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Home My WebLink About223-007From:Guhl, Meredith D (OGC) To:Joseph Lastufka Subject:PBU PTM P1-17A, PTD 223-007, Expired Date:Thursday, April 3, 2025 9:21:00 AM Hello Joe, The following Permit to Drill, issued to HilcorpNorthSlope, has expired under Regulation 20 AAC 25.005 (g). The PTD will be marked expired in the AOGCC database. PBU PTM P1-17A, PTD 223-007, Issued 10 Feb 2023. Please let me know if you have any questions or concerns. 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. 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: Prudhoe Bay Field, Pt. McIntyre Oil Pool, PBU P1-17A Hilcorp Alaska, LLC Permit to Drill Number: 223-007 Surface Location: 1399' FSL, 865' FEL, Sec. 16, T12N, R14E, UM, AK Bottomhole Location: 1358' FNL, 4985' FWL, Sec. 16, T12N, R14E, 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, Brett W. Huber, Sr. Chair, Commissioner DATED this ___ day of February, 2023. 10 Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2023.02.10 13:24:41 -09'00' 1a. Contact Name:Trevor Hyatt Contact Email:trevor.hyatt@hilcorp.comAuthorized Name: Monty Myers Authorized Title:Drilling Manager Authorized Signature: Contact Phone:907-777-8396 Approved by:COMMISSIONER APPROVED BY THE COMMISSION Date: 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 5 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 Hilcorp North Slope, LLC Bond No. 107205344 11.Well Name and Number: PBU P1-17A TVD:12249'8887' 12. Field/Pool(s): PRUDHOE BAY, PT MCINTYRE OIL MD: ADL 028297 90-024 March 1, 2023 4a. Surface: Top of Productive Horizon: Total Depth: 1399' FSL, 865' FEL, Sec. 16, T12N, R14E, UM, AK 295' FNL, 1144' FWL, Sec. 15, T12N, R14E, UM, AK Kickoff Depth:10060 feet Maximum Hole Angle: 111 degrees Maximum Anticipated Pressures in psig (see 20 AAC 25.035) Downhole:Surface:3800 3000 17.Deviated wells:16. Surface: x-y- Zone -674191 5994526 4 10. KB Elevation above MSL: GL Elevation above MSL: feet feet 50 9.5 15.Distance to Nearest Well Open to Same Pool: Cement Quantity, c.f. or sacks MD Casing Program: 9250'7972' 19.PRESENT WELL CONDITION SUMMARY Production 80 280 cu ft Arctic Set 10532 9244 None 10440 9152 9490 42 - 122 Surface 2385 cu ft PF E, 406 cu ft Class G 8697 - 9057 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): 9.3#/6.6# 3807 9984 - 10344 50-029-22358-01-00 526 sx Class G Intermediate Conductor/Structural Single Zone Service - Disp NoYesPost initial injection MIT req'd: NoYes 5 Diverter Sketch Comm. TVD API Number: MD Sr Pet Geo 1358' FNL, 4985' FWL, Sec. 16, T12N, R14E, UM, AK Time v. Depth Plot5 5 Drilling Program 4800' (To be completed for Redrill and Re-Entry Operations) 20" 10-3/4" STL/TCII 3521 5228 - 8221 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. 3800 Centerpoint Dr, Suite 1400, Anchorage, AK 99503 6. Proposed Depth: 7. Property Designation (Lease Number): 8. DNR Approval Number:13.Approximate spud date: 9.Acres in Property: 14. Distance to Nearest Property: Location of Well (Governmental Section): 4b. 2560 500' 18.Specifications Top - Setting Depth - Bottom Casing Weight Grade TVDHole Coupling Length TVD (including stage data) x2-7/8" /6.5# /STL Total Depth MD (ft): Total Depth TVD (ft): Plugs (measured):Effect. Depth MD (ft): Effect. Depth TVD (ft):Junk (measured): Casing Length Size MD 42 - 122 41 - 3848 41 - 3576 104814 7-5/8"633 cu ft Class G 37 - 10518 37 - 9230 Scab Liner 4-1/2"5984 - 9505 Perforation Depth MD (ft):Perforation Depth TVD (ft): 20. Attachments Property Plat BOP Sketch Permit to Drill Number: Permit Approval Date: Reentry Hydraulic Fracture planned? Sr Pet Eng Sr Res Eng Cement Volume Comm. 12249'8887'226 sx Class G4-1/4"3-1/2"x3-1/4"13Cr85 2999' Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval (20 AAC 25.005(g)) 2.1.2023 By Samantha Carlisle at 1:05 pm, Feb 01, 2023 Digitally signed by Monty M Myers DN: cn=Monty M Myers, c=US, o=Hilcorp Alaska, LLC, ou=Technical Services - AK Drilling, email=mmyers@hilcorp.com Reason: I am approving this document Date: 2023.02.01 12:25:23 -09'00' Monty M Myers Redrill MGR09FEB2023 223-007 * BOPE test to 3500 psi. SFD 2/6/2023 * Variance to 20 AAC 25.112(i) approved for alternate plug placement of parent well. All drilling in the reservoir. DSR-2/1/23GCW 02/05/23JLC 2/10/2023 2/10/23 2/10/23Brett W. Huber, Sr.Digitally signed by Brett W. Huber, Sr. Date: 2023.02.10 13:25:01 -09'00' To: Alaska Oil & Gas Conservation Commission From: Trevor Hyatt Drilling Engineer Date: February 1, 2023 Re: PBU P1-17A Permit to Drill Approval is requested for drilling a CTD sidetrack lateral from well PBU P1-17 with the Nabors CDR2 Coiled Tubing Drilling. Proposed plan for P1-17A Producer: See P1-17 Sundry request for complete pre-rig details - Prior to drilling activities, screening will be conducted to drift for whipstock, MIT-IA, and Caliper log. E-line will then mill the SWN-nipple and set a 4-1/2"x7-5/8" whipstock. A coil tubing drilling sidetrack will be drilled with the Nabors CDR2 rig. The rig will move in, test BOPE and kill the well. If unable to set whipstock pre-rig, the rig will set the 4-1/2"x7-5/8" whipstock. A single string 3.80" window + 10' of formation will be milled. The well will kick off drilling and land in the Kuparuk sands. The lateral will continue in the Kuparuk to TD. Run open hole Density/Neutron logs after reaching TD and prior to running liner. The proposed sidetrack will be completed with a 3-1/2"x3-1/4"x2-7/8” 13Cr solid liner, cemented in place and selectively perforated post rig (will be perforated with rig if unable to post rig). This completion will completely isolate and abandon the parent Kuparuk perfs. The following describes the work planned. A wellbore schematic of the current well and proposed sidetrack is attached for reference. Pre-Rig Work: x Reference P1-17 Sundry submitted in concert with this request for full details. x General work scope of Pre-Rig work: 1. Slickline: Dummy WS drift, caliper 2. Fullbore: MITs 3. E-Line: Mill SWN Nipple and set whipstock (if needed mill nipple with service coil) 4. Valve Shop: Pre-CTD Tree Work as necessary Rig Work - (Estimated to start in March 2023): 1. MIRU and test BOPE to 3500 psi. MASP with gas (0.10 psi/ft) to surface is 3,000 psi a. Give AOGCC 24hr notice prior to BOPE test b. Test against swab and master valves (No TWC) c. Load pits with drilling fluid d. Open well and ensure zero pressure 2. Only if not done pre-rig – Set 4-1/2"x7-5/8" whipstock. a. Top of whipstock at 10,053’ MD oriented at 95° ROHS. 3. Mill 3.80” single string window (out of 7-5/8”) plus 10’ of rathole. a. Top of window (whipstock pinch point 7’ down from top) at 10,060’ MD. 4. Drill – Build & Lateral a. 3” BHA with GR/RES / Bi-center Bit (4.25”) b. 30° DLS build section – 327’ MD / Planned TD 10,387’ MD c. 12° DLS lateral section – 1,862’ MD / Planned TD 12,249’ MD d. Drill with a constant bottom hole pressure for entire sidetrack e. Pressure deployment will be utilized f. After TD and on the last trip out of hole lay in completion/kill weight fluid in preparation for liner run g. No flow test prior to laying down drilling BHA. Assure well is dead prior to picking up liner. PTD 223-007 Sundry 323-066 p completion will completelyyp p g( p isolate and abandon the parent Kuparuk perfs. g, g p g well will kick off drilling and land in the Kuparuk sands. 5. Run Open Hole Logs a. Run Density/Neutron logs prior to running liner. b. If wellbore conditions deteriorate, will not run logs. 6. Run and Cement Liner a. Have 2-3/8” safety joint with TIW valve ready to be picked up while running liner b. Swap BOP rams from 3” pipe/slip (drilling) to 2-3/8”x3-1/2” VBRs (running liner) and test to 3500 psi. c. Run 3-1/2”x3-1/4”x2-7/8” 13Cr solid liner to TD d. Swap well over to KCl e. Cement Liner with 50 bbls - 15.3 ppg Class G cement (TOC to TOL)* f. Only if not able to do with service coil extended perf post rig - Perforate well ~600’ g. Freeze protect well from ~2200’ TVD (min) h. RDMO Post Rig: 1. V: Valve & tree work 2. S: Set LTP* (if necessary) – RPM Log 3. C: Post rig perforate (~600’) (if done post rig - see future Extended Perf Sundry) 4. T: Portable Test Separator Flowback * Approved alternate plug placement per 20 AAC 25.112(i) Managed Pressure Drilling: Managed pressure drilling techniques will be employed on this well. The intent is to provide constant bottom hole pressure by using minimum 8.4 ppg drilling fluid in combination with annular friction losses and applied surface pressure. Constant BHP will be utilized to reduce pressure fluctuations to help with hole stability. Applying annular friction and choke pressure also allow use of lighter drilling fluid and minimizes fluid losses and/or fracturing at the end of the long well bores. A MPD choke for regulating surface pressure and is independent of the WC choke. Deployment of the BHA under trapped wellhead pressure will be necessary. Pressure deployment of the BHA will be accomplished utilizing 3” (bighole) & 2-3/8” (slimhole) pipe/slip rams (see attached BOP configurations). The annular preventer will act as a secondary containment during deployment and not as a stripper. Operating parameters and fluid densities will be adjusted based on real-time bottom hole pressure measurements while drilling and shale behavior. The following scenario is expected: MPD Pressure at the Planned Window (10,060’ MD - 8,772’ TVD) Pumps On Pumps Off A Target BHP at Window (ppg)4,470 psi 4,470 psi 9.8 B Annular friction - ECD (psi/ft)543 psi 0 psi 0.05 C Mud Hydrostatic (ppg)3,923 psi 3,923 psi 8.6 B+C Mud + ECD Combined 4,466 psi 3,923 psi (no choke pressure) A-(B+C)Choke Pressure Required to Maintain 4 psi 547 psi Target BHP at window and deeper Operation Details: Reservoir Pressure: x The estimated reservoir pressure is expected to be 3,800 psi at 8,800’ TVD (8.3 ppg equivalent). x Maximum expected surface pressure with gas (0.10 psi/ft) to surface is 3,000 psi (from estimated reservoir pressure). Mud Program: x Drilling: Minimum MW of 8.4 ppg KCL with Geovis for drilling. Managed pressure used to maintain constant BHP. x KWF will be stored on location. The tankage will contain 1.5 wellbore volumes of KWF to exceed the maximum possible BHP to be encountered as the lateral is drilled. Adjust with real time BHP monitoring. x Completion: A minimum MW 8.6 ppg KWF to be used for liner deployment. Will target 9.8 ppg to match managed pressure target. Disposal: x All Class l & II non-hazardous and RCRA-exempt drilling and completion fluids will go to GNI at DS 4. x Fluids >1% hydrocarbons or flammables must go to GNI. x Fluids >15% solids by volume must go to GNI. x Fluids with solids that will not pass through 1/4” screen must go to GNI. x Fluids with PH >11 must go to GNI. Hole Size: x 4.25” hole for the entirety of the production hole section. Liner Program: x 3-1/2”, 9.3#, 13Cr solid/cemented liner: 9,250’ MD – 9,400’ MD (50’ liner) x 3-1/4”, 6.6#, 13Cr solid/cemented liner: 9,400’ MD – 10,390’ MD (990’ liner) x 2-7/8”, 6.5#, 13Cr solid/cemented liner: 10,390’ MD – 12,249’ MD (1859’ liner) x The primary barrier for this operation: Kill Weight Fluid to provide overbalance as necessary x A X-over shall be made up to a 2-3/8” safety joint including a TIW valve for all tubulars ran in hole. Well Control: x BOP diagram is attached. MPD and pressure deployment is planned. x Pipe rams, blind rams and the CT pack off will be pressure tested to 250 psi and to 3,500 psi. x The annular preventer will be tested to 250 psi and 2,500 psi. x 1.5 wellbore volumes of KWF will be on location at all times during drilling operations. x Solid 2-7/8” Liner Running Ram Change: Change out 3” pipe/slip rams (for drilling) to 2-3/8”x3-1/2” VBR rams for liner run. Test VBR rams to 250 psi and 3,500 psi. x A X-over shall be made up to a 2-3/8” safety joint including a TIW valve for all tubulars ran in hole. x 2-3/8” safety joint will be utilized while running 2-7/8”, 3-1/4”, 3-1/2” solid or slotted liner. The desire is to keep the same standing orders for the entire liner run and not change shut in techniques from well to well (run safety joint with pre-installed TIW valve). When closing on a 2-3/8” safety joint, 2 sets of pipe/slip rams will be available, above and below the flow cross providing better well control option. Directional: x Directional plan attached. Maximum planned hole angle is 111°. Inclination at kick off point is 3°. x Magnetic and inclination surveys will be taken every 30 ft. No gyro will be run. x Distance to nearest property line – 4,800’ x Distance to nearest well within pool – 500’ Logging: x MWD directional, Gamma Ray, and Resistivity will be run through the entire open hole section. x Real time bore pressure to aid in MPD and ECD management. x Open holed Density/Neutron logs will be run after drilling to TD, but before running liner. Will drop these logs if hole conditions are questionable for running liner. x Possible RPM log will be run in cased hole post rig. Perforating: x ~600’ perforated post rig (See future perforating sundry request – if extended perforating is used) x 2” perf guns, 6 SPF, 60 deg phasing x If extended perforating is not an option, the well will be perforated with the rig under this PTD. Anti-Collision Failures: x No failures for P1-17A WP11 Hazards: x PBU P1-pad is an H2S pad. o The highest recorded H2S well on the pad was from P1-20 (850 ppm) in 2011. o Last recorded H2S on P1-17 was 110 ppm in 2022 x Two fault crossings expected. x High lost circulation risk. Trevor Hyatt CC: Well File Drilling Engineer Joseph Lastufka 907-223-3087 PBU P1-pad is an H2S pad. gp High lost circulation risk. 6WDQGDUG3URSRVDO5HSRUW -DQXDU\ 3ODQ3$ZS +LOFRUS1RUWK6ORSH//& *30$ 3 3ODQ36ORW 3ODQ3$ 2375 2500 2625 2750 2875 3000 3125 3250 3375 3500 3625 3750 3875 4000 4125 4250 4375 4500 South(-)/North(+) (250 usft/in)500 625 750 875 1000 1125 1250 1375 1500 1625 1750 1875 2000 2125 2250 West(-)/East(+) (250 usft/in) P1-17 wp11 polygon P1-17 wp11 tgt5 P1-17 wp11 tgt4 P1-17 wp11 tgt3 P1-17 wp11 tgt2 P1-17 wp11 tgt1 5750 6000 6250 6500 6750 7000 7250 7500 7 75 0 8 0 0 0 8 2 5 0 9244P1-177" TOW 2 7/8" x 4 1/4"8887P1-17A wp11KOP : Start Dir 9º/100' : 10060' MD, 8772.89'TVD : 94.97° RT TF Start Dir 30º/100' : 10080' MD, 8792.87'TVD Start Dir 12º/100' : 10386.17' MD, 8982.05'TVD Total Depth : 12248.66' MD, 8886.51' TVD CASING DETAILS TVD TVDSS MD Size Name 8772.89 8722.89 10060.00 7 7" TOW 8886.51 8836.51 12248.66 2-7/8 2 7/8" x 4 1/4" Project: GPMA Site: P1 Well: Plan: P1-17 Wellbore: Plan: P1-17A Plan: P1-17A wp11 WELL DETAILS: Plan: P1-17 Ground Level: 11.20 +N/-S +E/-W Northing Easting Latitude Longitude 0.00 0.00 5994526.484 674191.333 70° 23' 26.6463 N 148° 34' 58.3402 W REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Plan: P1-17 - Slot 17, True North Vertical (TVD) Reference: KB @ 50.00usft (ORIG KELLY BUSHING) Measured Depth Reference:KB @ 50.00usft (ORIG KELLY BUSHING) Calculation Method:Minimum Curvature 8375 8500 8625 8750 8875 9000 9125 9250 9375 9500 9625 9750 9875True Vertical Depth (250 usft/in)2250 2375 2500 2625 2750 2875 3000 3125 3250 3375 3500 3625 3750 3875 4000 Vertical Section at 12.63° (250 usft/in) P1-17 wp11 tgt1 P1-17 wp11 tgt2 P1-17 wp11 tgt3 P1-17 wp11 tgt4 P1-17 wp11 tgt5 P1-17 wp11 polygon 10000 10 500 10532 P1-17 7" TOW 2 7/8" x 4 1/4"105001100011500120001 2 2 4 9 P1-17A wp11 KOP : Start Dir 9º/100' : 10060' MD, 8772.89'TVD : 94.97° RT TF Start Dir 30º/100' : 10080' MD, 8792.87'TVD Start Dir 12º/100' : 10386.17' MD, 8982.05'TVD Total Depth : 12248.66' MD, 8886.51' TVD Hilcorp North Slope, LLC Calculation Method:Minimum Curvature Error System:ISCWSA Scan Method: Closest Approach 3D Error Surface: Ellipsoid Separation Warning Method: Error Ratio WELL DETAILS: Plan: P1-17 Ground Level: 11.20 +N/-S +E/-W Northing Easting Latitude Longitude 0.00 0.00 5994526.484 674191.333 70° 23' 26.6463 N 148° 34' 58.3402 W SURVEY PROGRAM Date: 2021-10-19T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 218.00 10060.00 1 : MWD - Standard (P1-17) 3_MWD 10060.00 12248.66 P1-17A wp11 (Plan: P1-17A) 3_MWD FORMATION TOP DETAILS No formation data is available REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Plan: P1-17 - Slot 17, True North Vertical (TVD) Reference:KB @ 50.00usft (ORIG KELLY BUSHING) Measured Depth Reference:KB @ 50.00usft (ORIG KELLY BUSHING) Calculation Method:Minimum Curvature Project:GPMA Site:P1 Well:Plan: P1-17 Wellbore:Plan: P1-17A Design:P1-17A wp11 CASING DETAILS TVD TVDSS MD Size Name 8772.89 8722.89 10060.00 7 7" TOW 8886.51 8836.51 12248.66 2-7/8 2 7/8" x 4 1/4" SECTION DETAILS Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation 1 10060.00 2.94 63.55 8772.89 3589.28 2009.63 0.00 0.00 3941.94 KOP : Start Dir 9º/100' : 10060' MD, 8772.89'TVD : 94.97° RT TF 2 10080.00 3.31 96.38 8792.87 3589.44 2010.66 9.00 94.97 3942.33 Start Dir 30º/100' : 10080' MD, 8792.87'TVD 3 10386.17 92.25 179.50 8982.05 3391.08 2023.71 30.00 83.00 3751.63 Start Dir 12º/100' : 10386.17' MD, 8982.05'TVD 4 10516.17 93.51 195.07 8975.47 3262.69 2007.31 12.00 85.00 3622.76 5 10641.17 100.39 208.50 8960.28 3147.78 1961.50 12.00 62.00 3500.60 6 10741.17 100.17 220.70 8942.37 3066.95 1905.74 12.00 90.00 3409.53 7 10891.17 86.26 232.18 8933.95 2964.24 1797.59 12.00 140.00 3285.65 8 11141.17 80.78 261.88 8962.78 2868.11 1571.73 12.00 102.00 3142.45 9 11241.17 83.05 249.97 8976.89 2844.05 1475.89 12.00 -80.00 3098.01 10 11421.17 98.39 265.23 8974.63 2805.60 1301.15 12.00 45.00 3022.27 11 11598.66 110.00 246.77 8930.83 2764.93 1135.10 12.00 -55.00 2946.26 12 11698.66 110.17 233.99 8896.36 2718.63 1053.66 12.00 -87.00 2883.27 13 11823.66 110.74 249.99 8852.42 2663.83 950.69 12.00 85.00 2807.28 14 12248.66 59.74 249.99 8886.51 2523.67 565.72 12.00 180.00 2586.30 Total Depth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(OOLSVH6HSDUDWLRQ 3DVV333 &HQWUH'LVWDQFH 3DVV33ODQ3*$63$*$6ZS &HQWUH'LVWDQFH 3DVV33ODQ3*$63$*$6ZS (OOLSVH6HSDUDWLRQ 3DVV33ODQ3*$63$*$6ZS &OHDUDQFH)DFWRU 3DVV333 &OHDUDQFH)DFWRU 3DVV33$19DZS &OHDUDQFH)DFWRU 3DVV33$19DZS (OOLSVH6HSDUDWLRQ 3DVV33$19DZS &HQWUH'LVWDQFH 3DVV33$3$ &OHDUDQFH)DFWRU 3DVV33$3$ (OOLSVH6HSDUDWLRQ 3DVV33$3$ &HQWUH'LVWDQFH 3DVV333 &OHDUDQFH)DFWRU 3DVV33/3/ &OHDUDQFH)DFWRU 3DVV3ODQ333 (OOLSVH6HSDUDWLRQ 3DVV3ODQ333 &OHDUDQFH)DFWRU 3DVV370&,17370&,17370&,17<5( &OHDUDQFH)DFWRU 3DVV6XUYH\WRROSURJUDP)URPXVIW7RXVIW6XUYH\3ODQ 6XUYH\7RRO B0:' 3$ZS B0:'-DQXDU\ &203$663DJHRI *30$+LOFRUS1RUWK6ORSH//&$QWLFROOLVLRQ5HSRUWIRU3ODQ33$ZS(OOLSVHHUURUWHUPVDUHFRUUHODWHGDFURVVVXUYH\WRROWLHRQSRLQWV6HSDUDWLRQLVWKHDFWXDOGLVWDQFHEHWZHHQHOOLSVRLGV&DOFXODWHGHOOLSVHVLQFRUSRUDWHVXUIDFHHUURUV&OHDUDQFH)DFWRU 'LVWDQFH%HWZHHQ3URILOHV'LVWDQFH%HWZHHQ3URILOHV(OOLSVH6HSDUDWLRQ'LVWDQFH%HWZHHQFHQWUHVLVWKHVWUDLJKWOLQHGLVWDQFHEHWZHHQZHOOERUHFHQWUHV$OOVWDWLRQFRRUGLQDWHVZHUHFDOFXODWHGXVLQJWKH0LQLPXP&XUYDWXUHPHWKRG-DQXDU\ &203$663DJHRI 0.001.002.003.004.00Separation Factor10125 10250 10375 10500 10625 10750 10875 11000 11125 11250 11375 11500 11625 11750 11875 12000 12125 12250 12375 12500Measured Depth (250 usft/in)P1-12A GAS wp03NV-18a wp07P1-18AP1-17PT MCINTYRE 01No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.WELL DETAILS:Plan: P1-17 NAD 1927 (NADCON CONUS)Alaska Zone 04Ground Level: 11.20+N/-S +E/-W Northing EastingLatitudeLongitude0.000.005994526.484674191.33370° 23' 26.6463 N148° 34' 58.3402 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: P1-17 - Slot 17, True NorthVertical (TVD) Reference:KB @ 50.00usft (ORIG KELLY BUSHING)Measured Depth Reference:KB @ 50.00usft (ORIG KELLY BUSHING)Calculation Method: Minimum CurvatureSURVEY PROGRAMDate: 2021-10-19T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool218.00 10060.00 1 : MWD - Standard (P1-17) 3_MWD10060.00 12248.66 P1-17A wp11 (Plan: P1-17A) 3_MWD0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)10125 10250 10375 10500 10625 10750 10875 11000 11125 11250 11375 11500 11625 11750 11875 12000 12125 12250 12375 12500Measured Depth (250 usft/in)GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference10060.00 To 12248.66Project: GPMASite: P1Well: Plan: P1-17Wellbore: Plan: P1-17APlan: P1-17A wp11Ladder / S.F. PlotsCASING DETAILSTVD TVDSS MD Size Name8772.89 8722.89 10060.00 7 7" TOW8886.51 8836.51 12248.66 2-7/8 2 7/8" x 4 1/4" Well Bighole Date Quick Test Sub to Otis -1.1 ft Top of 7" Otis 0.0 ft Distances from top of riser Excluding quick-test sub Top of Annular 6.0 ft Top of Annular Element 6.7 ft Bottom Annular 8.0 ft CL Blind/Shears 9.3 ft CL 2-3/8" Pipe/Slips 10.1 ft B1 B2 B3 B4 Choke Line Kill Line CL 3" Pipe/Slips 12.6 ft CL 2-3/8" Pipe/Slips 13.4 ft CL of Top Swab 16.0 ft Swab Test Pump Hose T1 T2 Swab 1 CL of Flow Cross 17.4 ft Master CL of Master 18.8 ft LDS IA OA LDS Ground Level CDR2-AC 4 Ram BOP Schematic 15-Jan-21 CDR2 Rig's Drip Pan 7-1/16" 5k Flange X 7" Otis Box Hydril 7 1/16" Annular 2-3/8" Pipe/Slips 7-1/16" 5k Mud Cross 2-3/8"Pipe/Slips Blind/Shear 7-1/16" 5 Mud Cross 3" Pipe/Slips 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. Prudhoe Bay 223-007 PBU P1-17A Pt McIntyre Oil WELL PERMIT CHECKLISTCompanyHilcorp North Slope, LLCWell Name:PRUDHOE BAY UN PTM P1-17AInitial Class/TypeDEV / PENDGeoArea890Unit11650On/Off ShoreOnProgramDEVField & PoolWell bore segAnnular DisposalPTD#:2230070PRUDHOE BAY, PT MCINTYRE OIL - 640180NA1 Permit fee attachedYes Entire well in ADL0028297.2 Lease number appropriateYes3 Unique well name and numberYes PRUDHOE BAY, PT MCINTYRE OIL – 6401804 Well located in a defined poolYes5 Well located proper distance from drilling unit boundaryYes6 Well located proper distance from other wellsYes7 Sufficient acreage available in drilling unitYes8 If deviated, is wellbore plat includedYes9 Operator only affected partyYes10 Operator has appropriate bond in forceYes11 Permit can be issued without conservation orderYes12 Permit can be issued without administrative approvalYes13 Can permit be approved before 15-day 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 In reservoir sidetrack. Parent well integrity confirmed.18 Conductor string providedYes In reservoir sidetrack. Parent well integrity confirmed.19 Surface casing protects all known USDWsYes In reservoir sidetrack. Parent well integrity confirmed.20 CMT vol adequate to circulate on conductor & surf csgYes In reservoir sidetrack. Parent well integrity confirmed.21 CMT vol adequate to tie-in long string to surf csgYes Fully cemented liner from TD to confining zones22 CMT will cover all known productive horizonsYes23 Casing designs adequate for C, T, B & permafrostYes CDR2 has adequate tankage and good trucking support24 Adequate tankage or reserve pitYes Sundry 323-06625 If a re-drill, has a 10-403 for abandonment been approvedYes Halliburton collision scan shows adequate wellbore separation26 Adequate wellbore separation proposedNA In reservoir sidetrack. Parent well integrity confirmed.27 If diverter required, does it meet regulationsYes MPD will be utilized. Dynamically overbalanced to pore pressure. KWF for running liner.28 Drilling fluid program schematic & equip list adequateYes 1 annular, 1 CT packoff, 4 ram CT stack29 BOPEs, do they meet regulationYes 5M psi stack pressure tested to 3500 psi. 3000 psi MPSP30 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 Monitoring will be required.33 Is presence of H2S gas probableNA This well will be a development well.34 Mechanical condition of wells within AOR verified (For service well only)Yes35 Permit can be issued w/o hydrogen sulfide measuresYes Expected pressure gradient is 0.432 psi/ft (8.31 ppg EMW). MPD will be used with 8.4 ppg mud36 Data presented on potential overpressure zonesNA with weight increases as needed to mitigate abnormal pressure and borehole instability.37 Seismic analysis of shallow gas zonesNA38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprSFDDate2/6/2023ApprMGRDate2/9/2023ApprSFDDate2/6/2023AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateJLC 2/10/2023