621-00-00 Depth MD Depth TVD ICD/Swell Packer Detail Depth MD Depth TVD ICD/Swell Packer Detail 5,422’ 3,941’ 4.5” x 8.25” Tendeka Water Swell Packer 10,661’ 4,002’ 4.5” x 8.25” Tendeka Water Swell Packer 5,799’ 3,947’ 4.5” Tendeka Sliding Sleeve w/ Screen and ICDs 10,998’ 4,002’ 4.5” Tendeka Sliding Sleeve w/ Screen and ICDs 5,986’ 3,951’ 4.5” x 8.25” Tendeka Water Swell Packer 11,305’ 3,998’ 4.5” x 8.25” Tendeka Water Swell Packer 6,322’ 3,957’ 4.5” Tendeka Sliding Sleeve w/ Screen and ICDs 11,762’ 3,985’ 4.5” Tendeka Sliding Sleeve w/ Screen and ICDs 6,627’ 3,956’ 4.5” x 8.25” Tendeka Water Swell Packer 12,272’ 3,981’ 4.5” x 8.25” Tendeka Water Swell Packer 6,806’ 3,990’ 4.5” Tendeka Sliding Sleeve w/ Screen and ICDs 12,616’ 3,999’ 4.5” Tendeka Sliding Sleeve w/ Screen and ICDs 7,033’ 4,005’ 4.5” x 8.25” Tendeka Water Swell Packer 12,887’ 4,013’ 4.5” x 8.25” Tendeka Water Swell Packer 8,365’ 4,016’ 4.5” x 8.25” Tendeka Water Swell Packer 13,590’ 4,035’ 4.5” Tendeka Sliding Sleeve w/ Screen and ICDs 8,585’ 4,000’ 4.5” Tendeka Sliding Sleeve w/ Screen and ICDs 13,860’ 4,037’ 4.5” x 8.25” Tendeka Water Swell Packer 8,733’ 3,991’ 4.5” x 8.25” Tendeka Water Swell Packer 14,197’ 4,040’ 4.5” Tendeka Sliding Sleeve w/ Screen and ICDs 9,150’ 3,982’ 4.5” Tendeka Sliding Sleeve w/ Screen and ICDs 14,465’ 4,026’ 4.5” x 8.25” Tendeka Water Swell Packer 9,496’ 3,983’ 4.5” x 8.25” Tendeka Water Swell Packer 14,764’ 4,012’ 4.5” Tendeka Sliding Sleeve w/ Screen and ICDs 9,875’ 3,985’ 4.5” Tendeka Sliding Sleeve w/ Screen and ICDs 14,995’ 4,007’ 4.5” x 8.25” Tendeka Water Swell Packer 10,059’ 3,995’ 4.5” x 8.25” Tendeka Water Swell Packer 15,298’ 4,012’ 4.5” Tendeka Sliding Sleeve w/ Screen and ICDs 10,394’ 4,002’ 4.5” Tendeka Sliding Sleeve w/ Screen and ICDs 15,487’ 4,016’ 4.5” x 8.25” Tendeka Water Swell Packer 15,869’ 4,032’ 4.5” Tendeka Sliding Sleeve w/ Screen and ICDs TD =16,070’(MD) / TD =4,015’(TVD) 20” Orig. KB Elev.: 59.3’/ GL Elev.: 25.0’ RKB – THF: 31.25’ (Doyon 14) 3-1/2” 2 9-5/8” 1 4/5 7 See ICD & Swell Packer Detail PBTD =16,050’ (MD) / PBTD =4,015’(TVD) 9-5/8” ‘ES’ Cementer @ 2,322’ MD 4-1/2” 6 3 CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF 20"x34” Conductor (Insulated) 215.5 / X-42 / Weld N/A Surface 114’N/A 9-5/8" Surface 40 / L-80 / TXP 8.679” Surface 5,393’ 0.0758 4-1/2” Liner 13.5 / L-80 / Hyd 625 3.795” 5,233’ 16,055’ 0.0149 TUBING DETAIL 3-1/2" Tubing 9.3 / L-80 / EUE 8RD 2.867” Surf 5,252’ 0.0870 JEWELRY DETAIL No Top MD Item ID Upper Completion 1 2,352’ 3.5” X Nipple (2.813” Packing Bore) 2.813” 2 4,889’ 3.5” XN Nipple (2.813” Packing Bore; 2.75” No-Go) 2.750” 3 5,158’ 3.5” Gauge Mandrel SGM-XPQG w/ ¼” Wire 2.896” 4 5,242’ 8.26” No Go Locater w/ 7.375” Seal Assembly 2.992” 5 5,243’ 7.375” Tieback above the SLZXP Liner Top Packer (Btm @ 5,252’)2.992” Lower Completion 6 5,233’ ZXP Liner Top Packer - 7 16,050’ WIV (Ball on Seat/ Closed) - OPEN HOLE / CEMENT DETAIL 42" 50 bbls (10 Yards Pilecrete dumped down backside) 12-1/4"Stg 1 – 138 bbl (330 sx) Lead 12.0 ppg / 82 bbl (400 sx) Tail 15.8 ppg Stg 2 – 315 bbl (410 sx) Lead 10.7 ppg / 55.8 bbl (270 sx) Tail 15.8 ppg 8-1/2” Cementless Injection Liner in 8-1/2” hole WELL INCLINATION DETAIL KOP @ 500’ Hole Angle @ XN = 70° @ 4,889’ MD Hole Angle @ Liner Top = 83° @ 5,233’ MD Max Hole Angle = 95° @ 8,303’ MD TREE & WELLHEAD Tree Cameron 3 1/8" 5M w/ 4-1/16” 5M Cameron Wing Wellhead Cameron 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs GENERAL WELL INFO API#: 50-029-23621-00-00 Completed by Doyon 14: 3/31/2019 PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status Schrader Bluff OA 9,905’ 9,915’ 3,987’ 3,987’ 10 8/4/2021 Open 10,420’ 10,430’ 4,002’ 4,002’ 10 8/4/2021 Open 11,025’ 11,035’ 4,003’ 4,003’ 10 8/4/2021 Open 11,790’ 11,800’ 3,985’ 3,985’ 10 8/4/2021 Open 12,645’ 12,655’ 4,001’ 4,001’ 10 8/4/2021 Open p( ) ( ) p( ) ( ) Schrader Bluff OA 9,905’ 9,915’ 3,987’ 3,987’ 10 8/4/2021 Open 10,420’ 10,430’ 4,002’ 4,002’ 10 8/4/2021 Open 11,025’ 11,035’ 4,003’ 4,003’ 10 8/4/2021 Open 11,790’ 11,800’ 3,985’ 3,985’ 10 8/4/2021 Open 12,645’ 12,655’ 4,001’ 4,001’ 10 8/4/2021 Open p( ) ( ) p( ) ( ) 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): 16,070'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 7/28/2021 3-1/2" Perforation Depth MD (ft): See Schematic Milne Point Unit M-11 C.O. 477.05 ZXP LTP And N/A 5,233 MD / 3,928 TVD and N/A 5,393' 16,055' See Schematic 114'20" 9-5/8" 4-1/2" 5,393' 10,822' 9.2# / L-80 / EUE 8rd TVD Burst 5,252' MD N/A 5,750psi 9,020psi 3,941' 4,041' 4,015'1,308 N/A Milne Point Field / Schrader Bluff Oil Pool 114'114' STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL025514, ADL388235 & ADL025515 219-010 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 50-029-23621-00-00 Hilcorp Alaska LLC Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): Tubing Size: PRESENT WELL CONDITION SUMMARY Length Size 4,041' 16,050' 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 Samantha Carlisle at 9:31 am, Jul 15, 2021 321-351 Chad Helgeson (1517) 2021.07.14 15:32:05 - 08'00' 10-404 MGR22JUL21 SFD 7/15/2021 DSR-7/15/21 dts 7/23/2021 JLC 7/23/2021 Jeremy Price Digitally signed by Jeremy Price Date: 2021.07.23 09:50:32 -08'00' RBDMS HEW 7/26/2021 CT Perforate Well: MPU M-11 Date: 7/14/2021 Well Name:MPU M-11 API Number:50-029-23621-00-00 Current Status:Injector - Online Pad:M-Pad Estimated Start Date:July 28th, 2021 Rig:CTU 6 Reg. Approval Req’d?Yes Date Reg. Approval Rec’vd: Regulatory Contact:Darci Horner Permit to Drill Number:219-010 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: 1,700 psi @ 3,920’ TVD Downhole Gauge |8.34 PPGE MPSP:1,308 psi @ 3,920’ TVD (0.1psi/ft gas gradient) Max Deviation:95° @ 8,303’ MD Max Dogleg:5.7°/100ft @ 4,295’ MD Min ID:2.75” ID @ 4,889’ MD XN Nipple Brief Well Summary: M-11 is a Schrader OA injector drilled in March 2019 to support M-10 and M-12 producers. The injector experienced an MBE to M-10 on 6/8/20, confirmed with a red dye test at five hours lag time. A MBE treatment was pumped into ICD #4 at 8,585’ MD with delayed success. Over time, a significant skin factor has built in M- 11 with injection rates down 50% versus expected. Objective: x Rig up coiled tubing and TCP to perforate solid liner to reduce skin factor and test methodology of increasing injection in wells completed with ICDs. o Targeting a 600 BWPD injection increase to result in ~400 BOPD increase between M-10 and M- 12. x Plan is to use Ballistic Time-Delay Fuse (BTDF) to initiate an on-time delay system to perforate seven 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 pressure tested to 1,500 psi for 30 mins on 10/17/19. x IA was pressure tested to 3,000 psi for 30 minutes on 3/30/19 upon initial completion. x FCO completed to 14,266’ CTMD on 6/24/2020. Coil Tubing Perforating Procedure 1. MIRU Coiled Tubing Unit with 2” 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. injector experienced an MBE to M-10 o CT Perforate Well: MPU M-11 Date: 7/14/2021 4. MU GR/CCL and drift assembly w/ circulating sub and 200’ of 2.3” OD spent perf guns. 5. Perform TIW valve stab drill with CT crew. 6. RIH to ~100’ past ICD #10 @ 12616’ MD. 7. Flag pipe for correlation. 8. Contact Engineer to review depth and planned perforation depths. 9. POOH to lateral KOP @ 5,450’ MD and confirm well is dead. Bleed any gas head pressure to return tank and document pressures for 15 minutes. 10. Circulate in KWF if necessary. 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 12645 12655 4001 4001 Schrader OA Sand Deployment Bar 6.5 Deployment Bar 6.5 Perf Gun 10 11790 11800 3985 3985 Schrader OA Sand Deployment Bar 6.5 Deployment Bar 6.5 Perf Gun 10 11025 11035 4003 4003 Schrader OA Sand Deployment Bar 6.5 Deployment Bar 6.5 Perf Gun 10 10420 10430 3993 3993 Schrader OA Sand Deployment Bar 6.5 Deployment Bar 6.5 Perf Gun 10 9905 9915 3987 3987 Schrader OA Sand Deployment Bar 6.5 Deployment Bar 6.5 Deployment Bar 6.5 Deployment Bar 6.5 Deployment Bar 6.5 Deployment Bar 6.5 Deployment Bar 6.5 Perf Gun 10 6350 6360 3958 3958 Schrader OA Sand Deployment Bar 6.5 Deployment Bar 6.5 Perf Gun 10 5830 5840 3948 3948 Schrader OA Sand Total Length 191.15 3555' Pick Up. Estimate 47 minutes travel time. 520' Pick Up. Estimate 7 minutes travel time. 515' Pick Up. Estimate 7 minutes travel time. 605' Pick Up. Estimate 8 minutes travel time. 765' Pick Up. Estimate 10 minutes travel time. 855' Pick Up. Estimate 11 minutes travel time. CT Perforate Well: MPU M-11 Date: 7/14/2021 Note: Well temperature is estimated at 68 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 5,830’ MD is after activating firing head is 133 minutes to ensure completion of maximum burn time of all delay fuses in the string.Do not pick up above LTP @ 5,250’ MD before 133 minutes after activation to avoid perforating tubing. 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 5830’ MD until full duration of delay period has elapsed of 133 minutes from time of firing head activation. 23. POOH to KOP @ 5,450’ 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 injector, RIH. Assure ability to circulate KWF across top of well if taking fluids. _____________________________________________________________________________________ Revised By: TDF 7/27/2020 SCHEMATIC Milne Point Unit Well: MPU M-11 PTD: 219-010 API: 50-029-23621-00-00 Depth MD Depth TVD ICD/Swell Packer Detail Depth MD Depth TVD ICD/Swell Packer Detail 5,422’ 3,941’4.5” x 8.25” Tendeka Water Swell Packer 10,661’ 4,002’4.5” x 8.25” Tendeka Water Swell Packer 5,799’ 3,947’4.5” Tendeka Sliding Sleeve w/ Screen and ICDs 10,998’ 4,002’4.5” Tendeka Sliding Sleeve w/ Screen and ICDs 5,986’ 3,951’4.5” x 8.25” Tendeka Water Swell Packer 11,305’ 3,998’4.5” x 8.25” Tendeka Water Swell Packer 6,322’ 3,957’4.5” Tendeka Sliding Sleeve w/ Screen and ICDs 11,762’ 3,985’4.5” Tendeka Sliding Sleeve w/ Screen and ICDs 6,627’ 3,956’4.5” x 8.25” Tendeka Water Swell Packer 12,272’ 3,981’4.5” x 8.25” Tendeka Water Swell Packer 6,806’ 3,990’4.5” Tendeka Sliding Sleeve w/ Screen and ICDs 12,616’ 3,999’4.5” Tendeka Sliding Sleeve w/ Screen and ICDs 7,033’ 4,005’4.5” x 8.25” Tendeka Water Swell Packer 12,887’ 4,013’4.5” x 8.25” Tendeka Water Swell Packer 8,365’ 4,016’4.5” x 8.25” Tendeka Water Swell Packer 13,590’ 4,035’4.5” Tendeka Sliding Sleeve w/ Screen and ICDs 8,585’ 4,000’4.5” Tendeka Sliding Sleeve w/ Screen and ICDs 13,860’ 4,037’4.5” x 8.25” Tendeka Water Swell Packer 8,733’ 3,991’4.5” x 8.25” Tendeka Water Swell Packer 14,197’ 4,040’4.5” Tendeka Sliding Sleeve w/ Screen and ICDs 9,150’ 3,982’4.5” Tendeka Sliding Sleeve w/ Screen and ICDs 14,465’ 4,026’4.5” x 8.25” Tendeka Water Swell Packer 9,496’ 3,983’4.5” x 8.25” Tendeka Water Swell Packer 14,764’ 4,012’4.5” Tendeka Sliding Sleeve w/ Screen and ICDs 9,875’ 3,985’4.5” Tendeka Sliding Sleeve w/ Screen and ICDs 14,995’ 4,007’4.5” x 8.25” Tendeka Water Swell Packer 10,059’ 3,995’4.5” x 8.25” Tendeka Water Swell Packer 15,298’ 4,012’4.5” Tendeka Sliding Sleeve w/ Screen and ICDs 10,394’ 4,002’4.5” Tendeka Sliding Sleeve w/ Screen and ICDs 15,487’ 4,016’4.5” x 8.25” Tendeka Water Swell Packer 15,869’ 4,032’4.5” Tendeka Sliding Sleeve w/ Screen and ICDs TD =16,070’(MD) / TD =4,015’(TVD) 20” Orig. KB Elev.: 59.3’/ GL Elev.: 25.0’ RKB – THF: 31.25’ (Doyon 14) 3-1/2” 2 9-5/8” 1 4/5 7 See ICD & Swell Packer Detail PBTD =16,050’ (MD) / PBTD =4,015’(TVD) 9-5/8” ‘ES’ Cementer @ 2,322’ MD 4-1/2” 6 3 CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF 20"x34” Conductor (Insulated) 215.5 / X-42 / Weld N/A Surface 114’ N/A 9-5/8" Surface 40 / L-80 / TXP 8.679” Surface 5,393’ 0.0758 4-1/2” Liner 13.5 / L-80 / Hyd 625 3.795” 5,233’ 16,055’ 0.0149 TUBING DETAIL 3-1/2" Tubing 9.3 / L-80 / EUE 8RD 2.867” Surf 5,252’ 0.0870 JEWELRY DETAIL No Top MD Item ID Upper Completion 1 2,352’ 3.5” X Nipple (2.813” Packing Bore) 2.813” 2 4,889’ 3.5” XN Nipple (2.813” Packing Bore; 2.75” No-Go) 2.750” 3 5,158’ 3.5” Gauge Mandrel SGM-XPQG w/ ¼” Wire 2.896” 4 5,242’ 8.26” No Go Locater w/ 7.375” Seal Assembly 2.992” 5 5,243’ 7.375” Tieback above the SLZXP Liner Top Packer (Btm @ 5,252’)2.992” Lower Completion 6 5,233’ ZXP Liner Top Packer - 7 16,050’ WIV (Ball on Seat/ Closed) - OPEN HOLE / CEMENT DETAIL 42" 50 bbls (10 Yards Pilecrete dumped down backside) 12-1/4"Stg 1 – 138 bbl (330 sx) Lead 12.0 ppg / 82 bbl (400 sx) Tail 15.8 ppg Stg 2 – 315 bbl (410 sx) Lead 10.7 ppg / 55.8 bbl (270 sx) Tail 15.8 ppg 8-1/2” Cementless Injection Liner in 8-1/2” hole WELL INCLINATION DETAIL KOP @ 500’ Hole Angle @ XN = 70° @ 4,889’ MD Hole Angle @ Liner Top = 83° @ 5,233’ MD Max Hole Angle = 95° @ 8,303’ MD TREE & WELLHEAD Tree Cameron 3 1/8" 5M w/ 4-1/16” 5M Cameron Wing Wellhead Cameron 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs GENERAL WELL INFO API#: 50-029-23621-00-00 Completed by Doyon 14: 3/31/2019 _____________________________________________________________________________________ Revised By: TDF 7/14/2021 PROPOSED Milne Point Unit Well: MPU M-11 PTD: 219-010 API: 50-029-23621-00-00 Depth MD Depth TVD ICD/Swell Packer Detail Depth MD Depth TVD ICD/Swell Packer Detail 5,422’ 3,941’ 4.5” x 8.25” Tendeka Water Swell Packer 10,661’ 4,002’ 4.5” x 8.25” Tendeka Water Swell Packer 5,799’ 3,947’ 4.5” Tendeka Sliding Sleeve w/ Screen and ICDs 10,998’ 4,002’ 4.5” Tendeka Sliding Sleeve w/ Screen and ICDs 5,986’ 3,951’ 4.5” x 8.25” Tendeka Water Swell Packer 11,305’ 3,998’ 4.5” x 8.25” Tendeka Water Swell Packer 6,322’ 3,957’ 4.5” Tendeka Sliding Sleeve w/ Screen and ICDs 11,762’ 3,985’ 4.5” Tendeka Sliding Sleeve w/ Screen and ICDs 6,627’ 3,956’ 4.5” x 8.25” Tendeka Water Swell Packer 12,272’ 3,981’ 4.5” x 8.25” Tendeka Water Swell Packer 6,806’ 3,990’ 4.5” Tendeka Sliding Sleeve w/ Screen and ICDs 12,616’ 3,999’ 4.5” Tendeka Sliding Sleeve w/ Screen and ICDs 7,033’ 4,005’ 4.5” x 8.25” Tendeka Water Swell Packer 12,887’ 4,013’ 4.5” x 8.25” Tendeka Water Swell Packer 8,365’ 4,016’ 4.5” x 8.25” Tendeka Water Swell Packer 13,590’ 4,035’ 4.5” Tendeka Sliding Sleeve w/ Screen and ICDs 8,585’ 4,000’ 4.5” Tendeka Sliding Sleeve w/ Screen and ICDs 13,860’ 4,037’ 4.5” x 8.25” Tendeka Water Swell Packer 8,733’ 3,991’ 4.5” x 8.25” Tendeka Water Swell Packer 14,197’ 4,040’ 4.5” Tendeka Sliding Sleeve w/ Screen and ICDs 9,150’ 3,982’ 4.5” Tendeka Sliding Sleeve w/ Screen and ICDs 14,465’ 4,026’ 4.5” x 8.25” Tendeka Water Swell Packer 9,496’ 3,983’ 4.5” x 8.25” Tendeka Water Swell Packer 14,764’ 4,012’ 4.5” Tendeka Sliding Sleeve w/ Screen and ICDs 9,875’ 3,985’ 4.5” Tendeka Sliding Sleeve w/ Screen and ICDs 14,995’ 4,007’ 4.5” x 8.25” Tendeka Water Swell Packer 10,059’ 3,995’ 4.5” x 8.25” Tendeka Water Swell Packer 15,298’ 4,012’ 4.5” Tendeka Sliding Sleeve w/ Screen and ICDs 10,394’ 4,002’ 4.5” Tendeka Sliding Sleeve w/ Screen and ICDs 15,487’ 4,016’ 4.5” x 8.25” Tendeka Water Swell Packer 15,869’ 4,032’ 4.5” Tendeka Sliding Sleeve w/ Screen and ICDs TD =16,070’(MD) / TD =4,015’(TVD) 20” Orig. KB Elev.: 59.3’/ GL Elev.: 25.0’ RKB – THF: 31.25’ (Doyon 14) 3-1/2” 2 9-5/8” 1 4/5 7 See ICD & Swell Packer Detail PBTD =16,050’ (MD) / PBTD =4,015’(TVD) 9-5/8” ‘ES’ Cementer @ 2,322’ MD 4-1/2” 6 3 CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF 20"x34” Conductor (Insulated) 215.5 / X-42 / Weld N/A Surface 114’ N/A 9-5/8" Surface 40 / L-80 / TXP 8.679” Surface 5,393’ 0.0758 4-1/2” Liner 13.5 / L-80 / Hyd 625 3.795” 5,233’ 16,055’ 0.0149 TUBING DETAIL 3-1/2" Tubing 9.3 / L-80 / EUE 8RD 2.867” Surf 5,252’ 0.0870 JEWELRY DETAIL No Top MD Item ID Upper Completion 1 2,352’ 3.5” X Nipple (2.813” Packing Bore) 2.813” 2 4,889’ 3.5” XN Nipple (2.813” Packing Bore; 2.75” No-Go) 2.750” 3 5,158’ 3.5” Gauge Mandrel SGM-XPQG w/ ¼” Wire 2.896” 4 5,242’ 8.26” No Go Locater w/ 7.375” Seal Assembly 2.992” 5 5,243’ 7.375” Tieback above the SLZXP Liner Top Packer (Btm @ 5,252’)2.992” Lower Completion 6 5,233’ ZXP Liner Top Packer - 7 16,050’ WIV (Ball on Seat/ Closed) - OPEN HOLE / CEMENT DETAIL 42" 50 bbls (10 Yards Pilecrete dumped down backside) 12-1/4"Stg 1 – 138 bbl (330 sx) Lead 12.0 ppg / 82 bbl (400 sx) Tail 15.8 ppg Stg 2 – 315 bbl (410 sx) Lead 10.7 ppg / 55.8 bbl (270 sx) Tail 15.8 ppg 8-1/2” Cementless Injection Liner in 8-1/2” hole WELL INCLINATION DETAIL KOP @ 500’ Hole Angle @ XN = 70° @ 4,889’ MD Hole Angle @ Liner Top = 83° @ 5,233’ MD Max Hole Angle = 95° @ 8,303’ MD TREE & WELLHEAD Tree Cameron 3 1/8" 5M w/ 4-1/16” 5M Cameron Wing Wellhead Cameron 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs GENERAL WELL INFO API#: 50-029-23621-00-00 Completed by Doyon 14: 3/31/2019 PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status Schrader OA 5,830 5,840’ 3,948’ 3,948’ 10 Future Pending 6,350’ 6,360’ 3,958’ 3,958’ 10 Future Pending 9,905’ 9,915’ 3,987’ 3,987’ 10 Future Pending 10,420’ 10,430’ 4,002’ 4,002’ 10 Future Pending 11,025’ 11,035’ 4,003’ 4,003’ 10 Future Pending 11,790’ 11,800’ 3,985’ 3,985’ 10 Future Pending 12,645’ 12,655’ 4,001’ 4,001’ 10 Future Pending CT Perforate Well: MPU M-11 Date: 7/14/2021 CT Perforate Well: MPU M-11 Date: 7/14/2021 Equipment Layout Diagram CT Perforate Well: MPU M-11 Date: 7/14/2021 Standing Orders for Open Hole Well Control during Perf Gun Deployment Samuel Gebert Hilcorp Alaska, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: sam.gebert@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: Date: DATE: 01/15/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU M-11 (PTD 219-010) COIL FLAG 10/16/2020 Please include current contact information if different from above. PTD: 2190100 E-Set: 34584 Received by the AOGCC 01/19/2021 Abby Bell 01/19/2021 1. Operations Abandon Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Suspend Perforate Other Stimulate Alter Casing Change Approved Program Plug for Redrill Perforate New Pool Repair Well Re-enter Susp Well Other: Conformance Treatment Hilcorp Alaska Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number): 8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071):10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 16,070 feet N/A feet true vertical 4,041 feet N/A feet Effective Depth measured 16,050 feet 5,233 feet true vertical 4,015 feet 3,928 feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth)3-1/2" 9.2# / L-80 / EUE 8rd 5,252' 3,930' Packers and SSSV (type, measured and true vertical depth)ZXP LTP N/A See Above N/A 12. Stimulation or cement squeeze summary: N/A Intervals treated (measured): Treatment descriptions including volumes used and final pressure: N/A 13. Prior to well operation: Subsequent to operation: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Chad Helgeson Contact Name: Authorized Title:Operations Manager Contact Email: Contact Phone: WINJ WAG 0 Water-Bbl MD 114' 5,393' 16,055' TVD 114' Oil-Bbl measured true vertical Packer Size N/A Junk measured 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 3. Address: 4. Well Class Before Work: 0 Representative Daily Average Production or Injection Data 00 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 219-010 50-029-23621-00-00 Plugs ADL025514, ADL388235 & ADL025515 5. Permit to Drill Number: Milne Point Field / Schrader Bluff Oil Pool 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 320-361 698 Authorized Signature with date: Authorized Name: Abhijeet Tambe Abhijeet.Tambe@hilcorp.com 0 Milne Point Unit M-11 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf 0 Casing Pressure Tubing Pressure 0 N/A measured Casing Conductor Length 114' 5,393' 10,822' Surface Liner 777-8485 20" 9-5/8" 4-1/2" 3,941' 4,041' 8,540psi 776 2. Operator Name Senior Engineer: Senior Res. Engineer: Collapse N/A 3,090psi Burst N/A 5,750psi 9,020psi Form 10-404 Revised 3/2020 Submit Within 30 days of Operations Chad A Helgeson 2020.11.13 14:47:24 -09'00' By Samantha Carlisle at 10:31 am, Nov 16, 2020 RBDMS HEW 11/16/2020 MGR05JAN2021 SFD 11/17/2020DSR-11/17/2020 Well Name Rig API Number Well Permit Number Start Date End Date MP M-11 CTU 50-029-23621-00-00 219-010 9/2/2020 10/31/2020 No operations to report. Continue OPS from 9/3/2020 - MU Straddle Packer BHA and RIH to flag. Correct depth to CL of straddle packers, PUH to ICD #4 depth at 8585 and set packers. Perform injectivity test for 30 min baseline. Batch up H2Zero Slurry and pump as per plan. Pumped 30 bbls + 1 bbl over displacement as per plan into formation. Pull released packers, relaxed elements and POOH. Packers swabbing in the 3-1/2, slow down POOH speed, had to stop several times to allow fluid to bypass Packers. Tried to pump down the coil and coil pressure just continued to climb. POOH in stages allowing fluid to bypass. Made it OOH with all rubbers intact. MU nozzle BHA and RIH to FP the well from 2,500' TVD to surface. Tag up, close SSV and Swab, LD BHA, install night cap and test to 250 low and 3,500 high to secure well 9/5/2020 - Saturday No operations to report. 9/8/2020 - Tuesday 9/6/2020 - Sunday No operations to report. 9/7/2020 - Monday 9/4/2020 - Friday MU Nozzle BHA, cleaned out Ice Plug to 3,000' then POOH. MU Packer Logging BHA. RIH to 14,900', PUH to 14,884' and set packer, online down coil at 0.5 bpm to check injectivity, pressure continued to climb with no break over to 2,910psi and shut down the pump. Circ pressure with a closed choke was 767psi at 1.7 bpm before setting packer. Discuss with Engineer and decision was made to release the packer and POOH. Very low injectivity through ICD's 14 & 15 and probably not communicating to M-10. Stop at 8,800' and log for coil flag then POOH, good data. Red Dye test. (pressure test RU 294/4,063 psi). Spot unit, RU and SB. Job postponed. 9/2/2020 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary Mobilize CTU #6 from Deadhorse to Milne Point, MIRU and test BOPE 250 low/4,000 high, pass. 9/3/2020 - Thursday MU Retrievable Packer BHA with READ GR/CCL Mem Log. Stop RIH, mechanical issue with deck engine, fan belt slack adjuster bolts backed out, tried to tighten but stripped out. Suspend OPS to replace bolts with correct longer stud bolts to engage deeper threads. Torque nuts to spec and function test. Good test, continue OPS on 9/4/2020. Well Name Rig API Number Well Permit Number Start Date End Date MP M-11 CTU 50-029-23621-00-00 219-010 9/2/2020 10/31/2020 MIRU CTU#9, Nipple up BOPE. PT surface 360psi Low / 3,600psi High. Will return in a.m. for IPROF No operations to report. 9/19/2020 - Saturday No operations to report. 9/22/2020 - Tuesday 9/20/2020 - Sunday No operations to report. 9/21/2020 - Monday 9/18/2020 - Friday No operations to report. 9/16/2020 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary No operations to report. 9/17/2020 - Thursday Freeze Protect (Pressure Test Surface lines 250/2000 psi) Pump 25 bbls Dsl down Tbg. Well Name Rig API Number Well Permit Number Start Date End Date MP M-11 CTU 50-029-23621-00-00 219-010 9/2/2020 10/31/2020 9/25/2020 - Friday No operations to report. 9/23/2020 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary Pre heat and circulate fluid. (Pressure test RU. 250/2,500psi) Heated 37 bbls diesel to 90* and displaced coil fluid to open top. Circulted and heated transport to 100* pumped 5 bbls diesel into transport for end job FP fluid. CTU#9 1.75" Coil: Rih w/ CTC (2.13" x 0.40'), MHA (2.13" x 2.44'), Ported x-over (2.13" x 0.44'), K-jt (1.75" x 0.75'), x-over (1.75" x 0.35), MBH (1.69" x 2.38'), UMT (1.69" x 2.14'), CCL (1.69" x 1.54'), Centralizer (2.0" x 2.0'), QPS (1.69" x 1.58'), Inline Spinner (2.13" x 1.44'), PRT (1.69" x 1.04') Centralizer (2.0" x 2.0'), Continuous Jewelled Flow meter (2.13" x 1.16') TL= 19.67'. Perform spinner calibration passes from 5,600'- 5,800'. Rih to 11,500'. Perform 90 fpm / 60 fpm pass up. Perform stop counts above each sliding sleeve above 11,500'. Pooh. Download data. Have data. Send to OE to review. RDMO 9/24/2020 - Thursday No operations to report. No operations to report. No operations to report. 9/26/2020 - Saturday No operations to report. 9/29/2020 - Tuesday 9/27/2020 - Sunday No operations to report. 9/28/2020 - Monday Well Name Rig API Number Well Permit Number Start Date End Date MP M-11 CTU 50-029-23621-00-00 219-010 9/2/2020 10/31/2020 10/16/2020 - Friday Move CTU 6 to M-Pad. MIRU CTU, Test BOPE 250L/ 3,500H. NU BOPE on well. MU Logging BHA and RIH to 10,500'. POH to 10,350' and paint white flag. Displace coil and well to 2% KCL with safelube. Pumped 5 bbl diesel. POOH logging to 5,600' ctmd. Stop logging pass at 5,300' ctmd. Pause for two minutes. POH. OOH, Displace coil to diesel and r/d logging tools. MU BOT packer assembley and make up on well. Pressure test on well to 300psi and 4,200psi. RIH to 10,500' with BOT packer. 10/14/2020 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary No operations to report. 10/15/2020 - Thursday No operations to report. No operations to report. RIH and set Packer at 10,430' and inject through ICD's 1-7. No communication, PUH and set packer at 9,250' below ICD #5, injection pressure higher at lower rate. Call and discuss moving down to 12,660' between ICD's 10 & 11 split the difference between remaining untested ICD's, no communication to M-10. RIH to 14,250' between ICD's 12 & 13, no communication, RIH below ICD 13 WO setting packer, no communication from any of the tests to M-10. Talk to OE and we are done, POOH while the town team discusses if there is anything else we can do before RD. 10/17/2020 - Saturday No operations to report. 10/20/2020 - Tuesday 10/18/2020 - Sunday Freeze Protect (MBE broke down) (Pressure test surface lines 250/2500psi) Pump 28 bbls Dsl down Tbg 10/19/2020 - Monday Well Name Rig API Number Well Permit Number Start Date End Date MP M-11 CTU 50-029-23621-00-00 219-010 9/2/2020 10/31/2020 No operations to report. CTU #6 1.75" CT .156" wall. Continue OPS from 10/30/2020. MU BOT iSAP Packer BHA and RIH. Establish injectivity (1.2 bpm @ 688psi WHP) and pressure increase on M-10 BHP. Set PKR at 6,900' just below ICD #3. Online at 0.2-0.3 bpm 800psi, shut down, release PKR, move down below ICD #5 to 9,250' and set PKR. PKR set, online down backside. Shut down and release PKR and move down below ICD #7, set PKR and pump down backside. Not seeing any BHP increase on M-10. Release PKR and RIH while injecting. Stopped at 12,440'. OE is not seeing any BHP increase. POOH maintaining injection rate then shut down pump. OE did not see any pressure increases after the initial injection at 9,250', POOH. WHP increasing at 1,650', looks like we rolled a PKR rubber, RIH and POOH to try and roll it back. POOH clean, tag up, LD the BHA, stack down, install the night cap and test to secure the well for the night. 10/31/2020 - Saturday No operations to report. 11/3/2020 - Tuesday 11/1/2020 - Sunday No operations to report. 11/2/2020 - Monday 10/30/2020 - Friday CTU #6 1.75" CT .156" wall. MIRU CTU. Test BOPE 300psi low/ 4,000psi high. Secure well for the night. 10/28/2020 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary No operations to report. 10/29/2020 - Thursday No operations to report. Samuel Gebert Hilcorp Alaska, LLC GeoTech Assistant 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: sam.gebert@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: Date: DATE: 10/16/2020 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU M-11 (PTD 219-010) COIL FLAG 09/04/2020 Please include current contact information if different from above. PTD: 2190100 E-Set:34110 Received by the AOGCC 10/16/2020 Abby Bell 10/20/2020 Samuel Gebert Hilcorp Alaska, LLC GeoTech Assistant 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: sam.gebert@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: Date: DATE: 10/01/2020 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU M-11 (219-010) Injection Profile 07/04/2020 Please include current contact information if different from above. Received by the AOGCC 10/02/2020 PTD: 2190100 E-Set: 34029 Abby Bell 10/05/2020 Samuel Gebert Hilcorp Alaska, LLC GeoTech Assistant 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: sam.gebert@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: Date: DATE: 10/01/2020 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU M-11 (219-010) Injection Profile 06/13/2020 Please include current contact information if different from above. PTD: 2190100 E-Set: 34028 Received by the AOGCC 10/02/2020 Abby Bell 10/05/2020 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: Conformance Treatment 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): 16,070'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:Abhijeet.Tambe@hilcorp.com Contact Phone: 777-8485 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 Milne Point Unit M-11 C.O. 477.05 8/26/2020 ZXP LTP And N/A 5,233 MD / 3,928 TVD and N/A Authorized Title: 17.I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Signature: 9/2/2020 3-1/2" Perforation Depth MD (ft): See Schematic See Schematic 114' 20" 9-5/8" 4-1/2" 5,393' 10,822' Perforation Depth TVD (ft): 5,750psi 9,020psi 3,941' 4,041' 5,393' 16,055' N/A Milne Point Field / Schrader Bluff Oil Pool 114' 114' 9.2# / L-80 / EUE 8rd TVD Burst 5,252' MD N/A Length Size 4,041' 16,050' 4,015' 1,308 PRESENT WELL CONDITION SUMMARY STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL025514, ADL388235 & ADL025515 219-010 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 50-029-23621-00-00 Hilcorp Alaska LLC Tubing Grade: Tubing MD (ft): Abhijeet Tambe COMMISSION USE ONLY Authorized Name: Tubing Size: ory Statu Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. Chad A Helgeson 2020.08.27 14:31:54 -08'00' By Samantha Carlisle at 9:52 pm, Aug 27, 2020 320-361 10-404 03SEP2020 03SEP2020 Mel Rixse SFD 8/28/2020 DSR-8/31/2020Comm. 9/3/2020 dts 9/3/2020 JLC 9/3/2020 RBDMS HEW 9/8/2020 CTU Conformance Treatment Well: MPU M-11 Date: 08/25/2020 Well Name:MPU M-11 API Number:50-029-23621-00 Current Status:Shut in –MBE Pad:M-Pad Estimated Start Date:09/2/2020 Rig:CTU Reg. Approval Req’d?Yes Date Reg. Approval Rec’vd:N/A Regulatory Contact:Tom Fouts Permit to Drill Number:219-010 First Call Engineer:Abhijeet Tambe (907) 777-8485 (O) (907) 331-9184 (M) Second Call Engineer:David Haakinson (907) 777-8343 (O) (307) 660-4999 (M) AFE Number: WellEZ Entry Required?Yes Current Bottom Hole Pressure: 1,700 psi @ 3,920’ TVD Downhole Gauge MPSP:1,308 psi @ 3,920’ TVD (0.1psi/ft gas gradient) Max Deviation:95° @ 8,303’ MD Max Dogleg:5.7°/100ft @ 4,295’ MD Min ID:2.75” ID @ 4,889’ MD XN Nipple Brief Well Summary: M-11 is a Schrader OA injector supporting M-10 and M-12 producers. The injector experienced an MBE to M-10 on 06/08/20, confirmed with a red dye test at five hours lag time. In late June 2020, an unsuccessful e-line tractor IPROF was attempted to locate the MBE. After observing an overpull at 5,480’MD, it was decided to not run the tractor through the restriction. Subsequently, a special high expansion shifting tool was run in an attempt to shift the Tendeka sleeves closed and find the MBE. Even though this tool seemed successful in closing (and opening) the sleeves, the results were inconclusive because of the pressure response observed in M-10. In a further attempt identify the MBE, a memory IPROF was successfully run on coiled tubing. The IPROF clearly indicates that ICDs #4 and #5 at 8,585’ MD’ and 9,150’ MD are taking most of flow along with the two ICDs (#14 and #15) at the toe (CT lockup at 14,873’ MD). Here is the summary of operations: 1) 6/7/2020: MBE occurs between M-11 and M-10 2) 6/8/2020: Red dye test performed. Positive with 5 hour timeline, indicative of MBE in upper half of laterals. 3) 6/13/2020: Tractored IPROF attempted. Tagged and pulled heavy at 5,480’ MD. 4) 6/24/2020: CT unit returns. CT FCO completed to ensure restriction removed. 5) 6/27/2020: CT High expansion shifting tool attempts sleeve closure/openings. No good on results as described above. 6) 7/5/2020: CT Memory IPROF run. Objective: 1) Confirm MBE via toe by injecting from ~14,800’ (through ICD #14 & #15). 2) Pump Conformance Treatment to isolate conductivity (MBE) between M-11i and M-10 through ICD #4. Risks: x Exceeding fracture pressure o The proposed fluid density of the H2Zero fluid is ~8.5 ppg (0.442 psi/ft) o Assuming a 0.64 psi/ft fracture gradient, do not exceed 800 psig surface injection pressure before accounting for frictional pressure. CTU Conformance Treatment Well: MPU M-11 Date: 08/25/2020 x Early Setup of Crosslinked Gel Causing stuck coiled tubing. o The use of a treatment packer should reduce risk of gel setup in coiled tubing annular space. o If the treatment packer becomes stuck, pump a ball to disconnect and leave downhole. x Early Release of Treatment Packers o It is important to maintain consistent temperatures throughout the job (source water, H2Zero gel) to avoid early release of the treatment packers. x Cross-Link Gel Screen-out o The goal is to leave plenty of treating pressure room to work with in the event we encounter a screenout. Note that the pumping viscosity is estimated to be 40 cP, so this is not anticipated. x Cross-linked Polymer Production o Producer M-10 must be shut in at the time the H2Zero conformance gel is pumped. o After the completion of the conformance job, M-10 should be brought online to tanks. Rig up three 400-bbl tanks for M-10 production If polymer or emulsion is seen, divert M-10 to tanks and attempt to keep the well online as long as possible to keep wellbore clean. Procedure: CTU & Pumping Unit: 1. Verify M-11 has remained shut-in. 2.Shut in M-10 Producer. Freeze Protect. 3. Rig up two 400 bbl uprights for source water, a trip tank for ~50 bbls of diesel, and a vac truck for ~20 bbls of KCl for mixing H2Zero product. 4. MIRU SLB CTU unit with 2” coiled tubing. 5. If BOPE test has not been completed in last 7 days, test BOPE to 250 psig low / 3,500 psig high. 6. RIH with 2” CT with CTC, DBCV, inflate valve, carrier and memory GR/CCL for tie-in and Baker retrievable packer w/ ball on seat. 7. RIH to ~2,000’ MD. Displace well freeze protect to tanks. 8. RIH to below ICD#4 to 8,605’ MD. 9. PU to 8,580’ MD at 40 FPM. Flag pipe. (correlation log run) 10. RIH to ~14,800’ MD (in July CT lock up occurred at 14,873’). Go as deep as possible or below 14,764’. CTU Conformance Treatment Well: MPU M-11 Date: 08/25/2020 11. Drop a ball to set the packer at ~14,800’. Confirm packer is set. 12. Confirm pumping crew is ready to pump. Add 15 bbl red dye to source water. 13.Note: Objective is to identify if MBE exists through ICD#14 & #15. Begin injecting source water down CT. a. Based on previous diagnostic run if MBE conductivity exists through ICD# 14; the red dye should show up at M-10 after pumping ~390 bbls of source water. Take samples to check for red dye. b. Document injection pressures and injection rates. If pressure climbs, DNE 800 psi. c. Monitor offset producer M-10 for any changes in bottom-hole pressure. d. Contact OE with results. 14. If MBE is confirmed via ICD #14 & #15, review with engineer to determine isolation plan. 15. POOH to surface for BHA Change. 16. RU Halliburton mixing and pumping equipment for H2Zero. 17. Establish site control and a separate radio channel for crews so that proper and clear communication will exist throughout the job. 18. Review GR/CCL data for tie in. Plan to set the lower treatment packer (mid-element) at 5’ below #4 ICD connection. 19. MU treatment BHA with 2” CT, CTC, and Baker Hughes Treatment BHA. Pup 4-½” 13.5#, 625 Wedge L-80 Box 3.850 4.500 3.53 7,311.04 8,743.96 8,747.49 Tendeka Water Swell Packer 3.850 8.250 10.89 7,321.93 8,733.07 8,743.96 8750 Proposed Pup 4-½” 13.5#, 625 Wedge L-80 Box 3.850 4.500 5.02 7,326.95 8,728.05 8,733.07 194 170 4-½” 13.5#, 625 Wedge L-80 Liner with 7.5'' OD Centralizer 3.850 4.500 39.96 7,366.91 8,688.09 8,728.05 195 171 4-½” 13.5#, 625 Wedge L-80 Liner with 7.5'' OD Centralizer 3.850 4.500 39.64 7,406.55 8,648.45 8,688.09 196 172 4-½” 13.5#, 625 Wedge L-80 Liner with 7.5'' OD Centralizer 3.850 4.500 39.95 7,446.50 8,608.50 8,648.45 Pup 4-½” 13.5#, 625 Wedge L-80 Pin 3.850 4.500 8.16 7,454.66 8,600.34 8,608.50 Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 3.850 5.950 15.13 7,469.79 8,585.21 8,600.34 8610 Proposed Pup 4-½” 13.5#, 625 Wedge L-80 Box 3.850 4.500 5.84 7,475.63 8,579.37 8,585.21 198 173 4-½” 13.5#, 625 Wedge L-80 Liner with 7.5'' OD Centralizer 3.850 4.500 39.65 7,515.28 8,539.72 8,579.37 199 174 4-½” 13.5#, 625 Wedge L-80 Liner with 7.5'' OD Centralizer 3.850 4.500 40.17 7,555.45 8,499.55 8,539.72 200 175 4-½” 13.5#, 625 Wedge L-80 Liner with 7.5'' OD Centralizer 3.850 4.500 39.97 7,595.42 8,459.58 8,499.55 201 176 4-½” 13.5#, 625 Wedge L-80 Liner with 7.5'' OD Centralizer 3.850 4.500 39.65 7,635.07 8,419.93 8,459.58 202 177 4-½” 13.5#, 625 Wedge L-80 Liner with 7.5'' OD Centralizer 3.850 4.500 39.98 7,675.05 8,379.95 8,419.93 Pup 4-½” 13.5#, 625 Wedge L-80 Box 3.850 4.500 3.70 7,678.75 8,376.25 8,379.95 Tendeka Water Swell Packer 3.850 8.250 10.91 7,689.66 8,365.34 8,376.25 8370 Proposed Pup 4-½” 13.5#, 625 Wedge L-80 Box 3.850 4.500 4.98 7,694.64 8,360.36 8,365.34 Y197 Z203 W193 Set in this area CTU Conformance Treatment Well: MPU M-11 Date: 08/25/2020 20. RIH to 8,600’ MD. POOH to tie into the flag pipe, GR/CCL tie in, and correction. 21. Confirm with Pumping crew that they are ready to mix fluids for pumping. 22. Pump a ball to set lowermost treatment packer. 23. Slack off weight slightly to confirm lower packer is set. 24. Continue to pressure up in 500 psig stages until burst disc pops at ~2,500 psig. The treatment packers should be set. 25. Begin injecting source water down CT for baseline injectivity. a. Do not exceed frac gradient (0.64). Document source water injection for 30 minutes. 26. Contact engineering with injectivity results. This testing is meant to confirm that the MBE has been isolated for pumping the treatment. a. If injection rate is less than 0.5 BPM at 800 psig, consider other pumping options for treatment. 27. Mix 8.5 ppg cross-linked H2Zero product. Note that we have approximately 4 hours to place product prior to setup. a. DNE frac gradient throughout the treatment.DNE 0.5 BPM treatment rate. b. Treatment Volumes: i. Source (Fresh) Water Spacer ii. 30 bbls of 8.5 ppg H2Zero mixed with KCl c.Volume Assumptions: i. Coiled Tubing (2”CT, 16,215 ft): ~45 bbls ii. Hole Volumes: ICD #4 – 8,585’ MD ICD #5 – 9,150’ MD 4-1/2” x 8-1/4” annulus capacity factor – 0.0464 bpf: Volume between ICDs: (9,150’-8,585’) x 0.0464 bpf =26.2 bbl 28. Place all volume of Crosslinked Gel product into ICD. a. If the treatment screens out early, PU to release packers and dilute H2Zero product by circulating water. Keep pipe moving and circulate a minimum of 5 bottoms up of KCl to dilute product. 29. Displace with 1 bbl of source water into ICD to clear wellbore. a. Do not inject into the well further to prevent over-displacement of H2Zero. 30. At this time, attempt to reduce fluid injection into the well as much as possible; take all returns to surface. 31. PU 5,500 lb-force to release packers. Allow elastomers to relax prior to pulling up-hole. 32. POOH to 2,500’ MD. 33. Pump Diesel freeze protect and 1 CT line volume to freeze protect the CT and well. 34. RDMO CTU and Mixing Unit. 35. Allow M-11 H2Zero product to setup for two-weeks prior to returning the well to injection or restarting M-10 production. Attachments: 1. As-built Schematic 2. H2Zero SDS _____________________________________________________________________________________ Revised By: TDF 7/27/2020 SCHEMATIC Milne Point Unit Well: MPU M-11 PTD: 219-010 API: 50-029-23621-00-00 Depth MD Depth TVD ICD/Swell Packer Detail Depth MD Depth TVD ICD/Swell Packer Detail 5,422’ 3,941’4.5” x 8.25” Tendeka Water Swell Packer 10,661’ 4,002’4.5” x 8.25” Tendeka Water Swell Packer 5,799’ 3,947’4.5” Tendeka Sliding Sleeve w/ Screen and ICDs 10,998’ 4,002’4.5” Tendeka Sliding Sleeve w/ Screen and ICDs 5,986’ 3,951’4.5” x 8.25” Tendeka Water Swell Packer 11,305’ 3,998’4.5” x 8.25” Tendeka Water Swell Packer 6,322’ 3,957’4.5” Tendeka Sliding Sleeve w/ Screen and ICDs 11,762’ 3,985’4.5” Tendeka Sliding Sleeve w/ Screen and ICDs 6,627’ 3,956’4.5” x 8.25” Tendeka Water Swell Packer 12,272’ 3,981’4.5” x 8.25” Tendeka Water Swell Packer 6,806’ 3,990’4.5” Tendeka Sliding Sleeve w/ Screen and ICDs 12,616’ 3,999’4.5” Tendeka Sliding Sleeve w/ Screen and ICDs 7,033’ 4,005’4.5” x 8.25” Tendeka Water Swell Packer 12,887’ 4,013’4.5” x 8.25” Tendeka Water Swell Packer 8,365’ 4,016’4.5” x 8.25” Tendeka Water Swell Packer 13,590’ 4,035’4.5” Tendeka Sliding Sleeve w/ Screen and ICDs 8,585’ 4,000’4.5” Tendeka Sliding Sleeve w/ Screen and ICDs 13,860’ 4,037’4.5” x 8.25” Tendeka Water Swell Packer 8,733’ 3,991’4.5” x 8.25” Tendeka Water Swell Packer 14,197’ 4,040’4.5” Tendeka Sliding Sleeve w/ Screen and ICDs 9,150’ 3,982’4.5” Tendeka Sliding Sleeve w/ Screen and ICDs 14,465’ 4,026’4.5” x 8.25” Tendeka Water Swell Packer 9,496’ 3,983’4.5” x 8.25” Tendeka Water Swell Packer 14,764’ 4,012’4.5” Tendeka Sliding Sleeve w/ Screen and ICDs 9,875’ 3,985’4.5” Tendeka Sliding Sleeve w/ Screen and ICDs 14,995’ 4,007’4.5” x 8.25” Tendeka Water Swell Packer 10,059’ 3,995’4.5” x 8.25” Tendeka Water Swell Packer 15,298’ 4,012’4.5” Tendeka Sliding Sleeve w/ Screen and ICDs 10,394’ 4,002’4.5” Tendeka Sliding Sleeve w/ Screen and ICDs 15,487’ 4,016’4.5” x 8.25” Tendeka Water Swell Packer 15,869’ 4,032’4.5” Tendeka Sliding Sleeve w/ Screen and ICDs TD =16,070’(MD) / TD =4,015’(TVD) 20” Orig. KB Elev.: 59.3’/ GL Elev.: 25.0’ RKB – THF: 31.25’ (Doyon 14) 3-1/2” 2 9-5/8” 1 4/5 7 See ICD & Swell Packer Detail PBTD =16,050’ (MD) / PBTD =4,015’(TVD) 9-5/8” ‘ES’ Cementer @ 2,322’ MD 4-1/2” 6 3 CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF 20"x34” Conductor (Insulated) 215.5 / X-42 / Weld N/A Surface 114’ N/A 9-5/8" Surface 40 / L-80 / TXP 8.679” Surface 5,393’ 0.0758 4-1/2” Liner 13.5 / L-80 / Hyd 625 3.795” 5,233’ 16,055’ 0.0149 TUBING DETAIL 3-1/2" Tubing 9.3 / L-80 / EUE 8RD 2.867” Surf 5,252’ 0.0870 JEWELRY DETAIL No Top MD Item ID Upper Completion 1 2,352’ 3.5” X Nipple (2.813” Packing Bore) 2.813” 2 4,889’ 3.5” XN Nipple (2.813” Packing Bore; 2.75” No-Go) 2.750” 3 5,158’ 3.5” Gauge Mandrel SGM-XPQG w/ ¼” Wire 2.896” 4 5,242’ 8.26” No Go Locater w/ 7.375” Seal Assembly 2.992” 5 5,243’ 7.375” Tieback above the SLZXP Liner Top Packer (Btm @ 5,252’)2.992” Lower Completion 6 5,233’ ZXP Liner Top Packer - 7 16,050’ WIV (Ball on Seat/ Closed) - OPEN HOLE / CEMENT DETAIL 42" 50 bbls (10 Yards Pilecrete dumped down backside) 12-1/4"Stg 1 – 138 bbl (330 sx) Lead 12.0 ppg / 82 bbl (400 sx) Tail 15.8 ppg Stg 2 – 315 bbl (410 sx) Lead 10.7 ppg / 55.8 bbl (270 sx) Tail 15.8 ppg 8-1/2” Cementless Injection Liner in 8-1/2” hole WELL INCLINATION DETAIL KOP @ 500’ Hole Angle @ XN = 70° @ 4,889’ MD Hole Angle @ Liner Top = 83° @ 5,233’ MD Max Hole Angle = 95° @ 8,303’ MD TREE & WELLHEAD Tree Cameron 3 1/8" 5M w/ 4-1/16” 5M Cameron Wing Wellhead Cameron 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs GENERAL WELL INFO API#: 50-029-23621-00-00 Completed by Doyon 14: 3/31/2019 SAFETY DATA SHEET Product Trade Name:H2ZERO Gelant Revision Date:25-Aug-2017 Revision Number:10 1. Identification 1.1. Product Identifier Product Trade Name:H2ZERO Gelant Synonyms None Chemical Family:Blend Internal ID Code HM004101 1.2 Recommended use and restrictions on use Application:System Uses advised against No information available 1.3 Manufacturer's Name and Contact Details Manufacturer/Supplier Halliburton Energy Services, Inc. P.O. Box 1431 Duncan, Oklahoma 73536-0431 Telephone: 1-281-871-6107 Halliburton Energy Services, Inc. 645 - 7th Ave SW Suite 1800 Calgary, AB T2P 4G8 Canada Prepared By Chemical Stewardship Telephone: 1-281-871-6107 e-mail: fdunexchem@halliburton.com 1.4. Emergency telephone number: Emergency Telephone Number 1-866-519-4752 or 1-760-476-3962 Global Incident Response Access Code: 334305 Contract Number: 14012 2. Hazards Identification 2.1 Classification in accordance with paragraph (d) of §1910.1200 As adopted by the competent authority, this product does not require an SDS or hazard warning label. Not classified 2.2. Label Elements Hazard Pictograms Signal Word:Not Classified Hazard Statements Not Hazardous _____________________________________________________________________________________________ Page 1 / 8 _____________________________________________________________________________________________ H2ZERO Gelant Revision Date:25-Aug-2017 Precautionary Statements Prevention None Response None Storage None Disposal None 2.3 Hazards not otherwise classified None known 3. Composition/information on Ingredients Substances CAS Number PERCENT (w/w) GHS Classification - US Contains no hazardous substances in concentrations above cut-off values according to the competent authority NA 60 - 100% Not classified The exact percentage (concentration) of the composition has been withheld as proprietary. 4. First Aid Measures 4.1. Description of first aid measures Inhalation If inhaled, remove from area to fresh air. Get medical attention if respiratory irritation develops or if breathing becomes difficult. Eyes In case of contact, immediately flush eyes with plenty of water for at least 15 minutes and get medical attention if irritation persists. Skin Wash with soap and water. Get medical attention if irritation persists. Ingestion Under normal conditions, first aid procedures are not required. 4.2 Most important symptoms/effects, acute and delayed No significant hazards expected. 4.3. Indication of any immediate medical attention and special treatment needed Notes to Physician Treat symptomatically. 5. Fire-fighting measures 5.1. Extinguishing media Suitable Extinguishing Media Water fog, carbon dioxide, foam, dry chemical. Extinguishing media which must not be used for safety reasons None known. 5.2 Specific hazards arising from the substance or mixture Special exposure hazards in a fire Decomposition in fire may produce harmful gases. 5.3 Special protective equipment and precautions for fire-fighters Special protective equipment for firefighters Full protective clothing and approved self-contained breathing apparatus required for fire fighting personnel. 6. Accidental release measures _____________________________________________________________________________________________ Page 2 / 8 _____________________________________________________________________________________________ H2ZERO Gelant Revision Date:25-Aug-2017 6.1. Personal precautions, protective equipment and emergency procedures Use appropriate protective equipment. See Section 8 for additional information 6.2. Environmental precautions None known. 6.3. Methods and material for containment and cleaning up Isolate spill and stop leak where safe. Contain spill with sand or other inert materials. Scoop up and remove. 7. Handling and storage 7.1. Precautions for safe handling Handling Precautions Avoid contact with eyes, skin, or clothing. Hygiene Measures Handle in accordance with good industrial hygiene and safety practice. 7.2. Conditions for safe storage, including any incompatibilities Storage Information Store away from oxidizers. Store in a cool, dry location. Store at temperature above 32 F (0 C). Do not freeze. 8. Exposure Controls/Personal Protection 8.1 Occupational Exposure Limits Substances CAS Number OSHA PEL-TWA ACGIH TLV-TWA Contains no hazardous substances in concentrations above cut-off values according to the competent authority NA Not applicable Not applicable 8.2 Appropriate engineering controls Engineering Controls None known. 8.3 Individual protection measures, such as personal protective equipment Personal Protective Equipment If engineering controls and work practices cannot prevent excessive exposures, the selection and proper use of personal protective equipment should be determined by an industrial hygienist or other qualified professional based on the specific application of this product. Respiratory Protection Not normally needed. But if significant exposures are possible then the following respirator is recommended: Dust/mist respirator. (N95, P2/P3) Hand Protection Normal work gloves. Skin Protection Normal work coveralls. Eye Protection Wear safety glasses or goggles to protect against exposure. Other Precautions None known. 9. Physical and Chemical Properties 9.1. Information on basic physical and chemical properties Property Values Physical State:Liquid Color Yellowish Odor:Mild amine Odor Threshold: No information available _____________________________________________________________________________________________ Page 3 / 8 _____________________________________________________________________________________________ H2ZERO Gelant Revision Date:25-Aug-2017 Remarks/ - Method pH:10.6 Freezing Point / Range -15°C/5°F Melting Point / Range No data available °C Boiling Point / Range 100 °C / 212 °F Flash Point >93/Opencup Flammability (solid, gas)No data available Upper flammability limit No data available Lower flammability limit No data available Evaporation rate No data available Vapor Pressure No data available Vapor Density No data available Specific Gravity 1.02 Water Solubility Soluble in water Solubility in other solvents No data available Partition coefficient: n-octanol/water No data available Autoignition Temperature No data available Decomposition Temperature No data available Viscosity No data available Explosive Properties No information available Oxidizing Properties No information available 9.2. Other information VOC Content (%)No data available 10. Stability and Reactivity 10.1. Reactivity Not expected to be reactive. 10.2. Chemical stability Stable 10.3. Possibility of hazardous reactions Will Not Occur 10.4. Conditions to avoid None anticipated 10.5. Incompatible materials Strong oxidizers. 10.6. Hazardous decomposition products Oxides of nitrogen. Carbon monoxide and carbon dioxide. 11. Toxicological Information 11.1 Information on likely routes of exposure Principle Route of Exposure Eye or skin contact, inhalation. 11.2 Symptoms related to the physical, chemical and toxicological characteristics Acute Toxicity Inhalation May cause mild respiratory irritation. Eye Contact May cause mechanical irritation to eye. Skin Contact None known. Ingestion None known. _____________________________________________________________________________________________ Page 4 / 8 _____________________________________________________________________________________________ H2ZERO Gelant Revision Date:25-Aug-2017 Chronic Effects/Carcinogenicity No data available to indicate product or components present at greater than 0.1% are chronic health hazards. 11.3 Toxicity data Toxicology data for the components Substances CAS Number LD50 Oral LD50 Dermal LC50 Inhalation Contains no hazardous substances in concentrations above cut-off values according to the competent authority NA No data available No data available No data available 12. Ecological Information 12.1. Toxicity Substance Ecotoxicity Data Substances CAS Number Toxicity to Algae Toxicity to Fish Toxicity to Microorganisms Toxicity to Invertebrates Contains no hazardous substances in concentrations above cut-off values according to the competent authority NA No information available No information available No information available No information available 12.2. Persistence and degradability Substances CAS Number Persistence and Degradability Contains no hazardous substances in concentrations above cut-off values according to the competent authority NA No information available 12.3. Bioaccumulative potential Substances CAS Number Log Pow Contains no hazardous substances in concentrations above cut-off values according to the competent authority NA No information available 12.4. Mobility in soil Substances CAS Number Mobility Contains no hazardous substances in concentrations above cut-off values according to the competent authority NA No information available 12.5 Other adverse effects _____________________________________________________________________________________________ Page 5 / 8 No information available _____________________________________________________________________________________________ H2ZERO Gelant Revision Date:25-Aug-2017 13. Disposal Considerations 13.1. Waste treatment methods Disposal methods Disposal should be made in accordance with federal, state, and local regulations. Contaminated Packaging Follow all applicable national or local regulations. 14. Transport Information US DOT UN Number Not restricted UN proper shipping name:Not restricted Transport Hazard Class(es): Not applicable Packing Group:Not applicable Environmental Hazards:Not applicable Canadian TDG UN Number Not restricted UN proper shipping name:Not restricted Transport Hazard Class(es):Not applicable Packing Group:Not applicable Environmental Hazards:Not applicable IMDG/IMO UN Number Not restricted UN proper shipping name:Not restricted Transport Hazard Class(es):Not applicable Packing Group:Not applicable Environmental Hazards:Not applicable IATA/ICAO UN Number Not restricted UN proper shipping name: Not restricted Transport Hazard Class(es):Not applicable Packing Group:Not applicable Environmental Hazards:Not applicable Transport in bulk according to Annex II of MARPOL 73/78 and the IBC Code Not applicable Special Precautions for User None 15. Regulatory Information US Regulations US TSCA Inventory All components listed on inventory or are exempt. TSCA Significant New Use Rules - S5A2 Substances CAS Number TSCA Significant New Use Rules - S5A2 Contains no hazardous substances in concentrations above cut-off values according to the competent authority NA Not applicable EPA SARA Title III Extremely Hazardous Substances Substances CAS Number EPA SARA Title III Extremely Hazardous Substances Contains no hazardous substances in concentrations NA Not applicable _____________________________________________________________________________________________ Page 6 / 8 _____________________________________________________________________________________________ H2ZERO Gelant Revision Date:25-Aug-2017 above cut-off values according to the competent authority EPA SARA (311,312) Hazard Class None EPA SARA (313) Chemicals Substances CAS Number Toxic Release Inventory (TRI) - Group I Toxic Release Inventory (TRI) - Group II Contains no hazardous substances in concentrations above cut-off values according to the competent authority NA Not applicable Not applicable EPA CERCLA/Superfund Reportable Spill Quantity Substances CAS Number CERCLA RQ Contains no hazardous substances in concentrations above cut-off values according to the competent authority NA Not applicable EPA RCRA Hazardous Waste Classification If product becomes a waste, it does NOT meet the criteria of a hazardous waste as defined by the US EPA. California Proposition 65 Substances CAS Number California Proposition 65 Contains no hazardous substances in concentrations above cut-off values according to the competent authority NA Not applicable U.S. State Right-to-Know Regulations Substances CAS Number MA Right-to-Know Law NJ Right-to-Know Law PA Right-to-Know Law Contains no hazardous substances in concentrations above cut-off values according to the competent authority NA Not applicable Not applicable Not applicable NFPA Ratings:Health 0, Flammability 0, Reactivity 0 HMIS Ratings:Health 0, Flammability 0, Reactivity 0 Canadian Regulations Canadian Domestic Substances List (DSL) All components listed on inventory or are exempt. 16. Other information Preparation Information Prepared By Chemical Stewardship Telephone: 1-281-871-6107 e-mail: fdunexchem@halliburton.com Revision Date:25-Aug-2017 Reason for Revision SDS sections updated: 2 _____________________________________________________________________________________________ Page 7 / 8 Additional information For additional information on the use of this product, contact your local Halliburton representative. For questions about the Safety Data Sheet for this or other Halliburton products, contact Chemical Stewardship at 1-580-251-4335. _____________________________________________________________________________________________ H2ZERO Gelant Revision Date:25-Aug-2017 Key or legend to abbreviations and acronyms used in the safety data sheet EZ±ERG\ZHLJKW &$6±&KHPLFDO$EVWUDFWV6HUYLFH d - day (&±(IIHFWLYH&RQFHQWUDWLRQ (U&±(IIHFWLYH&RQFHQWUDWLRQJURZWKUDWH h - hour /&±/HWKDO&RQFHQWUDWLRQ /'±/HWKDO'RVH //±/HWKDO/RDGLQJ PJNJ±PLOOLJUDPNLORJUDP PJ/±PLOOLJUDPOLWHU mg/m3 - milligram/cubic meter mm - millimeter mmHg - millimeter mercury 1,26+±1DWLRQDO,QVWLWXWHIRU2FFXSDWLRQDO6DIHW\DQG+HDOWK 173±1DWLRQDO7R[LFRORJ\3URJUDP 2(/±2FFXSDWLRQDO([SRVXUH/LPLW 3(/±3HUPLVVLEOH([SRVXUH/LPLW SSP±SDUWVSHUPLOOLRQ 67(/±6KRUW7HUP([SRVXUH/LPLW 7:$±7LPH:HLJKWHG$YHUDJH 81±8QLWHG1DWLRQV w/w - weight/weight Key literature references and sources for data www.ChemADVISOR.com/ Disclaimer Statement This information is furnished without warranty, expressed or implied, as to accuracy or completeness. The information is obtained from various sources including the manufacturer and other third party sources. The information may not be valid under all conditions nor if this material is used in combination with other materials or in any process. Final determination of suitability of any material is the sole responsibility of the user. End of Safety Data Sheet _____________________________________________________________________________________________ Page 8 / 8 DATA SUBMITTAL COMPLIANCE REPORT 7/1/2019 Permit to Drill 2190100 Well Name/No. MILNE PT UNIT M-11 Operator Hilcorp Alaska LLC C MD 16070 TVD 4041 Completion Date 3/31/2019 Completion Status 1WINJ Current Status 1WINJ REQUIRED INFORMATION / / Mud Log Not/ Samples No ✓ DATA INFORMATION List of Logs Obtained: ROP / ABG / DGR / EWR / ADR 2"/5" MD....ABG / DGGR / EWR / ADR 2"/5" TVD Well Log Information: Logi Electr Data Digital Dataset Log Log Run Interval OHI Type Med/Frmt Number Name Scale Media No Start Stop CH ED C 30613 Digital Data 112 16070 ED C 30613 Digital Data ED C 30613 Digital Data ED C 30613 Digital Data ED C 30613 Digital Data ED C 30613 Digital Data ED C 30613 Digital Data ED C 30613 Digital Data ED C 30613 Digital Data ED C 30613 Digital Data ED C 30613 Digital Data ED C 30613 Digital Data ED C 30613 Digital Data ED C 30613 Digital Data ED C 30613 Digital Data ED C 30613 Digital Data ED C 30613 Digital Data ED C 30613 Digital Data 5384 16034 API No. 50-029-23621-00-00 UIC Yes Directional Survey Yes V (from Master Well Data/Logs) Received Comments 4/16/2019 Electronic Data Set, Filename: MPU M-11 DGR AOGCC Page 1 of 2 Monday, July 1, 2019 ABG EWR ADR.las 4/16/2019 Electronic Data Set, Filename: MPU M-11 ADR Quadrants All Curves.las 4/16/2019 Electronic File: MPU M-11 LWD Final MD.cgm 4/16/2019 Electronic File: MPU M-11 LWD Final TVD.cgm 4/16/2019 Electronic File: MPU M-11 Definitive Survey Report.pdf 4/16/2019 Electronic File: MPU M-11 DSR.txt 4/16/2019 Electronic File: MPU M-11 GIS.txt 4/16/2019 Electronic File: MPU M-11_Plan.pdf 4/16/2019 Electronic File: MPU M-11_VSec.pdf 4/16/2019 Electronic File: MPU M-11 LWD Final MD.emf 4/16/2019 Electronic File: MPU M-11 LWD Final TVD.emf 4/16/2019 Electronic File: MPU M-11 ADR Geosteering Image.dlis 4/16/2019 Electronic File: MPU M-11 ADR Geosteering Image.ver 4/16/2019 Electronic File: MPU M-11 LWD Final MD.pdf 4/16/2019 Electronic File: MPU M-11 LWD Final TVD.pdf 4/16/2019 Electronic File: MPU M-11 LWD Final MD.tif 4/16/2019 Electronic File: MPU M-11 LWD Final TVD.tif 4/16/2019 Electronic File: EMFView3_1.zip AOGCC Page 1 of 2 Monday, July 1, 2019 DATA SUBMITTAL COMPLIANCE REPORT 7/112019 Permit to Drill 2190100 Well Name/No. MILNE PT UNIT M-11 MD 16070 TVD 4041 Completion Date 3/31/2019 ED C 30613 Digital Data Log C 30613 Log Header Scans Well Cores/Samples Information: Name INFORMATION RECEIVED Completion Report d Production Test Information Y Geologic Markers/Tops fY COMPLIANCE HISTORY Completion Date: 3/31/2019 Release Date: 2/15/2019 Description Comments: Operator Hilcorp Alaska LLC API No. 50-029.23621.00-00 Completion Status 1WINJ Current Status 1WINJ UIC Yes 4/16/2019 Electronic File: Readme.txt 0 0 2190100 MILNE PT UNIT M-11 LOG HEADERS Sample Interval Set Start Stop Sent Received Number Comments Directional / Inclination Data 'UY Mud Logs, Image Files, Digital Data Y /� Core Chips Y/i%MA1 Mechanical Integrity Test Information Y / NA Composite Logs, Image, Data Files Core Photographs Y /e) J�JAJ Daily Operations Summary Q Cuttings Samples Y / Laboratory Analyses Y / NA Date Comments ILI Compliance Reviewed By: Y ' Date: I I I AO(i('L' Page 2 of 2 Monday, July 1. 2019 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION N=U= =U APR ? 3 ?ntD WELL COMPLETION OR RECOMPLETION REPORT ANO-LOIG_� 1 a. Well Status: oil E] Gas❑ $PLUG❑ Other ❑ Abandoned ❑ Suspended❑ 1b. Well Class: 20AAC 25.105 20AAC 25.110 Development ❑ Exploratory ❑ GINJ ❑ WINJ E] WAGE] WDSPL ❑ No. of Completions: 1 Service 2 Stratigraphic Test ❑ 2. Operator Name: 6. Date Comp., Susp., or 14. Permit to Drill Number/ Sundry: Hilcorp Alaska, LLC Abend.: 3/31/2019 219-010 ' 3. Address: 7. Date Spudded: 15. API Number: 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 March 7, 2019 50-029-23621-00-00 4a. Location of Well (Governmental Section): 8. Date TD Reached: 16. Well Name and Number: , Surface: 5037' FSL, 141' FEL, Sec 14, T13N, R9E, UM, AK March 20, 2019 MPU M-11 Top of Productive Interval: 9. Ref Elevations: KB: 59.3' 17. Field / Pool(s): Milne Point Field 457' FNL, 2120' FEL, Sec 13, T13N, R9E, UM, AK GL: 25' BF: 25' " Schrader Bluff Oil Pool ' Total Depth: 1036' FNL, 1104' FWL, Sec 20, T13N, R10E, UM, AK 10. Plug Back Depth MD/TVD: 16,050' MD / 4,041' TVD ' 18. Property Designation: ADL025514, ADL388235, ADL025515 4b. Location of Well (State Base Plane Coordinates, NAD 27): 11. Total Depth MD/TVD: r 19. DNR Approval Number: Surface: x- 534023 y- 6027889 Zone- 4 16,070' MD / 4,041' TVD LONS 16-004 TPI: x- 537324 y- 6027691 Zone- 4 12. SSSV Depth MDTFVD: 20. Thickness of Permafrost MD/TVD: Total Depth: x- 545796 y- 6021880 ' Zone- 4 N/A 2,370' MD / 2,090' TVD 5. Directional or Inclination Survey: Yes ✓ (attached) No ❑ 13. Water Depth, if Offshore: 21. Re-drill/Lateral Top Window MD/TVD: Submit electronic and printed information per 20 AAC 25.050 N/A (ft MSL) N/A 22. Logs Obtained: List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data and printed logs within 90 days of completion, suspension, or abandonment, whichever occurs first. Types of logs to be listed include, but are not limited to: mud log, spontaneous potential, gamma ray, caliper, resistivity, porosity, magnetic resonance, dipmeter, formation tester, temperature, cement evaluation, casing collar locator, jewelry, and perforation record. Acronyms may be used. Attach a separate page if necessary ROP/ABG/DGR/EWR/ADR 2"/5" MD ABG/DGR/EWR/ADR 275" TVD 23. CASING, LINER AND CEMENTING RECORD WT. PER CASING FT GRADE SETTING DEPTH MD SETTING DEPTH TVD HOLE SIZE AMOUNT CEMENTING RECORD PULLED TOP BOTTOM TOP BOTTOM 20" 215# X-52 Surface 114' Surface 114' 42" ±270 ft3 9-5/8" 40# L-80 Surface 5,393' Surface 3,941' 12-1/4" Stg 1 L - 330 sx / T - 400sx Stg 2 L - 410 sx / T - 270 sx 216 bbls 3-1/2" 9.2# L-80 Surface 5,252' Surface 3,930' Tieback Tieback Tubing 4-1/2" 13.5# L-80 5,233' 16,055' 3,928' 4,041' 8-1/2" Injection Liner w/ ICDs & Swell Packers 24. Open to production or injection? Yes Q No ❑ 25. TUBING RECORD If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation SIZE DEPTH SET (MD) PACKER SET (MD/TVD) Size and Number; Date Perfd): 3-1/2" 5,252' 5,233' MD / 3,928' TVD "Please see attached Schematic for ICD/Swell Packer Detail— Liner Top Packer Liner run on 3/25/19 26, ACID, FRACTURE, CEMENT SQUEEZE, ETC. COMPLETION Was hydraulic fracturing used during completion? Yes No Ltj DATE T�Zo(9 Per 20 AAC 25.283 (i)(2) attach electronic and printed information DEPTH INTERVAL (MD) JAMOUNT AND KIND OF MATERIAL USED VERIFIED 27. PRODUCTION TEST Date First Production: Method of Operation (Flowing, gas lift, etc.): N/A N/A Date of Test: Hours Tested: Production for Oil -Bbl: Gas -MCF: Water -Bbl: Choke Size: Gas -Oil Ratio: Test Period Flow Tubing Casing Press: I Calculated Oil -Bbl: Gas -MCF: Water -Bbl: Oil Gravity - API (corr): Press. 24 -Hour ate Form 10-407 Revised 5/2017 S �5 , �q CONTINUED ON PAGE 2 DMSA PR 24466t ORIGINIAL onl LDHI s/�d�zorf 1 /��`il°l�7 �.toWPR 4 28. CORE DATA Conventional Core(s): Yes ❑ No ❑Q Sidewall Cores: Yes ❑ No Q If Yes, list formations and intervals cored (MD/TVD, From[To), and summarize lithology and presence of ail, gas or water (submit separate pages with this form, if needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071. 29. GEOLOGIC MARKERS (List all formations and markers encountered): 30. FORMATION TESTS NAME MD TVD Well tested? Yes ❑ No ❑� If yes, list intervals and formations tested, briefly summarizing test results. Permafrost - Top Permafrost - Base 2,370' 2,090' Attach separate pages to this form, if needed, and submit detailed test Top of Productive Interval 5,799' SB OA 3,947' information, including reports, per 20 AAC 25.071. SV5 1,420' 1,344' SV1 2,158' 1,928' Ugnu LA3 3,836' 3,234' SB NA 4,649' 3,753' SB OA 5,269' 3,931' Formation at total depth: Schrader Bluff 31. List of Attachments: Wellbore Schematic, Drilling and Completion Reports, Definitive Directional Surveys, Csg and Cmt Report. Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, core analysis, paleontological report, production or well test results, per 20 AAC 25.070. 32. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Authorized Name: Monty Myers Contact Name: Cody Dinger Authorized Title: Drilling Manager Contact Email: cdincer(alhilcom.com AuthorizedContact Phone: 777-8389 L Signature: — i Date: Z 3• Z0I INSTRUCTIONS General: This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed. All laboratory analytical reports regarding samples or tests from a well must be submitted to the AOGCC, no matter when the analyses are conducted. Item 1 a: Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item 1b: Well Class - Service wells: Gas Injection, Water Injection, Water -Alternating -Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Item 4b: TPI (Top of Producing Interval). Item 9: The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 15: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Item 19: Report the Division of Oil & Gas / Division of Mining Land and Water: Plan of Operations (LO/Region YY -123), Land Use Permit (LAS 12345), and/or Easement (ADL 123456) number. Item 20: Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Bax 29. Item 22: Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data and printed logs within 90 days of completion, suspension, or abandonment, whichever occurs first. Item 23: Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. Item 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). Item 28: Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity, permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology. Item 30: Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Item 31: Pursuant to 20 AAC 25.070, attach to this forth: 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 orwell test results. Form 10407 Revised 5/2017 Submit ORIGINAL Only ff HileorP Alaska, LLC Orig. KB Elev.: 59.3/ GL Elev.: 25.0' TD=16,074 (MD) /TD = 4,015(TVD) P91D=16,050' (MD)/PBTD=4,015'(TVD) 1 Schematic Milne Point Unit Well: MPU M-11 PTD: 219-010 API: 50-029-23621-00-00 TREE & WELLHEAD Tree Cameron 31/8"SIM w/4 -1/16"5M Cameron Wing Wellhead li Cameron 11"5Kx sliplock bottom w/(2) 2-1/16"5K outs OPEN HOLE / CEMENT DETAIL 42" 50 bbls (30 Yards Pilecrete dumped down backside) 12-1/4" Stg 1-138 bbl (330 sx) Lead 12.0 ppg / 82 bbl (400 sx) Tail 15.8 ppg Top Stg 2 — 315 bbl (410 sx) Lead 10.7 ppg / 55.8 bbl (270 sx) Tail 15.8 ppg 8-1/2" 1 Cementless Injection Liner in 8-1/2" hole CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF 20"x34" Conductor (insulated) 215.5/X-42/Weld N/A Surface 114' N/A 9-5/8" Surface 40/L-80/TXP 8.679" Surface 5,393' 0.0758 4-1/2" Liner 13.5 / L-80 / Hyd 625 3.795" 5,233' 16,055' 0.0149 TUBING DETAIL 3-1/2" Tubing 9.3 / L-80/ EUE 8RD 1 2.867" Surf 1 5,252' 1 0.0870 WELL INCLINATION DETAIL KOP @ 500' Hole Angle @ XN = 70° @ 4,889' MD Hole Angle @ Liner Top = 83' @ 5,233' MD Max Hole Angle = 95" @ 8,303' MD JEWELRY DETAIL No Top MD Item ID Upper Completion 1 2,352' 3.5" X Nipple (2.813" Packing Bore) 2.813" 2 4,889' 3.5" XN Nipple (2.813" Packing Bore; 2.75" No -Go) 2.750" 2T:3.5" Gauge Mandrel SGM-XPQG w/W Wire 2.896" 4 5,242' 8.26" No Go Locater w/ 7.375" Seal Assembly 2.992' 5 5,243' 7.375" Tieback above the SLZXP Liner Top Packer (Btm@5,252') 2.992" Lower Completion 6 5,233' ZXP UnerTop Packer - 7 16,050' WIV(Ball on Seat/Closed) 3,998' Depth ND ICD/Swell Packer Detail Depth MD Depth TVD ICO/Swell Packer Detail 3,941' 4.5" x 8.25" Tendeka Water Swell Packer 10,661' 4,002' 4.5" x 8.25" Tendeka Water Swell Packer 3,947' 4.5" Tendeka Sliding Sleeve w/ Screen and 1CDs 10,998' 4,002' 4.5" Tendeka Sliding Sleeve w/ Screen and ICDs 3,951' 4.5" x 8.25" Tendeka Water Swell Packer 11,305' 3,998' 4.5" x 8.25"Tendeka Water Swell Packer 3,957' 45" Tendeka Sliding Sleeve w/ Screen and [CDs 11,762' 3,985' 4.5" Tendeka Sliding Sleeve w/ Screen and 1CDs 3,956' 4.5" x 8.25" Tendeka Water Swell Packer 12,272' 3,981' 45" x 8 25"Tendeka Water Swell Packer 3,990' 4.5" Tendeka Sliding Sleeve w/ Screen and 1CDs 12,616' 3,999' 4.5Tendeka Sliding Sleeve w/ Screen and ICDs 4,005' 4.5" x 8.25" Tendeka Water Swell Packer 12,887' 4,013' 4.5"x 8.25" Tendeka Water Swell Packer 4,016' 4.5" x 8.25" Tendeka Water Swell Packer 13,590' 4,035' 4.5" Tendeka Sliding Sleeve w/ Screen and 1CDs 4,000' 4.5" Tendeka Sliding Sleeve w/ Screen and ICDs 13,860' 4,037' 4.5" x 8.25" Tendeka Water Swell Packer 3,991' 4.5" x 8 25" Tendeka Water Swell Packer 14,197' 4,040' 4.5" Tendeka Sliding Sleeve w/ Screen and LCDs 3,982' 4.5" Tendeka Sliding Sleeve w/ Screen and ICDs 14,465' 4,026' 4.5" x 8.25" Tendeka Water Swell Packer 3,983' 4.5" x 8.25" Tendeka Water Swell Packer 14,764' 4,012' 4.5" Tendeka Sliding Sleeve w/ Screen and ICDs 3,985' 4.5" Tendeka Sliding Sleeve w/ Screen and ICDs 14,995' 4,007' 4.5" x 8.25"Tendeka Water Swell Packer 3,995' 4.5" x 8.25" Tendeka Water Swell Packer 15,298' 4,012' 4.5" Tendeka Sliding Sleeve w/ Screen and 1CDs 4,002' 4.5" Tendeka Sliding Sleeve w/ Screen and [CDs 15,487 4,016' 4.5" x 825" Tendeka Water Swell Packer 15,869' 4,032' 4.5"Tendeka Sliding Sleeve w/ Screen and LCDs GENERAL WELL INFO API#: 50-029-23621-00-00 Completed by Doyon 14: 3/31/2019 Revised By: UD 4/23/2019 Hilcorp Energy Company Composite Report Well Name: MP M-11 Field: Milne Point Counly/State: , Alaska i (LAT/LONG): ovation (RKB): API #: Spud Date: 3/7/2019 Job Name: 1814460D MPU M-11 Drilling Contractor Doyon 14 AFE #: AFE $: Activity Datej",',',: ;� :y bilial"ONNAN 3/6/2019 Please refer to M-12 completion report for more details.;RU steam, air and water to the rig floor. Orientate the diverter adapter. Begin to load, strap and tally (including serial numbers) 5" NC50 DP. Spot the rock washer and fuel tank. Spot third party units. Changeout the arctic dump pump. MU the IBOP assembly to the top drive.;NU the diverter pipe. Work on rig acceptance checklist.;Remove split bushing and install solid bushing. Torque up bolts on the surface diverter and install the riser. Changeout the 4" demco on mud pump #1 & #2. Place plywood over rig mat cracks in walkways around the rig.;Continue to NU the diverter pipe, process 5" DP and work on rig acceptance checklist.;Finish processing the 5" DP. Completed the rig acceptance checklist and accepted the rig at 02:00 hours.;PJSM. PU and MU stands of 5" NC50 DP (81 of 174 joints; 27 of 58 stands). 3/7/2019 Continue to MU & stand back 5" DP in derrick. Add another section of diverter pipe to clear edge of pad (diverter length = 513'). On start up of the gas detection system it failed calibration. Start to change the brain box on the gas detection system.;AOGCC Representative Jeff Jones on location to witness the diverter test. Function diverter: Knife valve opened in 13 seconds and the annular closed in 28 seconds. Test PVT. All Good.;Accumulator Test:Syslem pressure = 3000 psi. Pressure after closure = 1900 psi. 200 psi attained in 38 seconds. Full pressure attained in 161 seconds. Nitrogen Bottles - 6 at 2016 psi.;Jeff Jones waived witness of the gas detection system due to the brain box it being replaced. Gas detection was fixed, calibrated and tested at 15:00 hours (good test).;Continue to PU DP for a total of 58 stands. Stand back 6 stands of HWDP. Stand back NM FC.;Conduct pre spud meeting with all hands on location. PJSM for PU BHA. PU clean out assembly, Used Baker VM3 & 1.5 bent motor. MU stand of HWDP. Flood conductor with water, check for leak and no leaks. Tag at 111'.;PT the mud lines to 250 psi (good test). Attempt to PT lines to 3500 psi but at 2350 psi the 4" demco valve on MP #1 was Ieaking.;Pull the cap and found a leaking o -ring. Blow down the lines and replace the o -ring. PT the lines to 250/3500 psi (good lest);Drill out the conductor with water from 111' to 121'. Displace the well to 8.8 ppg spud mud. Continue to drill 12-1/4" surface hole from 121' to 221' (PU = 50K, SO= 50K & ROT = 50K) at 350 GPM = 220 psi, 40 PRM = OK ft-Ibs torque and WOB = 9-15K.;BROOH to the conductor at 350 GPM = 330 psi and 40 RPM. RIH with no pumps or rotary to tag at 221'. Pump out of hole from 221'to 109. Circulate the conductor clean. Stand back a stand of 5" HWDP.;Lay down Baker VM3 bit. MU BHA #1: 12-1/4" Kymera bit, 1.5' bent motor, LWD and MWD. Carry scribe for offset.;Upload MWD tools.;Continue to MU BHA #i: stand of NM flex collar, crossover and stand of 5" HWDP. RIH to tag at 221'.;Drill 12-1/4" surface hole from 221' to 653' (653' TVD), 432' with AROP of 96 FPH. 400 GPM = 1190 psi, 40 RPM= 1 K ft -lbs torque, WOB = 15-25K, MW = 9.1 ppg, Vis = 193, ECD = 9.6 ppg, Max gas= 19 units PU = 74K, SO= 76K, ROT= 70K. Back ream 31' prior to connection.;Last survey at 598.45' MD, 598.29' TVD, 3.77" Inc, 27.55° Az. Distance to Well Plan #8 = 5.8' (5.6' low and 1.6' right).;Hauled 475 bible H2O from L -Pad lake for total = 475 bbls Hauled 0 bbls heated H2O from G&I = 0 Hauled 114 bbis cuttings/liquids to MPU G&I for total = 114 bbis 3/8/2019 Drill 12-1/4" surface hole from 65T to 1374'(130T TVD), 721' whh AROP of 120.2 FPH. 488 GPM = 1750 psi, 80 RPM = 3-5K ft -lbs torque, WOB = 18K, MW = 9.2+ ppg, Vis = 178, ECD = 10.0 ppg, Max gas = 17 units PU = 90K, SO = 785K, ROT = 86K. Back ream 31' prior to connection.;Drill 12-1/4" surface hole from 1374' to 2195' (1957' TVD), 821' with AROP of 136.8 FPH. 500 GPM = 1630 psi, 80 RPM = 3K ft -lbs torque, WOB = 7K, MW = 9.2 ppg, Vis = 154, ECD = 10.1 ppg, Max gas = 19 units PU = 112K, SO = 95K, ROT = 103K. Back ream 31' prior to connection.;Ddll 12-1/4" surface hole from 2195' to 3021' (2598' TVD), 826' with AROP of 137.7 FPH. 530 GPM = 1820 psi, 80 RPM = 6K ft -lbs torque, WOB = 5-15K, MW = 9.2 ppg, Vis = 161, ECD = 10.4 ppg, Max gas = 104 units PU = 135K, SO = 98K, ROT = 112K. Back ream 31' prior to connection.;Base of permafrost at 2110' (1890' TVD). Pumped 20 bbis hi -vis sweep at 2550', back 300 strokes late with 20% increase in cuttings over the shakem.;Drill 12-1/4" surface hole from 3021'to 3778' (3192' TVD), 757' with AROP of 126.2 FPH. 559 GPM = 2230 psi, 80 RPM = 8K ft -lbs torque, WOB = 16K, MW = 9.2 ppg, Vis = 173, ECD = 10.3 ppg, Max gas = 33 units PU = 156K, SO = 110K, ROT = 125K. Back ream 45' prior to connection.;Last survey at 3724.7' MD, 3148.59' TVD, 38.81 ° Inc, 78.54° Az. Distance to Well Plan #8 = 6.92' (5.9' high and 3.4' left). Currently drilling in the Ugnu L sand.;Hauled 1375 this H2O from L -Pad lake for total = 1850 bbis Hauled 0 bbis heated H2O from G&I = 0 Hauled 1678 bbis cuftings/liquids to MPU G&I for total = 1792 bills 319Y2019 Drill 12-1/4" surface hole from 3778' to 4412' (3626' TVD), 634' with AROP of 105.6 FPH. 568 GPM = 1960 psi, 80 RPM = 8-10K ft-Ibs torque, WOB = 3-5K, MW = 9.2 ppg, Vis = 127, ECD = 10.0 ppg, Max gas= 146 units PU = 170K, SO= 115K, ROT= 155K. Back ream 45prior to connection.;Pumped 30 bills hi - vis sweep at 3873', back on time with 10% increase in cutting over the shakers.;Drill 12-1/4" surface hole from 4412' to 4815' (3816 TVD), 403' with AROP of 67.2 FPH. 570 GPM = 2090 psi, 80 RPM=10-14K ft -lbs torque, WOB = 19K, MW = 9.2 ppg, Vis = 98, ECD = 10.1 ppg, Max gas = 56 units PU = 170K, SO = 115K, ROT= 135K. Back ream 45' prior to connection.;Pumped 30 bbls hi -vis sweep at 47291, back on time with 20% increase in cutting over the shakers.;Ddll 12-1/4" surface hole from 4815' to 5245' (3930' TVD), 430' with AROP of 71.2 FPH. 570 GPM = 2250 psi, 80 RPM = 13-16K ft-Ibs torque, WOB = 15K, MW= 9.2 ppg, Vis = 122, ECD = 10.3 ppg, Max gas = 149 units PU = 165K, SO = 105K, ROT = 130K. Back ream 45' prior to connection.;Ddll 12-1/4" surface hole from 5245'to TD at 5403' (3941' TVD), 158' with AROP of 79 FPH. 567 GPM = 2180 psi, 80 RPM = 12K ft-Ibs torque, WOB = 21 K, M W = 9.3 ppg, Vis =104, ECD = 10.1 ppg, Max gas = 83 unitsPU = 165K, SO = 103K, ROT = 126K. (Includes 1 hour time change for daylight savings).;Pump tandem sweep (30 bible each) and circulate out at 497 GPM = 2050 psi, 60 RPM = 8K ft -lbs torque. Sweeps back on time with 10% increase in cutting over the shakers. Continue to circulate and condition the mud until clean (total of 1.75 bottoms up).;Run back to 5403' (TD). BROOH at 5 minutes per stand from 5403' to 5195' at 500 GPM = 2050 psi and 60 RPM= 8K ft-Ibs torque.;Last survey at 5337.33 MD, 3937.73' TVD, 85.92° Inc, 126.06° Az. Distance to Well Plan #8 = 17.5' (15.1' high and 8.9' left). TD in the Schrader Bluff OA -1 sand.;Hauled 1440 bills H2O from L -Pad lake for total= 3290 bbis Hauled 0 bills heated H2O from G&I = 0 Hauled 1217 bbis cuttings/liquids to MPU G&I for total = 3009 bbis 3/10/2019 BROOH from 5195to 2340'. Pull at 5-10 Min per stand. Slight tight spots & pressure increases at all slides. Pull slow and let clean up. MW 9.3.;Back ream slow and circ trim up letting it clean up before base of permafrost. Cleaned up good after btm up.;Monitor well. Static. Attempt to pull on elevators. Swabbing and pulling 20-40k Over. Pull 60' & unable to to back down on elevators. Kelley up and wash down at 250 GOM 20 RPM. Work back down. Bring pumps to rate at 450 GPM & back ream out at 60 rpm.;BROOH from 2250' to 1285'. 450 GPM, 60 RPM. Pull slow throuugh slide areas where TO increase and pressure increase. Cleans up good after slides areas. MW 9.3 vis 88.;Continue to BROOH from 1285' to 749, 450 GPM = 1100 psi, 60 RPM = 5K ft -lbs torque. Attempt to POOH on elevators but unable too. Continue to BROOH from 749' to 470'(3 stands of 5" HWDP).;Blow down the top drive. POOH on elevators from 470' to 185'.;Lay down 3 NM flex collars from 185'to 98'.;Download MWD data.;Stabilizer and bit balled in clay. Clean stabilizer and bit. Lay down remaining BHA components from 98'to surface: LWD, MWD, bi sleeve and Kymera bit. Bit grade: 2-2-BT-T-E-1-CT-TD.;Clean and clear the rig floor.;Mobilize casing running equipment to the rig floor. RU the Volant tool, bail extensions, 9-5/8" elevators and air slips. SimOps: Replace IBOP nitrogen assist cylinder. Losses= 2 BPH while circulating over the top.;PJSM. PU and MU the float shoe, 1 joint of 9-5/8" casing and float collar. Check the floats (good). Fill the casing and establish circulation. Drop the bypass baffle. PU and MU the baffle adapter. Baker Lok each connection.;RIH with shoe track on 9-518", 40#, L-80, UP casing from 161' to 1056' filling on the fly topping off every 5 joints and installing centralizers per tally (torque= 20960 ft-Ibs).;Hauled 1380 bbls H2O from L -Pad lake for total= 4670 blots Hauled 0 bbls heated H2O from G&I = 0 Hauled 1387 bbls cuftings/liquids to MPU G&I for total = 4396 bbls 3/11/2019 Continue to RIH with shoe track on 9-5/8", 40#, L-80, UP casing from 1056' to 3700' PU = 190K & SO = 115K) filling on the Fly topping off every 5 joints and installing centralizers per tally (torque = 20960 ft-Ibs).;CBU staging the pumps up to 6 BPM = 300 psi.;Continue to RIH with shoe track on 9-5/8", 40#, L-80, TXP casing from 370U to 5393' (PU = 240K & SO = 125K) filling on the fly topping off every 5 joints and installing centralizers per tally (torque = 20960 ft- Ibs).;Circulate and condition the mud staging the pumps up to 6 BPM = 380 psi, 5 RPM = 20K ft -lbs torque and reciprocating 30' ;PJS with rig crew, HES cementers, MI Swaco and Peak truck drivers. SimOps: Continue to circulate and condition the mud (circulate a total of 2 bottoms up). Offload pit S.;Blow down the top drive and RU the cement line. Blow air to the cementers. Continue to circulate and condition while emptying pit#2.;Flood the lines with 5 bbls of water. PT lines to 1000/4500 psi for 5 minutes each (good test). Line up, mix & pump 60 bbl clean spacer with red die & pol-e-flake in the first 10 bbls. Drop the bypass .� plug. Line up mix & pump 138 bbls 12 pion lead cement (330 sacks). Lead cement wet at 23:50.;Mix & pump 82 bbls 15.8 ppg tail cement (400 sacks). Tail , 5� cement wet at 00:38. Drop the closing plug. HES pumped 20 bbls fresh water. Line up to the rig and start displacement. Pumped 9 bbls, lost suction on pit 4 and ` switched to pit 3 causing a 28 bbls difference in strokes vs actual bbls pumped.;Pump displacement to plug bump at 4040 strokes (calculated 3763 strokes). Final lift pressure 800 psi. Bumped plugs, pressured up l0 1300 psi & hold for 5 minutes. Rotated 5 RPM = 20K ft -lbs torque and reciprocated 20' until the last 10 bbls of the last 10 bbls.;Bleea to 0 psi, checked floats and Floats held. Cement in place at 2:37 hours. Pressure up and open the ES cementer at 3090 psi. Establish circulate at 6 BPM ;Continue to circulate getting back 60 bbls of clean spacer and 39 bbls of cement. Circulate an additional 2 bottoms up at 6 BPM = 330 psi.;Flush the surface equipment with black water.;Hauled 250 bbls H2O from L -Pad lake for total = 4920 bbls g Hauled 0 tools heated H2O from G&I = 0 a ( (V i 8 Hauled 639 bbls cuttings/liquids to MPU G&I for total = 5035 bbls yam' 5 3/12/2019 Continue to flush surface equipment with black water.;Circulate and condition at 6 BPM = 280 psi while prepping for the 2nd sta a cera 2nd stage cement job.;Blow air to cement unit to ensure clear. Flood the lines with 5 bbls of water. PT lines to 1000/4000 psi for 5 minutes each (good test). Lineup, mix & pump 60 bbl clean spacer with red die & pol-e-flake in the first 10 bbls.;Mix & pump 10.7 ppg lead cement at 6 BPM = 550 si. At 315 blols 410 sks away got good cement to surface. Mix & pump 55.8 bbls (270 sks) 15.8 ppg tai cement at 3 PM = 300 psi. Drop ES cementer closing plug.;HES pumped 20 bbls fresh water. Swap to the rig for displacement. Pump to plug bump at 1535 strokes (calculated 1546 strokes). Final lift pressure = 650 psi. Pressure up to 1550 psi to close the ES cementer and hold for 3 minutes. CIP at 15:34 hours_216 bbls of cement return to surface. Break off the cement line & verified ES cementer was closed. Break out the Volant & PU 150K over (250K on weight indicator) for setting the casing slips. Fill the stack with blackwater, disconnect the knife valve& function the diverter bag 3 times. Flush the stack through the 4" cellar valves.;PJSM. Suck out the casing. Remove the knife valve, split the surface stack and PU the stack 4'.;Install the 9-5/8" casing slip. SO and engage slips. Ruff cut the casing and pull the casing out of the stack.;Set the surface annular down. ND the diverter tee and adapter flange. SimOps: Breakout the 19' pup joint from the cut joint. Casing cut joint= 18.9V.;Make the final cut on the casing and dress the stump. NU the Cameron 11"x 13-5/8" casing spool. PT seal to 250/5000 psi for 5 minutes each (good tests). SimOps: Remove the bolts from the diverter line. RD the casing running equipment. Clean the pits and rock washer.;NU the RCD and flow line valve for MPD per Beyond.;NU the ROPE stack. Hook up the Koomey lines to the BOP stack. NU the kill and choke Iine.;Hauled 75 bbls H2O from L -Pad lake for total = 4995 bbls Hauled 430 bbls heated H2O from G&I = 430 Hauled 1971 bbls cuttingsAiquids to MPU G&I for total = 7006 bbls 3/13/2019 Torque all bolts.;RU MPD line on the stack. Install the MPD riser.;RU ROPE testing equipment. Install the test plug. Flood lines, choke manifold and stack with fresh water. Purge the air from the system.;Conduct initial BOPE test to 250/3000 psi: Lower pipe rams (2-7/8" x 5" VBR's) with 5" test joint, upper pipe rams (4-1/2" x 7" VBR's) with 5" test joint, annular with 5" test joints, accumulator drawdown test and test gas alarms.;The states right to witness was waived by AOGCC inspector Guy Cook via email on 3/13/19 at 05:14 hours. Tests: 1.Annular with 5" test joint, 5" FOSV #1, 3" Demco kill, choke valves 1, 12, 13 & 14 (passed) 2.UPR with 5" test joint, HCR Kill, choke valves 9 & 11 (passed);3.Manual kill, 5" FOSV #2, choke valves 5,8 & 10 (passed) 4.5" Dart, choke valves 4, 6 & 7 (passed) S.Upper IBOP, choke valve 2 (passed) 6.HCR choke, Lower IBOP (passed) 7.Manual choke (passed) 81PR with 5" test joint (passed) 9.Blind Rams, choke valve 3 (passed);I O.Manual adjustable choke (passed) 1l.Hydraulic super choke (passed) Accumulator Test: System pressure = 3000 psi Pressure after closure = 1675 psi 200 psi attained in 46 seconds Full pressure attained in 200 seconds Nitrogen Bottles - 6 at 2004 psi.;Pull the MPD riser and install the MPD test plug. PT the MPD equipment 250/1500 psi (good test). Pull the MPD test plug and install MPD riser.;RD BOPE testing equipment. Blow down the choke manifold, kill line and choke line. Pull the test plug and install the wear ring.;Mobilize BHA components to the rig floor.;PJSM. / PU and MU the 8-1/2" cleanout assembly. 8-112" VM -3 tricone bit (rerun 3), motor, float sub, UBHO, 3 NM flex collars, 2 stands of 5" HWDP, Hydra-Jar/HWDP stand and 3 stands of 5" HWDP to 686'.;RIH with the cleanout assembly on 5" DP from the pipe shed from 686' to 2306' (PU = 115K and SO = 851K).;Fill DP and obtain drilling parameters. Wash down from 2306'to hard tag at 2319.5' at 300 GPM = 500 psi. Drill out cement and ES cementer from 2319' to 2326' at 450 GPM = 880 psi, 40 RPM = 5K ft -lbs torque and WOB = t OK.;Turn off the rotary and slide through the ES cementer two times without issue. Blow down the top Lh� VVVVVV drive.;Continue to RIH with the cleanout assembly on 5" DP from the pipe shed from 2326to tag at 5204' (PU = 160K and SO = 80K).;Wash down from 5204' to hard tag at 5255' at 300 GPM = 740 psi;CBU at 450 GPM = 1120 psi, 40 RPM = 10K fldbs torque.;Lay down a single to 522T and blow down the top drive. RU testing equipment.;PT the casing to 2500 psi for 30 minutes (good tesfl.:RD and blow do" testing equipment. MU single joint of DP and obtain drilling parameter. 460 GPM = 1190 psi, 40 RPM = 11 K ft -lbs torque. Wash down to tag at 5255' and drill cement to 5257'. 3/14/2019 Continue to drill cement and the shoe track from 5257' to 5393' at 450 GPM = 1190 psi, 40 RPM= 11 K ft-lbs torque and 5-10K WOB. Cleanout the rat hole from 5393'to 5403'. Drill 20' of new formation from 5403'to 5423'.;PU to 5355' and CBU at 450 GPM = 1190 psi.;RU pressure testing equipment. Close the UPR and perform FIT to 12.0 Poo EMW with existing 9.3 ppg MW. Pumped 1.1 bbis to achieve 553 psi and bleed back 1 bbl. Open the UPR and RD the pressure testing equipment.;MU a single and RIH to 5386'. MU crossover from 4-1/2" IF back to 3-1/2" IF. Mobilize E-line equipment to the rig floor. RU AK E-Iine.;PU and MU the Gyro tools. RIH to 4200' and lost communication with the tools.;POOH. Inspect the tools and E-line. Found damaged cable 2.5' above cable head causing short circuit. Cutoff a section of E-line. Tie a new rope socket. Test the tool and the tools are working properly.;RIH with Gyro tools to 4516'. Stage up pumps & pump down gyro w/ 5 BPM, 490 PSI. Gyro survey while RIH. Tag UBHO sub at 5344'. Survey on the outrun, check gyro drift as required.;L/D gyro and R/D AK a- line. R/D pump-in sub and lines. Pump 20 bbl 10.8 ppg dry job, UD single to 5354'& blow down top drlve.;POOH If 5354'ti 3925'. 195K PUW 190K SOW.;Service rig, blocks and top drive. Change hydraulic hose on iron roughneck.;POOH f/ 3925'ti 686'. Perform flow check at HWDP. UD excess HWDP. Rack back HWDP jar stand and stand of NMDC to 126'. UD BHA #2 from 33'. Bit graded 1-2-WT-G-E-3-NO-BHA. Clear & clean rig floor.;Pick-up 54 joints 5" drill pipe in the mousehole and rack back 18 stands in the derrick.;Mobilize BHA to the rig floor. M/U BHA #3: 8-1/2" SK616 PDC bit & 7600 Geo-Pilot to 25'. 3/15/2019 Continue to MU BHA #3: LWD, MWD and two NM float subs to 89'.;Upload MWD. SimOps: RU the GeoSpan.;Finish MU BHA #3: a stand of NM flex collars and jar/HWDP stand to 276.;Shallow pulse test the MWD tools at 450 GPM = 950 psi (good test). Blow down the top drive.;Single in the hole with 5" NC50 DP from 275' to 2181'.;Fill the DP, function test the GeoSpan and break in the Geo-Pilot seals at 10 to 60 RPM = 2-3K ft-lbs torque, 450 GPM = 950 psi.;Confinue to single in the hole with 5" DP from 2181' to 5050' filling DP every 2000'. Continue to TIH with DP from the derrick from 5050' to 5327'. Fill the DP and blow down the top drive.;PJSM. Slip and cut 66' (10 wraps) of drilling line. Inspect the saver sub and found the threads to be sharp. Changeout the saver sub. SimOps: PT MPD hard line to 250/1200 psi (good test).;PJSM. Remove trip nipple. Install MPC RCD. M/U stand and place bit at 5385'. 180K PUW / 85K SOW.;PJSM. Line up pits and trucks for displacement. Displace wellbore to 8.8 ppg FloPro NT. Pump 30 bbl high viscosity spacer @ 3.0 BPM, 270 PSI followed by 8.8 ppg FloPro NT @ 7 BPM, 850 PSI ICP, 620 FCP. Slow to 5 BPM, 350 PSI FCP. Obtain slow pump rates. Line up mud pits for drilling.;Drill 8-1/2" production lateral f/ 5423' U 5852', 429' drilled, 787hr AROP. 450 GPM, 1070 PSI, 120 RPM, 10-13K TO, 8-11 K WOB. 165K PU, 85K SO, 120K ROT. 9.79 ECD initial clean hole @ 450 GPM. MW in 8.95, out 9.0, vis in 44, out 41, ECD=9.95.;Full open MPD chokes while drilling. Closed chokes on connections with no pressure build up. Survey every 45' for survey QC and anti-collision. Last survey @ 5732.91' MD / 3946.36 TVD, 88.40° inc, 123.92° azm. 30.63' from plan, 30.19' high and 3.27' right.;Hauled 65 bbls H2O from L-Pad lake for total = 5420 bbis Hauled 0 bbis heated H2O from G&I = 430 Hauled 404 bbis cuttings/liquids to MPU G&I for total = 7895 We 0 bbis daily losses, 0 bats cumulative losses. 3/16/2019 Drill 8-1/2' production hole from 5852' to 6357' (3957' TVD), 505' with AROP of 84.2 FPH. 480 GPM = 1100 psi, 140 RPM= 13-151(ft-lbs torque, WOB = 10K, MW = 8.9 ppg, Vis = 43, ECD = 10.04 ppg, Max gas= 84 units PU = 184K, SO= 72K, ROT= 120K. Back ream 30' on connections.;Drill 8-1/2" production hole from 635T to 6820' (3993' TVD), 463' with AROP of 77.2 FPH. 500 GPM = 1220 psi, 120 RPM = 15K ft-lbs torque, WOB = 5-20K, MW = 8.9 ppg, Vis = 43, ECD = 10.17 ppg, Max gas = 77 units PU = 190K, SO = 65K, ROT = 122K. Back ream 30' on connections.;Pumped tandem sweep at 6373', back 200 strokes late with 20% increase in cutting over the shakers. Started anti collision descent at 6400'.;Drill 8-1/2" production hole from 6820'to 7360' (4025' TVD), 540' with AROP of 90 FPH. 550 GPM = 1770 psi, 120 RPM = 15K ft-lbs torque, WOB = 8K, MW = 8.8 ppg, Vis = 436, ECD = 10.76 ppg, Max gas = 85 units PU = 180K, SO = 65K, ROT = 117K. Back ream 30' on connections.;Hi vis sweep at 6851', back 150 stokes late with 30% increase in cuttings over the shakers. MPD chokes full open when drilling, holding 60-70 PSI on connections to maintain 9.2 ppg EWM. Closest approach to L-20 @ 6950', 18.33' between ellipses at 1.176 CF.;Dnll 8-1/2" production hole from 7360' to 7994' (4043' TVD), 634' with AROP of 105.7 FPH. 500 GPM = 1810 psi, 120 RPM= 15K ft-lbs torque, WOB = 15-17K, MW= 8.8 ppg, Vis = 436, ECD = 10.76 ppg, Max gas = 17 units PU = 185K, SO= 57K, ROT= 110K. Back ream 30' on connections.;Hi vis sweep at 7440', back 150 stokes late with 20% increase in cuttings over the shakers. Last survey @ 7877.08' MD / 4044.68' TVD, 90.75° inc, 126.76° azm, 29.59 from plan, 1.04' low, 29.5T left. MPD chokes full open when drilling, holding 60-70 PSI on connections to maintain 9.2 ppg EWM.;Drilled 13 concretions for a total thickness of 128' (5% of the lateral).;Hauled 735 bbis H2O from L-Pad lake for total = 6155 bbls Hauled 0 bbis heated H2O from G&I = 430 Hauled 627 We cuttings/liquids to MPU G&I for total = 8522 bats 0 bbls daily losses, 0 bbis cumulative losses. 3/17/2019 Drill 8-1/2" production hole from 799N to 8566 (4001' TVD), 572' with AROP of 95.3 FPH. 500 GPM = 1800 psi, 120 RPM= 15K ft-lbs torque, WOB = 10K, MW = 9.2 ppg, Vis = 47, ECD = 11.13 ppg, Max gas = 77 units PU = 180K, $O = 58K, ROT= 112K. Back ream 30' on connections.;Hit the base of OA-4 at 8434' and OA-3 at 8505' Perform 290 bbl new mud dump and dilute @ 8280'. Pumped 30 bbis hi-vis sweep at 7994', back 200 strokes late w/ 20% Inc. in cutting over the shakers. Pumped 30 bbis hi-vis sweep at 8470', back 200 strokes late w/ 20% Inc. in cutting over the shakers.;Drill 8-1/2" production hole from 8566' to 9233' (3983' TVD), 667' with AROP of 111.2 FPH. 500 GPM = 1730 psi, 120 RPM = 17K ft-lbs torque, WOB = 5-15K, MW = 9.1 ppg, Vis = 45, ECD = 10.79 ppg, Max gas = 104 units PU = 180K, SO = 58K, ROT = 112K. Back ream 30' on connections.;Hit the base of the OA-2 at 8692' and OA-1 at 8795'. Perform 290 bbl new mud dump and dilute @ 8910'. Pumped 30 We hi-vis sweep at 9066, back 250 strokes late with 30% increase in cutting over the shakers.;Drill 8-1/2" production hole from 9233' to 9761' (3981' TVD), 528' with AROP of 88 FPH. 500 GPM = 1770 psi, 110 RPM = 19K ft-lbs torque, WOB = 12K, MW = 9.1 ppg, Vis = 45, ECD = 10.99 ppg, Max gas = 114 units PU = 195K, SO = N/A, ROT = 110K. Back ream 30' on connections. Lost SO weight @ 9138'.;Pumped 30 bbis hi-vis sweep at 9529, back 400 strokes late with 60% increase in cutting over the shakers.;Drill 8-112" production hole from 9761'to 10272' (4006' TVD), 511' with AROP of 85.2 FPH. 505 GPM = 1820 psi, 110 RPM = 19K ft-lbs torque, WOB = 8-15K, MW = 9.15 ppg, Vis = 45, ECD = 10.58 ppg, Max gas = 105 units PU = 200K, SO = N/A, ROT = 110K. Back ream 30' on connections.;Begin drop down to OA-3 at 9761'. Closest approach to L-35 at 9825', 63.6' center to center, - 21.53' ellipse, 0.75 CF. Pumped 30 bbis hi-vis sweep at 9996', back 100 strokes late w/ 30% increase in cutting over the shakers. Perform 290 bbl new mud dump & dilute at 10175'.;Hit base of OA-1 at 9997' and top of OA-3 at 10096. Drilled 27 concretions for a total thickness of 218'(4.6% of the lateral). Last survey @ 10116.73' MD / 3998.26' TVD, 87.23° inc, 128.59° azm, 38.08' from plan, 13.55' high and 35.59' Ieft.;Hauled 575 bbis H2O from L-Pad lake for total = 6730 bbis Hauled 0 bbis heated H2O from G&I = 430 Hauled 1776 bbis cutfingslliquids to MPU G&i for total = 10298 bbis 0 bbis daily losses, 0 bbls cumulative losses. 3/18/2019 Drill 8-1/2" production hole from 10272' to 10821' (4003' TVD), 549' with AROP of 91.5 FPH. 503 GPM = 1760 psi, 110 RPM= 21 K ft -lbs torque, WOB = 11- 15K, MW = 9.2 ppg, Vis = 46, ECD = 10.79 ppg, Max gas = 168 units PU = 220K, SO = N/A, ROT = 119K. Back ream 30' on connections.;Pumped 30 bbis hi - vis sweep at 10472', back on time with 50% increase in cutting over the shakers.;Drill 8-1/2" production hole from 10821' to 11516' (3990' TVD), 695' with AROP of 115.8 FPH. 500 GPM = 1870 psi, 100 RPM= 19K ft-Ibs torque, W OB = 5-15K, MW = 9.O ppg, Vis = 47, ECD = 11.17 ppg, Max gas = 124 units PU = 210K, SO= NfA, ROT= 115K. Back ream 30' on connections.;Performed 290 bbl new mud dump and dilute at 11150'. Pumped 30 bbis hi -vis sweep at 10955', back 250 stks late with 50% increase in cutting over the shakers.;Drill 8-112" production hole from 11516' to 11900' (3984' ND), 384' with AROP of 64 FPH. 500 GPM = 2000 psi, 100 RPM= 20-25Kft-lbs torque, WOB = 5-25K, MW = 9.1 ppg, Vis = 48, ECD = 11.34 ppg, Max gas = 133 units PU = 215K, SO= N/A, ROT = 113K. Back ream 30' on connections.;Pumped 30 hiss hi -vis sweep at 11616, back 400 stks late with no increase in cutting over the shakers. Add 0.5%Lo- Torq lube at 11855', 71K reduction in torque and 25K reduction in pickup weight.;Drill 8-1/2" production hole from 11900'to 12442' (3982' TVD), 542' with AROP of 90.3 FPH. 505 GPM = 2140 psi, 130 RPM = 18K ft -lbs torque, WOB = 12-15K, MW = 9.1 ppg, Vis = 48, ECD = 11.55 ppg, Max gas = 136 units PU = 175K, SO = NlA, ROT = 112K. Back ream 30' on connections.;Pumped 30 bbis hi -vis sweep at 11994', back 400 stks late with 50% increase in cutting over the shakers. Crossed fault @ 12278', suspect out the top of OA -1. Will drop down from 91 ° to 87°.;Last survey at 12397.34' MD, 3983.72' TVD, 85.93° Inc, 124.17° Az. Distance to Well Plan #8 = 13.95' (13.59' low and 3.15' right). Drilled 42 concretions for a total thickness of 329' (4.8% of the lateral).;Hauled 800 bbis H2O from L -Pad lake for total = 7530 bbis Hauled 0 bbls heated H2O from G&I = 430 Hauled 1197 bbls cuttingstliquids to MPU G&I for total = 11495 bbls 0 bbis daily losses, 0 bbis cumulative losses. 3/19/2019 D6118-1/2" production hole from 12442' to 12905' (4013' TVD), 463' with AROP of 77.2 FPH. 505 GPM = 2150 psi, 130 RPM= 201(ft-Ibs torque, WOB = 9- 15K, MW = 9.05 ppg, Vis = 44, ECD = 11.64 ppg, Max gas = 159 units PU = 194K, SO = N/A, ROT = 109K. Back ream 30' on connections.;Pumped 30 bbl hi - vis sweep at 12467' back 400 strokes late with 50% increase cuttings at the shakers.;Drill 8-1/2" production hole from 12905to 13510' (4031' TVD), 605' with AROP of 100.8 FPH. 475 GPM = 2080 psi, 110 RPM = 23K ft-Ibs torque, WOB = 5-20K, MW = 9.1 ppg, Vis = 46, ECD = 11.83 ppg, Max gas = 151 units PU = 195K, $O = N/A, ROT = 107K. Back ream 30' on connections.;Pumped 30 bbl hi -vis sweep at 12949' back 400 strokes late with 20% increase cuttings at the shakers.;Drill 8-1/2" production hole from 13510'to 13889' (4036' TVD), 379' with AROP of 63 FPH. 475 GPM = 1990 psi, 110 RPM= 23K ft-Ibs torque, WOB = 5-20K, MW= 9.0 ppg, Vis = 46, ECD = 11.58 ppg, Max gas= 172 units PU = 235K, SO= N/A, ROT= 115K. Back ream 30' on connections.;Holding 200 psi on connections Perform 580 bbis dilution at 13,800' for MBT. Pumped 30 bbls high viscosity sweep at 13516', 50% increase in cuttings 400 strokes Iate.;Drill 8-1/2" production hole from 13889' to 14362' (4032' TVD), 473' with AROP of 79 FPH. 505 GPM = 2170 psi, 120 RPM = 23K ft -lbs torque, WOB = 10-20K, MW = 9.0 ppg, Vis = 43, ECD = 11.25 ppg, Max gas = 241 units PU = 230K, SO = N/A, ROT = 112K. Back ream 30' on connections.;Pumped 30 bbls high viscosity sweep at 13984', 0% increase 400 strokes Iate.;Last survey at 14291.81' MD, 4036.52' TVD, 92.73° Inc,125.73° Az. Distance to Well Plan #8 = 42.42' (41.89' low and 6.65' Left). Drilled 60 concretions for a total thickness of 446'(5% of the lateral). 3362' drilled in OA -1; 952' drilled in OA -2; 2690' drilled in OA-3;Hauled 1020 bbls H2O from L -Pad lake for total = 8550 bbis Hauled 0 bbis heated H2O from G&I = 430 Hauled 1593 bbls cuttings/liquids to MPU G&I for total = 13088 bbls 0 bbis daily losses, 0 bbls cumulative losses. 3/20/2019 Drill 8-1/2" production hole from 14362' to 14932' (4006' TVD), 570' with AROP of 95 FPH. 505 GPM = 2250 psi, 120 RPM= 23K ft-Ibs torque, WOB = 10-15K, MW = 9.1 ppg, Vis = 43, ECD = 11.60 ppg, Max gas = 224 units PU = 208K, SO= N/A, ROT= 113K. Back ream 30' on connections.;Pumped 30 bbis high viscosity sweep at 14456', 75% increase 500 strokes Iate.;Dri118-1/2" production hole from 14932' to 15501' (4015' TVD), 569' with AROP of 95.8 FPH. 500 GPM = 2240 psi, 120 RPM = 24K ft-Ibs torque, WOB = 6-10K, MW = 9.0 ppg, Vis = 44, ECD = 11.72 ppg, Max gas = 339 units PU = 205K, SO = N/A, ROT = 108K. Back ream 30' on connections.;Perform 290 bbl 8.8 ppg new mud dilution at 15239. Pumped 30 bbis high viscosity sweep at 14932', 25% increase 500 strokes late. Pumped 30 bbis high viscosity sweep at 15417', 0% increase 550 strokes Iate.;Dri118-1/2" production hole from 15501'to TD 16070' (4015' TVD), 569' with AROP of 81 FPH. TD called by Geo after crossing expected fault. 500 GPM = 2420 psi, 120 RPM = 24K fl -lbs torq, WOB = 5-20K, MW = 9.0 ppg, Vis = 43, ECD = 11.74 ppg, Max gas = 87 units PU = 225K, SO = N/A, ROT = 112K.;290 bbis dilution at 15800'. Pumped high viscosity sweep at 15976; 0% increase, 500 atx late. Increase lube concentration at 15690' due to excessive torque (26-27Kft-Ibs).;CBU 500 gpm/2260 psi 80rpms/21 Kft-lbs, reciporcating pipe while building tandem sweep. Stand one stand back and pump low vis/weight and high vishveight tandem sweep (0%, 500 stx late). Stand back one stand perform 290 bbis dilution and increase lube concentration to 4%. ECD 11.44 ppg EMW.;Hauled 890 bbis H2O from L -Pad lake for total = 9440 bbls Hauled 0 bbls heated H2O from G&I = 430 Hauled 979 bbis cuttingsMquids to MPU G&I for total = 14067 bbis 0 bbis daily losses, 0 bbis cumulative Iosses.;Lasl survey at 16000.41' MD, 4037.12' TVD, 87.09° Inc,124.14° Az. Distance to Well Plan #8 = 74.75'(74.21 ' low and 8.13' right). Drilled 74 concretions for a total thickness of 554' (5.2% of the lateral). 4085' drilled in OA -1; 136T drilled in OA -2; 3317' drilled in OA -3 Hilcorp Energy Company Composite Report Well Name: MP M-11 Field: Milne Point County/State: , Alaska t (LAT/LONG): ovation (RKB): API #: Spud Date: 3/7/2019 Job Name: 18144600 MPU M-11 Completion Contractor AFE #: AFE $: Activity Date I Ops Summary 3121/2019 Circulate and condition the mud at 500 GPM, 2220 PSI, 110 RPM, 21K TO. Reciprocate f/ 15882't/ 15787' staggering end points. Finish increasing lube to 4% total, 3% LoTorq and 1% 776 tube. 46050 strokes pumped since TD, 4.3 bottoms up.,lnstall 270 & 230 mesh screens on shakers. Observe pressure with pumps off. 220 PSI with 9.2 ppg mud out= 10.25 ppg EMW.,Circulate and condition the mud for Production Screen Tests. 350 GPM, 1290 PSI, 40 RPM, 15-17K TQ. Reciprocate f/ 15882' V 15977'. Perform PST @ 4800 stks, mud in passed (4 sec, 4 sec, 4.8 sec). PST @ 10800 stks (hole volume) mud after shakers passed (5.23 sec, 4.92 sec, 4.8 sec). Shut down, install 270 mesh screens. Reciprocate f/ 15977' V 16069.,PST @ 14500 stks (hole volume+ pit volume), mud at flow line passed (5 sec, 4.7 sec. 4.7 sec). Total strokes pumped 16500 at 350 GPM, 2.2 bottoms up. Holding 50 PSI back pressure via MPD = 10.54 ECD with 9.0 ppg mud in/outwith pressure balance. 9.1 ppg at MPD Coriolis meter. Shut down, check pressure with MPD. 220 PSI = 10.2 ppg EMW.,BROOH to 13606'; w/ 385 GPM, 1600 PSI, 120 RPM, 16K TO. Begin at 10 min./stand f116070' V 1578T. Increase to 7 mint stand f/ 15787' V 15408'. Increase to 5 minJstand at 15408' MPD holding 80 PSI back reaming= 10.8 ppg ECD and 220 PSI on connections= 10.2 ppg EMW.,Continue to BROOH from 13606to 11617'; 385 gpm/1350 psi, 80rpms/14Kft-lbs Observe slight packoff at 13,000', slow pulling speed from 5 min/stand to 10 min/stand until through shale (12,502'- 12228'). Observe pack oft from 12235' to 12228', slow pulling speed and work pipe -clean. MPD holding 220 psi on connections for 10.2 ppg EMW, holding 110 psi while BROOH for 10.6 ppg ECD.,PST going in at 12,750'= 5.2 sec., 5.2 sec., 5.4 sec.,Continue to BROOH from 11617' to 9031'; 385 gpm/1200 psi, 80rpms/9Kft lbs pulling 5 min/stand Slight packoff at 11078', slow pulling speed and allow to clean up. MPD holding 245 psi on connections for 10.2 ppg EMW, holding 150 psi while BROOH for 10.6 ppg ECD. PST at 10,000' = 5.3 sec, 5.3 sec, 5.4 sec.,Hauled 815 bbis H2O from L -Pad lake for total = 10255 bbis Hauled 0 bbls heated H2O from G&I = 430 Hauled 1160 bbls cuttingsAiquids to MPU G&I for total = 15227 bbis 0 bbis daily losses, 0 bbis cumulative losses. 3/22/2019 Continue to BROOH from 9031'to 7424'. 385 GPM, 1120 PSI, 120 RPM, 9K ft/lbs. Pulling 5 min/stand. Reaming shale from 8434' at 10 min/stand. Slight pack - off at 8387', 7988, 7907' & 7478', work down then ream slowly and allow to clean up. Shakers blinded off at 8370' & 7988', stop reaming, reduce flow and allow to clean up before continuing. PST at 8170'= 5.4 sec, 5.6 sec, 5.6 sec.,MPD holding backpressure: 80-150 PSI (10.5-10.6 ppg ECD) while reaming and 225 PSI (10.5 ppg EWM) on connections.,Continue to BROOH from 7424! to 5328'. 385 GPM, 1040 PSI, 120 RPM, 4K Polbs. 150K PUW / 90K SOW. Reaming shale to 6984' at 10 min/stand. Larger pack -off at 7439' with thick, heavy (up to 10.5 ppg) mud at shakers. Slow pumps and allow to clean up before continuing. Increase pulling speed to 5 min/stand above shale. PST at 7150' = 5.2 sec, 5.2 sec, 5.3 sec.,Milne Point phase 2 driving conditions at 16:00.,Pump 26 bbl high viscosity sweep. 500 GPM, 1450 PSI, 80 RPM, 3K ftllbs. Sweep came back on stokes with 0% increase of cuttings. Increase flow to 550 GPM, 1660 PSI, 60 RPM, 2K Nlbs. Circulate 8112 strokes, 3x bottoms up.,Perform MPD formation pressure test. Bleed down to 200 PSI and built to 212 PSI. 190 PSI to 209 PSI, 185 PSI to 202 PSI, 175 PSI to 195 PSI, 170 PSI to 189 PSI, 160 PSI to 184 PSI. Final 160 PSI to 182 PSI. 182 PSI at 3941' TVD = 0.9 ppg + 9.3 ppg mud = 10.2 ppg EMW.,Weight up to 10.0 ppg while mixing dry product (oilfield salt) in 0.3 ppg increment at 385 GPM, 960 PSI, 60 RPM 3K ft/Ibs. Good 10.0 ppg MW in and out at 24000 strokes, 3.5 complete mud volume circulations (368 bbls downhole and 334 bbls on surface). Production Screen Test at 9.7 ppg = 5.4 sec, 5.4 sec, 5.5 sec.,Shut down and open MPD chokes, zero flow on Coriolis meter. Blow down top drive and MPD lines. Open MPD bleeder and perform flow check. Initial flow 0.67 BPH slowing to 0.23 BPH in 10 minute then to trickle. Sim -ops: change shaker screens and begin weighting up pit #4 to 10.2 ppg.,Weight up mud system to 10.2 ppg with oilfield salt and KCI for additional 0.2 ppg trip margin at 400 GPM, 1040 PSI, 60 RPM, 3K ft/lbs. Good 10.2 ppg MW in and out at 8756 strokes. Production Screen Test at 10.2 ppg = 6.2 sec, 6.3 sec, 6.3 sec.,Shut down and open MPD chokes, zero flow on Coriolis meter. Blow down top drive and MPD lines. Open MPD bleeder and perform flow check, wellbore static.,PJSM with Beyond and Doyon personnel. Remove MPD RCD element. Install trip nipple. 29,389'stripped through and 128 rotating hours on RCD.,UD 5" drill pipe from 5328'to 4787'. 138K PUW 1116K SOW.,Hauled 555 bbis H2O from L -Pad lake fortotal = 10810 bbls Hauled 0 bbis heated H2O from G&I = 430 Hauled 632 tools cuttingsAiquids to MPU G&I for total = 15859 bbis 0 bbis daily losses. 0 bbls cumulative losses. Rig fuel (gallons): Rec'd=0, Used=2664, On hand=8296. 3123/2019 POOH with 8-1/2" drilling assembly, laying down 5" drill pipe from 4787'to 275'. Monitor well prior to laying down the BHA. Slight losses about 1.5 BPH. 15.1 bbls lost over displacement on trip out. Note: Milne Point driving conditions upgraded to phase 1 at 07:30.,UD 8-1/2" drilling BHA from 275'to 83'. Read MWD tools. 100% data read from MWD tools. UD BHA from 83'. Wear observed on up hole blade of in-line stabilizer. One water course of the near bit stabilizer was packed with clay. Remainder of BHA in good condition. Bit grade: 1 - 1 -WT-A-X-1 -NO-TD. Static losses 1.5 BPH. Note: At 13:28 notified AOGCC for BOP testing on 24 March at 18:OO.,Clear rig floor. PJSM. UD 68 stands of 5" drill pipe from the derrick in the mousehole. Static losses 1.5-2 BPH.,Service rig draworks, inspect and service ST-80.,UD 22 stands of 5" drill pipe from the derrick in the mousehole. Total of 90 stands laid down. Static losses 1.5-2 BPH.,Load 5" HWDP in to shed. Make up and rack 33 stands in Derrick. Utilize 3.375" drift for HWDP. Static losses 1.5-2 BPH.,Hauled 60 bbls H2O from L -Pad lake for total = 10870 bbls Hauled 0 bbis heated H2O from G&I = 430 Hauled 0 bbis cuttings/liquids to MPU G&I for total = 15859 bbls 32 bbis daily losses. 32 bbis cumulative losses. 11a� _ _ -lri 3/24/2019 Makeup and rack 23 stands of 5" HWDP in derrick for a total of 56. Utilize 3.375" drift for HWDP. Static losses 1.5-2 BPH.,Flush BOP stack. Pull wear bushing. Install lower test plug. PJSM, remove 4-1/2"x7" VBR from upper cavities, then install 3-1/2" x 6" VBR. Rig up test equipment and perform body pressure test.,Test BOPS as per PTD and AOGCC requirements. AOGCC inspector Robert Noble waived witness of test at 11:52 on 24 March 2019. Tests: 1.Annular with 5" test joint, Upper IBOP, 3" Demco kill, choke valves 1, 12,13 & 14 (passed)2.UPR with 5" test joint, HCR Kill, choke valves 9 & 11, Lower IBOP (passed)3.Manual kill, 5" Dart, choke valves 5, 8 & 10 (passed) 4.#1 5" FOSV, choke valves 4, 6 & 7 (passed),6.Choke valve 3 (passed) THCR choke (passed)B.LPR with 5" test joint (passed)9.Blind Rams (passed)10.Hydraulic super choke, Manual adjustable choke (passed)l1.UPR w/ 4.5" test joint, Manual choke (passed)l 2.LPR's w/ 4.5" testjoint (passed)l 3Annular wl 4.5"testjoint(passed)l4.UPR w/3.5"test joint (passed),15.LPR w/3.5"lestjoint(passed)16.Annular w/3.5" test joint (passed) - 2500 psi high Accumulator Test: System pressure = 3000 psi Pressure after closure = 1750 psi200 psi attained in 44 seconds Full pressure attained in 194 seconds Nitrogen Bottles - 6 at 2050 psi.,RD BOPE testing equipment. Blow down the choke manifold, kill line and choke line. Pull the test plug and install the wear ring.,lnstall mouse hole. PJSM, Cut & Slip drilling Iine.,Mobilize casing equipment to dg floor. Rig up power tongs and 4-1/2" handling equipment. M/U safety joint for up coming inner string. WU floor valve to XO's for 4-1/2" Iiner.,Hauled 105 bbis H2O from L-Pad lake for total = 10975 bbis Hauled 0 bbis heated H2O from G&I = 430 Hauled 132 bbis cuttings/liquids to MPU G&I for total = 15991 bbls 28 bbis daily losses. 60 bbis cumulative losses. Rig fuel (gallons): Rec'd=0, Used=1277, On hand=9376. 3/25/2019 Continue to R/U to run 4-1/2" lower completion liner. WU triple connect (2-318" EUE x 4-1/2" H625 x 4-1/2" IF, 5" drill pipe, 5" safety valve, 4-1/2" IF x 2-3/8" XO sub with pup.,PJSM with Doyon and Baker for running 4-1/2" swell packer /ICD lower completion. PJSM. PAJ 4-1/2" float shoe, WIV, 4-1/2" joint of liner, drillable Pac-Off sub, 4-12" pup joint & 4-1/2" BTC pin x 4-1/2" H625 Wedge box XO pup joint. Run 4-1/2" 13.5# L-80 Hydril 625 Wedge liner with Tendeka water swell packers and Tendeka 250 micron screen ICDs as per tally to 2140'.,Torque connections to 9600 ftllbs with Doyon double stack tongs. Install one stop ring and one 4-1/2" x 7-1/2" ridged strain vane centralizer free floating on each joint of liner.1 BPH Iosses.,Run 4-1/2" 13.5# L-80 Hydril 625 Wedge liner with Tendeka water swell packers and Tendeka 250 micron screen ICDs as per tally from 2140'to 6722'. Torque connections to 9600 ft/lbs with Doyon double stack tongs. Install one stop ring and one 4-12" x 7-112" ridged strain vane centralizer free floating on each joint of liner. 96K PUW / 80K SOW at 5379' inside 9-518" casing. 1 BPH Iosses.,Run 4-1/2" 13.5# L-80 Hydril 625 Wedge liner with Tendeka water swell packers and Tendeka 250 micron screen ICDs as per tally from 6722' to 10794'. Torque connections to 9600 fVlbs with Doyon double stack tongs. Install one stop ring and one 4-1/2" x 7-1/2" ridged strain vane centralizer free floating on each joint of liner. 118K PUW / 65K SOW.,251 joints, stop rings & centralizers ran. 15x ICDs, 16x Swell Packers. Set 4-12" liner intension with 118k PUW. 1.5 BPH losses.,Rig up false rotary table, Change out 4-1/2" handling equipment for 2-3/8". Install swivel on bottom of the safety joint below the triple connect. 1 BPH Static loss rate.,P/U & M/U 2-3/8" EUE Slick Stinger and cross over sub to 2-318" PH-6. M/U cross over to H503. RIH with 2-3/8" 4.7# H503 inner string from 1 T to 2214' Utilize 1.773" drift while picking joints up. Torque H503 connections to 1700 ft/lbs with Doyon double stack tongs. 1 BPH loss rate,Hauled 25 bbis H2O from L-Pad lake for total = 11000 bbls Hauled 0 bbis heated H2O from G&I = 430 Hauled 75 bbis cuttings/liquids to MPU G&I for total = 16066 bbis 33.2 bbls daily losses. 93.2 bbls cumulative losses. Rig fuel (gallons): Rec'd=0, Used=1277, On hand=9376. 326/2019 Continue to run 23/8" 4.7# H503 inner string from 2214' to 2304'. WU XO sub then run 2-3/8" 5.95# WTS-6 inner string from 2304'to 5135'. Torque H503 connections to 1700 ft/Ibs and WTS-S to 3000 f albs with Doyon double stack tongs. Utilize 1.773" drift while picking joints up. Drift stuck in joint #165 & 166. Losses at 1 BPH.,Free drift from joints of 2-3/8". Begin drifting pipe on the rack. Got stuck on joint #195, 210, 214 & 216 due to scale buildup. Pipe was previously drifted with 1.70" drift and 1.75" phenolic ball. Baker Hughes and drilling engineer good to proceed with 1.75" drift (back-up activation ball size). Will continue to drift pipe with 1.70" drift off pipe skate to ensure pipe is clear. Losses at 1 BPH.,Continue to run 2-3/8" 5.95# WTS-6 inner string from 5135to 10759. (346 jts) Torque WTS-6 connections to 3000 ft/lbs with Doyon double stack tongs. Drifted with 1.75" phenolic ball. Losses at 1 BPH..Pick up working joint and RIH. Tag up 23' down. Lay down working joint and space out with 10' pup joint. PU - 75k, SO - 49k. 346 jts 2-318+ 10' pupjt in hole.,Rig down safetyjoint and make up 5" drill pipe with triple conned and cross over.,Pick up string with 4-1/2" Liner & inner string to 160k. Calculated PU -153k. Slack off to 40k with no string movement. Work string several times 200k, 225k, 250k. Slack off to neutral and engage rotary with tq limit set @ 8k. Work string down and broke free. Cease rotary and RIH to 10827' confirming liner packer hanger can be run below table with no resistance. Work 2x (clean) then set liner back in tension.,PU- 145k, SO - 70k, ROT - 95k 10 & 20 RPM - 7/8k tq.,Break out and lay down triple connect and 5" drill pipe joint.,Make up SLZXP Liner Top Packer w/ 7.375 seal, bore 7" x 9-5/8". Hyd setting tool - 8x 1/2" screws set at 2648 psi, 15% Brass.,Run the 4-1/2" 13.5# 625 Wedge L-80 Liner in hole on 5" HWDP from 10794' to 12248' -30'/min running speed. Establish circulation at 11763'to confirm clear flow path through string. Pumped 9 bbis @ 1 BPM - 660 psi before returns observed. Fill pipe on the fly, topping off every 5 stands. Loss rate at- 3 BPH.,Continue RIH with 4-12" 13.5# 625 Wedge L-80 Liner in hole on 5" HWDP from 12248' to 15526' -30'/min running speed. Fill pipe on the fly, topping off every 5 stands. Loss rate at - 4 BPH. PU - 275k, SO - 90K.,Hauled 30 bbis H2O from L-Pad lake for total = 11030 bbis Hauled 0 bbls heated H2O from G&I = 430 Hauled 57 bbls cuttings/liquids to MPU G&I for total = 16123 bbis 26 bbis daily losses. 119.2 bbls cumulative losses. Rig fuel (gallons): Recd=0, Used=1257, On hand=6981. 3/27/2019 Continue RIH with 4-1/2" 13.5# 625 Wedge L-80 Liner in hole on 5"HWDP from 15526' to 15809' where assembly took might -30'/min running speed. Establish free rotation with 10 RPM, 1 OK TO and circulation with 1 BPM, 710 PSI. Work liner down with 10 RPM, 10K TO and no circulation in 2-3' increments each reciprocation. Assembly was free and never overpulled. Tag bottom on depth at 16070'. 282K PUW / 118K SOW.,Pump 1 BPM, 710 PSI every 1/2 stand to ensure flow path clear. Did not want to displace 10.2 ppg kill weight mud with 9.2 ppg mud in the lateral before liner reaching bottom.,Stage up pumps to 2.2 BPM, 1410 PSI then shut down for displacement. 1700 PSI max pressure recommended by Baker, packer begins to set at 2200 PSI. Reciprocate pipe from 16070' to 16035' while holding PJSM for displacement. Line up pits and trucks for displacement and flush Iines.,Pump 30 bbis high vis spacer, 50 bbis seawater, 30 bbls SAPP pill, 50 bbis seawater, 30 bbis SAPP pill, 50 bbis seawater, 30 bbls SAPP pill, 30 bbis high vis spacer fol lowed by 280 bbis of seawater. Initial 2.0 BPM, 1520 PSI, final 2.3 BPM, 1600 PSI. Reciprocate 35' from 16070' to 16035'. 5770 strokes total. 9.7 ppg mud out at 4267 strokes, 9.5 ppg mud out at 5102 strokes.,Begin displacement to 10.0 ppg brine. 2.4 BPM, 1650 PSI. 9.0 ppg mud out at 9640 strokes. Trace amounts of wall cake observed at 10000 strokes. Lost 45K SOW and gained 45K PUW. Park string at 10560 strokes in tension, 275K PUW / 105K SOW. 8.7 ppg seawater back at 11700 stks. 9.3 ppg brine back at 15200 stks Shut down at 15400 stks w/ 9.5 ppg brine out. Max gas-123.,Pump down 1.25" ball at 2 BPM -1030 psi. Pump 30 bbl hi vis spacer followed with 10.0 ppg brine. Caught pressure at 736 stks, Calculated at 808 stks. Pressure up and see pusher shear at 2700 psi. Pump to 3000 psi and hold pressure for 5 min. S/O 40k to 90k hookload. Pump up to 3800 psi with rig pumps. Lineup on test pump and pressure to 4200 psi. Good indication of shear @4150 psi. BOL - 16055' / TOL - 5232.5'.,Bleed off pressure and P/U V to confirm released. Continue P/U 6' to expose dogs. S/O and shear dogsub with 50k, confirmed with 20 RPM rotary -4-7k.,Shut top rams. Pressure test annulus t/ 1500 psi for 10 min. P/U 15'to pullout slick stick. Lineup to circulate.,Establish circ withg 10.0 ppg Brine at 4 bpm - 3300 psi, losses calculated at 100 BPH. Reduce to 2.3 BPM, 1600 psi with 60 BPH loss rate. Displaced w/ four 4.5 X 2-3/8 liner volumes plus 9- 5/8" X 5" annular volume. 9.9+ brine back at 6600 strokes. Pumped total of 686 bbl. 60 BPH losses while circulating.,Break out and rack 1 stand back. Blow down Topdrive. Monitor well - Fluid level dropping slightly.,POOH from 16033' to 14722' racking 5" HWDP in Derrick. 19bbl Ioss.,Hauled 75 bbis H2O from L - Pad lake for total = I I105bbls Hauled 0 bbis heated H2O from G&I = 430 Hauled 1450 bbis cuttings/liquids to MPU G&I for total = 17573 bbis 25 bbis daily losses. 144.2 bbis cumulative losses. Rig fuel (gallons): Rec'd=4902, Used=1577, On hand=10306 3/28/2019 POOH racking back 5" HWDP from 14722'to 13829. LID 5" HWDP from 13820'to 10864'. 12-15 BPH lOsses.,L/D Baker liner running tool, space out pup and XO subs. R/U Doyon double stack power tongs. M/U XO on 5" drill pipe safety joint.,UD 2-318" WTS-6 inner string from 10750' to 2304'. 12-15 BPH Iosses.,UD 2 318" H503 inner string from 2304'to surface. LID slick stick and clear floor of 2-3/8" handling equipment. 12-15 BPH Iosses.,Clean and clear rig floor of 2-3/8" handling tools & BOT equipment. Break down safety joint.,Make up 3.52" OD stinger/wash joint to 8.38" NO GO XO. RIH on 5"HWDP U 2157. Continue RIH with 5" DP from 2157' to 5193' PIU - 175k, S/O - 138K 12-15 BPH Iosses.,Establish circulaflon at 2 BPM - 60 psi. Wash down and tag up no-go at 5267'. P/U 4' and increase flow rate to 4 BPM - 150 psi. Work string 10' while pumping 20 bbls to flush seat bore.,P/U 33' to position bottom of stinger above top of liner. PJSM with crew and third parry on displacement. Displace well to clean 10 ppg brine. Initial circulating rate of 4 BPM - 150 psi. Stage up to 7.85 BPM - 530 psi. No losses recorded while displacing.,Hauled 50 bbls H2O from L -Pad lake for total = 11155bbis Hauled 0 bbis heated H2O from G&I = 430 Hauled 820 bbis cuttings/liquids to MPU G&I for total = 18393 bbis 252 bbls daily losses. 396.2 bbls cumulative losses. Rig fuel (gallons): Recd=0, Used=1168, On hand=9138 3/29/2019 Finish 10.0 ppg new brine displacement at 5233' with 7.8 BPM, 530 PSI. High vis sweep back at 3770 strokes and clean brine at 4150 strokes. Shut down at 4466 strokes. 451 bbls pumped and 451 bbls returned, no losses during displacement. Perform 15 min. flow check- static then began dropping slowly.,POOH from 5233'to 32' laying down 5" HWDP & 5" drill pipe. UD no-go and 3-1/2" perforated wash tool. Losses began at 6 BPH and increased to 22 BPH.,R/D wash tool & pull wear bushing.,Rig up 3-1/2" handling tools. Hang sheave and rig up spooling unit. M/U FOSV. Pressure test TEK wire to 5000 psi.,P/U Baker Bullet seals tie -back assembly to 16. Run 3-12" 9.3# L-80 EUE tubing V 16't/ 5201'. Torque to 3100 ft/Ibs with Doyon casing double stack tongs. Test TEC wire every hour. Add Cannon Clamp every connection. 12 BPH loss rate.,RiH to 5252' Tag no-go w/ 10k (10.07' deeper than calculated). PN liner 1, to 5251'. Close annular & pressure up to 300 PSI to verify seal assembly in liner tie -back. UD 3joints for space out. PIU 3 pup joints & joint #168. 166 full banding clamps & 2 half clamps used. 80K PU / 70K SO.,C/O elevators to 5" OF, M/U head pin and XO on joint of 5" DP. M/U Hanger and terminate TEC wire per SLB rep. S/O while pumping 1.5 BPM - 60 psi to Located seals for displacement. PSI increase to 90. Shut down and pressure drop to Zero. Close Annular and pressure to 150 psi and strip up until pressure drop to zero. Open annular.,Drain fluid level in stack to below annular then close on landing joint. PJSM with rig crew and third party on freeze protect. Line up on annulus from mud pump via injection line and pump 150 bbis 1 % inhibited brine & 100 bbis diesel at 4 BPM. Initial circ pressure - 430 psi, final circ pressure - 630 psi. 35% loss rate while pumping.,Hauled 561 bbis H2O from L -Pad lake for total = 11716 bbis Hauled 0 bbis heated H2O from G&I = 430 Hauled 50 bbis cuttings/liquids to MPU GM for total = 18962 bbis 96 bbls daily losses. 492.2 bbis cumulative losses. Rig fuel (gallons): Rec'd=0, Used=1131 On hand=8007 3/30/2019 Finished pumping diesel freeze protect down the annulus with rig pumps. Fianl pressure 475 PSI. Shut down and slacked off closing ports in seal assembly. Bleed off pressure and drain stack. Good. Atempt to land hanger and unable to get last set of seals in LT. 3'shy. P/U & attempt to sting in and started getting flow out the annulus.,Continue to attempt to engage seals with no success. 10 attempts with set downs. Hanger at surface floating free. PJSM, Displace out diesel 191 bbl total. Well still flowing out the annulus. 10 PPG brine. Possible pressured up formation due to reverse circulating. Decide to continue another btm up through the gas buster and while flushing out gas buster it misted dirty bring out the vent.,Shut down and crew clean up brine mist to pad. Estimated 5 gal to pad. Thaw out uTube on Gas buster.,Open choke to pits and start pumps at 3 bpm. Monitor BBL in and out. Looking good. Check for flow. Static. open annular & circ at 6 bpm. Pump sweep to seals and work in LT until we saw pressure increase. PIU & increase flow rate to 10 BPM. Circ two btm up. Got back sweep and a good amount of sand. Circ until clean. Shut down and sting in seals and land hanger no problem.,RILD and test 9 5/6 X 31/2 to 3000 psi for 5 min. Bleed down and BOLD. Pull hanger out of profile and close annular. Put 250 psi on 9 518 X 31/2. P/U until we see pressure drop exposing ports. Shut down and prep for corrosion inhibiter displacement & Freeze protect. .,PJSM, Reverse circ corrosion inhibiter. Line up and circ 140 bbl down annulus taking returns up the tubing. Swap trucks and pump 192 bbl diesel. Final pressure 475 psi. Total of 331 bbis pumped, 267 bbis returned. 64 bbls Ioss.,Slack off and close ports. Bleed off pressure and open annular. Slack off to land hanger and string took weight V from landing. Close annular and pressure IA to 210 psi. Strip in V and land hanger. Bleed pressures off and RILDS. Return flow back from tubing with initial rate of 33 BPH and dropping. PU - 83K. SO - 71 k, 31 k set on hanger.,Perform MIT to 3150 psi Hold for 30 min on chart. Good A. Pumped 5.9 bbis, 5.9 bbis returned. Witness of MIT test waived by AOGCC Rep Jeffery Jones @ 17:09, 329/2019.,R/D landing joint, blow down lines free of fluid and install BPV. Vac fluid out of stack.,ND the BOP stack and rack back on the BOP stand. Secure BOPE for transport.,Clean the tubing hanger. NU the tubing head adapter and tree. Attempt to PT the tubing hanger void. Not able to achieve any stable pressure. Terminate the TEC wire.,Troubleshoot possible leaks, Tighten adapter flange nuts, pull cap and verify no oil in body, level tree and re -tighten adapter flange. C/O hydraulic pump.,PT the tubing hanger void to 500 psi for 5 minutes (good test) and 5000 psi for 15 minutes (good test).,Hauled 280 bbis H2O from L - Pad lake for total = 11996 bbls Hauled 0 bbls heated H2O from G&I = 430 Hauled 519 bbis cuttings/liquids to MPU G&I for total = 18962 bbls 179.5 bbls daily losses. 575.5 bbis cumulative losses. Rig fuel (gallons): Rec'd=0, Used=1278 On hand=6729 3/312019 Pull BPV & install TWC. Test tree to 5000 psi. -Good Test.,SLB rep function test downhole gauge - Pull TWC & install BPV.,PJSM, Rig up to freeze protect tubing. PT lines and bullhead 45 bbls diesel down tubing @ 1 bpm - FCP= 710psi„Blow down pumps & rig down lines. Clean out cellar box and secure cellar area. Rig released at 11:00 hours.,RDMO to M-04. See M-04 drilling report for details.,Hauled 0 bbls H2O from L-Pad lake for total = 11996 bbls Hauled 0 bbls heated H2O from G&I = 430 Hauled 15 bbls cuttings/liquids to MPU G&I for total = 18977 bbls Total 620.7 bbis loss to formation. Hilcorp Alaska, LLC Milne Point M Pt Moose Pad MPU M-11 MPU M-11 500292362100 Sperry Drilling Definitive Survey Report 25 March, 2019 HALLIBURTON Sperry Drilling Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-ordinate Reference: Well MPU M-11 Project: Milne Point TVD Reference: MPU M-11 Actual RKB @ 59.34usft Site: M Pt Moose Pad MD Reference: MPU M-11 Actual RKB @ 59.34usft Well: MPU M-11 North Reference: True Wellbore: MPU M-11 Survey Calculation Method: Minimum Curvature Design: MPU M-11 Database: NORTH US + CANADA Iroject Milne Point, ACT, MILNE POINT Map System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level Seo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point Map Zone: Alaska Zone 04 Using geodetic scale factor Well MPU M-11 Well Position +N/ -S +EI -W Position Uncertainty Wellbore MPU M-11 Magnetics Model Name 0.00 usft Northing: 6,027,889.61 usfl 0.00 usft Easting; 534,023.88 usfl 0.00 usft Wellhead Elevation: 25.00 usfl Sample Date Declination (`) User Defined 3,/5/2019 16.57 Latitude: 70° 29' 13.9935 N Longitude: 149° 43' 18.8653 W Ground Level: 25.00 usft Dip Angle Field Strength (') (nT) 80.99 57,477.00000000 Design MPU M-11 Audit Notes: Version: 1.0 Phase: ACTUAL Tie On Depth: 34.34 Vertical Section: Depth From (TVD) +N1S +E/ -W Direction (usft) (usft) (usft) (I 34.34 0.00 0.00 124.68 Survey Program Date 3/2512019 Map From To Vertical (usft) (usft) Survey (Wellbore) Tool Name Description Survey Date 223.06 5,337.33 MPU M-11 MWD+IFR2+MS+Sag(1)-Dt2_MWD+IFR2+MS+Sag A013Mb: IFR dec & multi -station analysis +sa 03101/2019 5,435.70 16,000.41 MPU M-11 MWD+IFR2+MS+Sag (2) (MF 2_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi -station analysis +sa 03/18/2019 Survey Map Map Vertical MD Inc Azi TVD TVDSS +N1S +EI -W Northing Easting DLS Section (usft) (1 (1) (usft) (usft) (usft) (usft) (ft) (ft) (°1100') (ft) Survey Tool Name 34.34 0.00 0.00 34.34 -25.00 000 0.00 6,027,889.61 534,023.88 0.00 0.00 UNDEFINED 223.06 1.08 227.05 223.05 163.71 -1.21 -1.30 6,027,888.39 534,022.58 0.57 -0.38 2_MWD+IFR2+MS+Sag(1) 317.79 1.55 219.64 317.75 258.41 -2.81 -2.77 6,027,886.79 534,021.12 0.53 -0.68 2_MWD+IFR2+MS+Sag(1) 413.20 0.56 287.42 413.15 353.81 -3.66 4.04 6,027,885.93 534,019.86 1.50 -1.24 2_MWD+1FR2+10S+Sag(1) 503.57 1.29 358.89 503.51 444.17 -2.51 -4.48 6,027,887.08 534,019.41 1.36 -2.26 2_MWD+IFR2+MS+Sag(1) 598.45 3.77 27.55 598.29 538.95 1.32 -3.06 6,027,890.92 534,020.81 2.86 -3.27 2_MWD+IFR2+MS+Sag(1) 693.16 7.64 40.15 692.52 633.18 8.90 2.44 6,027,898.52 534,026.28 4.27 -3.05 2_MWD+IFR2+MS+Sag(1) 788.33 12.35 53.70 786.23 726.89 19.77 14.73 6,027,909.44 534,038.52 5.50 0.87 2_MWD+IFR2+MS+Sag(1) 882.91 16.82 64.72 877.76 818.42 31.61 35.27 6,027,921.37 534,059.00 5.54 11.02 2_MWD+IFR2+MS+Sag(1) 976.73 21.48 69.02 966.36 907.02 43.56 63.60 6,027,933.46 534,087.28 5.19 27.52 2_MWD+IFR2+MS+Sag (1) 1,070.89 26.74 71.31 1,052.28 992.94 56.53 99.79 6,027,946.59 534,123.40 5.67 49.90 2_MWD+IFR2+MS+Sag(1) 1,166.29 31.11 73.82 1,135.76 1,076.42 70.28 143.81 6,027,960.54 534,167.36 4.75 78.27 2_MWD+IFR2+MS+Sag(1) 1,261.21 35.20 75.02 1,215.21 1,155.87 84.19 193.81 6,027,974.68 534,217.29 4.36 111.48 2_MWD+IFR2+MS+Sag (1) 3/152019 7:09.57PM Page 2 COMPASS 5000.15 Build 91 Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-ordinate Reference: Well MPU Mt -11 Project: Milne Point TVD Reference: MPU M-11 Actual RKB @ 59.34usft Site: M Pt Moose Pad MD Reference: MPU M-11 Actual RKB @ 59.34usft Well: MPU M-11 North Reference: True Wellbore: MPU M-11 Survey Calculation Method: Minimum Curvature Design: MPU M-11 Database: NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +N1 -S +E/ -W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°1100') (ft) Survey Tool Name 1,356.26 35.83 75.83 1,292.58 1,233.24 98.09 247.25 6,027,988.82 534,270.66 0.83 147.52 2_MWD+IFR2+MS+Sag(1) 1,450.29 36.45 75.92 1,368.52 1,309.18 111.62 301.03 6,028,002.59 534,324.37 0.66 184.04 2_MWD+IFR2+MS+Sag(1) 1,545.33 38.65 77.22 1,443.86 1,384.52 125.05 357.37 6,028,016.29 534,380.64 2.46 222.72 2_MWD+IFR2+MS+Sag(1) 1,640.65 38.13 78.48 1,518.58 1,459.24 137.52 415.23 6,028,029.01 534,438.44 0.99 263.22 2_MWD+IFR2+MS+Sag(1) 1,735.10 37.77 78.59 1,593.06 1,533.72 149.06 472.16 6,028,040.81 534,495.30 0.39 303.46 2_MWD+IFR2+MS+Sag(1) 1,830.15 37.16 79.53 1,668.50 1,609.16 160.04 528.92 6,028,052.05 534,552.01 0.88 343.89 2_MWD+IFR2+MS+Sag(1) 1,923.79 36.69 78.21 1,743.36 1,684.02 170.89 584.12 6,028,063.16 534,607.15 0.98 383.11 2 MWD+IFR2+MS+Sag(1) 2,018.56 38.53 77.19 1,818.43 1,759.09 183.22 640.62 6,028,075.74 534,663.59 2.05 422.56 2_MWD+IFR2+MS+Sag(1) 2,113.26 38.14 77.91 1,892.71 1,833.37 195.89 697.98 6,028,088.67 534,720.88 0.63 462.52 2_MWD+IFR2+MS+Sag(1) 2,208.41 39.87 77.30 1,966.65 1,907.31 208.75 756.46 6,028,101.79 534,779.30 1.86 503.30 2_MWD+IFR2+MS+Sag(1) 2,303.44 40.07 78.46 2,039.48 1,980.14 221.56 816.14 6,028,114.88 534,838.92 0.81 545.08 2_MWD+IFR2+MS+Sag(1) 2,397.38 39.30 78.50 2,111.77 2,052.43 233.54 874.92 6,028,127.13 534,897.64 0.82 586.60 2 MWD+IFR2+MS+Sag(1) 2,492.61 38.42 79.37 2,185.93 2,126.59 245.01 933.56 6,028,138.87 534,956.22 1.09 628.29 2_MWD+IFR2+MS+Sag(1) 2,587.62 38.79 80.17 2,260.17 2,200.83 255.54 991.90 6,028,149.66 535,014.50 0.65 670.28 2_MWD+IFR2+MS+Sag(1) 2,681.83 38.48 78.45 2,333.77 2,274.43 266.45 1,049.69 6,028,160.83 535,072.24 1.19 711.60 2_MWD+IFR2+MS+Sag(1) 2,776.09 39.39 77.01 2,407.09 2,347.75 279.04 1,107.57 6,028,173.69 535,130.05 1.36 752.03 2_MWD+IFR2+MS+Sag(1) 2,871.31 38.98 76.24 2,480.90 2,421.56 292.96 1,166.10 6,028,187.87 535,188.51 0.67 792.24 2_MWD+IFR2+MS+Sag(1) 2,965.73 37.22 75.85 2,555.20 2,495.86 307.00 1,222.64 6,028,202.17 535,244.98 1.88 830.75 2_MWD+IFR2+MS+Sag(1) 3,060.92 38.14 76.10 2,630.53 2,571.19 321.10 1,279.09 6,028,216.53 535,301.36 0.98 869.14 2_MWD+IFR2+MS+Sag(1) 3,155.68 39.02 76.07 2,704.61 2,645.27 335.31 1,336.45 6,028,231.00 535,358.65 0.93 908.23 2_MWD+IFR2+MS+Sag(1) 3,250.43 39.14 77.18 2,778.16 2,718.82 349.13 1,394.56 6,028,245.08 535,416.69 0.75 948.15 2_MWD+IFR2+MS+Sag(1) 3,344.46 38.91 77.22 2,851.21 2,791.87 362.25 1,452.29 6,028,258.46 535,474.36 0.25 988.17 2_MWD+IFR2+MS+Sag(1) 3,440.11 38.79 77.63 2,925.70 2,866.36 375.31 1,510.85 6,028,271.79 535,532.85 0.30 1,028.89 2 MWD+IFR2+MS+Sag(1) 3,533.81 38.58 78.11 2,998.84 2,939.50 387.62 1,568.11 6,028,284.36 535,590.05 0.39 1,068.97 2_MWD+IFR2+MS+Sag(1) 3,629.04 37.97 78.26 3,073.60 3,014.26 399.70 1,625.85 6,028,296.70 535,647.72 0.65 1,109.58 2_MWD+IFR2+MS+Sag(1) 3,724.70 38.81 78.54 3,148.58 3,089.24 411.64 1,684.04 6,028,308.91 535,705.85 0.90 1,150.64 2_MWD+IFR2+MS+Sag(1) 3,819.42 40.18 79.14 3,221.67 3,162.33 423.29 1,743.14 6,028,320.83 535,764.90 1.50 1,192.61 2_MWD+IFR2+MS+Sag(1) 3,915.29 41.13 81.71 3,294.41 3,235.07 433.67 1,804.72 6,028,331.49 535,826.42 2.01 1,237.35 2_MWD+IFR2+MS+Sag(1) 4,009.97 44.56 85.83 3,363.83 3,304.49 440.58 1,868.70 6,028,338.69 535,890.36 4.68 1,286.02 2_MWD+IFR2+MS+Sag (1) 4,103.09 45.88 89.70 3,429.43 3,370.09 443.13 1,934.72 6,028,341.54 535,956.36 3.27 1,338.87 2_MWD+IFR2+MS+Sag(1) 4,200.16 48.29 94.85 3,495.55 3,436.21 440.25 2,005.70 6,028,338.98 536,027.35 4.61 1,398.88 2_MWD+IFR2+MS+Sag (1) 4,295.13 51.63 100.38 3,556.67 3,497.33 430.53 2,077.70 6,028,329.60 536,099.38 5.68 1,463.61 2 MWD+IFR2+MS+Sag(1) 4,389.00 52.07 103.75 3,614.66 3,555.32 415.10 2,149.86 6,028,314.50 536,171.61 2.86 1,531.74 2_MWD+IFR2+MS+Sag(1) 4,484.21 55.95 106.18 3,670.61 3,611.27 395.18 2,224.25 6,028,294.92 536,246.08 4.57 1,604.25 2_MWD+IFR2+MS+Sag (1) 4,578.95 60.55 108.30 3,720.45 3,661.11 371.27 2,301.16 6,028,271.37 536,323.09 5.21 1,681.09 2_MWD+IFR2+MS+Sag(1) 4,672.74 64.75 110.07 3,763.53 3,704.19 343.88 2,379.81 6,028,244.34 536,401.85 4.78 1,761.35 2_MWD+IFR2+MS+Sag (1) 4,768.02 65.28 113.14 3,803.78 3,744.44 312.08 2,460.09 6,028,212.91 536,482.27 2.97 1,845.46 2_MWD+IFR2+MS+Sag(1) 4,863.10 69.23 115.07 3,840.54 3,781.20 276.26 2,540.10 6,028,177.46 536,562.44 4.56 1,931.64 2_MWD+IFR2+MS+Sag(1) 4,957.30 72.41 116.18 3,871.49 3,812.15 237.78 2,620.30 6,028,139.35 536,642.81 3.55 2,019.49 2_MWD+IFR2+MS+Sag (1) 5,051.84 77.11 118.41 3,896.33 3,836.99 195.95 2,701.32 6,028,097.89 536,724.01 5.47 2,109.92 2_MWD+IFR2+MS+Sag (1) 3,15/1019 7:09:57PM Page 3 COMPASS 5000.15 Build 91 Survey Map MD Inc Azi TVD TVDSS +N/ -S +E/ -W Northing (usft) (1) (1) (usft) (usft) (usft) (usft) (ft) 5,145.83 80.05 119.99 3,914.94 3,855.60 151.00 2,781.73 6,028,053.32 5,242.40 83.38 122.75 3,928.86 3,869.52 101.26 2,863.30 6,028,003.96 5,337.33 85.92 126.06 3,937.71 3,878.37 47.86 2,941.26 6,027,950.92 5,435.70 89.45 127.60 3,941.68 3,882.34 -11.05 3,019.92 6,027,892.38 5,447.28 89.09 128.02 3,941.83 3,882.49 -18.15 3,029.07 6,027,885.32 5,490.86 89.39 127.89 3,942.41 3,883.07 44.95 3,063.43 6,027,858.68 5,542.46 89.81 126.67 3,942.77 3,883.43 -76.20 3,104.48 6,027,827.62 5,590.83 88.89 125.18 3,943.32 3,883.98 -104.58 3,143.65 6,027,799.43 5,637.45 89.45 125.60 3,943.99 3,884.65 -131.57 3,181.65 6,027,772.61 5,686.35 89.02 124.89 3,944.65 3,885.31 -159.79 3,221.58 6,027,744.58 5,732.91 88.40 123.92 3,945.70 3,886.36 -186.09 3,259.98 6,027,718.45 5,781.73 88.47 123.90 3,947.03 3,887.69 -213.32 3,300.49 6,027,691.41 5,828.06 88.71 123.44 3,948.17 3,888.83 -238.99 3,339.03 6,027,665.92 5,875.99 89.39 124.33 3,948.96 3,889.62 -265.71 3,378.82 6,027,639.38 5,923.59 88.90 124.58 3,949.67 3,890.33 -292.64 3,418.06 6,027,612.64 5,972.03 88.09 123.87 3,950.95 3,891.61 -319.87 3,458.10 6,027,585.59 6,018.79 88.53 122.60 3,952.32 3,892.98 -345.49 3,497.19 6,027,560.15 6,067.25 88.22 121.60 3,953.70 3,894.36 -371.23 3,538.23 6,027,534.60 6,113.34 88.72 121.70 3,954.93 3,895.59 -395.41 3,577.45 6,027,510.61 6,163.18 89.89 122.74 3,955.53 3,896.19 -421.98 3,619.61 6,027,484.24 6,206.32 89.76 124.62 3,955.67 3,896.33 -445.90 3,655.50 6,027,460.48 6,257.61 88.90 125.70 3,956.27 3,896.93 475.43 3,697.43 6,027,431.14 6,304.35 89.33 126.31 3,956.99 3,897.65 -502.91 3,735.24 6,027,403.84 6,352.94 88.58 126.31 3,957.87 3,898.53 -531.67 3,774.39 6,027,375.26 6,399.45 86.85 125.52 3,959.73 3,900.39 -558.93 3,812.02 6,027,348.18 6,449.83 85.86 125.16 3,962.93 3,903.59 -588.02 3,853.04 6,027,319.28 6,494.83 85.61 125.27 3,966.28 3,906.94 -613.89 3,889.70 6,027,293.58 6,542.53 85.50 124.93 3,969.97 3,910.63 -641.24 3,928.61 6,027,266.41 6,590.37 85.37 124.52 3,973.78 3,914.44 -668.40 3,967.80 6,027,239.43 6,641.04 85.50 123.80 3,977.82 3,918.48 -696.76 4,009.60 6,027,211.26 6,686.01 86.24 123.38 3,981.05 3,921.71 -721.58 4,046.96 6,027,186.62 6,734.09 85.37 122.51 3,984.57 3,925.23 -747.66 4,087.20 6,027,160.73 6,780.94 85.87 123.37 3,988.15 3,928.81 -773.06 4,126.40 6,027,135.51 6,831.77 86.80 124.35 3,991.40 3,932.06 -801.32 4,168.52 6,027,107.45 6,876.50 85.37 124.42 3,994.45 3,935.11 -826.52 4,205.35 6,027,082.42 6,927.97 86.18 124.52 3,998.24 3,938.90 -855.57 4,247.67 6,027,053.56 6,972.33 86.37 124.42 4,001.13 3,941.79 -880.63 4,284.16 6,027,028.68 7,023.11 86.36 123.73 4,004.35 3,945.01 -909.02 4,326.14 6,027,000.48 7,066.96 86.36 123.50 4,007.13 3,947.79 -933.25 4,362.58 6,026,976.42 7,160.93 86.43 122.83 4,013.04 3,953.70 -984.55 4,441.09 6,026,925.48 Map Vertical Easting DLS Section (ft) (-/100-) (ft) Survey Tool Name 536,804.62 3.54 2,201.62 2_MWD+IFR2+MS+Sag(1) 536,886.40 4.46 2,297.00 2_MWD+IFR2+MS+Sag (1) 536,964.60 4.38 2,391.49 2_MWD+IFR2+MS+Sag(1) 537,043.52 3.91 2,489.69 2_MWD+IFR2+MS+Sag(2) 537,052.70 4.78 2,501.25 2_MWD+IFR2+MS+Sag (2) 537,087.18 0.75 2,544.76 2_MWD+IFR2+MS+Sag(2) 537,128.37 2.50 2,596.30 2 MWD+IFR2+MS+Sag(2) 537,167.66 3.62 2,644.66 2_MWD+IFR2+MS+Sag(2) 537,205.78 1.50 2,691.27 2_MWD+IFR2+MS+Sag(2) 537,245.84 1.70 2,740.16 2_MWD+IFR2+MS+Sag (2) 537,284.36 2.47 2,786.71 2_MWD+IFR2+MS+Sag(2) 537,324.98 0.15 2,835.51 2 MWD+IFR2+MS+Sag(2) 537,363.64 1.12 2,881.81 2_MWD+IFR2+MS+Sag(2) 537,403.54 2.34 2,929.73 2_MWD+IFR2+MS+Sag(2) 537,442.91 1.16 2,977.33 2_MWD+IFR2+MS+Sag(2) 537,483.06 2.22 3,025.75 2_MWD+IFR2+MS+Sag (2) 537,522.27 2.87 3,072.47 2_MWD+IFR2+MS+Sag(2) 537,563.42 2.16 3,120.86 2_MWD+IFR2+MS+Sag(2) 537,602.75 1.11 3,166.87 2 MWD+IFR2+MS+Sag(2) 537,645.02 3.14 3,216.66 2_MWD+IFR2+MS+Sag (2) 537,681.03 4.37 3,259.79 2_MWD+IFR2+MS+Sag (2) 537,723.08 2.69 3,311.08 2_MWD+IFR2+MS+Sag (2) 537,761.01 1.60 3,357.80 2_MWD+IFR2+MS+Sag (2) 537,800.29 1.54 3,406.36 2_MWD+IFR2+MS+Sag (2) 537,838.04 4.09 3,452.82 2_MWD+IFR2+MS+Sag (2) 537,879.19 2.09 3,503.09 2_MWD+IFR2+MS+Sag (2) 537,915.96 0.61 3,547.97 2_MWD+IFR2+MS+Sag (2) 537,954.99 0.75 3,595.52 2_MWD+IFR2+MS+Sag(2) 537,994.31 0.90 3,643.21 2_MWD+IFR2+MS+Sag(2) 538,036.23 1.44 3,693.72 2_MWD+IFR2+MS+Sag(2) 538,073.70 1.89 3,738.56 2_MWD+IFR2+MS+Sag (2) 538,114.05 2.56 3,786.49 2_MWD+IFR2+MS+Sag (2) 538,153.37 2.12 3,833.18 2_MWD+IFR2+MS+Sag (2) 538,195.62 2.66 3,883.90 2_MWD+IFR2+MS+Sag (2) 538,232.55 3.20 3,928.52 2_MWD+IFR2+MS+Sag (2) 538,275.00 1.59 3,979.85 2_MWD+IFR2+MS+Sag (2) 538,311.60 0.48 4,024.12 2_MWD+IFR2+MS+Sag (2) 538,353.71 1.36 4,074.79 2_MWD+IFR2+MS+Sag (2) 538,390.26 0.52 4,118.55 2_MWD+IFR2+MS+Sag (2) 538,468.99 0.72 4,212.30 2_MWD+IFR2+MS+Sag (2) 3/25/2019 7:09:57PM Page 4 COMPASS 5000.15 Build 91 Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-ordinate Reference: Well MPU N1.11 Project: Milne Point TVD Reference: MPU M-11 Actual RKB @ 59.34usft Site: M Pt Moose Pad MD Reference: MPU M-11 Actual RKB @ 59.34usft Well: MPU M-11 North Reference: True Wellbore: MPU M-11 Survey Calculation Method: Minimum Curvature Design: MPU M-11 Database: NORTH US+CANADA Survey Map MD Inc Azi TVD TVDSS +N/ -S +E/ -W Northing (usft) (1) (1) (usft) (usft) (usft) (usft) (ft) 5,145.83 80.05 119.99 3,914.94 3,855.60 151.00 2,781.73 6,028,053.32 5,242.40 83.38 122.75 3,928.86 3,869.52 101.26 2,863.30 6,028,003.96 5,337.33 85.92 126.06 3,937.71 3,878.37 47.86 2,941.26 6,027,950.92 5,435.70 89.45 127.60 3,941.68 3,882.34 -11.05 3,019.92 6,027,892.38 5,447.28 89.09 128.02 3,941.83 3,882.49 -18.15 3,029.07 6,027,885.32 5,490.86 89.39 127.89 3,942.41 3,883.07 44.95 3,063.43 6,027,858.68 5,542.46 89.81 126.67 3,942.77 3,883.43 -76.20 3,104.48 6,027,827.62 5,590.83 88.89 125.18 3,943.32 3,883.98 -104.58 3,143.65 6,027,799.43 5,637.45 89.45 125.60 3,943.99 3,884.65 -131.57 3,181.65 6,027,772.61 5,686.35 89.02 124.89 3,944.65 3,885.31 -159.79 3,221.58 6,027,744.58 5,732.91 88.40 123.92 3,945.70 3,886.36 -186.09 3,259.98 6,027,718.45 5,781.73 88.47 123.90 3,947.03 3,887.69 -213.32 3,300.49 6,027,691.41 5,828.06 88.71 123.44 3,948.17 3,888.83 -238.99 3,339.03 6,027,665.92 5,875.99 89.39 124.33 3,948.96 3,889.62 -265.71 3,378.82 6,027,639.38 5,923.59 88.90 124.58 3,949.67 3,890.33 -292.64 3,418.06 6,027,612.64 5,972.03 88.09 123.87 3,950.95 3,891.61 -319.87 3,458.10 6,027,585.59 6,018.79 88.53 122.60 3,952.32 3,892.98 -345.49 3,497.19 6,027,560.15 6,067.25 88.22 121.60 3,953.70 3,894.36 -371.23 3,538.23 6,027,534.60 6,113.34 88.72 121.70 3,954.93 3,895.59 -395.41 3,577.45 6,027,510.61 6,163.18 89.89 122.74 3,955.53 3,896.19 -421.98 3,619.61 6,027,484.24 6,206.32 89.76 124.62 3,955.67 3,896.33 -445.90 3,655.50 6,027,460.48 6,257.61 88.90 125.70 3,956.27 3,896.93 475.43 3,697.43 6,027,431.14 6,304.35 89.33 126.31 3,956.99 3,897.65 -502.91 3,735.24 6,027,403.84 6,352.94 88.58 126.31 3,957.87 3,898.53 -531.67 3,774.39 6,027,375.26 6,399.45 86.85 125.52 3,959.73 3,900.39 -558.93 3,812.02 6,027,348.18 6,449.83 85.86 125.16 3,962.93 3,903.59 -588.02 3,853.04 6,027,319.28 6,494.83 85.61 125.27 3,966.28 3,906.94 -613.89 3,889.70 6,027,293.58 6,542.53 85.50 124.93 3,969.97 3,910.63 -641.24 3,928.61 6,027,266.41 6,590.37 85.37 124.52 3,973.78 3,914.44 -668.40 3,967.80 6,027,239.43 6,641.04 85.50 123.80 3,977.82 3,918.48 -696.76 4,009.60 6,027,211.26 6,686.01 86.24 123.38 3,981.05 3,921.71 -721.58 4,046.96 6,027,186.62 6,734.09 85.37 122.51 3,984.57 3,925.23 -747.66 4,087.20 6,027,160.73 6,780.94 85.87 123.37 3,988.15 3,928.81 -773.06 4,126.40 6,027,135.51 6,831.77 86.80 124.35 3,991.40 3,932.06 -801.32 4,168.52 6,027,107.45 6,876.50 85.37 124.42 3,994.45 3,935.11 -826.52 4,205.35 6,027,082.42 6,927.97 86.18 124.52 3,998.24 3,938.90 -855.57 4,247.67 6,027,053.56 6,972.33 86.37 124.42 4,001.13 3,941.79 -880.63 4,284.16 6,027,028.68 7,023.11 86.36 123.73 4,004.35 3,945.01 -909.02 4,326.14 6,027,000.48 7,066.96 86.36 123.50 4,007.13 3,947.79 -933.25 4,362.58 6,026,976.42 7,160.93 86.43 122.83 4,013.04 3,953.70 -984.55 4,441.09 6,026,925.48 Map Vertical Easting DLS Section (ft) (-/100-) (ft) Survey Tool Name 536,804.62 3.54 2,201.62 2_MWD+IFR2+MS+Sag(1) 536,886.40 4.46 2,297.00 2_MWD+IFR2+MS+Sag (1) 536,964.60 4.38 2,391.49 2_MWD+IFR2+MS+Sag(1) 537,043.52 3.91 2,489.69 2_MWD+IFR2+MS+Sag(2) 537,052.70 4.78 2,501.25 2_MWD+IFR2+MS+Sag (2) 537,087.18 0.75 2,544.76 2_MWD+IFR2+MS+Sag(2) 537,128.37 2.50 2,596.30 2 MWD+IFR2+MS+Sag(2) 537,167.66 3.62 2,644.66 2_MWD+IFR2+MS+Sag(2) 537,205.78 1.50 2,691.27 2_MWD+IFR2+MS+Sag(2) 537,245.84 1.70 2,740.16 2_MWD+IFR2+MS+Sag (2) 537,284.36 2.47 2,786.71 2_MWD+IFR2+MS+Sag(2) 537,324.98 0.15 2,835.51 2 MWD+IFR2+MS+Sag(2) 537,363.64 1.12 2,881.81 2_MWD+IFR2+MS+Sag(2) 537,403.54 2.34 2,929.73 2_MWD+IFR2+MS+Sag(2) 537,442.91 1.16 2,977.33 2_MWD+IFR2+MS+Sag(2) 537,483.06 2.22 3,025.75 2_MWD+IFR2+MS+Sag (2) 537,522.27 2.87 3,072.47 2_MWD+IFR2+MS+Sag(2) 537,563.42 2.16 3,120.86 2_MWD+IFR2+MS+Sag(2) 537,602.75 1.11 3,166.87 2 MWD+IFR2+MS+Sag(2) 537,645.02 3.14 3,216.66 2_MWD+IFR2+MS+Sag (2) 537,681.03 4.37 3,259.79 2_MWD+IFR2+MS+Sag (2) 537,723.08 2.69 3,311.08 2_MWD+IFR2+MS+Sag (2) 537,761.01 1.60 3,357.80 2_MWD+IFR2+MS+Sag (2) 537,800.29 1.54 3,406.36 2_MWD+IFR2+MS+Sag (2) 537,838.04 4.09 3,452.82 2_MWD+IFR2+MS+Sag (2) 537,879.19 2.09 3,503.09 2_MWD+IFR2+MS+Sag (2) 537,915.96 0.61 3,547.97 2_MWD+IFR2+MS+Sag (2) 537,954.99 0.75 3,595.52 2_MWD+IFR2+MS+Sag(2) 537,994.31 0.90 3,643.21 2_MWD+IFR2+MS+Sag(2) 538,036.23 1.44 3,693.72 2_MWD+IFR2+MS+Sag(2) 538,073.70 1.89 3,738.56 2_MWD+IFR2+MS+Sag (2) 538,114.05 2.56 3,786.49 2_MWD+IFR2+MS+Sag (2) 538,153.37 2.12 3,833.18 2_MWD+IFR2+MS+Sag (2) 538,195.62 2.66 3,883.90 2_MWD+IFR2+MS+Sag (2) 538,232.55 3.20 3,928.52 2_MWD+IFR2+MS+Sag (2) 538,275.00 1.59 3,979.85 2_MWD+IFR2+MS+Sag (2) 538,311.60 0.48 4,024.12 2_MWD+IFR2+MS+Sag (2) 538,353.71 1.36 4,074.79 2_MWD+IFR2+MS+Sag (2) 538,390.26 0.52 4,118.55 2_MWD+IFR2+MS+Sag (2) 538,468.99 0.72 4,212.30 2_MWD+IFR2+MS+Sag (2) 3/25/2019 7:09:57PM Page 4 COMPASS 5000.15 Build 91 Company: Project: Site: Well: Wellbore: Design: Survey Hilcorp Alaska, LLC Milne Pcint M Pt Moose Pad MPU M-11 MPU M-11 MPU M-11 Halliburton Definitive Survey Report Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Database: Well MPU M-11 MPU M-11 Actual RKB @ 59.34usH MPU M-11 Actual RKB @ 59.34usft True Minimum Curvature NORTH US+CANADA Map Map Vertical MD Inc Azi TVD TVDSS +NI -S +El -W Northing Easting DLS Section (usft) (1) 0 (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (1t) Survey Tool Name 7,257.97 86.61 121.68 4,018.93 3,959.59 .1,036.24 4,523.00 6,026,874.17 538,551.13 1.20 4,309.07 2_MWD+IFR2+MS+Sag(2) 7,352.87 86.67 121.54 4,024.49 3,965.15 -1,085.90 4,603.68 6,026,824.89 538,632.03 0.16 4,403.67 2_MWD+IFR2+MS+Sag(2) 7,401.53 86.80 121.05 4,027.26 3,967.92 -1,111.13 4,645.19 6,026,799.85 538,673.65 1.04 4,452.17 2_MWD+IFR2+MS+Sog(2) 7,448.36 86.92 121.37 4,029.83 3,970.49 -1,135.36 4,685.19 6,026,775.80 538,713.75 0.73 4,498.84 2_MWD+IFR2+MS+Sag (2) 7,498.75 86.73 121.22 4,032.62 3,973.28 -1,161.50 4,728.18 6,026,749.87 538,756.86 0.48 4,549.07 2 MWD+IFR2+MS+Sag (2) 7,543.18 85.93 121.84 4,035.46 3,976.12 -1,184.68 4,765.97 6,026,726.86 538,794.75 2.28 4,593.34 2_MWD+IFR2+MS+Sag(2) 7,594.33 86.37 121.64 4,038.90 3,979.56 -1,211.53 4,809.37 6,026,700.21 538,838.27 0.94 4,644.31 2_MWD+IFR2+MS+Sag(2) 7,638.36 86.92 123.39 4,041.47 3,982.13 -1,235.16 4,846.44 6,026,676.76 538,875.44 4.16 4,688.23 2_MWD+IFR2+MS+Sag(2) 7,687.08 87.91 125.30 4,043.67 3,984.33 -1,262.61 4,886.62 6,026,649.49 538,915.74 4.41 4,736.89 2_MWD+IFR2+MS+Sag(2) 7,733.02 88.78 126.51 4,045.00 3,985.66 -1,289.54 4,923.81 6,026,622.73 538,953.06 3.24 4,782.80 2_MWD+IFR2+MS+Sag(2) 7,782.39 90.63 127.63 4,045.25 3,985.91 -1,319.30 4,963.20 6,026,593.16 538,992.58 4.38 4,832.13 2_MWD+IFR2+MS+Sag(2) 7,828.23 90.81 127.95 4,044.68 3,985.34 -1,347.39 4,999.43 6,026,565.24 539,028.92 0.80 4,877.89 2_MWD+IFR2+MS+Sag(2) 7,877.08 90.75 126.76 4,044.01 3,984.67 -1,377.02 5,038.25 6,026,535.78 539,067.88 2.44 4,926.69 2_MWD+IFR2+MS+Sag(2) 7,924.69 90.56 127.32 4,043.47 3,984.13 -1,405.70 5,076.25 6,026,507.28 539,106.01 1.24 4,974.25 2_MWD+IFR2+MS+Sag (2) 7,972.66 91.12 127.13 4,042.76 3,983.42 -1,434.72 5,114.44 6,026,478.45 539,144.33 1.23 5,022.17 2_MWD+IFR2+MS+Sag(2) 8,018.04 92.92 127.44 4,041.16 3,981.82 -1,462.19 5,150.53 6,026,451.14 539,180.53 4.02 5,067.47 2_MWD+IFR2+MS+Sag(2) 8,115.17 94.15 126.15 4,035.17 3,975.83 -1,520.25 5,228.16 6,026,393.44 539,258.42 1.83 5,164.35 2_MWD+IFR2+MS+Sag (2) 8,209.12 94.52 126.45 4,028.07 3,968.73 -1,575.71 5,303.66 6,026,338.33 539,334.16 0.51 5,257.99 2_MWD+IFR2+MS+Sag (2) 8,303.27 94.65 125.91 4,020.55 3,961.21 -1,631.11 5,379.41 6,026,283.28 539,410.16 0.59 5,351.81 2_MWD+IFR2+MS+Sag (2) 8,399.47 94.46 125.56 4,012.91 3,953.57 -1,687.12 5,457.25 6,026,227.64 539,488.25 0.41 5,447.69 2_MWD+IFR2+MS+Sag (2) 8,495.26 94.15 125.19 4,005.72 3,946.38 -1,742.42 5,535.13 6,026,172.70 539,566.38 0.50 5,543.20 2_MWD+IFR2+MS+Seg(2) 8,587.25 93.65 124.57 3,999.46 3,940.12 -1,794.90 5,610.42 6,026,120.57 539,641.90 0.86 5,634.98 2_MWD+IFR2+MS+Sag (2) 8,683.84 93.59 124.21 3,993.36 3,934.02 -1,849.35 5,689.97 6,026,066.49 539,721.69 0.38 5,731.37 2_MWD+IFR2+MS+Sag (2) 8,780.92 92.42 123.87 3,988.27 3,928.93 -1,903.62 5,770.30 6,026,012.60 539,802.26 1.25 5,828.31 2_MWD+IFR2+MS+Sag (2) 8,876.04 92.42 124.44 3,984.26 3,924.92 .1,956.97 5,848.95 6,025,959.61 539,881.14 0.60 5,923.34 2_MWD+IFR2+MS+Sag(2) 8,971.57 90.25 125.17 3,982.03 3,922.69 -2,011.48 5,927.36 6,025,905.46 539,959.79 2,40 6,018,84 2_MWD+IFR2+MS+Sag(2) 9,068.82 90.13 124.60 3,981.71 3,922.37 -2,067.10 6,007.13 6,025,850.21 540,039.81 0.60 6,116.09 2_MWD+IFR2+MS+Sag (2) 9,163.96 89.51 122.11 3,982.01 3,922.67 -2,119.41 6,086.59 6,025,798.28 540,119.50 2.70 6,211.19 2_MWD+IFR2+MS+Sag(2) 9,259.21 89.70 121.18 3,982.66 3,923.32 -2,169.38 6,167.68 6,025,748.68 540,200.81 1.00 6,306.31 2_MWD+IFR2+MS+Sag(2) 9,354.36 90.07 123.05 3,982.85 3,923.51 -2,219.96 6,248.27 6,025,698.48 540,281.62 2.00 6,401.36 2_MWD+IFR2+MS+Sag (2) 9,450.36 89.88 120.82 3,982.90 3,923.56 -2,270.74 6,329.73 6,025,648.08 540,363.31 2.33 6,497.24 2_MWD+IFR2+MS+Sag (2) 9,544.41 90.88 120.94 3,982.27 3,922.93 -2,319.00 6,410.45 6,025,600.18 540,444.23 1.07 6,591.08 2_MWD+IFR2+MS+Sag (2) 9,639.55 90.63 122.78 3,981.02 3,921.68 -2,369.22 6,491.24 6,025,550.35 540,525.25 1.95 6,686.09 2_MWD+IFR2+MS+Sag(2) 9,691.53 90.50 122.71 3,980.51 3,921.17 -2,397.33 6,534.96 6,025,522.43 540,569.09 0.28 6,738.04 2_MWD+IFR2+MS+Sag(2) 9,735.87 90.38 124.13 3,980.17 3,920.83 -2,421.75 6,571.97 6,025,498.19 540,606.21 3.21 6,782.37 2_MWD+IFR2+MS+Sag(2) 9,784.39 89.14 123.79 3,980.37 3,921.03 -2,448.86 6,612.21 6,025,471.27 540,646.57 2.65 6,830.88 2_MWD+IFR2+MS+Sag(2) 9,828.70 87.10 123.93 3,981.82 3,922.48 -2,473.53 6,648.98 6,025,446.77 540,683.45 4.61 6,875.16 2_MWD+IFR2+MS+Sag(2) 9,878.06 85.87 123.25 3,984.85 3,925.51 -2,500.79 6,690.02 6,025,419.70 540,724.61 2.85 6,924.42 2_MWD+IFR2+MS+Sag(2) 9,926.23 86.30 125.19 3,988.14 3,928.80 -2,527.81 6,729.76 6,025,392.86 540,764.47 4.12 6,972.47 2_MWD+IFR2+MS+Sag(2) 10,021.26 87.54 128.52 3,993.25 3,933.91 -2,584.72 6,805.67 6,025,336.31 540,840.63 3.73 7,067.28 2_MWD+IFR2+MS+Sag(2) 3252019 7:09:57PM Page 5 COMPASS 5000.15 Build 91 Company: Project: Site: Well: Wellbore: Design: Survey Hilcorp Alaska, LLC Milne Point M Pt Moose Pad MPU M-11 MPU M-11 MPU M-11 MD Inc (usft) (°) 10,116.73 87.23 10,212.53 88.65 10,307.16 89.70 10,401.56 90.26 10,498.08 89.88 10,593.53 90.07 10,689.58 89.82 10,784.21 90.32 10,880.07 89.70 10,975.23 90.13 11,070.80 89.20 11,166.11 91.31 11,261.13 92.36 11,356.34 92.05 11,451.25 92.42 11,546.27 91.49 11,639.61 90.44 11,735.62 91.24 11,829.81 89.82 11,924.53 90.38 12,019.03 89.88 12,114.01 91.68 12,208.75 90.87 12,303.63 90.01 12,397.34 85.93 12,492.57 84.88 12,586.97 87.17 Halliburton Definitive Survey Report Local Coordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Database: 129.93 129.17 128.81 127.49 125.19 122.81 123.23 124.00 123.10 122.42 124.18 125.56 125.68 126.47 126.10 4,002.41 4,002.44 4,002.32 4,002.36 4,002.46 4,002.34 4,002.32 4,002.47 4,003.02 4,002.60 3,999.56 3,995.89 3,992.19 3,988.95 3,987.38 3,943.07 3,943.10 3,942.98 3,943.02 3,943.12 3,943.00 3,942.98 3,943.13 3,943.68 3,943.26 3,940.22 3,936.55 3,932.85 3,929.61 3,928.04 -2,765.81 -2,825.92 -2,886.64 -2,945.60 -3,002.52 -3,055.43 -3,107.67 -3,160.35 -3,213.16 -3,264.73 -3,316.87 -3,371.26 -3,426.50 -3,482.42 .3,537.65 127.11 3,985.97 3,926.63 -3,594.89 124.95 3,985.10 3,925.76 -3,650.29 124.10 3,984.93 3,925.59 -3,703.97 123.77 3,984.72 3,925.38 -3,756.72 124.72 3,983.43 3,924.09 -3,810.16 124.76 3,981.32 3,921.98 124.66 3,980.59 3,921.25 124.17 3,983.91 3,924.57 124.47 3,991.54 3,932.20 124.44 3,998.08 3,938.74 12,681.69 87.35 123.92 4,002.61 12,776.40 87.17 123.57 4,007.14 12,870.37 87.10 123.42 4,011.83 12,964.93 88.78 124.51 4,015.23 13,060.18 88.40 125.80 4,017.58 13,155.81 88.16 125.54 4,020.45 13,249.97 88.16 125.49 4,023.47 13,345.00 88.22 124.82 4,026.47 13,440.52 87.72 125.11 4,029.86 13,534.19 88.22 125.34 4,033.17 13,629.87 89.45 124.93 4,035.12 13,724.56 89.64 124.98 4,035.87 13,819.53 89.64 124.93 4,036.47 3,943.27 3,947.80 3,952.49 3,955.89 3,958.24 3,961.11 3,964.13 3,967.13 3,970.52 3,973.83 3,975.78 3,976.53 3,977.13 -3,864.14 .3,918.16 -3,971.08 -4,024.60 -4,077.88 -4,131.03 -4,183.58 -4,235.37 4,288.17 4,342.99 4,398.73 4,453.40 4,508.09 -4,562.80 4,616.79 4,671.84 4,726.09 4,780.50 7,026.66 6,025,156.25 7,099.45 6,025,096.48 7,174.47 6,025,036.10 7,249.53 6,024,977.49 7,326.89 6,024,920.94 7,405.34 6,024,868.39 7,485.71 6,024,816.53 7,564.96 6,024,764.21 7,644.60 6,024,711.77 7,724.75 6,024,660.57 7;804.12 6,024,608.80 7,882.18 6,024,554.77 7,959.27 6,024,499.90 8,036.02 6,024,444.33 8,111.25 6,024,389.45 8,188.32 6,024,332.57 8,264.48 6,024,277.53 8,342.51 6,024,224.21 8,420.92 6,024,171.82 B,499.42 6,024,118.74 8,577.25 6,024,065.13 8,655.25 6,024,011.47 8,732.49 6,023,958.91 8,810.88 6,023,905.75 8,888.53 6,023,852.84 8,966.80 6,023,800.05 9,045.46 6,023,747.87 9,123.73 6,023,696.44 9,202.10 6,023,644.01 9,279.95 6,023,589.54 9,357.61 6,023,534.17 9,434.21 6,023,479.85 9,511.87 6,023,425.52 9,590.10 6,023,371.18 9,666.57 6,023,317.54 9,744.80 6,023,262.86 9,822.40 6,023,208.97 9,900.24 6,023,154.92 Well MPU M-11 MPU M-11 Actual RKB @ 59.34usft MPU M-11 Actual RKB @ 59.34usft True Minimum Curvature NORTH US + CANADA Map Vertical Easting DLS Section (ft) (-Itoo,) (ft) Survey Tool Name 540,915.48 0.33 7,162.43 2_MWD+IFR2+MS+Sag (2) 540,989.73 2.23 7,257.84 2_MWD+IFR2+MS+Sag (2) 541,062.42 1.14 7,352.04 2_MWD+IFR2+MS+Sag (2) 541,135.48 1.00 7,446.10 2_MWD+IFR2+MS+Sag (2) 541,210.77 0.54 7,542.35 2_MWD+IFR2+MS+Sag (2) 541,286.09 1.40 7,637.62 2_MWD+IFR2+MS+Sag (2) 541,363.71 2.41 7,733.62 2_MWD+IFR2+MS+Sag (2) 541,442.38 2.57 7,828.24 2_MWD+IFR2+MS+Sag(2) 541,522.99 0.78 7,924.06 2_MWD+IFR2+MS+Sag(2) 541,602.47 0.93 8,019.20 2_MWD+IFR2+MS+Sag (2) 541,682.35 1.35 8,114.75 2_MWD+IFR2+MS+Sag(2) 541,762.72 2.33 8,210.00 2_MWD+IFR2+MS+Sag(2) 541,842.32 2.16 8,304.94 2_MWD+IFR2+MS+Sag(2) 541,920.62 1.48 8,400.08 2_MWD+IFR2+MS+Sag(2) 541,997.96 0.41 8,494.90 2_MWD+IFR2+MS+Sag (2) 542,074.96 1.28 8,589.83 2_MWD+IFR2+MS+Sag (2) 542,150.43 1.19 8,683.12 2_MWD+IFR2+MS+Sag (2) 542,227.75 1.34 8,779.07 2_MWD+IFR2+MS+Sag (2) 542,304.15 2.74 8,873.22 2_MWD+IFR2+MS+Sag (2) 542,382.43 1.07 8,967.94 2_MWD+IFR2+MS+Sag (2) 542,461.06 0.63 9,062.43 2_MWD+IFR2+MS+Sag (2) 542,539.80 2.14 9,157.39 2_MWD+IFR2+MS+Sag (2) 542,617.87 0.86 9,252.11 2_MWD+IFR2+MS+Sag (2) 542,696.11 0.91 9,346.98 2_MWD+IFR2+MS+Sag (2) 542,773.58 4.39 9,440.61 2_MWD+IFR2+MS+Sag(2) 542,852.21 1.15 9,535.53 2_MWD+IFR2+MS+Sag(2) 542,930.10 2.43 9,629.70 2_MWD+IFR2+MS+Sag (2) 543,008.60 0.58 9,724.31 2_MWD+IFR2+MS+Sag (2) 543,087.50 0.42 9,818.90 2_MWD+IFR2+MS+Sag (2) 543,165.99 0.18 9,912.73 2 MWD+IFR2+MS+Sag(2) 543,244.59 2.12 10,007.22 2_MWD+IFR2+MS+Sag(2) 543,322.69 1.41 10,102.43 2_MWD+IFR2+MS+Sag(2) 543,400.59 0.37 10,198.00 2_MWD+IFR2+MS+Sag(2) 543,477.43 0.05 10,292.11 2_MWD+IFR2+MS+Sag(2) 543,555.33 0.71 10,387.08 2_MWD+IFR2+MS+Sag(2) 543,633.80 0.61 10,482.54 2_MWD+IFR2+MS+Sag(2) 543,710.51 0.59 10,576.15 2_MWD+IFR2+MS+Sag(2) 543,788.98 1.36 10,671.80 2_MWD+IFR2+MS+Sag(2) 543,866.83 0.21 10,766.49 2_MWD+IFR2+MS+Sag(2) 543,944.91 0.05 10,861.46 2_MWD+IFR2+MS+Sag(2) 3,252019 7:09:57PM Page 6 COMPASS 5000.15 Build 91 Map Azi TVD TVDSS +N/ -S +E/.W Northing (1) (usft) (usft) (usft) (usft) (ft) 128.59 3,997.60 3,938.26 -2,644.16 6,880.25 6,025,277.21 130.19 001.04 3,941.70 -2,704.91 6,954.24 6,025,216.81 129.93 129.17 128.81 127.49 125.19 122.81 123.23 124.00 123.10 122.42 124.18 125.56 125.68 126.47 126.10 4,002.41 4,002.44 4,002.32 4,002.36 4,002.46 4,002.34 4,002.32 4,002.47 4,003.02 4,002.60 3,999.56 3,995.89 3,992.19 3,988.95 3,987.38 3,943.07 3,943.10 3,942.98 3,943.02 3,943.12 3,943.00 3,942.98 3,943.13 3,943.68 3,943.26 3,940.22 3,936.55 3,932.85 3,929.61 3,928.04 -2,765.81 -2,825.92 -2,886.64 -2,945.60 -3,002.52 -3,055.43 -3,107.67 -3,160.35 -3,213.16 -3,264.73 -3,316.87 -3,371.26 -3,426.50 -3,482.42 .3,537.65 127.11 3,985.97 3,926.63 -3,594.89 124.95 3,985.10 3,925.76 -3,650.29 124.10 3,984.93 3,925.59 -3,703.97 123.77 3,984.72 3,925.38 -3,756.72 124.72 3,983.43 3,924.09 -3,810.16 124.76 3,981.32 3,921.98 124.66 3,980.59 3,921.25 124.17 3,983.91 3,924.57 124.47 3,991.54 3,932.20 124.44 3,998.08 3,938.74 12,681.69 87.35 123.92 4,002.61 12,776.40 87.17 123.57 4,007.14 12,870.37 87.10 123.42 4,011.83 12,964.93 88.78 124.51 4,015.23 13,060.18 88.40 125.80 4,017.58 13,155.81 88.16 125.54 4,020.45 13,249.97 88.16 125.49 4,023.47 13,345.00 88.22 124.82 4,026.47 13,440.52 87.72 125.11 4,029.86 13,534.19 88.22 125.34 4,033.17 13,629.87 89.45 124.93 4,035.12 13,724.56 89.64 124.98 4,035.87 13,819.53 89.64 124.93 4,036.47 3,943.27 3,947.80 3,952.49 3,955.89 3,958.24 3,961.11 3,964.13 3,967.13 3,970.52 3,973.83 3,975.78 3,976.53 3,977.13 -3,864.14 .3,918.16 -3,971.08 -4,024.60 -4,077.88 -4,131.03 -4,183.58 -4,235.37 4,288.17 4,342.99 4,398.73 4,453.40 4,508.09 -4,562.80 4,616.79 4,671.84 4,726.09 4,780.50 7,026.66 6,025,156.25 7,099.45 6,025,096.48 7,174.47 6,025,036.10 7,249.53 6,024,977.49 7,326.89 6,024,920.94 7,405.34 6,024,868.39 7,485.71 6,024,816.53 7,564.96 6,024,764.21 7,644.60 6,024,711.77 7,724.75 6,024,660.57 7;804.12 6,024,608.80 7,882.18 6,024,554.77 7,959.27 6,024,499.90 8,036.02 6,024,444.33 8,111.25 6,024,389.45 8,188.32 6,024,332.57 8,264.48 6,024,277.53 8,342.51 6,024,224.21 8,420.92 6,024,171.82 B,499.42 6,024,118.74 8,577.25 6,024,065.13 8,655.25 6,024,011.47 8,732.49 6,023,958.91 8,810.88 6,023,905.75 8,888.53 6,023,852.84 8,966.80 6,023,800.05 9,045.46 6,023,747.87 9,123.73 6,023,696.44 9,202.10 6,023,644.01 9,279.95 6,023,589.54 9,357.61 6,023,534.17 9,434.21 6,023,479.85 9,511.87 6,023,425.52 9,590.10 6,023,371.18 9,666.57 6,023,317.54 9,744.80 6,023,262.86 9,822.40 6,023,208.97 9,900.24 6,023,154.92 Well MPU M-11 MPU M-11 Actual RKB @ 59.34usft MPU M-11 Actual RKB @ 59.34usft True Minimum Curvature NORTH US + CANADA Map Vertical Easting DLS Section (ft) (-Itoo,) (ft) Survey Tool Name 540,915.48 0.33 7,162.43 2_MWD+IFR2+MS+Sag (2) 540,989.73 2.23 7,257.84 2_MWD+IFR2+MS+Sag (2) 541,062.42 1.14 7,352.04 2_MWD+IFR2+MS+Sag (2) 541,135.48 1.00 7,446.10 2_MWD+IFR2+MS+Sag (2) 541,210.77 0.54 7,542.35 2_MWD+IFR2+MS+Sag (2) 541,286.09 1.40 7,637.62 2_MWD+IFR2+MS+Sag (2) 541,363.71 2.41 7,733.62 2_MWD+IFR2+MS+Sag (2) 541,442.38 2.57 7,828.24 2_MWD+IFR2+MS+Sag(2) 541,522.99 0.78 7,924.06 2_MWD+IFR2+MS+Sag(2) 541,602.47 0.93 8,019.20 2_MWD+IFR2+MS+Sag (2) 541,682.35 1.35 8,114.75 2_MWD+IFR2+MS+Sag(2) 541,762.72 2.33 8,210.00 2_MWD+IFR2+MS+Sag(2) 541,842.32 2.16 8,304.94 2_MWD+IFR2+MS+Sag(2) 541,920.62 1.48 8,400.08 2_MWD+IFR2+MS+Sag(2) 541,997.96 0.41 8,494.90 2_MWD+IFR2+MS+Sag (2) 542,074.96 1.28 8,589.83 2_MWD+IFR2+MS+Sag (2) 542,150.43 1.19 8,683.12 2_MWD+IFR2+MS+Sag (2) 542,227.75 1.34 8,779.07 2_MWD+IFR2+MS+Sag (2) 542,304.15 2.74 8,873.22 2_MWD+IFR2+MS+Sag (2) 542,382.43 1.07 8,967.94 2_MWD+IFR2+MS+Sag (2) 542,461.06 0.63 9,062.43 2_MWD+IFR2+MS+Sag (2) 542,539.80 2.14 9,157.39 2_MWD+IFR2+MS+Sag (2) 542,617.87 0.86 9,252.11 2_MWD+IFR2+MS+Sag (2) 542,696.11 0.91 9,346.98 2_MWD+IFR2+MS+Sag (2) 542,773.58 4.39 9,440.61 2_MWD+IFR2+MS+Sag(2) 542,852.21 1.15 9,535.53 2_MWD+IFR2+MS+Sag(2) 542,930.10 2.43 9,629.70 2_MWD+IFR2+MS+Sag (2) 543,008.60 0.58 9,724.31 2_MWD+IFR2+MS+Sag (2) 543,087.50 0.42 9,818.90 2_MWD+IFR2+MS+Sag (2) 543,165.99 0.18 9,912.73 2 MWD+IFR2+MS+Sag(2) 543,244.59 2.12 10,007.22 2_MWD+IFR2+MS+Sag(2) 543,322.69 1.41 10,102.43 2_MWD+IFR2+MS+Sag(2) 543,400.59 0.37 10,198.00 2_MWD+IFR2+MS+Sag(2) 543,477.43 0.05 10,292.11 2_MWD+IFR2+MS+Sag(2) 543,555.33 0.71 10,387.08 2_MWD+IFR2+MS+Sag(2) 543,633.80 0.61 10,482.54 2_MWD+IFR2+MS+Sag(2) 543,710.51 0.59 10,576.15 2_MWD+IFR2+MS+Sag(2) 543,788.98 1.36 10,671.80 2_MWD+IFR2+MS+Sag(2) 543,866.83 0.21 10,766.49 2_MWD+IFR2+MS+Sag(2) 543,944.91 0.05 10,861.46 2_MWD+IFR2+MS+Sag(2) 3,252019 7:09:57PM Page 6 COMPASS 5000.15 Build 91 Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-ordinate Reference: Well MPU M-11 Project: Milne Point TVD Reference: MPU M-11 Actual RKB @ 59.34usft Site: M Pt Moose Pad MD Reference: MPU M-11 Actual RKB @ 59.34usft Well: MPU M-11 North Reference: True Wellbore: MPU M-11 Survey Calculation Method: Minimum Curvature Design: MPU M-11 Database: NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/ -S +EI -W Northing Easting DLS Section (usft) V) (') (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 13,913.53 89.51 124.10 4,037.16 3,977.82 -4,833.76 9,977.69 6,023,102.02 54022.59 0.89 10,955.45 2_MWD+IFR2+MS+Sag (2) 14,008.42 88.90 122.85 4,03848 3,979.14 4,886.09 10,056.83 6,023,050.05 544,101.96 1.47 11,050.31 2_MWD+IFR2+MS+Sag(2) 14,102.73 89.33 121.55 4,039.94 3,980.60 -4,936.34 10,136.62 6,023,000.18 544,181.98 1 A 11,144.52 2 MWD+IFR2+MS+Sag(2) 14,197.48 90.94 123.50 4,039.72 3,980.38 4,987.28 10,216.51 6,022,949.61 544,262.08 2.67 11,239.19 2_MWD+IFR2+MS+Sag(2) 14,291.81 92.73 125.73 4,036.69 3,977.35 -5,040.83 10,294.09 6,022,896.42 544,339.91 3.03 11,333.47 2_MWD+IFR2+MS+Sag(2) 14,386.99 93.78 126.67 4,031.29 3,971.95 -5,096.95 10,370.77 6,022,840.65 544,416.84 1.48 11,428.46 2_MWD+IFR2+MS+Sag(2) 14,481.63 93.28 126.02 4,025.46 3,966.12 -5,152.94 10,446.85 6,022,785.03 544,493.17 0.87 11,522.88 2_MWD+IFR2+MS+Sag(2) 14,577.35 92.72 125.15 4,020.45 3,961.11 -5,208.56 10,524.59 6,022,729.76 544,571.15 1.08 11,618.45 2_MWD+IFR2+MS+Sag(2) 14,672.91 92.05 125.65 4,016.48 3,957.14 -5,263.87 10,602.42 6,022,674.82 544,649.22 0.87 11,713.92 2_MWD+IFR2+MS+Sag(2) 14,768.00 93.22 125.87 4,012.10 3,952.76 -5,319.38 10,679.50 6,022,619.67 544,726.55 1.25 11,808.89 2_MWD+IFR2+MS+Sag(2) 14,862.95 91.86 124.28 4,007.90 3,948.56 -5,373.88 10,757.12 6,022,565.52 544,804.41 2.20 11,903.74 2_MWD+IFR2+MS+Sag(2) 14,957.39 89.70 124.52 4,006.61 3,947.27 -5,427.23 10,835.04 6,022,512.54 544,882.56 2.30 11,998.17 2_MWD+IFR2+MS+Sag(2) 15,051.42 89.02 125.28 4,007.66 3,948.32 -5,481.02 10,912.15 6,022,459.10 544,959.91 1.08 12,092.19 2_MWD+IFR2+MS+Sag(2) 15,146.89 88.96 125.00 4,009.34 3,950.00 -5,535.97 10,990.21 6,022,404.52 545,038.21 0.30 12,187.64 2_MWD+IFR2+MS+Sag(2) 15,241.02 89.27 124.66 4,010.80 3,951.46 -5,589.72 11,067.46 6,022,351.13 545,115.71 0.49 12,281.76 2_MWD+IFR2+MS+Sag(2) 15,336.50 88.96 125.04 4,012.27 3,952.93 -5,644.27 11,145.81 6,022,296.94 545,194.29 0.51 12,377.23 2_MWD+IFR2+MS+Sag(2) 15,431.72 88.71 123.88 4,014.21 3,954.87 -5,698.14 11,224.30 6,022,243.44 545,273.02 1.25 12,472.42 2_MWD+IFR2+MS+Sag (2) 15,524.98 87.60 122.90 4,017.21 3,957.87 -5,749.44 11,302.13 6,022,192.50 545,351.08 1.59 12,565.61 2_MWD+IFR2+MS+Sag(2) 15,620.46 87.85 122.92 4,021.00 3,961.66 -5,801.27 11,382.22 6,022,141.04 545,431.40 0.26 12,660.97 2_MWD+IFR2+MS+Sag(2) 15,714.93 86.48 125.80 4,025.68 3,966.34 -5,854.52 11,460.10 6,022,088.16 545,509.51 3.37 12,755.31 2_MWD+IFR2+MS+Sag (2) 15,810.75 88.10 127.91 4,030.21 3,970.87 5,911.92 11,536.68 6,022,031.11 545,586.35 2.77 12,850.94 2_MWD+IFR2+MS+Sag (2) 15,905.72 88.22 126.68 4,033.26 3,973.92 -5,969.43 11,612.19 6,021,973.95 545,662.11 1.30 12,945.76 2_MWD+IFR2+MS+Sag (2) 16,000.41 86.91 124.40 4,037.28 3,977.94 -6,024.42 11,689.17 6,021,919.32 545,739.33 2.78 13,040.35 2_MWD+IFR2+MS+Sag(2) 16,070.00 86.91 124.40 4,041.03 3,981.69 -6,063.68 11,746.50 6,021,880.33 545,796.84 0.00 13,109.84 PROJECTEDto TD Checked By: Chelsea Wright a uw Approved By: Mitch Laird Date: 03-25-2019 3,252019 7:09:57PM Page 7 COMPASS 5000.15 Build 91 ,� Z NJlcarp Energy Company CASING & CEMENTING REPORT Lease & Well No. MP M-11 Date Run 12 -Mar -19 _ County State Alaska Supv. Sunderland/Toomey CASING RECORD sudxe � TO 5,403.00 Shoe Depth: 5,393.00 PBTD: 5,268.98 No. Jts, Delivered 151 No. Jts. Run 131 No. As. Returned 18 Csg Wt. On Hook: 240,000 Type Float Collar, Antelope No. Him to Run: 16.5 Csg Wt, On Slips: 150,000 Type of Shoe: Antelope Casing Crew: Doyon Casing Rotate Csg X Yes No Beep Csg X Yes _ No _ Ft. Min. 9.3 PPG Fluid Description: Spud Mud Liner hanger Info (MakeNodel): Liner top Packer?: _Yes _No Liner hanger lest pressure: Floats Held X Yes_ No Centralizer Placement: Install 91 bow spring centralizer (12-1/4' x 9-5/8') refer to tally for placement. CEMENTING REPORT Shoe @ 5393 FC @ 5,308.41 Top of Liner #N/A Casing (Or Liner) Detail IacemenL Volume pumped (BBLs) Setting Depths Jt& Component Size Wt. Grade THD Make Length Bottom Top 1 Float Shoe 103/4 40.0 L-80 TXP Antelope 1.60 5,393.00 5,391.40 2 Casing 95/8 40.0 L-80 TXP Yes No Spacer returns? 81.70 5,391.40 5,309.70 1 Float Collar 103/4 40.0 L-80 TXP Antelope 1.29 5,309.70 5,308.41 1 Casing 95/8 40.0 L-80 TXP 37.95 5,309.70 5,270.46 1 Baffle Adapter 103/4 40.0 L-08 TXP Halliburton 1.48 5,270.46 5,268.98 75 Casing 95/8 40.0 L-80 UP 2,924.92 5,268.98 2,344.06 1 Pup Joint 95/8 40.0 L-80 UP 18.73 2,344.06 2,325.33 1 ES Cementer 103/4 40.0 L-80 TXP Halliburton 3.10 2,325.33 2,322.23 1 Pup Joint 95/8 40.0 L-80 UP 17.83 2,322.23 2,304.40 58 Casing 95/8 40.0 L-80 TXP 2,250.32 2,304.40 54.08 1 CashCut Joint 95/8 40.0 1-80 TXP 21.12 r 54.08 32.96 Csg Wt. On Hook: 240,000 Type Float Collar, Antelope No. Him to Run: 16.5 Csg Wt, On Slips: 150,000 Type of Shoe: Antelope Casing Crew: Doyon Casing Rotate Csg X Yes No Beep Csg X Yes _ No _ Ft. Min. 9.3 PPG Fluid Description: Spud Mud Liner hanger Info (MakeNodel): Liner top Packer?: _Yes _No Liner hanger lest pressure: Floats Held X Yes_ No Centralizer Placement: Install 91 bow spring centralizer (12-1/4' x 9-5/8') refer to tally for placement. CEMENTING REPORT Shoe @ 5393 FC @ 5,308.41 Top of Liner #N/A lush (Spacer) IacemenL Volume pumped (BBLs) r Clean Spacer Density (ppg) 10 Volume pumped (BBLs) I Slurry 5 Volume (actual /calculated): 408/380 1. ExtendaCEM disp: Rig Sacks: 330 Yield, uty(ppg) 12 Volume pumped (BBLs) 138 Mixing/ Pumping Rate (bpm): Slurry job 100 mt returns to surface? X .. SwiflCEM (class G) _No X Yes No Vol to Surf Sacks: 400 Yield: nty(ppg) 15.8 Volume pumped( BBLs) 82 Mixing/ Pumping Rate (tom): : Flush (Spacer) ed! Used To Determine TOC: Cement circulated out : Fresh Water Density (ppg) 8.34 Rate (bpm): 3 Volume: 20 IacemenL Volume pumped (BBLs) 55.8 Mixing / Pumping Rate (bpm) 3 Spud Mud Density (ppg) 9.3 Rate (bpm): 5 Volume (actual /calculated): 408/380 (psi): 800 Pump used for disp: Rig Bump Plug? X Yes No Bump press 131 ig Rotated? X Yes Reciprocated? X Yes % Returns during job 100 mt returns to surface? X _No Yes No Spacer returns? _No X Yes No Vol to Surf 36 ant In Place At: 2:37 Date: 3/12/2019 Estimated TOC: 2,325 ed! Used To Determine TOC: Cement circulated out X No % Returns during job 00 Stage Collar@ 2325 Type ES Cementer Closure OK Yes reflush (Spacer) ype: Clean Spacer Density(ppg) 10 Volume pumped (BBLs) ead Slurry ype: Permafrost Sacks: 410 Yield. ismaty, (ppg) 10 Volume pumped (BBLs) 315 Mixing / Pumping Rate (bpm): ail Slurry SwiftCEM (Gass G) Sacks: 270 Yield: 1.16 dy (ppg) 15.8 Volume pumped (BBLs) 55.8 Mixing / Pumping Rate (bpm) 3 Flush (Spacer) Fresh Water Density (ppg) 8.34 Rate (bpm): 20 Volume: 3 acement: Spud Mud Density (ppg) 9.3 Rate (bpm): 5 Volume (actual /calculated): 155/156 (psi): 650 Pump used for disp: Rig Bump Plug? X Yes _No Bump press 1550 1g Rotated? _Yes X No Reciprocated? _Yes X No % Returns during job 00 aril returns to surface? X Yes No Spacer returns? X Yes No Vol to Surf: 216 In Place At: 15:34 Date: 3/12/2019 Estimated TOG Used To Determine TOC: Cement to surface Post Job Calculations: Calculated Cmt Vol @ 0% excess: 325.3 Total Volume cmt Pumped: Cmt returned to surface: 255 Calculated cement left in wellbore: OH volume Calculated: 294.5 OH volume actual: 304.2 Actual %N 336 591 www.wellez.net WellEz Information Management LLC ver_D4818br I 21 9010 Dura Oudean Hilcorp Alaska, LLC AK_GeoTech 3800 Centerpoint Drive, Suite 1400 30 6 13 Anchorage, AK 99503 Tele: 907 777-8337 t.Lf. Fax: 907 777-8510 E-mail: doudean@hilcorp.com DATE: 4/11/2019 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 RECOVED APR 16 2019 AOGCC ROP DGR EWR ALD CTN MD & TVD CD: HALLIBURTON 7 MAR 2019 -Log Viewers 4/11%20192:15 AM Filefclder CGM 4,!11120198:18/.'M Filefclder Definith,e Survey 4./11/20198:18 AM Filefolder EMF 4'11/2D196:18AM Filefolder LAS 4/11/20198:18 AM Filefolder PDF 4/11120192,:19 AM Filefolder TIFF 4i11/20198:19AM Filefolder Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 JIF6 mojao Reyg, James B (DOA) From: Claude Demoski - (C) <cdemoski@hilcorp.com> Sent: Friday, March 22, 2019 3:12 PMI`d�izj �i z'(L9 To: Regg, James B (DOA) / / Cc: Ian Toomey - (C); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (DOA); 'Rig 14 (rig14 @doyondrilling.com)'; 'ahonea@doyondrilling.com' Subject: RE: Doyon 14, MPU M-11 BOPE test Attachments: Doyon 14 3-13-19 MPU M-11 Revised.xlsx Good afternoon Mr. Regg, Ian Toomey went on days off and I have been following up with the tool pusher about the test chart. We would like to submit a revised report with the following explanations: Please see revised report for Doyon 14 BOP test M-11. Test #1 low — FP, bled off to zero to work air out of system, then re -pressured to a stable low test. No changes in testing line up. Test #2 low — FP, bled off more than 10% of test pressure, still working air from system, re -pressured to a stable low test. No changes in testing line up. Test #3 low - FP — bled off to zero, then re -pressured to a stable low test. No changes in testing line up. Test #5 low —P — re -pressured to ensure test pressure was at the desired test pressure. No changes in in testing line up. Test #1 high — P — re -pressured to work air out of system on first test, bleed off was less than 10% of test pressure. Regards, C.A. Demoski I Drill Site Manager Doyon 14 1 Milne Point Office: 907-670-3090 Rig Floor: 907-670-3116 Positional Cell: 907-891-3064 From: Regg, James B (DOA) [mailto:iim.regg@alaska.gov) Sent: Thursday, March 14, 2019 8:36 AM To: Ian Toomey- (C) <itoomey@hilcorp.com> Cc: DOA AOGCC Prudhoe Bay <doa aogcc.prudhoe.bay@alaska.gov>; Brooks, Phoebe L (DOA) <phoebe brooks@alaska.gov> Subject: [EXTERNAL) RE: Doyon 14, MPU M-11 BOPE test According to the charts, tests 1,2,3,& 5 (low pressure) and test 1 high pressure required repressure —those would be FP's. Please explain/revise reports as appropriate. Jim Regg Supervisor, Inspections AOGCC 333 W.7'h Ave, Suite 100 SCANNED APR 0 12019 Anchorage, AK 99501 907-793-1236 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 Jim Regg at 907- 793-1236 or lim.regg@alaska.gov. From: Ian Toomey - (C) <itoomev@hilcorp.com> Sent: Wednesday, March 13, 2019 5:50 PM To: Regg, James B (DOA) <iim.regg@alaska.aov>; DOA AOGCC Prudhoe Bay<doa.aogcc.prudhoe.bay@alaska.eov>; Brooks, Phoebe L (DOA) <phoebe.brooks@alaska.gov> Cc: Cook, Guy D (DOA) <guy.cook@alaska.gov> Subject: Doyon 14, MPU M-11 BOPE test All, Here is the initial BOPE test for MPU M-11. Regards, Ian Toomey I Drill Site Manager Doyon 14 1 Milne Point Office: 907-670-3090 Doghouse: 907-670-3116 STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION -O BOPE Test Report "AII BOPE reports are due to the agency within 5 days of testing* Submit to:iim.recaCalalaska.aov: AOGCC.Inspectors(cDalaska.gov: phoebe. brooks(cbalaska.aov Contractor: Doyon - Rig No.: 14 DATE: 3/13/19 - Rig Rep.: J/Hansen A/Carlo Rig Phone: 907-670-3096 Operator: Hilcorp Alaska LLC Op. Phone: 907-670-3090 Rep.: I/Toomey E -Mail itoomevanhilcorp.com Well Name: MPU M-11 PTD # 2190100 - Sundry # Operation: Drilling: x Workover: Test: Initial: x Weekly: Test Result Test Result Location Gen. P Well Sign P Housekeeping P Rig P PTD On Location P - Hazard Sec. P " ling Order Posted P Misc. NA BOP STACK: Quantity Size/Type Test Result Stripper 0 1 NA Annular Preventer I 13-5/8 FP #1 Rams 1 4-1/2" X 7" FP #2 Rams I BLIND P #3 Rams 1 2-7/8" X 5" P #4 Rams 0 NA #5 Rams 0 NA #6 Rams 0 NA Choke Ln. Valves 1 3-1/8" P - HCR Valves 2 3-1/8" FP Kill Line Valves 2 3-1/8" FP Check Valve 0 NA BOP Misc 0 NA CHOKE MANIFOLD Quantity Test Result No. Valves 14 FP _ Manual Chokes I P Hydraulic Chokes I P CH Misc 0 NA Explor.: Bi -Weekly: Valves: 250/3000 FLOOR SAFETY Quantity Upper Kelly 1 Lower Kelly 1 Ball Type 2 Inside BOP 1 FSV Misc 0 MUD SYSTEM: Trip Tank Pit Level Indicators Flow Indicator Meth Gas Detector H2S Gas Detector MS Misc Visual Quantity Inside Reel valves 0 — MASP: 1349 ACCUMULATOR SYSTEM: Time/Pressure System Pressure (psi) Pressure After Closure (psi_ 200 psi Attained (sec) _ Full Pressure Attained (sec)_ Blind Switch Covers: Nitgn. Bottles # & psi (Avg.): 6 ACC Misc Test Results Number of Failures: 6 `/ Test Time: 5_0 Hours Repair or replacement of equipment will be made within 2004 Test Result P Alarm Test Result NA Test Result P - P P ' P Remarks: Tested Annular - Upper & Lower VBR's with 5" test jt. Tested 2ea FOSV and 1 as Dart. All tests performed against test plug. Test #1 low, F/P Annular, CV's 1-12-13-14, 5" TIW, Kill line demco, bled to zero & repressured good.Test #2 low, F/P Upper VBR's, CV9-11-HCR kill, bleed off & repressure. Test #3 low, F/P CV 5-8-10 Kill man -5" TIW, bled to zero & repressured stable. Test #5 low, F/P CV2 & Upper IBOP, repressured to ensure good lest pressure. No cycling or 24 hr Notice Yes DatefTime By Start Date/rime: 3/13/2019 10:30 d (date) (time) Witness Form 10-424 (Revised 04/2018) Doyon 14 3-13-19 MPU M-11 Revised 1)01o 14 TEST BOP'S 03-13-19 5" 1T 250/3000PSI 1) ANNULAR, CV 1, 12,13,14,5" TIW, KILL LINE DEMCO 2) UPPER RAMS (4.5X7), CV 9, 11, HCR KILL 3) CHOKE VALVES 5, 8, 10, MANUAL Kill, 5" TIW 4) CHOKE VALVES 4, 6, 7, 5" DART 5) CHOKE VALVES 2, UPPER IBOP 6) HCR CHOKE, LOWER IBOP 7) MANUAL CHOKE 8) LOWER RAMS (2 7/8X5) W/5" TEST JT KOOMY TEST, L/D 5" TEST JT, 9) BLIND RAMS, CHOKE VALVE 3 10) Manual Choke "B" 11) Hyd Choke "A" ce— LA a THE STATE °fALASKA GOVERNOR MIKE DUNLEAVY Monty Myers Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 v✓ W w.aogcc.alaska.gov Re: Milne Point Field, Schrader Bluff Oil Pool, MPU M-11 Hilcorp Alaska, LLC Permit to Drill Number: 219-010 Surface Location: 5037' FSL, 141' FEL, SEC. 14, TUN, R9E, UM, AK Bottomhole Location: 1139' FNL, 1264' FWL, SEC. 20, TUN, R10E, UM, AK Dear Mr. Myers: Enclosed is the approved application for the permit to drill the above referenced service well. Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by Hilcorp Alaska, LL in the attached application, the following well logs are also required for this well: Gamma ray log required from base of conductor to surface casing shoe. Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Daniel T. Se ount, Jr. Commissioner DATED this ( day of February, 2019. STATE OF ALASKA AL-161KA OIL AND GAS CONSERVATION COMMIb6ION PERMIT TO DRILL 20 AAC 25.005 JAN 2 5 2019 Ia. Type of Work:1 b. Proposed Well Class: Exploratory - Gas ElService - WAG LJService - Disp E]1c. Specify kll is proposed for: Drill Q' Lateral ❑ Stratigraphic Test ❑ Development -Oil El Service - Winj ❑Q - Single Zone ❑Q ' Coalbed as Gas hydrates ❑ Redrill ❑ Reentry ❑ Exploratory - Oil ❑ Development - Gas ❑ Service - Supply ❑ Multiple Zone ❑ Geothermal ❑ Shale Gas ❑ 2. Operator Name: 5. Bond: Blanket ❑Q . Single Well ❑ 11. Well Name and Number: Hilcorp Alaska, LLC Bond No. 022035244. MPU M-11 ' 3. Address: 6. Proposed Depth: 12. Field/Pool(s): 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 MD: 16,250' ' TVD: 3,965' Milne Point Field Schrader Bluff Oil Pool 4a. Location of Well (Governmental Section): 7. Property Designation: Surface: 5037' FSL, 141' FEL, Sec 14, T13N, R9E, UM, AK ADL025514, ADL388235, ADL025515 Top of Productive Horizon: 8. DNR Approval Number: 13. Approximate Spud Date: 240' FNL, 2430' FEL, Sec 13, T13N, R9E, UM, AK LONS 16-004 2/21/2019 Total Depth: 9. Acres in Property: 14. Distance to Nearest Property: 1139' FNL, 1264' FWL, Sec 20, T13N, R10E, UM, AK 7024 2859' to nearest unit boundary 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 58.7 • 15. Distance to Nearest Well Open Surface: x-534023. y-6027889 ' Zone -4 GL / BF Elevation above MSL (ft): 25 ' to Same Pool: 800' to M-10 16. Deviated wells: Kickoff depth: 375 feet 17. Maximum Potential ssures in psig (see 20 AAC 25.035) Maximum Hole Angle: 93 degrees �P Downhole: 1j3g f '77>' 4,, urface: 1349 - 18. Casing Program: Specifications Top - Setting Depth - Bo tom Cement Quantity, c.f. or sacks Hole Casing Weight Grade Coupling Length MD TVD MD TVD (including stage data) Cond 20" - X52 Weld 113' Surface Surface 113' 113' -270 ft3 12-1/4" 9-5/8" 40# L-80 TXP SR 5,396' Surface Surface 5,396' - 3,959' ' Stg1-L-772ft3/T-458ft3 _ Stg 2 - L - 1937 ft3 / T - 314 ft3 8-1/2" 4-1/2" ' 13.5# L-80 Hyd 625 11,000' 5,250' 3,941' 16,250' 3,965' Cementless Injection Liner ICDs Tieback 3-1/2" 9.3# L-80 EUE 8RD 5,250' Surface Surface 5,250' 3,941' Tieback 19. PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re -Entry Operations) Total Depth MD (ft): Total Depth TVD (ft): Plugs (measured): Effect. Depth MD (ft): Effect. Depth TVD (ft): Junk (measured): Casing Length Size Cement Volume MD TVD Conductor/Structural Surface Intermediate Production Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Hydraulic Fracture planned? Yes ❑ No ❑Q ' 20. Attachments: Property Plat O BOP Sketch Diverter Sketch Q Drilling Program Q Time v. Depth Plot Q B Seabed Report e Drilling Fluid Program e Shallow Hazard Analysis 20 AAC 25.050 requ'rement:D 21. Verbal Approval: Commission Representative: Date 22. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Name: Joe Engel Authorized Name: Monty Myers Contact Email:en el hilCOr .COm Authorized Title: Drilling Manager Contact Phone: 777-8395 Authorized Signature: —' Date: / i 2 S. p51 Commission Use Only Permit Drill q // ��!' rj/U API Number: ,�!•� 77�S/-�� Permit Approval See cover letter for other r: Number: 50-t��-Z,j(pW-� Date: requirements. 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: X 2 C00 5`' 3z) (% T75-+ Samples req'd: Yes E] No Mud log req'd: Yes ❑ No LVJV J f-✓ HiS measures: Yes El No [y]� Directional svy req'd: Yes �No ❑ 1 1 Spacing exception req'd: Yes ❑ No � Inclination -only svy req'd: YesEl No r. i!,t/ ,y, b -e_ ®� �� N` qu�r�,Q LOQ 0 /08 Post initial injection MIT req'd: YesO No ❑ .ql. APPROVED BY f C I \ Q1 Approved by: I HE COMMISSION Date: `d d d l rrNF ' 1 Revised 5/2017 This permit is valid for 24w, / Submit Form and h f o INA, ILMal per 20 AAC 25 t I' t men upicae H Hilcorp 1.25.2019 Commissioner Alaska Oil & Gas Conservation Commission 333 W. 7'h Avenue Anchorage, Alaska 99501 Re: Application for Permit to Drill MPU M-11 Dear Commissioner, Joe Engel Hilcorp Alaska, LLC Drilling Engineer P.O. Box 244027 Anchorage, AK 99524-4027 Tel 907 777 8395 Email: jengel@hilcorp.com Hilcorp Alaska, LLC hereby submits for review and approval for a Permit to Drill an onshore production well at Milne Point'M' Pad, well slot 11. MPU M-11 is a grassroots injector planned to be drilled in the Schrader Bluff OA sand. M-11 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 OA sand. An 8.5" lateral section will then be drilled. A 4-1/2" ICD 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 Feb 21, 2019, pending rig schedule. Please find attached the Form 10-401, Application For Permit to Drill per 20 AAC 25.005 (a) and the drilling program for MPU M-10, which includes information required by 20 AAC 25.005 (c). If you have any questions, or require further information, please do not hesitate to contact myself (Joe Engel) at 777-8395 or jengel@hilcorp.com or Monty Myers at 777-8431 or mmyers@hilcorp.com. Sincerely, r-Ve Jae- 25 6a- Joe Engel Drilling Engineer Hilcorp Alaska, LLC Page 1 of i 04� AQP f 0 lk Area of Review MPM-11 FEB 12 200 1--35,4 ®GCC CBL Top of CBL Top of Top of SB Top of SB Cement Cement Schrader OA PTD AN WELL STATUS OA (MD) OA (TVD) (MD) (TVD) status Zonal Isolation 218-165' 5D-029-23617-00-00 ' MPM-10 5B OA Producer 6,646' 3,998' N/A N/A Open N/A 51 BBLS of cement (250 sx) pumped thru 7" 197-136. 50-029-22790-00-00• MPL-20 ' Kuparuk Producer 10,038'- 3,964'• 8,196'- 3,543'• Closed ESCementer @ 10,446' MD. TOC @ 8,196' MD (calculated on gauge hole) fit- 5:(3. Is 6- "- -: -� i (540 f'7(73/A+D Pumped 51 bbis of cmt C 3SSz'T✓0 thru 7" ES Cementer @ 21_ a 50- 20-00-00 MPL-36 ' Kuparuk Producer 9,773' - 3,946' 7,982' • 3,608' a Closed 10,232' MD TOC @ 7,982' 5a<62%—Z 7— %% MD (calculated on gauge / r hole) G+k 9-5/8" surface casing run to 10,514 MD and cemented back to surface. 197-092.50-029-22768-00-00' MPL-35 P&A'd Kuparuk 9,038' 3,975' Surface• Surface Closed Wellbore was later sidetracked in ILA-✓ 9dory" a /o'174 .AV Kupamk, but isolation remained as MPG'35fi s�cSPt+ YS� Nz)p'-rv� the whipstock was set deep in 7"@ 07c 7"co-5 -� -19,272' MD. 9-5/8'surface using to 3,255' MD and cemented back to surface. 8- 1/2" OH drilled to 4,497 MD / 207-025 50-029-23345-00-00 Pesado 01 P&A'd 4,087' 4,006' Surface- Surface Closed 4,391'TVD for evaluation and r i cemented back to 3,280' MD w1th3 3/iCJ" �Z< cementlugs. The top plug s ued to kickoff Peado DIA sidetrack. Well Abandoned. 9.5/8" surface using to 3,255' MD and cemented back to surface. Sidetrack was kicked off using cement plug set in Pesatlo 01. 8- 1/2" OH was drilled to 4,339' MD / 4,286' TVD for evaluation and cemented back to 2,955' MD with 3 207-026. 50-029-23345-01-00- Pesado 03A' P&A'd 4,053' 4,002' Surface' Surface Closed cement plugs. Well has 9A ppg bring P/ 2,955' MOT/ 2SV MD. Clap installed inside 9-5/8" casing @ 21F MD. Well cemented to surface, surface/conductor cut off below ground level and abandonment marker installed per AOGCC regulations. 1--35,4 ®GCC Area of Review MPM-11 EC -1 ED FEB 11 20`19 AOGCC CBL Top of CBL Top of Top of SB Top of SB Cement Cement Schrader OA PTD API WELL STATUS OA [MD) CIA (TVD) (MD) (TVD) status Zonal Isolation 218-165 50-029-23617-00-00 MPM-10 5B OA Producer 6,646' 3,998' N/A N/A Open N/A 51 BBLs of cement (250 sx) pumped thru 7" 197-136 50-029-22790.00-00 MPL-20 Kuparuk Producer 10,038'' 3,964' 8,196'- 3,543' Closed ESCementer @ 10,446' MD. TOC @ 8,196' MD (calculated on gauge hole Pue 51 bbls of cmt Niru 7" ES Cementer @ 219-005 50-029-23620-00-00 MPL-36 Kuparuk Producer 9,773' • 3,946' 7,982' - 3,608' Op 10,232' MD TOC @ 7,982' MD (calculated on gauge hole) 9-5/8" surface casing run to 10,510' MO and cemented back to surface. 197-092 50-029-22768-00-00 MPL-35 P&A'd Kuparuk 9,038'• 97$I� urface Surface Closed Wellbore was later sidetracked In Kuparuk, but isolation remained as �t • the whipstock was set deep in 7"@ '"18,272'101). 9-5/8" surface using to 3,255' MD and cemented back to surface. 8- 1/2" Off drilled to 4,497' MD/ 207-025 50-029-23345-00-00 Pesado 01 P 4,087' 4,006' Surface • Surface Closed 4,391'TVD for evaluation and cemented back to 3,280' MD with 3 cement plugs. The top plug was used to kickoff Pesado 01A sidetrack. Well Abandoned. j Z 9-5/8" surface using to 3,255' MD Z and cemented back to surface. Sidetrack was kicked off using cement plug set In Pesado D1. 8- 1/2^ ON was drilled W 4,339' MD / 4,286' TVD for evaluation and cemented back to 2,955' MD with 3 207-026 50-029-23345-01-00 Pesado 01A P&A'd 4,053' 4,002' Surface ' Surface Closed cement plugs. Well has 9.4 ppg bdngp/2,955'MDT/25VMD, ❑Sp Installed inside 9.5/8" using @ 250' MD. Well cemented W surface, surface/conductor cut off below ground level and abandonment marker installed per AOGCC regulations. EC -1 ED FEB 11 20`19 AOGCC Area of Review MPM-11 **MPL-36 estimated spud date: 2/1/2019** CBL Top of CBL Top of Top of SB Top of SB Cement Cement Schrader OA PTD API WELL STATUS OA (MD) OA (TVD) (MD) (TVD) status Zonal Isolation 218-165 50-029-23617-00-00 MPM-10 SB OA Producer 6,646' 3,998' N/A N/A Open N/A 51 BB f cement (250 sx) pumped thru 7" 197-136 50-029-22790-00-00 MPL-20 Kuparuk Producer 10,038' 3,964' N/A N/A Closed ESCementer @ 10,446' MD. TOC @ 8,196' MD (calculated on gauge hole) 219-005 50-029-23620-00-00 **MPL-36** Future SB CAWINJ 9,773' 3,946' N/A N/A Open N/A 218-152 50-029-23615-00-00 MPL-35 SB OA Producer 9,038' 3,975' N N/A Open N/A 9-5/8" surface casing to 3,255' MD L and cemented back to surface. 8- 1/2" OH drilled to 4,497' MD / 4,391' 207-025 50-029-23345-00-00 Pesado 01 P&A'd 4,087' 4,006' Surface Surface Closed TVD for evaluation and cemented back to 3,280' MD with 3 cement plugs. The top Plug wasAsidetr used to / 0 kickoff Pesado OSA sidetrack. Well Abandoned. V r- 9-5/8" surface casing to 3,255' MD / t and cemented back to surface. y Sidetrack was kicked off using 9 cement plug set in Pesado 01. 8- 1/2" OH was drilled to 4,339' MD / 4,286' TVD for evaluation and 207-026 50-029-23345-01-00 Pesado 01 P&A'd 4,053' 4,002' Surface Surface Closed cemented back to 2,955' MD with 3 cement plugs. Well has 9.4 ppg bring F/2,955' MDT/ 250' MD. CIBP installed inside 9-5/8" casing @ 25U MD. Well cemented to surface, surface/conductor cut off below ground level and abandonment _ marker installed per AOGCC regulations. **MPL-36 estimated spud date: 2/1/2019** Hilcorp Alaska, LLC Milne Point Unit (MPU) M-11 Drilling Program Version 1 1/24/2019 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 NIU 21-1/4112M 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).....................................................................................36 18.0 RDMO............................................................................................................................................37 19.0 Doyon 14 Diverter Schematic.......................................................................................................38 20.0 Doyon 14 BOP Schematic.............................................................................................................39 21.0 Wellhead Schematic......................................................................................................................40 22.0 Days Vs Depth................................................................................................................................41 23.0 Formation Tops & Information...................................................................................................42 24.0 Anticipated Drilling Hazards.......................................................................................................43 25.0 Doyon 14 Layout............................................................................................................................46 26.0 FIT Procedure................................................................................................................................47 27.0 Doyon 14 Choke Manifold Schematic..........................................................................................48 28.0 Casing Design.................................................................................................................................49 29.0 8-1/2" Hole Section MASP............................................................................................................50 30.0 Spider Plot (NAD 27) (Governmental Sections).........................................................................51 31.0 Surface Plat (As Built) (NAD 27).................................................................................................52 32.0 Schrader Bluff OA Sand Offset MW vs TVD Chart ..................................................................53 33.0 Drill Pipe Information 5" 19.5# S-135 DS -50 & NC50...............................................................54 n Hilcorp � M 1.0 Well Summary Milne Point Unit M-11 SB Injector Drilling Procedure Well MPU M-11 Pad Milne Point "M" Pad Planned Completion Type 3-1/2" Injection Tubing Target Reservoir(s) Schrader Bluff OA Sand Planned Well TD, MD / TVD 16,250' MD / 3,965' TVD PBTD, MD / TVD 16,100' MD / 3,965' TVD Surface Location (Governmental) 5037' FSL, 141' FEL, Sec 14, T13N, R9E, UM, AK Surface Location (NAD 27) X= 534,023.88, Y= 6,027,889.61 Top of Productive Horizon Governmental) 240' FNL, 2430' FEL, Sec 13, T13N, R9E, UM, AK TPH Location (NAD 27) X= 537,013.54 Y= 6,027,906.57 BHL Governmental) 1139' FNL, 1264' FWL, Sec 20, T13N, R10E, UM, AK BHL (NAD 27) X= 545,957.92, Y=6,021,778.42 AFE Number 1814460M D,C,F AFE Drilling Das 17 days AFE Completion Das 7 days AFE Drilling Amount $4,068,540 AFE Completion Amount $1,605,460 AFE Facility Amount $391,000 Maximum Anticipated Pressure (Surface) 1349 psig Maximum Anticipated Pressure Downhole/Reservoir 1739 psig Work String 5" 19.5# S-135 DS -50 & NC 50 KB Elevation above MSL: 33.7 ft + 25.0 ft = 58.7 ft ' GL Elevation above MSL: 25.0 ft BOP Equipment 13-5/8" x 5M Annular, (3) ea 13-5/8" x 5M Rams Page 2 Milne Point Unit M-11 SB Injector HilcorDrilling Procedure �ezrp 2.0 Management of Change Information 14 Hilcorp Alaska, LLC Hilcorp il�rp Changes to Approved Permit to Drill Date: 1/21/2019 Subject: Changes to Approved Permit to Drill for MPU M-11 File #: MPU M-11 Drilling and Completion Program Any modifications to MPU M-11 Drilli�q & Completion Program will be documented and approved below. Changes to an approved APD will be cVditsthe EAOGt C. «a��i o-r_d :A aryh'�s�.� � Approval: Drilling Manager Prepared: Drilling Engineer Page 3 Date Date H Hilcorp 3.0 Tubular Program: Milne Point Unit M-11 SB Injector Drilling Procedure Hole Section OD (in) ID in Drift in _ Conn OD in Wt #lft Grade Conn Burst sl(psi) Collapse Tensio k 1 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 EUE8RD 9289 7399 163 4.0 Drill Pipe Information: All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery). Page 4 H Hilcorp U� 5.0 Internal Reporting Requirements Milne Point Unit M-11 SB Injector Drilling Procedure 5.1 Fill out daily drilling report and cost report on WellEz. • Report covers operations from 6am to 6am • Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left of the data entry area —this will not save the data entered, and will navigate to another data entry. • Ensure time entry adds up to 24 hours total. • Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. • Enter the MD and TVD depths EVERY DAY whether you are making hole or not. 5.2 Afternoon Updates • Submit a short operations update each work day to pmazzolini hilcorp com mmyers hilcorp jengel(2hilcorp.com and cdinger@hilcoip.com 5.3 Intranet Home Page Morning Update • Submit a short operations update each morning by lam on the company intranet homepage. On weekend and holidays, ensure to have this update in before 5am. 5.4 EHS Incident Reporting • Health and Safety: Notify EHS field coordinator. • Environmental: Drilling Environmental Coordinator • Notify Drilling Manager & Drilling Engineer on all incidents • Submit Hilcorp Incident report to contacts above within 24 hrs 5.5 Casing Tally • Send final "As -Run" Casing tally to mm ers hilcorp,com jeneelna hilco_pr .com and cdingerghilcorp.com 5.6 Casing and Cement report • Send casing and cement report for each string of casing to mmyers@hilco[p.com iengel@hilco!p.com and Win ger(c�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 mmvers@hilcoro.com Drilling Engineer Joe Engel 907.777.8395 805.235.6265 len¢el@hilcoro.com Completion Engineer Stan Porhola 907.777.8412 907.331.8228 sporhola@hilcorp.com Geologist Kevin Eastham 907.777.8316 907.360.5087 keasthamCcDhilcorp.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 kflemin¢@hilcorp.com EHS Manager Carl Jones 907.777.8327 907.382.4336 caiones@hilcorp.com Drilling Tech CodyDinger 907.777.8389 1 509.768.8196 cdin¢er@hilcorp.com Page 5 u Hilcorp Rear ��v"r 6.0 Planned Wellbore Schematic Proposed Schematic I®Ele, alwe MiL 587 TD-1B,2W(r7D)/TD•3,9ffPVDI ' PBTD=26M5'(M])/ P0rD=3,9f89M Page 6 Milne Point Unit M-11 SB Injector Drilling Procedure Milne Point Unit Well: MPU M-11 PTD: TBD API: TBD TREE & WELLHEAD T. hmeron3l/8'SM w/41/lY SM Cameron Wing WNIMad Camxan 3l'Sifa bNmmw 2 2-116"56 outs OPEN HOLE /CEMENT DETAIL 42" '270 f13 -u4„ Stg-712R31ea0 Tail Top /314 Stg 2 2-1937 R3 Lad/ 319 h3 Tail &12•Ceffandw Inia wUner in 8-11r lhok CASING DETAIL Size Type Wr Grade/ Conn Drift ID Top 6ta6'05-0 20° ContluRw /A/1(32/Weld WA Soho IC ±5,240' 938" Sura 40 L -80/1%P &75' 6unc�e 5 Laver Completion 41/2• Uner 1 /L410 625 3.85" 5,250' 16, TUBING DETAIL M 2' I Tubing 93 L-0 EUEBRD I I Surr I5250' pJ)870 WELL INCLINATION DETAIL I[OP@375' Mea lbk Angle=93• JEWELRY DETAIL No Top MD hem ID Upper Completion 1 Y2,325' X M"le 2 Y4, 100' 101 Nipple Pm W 3 ±5,240' No Ga tacarer 4 +5,250' rr ck SF.ae Laver Completion 4 1 25,250' Uner Top Peder 5 1 16,245' W JUII an Sear/ posed) PBTD o«u o.rm rcvrs�..n vmk..oma n^.o rv0 vOPertalku0 GENERAL WELL INFO AFM: TBO krld 14: FUNn Milne Point Unit M-11 SB Injector Drilling Procedure 7.0 Drilling / Completion Summary MPU M-11 is a grassroots injector planned to be drilled in the Schrader Bluff OA sand. M-11 is partof 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 OA sand. An 8.5" lateral section will then be drilled. A 4-1/2" ICD 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 Feb 21, 2019, pending rig schedule. Surface casing will be run to 5,396 MD / 3,959' 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 s ace 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 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. LAID: GR + ADR (For geo-steering) ' Page 7 Milne Point Unit M-11 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. • BOPs shall be tested at (2) week intervals during the drilling and completion of MPU M-11. Ensure to provide AOGCC 24 hrs notice prior to testing BOPS. • The initial test of BOP equipment will be to 250/3000 psi & subsequent tests of the BOP equipment will be to 250/3000 psi for 5/5 min (annular to 50% rated WP, 2500 psi on the high test for initial and subsequent tests). Confirm that these test pressures match those specified on the APD. • If the BOP is used to shut in on the well in a well control situation or control fluid flow from the well bore, AOGCC is to be notified and we must test all BOP components utilized for well control prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP test. • All AOGCC regulations within 20 AAC 25.033 "Primary well control for drilling: drilling fluid program and drilling fluid system". • All AOGCC regulations within 20 AAC 25.035 "Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements". o Ensure the diverter vent line is at least 75' away from potential ignition sources • Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office. AOGCC Regulation Variance Requests: Hilcorp Alaska LLC does not request any variances at this time. Page 8 Summary of BOP Equipment & Notifications Milne Point Unit M-11 SB Injector Drilling Procedure Hole Section Equipment Test Pressure(psi_ 12 1/4" 21-1/4" 2M Diverter w/ 16" Diverter Line Function Test Only • 13-5/8" x 5M Hydril "GK" Annular BOP 30 UD • 13-5/8" x 5M Hydril MPL Double Gate Initial Test: 25014OW o Blind ram in him cavity • Mud cross w/ 3" x 5M side outlets 8-1/2" 13-5/8" x 5M Hydril MPL Single ram '30" 3-1/8" x 5M Choke Line Subsequent Tests: 250/900[1' • 3-1/8" x 5M Kill line • 3-1/8" x 5M Choke manifold • Standpipe, floor valves, etc Primary closing unit: NL Shaffer, 6 station, 3000 psi, 180 gallon accumulator unit. Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is a 30:1 air pump, and emergency pressure is provided by bottled nitrogen. The remote closing operator panels are located in the doghouse and on accumulator unit. Required AOGCC Notifications: • Well control event (BOPS utilized to shut in the well to control influx of formation fluids). • 24 hours notice prior to spud. • 24 hours notice prior to testing BOPS. • 24 hours notice prior to casing running & cement operations. • Any other notifications required in APD. Regulatory Contact Information: AOGCC Jim Regg / AOGCC Inspector / (0): 907-793-1236 / Email: jim.regg@alaska.gov Guy Schwartz / Petroleum Engineer / (0): 907-793-1226 / (C): 907-301-4533 / Email: gLiy.schwartz(@,alaska.gov Victoria Loepp / Petroleum Engineer / (0): 907-793-1247 / Email: Victoria.loepp@alaska.gov Mel Rixse / Petroleum Engineer / (0): 907-793-1231 / (C): 907-223-3605 / Email: melvin.rixse@alaska.gov Primary Contact for Opportunity to witness: AOGCC.Inspectorsna,alaska.goy Test/Inspection notification standardization format: hap://doa.alaska.gov/oge/fonns/TestWitnessNotif.html Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) Page 9 H Hilcorp 9.0 R/U and Preparatory Work Milne Point Unit M-11 SB Injector Drilling Procedure 9.1 M-11 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 arg 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 (<80°F). 9.10 Set test plug in wellhead prior to N/U diverter to ensure nothing can fall into the wellbore if it is accidentally dropped. 9.11 Ensure 6" liners in mud pumps. • Continental EMSCO FB -1600 mud pumps are rated at 4665 psi, 462 gpm @ 110 spm @ 95% volumetric efficiency. Page 10 Milne Point Unit M-11 SB Injector Hiloo Drilling Procedure 10.0 NX 21-1/4" 2M Diverter System 10.1 N/U 21-1/4" Hydril MSP 2M Diverter System (Diverter Schematic attached to program). • N/U 16-3/4" 3M x 21-1/4" 2M DSA on 16-3/4" 3M wellhead. • N/U 21-1/4" diverter "T". • Knife gate, 16" diverter line. • Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C). • Diverter line must be 75 ft from nearest ignition source • Place drip berm at the end of diverter line. 10.2 Notify AOGCC. Function test diverter. Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens prior to annular closure. 10.3 Ensure to set up a clearly marked "warning zone" is established on each side and ahead of the vent line tip. "Warning Zone" must include: • A prohibition on vehicle parking • A prohibition on ignition sources or running equipment • A prohibition on staged equipment or materials • Restriction of traffic to essential foot or vehicle traffic only. 10.4 Set wear bushing in wellhead. Page 11 10.5 Rig & Diverter Orientation: • May change on location ------ -------------- 11 M-10 M-11 M-12 Milne Point Unit M-11 SB Injector Drilling Procedure 75' Radius Clear of Ignition Sources Diverter Line *Drawing Not To Scale MPU M -Pad Pagc 12 H H1oC01�p 11.0 Drill 12-1/4" Hole Section Milne Point Unit M-11 SB Injector Drilling Procedure 11.1 P/U 12-1/4" directional drilling assembly: • Ensure BHA components have been inspected previously. • Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. • Ensure TF offset is measured accurately and entered correctly into the MWD software. • Be sure to run a UBHO sub for wireline gyro • Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. • Drill string will be 5" 19.5# S-135. • Run a solid float in the surface hole section. 11.2 Begin drilling out from 20" conductor at reduced flow rates to avoid broaching the conductor. Consider using a trash bit to clean out conductor to mitigate potential damage from debris in conductor. 11.3 Drill 12-1/4" hole section to section TD, in the Schrader OA sand. Confirm this setting depth with the Geologist and Drilling Engineer while drilling the well. • Monitor the area around the conductor for any signs of broaching. If broaching is observed, Stop drilling (or circulating) immediately notify Drilling Engineer. • Efforts should be made to minimize dog legs in the surface hole. Keep DLS < 6 deg / 100. • Hold a safety meeting with rig crews to discuss: • Conductor broaching ops and mitigation procedures. • Well control procedures and rig evacuation • Flow rates, hole cleaning, mud cooling, etc. • Pump sweeps and maintain mud rheology to ensure effective hole cleaning. • Keep mud as cool as possible to keep from washing out permafrost. • Pump at 400-600 gpm. Monitor shakers closely to ensure shaker screens and return lines can handle the flow rate. • 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 • Slow in/out of slips and while tripping to keep swab and surge pressures low • Ensure shakers are functioning properly. Check for holes in screens on connections. • 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. • 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). • Perform wireline gyros until clean MWD surveys are seen. Take MWD surveys every stand drilled. Page 13 n Hilcorp C®poY Milne Point Unit M-11 SB Injector Drilling Procedure 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: • Gas hydrates can be identified by the gas detector and a decrease in MW or ECD • Monitor returns for hydrates, checking pressurized & non -pressurized scales • Past wells on E pad have increased MW to 9.8 ppg and added I-1.5ppb of Lecithin & .5% lube. After drilling through hydrate sands, MW was cut back to normal • 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. 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. 11.4 12-1/4" hole mud program summary: • 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 • 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. • 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. • 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. • 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 14 n Hilcorp U Milne Point Unit M-11 SB Injector Drilling Procedure • Casing Running: Reduce system YP with DESCO as required for running casing as allowed (do notjeopardize 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 AN FL pH Tem 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 N liquids) M -I Gel 50 lb sx 25 Soda Ash 50 lb sx 0.25 Pol Pac Supreme UL 50 Ib sx 0.08 Caustic Soda 50 lb sx 0.1 SCREENCLEEN 55 gat 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 • Pump at full drill rate (400-600 gpm), and maximize rotation. • Pull slowly, 5 -10 It /minute. • Monitor well for any signs of packing off or losses. • Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay balling. • If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until parameters are restored. 11.7 TOOH and LD BHA 11.8 No open hole logging program planned..tic� 4 E -L,;..' // J Page 15 Milne Point Unit M-17 SB Injector Hilco Drilling Procedure Env® C® 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) • Ensure 9-5/8" TXP x DS50 XO on rig floor and M/U to FOSV. • Use BOL 2000 thread compound. Dope pin end only w/ paint brush. • R/U of CRT if hole conditions require. • R/U a fill up tool to fill casing while running if the CRT is not used. • Ensure all casing has been drifted to 8.75" on the location prior to running. • Be sure to count the total # of joints on the location before running. • Keep hole covered while R/U casing tools. • Record OD's, ID's, lengths, S/N's of all components w/ vendor & model info. 12.3 PIU 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 Ada for . • Ensure bypass baffle is correctly installed on top of float collar. This end up. Bypass Baffle • Ensure proper operation of float equipment while picking up. • Ensure to record S/N's of all float equipment and stage tool components. Page 16 990 12.5 Float equipment and Stage tool equipment drawings: Type H ES Cementer Part No. SO No. Closing Sleeve No. Shear Pins Opening Sleeve No. Shear Pins ES Cementer Depth Baffle Adapter (it used) ID Depth Bypass or Shut -oft Baffle ID Depth Float Collar Depth Float Shoe AT Depth Hole TD "Reference Casing Sales Manual Section 5 Page 17 »A Overall Length 8 Min. ID After Drrllout C Max. Tool OD D opening Seat ID E Closing Seat ID Plug Set Part No. SO No. Closing Plug OD Opening Plug OD OD ShuloR Plug OD Bypass Plug (if used) OD Milne Point Unit M-11 SB Injector Drilling Procedure XikorP EUI Running Order Wl Cements : shut Off Pall Raffle Adapter 'a RpPass Plug aY Pass a -M Run War rear Shoe Milne Point Unit M-11 SB Injector Hilcorp Drilling Procedure U� 12.6 Continue running 9-5/8" surface casing • Fill casing while running using fill up line on rig floor. • Use BOL 2000 thread compound. Dope pin end only w/ paint brush. • Centralization: • Verify depth of lowest Ugnu water sand for isolation with Geolo ist Depth Interval Centralization Shoe —1000' Above Shoe 1/'t 1000' above Shoe — 2000' above Shoe 1/ 2 jts (Top of U¢nu) • Utilize a collar clamp until weight is sufficient to keep slips set properly. • Break circulation prior to reaching the base of the permafrost if casing run indicates poor hole conditions. • Any packing off while running casing should be treated as a major problem. It is preferable to POH with casing and condition hole than to risk not getting cement returns to surface. 12.7 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). • Install centralizers over couplings on 5 joints below and 10 joints above stage tool. • Do not place tongs on ES cementer, this can cause damaged to the tool. • Ensure tool is pinned with 6 opening shear pins. This will allow the tool to open at 3300 psi. • 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" 404 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 Page 18 GEOMETRY Threads per it 5 CPnneclion OD Opeen REGULAR PERFORMANCE Nwninal OD N.inal lC 8.625 in. 8.835in. Nominal Weight Wail Thickness 40 lba9t 0.385 in. Milne Point Unit 8.676 in. 38.87 lb,i t be M-11 SB Injector Compression strength Hilco n_� Max. Nlowable Sending 38 `+100 ft Drilling Procedure TXP® BTC ...1110812018 OlrlsiJa Diameter 8.825in_ Min. Wall Thickness Ti Grade LeD low Type Wall Thickness 0.395ie. ConnxNon OD OptI REGULAR COUPLING PIPE BODY I Grade L80 Type 1' Drift AP19hndard Eddy Red lid Band: Red 1s: Bard: Brown 2M Sand. 2nd Sandi - Brown Type Casing 3rd Band, - 3rd Banc: - 41h Band - GEOMETRY Threads per it 5 CPnneclion OD Opeen REGULAR PERFORMANCE Nwninal OD N.inal lC 8.625 in. 8.835in. Nominal Weight Wail Thickness 40 lba9t 0.385 in. Dnft Ppin End Might 8.676 in. 38.87 lb,i t OC ToWwce API PERFORMANCE Body Yield strength 916.1000 Its ImannlYiedi $750 psi SMYS 80000 psi Co6apse 3090 Psi GEOMETRY CGe.w on OD 10.625 in. Coupling Length 10825 en. Connection O 8.823 in. Make-up Lass 4.891 in. Threads per it 5 CPnneclion OD Opeen REGULAR PERFORMANCE Tension Elfxiency 100.05 JeintYeld strength 916.000x1000 Intimal Pressure Capeeny t41 5750000 psi be Cunpression Effgiencg 100% Compression strength 916000 x1000 Max. Nlowable Sending 38 `+100 ft Nis Ecemal Pressure Capacity 3090.000 psi MAKE-UPTORQUES Mimun 18860 114t Opdmum 20960 hobs Maxm nn 23060 ft -lbs OPERATION LIMIT TORQUES Operari^6'>';:a 35600 V'. Yield Toreue 43400 ft-Ibs Notes This connection is fully interchangeable with: TXP,8• BTC - 9.625 in. - 36143.5 / 47 / 53.5158.4 Ibs/ft [1] Internal Pressure Capacity related to structural resistance only. Internal pressure leak resistance as per section 10.3 API 5C31 ISO 10400 - 2007. Datasheet is also valid for Special Bevel option when applicable - except for Coupling Face Load, which will be reduced. Please contact a local Tenaris technical sales representative. Page 19 Milne Point Unit M-11 SB Injector Drilling Procedure 12.8 Continue running 9-5/8" surface casing • Fill casing while running using fill up line on rig floor. • Use BOL 2000 thread compound. Dope pin end only w/ paint brush. • Centralization: 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 20 Milne Point Unit M-11 SB Injector Hilco_TTY Drilling Procedure Enetp Compey 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. • How to handle cement returns at surface. Ensure vac trucks are on standby and ready to assist. • Which pumps will be utilized for displacement, and how fluid will be fed to displacement PUMP- • Ensure adequate amounts of water for mix fluid is heated and available in the water tanks. • Positions and expectations of personnel involved with the cementing operation. i. Extra hands in the pits to strap during the cement job to identify any losses • Review test reports and ensure pump times are acceptable. • Conduct visual inspection of all 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 151 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 V Stage Total Cement Volume: Page 21 t -7S s, -1K 5k Section Calculation Vol (bbl) Vol (ft3) 12-1/4" OH x 9-5/8" @ (4,396' - 2500') x .0558 bpf x 1.3 = 137.5 772.2 Qi Casing Total Lead N.3 137.5 772.2 12-1/4" OH x 9-5/8" (5,396'-4,396')x.0558bpfx1.3= 72.5 407 Casing ~ 9-5/8" Shoe Track 120' x .0758 bpf = 9.1 51.09 Total Tail I I 81.6 458 Page 21 t -7S s, -1K 5k Milne Point Unit M-11 SB Injector Hilcorp Drilling Procedure Enngy CamPM Cement Slurry Design (11t 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. _ 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: 5,314' x .0758 bpf = 402.8 bbls 40 bbls of weighted spacer to be left behind stage tool, confirm spacer is compatible with cement behind stage tool 13.12 Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any point during the job. Be prepared to pump out fluid from cellar. Have black water available to contaminate any cement seen at surface. 13.13 If plug is not bumped at calculated strokes, double check volumes and calculations. Over displace by no more than 50% of shoe track volume, t4.5 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 Page 22 Lead Slurry Tail Slurry System ExtendaCEM'" System SWiftCEM TM System Density 11.7 lb/gal 15.8 lb/gal Yield 4.298 ft3/sk 1.16 ft3/sk Mixed Water 21.13 gal/sk 5.04 gal/sk 13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Watch reciprocation PU and SO weights, if the hole gets "sticky", cease pipe reciprocation and continue with the cement job. 13.9 After pumping cement, drop top plug (Shutoff plug) and displace cement with spud mud out of mud pits, spotting water across the HEC stage cementer. _ Ensure volumes pumped and volumes returned are documented and constant communication between mud pits, HEC Rep and HES Cementers during the entire job. 13.10 Ensure rig pump is used to displace cement. To operate the stage tool hydraulically, the plug must be bumped. 13.11 Displacement calculation: 5,314' x .0758 bpf = 402.8 bbls 40 bbls of weighted spacer to be left behind stage tool, confirm spacer is compatible with cement behind stage tool 13.12 Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any point during the job. Be prepared to pump out fluid from cellar. Have black water available to contaminate any cement seen at surface. 13.13 If plug is not bumped at calculated strokes, double check volumes and calculations. Over displace by no more than 50% of shoe track volume, t4.5 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 Page 22 Milne Point Unit M-11 SB Injector Hilco Drilling Procedure E� 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 {fo'r the 2nd stage of the cement job. ��"'"i' If ESIPC is ran, Increase pressure to 2090 psi to shift ESIPC sleeve and to begin 'Sr" P ^ inflating the packer. Inflate packer as per HEC rep. Reference ESIPC procedure. • Once ESIPC packer is inflated, increase pressure to 3000 psi to open rupture disc / 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 23 n Hilcorp E, �v ^r Second Stage Surface Cement Job: Milne Point Unit M-11 SB Injector Drilling Procedure 13.18 Prepare for the 2nd stage as necessary. Circulate until first stage reaches sufficient compressive strength. (If ESIPC is used and packer element inflated, CBU xl minimum before pumping second stage). 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 2"d Stage Total Cement Volume: Cement Slurry Design (2nd stage cement job): Section Calculation Vol (bbl) Vol (ft3) SwiftCEM "" System (Hal Cem) 20" Conductor x 9-5/8" Casing (110') x .26 bpf x 1= 28.6 161 v 12- 1 4" CH x 9-5/8" Casing (2000'- 110') x .0558 bpf x 3 = 316.4 1776.3 Total Lead 345 1937 12-1/4" CH x 9-5/8" Casing (2500' - 2000') x .0558 bpf x 2 = 55.8 314 ~ Total Tail 55.8 314 Cement Slurry Design (2nd stage cement job): Page 24 Lead Slurry Tail Slurry System Permafrost L SwiftCEM "" System (Hal Cem) Density 10.7 lb/gal 15.8 lb/gal Yield 4.3279 ft3/sk 1.16 ft3/sk Mixed Water 21.405 gal/sk 5.08 gal/sk Page 24 n Hilcorp Em �pY Milne Point Unit M-11 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 n job. Set slips I ._X13.30 Make initial cut on 9-5/8" final joint. L/D cut joint. Make final cut on 9-5/8". Dress off stump. W NNN"' ✓ Install 9-5/8" wellhead. If transition nipple is welded on, allow to cool as per schedule. Ensure to report the following on wellez: • Pre flush type, volume (bbls) & weight (ppg) • Cement slurry type, lead or tail, volume & weight • Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration a. Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid b. Note if casing is reciprocated or rotated during the job c. Calculated volume of displacement, actual displacement volume, whether plug bumped & bump pressure, do floats hold d. Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure e. Note if pre flush or cement returns at surface & volume f Note time cement in place g. Note calculated top of cement h. Add any comments which would describe the success or problems during the cement job Send final "As -Run " casing tally & casing and cement report to jengeL@hilcorp. com and cdingerna hilcorycom This will he included with the EOW documentation that goes to the AOGCC. Page 25 H H E=R 14.0 14.1 14.2 14.3 Milne Point Unit M-11 SB Injector Drilling Procedure BOP NIU and Test N/D the diverter T, knife gate, diverter line & N/U 11" x 13-5/8" 5M casing spool. N/U 13-5/8" x 5M BOP as follows: • BOP configuration from top down: 13-5/8" x 5M annular / 13-5/8" x 5M double gate / 13- 5/8" x 5M mud cross / 13-5/8" x 5M single gate • Double gate ram should be dressed with 2-7/8" x 5" VBRs in top cavity, blind ram in bottom cavity. • Single ram can be dressed with 2-7/8" x 5" VBRs • N/U bell nipple, install flowline. • Install (1) manual valve & HCR valve on kill side of mud cross. (Manual valve closest to mud cross). • Install (1) manual valve on choke side of mud cross. Install an HRC outside of the manual valve Run 5" BOP test plug 14.4 Test BOP to 250/3000 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min. • Test 5" test joints • Confirm test pressures with PTD • Ensure to monitor side outlet valves and annulus valve pressure gauges to ensure no pressure is trapped underneath test plug • Once BOPE test is complete, send a copy of the test report to town engineer and drilling tech 14.5 R/D BOP test equipment 14.6 Dump and clean mud pits, send spud mud to G&I pad for injection. 14.7 Mix 8.9 ppg FloPro fluid for production hole. 1 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 26 H Hilcorp Milne Point Unit M-11 SB Injector Drilling Procedure 15.0 Drill 8-1/2" Hole Section 15.1 M/U 8.5" Cleanout BHA (Milltooth Bit & 1.220 PDM) 15.2 TIH w/ 8-1/2" cleanout BHA to stage tool. Note depth TOC tagged on AM report. Drill out stage tool or ESIPC. 15.3 TIH to TOC above the baffle adapter. Note depth TOC tagged on morning report. 15.4 R/LJ and test casing to 2500 psi / 30 min. Ensure to record volume / pressure (every 1/4bbl) and plot on FIT graph. AOGCC reg is 50% of burst = 5750 / 2 = —2875 psi, but max test pressure on Fj�--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 FMW. Chart Test. Ensure testis recorded on same chart as FIT. Document incremental volume pumped (and subsequent pressure) and volume returned. 15.8 POOH & LD Cleanout BHA 15.9 PIU 8-1/2" directional BHA. • Ensure BHA components have been inspected previously. • Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. • Ensure TF offset is measured accurately and entered correctly into the MWD software. • Ensure MWD is R/U and operational. • Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. • Drill string will be 5" 19.5# 5-135 DS50 & NC50. • Run a ported float in the production hole section. 15.10 8-1/2" hole section mud program summary: • Density: Weighting material to be used for the hole section will be calcium carbonate. Additional calcium carbonate will be on location to weight up the active system (1) ppg above highest anticipated MW. Use appropriate SAFECARB blend on this well Page 27 • Solids Concentration: It is imperative that the solids concentration be kept low while drilling the production hole section. Keep the shaker screen size optimized and fluid running to near the end of the shakers. It is okay if the shakers run slightly wet to ensure we are running the finest screens possible. • Rheology: Keep viscosifier additions to an absolute minimum (N -VIS). Data suggests excessive viscosifier concentrations can decrease return permeability. Do not pump high vis sweeps, instead use tandem sweeps. Ensure 6 r2m is > 8.5 (hole diameter) for sufficient hole cleanine • Run the centrifuge continuously while drilling the production hole, this will help with solids removal. • Dump and dilute as necessary to keep drilled solids to an absolute minimum. • MD Totco PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller's console, Co Man office, & Toolpusher office. System Type: 8.9 — 9.5 ppg FloPro drilling fluid Properties: Interval Densi Milne Point Unit YP LSYP Total Solids M-11 SB Injector HPHT Hilco+TTy Erc c22 Drilling Procedure • Solids Concentration: It is imperative that the solids concentration be kept low while drilling the production hole section. Keep the shaker screen size optimized and fluid running to near the end of the shakers. It is okay if the shakers run slightly wet to ensure we are running the finest screens possible. • Rheology: Keep viscosifier additions to an absolute minimum (N -VIS). Data suggests excessive viscosifier concentrations can decrease return permeability. Do not pump high vis sweeps, instead use tandem sweeps. Ensure 6 r2m is > 8.5 (hole diameter) for sufficient hole cleanine • Run the centrifuge continuously while drilling the production hole, this will help with solids removal. • Dump and dilute as necessary to keep drilled solids to an absolute minimum. • MD Totco PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller's console, Co Man office, & Toolpusher office. System Type: 8.9 — 9.5 ppg FloPro drilling fluid Properties: Interval Densi PV YP LSYP Total Solids MBT HPHT Hardness Production 11 8.9-9.5 -A 15-25 - ALAP 15-30 4-6 <10% <8 <l 1.0 <100 System Forni�lah'on: Product- production Size Pkg ppb or (% liquids) Busan 1060 55 gal dm 0.095 FLOTROL 55 lb sx 6 CONQOR 404 WH (8.5 gaU100 bbls) 55 gal dm 0.2 FLO-VISPLUS 25 lb sx 0.7 KCl 50 lb sx 10.7 SMB 50 lb sx 0.45 LOTORQ 55 gal dm 1.0 SAFE -CARE 10 (verify) 50 lb sx 10 SAFE-CARB 20 (verify) 50 Ib sx 10 Soda Ash 50 lb sx 0.5 Page 28 N I�ir'lc� 15.11 TIH with 8-1/2" directional assembly to bottom 15.12 Displace wellbore to 8.9 ppg Flo Pro drilling fluid Milne Point Unit M-11 SB Injector Drilling Procedure 15.13 Begin drilling 8.5" hole section, on -bottom staging technique: • Tag bottom and begin drilling with 100 - 120 rpms at bit. Allow WOB to stabilize at 5-8k. • Slowly begin bringing up rpms, monitoring stick slip and BHA vibrations • 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 ner Geologist and Drilling Engineer. • Flow Rate: 350-550 gpm, target min. AV's 200 ft/min, 385 gpm • RPM: 120+ • Ensure shaker screens are set up to handle this flowrate. Ensure shakers are running slightly wet to maximize solids removal efficiency. Check for holes in screens on every connection. • Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low • Take MWD surveys every stand, can be taken more frequently if deemed necessary, ex: . concretion deflection • Monitor Torque and Drag with pumps on every 5 stands • Monitor ECD, pump pressure & hookload trends for hole cleaning indication • Surveys can be taken more frequently if deemed necessary. • Good drilling and tripping practices are vital for avoidance of differential sticking. Make every effort to keep the drill string moving whenever possible and avoid stopping with the BHA across the sand for any extended period of time. • Use ADR to stay in section. Reservoir plan is to undulate between Schrader OAl & OA3 lobes in 1000-1500' MD increments, and keeping DLS <3° when moving between lobes • 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. • Target ROP is as fast as we can clean the hole without having to backream connections • Injection Pressure from F-110 & L-59 has been seen on M-10. Watch for higher than expected pressure. Increase MW if needed. • Schrader Bluff OA Concretions: 5-10% of lateral L-47:6%, L-50 9.5% F-106: 6.1%, F-107: 4.7%, F-018: 9.9%, F-109: 10%, F-110: 10.1% 15.15 Reference: Open hole sidetracking practice: • If a known fault is coming up, put a slight "kick-off ramp" in wellbore ahead of the fault so we have a nice place to low side. Attempt to lowside in a fast drilling interval where the wellbore is headed up. Orient TF to low side and dig a trough with high flowrates for the first 10 ft, working string back and forth. Trough for approx. 30 min. Page 29 H Hilcorp Milne Point Unit M-11 SB Injector Drilling Procedure • 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 • Monitor BU for increase in cuttings, cuttings in laterals come back in waves and not a consistent stream, circulate more if necessary • Ensure mud has necessary lube % for running liner • If seepage losses are seen while drilling, consider reducing MW at TD to 9.Oppg minimum 15.17 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 (0 350ml samples passing through the screen in the same amount of time which will indicate no plugging of the screen). Reference PST Test Procedure • Injection Control Devices (ICDs) are wire wrapped, and require passing PST with 250µ Coupons • Circulate and condition mud as much as needed to pass the production screen test • If not passing after first test, call Completion Engineer 15.18 BROOH with the drilling assembly to the 9-5/8" casing shoe • Circulate at full drill rate (385 gpm max). • Rotate at maximum rpm that can be sustained. • Limit pulling speed to 5 — 10 min/std (slip to slip time, not including connections). • If backreaming operations are commenced, continue backreaming to the shoe 15.19 CBU minimum two times at 9-5/8" shoe and clean casing with high vis sweeps. 15.20 Monitor well for flow. Increase mud weight if necessary Wellbore breathing has been seen on past MPU SB wells. Perform extended flow checks to determine if well is breathing, treat all flow as an influx until proven otherwise If necessary, increase MW at shoe for any higher than expected pressure seen 15.21 POOH and LD BHA. Rabbit DP on TOH, ensure rabbit diameter is sufficient for future ball drops. 15.22 Continue to POH and stand back BHA if possible. Rabbit DP on TOH, ensure rabbit diameter is sufficient for future ball drops. Only I" open hole logs are planned for the hole section (GR + Res). There will not be any additional logging runs conducted. Page 30 H Hilco�r 16.0 Run 4-1/2" Injection Liner (Lower Completion) Milne Point Unit M-11 SB Injector Drilling Procedure 16.1. Well control preparedness: In the event of an influx of formation fluids while running the 4- 1/2" liner with ICD and swell packers, the following well control response procedure will be followed: /• With ICD across the BOP: P/U & M/U the 5" safety joint (with 4-1/2" crossover installed on (/ bottom, TIN 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. / • With 4-1/2" solid joint across BOP: Slack off and position the 4-1/2" solid joint to MU the VITIW 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. Well control preparedness: In the event of an influx of formation fluids while running the 2- 3/8" inner string inside the 4-1/2" liner: • P/U & M/U the 5" safety joint (with 4-1/2" x 2-3/8" triple connect crossover installed on aA�1L` bottom, TIW valve in open position on top, 2-3/8" handling joint above TIW). M/U 2-3/8" 15{a and then 4-1/2" to triple connect. • This joint shall be fully M/U with crossovers and available prior to running the first joint • Slack off and position the 5" DP across the BOP, shut in ram or annular on 5" DP. Close TIW valve. Proceed with well kill operations. 16.4. R/U 4-1/2" liner running equipment. • Ensure 4-1/2" Hydril 625 x DS -50 crossover is on rig floor and M/U to FOSV. • Ensure the liner has been drifted on the deck prior to running. • Be sure to count the total # of joints on the deck before running. • Keep hole covered while R/U casing tools. • Record OD's, ID's, lengths, S/N's of all components w/ vendor & model info. 16.5. Run 4-1/2" injection liner. • 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 ICDs. • Utilize a collar clamp until weight is sufficient to keep slips set properly. • Use lift nubbins and stabbing guides for the liner run. 1/- • Fill 4-V2" liner with PST passed mud (to keep from plugging ICDs with solids) /+ • Install ICDs and swell packers as per the Running Order (Estimate 8 evenly spaced). • Do not place tongs or slips on swell packer elements or ICDs. • ICD and swell packer placement ±40' • The ICD connection is 4-1/2" 13.5# Hydril 625 • Remove protective packaging on swell packers just prior to picking up • If liner length exceeds surface casing length, ensure centralizers are placed I Jt for each joint outside of the surface shoe. This is to mitigate difference sticking risk while running inner string. Page 31 Milne Point Unit M-11 SB Injector Drilling Procedure • Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10 and 20 rpm 3-1/2" 9.34 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 Page 32 H Hilco7 Evvgy Cmnpey For the latest performance data. always visit our website: wwwAmaris.com Wedge 6250 Milne Point Unit M-11 SB Injector Drilling Procedure 1210412017 PERFORMANCE Tension Efclency Oubiee Diameter 4.500.. Mia wall 87.5% bhmal Press mcapamy 9020.000psi Thickness lbs r) Grade LBO Conpn!saon ETv:iarcy 00.5% Cpr ,an Sne^DN 290.115X1000 TM 1 71]'n03A wall TAicknesz 0290 n. Connec5on 00 REGULAR Fieemal Pmssure Capadty $510.000 psi opeon CAnPIING NPE Way Bogy: Red Ist Bane: Red MAKE-UP TORQUES Grade LBO Type 1 Drill APIStandard IR Band: Bro n 2nd Bane: Ian. 8000 ft -Os opfi. NODA-Ms 2nd Bane: - Bro n TTP. Casino are Bane. - 3rd Band' 4t Band Band: - PIPE BODY DATA GEOMETRY _ Nonwu100 4.500 n Normal Wert 13.50 msl0 o ih 3795n Nominal ID 3.920 in. Woe Thickness 0290,. Rain End WvgM 1395ftsN[ MT� All PERFORMANCE Body Yr G gm 307X1030Ibs mRmaJ YeM 9020 psi SMYS 80000 pv CMlapse 8540ps1 CONNECTION DATA GEOMETRY Conrc OD 4.714 n. Canoe 10 3.049 M. Makeup Loss tax n. Threats perm 359 Conne--eon OD Option REGULAR PERFORMANCE Tension Efclency SIB% J aywdseenph 279.37OXIMB bhmal Press mcapamy 9020.000psi lbs Conpn!saon ETv:iarcy 00.5% Cpr ,an Sne^DN 290.115X1000 Mav A9Pmbleeendng 71]'n03A lbs Fieemal Pmssure Capadty $510.000 psi MAKE-UP TORQUES Ian. 8000 ft -Os opfi. NODA-Ms Nauman 12500 AJbs OPERATION LIMB TORQUES GpeaaVToque 1200Uft4bs Yield Ta 15000 Aabs Notes For further information on concepts indhcated in this datasheet, download the Datasheet Manual from www tenans.wm 16.6. Ensure that the liner top packer is set — 150' MD above the 9-5/8" shoe. • 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. 16.7. R/U false rotary and rtm 2-3/8" 6.4#/ft inner string. Page 33 Milne Point Unit M-11 SB Injector Hilco Drilling Procedure E re c2 16.8. 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. 16.9. 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. 16.10. Note weight of liner. Run liner in the hole one stand and pump through liner hanger to ensure a clear flow path exists. 16.11. 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. 16.12. The liner and inner string will prevent the DP from auto filling. Fill DP every 5 stands, more frequently if SOW trend indicates. 16.13. 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. 16.14. If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensure shoe enters correct hole. 16.15. TIH deeper than planned setting depth. Last motion of the liner should be up to ensure it is set in tension. 16.16. Rig up to pump down the work string with the rig pumps. 16.17. 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. 16.18. Rig up to pump down the work string with the rig pumps. 16.19. Break circulation and begin displacing wellbore to —9.2 ppg KCl/NaCI (adjust brine weight if needed). Note the large OD on the ICDs. Begin circulating at —1 BPM and monitor pump pressures. Slowly bring rate up while circulating the lateral clean. 16.20. Monitor pump pressures closely and adjust pump rate if the well appears to be packing off at the ICDs. Note all losses. Catch mud for future use if feasible. 16.21. Monitor the returned fluids carefully and when no more filter cake appears at the shaker begin pumping SAPP pill. 16.22. Mix and pump 3 tandem 40 bbl 10 ppb SAPP pills (120 bbl total SAPP pill) with 100 bbl in between. Keep circulation rate low to keep from packing off around the ICDs. Monitor shakers for returns of mud filter cake and calcium carbonate. Circulate the well clean. Page 34 H Hilcorp E� ®w r 16.23. Repeat pumping SAPP pills as needed until the wellbore is clean. Milne Point Unit M-11 SB Injector Drilling Procedure Losses during the cleanup of the wellbore are a good indication that the mud filter cake is being removed, including an increase in the loss rate. Monitor the returned fluids to ensure as much mud and wall cake has been removed from the wellbore as possible so as to not impact wellbore injectivity. 16.24. Displace 1.5 OH & Liner volumes. 16.25. Shut down pumps. Drop setting ball down the workstring and pump slowly (1-2 bpm). Slow pump before the ball seats. Do not allow ball to slam into ball seat. Pressure up to 1,500 psi to shift the wellbore isolation valve closed. 16.26. Continue 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. 16.27. 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, 16.28. PU to neutral weight, close BOP and test annulus to 1500 psi for 10 min and chart record same. 16.29. 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. 16.30. Displace 2-3/8" x Liner, pump 2 circulations. 16.31. POOH, L/D and inspect running tools. If setting of liner hanger/packer proceeded as planned, LDDP on the TOH. L/D 2-3/8" inner string. Rack back enough 5" drill pipe for liner top clean outrun 16.32. Make up 3.5" wash tool & RIH on 5" DP to 4.5" liner top. 16.33. Flush liner top at max rate while displacing out well to clean brine. 16.34. POOH LD Remaining 5" DP. Page 35 H Hilcorp 17.0 Run 3-1/2" Tubing (Upper Completion) Milne Point Unit M-11 SB Injector Drilling Procedure 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@bilcoip.com for submission to AOGCC. 17.2 M/U injection assembly and RIH to setting depth. TIH no faster than 90 ft/min. • Ensure wear bushing is pulled. • Ensure 3-%2" EUE 8RD x NC -50 crossover is on rig floor and M/U to FOSV. • Ensure all tubing has been drifted in the pipe shed prior to running. • Be sure to count the total # of joints in the pipe shed before running. • Keep hole covered while R/U casing tools. • Record OD's, ID's, lengths, S/N's of all components w/ vendor & model info. • Monitor displacement from wellbore while RIH. 3-%2" Upper Completion Running Order • 3-'/z" Baker Ported Bullet Nose seal (stung into the tieback receptacle) S • 3 joints (minimum, more as needed) 3-'/z" 9.3#/ft, L-80 EUE 8RD tubing • 3-%2" "XN" nipple at TBD ✓ • 3-'/2" 9.3#/ft, L-80 EUE 8RD tubing • 3-'/2" "X" nipple at TBD MD • 3-'/2" 9.3#/ft, L-80 EUE 8RD space out pups • 1 joint 3-%2" 9.3#/ft, L-80 EUE 8RD tubing • 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. 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 I% corrosion inhibitor. 17.8 Freeze protect the tubing and IA to 3000' MD with ±210 bbl of diesel. Page 36 17.10 Continue pressurizing the annulus to 3000 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 a Page 37 Milne Point Unit M-11 SB Injector Hi EM -2 Drilling Procedure 17.9 Land hanger. RILDs and test hanger. 17.10 Continue pressurizing the annulus to 3000 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 a Page 37 Milne Point Unit M-11 SB Injector Hilco Drilling Procedure UZT_ 19.0 Doyon 14 Diverter Schematic 21.13' 2M Riw- 21-1W 2M— Dry T 21414' 2A Spacer Spa 16-14' 9M o 21.114' WA DSA Page 38 —M' rub Opminp "do V*v "-18' DrvMcr Um H Hilcorp �tM— 20.0 Doyon 14 BOP Schematic Kdl Line --"f' Page 39 Milne Point Unit M-11 SB Injector Drilling Procedure 2-7/8" x 5" VBR Blind Rams x SM HCR :hoke LOM al Gate Valve 2-7/8" x 5ti VBR H Hilcorp � T 21.0 Wellhead Schematic Page 40 Milne Point Unit M-11 SB Injector Drilling Procedure CAMERON II"5KA4BS A ScWumberger Company 116.091, pr 5K �+ �C .. A c 21 25" .�: H-0195 la. t2a2n I HraMon H Hilcorp U - 22.0 Days Vs Depth I 111 111 L d d a 8000 v N 10000 12000 14000 16000 0 Page 41 Milne Point Unit M-11 SB Injector Drilling Procedure MPU M-11 SB OA Injector Days vs Depth 5 10 15 20 Days 25 30 Milne Point Unit M-11 SB Injector Hilcorp Drilling Procedure c®v.^r 23.0 Formation Tops & Information MPU M-11 Formations (wp08) MD (ft) TVDss (ft) TVD Formation Pressure (ft) (psi) EMW (ppg) Base Permafrost 2141 1284 1342 590.48 8.46 LA3 3844 3191 3250 1430 8.46 Schrader Bluff NA 4736 3799 3800 1672 8.46 Schrader Bluff OA 5414 3902 3960 1742.4 8.46 L -Pad Data Sheet Formation Description (Closest & Most Analogous MPU Pad to Moose Pad) GENERALIZED GEOLOGICAL _FORECAST SS GEOLOGICAL COMMENTS TVD FM LITH DESCRIPTION u 0.a NOTE: See Indheidual Well Program for TWq�,o Gubi specific casing design, depths, sizes, N. fro'. gpp weights, grades and corInections. 1. O Ilncareolldehd cwres M rteelam sand rang small gravel g '• •. MN rNnor.iltlwa. IF SIGNIFICANT AMOUNTS OF GRAVEL 1 000' g ARE ENCOUNTERED WHEN DRILLING THE SURFACE HOLE, THE VISCOSITY OF THE MUD SYSTEM SHOULD IMMEDIATELY BE RAISED TO 150 SEC TO ENSURE EFFECTIVE HOLE CLEANING. +ton• Base permafrost bbreeds of sane, clays and sll.tures with occasional 2,000• show of awl. Wath possible sldalrackhp w le Sass. rets, wasNn¢'reaMn¢ LJ] s Ld S. � No hydrates encountered on I. -Ped wells drilled to date. Corelrned Irdarbods o1 sand, clays and onstres wth occasional shows of coal. Tracesof pyTiaa aNb ]100 It 3,000' Intervalat.i. 3t00 If nen be .fCk,.nd tight (1.41). Gay tMrbed• between 3000 and 4500 K C Utz A 36Sr a«n> Y UGNU: series f.crsw, upw.rds.nde which.. I�acpl made W of: Thom top t bottom) warea sand line Card. Why shah Batter doveloped l.e"WIN steles, as you UGNU progress Into the Land M(deeper). ugnuandsch.d•r¢wc Pw.iM•hydrocarbonellneMd tom•^d tos Wconaref Mbned.wiopneet NortMm area 1. I.tel downetructaeandwet. •37W W n4 I+V.cI 4000 INA) Schrader Bluff Sands: 4,000. Coa.ee .5onng cw.entp upnam Sanas as above Schadet BluR: Possible lost ci¢ulalion esceptmerecwdensed.M.1th wuslwal.o.L zone while drilling long strings and running •aye' F�. say dch •rote IMarval neo to 4600 K tgnuandschderBlas PwalNoMaowrbonenmhd casing. Recommend deep setting surface (Oyy te$Wcenerof Mllro0lMlppment LJy a,M LlS aro casing for Kuparuk long strings. Also, the mmpteted In the Schrader Bluff.and Northern... of Schrader Bluff sands are a potential Schrader L -Pad la aownet.ctw,nd neat. differential stuck pipe interval it left un -cased Bluff C surface ca.lrrg pol. h •rote below for Kuparuk long strings. Sands:1 Schrader Bluff OB sand for longer reach welt. Page 42 H Hilco�r 24.0 Anticipated Drilling Hazards Milne Point Unit M-11 SB Injector Drilling Procedure 12-1/4" Hole Section: Lost Circulation Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Gas Hydrates Gas hyrates have not been seen on Moose pad. However, be prepared for them. Remember that hydrate gas behave differently from a gas sand. Additional fluid density will not prevent influx of gas hydrates, but can help control the breakout at surface. Once a gas hydrate has been disturbed the gas will come out of the hole. Drill through the hydrate section as quickly as possible while minimizing gas belching. Minimize circulation time while drilling through the hydrate zone. Excessive circulation will accelerate formation thawing which can increase the amount of hydrates released into the wellbore. Keep the mud circulation temperature as cold as possible. Weigh mud with both a pressurized and non -pressurized mud scale. The non -pressurized scale will reflect the actual mud cut weight. Add 1.0 — 2.0 ppb Lecithin to the system to help thin the mud and release the gas. Isolate/dump contaminated fluid to remove hydrates from the system. Hole Cleaning: Maintain rheology of mud system. Sweep hole with high viscosity sweeps as necessary. Optimize solids control equipment to maintain density, sand content, and reduce the waste stream. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to avoid washing out a particular section of the hole. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Anti -Collison: There are a number of wells in close proximity. Take directional surveys every stand, take additional surveys if necessary. Continuously monitor proximity to offset wellbores and record any close approaches on AM report. Discuss offset wellbores with production foreman and consider shutting in adjacent wells if necessary. Monitor drilling parameters for signs of collision with another well. Wellbore stability (Permafrost, running sands and gravel, conductor broaching): Washouts in the permafrost can be severe if the string is left circulating across it for extended periods of time. Keep mud as cool as possible by taking on cold water and diluting often. High TOH and RIH speeds can aggravate fragile shale/coal formations due to the pressure variations 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: V Treat every hole section as though it has the potential for H2S. No H2S events have been documented on drill wells on this pad. Page 43 n Hilcorp Milne Point Unit M-11 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. 8-1/2" Hole Section: Anti -Collision: No immediate AC concerns on this well. However, there will be future issues that will be mitigated through gyro surveys. 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. Page 44 f 1,. , 2 ••1 a � MiU M 14082 MPUJN90 , I — rU J6�Wµ8dGe �• � J 3<nM y 3040 tt 0 3" 1W 1050 1400 1150 2100 N50 3800 0150 M ]RM14 aM 45M 4M 52H 'u&V WW 6H1 Mmsun U pM (100 uS n) 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. Page 44 H Hilcorp E� C. -Pr" Milne Point Unit M-11 SB Injector Drilling Procedure H2S: r Treat every hole section as though it has the potential for 1-12S. No 1-12S 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 1-12S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Abnormal Pressures and Temperatures: ✓ Offset injection pressure from F-110 & L-50 were seen on M-10. Be prepared to increase MW if necessary Page 45 Milne Point Unit M-11 SB Injector Hilcorp Drilling Procedure 25.0 Dovon 14 T o 1 o Page 46 H Hilcorp E.� C 26.0 FIT Procedure Milne Point Unit M-11 513 Injector Drilling 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/Li 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 u Hilo W22 27.0 Doyon 14 Choke Manifold Schematic Milne Point Unit M-11 SB Injector Drilling Procedure Page 48 J Milne Point Unit M-11 SB Injector Drilling Procedure 28.0 Casing Design n Hi 222 Calculation & Casing Design Factors Hole Size 12-1/4" Hole Size 8-1/2" Hole Size DATE: 1.21.2019 WELL: MPU M-11 DESIGN BY: Joe Engel n Criteria: Mud Density: 9.2 ppg Mud Density: 9.2 ppg Mud Density: Drilling Mode MASP: 1349 psi (see attached MASP determination & calculation) MASP: Production Mode MASP: 1349 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 Page 49 Casing Section Calculation/Specification 1 2 3 4 Casing OD 9-5/8" 4-1/2" Top (MD) 0 5,250 Top (TVD) 0 3,941 Bottom (MD) 5,396 16,250 Bottom (TVD) 3,959 3,965 Length 5,396 11,000 Weight (ppD 40 13.5 Grade L-80 L-80 Connection TV H625 Weight w/o Bouyancy Factor (lbs) 215,840. 148,500 Tension at Top of Section (Ibs) 215,840 148,500 Min strength Tension (1000 lbs) 916 279 Worst Case Safety Factor (Tension) 4.24 7 - Collapse Pressure at bottom (Psi) 1,956 1,959 Collapse Resistance w/o tension (Psi) 3,090 8,540 Worst Case Safety Factor (Collapse) 1.58 4.36 , MASP (psi) 1,349 1,349 Minimum Yield (psi) 5,750 9,020 Worst case safety factor (Burst) 4.26 6.69 ' Page 49 H Hilcor eo —,p 29.0 8-1/21' Hole Section MASP Milne Point Unit M-11 SB Injector Drilling Procedure Maximum Anticipated Surface Pressure Calculation 1-iilco1 8-1/2" Hole Section MPU M-11 Milne Point Unit MD TVD Planned Top: 5396 3959 Planned TD: 16250 3965 Anticipated Formations and Pressures: Formation TVD Est Pressure Oil/Gas/Wet PPG Grad Schrader Bluff OA Sandi 3,959 1742 Oil 8.46 1 0.440 Offset Well Mud Densities Wall MW ranaa Tnn (TVDI Snttom IND) Date L-50 8.8-9.1 Surface 4125 2015 L-49 9.0-9.2 Surface 4196 2015 L-48 8.9-9.2 Surface 4147 2015 L-47 8.8-9.0 Surface 4158 2015 L-46 9.0-9.3 Surface 4177 2015 Assumptions: 1. Field test data suggests the Fracture Gradient in the Schrader Bluff is btwn 11.5 and 15 ppg EMW. 2. Maximum planned mud density forthe 8-1/2" hole section is 9.5 ppg. 3. Calculations assume full evacuation of wellbore togas Fracture Pressure at 9-5/8" shoe considering a full column of gas from shoe to surface: 3,965 (ft) x 0.78(psi/ft)= 3093 3093(psi)-[0.1(psi/ft)'3965(ft)]= 2697 psi MASP from pore pressure (complete evacuation of wellbore togas from Schrader Bluff OA sand) 3965 (ft) x 0.44(psi/ft)= 1745 psi 174S(psi)-0.1(psi/ft)'3965(ft) 1349 psi 'I Summary: 0 1. MASP while drilling 8-1/2" production hole is governed by pore pressure and evacuation of entire wellbore togas at 0.1 psi/ft. Page 50 Milne Point Unit M-11 SB Injector Hilmal Drilling Procedure Em 30.0 Spider Plot (NAD 27) (Governmental Sections) Sec:2 'Sec. i 3.. \i, / ��/��_Sec.6_ \ 3 \ 4 )Sec/5...f (625) a ♦ , 1 ez F9 fi,P� I , l 6JL Ill i, I \ G Pain > I ADL3882351' -• '- `\ADL025 Co¢uz_8 'Sec 11 Sec. 12 0629) Loz/a, L -me //\ i ADL355023 %\ N1PU M-11'SHL 'P/:' 1(\ P� —< ____ N1PU M-II_TPH t `(P`STpO ;IP PE50.00`f / \/ I I L ��Sec. Sec.',13 I I sec.- 18 %�` i. 1 17`• MIL POINT UNIT I (630) 1 /�/ U013N009E. U013NO10E`�tL-+s Sm. 14 La)A I \ / •L-- I I � I AbL025515 . ALfO 1j/ 1 lV�NO. IL•A IL-S3PB1 1 II /' / N1PU N7 -I I_BHL .51 1 1 L'37 L-A 1 L51 ? 01 Sec. 2311 Sec.•24 19 Sec. 20 1 I _ 1 Legend , 'u; -oto MINE SITE E • MPU M-11 SHL Other Surface Holes (SHE) 3:n}'M x MPU M-11_TPH Other Bottom Holes (SHL) L-3sAYe2 - - -Other Well Paths MPU M-11_BHL _ Coastline (USGS 1:63k) .. EQUIPMENT PAD ADL025519 O 08 and Gas Unit Boundary Sec. 26 Sec. 25 AD Pad Footprint KUPARUK RIVER UNIT Milne Point Unit Ili.y ,bi�lll. MPU M-11 Well 0 1,000 2,000 m.P wl♦. ,aarmw WPO8 mommom== Feet Page 51 n Hileorp Est,, C®PnY 31.0 Surface Plat (As Built) (NAD 27) 1 M-04 M-031 ` I MPU MOOSE PAD NOTES: 1. AL44EA STAR PLANE OWRONARS APE NADET. SOFT 4 I SODOM PR90ONS ARE NAD27. } MASS a HORIZONTAL AND VFRIICIL CONTROL IS M005 PAD MONUMENT CP2. 4. NN MOOSE PAD SCALE FAC' IS OINVUH. i DAR OF MWEY. SE I]ER 2A SMB. R. PER'NEMLE F¢0 SOK NC,! -M PP, 2M -X Page 52 MOOSE PAD Al 23 Milne Point Unit M-11 SB Injector Drilling Procedure VICINITY MAP NTs I F_GEND, AS -BUILT MobCfOR ■ EAISONOCGtoucTOR ,gyp•'` a; q,9m 10200 I OCATEO WITHIN PRDTRACTED SEC. 14. T. 13 N.. R. 9 E.. UMIAT MERIDIAN. ALASKA WILL SURVEYOR'S CERTIFICATE I MRMY CERT MAT I AN GRAPHIC SCALE TOOPRMYREOACMU L/S.MKD ANDDi UMN� 0 100 200 b0 il$ STAT£ OF ALASKA AND NAT NO. TPS AS-EP.ILT REPRESENTS A SURVEY (N PEST) MADE BY LLE ORL.NDER MY OFECT 200 N. VPERMSON AND MAT Aa DIMENSIONS AND OMOR DETAILS ARE CORREM AS OF SEPRMBER 26, 2D18. I OCATEO WITHIN PRDTRACTED SEC. 14. T. 13 N.. R. 9 E.. UMIAT MERIDIAN. ALASKA WILL A.S.P. GEDDETIC GEODETIC SECTION CELLAR NO. COCROINATES POSITION DMS POSITION D.DO OFFSETS BOX EL Y- 6,027,889.71 70'29'14.024" 70.4872289' 5,040' FSL 25.0' M-03 X- 533.363.90 149'43'38.285" 149.7273014' 801' FEL Y= 6,027,889.58 70'29'14.021" 70.4872281' 5,040' FSL 25.0' M-04 X= 533,393.80 149'43'37.405" 149.7270569' 771' FEL Y= 6,027,889.65 70'29'13.990" 70.4872194' 5,037' FSL 24.9 M-10 X= 534,113.80 149'43'16.220" 149.7211722' 51' FEL Y=.6,027,869.61 70'29'13.993" 70.4872203' 5,037' FSL ' 25.0' M-11 X= . 534,023.88 149'43'18.865" 149.7219069' 141' FEL Y= 6,027,889.80 70'29'13.999" 70.4872219' 5,037' FSL 25.0' M-12 Xs 533,933.89 149'43'21.513" 149.7226425' 231' FEL Mms bell yR�ro�Alaska P 2 P IaRK PAD IFMILNE PONT, ALASKA s�T NOOSE PAD, Y,E116 N-03. 04, 10, 11, 17 P, ""�"'+r _ 2Pu• CONDUCTOR AS -BUILT 1 ' I H Hilcrp Ems122 32.0 Milne Point Unit M-11 SB Injector Drilling Procedure Schrader Bluff OA Sand Offset MW vs TVD Chart Page 53 Schrader Bluff OA Sand Offset MW vs TVD mw, PPS 8.5 8.7 8.9 9.1 9.3 9.5 9.7 9.9 10.1 10.3 10.5 0 Soo 1000 1500 2000 0 2500 3000 3500 4000 4500 —MPU L-46 (2015) —MPU L-47 (2015) —MPU L-48 (2015) —MPU L-49 (2015) —MPU L-50 (2015) —MPU F-106 (2017) —MPU F-107 (2017) —MPU F-108 (2017) —MPU F-109 (2017) —MPU F-110 (2017) n HilCOT Cmuy®Y Milne Point Unit M-11 SB Injector Drilling Procedure 33.0 Drill Pipe Information 5" 19.5# S-135 DS -50 & NC50 Drill Pipe Configuration Pipe Body OD m 5.000 Pipe Body Wall Thickness; m 0.362 Pipe Body Gmde S-135 Drill Pipe l enigh Tool Joint SMYS Connection GPDS50 Tod Joint OD 6.625 Tod Joint ID an: 3250 Pin Tong 9 Box Tong (.:12 80 % Ins ion Class Nar TD miYI'nae G�nn¢ISO aa[0.M1CWI leOAe a", {", - 31.1. ilN"•1 '..N ee u.`.. Nominal Weight Designation 19.50 Drill Pipe Approximate Length m 131.5 SnroothEdge Height .)T3/32 Raised Tool Joint SMYS Iw1! 120 000 Upset Type IlEu Max Upset OD (DTE) o.r 5.125 Friction Fades 11.0 124 NOX. Tart' s.,, m., 1111We 1Y=dlc Drill Pipe Performance Drill -Pipe Length Range2 Performance of Drill Pipe with Pipe Body at Best Estimates Nominal 80 %rns ecUon Class trxamoamalI uxm cossral aaenac Raw) 1 'knw Nax-e operational Max Tension Drill Pipe Ad' wee We t msnu 24.11 23'19 r"°1e 1ne3) To ve mamt ma Fluid Displacemerd twtni 0.37 0.36 43,100 Tension Onty 0 560800 Fluid Dis acemen[ 12 -*1 0.0(MS comDlr<e mama 39,600 410,500 Fluid Ce test 0.70 0.72 Fluid Capacity, 0"10.0169 0.0167 0.0172 sernl.n war 36,100 Tension only 0 560.800 Drift Size oa13.125 �'m0 32'100 467400 ' ripe. oo rc1a ov.n Nwl: a: U. eonge _, lble: pNi [®e aisemdy vawr art Dei1 efDrn.Mx anD 1ruY.n'YOts m qq: DY!/ mll mknrce, IMervl gai,r DUNNO Daa oNer hCYIS. Connection Performance GPDS50 ( 6.625 ant OD X 3.250 rxa ID ) 120.000 m.n Tool Joint Dimensions Balanced 00 m 6.435 wmmwn Toq mm co arwgi 5.930 aRlnxnm cuss nn ureawn Tod,lmlaow 5.93 CautlnWm IIN 3732 Raised 6.812 m! Vom to Bevel Worn to Min TJ OD for niamatar I APIPremium Class is+.5219 Note Ekvala c�a]Iy DOXEMEVYRCY Ek iYf EOR. DD'.cif f>itt.iM [ML%1 aVC Assumetl Elevator Bore Diameter Nq[. w rquD eYvgw oo k�:.a akvalDr 4s�a.nmrn amrtne 11nxa-Dq misae. Pipe Body Slip Crushing Capacity Pipe Body Configmetim if 5-, oD 0.362 tN Wan Nominal 1 80 %Inspection Class I API Premium Class ISlip Crushina Capacity tri•! 498,3DO 1396.5w 1396.500 rrer Etao-anlia aq auRlrom111s Gkaa3E rU11xsq-fiegga rD.kun+t Assumed Sl'r Len thIT7 m 16.5 rwgreaa<leruvwa. tsYsvmxagewnam o-ao.x meem.m Transverse Load Factor fK1 42 ""F1pOi'tra `monur+exs°me"vaa vm; mElxan>maw nsz nnlaaoo amain .env ,anmlvtmxs ewmnwm uewl�,n= PipeBOdvPerformance Pipe BadyCoM!auradon( 5m! OD 0.362w Wall Page 54 Nar TD miYI'nae G�nn¢ISO aa[0.M1CWI leOAe a", {", - 31.1. ilN"•1 '..N ee u.`.. 80% Inspection class TodJmi Torsional Strendh tnkst 71,800 1250,000 Tod Joint Tensile Strecith ce.r Elevator Shoulder Information SmoothEdge Height 3%32 Raised 560,800 7Elevator Sox OD on16.812 Caped an 1,658,000 Tool Joint Dimensions Balanced 00 m 6.435 wmmwn Toq mm co arwgi 5.930 aRlnxnm cuss nn ureawn Tod,lmlaow 5.93 CautlnWm IIN 3732 Raised 6.812 m! Vom to Bevel Worn to Min TJ OD for niamatar I APIPremium Class is+.5219 Note Ekvala c�a]Iy DOXEMEVYRCY Ek iYf EOR. DD'.cif f>itt.iM [ML%1 aVC Assumetl Elevator Bore Diameter Nq[. w rquD eYvgw oo k�:.a akvalDr 4s�a.nmrn amrtne 11nxa-Dq misae. Pipe Body Slip Crushing Capacity Pipe Body Configmetim if 5-, oD 0.362 tN Wan Nominal 1 80 %Inspection Class I API Premium Class ISlip Crushina Capacity tri•! 498,3DO 1396.5w 1396.500 rrer Etao-anlia aq auRlrom111s Gkaa3E rU11xsq-fiegga rD.kun+t Assumed Sl'r Len thIT7 m 16.5 rwgreaa<leruvwa. tsYsvmxagewnam o-ao.x meem.m Transverse Load Factor fK1 42 ""F1pOi'tra `monur+exs°me"vaa vm; mElxan>maw nsz nnlaaoo amain .env ,anmlvtmxs ewmnwm uewl�,n= PipeBOdvPerformance Pipe BadyCoM!auradon( 5m! OD 0.362w Wall Page 54 S-135) N(hs'PYIPR a urgamm a mtaRe.IDR a S-135) a, $ $1 - maamo+aew q r PPl Nominal 80% Inspection class API Premen Class Pipe Tensile Strength ar. 712100 560,800 560,800 Pipe Torsional Strength 4" 74.100 58.1 DO 58.100 TJ;PipeBody Torsional Ratio 0.97 124 124 80% Pipe Torsional strength twml 59,300 46,500 46,50D Burst iceo 17.105 15.638 15.638 collapse ca>°t 15.672 10.029 10.029 Pipe OD Ont 5.000 4.855 Wall Thickness aa10.362 0.290 0290 Nominal Pipe ID int 4276 4276 14210 Cross Sectional Area of Pi Botl oa^21 5275 4.154 4.154 Cross Sectional Area or OD n,21 19.635 18.514 18.514 Cross Sectional Area of ID (--z'14.360 14.360 14.360 Sedan Modulus o s 5.708 4.476 14.476 Polar Section Modulus (e•31 11,415 8.953 18.953 S-135) N(hs'PYIPR a urgamm a mtaRe.IDR a S-135) a, $ $1 - maamo+aew q r PPl Hilcorp Alaska, LLC Milne Point M Pt Moose Pad Plan: MPU M-11 MPU M-11 Plan: M-11 wp08 Standard Proposal Report 21 January, 2019 HALLIBURTON Sperry Drilling Services Project., Milne Point Site: M Pt Moose Pad Well: Plan: MPU M-11 Wellbore: MPU M-11 Design: M-11 wi FWLLIBURTON F ME S., del Coatlinate (N/E) Reference: Well Plan: MPU M-11, True North Vertical (TVD) Reference: M-11 @ 58.70us8 Measured Depth Referenca: M-11 @ 58.70usft Calculation Method Minimum Curvature Hilcorp Alaska, LLC Calculation Method: Minimum Curvature Error System: ISCWSA Scali Method: Closest Approach 3D Error Surface: Pedal Curve Warning Method: Error Ratio DDI = 7.028 -750 /bu N O � 1500 L d 2250 cti Y m N 3000 F 4500 Start Dir 3°/100' : 375' MD, 375'TVD StartDir 4°/100' : 591.67' MD, 5912'W D 60___--_- O End Dir : 1452.77' MD, 1379.76' WD 41 �O 1000 ryry'II �O 6ya N Q' 41 06 +Nl-S +EI -W Narlhlrg 0.00 0.00 9027889.61 WELL DETAILS: Plan: MPU %11 sound! Lewl: 25.00 Easong Ulfttude Longitude 534023.88 70° 29' 13.993 N 14V 43'18.855 W No formation data is available WD TVDSS MD Size Name 3958.70 3900.00 5395.67 9-5/8 9 5/8" x 12 1/4" 3965.01 3906.31 16250.00 7 6 5/8" x 8 1 /2" Depth From Depth To Survey/Plan 33.70 5400.00 M -it w 08 ^�@ ab�r1. O^0 o ° I 5400.00 16250.00 M-11 sI z_mvvu+irrtz+m: 5 AV Oold x4 O' ^O� 6 0^ y1Pry� ,.pn�C` p�0 yqb.�° °A91y�A0,C �cf�O"+°' 'vC' a111M1"�1f�•�0 16' T ya�1' yS1° yoJ,tvtiq ,oP° y. ao- �9 1L' °' 9 99 hg O A O' A" 16C' rp5. (cP ,ADO sP' �O' �° Q. °p�f' 4d�� ` d°� A°1 ye� 1�°ct' ,t1 1�k0' Oaf ap ,i1 ,��` A�X10, yy1 °1a1' "a0" yg-.d 6• oto yyd a . °y.¢ .° 01. .ti°, d:' Fo a'. F° ,ey �•� 1°1n ,.� ,gat' O O•' ,(3 1 �°' 0 a' .i eb \O , 61 �y' 1a" d%° \°'a' O< ayyro' ^,�a dy. :e•P y�. 11°^ 6,y� 5 va e c" B & �^ a ca c ¢F m 0� C° 87 a e� e DOa, PA °. �° @ 9 �Su pa O � OY 6 O 04 04 04 O p0° pY cY y4 yT c, d' O P b vii o o � o m 9 5/8" x 12 1/4" - MPU M-11 wp06 Heel Oi O' do O� O O O -0M .O Oi Co 0. G P O to O O O o m t� o o m do o ,M-11 wP08 'n m � ' f a e w ed 16250 M-11 wp05 CP4 M-11 wI CP5 s 5/8" x 8 1/2" M-11 wp05 CP4.5 M-11 wp05 CP6 M-11 WP05 Cf 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750 10500 11250 12000 12750 13500 14250 Vertical Section at 124.70'(1500 usft/in) SECTION DETAILS Sec MD Inc Azi TVD -N/-S +E/ -W Dleg TFace VSect Target Annotation 1 33.70 0.00 0.00 33.70 0.00 0.00 0.00 0.00 0.00 2 375.00 0.00 0.00 375.00 0.00 0.00 0.00 0.00 0.00 Start Dir 7/100' : 375' MD, 375'TVD 3 591.67 6.50 30.00 591.20 10.63 6.14 3.00 30.00 -1.01 Start Dir 4°/100' : 591.67' MD, 591.2'WD 4 1452.77 38.52 77.89 1379.76 112.19 301.61 4.00 54.76 184.10 End Dir : 1452.77' MD, 1379.76' TVD 5 3805.13 38.52 77.89 3220.32 419.61 1733.89 0.00 0.00 1186.63 Start Dir 4°/100' : 3805.13' MD, 3220.327VD 6 5295.67 84.00 124.69 3948.25 62.33 2904.70 4.00 57.18 2352.60 End Dir : 5295.67' MD, 3948.25' TVD 7 5395.67 84.00 124.69 3958.70 5.73 2986.47 0.00 0.00 2452.05 MPU M-11 wp06 Heel 8 5470.67 84.00 124.69 3966.54 -36.72 3047.80 0.00 0.00 2526.64 Start Dir 4-1100' : 5470.67' MD, 391 9 5600.67 89.20 124.69 397425 -110.55 3154.47 4.00 0.00 2656.36 End Dir : 5600.67' MD, 3974.25' TVD 10 6665.00 89.20 124.69 3989.11 -716.25 4029.52 0.00 0.00 3720.59 Start Dir 4°/100' : 6665' MD, 39891 11 6720.00 87.00 124.69 3990.93 -747.53 4074.72 4.00 180.00 3775.56 End Dir : 6720' MD, 3990.93' TVD 12 7680.00 87.00 124.69 4041.17 -1293.15 4862.99 0.00 0.00 4734.24 Start Dir 4-1100' : 7680' MD, 4041.17'WD 13 7755.00 90.00 124.69 4043.14 -1335.82 4924.63 4.00 0.00 4809.21 End Dir : 7755' MD, 4043.14' TVD 14 7910.00 90.00 124.69 4043.14 -1424.03 5052.08 0.00 0.00 4964.21 Start Dir 4°/100' : 7910' MD, 4043.14'WD 15 8010.00 94.00 124.69 4039.65 -1480.90 5134.24 4.00 0.00 5064.13 End Dir : 8010' MD, 4039.65' WD 16 8860.00 94.00 124.69 3980.35 -1963.49 5831.44 0.00 0.00 5912.06 Start Dir 4°/100': 8860'MD, 3980.361 17 8960.00 90.00 124.69 3976.86 -2020.35 5913.60 4.00 180:00 6011.98 End Dir : 8960' MD, 3976.88' ND 18 9880.00 90.00 124.69 3976.86 -2543.96 6670.06 0.00 0.00 6931.98 Start Dir 4-1100' : 9880' MD, 3976.861 19 9931.74 87.93 124.58 3977.80 -2573.36 6712.62 4.00 -176.98 6983.70 End Dir :9931.74' MD, 3977.8' ND 20 10481.54 87.93 124.58 3997.62 -2885.21 7164.99 0.00 0.00 7533.15 Start Dir 4-100' : 10481.54' MD, 3991 21 10538.27 90.20 124.69 3998.55 -2917.44 7211.66 4.00 2.76 7589.87 End Dir : 10538.27' MD, 3998.55' TVD 22 11268.27 90.20 124.69 3996.00 -3332.91 7811.90 0.00 0.00 8319.86 M-11 wp05 CP4 Start Dir 4.1100' : 11268.27' MD, 3996'WD 23 11363.38 94.00 124.67 3992.51 -3386.98 7890.04 4.00 -0.25 8414.88 End Dir : 11363.38' MD, 3992.51' WD 24 11575.21 94.00 124.67 3977.72 -3507.20 8063.83 0.00 0.00 8626.20 Start Dir 4°/100' : 11575.21' MD, 391 25 11657.82 90.70 124.68 3974.33 -3554.15 8131.69 4.00 179.89 8708.73 End Dir : 11657.82' MD, 3974.33' WD 26 12257.82 90.70 124.68 3967.00 -3895.52 8625.06 0.00 0.00 9308.68 M-11 wp05 CP4.5 Start Dir 4°/100' : 12257.82' MD, 396TTVD 27 12282.86 89.70 124.68 3966.91 -3909.77 8645.66 4.00 -179.90 9333.73 End Dir : 12282.86' MD, 3966.91' TuD 28 12869.00 89.70 124.68 3970.00 -4243.26 9127.67 0.00 0.00 9919.86 MAI wp05 CPS Start Dir 4°/100' : 12869' MD, 3970'WD 29 12952.98 86.34 124.68 3972.90 -4291.00 9196.68 4.00 -179.95 10003.77 End Dir : 12952.98' MD, 3972.9' ND 30 13183.07 86.34 124.68 3987.60 -4421.64 9385.52 0.00 0.00 10233.39 Start Dir 4°/100' : 13183.07' MD, 39131 13269.59 89.80 124.68 3990.51 -4470.83 9456.62 4.00 0.08 10319.86 End Dir : 13269.59' MD, 3990.51' TVD 32 14269.59 89.80 124.68 3994.00 -5039.82 10278.96 0.00 0.00 11319.85 M-11 wp05 CP6 Start Dir 4-1100' : 14269.59' MD, 3994'WD 33 14345.05 92.82 124.68 3992.28 -5082.74 10340.99 4.00 -0.09 11395.28 End Dir : 14345.05' MD, 3992.28' WD 34 14707.15 92.82 124.68 3974.47 -5288.49 10638.41 0.00 0.00 11756.94 Start Dir 4-1100 : 14707.15' MD, 391 35 14770.10 90.30 124.68 3972.76 -5324.30 10690.16 4.00 179.89 11819.87 End Dir : 14770.1' MD, 3972.76' TVD 36 15870.10 90.30 124.68 3967.00 -5950.18 11594.73 0.00 0.00 12919.85 M-11 wp05 CP7 37 16250.00 90.30 124.68 3965.01 -6166.34 11907.13 0.00 0.00 13299.74 Total Depth : 16250' MD, 3965.01' TuD StartDir 4°/100' : 591.67' MD, 5912'W D 60___--_- O End Dir : 1452.77' MD, 1379.76' WD 41 �O 1000 ryry'II �O 6ya N Q' 41 06 +Nl-S +EI -W Narlhlrg 0.00 0.00 9027889.61 WELL DETAILS: Plan: MPU %11 sound! Lewl: 25.00 Easong Ulfttude Longitude 534023.88 70° 29' 13.993 N 14V 43'18.855 W No formation data is available WD TVDSS MD Size Name 3958.70 3900.00 5395.67 9-5/8 9 5/8" x 12 1/4" 3965.01 3906.31 16250.00 7 6 5/8" x 8 1 /2" Depth From Depth To Survey/Plan 33.70 5400.00 M -it w 08 ^�@ ab�r1. O^0 o ° I 5400.00 16250.00 M-11 sI z_mvvu+irrtz+m: 5 AV Oold x4 O' ^O� 6 0^ y1Pry� ,.pn�C` p�0 yqb.�° °A91y�A0,C �cf�O"+°' 'vC' a111M1"�1f�•�0 16' T ya�1' yS1° yoJ,tvtiq ,oP° y. ao- �9 1L' °' 9 99 hg O A O' A" 16C' rp5. (cP ,ADO sP' �O' �° Q. °p�f' 4d�� ` d°� A°1 ye� 1�°ct' ,t1 1�k0' Oaf ap ,i1 ,��` A�X10, yy1 °1a1' "a0" yg-.d 6• oto yyd a . °y.¢ .° 01. .ti°, d:' Fo a'. F° ,ey �•� 1°1n ,.� ,gat' O O•' ,(3 1 �°' 0 a' .i eb \O , 61 �y' 1a" d%° \°'a' O< ayyro' ^,�a dy. :e•P y�. 11°^ 6,y� 5 va e c" B & �^ a ca c ¢F m 0� C° 87 a e� e DOa, PA °. �° @ 9 �Su pa O � OY 6 O 04 04 04 O p0° pY cY y4 yT c, d' O P b vii o o � o m 9 5/8" x 12 1/4" - MPU M-11 wp06 Heel Oi O' do O� O O O -0M .O Oi Co 0. G P O to O O O o m t� o o m do o ,M-11 wP08 'n m � ' f a e w ed 16250 M-11 wp05 CP4 M-11 wI CP5 s 5/8" x 8 1/2" M-11 wp05 CP4.5 M-11 wp05 CP6 M-11 WP05 Cf 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750 10500 11250 12000 12750 13500 14250 Vertical Section at 124.70'(1500 usft/in) HALLIBURTON 3000— eaemv oenn�e 2250—S9\,y,�y0^6.10 1500\\d} .S9\ 96••1 ip\\ S� OS OS , a1 750 0 9 5/8" x 12 1/4" MPU M-1 I vT06 Haul Project: Milne Point TVD TVDSS MD Size Name Site: M Pt Moose Pad 3958.70 3900.00 5395.67 9-5/8 9518"x121/4" Well: Plan: MPU M-11 3965.01 3906.31 16250.00 7 6 5/8" x 8 12" O ,qR S 0 1 Wellbore: MPU M-11 Plan: M-11 wp08 WELL DEfAnS: Plan: MPU M-11 Ground level: 25.00 +N/-8 +E/ -W NoMin6'"6 Iaunude Lu"®wde 0.00 0.00 602788961 534023.88 7129' 13 993 N 149.43' 18.865 W Co -aminate (NIE) Reference: Web Plan: MPU M11, Tme N"nh Nadal (ND) Reference: M-11 ® 58.70m0 MeasureCDapth neannn. M-11 WOW Minim•®im C 70.11 almllaliuv ure ��a� SSSS 9\a� eP''p 4A5 1p OS � SIS 4� A9 •y'1^bC` y'�O 9't s' 90 e�• e�• •Cy0 le 9'0.. �9; •CSP 1p S - �OS �tA" \3y$•y. � .(1: \$,y0� �p A,p? �1C� q W aA03 Oyu .0yb9 M-11 WP05CP4 QyTV yp e M -I I w 05 CP4.5 \\C¢ `�• p X91 S^3o. Alb. M.11 "05 CPS Vb M -II W,O Cm ,So AWbb M -I I Wp05 CP7 6 5/8" 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750 10500 11250 12000 12750 13500 14250 West( -)/East(+) (1500 mft/in) HALLIBURTON Database: NORTH US+CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: Plan: MPU M-11 Wellbore: MPU M-11 Design: M-11 wp08 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Well Plan: MPU M-11 M-11 @ 58.70usft M-11 @ 58.70usft True Minimum Curvature Halliburton Standard Proposal Report Project Milne Point, ACT, MILNE POINT Map System: US Stale Plane 1927 (Exact solution) - System Datum: Mean Sea Level Geo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point Map Zone: Alaska Zone 04 Using geodetic scale factor Site M Pt Moose Pad Site Position: Northing: 6,027,877.65usft Latitude: 70° 29' 13.905 N From: Map Easting: 533,363.92usft Longitude: 149" 43'38.286 W Position Uncertainty: 0.00 usft Slot Radius: 13-3/16" Grid Convergence: 0.26 ° Well Plan: MPU M-11 Well Position +N/ -S 0.00 usft Northing: 6,027,889.61 usft - Latitude: 70' 29' 13.993 N +E/ -W 0.00 usft Easting: 534,023.88 usft - Longitude: 149° 43' 18.865 W Position Uncertainty 0.00 usft Wellhead Elevation: 25.00 usft Ground Level: - 25.00 usft Wellbore MPU M-11 Magnetics Model Name Sample Date Declination Dip Angle Field Strength BGGM2018 2120/2019 16.77 80.97 5"7,435.07594571 Design M-11 Wp08 - - - --- ' Audit Notes: Passes AC Against L-36 Version: Phase: PLAN Tie On Depth: 33.70 Vertical Section: Depth From (TVD) +NIS +E/ -W Direction (usft) (usft) (usft) 33.70 0.00 0.00 124.4. 70 - 1212019 7'33:40PM Page 2 COMPASS 5000.15 Build 91 Halliburton HA LL I B U R TO N Standard Proposal Report Database: Company: Project: Site: Well: Wellbore: Design: NORTH US + CANADA Hilcorp Alaska, LLC Milne Point M Pt Moose Pad Plan: MPU M-11 MPU M-11 M-11 wp08 Local Coordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Well Plan: MPU M-11 M-11 @ 58.70usft M-11 @ 58.70usft True Minimum Curvature Plan Sections Measured Vertical TVD Dogleg Build Turn Depth Inclination Azimuth Depth System +N/.S +PJ -W Rate Rate Rate Tool Face (usft) (') C) (usft) usft (usft) (usft) ('/100usft) ("/100usft) ('it00usft) V) 33.70 0.00 0.00 33.70 -25.00 0.00 0.00 0.00 0.00 0.00 0.00 375.00 0.00 0.00 375.00 316.30 0.00 0.00 0.00 0.00 0.00 0.00 591.67 6.50 30.00 591.20 532.50 10.63 6.14 3.00 3.00 0.00 30.00 1,452.77 38.52 77.89 1,379.76 1.321.06 112.19 301.61 4.00 3.72 5.56 54.76 3,805.13 38.52 77.89 3,220.32 3,161.62 419.61 1,733.89 0.00 0.00 0.00 0.00 5,295.67 84.00 124.69 3,948.25 3,889.55 62.33 2,904.70 4.00 3.05 3.14 57.18 5,395.67 84.00 124.69 3,958.70 3,900.00 5.73 2,986.47 0.00 0.00 0.00 0.00 5,470.67 84.00 124.69 3,966.54 3,907.84 -36.72 3,047.80 0.00 0.00 0.00 0.00 5,600.67 89.20 124.69 3,974.25 3,915.55 -110.55 3,154.47 4.00 4.00 0.00 0.00 6,665.00 89.20 124.69 3,989.11 3,930.41 -716.25 4,029.52 0.00 0.00 0.00 0.00 6,720.00 87.00 124.69 3,990.93 3,932.23 -747.53 4,074.72 4.00 -4.00 0.00 180.00 7,680.00 87.00 124.69 4,041.17 3.98247 -1,293.15 4,862.99 0.00 0.00 0.00 0.00 7,755.00 90.00 124.69 4,043.14 3.984.44 -1,335.82 4,924.63 4.00 4.00 0.00 0.00 7,910.00 90.00 124.69 4,043.14 3,984.44 -1,424.03 5,052.08 0.00 0.00 0.00 0.00 8,010.00 94.00 124.69 4,039.65 3,980.95 -1,480.90 5,134.24 4.00 4.00 0.00 0.00 8,860.00 94.00 124.69 3,980.35 3,921.65 -1,963.49 5,831.44 0.00 0.00 0.00 0.00 8,960.00 90.00 124.69 3,976.86 3,918.16 -2,020.35 5,913.60 4.00 -4.00 0.00 180.00 9,880.00 90.00 124.69 3,976.86 3,918.16 -2,543.96 6,670.06 0.00 0.00 0.00 0.00 9,931.74 87.93 124.58 3,977.80 3,919.10 -2,573.36 6,712.62 4.00 -3.99 -0.21 -176.98 10,481.54 87.93 124.58 3,997.62 3,938.92 -2,885.21 7,164.99 0.00 0.00 0.00 0.00 10,538.27 90.20 124.69 3,998.55 3,939.85 -2,917.44 7,211.66 4.00 4.00 0.19 2.76 11,268.27 90.20 124.69 3,996.00 3,937.30 -3,332.91 7,811.90 0.00 0.00 0.00 0.00 11,363.38 94.00 124.67 3,992.51 3,933.81 -3,386.98 7,890.04 4.00 4.00 -0.02 -0.25 11,575.21 94.00 124.67 3,977.72 3.919.02 -3,507.20 8,063.83 0.00 0.00 0.00 0.00 11,657.82 90.70 124.68 3,974.33 3,915.63 -3,554.15 8,131.69 4.00 -4.00 0.01 179.89 12,257.82 90.70 124.68 3,967.00 3,908.30 -3,895.52 8,625.06 0.00 0.00 0.00 0.00 12,282.86 89.70 124.68 3,966.91 3,908.21 -3,909.77 8,645.66 4.00 -4.00 -0.01 -179.90 12,869.00 89.70 124.68 3,970.00 3,911.30 4,243.26 9,127.67 0.00 0.00 0.00 0.00 12,952.98 86.34 124.68 3,972.90 3,914.20 4,291.00 9,196.68 4.00 -4.00 0.00 -179.95 13,183.07 86.34 124.68 3,987.60 3,928.90 4,421.64 9,385.52 0.00 0.00 0.00 D.OD 13,269.59 89.80 124.68 3,990.51 3,931.81 4,470.83 9,456.62 4.00 4.00 0.01 0.08 14,269.59 89.80 124.68 3,994.00 3,935.30 -5,039.82 10,278.96 0.00 0.00 0.00 0.00 14,345.05 92.82 124.68 3,992.28 3,933.58 -5,082.74 10,340.99 4.00 4.00 -0.01 -0.09 14,707.15 92.82 124.68 3,974.47 3,815.77 -5,288.49 10,638.41 0.00 0.00 0.00 0.00 14,770.10 90.30 124.68 3,972.76 3,914.06 -5,324.30 10,690.16 4.00 4.00 0.01 179.89 15,870.10 90.30 124.68 3,967.00 3,908.30 -5,950.18 11,594.73 0.00 0.00 0.00 0.00 16,250.00 90.30 124.68 3,965.01 3,906.31 -6,166.34 11,907.13 0.00 0.00 0.00 0.00 1212019 7:33:40PM Page 3 COMPASS 5000.15 Build 91 HALLIBURTON Database: NORTH US+CANADA 0.00 Company: Hilcorp Alaska, LLC 0.00 Project: Milne Paint 200.00 Site: M Pt Moose Pad 200.00 Well: Plan: MPU M-11 0.00 Wellbore: MPU M-11 0.00 Design: M-11 Wp08 Start Dir Pianned Survey MD, 375'TVD 0.00 400.00 0.75 Measured 400.00 Vertical Depth Inclination Azimuth Depth TVD.. (usft) (_) (_) (usft) usft 33.70 0.00 0.00 33.70 100.00 0.00 0.00 100.00 200.00 0.00 0.00 200.00 300.00 0.00 0.00 300.00 375.00 0.00 0.00 375.00 Start Dir 3.1100' : 375' MD, 375'TVD 0.00 400.00 0.75 30.00 400.00 500.00 3.75 30.00 499.91 591.67 6.50 30.00 591.21 Start Dir 4'1100': 591.67' MD, 591.27VD 600.00 6.70 32.33 599.48 700.00 9.67 51.56 698.47 800.00 13.19 61.25 796.48 900.00 16.92 66.82 893.03 1,000.00 20.76 70.40 987.66 1,100.00 24.64 72.90 1,079.90 1,200.00 28.55 74.76 1,169.31 1,300.00 32.48 76.20 1,255.44 1,400.00 36.43 77.36 1,337.88 1,452.77 38.52 77.89 1,379.76 End Dir : 1452.77' MD, 1379.76' TVD 534,079.99 1,500.00 38.52 77.89 1,416.71 1,600.00 38.52 77.89 1,494.95 1,700.00 38.52 77.89 1,573.20 1,800.00 38.52 77.89 1,651.44 1,900.00 38.52 77.89 1,729.68 2,000.00 38.52 77.89 1,807.93 2,100.00 38.52 77.89 1,886.17 2,200.00 38.52 77.89 1,964.41 2,300.00 38.52 77.89 2,042.66 2,400.00 38.52 77.89 2,120.90 2,500.00 38.52 77.89 2,199.14 2,600.00 38.52 77.89 2,277.39 2,700.00 38.52 77.89 2,355.63 2,800.00 38.52 77.89 2,433.87 2,900.00 38.52 77.89 2,512.12 3,000.00 38.52 77.89 2,590.36 3,100.00 38.52 77.89 2,668.60 3,200.00 38.52 77.89 2,746.85 3,300.00 38.52 77.89 2,825.09 3,400.00 38.52 77.89 2,903.33 3,500.00 38.52 77.89 2,981.58 3,600.00 38.52 77.89 3,059.82 3,700.00 38.52 77.89 3,138.06 3,800.00 38.52 77.89 3,216.31 Halliburton Standard Proposal Report Local Co-ordinate Reference: Well Plan: MPU M-11 TVD Reference: M-11 @ 58.70usft MD Reference: M41 @ 58.70usft North Reference: True Survey Calculation Method: Minimum Curvature Map Map -NIS +EI -W Northing Easting DLS Vert Section (usft) (usft) (usft) (usft) -25.00 -25.00 0.00 0.00 6,027,889.61 534,023.88 0.00 0.00 41.30 0.00 0.00 6,027,889.61 534,023.88 0.00 0.00 141.30 0.00 0.00 6,027,889.61 534,023.88 0.00 0.00 241.30 0.00 0.00 6,027,889.61 534,023.88 0.00 0.00 316.30 0.00 0.00 6,027,889.61 534,023.88 0.00 0.00 341.30 0.14 0.08 6,027,889.75 534,023.96 3.00 -0.01 441.21 3.54 2.04 6,027,893.16 534,025.91 3.00 -0.34 532.51 10.63 6.14 6,027,900.27 534,029.97 3.00 -1.01 540.78 11.45 6.63 6,027,901.09 534,030.46 4.00 -1.06 639.77 21.60 16.33 6,027,911.29 534,040.11 4.00 1.13 737.78 32.32 32.92 6,027,922.07 534,056.65 4.00 8.67 834.33 43.54 56.31 6,027,933.40 534,079.99 4.00 21.51 928.96 55.22 86.40 6,027,945.22 534,110.02 4.00 39.60 1,021.20 67.29 123.03 6,027,957.46 534,146.59 4.00 62.84 1,110.61 79.71 166.03 6,027,970.07 534,189.52 4.00 91.12 1,196.74 92.40 215.18 6,027,982.98 534,238.61 4.00 124.31 1,279.18 105.31 270.25 6,027,996.14 534,293.62 4.00 162.24 1,321.06 112.19 301.61 6,028,003.16 534,324.94 4.00 184.10 1,358.01 118.36 330.37 6,028,009.47 534,353.67 0.00 204.23 1,436.25 131.43 391.25 6,028,022.81 534,414.49 0.00 246.85 1,514.50 144.50 452.14 6,028,036.16 534,475.31 0.00 289.47 1,592.74 157.56 513.03 6,028,049.50 534,536.13 0.00 332.08 1,670.98 170.63 573.91 6,028,062.85 534,596.95 0.00 374.70 1,749.23 183.70 634.80 6,028,076.19 534,657.77 0.00 417.32 1,827.47 196.77 695.69 6,028,089.54 534,718.59 0.00 459.94 1,905.71 209.84 756.57 6,028,102.89 534,779.41 0.00 502.56 1,983.96 222.91 817.46 6,028,116.23 534,840.23 0.00 545.17 2,062.20 235.98 878.35 6,028,129.58 534,901.05 0.00 587.79 2,140.44 249.04 939.23 6,028,142.92 534,961.87 0.00 630.41 2,218.69 262.11 1,000.12 6,028,156.27 535,022.69 0.00 673.03 2,296.93 275.18 1,061.01 6,028,169.61 535,083.51 0.00 715.65 2,375.17 288.25 1,121.90 6,028,182.96 535,144.33 0.00 758.26 2,453.42 301.32 1,182.78 6,028,196.31 535,205.15 0.00 800.88 2,531.66 314.39 1,243.67 6,028,209.65 535,265.97 0.00 843.50 2,609.90 327.46 1,304.56 6,028,223.00 535,326.80 0.00 886.12 2,688.15 340.52 1,365.44 6,028,236.34 535,387.62 0.00 928.74 2,766.39 353.59 1,426.33 6,028,249.69 535,448.44 0.00 971.36 2,844.63 366.66 1,487.22 6,028,263.03 535,509.26 0.00 1,013.97 2,922.88 379.73 1,548.10 6,028,276.38 535,570.08 0.00 1,056.59 3,001.12 392.80 1,608.99 6,028,289.73 535,630.90 0.00 1,099.21 3,079.36 405.87 1,669.88 6,028,303.07 535,691.72 0.00 1,141.83 3,157.61 418.94 1,730.76 6,028,316.42 535,752.54 0.00 1,184.45 112112019 7:33:40PM Page 4 COMPASS 5000.15 Build 91 Halliburton HALLI B U RTO N Standard Proposal Report Database: Company: Project: Site: Well: Wellbore: Design: NORTH US + CANADA Hiloorp Alaska, LLC Milne Point M Pt Moose Pad Plan: MPU M-11 MPU M-11 M-11 WP08 Local Co-ordinate Reference: Well Plan: MPU M-11 TVD Reference: M-11 @ 58.70usft MD Reference: M-11 @ 58.70usft North Reference: True Survey Calculation Method: Minimum Curvature Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +NIS +E/ -W Northing Easting DLS Vert Section (usft) (1) (1) (usft) usft (usft) (usft) (usft) (usft) 3,161,62 3,805.13 38.52 77.89 3,220.32 3,161.62 419.61 1,733.89 6,028,317.10 535,755.66 0.00 1,186.63 Start Dir 4°1100' : 3805.13' MD, 3220.32'TVD 3,900.00 40.68 82.78 3,293.44 3,234.74 429.69 1,793.46 6,028,327.46 535,815.18 4.00 1,229.87 4,000.00 43.16 87.48 3,367.86 3,309.16 435.30 1,859.99 6,028,333.37 535,881.68 4.00 1,281.38 4,100.00 45.82 91.75 3,439.20 3,380.50 435.71 1,930.03 6,028,334.10 535,951.71 4.00 1,338.72 4,200.00 48.62 95.64 3,507.13 3,448.43 430.93 2,003.24 6,028,329.66 536,024.93 4.00 1,401.63 4,300.00 51.54 99.20 3,571.30 3,512.60 420.99 2,079.26 6,028,320.06 536,100.98 4.00 1,469.79 4,400.00 54.57 102.48 3,631.41 3,572.71 405.92 2,157.72 6,028,305.35 536,179.50 4.00 1,542.87 4,500.00 57.67 105.52 3,687.16 3,628.46 385.81 2,238.24 6,028,285.61 536,260.11 4.00 1,620.52 4,600.00 60.84 108.35 3,738.28 3,679.58 360.74 2,320.42 6,028,260.93 536,342.40 4.00 1,702.36 4,700.00 64.07 111.02 3,784.52 3,725.82 330.86 2,403.88 6,028,231.43 536,425.98 4.00 1,787.98 4,800.00 67.35 113.54 3,825.66 3,766.96 296.29 2,488.19 6,028,197.25 536,510.44 4.00 1,876.98 4,900.00 70.66 115.94 3,861.49 3,802.79 257.21 2,572.95 6,028,158.56 536,595.37 4.00 1,968.91 5,000.00 74.00 118.25 3,891.85 3,833.15 213.80 2,657.75 6,028,115.55 536,680.36 4.00 2,063.34 5,100.00 77.37 120A8 3,916.57 3,857.87 166.29 2,742.17 6,028,068.43 536,764.99 4.00 2,159.79 5,200.00 80.75 122.65 3,935.55 3,876.85 114.90 2,825.80 6,028,017.42 536,848.85 4.00 2,257.81 5,295.67 84.00 124.69 3,948.25 3,889.55 62.33 2,904.70 6,027,965.22 536,927.98 4.00 2,352.60 End Dir : 5295.67' MD, 3948.25' TVD 5,300.00 84.00 124.69 3,948.70 3,890.00 59.88 2,908.24 6,027,962.79 536,931.53 0.00 2,356.91 5,395.67 84.00 124.69 3,958.70 3,900.00 5.73 2,986.47 6,027,909.00 537,010.00 0.00 2,452.05 9 5/8" x 12 114" 5,400.00 84.00 124.69 3,959.15 3,900.45 3.28 2,990.01 6,027,906.56 537,013.55 0.00 2,456.36 5,470.67 84.00 124.69 3,966.54 3,907.84 -36.72 3,047.80 6,027,866.83 537,071.52 0.00 2,526.64 Start Dir 4-1100': 5470.6T MD, 3966.54TVD 5,500.00 85.17 124.69 3,969.31 3,910.61 -53.34 3,071.81 6,027,850.33 537,095.60 4.00 2,555.84 5,600.00 89.17 124.69 3,974.24 3,915.54 -110.17 3,153.92 6,027,793.88 537,177.96 4.00 2,655.70 5,600.67 89.20 124.69 3,974.25 3,915.55 -110.56 3,154.47 6,027,793.50 537,178.51 3.99 2,656.37 End Dir : 5600.67' MD, 3974.25' TVD 5,700.00 89.20 124.69 3,975.63 3,916.93 -167.08 3,236.14 6,027,737.35 537,260.43 0.00 2,755.69 5,800.00 89.20 124.69 3,977.03 3,918.33 -223.99 3,318.35 6,027,680.82 537,342.90 0.00 2,855.68 5,900.00 89.20 124.69 3,978.43 3,919.73 -280.90 3,400.57 6,027,624.30 537,425.36 0.00 2,955.67 6,000.00 89.20 124.69 3,979.82 3,921.12 -337.81 3,482.79 6,027,567.77 537,507.83 0.00 3,055.66 6,100.00 89.20 124.69 3,981.22 3,922.52 -394.71 3,565.00 6,027,511.25 537,590.30 0.00 3,155.65 6,200.00 89.20 124.69 3,982.61 3,923.91 -451.62 3,647.22 6,027,454.72 537,672.77 0.00 3,255.64 6,300.00 89.20 124.69 3,984.01 3,925.31 -508.53 3,729.43 6,027,398.19 537,755.23 0.00 3,355.63 6,400.00 89.20 124.69 3,985.41 3,926.71 -565.44 3,811.65 6,027,341.67 537,837.70 0.00 3,455.62 6,500.00 89.20 124.69 3,986.80 3,928.10 -622.35 3,893.87 6,027,285.14 537,920.17 0.00 3,555.61 6,600.00 89.20 124.69 3,988.20 3,929.50 -679.26 3,976.08 6,027,228.62 538,002.64 0.00 3,655.60 6,665.00 89.20 124.69 3,989.11 3,930.41 -716.25 4,029.52 6,027,191.88 538,056.24 0.00 3,720.59 Start Dir 4°/100' : 6665' MD, 3989.11'T/D 6,700.00 87.80 124.69 3,990.02 3,931.32 -736.16 4,058.29 6,027,172.10 538,085.10 4.00 3,755.58 6,720.00 87.00 124.69 3,990.93 3,932.23 -747.53 4,074.72 6,027,160.80 538,101.58 4.00 3,775.56 End Dir : 6720' MD, 3990.93' T/D 6,800.00 87.00 124.69 3,995.12 3,936.42 -793.00 4,140.41 6,027,115.64 538,167.47 0.00 3,855.45 6,900.00 87.00 124.69 4,000.35 3,941.65 -849.83 4,222.52 6,027,059.19 538,249.83 0.00 3,955.31 1/21/1019 7.'33:40PM Page COMPASS 5000,15 Build 91 HALLIBURTON Database: NORTH US+CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: Plan: MPU M-11 Wellbom: MPU M-11 Design: M-11 Wp08 Planned Survey Measured Vertical Depth Inclination Azimuth Depth (usft) (I (I (weft) 7,000.00 87.00 124.69 4,005.58 7,100.00 87.00 124.69 4,010.82 7,200.00 87.00 124.69 4,016.05 7,300.00 87.00 124.69 4,021.29 7,400.00 87.00 124.69 4,026.52 7,500.00 87.00 124.69 4,031.75 7,600.00 87.00 124.69 4,036.99 7,680.00 87.00 124.69 4,041.17 Start Dir 4.1100' : 7680' MD, 4041.17'7VD 7,700.00 87.80 124.69 4,042.08 7,755.00 90.00 124.69 4,043.14 End Dir : 7755' MD, 4043.14' TVD -1,190.85 7,800.00 90.00 124.69 4,043.14 7,900.00 90.00 124.69 4,043.14 7,910.00 90.00 124.69 4,043.14 Start Dir 4°/100' : 7910' MD, 4043.14'TVD 8,000.00 93.60 124.69 4,040.31 8,010.00 94.00 124.69 4,039.65 End Dir : 8010' MD, 4039.65' TVD 4,754.22 8,100.00 94.00 124.69 4,033.37 8,200.00 94.00 124.69 4,026.39 8,300.00 94.00 124.69 4,019.42 8,400.00 94.00 124.69 4,012.44 8,500.00 94.00 124.69 4,005.47 8,600.00 94.00 124.69 3,998.49 8,700.00 94.00 124.69 3,991.51 8,800.00 94.00 124.69 3,984.54 8,860.00 94.00 124.69 3,980.35 Start Dir 4°1100' : 8860' MD, 3980.35'TVD 8,900.00 92.40 124.69 3,978.12 8,960.00 90.00 124.69 3,976.86 End Dir :8960' MD, 3976.86' TVD -1,588.77 9,000.00 90.00 124.69 3,976.86 9,100.00 90.00 124.69 3,976.86 9,200.00 90.00 124.69 3,976.86 9,300.00 90.00 124.69 3,976.86 9,400.00 90.00 124.69 3,976.86 9,500.00 90.00 124.69 3,976.86 9,600.00 90.00 124.69 3,976.86 9,700.00 90.00 124.69 3,976.86 9,800.00 90.00 124.69 3,976.86 9,880.00 90.00 124.69 3,976.86 Start Dir 4°/100' : 9880' MD, 3976.867VD 5,782.23 9,900.00 89.20 124.65 3,977.00 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Well Plan: MPU M-11 M-11 @ 58.70usft M-11 @ 58.70usft True Minimum Curvature Halliburton Standard Proposal Report 121/2019 7:33:40PM Page 6 COMPASS 5000.15 Build 91 Map Map TVDss -N/-S +E/ -W Northing Easting DLS Vert Section usft (usft) (usft) (usft) (usft) 3,946.88 3,946.88 -906.67 4,304.63 6,027,002.73 538,332.19 0.00 4,055.18 3,952.12 -963.50 4,386.74 6,026,946.28 538,414.55 0.00 4,155.04 3,957.35 -1,020.34 4,468.86 6,026,889.82 538,496.92 0.00 4,254.90 3,962.59 -1,077.18 4,550.97 6,026,833.37 538,579.28 0.00 4,354.76 3,967.82 -1,134.01 4;633.08 6,026,776.92 538,661.64 0.00 4,454.63 3,973.05 -1,190.85 4,715.19 6,026,720.46 538,744.00 0.00 4,554.49 3,978.29 -1,247.68 4,797.30 6,026,664.01 538,826.37 0.00 4,654.35 3,982.47 -1,293.15 4,862.99 6,026,618.85 538,892.26 0.00 4,734.24 3,983.38 -1,304.52 4,879.42 6,026,607.55 538,908.73 4.00 4,754.22 3,984.44 -1,335.82 4,924.63 6,026,576.47 538,954.09 4.00 4,809.21 3,984.44 -1,361.43 4,961.63 6,026,551.03 538,991.20 0.00 4,854.21 3,984.44 -1,418.34 5,043.86 6,026,494.50 539,073.68 0.00 4,954.21 3,984.44 -1,424.03 5,052.08 6,026,488.94 539,081.92 0.00 4,964.21 3,981.61 -1,475.22 5,126.03 6,026,438.00 539,156.10 4.00 5,054.15 3,980.95 -1,480.90 5,134.24 6,026,432.36 539,164.33 4.00 5,064.13 3,974.67 -1,532.00 5,208.06 6,026,381.60 539,238.38 0.00 5,153.91 3,967.69 -1,588.77 5,290.08 6,026,325.21 539,320.65 0.00 5,253.67 3,960.72 -1,645.55 5,372.11 6,026,268.82 539,402.93 0.00 5,353.42 3,953.74 -1,702.32 5,454.13 6,026,212.42 539,485.20 0.00 5,453.18 3,946.77 -1,759.10 5,536.16 6,026,156.03 539,567.48 0.00 5,552.93 3,939.79 -1,815.87 5,618.18 6,026,099.64 539,649.75 0.00 5,652.69 3,932.81 -1,872.65 5,700.20 6,026,043.24 539,732.03 0.00 5,752.45 3,925.84 .1,929.42 5,782.23 6,025,986.85 539,814.30 0.00 5,852.20 3,921.65 -1,963.49 5,831.44 6,025,953.01 539,863.67 0.00 5,912.06 3,919.42 -1,986.22 5,864.28 6,025,930.44 539,896.61 4.00 5,951.99 3,918.16 -2,020.35 5,913.60 6,025,896.53 539,946.08 4.00 6,011.98 3,918.16 -2,043.12 5,946.49 6,025,873.92 539,979.07 0.00 6,051.98 3,918.16 -2,100.03 6,028.71 6,025,817.38 540,061.54 0.00 6,151.98 3,918.16 -2,156.95 6,110.94 6,025,760.85 540,144.02 0.00 6,251.98 3,918.16 -2,213.86 6,193.16 6,025,704.32 540,226.49 0.00 6,351.98 3,918.16 -2,270.77 6,275.39 6,025,647.79 540,308.97 0.00 6,451.98 3,918.16 -2,327.69 6,357.61 6,025,591.26 540,391.44 0.00 6,551.98 3,918.16 -2,384.60 6,439.84 6,025,534.73 540,473.92 0.00 6,651.98 3,918.16 -2,441.51 6,522.06 6,025,478.20 540,556.40 0.00 6,751.98 3,918.16 -2,498.43 6,604.28 6,025,421.67 540,638.87 0.00 6,851.98 3,918.16 -2,543.96 6,670.06 6,025,376.44 540,704.85 0.00 6,931.98 3,918.30 -2,555.34 6,686.51 6,025,365.14 540,721.35 4.00 6,951.98 121/2019 7:33:40PM Page 6 COMPASS 5000.15 Build 91 HALLIBURTON Database: NORTH US+CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: Plan: MPU M-11 Wellborn: MPU M-11 Design: M-11 Wp08 Planned Survey Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Measured Map +EI -W Northing Vertical (usft) (usft) (usft) 3,919.10 Depth Inclination Azimuth Depth TVDss +NIS (usft) (1 (1) (usft) usft (usft) 9,931.74 87.93 124.58 3,977.80 3,919.10 -2,573.36 End Dir : 9931.74' MD, 3977.8' TVD 0.00 7,451.66 8,650.95 10,000.00 87.93 124.58 3,980.26 3,921.56 -2,612.08 10,100.00 87.93 124.58 3,983.87 3,925.17 -2,668.80 10,200.00 87.93 124.58 3,987.47 3,928.77 -2,725.52 10,300.00 87.93 124.58 3,991.08 3,932.38 -2,782.24 10,400.00 87.93 124.58 3,994.68 3,935.98 -2,838.96 10,481.54 87.93 124.58 3,997.62 3,938.92 -2,885.21 Start Dir 4°1100' : 10481.54' MD, 3997.62'TVD 0.00 9,308.69 10,500.00 88.67 124.62 3,998.17 3,939.47 -2,895.68 10,538.27 90.20 124.69 3,998.55 3,939.85 -2,917.44 End Dir : 10538.27' MD, 3998.55' TVD 10,600.00 90.20 124.69 3,998.33 3,939.63 -2,952.58 10,700.00 90.20 124.69 3,997.98 3,939.28 -3,009.49 10,800.00 90.20 124.69 3,997.63 3,938.93 -3,066.40 10,900.00 90.20 124.69 3,997.29 3,938.59 -3,123.31 11,000.00 90.20 124.69 3,996.94 3,938.24 -3,180.23 11,100.00 90.20 124.69 3,996.59 3,937.89 -3,237.14 11,200.00 90.20 124.69 3,996.24 3,937.54 -3,294.05 11,268.27 90.20 124.69 3,996.00 3,937.30 -3,332.91 Start Dir 4°/100' : 11268.27' MD, 3996'TVD 11,300.00 91.47 124.68 3,995.54 3,936.84 -3,350.96 11,363.38 94.00 124.67 3,992.51 3,933.81 -3,386.98 End Dir : 11363.38' MD, 3992.51' TVD 11,400.00 94.00 124.67 3,989.95 3,931.25 -3,407.76 11,500.00 94.00 124.67 3,982.97 3,924.27 -3,464.52 11,575.21 94.00 124.67 3,977.72 3,919.02 -3,507.20 Start Dir4°/700': 11575.21' MD, 3977.72'TVD 11,600.00 93.01 124.68 3,976.20 3,917.50 -3,521.27 11,657.82 90.70 124.68 3,974.33 3,915.63 -3,554.15 End Dir : 11657.82' MD, 3974.33' TVD 11,700.00 90.70 124.68 3,973.81 3,915.11 -3,578.15 11,800.00 90.70 124.68 3,972.59 3,913.89 -3,635.05 11,900.00 90.70 124.68 3,971.37 3,912.67 -3,691.94 12,000.00 90.70 124.68 3,970.15 3,911.45 -3,748.84 12,100.00 90.70 124.68 3,968.93 3,910.23 -3,805.73 12,200.00 90.70 124.68 3,967.71 3,909.01 -3,862.63 12,257.82 90.70 124.68 3,967.00 3,908.30 -3,895.52 Start Dir 4°/100' : 12257.82' MD, 3967'rVD 12,282.86 89.70 124.68 3,966.91 3,908.21 -3,909.77 End Dir :12282.86' MD, 3966.91' TVD 12,300.00 89.70 124.68 3,967.00 3,908.30 -3,919.52 12,400.00 89.70 124.68 3,967.53 3,908.83 -3,976.42 12,500.00 89.70 124.68 3,968.06 3,909.36 -4,033.31 12,600.00 89.70 124.68 3,968.58 3,909.88 .4,090.21 Halliburton Standard Proposal Report Well Plan: MPU M-11 M-11 @ 58.70usft M-11 @ 58.70usft True Minimum Curvature Map Map +EI -W Northing Easting DLS Vert Section (usft) (usft) (usft) 3,919.10 6,712.62 6,025,347.24 540,747.54 4.00 6,983.71 6,768.79 6,025,308.78 540,803.88 0.00 7,051.92 7,890.04 6,851.07 6,025,252.44 540,886.41 0.00 7,151.86 6,024,518.45 6,933.35 6,025,196.11 540,968.94 0.00 7,251.79 542,040.98 7,015.63 6,025,139.77 541,051.47 0.00 7,351.73 0.00 7,097.90 6,025,083.43 541,134.00 0.00 7,451.66 8,650.95 7,164.99 6,025,037.49 541,201.29 0.00 7,533.15 8,166.38 7,180.18 6,025,027.09 541,216.53 4.00 7,551.60 7,211.66 6,025,005.48 541,248.10 4.00 7,589.87 7,262.42 6,024,970.58 541,299.01 0.00 7,651.60 7,890.04 7,344.64 6,024,914.05 541,381.49 0.00 7,751.59 6,024,518.45 7,426.87 6,024,857.52 541,463.96 0.00 7,851.59 542,040.98 7,509.09 6,024,800.99 541,546.44 0.00 7,951.59 0.00 7,591.31 6,024,744.46 541,628.91 0.00 8,051.59 8,650.95 7,673.54 6,024,687.92 541,711.39 0.00 8,151.59 8,166.38 7,755.76 6,024,631.39 541,793.86 0.00 8,251.59 6,024,292.69 7,811.90 6,024,592.80 541,850.17 0.00 8,319.86 542,370.70 7,837.98 6,024,574.87 541,876.34 4.00 8,351.59 7,890.04 6,024,539.09 541,928.55 4.00 8,414.89 7,920.08 6,024,518.45 541,958.69 0.00 8,451.42 8,002.12 6,024,462.08 542,040.98 0.00 8,551.18 8,063.83 6,024,419.68 542,102.87 0.00 8,626.20 8,084.17 6,024,405.70 542,123.28 4.00 8,650.95 8,131.70 6,024,373.04 542,170.95 4.00 8,708.73 8,166.38 6,024,349.21 542,205.74 0.00 8,750.91 8,248.61 6,024,292.69 542,288.22 0.00 8,850.90 8,330.84 6,024,236.18 542,370.70 0.00 8,950.89 8,413.06 6,024,179.67 542,453.17 0.00 9,050.89 8,495.29 6,024,123.16 542,535.65 0.00 9,150.88 8,577.52 6,024,066.64 542,618.13 0.00 9,250.87 8,625.06 6,024,033.97 542,665.82 0.00 9,308.69 8,645.66 6,024,019.82 542,686.48 4.00 9,333.73 8,659.75 6,024,010.13 542,700.62 0.00 9,350.87 8,741.99 6,023,953.62 542,783.10 0.00 9,450.86 8,824.22 6,023,897.10 542,865.59 0.00 9,550.86 8,906.46 6,023,840.59 542,948.07 0.00 9,650.86 1212019 7:33:40PM Page 7 COMPASS 5000.15 Build 91 Halliburton HA L L I B U R TO N Standard Proposal Report Database: NORTH US + CANADA Local Co-ordinate Reference: Well Plan: MPU M-11 Company: Hilcorp Alaska, LLC TVD Reference: M-11 @ 58.70usft Project: Milne Point MD Reference: M-11 @ 58.70usft Site: M Pt Moose Pad North Reference: True Well: Plan: MPU M-11 Survey Calculation Method: Minimum Curvature Wellbore: MPU M-11 Depth Inclination Design: M-11 wp08 TVDss +WS Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +WS +E/.W Northing Easting DLS Vert Section (usft) (°) (°) (usft) usft (usft) (usft) (usft) (usft) 3,910.41 12,700.00 89.70 124.68 3,969.11 3,910.41 -4,147.10 8,988.69 6,023,784.08 543,030.56 0.00 9,750.86 12,800.00 89.70 124.68 3,969.64 3,910.94 -4,204.00 9,070.93 6,023,727.56 543,113.05 0.00 9,850.86 12,869.00 89.70 124.68 3,970.00 3,911.30 -4,243.26 9,127.67 6,023,688.57 543,169.96 0.00 9,919.86 Start Dir 4°1100' : 12869' MD, 39707VD 12,900.00 88.46 124.68 3,970.50 3,911.80 -4,260.89 9,153.16 6,023,671.05 543,195.53 4.00 9,950.85 12,952.98 86.34 124.68 3,972.90 3,914.20 -4,291.00 9,196.68 6,023,641.15 543,239.18 4.00 10,003.78 End Dir : 12952.98' MD, 3972.9' TVD 13,000.00 86.34 124.68 3,975.91 3,917.21 -4,317.70 9,235.27 6,023,614.63 543,277.89 0.00 10,050.70 13,100.00 86.34 124.68 3,982.29 3,923.59 -4,374.48 9,317.34 6,023,558.23 543,360.21 0.00 10,150.50 13,183.07 86.34 124.68 3,987.60 3,928.90 -4,421.64 9,385.52 6,023,511.39 543,428.60 0.00 10,233.40 Start Dir 4°1100' : 13183.07' MD, 3987.6'TVD 13,200.00 87.02 124.68 3,988.58 3,929.88 -4,431.26 9,399.42 6,023,501.84 543,442.54 4.00 10,250.30 13,269.59 89.80 124.68 3,990.51 3,931.81 4,470.83 9,456.62 6,023,462.53 543,499.92 4.00 10,319.85 End Dir : 13269.59' MD, 3990.51' TVD 13,300.00 89.80 124.68 3,990.62 3,931.92 -4,488.13 9,481.62 6,023,445.34 543,525.00 0.00 10,350.26 13,400.00 89.80 124.68 3,990.96 3,932.26 4,545.03 9,563.86 6,023,388.82 543,607.49 0.00 10,450.26 13,500.00 89.80 124.68 3,991.31 3,932.61 -4,601.93 9,646.09 6,023,332.31 543,689.97 0.00 10,550.26 13,600.00 89.80 124.68 3,991.66 3,932.96 -4,658.83 9,728.33 6,023,275.79 543,772.46 0.00 10,650.26 13,700.00 89.80 124.68 3,992.01 3,933.31 -4,715.73 9,810.56 6,023,219.27 543,854.94 0.00 10,750.26 13,800.00 89.80 124.68 3,992.36 3,933.66 -4,772.63 9,892.79 6,023,162.76 543,937.43 0.00 10,850.26 13,900.00 89.80 124.68 3,992.71 3,934.01 -4,829.53 9,975.03 6,023,106.24 544,019.91 0.00 10,950.26 14,000.00 89.80 124.68 3,993.06 3,934.36 -4,886.43 10,057.26 6,023,049.72 544,102.40 0.00 11,050.26 14,100.00 89.80 124.68 3,993.41 3,934.71 -4,943.32 10,139.49 6,022,993.21 544,184.88 0.00 11,150.26 14,200.00 89.80 124.68 3,993.76 3,935.06 -5,000.22 10,221.73 6,022,936.69 544,267.37 0.00 11,250.26 14,269.59 89.80 124.68 3,994.00 3,935.30 -5,039.82 10,278.95 6,022,897.36 544,324.77 0.00 11,319.85 Start Dir4°N00': 14269.59' MD, 3994'TVD 14,300.00 91.02 124.68 3,993.78 3,935.08 -5,057.12 10,303.96 6,022,880.18 544,349.85 4.00 11,350.26 14,345.05 92.82 124.68 3,992.28 3,933.58 -5,082.74 10,340.99 6,022,854.73 544,386.99 4.00 11,395.28 End Dir : 14345.05' MD, 3992.28' TVD 14,400.00 92.82 124.68 3,989.57 3,930.87 -5,113.96 10,386.12 6,022,823.72 544,432.26 0.00 11,450.16 14,500.00 92.82 124.68 3,984.66 3,925.96 -5,170.78 10,468.26 6,022,767.28 544,514.65 0.00 11,550.04 14,600.00 92.82 124.68 3,979.74 3,921.04 -5,227.61 10,550.40 6,022,710.83 544,597.04 0.00 11,649.92 14,700.00 92.82 124.68 3,974.82 3,916.12 -5,284.43 10,632.54 6,022,654.39 544,679.43 0.00 11,749.80 14,707.15 92.82 124.68 3,974.47 3,915.77 -5,288.49 10,638.41 6,022,650.36 544,685.33 0.00 11,756.94 Start Dir 4°1100' : 14707.15' MD, 3974.47fVO 14,770.10 90.30 124.68 3,972.76 3,914.06 -5,324.29 10,690.16 6,022,614.80 544,737.23 4.00 11,819.86 End Dir : 14770.1' MD, 3972.76' TVD 14,800.00 90.30 124.68 3,972.60 3,913.90 .5,341.31 10,714.75 6,022,597.90 544,761.89 0.00 11,849.76 14,900.00 90.30 124.68 3,972.08 3,913.38 -5,398.21 10,796.98 6,022,541.38 544,844.38 0.00 11,949.76 15,000.00 90.30 124.68 3,971.56 3,912.86 -5,455.10 10,879.21 6,022,484.87 544,926.86 0.00 12,049.76 15,100.00 90.30 124.68 3,971.03 3,912.33 -5,512.00 10,961.45 6,022,428.35 545,009.34 0.00 12,149.76 15,200.00 90.30 124.68 3,970.51 3,911.81 -5,568.90 11,043.68 6,022,371.84 545,091.83 0.00 12,249.76 15,300.00 90.30 124.68 3,969.99 3,911.29 -5,625.80 11,125.91 6,022,315.32 545,174.31 0.00 12,349.76 15,400.00 90.30 124.68 3,969.46 3,910.76 -5,682.70 11,208.15 6,022,258.80 545,256.80 0.00 12,449.75 15,500.00 90.30 124.68 3,968.94 3,910.24 -5,739.60 11,290.38 6,022,202.29 545,339.28 0.00 12,549.75 1212019 7:33:40PM Page 8 COMPASS 5000.15 Build 91 HALLIBURTON Database: NORTH US + CANADA Local Co-ordinate Reference: Well Plan: MPU M-11 Company: Hi carp Alaska, LLC TVD Reference: M-11 @ 58.70usft Project: Milne Point MD Reference: M-11 @ 58.70usft Site: M Pt Moose Pad North Reference: True Well: Plan: MPU M-11 Survey Calculation Method: Minimum Curvature Halliburton Standard Proposal Report Wellborn: MPU M-11 Target Name Design: M-11 wp08 -hit/miss target Dip Angle Dip Dir. TVD +N/S +E/ -W Planned Survey Easting -Shape (°) (°) (usft) (usft) (usft) (usft) (usft) M-11 wp05 CP5 Measured 0.00 3,970.00 Vertical 9,127.67 6,023,688.57 543,169.96 Map Map Depth Inclination Azimuth Depth TVDss +NIS +E/ -W Northing Easting DLS Vert Section (usft) (I (I (usft) usft (usft) (usft) (usft) (usft) 3,909.71 15,600.00 90.30 124.68 3,968.41 3,909.71 -5,796.49 11,372.61 6,022,145.77 545,421.77 0.00 12,649.75 15,700.00 90.30 124.68 3,967.89 3,909.19 -5,853.39 11,454.85 6,022,089.26 545,504.25 0.00 12,749.75 15,800.00 90.30 124.68 3,967.37 3,908.67 -5,910.29 11,537.08 6,022,032.74 545,586.74 0.00 12,849.75 15,870.10 90.30 124.68 3,967.00 3,908.30 -5,950.18 11,594.73 6,021,993.12 545,644.56 0.00 12,919.85 15,900.00 90.30 124.68 3,966.84 3,908.14 -5,967.19 11,619.31 6,021,976.22 545,669.22 0.00 12,949.75 16,000.00 90.30 124.68 3,966.32 3,907.62 -6,024.09 11,701.54 6,021,919.71 545,751.70 0.00 13,049.75 16,100.00 90.30 124.68 3,965.80 3,907.10 -6,080.99 11,783.76 6,021,863.19 545,834.19 0.00 13,149.74 16,200.00 90.30 124.68 3,965.27 3,906.57 -6,137.89 11,866.01 6,021,806.68 545,916.67 0.00 13,249.74 16,250.00 90.30 124.68 3,965.01. 3,906.31 -6,166.34 11,907.13 6,021,778.42 545,957.92 0.00 13,299.74 Total Depth : 16250' MD, 3965.01' TVD - Point Targets Target Name -hit/miss target Dip Angle Dip Dir. TVD +N/S +E/ -W Northing Easting -Shape (°) (°) (usft) (usft) (usft) (usft) (usft) M-11 wp05 CP5 0.00 0.00 3,970.00 -4,243.26 9,127.67 6,023,688.57 543,169.96 - plan hits target center - Point M-11 wp05 CP4 0.00 0.00 3,996.00 -3,332.91 7,811.90 6,024,592.80 541,850.17 - plan hits target center - Point M-11 wp05 CP7 0.00 0.00 3,967.00 -5,950.18 11,594.73 6,021,993.12 545,644.56 - plan hits target center - Point M-11 wp05 CP4.5 0.00 0.00 3,967.00 -3,895.52 8,625.06 6,024,033.97 542,665.82 - plan hits target center - Point MPU M-11 wp06 Heel 0.00 0.00 3,958.70 5.73 2,986.47 6,027,909.00 537,010.00 - plan hits target center - Point M-11 wp05 CP6 0.00 0.00 3,994.00 -5,039.82 10,278.96 6,022,897.36 544,324.77 - plan hits target center - Point Casing Points Measured Depth (usft) 5,395.67 16,250.00 Vertical Casing Hole Depth Diameter Diameter (usft) Name ("1 ("I 3,958.70 95/8"x121/4" 9-5/8 12-1/4 3,965.01 6 5/8" x 8 1/2" 7 8-112 1212019 7:33:40PM Page 9 COMPASS 5000.15 Build 91 Plan Annotations Halliburton H A LL I B U R TO N Standard Proposal Report Database: NORTH US + CANADA Local Co-ordinate Reference: Well Plan: MPU M-11 Company: Hiloorp Alaska, LLC TVD Reference: M-11 @ 58.70usft Project: Milne Point MD Reference: M-11 @ 58.70usft Site: M Pt Moose Pad North Reference: True Well: Plan: MPU M-11 Survey Calculation Method: Minimum Curvature Wellbore: MPU M-11 0.00 Start Dir 3-1100': 375' MD, 375'TVD Design: M-11 wp08 591.21 10.63 Plan Annotations Measured Vertical Local Coordinates Depth Depth +N/ -S +E/ -W (usft) (usft) (usft) (usft) Comment 375.00 375.00 0.00 0.00 Start Dir 3-1100': 375' MD, 375'TVD 591.67 591.21 10.63 6.14 Start Dir 4°/100' : 591.67' MD, 591.2'TVD 1,452.77 1,379.76 112.19 301.61 End Dir : 1452.77' MD, 1379.76' TVD 3,805.13 3,220.32 419.61 1,733.89 Start Dir 4°/100' : 3805.13' MD, 3220.32'TVD 5,295.67 3,948.25 62.33 2,904.70 End Dir : 5295.67' MD, 3948.25' TVD 5,470.67 3,966.54 -36.72 3,047.80 Start Dir 4-1100': 5470.67' MD, 3966.547VD 5,600.67 3,974.25 -110.56 3,154.47 End Dir : 5600.67' MD, 3974.25' TVD 6,665.00 3,989.11 -716.25 4,029.52 Start Dir 4-/100': 6665' MO, 3989.1l'TVD 6,720.00 3,990.93 -747.53 4,074.72 End Dir : 6720' MD, 3990.93' TVD 7,680.00 4,041.17 -1,293.15 4,862.99 Start Dir4°/100': 7680'MD,4041.17'TVD 7,755.00 4,043.14 -1,335.82 4,924.63 End Dir : 7755' MD, 4043.14' TVD 7,910.00 4,043.14 -1,424.03 5,052.08 StartDir 4°/100' : 7910' MD, 4043.14'TVD 8,010.00 4,039.65 -1,480.90 5,134.24 End Dir : 8010' MD, 4039.65' TVD 8,860.00 3,980.35 -1,963.49 5,831.44 StartDir4°/100':8860' MD, 3980.35TVD 8,960.00 3,976.86 -2,020.35 5,913.60 End Dir : 8960' MD, 3976.86' TVD 9,880.00 3,976.86 -2,543.96 6,670.06 Start Dir4°/100' : 9880' MD, 3976.86'TVD 9,931.74 3,977.80 -2,573.36 6,712.62 End Dir : 9931.74' MD, 3977.8' TVD 10,481.54 3,997.62 -2,885.21 7,164.99 Start Dir4°/100': 10481.54'MD,3997.62'TVD 10,538.27 3,998.55 -2,917.44 7,211.66 End Dir : 10538.27' MD, 3998.55' TVD 11,268.27 3,996.00 -3,332.91 7,811.90 Start Dir4°/100': 11268.27' MD, 3996'TVD 11,363.38 3,992.51 -3,386.98 7,890.04 End Dir : 11363.38' MD, 3992.51' TVD 11,575.21 3,977.72 -3,507.20 8,063.83 StartDir 4°/100' : 11575.21' MD, 3977.72'TVD 11,657.82 3,974.33 -3,554.15 8,131.70 End Dir : 11657.82' MD, 3974.33' TVD 12,257.82 3,967.00 3,895.52 8,625.06 Start Dir 4°/100' : 12257.82' MD, 3967'TVD 12,282.86 3,966.91 -3,909.77 8,645.66 End Dir : 12282.86' MD, 3966.91' TVD 12,869.00 3,970.00 1,243.26 9,127.67 StartDir4°/100': 12869'MD,3970'TVD 12,952.98 3,972.90 1,291.00 9,196.68 End Dir : 12952.98' MD, 3972.9' TVD 13,183.07 3,987.60 1,421.64 9,385.52 Start Dir 4°/100' : 13183.07' MD, 3987.6'TVD 13,269.59 3,990.51 1,470.83 9,456.62 End Dir : 13269.59' MD, 3990.51' TVD 14,269.59 3,994.00 -5,039.82 10,278.95 Start Dir 4°/100' : 14269.59' MD, 3994'TVD 14,345.05 3,992.28 -5,082.74 10,340.99 End Dir : 14345.05' MD, 3992.28' TVD 14,707.15 3,974.47 -5,288.49 10,638.41 StartDir 4°/100' : 14707.15' MD, 3974.47'TVD 14,770.10 3,972.76 -5,324.29 10,690.16 End Dir : 14770.1' MD, 3972.76' TVD 16,250.00 3,965.01 -6,166.34 11,907.13 Total Depth : 16250' MD, 3965.01' TVD 12112019 7.'33:40PM Page 10 COMPASS 5000.15 Build 91 Hilcorp Alaska, LLC Milne Point M Pt Moose Pad Plan: MPU M-11 MPU M-11 M-11 wp08 Sperry Drilling Services Clearance Summary Anticollision Report 21 January, 2019 Closest Approach 3D Proximity Scan on Current Survey Data (Hlghside Reference) Reference Design: M Pt Moose Pad -Plan: MPU M-11 -MPU M-11 -M-11 wp08 Well Coordinates: 6,027,889.61 N, 534,023.88 E (70° 29' 13.99" N, 149° 43' 18.87" W) Datum Height: M-11 @ 58.70usft Scan Range: 33.70 to 5,400.00 usft. Measured Depth. Scan Radius Is Unlimited . Clearance Factor cutoff Is Unlimited. Max Ellipse Separation Is 1,000.00 usft Geodetic Scale Factor Applied Version: 5000.15 Build: 91 Scan Type: NO GLOBAL FILTER: Using user defined selection & filtering criteria Scan Type: 25.00 HALLIBURTON Sperry Drilling Services HALLIBURTON Anticollision Report for Plan: MPU M-11 - M-11 wp08 Hilcorp Alaska, LLC Milne Point Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference) Reference Design: M Pt Moose Pad - Plan: MPU M-11 - MPU M-11 - M-11 wpOS Scan Range: 33.70 to 5,400.00 usft. Measured Depth. Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation Is 1,000.00 usft Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name -Wellbore Name - Design (usft) (usft) (usft) (usft) usft M Pt L Pad MPL-20 - MPL-20 - MPL-20 5,400.00 1,559.65 5,400.00 1,417.63 10,188.07 10.982 Clearance Factor Pass - MPL-32 - MPL-32 - MPL-32 5,400.00 779.41 5,400.00 638.16 10,623.74 5.518 Clearance Factor Pass - M Pt Moose Pad Plan: MPU M-12 - MPU M-12 - MPU M-12 wp08 358.70 90.00 358.70 86.76 358.70 27.764 Centre Distance Pass - Plan: MPU M-12 - MPU M-12 - MPU M-12 wp08 583.70 91.19 583.70 86.34 588.20 18.809 Ellipse Separation Pass - Plan: MPU M-12 - MPU M-12 - MPU M-12 wp08 5,400.00 817.96 5,400.00 719.75 5,630.32 8.329 Clearance Factor Pass - Plan: MPU M-13 - M-13 - M-13 (Stonewall Inj) wp02 358.70 115.92 358.70 112.65 354.70 35.407 Centre Distance Pass - Plan: MPU M-13 - M-13 - M-13 (Stonewall Inj) wp02 383.70 115.94 383.70 112.49 379.70 33.575 Ellipse Separation Pass - Plan: MPU M-13 - M-13 - M-13 (Stonewall Inj) wp02 4,883.70 1,599.17 4,883.70 1,526.82 4,572.66 22.104 Clearance Factor Pass - Plan: MPU M-14 - M-14 - M-14 (McCllan Prod) wp02 358.70 164.11 358.70 160.86 354.70 50.594 Centre Distance Pass - Plan: MPU M-14 - M-14 - M-14 (McCllan Prod) wp02 383.70 164.12 383.70 160.70 379.70 47.951 Ellipse Separation Pass - Plan: MPU M-14 - AA4 - M-14 (McCllan Prod) wp02 783.70 210.12 783.70 203.87 770.97 33.635 Clearance Factor Pass - Plan: MPU M-15 - M-15 - M-15 (Bragg Inj) wp03 358.70 237.97 358.70 234.70 354.70 72.683 Centre Distance Pass - Plan: MPU M-15 - M-15 - M-15 (Bragg Inj) wp03 383.70 237.99 383.70 234.53 379.70 68.91B Ellipse Separation Pass - Plan: MPU M-15 - M-15 - M-15 (Bragg Inj) wp03 883.70 312.18 883.70 305.17 860.15 44.534 Clearance Factor Pass - Rig: MPU M-10 - MPU M-10 - MPU M-10 wp10 33.70 89.93 33.70 89.14 34.03 114.289 Centre Distance Pass - Rig: MPU M-10 - MPU M-10 - MPU M-10 wp10 258.70 90.60 258.70 88.45 258.25 42.102 Ellipse Separation Pass - Rig: MPU M-10 - MPU M-10 - MPU M-10 wp10 1,608.70 105.82 1,608.70 93.80 1,535.59 8.800 Clearance Factor Pass - RIg: MPU M-10 - MPU M-10 - MPU M-10 33.70 89.93 33.70 89.14 34.03 114.289 Centre Distance Pass - Rig: MPU M-10 - MPU M-10 - MPU M-10 258.70 90.60 258.70 88.45 258.25 42.102 Ellipse Separation Pass - Rig: MPU M-10 - MPU M-10 - MPU M-10 1,608.70 105.82 1,608.70 93.80 1,535.59 8.800 Clearance Factor Pass - Rig: MPU M-10 - MPU M-1 OPB1 - MPU M-10PB1 33.70 89.93 33.70 89.02 34.03 98.622 Centre Distance Pass - Rig: MPU M -10 -MPU M-10PB1 -MPU M-10PB1 258.70 90.60 258.70 88.33 258.25 39.790 Ellipse Separation Pass - Rig:MPUM-IO- MPU M-1 OPB1-MPU M-1 OPB1 1,608.70 105.82 1,608.70 93.67 1,535.59 8.709 Clearance Factor Pass - Rig: MPU M-10 - MPU M-10PB2 - MPU M-10PB2 33.70 89.93 33.70 89.02 34.03 98.622 Centre Distance Pass - Rig: MPU M-10 - MPU M-10PB2 - MPU M-1 OPB2 258.70 90.60 258.70 88.33 258.25 39.790 Ellipse Separation Pass - Rig: MPU M-10 - MPU M-10PB2 - MPU M-10PB2 1,608.70 105.82 1,608.70 93.67 1,535.59 8.709 Clearance Factor Pass - 21 January, 2019 - 18:50 Page 2 of 5 COMPASS HALLIBURTON Anticollision Report for Plan: MPU M-11 - M-11 wp08 Closest Approach 31) Proximity Scan on Current Survey Data (Highside Reference) Reference Design: M Pt Moose Pad - Plan: MPU M-11 - MPU M•11 - M-11 wp06 Scan Range: 33.70 to 5,400.00 usft. Measured Depth. Scan Radius is Unlimited . Clearance Factor cutoff Is Unlimited. Max Ellipse Separation is 1,000.00 usft Hilcorp Alaska, LLC Milne Point Survey tool proyam From To Survey/Plan Survey Tool (usft) (usft) 33.70 5,400.00 M-11 wp08 2 MWD+IFR2+MS+Sag 5,400.00 16,250.00 M-11 wp08 2 MWD+IFR2+MS+Sag Ellipse error terms are correlated across survey tool fie -on points. Calculated ellipses incorporate surface errors. Separation is the actual distance between ellipsoids. Distance Between centres is the straight line distance between wellbore centres. Clearance Factor = Distance Between Profiles / (Distance Between Profiles - Ellipse Separation). All station coordinates were calculated using the Minimum Curvature method. 21 January, 2019 - 18:50 Page 3 0/5 COMPASS Measured Minimum @Measuretl Ellipse @Measuretl Clearance Summary Based on Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name - Wellbore Name - Design (usft) (usft) (usft) (usft) usft Rig: MPU M-10 - MPU M-10PB3 - MPU M -10P133 33.70 89.93 33.70 89.02 34.03 98.622 Centre Distance Pass - Rig: MPU M-10 - MPU M-10PB3 - MPU M-10PB3 258.70 90.60 258.70 88.33 258.25 39.790 Ellipse Separation Pass - Rig: MPU M-10 - MPU M-10PB3 - MPU M-10PB3 1,608.70 105.82 1,608.70 93.67 1,535.59 8.709 Clearance Factor Pass - Slot 42-Placeholder-Slot 42-Placeholder-Slot 42- 358.70 119.93 358.70 116.69 321.00 37.001 Centre Distance Pass - Slot 42-Placeholder-Slot 42-Placeholder-Slot 42- 408.70 120.08 408.70 116.48 371.00 33.366 Ellipse Separation Pass - Slot 42-Placeholder-Slot 42-Placeholder-Slot 42- 733.70 143.38 733.70 137.46 693.93 24.214 Clearance Factor Pass- Slot 46-Placeholder-Slot 46-Placeholder-Slot 46- 358.70 60.07 358.70 56.83 321.00 18.533 Centre Distance Pass - Slot 46-Placeholder-Slot 46-Placeholder-Slot 46- 408.70 60.22 408.70 56.62 371.00 16.733 Ellipse Separation Pass - Slot 46-Placeholder-Slot 46-Placeholder-Slot 46- 633.70 70.84 633.70 65.64 595.22 13.605 Clearance Factor Pass - Slot 52-Placeholtler-Slot 52-Placeholder-Slot 52- 667.60 25.56 667.60 20.11 628.78 4.693 Centre Distance Pass - Slot 52-Placeholder-Slot 52-Placeholder-Slot 52- 683.70 25.62 683.70 20.06 644.69 4.606 Ellipse Separation Pass - Slot 52-Placeholder-Slot 52-Placeholder-Slot 52- 708.70 26.05 708.70 20.30 669.34 4.532 Clearance Factor Pass- Slot 58-Placeholder-Slot 58-Placeholtler-Slot 58- 1,038.40 63.62 1,038.40 55.33 985.69 7.677 Ellipse Separation Pass - Slot 58-Placeholtler-Slot 58-Placeholder-Slot 58- 1,058.70 64.22 1,058.70 55.79 11000.00 7.620 Clearance Factor Pass - Survey tool proyam From To Survey/Plan Survey Tool (usft) (usft) 33.70 5,400.00 M-11 wp08 2 MWD+IFR2+MS+Sag 5,400.00 16,250.00 M-11 wp08 2 MWD+IFR2+MS+Sag Ellipse error terms are correlated across survey tool fie -on points. Calculated ellipses incorporate surface errors. Separation is the actual distance between ellipsoids. Distance Between centres is the straight line distance between wellbore centres. Clearance Factor = Distance Between Profiles / (Distance Between Profiles - Ellipse Separation). All station coordinates were calculated using the Minimum Curvature method. 21 January, 2019 - 18:50 Page 3 0/5 COMPASS HALLIBURTON Project: Milne Poon( REFERENCE INFORMATION WELLDEfAgS:PIan: MPUM-II NAD1927(NADCONCONUS Alaska Zone04 ) Coam iml (ND) Reference: Well @ 5 MPU M-11, True N9eM1 medical Rutin Reference'. M.11 ® 59.70usfl Meesuretl Depthon Mnhce: Mini um curvature calculation Method: Minimum Curvature Site: M Pt Moose Pad 9Perry Oelllln9 Well: Plan: MPU M-11 Wellbore: MPU M-11 +N/- Gowd level: 25 00 6 +0,-W 27SSing lin lannude longitude 0.00 000 602]889.61 534023.88 70°29'13993N 149°43'18.865 Plan: M-11 WpO8 SURVEY PROGRAM NO GLOBAL FILTER: Using user defined selection 8 filtering criteria Depth From Depth To Survey/Plan Tool 33.70 5400.00 M-11 wP08 2 MWD+IFR2+MS+Sag 5400.00 16250.00 M-11 wp06 2_MWD+IFR2+MS+Sag Ladder/S.F. Plots SH (1 of 2) 33.70 To 5400.D0 CASING DETAILS TVD TVDSS MD Size Name 3958.70 3900.00 5395.67 9-5/8 9 5/8" x 12 1/4" 3965.01 3906.31 16250.00 7 65/8"x81/2" --_ --_...— T__... '! "IwPO2 GI50.00 0 p120.00 I' 1j II„ YY� Slo;a ii t toneWall —Id1➢ M- In17 WPLo OPB3 2 O F2 90.00 - .,i ... _ _MPU II MPU M•1(IPB2 U-M-10Pi1 +— a m- U) S of 46 Pill holder •� MPU M-10 SIot58-=slalihode..............._—_ __— ._......—�— —_..-.- U $lot 52 Plxehold r / 30.00— U m -;- "itIm it Im 0.00 0 350 700 1050 1400 1750 2100 2450 2800 3150 3500 3850 4200 4550 4900 5250 5600 5950 6300 Measured Depth (700 usft/in) --- ----- ---- -- ------- `o .00 5 3.00-- U- U- C .0 Collision Risk Procedures Req. n N 1.50 Collision Avoidance Req. - No -Go Zone - Stop Drilling 000- 0 400 800 1200 1600 2000 2400 2800 3200 3600 4000 4400 4800 5200 5600 6000 6400 Measured Depth (700 usft/in) Hilcorp Alaska, LLC Milne Point M Pt Moose Pad Plan: MPU M-11 MPU M-11 M-11 Wp08 Sperry Drilling Services Clearance Summary Anticollision Report 21 January, 2019 Closest Approach 3D Proximity Scan on Current Survey Data (Hlghslde Reference) Reference Design: M Pt Moose Pad - Plan: MPU M-11 • MPU M-11 - M-11 wp08 Well Coordinates: 6,027,889.61 N, 534,023.88 E (70° 29' 13.99" N, 149° 43' 18.87' W) Datum Height: M-11 @ 58.70usft Scan Range: 5,400.00 to 16,250.00 Usti. Measured Depth. Scan Radius Is Unlimited. Clearance Factor cutoff Is Unlimited. Max Ellipse Separation Is 1,000.00 usft Geodetic Scale Factor Applied Version: 5000.15 Build: 91 Scan Type: NO GLOBAL FILTER: Using user defined selection & filtering criteria Scan Type: 25.00 HALLIBURTON Sperry Drilling Services HALLIBURTON Anticollision Report for Plan: MPU M-11 - M-11 wp08 Closest Approach 3D Proximity Scan on Current Survey Data (Highs de Reference) Reference Design: M Pt Moose Pad - Plan: MPU M-11 - MPU M-11 . M-11 wpoa Scan Range: 5,400.00 to 16,250.00 usft. Measured Depth. Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,000.00 usft Hilcorp Alaska, LLC Milne Point Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name -Wellbore Name - Design (usft) (usH) (usft) (usft) usft M Pt L Pad MPL-20 - MPL-20 - MPL-20 6,925.00 132.06 6,925.00 20.60 9,832,07 1.185 Clearance Factor Pass - MPL-20 - MPL-20 - MPL-20 6,950.00 120.50 6,950.00 20.44 9,826.15 1.204 Ellipse Separation Pass - MPL-20 - MPL-20 - MPL-20 6,999.48 110.52 6,999.48 35.57 9,814.22 1.475 Centre Distance Pass - MPL-32 - MPL-32 - MPL-32 6,143.85 352.37 6,143.85 299.23 10,328.09 6.631 Centre Distance Pass - MPL-32 - MPL-32 - MPL-32 6,250.00 366.00 6,250.00 287.72 10,288.93 4.676 Ellipse Separation Pass - MPL-32 - MPL-32 - MPL-32 6,450.00 453.08 6,450.00 332.80 10,212.17 3.767 Clearance Factor Pass - MPL-34 - MPL-34 - MPL-34 8,337.43 478.79 8,337.43 432.24 9,983.46 10.287 Centre Distance Pass - MPL-34 - MPL-34 - MPL-34 8,375.00 480.22 8,375.00 431.59 9,977.19 9.875 Ellipse Separation Pass - MPL-34 - MPL-34 - MPL-34 8,725.00 612.60 8,725.00 524.84 9,917.83 6.981 Clearance Factor Pass - MPL-35 - MPL-35 - MPL-35 - MPL-35-MPL-35-MPL-35 -■ MPL-35 - MPL-35A- MPL-35A - MPL-35 - MPL-35A- N1 - MPL- - MPL-35-MPL-35APB135APBi - MPL-35-MPL-35APBi-MPL-35APB2 - MPL-35 - MPL-35APB2 - MPL-35APB2 - MPL-35 - MPL-35APB2 - MPL-35APB2 - MPL-35 - MPL-35APB3 - MPLJ5AP83 MPL-35 - MPL-35APB3 - MPL-35APB3 MPL-36 - MPL-36 - MPL-36 7,900.00 113.21 7,900.00 5.82 9,826.19 1.054 Clearance Factor Pass - MPL-36 - MPL-36 - MPL-36 7,972.59 91.09 7,972.59 22.05 9,805.40 1.319 Centre Distance Pass - MPL-36 - MPL-361.1 - MPL-36LI 7,900.00 113.21 7,900.00 5.93 9,826.19 1.055 Clearance Factor Pass - MPL-36 - MPL-361-1 - MPL-36L7 7,972.59 91.09 7,972.59 22.23 9,805.40 1.323 Centre Distance Pass - MPL-36-MPL-361-1 PB1 - MPL-361-1 PB1 7,900.00 113.21 7,900.00 5.80 9,826.19 1.054 Clearance Factor Pass - MPL-36 - MPL-361-1 PB1 - MPL-361-1 PB1 7,972.59 91.09 7,972.59 22.16 9,805.40 1.321 Centre Distance Pass - MPL-3fi - MPL-36PB7 - MPL-36PB7 7,900.00 113.21 7,900.00 5.82 9,826.19 1.054 Clearance Factor Pass - MPL-36 - MPL-36PB1 - MPL-36PB7 7,972.59 91.09 7,972.59 22.05 9,805.40 1.319 Centre Distance Pass - MPL-37 - MPL-37 - MPL-37 9,942.96 504.88 9,942.96 429.96 9,693.17 6.739 Centre Distance Pass - 21 January, 2019 - 18:59 Page 2 of 7 COMPASS HALLIBURTON Anticollision Report for Plan: MPU M-11 - M-11 wp08 Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference) Reference Design: M Pt Moose Pad - Plan: MPU M-11 -MPU M-11 -M-11 wp08 Scan Range: 5,400.00 to 16,250.00 usft. Measured Depth. Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,000.00 usft Hilcorp Alaska, LLC Milne Point 21 January, 2019 - 18:59 Page 3 of 7 COMPASS Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name - Wellbore Name - Design (usft) (usft) (usft) (usft) usft MPL-37 - MPL-37 - MPL-37 10,000.00 507.96 10,000.00 427.92 9,688.90 6.347 Ellipse Separation Pass - MPL-37 - MPL-37 - MPL-37 10,275.00 603.33 10,275.00 489.89 9,669.06 5.318 Clearance Factor Pass- - MPL-37-MPL-37A-MPL-37A 9,942.96 504.88 9,942.96 429.96 9,702.37 6.739 Centre Distance Pass - MPL-37 - MPL-37A- MPL-37A 10,000.00 507.96 10,000.00 427.92 9,698.10 6.347 Ellipse Separation Pass - MPL-37 - MPL-37A - MPL-37A 10,275.00 603.33 10,275.00 489.88 9,678.26 5.318 Clearance Factor Pass - MPL-39 - MPL-39 - MPL-39 7,199.11 900.24 7,199.11 795.33 9,475.00 8.581 Centre Distance Pass - MPL-39-MPL-39-MPL-39 7,275.00 903.33 7,275.00 792.85 9,464.04 8.176 Ellipse Separation Pass - MPL-39 - MPL-39 - MPL-39 7,600.00 983.08 7,600.00 851.97 9,415.60 7.499 Clearance Factor Pass - MPLA5 - MPL-45 - MPL-45 12,700.00 1,434.08 12,700.00 1,085.99 9,365.00 4.120 Clearance Factor Pass - MPL-45 - MPL-45 - MPL-45 12,925.00 1,397.14 12,925.00 1,066.42 9,365.00 4.225 Ellipse Separation Pass - MPL-45-MPL-45-MPL-45 13,049.64 1,391.58 13,049.64 1,074.14 9,365.00 4.384 Centre Distance Pass - MPL-50-MPL50-MPL-50 14,823.32 1,598.33 14,823.32 1,267.99 11,678.12 4.838 Centre Distance Pass - MPL-50-MPL50-MPL-50 15,025.00 1,599.95 15,025.00 1,260.79 11,856.60 4.717 Clearance Factor Pass - MPU L-51 - MPU L-51 - MPU L-51 11,494.52 149.82 11,494.52 92.71 9,838.63 2.624 Centre Distance Pass - MPU L-51 - MPU L-51 - MPU L-51 11,575.00 166.41 11,575.00 80.90 9,873.19 1.946 Ellipse Separation Pass - MPU L-51 - MPU L-51 - MPU L-51 11,625.00 191.11 11,625.00 84.94 9,894.79 1.800 Clearance Factor Pass - MPU L -52 -MPU L -52 -MPU L-52 9,825.00 161.35 9,825.00 69.73 10,010.91 1.761 Clearance Factor Pass - MPU L -52 -MPU L -52 -MPU L-52 9,850.00 148.30 9,850.00 66.19 10,019.32 1.806 Ellipse Separation Pass - MPU L -52 -MPU L -52 -MPU L-52 9,924.69 129.08 9,924.69 77.25 10,044.47 2.491 Centre Distance Pass- -' MPU L-53 - MPU L-53 - MPU L-53 8,461.77 168.57 8,461.77 101.14 10,438.32 2.500 Centre Distance Pass - MPUL-53-MPU L -53 -MPU L-53 8,475.00 169.03 8,475.00 100.65 10,443.20 2.472 Ellipse Separation Pass - MPUL-53-MPU L -53 -MPU L-53 8,525.00 178.89 8,525.00 104.90 10,458.99 2.418 Clearance Factor Pass- MPU L54 -MPU L -54 -MPU L-54 12,325.00 138.69 12;325.00 23.97 10,186.19 1.209 Clearance Factor Pass - MPU L-54 - MPU L-54 - MPU L-54 12,413.19 112.69 12,413.19 50.51 10,222.09 1.812 Centre Distance Pass - MPU L -56 -MPU L56 -MPU L-56 9,100.00 158.64 9,100.00 68.82 10,133.54 1.766 Clearance Factor Pass - MPU L -56 -MPU L -56 -MPU L-56 9,125.00 144.73 9,125.00 64.05 10,140.91 1.794 Ellipse Separation Pass - MPU L -56 -MPU L -56 -MPU L-56 9,205.39 122.77 9,205.39 71.78 10,165.13 2.408 Centre Distance Pass- MPU L57 -MPU L -57 -MPU L-57 10,525.00 213.77 10,525.00 107.04 9,856.50 2.003 Clearance Factor Pass - MPU L57 - MPU L-57 - MPU L-57 10,600.00 178.48 10,600.00 97.83 9,893.35 2.213 Ellipse Separation Pass - MPU L-57 - MPU L-57 - MPU L-57 10,681.08 163.38 10,681.08 109.07 9,931.44 3.009 Centre Distance Pass - 21 January, 2019 - 18:59 Page 3 of 7 COMPASS HALLIBURTON Anticollision Report for Plan: MPU M-11 - M-11 wp08 Closest Approach 3D Proximity Scan on Current Survey Data (Highslde Reference) Reference Design: M Pt Moose Pad - Plan: MPU M-11 -MPU M-11 - M-11 wpo8 Scan Range: 5,400.00 to 16,250.00 usft. Measured Depth. Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,000.00 usft Hilcorp Alaska, LLC Milne Point Milne Point Exploration Pesado-01 - PESADO-01 - Pesado-0i Measured Minimum @Measuretl Ellipse @Measured Clearance Summary Based on Pass - Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name - Wellbore Name -Design (usft) (usft) (usft) (usft) usft 8.774 Clearance Factor Pass - MPU L-57 - MPU L-57PB1 - MPU L-57PB7 10,525.00 213.77 10,525.00 107.04 9,856.50 2.003 Clearance Factor Pass - MPU L-57 - MPU L-57PB1 - MPU L-57PB1 10,600.00 178.48 10,600.00 97.83 9,893.35 2.213 Ellipse Separation Pass - MPU L-57 - MPU L-57PB1 - MPU L-57PB1 10.681.08 163.38 10,681.08 109.07 9,931.44 3.009 Centre Distance Pass - M Pt Moose Pad Plan: MPU M-12 - MPU M-12 - MPU M-12 wp08 5,501.17 817.86 5,501.17 718.38 5,731.03 8.221 Centre Distance Pass - Plan: MPU M-12 - MPU M-12 - MPU M-12 wp08 16,225.00 840.08 16,225.00 279.79 16,451.36 1.499 Clearance Factor Pass - Rig: MPU M-10 - MPU M-10 - MPU M-10 wpl0 5,40D.00 672.02 5,400.00 596.09 5,028.12 8.851 Centre Distance Pass - Rig: MPU M-10 - MPU M-10 - MPU M-10 wp1D 15,850.00 752.81 151850.00 297.85 15,616.67 1.655 Ellipse Separation Pass - Rig: MPU M-10 - MPU M-10 - MPU M-10 wp10 15,875.00 754.09 15,875.00 298.06 15,616.67 1.654 Clearance Factor Pass - Rig: MPU M -10 -MPU M -IO - MPU M-10 5,400.00 672.02 5,400.00 596.09 5,028.12 8.851 Centre Distance Pass - Rig: MPU M -10 -MPU M -IO - MPU M-10 15,325.00 811.01 15,325.00 365.06 15,082.00 1.819 Ellipse Separation Pass - Rig: MPU M-10 - MPU M-10 - MPU M-10 15,350.00 812.59 15,350.00 365.76 15,082.00 1.819 Clearance Factor Pass - Rig: MPU M-10 - MPU M-1 OPBi - MPU M-10PB1 5,400.00 672.02 5,400.00 595.96 5,028.12 8.836 Centre Distance Pass - Rig: MPU M-10 - MPU M-10PBI - MPU M-10PB1 12,875.00 793.99 12,875.00 415.24 12,630.00 2.096 Ellipse Separation Pass - Rig: MPU M-10 - MPU M-10PB1 - MPU M-10PB1 12,900.00 795.45 12,900.00 415.60 12,630.00 2.094 Clearance Factor Pass - Rig: MPU M -10 -MPU M-10PB2-MPU M-10PB2 5,400.00 672.02 5,400.00 595.96 5,028.12 8.836 Centre Distance Pass - Rig: MPUM-10-MPU M-10PB2-MPU M-10PB2 13,075.00 797.30 13,075.00 419.96 12,820.00 2.113 Ellipse Separation Pass - Rig: MPUM-10-MPU M-10PB2-MPU M-10PB2 13,100.00 798.86 13,100.00 420.41 12,820.00 2.111 Clearance Factor Pass - Rig: MPU M-10 - MPU M-10PB3 - MPU M-10PB3 5,400.00 672.02 5,400.00 595.96 5,028.12 8.836 Centre Distance Pass - Rig: MPU M-10 - MPU M-10PB3 - MPU M-10PB3 15,650.00 813.50 15,650.00 353.19 15,405.00 1.767 Ellipse Separation Pass - Rig: MPU M-10 - MPU M-1 OP83 - MPU M-1 OPB3 15,675.00 815.01 15,675.00 353.84 15,405.00 1.767 Clearance Factor Pass - Milne Point Exploration Pesado-01 - PESADO-01 - Pesado-0i 8,811.47 1,030.72 8,811.47 917.15 3,759.65 9.076 Centre Distance Pass - Pesado-01 - PESADO-01 - Pesado-01 8,850.D0 1,031.43 8,850.00 916.36 3,764.06 8.964 Ellipse Separation Pass - Pesado-01 - PESADO-01 - Pesado-01 9,000.00 1,049.18 9,000.00 929.61 3,784.62 8.774 Clearance Factor Pass - Pesado-0l-PESADO-01A-Pesado-01A 8,782.39 968.24 8,782.39 854.21 3,922.18 8.491 Centre Distance Pass - Pesado-01-PESADO-01A-Pesado-01A 8,825.00 969.17 8,825.00 853.57 3,921.63 8.384 Ellipse Separation Pass - Pesado-0l-PESADO-01A-Pesado-01A 8,950.00 982.94 8,950.00 863.86 3,922.82 8.254 Clearance Factor Pass - 21 January, 2019 - 18:59 Page 4 of 7 COMPASS HALLIBURT®N Anticollision Report for Plan: MPU M-11 - M-11 wp08 Survey tool program From (usft) 33.70 5,400.00 To (usft) 5,400.00 M-11 wpOB 16,250.00 M-11 wpOB Ellipse error terms are correlated across survey tool tie -on points. Calculated ellipses incorporate surface errors. Separation is the actual distance between ellipsoids. Distance Between centres is the straight line distance between wellbore centres. Clearance Factor = Distance Between Profiles 1 (Distance Between Profiles - Ellipse Separation). All station coordinates were calculated using the Minimum Curvature method. Survey/Plan Survey Tool 2_MWD+IFR2+MS+Sag 2_MWD+IFR2+MS+Sag Hilcorp Alaska, LLC Milne Point 21 January, 2019 - IS: 59 Page 5 o/ 7 COMPASS Project: Milne Point REFERENCE INFORMATION WEIl DEI'AdSFan: MPU M-11 NAD1927(NADCONCONUS) Alaska ZoneW HALLIBURTON Site: M Pt Moose Pad Co-onflude (Ne Reference: Well Plan: WU Wil. Tme NOM Gound Level: 25.00 Medical n VD) Reference: M-11 @ 58.70usfl +N/-5 +E/_W 9par•ry 0�116nR Well: Plan: MPU M-11 Measured Depth Reference: M-11958.70usd NOnhing Earring Letinude luny rude Wellbore: MPU M-11 Celcula8on Method Minimum Curvature 0.00 0.00 6027889,61 534023 88 7W 29' 13,993 N 14V 43' 18.865 W Plan: M-11 Wp08 SURVEY PROGRAM NO GLOBAL FILTER: Using user defined selection 8 filtering Crile is 5400.00 To 16250.00 Depth From Depth To Survey/Plan Tool Ladder/S.F. Plots 33.70 5400.00 M-11 wp08 2_MWD+IFR2+MS+Sag CASING DETAILS 5400.00 16250.00 M-11 wp08 2 MWD+IFR2+MS+Sag PH (2 of 2)TVD TVDSS MD Size Name 3958.70 3900.00 5395.67 9-5/8 95/8"x121/4" 3965.01 3906.31 16250.00 7 65/8"x81/2" -.. ,. V r 111 , X150.00 I MPLJ L 57 1 o I MPU L-5 III Ii I ,j120.00—MPL- MPU L-52 0 O mL-5 90.00 " MPU _ J I� �V MPL-35APB3 n m I� MRL-35A B2 I b1PL-3sA B1 MPL-51 MPL-54 60.00--- _--. `IMPL-35 _ _._ O MPL-36 MP -35A p w 30.00 —! c m U 0.00 5400 6000 6600 7200 7800 8400 9000 9600 10200 10800 11400 12000 12600 13200 13800 14400 15000 15600 16200 Measured Depth (1200 usft/in) 4.50- ro - — — - -� 0 0 .00 LL3.00— Collision Risk Procedures Req. Collision Collision Avoidance R1q. ------ a 1.50- - No-Go Zone - Stop Drilling sA • NOERROR �d %i—Iq 0.00 5200 5850 6500 7150 7800 8450 9100 9750 10400 11050 11700 12350 13000 13650 14300 14950 15600 16250 Measured Depth (1200 usft/in) L .9 s— Ps,A c, K .-.P , j -_ Rob ,psi _--� 7"�� Schwartz, Guy L (DOA) From: Monty Myers <mmyers@hilcorp.com> Sent: Thursday, February 14, 2019 9:50 AM To: Schwartz, Guy L (DOA) Subject: RE: [EXTERNAL] FW: M-11 (PTD 219-010) SB Injector Good morning Guy, We are obtaining some additional north seeking gyro surveys on some nearby wells to mitigate the risk of collision and clean up the AC issues. While drilling near the intersection points we will shut in the affected well and monitor our surveys closely, looking for magnetic interference, while we drill by. We will also be taking short surveys at that point. 15-30 foot surveys. Monty M Myers Drilling Manager 907.538.1168 (c) 907.777.8431 (o) From: Schwartz, Guy L (DOA) [mailto:guy.schwartz@alaska.gov] Sent: Thursday, February 14, 2019 9:43 AM To: Monty Myers <mmyers@hilcorp.com> Subject: [EXTERNAL] FW: M-11 (PTD 219-010) SB Injector Guess Joe is out... Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office 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 Guy Schwartz at (907-793-1226) or (Guv.schwartz@alaska.gov[. From: Schwartz, Guy L (DOA) Sent: Thursday, February 14, 2019 9:32 AM To: Joe Engel <IenRel@hilcoro.com> Cc: Davies, Stephen F (DOA) (steve.daviesPalaska.gov) <steve.davies@alaska.aov> Subject: M-11 (PTD 219-010) SB Injector Joe, I was looking at the AOR and the collision data. L-35 (actually L -35A from S/T that failed) is listed the AOR. The well has surface casing that was set just below the SB and fully cemented. This well has a history of surface pressure (900 psi or so) even though it is suspended with a plug in the 7" just above the Kuparak sands. According to the collision data it fails the clearance factor also. What are you doing to mitigate this in case you run into L -35A while drilling by? Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office 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 Guy Schwartz of (907-793-1226 ( or (Guv.schwartz@alaska.aov(. Davies, Stephen F (DOA) From: Cody Dinger <cdinger@hilcorp.com> Sent: Monday, February 11, 2019 2:20 PM To: Davies, Stephen F (DOA) Subject: RE: [EXTERNAL] MPU M-11 (PTD 219-010) -Question Attachments: AOR for MPM-11 2-11-19.pdf Steve, See my response below and the attached correct AOR table. Thanks, Cody From: Davies, Stephen F (DOA) [mailto:steve.davies@alaska.gov] Sent: Monday, February 11, 2019 2:10 PM To: Cody Dinger <cdinger@hilcorp.com> Subject: RE: [EXTERNAL] MPU M-11 (PTD 219-010) - Question Cody, Quick, additional questions: 1. On the revised AOR table for MPU M-11, the L-36 well is listed as having a status of "Kuparuk Producer" with the Schrader OA status of "Open." On the previous version of the table, the well status is given as "Future SB OA WIND" with a Schrader OA status as "Open." Which is correct? The L-36 is a current Kuparuk producer, I made the mistake of putting Future SB OA WINJ because I was mixing up L-36 & L-35 with our current drill wells of E- 36 and E-35. The Schrader is closed in MPL-36. ` 2. The revised table gives the TOC for L-36 as 7983' MD with the Top of SB OA given as 9773' MD, which suggests to me that the OA is covered by cement, but again the Schrader OA status is listed as "Open." Which is correct? The Schrader OA is closed, table updated. 3. When completed, will M-11 be pre -produced for more than 30 days, or will it simply be flowed back for a short period of time to clean up the perfs prior to beginning injection operations? M-11 will not be pre -produced. Thank you again foryour help, Steve Davies 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(atalaska.eov. From: Cody Dinger <cdinger@hilcorp.com> Sent: Monday, February 11, 2019 11:03 AM To: Davies, Stephen F (DOA) <steve.davies@alaska.eov> Cc: Joe Engel <ienael@hilcorp.com>; Monty Myers <mmvers@hilcorp.com> Subject: RE: [EXTERNAL] MPU M-11 (PTD 219-010) - Question Hi Steve, I have updated the AOR table with details on L-20, L-35 and L-36 and attached it here. L-32 and L-34 do not pass through the AOR. Geology has informed me that no faults occur in the OA sand within the AOR. Thanks, Cody Dinger Hilcorp Alaska, LLC Drilling Technician cdinger@hilcorp.com Direct: 907-777-8389 From: Joe Engel Sent: Wednesday, February 06, 2019 12:57 PM To: Kevin Eastham <keasthamCg@hilcorp.com>; Seth Nolan <snolan@hilcorp.com> Cc: Cody Dinger <cdinger@hilcorp.com>; Reid Edwards <reedwards@hilcorp.com>; Monty Myers <mmyers@ hilcorp.com> Subject: FW: [EXTERNAL] MPU M-11 (PTD 219-010) - Question Kevin/Seth/Cody — See Steves questions regarding M-11 AOR below. I have already answered his question regarding planned injection mitigation (MPD and S/I wells). Thanks. Joe Engel I Drilling Engineer I Hilcorp Alaska, LLC 3800 Centerpoint Dr., Ste. 1400 1 Anchorage I AK 199503 Office: 907.777.8395 1 Cell: 805.235.6265 From: Davies, Stephen F (DOA)[mailto:steve.davies@alaska.govl Sent: Wednesday, February 6, 2019 12:14 PM To: Joe Engel <iengel@hilcorp.com> Subject: [EXTERNAL] MPU M-11 (PTD 219-010) - Question Joe, I'm reviewing the Permit to Drill application for Hilcorp's planned MPU M-11 injection well. I have a few questions. 1. 1 notice that existing Kuparuk wells L-20, L36, and L-35 are not included in the Cement/Zonal Isolation table for the M-11 well. Don't these wells pass through the OA sand and or the confining intervals within the Area of Review for M-11? If so, please update the Area of Review table to include this information. Do L-32 and L-34 pass through the lower confining interval within the Area of Review? If so, please update the table accordingly. 2. Do any faults occur in the OA sand within the Area of Review? If so, please provide a map that shows the wells and faults within the Area of Review. Please annotate the map to indicate the down -thrown direction and vertical displacement of each fault. Could any of these faults provide conduits between wells or for injected fluids to migrate out of zone? If so, what are Hilcorp's planned monitoring or mitigating measures? Thank you for your help, Steve Davies 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 907-793-3224 or steve.davies(malaska.gov. Davies, Stephen F (DOA) From: Davies, Stephen F (DOA) Sent: Monday, February 11, 2019 2:10 PM To: 'Cody Dinger' Subject: RE: [EXTERNAL] MPU M-11 (PTD 219-010) - Question Cody, Quick, additional questions: 1. On the revised AOR table for MPU M-11, the L-36 well is listed as having a status of "Kuparuk Producer" with the Schrader OA status of "Open" On the previous version of the table, the well status is given as "Future SB OA WIND" with a Schrader OA status as "Open." Which is correct? 2. The revised table gives the TOC for L-36 as 7983' MD with the Top of SB OA given as 9773' MD, which suggests to me that the OA is covered by cement, but again the Schrader OA status is listed as "Open." Which is correct? 3. When completed, will M-11 be pre -produced for more than 30 days, or will it simply be flowed back for a short period of time to clean up the perfs prior to beginning injection operations? Thank you again for your help, Steve Davies 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.daviesPalaska.gov. From: Cody Dinger <cdinger@hilcorp.com> Sent: Monday, February 11, 2019 11:03 AM To: Davies, Stephen F (DOA) <steve.davies@alaska.gov> Cc: Joe Engel <jengel@hilcorp.com>; Monty Myers <mmyers@hilcorp.com> Subject: RE: [EXTERNAL] MPU M-11 (PTD 219-010) - Question Hi Steve, I have updated the AOR table with details on L-20, L-35 and L-36 and attached it here. L-32 and L-34 do not pass through the AOR. Geology has informed me that no faults occur in the OA sand within the AOR. Thanks, Cody Dinger Hilcorp Alaska, LLC Drilling Technician cdineer@hilcoro.com Direct: 907-777-8389 From: Joe Engel Sent: Wednesday, February 06, 2019 12:57 PM To: Kevin Eastham <keastham@hilcorp.com>; Seth Nolan <snolan@hilcorp.com> Davies, Stephen F (DOA) From: Cody Dinger <cdinger@hilcorp.com> Sent: Monday, February 11, 2019 11:03 AM To: Davies, Stephen F (DOA) Cc: Joe Engel; Monty Myers Subject: RE: [EXTERNAL] MPU M-11 (PTD 219-010) - Question Attachments: AOR for MPM-11 2-11-19.pdf Hi Steve, I have updated the AOR table with details on L-20, L-35 and L-36 and attached it here. L-32 and L-34 do not pass through the AOR. Geology has informed me that no faults occur in the OA sand within the AOR. Thanks, Cody Dinger Hilcorp Alaska, LLC Drilling Technician cdineer@hilcorq.com Direct: 907-777-8389 From: Joe Engel Sent: Wednesday, February 06, 2019 12:57 PM To: Kevin Eastham <keastham@hilcorp.com>; Seth Nolan <snolan@hilcorp.com> Cc: Cody Dinger <cdinger@hilcorp.com>; Reid Edwards <reedwards@hilcorp.com>; Monty Myers <mmyers@ hilcorp.com> Subject: FW: [EXTERNAL] MPU M-11 (PTD 219-010) - Question Kevin/Seth/Cody — See Steves questions regarding M-11 AOR below. I have already answered his question regarding planned injection mitigation (MPD and S/I wells). Thanks. Joe Engel I Drilling Engineer I Hilcorp Alaska, LLC 3800 Centerpoint Dr., Ste. 1400 1 Anchorage I AK 199503 Office: 907.777.8395 1 Cell: 805.235.6265 From: Davies, Stephen F (DOA) [mailto:steve.davies@alaska.aovI Sent: Wednesday, February 6, 2019 12:14 PM To: Joe Engel <iengel@hilcorp.com> Subject: [EXTERNAL] MPU M-11 (PTD 219-010) - Question Joe, I'm reviewing the Permit to Drill application for Hilcorp's planned MPU M-11 injection well. I have a few questions. 1. 1 notice that existing Kuparuk wells L-20, L36, and L-35 are not included in the Cement/Zonal Isolation table for the M-11 well. Don't these wells pass through the OA sand and or the confining intervals within the Area of Review for M-11? If so, please update the Area of Review table to include this information. Do L-32 and L-34 pass through the lower confining interval within the Area of Review? If so, please update the table accordingly. 2. Do any faults occur in the OA sand within the Area of Review? If so, please provide a map that shows the wells and faults within the Area of Review. Please annotate the map to indicate the down -thrown direction and vertical displacement of each fault. Could any of these faults provide conduits between wells or for injected fluids to migrate out of zone? If so, what are Hilcorp's planned monitoring or mitigating measures? Thank you for your help, Steve Davies 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. AOGCC PTD No. 219-010 Coordinate Check 28 January 2019 INPUT Geographic, NAD27 OUTPUT State Plane, NAD27 5004 - Alaska 4, U.S. Feet MPU M-11 1f1 Latitude: 70 29 13.99300 NorthingN: 6027889.564 Longitude: 149 43 18.86500 Easting/X: 534023.889 Convergence: 0 15 43.63765 ScaleFactor: 0.999901315 Remark: Corpscon v6.0.1, U.S. Army Corps of Engineers TRANSMITTAL LETTER CHECKLIST WELL NAME: /vli�g� fes( l PTD: Development ✓ Service Exploratory _ Stratigraphic Test _ Non -Conventional FIELD: g/ l k ole POOL: �G q l �p / Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI The permit is for a new wellbore segment of existing well Permit LATERAL No. , API No. 50- _ be function the (If last two digits Production should continue to reported as a of original in API number are API number stated above. between 60-69 In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well Pilot Hole name ( PH) and API number (50- - from records, data and logs acquired for well name on permit . The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce/inject is contingent upon issuance of a conservation Spacing Exception order approving a spacing exception. (Company Name) Operator assumes the liability of any protest to the spacing exception that may occur. All dry ditch sample sets submitted to the AOGCC must be in no greater Dry Ditch Sample than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. Please note the following special condition of this permit: production or production testing of coal bed methane is not allowed for Non -Conventional (name of well) until after (Company Name) has designed and Well implemented a water well testing program to provide baseline data on water quality and quantity. (Company Name) must contact the AOGCC to obtain advance approval of such water well testing program. / Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by man Name) in the attached application, the following well logs are also required for this well: (� 4la ie Well Logging .nn u c c.l� ��o-, Requirements / Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, f/ composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. Revised 2/2015 WELL PERMIT CHECKLIST Field & Pool MILNE POINT, SCHRADER BLFF OIL - 525140 Well Name: MILNE PT UNIT M-11 Program SER Well bore seg ❑ PTD#:2190100 Company HILCORP ALASKA LLC Initial Class/Type SER / PEND GeoArea 890 Unit 11328 On/Off Shore On Annular Disposal ❑ Administration 1 Permit fee attached - - - .. - - NA 2 Lease number appropriate- - - - - .... - - - - . Yes - - - - _ - Surf. Loc & Top Prod Int lie inADL0025514; Portion of Well Passes Thru ADL003882 3 Unique well name and number . - - - - - - Yes - - - TO lies in ADL0025515...... . . . . . . . . . . ..... . . . . . .....rg- d'j 4 Well located in a -defined pool . .. . . . . . . . . . . . . .... . . . . . . ........... Yes - - - - _ Milne Point Schrader Bluff Oil Pool (525140), governed by CO 477, amended by CO 477.05, - - - - - _ - - - - 5 Well located proper distance from drilling unit boundary ......... . . . . . ... .. . . . . Yes - - - - CO 477.05- specifies: -'There are no restrictions as to well spacing except that no pay shall- - - - - ..... 6 Welllocated proper distance from other wells... - - - - - - - - - Yes - .. _ be openedina well closer than 500 feet from the exterior boundary of the affected area.° - 7 Sufficient acreage available in drilling unit.. - - .. Yes - - - Well bore conforms to spacing requirements. - - - - 8 If deviated, is wellbore platinaluded _ _ - - _ _ - - _ Yes 9 Operator only affected party--..... -.. -------- ------ ...... Yes... --- --- -- ------ ---.. _.... -... ---- ---------..... -------...... 10 Operator hasappropriate bond in force - - - .... - _ - - - .... _ - Yes - 11 Permit can be issued without conservation order . .. . . . . . . . . ....... . . . . . . . Yes - - - Appr Date 12 Permit can be issued without administrative approval - - - .. - - - _ _ . _ . Yes 13 Can permit be approved before 15 -day wait- Yes SFD 2/12!2019 --_-------.. - - ... - - - - - - ------- - - - - - - - - - - - --- - - -------.. 14 Well located within area and strata authorised by Injection Order # (put 10# in. comments) (For- Yes - - - - - - - --------- - - - - - - - - - - - 15 All wells within 1/4, mile area of review identified (For service well only). - - .. Yes .... - - MPU M-10, L-20,1_736, L-35, Pesado 1, Pesado 1A 16 Pre -produced injector: duration of pre -production less than 3 months (For service well only) - - No . . . . . ....... . . . . . . 17 Nonconven, gas conforms to AS31,05.030(j.1.A),0 2.A -D) - - - - -- -- - - - - - - - - - Yes 18 Conductor string -provided ........... .. .. ......................... Yes..-.-. _20V'set at 113 ft,_-----_- --...... Engineering 19 Surfaceeasing, protects all known USDWs - - - - - NA- - - -.. ---..-. - Permafrost area..: - 20 CMT.vol- adequate _to circulate on conductor & surf.esg - - - - - - - - ------- - - - - - - - - Yes _ - - .... Using stage cement on 9 5/8" casing . ES at 2500 ft.... - - - 21 CMT vol adequate. to tie-in Jong string to surf csg.. . . . . .... . . . . . .. . . . .. Yes ... 22 CMT. will coyer all known productive horizons_ ... _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes _ _ _ - _ ........ 23 Casing designs adequate for C, T, B &_permafrost- - - - - - - - - ---- - - - - - - - - - Yes . _ ... - - BTC calc are with Safety margin-.. - - - - - - - - - 24 Adequate tankageorreserve pit _ _ .... - - - - - . - - _ Yes ....... Rig has steel pits.. All waste to approved disposal wells.- - 25 If a re -doll, has.a 10-403 for abandonment been approved . . . . . . . .......NA - _ _ _ - _ - grassroots.well.- 26 Adequate wellbore separation proposed _ - - - - - - - - - - Yes - _ .... Close_crossing with L -35A at about 9800 ft md. - 90 deg to path.. Extra precaution required. - 27 If diverter required, does it meet regulations.. Yes - - 16" diverter...- map of Jayout is provided. Appr Date 28 Drilling fluid program schematic.& equip list adequate---- - - - - - - - - - ---- - - - - Yes - - - - - - Max formation press= 1745 -psi -(8.46 ppg. ). Will doll with -8.9-9.5 ppg mud - - - GLS 2/15/2019 29 BOPEs, do.they meet regulation - - - - - - - - - - - ----- - - - - - - ---- - - - - - - - - Yes - - .. Doyon 14 has -135/8" BOPE .5000 psi W.P- - 30 ROPE press rating appropriate; test to _(put prig in comments) . ....... . . . . . . . . . . Yes ... - MASP = 1349 psi will test BOPS to 3000 psi _ - _ .... 31 Choke_manifold complies w/API. RP -53 (May 84) . Yes - - - - - - - - - - - --- - - - - - - - - - - - -------- - - - - - - - -- - - - - - - - - - - - - 32 Work will occur without operation shutdown- - .. - - - - - _ - - _ - - - - - Yes - - - ----- - - - - - - - - - - - - - 33 Js presence of H2S gas, probable - - - _ - _ - - - No.. .. H2S not expected. - ....... - . . . . . .... . . . . . . ....... . . . . . .. 34 Mechanical condition of wells within AOR verified (For service well only) - - - - - - - - - Yes ....... 1/4 mile AOR completed. All wells in area are isolated mechanically. ... . . . . . . ..... 35 Permit can be issued w/o hydrogen sulfide measures - .... . . . . .... . . . Yes - _ - - _ _ _ H2S not anticipated from drilling of offset wells; however, rig will have H28 sensors and alarms._ Geology 36 Data. presented on potential overpressure zones- --- - - - - - - - -- - - - Yes _ . _ - _ .. Gas hydrates not expected from ddlling.of offset wells, but mitigation measures are discussed on page 14. - - Appr Date 37 Seismic analysis of ahailow gas zones ......... . . . . . .... - - - - - ..... NA........ Operator's planned.mud.weights appear sufficient to Control -expected formation pressures SFD 2/6/2019 38 Seabed condition survey (if off -shore) ----- - - - - - - - - - --- - - - - - - - - - - - - - - - - NA ..... - - Nearby well M-10.encountered elevated pressure due to injection in nearbywefs F-110 and 1_50. Operator .... . 39 Contact name/phone for weekly -progress reports [exploratory only] - - - - _ _ - .... _ - NA - - - will be ready -to increase_mud_weight if needed as discussed on page 45. . . . . ....... . . . . . . Geologic Engineering Public Schrader Bluff Water injector. Commissioner: Date: Commissioner, Date Commissioner Date - C ` 2-/5 -i S