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Home My WebLink About221-076Nolan 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: 1/21/2026 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20260121 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# BCU 16RD 50133205540100 207125 12/3/2025 AK E-LINE PPROF T41253 BRU 211-35 50283201890000 223050 11/7/2025 AK E-LINE Perf T41254 BRU 213-26 50283201920000 223069 11/23/2025 AK E-LINE Perf T41255 BRU 213-26T 50283202040000 225038 11/4/2025 AK E-LINE Perf T41256 BRU 241-34S 50283201980000 224077 11/9/2025 AK E-LINE Perf T41257 BRU 241-34T 50283201810000 220052 11/6/2025 AK E-LINE Perf T41258 BRU 244-27 50283201850000 222038 12/13/2025 AK E-LINE Perf T41259 BRU 244-27 50283201850000 222038 12/19/2025 AK E-LINE StripGun T41259 GP ST 17586 9 50733204480000 193062 11/13/2025 AK E-LINE Perf T41260 IRU 241-01 50283201840000 221076 12/21/2025 AK E-LINE Perf T41261 IRU 241-01 50283201840000 221076 12/30/2025 AK E-LINE Perf T41261 IRU 241-01 50283201840000 221076 12/16/2025 AK E-LINE Plug T41261 IRU 241-01 50283201840000 221076 11/26/2025 AK E-LINE Plug/Perf T41261 KALOTSA 01 50133206570000 216132 11/19/2025 AK E-LINE Perf T41262 KBU 31-18 50133206490000 215024 11/8/2025 AK E-LINE Drift/PPROF T41263 KU 12-17 50133205770000 208089 11/14/2025 AK E-LINE StimGun T41264 LRU C-01RD 50283200610100 201168 11/27/2025 AK E-LINE RCT/Perf T41265 MPI 2-32 50029220840000 190119 12/10/2025 AK E-LINE LDL T41266 MPI 2-38 50029220900000 190129 12/5/2025 AK E-LINE LDL T41267 MPU H-16 50029232270000 204190 12/3/2025 AK E-LINE CBL T41268 MPU H-16 50029232270000 204190 11/19/2025 AK E-LINE TubingCut T41268 MPU I-14 50029232140000 204119 11/13/2025 AK E-LINE CBL T41269 NCIU A-06A 50883200260100 225071 11/28/2025 AK E-LINE Perf/Plug T41270 NCIU A-08 50883200280000 169063 12/2/2025 AK E-LINE GPT T41271 NCIU A-19 50883201940000 224026 12/16/2025 AK E-LINE GPT T41272 NCIU A-19 50883201940000 224026 12/12/2025 AK E-LINE GPT/Perf/Plug T41272 NCIU A-19 50883201940000 224026 12/17/2025 AK E-LINE Perf T41272 NCIU A-21A 50883201990100 225075 12/30/2025 AK E-LINE PPROF T41273 OP19-T1N 50029234910000 213068 11/19/2025 AK E-LINE TubingPunch T41274 T41261IRU 241-01 50283201840000 221076 12/21/2025 AK E-LINE Perf T41261IRU 241-01 50283201840000 221076 12/30/2025 AK E-LINE Perf T41261IRU 241-01 50283201840000 221076 12/16/2025 AK E-LINE Plug IRU 241-01 50283201840000 221076 11/26/2025 AK E-LINE Plug/Perf Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2026.01.21 13:56:35 -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: PCU D-10 50283202080000 225082 12/9/2025 AK E-LINE Perf T41275 SCU 322C-04 50133101040100 215217 12/4/2025 AK E-LINE TubingPunch T41276 SRU 222-33 50133207150000 223100 12/7/2025 AK E-LINE Plug T41277 SU 43-10 50133207390000 225107 11/26/2025 AK E-LINE CBL T41278 TBU A-12RD 50733200760100 171029 11/29/2025 AK E-LINE Perf T41279 TBU D-24A 50733202240100 174064 12/2/2025 AK E-LINE TubingPunch T41280 TBU D-24A 50733202240100 174064 11/21/2025 AK E-LINE TubingPunch T41280 TBU M-10 50733205880000 209154 11/15/2025 AK E-LINE Perf T41281 Please include current contact information if different from above. Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2026.01.21 13:56:51 -09'00' 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address: Stratigraphic Service 6. API Number: 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number): 10. Field: 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 9,585' N/A Casing Collapse Structural Conductor 1,410psi Surface 2,470psi Intermediate 4,790psi Production 7,500psi Liner Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16. Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng chelgeson@hilcorp.com 907-777-8405 Noel Nocas, Operations Manager 907-564-5278 Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY Chad Helgeson AOGCC USE ONLY Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL032930 221-076 50-283-20184-00-00 Hilcorp Alaska, LLC Proposed Pools: 12.6 / L-80 TVD Burst 5,818' 8,430psi 2,586' 120' 7-5/8"5,994' 3,005' MD 5,994' Length 5,116 - 5,381 6,880psi 2,980psi 5,210psi 120' 4,915' 120' 3,005' December 2, 2025 Tieback 4-1/2" 9,585' Perforation Depth MD (ft): 6,253 - 6,590 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Ivan River Unit (IRU) 241-01CO 795 Same 7,733'4-1/2" ~1978psi 3,774' See Schematic Size Other: LTP; N/A 5,811' MD / 4,772' TVD; N/A 7,732' 6,214' 5,086' Ivan River Undefined Gas Pool 16" 10-3/4" m n P s 66 t N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 9:45 am, Nov 18, 2025 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2025.11.17 17:06:17 - 09'00' Noel Nocas (4361) 325-708 BJM 11/20/25 10-404 A.Dewhurst 18NOV25 DSR-11/19/25JLC 11/20/2025 11/20/25 Well Prognosis Well Name: IRU 241-01 API Number: 50-283-20184-00-00 Current Status: Flowing Gas Well Permit to Drill Number: 221-076 First Call Engineer: Chad Helgeson (907) 777-8405 (O) (907) 229-4824 (C) Second Call Engineer: Scott Warner (907) 830-8863 Maximum Expected BHP: 2169 psi @ 5046 TVD (Based on 0.43 psi/ft gradient)) Max. Potential Surface Pressure: 1978 psi (Based on 0.038 psi/ft gas gradient to surface) Applicable Frac Gradient: 0.69 psi/ft using 13.19 ppg EMW FIT at the surface casing shoe 7/15/22 Shallowest Potential Perf TVD: MPSP/(0.69-0.038) = 1978 psi / 0.65 = 3043 TVD Top of Pools per CO 614: Ivan River Undefined Gas Pool Well Status: Well flowing @ 267 mcf @ 95 psi Brief Well Summary: IRU 241-01 started drilling in late 2021 and completed as a Beluga and Sterling producer in Summer of 2022. Initial production started in August of 2022 with rates of 5.8 mmscfd. Additional sands were perforated in 2024 to keep well unloaded and flowed until the well died in March of 2025. A coil tubing cleanout was completed and perfs were added with screen in the well, flowing steady until recently dropping to ~250 mcf. The well is below the unload rate and additional zones need to be added. The purpose of this sundry is to add perforations in the Sterling Sands. All sands lie in the Ivan River Undefined Gas Pool. Wellbore Conditions: The well has a 4.5 cemented liner (Top of Good Cement 6037) Current top open perf @ 6144-6,148 SL tag depth: 6134 on 10/13/25 Top of screen above perfs Procedure: 1. Review all approved COAs 2. SL MIRU PT Lubricator 250/2500 psi 3. Pull screen if possible 4. RDMO SL 5. RU Eline PT Lubricator 250 psi low / 2500 psi high 6. Pressure well with sales gas ~800 psi 7. Perforate and test Beluga sands within the interval below, from the bottom up: a. If any zone produces sand and/or water or needs isolated, RIH and set plug above the perforations (no cement due to how close each zone is). b. Pending well production, all perf intervals may not be completed 8. RDMO Eline Formation MD TOP MD BASE TVD TOP TVD BASE H ST X3 ±6,043 ±6,049 ±4,953 ±4,957 ±6 ST A1 ±6,068 ±6,073 ±4,972 ±4,976 ±5 ST A2 ±6,078 ±6,093 ±4,980 ±4,992 ±15 ST A2 ±6,096 ±6,111 ±4,994 ±5,006 ±15 Well Prognosis 9. Set new screen over zone with SL or Eline, pending tool availability. 10. Turn well over to production & flow test well Attachments: 1. Current Well Schematic 2. Proposed Well Schematic _____________________________________________________________________________________ Updated by DMA 05-30-25 SCHEMATIC Well: Ivan River 241-01 PTD: 221-076 API: 50-283-20184-00-00 PERFORATION DETAIL Zone Top MD Btm MD Top TVD Btm TVD FT Date Status ST A3 6,1446,1485,0325,03545/16/25 Open ST A3 6,1536,1635,0395,046105/10/25 Open ST A5 6,2536,2655,1165,126122/26/24 Isolated ST A5 6,2796,2875,1375,14384/30/25 Isolated ST B1 6,3066,3235,1585,172178/31/22 Isolated ST B2 6,3356,3455,1815,188102/25/24 Isolated ST B2 6,355 6,361 5,196 5,201 62/25/24 Isolated ST B2 6,370 6,378 5,208 5,214 82/25/24 Isolated Beluga U 6,576 6,590 5,368 5,381 1408/25/22 Isolated Beluga D1 6,638 6,647 5,418 5,425 908/24/22 Isolated Beluga E5d 7,170 7,180 5,829 5,839 1008/13/22 Isolated BEL H4u 8,233 8,242 6,667 6,674 908/12/22 Isolated BEL H4m 8,254 8,263 6,684 6,691 908/12/22 Isolated BEL H4L 8,289 8,309 6,712 6,727 2008/12/22 Isolated BEL H8 8,395 8,415 6,795 6,811 2008/12/22 Isolated BEL H15 8,698 8,713 7,033 7,045 1508/10/22 Isolated BEL I3 9,001 9,006 7,272 7,277 508/10/22 Isolated BEL I5 9,103 9,119 7,351 7,364 1608/10/22 Isolated BEL I8 9,202 9,215 7,427 7,438 1308/10/22 Isolated OPEN HOLE / CEMENT DETAIL 10-3/4TOC @ Surface 7-5/8"Est. TOC @ 1,677 Pumped 40% excess (good returns during job, no cement returns off top of liner) 4-1/2Pumped 118bbls (290 sx) of 12 ppg lead followed by 23 bbls (95 sx) of 15.3 ppg tail. (30 bbls of spacer & 48 bbls of cement to surface) TOC @ 6,037 CBL (8-5-22) CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16Conductor Driven to Set Depth 84 X-56 Weld 15.01Surf 120 10-3/4Surf Csg 45.5 L-80 DWC/C 9.950Surf 3,005 7-5/8"Int. Csg 29.7 L-80 CDC 6.875Surf 5,994 4-1/2"Prod Lnr 12.6 L-80 DWC/C HT 3.9585,8119,585 4-1/2"Prod Tieback 12.6 L-80 DWC/C HT 3.958Surf 5,818 JEWELRY DETAIL No. Depth ID OD Item 1 5183.9585.840Chem Injection Mandrel 2 2,7376.8759.9507-5/8 Swell Packer 3 5,8114.8756.540Flex-Lock V Liner hanger / HRD-E ZXP LTP Assembly 5,8184.8905.700Tieback Seal Assy. (2.92 off no-go) 4 6,134Screen assembly top 24ft OAL (See notes below for screen details) 5 6,240CIBP w 26 cement TOC @ 6,214 (5/8/25) 6 6,290CIBP (4/28/25) 7 6,6283.9583.5 Big Boy CIBP (8/25/22) 8 7,1003.9583.5 Big Boy CIBP (8/21/22) 9 8,2003.71CIBP (08/12/22) 10 8,6683.71CIBP(08/10/22) NOTES Screen Detail AA stop set at 6134 above a D&D Packoff w/ G Fish neck,w/ KOBE KO assembly, w/ 13 2-3/8 HES screen on top od AD-2 Stop set at 6,165. (6- 8 prong w/ 1.9-2.0 swedge to knockout Kobe to equalize before pulling AA stop.) _____________________________________________________________________________________ Updated by CAH 11-12-25 PROPOSED Well: Ivan River 241-01 PTD: 221-076 API: 50-283-20184-00-00 PERFORATION DETAIL Zone Top MD Btm MD Top TVD Btm TVD FT Date Status ST X3 ±6,043±6,049±4,953±4,957±6TBD Proposed ST A1 ±6,068±6,073±4,972±4,976±5TBD Proposed ST A2 ±6,078±6,093±4,980±4,992±15TBD Proposed ST A2 ±6,096 ±6,111 ±4,994 ±5,006 ±15TBD Proposed ST A3 6,1446,1485,0325,03545/16/25 Open ST A3 6,1536,1635,0395,046105/10/25 Open ST A5 6,253 6,265 5,116 5,126 122/26/24 Isolated ST A5 6,2796,2875,1375,14384/30/25 Isolated ST B1 6,306 6,323 5,158 5,172 178/31/22 Isolated ST B2 6,335 6,345 5,181 5,188 102/25/24 Isolated ST B2 6,355 6,361 5,196 5,201 62/25/24 Isolated ST B2 6,370 6,378 5,208 5,214 82/25/24 Isolated Beluga U 6,576 6,590 5,368 5,381 1408/25/22 Isolated Beluga D1 6,638 6,647 5,418 5,425 908/24/22 Isolated Beluga E5d 7,170 7,180 5,829 5,839 1008/13/22 Isolated BEL H4u 8,233 8,242 6,667 6,674 908/12/22 Isolated BEL H4m 8,254 8,263 6,684 6,691 908/12/22 Isolated BEL H4L 8,289 8,309 6,712 6,727 2008/12/22 Isolated BEL H8 8,395 8,415 6,795 6,811 2008/12/22 Isolated BEL H15 8,698 8,713 7,033 7,045 1508/10/22 Isolated BEL I3 9,001 9,006 7,272 7,277 508/10/22 Isolated BEL I5 9,103 9,119 7,351 7,364 1608/10/22 Isolated BEL I8 9,202 9,215 7,427 7,438 1308/10/22 Isolated OPEN HOLE / CEMENT DETAIL 10-3/4TOC @ Surface 7-5/8"Est. TOC @ 1,677 Pumped 40% excess (good returns during job, no cement returns off top of liner) 4-1/2Pumped 118bbls (290 sx) of 12 ppg lead followed by 23 bbls (95 sx) of 15.3 ppg tail. (30 bbls of spacer & 48 bbls of cement to surface) TOC @ 6,037 CBL (8-5-22) CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16Conductor Driven to Set Depth 84 X-56 Weld 15.01Surf 120 10-3/4Surf Csg 45.5 L-80 DWC/C 9.950Surf 3,005 7-5/8"Int. Csg 29.7 L-80 CDC 6.875Surf 5,994 4-1/2"Prod Lnr 12.6 L-80 DWC/C HT 3.9585,8119,585 4-1/2"Prod Tieback 12.6 L-80 DWC/C HT 3.958Surf 5,818 JEWELRY DETAIL No. Depth ID OD Item 1 5183.9585.840Chem Injection Mandrel 2 2,7376.8759.9507-5/8 Swell Packer 3 5,8114.8756.540Flex-Lock V Liner hanger / HRD-E ZXP LTP Assembly 5,8184.8905.700Tieback Seal Assy. (2.92 off no-go) 4 ±6,034Screen assembly top 24ft OAL (See notes below for screen details) 5 6,240CIBP w 26 cement TOC @ 6,214 (5/8/25) 6 6,290CIBP (4/28/25) 7 6,6283.9583.5 Big Boy CIBP (8/25/22) 8 7,1003.9583.5 Big Boy CIBP (8/21/22) 9 8,2003.71CIBP (08/12/22) 10 8,6683.71CIBP(08/10/22) NOTES Screen Detail AA stop set at 6034 above a D&D Packoff w/ G Fish neck,w/ KOBE KO assembly, w/ 13 2-3/8 HES screen on top od AD-2 Stop set at 6,165. (6- 8 prong w/ 1.9-2.0 swedge to knockout Kobe to equalize before pulling AA stop.) 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: 6/13/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20250613 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# AN-17A 50733203110100 213049 4/14/2025 AK E-LINE GPT T40549 AN-17A 50733203110100 213049 4/16/2025 AK E-LINE Perf T40549 BRU 244-27 50283201850000 222038 5/15/2025 AK E-LINE Perf T40550 IRU 241-01 50283201840000 221076 5/16/2025 AK E-LINE Perf T40551 KU 13-06A 50133207160000 223112 3/18/2025 AK E-LINE CIBP T40552 KU 13-06A 50133207160000 223112 5/9/2025 AK E-LINE Perf T40552 KU 33-08 50133207180000 224008 5/30/2025 AK E-LINE Perf T40553 MPU K-33 50029227290000 196202 5/2/2025 AK E-LINE Caliper T40554 Aurora S-100A 50029229620100 224083 5/8/2025 BAKER MRPM Borax #2 T40555 PBU 06-12C 50029204560300 225022 5/15/2025 BAKER MRPM T40556 PBU B-30B 50029215420200 225009 4/9/2025 BAKER MRPM T40557 PBU D-03B 50029200570300 225008 5/2/2025 BAKER MRPM T40558 PBU H-29B 50029218130200 225005 5/7/2025 BAKER MRPM T40559 END 1-25A 50029217220100 197075 5/4/2025 HALLIBURTON MFC40 T40560 END 3-03 50029223060000 192121 5/18/2025 HALLIBURTON PPROF T40561 NS-33A 50029233250100 208189 5/13/2025 HALLIBURTON MFC24 T40562 PBU D-03B 50029200570300 225008 5/2/2025 HALLIBURTON RBT T40558 PBU H-29B 50029218130200 225005 5/7/2025 HALLIBURTON RBT T40559 PBU L-108 50029230900000 202109 5/16/2025 HALLIBURTON IPROF T40563 Please include current contact information if different from above. IRU 241-01 50283201840000 221076 5/16/2025 AK E-LINE Perf Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.06.17 11:38:14 -08'00' 1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: CTCO, N2 Development Exploratory 3. Address:Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number):8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071):10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 9,585 feet See Schematic feet true vertical 7,732 feet N/A feet Effective Depth measured 6,214 feet 5,811 feet true vertical 5,086 feet 4,772 feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth)Tieback 4-1/2" 12.6# / L-80 5,818' MD 4,778' TVD Packers and SSSV (type, measured and true vertical depth)LTP & NA 5,811' MD 4,772' TVD N/A; N/A 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure:N/A 13a. Prior to well operation: Subsequent to operation: 13b. Pools active after work: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Authorized Name and Digital Signature with Date:Contact Name: Contact Email: Authorized Title:Contact Phone: Chad Helgeson, Operations Engineer 325-236 Sr Pet Eng:Sr Pet Geo:Sr Res Eng: WINJ WAG 0 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Noel Nocas, Operations Manager 907-564-5278 N/A chelgeson@hilcorp.com 907-777-8405 measured true vertical Packer Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf MD 0 Size 120' 0 0791 0 6170 777 measured TVD 7-5/8" 4-1/2" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 221-076 50-283-20184-00-00 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Hilcorp Alaska, LLC N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: ADL032930 Ivan River / Undefined Gas Pool Ivan River Unit (IRU) 241-01 Plugs Junk measured Length Production Liner 5,994' 3,774' Casing Structural 4,915' 7,733' 5,994' 9,585' 120'Conductor Surface Intermediate 16" 10-3/4" 120' 3,005' 4,790psi 7,500psi 2,980psi 5,210psi 6,880psi 8,430psi 3,005'2,586' Burst Collapse 1,410psi 2,470psi p k ft t Fra O s 6. A G L PG , Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov By Grace Christianson at 10:40 am, Jun 05, 2025 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2025.06.04 19:36:10 - 08'00' Noel Nocas (4361) BJM 9/23/25 RBDMS JSB 061325 DSR-6/18/25 Page 1/3 Well Name: IRU 241-01 Report Printed: 5/21/2025WellViewAdmin@hilcorp.com Alaska Weekly Report - Operations Wellbore API/UWI:50-283-20184-00-00 Field Name:Ivan River State/Province:ALASKA Permit to Drill (PTD) #:221-076 Sundry #:325-236 Rig Name/No: Jobs Actual Start Date:4/4/2025 End Date: Report Number 1 Report Start Date 4/18/2025 Report End Date 4/19/2025 Last 24hr Summary PJSM, Crew travel to location, Swing BOP from Iru 11-06 to IRU 241-01, Spot in & rig up coil equipment. Report Number 2 Report Start Date 4/19/2025 Report End Date 4/20/2025 Last 24hr Summary PJSM, Crew travel to location, Function test BOPE, Pressure test BOPE 250-low, 3000-high, Witnesss waived by Jim Regg, Pick up & make up injector & lube test 250-low, 3000-high, Make up BHA (1 x 2.7" nozzle, 1 x monel, 1 x check valve, 1 x coil connector), Run in hole, Dry tag @ 6196 CTM, Cool down & pump N2, Unload reel to surface, Inject H20 @ .4 bbl/min with N2, Wash f/6209'-t/6347' CTM, Circulate bottoms up, Kick out H20, Dry up well with N2 recovered 23 of 24 bbls, Pull out of hole to 3500' While pressuring up well to 1500 psi, Run in hole to tag @ 6347' CTM, Pull out of hole pumping N2 to 1500 psi, Secure well, Blow down reel, Break down BHA, Unstab lay down lube & injector for the night. Report Number 3 Report Start Date 4/23/2025 Report End Date 4/24/2025 Last 24hr Summary MIRU AK E-line. PT lubricator 250/3000psi, good test. SITP 400psi. RIH w/ GPT, JB w/ 3.75" gauge ring, unable to get past liner hanger at 5809'. Attempt working through at different speeds, no luck. POOH, RIH w/ GPT, JB w/ 3.55" gauge ring, still setting down at 5809', no fluid seen w/ GPT. POOH, nothing in junk basket. L/d lubricator, secure well, SDFN. Report Number 4 Report Start Date 4/24/2025 Report End Date 4/25/2025 Last 24hr Summary PTW, PJSM, travel to Ivan River. P/u lubricator, and tool string and stab on. SITP 400psi. RIH w/ GPT, making it past 5809' with no issue, setting down at 6193' (coil cleaned out down to 6347' CTM). POOH. No fluid seen down to 6193'. Secure well, RDMO slick line. Report Number 5 Report Start Date 4/25/2025 Report End Date 4/26/2025 Last 24hr Summary Load up from K pad and travel to Ivan River. R/u slick line. PT lubricator 250/2500psi, good test. SITP 430psi. RIH W/ 2.5"x6' DD bailer to 6,177' KB, W/T 6,179', POOH 1/2 full clay. Cont, bailing, making a total of 7 runs and getting to a depth of 6197' KB. L/d lubricator, secure well, SDFN. Report Number 6 Report Start Date 4/26/2025 Report End Date 4/27/2025 Last 24hr Summary Travel to Ivan River. Start equipment, stab on lubricator. SITP 450psi. RIH W/ 2.5"x11' pump bailer to 6,162' KB, W/T, POOH 1/4 full clay. Cont RIH with bailer working down through dry, loose sand to 6233'. Made a total of 12 runs with bailer. L/d lubricator, secure well, SDFN. Report Number 7 Report Start Date 4/27/2025 Report End Date 4/28/2025 Last 24hr Summary Travel to Ivan River, stab lubricator, SITP 460psi. RIH W/ 2.5"x11' pump bailer, tag at 6,233' KB, W/T, POOH full sand, rod jammed. Clean out bailer, switch to drive down. RIH W/ 2.5"x11' DD bailer to 6,234' KB, W/T 5 min, POOH 1/8 full sand. Switch from long pump rod to short pump rod. Bail from 6,241' KB to 6,279' with 2.5"x11' short stroke pump bailer. Make 13 runs, bailer comes back full. L/d lubricator, secure well, SDFN. SITP 480psi. Report Number 8 Report Start Date 4/28/2025 Report End Date 4/29/2025 Last 24hr Summary Travel to Ivan River. Stab on lubricator. RIH W/ 2.5"x11' pump bailer to 6,237' KB, W/T 3 min, 6,245', POOH full thick mud. Make a total of 16 runs with bailer to depth of 6314'KB. Make final run W/ 4 1/2 BLB, tag at 6,312' POOH. R/d slick line, R/u e-line. PT lubricator 250/3000psi, good test. SITP 550psi. RIH w/ 3.5" CIBP, CCL to top of plug 12.6' bottom of plug 13.5', tagging fill at 6294.5'. Make correlation pass, send to town, confirmed on depth. Since unable to set at 6300'decision made to set as low as possible and adjust perf interval as needed (next perf interval 6273'-6290') . Tag fill, p/u until weight breaks over, set CIBP, confirm set with tag, CIBP set at 6290'. POOH. L/d lubricator, secure well, SDFN. Report Number 9 Report Start Date 4/29/2025 Report End Date 4/30/2025 Last 24hr Summary Travel to Ivan River. R/u e-line. RIH w/ 2-3/4"x14' perf gun, to perf ST A5 6273'-6287', tagging CIBP at 6290.4', Make correlation pass, send to town, confirmed on depth. Run in unable to get back on depth, seeing over pull through open perfs at 6253'-6265', Run back down still unable to get to original depth, attempt a third time with no luck, POOH. R/d e-line , r/u slick line. Make 3 runs W/ 2.5"x11' pump bailer to undetermined depth because counter isn't working properly, W/T, POOH full fluid, a bit of sand. Not getting many solids or seeing any over pull picking up off bottom. L/d lubricator, secure well SDFN. Report Number 10 Report Start Date 4/30/2025 Report End Date 5/1/2025 Last 24hr Summary Travel to Ivan River. R/u slick line, inspect counter, set up depth recorder. RIH W/ 2.5"x11' pump bailer to 6,230' KB, W/T, POOH full fluid, a bit of sand. depth recorder and counter still not showing correct depth. Tighten down counter. Make three more bailer runs getting back mostly fluid and minimal sand. RIH with 2.7" LIB getting good impression of top of plug. RDMO slick line. R/u e-line. PT lubricator 250/3000psi, good test. RIH w/ 2-3/4"x8' perf gun, tag CIBP at 6290', correlate, shoot ST A5 6279'-6287'. Starting pressure 1285psi, 5/10/15min, 1455/1485/1499. POOH. All shots fired, bullnose full of sand. SITP 1517psi. RIH w/ 2-3/4"x6' perf gun, sat down at 5942', p/u and confirm with 2nd set down. POOH, secure well, l/d lubricator, disarm gun, SDFN. ggg p shoot ST A5 6279'-6287 CIBP set at 6290'. Page 2/3 Well Name: IRU 241-01 Report Printed: 5/21/2025WellViewAdmin@hilcorp.com Alaska Weekly Report - Operations Report Number 11 Report Start Date 5/2/2025 Report End Date 5/3/2025 Last 24hr Summary MIRU slick line. PT lubricator 250/3000psi. SITP 1550psi. RIH W/ 2.5"x11' pump bailer to 5,887' KB, W/T 5896', POOH full very thick mud. Continue bailer runs getting back minimal amount of clay with first few runs. Switch bailer, RIH W/ 1.75"x3' DD bailer to 5,900' KB, W/T 5,903', POOH full mud, bottom packed off. Switch back to 2.5" pump bailer, working down to final depth of 5905'KB. Made a total of 9 bailer runs. L/d lubricator, secure well, SDFN. Report Number 12 Report Start Date 5/3/2025 Report End Date 5/4/2025 Last 24hr Summary Travel to Ivan River, stab on lubricator, SITP 1550psi. RIH W/ 2.5"x11' pump bailer to 5,899' KB, W/T, POOH full mud, with a chunk of clay. Second run made it to 5902'. Found compromised threads on bailer and flapper saver while clearing out bailer. Change out bailer to 3". RIH W/ 3"x8' pump bailer, to 5,895' KB, W/T, POOH full fluid. Make 3 more runs w/ 3" bailer working down to 5940' getting back light mud. RIH with 4-1/2" brush tagging at 5939', confirming solids are not getting suspended or strung out in tubing. Make 2 more runs with bailer, working down to final depth of 5945'. L/d lubricator, secure well, SDFN. Report Number 13 Report Start Date 5/4/2025 Report End Date 5/5/2025 Last 24hr Summary Travel to Ivan River, stab on lubricator, SITP 1380psi. RIH W/ 3"x8' pump bailer to 5,943' KB, W/T, POOH full mud. Continue running bailer a total of 8 runs, getting to 5971' and not seeing increase in depth on multiple runs. switch to drive down bailer. RIH W/ 2.5"x6' DD bailer to 5,968' KB, W/T, POOH empty. Discuss with OE on getting coil out to clean out. Secure well R/d slickline. SDFN. Report Number 14 Report Start Date 5/5/2025 Report End Date 5/6/2025 Last 24hr Summary MIRU Fox Energy Coil Report Number 15 Report Start Date 5/6/2025 Report End Date 5/7/2025 Last 24hr Summary Travel to Ivan River. P/u injector m/u tools. Pull test connector to 15k. Test BOPE as per AOGCC's and Hilcorp's standards, 250psi low, 3000psi high, all tests passed, witness waived by Jim Regg on 5/5/25 at 8:44 AM. Stab on well, fill reel w/ water., PT stack 250/3000psi, good test. bleed off to 1500psi and open well. RIH w/ 2.72" wash nozzle, filling 4-1/2" tubing while running in hole, holding back pressure and slowly let bleed down while filling. Starting tubing pressure 1800psi, pumping at 1bpm. Run in to 5500' decreasing back pressure to 0 psi. Increase pump rate to 1.5bpm, 2900psi and CBU. Shut down pump, run in and dry tag at 5986' CTM. Bring pump on at 1.5bpm, 2000psi. Wash down from 5986' to CIBP at 6300'CTM. Pump 10bbls sweep around and POOH. Secure well, l/d lubricator and injector. Report Number 16 Report Start Date 5/7/2025 Report End Date 5/8/2025 Last 24hr Summary MIRU AK E-line Stab on and pt lubricator 250/3000psi, good test. SITP 0psi. RIH w/ 3.50" CIBP. Fluid seen at 340'. Sat down at 6008', attempt to p/u seeing over pull. Work tool string up to 1900# with no luck. Pressure up tubing to 500psi, work toolstring with no luck. Increase pressure to 1000psi, work tool string, no movement. Hold p/u wt at 1500# and surge pressure, no change. Discuss with OE, decision made to set plug and get coil to mill up plug. Set plug at 6008' ELM. Pooh. Secure well, L/d lubricator, SDFN. Report Number 17 Report Start Date 5/8/2025 Report End Date 5/9/2025 Last 24hr Summary P/u lubricator and injector. Drift all BHA components. M/u connector, pull test to 30k, PT 3000psi. M/u 3-3/4" tri cone BHA, OAL 25.36'. Stab on, shell test to 3000psi. Open up well tubing pressure 0psiRIH w/ 3-3/4" tri cone bit. Stop at 5900', check parameters, circulate at 1.75 BPM, 3750 psi, p/u wt 20k, RI wt 7k. Lower pump rate to 1 bpm, 1250psi, RIH tag at 6022' CTM. P/u increase pump rate to 1.75bpm, 3350psi. Run in put 2k down on plug. Mill on 3-1/2" CIBP at 6022', 2bpm, 3750psi, 2k wob. Get through plug, continue reaming down tagging at 6295' CTM. P/u pump 15bbls sweep, get sweep to surface, pull up to 5500', shut down pump and dry tag at 6295'. P/u to 6280', drop ball to open circ. sub, pump 10bbls sweep chased w/ water. With circ. sub open increase rate to 3bpm, 4000psi. With sweep out of bit, POOH slow while pumping at same rate. At surface shut in well w/ 300psi on tubing. R/d coil, r/u e-line. RIH w/ 3.55"GR/ junk basket, tag at 6287.5'. RIH w/ 3.71" CIBP', correlate, set plug at 6240'. Make 4 runs w/ 2.5"x20' cement bailer filled with 4.2 gal cement. 16.8 gallons dumped on CIBP in 4-1/2" tubing puts 26' on top of CIBP at 6240' placing top of cement at 6214'. Report Number 18 Report Start Date 5/9/2025 Report End Date 5/10/2025 Last 24hr Summary Travel to Ivan River. P/u lubricator and injector, Cut 20' coil. dress coil and m/u connector, pull test to 15k, m/u reverse out nozzle, Stab on lubricator/injector, pressure test 250/3000psi. Fluid pack 4-1/2" tubing with water. PT tubing and CIBP to 1727psi, hold for 15 minutes, no drop in pressure, good test. RIH w/ coil blowing tubing dry w/N2 down to 6190' CTM at 1000scf/min 1800psi. Trap 1450 psi on tubing. 189k scf N2 pumped., Got back 127bbls water in return tank. secure well. R/d lubricator and injector. SDFN. Report Number 19 Report Start Date 5/10/2025 Report End Date 5/11/2025 Last 24hr Summary Travel to Ivan River. M/u gun tool string. Stab lubricator, PT 250/3000psi. SITP 1000psi. Increase tubing pressure to 1400psi w/ N2. RIH w/ 2-3/4"x10' perf gun, make correlation pass, shoot ST A3 6153'-6163'. Initial pressure 1400psi no change in pressure after 15 minutes. POOH. All shots fired, bullnose wet. M/u GPT tool string. RIH w/ GPT tagging TOC at 6214' (CIBP @ 6240), p/u see fluid level at 6120'. Tubing pressure at 1370psi, start bleeding down tubing slow checking for fluid level change, temp change and fill. At 1000 psi fluid level had risen to 6100', seeing cooling at perfs, no change in tag depth, no LEL's detected. . Continue bleeding down Seeing LEL's at 860psi, shut in bleeder, POOH. Pressure climbed to 980psi while pooh. Secure well, l/d lubricator, SDFN. j,g gallons dumped on CIBP in 4-1/2",,pg tubing puts 26' on top of CIBP at 6240' placing top of cement at 6214'. pg set plug at 6240pg gg shoot ST A3 6153'-6163 Page 3/3 Well Name: IRU 241-01 Report Printed: 5/21/2025WellViewAdmin@hilcorp.com Alaska Weekly Report - Operations Report Number 20 Report Start Date 5/11/2025 Report End Date 5/12/2025 Last 24hr Summary RDMO coil tubing package and get to barge landing. Ops r/u Party Ball, test lines, no leaks. SITP 1360psi. Flow well, stabilize at 1013psi, 442 mcf. Monitor flow for 24-48 hours. Move out e-line to store equipment on D-pad. Coil and e-line crews depart Beluga. Report Number 21 Report Start Date 5/16/2025 Report End Date 5/17/2025 Last 24hr Summary PTW/PJSM, MIRU AK Eline, PT 250/2500. Well flowing 500 mcf, 960psi, Ran GPT, 2.75" JB. see gas fluid mix @ 5950'. Tag @ 6214'. Shut is well. Perforate Sterling A3 W/ 2 1/2" (6spf) from 6144'-6148'. Tagged @ 6212' W/ perf gun, built 13psi in 15 mins. Rig down AK ELine & MIRU PWL, PT 250/2500, 3.80" g-ring. SD @ 6190' SLM (+22' correction to Eline last tag @ 6212'), set AD-2 tbg stop mid slip @ 6143' SLM, 6165' CELM, Ran HES screen SD @ 6160' SLM. (zero issue?) Ran 4 1/2" D&D packoff, SD @ 6136' SLM 17' deep, pulled packoff OOH, LDFN Report Number 22 Report Start Date 5/17/2025 Report End Date 5/18/2025 Last 24hr Summary PTW/PJSM, Pulled HES screen from 6136' SLM, Pulled AD-2 from 6161' SLM, Reran 4 1/2" AD-2 stop, tag @ 6208' SLM (+4' corr. to ELMD), Flag wire & PUH to flag. Set mid slips @ 6161' SLM (6165' CELM), POOH (apprears counter changed after setting the AD-2 yesterday) Ran HES screen (24'2" OAL, max OD 3.72", 2 3/8" base pipe, Material #102156641, SN 21514-1-001) SD @ 6161' SLM, Ran 4 1/2" D&D packoff with kobe knock out, D&D stinger(3.72" OD, 47" OAL, stinger shoulder to ME 23.5", 35" from top - kobe), SD @ 6137' SLM. Mid Element @ 6135' SLM, 6139' CELM, Ran 4 1/2" AA tbg stop SD @ 6134' SLM ,, Sterling A3 W / 2 1/2" (6spf) from 6144'-6148 _____________________________________________________________________________________ Updated by DMA 05-30-25 SCHEMATIC Well: Ivan River 241-01 PTD: 221-076 API: 50-283-20184-00-00 PERFORATION DETAIL Zone Top MD Btm MD Top TVD Btm TVD FT Date Status ST A3 6,144’6,148’5,032’5,035’4’5/16/25 Open ST A3 6,153’6,163’5,039’5,046’10’5/10/25 Open ST A5 6,253’6,265’5,116’5,126’12’2/26/24 Isolated ST A5 6,279’6,287’5,137’5,143’8’4/30/25 Isolated ST B1 6,306’6,323’5,158’5,172’17’8/31/22 Isolated ST B2 6,335’6,345’5,181’5,188’10’2/25/24 Isolated ST B2 6,355’6,361’5,196’5,201’6’2/25/24 Isolated ST B2 6,370’6,378’5,208’5,214’8’2/25/24 Isolated Beluga U 6,576’6,590’5,368’5,381’14’08/25/22 Isolated Beluga D1 6,638’6,647’5,418’5,425’9’08/24/22 Isolated Beluga E5d 7,170’7,180’5,829’5,839’10’08/13/22 Isolated BEL H4u 8,233’8,242’6,667’6,674’9’08/12/22 Isolated BEL H4m 8,254’8,263’6,684’6,691’9’08/12/22 Isolated BEL H4L 8,289’8,309’6,712’6,727’20’08/12/22 Isolated BEL H8 8,395’8,415’6,795’6,811’20’08/12/22 Isolated BEL H15 8,698’8,713’7,033’7,045’15’08/10/22 Isolated BEL I3 9,001’9,006’7,272’7,277’5’08/10/22 Isolated BEL I5 9,103’9,119’7,351’7,364’16’08/10/22 Isolated BEL I8 9,202’9,215’7,427’7,438’13’08/10/22 Isolated OPEN HOLE / CEMENT DETAIL 10-3/4”TOC @ Surface 7-5/8"Est. TOC @ 1,677’ Pumped 40% excess (good returns during job, no cement returns off top of liner) 4-1/2”Pumped 118bbls (290 sx) of 12 ppg lead followed by 23 bbls (95 sx) of 15.3 ppg tail. (30 bbls of spacer & 48 bbls of cement to surface) TOC @ 6,037’ CBL (8-5-22) CASING DETAIL Size Type Wt Grade Conn.ID Top Btm 16”Conductor – Driven to Set Depth 84 X-56 Weld 15.01”Surf 120’ 10-3/4”Surf Csg 45.5 L-80 DWC/C 9.950”Surf 3,005’ 7-5/8"Int. Csg 29.7 L-80 CDC 6.875”Surf 5,994’ 4-1/2"Prod Lnr 12.6 L-80 DWC/C HT 3.958”5,811’9,585’ 4-1/2"Prod Tieback 12.6 L-80 DWC/C HT 3.958”Surf 5,818’ JEWELRY DETAIL No.Depth ID OD Item 1 518’3.958”5.840”Chem Injection Mandrel 2 2,737’6.875”9.950”7-5/8” Swell Packer 3 5,811’4.875”6.540”Flex-Lock V Liner hanger / HRD-E ZXP LTP Assembly 5,818’4.890”5.700”Tieback Seal Assy. (2.92’ off no-go) 4 6,134’Screen assembly top 24ft OAL (See notes below for screen details) 5 6,240’CIBP w 26’ cement – TOC @ 6,214’ (5/8/25) 6 6,290’CIBP (4/28/25) 7 6,628’3.958’3.5” Big Boy CIBP (8/25/22) 8 7,100’3.958”3.5” Big Boy CIBP (8/21/22) 9 8,200’3.71”CIBP (08/12/22) 10 8,668’3.71”CIBP(08/10/22) NOTES Screen Detail AA stop set at 6134’ above a D&D Packoff w/ G Fish neck,w/ KOBE KO assembly, w/ 13’ 2-3/8” HES screen on top od AD-2 Stop set at 6,165’’. (6- 8’ prong w/ 1.9-2.0” swedge to knockout Kobe to equalize before pulling AA stop.) 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: 5/29/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20250529 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# BCU 19RD 50133205790100 219188 5/10/2025 AK E-LINE GPT/CIBP/Perf HVB 13A 50231200320100 224160 3/16/2025 YELLOWJACKET SCBL IRU 241-01 50283201840000 221076 5/7/2025 AK E-LINE Plug/Perf KBU 22-06Y 50133206500000 215044 5/6/2025 AK E-LINE Perf KBU 22-06Y 50133206500000 215044 5/7/2025 AK E-LINE Perf KBU 24-06RD 50133204990100 206013 4/8/2025 YELLOWJACKET GPT-PLUG MPI 1-61 50029225200000 194142 5/10/2025 AK E-LINE Perf MPU E-42 50029236350000 219082 5/3/2025 AK E-LINE Patch MPU S-55 50029238130000 225006 5/13/2025 AK E-LINE CBL OP16-03 50029234420000 211017 4/25/2025 READ LeakDetect PAXTON 13 50133207330000 225021 4/29/2025 YELLOWJACKET SCBL PBU 01-12B 50029202690200 223090 4/8/2025 HALLIBURTON RBT PBU D-08B 50029203720200 225007 3/22/2025 BAKER MRPM PBU H-17B (REVISION)50029208620100 197152 4/10/2025 HALLIBURTON RBT-COILFLAG PBU J-25B 50029217410200 224134 3/10/2025 BAKER MRPM PBU K-19C (REVISION)50029225310300 224004 3/27/2025 BAKER MRPM PBU K-19C 50029225310300 224004 3/27/2025 HALLIBURTON RBT SRU 241-33B 50133206960000 221053 3/12/2025 YELLOWJACKET PERF Revision Explanation: Both wells had wrong side stack well name and API#/PTD on previous upload H-17b was marked as H-17A and K-19C was marked as K-19B. Well name now reflets correct sidetrack and has correct SPI# and PTD. T40489 T40490 T40491 T40492 T40492 T40493 T40494 T40495 T40496 T40497 T40498 T40499 T40500 T40501 T40502 T40503 T40503 T40504 IRU 241-01 50283201840000 221076 5/7/2025 AK E-LINE Plug/Perf Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.05.29 14:33:01 -08'00' 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: 5/15/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20250515 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# BRU 241-23 50283201910000 223061 4/24/2025 AK E-LINE Plug/Perf T40412 END 2-72 50029237810000 224016 4/4/2025 READ CoilFlag T40413 IRU 241-01 50283201840000 221076 4/30/2025 AK E-LINE Perf T40414 IRU 241-01 50283201840000 221076 4/23/2025 AK E-LINE Plug/Perf T40414 KU 33-08 50133207180000 224008 4/22/2025 AK E-LINE PPROF T40415 MRU D-16RD 50733201830100 180110 4/21/2025 AK E-LINE Cement/Perf T40416 NSU NS-06 50029230880000 202101 4/21/2025 AK E-LINE PPROF T40417 NSU NS-19 50029231220000 202207 4/27/2025 AK E-LINE Perf T40418 NSU NS-20 50029231180000 202188 4/24/2025 AK E-LINE Perf T40419 NSU NS-23 50029231460000 203050 4/23/2024 AK E-LINE Packer T40420 PBU 02-10B 50029201630200 200064 3/21/2025 BAKER SPN T40421 PBU 06-19B 50029207910200 224095 3/1/2025 BAKER MRPM Borax T40422 PBU S-100A 50029229620100 224083 2/28/2025 BAKER MRPM Borax T40423 PBU Z-235 (Revised)50029237600000 223055 4/1/2025 READ InectionProfile T40424 SRU 231-33 50133101630100 223008 5/1/2025 AK E-LINE Plug/Perf T40425 Revision Explanation: Processing report added Please include current contact information if different from above. T40414IRU 241-01 50283201840000 221076 4/30/2025 AK E-LINE Perf T40414IRU 241-01 50283201840000 221076 4/23/2025 AK E-LINE Plug/Perf Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.05.16 08:15:21 -08'00' CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:McLellan, Bryan J (OGC) To:Chad Helgeson Cc:Donna Ambruz; Noel Nocas Subject:RE: IRU 241-01 (PTD#221-076) Sundry # 325-236 Cement plug question Date:Tuesday, April 22, 2025 11:43:00 AM Chad, Yes, Hilcorp has approval to set 25’ cement on top of the contingency plug at 6240’ instead on the plug at 6300’. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Chad Helgeson <chelgeson@hilcorp.com> Sent: Tuesday, April 22, 2025 11:03 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com>; Noel Nocas <Noel.Nocas@hilcorp.com> Subject: IRU 241-01 (PTD#221-076) Sundry # 325-236 Cement plug question Bryan, Thanks for processing the Sundry request quickly for me on IRU 241-01. I see you added the requirement to add 25ft of cement on the plug at 6300’. Which would put the top of cement at 6275’. Our bottom perf for this interval is 6290’. I know there is still some debate occurring about the indigenous strata and the need for 25ft of cement, but can we get approval to place this 25ft of cement in the 4-1/2” tubing somewhere else in the well. Let me know if we can plan to place 25ft cement plug in step C in contingency stage (instead of 10ft listed in procedure) if these perfs are not successful. I do think a 10ft cement plug in 4- 1/2” pipe meets the engineering requirements for our wells in cook inlet. Let me know how you would like us to proceed with the cement plug operations, feel free to give me a call if you want to discuss other options. Chad Helgeson Operations Engineer Kenai Asset Team 907-777-8405 - O 907-229-4824 - C The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number): 10. Field: 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 9,585'N/A Casing Collapse Structural Conductor 1,410psi Surface 2,470psi Intermediate 4,790psi Production 7,500psi Liner Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16. Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng chelgeson@hilcorp.com 907-777-8405 Noel Nocas, Operations Manager 907-564-5278 Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY Chad Helgeson AOGCC USE ONLY Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL032930 221-076 50-283-20184-00-00 Hilcorp Alaska, LLC Proposed Pools: 12.6 / L-80 TVD Burst 5,818' 8,430psi 2,586'3,005' Size 120' 7-5/8"5,994' 3,005' MD 5,994' 5,116 - 5,381 6,880psi 2,980psi 5,210psi 120' 4,915' 120' Length April 19, 2025 Tieback 4-1/2" 9,585' Perforation Depth MD (ft): 6,253 - 6,590 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Ivan River Unit (IRU) 241-01CO 795 Same 7,733'4-1/2" 2,011psi 3,774' 6,628' & 7,100' Other: CTCO, N2 Swell Pkr & N/A 2,737 (MD) 2,380 (TVD) & N/A 7,732' 6,628' 5,410' Ivan River Undefined Gas Pool 16" 10-3/4" No Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 8:03 am, Apr 17, 2025 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2025.04.16 17:28:45 - 08'00' Noel Nocas (4361) 325-236 DSR-4/17/25 April 19, 2025 RUSH SFD Perforate SFD 4/17/2025 Apr 17, 2025 Yes, for CTCO only 4/18/25 Bryan McLellan CT BOP test to 3000 psi BJM 4/21/25 Place 25' of cement on top of CIBP @ 6300' MD. 10-404 *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.04.21 13:46:53 -08'00'04/21/25 RBDMS JSB 042225 Well Prognosis Well Name: IRU 241-01 API Number: 50-283-20184-00-00 Current Status: SI Gas Well Permit to Drill Number: 221-076 First Call Engineer: Chad Helgeson (907) 777-8405 (O) (907) 229-4824 (C) Second Call Engineer: Scott Warner (907) 830-8863 Maximum Expected BHP:2206 psi @ 5132’ TVD (Based on 0.43 psi/ft gradient)) Max. Potential Surface Pressure:2011 psi (Based on 0.038 psi/ft gas gradient to surface) Applicable Frac Gradient:0.69 psi/ft using 13.19 ppg EMW FIT at the surface casing shoe 7/15/22 Shallowest Potential Perf TVD:MPSP/(0.69-0.038) = 2011 psi / 0.65 = 3103‘ TVD Top of Pools per CO 614:Ivan River Undefined Gas Pool Well Status:SI gas well with fill in well Brief Well Summary: IRU 241-01 started drilling in late 2021 and completed as a Beluga and Sterling producer in Summer of 2022. Initial production started in August of 2022 with rates of 5.8 mmscfd. Additional sands were perforated in 2024 to keep well unloaded and flowed until the well died in March of 2025. The purpose of this sundry is to cleanout the well with coil, set a plug, blow well dry with n2 and add perforations in the Sterling Sands. All sands lie in the Ivan River Undefined Gas Pool. Wellbore Conditions: Current flowrate: SI The well has a 4.5” cemented liner (Top of Good Cement – 6037’) Current open perfs @ 6253-6590’ SL tag depth: 6196’ on 3/27/25 Procedure: 1. Review all approved COAs 2. MIRU Fox Coil Tubing unit with 1.75” Coil and pressure control equipment 3. PT lubricator to 250 psi low/ 3000 psi high a. Provide AOGCC 48 hr notice for BOP test 4. RIH and clean out wellbore to 6576 or as deep as possible, but minimum to 6350’. Circulate well clean 5. RU Eline PT Lubricator 250 psi low / 2500 psi high 6. PU & RIH w/CIBP and set plug at 6300’. 7. Pressure up well and ensure can inject to open zone at 6253-6265’ with pump 8. RDMO Coil Equipment 9. RU N2 pressure pump and PT lines to 4000 psi 10. Pressure up with N2 and push water into formation at 750 scfm (do not exceed 3500 psi) 11. RU Eline PT Lubricator 250 psi low / 4000 psi high 12. RIH with perf guns and perforate the following sand 13. Ops to flow well Formation MD TOP MD BASE TVD TOP TVD BASE H Sterling A5 ±6,273’ ±6,290’ ±5,132’ ±5,145’ ±17 Cleaned out to 6347' md as of 4/20/25 per Chad Helgeson. -bjm Place 25' of cement on top of plug. -bjm CT work verbally approved 4/18/25. -bjm Well Prognosis Continued work if zone does not flow (contingency): A. SL/Eline Tag fill/plug on well a. If there is fill over proposed perfs, bail fill or cleanout with coil tubing (following above procedure 1-4) b. If bailing fill, use N2 to push away water once perfs are clear c. If using coil for cleanout, blow well dry with N2 after setting plug in next step B. RU Eline PT Lubricator 250 psi low / 2500 psi high C. Eline RU & set plug at 6240’ & dump 10ft of cement on plug D. Pressure well with sales gas ~800 psi E. Perforate and test Beluga sands within the interval below, from the bottom up: a. If any zone produces sand and/or water or needs isolated, RIH and set plug above the perforations (no cement due to how close each zone is). b. Pending well production, all perf intervals may not be completed c. If necessary, use nitrogen to pressure up well during perforating or to depress water prior to setting a plug above perforations F. RDMO Eline G. Turn well over to production & flow test well Coil Procedure (Contingency) If necessary to cleanout or unload well with coiled tubing: 1. MIRU Coiled Tubing Unit, PT BOPE to 3,000 psi High/250 psi Low 2. Provide AOGCC 24hrs notice of BOP test 3. PU wash nozzle, RIH and cleanout well to below perfs or proposed plug depth 4. PU CT jet nozzle and RIH, unload fluid from the wellbore with nitrogen a. Reverse circ out any fluid if perfs are isolated/plugged back and in cased hole 5. RDMO coil tubing Attachments: 1. Current Well Schematic 2. Proposed Well Schematic 3. Fox CT BOP Drawing 4. Nitrogen procedure Formation MD TOP MD BASE TVD TOP TVD BASE H ST X3 ±6,043’ ±6,049’ ±4,953’ ±4,957’ ±6’ ST A1 ±6,068’ ±6,073’ ±4,972’ ±4,976’ ±5’ ST A2 ±6,078’ ±6,093’ ±4,980’ ±4,992’ ±15’ ST A2 ±6,096’ ±6,111’ ±4,994’ ±5,006’ ±15’ ST A3 ±6,144’ ±6,148’ ±5,032’ ±5,035’ ±4’ ST A3 ±6,153’ ±6,163’ ±5,039’ ±5,046’ ±10’ _____________________________________________________________________________________ Updated by CAH 04-14-25 SCHEMATIC Well: Ivan River 241-01 PTD: 221-076 API: 50-283-20184-00-00 PERFORATION DETAIL Zone Top MD Btm MD Top TVD Btm TVD FT Date Status ST A5 6,253’ 6,265’ 5,116’ 5,126’ 12’ 2/26/24 Open ST B1 6,306’ 6,323’ 5,158’ 5,172’ 17’ 8/31/22 Open ST B2 6,335’ 6,345’ 5,181’ 5,188’ 10’ 2/25/24 Open ST B2 6,355’ 6,361’ 5,196’ 5,201’ 6’ 2/25/24 Open ST B2 6,370’ 6,378’ 5,208’ 5,214’ 8’ 2/25/24 Open Beluga U 6,576’ 6,590’ 5,368’ 5,381’ 14’ 08/25/22 Open Beluga D1 6,638’ 6,647’ 5,418’ 5,425’ 9’ 08/24/22 Isolated Beluga E5d 7,170’ 7,180’ 5,829’ 5,839’ 10’ 08/13/22 Isolated BEL H4u 8,233’ 8,242’ 6,667’ 6,674’ 9’ 08/12/22 Isolated BEL H4m 8,254’ 8,263’ 6,684’ 6,691’ 9’ 08/12/22 Isolated BEL H4L 8,289’ 8,309’ 6,712’ 6,727’ 20’ 08/12/22 Isolated BEL H8 8,395’ 8,415’ 6,795’ 6,811’ 20’ 08/12/22 Isolated BEL H15 8,698’ 8,713’ 7,033’ 7,045’ 15’ 08/10/22 Isolated BEL I3 9,001’ 9,006’ 7,272’ 7,277’ 5’ 08/10/22 Isolated BEL I5 9,103’ 9,119’ 7,351’ 7,364’ 16’ 08/10/22 Isolated BEL I8 9,202’ 9,215’ 7,427’ 7,438’ 13’ 08/10/22 Isolated OPEN HOLE / CEMENT DETAIL 10-3/4” TOC @ Surface 7-5/8"Est. TOC @ 1,677’ Pumped 40% excess (good returns during job, no cement returns off top of liner) 4-1/2”Pumped 118bbls (290 sx) of 12 ppg lead followed by 23 bbls (95 sx) of 15.3 ppg tail. (30 bbls of spacer & 48 bbls of cement to surface) TOC @ 6,037’ CBL (8-5-22) TD =9,585’ (MD) / TD =7,732’ (TVD) 16” KB Elev.: 42.3’ / GL Elev.: 23.8’ 7-5/8” 6 7 5 4 16 10-3/4” 17 PBTD =9,499’ (MD) / PBTD =7,662’ (TVD) 4-1/2” 2 6-3/4” Hole 9-7/8” Hole 13-1/2” Hole 1 3 BEL H15-I8 BEL H4-H8 BEL E5 spent perf gun ST A5-B2 BEL U-D1 SL Tagged 6196’ 3-27-25 CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16”Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 120’ 10-3/4” Surf Csg 45.5 L-80 DWC/C 9.950” Surf 3,005’ 7-5/8" Int. Csg 29.7 L-80 CDC 6.875” Surf 5,994’ 4-1/2" Prod Lnr 12.6 L-80 DWC/C HT 3.958” 5,811’ 9,585’ 4-1/2" Prod Tieback 12.6 L-80 DWC/C HT 3.958” Surf 5,818’ JEWELRY DETAIL No. Depth ID OD Item 1 518’ 3.958” 5.840” Chem Injection Mandrel 2 2,737’ 6.875” 9.950” 7-5/8” Swell Packer 3 5,811’ 4.875” 6.540” Liner hanger / LTP Assembly 5,818’ 4.890” 5.700” Tieback Seal Assy. (2.92’ off no-go) 4 6,628’ 3.958’ 3.5” Big Boy CIBP (8/25/22) 5 7,100’ 3.958” 3.5” Big Boy CIBP (8/21/22) 6 8,200’ 3.71” CIBP (08/12/22) 7 8,668’ 3.71” CIBP(08/10/22) _____________________________________________________________________________________ Updated by CAH 04-14-25 PROPOSED Well: Ivan River 241-01 PTD: 221-076 API: 50-283-20184-00-00 PERFORATION DETAIL Zone Top MD Btm MD Top TVD Btm TVD FT Date Status ST X3 ѷ͕Ϡ͏͓͒Ѝ ѷ͕Ϡ͏͓͘Ѝ ѷ͓Ϡ͔͒͘Ѝ ѷ͓Ϡ͔͖͘Ѝ ѷ͕Ѝ TBD Proposed ST A1 ѷ͕Ϡ͏͕͗Ѝ ѷ͕Ϡ͏͖͒Ѝ ѷ͓Ϡ͖͑͘Ѝ ѷ͓Ϡ͖͕͘Ѝ ѷ͔Ѝ TBD Proposed ST A2 ѷ͕Ϡ͏͖͗Ѝ ѷ͕Ϡ͏͒͘Ѝ ѷ͓Ϡ͗͘͏Ѝ ѷ͓Ϡ͑͘͘Ѝ ѷ͔͐Ѝ TBD Proposed ST A2 ѷ͕Ϡ͏͕͘Ѝ ѷ͕Ϡ͐͐͐Ѝ ѷ͓Ϡ͓͘͘Ѝ ѷ͔Ϡ͏͏͕Ѝ ѷ͔͐Ѝ TBD Proposed ST A3 ѷ͕Ϡ͓͓͐Ѝ ѷ͕Ϡ͓͐͗Ѝ ѷ͔Ϡ͏͒͑Ѝ ѷ͔Ϡ͏͔͒Ѝ ѷ͓Ѝ TBD Proposed ST A3 ѷ͕Ϡ͔͐͒Ѝ ѷ͕Ϡ͕͐͒Ѝ ѷ͔Ϡ͏͒͘Ѝ ѷ͔Ϡ͏͓͕Ѝ ѷ͐͏Ѝ TBD Proposed ST A5 6,253’ 6,265’ 5,116’ 5,126’ 12’ 2/26/24 Open ST A5 ѷ͕Ϡ͖͑͒Ѝ ѷ͕Ϡ͑͘͏Ѝ ѷ͔Ϡ͐͒͑Ѝ ѷ͔Ϡ͓͔͐Ѝ ѷ͖͐Ѝ TBD Proposed ST B1 6,306’ 6,323’ 5,158’ 5,172’ 17’ 8/31/22 Isolated ST B2 6,335’ 6,345’ 5,181’ 5,188’ 10’ 2/25/24 Isolated ST B2 6,355’ 6,361’ 5,196’ 5,201’ 6’ 2/25/24 Isolated ST B2 6,370’ 6,378’ 5,208’ 5,214’ 8’ 2/25/24 Isolated Beluga U 6,576’ 6,590’ 5,368’ 5,381’ 14’ 08/25/22 Isolated Beluga D1 6,638’ 6,647’ 5,418’ 5,425’ 9’ 08/24/22 Isolated Beluga E5d 7,170’ 7,180’ 5,829’ 5,839’ 10’ 08/13/22 Isolated BEL H4u 8,233’ 8,242’ 6,667’ 6,674’ 9’ 08/12/22 Isolated BEL H4m 8,254’ 8,263’ 6,684’ 6,691’ 9’ 08/12/22 Isolated BEL H4L 8,289’ 8,309’ 6,712’ 6,727’ 20’ 08/12/22 Isolated BEL H8 8,395’ 8,415’ 6,795’ 6,811’ 20’ 08/12/22 Isolated BEL H15 8,698’ 8,713’ 7,033’ 7,045’ 15’ 08/10/22 Isolated BEL I3 9,001’ 9,006’ 7,272’ 7,277’ 5’ 08/10/22 Isolated BEL I5 9,103’ 9,119’ 7,351’ 7,364’ 16’ 08/10/22 Isolated BEL I8 9,202’ 9,215’ 7,427’ 7,438’ 13’ 08/10/22 Isolated OPEN HOLE / CEMENT DETAIL 10-3/4” TOC @ Surface 7-5/8"Est. TOC @ 1,677’ Pumped 40% excess (good returns during job, no cement returns off top of liner) 4-1/2”Pumped 118bbls (290 sx) of 12 ppg lead followed by 23 bbls (95 sx) of 15.3 ppg tail. (30 bbls of spacer & 48 bbls of cement to surface) TOC @ 6,037’ CBL (8-5-22) TD =9,585’ (MD) / TD =7,732’ (TVD) 16” KB Elev.: 42.3’ / GL Elev.: 23.8’ 7-5/8” 4 5 16 10-3/4” 17 PBTD =9,499’ (MD) / PBTD =7,662’ (TVD) 4-1/2” 2 6-3/4” Hole 9-7/8” Hole 13-1/2” Hole 1 3 BEL H15-I8 BEL H4-H8 BEL E5 ST A5 ST X1-A3 21’ spent perf gun (8/14/22) @ 7170’ ST B1-B2 BEL U-D1 6 7 8 ST X3 CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16”Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 120’ 10-3/4” Surf Csg 45.5 L-80 DWC/C 9.950” Surf 3,005’ 7-5/8" Int. Csg 29.7 L-80 CDC 6.875” Surf 5,994’ 4-1/2" Prod Lnr 12.6 L-80 DWC/C HT 3.958” 5,811’ 9,585’ 4-1/2" Prod Tieback 12.6 L-80 DWC/C HT 3.958” Surf 5,818’ JEWELRY DETAIL No. Depth ID OD Item 1 518’ 3.958” 5.840” Chem Injection Mandrel 2 2,737’ 6.875” 9.950” 7-5/8” Swell Packer 3 5,811’ 4.875” 6.540” Liner hanger / LTP Assembly 5,818’ 4.890” 5.700” Tieback Seal Assy. (2.92’ off no-go) 4 ~6,300’ 3.958 CIBP 5 6,628’ 3.958’ 3.5” Big Boy CIBP (8/25/22) 6 7,100’ 3.958” 3.5” Big Boy CIBP (8/21/22) 7 8,200’ 3.71” CIBP (08/12/22) 8 8,668’ 3.71” CIBP(08/10/22) 1 McLellan, Bryan J (OGC) From:Chad Helgeson <chelgeson@hilcorp.com> Sent:Monday, April 21, 2025 10:05 AM To:McLellan, Bryan J (OGC) Cc:Donna Ambruz; Noel Nocas Subject:IRU 241-01 (PTD#221-076) Coil cleanout Bryan, We cleaned out Ivan River 241-01 this weekend with coil, thanks for providing the verbal approval on that portion of the work. I just wanted to let you know that we were only able to clean the well to 6347’ Coil measurement and were not able to get deeper. Thanks Chad Helgeson Operations Engineer Kenai Asset Team 907-777-8405 - O 907-229-4824 - C The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. 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: 3/19/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20240319 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BCU 13 50133205250000 203138 12/5/2023 AK E-LINE Plug/Cement/Cutter GP ST 18742 37 (AN 37) 50733203940000 187109 11/12/2023 AK E-LINE PERF IRU 241-01 50283201840000 221076 2/25/2024 AK E-LINE Perf/GPT KU 13-06A 50133207160000 223112 2/9/2024 AK E-LINE GPT MPU CFP-02 50029212580000 184242 3/13/2024 READ CaliperSurvey NCIU A-18 50883201890000 223033 12/13/2023 AK E-LINE GPT/Plug/Perf PBU L-122 50029231470000 203051 3/2/2024 AK E-LINE LowerPatchPacker PBU L4-14 50029219730000 189098 11/22/2023 AK E-LINE PERF SRU 241-33B 50133206960000 221053 3/4/2024 AK E-LINE GPT/Cmnt/CIBP/Perf Please include current contact information if different from above. T38648 T38649 T38650 T38651 T38652 T38653 T38654 T38655 T38656 IRU 241-01 50283201840000 221076 2/25/2024 AK E-LINE Perf/GPT Meredith Guhl Digitally signed by Meredith Guhl Date: 2024.03.21 11:50:20 -08'00' 1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: Development Exploratory 3. Address:Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number):8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071):10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 9,585 feet 6628, 7100 feet true vertical 7,732 feet N/A feet Effective Depth measured 6,628 feet 2,737 feet true vertical 5,410 feet 2,380 feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth)Tieback 4-1/2" 12.6# / L-80 5,818' MD 4,778' TVD Packers and SSSV (type, measured and true vertical depth)Swell Pkr & NA 2,737' MD 2,380' TVD 5818 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure:N/A 13a. Prior to well operation: Subsequent to operation: 13b. Pools active after work: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Authorized Name and Digital Signature with Date:Contact Name: Contact Email: Authorized Title:Contact Phone: Jake Flora, Operations Engineer 324-014 Sr Pet Eng:Sr Pet Geo:Sr Res Eng: WINJ WAG 95 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Noel Nocas, Operations Manager 907-564-5278 N/A jake.flora@hilcorp.com 907-777-8442 measured true vertical Packer Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf MD 0 Size 120' 0 01017 0 2190 352 measured TVD 7-5/8" 4-1/2" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 221-076 50-283-20184-00-00 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Hilcorp Alaska, LLC N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: ADL032930 Ivan River / Undefined Gas Pool Ivan River Unit (IRU) 241-01 Plugs Junk measured Length Production Liner 5,994' 3,774' Casing Structural 4,915' 7,733' 5,994' 9,585' 120'Conductor Surface Intermediate 16" 10-3/4" 120' 3,005' 4,790psi 7,500psi 2,980psi 5,210psi 6,880psi 8,430psi 3,005'2,586' Burst Collapse 1,410psi 2,470psi p k ft t Fra O s 6. A G L PG , Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov By Samantha Coldiron at 9:17 am, Apr 15, 2024 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2024.04.12 17:28:36 - 08'00' Noel Nocas (4361) DSR-4/23/24 RBDMS JSB 041824 Well Name: IRU 241-01 API #:50-283-20184-00-00 Field:Ivan River Start Date:2/25/2024 Permit #:221-076 Sundry #:324-014 End Date: 2/25/2024 2/26/2024 4/10/2024 Activity Report PJSM, Crew travel to location, Spot in & rig up equipment, Pressure test lube 250/3000-good, Run in hole to tag @ 6394', Pull out of hole & run perf guns, Perforate ST-B2 (6370-6378) OG psi: 375, End psi: 375, ST-B2 (6355-6361) OG psi: 369, End psi: 370, ST-B2 (6335-6345) OG psi: 675, End psi: 398, Pull out of hole, Shut in & secure well, Rig down. PJSM, Crew travel to location, Start & warm equipment, Make up GPT & lube, Pressure test 250/3000-good, Run in hole with CCL/GR/GPT, No fluid, Pull out & pick up run #2 to perf ST-A5 sands @ 6253'-6265', OG psi: 555/ End psi: 517, Pull out of hole, PIck up run #3 CCL/GR/GPT, Run in hole to tag 6359' (no fluid), Pull out of hole & Secure well, Release to BRU 244-27. Daily Operations: Production evaluation complete. Page 1 of 1 _____________________________________________________________________________________ Updated by DMA 04-11-24 SCHEMATIC Well: Ivan River 241-01 PTD: 221-076 API: 50-283-20184-00-00 PERFORATION DETAIL Zone Top MD Btm MD Top TVD Btm TVD FT Date Status ST A5 6,263’6,265’5,116’5,126’12’2/26/24 Open ST B1 6,306’6,323’5,158’5,172’17’8/31/22 Open ST B2 6,370’6,378’5,208’5,214’8’2/25/24 Open Beluga U 6,576’6,590’5368’5381’14’08/25/22 Open Beluga D1 6,638’6,647’5418’5425’9’08/24/22 Isolated Beluga E5d 7,170’7,180’5829’5839’10’08/13/22 Isolated BEL H4u 8,233’8,242’6,667’6,674’9’08/12/22 Isolated BEL H4m 8,254’8,263’6,684’6,691’9’08/12/22 Isolated BEL H4L 8,289’8,309’6,712’6,727’20’08/12/22 Isolated BEL H8 8,395’8,415’6,795’6,811’20’08/12/22 Isolated BEL H15 8,698’8,713’7,033’7,045’15’08/10/22 Isolated BEL I3 9,001’9,006’7,272’7,277’5’08/10/22 Isolated BEL I5 9,103’9,119’7,351’7,364’16’08/10/22 Isolated BEL I8 9,202’9,215’7,427’7,438’13’08/10/22 Isolated OPEN HOLE / CEMENT DETAIL 10-3/4”TOC @ Surface 7-5/8"Est. TOC @ 1,677’ 4-1/2”TOC @ 6,040’ CBL CASING DETAIL Size Type Wt Grade Conn.ID Top Btm 16”Conductor – Driven to Set Depth 84 X-56 Weld 15.01”Surf 120’ 10-3/4”Surf Csg 45.5 L-80 DWC/C 9.950”Surf 3,005’ 7-5/8"Int. Csg 29.7 L-80 CDC 6.875”Surf 5,994’ 4-1/2"Prod Lnr 12.6 L-80 DWC/C HT 3.958”5,811’9,585’ 4-1/2"Prod Tieback 12.6 L-80 DWC/C HT 3.958”Surf 5,818’ JEWELRY DETAIL No.Depth ID OD Item 1 518’3.958”5.840”Chem Injection Mandrel 2 2,737’6.875”9.950”7-5/8” Swell Packer 3 5,811’4.875”6.540”Liner hanger / LTP Assembly 5,818’4.890”5.700”Tieback Seal Assy. (2.92’ off no-go) 4 8,200’3.71”CIBP (08/12/22) 5 8,668’3.71”CIBP(08/10/22) 1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: N2 2.Operator Name:4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number):10. Field: 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 9,585'N/A Casing Collapse Structural Conductor 1,410psi Surface 2,470psi Intermediate 4,790psi Production 7,500psi Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng Swell Pkr & N/A 2,737 (MD) 2,380 (TVD) & N/A 7,732'6,628'5,410' Ivan River Undefined Gas Pool 16" 10-3/4" See Attached Schematic 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Ivan River Unit (IRU) 241-01CO 795 Same 7,733'4-1/2" 1937psi 3,774' 6,628' & 7,100' Length January 25, 2024 Tieback 4-1/2" 9,585' Perforation Depth MD (ft): 5,994' See Attached Schematic 6,880psi 2,980psi 5,210psi 120' 4,915' 120' 3,005' Size 120' 7-5/8"5,994' 3,005' MD Hilcorp Alaska, LLC Proposed Pools: 12.6 / L-80 TVD Burst 5,818' 8,430psi 2,586' Tubing MD (ft):Perforation Depth TVD (ft): Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 AD32930 221-076 50-283-20184-00-00 Tubing Size: PRESENT WELL CONDITION SUMMARY Jake Flora, Operations Engineer AOGCC USE ONLY Tubing Grade: jake.flora@hilcorp.com 907-777-8442 Noel Nocas, Operations Manager 907-564-5278 Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi):Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: m n P 66 t 2 N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 8:48 am, Jan 12, 2024 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2024.01.10 17:29:41 - 09'00' Noel Nocas (4361) 324-014 DSR-1/26/24 10-404 Perforate ADL032930 SFD SFD 1/23/2024BJM 1/16/24*&:JLC 1/29/2024 1/29/24Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2024.01.29 15:05:48 -09'00' RBDMS JSB 013024 Well Prognosis Well Name: IRU 241-01 API Number: 50-283-20184-00-00 Current Status: Gas Producer Permit to Drill Number: 221-076 First Call Engineer: Jake Flora (907) 777-8442 (O) (720) 988-5375 (C) Second Call Engineer: Chad Helgeson (907) 777-8420 (O) (907) 229-4824 (M) Maximum Expected BHP: 2475 psi 0.46 psi/ft gradient (5381’ TVD) Max. Potential Surface Pressure: 1937 psi BHP minus 0.1 psi/ft gradient Well Status: Online Gas Producer Last well test: 350 mcfd @ 216 psi, 0 bw Brief Well Summary IRU 241-01 was drilled in late 2021 and completed as a Beluga and Sterling producer. The well has significantly declined to the current rate. The purpose of this sundry is to increase productivity by perforating additional Sterling sands. All sands lie in the Ivan River Undefined Gas Pool. History: Open Perfs: Sterling B1 6306 - 6323’ MD 5158 - 5172’ TVD Beluga U 6576 - 6590’ MD 5368 - 5381’ TVD 01/07/24 2.70” GR to 6325’, 2-7/8 dummy gun to 6315’ Procedure: 1. Review approved COAs 2. MIRU Eline, PT lubricator to 3000 psi. 3. Perforate sands from the below interval bottom up: Proposed interval: Sterling X2 – C1 6042’ – 6484’ MD 4952’ – 5297’ TVD a. If any zone produces sand and/or water or needs isolated, RIH and set plug above the perforations OR patch across the perforations. b. If necessary use nitrogen to pressure up well during perforating 4. Return to production Attachments: 1. Actual Schematic 2. Proposed Schematic 3. Nitrogen SOP _____________________________________________________________________________________ EditedBy: CJD09/21/22 SCHEMATIC Well: Ivan River 241-01 PTD: 221-076 API: 50-283-20184-00-00 PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD)FT Date Status ST B1 6,306’6,323’5,158’5,172’17’8/31/22 Open Beluga u 6,576’6,590’5368’5381’14’08/25/22 Open Beluga d1 6,638’6,647’5418’5425’9’08/24/22 Isolated Beluga_E5d 7,170’7,180’5829’5839’10’08/13/22 Isolated BEL_H4u 8,233’8,242’6,667’6,674’9’08/12/22 Isolated BEL_H4m 8,254’8,263’6,684’6,691’9’08/12/22 Isolated BEL_H4L 8,289’8,309’6,712’6,727’20’08/12/22 Isolated BEL_H8 8,395’8,415’6,795’6,811’20’08/12/22 Isolated BEL_H15 8,698’8,713’7,033’7,045’15’08/10/22 Isolated BEL_I3 9,001’9,006’7,272’7,277’5’08/10/22 Isolated BEL_I5 9,103’9,119’7,351’7,364’16’08/10/22 Isolated BEL_I8 9,202’9,215’7,427’7,438’13’08/10/22 Isolated OPEN HOLE / CEMENT DETAIL 10-3/4”TOC @ Surface 7-5/8"Est. TOC @ 1,677’ 4-1/2”TOC @ 6,040’ CBL CASING DETAIL Size Type Wt Grade Conn.ID Top Btm 16”Conductor – Driven to Set Depth 84 X-56 Weld 15.01”Surf 120’ 10-3/4”Surf Csg 45.5 L-80 DWC/C 9.950”Surf 3,005’ 7-5/8"Int. Csg 29.7 L-80 CDC 6.875”Surf 5,994’ 4-1/2"Prod Lnr 12.6 L-80 DWC/C HT 3.958”5,811’9,585’ 4-1/2"Prod Tieback 12.6 L-80 DWC/C HT 3.958”Surf 5,818’ JEWELRY DETAIL No.Depth ID OD Item 1 518’3.958”5.840”Chem Injection Mandrel 2 2,737’6.875”9.950”7-5/8” Swell Packer 3 5,811’4.875”6.540”Liner hanger / LTP Assembly 5,818’4.890”5.700”Tieback Seal Assy. (2.92’ off no-go) 4 8,200’3.71”CIBP (08/12/22) 5 8,668’3.71”CIBP(08/10/22) _____________________________________________________________________________________ Updated by DMA 01-10-24 PROPOSED Well: Ivan River 241-01 PTD: 221-076 API: 50-283-20184-00-00 PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD)FT Date Status ST X2-C1 ±6,042’±6,484’±4,952’±5,297’±442 Proposed TBD ST B1 6,306’6,323’5,158’5,172’17’8/31/22 Open Beluga u 6,576’6,590’5368’5381’14’08/25/22 Open Beluga d1 6,638’6,647’5418’5425’9’08/24/22 Isolated Beluga_E5d 7,170’7,180’5829’5839’10’08/13/22 Isolated BEL_H4u 8,233’8,242’6,667’6,674’9’08/12/22 Isolated BEL_H4m 8,254’8,263’6,684’6,691’9’08/12/22 Isolated BEL_H4L 8,289’8,309’6,712’6,727’20’08/12/22 Isolated BEL_H8 8,395’8,415’6,795’6,811’20’08/12/22 Isolated BEL_H15 8,698’8,713’7,033’7,045’15’08/10/22 Isolated BEL_I3 9,001’9,006’7,272’7,277’5’08/10/22 Isolated BEL_I5 9,103’9,119’7,351’7,364’16’08/10/22 Isolated BEL_I8 9,202’9,215’7,427’7,438’13’08/10/22 Isolated OPEN HOLE / CEMENT DETAIL 10-3/4”TOC @ Surface 7-5/8"Est. TOC @ 1,677’ 4-1/2”TOC @ 6,040’ CBL CASING DETAIL Size Type Wt Grade Conn.ID Top Btm 16”Conductor – Driven to Set Depth 84 X-56 Weld 15.01”Surf 120’ 10-3/4”Surf Csg 45.5 L-80 DWC/C 9.950”Surf 3,005’ 7-5/8"Int. Csg 29.7 L-80 CDC 6.875”Surf 5,994’ 4-1/2"Prod Lnr 12.6 L-80 DWC/C HT 3.958”5,811’9,585’ 4-1/2"Prod Tieback 12.6 L-80 DWC/C HT 3.958”Surf 5,818’ JEWELRY DETAIL No.Depth ID OD Item 1 518’3.958”5.840”Chem Injection Mandrel 2 2,737’6.875”9.950”7-5/8” Swell Packer 3 5,811’4.875”6.540”Liner hanger / LTP Assembly 5,818’4.890”5.700”Tieback Seal Assy. (2.92’ off no-go) 4 8,200’3.71”CIBP (08/12/22) 5 8,668’3.71”CIBP(08/10/22) STANDARD WELL PROCEDURE NITROGEN OPERATIONS 12/08/2015 FINAL v1 Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. DA T A S U B M I T T A L C O M P L I A N C E R E P O R T AP I N o . 50 - 2 8 3 - 2 0 1 8 4 - 0 0 - 0 0 We l l N a m e / N o . IV A N R I V E R U N I T 2 4 1 - 0 1 Co m p l e t i o n S t a t u s 1- G A S Co m p l e t i o n D a t e 8/ 9 / 2 0 2 2 Pe r m i t t o D r i l l 22 1 0 7 6 0 Op e r a t o r Hi l c o r p A l a s k a , L L C MD 95 8 5 TV D 77 3 2 Cu r r e n t S t a t u s 1- G A S 9/ 2 1 / 2 0 2 3 UI C No We l l L o g I n f o r m a t i o n : Di g i t a l Me d / F r m t Re c e i v e d St a r t S t o p OH / CH Co m m e n t s Lo g Me d i a Ru n No El e c t r Da t a s e t Nu m b e r Na m e In t e r v a l Li s t o f L o g s O b t a i n e d : LW D : P C G / A G R / D G R / E W R / A D R / A L D / C T N , M u d l o g s , G P T , P e r f L o g , C B L 8 - 5 - 2 2 No No Ye s Mu d L o g S a m p l e s D i r e c t i o n a l S u r v e y RE Q U I R E D I N F O R M A T I O N (f r o m M a s t e r W e l l D a t a / L o g s ) DA T A I N F O R M A T I O N Lo g / Da t a Ty p e Lo g Sc a l e DF 12 / 6 / 2 0 2 1 11 0 3 0 1 4 E l e c t r o n i c D a t a S e t , F i l e n a m e : I R U 2 4 1 - 0 1 Su r f a c e F i n a l L W D . l a s 36 0 6 0 ED Di g i t a l D a t a DF 12 / 6 / 2 0 2 1 E l e c t r o n i c F i l e : I R U 2 4 1 - 0 1 S u r f a c e F i n a l L W D MD . c g m 36 0 6 0 ED Di g i t a l D a t a DF 12 / 6 / 2 0 2 1 E l e c t r o n i c F i l e : I R U 2 4 1 - 0 1 S u r f a c e F i n a l L W D TV D . c g m 36 0 6 0 ED Di g i t a l D a t a DF 12 / 6 / 2 0 2 1 E l e c t r o n i c F i l e : I R U 2 4 1 - 0 1 - s u r f a c e s u r v e y s . x l s x 36 0 6 0 ED Di g i t a l D a t a DF 12 / 6 / 2 0 2 1 E l e c t r o n i c F i l e : I R U 2 4 1 - 0 1 - S u r f a c e _ D S R . p d f 36 0 6 0 ED Di g i t a l D a t a DF 12 / 6 / 2 0 2 1 E l e c t r o n i c F i l e : I R U 2 4 1 - 0 1 - S u r f a c e _ D S R . t x t 36 0 6 0 ED Di g i t a l D a t a DF 12 / 6 / 2 0 2 1 E l e c t r o n i c F i l e : I R U 2 4 1 - 0 1 - S u r f a c e _ G I S . t x t 36 0 6 0 ED Di g i t a l D a t a DF 12 / 6 / 2 0 2 1 E l e c t r o n i c F i l e : I R U 2 4 1 - 0 1 - S u r f a c e _ P l a n . p d f 36 0 6 0 ED Di g i t a l D a t a DF 12 / 6 / 2 0 2 1 E l e c t r o n i c F i l e : I R U 2 4 1 - 0 1 - S u r f a c e _ V S e c . p d f 36 0 6 0 ED Di g i t a l D a t a DF 12 / 6 / 2 0 2 1 E l e c t r o n i c F i l e : I R U 2 4 1 - 0 1 S u r f a c e F i n a l L W D MD . e m f 36 0 6 0 ED Di g i t a l D a t a DF 12 / 6 / 2 0 2 1 E l e c t r o n i c F i l e : I R U 2 4 1 - 0 1 S u r f a c e F i n a l L W D TV D . e m f 36 0 6 0 ED Di g i t a l D a t a DF 12 / 6 / 2 0 2 1 E l e c t r o n i c F i l e : I R U 2 4 1 - 0 1 S u r f a c e F i n a l L W D MD . p d f 36 0 6 0 ED Di g i t a l D a t a DF 12 / 6 / 2 0 2 1 E l e c t r o n i c F i l e : I R U 2 4 1 - 0 1 S u r f a c e F i n a l L W D TV D . p d f 36 0 6 0 ED Di g i t a l D a t a DF 12 / 6 / 2 0 2 1 E l e c t r o n i c F i l e : I R U 2 4 1 - 0 1 S u r f a c e F i n a l L W D MD . t i f 36 0 6 0 ED Di g i t a l D a t a DF 12 / 6 / 2 0 2 1 E l e c t r o n i c F i l e : I R U 2 4 1 - 0 1 S u r f a c e F i n a l L W D TV D . t i f 36 0 6 0 ED Di g i t a l D a t a Th u r s d a y , S e p t e m b e r 2 1 , 2 0 2 3 AO G C C P a g e 1 o f 8 Su p p l i e d b y Op Su p p l i e d b y Op IR U 2 4 1 - 0 1 , Sur fac e F i n a l L W D . l a s DA T A S U B M I T T A L C O M P L I A N C E R E P O R T AP I N o . 50 - 2 8 3 - 2 0 1 8 4 - 0 0 - 0 0 We l l N a m e / N o . IV A N R I V E R U N I T 2 4 1 - 0 1 Co m p l e t i o n S t a t u s 1- G A S Co m p l e t i o n D a t e 8/ 9 / 2 0 2 2 Pe r m i t t o D r i l l 22 1 0 7 6 0 Op e r a t o r Hi l c o r p A l a s k a , L L C MD 95 8 5 TV D 77 3 2 Cu r r e n t S t a t u s 1- G A S 9/ 2 1 / 2 0 2 3 UI C No 0 0 2 2 1 0 7 6 0 I V A N R I V E R U N I T 2 4 1 - 0 1 L O G HE A D E R S 36 0 6 0 Lo g Lo g H e a d e r S c a n s DF 12 / 2 1 / 2 0 2 1 0 3 0 2 8 E l e c t r o n i c D a t a S e t , F i l e n a m e : H i l c o r p I R U - 2 4 1 - 01 H a l l i b u r t o n S D L F i n a l M u d l o g . l a s 36 1 0 1 ED Di g i t a l D a t a DF 12 / 2 1 / 2 0 2 1 E l e c t r o n i c F i l e : H i l c o r p I R U - 2 4 1 - 0 1 H a l l i b u r t o n SD L 2 i n M D D r i l l i n g E n g i n e e r i n g L o g . c g m 36 1 0 1 ED Di g i t a l D a t a DF 12 / 2 1 / 2 0 2 1 E l e c t r o n i c F i l e : H i l c o r p I R U - 2 4 1 - 0 1 H a l l i b u r t o n SD L 2 i n M D F o r m a t i o n E v a l u a t i o n L o g . c g m 36 1 0 1 ED Di g i t a l D a t a DF 12 / 2 1 / 2 0 2 1 E l e c t r o n i c F i l e : H i l c o r p I R U - 2 4 1 - 0 1 H a l l i b u r t o n SD L 2 i n M D G a s R a t i o L o g . c g m 36 1 0 1 ED Di g i t a l D a t a DF 12 / 2 1 / 2 0 2 1 E l e c t r o n i c F i l e : H i l c o r p I R U - 2 4 1 - 0 1 H a l l i b u r t o n SD L 2 i n T V D D r i l l i n g E n g i n e e r i n g L o g . c g m 36 1 0 1 ED Di g i t a l D a t a DF 12 / 2 1 / 2 0 2 1 E l e c t r o n i c F i l e : H i l c o r p I R U - 2 4 1 - 0 1 H a l l i b u r t o n SD L 2 i n T V D F o r m a t i o n E v a l u a t i o n L o g . c g m 36 1 0 1 ED Di g i t a l D a t a DF 12 / 2 1 / 2 0 2 1 E l e c t r o n i c F i l e : H i l c o r p I R U - 2 4 1 - 0 1 H a l l i b u r t o n SD L 2 i n T V D G a s R a t i o L o g . c g m 36 1 0 1 ED Di g i t a l D a t a DF 12 / 2 1 / 2 0 2 1 E l e c t r o n i c F i l e : H i l c o r p I R U - 2 4 1 - 0 1 H a l l i b u r t o n SD L 5 i n M D D r i l l i n g E n g i n e e r i n g L o g . c g m 36 1 0 1 ED Di g i t a l D a t a DF 12 / 2 1 / 2 0 2 1 E l e c t r o n i c F i l e : H i l c o r p I R U - 2 4 1 - 0 1 H a l l i b u r t o n SD L 5 i n M D F o r m a t i o n E v a l u a t i o n L o g . c g m 36 1 0 1 ED Di g i t a l D a t a DF 12 / 2 1 / 2 0 2 1 E l e c t r o n i c F i l e : H i l c o r p I R U - 2 4 1 - 0 1 H a l l i b u r t o n SD L 5 i n M D G a s R a t i o L o g . c g m 36 1 0 1 ED Di g i t a l D a t a DF 12 / 2 1 / 2 0 2 1 E l e c t r o n i c F i l e : H i l c o r p I R U - 2 4 1 - 0 1 H a l l i b u r t o n SD L 5 i n T V D D r i l l i n g E n g i n e e r i n g L o g . c g m 36 1 0 1 ED Di g i t a l D a t a DF 12 / 2 1 / 2 0 2 1 E l e c t r o n i c F i l e : H i l c o r p I R U - 2 4 1 - 0 1 H a l l i b u r t o n SD L 5 i n T V D F o r m a t i o n E v a l u a t i o n L o g . c g m 36 1 0 1 ED Di g i t a l D a t a DF 12 / 2 1 / 2 0 2 1 E l e c t r o n i c F i l e : H i l c o r p I R U - 2 4 1 - 0 1 H a l l i b u r t o n SD L 5 i n T V D G a s R a t i o L o g . c g m 36 1 0 1 ED Di g i t a l D a t a DF 12 / 2 1 / 2 0 2 1 E l e c t r o n i c F i l e : H i l c o r p I R U - 2 4 1 - 0 1 H a l l i b u r t o n SD L 2 i n M D D r i l l i n g E n g i n e e r i n g L o g . e m z 36 1 0 1 ED Di g i t a l D a t a DF 12 / 2 1 / 2 0 2 1 E l e c t r o n i c F i l e : H i l c o r p I R U - 2 4 1 - 0 1 H a l l i b u r t o n SD L 2 i n M D F o r m a t i o n E v a l u a t i o n L o g . e m z 36 1 0 1 ED Di g i t a l D a t a DF 12 / 2 1 / 2 0 2 1 E l e c t r o n i c F i l e : H i l c o r p I R U - 2 4 1 - 0 1 H a l l i b u r t o n SD L 2 i n M D G a s R a t i o L o g . e m z 36 1 0 1 ED Di g i t a l D a t a DF 12 / 2 1 / 2 0 2 1 E l e c t r o n i c F i l e : H i l c o r p I R U - 2 4 1 - 0 1 H a l l i b u r t o n SD L 2 i n T V D D r i l l i n g E n g i n e e r i n g L o g . e m z 36 1 0 1 ED Di g i t a l D a t a Th u r s d a y , S e p t e m b e r 2 1 , 2 0 2 3 AO G C C P a g e 2 o f 8 Hi l c o r p I R U - 2 4 1 - , 01 H a l l i b u r t o n SDL F i n a l M u d l o g.l a s DA T A S U B M I T T A L C O M P L I A N C E R E P O R T AP I N o . 50 - 2 8 3 - 2 0 1 8 4 - 0 0 - 0 0 We l l N a m e / N o . IV A N R I V E R U N I T 2 4 1 - 0 1 Co m p l e t i o n S t a t u s 1- G A S Co m p l e t i o n D a t e 8/ 9 / 2 0 2 2 Pe r m i t t o D r i l l 22 1 0 7 6 0 Op e r a t o r Hi l c o r p A l a s k a , L L C MD 95 8 5 TV D 77 3 2 Cu r r e n t S t a t u s 1- G A S 9/ 2 1 / 2 0 2 3 UI C No DF 12 / 2 1 / 2 0 2 1 E l e c t r o n i c F i l e : H i l c o r p I R U - 2 4 1 - 0 1 H a l l i b u r t o n SD L 2 i n T V D F o r m a t i o n E v a l u a t i o n L o g . e m z 36 1 0 1 ED Di g i t a l D a t a DF 12 / 2 1 / 2 0 2 1 E l e c t r o n i c F i l e : H i l c o r p I R U - 2 4 1 - 0 1 H a l l i b u r t o n SD L 2 i n T V D G a s R a t i o L o g . e m z 36 1 0 1 ED Di g i t a l D a t a DF 12 / 2 1 / 2 0 2 1 E l e c t r o n i c F i l e : H i l c o r p I R U - 2 4 1 - 0 1 H a l l i b u r t o n SD L 5 i n M D D r i l l i n g E n g i n e e r i n g L o g . e m z 36 1 0 1 ED Di g i t a l D a t a DF 12 / 2 1 / 2 0 2 1 E l e c t r o n i c F i l e : H i l c o r p I R U - 2 4 1 - 0 1 H a l l i b u r t o n SD L 5 i n M D F o r m a t i o n E v a l u a t i o n L o g . e m z 36 1 0 1 ED Di g i t a l D a t a DF 12 / 2 1 / 2 0 2 1 E l e c t r o n i c F i l e : H i l c o r p I R U - 2 4 1 - 0 1 H a l l i b u r t o n SD L 5 i n M D G a s R a t i o L o g . e m z 36 1 0 1 ED Di g i t a l D a t a DF 12 / 2 1 / 2 0 2 1 E l e c t r o n i c F i l e : H i l c o r p I R U - 2 4 1 - 0 1 H a l l i b u r t o n SD L 5 i n T V D D r i l l i n g E n g i n e e r i n g L o g . e m z 36 1 0 1 ED Di g i t a l D a t a DF 12 / 2 1 / 2 0 2 1 E l e c t r o n i c F i l e : H i l c o r p I R U - 2 4 1 - 0 1 H a l l i b u r t o n SD L 5 i n T V D F o r m a t i o n E v a l u a t i o n L o g . e m z 36 1 0 1 ED Di g i t a l D a t a DF 12 / 2 1 / 2 0 2 1 E l e c t r o n i c F i l e : H i l c o r p I R U - 2 4 1 - 0 1 H a l l i b u r t o n SD L 5 i n T V D G a s R a t i o L o g . e m z 36 1 0 1 ED Di g i t a l D a t a DF 12 / 2 1 / 2 0 2 1 E l e c t r o n i c F i l e : H i l c o r p I R U - 2 4 1 - 0 1 H a l l i b u r t o n SD L E n d o f W e l l R e p o r t . p d f 36 1 0 1 ED Di g i t a l D a t a DF 12 / 2 1 / 2 0 2 1 E l e c t r o n i c F i l e : H i l c o r p I R U - 2 4 1 - 0 1 H a l l i b u r t o n SD L 2 i n M D D r i l l i n g E n g i n e e r i n g L o g . p d f 36 1 0 1 ED Di g i t a l D a t a DF 12 / 2 1 / 2 0 2 1 E l e c t r o n i c F i l e : H i l c o r p I R U - 2 4 1 - 0 1 H a l l i b u r t o n SD L 2 i n M D F o r m a t i o n E v a l u a t i o n L o g . p d f 36 1 0 1 ED Di g i t a l D a t a DF 12 / 2 1 / 2 0 2 1 E l e c t r o n i c F i l e : H i l c o r p I R U - 2 4 1 - 0 1 H a l l i b u r t o n SD L 2 i n M D G a s R a t i o L o g . p d f 36 1 0 1 ED Di g i t a l D a t a DF 12 / 2 1 / 2 0 2 1 E l e c t r o n i c F i l e : H i l c o r p I R U - 2 4 1 - 0 1 H a l l i b u r t o n SD L 2 i n T V D D r i l l i n g E n g i n e e r i n g L o g . p d f 36 1 0 1 ED Di g i t a l D a t a DF 12 / 2 1 / 2 0 2 1 E l e c t r o n i c F i l e : H i l c o r p I R U - 2 4 1 - 0 1 H a l l i b u r t o n SD L 2 i n T V D F o r m a t i o n E v a l u a t i o n L o g . p d f 36 1 0 1 ED Di g i t a l D a t a DF 12 / 2 1 / 2 0 2 1 E l e c t r o n i c F i l e : H i l c o r p I R U - 2 4 1 - 0 1 H a l l i b u r t o n SD L 2 i n T V D G a s R a t i o L o g . p d f 36 1 0 1 ED Di g i t a l D a t a DF 12 / 2 1 / 2 0 2 1 E l e c t r o n i c F i l e : H i l c o r p I R U - 2 4 1 - 0 1 H a l l i b u r t o n SD L 5 i n M D D r i l l i n g E n g i n e e r i n g L o g . p d f 36 1 0 1 ED Di g i t a l D a t a DF 12 / 2 1 / 2 0 2 1 E l e c t r o n i c F i l e : H i l c o r p I R U - 2 4 1 - 0 1 H a l l i b u r t o n SD L 5 i n M D F o r m a t i o n E v a l u a t i o n L o g . p d f 36 1 0 1 ED Di g i t a l D a t a DF 12 / 2 1 / 2 0 2 1 E l e c t r o n i c F i l e : H i l c o r p I R U - 2 4 1 - 0 1 H a l l i b u r t o n SD L 5 i n M D G a s R a t i o L o g . p d f 36 1 0 1 ED Di g i t a l D a t a Th u r s d a y , S e p t e m b e r 2 1 , 2 0 2 3 AO G C C P a g e 3 o f 8 DA T A S U B M I T T A L C O M P L I A N C E R E P O R T AP I N o . 50 - 2 8 3 - 2 0 1 8 4 - 0 0 - 0 0 We l l N a m e / N o . IV A N R I V E R U N I T 2 4 1 - 0 1 Co m p l e t i o n S t a t u s 1- G A S Co m p l e t i o n D a t e 8/ 9 / 2 0 2 2 Pe r m i t t o D r i l l 22 1 0 7 6 0 Op e r a t o r Hi l c o r p A l a s k a , L L C MD 95 8 5 TV D 77 3 2 Cu r r e n t S t a t u s 1- G A S 9/ 2 1 / 2 0 2 3 UI C No DF 12 / 2 1 / 2 0 2 1 E l e c t r o n i c F i l e : H i l c o r p I R U - 2 4 1 - 0 1 H a l l i b u r t o n SD L 5 i n T V D D r i l l i n g E n g i n e e r i n g L o g . p d f 36 1 0 1 ED Di g i t a l D a t a DF 12 / 2 1 / 2 0 2 1 E l e c t r o n i c F i l e : H i l c o r p I R U - 2 4 1 - 0 1 H a l l i b u r t o n SD L 5 i n T V D F o r m a t i o n E v a l u a t i o n L o g . p d f 36 1 0 1 ED Di g i t a l D a t a DF 12 / 2 1 / 2 0 2 1 E l e c t r o n i c F i l e : H i l c o r p I R U - 2 4 1 - 0 1 H a l l i b u r t o n SD L 5 i n T V D G a s R a t i o L o g . p d f 36 1 0 1 ED Di g i t a l D a t a DF 12 / 2 1 / 2 0 2 1 E l e c t r o n i c F i l e : H i l c o r p I R U - 2 4 1 - 0 1 H a l l i b u r t o n SD L 2 i n M D D r i l l i n g E n g i n e e r i n g L o g . t i f 36 1 0 1 ED Di g i t a l D a t a DF 12 / 2 1 / 2 0 2 1 E l e c t r o n i c F i l e : H i l c o r p I R U - 2 4 1 - 0 1 H a l l i b u r t o n SD L 2 i n M D F o r m a t i o n E v a l u a t i o n L o g . t i f 36 1 0 1 ED Di g i t a l D a t a DF 12 / 2 1 / 2 0 2 1 E l e c t r o n i c F i l e : H i l c o r p I R U - 2 4 1 - 0 1 H a l l i b u r t o n SD L 2 i n M D G a s R a t i o L o g . t i f 36 1 0 1 ED Di g i t a l D a t a DF 12 / 2 1 / 2 0 2 1 E l e c t r o n i c F i l e : H i l c o r p I R U - 2 4 1 - 0 1 H a l l i b u r t o n SD L 2 i n T V D D r i l l i n g E n g i n e e r i n g L o g . t i f 36 1 0 1 ED Di g i t a l D a t a DF 12 / 2 1 / 2 0 2 1 E l e c t r o n i c F i l e : H i l c o r p I R U - 2 4 1 - 0 1 H a l l i b u r t o n SD L 2 i n T V D F o r m a t i o n E v a l u a t i o n L o g . t i f 36 1 0 1 ED Di g i t a l D a t a DF 12 / 2 1 / 2 0 2 1 E l e c t r o n i c F i l e : H i l c o r p I R U - 2 4 1 - 0 1 H a l l i b u r t o n SD L 2 i n T V D G a s R a t i o L o g . t i f 36 1 0 1 ED Di g i t a l D a t a DF 12 / 2 1 / 2 0 2 1 E l e c t r o n i c F i l e : H i l c o r p I R U - 2 4 1 - 0 1 H a l l i b u r t o n SD L 5 i n M D D r i l l i n g E n g i n e e r i n g L o g . t i f 36 1 0 1 ED Di g i t a l D a t a DF 12 / 2 1 / 2 0 2 1 E l e c t r o n i c F i l e : H i l c o r p I R U - 2 4 1 - 0 1 H a l l i b u r t o n SD L 5 i n M D F o r m a t i o n E v a l u a t i o n L o g . t i f 36 1 0 1 ED Di g i t a l D a t a DF 12 / 2 1 / 2 0 2 1 E l e c t r o n i c F i l e : H i l c o r p I R U - 2 4 1 - 0 1 H a l l i b u r t o n SD L 5 i n M D G a s R a t i o L o g . t i f 36 1 0 1 ED Di g i t a l D a t a DF 12 / 2 1 / 2 0 2 1 E l e c t r o n i c F i l e : H i l c o r p I R U - 2 4 1 - 0 1 H a l l i b u r t o n SD L 5 i n T V D D r i l l i n g E n g i n e e r i n g L o g . t i f 36 1 0 1 ED Di g i t a l D a t a DF 12 / 2 1 / 2 0 2 1 E l e c t r o n i c F i l e : H i l c o r p I R U - 2 4 1 - 0 1 H a l l i b u r t o n SD L 5 i n T V D F o r m a t i o n E v a l u a t i o n L o g . t i f 36 1 0 1 ED Di g i t a l D a t a DF 12 / 2 1 / 2 0 2 1 E l e c t r o n i c F i l e : H i l c o r p I R U - 2 4 1 - 0 1 H a l l i b u r t o n SD L 5 i n T V D G a s R a t i o L o g . t i f 36 1 0 1 ED Di g i t a l D a t a DF 12 / 2 1 / 2 0 2 1 E l e c t r o n i c F i l e : E M F V i e w 3 _ 1 . z i p 36 1 0 1 ED Di g i t a l D a t a DF 12 / 2 1 / 2 0 2 1 E l e c t r o n i c F i l e : R e a d m e . t x t 36 1 0 1 ED Di g i t a l D a t a 0 0 2 2 1 0 7 6 0 I V A N R I V E R U N I T 2 4 1 - 0 1 L O G HE A D E R S 36 1 0 1 Lo g Lo g H e a d e r S c a n s DF 7/ 2 9 / 2 0 2 2 82 9 5 8 4 E l e c t r o n i c D a t a S e t , F i l e n a m e : I R U 2 4 1 - 0 1 L W D Fi n a l . l a s 36 8 3 9 ED Di g i t a l D a t a Th u r s d a y , S e p t e m b e r 2 1 , 2 0 2 3 AO G C C P a g e 4 o f 8 IR U 2 4 1 - 0 1 L W D Fi n al. l as DA T A S U B M I T T A L C O M P L I A N C E R E P O R T AP I N o . 50 - 2 8 3 - 2 0 1 8 4 - 0 0 - 0 0 We l l N a m e / N o . IV A N R I V E R U N I T 2 4 1 - 0 1 Co m p l e t i o n S t a t u s 1- G A S Co m p l e t i o n D a t e 8/ 9 / 2 0 2 2 Pe r m i t t o D r i l l 22 1 0 7 6 0 Op e r a t o r Hi l c o r p A l a s k a , L L C MD 95 8 5 TV D 77 3 2 Cu r r e n t S t a t u s 1- G A S 9/ 2 1 / 2 0 2 3 UI C No DF 7/ 2 9 / 2 0 2 2 E l e c t r o n i c F i l e : I R U 2 4 1 - 0 1 L W D F i n a l M D . c g m 36 8 3 9 ED Di g i t a l D a t a DF 7/ 2 9 / 2 0 2 2 E l e c t r o n i c F i l e : I R U 2 4 1 - 0 1 L W D F i n a l T V D . c g m 36 8 3 9 ED Di g i t a l D a t a DF 7/ 2 9 / 2 0 2 2 E l e c t r o n i c F i l e : I R U 2 4 1 - 0 1 _ D e f i n i t i v e S u r v e y Re p o r t . p d f 36 8 3 9 ED Di g i t a l D a t a DF 7/ 2 9 / 2 0 2 2 E l e c t r o n i c F i l e : I R U 2 4 1 - 0 1 _ D S R A c t u a l _ P l a n . p d f 36 8 3 9 ED Di g i t a l D a t a DF 7/ 2 9 / 2 0 2 2 E l e c t r o n i c F i l e : I R U 2 4 1 - 0 1 _ D S R Ac t u a l _ V S e c . p d f 36 8 3 9 ED Di g i t a l D a t a DF 7/ 2 9 / 2 0 2 2 E l e c t r o n i c F i l e : I R U 2 4 1 - 0 1 _ D S R . t x t 36 8 3 9 ED Di g i t a l D a t a DF 7/ 2 9 / 2 0 2 2 E l e c t r o n i c F i l e : I R U 2 4 1 - 0 1 _ D S R _ G I S . t x t 36 8 3 9 ED Di g i t a l D a t a DF 7/ 2 9 / 2 0 2 2 E l e c t r o n i c F i l e : I R U 2 4 1 - 0 1 _ F i n a l S u r v e y s . x l s x 36 8 3 9 ED Di g i t a l D a t a DF 7/ 2 9 / 2 0 2 2 E l e c t r o n i c F i l e : I R U 2 4 1 - 0 1 L W D F i n a l M D . e m f 36 8 3 9 ED Di g i t a l D a t a DF 7/ 2 9 / 2 0 2 2 E l e c t r o n i c F i l e : I R U 2 4 1 - 0 1 L W D F i n a l T V D . e m f 36 8 3 9 ED Di g i t a l D a t a DF 7/ 2 9 / 2 0 2 2 E l e c t r o n i c F i l e : I R U 2 4 1 - 0 1 L W D F i n a l M D . p d f 36 8 3 9 ED Di g i t a l D a t a DF 7/ 2 9 / 2 0 2 2 E l e c t r o n i c F i l e : I R U 2 4 1 - 0 1 L W D F i n a l T V D . p d f 36 8 3 9 ED Di g i t a l D a t a DF 7/ 2 9 / 2 0 2 2 E l e c t r o n i c F i l e : I R U 2 4 1 - 0 1 L W D F i n a l M D . t i f 36 8 3 9 ED Di g i t a l D a t a DF 7/ 2 9 / 2 0 2 2 E l e c t r o n i c F i l e : I R U 2 4 1 - 0 1 L W D F i n a l T V D . t i f 36 8 3 9 ED Di g i t a l D a t a DF 8/ 4 / 2 0 2 2 29 1 0 9 6 5 0 E l e c t r o n i c D a t a S e t , F i l e n a m e : I R U 2 4 1 - 0 1 . l a s 36 8 4 8 ED Di g i t a l D a t a DF 8/ 4 / 2 0 2 2 E l e c t r o n i c F i l e : I R U 2 4 1 - 0 1 D a i l y R e p o r t s . p d f 36 8 4 8 ED Di g i t a l D a t a DF 8/ 4 / 2 0 2 2 E l e c t r o n i c F i l e : I R U 2 4 1 - 0 1 F i n a l W e l l R e p o r t . p d f 36 8 4 8 ED Di g i t a l D a t a DF 8/ 4 / 2 0 2 2 E l e c t r o n i c F i l e : I R U 2 4 1 - 0 1 D r i l l i n g D y n a m i c s Lo g M D 2 i n . p d f 36 8 4 8 ED Di g i t a l D a t a DF 8/ 4 / 2 0 2 2 E l e c t r o n i c F i l e : I R U 2 4 1 - 0 1 D r i l l i n g D y n a m i c s Lo g M D 5 i n . p d f 36 8 4 8 ED Di g i t a l D a t a DF 8/ 4 / 2 0 2 2 E l e c t r o n i c F i l e : I R U 2 4 1 - 0 1 D r i l l i n g D y n a m i c s Lo g T V D 2 i n . p d f 36 8 4 8 ED Di g i t a l D a t a DF 8/ 4 / 2 0 2 2 E l e c t r o n i c F i l e : I R U 2 4 1 - 0 1 D r i l l i n g D y n a m i c s Lo g T V D 5 i n . p d f 36 8 4 8 ED Di g i t a l D a t a DF 8/ 4 / 2 0 2 2 E l e c t r o n i c F i l e : I R U 2 4 1 - 0 1 F o r m a t i o n L o g M D 2i n . p d f 36 8 4 8 ED Di g i t a l D a t a DF 8/ 4 / 2 0 2 2 E l e c t r o n i c F i l e : I R U 2 4 1 - 0 1 F o r m a t i o n L o g M D 5i n . p d f 36 8 4 8 ED Di g i t a l D a t a Th u r s d a y , S e p t e m b e r 2 1 , 2 0 2 3 AO G C C P a g e 5 o f 8 IR U 2 4 1 - 0 1 . l a s DA T A S U B M I T T A L C O M P L I A N C E R E P O R T AP I N o . 50 - 2 8 3 - 2 0 1 8 4 - 0 0 - 0 0 We l l N a m e / N o . IV A N R I V E R U N I T 2 4 1 - 0 1 Co m p l e t i o n S t a t u s 1- G A S Co m p l e t i o n D a t e 8/ 9 / 2 0 2 2 Pe r m i t t o D r i l l 22 1 0 7 6 0 Op e r a t o r Hi l c o r p A l a s k a , L L C MD 95 8 5 TV D 77 3 2 Cu r r e n t S t a t u s 1- G A S 9/ 2 1 / 2 0 2 3 UI C No DF 8/ 4 / 2 0 2 2 E l e c t r o n i c F i l e : I R U 2 4 1 - 0 1 F o r m a t i o n L o g T V D 2i n . p d f 36 8 4 8 ED Di g i t a l D a t a DF 8/ 4 / 2 0 2 2 E l e c t r o n i c F i l e : I R U 2 4 1 - 0 1 F o r m a t i o n L o g T V D 5i n . p d f 36 8 4 8 ED Di g i t a l D a t a DF 8/ 4 / 2 0 2 2 E l e c t r o n i c F i l e : I R U 2 4 1 - 0 1 G a s R a t i o L o g M D 2i n . p d f 36 8 4 8 ED Di g i t a l D a t a DF 8/ 4 / 2 0 2 2 E l e c t r o n i c F i l e : I R U 2 4 1 - 0 1 G a s R a t i o L o g M D 5i n . p d f 36 8 4 8 ED Di g i t a l D a t a DF 8/ 4 / 2 0 2 2 E l e c t r o n i c F i l e : I R U 2 4 1 - 0 1 G a s R a t i o L o g T V D 2i n . p d f 36 8 4 8 ED Di g i t a l D a t a DF 8/ 4 / 2 0 2 2 E l e c t r o n i c F i l e : I R U 2 4 1 - 0 1 G a s R a t i o L o g T V D 5i n . p d f 36 8 4 8 ED Di g i t a l D a t a DF 8/ 4 / 2 0 2 2 E l e c t r o n i c F i l e : I R U 2 4 1 - 0 1 L W D C o m b o L o g M D 2i n . p d f 36 8 4 8 ED Di g i t a l D a t a DF 8/ 4 / 2 0 2 2 E l e c t r o n i c F i l e : I R U 2 4 1 - 0 1 L W D C o m b o L o g M D 5i n . p d f 36 8 4 8 ED Di g i t a l D a t a DF 8/ 4 / 2 0 2 2 E l e c t r o n i c F i l e : I R U 2 4 1 - 0 1 L W D C o m b o L o g TV D 2 i n . p d f 36 8 4 8 ED Di g i t a l D a t a DF 8/ 4 / 2 0 2 2 E l e c t r o n i c F i l e : I R U 2 4 1 - 0 1 L W D C o m b o L o g TV D 5 i n . p d f 36 8 4 8 ED Di g i t a l D a t a DF 8/ 4 / 2 0 2 2 E l e c t r o n i c F i l e : I R U 2 4 1 - 0 1 D r i l l i n g D y n a m i c s Lo g M D 2 i n . t i f 36 8 4 8 ED Di g i t a l D a t a DF 8/ 4 / 2 0 2 2 E l e c t r o n i c F i l e : I R U 2 4 1 - 0 1 D r i l l i n g D y n a m i c s Lo g M D 5 i n . t i f 36 8 4 8 ED Di g i t a l D a t a DF 8/ 4 / 2 0 2 2 E l e c t r o n i c F i l e : I R U 2 4 1 - 0 1 D r i l l i n g D y n a m i c s Lo g T V D 2 i n . t i f 36 8 4 8 ED Di g i t a l D a t a DF 8/ 4 / 2 0 2 2 E l e c t r o n i c F i l e : I R U 2 4 1 - 0 1 D r i l l i n g D y n a m i c s Lo g T V D 5 i n . t i f 36 8 4 8 ED Di g i t a l D a t a DF 8/ 4 / 2 0 2 2 E l e c t r o n i c F i l e : I R U 2 4 1 - 0 1 F o r m a t i o n L o g M D 2i n . t i f 36 8 4 8 ED Di g i t a l D a t a DF 8/ 4 / 2 0 2 2 E l e c t r o n i c F i l e : I R U 2 4 1 - 0 1 F o r m a t i o n L o g M D 5i n . t i f 36 8 4 8 ED Di g i t a l D a t a DF 8/ 4 / 2 0 2 2 E l e c t r o n i c F i l e : I R U 2 4 1 - 0 1 F o r m a t i o n L o g T V D 2i n . t i f 36 8 4 8 ED Di g i t a l D a t a DF 8/ 4 / 2 0 2 2 E l e c t r o n i c F i l e : I R U 2 4 1 - 0 1 F o r m a t i o n L o g T V D 5i n . t i f 36 8 4 8 ED Di g i t a l D a t a Th u r s d a y , S e p t e m b e r 2 1 , 2 0 2 3 AO G C C P a g e 6 o f 8 DA T A S U B M I T T A L C O M P L I A N C E R E P O R T AP I N o . 50 - 2 8 3 - 2 0 1 8 4 - 0 0 - 0 0 We l l N a m e / N o . IV A N R I V E R U N I T 2 4 1 - 0 1 Co m p l e t i o n S t a t u s 1- G A S Co m p l e t i o n D a t e 8/ 9 / 2 0 2 2 Pe r m i t t o D r i l l 22 1 0 7 6 0 Op e r a t o r Hi l c o r p A l a s k a , L L C MD 95 8 5 TV D 77 3 2 Cu r r e n t S t a t u s 1- G A S 9/ 2 1 / 2 0 2 3 UI C No DF 8/ 4 / 2 0 2 2 E l e c t r o n i c F i l e : I R U 2 4 1 - 0 1 G a s R a t i o L o g M D 2i n . t i f 36 8 4 8 ED Di g i t a l D a t a DF 8/ 4 / 2 0 2 2 E l e c t r o n i c F i l e : I R U 2 4 1 - 0 1 G a s R a t i o L o g M D 5i n . t i f 36 8 4 8 ED Di g i t a l D a t a DF 8/ 4 / 2 0 2 2 E l e c t r o n i c F i l e : I R U 2 4 1 - 0 1 G a s R a t i o L o g T V D 2i n . t i f 36 8 4 8 ED Di g i t a l D a t a DF 8/ 4 / 2 0 2 2 E l e c t r o n i c F i l e : I R U 2 4 1 - 0 1 G a s R a t i o L o g T V D 5i n . t i f 36 8 4 8 ED Di g i t a l D a t a DF 8/ 4 / 2 0 2 2 E l e c t r o n i c F i l e : I R U 2 4 1 - 0 1 L W D C o m b o L o g M D 2i n . t i f 36 8 4 8 ED Di g i t a l D a t a DF 8/ 4 / 2 0 2 2 E l e c t r o n i c F i l e : I R U 2 4 1 - 0 1 L W D C o m b o L o g M D 5i n . t i f 36 8 4 8 ED Di g i t a l D a t a DF 8/ 4 / 2 0 2 2 E l e c t r o n i c F i l e : I R U 2 4 1 - 0 1 L W D C o m b o L o g TV D 2 i n . t i f 36 8 4 8 ED Di g i t a l D a t a DF 8/ 4 / 2 0 2 2 E l e c t r o n i c F i l e : I R U 2 4 1 - 0 1 L W D C o m b o L o g TV D 5 i n . t i f 36 8 4 8 ED Di g i t a l D a t a DF 8/ 4 / 2 0 2 2 E l e c t r o n i c F i l e : I R U 2 4 1 - 0 1 S h o w R e p o r t s . p d f 36 8 4 8 ED Di g i t a l D a t a DF 9/ 3 0 / 2 0 2 2 93 7 1 5 6 5 3 E l e c t r o n i c D a t a S e t , F i l e n a m e : I R U _ 2 4 1 - 01 _ C B L _ 0 5 - A u g - 2 0 2 2 _ ( 3 8 9 5 ) . l a s 37 0 8 1 ED Di g i t a l D a t a DF 9/ 3 0 / 2 0 2 2 93 9 3 9 0 3 4 E l e c t r o n i c D a t a S e t , F i l e n a m e : I R U _ 2 4 1 - 01 _ P e r f _ 0 9 - A u g - 2 0 2 2 _ ( 3 9 0 0 ) . l a s 37 0 8 1 ED Di g i t a l D a t a DF 9/ 3 0 / 2 0 2 2 E l e c t r o n i c F i l e : I R U _ 2 4 1 - 0 1 _ C B L _ 0 5 - A u g - 20 2 2 _ ( 3 8 9 5 ) . p d f 37 0 8 1 ED Di g i t a l D a t a DF 9/ 3 0 / 2 0 2 2 E l e c t r o n i c F i l e : I R U _ 2 4 1 - 0 1 _ P e r f _ 0 9 - A u g - 20 2 2 _ ( 3 9 0 0 ) . p d f 37 0 8 1 ED Di g i t a l D a t a DF 11 / 9 / 2 0 2 2 94 2 0 8 2 9 0 E l e c t r o n i c D a t a S e t , F i l e n a m e : I R U _ 2 4 1 - 01 _ G P T _ 1 4 - A u g - 2 0 2 2 _ ( 3 9 0 5 ) . l a s 37 2 4 4 ED Di g i t a l D a t a DF 11 / 9 / 2 0 2 2 87 2 8 8 4 9 2 E l e c t r o n i c D a t a S e t , F i l e n a m e : I R U _ 2 4 1 - 01 _ P l u g _ P e r f _ 1 4 - A u g - 2 0 2 2 _ ( 3 9 0 5 ) . l a s 37 2 4 4 ED Di g i t a l D a t a DF 11 / 9 / 2 0 2 2 -9 6 6 2 8 E l e c t r o n i c D a t a S e t , F i l e n a m e : I R U _ 2 4 1 - 01 _ G P T _ P l u g _ P e r f _ 3 1 - A u g - 2 0 2 2 _ ( 3 9 4 3 ) . l a s 37 2 4 4 ED Di g i t a l D a t a DF 11 / 9 / 2 0 2 2 70 3 6 6 4 8 2 E l e c t r o n i c D a t a S e t , F i l e n a m e : I R U _ 2 4 1 - 01 _ P e r f _ 2 5 - A u g - 2 0 2 2 _ ( 3 9 2 9 ) . l a s 37 2 4 4 ED Di g i t a l D a t a DF 11 / 9 / 2 0 2 2 71 4 1 6 7 8 6 E l e c t r o n i c D a t a S e t , F i l e n a m e : I R U _ 2 4 1 - 01 _ P l u g _ G R _ 2 2 - A u g - 2 0 2 2 _ ( 3 9 2 4 ) . l a s 37 2 4 4 ED Di g i t a l D a t a Th u r s d a y , S e p t e m b e r 2 1 , 2 0 2 3 AO G C C P a g e 7 o f 8 DA T A S U B M I T T A L C O M P L I A N C E R E P O R T AP I N o . 50 - 2 8 3 - 2 0 1 8 4 - 0 0 - 0 0 We l l N a m e / N o . IV A N R I V E R U N I T 2 4 1 - 0 1 Co m p l e t i o n S t a t u s 1- G A S Co m p l e t i o n D a t e 8/ 9 / 2 0 2 2 Pe r m i t t o D r i l l 22 1 0 7 6 0 Op e r a t o r Hi l c o r p A l a s k a , L L C MD 95 8 5 TV D 77 3 2 Cu r r e n t S t a t u s 1- G A S 9/ 2 1 / 2 0 2 3 UI C No We l l C o r e s / S a m p l e s I n f o r m a t i o n : Re c e i v e d St a r t S t o p C o m m e n t s To t a l Bo x e s Sa m p l e Se t Nu m b e r Na m e In t e r v a l IN F O R M A T I O N R E C E I V E D Co m p l e t i o n R e p o r t Pr o d u c t i o n T e s t I n f o r m a t i o n Ge o l o g i c M a r k e r s / T o p s Y Y / N A Y Co m m e n t s : Co m p l i a n c e R e v i e w e d B y : Da t e : Mu d L o g s , I m a g e F i l e s , D i g i t a l D a t a Co m p o s i t e L o g s , I m a g e , D a t a F i l e s Cu t t i n g s S a m p l e s Y / N A Y Y / N A Di r e c t i o n a l / I n c l i n a t i o n D a t a Me c h a n i c a l I n t e g r i t y T e s t I n f o r m a t i o n Da i l y O p e r a t i o n s S u m m a r y Y Y / N A Y Co r e C h i p s Co r e P h o t o g r a p h s La b o r a t o r y A n a l y s e s Y / N A Y / N A Y / N A CO M P L I A N C E H I S T O R Y Da t e C o m m e n t s De s c r i p t i o n Co m p l e t i o n D a t e : 8 / 9 / 2 0 2 2 Re l e a s e D a t e : 10 / 2 0 / 2 0 2 1 DF 11 / 9 / 2 0 2 2 E l e c t r o n i c F i l e : I R U _ 2 4 1 - 0 1 _ G P T _ P l u g _ P e r f _ 1 4 - Au g - 2 0 2 2 _ ( 3 9 0 5 ) . p d f 37 2 4 4 ED Di g i t a l D a t a DF 11 / 9 / 2 0 2 2 E l e c t r o n i c F i l e : I R U _ 2 4 1 - 0 1 _ G P T _ P l u g _ P e r f _ 3 1 - Au g - 2 0 2 2 _ ( 3 9 4 3 ) . p d f 37 2 4 4 ED Di g i t a l D a t a DF 11 / 9 / 2 0 2 2 E l e c t r o n i c F i l e : I R U _ 2 4 1 - 0 1 _ P e r f _ 2 5 - A u g - 20 2 2 _ ( 3 9 2 9 ) . p d f 37 2 4 4 ED Di g i t a l D a t a DF 11 / 9 / 2 0 2 2 E l e c t r o n i c F i l e : I R U _ 2 4 1 - 0 1 _ P l u g _ G R _ 2 2 - A u g - 20 2 2 _ ( 3 9 2 4 ) . p d f 37 2 4 4 ED Di g i t a l D a t a 8/ 2 5 / 2 0 2 2 30 0 0 9 5 8 4 4 1 8 1 1 Cu t t i n g s Th u r s d a y , S e p t e m b e r 2 1 , 2 0 2 3 AO G C C P a g e 8 o f 8 M. G u h l 9/ 2 2 / 2 0 2 3 Kyle Wiseman Hilcorp Alaska, LLC Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: Kyle.Wiseman@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 11/8/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20221108 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# IRU 241-01 502832018400 221076 8/14/2022 AK E-Line GPT/Plug/Perf IRU 241-01 502832018400 221076 8/31/2022 AK E-Line GPT/Plug/Perf IRU 41-01 502832008800 192109 9/9/2022 AK E-Line GR/Perf IRU 241-01 502832018400 221076 8/25/2022 AK E-Line Perf IRU 241-01 502832018400 221076 8/22/2022 AK E-Line Plug/GR MPU S-34 500292317100 203130 9/4/2022 AK E-Line Cut Tubing NCI A-09A 508832002901 222024 8/20/2022 AK E-Line Perf NCI A-10B 508832003002 222025 8/23/2022 AK E-Line Perf Please include current contact information if different from above. T37244 T37244 T37245 T37244 T37244 T37246 T37247 T37248 IRU 241-01 502832018400 221076 8/14/2022 AK E-Line GPT/Plug/Perf IRU 241-01 502832018400 221076 8/31/2022 AK E-Line GPT/Plug/Perf IRU 241-01 502832018400 221076 8/25/2022 AK E-Line Perf IRU 241-01 502832018400 221076 8/22/2022 AK E-Line Plug/GR Kayla Junke Digitally signed by Kayla Junke Date: 2022.11.09 11:47:34 -09'00' 1 Regg, James B (OGC) From:Cole Bartlewski <cbartlewski@hilcorp.com> Sent:Friday, October 28, 2022 6:53 AM To:Brooks, Phoebe L (OGC) Cc:Regg, James B (OGC) Subject:RE: [EXTERNAL] RE: SLB CTU 13 BOPE test report for 8/20/22 on IRU 241-01 Phoebe & Jim, Sorry for the late response. The amount of emails these days seems like it has tripled. I have corrected my copy to show 12 seconds. Cole Bartlewski Hilcorp Alaska, LLC Sr. Wellsite Supervisor Email: cbartlewski@hilcorp.com Office 907-283-1301 Cell 907-690-2854 Hilcorp Alaska, LLC A Company built on Energy From: Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov> Sent: Monday, October 24, 2022 7:17 AM To: Cole Bartlewski <cbartlewski@hilcorp.com> Cc: Regg, James B (OGC) <jim.regg@alaska.gov> Subject: [EXTERNAL] RE: SLB CTU 13 BOPE test report for 8/20/22 on IRU 241‐01 Cole, Did you send a response on this one? Thanks, Phoebe Phoebe Brooks Research Analyst Alaska Oil and Gas Conservation Commission Phone: 907‐793‐1242 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 Phoebe Brooks at 907-793-1242 or phoebe.brooks@alaska.gov. From: Regg, James B (OGC) <jim.regg@alaska.gov> Sent: Tuesday, October 4, 2022 12:03 PM CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. Ivan River Unit 241-01 PTD 2210760 2 To: Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov>; Cole Bartlewski <cbartlewski@hilcorp.com> Subject: RE: SLB CTU 13 BOPE test report for 8/20/22 on IRU 241‐01 Should #2 Rams be 11 or 12 seconds (not 121 sec)? Jim Regg Supervisor, Inspections AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907‐793‐1236 From: Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov> Sent: Monday, August 29, 2022 1:37 PM To: Cole Bartlewski <cbartlewski@hilcorp.com> Cc: Regg, James B (OGC) <jim.regg@alaska.gov> Subject: RE: SLB CTU 13 BOPE test report for 8/20/22 on IRU 241‐01 Cole, I added “0” to the blank Control System Response Times. Please update your copy. Thank you, Phoebe Phoebe Brooks Research Analyst Alaska Oil and Gas Conservation Commission Phone: 907‐793‐1242 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 Phoebe Brooks at 907-793-1242 or phoebe.brooks@alaska.gov. From: Cole Bartlewski <cbartlewski@hilcorp.com> Sent: Thursday, August 25, 2022 9:57 AM To: Regg, James B (OGC) <jim.regg@alaska.gov>; Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov>; DOA AOGCC Prudhoe Bay <doa.aogcc.prudhoe.bay@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com>; Juanita Lovett <jlovett@hilcorp.com> Subject: SLB CTU 13 BOPE test report for 8/20/22 on IRU 241‐01 Good morning, BOPE test report attached for SLB CTU 13 on Ivan River Unit 241‐01. Respectfully, Cole Bartlewski CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. 3 Hilcorp Alaska, LLC Sr. Wellsite Supervisor Email: cbartlewski@hilcorp.com Office 907-283-1301 Cell 907-690-2854 Hilcorp Alaska, LLC A Company built on Energy The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION *All BOPE reports are due to the agency within 5 days of testing* Submit to:jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov Rig Owner:Rig No.:13 DATE:8/20/22 Rig Rep.:Rig Email: Operator: Operator Rep.:Op. Rep Email: Well Name:PTD #2210760 Sundry #321-601 Operation:Drilling:Workover:x Explor.: Test:Initial:x Weekly:Bi-Weekly:Other: Rams:250/3500 Annular:250/3500 Valves:250/3500 MASP:2839 MISC. INSPECTIONS:TEST DATA FLOOR SAFETY VALVES: Test Result/Type Test Result Quantity Test Result Housekeeping P Well Sign P Upper Kelly 0 NA Permit On Location P Hazard Sec.NA Lower Kelly 0 NA Standing Order Posted NA Misc.NA Ball Type 0 NA Test Fluid Water Inside BOP 0 NA FSV Misc 0 NA BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm Stripper 1 1.75 P Trip Tank NA NA Annular Preventer 0 N/A NA Pit Level Indicators NA NA #1 Rams 1 Blind Shear P Flow Indicator NA NA #2 Rams 1 Blind Shear P Meth Gas Detector NA NA #3 Rams 1 1.75"/Pipes P H2S Gas Detector NA NA #4 Rams 1 1.75" slips P MS Misc 0 NA #5 Rams 0 N/A NA #6 Rams 0 N/A NA ACCUMULATOR SYSTEM: Choke Ln. Valves 2 2" FMC FP Time/Pressure Test Result HCR Valves 0 N/A NA System Pressure (psi)2950 P Kill Line Valves 0 N/A NA Pressure After Closure (psi)2780 P Check Valve 1 2" Flapper P 200 psi Attained (sec)N/A NA BOP Misc 2 EQ ports P Full Pressure Attained (sec)N/A NA Blind Switch Covers:All stations Yes CHOKE MANIFOLD:Bottle Precharge:NA Quantity Test Result Nitgn. Bottles # & psi (Avg.):0 NA No. Valves 6 P ACC Misc 0 NA Manual Chokes 2 P Hydraulic Chokes 0 NA Control System Response Time:Time (sec)Test Result CH Misc 0 NA Annular Preventer 0 NA #1 Rams 11 P Coiled Tubing Only:#2 Rams 121 P Inside Reel valves 1 P #3 Rams 14 P #4 Rams 14 P Test Results #5 Rams 0 NA #6 Rams 0 NA Number of Failures:2 Test Time:3.5 HCR Choke 0 NA Repair or replacement of equipment will be made within days. HCR Kill 0 NA Remarks: AOGCC Inspection 24 hr Notice Yes Date/Time 8/17/22@1813 Waived By Test Start Date/Time:8/20/2022 14:30 (date)(time)Witness Test Finish Date/Time:8/20/2022 18:00 BOPE Test Report Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Jim Regg Schlumberger Choke line valves (2) or pump in sub valves failed. Greased, actuated valves, re test good. Donovan Thibeaux Hilcorp Alaska Cole Bartlewski IRU 241-01 Test Pressure (psi): Dthibeaux2@slb.com cbartlewski@hilcorp.com Form 10-424 (Revised 08/2022)2022-0820_SLB13_IRU_241-01          jbr====12  jbr J. Regg; 11/28/2022 From:Regg, James B (OGC) To:AOGCC Records (CED sponsored) Subject:BOP - SLB13 Date:Monday, November 28, 2022 12:07:55 PM Attachments:2022-0820_SLB13_IRU_241-01.pdf Ivan River Unit 241-01 (PTD 2210760) Jim Regg Supervisor, Inspections AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907-793-1236 David Dempsey Hilcorp Alaska, LLC Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.dempsey2@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 09/28/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20220928 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BCU 07A 501332028401 214060 7/12/2022 AK E-Line CIBP GPT BCU 18RD 501332058401 222033 7/13/2022 AK E-Line Perf BCU 18RD 501332058401 222033 7/16/2022 AK E-Line GPT Perf BCU 18RD 501332058401 222033 7/23/2022 AK E-Line GPT CIBP Perf BRU 212-24 502832003700 172015 6/27/2022 AK E-Line CBL BRU 212-24 502832003700 172015 7/5/2022 AK E-Line CIBP CBL TBG END 1-45 500292199100 189124 7/23/2022 AK E-Line Perf END 4-02 500292178900 188022 7/21/2022 AK E-Line Perf HVB B-16 502312004000 212133 6/23/2022 AK E-Line Drift, Plug, Cement IRU 241-01 502832018400 221076 8/5/2022 AK E-Line CBL IRU 241-01 502832018400 221076 8/9/2022 AK E-Line Perf Kalotsa 6 501332068500 219114 7/16/2022 AK E-Line Perf KTU 24-06H 501332049000 199073 7/15/2022 AK E-Line GPT Perf MPU S-34 500292317100 203130 7/5/2022 AK E-Line Drift PBU F-26C 500292198703 213045 8/4/2022 AK E-Line Patch/LDL SRU 213-15 501332065200 215100 8/3/2022 AK E-Line GPT Perf Please include current contact information if different from above. 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>ŝŶĞƌ,ĂŶŐĞƌ ϳϱͬϴ >ͲϴϬ tͬͲ,d ĂŬĞƌ ϯϮ͘ϳϳ ϱ͕ϴϰϰ͘ϭϵ ϱ͕ϴϭϭ͘ϰϮ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ll BOPE reports are due to the agency within 5 days of testing* SSu b m i t t o :jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov Owner/Contractor: Rig No.:13 DATE: 8/4/22 Rig Rep.: Rig Phone: 907-659-2434 Operator: Op. Phone:907-777-8300 Rep.: E-Mail Well Name: PTD #22210760 Sundry #321-601 Operation: Drilling: Workover: X Explor.: Test: Initial: X Weekly: Bi-Weekly: Other: Rams:250/3500 Annular: Valves:250/3500 MASP:2839 MISC. INSPECTIONS: TEST DATA FLOOR SAFETY VALVES: Test Result Test Result Quantity Test Result Location Gen.P Well Sign P Upper Kelly 0NA Housekeeping P Rig NA Lower Kelly 0NA PTD On Location P Hazard Sec.NA Ball Type 0NA Standing Order Posted NA Misc.NA Inside BOP 0NA FSV Misc 0NA BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm Stripper 1 1.75" top load P Trip Tank NA NA Annular Preventer 0 NA NA Pit Level Indicators NA NA #1 Rams 1 1.75 B/S P Flow Indicator NA NA #2 Rams 1 1.75 B/S P Meth Gas Detector NA NA #3 Rams 1 1.75 Slips P H2S Gas Detector NA NA #4 Rams 1 1.75 Pipes P MS Misc 0NA #5 Rams 0 NA NA #6 Rams 0 NA NA Quantity Test Result Choke Ln. Valves 1 2x2 FMC P Inside Reel valves 1P HCR Valves 0 NA NA Kill Line Valves 2 2x2 FMC P Check Valve 1 2" 1502 P ACCUMULATOR SYSTEM: BOP Misc 3 EQ PORTS P Time/Pressure Test Result System Pressure (psi)3000 P CHOKE MANIFOLD:Pressure After Closure (psi)1600 P Quantity Test Result 200 psi Attained (sec)13 P No. Valves 5P Full Pressure Attained (sec)60 P Manual Chokes 2P Blind Switch Covers: All stations Yes Hydraulic Chokes 0NA Nitgn. Bottles # & psi (Avg.): NA NA CH Misc 0NA ACC Misc 0NA Test Results Number of Failures:0 Test Time:3.5 Hours Repair or replacement of equipment will be made within NA days. Remarks: AOGCC Inspection 24 hr Notice Yes Date/Time 8/2/22 15:37 Waived By Test Start Date/Time:8/4/2022 17:00 (date) (time)Witness Test Finish Date/Time:8/4/2022 20:30 BOPE Test Report Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Jim Regg Schlumberger A push/pull test was conducted on the slip rams. Bryson Lowe Hilcorp Brad Gathman IRU 241-01 Test Pressure (psi): brad.gathman@hilcorp.com Form 10-424 (Revised 02/2022) 2022-0804_BOP_Schlumberger13_IRU_241-01 9 9 9 9 9 9 9 91$ 9 9 9 MEU -5HJJ +LOFRUS$ODVND//& Ilan r�r�r lLra.,r. LL! Date: 08/25/2022 David Douglas Hilcorp Alaska, LLC Sr. GeoTechnician 3800 CenterPoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.douglas@hilcorp.com To: Alaska Oil & Gas Conservation Commission Petroleum Geology Assistant 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMITTAL IRU 241-01 - PTD 221-076 - API 50-283-20184-00-00 a'� 1-oq(0 03�i RECEIVED AUG 2 5 2022 pAOGCC Washed and Dried Well Samples (TD: 07/21/2022) A Set (4 Boxes): WELL BOX SAMPLE INTERVAL (FEET / MD) IRU 241-01 BOX 1 OF 4 3000' - 4890' MD IRU 241-01 BOX 2 OF 4 4890' - 6690' MD IRU 241-01 BOX 3 OF 4 6690' — 8340' MD IRU 241-01 BOX 4 OF 4 8340' — 9584' MD (TD) Please include current contact information if different from above. Please acknowledge receipt by signing and returning one copy of this transmittal. Date: a � 1 12 From:McLellan, Bryan J (OGC) To:Jacob Flora Subject:RE: IRU 241-01 (Sundry 321-601) (PTD 221-076) (Request to clean out with coil) Date:Wednesday, August 17, 2022 3:17:00 PM Attachments:image002.png Jake, You have approval to perform the steps listed in your email below as part of Sundry 321-601. All conditions of the original sundry still apply. Regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, AK 99501 Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Jacob Flora <Jake.Flora@hilcorp.com> Sent: Wednesday, August 17, 2022 3:01 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: RE: IRU 241-01 (Sundry 321-601) (PTD 221-076) (Request to clean out with coil) Hi Bryan, We could be rigging back up on this well tomorrow afternoon. Below is the earlier request to put coil back on the well for a cleanout. Does this email suffice or do you need more detail on the operation than outline below? Greatly appreciated, Jake From: Jacob Flora Sent: Monday, August 15, 2022 11:48 AM To: bryan.mclellan@alaska.gov Subject: IRU 241-01 (Sundry 321-601) (PTD 221-076) (Request to clean out with coil) Hello Bryan, Hilcorp is requesting to put coil back on the well to clean out fill and fish e-line. The attached WBD is updated and reflects all perforating and plugging to date. When the top open perf set was shot it brought in ~700’ of fill and planted the e-line toolstring (spent gun). We dropped a Kinley cutter and recovered the cutter with 6400’ of e-line, leaving 690’ of e-line in the hole. Then a LIB was run and confirmed top of wire and fill at 6400’. Hilcorp requests approval for the following steps: 1. MIRU coil tubing, provide 48 hr BOP test notification, test BOPs to 3500 psi 2. Cleanout fill and fish wire as deep as possible 3. Set CIBP as deep as possible (we have to reach at least 6650’ to see all uphole pay zones) 4. Continue testing uphole Please let me know if you need anything further in your review, Thanks, Jake From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Sent: Friday, August 12, 2022 4:29 PM To: Jacob Flora <Jake.Flora@hilcorp.com>; Roby, David S (OGC) <dave.roby@alaska.gov> Cc: Matthew Petrowsky <mpetrowsky@hilcorp.com>; Christopher Stone <Christopher.Stone@hilcorp.com>; AOGCC Records (CED sponsored) <aogcc.records@alaska.gov> Subject: [EXTERNAL] 20220812 1628 PTD221-076, IRU241-076 Sundry 321-601 (Request to add more perfs in same pool, testing new well) Jacob, Approved to perf in the same pool. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-297-8474 Cell 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 Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). cc. Roby From: Jacob Flora <Jake.Flora@hilcorp.com> Sent: Friday, August 12, 2022 4:08 PM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Roby, David S (OGC) <dave.roby@alaska.gov> Cc: Matthew Petrowsky <mpetrowsky@hilcorp.com>; Christopher Stone <Christopher.Stone@hilcorp.com> Subject: Fwd: [EXTERNAL] PTD221-076, IRU241-076 Sundry 321-601 (Request to add more perfs in same pool, testing new well) Hello Mr. Rixse, We are still testing the new Ivan River well and request to add the below table to the approved perf range. We are setting a plug now at 8200’, above all open perfs (everything tested so far is wet), and would like to move uphole per the table. To note we are staying in the same pool and will not test anything higher until approvals are given to plug back the Beluga. Best Regards, Jake Flora Begin forwarded message: From: Matthew Petrowsky <mpetrowsky@hilcorp.com> Date: August 12, 2022 at 3:58:40 PM AKDT To: Jacob Flora <Jake.Flora@hilcorp.com> Subject: FW: [EXTERNAL] PTD221-076, IRU241-076 Sundry 321-601 TOC from CBL Sand Perforation Top Perforation Bottom Perforation Top Perforation Bottom Total Footage (MD)(MD)(TVD)(TVD)(MD) Beluga_D ±6,575’±6,598’±5,368’±5,386’23‘ Beluga_D1 ±6,638’±6,647’±5,418’±5,425’9‘ Beluga_D5u ±6,743’±6,753’±5,499’±5,507’10‘ Beluga_D5L ±6,758’±6,774’±5,511’±5,523’16‘ Beluga_E ±6,797’±6,804’±5,541’±5,546’7‘ Beluga_E1u ±6,845’±6,859’±5,578’±5,588’14‘ Beluga_E1L ±6,893’±6,900’±5,615’±5,620’7‘ Beluga_E2 ±6,921’±6,933’±5,636’±5,645’12‘ Beluga_E3 ±6,965’±6,973’±5,670’±5,676’8‘ Beluga_E5c ±7,152’±7,157’±5,815’±5,819’5‘ Beluga_E5d ±7,168’±7,184’±5,827’±5,839’16‘ Beluga_F1 ±7,251’±7,256’±5,892’±5,896’5‘ Beluga_F2u ±7,314’±7,322’±5,941’±5,947’8‘ Beluga_F2m ±7,326’±7,345’±5,950’±5,965’19‘ Beluga_F2L ±7,350’±7,356’±5,969’±5,973’6‘ BEL_F4 ±7,430’±7,442’±6,031’±6,041’12’ IRU_Cong ±7,476’±7,484’±6,068’±6,074’8’ BEL_G9 ±7,970’±7,978’±6,460’±6,466’8’ BEL_H1 ±8,133’±8,139’±6,588’±6,593’6’ Best Regards, Matthew J. Petrowsky |Geologist, Kenai Team|Hilcorp Alaska, LLC|(w) 907.777.8404|(c) 814.421.6753|Office: 13150| |3800 Centerpoint Dr. Suite 1400|Anchorage|Alaska|99503| From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Sent: Monday, August 8, 2022 12:26 To: Ryan Rupert <Ryan.Rupert@hilcorp.com> Cc: Jacob Flora <Jake.Flora@hilcorp.com>; Juanita Lovett <jlovett@hilcorp.com>; Matthew Petrowsky <mpetrowsky@hilcorp.com>; Brad Gathman - (C) <Brad.Gathman@hilcorp.com>; Christopher Stone <Christopher.Stone@hilcorp.com>; Roby, David S (OGC) <dave.roby@alaska.gov>; Boyer, David L (OGC) <david.boyer2@alaska.gov> Subject: RE: [EXTERNAL] PTD221-076, IRU241-076 Sundry 321-601 TOC from CBL Ryan, Approved to perforate intervals as described immediately below. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-297-8474 Cell 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 Mel Rixse at (907-793- 1231 ) or (Melvin.Rixse@alaska.gov). From: Ryan Rupert <Ryan.Rupert@hilcorp.com> Sent: Monday, August 8, 2022 11:28 AM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Jacob Flora <Jake.Flora@hilcorp.com>; Juanita Lovett <jlovett@hilcorp.com>; Matthew Petrowsky <mpetrowsky@hilcorp.com>; Brad Gathman - (C) <Brad.Gathman@hilcorp.com>; Christopher Stone <Christopher.Stone@hilcorp.com> Subject: FW: [EXTERNAL] PTD221-076, IRU241-076 Sundry 321-601 TOC from CBL Mel- For the immediate term, please see the below Beluga only perf intervals. After exhausting these, Hilcorp would come back to the agency for additional uphole approvals, plug / P&A needs, etc… For the immediate term Hilcorp is only asking for approval for the intervals below, which are all within the Beluga Sand Perforation Top Perforation Bottom Perforation Top Perforation Bottom Total Footage (MD)(MD)(TVD)(TVD)(MD) BEL_F4 ±7,430’±7,442’±6,031’±6,041’12’ IRU_Cong ±7,476’±7,484’±6,068’±6,074’8’ BEL_G9 ±7,970’±7,978’±6,460’±6,466’8’ BEL_H1 ±8,133’±8,139’±6,588’±6,593’6’ BEL_H4u ±8,233’±8,242’±6,667’±6,674’9’ BEL_H4m ±8,254’±8,263’±6,684’±6,691’9’ BEL_H4L ±8,289’±8,309’±6,712’±6,727’20’ BEL_H8 ±8,395’±8,415’±6,795’±6,811’20’ BEL_H15 ±8,698’±8,713’±7,033’±7,045’15’ BEL_I3 ±9,001’±9,006’±7,272’±7,277’5’ BEL_I5 ±9,103’±9,119’±7,351’±7,364’16’ BEL_I8 ±9,202’±9,215’±7,427’±7,438’13’ Ryan Rupert Kenai Ops Engineer (#13088) 907-301-1736 (Cell) 907-777-8503 (Office) From: Matthew Petrowsky <mpetrowsky@hilcorp.com> Sent: Monday, August 8, 2022 11:09 AM To: Christopher Stone <Christopher.Stone@hilcorp.com>; Ryan Rupert <Ryan.Rupert@hilcorp.com> Subject: FW: [EXTERNAL] PTD221-076, IRU241-076 Sundry 321-601 TOC from CBL Best Regards, Matthew J. Petrowsky |Geologist, Kenai Team|Hilcorp Alaska, LLC|(w) 907.777.8404|(c) 814.421.6753|Office: 13150| |3800 Centerpoint Dr. Suite 1400|Anchorage|Alaska|99503| From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Sent: Monday, August 8, 2022 10:29 To: Brad Gathman - (C) <Brad.Gathman@hilcorp.com> Cc: Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov>; Jacob Flora <Jake.Flora@hilcorp.com>; Matthew Petrowsky <mpetrowsky@hilcorp.com>; Boyer, David L (OGC) <david.boyer2@alaska.gov>; Roby, David S (OGC) <dave.roby@alaska.gov>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: [EXTERNAL] PTD221-076, IRU241-076 Sundry 321-601 TOC from CBL Brad, As I am not familiar with the confining zones , etc. for this well, I will require more information. Questions: 1. I see a proposed perf interval, but not a final. Has Hilcorp provided this to AOGCC? 2. On the approved 10-403 it states: “P&A plug to be set above Beluga per 20 AAC 25.112 prior to perforating Sterling” Are you just perforating the Beluga? I will probably have more questions once I know the above answers. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-297-8474 Cell 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 Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). cc. Victoria, David Boyer, David Roby From: Brad Gathman - (C) <Brad.Gathman@hilcorp.com> Sent: Monday, August 8, 2022 9:55 AM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov>; Jacob Flora <Jake.Flora@hilcorp.com>; Matthew Petrowsky <mpetrowsky@hilcorp.com> Subject: Re: [EXTERNAL] RE: IRU 241-01 CBL Mel, The log relates to approved sundry 321-601. Sorry about not including that on the email. Thanks, Brad Gathman WSM, Hilcorp AK +1 907-297-8412 On Aug 8, 2022, at 9:23 AM, Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> wrote: Brad, Does this log relate to any of the following approved sundries? If so, please identify. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. Some people who received this message don't often get email from brad.gathman@hilcorp.com. Learn why this is important Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-297-8474 Cell 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 Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). cc. Victoria From: Brad Gathman - (C) <Brad.Gathman@hilcorp.com> Sent: Monday, August 8, 2022 7:46 AM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov> Cc: Jacob Flora <Jake.Flora@hilcorp.com>; Matthew Petrowsky <mpetrowsky@hilcorp.com> Subject: FW: IRU 241-01 CBL Mel/Victoria, Would you be able to review the CBL since Bryan is out of the office. The plan is to start perforating today with your approval. Thanks, Brad Gathman 907-297-8412 From: Brad Gathman - (C) Sent: Monday, August 8, 2022 7:39 AM To: bryan.mclellan@alaska.gov Cc: Jacob Flora <Jake.Flora@hilcorp.com>; Matthew Petrowsky <mpetrowsky@hilcorp.com> Subject: IRU 241-01 CBL Bryan, Attached is the Cement Bond Log data from IRU 241-01. Perforating will begin today with your review & approval. Estimated TOC = 6040’ Thanks, Brad Gathman 907-297-8412 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you arenot an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. Ifyou have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use ofthis message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry outsuch virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intendedrecipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message andany attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intendedrecipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message andany attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by returnemail or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments willnot adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you havereceived this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments willnot adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. From:Rixse, Melvin G (OGC) To:Jacob Flora; Roby, David S (OGC) Cc:Matthew Petrowsky; Christopher Stone; AOGCC Records (CED sponsored) Subject:20220812 1628 PTD221-076, IRU241-076 Sundry 321-601 (Request to add more perfs in same pool, testing new well) Date:Friday, August 12, 2022 4:29:15 PM Attachments:image002.png Jacob, Approved to perf in the same pool. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-297-8474 Cell 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 Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). cc. Roby From: Jacob Flora <Jake.Flora@hilcorp.com> Sent: Friday, August 12, 2022 4:08 PM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Roby, David S (OGC) <dave.roby@alaska.gov> Cc: Matthew Petrowsky <mpetrowsky@hilcorp.com>; Christopher Stone <Christopher.Stone@hilcorp.com> Subject: Fwd: [EXTERNAL] PTD221-076, IRU241-076 Sundry 321-601 (Request to add more perfs in same pool, testing new well) Hello Mr. Rixse, We are still testing the new Ivan River well and request to add the below table to the approved perf range. We are setting a plug now at 8200’, above all open perfs (everything tested so far is wet), and would like to move uphole per the table. To note we are staying in the same pool and will not test anything higher until approvals are given to plug back the Beluga. Best Regards, Jake Flora Begin forwarded message: From: Matthew Petrowsky <mpetrowsky@hilcorp.com> Date: August 12, 2022 at 3:58:40 PM AKDT To: Jacob Flora <Jake.Flora@hilcorp.com> Subject: FW: [EXTERNAL] PTD221-076, IRU241-076 Sundry 321-601 TOC from CBL Sand Perforation Top Perforation Bottom Perforation Top Perforation Bottom Total Footage (MD)(MD)(TVD)(TVD)(MD) Beluga_D ±6,575’±6,598’±5,368’±5,386’23‘ Beluga_D1 ±6,638’±6,647’±5,418’±5,425’9‘ Beluga_D5u ±6,743’±6,753’±5,499’±5,507’10‘ Beluga_D5L ±6,758’±6,774’±5,511’±5,523’16‘ Beluga_E ±6,797’±6,804’±5,541’±5,546’7‘ Beluga_E1u ±6,845’±6,859’±5,578’±5,588’14‘ Beluga_E1L ±6,893’±6,900’±5,615’±5,620’7‘ Beluga_E2 ±6,921’±6,933’±5,636’±5,645’12‘ Beluga_E3 ±6,965’±6,973’±5,670’±5,676’8‘ Beluga_E5c ±7,152’±7,157’±5,815’±5,819’5‘ Beluga_E5d ±7,168’±7,184’±5,827’±5,839’16‘ Beluga_F1 ±7,251’±7,256’±5,892’±5,896’5‘ Beluga_F2u ±7,314’±7,322’±5,941’±5,947’8‘ Beluga_F2m ±7,326’±7,345’±5,950’±5,965’19‘ Beluga_F2L ±7,350’±7,356’±5,969’±5,973’6‘ BEL_F4 ±7,430’±7,442’±6,031’±6,041’12’ IRU_Cong ±7,476’±7,484’±6,068’±6,074’8’ BEL_G9 ±7,970’±7,978’±6,460’±6,466’8’ BEL_H1 ±8,133’±8,139’±6,588’±6,593’6’ Best Regards, Matthew J. Petrowsky |Geologist, Kenai Team|Hilcorp Alaska, LLC|(w) 907.777.8404|(c) 814.421.6753|Office: 13150| |3800 Centerpoint Dr. Suite 1400|Anchorage|Alaska|99503| From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Sent: Monday, August 8, 2022 12:26 To: Ryan Rupert <Ryan.Rupert@hilcorp.com> Cc: Jacob Flora <Jake.Flora@hilcorp.com>; Juanita Lovett <jlovett@hilcorp.com>; Matthew Petrowsky <mpetrowsky@hilcorp.com>; Brad Gathman - (C) <Brad.Gathman@hilcorp.com>; Christopher Stone <Christopher.Stone@hilcorp.com>; Roby, David S (OGC) <dave.roby@alaska.gov>; Boyer, David L (OGC) <david.boyer2@alaska.gov> Subject: RE: [EXTERNAL] PTD221-076, IRU241-076 Sundry 321-601 TOC from CBL Ryan, Approved to perforate intervals as described immediately below. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-297-8474 Cell 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 Mel Rixse at (907-793- 1231 ) or (Melvin.Rixse@alaska.gov). From: Ryan Rupert <Ryan.Rupert@hilcorp.com> Sent: Monday, August 8, 2022 11:28 AM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Jacob Flora <Jake.Flora@hilcorp.com>; Juanita Lovett <jlovett@hilcorp.com>; Matthew Petrowsky <mpetrowsky@hilcorp.com>; Brad Gathman - (C) <Brad.Gathman@hilcorp.com>; Christopher Stone <Christopher.Stone@hilcorp.com> Subject: FW: [EXTERNAL] PTD221-076, IRU241-076 Sundry 321-601 TOC from CBL Mel- For the immediate term, please see the below Beluga only perf intervals. After exhausting these, Hilcorp would come back to the agency for additional uphole approvals, plug / P&A needs, etc… For the immediate term Hilcorp is only asking for approval for the intervals below, which are all within the Beluga Sand Perforation Top Perforation Bottom Perforation Top Perforation Bottom Total Footage (MD)(MD)(TVD)(TVD)(MD) BEL_F4 ±7,430’±7,442’±6,031’±6,041’12’ IRU_Cong ±7,476’±7,484’±6,068’±6,074’8’ BEL_G9 ±7,970’±7,978’±6,460’±6,466’8’ BEL_H1 ±8,133’±8,139’±6,588’±6,593’6’ BEL_H4u ±8,233’±8,242’±6,667’±6,674’9’ BEL_H4m ±8,254’±8,263’±6,684’±6,691’9’ BEL_H4L ±8,289’±8,309’±6,712’±6,727’20’ BEL_H8 ±8,395’±8,415’±6,795’±6,811’20’ BEL_H15 ±8,698’±8,713’±7,033’±7,045’15’ BEL_I3 ±9,001’±9,006’±7,272’±7,277’5’ BEL_I5 ±9,103’±9,119’±7,351’±7,364’16’ BEL_I8 ±9,202’±9,215’±7,427’±7,438’13’ Ryan Rupert Kenai Ops Engineer (#13088) 907-301-1736 (Cell) 907-777-8503 (Office) From: Matthew Petrowsky <mpetrowsky@hilcorp.com> Sent: Monday, August 8, 2022 11:09 AM To: Christopher Stone <Christopher.Stone@hilcorp.com>; Ryan Rupert <Ryan.Rupert@hilcorp.com> Subject: FW: [EXTERNAL] PTD221-076, IRU241-076 Sundry 321-601 TOC from CBL Best Regards, Matthew J. Petrowsky |Geologist, Kenai Team|Hilcorp Alaska, LLC|(w) 907.777.8404|(c) 814.421.6753|Office: 13150| |3800 Centerpoint Dr. Suite 1400|Anchorage|Alaska|99503| From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Sent: Monday, August 8, 2022 10:29 To: Brad Gathman - (C) <Brad.Gathman@hilcorp.com> Cc: Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov>; Jacob Flora <Jake.Flora@hilcorp.com>; Matthew Petrowsky <mpetrowsky@hilcorp.com>; Boyer, David L (OGC) <david.boyer2@alaska.gov>; Roby, David S (OGC) <dave.roby@alaska.gov>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: [EXTERNAL] PTD221-076, IRU241-076 Sundry 321-601 TOC from CBL Brad, As I am not familiar with the confining zones , etc. for this well, I will require more information. Questions: 1. I see a proposed perf interval, but not a final. Has Hilcorp provided this to AOGCC? 2. On the approved 10-403 it states: “P&A plug to be set above Beluga per 20 AAC 25.112 prior to perforating Sterling” Are you just perforating the Beluga? I will probably have more questions once I know the above answers. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-297-8474 Cell 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 Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). cc. Victoria, David Boyer, David Roby From: Brad Gathman - (C) <Brad.Gathman@hilcorp.com> Sent: Monday, August 8, 2022 9:55 AM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov>; Jacob Flora <Jake.Flora@hilcorp.com>; Matthew Petrowsky <mpetrowsky@hilcorp.com> Subject: Re: [EXTERNAL] RE: IRU 241-01 CBL Mel, The log relates to approved sundry 321-601. Sorry about not including that on the email. Thanks, Brad Gathman CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. Some people who received this message don't often get email from brad.gathman@hilcorp.com. Learn why this is important WSM, Hilcorp AK +1 907-297-8412 On Aug 8, 2022, at 9:23 AM, Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> wrote: Brad, Does this log relate to any of the following approved sundries? If so, please identify. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-297-8474 Cell 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 Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). cc. Victoria From: Brad Gathman - (C) <Brad.Gathman@hilcorp.com> Sent: Monday, August 8, 2022 7:46 AM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov> Cc: Jacob Flora <Jake.Flora@hilcorp.com>; Matthew Petrowsky <mpetrowsky@hilcorp.com> Subject: FW: IRU 241-01 CBL Mel/Victoria, Would you be able to review the CBL since Bryan is out of the office. The plan is to start perforating today with your approval. Thanks, Brad Gathman 907-297-8412 From: Brad Gathman - (C) Sent: Monday, August 8, 2022 7:39 AM To: bryan.mclellan@alaska.gov Cc: Jacob Flora <Jake.Flora@hilcorp.com>; Matthew Petrowsky <mpetrowsky@hilcorp.com> Subject: IRU 241-01 CBL Bryan, Attached is the Cement Bond Log data from IRU 241-01. Perforating will begin today with your review & approval. Estimated TOC = 6040’ Thanks, Brad Gathman 907-297-8412 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you arenot an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. Ifyou have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use ofthis message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry outsuch virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intendedrecipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email inerror, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message andany attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as itconsiders appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intendedrecipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message andany attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as itconsiders appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by returnemail or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments willnot adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. David Douglas Hilcorp Alaska, 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: Date: 08/03/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL WELL: IRU 241-01 (PTD 221-076) PTD: 221-076 API: 50-283-20184-00-00 MUDLOGS - EOW DRILLING REPORTS (07/06/2022 to 07/21/2021) *** PRODUCTION HOLE *** 1. FINAL EOW REPORT 2. DAILY REPORTS 3. SHOW REPORTS 4. DIGITAL DATA (LAS) 5. MUDLOG PRINTS (2” and 5” MD and TVD COLOR PRINTS – TIFF AND PDF FORMATS) Formation Log LWD Combo Log Gas Ratio Log Drilling Dynamics Log SFTP Transfer - Main Folder Contents: Please include current contact information if different from above. PTD:221-076 T36848 Kayla Junke Digitally signed by Kayla Junke Date: 2022.08.04 09:10:30 -08'00' David Douglas Hilcorp Alaska, 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: Date: 07/29/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL WELL: IRU 241-01 (PTD 221-076) PTD: 221-076 API: 50-283-20184-00-00 *** SURFACE HOLE (2021) and PRODUCTION HOLE (2022) COMPOSITED *** FINAL LWD FORMATION EVALUATION LOGS (11/23/2021 to 07/21/2022) x PCG, AGR, DGR, EWR-Phase 4, EWR-M5, ADR, ALD, CTN (2” & 5” MD/TVD Color Logs) x Final Definitive Directional Survey SFTP Transfer - Data Folders: Please include current contact information if different from above. PTD:221-076 T36839 Kayla Junke Digitally signed by Kayla Junke Date: 2022.07.29 14:51:04 -08'00' 1 Regg, James B (OGC) From:Rance Pederson - (C) <rpederson@hilcorp.com> Sent:Thursday, July 28, 2022 4:03 PM To:Regg, James B (OGC); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (OGC); Wallace, Chris D (OGC) Subject:Rig 147 MIT Test Report Attachments:MIT Hilcorp 147 07-28-22.xlsx; IRU 241-01 MIT-T-IA Test Chart_7-28-22.pdf Please see the attached test report and chart for MIT T and MIT IA on IRU 241 01 Rance Pederson Drilling Foreman Ivan River Unit 907 776 6776 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. Submit to: OPERATOR: FIELD /UNIT /PAD: DATE: OPERATOR REP: AOGCC REP: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2210760 Type Inj N Tubing 0 3590 3575 3575 Type Test P Packer TVD 4789 BBL Pump 1.6 IA 0 330 330 328 Interval I Test psi 3500 BBL Return 1.6 OA Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2210760 Type Inj N Tubing 0 376 376 376 Type Test P Packer TVD 4789 BBL Pump 1.7 IA 0 2500 2500 2498 Interval I Test psi 2500 BBL Return 1.7 OA Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W = Water P = Pressure Test I = Initial Test P = Pass G = Gas O = Other (describe in Notes) 4 = Four Year Cycle F = Fail S = Slurry V = Required by Variance I = Inconclusive I = Industrial Wastewater O = Other (describe in notes) N = Not Injecting Notes:4 1/2" tieback string and liner. ZXP Liner Top Packer at 4789' tvd. Witness waived by Jim Regg on 7-27-22 at 08:27 IRU 241-01 IRU 241-01 Hilcorp Alaska, LLC Beluga River Field / Ivan River Unit / Ivan River Pad Witness Waived Rance Pederson 07/28/22 Notes:7 5/8" x 4 1/2" annulus. ZXP Liner Top Packer at 4789' tvd. Witness waived by Jim Regg on 7-27-22 at 08:27 Notes: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Int egr ity Test jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov Form 10-426 (Revised 01/2017)2022-0728_MITP_IRU_241-01_2tests 4 1/2" tieback string and liner. 7 5/8" x 4 1/2" annulus. 5HJJ-DPHV%2*& )URP%URRNV3KRHEH/2*& 6HQW7XHVGD\-XO\30 7R5HJJ-DPHV%2*& 6XEMHFW):5LJ%237HVW $WWDFKPHQWV+LOFRUS[OV[ WŚŽĞďĞƌŽŽŬƐ ZĞƐĞĂƌĐŚŶĂůǇƐƚ ůĂƐŬĂKŝůĂŶĚ'ĂƐŽŶƐĞƌǀĂƚŝŽŶŽŵŵŝƐƐŝŽŶ WŚŽŶĞ͗ϵϬϳͲϳϵϯͲϭϮϰϮ 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 Phoebe Brooks at 907-793-1242 or phoebe.brooks@alaska.gov. &ƌŽŵ͗ZĂŶĐĞWĞĚĞƌƐŽŶͲ;ͿфƌƉĞĚĞƌƐŽŶΛŚŝůĐŽƌƉ͘ĐŽŵх ^ĞŶƚ͗dƵĞƐĚĂǇ͕:ƵůǇϮϲ͕ϮϬϮϮϯ͗ϱϰWD dŽ͗ƌŽŽŬƐ͕WŚŽĞďĞ>;K'ͿфƉŚŽĞďĞ͘ďƌŽŽŬƐΛĂůĂƐŬĂ͘ŐŽǀх ^ƵďũĞĐƚ͗ZŝŐϭϰϳKWdĞƐƚϬϳͲϭϰͲϮϮ WŚŽĞďĞ͕:ĞƐƐĂƐŬĞĚŵĞƚŽĂĚĚƚŚĞďŽƚƚůĞĐŽƵŶƚĂŶĚƌĞͲƐĞŶĚǇŽƵƚŚĞƚĞƐƚĨŽƌŵ͊ ZĂŶĐĞWĞĚĞƌƐŽŶ ƌŝůůŝŶŐ&ŽƌĞŵĂŶ /ǀĂŶZŝǀĞƌhŶŝƚ ϵϬϳͲϳϳϲͲϲϳϳϲ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ll BOPE reports are due to the agency within 5 days of testing* SSu b m i t t o :jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov Owner/Contractor: Rig No.:147 DATE: 7/14/22 Rig Rep.: Rig Phone: 907-283-1386 Operator: Op. Phone:907-776-6776 Rep.: E-Mail Well Name: PTD #22210760 Sundry # Operation: Drilling: x Workover: Explor.: Test: Initial: Weekly: Bi-Weekly: x Other: Rams:250/3500 Annular:250/2500 Valves:250/3500 MASP:2839 MISC. INSPECTIONS: TEST DATA FLOOR SAFETY VALVES: Test Result Test Result Quantity Test Result Location Gen.P Well Sign P Upper Kelly 1P Housekeeping P Rig P Lower Kelly 1P PTD On Location P Hazard Sec.P Ball Type 1P Standing Order Posted P Misc.NA Inside BOP 1P FSV Misc 0NA BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm Stripper 0NATrip Tank PP Annular Preventer 1 11"P Pit Level Indicators PP #1 Rams 1 2 7/8" x 5"P Flow Indicator PP #2 Rams 1 Blind P Meth Gas Detector PP #3 Rams 1 4.5"P H2S Gas Detector PP #4 Rams 0NAMS Misc 0NA #5 Rams 0NA #6 Rams 0NA Quantity Test Result Choke Ln. Valves 1 3 1/8"P Inside Reel valves 0NA HCR Valves 2 2 1/16" & 3 1/8"P Kill Line Valves 3 2 1/16"P Check Valve 0NAACCUMULATOR SYSTEM: BOP Misc 0 NA Time/Pressure Test Result System Pressure (psi)3000 P CHOKE MANIFOLD:Pressure After Closure (psi)1750 P Quantity Test Result 200 psi Attained (sec)28 P No. Valves 13 P Full Pressure Attained (sec)98 P Manual Chokes 1P Blind Switch Covers: All stations Yes Hydraulic Chokes 1P Nitgn. Bottles # & psi (Avg.): 4 @ 2550 P CH Misc 0NA ACC Misc 0NA Test Results Number of Failures:0 Test Time:5.0 Hours Repair or replacement of equipment will be made within days. Remarks: AOGCC Inspection 24 hr Notice Yes Date/Time 7-10-22 18:30 Waived By Test Start Date/Time:7/14/2022 2:30 (date) (time)Witness Test Finish Date/Time:7/14/2022 5:30 BOPE Test Report Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Jim Regg Hilcorp Tested with 4.5" test joint at 250 psi low 3500 psi high for 5 minutes each test. Tested annular with 4.5" test joint at 250 psi low 2500 psi high for 5 minutes. Quadco Rep tested audio and visual gas alarms with no issues. Jon Van-Evera Hilcorp Alaska, LLC Jess Richardson IRU 241-01 Test Pressure (psi): jesrichardson@hilcorp.com Form 10-424 (Revised 02/2022) 2022-0714_BOP_Hilcorp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y Samantha Carlisle at 10:39 am, Jun 15, 2022 'LJLWDOO\VLJQHGE\0RQW\00\HUV '1FQ 0RQW\00\HUVF 86 R +LOFRUS$ODVND//&RX 7HFKQLFDO 6HUYLFHV$.'ULOOLQJ HPDLO PP\HUV#KLOFRUSFRP 5HDVRQ,DPDSSURYLQJWKLVGRFXPHQW 'DWH 0RQW\0 0\HUV $'/ '/% '/%0*5-81 ; '65 %23(WHVWSVL$QQXODUWRSVL GWV -/& Jeremy Price Digitally signed by Jeremy Price Date: 2022.06.28 12:55:23 -08'00' RBDMS JSB 063022 STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report for: Reviewed By: P.I. Suprv Comm ________IVAN RIVER UNIT 241-01 JBR 07/21/2022 MISC. INSPECTIONS: FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK: ACCUMULATOR SYSTEM:MUD SYSTEM: P/F P/F P/FP/FP/F Visual Alarm QuantityQuantity Time/Pressure SizeQuantity Number of Failures:2 4-1/2" joint. HCR Kill FP-greased/cycled for pass. LPR FP-bumped up for a pass. Sundry is to "resume drilling operations". Annular 20 secs; Rams 4 secs; HCRs 2 secs. Test Results TEST DATA Rig Rep:Ken PorterfieldOperator:Hilcorp Alaska, LLC Operator Rep:Rance Pederson Contractor/Rig No.:Hilcorp 147 PTD#:2210760 DATE:7/4/2022 Type Operation:DRILL Annular: 250/3500Type Test:INIT Valves: 250/3500 Rams: 250/3500 Test Pressures:Inspection No:bopSAM220706161331 Inspector Austin McLeod Inspector Insp Source Related Insp No: INSIDE REEL VALVES: Quantity P/F (Valid for Coil Rigs Only) Remarks: Test Time 6.5 MASP: 2839 Sundry No: 322-360 Location Gen.:P Housekeeping:P PTD On Location P Standing Order Posted P Well Sign P Drl. Rig P Hazard Sec.P Misc NA Upper Kelly 1 P Lower Kelly 1 P Ball Type 1 P Inside BOP 1 P FSV Misc 0 NA 13 PNo. Valves 1 PManual Chokes 1 PHydraulic Chokes 0 NACH Misc Stripper 0 NA Annular Preventer 1 11"P #1 Rams 1 4.5"P #2 Rams 1 Blinds P #3 Rams 1 4.5"FP #4 Rams 0 NA #5 Rams 0 NA #6 Rams 0 NA Choke Ln. Valves 1 3-1/8"P HCR Valves 2 2-1/16"/3-1/8 FP Kill Line Valves 3 2-1/16"P Check Valve 0 NA BOP Misc 0 NA System Pressure P3000 Pressure After Closure P1750 200 PSI Attained P27 Full Pressure Attained P118 Blind Switch Covers:PAll stations Nitgn. Bottles (avg):P4@2525 ACC Misc NA0 P PTrip Tank P PPit Level Indicators P PFlow Indicator P PMeth Gas Detector P PH2S Gas Detector NA NAMS Misc Inside Reel Valves 0 NA        tĞůů͗/ZhϮϰϭͲϬϭ ZĞƐƵŵƉƚŝŽŶŽĨKƉĞƌĂƚŝŽŶƐ tĞůůEĂŵĞ͗/ZhϮϰϭͲϬϭ W/EƵŵďĞƌ͗ϱϬͲϮϴϯͲϮϬϭϴϰͲϬϬͲϬϬ ƵƌƌĞŶƚ^ƚĂƚƵƐ͗KƉĞƌĂƚŝŽŶƐ^ŚƵƚĚŽǁŶ>ĞŐ͗Eͬ ƐƚŝŵĂƚĞĚ^ƚĂƌƚĂƚĞ͗ϬϳͬϬϭͬϮϮZŝŐ͗ZŝŐϭϰϳ ZĞŐ͘ƉƉƌŽǀĂůZĞƋ͛Ě͍ϰϬϯĂƚĞZĞŐ͘ƉƉƌŽǀĂůZĞĐ͛ǀĚ͗ ZĞŐƵůĂƚŽƌǇŽŶƚĂĐƚ͗ŽĚǇŝŶŐĞƌ;ϴϯϴϵͿWĞƌŵŝƚƚŽƌŝůůEƵŵďĞƌ͗ϮϮϭͲϬϳϲ &ŝƌƐƚĂůůŶŐŝŶĞĞƌ͗&ƌĂŶŬZŽĂĐŚ;ϵϬϳͿϳϳϳͲϴϰϭϯ;KͿ;ϵϬϳͿϱϴϰͲϮϯϮϭ;DͿ ^ĞĐŽŶĚĂůůŶŐŝŶĞĞƌ͗^ĞĂŶDĐůĂƵŐŚůŝŶ;ϵϬϳͿϮϮϯͲϲϳϴϰ;DͿ;ϵϬϳͿϮϮϯͲϲϳϴϰ;DͿ ƌŝĞĨtĞůů^ƵŵŵĂƌǇ ůĂƐŬĂĞƉĂƌƚŵĞŶƚŽĨ&ŝƐŚΘ'ĂŵĞ;&Θ'ͿŚĂƐŐƌĂŶƚĞĚ,ŝůĐŽƌƉĂǁŝŶĚŽǁĨƌŽŵ:ƵůǇϭ͕ƚŽƵŐƵƐƚϭϱ͕ƚŽ ĚƌŝůůĂŶĚĐŽŵƉůĞƚĞ/ZhϮϰϭͲϬϭ dŚĞƉůĂŶĨŽƌǁĂƌĚĨŽƌ/ZhϮϰϭͲϬϭŝƐƚŽƌĞƐƵŵĞĚƌŝůůŝŶŐŽƉĞƌĂƚŝŽŶƐĨƌŽŵƐĞĐƚŝŽŶϭϰŽĨƚŚĞŽƌŝŐŝŶĂůůǇ ĂƉƉƌŽǀĞĚĚƌŝůůŝŶŐƉĞƌŵŝƚ͘ ƵƌƌĞŶƚǁĞůůĐŽŶĚŝƚŝŽŶŝƐĂƐĨŽůůŽǁƐ͗ xϭϬͲϯͬϰ͟ϰϱ͘ϱη>ͲϴϬƐƵƌĨĂĐĞĐĂƐŝŶŐƚŽϯ͕ϬϬϱ͛ĂŶĚĨƵůůǇĐĞŵĞŶƚĞĚŝŶƉůĂĐĞ;ĐĞŵĞŶƚƚŽƐƵƌĨĂĐĞ ďĞĨŽƌĞƉůƵŐďƵŵƉͿ xƌǇŚŽůĞƚƌĞĞŝŶƐƚĂůůĞĚ 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RQZDUGWUDQVPLVVLRQRSHQLQJRUXVHRIWKLVPHVVDJHDQGDQ\DWWDFKPHQWVZLOOQRWDGYHUVHO\DIIHFWLWVV\VWHPVRUGDWD1RUHVSRQVLELOLW\ LVDFFHSWHGE\WKHFRPSDQ\LQWKLVUHJDUGDQGWKHUHFLSLHQWVKRXOGFDUU\RXWVXFKYLUXVDQGRWKHUFKHFNVDVLWFRQVLGHUVDSSURSULDWH 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: Ivan River Field, Undefined Gas Pool, IRU 241-01 Hilcorp Alaska, LLC Permit to Drill Number: 221-076 Surface Location: 596' FSL, 581' FEL, Sec 1, T13N, R9W, SM, AK Bottomhole Location: 32' FNL, 404' FEL, Sec 1, T13N, R9W, SM, AK Dear Mr. Myers: Enclosed is the approved application for the permit to drill the above referenced 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 October, 2021. Jeremy Price Digitally signed by Jeremy Price Date: 2021.10.20 11:14:26 -08'00' 1a. Type of Work:1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp 1c. Specify if well is proposed for: Drill Lateral Stratigraphic Test Development - Oil Service - Winj Single Zone Coalbed Gas Gas Hydrates Redrill Reentry Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal Shale Gas 2. Operator Name:5. Bond: Blanket Single Well 11. Well Name and Number: Bond No. 3. Address:6. Proposed Depth: 12. Field/Pool(s): MD: 9,554' TVD: 7,720' 4a. Location of Well (Governmental Section):7. Property Designation: Surface: Top of Productive Horizon:8. DNR Approval Number: 13. Approximate Spud Date: Total Depth: 9. Acres in Property: 14. Distance to Nearest Property: 4b. Location of Well (State Base Plane Coordinates - NAD 27):10. KB Elevation above MSL (ft): 48.7 15. Distance to Nearest Well Open Surface: x-359830 y- 2646285 Zone-4 30.2 to Same Pool: 109' to IRU 13-31 16. Deviated wells:Kickoff depth: 200 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 38.9 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD Cond 16" 84# X-56 Weld 120' Surface Surface 120' 120' 13-1/2" 10-3/4" 45.5# L-80 DWC/C 3,000' Surface Surface 3,000' 2,575' 9-7/8" 7-5/8" 29.7# L-80 DWC/C HT 5,981 Surface Surface 5,981' 4,900' 6-3/4" 4-1/2" 12.6# L-80 DWC/C HT 3,773' 5,781' 4,742' 9,554' 7,720' 19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Junk (measured): TVD Hydraulic Fracture planned?Yes No 20. Attachments:Property Plat BOP Sketch Drilling Program Time v. Depth Plot Shallow Hazard Analysis Diverter Sketch Seabed Report Drilling Fluid Program 20 AAC 25.050 requirements Contact Name: Contact Email: Contact Phone: Date: Permit to Drill API Number: Permit Approval Number:Date: 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 Mud log req'd: Yes No H2S measures: Yes No Directional svy req'd: Yes No Spacing exception req'd: Yes No Inclination-only svy req'd: Yes No Post initial injection MIT req'd: Yes No APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng 11/1/2021 2197' to nearest unit boundary Frank Roach frank.roach@hilcorp.com 907-777-7413 L - 653 ft3 / T - 104 ft3 Drilling Manager Monty Myers 21. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Surface Perforation Depth TVD (ft):Perforation Depth MD (ft): Production Liner Intermediate Conductor/Structural Authorized Title: Authorized Signature: Authorized Name: LengthCasing Cement Volume MDSize Plugs (measured): (including stage data) Driven L - 1803 ft3 / T - 407 ft3 Effect. Depth MD (ft):Effect. Depth TVD (ft): 2172 18. Casing Program:Top - Setting Depth - BottomSpecifications 3611 GL / BF Elevation above MSL (ft): Total Depth MD (ft):Total Depth TVD (ft): 022224484 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 L - 857 ft3 / T - 171 ft3 2839 1689' FNL, 1763' FEL, Sec 1, T13N, R9W, SM, AK 32' FNL, 404' FEL, Sec 1, T13N, R9W, SM, AK LOCI 08-07 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Hilcorp Alaska, LLC 596' FSL, 581' FEL, Sec 1, T13N, R9W, SM, AK ADL32930 IRU 241-01 Ivan River Unit Undefined Gas Pool Cement Quantity, c.f. or sacks Commission Use Only See cover letter for other requirements. es N ype of W L l R L 1b S Class: os N es No s N o D s s sD 84 o : well is p G S S 20 S S S es No s No S G E S es No s Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g) 9.24.2021 By Samantha Carlisle at 3:26 pm, Sep 24, 2021 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: 2021.09.24 15:20:29 -08'00' Monty M Myers MITIA to 3000 psi after installing 4-1/2" tbg tieback. Provide 48 hrs notice for AOGCC witness of MIT-T and MIT-IA. 221-076 DSR-9/27/21 BOP test to 3500 psi, annular test to 2500 psi Send FIT/LOT data to AOGCC within 2 days of performing tests. BJM 10/14/21 SFD 9/30/2021 50-283-20184-00-00 dts 10/20/2021 JLC 10/20/2021 10/20/21 Jeremy Price Digitally signed by Jeremy Price Date: 2021.10.20 11:17:26 -08'00' IRU 241-01 Drilling Program Rev 0 September 5, 2021 Contents 1.0 Well Summary...........................................................................................................................2 2.0 Management of Change Information........................................................................................3 3.0 Tubular Program:......................................................................................................................4 4.0 Drill Pipe Information:..............................................................................................................4 5.0 Internal Reporting Requirements.............................................................................................5 6.0 Planned Wellbore Schematic.....................................................................................................6 7.0 Drilling / Completion Summary................................................................................................7 8.0 Mandatory Regulatory Compliance / Notifications..................................................................9 9.0 R/U and Preparatory Work.....................................................................................................11 10.0 N/U 21-1/4” Diverter ................................................................................................................12 11.0 Drill 13-1/2” Hole Section ........................................................................................................14 12.0 Run 10-3/4” Surface Casing ....................................................................................................16 13.0 Cement 10-3/4” Surface Casing ...............................................................................................19 14.0 BOP N/U and Test....................................................................................................................22 15.0 Drill 9-7/8” Hole Section ..........................................................................................................23 16.0 Run 7-5/8” Production Casing.................................................................................................26 17.0 Cement 7-5/8” Production Casing ...........................................................................................29 18.0 Drill 6-3/4” Hole Section ..........................................................................................................33 19.0 Run 4-1/2” Production Liner ...................................................................................................36 20.0 Cement 4-1/2” Production Liner .............................................................................................39 21.0 4-1/2” Liner Tieback Polish Run and Cleanout Run..............................................................43 22.0 4-1/2” Tieback Run ..................................................................................................................44 23.0 RDMO......................................................................................................................................44 24.0 Diverter Schematic ..................................................................................................................45 25.0 BOP Schematic ........................................................................................................................46 26.0 Wellhead Schematic.................................................................................................................47 27.0 Days Vs Depth..........................................................................................................................48 28.0 Geo-Prog..................................................................................................................................49 29.0 Anticipated Drilling Hazards ..................................................................................................50 30.0 Hilcorp Rig 147 Layout ...........................................................................................................53 31.0 FIT/LOT Procedure.................................................................................................................54 32.0 Choke Manifold Schematic......................................................................................................55 33.0 Casing Design Information......................................................................................................56 34.0 9-7/8” Hole Section MASP.......................................................................................................57 Page 2 Version 0 September, 2021 IRU 241-01 Drilling Procedure Rev 0 35.0 6-3/4” Hole Section MASP .......................................................................................................58 36.0 Spider Plot (Governmental Sections)......................................................................................59 37.0 Surface Plat (As-Staked NAD27).............................................................................................60 1.0 Well Summary Well IRU 241-01 Pad & Old Well Designation Ivan River Pad / grass roots well Planned Completion Type 4-1/2”Production tubing Target Reservoir(s)Sterling/Beluga/Tyonek Gas Sands Planned Well TD, MD / TVD 9,554’MD / 7,720’ TVD PBTD, MD / TVD 9,474’ MD / 7,657’TVD Surface Location (Governmental)596’ FSL, 581’ FEL, Sec 1, T13N, R9W, SM, AK Surface Location (NAD 27)X=359830.90 Y=2646285.80 Top of Productive Horizon (Governmental)1689' FNL, 1763' FEL, Sec 1, T13N, R9W, SM, AK TPH Location (NAD 27)X=358686.34, Y=2649294.24 BHL (Governmental)32' FNL, 404' FEL, Sec 1, T13N, R9W, SM, AK BHL (NAD 27)X=360065.82, Y=2650934.82 AFE Number AFE Drilling Days 4 MOB, 32 DRLG AFE Completion Days AFE Drilling Amount AFE Completion Amount Maximum Anticipated Pressure (Surface)2839 psi Maximum Anticipated Pressure (Downhole/Reservoir)3611 psi Work String 4-1/2” 16.6# S-135 CDS-40 RKB –GL 48.7’(30.2 + 18.5) Ground Elevation 30.2’ BOP Equipment 11” 5M Annular BOP 11” 5M Double Ram 11” 5M Single Ram Page 3 Version 0 September, 2021 IRU 241-01 Drilling Procedure Rev 0 2.0 Management of Change Information Page 4 Version 0 September, 2021 IRU 241-01 Drilling Procedure Rev 0 3.0 Tubular Program: Hole Section OD (in)ID (in)Drift (in) Conn OD (in) Wt (#/ft) Grade Conn Burst (psi) Collapse (psi) Tension (k-lbs) Cond 16”15.01”14.822”-84 X-56 Weld 2980 1410 - 13-1/2”10-3/4”9.950”9.875”11.750”45.5 L-80 DWC/C 5210 2470 1040 9-7/8”7-5/8”6.875”6.750”8.500”29.7 L-80 USS-CDC 6880 4790 683 6-3/4”4-1/2”3.958”3.833”5.000”12.6 L-80 DWC/C-HT 8430 7500 288 4.0 Drill Pipe Information: Hole Section OD (in) ID (in)TJ ID (in) TJ OD (in) Wt (#/ft) Grade Conn Burst (psi) Collapse (psi) Tension (k-lbs) All 4-1/2”3.826 2.6875”5.25”16.6 S-135 CDS40 17,693 16,769 468k Cleanout 2-7/8”2.323 2.265”3.438”7.9 P-110 PH-6 16,896 16,082 194k All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery to TSA in Fairbanks). Page 5 Version 0 September, 2021 IRU 241-01 Drilling Procedure Rev 0 5.0 Internal Reporting Requirements 5.1 Fill out daily drilling report and cost report on Wellez. x Report covers operations from 6am to 6am x Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left of the data entry area –this will not save the data entered, and will navigate to another data entry tab. x Ensure time entry adds up to 24 hours total. x Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. 5.2 Afternoon Updates x Submit a short operations update each work day to pmazzolini@hilcorp.com, mmyers@hilcorp.com, Frank.Roach@hilcorp.com,andcdinger@hilcorp.com 5.3 Intranet Home Page Morning Update x Submit a short operations update each morning by 7am on the company intranet homepage. On weekend and holidays, ensure to have this update in before 5am. Each rig will be assigned a username to login with. 5.4 EHS Incident Reporting x Notify EHS field coordinator. 1. This could be one of (3) individuals as they rotate around. Know who your EHS field coordinator is at all times, don’t wait until an emergency to have to call around and figure it out!!!! a. John Coston: O: (907) 777-6726 C: (907) 227-3189 b. Jacob Nordwall: O: (907) 777-8418 C: (907) 748-0753 2. Spills: Keegan Fleming: O:907-777-8477 C:907-350-9439 x Notify Drlg Manager 1. Monty M Myers: O: 907-777-8431 C: 907-538-1168 x Submit Hilcorp Incident report to contacts above within 24 hrs 5.5 Casing Tally x Send final “As-Run” Casing tally to mmyers@hilcorp.com, Frank.Roach@hilcorp.com, and cdinger@hilcorp.com 5.6 Casing and Cmt report x Send casing and cement report for each string of casing to mmyers@hilcorp.com, Frank.Roach@hilcorp.com, and cdinger@hilcorp.com Page 6 Version 0 September, 2021 IRU 241-01 Drilling Procedure Rev 0 6.0 Planned Wellbore Schematic Page 7 Version 0 September, 2021 IRU 241-01 Drilling Procedure Rev 0 7.0 Drilling / Completion Summary IRU 241-01 is a S-shaped well to be drilled off of the Ivan River pad on the west bank of the Cook Inlet. The well will be drilled to target Sterling and Beluga gas sands. The base plan is deviated wellbore with a kickoff point at ~200’MD. Maximum hole angle will be 39 deg before dropping to 38 deg and TD of the well will be 9,554’ TMD/ 7,720’ TVD. Drilling operations are expected to commence approximately November 1st, 2021. The Hilcorp Rig # 147 will be used to drill the wellbore then run casing and cement. Surface casing will be run to ~3,000’MD / 2,575’ TVD and cemented to surface to ensure protection of any shallow freshwater resources. Cement returns to surface will confirm TOC at surface. If cmt returns to surface are not observed, a Temp log will be run between 6 –18 hrs after CIP to determine TOC. Necessary remedial action will then be discussed with AOGCC authorities. All waste & mud generated during drilling and completion operations will be hauled to the Kenai Gas Field G&I facility for disposal / beneficial reuse depending on test results. General sequence of operations: 1. MOB Hilcorp Rig # 147 to well site 2. N/U diverter and test. 3. Drill 13-1/2”hole to 3,00’ MD. 4. POOH w/drill pipe. Perform logging. Perform cleanout run. 5. Run and cement 10-3/4”surface casing. 6. ND diverter, N/U & test 11” x 5M BOP. 7. Drill 9-7/8” hole to 5,981’ MD. 8. POOH w/drill pipe. Perform logging. Perform cleanout run. 9. Run and cement 7-5/8” production casing. 10. Drill 6-3/4” hole section to 9,554’MD. Perform wiper trips as needed. 11. POOH w/drill pipe. Perform logging. Perform cleanout run. 12. Run and cmt 4-1/2”production liner. 13. POOH laying down running tools. 14. PU clean out assembly and RIH. Displace well to 6% KCL completion fluid. 15. POOH and LD clean out assembly. 16. Run tieback/upper completion 17. N/D BOP, N/U dry hole tree, RDMO. p o target Sterling and Beluga gas sands. 3,000' e Hilcorp Rig # 147 w Page 8 Version 0 September, 2021 IRU 241-01 Drilling Procedure Rev 0 Reservoir Evaluation Plan: 1. Surface hole: GR + Res 2. Intermediate hole: Triple Combo w/e-line sonic and FMI after TD 3. Production Hole: Triple Combo w/e-line sonic and FMI after TD 4. Mud loggers from surface casing point to TD. Page 10 Version 0 September, 2021 IRU 241-01 Drilling Procedure Rev 0 Summary of BOP Equipment and Test Requirements Hole Section Equipment Test Pressure (psi) 13-1/2”x 21-1/4” x 2M Hydril MSP diverter Function Test Only 9-7/8” & 6-3/4” x 11” x 5M Annular BOP x 11” x 5M Double Ram o Blind ram in btm cavity x Mud cross x 11” x 5M Single Ram x 3-1/8” 5M Choke Line x 2-1/16” x 5M Kill line x 3-1/8” x 2-1/16” 5M Choke manifold x Standpipe, floor valves, etc Initial Test: 250/3500 (Annular 2500 psi) Subsequent Tests: 250/3500 (Annular 2500 psi) x Primary closing unit: Control Technologies accumulator unit, 5 station, 120 gallon (12 x 11 gal bottles). x Primary closing hydraulic pressure is provided by an electrically driven triplex pump. Emergency pressure is provided by bottled nitrogen. Required AOGCC Notifications: x Well control event (BOPs utilized to shut in the well to control influx of formation fluids). x 24 hours notice prior to spud. x 24 hours notice prior to testing BOPs. x 24 hours notice prior to casing running & cement operations. x Any other notifications required in APD. Additional requirements may be stipulated on APD and Sundry. Regulatory Contact Information: AOGCC Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email: jim.regg@alaska.gov Bryan McLellan / Petroleum Engineer / (O): 907-793-1226 / Email: bryan.mclellan@alaska.gov Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Email: victoria.loepp@alaska.gov Primary Contact for Opportunity to witness: AOGCC.Inspectors@alaska.gov Test/Inspection notification standardization format: http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) Page 11 Version 0 September, 2021 IRU 241-01 Drilling Procedure Rev 0 9.0 R/U and Preparatory Work 9.1 Set 16” conductor at +/-120’ below ground level. 9.2 Dig out and set impermeable cellar. 9.3 Install slip-on 16-3/4” 3M “A” section. Ensure to orient wellhead so that tree will line up with flowline later. 9.4 Level pad and ensure enough room for layout of rig footprint and R/U. 9.5 Layout Herculite on pad to extend beyond footprint of rig. 9.6 R/U Hilcorp Rig # 147, spot service company shacks, spot & R/U company man & toolpusher offices. 9.7 RU Mud loggers. Mud loggers are required on surface hole section taking 30’ samples 9.8 After rig equipment has been spotted, R/U handi-berm containment system around footprint of rig. 9.9 Mix mud for 13-1/2”hole section. 9.10 Install 5-1/2” liners in mud pumps. x HHF-1000 mud pumps are rated at 3633 psi (85%) / 333 gpm (100%) at 120 spm with 5-1/2” liners. Layout Herculite on pad to extend beyond footprint of rig. Page 12 Version 0 September, 2021 IRU 241-01 Drilling Procedure Rev 0 10.0 N/U 21-1/4” Diverter 10.1 N/U 21-1/4” Diverter x N/U 21-1/4” diverter “T”. x Knife gate, 16” diverter line. x Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C). 10.2 Function test diverter. Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens prior to annular closure. Ensure to notify AOGCC inspector to witness function test of diverter. x NOTE: Ensure closing time on diverter annular is in line with API RP 64: o Annular element ID 20” or smaller: Less than 30 seconds o Annular element ID greater than 20”: Less than 45 seconds 10.3 Ensure to set up a clearly marked “warning zone” is established on each side and ahead of the vent line tip. “Warning Zone” must include: x A prohibition on vehicle parking x A prohibition on ignition sources or running equipment x A prohibition on staged equipment or materials x Restriction of traffic to essential foot or vehicle traffic only. 10.4 Set wear bushing in wellhead. Page 13 Version 0 September, 2021 IRU 241-01 Drilling Procedure Rev 0 10.5 Rig 147 Orientation: Note: Actual layout may be different on location Page 14 Version 0 September, 2021 IRU 241-01 Drilling Procedure Rev 0 11.0 Drill 13-1/2”Hole Section 11.1 P/U 13-1/2”directional drilling assy: x Ensure BHA components have been inspected previously. x Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. x Ensure TF offset is measured accurately and entered correctly into the MWD software. x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. x Workstring will be 4.5” 16.6# S-135 CDS40 11.2 4-1/2”Workstring & HWDP will come from Hilcorp. 11.3 Begin drilling out from 16”conductor at reduced flow rates to avoid broaching the conductor. 11.4 Drill 13-1/2”hole section to 3,000’MD/ 2,575’ TVD. Confirm this setting depth with the geologist and Drilling Engineer while drilling the well. x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Pump at 500 - 550 gpm. Ensure shaker screens are set up to handle this flowrate. x Utilize past experience to drill through coal seams efficiently. Coal seam log will be provided by Hilcorp Geo team. x Keep swab and surge pressures low when tripping. x Make wiper trips every 500’ or every couple days unless hole conditions dictate otherwise. x Ensure shale shakers are functioning properly. Check for holes in screens on connections. x Adjust MW as necessary to maintain hole stability. x TD the hole section in a good shale between 2,950’ and 3,050’MD. x Take MWD surveys every stand drilled (60’ intervals). 11.5 13-1/2”hole mud program summary: Weighting material to be used for the hole section will be barite. Additional barite will be on location to weight up the active system (1) ppg above highest anticipated MW. We will start with a simple gel + FW spud mud at 8.8 ppg. Pason PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, Toolpusher office, and mud loggers office. Superseded y()pp W spud mud at 8.8 ppg. Geoprognosis in section 28 indicates formation pressures of 9.0 ppg EMW just below planned surface casing shoe depth. Surface hole pore pressure prognosis is not included. Need to use higher mud weight for surface hole. See updated surface hole drilling plan attached - bjm See attached email correspondence and revised section 11.0 - bjm Page 15 Version 0 September, 2021 IRU 241-01 Drilling Procedure Rev 0 System Type: 8.8 –9.5 ppg Pre-Hydrated Aquagel/freshwater spud mud Properties: Depths Density Viscosity Plastic Viscosity Yield Point API FL pH 120-3000’ 8.8 – 9.5 85-150 20 - 40 25 - 45 <10 8.5-9.0 System Formulation: Aquagel + FW spud mud Product Concentration FRESH WATER SODA ASH AQUAGEL CAUSTIC SODA BARAZAN D+ BAROID 41 PAC-L /DEXTRID LT ALDACIDE G X-TEND II 0.905 bbl 0.5 ppb 12-15 ppb 0.1 ppb (9 pH) as needed as required for weight if required for <12 FL 0.1 ppb 0.02 ppb 11.6 At TD; pump sweeps, CBU, and pull a wiper trip back to the 16”conductor shoe. 11.7 RIH to TD, noting any tight spots along the way. CBU at least once at TD to ensure hole is clean for casing run. 11.8 POOH and LD BHA. Page 9 Version 0 September, 2021 IRU 241-01 Drilling Procedure Rev 0 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the below AOGCC regulations. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. x BOPs shall be tested at (2) week intervals during the drilling of IRU 241-01. Ensure to provide AOGCC 24 hrs notice prior to testing BOPs. x The initial test of BOP equipment will be to 250/3500 psi & subsequent tests of the BOP equipment will be to 250/3500 psi for 5/5 min (annular to 50% rated WP, 2500 psi on the high test for initial and subsequent tests). Confirm that these test pressures match those specified on the PTD. x If the BOP is used to shut in on the well in a well control situation, we must test all BOP components utilized for well control prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP test. x All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid program and drilling fluid system”. x All AOGCC regulations within 20 AAC 25.035 “Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements” x Ensure AOGCC approved drilling permits are posted on the rig floor and in Co Man office. Regulation Variance Requests: x initial test of BOP equipment will be to 250/3500 psi subsequent tests of the BOP equipment will be to 250/3500 psi Page 14 Version 1 October, 2021 IRU 241-01 Drilling Procedure Rev 1 11.0 Drill 13-1/2” Hole Section 11.1 P/U 13-1/2” directional drilling assy: x Ensure BHA components have been inspected previously. x Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. x Ensure TF offset is measured accurately and entered correctly into the MWD software. x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. x Workstring will be 4.5” 16.6# S-135 CDS40 11.2 4-1/2” Workstring & HWDP will come from Hilcorp. 11.3 Begin drilling out from 16” conductor at reduced flow rates to avoid broaching the conductor. 11.4 Drill 13-1/2” hole section to 3,000’ MD/ 2,575’ TVD. Confirm this setting depth with the geologist and Drilling Engineer while drilling the well. x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Pump at 500 - 550 gpm. Ensure shaker screens are set up to handle this flowrate. x Utilize past experience to drill through coal seams efficiently. Coal seam log will be provided by Hilcorp Geo team. x Keep swab and surge pressures low when tripping. x Make wiper trips every 500’ or every couple days unless hole conditions dictate otherwise. x Ensure shale shakers are functioning properly. Check for holes in screens on connections. x Adjust MW as necessary to maintain hole stability and overbalance. x Increase MW while drilling ahead and ensure weight is at least 9.3 ppg ~100’ before section TD. x TD the hole section in a good shale between 2,950’ and 3,050’MD. x Take MWD surveys every stand drilled (60’ intervals). 11.5 13-1/2” hole mud program summary: Weighting material to be used for the hole section will be barite. Additional barite will be on location to weight up the active system (1) ppg above highest anticipated MW. We will start with a simple gel + FW spud mud at 9.0 ppg. Pason PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, Toolpusher office, and mud loggers office. Page 15 Version 1 October, 2021 IRU 241-01 Drilling Procedure Rev 1 System Type:9.0 – 9.5 ppg Pre-Hydrated Aquagel/freshwater spud mud Properties: Depths Density Viscosity Plastic Viscosity Yield Point API FL pH 120-3000’9.0 – 9.5 85-150 20 - 40 25 - 45 <10 8.5-9.0 System Formulation: Aquagel + FW spud mud Product Concentration FRESH WATER SODA ASH AQUAGEL CAUSTIC SODA BARAZAN D+ BAROID 41 PAC-L /DEXTRID LT ALDACIDE G X-TEND II 0.905 bbl 0.5 ppb 12-15 ppb 0.1 ppb (9 pH) as needed as required for weight if required for <12 FL 0.1 ppb 0.02 ppb 11.6 At TD; pump sweeps, CBU, and pull a wiper trip back to the 16” conductor shoe. 11.7 RIH to TD, noting any tight spots along the way. CBU at least once at TD to ensure hole is clean for casing run. 11.8 POOH and LD BHA. Page 16 Version 0 September, 2021 IRU 241-01 Drilling Procedure Rev 0 12.0 Run 10-3/4”Surface Casing 12.1 R/U and pull wearbushing. 12.2 R/U Weatherford 10-3/4”casing running equipment. x Ensure 10-3/4”DWC x CDS 40 XO on rig floor and M/U to FOSV. x R/U fill-up line to fill casing while running. x Ensure all casing has been drifted on the location prior to running. x Be sure to count the total # of joints on the location before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 12.3 P/U shoe joint. Visually verify no debris inside joint. 12.4 Continue M/U & thread locking shoe track assy consisting of: x (1) Shoe joint w/ float shoe bucked on (thread locked). x (1) Joint with coupling thread locked. x (1) Joint with float collar bucked on pin end & thread locked. x Install (2) centralizers on shoe joint over a stop collar. 10’ from each end. x Install (1) centralizer, mid tube on thread locked joint and on FC joint. x Ensure proper operation of float equipment. 12.5 Continue running 10-3/4”surface casing x Fill casing while running using fill up line on rig floor. x Use “API Modified” thread compound. Dope pin end only w/ paint brush. x Install (1) centralizer every other joint to 300’. Do not run any centralizers above 300’ in the event a top out job is needed. x Utilize a collar clamp until weight is sufficient to keep slips set properly. 10-3/4” 45.5# DWC/C M/U torques Casing OD Minimum Maximum Yield Torque 10-3/4”35,900 ft-lbs 42,200 ft-lbs 48,500 ft-lbs Page 17 Version 0 September, 2021 IRU 241-01 Drilling Procedure Rev 0 Page 18 Version 0 September, 2021 IRU 241-01 Drilling Procedure Rev 0 12.6 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 12.7 Slow in and out of slips. 12.8 P/U casing hanger joint and M/U to string. Casing hanger joint will come out to the rig with the landing joint already M/U. Position the shoe as close to TD as possible. Strap the landing joint while it is on the deck and mark the joint at (1) ft intervals to use as a reference when landing the hanger. 12.9 Lower string and land out in wellhead. Confirm measurements indicate the hanger has correctly landed out in the wellhead profile. 12.10 R/U circulating equipment and circulate the greater of 1 x casing capacity or 1 x OH volume. Elevate the hanger offseat to avoid plugging the flutes. Stage up pump slowly and monitor losses closely while circulating. 12.11 After circulating, lower string and land hanger in wellhead again. Page 19 Version 0 September, 2021 IRU 241-01 Drilling Procedure Rev 0 13.0 Cement 10-3/4”Surface Casing 13.1 Hold a pre-job safety meeting over the upcoming cmt operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud & water can be delivered to the cmt unit at acceptable rates. x Pump 20 bbls of freshwater through all of Halliburton’s equipment, taking returns to cuttings bin, prior to pumping any fluid downhole x How to handle cmt returns at surface. x Which pump will be utilized for displacement, and how fluid will be fed to displacement pump. x Positions and expectations of personnel involved with the cmt operation. 13.2 Document efficiency of all possible displacement pumps prior to cement job 13.3 R/U cmt head (if not already done so). Ensure top and bottom plugs have been loaded correctly. 13.4 Pump 5 bbls 10 ppg spacer. Test surface cmt lines. 13.5 Pump remaining 10 ppg spacer. 13.6 Drop bottom plug. Mix and pump cmt per below recipe. 13.7 Cement volume based on annular volume + 100% open hole excess. Job will consist of lead & tail, TOC brought to surface. Estimated Total Cement Volume: Section:Calculation:Vol (BBLS)Vol (ft3) 12.0 ppg LEAD: 16”Conductor x 10-3/4” casing annulus: 120’ x .10660 bpf =12.79 71.8 12.0 ppg LEAD: 13-1/2”OH x 10-3/4” Casing annulus: (2500’ –120’) x .06478 bpf x 2 = 308.37 1731.4 Total LEAD:321.16 bbl 1803.2 ft3 15.4 ppg TAIL: 13-1/2”OH x 10-3/4” Casing annulus: (3000’- 2500’)x .06478 bpf x 2= 64.78 363.7 15.4 ppg TAIL: 10-3/4”Shoe track: 80 x .09617 bpf =7.69 43.2 Total TAIL:72.48 bbl 406.9 ft3 TOTAL CEMENT VOL:393.64 bbl 2210.1 ft3 Verified Cement Calcs - bjm Page 20 Version 0 September, 2021 IRU 241-01 Drilling Procedure Rev 0 Cement Slurry Design: 13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Keep the hanger elevated above the wellhead while working. If the hole gets “sticky”, land the hanger on seat and continue with the cement job. 13.9 After pumping cement, drop top plug and displace cement with spud mud. 13.10 Ensure cement unit is used to displace cmt so that volume tracking is more accurate. 13.11 Displacement calculation: 3000’-80’ = 2920’x .09617 bpf = 281 bbls 13.12 Monitor returns closely while displacing cement. Adjust pump rate if necessary. If hanger flutes become plugged, open wellhead side outlet in cellar and take returns to cellar. Be prepared to pump out fluid from cellar. Have some sx of sugar available to retard setting of cement. 13.13 Do not overdisplace by more than ½ shoe track volume. Total volume in shoe track is 7.7 bbls. x Be prepared for cement returns to surface. If cmt returns are not observed to surface, be prepared to run a temp log between 12 –18 hours after CIP. Lead Slurry (2500’ MD to surface)Tail Slurry (3000’ to 2500’ MD) System Extended Conventional Density 12 lb/gal 15.4 lb/gal Yield 2.40 ft3/sk 1.16 ft3/sk Mixed Water 14.25 gal/sk 5.04 gal/sk Mixed Fluid 14.25 gal/sk 5.04 gal/sk Additives Code Description Code Description Type I/II Cement Class A Type I/II Cement Class A Halad-344 Fluid Loss Halad-344 Fluid Loss CalSeal Accelerator CalSeal Accelerator VersaSet Thixotropic CFR-3 Dispersant D-Air 5000 Anti Foam UCS Slurry Conditioner Econolite Light-weight add.Super CBL Anti-Gas Migration SA-1015 Suspension Agent BridgeMaker II Lost Circulation Page 21 Version 0 September, 2021 IRU 241-01 Drilling Procedure Rev 0 x Be prepared with small OD top out tubing in the event a top out job is required. The AOGCC will require us to run steel pipe through the hanger flutes. The ID of the flutes is 1.5”. 13.14 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held. 13.15 R/D cement equipment. Flush out wellhead with FW. 13.16 Back out and L/D landing joint. Flush out wellhead with FW. 13.17 M/U pack-off running tool and pack-off to bottom of Landing joint. Set casing hanger packoff. Run in lock downs and inject plastic packing element. 13.18 Lay down landing joint and pack-off running tool. Ensure to report the following on wellez: x Pre flush type, volume (bbls) & weight (ppg) x Cement slurry type, lead or tail, volume & weight x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid x Note if casing is reciprocated or rotated during the job x Calculated volume of displacement, actual displacement volume, whether plug bumped & bump pressure, do floats hold x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure x Note if pre flush or cement returns at surface & volume x Note time cement in place x Note calculated top of cement x Add any comments which would describe the success or problems during the cement job Send final “As-Run” casing tally & casing and cement report to cdinger@hilcorp.com and Frank.Roach@hilcorp.com. This will be included with the EOW documentation that goes to the AOGCC. Page 22 Version 0 September, 2021 IRU 241-01 Drilling Procedure Rev 0 14.0 BOP N/U and Test 14.1 ND Diverter line and diverter 14.2 N/U multi-bowl wellhead assy. Install 10-3/4” packoff P-seals. Test to 3000 psi. 14.3 N/U 11” x 5M BOP as follows: x BOP configuration from Top down: 11” x 5M annular BOP/11” x 5M double ram /11” x 5M mud cross/11” x 5M single ram x Double ram should be dressed with 2-7/8” x 5” variable bore rams in top cavity, blind ram in btm cavity. x Single ram should be dressed with 2-7/8” x 5” variable bore rams x N/U bell nipple, install flowline. x Install (2) manual valves & a check valve on kill side of mud cross. x Install (1) manual valve on choke side of mud cross. Install an HCR outside of the manual valve. 14.4 Run 4-1/2”BOP test assy, land out test plug (if not installed previously). x Test BOP to 250/3500 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min. x Ensure to leave “B” section side outlet valves open during BOP testing so pressure does not build up beneath the test plug. 14.5 R/D BOP test assy. 14.6 Dump and clean mud pits, send spud mud to G&I pad for injection. 14.7 Mix 9.0 ppg 6% KCL PHPA mud system. 14.8 R/U mud loggers for production hole section. 14.9 Rack back as much 4-1/2”DP in derrick as possible to be used while drilling the hole section. 14.10 Install 5-1/2” liners in mud pumps. x HHF-1000 mud pumps are rated at 3633 psi (85%) / 333 gpm (100%) at 120 spm with 5-1/2” liners. ypg( py) t BOP to 250/3500 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min. See attached email correspondence and revised section 14.0 - 15.0. - bjm Geoprog for this hole section is 9.0 ppg EMW pore pressure. Need some overbalance. bjm 9.3 ppg mud per attached email from Frank Roach. Superseded. Page 23 Version 0 September, 2021 IRU 241-01 Drilling Procedure Rev 0 15.0 Drill 9-7/8” Hole Section 15.1 Pull test plug, run and set wear bushing 15.2 Ensure BHA components have been inspected previously. 15.3 Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. 15.4 TIH, conduct shallow hole test of MWD, and confirm all LWD functioning properly. 15.5 Ensure TF offset is measured accurately and entered correctly into the MWD software. 15.6 Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. 15.7 Workstring will be 4.5” 16.6# S-135 CDS40. Ensure to have enough 4-1/2” DP in derrick to drill the entire open hole section without having to pick up pipe from the pipeshed. 15.8 9-7/8” hole section mud program summary: Weighting material to be used for the hole section will be barite, salt and calcium carbonate. Additional calcium carbonate will be on location to weight up the active system (1) ppg above highest anticipated MW. Pason PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, Toolpusher office, and mud loggers office. System Type: 9.0 ppg 6% KCL PHPA fresh water-based drilling fluid. Properties: MD Mud Weight Viscosity Plastic Viscosity Yield Point pH HPHT 3,000’-5,981’9.0 –10.5 40-53 15-25 15-25 8.5-9.5 11.0 9.3 ppg minimum mud weight required per attached email from Frank Roach. bjm 9.3 - 10.5 ppg - bjm Superseded Page 24 Version 0 September, 2021 IRU 241-01 Drilling Procedure Rev 0 System Formulation: 6% KCL EZ Mud DP Product Concentration Water KCl Caustic BARAZAN D+ EZ MUD DP DEXTRID LT PAC-L BARACARB 5/25/50 BAROID 41 ALDACIDE G BARACOR 700 BARASCAV D 0.905 bbl 22 ppb (29 K chlorides) 0.2 ppb (9 pH) 1.25 ppb (as required 18 YP) 0.75 ppb (initially 0.25 ppb) 1-2 ppb 1 ppb 15 - 20 ppb (5 ppb of each) as required for a 9.0 –10.5 ppg 0.1 ppb 1 ppb 0.5 ppb (maintain per dilution rate) 15.9 TIH w/ 9-7/8”directional assy to TOC. Shallow test MWD and LWD on trip in. Note depth TOC tagged on AM report. 15.10 R/U and test casing to 3000 psi / 30 min. Ensure to record volume / pressure and plot on LOT graph. AOGCC requirement is 50% of burst.10-3/4” burst is 5210 psi / 2 = 2605 psi. 15.11 Drill out shoe track and 20’ of new formation. 15.12 CBU and condition mud for FIT. 15.13 Conduct FIT. Target value is 13.5 ppg EMW. Note: Offset field test data predicts frac gradient at the 10-3/4”shoe to be between 11.3 –14.5 ppg EMW. A 13.5 ppg LOT results in a 3.5 ppg kick margin and a >15 bbl kick tolerance volume while drilling with the planned MW of 10.0 ppg.Minimum value to attain greater than 15 bbl kick tolerance is 11.2 ppg EMW. 15.14 Drill 9-7/8”hole section to 5,981’ MD / 4,900’ TVD x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Pump at 500 - 600 gpm. Ensure shaker screens are set up to handle this flowrate. x Keep swab and surge pressures low when tripping. x Make wiper trips every 1000’ unless hole conditions dictate otherwise. x On the second wiper trip (around 5,000’ MD), trip back to the 10-3/4” shoe x Ensure shale shakers are functioning properly. Check for holes in screens on connections. x Adjust MW as necessary to maintain hole stability. Keep HTHP fluid loss < 10. x Take MWD surveys every 100’drilled. Surveys can be taken more frequently if deemed necessary. x Take (3) sets of formation samples every 20’. 15.15 At TD; pump sweeps, CBU, and pull a wiper trip back to the 10-3/4”shoe. gp p p AOGCC requirement is 50% of burst.10-3/4” burst is 5210 psi / 2 = 2605 psi. 9.3-10.5 ppg Page 25 Version 0 September, 2021 IRU 241-01 Drilling Procedure Rev 0 15.16 TOH with the drilling assy, standing back drill pipe. 15.17 LD BHA 15.18 RU E-Line and perform wireline logging plan. 15.19 RD E-Line. PU 9-7/8”clean out BHA, and TIH to TD. 15.20 Pump sweep, CBU and condition mud for casing run. 15.21 POOH and LD BHA 15.22 Install 7-5/8” casing rams in BOP stack and test. 3DJH 9HUVLRQ 2FWREHU IRU 241-01 Drilling Procedure Rev 1 %2318DQG7HVW 1''LYHUWHUOLQHDQGGLYHUWHU 18PXOWLERZOZHOOKHDGDVV\,QVWDOO´SDFNRII3VHDOV7HVWWRSVL 18´[0%23DVIROORZV x %23FRQILJXUDWLRQIURP7RSGRZQ´[0DQQXODU%23´[0GRXEOHUDP´[0 PXGFURVV´[0VLQJOHUDP x 'RXEOHUDPVKRXOGEHGUHVVHGZLWK ´[´YDULDEOHERUHUDPV LQWRSFDYLW\EOLQGUDP LQEWPFDYLW\ x 6LQJOHUDPVKRXOGEHGUHVVHGZLWK ´[´YDULDEOHERUHUDPV x 18EHOOQLSSOHLQVWDOOIORZOLQH x ,QVWDOOPDQXDOYDOYHV DFKHFNYDOYHRQNLOOVLGHRIPXGFURVV x ,QVWDOOPDQXDOYDOYHRQFKRNHVLGHRIPXGFURVV,QVWDOODQ+&5RXWVLGHRIWKHPDQXDO YDOYH 5XQ´%23WHVWDVV\ODQGRXWWHVWSOXJLIQRWLQVWDOOHGSUHYLRXVO\ x 7HVW%23WRSVLIRUPLQ7HVWDQQXODUWRSVLIRUPLQ x (QVXUHWROHDYH³%´VHFWLRQVLGHRXWOHWYDOYHVRSHQGXULQJ%23WHVWLQJVRSUHVVXUHGRHVQRW EXLOGXSEHQHDWKWKHWHVWSOXJ 5'%23WHVWDVV\ 'XPSDQGFOHDQPXGSLWVVHQGVSXGPXGWR* ,SDGIRULQMHFWLRQ 0L[SSJ.&/3+3$PXGV\VWHP 58PXGORJJHUVIRUSURGXFWLRQKROHVHFWLRQ 5DFNEDFNDVPXFK´'3LQGHUULFNDVSRVVLEOHWREHXVHGZKLOHGULOOLQJWKHKROHVHFWLRQ ,QVWDOO´OLQHUVLQPXGSXPSV x ++)PXGSXPSVDUHUDWHGDWSVLJSPDWVSPZLWK´ OLQHUV 3DJH 9HUVLRQ 2FWREHU IRU 241-01 Drilling Procedure Rev 1 'ULOO´+ROH6HFWLRQ 3XOOWHVWSOXJUXQDQGVHWZHDUEXVKLQJ (QVXUH%+$FRPSRQHQWVKDYHEHHQLQVSHFWHGSUHYLRXVO\ 'ULIWDQGFDOLSHUDOOFRPSRQHQWVEHIRUH089LVXDOO\YHULI\QRGHEULVLQVLGHFRPSRQHQWVWKDW FDQQRWEHGULIWHG 7,+FRQGXFWVKDOORZKROHWHVWRI0:'DQGFRQILUPDOO/:'IXQFWLRQLQJSURSHUO\ (QVXUH7)RIIVHWLVPHDVXUHGDFFXUDWHO\DQGHQWHUHGFRUUHFWO\LQWRWKH0:'VRIWZDUH +DYH''UXQK\GUDXOLFVFDOFXODWLRQVRQVLWHWRHQVXUHRSWLPXPQR]]OHVL]LQJ+\GUDXOLFV FDOFXODWLRQVDQGUHFRPPHQGHG7)$LVDWWDFKHGEHORZ :RUNVWULQJZLOOEH´6&'6(QVXUHWRKDYHHQRXJK´'3LQGHUULFNWRGULOO WKHHQWLUHRSHQKROHVHFWLRQZLWKRXWKDYLQJWRSLFNXSSLSHIURPWKHSLSHVKHG ´KROHVHFWLRQPXGSURJUDPVXPPDU\ :HLJKWLQJPDWHULDOWREHXVHGIRUWKHKROHVHFWLRQZLOOEHEDULWHVDOWDQGFDOFLXPFDUERQDWH $GGLWLRQDOFDOFLXPFDUERQDWHZLOOEHRQORFDWLRQWRZHLJKWXSWKHDFWLYHV\VWHPSSJDERYH KLJKHVWDQWLFLSDWHG0: 3DVRQ397ZLOOEHXVHGWKURXJKRXWWKHGULOOLQJDQGFRPSOHWLRQSKDVH5HPRWHPRQLWRULQJ VWDWLRQVZLOOEHDYDLODEOHDWWKHGULOOHU¶VFRQVROH&R0DQRIILFH7RROSXVKHURIILFHDQGPXG ORJJHUVRIILFH System Type:SSJ.&/3+3$IUHVKZDWHUEDVHGGULOOLQJIOXLG 1RWH(VWLPDWHGSUHVVXUHVLQWKHIRUPDWLRQEHORZVXUIDFHFDVLQJDUHaSSJ(0:6WDUWLQJZLWKD SSJPXGSURYLGHVRYHUEDODQFHQHHGHGWRGULOODKHDGDQGWULSPDUJLQDWLQWHUYDO7' Properties: 0'0XG :HLJKW 9LVFRVLW\3ODVWLF 9LVFRVLW\<LHOG3RLQW S++3+7 ¶¶± 3DJH 9HUVLRQ 2FWREHU IRU 241-01 Drilling Procedure Rev 1 System Formulation:.&/(=0XG'3 3URGXFW &RQFHQWUDWLRQ :DWHU .&O &DXVWLF %$5$=$1' (=08''3 '(;75,'/7 3$&/ %$5$&$5% %$52,' $/'$&,'(* %$5$&25 %$5$6&$9' EEO SSE.FKORULGHV SSES+ SSEDVUHTXLUHG<3 SSELQLWLDOO\SSE SSE SSE SSESSERIHDFK DVUHTXLUHGIRUD ±SSJ SSE SSE SSEPDLQWDLQSHUGLOXWLRQUDWH 7,+Z´GLUHFWLRQDODVV\WR72&6KDOORZWHVW0:'DQG/:'RQWULSLQ1RWHGHSWK 72&WDJJHGRQ$0UHSRUW 58DQGWHVWFDVLQJWRSVLPLQ(QVXUHWRUHFRUGYROXPHSUHVVXUHDQGSORWRQ/27 JUDSK$2*&&UHTXLUHPHQWLVRIEXUVW´EXUVWLVSVL SVL 'ULOORXWVKRHWUDFNDQG¶RIQHZIRUPDWLRQ &%8DQGFRQGLWLRQPXGIRU),7 &RQGXFW),77DUJHWYDOXHLV SSJ(0: Note: Offset field test data predicts frac gradient at the 10-3/4” shoe to be between 11.3 – 14.5 ppg EMW. A 13.5 ppg LOT results in a 3.5 ppg kick margin and a >15 bbl kick tolerance volume while drilling with the planned MW of 10.0 ppg.Minimum value to attain greater than 15 bbl kick tolerance is 11.2 ppg EMW. 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R/U Weatherford 7-5/8”casing running equipment. x Ensure 7-5/8”CDC x CDS 40 crossover on rig floor and M/U to FOSV. x R/U fill up line to fill casing while running. x Ensure all casing has been drifted prior to running. x Be sure to count the total # of joints before running. x Keep hole covered while R/U equipment. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 16.2. P/U shoe joint, visually verify no debris inside joint. 16.3. Continue M/U & thread locking shoe track assy consisting of: x (1) Shoe joint w/ shoe bucked on & threadlocked (coupling also thread locked). x (1) joint casing, threadlocked (coupling also thread locked) x (1) Joint with float collar bucked on pin end & threadlocked (coupling also thread locked). x Solid body centralizers will be pre-installed on shoe joint an FC joint. x Leave centralizers free floating so that they can slide up and down the joint. x Ensure proper operation of float shoe and float collar. x Utilize a collar clamp until weight is sufficient to keep slips set properly 16.4. Continue running 7-5/8”production casing x Fill casing while running using fill up line on rig floor. x Use “API Modified” thread compound. Dope pin end only w/ paint brush. x Install solid body centralizers on every joint across zones of interest, TBD after LWD. x Install solid body centralizers on every other joint to 10-3/4” shoe. Leave the centralizers free floating. x Pick up swell packer and place in string at approximately 250’ above 10-3/4” surface casing shoe depth (~2,750’ MD). 16.5. Continue running 7-5/8” production casing 7-5/8”29.7# CDC M/U torques Casing OD Minimum Maximum Yield Torque 7-5/8”14,000 ft-lbs 17,000 ft-lbs 20,900 ft-lbs Page 27 Version 0 September, 2021 IRU 241-01 Drilling Procedure Rev 0 Page 28 Version 0 September, 2021 IRU 241-01 Drilling Procedure Rev 0 16.6. Run in hole w/ 7-5/8”casing to the 10-3/4” casing shoe. 16.7. Fill the casing with fill up line and break circulation every 1,000 feet to the shoe or as the hole dictates. 16.8. Obtain slack off weight, PU weight, rotating weight, and torque of the casing. 16.9. Circulate 2X bottoms up at shoe, ease casing thru shoe. 16.10. Continue to RIH w/ casing no faster than 1 jt./minute. Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 16.11. Set casing slowly in and out of slips. 16.12. Monitor PUW & SOW. Circulate BU if needed. Highlight zones of interest before running past, ex: coals 16.13. Swedge up and wash last stand before picking up hanger/landing joint. Note slack-off and pick- up weights. 16.14. P/U casing hanger joint and M/U to string. Casing hanger joint will come out to the rig with the landing joint already M/U. Position the shoe as close to TD as possible. Strap the landing joint while it is on the deck and mark the joint at (1) ft intervals to use as a reference when landing the hanger. 16.15. Lower string and land out in wellhead. Confirm measurements indicate the hanger has correctly landed out in the wellhead profile. 16.16. Stage pump rates up slowly to circulating rate. Circ and condition mud with casing on bottom. Circulate 2X bottoms up or until pressures stabilize and mud properties are correct and the shakers are clean. Reduce the low-end rheology of the drilling fluid by adding water and thinners. 16.17. Rotate and reciprocate string if hole conditions allow. Circ until hole and mud is in good condition for cementing. Page 29 Version 0 September, 2021 IRU 241-01 Drilling Procedure Rev 0 17.0 Cement 7-5/8”Production Casing 17.1. Hold a pre-job safety meeting over the upcoming cmt operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud & water can be delivered to the cmt unit at acceptable rates. x Pump 20 bbls of freshwater through all of Halliburton’s equipment, taking returns to cuttings bin, prior to pumping any fluid downhole x How to handle cmt returns at surface, regardless of how unlikely it is that this should occur. x Which pump will be utilized for displacement, and how fluid will be fed to displacement pump. x Positions and expectations of personnel involved with the cmt operation. x Document efficiency of all possible displacement pumps prior to cement job. 17.2. Attempt to reciprocate the casing during cmt operations until hole gets sticky. 17.3. R/U cmt head (if not already done so). Ensure top and bottom plugs have been loaded correctly. 17.4. Pump 5 bbls of 12.5 ppg Mud Push spacer. 17.5. Test surface cmt lines to 4500 psi. 17.6. Pump remaining 12.5 ppg Mud Push spacer. 17.7. Drop bottom plug. Mix and pump cmt per below recipe. 17.8. Cement volume based on annular volume + 40% open hole excess. Job will consist of lead & tail, TOC brought to 500’ above surface casing shoe. Page 30 Version 0 September, 2021 IRU 241-01 Drilling Procedure Rev 0 Estimated Total Cement Volume: Cement Slurry Design: Section:Calculation:Vol (BBLS)Vol (ft3) 12.0 ppg LEAD: 10-3/4” casing x 7-5/8” casing annulus: (3000’ –2500’)x .03969 bpf =19.85 111.4 12.0 ppg LEAD: 9-7/8” OH x 7-5/8” Casing annulus: (5481’ –3000’) x .03825 bpf x 1.4 = 132.86 746.0 Total LEAD:152.71 bbl 857.4 ft3 15.4 ppg TAIL: 9-7/8” OH x 7-5/8” Casing annulus: (5981’- 5481’) x .03825 bpf x 1.4 = 26.78 150.3 15.4 ppg TAIL: 7-5/8” Shoe track: 80 x .04592 bpf =3.67 20.6 Total TAIL:30.45 bbl 170.9 ft3 TOTAL CEMENT VOL:183.16 bbl 1028.3 ft3 Lead Slurry (5481’ MD to 2500’ MD)Tail Slurry (5981’ to 5481’ MD) System Extended Conventional Density 12 lb/gal 15.4 lb/gal Yield 2.40 ft3/sk 1.16 ft3/sk Mixed Water 14.25 gal/sk 5.04 gal/sk Mixed Fluid 14.25 gal/sk 5.04 gal/sk Additives Code Description Code Description Type I/II Cement Class A Type I/II Cement Class A Halad-344 Fluid Loss Halad-344 Fluid Loss CalSeal Accelerator CalSeal Accelerator VersaSet Thixotropic CFR-3 Dispersant D-Air 5000 Anti Foam UCS Slurry Conditioner Econolite Light-weight add.Super CBL Anti-Gas Migration SA-1015 Suspension Agent BridgeMaker II Lost Circulation Verified cement calcs - bjm Page 31 Version 0 September, 2021 IRU 241-01 Drilling Procedure Rev 0 17.9. Attempt to reciprocate casing during cement pumping if hole conditions allow. Keep the hanger elevated above the wellhead while working. If the hole gets “sticky”, land the hanger on seat and continue with the cement job. 17.10. After pumping cement, drop top plug and displace cement with mud. Displace at max rate of 5 bbl/min. 17.11. Displacement calculation: 5981’-80’ = 5901’ x .04592 bpf = 271 bbls 17.12. If hole conditions allow –continue reciprocating casing throughout displacement. This will ensure a high quality cement job with 100% coverage around the pipe. 17.13. If elevated displacement pressures are encountered, position casing at setting depth and cease reciprocation. Monitor returns & pressure closely while circulating. Notify Drilling Foreman immediately of any changes. 17.14. Do not overdisplace by more than ½ shoe track. Shoe track volume is 3.7 bbls. 17.15. Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. Note amount of fluid returned after bumping plug and releasing pressure. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held. 17.16. Bleed pressure to zero to check float equipment. Watch for flow. Note amount of fluid returned after bumping plug and releasing pressure. 17.17. R/D cement equipment. Flush out wellhead with FW. 17.18. Back out and L/D landing joint. Flush out wellhead with FW. 17.19. M/U pack-off running tool and pack-off to bottom of Landing joint. Set casing hanger packoff. Run in lock downs and inject plastic packing element. 17.20. Lay down landing joint and pack-off running tool. Page 32 Version 0 September, 2021 IRU 241-01 Drilling Procedure Rev 0 Ensure to report the following on wellez: x Pre flush type, volume (bbls) & weight (ppg) x Cement slurry type, lead or tail, volume & weight x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid x Note if casing is reciprocated or rotated during the job x Calculated volume of displacement , actual displacement volume, whether plug bumped & bump pressure, do floats hold x Percent mud returns during job. If intermittent, note timing during pumping of job. Final circulating pressure x Note if pre flush or cement returns at surface & volume x Note time cement in place x Note calculated top of cement x Add any comments which would describe the success or problems during the cement job Send final “As-Run” casing tally & casing and cement report to cdinger@hilcorp.com and Frank.Roach@hilcorp.com. This will be included with the EOW documentation that goes to the AOGCC. Page 33 Version 0 September, 2021 IRU 241-01 Drilling Procedure Rev 0 18.0 Drill 6-3/4” Hole Section 18.1 Pull test plug, run and set wear bushing 18.2 Ensure BHA components have been inspected previously. 18.3 Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. 18.4 TIH, conduct shallow hole test of MWD, and confirm all LWD functioning properly. 18.5 Ensure TF offset is measured accurately and entered correctly into the MWD software. 18.6 Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. 18.7 Workstring will be 4-1/2” 16.6# S-135 CDS40. Ensure to have enough 4-1/2” DP in derrick to drill the entire open hole section without having to pick up pipe from the pipeshed. 18.8 6-3/4” hole section mud program summary: Weighting material to be used for the hole section will be barite, salt and calcium carbonate. Additional calcium carbonate will be on location to weight up the active system (1) ppg above highest anticipated MW. Pason PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, Toolpusher office, and mud loggers office. System Type: 9.0 ppg 6% KCL PHPA fresh water-based drilling fluid. Properties: MD Mud Weight Viscosity Plastic Viscosity Yield Point pH HPHT 5,981’-9,554’9.0 –10.5 40-53 15-25 15-25 8.5-9.5 11.0 Superseded Geoprog for this hole section is 9.0 ppg EMW pore pressure. Need some overbalance. bjm See attached email correspondence and revised section 18.0 - bjm Page 34 Version 0 September, 2021 IRU 241-01 Drilling Procedure Rev 0 System Formulation: 6% KCL EZ Mud DP Product Concentration Water KCl Caustic BARAZAN D+ EZ MUD DP DEXTRID LT PAC-L BARACARB 5/25/50 BAROID 41 ALDACIDE G BARACOR 700 BARASCAV D 0.905 bbl 22 ppb (29 K chlorides) 0.2 ppb (9 pH) 1.25 ppb (as required 18 YP) 0.75 ppb (initially 0.25 ppb) 1-2 ppb 1 ppb 15 - 20 ppb (5 ppb of each) as required for a 9.0 –10.5 ppg 0.1 ppb 1 ppb 0.5 ppb (maintain per dilution rate) 18.9 TIH w/ 6-3/4” directional assy to TOC. Shallow test MWD and LWD on trip in. Note depth TOC tagged on AM report. 18.10 R/U and test casing to 3500 psi / 30 min. Ensure to record volume / pressure and plot on FIT graph. AOGCC requirement is 50% of burst. 7-5/8” burst is 6890 psi / 2 = 3445 psi. 18.11 Drill out shoe track and 20’ of new formation. 18.12 CBU and condition mud for LOT. 18.13 Conduct LOT. Target value is 13.5 ppg EMW. Note: Offset field test data predicts frac gradient at the 7-5/8” shoe to be between 12.0 –15.5 ppg EMW. A 13.5 ppg LOT results in a 3.0 ppg kick margin and a >15 bbl kick tolerance volume while drilling with the planned MW of 10.5 ppg.Minimum value to attain greater than 15 bbl kick tolerance is 11.7 ppg EMW. 18.14 Drill 6-3/4” hole section to 9,554’ MD / 7,720’ TVD x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Pump at 400 - 500 gpm. Ensure shaker screens are set up to handle this flowrate. x Keep swab and surge pressures low when tripping. x Make wiper trips every 1000’ unless hole conditions dictate otherwise. x On the second wiper trip (around 7,900’ MD), trip back to the 7-5/8” shoe to split the hole section in half x Ensure shale shakers are functioning properly. Check for holes in screens on connections. x Adjust MW as necessary to maintain hole stability. Keep HTHP fluid loss < 10. x Take MWD surveys every 100’ drilled. Surveys can be taken more frequently if deemed necessary. x Take (3) sets of formation samples every 20’. Assumes 0 ppg kick intensity over mud weight. bjm Page 35 Version 0 September, 2021 IRU 241-01 Drilling Procedure Rev 0 18.15 At TD; pump sweeps, CBU, and pull a wiper trip back to the 7-5/8” shoe. 18.16 TOH with the drilling assy, standing back drill pipe. 18.17 LD BHA 18.18 RU E-Line and perform wireline logging plan. 18.19 RD E-Line. PU 6-3/4” clean out BHA, and TIH to TD. 18.20 Pump sweep, CBU and condition mud for casing run. 18.21 POOH and LD BHA 18.22 2-7/8” x 5-1/2” VBRs previously installed in BOP stack and tested with 4-1/2” test joint. 3DJH 9HUVLRQ 2FWREHU IRU 241-01 Drilling Procedure Rev 1 'ULOO´+ROH6HFWLRQ 3XOOWHVWSOXJUXQDQGVHWZHDUEXVKLQJ (QVXUH%+$FRPSRQHQWVKDYHEHHQLQVSHFWHGSUHYLRXVO\ 'ULIWDQGFDOLSHUDOOFRPSRQHQWVEHIRUH089LVXDOO\YHULI\QRGHEULVLQVLGHFRPSRQHQWVWKDW FDQQRWEHGULIWHG 7,+FRQGXFWVKDOORZKROHWHVWRI0:'DQGFRQILUPDOO/:'IXQFWLRQLQJSURSHUO\ (QVXUH7)RIIVHWLVPHDVXUHGDFFXUDWHO\DQGHQWHUHGFRUUHFWO\LQWRWKH0:'VRIWZDUH +DYH''UXQK\GUDXOLFVFDOFXODWLRQVRQVLWHWRHQVXUHRSWLPXPQR]]OHVL]LQJ+\GUDXOLFV FDOFXODWLRQVDQGUHFRPPHQGHG7)$LVDWWDFKHGEHORZ :RUNVWULQJZLOOEH´6&'6(QVXUHWRKDYHHQRXJK´'3LQGHUULFNWR GULOOWKHHQWLUHRSHQKROHVHFWLRQZLWKRXWKDYLQJWRSLFNXSSLSHIURPWKHSLSHVKHG ´KROHVHFWLRQPXGSURJUDPVXPPDU\ :HLJKWLQJPDWHULDOWREHXVHGIRUWKHKROHVHFWLRQZLOOEHEDULWHVDOWDQGFDOFLXPFDUERQDWH $GGLWLRQDOFDOFLXPFDUERQDWHZLOOEHRQORFDWLRQWRZHLJKWXSWKHDFWLYHV\VWHPSSJDERYH KLJKHVWDQWLFLSDWHG0: 3DVRQ397ZLOOEHXVHGWKURXJKRXWWKHGULOOLQJDQGFRPSOHWLRQSKDVH5HPRWHPRQLWRULQJ VWDWLRQVZLOOEHDYDLODEOHDWWKHGULOOHU¶VFRQVROH&R0DQRIILFH7RROSXVKHURIILFHDQGPXG ORJJHUVRIILFH System Type:SSJ.&/3+3$IUHVKZDWHUEDVHGGULOOLQJIOXLG 1RWH(VWLPDWHGSUHVVXUHVLQWKHIRUPDWLRQEHORZVXUIDFHFDVLQJDUHaSSJ(0:6WDUWLQJZLWKD SSJPXGSURYLGHVRYHUEDODQFHQHHGHGWRGULOODKHDGDQGWULSPDUJLQDWLQWHUYDO7' Properties: 0'0XG :HLJKW 9LVFRVLW\3ODVWLF 9LVFRVLW\<LHOG3RLQW S++3+7 ¶¶± 3DJH 9HUVLRQ 2FWREHU IRU 241-01 Drilling Procedure Rev 1 System Formulation:.&/(=0XG'3 3URGXFW &RQFHQWUDWLRQ :DWHU .&O &DXVWLF %$5$=$1' (=08''3 '(;75,'/7 3$&/ %$5$&$5% %$52,' $/'$&,'(* %$5$&25 %$5$6&$9' EEO SSE.FKORULGHV SSES+ SSEDVUHTXLUHG<3 SSELQLWLDOO\SSE SSE SSE SSESSERIHDFK DVUHTXLUHGIRUD ±SSJ SSE SSE SSEPDLQWDLQSHUGLOXWLRQUDWH 7,+Z´GLUHFWLRQDODVV\WR72&6KDOORZWHVW0:'DQG/:'RQWULSLQ1RWHGHSWK 72&WDJJHGRQ$0UHSRUW 58DQGWHVWFDVLQJWRSVLPLQ(QVXUHWRUHFRUGYROXPHSUHVVXUHDQGSORWRQ),7 JUDSK$2*&&UHTXLUHPHQWLVRIEXUVW´EXUVWLVSVL SVL 'ULOORXWVKRHWUDFNDQG¶RIQHZIRUPDWLRQ &%8DQGFRQGLWLRQPXGIRU/27 &RQGXFW/277DUJHWYDOXHLV SSJ(0: Note: Offset field test data predicts frac gradient at the 7-5/8” shoe to be between 12.0 – 15.5 ppg EMW. A 13.5 ppg LOT results in a 3.0 ppg kick margin and a >15 bbl kick tolerance volume while drilling with the planned MW of 10.5 ppg.Minimum value to attain greater than 15 bbl kick tolerance is 11.7 ppg EMW. 'ULOO´KROHVHFWLRQWR¶0'¶79' x 3XPSVZHHSVDQGPDLQWDLQPXGUKHRORJ\WRHQVXUHHIIHFWLYHKROHFOHDQLQJ x 3XPSDWJSP(QVXUHVKDNHUVFUHHQVDUHVHWXSWRKDQGOHWKLVIORZUDWH x .HHSVZDEDQGVXUJHSUHVVXUHVORZZKHQWULSSLQJ x 0DNHZLSHUWULSVHYHU\¶XQOHVVKROHFRQGLWLRQVGLFWDWHRWKHUZLVH x 2QWKHVHFRQGZLSHUWULSDURXQG¶0'WULSEDFNWRWKH´VKRHWRVSOLWWKHKROH VHFWLRQLQKDOI x (QVXUHVKDOHVKDNHUVDUHIXQFWLRQLQJSURSHUO\&KHFNIRUKROHVLQVFUHHQVRQFRQQHFWLRQV x $GMXVW0:DVQHFHVVDU\WRPDLQWDLQKROHVWDELOLW\.HHS+7+3IOXLGORVV x 7DNH0:'VXUYH\VHYHU\¶GULOOHG6XUYH\VFDQEHWDNHQPRUHIUHTXHQWO\LIGHHPHG QHFHVVDU\ x 7DNHVHWVRIIRUPDWLRQVDPSOHVHYHU\¶ $VVXPLQJSSJNLFNLQWHQVLW\RYHUPXGZHLJKWEMP 3DJH 9HUVLRQ 2FWREHU IRU 241-01 Drilling Procedure Rev 1 $W7'SXPSVZHHSV&%8DQGSXOODZLSHUWULSEDFNWRWKH´VKRH 72+ZLWKWKHGULOOLQJDVV\VWDQGLQJEDFNGULOOSLSH /'%+$ 58(/LQHDQGSHUIRUPZLUHOLQHORJJLQJSODQ 5'(/LQH38´FOHDQRXW%+$DQG7,+WR7' 3XPSVZHHS&%8DQGFRQGLWLRQPXGIRUFDVLQJUXQ 322+DQG/'%+$ ´[´9%5VSUHYLRXVO\LQVWDOOHGLQ%23VWDFNDQGWHVWHGZLWK´WHVWMRLQW Page 36 Version 0 September, 2021 IRU 241-01 Drilling Procedure Rev 0 19.0 Run 4-1/2” Production Liner 19.1. R/U Weatherford 4-1/2”casing running equipment. x Ensure 4-1/2”DWC/C-HT x CDS 40 crossover on rig floor and M/U to FOSV. x R/U fill up line to fill liner while running. x Ensure all liner has been drifted prior to running. x Be sure to count the total # of joints before running. x Keep hole covered while R/U liner tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 19.2. P/U shoe joint, visually verify no debris inside joint. 19.3. Continue M/U & thread locking shoe track assy consisting of: x (1) Shoe joint w/ shoe bucked on & threadlocked (coupling also thread locked). x (1) Joint with float collar bucked on pin end & threadlocked (coupling also thread locked). x (1) Joint with Baker landing collar bucked on pin end & threadlocked. x Solid body centralizers will be pre-installed on shoe joint an FC joint. x Leave centralizers free floating so that they can slide up and down the joint. x Ensure proper operation of float shoe and float collar. x Utilize a collar clamp until weight is sufficient to keep slips set properly 19.4. Continue running 4-1/2” production liner x Fill liner while running using fill up line on rig floor. x Use “API Modified” thread compound. Dope pin end only w/ paint brush. x Install solid body centralizers on every joint across zones of interest, TBD after LWD. x Install solid body centralizers on every other joint to 7-5/8” shoe. Leave the centralizers free floating. 19.5. Continue running 4-1/2” production liner 4-1/2” 12.6# DWC/C-HT M/U torques Casing OD Minimum Maximum Yield Torque 4-1/2”5,800 ft-lbs 6,500 ft-lbs 9,240 ft-lbs Page 37 Version 0 September, 2021 IRU 241-01 Drilling Procedure Rev 0 Page 38 Version 0 September, 2021 IRU 241-01 Drilling Procedure Rev 0 19.6. Run in hole w/ 4-1/2” liner. 19.7. Fill the liner with fill up line and break circulation every 1,000 feet to the shoe or as the hole dictates. 19.8. Obtain slack off weight, PU weight, rotating weight, and torque of the liner. 19.9. PU 4-1/2”X 7-5/8” Baker liner hanger/LTP assembly. RIH 1 stand and circulate one liner volume to clear string. Obtain slack off weight, PU weight, rotating weight, and torque parameters of the liner. 19.10. Continue to RIH w/liner to shoe. Break circulation every 1,000 feet to the shoe or as the hole dictates. 19.11. Set liner slowly in and out of slips. 19.12. Circulate 2X bottoms up at shoe, ease liner thru shoe. 19.13. Continue running in hole at slow speeds to avoid surging well. Target 20 ft/min and adjust slower as hole conditions dictate. 19.14. Monitor PUW & SOW. Circulate BU if needed. Highlight zones of interest before running past, ex: coals 19.15. Swedge up and wash last stand to bottom. P/U 2-5’ off bottom. Note slack-off and pick-up weights. 19.16. Stage pump rates up slowly to circulating rate. Circ and condition mud with liner on bottom. Circulate 2X bottoms up or until pressures stabilize and mud properties are correct and the shakers are clean. Reduce the low-end rheology of the drilling fluid by adding water and thinners. 19.17. Rotate and reciprocate string if hole conditions allow. Circ until hole and mud is in good condition for cementing. Page 39 Version 0 September, 2021 IRU 241-01 Drilling Procedure Rev 0 20.0 Cement 4-1/2” Production Liner 20.1. Hold a pre-job safety meeting over the upcoming cmt operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud & water can be delivered to the cmt unit at acceptable rates. x Pump 20 bbls of freshwater through all of Halliburton’s equipment, taking returns to cuttings bin, prior to pumping any fluid downhole x How to handle cmt returns at surface, regardless of how unlikely it is that this should occur. x Which pump will be utilized for displacement, and how fluid will be fed to displacement pump. x Positions and expectations of personnel involved with the cmt operation. x Document efficiency of all possible displacement pumps prior to cement job. 20.2. Attempt to rotate and reciprocate the liner during cmt operations until hole gets sticky 20.3. Pump 5 bbls of 12.5 ppg Mud Push spacer. 20.4. Test surface cmt lines to 4500 psi. 20.5. Pump remaining 12.5 ppg Mud Push spacer. 20.6. Mix and pump lead and tail cement per below recipe. Ensure cement is pumped at designed weight. Job is designed to pump 40% OH excess. Estimated Total Cement Volume: Section:Calculation:Vol (BBLS)Vol (ft3) 12.0 ppg LEAD: 7-5/8” csg x 4-1/2” drillpipe annulus: 200’ x .02624 bpf =5.25 29.5 12.0 ppg LEAD: 7-5/8” csg x 4-1/2” liner annulus: 200’ x .02624 bpf =5.25 29.5 12.0 ppg LEAD: 6-3/4” OH x 4-1/2” annulus: (9054’ –5981’) x .02459 bpf x 1.4 = 105.79 594.0 Total LEAD:116.29 bbl 653.0 ft3 15.4 ppg TAIL: 6-3/4” OH x 4-1/2” annulus: (9554’- 9054’) x .02459 bpf x 1.4 = 17.21 96.6 15.4 ppg TAIL: 4-1/2” Shoe track: 80 x .01522 bpf =1.22 6.8 Total TAIL:18.43 bbl 103.5 ft3 TOTAL CEMENT VOL:134.72 bbl 756.5 ft3 Verified Cement calcs - bjm p pump 40% OH excess. Page 40 Version 0 September, 2021 IRU 241-01 Drilling Procedure Rev 0 Cement Slurry Design: 20.7. Drop drillpipe dart and displace with drilling mud. If hole conditions allow –continue rotating and reciprocating liner throughout displacement. This will ensure a high quality cement job with 100% coverage around the pipe. 20.8. Displace cement at max rate of 5 bbl/min. Reduce pump rate to 2-3 bpm prior to latching DP dart into liner wiper plug. Note plug departure from liner hanger running tool and resume pumping at full displacement rate. Displacement volume can be re-zeroed at this point. 20.9. If elevated displacement pressures are encountered, position casing at setting depth and cease reciprocation. Monitor returns & pressure closely while circulating. Notify Drilling Foreman immediately of any changes. 20.10. Bump the plug and pressure up to up as required by Baker procedure to set the liner hanger (ensure pressure is above nominal setting pressure, but below pusher tool activation pressure). Hold pressure for 3-5 minutes. 20.11. Slack off total liner weight plus 30k to confirm hanger is set. 20.12. Do not overdisplace by more than ½ shoe track. Shoe track volume is 1.2 bbls. 20.13. Bleed pressure to zero to check float equipment. Watch for flow. Note amount of fluid returned after bumping plug and releasing pressure. 20.14. Pick up to expose dogs and set liner top packer. Lead Slurry (9054’ MD to 5781’ MD)Tail Slurry (9554’ to 9054’ MD) System Extended Conventional Density 12 lb/gal 15.4 lb/gal Yield 2.4 ft3/sk 1.24 ft3/sk Mixed Water 14.09 gal/sk 5.58 gal/sk Mixed Fluid 14.09 gal/sk 5.58 gal/sk Additives Code Description Code Description Type I/II Cement CLASS A Type I/II Cement CLASS A Halad-344 Fluid Loss Halad-344 Fluid Loss HR-5 Retarder HR-5 Retarder D-Air 5000 Anti Foam CFR-3 Dispersant Econolite Light-weight add.UCS Slurry Conditioner SA-1015 Suspension Agent Super CBL Anti-Gas Migration BridgeMaker II Lost Circulation Page 41 Version 0 September, 2021 IRU 241-01 Drilling Procedure Rev 0 20.15. Pressure up drill pipe to 500 psi and pick up to remove the RS packoff bushing from the RS nipple. Bump up pressure as req’d to maintain 500 psi DP pressure while moving pipe until the pressure drops rapidly, indicating pack-off is above the sealing area (ensure that 500 psi will be enough to overcome hydrostatic differential at liner top). 20.16. Immediately with the loss of pressure and before DP reaches zero, initiate circulation while picking up to position the bottom of the stinger inside the tieback sleeve. Increase pump rate to wellbore clean up rate until the sleeve area is thoroughly cleaned. 20.17. Pick up to the high-rate circulation point above the tieback extension, mark the pipe for reciprocation, do not re-tag the liner top, and circulate the well clean. Watch for cement returns and record the estimated volume. Rotate & circulate to clear cmt from DP. 20.18. RD cementers and flush equipment. POOH, LDDP and running tool. Verify the liner top packer received the required setting force by inspecting the rotating dog sub. Backup release from liner hanger: 20.19. If the HRD-E tool still does not release hydraulically, left-hand (counterclockwise) torque will have to be applied to the tool. This torque acts to shear brass screws. Bleed off pump pressure and ensure that the tool is in the neutral position. Apply left-hand torque as required to shear screws. 20.20.NOTE: Some hole conditions may require movement of the drillpipe to “work” the torque down to the setting tool. 20.21. After screws have sheared, the top sub and body of the setting tool will turn 1/4 turn. Then proceed slacking off set-down weight to shear second set of shear screws. The top sub will drop 1-3/4 inches. At this point, the bottom sub no longer supports the collet fingers. Pick straight up with workstring to release collet from the profile. 20.22. WOC minimum of 12 hours, test liner to 3500 psi and chart for 30 minutes. Page 42 Version 0 September, 2021 IRU 241-01 Drilling Procedure Rev 0 Ensure to report the following on wellez: x Pre flush type, volume (bbls) & weight (ppg) x Cement slurry type, lead or tail, volume & weight x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid x Note if liner is reciprocated or rotated during the job x Calculated volume of displacement , actual displacement volume, whether plug bumped & bump pressure, do floats hold x Percent mud returns during job. If intermittent, note timing during pumping of job. Final circulating pressure x Note if pre flush or cement returns at surface & volume x Note time cement in place x Note calculated top of cement x Add any comments which would describe the success or problems during the cement job Send final “As-Run” liner tally & liner and cement report to cdinger@hilcorp.com and Frank.Roach@hilcorp.com. This will be included with the EOW documentation that goes to the AOGCC. Page 43 Version 0 September, 2021 IRU 241-01 Drilling Procedure Rev 0 21.0 4-1/2”Liner Tieback Polish Run and Cleanout Run 21.1. PU liner tieback polish mill assy per Baker rep and RIH on drillpipe. 21.2. RIH to top of liner assembly and establish parameters. Polish tieback receptacle per Baker procedure. 21.3. POOH, and LD polish mill. 21.4. M/U casing clean out assy complete with casing scraper assys for each size casing in the hole. x 3-1/2” bit or mill x Casing scraper & brush for 4-1/2” 12.6# tubulars x +/- 3600’ 2-7/8” PH-6 workstring. x Casing scraper & brush for 7-5/8” 29.7# casing x 4-1/2” DP to surface. 21.5. TIH & clean out well to landing collar (+/- 9,474’MD). x Circulate as needed on trip in if string begins to take weight. x Circulate hi-vis sweeps as necessary to carry debris out of wellbore. x Ensure 3-1/2” bit is worked down to the landing collar. x Space out the cleanout BHA so that the 3-1/2” bit reaches the 4-1/2” landing collar when crossover/7-5/8” casing scraper is +/-30’ above the 4-1/2” liner top. 21.6. After wellbore has been cleaned out satisfactorily using mud, test 7-5/8” casing/ 4-1/2” liner envelope to 3500 psi / 30 min. Ensure to chart record casing test. 21.7. Displace drilling fluid in wellbore with a hi-vis pill followed by 6% KCl completion fluid. 21.8. Once completion fluid is fully swapped, shut down and monitor well for 30 min to confirm no- flow. 21.9. POOH, LDDP and workstring. Clean and clear rig floor in preparation for running tieback. Monitor returns to verify 1:1 returns while displacing to underbalanced fluid. bjm Displace drilling fluid in wellbore with a hi-vis pill followed by 6% KCl completion flu test 7-5/8” casing/ 4-1/2”liner envelope to 3500 psi / 30 min. Page 44 Version 0 September, 2021 IRU 241-01 Drilling Procedure Rev 0 22.0 4-1/2”Tieback Run 22.1 PU 4-1/2”tieback assembly and RIH with 4-1/2” 17# L-80 CDC HTQ casing. 22.2 No-go tieback seal assembly in liner PBR and mark pipe. PU pup joint(s) if necessary to space out tieback seals in PBR. 22.3 PU hanger and land string in hanger bowl. Note distance of seals from no-go. 22.4 Install packoff and test hanger void. 22.5 Test 4-1/2”liner and tieback to 3,500 psi and chart for 30 minutes. 22.6 Test 7-5/8” x 4-1/2” annulus to 2,500 psi and chart for 30 minutes. 23.0 RDMO 23.1 Install BPV in wellhead 23.2 N/D BOPE 23.3 N/U dry-hole tree or (if space permitting) full tree and test to 5,000 psi. 23.4 RDMO Hilcorp Rig #147 MITIA to 3000 psi. Provide 48 hrs notice to AOGCC inspectors to witness MIT-T and MIT-IA. bjm Page 45 Version 0 September, 2021 IRU 241-01 Drilling Procedure Rev 0 24.0 Diverter Schematic 16'’ Hydril V 4.30'Hydril MSP 21-¼ 2M .50' 4.00' 2.67' 1.33' 4.37' Grade Level 3.09' DSA16¾3MX21¼2M 21 ¼ 2M Spool 21 ¼ 2M Diverter Tee 16'’150 outlet 4.08' 16'’ casing cut @64'’ below ground level .42' Page 46 Version 0 September, 2021 IRU 241-01 Drilling Procedure Rev 0 25.0 BOP Schematic Page 47 Version 0 September, 2021 IRU 241-01 Drilling Procedure Rev 0 26.0 Wellhead Schematic Page 48 Version 0 September, 2021 IRU 241-01 Drilling Procedure Rev 0 27.0 Days Vs Depth Page 49 Version 0 September, 2021 IRU 241-01 Drilling Procedure Rev 0 28.0 Geo-Prog Page 50 Version 0 September, 2021 IRU 241-01 Drilling Procedure Rev 0 29.0 Anticipated Drilling Hazards 13-1/2” Hole Section: Lost Circulation: Ensure 500 lbs of medium/coarse fibrous material & 500 lbs different sizes of Calcium Carbonate are available on location to mix LCM pills at moderate product concentrations. Hole Cleaning: Maintain rheology w/ gel and gel extender. Sweep hole with gel or flowzan sweeps as necessary. Optimize solids control equipment to maintain density, sand content, and reduce the waste stream. Maintain YP between 25 –45 to optimize hole cleaning and control ECD. Wellbore stability: Lithology through this zone is a composite of pebble conglomerate and sand in the upper intervals with intermittent clay matrix. Carbonaceous material and coal may be noted. Gravel sizes that are larger than normal can cause hole-cleaning problems. If encountered, be prepared to increase the viscosity. Excessive quantities of gravel and sand may indicate wellbore instability. Increase properties up to a YP of ~50 -~60 lbs/100ft2 to combat this issue. Maintain low flow rates for the initial 200’ of drilling to reduce the likelihood of washing out the conductor shoe. To help insure good cement to surface after running the casing, condition the mud to a YP of 25 –30 prior to cement operations. Do not lower the YP beyond 25 to avoid trouble with sands that may be found on this well. Have Desco DF, SAPP, and water on hand to ensure the desired rheologies can be achieved. H2S: H2S is not present in this hole section. No abnormal pressures or temperatures are present in this hole section. Page 51 Version 0 September, 2021 IRU 241-01 Drilling Procedure Rev 0 9-7/8”Hole Section: Lost Circulation: Ensure 500 lbs of medium/coarse fibrous material & 500 lbs different sizes of Calcium Carbonate are available on location to mix LCM pills at moderate product concentrations. Given the distance from support and the potential low pressure across injection zones, ensure all LCM inventory is fully stocked before drilling out surface casing. Hole Cleaning: Maintain rheology w/ viscosifier as necessary. Sweep hole w/ 20 bbls hi-vis pills as necessary. Optimize solids control equipment to maintain density and minimize sand content. Maintain YP between 20 - 30 to optimize hole cleaning and control ECD. Wellbore stability: Maintain MW as necessary using additions of Calcium Carbonate as weighting material. A torque reduction lube may be used in this hole section in concentrations up to 3% if needed. Maintain 6% KCl in system for shale inhibition. Coal Drilling: The following lessons were learned from extensive experience drilling coal seams in Cook Inlet. The need for good planning and drilling practices is also emphasized as a key component for success. x Keep the drill pipe in tension to prevent a whipping effect which can disturb coal sections. x Use asphalt-type additives to further stabilize coal seams. x Increase fluid density as required to control running coals. x Emphasize good hole cleaning through hydraulics, ROP and system rheology. H2S: H2S is not present in this hole section. No abnormal pressures or temperatures are present in this hole section. Page 52 Version 0 September, 2021 IRU 241-01 Drilling Procedure Rev 0 6-3/4” Hole Section: Lost Circulation: Ensure 1000 lbs of each of the different sizes of Calcium Carbonate are available on location to mix LCM pills at moderate product concentrations. Given the potential low pressure in the Beluga A5, B1, B2, and C1, ensure all LCM inventory is fully stocked before drilling out surface casing. Hole Cleaning: Maintain rheology w/ viscosifier as necessary. Sweep hole w/ 20 bbls hi-vis pills as necessary. Optimize solids control equipment to maintain density and minimize sand content. Maintain YP between 20 - 30 to optimize hole cleaning and control ECD. Wellbore stability: Maintain MW as necessary using additions of Calcium Carbonate as weighting material. A torque reduction lube may be used in this hole section in concentrations up to 3% if needed. Maintain 6% KCl in system for shale inhibition. Coal Drilling: The following lessons were learned from extensive experience drilling coal seams in Cook Inlet. The need for good planning and drilling practices is also emphasized as a key component for success. x Keep the drill pipe in tension to prevent a whipping effect which can disturb coal sections. x Use asphalt-type additives to further stabilize coal seams. x Increase fluid density as required to control running coals. x Emphasize good hole cleaning through hydraulics, ROP and system rheology. H2S: H2S is not present in this hole section. No abnormal temperatures are present in this hole section. potential low pressure in the Beluga A5, B1, B2, and C1, Page 53 Version 0 September, 2021 IRU 241-01 Drilling Procedure Rev 0 30.0 Hilcorp Rig 147 Layout Page 54 Version 0 September, 2021 IRU 241-01 Drilling Procedure Rev 0 31.0 FIT/LOT Procedure Formation Integrity Test (FIT) and Leak-Off Test (LOT) Procedures Procedure for FIT: 1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe). 2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe. 3. Close the blowout preventer (ram or annular). 4. Pump down the drill stem at 1/4 to 1/2 bpm. 5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe. 6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes. Record time vs. pressure in 1-minute intervals. 7. Bleed the pressure off and record the fluid volume recovered. The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick tolerance in case well control measures are required. Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid; at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure monitored as with an FIT. Page 55 Version 0 September, 2021 IRU 241-01 Drilling Procedure Rev 0 32.0 Choke Manifold Schematic Page 56 Version 0 September, 2021 IRU 241-01 Drilling Procedure Rev 0 33.0 Casing Design Information Page 57 Version 0 September, 2021 IRU 241-01 Drilling Procedure Rev 0 34.0 9-7/8”Hole Section MASP Page 58 Version 0 September, 2021 IRU 241-01 Drilling Procedure Rev 0 35.0 6-3/4” Hole Section MASP Page 59 Version 0 September, 2021 IRU 241-01 Drilling Procedure Rev 0 36.0 Spider Plot (Governmental Sections) Page 60 Version 0 September, 2021 IRU 241-01 Drilling Procedure Rev 0 37.0 Surface Plat (As-Staked NAD27) 6WDQGDUG3URSRVDO5HSRUW 6HSWHPEHU 3ODQ,58ZS +LOFRUS$ODVND//& %HOXJD5LYHU1RUWK ,YDQ5LYHU 3ODQ,58 ,58 0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000 6500 7000 7500True Vertical Depth (1000 usft/in)-1000 -500 0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000 Vertical Section at 2.20° (1000 usft/in) IRU Shute wp03 Target #1 IRU Shute wp03 Target #2 10 3/4" x 13 1/2" 7 5/8" x 9 7/8" 4 1/2" x 6 3/4" 5 0 0 1 0 0 0 15 0 0 2 0 0 0 2 5 0 0 3 0 00 3 5 0 0 40 0 0 4 5 0 0 5 0 0 0 5 5 0 0 600 06 5 0 0 7 0 0 0 7 5 0 0 8 0 0 0 8 5 0 0 9 0 0 0 9 5 0 0 9 5 5 4 IRU 241-01 wp06 Start Dir 3º/100' : 200' MD, 200'TVD End Dir : 1534.71' MD, 1435.06' TVD Start Dir 3º/100' : 5467.01' MD, 4495.35'TVD End Dir : 6863.83' MD, 5602.24' TVD Total Depth : 9554.32' MD, 7720' TVD Top 14-31 Injection Zone Bottom 14-31 Injection Zone Top 13-31 Injection Zone Bottom 13-31 Injection Zone ST_X2_Coal (Top Coal) Lower Sterling (Base Coal) ST_A1 ST_A5 ST_B1 ST_B2 BEL_C1 BEL_D1 BEL_H15 BEL_I BEL_I15 Hilcorp Alaska, LLC Calculation Method:Minimum Curvature Error System:ISCWSA Scan Method: Closest Approach 3D Error Surface: Ellipsoid Separation Warning Method: Error Ratio WELL DETAILS: Plan: IRU 241-01 30.20 +N/-S +E/-W Northing Easting Latitude Longitude 0.00 0.00 2646285.80 359830.90 61° 14' 26.4649 N 150° 47' 44.5043 W SURVEY PROGRAM Date: 2021-07-08T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 18.50 3474.00 IRU 241-01 wp06 (IRU 241-01) 3_MWD+AX+Sag 3474.00 6101.00 IRU 241-01 wp06 (IRU 241-01) 3_MWD+AX+Sag 6101.00 9554.32 IRU 241-01 wp06 (IRU 241-01) 3_MWD+AX+Sag FORMATION TOP DETAILS TVDPath TVDssPath MDPath Formation 2626.70 2578.00 3065.90 Top 14-31 Injection Zone 3074.70 3026.00 3641.55 Bottom 14-31 Injection Zone 4279.70 4231.00 5189.91 Top 13-31 Injection Zone 4688.70 4640.00 5713.35 Bottom 13-31 Injection Zone 4850.70 4802.00 5918.50 ST_X2_Coal (Top Coal) 4876.70 4828.00 5951.49 Lower Sterling (Base Coal) 4938.70 4890.00 6030.37 ST_A1 5109.70 5061.00 6247.08 ST_A5 5154.70 5106.00 6303.50 ST_B1 5171.70 5123.00 6324.77 ST_B2 5279.70 5231.00 6459.53 BEL_C1 5395.70 5347.00 6604.14 BEL_D1 7006.70 6958.00 8648.12 BEL_H15 7189.70 7141.00 8880.61 BEL_I 7626.70 7578.00 9435.79 BEL_I15 REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Plan: IRU 241-01, True North Vertical (TVD) Reference:IRU 241-01 As Staked @ 48.70usft Measured Depth Reference:IRU 241-01 As Staked @ 48.70usft Calculation Method:Minimum Curvature Project:Beluga River North Site:Ivan River Well:Plan: IRU 241-01 Wellbore:IRU 241-01 Design:IRU 241-01 wp06 CASING DETAILS TVD TVDSS MD Size Name 2944.30 2895.60 3474.00 10-3/4 10 3/4" x 13 1/2" 4994.07 4945.37 6101.00 7-5/8 7 5/8" x 9 7/8" 7720.00 7671.30 9554.32 4-1/2 4 1/2" x 6 3/4" SECTION DETAILS Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation 1 18.50 0.00 0.00 18.50 0.00 0.00 0.00 0.00 0.00 2 200.00 0.00 0.00 200.00 0.00 0.00 0.00 0.00 0.00 Start Dir 3º/100' : 200' MD, 200'TVD 3 550.00 10.50 0.00 548.04 31.98 0.00 3.00 0.00 31.96 4 1534.71 38.90 336.30 1435.06 413.30 -127.08 3.00 -30.79 408.13 End Dir : 1534.71' MD, 1435.06' TVD 5 5467.01 38.90 336.30 4495.35 2674.45 -1119.48 0.00 0.00 2629.60 Start Dir 3º/100' : 5467.01' MD, 4495.35'TVD 6 6061.39 38.50 5.00 4963.00 3032.53 -1178.84 3.00 102.54 2985.15 IRU Shute wp03 Target #1 7 6863.83 38.08 44.33 5602.24 3464.76 -981.24 3.00 106.61 3424.63 End Dir : 6863.83' MD, 5602.24' TVD 8 9427.28 38.08 44.33 7620.00 4595.84 123.56 0.00 0.00 4597.20 IRU Shute wp03 Target #2 9 9554.32 38.08 44.33 7720.00 4651.90 178.31 0.00 0.00 4655.31 Total Depth : 9554.32' MD, 7720' TVD 0 325 650 975 1300 1625 1950 2275 2600 2925 3250 3575 3900 4225 4550 4875 5200 5525 South(-)/North(+) (650 usft/in)-2600 -2275 -1950 -1625 -1300 -975 -650 -325 0 325 650 975 1300 1625 West(-)/East(+) (650 usft/in) IRU Shute wp03 Target #2 IRU Shute wp03 Target #1 10 3/4" x 13 1/2" 7 5/8" x 9 7/8" 4 1/2" x 6 3/4" 500 1 0 0 0 1 2 5 0 1 5 0 0 1 7 5 0 2 0 0 0 2 2 5 0 2 5 0 0 2 7 5 0 3 0 0 0 3 2 5 0 3 5 0 0 3 7 5 0 4 0 0 0 4 2 5 0 4 5 0 0 4 7 5 0 5000 5250 5 5 0 0 5 7 5 0 6 0 0 0 6 2 5 0 6 5 0 0 6 7 5 0 7 0 0 0 7 2 5 0 7 5 0 0 7 7 2 0 I R U 2 4 1-0 1 w p 0 6 Start Dir 3º/100' : 200' MD, 200'TVD End Dir : 1534.71' MD, 1435.06' TVD Start Dir 3º/100' : 5467.01' MD, 4495.35'TVD End Dir : 6863.83' MD, 5602.24' TVD Total Depth : 9554.32' MD, 7720' TVD CASING DETAILS TVD TVDSS MD Size Name 2944.30 2895.60 3474.00 10-3/4 10 3/4" x 13 1/2" 4994.07 4945.37 6101.00 7-5/8 7 5/8" x 9 7/8" 7720.00 7671.30 9554.32 4-1/2 4 1/2" x 6 3/4" Project: Beluga River North Site: Ivan River Well: Plan: IRU 241-01 Wellbore: IRU 241-01 Plan: IRU 241-01 wp06 WELL DETAILS: Plan: IRU 241-01 30.20 +N/-S +E/-W Northing Easting Latitude Longitude 0.00 0.00 2646285.80 359830.90 61° 14' 26.4649 N 150° 47' 44.5043 W REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Plan: IRU 241-01, True North Vertical (TVD) Reference: IRU 241-01 As Staked @ 48.70usft Measured Depth Reference:IRU 241-01 As Staked @ 48.70usft Calculation Method:Minimum Curvature 3URMHFW &RPSDQ\ /RFDO&RRUGLQDWH5HIHUHQFH 79'5HIHUHQFH 6LWH +LOFRUS$ODVND//& %HOXJD5LYHU1RUWK ,YDQ5LYHU 6WDQGDUG3URSRVDO5HSRUW :HOO :HOOERUH 3ODQ,58 ,58 6XUYH\&DOFXODWLRQ0HWKRG0LQLPXP&XUYDWXUH ,58$V6WDNHG#XVIW 'HVLJQ,58ZS 'DWDEDVH1257+86&$1$'$ 0'5HIHUHQFH,58$V6WDNHG#XVIW 1RUWK5HIHUHQFH :HOO3ODQ,58 7UXH 0DS6\VWHP *HR'DWXP 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eparation Factor0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000 6500 7000 7500 8000 8500 9000 9500Measured Depth (1000 usft/in)IRU 44-36IRU 14-31No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.WELL DETAILS:Plan: IRU 241-01 NAD 1927 (NADCON CONUS)Alaska Zone 0430.20+N/-S +E/-W Northing EastingLatitudeLongitude0.000.002646285.80 359830.9061° 14' 26.4649 N 150° 47' 44.5043 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: IRU 241-01, True NorthVertical (TVD) Reference: IRU 241-01 As Staked @ 48.70usftMeasured Depth Reference:IRU 241-01 As Staked @ 48.70usftCalculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2021-07-08T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool18.50 3474.00 IRU 241-01 wp06 (IRU 241-01) 3_MWD+AX+Sag3474.00 6101.00 IRU 241-01 wp06 (IRU 241-01) 3_MWD+AX+Sag6101.00 9554.32 IRU 241-01 wp06 (IRU 241-01) 3_MWD+AX+Sag0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000 6500 7000 7500 8000 8500 9000 9500Measured Depth (1000 usft/in)IRU 11-06IRU 13-31IRU 44-01IRU 44-36IRU 23-12GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference18.50 To 9554.32Project: Beluga River NorthSite: Ivan RiverWell: Plan: IRU 241-01Wellbore: IRU 241-01Plan: IRU 241-01 wp06Ladder / S.F. PlotsCASING DETAILSTVD TVDSS MD Size Name2944.30 2895.60 3474.00 10-3/4 10 3/4" x 13 1/2"4994.07 4945.37 6101.00 7-5/8 7 5/8" x 9 7/8"7720.00 7671.30 9554.32 4-1/2 4 1/2" x 6 3/4" 1 Carlisle, Samantha J (CED) From:McLellan, Bryan J (CED) Sent:Thursday, October 7, 2021 8:46 AM To:Frank Roach Subject:RE: [EXTERNAL] IRU 241-01 PTD - mud weight Frank, Thanksforupdatingtheprogram.IamplanningtojustannotatethePrograminthePTDwiththesechangeshighlighted inyellow.Doesthatworkforyou? Onthesurfacehole,Idon’tthinkyoucanleaveittothediscretionoftheCompanymanastowhenheweightsupfrom 8.8to9.3ppg.Hehasnowayofknowinghowmuchoverbalancehehasunlessthewellstartsflowing.Ifthathappens, sincehe’sondiverter,there’snotmuchhecando,exceptpumplikehellandtrytouseECDtokeepthewellfrom flowinguntilhegetsheaviermudinthepits. YourGeoorREshouldprovideyouanduswithporepressureestimatesacrosstheentiresurfaceholesectionsoyoucan decidewhentoweightup.Orjustkeepitsimpleanddrilltheentiresectionwith9.3ppgmud. Givemeacallifyouwanttodiscussorsuggestadifferentapproach. BryanMcLellan SeniorPetroleumEngineer AlaskaOil&GasConservationCommission 333W7thAve Anchorage,AK99501 Bryan.mclellan@alaska.gov +1(907)250Ͳ9193 From:FrankRoach<Frank.Roach@hilcorp.com> Sent:Wednesday,October6,20213:21PM To:McLellan,BryanJ(CED)<bryan.mclellan@alaska.gov> Subject:RE:[EXTERNAL]IRU241Ͳ01PTDͲmudweight Bryan, Thankyouforthosecommentsandyou’reabsolutelyright. Forthesurfacehole,theplannedmudweightrange8.8ppgto9.5ppg.Step11.4hadabulletpointto“Adjustingmud weightasnecessarytomaintainholestability”.Thishasbeeneditedtoincludemaintainingoverbalance.Alsoaddedwas anotherbullettohavethemudweightuptoatleast9.3ppgpriortoTD. Forthesubsequentholesections,minimummudweighthasbeenincreasedfromthe9.0ppgto9.3ppgtoprovidethat overbalanceandtripmargin. Attachedisarevisedprogram,withtheabovechangeshighlightedinyellow(pages14,22Ͳ24,and33Ͳ34). Thanksagainforthecatch. Regards, 2 FrankVRoach DrillingEngineer 907.854.2321(c) 907.777.8413(o) From:McLellan,BryanJ(CED)<bryan.mclellan@alaska.gov> Sent:Tuesday,October5,202116:24 To:FrankRoach<Frank.Roach@hilcorp.com> Subject:[EXTERNAL]IRU241Ͳ01PTDͲmudweight Frank, I’mreviewingthePTDforthiswellandhadacouplequestions 1.Geoprognosis in section 28 indicates formation pressures of 9.0 ppg EMW just below planned surface casing shoe depth. Surface hole pore pressure prognosis is not included. Surface hole spud mud is planned at 8.8 ppg. Need to transition to higher mud weight for surface hole at some depth. 2.For the 9.75” hole section, Geoprog is 9.0 ppg and mud is 9.0 ppg. Need some overbalance. 3.Same for the 6.75” hole section. Need some overbalance. BryanMcLellan SeniorPetroleumEngineer AlaskaOil&GasConservationCommission 333W7thAve Anchorage,AK99501 Bryan.mclellan@alaska.gov +1(907)250Ͳ9193 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 1 Carlisle, Samantha J (CED) From:McLellan, Bryan J (CED) Sent:Thursday, October 14, 2021 8:42 AM To:Frank Roach Subject:RE: Surface Mud Weights/Pressures IRU 241-01 PTD Thanksfortrackingthisdown.Iagreewithyourupdatedplannedmudweightinsurfacehole,aswellasthepreviously agreedmudweightforthetwodeeperholesections. Matchingthemudweightinthesurfaceholetothatinthecloseoffsetwellsprovidesreasonableassurancethatyour mudweightwillbeabovetheporepressureinIRU241Ͳ01. I’llmakenoteofitontheprocedurethatwasincludedwithyourPTDapplication. Regards BryanMcLellan SeniorPetroleumEngineer AlaskaOil&GasConservationCommission 333W7thAve Anchorage,AK99501 Bryan.mclellan@alaska.gov +1(907)250Ͳ9193 From:FrankRoach<Frank.Roach@hilcorp.com> Sent:Wednesday,October13,20213:57PM To:McLellan,BryanJ(CED)<bryan.mclellan@alaska.gov> Subject:SurfaceMudWeights/PressuresIRU241Ͳ01PTD Bryan, Asdiscussed,belowistheresponsereceivedfrommygeologistandRE.WhileIdonothaveanymeasuredpressuredata fromtheoffsetwellsinsurfacehole,dohavethemorningreportsfromChevron’s11Ͳ06surfaceandintermediateholes. Theyspuddedwithan8.7ppgmud,upto9.0ppgat837’,andwereata9.1ppgmudweightatourplannedsurface casingpoint.NoissueswerenotedinChevron’smorningreportswhiledrillingthisfootage. Myplanistospudwitha9.0ppgmudandhavethesystemupto9.3ppg~100’beforeTDtomakesurewe’recovered forthe14Ͳ31injectionzonefromtheGeoprogifformationtopscomeinshallow(notexpectedduetoouroffset difference).Ipulledoutthepagesfromthesurfacesectionsoyoucanseehowit’swrittenintheprogramfortherig team. ThanksforyourpatiencewhileIgotthisrundownandletmeknowifyouneedanythingadditional. Regards, FrankVRoach DrillingEngineer 907.854.2321(c) 907.777.8413(o) 2 From:MatthewPetrowsky<mpetrowsky@hilcorp.com> Sent:Wednesday,October13,202114:31 To:FrankRoach<Frank.Roach@hilcorp.com>;AnthonyMcConkey<amcconkey@hilcorp.com> Subject:IRU241Ͳ01–surfacepressures HeyFrank, Aswediscussed,abovetheshallowestinjectionzone(14Ͳ31)theformationpressuregradientisassumedtobeawater gradient(0.45psi/ft.).Thisisbecausewedon’thaveanypressuredatasuggestinganythingunder/overpressure.Not onlythat,butthisgradientisalsoinlinewithwhatthemostrecentdrillwell(11Ͳ06)encounteredbackin2009.Letme knowifyouhaveanyquestions.Thanks! Best Regards, Matthew J. Petrowsky |Geologist, Kenai Team|Hilcorp Alaska, LLC|(w) 907.777.8404|(c) 814.421.6753|Office: 13150| |3800 Centerpoint Dr. Suite 1400|Anchorage|Alaska|99503| The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. Revised 2/2015 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 No. _____________, API No. 50-_______________________. Production should continue to be reported as a function of the original API number stated above. Pilot Hole In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well name (_______________________PH) and API number (50-_____________________) from records, data and logs acquired for well (name on permit). Spacing Exception The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce/inject is contingent upon issuance of a conservation order approving a spacing exception. (_____________________________) as 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' sample intervals from below the permafrost or from where samples are first caught and 10' 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 well ( ) until after ( ) has designed and implemented a water well testing program to provide baseline data on water quality and quantity. (________________________) must contact the AOGCC to obtain advance approval of such 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 (_______________________________) 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 well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. 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