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Home My WebLink About224-133Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 3/2/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20250302 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# CLU 11 50133205590000 206058 2/19/2025 AK E-LINE CBL,CIBP CLU 11 50133205590000 206058 2/13/2025 AK E-LINE CIBP END 1-65A 50029226270100 203212 1/27/2025 HALLIBURTON COILFLAG END 2-56A 50029228630100 198058 2/6/2025 HALLIBURTON COILFLAG END 2-72 50029237810000 224016 2/2/2025 HALLIBURTON PPROF MPU F-29 50029226880000 196117 1/31/2025 HALLIBURTON MFC24 MPU L-02A 50029219980100 209147 2/17/2025 READ CaliperSurvey MPU L-36 50029227940000 197148 1/18/2025 HALLIBURTON MFC24 MPU R-144 50029238090000 224148 2/11/2025 HALLIBURTON WFL-TMD3D NCIU A-21 50883201990000 224086 2/18/2025 AK E-LINE Perf ODSN-25 50703206560000 212030 2/16/2025 READ MemoryLeakPoint PBU 06-05A 50029202980100 224115 1/15/2025 BAKER MRPM PBU 06-15A 50029204590200 224108 12/27/2024 HALLIBURTON RBT PBU 06-16B 50029204600200 223072 1/25/2025 BAKER MRPM PBU B-12B 50029203320200 224133 1/19/2025 BAKER MRPM PBU S-126B 50029233630200 224084 2/7/2025 HALLIBURTON RBT PBU V-105 50029230970000 202131 2/9/2025 HALLIBURTON IPROF PBU W-01A 50029218660100 203176 1/19/2025 AK E-LINE CBL PBU W-01B 50029218660200 224149 1/28/2025 HALLIBURTON RBT PCU 02A 50283200220100 224110 1/24/2025 AK E-LINE CIBP Please include current contact information if different from above. T40161 T40161 T40162 T40163 T40164 T40165 T40166 T40167 T40168 T40169 T40170 T40171 T40172 T40173 T40174 T40175 T40176 T40177 T40178 T40179 PBU B-12B 50029203320200 224133 1/19/2025 BAKER MRPM Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.03.03 10:15:14 -09'00' David Douglas Hilcorp North Slope, 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: Hilcorp North Slope, LLC Date: 02/10/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL WELL: PBU B-12B PTD: 224-133 API: 50-029-20332-02-00 FINAL LWD FORMATION EVALUATION LOGS (01/08/2025 to 01/13/2025) Multiple Propagation Resistivity & Gamma Ray (2” & 5” MD/TVD Color Logs) Pressure While Drilling (PWD) Final Definitive Directional Surveys SFTP Transfer - Data Main Folders: Please include current contact information if different from above. 224-133 T40071 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.02.11 08:42:04 -09'00' 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 Sean McLaughlin Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK, 99503 Re: Prudhoe Bay Field, Prudhoe Oil Pool, PBU B-12B Hilcorp Alaska, LLC Permit to Drill Number: 224-133 Surface Location: 1850’ FNL, 1609’ FEL, Sec 31, T11N, R14E, UM, AK Bottomhole Location: 832' FSL, 1651' FWL, Sec 32, T11N, R14E, UM, AK Dear Mr. McLaughlin: 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 AOGCCreserves 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 AOGCCspecifically 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 AOGCCorder, 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 1th day of December2024. Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.12.18 08:16:53 -09'00' 3-1/2"x3-1/4" By Grace Christianson at 2:39 pm, Oct 29, 2024 Digitally signed by Sean McLaughlin (4311) DN: cn=Sean McLaughlin (4311) Date: 2024.10.28 17:23:31 - 08'00' Sean McLaughlin (4311) DSR-10/29/24 224-133 A.Dewhurst 30OCT24 50-029-20332-02-00 WCB 12-4-2024 *BOPE test to 3500 psi. Annular to 2500 psi. 24-hr notice to AOGCC. *Variance to 20 AAC 25.112(i) approved for alternate cement plug placement with fully cemented production liner. *Parent well B-12A to remain as a development oil well until completion of B-12B drilling ops and isolation of existing perfs with liner cement job, at which time B-12A will be considered abandoned. *The service coil window milling step will require a 10-403 Change of Approved program to this PTD. *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.12.18 08:17:07 -09'00' 12/18/24 12/18/24 RBDMS JSB 122024 To: Alaska Oil & Gas Conservation Commission From: Ryan Ciolkosz Drilling Engineer Date: October 28, 2024 Re:B-12B Permit to Drill Approval is requested for drilling a CTD sidetrack lateral from well B-12A with the Nabors CDR2/CDR3 Coiled Tubing Drilling. Proposed plan for B-12B Producer: See B-12A Sundry request for complete pre-rig details - Prior to drilling activities, coil will clean out fill and mill XN nipple out to 3.80". Screening will be conducted to drift for whipstock, caliper, and MIT. E-line will set a 4- 1/2"x7" whipstock. Coil will mill window pre-rig. If unable to set the whipstock or milling the window, for scheduling reasons, the rig will perform that work. A coil tubing drilling sidetrack will be drilled with the Nabors CDR2/CDR3 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" whipstock. A single string 3.80" window + 10' of formation will be milled. The well will kick off drilling in the Shublik and lands in Ivishak Zone 4. The lateral will continue in Zone 4 to TD. 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 Ivishak 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 B-12A Sundry submitted in concert with this request for full details. 1. Coil : Fill cleanout and Mill XN nipple 2. Slickline : Dummy WS drift and Caliper, SBHPS. 3. E-Line : Set 4-1/2" x 7" Whipstock at 9027' MD at 0 deg ROHS 4. Fullbore : MIT-IA or MIT-T & CMIT 5. Coil : Mill Window (if window not possible, mill with rig) 6. Valve Shop : Pre-CTD Tree Work 7. Operations : Remove wellhouse and level pad. Rig Work: (Estimated to start in December 2024) 1. MIRU and test BOPE 250 psi low and 3,500 psi high (MASP 2,433 psi). Give AOGCC 24hr notice prior to BOPE test. 2. Mill 3.80” Window. 3. Drill build section: 4.25" OH, ~215' (30 deg DLS planned). 4. Drill production lateral: 4.25" OH, ~2488' (12 deg DLS planned). Swap to KWF for liner. 5. Run 3-1/2” x 3-1/4” x 2-7/8” 13Cr liner (swap to VBRs and test prior to running liner) 6. Pump primary cement job: 39 bbls, 15.3 ppg Class G, 1.24 cuft/sx, TOC at TOL*. 7. Only if not able to do with service coil extended perf post rig – Perforate Liner 8. Freeze protect well to a min 2,200' TVD. 9. Close in tree, RDMO. * Approved alternate plug placement per 20 AAC 25.112(i) Post Rig Work: 1. Valve Shop : Valve & tree work 2. Slickline : SBHPS, set LTP* (if necessary). Set live GLVs. 3. Service Coil : Memory RPM and CBL and Post rig perforate (~10'-30’). 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”/3-1/8” (big hole) & 2-3/8” (slim hole) 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 (9027' MD -8,720' TVD) Pumps On Pumps Oī A Target BHP at Window (ppg)4,444 psi 4,444 psi 9.8 B ŶŶƵůĂƌĨƌŝĐƟŽŶ- ECD ;ƉƐŝͬŌͿ 542 psi 0 psi 0.09 C DƵĚ,ǇĚƌŽƐƚĂƟĐ;ƉƉŐͿ 3,900 psi 3,900 psi 8.6 B+C Mud + ECD Combined 4,441 psi 3,900 psi (no choke pressure) A-(B+C)Choke Pressure Required to Maintain 3 psi 544 psi Target BHP at window and deeper Operation Details: Reservoir Pressure: x The estimated reservoir pressure is expected to be 3,313 psi at 8,800 TVD. (7.2 ppg equivalent). x Maximum expected surface pressure with gas (0.10 psi/ft) to surface is 2,433 psi (from estimated reservoir pressure). Mud Program: x Drilling: Minimum MW of 8.4 ppg KCL with viscosifier for drilling. Managed pressure used to maintain constant BHP. 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. 8.4 Liner Program: x 3-1/2", 9.3#, 13Cr Solid: 8,820' MD – 9,010' MD (190' liner) x 3-1/4", 6.6#, 13Cr Solid: 9,010' MD – 9,300' MD (290' liner) x 2-7/8", 6.5#, 13Cr Solid: 9,300' MD – 11,730' MD (2,430' 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 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”/3-1/8” pipe/slip rams (for drilling) to 2-3/8” x 3- 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 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 102°. Inclination at kick off point is 43°. x Magnetic and inclination surveys will be taken every 30 ft. No gyro will be run. x Distance to nearest property line – 20,660 ft x Distance to nearest well within pool – 700 ft 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. Perforating: x 30’ perforated post rig – See attached extended perforating procedure. x 2" Perf Guns at 6 spf x If post rig extended perforating with service coil is not an option, the well will be perforated with the rig or post rig under this PTD. x The well will be perforated between the CTD whipstock and TD of the newly drilled CTD well, completely in the Prudhoe Pool. x Formations: Top of Prudhoe Pool at 8921’ MD in the parent Anti-Collision Failures: x No Anti-collision failures with the planned B-12B wellpath Hazards: x DS/Pad is an H2S pad. The last H2S reading on B-12A: 136 ppm on 06/20/2024. x Max H2S recorded on DS/Pad: 160 ppm. x 1 fault crossings expected. x Medium lost circulation risk. Ryan Ciolkosz CC: Well File Drilling Engineer Joseph Lastufka (907-244-4357) Post-Rig Service Coil Perforating Procedure: Coiled Tubing Notes: x Due to the necessary open hole deployment of Extended Perforating jobs, 24-hour crew and WSS coverage is required. x Note: The well will be killed and monitored before making up the initial perfs guns. This will provide guidance as to whether the well will be killed by bullheading or circulating bottoms up throughout the job. If pressure is seen immediately after perforating, it will either be killed by bullheading while POOH or circulating bottoms up through the same port that opened to shear the firing head. Coil Tubing 1. MIRU Coiled Tubing Unit and spot ancillary equipment. 2. MU nozzle drift BHA (include SCMT and/or RPM log as needed). 3. RIH to PBTD. a. Displace well with weighted brine while RIH (minimum 8.4 ppg to be overbalanced). 4. POOH (and RPM log if needed) and lay down BHA. 5. After MU MHA and pull testing the CTC, tag-up on the CT stripper to ensure BHA cannot pull through the brass upon POOH with guns. 6. There will be no perforations to bullhead kill the well. Well will already be loaded w/ weighted brine or KCl per previous steps. Re-load well at WSS discretion. 7. At surface, prepare for deployment of TCP guns. 8.Confirm well is dead. Bleed any pressure off to return tank. Kill well w/ KWF, weighted brine as needed (minimum 8.4 ppg). Maintain continuous hole fill taking returns to tank until lubricator connection is reestablished. Fluids man-watch must be performed while deploying perf guns to ensure the well remains killed and there is no excess flow. 9.Pickup safety joint and TIW valve and space out before MU guns.Review well control steps with crew prior to breaking lubricator connection and commencing makeup of TCP gun string. Once the safety joint and TIW valve have been spaced out, keep the safety joint/TIW valve readily accessible near the working platform for quick deployment if necessary. 10. Break lubricator connection at QTS and begin makeup of TCP guns and blanks per schedule below.Max BHA length per PTD is 500ft. Fluids man-watch must be performed while deploying perf guns to ensure the well remains killed and there is no excess flow. a. Perforation details i.Perf Interval:The well will be perforated between the CTD whipstock and TD of the newly drilled CTD well, completely in the Ivishak pool. ii.Perf Length:500’ iii.Gun Length:500’ iv.Weight of Guns (lbs):2300lbs (4.6ppf) 11. MU lubricator and RIH with perf gun and tie-in to coil flag correlation. Pickup and perforate perforation intervals (TBD). POOH. a. Note any tubing pressure change in WSR. 12. After perforating, PUH to top of liner or into tubing tail to ensure debris doesn’t fall in on the guns and stick the BHA.Confirm well is dead and re-kill if necessary before pulling to surface. 13. Pump pipe displacement while POOH.Stop at surface to reconfirm well dead and hole full. 14. Review well control steps with crew prior to breaking lubricator connection and commencing breakdown of TCP gun string. Standing orders flow chart included with this sundry request. Ensure safety joint and TIW valve assembly are on-hand before breaking off lubricator to LD gun BHA. 15. Freeze protect well to 2,000’ TVD. 16. RDMO CTU. Coiled Tubing BOPs Standing Orders for Open Hole Well Control during Perf Gun Deployment Equipment Layout Diagram Well 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 2.75 ft C L Annular 3.40 ft Bottom Annular 4.75 ft CL Blind/Shears 6.09 ft CL 2.0" Pipe / Slips 6.95 ft B3 B4 B1 B2 Kill Line Choke Line CL 2-3/8" Pipe / Slip 9.54 ft CL 2.0" Pipe / Slips 10.40 ft TV1 TV2 T1 T2 Flow Tee Master Master LDS IA OA LDS Ground Level 3" LP hose open ended to Flowline CDR2-AC BOP Schematic CDR2 Rig's Drip Pan Fill Line from HF2 Normally Disconnected 3" HP hose to Micromotion Hydril 7 1/16" Annular Blind/Shear 2-3/8" Pipe/Slips 2 3/8" Pipe/Slips 2 3/8" Pipe/Slips 7-1/16" 5k Mud Cross 2-3/8" Pipe/Slips 3.0" Pipe / Slip HF nneceeeeeeeeeeeeeeeeeeeeeeeeeeeeeeeeee Well Date Quick Test Sub to Otis Top of 7" Otis Top of Annular C L Annular Bottom Annular CL Blind/Shears CL 2-3/8" Pipe / Slips B6 B5 B8 B7 Choke Line Kill Line CL 3" Pipe / Slip CL 2-3/8" Pipe / Slips TV1 TV2 T1 T2 Flow Tee Master Master LDS IA OA LDS Ground Level CDR3-AC BOP Schematic CDR3 Rig's Drip Pan Fill Line Normally Disconnected 2" HP hose to Micromotion Hydril 7 1/16" Annular Blind/Shear 2-3/8" Pipe/Slips 2 3/8" Pipe/Slips 2 3/8" Pipe/Slips 7-1/16" 5k Mud Cross 2-3/8" Pipe/Slips 3" Pipe / Slip neceeeeeeeeeeeeeeeeeeeeeeeeeeeeeeeeeeee $) $) $) $) $) $) $) $) ! !! !! !!! !!!!!! ! !! ! !! !!!! !!!! ! !!! ! ! !! ! ! ! D $) Prudhoe Bay Unit ADL28313 ADL28310 B-12 B-12A B-16A B-22A B-23 B-29A B-31 X-27 Sec. 32 Sec. 5 Sec. 31 (607) Sec. 6 (609)U010N014E U011N014E B PAD PLAN: B-12B_SHL PLAN: B-12B_TPH PLAN: B-12B_BHL Map Date: 4/24/2024 Prudhoe Bay Unit B-12B Well wp02 E0 550 1,100Feet Legend $)PLAN: B-12B_BHL !PLAN: B-12B_SHL D PLAN: B-12B_TPH $)Other Bottom Holes (BHL) Other Well Paths Pad Footprint Oil and Gas Unit Boundary CO - 341J AIO_3C Well located within PA - IPA Document Path: O:\AWS\GIS\Products\Alaska\NS\Wells\TRS_Distance\mxds\2024\NorthSlope_PBU_B-12B_wp02.mxd -3200-2800-2400-2000-1600-1200-800South(-)/North(+) (800 usft/in)800 1200 1600 2000 2400 2800 3200 3600 4000 West(-)/East(+) (800 usft/in)720076008000840088009185X-27840088009153B-22A76008000840088009178B-02600064006800B-10A600064006800720076008000B-10KOP7200B-26CKOPB-26B44004800520056006000640068007200B-346800720076008000840088009244B-1276008000840088009189B-12A560060006400680072007600800084008800B-2688008 92 7 B-2 6 AKOPKOPKOP 640068007200B-1488008 9 77B-12B wp02Top of Window - 9055'MDEnd 30dls - 9242'MDTD - 11730'MD86008700880089009000True Vertical Depth (200 usft/in)1200 1400 1600 1800 2000 2200 2400 2600 2800 3000 3200 3400 3600 3800 4000 4200 4400 4600 4800 5000 Vertical Section at 120.00° (400 usft/in)B-12B-12AB-12B wp02Top of Window - 9055'MDEnd 30dls - 9242'MDTD - 11730'MDSec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect1 9027.00 43.82 154.80 8720.48 -1555.99 1039.82 0.00 0.00 1678.512 9047.00 45.62 154.80 8734.69 -1568.73 1045.82 9.00 0.00 1690.073 9121.60 68.00 154.80 8775.27 -1624.86 1072.23 30.00 0.00 1741.014 9241.60 68.00 115.97 8820.22 -1702.55 1148.89 30.00 -90.00 1846.245 9352.60 68.00 101.79 8861.80 -1735.77 1246.02 11.84 -90.00 1946.976 9457.60 68.00 115.20 8901.13 -1766.59 1338.13 11.84 90.00 2042.157 9666.02 90.00 127.41 8940.80 -1872.72 1511.09 12.00 30.00 2245.018 9823.48 101.50 142.50 8924.96 -1982.75 1621.60 12.00 52.00 2395.729 9944.00 101.50 127.74 8900.94 -2066.20 1704.70 12.00 -90.00 2509.4210 10089.00 101.50 145.50 8872.03 -2169.05 1801.91 12.00 90.00 2645.0311 10296.00 101.50 120.14 8830.76 -2305.80 1949.48 12.00 -90.00 2841.2012 10416.00 101.50 134.84 8806.83 -2377.18 2042.53 12.00 90.00 2957.4713 10596.00 101.50 112.79 8770.95 -2474.74 2188.17 12.00 -90.00 3132.3814 10697.80 90.00 108.64 8760.76 -2510.47 2282.75 12.00 -160.00 3232.1515 10840.11 77.00 97.47 8776.89 -2542.46 2419.93 12.00 -140.00 3366.9516 10966.00 77.00 112.98 8805.21 -2574.58 2537.93 12.00 90.00 3485.2017 11236.00 77.00 79.72 8865.94 -2603.26 2795.74 12.00 -90.00 3722.8118 11441.00 77.00 104.97 8912.06 -2611.37 2993.70 12.00 90.00 3898.3019 11730.00 77.00 69.37 8977.07 -2597.69 3270.45 12.00 -90.00 4131.13Project: Prudhoe BaySite: BWell: B-12Wellbore: PLAN: B-12BPlan: B-12B wp02WELLBORE DETAILSParent Wellbore:B-12ATop of Window: 9027.00B-12B wp02Depth From Depth To Survey/Plan Tool103.71 7803.71 B-12 Srvy 1 BOSS-GYRO (B-12) 3_Gyro-SR-GMS17820.00 9027.00 B-12A Srvy 1 MWD (B-12A) 3_MWD9027.00 11730.00 B-12B wp02 (PLAN: B-12B) 3_MWDWELL DETAILSNorthing: 5948801.00Easting: 664052.00Lattitude: 70° 15' 59.2723 NLongitude: 148° 40' 24.3859 WB-12B wp02SECTION DETAILSHilcorp Alaska, LLCSURVEY PROGRAMNAD 1927 (NADCON CONUS)US State Plane 1927 (Exact solution)Alaska Zone 04PROJECT DETAILSREFERENCE INFORMATIONCoordinate(N/E) Reference: Well B-12, True NorthVertical (TVD) Reference: KB @ 68.20usft (B-12A)Measured Depth Reference: KB @ 68.20usft (B-12A)Section (VS) Reference: Slot - (0.00N, 0.00E)Calculation Method: Minimum CurvatureREFERENCE INFORMATION ! 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' 8 & ;< $/= % E "> 6' +, # . !:F *' :"F "G "!"""" 2## 0( + 2## 0 # 0( + !"# $% * ' +, 7 # / 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 no greater 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 OILPRUDHOE BAY PBU B-12B 224-133 WELL PERMIT CHECKLISTCompanyHilcorp North Slope, LLCWell Name:PRUDHOE BAY UNIT B-12BInitial Class/TypeDEV / PENDGeoArea890Unit11650On/Off ShoreOnProgramDEVField & PoolWell bore segAnnular DisposalPTD#:2241330PRUDHOE BAY, PRUDHOE OIL - 640150NA1Permit fee attachedYesADL0283102Lease number appropriateYes3Unique well name and numberYesPRUDHOE BAY, PRUDHOE OIL - 640150 - governed by CO 341J4Well 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)NAThis well is an in-zone CTD sidetrack from an existing wellbore with pressure integrity.18Conductor string providedNAAll drilling on this sidetrack will be below the existing SC shoe.19Surface casing protects all known USDWsNAThis well is an in-zone CTD sidetrack from an existing wellbore with pressure integrity.20CMT vol adequate to circulate on conductor & surf csgNAThis well is an in-zone CTD sidetrack from an existing wellbore with pressure integrity.21CMT vol adequate to tie-in long string to surf csgYesFully cemented production liner will isolate the parent wellbore.22CMT will cover all known productive horizonsYes23Casing designs adequate for C, T, B & permafrostYesCDR2 and CDR3 have adequate tankage and good trucking support.24Adequate tankage or reserve pitYes25If a re-drill, has a 10-403 for abandonment been approvedYesNo wells with SF < 1.26Adequate wellbore separation proposedNAAll drilling will be below the SC shoe.27If diverter required, does it meet regulationsYesMPD w/8.4 ppg mud, and res pressure of 7.2 ppg equivalent.28Drilling fluid program schematic & equip list adequateYesCT packoff, flow cross, annular, blind/shear, CT pipe slips, flow cross, BHA pipe slips, CT pipe slips29BOPEs, do they meet regulationYes7-1/16" 5000 psi stack, pressure tested to 3500 psi.30BOPE press rating appropriate; test to (put psig in comments)YesFlanged choke and kill lines between dual combis w/remote choke.31Choke manifold complies w/API RP-53 (May 84)Yes32Work will occur without operation shutdownYesPrudhoe's B-Pad is an H2S pad. Max H2S recorded was 160 ppm. Monitoring will be conducted.33Is presence of H2S gas probableNAThis is a development well.34Mechanical condition of wells within AOR verified (For service well only)NoMax H2S recorded on DS/Pad: 160 ppm35Permit can be issued w/o hydrogen sulfide measuresYesExpected reservoir pressure is 7.2 ppg EMW. MPD to be employed.36Data presented on potential overpressure zonesNAOne fault crossing expected.37Seismic analysis of shallow gas zonesNA38Seabed condition survey (if off-shore)NA39Contact name/phone for weekly progress reports [exploratory only]ApprADDDate10/30/2024ApprWCBDate12/4/2024ApprADDDate10/30/2024AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDate*&:JLC 12/18/2024