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Home My WebLink About220-0291 Guhl, Meredith D (OGC) From:Guhl, Meredith D (OGC) Sent:Wednesday, June 29, 2022 10:02 AM To:Abbie Barker; Carrie Janowski; Cody Dinger; Darci Horner - (C); Donna Ambruz; Jerimiah Galloway; Joseph Lastufka; Josh Allely; Juanita Lovett; Tom Fouts Subject:PBU Expired Permits: 220-029, 220-031, and 220-033 Hello, The following Permits to Drill, issued to Hilcorp North Slope, have expired under Regulation 20 AAC 25.005 (g). The PTDs will be marked expired in the AOGCC database.  PBU K‐322, PTD 220‐029, issued 2 April 2020  PBU 11‐41, PTD 220‐031, issued 27 March 2020  PBU 04‐31A, PTD 220‐033, issued 31 March 202 If you have any questions, please contact me. Thank you, Meredith Meredith Guhl (she/her) Petroleum Geology Assistant Alaska Oil and Gas Conservation Commission 333 W. 7th Ave, Anchorage, AK 99501 meredith.guhl@alaska.gov Direct: (907) 793‐1235 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 Meredith Guhl at 907‐793‐1235 or meredith.guhl@alaska.gov. 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 Kenneth Allen Engineering Team Lead BP Exploration (Alaska), Inc. PO Box 196612 Anchorage, AK 99519-6612 Re: Prudhoe Bay Field, Lisburne Oil Pool, PBU K-322 BP Exploration (Alaska), Inc. Permit to Drill Number: 220-029 Surface Location: 3308’FSL, 4089’FEL, SEC. 04, T11N, R14E, UM Bottomhole Location: 2047’FSL, 3536’FEL, SEC. 34, T12N, R14E, UM Dear Mr. Allen: Enclosed is the approved application for the permit to drill the above referenced development well. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Jeremy M. Price Chair DATED this ___ day of April, 2020. Sincerely, Jeremy M Price 2 1a. Contact Name Minge, David Contact Email David.Minge@bp.comAuthorized Name Allen, Kenneth W Authorized Title Engineering Team Lead Authorized Signature Contact Phone +1 9075645279 Approved by: COMMISSIONER APPROVED BY THE COMMISSION Date: 5 22. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Drill Type of Work: Redrill Lateral 1b.Proposed Well Class:Exploratory - Gas 5 Service - WAG 5 1c. Specify if well is proposed for: Development - Oil Service - Winj Multiple Zone Exploratory - Oil Gas Hydrates Geothermal BP Exploration (Alaska), Inc Bond No. 29S105380 11.Well Name and Number: PBU K-322 TVD:14654'8653' 12. Field/Pool(s): PRUDHOE BAY, LISBURNE OIL MD: ADL 028303 & 028300 95-001 June 1, 2020 4a. Surface: Top of Productive Horizon: Total Depth: 3308' FSL, 4089' FEL, Sec. 04, T11N, R14E, UM 3319' FSL, 516' FEL, Sec. 04, T11N, R14E, UM 2047' FSL, 3536' FEL, Sec. 34, T12N, R14E, UM Kickoff Depth:300 feet Maximum Hole Angle: 108 degrees Maximum Anticipated Pressures in psig (see 20 AAC 25.035) Downhole:Surface:3488 2614 17.Deviated wells:16. Surface: x- y- Zone -671459 5975249 ASP 4 10. KB Elevation above MSL: GL Elevation above MSL: feet feet 72.92 23.70 15.Distance to Nearest Well Open to Same Pool: Cement Quantity, c.f. or sacks MD Casing Program: Surface Surface Surface Surface 7721' 8680' 19.PRESENT WELL CONDITION SUMMARY Production Surface Seabed Report Drilling Fluid Program 5 20 AAC 25.050 requirements Shallow Hazard Analysis 5 Date Commission Use Only See cover letter for other requirements: Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales: Samples req'd: Yes No H2S measures Yes No Spacing exception req'd: Yes No Mud log req'd: Yes No Directional svy req'd: Yes No Inclination-only svy req'd: Yes No Other: Date 21. Address: Location of Well (State Base Plane Coordinates - NAD 27): 215.5#A-53 9521' TVDCement Volume 20"x34"80' 5128' Intermediate Conductor/Structural Single Zone Service - Disp NoYesPost initial injection MIT req'd: NoYes 5 Diverter Sketch STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 Stratigraphic Test Development - Gas Service - Supply Coalbed Gas Shale Gas 2.Operator Name: 5.Bond Blanket 5 Single Well 3. P.O. Box 196612 Anchorage, AK 99519-6612 6. Proposed Depth: 7. Property Designation (Lease Number): 8. DNR Approval Number:13.Approximate spud date: 9.Acres in Property: 14. 12500 Distance to Nearest Property: Location of Well (Governmental Section): 4b. 2560 2400 18.Specifications Top - Setting Depth - Bottom Casing Weight Grade TVDHole Coupling MDLengthTVD (including stage data) 42" 16" 12-1/4" 8-1/2" 6-1/8" 13-3/8" 9-5/8" 7" 4-1/2" 68# 47# 26# 12.6# L-80 L-80 L-80 BTC Vam 21 VamTop H VamTop 3982' 8596' 1225' Surface Surface 8446' 80' 3982' 8596' 9671' 14654' 80' 3702' 7856' 8808' 8653' 260 sx Arctic Set (Approx.) 2153 sx LiteCrete, 312 sx Class 'G' 629 sx LiteCrete, 163 sx Class 'G' 276 sx Class 'G' 562 sx Class 'G' (To be completed for Redrill and Re-Entry Operations) Total Depth MD (ft): Total Depth TVD (ft):Plugs (measured):Effect. Depth MD (ft): Effect. Depth TVD (ft):Junk (measured): Casing Length Size MD Liner Perforation Depth MD (ft):Perforation Depth TVD (ft): 20. Attachments Property Plat 5 BOP Sketch 5 Drilling Program 5 Time v. Depth Plot Verbal Approval: Permit to Drill Number:API : 50-Permit Approval Date: Commission Representative: Reentry 13Cr85 Hydraulic Fracture planned? Form 10-401 Revised 5/2017 This permit is valid for 24 months from the date of approval (20 AAC 25.005(g))Submit Form and Attachments in Duplicate By Samantha Carlisle at 8:27 am, Mar 18, 2020 Kenneth Allen Digitally signed by Kenneth Allen Date: 2020.03.17 16:41:01 -08'00' X X *BOPE Test to 3500 psi *Approved variance to 20 AAC 25.033 - No flow paddle required for first 1000' MD of drlg *Approved variance to 20 AAC 25.030 (f) no FIT required on 7" casing shoe if 7" liner is fully cemented. X X 029-23672-00-00 X CDW 03/18/2020 DSR-3/18/2020 X 220-029 X MGR19MAR20 DLB 03/31/20 *CO 721 provides comingling of Ivishak and Lisburne oil pools. *10-403 Required for acid stimulation lly cemented. 20 MGRGGGGGGRGRGGGGRGGGGG19MAR20 es cesscesscesssceses cessessscssssscsseesesscssccominglingngngngnggngnnggngnnngnggggggggggg of Ioovishakhahakakhakakhakkakhahakakhakahahakhakakhakhahakakhakaaahakahahakhaa and L 4/2/2020 K-322 PTD 1 3/17/2020 To: Alaska Oil & Gas Conservation Commission From: David Mingé, ODE Date: March 17, 2020 RE: K-322 Permit to Drill The K-322 well is scheduled to be drilled by Parker 272 in May 2020. This grassroots well is a horizontal producer targeting the Lisburne (Wahoo). The planned well is a four string, big-bore design using 13-3/8” surface casing, 9-5/8” intermediate casing, 7” intermediate liner and 4-1/2” production liner. The surface casing will be set in the SV4. The first and second intermediate strings will be set in the HRZ and top Lisburne, respectively. The production interval will be completed with a cemented and perforated liner. Maximum anticipated surface pressure will be from the Lisburne. With a full column of gas, MASP from Lisburne to surface is 2614 psi (7.7 ppg EMW in Lisburne at 9035’ TVDss with 0.1 psi/ft gas gradient). The well will be drilled by Parker 272 using their 5000 psi four preventer BOP stack (3 rams and an annular). The BOP rams and annular will be tested to 3500 psi. A detailed operations summary is included with the permit application. If there are any questions concerning information on K-322, please do not hesitate to use the contact information below. David Mingé Office: (907) 564-4061 Cell: (907) 250-2917 Email: david.minge@bp,com Attachments: Well Bore Schematic Directional Package BOPE Schematic Diverter Line Layout Diagram As-Staked Survey K-322 PTD 2 3/17/2020 Planned Well Summary Well K-322 Well Type Producer Target Objective Lisburne Current Status Grass Roots Well Estimated Start Date: 06/01/2020 Time to Complete: 29 Days Surface Location Northing Easting Offsets TRS 5,975,249 671,459 3308’ FSL / 4089’ FEL 11N 14E Sec 4 Northing Easting TVDss Offsets TRS TLSB 5,975,342 675,031 8733’ 3319’ FSL / 516’ FEL 11N 14E Sec 4 BHL 5,979,402 677,188 8580’ 2047’ FSL / 3536’ FEL 12N 14E Sec 34 Planned KOP: 300’ MD Planned TD: 14,654’ MD / 8580’ TVDss Rig: Parker 272 GL-RT: 47.1 RTE (ref MSL): 72.9 Directional – WP17 Maximum Hole Angle: ~27° in the surface section ~27° in the intermediate 1 section ~31° in the intermediate 2 section ~108° in the production section Close Approach Wells: All offset wells pass BP anti-collision scan criteria, but some offsets must be shut-in to pass scan criteria – reference “Surface and Anti- Collision Issues” section. Survey Program: Reference attached directional program Nearest Property Line: ~12,500’ Nearest Well within Pool: ~2400’ Hydraulic Fracture Planned? No K-322 PTD 3 3/17/2020 Formation Tops and Pore Pressure Estimate Formation Estimated Formation Top (TVDss) Most Likely Pore Pressure (EMW ppg) Fluid Type (for sands) BPRF 1820 8.4 SV5 2945 8.4 Water SV4 3205 8.4 Water SV3 3679 8.4 Water SV2 3819 8.4 Water SV1 4208 8.4 Water UG4 4638 9.3 Water UG3 4865 9.3 Water UG1 5378 9.3 Water WS2 5979 9.2 Water CM3 6373 9.2 CM2 7022 9.7 CM1 7378 9.9 THRZ 7623 9.9 LCU 7843 10.2 TJA 7938 10.2 TSGR 8038 7.71 Gas SHUBLIK 8086 7.67 Gas TSAD 8136 7.64 Gas/Oil TKVK 8611 9.9 TLSB 8733 7.68 Oil K-322 PTD 4 3/17/2020 Casing/Tubing Program Hole Size Casing / Tbg O.D. Wt/Ft Grade Conn Length Top MD / TVDss Bottom MD / TVDss 42” 20” x 34” 215.5# A-53 - 80’ Surface 127’ / 56’ 16” 13-3/8” 68# L-80 BTC 3982’ Surface 3982’ / 3629’ 12-1/4” 9-5/8” 47# L-80 Vam 21 8596’ Surface 8596’ / 7783’ 8-1/2” 7” 26# L-80 Vam Top HC 1225’ 8446’ / 7648’ (150’ lap) 9671’ / 8735’ 6-1/8” 4-1/2” 12.6# 13Cr-85 Vam Top 5128’ 9521’ / 8607’ (150’ lap) 14654’ / 8580’ Mud Program Surface Mud Properties: MMH Depth Interval Density (ppg) PV (cp) YP (lb/100ft2) Surface – 16” TD (SV4) 8.5 – 9.1 6-20 35-80 Intermediate 1 Mud Properties: LSND Depth Interval Density (ppg) PV (cp) YP (lb/100ft2) 13-3/8” Shoe – SV1 8.7 – 9.0 10-20 20-30 UG4 – CM3 9.6 – 9.9 10-20 20-30 CM2 – CM1 9.9 – 10.4 10-20 20-30 HRZ 10.2 – 10.5 10-20 20-30 Intermediate 2 Mud Properties: LSND Depth Interval Density (ppg) PV (cp) YP (lb/100ft2) 9-5/8” Shoe – TD 10.2 – 10.5 10-20 20-30 Production Mud Properties: Water Based Polymer Fluid Depth Interval Density (ppg) PV (cp) YP (lb/100ft2) 7” Shoe - TD 8.5 – 9.0 <12 12-20 Logging Program Surface Sample Catchers - not required for surface hole Drilling: Dir/GR Open Hole: None Cased Hole: None Intermediate 1 Sample Catchers – as required by Geology Drilling: Dir/GR/RES Open Hole: None Cased Hole: None Intermediate 2 Sample Catchers – as required by Geology Drilling: Dir/GR/RES Open Hole: None Cased Hole: None Production Sample Catchers – as required by Geology Drilling: Dir/GR/RES/NEU/DEN Open Hole: None Cased Hole: None K-322 PTD 5 3/17/2020 Cement Program Surface Basis Lead Open hole volume + 300% excess in permafrost / 40% excess below permafrost Lead TOC Surface Tail Open hole volume + 40% excess + 80 ft shoe track Tail TOC 500 ft MD above casing shoe Total Cement Volume Spacer ~100 bbls of 10 ppg Viscosified Spacer (Mud Push II) Lead 732.5 bbls, 4113 cuft, 2153 sks 11.0 ppg LiteCRETE - 1.91 cuft/sk Tail 64.4 bbls, 362 cuft, 312 sks 15.8 ppg Class G – 1.16 cuft/sk Temp BHST 60° F Intermediate 1 Basis Lead Open hole volume + 0% excess Lead TOC 500 ft MD above TUG4 Tail Open hole volume + 0% excess + 80 ft shoe track Tail TOC 500 ft MD above casing shoe Total Cement Volume Spacer ~50 bbls of 13 ppg Viscosified Spacer (Mud Push II) Lead 194.9 bbls, 1094 cuft, 629 sks 11.5 ppg LiteCRETE - 1.74 cuft/sk Tail 33.7 bbls, 189 cuft, 163 sks 15.8 ppg Class G – 1.16 cuft/sk Temp BHST 150° F Intermediate 2 Basis Lead N/A Lead TOC N/A Tail Open hole volume + 40% excess + 150 ft liner lap + 650 ft 7” LNR x 9-5/8” CSG + 80 ft shoe track Tail TOC Top of liner Total Cement Volume Spacer ~30 bbls of 13 ppg Viscosified Spacer (Mud Push II) Lead N/A Tail 57.5 bbls, 323 cuft, 276 sks 15.8 ppg Class G – 1.17 cuft/sk Temp BHST 150° F Production Basis Lead N/A Lead TOC N/A Tail Open hole volume + 30% excess + 150 ft liner lap + 200 ft 4” DP x LNR + 80 ft shoe track Tail TOC Top of liner Total Cement Volume Spacer ~50 bbls of 12 ppg Viscosified Spacer (Mud Push II) Lead N/A Tail 117.1 bbls, 657 cuft, 562 sks 15.8 ppg Class G – 1.17 cuft/sk Contingency: 8.6 ppg Bimodal (volume scaled to severity of loss rate) Temp BHST 190° F K-322 PTD 6 3/17/2020 Surface and Anti-Collision Issues Surface Close Proximity: No wells will be affected by the Parker 272 rig shadow. Sub-Surface Pressure Management: No wells will be shut-in for reservoir pressure purposes while drilling. Anti-Collision: All offset wells pass BP anti-collision scan criteria, but some offsets must be shut-in to pass scan criteria: x K-17A: Shut-in at surface during INT2 section drilling Offset Well Ownership Information All offset wells identified within 200 ft of the proposed wellbore are operated by BP. Hydrogen Sulfide Reference “Drilling Critical Issues” section. Faults Reference “Drilling Critical Issues” section. Drilling Waste Disposal x There is no annular injection in this well. x Cuttings Handling: Cuttings generated from drilling operations will be hauled to grind and inject at DS-04. Any metal cuttings will be sent to the North Slope Borough. x Fluid Handling: Haul all drilling and completion fluids and other Class II wastes to DS-04 for injection. Haul Class I waste to DS-04 and/or Pad 3 for disposal. Contact the GPB Environmental Advisors (659-5893) for guidance. K-02 fails 'major risk'. This well is abandoned. K-322 PTD 7 3/17/2020 Well Control The 16” surface hole will be drilled with a diverter (see attached diverter layout). The 12-1/4”, 8-1/2” and 6-1/8” hole sections will be drilled with well control equipment consisting of 5000 psi working pressure rams (2), blind/shear rams, and annular preventer capable of handling the maximum potential surface pressures. Based upon calculations below, BOP equipment will be tested to 3500 psi. BOP test frequency for K-322 will be 14 days with function test every 7 days. Except in the event of a significant operational issue that may affect well integrity or pose safety concerns, an extension to the 14-day BOP test period should not be requested. 12-1/4” Intermediate 1 Interval Maximum anticipated BHP 3055 psi at the BWS2 at 6386’ TVDss (9.2 ppg EMW) Maximum surface pressure 2417 psi at the BWS2 (0.10 psi/ft gas gradient to surface) Kick tolerance >25 bbls with 11.6 ppg frac gradient. Assumes 9.2 ppg pore pressure in the BWS2 + 0.5 ppg kick intensity and 10.4 ppg MW. Planned BOP test pressure Rams test to 3500 psi / 250 psi Annular test to 3500 psi / 250 psi Integrity Test – 12-1/4” hole LOT after drilling 20’-50’ of new hole 9-5/8” Casing Test 3500 psi surface pressure 8-1/2” Intermediate 2 Interval Maximum anticipated BHP 3488 psi at the TLSB at 8733’ TVDss (7.7 ppg EMW) Maximum surface pressure 2614 psi at the TLSB (0.10 psi/ft gas gradient to surface) Kick tolerance >25 bbls with 11.7 ppg frac gradient. Assumes a 7.7 ppg pore pressure in the LSB + 0.5 ppg kick intensity and 10.7 ppg MW. Planned BOP test pressure Rams test to 3500 psi / 250 psi Annular test to 3500 psi / 250 psi Integrity Test – 8-1/2” hole LOT after drilling 20’-50’ of new hole 7” Liner Test 3500 psi surface pressure 6-1/8” Production Interval Maximum anticipated BHP 3613 psi in the LSB at 9035’ TVDss (7.7 ppg EMW) Maximum surface pressure 2709 psi in the LSB (0.10 psi/ft gas gradient to surface) Kick tolerance Assumed infinite Planned BOP test pressure Rams test to 3500 psi / 250 psi. Annular test to 3500 psi / 250 psi Integrity Test – 6-1/8” hole N/A – reference variance request 4-1/2” Liner Top Packer Test 3500 psi surface pressure Planned completion fluids 8.5 ppg seawater / ~2000’ 6.8 ppg diesel cap K-322 PTD 8 3/17/2020 Variance Requests 1. To avoid the risk of plugging the flow line with large rocks and wood encountered while drilling surface hole, it is requested to drill without a flow paddle for the first portion of the surface hole. After drilling past the larger rocks and wood sections, the flow paddle will be put back in the flow line (<1000 ft). This is a variance from 20 AAC 25.033. Procedures/Safeguards with paddle removed: x Fluid levels will be monitored in the pits for both gains and losses while drilling. Alarms will be set to indicate if gain or loss of more than 10 bbls has occurred. x The well will be monitored for flow when the pumps are off at each connection. x The planned 8.5 – 9.1 ppg fluid will provide over balance to formation fluid. 2. Production Hole FIT: Given that the planned depth of the intermediate 2 liner is at the top of the target reservoir (Lisburne), and the production hole planned well path does not depart from the reservoir, a variance from 20 AAC 25.030(f) is requested to forgo the FIT in production hole. If there are problems during the intermediate cement job (i.e. losses) which jeopardize the ability to meet AOGCC or BP cementing requirements, or there is U-tube upon drilling out the shoe, this variance will not apply. 7" liner cementing report to be provided to AOGCC for approval to fore go FIT. K-322 PTD 9 3/17/2020 Drill and Complete Operations Summary Pre-Rig Operations 1. Install 20” conductor and cellar box. Weld landing ring. Survey. Rig Operations 1. MIRU Parker 272. 2. Nipple up diverter system and function test. 3. MU 16” surface motor drilling assembly with 5” DP and drill to TD. Wiper trip. POOH and LD drilling assembly. 4. Run 13-3/8” casing to TD and cement. Test casing to 3500 psi. 5. Nipple down diverter system. Nipple up 13-5/8” wellhead system. Nipple up BOPE and test to 3500 psi. BOP configuration (top-bottom): annular, 9-5/8” FBR, blind/shear, mud cross, 2-7/8” x 5” VBR. 6. MU 12-1/4” intermediate #1 drilling assembly with 5” DP. Drill shoe track and 20’-50’ formation. 7. Perform LOT. 8. Drill 12-1/4” section to TD in the HRZ formation. POOH and LD drilling assembly. 9. Run 9-5/8” casing to TD and cement. Test casing to 3500 psi. 10. Install 9-5/8” casing packoff and test to 3500 psi. Inject freeze protect into 9-5/8” x 13-3/8” annulus. 11. Change upper ram to 4-1/2” x 7” VBR and test. 12. MU 8-1/2” intermediate #2 drilling assembly with tapered 4” x 5” DP. Drill shoe track and 20’- 50’ formation. 13. Perform LOT. 14. Drill 8-1/2” section to TD in the top Lisburne. POOH and LD drilling assembly. 15. Run 7” liner to TD and cement. POOH and LD liner running assembly. Test liner to 3500 psi. 16. MU 6-1/8” production drilling assembly with tapered 4” x 5” DP. 17. Drill 6-1/8” section to TD in the Lisburne formation. POOH and LD drilling assembly. 18. Run 4-1/2” liner to TD and cement. Set hanger and liner top packer. POOH and LD liner running assembly. 19. Test liner / liner top packer to 3500 psi. 20. Run ~2000’ of 2-7/8” guns (production liner) and ~30’ of 4-5/8” guns (perforate 7” liner for Sag River in-situ GL) and perforate. 21. Run and land 4-1/2” completion. 22. Drop B&R and set production packer. Individually test tubing and IA to 3500 psi. 23. Shear GLV and circulate freeze protect to ~2000’ TVD. Set TWC and test to 3500 psi. 24. Nipple down BOPE. Nipple up adapter and dry hole tree and test to 4500 psi. 25. RDMO Parker 272. Dual packer completions - needs clarification. report and casing test digital data to AOGCC. 24 hour notice to AOGCC to witness. Casing test and LOT digital data to AOGCC. 24 hour notice to AOGCC to witness. Operations cementing Casing test and LOT digital data to AOGCC. * * Per CO 721: comingling of Ivishak & Lisburne approved on K-322. Therefore a test of the lower completion packer not required. K-322 PTD 10 3/17/2020 Post-Rig Operations 1 V Install tree. Pull TWC. 2 S Pull B&R. Set DGLV. 3 C Set retainer/CBP. Acid job. Mill retainer/CBP. Estimate 5 stages. 4 S Set LGLVs. SBHP. 5 T Flowback test. 10-403 will be required for acid stimulation. K-322 PTD 11 3/17/2020 K-322 Drilling Critical Issues POST THIS NOTICE IN THE DOGHOUSE I. Well Control / Reservoir Pressures A. Surface Hole: The permafrost and SV formation are expected to be normally pressured at 8.4 ppg EMW. Pore pressures will be controlled with 8.5 – 9.1 ppg water based mud. B. Intermediate 1 Hole: The Ugnu and WS formation are expected to be at 9.3 and 9.2 ppg EMW, respectively. Pore pressures will be controlled with a 9.6 – 10.5 ppg water based mud. C. Intermediate 2 Hole: The Sadlerochit formation is expected to be 7.3 – 7.7 ppg EMW. The Lisburne formation is expected to be at 7.7 ppg EMW at casing point. Pore pressures will be controlled with a 10.2 – 10.5 ppg water based mud. D. Production Hole: The Lisburne is expected to be at 7.7 ppg EMW. Reservoir pressures will be controlled by using 8.5 – 9.0 ppg water based mud. II. Lost Circulation/Breathing A. Surface Hole: There are no expected fault crossings. Be alert for surface broaching in offset wells. B. Intermediate 1 Hole: There are no expected fault crossings. Be aware of wellbore breathing risk in the Colville formation. Keep drilling ECDs below hard line. C. Intermediate 2 Hole: There is one fault crossing. Be aware of lost circulation risk at casing point. D. Production Hole: There are five expected fault crossings. Expect lost circulation. III. Fault Locations Formation Where Fault Encountered MD Intersect TVDss Intersect Throw Direction and Magnitude Uncertainty Lost Circ Potential Fault 1 / Lisburne 10150’ 9019’ N / 25’ <200’ Medium Fault 2 / Lisburne 10818’ 8898’ W / 25’ <200’ Low Fault 3 / Lisburne 13179’ 8838’ S / 190’ <200’ High Fault 4 / Lisburne 14283’ 8669’ W / 40’ <200’ Low IV. Integrity Testing V. Hydrogen Sulfide K-Pad is not an H2S site. Recent H2S data from the pad is as follows: Well Name H2S Level Date of Reading #1 Closest SHL Well H2S Level K-317 15 03/15/2018 #2 Closest SHL Well H2S Level K-04C 10 01/08/2018 #1 Closest BHL Well H2S Level K-317 15 03/15/2018 #2 Closest BHL Well H2S Level L1-23 25 01/03/2019 #3 Closest BHL Well H2S Level K-19B 12 07/07/2018 Max Recorded H2S on Pad/Facility K-10C 30 02/03/2014 VI. Anti-Collision Issues All offset wells pass BP anti-collision scan criteria, but some offsets must be shut-in to pass scan criteria: x K-17A: Shut-in at surface during INT2 section drilling CONSULT THE K-PAD DATA SHEET AND THE WELL PLAN FOR ADDITIONAL INFORMATION. Test Point Test Depth Test type EMW (lb/gal) 13-3/8” Shoe 20’-50’ from the 13-3/8” shoe LOT 11.6 ppg 9-5/8” Shoe 20’-50’ from the 9-5/8” shoe LOT 11.7 ppg K-17A perfed in the Ivishak where collision would occur. - K-02 fails 'major risk' per BPXA this well is an abandoned 13-3/8" casing string. !""#! $%!% & ' ()* ' " + % & ! 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WELL PERMIT CHECKLISTCompanyBP Exploration (Alaska) Inc.Well Name:PRUDHOE BAY UN LIS K-322Initial Class/TypeDEV / PENDGeoArea890Unit11650On/Off ShoreOnProgramDEVField & PoolWell bore segAnnular DisposalPTD#:2200290PRUDHOE BAY, LISBURNE OIL - 640144NA1 Permit fee attachedYes2 Lease number appropriateYes3 Unique well name and numberYes4 Well located in a defined poolYes5 Well located proper distance from drilling unit boundaryYes6 Well located proper distance from other wellsYes7 Sufficient acreage available in drilling unitYes Directional plan view & wellbore profile included.8 If deviated, is wellbore plat includedYes9 Operator only affected partyYes10 Operator has appropriate bond in forceNo Spacing Exception required.11 Permit can be issued without conservation orderNo12 Permit can be issued without administrative approvalYes13 Can permit be approved before 15-day waitNA14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (ForNA15 All wells within 1/4 mile area of review identified (For service well only)NA16 Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes 20" x 34" A-53 cemented in place18 Conductor string providedYes 13-3/8" surface to 3629' ssTVD fully cemented19 Surface casing protects all known USDWsYes20 CMT vol adequate to circulate on conductor & surf csgYes Intermediate 1 casing cemented from Ivishak to 500' above UG421 CMT vol adequate to tie-in long string to surf csgYes Int 2 liner fully cemented across the Ivishak22 CMT will cover all known productive horizonsYes23 Casing designs adequate for C, T, B & permafrostYes Parker 272 has adequate tankage and good trucking support.24 Adequate tankage or reserve pitNA This is a grass roots well. - Not applicable25 If a re-drill, has a 10-403 for abandonment been approvedYes K-02 offset fully abandoned. K-17 perforated as drill by in the Ivishak. Will be shut in.26 Adequate wellbore separation proposedYes Drawing included.27 If diverter required, does it meet regulationsYes All fluids overbalance to pore pressure.28 Drilling fluid program schematic & equip list adequateYes 1 annular, 3 ram, 1 flow cross stack29 BOPEs, do they meet regulationYes 5000 psi stack , tested to 3500 psi30 BOPE press rating appropriate; test to (put psig in comments)Yes31 Choke manifold complies w/API RP-53 (May 84)Yes32 Work will occur without operation shutdownNo No wells on K pad >100 ppm H2S33 Is presence of H2S gas probableNA This is a development well.34 Mechanical condition of wells within AOR verified (For service well only)No K-Pad wells are H2S-bearing. H2S measures are required.35 Permit can be issued w/o hydrogen sulfide measuresYes36 Data presented on potential overpressure zonesNA37 Seismic analysis of shallow gas zonesNA38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprDLBDate3/18/2020ApprMGRDate3/19/2020Appr DateAdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDate-03 dts4/1/2020JLC 4/2/2020