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Home My WebLink About224-090Nolan 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: 2/8/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20240208 Well API #PTD #Log Date Log Company Log Type BCU 09A 50133204450100 224113 11/13/2024 YELLOWJACKET GPT-PERF BCU 09A 50133204450100 224113 10/30/2024 YELLOWJACKET GPT BCU 11A 50133205210100 224123 11/9/2024 YELLOWJACKET SCBL BCU 25 50133206440000 214132 11/2/2024 YELLOWJACKET SCBL END 2-74 REVISED 50029237850000 224024 12/5/2024 HALLIBURTON MFC24 HVA 10 50231200280000 204186 11/13/2024 YELLOWJACKET GPT-PERF KU 23-07A 50133207300000 224126 11/23/2024 YELLOWJACKET SCBL NCIU A-21 50883201990000 224086 11/29/2024 AK E-LINE CaliperSurvey PAXTON 6 50133207070000 222054 11/7/2024 YELLOWJACKET PERF PBU 01-37 50029236330000 219073 11/23/2024 BAKER MRPM PBU 06-15A 50029204590200 224108 12/26/2024 BAKER MRPM PBU 06-19B 50029207910200 224095 12/10/2024 BAKER MRPM PBU 07-29E 50029217820500 213001 11/26/2024 BAKER SPN PBU 14-31A 50029209890100 224090 11/10/2024 BAKER MRPM PBU 14-41A 50029222900100 224076 11/9/2024 BAKER MRPM SRU 241-33B 50133206960000 221053 11/5/2024 YELLOWJACKET GPT-PERF Revision Explanation: Annotations added to processed log. Please include current contact information if different from above. T40053 T40053 T40054 T40055 T40056 T40057 T40058 T40059 T40060 T40061 T40062 T40063 T40064 T40065 T40066 T40067 PBU 14-31A 50029209890100 224090 11/10/2024 BAKER MRPM Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.02.07 13:25:23 -09'00' Nolan 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: 1/16/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20240116 Well API #PTD #Log Date Log Company Log Type AOGCC ESet # BCU 09A 50133204450100 224113 10/26/2024 YELLOWJACKET SCBL BCU 12A 50133205300100 214070 8/21/2024 YELLOWJACKET GPT-PLUG-PERF BRU 233-23T 50283202000000 224088 12/28/2024 AK E-LINE PPROF BRU 233-27 50283100260000 163002 12/31/2024 AK E-LINE PPROF BRU 243-34 50283201240000 208079 12/27/2024 AK E-LINE PPROF GP 03-87 50733204370000 166052 12/25/2024 AK E-LINE CBL GP AN-17A 50733203110100 213049 12/16/2024 AK E-LINE CBL GP AN-17A 50733203110100 213049 12/21/2024 AK E-LINE Perf GP BR-03-87 50733204370000 166052 1/3/2025 AK E-LINE CBL IRU 44-36 50283200890000 193022 1/3/2024 AK E-LINE Depth Determination/Plug IRU 44-36 50283200890000 193022 12/26/2024 AK E-LINE DepthDetermination KU 31-07X 50133204950000 200148 12/3/2024 AK E-LINE Perf MPU B-21 50029215350000 186023 1/4/2025 AK E-LINE PlugSettingRecord MPU H-08B 50029228080200 201047 12/28/2024 AK E-LINE Welltech MRU G-01RD 50733200370100 191139 12/12/2024 AK E-LINE IPROF MRU G-01RD 50733200370100 191139 12/18/2024 AK E-LINE Perf MRU M-25 50733203910000 187086 12/3/2024 AK E-LINE Perf MRU M-25 50733203910000 187086 12/19/2024 AK E-LINE Perf PBU 01-37 50029236330000 219073 11/23/2024 HALLIBURTON PPROF PBU 06-05 50029202980000 178020 12/21/2024 HALLIBURTON RBT PBU 06-19B 50029207910200 224095 12/11/2024 HALLIBURTON RBT PBU 11-38A 50029227230100 198216 11/27/2024 HALLIBURTON TEMP PBU 14-31A 50029209890100 224090 11/11/2024 HALLIBURTON RBT PBU L-103 50029231010000 202139 11/25/2024 HALLIBURTON IPROF PBU M-207 50029238070000 224141 12/25/2024 HALLIBURTON RBT PBU P2-55 50029222830000 192082 12/5/2024 HALLIBURTON PPROF PBU S-15 50029211130000 184071 11/18/2024 HALLIBURTON RBT TBU M-25 50733203910000 187086 12/13/2024 AK E-LINE Perf T39958 T39959 T39960 T39961 T39962 T39963 T39964 T39964 T39965 T39966 T39966 T39967 T39968 T39969 T39970 T39970 T39971 T39971 T39972 T39973 T39974 T39975 T39976 T39977 T39978 T39979 T39980 T39981 PBU 14-31A 50029209890100 224090 11/11/2024 HALLIBURTON RBT Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.01.16 13:56:40 -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: 11/22/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL WELL: PBU 14-31A PTD: 224-090 API: 50-029-20989-01-00 FINAL LWD FORMATION EVALUATION LOGS (10/23/2024 to 10/28/2024) 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. 224-090 T39798 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.11.22 14:11:31 -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 Monty M. Myers Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK, 99503 Re: Prudhoe Bay Field, Prudhoe Oil Pool, PBU 14-31A Hilcorp Alaska, LLC Permit to Drill Number: 224-090 Surface Location: 157' FSL, 1317' FEL, Sec. 04, T10N, R14E, UM, AK Bottomhole Location: 327' FSL, 562' FWL, Sec. 03, T10N, 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, Jessie L. Chmielowski Commissioner DATED this 29th day of August 2024. Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.08.29 11:06:44 -08'00' Drilling Manager 06/28/24 Monty M Myers By Grace Christianson at 1:08 pm, Jun 28, 2024 A.Dewhurst 27AUG24 *BOPE test to 3500 psi. Annular to 2500 psi. *Variance to 20 AAC 25.112(I) approved for alternate plug placement with fully cemented production liner. WCB 8-6-2024 50-029-20989-01-00 * Approved for post rig perforating with perf gun BHA not to exceed 500' in length. 224-090 DSR-7/8/24 MGR06AUG2024 *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.08.29 11:06:56 -08'00'08/29/24 08/29/24 RBDMS JSB 083024 To: Alaska Oil & Gas Conservation Commission From: Ryan Ciolkosz Drilling Engineer Date: June 27, 2024 Re:14-31A Permit to Drill Approval is requested for drilling a CTD sidetrack lateral from well 14-31 with the Nabors CDR2/CDR3 Coiled Tubing Drilling. Proposed plan for 14-31A Producer: See 14-31 Sundry request for complete pre-rig details - Prior to drilling activities, Slickline will drift for a whipstock, dummy the GLVs, and caliper the casing/tubing. 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. CDR will set a 4-1/2"x 9-5/8" whipstock at 9360' MD and mill a single string 3.80" window + 10' of formation. The well will kick off drilling in Ivishak Zone 4 and drill an S-shaped well through Zones 4/3/2 to TD. The proposed sidetrack will be completed with a 3-1/2" x 3-1/4" x 2-7/8" 13Cr solid liner, cemented in place and selectively perforated post rig. This completion will target isolating and abandoning 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 14-31 Sundry submitted in concert with this request for full details. 1. Slickline : Dummy GLV, WS drift, and Caliper 2. Fullbore : MIT 3. Valve Shop : Pre-CTD Tree Work 4. Operations : Remove wellhouse and level pad. Rig Work: (Estimated to start in October 2024) 1. MIRU and test BOPE 250 psi low and 3,500 psi high (MASP 2,460 psi). 2. Set 4-1/2" x 9-5/8" Whipstock at 9360' @ 170 deg True North (Use Gyro to orient) 3. Mill 3.80” Window (Use Gyro to orient) 4. Drill build section: 4.25" OH, ~249' (35 deg DLS planned). 5. Drill production lateral: 4.25" OH, ~2161' (12 deg DLS planned). 6. Run 3-1/2” x 3-1/4” x 2-7/8” 13Cr liner with BSELRT and C2 Sleeve 7. Pump primary cement job: 42 bbls, 15.3 ppg Class G, TOC at TOL*. 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 : Set LTP* (if necessary). Set live GLVs. 3. Service Coil : Post rig perforate (~30’)/CBL/RPM. CDR2/CDR3 PTD 224-090 Sundry 324-375 CDR2/CDR3 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” (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 (9360' MD -8,653' TVD) Pumps On Pumps Oī A Target BHP at Window (ppg)4,410 psi 4,410 psi 9.8 B ŶŶƵůĂƌĨƌŝĐƟŽŶ- ECD ;ƉƐŝͬŌͿ 562 psi 0 psi 0.09 C DƵĚ,ǇĚƌŽƐƚĂƟĐ;ƉƉŐͿ 3,870 psi 3,870 psi 8.6 B+C Mud + ECD Combined 4,431 psi 3,870 psi (no choke pressure) A-(B+C)Choke Pressure Required to Maintain 0 psi 540 psi Target BHP at window and deeper Operation Details: Reservoir Pressure: x The estimated reservoir pressure is expected to be 3,267 psi at 8,800 TVD. (7.1 ppg equivalent). x Maximum expected surface pressure with gas (0.10 psi/ft) to surface is 2,460 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. Liner Program: x 3-1/2", 9.3#, 13Cr/Solid: 9,160' MD – 9,350' MD (190' liner) x 3-1/4", 6.6#, 13Cr/Solid: 9,350' MD – 9,700' MD (350' liner) x 2-7/8", 6.5#, 13Cr/Solid: 9,700' MD – 11,770' MD (2,070' 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” 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 105°. Inclination at kick off point is 0°. x Magnetic and inclination surveys will be taken every 30 ft. No gyro will be run. x Distance to nearest property line – ~17,500' 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 Ivishak pool. x Formations: Top of Ivishak 9342’ MD in the parent Anti-Collision Failures: x No anti-collision failures with 14-31A WP02 Hazards: x DS/Pad is an H2S pad. The last H2S reading on 14-31: 58 ppm on 03/24/2023. x Max H2S recorded on DS/Pad: 140 ppm.. x 0 fault crossings expected. x Moderate 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 (ddinclude 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 $) $) $) $) $) $) !! !!!!! !! !! !! ! ! ! ! !!!!! !! !!!!! !! !! ! !! !! !!!! ! ! ! ! D $)PLAN: 14-31A_BHL PLAN: 14-31A_TPH PLAN: 14-31A_SHL Oil Rim PAGas Cap PAADL028312 DS14 AIDEA FS3 U010N014E Sec. 4 Sec. 9 Sec. 3 Sec. 10 PRUDHOE BAY UNIT 14-41 14-35 14-31 14-20 14-05 14-05A Map Date: 2/16/2024 Prudhoe Bay Unit 14-31A Well wp02 E0290580 Feet Legend T14_31A_wp02 $)PLAN: 14-31A_BHL !PLAN: 14-31A_SHL D PLAN: 14-31A_TPH $)Other Bottom Holes (BHL) Other Well Paths Pad Footprint PA Boundary CO_341J AIO_4G Document Path: O:\AWS\GIS\Products\Alaska\NS\Wells\TRS_Distance\mxds\2024\NorthSlope_14-31A wp02.mxd -50005001000150020002500South(-)/North(+) (1000 usft/in)-500 0 500 1000 1500 2000 2500 3000 3500 West(-)/East(+) (1000 usft/in)893707-20C8 80 0 9 0 0 1 1 4 -1 6 A 480052005600600064006 80 07200 760080008400880014-16BPB14800520056006000640068007200760080008400 9 2 0 0936114-1 6 14-16B1 4-1 6A P B 1 40080012001600200024002 8 0 0 3 2 0 0 3 60 0 4 0 0 0 4 4 0 0 48 0 0 5 2 00 5600 6 0 0 0 14-33 4000440048005200560060006400680072007600800014 -03 400800120016002000240028003 2 0 036004000440048005200560060006400 6800720076008000840088009200937014-41880014-41A wp0140080012001600200024002800320036004000440048005200560060006400680014-4340080012001600200024002800320036004000440048005200560060006400680072008400880092 00922914-3 14008001200160020002400280032003 6 0 0 4 00 0 4 4 0 048005200 5 60 0 6 0 00 6 4 0 0 6 800 7 20 0 7 6 00 8 0 0 0 8 4 0 014-32 14-32A2800 3200 3600 4000 4400 480 0 52005600 14-34400800120016002000 240 0 2800 3200320214-34P B 1 2 80 0 3 2 0 0 36 00 4 0 0 0 4400 4 8 0 0 5 200 5 6 0 0 1 4-3 4P B 2 400800120016002000240028 0 0320036004000440048005200 560060 0 0 6 4 00 6 8 0 0 72 0 0 7 6 00 8 0 0 0 84 0088009200924314-35870014-02CL18800890314-31A wp02Top of Window - 9360'MDEnd 35dls - 9609'MDTD - 11770'MD87008800890090009100True Vertical Depth (200 usft/in)-2400 -2200 -2000 -1800 -1600 -1400 -1200 -1000 -800 -600 -400 -200 0 200 400 600 800 1000 1200 1400 Vertical Section at 165.00° (400 usft/in)14-3114-31A wp02Top of Window - 9360'MDEnd 35dls - 9609'MDTD - 11770'MDSec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect1 9360.00 0.84 329.30 8719.36 2283.49 1227.60 0.00 0.00 -1887.952 9380.00 0.98 167.82 8739.35 2283.44 1227.56 9.00 -170.00 -1887.923 9450.00 25.48 167.82 8806.98 2267.90 1230.92 35.00 0.00 -1872.044 9608.62 81.00 167.82 8898.23 2148.48 1256.70 35.00 0.00 -1750.025 9774.00 81.00 187.91 8924.10 1986.09 1262.76 12.00 90.00 -1591.596 9976.00 81.00 163.37 8955.70 1788.67 1277.82 12.00 -90.00 -1397.007 10055.72 90.00 160.11 8961.95 1713.29 1302.71 12.00 -20.00 -1317.748 10184.50 104.50 165.51 8945.73 1591.65 1340.45 12.00 20.00 -1190.489 10285.00 104.50 177.96 8920.57 1495.55 1354.41 12.00 90.00 -1094.0410 10465.00 104.50 155.66 8875.50 1326.95 1393.92 12.00 -90.00 -920.9611 10625.00 104.50 175.48 8835.44 1177.68 1432.33 12.00 90.00 -766.8412 10820.00 104.50 151.32 8786.61 998.09 1485.86 12.00 -90.00 -579.5213 10934.00 104.50 165.45 8758.07 895.75 1526.41 12.00 90.00 -470.1614 11062.23 90.00 160.24 8741.92 774.59 1563.91 12.00 -160.00 -343.4315 11191.00 75.50 154.84 8758.14 656.86 1612.48 12.00 -160.00 -217.1416 11321.00 75.50 138.73 8790.69 551.91 1681.19 12.00 -90.00 -97.9817 11546.00 75.50 166.61 8847.03 360.30 1780.22 12.00 90.00 112.7418 11770.00 75.50 138.86 8903.11 169.41 1878.60 12.00 -90.00 322.58Project: Prudhoe BaySite: 14Well: 14-31Wellbore: PLAN: 14-31APlan: 14-31A wp02WELLBORE DETAILSParent Wellbore:14-31Top of Window: 9360.0014-31A wp02Depth From Depth To Survey/Plan Tool100.00 9360.00 1 : Camera based gyro multisho (14-31)3_CB-Film-GMS29360.00 11770.00 14-31A wp02 (PLAN: 14-31A) 3_MWDWELL DETAILSNorthing: 5940495.50Easting: 675120.04Lattitude: 70° 14' 35.1523 NLongitude: 148° 35' 7.9276 W14-31A wp02SECTION DETAILSHilcorp Alaska, LLCSURVEY PROGRAMNAD 1927 (NADCON CONUS)US State Plane 1927 (Exact solution)Alaska Zone 04PROJECT DETAILSREFERENCE INFORMATIONCoordinate(N/E) Reference: Well 14-31 - Slot 31, True NorthVertical (TVD) Reference: KB @ 69.00usft (53 : 31 7/22/1983 00:00)Measured Depth Reference: KB @ 69.00usft (53 : 31 7/22/1983 00:00)Section (VS) Reference: Slot - 31(0.00N, 0.00E)Calculation Method: Minimum CurvatureREFERENCE INFORMATION ! " #$ % & ! ' $ ! ( )*+ ( , ,- .$! /" !""# $%&'())*+, -.//.'0)) ))1 +0 2)/ +-34!5! 63 /+ ($%&'())*+, -.//.'0)) ))1 % " ( 7 6 / $' 1 +' & / 2 $'+'8 '/-+39 1 4'/-+ 4::81 8;6346 63 <) ! # 8=7* 8== * 3 ' 0 4$ % "0 50 1! .0 6) * ! * * >(/ ?) , '' ,--( &- ,)(0 )()) -)>@/&(,0 0>,@&(-/&)7 , , 0 50 % "0 * 657, 6%7 4$ * * *1 . * * )()) )()) , ') ',(,) &-, /)() '()/,"5. *)()) -)>@,(,/ 0>,@-('/-&7 ,- + 89: 30" 8): ' + + 0 89: / %'/0 "* % +0 2)/ * + "3 '8)*+: 8(: 6%7 8(: + 89: 657, 8(: );+ "' &)()) &,()))()))())/-()) & ! ' $ ! 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B" 4858 < - #(*# #(*# #(*# @# @ - - @# @ @# - - @ # # # @ # # # @ @ & & & @ #* #* #* @# 5 ; 5 4 6 . 2 ' . = - !*( %5? , C # ;. 23 $ ' "D 1. &#D #E #"#### 8$$ 6/ 2 8$$ 6 $ 6/ 2 !"##$ %& ' ()**)!+ ## 1 . 23 < $ 5 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 Distances from top of riser Excluding quick-test sub Top of Annular C L Annular Bottom Annular CL Blind/Shears CL 2.0" Pipe / Slips B3 B4 B1 B2 Kill Line Choke Line CL 2-3/8" Pipe / Slip CL 2.0" Pipe / Slips TV1 TV2 T1 T2 Flow Tee Master Master LDS IA OA LDS Ground Level 3" LP hose open ended to Flowline CDR3-AC BOP Schematic CDR3 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 neceeeeeeeeeeeeeeeeeeeeeeeeeeeeeeeeeeee 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. PBU 14-31A 224-090 PRUDHOE BAY PRUDHOE OIL WELL PERMIT CHECKLISTCompanyHilcorp North Slope, LLCWell Name:PRUDHOE BAY UNIT 14-31AInitial Class/TypeDEV / PENDGeoArea890Unit11650On/Off ShoreOnProgramDEVField & PoolWell bore segAnnular DisposalPTD#:2240900PRUDHOE BAY, PRUDHOE OIL - 640150NA1Permit fee attachedYesADL0283122Lease 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. Parent well isolates the reservoir.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 pitYesSundry 324-37525If a re-drill, has a 10-403 for abandonment been approvedYesAll separation factors greater than 1.26Adequate wellbore separation proposedNAAll drilling will be below the SC shoe.27If diverter required, does it meet regulationsYesMPD but reservoir pressure of 7.1 ppg equivalent is below water gradient of 8.33 ppg.28Drilling fluid program schematic & equip list adequateYesCT packoff, flow cross, annular, blind/shear rams, 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 DS-14 is an "H2S pad." 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)NoDS 14 wells are H2S-bearing. H2S measures are required.35Permit can be issued w/o hydrogen sulfide measuresYesAnticipated pore pressure of 7.1 ppg EMW. MPD to be employed. No faults anticipated.36Data presented on potential overpressure zonesNA37Seismic analysis of shallow gas zonesNA38Seabed condition survey (if off-shore)NA39Contact name/phone for weekly progress reports [exploratory only]ApprADDDate8/27/2024ApprDateApprADDDate8/27/2024AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDate*&:JLC 8/29/2024