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Home My WebLink About221-044MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Tuesday, November 25, 2025 SUBJECT:Mechanical Integrity Tests TO: FROM:Kam StJohn P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL Hilcorp Alaska, LLC S-44 MILNE PT UNIT S-44 Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 11/25/2025 S-44 50-029-23694-00-00 221-044-0 W SPT 4096 2210440 1500 537 538 541 541 4YRTST P Kam StJohn 10/12/2025 Monobore 4 Yr 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 S-44 Inspection Date: Tubing OA Packer Depth 115 1701 1626 1602IA 45 Min 60 Min Rel Insp Num: Insp Num:mitKPS251012104846 BBL Pumped:1.9 BBL Returned:1.9 Tuesday, November 25, 2025 Page 1 of 1          Kaitlyn Barcelona Hilcorp North Slope, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 564-4389 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: DATE: 06/13/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU S-44 (PTD 221-044) IPROF 06/05/2022 Please include current contact information if different from above. 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Anchorage, AK 99501 DATA TRANSMITTAL MPU S-44 (PTD 221-044) Coil Flag 11/30/2021 Please include current contact information if different from above. 37' (6HW Received By: 12/09/2021 By Abby Bell at 4:29 pm, Dec 08, 2021 1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: ___________________ 2. Operator Name:4.Current Well Class:5.Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception?Yes No 9. Property Designation (Lease Number):10. Field/Pool(s): 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 13,437'N/A Casing Collapse Conductor N/A Surface 4,760psi 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. W ell 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 AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC 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 AOGCC Date: Comm.Comm.Sr Pet Eng Sr Pet Geo Sr Res Eng 2,239' 5,242' 4-1/2" 117'20" 9-5/8" 9-5/8" 2,239' 8,380' 3,003' 13,437' Length Size 117'117' 9.3# / L-80 / EUE 8rd TVD Burst 5,056' MD N/A 9,020psi 6,870psi 5,750psi 2,012' 4,110' 4,082' PRESENT WELL CONDITION SUMMARY STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0025518 & ADL0380109 221-044 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 50-029-23694-00-00 Hilcorp Alaska LLC MILNE PT UNIT S-44 MILNE POINT / SCHRADER BLUFF OIL C.O. 477.05 Tubing Grade:Tubing MD (ft):Perforation Depth TVD (ft): Tubing Size: 9-5/8" SLZXP Packer and N/A 5,047 MD / 4,096 TCD and N/A See Schematic See Schematic 11/8/2021 3-1/2" Perforation Depth MD (ft): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: AOGCC USE ONLY Operations Manager Brian Glasheen brian.glasheen@hilcorp.com 907-564-5277 4,082' 13,437' 4,082' 1,289 N/A No No Form 10-403 Revised 10/2021 Approved application is valid for 12 months from the date of approval. Taylor Wellman for David Haakinson By Samantha Carlisle at 12:18 pm, Nov 04, 2021 321-569 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143), ou=Users Date: 2021.11.04 10:28:09 -08'00' Taylor Wellman (2143) DSR-11/4/21SFD 11/4/2021MGR08NOV21 10-404 dts 11/9/2021 JLC 11/9/2021 Jeremy Price Digitally signed by Jeremy Price Date: 2021.11.09 12:03:06 -09'00' RBDMS HEW 11/12/2021 Add Perf MPU S-44 Date 10/27/21 Well Name:MPU S-44 API Number:50-029-23694-00-00 Current Status:Shut-in Pad:S-Pad Estimated Start Date:November 8th 2021 Rig:Service Coil Reg. Approval Req’d?Yes Date Reg. Approval Rec’vd: Regulatory Contact:Tom Fouts Permit to Drill Number:221-044 First Call Engineer:Brian Glasheen 907-564-5277 (o) 907-545-1144 © Second Call Engineer: AFE Number:211-00042 Job Type:Extended APF Current Bottom Hole Pressure:1,689 psi @ 4,000’ TVD 8.1 PPGE | 10/27/21 DHPG Max. Anticipated Surface Pressure:1,289psi (Based on 0.1 psi/ft. gas gradient) Min ID:2.75” ID XN @ 4,653’ MD Max Angle:93 Deg @ 9,425’ Reference Log: HAL Sperry Drilling 6/21/21 Tie In Log: HAL Sperry Drilling 6/21/21 Brief Well Summary: Well is a brand new injector and completed with 100 micron screens to help distribute injections. After the well was put on injections the screens fine mesh size cause too big of a pressure drop and started to form hydrates in the well and not allow desired injection rates to maintain VRR’s. Objective: Use coil to add new perforations. Sundry Procedure (Approval Required to Proceed): Note: The well will be killed and monitored before making up the initial perfs guns. This is generally done during the drift/logging run. This will provide guidance as to whether the well will be killed by bullheading or circulating bottoms up throughout the job. If pressure is seen immediately after perforating, it will either be killed by bullheading while POOH or circulating bottoms up through the same port that opened to shear the firing head. Coil Tubing 1. MIRU Coiled Tubing Unit and spot ancillary equipment. 2. Pressure test BOPE to 3,500 psi Hi 250 Low, 10 min each test. 1. Each subsequent test of the lubricator will be to 3,500 psi Hi 250 Low to confirm no leaks. 2. No AOGCC notification required. 3. Record BOPE test results on 10-242 form.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. Bullhead 254 bbls of 8.4 ppg 1% KCl or 8.5 ppg seawater down the tubing to the formation. (This step can be performed any time prior to open-hole deployment of the perf guns. Timing of the well kill is at the discretion of the WSS.) a. Wellbore volume =5,047*.0087+ 8,390*.0149= 169 bbls 4. MU and RIH with logging tools and dummy gun drift BHA to resemble perf gun. Tag PBTD or reach lock out depth prior to logging OOH. Flag pipe for bottom perf interval at 13,100 MD’. * o add new perforations. Add Perf MPU S-44 Date 10/27/21 5. POOH and confirm good data. 6. Contact OE prior to perforating for final approval of tie-ins. 7. Freeze protect tubing as needed. 8. At surface, prepare for deployment of TCP guns. 9. Confirm well is dead. Bleed any pressure off to return tank. Kill well w/8.4 ppg 1% KCl or 8.5 ppg as needed. Maintain continuous hole fill taking returns to tank until lubricator connection is reestablished. 10. Monitor tankage and document with trip sheet. 11. Pickup safety joint and TIW valve and space out before MU guns.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. 12. Break lubricator connection at QTS and begin makeup of TCP and deployment bars (2" Millennium or equivalent) per schedule below. a.Note: i. Gun lengths need to be verified and confirmed post drift and tie-in run with remaining BHA components.. ii. Guns are 6 SPF, 60-degree phasing. iii. Well temperature is estimated at 70 deg F. Delay fuses are temperature dependent and nominal burn time is estimated at 7.84 minutes per delay fuse at this temperature. Minimum time before picking up BHA above 5,464’ 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. MPU S-44 Add perf Schedule per Tie-In log depths Equipment Length (ft)Top Depth (MD)Bottom Depth (MD)Sand Firing Head 3.65 Spacer 7 Perf Gun 10 13,180'13,190'Schrader Deployment Bar 6.5 303'4 Deployment Bar 6.5 Pick up length Estimate Travel time (Min) Perf Gun 10 12,877'12,887'Schrader Deployment Bar 6.5 572'8 Deployment Bar 6.5 Pick up length Estimate Travel time (Min) Perf Gun 10 12,305'12,315'Schrader Deployment Bar 6.5 583'8 Deployment Bar 6.5 Pick up length Estimate Travel time (Min) Perf Gun 10 11,722'11,732'Schrader Deployment Bar 6.5 626'8 Deployment Bar 6.5 Pick up length Estimate Travel time (Min) Perf Gun 10 11,096'11,106'Schrader Deployment Bar 6.5 808'11 Deployment Bar 6.5 Pick up length Estimate Travel time (Min) Perf Gun 10 10,288'10,298'Schrader Add Perf MPU S-44 Date 10/27/21 Deployment Bar 6.5 531'7 Deployment Bar 6.5 Pick up length Estimate Travel time (Min) Perf Gun 10 9,757'9,767'Schrader Deployment Bar 6.5 1,753'23 Deployment Bar 6.5 Pick up length Estimate Travel time (Min) Deployment Bar 6.5 Perf Gun 10 8,004'8,014'Schrader Deployment Bar 6.5 466'6 Deployment Bar 6.5 Pick up length Estimate Travel time (Min) Perf Gun 10 7,538'7,548'Schrader Deployment Bar 6.5 323'4 Deployment Bar 6.5 Pick up length Estimate Travel time (Min) Perf Gun 10 7,215'7,225'Schrader Deployment Bar 6.5 199'3 Deployment Bar 6.5 Pick up length Estimate Travel time (Min) Perf Gun 10 7,016'7,026'Schrader Deployment Bar 6.5 542'7 Deployment Bar 6.5 Pick up length Estimate Travel time (Min) Perf Gun 10 6,474'6,484'Schrader Deployment Bar 6.5 403'5 Deployment Bar 6.5 Pick up length Estimate Travel time (Min) Perf Gun 10 6,071'6,081'Schrader Deployment Bar 6.5 607'8 Deployment Bar 6.5 Pick up length Estimate Travel time (Min) Perf Gun 10 5,464'5,474'Schrader Total Length 326.15 13. RIH with perf gun and tie-in. Pickup and perforate intervals per Perf Schedule above. POOH. a. Note any tubing pressure change in WSR. 14. Space out for bottom shot. 15. Once on depth. Confirm plan of operations and firing sequence with coil crew. 16. Pre-plan stop depths to account for space out of guns in BHA. 17. Launch ½” ball to activate firing head. 18.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. 19. 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 5,464’ MD until full duration of delay period has elapsed from time of firing head activation. 23. POOH. Stop at surface to reconfirm well is dead and hole is full. 24. Review well control steps with crew prior to breaking lubricator connection and commencing breakdown of TCP gun string. 25. Repeat steps as necessary for subsequent guns per Add perf Schedule above. 26. RDMO CTU. Make up PCE. * See note above regarding kill methods if pressure observed at surface after perforating. Standing orders flow chart included with this sundry request. Add Perf MPU S-44 Date 10/27/21 27. RTI or FP well. Attachments: 1. As-built Schematic 2. Proposed Schematic 3. Coil Tubing BOPE Schematic Equipment Layout Diagram 4. Standing Orders for Open Hole Well Control during Perf Gun Deployment _____________________________________________________________________________________ Revised By: JNL 7/21/21 SCHEMATIC Milne Point Unit Well: MPU S-44 PTD: 50-029-23694-00-00 API: 221-044 4-1/2” SCREEN Liner Jts Top (MD) Btm (MD) Top (MD) Btm (TVD) 1 5,402’ 4,111’ 5,444’ 4,110’ 1 6,010’ 4,105’ 6,051’ 4,105’ 1 6,423’ 4,108’ 6,454’ 4,108’ 1 6,955’ 4,100’ 6,996’ 4,099’ 1 7,153’ 4,097’ 7,195’ 4,097’ 1 7,477’ 4,092’ 7,518’ 4,091’ 1 7,943’ 4,088’ 7,984’ 4,088’ 1 9,696’ 4,065’ 9,737’ 4,064’ 1 10,227’ 4,068’ 10,268’ 4,069’ 1 11,035’ 4,068’ 11,076’ 4,067’ 1 11,661’ 4,082’ 11,702’ 4,083’ 1 12,243’ 4,085’ 12,285’ 4,085’ 1 12,816’ 4,090’ 12,857’ 4,090’ 1 13,233’ 4,088’ 13,274’ 4,087’ TD =13,437’(MD) / TD =4,082’(TVD) 20” Orig. KB Elev.:63.24’ / GL Elev.: 37.0’ 3-1/2” 2 9-5/8” 1 3/4 6 See Screen Liner Detail PBTD =13,437’ (MD) / PBTD =4,082’(TVD) 9-5/8” ‘ES’ Cementer @ 2,239’ 4-1/2” 5 CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF 20" Conductor 129.5 / X-52 / Weld N/A Surface 117’ N/A 9-5/8" Surface 47 / L-80 / TXP 8.525” Surface 2,239’ 0.0732 9-5/8" Surface 40 / L-80 / TXP 8.679” 2,239’ 5,242’ 0.0758 4-1/2” Liner 13.5 / L-80 / Hyd 625 3.795” 5,047’ 13,437’ 0.0149 TUBING DETAIL 3-1/2" Tubing 9.3 / L-80 / EUE 8RD 2.992” Surf 5,056’ 0.0087 JEWELRY DETAIL No Top MD Item ID Upper Completion 1 4,600’ Zenith G6 Gauge 400 Bar 150C, 2 Press 2 Temp 2.992” 2 4,653’ XN Nipple, 2.85” Bottom No-Go, 2.813” Packing Bore 2.750” 3 5,045’ 8.25” No Go Locater Sub (3.61’ off No-go) 2.970” 4 5,046’ Bullet Seals – TXP Top Box x Mule Shoe 6.160” Lower Completion 5 5,047’ 9-5/8” SLZXP Liner Top Packer 7.020” 6 13,435’ Shoe 3.950” OPEN HOLE / CEMENT DETAIL 44” 18.5 Bbls Concrete 12-1/4"Stg 1 –Lead 366 sx / Tail 391 sx Stg 2 –Lead 710 sx / Tail 270 sx 8-1/2” Cementless Screen Liner WELL INCLINATION DETAIL KOP @ 433’ MD Max Hole Angle = 93° TREE & WELLHEAD Tree Cameron 3 1/8" 5M w/ 4-1/16” 5M Cameron Wing Wellhead Cameron 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs GENERAL WELL INFO API#: 50-029-23694-00-00 Completed by Innovation: 7/8/2021 _____________________________________________________________________________________ Revised By: TDF 11/2/2021 PROPOSED Milne Point Unit Well: MPU S-44 PTD: 50-029-23694-00-00 API: 221-044 TD =13,437’(MD) / TD =4,082’(TVD) 20” Orig. KB Elev.:63.24’ / GL Elev.: 37.0’ 3-1/2” 2 9-5/8” 1 3/4 6 See Screen Liner Detail PBTD =13,437’ (MD) / PBTD =4,082’(TVD) 9-5/8” ‘ES’ Cementer @ 2,239’ 4-1/2” 5 CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF 20" Conductor 129.5 / X-52 / Weld N/A Surface 117’ N/A 9-5/8" Surface 47 / L-80 / TXP 8.525” Surface 2,239’ 0.0732 9-5/8" Surface 40 / L-80 / TXP 8.679” 2,239’ 5,242’ 0.0758 4-1/2” Liner 13.5 / L-80 / Hyd 625 3.795” 5,047’ 13,437’ 0.0149 TUBING DETAIL 3-1/2" Tubing 9.3 / L-80 / EUE 8RD 2.992” Surf 5,056’ 0.0087 OPEN HOLE / CEMENT DETAIL 44” 18.5 Bbls Concrete 12-1/4"Stg 1 –Lead 366 sx / Tail 391 sx Stg 2 –Lead 710 sx / Tail 270 sx 8-1/2” Cementless Screen Liner WELL INCLINATION DETAIL KOP @ 433’ MD Max Hole Angle = 93° TREE & WELLHEAD Tree Cameron 3 1/8" 5M w/ 4-1/16” 5M Cameron Wing Wellhead Cameron 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs JEWELRY DETAIL No Top MD Item ID Upper Completion 1 4,600’ Zenith G6 Gauge 400 Bar 150C, 2 Press 2 Temp 2.992” 2 4,653’ XN Nipple, 2.85” Bottom No-Go, 2.813” Packing Bore 2.750” 3 5,045’ 8.25” No Go Locater Sub (3.61’ off No-go) 2.970” 4 5,046’ Bullet Seals – TXP Top Box x Mule Shoe 6.160” Lower Completion 5 5,047’ 9-5/8” SLZXP Liner Top Packer 7.020” 6 13,435’ Shoe 3.950” PERFORATION DETAIL Schrader Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status Schrader ±5,464’ ±5,474’ ±4,110’ ±4,110’ ±10’ Future Future ±6,071’ ±6,081’ ±4,105’ ±4,105’ ±10’ Future Future ±6,474’ ±6,484’ ±4,108’ ±4,108’ ±10’ Future Future ±7,016’ ±7,026’ ±4,099’ ±4,099’ ±10’ Future Future ±7,215’ ±7,225’ ±4,097’ ±4,096’ ±10’ Future Future ±7,538’ ±7,548’ ±4,091’ ±4,091’ ±10’ Future Future ±8,004’ ±8,014’ ±4,088’ ±4,088’ ±10’ Future Future ±9,757’ ±9,767’ ±4,064’ ±4,064’ ±10’ Future Future ±10,288’ ±10,298’ ±4,069’ ±4,069’ ±10’ Future Future ±11,096’ ±11,106’ ±4,067’ ±4,067’ ±10’ Future Future ±11,722’ ±11,732’ ±4,084’ ±4,084’ ±10’ Future Future ±12,305’ ±12,315’ ±4,085’ ±4,085’ ±10’ Future Future ±12,877’ ±12,887’ ±4,091’ ±4,091’ ±10’ Future Future ±13,180’ ±13,190’ ±4,089’ ±4,089’ ±10’ Future Future Ugnu – TCP 5” 5132 Razor RDX SBH TL LD, 16 spf (32.0 gr, 1.04 EH, 6.7 Pen) _____________________________________________________________________________________ Revised By: TDF 11/2/2021 PROPOSED Milne Point Unit Well: MPU S-44 PTD: 50-029-23694-00-00 API: 221-044 4-1/2” Screen Liner Detail Jts Top (MD) Top (TVD) Btm (MD) Btm (TVD) 1 5,402’ 4,111’ 5,444’ 4,110’ 1 6,010’ 4,105’ 6,051’ 4,105’ 1 6,423’ 4,108’ 6,454’ 4,108’ 1 6,955’ 4,100’ 6,996’ 4,099’ 1 7,153’ 4,097’ 7,195’ 4,097’ 1 7,477’ 4,092’ 7,518’ 4,091’ 1 7,943’ 4,088’ 7,984’ 4,088’ 1 9,696’ 4,065’ 9,737’ 4,064’ 1 10,227’ 4,068’ 10,268’ 4,069’ 1 11,035’ 4,068’ 11,076’ 4,067’ 1 11,661’ 4,082’ 11,702’ 4,083’ 1 12,243’ 4,085’ 12,285’ 4,085’ 1 12,816’ 4,090’ 12,857’ 4,090’ 1 13,233’ 4,088’ 13,274’ 4,087’ GENERAL WELL INFO API#: 50-029-23694-00-00 Completed by Innovation: 7/8/2021 Add Perf MPU S-44 Date 10/27/21 Coil Tubing BOPE Add Perf MPU S-44 Date 10/27/21 Equipment Layout Diagram Add Perf MPU S-44 Date 10/27/21 Standing Orders for Open Hole Well Control during Perf Gun Deployment Standing Orders for Service Coiled Tubing Operations While Deploying Extended Length Perforating BHA WELL BEGINS FLOWING DURING OPEN HOLE DEPLOYMENT Pull BHA above blind/shear rams, and close blind/shears. Space out BHA with safety joint above slip bowl, set hand slips Install safety joint with open TIW Can BHA be pulled above blind/shear rams in a single pick? Pull hand slips YES NO Begin Notifications Close Upper Pipe/Slip Ram Close TIW Close choke valves, monitor and record SIWHP Close choke line. Monitor and record SIWHP Lower safety joint and space out over BOP, set hand slips Begin Notifications From:Rixse, Melvin G (CED) To:Carlisle, Samantha J (CED); Roby, David S (CED); Davies, Stephen F (CED); Boyer, David L (CED) Subject:RE: 10-403 Hilcorp_MPU_S-44_received110321_review.pdf Date:Wednesday, November 3, 2021 5:26:23 PM Samantha, This 10-403 is rejected. Hilcorp is to include 'standing orders' and 'equipment layout' in these extended perforating (deploying without a lubricator) sundries. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-223-3605 Cell CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). -----Original Message----- From: Carlisle, Samantha J (CED) <samantha.carlisle@alaska.gov> Sent: Wednesday, November 3, 2021 1:41 PM To: Rixse, Melvin G (CED) <melvin.rixse@alaska.gov>; Roby, David S (CED) <dave.roby@alaska.gov>; Davies, Stephen F (CED) <steve.davies@alaska.gov>; Boyer, David L (CED) <david.boyer2@alaska.gov> Subject: 10-403 Hilcorp_MPU_S-44_received110321_review.pdf You are invited to review the document "Hilcorp_MPU_S-44_received110321_review.pdf" located at: <\\cedogcfs\shared\AOGCC\Processing\10-403\Hilcorp_MPU_S-44_received110321_review.pdf> You can use Adobe Acrobat or Adobe Reader to review this document. Open the document in Adobe Acrobat or Adobe Reader, and make your comments using the Comment & Markup tools. When you are finished, click Publish Comments to automatically return your comments to the author and all other reviewers. Get the free latest version of Adobe Acrobat Reader from: <http://www.adobe.com/go/reader> RBDMS HEW 11/4/2021 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: ___________________ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address: Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception? Yes No 9. Property Designation (Lease Number): 10. Field/Pool(s): 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 13,437'N/A Casing Collapse Conductor N/A Surface 4,760psi 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 AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC 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 AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng 2,239' 5,242' 4-1/2" 117' 20" 9-5/8" 9-5/8" 2,239' 8,380' 3,003' 13,437' Length Size 117' 117' 9.3# / L-80 / EUE 8rd TVD Burst 5,056' MD N/A 9,020psi 6,870psi 5,750psi 2,012' 4,110' 4,082' PRESENT WELL CONDITION SUMMARY STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0025518 & ADL0380109 221-044 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 50-029-23694-00-00 Hilcorp Alaska LLC MILNE PT UNIT S-44 MILNE POINT / SCHRADER BLUFF OIL C.O. 477.05 Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): Tubing Size: 9-5/8" SLZXP Packer and N/A 5,047 MD / 4,096 TCD and N/A See Schematic See Schematic 11/8/2021 3-1/2" Perforation Depth MD (ft): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: AOGCC USE ONLY Operations Manager Brian Glasheen brian.glasheen@hilcorp.com 907-564-5277 4,082' 13,437' 4,082' 1,289 N/A No No Form 10-403 Revised 10/2021 Approved application is valid for 12 months from the date of approval. Taylor Wellman for David Haakinson By Samantha Carlisle at 1:38 pm, Nov 03, 2021 321-565 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143), ou=Users Date: 2021.11.03 10:50:14 -08'00' Taylor Wellman (2143) DSR-11/3/21SFD 11/4/2021 MIT Req d? YYes Reqquuired ? Yes No Subsequent Form Reqquuired: COMMISSSIONERR No No MIT Req'd?Y R COMMISSIONER NMIT Req'd?Yes R COOMMISSIONER Noo Add Perf MPU S-44 Date 10/27/21 Well Name:MPU S-44 API Number:50-029-23694-00-00 Current Status:Shut-in Pad:S-Pad Estimated Start Date:November 8th 2021 Rig:Service Coil Reg. Approval Req’d?Yes Date Reg. Approval Rec’vd: Regulatory Contact:Tom Fouts Permit to Drill Number:221-044 First Call Engineer:Brian Glasheen 907-564-5277 (o) 907-545-1144 © Second Call Engineer: AFE Number:211-00042 Job Type:Extended APF Current Bottom Hole Pressure:1,689 psi @ 4,000’ TVD 8.1 PPGE | 10/27/21 DHPG Max. Anticipated Surface Pressure:1,289psi (Based on 0.1 psi/ft. gas gradient) Min ID:2.75” ID XN @ 4,653’ MD Max Angle:93 Deg @ 9,425’ Reference Log: HAL Sperry Drilling 6/21/21 Tie In Log: HAL Sperry Drilling 6/21/21 Brief Well Summary: Well is a brand new injector and completed with 100 micron screens to help distribute injections. After the well was put on injections the screens fine mesh size cause too big of a pressure drop and started to form hydrates in the well and not allow desired injection rates to maintain VRR’s. Objective: Use coil to add new perforations. Sundry Procedure (Approval Required to Proceed): Note: The well will be killed and monitored before making up the initial perfs guns. This is generally done during the drift/logging run. This will provide guidance as to whether the well will be killed by bullheading or circulating bottoms up throughout the job. If pressure is seen immediately after perforating, it will either be killed by bullheading while POOH or circulating bottoms up through the same port that opened to shear the firing head. Coil Tubing 1. MIRU Coiled Tubing Unit and spot ancillary equipment. 2. Pressure test BOPE to 3,500 psi Hi 250 Low, 10 min each test. 1. Each subsequent test of the lubricator will be to 3,500 psi Hi 250 Low to confirm no leaks. 2. No AOGCC notification required. 3. Record BOPE test results on 10-242 form.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. Bullhead 254 bbls of 8.4 ppg 1% KCl or 8.5 ppg seawater down the tubing to the formation. (This step can be performed any time prior to open-hole deployment of the perf guns. Timing of the well kill is at the discretion of the WSS.) a. Wellbore volume =5,047*.0087+ 8,390*.0149= 169 bbls 4. MU and RIH with logging tools and dummy gun drift BHA to resemble perf gun. Tag PBTD or reach lock out depth prior to logging OOH. Flag pipe for bottom perf interval at 13,100 MD’. o add new perforations. Add Perf MPU S-44 Date 10/27/21 5. POOH and confirm good data. 6. Contact OE prior to perforating for final approval of tie-ins. 7. Freeze protect tubing as needed. 8. At surface, prepare for deployment of TCP guns. 9. Confirm well is dead. Bleed any pressure off to return tank. Kill well w/8.4 ppg 1% KCl or 8.5 ppg as needed. Maintain continuous hole fill taking returns to tank until lubricator connection is reestablished. 10. Monitor tankage and document with trip sheet. 11. Pickup safety joint and TIW valve and space out before MU guns.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. 12. Break lubricator connection at QTS and begin makeup of TCP and deployment bars (2" Millennium or equivalent) per schedule below. a.Note: i. Gun lengths need to be verified and confirmed post drift and tie-in run with remaining BHA components.. ii. Guns are 6 SPF, 60-degree phasing. iii. Well temperature is estimated at 70 deg F. Delay fuses are temperature dependent and nominal burn time is estimated at 7.84 minutes per delay fuse at this temperature. Minimum time before picking up BHA above 5,464’ 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. MPU S-44 Add perf Schedule per Tie-In log depths Equipment Length (ft)Top Depth (MD)Bottom Depth (MD)Sand Firing Head 3.65 Spacer 7 Perf Gun 10 13,180'13,190'Schrader Deployment Bar 6.5 303'4 Deployment Bar 6.5 Pick up length Estimate Travel time (Min) Perf Gun 10 12,877'12,887'Schrader Deployment Bar 6.5 572'8 Deployment Bar 6.5 Pick up length Estimate Travel time (Min) Perf Gun 10 12,305'12,315'Schrader Deployment Bar 6.5 583'8 Deployment Bar 6.5 Pick up length Estimate Travel time (Min) Perf Gun 10 11,722'11,732'Schrader Deployment Bar 6.5 626'8 Deployment Bar 6.5 Pick up length Estimate Travel time (Min) Perf Gun 10 11,096'11,106'Schrader Deployment Bar 6.5 808'11 Deployment Bar 6.5 Pick up length Estimate Travel time (Min) Perf Gun 10 10,288'10,298'Schrader Add Perf MPU S-44 Date 10/27/21 Deployment Bar 6.5 531'7 Deployment Bar 6.5 Pick up length Estimate Travel time (Min) Perf Gun 10 9,757'9,767'Schrader Deployment Bar 6.5 1,753'23 Deployment Bar 6.5 Pick up length Estimate Travel time (Min) Deployment Bar 6.5 Perf Gun 10 8,004'8,014'Schrader Deployment Bar 6.5 466'6 Deployment Bar 6.5 Pick up length Estimate Travel time (Min) Perf Gun 10 7,538'7,548'Schrader Deployment Bar 6.5 323'4 Deployment Bar 6.5 Pick up length Estimate Travel time (Min) Perf Gun 10 7,215'7,225'Schrader Deployment Bar 6.5 199'3 Deployment Bar 6.5 Pick up length Estimate Travel time (Min) Perf Gun 10 7,016'7,026'Schrader Deployment Bar 6.5 542'7 Deployment Bar 6.5 Pick up length Estimate Travel time (Min) Perf Gun 10 6,474'6,484'Schrader Deployment Bar 6.5 403'5 Deployment Bar 6.5 Pick up length Estimate Travel time (Min) Perf Gun 10 6,071'6,081'Schrader Deployment Bar 6.5 607'8 Deployment Bar 6.5 Pick up length Estimate Travel time (Min) Perf Gun 10 5,464'5,474'Schrader Total Length 326.15 13. RIH with perf gun and tie-in. Pickup and perforate intervals per Perf Schedule above. POOH. a. Note any tubing pressure change in WSR. 14. Space out for bottom shot. 15. Once on depth. Confirm plan of operations and firing sequence with coil crew. 16. Pre-plan stop depths to account for space out of guns in BHA. 17. Launch ½” ball to activate firing head. 18.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. 19. 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 5,464’ MD until full duration of delay period has elapsed from time of firing head activation. 23. POOH. Stop at surface to reconfirm well is dead and hole is full. 24. Review well control steps with crew prior to breaking lubricator connection and commencing breakdown of TCP gun string. 25. Repeat steps as necessary for subsequent guns per Add perf Schedule above. 26. RDMO CTU. Add Perf MPU S-44 Date 10/27/21 27. RTI or FP well. Attachments: 1. As-built Schematic 2. Proposed Schematic 3. Coil Tubing BOPE Schematic _____________________________________________________________________________________ Revised By: JNL 7/21/21 SCHEMATIC Milne Point Unit Well: MPU S-44 PTD: 50-029-23694-00-00 API: 221-044 4-1/2” SCREEN Liner Jts Top (MD) Btm (MD) Top (MD) Btm (TVD) 1 5,402’ 4,111’ 5,444’ 4,110’ 1 6,010’ 4,105’ 6,051’ 4,105’ 1 6,423’ 4,108’ 6,454’ 4,108’ 1 6,955’ 4,100’ 6,996’ 4,099’ 1 7,153’ 4,097’ 7,195’ 4,097’ 1 7,477’ 4,092’ 7,518’ 4,091’ 1 7,943’ 4,088’ 7,984’ 4,088’ 1 9,696’ 4,065’ 9,737’ 4,064’ 1 10,227’ 4,068’ 10,268’ 4,069’ 1 11,035’ 4,068’ 11,076’ 4,067’ 1 11,661’ 4,082’ 11,702’ 4,083’ 1 12,243’ 4,085’ 12,285’ 4,085’ 1 12,816’ 4,090’ 12,857’ 4,090’ 1 13,233’ 4,088’ 13,274’ 4,087’ TD =13,437’(MD) / TD =4,082’(TVD) 20” Orig. KB Elev.:63.24’ / GL Elev.: 37.0’ 3-1/2” 2 9-5/8” 1 3/4 6 See Screen Liner Detail PBTD =13,437’ (MD) / PBTD =4,082’(TVD) 9-5/8” ‘ES’ Cementer @ 2,239’ 4-1/2” 5 CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF 20" Conductor 129.5 / X-52 / Weld N/A Surface 117’ N/A 9-5/8" Surface 47 / L-80 / TXP 8.525” Surface 2,239’ 0.0732 9-5/8" Surface 40 / L-80 / TXP 8.679” 2,239’ 5,242’ 0.0758 4-1/2” Liner 13.5 / L-80 / Hyd 625 3.795” 5,047’ 13,437’ 0.0149 TUBING DETAIL 3-1/2" Tubing 9.3 / L-80 / EUE 8RD 2.992” Surf 5,056’ 0.0087 JEWELRY DETAIL No Top MD Item ID Upper Completion 1 4,600’ Zenith G6 Gauge 400 Bar 150C, 2 Press 2 Temp 2.992” 2 4,653’ XN Nipple, 2.85” Bottom No-Go, 2.813” Packing Bore 2.750” 3 5,045’ 8.25” No Go Locater Sub (3.61’ off No-go) 2.970” 4 5,046’ Bullet Seals – TXP Top Box x Mule Shoe 6.160” Lower Completion 5 5,047’ 9-5/8” SLZXP Liner Top Packer 7.020” 6 13,435’ Shoe 3.950” OPEN HOLE / CEMENT DETAIL 44” 18.5 Bbls Concrete 12-1/4"Stg 1 –Lead 366 sx / Tail 391 sx Stg 2 –Lead 710 sx / Tail 270 sx 8-1/2” Cementless Screen Liner WELL INCLINATION DETAIL KOP @ 433’ MD Max Hole Angle = 93° TREE & WELLHEAD Tree Cameron 3 1/8" 5M w/ 4-1/16” 5M Cameron Wing Wellhead Cameron 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs GENERAL WELL INFO API#: 50-029-23694-00-00 Completed by Innovation: 7/8/2021 _____________________________________________________________________________________ Revised By: TDF 11/2/2021 PROPOSED Milne Point Unit Well: MPU S-44 PTD: 50-029-23694-00-00 API: 221-044 TD =13,437’(MD) / TD =4,082’(TVD) 20” Orig. KB Elev.:63.24’ / GL Elev.: 37.0’ 3-1/2” 2 9-5/8” 1 3/4 6 See Screen Liner Detail PBTD =13,437’ (MD) / PBTD =4,082’(TVD) 9-5/8” ‘ES’ Cementer @ 2,239’ 4-1/2” 5 CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF 20" Conductor 129.5 / X-52 / Weld N/A Surface 117’ N/A 9-5/8" Surface 47 / L-80 / TXP 8.525” Surface 2,239’ 0.0732 9-5/8" Surface 40 / L-80 / TXP 8.679” 2,239’ 5,242’ 0.0758 4-1/2” Liner 13.5 / L-80 / Hyd 625 3.795” 5,047’ 13,437’ 0.0149 TUBING DETAIL 3-1/2" Tubing 9.3 / L-80 / EUE 8RD 2.992” Surf 5,056’ 0.0087 OPEN HOLE / CEMENT DETAIL 44” 18.5 Bbls Concrete 12-1/4"Stg 1 –Lead 366 sx / Tail 391 sx Stg 2 –Lead 710 sx / Tail 270 sx 8-1/2” Cementless Screen Liner WELL INCLINATION DETAIL KOP @ 433’ MD Max Hole Angle = 93° TREE & WELLHEAD Tree Cameron 3 1/8" 5M w/ 4-1/16” 5M Cameron Wing Wellhead Cameron 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs JEWELRY DETAIL No Top MD Item ID Upper Completion 1 4,600’ Zenith G6 Gauge 400 Bar 150C, 2 Press 2 Temp 2.992” 2 4,653’ XN Nipple, 2.85” Bottom No-Go, 2.813” Packing Bore 2.750” 3 5,045’ 8.25” No Go Locater Sub (3.61’ off No-go) 2.970” 4 5,046’ Bullet Seals – TXP Top Box x Mule Shoe 6.160” Lower Completion 5 5,047’ 9-5/8” SLZXP Liner Top Packer 7.020” 6 13,435’ Shoe 3.950” PERFORATION DETAIL Schrader Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status Schrader ±5,464’ ±5,474’ ±4,110’ ±4,110’ ±10’ Future Future ±6,071’ ±6,081’ ±4,105’ ±4,105’ ±10’ Future Future ±6,474’ ±6,484’ ±4,108’ ±4,108’ ±10’ Future Future ±7,016’ ±7,026’ ±4,099’ ±4,099’ ±10’ Future Future ±7,215’ ±7,225’ ±4,097’ ±4,096’ ±10’ Future Future ±7,538’ ±7,548’ ±4,091’ ±4,091’ ±10’ Future Future ±8,004’ ±8,014’ ±4,088’ ±4,088’ ±10’ Future Future ±9,757’ ±9,767’ ±4,064’ ±4,064’ ±10’ Future Future ±10,288’ ±10,298’ ±4,069’ ±4,069’ ±10’ Future Future ±11,096’ ±11,106’ ±4,067’ ±4,067’ ±10’ Future Future ±11,722’ ±11,732’ ±4,084’ ±4,084’ ±10’ Future Future ±12,305’ ±12,315’ ±4,085’ ±4,085’ ±10’ Future Future ±12,877’ ±12,887’ ±4,091’ ±4,091’ ±10’ Future Future ±13,180’ ±13,190’ ±4,089’ ±4,089’ ±10’ Future Future Ugnu – TCP 5” 5132 Razor RDX SBH TL LD, 16 spf (32.0 gr, 1.04 EH, 6.7 Pen) _____________________________________________________________________________________ Revised By: TDF 11/2/2021 PROPOSED Milne Point Unit Well: MPU S-44 PTD: 50-029-23694-00-00 API: 221-044 4-1/2” Screen Liner Detail Jts Top (MD) Top (TVD) Btm (MD) Btm (TVD) 1 5,402’ 4,111’ 5,444’ 4,110’ 1 6,010’ 4,105’ 6,051’ 4,105’ 1 6,423’ 4,108’ 6,454’ 4,108’ 1 6,955’ 4,100’ 6,996’ 4,099’ 1 7,153’ 4,097’ 7,195’ 4,097’ 1 7,477’ 4,092’ 7,518’ 4,091’ 1 7,943’ 4,088’ 7,984’ 4,088’ 1 9,696’ 4,065’ 9,737’ 4,064’ 1 10,227’ 4,068’ 10,268’ 4,069’ 1 11,035’ 4,068’ 11,076’ 4,067’ 1 11,661’ 4,082’ 11,702’ 4,083’ 1 12,243’ 4,085’ 12,285’ 4,085’ 1 12,816’ 4,090’ 12,857’ 4,090’ 1 13,233’ 4,088’ 13,274’ 4,087’ GENERAL WELL INFO API#: 50-029-23694-00-00 Completed by Innovation: 7/8/2021 Add Perf MPU S-44 Date 10/27/21 Coil Tubing BOPE MEMORANDUM TO: Jim Regg�, 1 l 7U� P.I. Supervisor FROM: Bob Noble Petroleum Inspector I Well Name MILNE PT UNIT S-44 Insp Num: mitRCN211025170032 Rel Insp Num: NON -CONFIDENTIAL State of Alaska Alaska Oil and Gas Conservation Commission DATE: Monday, November 1, 2021 SUBJECT: Mechanical Integrity Tests Mlcorp Alaska, LLC S-44 MILNE PT UNIT S44 Src: Inspector Reviewed By: P.I. Supry J Comm API Well Number 50-029-23694-00-00 Inspector Name: Bob Noble Permit Number: 221-044-0 Inspection Date: 10/25/2021 Packer e In Well spa T YP J w JTVD PTD 2210440 'Type Testi SPT `ITest psi BBL Pumped: 4.5 BBL Returned: Interval INITAL jPAF Notes: Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Tubing 86 - 88 86 -86 4096 � 1500 IA 0 1914 1815 1786 - 2-5 - OA i P Monday, November 1, 2021 Page 1 of I DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-23694-00-00Well Name/No. MILNE PT UNIT S-44Completion Status1WINJCompletion Date7/8/2021Permit to Drill2210440Operator Hilcorp Alaska, LLCMD13437TVD4082Current Status1WINJ7/27/2021UICYesWell Log Information:DigitalMed/FrmtReceivedStart StopOH /CHCommentsLogMediaRunNoElectr DatasetNumberNameIntervalList of Logs Obtained:ROP, AGR, ABG, DGR, EWR, ADR MD & TVDNoNoYesMud Log Samples Directional SurveyREQUIRED INFORMATION(from Master Well Data/Logs)DATA INFORMATIONLog/DataTypeLogScaleDF7/13/20215235 13400 Electronic Data Set, Filename: MPU S-44 ADR Quadrants All Curves.las35353EDDigital DataDF7/13/2021 Electronic File: MPU S-44 Geosteering End of Well Report.pdf35353EDDigital DataDF7/13/2021 Electronic File: MPU S-44 Geosteering EOW Plot.emf35353EDDigital DataDF7/13/2021 Electronic File: MPU S-44 Geosteering EOW Plot.pdf35353EDDigital DataDF7/13/2021 Electronic File: MPU S-44 Geosteering EOW Plot.tif35353EDDigital DataDF7/13/2021 Electronic File: MPU S-44 Geosteering EOW Plot300dpi.tif35353EDDigital DataDF7/13/2021 Electronic File: MPU S-44 Post-Well Geosteering X-Section Summary.pdf35353EDDigital DataDF7/13/2021 Electronic File: MPU_S-44_Geosteering.dlis35353EDDigital DataDF7/13/2021 Electronic File: MPU_S-44_Geosteering.ver35353EDDigital Data0 0 2210440 MILNE PT UNIT S-44 LOG HEADERS35353LogLog Header ScansDF7/13/202195 13437 Electronic Data Set, Filename: MPU S-44 LWD FInal.las35354EDDigital DataDF7/13/2021 Electronic File: MPU S-44 LWD Final TVD.cgm35354EDDigital DataDF7/13/2021 Electronic File: MPU S-44i_Definitive Survey Report.pdf35354EDDigital DataDF7/13/2021 Electronic File: MPU S-44i_DSR.txt35354EDDigital DataDF7/13/2021 Electronic File: MPU S-44i_GIS.txt35354EDDigital DataTuesday, July 27, 2021AOGCCPage 1 of 3MPU S-44 LWDFInal.las DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-23694-00-00Well Name/No. MILNE PT UNIT S-44Completion Status1WINJCompletion Date7/8/2021Permit to Drill2210440Operator Hilcorp Alaska, LLCMD13437TVD4082Current Status1WINJ7/27/2021UICYesWell Cores/Samples Information:ReceivedStart Stop CommentsTotalBoxesSample SetNumberNameIntervalINFORMATION RECEIVEDCompletion ReportProduction Test InformationGeologic Markers/TopsY Y / NAYComments:Mud Logs, Image Files, Digital DataComposite Logs, Image, Data Files Cuttings SamplesY / NAYY / NADirectional / Inclination DataMechanical Integrity Test InformationDaily Operations SummaryYY / NAYCore ChipsCore PhotographsLaboratory AnalysesY / NAY / NAY / NACOMPLIANCE HISTORYDate CommentsDescriptionCompletion Date:7/8/2021Release Date:6/8/2021DF7/13/2021 Electronic File: MPU S-44i_Plan.pdf35354EDDigital DataDF7/13/2021 Electronic File: MPU S-44i_Surveys.xlsx35354EDDigital DataDF7/13/2021 Electronic File: MPU S-44i_VSec.pdf35354EDDigital DataDF7/13/2021 Electronic File: MPU S-44 LWD Final MD.emf35354EDDigital DataDF7/13/2021 Electronic File: MPU S-44 LWD Final TVD.emf35354EDDigital DataDF7/13/2021 Electronic File: MPU S-44 LWD Final MD.pdf35354EDDigital DataDF7/13/2021 Electronic File: MPU S-44 LWD Final TVD.pdf35354EDDigital DataDF7/13/2021 Electronic File: MPU S-44 LWD Final MD.tif35354EDDigital DataDF7/13/2021 Electronic File: MPU S-44 LWD Final TVD.tif35354EDDigital Data0 0 2210440 MILNE PT UNIT S-44 LOG HEADERS35354LogLog Header ScansTuesday, July 27, 2021AOGCCPage 2 of 3 DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-23694-00-00Well Name/No. MILNE PT UNIT S-44Completion Status1WINJCompletion Date7/8/2021Permit to Drill2210440Operator Hilcorp Alaska, LLCMD13437TVD4082Current Status1WINJ7/27/2021UICYesCompliance Reviewed By:Date:Tuesday, July 27, 2021AOGCCPage 3 of 3M.Guhl7/27/2021 MEMORANDUM TO: Jim Regg�, 1 l 7U� P.I. Supervisor FROM: Bob Noble Petroleum Inspector I Well Name MILNE PT UNIT S-44 Insp Num: mitRCN211025170032 Rel Insp Num: NON -CONFIDENTIAL State of Alaska Alaska Oil and Gas Conservation Commission DATE: Monday, November 1, 2021 SUBJECT: Mechanical Integrity Tests Mlcorp Alaska, LLC S-44 MILNE PT UNIT S44 Src: Inspector Reviewed By: P.I. Supry J Comm API Well Number 50-029-23694-00-00 Inspector Name: Bob Noble Permit Number: 221-044-0 Inspection Date: 10/25/2021 Packer e In Well spa T YP J w JTVD PTD 2210440 'Type Testi SPT `ITest psi BBL Pumped: 4.5 BBL Returned: Interval INITAL jPAF Notes: Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Tubing 86 - 88 86 -86 4096 � 1500 IA 0 1914 1815 1786 - 2-5 - OA i P Monday, November 1, 2021 Page 1 of I 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: 37.0' BF: Total Depth: 10. Plug Back Depth MD/TVD: 18. Property Designation: 4b. Location of Well (State Base Plane Coordinates, NAD 27): 11. Total Depth MD/TVD: 19. DNR Approval Number: Surface: x- y- Zone- 4 TPI: x- y- Zone- 4 12. SSSV Depth MD/TVD: 20. Thickness of Permafrost MD/TVD: Total Depth: x- y- Zone- 4 5. Directional or Inclination Survey: Yes (attached) No 13. Water Depth, if Offshore: 21. Re-drill/Lateral Top Window MD/TVD: Submit electronic information per 20 AAC 25.050 (ft MSL) 22.Logs Obtained: 23. BOTTOM 20" X-52 117' L-80 2,012' L-80 4,110' 4-1/2" L-80 4,082' 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 7/5/2021 6/21/2021 ADL 380109 & 025518 01-001 2,043' / 1,842' N/AN/A 13,437' / 4,082' ROP, AGR, ABG, DGR, EWR, ADR MD & TVD Sr Res EngSr Pet GeoSr Pet Eng Oil-Bbl: Water-Bbl: 9-5/8" 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 Water-Bbl: PRODUCTION TEST Not on Injection Date of Test:Gas-Oil Ratio:Choke Size: Flow Tubing 129.5# 47# 117' 2,239' 5,242' Per 20 AAC 25.283 (i)(2) attach electronic information 40# 13,437' 2,012' 4,096' DEPTH SET (MD) 5,047' / 4,096' PACKER SET (MD/TVD) CASING WT. PER FT.GRADE 13.5# BOTTOM TOP 5999936 Surface *** Please see Schematic for Details*** None 12-1/4" CEMENTING RECORD 44" 18.5 Bbls Concrete 565175 563037 TOP SETTING DEPTH MD Surface SETTING DEPTH TVD 6007861 565406 5999865 2006' FNL, 835' FEL, Sec. 12, T12N, R10E, UM, AK 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 Surface HOLE SIZE AMOUNT PULLED 3202' FSL, 605' FEL, Sec. 12, T12N, R10E, UM, AK 657' FSL, 2371' FWL, Sec. 35, T13N, R10E, UM, AK 221-044 Milne Point Field / Schrader Bluff Oil Pool 63.24' 13,437' / 4,082' 50-029-23694-00-00 MPU S-44 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG Hilcorp Alaska, LLC WAG Gas 7/8/2021 Surface 2,239' Stg 1 L - 366 sx / T - 391 sx Stg 2 L - 710 sx / T - 270 sx 5,047' 5,056'3-1/2" 9.3# L-80 SIZEIf Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number; Date Perfd): ACID, FRACTURE, CEMENT SQUEEZE, ETC. CASING, LINER AND CEMENTING RECORD List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data within 90 days of completion, Uncemented Screen Liner8-1/2" TUBING RECORD Liner Top Packer Form 10-407 Revised 3/2020 Submit within 30 days of Completion, Suspension, or Abandonment By Meredith Guhl at 10:22 am, Jul 21, 2021 RBDMS HEW 7/22/2021 Completion Date 7/8/2021 HEW G DSR-7/22/21DLB 07/22/2021 MGR23JUL2021 Conventional Core(s): Yes No Sidewall Cores: 30. MD TVD 40' 40' 2083' 1882' Top of Productive Interval 1564' 1456' 2559' 2288' 3947' 3605' 4940' 4086' 5161' 4106' SB NB 5161' 4106' 31. List of Attachments: 32. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Name: Joe Lastufka Contact Email:joseph.lastufka@hilcorp.com Authorized Contact Phone: 777-8400 General: Item 1a: Item 1b: Item 4b: Item 9: Item 15: Item 19: Item 20: Item 22: Item 23: Item 24: Item 27: Item 28: Item 30: Item 31: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data within 90 days of completion, suspension, or abandonment, whichever occurs first. Well Class - Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and other tests as required including, but not limited to: core analysis, paleontological report, production or well test results. Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29. Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity, permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology. The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Report the Division of Oil & Gas / Division of Mining Land and Water: Plan of Operations (LO/Region YY-123), Land Use Permit (LAS 12345), and/or Easement (ADL 123456) number. INSTRUCTIONS Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. TPI (Top of Producing Interval). Yes No Well tested? Yes No 28. CORE DATA If yes, list intervals and formations tested, briefly summarizing test results. Attach separate pages to this form, if needed, and submit detailed test information, including reports, per 20 AAC 25.071. NAME Schrader Bluff NA SV 5 SV 1 If Yes, list formations and intervals cored (MD/TVD, From/To), and summarize lithology and presence of oil, gas or water (submit separate pages with this form, if needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071. Authorized Name: Monty Myers Authorized Title: Drilling Manager Schrader Bluff NB Permafrost - Base 29. GEOLOGIC MARKERS (List all formations and markers encountered): Formation at total depth: Ugnu LA3 FORMATION TESTS Permafrost - Top This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed. All laboratory analytical reports regarding samples or tests from a well must be submitted to the AOGCC, no matter when the analyses are conducted. Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, core analysis, paleontological report, production or well test results, per 20 AAC 25.070. LOT / FIT Data Sheet, Drilling and Completion Reports, Definitive Directional Survey, Wellbore Schematic Signature w/Date: Form 10-407 Revised 3/2020 Submit within 30 days of Completion, Suspension, or Abandonment 7.21.2021Digitally signed by Monty M Myers DN: cn=Monty M Myers, c=US, o=Hilcorp Alaska, LLC, ou=Technical Services - AK Drilling, email=mmyers@hilcorp.com Reason: I am approving this document Date: 2021.07.21 10:13:33 -08'00' Monty M Myers 6%1% _____________________________________________________________________________________ Revised By: JNL 7/21/21 SCHEMATIC Milne Point Unit Well: MPU S-44 PTD: 50-029-23694-00-00 API: 221-044 4-1/2” SCREEN Liner Jts Top (MD) Btm (MD) Top (MD) Btm (TVD) 1 5,402’ 4,111’ 5,444’ 4,110’ 1 6,010’ 4,105’ 6,051’ 4,105’ 1 6,423’ 4,108’ 6,454’ 4,108’ 1 6,955’ 4,100’ 6,996’ 4,099’ 1 7,153’ 4,097’ 7,195’ 4,097’ 1 7,477’ 4,092’ 7,518’ 4,091’ 1 7,943’ 4,088’ 7,984’ 4,088’ 1 9,696’ 4,065’ 9,737’ 4,064’ 1 10,227’ 4,068’ 10,268’ 4,069’ 1 11,035’ 4,068’ 11,076’ 4,067’ 1 11,661’ 4,082’ 11,702’ 4,083’ 1 12,243’ 4,085’ 12,285’ 4,085’ 1 12,816’ 4,090’ 12,857’ 4,090’ 1 13,233’ 4,088’ 13,274’ 4,087’ TD =13,437’(MD) / TD =4,082’(TVD) 20” Orig. KB Elev.:63.24’ / GL Elev.: 37.0’ 3-1/2” 2 9-5/8” 1 3/4 6 See Screen Liner Detail PBTD =13,437’ (MD) / PBTD =4,082’(TVD) 9-5/8” ‘ES’ Cementer @ 2,239’ 4-1/2” 5 CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF 20" Conductor 129.5 / X-52 / Weld N/A Surface 117’ N/A 9-5/8" Surface 47 / L-80 / TXP 8.525” Surface 2,239’ 0.0732 9-5/8" Surface 40 / L-80 / TXP 8.679” 2,239’ 5,242’ 0.0758 4-1/2” Liner 13.5 / L-80 / Hyd 625 3.795” 5,047’ 13,437’ 0.0149 TUBING DETAIL 3-1/2" Tubing 9.3 / L-80 / EUE 8RD 2.992” Surf 5,056’ 0.0087 JEWELRY DETAIL No Top MD Item ID Upper Completion 1 4,600’ Zenith G6 Gauge 400 Bar 150C, 2 Press 2 Temp 2.992” 2 4,653’ XN Nipple, 2.85” Bottom No-Go, 2.813” Packing Bore 2.750” 3 5,045’ 8.25” No Go Locater Sub (3.61’ off No-go) 2.970” 4 5,046’ Bullet Seals – TXP Top Box x Mule Shoe 6.160” Lower Completion 5 5,047’ 9-5/8” SLZXP Liner Top Packer 7.020” 6 13,435’ Shoe 3.950” OPEN HOLE / CEMENT DETAIL 44” 18.5 Bbls Concrete 12-1/4"Stg 1 –Lead 366 sx / Tail 391 sx Stg 2 –Lead 710 sx / Tail 270 sx 8-1/2” Cementless Screen Liner WELL INCLINATION DETAIL KOP @ 433’ MD Max Hole Angle = 93° TREE & WELLHEAD Tree Cameron 3 1/8" 5M w/ 4-1/16” 5M Cameron Wing Wellhead Cameron 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs GENERAL WELL INFO API#: 50-029-23694-00-00 Completed by Innovation: 7/8/2021 CASING AND LEAK-OFF FRACTURE TESTS Well Name:MPU S-44 Date:6/28/2021 Csg Size/Wt/Grade: 9.625 40#/47# L-80 Supervisor:Anderson / Vanderpool Csg Setting Depth:5,242 4,109 TVD Mud Weight:8.9 ppg LOT / FIT Press =690 psi LOT / FIT =12.13 ppg Hole Depth =5272 md Fluid Pumped=1.1 Bbls Volume Back =1.1 bbls Estimated Pump Output:0.062 Barrels/Stroke LOT / FIT DATA CASING TEST DATA Enter Strokes Enter Pressure Enter Strokes Enter Pressure Here Here Here Here ->250 ->030 ->4129 ->478 ->6213 ->12 250 ->8318 ->20 510 ->10 419 ->28 750 ->12 499 ->36 1032 ->14 589 ->44 1309 ->16 663 ->52 1588 ->17 690 ->60 1870 ->20 ->70 2230 ->22 ->74 2369 ->24 ->82 2655 ->26 ->84 2736 ->28 -> Enter Holding Enter Holding Enter Holding Time Here Pressure Here Time Here Pressure Here ->0670 ->02736 ->1628 ->52728 ->2601 ->10 2721 ->3580 ->15 2718 ->4567 ->20 2714 ->5555 ->25 2711 ->6546 ->30 2707 ->7536 -> ->8527 -> ->9519 -> ->10 512 -> -> -> -> -> -> -> 2 4 6 8 10 12 14 1617 0 4 12 20 28 36 44 52 60 70 74 82 84 0 100 200 300 400 500 600 700 800 900 1000 1100 1200 1300 1400 1500 1600 1700 1800 1900 2000 2100 2200 2300 2400 2500 2600 2700 2800 2900 3000 3100 3200 3300 3400 3500 3600 3700 3800 3900 4000 0 102030405060708090Pressure (psi)Strokes (# of) LOT / FIT DATA CASING TEST DATA 670628601580567555546536527519512 2736 2728 2721 2718 2714 2711 2707 0 100 200 300 400 500 600 700 800 900 1000 1100 1200 1300 1400 1500 1600 1700 1800 1900 2000 2100 2200 2300 2400 2500 2600 2700 2800 2900 3000 3100 3200 3300 3400 3500 3600 3700 3800 3900 4000 0 5 10 15 20 25 30Pressure (psi)Time (Minutes) LOT / FIT DATA CASING TEST DATA Activity Date Ops Summary 6/19/2021 Cont walk Sub off S-45. Crab walk Sub down well row to S-44. Level pad around cellar. Lay down Herculite and matt boards. Walk sub over S-44 W/ D9 and center W/ stompers. Cont lay down matt boards. Set down out riggers Spot diverter sections. Spot Catwalk. Safe out stairs and scope cattle chute. 6/20/2021 Cont set mats. Set Mud & Gen mods. NES trucks released @ 07:30. SIMOPS assy MP fluid ends. Spot break & enviro vac. Hook up inner connects throughout rig. Build containment for cutting box & spot. Safe out all landings, stairs & walkways. Safe out hand rails and roof hatches. Went to Gen power @ 09:45. Run high line power cable, went to high line power @ 10:40. Stage Beyond MPD conex. Scope up derrick and bridle down. Cont painting jeep wheels in shop. C/O hydraulic filter on catwalk HPU. Work on rig acceptance check list. Bring steam, H2O and air throughout rig. Cont assy mud pump fluid ends. Dress shakers to 100's. Test centrifuge. Free up feed pump for centrifuge 1. Cont working on rig acceptance check list. PJSM Remove RCD head on stack. Install speed head on conductor as per NOS. Install diverter tee and set stack. Install companion flange and plug valve on kill line. PM Degasser. Bring on 620 bbls 8.6 ppg spud mud to pits. Perform Koomey inspection. PJSM Trq speed head, Tee and stack (2.3K ft/lb). Install bell nipple and riser. Center stack W/chain binders. Chase threads on knife valve. Install knife valve. Install 3 ea 16" diverter sections between stack and catwalk. Roads and pads crane in location at 21:30. Install 4 sections 16" diverter past catwalk. Release crane at 22:30. Run spud mud through MP 1 &2. Cont bring spud mud into pits. Finish bolt up on diverter. Secure stands for diverter. Install 5" hydraulic elevators. Install drain lines drip pan. Rig acceded at 01:00. Perform Annular closure 10 sec, knife 5 sec. Test H2S 10-20 ppm, LEL 20-40%, PVT high/ low level alarms. Checked PVT sensors and return flow. Koomey draw drown Initial System 3,000 PSI, after System 2,000 PSI, 200 PSI increase 16 Sec, full charge 56 sec. Nitrogen 6 bottle average 2,283 PSI. Witnessed waived by AOGCC Bob Noble. PJSM P/U M/U singles 5" 19.5# S-125 NC50 D.P. and rack back in derrick. (130 jnts) Drift OD 3.125". Daily Disposal to G&I = 0 bbls, total = 0 bbls. Daily Water from S-Pad Creek = 480 bbls. Total Water from S-Pad Creek = 480 bbls. Daily Metal: 0 lb. Total Metal 0 lb. 6/21/2021 Continue P/U and rack back a total of 82 stds 5" S-135 NC50 19.5# drill pipe (3.125" drift), Rack back 9 stds 5" S-135 NC50 49.5# HWDP w/ jars (2.75" drift). Mob BHA components to rig floor. Install split bushings. Prep pipeshed with BHA. Perform diverter rig evacuation drill with all personnel onsite. Muster @ primary muster point at entrance of location (truck shop). All personnel accounted for with post discussion (3rd party involvement). Stand down drill. M/U 12-1/4" kymera w/ 1.50° Mtr. Flood surface lines and conductor. P/T high psi mud lines to 3000 psi with no leaks. No leaks observed on diverter system. Dry tag ice @ 30' MD. Wash down from 30' to btm of conductor @ 107' with H2O, 400 gpm, 250 psi. Displace to spud mud on the fly @ 107' MD Drlg 12.25" surface hole F/ 107' - T/ 220' md with dumb iron motor assy. 450 gpm, 550 psi, 40 rpm, 1.7k tq, 3-5k wob, 46k up, 42k dn, 42k rot. 100-150 fph. BROOH F/ 220 to 180' then pull clean to surface racking back HWDP. Inspect bit (no damage). M/U GWD/DM/TM MWD tools, UBHO sub.. Scribe MWD to Gyro 186/794=84.33° RFO, MWD to Mtr 20/797 = 9.03° RFO. Upload MWD. M/U Flex DC.s. XO and 5" HWDP. Trip in to 220' MD (no fill). PJSM Rotary Drill 12.25" Surface Hole F/ 200' to 424' MD ( 424' TVD) Total 224’ (AROP 56’) 450 GPM, 960 psi 40 RPM, TRQ on 1.3k, TRQ off 1.2k, F/O 60%, WOB 4k. ECD 8.89. Max Gas 13u. P/U 58k, SLK 57k, ROT 58k. Slide/ Rot 12.25" Surface Hole F/ 424' to 593' MD ( 592' TVD) Total 169’ (AROP 56’) 445 GPM, 1,350 psi 40 RPM, TRQ on 1.8k, TRQ off 1.8k, F/O 60%, WOB 15k. ECD 9.45. Max Gas 13k. P/U 64k, SLK 68k, ROT 68k. Start build 4°/100 at 424' MD. F/ Gyro to magnetic MWD survey 496', Bit 533' MD. Clean Magnet Slide/ Rot 12.25" Surface Hole F/ 593' to 1,292' MD (1,236' TVD) Total 699’ (AROP 116.5’) 475 GPM, 1,475 psi 50 RPM, TRQ on 4-5k, TRQ off 3k, F/O 65%, WOB 8-12k. ECD 9.84. Max Gas 116u. P/U 77K, SLK 75K, ROT 74K. Jet flowline every other stand. Cont build 4°/100 as per plan.. Distance to WP06: 9.2', 8.64' High, 3.15' Left Daily Disposal to G&I = 285 bbls, total = 285 bbls. Daily Water from S-Pad Creek = 400 bbls. Total Water from S-Pad Creek = 880 bbls. Daily Metal: 0 lb. Total Metal 0 lb. 6/22/2021 Slide/ Rot 12.25" Surface hole from 1292' MD to 2118' MD (1910' TVD). Total 826' (AROP 137.6 ft/hr) 500 gpm, 1600 psi, 60 rpm, TRQ on 4.5K, TRQ off 3K, F/O 58%, WOB 4-6K, ECD 10.1, Max Gas 348u. P/U 94K, SLK 78K, ROT 86K. Base Permafrost at 2082' (1882' TVD). End 4°/100 at 1,325' MD. Hold tangent 35° inc 170.5ô azi F/ 1,325' to 2,500' MD. Slide/ Rot 12.25" Surface Hole F/ 2,118' to 2,882' MD (2,586' TVD) Total 764’ (AROP 127.4’) 525 GPM, 1,575 psi 60 RPM, TRQ on 4-6k, TRQ off 3-5k, F/O 55%, WOB 2-12k. ECD 9.71 . Max Gas 813u. P/U 114K, SLK 90K, ROT 101K. Back ream 15' per stand. Drop 4°/100 at 2,500' MD. Drop 5°/100 at 2,800' MD. Slide/ Rot 12.25" Surface Hole F/ 2,882' to 3,294' MD (2.992' TVD) Total 412’ (AROP 68.7’) 525 GPM, 1,686 psi 60 RPM, TRQ on 5-7k, TRQ off 4-7k, F/O 64%, WOB 2-8k. ECD 9.76 . Max Gas 439u. P/U 125K, SLK 100K, ROT 112K. Back ream 30' per stand. At 3,000' MD start 5°/100 3D curve. Slide 12.25" Surface Hole F/ 3,294' to 3,708' MD (3,396' TVD) Total 414’ (AROP 69’) 425 GPM, 1,230 psi , psi off 1,190 F/O 56%, WOB 2-4k. ECD 9.6 . Max Gas 251u. P/U 251K, SLK 135K, ROT 101K. At 3,000' MD start 5°/100 3D curve. At 3,145’ mtr out fell 5°/100 over two surveys fell to 4.3°/100. Projected 1.9° inc 200° azi at 3,271’, never dropped below 3° inc. Racked back 1 stand and decided best plan to slide straight right and carry angle. Slide full stands. Mtr out 5.39°/100 started getting turn. Survey 3,463’ Assy show 6.22° output and 309.31° azi. Hold 90R turning to 335° and start build to 85° W/ 341° azi. Distance to WP06: 30', 7' High, 28' Left Daily Disposal to G&I = 1368 bbls, total = 1653 bbls. Daily Water from S-Pad Creek = 1360 bbls. Total Water from S-Pad Creek = 2240 bbls. Daily Metal: 0 lb. Total Metal 0 lb. 6/23/2021 Drill 12-1/4" surface hole f/ 3708' t/ 4026’ (3665’ TVD) 318' drilled, 53’/hr AROP. 475 GPM, 1775 PSI, 60 RPM, 9k Tq, 7-9k WOB. MW 9.1, Vis 119, 9.7 ECD, Max Gas = 434u. 146k PU / 103k SO / 120k ROT. Target 5° DL for build and turn. Backream full stands Drill 12-1/4" surface hole f/ 4026' t/ 4277’ (3845’ TVD) 251' drilled, 41.83’/hr AROP. 500 GPM, 1790 PSI, 80 RPM, 7-10k Tq, 7-10k WOB. MW 9.1, Vis 67, 9.69 ECD, Max Gas = 389u. 152k PU / 103k SO / 124k ROT. Target 5° DL for build and turn. Backream full stands Drill 12-1/4" surface hole f/ 4277' t/ 4406’ (3918’ TVD) 129' drilled, 43’/hr AROP. 500 GPM, 1712 PSI, 60 RPM, 10-11k Tq, 2-3k WOB. MW 9.1, Vis 70, 9.83 ECD, Max Gas = 304u. 159k PU / 100k SO / 122k ROT. Target 5° DL for build and turn. Backream full stands Assembly hanging up through clays, start oscillating string to achieve more consistent weight to bit transfer, though still experiencing a slow AROP through slide sets. Utilizing 70-87% slide to achieve directional objective. Survey at 4354’ shows an 8.9° DL. BROOH two stands and ream 55’ slide section 2x. Section was ratty with erratic Tq swings first pass, cleaning up after 2nd. Re-shoot survey and see no decrease in DL. Proceed to drill ahead. Drill 12-1/4" surface hole f/ 4406' t/ 4471’ (3950’ TVD) 65' drilled, 32.5’/hr AROP. 500 GPM, 1680 PSI, 60 RPM, 9-12k Tq, 2-10k WOB. MW 9.15, Vis 85, 9.83 ECD, Max Gas = 840u. 159k PU / 102k SO / 120k ROT. Target 5° DL for build and turn. Backream full stands Drill 12-1/4" surface hole f/ 4471' t/ 4789’ (4065’ TVD) 318' drilled, 53’/hr AROP. 500 GPM, 17680 PSI, 60 RPM, 12k Tq, 8k WOB. MW 9.1, Vis 68, 9.63 ECD, Max Gas = 835u. 163k PU / 94k SO / 121k ROT. Target 5° DL for build and turn. Backream full stands Top of UG_MB logged at 4,290’ MD, 3,853’ TVD. Last survey at 4735.52' MD / 4053.84' TVD, 75.38° inc, 340.79° azm, 17.79' from plan, 16.33' low and 7.05' right. Daily Loss = 0 bbls, Cumulative losses = 0 bbls. Daily Disposal to G&I = 798 bbls, total = 2451 bbls. Daily Water from S-Pad Creek = 880 bbls. Total Water from S-Pad Creek = 3120 bbls. Daily Metal: 0 lb. Total Metal 0 lb. 50-029-23694-00-00API #: Well Name: Field: County/State: MP S-44 Milne Point Hilcorp Energy Company Composite Report , Alaska 6/21/2021Spud Date: 6/24/2021 Drill 12-1/4" Surface Hole f/4789' t/ 5252' MD (4110' TVD) casing point (463' total = 66.1 fph AROP). 60 RPM, 10-12k Tq, 2k WOB, 500 GPM, 1930 PSI. ECD 9.92 ppg w/ 9.3 ppg MW. P/U 150k, S/O 93k, ROT 120k. Distance to WP06: 7.23', 7.22' below, 0.36' right. Pump 55 bbl Hi-Vis sweep w/ WALL-NUT. BROOH from 5252’ to 5044' while circulating 3x BU, 525 GPM, 1730 psi, 80 rpms, 10-14k Tq. Sweep back 62 bbls late with no visible increase in cuttings. RIH to bottom with no fill encountered. Monitor well, static. 150k PU, 93k SO BROOH from 5252' to 2309' at 525 gpm, 1672 psi, 80 rpms, 5-8k Tq. Pulling speeds 15-35 fpm as hole dictates. Max gas 106u. PUW 105k, SOW 82k, ROT 94k BROOH f/ 2309' t/ 720', 30-35 FPM, slowing as necessary, 500 GPM, 1200 PSI, 60 RPM, 9-10k Tq. Max gas 150u. Pull slow f/ 2118’ t/ 2054’ while circulating a BU. Pull through BAPF @ 15 FPM, no issues. Monitor Well – Static. Attempt to pull HWDP on elevators with no success, seeing 15k overpull. Continue BROOH t/ 596’ where assembly was able to pull on elevators. No losses recorded while BROOH POOH on elevators from 596', rack back HWDP/Jars. L/D (2) DC. Plug in and download MWD. Daily Disposal to G&I = 798 bbls, total = 3249 bbls. Daily Water from S-Pad Creek = 1040 bbls. Total Water from S-Pad Creek = 4160 bbls. Daily Metal: 0 lb. Total Metal 0 lb. Daily Mud lost to formation 0 bbls, total = 0 bbls. 6/25/2021 Continue download MWD. L/D Remaining BHA, UBHO sub, TM, EWR & DM collars. Drain mud motor and L/D bit. Dull Bit Grade: 1-3-BT-S-X-IN-NO-TD (PDC), 1- 1-NO-A-E-I-NO-TD (Cone). SimOps while plugged into MWD: Bring centralizers to rig floor Rig up to RIH with 9-5/8" casing. . M/U Volant CRT tool, bail extensions, elevators, double stack power tongs. PJSM. RIH with 9-5/8", 40#, L-80 TXP casing. M/U shoe track, baker lock first 4 connections. Check floats – good. Install bypass baffle on top of float collar. Continue to RIH with 9-5/8" casing as per tally to 530'. PUW 48K SOW 47K Torque all connections to 20,960 ft/lbs w/ Weatherford double stack tongs, Two 9-5/8" x 12-1/4" centralizer & 4 stop rings on shoe jt, 1 free floating centralizer on Baker-Loc jt, 1 centralizer w/ 2 stop rings on the float collar and baffle adapter jts. 1 free floating centralizer every jt #5-13 Run 9-5/8" 40# L-80 TXP-BTC casing f/ 530' t/ 2230'. 110k PU, 88k SO. Torque to 20,960 ft/lbs with Weatherford double stack tongs. Fill casing every 5 jts & top off every 10 joints. Install 9-5/8"x12-1/4" centralizer on every joint 6-26 and every other joint #28 to 50. CBU at 2230', stage pump to 6 bpm, 120 psi Run 9-5/8" 40# L-80 TXP-BTC casing f/ 2230' t/ 2982'. Torque to 20,960 ft/lbs with Weatherford double stack tongs. Install 9-5/8" x 12-1/4" bow spring centralizers on every joint #70-75. Fill casing every 5 jts & top off every 10 joints. Installed ES cementer between joints #75 & #76, thread lock both connections. One centralizer & 2 stop rings installed on each pup joint above and below the ES cementer. Run 9-5/8" 47# L-80 TXP-BTC casing from 3020’, joint #76, to 5244’ Torque to 23,820 ft/lbs with Weatherford double stack tongs. Install centralizers every joint f/ #76 to #81, then every other jt f/ #83 t/ #127. Fill casing every 5 jts & top off every 10 joints. 130 total joints ran, 75 each 40# and 55 each 47#. 76 total 9-5/8" x 12-1/4" bow spring centralizers ran and 12 stop rings. 44 bbls total lost while running casing. Circulate and condition the mud one S/S circulation until even mud in/out. Staged pumps up t/ 6 BPM, 240 psi. Start Rot 1-5 RPM, 17K Tq @ 3 BPM pump rate. Reciprocate 30-38' f/ 5244'. MW 9.4 in / 9.4 out, Max Gas @ BU = 53u. 246K PU / 126K SO. No losses recorded. Monitor Well 30 min. Static. Continue circulate and condition the mud, stage pumps up t/ 6 BPM, 200 psi. Rot 1-5 RPM, 17K Tq, Reciprocate 30-38' f/ 5244'. SimOps: Remove 20’ section of diverter vent line, mobilize HES cement equipment to West side of pad and nipple diverter line back up. Spot HES equipment, SS & Vac trucks into place. Rig up HES cementers. Daily Disposal to G&I = 939 bbls, total = 4188 bbls. Daily Water from S-Pad Creek = 480 bbls. Total Water from S-Pad Creek = 4640 bbls. Daily Metal: 0 lb. Total Metal 0 lb. Daily Mud lost to formation 44 bbls, total = 44 bbls. 6/26/2021 Break Volant CRT out of stump, inspect and make back up to string. Circulate through bleeder to clean out flow line, clean both mud pump suction screens. Blow air to cementers to ensure line clear. Rig up cement hoses to Volant CRT, and break circulation staging up to 5.5 bpm, 340 psi through the cement line. Hold PJSM with rig crew, HES crew, Baroid & ASRC on 1st stage cement job HES pump 5 bbls fresh water, 2 BPM, 80 PSI. PT lines to 1000 PSI low / 4000 PSI high. Mix & pump 55 bbls of 10.0 ppg Tuned Spacer w/ 4# red dye & 5# Pol-E-Flake in 1st 10 bbls, 5.7 BPM, 345 PSI. Drop by-pass plug. Mix & pump 153 bbls of 12.0 ppg lead cmt (366 sks @ 2.347^3/sk yield), 5.6 BPM, 566 PSI Mix & pump 80 bbls of 15.8 ppg tail cmt (391 sks @ 1.15^3/sk yield), 5.5 BPM, 892 PSI. Drop shut-off plug. Pump 20 bbls fresh water, 5.6 BPM, 339 PSI. Displace cmt with 187 bbls, 9.4 ppg spud mud with rig pumps 5 BPM, 202 PSI HES pump 90 bbls 9.4 ppg tuned spacer, 4.8 BPM, 175 PSI. Cont displace from rig 80.3 bbls, 5 bpm, 806 psi. plug bumped @ 4300 stks, 5.2 bbls early FCP 902 psi, Pressure to 1400 psi, hold for 5 min, Bleed off and check floats. Holding. Pressure to 3550 psi shifting ESC tool open at 2238'. CIP @ 10:23 Rot and recip string until 209 bbls into displacement. Work string and attempt to get back on depth. Pick up to 355k (110k over) and slack off with all available weight for 20 min while finishing displacement with no success. Set string at 5242’ md prior to bumping plug. No losses recorded. Submit 24 hr notice to AOGCC for upcoming BOP test @ 08:30. CBU 2x thru ESC @ 2238' stage pump to 6 bpm, 380 psi, dump contaminated returns to cuttings box. Dumped total 186 bbls, 71 bbls clabbored interface, 55 bbls cmt, and 60 bbls spacer. Shut pumps down for 5 min, allowing formation to slough. Cont to pump 6 bpm, 380 psi. CBU another 2x. Shut pumps down. Disconnect Knife valve from accumulator. Drain stack and flush with black water pills while function annular. Reconnect knife valve. Cont. circulating through ES cementer at 6 bpm, 390 psi while prepping pits for second stage and WOC. SimOps: Clean pump suction screens, jet flowline and mobile Wellhead equipment and emergency slips into cellar. Perform 2nd stage cmt job. Flood lines w/ 5 bbls water. Mix & pump 55 bbls of of 10.0 ppg Tuned Spacer 5.5 BPM, 330 PSI. Mix & pump 365 bbls of 10.7 ppg ArcticCem Lead Cement 2.88 ft^3/sk yield, 710 sks, 5.8 BPM, 640 PSI. Interface back @ 225 bbls, dump to cutting box. Good cmt back @ 350 bbls Mix and pump 56 bbls 15.8 ppg Premium G Tail Cement 1.169 ft^3/sk yield, 270 sks, 3.5 BPM, 370 PSI. Drop closing plug. HES pump 20 bbls water 6 BPM, 400 PSI. Displace w/ 141.6 bbls 9.4 ppg spud mud @ 6 BPM, 330 psi ICP / 891 psi FCP. Slow to 2 BPM, 500 PSI for last 10 bbls. Bump plug at 2285 stks (41 stks under calculated). Pressure up, ESC shifted close at 1400 PSI. CIP at 20:35. 230 bbls of cement, 70 bbls of interface, and 55 bbl spacer returned to surface. Full returns throughout 2nd stage. PJSM Disconnect cement lines and flush W/ back water. Disconnect knife valve and flush stack 3x w/ black water. Break out Volant tool and L/D. Disconnect and rig down diverter line W/ crane. Install 9.625" elevators. B/D lines and clean cellar box. Install bridge cranes to Stack and remove binders. P/U Stack and set emergency slips as per NOS rep onsite. (115K in slips). SimOps: Flush lines and pumps in pits. Begin offloading surface mud. P/U Stack and make initial cut on 9.625" csg and L/D cut jt, (32.36'). Remove 9-5/8” handling equipment f/ rig floor. Set Stack back down. P/U M/U 5" working single & Stack washer. Flush Stack w/ black water. L/D single and stack washer. B/D Top Drive and mud lines. Remove riser & knife valve, P/U Stack and break off speed head. Remove speed head, DSA and diverter tee. Set Stack on pedestal. Make final cut on 9.625" Csg 22" above E Slips and dress stump. Clean out stud holes on annular and install MPD RCD mounting studs. SimOps: Cleaning Mud Pits and Suction manifolds on Mud Pumps PJSM P/U MPD RCD w/ top drive and hang below flow box. P/U Stack and move under RCD, lift Stack and bolt up RCD. Move Stack back to pedestal. Install Cameron T-103 nipple & fill w/ plastic. SimOps: Torque MPD RCD bolts t/ annular. Continue with pit cleaning. Daily Disposal to G&I = 1483 bbls, total = 5671 bbls. Daily Water from S-Pad Creek = 1040 bbls. Total Water from S-Pad Creek = 5680 bbls. Daily Metal: 0 lb. Total Metal 0 lb. Daily Mud lost to formation 0 bbls, total = 44 bbls. 6/27/2021 Continue Install Cameron T-103 nipple & fill w/ plastic. Test to 500/3800 psi, 5/10 min – Good. Install tubing spool and test void 500/5000 psi 5/10 min. Set test plug in tubing spool and RILDS. SimOps: Torque MPD RCD mounting bolts. Install DSA, 2’ spacer spool & BOP stack. Install drip pan, choke & kill lines. Obtain RKB measurements. SimOps: M/U valve assembly on rig floor. P/U split bushings, load test jts in shed grease crown and cont cleaning pits. Install 1502 flanges on IA & OA. Finish trq BOPE studs. Secure BOP W/ turnbuckles. Install hole fill & beyond hard lines. SIMOPS M/U valve assembly on rig floor. Grease choke manifold. Install mouse hole and R/U 5” elevators De-Energize accumulator. Change out UPR to 2-7/8”x5.5” VBR. Re-Energize accumulator. Fill Stack and circ through BEYOND MPD lines checking for leaks. PT MPD Surface Equip. to 250/1200 psi. Blow down lines R/D MPD Cap and install flow riser. M/U 5" test jt and valve assembly to test plug, R/U Top Drive and Test Hoses. Fill stack, flood system and purge of air. Perform body test to 1500 psi. - Good Test BOPE as per PTD & AOGCC requirements. Man Super and Super chokes tested to 1600 psi, all other tests performed to 250 PSI low / 3000 PSI high. All tests held for 5 min. each & performed w/ fresh water against test plug. AOGCC rep Adam Earl waived witness for BOP test @ 17:59 hrs 06/26/2021. #1: Annular on 5" test joint, choke valves #11, 12,13,14,15, #3" kill, 5” dart valve & upper IBOP. #2: Upper 2-7/8"x5.5" VBR on 5" test joint, choke valves #7, 8,9,10, 5” FOSV #1, HCR Kill, #3: Manual Super Choke. #4: Manual Kill, Choke valves #4, 5 & 6. #5: Lower 2-7/8"x5.5" VBR on 5" test joint #6: Blind rams, choke valve #1, 2 & 3. #7: Annular on 3.5" test joint, 5” FOSV #2, HCR Choke. #8: Upper 2-7/8"x5.5" VBR on 3.5" test joint, Manual Choke. #9: Lower 2-7/8"x5.5" VBR on 3.5" test joint. #10: Super Choke Accum test: 3050 PSI system pressure, 1550 PSI after closure. 26 sec for 200 PSI recharge, 98 sec full PSI recharge. 2350 PSI six nitrogen bottle average. Test gas, PVT and flow alarms. 1 F/P – Superchoke fail, C/O seals & upper disk, re-test pass. R/D Test Equipment, Pull Test plug and L/D same. Blow down choke/Kill lines. Install 10" ID Wear Bushing. RILDS (4) P/U 8.5" Bit, M/U Motor, RIH with 9 stds HWDP/Jars out of Derrick to 590'. Single in hole P/U 5" DP from 590' to 2084'. Drift with 3.125 Drift. PUW 91k, SO, 71k. Establish parameters at 2084’ MD. 400 gpm, 750 psi, 40 rpm, 4.5 k trq, Wash/Ream down, tag up at 2236'. ES on depth at 2,238’ MD. Drill plug & ES t/ 2242' w/ 6-10k WOB. Swab leaking on #2 MP @ 2239'. Drill with 1 MP @ 320 GPM, 545 psi. 50 RPM 5k Tq. Ream through 2x and pass through with no pumps. Continue to single in hole P/U 5" DP from 2242' to 4725'. Drift with 3.125 Drift. PUW 169k, SO, 80k. Daily Disposal to G&I = 632 bbls, total = 6303 bbls. Daily Water from S-Pad Creek = 320 bbls. Total Water from S-Pad Creek = 6000bls. Daily Metal: 0 lb. Total Metal 0 lb. Daily Mud lost to formation 0 bbls, total = 44 bbls. 6/28/2021 TIH w/ 5” DP stands out of Derrick f/ 4725' t/ 5042'. Wash down f/ 5042' t/ 5105', 200 GPM. No cement stringers encountered. Circulate a bottoms up at 5105', 500 GPM, 935 PSI, 30 RPM, 13.5k Tq. Reciprocate 60'. 183k PU / 82k SO / 115k ROT. Install FOSV, slip and cut 113' drilling line, Inspect Drawworks brakes. Torque deadman mounting bolts to spec @ 225 ft/lbs. Perform EAM for crown sheave wobble. Inspect/service Iron roughneck, blocks and TopDrive. Calibrate drawworks/block height. Rig up test equipment. Close upper 2-7/8"x5.5" VBR on 5" drill pipe. Pump down drill pipe and kill line. Pressure test 9-5/8" casing to 2700 PSI for 30 min on chart - good. 4.4 bbls pumped, 3.5 bbls bled back. R/D test equipment and blow down lines. Wash down f/ 5105' and tag BA w/ 10K at 5114', drill 9-5/8" shoe track f/ 5114' to 5242', 460 GPM, 1080 PSI, 40 RPM, 14k TQ, 7-10k WOB. All FE on depth, float collar f/ 5156’ t/ 5158’ & shoe f/ 5240' t/ 5242'. Ream each 2x times. 183k PU / 82k SO / 115k ROT. Drill 20' of new hole f/ 5252' t/ 5272', 400 GPM, 920 PSI, 40 RPM, 12-15k TQ, 3-7k WOB, 173k PU / 83k SO / 110k ROT. Start displacing Wellbore to 8.9 ppg. BARADRIL-N while cleaning out rathole @ 5245’ Continue to displace Spud Mud to 8.9 ppg Baradril-N. 400 GPM, 465 PSI, 40 RPM 13-15k Tq. Obtain SPR’s & Flow Check Well - Static Rack stand back t/ 5233' MD. Perform good FIT to 12.0 ppg EMW with 8.9 ppg MW to 663 PSI @ 4110' TVD / 5242' MD. 1.1 bbls pumped, 1.1 bbls bled back. Perform flow check - static. POOH f/ 5233' t/ 4915' with proper displacement. Pump 10.7 ppg dry job. POOH on elevators f/ 4915' t/ 590' at the HWDP, flow check the well, static, L/D excess HWDP, rack back jar stand, L/D Motor & 8 1/2'' MT bit = 1-1-WT-A-E-I- NO-BHA. Calculated displacement on TOOH. Rig on High-Line power @ 16:52 Clear and clean rig floor, Mobilize BHA components and tools to rig floor. Remove wear bushing. M/U stack washing tool and flush stack. Install wear bushing. RILDS (4) M/U 8.5'' BHA #3 with a 8.5'' SK616M-J1D bit, Geo Pilot, ADR, ILS, DGR, PWD, DM, TM & stabilizer t/ 88' Initialize MWD tools, M/U remaining BHA, 2x NMFCs with 2 float subs 2x std HWDP with Jars to 278.54', Corrosion ring installed at top of flex collars. Shallow pulse test MWD 450 gpm, 617 psi - Good Blow down TopDrive & single in hole with 5'' DP from shed to 945'. Pipe drifted t/ 3.125”. 58k PU / 57k SO Hold Kick while tripping drill with rig crew. Service rig, Grease Crown, Inspect Iron Roughneck. SimOps: C/O Hyd hose on pipe skate. Fill pipe, break in Geo pilot seals, blow down TopDrive. SimOps: Finish C/O Hyd hose on pipe skate. Continue RIH picking up 5” DP singles from shed t/ 4537’, pipe drifted t/ 3.125”, slow down passing ESC @ 2238'. 188k PU / 88k SO. TIH with 5” DP stands to 5172’. 191k PU / 86k SO. No Losses Recorded. Monitor Well – Static. Remove riser and install RCD bearing as per Beyond rep onsite. Daily Disposal to G&I = 812 bbls, total = 7115 bbls. Daily Water from S-Pad Creek = 240 bbls. Total Water from S-Pad Creek = 6240bls. Daily Metal: 0 lb. Total Metal 0 lb. Interval Daily Mud lost to formation 0 bbls, total = 0 bbls. 6/29/2021 Continue MPD RCD bearing installation as per Beyond rep onsite. Establish circulation through MPD. Check for leaks – Good. Obtain SPR’s and wash down f/ 5,240' t/ bottom @ 5272’, No issues exiting shoe. 450 GPM 980 PSI 40 RPM, 9k Tq. Drill 8-1/2"lateral f/ 5272' t/ 5680' (4108' TVD) 408' drilled, 81.6 fph AROP. 450 GPM, 1010 PSI, 120 RPM, 12k Tq, 8-10k WOB. MW 8.85, Vis 42, ECD 9.85 max gas 654u. 156k PU / 74k SO / 106k ROT. Backream full stands. MPD full open drilling with 55 psi line pressure. Maintain NB sand Drill 8-1/2" lateral f/ 5680' t/ 6442' (4109' TVD) 762' drilled, 127 fph AROP. 500 GPM, 1360 PSI, 120 RPM, 9-10k Tq,5-15k WOB. MW in/out 9.0/9.05, Vis in/out 47/52, ECD 10.22 max gas 605u. 132k PU / 88k SO / 101k ROT. Backream full stands. MPD full open drilling with 55 psi line pressure. Maintain NB sand Drill 8-1/2" lateral f/ 6442' t/ 7078' (4097' TVD) 636' drilled, 106 fph AROP. 485 GPM, 1560 PSI, 120 RPM, 10- 13k Tq, 8-18k WOB. MW in/out 9.0/9.1, Vis in/out 48/50, ECD 10.60 max gas 593u. 132k PU / 79k SO / 98k ROT. Drill 8-1/2" lateral f/ 7078' t/ 7589' (4089’ TVD) 511' drilled , 85.16'/hr AROP. 500 GPM, 1680 PSI, 120 RPM, 14k Tq, 8-10k WOB. MW in/out 9.1/9.15, Vis in/out 49/55, ECD 10.89, Max Gas 645u. 142k PU / 62k SO / 100k ROT. MPD full open drilling with 55 psi line pressure. Hold 150 psi during connections. Pumped hi vis sweep at 7460', back on time with 20% increase. Maintain NB sand. Last survey @ 7518.04' MD / 4091.18' TVD, 91.11° inc, 340.16° azm, 10.34' from plan, 0.69' High, 10.32' Right. Drilled 4 concretions for a total thickness of 17' (0.8% of the lateral). Daily Disposal to G&I = 513 bbls, total = 7628 bbls. Daily Water from S-Pad Creek = 640 bbls. Total Water from S- Pad Creek = 6880bls. Daily Metal: 0 lb. Total Metal 0 lb. Interval Daily Mud lost to formation 0 bbls, total = 0 bbls. 6/30/2021 Drill 8-1/2" lateral f/ 7589' t/ 8289' (4088’ TVD) 700' drilled , 116'/hr AROP. 500 GPM, 1730 PSI, 110 RPM, 14k Tq, 10-15k WOB. MW in/out 9.0/9.15, Vis in/out 45/52, ECD 11.15, Max Gas 792u. 154k PU / 62k SO / 101k ROT. MPD full open drilling with 55 psi line pressure. Hold 150 psi during connections. Drill 8-1/2" lateral f/ 8289' t/ 8930' (4089’ TVD) 641' drilled , 106.8'/hr AROP. 500 GPM, 1940 PSI, 120 RPM, 12k Tq, 5-18k WOB. MW in/out 9.2/9.2, Vis in/out 47/51, ECD 11.38, Max Gas 675u. 131k PU / 77k SO / 95k ROT. MPD full open drilling with 55 psi line pressure. Hold 150 psi during connections. Exit base of NB sands @ 8600'. Target 92° inclination to reacquire sands. Drill 8-1/2" lateral f/ 8932' t/ 9270' (4081’ TVD) 338' drilled , 56.33'/hr AROP. 500 GPM, 1980 PSI, 120 RPM, 10- 12k Tq, 5-18k WOB. MW in/out 9.25/9.25, Vis in/out 48/55, ECD 11.42, Max Gas 692u. 133k PU / 73k SO / 94k ROT MPD full open drilling with 55 psi line pressure. Hold 150 psi during connections. Target 93° to reacquire NB package. Drill 8-1/2" lateral f/ 9270' t/ 9496' (4070’ TVD) 226' drilled , 37.66'/hr AROP. 500 GPM, 2050 PSI, 120 RPM, 13k Tq, 16-18k WOB. MW in/out 9.2/9.25, Vis in/out 50/56, ECD 11.37, Max Gas 327u. 134k PU / 69k SO / 92k ROT MPD full open drilling with 55 psi line pressure. Hold 150 psi during connections. Target 93° to reacquire NB package. Enter sands @ 9363’. Continue hold 93°. Total 763’ drilled below base of NB Sand. Last survey @ 9425.39' MD / 4074.56' TVD, 92.9° inc, 352.51° az, 33.09' from plan, 10.71' High, 31.31' Left. Drilled 7 concretions for a total thickness of 29' (0.7% of the lateral). Daily Disposal to G&I = 684 bbls, total = 8312’ bbls. Daily Water from S-Pad Creek = 640 bbls. Total Water from S-Pad Creek = 6880bls. Daily Metal: 0 lb. Total Metal 0 lb. Interval Daily Mud lost to formation = 0 bbls, total = 0 bbls. 7/1/2021 Drill 8-1/2" lateral f/ 9496' t/ 9878' (4061’ TVD) 409' drilled , 68'/hr AROP. 550 GPM, 2400 PSI, 110 RPM, 15k Tq, 12-15k WOB. MW in/out 9.2/9.2, Vis in/out 48/52, ECD 11.4, Max Gas 920u. 156k PU / NA SO / 96k ROT. MPD full open drilling with 55 psi line pressure. Hold 150 psi during connections. Drill 8-1/2" lateral f/ 9878' t/10193' (4067’ TVD) 315' drilled , 52.5'/hr AROP. 530 GPM, 2250 PSI, 80-120 RPM, 11-13k Tq, 5-20k WOB. MW in/out 9.15/9.2, Vis in/out 42/45, ECD 11.2, Max Gas 980u. 159k PU / NA SO / 95k ROT At 9,900' increase lube concentration to from 1.5% to 2.5% to mitigate slip stick. MPD full open drilling with 55 psi line pressure. Hold 150 psi during connections. Drill 8-1/2" lateral f/ 10193' t/ 10448' (4069’ TVD) 225' drilled , 42.5’/hr AROP. 530 GPM, 2305 PSI, 80-120 RPM, 11-13k Tq, 5-20k WOB. MW in/out 9.15/9.15, Vis in/out 43/45, ECD 11.25, Max Gas 947u. 144k PU / 71k SO / 94k ROT MPD full open drilling with 55 psi line pressure. Hold 150 psi during connections. Regain SO Wt @ 10387’ Drill 8-1/2" lateral f/ 10488' t/ 10641' (4071’ TVD) 193' drilled, 32.16’/hr AROP. 530 GPM, 2270 PSI, 80-120 RPM, 11-13k Tq, 15-20k WOB. MW in/out 9.15/9.15, Vis in/out 43/48, ECD 11.34, Max Gas 856u. 145k PU / 64k SO / 99k ROT. MPD full open drilling. Hold 150 psi during connections Last survey @ 10570.52' MD / 4071.32' TVD, 89.63° inc, 344.02° azm, 12.54' from plan, 12.48' High, 1.14' Right. Drilled 15 concretions for a total thickness of 93' (1.7% of the lateral). Daily Disposal to G&I = 1036 bbls, total = 9348’ bbls. Daily Water from S-Pad Creek = 1040 bbls. Total Water from S-Pad Creek = 8800 bbls. Daily Metal: 50 lb. Total Metal 50 lb. Interval Daily Mud lost to formation = 0 bbls, total = 0 bbls. 7/2/2021 Drill 8-1/2" lateral f/ 10,641' t/ 10660' (4071’ TVD) 19' drilled, 38’/hr AROP. 530 GPM, 2270 PSI, 80-120 RPM, 11-13k Tq, 15-20k WOB. MW in/out 9.15/9.15, Vis in/out 43/48, ECD 11.34, Max Gas 856u. 145k PU / 64k SO / 99k ROT. MPD full open drilling. Hold 150 psi during connections Decision made to pull wiper trip to 8500' due to slow ROP. BROOH f/10,660' to 8500', with full drilling parameters 550 , 120 RPM. MPD trap 150 psi on connections. At 9850' see erratic Tq and drag, wipe through x2 and clean up. @ 9400' to 8480' slow pulling speed to 15-25 fpm. P/U 177, S/O 54, Rot 94 Pump 40 bbl hi vis sweep, Rot/Recip f/ 8544 to 8480'. 550 GPM, 2190 PSI, 120 RPM, 9-10K Tq. Sweep back on time with 200% increase in cuttings @ shakers TIH on elevators from 8480' to 10,578' W/O issues, wash down at full drilling rates from 10,578' to 10,660' tag bottom on depth. 550 GPM, 2405 PSI, 120 RPM, 11-12K Tq. P/U 158, S/O 70, Rot 97 Drill ahead f/10,660' to 10,674' attempting to obtain ROP. See weight stack out, stage WOB f/12K-24K. See intermittent drilling break just under 25 fph. No success obtain sustainable ROP. Monitor Well. Well Static. Pump Out Of Hole W/O Rotation f/10,674' to 8480' @ 40-45 fpm, 550 GPM, 2130 PSI, ECD 10.9, Max Gas 91u, P/U 142K, S/O 67K. L/D top of Stand 163 to alternate breaks on trip out. BROOH f/ 8480' t/ 7035' at 10-30 ft/min, 550 GPM, 1935 PSI, 120 RPM, 9-17k Tq. MW in/out 9.2/9.3, Vis in/out 45/48, ECD 10.72, Max Gas 234u. 145k PU / 57k SO / 102k ROT Tight spot at 8066’, stalled string while backreaming. Work string down, dressing area, no issues reaming back through. MPD full open choke. No pressure build or flow observed during pumps down. Continue BROOH f/ 7035' t/ 5394' at 10-25 ft/min, 550 GPM, 1650 PSI, 80-120 RPM, 5-12k Tq. MW in/out 9.2/9.2, Vis in/out 44/49, ECD 10.31, Max Gas 146u. 127k PU / 87k SO / 104k ROT. Pump out with no rotation f/ 5394' t/ 5204', 9-5/8" casing shoe @ 5242'. No issues entering shoe. No losses BROOH Start to experience intermittent sections of overpull 20-30k with only slight erratic Tq from 6540’. Courser sand & silt returns at shakers through ratty sections. At 6085’ packing off was experience coupled with overpull and weight stacking when slack off. Work free and dress area clean. Last survey @ 10604.50' MD / 4071.63' TVD, 89.31° inc, 344.75° azm, 12.18' from plan, 12.413' High, 1.12' Left. Drilled 15 concretions for a total thickness of 93' (1.7% of the lateral). Daily Disposal to G&I = 825 bbls, total = 10173’ bbls. Daily Water from S-Pad Creek = 720 bbls. Total Water from S-Pad Creek = 7520 bbls. Daily Metal: 30 lb. Total Metal 80 lb. Interval Daily Mud lost to formation = 0 bbls, total = 0 bbls. 7/3/2021 Pump 45 bbl high vis sweep. 550 GPM, 1615 psi. 80 RPM, 5k Tq. Sweep return on time with 10% increase in cuttings. Max gas with BU 15u. Monitor Well 10 min – Static – Monitor pressure build with MPD chokes closed for 5 min. No increase observed Pump dry job, Blow down TopDrive. Drain Stack, Remove MPD RCD Bearing & install trip nipple. Check for leaks. Good TOOH on elevators f/ 5204'. t/ 153'. Rack 2x stds HWDP in Derrick. Flow check before pulling BHA, static. Rack back flex collars and lay down IBS, TM, DM, ADR, GeoPilot, NRP & Bit. IBS stabilizer blades were worn from 8-3/8" gauge to 7-1/8" gauge, ILS stabilizer showed significant wear & Geo-Pilot had a damaged cutter. Bit and NPR came out packed with clay and silt. Bit graded 2-5-CT-S-X-I-BU-PR M/U new 8-1/2" RSS drilling assembly with Hycalog 8-1/2” PDC & NRP, Geo-Pilot, ADR, DGR, PWD, directional MWD sensors & 8.48” IBS. Initialize MWD and upload MWD data. TIH with 2x each NMDC, float subs & stands of HWDP/jars to 277'. Shallow pulse test MWD, 450 GPM, 720 PSI - good test. TIH f/ 277' t/ 5171' from the derrick. 118k PU / 89k SO. Fill pipe every 2500'. Break in Geo-Pilot seals @ 2810’ - 10, 20, 30, 40 & 50 RPM. No losses. Recorded on TIH Circulate bottoms up – 550 GPM, 1525 psi. 30 RPM, 5k Tq. 14u Max gas with BU. Blow down top drive, Install FOSV. Slip & cut 50' of drilling line & service rig. Grease crown, blocks, TopDrive Iron Roughneck and IBOP. Check oil in TopDrive. Monitor Well w/ hole fill while Cut and Slip. Static. Remove trip nipple and install Beyond MPD Bearing. Circulate through MPD lines and establish parameters at 5235’ prior to exit casing. TIH on elevators f/ 5235’ t/ 10450’. Fill pipe every 2500’. Clean exiting casing and no issues trip in through open hole. 3.3 bbls loss recorded on trip in hole. Wash and ream f/ 10450’ t/ 10674’. 500 GPM, 1860 psi. 60 RPM, 11-12k Tq. Tag bottom on depth, no issues reaming down. 161k PU / 58k SO / 100k ROT Drill 8-1/2" lateral f/ 10674' t/ 10900' (4070’ TVD) 226' drilled , 50.22/hr AROP. 550 GPM, 2340 PSI, 80-120 RPM, 15-18k Tq, 5-14k WOB. MW in/out 9.2/9.2, Vis in/out 45/51, ECD 11.2, Max Gas 636u. 155k PU / 55k SO / 92k ROT. MPD full open drilling. Closed with 15 psi during connections, no build seen Last survey @ 10823.42' MD / 4070.87' TVD, 90.62° inc, 351.50° azm, 12.86' from plan, 12.64' High, 2.38' Left. Drilled 16 concretions for a total thickness of 103' (1.9% of the lateral). Daily Disposal to G&I = 114 bbls, total = 10287 bbls. Daily Water from S-Pad Creek = 240 bbls. Total Water from S-Pad Creek = 9760 bbls. Daily Metal: 20 lbs Total Metal 120 lbs. Interval Daily Mud lost to formation = 0 bbls, total = 0 bbls. 7/4/2021 Drill 8-1/2" lateral f/ 10900' t/ 11244' (4066’ TVD) 344' drilled , 57.3'/hr AROP. 550 GPM, 2340 PSI, 80-120 RPM, 15-18k Tq, 5-15k WOB. MW in/out 9.2/9.2, Vis in/out 45/51, ECD 11.6, Max Gas 934u. 154k PU / 45k SO / 97k ROT. MPD full open drilling. Closed with 15 psi during connections, no build seen Drill 8-1/2" lateral f/ 11244' t/ 11513' (4080’ TVD) 269' drilled , 44.8'/hr AROP. 550 GPM, 2380 PSI, 80-120 RPM, 12-14k Tq, 5-15k WOB. MW in/out 9.2/9.25, Vis in/out 43/46, ECD 11..11, Max Gas 487u. 148k PU / 69k SO / 98k ROT Drill 8-1/2" lateral f/ 11513' t/ 12100' (4085’ TVD) 587' drilled , 97.83/hr AROP. 550 GPM, 2350 PSI, 80-120 RPM, 13-16k Tq, 2-15k WOB. MW in/out 9.25/9.3, Vis in/out 43/54, ECD 11.38, Max Gas 1188u. 161k PU / 0k SO / 98k ROT. Maintain SB_NB sands Backream full stands at connection. MPD full open drilling. Closed choke during connections with no pressure build observed. Drill 8-1/2" lateral f/ 12100' t/ 12760' (4086’ TVD) 660' drilled , 110/hr AROP. 550 GPM, 2500 PSI, 80-120 RPM, 13-16k Tq, 14-16k WOB. MW in/out 9.25/9.25, Vis in/out 44/56, ECD 11.58, Max Gas 1315u. 155k PU / 35k SO / 96k ROT. Loss SO Wt @ 12485'. Maintain SB_NB sands MPD full open drilling. Closed choke during connection. No pressure build observed. Last survey @ 12668.00' MD / 4087.29' TVD, 90.01° inc,348.67° azm, 6.24' from plan, 5.96' Low, 1.86' Left. Drilled 36 concretions for a total thickness of 346' (4.7% of the lateral). Daily Disposal to G&I = 513 bbls, total = 10800 bbls. Daily Water from S-Pad Creek = 720 bbls. Total Water from S-Pad Creek = 10480 bbls. Daily Metal: 0 lbs Total Metal 120 lbs. Interval Daily Mud lost to formation = 27 bbls, total = 30 bbls. 7/5/2021 Drill 8-1/2" lateral f/ 12,760' t/ 13,437' (4082’ TVD) 677' drilled , 84.6/hr AROP. 550 GPM, 2750 PSI, 80-120 RPM, 13-16k Tq, 8-15k WOB. MW in/out 9.25/9.25, Vis in/out 44/56, ECD 12.1, Max Gas 1287u. 159k PU / 35k SO / 92k ROT. Maintain SB_NB sands Pump 45 bbls, 9.0 ppg/35 Visc followed w/ 35 bbls 10.3 ppg/253 Vis Tandem Sweeps to surface. 550 GPM/2640 PSI, 120 RPM, 17K TQ, Max gas 520u, ECD 11.72. Sweep back 10 bbls Late. Minimal change at shakers. Rack back 1 stand, CBU x 3 at same Parameters. TIH back to bottom and stage trucks, Prep pits for Chem train and displacement. Dynamic loss rate @ 11 BPH. 144k PU / 0k SO / 95k ROT Pump 3x 40 bbl SAPP pills separated by 20 bbl 9.3 ppg visc lube (1.5%) QuickDril spacers then chased w/ 9.3 ppg QuickDril Vis lubed brine. Overboard all returns. Pills back on time. 500 GPM, 2310 psi 120 RPM, (17k Tq prior Disp, 19k post Disp). Regained SO Wt post disp. 162k PU / 46k SO / 100k ROT Take returns back to the pits. Obtain passing PST w/ 3 avg @ 6.66 sec from flow line and 3 avg @ 6.11 sec from suction pit. Obtain new slow pump rates. Perform pressure monitoring w/ MPD. Close choke w/ 15 psi dropping to 7 psi after 10 min, indication of slight losses. Drop 2.39” metal drift and BROOH f/ 13437' t/ 12039' at 25-35 FPM as hole dictates. 500 GPM, 1530 PSI, 120 RPM, 17-19k Tq. MPD full open choke. ECD = 10.64, Max gas 241u. Dynamic loss rate slowing to 4 BPH BROOH f/ 12039' t/ 8850' at 15-40 FPM slowing as needed for hole cleaning, 500 GPM,1440 psi, 120 RPM, 13-15k Tq. MPD full open choke while BR Shut in and monitor pressure during connections. No building observed. 22 bbl total losses while BROOH Final survey distance to Wp06: 14.81', 4.08' Low, 14.24’ Left. Drilled 50 concretions for a total thickness of 426' (5.2% of the lateral). Total footage NB Sand 7315, Out of zone 880', Total 8195' below 9- 5/8” Casing Shoe Daily Disposal to G&I = 2317 bbls, total = 13117 bbls. Daily Water from S-Pad Creek = 720 bbls. Total Water from S-Pad Creek = 11200 bbls. Daily Metal: 10 lbs Total Metal 130 lbs. Interval Daily Mud lost to formation = 60 bbls, total = 90 bbls. 7/6/2021 Continue to BROOH from 8850' to 5425'. 500 GPM, 1140 PSI, 120 RPM, 10K TQ, Pulling 15-50 fpm. Pumped out from 5425' to 5235'. See 4-6K Drag w/BHA entering shoe. Max gas 274u, PU 154K, SO 85K. Pump 35 bbls/300 visc sweep and circulate casing clean. Perform PST Test from Flow Line and suction Pit. (100 Micron Screens) Monitor Well, Well static. Drain Stack and pull RCD Bearing. Install flow riser POOH L/D 5" DP from 5235' to BHA @ 277'. 15 bbl loss on trip out of hole Lay down HWDP, Jars, NMDC & Float Subs. Drift landed at upper float sub. Download MWD tool and continue L/D remaining BHA -TM, DM, ADR, GeoPilot and Bit. Bit Grade 2-2-CT-A-X-I-WT-TD. Clean and clear rig floor of BHA components. Static loss ~1.5 BPH. R/U Weatherford double stack tongs and 4-1/2” handling Equip. Stage and organize 4.5" liner components in pipe shed. Bring centralizers and stop rings to rig floor. Static loss ~1.5 BPH P/U round nose shoe w/ XO jt, and run 4-1/2'', 13.5#, L-80 W625 injection liner as per tally to 2522'. Torque to 9600 ft/lb with Weatherford double stack tongs. 59k PU / 56k SO. ~4 BPH Loss rate. Continue to run 4.5" ScreenS & 4-1/2'', 13.5#, L-80 W625 as per tally to 8363' . Torque to 9600 ft/lb with Weatherford double stack tongs. 88k PU / 71k SO inside the 9-5/8" shoe 5201'. 2.7k Tq @ 10 RPM, 3k Tq @ 20 RPM On blank jts- install 1- 4 1/2'' x 7 1/4'' straight vane centralizer w/ 1- stop ring free floating on each joint. 189 blank joints, 14 Baker 100 micron screens. 4 BPH loss rate, 35 bbls lost running liner. M/U Baker 7"x9-5/8" SLZXP liner top packer to 8402' then run one stand of 5" drill pipe to 8455'. Pump 10 bbls to ensure clear flow path through Baker tools, 4 BPM, 220 PSI. Obtain parameters: 100k PU / 66k SO / 81k ROT Daily Disposal to G&I = 171 bbls, total = 13288 bbls. Daily Water from S-Pad Creek = 0 bbls. Total Water from S-Pad Creek = 10800 bbls. Daily H2O from A-Pad: 80. Total H2O from A-Pad:480. Daily Metal: 0 lbs Total Metal 130 lbs. Interval Daily Mud lost to formation = 81 bbls, total = 171 bbls. 7/7/2021 R/D Weatherford 4.5" Handling equipment. C/O to Hyd Elevators for DP. Remove misc from Rig Floor. TIH with liner conveyed on 5" DP from 8450' to 13,437'. PUW 184K, SOW 54K. No issues running liner to bottom. Park Liner on depth @ 13,437' Shoe depth placing TOL @ 5047. Drop 1.25" Ball and chase on seat @ 4 bpm. Set/Release from PKR as per Baker Rep Procedure. No issues setting or releasing from PKR. PT Top of PKR to 1700 psi for 10 min. Good test. L/D 2 jts and park above TOL. CBU. Pump corrosion inhibited Slug POOH L/D DP from 5000’ to surface. L/D Liner Hgr Running tool. RIH with DP stands from derrick to 3608' md. Pump 10 bbl corrosion inhibited slug. POOH L/D DP from 3608' to surface Rig up to run 3.5" upper completion. Pull and L/D wear bushing. Clear rig floor and mobilize 3.5" handling equipment and cannon clamps to rig floor. Remove 5" Hydraulic elevators and install 3.5" elevators. RIH with 3.5", 9.3#, L-80 EUE 8-rd upper completion w/ 7.3" Baker Ported Seal Assy, XN nipple and 3.5" Baker Gauge Mandrel to 3781' md at 90 ft/min. Daily Disposal to G&I = 171 bbls, total = 13288 bbls. Daily Water from S-Pad Creek = 0 bbls. Total Water from S-Pad Creek = 10800 bbls. Daily H2O from A-Pad: 0. Total H2O from A-Pad:480. Daily Metal: 0 lbs Total Metal 130 lbs. Interval Daily Mud lost to formation = 43 bbls, total = 214 bbls. Activity Date Ops Summary 7/8/2021 Continue to RIH with 3.5#,9.3#, L-80 EUE 8-rd upper completion from 3781' to 4975' md.,Space out 3.5# upper completion: tag no-go at 5061' md. L/D 3 jts and M/U 4 space out pups (2.08', 4.09', 8.18', 8.19') and jt #159. M/U hanger and landing joint. Terminate TEC-wire and wrap around hanger per wellhead rep. Land completion with no-go 3.61' off TOL. Pressure up to 500 psi and verify seals engaged. Pick up to expose ports and bleed off pressure. Establish circulation.,Reverse in 240 bbls of corrosion inhibited brine at 4 bpm, 300 psi. Reverse in 125 bbls of diesel freeze protect at 4 bpm, 450 psi and chase with 10 bbls of water to flush lines. Clean and clear rig floor: rig down Weatherford casing tools and Centrilift tools,Land 3.5" upper completion with 22 Klbs. RILDS per wellhead rep. Lay down landing joint and blow down top drive and kill line.,Pressure test IA and seals to 2500 psi for 30 min: good test. Pumped 3.7 bbls bled back 3.4 bbls. Blow down lines and rig down test equipment. Ste BPV per wellhead rep.,Prep to R/D BOPE: flush pumps and surface lines with heated soap pill. Blow down all surface lines and begin offloading mud from pits.,N/D BOPE: Bleed off accumulator, pull bushings and riser. Remove RCD drip pan, choke and kill lines. N/D RCD head and set back. N/D BOP stack and rack back to pedestal. Continue to offload mud in pits. Load and process 5" drill pipe in pipe shed. Take apart MP 1&2 for inspection.,N/U tubing head adapter and tree per wellhead rep. Terminate TEC-wire and tighten flange bolts. PT hanger void per wellhead rep 500 psi low / 5000 psi high for 5 / 15 min: good test. PT tree 250 psi low / 5000 psi high for 15 / 15 min: good test. Remove CTS plug and BPV per wellhead rep.,Continue to clean mud pits and work on MP 1&2. Continue to load and process 5" drill pipe in pipe shed. Rig down rig floor equipment and prep for move. Bridal up and scope down derrick.,Continue to R/D for move to MP S-46. Remove companion flange and secure tree and cellar. Clean out cellar box. Flip roof caps and prep stairs and landings for move. Disconnect Mezzanine interconnect lines. Continue to clean mud pits and process 5" drill pipe in pipe shed. Release from MP S-44 at 0:00. 50-029-23694-00-00API #: Well Name: Field: County/State: MP S-44 Milne Point Hilcorp Energy Company Composite Report , Alaska 6/21/2021Spud Date: TD Shoe Depth: PBTD: No. Jts. Returned RKB RKB to BHF RKB to THF Jts. 1 2 1 1 1 71 1 1 1 54 1 X Yes No X Yes No 2.69 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 No Casing Rotated?X Yes No Reciprocated?X Yes No % Returns during job Cement returns to surface? Yes X No Spacer returns?Yes X 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:Yes No Casing Rotated? Yes X No Reciprocated? Yes X No % Returns during job Cement returns to surface?X Yes No Spacer returns?Yes X No Vol to Surf: Cement In Place At: Date: Estimated TOC: Method Used To Determine TOC: Post Job Calculations: Calculated Cmt Vol @ 0% excess: Total Volume cmt Pumped: Cmt returned to surface: Calculated cement left in wellbore: OH volume Calculated: OH volume actual: Actual % Washout: Casing (Or Liner) Detail Shoe Cut Joint of Casing 10 3/4 332.5 13.5293.1SECOND STAGEHalliburton Rotate Csg Recip Csg Ft. Min. PPG9.4 Shoe @ 5242 FC @ Top of Liner5,156.57 Floats Held 323.1 654 285 369 H2O CASING RECORD County State Alaska Supv.B Anderson / J Vanderpool Hilcorp Energy Company CASING & CEMENTING REPORT Lease & Well No.MP S-44 Date Run 25-Jun-21 Setting Depths Component Size Wt. Grade THD Make Length Bottom Top TXP BTC-SR Innovex 1.58 5,242.00 5,240.42 9.01 34.84 25.839 5/8 47.0 L-80 TXP BTC-SR Tenaris Csg Wt. On Hook:150,000 Type Float Collar:Innovex No. Hrs to Run:13.5 8.34 5.6 0 10 10.7 365 5.8 100 339 Bump Plug?FIRST STAGE10Tuned Spacer 55 15.8 400 3.5 8.34 6 20/20 20/20 0 Halliburton 15.8 80 Bump pressBump Plug? Y 0 2238.66 5,242.005,252.00 CEMENTING REPORT Csg Wt. On Slips:115,000 Spud Mud HAL Tuned Spacer 710 2.88 Stage Collar @ 55 Bump press 100 0 ESC II Closure OK 56 12 153 26.24 RKB to CHF Type of Shoe:Innovex Casing Crew:Weathorford No. Jts. Delivered 145 No. Jts. Run 131 Length Measurements W/O Threads Ftg. Delivered Ftg. Run 5,216.17 Ftg. Returned Ftg. Cut Jt.9.01 Ftg. Balance www.wellez.net WellEz Information Management LLC ver_04818br 5.5 Arctic Cem Type 75 joints of 40# casing and 54 joints + cut joint of 47# casing ran. 76 total 9-5/8"x12-1/4" bow spring centralizer w/ 12 stop rings ran. Two centralizers on joint #1, one each on joints #2-26. Every other joint #28-50, every. Every joint & pup joints from #70-81, then every other joint from #83-127. Casing 9 5/8 40.0 L-80 TXP BTC-SR Tenaris 82.56 5,240.42 5,157.86 Float Collar 10 3/4 TXP BTC-SR Innovex 1.29 5,157.86 5,156.57 Casing 9 5/8 40.0 L-80 TXP BTC-SR Tenaris 40.56 5,156.57 5,116.01 Baffle Adapter 10 3/4 TXP BTC-SR HES 1.40 5,116.01 5,114.61 Casing 9 5/8 40.0 L-80 TXP BTC-SR Tenaris 2,855.03 5,114.61 2,259.58 Pup Joint 9 5/8 40.0 L-80 TXP BTC-SR Tenaris 18.10 2,259.58 2,241.48 ES II Cementer 10 3/4 TXP BTC-SR HES 2.82 2,241.48 2,238.66 Pup Joint 9 5/8 47.0 L-80 TXP BTC-SR Tenaris 17.55 2,238.66 2,221.11 Casing 9 5/8 47.0 L-80 TXP BTC-SR Tenaris 2,186.27 2,221.11 34.84 Arctic Cem 366 2.35 Premium G 391 1.15 5.6 Premium G 270 1.17 0 H2O contaminated returns to surface. 230 bbls cement returned to surface 'HILQLWLYH6XUYH\5HSRUW -XO\ +LOFRUS$ODVND//& 0LOQH3RLQW 03W63DG 0386L 3URMHFW &RPSDQ\ /RFDO&RRUGLQDWH5HIHUHQFH 79'5HIHUHQFH 6LWH +LOFRUS$ODVND//& 0LOQH3RLQW 03W63DG 'HILQLWLYH6XUYH\5HSRUW :HOO :HOOERUH 0386L 0386L 6XUYH\&DOFXODWLRQ0HWKRG0LQLPXP&XUYDWXUH 0386$FWXDO5.%#XVIW 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B0:',)5066DJ B0:',)5066DJ 352-(&7('WR7' $SSURYHG%\&KHFNHG%\'DWH 30 &203$66%XLOG(3DJH Chelsea Wright Digitally signed by Chelsea Wright Date: 2021.07.06 10:06:04 -08'00' Benjamin Hand Digitally signed by Benjamin Hand Date: 2021.07.06 10:54:19 -08'00' David Douglas Hilcorp Alaska, LLC Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or fax to 907 564-4422. Received By: Date: Date: 7/13/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU S-44 (PTD 221-044) FINAL LWD FORMATION EVALUATION LOGS (06/21/2021 to 07/05/2021) •EWR-M5, AGR, ABG, DGR, ADR, Horizontal Presentation (2” & 5” MD/TVD Color Logs) •Final Definitive Directional Survey SFTP Transfer - Data Folders: Please include current contact information if different from above. 07/13/2021 PTD: 2210440 E-Set: 35354 David Douglas Hilcorp Alaska, LLC Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or fax to 907 564-4422. Received By: Date: Date: 07/13/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU S-44 (PTD 221-044) FINAL EOW REPORT – GEOSTEERING LOGS (06/29/2021 to 07/05/2021) SFTP Transfer - Data Folders: Please include current contact information if different from above. 07/13/2021 PTD: 2210440 E-Set: 35353 1 Guhl, Meredith D (CED) From:Rixse, Melvin G (CED) Sent:Sunday, June 20, 2021 12:51 PM To:Nathan Sperry Subject:Re: [EXTERNAL] Re: PTD 221-044 Hilcorp Well S-44 - Variance Request Nathan, Hilcorp is approved to take out 20’ section of diverter to temporarily mobilize cementing equipment while rig is circulating overbalanced fluid. Diverter will be reinstalled for cementing operations. Mel Rixse On Jun 20, 2021, at 10:47 AM, Nathan Sperry <Nathan.Sperry@hilcorp.com> wrote: 1) Lighter fluid will not be circulated while the diverter is shortened. 2) Yes, the diverter section will be reattached prior to cementing. Thank you On Jun 20, 2021, at 12:39 PM, Rixse, Melvin G (CED) <melvin.rixse@alaska.gov> wrote: Nathan, To clarify: 1. Will fluids lighter than mud weight be circulated while diverter is shortened? 2. Will the diverter be reattached before cementing? Mel Rixse On Jun 20, 2021, at 8:26 AM, Nathan Sperry <Nathan.Sperry@hilcorp.com> wrote: Mel, To clarify a few points, the 20 foot section would be removed mid‐run and would put the nearest end of the break roughly 40’ from the wellhead. The section would be removed long enough to mobilize cement equipment (units, vac trucks, etc) and then would be reinstalled prior to pumping stage 1. The rig will continue to circulate while the section is removed mobilized. Regards, Nate Sperry 2 On Jun 20, 2021, at 9:07 AM, Nathan Sperry <Nathan.Sperry@hilcorp.com> wrote: Good morning Mel, Innovation is requesting a variance on well MPU S‐44 to remove 20’ section of vent line post drilling and running 9‐5/8” casing on surface. S‐Pad has an alternative route to West side of location for light traffic only during drilling operations. The section of vent line would be removed once casing is on depth and a minimum of 1.5 btms up have been circulated to ensure any and all gas/hydrocarbons have been cleared of wellbore. We would like to remove the section of vent line to gain needed access to the West side of the location for cement equipment to perform the surface cement job. This was previously requested and approved by AOGCC on well MPU S‐57 in February of 2020. We wrapped up S‐45 last night and are rigging up on S‐ 44 today. Thank you, Nate Sperry Drilling Engineer Hilcorp Alaska, LLC O: 907‐777‐8450 C: 907‐301‐8996 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Monty M. Myers Drilling Manager Hilcorp Alaska, Inc. 3800 Centerpoint Drive, Suite 400 Anchorage, AK 99503 Re: Milne Point Field, Kuparuk Oil Pool, MPU S-44 Hilcorp Alaska, LLC Permit to Drill Number: 221-044 Surface Location: 3202' FSL, 605' FEL, Sec. 12, T12N, R10E, UM, AK Bottomhole Location: 845' FSL, 2347' FWL, Sec. 35, T13N, R10E, UM, AK Dear Mr. Myers: Enclosed is the approved application for the permit to drill the above referenced well. Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Jeremy M. Price Chair DATED this ___ day of June, 2021. Jeremy Price Digitally signed by Jeremy Price Date: 2021.06.08 14:57:42 -08'00' 1a. Type of Work: 1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp 1c. Specify if well is proposed for: Drill Lateral Stratigraphic Test Development - Oil Service - Winj Single Zone Coalbed Gas Gas Hydrates Redrill Reentry Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal Shale Gas 2.Operator Name:5. Bond: Blanket Single Well 11.Well Name and Number: Bond No. 3. Address:6. Proposed Depth:12. Field/Pool(s): MD: 13,577' TVD: 4,081' 4a. Location of Well (Governmental Section): 7. Property Designation: Surface: Top of Productive Horizon:8.DNR Approval Number:13.Approximate Spud Date: Total Depth: 9. Acres in Property: 14. Distance to Nearest Property: 3306' 4b. Location of Well (State Base Plane Coordinates - NAD 27):10.KB Elevation above MSL (ft): 63.5'15.Distance to Nearest Well Open Surface: x-565406 y- 5999865 Zone- 4 37.0' to Same Pool:1325' 16.Deviated wells: Kickoff depth: 500 feet 17.Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 90 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD Driven 20" 129.5# X-52 80' Surface Surface 110' 110' 47# L-80 TXP 2,500' Surface Surface 2,500' 2,236' 40# L-80 TXP 2,595' 2,500' 2,236' 5,095' 4,097' 8-1/2" 4-1/2" 13.5# L-80 Hyd 625 8,632' 4,945' 4,084' 13,577' 4,081' 19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Junk (measured): TVD Hydraulic Fracture planned? Yes No 20. Attachments: Property Plat BOP Sketch Drilling Program Time v. Depth Plot Shallow Hazard Analysis Diverter Sketch Seabed Report Drilling Fluid Program 20 AAC 25.050 requirements Contact Name: Nathan Sperry Monty Myers Contact Email:nathan.sperry@hilcorp.com Drilling Manager Contact Phone:777-8450 Date: Permit to Drill API Number: Permit Approval Number:Date: Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales: Samples req'd: Yes No Mud log req'd: Yes No H2S measures: Yes No Directional svy req'd: Yes No Spacing exception req'd: Yes No Inclination-only svy req'd: Yes No Post initial injection MIT req'd: Yes No APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng 12-1/4" 9-5/8" 6/23/2021 21. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Surface Perforation Depth TVD (ft): GL / BF Elevation above MSL (ft): Perforation Depth MD (ft): Uncemented Screen Liner Effect. Depth MD (ft): Effect. Depth TVD (ft): Authorized Title: Authorized Signature: Production Liner Intermediate Authorized Name: Conductor/Structural LengthCasing Cement Volume MDSize Plugs (measured): (including stage data) Stg 1 L - 649 ft3 / T - 458 ft3 5120 18.Casing Program: Top - Setting Depth - BottomSpecifications 1917 Total Depth MD (ft): Total Depth TVD (ft): 22224484 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 Stg 2 L - 1935 ft3 / T - 313 ft3 1507 1973' FNL, 847' FEL, Sec, 12, T12N, R10E, UM, AK 845' FSL, 2347' FWL, Sec. 35, T13N, R10E, UM, AK 01-001 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 Hilcorp Alaska, LLC 3202' FSL, 605' FEL, Sec. 12, T12N, R10E, UM, AK ADL 380109 & 025518 MPU S-44 Milne Point Field Schrader Bluff Oil Pool Cement Quantity, c.f. or sacks Commission Use Only See cover letter for other requirements. Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g) 6.3.2021 By Samantha Carlisle at 9:27 am, Jun 03, 2021 Digitally signed by Monty M Myers DN: cn=Monty M Myers, c=US, o=Hilcorp Alaska, LLC, ou=Technical Services - AK Drilling, email=mmyers@hilcorp.com Reason: I am approving this document Date: 2021.06.03 09:19:35 -08'00' Monty M Myers X X * BOPE test to 3000 psi. Annular to 2500 psi. * State witnessed MIT-IA to 2500 psi. X DSR-6/3/21 221-044 X X MGR04JUN2021 X X 50-029-23694-00-00 DLB 06/08/2021dts 6/8/2021 JLC 6/8/2021 6/8/21 6/8/21Jeremy Price Digitally signed by Jeremy Price Date: 2021.06.08 14:58:41 -08'00' Area of Review MPS-44PTDAPIWELL STATUSTop of SBNB (MD)Top of SBNB (TVD)Top ofCement(MD)Top ofCement(TVD)Schrader NBstatusZonal Isolation202-114 50-029-23093-00-00 MPU S-13 OA / OB Injector 4,440' 4,089' Surface Surface ClosedCement to Surface221-042 50-029-23693-00-00 MPU S-45 NB Producer (not drilled) ~5,842' ~4,045' N/A N/A TBD - OpenOpen to Injection Support onceDrilled202-242 50-029-23133-00-00 MPU S-18 OA / OB Injector 8,243' 4,138' 5,340' 3,092' Closed7" casing ran to 8,704 MD andcement top calculated at 5,340'203-065 50-029-23151-00-00 MPU S-16 NB Injector 5,866' 4,091 N/A N/A OpenOpen to Injection Support205-135 50-029-23276-00-00 MPU S-90 Sag River Producer 4,740' 4,118' 6,347' 5,521' Closed9-5/8" casing ran to 7,942' MD andcement top calculated at 6,347'201-245 50-029-23061-00-00 MPU S-15 OA / OB Injector 4,401' 4,179' Surface Surface ClosedCement to Surface220-013 50-029-23666-00-00 MPU S-57 NE Producer 4,875' 4,077' Surface Surface ClosedCement to Surface202-132 50-029-23098-00-00 MPU S-23 OB Producer 4,556' 4076' Surface Surface ClosedCement to Surface202-133 50-029-23098-60-00 MPU S-23L1 OA Producer 4,556' 4,076' Surface Surface ClosedCement to Surface202-173 50-029-23115-00-00 MPU S-17 OB Producer 4,485' 4,124' Surface Surface ClosedCement to Surface202-174 50-029-23115-60-00 MPU S-17L1 OA Producer 4,485' 4,124' Surface Surface ClosedCement to Surface203-038 50-029-23142-00-00 MPU S-24 Shut In NB Producer 4,876' 4,029' N/A N/A OpenOpen to Injection Support202-195 50-029-23119-00-00 MPU S-29 Shut In OB Producer7,863' 4,013'Surface SurfaceClosedCement to Surface202-196 50-029-23119-60-00 MPU S-29L1 Shut In OA Producer7,863' 4,013'Surface SurfaceClosedCement to Surface197-173 50-029-22808-00-00 MPU H-08 P&A'd8,763' 4,024' Surface Surface ClosedCement to Surface199-122 50-029-22808-01-00 MPU H-08A P&A'd8,763' 4,024' Surface Surface ClosedCement to Surface201-047 50-029-22808-02-00 MPU H-08B OB ProducerN/A N/A Surface Surface ClosedCement to Surface201-048 50-029-22808-60-00 MPU H-08BL1 OA ProducerN/A N/A Surface Surface ClosedCement to Surface197-170 50-029-22807-00-00 MPU H-12 Shut in NB, OA, OB WINJ7,896' 4,095' Surface Surface OpenOpen to Injection Support Milne Point Unit (MPU) S-44 Drilling Program Version 1 5/3/2021 Table of Contents 1.0 Well Summary ........................................................................................................................... 2 2.0 Management of Change Information ........................................................................................ 3 3.0 Tubular Program:...................................................................................................................... 4 4.0 Drill Pipe Information: .............................................................................................................. 4 5.0 Internal Reporting Requirements ............................................................................................. 5 6.0 Planned Wellbore Schematic ..................................................................................................... 6 7.0 Drilling / Completion Summary ................................................................................................ 8 8.0 Mandatory Regulatory Compliance / Notifications .................................................................. 9 9.0 RU and Preparatory Work ...................................................................................................... 11 10.0 NU 13-5/8” 5M Diverter Configuration .................................................................................. 12 11.0 Drill 12-1/4” Hole Section ........................................................................................................ 14 12.0 Run 9-5/8” Surface Casing ...................................................................................................... 17 13.0 Cement 9-5/8” Surface Casing ................................................................................................. 23 14.0 NU BOP and Test..................................................................................................................... 28 15.0 Drill 8-1/2” Hole Section .......................................................................................................... 29 16.0 Run 4-1/2” Injection Liner (Lower Completion) .................................................................... 34 17.0 Run 3-1/2” Tubing (Upper Completion) ................................................................................. 38 18.0 Innovation Rig Diverter Schematic ......................................................................................... 40 19.0 Innovation Rig BOP Schematic ............................................................................................... 41 20.0 Wellhead Schematic ................................................................................................................. 42 21.0 Days Vs Depth .......................................................................................................................... 43 22.0 Formation Tops & Information............................................................................................... 44 23.0 Anticipated Drilling Hazards .................................................................................................. 46 24.0 Innovation Rig Layout ............................................................................................................. 49 25.0 FIT Procedure .......................................................................................................................... 50 26.0 Innovation Rig Choke Manifold Schematic ............................................................................ 51 27.0 Casing Design ........................................................................................................................... 52 28.0 8-1/2” Hole Section MASP ....................................................................................................... 53 29.0 Spider Plot (NAD 27) (Governmental Sections) ...................................................................... 54 30.0 Surface Plat (As Built) (NAD 27) ............................................................................................. 55 Page 2 Milne Point Unit S-44 SB Injector Drilling Procedure 1.0 Well Summary Well MPU S-44 Pad Milne Point “S” Pad Planned Completion Type 3-1/2” Injection Tubing Target Reservoir(s) Schrader Bluff Nb Sand Planned Well TD, MD / TVD 13,577’ MD / 4,081’ TVD PBTD, MD / TVD 13,577’ MD / 4,081’ TVD Surface Location (Governmental) 2078' FNL, 605' FEL, Sec 12, T12N, R10E, UM, AK Surface Location (NAD 27) X= 565,406 Y=5,999,865 Top of Productive Horizon (Governmental)1973' FNL, 847' FEL, Sec 12, T12N, R10E, UM, AK TPH Location (NAD 27) X= 563,011 Y=6,008,048 BHL (Governmental) 845' FSL, 2347' FWL, Sec 35, T13N, R10E, UM, AK BHL (NAD 27) X= 563,011 Y=6,080,048 AFE Number AFE Drilling Days 17 days AFE Completion Days 3 days AFE Drilling Amount AFE Completion Amount AFE Facility Amount Maximum Anticipated Pressure (Surface) 1,507 psig Maximum Anticipated Pressure (Downhole/Reservoir) 1,917 psig Work String 5”, 19.5#, S-135, DS-50 & NC 50 KB Elevation above MSL: 26.5 ft + 37.0 ft = 63.5 ft GL Elevation above MSL: 37.0 ft BOP Equipment 13-5/8” x 5M Annular, (3) ea 13-5/8” x 5M Rams Page 3 Milne Point Unit S-44 SB Injector Drilling Procedure 2.0 Management of Change Information Page 4 Milne Point Unit S-44 SB Injector Drilling Procedure 3.0 Tubular Program: Hole Section OD (in)ID (in)Drift (in) Conn OD (in) Wt (#/ft) Grade Conn Burst (psi) Collapse (psi) Tension (k-lbs) Cond 20” 19.250”---X-52Weld 12-1/4”9-5/8” 8.835”8.679”10.625”40.0 L-80 TXP 5,750 3,090 916 9-5/8” 8.681”8.525”10.625”47 L-80 TXP 6,870 4,750 1,086 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 8 RD 10,160 10,535 207 4.0 Drill Pipe Information: Hole Section OD (in) ID (in)TJ ID (in) TJ OD (in) Wt (#/ft) Grade Conn M/U (Min) M/U (Max) Tension (k-lbs) Surface & Production 5”4.276” 3.25” 6.625” 19.5 S-135 GPDS50 36,100 43,100 560klb 5”4.276”3.25” 6.625”19.5 S-135 NC50 31,032 34,136 560klb All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery). Page 5 Milne Point Unit S-44 SB Injector Drilling Procedure 5.0 Internal Reporting Requirements 5.1 Fill out daily drilling report and cost report on WellEz. x Report covers operations from 6am to 6am x Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left of the data entry area – this will not save the data entered, and will navigate to another data entry. x Ensure time entry adds up to 24 hours total. x Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. x Enter the MD and TVD depths EVERY DAY whether you are making hole or not. 5.2 Afternoon Updates x Submit a short operations update each work day to pmazzolini@hilcorp.com, mmyers@hilcorp, nathan.sperry@hilcorp.com and joseph.lastufka@hilcorp.com 5.3 Intranet Home Page Morning Update x Submit a short operations update each morning by 7am on the company intranet homepage. On weekend and holidays, ensure to have this update in before 5am. 5.4 EHS Incident Reporting x Health and Safety: Notify EHS field coordinator. x Environmental: Drilling Environmental Coordinator x Notify Drilling Manager & Drilling Engineer on all incidents x Submit Hilcorp Incident report to contacts above within 24 hrs 5.5 Casing Tally x Send final “As-Run” Casing tally to mmyers@hilcorp,com nathan.sperry@hilcorp.com and joseph.lastufka@hilcorp.com 5.6 Casing and Cement report x Send casing and cement report for each string of casing to mmyers@hilcorp,com nathan.sperry@hilcorp.com and joseph.lastufka@hilcorp.com 5.7 Hilcorp Milne Point Contact List: Title Name Work Phone Cell Phone Email Drilling Manager Monty Myers 907.777.8431 907.538.1168 mmyers@hilcorp.com Drilling Engineer Joe Engel 907.777.8395 805.235.6265 jengel@hilcorp.com Drilling Engineer Nate Sperry 907.777.8450 907.301.8996 nathan.sperry@hilcorp.com Completion Engineer David Gorm 907.777.8333 505.215.2819 dgorm@hilcorp.com Geologist John Salsbury 907.777.8481 907.350.1088 jsalsbury@hilcorp.com Reservoir Engineer Reid Edwards 907.777.8421 907.250.5081 reedwards@hilcorp.com Drilling Env. Coordinator Keegan Fleming 907.777.8477 907.350.9439 kfleming@hilcorp.com EHS Manager Carl Jones 907.777.8327 907.382.4336 cajones@hilcorp.com Drilling Tech Joe Lastufka 907.777.8400 907.227.8496 Joseph.Lastufka@hilcorp.com Page 6 Milne Point Unit S-44 SB Injector Drilling Procedure 6.0 Planned Wellbore Schematic Page 8 Milne Point Unit S-44 SB Injector Drilling Procedure 7.0 Drilling / Completion Summary MPU S-44 is a grassroots injector planned to be drilled in the Schrader Bluff Nb sand. S-44 is part of a multi well program targeting the Schrader Bluff sand on S-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 Nb sand. An 8-1/2” lateral section will then be drilled. A 4-1/2” screened injection liner will be run in the open hole section. The Innovation Rig will be used to drill and complete the wellbore. Drilling operations are expected to commence approximately June 23rd, 2021, pending rig schedule. Surface casing will be run to 5,095’ MD / 4,097’ TVD and cemented to surface via a 2 stage primary cement job. Cement returns to surface will confirm TOC at surface. If cement returns to surface are not observed, necessary remedial action will then be discussed with AOGCC authorities. All cuttings & mud generated during drilling operations will be hauled to the Milne Point “B” pad G&I facility. General sequence of operations: 1. MIRU Innovation to well site 2. NU & Test 13-5/8” Diverter and 16” diverter line 3. Drill 12-1/4” hole to TD of surface hole section. Run and cement 9-5/8” surface casing. 4. ND diverter, NU & test 13-5/8” x 5M BOP. 5. Drill 8-1/2” lateral to well TD. Run 4-1/2” injection liner. 6. Run 3-1/2” tubing. 7. 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 9 Milne Point Unit S-44 SB Injector Drilling Procedure 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the all applicable AOGCC regulations, specific regulations are listed below. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. x BOPs shall be tested at (2) week intervals during the drilling and completion of MPU S-44. Ensure to provide AOGCC 24 hrs notice prior to testing BOPs. x The initial test of BOP equipment will be to 250/3000 psi & subsequent tests of the BOP equipment will be to 250/3000 psi for 5/5 min (annular to 50% rated WP, 2500 psi on the high test for initial and subsequent tests).Confirm that these test pressures match those specified on the APD. x If the BOP is used to shut in on the well in a well control situation or control fluid flow from the well bore, AOGCC is to be notified and we must test all BOP components utilized for well control prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP test. x All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid program and drilling fluid system”. x All AOGCC regulations within 20 AAC 25.035 “Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements”. o Ensure the diverter vent line is at least 75’ away from potential ignition sources x Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office. x Notify the AOGCC at least 24 hours in advance of the IA pressure test after running the completion as per 20 AAC 25.412 (e). Record pressure test on 10-426 form and email to Abhijeet.tambe@hilcorp.com for submission to AOGCC. x Hilcorp Alaska proposes to demonstrate isolation of the injected fluid as required under 20 AAC 25.412 (d) through cement job operational reports of a complete two stage cement job on the 9-5/8” surface casing. Planned surface cement volumes and cement returns to surface seen during both stages will indicate placement of cement in the entire surface casing annulus. A successful FIT after surface casing drill out will demonstrate isolation of injection fluid. AOGCC Regulation Variance Requests: Hilcorp Alaska LLC does not request any variances at this time. Page 10 Milne Point Unit S-44 SB Injector Drilling Procedure Summary of BOP Equipment and Test Requirements Hole Section Equipment Test Pressure (psi) 12 1/4”x 13-5/8” 5M CTI Annular BOP w/ 16” diverter line Function Test Only 8-1/2” x 13-5/8” x 5M Control Technology Inc Annular BOP x 13-5/8” x 5M Control Technology Inc Double Gate o Blind ram in btm cavity x Mud cross w/ 3” x 5M side outlets x 13-5/8” x 5M Control Technology Single ram x 3-1/8” x 5M Choke Line x 3-1/8” x 5M Kill line x 3-1/8” x 5M Choke manifold x Standpipe, floor valves, etc Initial Test: 250/3,000 Subsequent Tests: 250/3,000 Primary closing unit: Control Technology Inc. (CTI), 6 station, 3,000 psi, 220 gallon accumulator unit. Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is an electric triplex pump on a different electrical circuit and emergency pressure is provided by bottled nitrogen. The remote closing operator panels are located in the doghouse and on accumulator unit. Required AOGCC Notifications: x Well control event (BOPs utilized to shut in the well to control influx of formation fluids). x 24 hours notice prior to spud. x 24 hours notice prior to testing BOPs. x 24 hours notice prior to casing running & cement operations. x Any other notifications required in APD. Regulatory Contact Information: AOGCC Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email:jim.regg@alaska.gov Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Email:Victoria.loepp@alaska.gov Mel Rixse / Petroleum Engineer / (O): 907-793-1231 / (C): 907-223-3605 / Email:melvin.rixse@alaska.gov Primary Contact for Opportunity to witness:AOGCC.Inspectors@alaska.gov Test/Inspection notification standardization format:http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) Page 11 Milne Point Unit S-44 SB Injector Drilling Procedure 9.0 RU and Preparatory Work 9.1 S-44 will utilize a newly set 20” conductor on S-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 the rig. 9.7 MIRU Innovation Rig. Ensure rig is centered over conductor to prevent any wear to BOPE or wellhead. 9.8 Mud loggers WILL NOT be used on either hole section. 9.9 Mix spud mud for 12-1/4” surface hole section. Ensure mud temperatures are cool (<80qF). 9.10 Set test plug in wellhead prior to NU diverter to ensure nothing can fall into the wellbore if it is accidentally dropped. 9.11 Ensure 5” liners in mud pumps. x White Star Quattro 1300 HP mud pumps are rated at 4,097 psi, 381 gpm @ 140 spm @ 96.5% volumetric efficiency. Page 12 Milne Point Unit S-44 SB Injector Drilling Procedure 10.0 NU 13-5/8” 5M Diverter Configuration 10.1 NU 13-5/8” CTI BOP stack in diverter configuration (Diverter Schematic attached to program). x NU 20” x 13-5/8” DSA x NU 13 5/8”, 5M diverter “T”. x NU Knife gate & 16” diverter line. x Ensure diverter RU complies with AOGCC reg 20.AAC.25.035(C). x Diverter line must be 75 ft from nearest ignition source x Place drip berm at the end of diverter line. x Utilized extensions if needed. 10.2 Notify AOGCC. Function test diverter. x Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens prior to annular closure. x Ensure that the annular closes in less than 30 seconds (API Standard 64 3rd edition March 2018 section 12.6.2 for packing element ID less than or equal to 20”) 10.3 Ensure to set up a clearly marked “warning zone” is established on each side and ahead of the vent line tip. “Warning Zone” must include: x A prohibition on vehicle parking x A prohibition on ignition sources or running equipment x A prohibition on staged equipment or materials x Restriction of traffic to essential foot or vehicle traffic only. 24 hour notice. Page 13 Milne Point Unit S-44 SB Injector Drilling Procedure 10.4 Rig & Diverter Orientation: Page 14 Milne Point Unit S-44 SB Injector Drilling Procedure 11.0 Drill 12-1/4” Hole Section 11.1 PU 12-1/4” directional drilling assembly: x Ensure BHA components have been inspected previously. x Drift and caliper all components before MU. Visually verify no debris inside components that cannot be drifted. x Ensure TF offset is measured accurately and entered correctly into the MWD software. x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. x Drill string will be 5”, 19.5#, S-135, NC50. x Run a solid float in the surface hole section. 11.2 Begin drilling out from 20” conductor at reduced flow rates to avoid broaching the conductor. x Consider using a trash bit to clean out conductor to mitigate potential damage from debris in conductor. 11.3 Drill 12-1/4” hole section to TD x Monitor the area around the conductor for any signs of broaching. If broaching is observed, Stop drilling (or circulating) immediately notify Drilling Engineer. x Efforts should be made to minimize dog legs in the surface hole. x Hold a safety meeting with rig crews to discuss: x Conductor broaching ops and mitigation procedures. x Well control procedures and rig evacuation x Flow rates, hole cleaning, mud cooling, etc. x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Keep mud as cool as possible to keep from washing out permafrost. x Pump at 400-600 GPM. Monitor shakers closely to ensure shaker screens and return lines can handle the flow rate. x Ensure to not out drill hole cleaning capacity, perform clean up cycles or reduce ROP if packoffs, increase in pump pressure, or changes in hookload are seen. x Slow in/out of slips and while tripping to keep swab and surge pressures low. x Ensure shakers are functioning properly. Check for holes in screens on connections. x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of pea gravel, clay balling, or packing off. x Adjust MW and viscosity as necessary to maintain hole stability. x Perform GWD surveys until MWD surveys are clean. Take MWD surveys every stand drilled as well. x Gas hydrates may be present on S-pad. Historically encountered hydrates are typically around 2,100’-2,400’ TVD (just below permafrost). Be prepared for hydrates: x Gas hydrates can be identified by the gas detector and a decrease in MW or ECD x Monitor returns for hydrates, checking pressurized & non-pressurized scales x Do not stop to circulate out gas hydrates – this will only exacerbate the problem by washing out additional permafrost. Attempt to control drill (150 FPH MAX) through the Page 15 Milne Point Unit S-44 SB Injector Drilling Procedure zone completely and efficiently to mitigate the hydrate issue. Flowrates can also be reduced to prevent mud from belching over the bell nipple. Consider adding Lecithin to allow the gas to break out. x Gas hydrates are not a gas sand. Once a hydrate is disturbed the gas will come out of the well. MW will not control gas hydrates but will affect how gas breaks out at surface x A/C: x There are no wells with a clearance factor < 1.0 11.4 12-1/4” hole mud program summary: x Density: Weighting material to be used for the hole section will be barite. Additional barite or spike fluid will be on location to weight up the active system (1) ppg above highest anticipated MW. We will start with a simple gel + FW spud mud at 8.8 ppg and TD with 9.2+ ppg. Depth Interval MW (ppg) Surface – Base Permafrost 8.9+ Base Permafrost - TD 9.2+ x PVT System: MD Totco PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, Toolpusher office, and mud loggers office. x Rheology: Aquagel and Barazan D+ should be used to maintain rheology. Begin system with a 75 YP but reduce this once clays are encountered. Maintain a minimum 25 YP at all times while drilling. Be prepared to increase the YP if hole cleaning becomes an issue. x Fluid Loss: DEXTRID and/or PAC L should be used for filtrate control. Background LCM (10 ppb total) BARACARBs/BAROFIBRE/STEELSEALs can be used in the system while drilling the surface interval to prevent losses and strengthen the wellbore. x Wellbore and mud stability:Additions of CON DET PRE-MIX/DRIL N SLIDE are recommended to reduce the incidence of bit balling and shaker blinding when penetrating the high-clay content sections of the Sagavanirktok and the heavy oil sections of the UGNU 4A. Maintain the pH in the 8.5 – 9.0 range with caustic soda. Daily additions of ALDACIDE G / X-CIDE 207 MUST be made to control bacterial action. x Casing Running:Reduce system YP with DESCO as required for running casing as allowed (do not jeopardize hole conditions). Run casing carefully to minimize surge and swab pressures. Reduce the system rheology once the casing is landed to a YP < 20 (check with the cementers to see what YP value they have targeted). System Type:8.8 – 9.2 ppg Pre-Hydrated Aquagel/freshwater spud mud Properties: Section Density Viscosity Plastic Viscosity Yield Point API FL pH Temp Surface 8.8 –9.8 75-175 20 - 40 25-45 <10 8.5 –9.0 70 F EMW needed: 8.46 ppg EMW needed: 8.46 - 9.00 ppg DLB Page 16 Milne Point Unit S-44 SB Injector Drilling Procedure System Formulation: Gel + FW spud mud Product Concentration Fresh Water soda Ash AQUAGEL caustic soda BARAZAN D+ BAROID 41 PAC-L /DEXTRID LT ALDACIDE G 0.905 bbl 0.5 ppb 15 - 20 ppb 0.1 ppb (8.5 – 9.0 pH) as needed as required for 8.8 – 9.2 ppg if required for <10 FL 0.1 ppb 11.5 At TD, CBU and condition the mud until the hole is clean while BROOH. Rack back stands but do not trip to bottom until the hole is clean. 11.6 RIH to bottom, proceed to BROOH to HWDP x Pump at full drill rate (400-600 GPM), and maximize rotation. x Pull slowly, 5 – 10 FPM, as dictated by hole conditions x Monitor well for any signs of packing off or losses. x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay balling. x If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until parameters are restored. 11.7 TOOH and LD BHA 11.8 No open hole logging program planned. Page 17 Milne Point Unit S-44 SB Injector Drilling Procedure 12.0 Run 9-5/8” Surface Casing 12.1 RU and pull wearbushing. 12.2 RU Weatherford 9-5/8” casing running equipment (CRT & Tongs) x Ensure 9-5/8” TXP x DS50 XO on rig floor and MU to FOSV. x Use BOL 2000 thread compound. Dope pin end only w/ paint brush. x RU of CRT if hole conditions require. x RU a fill up tool to fill casing while running if the CRT is not used. x Ensure all casing has been drifted to 8.750” on the location prior to running. x Top 2000’ of casing 47# drift 8.525” x Be sure to count the total # of joints on the location before running. x Keep hole covered while RU casing tools. x Record OD’s, ID’s, lengths and 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 locking 120’ shoe track assembly consisting of: 9-5/8” Float Shoe 1 joint – 9-5/8” TXP, 2 Centralizers 10’ from each end with stop rings 1 joint –9-5/8” TXP, 1 Centralizer mid joint with stop ring 9-5/8” Float Collar w/ Stage Cementer Bypass Baffle ‘Top Hat’ 1 joint –9-5/8” TXP, 1 Centralizer mid joint with stop ring 9-5/8” HES Baffle Adaptor x Ensure bypass baffle is correctly installed on top of float collar. x Ensure proper operation of float equipment while picking up. x Ensure to record SN’s of all float equipment and stage tool components. This end up. Bypass Baffle 2500' Page 18 Milne Point Unit S-44 SB Injector Drilling Procedure 12.5 Float equipment and Stage tool equipment drawings: Page 19 Milne Point Unit S-44 SB Injector Drilling Procedure 12.6 Continue running 9-5/8” surface casing x Fill casing while running using fill up line on rig floor. x Use BOL 2000 thread compound. Dope pin end only w/ paint brush. x Centralization: Verify depth of lowest Ugnu water sand for isolation with Geologist x Utilize a collar clamp until weight is sufficient to keep slips set properly. x Break circulation prior to reaching the base of the permafrost if casing run indicates poor hole conditions. x Any packing off while running casing should be treated as a major problem. It is preferable to POOH 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 (roughly ~ 2,500’ MD). x Install centralizers over couplings on 5 joints below and 10 joints above stage tool. x Do not place tongs on ES cementer, this can cause damaged to the tool. x Ensure tool is pinned with 6 opening shear pins. This will allow the tool to open at 3300 psi. 9-5/8”, 40#, L-80, TXP MU Torques: Casing OD Minimum Optimum Maximum 9-5/8”18,860 ft-lbs 20,960 ft-lbs 23,060 ft-lbs 9-5/8” 47# L-80 TXP MUT: Casing OD Minimum Optimum Maximum 9-5/8” 21,440 ft-lbs 2,3820 ft-lbs 26,200 ft-lbs Depth Interval Centralization Shoe – 1000’ Above Shoe 1/joint 1000’ above Shoe –2000’ above Shoe (Top of Ugnu)1/ 2 joints Page 20 Milne Point Unit S-44 SB Injector Drilling Procedure Page 21 Milne Point Unit S-44 SB Injector Drilling Procedure 12.8 Continue running 9-5/8” surface casing x 9-5/8” 47# from 2000’ to surface x Centralizers: 1 centralizer every 3rd joint to 200’ from surface x Fill casing while running using fill up line on rig floor. x Use BOL 2000 thread compound. Dope pin end only with paint brush. Page 22 Milne Point Unit S-44 SB Injector Drilling Procedure 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 job and mark the joint at (1) ft intervals to use as a reference when getting the casing on depth. 12.12 Lower casing to setting depth. Confirm measurements. 12.13 Have slips staged in cellar, along with necessary equipment for the operation. 12.14 Circulate and condition mud through CRT. Reduce YP to < 20 to help ensure success of cement job. Ensure adequate amounts of cold MU water are available to achieve this. If possible reciprocate casing string while conditioning mud. Page 23 Milne Point Unit S-44 SB Injector Drilling Procedure 13.0 Cement 9-5/8” Surface Casing 13.1 Hold a pre-job safety meeting over the upcoming cement operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud & water can be delivered to the cementing unit at acceptable rates. x How to handle cement returns at surface. Ensure vac trucks are on standby and ready to assist. x Which pumps will be utilized for displacement, and how fluid will be fed to displacement pump. x Ensure adequate amounts of water for mix fluid is heated and available in the water tanks. x Positions and expectations of personnel involved with the cementing operation. i. Extra hands in the pits to strap during the cement job to identify any losses x Review test reports and ensure pump times are acceptable. x Conduct visual inspection of all hard lines and connections used to route slurry to rig floor. 13.2 Document efficiency of all possible displacement pumps prior to cement job. 13.3 Flush through cement pump and treating iron from pump to rig floor to the shakers. This will help ensure any debris left in the cement pump or treating iron will not be pumped downhole. 13.4 R/U cement line (if not already done so). Company Rep to witness loading of the top and bottom plugs to ensure done in correct order. 13.5 Fill surface cement lines with water and pressure test. 13.6 Pump remaining 60 bbls 10.5 ppg tuned spacer. 13.7 Drop bottom plug (flexible bypass plug) – HEC rep to witness. Mix and pump cement per below calculations for the 1st stage, confirm actual cement volumes with cementer after TD is reached. 13.8 Cement volume based on annular volume + 30% open hole excess. Job will consist of lead & tail, TOC brought to stage tool. Estimated 1st Stage Total Cement Volume: 395 sx 276 sx Page 24 Milne Point Unit S-44 SB Injector Drilling Procedure Cement Slurry Design (1st Stage Cement Job): 13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Watch reciprocation PU and SO weights, if the hole gets “sticky”, cease pipe reciprocation and continue with the cement job. 13.9 After pumping cement, drop top plug (Shutoff plug) and displace cement with spud mud out of mud pits, spotting water across the HEC stage cementer. x Ensure volumes pumped and volumes returned are documented and constant communication between mud pits, HEC Rep and HES Cementers during the entire job. 13.10 Ensure rig pump is used to displace cement. Displacement calculations have proven to be very accurate using 0.0625 bps (5” liners) for the Quattro pump output. To operate the stage tool hydraulically, the plug must be bumped. 13.11 Displacement calculation: 2,000’ x 0.0732 BPF + (5,095’ – 120’ - 2,000’) x .0758 BPF = 372.0 bbls 80 bbls of tuned spacer to be left behind stage tool,confirm fluid is compatible with cement behind stage tool 13.12 Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any point during the job. Be prepared to pump out fluid from cellar. Have black water available to contaminate any cement seen at surface. 13.13 If plug is not bumped at calculated strokes, double check volumes and calculations. Over displace by no more than 50% of shoe track volume, ±4.5 bbls before consulting with Drilling Engineer. 13.14 If plug is not bumped, consult with Drilling Engineer. Ensure the free fall stage tool opening plug is available if needed. This is the back-up option to open the stage tool if the plugs are not bumped. 13.15 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held, this is to ensure the stage tool is not prematurely opened. Lead Slurry Tail Slurry Density 12.0 lb/gal 15.8 lb/gal Yield 2.35 ft3/sk 1.16 ft3/sk Mixed Water 13.92 gal/sk 4.98 gal/sk (2500 * .0732) + ((5095 - 120 - 2500) * .0758) = 370.6 bbls Page 25 Milne Point Unit S-44 SB Injector Drilling Procedure 13.16 Increase pressure to 3,300 psi to open circulating ports in stage collar. Slightly higher pressure may be necessary if TOC is above the stage tool. CBU and record any spacer or cement returns to surface and volume pumped to see the returns. Circulate until YP < 20 again in preparation for the 2nd stage of the cement job. 13.17 Be prepared for cement returns to surface. Dump cement returns in the cellar or open the shaker bypass line to the cuttings tank. Have black water available and vac trucks ready to assist. Ensure to flush out any rig components, hard lines and BOP stack that may have come in contact with the cement. Page 26 Milne Point Unit S-44 SB Injector Drilling Procedure Second Stage Surface Cement Job: 13.18 Prepare for the 2 nd stage as necessary. Circulate until first stage reaches sufficient compressive strength. Try to maintain flow rate through stage tool until 2nd stage is ready. Hold pre-job safety meeting. x Past wells have seen pressure increase while circulating through stage tool after reduced rate 13.19 HEC representative to witness the loading of the ES cementer closing plug in the cementing head. 13.20 Fill surface lines with water and pressure test. 13.21 Pump remaining 60 bbls 10.5 ppg tuned spacer. 13.22 Mix and pump cmt per below recipe for the 2 nd 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): 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 Lead Slurry Tail Slurry System Permafrost L Density 10.7 lb/gal 15.8 lb/gal Yield 4.41 ft3/sk 1.17 ft3/sk Mixed Water 22.02 gal/sk 5.08 gal/sk 437 sx 270 sx Page 27 Milne Point Unit S-44 SB Injector Drilling Procedure 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 - 200 bbls of cement slurry to surface. 13.29 Land closing plug on stage collar and pressure up to 1,000 – 1,500 psi to ensure stage tool closes. Follow instructions of Halliburton personnel. Bleed off pressure and check to ensure stage tool has closed. Slips will be set as per plan to allow full annulus for returns during surface cement job. Set slips 13.30 Make initial cut on 9-5/8” final joint. L/D cut joint. Make final cut on 9-5/8”. Dress off stump. Install 9-5/8” wellhead. If transition nipple is welded on, allow to cool as per schedule. Ensure to report the following on wellez: x Pre flush type, volume (bbls) & weight (ppg) x Cement slurry type, lead or tail, volume & weight x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid x Note if casing is reciprocated or rotated during the job x Calculated volume of displacement , actual displacement volume, whether plug bumped & bump pressure, do floats hold x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure x Note if pre flush or cement returns at surface & volume x Note time cement in place x Note calculated top of cement x Add any comments which would describe the success or problems during the cement job Send final “As-Run” casing tally & casing and cement report to nathan.sperry@hilcorp.com and joseph.lastufka@hilcorp.com This will be included with the EOW documentation that goes to the AOGCC. Page 28 Milne Point Unit S-44 SB Injector Drilling Procedure 14.0 NU BOP and Test 14.1 ND the diverter T, 16” knife gate, 16” diverter line & NU 11” x 13-5/8” 5M casing spool. 14.2 NU 13-5/8” x 5M CTI BOP as follows: x BOP configuration from top down: 13-5/8” x 5M annular / 13-5/8” x 5M double gate / 13- 5/8” x 5M mud cross / 13-5/8” x 5M single gate x Double gate ram should be dressed with 2-7/8” x 5-1/2” VBRs in top cavity,blind ram in bottom cavity. x Single ram should be dressed with 2-7/8” x 5-1/2” VBRs or 5” Solid Body Rams x NU bell nipple, install flowline. x Install (1) manual valve & HCR valve on kill side of mud cross. (Manual valve closest to mud cross). x Install (1) manual valve & HCR valve on choke side of mud cross. (manual valve closest to mud cross) 14.3 Run 5” BOP test plug (if not installed previously). x Test BOP to 250/3,000 psi for 5/5 min. Test annular to 250/2,500 psi for 5/5 min. x Confirm test pressures with PTD x Ensure to monitor side outlet valves and annulus valve pressure gauges to ensure no pressure is trapped underneath test plug x Once BOPE test is complete, send a copy of the test report to town engineer and drilling tech 14.4 RD BOP test equipment 14.5 Dump and clean mud pits, send spud mud to G&I pad for injection. 14.6 Mix 8.9 ppg Baradrill-N fluid for production hole. 14.7 Set wearbushing in wellhead. 14.8 Rack back as much 5” DP in derrick as possible to be used while drilling the hole section. 24 hour notice to AOGCC. Page 29 Milne Point Unit S-44 SB Injector Drilling Procedure 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 morning report. Drill out stage tool. 15.3 TIH to TOC above the baffle adapter. Note depth TOC tagged on morning report. 15.4 RU and test casing to 2,500 psi for 30 minutes charted. Ensure to record volume / pressure and plot on FIT graph. AOGCC reg is 50% of burst = 6870 / 2 = ~3500 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. Pump at least one high vis sweep at maximum rate to surface to clean up debris. 15.7 Conduct FIT to 12.0 ppg EMW. Chart test. Ensure test is recorded on same chart as FIT. Document incremental volume pumped (and subsequent pressure) and volume returned. 15.8 POOH & LD cleanout BHA 15.9 PU 8-1/2” directional BHA. x Ensure BHA components have been inspected previously. x Drift and caliper all components before MU. Visually verify no debris inside components that cannot be drifted. x Ensure TF offset is measured accurately and entered correctly into the MWD software. x Ensure MWD is RU and operational. x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. x Drill string will be 5”, 19.5#, S-135, DS50 & NC50. x Run a ported float in the production hole section. 15.10 8-1/2” hole section mud program summary: x Density: Weighting material to be used for the hole section will be calcium carbonate. Additional calcium carbonate will be on location to weight up the active system (1) ppg above highest anticipated MW. Casing test and FIT digital data to AOGCC. Page 30 Milne Point Unit S-44 SB Injector Drilling Procedure x Solids Concentration: It is imperative that the solids concentration be kept low while drilling the production hole section. Keep the shaker screen size optimized and fluid running to near the end of the shakers. It is okay if the shakers run slightly wet to ensure we are running the finest screens possible. x Rheology: Keep viscosifier additions to an absolute minimum (N-VIS). Data suggests excessive viscosifier concentrations can decrease return permeability. Do not pump high vis sweeps, instead use tandem sweeps. Ensure 6 rpm is > 8.5 (hole diameter) for sufficient hole cleaning x Run the centrifuge continuously while drilling the production hole, this will help with solids removal. x Dump and dilute as necessary to keep drilled solids to an absolute minimum. x MD Totco PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, & Toolpusher office. System Type:8.9 – 9.5 ppg Baradrill-N drilling fluid Properties: Section Density Plastic Viscosity Yield Point Total Solids MBT HPHT Production 8.9-9.5 15-25 20-25 <10% <7 <11.0 System Formulation: Baradrill-N Product Concentration Water KCL KOH N-VIS DEXTRID LT BARACARB 5 BARACARB 25 BARACARB 50 BARACOR 700 BARASCAV D X-CIDE 207 0.955 bbl 11 ppb 0.1 ppb 1.0 – 1.5 ppb 5 ppb 4 ppb 4 ppb 2 ppb 1.0 ppb 0.5 ppb 0.015 ppb 15.11 TIH with 8-1/2” directional assembly to bottom 15.12 Displace wellbore to 8.9 ppg Baradrill-N drilling fluid Page 31 Milne Point Unit S-44 SB Injector Drilling Procedure 15.13 Begin drilling 8-1/2” hole section, on-bottom staging technique: x Tag bottom and begin drilling with 100 - 120 RPMs at bit. Allow WOB to stabilize at 5-8K. x Slowly begin bringing up rpms, monitoring stick slip and BHA vibrations. x If BHA begins to show excessive vibrations / whirl / stick slip, it may be necessary to PU off bottom and restart on bottom staging technique. If stick slip continues, consider adding 0.5% lubes. 15.14 Drill 8-1/2” hole section to section TD per Geologist and Drilling Engineer. x Flow Rate: 350-550 GPM, target min. AV’s 200 FPM, 385 GPM x RPM: 120+ x Ensure shaker screens are set up to handle this flowrate. Ensure shakers are running slightly wet to maximize solids removal efficiency. Check for holes in screens on every connection. x Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low x Take MWD surveys every stand, can be taken more frequently if deemed necessary, ex: concretion deflection x Monitor Torque and Drag with pumps on every 5 stands x Monitor ECD, pump pressure & hookload trends for hole cleaning indication x Surveys can be taken more frequently if deemed necessary. x Good drilling and tripping practices are vital for avoidance of differential sticking. Make every effort to keep the drill string moving whenever possible and avoid stopping with the BHA across the sand for any extended period of time. x Use ADR to stay in section. x Limit maximum instantaneous ROP to < 250 FPH. The sands will drill faster than this, but when concretions are hit when drilling this fast, cutter damage can occur. x Schrader Bluff Nb Concretions: 4-6% of lateral x A/C, wells with < 1.0 clearance factor: x S-16 has a clearance factor of 0.545. S-16 is a Schrader O-sands water injector that is shut-in and scheduled to be P&A’d. 15.15 Reference:Halliburton has a procedure for Schrader OH sidetracks based on lessons learned and best practices. Ensure the DD is referencing their procedure. x Patience is key! Getting kicked off too quickly might have been the cause of failed liner runs on past wells. x If a known fault is coming up, put a slight “kick-off ramp” in wellbore ahead of the fault so we have a nice place to low side. x Attempt to lowside in a fast drilling interval where the wellbore is headed up.NOTE: In Nb sand wells, it helps to pick a siltier section to help mitigate junction collapse. x Orient TF to low side and dig a trough with high flowrates for the first 30 feet, working string back and forth. Trough for approximately 30 minutes. x Time drill at 4 to 6 feet per hour with high flow rates. Gradually increase ROP as the openhole sidetrack is achieved. 15.16 At TD, CBU at least 4 times at 200 FPM AV (385+ GPM) and rotation (120+ RPM). Pump tandem sweeps if needed Page 32 Milne Point Unit S-44 SB Injector Drilling Procedure x Monitor BU for increase in cuttings, cuttings in laterals come back in waves and not a consistent stream, circulate more if necessary x Ensure mud has necessary lube % for running liner x If seepage losses are seen while drilling, consider reducing MW at TD to 9.0 ppg minimum 15.17 Mix and pump 40 bbl 10 ppb SAPP pill. Line up to a closed loop system and circulate three SAP pills with 50 bbl in between. Displace out SAP pills. Monitor shakers for returns of mud filter cake and calcium carbonate. Circulate the well clean. Losses during the cleanup of the wellbore are a good indication that the mud filter cake is being removed, including an increase in the loss rate. 15.18 Displace 1.5 OH + Liner volume with viscosified brine. x Proposed brine blend (same as used on M-16, aiming for an 8 on the 6 rpm reading) - KCl: 7.1bbp for 2% NaCl: 60.9 ppg for 9.4 ppg Lotorq: 1.5% Lube 776: 1.5% Soda Ash: as needed for 9.5 pH Busan 1060: 0.42ppb Flo-Vis Plus: 1.25 ppb x Monitor well for loss rate and contact Drilling Engineer and/or Ops Engineer if further discussion needed prior to BROOH. x Record SO, PU weights and rotating torque to compare to pre-brine values in report. 15.19 BROOH with the drilling assembly to the 9-5/8” casing shoe x Circulate at full drill rate (less if losses are seen, 350 GPM). x Rotate at maximum rpm that can be sustained. x Pulling speed 5 – 10 min/stand (slip to slip time, not including connections), adjust as dictated by hole conditions x If backreaming operations are commenced, continue backreaming to the shoe 15.20 If abnormal pressure has been observed in the lateral, utilize MPD to close on connections while BROOH. 15.21 CBU minimum two times at 9-5/8” shoe and clean casing with high vis sweeps. 15.22 Monitor well for flow / pressure build up with MPD. Increase fluid weight if necessary Page 33 Milne Point Unit S-44 SB Injector Drilling Procedure x Wellbore breathing has been seen on past MPU SB wells. Perform extended flow checks to determine if well is breathing, treat all flow as an influx until proven otherwise 15.23 POOH laying down DP. Only rack back the length needed to run the liner. 15.24 Continue to POOH and LD BHA. 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 34 Milne Point Unit S-44 SB Injector Drilling Procedure 16.0 Run 4-1/2” Injection Liner (Lower Completion) 16.1. Confirm VBR’s have been tested on 3-1/2” and 5” test joints to 250/3,000 psi. 16.2.Well control preparedness: In the event of an influx of formation fluids while running the 4- 1/2” production screens, the following well control response procedure will be followed: x 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” screen. x Slack off and position the 5” DP across the BOP, shut in ram or annular on 5” DP. Close TIW valve. x Proceed with well kill operations. 16.3. RU 4-1/2” liner running equipment. x Ensure 4-1/2” Hydril 625 x DS-50 crossover is on rig floor and M/U to FOSV. x Ensure the liner has been drifted on the deck prior to running. x Be sure to count the total # of joints on the deck before running. x Keep hole covered while RU casing tools. x Record OD’s, ID’s, lengths and SN’s of all components with vendor & model info. 16.4. Run 4-1/2” screen injection liner – Reference screen handling and running procedure. x Use Best O Life 2000 AG thread compound. Dope pin end only with paint brush. Wipe off excess. Thread compound will plug the screens. x Utilize a collar clamp until weight is sufficient to keep slips set properly. x Run packoff and float shoe on bottom. x 4-1/2” Screens should auto–fill, top off with completion brine if needed x Swell packers will not be required on this completion unless the well is drilled out of zone x If needed, install swell packers as per the lower completion tally. x Remove protective packaging on swell packers just prior to picking up x Do not place tongs or slips on the packer element 4-1/2”, 13.5#, L-80, Hydril 625 MU Torques Casing OD Minimum Optimum Maximum Operating Torque Yield Torque 4-1/2”8,000 ft-lbs 9,600 ft-lbs 12,800 ft-lbs 15,000 ft-lbs Page 35 Milne Point Unit S-44 SB Injector Drilling Procedure 16.6. Ensure that the liner top packer is set ~150’ MD above the 9-5/8” shoe. x AOGCC regulations require a minimum 100’ overlap between the inner and outer strings as per 20 AAC 25.030(d)(6). Ensure hanger/packer will not be set in a 9-5/8” connection. 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. Page 36 Milne Point Unit S-44 SB Injector Drilling Procedure 16.8. MU Baker SLZXP liner hanger/packer to 4-1/2” liner. 16.9. Note: PU, SO, ROT and torque of liner. Run liner in the hole one stand and pump through liner hanger to ensure a clear flow path exists. 16.10. RIH with liner no faster than 30 FPM – 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. Slow in and out of slips. Ensure accurate slack off data is gathered during RIH. Record shoe depth + SO depth every stand. Record torque value if it becomes necessary to rotate the string to bottom. 16.12. Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10, & 20 RPM. 16.13. If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensure shoe enters correct hole. 16.14. TIH deeper than planned setting depth. Last motion of the liner should be up to ensure it is set in tension. 16.15. Rig up to pump down the work string with the rig pumps. 16.16. Break circulation. Begin circulating at ~1 BPM and monitor pump pressures. Do not exceed 1,600 psi while circulating.Pusher tool is set at 2,100 psi with 5% shear screws but it should be discussed before exceeding 1,600 psi. Note all losses. Confirm all pressures with Baker. 16.17. Prior to setting the hanger and packer, double check all pipe tallies and record amount of drill pipe left on location. Ensure all numbers coincide with proper setting depth of liner hanger. 16.18. Shut down pumps. Drop setting ball (ball seat now located in HRDE setting tool and not at the WIV) down the workstring and pump slowly (1-2 BPM). Slow pump before the ball seats. Do not allow ball to slam into ball seat. 16.19. Continue pressuring up to 2,700 psi to set the SLZXP liner hanger/packer. Hold for 5 minutes. Slack off 20K lbs on the ZXP to ensure the HRDE setting tool is in compression for release from the SLZXP liner hanger/packer. Continue pressuring up 4,500 psi to neutralize and release running tools. 16.20. Bleed DP pressure to 0 psi. Pick up to expose rotating dog sub and set down 50K without pulling sleeve packoff. Contingency (if suspected not released from running tool) - Pick back up without pulling sleeve packoff, begin rotating at 10-20 RPM and set down 50K again. 16.21. PU to neutral weight, close BOP and test annulus to 1,500 psi for 10 minutes charted. Page 37 Milne Point Unit S-44 SB Injector Drilling Procedure 16.22. Bleed off pressure and open BOPE. Pickup to verify that the HRD setting tool has released. If packer did not test, rotating dog sub can be used to set packer. If running tool cannot be hydraulically released, apply LH torque to mechanically release the setting tool. 16.23. POOH laying down DP/HWDP. LD and inspect the liner running tools. Once running tools are LD, swap to the Completion AFE. Page 38 Milne Point Unit S-44 SB Injector Drilling Procedure 17.0 Run 3-1/2” Tubing (Upper Completion) 17.1 Notify the AOGCC at least 24 hours in advance of the IA pressure test after running the completion as per 20 AAC 25.412 (e). Record pressure test on 10-426 form and email to abhijeet.tambe@hilcorp.com for submission to AOGCC. 17.2 MU injection assembly and RIH to setting depth. TIH no faster than 90 FPM. x Ensure wear bushing is pulled. x Ensure 3-1/2” EUE 8rd x NC-50 crossover is on rig floor and MU to FOSV. x Ensure all tubing has been drifted in the pipe shed prior to running. x Be sure to count the total # of joints in the pipe shed before running. x Keep hole covered while RU casing tools. x Record OD’s, ID’s, lengths and SN’s of all components with vendor & model info. x Monitor displacement from wellbore while RIH. 3-1/2” Upper Completion Running Order: x 7.30” Baker Ported Bullet Nose seal (stung into the tie back receptacle, crossover to 3-1/2”, 9.3#, EUE 8rd) x 3 joints (minimum, more as needed), 3-1/2”, 9.3#, EUE 8rd tubing x 3-1/2” “XN” nipple at TBD (less than 70° hole angle) x 1 joints, 3-1/2”, 9.3#, EUE 8rd tubing x 3-1/2” Baker gauge mandrel o Cross collar clamps: Every joint for first 10 joints, every other joint beyond this to surface x XX Joints, 3-1/2”, 9.3#, EUE 8rd tubing x Space out pup(s), 3-1/2”, 9.3#, EUE 8rd tubing x 1 joint, 3-1/2”, 9.3#, EUE 8rd tubing x Tubing hanger with 3-1/2” EUE 8rd pin down 17.3 Locate and no-go out the seal assembly. Close annular and test to 500 psi to confirm seals engaged. 17.4 Bleed pressure and open annular. Space out the completion (±2’ above No-Go). Place all space out pups below the first full joint of the completion. Page 39 Milne Point Unit S-44 SB Injector Drilling Procedure 17.5 MU the tubing hanger and landing joint. 17.6 RIH. Close annular and test 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 corrosion inhibited brine. 17.8 Freeze protect the IA to ~2,000’ TVD (base on actual well deviation) with diesel. 17.9 Land hanger and RILDS. 17.10 PT the IA to 2,500 psi for 30 minutes charted. i. Note this test must be witnessed by the AOGCC representative. 17.11 Set BPV, ensure new body seals are installed each time. 17.12 ND BOPE and install the plug off tool into the BPV. 17.13 NU the tubing head adapter and NU the 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 ~2,000’ TVD (base on actual well deviation). 17.17 Install all tree gauges. Secure the tree and cellar. Release the rig. 17.18 RDMO the Innovation Rig. 17.19 Turn the well over to operations via handover form. Page 40 Milne Point Unit S-44 SB Injector Drilling Procedure 18.0 Innovation Rig Diverter Schematic Page 41 Milne Point Unit S-44 SB Injector Drilling Procedure 19.0 Innovation Rig BOP Schematic Page 42 Milne Point Unit S-44 SB Injector Drilling Procedure 20.0 Wellhead Schematic Page 43 Milne Point Unit S-44 SB Injector Drilling Procedure 21.0 Days Vs Depth Page 44 Milne Point Unit S-44 SB Injector Drilling Procedure 22.0 Formation Tops & Information Page 45 Milne Point Unit S-44 SB Injector Drilling Procedure Page 46 Milne Point Unit S-44 SB Injector Drilling Procedure 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 been seen on S-Pad. 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. Well Specific A/C: x There are no wells with a clearance factor of <1.0 Wellbore stability (Permafrost, running sands and gravel, conductor broaching): Washouts in the permafrost can be severe if the string is left circulating across it for extended periods of time. Keep mud as cool as possible by taking on cold water and diluting often. High TOH and RIH speeds can aggravate fragile shale/coal formations due to the pressure variations between surge and swab. Bring the pumps on slowly after connections. Monitor conductor for any signs of broaching. Maintain mud parameters and increase MW to combat running sands and gravel formations. Page 47 Milne Point Unit S-44 SB Injector Drilling Procedure H2S: Treat every hole section as though it has the potential for H2S. MPU S-pad is not known for H2S. Three samples containing H2S have been captured. S-08 had 50 ppm measured in 2012. S-12 had 28.9 ppm measured in 2012. S-39 had 2 ppm measured in 2014. 1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Page 48 Milne Point Unit S-44 SB Injector Drilling Procedure 8-1/2” Hole Section: Hole Cleaning: Maintain rheology of mud system. Sweep hole with low-vis water sweeps. Ensure shakers are set up with appropriate screens to maximize solids removal efficiency. Run centrifuge continuously. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Maintain circulation rate of > 300 gpm Lost Circulation: Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Faulting: There are no planned fault crossings. Of an unmapped fault is crossed, we’ll need to either drill up or down to get a look at the LWD log and determine the throw and then replan the wellbore. H2S: Treat every hole section as though it has the potential for H2S. MPU S-pad is not known for H2S. Three samples containing H2S have been captured. S-08 had 50 ppm measured in 2012. S-12 had 28.9 ppm measured in 2012. S-39 had 2 ppm measured in 2014. 1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Abnormal Pressures and Temperatures: Abnormal pressure can be seen on S-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. x S-16 has a clearance factor of 0.545. S-16 is a Schrader O-sands water injector that is shut-in and scheduled to be P&A’d. Page 49 Milne Point Unit S-44 SB Injector Drilling Procedure 24.0 Innovation Rig Layout Page 50 Milne Point Unit S-44 SB Injector Drilling Procedure 25.0 FIT Procedure Formation Integrity Test (FIT) and Leak-Off Test (LOT) Procedures Procedure for FIT: 1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe). 2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe. 3. Close the blowout preventer (ram or annular). 4. Pump down the drill stem at 1/4 to 1/2 bpm. 5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe. 6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes. Record time vs. pressure in 1-minute intervals. 7. Bleed the pressure off and record the fluid volume recovered. The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick tolerance in case well control measures are required. Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid; at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure monitored as with an FIT. Ensure that casing test and subsequent FIT tests are recorded on the same chart. Document incremental volume pumped and returned during test. Page 51 Milne Point Unit S-44 SB Injector Drilling Procedure 26.0 Innovation Rig Choke Manifold Schematic Page 52 Milne Point Unit S-44 SB Injector Drilling Procedure 27.0 Casing Design Page 53 Milne Point Unit S-44 SB Injector Drilling Procedure 28.0 8-1/2” Hole Section MASP Page 54 Milne Point Unit S-44 SB Injector Drilling Procedure 29.0 Spider Plot (NAD 27) (Governmental Sections) Page 55 Milne Point Unit S-44 SB Injector Drilling Procedure 30.0 Surface Plat (As Built) (NAD 27) 6WDQGDUG3URSRVDO5HSRUW 0D\ 3ODQ0386ZS +LOFRUS$ODVND//& 0LOQH3RLQW 03W63DG 3ODQ0386 0386 06001200180024003000360042004800True Vertical Depth (1200 usft/in)-2400 -1800 -1200 -600 0 600 1200 1800 2400 3000 3600 4200 4800 5400 6000 6600 7200 7800 8400 9000 9600Vertical Section at 344.18° (1200 usft/in)MPU S-Talarus wp05 HeelMPU S-Talarus wp04 mid1MPU S-Talarus wp05 toe9 5/8" x 12 1/4"7" x 8 1/2"5001000150020002500300035004000450050005500 6000 6500 7000 7500 8000 8500 9000 9500 10000 10500 11000 115 00 1 200012500130001350013577MPU S-44 wp06Start Dir 4º/100' : 450' MD, 450'TVDEnd Dir : 1325' MD, 1271.59' TVDStart Dir 4º/100' : 2400' MD, 2152.18'TVDStart Dir 5º/100' : 2750' MD, 2460.44'TVDEnd Dir : 2842.81' MD, 2548.27' TVDStart Dir 5º/100' : 2913.37' MD, 2615.89'TVDEnd Dir : 4944.87' MD, 4084.03' TVDStart Dir 3º/100' : 5094.87' MD, 4097.1'TVDEnd Dir : 5272.22' MD, 4104.35' TVDStart Dir 3º/100' : 8280.82' MD, 4087.78'TVDEnd Dir : 8519.48' MD, 4086.47' TVDTotal Depth : 13576.59' MD, 4080.5' TVDBPRFUG3 CoalUG2 CoalLA3LA1UG MAUG MBUG MCUG MDUG MESB NASB_NB (target)Hilcorp Alaska, LLCCalculation Method:Minimum CurvatureError System:ISCWSAScan Method: Closest Approach 3DError Surface: Ellipsoid SeparationWarning Method: Error RatioWELL DETAILS: Plan: MPU S-4437.00+N/-S +E/-WNorthingEastingLatittudeLongitude0.000.005999865.320565406.450 70° 24' 36.302 N 149° 28' 2.711 WSURVEY PROGRAMDate: 2021-02-04T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool26.50 600.00 MPU S-44 wp06 (MPU S-44) 3_Gyro-GC_Csg600.00 5094.00 MPU S-44 wp06 (MPU S-44) 3_MWD+IFR2+MS+Sag5094.00 13576.59 MPU S-44 wp06 (MPU S-44) 3_MWD+IFR2+MS+SagFORMATION TOP DETAILSTVDPath TVDssPath MDPath Formation1865.48 1801.98 2050.01 BPRF2968.50 2905.00 3270.67 UG3 Coal3241.70 3178.20 3547.43 UG2 Coal3600.61 3537.113945.81 LA33680.67 3617.17 4046.88 LA13846.44 3782.94 4286.38 UG MA3891.69 3828.19 4363.40 UG MB3916.73 3853.23 4409.48 UG MC3931.07 3867.57 4437.27 UG MD4037.35 3973.85 4701.56 UG ME4079.94 4016.44 4905.64 SB NA4101.94 4038.44 5165.20 SB_NB (target)REFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU S-44, True NorthVertical (TVD) Reference:MPU S-44 As-built @ 63.50usftMeasured Depth Reference:MPU S-44 As-built @ 63.50usftCalculation Method:Minimum CurvatureProject:Milne PointSite:M Pt S PadWell:Plan: MPU S-44Wellbore:MPU S-44Design:MPU S-44 wp06CASING DETAILSTVD TVDSS MD SizeName4097.10 4033.60 5094.87 9-5/8 9 5/8" x 12 1/4"4080.50 4017.00 13576.59 7 7" x 8 1/2"SECTION DETAILSSec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation1 26.50 0.00 0.00 26.50 0.00 0.00 0.00 0.00 0.002 450.00 0.00 0.00 450.00 0.00 0.00 0.00 0.00 0.00 Start Dir 4º/100' : 450' MD, 450'TVD3 1325.00 35.00 170.50 1271.59 -255.49 42.75 4.00 170.50 -257.47 End Dir : 1325' MD, 1271.59' TVD4 2400.00 35.00 170.50 2152.18 -863.63 144.52 0.00 0.00 -870.33 Start Dir 4º/100' : 2400' MD, 2152.18'TVD5 2750.00 21.00 170.50 2460.44 -1025.29 171.57 4.00 180.00 -1033.24 Start Dir 5º/100' : 2750' MD, 2460.44'TVD6 2842.81 16.62 165.72 2548.27 -1054.57 177.60 5.00 -162.88 -1063.05 End Dir : 2842.81' MD, 2548.27' TVD7 2913.37 16.62 165.72 2615.89 -1074.13 182.57 0.00 0.00 -1083.22 Start Dir 5º/100' : 2913.37' MD, 2615.89'TVD8 4944.87 85.00 341.55 4084.03 -136.24 -161.14 5.00 175.76 -87.17 End Dir : 4944.87' MD, 4084.03' TVD9 5094.87 85.00 341.55 4097.10 5.51 -208.43 0.00 0.00 62.10 MPU S-Talarus wp05 Heel Start Dir 3º/100' : 5094.87' MD, 4097.1'TVD10 5272.22 90.32 341.31 4104.35 173.43 -264.84 3.00 -2.55 239.04 End Dir : 5272.22' MD, 4104.35' TVD11 8280.82 90.32 341.31 4087.78 3023.39 -1228.75 0.00 0.00 3243.82 Start Dir 3º/100' : 8280.82' MD, 4087.78'TVD12 8511.06 90.32 348.22 4086.50 3245.40 -1289.20 3.00 89.94 3473.91 MPU S-Talarus wp04 mid113 8519.48 90.07 348.21 4086.47 3253.64 -1290.92 3.00 -178.35 3482.30 End Dir : 8519.48' MD, 4086.47' TVD14 13576.59 90.07348.21 4080.50 8204.12 -2323.92 0.00 0.00 8526.91 MPU S-Talarus wp05 toe Total Depth : 13576.59' MD, 4080.5' TVD -1000 -500 0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000 6500 7000 7500 8000 South(-)/North(+) (1000 usft/in)-4500 -4000 -3500 -3000 -2500 -2000 -1500 -1000 -500 0 500 1000 1500 2000 2500 West(-)/East(+) (1000 usft/in) MPU S-Talarus wp05 toe MPU S-Talarus wp04 mid1 MPU S-Talarus wp05 Heel 9 5/8" x 12 1/4" 7" x 8 1/2" 1 0 0 0 2 7 5 0 3 5 0 0 3 7 5 0 4 0 0 0 4 0 8 1 MPU S-44 wp06 Start Dir 4º/100' : 450' MD, 450'TVD End Dir : 1325' MD, 1271.59' TVD Start Dir 4º/100' : 2400' MD, 2152.18'TVD Start Dir 5º/100' : 2750' MD, 2460.44'TVD End Dir : 2842.81' MD, 2548.27' TVD Start Dir 5º/100' : 2913.37' MD, 2615.89'TVD End Dir : 4944.87' MD, 4084.03' TVD Start Dir 3º/100' : 5094.87' MD, 4097.1'TVD End Dir : 5272.22' MD, 4104.35' TVD Start Dir 3º/100' : 8280.82' MD, 4087.78'TVD End Dir : 8519.48' MD, 4086.47' TVD Total Depth : 13576.59' MD, 4080.5' TVD CASING DETAILS TVD TVDSS MD Size Name 4097.10 4033.60 5094.87 9-5/8 9 5/8" x 12 1/4" 4080.50 4017.00 13576.59 7 7" x 8 1/2" Project: Milne Point Site: M Pt S Pad Well: Plan: MPU S-44 Wellbore: MPU S-44 Plan: MPU S-44 wp06 WELL DETAILS: Plan: MPU S-44 37.00 +N/-S +E/-W Northing Easting Latittude Longitude 0.00 0.00 5999865.320 565406.450 70° 24' 36.302 N 149° 28' 2.711 W REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Plan: MPU S-44, True North Vertical (TVD) Reference: MPU S-44 As-built @ 63.50usft Measured Depth Reference:MPU S-44 As-built @ 63.50usft Calculation Method:Minimum Curvature 3URMHFW &RPSDQ\ 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eparation Factor0 275 550 825 1100 1375 1650 1925 2200 2475 2750 3025 3300 3575 3850 4125 4400 4675 4950 5225Measured Depth (550 usft/in)No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.WELL DETAILS:Plan: MPU S-44 NAD 1927 (NADCON CONUS)Alaska Zone 0437.00+N/-S +E/-W Northing Easting Latittude Longitude0.000.005999865.320565406.45070° 24' 36.302 N149° 28' 2.711 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU S-44, True NorthVertical (TVD) Reference: MPU S-44 As-built @ 63.50usftMeasured Depth Reference:MPU S-44 As-built @ 63.50usftCalculation Method: Minimum CurvatureSURVEY PROGRAMDate: 2021-02-04T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool26.50 600.00 MPU S-44 wp06 (MPU S-44) 3_Gyro-GC_Csg600.00 5094.00 MPU S-44 wp06 (MPU S-44) 3_MWD+IFR2+MS+Sag5094.00 13576.59 MPU S-44 wp06 (MPU S-44) 3_MWD+IFR2+MS+Sag0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)0275 550 825 1100 1375 1650 1925 2200 2475 2750 3025 3300 3575 3850 4125 4400 4675 4950 5225Measured Depth (550 usft/in)MPS-39MPS-41MPS-43MPU S-203MPU S-56PB1MPU S-57MPU S-201 wp07MPU S-202 wp10MPU S-45 wp07MPU S-46 wp03MPU S-47 wp03MPU S-48 wp03GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference26.50 To 13576.59Project: Milne PointSite: M Pt S PadWell: Plan: MPU S-44Wellbore: MPU S-44Plan: MPU S-44 wp06Ladder / S.F. 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eparation Factor4950 5400 5850 6300 6750 7200 7650 8100 8550 9000 9450 9900 10350 10800 11250 11700 12150 12600 13050 13500Measured Depth (900 usft/in)No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.WELL DETAILS:Plan: MPU S-44 NAD 1927 (NADCON CONUS)Alaska Zone 0437.00+N/-S +E/-W Northing Easting Latittude Longitude0.000.005999865.320565406.450 70° 24' 36.302 N149° 28' 2.711 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU S-44, True NorthVertical (TVD) Reference: MPU S-44 As-built @ 63.50usftMeasured Depth Reference:MPU S-44 As-built @ 63.50usftCalculation Method: Minimum CurvatureSURVEY PROGRAMDate: 2021-02-04T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool26.50 600.00 MPU S-44 wp06 (MPU S-44) 3_Gyro-GC_Csg600.00 5094.00 MPU S-44 wp06 (MPU S-44) 3_MWD+IFR2+MS+Sag5094.00 13576.59 MPU S-44 wp06 (MPU S-44)3_MWD+IFR2+MS+Sag0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)4950 5400 5850 6300 6750 7200 7650 8100 8550 9000 9450 9900 10350 10800 11250 11700 12150 12600 13050 13500Measured Depth (900 usft/in)MPH-08AMPH-08APB1MPH-08BMPH-08BMPH-08BL1MPH-08BL1MPH-08BPB1MPS-16GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference26.50 To 13576.59Project: Milne PointSite: M Pt S PadWell: Plan: MPU S-44Wellbore: MPU S-44Plan: MPU S-44 wp06CASING DETAILSTVD TVDSS MD Size Name4097.10 4033.60 5094.87 9-5/8 9 5/8" x 12 1/4"4080.50 4017.00 13576.59 7 7" x 8 1/2"Ladder / S.F. Plots2 of 2 _____________________________________________________________________________________ Revised By: JNL 5/27/21 PROPOSED SCHEMATIC Milne Point Unit Well: MPU S-44 PTD: TBD API: TBD 4-1/2” SCREEN Liner Jts Top (MD) Btm (MD) Top (MD) Btm (TVD) TD =13,577’(MD) / TD =4,081’(TVD) 20” Orig. KB Elev.:63.5’ / GL Elev.: 37.0’ 3-1/2” 2 9-5/8” 1 3/4 6 See Screen Liner Detail PBTD =13,577’ (MD) / PBTD =4,081’(TVD) 9-5/8” ‘ES’ Cementer @ ~2,500’ 4-1/2” 5 CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF 20" Conductor 129.5 / X-52 / Weld N/A Surface 110’ N/A 9-5/8" Surface 47 / L-80 / TXP 8.525” Surface 2,500’ 0.0732 9-5/8" Surface 40 / L-80 / TXP 8.679” 2,500’ 5,095’ 0.0758 4-1/2” Liner 13.5 / L-80 / Hyd 625 3.795” 4,945’ 13,577’ 0.0149 TUBING DETAIL 3-1/2" Tubing 9.3 / L-80 / EUE 8RD 2.867” Surf 4,945’ 0.0870 JEWELRY DETAIL No Top MD Item ID Upper Completion 1 TBD Zenith G6 Gauge 400 Bar 150C, 2 Press 2 Temp 2.992” 2 TBD “Brace” XN Nipple, 2.813” Packing Bore, 2.75” No-Go 2.750” 3 TBD 8.25” No Go Locater Sub (2.13’ off No-go) 2.980” 4 TBD Bullet Seals – TXP Top Box x Mule Shoe 6.180” Lower Completion 5 TBD 9-5/8” SLZXP Liner Top Packer 6.190” 6TBDShoe OPEN HOLE / CEMENT DETAIL Driven 20” Conductor 12-1/4"Stg 1 –Lead 649 ft3 / Tail 458 ft3 Stg 2 –Lead 1935 ft3 / Tail 313 ft3 8-1/2” Cementless Screen Liner WELL INCLINATION DETAIL KOP @ 500’ MD Max Hole Angle = 90° TREE & WELLHEAD Tree Cameron 3 1/8" 5M w/ 4-1/16” 5M Cameron Wing Wellhead Cameron 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs GENERAL WELL INFO API#: TBD Completed by Innovation: TBD 1 Guhl, Meredith D (CED) From:Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Sent:Tuesday, June 8, 2021 1:17 PM To:Boyer, David L (CED) Subject:RE: [EXTERNAL] RE: MPU S-44 10-401 Permit to Drill David, Good question… From my understanding it will not pre‐produce. If something somehow changes I’ll do my best to let you know but both S‐44 and S‐46 should be injectors only from completion. Thanks, Joe Lastufka Sr. Drilling Technologist Hilcorp North Slope, LLC Office: (907)777-8400, Cell:(907)227-8496 From: Boyer, David L (CED) <david.boyer2@alaska.gov> Sent: Tuesday, June 8, 2021 12:10 PM To: Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Subject: [EXTERNAL] RE: MPU S‐44 10‐401 Permit to Drill Joe, Since MPU S‐44 is an injector, is Hilcorp planning to pre‐produce the well? If yes, for how long? Thanks, Dave B. AOGCC From: Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Sent: Thursday, June 3, 2021 9:24 AM To: AOGCC Permitting (CED sponsored) <aogcc.permitting@alaska.gov> Cc: Davies, Stephen F (CED) <steve.davies@alaska.gov>; Boyer, David L (CED) <david.boyer2@alaska.gov> Subject: MPU S‐44 10‐401 Permit to Drill Hello, Please see attached electronic distribution of MPU S‐44 Permit to Drill. Please let me know if you have any questions. Thanks! Thanks, Joe Lastufka Sr. Drilling Technologist Hilcorp North Slope, LLC Office: (907)777-8400, Cell:(907)227-8496 2 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. Revised 2/2015 TRANSMITTAL LETTER CHECKLIST WELL NAME: ______________________________________ PTD: _____________________________________________ ___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional FIELD: ____________________________ POOL: ______________________________________ Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI LATERAL (If last two digits in API number are between 60-69) The permit is for a new wellbore segment of existing well Permit No. _____________, API No. 50-_______________________. Production should continue to be reported as a function of the original API number stated above. Pilot Hole In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well name (_______________________PH) and API number (50-_____________________) from records, data and logs acquired for well (name on permit). Spacing Exception The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce/inject is contingent upon issuance of a conservation order approving a spacing exception. (_____________________________) as Operator assumes the liability of any protest to the spacing exception that may occur. Dry Ditch Sample All dry ditch sample sets submitted to the AOGCC must be in no greater than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. Non- Conventional Well Please note the following special condition of this permit: Production or production testing of coal bed methane is not allowed for well ( ) until after ( ) has designed and implemented a water well testing program to provide baseline data on water quality and quantity. (________________________) must contact the AOGCC to obtain advance approval of such water well testing program. Well Logging Requirements Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by (_______________________________) in the attached application, the following well logs are also required for this well: Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. Milne Point Unit X X 221-044 Schrader Bluff Oil X MPU S-44 WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name:MILNE PT UNIT S-44Initial Class/TypeSER / PENDGeoArea890Unit11328On/Off ShoreOnProgramSERField & PoolWell bore segAnnular DisposalPTD#:2210440MILNE POINT, SCHRADER BLFF OIL - 525140NA1 Permit fee attachedYes2 Lease number appropriateYes3 Unique well name and numberNA4 Well located in a defined poolYes5 Well located proper distance from drilling unit boundaryYes6 Well located proper distance from other wellsYes7 Sufficient acreage available in drilling unitYes8 If deviated, is wellbore plat includedYes9 Operator only affected partyYes10 Operator has appropriate bond in forceYes11 Permit can be issued without conservation orderYes12 Permit can be issued without administrative approvalYes13 Can permit be approved before 15-day waitYes AIO No. 10-B14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (For servYes15 All wells within 1/4 mile area of review identified (For service well only)Yes16 Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes 20" 129.5# conductor driven to 80'18 Conductor string providedYes Fully cemented 9-5/8" surface casing set in the SB sand.19 Surface casing protects all known USDWsYes Fully cemented 9-5/8" surface casing set in the SB sand.20 CMT vol adequate to circulate on conductor & surf csgYes Fully cemented 9-5/8" surface casing set in the SB sand.21 CMT vol adequate to tie-in long string to surf csgYes Fully cemented 9-5/8" surface casing set in the SB sand.22 CMT will cover all known productive horizonsYes 47# 9-5/8" L-80 run across the permafrost23 Casing designs adequate for C, T, B & permafrostYes Innovation has adequate tankage and good truck support.24 Adequate tankage or reserve pitNA This is a new grassroots well.25 If a re-drill, has a 10-403 for abandonment been approvedYes One close approach in the reservoir to another SB injector.26 Adequate wellbore separation proposedYes 16" diverter27 If diverter required, does it meet regulationsYes All fluids overbalanced to pore pressure.28 Drilling fluid program schematic & equip list adequateYes 1 annular, 3 ram stack, 1 flow cross29 BOPEs, do they meet regulationYes 5000 psi stack30 BOPE press rating appropriate; test to (put psig in comments)Yes31 Choke manifold complies w/API RP-53 (May 84)Yes32 Work will occur without operation shutdownNo H2S not likely on MPU S pad. H2S monitoring equipment will be on the rig.33 Is presence of H2S gas probableYes34 Mechanical condition of wells within AOR verified (For service well only)Yes H2S not anticipated from drilling of offset wells; however, rig will have H2S sensors and alarms.35 Permit can be issued w/o hydrogen sulfide measuresYes36 Data presented on potential overpressure zonesNA37 Seismic analysis of shallow gas zonesNA38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprDLBDate6/3/2021ApprMGRDate6/4/2021ApprDLBDate6/3/2021AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDate-03JLC 6/8/2021