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220-031
1 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, Prudhoe Oil Pool, PBU 11-41 BP Exploration (Alaska), Inc. Permit to Drill Number: 220-031 Surface Location: 656’FSL, 275’FEL, SEC. 28, T11N, R15E, UM Bottomhole Location: 5807’FNL, 3081’FEL, SEC. 16, T11N, R15E, 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 March, 2020. Sincerely, Jeremy M Price 27 1a. Contact Name:Nocas, Noel Contact Email:Noel.Nocas@bp.comAuthorized Name:Allen, Kenneth W Authorized Title:Engineering Team Lead Authorized Signature: Contact Phone:+1 9075645027 Approved by: COMMISSIONER APPROVED BY THE COMMISSION Date: 5 21. 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 11-41 TVD:15434'8620' 12. Field/Pool(s): PRUDHOE BAY, PRUDHOE OIL MD: ADL 028325 & 028322 70-054 July 1, 2020 4a. Surface: Top of Productive Horizon: Total Depth: 656' FSL, 275' FEL, Sec. 28, T11N, R15E, UM 3812' FNL, 2314' FEL, Sec. 21, T11N, R15E, UM 5807' FNL, 3081' FEL, Sec. 16, T11N, R15E, UM Kickoff Depth:500 feet Maximum Hole Angle: 109 degrees Maximum Anticipated Pressures in psig (see 20 AAC 25.035) Downhole:Surface:3305 2437 17.Deviated wells:16. Surface: x- y- Zone -707258 5952373 ASP 4 10. KB Elevation above MSL: GL Elevation above MSL: feet feet 75.1 28.00 15.Distance to Nearest Well Open to Same Pool: Cement Quantity, c.f. or sacks MD Casing Program: Surface Surface Surface Surface 8202' 19.PRESENT WELL CONDITION SUMMARY Production Surface Seabed Report Drilling Fluid Program 5 20 AAC 25.050 requirements Shallow Hazard Analysis 5 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: Address: Location of Well (State Base Plane Coordinates - NAD 27): 129.45#X-6520"x34"80' Intermediate Conductor/Structural Single Zone Service - Disp No YesPost initial injection MIT req'd: No Yes 5 Diverter Sketch Sr Pet Eng Sr Res Eng TVD 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. 34406 Distance to Nearest Property: Location of Well (Governmental Section): 4b. 2560 250 18.Specifications Top - Setting Depth - Bottom Casing Weight Grade TVDHole Coupling MDLengthTVD (including stage data) 42" 13-1/2" 9-7/8" 6-1/8" 10-3/4" 7" 4-1/2" 45.5# 26# 12.6# L-80 13Cr85 L-80 Vam 21 VamTop HC VamTop 4025' 11290' 4290' Surface Surface 11140' 80' 4025' 11290' 15430' 80' 3701' 8335' 8620' 260 sx Arctic Set (Approx.) 2076 sx LiteCrete, 257 sx Class 'G' 490 sx Class 'G' 490 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 BOP Sketch 55 Drilling Program 55 Time v. Depth Plot Permit to Drill Number:API Number : 50-Permit Approval Date: Reentry Hydraulic Fracture planned? CementVolume Sr PetGeo Form 10-401 Revised 3/2020 This permit is valid for 24 months from the date of approval (20 AAC 25.005(g)) Kenneth Allen Digitally signed by Kenneth Allen Date: 2020.03.24 05:56:56 -08'00' By Samantha Carlisle at 8:57 am, Mar 24, 2020 50-029-23674-00-00 SFD 3/24/2020 *BOPE test to 3500 psi *Approved variance to 20 AAC 25.033 - No flow paddle required for first 1000' MD of drilling *Approved variance to 20 AAC 25.030 (f) no FIT required on 7" casing shoe if 7" casing cementing report provided to AOGCC for review and approval MGR26MAR2020 DSR-3/26/2020 220-031 variance to 20 AAC 25.030 (f) eeeeeeeeeeporppopppopppppppopppoppppopppt provided to AOGCGCOGCCOGCOGCGCGOGCGCCGGCOGCGCOGCGCCGCGCCGCCGCGOGCGC for MAR2R2R2R222RR22R2R2R22R222R22R2222222020 3/27/2020 3/27/2020 5207 272 11-41 PTD 1 3/21/2020 To: Alaska Oil & Gas Conservation Commission From: Noel Nocas, ODE Date: March 21, 2020 RE: 11-41 Permit to Drill The 11-41 is scheduled to be drilled by Parker 272 in July 2020. This grassroots well is a horizontal producer in Zone 1 of the Ivishak. The planned well is a three-string Modified-Slimhole design utilizing 10-3/4” Surface Casing, 7” Intermediate Casing, and 4-1/2” Production Liner. The surface casing will be set in the SV4 shale, intermediate casing at the top of the Ivishak and the production interval will be cemented and perforated. The maximum anticipated surface pressure from the Ivishak with a full column of gas from TD to surface is 2437 psi (assumes 7.32 ppg EMW most likely pore pressure and a 0.1 psi/ft gas gradient). The well will be drilled by Parker 272 using their 5,000 psi four preventer BOP stack (3 rams and an annular). The BOP rams and annular will be tested to 3,500 psi. A detailed operations summary is included with the permit application. If there are any questions concerning information on 11-41, please do not hesitate to use the contact information below. Noel Nocas Office: (907) 564-5027 Cell: (907) 229-9532 Email: noel.nocas@bp.com Attachments: Well Bore Schematic Directional Package BOPE Schematic Diverter Line Layout Diagram 11-41 PTD 2 3/21/2020 Planned Well Summary Well 11-41 Well Type Producer Target Objective Ivishak Current Status Grass Roots Well Estimated Start Date: July 2020 Time to Complete: 25 Days Approximate Surface Location Northing Easting Offsets TRS 5,952,373.00 707,258.00 656.00’ FSL / 275.24’ FEL 11N 15E Sec 28 *BP will update the AOGCC with As-Staked and As-Built as they are received Northing Easting TVDss Offsets TRS TSAD 5,958,406.32 705,039.37 8,270.5 3811.9’ FNL / 2313.8’ FEL 11N 15E Sec 21 BHL 5,962,268.19 704,156.95 8,545.0 5207.1’ FNL / 3081.19’ FEL 11N 15E Sec 16 Planned KOP: 500’ MD Planned TD: 15,43’ MD / 8,545’ TVDss Rig: Parker 272 GL-RT: 47.1 RTE (ref MSL): 75.1 Directional – BH WP06 Maximum Hole Angle: ~53° in the surface section ~53° in the intermediate section ~10 ° 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: ~34,406’ Nearest Well within Pool: ~250’ Hydraulic Fracture Planned? No 11-41 PTD 3 3/21/2020 Formation Tops and Pore Pressure Estimate Formation Estimated Formation Top (TVDss) Most Likely Pore Pressure (EMW ppg) Fluid Type (for sands) G1 443 8.4 BPRF 1866 8.4 SV6 2330 8.4 Water SV5 3092 8.4 Water SV4 3226 8.4 Water SV3 3704 8.4 Water SV2 3893 8.4 Water SV1 4293 8.4 Water UG4 4827 9.5 Water UG3 5000 9.5 Water UG1 5695 9.5 Water WS2 6364 9.3 Water WS1 6455 9.3 Water CM3 6697 9.7 Possible hydrocarbons CM2 7139 9.8 Possible hydrocarbons CM1 7685 10 Possible hydrocarbons THRZ 8048 10 BHRZ 8247 10 LCU 8259 7.59 TSAD 8271 7.58 Gas 42N 8333 7.54 42P 8336 7.54 Gas TCGL 8391 7.5 Gas BCGL 8437 7.47 Gas 24N 8517 7.42 24P 8526 7.41 Gas 22N 8569 7.39 22P 8585 7.38 Gas 14N 8635 7.35 TDF 8664 7.33 Gas BSAD 8682 7.32 Oil Supersceded on following page. 11-41 PTD 4 3/21/2020 Casing/Tubing Program Hole Size Casing / Tbg O.D. Wt/Ft Grade Conn Length Top MD / TVDss Bottom MD / TVDss 42” 20” x 34” 129.45# X-65 - ~80’ Surface 127’ / 52’ 13-1/2” 10-3/4” 45.5# L-80 Vam 21 4,025’ Surface 4,025’ / 3,626’ 9-7/8” 7” 26# L-80 VamTop HC 11,290’ Surface 11,290’ / 8,260’ 6-1/8” 4-1/2” 12.6# 13Cr-85 Vam Top 4,290’ 11,140’ / 8,127’ (150’ lap) 15,430’ / 8,545’ Tubing 4-1/2” 12.6# 13Cr-85 Vam Top 11,140’ Surface 11,145’ / 8,130’ (~5’ into liner TBS) Mud Program Surface Mud Properties: MMH Depth Interval Density (ppg) PV (cp) YP (lb/100ft2) Surface – 13-1/2” TD (SV5) 8.5 – 9.1 6-20 35-80 Intermediate Mud Properties: LSND Depth Interval Density (ppg) PV (cp) YP (lb/100ft2) 10-3/4” Shoe – CM3 9.1 – 9.8 10-20 20-30 CM2 – CM1 9.8 – 10.2 10-20 20-30 HRZ – 9-7/8” TD (TSGR) 10.3 – 10.8 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 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 11-41 PTD 5 3/21/2020 Cement Program Surface Basis Lead Open hole volume + 350% excess in permafrost and 40% excess below permafrost Lead TOC Target surface Tail Open hole volume + 40% excess + 85 ft shoe track Tail TOC 500 ft MD above casing shoe Total Cement Volume Spacer ~100 bbls of Viscosified Spacer weighted to ~10.5 ppg (Mud Push II) Lead 706 bbls, 3965 cuft, 2076 sks of 11.0 ppg LiteCRETE – 1.91 cuft/sk Tail 53 bbls, 298 cuft, 257 sks 15.8 ppg Class G – 1.16 cuft/sk Temp BHST 67° F Intermediate Basis Lead N/A Lead TOC N/A Tail Open hole volume + 40% excess + 85 ft shoe track Tail TOC 1500 ft MD above casing shoe Total Cement Volume Spacer ~50 bbls of Viscosified Spacer weighted to ~11-13 ppg (Mud Push II) Lead N/A Tail 102.2 bbls, 574 cuft, 49 sks 15.8 ppg Class G – 1.17 cuft/sk Temp BHST 166° F Production Basis Lead N/A Lead TOC N/A Tail Open hole volume + 30% excess + 85 ft shoe track + liner lap + 200’ 4” DP x 7” CSG annulus Tail TOC Top of liner Total Cement Volume Spacer 30 bbls of 12 ppg Viscosified Spacer (Mud Push II) Lead N/A Tail 102.2 bbls, 574 cuft, 490 sks of 15.8 ppg Class G – 1.17 cuft/sk Temp BHST 172° F 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 pressure management while drilling Anti-Collision: No wells will be shut in for pressure management while drilling, all offset wells pass BP anti-collision scan criteria. 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. Offset well (s) 11-23 and 11-23A reduced to minor risk, i.e., no HSE risk. These larterals are abandoned. 11-41 PTD 6 3/21/2020 Drilling Waste Disposal x There is no annular injection in this well. x Cuttings Handling: Cuttings generated from drilling operations will be hauled to the MI Waste Disposal Facility. 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 the Waste Disposal Facility for injection. Haul Class I waste to Waste Disposal Facility for disposal. Contact the GPB Environmental Advisors (659-5893) for guidance. 11-41 PTD 7 3/21/2020 Well Control The 13.5” surface hole will be drilled with a diverter (see attached diverter layout). The 9-7/8” and 6- 1/8” hole sections will be drilled with well control equipment consisting of 5,000 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 3,500 psi. BOP test frequency for 11-41 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. 9-7/8” Intermediate Interval Maximum anticipated BHP 3,256 psi at the TSAD at 8,260’ TVDss (7.58 ppg EMW) Maximum surface pressure 2,430 psi at the TAD (0.10 psi/ft gas gradient to surface) Kick tolerance 25 bbls with 12 ppg frac gradient. Assumes 7.58 ppg pore pressure in the TSADD + 0.5 ppg kick intensity and 10.5 ppg MW. Planned BOP test pressure Rams test to 3,500 psi / 250 psi. Annular test to 3,500 psi / 250 psi Integrity Test – 9-7/8” hole LOT after drilling 20’-50’ of new hole 7” Casing Test 3,500 psi surface pressure 6-1/8” Production Interval Maximum anticipated BHP 3,305 psi in the BSAD at 8,682’ TVDss (7.32 ppg EMW) Maximum surface pressure 2,437 psi (0.10 psi/ft gas gradient to surface) Kick tolerance Assumed Infinite Planned BOP test pressure Rams test to 3,500 psi / 250 psi. Annular test to 3,500 psi / 250 psi Integrity Test – 6-1/8” hole N/A – See Variance Request 4-1/2” Liner Top Packer 3,500 psi surface pressure Planned completion fluids 8.5 ppg seawater / ~2000’ 6.8ppg TVDss diesel cap 11-41 PTD 8 3/21/2020 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 casing is at the top of the target reservoir, 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 * Variance will require AOGCC review of BPXA 7" cementing report to assure cement integrity of the 7" casing shoe and to project expected TOC external to 7" casing. 11-41 PTD 9 3/21/2020 Drill and Complete Operations Summary Pre-Rig Operations 1. Install 20” conductor and cellar box. Weld landing ring. Survey. Rig Operations MIRU Parker 272. Nipple up diverter system and function test. Run 13-1/2” drilling assembly on 5” DP. Drill 13-1/2” surface interval to 10-3/4” casing point within the lower SV Run 10-3/4”, 45.5#, L-80, VAM21 casing and cement to surface. Nipple down diverter and nipple up wellhead. Nipple up BOPE and test to 3,500 psi. Top tobottom: annular preventer, 4-1/2” x 7” rams, blind/shear, mud cross, 2-7/8” x 5” VBR Pressure test 10-3/4” casing to 3500 psi. Run 9-7/8” drilling assembly on 5” DP. Displace to LSND mud. Drill out shoe track and 20’ of new formation. Perform LOT. Drill 9-7/8” intermediate interval to 7” casing point at TSHU/TSAD Circulate well clean and POOH. Run 7”, 26#, L-80, VamTop HC casing from surface and cement Install and test 7” pack-off. Initiate injection into OA to ensure annulus is open for future freeze protection. Freeze protect OA once cement reaches sufficient compressive strength. Pressure test 7” casing to 3,500 psi. Swap upper rams to 2-7/8” x 5” VBR and test. Run 6-1/8” drilling assembly on 4” DP. Displace wellbore to 8.6 ppg Solids-Free drilling fluid. Flow check for 15 minutes. Drill out shoe track and 20’ of new formation. Flowcheck for 15 minutes. Drill the 6-1/8” production lateral per directional plan to TD. Circulate well clean, shorttrip as needed and POOH. Run 4-1/2”, 12.6# 13Cr VamTop liner to TD & cement to TOL. Displace liner with 8.6ppg mud. Set liner hanger and packer. Displace wellbore to clean seawater. Assurance test to 3,500 psi. POOH and LD liner running tool. RU and run ~2500’ of 2-7/8” perf guns. Perforate per subsurface team. POOH. Run 4-1/2”, 12.6#, 13Cr-85 Vam-Top completion. Tag up in TBR, space out and land tubing hanger. Reverse circulate inhibited seawater. Drop ball & rod and set production packer. Individually test tubing and IA to 3,500 psi each. Shear DCK valve. Reverse circulate diesel freeze protection. Allow diesel to U-tube so that T x IA is freeze protected down to ~2000’ TVD. Install and test TWC and test from above and below to 3,500 psi. Nipple down BOPE. Nipple up adapter flange and dry hole tree and test each to 4,500 psi. Secure well and RDMO. Intermediate casing test and 7" casing cementing report to AOGCC. AOGCC approval of cementing report prior to drilling out of 7" shoe. Surface casing test and formation LOT digital data to AOGCC. 24 hour notice to AOGCC to witness diverter system and function test. 24 hour notice to AOGCC to witness. 11-41 PTD 10 3/21/2020 Post-Rig Operations: 1. Pull TWC/Tree work as needed 2. Pull B&R, Set LGLV’s 3. Flowback 11-41 PTD 11 3/21/2020 11-41 Drilling Critical Issues POST THIS NOTICE IN THE DOGHOUSE I. Well Control / Reservoir Pressures A. Intermediate Hole 1: The UG4 is expected to be a 9.5 ppg EMW. The CM1, CM2 and CM3 are expected to be 9.7-10ppg EMW. Formation pressures will be controlled with a 9.8 – 10.2 ppg mud At this point, there will be a weight up to 10.4 – 11.0 ppg to drill the rest of the interval to TD. B. Production Hole: The Ivishak is expected to be at a ~7.32-7.58 ppg EMW. Reservoir pressures will be controlled by using 8.5 – 9.0 ppg water based mud. II. Lost Circulation/Breathing A. Intermediate Hole: There are no expected fault crossings in the intermediate hole. However, breathing has been known to occur in the Colville on other Drill Sites in Prudhoe Bay as a result of high ECD’s. B. Production Hole: There are no expected fault crossings in the production hole. Past wells have experienced lost circulation and the risk should be considered low. III. Fault Locations No Fault Crossings Planned IV. Integrity Testing V. Hydrogen Sulfide DS-11 is considered an H2S site. Recent H2S data from the pad is as follows: VI. Anti-Collision Issues All offset wells pass BP anti-collision scan criteria. CONSULT THE DS-11 DATA SHEET AND THE WELL PLAN FOR ADDITIONAL INFORMATION. Test Point Test Depth Test type EMW (lb/gal) 10-3/4” Shoe 20’-50’ from the shoe LOT 12.01 ppg Offset wells 11-23 and 11-23A collision risk reduced to 'minor risk', i.e. no HSE risk in the event of a collision. These laterals are abandoned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D DD hD 11-41 PTD Revised Formation Tops and Pore Pressure Estimate for 11-41 Formation Estimated Formation Top (TVDss) Most Likely Pore Pressure (EMW ppg) Fluid Type (for sands) G1 443 8.4 BPRF 1866 8.4 SV6 2330 8.4 Water SV5 3092 8.4 Water SV4 3226 8.4 Water SV3 3704 8.4 Water SV2 3893 8.4 Water SV1 4293 8.4 Water UG4 4827 9.5 Water UG3 5000 9.5 Water UG1 5695 9.5 Water WS2 6364 9.3 Water WS1 6455 9.3 Water CM3 6697 9.7 CM2 7139 9.8 CM1 7685 10 THRZ 8048 10 BHRZ 8247 10 LCU 8259 7.59 TSAD 8271 7.58 Gas 42N 8333 7.54 42P 8336 7.54 Gas TCGL 8391 7.5 Gas BCGL 8437 7.47 Water 24N 8517 7.42 24P 8526 7.41 Water 22N 8569 7.39 22P 8585 7.38 Gas 14N 8635 7.35 TDF 8664 7.33 Oil BSAD 8682 7.32 Oil 1 Davies, Stephen F (CED) From:Lastufka, Joseph N <Joseph.Lastufka@bp.com> Sent:Thursday, April 2, 2020 11:42 AM To:Davies, Stephen F (CED) Cc:Rixse, Melvin G (CED); Nocas, Noel Subject:As-Staked for 11-41 (PTD #220-031) Attachments:FRB20 DS11 01-00 DS11-41 CONDUTOR INSTALL-As-Staked.pdf Steve, WejustgottheAsͲStakedfor11Ͳ41(PTD#220Ͳ031),andtheXcoordinatechanged~3’fromtheapprovedPermittoDrill forthesurfacelocation. Pleaseletmeknowifyouneedanythingelseorifyouhavequestions.Thanks! Thank you, Joe Lastufka SIM Specialist Cell: (907) 227-8496 | Office: (907) 564-4091 --------------------------------------------------------------------------------------------------- BP Exploration Alaska | 900 E. Benson Blvd. | Room: 717B | Anchorage, AK --------------------------------------------------------------------------------------------------- WELL PERMIT CHECKLISTCompanyBP Exploration (Alaska) Inc.Well Name:PRUDHOE BAY UNIT 11-41Initial Class/TypeDEV / PENDGeoArea890Unit11650On/Off ShoreOnProgramDEVField & PoolWell bore segAnnular DisposalPTD#:2200310PRUDHOE BAY, PRUDHOE OIL - 640150NA1 Permit fee attachedYes Surface location in ADL 028325; top prod interval & TD om ADL 028322.2 Lease number appropriateYes3 Unique well name and numberYes PRUDHOE BAY, PRUDHOE OIL POOL - 64015, governed by CO 341H4 Well located in a defined poolYes CO 341H, Rule 2: There shall be no restrictions as to well spacing except that no pay shall be5 Well located proper distance from drilling unit boundaryYes opened in a well closer than 500 feet to the boundary of the affected area.6 Well located proper distance from other wellsYes As planned, well conforms to spacing requirements.7 Sufficient acreage available in drilling unitYes8 If deviated, is wellbore plat includedYes9 Operator only affected partyYes10 Operator has appropriate bond in forceYes11 Permit can be issued without conservation orderYes12 Permit can be issued without administrative approvalYes13 Can permit be approved before 15-day waitNA14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (For seNA15 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 34" x 20" Insulated conductor18 Conductor string providedYes Surface casing shoe set at 3626' ssTVD, below top of SV419 Surface casing protects all known USDWsYes 350% excess cement across the permafrost20 CMT vol adequate to circulate on conductor & surf csgNA Top of 7" cement 1500' MD above shoe, TOC @ ~7141' ssTVD below top of CM2, no hydrocarbons in West Sak21 CMT vol adequate to tie-in long string to surf csgYes22 CMT will cover all known productive horizonsYes23 Casing designs adequate for C, T, B & permafrostYes Parker 242 has adequate truck support and tankage24 Adequate tankage or reserve pitNA This is a new grass roots well.25 If a re-drill, has a 10-403 for abandonment been approvedYes Wellpath meets BP separtation criteria. 2 close approaches in the reservoir to abanded wellbores.26 Adequate wellbore separation proposedYes27 If diverter required, does it meet regulationsYes All fluids planned to be overbalanced to pore pressure.28 Drilling fluid program schematic & equip list adequateYes 1 annular, 3 ram stack29 BOPEs, do they meet regulationYes 5000 psi stack pressure tested to 3500 psi.30 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 shutdownYes DS 11 is considered a H2S pad. Standard BPXA H2S monitoring will be in place.33 Is presence of H2S gas probableNA This well is a planned producer.34 Mechanical condition of wells within AOR verified (For service well only)No DS 11 wells are H2S-bearing. H2S measures are required.35 Permit can be issued w/o hydrogen sulfide measuresYes Planned mud weights appear adequate to control the operator's forecast of estimated pore pressures.36 Data presented on potential overpressure zonesNA Should higher pore pressures be encountered, BP has immediate access to nearby fluid mixing facilities.37 Seismic analysis of shallow gas zonesNA Potential for breathing in intermediate hole. Potential for lost circulation in production hole.38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprSFDDate3/24/2020ApprMGRDate3/26/2020ApprSFDDate3/24/2020AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateGWV-03JLC3/26/2020
