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Home My WebLink About224-107From:Rixse, Melvin G (OGC) To:Taylor Wellman Cc:Lau, Jack J (OGC); Regg, James B (OGC) Subject:20250110 1523 APPROVAL for IA Water Injection for ESP LIft MPU J-40 (PTD 224-107) / MPU J-42 (PTD224- 072) / MPU J-44 (PTD) Water Assist Down the IA Piping Date:Friday, January 10, 2025 3:26:28 PM Attachments:J-40 J-42 J-44 Proposed Water Assist IA Piping.pptx Taylor, Hilcorp is approved to proceed with IA water injection on MPU packerless ESP wells as per piping diagram attached and with performance testing on IA safety valve systems under 20 AAC 265. IA XV valve to be in communication to the SSV system as described in red text below. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-297-8474 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). From: Taylor Wellman <twellman@hilcorp.com> Sent: Friday, January 10, 2025 2:53 PM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Lau, Jack J (OGC) <jack.lau@alaska.gov>; Regg, James B (OGC) <jim.regg@alaska.gov> Subject: RE: [EXTERNAL] 2 Questions : MPU J-40 (PTD ) / MPU J-42 (PTD) / MPU J-44 (PTD) Water Assist Down the IA Piping Mel, Please see responses in red below. Thank you, Taylor Taylor Wellman Hilcorp Alaska, LLC: Wells Manager – Milne Point Office: (907) 777-8449 Cell: (907) 947-9533 CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. Email: twellman@hilcorp.com From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Sent: Friday, January 10, 2025 11:04 AM To: Taylor Wellman <twellman@hilcorp.com> Cc: Lau, Jack J (OGC) <jack.lau@alaska.gov>; jim.regg <jim.regg@alaska.gov> Subject: [EXTERNAL] 2 Questions : MPU J-40 (PTD ) / MPU J-42 (PTD) / MPU J-44 (PTD) Water Assist Down the IA Piping Taylor, Per 20 AAC 265 (c) (5): Well Safety Valve Systems (5) in a well's safety valve system a fusible plug or a functionally equivalent device must be installed near enough to the wellhead so that the well will be immediately shut-in if there is a fire; And 20 AAC 265 (h) Except for a well injecting water, safety valve system testing is required. Safety valve system testing may consist of a function-test, a performance-test, or both. A performance-test includes a function pressure-test of the system's valves and a function-test of the mechanical or electrical actuating device. A safety valve system component fails a performance-test when a test criterion in (9) - (12) of this subsection is not met on the first attempt. The safety valve system must be tested as follows: ……… Questions: 1. Is there a fusible plug or functionally equivalent device triggering XV (as required in subsection (5) above)? Yes. The XV is tied into the SSV. If the SSV trips, so does the XV to the powerfluid/IA. The SSV panel has the functionally equivalent portion if too high of heat is detected, the panel hydraulic dumps causing both SSV and XV to shut. 2. Because these wells water injection side are in communication to hydrocarbons, do you plan to ‘performance test’ the new installation? Yes. We plan to provide notification for witnessing of this at your inspectors discretion. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-297-8474 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). cc. Jim Regg, Jack Lau From: Taylor Wellman <twellman@hilcorp.com> Sent: Thursday, January 9, 2025 1:08 PM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Lau, Jack J (OGC) <jack.lau@alaska.gov>; Regg, James B (OGC) <jim.regg@alaska.gov> Subject: RE: [EXTERNAL] RE: MPU J-40 (PTD ) / MPU J-42 (PTD) / MPU J-44 (PTD) Water Assist Down the IA Piping Gentlemen, I’m sorry for the delay in this. I’ve been out for the past few weeks. Attached are the piping diagram and a cause and effects sheet. For the process safety chart/Hazard Analysis we evaluate the existing Hazan with the proposed incorporated sections to see if they cause any issues with protection layers for each affected node. The cause and effects sheets were generated from a review of the Hazan. All backside water assist wells has a shutdown system similar to what is in place for power fluid wells. For the backside water assist wells: Pressure Alarm High: Alarm is located upstream of the power fluid XV and downstream of the choke. Alarm set at 1,500 psi and triggers shutting in the power fluid XV. Pressure Alarm Low: Upstream of the power fluid XV and upstream of the power fluid choke the low pressure alarm and pressure switch low low is set at 500 psi which will also trigger shutting of the power fluid XV. Standard set points remain on the production tubing side. The backside water assist XV (referred to as PFV XV) will also shut on any alarm on the production side. If you would like any additional information or to talk through this please let me know. Thank you, Taylor CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. Taylor Wellman Hilcorp Alaska, LLC: Wells Manager – Milne Point Office: (907) 777-8449 Cell: (907) 947-9533 Email: twellman@hilcorp.com From: Taylor Wellman <twellman@hilcorp.com> Sent: Friday, December 13, 2024 1:26 PM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Lau, Jack J (OGC) <jack.lau@alaska.gov>; jim.regg <jim.regg@alaska.gov> Subject: RE: [EXTERNAL] RE: MPU J-40 (PTD ) / MPU J-42 (PTD) / MPU J-44 (PTD) Water Assist Down the IA Piping Mel and Jack, Please find the attached diagram showing the location of the valves and pressure alarms. We are conducting the Hazan for this setup and I will provide as soon as it is completed but I wanted to get you this diagram ahead of that. Thank you, Taylor Taylor Wellman Hilcorp Alaska, LLC: Wells Manager – Milne Point Office: (907) 777-8449 Cell: (907) 947-9533 Email: twellman@hilcorp.com From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Sent: Wednesday, December 4, 2024 4:33 PM To: Taylor Wellman <twellman@hilcorp.com> Cc: Lau, Jack J (OGC) <jack.lau@alaska.gov>; jim.regg <jim.regg@alaska.gov> Subject: [EXTERNAL] RE: MPU J-40 (PTD ) / MPU J-42 (PTD) / MPU J-44 (PTD) Water Assist Down the IA Piping Taylor, Please provide 1. A process safety chart 2. A piping diagram – See attached 3. Trip pressures– See attached 4. Notification for inspection once rigged up. – Will send in once ready Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-297-8474 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). cc. Jim Regg, Jack Lau From: Rixse, Melvin G (OGC) Sent: Tuesday, December 3, 2024 5:26 PM To: 'Taylor Wellman' <twellman@hilcorp.com> Cc: Lau, Jack J (OGC) <jack.lau@alaska.gov>; Regg, James B (OGC) <jim.regg@alaska.gov> Subject: RE: MPU J-40 (PTD ) / MPU J-42 (PTD) / MPU J-44 (PTD) Water Assist Down the IA Piping Taylor, This sounds reasonable, but I want to review with other AOGCC staff. I will get back to you before the end of the week. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-297-8474 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). cc. Jim Regg, Jack Lau From: Taylor Wellman <twellman@hilcorp.com> Sent: Tuesday, December 3, 2024 11:28 AM To: Regg, James B (OGC) <jim.regg@alaska.gov>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Subject: MPU J-40 (PTD ) / MPU J-42 (PTD) / MPU J-44 (PTD) Water Assist Down the IA Piping CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. Mr. Regg and Mr. Rixse, Issue: There are 3 wells at Milne Point J-Pad that are Schrader Bluff producers with ESP’s installed. These wells are showing issues with being able to consistently lift and the ESP runs extremely erratic. The theory is that these higher viscosity Schrader N-Sand wells aren’t allowing gas to fully break out and be separated as it goes through the ESP intake/gas separator. Diagnostics: Attempted to trickle warm fluids down the IA (~400 bwpd) to keep the ESP loaded under a fully manned operation. We would like to continue this operation and install permanent piping to do so. Proposed solution for safety system: Install piping from the powerfluid header to the IA of these ESP producers. Included in the piping would be a shutdown valve, high and low pressure pilots. The shutdown valve would also be tied to the SSV on the production tree and trip if the SSV tripped. The setup would be the same setup as the IA (powerfluid side of a reverse circulating jet pump). I believe that setup would meet the requirements in 20 AAC 25.265 and meet the intent as prescribed for wells operated under Jet Pump in CO 808 Rule 3. I am available to meet, talk or provide any additional information if you’d like. Thank you, Taylor Taylor Wellman Hilcorp Alaska, LLC: Wells Manager – Milne Point Office: (907) 777-8449 Cell: (907) 947-9533 Email: twellman@hilcorp.com The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. To Production HeaderWingChoke Master SSV (Actated) Swab Choke Check J-40/42/44 (ESP Producer) IA Csg ValveXV (actuated SD valve) PSLL (Low low pressure trip) Set Pt: 50% of header pressure PSHH (high high pressure trip) Set Pt: 1,500psi From Powerfluid Header Proposed New Installation Existing Installation 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. Received By: Date: Date: 11/20/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL: WELL: MPU J-40 PTD: 224-107 API: 50-029-23798-00-00 FINAL LWD FORMATION EVALUATION + GEOSTEERING (10/01/2024 to 10/14/2024) x ROP, AGR, ABG, DGR, EWR-M5, ADR, Horizontal Presentation (2” & 5” MD/TVD Color Logs) x Final Definitive Directional Survey x Final Geosteering and EOW Report/Plots SFTP Transfer – Main Folders: FINAL LWD Subfolders: FINAL Geosteering Subfolders: Please include current contact information if different from above. 224-107 T39791 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.11.20 15:53:45 -09'00' STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report for: Reviewed By: P.I. Suprv Comm ________MILNE PT UNIT J-40 JBR 12/06/2024 MISC. INSPECTIONS: FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK: ACCUMULATOR SYSTEM:MUD SYSTEM: P/F P/F P/FP/FP/F Visual Alarm QuantityQuantity Time/Pressure SizeQuantity Number of Failures:1 Tested with 3-1/2", 4-1/2", & 7" Test joints. We tested a 3-1/2" TIW & dart valves, also tested 4-1/2" TIW and dart valves. Upper IBOP failed on high and low attempts, greased and that actually made it worse. This was a brand new valve prior to drilling surface hole on this well. They changed it out and passed. N2 Precharge: 18 @ 937 psi. Test Results TEST DATA Rig Rep:J. Charlie, C. CvetkovskOperator:Hilcorp Alaska, LLC Operator Rep:M. Brouillet, I. Toomey Rig Owner/Rig No.:Doyon 14 PTD#:2241070 DATE:10/9/2024 Type Operation:DRILL Annular: 250/3000Type Test:INIT Valves: 250/3000 Rams: 250/3000 Test Pressures:Inspection No:bopJDH241010154410 Inspector Josh Hunt Inspector Insp Source Related Insp No: INSIDE REEL VALVES: Quantity P/F (Valid for Coil Rigs Only) Remarks: Test Time 15 MASP: 1325 Sundry No: Control System Response Time (sec) Time P/F Housekeeping:P PTD On Location P Standing Order Posted P Well Sign P Hazard Sec.P Test Fluid W Misc NA Upper Kelly 1 FP Lower Kelly 1 P Ball Type 2 P Inside BOP 2 P FSV Misc 0 NA 14 PNo. Valves 1 PManual Chokes 1 PHydraulic Chokes 0 NACH Misc Stripper 0 NA Annular Preventer 1 13-5/8"P #1 Rams 1 4-1/2"x7" VB P #2 Rams 1 Blinds P #3 Rams 1 2-7/8"x5" VB P #4 Rams 0 NA #5 Rams 0 NA #6 Rams 0 NA Choke Ln. Valves 2 3-1/8" 5K P HCR Valves 2 3-1/8" 5K P Kill Line Valves 2 3-1/8" 5K P Check Valve 0 NA BOP Misc 0 NA System Pressure P2900 Pressure After Closure P1700 200 PSI Attained P54 Full Pressure Attained P190 Blind Switch Covers:PAll Stations Bottle precharge P Nitgn Btls# &psi (avg)P6@1964 ACC Misc NA0 P PTrip Tank P PPit Level Indicators P PFlow Indicator P PMeth Gas Detector P PH2S Gas Detector 0 NAMS Misc Inside Reel Valves 0 NA Annular Preventer P14 #1 Rams P7 #2 Rams P7 #3 Rams P7 #4 Rams NA0 #5 Rams NA0 #6 Rams NA0 HCR Choke P1 HCR Kill P1 9 9 9 9 9999 9 9 FP Upper IBOP failed on high and low attempts, Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Monty M. Myers Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK, 99503 Re: Milne Point Field, Schrader Bluff Oil Pool, MPU J-40 Hilcorp Alaska, LLC Permit to Drill Number: 224-107 Surface Location: 2305' FSL, 3172' FEL, Sec 028, T13N, R10E, UM, AK Bottomhole Location: 350' FNL, 958' FEL, Sec 02, T12N, 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 all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. 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, Jessie L. Chmielowski Commissioner DATED this 27th day of August 2024. Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.08.27 17:32:01 -08'00' Drilling Manager 07/25/24 Monty M Myers By Grace Christianson at 9:34 am, Jul 25, 2024 A.Dewhurst 22AUG24 MGR29JULY2024 552,148' DSR-7/31/24 50-029-23798-00-00 * BOPE test to 3000 psi. Annular to 2500 psi. * Casing test and FIT digital data to AOGCC immediately upon completion of performing FIT. 6,014,704' 224-107 -see attached emails A.Dewhurst 22AUG24 *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.08.27 17:32:16 -08'00' 08/27/24 08/27/24 RBDMS JSB 082824 Milne Point Unit (MPU) J-40 Application for Permit to Drill Version 1 7/24/2024 Table of Contents 1.0 Well Summary .......................................................................................................................... 2 2.0 Management of Change Information ....................................................................................... 3 3.0 Tubular Program:..................................................................................................................... 4 4.0 Drill Pipe Information: ............................................................................................................. 4 5.0 Internal Reporting Requirements ............................................................................................ 5 6.0 Planned Wellbore Schematic .................................................................................................... 6 7.0 Drilling / Completion Summary ............................................................................................... 7 8.0 Mandatory Regulatory Compliance / Notifications ................................................................. 8 9.0 R/U and Preparatory Work .................................................................................................... 10 10.0 N/U 13-5/8” 5M Diverter System ............................................................................................ 11 11.0 Drill 12-1/4” Hole Section ....................................................................................................... 13 12.0 Run 9-5/8” Surface Casing ..................................................................................................... 16 13.0 Cement 9-5/8” Surface Casing ................................................................................................ 22 14.0 ND Diverter, NU BOPE, & Test ............................................................................................. 27 15.0 Drill 8-1/2” Hole Section ......................................................................................................... 28 16.0 Run 4-1/2” Screened Liner ..................................................................................................... 33 17.0 Run 7” Tieback ....................................................................................................................... 37 18.0 Run Upper Completion – ESP ................................................................................................ 40 19.0 Doyon 14 Diverter Schematic ................................................................................................. 43 20.0 Doyon 14 BOP Schematic ....................................................................................................... 44 21.0 Wellhead Schematic ................................................................................................................ 45 22.0 Days Vs Depth ......................................................................................................................... 46 23.0 Formation Tops & Information.............................................................................................. 47 24.0 Anticipated Drilling Hazards ................................................................................................. 48 25.0 Doyon 14 Rig Layout .............................................................................................................. 51 26.0 FIT Procedure ......................................................................................................................... 52 27.0 Doyon 14 Rig Choke Manifold Schematic .............................................................................. 53 28.0 Casing Design .......................................................................................................................... 54 29.0 8-1/2” Hole Section MASP ...................................................................................................... 55 30.0 Spider Plot (NAD 27) (Governmental Sections) ..................................................................... 56 31.0 Surface Plat (As Staked) (NAD 27) ........................................................................................ 57 Page 2 Milne Point Unit J-40 SB Producer PTD Application 1.0 Well Summary Well MPU J-40 Pad Milne Point “J” Pad Planned Completion Type ESP Target Reservoir(s) Schrader Bluff NB Sand Planned Well TD, MD / TVD 16,156’ MD / 4,072’ TVD PBTD, MD / TVD 16,156’ MD / 4,072’ TVD Surface Location (Governmental) 2305' FSL, 3172' FWL, Sec 28, T13N, R10E, UM, AK Surface Location (NAD 27) X= 552148, Y=6014704 Top of Productive Horizon (Governmental)1992' FSL, 1594' FWL, Sec 33, T13N, R10E, UM, AK TPH Location (NAD 27) X= 551688, Y= 6009108 BHL (Governmental) 350' FNL, 958' FEL, Sec 2, T12N, R10E, UM, AK BHL (NAD 27) X= 559712, Y= 6006825 AFE Drilling Days 21 AFE Completion Days 3 Maximum Anticipated Pressure (Surface) 1325 psig Maximum Anticipated Pressure (Downhole/Reservoir) 1704 psig Work String 5” 19.5# S-135 NC 50 Doyon 14 KB Elevation above MSL: 33.4 ft + 33.5 ft = 66.9 ft GL Elevation above MSL: 33.4 ft BOP Equipment 13-5/8” x 5M Annular, (3) ea 13-5/8” x 5M Rams Page 3 Milne Point Unit J-40 SB Producer PTD Application 2.0 Management of Change Information Page 4 Milne Point Unit J-40 SB Producer PTD Application 3.0 Tubular Program: Hole Section OD (in)ID (in) Drift (in) Conn OD (in) Wt (#/ft) Grade Conn Burst (psi) Collapse (psi) Tension (k-lbs) Cond 20” 19.25”---X-52Weld 12-1/4”9-5/8” 8.835” 8.679”10.625”40 L-80 TXP 5,750 3,090 916 9-5/8” 8.681” 8.525” 10.625” 47 L-80 TXP 6,870 4,750 1,086 Tieback 7” 6.276” 6.151” 7.656” 26 L-80 TXP 7,240 5,410 604 8-1/2”4-1/2” Screens 3.920” 3.795” 4.714” 13.5 L-80 Hydril 625 9,020 8,540 279 Tubing 3-1/2” 2.992” 2.867” 4.500” 9.3 L-80 EUE 8RD 9289 7399 163 4.0 Drill Pipe Information: Hole Section OD (in) ID (in)TJ ID (in) TJ OD (in) Wt (#/ft) Grade Conn M/U (Min) M/U (Max) Tension (k-lbs) Surface & Production 5”4.276” 3.25” 6.625” 19.5 S-135 DS50 36,100 43,100 560klb 5”4.276” 3.25” 6.625” 19.5 S-135 NC50 30,730 34,136 560klb All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery). Page 5 Milne Point Unit J-40 SB Producer PTD Application 5.0 Internal Reporting Requirements 5.1 Fill out daily drilling report and cost report on WellView. 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 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 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 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 nathan.sperry@hilcorp.com and joseph.lastufka@hilcorp.com 5.7 Hilcorp Milne Point Contact List: Title Name Work Phone Email Drilling Manager Monty Myers 907.777.8431 mmyers@hilcorp.com Drilling Engineer Nate Sperry 907.777.8450 nathan.sperry@hilcorp.com Drilling Engineer Joe Engel 907.777.8395 jengel@hilcorp.com Completion Engineer Todd Sidoti Todd.Sidoti@hilcorp.com Geologist Katie Cunha 907.564.4786 Katharine.cunha@hilcorp.com Reservoir Engineer Almas Aitkulov 907.564.4250 aaitkulov@hilcorp.com Drilling Env. Coordinator Adrian Kersten adrian.kersten@hilcorp.com EHS Director Laura Green 907.777.8314 lagreen@hilcorp.com Drilling Tech Joe Lastufka 907.777.8400 Joseph.Lastufka@hilcorp.com Page 6 Milne Point Unit J-40 SB Producer PTD Application 6.0 Planned Wellbore Schematic Page 7 Milne Point Unit J-40 SB Producer PTD Application 7.0 Drilling / Completion Summary MPU J-40 is a grassroots producer planned to be drilled in the Schrader Bluff NB sand. J-40 is part of a multi well program targeting the Schrader Bluff sand on J-pad The directional plan is 12-1/4” surface hole with 9-5/8” surface casing set in the base of the Schrader Bluff NA. An 8-1/2” lateral section will be drilled and completed with a 4-1/2” liner. The well will be produced with an ESP. Doyon 14 will be used to drill and complete the wellbore. Drilling operations are expected to commence approximately September 20, 2024, pending rig schedule. Surface casing will be run to 7,800’ MD / 3,790’ TVD and cemented to surface via a 2-stage primary cement job. Cement returns to surface will confirm TOC at surface. If cement returns to surface are not observed, necessary remedial action will then be discussed with AOGCC authorities. All cuttings & mud generated during drilling operations will be hauled to the Milne Point “B” pad G&I facility. General sequence of operations: 1. MIRU Doyon 14 to well site 2. N/U & Test 21-1/4” Diverter and 16” diverter line 3. Drill 12-1/4” hole to TD of surface hole section. Run and cement 9-5/8” surface casing 4. N/D diverter, N/U wellhead, NU 13-5/8” 5M BOP & Test 5. Drill 8-1/2” lateral to well TD 6. Run 4-1/2” production liner 7. Run 7” tieback 8. Run Upper Completion 9. N/D BOP, N/U Tree, RDMO Reservoir Evaluation Plan: 1. Surface hole: No mud logging. Remote geologist. LWD: GR + Res 2. Production Hole: No mud logging. Remote geologist. LWD: GR + ADR (For geo-steering) Page 8 Milne Point Unit J-40 SB Producer PTD Application 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that all drilling and completion operations comply with all applicable AOGCC regulations. Operations stated in this PTD application may be altered based on sound engineering judgement as wellbore conditions require, but no AOGCC regulations will be varied from without prior approval from the AOGCC. 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 Review all conditions of approval of the PTD on the 10-401 form. Ensure that the conditions of approval are captured in shift handover notes until they are executed and complied with. x BOPs shall be tested at (2) week intervals during the drilling and completion of MPU J-40. Ensure to provide AOGCC 24 hrs notice prior to testing BOPs. x The initial test of BOP equipment will be to 250/3,000 psi & subsequent tests of the BOP equipment will be to 250/3,000 psi for 5/5 min (annular to 50% rated WP, 2,500 psi on the high test for initial and subsequent tests).Confirm that these test pressures match those specified on the APD. 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 Casing pressure test criteria in 20 AAC 25.030 (e) Casing and Cementing,“A casing pressure test must be performed if BOPE is to be installed on a casing. The casing must be tested to hold a minimum surface pressure equal to 50 percent of the casing internal yield pressure. The test pressure must show stabilizing pressure and may not decline more than 10 percent within 30 minutes. The results of this test and any subsequent tests of the casing must be recorded as required by 20 AAC 25.070(1)”. AOGCC Regulation Variance Requests: x None Page 9 Milne Point Unit J-40 SB Producer PTD Application Summary of BOP Equipment & Notifications Hole Section Equipment Test Pressure (psi) 12 1/4”x 21-1/4” 2M Diverter w/ 16” Diverter Line Function Test Only 8-1/2” x 13-5/8” x 5M Hydril “GK” Annular BOP x 13-5/8” x 5M Hydril MPL Double Gate o Blind ram in btm cavity x Mud cross w/ 3” x 5M side outlets x 13-5/8” x 5M Hydril MPL Single ram x 3-1/8” x 5M Choke Line x 3-1/8” x 5M Kill line x 3-1/8” x 5M Choke manifold x Standpipe, floor valves, etc Initial Test: 250/3000 Subsequent Tests: 250/3000 Primary closing unit: NL Shaffer, 6 station, 3000 psi, 180 gallon accumulator unit. Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is a 30:1 air pump, and emergency pressure is provided by bottled nitrogen. The remote closing operator panels are located in the doghouse and on accumulator unit. Required AOGCC Notifications: x Well control event (BOPs utilized to shut in the well to control influx of formation fluids). x 24 hours notice prior to spud. x 24 hours notice prior to testing BOPs. x 24 hours notice prior to casing running & cement operations. x Any other notifications required in APD. Regulatory Contact Information: AOGCC Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email:jim.regg@alaska.gov Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Email:Victoria.loepp@alaska.gov Mel Rixse / Petroleum Engineer / (O): 907-793-1231 / (C): 907-223-3605 / Email:melvin.rixse@alaska.gov Primary Contact for Opportunity to witness:AOGCC.Inspectors@alaska.gov Test Inspection notification standardization format:http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) Page 10 Milne Point Unit J-40 SB Producer PTD Application 9.0 R/U and Preparatory Work 9.1 J-40 will utilize a newly set 20” conductor on J-pad. Ensure to review attached surface plat and make sure rig is over appropriate conductor. 9.2 Ensure PTD and drilling program are posted in the rig office and on the rig floor. 9.3 Install landing ring. 9.4 Insure (2) 4” nipples are installed on opposite sides of the conductor with ball valves on each. 9.5 Level pad and ensure enough room for layout of rig footprint and R/U. 9.6 Rig mat footprint of rig. 9.7 MIRU Doyon 14. Ensure rig is centered over conductor to prevent any wear to BOPE or wellhead. 9.8 Mud loggers WILL NOT be used on either hole section. 9.9 Mix spud mud for 12-1/4” surface hole section. Ensure mud temperatures are cool (<80qF). 9.10 Ensure 6” liners in mud pumps. x Continental EMSCO FB-1600 mud pumps are rated at 4665 psi, 462 gpm @ 110 spm @ 95% volumetric efficiency. Page 11 Milne Point Unit J-40 SB Producer PTD Application 10.0 N/U 13-5/8” 5M Diverter System 10.1 N/U 21-1/4” Hydril MSP 2M Diverter System (Diverter Schematic attached to program). x N/U 16-3/4” 3M x 21-1/4” 2M DSA on 16-3/4” 3M wellhead. x N/U 21-1/4” diverter “T”. x Knife gate, 16” diverter line. x Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C). x Diverter line must be 75 ft from nearest ignition source x Place drip berm at the end of diverter line. 10.2 Notify AOGCC. Function test diverter. 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 45 seconds (API Standard 64 3rd edition March 2018 section 12.6.2 for packing element ID greater than 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. Page 12 Milne Point Unit J-40 SB Producer PTD Application 10.4 Rig & Diverter Orientation: x May change on location Page 13 Milne Point Unit J-40 SB Producer PTD Application 11.0 Drill 12-1/4” Hole Section 11.1 P/U 12-1/4” directional drilling assembly: x Ensure BHA components have been inspected previously. x Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. x Ensure TF offset is measured accurately and entered correctly into the MWD software. x Use GWD until MWD surveys are clean and then swap to MWD. x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. x Drill string will be 5” 19.5# S-135. x Run a solid float in the surface hole section. 11.2 Begin drilling out from 20” conductor at reduced flow rates to avoid broaching the conductor. x Consider using a trash bit to clean out conductor to mitigate potential damage from debris in conductor. 11.3 Drill 12-1/4” hole section to section TD in the Schrader NB sand. Confirm this setting depth with the Geologist and Drilling Engineer while drilling the well. x Monitor the area around the conductor for any signs of broaching. If broaching is observed, stop drilling (or circulating) immediately notify Drilling Engineer. x Efforts should be made to minimize dog legs in the surface hole. Keep DLS < 6 deg / 100. x Hold a safety meeting with rig crews to discuss: x Conductor broaching ops and mitigation procedures. x Well control procedures and rig evacuation x Flow rates, hole cleaning, mud cooling, etc. x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Keep mud as cool as possible to keep from washing out permafrost. x Pump at 400-600 gpm. Monitor shakers closely to ensure shaker screens and return lines can handle the flow rate. x Do not out drill hole cleaning capacity. Perform clean up cycles or reduce ROP if packoffs, increase in pump pressure, or changes in hookload are seen. x Slow in/out of slips and while tripping to keep swab and surge pressures low. x Ensure shakers are functioning properly. Check for holes in screens on connections. x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of pea gravel, clay balling or packing off. x Adjust MW and viscosity as necessary to maintain hole stability, ensure MW is at a 9.2 minimum at TD (pending MW increase due to hydrates). x Be prepared for gas hydrates. In MPU they have been encountered between 2,100’-2,400’ TVD (just below permafrost). 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 14 Milne Point Unit J-40 SB Producer PTD Application zone completely and efficiently to mitigate the hydrate issue. Flowrates can also be reduced to prevent mud from belching over the bell nipple. x Gas hydrates are not a gas sand. Once a hydrate is disturbed, the gas will come out of the well. MW will not control gas hydrates MW will affect how gas breaks out at surface. x Surface Hole AC: x There are no wells with a clearance factor of <1.0 11.4 12-1/4” hole mud program summary: 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+ MW can be cut once ~500’ below hydrate zone PVT System: MD Totco PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, Toolpusher office, and mud loggers office. Rheology:MI Gel and CF Desco II should be used to maintain rheology. Begin system with a 75 YP but reduce this once clays are encountered. Maintain a minimum 25 YP at all times while drilling. Be prepared to increase the YP if hole cleaning becomes an issue. Fluid Loss: MI PAC UL should be used for filtrate control. Background LCM (10 ppb total) can be used in the system while drilling the surface interval to prevent losses and strengthen the wellbore. Wellbore and mud stability:Additions of SCREENKLEEN 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 Busan 1060 MUST be made to control bacterial action. 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 Page 15 Milne Point Unit J-40 SB Producer PTD Application Surface 8.8 – 9.8 75-175 20 - 40 25-45 <10 8.5 – 9.0 70 F System Formulation: Gel + FW spud mud Product- Surface hole Size Pkg ppb or (% liquids) M-I Gel 50 lb sx 25 Soda Ash 50 lb sx 0.25 PolyPac Supreme UL 50 lb sx 0.08 Caustic Soda 50 lb sx 0.1 SCREENCLEEN 55 gal dm 0.5 11.5 At TD; PU 2-3 stands off bottom to avoid washing out the hole at TD, CBU, pump tandem sweeps and drop viscosity. 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 ft / minute, adjust as dictated by hole conditions x Monitor well for any signs of packing off or losses. x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay balling. x If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until parameters are restored. 11.7 TOOH and LD BHA 11.8 No open hole logging program planned. Page 16 Milne Point Unit J-40 SB Producer PTD Application 12.0 Run 9-5/8” Surface Casing 12.1 R/U and pull wearbushing. 12.2 R/U 9-5/8” casing running equipment (CRT & Tongs) x Ensure 9-5/8” TXP x NC50 XO on rig floor and M/U to FOSV. x Use BOL 2000 thread compound. Dope pin end only w/ paint brush. x R/U of CRT if hole conditions require. x R/U a fill up tool to fill casing while running if the CRT is not used. x Ensure all casing has been drifted to 8.5” on the location prior to running. x Note that 47# drift is 8.525” x Be sure to count the total # of joints on the location before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, and lengths of all components w/ vendor & model info. 12.3 P/U shoe joint and visually verify there is no debris inside joint. 12.4 Continue M/U & thread locking 120’ shoe track assembly consisting of: 9-5/8” Float Shoe 1 joint – 9-5/8” TXP, 2 Centralizers 10’ from each end w/ stop rings 1 joint –9-5/8” TXP, 1 Centralizer mid joint w/ stop ring 9-5/8” Float Collar w/ Stage Cementer Bypass Baffle ‘Top Hat’ 1 joint –9-5/8” TXP, 1 Centralizer mid joint with stop ring 9-5/8” HES Baffle Adaptor x Ensure bypass baffle is correctly installed on top of float collar. x Ensure proper operation of float equipment while picking up. x Ensure to record S/N’s of all float equipment and stage tool components. This end up. Bypass Baffle Page 17 Milne Point Unit J-40 SB Producer PTD Application 12.5 Float equipment and Stage tool equipment drawings: Page 18 Milne Point Unit J-40 SB Producer PTD Application 12.6 Continue running 9-5/8” surface casing x Fill casing while running using fill up line on rig floor. x Use BOL 2000 thread compound. Dope pin end only w/ paint brush. x Centralization: x 1 centralizer every joint to ~ 1,000’ MD from shoe x 1 centralizer every 2 joints to ~2,000’ above shoe (Top of Lowest Ugnu) x Verify depth of lowest Ugnu water sand for isolation with Geologist x Utilize a collar clamp until weight is sufficient to keep slips set properly. x Break circulation prior to reaching the base of the permafrost if casing run indicates poor hole conditions. x Any packing off while running casing should be treated as a major problem. It is preferable to POOH with casing and condition hole than to risk not getting cement returns to surface. x If we experienced losses while BROOH, or if the mud returns are coming back thick, break circulation more frequently and plan to CBU multiple times prior to reaching TD. Confirm circ strategy with drilling engineer. 12.7 Install the Halliburton Type H ES-II Stage tool so that it is positioned at least 100’ TVD below the permafrost. x Install centralizers over couplings on 5 joints below and 5 joints above stage tool. x Do not place tongs on ES cementer, this can cause damaged to the tool. x Ensure tool is pinned with 6 opening shear pins. This will allow the tool to open at 3300 psi. 9-5/8” 40# L-80 TXP Make-Up Torques: Casing OD Minimum Optimum Maximum 9-5/8”18,860 ft-lbs 20,960 ft-lbs 23,060 ft-lbs 9-5/8” 47# L-80 TXP MUT: Casing OD Minimum Optimum Maximum 9-5/8”21,440 ft-lbs 23,820 ft-lbs 26,200 ft-lbs Page 19 Milne Point Unit J-40 SB Producer PTD Application Page 20 Milne Point Unit J-40 SB Producer PTD Application 12.8 Continue running 9-5/8” surface casing 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 w/ paint brush. x Centralization: o 1 centralizer every 2 joints to base of conductor 12.9 Ensure the permafrost is covered with 9-5/8” 47# from BPRF to Surface x Ensure drifted to 8.525” Page 21 Milne Point Unit J-40 SB Producer PTD Application 12.10 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 12.11 Slow in and out of slips. 12.12 P/U landing joint and M/U to casing string. Position the casing shoe +/- 10’ from TD. Strap the landing joint prior to the casing job and mark the joint at (1) ft intervals to use as a reference when getting the casing on depth. 12.13 Lower casing to setting depth. Confirm measurements. 12.14 Have slips staged in cellar along with necessary equipment for the operation. 12.15 Circulate and condition mud through CRT. Reduce YP to < 20 to help ensure success of cement job. Ensure adequate amounts of cold M/U water are available to achieve this. If possible, reciprocate casing string while conditioning mud. Page 22 Milne Point Unit J-40 SB Producer PTD Application 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 Have a plan to handle cement returns to surface. 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 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: Page 23 Milne Point Unit J-40 SB Producer PTD Application Cement Slurry Design (1st Stage Cement Job): 13.9 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. 13.10 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. 13.11 The plug must be bumped to operate the stage tool hydraulically, 13.12 Displacement calculation: See calculation in step 13.8 80 bbls of tuned spacer to be left on top of stage tool so that the first fluid through the ES cementer is tuned spacer to minimize the risk of flash setting cement 13.13 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. 13.14 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. Ensure the free fall stage tool opening plug is available. This is the back-up option to open the stage tool. 13.15 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held, this is to ensure the stage tool is not prematurely opened. 13.16 Increase pressure to 3,300 psi to open circulating ports in stage collar. Slightly higher pressure may be necessary if TOC is above the stage tool. CBU and record any spacer or cement returns to surface and volume pumped to see the returns. Circulate until YP < 20 again in preparation for the 2nd stage of the cement job. Lead Slurry Tail Slurry System EconoCem HalCem Density 12.0 lb/gal 15.8 lb/gal Yield 2.35 ft3/sk 1.16 ft3/sk Mix Water 13.92 gal/sk 4.98 gal/sk Page 24 Milne Point Unit J-40 SB Producer PTD Application 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 25 Milne Point Unit J-40 SB Producer PTD Application 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. 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. Lead Slurry Tail Slurry System ArcticCem HalCem Density 10.7 lb/gal 15.8 lb/gal Yield 2.88 ft3/sk 1.17 ft3/sk Mixed Water 22.02 gal/sk 5.08 gal/sk Page 26 Milne Point Unit J-40 SB Producer PTD Application 13.26 Displacement calculation: 2500’ x 0.0732 bpf = 183.0 bbls mud 13.27 Monitor returns closely while displacing cement. Adjust pump rate if necessary. Wellhead side outlet valve in cellar can be opened to take returns to cellar if required. Be prepared to pump out fluid from cellar. Have black water available to retard setting of cement. 13.28 Decide ahead of time what will be done with cement returns once they are at surface. We should circulate approximately 150 - 250 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 WellView: 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 27 Milne Point Unit J-40 SB Producer PTD Application 14.0 ND Diverter, NU BOPE, & Test 14.1 ND the diverter T, knife gate, diverter line & NU 11” x 13-5/8” 5M casing spool. 14.2 NU 13-5/8” x 5M BOP as follows: x BOP configuration from top down: 13-5/8” x 5M annular / 13-5/8” x 5M double gate / 13- 5/8” x 5M mud cross / 13-5/8” x 5M single gate x Double gate ram should be dressed with 4-1/2” x 7” VBRs in top cavity,blind ram in bottom cavity. x Single ram can be dressed with 2-7/8” x 5” VBRs x NU bell nipple, install flowline. x Install (1) manual valve & HCR valve on kill side of mud cross. (Manual valve closest to mud cross). x Install (1) manual valve on choke side of mud cross. Install an HRC outside of the manual valve 14.3 RU MPD RCD and related equipment 14.4 Run 5” BOP test plug 14.5 Test BOP to 250/3,000 psi for 5/5 min. Test annular to 250/2,500 psi for 5/5 min. x Test 2-7/8” x 5” rams with the 3-1/2” and 5” test joints x Test 4-1/2” x 7” rams with 5” and 7” test joints. x Confirm test pressures with PTD x Ensure to monitor side outlet valves and annulus valve pressure gauges to ensure no pressure is trapped underneath test plug x Once BOPE test is complete, send a copy of the test report to town engineer and drilling tech 14.6 RD BOP test equipment 14.7 Dump and clean mud pits, send spud mud to G&I pad for injection. 14.8 Mix 8.9 ppg FloPro for production hole. 14.9 Set wearbushing in wellhead. 14.10 If needed, rack back as much 5” DP in derrick as possible to be used while drilling the hole section. 14.11 Ensure 5” liners in mud pumps. Page 28 Milne Point Unit J-40 SB Producer PTD Application 15.0 Drill 8-1/2” Hole Section 15.1 Confirm with DE whether we will cleanout with a cleanout assembly or the lateral assembly. 15.2 If a cleanout assembly is required, MU 8-1/2” Cleanout BHA (Milltooth Bit & 1.22° PDM). 15.3 TIH w/ 8-1/2” cleanout BHA to stage tool. Note depth TOC tagged on AM report. Drill out stage tool. 15.4 TIH to TOC above the baffle adapter. Note depth TOC tagged on morning report. 15.5 RU and test casing to 2,500 psi / 30 min. Ensure to record volume / pressure (every ¼ bbl) and plot on FIT graph. AOGCC reg is 50% of burst = 5,750 / 2 = ~2,875 psi, but max test pressure on the well is 2,500 psi as per AOGCC. Document incremental volume pumped (and subsequent pressure) and volume returned. Ensure rams are used to test casing as per AOGCC Industry Guidance Bulletin 17-001. 15.6 Drill out shoe track and 20’ of new formation. 15.7 CBU and condition mud for FIT. 15.8 Conduct FIT to 12.0 ppg EMW. Chart Test. Ensure test is recorded on same chart as casing test. Document incremental volume pumped (and subsequent pressure) and volume returned. 15.9 POOH and LD cleanout BHA 15.10 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 NC50. Schrader Bluff Bit Jetting Guidelines Formation Jetting TFA NB 6 x 14 0.902 OA 6 x 13 0.778 OB 6 x 13 0.778 FIT and casing test digital data to AOGCC upon completion of FIT. - mgr Page 29 Milne Point Unit J-40 SB Producer PTD Application 15.11 8-1/2” hole section mud program summary: x Density: Weighting material to be used for the hole section will be calcium carbonate. Additional calcium carbonate will be on location to weight up the active system (1) ppg above highest anticipated MW. x Solids Concentration: It is imperative that the solids concentration be kept low while drilling the production hole section. Keep the shaker screen size optimized and fluid running to near the end of the shakers. It is okay if the shakers run slightly wet to ensure we are running the finest screens possible. x Rheology: Keep viscosifier additions to an absolute minimum (N-VIS). Data suggests excessive viscosifier concentrations can decrease return permeability. Do not pump high vis sweeps, instead use tandem sweeps. Ensure 6 rpm is > 8.5 (hole diameter) for sufficient hole cleaning x Run the centrifuge continuously while drilling the production hole, this will help with solids removal. x Dump and dilute as necessary to keep drilled solids to an absolute minimum. x MD Totco PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, & Toolpusher office. System Type:8.9 – 9.5 ppg FloPro drilling fluid Properties: Interval Density PV YP LSYP Total Solids MBT HPHT Hardness Production 8.9-9.5 15-25 - ALAP 15 - 30 4-6 <10% <8 <11.0 <100 Page 30 Milne Point Unit J-40 SB Producer PTD Application System Formulation: 15.12 TIH with 8-1/2” directional assembly to bottom 15.13 Install MPD RCD 15.14 Displace wellbore to 8.9 ppg FloPro drilling fluid 15.15 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 ft/min, 385 GPM x RPM: 120+ x Ensure shaker screens are set up to handle this flowrate. Ensure shakers are running slightly wet to maximize solids removal efficiency. Check for holes in screens on every connection. x Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low x Take MWD surveys every stand, can be taken more frequently if deemed necessary, ex: concretion deflection x Monitor Torque and Drag with pumps on every 5 stands x Monitor ECD, pump pressure & hookload trends for hole cleaning indication x 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. x Use ADR to stay in section. Reservoir plan is to stay in NB sand. x Limit maximum instantaneous ROP to < 250 FPH. The sands will drill faster than this, but when concretions are hit when drilling this fast, cutter damage can occur. x Target ROP is as fast as we can clean the hole without having to backream connections Page 31 Milne Point Unit J-40 SB Producer PTD Application x Schrader Bluff NB Concretions: 4-6% Historically x MPD will be utilized to monitor pressure build up on connections. x 8-1/2” Lateral A/C: x There are no wells with a CF < 1.0. 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. 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 ft/min AV (385+ GPM) and rotation (120+ RPM). Pump tandem sweeps if needed x Monitor BU for increase in cuttings, cuttings in laterals come back in waves and not a consistent stream, circulate more if necessary x If seepage losses are seen while drilling, consider reducing MW at TD to 9.0 ppg minimum 15.17 Mix and pump 40 bbl 10 ppb SAPP pill. Line up to a closed loop system and circulate three SAP pills with 50 bbl in between. Displace out SAP pills. Monitor shakers for returns of mud filter cake and calcium carbonate. Circulate the well clean. Losses during the cleanup of the wellbore are a good indication that the mud filter cake is being removed, including an increase in the loss rate. 15.18 Displace 1.5 OH + liner volume with viscosified brine. x Proposed brine blend - KCl: 7.1ppb for 2% NaCl: 60.9ppg for 9.4ppg Lotorq: 1.5% Lube 776: 1.5% Soda Ash: as needed for 9.5pH Busan 1060: 0.42ppb Flo-Vis Plus: 1.25ppb Page 32 Milne Point Unit J-40 SB Producer PTD Application x Monitor well for loss rate and contact Drilling Engineer and/or Ops Engineer if further discussion needed prior to BROOH. 15.16 Monitor the returned fluids carefully while displacing to brine. After 1 (or more if needed) BU, Perform production screen test (PST). The brine has been properly conditioned when it will pass the production screen test (x3 350 ml samples passing through the screen in the same amount of time which will indicate no plugging of the screen). Reference PST Test Procedure 15.19 BROOH with the drilling assembly to the 9-5/8” casing shoe x Circulate at full drill rate (less if losses are seen, 350 GPM minimum). x Rotate at maximum RPM that can be sustained. x Pulling speed 5 – 10 min/stand (slip to slip time, not including connections), adjust as dictated by hole conditions x When pulling across any OHST depths, turn pumps off and rotary off to minimize disturbance. Trip back in hole past OHST depth to ensure liner will stay in correct hole section, check with ABI compared to as drilled surveys 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. x Wellbore breathing has been seen on past MPU SB wells. Perform extended flow checks to determine if well is breathing, treat all flow as an influx until proven otherwise x If necessary, increase MW at shoe for any higher-than-expected pressure seen x Ensure fluid coming out of hole has passed a PST at the possum belly 15.23 POOH and LD BHA. 15.24 Continue to POOH and stand back BHA if possible. Rabbit DP on TOOH, ensure rabbit diameter is sufficient for future ball drops. Only LWD open hole logs are planned for the hole section (GR + Res). There will not be any additional logging runs conducted. Page 33 Milne Point Unit J-40 SB Producer PTD Application 16.0 Run 4-1/2” Screened Liner NOTE: If an open hole sidetrack was performed, drop the centralizers on the lowermost 2-3 joints and run them slick. 16.1 Well control preparedness: In the event of an influx of formation fluids while running the 4- 1/2” screened liner, the following well control response procedure will be followed: x P/U & M/U the 5” safety joint (with 4-1/2” crossover installed on bottom, TIW valve in open position on top, 4-1/2” handling joint above TIW). This joint shall be fully M/U and available prior to running the first joint of 4-1/2” screened liner. x Slack off and with 5” DP across the BOP, shut in ram or annular on 5” DP. Close TIW. x Proceed with well kill operations. 16.2 R/U 4-1/2” liner running equipment. x Ensure 4-1/2” 13.5# Hydril 625 x NC50 crossover is on rig floor and M/U to FOSV. x Ensure all casing has been drifted on the deck prior to running. x Be sure to count the total # of joints on the deck before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, and lengths of all components w/ vendor & model info. 16.3 Run 4-1/2” screened production liner until XO point for SLZXP x Use API Modified or “Best O Life 2000 AG”thread compound. Dope pin end only w/ paint brush. Wipe off excess. Thread compound can plug the screens x Utilize a collar clamp until weight is sufficient to keep slips set properly. x Use lift nubbins and stabbing guides for the liner run. x Fill 4-½” liner with PST passed mud (to keep from plugging screens with solids) x Install screen joints as per the Running Order (From Operations Engineer post TD). o Do not place tongs or slips on screen joints o Screen placement ±40’ o The screen connection is 4-1/2” 13.5# Hydril 625 x If liner length exceeds surface casing length, ensure centralizers are placed 1/jt for each joint outside of the surface shoe. This is to mitigate difference sticking risk while running inner string. x Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10 and 20 rpm Page 34 Milne Point Unit J-40 SB Producer PTD Application 4-1/2” 13.5# L-80 Hydril 625 Torque OD Minimum Optimum Maximum 4-1/2 8,000 ft-lbs 9,600 ft-lbs 12,800 ft-lbs Page 35 Milne Point Unit J-40 SB Producer PTD Application 16.6. Ensure to run enough liner to provide for approx. 150’ overlap inside 9-5/8” casing. Ensure hanger/pkr will not be set in a 9-5/8” connection. x AOGCC regulations require a minimum 100’ overlap between the inner and outer strings as per 20 AAC 25.030(d)(6). Do not place liner hanger/packer across 9-5/8” connection. 16.7. Before picking up Baker SLZXP liner hanger / packer assembly, count the # of joints on the pipe deck to make sure it coincides with the pipe tally. 16.8. M/U Baker SLZXP liner top packer to 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 ft/min – this is to prevent buckling the liner and drill string and weight transfer to get liner to bottom with minimal rotation. Watch displacement carefully and avoid surging the hole or buckling the liner. Slow down running speed if necessary. x Ensure 5” DP/HWDP has been drifted 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 down the workstring and pump slowly (1-2 BPM). Slow pump before the ball seats. Do not allow ball to slam into ball seat. Page 36 Milne Point Unit J-40 SB Producer PTD Application 16.19. Continue pressuring up to 2,700 psi to set the SLZXP liner hanger/packer. Hold for 5 minutes. Slack off 20K lbs on the SZXP liner hanger/packer to ensure the HRDE setting tool is in compression for release from the SLZXP liner hanger/packer. Continue pressuring up 4,500 psi to release the HRDE running tool. 16.20. Bleed DP pressure to 0 psi. Pick up to expose rotating dog sub and set down 50K without pulling sleeve packoff. Pick back up without pulling sleeve packoff, begin rotating at 10-20 RPM and set down 50K again. 16.21. PU to neutral weight, close BOP, and test annulus to 1,500 psi for 10 minutes. 16.22. Bleed off pressure and open BOPE. Pickup to verify that the HRD setting tool has released. If packer did not test, rotating dog sub can be used to set packer. If running tool cannot be hydraulically released, apply LH torque to mechanically release the setting tool. 16.23. PU pulling running tool free of the packer and displace at max rate to wash the liner top. Pump sweeps as needed. 16.24. POOH. LD and inspect running tools. If setting of liner hanger/packer proceeded as planned, LD DP on the TOOH. Note: Once running tool is LD, swap to the completion AFE. Page 37 Milne Point Unit J-40 SB Producer PTD Application 17.0 Run 7” Tieback 17.1 RU and pull wear bushing. Get an accurate measurement of RKB to tubing hanger load shoulder to be used for tie-back space out calculation. Install 7” solid body casing rams in the upper ram cavity. RU testing equipment. PT to 250/3,000 psi with 7” test joint. RD testing equipment. 17.2 RU 7” casing handling equipment. x Ensure XO to DP made up to FOSV and ready on rig floor. x Rig up computer torque monitoring service. x String should stay full while running, RU fill up line and check as appropriate. 17.3 PU 7” tieback seal assembly and set in rotary table. Ensure 7” seal assembly has (4) 1” holes above the first seal. These holes will be used to spot diesel freeze protect in the 9-5/8” x 7” annulus. 17.4 MU first joint of 7” to seal assy. 17.5 Run 7”, 26#, L-80 TXP tieback tieback to position seal assembly two joints above tieback sleeve. Record PU and SO weights. 7”, 26#, L-80, TXP =Casing OD Torque (Min) Torque (Opt)Torque (Max)Torque (Operating) 7”13,280 ft-lbs 14,750 ft-lbs 16,230 ft-lbs 20,000 ft-lbs Page 38 Milne Point Unit J-40 SB Producer PTD Application Page 39 Milne Point Unit J-40 SB Producer PTD Application 17.5 MU 7” to DP crossover. 17.5 MU stand of DP to string and MU top drive. 17.5 Break circulation at 1 BPM and begin lowering string. 17.5 Note seal assembly entering tieback sleeve with a pressure increase, stop pumping and bleed off pressure. Leave standpipe bleed off valve open. 17.5 Continue lowering string and land out on no-go. Set down 5 – 10K and mark the pipe as “NO- GO DEPTH”. 17.5 PU string & remove unnecessary 7” joints. 17.5 Space out with pups as needed to leave the no-go 1 ft above fully no-go position when the casing hanger is landed. Ensure one full joint is below the casing hanger. 17.5 PU and MU the 7” casing hanger. 17.5 Ensure circulation is possible through 7” string. 17.5 RU and circulation corrosion inhibited brine in the 9-5/8” x 7” annulus. 17.5 With seals stabbed into tieback sleeve, spot diesel freeze protection from 2,500’ TVD to surface in 9-5/8” x 7” annulus by reverse circulating through the holes in the seal assembly. Ensure annular pressure are limited to prevent collapse of the 7” casing (verify collapse pressure of 7” tieback seal assembly). 17.5 SO and land hanger. Confirm hanger has seated properly in wellhead. Make note of actual weight on hanger on morning report. 17.5 Back out the landing joint. MU packoff running tool and install packoff on bottom of landing joint. Set casing hanger packoff and RILDS. PT void to 3,000 psi for 10 minutes. 17.5 RD casing running tools. 17.5 PT 9-5/8” x 7” annulus to 1,500 psi for 30 minutes charted. Page 40 Milne Point Unit J-40 SB Producer PTD Application 18.0 Run Upper Completion – ESP 18.1 RU to run 3-1/2”, 9.3#, L-80 EUE tubing. x Ensure wear bushing is pulled. x Ensure 3-1/2”, L-80, 9.3#, EUE 8RD x NC50 crossover is on rig floor and M/U to FOSV. x Ensure all tubing has been drifted in the pipe shed prior to running. x Be sure to count the total # of joints in the pipe shed before running. x Keep hole covered while RU casing tools. x Record OD’s, ID’s, lengths, SN’s of all components with vendor & model info. x Monitor displacement from wellbore while RIH. Page 41 Milne Point Unit J-40 SB Producer PTD Application 18.2 PU, MU and RH with the following 3-1/2” ESP completion (confirm tally with Operations Engineer where to place ESP base): Colors indicate assemblies to be bucked up prior to RWO. Nom. Size ~Length Item Lb/ft Material Notes Centralizer ~L-80 Sensor, Zenith L-80 Baker Motor L-80 Summit Lower Tandem Seal L-80 Summit Upper Tandem Seal L-80 Summit Gas Avoider L-80 Summit Gas Seperator L-80 Summit Pump L-80 Summit Pump L-80 Summit 3- 1/2''Zenith Ported Sub Press Port L-80 Baker 3- 1/2'' 1 joint L-80 3- 1/2''10'Pup Joint 9.2 L-80 3- 1/2''3-1/2' XN nip L-80 3- 1/2''10'Pup Joint 9.2 L-80 3- 1/2'' 1 joint L-80 3- 1/2’’GLM with DMY 3- 1/2''Joints 9.2 L-80 3- 1/2’’GLM with live valve Placed +- 110’ MD 3- 1/2''Space out PUPS 9.2 L-80 3- 1/2'' 1 joint 9.2 L-80 3- 1/2''PUP 9.2 L-80 4- 1/2''Tubing Hanger 9.2 L-80 18.3 PU and MU the 4-1/2” tubing hanger. Make final splice of the ESP wire and ensure any unused control line ports are dummied off. Page 42 Milne Point Unit J-40 SB Producer PTD Application 18.4 Record PU and SO weights before landing hanger. Note PU and SO weights on tally along with band/clamp summary. 18.5 Land the tubing hanger and RILDS. Lay down the landing joint. 18.6 Install 4” HP BPV. ND BOP. Install the plug off tool. 18.7 NU the tubing head adapter and NU the tree. 18.8 PT the tubing hanger void to 500/5,000 psi. PT the tree to 250/5,000 psi. 18.9 Pull the plug off tool and BPV. 18.10 Reverse circulate the well over to corrosion inhibited source water follow by diesel freeze protect to 2,500’ MD. 18.11 Prepare to hand over well to production. Ensure necessary forms filled out and well handed over with valve alignment as per operations personnel. 18.12 RDMO Page 43 Milne Point Unit J-40 SB Producer PTD Application 19.0 Doyon 14 Diverter Schematic Page 44 Milne Point Unit J-40 SB Producer PTD Application 20.0 Doyon 14 BOP Schematic 2-7/8” x 5” Page 45 Milne Point Unit J-40 SB Producer PTD Application 21.0 Wellhead Schematic Page 46 Milne Point Unit J-40 SB Producer PTD Application 22.0 Days Vs Depth Page 47 Milne Point Unit J-40 SB Producer PTD Application 23.0 Formation Tops & Information MPU J-40 Formations TVD (ft) TVDss (ft) MD (ft) Formation Pressure (psi) EMW (ppg) BPRF 1920 1853 2658 845 8.46 SV1 2107 2040 3097 927 8.46 UG LA3 3397 3330 6130 1494 8.46 UG_MD 3586 3519 6643 1578 8.46 SCHRADER NB 3791 3724 7816 1668 8.46 Page 48 Milne Point Unit J-40 SB Producer PTD Application 24.0 Anticipated Drilling Hazards 12-1/4” Hole Section: Lost Circulation Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Gas Hydrates Gas hydrates are generally not seen on J-pad. Remember that hydrate gas behaves differently from a gas sand. Additional fluid density will not prevent influx of gas hydrates but can help control the breakout at surface. Once a gas hydrate has been disturbed the gas will come out of the hole. Drill through the hydrate section as quickly as possible while minimizing gas belching. Minimize circulation time while drilling through the hydrate zone. Excessive circulation will accelerate formation thawing which can increase the amount of hydrates released into the wellbore. Keep the mud circulation temperature as cold as possible. Weigh mud with both a pressurized and non-pressurized mud scale. The non- pressurized scale will reflect the actual mud cut weight. Isolate/dump contaminated fluid to remove hydrates from the system. Hole Cleaning: Maintain rheology of mud system. Sweep hole with high viscosity sweeps as necessary. Optimize solids control equipment to maintain density, sand content, and reduce the waste stream. Monitor ECD’s to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPM’s when CBU and keep pipe moving to avoid washing out a particular section of the hole. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Anti-Collison: There are no known wells with a clearance factory <1.0. Take directional surveys every stand, take additional surveys if necessary. Continuously monitor proximity to offset wellbores and record any close approaches on AM report. Well Specific A/C: x There are no wells with a clearance factor of <1.0 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 49 Milne Point Unit J-40 SB Producer PTD Application H2S: Treat every hole section as though it has the potential for H2S. MPU J-pad is not known for H2S. J-10 had 10ppm H2S (2013) and J-18 had 9.6 (2009). 1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Page 50 Milne Point Unit J-40 SB Producer PTD Application 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. Maint. 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 multiple planned fault crossings for J-40. H2S: Treat every hole section as though it has the potential for H2S. MPU J-pad is not known for H2S. J-10 had 10ppm H2S (2013) and J-18 had 9.6 (2009). 1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Abnormal Pressures and Temperatures: Reservoir pressures are expected to be normal. Utilize MPD to mitigate any abnormal pressure seen. Anti-Collision Take directional surveys every stand, take additional surveys if necessary. Continuously monitor drilling parameters for signs of magnetic interference with another well. Reference A/C report in directional plan. Well Specific AC: x There are no wells with a CF < 1.0. Page 51 Milne Point Unit J-40 SB Producer PTD Application 25.0 Doyon 14 Rig Layout Page 52 Milne Point Unit J-40 SB Producer PTD Application 26.0 FIT Procedure Formation Integrity Test (FIT) and Leak-Off Test (LOT) Procedures Procedure for FIT: 1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe). 2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe. 3. Close the blowout preventer (ram or annular). 4. Pump down the drill stem at 1/4 to 1/2 bpm. 5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe. 6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes. Record time vs. pressure in 1-minute intervals. 7. Bleed the pressure off and record the fluid volume recovered. The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick tolerance in case well control measures are required. Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid; at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure monitored as with an FIT. Ensure that casing test and subsequent FIT tests are recorded on the same chart. Document incremental volume pumped and returned during test. Page 53 Milne Point Unit J-40 SB Producer PTD Application 27.0 Doyon 14 Rig Choke Manifold Schematic Page 54 Milne Point Unit J-40 SB Producer PTD Application 28.0 Casing Design Page 55 Milne Point Unit J-40 SB Producer PTD Application 29.0 8-1/2” Hole Section MASP Page 56 Milne Point Unit J-40 SB Producer PTD Application 30.0 Spider Plot (NAD 27) (Governmental Sections) Page 57 Milne Point Unit J-40 SB Producer PTD Application 31.0 Surface Plat (As Staked) (NAD 27) 6WDQGDUG3URSRVDO5HSRUW -XO\ 3ODQ038-ZS +LOFRUS$ODVND//& 0LOQH3RLQW 03W-3DG 3ODQ038- 038- -55005501100165022002750330038504400True Vertical Depth (1100 usft/in)0 550 1100 1650 2200 2750 3300 3850 4400 4950 5500 6050 6600 7150 7700 8250 8800 9350 9900 10450 11000Vertical Section at 136.57° (1100 usft/in)MPU J-40 wp06 tgt1MPU J-40 wp06 tgt2MPU J-40 wp06 tgt3MPU J-40 wp06 tgt4MPU J-40 wp06 tgt5MPU J-40 wp06 tgt7MPU J-40 wp06 tgt9MPU J-40 wp06 tgt109 5/8" x 12 1/4"4 1/2" x 8 1/2"50010001500200025003000350040004500500055006000650070007500800085009000950010000105001100011500120001250013000135001400014500150001550016156MPU J-40 wp06Start Dir 3º/100' : 250' MD, 250'TVDStart Dir 4º/100' : 450' MD, 449.63'TVDEnd Dir : 1945.28' MD, 1616.34' TVDStart Dir 4.5º/100' : 5765.44' MD, 3244.35'TVDEnd Dir : 7468.72' MD, 3760.95' TVDBegin GeosteeringTotal Depth : 16155.72' MD, 4072.1' TVDSV6Base PermafrostSV1UG_LA3UG_MDSB_NASB_NBHilcorp Alaska, LLCCalculation Method:Minimum CurvatureError System:ISCWSAScan Method: Closest Approach 3DError Surface: Ellipsoid SeparationWarning Method: Error RatioWELL DETAILS: Plan: MPU J-4033.40+N/-S +E/-WNorthingEastingLatitudeLongitude0.000.00 6014704.42552148.00 70° 27' 3.2782 N 149° 34' 28.3031 WSURVEY PROGRAMDate: 2024-07-17T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool33.70 1500.00 MPU J-40 wp06 (MPU J-40) GYD_Quest GWD1500.00 7800.00 MPU J-40 wp06 (MPU J-40) 3_MWD+IFR2+MS+Sag7800.00 16155.72 MPU J-40 wp06 (MPU J-40) GYD_Quest GWDFORMATION TOP DETAILSTVDPath TVDssPath MDPath Formation893.10 826.00 911.45 SV61920.10 1853.00 2658.07 Base Permafrost2107.10 2040.00 3096.86 SV13397.10 3330.00 6130.25 UG_LA33586.10 3519.00 6643.14 UG_MD3758.10 3691.00 7437.77 SB_NA3791.10 3724.00 7815.67 SB_NBREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU J-40, True NorthVertical (TVD) Reference:WELL @ 67.10usft (Original Well Elev)Measured Depth Reference:WELL @ 67.10usft (Original Well Elev)Calculation Method: Minimum CurvatureProject:Milne PointSite:M Pt J PadWell:Plan: MPU J-40Wellbore:MPU J-40Design:MPU J-40 wp06CASING DETAILSTVD TVDSS MD SizeName3789.79 3722.69 7800.00 9-5/8 9 5/8" x 12 1/4"4072.10 4005.00 16155.72 4-1/2 4 1/2" x 8 1/2"SECTION DETAILSSec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation1 33.70 0.00 0.00 33.70 0.00 0.00 0.00 0.00 0.002 250.00 0.00 0.00 250.00 0.00 0.00 0.00 0.00 0.00 Start Dir 3º/100' : 250' MD, 250'TVD3 450.00 6.00 220.00 449.63 -8.01 -6.73 3.00 220.00 1.20 Start Dir 4º/100' : 450' MD, 449.63'TVD4 850.00 21.93 212.64 836.58 -87.45 -60.80 4.00 -10.00 21.715 1945.28 64.78 197.58 1616.34 -765.34 -334.23 4.00 -19.84 326.04 End Dir : 1945.28' MD, 1616.34' TVD6 5765.44 64.78 197.58 3244.35 -4059.79 -1378.15 0.00 0.00 2000.91 Start Dir 4.5º/100' : 5765.44' MD, 3244.35'TVD7 7468.72 85.00 120.00 3760.95 -5428.99 -784.92 4.50 -89.27 3403.08 End Dir : 7468.72' MD, 3760.95' TVD8 7768.72 85.00 120.00 3787.10 -5578.42 -526.10 0.00 0.00 3689.53 MPU J-40 wp06 tgt19 8022.40 86.28 110.22 3806.44 -5685.60 -297.33 3.88 -82.94 3924.6410 8032.53 86.28 110.22 3807.10 -5689.10 -287.84 0.00 0.00 3933.70 MPU J-40 wp06 tgt211 8158.20 88.38 107.88 3812.96 -5730.06 -169.20 2.50 -47.98 4045.0112 9366.68 88.38 107.88 3847.10 -6101.02 980.43 0.00 0.00 5104.73 MPU J-40 wp06 tgt313 9516.28 88.44 104.14 3851.25 -6142.27 1124.14 2.50 -89.18 5233.4814 11637.99 88.44 104.14 3909.10 -6660.49 3180.78 0.00 0.00 7023.67 MPU J-40 wp06 tgt415 11733.27 88.14 106.51 3911.95 -6685.65 3272.63 2.50 97.24 7105.0916 13123.67 88.14 106.51 3957.10 -7080.50 4605.02 0.00 0.00 8307.79 MPU J-40 wp06 tgt517 13376.04 82.86 103.04 3976.90 -7144.65 4848.16 2.50 -146.91 8521.5318 13443.49 82.86 103.04 3985.29 -7159.75 4913.36 0.00 0.00 8577.3219 13730.23 88.85 106.99 4006.01 -7233.83 5189.40 2.50 33.50 8820.8820 14980.23 88.85 106.99 4031.10 -7599.02 6384.60 0.00 0.00 9907.74 MPU J-40 wp06 tgt721 15077.35 87.71 104.85 4034.02 -7625.64 6477.95 2.50 -118.08 9991.2422 15779.64 87.71 104.85 4062.10 -7805.44 7156.25 0.00 0.00 10588.12 MPU J-40 wp06 tgt923 16138.40 89.18 114.41 4071.85 -7925.77 7493.64 2.70 81.38 10907.4524 16155.72 89.18 114.41 4072.10 -7932.93 7509.40 0.00 0.00 10923.48 MPU J-40 wp06 tgt10 Total Depth : 16155.72' MD, 4072.1' TVD -8000-7200-6400-5600-4800-4000-3200-2400-1600-8000South(-)/North(+) (1200 usft/in)-2400 -1600 -800 0 800 1600 2400 3200 4000 4800 5600 6400 7200 8000 8800West(-)/East(+) (1200 usft/in)MPU J-40 wp06 tgt10MPU J-40 wp06 tgt9MPU J-40 wp06 tgt7MPU J-40 wp06 tgt5MPU J-40 wp06 tgt4MPU J-40 wp06 tgt3MPU J-40 wp06 tgt2MPU J-40 wp06 tgt19 5/8" x 12 1/4"4 1/2" x 8 1/2"25050075010001250150017502000225025002750300032503500375040004072MPU J-40 wp06Start Dir 3º/100' : 250' MD, 250'TVDStart Dir 4º/100' : 450' MD, 449.63'TVDEnd Dir : 1945.28' MD, 1616.34' TVDStart Dir 4.5º/100' : 5765.44' MD, 3244.35'TVDEnd Dir : 7468.72' MD, 3760.95' TVDBegin GeosteeringTotal Depth : 16155.72' MD, 4072.1' TVDProject: Milne PointSite: M Pt J PadWell: Plan: MPU J-40Wellbore: MPU J-40Plan: MPU J-40 wp06WELL DETAILS: Plan: MPU J-4033.40+N/-S +E/-W Northing Easting Latitude Longitude0.00 0.006014704.42 552148.00 70° 27' 3.2782 N 149° 34' 28.3031 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU J-40, True NorthVertical (TVD) Reference: WELL @ 67.10usft (Original Well Elev)Measured Depth Reference:WELL @ 67.10usft (Original Well Elev)Calculation Method:Minimum CurvatureCASING DETAILSTVD TVDSS MD Size Name3789.79 3722.69 7800.00 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eparation Factor0 425 850 1275 1700 2125 2550 2975 3400 3825 4250 4675 5100 5525 5950 6375 6800 7225 7650 8075Measured Depth (850 usft/in)MPJ-22MPJ-27MPU I-28iMPJ-28MPI-19L1MPI-19MPU I-21iMPH-16MPJ-05No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.WELL DETAILS:Plan: MPU J-40 NAD 1927 (NADCON CONUS)Alaska Zone 0433.40+N/-S +E/-W Northing EastingLatitudeLongitude0.000.006014704.42552148.0070° 27' 3.2782 N149° 34' 28.3031 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU J-40, True NorthVertical (TVD) Reference: WELL @ 67.10usft (Original Well Elev)Measured Depth Reference:WELL @ 67.10usft (Original Well Elev)Calculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2024-07-17T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool33.70 1500.00 MPU J-40 wp06 (MPU J-40) GYD_Quest GWD1500.00 7800.00 MPU J-40 wp06 (MPU J-40) 3_MWD+IFR2+MS+Sag7800.00 16155.72 MPU J-40 wp06 (MPU J-40) GYD_Quest GWD0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)0 425 850 1275 1700 2125 2550 2975 3400 3825 4250 4675 5100 5525 5950 6375 6800 7225 7650 8075Measured Depth (850 usft/in)MPJ-16MPJ-27MPJ-07MPJ-20MPJ-13MPU J-46 wp04MPJ-28MPJ-12MPJ-06MPU J-44 wp06MPJ-19MPJ-09MPU J-42MPJ-21MPJ-17MPJ-18MPJ-05NO GLOBAL FILTER: Using user defined selection & filtering criteria33.70 To 16155.72Project: Milne PointSite: M Pt J PadWell: Plan: MPU J-40Wellbore: MPU J-40Plan: MPU J-40 wp06Ladder / S.F. 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*<'B4XHVW*:'(OOLSVHHUURUWHUPVDUHFRUUHODWHGDFURVVVXUYH\WRROWLHRQSRLQWV6HSDUDWLRQLVWKHDFWXDOGLVWDQFHEHWZHHQHOOLSVRLGV&DOFXODWHGHOOLSVHVLQFRUSRUDWHVXUIDFHHUURUV&OHDUDQFH)DFWRU 'LVWDQFH%HWZHHQ3URILOHV'LVWDQFH%HWZHHQ3URILOHV(OOLSVH6HSDUDWLRQ'LVWDQFH%HWZHHQFHQWUHVLVWKHVWUDLJKWOLQHGLVWDQFHEHWZHHQZHOOERUHFHQWUHV$OOVWDWLRQFRRUGLQDWHVZHUHFDOFXODWHGXVLQJWKH0LQLPXP&XUYDWXUHPHWKRG-XO\ &203$663DJHRI 0.001.002.003.004.00Separation Factor7600 8075 8550 9025 9500 9975 10450 10925 11400 11875 12350 12825 13300 13775 14250 14725 15200 15675 16150 16625Measured Depth (950 usft/in)MPH-06MPH-17MPU J-41 wp05MPI-01MPI-15MPI-15L1MPI-15PB1MPH-16L1MPH-16MPH-15MPS-35No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.WELL DETAILS:Plan: MPU J-40 NAD 1927 (NADCON CONUS)Alaska Zone 0433.40+N/-S +E/-W Northing EastingLatitudeLongitude0.000.006014704.42 552148.00 70° 27' 3.2782 N 149° 34' 28.3031 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU J-40, True NorthVertical (TVD) Reference: WELL @ 67.10usft (Original Well Elev)Measured Depth Reference:WELL @ 67.10usft (Original Well Elev)Calculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2024-07-17T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool33.70 1500.00 MPU J-40 wp06 (MPU J-40) GYD_Quest GWD1500.00 7800.00 MPU J-40 wp06 (MPU J-40) 3_MWD+IFR2+MS+Sag7800.00 16155.72 MPU J-40 wp06 (MPU J-40) GYD_Quest GWD0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)7600 8075 8550 9025 9500 9975 10450 10925 11400 11875 12350 12825 13300 13775 14250 14725 15200 15675 16150 16625Measured Depth (950 usft/in)MPH-06MPI-15MPI-15L1MPH-16L1MPH-15NO GLOBAL FILTER: Using user defined selection & filtering criteria33.70 To 16155.72Project: Milne PointSite: M Pt J PadWell: Plan: MPU J-40Wellbore: MPU J-40Plan: MPU J-40 wp06CASING DETAILSTVD TVDSS MD Size Name3789.79 3722.69 7800.00 9-5/8 9 5/8" x 12 1/4"4072.10 4005.00 16155.72 4-1/2 4 1/2" x 8 1/2" 1 Dewhurst, Andrew D (OGC) From:Dewhurst, Andrew D (OGC) Sent:Thursday, 22 August, 2024 16:40 To:Joseph Lastufka; Nathan Sperry Cc:Davies, Stephen F (OGC); Guhl, Meredith D (OGC); Rixse, Melvin G (OGC) Subject:RE: [EXTERNAL] MPU J-40 PTD (224-107): Question Joe, No problem. Thanks for the quick reply. Andy From: Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Sent: Thursday, 22 August, 2024 16:25 To: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Nathan Sperry <Nathan.Sperry@hilcorp.com> Cc: Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Subject: RE: [EXTERNAL] MPU J-40 PTD (224-107): Question Andy, That was my fault – mixed coordinates with another well on the form. The directional and the oƯsets (Section 4a) are correct. Sorry about that. Please replace page 1 with this updated version. Please let me know if you have any other questions. Thanks! Thanks, Joe Lastufka Sr. Drilling Technologist Hilcorp North Slope, LLC Office: (907)777-8400, Cell:(907)227-8496 From: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Sent: Thursday, August 22, 2024 4:18 PM To: Nathan Sperry <Nathan.Sperry@hilcorp.com> Cc: Joseph Lastufka <Joseph.Lastufka@hilcorp.com >; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Subject: [EXTERNAL] MPU J-40 PTD (224-107): Question Nate, The SHL coordinates listed on the 10-401 for the MPU J-40 well diīer from those on the associated direc Ɵonal plan. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. 2 Would you please conĮrm that these are the correct NAD27 SHL coordinates: Thanks, Andy Andrew Dewhurst Senior Petroleum Geologist Alaska Oil and Gas ConservaƟon Commission 333 W. 7th Ave, Anchorage, AK 99501 andrew.dewhurst@alaska.gov Direct: (907) 793-1254 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 7/2022 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 Number _____________, API Number 50-______________________. Production from or injection into this wellbore must be reported under the original API Number stated above. Spacing Exception The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce or inject is contingent upon issuance of a conservation order approving a spacing exception. The 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 nogreater than 30-foot sample intervals from below the permafrost or from where samples are first caught and 10-foot 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 this well until after the Operator has designed and implemented a water-well testing program to provide baseline data on water quality and quantity. The Operator must contact the AOGCC to obtain advance approval of such a 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 the Operator 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 all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. MPU J-40 224-107 MILNE POINT SCHRADER BLUFF OIL WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name:MILNE PT UNIT J-40Initial Class/TypeDEV / PENDGeoArea890Unit11328On/Off ShoreOnProgramDEVField & PoolWell bore segAnnular DisposalPTD#:2241070MILNE POINT, SCHRADER BLFF OIL - 525140NA1Permit fee attachedYesADL025906 and ADL3801092Lease number appropriateYes3Unique well name and numberYesMILNE POINT, SCHRADER BLFF OIL - 525140 - governed by CO 477, 477.0054Well located in a defined poolYes5Well located proper distance from drilling unit boundaryNA6Well located proper distance from other wellsYes7Sufficient acreage available in drilling unitYes8If deviated, is wellbore plat includedYes9Operator only affected partyYes10Operator has appropriate bond in forceYes11Permit can be issued without conservation orderYes12Permit can be issued without administrative approvalYes13Can permit be approved before 15-day waitNA14Well located within area and strata authorized by Injection Order # (put IO# in comments) (ForNA15All wells within 1/4 mile area of review identified (For service well only)NA16Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes20" 129.5# X-52 driven to 135'18Conductor string providedYes9-5/8" L-80 47# to BOPF, 9-5/8" L-80 40# to SB reservoir19Surface casing protects all known USDWsYes9-5/8" fully cemented from reservoir to surface. Two stage cement job through ported collar.20CMT vol adequate to circulate on conductor & surf csgYes9-5/8" fully cemented from reservoir to surface. Two stage cement job through ported collar.21CMT vol adequate to tie-in long string to surf csgYes9-5/8" fully cemented from reservoir to surface. Two stage cement job through ported collar.22CMT will cover all known productive horizonsYes9-5/8" L-80 47# to BOPF, 9-5/8" L-80 40 to SB reservoir23Casing designs adequate for C, T, B & permafrostYesDoyon 14 rig has adequate tankage and good trucking support24Adequate tankage or reserve pitNAThis is a grassroots well.25If a re-drill, has a 10-403 for abandonment been approvedYesHalliburton collision scan shows no close approaches with HSE risk.26Adequate wellbore separation proposedYes16" Diverter27If diverter required, does it meet regulationsYesAll fluids overbalanced to expected pore pressure.28Drilling fluid program schematic & equip list adequateYes1 annular, 3 ram stack tested to 3000 psi.29BOPEs, do they meet regulationYes13-5/8" , 5000 psi stack tested to 3000 psi.30BOPE press rating appropriate; test to (put psig in comments)YesDoyon 14 14 x 3-1/8" manual gate valves, 1 x 3-1/8" manual choke and 1 x 3-1/16" remote hydraulic choke.31Choke manifold complies w/API RP-53 (May 84)Yes32Work will occur without operation shutdownNoMonitoring will be required33Is presence of H2S gas probableNAThis is a development well.34Mechanical condition of wells within AOR verified (For service well only)YesRig will have detection equipment. J-10 had 10ppm H2S (2013).35Permit can be issued w/o hydrogen sulfide measuresYesReservoir anticipated to be normally pressured (8.45 ppg EMW). Multiple faults expected.36Data presented on potential overpressure zonesNA37Seismic analysis of shallow gas zonesNA38Seabed condition survey (if off-shore)NA39Contact name/phone for weekly progress reports [exploratory only]ApprADDDate22-Aug-24ApprMGRDate30-Jul-24ApprADDDate22-Aug-24AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDate*&:JLC 8/27/2024