The URL can be used to link to this page

Home My WebLink About220-016MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Wednesday, May 22, 2024 SUBJECT:Mechanical Integrity Tests TO: FROM:Kam StJohn P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL Hilcorp Alaska, LLC M-25 MILNE PT UNIT M-25 Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 05/22/2024 M-25 50-029-23668-00-00 220-016-0 W SPT 3598 2200160 1500 695 698 698 700 4YRTST P Kam StJohn 4/13/2024 Monobore Injector, No OA 4 year AOGCC witness MIT-IA 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-25 Inspection Date: Tubing OA Packer Depth 61 1702 1629 1606IA 45 Min 60 Min Rel Insp Num: Insp Num:mitKPS240413111235 BBL Pumped:3 BBL Returned:3 Wednesday, May 22, 2024 Page 1 of 1           Kaitlyn Barcelona Hilcorp North Slope, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: DATE: 10/18/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU M-25 (PTD 220-016) Coil Flag 09/16/2021 Please include current contact information if different from above. 37' (6HW Received By: 10/19/2021 By Abby Bell at 11:56 am, Oct 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 Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number):8. W ell Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071):10.Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 14,070 feet N/A feet true vertical 3,519 feet N/A feet Effective Depth measured 14,070 feet feet true vertical 3,519 feet 3,598 feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth)3-1/2" 9.3# / L-80 / EUE 8rd 5,876'3,598' Packers and SSSV (type, measured and true vertical depth)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.W ell Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16.W ell 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: 5867' and 15 swell packers SLZXP LTP and 15 Swell Packers Hilcorp Alaska LLC 2. Operator Name Senior Engineer:Senior Res. Engineer: Collapse N/A 3,090psi Burst N/A 5,750psi 777-8343 20" x 34" 9-5/8" 4-1/2" 3,607' 3,519' 8,540psi 114' 6,047' 10,472' Surface Liner Oil-Bbl 9,020psi Milne Point Unit M-25 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf 0 Casing Pressure Tubing Pressure 0 N/A measured 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 321-418 701 Authorized Signature with date: David Haakinson dhaakinson@hilcorp.com 10661 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 220-016 50-029-23668-00-00 Plugs ADL025514 5. Permit to Drill Number: Milne Point Field / Schrader Bluff Oil Pool Junk measured 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 3. Address: 4. W ell Class Before Work: 0 Representative Daily Average Production or Injection Data N/A0 114' measured true vertical Packer Size N/A Casing Conductor Length Operations Manager Chad Helgeson WINJ WAG 0 W ater-Bbl MD 114' 6,047' 14,070' TVD Form 10-404 Revised 3/2020 Submit Within 30 days of Operations By Meredith Guhl at 9:05 am, Oct 01, 2021 Digitally signed by David Haakinson (3533) DN: cn=David Haakinson (3533), ou=Users Date: 2021.10.01 06:53:22 -08'00' David Haakinson (3533) DSR-10/5/21 SFD 10/6/2021RBDMS HEW 10/1/2021 MGR 15OCT21 Well Name Rig API Number Well Permit Number Start Date End Date MP M-25 CTU 50-029-23668-00-00 220-016 9/16/2021 9/17/2021 9/17/2021 - Friday CTU #6 with 1.75" coil. Crews arrive on location. MU swivel to MHA. Pressure test to 3500psi. MU Injector to well. Open well and pump 55bbls 9.6 ppg NaCl KWF w/0.6% safe-lube. Flow check well and review shut in procedures with crew. MU SLB TCP BHA w/2.0" 2006 PJ Omega 6spf perforating guns. RIH to flag depth and correct to top shot. Stop at 10,850' and drop 1/2" aluminum ball. Land ball at 31.4 bbls. Fire guns at 2657 psi. PUH and perforate rest of scheduled perforations. Perforated the following intervals with 2.0" 2006 PJ Omega 6spf: (10,850' - 10,860'), (9,995' - 10,005'), (9,370' - 9,380'),(8,750' - 8,760'), (8,205' - 8,215'), (7,800' - 7,810'), (7,520' - 7,530'), (6,605' - 6,615'), (6,300' - 6,310'). POOH. Pump 55 bbls 9.6 ppg NaCl KWF w/0.6% safe-lube down tubing. Shut down and monitor well for flow. Confirm no-flow. LD SLB perforating guns. Confirm all shots fired. Freeze protect coil and surface lines with diesel. Secure well and SDFN. Notify operator well is ready to POI.* Hilcorp Alaska, LLC Weekly Operations Summary 9/16/2021 - Thursday CTU #6 with 1.75" coil. Crews arrive on location. Install UTIM to record coil condition. MU Quadco MHA. Pull test to 25k. Pressure test to 3500 psi. Wait on crane operator. Open well and attempt to bleed off pressure. Unsuccessful. Bullhead kill well with source water and safe lube. Pump 51 bbls and WHP continues to repressure up to 180 psi. MU and RIH with READ GR/CCL logging BHA and 10' of spent 2.0" perf gun. Begin locking up/stacking weight @ 10,200'. Work coil to 10,806' and no further progress. POOH logging. Paint flags @ 10,790' and 10,000'. Continue logging pass to 9,200'. POOH. Freeze protect well with 27 bbls of diesel. Secure well and rig down READ and SLB dummy perf gun. SDFN. Job continued on 9/17/21 WSR. _____________________________________________________________________________________ Revised By: DH 9/30/2021 SCHEMATIC Milne Point Unit Well: MPU M-25 PTD: 220-016 API: 50-029-23668-00-00 Depth MD Depth TVD ICD/Swell Packer Detail See Page 2 TD = 14,070’(MD) / TD =3,519’(TVD) 20” Orig. KB Elev.: 59.2’/ GL Elev.: 25.2’ 3-1/2”2 9-5/8” 1 3/4 6 See ICD & Swell Packer Detail PBTD =14,070’ (MD) / PBTD =3,519’(TVD) 9-5/8” ‘ES’ Cementer @ 2,401’ MD 4-1/2” 5 CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF 20"x 34” Conductor (Insulated) 215.5 / X-52 / Weld N/A Surface 114’N/A 9-5/8" Surface 40 / L-80 / TXP 8.679” Surface 6,047’ 0.0758 4-1/2” Liner 13.5 / L-80 / Hyd 625 3.795” 5,867’ 14,070’ 0.0149 TUBING DETAIL 3-1/2" Tubing 9.3 / L-80 / EUE 8RD 2.867” Surf 5,876’ 0.0870 JEWELRY DETAIL No Top MD Item ID Upper Completion 1 4,738’ 3-1/2” Gauge Mandrel w/ ¼” Wire 2.992” 2 4,791’ XN Landing Nipple w/ 2.813” Packing Bore 2.813” 3 5,865’ 8.25” No Go Locater Sub (1.32’ off No-go) 6.170” 4 5,867’ 7.375” Tieback above the SLZXP Liner Top Packer 6.170” Lower Completion 5 5,867’ 7” x 9-5/8” SLZXP Liner Top Packer with 7.38” Seal Bore 6.180” 6 14,070’ Shoe 3.970” OPEN HOLE / CEMENT DETAIL 42" ±270 ft3 12-1/4"Stg 1 –Lead 440 sx / Tail 400 sx Stg 2 –Lead 400 sx / Tail 270 sx 8-1/2” Cementless Injection Liner in 8-1/2” hole WELL INCLINATION DETAIL KOP @ 234’ Hole Angle @ XN = 64 ° Hole Angle @ Liner Top = 84° Max Hole Angle = 96° TREE & WELLHEAD Tree Cameron 3 1/8" 5M w/ 3-1/8” 5M Cameron Wing Wellhead Cameron 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs GENERAL WELL INFO API#: 50-029-23668-00-00 Completed by Doyon 14: 3/11/2020 PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status Schrader OA Sands 6,300’ 6,310’ 3,614’ 3,615’ 10 9/17/2021 Open 6,605’ 6,615’ 3,627’ 3,627’ 10 9/17/2021 Open 7,520’ 7,530’ 3,597’ 3,597’ 10 9/17/2021 Open 7,800’ 7,810’ 3,597’ 3,597’ 10 9/17/2021 Open 8,205’ 8,215’ 3,592’ 3,592’ 10 9/17/2021 Open 8,750’ 8,760’ 3,589’ 3,589’ 10 9/17/2021 Open 9,370’ 9,380’ 3,605’ 3,604’ 10 9/17/2021 Open 9,995’ 10,005 3,606’ 3,606’ 10 9/17/2021 Open 10,850’ 10,860’ 3,580’ 3,579’ 10 9/17/2021 Open Schrader OA Sands 6,300’ 6,310’ 3,614’ 3,615’ 10 9/17/2021 Open 6,605’ 6,615’ 3,627’ 3,627’ 10 9/17/2021 Open 7,520’ 7,530’ 3,597’ 3,597’ 10 9/17/2021 Open 7,800’ 7,810’ 3,597’ 3,597’ 10 9/17/2021 Open 8,205’ 8,215’ 3,592’ 3,592’ 10 9/17/2021 Open 8,750’ 8,760’ 3,589’ 3,589’ 10 9/17/2021 Open 9,370’ 9,380’ 3,605’ 3,604’ 10 9/17/2021 Open 9,995’ 10,005 3,606’ 3,606’ 10 9/17/2021 Open 10,850’ 10,860’ 3,580’ 3,579’ 10 9/17/2021 Open,,,,p// Depth MD Depth TVD ICD/Swell Packer Detail 6,074’ 3,607’ Tendeka Water Swell Packer 6,221’ 3,611’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 6,407’ 3,620’ Tendeka Water Swell Packer 6,678’ 3,628’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 6,907’ 3,622’ Tendeka Water Swell Packer 7,265’ 3,605’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 7,662’ 3,596’ Tendeka Water Swell Packer 7,850’ 3,595’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 8,079’ 3,591’ Tendeka Water Swell Packer 8,183’ 3,592’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 8,538’ 3,596’ Tendeka Water Swell Packer 8,642’ 3,594’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 8,785’ 3,587’ Tendeka Water Swell Packer 9,139’ 3,599’ Tendeka Water Swell Packer 9,326’ 3,605’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 9,596’ 3,602’ Tendeka Water Swell Packer 10,117’ 3,601’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 10,636’ 3,591’ Tendeka Water Swell Packer 11,034’ 3,576’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 11,345’ 3,579’ Tendeka Water Swell Packer 11,532’ 3,582’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 11,884’ 3,587’ Tendeka Water Swell Packer 12,280’ 3,566’ Tendeka Water Swell Packer 12,552’ 3,550’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 12,946’ 3,544’ Tendeka Water Swell Packer 13,258’ 3,535’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 13,487’ 3,532’ Tendeka Water Swell Packer 13,759’ 3,465’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 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): 14,070'N/A Casing Collapse Conductor Insulated 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 David Haakinson COMMISSION USE ONLY Authorized Name: Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): Tubing Size: PRESENT WELL CONDITION SUMMARY STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0025514 220-016 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 50-029-23668-00-00 Hilcorp Alaska LLC Length Size 3,519' 14,070' 3,519' 1,150 N/A MILNE POINT / SCHRADER BLUFF OIL 114' 114' 9.3# / L-80 / EUE 8rd TVD Burst 5,867' MD N/A 5,750psi 9,020psi 3,607' 3,519' 6,047' 14,070' See Schematic 114' 20" x 34" 9-5/8" 4-1/2" 6,047' 10,472' Authorized Signature: 9/8/2021 3-1/2" Perforation Depth MD (ft): See Schematic MILNE PT UNIT M-25 C.O. 477.05 SLZXP LTP & Swell Packers (See Schematic) and N/A 5,867 MD / 3,598 TVD & Swell Packers (See Schematic) 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. ory Statu Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 3:13 pm, Aug 23, 2021 321-418 Digitally signed by Chad Helgeson (1517) DN: cn=Chad Helgeson (1517), ou=Users Date: 2021.08.23 14:57:41 -08'00' Chad Helgeson (1517) SFD 8/24/2021 DSR-8/23/21MGR31AUG21 1,150 10-404 dts 8/31/2021 JLC 8/31/2021 Jeremy Price Digitally signed by Jeremy Price Date: 2021.08.31 17:55:22 -08'00' RBDMS HEW 9/1/2021 CT Perforate Well: MPU M-25 Date: 8/23/2021 Well Name:MPU M-25 API Number:50-029-23668-00-00 Current Status:Injector - Online Pad:M-Pad Estimated Start Date:September 8th, 2021 Rig:CT Reg. Approval Req’d?Yes Date Reg. Approval Rec’vd: Regulatory Contact:Darci Horner Permit to Drill Number: 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: 1,500 psi @ 3,500’ TVD Downhole Gauge |8.24 PPGE MPSP:1,150 psi @ 3,500’ TVD (0.1psi/ft gas gradient) Max Deviation:96° @ 12,291’ MD Max Dogleg:7.2°/100ft @ 4,890’ MD Min ID:2.75” ID @ 4,791’ MD XN Nipple Brief Well Summary: M-25 is a Schrader OA injector drilled in March 2020 to support M-24 and M-26 producers. The injector is performing poorly with a normalized injectivity index at roughly 50% of the offset injectors in the area. 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 300 BWPD injection increase to result in ~200 BOPD increase between M-24 and M- 26. 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 2,500 psi for 30 mins on 3/11/2020 x No well-work has been completed on the well post drilling. 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. 4. MU GR/CCL and drift assembly w/ circulating sub and 50’ of 2.3” OD spent perf guns. 5. Perform TIW valve stab drill with CT crew. 6. RIH to ~100’ past ICD #13 to 13,859’ MD or lockup depth. CT Perforate Well: MPU M-25 Date: 8/23/2021 7. Flag pipe for correlation. 8. Contact Engineer to review depth and planned perforation depths. 9. POOH to lateral KOP @ 5,900’ 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. CT Perforate Well: MPU M-25 Date: 8/23/2021 Note: Well temperature is estimated at 65 deg F. Delay fuses are temperature dependent and nominal burn time is estimated at 7.84 minutes per delay fuse at this temperature. Minimum time before picking up BHA above 6,300’ MD is after activating firing head is 7.84 minutes times the amount of deployment fuses in hole to ensure completion of maximum burn time of all delay fuses in the string. 16. Tie into flagged CT depth. Space out for bottom shot. 17. Once on depth. Confirm plan of operations and firing sequence with coil crew. 18. Pre-plan stop depths to account for space out of guns in BHA. Send to Engineer prior to dropping 1/2” activation ball. 19. Launch ½” ball to activate firing head. Equipment Length (ft) Top Depth (MD) Bottom Depth (MD) Top Depth (TVD) Bottom Depth (TVD) Sand Firing Head 3.65 Spacer 7 Perf Gun 5 13150 13155 3,535 3,535 Schrader OA Sand Deployment Bar 6.5 Deployment Bar 6.5 Perf Gun 5 12460 12465 3,553 3,553 Schrader OA Sand Deployment Bar 6.5 Deployment Bar 6.5 Perf Gun 5 11755 11760 3,586 3,586 Schrader OA Sand Deployment Bar 6.5 Deployment Bar 6.5 Perf Gun 5 10850 10855 3,580 3,580 Schrader OA Sand Deployment Bar 6.5 Deployment Bar 6.5 Perf Gun 5 9995 10000 3,606 3,606 Schrader OA Sand Deployment Bar 6.5 Deployment Bar 6.5 Perf Gun 5 9370 9375 3,605 3,605 Schrader OA Sand Deployment Bar 6.5 Deployment Bar 6.5 Perf Gun 5 8750 8755 3,589 3,589 Schrader OA Sand Deployment Bar 6.5 Deployment Bar 6.5 Perf Gun 5 8205 8210 3,592 3,592 Schrader OA Sand Deployment Bar 6.5 Deployment Bar 6.5 Perf Gun 5 7800 7805 3,597 3,597 Schrader OA Sand Deployment Bar 6.5 Deployment Bar 6.5 Perf Gun 5 7520 7525 3,597 3,597 Schrader OA Sand Deployment Bar 6.5 Deployment Bar 6.5 Perf Gun 5 6605 6610 3,627 3,627 Schrader OA Sand Deployment Bar 6.5 Perf Gun 5 6300 6305 3,614 3,614 Schrader OA Sand Total Length 207.15 545' Pick Up. Estimate 7 minutes travel time. 405' Pick Up. Estimate 5 minutes travel time. 280' Pick Up. Estimate 4 minutes travel time. 915' Pick Up. Estimate 12 minutes travel time. 305' Pick Up. Est. 4 min travel time 620' Pick Up. Estimate 8 minutes travel time. 690' Pick Up. Estimate 9 minutes travel time. 705' Pick Up. Estimate 9 minutes travel time. 905' Pick Up. Estimate 12 minutes travel time. 855' Pick Up. Estimate 11 minutes travel time. 625' Pick Up. Estimate 8 minutes travel time. CT Perforate Well: MPU M-25 Date: 8/23/2021 a.Note: Once ½” ball is launched and firing head is activated, there is no ability to stop the delay fuses from continuing. Indication of first zone will occur when shift of firing head is observed. b. A portable shot detection system needs to be used to detect gun activation. 20. Continue to observe weight indicator and pressure for other signs of gun activation. 21. Begin working up-hole for additional perforation depths. 22.If no indication is observed for a zone; stop and do not pick up past top perf depth of 6,300’ MD until full duration of delay period has elapsed from time of firing head activation. 23. POOH to KOP @ 5,900’ 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 Standing orders flow chart included with this sundry request. _____________________________________________________________________________________ Revised By: TDF 8/23/2021 SCHEMATIC Milne Point Unit Well: MPU M-25 PTD: 220-016 API: 50-029-23668-00-00 Depth MD Depth TVD ICD/Swell Packer Detail See Page 2 TD =14,070’ (MD) / TD =3,519’ (TVD) 20” Orig. KB Elev.: 59.2’/ GL Elev.: 25.2’ 3-1/2”2 9-5/8” 1 3/4 6 See ICD & Swell Packer Detail PBTD =14,070’ (MD) / PBTD =3,519’(TVD) 9-5/8” ‘ES’ Cementer @ 2,401’ MD 4-1/2” 5 CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF 20"x 34” Conductor (Insulated) 215.5 / X-52 / Weld N/A Surface 114’ N/A 9-5/8" Surface 40 / L-80 / TXP 8.679” Surface 6,047’ 0.0758 4-1/2” Liner 13.5 / L-80 / Hyd 625 3.795” 5,867’ 14,070’ 0.0149 TUBING DETAIL 3-1/2" Tubing 9.3 / L-80 / EUE 8RD 2.867” Surf 5,876’ 0.0870 JEWELRY DETAIL No Top MD Item ID Upper Completion 1 4,738’ 3-1/2” Gauge Mandrel w/ ¼” Wire 2.992” 2 4,791’ XN Landing Nipple w/ 2.813” Packing Bore 2.813” 3 5,865’ 8.25” No Go Locater Sub (1.32’ off No-go) 6.170” 4 5,867’ 7.375” Tieback above the SLZXP Liner Top Packer 6.170” Lower Completion 5 5,867’ 7” x 9-5/8” SLZXP Liner Top Packer with 7.38” Seal Bore 6.180” 6 14,070’ Shoe 3.970” OPEN HOLE / CEMENT DETAIL 42" ±270 ft3 12-1/4"Stg 1 –Lead 440 sx / Tail 400 sx Stg 2 –Lead 400 sx / Tail 270 sx 8-1/2” Cementless Injection Liner in 8-1/2” hole WELL INCLINATION DETAIL KOP @ 234’ Hole Angle @ XN = 64 ° Hole Angle @ Liner Top = 84° Max Hole Angle = 96° TREE & WELLHEAD Tree Cameron 3 1/8" 5M w/ 3-1/8” 5M Cameron Wing Wellhead Cameron 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs GENERAL WELL INFO API#: 50-029-23668-00-00 Completed by Doyon 14: 3/11/2020 Depth MD Depth TVD ICD/Swell Packer Detail 6,074’ 3,607’ Tendeka Water Swell Packer 6,221’ 3,611’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 6,407’ 3,620’ Tendeka Water Swell Packer 6,678’ 3,628’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 6,907’ 3,622’ Tendeka Water Swell Packer 7,265’ 3,605’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 7,662’ 3,596’ Tendeka Water Swell Packer 7,850’ 3,595’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 8,079’ 3,591’ Tendeka Water Swell Packer 8,183’ 3,592’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 8,538’ 3,596’ Tendeka Water Swell Packer 8,642’ 3,594’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 8,785’ 3,587’ Tendeka Water Swell Packer 9,139’ 3,599’ Tendeka Water Swell Packer 9,326’ 3,605’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 9,596’ 3,602’ Tendeka Water Swell Packer 10,117’ 3,601’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 10,636’ 3,591’ Tendeka Water Swell Packer 11,034’ 3,576’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 11,345’ 3,579’ Tendeka Water Swell Packer 11,532’ 3,582’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 11,884’ 3,587’ Tendeka Water Swell Packer 12,280’ 3,566’ Tendeka Water Swell Packer 12,552’ 3,550’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 12,946’ 3,544’ Tendeka Water Swell Packer 13,258’ 3,535’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 13,487’ 3,532’ Tendeka Water Swell Packer 13,759’ 3,465’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge _____________________________________________________________________________________ Revised By: TDF 8/23/2021 PROPOSED Milne Point Unit Well: MPU M-25 PTD: 220-016 API: 50-029-23668-00-00 Depth MD Depth TVD ICD/Swell Packer Detail See Page 2 TD = 14,070’(MD) / TD =3,519’(TVD) 20” Orig. KB Elev.: 59.2’/ GL Elev.: 25.2’ 3-1/2”2 9-5/8” 1 3/4 6 See ICD & Swell Packer Detail PBTD =14,070’ (MD) / PBTD =3,519’(TVD) 9-5/8” ‘ES’ Cementer @ 2,401’ MD 4-1/2” 5 CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF 20"x 34” Conductor (Insulated) 215.5 / X-52 / Weld N/A Surface 114’ N/A 9-5/8" Surface 40 / L-80 / TXP 8.679” Surface 6,047’ 0.0758 4-1/2” Liner 13.5 / L-80 / Hyd 625 3.795” 5,867’ 14,070’ 0.0149 TUBING DETAIL 3-1/2" Tubing 9.3 / L-80 / EUE 8RD 2.867” Surf 5,876’ 0.0870 JEWELRY DETAIL No Top MD Item ID Upper Completion 1 4,738’ 3-1/2” Gauge Mandrel w/ ¼” Wire 2.992” 2 4,791’ XN Landing Nipple w/ 2.813” Packing Bore 2.813” 3 5,865’ 8.25” No Go Locater Sub (1.32’ off No-go) 6.170” 4 5,867’ 7.375” Tieback above the SLZXP Liner Top Packer 6.170” Lower Completion 5 5,867’ 7” x 9-5/8” SLZXP Liner Top Packer with 7.38” Seal Bore 6.180” 6 14,070’ Shoe 3.970” OPEN HOLE / CEMENT DETAIL 42" ±270 ft3 12-1/4"Stg 1 –Lead 440 sx / Tail 400 sx Stg 2 –Lead 400 sx / Tail 270 sx 8-1/2” Cementless Injection Liner in 8-1/2” hole WELL INCLINATION DETAIL KOP @ 234’ Hole Angle @ XN = 64 ° Hole Angle @ Liner Top = 84° Max Hole Angle = 96° TREE & WELLHEAD Tree Cameron 3 1/8" 5M w/ 3-1/8” 5M Cameron Wing Wellhead Cameron 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs GENERAL WELL INFO API#: 50-029-23668-00-00 Completed by Doyon 14: 3/11/2020 PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status Schrader OA Sands 6,300’ 6,305’ 3,614’ 3,615’ 5 Future Pending 6,605’ 6,610’ 3,627’ 3,627’ 5 Future Pending 7,520’ 7,525’ 3,597’ 3,597’ 5 Future Pending 7,800’ 7,805’ 3,597’ 3,597’ 5 Future Pending 8,205’ 8,210’ 3,592’ 3,592’ 5 Future Pending 8,750’ 8,755’ 3,589’ 3,589’ 5 Future Pending 9,370’ 9,375’ 3,605’ 3,604’ 5 Future Pending 9,995’ 10,000 3,606’ 3,606’ 5 Future Pending 10,850’ 10,855’ 3,580’ 3,580’ 5 Future Pending 11,755’ 11,760’ 3,586’ 3,586’ 5 Future Pending Depth MD Depth TVD ICD/Swell Packer Detail 6,074’ 3,607’ Tendeka Water Swell Packer 6,221’ 3,611’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 6,407’ 3,620’ Tendeka Water Swell Packer 6,678’ 3,628’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 6,907’ 3,622’ Tendeka Water Swell Packer 7,265’ 3,605’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 7,662’ 3,596’ Tendeka Water Swell Packer 7,850’ 3,595’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 8,079’ 3,591’ Tendeka Water Swell Packer 8,183’ 3,592’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 8,538’ 3,596’ Tendeka Water Swell Packer 8,642’ 3,594’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 8,785’ 3,587’ Tendeka Water Swell Packer 9,139’ 3,599’ Tendeka Water Swell Packer 9,326’ 3,605’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 9,596’ 3,602’ Tendeka Water Swell Packer 10,117’ 3,601’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 10,636’ 3,591’ Tendeka Water Swell Packer 11,034’ 3,576’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 11,345’ 3,579’ Tendeka Water Swell Packer 11,532’ 3,582’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 11,884’ 3,587’ Tendeka Water Swell Packer 12,280’ 3,566’ Tendeka Water Swell Packer 12,552’ 3,550’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 12,946’ 3,544’ Tendeka Water Swell Packer 13,258’ 3,535’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 13,487’ 3,532’ Tendeka Water Swell Packer 13,759’ 3,465’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge CT Perforate Well: MPU M-25 Date: 8/23/2021 CT Perforate Well: MPU M-25 Date: 8/23/2021 Equipment Layout Diagram CT Perforate Well: MPU M-25 Date: 8/23/2021 Standing Orders for Open Hole Well Control during Perf Gun Deployment MEMORANDUM TO: Jim Regg�Lf P-1. Supervisor ' �f`i1 7312OW FROM: Matt Herrera Petroleum Inspector NON -CONFIDENTIAL State of Alaska Alaska Oil and Gas Conservation Commission DATE: Tuesday, April 7, 2020 SUBJECT: Mechanical Integrity Tests Hilcorp Alaska, LLC M-25 MILNE PT UNIT M-25 Sre: Inspector Reviewed By: J P.I. Sup" rfz- Comm Well Name MILNE PT UNIT M-25 API Well Number 50-029-23668-00-00 Inspector Name: Matt Herrera Permit Number: 220-016-0 Inspection Date: 4/6/2020 ' Insp Num: maMFH200406133547 Rel Insp Num: Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Well M-25 - Type Inj w TVD 3600 - Tubing 809 813 809 - 808 - PTD 2200160 Type Test SPT (Test psi 1500 IA Ha 1823 1752 - 1733— – BBL Pumped: 2.7 BBL Returned: 2.7 OA Interval WITAL P/F P Notes: IA Pressure tested to 1800 PSI Per Operator. Well is a Monobore Completion no OA > Tuesday, April 7, 2020 Page I of I DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-23668-00-00Well Name/No. MILNE PT UNIT M-25Completion Status1WINJCompletion Date3/11/2020Permit to Drill2200160Operator Hilcorp Alaska, LLCMD14070TVD3519Current Status1WINJ4/13/2020UICYesWell Log Information:DigitalMed/FrmtReceivedStart StopOH /CHCommentsLogMediaRunNoElectr DatasetNumberNameIntervalList of Logs Obtained:ROP, DGR, AGR, ABG, ADR, EWR MD and TVDNoNoYesMud Log Samples Directional SurveyREQUIRED INFORMATION(from Master Well Data/Logs)DATA INFORMATIONLog/DataTypeLogScaleC3/25/2020110 14070 Electronic Data Set, Filename: MPU M-25 LWD Final.las32253EDDigital DataC3/25/20206030 14032 Electronic Data Set, Filename: MPU M-25 ADR Quadrants All Curves.las32253EDDigital DataC3/25/2020 Electronic File: MPU M-25 LWD Final MD.cgm32253EDDigital DataC3/25/2020 Electronic File: MPU M-25 LWD Final TVD.cgm32253EDDigital DataC3/25/2020 Electronic File: MPU M-25 surveys.xlsx32253EDDigital DataC3/25/2020 Electronic File: MPU M-25i_Definitive Survey Report.pdf32253EDDigital DataC3/25/2020 Electronic File: MPU M-25i_Definitive Survey Report.txt32253EDDigital DataC3/25/2020 Electronic File: MPU M-25i_GIS.txt32253EDDigital DataC3/25/2020 Electronic File: MPU M-25i_Plan.pdf32253EDDigital DataC3/25/2020 Electronic File: MPU M-25i_VSec.pdf32253EDDigital DataC3/25/2020 Electronic File: MPU M-25 LWD Final MD.emf32253EDDigital DataC3/25/2020 Electronic File: MPU M-25 LWD Final TVD.emf32253EDDigital DataC3/25/2020 Electronic File: MPU_M-25_Geosteering.dlis32253EDDigital DataC3/25/2020 Electronic File: MPU_M-25_Geosteering.ver32253EDDigital DataC3/25/2020 Electronic File: MPU M-25 LWD Final MD.pdf32253EDDigital DataC3/25/2020 Electronic File: MPU M-25 LWD Final TVD.pdf32253EDDigital DataC3/25/2020 Electronic File: MPU M-25 LWD Final MD.tif32253EDDigital DataC3/25/2020 Electronic File: MPU M-25 LWD Final TVD.tif32253EDDigital DataMonday, April 13, 2020AOGCCPage 1 of 2MPU M-25 LWDFinal.las DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-23668-00-00Well Name/No. MILNE PT UNIT M-25Completion Status1WINJCompletion Date3/11/2020Permit to Drill2200160Operator Hilcorp Alaska, LLCMD14070TVD3519Current Status1WINJ4/13/2020UICYesWell Cores/Samples Information:ReceivedStart Stop CommentsSentSample SetNumberNameIntervalINFORMATION RECEIVEDCompletion ReportProduction Test InformationGeologic Markers/TopsY Y / NAYComments:Compliance Reviewed By:Date:Mud Logs, Image Files, Digital DataComposite Logs, Image, Data Files Cuttings SamplesY / NAYY / NADirectional / Inclination DataMechanical Integrity Test InformationDaily Operations SummaryYY / NAYCore ChipsCore PhotographsLaboratory AnalysesY / NAY / NAY / NACOMPLIANCE HISTORYDate CommentsDescriptionCompletion Date:3/11/2020Release Date: 2/13/2020C3/25/2020 Electronic File: EMFView3_1.zip32253EDDigital DataC3/25/2020 Electronic File: Readme.txt32253EDDigital Data0 0 2200160 MILNE PT UNIT M-25 LOG HEADERS32253LogLog Header ScansMonday, April 13, 2020AOGCCPage 2 of 2M. Guhl4/13/2020 1a. Well Status:Oil SPLUG Other Abandoned Suspended 1b. Well Class: 20AAC 25.105 20AAC 25.110 Development Exploratory GINJ WINJ WDSPL No. of Completions: _1 Service Stratigraphic Test 2. Operator Name: 6. Date Comp., Susp., or 14. Permit to Drill Number / Sundry: Aband.: 3. Address: 7. Date Spudded: 15. API Number: 4a. Location of Well (Governmental Section): 8. Date TD Reached: 16. Well Name and Number: Surface: Top of Productive Interval: 9. Ref Elevations: KB: 17. Field / Pool(s): GL: 25.2' BF: 25.2' Total Depth: 10. Plug Back Depth MD/TVD: 18. Property Designation: 4b. Location of Well (State Base Plane Coordinates, NAD 27): 11. Total Depth MD/TVD: 19. DNR Approval Number: Surface: x- y- Zone- 4 TPI: x- y- Zone- 4 12. SSSV Depth MD/TVD: 20. Thickness of Permafrost MD/TVD: Total Depth: x- y- Zone- 4 5. Directional or Inclination Survey: Yes (attached) No 13. Water Depth, if Offshore: 21. Re-drill/Lateral Top Window MD/TVD: Submit electronic information per 20 AAC 25.050 (ft MSL) 22. Logs Obtained: 23. BOTTOM 20" X-52 114' 4-1/2" L-80 3,519' 24. Open to production or injection? Yes No 25. 26. Was hydraulic fracturing used during completion? Yes No DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 27. Date First Production: Method of Operation (Flowing, gas lift, etc.): Hours Tested: Production for Gas-MCF: Test Period Casing Press: Calculated Gas-MCF: Oil Gravity - API (corr): Press. 24-Hour Rate ACID, FRACTURE, CEMENT SQUEEZE, ETC. CASING, LINER AND CEMENTING RECORD List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data within 90 days of completion, TUBING RECORD Liner Top Packer 3,607' 12-1/4" Cementless Injection Liner w/ ICDs 8-1/2" 42" 5,876'3-1/2" SIZEIf Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number; Date Perfd): Stg 1 L - 440 sx / T - 400 sx Stg 2 L - 400 sx / T - 270 sx 5,867' 14,070' 3,598'13.5# 9-5/8" 40# L-80 Surface 6,047' Surface 200 bbls Surface ±270 ft3Surface215.5# 114' STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG Hilcorp Alaska, LLC WAG Gas 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 3/11/2020 5039' FSL, 621' FEL, Sec 14, T13N, R9E, UM, AK 580' FSL, 1413' FWL, Sec 23, T13N, R9E, UM, AK 220-016 Milne Point Unit / Schrader Bluff Oil Pool 59.2' 14,070' MD / 3,519' TVD HOLE SIZE AMOUNT PULLED 50-029-23668-00-00 MPU M-25 533543 6027889 2141' FNL, 1909' FWL, Sec 14, T13N, R9E, UM, AK CEMENTING RECORD 6025977 SETTING DEPTH TVD 6018137 BOTTOM TOP CASING WT. PER FT.GRADE 530804 530349 TOP SETTING DEPTH MD Per 20 AAC 25.283 (i)(2) attach electronic information DEPTH SET (MD) 5,867' MD / 3,598' TVD PACKER SET (MD/TVD) Gas-Oil Ratio:Choke Size:Water-Bbl: PRODUCTION TEST N/A Date of Test: N/A Flow Tubing Oil-Bbl: suspension, or abandonment, whichever occurs first. Types of logs to be listed include, but are not limited to: mud log, spontaneous potential, gamma ray, caliper, resistivity, porosity, magnetic resonance, dipmeter, formation tester, temperature, cement evaluation, casing collar locator, jewelry, and perforation record. Acronyms may be used. Attach a separate page if necessary N/A *** Please See attached schematic for ICD detail *** Liner run on 3/9/2020 ROP, DGR, AGR, ABG, ADR, EWR MD & TVD Sr Res EngSr Pet GeoSr Pet Eng Oil-Bbl: Water-Bbl: March 6, 2020 February 24, 2020 ADL025514 LONS 16-004 2,095' MD / 1,834' TVD N/AN/A N/A 14,070' MD / 3,519' TVD WINJ SPLUGOther Abandoned Suspended Stratigraphic Test No No (attached) No Form 10-407 Revised 3/2020 Submit within 30 days of Completion, Suspension, or Abandonment By Samantha Carlisle at 11:02 am, Apr 08, 2020 GSFD 4/13/2020 (gls)Note: Surface casing FIT raw data is included at end of 10-407 report DSR-4/8/2020gls 4/9/20 RBDMS HEW 4/9/2020 Completion Date 3/11/2020 HEW Conventional Core(s): Yes No Sidewall Cores: 30. MD TVD 2,095' 1,834' Top of Productive Interval 6,221' SB OA 3,611' 1,357' 1,305' 2,151' 1,869' 4,140' 3,105' 5,024' 3,485' 5,972' 3,605' SB OA 31. List of Attachments: 32. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Name: Cody Dinger Contact Email:cdinger@hilcorp.com Authorized Contact Phone:777-8389 General: Item 1a: Item 1b: Item 4b: Item 9: Item 15: Item 19: Item 20: Item 22: Item 23: Item 24: Item 27: Item 28: Item 30: Item 31: FORMATION TESTS Permafrost - Top SV5 This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed. All laboratory analytical reports regarding samples or tests from a well must be submitted to the AOGCC, no matter when the analyses are conducted. Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, core analysis, paleontological report, production or well test results, per 20 AAC 25.070. If Yes, list formations and intervals cored (MD/TVD, From/To), and summarize lithology and presence of oil, gas or water (submit separate pages with this form, if needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071. Authorized Name: Monty Myers Authorized Title: Drilling Manager Permafrost - Base 29. GEOLOGIC MARKERS (List all formations and markers encountered): Yes No Well tested? Yes No 28. CORE DATA If yes, list intervals and formations tested, briefly summarizing test results. Attach separate pages to this form, if needed, and submit detailed test information, including reports, per 20 AAC 25.071. NAME SB OA SV1 Ugnu LA3 Formation at total depth: SB NA Wellbore Schematic, Drilling and Completion Reports, Definitive Directional Surveys, Csg and Cmt Report, FIT Chart Signature w/Date: Report the Division of Oil & Gas / Division of Mining Land and Water: Plan of Operations (LO/Region YY-123), Land Use Permit (LAS 12345), and/or Easement (ADL 123456) number. INSTRUCTIONS Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. TPI (Top of Producing Interval). Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data within 90 days of completion, suspension, or abandonment, whichever occurs first. Well Class - Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and other tests as required including, but not limited to: core analysis, paleontological report, production or well test results. Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29. Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity, permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology. The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). No NoSidewall Cores: Yes No Form 10-407 Revised 3/2020 Submit within 30 days of Completion, Suspension, or Abandonment Digitally signed by Monty M Myers DN: cn=Monty M Myers, c=US, o=Hilcorp Alaska, LLC, ou=Technical Services - AK Drilling, email=mmyers@hilcorp.com Reason: I am approving this document Date: 2020.04.08 10:52:02 -08'00' Monty M Myers _____________________________________________________________________________________ Revised By: CJD 4/7/20 Schematic Milne Point Unit Well: MPU M-25 PTD: 220-016 API: 50-029-23668-00-00 Depth MD Depth TVD ICD/Swell Packer Detail See Page 2 CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF 20"x 34” Conductor (Insulated) 215.5 / X-52 / Weld N/A Surface 114’ N/A 9-5/8" Surface 40 / L-80 / TXP 8.679” Surface 6,047’ 0.0758 4-1/2” Liner 13.5 / L-80 / Hyd 625 3.795” 5,867’ 14,070’ 0.0149 TUBING DETAIL 3-1/2" Tubing 9.3 / L-80 / EUE 8RD 2.867” Surf 5,876’ 0.0870 JEWELRY DETAIL No Top MD Item ID Upper Completion 1 4,738’ 3-1/2” Gauge Mandrel w/ ¼” Wire 2.992” 2 4,791’ XN Landing Nipple w/ 2.813” Packing Bore 2.813” 3 5,865’ 8.25” No Go Locater Sub (1.32’ off No-go) 6.170” 4 5,867’ 7.375” Tieback above the SLZXP Liner Top Packer 6.170” Lower Completion 5 5,867’ 7” x 9-5/8” SLZXP Liner Top Packer with 7.38” Seal Bore 6.180” 6 14,070’ Shoe 3.970” OPEN HOLE / CEMENT DETAIL 42" ±270 ft3 12-1/4" Stg 1 –Lead 440 sx / Tail 400 sx Stg 2 –Lead 400 sx / Tail 270 sx 8-1/2” Cementless Injection Liner in 8-1/2” hole WELL INCLINATION DETAIL KOP @ 234’ Hole Angle @ XN = 64 ° Hole Angle @ Liner Top = 84° Max Hole Angle = 96° TREE & WELLHEAD Tree Cameron 3 1/8" 5M w/ 3-1/8” 5M Cameron Wing Wellhead Cameron 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs GENERAL WELL INFO API#: 50-029-23668-00-00 Completed by Doyon 14: 3/11/2020 pre injection MIT to 2500 psi Depth MD Depth TVD ICD/Swell Packer Detail 6,074’ 3,607’ Tendeka Water Swell Packer 6,221’ 3,611’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 6,407’ 3,620’ Tendeka Water Swell Packer 6,678’ 3,628’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 6,907’ 3,622’ Tendeka Water Swell Packer 7,265’ 3,605’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 7,662’ 3,596’ Tendeka Water Swell Packer 7,850’ 3,595’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 8,079’ 3,591’ Tendeka Water Swell Packer 8,183’ 3,592’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 8,538’ 3,596’ Tendeka Water Swell Packer 8,642’ 3,594’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 8,785’ 3,587’ Tendeka Water Swell Packer 9,139’ 3,599’ Tendeka Water Swell Packer 9,326’ 3,605’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 9,596’ 3,602’ Tendeka Water Swell Packer 10,117’ 3,601’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 10,636’ 3,591’ Tendeka Water Swell Packer 11,034’ 3,576’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 11,345’ 3,579’ Tendeka Water Swell Packer 11,532’ 3,582’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 11,884’ 3,587’ Tendeka Water Swell Packer 12,280’ 3,566’ Tendeka Water Swell Packer 12,552’ 3,550’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 12,946’ 3,544’ Tendeka Water Swell Packer 13,258’ 3,535’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 13,487’ 3,532’ Tendeka Water Swell Packer 13,759’ 3,465’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge Activity Date Ops Summary 2/23/2020 Rig on M-35. Rig released at 24:00 23 February 2020. *** Submitted 24 hr notification @ 10:43 to AOGCC for upcoming Diverter test on M-25 ***;Move rig from south side to north side of Moose pad. Spot and level rig over well. Install all landings and walkways. Skid rig floor into drilling position. Spot service company buildings. Spot rock washer & fuel trailer. Load BHA into the pipe shed. 2/24/2020 Continue to R/U on M-25, Ready rig floor. install 90' mouse hole, M/U Stand 5'' DP, hang from blocks to check rig level and centered over well, good, R/U rock washer & fuel trailer. Spot water pump house. Install 4'' conductor valves.;N/U diverter adapter, annular & knife valve. Begin installing diverter. Install walkways and landings outside of rig, inspect saver sub and grabber dies- good, work on rig acceptance checklist SimOps: welder repair MP 1 suction line pit 4, C/O valves /seats MP 2. Put rig on high line power @ 10:20.;Continue to R/U and install diverter system, set containment and diverter warning signs, repair MP 1 suction line, install flow riser, WH rep energize seals on the WH adaptor, set water tank and spot cement silos. Remove Work on acceptance checklist. Accept rig @ 16:00 hrs.;PJSM, slip and cut 40' drilling line, re-calibrate block height. Inspect saver sub & grabber dies - good.;Perform diverter function test on 5" drill pipe. 3000 PSI system, 1800 PSI after closure, 200 PSI recovery 40 sec., full recovery 159 sec., knife valve open in 11 sec., annular close in 28 sec. *** AOGCC inspector Brian Bixby waived witness of the test at 10:54 on 24 Feb 2020 ***;Remove 5" HWDP from the shed & replace with Hilcorp owned HWDP and strap HWDP. P/U 17 joints 5" HWDP & jars, racking back 6 stands in the derrick. Repaired #1 mud pump suction line in pit#4. Check for leaks - none.;PJSM, M/U BHA #1: 12-1/4" Kymera KM633X bit, 8" mud motor w/ 1.5° AKO, bottle neck XO to 35'. RIH one stand 5" HWDP and tag bottom @ 112'.;Load 100 bbls of water in pit #4 to drill out conductor. Load pits with 290 bbls of spud mud. Function mud pump pop-off valves with water - lines clear. Test PVT levels & flow alarms. Sim-ops: R/U choke & gas buster line.;Pre-spud meeting with all parties involved. Pressure test mud lines to 3500 PSI and seat #1 mud pump valve seats. Flood stack & check for leaks - knife valve leaking. Drain stack & blow down top drive.;Disconnect knife valve on diverter tee side. Inspect knife valve - found minor sand / clay on blade. Sealing surfaces looked good, observed beveled edge press knife valve to seat when functioning. Function multiple times, looks good. Re-assembly, replace gasket and flood test.;Drill out 20" conductor f/ 112' to 114'. Drill 12-1/4" hole from 114' to 220', 106' drilled, 53'/hr AROP. 330 GPM, 150 PSI, 40 RPM, 1K TQ for 1st 30'. Utilize fresh water for first 10' of drilling & swap to 8.7 ppg spud mud on the fly. Increase to 400 GPM, 540 PSI, 40 RPM, 1-3K TQ, 5-10K WOB.;8.95 ppg MW, 300+ vis. 53K PU / 60K SO / 55K ROT. No surveys at this point.;Circulate 2x bottoms up while reaming f/ 220' t/ 128'. POOH f/ 128' t/ 35'. Blow down top drive. Inspect bit. M/U TM hang off collar to 42'.;Daily (midnight) losses = 0 bbls. Cumulative losses = 0 bbls. Hauled 350 bbls H2O from L-Pad for total = 350 bbls 2/25/2020 Orientate UBH0 to MWD. Upload and test MWD, RIH with 3-NMFDCs, XO & Stand of HWDP to 220'. Take rig off High Line @ 08:40 and put on gen power, issues with Turbine at L-Pad.;Drill 12-1/4" surface hole f/ 220' t/ 386', (386’ TVD) 166' drilled, 66.4’/hr AROP. 550 GPM, 1250 PSI, 60 RPM, 3K TQ, 10K WOB MW 8.9 in / 9.0 out, vis 300 in / 300 out, 9.0 ECD. 63K PU / 70K SO / 65K ROT Kick off @ 366’, target 3.0° BUR.;Drill 12-1/4" surface hole f/ 386' t/ 1038’, (1026’ TVD) 652' drilled, 108.7’/hr AROP. 540 GPM, 1370 PSI, 60 RPM, 5K TQ, 10K WOB MW 9.0 in / 9.0 out, vis 190 in / 130 out, 9.7 ECD. 89K PU / 81K SO / 90K ROT Increase to 4° BUR at 550' then reduce to 3.74° at 650' and start left turn with 4.71°/100'.;Drill 12-1/4" surface hole f/ 1038' t/ 1882’, (1694’ TVD) 844' drilled, 140.7’/hr AROP. 545 GPM, 1810 PSI, 60 RPM, 5-8K TQ, 15-25K WOB MW 9.25 in / 9.35 out, vis 160 in / 178 out, 10.33 ECD. 99K PU / 95K SO / 98K ROT Begin 51.1° tangent at 1845’.;Drill 12-1/4" surface hole f/ 1882' t/ 2630’, (2226’ TVD) 748' drilled, 124.7’/hr AROP. 550 GPM, 1700 PSI, 60 RPM, 5K TQ, 8-10K WOB MW9.35 in / 9.4 out, vis 95 in / 120 out, 10.52 ECD. 109K PU / 96K SO / 100K ROT Hold 51.1° tangent.;Base of Permafrost logged @ 2095’MD / 1834’ TVD. Last survey at 2604.10' MD / 2147.13' TVD, 51.36° inc, 273.46° azm, 21.62' from plan, 21.37' high and 3.31' right.;Daily Loss = 0 bbls, Cumulative losses = 0 bbls Hauled 1050 bbls H2O from L-Pad for total = 1400 bbls Hauled to MPU G&I 984 bbls cuttings/mud/cement for total = 984 bbls 2/26/2020 Drill 12-1/4" surface hole f/ 2630' t/ 3465’ (2691’ TVD) 835' drilled, 139’/hr AROP. 565 GPM, 1920 PSI, 70 RPM, 8-10K TQ, 10K WOB. MW 9.35 in / 9.4 out, vis 135 in / 150 out, 10.4 ECD. 125K PU / 100K SO / 115K ROT Max Gas = 64u. Start build & turn, target 4°/100' DL.;Drill 12-1/4" surface hole f/ 3465' t/ 4097’ (3080’ TVD) 632' drilled, 105’/hr AROP. 540 GPM, 1840 PSI, 70 RPM, 10-13K TQ, 15K WOB. MW 9.2 in / 9.25 out, vis 150 in / 146 out, 10.1 ECD. 146K PU / 100K SO / 120K ROT Max Gas = 52u. Continue build & turn with 4°/100' DL.;At 3800' start adding 0.5% ScreenKleen to prevent screen blinding from heavy oil while drilling UGNU L&M sands.;Drill 12-1/4" surface hole f/ 4097' t/ 4402’ (3239’ TVD) 305' drilled, 102’/hr AROP. 550 GPM, 1890 PSI, 70 RPM, 10-13K TQ, 15- 20K WOB. MW 9.2 in / 9.2 out, vis 71 in / 103 out, 10.0 ECD. 146K PU / 102K SO / 122K ROT Max Gas = 55u. Continue build & turn. Top of Ungu L&M sands logged at 4159'.;Service #1 conveyor, adjust idler sprocket toe alignment and chain tension. SimOps: Ream out slide section 3x to aid in maintaining directional angle. 550 GPM, 1670 psi. 70 RPM, 9-13k Tq. 9.9 ECD.;Drill 12-1/4" surface hole f/ 4402' t/ 4660’ (3350’ TVD) 258' drilled, 103’/hr AROP. 550 GPM, 1940 PSI, 70 RPM, 10-13K TQ, 15-20K WOB. MW 9.2 in / 9.3 out, vis 128 in / 181 out, 10.2 ECD. 162K PU / 94K SO / 124K ROT Max Gas = 225u. Continue build & turn with 4°/100' DL.;Drill 12-1/4" surface hole f/ 4660' t/ 5210’ (3526’ TVD) 550' drilled, 92’/hr AROP. 550 GPM, 2020 PSI, 70 RPM, 10-13K TQ, 15-20K WOB. MW 9.4 in / 9.45 out, vis 110 in / 120 out, 10.34 ECD. 160K PU / 95K SO / 120K ROT Max Gas = 290u.;Fault #1 logged at 4584’ MD with a 140’ DTE throw. Moderate shaker blinding starting at 4730’. Last survey at 5176.39' MD / 3520.17' TVD, 79.49° inc, 189.35° azm, 22.57' from plan, 8.06' low and 21.09' right.;Daily Loss = 0 bbls, Cumulative losses = 0 bbls Hauled 1570 bbls H2O from L-Pad for total = 2970 bbls Hauled to MPU G&I 1478 bbls cuttings/mud/cement for total = 2462 bbls n (LAT/LONG): evation (RKB): API #: Well Name: Field: County/State: MP M-25 Milne Point Hilcorp Energy Company Composite Report , Alaska Contractor AFE #: AFE $: Doyon 14 Job Name:1915944D MPU M-25 Drilling Spud Date: ;Drill out 20" conductor f/ 112' to 114'. Drill 12-1/4" hole from 114' to 220', ;Perform diverter function test on 5" drill pipe. 2/27/2020 Drill 12-1/4" surface hole f/ 5210' t/ 5786’ (3588’ TVD) 576' drilled, 96’/hr AROP. 535 GPM, 2150 PSI, 60 RPM, 17K TQ, 15K WOB. MW 9.55 in / 9.55 out, vis 92 in / 110 out, 10.4 ECD. 150K PU / 90K SO / 105K ROT Max Gas = 411u. Fault #2 drilled at 5234’, 60-70’ throw DTN.;Drill 12-1/4" surface hole f/ 5786' t/ 6054’ (3607’ TVD) 268' drilled, 107’/hr AROP. 550 GPM, 2230 PSI, 80 RPM, 15K TQ, 15K WOB. MW 9. 4 in / 9.4 out, vis 101 in / 78 out, 10.7 ECD. 148K PU / 87K SO / 114K ROT Max Gas = 241u.;OA-1 sand top at 5985’ MD / 3606’ TVD. TD of surface hole @ 6054’ MD / 3607’ TVD. Last survey at 6014.72' MD / 3606.80' TVD, 89.64° inc, 180.95° azm, 29.46' from plan, 29.46' low and 0.10' right.;Pump 27 bbl high vis sweep around while BROOH t/ 5880'. Sweep was strung out and not identified when returned to surface. RIH from 5880’ to bottom at 6054’. Perform flow check – Static – **Swap Rig to Highline power at 16:15**.;BROOH f/ 6054' t/ 3311', , at 5 min/stand, slowing as necessary for torque or pressure increases. 550 GPM, 1650 PSI, 80 RPM, 10-15K TQ, 9.3 ECD. 150k PU/ 94k SO / 115k ROT. Work tight spot at 4703’ several times until clean.;BROOH f/ 3311' t/ 1258' at 5 min/stand, slowing as necessary for Tq or pressure increases. 550 GPM, 1300 PSI, 80 RPM, 5-7K TQ. 100k PU/ 85k SO / 90k ROT. Pull slow f/ 2100’ t/ 2000’ while CBU. Increase in sand, silt & clay at 1665’, moderate shaker blinding, reduce pulling speed until cleaned up.;Daily Loss = 0 bbls, Cumulative losses = 0 bbls Hauled 1820 bbls H2O from L-Pad for total = 4790 bbls Hauled to MPU G&I 1721 bbls cuttings/mud/cement for total = 4183 bbls 2/28/2020 Back Ream out of the hole F/ 1258' T/ 838'. Pull last stand of 5'' Dp to 734 with no rot getting two btm up. Blowdown TD.;POOH on elevators, racking back HWDP, F/ 728' T/ 179'.;L/D Collars, Down load MWD. L/D MWD, Bit & Motor. Bit Grade 1-2-BT-S-E-1-CT-TD, Clean and clear the rig floor.;R/U to run 9 5/8 Casing. R/U 350 slips, Elevators & Volant tool. Install bail extensions.;PJSM. P/U & M/U 9-5/8" shoe joint, threadlocked joint, float collar joint, baffle adapter joint & joint #5 to 200'. Pump through shoe track to check floats - good. Install two 9-5/8"x12-1/4" centralizers w/ 4 stop rings on shoe joint, one centralizer w/ 2 stop rings on jt. #2, 3 & 4.;Run 9-5/8" 40# L-80 TXP BTC-SR casing f/ 200' t/ 2091'. Torque to 20960 ft/lbs with Doyon Volant tool. Fill pipe on the fly & top off every 10 joints. Install one 9-5/8"x12-1/4" centralizer on every joint #6 to 26.;L/D jts #52 & 53 after threads galled while making up, replace with jts #159 & 160. C/O collar on jt #51. C/O the volant swivel cable slings with chains.;Run 9-5/8" 40# L-80 TXP BTC-SR casing f/ 2091' t/ 3151’. Torque to 20960 ft/lbs with Doyon Volant tool. Fill pipe on the fly & top off every 10 joints. Install one 9-5/8"x12-1/4" centralizer on every other joint #27 to 51. 17 bbls lost while running first 80 joints.;Stage pumps up to 4 BPM, 160 PSI, while maintaining 9.25 ppg MW in adding water at 70 BPM to treat 9.6 ppg MW out and 130 vis. Increase to 5.5 BPM, 170 PSI and finished circulating a bottoms up.;Continue run 9-5/8" 40# L-80 TXP BTC-SR casing f/ 3151' t/ 6047'. Wash down f/ 6034' t/ 6047' @ 2 BPM 290 psi. Tq to 20960 ft/lbs with Doyon Volant tool. Fill pipe on the fly & top off every 10 joints. Install 9-5/8"x12-1/4" centralizer on every joint #89 to 92 & #93-96 then every other jt #98- 150.;Inspect ESC and verify pinned f/ 3300 psi, M/U Per HES rep with 1 ea centralizer installed on pup joints above and below ESC. ES Cementer placed at 3644', between joints #92 & 93. 38.5 bbls total loss while running casing.;Daily Loss (Midnight) = 17 bbls, Cumulative losses = 17 bbls Hauled 900 bbls H2O from L-Pad for total = 5690 bbls Hauled to MPU G&I 916 bbls cuttings/mud/cement for total = 5099 bbls 2/29/2020 Stage up pumps to 7 bpm 10 RPM 18K tq. Total of 43 bbls loss while running casing and circulating.;PJSM, Surface cmt job. Shut down Rig pumps. Blow down TD. R/U cmt lines. Line up rig pumps and pump 50 bbl heavy treated mud. Line up to HES.;HES pump 5 bbl H2o, Test lines. Fail. Change out leaking Plug valve. Re test to 4K Good. HES pump 53 bbl tunes spacer with Red Die in first 10 bbl. & polly flake. Drop btm Bypass plug, Mix & pump 181 bbl 12 ppg Lead cmt. 440 SX Mix & pump 82 bbl 15.8 Tail cmt 400 SX Drop top plug, HES pump 20 bbl.;Displace with rig with 237 bbl 9.4 PPG mud. Swap to HES & pump 80 bbl Tuned spacer. Swap to rig. Finish displacement with rig at 6 bpm, 112 bbl calculated bump. Rotate and reciprocated casing throughout cementing and displacement.;DID not Bump. Pump 8 bbl of the 9 bbl shoe track. Did not bump. FCP 521 psI. Check floats. Good. Bled back 1 bbl.;Drop free fall opening plug. The BOMB. Let fall 20 min. Blow down cmt lines while waiting. Purge cmt lines to rig floor. Bring pumps on at .5 BPM & ES CMT tool opend at 490 psi with full returns. Took one bbl to open. CIP 12:42.;Bring pumps up to 6 bpm & work pipe F/ 100K to 250k while circulating out spacer and cmt. Saw polly flake at tool opening. Saw 60 bbl spacer & 40 bbl cmt returned to surface. Cmt came back 50 bbl late from calculated. Got clean mud back at 330 bbl returned. Two btm up. 70 bbl late.;Circ two more btm up. no clabbored up mud. Shut down pumps.;Blow down surface equipment and flush all equipment with black water to clean up cmt. C/O Lo-torq valve on cement line.;Continue to circulate through ES cementer while preparing for 2nd stage cement job. 6 BPM, 190 PSI. Empty rockwasher & haul off fluilds, haul 79° water for cement job and mix black water pills. Hold PJSM for cement job. Prime cement unit & batch up spacer.;Perform 2nd stage cement job. Mix & pump 60 bbls of 10 ppg Tuned Spacer at 5 BPM, 233 PSI (4# red dye & 5# Pol-E-Flake in 1st 10 bbls). Mix & pump 313 bbls of 10.7 ppg Permafrost L lead cement (400 sks, 4.407 ft^3/sk yield) at 4.1 BPM, 235 PSI.;Mix & pump 56 bbls of 15.8 ppg Tail cement (270 sks, 1.169 ft^3/sk yield) at 3 BPM, 280 PSI. Drop closing plug. Pump 20 bbls fresh water at 6 BPM, 307 PSI.;Displace w/ 9.2 ppg spud mud w/ rig mud pump at 6 BPM, 200 PSI ICP, 480 PSI FCP. Bump plug at 1595 stks. 15 stks early of calculated. Pressure up and observe ES cmt tool close at 1180 psi. Pressure up to 1600 psi and hold for 3 minutes. Bleed off pressure. Held. Good. 1 bbl bled back CIP @ 22:55.;200 bbl cement returned to surface. No losses recorded while cementing. No clabbored up mud . ***AOGCC notified of upcoming BOP test at 10:42 on 29 Feb 2020, witness was waived by AOGCC Inspector Jeff Jones at 14:14 on 29 Feb 2020***.;Blow down cement lines. Disconnect accumulator lines to knife valve. Flush diverter stack with black water, functioning annular diverter 3 times. L/D volant CRT.;Disconnect knife valve & diverter line. N/D diverter from adapter & hoist stack. WH rep install 9 5/8 casing slips w/ 120k on slips. Welder cut 9 5/8'' casing, Total cut joint= 19.77'.;N/D flow nipple, riser & diverter stack. Capture lessons learned and procedures from Initial use of new trolley system for removing Annular and Tee from cellar.;Daily Loss = 26 bbls, Cumulative losses = 43 bbls Hauled 390 bbls H2O from L-Pad for total = 6080 bbls Hauled 815 bbls Source Water from G&I for total = 815 bbls Hauled to MPU G&I 1328 bbls cuttings/mud/cement for total = 6427 bbls 2nd stager drop plug ;Run 9-5/8" 40# L-80 TXP BTC-SR casing f/ 200' t/ 2091' No losses recorded while cementing. Prime cement unit & batch up spacer.;Perform 2nd stage cement job. Mix & pump 60 bbls of 10 ppg Tuned Spacer at 5 BPM, 233 PSI (4# red dye & 5# Pol-E-Flake in 1st 10 bbls). Mix & pump 313 bbls of 10.7 ppg Permafrost L lead cement (400 sks, 4.407 ft^3/sk yield) at 4.1 BPM, 235 PSI.;Mix & pump 56 bbls of 15.8 ppg Tail cement (270 sks, 1.169 ft^3/sk yield) at 3 BPM, Saw 60 bbl spacer & 40 bbl cmt returned to surface. & ES CMT tool opend at 490 psi ;200 bbl cement returned to surface. HES pump 53 bbl tunes spacer with Red Die in first 10 bbl. & polly flake. Drop btm Bypass plug, Mix & pump 181 bbl 12 ppg Lead cmt. 440 SX Mix & pump 82 bbl 15.8 Tail cmt 400 SX Drop top plug, HES pump 20 bbl.;Displace with rig with 237 bbl 9.4 PPG mud. Swap to HES & pump 80 bbl Tuned spacer. Swap to rig. Finish displacement with rig at 6 bpm, 112 bbl calculated bump. ;Drop free fall opening plug. The BOMB. Let fall 20 min. 1ststage 3/1/2020 Finish N/D diverter system & mobilize Well head equipment to Cellar. Make final cut on casing stump and dress cut.;N/U T103 Mandrill, test Mandrill 250/2400 psi for 5/10 min. Test Wellhead void to to 500 psi for 5 min and 5000 psi for 10 min @ per WH rep. SimOps: C/O Saver Sub on TopDrive.;PJSM, N/U BOP stack, hook up accumulator lines, N/U kill and choke lines. Install trip nipple, install mouseholes, load test joints in mouseholes. Prep t/ work on pipe skate.;PJSM, M/U 3.5'' test joint, flood stack and shell test BOP to 3000 psi. Rig electrician test rig gas alarms.;Test BOP equipment as per PTD & AOGCC requirements. All tests performed to 250 PSI low / 3000 PSI high. All tests held for 5 min. each. All tests performed w/ fresh water against test plug. ***AOGCC rep Jeff Jones waived witness for BOP test @ 14:14 hrs 02/29/20***;#1: Annular on 3.5" test joint, choke valves #1, 12,13,14, 3" kill Demco & upper IBOP. #2: Choke valves 9,11, HCR kill & lower IBOP. #3: Choke valves 5,8,10, manual kill & 5" TIW #1. #4: Choke valves 4,6,7 & 5" TIW #2. #5: Lower 3-1/2"x6" VBR on 3.5" test joint & 5” dart valve;#6: Upper 4-1/2”x7” VBR on 4.5" test joint, choke valves #2, 3-1/2” TIW #7: Upper 4-1/2”x7” VBR, on 4.5" test joint, HCR choke, 3-1/2” dart valve #8: Upper 4-1/2”x7” VBR, on 4.5" test joint, Manual choke #9: Lower 3-1/2"x6" VBR 4.5” test joint #10 Blind rams, choke valve #3;#11 Upper 4-1/2”x7” VBR on 5" test joint, choke valves #3. #12: Lower 3-1/2"x6" VBR on 5" test joint #13: Hyd choke “A” #14: Man choke “B” Accum test: 3000 PSI system pressure, 1650 PSI after closure. 47 sec for 200 PSI recharge, 192 sec full PSI recharge. 2050 PSI six nitrogen bottle average.;Blow down lines & rig down test equipment. Break down valves from test manifold & ready floor safety valves Pull test plug and install 10" I.D. wear bushing.;M/U 8-1/5" bit & 6.75" mud motor to 32' then TIH to 2209' with 5" HWDP & drill pipe out of the derrick. 100k PU / 82k SO.;Wash down f/ 2209' t/ 2397’ w/ 250 GPM, 420 PSI. Tag up cement at 2397’. Ream down f/ 2397' t/ 2402' w/ 420 GPM, 800 PSI, 30 RPM, 3-5K TQ. Drill cement & ES cementer f/ 2402' t/ 2402 w/ 6-7K WOB. Ream through 3x times, then work through 3x times with no pump or rotary.;Trip in hole with 5" DP f/ 2404' t/ 5733'. 170k PU / 75k SO.;Daily Loss = 0 bbls, Cumulative losses = 43 bbls Hauled 225 bbls H2O from L-Pad for total = 6305 bbls Hauled 0 bbls Source Water from G&I for total = 815 bbls Hauled to MPU G&I 618 bbls cuttings/mud/cement for total = 7045 bbls 3/2/2020 TIH to 5827’. Circ btm up before casing test. 510 GPM - 1380 psi, 30 RPM - 13k Tq. Reciprocate string 20' while circulating.;Test casing to 2500 psi for 30 Min. Took 5.5 bbl to pressure up.;Wash down and tag cmt at 5892’. Drill cmt and FE on depth and drill out shoe at 6047’. Clean out rathole t/ 6054 and drill 20’ new hole to 6074’. 460 GPM - 1420 psi, 30 RPM - 14k Tq, 8k WOB. Worked through BA, FE and shoe 3 times.;Circ btm up in casing. 470 GPM - 1420 psi, 30 RPM - 14k Tq.;Perform FIT to 12 PPG EMW. Good. Took 1.2 bbl to pressure up to 544 psi. Hold for 10 min. Bled down to 500 psi.;Pump Dry job and POOH to HWDP. L/D unneeded HWDP, Motor and Bit. Bit Graded: 1-2-CT-S-E-1-WT-BHA.;Clean and clear rig floor. Mobilize split bushing to floor and L/D master bushings.;PJSM, P/U BHA #3. M/U bit, Geo-Pilot & MWD tools to 83'. Initialize & test MWD tools. M/U 2 float subs & 3 NMDC to 178’. TIH w/ jar stand to 275'. Sim-ops: pressure test MPD lines to 250 PSI low / 1000 PSI high - good tests.;RIH w/ 1 std 5” DP & Shallow pulse test MWD with 470 GPM, 900 PSI - good test. Pressure test Geo-Span to 3000 PSI. Blow down top drive.;TIH f/ 370' t/ 4939' filling pipe every 2000'. Break-in Geo-Pilot seals at 2177' w/ 450 GPM, 1030 PSI, 5- 70 RPM, 8K TQ.;Grease Drawworks, troubleshoot unusual vibrations in Drawworks, inspect Drawworks chains and find a master link keeper broke and chain starting to part.;Change out high drum chain on Drawworks.;TIH f/ 4939' t/ 6048', 170K PU / 75K SO.;Remove trip nipple & install MPD RCD. Remove trip nipple from rig floor & install flow line plug.;Perform displacement to 8.8 ppg Flo-Pro mud @ 7.5 BPM, 600 PSI, 40 RPM, 15K TQ. Place bit on bottom @ 6074' when sweep & new mud exit drill string. Pull back into shoe & reciprocate pipe 55' while displacing.;Daily Loss = 0 bbls, Cumulative losses = 43 bbls Hauled 295 bbls H2O from L-Pad for total = 6600 bbls Hauled 0 bbls Source Water from G&I for total = 815 bbls Hauled to MPU G&I 271 bbls cuttings/mud/cement for total = 7316 bbls 3/3/2020 Continue displacement to 8.8 ppg Flo-Pro mud @ 8 BPM, 830 PSI, 40 RPM, 14K TQ. Reciprocate pipe 55'. Obtain SPR’s.;Blow down top drive, PJSM, hang blocks, slip and cut 47' drilling line, re-calibrate block height. Service top drive. Simops: Clean pit 4 and under shakers.;Drill 8-1/2" production lateral f/ 6074' t/ 6302’ (3615’ TVD), 228' drilled, 91.2'/hr AROP. 500 GPM, 1210 PSI, 120 RPM, 12k Tq, 3-5k WOB. 155k PU / 75k SO / 110k ROT. MW 8.75 ppg in / 8.75 out, 41 Vis in / 42 out, 9.9 ECD, max gas 1322u. Drilling in OA-1.;Drill 8-1/2" production lateral f/ 6302' t/ 7071’ (3620’ TVD), 769' drilled, 128.17'/hr AROP. 500 GPM, 1400 PSI, 120 RPM, 15k Tq, 16k WOB. 147k PU / 77k SO / 110K ROT. MW 8.9 ppg in / 9.0 out, 40 Vis in / 40 out, 10.3 ECD, max gas 719u.;Undulate down and enter OA-3 @ 6488', maintain lobe until 6910' then revert back up toward OA-1. Pumped high vis sweep at 7030', back at calc stks with 50% increase of cuttings. MPD full open while drilling. Observe 40 psi build with choke shut on connections.;Drill 8-1/2" production lateral f/ 7071' t/ 7794’ (3597’ TVD), 723' drilled, 120.5'/hr AROP. 515 GPM, 1600 PSI, 120 RPM, 15k Tq, 14-15k WOB. 149k PU / 69k SO / 109K ROT. MW 8.85 ppg in / 9.0 out, 43 Vis in / 43 out, 11.0 ECD, max gas 625u.;Entered OA-1 @ 7038' and maintain lobe until undulating down at 7626'. Enter OA-3 at 7715'. Start to see 12-20 ppm methane at possum belly with higher gas peaks. MPD hold 125 psi while drilling (target 10.8 ppg ECD), trap 150 psi during connections.;Drill 8-1/2" production lateral f/ 7794' t/ 8555’ (3598’ TVD), 761' drilled, 126.8’/hr AROP. 500 GPM, 1776 PSI, 100 RPM, 14k Tq, 14-15k WOB. 145k PU / 70k SO / 105K ROT. MW 9.05 ppg in / 9.1 out, 42 Vis in / 48 out, 11.0 ECD, max gas 630u.;MPD full open while drilling. Observe 35 psi build with choke shut on connections. Pumped high vis sweep at 8079', back at calc stks with 50% increase of cuttings. Hold OA-3 until 8156’. Encountered a fault, moving the wellbore from the upper OA-3 into the lower OA-1. Undulate back to OA-3.;11 concretions have been drilled for a total thickness of 47' (2.0% of the lateral). Last survey at 8485.92 MD / 3596.09' TVD, 88.53° inc, 181.66' azm, 56.05' from plan, 51.64' low, 6.5' right.;Daily Loss = 0 bbls, Cumulative losses = 43 bbls Hauled 510 bbls H2O from L-Pad for total = 7110 bbls Hauled 0 bbls Source Water from G&I for total = 815 bbls Hauled to MPU G&I 1134 bbls cuttings/mud/cement for total = 8449 bbls 3/4/2020 Drill 8-1/2" production lateral f/ 8555' t/ 9210’ (3611’ TVD), 655' drilled, 109.2’/hr AROP. 500 GPM, 1770 PSI, 110 RPM, 12k Tq, 16k WOB. 145k PU / 70k SO / 110K ROT. MW 9.1 ppg in / 9.2 out, 44 Vis in / 48 out, 11.0 ECD, max gas 538u. MPD full open while drilling. Holding 50 psi on connections.;Pumped high vis sweep at 9031', back at calc stks with 25% increase of cuttings. Fault #2 at 8554’ - 4’ throw DTS. Fault #3 at 8822’ – 55’ throw DTS. Fault #3 moved the wellbore out of the OA-3 into the shale above the OA package. Drop to 88° and re-enter the OA-1 @ 9200’. 378’ above OA sands.;Drill 8-1/2" production lateral f/ 9210' t/ 9935’ (3606’ TVD), 725' drilled, 120.8’/hr AROP. 500 GPM, 1890 PSI, 120 RPM, 13k Tq, 5k WOB. 145k PU / 73k SO / 100K ROT. MW 9.1 ppg in / 9.2 out, 43 Vis in / 46 out, 11.35 ECD, max gas 587u. MPD full open while drilling. Holding 50 psi on connections.;Drill 8-1/2" production lateral f/ 9935' t/ 10647’ (3594’ TVD), 712' drilled, 118.7’/hr AROP. 500 GPM, 1810 PSI, 120 RPM, 13k Tq, 4k WOB. 145k PU / 73k SO / 100K ROT. MW 9.1 ppg in / 9.2 out, 43 Vis in / 46 out, 11.35 ECD, max gas 556u.;Continue drilling the OA-3. Pumped high vis sweep at 9980', back 100 stks early with 50% increase of cuttings. With MBT & ECD climbing to 6.5 & 11.5 respectively, perform 290 bbl whole mud dilution at 10,241’. ECD drop to 11.15 ppg after dilution.;Drill 8-1/2" production lateral f/ 10647' t/ 11218 (3578’ TVD), 571’ drilled, 95.2’/hr AROP. 500 GPM, 1970 PSI, 120 RPM, 12k Tq, 5k WOB. 151k PU / 60k SO / 101K ROT. MW 9.05 ppg in / 9.2 out, 43 Vis in / 54 out, 11.50 ECD, max gas 720u. Revert back up and enter the OA-1 at 10775'.;MPD full open while drilling. Holding 50 psi on conn Pump hi vis sweep at 11022', back 100 stks early with 30% increase. 24 concretions have been drilled for a total of 101' (2.0% of the lateral)Last svy 11150.15' MD / 3576.64' TVD, 89.39° inc, 183.64° azm, 74.61' from plan, 74.53' low, 3.46' left.;Daily Loss = 0 bbls, Cumulative losses = 43 bbls Hauled 930 bbls H2O from L-Pad for total = 8040 bbls Hauled 0 bbls Source Water from G&I for total = 815 bbls Hauled to MPU G&I 1152 bbls cuttings/mud/cement for total = 9601 bbls Drill cement & ES cementer f/ 2402' t/ 2402 w/ 6-7K WOB. Ream through Tq.;Perform FIT to 12 PPG EMW. Good. Make final cut on casing stump and dress cut. ;Test casing to 2500 psi for 30 Min. MIT csg FIT ;Test BOP equipment as per PTD & AOGCC requirements. Drill 8-1/2" production lateral f/ 8555' t/ 9210’ (3611’ TVD), 3/5/2020 Drill 8-1/2" production lateral f/ 11218' t/ 11789’ (3586’ TVD), 571’ drilled, 95.2’/hr AROP. 500 GPM, 2110 PSI, 120 RPM, 14k Tq, 6k WOB. 150k PU / 60k SO / 105K ROT. MW 9.1 ppg in / 9.15 out, 43 Vis in / 47 out, 11.20 ECD, max gas 490u. MPD full open while drilling. Holding 50 psi on connections.;Drill 8-1/2" production lateral f/ 11789' t/ 12262’ (3565’ TVD), 473’ drilled, 78.8’/hr AROP. 500 GPM, 2130 PSI, 120 RPM, 14k Tq, 6k WOB. 155k PU / 40k SO / 100K ROT. MW 9.0 ppg in / 9.2 out, 42 Vis in / 43 out, 11.60 ECD, max gas 556u. MPD full open while drilling. Holding 50 psi on connections.;Fault #4 at 11960’ with a 60’ throw DTN moved the wellbore out of the OA-1 & into the shale below the OA package. Build to 95° and re-enter the OA-31 @ 12423'. Pumped high vis sweep at 11980', back 150 stks early with 25% increase of cuttings.;Drill 8-1/2" production lateral f/ 12262' t/ 12742’ (3547’ TVD), 480’ drilled, 80.0’/hr AROP. 500 GPM, 1940 PSI, 120 RPM, 14k Tq, 5k WOB. 163k PU / 40k SO / 103K ROT. MW 9.0 ppg in / 9.1 out, 42 Vis in / 42 out, 11.60 ECD, max gas 471u.;MPD full open while drilling. Holding 50 psi on connections. Pumped high vis sweep at 12265', back 150 stks early with 10% increase of cuttings. 290 bbl whole mud dilution at 12,400’. ECD reduced f/ 11.6 t/ 11.25. No change in MBT of 8.;Drill 8-1/2" production lateral f/ 12742' t/ 13280’ (3539’ TVD), 538’ drilled, 89.7’/hr AROP. 500 GPM, 2130PSI, 120 RPM, 14k Tq, 5-20k WOB. 165k PU / 40k SO / 100K ROT. MW 9.0 ppg in / 9.05 out, 42 Vis in / 44 out, 11.50 ECD, max gas 461u.;MPD full open while drilling. Holding 50 psi on connections. 290 bbl whole mud dilution at 13025’. ECD reduced f/ 11.6 t/ 11.30.;37 concretions have been drilled for a total thickness of 173' (2.2% of the lateral). Last survey at 13147.79' MD / 3534.62' TVD, 90.31° inc, 187.15° azm, 65.02' from plan, 53.21' low and 37.36' left.;Daily Loss = 0 bbls, Cumulative losses = 43 bbls Hauled 765 bbls H2O from L-Pad for total = 8805 bbls Hauled 0 bbls Source Water from G&I for total = 815 bbls Hauled to MPU G&I 1193 bbls cuttings/mud/cement for total = 10794 bbls 3/6/2020 Drill 8-1/2" production lateral f/ 13280' t/ 13711’ (3526’ TVD), 431’ drilled, 71.8’/hr AROP. 500 GPM, 2150PSI, 120 RPM, 17k Tq, 15-20k WOB. 170k PU / 40k SO / 100K ROT. MW 9.0 ppg in / 9.05 out, 42 Vis in / 46 out, 11.20 ECD, max gas 522u. MPD full open while drilling. Holding 50 psi on connections;Maintain the OA- 1 sands. Pumped high vis sweep at 13598', back 150 stks early with 50% increase of cuttings.;Drill 8-1/2" production lateral f/ 13711' t/ 14070’ (3519’ TVD), 359’ drilled, 143’/hr AROP. 500 GPM, 2160PSI, 120 RPM, 17k Tq, 5-16k WOB. 175k PU / 40k SO / 105K ROT. MW 9.0 ppg in / 9.1 out, 42 Vis in / 46 out, 11.35 ECD, max gas 597u. MPD full open while drilling. Holding 50 psi on connections.;TD in the OA-1. Last survey at 14000.72' MD / 3520.81' TVD, 91.31° inc, 184.96° azm, 47.87’ from plan, 41.82' low and 23.30’ right. 42 concretions were drilled in the lateral, for a total thickness of 202' (2.5%).;Pump low vis sweep followed by a high vis sweep. no increase of cutting observed, back on calc stks. 500 GPM, 2160 PSI, 120 RPM, 15K TQ, Continue to circulate 4 bottoms up while preparing mud pits for SAPP pills & brine displacement. Rack back a stand every bottoms up f/ 14070' t/ 13695'.;Wash back to bottom after 4x BU, 450 GPM – 1750 psi, 90 RPM – 14k Tq. Continue circulating while hold PJSM for displacing.;Pump SAPP pill treatment: 30 bbl hi-vis spacer, 40 bbls seawater, 30 bbls SAPP #1, 40 bbls seawater, 30 bbls SAPP #2, 40 bbls seawater, 30 bbls SAPP #3, 200 bbls seawater, 30 bbls hi-vis spacer.;Displace w/ 8.5 ppg 4% lube viscosified brine 6 BPM, 900 PSI ICP - 7 BPM, 700 PSI FCP, 90 RPM, 15k Tq start - 12K Tq final. Divert mud, SAPP trains/seawater to rock washer, w/ 8.5 ppg at returns MPD line @ 22 psi line pressure (10.05 ppg ECD ) pump until clean brine returns. 993 bbl total.;Perform PST tests: 3x test w/300ml each 4.25sec 4.37sec 4.54sec No losses recorded during displacement. Obtain SPR’s Monitor well with MPD closed choke. Bleed off and monitor for 4 min. Initial pressure build to 50psi, final build to 43 psi.;BROOH f/ 14070' t/ 13122' at 6-7 min/std. 500 GPM,1470 psi, 120 RPM, 14K Tq. MPD holding 65 psi when pumps on, 105 psi during connections.;Daily Loss = 0 bbls, Cumulative losses = 43 bbls Hauled 665 bbls H2O from L-Pad for total = 9470 bbls Hauled 0 bbls Source Water from G&I for total = 815 bbls Hauled to MPU G&I 2288 bbls cuttings/mud/cement for total = 13082 bbls 3/7/2020 BROOH f/ 13122’ t/ 11316' at 5 min/stand, slow for TQ or pressure increases. 500 GPM, 1460 PSI, 120 RPM, 14K TQ, 10.40 ECD. 165K PU / 50K SO / 105K ROT. Max Gas: 2641u. MPD holding 200 PSI on connections. 65 psi w/full open choke while reaming. No losses recorded.;Slight packing off intermittently while backreaming through the shale below the OA package f/ 12250' t/ 12030'. Slow pulling speed as needed and work back through several tight spots until clean.;BROOH f/ 11316’ t/ 8462' at 5 min/stand, slow for TQ or pressure increases. 500 GPM, 1390 PSI, 110 RPM, 9K TQ, 10.55 ECD. 147K PU / 85K SO / 106K ROT. Max Gas: 186u. MPD holding 200 PSI on connections. 45 psi w/full open choke while reaming. No losses recorded.;BROOH f/ 8462' t/ 9 5/8 shoe @ 6047' at 5 min/stand, slow for TQ or pressure increases. 500 GPM, 1300 PSI, 120 RPM,7K TQ, 10.20 ECD. 135K PU / 100K SO / 115K ROT. Max Gas: 628u MPD holding 200 PSI on conn. 45 psi w/full open choke while reaming. Start to see 3 BPH losses. Total 19 bbls loss on BROOH;Pump 30 bbl high vis sweep around plus additional bottoms up, cleaning 9 5/8'' casing, 1380 psi, 60-80 rpm, 3k torque, working pipe 90'. Sweep back on time w/ no increase in cuttings.;B/D TD. Close MPD choke and monitor pressure build f/ 11 psi to 56 psi in 5 min, bleed off t/ 10 psi and build back to 46 psi in 5 min.;Weight up from 8.8 ppg to 9.1 ppg, circulate around @ 500 gpm, 1060 psi, 80 rpm working pipe slow 3k tq. Cap well f/ shoe up. Good 9.1 ppg in/out.;Shut down, blow down top drive, allow flow to settle out then shut MPD choke. Build f/ 10 PSI t/ 24 PSI in 5 min. Blow down MPD lines. Open chokes & monitor well through 2" bleed off at bell nipple. Initial 2.0 BPH to 0.25 BPH in 20 min. then static. SimOps: Hold PJSM for remove MPD bearing.;Install FOSV. PJSM. Remove MPD RCD element, clean dirty flange then install trip nipple. Fill trip nipple & check for leaks - none.;PJSM. Cut and slip drilling line. Monitor Well on trip tank. 0.5 BPH static losses.;Daily Loss = 19 bbls, Cumulative losses = 62 bbls Hauled 450 bbls H2O from L-Pad for total = 9920 bbls Hauled 0 bbls Source Water from G&I for total = 815 bbls Hauled to MPU G&I 1473 bbls cuttings/mud/cement for total = 14555 bbls 3/8/2020 Finish slip and cut 39’ drilling line. Service Topdrive, drawworks and roughneck. Re-Calibrate block height. Circulate over top of well on trip tank to monitor well. 0.5 BPH losses.;Obtain new SPR’s, Pump dry job & drop 2.45'' drift on wire. Blow down TD.;POOH on elevators, racking 5'' DP stands in derrick f/ 5987’' t/ 2270'. Lay down remaining DP to shed f/ 2270' t/ 275'. 11 bbl losses on Trip out from shoe.;L/D 2 joints HWDP, recover drift and wire, L/D jars, 3 NM drill collars, 2 float subs to 83'. Read MWD tools, L/D remaining BHA. Bit grade= 2-1-CT-N-X-I-WT-TD. Clear and clean rig floor.;Mobilize 4-1/2" casing equipment to rig floor & R/U. Load tallied Swell Packers & ICD’s in pipeshed and prep to be picked up. M/U FOSV t/ XO on rig floor. Loss rate 2 BPH.;Hold PJSM with rig & casing crew. P/U shoe joint and RIH w/ 4-1/2", 13.5#, L-80, 625 Wedge liner as per tally t/ 5504'. Install 1 free floating centralizer & stop ring every joint. M/U Tq = 9600 ft/lbs. Loss rate running liner 2 bph, 12 bbls total loss. Fill pipe every 15 jts. 82k P/U, 75k S/O.;Continue RIH w/ 4-1/2", 13.5#, L-80, 625 Wedge liner as per tally f/ 5504’ t/ 8084'. Install 1 free floating centralizer & stop ring every joint. M/U Tq = 9600 ft/lbs. Loss rate running liner 1 bph, 18 bbls total loss while running liner. At 6036' - 90k PU / 75K SO.;Interval Daily Loses (Midnight) = 41 bbls, Cumulative losses = 60 bbls Hauled 75 bbls H2O from L-Pad for total = 9995 bbls Hauled 0 bbls Source Water from G&I for total = 815 bbls Hauled to MPU G&I 855 bbls cuttings/mud/cement for total = 15410 bbls RIH w/ 4-1/2", 13.5#, L-80, 625 Wedge liner as per tally t/ 5504'. ;POOH on elevators, Run inj liner ;Mobilize 4-1/2" casing equipment to rig floor 3/9/2020 P/U 4.5 625 13.5# injection completion F/ 8084' T/ 8180'. M/U SLZXP LT packer & pump 5 bbl through to verify clear. Good.;RIH with liner on 5' dp from derrick. F/ 8214' T/ 11453'. Tag up at 9260' & work through on elevators. Tag up at 9810'. Attempt to work past with rotary at 10K Tq & 20 RPM. No Go. Continue to work on elevators with no rotary and got past. Swell packers hanging up at 8600' +/-. OA 4 Shales.;P/U 69 joints of HWDP T/ 13547'. Make and break twice to break in new HWDP. Make up new pipe to 32K tq. UP/DN 195' / 125K. RIH on 5'' DP from the derrick F/ 13547' T/ 14070'. Tag bottom on depth at 14070'. Tag twice and put liner in tension w/ 5.5' of stretch.;Drop ball and wait 20 min. Pump down at 3 bpm and ball on seat at 56 bbl. Pressure up and see pusher tool go at 2650 psi. Hold 3K for 5 min. Slack off to 90K. Pressure up to 4120 psi and neutralizer tool released. P/U & verify free. 170K up. Good.;P/U 5’ & expose dog sub, set 25k down verifying packer is set. Close upper pipe rams & pressure test packer top for 10 min. to 1500 - good test. R/D test equipment & blow down lines. TOL @ 5866.57'.;Pump out of liner top, lay down 2 jts f/ 5895’ t/ 5847’. Pump hi-vis sweep around, ICP 2560 psi at 336 GPM / FCP 930 psi at 450 GPM. Work string 30’ and rotate 5 RPM, 4k Tq.;Pump hi vis spacer and displace to 9.2 ppg clean brine. ICP 1050 psi at 380 GPM / FCP 540 psi at 300 GPM. Continue working rot 5 RPM, & recip string 20’. Pumped a total of 561 bbls clean brine.;Blow down TD, Monitor Well – static -. POOH f/ 5847 laying down all drill pipe & HWDP. SimOps: Clean mud pits and rig down tank farm. Losses at 1-2 BPH;Inspect liner running tool. Rupture disk sheared, ball seat did not shear. Service break connections and lay down tool. Remove wear bushing.;Mobilize 3-1/2" completion equipment to the rig floor: Doyon double stack tongs, slips & elevators. M/U XO’s t/ FOSV. PJSM for running tubing. Review well control plan w/ tubing & TEC wire across BOPs.;M/U Baker 7.40" ported bullet seal assy to 18'. Run 10 joints of 3.5" 9.3# EUE L-80 tubing to 330'. Torque to 3,100 ft/lbs w/ Doyon double stack tongs. 1.5 BPH loss rate.;****Notify AOGCC of upcoming Pre MIT IA @ 07:30 on 3/10/2020**** Witness was waived by AOGCC rep Matthew Herrera @ 07:41 on 3/10/2020;Interval Daily (Midnight) Loss = 33 bbls, Cumulative losses = 93 bbls Hauled 50 bbls H2O from L-Pad for total = 10045 bbls Hauled 0 bbls Source Water from G&I for total = 815 bbls Hauled to MPU G&I 871 bbls cuttings/mud/cement for total = 16281 bbls Activity Date Ops Summary 3/10/2020 Continue to P/U and run 3-1/2 tubing f/ 330' to 1073' @ jt 34. Torque to 3100 ft/lbs with Doyon double stack tongs., M/U XN nipple w/ pup jt above and below, run jt 35 to 1127', Install Zenith C-6 gauge with pup jt above and below, test wire, good. 1.5 BPH loss rate.,Run 3-1/2" 9.3# L-80 EUE tubing f/ 1148' t/ 3118' , Torque to 3100 ft/lbs with Doyon double stack tongs. Install cross coupler Cannon clamp on every joint on first 6 jts to secure TEC wire, then every other jt. Continuous monitoring of gauge while running and testing every 1000'. 1.5 BPH loss rate. PU 60K, SO 60K.,Run 3-1/2" 9.3# L-80 EUE tubing f/ 3118' t/ 5814 @ jt 187 , Torque to 3100 ft/lbs. Install cross coupler Cannon clamp on every other joint. M/U joint 188,189 and 190, nogo out on TOL @ 5868.05'. Continuous monitoring of gauge while running and testing every 1000'.,*** Submit 24 hr notification @ 13:20 to AOGCC for upcoming Diverter test on M-25 ***,P/U 6'', Close annular, pressure up backside to 400 psi verifying seals engaged, good. Bleed off and open annular. PU 74K, SO 66K.,Space out as per Baker rep, L/D 4 jts, M/U 2-8' , 1- 6' and 1-4' pup jts ( 26.45' ), M/U jt 187. M/U Cameron hanger w/ pup 4.15’ pup joint, XO subs, 5" landing joint, FOSV, side entry sub & pup joint to reverse circulate. Perform hanger penetration w/ tech cable. Take final readings 1611 psi PPa, 1613 psi, Tt 71.4 deg Tt, 71.5 deg, Ta, V 18.,Drain Stack, RIH and Land hanger, P/U 2' and rig up cement hose to side entry sub. - 80 full Cannon clamps ran -.,PJSM. P/U 2', close annular & pressure up to 250 PSI. P/U until pressure dumps. Pressure test lines and reverse circulate 245 bbls of 9.3 ppg Conqor 303A inhibited brine at 7 BPM, 1420 PSI. Reverse circulate 145 bbls of diesel freeze protection at 4 BPM, 470 PSI ICP, 770 PSI FCP.,Slack off t/ 1’ above landing hanger, closing circ ports on bullet seal assembly. Bleed off trapped annulus pressure to cuttings tank. Blow down diesel in BOP stack to the cuttings tank. Land tubing hanger with 26K on hanger and run in lock down screws. EOP at 5876.33', locator sub 1.32' off no-go.,Perform 2500 PSI pre-injection MIT for 30 min. on chart. R/U test equipment, apply 2650 psi to 9 5/8" x 3 1/2" annulus, first 15 min bled off 100 psi, final 15 min bled off 40 psi, good test, bleed off to cuttings box, Pumped 4.6 bbls, bled back 4.6 bbls. AOGCC rep Matthew Herrera waived witness to MIT test 7:41 am on 3-9-20.,R/D test equipment, blow down lines. L/D landing joint, install BPV as per WH rep, Remove MPD drip pan, clear rig floor, suck out stack.,PJSM, N/D BOP stack and rack on stump. SimOps: Remove support buildings in prep for rig move.,Bring tree into cellar and warm with steam. Install CAHN seal on hanger and install dart in BPV. Feed TEC wire through adapter flange and nipple up tree.,Interval Daily Loss = 25 bbls, Cumulative losses = 118 bbls Hauled 365 bbls H2O from L-Pad for total = 10410 bbls Hauled 0 bbls Source Water from G&I for total = 815 bbls Hauled to MPU G&I 786 bbls cuttings/mud/cement for total = 17067 bbls 3/11/2020 N/U adapter flange and tree. Test hanger void to 500 PSI low for 5 min & 5000 PSI high for 10 min, good.,R/U test equipment. Test tree with diesel to 250/5000 PSI 5 min. each. good. R/D test equipment.,Pull BPV dart. R/U and test lines. PJSM. Bullhead 23 bbls diesel down tubing through BPV @ 1.6 bpm. ICP 690 psi, FCP 960 psi. freeze protect tbg to 2500'. Flush lines with water, blow down line to cuttings box, R/D same. Secure tree and cellar. Vac out cuttings box. Rig released @ 12:00.,Please refer to MPU M-43 for remaining activities. n (LAT/LONG): evation (RKB): API #: Well Name: Field: County/State: MP M-25 Milne Point Hilcorp Energy Company Composite Report , Alaska Contractor AFE #: AFE $: Job Name:1915944C MPU M-25 Completion Spud Date: MIT-IA ,Perform 2500 PSI pre-injection MIT for 30 min. on Continue to P/U and run 3-1/2 tubing f/ 330' to 1073' @ jt 34. Run tubing 09 March, 2020 Milne Point M Pt Moose Pad MPU M-25i 500292366800 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt Moose Pad Halliburton Definitive Survey Report Well: Wellbore: MPU M-25i MPU M-25i Survey Calculation Method:Minimum Curvature MPU M-25 Actual RKB @ 59.20usft Design:MPU M-25i Database:NORTH US + CANADA MD Reference:MPU M-25 Actual RKB @ 59.20usft North Reference: Well MPU M-25i True Map System: Geo Datum: Project Map Zone: System Datum:US State Plane 1927 (Exact solution) NAD 1927 (NADCON CONUS) Milne Point, ACT, MILNE POINT Alaska Zone 04 Mean Sea Level Using Well Reference Point Using geodetic scale factor Well Well Position Longitude: Latitude: Easting: Northing: usft +E/-W +N/-S Position Uncertainty usft usft usftGround Level: MPU M-25i, Slot 18 usft usft 0.00 0.00 6,027,889.56 533,543.90 25.20Wellhead Elevation:usft0.50 70° 29' 14.014 N 149° 43' 32.988 W Wellbore Declination (°) Field Strength (nT) Sample Date Dip Angle (°) MPU M-25i Model NameMagnetics BGGM2019 2/20/2020 16.12 80.90 57,396.67386711 Phase:Version: Audit Notes: Design MPU M-25i 1.0 ACTUAL Vertical Section: Depth From (TVD) (usft) +N/-S (usft) Direction (°) +E/-W (usft) Tie On Depth:34.00 184.560.000.0034.00 From (usft) Survey Program DescriptionTool NameSurvey (Wellbore) To (usft) Date 3/9/2020 Survey Date 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sa234.16 6,014.72 MPU M-25 MWD+IFR2+MS+Sag (1) (MP 02/12/2020 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sa6,106.18 14,000.72 MPU M-25 MWD+IFR2+MS+Sag (2) (MP 03/04/2020 MD (usft) Inc (°) Azi (°) +E/-W (usft) +N/-S (usft) Survey TVD (usft) TVDSS (usft) Map Northing (ft) Map Easting (ft) Vertical Section (ft) DLS (°/100')Survey Tool Name 34.00 0.00 0.00 34.00 0.00 0.00-25.20 6,027,889.56 533,543.90 0.00 0.00 UNDEFINED 234.16 1.01 354.59 234.15 1.76 -0.17174.95 6,027,891.32 533,543.73 0.50 -1.74 3_MWD+IFR2+MS+Sag (1) 325.69 1.28 357.79 325.66 3.58 -0.28266.46 6,027,893.14 533,543.60 0.30 -3.55 3_MWD+IFR2+MS+Sag (1) 420.55 1.36 330.76 420.50 5.62 -0.87361.30 6,027,895.18 533,543.00 0.66 -5.53 3_MWD+IFR2+MS+Sag (1) 515.51 2.62 326.91 515.40 8.42 -2.61456.20 6,027,897.97 533,541.25 1.33 -8.19 3_MWD+IFR2+MS+Sag (1) 609.00 5.53 327.26 608.64 14.00 -6.21549.44 6,027,903.53 533,537.63 3.11 -13.47 3_MWD+IFR2+MS+Sag (1) 702.60 7.35 316.40 701.65 22.13 -12.78642.45 6,027,911.63 533,531.02 2.33 -21.05 3_MWD+IFR2+MS+Sag (1) 797.51 10.15 298.69 795.46 30.55 -24.31736.26 6,027,920.00 533,519.46 4.06 -28.52 3_MWD+IFR2+MS+Sag (1) 892.59 14.64 285.93 888.32 37.87 -43.22829.12 6,027,927.23 533,500.51 5.50 -34.32 3_MWD+IFR2+MS+Sag (1) 987.95 19.33 280.99 979.50 44.19 -70.32920.30 6,027,933.43 533,473.39 5.14 -38.46 3_MWD+IFR2+MS+Sag (1) 1,082.56 23.31 279.50 1,067.62 50.27 -104.171,008.42 6,027,939.36 533,439.52 4.25 -41.83 3_MWD+IFR2+MS+Sag (1) 1,177.49 27.86 279.86 1,153.22 57.17 -144.571,094.02 6,027,946.07 533,399.09 4.80 -45.50 3_MWD+IFR2+MS+Sag (1) 1,273.30 32.93 281.93 1,235.83 66.40 -192.141,176.63 6,027,955.08 533,351.49 5.40 -50.91 3_MWD+IFR2+MS+Sag (1) 3/9/2020 11:08:56AM COMPASS 5000.15 Build 91E Page 2 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt Moose Pad Halliburton Definitive Survey Report Well: Wellbore: MPU M-25i MPU M-25i Survey Calculation Method:Minimum Curvature MPU M-25 Actual RKB @ 59.20usft Design:MPU M-25i Database:NORTH US + CANADA MD Reference:MPU M-25 Actual RKB @ 59.20usft North Reference: Well MPU M-25i True MD (usft) Inc (°) Azi (°) +E/-W (usft) +N/-S (usft) Survey TVD (usft) TVDSS (usft) Map Northing (ft) Map Easting (ft) Vertical Section (ft) DLS (°/100')Survey Tool Name 1,367.88 35.89 281.23 1,313.86 77.11 -244.491,254.66 6,027,965.56 533,299.09 3.16 -57.43 3_MWD+IFR2+MS+Sag (1) 1,463.30 39.19 280.61 1,389.51 88.11 -301.571,330.31 6,027,976.30 533,241.96 3.48 -63.86 3_MWD+IFR2+MS+Sag (1) 1,558.66 40.79 278.62 1,462.57 98.33 -361.991,403.37 6,027,986.25 533,181.51 2.15 -69.24 3_MWD+IFR2+MS+Sag (1) 1,653.42 41.70 275.93 1,533.82 106.23 -423.951,474.62 6,027,993.86 533,119.52 2.10 -72.18 3_MWD+IFR2+MS+Sag (1) 1,748.74 44.72 273.33 1,603.29 111.45 -488.981,544.09 6,027,998.79 533,054.47 3.68 -72.22 3_MWD+IFR2+MS+Sag (1) 1,843.97 46.54 271.76 1,669.89 114.46 -556.981,610.69 6,028,001.49 532,986.46 2.25 -69.81 3_MWD+IFR2+MS+Sag (1) 1,938.65 49.29 270.56 1,733.34 115.86 -627.231,674.14 6,028,002.58 532,916.22 3.05 -65.63 3_MWD+IFR2+MS+Sag (1) 2,033.74 49.58 271.17 1,795.18 116.96 -699.461,735.98 6,028,003.35 532,843.99 0.57 -60.98 3_MWD+IFR2+MS+Sag (1) 2,128.87 51.55 272.17 1,855.60 119.11 -772.891,796.40 6,028,005.17 532,770.55 2.22 -57.28 3_MWD+IFR2+MS+Sag (1) 2,223.99 52.48 272.63 1,914.14 122.25 -847.801,854.94 6,028,007.97 532,695.64 1.05 -54.46 3_MWD+IFR2+MS+Sag (1) 2,318.43 53.00 272.62 1,971.32 125.69 -922.881,912.12 6,028,011.07 532,620.55 0.55 -51.92 3_MWD+IFR2+MS+Sag (1) 2,413.59 52.37 274.97 2,029.01 130.69 -998.391,969.81 6,028,015.74 532,545.03 2.07 -50.90 3_MWD+IFR2+MS+Sag (1) 2,506.91 51.51 275.48 2,086.54 137.38 -1,071.562,027.34 6,028,022.09 532,471.84 1.02 -51.75 3_MWD+IFR2+MS+Sag (1) 2,604.10 51.36 273.46 2,147.13 143.31 -1,147.312,087.93 6,028,027.68 532,396.06 1.63 -51.64 3_MWD+IFR2+MS+Sag (1) 2,699.55 51.05 274.26 2,206.94 148.31 -1,221.542,147.74 6,028,032.35 532,321.83 0.73 -50.73 3_MWD+IFR2+MS+Sag (1) 2,794.92 50.56 273.89 2,267.21 153.57 -1,295.262,208.01 6,028,037.27 532,248.09 0.60 -50.10 3_MWD+IFR2+MS+Sag (1) 2,890.41 50.72 273.27 2,327.77 158.17 -1,368.952,268.57 6,028,041.54 532,174.39 0.53 -48.84 3_MWD+IFR2+MS+Sag (1) 2,985.66 51.79 271.68 2,387.38 161.37 -1,443.162,328.18 6,028,044.41 532,100.17 1.72 -46.13 3_MWD+IFR2+MS+Sag (1) 3,080.65 50.89 271.40 2,446.72 163.37 -1,517.312,387.52 6,028,046.07 532,026.02 0.98 -42.22 3_MWD+IFR2+MS+Sag (1) 3,175.84 50.39 272.02 2,507.09 165.56 -1,590.872,447.89 6,028,047.93 531,952.45 0.73 -38.56 3_MWD+IFR2+MS+Sag (1) 3,270.90 50.14 270.74 2,567.86 167.33 -1,663.952,508.66 6,028,049.36 531,879.37 1.07 -34.51 3_MWD+IFR2+MS+Sag (1) 3,367.13 51.17 266.17 2,628.88 165.30 -1,738.312,569.68 6,028,047.00 531,805.04 3.82 -26.57 3_MWD+IFR2+MS+Sag (1) 3,462.30 50.87 261.83 2,688.77 157.57 -1,811.852,629.57 6,028,038.95 531,731.53 3.56 -13.03 3_MWD+IFR2+MS+Sag (1) 3,557.14 49.99 257.30 2,749.20 144.36 -1,883.722,690.00 6,028,025.41 531,659.73 3.80 5.86 3_MWD+IFR2+MS+Sag (1) 3,653.21 51.82 251.97 2,809.81 124.57 -1,955.552,750.61 6,028,005.30 531,588.00 4.71 31.29 3_MWD+IFR2+MS+Sag (1) 3,748.05 52.43 247.07 2,868.06 98.38 -2,025.642,808.86 6,027,978.79 531,518.04 4.13 62.97 3_MWD+IFR2+MS+Sag (1) 3,842.86 50.57 243.04 2,927.09 67.13 -2,092.912,867.89 6,027,947.24 531,450.92 3.86 99.47 3_MWD+IFR2+MS+Sag (1) 3,938.19 51.34 236.16 2,987.18 29.69 -2,156.682,927.98 6,027,909.52 531,387.32 5.66 141.87 3_MWD+IFR2+MS+Sag (1) 4,033.62 54.43 232.37 3,044.77 -14.78 -2,218.402,985.57 6,027,864.78 531,325.81 4.53 191.10 3_MWD+IFR2+MS+Sag (1) 4,128.92 56.67 228.56 3,098.69 -64.81 -2,278.963,039.49 6,027,814.47 531,265.48 4.05 245.79 3_MWD+IFR2+MS+Sag (1) 4,223.67 59.81 225.64 3,148.57 -119.66 -2,337.943,089.37 6,027,759.37 531,206.76 4.22 305.16 3_MWD+IFR2+MS+Sag (1) 4,319.13 62.00 223.24 3,194.99 -179.22 -2,396.323,135.79 6,027,699.55 531,148.65 3.18 369.17 3_MWD+IFR2+MS+Sag (1) 4,414.68 62.36 220.07 3,239.59 -242.35 -2,452.473,180.39 6,027,636.17 531,092.79 2.96 436.57 3_MWD+IFR2+MS+Sag (1) 4,509.36 63.83 215.44 3,282.45 -309.09 -2,504.133,223.25 6,027,569.21 531,041.44 4.63 507.20 3_MWD+IFR2+MS+Sag (1) 4,604.57 62.99 211.22 3,325.08 -380.20 -2,550.903,265.88 6,027,497.90 530,994.99 4.06 581.80 3_MWD+IFR2+MS+Sag (1) 4,699.28 63.97 207.08 3,367.39 -454.20 -2,592.163,308.19 6,027,423.72 530,954.07 4.05 658.84 3_MWD+IFR2+MS+Sag (1) 4,795.18 64.90 202.64 3,408.79 -532.67 -2,628.503,349.59 6,027,345.10 530,918.09 4.29 739.96 3_MWD+IFR2+MS+Sag (1) 4,890.30 70.72 198.66 3,444.71 -615.05 -2,659.483,385.51 6,027,262.58 530,887.48 7.24 824.54 3_MWD+IFR2+MS+Sag (1) 4,986.07 72.86 196.22 3,474.64 -701.83 -2,686.733,415.44 6,027,175.69 530,860.63 3.29 913.21 3_MWD+IFR2+MS+Sag (1) 5,081.04 76.13 193.46 3,500.03 -790.28 -2,710.153,440.83 6,027,087.15 530,837.61 4.44 1,003.24 3_MWD+IFR2+MS+Sag (1) 3/9/2020 11:08:56AM COMPASS 5000.15 Build 91E Page 3 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt Moose Pad Halliburton Definitive Survey Report Well: Wellbore: MPU M-25i MPU M-25i Survey Calculation Method:Minimum Curvature MPU M-25 Actual RKB @ 59.20usft Design:MPU M-25i Database:NORTH US + CANADA MD Reference:MPU M-25 Actual RKB @ 59.20usft North Reference: Well MPU M-25i True MD (usft) Inc (°) Azi (°) +E/-W (usft) +N/-S (usft) Survey TVD (usft) TVDSS (usft) Map Northing (ft) Map Easting (ft) Vertical Section (ft) DLS (°/100')Survey Tool Name 5,176.39 79.49 189.35 3,520.17 -881.61 -2,728.553,460.97 6,026,995.74 530,819.62 5.49 1,095.74 3_MWD+IFR2+MS+Sag (1) 5,271.31 81.87 187.13 3,535.54 -974.29 -2,741.963,476.34 6,026,903.01 530,806.63 3.41 1,189.20 3_MWD+IFR2+MS+Sag (1) 5,366.51 84.07 183.82 3,547.19 -1,068.33 -2,750.973,487.99 6,026,808.94 530,798.05 4.15 1,283.66 3_MWD+IFR2+MS+Sag (1) 5,461.64 84.41 180.42 3,556.74 -1,162.90 -2,754.473,497.54 6,026,714.36 530,794.97 3.57 1,378.21 3_MWD+IFR2+MS+Sag (1) 5,556.59 85.01 178.44 3,565.50 -1,257.44 -2,753.533,506.30 6,026,619.84 530,796.34 2.17 1,472.37 3_MWD+IFR2+MS+Sag (1) 5,651.96 83.83 178.52 3,574.77 -1,352.32 -2,751.013,515.57 6,026,524.98 530,799.29 1.24 1,566.75 3_MWD+IFR2+MS+Sag (1) 5,747.44 84.08 179.00 3,584.83 -1,447.24 -2,748.963,525.63 6,026,430.08 530,801.77 0.56 1,661.21 3_MWD+IFR2+MS+Sag (1) 5,843.51 83.32 178.98 3,595.37 -1,542.72 -2,747.273,536.17 6,026,334.62 530,803.88 0.79 1,756.25 3_MWD+IFR2+MS+Sag (1) 5,939.21 86.23 179.47 3,604.08 -1,638.00 -2,745.993,544.88 6,026,239.35 530,805.60 3.08 1,851.13 3_MWD+IFR2+MS+Sag (1) 6,014.72 89.64 180.95 3,606.80 -1,713.45 -2,746.263,547.60 6,026,163.91 530,805.66 4.92 1,926.36 3_MWD+IFR2+MS+Sag (1) 6,106.18 89.52 180.78 3,607.47 -1,804.90 -2,747.643,548.27 6,026,072.47 530,804.69 0.23 2,017.63 3_MWD+IFR2+MS+Sag (2) 6,200.99 87.66 180.00 3,609.81 -1,899.67 -2,748.293,550.61 6,025,977.70 530,804.48 2.13 2,112.15 3_MWD+IFR2+MS+Sag (2) 6,296.74 87.17 179.62 3,614.13 -1,995.32 -2,747.973,554.93 6,025,882.06 530,805.23 0.65 2,207.48 3_MWD+IFR2+MS+Sag (2) 6,391.79 86.67 179.78 3,619.23 -2,090.23 -2,747.483,560.03 6,025,787.16 530,806.15 0.55 2,302.05 3_MWD+IFR2+MS+Sag (2) 6,486.58 88.22 180.64 3,623.46 -2,184.92 -2,747.823,564.26 6,025,692.48 530,806.23 1.87 2,396.47 3_MWD+IFR2+MS+Sag (2) 6,582.45 88.34 181.76 3,626.34 -2,280.73 -2,749.833,567.14 6,025,596.68 530,804.66 1.17 2,492.13 3_MWD+IFR2+MS+Sag (2) 6,677.65 89.46 182.02 3,628.16 -2,375.86 -2,752.973,568.96 6,025,501.55 530,801.95 1.21 2,587.21 3_MWD+IFR2+MS+Sag (2) 6,772.69 90.38 182.26 3,628.30 -2,470.83 -2,756.523,569.10 6,025,406.57 530,798.83 1.00 2,682.16 3_MWD+IFR2+MS+Sag (2) 6,867.75 92.86 182.41 3,625.61 -2,565.77 -2,760.393,566.41 6,025,311.62 530,795.38 2.61 2,777.10 3_MWD+IFR2+MS+Sag (2) 6,963.25 93.54 182.52 3,620.28 -2,661.03 -2,764.493,561.08 6,025,216.35 530,791.71 0.72 2,872.39 3_MWD+IFR2+MS+Sag (2) 7,058.34 92.48 182.45 3,615.28 -2,755.90 -2,768.613,556.08 6,025,121.48 530,788.02 1.12 2,967.29 3_MWD+IFR2+MS+Sag (2) 7,153.25 92.85 183.35 3,610.87 -2,850.58 -2,773.403,551.67 6,025,026.78 530,783.65 1.02 3,062.05 3_MWD+IFR2+MS+Sag (2) 7,247.90 92.54 182.15 3,606.42 -2,945.02 -2,777.943,547.22 6,024,932.34 530,779.54 1.31 3,156.55 3_MWD+IFR2+MS+Sag (2) 7,343.13 92.42 180.21 3,602.30 -3,040.13 -2,779.903,543.10 6,024,837.22 530,778.01 2.04 3,251.52 3_MWD+IFR2+MS+Sag (2) 7,438.73 91.74 179.53 3,598.83 -3,135.67 -2,779.683,539.63 6,024,741.70 530,778.66 1.01 3,346.74 3_MWD+IFR2+MS+Sag (2) 7,533.73 91.18 179.14 3,596.41 -3,230.63 -2,778.583,537.21 6,024,646.75 530,780.19 0.72 3,441.31 3_MWD+IFR2+MS+Sag (2) 7,628.99 89.45 178.99 3,595.89 -3,325.87 -2,777.033,536.69 6,024,551.53 530,782.18 1.82 3,536.13 3_MWD+IFR2+MS+Sag (2) 7,723.84 89.39 180.24 3,596.85 -3,420.71 -2,776.393,537.65 6,024,456.70 530,783.24 1.32 3,630.62 3_MWD+IFR2+MS+Sag (2) 7,819.42 90.32 180.64 3,597.09 -3,516.29 -2,777.123,537.89 6,024,361.13 530,782.94 1.06 3,725.95 3_MWD+IFR2+MS+Sag (2) 7,914.88 92.30 181.28 3,594.91 -3,611.71 -2,778.723,535.71 6,024,265.72 530,781.77 2.18 3,821.19 3_MWD+IFR2+MS+Sag (2) 8,007.73 91.18 182.15 3,592.09 -3,704.47 -2,781.503,532.89 6,024,172.95 530,779.41 1.53 3,913.88 3_MWD+IFR2+MS+Sag (2) 8,100.39 89.45 182.23 3,591.58 -3,797.06 -2,785.043,532.38 6,024,080.36 530,776.29 1.87 4,006.46 3_MWD+IFR2+MS+Sag (2) 8,199.00 89.64 182.76 3,592.36 -3,895.57 -2,789.333,533.16 6,023,981.84 530,772.44 0.57 4,105.00 3_MWD+IFR2+MS+Sag (2) 8,295.65 90.69 183.76 3,592.08 -3,992.06 -2,794.833,532.88 6,023,885.33 530,767.38 1.50 4,201.62 3_MWD+IFR2+MS+Sag (2) 8,390.91 87.97 183.93 3,593.20 -4,087.09 -2,801.213,534.00 6,023,790.28 530,761.42 2.86 4,296.86 3_MWD+IFR2+MS+Sag (2) 8,485.92 88.53 181.66 3,596.10 -4,181.94 -2,805.843,536.90 6,023,695.43 530,757.22 2.46 4,391.77 3_MWD+IFR2+MS+Sag (2) 8,580.96 91.19 180.90 3,596.33 -4,276.94 -2,807.973,537.13 6,023,600.42 530,755.53 2.91 4,486.65 3_MWD+IFR2+MS+Sag (2) 8,676.50 92.86 180.39 3,592.95 -4,372.41 -2,809.043,533.75 6,023,504.95 530,754.88 1.83 4,581.90 3_MWD+IFR2+MS+Sag (2) 8,772.12 92.91 179.61 3,588.14 -4,467.91 -2,809.043,528.94 6,023,409.47 530,755.31 0.82 4,677.10 3_MWD+IFR2+MS+Sag (2) 8,867.10 90.87 180.05 3,585.01 -4,562.83 -2,808.763,525.81 6,023,314.56 530,756.02 2.20 4,771.70 3_MWD+IFR2+MS+Sag (2) 3/9/2020 11:08:56AM COMPASS 5000.15 Build 91E Page 4 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt Moose Pad Halliburton Definitive Survey Report Well: Wellbore: MPU M-25i MPU M-25i Survey Calculation Method:Minimum Curvature MPU M-25 Actual RKB @ 59.20usft Design:MPU M-25i Database:NORTH US + CANADA MD Reference:MPU M-25 Actual RKB @ 59.20usft North Reference: Well MPU M-25i True MD (usft) Inc (°) Azi (°) +E/-W (usft) +N/-S (usft) Survey TVD (usft) TVDSS (usft) Map Northing (ft) Map Easting (ft) Vertical Section (ft) DLS (°/100')Survey Tool Name 8,962.23 87.04 181.09 3,586.74 -4,657.92 -2,809.713,527.54 6,023,219.47 530,755.51 4.17 4,866.56 3_MWD+IFR2+MS+Sag (2) 9,057.35 85.00 182.56 3,593.35 -4,752.76 -2,812.733,534.15 6,023,124.63 530,752.91 2.64 4,961.34 3_MWD+IFR2+MS+Sag (2) 9,152.51 86.24 185.08 3,600.61 -4,847.42 -2,819.053,541.41 6,023,029.95 530,747.02 2.94 5,056.20 3_MWD+IFR2+MS+Sag (2) 9,247.24 88.41 186.70 3,605.03 -4,941.54 -2,828.763,545.83 6,022,935.80 530,737.73 2.86 5,150.79 3_MWD+IFR2+MS+Sag (2) 9,341.38 91.56 188.43 3,605.06 -5,034.84 -2,841.153,545.86 6,022,842.45 530,725.77 3.82 5,244.79 3_MWD+IFR2+MS+Sag (2) 9,436.22 90.38 188.69 3,603.45 -5,128.61 -2,855.273,544.25 6,022,748.63 530,712.08 1.27 5,339.38 3_MWD+IFR2+MS+Sag (2) 9,531.79 90.32 186.88 3,602.87 -5,223.30 -2,868.213,543.67 6,022,653.90 530,699.56 1.89 5,434.79 3_MWD+IFR2+MS+Sag (2) 9,624.89 90.19 184.64 3,602.46 -5,315.92 -2,877.553,543.26 6,022,561.24 530,690.63 2.41 5,527.87 3_MWD+IFR2+MS+Sag (2) 9,721.58 89.70 184.87 3,602.55 -5,412.28 -2,885.573,543.35 6,022,464.86 530,683.06 0.56 5,624.56 3_MWD+IFR2+MS+Sag (2) 9,817.17 89.08 183.53 3,603.57 -5,507.60 -2,892.573,544.37 6,022,369.51 530,676.49 1.54 5,720.14 3_MWD+IFR2+MS+Sag (2) 9,912.38 88.40 183.22 3,605.66 -5,602.62 -2,898.173,546.46 6,022,274.48 530,671.31 0.78 5,815.30 3_MWD+IFR2+MS+Sag (2) 10,006.98 91.00 184.07 3,606.16 -5,697.02 -2,904.193,546.96 6,022,180.06 530,665.72 2.89 5,909.88 3_MWD+IFR2+MS+Sag (2) 10,102.70 93.47 183.51 3,602.42 -5,792.45 -2,910.513,543.22 6,022,084.61 530,659.83 2.65 6,005.51 3_MWD+IFR2+MS+Sag (2) 10,197.66 90.69 182.77 3,598.98 -5,887.20 -2,915.713,539.78 6,021,989.86 530,655.06 3.03 6,100.37 3_MWD+IFR2+MS+Sag (2) 10,292.29 89.88 183.42 3,598.51 -5,981.69 -2,920.813,539.31 6,021,895.35 530,650.38 1.10 6,194.97 3_MWD+IFR2+MS+Sag (2) 10,386.51 91.25 183.70 3,597.58 -6,075.72 -2,926.663,538.38 6,021,801.31 530,644.96 1.48 6,289.16 3_MWD+IFR2+MS+Sag (2) 10,481.97 91.68 184.69 3,595.14 -6,170.89 -2,933.643,535.94 6,021,706.11 530,638.41 1.13 6,384.59 3_MWD+IFR2+MS+Sag (2) 10,577.62 90.56 185.07 3,593.27 -6,266.17 -2,941.783,534.07 6,021,610.80 530,630.70 1.24 6,480.22 3_MWD+IFR2+MS+Sag (2) 10,672.87 93.04 185.29 3,590.27 -6,360.98 -2,950.373,531.07 6,021,515.97 530,622.53 2.61 6,575.41 3_MWD+IFR2+MS+Sag (2) 10,765.11 94.09 185.16 3,584.54 -6,452.66 -2,958.763,525.34 6,021,424.26 530,614.57 1.15 6,667.46 3_MWD+IFR2+MS+Sag (2) 10,860.84 92.17 184.65 3,579.31 -6,547.89 -2,966.933,520.11 6,021,329.00 530,606.82 2.07 6,763.04 3_MWD+IFR2+MS+Sag (2) 10,959.95 90.44 182.55 3,577.05 -6,646.77 -2,973.153,517.85 6,021,230.11 530,601.05 2.74 6,862.10 3_MWD+IFR2+MS+Sag (2) 11,055.51 90.32 181.34 3,576.42 -6,742.27 -2,976.393,517.22 6,021,134.60 530,598.24 1.27 6,957.56 3_MWD+IFR2+MS+Sag (2) 11,150.15 89.39 183.64 3,576.66 -6,836.81 -2,980.513,517.46 6,021,040.05 530,594.55 2.62 7,052.13 3_MWD+IFR2+MS+Sag (2) 11,245.43 89.27 184.44 3,577.77 -6,931.85 -2,987.223,518.57 6,020,944.99 530,588.27 0.85 7,147.40 3_MWD+IFR2+MS+Sag (2) 11,340.74 89.14 187.11 3,579.10 -7,026.66 -2,996.813,519.90 6,020,850.15 530,579.11 2.80 7,242.67 3_MWD+IFR2+MS+Sag (2) 11,434.31 88.34 188.29 3,581.16 -7,119.36 -3,009.343,521.96 6,020,757.40 530,567.00 1.52 7,336.07 3_MWD+IFR2+MS+Sag (2) 11,529.71 89.64 187.29 3,582.84 -7,213.86 -3,022.273,523.64 6,020,662.86 530,554.50 1.72 7,431.30 3_MWD+IFR2+MS+Sag (2) 11,625.04 89.27 185.31 3,583.74 -7,308.61 -3,032.733,524.54 6,020,568.07 530,544.46 2.11 7,526.58 3_MWD+IFR2+MS+Sag (2) 11,720.43 88.84 185.75 3,585.32 -7,403.54 -3,041.923,526.12 6,020,473.11 530,535.70 0.64 7,621.94 3_MWD+IFR2+MS+Sag (2) 11,815.00 88.90 184.43 3,587.18 -7,497.71 -3,050.313,527.98 6,020,378.91 530,527.74 1.40 7,716.49 3_MWD+IFR2+MS+Sag (2) 11,909.82 91.19 182.22 3,587.11 -7,592.36 -3,055.813,527.91 6,020,284.24 530,522.67 3.36 7,811.28 3_MWD+IFR2+MS+Sag (2) 12,005.38 91.99 180.54 3,584.46 -7,687.85 -3,058.113,525.26 6,020,188.75 530,520.80 1.95 7,906.65 3_MWD+IFR2+MS+Sag (2) 12,100.67 93.60 181.36 3,579.81 -7,783.01 -3,059.683,520.61 6,020,093.59 530,519.65 1.90 8,001.63 3_MWD+IFR2+MS+Sag (2) 12,195.99 94.21 181.68 3,573.32 -7,878.08 -3,062.213,514.12 6,019,998.53 530,517.56 0.72 8,096.60 3_MWD+IFR2+MS+Sag (2) 12,290.65 95.95 182.33 3,564.94 -7,972.30 -3,065.503,505.74 6,019,904.30 530,514.68 1.96 8,190.79 3_MWD+IFR2+MS+Sag (2) 12,386.41 94.15 181.95 3,556.51 -8,067.62 -3,069.073,497.31 6,019,808.97 530,511.55 1.92 8,286.09 3_MWD+IFR2+MS+Sag (2) 12,481.66 91.61 181.70 3,551.72 -8,162.70 -3,072.103,492.52 6,019,713.90 530,508.95 2.68 8,381.10 3_MWD+IFR2+MS+Sag (2) 12,576.66 91.12 181.08 3,549.46 -8,257.64 -3,074.403,490.26 6,019,618.95 530,507.08 0.83 8,475.93 3_MWD+IFR2+MS+Sag (2) 12,672.33 90.50 180.60 3,548.11 -8,353.29 -3,075.803,488.91 6,019,523.31 530,506.11 0.82 8,571.38 3_MWD+IFR2+MS+Sag (2) 3/9/2020 11:08:56AM COMPASS 5000.15 Build 91E Page 5 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt Moose Pad Halliburton Definitive Survey Report Well: Wellbore: MPU M-25i MPU M-25i Survey Calculation Method:Minimum Curvature MPU M-25 Actual RKB @ 59.20usft Design:MPU M-25i Database:NORTH US + CANADA MD Reference:MPU M-25 Actual RKB @ 59.20usft North Reference: Well MPU M-25i True MD (usft) Inc (°) Azi (°) +E/-W (usft) +N/-S (usft) Survey TVD (usft) TVDSS (usft) Map Northing (ft) Map Easting (ft) Vertical Section (ft) DLS (°/100')Survey Tool Name 12,767.58 89.45 180.27 3,548.15 -8,448.54 -3,076.523,488.95 6,019,428.07 530,505.81 1.16 8,666.39 3_MWD+IFR2+MS+Sag (2) 12,862.18 91.49 182.27 3,547.37 -8,543.10 -3,078.623,488.17 6,019,333.51 530,504.14 3.02 8,760.82 3_MWD+IFR2+MS+Sag (2) 12,958.07 92.85 184.50 3,543.74 -8,638.75 -3,084.283,484.54 6,019,237.85 530,498.92 2.72 8,856.61 3_MWD+IFR2+MS+Sag (2) 13,053.06 93.91 186.69 3,538.14 -8,733.11 -3,093.523,478.94 6,019,143.45 530,490.10 2.56 8,951.41 3_MWD+IFR2+MS+Sag (2) 13,147.79 90.31 187.15 3,534.65 -8,827.07 -3,104.923,475.45 6,019,049.45 530,479.12 3.83 9,045.98 3_MWD+IFR2+MS+Sag (2) 13,243.00 88.96 187.17 3,535.26 -8,921.53 -3,116.793,476.06 6,018,954.94 530,467.68 1.42 9,141.09 3_MWD+IFR2+MS+Sag (2) 13,338.21 91.99 190.14 3,534.47 -9,015.64 -3,131.113,475.27 6,018,860.78 530,453.79 4.46 9,236.03 3_MWD+IFR2+MS+Sag (2) 13,434.15 90.93 191.03 3,532.02 -9,109.91 -3,148.733,472.82 6,018,766.44 530,436.60 1.44 9,331.41 3_MWD+IFR2+MS+Sag (2) 13,528.44 89.82 191.10 3,531.41 -9,202.44 -3,166.833,472.21 6,018,673.84 530,418.92 1.18 9,425.09 3_MWD+IFR2+MS+Sag (2) 13,623.87 91.68 192.12 3,530.16 -9,295.91 -3,186.033,470.96 6,018,580.29 530,400.14 2.22 9,519.78 3_MWD+IFR2+MS+Sag (2) 13,718.78 92.36 190.17 3,526.81 -9,388.97 -3,204.363,467.61 6,018,487.17 530,382.23 2.17 9,614.00 3_MWD+IFR2+MS+Sag (2) 13,814.41 91.31 185.74 3,523.75 -9,483.60 -3,217.593,464.55 6,018,392.48 530,369.43 4.76 9,709.39 3_MWD+IFR2+MS+Sag (2) 13,909.42 90.50 184.14 3,522.25 -9,578.24 -3,225.773,463.05 6,018,297.81 530,361.68 1.89 9,804.38 3_MWD+IFR2+MS+Sag (2) 14,000.72 91.31 184.96 3,520.81 -9,669.24 -3,233.013,461.61 6,018,206.79 530,354.85 1.26 9,895.67 3_MWD+IFR2+MS+Sag (2) 14,070.00 91.31 184.96 3,519.22 -9,738.25 -3,239.003,460.02 6,018,137.77 530,349.17 0.00 9,964.93 PROJECTED to TD Approved By:Checked By:Date: 3/9/2020 11:08:56AM COMPASS 5000.15 Build 91E Page 6 Chelsea Wright Digitally signed by Chelsea Wright Date: 2020.03.09 08:17:04 -08'00' Benjamin Hand Digitally signed by Benjamin Hand Date: 2020.03.09 07:58:51 -09'00' TD Shoe Depth: PBTD: Jts. 1 2 1 1 1 89 1 1 1 59 1 X Yes No X Yes No 30 Fluid Description: Liner hanger Info (Make/Model):Liner top Packer?: Yes No Liner hanger test pressure:X Yes No Centralizer Placement: Preflush (Spacer) Type: Density (ppg) Volume pumped (BBLs) Lead Slurry Type:Sacks: Yield: Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Tail Slurry Type:Sacks: Yield: Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Post Flush (Spacer) Type: Density (ppg)Rate (bpm):Volume: Displacement: Type:Density (ppg)Rate (bpm): Volume (actual / calculated): FCP (psi): Pump used for disp: Yes X No Casing Rotated?X Yes No Reciprocated?X Yes No % Returns during job Cement returns to surface?X Yes No Spacer returns?X Yes No Vol to Surf: Cement In Place At: Date: Estimated TOC: Method Used To Determine TOC: Preflush (Spacer) Type: Density (ppg) Volume pumped (BBLs) Lead Slurry Type:Sacks: Yield: Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Tail Slurry Type:Sacks: Yield: Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Post Flush (Spacer) Type: Density (ppg)Rate (bpm):Volume: Displacement: Type:Density (ppg)Rate (bpm): Volume (actual / calculated): FCP (psi): Pump used for disp: X Yes No Casing Rotated? Yes X No Reciprocated? Yes X No % Returns during job Cement returns to surface?X Yes No Spacer returns?X Yes No Vol to Surf: Cement In Place At: Date: Estimated TOC: Method Used To Determine TOC: Post Job Calculations: Calculated Cmt Vol @ 0% excess: Total Volume cmt Pumped: Cmt returned to surface: Calculated cement left in wellbore: OH volume Calculated: OH volume actual: Actual % Washout: Casing (Or Liner) Detail Shoe Cut Joint of Casing 10 3/4 50.0 363.8 7.69337.8SECOND STAGERig 22:55 Returns to surface Rotate Csg Recip Csg Ft. Min.PPG9.2 Shoe @ 6047 FC @ Top of Liner5,964.75 Floats Held 378 634.6 240 394.6 Spud Mud CASING RECORD County State Alaska Supv.S. Sunderland /J. Vanderpool Hilcorp Energy Company CASING & CEMENTING REPORT Lease & Well No.MP M-25 Date Run 28-Feb-20 Setting Depths Component Size Wt.Grade THD Make Length Bottom Top TXP BTC-SR Innovex 1.59 6,047.00 6,045.41 19.77 51.41 31.649 5/8 40.0 L-80 TXP BTC-SR Tenaris Csg Wt. On Hook:105,000 Type Float Collar:Innovex No. Hrs to Run:17 9.4 6 1180 10 10.7 312.8 4.1 100 521 Bump Plug?FIRST STAGE10Tuned Spacer 60 15.8 480 5 9.2 6 161.1/162.6 357.7/349.7 521 40 Rig 15.8 82 Bump press Returns to surface Bump Plug? 12:42 2/29/2020 2,401 2401.39 6,047.006,054.00 5,900.00 CEMENTING REPORT Csg Wt. On Slips:120,000 Spud Mud Tuned Spacer 400 4.41 Stage Collar @ 60 Bump press 100 200 ES Cementer Closure OK 55.8 12 184 Type of Shoe:Innovex Casing Crew:Doyon www.wellez.net WellEz Information Management LLC ver_04818br 4 Perm L Type Two 9-5/8"x12-1/4" centralizers w/ 4 stop rings on shoe joint, one centralizer w/ 2 stop rings on jt. #2, 3 & 4. 9-5/8"x12-1/4" centralizer on every joint #6 to 26 then every other joint #27 to 51 Casing 9 5/8 40.0 L-80 TXP BTC-SR Tenaris 79.36 6,045.41 5,966.05 Float Collar 10 3/4 40.0 TXP BTC-SR Innovex 1.30 5,966.05 5,964.75 Casing 9 5/8 50.0 L-80 TXP BTC-SR Tenaris 39.96 5,964.75 5,924.79 Baffle Adapter 10 3/4 40.0 TXP BTC-SR HES 1.47 5,924.79 5,923.32 Casing 9 5/8 40.0 L-80 TXP BTC-SR Tenaris 3,501.27 5,923.32 2,422.05 Pup Joint 9 5/8 40.0 L-80 TXP BTC-SR Tenaris 17.84 2,422.05 2,404.21 ESC II 10 3/4 40.0 TXP BTC-SR HES 2.82 2,404.21 2,401.39 Pup Joint 9 5/8 40.0 L-80 TXP BTC-SR Tenaris 16.14 2,401.39 2,385.25 Casing 9 5/8 40.0 L-80 TXP BTC-SR Tenaris 2,333.84 2,385.25 51.41 Lead Cement 440 2.35 Tail Cement 400 1.16 4.5 Tail Cement 270 1.17 2/29/2020 37 Spud Mud ESC II 10 3/4 40.0 TXP BTC-SR HES 2.82 2,404.21 2,401.39 -did not bump plug.. dropped bomb to open ES gls CASING AND LEAK-OFF FRACTURE TESTS Well Name:MPU M-25 Date:3/2/2020 Csg Size/Wt/Grade:9.625"40#, L-80 Supervisor:Sunderland/ Vanderpool Csg Setting Depth:6047 TMD 3607 TVD Mud Weight:9.1 ppg LOT / FIT Press =544 psi LOT / FIT =12.00 ppg Hole Depth =6054 md Fluid Pumped=1.0 Bbls Volume Back =1.0 bbls Estimated Pump Output:0.101 Barrels/Stroke LOT / FIT DATA CASING TEST DATA Enter Strokes Enter Pressure Enter Strokes Enter Pressure HH er e HH er e HH er e HH er e ->00 ->00 ->285 ->5 160 ->4 180 ->10 317 ->6 272 ->15 539 ->8 405 ->20 722 ->10 486 ->25 961 ->12 570 ->30 1180 -> ->35 1496 -> ->40 1776 -> ->45 2132 -> ->50 2392 -> ->55 2632 -> -> -> -> Enter Holding Enter Holding Enter Holding Enter Holding Time Here Pressure Here Time Here Pressure Here ->0 ->0 2632 ->1 556 ->5 2620 ->2 542 ->10 2610 ->3 532 ->15 2605 ->4 523 ->20 2600 ->5 518 ->25 2600 ->6 514 ->30 2600 ->7 511 ->35 2600 ->8 504 -> ->9 504 -> ->10 500 -> ->11 -> ->12 -> ->13 -> ->14 ->15 ->16 NOTE: FIT data for Schrader Bluff Injectors now included in 10-407 (gls 4/9/20) 0 2 4 6 8 10 12 0 5 10 15 20 25 30 35 40 45 50 55 0 100 200 300 400 500 600 700 800 900 1000 1100 1200 1300 1400 1500 1600 1700 1800 1900 2000 2100 2200 2300 2400 2500 2600 2700 2800 2900 3000 0 102030405060Pressure (psi)Strokes (# of) LOT / FIT DATA CASING TEST DATA 556542532523518514511504504500 2632 2620 2610 2605 2600 2600 2600 2600 0 100 200 300 400 500 600 700 800 900 1000 1100 1200 1300 1400 1500 1600 1700 1800 1900 2000 2100 2200 2300 2400 2500 2600 2700 2800 2900 3000 0 5 10 15 20 25 30 35Pressure (psi)Time (Minutes) LOT / FIT DATA CASING TEST DATA akHkrLLC DATE 03/23/2020 22 00 16 Debra Oudean Hilcorp Alaska, LLC GeoTech 3800 Centerpoint Drive, Suite 1400 3 2 2 5 3 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: doudean@hilcorp.com To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Ste 100 Anchorage, AK 99501 MPU M-25 (220-016) Halliburton LWD FINAL 9 MAR 2020 M-25 _Log Viewers 3/23/2020 9;64 ANE File folder CGM 3/Z3./2020 9:56 AM Filefolder Definitive Survey 3/23/2020 9:56 AM File folder EMF 3/Z3/2020 9:56 AM Fife folder LAS 3/23/20209;57AM Filefolder PDF 3/23/20209:57 AM Filefolder TIFF 3/23f20209:57AM File folder Please include current contact information if different from above. RECEIVED MAR 2 5 2020 AOGCC Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 Received By: Date: WZ0 THE STATE °'ALASKA GOVERNOR MIKE DUNLEAVY Monty Myers Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Milne Point Field, Schrader Bluff Oil Pool, MPU M-25 Hilcorp Alaska, LLC Permit to Drill Number: 220-016 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.olaska.gov Surface Location: 5039' FSL, 621' FEL, SEC. 14, T13N, R9E, UM, AK Bottomhole Location: 719' FSL, 1448' FWL, SEC. 23, T13N, R9E, UM, AK Dear Mr. Myers: Enclosed is the approved application for the permit to drill the above referenced service well. Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Price Chair DATED this \') day of February, 2020. RECEIVED STATE OF ALASKA AL„61KA OIL AND GAS CONSERVATION COMMISSION FEB 0 5 2020 PERMIT TO DRILL 20 AAC 25.005 .� 1 a. Type of Work: 1b. Proposed Well Class: Exploratory - Gas ❑ Service - WAG ❑ Service - Disp ❑ 1c. Spk. fyA#wffl&§Xkgosed for: Drill Q Lateral ❑ Stratigraphic Test ❑ Development - Oil ❑ Service - Winj ❑Q i Single Zone Coalbed Gas ❑ Gas Hydrates ❑ Redrill ❑ Reentry ❑ Exploratory - Oil ❑ Development - Gas ❑ Service - Supply ❑ Multiple Zone ❑ Geothermal ❑ Shale Gas ❑ 2. Operator Name: 5. Bond: Blanket ❑✓ Single Well ❑ 11. Well Name and Number: Hilcorp Alaska, LLC Bond No. 022224484 MPU M-25 3. Address: 6. Proposed Depth: 12. Field/Pool(s): 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 MD: 13,916' TVD: 3,479' Milne Point Unit Schrader Bluff Oil Pool 4a. Location of Well (Governmental Section): 7. Property Designation: Surface: 5039' FSL, 621' FEL, Sec 14, T13N, R9E, UM, AK ADL025514 0 Sq N b Top of Productive Horizon: 8. DNR Approval Number: 13. Approximate Spud Date: 1741' FNL, 1916' FWL, Sec 14, T13N, R9E, UM, AK LONS 16-004 2/21/2020 9. Acres in Property: 14. Distance to Nearest Property: Total Depth: 719' FSL, 1448' FWL, Sec 23, T13N, R9E, UM, AK 2560 720' to nearest unit boundary 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 58.9' 15. Distance to Nearest Well Open Surface: x-533543 y- 6027889 Zone -4 GL / BF Elevation above MSL (ft): 25.2' to Same Pool: 800' to MPU M-24 16. Deviated wells: Kickoff depth: 500 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 91 degrees Downhole: 1574 Surface: 1215 18. Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks Hole Casing Weight Grade Coupling Length MD TVD MD TVD (including stage data) Cond 20" - X52 Weld 114' Surface Surface 114' 114' -270 ft3 Stg 1 - L - 898 ft3 / T - 458 ft3 12-1/4" 9-5/8" 40# L-80 TXP 5,705' Surface Surface 5,705' 3,574' Stg2-L-1937ft3/T-314ft3 8-1/2" 4-1/2" 1 13.5# L-80 Hyd 625 8,361' 5,555' 3,560' 13,916' 3,479' Cementless Injection Liner ICDs Tieback 1 3-1/2" 1 9 1 L-80 I EUE8RD1 5,555 1 urface I urface 1 5,555' 3,560' 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 0 20. Attachments: Property Plat ❑ BOP Sketch Drilling Program Time v. Depth Plot ❑ ❑ ❑ Shallow Hazard Analysis ❑ Diverter Sketch Seabed Report Drilling Fluid Program 20 AAC 25.050 requirements 21. Verbal Approval: Commission Representative: Date 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 hiIcor .Com Authorized Title: Drilling Manager Contact Phone: 777-8395 Authorized Signature: Date: . • Zp Z o Commission Use Only Permit to Drill JAPI Number: Permit Approv I See cover letter for other Number: _0 50 6 — Q0_0C) Date: D requirements. r ,� 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: LJv Other: -f , 00 p J y 8 b 0 I �S. F- Samples req'd: Yes ❑ No [g Mud log req'd: Yes ❑ No [[� V 0 o r� H2S measures: Yes ❑ Nov Directional svy req'd: Yes 2Z Ela SCS v S� ,�n `' S Spacing exception req'd: Yes ❑ No [�) Inclination -only svy req'd: Yes ❑ Flo [� Post initial injection MIT req'd: Yes Lrq-,/No ❑ APPROVED BY :?,.,/ +� Approved by: COMMISSIONER THE COMMISSION Date: SubmitFN AL Form 10-401 Revis d 5/ o17 This permit is valid for 24 months from t f approval pe 0 AAC 25.005(8) Attach pet n 2 14- 4:140 KUPARUK RIVER UNIT 1-1 M-2}' i a26 M=45 �p07 I 32-14 ,8 -14A II y I d I� I Ittl� jl`� I PETR V4Q02012'.12:23 PM M HILCORP ALASKA LLC I MILNE POINT FIELD I AOR MAP M-25 Injector (Proposed) 0 1 000 2 000 FEET WELL SYMBOLS • Active Oil MJ Well (Water Flood) X P&A Oil SWduD mr Location P— Producer Location REMARKS Well Symbols at top of Schrader Bluff OA Sand Black dash circle = 1320' radius from OA sand in heel and toe of proposed M-25 drill well February 4, 2020 N logy In V Ul O co N lD w rn to Q1 O O 00 00 N m O Ul O N l0 w rn In V O O � D — � � m N N r r rn .A In L/I n n 3 - Di CL v Ln CDD ((D C o O_ O O_ N n n o rn D o 00 0 o o n p W O -� w w DO Ln V 'a G O Iq O v N n Ln m �i- c m M o Cu 0 n (D n M j -O rt o n V) c W (D 3 0 n n j 'a rD (D o n S O 0 v 'O O Q (D (D (D 0 D 00 -a �o (D (D 3 3 N O O O 3 (D (D - n rr n r+ � O O O y 3 3 = N (A Q O O 3 O O q ;; Hilcorp Alaska, LLC Milne Point Unit (MPU) M-25 Drilling Program Version 1 2/5/2020 Table of Contents 1.0 Well Summary.................................................................................................................................2 2.0 Management of Change Information............................................................................................3 3.0 Tubular Program: ........................................................................................................................... 4 4.0 Drill Pipe Information: ................................................................................................................... 4 5.0 Internal Reporting Requirements..................................................................................................5 6.0 Planned Wellbore Schematic..........................................................................................................6 7.0 Drilling / Completion Summary.....................................................................................................7 8.0 Mandatory Regulatory Compliance / Notifications.....................................................................8 9.0 RU and Preparatory Work...........................................................................................................10 10.0 NU 21-1/4" 2M Diverter System..................................................................................................11 11.0 Drill 12-1/4" Hole Section.............................................................................................................13 12.0 Run 9-5/8" Surface Casing...........................................................................................................16 13.0 Cement 9-5/8" Surface Casing.....................................................................................................21 14.0 BOP NU and Test..........................................................................................................................26 15.0 Drill 8-1/2" Hole Section...............................................................................................................27 16.0 Run 4-1/2" Injection Liner (Lower Completion)........................................................................32 17.0 Run 3-1/2" Tubing (Upper Completion).....................................................................................36 18.0 Doyon 14 Diverter Schematic.......................................................................................................38 19.0 Doyon 14 BOP Schematic.............................................................................................................39 20.0 Wellhead Schematic......................................................................................................................40 21.0 Days Vs Depth................................................................................................................................41 22.0 Formation Tops & Information...................................................................................................42 23.0 Anticipated Drilling Hazards.......................................................................................................43 24.0 Doyon 14 Layout............................................................................................................................46 25.0 FIT Procedure................................................................................................................................47 26.0 Doyon 14 Choke Manifold Schematic..........................................................................................48 27.0 Casing Design.................................................................................................................................49 28.0 8-1/2" Hole Section MASP............................................................................................................50 29.0 Spider Plot (NAD 27) (Governmental Sections).........................................................................51 30.0 Surface Plat (As Built) (NAD 27).................................................................................................52 31.0 Schrader Bluff OA Sand Offset MW vs TVD Chart..................................................................53 Hilcox Energy ComP�Y 1.0 Well Summary Milne Point Unit M-25 SB Injector Drilling Procedure Well MPU M-25 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 13,915' MD / 3,478' TVD PBTD, MD / TVD 13,905' MD / 3,478' TVD Surface Location (Governmental) 5039' FSL, 621' FEL, Sec 14, T13N, R9E, UM, AK Surface Location (NAD 27) X= 533,543 Y= 6,027,889 Top of Productive Horizon (Governmental) 1741' FNL, 1916' FWL, See 14, TON, R9E, UM, AK TPH Location (NAD 27) X= 530,809 Y= 6,026,377 BHL (Governmental) 719' FSL, 1448' FWL, Sec 23, T13N, R9E, UM, AK BHL (NAD 27) X= 530,384 Y=6,018,277 AFE Number 1915944M (D,C,F) AFE Drilling Days 19 days AFE Completion Das 4 days AFE Drilling Amount $4,227,470 AFE Completion Amount $1,585,308 ✓ AFE Facility Amount $391,000 Maximum Anticipated Pressure (Surface) 1,215 psig Maximum Anticipated Pressure (Downhole/Reservoir) 1,574 psig Work String 5" 19.54 S-135 DS -50 & NC 50 KB Elevation above MSL: 33.7 ft + 25.1 ft = 58.8 ft GL Elevation above MSL: 25.1 ft BOP Equipment 13-5/8" x 5M Annular, (3) each 13-5/8" x 5M Rams Page 2 Milne Point Unit M-25 SB Injector Hilco Drilling Procedure EW 2.0 Management of Change Information 14 Hilcorp Alaska, LLC Hilcorp Changes to Approved Permit to Drill Date: 215/2020 Subject: Changes to Approved Permit to Drill for MPU M-25 File #: MPU M-25 Drilling and Completion Program Any modifications to MPU M-25 Drilling & Completion Program will be documented and approved below. Changes to an approved APD will be approved in advance to the AGGCC. Approval] Drilling Manager Prepared: Drilling Engineer Page 3 re Date Date 3.0 Tubular Program: Milne Point Unit M-25 SB Injector Drilling Procedure Hole Section OD (in) ID (in) Drift (in) Conn OD , (in) Wt 0/ft)(psi) Grade Conn Burst I Collapse (psi) Tension (k -lbs Cond 20" 19.25" - - - X-52 Weld Min Max(k-lbs) 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" 3.960" 3.795" 4.714" 13.5 L-80 H625 9,020 8,540 279 Tubing 3-1/2" 2.992" 2.867" 4.500" 9.3 L-80 EUE 8RD 9,289 7,399 163 4.0 Drill Pipe Information: Hole OD ID (in) TJ ID TJ OD Wt Grade Conn M/U M/U Tension Section in in in(ft/ft) Min Max(k-lbs) Surface & 5" 4.276" 3.25" 6.625" 19.5 5-135 GPDS50 36,100 43,100 560klb Production 5" 1 4.276" 1 3.25" 1 6.625" 19.5 S-135 NC50 31,032 34,136 560klb All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery). Page 4 5.0 Internal Reporting Requirements Milne Point Unit M-25 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 pmazzolinighilcoM.com, mmyers c(1)e,hilcorp, jengel(2hilcorp.com and cdinger@hilcorp.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 e,hilcorp,com jengel(cr�,hilcorp.com and cdingerghilcorp.com 5.6 Casing and Cement report • Send casing and cement report for each string of casing to mm ersghilcorp.com jeng_el@hilcorp.com and cding_er@hilcorp.com 5.7 Hilcorp Milne Point Contact List: Title Name Work Phone Cell Phone Email Drilling Manager Monty Myers 907.777.8431 907.538.1168 mmyers@hilcorp.com Drilling Engineer Joe Engel 907.777.8395 805.235.6265 jengel@hilcorp.com Completion Engineer Ian Toomey 907.777.8434 907.903-3987 itoomey@hilcorp.com Geologist Kevin Eastham 907.777.8316 907.360.5087 keastham@hilcorp.com Reservoir Engineer Reid Edwards 907.777.8421 907.250.5081 reedwards@hilcorp.com Drilling Env. Coordinator Keegan Fleming 907.777.8477 907.350.9439 kfleming@hilcorp.com EHS Manager Carl Jones 907.777.8327 907.382.4336 cajones@hilcorp.com Drilling Tech Cody Dinger 907.777.8389 509.768.8196 cdinger@hilcorp.corn Page 5 Hilcox Enema ComP�➢ Milne Point Unit M-25 SB Injector Drilling Procedure 6.0 Planned Wellbore Schematic W44.1- yh� �14pw Milne Paint Unit Well: MPU M-25 Proposed Schematic PTD: TBD API: TBD O:g KB Sev: S89/GL 58f.: 25Z TD=13,91' IhiJ /TD=3,XVlTVq PBTD=13,1-115' lIVq /P5M=3,4v1a(7VC{ Page 6 ------- ----- ----- -- -- ------ -- - --- ------------- ---- TREE &WELLHEAD Tree I Curneron3lA'SMw14-ltlV5MCarmronWng Wellhead I Cameron 11'5K x4Ul;JWJt bottom wJ l2l 2-1J16" SK cuts -----------------------------W6-Li----------------------------------------- OPEN HOLE /CEMENT DETAIL 42" 1270 K3 12-1/4" Stg 1 -Lead 896 Ft3 /Tail 4S8 Ft3 S%2 -Lead 1937 R3 / Tail 314 ft3 6-1/2" 1 C#WCOOM In'e[tion liner in 8-lIY' hole •----------------------------------------------------------------------------------------- CASING DETAIL Side Type V.V Grade/ Conn Drift ID Top Ban BPF 20"x34" Condutwrlinsulatedl 215.5/X-S2/1Nekl N/A Surface 114' NIA 9-5/8" Surface 40/L-90ITV &679" Surface 5,705' 1 A7M 4-112" Liner 1351 L IM J 62S 3.795" 5,555' 13.916' 1 0.0149 TUBING DETAIL 3- Tutrin 9.3 L -8o i rug 8RD 1 2.867' 1 Surf I5 555' OA870 WELL INCLINATION DETAIL KOP 0 Sur iloleAn a@XN=TBD' i We An& & Liner Top = T8V Max Hot An81e = T80' Depth Depth ICE)/Swell Packer Detail MD T%M 760 ----------------------------------------- GENERAL WELL INK) APIR- TBD Completed bV DoVon 14-TBO JEWELRY DETAIL No Top NID Item ID Upper Completion TBO 3-1/2' X Nipple [2.613' Parkin g Bore► 2.613" 2 T80 3-IJ2" XN Nipvhe, 2.813" Packing Bore, 2.75' ND -Go, w/8) 1C 2.7WL' TBD 3-1%2' Gauge Mandrel SGMFXPQG wJ 31' %Vire 2.992" 4 TBO 8.25' No Gs Lacater Sub 12.76' off N of 6.170" T8D 7.375" Tieback above the SLZXP Liner Tcp Packer 6.1h1" Lower Completion 6 15,555' 7` x 9-518' SMP Liner Top Packer with 7.38' Seal Bare 7 13,916 Shoe Depth Depth ICE)/Swell Packer Detail MD T%M 760 ----------------------------------------- GENERAL WELL INK) APIR- TBD Completed bV DoVon 14-TBO Milne Point Unit M-25 SB Injector Hilco Drilling Procedure �� E . 7.0 Drilling / Completion Summary MPU M-25 is a grassroots injector planned to be drilled in the Schrader Bluff OA sand. M-25 is part of a multi well program targeting the Schrader Bluff sand on M -Pad. The directional plan is a catenary well path build, 12-1/4" hole with 9-5/8" surface casing set into the top of the Schrader Bluff OA sand. An 8-1/2" 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 February 21, 2020, pending rig schedule. Surface casing will be run to 5,704' MD / 3,573' TVD and cemented to surface via a 2 stage primary cement job. Cement returns to surface will confirm TOC at surface. If cement returns to surface are not observed, necessary remedial action will then be discussed with AOGCC authorities. All cuttings & mud generated during drilling operations will be hauled to the Milne Point `B" pad G&I facility. General sequence of operations: 1. MIRU Doyon 14 to well site 2. NU & Test 21-1/4" Diverter and 16" diverter line 3. Drill 12-1/4" hole to TD of surface hole section. Run and cement 9-5/8" surface casing 4. ND diverter, NU & test 13-5/8" x 5M BOP. Install MPD Riser 5. Drill 8-1/2" lateral to well TD. Run 4-1/2" injection liner. 6. Run 3-1/2" tubing. 7. ND BOP, NU Tree, RDMO. Reservoir Evaluation Plan: 1. Surface hole: No mud logging. On Site geologist. LWD: GR + Res 2. Production Hole: No mud logging. On site geologist. LWD: GR + ADR (For geo-steering) Page 7 Hilcorp Milne Point Unit M-25 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. • BON shall be tested at (2) week intervals during the drilling and completion of MPU M-25. Ensure to provide AOGCC 24 hrs notice prior to testing BOPS. • The initial test of BOP equipment will be to 250/3,000 psi & subsequent tests of the BOP equipment will be to 250/3,000 psi for 5/5 min (annular to 50% rated WP, 2,500 psi on the high test for initial and subsequent tests). Confirm that these test pressures match those specified on the APD. • 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-25 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 • 13-5/8" x 5M Hydril MPL Double Gate Initial Test: 250/3,000 o Blind ram in btm cavity • Mud cross w/ 3" x 5M side outlets 8-1/2" 0 13-5/8" x 5M Hydril MPL Single ram • 3-1/8" x 5M Choke Line Subsequent Tests: • 3-1/8" x 5M Kill line 250/3,000 • 3-1/8" x 5M Choke manifold • Standpipe, floor valves, etc Primary closing unit: NL Shaffer, 6 station, 3,000 psi, 180 gallon accumulator unit. Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is a 30:1 air pump, and emergency pressure is provided by bottled nitrogen. The remote closing operator panels are located in the doghouse and on accumulator unit. Required AOGCC Notifications: • 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: iim.reizg@alaska.gov Guy Schwartz / Petroleum Engineer / (0): 907-793-1226 / (C): 907-301-4533 / Email: guy. schwartzgalaska.gov Victoria Loepp / Petroleum Engineer / (0): 907-793-1247 / Email: Victoria.loepp(a,alaska.gov Mel Rixse / Petroleum Engineer / (0): 907-793-1231 / (C): 907-223-3605 / Email: melvin.rixse(2alaska.gov Primary Contact for Opportunity to witness: AOGCC.Inspectorsgalaska.gov Test/Inspection notification standardization format: http://doa.alaska.gov/ogc/forms/TestWitnessNotifhtml Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) Page 9 Milne Point Unit M-25 SB Injector Hilco Drilling Procedure eneW c� 9.0 RU and Preparatory Work 9.1 M-25 will utilize a newly set 20" conductor on M -Pad. Ensure to review attached surface plat and make sure rig is over appropriate conductor. 9.2 Ensure PTD and drilling program are posted in the rig office and on the rig floor. 9.3 Install landing ring. 9.4 Insure (2) 4" nipples are installed on opposite sides of the conductor with ball valves on each. 9.5 Level pad and ensure enough room for layout of rig footprint and RU. 9.6 Rig mat footprint of rig. 9.7 MIRU Doyon 14. Ensure rig is centered over conductor to prevent any wear to BOPE or wellhead. 9.8 Mud loggers WILL NOT be used on either hole section. 9.9 Mix spud mud for 12-1/4" surface hole section. Ensure mud temperatures are cool (<80°F). 9.10 Ensure 6" liners in mud pumps. • Continental EMSCO FB -1600 mud pumps are rated at 4,665 psi, 462 gpm @ 110 spm @ 95% volumetric efficiency. Page 10 Hilcorp Energy ComP�Y 10.0 NU 21-1/4" 2M Diverter System !Milne Point Unit M-25 SB Injector Drilling Procedure 10.1 /U 21-1/4" Hydril MSP 2M Diverter System (Diverter Schematic attached to program). • NU 16-3/4" 3M x 21-1/4" 2M DSA on 16-3/4" 3M wellhead. • NU 21-1/4" diverter "T". • Knife gate, 16" diverter line. • Ensure diverter RU complies with AOGCC reg 20.AAC.25.035(C). • Diverter line must be 75 ft from nearest isnition 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. Page 11 Milne Point Unit M-25 SB Injector HilcoT+T�+1 Drilling Procedure Enew Company 10.4 Rig & Diverter Orientation: • May change on location 1 ■ M-16 M-58 ■ M -z2 ■ ■ M-17 M-23 ■ ■ M-18 M-25 l ■ ■ �ht-19 r M-26 M-04 ■ M-03 ■ ■ M -Q5 ■ M -o6 I 75' Radius Clear of ignition Sources Diaerter Line MPU M -Pad *drawing Not To Scale Page 12 11.0 11.2 Milne Point Unit M-25 SB Injector Drilling Procedure Drill 12-1/4" Hole Section PU 12-1/4" directional drilling assembly: • Ensure BHA components have been inspected previously. • Drift and caliper all components before MU. 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. 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 j ets hooked up and be ready to j et 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 ppg 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 I/ Milne Point Unit M-25 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 2,100-2,400' 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 and added 1-1.5ppb 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. • AC: There are no actual offset wells with a clearance factors <1.0 in the surface hole section • M-51 — Slot 12 is a planned well and does not exist yet 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 (ppg) Surface — Base Permafrost 8.9+ Base Permafrost - TD 9. (For Hydrates if need based on offset wells) W can be cut once —500' below hydrate zone o g Mvl= • 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) BARACARBsBAROFIBRE/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 1 Milne Point Unit M-25 SB Injector Drilling Procedure • Casing Running: Reduce system YP with DESCO as required for running casing as allowed (do not jeopardize hole conditions). Run casing carefully to minimize surge and swab pressures. Reduce the system rheology once the casing is landed to a YP < 20 (check with the cementers to see what YP value they have targeted). System Type: 8.8 - 9.2 ppg Pre -Hydrated Aquagel/freshwater spud mud Properties: Section ensi Viscosity Plastic Viscosi I Yield Point API FL 1 pH Tem Surface 1/8.8-9._8_ 75-175 1 20-40 1 25-45 <10 1 8.5-9.0 50 System Formulation: Gel + FW spud mud Product- Surface hole Size Pkg ppb or (% liquids) M -I Gel 50 lb sx 25 Soda Ash 50 lb sx 0.25 Pol Pac Supreme UL, 50 lb sx 0.08 Caustic Soda 50 lb sx 0.1 SCREENCLEEN 1 55 1 gal dm 1 0.5 11.5 At TD; PU 2-3 stands off bottom, CBU, pump tandem sweeps and drop viscosity. 11.6 RIH to bottom, proceed to BROOH to HWDP • Pump at full drill rate (400-600 gpm), and maximize rotation. • Pull slowly, 5 — 10 ft per 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. Q� Page 15 0 12.0 Run 9-5/8" Surface Casing 12.1 RU and pull wearbushing. Milne Point Unit M-25 SB Injector Drilling Procedure 12.2 RU Doyon 9-5/8" casing running equipment (CRT & Tongs) • Ensure 9-5/8" TXP x DS50 XO on rig floor and MU to FOSV. • Use BOL 2000 thread compound. Dope pin end only with paint brush. • RU of CRT if hole conditions require. • RU a fill up tool to fill casing while running if the CRT is not used. • Ensure all casing has been drifted to 8.750" on the location prior to running. • Be sure to count the total 4 of joints on the location before running. • Keep hole covered while RU casing tools. • Record OD's, ID's, lengths, SN's of all components with vendor & model info. 12.3 PU shoe joint, visually verify no debris inside joint. 12.4 Continue MU & thread lockiniz 120' shoe track assemblv consisting of - 9 -5/8" Float Shoe 1 joint — 9-5/8" TXP, 2 Centralizers 10' from each end w/ stop rings 1 joint — 9-5/8" TXP, 1 Centralizer mid joint w/ stop ring 9-5/8" Float Collar w/ Stage Cementer Bypass Baffle `Top Hat' 1 joint — 9-5/8" TXP, 1 Centralizer mid joint with stop ring 9-5/8" HES Baffle Adaptor • 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 SN's of all float equipment and stage tool components. Page 16 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 (if used) ID Depth Bypass or Shut-off Baffle ID Depth Float Collar Depth Float Shoe Depth Hole TD "Reference Casing Sales Manual Section 5 Page 17 "A Overall Length B Mm. ID After Drillout C Max. TC -01 OD D Openmg Seat ID E Closing Seat ID Plug Set Part No. SO No_ Closing Plug U- OD Opening Plug OD OD Shut-off Plug OD Bypass Plug (if used) OD Milne Point Unit M-25 SB Injector Drilling Procedure Hikotp ES41 Running Order ES -11 Cementer / Shut off Plug Baffle Adapter By-pass Plug By Pass Baffle Float [altar Float Shoe Milne Point Unit M-25 SB Injector Drilling Procedure 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 Geologist Depth Interval Centralization Shoe — 1,000' Above Shoe 1/jt 1,000' above Shoe — 2,000' above Shoe 1/ 2 jts (Top of Ugnu) • 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 5 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 3,300 psi. • ESIPC: Ensure tool is pinned properly. ESIPC packer to inflate at 2,080 psi, and the tool to open at 3,000 psi. Reference ESIPC Procedure. 9-5/8" 40# L-80 TXP Make Up Torques: Casing OD Minimum OptimumMaximum 9-5/8" 18,860 ft -lbs 20,960 ft -lbs 23,060 ft -lbs Page 18 Hilcox F -W :— TXP® BTC Milne Point Unit M-25 SB Injector Drilling Procedure . - 11108,,'2018 Outside Diameter 9.625 in. Min. Wall 87.5% PERFORMANCE Thickness k ini YiaM Stangth I") Grade LBO 41MType lbs 1 Compression Snength 916.000 x1000 Wall Thickness 0-39501- Connection GD REGULAR Option COUPLING PIPE BODY Body- Red 1st Band: Red Grade L80 Type 9' Drift API Standard tst Sarx1: Brawn 2nd Band: 2nd Band: - Browm Type Casing 3rd Band: - 3rd Band: - 41h Band: - :il 1 GEOMETRY Nominal CC, 9.625 in. Nominal Weight 40 +bsrYt Drift 8.679 in Nominal IC 8.835 in. We'l,: Thickness 0.335 in. Plain End 4^deight 38.97 Ib0t OD To6sTance API PERFORMANCE Body Y*id Strength 916 x1000 Pas hmematYr*id 5750 ps SMYS 80006 psi CoOapse 3090 ,-Si GEOMETRY Comneotw OD 10.625 in. Coupling Length 10.825 in Connection ID 8.823 in. Make-up Loss 4.891 in. Threads per ir 5 Connection OD Option REGULAR PERFORMANCE Tension ENxiency 100.0% k ini YiaM Stangth 916.000 x1000 Internal Pressure Capac y Ir 5750.000 psi lbs ccmpression Effivency 100 °,_ Compression Snength 916.000 x1000 Max. Allowable Bending 38 `€100 ft lbs External Pressure Capacira 3090.000 ps MAKE-UP TORQUES Minimum 18860 ft-ks Optimum 20960 P.4bs Maximum 23CEC`-Ic_s OPERATION LIMIT TORQUES Operating Torque 35600 ft-'lts Yield Torque 43403 f.-Ibs Notes This connection is fully interchangeable with: TXP@ BTC - 9-625 in- - 36 143.5 147 153.5 159.4 Ibslft [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 Tenariss technical sales representative. Page 19 i Milne Point Unit M-25 SB Injector Hilco'rnr EOR® COIDp6Gj' 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 PU landing joint and MU to casing string. Position the casing shoe +/- 10' from TD. Strap the landing joint prior to the casing j ob 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 13.0 Cement 9-5/8" Surface Casing Milne Point Unit M-25 SB Injector Drilling Procedure 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 RAJ cement line (if not already done so). Company Rep to witness loading of the top and bottom plugs to ensure done in correct order. 13.5 Fill surface cement lines with water and pressure test. 13.6 Pump remaining 60 bbls 10.5 ppg tuned spacer. 13.7 Drop bottom plug (flexible bypass plug) — HEC rep to witness. Mix and pump cement per below calculations for the 1St stage, confirm actual cement volumes with cementer after TD is reached. 13.8 Cement volume based on annular volume + 30% open hole excess. Job will consist of lead & tail, TOC brought to stage tool. Estimated 11t Stage Total Cement Volume: Page 21 Section Calculation Vol (bbl) Vol (ft3) 12-1/4" OH x 9-5/8" (4,704'- 2500') x .0558 bpf x 1.3 = 159.8 897.6 v Casing J Total Lead 159.8 897.6 12-1/4" OH x 9-5/8" (5,704'- 4,704') x .0558 bpf x 1.3 = 72.5 407 — Casing ~ 9-5/8" Shoe Track 120'x .0758 bpf = 9.1 51.09 Total Tail 81.6 458 Page 21 Milne Point Unit M-25 SB Injector Hilcot�'t��+ Drilling Procedure Energy Cavpa'ny Cement Slurry Design (1st Stage Cement Job): Note: Lead Cement Viscosity to be lowered to prevent poor interface once stage tool is opened and cement is circulated to surface 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: 5,584' x.0758 bpf = 423.3 bbls 80 bbls of tuned spacer to be left behind stage tool, confirm spacer is compatible with cement behind stage tool & that sufficient spacer will be above the tool to exit when circulation istool & that sufficient spacer will be above the tool to exit when circulation is established. 13.12 Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any point during the job. Be prepared to pump out fluid from cellar. Have black water available to contaminate any cement seen at surface. 13.13 If plug is not bumped at calculated strokes, double check volumes and calculations. Over displace by no more than 50% of shoe track volume, ±4.5 bbls before consulting with Drilling Engineer. 13.14 If plug is not bumped, consult with Drilling Engineer. Ensure the free fall stage tool opening plug is available if needed. This is the back-up option to open the stage tool if the plugs are not bumped. Page 22 Lead Slurry Tail Slurry Density 12.0 Ib/gal 15.8 Ib/gal Yield 2.35 ft3/sk 1.16 ft3/sk Mixed Water 13.92 gal/sk 4.98 gal/sk Note: Lead Cement Viscosity to be lowered to prevent poor interface once stage tool is opened and cement is circulated to surface 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: 5,584' x.0758 bpf = 423.3 bbls 80 bbls of tuned spacer to be left behind stage tool, confirm spacer is compatible with cement behind stage tool & that sufficient spacer will be above the tool to exit when circulation istool & that sufficient spacer will be above the tool to exit when circulation is established. 13.12 Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any point during the job. Be prepared to pump out fluid from cellar. Have black water available to contaminate any cement seen at surface. 13.13 If plug is not bumped at calculated strokes, double check volumes and calculations. Over displace by no more than 50% of shoe track volume, ±4.5 bbls before consulting with Drilling Engineer. 13.14 If plug is not bumped, consult with Drilling Engineer. Ensure the free fall stage tool opening plug is available if needed. This is the back-up option to open the stage tool if the plugs are not bumped. Page 22 0 Hilcorp E -V C-PZY Milne Point Unit M-25 SB Injector Drilling Procedure 13.15 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held, this is to ensure the stage tool is not prematurely opened. 13.16 Increase pressure to 3,300 psi to open circulating ports in stage collar. Slightly higher pressure may be necessary if TOC is above the stage tool. CBU and record any spacer or cement returns to surface and volume pumped to see the returns. Circulate until YP < 20 again in preparation for the 2nd stage of the cement job. 13.17 Be prepared for cement returns to surface. Dump cement returns in the cellar or open the shaker bypass line to the cuttings tank. Have black water available and vac trucks ready to assist. Ensure to flush out any rig components, hard lines and BOP stack that may have come in contact with the cement. Page 23 Milne Point Unit M-25 SB Injector Hilco+Tfr1 Drilling Procedure Energy Compiny Second Stage Surface Cement Job: 13.18 Prepare for the 2nd stage as necessary. Circulate until first stage reaches sufficient compressive strength. Hold pre job safety meeting. 13.19 HEC representative to witness the loading of the ES cementer closing plug in the cementing head. 13.20 Fill surface lines with water and pressure test. 13.21 Pump remaining 60 bbls 10.5 ppg tuned spacer. 13.22 Mix and pump cmt per below recipe for the 2nd stage. 13.23 Cement volume based on annular volume + open hole excess (200% for lead and 100% for tail). Job will consist of lead & tail, TOC brought to surface. However cement will continue to be pumped until clean spacer is observed at surface. Estimated 2nd Stage Total Cement Volume: Cement Slurry Design (2nd stage cement job): Section Calculation Vol (bbl) Vol (ft3) 20" Conductor x 9-5/8" Casing (110') x .26 bpf x 1 = 28.6 161 J 12-1/4" OH x 9-5/8" Casing (2,000'- 110') x .0558 bpf x 3 = 316.4 1776.3 Total Lead 345 1937 — 12-1/4" OH x 9-5/8" Casing (2,500'- 2,000') 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 Density 10.7 Ib/gal 15.8 Ib/gal Yield 4.41 ft3/sk 1.17 ft3/sk Mixed Water 22.02 gal/sk 5.08 gal/sk Page 24 Hilcorp Energy Company Milne Point Unit M-25 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: 2,500' x .0758 bpf = 190 bbls mud 13.27 Monitor returns closely while displacing cement. Adjust pump rate if necessary. Wellhead side outlet valve in cellar can be opened to take returns to cellar if required. Be prepared to pump out fluid from cellar. Have black water available to retard setting of cement. 13.28 Decide ahead of time what will be done with cement returns once they are at surface. We should circulate approximately 100 - 150 bbls of cement slurry to surface. 13.29 Land closing plug on stage collar and pressure up to 1,000 — 1,500 psi to ensure stage tool closes. Follow instructions of Halliburton personnel. Bleed off pressure and check to ensure stage tool has closed. Slips will be set as per plan to allow full annulus for returns during surface cement job. Set slips 13.30 Make initial cut on 9-5/8" final joint. LD cut joint. Make final cut on 9-5/8". Dress off stump. Install 9-5/8" wellhead. If transition nipple is welded on, allow to cool as per schedule. Ensure to report the following on wellez: • 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-ngel cghilcorp. com and cdin er e,hilcorp. com This will be included with the EOW documentation that goes to the AOGCC. Page 25 ff Hilcorp E -Sy m. 14.0 14.1 Milne Point Unit M-25 SB Injector Drilling Procedure BOP NU and Test ND the diverter T, knife gate, diverter line & NU 11" x 13-5/8" 5M casing spool. 14.2 NU 13-5/8" x 5M BOP stack as follows: • BOP stack 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 • NU 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 14.3 Run 5" BOP test plug 14.4 Test BOPE to 250/3,000 psi for 5/5 minutes. Test annular to 250/2,500 psi for 5/5 minutes. • 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 RD BOPE testing equipment 14.6 Dump and clean mud pits, send spud mud to G&1 pad for injection. 14.7 Mix 8.9 ppg F1oPro fluid for production hole. 14.8 Pull the test plug and 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 Milne Point Unit M-25 SB Injector Hilcorp Drilling Procedure E—W Company 15.0 Drill 8-1/2" Hole Section 15.1 MU 8-1/2" cleanout BHA (Milltooth Bit & 1.22° PDM) 15.2 TIH with 8-1/2" cleanout BHA to stage tool. Note depth TOC tagged on AM report. Drill out stage tool. 15.3 TIH to TOC above the baffle adapter. Note depth TOC tagged on morning report. 15.4 RU and PT casing to 2,500 psi for 30 minutes. Ensure to record volume / pressure (every 1/4 bbl) and plot on FIT graph. AOGCC reg is 50% of burst = 5,750 / 2 = —2,875 psi, but max test pressure on the well is 2,500 psi as per AOGCC. Document incremental volume pumped (and subsequent pressure) and volume returned. Ensure rams are used to test casing as per AOGCC Industry Guidance Bulletin 17-001. 15.5 Drill out shoe track and 20' of new formation. 15.6 CBU and condition mud for FIT. 15.7 Conduct FIT to 12.0 ppg EMW. Chart Test. Ensure test is recorded on same chart as FIT. Document incremental volume pumped (and subsequent pressure) and volume returned. .8 POOH & LD Cleanout BHA 15 A 15.9 PU 8-1/2" directional BHA. • Ensure BHA components have been inspected previously. • Drift and caliper all components before MU. 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 RU 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# S-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 • Milne Point Unit M-25 SB Injector 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 rpm is > 8.5 (hole diameter) for sufficient hole cleaniniz • 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 F1oPro drilling fluid Properties: Interval Densit PV YP LSYP Total Solids MBT HPHT Hardness Production 8.9-9.5 15-25 - ALAP 15-30 4-6 <10% <8 <1 1.0 <100 System Formulation: OIZO. K. M Page 28 Product- production Size Pkg ppb or (% liquids) Busan 1060 55 gal dm 0.095 FLOTROL 55 lb sx 6 CONQOR 404 WH (8.5 gal/ 100 bbls) 55 gal dm 0.2 FLONIS PLUS 25 lb sx 0.7 KCl 50 lb sx 10.7 SMB 50 lb sx 0.45 LOTORQ 55 gal dm 1.0 SAFE-CARB 10 (verify) 50 lb sx 10 SAFE-CARB 20 (verify) 50 lb sx 10 Soda Ash 50 lb sx 0.5 15.11 TIH with 8-1/2" directional assembly to bottom 15.12 Displace wellbore to 8.9 ppg Flo Pro drilling fluid Milne Point Unit M-25 SB Injector Drilling Procedure 15.13 Begin drilling 8-1/2" 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 PU off bottom and restart on bottom staging technique. If stick slip continues, consider adding .5% lubes 15.14 Drill 8-1/2" hole section to section TD per Geologist and Drilling Engineer. • 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 0A1 & OA3 lobes in 1,000-1,500' 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 • Offset injection pressure from F-110 & L-50 has been seen on recent M -Pad wells. Watch for higher than expected pressure. MPD will be utilized to monitor pressure build up on connections • AC: • There are no offset wells in the Schrader OA sand that have a clearance factor of <1.0. • 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% Page 29 Hilcorp Energy CmpwY Milne Point Unit M-25 SB Injector Drilling Procedure 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. • 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 Once hole is clean, displace to lubricated, viscosified 8.8 ppg 2% KCl brine. 15.18 Monitor the returned fluids carefully while conditioning the mud. After 4 (or more) BU, Perform production screen test (PST). The mud has been properly conditioned when the mud will pass the production screen test (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 15.19 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 15.20 CBU minimum two times at 9-5/8" shoe and clean casing with high vis sweeps. 15.21 Monitor well for flow. Increase mud weight if necessary • 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 15.22 POOH and LD BHA. Rabbit DP on TOOH, ensure rabbit diameter is sufficient for future ball drops. Page 30 Milne Point Unit M-25 SB Injector Drilling Procedure 15.23 Continue to POOH and stand back BHA if possible. Rabbit DP on TOOH, ensure rabbit diameter is sufficient for future ball drops. Only LWD open hole logs are planned for the hole section (GR + Res). There will not be any additional logging runs conducted. Page 31 l 16.0 Run 4-1/2" Injection Liner (Lower Completion) Milne Point Unit M-25 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: PU & MU the 5" safety joint (with 4-1/2" crossover installed on bottom, TIW valve in open position on top, 4-1/2" handling joint above TIW). This joint shall be fully MU and available prior to running the first joint of 4-1/2" liner. • With 4-1/2" solid joint across BOP: Slack off and position the 4-1/2" solid joint to MU the TIW valve. Shut in ram or annular on 4-1/2" solid joint. Close TIW valve. 16.2. Confirm VBR have been tested on 4-1/2" and 5" test joints to 250/3,000 psi. 16.3. RU 4-1/2" liner running equipment. • Ensure 4-1/2" Hydril 625 x DS -50 crossover is on rig floor and MU 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 RU casing tools. • Record OD's, ID's, lengths, SN's of all components with vendor & model info. 16.4. 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. • Fill 4-1/2" liner with PST passed mud (to keep from plugging ICDs with solids) • Install ICDs and swell packers as per the Running Order • (From Completion Engineer post TD). • 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# Hydri1625 • Remove protective packaging on swell packers just prior to picking up • If liner length exceeds surface casing length, ensure centralizers are placed 1/joint for each joint outside of the surface shoe. This is to mitigate difference sticking risk while running inner string. • Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10 and 20 rpm 4-1/2" 13.5# L-80 H625 Casing OD Minimum Optimum Maximum Operating Torque 4.5" 8,000 ft -lbs 9,600 ft -lbs 12,800 ft -lbs Page 32 l Hills B�Compmy For the latest performance data, always visit our website: www.tenaris.com Wedge 6250 Outride Diameter 4.500 in. Wall Thickness 0290 in. Grade L80 Type 1' GEOMETRY Min_ wall 87.5`4 Thickness Connection OD REGULAR Option Dry API Standard Type Casing Milne Point Unit M-25 SB Injector Drilling Procedure ,--.12/04/2017 f'1 Grade L80 4.500 - Nominal Weil+^ Type 1 Nominal ID COUPLING PIPE BODY Body Red 1 st Band: Red 1st Band: Brown 2nd Band: 2nd Band: - Brown 3rd Band: - 3rd Band: - 902D ps. 2MY8 80000 ps 41h Band: - Nominal OD 4.500 - Nominal Weil+^ 13.50 LsYt Drift 3.795 vn. Nominal ID 3.920 n. Wa",I. Thickness 0290 r- Hain End Weight 13,05 AWR CID ToSerance API Connection, OD Opton PERFORMANCE Body Ysk.' Sbengd, 307 x1000 lbs Internal Yield 902D ps. 2MY8 80000 ps Collapse 8540 psi Connector OD 4.714 an. Connecto n ID 3.819 r:. Make-up Loss 4,830,n Threads per in 3.59 Connection, OD Opton REGULAR PERFORMANCE Tension Efficlenoy 91.0% Joint Yield Svength 279.370 x1DDD Internal Pressure Capacity 9D20.000 ps lbs Compression Efficiency 94.5'' a Compression Strerglh 290.115 x1071 Max Allowable Bending 73.7'11_CI', lbs External Pressure Capacity 8540.000 psi MAKE-UP TORQUES Minimum 8000 ft -lbs Optimum 9600 9.Its Mammmn 12800 9 -lbs OPERATION LIMIT TORQUES Cperatsg Torque 12800 ft4bs Yield TaTqne 1500D Nabs Notes For further information on concepts indicated in this datasheet, download the Datasheet Manual from www_tenatis.com Page 33 Milne Point Unit M-25 SB Injector Hilco Drilling Procedure 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. Before picking up Baker SLZXP liner hanger / packer assembly, count the # of joints on the pipe deck to make sure it coincides with the pipe tally. 16.8. 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 minutes for mixture to set up. 16.9. Note weight of liner. Run liner in the hole one stand and pump through liner hanger to ensure a clear flow path exists. 16.10. RIH with liner on DP no faster than 30 ft/min — this is to prevent buckling the liner and drill string. Watch displacement carefully and avoid surging the hole or buckling the liner. Slow down running speed if necessary. 16.11. The liner and inner string will prevent the DP from auto filling. Fill DP every 5 stands, more frequently if SOW trend indicates. 16.12. Slow in and out of slips. Ensure accurate slack off data is gathered during RIH. Record shoe depth + SO depth every stand. Record torque value if it becomes necessary to rotate the string to bottom. 16.13. If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensure shoe enters correct hole. 16.14. TIH deeper than planned setting depth. Last motion of the liner should be up to ensure it is set in tension. 16.15. Rig up to pump down the work string with the rig pumps. 16.16. Prior to setting the hanger and packer, double check all pipe tallies and record amount of drill pipe left on location. Ensure all numbers coincide with proper setting depth of liner hanger. 16.17. Drop setting ball down the DP and pump slowly (1-2 BPM). Slow pump before the ball seats. Do not allow ball to slam into ball seat. Pressure up to 1,500 psi to shift the wellbore isolation valve closed. 16.18. Continue pressuring up to 2,700 psi to set the SLZXP liner hanger/packer. Hold for 5 minutes. SO 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 4,100 psi to neutralize and release running tools. Page 34 Milne Point Unit M-25 SB Injector Drilling Procedure 16.19. Bleed DP pressure to zero, PU to expose rotating dog sub and set down 50K without pulling sleeve packoff. Pick back up without pulling sleeve packoff, begin rotating at 10-20 RPM and set down 50K again, 16.20. PU to neutral weight, close BOP and PT the annulus to 1,500 psi for 10 minutes charted 16.21. Bleed off pressure and open BOPE. Pickup to verify that the HRD setting tool has released. If packer did not test, rotating dog sub can be used to set packer. If running tool cannot be hydraulically released, apply LH torque to mechanically release the setting tool. 16.22. Displace DP x Liner, pump 1-2 circulations. 16.23. POOH laying down DP then rack back enough 5" DP for the liner top cleanout run. LD and inspect the running tools. Once running tools are LD, Swap to Completion AFE 16.24. Make up 3-1/2" wash tool & RIH on 5" DP to the liner top. 16.25. Flush liner top at max rate while displacing out well to clean brine. 16.26. POOH LD the remaining 5" DP. Page 35 17.0 Run 3-1/2" Tubing (Upper Completion) Milne Point Unit M-25 SB Injector Drilling Procedure 17.1 Notif y 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 wrivardnhilcorp.com for submission to AOGCC. 17.2 MU injection assembly and RIH to setting depth. TIH no faster than 90 ft/min. • Ensure wear bushing is pulled. • Ensure 3-1/2" EUE 8rd x NC -50 crossover is on rig floor and MU 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 RU casing tools. • Record OD's, ID's, lengths, SN's of all components w/ vendor & model info. • Monitor displacement from wellbore while RIH. 3-1/2" 9.3# L-80 EUE 8RD Tubing OD Minimum Optimum Maximum Operating Torque 3-1/2" 2,350 ft -lbs 3,130 ft -lbs 3,910 ft -lbs 3-1/2" Upper Completion Running Order • 3-1/2" Baker Ported Bullet Nose seal (stung into the tie back receptacle) • 3 joints (minimum, more as needed) 3-1/2" 9.34, L-80 EUE 8RD tubing • Gauge Mandrel (pressure gauge installed) with 10' handling pump above and below • X joints 3-1/2" 9.3#, L-80 EUE 8RD tubing • 2.813" `XN' nipple (2.75" no-go) at deepest point possible (less than 65° deviation) with 10' handling pump above and below • X joints 3-1/2" 9.3#, L-80 EUE 8RD tubing • 2.813" `X' nipple at TBD MD with 10' handling pump above and below • X joints 3-1/2" 9.3#, L-80 EUE 8RD tubing • Space out pups (as needed) 3-1/2" 9.3#, L-80 EUE 8RD • 1 joint 3-1/2" 9.3#, L-80 EUE 8RD tubing • Tubing hanger with 3-1/2" EUE 8RD pin down Page 36 Milne Point Unit M-25 SB Injector Hilco�P Drilling Procedure � � 17.3 Locate and no-go out the seal assembly. Close annular and test to 500 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 pressure up to 500 psi to confirm seals are engaged. Bleed pressure down to 250 psi. PU until ports in seal assembly exposed. 17.7 Reverse circulate the well with brine and 1% corrosion inhibitor. 17.8 Freeze protect the IA to 2,100' TVD (based on actual well deviation) with diesel. 17.9 Land hanger and RLD. 17.10 PT the IA to 2,500 Dsi and test for 30 minutes charted. -j Note this test must be witnessed by the AOGCC representative. 17.11 Set BPV, ensure new body sea s are installed each time. 17.12 ND BOPE and install plug off tool in to the BPV. 17.13 NU the tubing head adapter and tree. 17.14 PT the tubing hanger void to 500/5,000 psi. PT the tree to 250/5,000 psi. 17.15 Pull the plug off tool from the BPV. 17.16 Bullhead diesel down the tubing to 2,100' TVD (based on actual well deviation). 17.17 Install all tree gauges. Secure the tree and cellar. Release the rig. 17.18 RDMO Doyon 14. 17.19 Turn the well over to operations via handover form. Page 3 7 HilmF--" 18.0 Doyon 14 Diverter Schematic 21-114' 2M R ser — 21-1;4' 2M--' Dverter "r' 21-1412% Spacer Spoo 16-14'3M r 21.1?4' 2M DSA Page 3 8 Milne Point Unit M-25 SB Injector Drilling Procedure —lb' run opcgbng Knrle Valve 16' Dwrter Uno 19.0 Doyon 14 BOP Schematic Kill Line—`""`+� Page 39 Milne Point Unit M-25 SB Injector Drilling Procedure 2-7/8" x 5" VBR Blind Rams x SM HCR al Gate Va" 2-7/8" x 5" VBR Hilcorp F -W C -p -r 20.0 Wellhead Schematic Page 40 Milne Point Unit M-25 SB Injector Drilling Procedure CAMERON I I" 5KAIBS A Schlumberger Company 37.3411 21-2511 Ltnp— ■I�I� �,�_`� iiia �I�I■_, 1.-1*B 0195 I�12 tz-f7 IAB:'ndom 21.0 Days Vs Depth n e// t Q a 8000 a� 10000 iiI/N't MCMI/.$] Page 41 Milne Point Unit M-25 SB Injector Drilling Procedure MPU M-25 SB OA Injector Days vs Depth 0 S 10 15 20 25 Days 22.0 Formation Tops & Information Milne Point Unit M-25 SB Injector Drilling Procedure MPU M-25 Formations (wp07) MD (ft) TVDss (ft) TVD (ft) Formation Pressure (psi) EMW (ppg) Base Permafrost 2084 -1777 1829 804.76 8.46 Ugnu LA3 4140 -3049 3101 1364.44 8.46 Schrader Bluff NA j 4979 j -3410 j 3462 1 1523.28 8.46 Schrader Bluff OA 1 5800 1 -3527 1 3579 1 1574.76 8.46 L -Pad Data Sheet Formation Description (Closest & Most Analogous MPU Pad to Moose GENERALIZED GEOLOGICAL SS Schrader Bluff Sands: GEOLOGICAL TVD FM JLITH DESCRIPTION a¢c.a •4170• OSandt Interval at -!- 4400 ft can be sticky and tight (Ldi). ae� ra.sw Gubik to SW comer of Milne development L37 and L-45 are casing for Kuparuk long strings. Also, the Clay hterbeds between 3000 and 4500 ft .r -iso•. 600 .. . 4472'- _ 1 0 L Unconsolidated coarse to medium sand and small gravel Sands: A 365T with minor sl tttone. 1,000' 1750Base permafrost hterbeds of urd, clays and siltstonos with occasional 20001 show of coal. Watch possible sidetracking while washingtreaming, L33 & L-15. COMMENTS NOTE: Soo individual Well Program for specific casing design, depths, sizes, weights, grades and connections. IF SIGNIFICANT AMOUNTS OF GRAVEL ARE ENCOUNTERED WHEN DRILLING THE -416= SURFACE HOLE, THE VISCOSITY OF THE MUD SYSTEM SHOULD IMMEDIATELY BE RAISED TO 150 SEC TO ENSURE EFFECTIVE HOLE CLEANING. -oom No hydrates encountered on L -Pad wells drilled to date. •4000' (NA) Schrader Bluff Sands: continued imorbods of sand, clays and siltstones with continued layering coarsening upward sands as above -OOM Schrader Bluff: Possible lost circulation EF) occasional shows of coal. Traces of pyrite at •f- 4100 ft $ 00O, •4170• OSandt Interval at -!- 4400 ft can be sticky and tight (Ldi). (OA) E� . to SW comer of Milne development L37 and L-45 are casing for Kuparuk long strings. Also, the Clay hterbeds between 3000 and 4500 ft completed in the Schrader Bluff sand. Northern area of Schrader Bluff sands are a potential C 4472'- Bluff L Surface casing point h shale below for Kuparuk long strings. Sands: A 365T It�snas Y UGNU: Series of coarsening upward sands which am (-&MCD) made up of: (from top to bottom) coarse sand, fine sand, silty shale. Better developed intervening shales as you UGNU progress into the L and M (doeper) Ugnu and Schrader Bluff. Possible hydrocarbons limited 4saahlm to SW comer of Mille development Northem area is tie! downstructtae and wat. •4739' (JIB.Ci COMMENTS NOTE: Soo individual Well Program for specific casing design, depths, sizes, weights, grades and connections. IF SIGNIFICANT AMOUNTS OF GRAVEL ARE ENCOUNTERED WHEN DRILLING THE -416= SURFACE HOLE, THE VISCOSITY OF THE MUD SYSTEM SHOULD IMMEDIATELY BE RAISED TO 150 SEC TO ENSURE EFFECTIVE HOLE CLEANING. -oom No hydrates encountered on L -Pad wells drilled to date. •4000' (NA) Schrader Bluff Sands: NSand 4,000• t.Ae.c,o, continued layering coarsening upward sands as above -OOM Schrader Bluff: Possible lost circulation EF) except more condensed and with occasional coal. zone while drilling long strings and running •4170• OSandt Clay rich shale interval 4300 to 4600 ft Ugnu and Schrader Bluff: Possible hydrocarbons limited casing. Recommend deep setting surface (OA) E� . to SW comer of Milne development L37 and L-45 are casing for Kuparuk long strings. Also, the completed in the Schrader Bluff sand. Northern area of Schrader Bluff sands are a potential Schrader L -Pad Is downstmcture and wet. differential stuck pipe interval if left un -cased Bluff C Surface casing point h shale below for Kuparuk long strings. Sands: Schrader Bluff OB sand for longer reach wells. Page 42 v/ Milne Point Unit M-25 SB Injector Hilco Drilling Procedure .T 23.0 Anticipated Drilling Hazards 12-1/4" Hole Section: Lost Circulation Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Gas Hydrates Gas hyrates have not been seen on Moose pad. However, be prepared for them. Remember that hydrate gas behave differently from a gas sand. Additional fluid density will not prevent influx of gas hydrates, but can help control the breakout at surface. Once a gas hydrate has been disturbed the gas will come out of the hole. Drill through the hydrate section as quickly as possible while minimizing gas belching. Minimize circulation time while drilling through the hydrate zone. Excessive circulation will accelerate formation thawing which can increase the amount of hydrates released into the wellbore. Keep the mud circulation temperature as cold as possible. Weigh mud with both a pressurized and non -pressurized mud scale. The non -pressurized scale will reflect the actual mud cut weight. Add 1.0 — 2.0 ppb Lecithin to the system to help thin the mud and release the gas. Isolate/dump contaminated fluid to remove hydrates from the system. Hole Cleaning: Maintain rheology of mud system. Sweep hole with high viscosity sweeps as necessary. Optimize solids control equipment to maintain density, sand content, and reduce the waste stream. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to avoid washing out a particular section of the hole. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Anti -Collison: Take directional surveys every stand, take additional surveys if necessary. Continuously monitor proximity to offset wellbores and record any close approaches on AM report. Discuss offset wellbores with production foreman and consider shutting in adjacent wells if necessary. Monitor drilling parameters for signs of collision with another well. A/C Specifics: • There are no actual offset wells with a clearance factors <1.0 in the surface hole section M-51 — Slot 12 is a planned well and does not exist yet 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. Page 43 Hilcorp Energy Company Milne Point Unit M-25 SB Injector Drilling Procedure H2S: Treat every hole section as though it has the potential for 1-12S. No H2S events have been documented on drill wells on this pad. 1. The AOGCC will be notified within 24 hours if 1-12S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Page 44 Hilcorp Energy C—pmy 8-1/2" Hole Section: Milne Point Unit M-25 SB Injector Drilling Procedure Hole Cleaning: Maintain rheology of mud system. Sweep hole with low -vis water sweeps. Ensure shakers are set up with appropriate screens to maximize solids removal efficiency. Run centrifuge continuously. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Maintain circulation rate of > 300 gpm Lost Circulation: Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Faulting: There is at least (1) fault that will be crossed while drilling the well. There could be others and the throw of these faults is not well understood at this point in time. When a known fault is coming up, ensure to put a "ramp" in the wellbore to aid in kicking off (low siding) later. Once a fault is crossed, we'll need to either drill up or down to get a look at the LWD log and determine the throw and then replan the wellbore. H2S: Treat every hole section as though it has the potential for 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. J 2. The rig will have fully functioning automatic 1-12S 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: Reservoir pressures are expected to be normal. Abnormal (offset injection) pressure has been seen on M - Pad. Utilize MPD to mitigate any abnormal pressure seen. Anti -Collision Take directional surveys every stand, take additional surveys if necessary. Continuously monitor drilling parameters for signs of magnetic interference with another well. Reference A/C report in directional plan. There are no wells with a separation factor of <1. Specific AC risk addressed in 8.5" hole section, 15 as well. A/C Specifics: • There are no offset wells in the Schrader OA sand that have a clearance factor of <1.0. Page 45 Milne Point Unit M-25 SB Injector Hilco1T Drilling Procedure E -W Compmy 24.0 Dovon 14 Lavout T a Page 46 C. Page 46 C. 25.0 FIT Procedure Formation Integrity Test (FIT) and Leak -Off Test (LOT) Procedures Procedure for FIT: Milne Point Unit M-25 SB Injector Drilling Procedure 1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe). 2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe. 3. Close the blowout preventer (ram or annular). 4. Pump down the drill stem at 1/4 to 1/2 bpm. 5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe. 6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes. Record time vs. pressure in 1 -minute intervals. 7. Bleed the pressure off and record the fluid volume recovered. The pre -determined surface pressure for each formation integrity test is based on achieving an EMW at least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick tolerance in case well control measures are required. Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of stopping at a pre -determined point, surface pressure is increased until the formation begins to take fluid; at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure monitored as with an FIT. Ensure that casing test and subsequent FIT tests are recorded on the same chart. Document incremental volume pumped and returned during test. Page 47 HilmE—W Company 26.0 Doyon 14 Choke Manifold Schematic Milne Point Unit M-25 SB Injector Drilling Procedure Page 48 Milne Point Unit M-25 SB Injector Hilco Drilling Procedure � c2 27.0 Casing Design ifCalculation & Casing Design Factors HUMT DATE: 2/5/2020 WELL: MPU M-25 DESIGN BY: Joe Engel Hole Size 12-1/4" Hole Size 8-1/2" Hole Size Drilling Mode MASP: MASP: Production Mode MASP: Collapse Calculation: Section Calculation Design Criteria: Mud Density: 9.2 ppg Mud Density: 9.2 ppg Mud Density: 1215 psi (see attached MASP determination & calculation) 1215 psi (see attached MASP determination & calculation 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 5,704 Top (TVD) 0 3,573 Bottom (MD) 5,704 13,915 Bottom (TVD) 3,573 3,478 Length 5,704 8,211 Weight (ppf) 40 13.5 Grade L-80 L-80 Connection TXP H625 Weight w/o Bouyancy Factor (lbs) 228,160 110,849 Tension at Top of Section (lbs) 228,160 110,849 Min strength Tension (1000 lbs) 916 279 Worst Case Safety Factor (Tension) 4.01 .j 2.52 Collapse Pressure at bottom (Psi) 1,765 1,718 Collapse Resistance w/o tension (Psi) 3,090 8,540 Worst Case Safety Factor (Collapse) 1.75 ✓ 4.97 MASP (psi) 1,215 1,215 Minimum Yield (psi) 5,750 9,020 Worst case safety factor (Burst) 4.73 :/ 7.42 Page 49 28.0 8-1/2" Hole Section MASP Milne Point Unit M-25 SB Injector Drilling Procedure Maximum Anticipated Surface Pressure Calculation Hill 8-1/2" Hole Section MPU M-25 Milne Point Unit MD TVD Planned Top: 5704 3573 Planned TD: 13915 3478 lnticipated Formations and Pressures: Formation TVD Est Pressure Oil/Gas/Wet PPG Grad ichrader Bluff OA Sandi 3,573 1572 1 Oil 8.46 0.440 Offset Well Mud Densities Well MW range Top (TVD) Bottom (TVD) Date M-23 9.1-9.3 Surface 3813 2020 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 for the 8-1/2" hole section is 9.5 ppg. 3. Calculations assume full evacuation of wellbore to gas Fracture Pressure at 9-5/8" shoe considering a full column of gas from shoe to surface: 3573 (ft) x 0.78(psi/ft)= 2787 2787(psi) - [0.1(psi/ft)*3573(ft)]= 2430 psi MASP from pore pressure (complete evacuation of wellbore to gas from Schrader Bluff OA 3573 (ft) x 0.44(psi/ft)= 1572 psi 1572(psi) - 0.1(psi/ft)*3573(ft) F1215 psi Summary: 1. MASP while drilling 8-1/2" production hole is governed by pore pressure and evacuation of entire wellbore to gas at 0.1 psi/ft. Page 50 29.0 Spider Plot (NAD 27) (Governmental Sections) �o.cs r� ADLD25513 r RIVER X)x Milne Point Unit M-25 SB Injector Drilling Procedure I 1 1 I 1 1 1 I 1 1 I I 1 I 1 1 1 1 1 1 1 1 l 1 1 1 r I 1 IF.1.:6 q r U013NO09E Sfe''11 � .: ... ♦ 1 i fADL3550231t i 1 Sec, 12, L40 . O r l ; rt 1 1 1 1 n r ADL388235 101, l r =r y L ?7 'Si Slit �it `♦� +� I +r 1 f p 1 ! 11 1 11 t 1 p 1 % L y ♦ ` I ��♦ I 1 t ` `♦ % 11 1 1 I t 1 1 t ` i T� \P1=N, I1 iI t1 1 ! } ♦` O I 1 r `1 � 1 11 r� r I O 1 I I 11 t 2 i I I r ♦ A 1 i ♦ p Sec. 141 J 1 1 1 �i4 i`• 1 0 1 / 1 1 1 .1� 1 ♦ 1 O f 1 I li~ It- 1ty O 1 1 I 1 rr o o 0 0 1 A Legend � 1 O 1 / 1 r� I I I 1 t ♦tr 1 o I L' MILNE 11 • NiPU M-25i_SHL i o i '''POINT UNIT 1 1 It I i• 1 O r r I I • It r 1 y,y °o a r ,/ ADL025514 1 In,.,;, 1 , •1' ytl ` O 1 4 1 a t 1♦ 1 0o p 71 ( r I 1 1 � O 11 . 1 . 1 7 1 �' ♦ I 1 1 I 1 1 1 I 1 1 I I 1 I 1 1 1 1 1 1 1 1 l 1 1 1 r I 1 IF.1.:6 q r U013NO09E O r l rt 1 1 1 1 n r I 1 l +r 1 1 I O I 1 r 1 1 t r♦ I Q/ -: 1 I I r ♦ A ' l J 1 1 1 �i4 i`• 1 � O 1 1 I 1 rr o o 1I Sec. 23 1 A Legend � / I rr 11 1 11 • NiPU M-25i_SHL , .la,u o 1 I 1 1 X NIPU M -25i TPH 00 1 'm — °o 1 i fi MPU M -25i BHL — O 1 1 I 0o I Other Surface Holes (SHL) 0 o° 1 1 1 I Other BoaDrn Holes (BHL) 0 11 e %1PU M-25i_3313L ; 'IL"76 V,,_23 L 1W I I - - - Other Well Paths ht.1 Coastline J.USGS 1:63k) Oil and Gas Unit Boundary Pad Footprint See 27 , ADL025520 ♦♦ ADI -025519 Se: 2L E UIPMENT PAD Sec- 25 ) Milne Point Unit Alaska State Plane Zonae 4 MAD 1927 I6k.rp lM.4.. 1.,MPU M-25 Well 0 500 1,000 1,500 IAip Date: zwMn wpW Feet Page 51 Hilcox En.w r— 30.0 Surface Plat (As Built) (NAD 27) I CJ21., A.S.P. COORDINATES PLANT COORDINATES GEODETIC POSITION DMS Z SECTION OFFSETS PAD ELEVATION CELLAR 8OX EL_ I Y= 6,027,889.56 N= 1,291.92 70'29'14.014" I 12 I 25.2' SEC_ 13 X= 533,543.90 SEG 11 149'43'32,988" 149.7258300' _ ••---------��1--- _ M-10 ■ Y= 6,027,889.58 N= 1,291,95 7029'14.020' M-11 ■ 5,039' FS? 25.2' 25.3' ■ M-13 I 14943'36.519" Y-12 ■ 741' FEL ■ N-14 I M-20 ■ M-67 ■ ■ M-15 M-21 ■ C ■ M—t4 JU— - ,22 ■ M-17 IM-23 ■ ■ M-10 M-25 t M-24 ■ ■ M—t9 I M-26 . • N -0s I I MOOSE PAD ■ Y -OB I GRAPHIC SCALE 0 100 200 400 ( N FEET ) 1 kr ch . 200 1L Milne Point Unit M-25 SB Injector Drilling Procedure SURVEYOR'S CERTIFICATE I HEAE9Y C£HTFY THAT I AM PRaPtTtt.Y RERSSTERED AND LICENSED TO PRACTICE LANDI SURVEYING IN THE STATE OF ALASKA AND THAT THIS AS -BUILT REPRESENTS A SURVEY MADE BY ME OR UNDER YY DIRECT SUPEWSON AND THAT ALL DIMENSIONS AND 01HER DETALS ARE 1 Cf �,ltyTC CONAECT AS OF OCT09ER 16. 2019. l EGENQi NOTES" - } AS-BULT CONDUCTOR 1. ALAWA STATE PLANE COORDINATES ARE NAD27, ZONE 4. 2 6ECOEMC POSTIONS ARE NA027. ■ EMSTM CONDUCTOR y BASS OF HORRONTAL AND VERTICAL CONTROL IS Sm -A AP 571[0 NE, 4. MPU NOOSE AWMAE PAD SCALE FACTOR 13 719999013. 5. DATE Of SJRVEY: OCTOBER 15, 2919. & REFERENCE FIELD BOOK, NC19-04 PG 25. LOCATED WITHIN PROTRACTED SFC. 14. T. 13 N.. R. 9 F.. UMIAT MERMAN. ALASKA WELL NO. A.S.P. COORDINATES PLANT COORDINATES GEODETIC POSITION DMS GEODETIC POSITION D.9D SECTION OFFSETS PAD ELEVATION CELLAR 8OX EL_ M-25 Y= 6,027,889.56 N= 1,291.92 70'29'14.014" 70.4872262' 5,039' FSL ' 25.1' 25.2' X= 533,543.90 E= 1,545,06 149'43'32,988" 149.7258300' 6 21 FEL M-26 Y= 6,027,889.58 N= 1,291,95 7029'14.020' 70.4872277' 5,039' FS? 25.2' 25.3' X= 533,423.92 E= 1,425.06 14943'36.519" 149.7258107' 741' FEL Mom DRAPER re 11 ;w 10 4 9 vt1w PA a" r �r no®uISM— i 1' — 200' Page 52 [Hflcorp Mwka MPU MOOSE PAD AS -BUILT CONDUCTORS WELLS M-25 & M-26 HilmEuew Pauy Milne Point Unit M-25 SB Injector Drilling Procedure 31.0 Schrader Bluff OA Sand Offset MW vs TVD Chart Schrader Bluff OA Sand Offset MW vs TVD MW, ppb 8.5 8.7 8.9 9.1 9.3 9.5 9.7 9.9 10.110.3 10.5 0 1 11111 500 1000 1500 i 2000 4= I >D 2500 3000 3500 4000 4500 Page 53 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) Hilcorp Alaska, LLC Milne Point M Pt Moose Pad Plan: MPU M -25i MPU M -25i Plan: MPU M-25 wp07 Standard Proposal Report 28 January, 2020 HALLIBURTON Sperry Drilling Services ✓, Project: Milne Point Site: M PtMoose Pad Well: Plan: MPU M-251 Wellbore: MPU 14-25i Design: MPUM-25wp07 HALUBURTON ePer,w lxenr+o Hilcorp Alaska, LLC Calculation Method: Minimum Curvature Error System: ISCWSA Scan Method: Closest Approach 3D Error Surface: Pedal Curye Warning Method: Error Ratio FORMATION TOP DETAILS No f. -b- date k evegebM CASING DETAILS ND NDSS MD Size Name 3573.90 3515.00 5704.93 9-5/8 95/8" x 12 1/4" 3478.90 342000 13915.96 4-1/2 41/2 x812" WELL DETAILS: Plan: MPU M -25i SURVEY PROGRAM 25.20 Lengdude +000 Northing Fasting Latittude SECTION DETAILS Validated : Yes Version: 0.00 0 00 602]88.9.56 533543.90 ]0.29' 14.014 N 149.4]' 32.968 W Sec MD Inc Ali ND +N/ -S +E/ -W Dleg Trace VSect Target Annotation 1 33.70 0.00 0.00 33.70 0.00 0.00 0.00 0.00 0.00 2 470.00 0.00 0.00 470.00 0.00 0.00 0.00 0.00 0.00 StartDir 3°/100" 470' MD, 470TVD 3 550.00 2.40 330.00 549.98 1.45 -0.84 3.00 330.00 -1.38 StartDir 4°/100' : 550' MD, 549.98'IVO 4 650.00 6.40 330.00 649.66 8.09 -4.67 4.00 0.00 -7.70 5 1845.86 51.17 273.65 1679.32 100.92 -533.92 4.00 -61.03 -58.15 End Dir : 1845.86' MD, 1679.32' ND 6 3236.31 51.17 273.65 2551.23 169.85 -1614.83 0.00 0.00 -00.93 Start Dir 4°/100' : 3236.31' MD, 2551.23' 7 5454.93 85.00 181.23 3552.11 -1156.37 -2734.19 4.00 -95.41 1370.08 End Dir : 5454.93' MD, 3552.11' TVD 8 5704.93 85.00 181.23 3573.90 -1405.36 -2739.54 0.00 0.00 1618.71 MPU M -25i wp07 Heel Start Dir 4-/100': 5704.93' MD, 3573.97V 9 5849.00 90.7fi 181.23 3579.22 -1549.24 -2742.63 4.00 0.04 1762.38 End Dir : 5849' MD, 3579.22' ND 10 8877.13 90.76 181.23 3538.90 -4576.40 -2807.85 0.00 0.00 4785.14 MPU M -25i Wp05 CP1 Start Dir 4.1100' : 8877.13' MD, 3538.9 118959.27 90.94 184.52 3537.68 -0658.41 -2811.96 4.00 86.89 4867.23 End Dir : 8959.27' MD, 3537.68' ND 12 1 2237.05 90.94 184.52 3483.90 -7925.58 -3069.98 0.00 0.00 8144.56 MPU M -25i wpO5 CP2 Start Dir 4-1100': 12237.05' MD, 3483.9' 13 12256 43 90.17 184.56 3483.71 -7944.90 -3071.51 4.00 176.47 8163.95 End Dir : 12256.43' MD, 3483.71' TVD 14 13915.96 90.17 184.56 3478.90 -9599.16 -3203.54 0.00 0.00 9823.46 MPU M -25i Wp05 Toe Total Depth : 13915.96' MD, 3478.9' ND WELL DETAILS: Plan: MPU M -25i SURVEY PROGRAM 25.20 Lengdude +000 Northing Fasting Latittude Dale: 2017-11-11T000001 Validated : Yes Version: 0.00 0 00 602]88.9.56 533543.90 ]0.29' 14.014 N 149.4]' 32.968 W Depth From Depth To Survey/Plan Tool 33.70 550.00 MPU M-25 wp07 (MPU M -25i) 3_Gyro-GC _Csg REFERENCE INFORMATION 550.00 5704.93 13915.96 MPU M-25 wp07 (MPU M-25) MPU W25 wp07 (MPU M -25i) s- 3_MWD+IFR2+MS+Sa 570493 3_MWD-lFR2+MS+Sa Coordinate (N/E) Reference: Wall PNn: MPU M -25i. True NoM V-.1(TVD)R0-,- MPU M -25A-1 RKB @ 58.90usn (D-14) Measured Depth Reference: MPU M-25ACWe1 RKB @ 58.9 -ft (D-14) Calculatlon Method: Minimum C- - 0- 0 A Start Dir 3°/100' : 470' MD, 470'ND Start Dir4e/100' : 550' MD, 549.98'TVD 500-- 625 End Dir : 1845.86' MD, 1679.32' TVD c 1000 �O 1250 yryr'' O !, 15 N 00 y ob Cb V ^�. Rr a187s " 2000 �O yry: `5'' �O yam rs^ 4z IV lb 2500 h�cb. a 3 ^. y2500- a� `o 3500 6 3125 yoo o ha / < , Z:- D of �c0 a 0 o a c a 9 5/8" x 12 1/4" - g rn g o g 4 0 3750 0 0 o V o c MPU M -25i wp07 Heel MPU M -25i wp05 CP1 ZO 0 b b� n R, ` r �o 4 1/2" x 8 112" rn I o " ro' � � MPU M-25 wp07 g o, 0 0 o on MPU M -25i wp05 CP2 MPU M -25i wp05 Toe -625 0 625 1250 1875 2500 3125 3750 4375 5000 5625 6250 6875 7500 8125 8750 9375 10000 10625 11250 Vertical Section at 184.56° (1250 usftlin) WELL DETAILS: Plan: MPU M -25i 25.20 +N/ -S +E/ -W Northing Easting Latittude Longitude 0.00 0.00 6027889.56 533543.90 70° 29' 14.014 N 149° 43'32.988 W REFERENCE INFORMATION Co-ordinate (N/E) Reference: Well Plan: MPU M -25i, True North Vertical (TVD) Reference: MPU M-25 Actual RKB 58.90usft (D-14) Measured Depth Reference: MPU M-25 Actual RKB @ 58.90usft (D-14) Calculation Method: Minimum Curvature 2250 HALLIBURTON Project: Milne Point Site: M Pt Moose Pad sp—ry Well: Plan: MPU M -25i Wellbore: Plan: MPU M -25i MPU M-25 wp07 I 1500- 500 750 750— CASING DETAILS c h o 0 o I I WELL DETAILS: Plan: MPU M -25i 25.20 +N/ -S +E/ -W Northing Easting Latittude Longitude 0.00 0.00 6027889.56 533543.90 70° 29' 14.014 N 149° 43'32.988 W REFERENCE INFORMATION Co-ordinate (N/E) Reference: Well Plan: MPU M -25i, True North Vertical (TVD) Reference: MPU M-25 Actual RKB 58.90usft (D-14) Measured Depth Reference: MPU M-25 Actual RKB @ 58.90usft (D-14) Calculation Method: Minimum Curvature 2250 TVD TVDSS MD Size Name i 3573.90 3515.00 5704.93 9-5/8 9 5/8" x 12 1/4" 3478.90 3420.00 13915.96 4-1/2 4 1/2" x 8 1/2" I 1500- 500 750 750— c h o 0 o I I 0 ---f O 1 '7�sp Start Dir W160-: 470' MD, 470TVD' i Start Dir 4°/100' : 950' MD, 549.98'TVD -750 I 9 5/8" x 12 1/4" 3500 End Dir : 1845.86' MD, 1679.32' TVD I _ _ _ Start Dir 40/100'- 3236.31'MD, 2551.23TVD End Dir : 5454.93' MD, 3552.11' TVD -1500 _ rU M -25i wp07 Heel f"- - - - Sart Dir 4°/100' :5704.93' MD, 3573.9'TVD - I End Dir : 5849' MD, 3579.22' TVD -2250- 2250-3000-3750 I -3000- -3750 + � I C I 70 Start Dir 4°/100' :8877.13' MD, 3538.9TVD C MPU M -25i wpO5 CPI -4500 I _ End Dir : 8959.27' MD, 3537.68' TVD I -5250- 5250-6000-6750-7500 -6000- -6750- -7500— 1 Start Dir 4°/100' : 12237.05' MD, 3483.9TVD MPU M -25i wpO5 CP2 -8250 Fnd Dir : 12256.43' MD, 3483.71' TVD I I -9000 I I I MPU M -#5i "05 Toe 1 - - - - - Total Depth : 13915.96' MD, 3478.9' TVD MPU 500' Buffer " -9750 - 3479 L- -'= - - - Z - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - L 4 1/2" x 8 1/2" 1 MPU M-25 WP07 -10500 -6000 -5250 -4500 -3750 -3000 -2250 -1500 -750 0 750 1500 2250 3000 3750 4500 West( -)/East(+) (1500 usf4/in) HALLIBURTON Database: NORTH US + CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: Plan: MPU M -25i Wellbore: MPU M -25i Design: MPU M-25 wp07 Halliburton Standard Proposal Report Local Co-ordinate Reference: Well Plan: MPU M -25i TVD Reference: MPU M-25 Actual RKB @ 58.90usft (D-14) MD Reference: MPU M-25 Actual RKB @ 58.90usft (D-14) North Reference: True Survey Calculation Method: Minimum Curvature Project Milne Point, ACT, MILNE POINT Map System: US State 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 6,027,877.65usft Latitude: 533,363.92 usft Longitude: 13-3/16" Grid Convergence: 6,027,889.56 usft Latitude: 533,543.90 usft Longitude: usft Ground Level: 70° 29' 13.905 N 149° 43'38.286 W 0.26 ° 70° 29' 14.014 N 149° 43'32.988 W 25.20 usft Wellbore MPU M -25i Site M Pt Moose Pad Site Position: Northing: From: Map Easting: Position Uncertainty: 5.00 usft Slot Radius: Well Plan: MPU M -25i, Slot 18 Magnetics Well Position +Nl-S 0.00 usft Northing: +El -W 0.00 usft Easting: Position Uncertainty 0.50 usft Wellhead Elevation: 6,027,877.65usft Latitude: 533,363.92 usft Longitude: 13-3/16" Grid Convergence: 6,027,889.56 usft Latitude: 533,543.90 usft Longitude: usft Ground Level: 70° 29' 13.905 N 149° 43'38.286 W 0.26 ° 70° 29' 14.014 N 149° 43'32.988 W 25.20 usft Wellbore MPU M -25i Magnetics Model Name Sample Date Declination Dip Angle Field Strength (nT) BGGM2019 2/20/2020 16.12 80.90 57,396.67386711 Design MPU M-25 wp07 Audit Notes: Version: Phase: PLAN Tie On Depth: 33.70 Vertical Section: Depth From (TVD) +N/ -S +E/ -W Direction (usft) (usft) (usft) (°) 33.70 0.00 0.00 184.56 Plan Sections Measured Vertical TVD Dogleg Build Turn Depth Inclination Azimuth Depth System +N/ -S +E/ -W Rate Rate Rate Tool Face (usft) (°) (1 (usft) usft (usft) (usft) (°/100usft) (°/100usft) (°/100usft) (°) 33.70 0.00 0.00 33.70 -25.20 0.00 0.00 0.00 0.00 0.00 0.00 470.00 0.00 0.00 470.00 411.10 0.00 0.00 0.00 0.00 0.00 0.00 550.00 2.40 330.00 549.98 491.08 1.45 -0.84 3.00 3.00 0.00 330.00 650.00 6.40 330.00 649.66 590.76 8.09 -4.67 4.00 4.00 0.00 0.00 1,845.86 51.17 273.65 1,679.32 1,620.42 100.92 -533.92 4.00 3.74 -4.71 -61.03 3,236.31 51.17 273.65 2,551.23 2,492.33 169.85 -1,614.83 0.00 0.00 0.00 0.00 5,454.93 85.00 181.23 3,552.11 3,493.21 -1,156.37 -2,734.19 4.00 1.53 -4.17 -95.41 5,704.93 85.00 181.23 3,573.90 3,515.00 -1,405.36 -2,739.54 0.00 0.00 0.00 0.00 5,849.00 90.76 181.23 3,579.22 3,520.32 -1,549.24 -2,742.63 4.00 4.00 0.00 0.04 8,877.13 90.76 181.23 3,538.90 3,480.00 -4,576.40 -2,807.85 0.00 0.00 0.00 0.00 8,959.27 90.94 184.52 3,537.68 3,478.78 -4,658.41 -2,811.96 4.00 0.22 3.99 86.89 12,237.05 90.94 184.52 3,483.90 3,425.00 -7,925.58 -3,069.98 0.00 0.00 0.00 0.00 12,256.43 90.17 184.56 3,483.71 3,424.81 -7,944.90 -3,071.51 4.00 -3.99 0.25 176.47 13,915.96 90.17 184.56 3,478.90 3,420.00 -9,599.16 -3,203.54 0.00 0.00 0.00 0.00 1128/2020 3:10.34PM Page 2 COMPASS 5000.15 Build 91E �%" HALLIBURTON Database: NORTH US + CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: Plan: MPU M -25i Wellbore: MPU M -25i Design: MPU M-25 wp07 Planned Survey Measured Map Vertical Depth Inclination Azimuth Depth TVDss (usft) V) (1) (usft) usft 33.70 0.00 0.00 33.70 -25.20 100.00 0.00 0.00 100.00 41.10 200.00 0.00 0.00 200.00 141.10 300.00 0.00 0.00 300.00 241.10 400.00 0.00 0.00 400.00 341.10 470.00 0.00 0.00 470.00 411.10 Start Dir 3°/100' : 470' MD, 4707VD 533,543.90 0.00 500.00 0.90 330.00 500.00 441.10 550.00 2.40 330.00 549.98 491.08 Start Dir 4°/100' : 550' MD, 549.987VD 3.00 -0.19 600.00 4.40 330.00 599.89 540.99 650.00 6.40 330.00 649.66 590.76 700.00 7.57 316.60 699.29 640.39 800.00 10.68 300.43 798.03 739.13 900.00 14.24 291.85 895.67 836.77 1,000.00 17.98 286.70 991.73 932.83 1,100.00 21.81 283.30 1,085.75 1,026.85 1,200.00 25.69 280.88 1,177.27 1,118.37 1,300.00 29.60 279.06 1,265.84 1,206.94 1,400.00 33.53 277.63 1,351.03 1,292.13 1,500.00 37.47 276.47 1,432.43 1,373.53 1,600.00 41.42 275.50 1,509.64 1,450.74 1,700.00 45.38 274.67 1,582.28 1,523.38 1,800.00 49.35 273.95 1,650.00 1,591.10 1,845.86 51.17 273.65 1,679.32 1,620.42 End Dir : 1845.86' MD, 1679.32' ND 93.06 1,900.00 51.17 273.65 1,713.27 1,654.37 2,000.00 51.17 273.65 1,775.98 1,717.08 2,100.00 51.17 273.65 1,838.69 1,779.79 2,200.00 51.17 273.65 1,901.39 1,842.49 2,300.00 51.17 273.65 1,964.10 1,905.20 2,400.00 51.17 273.65 2,026.81 1,967.91 2,500.00 51.17 273.65 2,089.51 2,030.61 2,600.00 51.17 273.65 2,152.22 2,093.32 2,700.00 51.17 273.65 2,214.93 2,156.03 2,800.00 51.17 273.65 2,277.63 2,218.73 2,900.00 51.17 273.65 2,340.34 2,281.44 3,000.00 51.17 273.65 2,403.05 2,344.15 3,100.00 51.17 273.65 2,465.76 2,406.86 3,200.00 51.17 273.65 2,528.46 2,469.56 3,236.31 51.17 273.65 2,551.23 2,492.33 Start Dir 40/100' : 3236.31' MD, 2551.23'TVD -1,353.39 3,300.00 50.97 270.38 2,591.26 2,532.36 3,400.00 50.85 265.23 2,654.34 2,595.44 3,500.00 50.96 260.08 2,717.43 2,658.53 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Halliburton Standard Proposal Report Well Plan: MPU M -25i MPU M-25 Actual RKB @ 58.90usft (D-14) MPU M-25 Actual RKB @ 58.90usft (D-14) True Minimum Curvature 171.60 -1,664.34 6,028,053.63 531,878.97 4.00 -38.74 168.63 -1,741.85 6,028,050.32 531,801.48 4.00 -29.62 158.72 -1,818.77 6,028,040.06 531,724.61 4.00 -13.62 112812020 3:10:34PM Page 3 COMPASS 5000.15 Build 91E Map Map +N/ -S +E/ -W Northing Easting DLS Vert Section (usft) (usft) (usft) (usft) -25.20 0.00 0.00 6,027,889.56 533,543.90 0.00 0.00 0.00 0.00 6,027,889.56 533,543.90 0.00 0.00 0.00 0.00 6,027,889.56 533,543.90 0.00 0.00 0.00 0.00 6,027,889.56 533,543.90 0.00 0.00 0.00 0.00 6,027,889.56 533,543.90 0.00 0.00 0.00 0.00 6,027,889.56 533,543.90 0.00 0.00 0.20 -0.12 6,027,889.76 533,543.78 3.00 -0.19 1.45 -0.84 6,027,891.01 533,543.06 3.00 -1.38 4.02 -2.32 6,027,893.57 533,541.56 4.00 -3.82 8.09 -4.67 6,027,897.63 533,539.19 4.00 -7.70 12.90 -8.33 6,027,902.42 533,535.51 4.00 -12.20 22.39 -20.85 6,027,911.85 533,522.95 4.00 -20.66 31.66 -40.26 6,027,921.03 533,503.50 4.00 -28.36 40.67 -66.46 6,027,929.93 533,477.26 4.00 -35.26 49.38 -99.33 6,027,938.49 533,444.36 4.00 -41.33 57.75 -138.71 6,027,946.68 533,404.95 4.00 -46.54 65.73 -184.39 6,027,954.45 533,359.23 4.00 -50.86 73.29 -236.17 6,027,961.78 533,307.42 4.00 -54.28 80.39 -293.79 6,027,968.61 533,249.78 4.00 -56.78 86.99 -356.97 6,027,974.93 533,186.58 4.00 -58.33 93.06 -425.40 6,027,980.69 533,118.13 4.00 -58.95 98.58 -498.74 6,027,985.88 533,044.77 4.00 -58.62 100.92 -533.92 6,027,988.06 533,009.58 4.00 -58.15 103.60 -576.01 6,027,990.55 532,967.49 0.00 -57.48 108.56 -653.75 6,027,995.16 532,889.73 0.00 -56.24 113.52 -731.49 6,027,999.76 532,811.98 0.00 -55.00 118.47 -809.23 6,028,004.37 532,734.23 0.00 -53.76 123.43 -886.96 6,028,008.98 532,656.48 0.00 -52.52 128.39 -964.70 6,028,013.59 532,578.72 0.00 -51.29 133.35 -1,042.44 6,028,018.19 532,500.97 0.00 -50.05 138.31 -1,120.18 6,028,022.80 532,423.22 0.00 -48.81 143.26 -1,197.92 6,028,027.41 532,345.47 0.00 -47.57 148.22 -1,275.66 6,028,032.01 532,267.71 0.00 -46.33 153.18 -1,353.39 6,028,036.62 532,189.96 0.00 -45.10 158.14 -1,431.13 6,028,041.23 532,112.21 0.00 -43.86 163.10 -1,508.87 6,028,045.83 532,034.46 0.00 -42.62 168.05 -1,586.61 6,028,050.44 531,956.71 0.00 -41.38 169.85 -1,614.84 6,028,052.11 531,928.47 0.00 -40.93 171.60 -1,664.34 6,028,053.63 531,878.97 4.00 -38.74 168.63 -1,741.85 6,028,050.32 531,801.48 4.00 -29.62 158.72 -1,818.77 6,028,040.06 531,724.61 4.00 -13.62 112812020 3:10:34PM Page 3 COMPASS 5000.15 Build 91E Database: NORTH US + CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: ""' M Pt Moose Pad Well: Plan: MPU M -25i Wellbore: MPU M -25i Design: MPU M-25 wp07 Planned Survey Halliburton Standard Proposal Report Local Co-ordinate Reference: Well Plan: MPU M -25i TVD Reference: MPU M-25 Actual RKB @ 58.90usft (D-14) MD Reference: MPU M-25 Actual RKB @ 58.90usft (D-14) North Reference: True Survey Calculation Method: Minimum Curvature Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/ -S +E/ -W Northing Easting DLS Vert Section (usft) (1) (1) (usft) usft (usft) (usft) (usft) (usft) 2,721.32 3,600.00 51.29 254.96 2,780.22 2,721.32 141.89 -1,894.74 6,028,022.89 531,648.73 4.00 9.19 3,700.00 51.84 249.90 2,842.41 2,783.51 118.25 -1,969.36 6,027,998.91 531,574.22 4.00 38.70 3,800.00 52.61 244.93 2,903.69 2,844.79 87.89 -2,042.29 6,027,968.23 531,501.43 4.00 74.76 3,900.00 53.57 240.08 2,963.77 2,904.87 50.98 -2,113.17 6,027,931.00 531,430.73 4.00 117.19 4,000.00 54.73 235.35 3,022.35 2,963.45 7.68 -2,181.65 6,027,887.40 531,362.45 4.00 165.79 4,100.00 56.07 230.77 3,079.15 3,020.25 -41.78 -2,247.40 6,027,837.64 531,296.93 4.00 220.33 4,200.00 57.58 226.34 3,133.89 3,074.99 -97.18 -2,310.10 6,027,781.97 531,234.49 4.00 280.53 4,300.00 59.23 222.07 3,186.30 3,127.40 -158.23 -2,369.45 6,027,720.66 531,175.43 4.00 346.11 4,400.00 61.01 217.94 3,236.13 3,177.23 -224.64 -2,425.14 6,027,654.00 531,120.03 4.00 416.74 4,500.00 62.92 213.96 3,283.14 3,224.24 -296.09 -2,476.92 6,027,582.33 531,068.58 4.00 492.08 4,600.00 64.94 210.11 3,327.09 3,268.19 -372.24 -2,524.53 6,027,505.98 531,021.32 4.00 571.76 4,700.00 67.05 206.39 3,367.78 3,308.88 -452.69 -2,567.74 6,027,425.33 530,978.48 4.00 655.40 4,800.00 69.25 202.79 3,405.00 3,346.10 -537.08 -2,606.33 6,027,340.78 530,940.27 4.00 742.59 4,900.00 71.52 199.29 3,438.57 3,379.67 -624.98 -2,640.13 6,027,252.74 530,906.88 4.00 832.90 5,000.00 73.85 195.89 3,468.33 3,409.43 -715.97 -2,668.96 6,027,161.63 530,878.46 4.00 925.89 5,100.00 76.24 192.57 3,494.14 3,435.24 -809.60 -2,692.69 6,027,067.90 530,855.16 4.00 1,021.12 5,200.00 78.67 189.31 3,515.87 3,456.97 -905.42 -2,711.19 6,026,972.01 530,837.09 4.00 1,118.10 5,300.00 81.13 186.11 3,533.41 3,474.51 -1,002.96 -2,724.39 6,026,874.42 530,824.33 4.00 1,216.38 5,400.00 83.62 182.95 3,546.67 3,487.77 -1,101.75 -2,732.21 6,026,775.61 530,816.96 4.00 1,315.48 5,454.93 85.00 181.23 3,552.11 3,493.21 -1,156.37 -2,734.19 6,026,720.99 530,815.22 4.00 1,370.09 End Dir : 5454.93' MD, 3552.11' TVD 5,500.00 85.00 181.23 3,556.04 3,497.14 -1,201.26 -2,735.15 6,026,676.10 530,814.46 0.00 1,414.91 5,600.00 85.00 181.23 3,564.76 3,505.86 -1,300.85 -2,737.29 6,026,576.50 530,812.77 0.00 1,514.36 5,704.93 85.00 181.23 3,573.90 3,515.00 -1,405.36 -2,739.54 6,026,472.00 530,811.00 0.00 1,618.71 Start Dir 4°/100' : 5704.93' MD, 3573.9'TVD - 9 5/8" x 121/4" 5,800.00 88.80 181.23 3,579.04 3,520.14 -1,500.25 -2,741.58 6,026,377.11 530,809.39 4.00 1,713.47 5,849.00 90.76 181.23 3,579.22 3,520.32 -1,549.24 -2,742.63 6,026,328.12 530,808.55 4.00 1,762.38 End Dir : 5849' MD, 3579.22' TVD 5,900.00 90.76 181.23 3,578.54 3,519.64 -1,600.22 -2,743.73 6,026,277.14 530,807.69 0.00 1,813.29 6,000.00 90.76 181.23 3,577.21 3,518.31 -1,700.19 -2,745.88 6,026,177.17 530,805.98 0.00 1,913.11 6,100.00 90.76 181.23 3,575.88 3,516.98 -1,800.16 -2,748.04 6,026,077.20 530,804.28 0.00 2,012.94 6,200.00 90.76 181.23 3,574.55 3,515.65 -1,900.13 -2,750.19 6,025,977.24 530,802.58 0.00 2,112.76 6,300.00 90.76 181.23 3,573.22 3,514.32 -2,000.09 -2,752.34 6,025,877.27 530,800.88 0.00 2,212.58 6,400.00 90.76 181.23 3,571.89 3,512.99 -2,100.06 -2,754.50 6,025,777.30 530,799.17 0.00 2,312.41 6,500.00 90.76 181.23 3,570.55 3,511.65 -2,200.03 -2,756.65 6,025,677.34 530,797.47 0.00 2,412.23 6,600.00 90.76 181.23 3,569.22 3,510.32 -2,300.00 -2,758.80 6,025,577.37 530,795.77 0.00 2,512.05 6,700.00 90.76 181.23 3,567.89 3,508.99 -2,399.97 -2,760.96 6,025,477.40 530,794.07 0.00 2,611.87 6,800.00 90.76 181.23 3,566.56 3,507.66 -2,499.93 -2,763.11 6,025,377.44 530,792.36 0.00 2,711.70 6,900.00 90.76 181.23 3,565.23 3,506.33 -2,599.90 -2,765.27 6,025,277.47 530,790.66 0.00 2,811.52 7,000.00 90.76 181.23 3,563.90 3,505.00 -2,699.87 -2,767.42 6,025,177.50 530,788.96 0.00 2,911.34 7,100.00 90.76 181.23 3,562.56 3,503.66 -2,799.84 -2,769.57 6,025,077.54 530,787.26 0.00 3,011.16 7,200.00 90.76 181.23 3,561.23 3,502.33 -2,899.81 -2,771.73 6,024,977.57 530,785.55 0.00 3,110.99 7,300.00 90.76 181.23 3,559.90 3,501.00 -2,999.77 -2,773.88 6,024,877.60 530,783.85 0.00 3,210.81 7,400.00 90.76 181.23 3,558.57 3,499.67 -3,099.74 -2,776.03 6,024,777.64 530,782.15 0.00 3,310.63 7,500.00 90.76 181.23 3,557.24 3,498.34 -3,199.71 -2,778.19 6,024,677.67 530,780.45 0.00 3,410.45 1/28/2020 3:10:34PM Page 4 COMPASS 5000.15 Build 91E Database: NORTH US + CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: Plan: MPU M -25i Wellbore: MPU M -25i Design: MPU M-25 wp07 Planned Survey Measured -2,815.17 Map Vertical 0.00 Depth Inclination Azimuth Depth TVDss (usft) (1) (1) (usft) usft 7,600.00 90.76 181.23 3,555.91 3,497.01 7,700.00 90.76 181.23 3,554.58 3,495.68 7,800.00 90.76 181.23 3,553.24 3,494.34 7,900.00 90.76 181.23 3,551.91 3,493.01 8,000.00 90.76 181.23 3,550.58 3,491.68 8,100.00 90.76 181.23 3,549.25 3,490.35 8,200.00 90.76 181.23 3,547.92 3,489.02 8,300.00 90.76 181.23 3,546.59 3,487.69 8,400.00 90.76 181.23 3,545.25 3,486.35 8,500.00 90.76 181.23 3,543.92 3,485.02 8,600.00 90.76 181.23 3,542.59 3,483.69 8,700.00 90.76 181.23 3,541.26 3,482.36 8,800.00 90.76 181.23 3,539.93 3,481.03 8,877.13 90.76 181.23 3,538.90 3,480.00 Start Dir 4°/100' : 8877.13' MD, 3538.9'TVD 530,760.02 8,900.00 90.81 182.15 3,538.59 3,479.69 8,959.27 90.94 184.52 3,537.68 3,478.78 End Dir : 8959.27' MD, 3537.68' ND 530,757.00 9,000.00 90.94 184.52 3,537.01 3,478.11 9,100.00 90.94 184.52 3,535.37 3,476.47 9,200.00 90.94 184.52 3,533.73 3,474.83 9,300.00 90.94 184.52 3,532.09 3,473.19 9,400.00 90.94 184.52 3,530.45 3,471.55 9,500.00 90.94 184.52 3,528.81 3,469.91 9,600.00 90.94 184.52 3,527.17 3,468.27 9,700.00 90.94 184.52 3,525.53 3,466.63 9,800.00 90.94 184.52 3,523.88 3,464.98 9,900.00 90.94 184.52 3,522.24 3,463.34 10,000.00 90.94 184.52 3,520.60 3,461.70 10,100.00 90.94 184.52 3,518.96 3,460.06 10,200.00 90.94 184.52 3,517.32 3,458.42 10,300.00 90.94 184.52 3,515.68 3,456.78 10,400.00 90.94 184.52 3,514.04 3,455.14 10,500.00 90.94 184.52 3,512.40 3,453.50 10,600.00 90.94 184.52 3,510.76 3,451.86 10,700.00 90.94 184.52 3,509.12 3,450.22 10,800.00 90.94 184.52 3,507.48 3,448.58 10,900.00 90.94 184.52 3,505.84 3,446.94 11,000.00 90.94 184.52 3,504.20 3,445.30 11,100.00 90.94 184.52 3,502.56 3,443.66 11,200.00 90.94 184.52 3,500.91 3,442.01 11,300.00 90.94 184.52 3,499.27 3,440.37 11,400.00 90.94 184.52 3,497.63 3,438.73 11,500.00 90.94 184.52 3,495.99 3,437.09 11,600.00 90.94 184.52 3,494.35 3,435.45 Local Co-ordinate Reference TVD Reference: MD Reference: North Reference: Survey Calculation Method: Halliburton Standard Proposal Report Well Plan: MPU M -25i MPU M-25 Actual RKB @ 58.90usft (D-14) MPU M-25 Actual RKB @ 58.90usft (D-14) True Minimum Curvature -4,699.01 -2,815.17 Map Map 0.00 4,907.95 +N/ -S +E/ -W Northing Easting DLS Vert Section (usft) (usft) (usft) (usft) 3,497.01 5,107.93 -3,299.68 -2,780.34 6,024,577.70 530,778.74 0.00 3,510.28 -3,399.64 -2,782.49 6,024,477.74 530,777.04 0.00 3,610.10 -3,499.61 -2,784.65 6,024,377.77 530,775.34 0.00 3,709.92 -3,599.58 -2,786.80 6,024,277.80 530,773.64 0.00 3,809.75 -3,699.55 -2,788.96 6,024,177.84 530,771.93 0.00 3,909.57 -3,799.52 -2,791.11 6,024,077.87 530,770.23 0.00 4,009.39 -3,899.48 -2,793.26 6,023,977.90 530,768.53 0.00 4,109.21 -3,999.45 -2,795.42 6,023,877.94 530,766.83 0.00 4,209.04 -4,099.42 -2,797.57 6,023,777.97 530,765.12 0.00 4,308.86 -4,199.39 -2,799.72 6,023,678.00 530,763.42 0.00 4,408.68 -4,299.36 -2,801.88 6,023,578.04 530,761.72 0.00 4,508.50 -4,399.32 -2,804.03 6,023,478.07 530,760.02 0.00 4,608.33 -4,499.29 -2,806.18 6,023,378.10 530,758.31 0.00 4,708.15 -4,576.40 -2,807.85 6,023,301.00 530,757.00 0.00 4,785.14 -4,599.26 -2,808.52 6,023,278.14 530,756.43 4.00 4,807.98 -4,658.41 -2,811.96 6,023,218.97 530,753.25 4.00 4,867.23 -4,699.01 -2,815.17 6,023,178.36 530,750.23 0.00 4,907.95 -4,798.69 -2,823.04 6,023,078.66 530,742.81 0.00 5,007.94 -4,898.36 -2,830.91 6,022,978.96 530,735.39 0.00 5,107.93 -4,998.04 -2,838.78 6,022,879.26 530,727.97 0.00 5,207.91 -5,097.72 -2,846.66 6,022,779.56 530,720.54 0.00 5,307.90 -5,197.39 -2,854.53 6,022,679.86 530,713.12 0.00 5,407.88 -5,297.07 -2,862.40 6,022,580.16 530,705.70 0.00 5,507.87 -5,396.75 -2,870.27 6,022,480.46 530,698.28 0.00 5,607.86 -5,496.42 -2,878.14 6,022,380.76 530,690.86 0.00 5,707.84 -5,596.10 -2,886.01 6,022,281.06 530,683.44 0.00 5,807.83 -5,695.77 -2,893.89 6,022,181.36 530,676.02 0.00 5,907.82 -5,795.45 -2,901.76 6,022,081.65 530,668.60 0.00 6,007.80 -5,895.13 -2,909.63 6,021,981.95 530,661.17 0.00 6,107.79 -5,994.80 -2,917.50 6,021,882.25 530,653.75 0.00 6,207.78 -6,094.48 -2,925.37 6,021,782.55 530,646.33 0.00 6,307.76 -6,194.15 -2,933.24 6,021,682.85 530,638.91 0.00 6,407.75 -6,293.83 -2,941.12 6,021,583.15 530,631.49 0.00 6,507.74 -6,393.51 -2,948.99 6,021,483.45 530,624.07 0.00 6,607.72 -6,493.18 -2,956.86 6,021,383.75 530,616.65 0.00 6,707.71 -6,592.86 -2,964.73 6,021,284.05 530,609.23 0.00 6,807.70 -6,692.54 -2,972.60 6,021,184.35 530,601.80 0.00 6,907.68 -6,792.21 -2,980.47 6,021,084.65 530,594.38 0.00 7,007.67 -6,891.89 -2,988.35 6,020,984.94 530,586.96 0.00 7,107.66 -6,991.56 -2,996.22 6,020,885.24 530,579.54 0.00 7,207.64 -7,091.24 -3,004.09 6,020,785.54 530,572.12 0.00 7,307.63 -7,190.92 -3,011.96 6,020,685.84 530,564.70 0.00 7,407.61 -7,290.59 -3,019.83 6,020,586.14 530,557.28 0.00 7,507.60 112W020 3:10:34PM Page 5 COMPASS 5000.15 Build 91E Database: NORTH US + CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: Plan: MPU M -25i Wellbore: MPU M -25i Design: MPU M-25 wp07 Planned Survey Measured Map Vertical Depth Inclination Azimuth Depth TVDss (usft) (°) (°) (usft) usft 11,700.00 90.94 184.52 3,492.71 3,433.81 11,800.00 90.94 184.52 3,491.07 3,432.17 11,900.00 90.94 184.52 3,489.43 3,430.52 12,000.00 90.94 184.52 3,487.79 3,428.89 12,100.00 90.94 184.52 3,486.15 3,427.2E 12,200.00 90.94 184.52 3,484.51 3,425.61 12,237.05 90.94 184.52 3,483.90 3,425.00 Start Dir 4'/100': 12237.05' MD, 3483.9'TVD 12,256.43 90.17 184.56 3,483.71 3,424.81 End Dir : 12256.43' MD, 3483.71' TVD 6,019,951.00 12,300.00 90.17 184.56 3,483.59 3,424.69 12,400.00 90.17 184.56 3,483.30 3,424.4C 12,500.00 90.17 184.56 3,483.01 3,424.11 12,600.00 90.17 184.56 3,482.72 3,423.82 12,700.00 90.17 184.56 3,482.43 3,423.53 12,800.00 90.17 184.56 3,482.14 3,423.24 12,900.00 90.17 184.56 3,481.85 3,422.95 13,000.00 90.17 184.56 3,481.56 3,422.66 13,100.00 90.17 184.56 3,481.27 3,422.37 13,200.00 90.17 184.56 3,480.98 3,422.08 13,300.00 90.17 184.56 3,480.69 3,421.79 13,400.00 90.17 184.56 3,480.40 3,421.50 13,500.00 90.17 184.56 3,480.11 3,421.21 13,600.00 90.17 184.56 3,479.82 3,420.92 13,700.00 90.17 184.56 3,479.53 3,420.63 13,800.00 90.17 184.56 3,479.24 3,420.34 13,900.00 90.17 184.56 3,478.95 3,420.05 13,915.96 90.17 184.56 3,478.90 3,420.00 Total Depth: 13915.96' MD, 3478.9' TVD 0.00 Halliburton Standard Proposal Report Local Co-ordinate Reference: Well Plan: MPU M -25i TVD Reference: MPU M-25 Actual RKB @ 58.90usft (D-14) MD Reference: MPU M-25 Actual RKB @ 58.90usft (D-14) North Reference: True Survey Calculation Method: Minimum Curvature 1/282020 3:10:34PM Page 6 COMPASS 5000.15 Build 91E Map Map +N/ -S +E/ -W Northing Easting DLS Vert Section (usft) (usft) (usft) (usft) 3,433.81 -7,390.27 -3,027.70 6,020,486.44 530,549.86 0.00 7,607.59 -7,489.95 -3,035.58 6,020,386.74 530,542.43 0.00 7,707.57 -7,589.62 -3,043.45 6,020,287.04 530,535.01 0.00 7,807.56 -7,689.30 -3,051.32 6,020,187.34 530,527.59 0.00 7,907.55 -7,788.97 -3,059.19 6,020,087.64 530,520.17 0.00 8,007.53 -7,888.65 -3,067.06 6,019,987.94 530,512.75 0.00 8,107.52 -7,925.58 -3,069.98 6,019,951.00 530,510.00 0.00 8,144.57 -7,944.90 -3,071.51 6,019,931.67 530,508.55 4.00 8,163.94 -7,988.33 -3,074.98 6,019,888.23 530,505.28 0.00 8,207.51 -8,088.01 -3,082.93 6,019,788.52 530,497.78 0.00 8,307.51 -8,187.70 -3,090.89 6,019,688.82 530,490.27 0.00 8,407.51 -8,287.38 -3,098.85 6,019,589.11 530,482.77 0.00 8,507.51 -8,387.06 -3,106.80 6,019,489.40 530,475.26 0.00 8,607.51 -8,486.74 -3,114.76 6,019,389.69 530,467.76 0.00 8,707.51 -8,586.43 -3,122.71 6,019,289.99 530,460.25 0.00 8,807.51 -8,686.11 -3,130.67 6,019,190.28 530,452.75 0.00 8,907.51 -8,785.79 -3,138.62 6,019,090.57 530,445.24 0.00 9,007.51 -8,885.47 -3,146.58 6,018,990.86 530,437.74 0.00 9,107.51 -8,985.16 -3,154.54 6,018,891.16 530,430.23 0.00 9,207.51 -9,084.84 -3,162.49 6,018,791.45 530,422.72 0.00 9,307.51 -9,184.52 -3,170.45 6,018,691.74 530,415.22 0.00 9,407.51 -9,284.20 -3,178.40 6,018,592.03 530,407.71 0.00 9,507.51 -9,383.89 -3,186.36 6,018,492.32 530,400.21 0.00 9,607.51 -9,483.57 -3,194.32 6,018,392.62 530,392.70 0.00 9,707.51 -9,583.25 -3,202.27 6,018,292.91 530,385.20 0.00 9,807.51 -9,599.16 -3,203.54 6,018,277.00 530,384.00 0.00 9,823.46 1/282020 3:10:34PM Page 6 COMPASS 5000.15 Build 91E Database: NORTH US + CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: Plan: MPU M -25i Wellbore: MPU M -25i Design: MPU M-25 wp07 Targets Target Name Halliburton Standard Proposal Report Local Co-ordinate Reference: Well Plan: MPU M -25i TVD Reference: MPU M-25 Actual RKB @ 58.90usft (D-14) MD Reference: MPU M-25 Actual RKB @ 58.90usft (D-14) North Reference: True Survey Calculation Method: Minimum Curvature hit/miss target Dip Angle Dip Dir. TVD +N/ -S +E/ -W Shape C) (1) (usft) (usft) (usft) MPU M -25i wp05 CP1 0.00 0.00 3,538.90 -4,576.40 -2,807.85 plan hits target center Point MPU M -25i wp05 Toe plan hits target center Point MPU M -25i wp07 Heel plan hits target center Circle (radius 30.00) MPU M -25i wp05 CP2 plan hits target center Point Casing Points Northing Easting (usft) (usft) 6,023,301.00 530,757.00 0.00 0.00 3,478.90 -9,599.16 -3,203.54 6,018,277.00 530,384.00 0.00 0.00 3,573.90 -1,405.36 -2,739.54 6,026,472.00 530,811.00 0.00 0.00 3,483.90 -7,925.58 -3,069.98 6,019,951.00 530,510.00 Measured Vertical Depth Depth (usft) (usft) Name 5,704.93 3,573.90 9 5/8" x 12 1/4" 13,915.96 3,478.90 41/2"x81/2" Plan Annotations Measured Vertical Depth Depth (usft) (usft) 470.00 470.00 550.00 549.98 1,845.86 1,679.32 3,236.31 2,551.23 5,454.93 3,552.11 5,704.93 3,573.90 5,849.00 3,579.22 8,877.13 3,538.90 8,959.27 3,537.68 12,237.05 3,483.90 12,256.43 3,483.71 13,915.96 3,478.90 Casing Hole Diameter C) Diameter (") 9-5/8 12-1/4 4-1/2 8-1/2 Local Coordinates +N/ -S +EI -W (usft) (usft) Comment 0.00 0.00 Start Dir 30/100' : 470' MD, 470'TVD 1.45 -0.84 Start Dir 4°/100' : 550' MD, 549.98'TVD 100.92 -533.92 End Dir : 1845.86' MD, 1679.32' TVD 169.85 -1,614.84 Start Dir 41/100': 3236.31' MD, 2551.23'TVD -1,156.37 -2,734.19 End Dir : 5454.93' MD, 3552.11' TVD -1,405.36 -2,739.54 Start Dir 4°/100' : 5704.93' MD, 3573.9'TVD -1,549.24 -2,742.63 End Dir : 5849' MD, 3579.22' TVD -4,576.40 -2,807.85 Start Dir 4°/100' : 8877.13' MD, 3538.9'TVD -4,658.41 -2,811.96 End Dir : 8959.27' MD, 3537.68' TVD -7,925.58 -3,069.98 Start Dir 41/100' : 12237.05' MD, 3483.9'TVD -7,944.90 -3,071.51 End Dir : 12256.43' MD, 3483.71' TVD -9,599.16 -3,203.54 Total Depth : 13915.96' MD, 3478.9' TVD 1128/2020 3:10:34PM Page 7 COMPASS 5000.15 Build 91E Hilcorp Alaska, LLC Milne Point M Pt Moose Pad Plan: MPU M -25i MPU M -25i MPU M-25 wp07 Sperry Drilling Services Clearance Summary Anticollision Report 28 January, 2020 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt Moose Pad - Plan: MPU M -25i - MPU M -25i - MPU M-25 Wp07 Well Coordinates: 6,027,889.56 N, 533,543.90 E (70° 29'14.01" N, 149'43'32.99" W) Datum Height: MPU M-25 Actual RKB @ 58.90usft (D-14) Scan Range:33.70 to 5,704.93 usft. Measured Depth. Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usft Geodetic Scale Factor Applied Version: 5000.15 Build: 91E Scan Type: GLOBAL FILTERAPPLIED : All wellpaths within 200'+ 100/1000 of reference Scan Type: 25.00 HALLIBURTON Sperry Drilling Services HALLIBURTON Anticollision Report for Plan: MPU M -25i - MPU M-25 wp07 Hilcorp Alaska, LLC Milne Point Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) 152.07 Reference Design: M Pt Moose Pad - Plan: MPU M-251 - MPU M-251 - MPU M-25 wp07 146.62 Scan Range: 33.70 to 5,704.93 usft. Measured Depth. 27.921 Centre Distance Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 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 Moose Pad MPU M-03 - MPU M-03 - MPU M-03 MPU M-03 - MPU M-03 - MPU M-03 MPU M-03 - MPU M-03 - MPU M-03 MPU M-04 - MPU M-04 - MPU M-04 MPU M-04 - MPU M-04 - MPU M-04 MPU M-04 - MPU M-04 - MPU M-04 MPU M-06 - MPU M-06 - MPU M-06 MPU M-06 - MPU M-06 - MPU M-06 MPU M-06 - MPU M-06 - MPU M-06 MPU M-16 - MPU M-16 - MPU M-16 MPU M-16 - MPU M-16 - MPU M-16 MPU M-16 - MPU M-16 - MPU M-16 MPU M -17i - MPU M -17i - MPU M -17i MPU M -17i - MPU M -17i - MPU M -17i MPU M -17i - MPU M -17i - MPU M -17i MPU M-18 - MPU M-18 - MPU M-18 MPU M-18 - MPU M-18 - MPU M-18 MPU M-18 - MPU M-18 - MPU M-18 MPU M-18 - MPU M-18PB1 - MPU M-18PB1 MPU M-18 - MPU M-18PB1 - MPU M-18PB1 MPU M-18 - MPU M-18PB1 - MPU M-18PB1 MPU M-18 - MPU M-18PB2 - MPU M-18PB2 MPU M-18 - MPU M-18PB2 - MPU M-18PB2 MPU M-18 - MPU M-18PB2 - MPU M-18PB2 MPU M -19i - MPU M -19i - MPU M -19i MPU M -19i - MPU M -19i - MPU M -19i MPU M -19i - MPU M-19PB1 - MPU M-19PB1 MPU M -19i - MPU M-19PB1 - MPU M-19PB1 870.85 152.07 870.85 146.62 849.82 27.921 Centre Distance Pass - 883.70 152.13 883.70 146.62 860.79 27.581 Ellipse Separation Pass - 1,033.70 164.81 1,033.70 158.38 985.15 25.639 Clearance Factor Pass - 826.47 130.83 826.47 125.71 816.66 25.556 Centre Distance Pass - 833.70 130.85 833.70 125.69 823.08 25.353 Ellipse Separation Pass - 958.70 139.31 958.70 133.41 930.73 23.642 Clearance Factor Pass - 440.98 269.49 440.98 266.28 440.58 84.104 Centre Distance Pass - 483.70 269.65 483.70 266.20 481.25 78.197 Ellipse Separation Pass - 3,483.70 505.50 3,483.70 426.20 3,235.00 6.375 Clearance Factor Pass - 414.07 216.84 414.07 213.80 414.30 71.307 Centre Distance Pass - 433.70 216.88 433.70 213.73 433.04 68.827 Ellipse Separation Pass - 683.70 243.14 683.70 238.74 653.44 55.249 Clearance Factor Pass - 329.08 152.83 329.08 150.16 329.08 57.274 Centre Distance Pass - 383.70 152.99 383.70 150.00 382.84 51.251 Ellipse Separation Pass - 608.70 169.13 608.70 164.89 590.41 39.860 Clearance Factor Pass - 33.70 137.71 33.70 136.30 34.42 97.552 Centre Distance Pass - 458.70 138.30 458.70 134.86 458.00 40.199 Ellipse Separation Pass - 608.70 149.54 608.70 145.28 600.39 35.069 Clearance Factor Pass - 33.70 137.71 33.70 136.30 34.42 97.552 Centre Distance Pass - 458.70 138.30 458.70 134.86 458.00 40.199 Ellipse Separation Pass - 608.70 149.54 608.70 145.28 600.39 35.069 Clearance Factor Pass - 33.70 137.71 33.70 136.30 34.42 97.552 Centre Distance Pass - 458.70 138.30 458.70 134.86 458.00 40.199 Ellipse Separation Pass - 608.70 149.54 608.70 145.28 600.39 35.069 Clearance Factor Pass - 33.70 127.62 33.70 125.71 34.36 66.765 Ellipse Separation Pass - 558.70 159.57 558.70 155.58 535.71 39.934 Clearance Factor Pass - 33.70 127.62 33.70 125.71 34.36 66.765 Ellipse Separation Pass - 558.70 159.57 558.70 155.58 535.71 39.934 Clearance Factor Pass - 28 January, 2020 - 15:11 Page 2 of 8 COMPASS HALLIBURTON Hilcorp Alaska, LLC Milne Point Anticollision Report for Plan: MPU M -25i - MPU M-25 wp07 528.61 118.00 528.61 114.23 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) 31.353 Centre Distance Pass - MPU M-22 - MPU M-22PB1 - MPU M-22PB1 558.70 118.13 Reference Design: M Pt Moose Pad - Plan: MPU M -25i - MPU M -25i - MPU M-25 Wp07 114.20 560.42 30.020 Ellipse Separation Pass - MPU M-22 - MPU M-22PB1 - MPU M-22PB1 Scan Range: 33.70 to 5,704.93 usff. Measured Depth. 131.76 758.70 126.84 753.83 26.778 Clearance Factor Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usft MPU M-24 - MPU M-24 - MPU M-24 314.47 29.93 314.47 Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on 358.70 Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name - Wellbore Name - Design (usft) (usft) (usft) (usft) usft 558.70 31.18 MPU M -21i - MPU M -21i - MPU M-21 i 217.50 209.91 217.50 207.70 217.47 94.905 Centre Distance Pass - MPU M -21i - MPU M -21i - MPU M-21 i 433.70 210.44 433.70 207.16 432.64 64.212 Ellipse Separation Pass - MPU M-21i-MPUM-21i- MPU M -21i 858.70 256.13 858.70 250.71 840.64 47.267 Clearance Factor Pass - MPU M-22 - MPU M-22 - MPU M-22 528.61 118.00 528.61 114.23 530.53 31.353 Centre Distance Pass - MPU M-22 - MPU M-22 - MPU M-22 558.70 118.13 558.70 114.20 560.42 30.020 Ellipse Separation Pass - MPU M-22 - MPU M-22 - MPU M-22 758.70 131.76 758.70 126.84 753.83 26.778 Clearance Factor Pass - MPU M-22 - MPU M-22PB1 - MPU M-22PB1 528.61 118.00 528.61 114.23 530.53 31.353 Centre Distance Pass - MPU M-22 - MPU M-22PB1 - MPU M-22PB1 558.70 118.13 558.70 114.20 560.42 30.020 Ellipse Separation Pass - MPU M-22 - MPU M-22PB1 - MPU M-22PB1 758.70 131.76 758.70 126.84 753.83 26.778 Clearance Factor Pass - MPU M-24 - MPU M-24 - MPU M-24 314.47 29.93 314.47 27.28 307.52 11.304 Centre Distance Pass - MPU M-24 - MPU M-24 - MPU M-24 358.70 30.05 358.70 27.17 351.59 10.445 Ellipse Separation Pass - MPU M-24 - MPU M-24 - MPU M-24 558.70 35.17 558.70 31.18 549.32 8.813 Clearance Factor Pass - MPU M-24 - MPU M-24PB1 - MPU M-24PB1 314.47 29.93 314.47 27.28 307.52 11.304 Centre Distance Pass - MPU M-24 - MPU M-24PB1 - MPU M-24PB1 358.70 30.05 358.70 27.17 351.59 10.445 Ellipse Separation Pass - MPU M-24 - MPU M-24PB1 - MPU M-24PB1 558.70 35.17 558.70 31.18 549.32 8.813 Clearance Factor Pass - MPU M-24 - MPU M-24PB2 - MPU M-24PB2 314.47 29.93 314.47 27.28 307.52 11.304 Centre Distance Pass - MPU M-24 - MPU M-24PB2 - MPU M-24PB2 358.70 30.05 358.70 27.17 351.59 10.445 Ellipse Separation Pass - MPU M-24 - MPU M-24PB2 - MPU M-24PB2 558.70 35.17 558.70 31.18 549.32 8.813 Clearance Factor Pass - MPU M-24 - MPU M-24PB3 - MPU M-24PB3 314.47 29.93 314.47 27.28 307.52 11.304 Centre Distance Pass - MPU M-24 - MPU M-24PB3 - MPU M-2413133 358.70 30.05 358.70 27.17 351.59 10.445 Ellipse Separation Pass - MPU M-24 - MPU M-24PB3 - MPU M-24PB3 558.70 35.17 558.70 31.18 549.32 8.813 Clearance Factor Pass - MPU M-26 - MPU M-26 - MPU M-26 33.70 119.99 33.70 118.58 26.15 85.001 Centre Distance Pass - MPU M-26 - MPU M-26 - MPU M-26 83.70 120.06 83.70 118.55 75.91 79.183 Ellipse Separation Pass - MPU M-26 - MPU M-26 - MPU M-26 4,383.70 835.80 4,383.70 757.32 4,058.39 10.649 Clearance Factor Pass - MPU M-26 - MPU M-26PB1 - MPU M-26PB1 33.70 119.99 33.70 118.58 26.15 85.001 Centre Distance Pass - MPU M-26 - MPU M-26PB1 - MPU M-26PB1 83.70 120.06 83.70 118.55 75.91 79.183 Ellipse Separation Pass - MPU M-26 - MPU M-26PB1 - MPU M-26PB1 4,383.70 835.80 4,383.70 757.31 4,058.39 10.648 Clearance Factor Pass - Plan: Kup S1 Deep KOP - Slot 17 - Kup S1 - Kup S1 w 458.70 123.57 458.70 119.81 458.50 32.830 Centre Distance Pass - Plan: Kup S1 Deep KOP - Slot 17 - Kup S1 - Kup S1 w 483.70 123.61 483.70 119.70 483.50 31.604 Ellipse Separation Pass - Plan: Kup S1 Deep KOP - Slot 17 - Kup S1 - Kup S1 w 5,704.93 1,515.36 5,704.93 1,431.63 4,812.32 18.097 Clearance Factor Pass - 28 January, 2020 - 15. 11 Page 3 of 8 COMPASS HALLIBURTON Anticollision Report for Plan: MPU M -25i - MPU M-25 wp07 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) 57.549 Centre Distance 283.29 Reference Design: M Pt Moose Pad - Plan: MPU M -25i - MPU M -25i - MPU M-25 wp07 584.29 39.675 Clearance Factor Scan Range: 33.70 to 5,704.93 usft. Measured Depth. 51.923 Centre Distance 283.30 49.792 Ellipse Separation 563.16 Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usft 357.44 Measured Minimum @Measured Ellipse Site Name Depth Distance Depth Separation Comparison Well Name - Wellbore Name - Design (usft) (usft) (usft) (usft) Plan Kup S2 - Slot 11 - Kup S2 - KupS2 wp03 - 200ft 261.51 152.82 261.51 150.16 Plan Kup S2 - Slot 11 - Kup S2 - KupS2 wp03 - 200ft 283.70 152.82 283.70 150.05 Plan: Kup S2 - Slot 11 - Kup S2 - KupS2 wp03 - 200ft 608.70 177.42 608.70 172.95 Plan: Kup S3 - Slot 13 - Kup S3 - Kup S3 Early KOP - 261.51 137.33 261.51 134.68 Plan Kup S3 - Slot 13 - Kup S3 - Kup S3 Early KOP - 283.70 137.33 283.70 134.57 Plan Kup S3 - Slot 13 - Kup S3 - Kup S3 Early KOP - 583.70 159.09 583.70 154.50 Plan: MPU M-07WSW- MPU M-07 (WSW) - M-07WS 310.59 218.27 310.59 214.93 Plan: MPU M-07WSW- MPU M-07 (WSW) - M-07WS 358.70 218.36 358.70 214.76 Plan: MPU M-07WSW - MPU M-07 (WSW) - M-07WS 1,008.70 240.31 1,008.70 233.00 Plan: MPU M-47 (MPU M -21i P2 - Slot 30) - M -21i Pha 411.08 180.12 411.08 176.23 Plan: MPU M-47 (MPU M-211 P2 - Slot 30) - M -21i Pha 483.70 180.22 483.70 175.91 Plan: MPU M-47 (MPU M -21i P2 -Slot 30) - M -21i Pha 783.70 201.85 783.70 196.08 Plan: MPU M-48 - Slot 24 - MPU M48 - MPU M48 wr 503.96 89.72 503.96 85.73 Plan: MPU M48 - Slot 24 - MPU M-48 - MPU M48 wp 533.70 89.81 533.70 85.64 Plan: MPU M-48 - Slot 24 - MPU M48 - MPU M48 wp 733.70 97.71 733.70 92.61 Plan: MPU M-49 - Slot 20 - MPU M49 - MPU M-49 wr 489.62 30.06 489.62 26.14 Plan: MPU M-49 - Slot 20 - MPU M49 - MPU M-49 wp 683.70 30.37 683.70 25.52 Plan: MPU M49 - Slot 20 - MPU M-49 - MPU M49 wp 758.70 31.80 758.70 26.57 Plan: MPU M-50 - Slot 14 - MPU M-50 - MPU M-50 wp Plan: MPU M-50 - Slot 14 - MPU M-50 - MPU M-50 wp Plan: MPU M-50 - Slot 14 - MPU M-50 - MPU M-50 wp q Ian: MPU M-51 - Slot 12 - MPU M-51 - MPU M-51 wr Plan: MPU M-51 - Slot 12 - MPU M-51 - MPU M-51 wp Plan: MPU M-51 - Slot 12 - MPU M-51 - MPU M-51 wp Plan: MPU M-52 - Slot 09 - MPU M-52 - MPU M-52 wp Plan: MPU M-52 - Slot 09 - MPU M-52 - MPU M-52 wp Plan: MPU M-52 - Slot 09 - MPU M-52 - MPU M-52 wp Plan: MPU M-58(IRA) - Slot 28 - MPU M-58 - MPU M= Plan: MPU M-58(IRA) - Slot 28 - MPU M-58 - MPU M= Plan: MPU M-58(IRA) - Slot 28 - MPU M-58 - MPU M-' @Measured Clearance Summary Based on Depth Factor Minimum usft 261.31 57.549 Centre Distance 283.29 55.179 Ellipse Separation 584.29 39.675 Clearance Factor 261.31 51.923 Centre Distance 283.30 49.792 Ellipse Separation 563.16 34.716 Clearance Factor 310.39 65.335 Centre Distance 357.44 60.727 Ellipse Separation 978.52 32.854 Clearance Factor 410.88 46.272 Centre Distance 483.02 41.825 Ellipse Separation 777.18 34.981 Clearance Factor 504.57 22.444 Centre Distance 534.47 21.526 Ellipse Separation 734.47 19.151 Clearance Factor 489.57 7.679 Centre Distance 685.65 6.264 Ellipse Separation 761.35 6.082 Clearance Factor 311.51 59.91 311.51 57.00 311.31 20.603 Centre Distance 358.70 60.04 358.70 56.88 357.93 18.981 Ellipse Separation 1,733.70 264.52 1,733.70 246.59 1,641.16 14.756 Clearance Factor 261.51 172.19 261.51 169.54 261.31 64.889 Centre Distance 383.70 172.42 383.70 169.11 382.69 52.066 Ellipse Separation 4,633.70 762.90 4,633.70 680.82 4,284.75 9.295 Clearance Factor 458.70 149.86 458.70 146.13 458.50 40.120 Centre Distance 483.70 149.89 483.70 146.01 483.50 38.623 Ellipse Separation 4,983.70 959.05 4,983.70 892.49 4,831.54 14.410 Clearance Factor Hilcorp Alaska, LLC Milne Point Separation Warning Pass - Pass- Pass- Pass- Pass- Pass- Pass- Pass- Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - 28 January, 2020 - 15:11 Page 4 of 8 COMPASS HALLIBURTON Hilcorp Alaska, LLC Milne Point Anticollision Report for Plan: MPU M -25i - MPU M-25 wp07 1,100.19 96.61 1,100.19 88.87 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) 12.488 Ellipse Separation Pass - Proposal: MPU M-09DSW-APHill -M-09DSW-APH 1,133.70 98.74 Reference Design: M Pt Moose Pad - Plan: MPU M -25i - MPU M -25i - MPU M-25 wp07 90.77 1,121.98 12.384 Clearance Factor Pass - Proposal: N1 Kuparuk - Slot 34 - MPU M -N1 - Kup N1 Scan Range: 33.70 to 5,704.93 usft. Measured Depth. 238.17 533.88 233.99 537.98 56.948 Centre Distance Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usft Proposal: N1 Kuparuk - Slot 34 - MPU M -N1 - Kup N1 558.70 238.24 558.70 Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on 1,083.70 Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name - Wellbore Name - Design (usft) (usft) (usft) (usft) usft 472.80 55.24 Proposal: MPU M-05DSW - Slot 3 - MPU M-05 (Beaur 261.51 243.89 261.51 241.24 261.31 92.029 Centre Distance Pass - Proposal: MPU M-05DSW - Slot 3 - MPU M-05 (Beaur 283.70 243.89 283.70 241.13 283.14 88.268 Ellipse Separation Pass - Proposal: MPU M-05DSW - Slot 3 - MPU M-05 (Beaur 5,704.93 1,578.46 5,704.93 1,503.14 4,358.58 20.958 Clearance Factor Pass - Proposal: MPU M-08DSW - McLaws - M-08DSW - Mc 455.05 194.13 455.05 190.77 451.08 57.772 Centre Distance Pass - Proposal: MPU M-08DSW - McLaws - M-08DSW - Mc 483.70 194.16 483.70 190.65 479.57 55.387 Ellipse Separation Pass - Proposal: MPU M-08DSW - McLaws - M-08DSW - Mc 833.70 220.78 833.70 216.11 800.00 47.285 Clearance Factor Pass - Proposal: MPU M-09DSW-APHill -M-09DSW-APH 1,100.19 96.61 1,100.19 88.87 1,095.05 12.488 Ellipse Separation Pass - Proposal: MPU M-09DSW-APHill -M-09DSW-APH 1,133.70 98.74 1,133.70 90.77 1,121.98 12.384 Clearance Factor Pass - Proposal: N1 Kuparuk - Slot 34 - MPU M -N1 - Kup N1 533.88 238.17 533.88 233.99 537.98 56.948 Centre Distance Pass - Proposal: N1 Kuparuk - Slot 34 - MPU M -N1 - Kup N1 558.70 238.24 558.70 233.92 563.04 55.140 Ellipse Separation Pass - Proposal: N1 Kuparuk- Slot 34 - MPU M -N1 - Kup N1 1,083.70 328.08 1,083.70 320.27 1,065.87 42.050 Clearance Factor Pass - Rig: MPU M -23i - MPU M -23i - MPU M-23 wp06 472.80 59.05 472.80 55.24 473.21 15.488 Centre Distance Pass - Rig: MPU M -23i - MPU M -23i - MPU M-23 wp06 483.70 59.05 483.70 55.18 484.06 15.235 Ellipse Separation Pass - Rig: MPU M -23i - MPU M -23i - MPU M-23 wp06 683.70 65.21 683.70 60.33 683.57 13.362 Clearance Factor Pass - Rig: MPU M -23i - MPU M -23i - MPU M -23i 33.70 59.98 33.70 58.06 33.79 31.377 Ellipse Separation Pass - Rig: MPU M -23i - MPU M -23i - MPU M -23i 683.70 72.39 683.70 67.82 682.58 15.852 Clearance Factor Pass - Slot 19 - Placeholder - Slot 19 - Placeholder - Slot 19- 458.70 127.19 458.70 123.42 420.80 33.808 Centre Distance Pass - Slot 19 - Placeholder - Slot 19 - Placeholder - Slot 19- 483.70 127.23 483.70 123.32 445.80 32.546 Ellipse Separation Pass - Slot 19 - Placeholder - Slot 19 - Placeholder - Slot 19- 858.70 163.36 858.70 157.56 817.61 28.122 Clearance Factor Pass - Slot 25 - Placeholder - Slot 25 - Placeholder - Slot 25 F 458.70 172.33 458.70 168.58 420.80 45.962 Centre Distance Pass - Slot 25 - Placeholder - Slot 25 - Placeholder - Slot 25 F 483.70 172.38 483.70 168.48 445.80 44.246 Ellipse Separation Pass - Slot 25 - Placeholder - Slot 25 - Placeholder - Slot 25 F 858.70 214.21 858.70 208.42 817.61 36.960 Clearance Factor Pass - Slot 27 - Placeholder - Slot 27 - Placeholder - Slot 27- 458.70 194.43 458.70 190.69 420.80 51.904 Centre Distance Pass - Slot 27 - Placeholder - Slot 27 - Placeholder - Slot 27- 483.70 194.48 483.70 190.59 445.80 49.965 Ellipse Separation Pass - Slot 27 - Placeholder- Slot 27 - Placeholder - Slot 27- 933.70 253.84 933.70 247.61 890.34 40.726 Clearance Factor Pass - Slot 31 - Placeholder- Slot 31 - Placeholder - Slot 31- 458.70 243.76 458.70 240.02 420.80 65.150 Centre Distance Pass - Slot 31 - Placeholder- Slot 31 - Placeholder - Slot 31- 483.70 243.81 483.70 239.92 445.80 62.713 Ellipse Separation Pass - Slot 31 - Placeholder- Slot 31 - Placeholder - Slot 31- 983.70 316.88 983.70 310.35 938.30 48.544 Clearance Factor Pass - 28 January, 2020 - 15:11 Page 5 of 8 COMPASS HALLIBURTON Anticollision Report for Plan: MPU M -25i - MPU M-25 wpO7 Survey tool j2r0qram From (usR) 33.70 550.00 5,704.93 To (usR) 550.00 MPU M-25wp07 5,704.93 MPU M-25 wp07 13,915.96 MPU M-25 wp07 Survey/Plan 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 / (Distance Between Profiles - Ellipse Separation). All station coordinates were calculated using the Minimum Curvature method. Survey Tool 3_Gyro-GC_Csg 3 MWD+IFR2+MS+Sag 3M WD+IFR2+MS+Sag Hilcorp Alaska, LLC Milne Point 28 January, 2020 - 15:11 Page 6 of 8 COMPASS REFERENCE INFORMATION WE.L DEL4IIS:PIen:MPUM-25i NAD1927 HALLIBURTON Protect: Milne Paint (NADCONCONUS) Almka Zone04 Site: M Pt Moose Pad Co-or6i Rererence: Wel Plan: MPU True 2520 1e TVID) 1 RKB — Well: Plan: MPU M -25i VerScd D( I )Reference: MPU M-25ACNa1 RKB@ Se.9Wsft(Q14) Sperry Orllling Measured Ra/erence: MPU M-25 ACNalRKB SB.90esft (Q14) +N/0 +F1 -W NoMipg E I'29' 14¢ 9.43' 3 ,9 Wellbore: MPU M -25i 1 Celalation MetM1od: Minimum Curvature 0.00 0.00 6027889.56 533543.90 70°29' 14014N 149°43' 32.988 3543 Plan: MPU M-25 wp07 SURVEY PROGRAM NO GLOBAL FILTER: Using user defined selection & filtering criteria ome: 20-11-T0u:W:W Wlidamd: Yea wr:ien: 33.70 To 13915.96 oapm 1r 0I To Survay/Pmn Teel CASING DETAILS 33.70 5W.W MPU M -25w 07 (MPU M-257Em 3_Gyro-GC_Csg Ladder/ ST. Plots 550.00 5]04.93 MPUM-25Mk (MPUM-25) 3_MWG FRIM :,g TVD TVD$$ MD Si. Name t of 2 5704,93 1391596 MPU M-25 MW QAPU M-25) 3_MW D+IFR2.MS+Sg 1 L 3573.90 3515.00 5704.93 9-5/8 9 5/8" x 12 1/4" 3478.90 3420.00 13915.96 4-12 41/2'1 8 1/2" 180.00 —. -- -- r - --- i X150.00 — —- N MP M-51 wp0 - I 00 ,D120.00 —' oMPU m 26 c" j i MPU N -22 ✓,/ i m MPU m 51 wp01 I OR 90.00 rn MPU KI wp01 MPU 23i i 60.00— to 0.00 MPU MPU M 50 wp01 MPU V 23 wpo6 I MPU N9 wp01 c 30.00— d) MPU - 4 0 300 600 900 1200 1500 1800 2100 2400 2700 3000 3300 3600 3900 4200 4500 4800 5100 5400 5700 Measured Depth (600 usft/in) 4.00 Ti__..._ - o v 3.00 -- CID U o 2.00 CL � Collision Risk Procedures Req. I I Collision Avoidance Req. j 1.00 _ _ � �, No -Go Zone - Stop Drilling -- I - MPU M-91 wrp 1 0.00 0 300 600 900 1200 1500 1800 2100 2400 2700 3000 3300 3600 3900 4200 4500 4800 5100 5400 5700 Measured Depth (600 usft/in) Hilcorp Alaska, LLC Milne Point M Pt Moose Pad Plan: MPU M -25i MPU M -25i MPU M-25 wp07 Sperry Drilling Services Clearance Summary Anticollision Report 28 January, 2020 Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference) Reference Design: M Pt Moose Pad - Plan: MPU M -25i - MPU M -25i - MPU M-25 Wp07 Well Coordinates: 6,027,889.56 N, 533,543.90 E (70° 29' 14.01" N, 149° 43' 32.99" W) Datum Height: MPU M-25 Actual RKB @ 58.90usft (D-14) Scan Range:5,704.93 to 13,915.96 usft. Measured Depth. Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usft Geodetic Scale Factor Applied Version: 5000.15 Build: 91E Scan Type: • • - Scan Type: 25.00 HALLIBURTON Sperry Drilling Services HALLIBURTON Anticollision Report for Plan: MPU M -25i - MPU M-25 wp07 Hilcorp Alaska, LLC Milne Point Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference) 777.95 Reference Design: M Pt Moose Pad - Plan: MPU M -25i - MPU M -25i - MPU M-25 wp07 586.90 Scan Range: 5,704.93 to 13,915.96 usft. Measured Depth. 4.072 Centre Distance Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 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 Moose Pad MPU M-24 - MPU M-24 - MPU M-24 MPU M-24 - MPU M-24 - MPU M-24 MPU M -24 -MPU M-24PB1 -MPU M-24PB1 MPU M-24 - MPU M-24PB2 - MPU M-24PB2 MPU M -24 -MPU M-24PB2-MPU M-24PB2 MPU M-24 - MPU M-24PB3 - MPU M-24PB3 MPU M-24 - MPU M-24PB3 - MPU M-24PB3 MPU M-26 - MPU M-26 - MPU M-26 MPU M-26 - MPU M-26PB1 - MPU M-26PB1 MPU M-26- MPU M-26PB1 - MPU M-26PB1 MPU M-26- MPU M-26PB1 - MPU M-26PB1 Plan: Kup S1 Deep KOP - Slot 17 - Kup S1 - Kup S1 w Plan: Kup S1 Deep KOP - Slot 17 - Kup S1 - Kup S1 w Plan: Kup S1 Deep KOP - Slot 17 - Kup S1 - Kup S1 w Plan: Kup S2 - Slot 11 - Kup S2 - KupS2 wp03 - 200ft Plan: Kup S2 - Slot 11 - Kup S2 - KupS2 wp03 - 200ft Plan: Kup S2 - Slot 11 - Kup S2 - KupS2 wp03 - 200ft Plan: MPU M-50 - Slot 14 - MPU M-50 - MPU M-50 wF Plan: MPU M-50 - Slot 14 - MPU M-50 - MPU M-50 wE Plan: MPU M-52 - Slot 09 - MPU M-52 - MPU M-52 wp Plan: MPU M-58(IRA) -Slot 28- MPU M-58 - MPU M= Plan: MPU M-58(IRA) - Slot 28 - MPU M-58 - MPU M-! Proposal: MPU M-05DSW - Slot 3 - MPU M-05 (Beaur Proposal: MPU M-05DSW - Slot 3 - MPU M-05 (Beaur 12,353.86 777.95 12,353.86 586.90 12,839.39 4.072 Centre Distance Pass - 13,915.96 797.89 13,915.96 573.10 14,426.98 3.549 Clearance Factor Pass - 5,704.93 1,132.11 5,704.93 1,049.52 5,803.00 13.708 Clearance Factor Pass - 9,329.93 783.52 9,329.93 620.76 9,810.00 4.814 Clearance Factor Pass - 9,334.02 783.50 9,334.02 620.81 9,810.00 4.816 Centre Distance Pass - 8,924.90 794.91 8,924.90 671.61 9,379.75 6.447 Centre Distance Pass - 13,904.93 846.75 13,904.93 598.39 14,389.00 3.409 Clearance Factor Pass - 13,915.96 850.81 13,915.96 601.57 14,940.00 3.414 Clearance Factor Pass - 12,660.22 950.41 12,660.22 721.26 13,622.00 4.147 Centre Distance Pass - 12,679.93 950.62 12,679.93 720.75 13,622.00 4.136 Ellipse Separation Pass - 12,754.93 955.12 12,754.93 723.20 13,622.00 4.118 Clearance Factor Pass - 6,879.93 965.76 6,879.93 884.66 5,567.74 11.908 Clearance Factor Pass - 7,229.93 917.50 7,229.93 845.64 5,791.50 12.767 Ellipse Separation Pass - 7,274.51 916.86 7,274.51 846.40 5,820.01 13.012 Centre Distance Pass - 9,029.93 906.98 9,029.93 785.89 6,837.35 7.490 Clearance Factor Pass - 9,229.93 895.35 9,229.93 777.64 7,002.77 7.607 Ellipse Separation Pass - 9,295.84 894.58 9,295.84 778.39 7,057.29 7.699 Centre Distance Pass - 8,921.76 881.77 8,921.76 754.71 9,066.79 6.939 Centre Distance Pass - 13,915.96 1,015.57 13,915.96 745.28 14,058.57 3.757 Clearance Factor Pass - 13,915.96 682.35 13,915.96 420.19 14,590.95 2.603 Clearance Factor Pass - 5,704.93 846.32 5,704.93 803.95 5,212.87 19.971 Ellipse Separation Pass - 6,404.93 1,167.58 6,404.93 1,108.63 5,477.36 19.806 Clearance Factor Pass - 7,799.78 104.71 7,799.78 17.13 5,934.79 1.196 Centre Distance Pass - 7,854.93 114.23 7,854.93 4.78 5,965.95 1.044 Clearance Factor Pass - 28 January, 2020 - 15:13 Page 2 of 5 COMPASS HALLIBURTON Anticollision Report for Plan: MPU M -25i - MPU M-25 wp07 Survey tool program From To Survey/Plan (usft) (usft) 33.70 550.00 MPU M-25 wp07 550.00 5,704.93 MPU M-25 wp07 5,704.93 13,915.96 MPU M-25 wp07 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 / (Distance Between Profiles - Ellipse Separation). All station coordinates were calculated using the Minimum Curvature method. Survey Tool 3_Gyro-GC_Csg 3 MWD+IFR2+MS+Sag 3_M WD+IFR2+MS+Sag Hileorp Alaska, LLC Milne Point 28 January, 2020 - 15:13 Page 3 of 5 COMPASS HALLIBURTON Project: Milne Point REFERENCE INFORMATION WELL DEMO S:PI.: MPU M -25i NAD 1927 (NADC0.Y CONUB) AlasYa Zone 61 Site: M PI Moose Pad Ca-oNirute (NlE) R -n- - Plan: MPU M -25i, True Na 25 20 sorry onmr,g Well: Plan: MPU M -25i vergcal (rV0) Rerere MPV M-25 Actual RKB @ 56.90usfl (0.14) +N/ -S +g/_W NoNtin g Ewting lalitmde Longitude MeasureE Depen Rerarence: MPU M-25 Actual RKB 59.90usft(P14) Wellbore: MPU M -25i Catalano. Memos Minimum Curvature 0.00 0.00 6027889.56 533543.90 70' 29 14.014 N 149° 43' 32.988 Plan: MPU M-25 wp07 SURVEY PROGRAM NO GLOBAL FILTER: Using user defined selection & filtering criteria Dem: 20f7-11-14-:0000 valmema:Yap veraon: 33.70 To 13915.96 EM Depen Fra. Depth Ta SurveylPlanToa, CASING U6TAIIS 33.70 550.00 MPU M-25 M-25) 3_Gyr GC Cap wp07 (MPU Ladder/ ST Plots 55000 570493 MPUM-25w07(MPUM-25) 3MWD+IFR2.MS.S.g 5704.93 13915.96 MPU. -25_1(.1U.-25) 3_MW9-,FR2-MS-Sag TVD IV�55 MD 512e Nam 2 of 2 3573.90 3515.00 5704.93 9-5/8 9 5/8" x l2 1/4" 3478.90 3420.00 13915.96 4-1/2 4 1/2" x 8 1/2" 180.00 -- ---- I I I c � ' X150.00 - - ------ I I 0 x_120.00 C O m I I 0 90.00- a) j m 0.00 u 60.00- 30.00 30.00 - - - -- U 0.00 5950 6375 6800 7225 7650 8075 8500 8925 9350 9775 10200 10625 11050 11475 11900 12325 12750 13175 13600 1402 Measured Depth (850 usft/in) 4.00 i i I M-05DSV wp03 I 1 3.00 IL c Collision Risk Procedures Req. 2.00- .00 CollisionQ.. Collision Avoidance Reto - I No -Go Zone -Stop Drilling 1.00 NOERRDRS 0.00 5950 6375 6800 7225 7650 8075 8500 8925 9350 9775 10200 10625 11050 11475 11900 12325 12750 13175 13600 1402 Measured Depth (850 usft/in) Boyer, David L (CED) From: Cody Dinger <cdinger@hilcorp.com> Sent: Wednesday, February 5, 2020 3:28 PM To: Boyer, David L (CED); Davies, Stephen F (CED) Cc: Joseph Engel Subject: MPU M-25 Permit to Drill Attachments: MPU M-25 wp07_GEO.TXT; MPU M-25 wp07_GIS.TXT; MPU M-25 wp07.txt Gentlemen, MPU M-25 directional plan is attached here. Well will not be pre -produced. Thanks, Cody Dinger Hilcorp Alaska, LLC Drilling Tech 907-777-8389 The information contained in this e-mail message is confidential information intended only for the use of the recipient(s) named above. In addition, this communication may be legally privileged. If the reader of this e-mail is not an intended recipient, you have received this e-mail in error and any review, dissemination, distribution or copying is strictly prohibited. If you have received this e-mail in error, please notify the sender immediately by return e-mail and permanently delete the copy you received. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. Transform Points Source coordinate systemTarget coordinate system State Plane 1927 - AJaska Zone 4 M Adbers Equal Area (-150) MM 0- Datum: 6�7 . Datum: NAD 1927 - North America Datum of 1927 (Mean) NAD 1527 - North P4nerica Datum of 1927 (Mean) I Type values ir>to the —spreadsheet or copy —and -paste -_'columns ofdatafrom - spreadsheet "usIn_g _the keyb`oa_rd_shortcuts Ctd+_C t—o- popy and Ctd+Vto paste. Then click on the appropriate arrow button to transform the points to the desired coordinate system. < Back Finish Cancel Help TRANSMITTAL LETTER CHECKLIST WELL NAME: MPU M - a, s PTD: gao—(J I_A Development 1/Service _ Exploratory _ Stratigraphic Test _ Non -Conventional FIELD: i Ike, 1 O 1 h74� POOL: 5 G k 1r a,�e l/` 13( uf�P 0 i I, 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- - - - (If last two digits Production should continue to be reported as a function of the 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. Spacing Approval to produce/inject is contingent upon issuance of a Exception conservation 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: Non- production or production testing of coal bed methane is not allowed for 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 (Company Name) in the attached application, the following well logs are also required for this well: Well Logging Requirements 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. Revised 2/2015 WELL PERMIT CHECKLIST Field & Pool MILNE POINT, SCHRADER BLFF OIL - 525140 PTD#:2200160 Company Hilcorp Alaska LLC_ __- _ Initial Class/Type Well Name: MILNE_PT UNIT M-25 - - - -- _ _Program SER __--_-_ Well bore seg ❑ SER_/ PEND GeoArea 890 _ - Unit 11328_ _ On/Off Shore On Annular Disposal ❑ Administration 1 Permit fee attached NA omission 2 Lease number appropriate Yes 3 Unique well name and number Yes ------- 4 Welllocatedin a defined -pool Yes 15 Well located proper distance from drilling unit boundary Yes i6 Well located proper distance from other wells Yes 7 Sufficient acreage available indrillingunit Yes 8 If deviated, is wellbore plat included Yes 9 Operator only affected party Yes - - - - 10 Operator has appropriate 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 DLB 2/7/2020 14 Well located within area andstrataauthorized by Injection Order # (put 10# in comments) (For Yes A10_No. 10-13; CO 477.05 15 All wells within 1/4 mile area of review identified (For service well only)- Yes I16 -Pre-produced injector: duration of pre -production less than 3 months (For service well only) NA Well will not be pre -produced, per operator e-mail. 17 Nonconven. gas conforms to AS31.05.0300.1.A),0.2.A-D) NA 18 Conductor string provided Yes 20 inch Conductor at 114 ft Engineering 19 Surface casing_ protects all known USDWs NA no aquifers 20 CMT vol_ adequate to circulate on conductor & surf csg Yes - 9 5/8" will be fully cemented .. Us ES stage tool at 2500 ft. 21 CMT vol adequate to tie-in long string to -surf csg Yes 9 5/8" casing shoe will be at 5700 ft. (3575 ft TVD) 22 CMT will cover all known productive horizons Yes injection lateral will have swell packers and ICDs 23 Casing designs adequate for C, T, B &_permafrost Yes - - 24 Adequate tankage or reserve pit Yes Rig has steel pits. 25 If a re -drill, has a 10-403 for abandonment been approved NA 26 Adequate wellbore separation proposed Yes no issues 127 If-diverter required, does it meet regulations_ - - Yes Appr Date 28 Drilling fluid program schematic & equip list adequate Yes Max formation press= 157.4 psi (8.6_ppg EMW) will drill with 8.8 -9.5 ppg mud GLS 2/12/2020 29 BOPEs, do they meet regulation Yes Doyon 14 has 13 5/8" 5000 psi WP BOPE 30 BOPE press rating appropriate; test to (put psig in comments) Yes MASP = 1215 psi Will test BOPE to 3000 psi - 31 Choke manifold complies w/API RP -53 (May 84)_ Yes - 32 Work will occur without operation shutdown Yes 33 Is presence of H2S gas probable No 34 Mechanical condition of wells within AOR verified (For service well only) Yes 1/4 mile review completed. 35 Permit can be issued w/o hydrogen sulfide measures Yes H2S not anticipated from drilling of offset wells; however, rig will have H2S sensors and alarms. _ Geology 36 Data presented on potential overpressure zones Yes Appr Date 37 Seismic analysis of shallow gas zones NA DLB 2/7/2020 38 Seabed condition survey (if off -shore) NA 39 Contact name/phone for weekly progress reports_ [exploratory only] NA Geologic Date: Engineering Date Public OA sand Schrader Bluff injector. Water only. GLS Date Commissioner: o is 3C Commissioner: "11312, omission