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Home My WebLink About223-1001. 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): 4,100' N/A Casing Collapse Structural Conductor 1,410psi Surface 4,790psi Intermediate Production 10,540psi 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: Ryan Lemay, Operations Engineer Contact Email:ryan.lemay@hilcorp.com Contact Phone: 661-487-0871 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 Other: N2 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 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 FEDA028399 223-100 50-133-20715-00-00 Hilcorp Alaska, LLC Proposed Pools: 9.2# / L-80 TVD Burst 2,531' 10,160psi 2,554' Size 120' 2,738' MD See Attached Schematic 2,980psi 6,890psi 120'120' 2,738' February 24, 2026 Tieback 3-1/2" 4,099' Perforation Depth MD (ft): 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Swanson River Unit (SRU) 222-33CO 716A Same 3,885'3-1/2" ~973psi 1,576' See Schematic Length Liner Top Pkr; N/A 2,523' MD/2,349' TVD; N/A 3,886' 3,175' 2,980' Swanson River Sterling-Upper Beluga Gas 16" 7-5/8" See Attached Schematic No Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2026.02.10 15:37:16 - 09'00' Noel Nocas (4361) 326-082 By Grace Chistianson at 7:27 am, Feb 11, 2026 SFD 2/11/2026 Perforate 10-404 DSR-2/12/26BJM 2/12/26JLC 2/12/2026 02/12/26 Well Prognosis Well: SRU 222-33 Well Name: SRU 222-33 API Number: 50-133-20715-00-00 Current Status: Producing Gas Well Permit to Drill Number: 223-100 Regulatory Contact: Donna Ambruz (907) 777-8305 First Call Engineer: Ryan LeMay (661)487-0871 (M) Second Call Engineer: Chad Helgeson (907) 777-8405 (O)(907) 229-4824 (C) Maximum Expected BHP: 1259 psi @ 2861 TVD Based on 0.44 psi/ft Max. Potential Surface Pressure: 973 psi Based on 0.1 psi/ft gas gradient to surface Applicable Frac Gradient: 0.70 psi/ft using 13.5 ppg EMW FIT at the 7-5/8 surface casing shoe Shallowest Allowable Perf TVD: MPSP/(0.70-0.1) = 973 psi / 0.60 = 1622 TVD Top of Applicable Gas Pool / PA: 2482 MD / 2311 TVD (Sterling / Upper Beluga) Recent Well History Summary: In December of 2025, the ST_B3 (3,141 3,144) interval was perforated and initial production came on at 2886 mcfd / 0 bwpd / 991 psi FTP. However, within 30 days of production from this zone, water production sharply increased and gas rate began to decrease sharply as well. By the beginning of February 2026, gas rate had fallen off to 500-600 mcfd / 1000+ bwpd / 140 psi FTP before ultimately watering out and ceasing to sustain gas production. The purpose of this Sundry is to plug and isolate the currently open ST_B3 interval and add additional perforations in the ST_A12 ST_B2 sands. Notes Regarding Wellbore Condition Inclination o Max deviation of 30.3° @ 1,667 MD o Max DLS of 3.99°/ 100 @ 1,086 MD Procedure: 1. MIRU E-line and pressure control equipment 2. PT lubricator to 250 psi low / 2,000 psi high 3.RIH and set CIBP at + 3,091 (50 above current perforations ST_B3 3,141 3,144) 4. RIH and perforate ST_B2 ST_A12 from bottom up. Below are proposed targeted sands in order of testing (bottom/up), but additional sand may be added depending on results of these perfs, between the proposed top and bottom perfs Sand Top MD Btm MD Top TVD Btm TVD Interval ST_A12 ±2,738' ±2,749' ±2,554' ±2,565' ±11' ST_A13 ±2,825' ±2,838' ±2,639' ±2,642' ±9' ST_A14 ±2,842' ±2,848' ±2,656' ±2,660' ±6' ST_A14 ±2,861' ±2,871' ±2,673' ±2,683' ±10' ST_B1 ±2,925' ±2,956' ±2,735' ±2,766' ±31' ST_B2 ±3,026' ±3,053' ±2,833' ±2,861' ±27' additional sand may be added depending on results of these perfs Approval in advance from AOGCC is required. SFD Well Prognosis Well: SRU 222-33 a. Correlate using Open Hole Correlation Log provided by Geologist. Send the correlation pass to the Operations Engineer, Reservoir Engineer, and Geologist for confirmation b. Use Gamma/CCL to correlate c. Record Tubing pressures before and after each perforating run at 5 min, 10 min, and 15 min intervals post perf shot (if using switched guns, wait 10 min between shots) d. Pending well production, all perf intervals may not be completed e. If any current or proposed zone produces sand and/or water or needs isolated, RIH and set plug above the perforations OR patch across the perforations i. Note: A CIBP may be used instead of WRP if it is determined that no cement is needed for operational purposes. 35ft will not be placed on each plug as these zones are close together in the same pool / PA. If possible, the CIBP will be set 50 above of the top of the last perforated sand unless zones are too close together in which case the plug will be set within 50. f. If necessary, use high pressure pad gas or N2 to pressure up well during perforating or to depress water prior to setting a plug above perforations. 5. RDMO Contingency Procedure: Coiled Tubing Cleanout 1. If throughout the job any current or proposed zones produce sand and / or water that cannot be depressed and pushed away with nitrogen or high-pressure pad gas, a coil tubing unit may be rigged up to clean out fill or fluid blown down as necessary. a. MIRU CTU, PT BOPE to 250 psi low / 2000 psi high i. Provide AOGCC 24hrs notice of BOP test. b. Cleanout wellbore fill and / or blowdown well with nitrogen if necessary. Attachments: 1. Current Schematic 2. Proposed Schematic 3. Standard Well Procedure N2 Operations 4. Coil Tubing BOP Diagrams (Fox & Element) Updated by RPL 12-29-25 SCHEMATIC Swanson River Unit SRU 222-33 PTD: 223-100 API: 50-133-20715-00-00 PBTD = 4,023 MD / TVD = 3,811 TD = 4,100 MD / TVD = 3,886 RKB to GL = 18.0 CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16 Conductor Driven to Set Depth 84 X-56 Weld 15.01 Surf 120' 7-5/8" Surf Csg 29.7 L-80 TXP BTC 6.875 Surf 2,738 3-1/2" Prod Lnr 9.2 L-80 Hyd 563 2.867 2,523 4,099 3-1/2" Prod Tieback 9.2 L-80 Hyd 563 2.867 Surf 2,531 1 16 7-5/8 9-7/8 hole 3-1/2 JEWELRY DETAIL No. Depth ID OD Item 1 2,523 3.500 6.540 Flex-Lock liner hanger, HRDE ZXPN Liner top Packer & Bullet Seal assembly 2 3,175 CIBP 12/12/25 3 3,224 CIBP 12/7/25 4 3,574 CIBP w / 36 cement TOC @ 3,538 6/29/25 5 3,726 CIBP w / 5 cement TOC @ 3,721 3/27/24 OPEN HOLE / CEMENT DETAIL 7-5/8" TOC @ Surface Pumped 156 bbls of 12ppg lead and 34bbls 15.8 ppg tail. (67 bbls of cement returns) 3-1/2 TOC @ TOL, Pumped 46 bbls (115sx) 12 ppg Type I II Lead followed by 24 bbl (122sx) of 15.3 ppg Type I II cement, with no losses. Circulated 30 bbls of spacer & 24bbls of cement contaminated mud. 6-3/4 hole PERFORATION DETAIL Sands Top MD Btm MD Top TVD Btm TVD FT Date Status ST_B3 3,141' 3,144' 2,946' 2,949' 3' 12/12/25 Open ST_B3 3,185' 3,191' 2,991' 2,997' 6' 6/30/25 Isolated ST_B4 3,202 3,208 3,008 3,014 6 6/29/25 Isolated ST_B5 3,236' 3,239 3,039' 3,042' 3' 7/15/25 Isolated ST_B5 3,241 3,246 3,044 3,049 5 12/5/25 Isolated ST_B8 3,624' 3,633' 3,420' 3,429' 9' 6/28/25 Isolated ST_B8 3,624' 3,633' 3,420' 3,429' 9' 1/15/25 Isolated ST_B8 3,626' 3,628' 3,422' 3,424' 2' 1/15/25 Isolated ST B9 3,697' 3,705' 3,491' 3,500' 8' 3/28/24 Isolated UB 36-8 3,736 3,743 3,530 3,537 7 12/19/23 Isolated UB 36-8 3,773 3,776 3,567 3,570 3 12/19/23 Isolated UB 36-8 3,795 3,799 3,587 3,591 4 12/18/23 Isolated 5 2 3 4 Updated by RPL 2/10/26 PROPOSED SCHEMATIC Swanson River Unit SRU 222-33 PTD: 223-100 API: 50-133-20715-00-00 PBTD = 4,023 MD / TVD = 3,811 TD = 4,100 MD / TVD = 3,886 RKB to GL = 18.0 CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16 Conductor Driven to Set Depth 84 X-56 Weld 15.01 Surf 120' 7-5/8" Surf Csg 29.7 L-80 TXP BTC 6.875 Surf 2,738 3-1/2" Prod Lnr 9.2 L-80 Hyd 563 2.867 2,523 4,099 3-1/2" Prod Tieback 9.2 L-80 Hyd 563 2.867 Surf 2,531 1 16 7-5/8 9-7/8 hole 3-1/2 JEWELRY DETAIL No. Depth ID OD Item 1 2,523 3.500 6.540 Flex-Lock liner hanger, HRDE ZXPN Liner top Packer & Bullet Seal assembly 2 +3,091 CIBP (Proposed) 3 3,175 CIBP 12/12/25 4 3,224 CIBP 12/7/25 5 3,574 CIBP w / 36 cement TOC @ 3,538 6/29/25 6 3,726 CIBP w / 5 cement TOC @ 3,721 3/27/24 OPEN HOLE / CEMENT DETAIL 7-5/8" TOC @ Surface Pumped 156 bbls of 12ppg lead and 34bbls 15.8 ppg tail. (67 bbls of cement returns) 3-1/2 TOC @ TOL, Pumped 46 bbls (115sx) 12 ppg Type I II Lead followed by 24 bbl (122sx) of 15.3 ppg Type I II cement, with no losses. Circulated 30 bbls of spacer & 24bbls of cement contaminated mud. 6-3/4 hole PERFORATION DETAIL Sands Top MD Btm MD Top TVD Btm TVD FT Date Status ST_A12 +2,738 +2,749 +2,554 +2,565 +11 TBD Proposed ST_A13 +2,825 +2,838 +2,639 +2,642 +9 TBD Proposed ST_A14 +2,842 +2,848 +2,656 +2,660 +6 TBD Proposed ST_A14 +2,861 +2,871 +2,673 +2,683 +10 TBD Proposed ST_B1 +2,925 +2,956 +2,735 +2,766 +31 TBD Proposed ST_B2 +3,026 +3,053 +2,833 +2,861 +27 TBD Proposed ST_B3 3,141' 3,144' 2,946' 2,949' 3' 12/12/25 Isolate ST_B3 3,185' 3,191' 2,991' 2,997' 6' 6/30/25 Isolated ST_B4 3,202 3,208 3,008 3,014 6 6/29/25 Isolated ST_B5 3,236' 3,239 3,039' 3,042' 3' 7/15/25 Isolated ST_B5 3,241 3,246 3,044 3,049 5 12/5/25 Isolated ST_B8 3,624' 3,633' 3,420' 3,429' 9' 6/28/25 Isolated ST_B8 3,624' 3,633' 3,420' 3,429' 9' 1/15/25 Isolated ST_B8 3,626' 3,628' 3,422' 3,424' 2' 1/15/25 Isolated ST B9 3,697' 3,705' 3,491' 3,500' 8' 3/28/24 Isolated UB 36-8 3,736 3,743 3,530 3,537 7 12/19/23 Isolated UB 36-8 3,773 3,776 3,567 3,570 3 12/19/23 Isolated UB 36-8 3,795 3,799 3,587 3,591 4 12/18/23 Isolated 6 3 4 5 2 ST_B2 ST_A12 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. Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 1/21/2026 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 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. SRU 222-33 50133207150000 223100 12/7/2025 AK E-LINE Plug 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): 4,100' N/A Casing Collapse Structural Conductor 1,410psi Surface 4,790psi Intermediate Production 10,540psi 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: Ryan Lemay, Operations Engineer Contact Email:ryan.lemay@hilcorp.com Contact Phone: 661-487-0871 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 Liner Top Pkr; N/A 2,523' MD/2,349' TVD; N/A 3,886' 3,721' 3,515' Swanson River Sterling-Upper Beluga Gas 16" 7-5/8" See Attached Schematic 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Swanson River Unit (SRU) 222-33CO 716A Same 3,885'3-1/2" 1190psi 1,576' 3,721 Length May 7, 2025 Tieback 3-1/2" 4,099' Perforation Depth MD (ft): See Attached Schematic 2,980psi 6,890psi 120'120' 2,738' Size 120' 2,738' MD 9.2# / L-80 TVD Burst 2,531' 10,160psi 2,554' Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEDA028399 223-100 50-133-20715-00-00 Hilcorp Alaska, LLC Proposed Pools: PRESENT WELL CONDITION SUMMARY AOGCC USE ONLY Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): Other: N2, CTCO 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: 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 10:40 am, Apr 29, 2025 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2025.04.29 08:50:07 - 08'00' Noel Nocas (4361) 325-266 BJM 5/2/25 DSR-4/29/25 10-404 A.Dewhurst 13MAY25 05/13/25 Well Prognosis Well: SRU 222-33 Well Name: SRU 222-33 API Number: 50-133-20715-00-00 Current Status: Producing Gas Well Permit to Drill Number: 223-100 Regulatory Contact: Donna Ambruz (907) 777-8305 First Call Engineer: Ryan LeMay (661)487-0871 (M) Second Call Engineer: Scott Warner (907) 830-8863 (M) (907) 564-4506 (O) Maximum Expected BHP: 1540 psi @ 3500 TVD Based on 0.44 psi/ft Max. Potential Surface Pressure: 1190 psi Based on 0.1 psi/ft gas gradient to surface Applicable Frac Gradient: 0.70 psi/ft using 13.5 ppg EMW FIT at the 7-5/8 surface casing shoe Shallowest Allowable Perf TVD: MPSP/(0.70-0.1) = 1190 psi / 0.60 = 1983 TVD (No plans to perforate above applicable gas pool / PA) Top of Applicable Gas Pool / PA: 2482 MD / 2311 TVD (Sterling / Upper Beluga) Well Status: Online Gas Producer flowing at 1.9 mmcfd, 10 bwpd, 390 psi FTP (As of 4/21/25) Brief Well Summary In January of 2025, perforations were added in the ST_B8 sands. Gas production improved from 370mcfd @ 142 psi FTP to 3.2 mmcfd @ 1040 psi FTP after perforations were added. In mid-April 2025 gas production began to decline significantly. Current production as of 4/21/25 is 1.9 mmcfd, 10 bwpd, 390 psi FTP. The purpose of this Sundry is to add additional perforations in the ST_A12 ST_B5 sands. Notes Regarding Wellbore Condition Inclination o Max deviation of 30.3° @ 1,667 MD o Max DLS of 3.99°/100 @ 1,086 MD Procedure: 1. MIRU E-line and pressure control equipment 2. PT lubricator to 250 psi low / 2,000 psi high 3. RIH and perforate ST_B5 ST_A12 from bottom up. Below are proposed targeted sands in order of testing (bottom/up), but additional sand may be added depending on results of these perfs, between the proposed top and bottom perfs Sand Top MD Btm MD Top TVD Btm TVD Interval ST_A12 ±2,738' ±2,749' ±2,554' ±2,565' ±11' ST_A13 ±2,825' ±2,838' ±2,639' ±2,642' ±9' ST_A14 ±2,842' ±2,848' ±2,656' ±2,660' ±6' ST_A14 ±2,861' ±2,871' ±2,673' ±2,683' ±10' ST_B1 ±2,926' ±2,956' ±2,736' ±2,766' ±30' ST_B2 ±3,026' ±3,053' ±2,833' ±2,861' ±27' ST_B3 ±3,141' ±3,150' ±2,946' ±2,955' ±9' ST_B3 ±3,185' ±3,191' ±2,991' ±2,994' ±6' ST_B4 ±3,202' ±3,208' ±3,008' ±3,010' ±6' ST_B5 ±3,236' ±3,257' ±3,039' ±3,060' ±21' Well Prognosis Well: SRU 222-33 a. Correlate using Open Hole Correlation Log provided by Geologist. Send the correlation pass to the Operations Engineer, Reservoir Engineer, and Geologist for confirmation b. Use Gamma/CCL to correlate c. Record Tubing pressures before and after each perforating run at 5 min, 10 min, and 15 min intervals post perf shot (if using switched guns, wait 10 min between shots) d. Pending well production, all perf intervals may not be completed e. If any zone produces sand and/or water or needs isolated, RIH and set plug above the perforations OR patch across the perforations i. Note: A CIBP may be used instead of WRP if it is determined that no cement is needed for operational purposes. 35ft will not be placed on each plug as these zones are close together. If possible, the CIBP will be set 50 above of the top of the last perforated sand unless zones are too close together in which case the plug will be set within 50. f. If necessary, use high pressure pad gas or N2 to pressure up well during perforating or to depress water prior to setting a plug above perforations. 4. RDMO Contingency Procedure: Coiled Tubing Cleanout 1. If throughout the job any current or proposed zones produce sand and / or water that cannot be depressed and pushed away with nitrogen or high-pressure pad gas, a coil tubing unit may be rigged up to clean out fill or fluid blown down as necessary. a. MIRU Fox CTU, PT BOPE to 250 psi low / 2500 psi high i. Provide AOGCC 24hrs notice of BOP test. b. Cleanout wellbore fill and / or blowdown well with nitrogen if necessary. Attachments: 1. Current Schematic 2. Proposed Schematic 3. Standard Well Procedure N2 Operations 4. Coil Tubing BOP Diagram Updated by DMA 01-24-25 SCHEMATIC Swanson River Unit SRU 222-33 PTD: 223-100 API: 50-133-20715-00-00 PBTD = 4,023 MD / TVD = 3,811 TD = 4,100 MD / TVD = 3,886 RKB to GL = 18.0 CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16 Conductor Driven to Set Depth 84 X-56 Weld 15.01 Surf 120' 7-5/8" Surf Csg 29.7 L-80 TXP BTC 6.875 Surf 2,738 3-1/2" Prod Lnr 9.2 L-80 Hyd 563 2.867 2,523 4,099 3-1/2" Prod Tieback 9.2 L-80 Hyd 563 2.867 Surf 2,531 1 16 7-5/8 9-7/8 hole 3-1/2 JEWELRY DETAIL No. Depth ID OD Item 1 2,523 3.500 6.540 Flex-Lock liner hanger, HRDE ZXPN Liner top Packer & Bullet Seal assembly 2 3,726 CIBP w/ 5 cement TOC @ 3,721 3/27/24 OPEN HOLE / CEMENT DETAIL 7-5/8" TOC @ Surface Pumped 156 bbls of 12ppg lead and 34bbls 15.8 ppg tail. (67 bbls of cement returns) 3-1/2 TOC @ TOL, Pumped 46 bbls (115sx) 12 ppg Type I II Lead followed by 24 bbl (122sx) of 15.3 ppg Type I II cement, with no losses. Circulated 30 bbls of spacer & 24bbls of cement contaminated mud. 6-3/4 hole PERFORATION DETAIL Sands Top MD Btm MD Top TVD Btm TVD FT Date Status ST_B8 3,624' 3,633' 3,420' 3,029' 9' 1/15/25 Open ST_B8 3,626' 3,628' 3,422' 3,424' 2' 1/15/25 Open ST B9 3,697' 3,705' 3,491' 3,500' 8' 3/28/24 Open UB 36-8 3,736 3,743 3,530 3,537 7 12/19/23 Isolated UB 36-8 3,773 3,776 3,567 3,570 3 12/19/23 Isolated UB 36-8 3,795 3,799 3,587 3,591 4 12/18/23 Isolated 2 Updated by RPL 04-22-25 SCHEMATIC Proposed Swanson River Unit SRU 222-33 PTD: 223-100 API: 50-133-20715-00-00 PBTD = 4,023 MD / TVD = 3,811 TD = 4,100 MD / TVD = 3,886 RKB to GL = 18.0 CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16 Conductor Driven to Set Depth 84 X-56 Weld 15.01 Surf 120' 7-5/8" Surf Csg 29.7 L-80 TXP BTC 6.875 Surf 2,738 3-1/2" Prod Lnr 9.2 L-80 Hyd 563 2.867 2,523 4,099 3-1/2" Prod Tieback 9.2 L-80 Hyd 563 2.867 Surf 2,531 1 16 7-5/8 9-7/8 hole 3-1/2 JEWELRY DETAIL No. Depth ID OD Item 1 2,523 3.500 6.540 Flex-Lock liner hanger, HRDE ZXPN Liner top Packer & Bullet Seal assembly 2 3,726 CIBP w/ 5 cement TOC @ 3,721 3/27/24 OPEN HOLE / CEMENT DETAIL 7-5/8" TOC @ Surface Pumped 156 bbls of 12ppg lead and 34bbls 15.8 ppg tail. (67 bbls of cement returns) 3-1/2 TOC @ TOL, Pumped 46 bbls (115sx) 12 ppg Type I II Lead followed by 24 bbl (122sx) of 15.3 ppg Type I II cement, with no losses. Circulated 30 bbls of spacer & 24bbls of cement contaminated mud. 6-3/4 hole PERFORATION DETAIL Sands Top MD Btm MD Top TVD Btm TVD FT Date Status ST_A12 ±2,738' ±2,749' ±2,554' ±2,565' ±11' Proposed ST_A13 ±2,825' ±2,838' ±2,639' ±2,642' ±9' Proposed ST_A14 ±2,842' ±2,848' ±2,656' ±2,660' ±6' Proposed ST_A14 ±2,861' ±2,871' ±2,673' ±2,683' ±10' Proposed ST_B1 ±2,926' ±2,956' ±2,736' ±2,766' ±30' Proposed ST_B2 ±3,026' ±3,053' ±2,833' ±2,861' ±27' Proposed ST_B3 ±3,141' ±3,150' ±2,946' ±2,955' ±9' Proposed ST_B3 ±3,185' ±3,191' ±2,991' ±2,994' ±6' Proposed ST_B4 ±3,202' ±3,208' ±3,008' ±3,010' ±6' Proposed ST_B5 ±3,236' ±3,257' ±3,039' ±3,060' ±21' Proposed ST_B8 3,624' 3,633' 3,420' 3,029' 9' 1/15/25 Open ST_B8 3,626' 3,628' 3,422' 3,424' 2' 1/15/25 Open ST B9 3,697' 3,705' 3,491' 3,500' 8' 3/28/24 Open UB 36-8 3,736 3,743 3,530 3,537 7 12/19/23 Isolated UB 36-8 3,773 3,776 3,567 3,570 3 12/19/23 Isolated UB 36-8 3,795 3,799 3,587 3,591 4 12/18/23 Isolated 2 ST_A12 ST_B5 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. 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: 11/07/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20251107 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# BRU 212-26 50283201820000 220058 9/20/2025 AK E-LINE Perf BRU 212-35 50283100270000 162018 10/12/2025 AK E-LINE TubingPuncher BRU 234-27 50283202070000 225065 7/17/1905 AK E-LINE CBL-02-October BRU 234-27 50283202070000 225065 10/6/2025 AK E-LINE CIBP/Perf GP 42-23RD 50733201140100 195145 10/26/2025 AK E-LINE TubingPunch GP ST 42-23RD 50733201140100 195145 10/9/2025 AK E-LINE JetCut MPL-54 50029236070000 218066 10/16/2025 READ CaliperSurvey MPL-57 50029236090000 218072 10/27/2025 READ CaliperSurvey MPU B-21 50029215350000 186023 10/25/2025 AK E-LINE RBP NCIU A-07 50883200270000 169058 10/10/2025 AK E-LINE JetCut NCIU A-17A 50883201880100 225089 10/10/2025 AK E-LINE Perf NCIU A-17A 50883201880100 225089 10/14/2025 AK E-LINE Perf PBU 01-10A 50029201690200 225055 8/29/2025 HALLIBURTON RBT PBU 05-11A 50029202520100 196097 10/11/2025 BAKER RPM PBU 05-31B 50029221590200 210085 10/14/2025 BAKER SPN PBU F-06B 50029200970200 225054 9/27/2025 BAKER MRPM PBU F-42A 50029221080100 207093 10/27/2025 BAKER RPM PBU H-07B 50029202420200 225064 9/29/2025 BAKER MRPM PBU L5-27 50029236270000 219046 10/7/2025 BAKER SPN PBU Q-06A 50029203460100 198090 8/22/2025 YELLOWJACKET SCBL SD-06 50133205820000 208160 7/23/2025 YELLOWJACKET GPT-PERF SRU 222-33 50133207150000 223100 7/15/2025 YELLOWJACKET PERF Please include current contact information if different from above. T41066 T41067 T41068 T41068 T41069 T41069 T41070 T41071 T41072 T41073 T41074 T41074 T41075 T41076 T41077 T41078 T41079 T41080 T41081 T41082 T41083 T41084SRU 222-33 50133207150000 223100 7/15/2025 YELLOWJACKET PERF Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.11.07 15:03:51 -09'00' 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:Ryan Lemay; Maercklein, William C Cc:Donna Ambruz Subject:RE: Program Change Request / Hilcorp / Swanson River / SRU 222-33 / AOGCC Sundry # 325-266 / BLM Sundry ID 2849129 Date:Tuesday, June 24, 2025 3:00:00 PM Ryan, The change below is approved. Regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Ryan Lemay <Ryan.Lemay@hilcorp.com> Sent: Tuesday, June 24, 2025 11:07 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Maercklein, William C <wmaercklein@blm.gov> Cc: Donna Ambruz <dambruz@hilcorp.com> Subject: Program Change Request / Hilcorp / Swanson River / SRU 222-33 / AOGCC Sundry # 325- 266 / BLM Sundry ID 2849129 Good morning Bryan and Will, Hilcorp Swanson River SRU 222-33 PTD 223-100 API: 50-133-20715-00-00 AOGCC Sundry # 325-266 BLM Sundry ID 2849129 Summary: When the current Sundry was submitted and approved SRU 222-33 was producing ~1.9mmcfd / 10 bwpd / 390 psi FTP Since submittal, the well production continued to decline to ~700 mcfd / 55 bwpd / 210 psi FTP before abruptly dying out within the last week. Multiple attempts were made to recover and bring well back online without success. Program Change Request: Hilcorp is requesting to re-perforate the existing and currently open perforations ST_B9 (+ 3697’ – 3705’ MD) ST_B8 (+ 3624’-3633’ MD) If after re-perforating current zones the flow test indicates these zones can no longer sustain flow / produce excess water A CIBP may be set at + 3574’ MD with 35’ of cement dump bailed on top of plug. Continue with adding perforations per originally approved sundry procedure / conditions. Thank you for your time and please let me know if you have questions or need additional information for this request. Ryan LeMay Operations Engineer Swanson River / Beaver Creek Cell: (661) 487-0871 E-mail: Ryan.lemay@hilcorp.com 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, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis 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. 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 4,100 feet 3,721 feet true vertical 3,886 feet N/A feet Effective Depth measured 3,721 feet 2,523 feet true vertical 3,515 feet 2,349 feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth) Tieback 3-1/2" 9.2# / L-80 2,531' MD 2,357' TVD Packers and SSSV (type, measured and true vertical depth) Liner Top Pkr; N/A 2,523' MD/2,349' 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: Scott Warner, Operations Engineer 324-719 Sr Pet Eng: Sr Pet Geo: Sr Res Eng: WINJ WAG 347 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 scott.warner@hilcorp.com 907-564-4506 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' 003174 0 1390 1037 measured TVD 37316 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 223-100 50-133-20715-00-00 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: FEDA028399 Swanson River / Sterling-Upper Beluga Gas Swanson River Unit (SRU) 222-33 Plugs Junk measured Length Production Liner 1,578' Casing Structural 3,885'4,099' 120'Conductor Surface Intermediate 16" 7-5/8" 120' 2,738' 10,540psi 2,980psi 6,890psi 10,160psi 2,738' 2,554' Burst Collapse 1,410psi 4,790psi PL G 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 8:39 am, Jan 27, 2025 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2025.01.24 14:39:11 - 09'00' Noel Nocas (4361) RBDMS JSB 013025 BJM 2/10/25 A.Dewhurst 13FEB25 DSR-1/31/25 Page 1/1 Well Name: SRF SRU 222-33 Report Printed: 1/22/2025WellViewAdmin@hilcorp.com Alaska Weekly Report - Operations Jobs Actual Start Date:12/30/2024 End Date: Report Number 1 Report Start Date 1/15/2025 Report End Date 1/16/2025 Last 24hr Summary PTW, JSA with YJOS E-line crew. MIRU. PT 250/3500 psi wireline valves and lubricator. RIH with 7' x 1 11/16" WB, 1 11/16" GG & SS, 9' and 2' of 2" O.D. guns loaded HSC 6 spf. Pressure up wellbore with lift gas to 506 psi. Pull correlation log and send to town. On depth. Spot 2' gun in the middle of ST B8 sands. Shoot from 3626'-3628' (CCL depth 3606') with switch gun. Good indication of shots fired. WHP increase. Pressure equalized. Perf 9' ST B8 sand from 3624'-3633' ccl depth 3615'. Pressure climbed to 1054 psi. POOH to surface. RIg back E-line lubricator and install night cap. Operations bring well online after replacing choke. Worked well rate and pressure up to 1.9 mmcfd at 1020 psi. Rig down YOS E-line. Field: Swanson River Sundry #: State: ALASKA Rig/Service:Permit to Drill (PTD) #:223-100Permit to Drill (PTD) #:223-100 Wellbore API/UWI:50-133-20715-00-00 Updated by DMA 01-24-25 SCHEMATIC Swanson River Unit SRU 222-33 PTD: 223-100 API: 50-133-20715-00-00 PBTD = 4,023’ MD / TVD = 3,811’ TD = 4,100’ MD / TVD = 3,886’ RKB to GL = 18.0’ CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16” Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 120' 7-5/8" Surf Csg 29.7 L-80 TXP BTC 6.875” Surf 2,738’ 3-1/2" Prod Lnr 9.2 L-80 Hyd 563 2.867” 2,523’ 4,099’ 3-1/2" Prod Tieback 9.2 L-80 Hyd 563 2.867” Surf 2,531’ 1 16” 7-5/8” 9-7/8” hole 3-1/2” JEWELRY DETAIL No. Depth ID OD Item 1 2,523’ 3.500” 6.540” Flex-Lock liner hanger, HRDE ZXPN Liner top Packer & Bullet Seal assembly 2 3,726’ CIBP w/ 5’ cement – TOC @ 3,721’ 3/27/24 OPEN HOLE / CEMENT DETAIL 7-5/8" TOC @ Surface Pumped 156 bbls of 12ppg lead and 34bbls 15.8 ppg tail. (67 bbls of cement returns) 3-1/2” TOC @ TOL, Pumped 46 bbls (115sx) 12 ppg Type I II Lead followed by 24 bbl (122sx) of 15.3 ppg Type I II cement, with no losses. Circulated 30 bbls of spacer & 24bbls of cement contaminated mud. 6-3/4” hole PERFORATION DETAIL Sands Top MD Btm MD Top TVD Btm TVD FT Date Status ST_B8 3,624' 3,633' 3,420' 3,029' 9' 1/15/25 Open ST_B8 3,626' 3,628' 3,422' 3,424' 2' 1/15/25 Open ST B9 3,697' 3,705' 3,491' 3,500' 8' 3/28/24 Open UB 36-8 3,736’ 3,743’ 3,530’ 3,537’ 7’ 12/19/23 Isolated UB 36-8 3,773’ 3,776’ 3,567’ 3,570’ 3’ 12/19/23 Isolated UB 36-8 3,795’ 3,799’ 3,587’ 3,591’ 4’ 12/18/23 Isolated 2 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 4,100 feet 3,721 feet true vertical 3,886 feet N/A feet Effective Depth measured 3,721 feet 2,523 feet true vertical 3,515 feet 2,349 feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth) Tieback 3-1/2" 9.2# / L-80 2,531' MD 2,357' TVD Packers and SSSV (type, measured and true vertical depth) Liner Top Pkr; N/A 2,523' MD/2,349' 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: Jake Flora, Operations Engineer 324-057 Sr Pet Eng: Sr Pet Geo: Sr Res Eng: WINJ WAG 1454 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' 002405 0 1899 564 measured TVD 37316 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 223-100 50-133-20715-00-00 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: FEDA028399 Swanson River / Sterling-Upper Beluga Gas Swanson River Unit (SRU) 222-33 Plugs Junk measured Length Production Liner 1,578' Casing Structural 3,885'4,099' 120'Conductor Surface Intermediate 16" 7-5/8" 120' 2,738' 10,540psi 2,980psi 6,890psi 10,160psi 2,738' 2,554' Burst Collapse 1,410psi 4,790psi Development Service GINJ SUSP SPLUG Gas 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 11:08 am, Apr 25, 2024 Noel Nocas (4361) Digitally signed by Noel Nocas (4361) Date: 2024.04.25 10:31:30 -08'00' A.Dewhurst 13FEB25 DSR-4/29/24 RBDMS JSB 043024 Well Name: SRF SRU 222-33 API #:50-133-20715-00-00 Field:Swanson River Start Date:3/27/2024 Permit #:223-100 Sundry #:324-057 End Date: 3/27/2024 3/28/2024 Daily Operations: Activity Report PJSM, Crew mob equipment to location, Spot in & rig up, Pick up plug & lube, Stab onto well & pressure test lube 250/2000-good, Run #1 2.75" CIBP & perform correlation pass (adjust +/-), Pull on depth & set CIBP @ 3726', Pull out of hole & lay down, Pick up 2.5" cement bailer, Load bailer with 2 gal cmt, Run in hole & bail cmt from 3726' to 3721' (5'), Pull out of hole & secure well to WOC. PJSM, Crew travel to location, Start & warm equipment, Pick up run #1 & lube, Pressure test 250/2000-good, Run in hole with Run #1 ST- B9 (3697-3705), Perform draw down & test, Rig down AK Eline Page 1 of 1 Updated by DMA 04-24-24 SCHEMATIC Swanson River Unit SRU 222-33 PTD: 223-100 API: 50-133-20715-00-00 PBTD = 4,023’ MD / TVD = 3,811’ TD = 4,100’ MD / TVD = 3,886’ RKB to GL = 18.0’ CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16” Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 120' 7-5/8" Surf Csg 29.7 L-80 TXP BTC 6.875” Surf 2,738’ 3-1/2" Prod Lnr 9.2 L-80 Hyd 563 2.867” 2,523’ 4,099’ 3-1/2" Prod Tieback 9.2 L-80 Hyd 563 2.867” Surf 2,531’ 1 16” 7-5/8” 9-7/8” hole 3-1/2” JEWELRY DETAIL No. Depth ID OD Item 1 2,523’ 3.500” 6.540” Flex-Lock liner hanger, HRDE ZXPN Liner top Packer & Bullet Seal assembly 2 3,726’ CIBP w/ 5’ cement – TOC @ 3,721’ 3/27/24 OPEN HOLE / CEMENT DETAIL 7-5/8" TOC @ Surface Pumped 156 bbls of 12ppg lead and 34bbls 15.8 ppg tail. (67 bbls of cement returns) 3-1/2” TOC @ TOL, Pumped 46 bbls (115sx) 12 ppg Type I II Lead followed by 24 bbl (122sx) of 15.3 ppg Type I II cement, with no losses. Circulated 30 bbls of spacer & 24bbls of cement contaminated mud. 6-3/4” hole PERFORATION DETAIL Sands Top MD Btm MD Top TVD Btm TVD FT Date Status ST B9 3,697' 3,705' 3,491' 3,500' 8' 3/28/24 Open UB 36-8 3,736’ 3,743’ 3,530’ 3,537’ 7’ 12/19/23 Isolated UB 36-8 3,773’ 3,776’ 3,567’ 3,570’ 3’ 12/19/23 Isolated UB 36-8 3,795’ 3,799’ 3,587’ 3,591’ 4’ 12/18/23 Isolated 2 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:Brooks, Phoebe L (OGC) To:Daniel Scarpella Cc:Regg, James B (OGC) Subject:RE: Hilcorp Fox CTU #8 SRU 222-33 BOPE Test Sundry Number added to form Date:Tuesday, January 23, 2024 2:11:15 PM Attachments:Fox 8 12-14-23.xlsx I added the operation type Workover. 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: Daniel Scarpella <Daniel.Scarpella@hilcorp.com> Sent: Friday, December 15, 2023 12:09 PM To: Regg, James B (OGC) <jim.regg@alaska.gov>; DOA AOGCC Prudhoe Bay <doa.aogcc.prudhoe.bay@alaska.gov>; Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov> Cc: Jacob Flora <Jake.Flora@hilcorp.com> Subject: Hilcorp Fox CTU #8 SRU 222-33 BOPE Test Sundry Number added to form Attached is the BOPE test form for FOX CTU Services on SRU 222-33 With the Sundry Number! Thank you, Daniel Scarpella Hilcorp North Slope LLC., Alaska | Sr. Well Site Supervisor | PBU Wells Team 907.230.2692 cell | 907.659.5580 office | H 2154 | alt. Anthony Knowles Well Interventions:daniel.scarpella@hilcorp.com RWO Operations:pbwellsrwowss@hilcorp.com P.O. Box 340067| DP PBOC 34 | PBOC 20| Prudhoe Bay, AK 99734 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 6ZDQVRQ5LYHU8QLW 37' added the operation type Workover STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION *All BOPE reports are due to the agency within 5 days of testing* SSu bmitt to :jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov Rig Owner: Rig No.:8 DATE: 12/14/23 Rig Rep.: Rig Email: Operator: Operator Rep.: Op. Rep Email: Well Name:PTD #2231000 Sundry #323-661 Operation: Drilling: Workover: X Explor.: Test: Initial: X Weekly: Bi-Weekly: Other: Rams:250/3000 Annular: Valves:250/3000 MASP:1207 MISC. INSPECTIONS: TEST DATA FLOOR SAFETY VALVES: Test Result/Type Test Result Quantity Test Result Housekeeping P Well Sign P Upper Kelly 0NA Permit On Location P Hazard Sec.P Lower Kelly 0NA Standing Order Posted P Misc.NA Ball Type 0NA Test Fluid Other Inside BOP 0NA FSV Misc 0NA BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm Stripper 0NATrip Tank NA NA Annular Preventer 0NAPit Level Indicators NA NA #1 Rams 1 4-1/16' Blind/Shea P Flow Indicator NA NA #2 Rams 1 1-3/4" Pipe/Slip P Meth Gas Detector NA NA #3 Rams 0NAH2S Gas Detector PP #4 Rams 0NAMS Misc 0NA #5 Rams 0NA #6 Rams 0NAACCUMULATOR SYSTEM: Choke Ln. Valves 2 2"P Time/Pressure Test Result HCR Valves 0NASystem Pressure (psi)3000 P Kill Line Valves 2 2"P Pressure After Closure (psi)2400 P Check Valve 0NA200 psi Attained (sec)3 P BOP Misc 0NAFull Pressure Attained (sec)14 P Blind Switch Covers: All stations Yes CHOKE MANIFOLD:Bottle Precharge: 1350 psi P Quantity Test Result Nitgn. Bottles # & psi (Avg.): 4/1350 psi P No. Valves 5P ACC Misc 0NA Manual Chokes 2P Hydraulic Chokes 0NA Control System Response Time:Time (sec) Test Result CH Misc 0NA Annular Preventer 0 NA #1 Rams 43 P Coiled Tubing Only:#2 Rams 44 P Inside Reel valves 1P #3 Rams 0 NA #4 Rams 0 NA Test Results #5 Rams 0 NA #6 Rams 0 NA Number of Failures:0 Test Time:4.0 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 12/13/2023 2:00PM Waived By Test Start Date/Time:12/14/2023 17:30 (date) (time)Witness Test Finish Date/Time:12/14/2023 21:30 BOPE Test Report Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Jim Regg Fox Test w/ 50/50 mix of water & methanol Recieved waive of witness from Jim Regg via phone conversation and email on 12/14/2023 Receved email from Brian McClellan; 12/14/2023, that Hilcorp has verbal approval to perform the Coiled tubing portion, steps 1-10, of the sundry application. *** Note: Took several times to during first test to find leak. Needle valve/block valve at field test pump bad/replaced and found air in the debooster line for the pressure sensor. Perged line with clean fluid to get air out. No components on the stack or block valves invoved with the testing failed.*** Jeremy Hart Hilcorp Alaska LLC. Daniel Scarpella SRU 222-33 Test Pressure (psi): jeremyhart76@gmail.com daniel.scarpella@hilcorp.com Form 10-424 (Revised 08/2022)2023-1214_BOP_Fox8_SRU_222-33 9 9 9 9 9 9 9 9 9 9 9 MEU -5HJJ X 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): 4,100'N/A Casing Collapse Structural Conductor 1,410psi Surface 4,790psi Intermediate Production 10,540psi 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 Other: N2 Operations scott.warner@hilcorp.com 907-564-4506 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 Scott Warner 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 FEDA028399 223-100 50-133-20715-00-00 Hilcorp Alaska, LLC Proposed Pools: 9.2# / L-80 TVD Burst 2,531' 10,160psi 2,554' Size 120' 2,738' MD See Attached Schematic 2,980psi 6,890psi 120'120' 2,738' January 14, 2025 Tieback 3-1/2" 4,099' Perforation Depth MD (ft): 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Swanson River Unit (SRU) 222-33CO 716A Same 3,885'3-1/2" 1187psi 1,576' 3,721 Length Liner Top Pkr; N/A 2,523' MD/2,349' TVD; N/A 3,886' 3,721' 3,515' Swanson River Sterling-Upper Beluga Gas 16" 7-5/8" See Attached Schematic 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 11:01 am, Dec 31, 2024 324-719 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2024.12.31 08:49:35 - 09'00' Noel Nocas (4361) BJM 1/8/24 SFD 12/31/2024 10-404 DSR-1/8/25 Perforate &':&':IRU-/& Gregory C. Wilson Digitally signed by Gregory C. Wilson Date: 2025.01.09 13:36:23 -09'00'01/09/25 RBDMS JSB 011025 Well Prognosis Well: SRU 222-33 Well Name:SRU 222-33 API Number:50-133-20715-00-00 Current Status:Producing Gas Well Permit to Drill Number:223-100 Regulatory Contact:Donna Ambruz (907) 777-8305 First Call Engineer:Scott Warner (907) 564-4506 (O) (907) 830-8863 (C) Second Call Engineer:Chad Helgeson (907) 777-8405 (O) (907) 229-4824 (C) Maximum Expected BHP:1536 psi @ 3491’ TVD Based on 0.44 psi/ft Max. Potential Surface Pressure:1187 psi Based on 0.1 psi/ft gas gradient to surface Applicable Frac Gradient:0.702 psi/ft using 13.5 ppg EMW FIT at the 7-5/8” surface casing shoe Shallowest Allowable Perf TVD:MPSP/(0.70-0.1) = 1187 psi / 0.60 = 1978‘ TVD Top of Applicable Gas Pool:1650’ MD/ 1509’ TVD (Will not perforate above surface casing shoe) Well Status:Online Gas Producer flowing at 387 mscfd, 0 bwpd, 139 psi FTP Brief Well Summary SRU 222-33 was drilled in December 2023 targeting the Sterling and Beluga sands. The well was originally completed in the 36-8 sand with an IP of 1 mmscfd. By March of 2023 those perfs had depleted and the well was plugged back with a CIBP and cement cap. New perforations were added in the Sterling/Upper Beluga gas sand which IP’d at ~3.0 mmscfd but has been on steady decline since. The purpose of this sundry is to add additional perforations in the Sterling/Upper Beluga gas sands to increase production while preserving current online rate. Notes Regarding Wellbore Condition x Inclination o Max deviation of 30.3° @ 1,667’ MD o Max DLS of 3.99°/100’ @ 1,086’ MD x Recent Tags o 12/20/24: SL RIH and tag fill at 3705’ falling to 3718’ KB w/ 2.74” GR. Saw fluid level at 2860’ KB o 3/28/24: EL set CIBP at 3726’ w/ 5’ cement dump bailed on top. Perforated the ST-B9 sand from 3697-3705’ o 3/24/24: SL RIH w/ 2.5”x 6’ bailer to 3857’ KB Procedure: 1. MIRU E-line and pressure control equipment 2. PT lubricator to 250 psi low /2,000 psi high 3. RIH and perforate ST-B8 – ST-A12 from bottom up with 2” 60 deg phased perf guns: Below are proposed targeted sands in order of testing (bottom/up), but additional sand may be added depending on results of these perfs, between the proposed top and bottom perfs Sand Top MD Btm MD Top TVD Btm TVD Interval ST_A12 ±2,738' ±2,749' ±2,554' ±2,565'±11' (Will not perforate above surface casing shoe) Well Prognosis Well: SRU 222-33 ST_A13 ±2,825' ±2,838' ±2,639' ±2,642'±9' ST_A14 ±2,842' ±2,848' ±2,656' ±2,660'±6' ST_A14 ±2,861' ±2,871' ±2,673' ±2,683'±10' ST_B1 ±2,926' ±2,956' ±2,736' ±2,766'±30' ST_B2 ±3,026' ±3,053' ±2,833' ±2,861'±27' ST_B3 ±3,141' ±3,150' ±2,946' ±2,955' ±9' ST_B3 ±3,185' ±3,191' ±2,991' ±2,994' ±6' ST_B4 ±3,202' ±3,208' ±3,008' ±3,010' ±6' ST_B5 ±3,236' ±3,257' ±3,039' ±3,060' ±21' ST_B8 ±3,625' ±3,632' ±3,420' ±3,428' ±7' a. Proposed perfs are also shown on the proposed schematic in red font b. Correlate using Open Hole Correlation Log provided by Geologist. Send the correlation pass to the Operations Engineer, Reservoir Engineer, and Geologist for confirmation c. Use Gamma/CCL to correlate d. Record Tubing pressures before and after each perforating run at 5 min, 10 min, and 15 min intervals post perf shot (if using switched guns, wait 10 min between shots) e. Pending well production, all perf intervals may not be completed f. If any zone produces sand and/or water or needs isolated, RIH and set plug above the perforations OR patch across the perforations i.Note: All proposed perforations are in the same Pool / PA. A CIBP may be used instead of WRP if it is determined that no cement is needed for operational purposes. 35ft will not be placed on each plug as these zones are close together in same PA. If possible, the CIBP will be set 50’ above of the top of the last perforated sand unless zones are too close together in which case the plug will be set within 50’. g. If necessary, use nitrogen to pressure up well during perforating or to depress water prior to setting a plug above perforations 4. RDMO Attachments: 1. Current Schematic 2. Proposed Schematic 3. Standard Well Procedure – N2 Operations Updated by DMA 04-24-24 SCHEMATIC Swanson River Unit SRU 222-33 PTD: 223-100 API: 50-133-20715-00-00 PBTD = 4,023’ MD / TVD = 3,811’ TD = 4,100’ MD / TVD = 3,886’ RKB to GL = 18.0’ CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16” Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 120' 7-5/8" Surf Csg 29.7 L-80 TXP BTC 6.875” Surf 2,738’ 3-1/2" Prod Lnr 9.2 L-80 Hyd 563 2.867” 2,523’ 4,099’ 3-1/2" Prod Tieback 9.2 L-80 Hyd 563 2.867” Surf 2,531’ 1 16” 7-5/8” 9-7/8” hole 3-1/2” JEWELRY DETAIL No. Depth ID OD Item 1 2,523’ 3.500” 6.540” Flex-Lock liner hanger, HRDE ZXPN Liner top Packer & Bullet Seal assembly 2 3,726’ CIBP w/ 5’ cement – TOC @ 3,721’ 3/27/24 OPEN HOLE / CEMENT DETAIL 7-5/8" TOC @ Surface Pumped 156 bbls of 12ppg lead and 34bbls 15.8 ppg tail. (67 bbls of cement returns) 3-1/2” TOC @ TOL, Pumped 46 bbls (115sx) 12 ppg Type I II Lead followed by 24 bbl (122sx) of 15.3 ppg Type I II cement, with no losses. Circulated 30 bbls of spacer & 24bbls of cement contaminated mud. 6-3/4” hole PERFORATION DETAIL Sands Top MD Btm MD Top TVD Btm TVD FT Date Status ST B9 3,697' 3,705' 3,491' 3,500' 8' 3/28/24 Open UB 36-8 3,736’ 3,743’ 3,530’ 3,537’ 7’ 12/19/23 Isolated UB 36-8 3,773’ 3,776’ 3,567’ 3,570’ 3’ 12/19/23 Isolated UB 36-8 3,795’ 3,799’ 3,587’ 3,591’ 4’ 12/18/23 Isolated 2 Updated by SRW 12-30-24 PROPOSED Swanson River Unit SRU 222-33 PTD: 223-100 API: 50-133-20715-00-00 PBTD = 4,023’ MD / TVD = 3,811’ TD = 4,100’ MD / TVD = 3,886’ RKB to GL = 18.0’ CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16”Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 120' 7-5/8" Surf Csg 29.7 L-80 TXP BTC 6.875” Surf 2,738’ 3-1/2" Prod Lnr 9.2 L-80 Hyd 563 2.867” 2,523’ 4,099’ 3-1/2" Prod Tieback 9.2 L-80 Hyd 563 2.867” Surf 2,531’ 1 16” 7-5/8” 9-7/8” hole 3-1/2” JEWELRY DETAIL No. Depth ID OD Item 1 2,523’ 3.500” 6.540” Flex-Lock liner hanger, HRDE ZXPN Liner top Packer & Bullet Seal assembly 2 3,726’ CIBP w/ 5’ cement – TOC @ 3,721’ 3/27/24 OPEN HOLE / CEMENT DETAIL 7-5/8"TOC @ Surface Pumped 156 bbls of 12ppg lead and 34bbls 15.8 ppg tail. (67 bbls of cement returns) 3-1/2” TOC @ TOL, Pumped 46 bbls (115sx) 12 ppg Type I II Lead followed by 24 bbl (122sx) of 15.3 ppg Type I II cement, with no losses. Circulated 30 bbls of spacer & 24bbls of cement contaminated mud. 6-3/4” hole PERFORATION DETAIL Sands Top MD Btm MD Top TVD Btm TVD FT Date Status ST_A12 ±2,738' ±2,749' ±2,554' ±2,565' ±11' TBD Proposed ST_A13 ±2,825' ±2,838' ±2,639' ±2,642' ±9' TBD Proposed ST_A14 ±2,842' ±2,848' ±2,656' ±2,660' ±6' TBD Proposed ST_A14 ±2,861' ±2,871' ±2,673' ±2,683' ±10' TBD Proposed ST_B1 ±2,926' ±2,956' ±2,736' ±2,766' ±30' TBD Proposed ST_B2 ±3,026' ±3,053' ±2,833' ±2,861' ±27' TBD Proposed ST_B3 ±3,141' ±3,150' ±2,946' ±2,955' ±9' TBD Proposed ST_B3 ±3,185' ±3,191' ±2,991' ±2,994' ±6' TBD Proposed ST_B4 ±3,202' ±3,208' ±3,008' ±3,010' ±6' TBD Proposed ST_B5 ±3,236' ±3,257' ±3,039' ±3,060' ±21' TBD Proposed ST_B8 ±3,625' ±3,632' ±3,420' ±3,428' ±7' TBD Proposed ST B9 3,697' 3,705' 3,491' 3,500' 8' 3/28/24 Open UB 36-8 3,736’ 3,743’ 3,530’ 3,537’ 7’ 12/19/23 Isolated UB 36-8 3,773’ 3,776’ 3,567’ 3,570’ 3’ 12/19/23 Isolated UB 36-8 3,795’ 3,799’ 3,587’ 3,591’ 4’ 12/18/23 Isolated 2 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. 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. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. From:Joshua Riley - (C) To:Regg, James B (OGC) Cc:Brooks, Phoebe L (OGC) Subject:RE: [EXTERNAL] RE: AOGCC Test Witness Notification Request: BOPE, Hilcorp 169, Swanson River SRU 222-33 Date:Tuesday, December 12, 2023 10:57:49 AM Attachments:SRU 222-33 Initial BOP Test.xlsx Here is the BOP form, I filled it out Im sorry I thought I sent it. Josh RileyHilcorp DSM: 907-283-1369Cell: 907-252-1211 Hilcorp Alaska, LLC From: Regg, James B (OGC) [mailto:jim.regg@alaska.gov] Sent: Tuesday, December 12, 2023 10:54 AM To: Joshua Riley - (C) <jriley@hilcorp.com> Cc: Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov> Subject: [EXTERNAL] RE: AOGCC Test Witness Notification Request: BOPE, Hilcorp 169, Swanson River SRU 222-33 Was a BOPE test performed on 12/6 as scheduled? AOGCC has not received a copy of the test report. Jim Regg Supervisor, Inspections AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907-793-1236 From: Jotform <noreply@jotform.com> Sent: Monday, December 4, 2023 8:26 AM To: DOA AOGCC Prudhoe Bay <doa.aogcc.prudhoe.bay@alaska.gov>; ced-svc-ogcforms (CED sponsored) <ced-ogc-jotforms@alaska.gov> Subject: AOGCC Test Witness Notification Request: BOPE, Hilcorp 169, Swanson River SRU 222-33 6ZDQVRQ5LYHU8QLW 37' Question Answer Type of Test Requested: BOPE Requested Time for Inspection 12-06-2023 9:00 AM Location Hilcorp 169, Swanson River SRU 222-33 Name Josh Riley E-mail jriley@hilcorp.com Phone Number (907) 2831369 Company Hilcorp Other Information: We will be ready to perform our initial BOP Test w/ 4.5'' and 3.5'' test jts on SRU 222-33, we will update you further if you wish to witness. Submission ID: 5775199311311033081 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* SSu bmitt to :jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov Rig Owner: Rig No.:169 DATE: 12/6/23 Rig Rep.: Rig Email: Operator: Operator Rep.: Op. Rep Email: Well Name:PTD #2231000 Sundry # Operation: Drilling: X Workover: Explor.: Test: Initial: X Weekly: Bi-Weekly: Other: Rams:250/3000 Annular:250/3000 Valves:250/3000 MASP:1240 MISC. INSPECTIONS: TEST DATA FLOOR SAFETY VALVES: Test Result/Type Test Result Quantity Test Result Housekeeping P Well Sign P Upper Kelly 1P Permit On Location P Hazard Sec.P Lower Kelly 1P Standing Order Posted P Misc.NA Ball Type 1P Test Fluid Water 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 Blinds P Meth Gas Detector PP #3 Rams 1 2 7/8'' X 5''P H2S Gas Detector PP #4 Rams 0NAMS Misc 0NA #5 Rams 0NA #6 Rams 0NAACCUMULATOR SYSTEM: Choke Ln. Valves 1 3 1/8 P Time/Pressure Test Result HCR Valves 2 3 1/8 & 2 1/16 P System Pressure (psi)3000 P Kill Line Valves 1 2 1/16 P Pressure After Closure (psi)1600 P Check Valve 0NA200 psi Attained (sec)23 P BOP Misc 0NAFull Pressure Attained (sec)93 P Blind Switch Covers: All stations Yes CHOKE MANIFOLD:Bottle Precharge:P Quantity Test Result Nitgn. Bottles # & psi (Avg.): 4@2475 P No. Valves 15 P ACC Misc 0NA Manual Chokes 1P Hydraulic Chokes 1P Control System Response Time:Time (sec) Test Result CH Misc 0NA Annular Preventer 15 P #1 Rams 4 P Coiled Tubing Only:#2 Rams 4 P Inside Reel valves 0NA #3 Rams 4 P #4 Rams 0 NA Test Results #5 Rams 0 NA #6 Rams 0 NA Number of Failures:0 Test Time:6.0 HCR Choke 2 P Repair or replacement of equipment will be made within days. HCR Kill 2 P Remarks: AOGCC Inspection 24 hr Notice Yes Date/Time 12/4/2023 8:26am Waived By Test Start Date/Time:12/6/2023 7:30 (date) (time)Witness Test Finish Date/Time:12/6/2023 13:30 BOPE Test Report Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Sully Sullivan Hilcorp Tested 3.5'' and 4.5'' Test Joints, Test witnessed By BLM inspector Allie Schoessler all test 5 min low 10 min high, no failures, tested PVT and Gas Alarms Jon Van Evra Hilcorp Alaska LLC Josh Riley SRU 222-33 Test Pressure (psi): jriley@hilcorp.com Form 10-424 (Revised 08/2022) 2023-1206_BOP_Hilcorp169_SRU_222-33 99 9 9 9 9 99 9 9 9 - 5HJJ witnessed By BLM inspector Allie Schoessler 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:Joshua Riley - (C) To:Regg, James B (OGC); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (OGC); Wallace, Chris D (OGC) Subject:BOPE Test Report Date:Sunday, December 10, 2023 6:05:32 AM Attachments:Hilcorp_MIT_SRU 222-33_12-9-2023.xlsx Here is the MIT of SRU 222-33 post completion. Thank you. Josh RileyHilcorp DSM: 907-283-1369Cell: 907-252-1211 Hilcorp Alaska, LLC 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 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 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. Swanson River Unit 222-33 PTD 2231000 Submit to: OPERATOR: FIELD / UNIT / PAD: DATE: OPERATOR REP: AOGCC REP: Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD 2231000 Type Inj Tubing 0 2173 2165 2161 Type Test P Packer TVD 2335 BBL Pump 0.3 IA 0 0 0 0 Interval O Test psi 2000 BBL Return 0.3 OA 0 0 0 0 Result P Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD 2331000 Type Inj Tubing 0 0 0 0 Type Test P Packer TVD 2348'BBL Pump 0.8 IA 0 2100 2095 2095 Interval O Test psi 2000 BBL Return 0.8 OA 0 0 0 0 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 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 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 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 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 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: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov Notes:MIT-T Post Completion, 7 5/8" liner top packer element at 2534' md/ 2360' tvd, 3-1/2" tubing and liner. Notes: Notes: Hilcorp Alaska LLC Swanson River / SRU / 32-33 Justin Gruenberg 12/09/23 Notes:MIT-T Post Completion, 7 5/8" liner top packer element at 2534' md/ 2360' tvd, 3-1/2" tubing and liner. Notes: Notes: Notes: SRU 222-33 SRU 222-33 Form 10-426 (Revised 01/2017)2023-1209_MITP_SRU_222-33_2tests         ====== MIT-IAjbr J. Regg; 5/6/2024 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: 4/19/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20240419 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BRU 241-23 50283201910000 223061 4/5/2024 AK E-Line Perf BRU 242-04 50283201640000 212041 3/20/2024 AK E-Line JB/PProf NCIU A-17 50883201880000 223031 3/27/2024 AK E-Line GPT/Perf PBU 05-02A 50029201440100 201241 4/6/2024 Halliburton PPROF PBU 09-35A 50029213140100 193031 4/9/2024 Halliburton RBT PBU 13-24A 50029207390100 204243 4/5/2024 Halliburton RBT PBU B-14A 50029203490100 209059 4/2/2024 Halliburton RBT PBU D-31B 50029226720200 212168 4/7/2024 Halliburton PERF SRU 222-33 50133207150000 223100 3/27/2024 AK E-Line CIBP/Perf SRU 224-10 50133101380100 222124 3/29/2024 AK E-Line CIBP/Perf SRU 241-33B 50133206960000 221053 4/2/2024 AK E-Line CIBP Please include current contact information if different from above T38718 T38719 T38720 T38721 T38722 T38723 T38724 T38725 T38726 T38727 T38728 SRU 222-33 50133207150000 223100 3/27/2024 AK E-Line CIBP/Perf Meredith Guhl Digitally signed by Meredith Guhl Date: 2024.04.19 14:54:13 -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: 4/4/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20240404 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BCU 19RD 50133205790100 219188 2/23/2024 YELLOW JACKET GPT-PERF BRU 241-23 50283201910000 223061 11/25/2023 AK E-LINE Perf HV B-13 50231200320000 207151 3/11/2024 YELLOW JACKET GPT KALOTSA 6 50133206850000 219114 3/2/2024 YELLOW JACKET PERF KU 13-06A 50133207160000 223112 3/13/2024 YELLOW JACKET GPT-PERF KU 21-06RD 50133100900100 201097 3/19/2024 YELLOW JACKET GPT-PERF END MPI 2-62 50029216480000 186158 2/14/2024 YELLOW JACKET PERF MPU G-18 50029231940000 204020 3/21/2024 READ Caliper Survey MPU G-18 50029231940000 204020 3/9/2024 AK E-LINE HoistCutter MPU I-24 50029237780000 224001 3/11/2024 AK E-LINE CBL NCIU A-18 50883201890000 223033 12/20/2023 AK E-LINE Perf NCIU A-18 50883201890000 223033 12/18/2024 AK E-LINE GPT/Plug/Perf PAXTON 3 50133205880000 209168 3/6/2024 YELLOW JACKET GPT PAXTON 3 50133205880000 209168 3/8/2024 YELLOW JACKET PERF PAXTON 3 50133205880000 209168 3/12/2024 AK E-LINE PPROF PAXTON 7 50133206430000 214130 2/26/2024 YELLOW JACKET PERF PBU 09-52 50029236180000 218168 3/24/2024 HALLIBURTON PPROF SD-06 50133205820000 208160 2/20/2024 YELLOW JACKET PERF SRU 222-33 50133207150000 223100 12/19/2023 AK E-LINE Perf Please include current contact information if different from above T38683 T38684 T38685 T38686 T38689 T38687 T38690 T38691 T38691T38692 T38963 T38963 T38694 T38694 T38694 T38695 T38696 T38697 T38698SRU 222-33 50133207150000 223100 12/19/2023 AK E-LINE Perf Meredith Guhl Digitally signed by Meredith Guhl Date: 2024.04.09 13:48:29 -08'00' 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 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): 4,100'N/A Casing Collapse Structural Conductor 1,410psi Surface 4,790psi Intermediate Production 10,540psi 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 Liner Top Pkr; N/A 2,523' MD/2,349' TVD; N/A 3,886' 4,023' 3,811' Swanson River Sterling-Upper Beluga Gas 16" 7-5/8" See Attached Schematic 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Swanson River Unit (SRU) 222-33CO 716A Same 3,885'3-1/2" 1,207psi 1,578' N/A Length February 15, 2024 Tieback 3-1/2" 4,099' Perforation Depth MD (ft): See Attached Schematic 2,980psi 6,890psi 120'120' 2,738' Size 120' 2,738' MD Hilcorp Alaska, LLC Proposed Pools: 9.2# / L-80 TVD Burst 2,531' 10,160psi 2,554' 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 FEDA028399 223-100 50-133-20715-00-00 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: Perforate Repair Wepair Well Exploratory Stratigraphic Development Service BOP TestMechanical Integrity Test No Wellbore schematic Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Samantha Coldiron at 2:21 pm, Feb 07, 2024 324-057 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2024.02.06 18:58:11 - 09'00' Noel Nocas (4361) BJM 2/14/24 Perforate f SFD 2/8/2024 Sterling-Upper Beluga Gas 10-404 DSR-2/13/24($8JLC 2/21/2024 Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2024.02.21 15:39:51 -09'00'02/21/24 RBDMS JSB 022324 Initial Completion Well: SRU 222-33 Well Name:SRU 222-33 API Number:50-133-20715-00-00 Current Status:New Drill Gas Producer Permit to Drill Number:223-100 First Call Engineer:Jake Flora (720) 988-5375 (c) Second Call Engineer:Chad Helgeson (907) 229-4824 (c) Maximum Expected BHP: 1,566 psi @ 3,587’ TVD 8.4 ppg normal gradient Max. Potential Surface Pressure: 1,207 psi Using 0.1 psi/ft Current Status: Producing Gas Well 998mcfd, 1bwpd @ 452 psi (1/31/24) Brief Well Summary SRU 222-33 was drilled with Hilcorp Rig 169 December 2023 targeting Sterling and Beluga sands in the central block of Swanson River Field. The well was successfully completed in the Upper Beluga 36-8 sands with an IP of 1MM. The tubing pressure has been steadily dropping since with the objective of this sundry is to increase productivity by plugging back the Beluga and perforating sands in the Sterling. Hilcorp requests a variance from BLM Onshore Order #2 to allow the CIBP to be set within 10’ of the open perforations AND to allow just 5’ of cement to be placed on the plug. This request is due to the small interval between open and proposed perforations at just 31’. Notes Regarding Wellbore Condition Current Gross Perf Interval: 3736-3799’ MD (3530-3591’ TVD) 12/15/23 Cleanout well with 2.75” coil bit to 4027’, blow dry w N2 12/19/23 Perforated UB 36-8 3795-99’ The top of the Beluga Pool is 3,718’ MD/3,512’ TVD. Procedure 1. RU E-line, PT lubricator to 2000 psi 2. Depress fluid level with pad gas OR nitrogen 3. Set plug at ~3726’ (10’ over the highest open perforation) 4. Dump 5’ cement on plug 5. Perforate Sterling sands from the bottom up within the below intervals: Well Name Zone Top MD Base MD Top TVD Base TVD Footage SRU 222-33 ST_A12 2738 2749 2554 2565 10 SRU 222-33 ST_A13 2826 2829 2639 2642 3 SRU 222-33 ST_A14 2843 2847 2656 2660 3 SRU 222-33 ST_A14 2861 2871 2673 2683 10 SRU 222-33 ST_B1 2926 2956 2736 2766 30 SRU 222-33 ST_B2 3026 3053 2833 2861 28 SRU 222-33 ST_B3 3141 3150 2946 2955 8 1,207 psi Surface casing shoe is set at 2,738' MD in this well. SFD 8.4 ppg normal gradient Top of Sterling/Upper Beluga Gas Pool is about 2,485' MD / 2,305' TVD in this well. SFD Initial Completion Well: SRU 222-33 SRU 222-33 ST_B3 3186 3189 2991 2994 3 SRU 222-33 ST_B4 3204 3206 3008 3010 2 SRU 222-33 ST_B5 3236 3257 3039 3060 21 SRU 222-33 ST_B8 3625 3632 3420 3428 8 SRU 222-33 ST_B9 3697 3705 3491 3500 8 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. Frac Calcs: Using 13.5 ppg EMW (0.702 psi/ft) frac gradient at from SC shoe depth c. Shallowest Allowable Perf TVD = MPSP/(0.702-0.1) = 1207 psi / 0.602 = 2004‘ TVD Attachments: 1. Current Wellbore Schematic 2. Proposed Wellbore Schematic 3. Nitrogen SOP , equivalent to 2,160' MD. Surface casing shoe is set at 2,738' MD. AOGCC does not allow perforation of surface casing. SFD potential SFD Shallowest Allowable Perf TVD = MPSP/(0.702-0.1) = 1207 psi / 0.602 = 2004‘ TVD Updated by CJD 1-11-24 SCHEMATIC Swanson River Unit SRU 222-33 PTD: 223-100 API: 50-133-20715-00-00 PBTD = 4,023’ MD / TVD = 3,811’ TD = 4,100’ MD / TVD = 3,886’ RKB to GL = 18.0’ CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16” Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 120' 7-5/8" Surf Csg 29.7 L-80 TXP BTC 6.875” Surf 2,738’ 3-1/2" Prod Lnr 9.2 L-80 Hyd 563 2.867” 2,523’ 4,099’ 3-1/2" Prod Tieback 9.2 L-80 Hyd 563 2.867” Surf 2,531’ 1 16” 7-5/8” 9-7/8” hole 3-1/2” JEWELRY DETAIL No. Depth ID OD Item 1 2,523’ 3.500” 6.540” Flex-Lock liner hanger, HRDE ZXPN Liner top Packer & Bullet Seal assembly OPEN HOLE / CEMENT DETAIL 7-5/8" TOC @ Surface Pumped 156 bbls of 12ppg lead and 34bbls 15.8 ppg tail. (67 bbls of cement returns) 3-1/2” TOC @ TOL, Pumped 46 bbls (115sx) 12 ppg Type I II Lead followed by 24 bbl (122sx) of 15.3 ppg Type I II cement, with no losses. Circulated 30 bbls of spacer & 24bbls of cement contaminated mud. 6-3/4” hole PERFORATION DETAIL Sands Top MD Btm MD Top TVD Btm TVD FT Date Status UB 36-8 3,736’ 3,743’ 3,530’ 3,537’ 7 12/19/23 Open UB 36-8 3,773’ 3,776’ 3,567’ 3,570’ 3 12/19/23 Open UB 36-8 3,795’ 3,799’ 3,587’ 3,591’ 4 12/18/23 Open Updated by DMA 02-01-24 PROPOSED Swanson River Unit SRU 222-33 PTD: 223-100 API: 50-133-20715-00-00 PBTD = 4,023’ MD / TVD = 3,811’ TD = 4,100’ MD / TVD = 3,886’ RKB to GL = 18.0’ CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16” Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 120' 7-5/8" Surf Csg 29.7 L-80 TXP BTC 6.875” Surf 2,738’ 3-1/2" Prod Lnr 9.2 L-80 Hyd 563 2.867” 2,523’ 4,099’ 3-1/2" Prod Tieback 9.2 L-80 Hyd 563 2.867” Surf 2,531’ 1 16” 7-5/8” 9-7/8” hole 3-1/2” JEWELRY DETAIL No. Depth ID OD Item 1 2,523’ 3.500” 6.540” Flex-Lock liner hanger, HRDE ZXPN Liner top Packer & Bullet Seal assembly 2 ±3,726’ CIBP w/ 5’ cement – TOC ~ 3,721’ OPEN HOLE / CEMENT DETAIL 7-5/8" TOC @ Surface Pumped 156 bbls of 12ppg lead and 34bbls 15.8 ppg tail. (67 bbls of cement returns) 3-1/2” TOC @ TOL, Pumped 46 bbls (115sx) 12 ppg Type I II Lead followed by 24 bbl (122sx) of 15.3 ppg Type I II cement, with no losses. Circulated 30 bbls of spacer & 24bbls of cement contaminated mud. 6-3/4” hole PERFORATION DETAIL Sands Top MD Btm MD Top TVD Btm TVD FT Date Status ST_A12 ±2,738' ±2,749' ±2,554' ±2,565' ±10' Proposed TBD ST_A13 ±2,826' ±2,829' ±2,639' ±2,642' ±3' Proposed TBD ST_A14 ±2,843' ±2,847' ±2,656' ±2,660' ±3' Proposed TBD ST_A14 ±2,861' ±2,871' ±2,673' ±2,683' ±10' Proposed TBD ST_B1 ±2,926' ±2,956' ±2,736' ±2,766' ±30' Proposed TBD ST_B2 ±3,026' ±3,053' ±2,833' ±2,861' ±28' Proposed TBD ST_B3 ±3,141' ±3,150' ±2,946' ±2,955' ±8' Proposed TBD ST_B3 ±3,186' ±3,189' ±2,991' ±2,994' ±3' Proposed TBD ST_B4 ±3,204' ±3,206' ±3,008' ±3,010' ±2' Proposed TBD ST_B5 ±3,236' ±3,257' ±3,039' ±3,060' ±21' Proposed TBD ST_B8 ±3,625' ±3,632' ±3,420' ±3,428' ±8' Proposed TBD ST_B9 ±3,697' ±3,705' ±3,491' ±3,500' ±8' Proposed TBD ST_A12 ±2,738' ±2,749' ±2,554' ±2,565' ±10' Proposed TBD UB 36-8 3,736’ 3,743’ 3,530’ 3,537’ 7 12/19/23 Open UB 36-8 3,773’ 3,776’ 3,567’ 3,570’ 3 12/19/23 Open UB 36-8 3,795’ 3,799’ 3,587’ 3,591’ 4 12/18/23 Open 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. 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: 2/2/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20240202 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BRU 213-26 50283201920000 223069 11/5/2023 AK E-LINE PERF KU 13-06A 50133207160000 223112 12/28/2023 AK E-LINE CBL MPU B-09 50029212970000 185034 1/26/2024 READ Caliper Survey MPU B-19 50029214510000 185230 1/26/2024 READ Caliper Survey PBU W-08A 50029219060100 202090 12/27/2023 HALLIBURTON WFL-TMD3D SRU 222-33 50133207150000 223100 12/16/2023 AK E-LINE CBL Please include current contact information if different from above. T38477 T38478 T38479 T38480 T38481 T38482 2/2/2024 SRU 222-33 50133207150000 223100 12/16/2023 AK E-LINE CBL Kayla Junke Digitally signed by Kayla Junke Date: 2024.02.02 15:40:47 -09'00' 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:AOGCC Records (CED sponsored) Subject:Fwd: SRU 222-33 AOGCC 10-403 323-661 PTD 223-100 Approved 12-15-23 CBL Log Date:Monday, December 18, 2023 9:09:19 AM Attachments:UNCORRELATED MAIN PASS.las UNCORRELATED MAIN PASS.pdf Email below for the well file Sent from my iPhone Begin forwarded message: From: "McLellan, Bryan J (OGC)" <bryan.mclellan@alaska.gov> Date: December 18, 2023 at 9:08:02 AM AKST To: Jacob Flora <Jake.Flora@hilcorp.com> Cc: Chad Helgeson <chelgeson@hilcorp.com>, "McLellan, Bryan J (OGC)" <bryan.mclellan@alaska.gov> Subject: Re: SRU 222-33 AOGCC 10-403 323-661 PTD 223-100 Approved 12-15-23 CBL Log Jake, Hilcorp has approval to proceed with perfs per sundry. Bryan McLellan Sent from my iPhone On Dec 16, 2023, at 11:44 AM, Jacob Flora <Jake.Flora@hilcorp.com> wrote: Bryan, Please see attached CBL for the latest Swanson well. The TOC I’d right at the liner top. Let us know if you have any questions about the log, Thanks, Jake Sent from my iPhone Begin forwarded message: From: Daniel Scarpella <Daniel.Scarpella@hilcorp.com> Date: December 16, 2023 at 10:23:22 AM AKST To: Chad Helgeson <chelgeson@hilcorp.com>, Jacob Flora <Jake.Flora@hilcorp.com>, Meredyth Richards <Meredyth.Richards@hilcorp.com>, Sean Wagner <Sean.Wagner@hilcorp.com> Cc: Taylor Malone <tmalone@hilcorp.com> Subject: SRU 222-33 CBL Log Good day all, Looks like you have good CMT to LNR top. I’ll let you be the judge of that. Let me know via text, that we’re good to reverse out the fluid from the wellbore. Cell reception is very bad out here. Seem to be getting tests fine. Your support is appreciated, Daniel Scarpella Hilcorp North Slope LLC., Alaska | Sr. Well Site Supervisor | PBU Wells Team 907.230.2692 cell | 907.659.5580 office | H 2154 | alt. Anthony Knowles Well Interventions: daniel.scarpella@hilcorp.com RWO Operations: pbwellsrwowss@hilcorp.com P.O. Box 340067| DP PBOC 34 | PBOC 20| Prudhoe Bay, AK 99734 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, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, thenpromptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibilityof the recipient to ensure that the onward transmission, opening, or use of this message and anyattachments will not adversely affect its systems or data. No responsibility is accepted by thecompany in this regard and the recipient should carry out such virus and other checks as it considersappropriate. 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: 12/15/2023 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL SRU 222-33 PTD: 223-100 API: 50-133-20715-00-00 FINAL LWD FORMATION EVALUATION LOGS (12/02/2023 to 12/07/2023) ADR, DGR, PCG, ALD, CTN (2” & 5” MD/TVD Color Logs) Final Definitive Directional Survey SFTP Transfer - Data Folders: Please include current contact information if different from above. PTD: 223-100 T38228 12/18/2023Kayla Junke Digitally signed by Kayla Junke Date: 2023.12.18 11:16:12 -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 Other: Initial Completion, 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): 4,100'N/A Casing Collapse Structural Conductor 1,410psi Surface 4,790psi Intermediate Production 10,540psi 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 Liner Top Pkr; N/A 2,521' MD/2,347' TVD; N/A 3,886'4,023'3,811' Swanson River Sterling-Upper Beluga Gas 16" 7-5/8" See Attached Schematic 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Swanson River Unit (SRU) 222-33CO 716A Same 3,885'3-1/2" 1207 1,578' N/A Length December 14, 2023 Tieback 3-1/2" 4,099' Perforation Depth MD (ft): See Attached Schematic 2,980psi 6,890psi 120'120' 2,737' Size 120' 2,737' MD Hilcorp Alaska, LLC Proposed Pools: 9.2# / L-80 TVD Burst 2,521' 10,160psi 2,553' 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 FEDA028399 223-100 50-133-20715-00-00 Tubing Size: PRESENT WELL CONDITION SUMMARY Chad Helgeson, Operations Engineer AOGCC USE ONLY Tubing Grade: 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: m n P s 66 t 2 c 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 12:54 pm, Dec 12, 2023 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2023.12.12 10:07:26 - 09'00' Noel Nocas (4361) 323-661 SFD 12/13/2023 Yes, for CT portion 12/14/23 Bryan McLellan 10-407 Perforate Submit CBL to AOGCC and obtain approval prior to perforating. BJM 12/14/23 DSR-12/14/23 X CT BOP test to 3000 psi *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2023.12.15 09:47:20 -09'00'12/15/23 RBDMS JSB 012424 Initial Completion Well: SRU 222-33 Well Name: SRU 222-33 API Number: 50-133-20715-00-00 Current Status: New Drill Gas Producer Permit to Drill Number: 223-100 First Call Engineer: Chad Helgeson (907) 229-4824 (c) Second Call Engineer: Jake Flora (720) 988-5375 (c) Maximum Expected BHP: 1,566 psi @ 3,587’ TVD 8.4 ppg normal gradient Max. Potential Surface Pressure: 1,207 psi Using 0.1 psi/ft Brief Well Summary SRU 222-33 was drilled with Hilcorp Rig 169 December 2023 targeting Sterling and Beluga sands in the central block of Swanson River Field. The well was TD’ this week and completed with 3.5”. The objective of this sundry is to clean out the liner with coil tubing, complete a CBL, remove fluid from well bore and perforate sands working from the bottom of the well. Initial targeted sand will be in the Beluga Gas Pool/PA. Wellbore Conditions: The well is full of 9.1 ppg drilling mud, with the tubing and annulus displaced to Corrosion inhibited 6% KCL, the tubing and annulus were pressure tested to 3500 psi. The top of the Beluga Pool is 3,718’ MD/3,512’ TVD. Coiled Tubing Procedure 1. MIRU Coiled Tubing and pressure control equipment 2. PT lubricator to 250psi low / 3000psi high a. Provide AOGCC and BLM 24hr notice for BOP test 3. MU cleanout BHA a. Motor and roller cone bit for cement stringers 4. RIH to PBTD (4,023’) cleanout well and swap well over to water 5. RU Eline on coil BOPs or run memory CBL on coil 6. Log CBL 7. RDMO EL 8. CT RIH with nozzle and blow well dry with nitrogen a. Reverse circulate water out of wellbore b. Target recovery = 35bbls i. Tubing Volume: 22bbls ii. Liner volume: 13 bbls 9. Trap ~1000 psi of N2 on wellbore (confirm with OE for final pressure left on well) 10. RDMO CT 11. MIRU E-line and pressure control equipment 12. PT lubricator to 250psi low / 2000psi high 13. RIH and perforate per RE/Geo (see table below) Initial targeted sand will be in the Beluga Gas Pool/ top of the Beluga Pool is 3,718’ MD/ Submit CBL to AOGCC and obtain approval prior to perforating. -bjm Initial Completion Well: SRU 222-33 Sands Top MD Btm MD Top TVD Btm TVD FT UB_35 3736 3743 3529 3537 7 UB_36-8 3774 3776 3567 3570 3 UB_36-8 3795 3799 3587 3591 4 14. Make correlation pass and send log in to Operations Engineer, Reservoir Engineer and the Geologist. a. Record initial and 5/10/15 minute tubing pressures after firing b. Above perfs will be shot in the Beluga Gas Pool governed by CO 716A 15. RD E-Line Unit and turn well over to production 16. Operations to flow well and test zones 17. Test SVS as per 20 AAC 25.265 once stable flow is achieved a) Notify AOGCC 24hrs in advance of testing SVS E-line Procedure (Contingency) If any zone produces sand and/or water or needs isolated: 18. MIRU Eline and N2 pump truck 19. Pressure test equipment to 3,500 psi High/250 psi Low 20. Eline run PT to find fluid level 21. RU N2 or use gas lift and push fluid below perfs (verify fluid depth with PT tool) 22. PU 3-1/2” CIBP/WRBP or patch Note: All proposed perforations are in the same Pool / PA. A CIBP may be used instead of WRP if it is determined that no cement is needed for operational purposes. If necessary to cleanout or unload well with coiled tubing, 23. MIRU Coiled Tubing Unit, PT BOPE to 3,000 psi High/250 psi Low 24. Provide AOGCC 24hrs notice of BOP test 25. PU wash nozzle, RIH and cleanout well to below perfs or proposed plug depth 26. 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 27. RDMO coil tubing Attachments: 1. Current Wellbore Schematic 2. Proposed Wellbore Schematic 3. Fox CT BOP Drawing 4. Nitrogen procedure Updated by DMA 12-12-23 SCHEMATIC Swanson River Unit SRU 222-33 PTD: 223-100 API: 50-133-20715-00-00 PBTD = 4,023’ MD / TVD = 3,811’ TD = 4,100’ MD / TVD = 3,886’ RKB to GL = 18.0’ CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16” Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 120' 7-5/8" Surf Csg 29.7 L-80 TXP BTC 6.875” Surf 2,737’ 3-1/2" Prod Lnr 9.2 L-80 Hyd 563 2.867” 2,521’ 4,099’ 3-1/2" Prod Tieback 9.2 L-80 Hyd 563 2.867” Surf 2,521’ 1 16” 7-5/8” 9-7/8” hole 3-1/2” JEWELRY DETAIL No. Depth ID OD Item 1 2,521’ 3.500” 6.540” Flex-Lock liner hanger, HRDE ZXPN Liner top Packer & Bullet Seal assembly OPEN HOLE / CEMENT DETAIL 7-5/8" TOC @ Surface Pumped 156 bbls of 12ppg lead and 34bbls 15.8 ppg tail. (67 bbls of cement returns) 3-1/2” TOC @ TOL, Pumped 46 bbls (115sx) 12 ppg Type I II Lead followed by 24 bbl (122sx) of 15.3 ppg Type I II cement, with no losses. Circulated 30 bbls of spacer & 24bbls of cement contaminated mud. 6-3/4” hole Updated by DMA 12-12-23 PROPOSED Swanson River Unit SRU 222-33 PTD: 223-100 API: 50-133-20715-00-00 PBTD = 4,023’ MD / TVD = 3,811’ TD = 4,100’ MD / TVD = 3,886’ RKB to GL = 18.0’ CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16” Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 120' 7-5/8" Surf Csg 29.7 L-80 TXP BTC 6.875” Surf 2,737’ 3-1/2" Prod Lnr 9.2 L-80 Hyd 563 2.867” 2,521’ 4,099’ 3-1/2" Prod Tieback 9.2 L-80 Hyd 563 2.867” Surf 2,521’ 1 16” 7-5/8” 9-7/8” hole 3-1/2” JEWELRY DETAIL No. Depth ID OD Item 1 2,521’ 3.500” 6.540” Flex-Lock liner hanger, HRDE ZXPN Liner top Packer & Bullet Seal assembly OPEN HOLE / CEMENT DETAIL 7-5/8" TOC @ Surface Pumped 156 bbls of 12ppg lead and 34bbls 15.8 ppg tail. (67 bbls of cement returns) 3-1/2” TOC @ TOL, Pumped 46 bbls (115sx) 12 ppg Type I II Lead followed by 24 bbl (122sx) of 15.3 ppg Type I II cement, with no losses. Circulated 30 bbls of spacer & 24bbls of cement contaminated mud. 6-3/4” hole PERFORATION DETAIL Sands Top MD Btm MD Top TVD Btm TVD FT Date Status UB_35 ±3,736’ ±3,743’ ±3,529’ ±3,537’ ±7’ Proposed TBD UB_36-8 ±3,774’ ±3,776’ ±3,567’ ±3,570’ ±3’ Proposed TBD UB_36-8 ±3,795’ ±3,799’ ±3,587’ ±3,591’ ±4’ Proposed TBD 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. STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION DIVERTER Test Report for: Reviewed By: P.I. Suprv Comm ________SWANSON RIV UNIT 222-33 JBR 01/18/2024 MISC. INSPECTIONS: GAS DETECTORS: DIVERTER SYSTEM:MUD SYSTEM: P/F P/F P/F Alarm Visual Alarm Visual Time/Pressure Size Number of Failures:0 Remarks:Test was performed with a 4.5" test joint 15 accumulator bottles with an average of 1,000 PSI 4 alarms stations tested. Very good test. They were ready for me when I arrived and had all there ducks in a row. TEST DATA Rig Rep:John Van EvraOperator:Hilcorp Alaska, LLC Operator Rep: Contractor/Rig No.:Hilcorp 169 PTD#:2231000 DATE:12/2/2023 Well Class:DEV Inspection No:divJDH231202100125 Inspector Josh Hunt Inspector Insp Source Related Insp No: Test Time:1 ACCUMULATOR SYSTEM: Location Gen.:P Housekeeping:P Warning Sign P 24 hr Notice:P Well Sign:P Drlg. Rig.P Misc:NA Methane:P P Hydrogen Sulfide:P P Gas Detectors Misc:0 NA Designed to Avoid Freeze-up?P Remote Operated Diverter?P No Threaded Connections?P Vent line Below Diverter?P Diverter Size:21.25 P Hole Size:9.88 P Vent Line(s) Size:16 P Vent Line(s) Length:89 P Closest Ignition Source:75 P Outlet from Rig Substructure:80 P Vent Line(s) Anchored:P Turns Targeted / Long Radius:NA Divert Valve(s) Full Opening:P Valve(s) Auto & Simultaneous: Annular Closed Time:32 P Knife Valve Open Time:2 P Diverter Misc:0 NA Systems Pressure:P3000 Pressure After Closure:P1500 200 psi Recharge Time:P20 Full Recharge Time:P107 Nitrogen Bottles (Number of):P4 Avg. Pressure:P2475 Accumulator Misc:NA0 P PTrip Tank: P PMud Pits: P PFlow Monitor: 0 NAMud System Misc:       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: Swanson River Field, Sterling/Upper Beluga Gas Pool, SRU 222-33 Hilcorp Alaska, LLC Permit to Drill Number: 223-100 Surface Location: 1871' FNL, 1950' FEL, Sec 33, T8N, R9W, SM, AK Bottomhole Location: 1723' FNL, 2232' FWL, Sec 33, T8N, R9W, SM, AK Dear Mr. Myers: Enclosed is the approved application for the permit to drill the above referenced well. Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Brett W. Huber, Sr. Chair, Commissioner DATED this ___ day of November 2023. Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2023.11.15 14:26:32 -09'00' 15 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: 3,973' TVD: 3,755' 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): 187.6 15. Distance to Nearest Well Open Surface: x-345719 y- 2464588 Zone-4 169.6 to Same Pool: 750' to SRU 32A-33 16. Deviated wells: Kickoff depth: 250 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 30.6 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD Conductor 16" 84# X-56 Weld 120' Surface Surface 120' 120' 9-7/8" 7-5/8" 29.7# L-80 TXP 2,649' Surface Surface 2,649' 2,462' 6-3/4" 3-1/2" 9.2# L-80 Hyd 563 1,523' 2,450' 2,272' 3,973' 3,755' Tieback 3-1/2" 9.2# L-80 Hyd 563 2,450' Surface Surface 2,450' 2,272' 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 SRU 222-33 Swanson River Field Sterling/Upper Beluga Gas Pool Cement Quantity, c.f. or sacks Commission Use Only See cover letter for other requirements. 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 - 682 ft3 / T - 160 ft3 1240 1743' FNL, 2476' FWL, Sec 33, T8N, R9W, SM, AK 1723' FNL, 2232' FWL, Sec 33, T8N, R9W, SM, AK N/A 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Hilcorp Alaska, LLC 1871' FNL, 1950' FEL, Sec 33, T8N, R9W, SM, AK AKA028399 1760 18. Casing Program: Top - Setting Depth - BottomSpecifications 1615 Cement Volume MDSize Plugs (measured): (including stage data) Driven L - 2093 ft3 / T - 217 ft3 LengthCasing Conductor/Structural Effect. Depth MD (ft): Effect. Depth TVD (ft): Authorized Title: Authorized Signature: Production Liner Intermediate Authorized Name: Drilling Manager Monty Myers 12/9/2023 996' to nearest unit boundary Sean Mclaughlin sean.mclaughlin@hilcorp.com 907-223-6784 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): GL / BF Elevation above MSL (ft): Perforation Depth MD (ft): Tieback Assy. Stratigraphic Test No Mud log req'd: Yes No No Directional svy req'd: Yes No Seabed ReportDrilling Fluid Program 20 AAC 25.050 requirements BOP SketchDrilling Program Time v. Depth Plot Shallow Hazard Analysis Single Well Gas Hydrates No Inclination-only svy req'd: Yes No Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal No No Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g) Drilling Manager 10/24/23 Monty M Myers By Grace Christianson at 2:13 pm, Oct 25, 2023 Submit FIT/LOT results to AOGCC within 48 hrs of performing test BJM 11Nov23 50-133-20715-0000223-100 DSR-11/2/23 BOP test to 3000 psi. Annular test to 2500 psi. Verify shut-in bottom hole pressure in offset injector SRU 32-33WD and adjust mud weight as needed to maintain overbalance prior to drilling injection zone. A.Dewhurst 09NOV23($8JLC 11/15/2023 Brett W. Huber, Sr.Digitally signed by Brett W. Huber, Sr. Date: 2023.11.15 14:26:55 -09'00' 11/15/23 11/15/23 SRU 222-33 Drilling Program Swanson River Unit Rev. PTD October 23, 2023 SRU 222-33 Drilling Procedure 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..................................................................8 9.0 R/U and Preparatory Work.....................................................................................................11 10.0 N/U 21-1/4” 2M Diverter .........................................................................................................12 11.0 Drill 9-7/8” Hole Section ..........................................................................................................13 12.0 Run 7-5/8” Surface Casing ......................................................................................................15 13.0 Cement 7-5/8” Surface Casing.................................................................................................17 14.0 BOP N/U and Test....................................................................................................................20 15.0 Drill 6-3/4” Hole Section ..........................................................................................................21 16.0 Run 3-1/2” Production Liner ...................................................................................................23 17.0 Cement 3-1/2” Production Liner .............................................................................................26 18.0 3-1/2” Liner Tieback Polish Run .............................................................................................30 19.0 3-1/2” Tieback Run..................................................................................................................30 20.0 Diverter Schematic ..................................................................................................................31 21.0 BOP Schematic ........................................................................................................................32 22.0 Wellhead Schematic.................................................................................................................33 23.0 Anticipated Drilling Hazards ..................................................................................................34 24.0 Hilcorp Rig 169 Layout ...........................................................................................................36 25.0 FIT/LOT Procedure.................................................................................................................37 26.0 Choke Manifold Schematic......................................................................................................38 27.0 Casing Design Information......................................................................................................39 28.0 6-3/4” Hole Section MASP .......................................................................................................40 29.0 Spider Plot (Governmental Sections NAD83).........................................................................41 30.0 660’ Radius for SSSV...............................................................................................................42 31.0 Surface Plat (As-Staked NAD27 & NAD83)...........................................................................43 Page 2 Version PTD October, 2023 SRU 222-33 Drilling Procedure Rev 0 1.0 Well Summary Well SRU 222-33 Pad & Old Well Designation SRU 32-33 Planned Completion Type 3-1/2”Production Liner w/Tieback Target Reservoir(s)Sterling Planned Well TD, MD / TVD 3973’MD / 3755’ TVD PBTD, MD 3873’ MD AFE Number AFE Drilling Days 16 AFE Drilling Amount Maximum Anticipated Pressure (Surface)1240 psi Maximum Anticipated Pressure (Downhole/Reservoir)1615 psi Work String 4-1/2” 16.6# S-135 CDS-40 RKB –GL 187.62 Ground Elevation 169.62 BOP Equipment 11” 5M Annular BOP 11” 5M Double Ram 11” 5M Single Ram Page 3 Version PTD October, 2023 SRU 222-33 Drilling Procedure Rev 0 2.0 Management of Change Information Page 4 Version PTD October, 2023 SRU 222-33 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”17”84 X-56 Weld 2980 1410 - Surface 9-7/8”7-5/8”6.875”6.750”8.500”29.7 L-80 TXP 6890 4790 683 Prod 6-3/4”3-1/2”2.992”2.867”4.250”9.2 L-80 HYD-563 10160 10540 207 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 All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery to TSA in Fairbanks). Page 5 Version PTD October, 2023 SRU 222-33 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 Ensure time entry adds up to 24 hours total. x Capture any out of scope work as NPT. 5.2 Afternoon Updates x Submit a short operations update each work day to KenaiCIODrilling@hilcorp.com 5.3 Intranet Home Page Morning Update x Submit a short operations update each morning by 7am on the company intranet homepage. 5.4 EHS Incident Reporting x Notify EHS field coordinator. 1. John Coston: O: (907) 777-6726 C: (907) 227-3189 2. Jacob Nordwall: O: (907) 777-8418 C: (907) 748-0753 3. For Spills: 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 sean.mclaughlin@hilcorp.com, and cdinger@hilcorp.com 5.6 Casing and Cmt report x Send casing and cement report for each string of casing to sean.mclaughlin@hilcorp.com, and cdinger@hilcorp.com Page 6 Version PTD October, 2023 SRU 222-33 Drilling Procedure Rev 0 6.0 Planned Wellbore Schematic Page 7 Version PTD October, 2023 SRU 222-33 Drilling Procedure Rev 0 7.0 Drilling / Completion Summary SRU 222-33 is going to be drilled for the Sterling Sands in the Central block. There have been three drill wells since 2017 [241-33, 241-33B, and 231-33] that have logged 7+ Sterling sands in this area, only 4 of which have been partially drained. The objective of this well is to accelerate the rate from these sands. The base plan is a directional wellbore with a kickoff point at ~400’MD. Maximum hole angle will be 24 deg. and TD of the well will be 3973’ TMD/ 3755’ TVD, ending with 12 deg inclination. Drilling operations are expected to commence approximately December 2023. The Hilcorp Rig # 169 will be used to drill the wellbore then run casing and cement. 7-5/8” surface casing will be run and cemented to surface to ensure protection of any shallow freshwater resources. Cement returns to surface will confirm TOC at surface. 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 # 169 to well site 2. N/U diverter and test. 3. Drill 9-7/8”hole to 2649’ MD. Run and cmt 7-5/8”surface casing. 4. ND diverter, N/U & test 11” x 5M BOP to 3000 psi 5. Test Surface casing to 3500 psi. 6. Drill out shoe and perform a FIT to 13.5 ppg EMW 7. Drill 6-3/4” hole section to 3973’MD. Perform Wiper trip. 8. Run and cmt 3-1/2”production liner. 9. PU polish mill assembly and RIH to polish sealbore 10. Displace well above liner top to 6% KCL completion fluid. 11. RIH and land 3-1/2” tieback string in liner top. 12. MIT Tubing and IA to 2000 psi. 13. N/D BOP, N/U dry hole tree, RDMO. Reservoir Evaluation Plan: 1. Surface hole: GR + Res LWD 2. Production Hole: Triple Combo LWD 3. Mud loggers from surface casing point to TD. 250' 30 Page 8 Version PTD October, 2023 SRU 222-33 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 and all BLM regulations pertaining to Onshore Order No.1. 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 SRU 222-33. Ensure to provide AOGCC 24 hrs notice prior to testing BOPs. And BLM 48 hrs notice prior to testing. x The initial test of BOP equipment will be to 250/3000 psi & subsequent tests of the BOP equipment will be to 250/3000 psi for 5/10 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 APD. x If the BOP is used to shut in on the well in a well control situation, 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 and BLM approved drilling permits are posted on the rig floor and in Co Man office. x Review all conditions of approval of the AOGCC PTD on the 10-401 form and the BLM APD. Ensure that the conditions of approval are captured in shift handover notes until they are executed and complied with. Regulation Variance Requests: x BLM: o Onshore Oil and Gas Order No. 2.IV: Hilcorp requests approval to install a 2-1/16” 5M HCR valve on kill line in lieu of a check valve. Operator suspects a freeze plug risk associated with installation of a check valve in the kill line. o Onshore Oil and Gas Order No. 2.IV: Hilcorp requests approval to utilize flexible choke and kill lines in lieu of hard piping. Page 9 Version PTD October, 2023 SRU 222-33 Drilling Procedure Rev 0 Summary of BOP Equipment and Test Requirements Hole Section Equipment Test Pressure (psi) 9-7/8”x 21-1/4” x 2M Hydril MSP diverter Function Test Only 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: 250/3000 (Annular 2500 psi) Subsequent Tests: 250/3000 (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 testing BOPs. x Any other notifications required in APD. Required BLM Notifications: x 48 hours before spud. Follow up with actual spud date and time within 24 hours. x 72 hours before casing running and cmt operations x 72 hours before BOPE tests x 72 hours before logging, coring, & testing x Any other notifications required in APD Additional requirements may be stipulated on APD and Sundry. Page 10 Version PTD October, 2023 SRU 222-33 Drilling Procedure Rev 0 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) BLM Allie Schoessler / BLM Petroleum Engineer / (O): 907-271-3127 Email: aschoessler@blm.gov Use the below email address for BOP notifications to the BLM: BLM_AK_AKSO_EnergySection_Notifications@blm.gov 2016 Waste Prevention Rule - Waste Minimization Plan for Drilling: Hilcorp Alaska will not be venting or flaring any gas while drilling this well. The only waste produced from this well will be used mud and cuttings and will be handled at the Kenai Gas Field G&I facility for beneficial reuse, if possible after testing, and disposal. Page 11 Version PTD October, 2023 SRU 222-33 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 Seaboard 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 # 169, spot service company shacks, spot & R/U company man & toolpusher offices. 9.7 RU Mud loggers on surface hole section for gas detection only. No samples required 9.8 After rig equipment has been spotted, R/U handi-berm containment system around footprint of rig. 9.9 Mix mud for 9-7/8”hole section. 9.10 Install 5-1/2” liners in mud pumps. x HHF-1000 mud pumps are rated at 3036 psi (85%) / 370 gpm (100%) at 120 strokes with 5-1/2” liners. Page 12 Version PTD October, 2023 SRU 222-33 Drilling Procedure Rev 0 10.0 N/U 21-1/4” 2M Diverter 10.1 N/U 21-1/4” Hydril MSP 2M diverter System. x N/U 16-3/4” 3M x 21-1/4” 2M DSA (Hilcorp) on 16-3/4” 3M wellhead. 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. x NOTE: Ensure closing time on diverter annular is in line with API RP 64: 2..1.1.Annular element ID 20” or smaller: Less than 30 seconds 2..1.2.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 PTD October, 2023 SRU 222-33 Drilling Procedure Rev 0 10.5 Rig 169 and estimated Diverter line orientation on SRU 32-33 Pad: 11.0 Drill 9-7/8”Hole Section 11.1 P/U directional drilling assy: x 9-7/8” Openhole, 6-3/4” drilling tools 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. Hydraulics calculations and recommended TFA is attached below. x Workstring will be 4.5” 16.6# S-135 CDS40 11.2 Begin drilling out from 16”conductor at reduced flow rates to avoid broaching the conductor. Page 14 Version PTD October, 2023 SRU 222-33 Drilling Procedure Rev 0 11.3 Drill surface hole section to 2649’MD/ 2462’ TVD. Confirm this setting depth with the geologist and Drilling Engineer while drilling the well. x SRU 32-33WD (water injector) to be shut in 30 days prior to spud. x Drill through the water disposal zone in the A7-A10 Sterling. Set the casing shoe in the A11. x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Pump at ~400 gpm. Ensure shaker screens are set up to handle this flowrate. x Utilize Kenai and Inlet experience to drill through coal seams efficiently. x Keep swab and surge pressures low when tripping. x Make wiper trips every 1000’ 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 Take MWD surveys every stand drilled (60’ intervals). 11.4 9-7/8”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. System Type: 8.8 –9.5 ppg Pre-Hydrated Aquagel/freshwater spud mud Properties: Depths Density Viscosity Plastic Viscosity Yield Point API FL pH 120-2649’ 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 ggg g SRU 32-33WD (water injector) to be shut in 30 days prior to spud. Verify shut-in bottom hole pressure in offset injector SRU 32-33WD and adjust mud weight as needed to maintain overbalance in injection zone. See attached email dated 11/14/23 from Sean McLaughlin. -bjm Page 15 Version PTD October, 2023 SRU 222-33 Drilling Procedure Rev 0 11.5 At TD; pump sweeps, CBU, and pull a wiper trip back to the 16”conductor shoe. 11.6 TOH with the drilling assy, handle BHA as appropriate. 12.0 Run 7-5/8”Surface Casing 12.1 R/U and pull wearbushing. 12.2 R/U Weatherford 7-5/8”casing running equipment. x Ensure 7-5/8”TXP 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 7-5/8”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 Note M/U torque values required to achieve this position. x Install (1) centralizer every other joint to 300’. Do not run any centralizers above 300’ in the event a top job is needed. x Utilize a collar clamp until weight is sufficient to keep slips set properly. Page 16 Version PTD October, 2023 SRU 222-33 Drilling Procedure Rev 0 Page 17 Version PTD October, 2023 SRU 222-33 Drilling Procedure Rev 0 12.6 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. Slow in and out of slips. 12.7 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. 12.8 Lower string and land out in wellhead. Confirm measurements indicate the hanger has correctly landed out in the wellhead profile. 12.9 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. 12.10 After circulating, lower string and land hanger in wellhead again. 13.0 Cement 7-5/8”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 Discuss how to handle cmt returns at surface. x Confirm which pump will be utilized for displacement, and how fluid will be fed to displacement pump. x Determine 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 spacer. Test surface cmt lines. 13.5 Pump remaining spacer. 13.6 Drop bottom plug. Mix and pump cmt per below recipe. 13.7 Cement volume based on annular volume + 50% open hole excess. Job will consist of lead & tail, TOC brought to surface. Page 18 Version PTD October, 2023 SRU 222-33 Drilling Procedure Rev 0 Estimated Total Cement Volume: Cement Slurry Design: Lead Slurry (2149’ MD to surface)Tail Slurry (2649’ to 2149’ 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 volumes. number of sacks should be 363 lead and 161 tail. See attached email from Sean McLaughlin 11/14/23 -bjm363.3 sx 524.4 sx 161.1 sx Page 19 Version PTD October, 2023 SRU 222-33 Drilling Procedure Rev 0 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 (7-5/8” casing): 2649’- 100’ = 2549’x .04592 bpf = 117 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. 13.13 Do not overdisplace by more than 1 shoe track volume. Total volume in shoe track is 4.6 bbls. 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 Page 20 Version PTD October, 2023 SRU 222-33 Drilling Procedure Rev 0 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 sean.mclaughlin@hilcorp.com. 14.0 BOP N/U and Test 14.1 ND Diverter line and diverter 14.2 N/U multi-bowl wellhead assy. Install 7-5/8” 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 3-1/2” and 4-1/2”BOP test assy, land out test plug (if not installed previously). x Utilize 3-1/2” and 4-1/2” test joints. x Test BOP to 250/3000 psi for 5/10 min. x Test annular to 250/2500 psi for 5/10 min with a 3-1/2” test joint 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. Page 21 Version PTD October, 2023 SRU 222-33 Drilling Procedure Rev 0 15.0 Drill 6-3/4” 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. 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 6-3/4” hole section mud program summary: Starting mud weight for the production interval is 9.0ppg or the surface interval mud weight at TD, whichever is heavier. 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 2649’- 3972’9.0 –9.7 40-53 15-25 15-25 8.5-9.5 11.0 Page 22 Version PTD October, 2023 SRU 222-33 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 –10.0 ppg 0.1 ppb 1 ppb 0.5 ppb (maintain per dilution rate) 15.9 TIH w/ 6-3/4” directional assy to TOC. Shallow test MWD and LWD on trip in. Note depth TOC tagged on AM report. 15.10 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 6880 psi / 2 = 3440 psi. 15.11 Drill out shoe track and 20’ of new formation. 15.12 CBU and condition mud for FIT. 15.13 Conduct FIT to 13.5 ppg EMW. (13.0 FIT = 24 bbl KTV) 15.14 Drill 6-3/4” hole section to 3972’ MD / 3755’ TVD x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Pump at ~200-270 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 600’ 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. 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 7-5/8”shoe. 15.16 TOH with the drilling assy, standing back enough drill pipe for the upcoming liner run 15.17 POOH LDDP and BHA. 15.18 Ensure 2-7/8” x 5” VBRs previously installed in BOP stack and tested with 3-1/2” test joint. Page 23 Version PTD October, 2023 SRU 222-33 Drilling Procedure Rev 0 16.0 Run 3-1/2”Production Liner 16.1. R/U Parker 3-1/2”casing running equipment. x Ensure 3-1/2”HYD 563 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 casing tools. 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 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 16.4. Continue running 3-1/2”production liner 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 7-5/8” shoe. Leave the centralizers free floating. 16.5. Continue running 3-1/2” production liner Page 24 Version PTD October, 2023 SRU 222-33 Drilling Procedure Rev 0 Page 25 Version PTD October, 2023 SRU 222-33 Drilling Procedure Rev 0 16.6. Run in hole w/ 3-1/2” liner to the 7-5/8” 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. PU 3-1/2” 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. 16.13. Continue running in hole at slow speeds to avoid surging well. Target 20 ft/min and adjust slower as hole conditions dictate. 16.14. Swedge up and wash last stand to bottom. P/U 5’ off bottom. Note slack-off and pick-up weights. 16.15. 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. 16.16. Rotate and reciprocate string if hole conditions allow. Circ until hole and mud is in good condition for cementing. Page 26 Version PTD October, 2023 SRU 222-33 Drilling Procedure Rev 0 17.0 Cement 3-1/2”Production Liner 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 rotate and reciprocate the liner during cmt operations until hole gets sticky 17.3. Pump 5 bbls spacer. 17.4. Test surface cmt lines to 4500 psi. 17.5. Pump remaining spacer. 17.6. 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. Page 27 Version PTD October, 2023 SRU 222-33 Drilling Procedure Rev 0 Estimated Total Cement Volume: Cement Slurry Design: Production Liner Cement Volumes Surface Casing OD 7.625 Suface Casing ID 6.875 Hole Size 6.75 in Casing OD 3.5 in Casing ID 2.992 in DP OD 4.5 in DP x Casing Annular Capacity 0.02624 bbl/ft Liner x Casing Annular Capacity 0.03402 bbl/ft Liner x OH Annular Capacity 0.03236 bbl/ft Casing Capacity 0.00870 bbl/ft OH Excess 40% Lead Cement Liner x OH 37.33 bbls 209.6 Liner x Casing 6.80 bbls 38.2 DP x Casing 5.25 bbls 29.5 Total Lead 49.38 bbls 277.3 sks Tail Cement Casing x OH 22.65 bbls 127.2 Shoetrack 0.70 bbls 3.9 Total Tail 23.35 bbls 131.1 sks Total Job 72.73 bbls 408.4 sks Lead Slurry (3473’ MD to 2449 MD)Tail Slurry (3973’ to 3473’ MD) System Extended Conventional Density 12 lb/gal 15.4 lb/gal Yield 2.46 ft3/sk 1.22 ft3/sk Mixed Water 14.349 gal/sk 5.507 gal/sk Mixed Fluid 14.469 gal/sk 5.507 gal/sk Additives Code Description Concentration Code Description Concentration G Cement 94#/sk A Cement 94#/sk D110 Retarder 0.15 gal/sk BWOC D046 Anti Foam 0.2 % BWOC D046 Anti Foam 0.2 % BWOC D065 Dispersant 0.4 % BWOC D079 Extender 2.0 % BWOC S002 CaCl2 0.35 % BWOC D020 Extender 3.0 % BWOC D177 CaCl2 0.1 % BWOC Verified cement calcs. Number of sacks should be 113 lead and 107 tail. See attached email from Sean McLaughlin dated 11/14/23. -bjm 220.2 sx 107.5 sx 112.7 sx Page 28 Version PTD October, 2023 SRU 222-33 Drilling Procedure Rev 0 17.7. 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. 17.8. 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. 17.9. 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. 17.10. 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. 17.11. Slack off total liner weight plus 30k to confirm hanger is set. 17.12. Do not overdisplace by more than 1 shoe track. Shoe track volume is 1 bbls. 17.13. Continue pressuring up to activate LTP pusher tool and set packer with running tool in compression. 17.14. Pressure up to 4,500 psi to neutralize the pusher tool and release the running tool (HRD-E) from the liner. 17.15. Bleed pressure to zero to check float equipment. Watch for flow. Note amount of fluid returned after bumping plug and releasing pressure. 17.16. P/U past free-travel verify setting tool is released, confirmed by loss of liner weight 17.17. 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). 17.18. 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. Page 29 Version PTD October, 2023 SRU 222-33 Drilling Procedure Rev 0 17.19. 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. 17.20. 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: 17.21. 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. 17.22.NOTE: Some hole conditions may require movement of the drillpipe to “work” the torque down to the setting tool. 17.23. 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. 17.24. WOC minimum of 12 hours, test casing to 3500 psi and chart for 30 minutes. 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 sean.mclaughlin@hilcorp.com. Page 30 Version PTD October, 2023 SRU 222-33 Drilling Procedure Rev 0 18.0 3-1/2”Liner Tieback Polish Run 18.1. PU liner tieback polish mill assy per Baker rep and RIH on drillpipe. 18.2. RIH to top of liner assembly and establish parameters. Polish tieback receptacle per Baker procedure. 18.3. CBU and displace well to 6% KCl completion fluid. 18.4. POOH LDDP and BHA 18.5. If not completed, test 3-1/2” liner to 2000 psi and chart for 30 minutes 19.0 3-1/2” Tieback Run 19.1 PU 3-1/2” tieback assembly and RIH with 3-1/2” 9.2# L-80 H563 liner x No SSSV, GLM, or CIM required. 19.2 No-go tieback seal assembly in liner PBR and mark pipe. PU pup joint(s) if necessary to space out tieback seals in PBR. 19.3 PU hanger and land string in hanger bowl. Note distance of seals from no-go. 19.4 Install packoff and test hanger void. 19.5 Test 3-1/2” liner and tieback to 2000 psi and chart for 30 minutes. 19.6 Test 7-5/8” x 3-1/2” annulus to 2000 psi and chart for 30 minutes. 19.7 Install BPV in wellhead 19.8 N/D BOPE 19.9 N/U dry hole tree or full tree (if available). 19.10 RDMO Hilcorp Rig #169 Page 31 Version PTD October, 2023 SRU 222-33 Drilling Procedure Rev 0 20.0 Diverter Schematic Page 32 Version PTD October, 2023 SRU 222-33 Drilling Procedure Rev 0 21.0 BOP Schematic Page 33 Version PTD October, 2023 SRU 222-33 Drilling Procedure Rev 0 22.0 Wellhead Schematic Page 34 Version PTD October, 2023 SRU 222-33 Drilling Procedure Rev 0 23.0 Anticipated Drilling Hazards 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. 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. Abnormal pressures or temperatures: None Water injection from nearby well 32-33WD has potential for overpressure. The water injection zone will be drilled on diverter. Water injector to be shut-in 30 days prior to spud and BHP verified prior to spud. Spud mud weight to be adjusted as needed to maintain overbalance. -bjm Page 35 Version PTD October, 2023 SRU 222-33 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. Losses not experienced in SRU 241-33B in 2021. However, 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. Reservoir Pressure: No abnormal pressures Page 36 Version PTD October, 2023 SRU 222-33 Drilling Procedure Rev 0 24.0 Hilcorp Rig 169 Layout Page 37 Version PTD October, 2023 SRU 222-33 Drilling Procedure Rev 0 25.0 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 38 Version PTD October, 2023 SRU 222-33 Drilling Procedure Rev 0 26.0 Choke Manifold Schematic Page 39 Version PTD October, 2023 SRU 222-33 Drilling Procedure Rev 0 27.0 Casing Design Information Page 40 Version PTD October, 2023 SRU 222-33 Drilling Procedure Rev 0 28.0 6-3/4” Hole Section MASP Page 41 Version PTD October, 2023 SRU 222-33 Drilling Procedure Rev 0 29.0 Spider Plot (Governmental Sections NAD83) Page 42 Version PTD October, 2023 SRU 222-33 Drilling Procedure Rev 0 30.0 660’ Radius for SSSV Page 43 Version PTD October, 2023 SRU 222-33 Drilling Procedure Rev 0 31.0 Surface Plat (As-Staked NAD27 & NAD83) 0 250 500 750 1000 1250 1500 1750 2000 2250 2500 2750 3000 3250 3500 3750 Tr u e V e r t i c a l D e p t h ( 5 0 0 u s f t / i n ) -250 0 250 500 750 1000 1250 1500 1750 2000 2250 2500 2750 3000 3250 Vertical Section at 278.00° (500 usft/in) SRU 222-33 Tgt1 7 5/8" x 9 7/8" 3 1/2" x 6 3/4" 500 1 0 0 0 1 5 0 0 2 0 0 0 2 5 0 0 3 0 0 0 3 5 0 0 3 9 7 3 SRU 222-33 wp02a Start Dir 2º/100' : 250' MD, 250'TVD Start Dir 3.5º/100' : 450' MD, 449.84'TVD Start Dir 3.5º/100' Turn: 600' MD, 598.78'TVD End Dir : 1332.72' MD, 1287.1' TVD Start Dir 2º/100' : 1898.57' MD, 1773.91'TVD End Dir : 2830.94' MD, 2638.62' TVD Total Depth : 3972.56' MD, 3755.3' TVD A7 - Disposal Zone A8 - Disposal Zone A9 - Disposal Zone A10 - Disposal Zone A11 A12 A13 A14 A15 B1 B2 B3 B4 B5 B6 B7 B8 B9 UB UB36-0 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 SRU 222-33 169.62 +N/-S +E/-W Northing Easting Latitude Longitude 0.00 0.00 2464588.50 345719.50 60° 44' 35.5134 N 150° 51' 43.9835 W SURVEY PROGRAM Date: 2023-10-19T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 18.00 2650.00 SRU 222-33 wp02a (SRU 222-33) 3_MWD+IFR1+MS+Sag 2650.00 3972.56 SRU 222-33 wp02a (SRU 222-33) 3_MWD+IFR1+MS+Sag FORMATION TOP DETAILS TVDPath TVDssPath MDPath Formation 2072.00 1884.38 2234.19 A7 - Disposal Zone 2151.00 1963.38 2320.06 A8 - Disposal Zone 2260.00 2072.38 2436.86 A9 - Disposal Zone 2305.00 2117.38 2484.57 A10 - Disposal Zone 2401.00 2213.38 2585.47 A11 2550.00 2362.38 2740.01 A12 2610.00 2422.38 2801.64 A13 2637.00 2449.38 2829.28 A14 2693.00 2505.38 2886.53 A15 2727.00 2539.38 2921.29 B1 2822.00 2634.38 3018.41 B2 2940.00 2752.38 3139.05 B3 2990.00 2802.38 3190.17 B4 3033.00 2845.38 3234.13 B5 3198.00 3010.38 3402.81 B6 3327.00 3139.38 3534.70 B7 3391.00 3203.38 3600.13 B8 3474.00 3286.38 3684.98 B9 3512.00 3324.38 3723.83 UB 3535.00 3347.38 3747.34 UB36-0 REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Plan SRU 222-33, True North Vertical (TVD) Reference:RKB As-Staked @ 187.62usft (HEC 169) Measured Depth Reference:RKB As-Staked @ 187.62usft (HEC 169) Calculation Method: Minimum Curvature Project:Swanson River Unit Site:SRU 32-33 Well:Plan SRU 222-33 Wellbore:SRU 222-33 Design:SRU 222-33 wp02a CASING DETAILS TVD TVDSS MD Size Name 2462.00 2274.38 2649.02 7-5/8 7 5/8" x 9 7/8" 3755.30 3567.68 3972.56 3-1/2 3 1/2" x 6 3/4" SECTION DETAILS Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation 1 18.00 0.00 0.00 18.00 0.00 0.00 0.00 0.00 0.00 2 250.00 0.00 0.00 250.00 0.00 0.00 0.00 0.00 0.00 Start Dir 2º/100' : 250' MD, 250'TVD 3 450.00 4.00 325.00 449.84 5.72 -4.00 2.00 325.00 4.76 Start Dir 3.5º/100' : 450' MD, 449.84'TVD 4 600.00 9.25 325.00 598.78 19.89 -13.93 3.50 0.00 16.56 Start Dir 3.5º/100' Turn: 600' MD, 598.78'TVD 5 1332.72 30.65 274.71 1287.10 84.56 -237.57 3.50 -64.96 247.03 End Dir : 1332.72' MD, 1287.1' TVD 6 1898.57 30.65 274.71 1773.91 108.27 -525.04 0.00 0.00 534.99 Start Dir 2º/100' : 1898.57' MD, 1773.91'TVD 7 2830.94 12.00 274.83 2638.62 136.21 -861.43 2.00 179.93 872.00 SRU 222-33 Tgt1 End Dir : 2830.94' MD, 2638.62' TVD 8 3972.56 12.00 274.83 3755.30 156.20 -1097.94 0.00 0.00 1108.99 Total Depth : 3972.56' MD, 3755.3' TVD -3 7 5 -3 0 0 -2 2 5 -1 5 0 -7 5 07515 0 22 5 30 0 37 5 45 0 52 5 60 0 South(-)/North(+) (150 usft/in) -1 2 7 5 - 1 2 0 0 - 1 1 2 5 - 1 0 5 0 - 9 7 5 - 9 0 0 - 8 2 5 - 7 5 0 - 6 7 5 - 6 0 0 - 5 2 5 - 4 5 0 - 3 7 5 - 3 0 0 - 2 2 5 - 1 5 0 - 7 5 0 7 5 1 5 0 We s t ( - ) / E a s t ( + ) ( 1 5 0 u s f t / i n ) SR U 2 2 2 - 3 3 T g t 1 7 5 / 8 " x 9 7 / 8 " 3 1 / 2 " x 6 3 / 4 " 25 0 5 0 0 750 1000 1250 1500 1750 2000 2250 2500 2750 3000 3250 3500 37503755 SR U 2 2 2 - 3 3 w p 0 2 a St a r t D i r 2 º / 1 0 0 ' : 2 5 0 ' M D , 2 5 0 ' T V D St a r t D i r 3 . 5 º / 1 0 0 ' : 4 5 0 ' M D , 4 4 9 . 8 4 ' T V D St a r t D i r 3 . 5 º / 1 0 0 ' T u r n : 6 0 0 ' M D , 5 9 8 . 7 8 ' T V D En d D i r : 1 3 3 2 . 7 2 ' M D , 1 2 8 7 . 1 ' T V D St a r t D i r 2 º / 1 0 0 ' : 1 8 9 8 . 5 7 ' M D , 1 7 7 3 . 9 1 ' T V D En d D i r : 2 8 3 0 . 9 4 ' M D , 2 6 3 8 . 6 2 ' T V D To t a l D e p t h : 3 9 7 2 . 5 6 ' M D , 3 7 5 5 . 3 ' T V D CA S I N G D E T A I L S TV D TV D S S M D Si z e N a m e 24 6 2 . 0 0 2 2 7 4 . 3 8 2 6 4 9 . 0 2 7 - 5 / 8 7 5 / 8 " x 9 7 / 8 " 37 5 5 . 3 0 3 5 6 7 . 6 8 3 9 7 2 . 5 6 3 - 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' # () & " * " # $% ! < , # & : , < + $ ' ( ) ( ( ) ' ( " ) ( ( ) ' ( " ) ( ( %* + & , * ( - * * . & . % % / ( & % / / - % & " / " . & ( / ( (- * * . & . % ) ' ( ) ( ( ) ' ( " ) ( ( ) ' ( " ) ( ( %+ & , ( - + % & % / / & % / - % + & " , " . & ( * (- + % & 0 ) ' ( ) ( ( ) ' ( ) ( ( ) ' ( ) ( ( . , & * ( " + & " . + & % + & . * & . . % "+ & 0 ) ' ( ) ( ( ) ' ( ) ( ( ) ' ( ) ( ( * & % % & " . + & / ( / & + % & . % * % & ) ' ( ) ( ( ) ' ( ) ( ( ) ' ( ) ( ( * & / * ( & " . + & . " ( , & % / & . % % ( & 0 ) ' ( ) ( ( ) ' ( ) ( ( ) ' ( ) ( ( . , & * ( " + & " . + & % + & . * & . . % "+ & 0 ) ' ( ) ( ( ) ' ( ) ( ( ) ' ( ) ( ( * & % % & " . + & / ( / & + % & . % * % & ) ' ( ) ( ( ) ' ( ) ( ( ) ' ( ) ( ( * & / * ( & " . + & . " ( , & % / & . % % ( & 0 ) ' ( ) ( ( 1 ) ' ( ) ( ( 1 ) ' ( ) ( ( 1 .+ & . % " - " " & + . ( & + " - + ( & , % " & + " / "- " " & + . 0 ) ' ( ) ( ( 1 ) ' ( ) ( ( 1 ) ' ( ) ( ( 1 .+ & . * " - " % & ( & * " " - + . & + " & + , "- " % & ) ' ( ) ( ( 1 ) ' ( ) ( ( 1 ) ' ( ) ( ( 1 ., & % " - " % & ( & * + " - " , & . ( " & * , / "- " % & 0 ) > ( " * ? ( " * @ ! ? "+ & - . % & ' ) ( ( ( 2 3 1 ! " ! 3 ! 4 - . % & ( - , * & % . ' ) ( ( ( 2 3 1 ! " ! 3 ! 4 " ! 5 6 7 8 ) & 6 9 & 0 6 6 $ & 0 : $ # ; $ ) < & 4 9 9 & 6 6 4 3 5 6 5 0 6 7 6 5 & 0. 0 0 1. 0 0 2. 0 0 3. 0 0 4. 0 0 Separation Factor 0 2 0 0 4 0 0 6 0 0 8 0 0 1 0 0 0 1 2 0 0 1 4 0 0 1 6 0 0 1 8 0 0 2 0 0 0 2 2 0 0 2 4 0 0 2 6 0 0 2 8 0 0 3 0 0 0 3 2 0 0 3 4 0 0 3 6 0 0 3 8 0 0 Me a s u r e d D e p t h ( 4 0 0 u s f t / i n ) SR U 3 2 A - 3 3 SR U 3 2 - 3 3 SR U 3 2 - 3 3 W D No - G o Z o n e - S t o p D r i l l i n g Co l l i s i o n A v o i d a n c e R e q u i r e d Co l l i s i o n R i s k P r o c e d u r e s R e q . NO E R R O R S WE L L D E T A I L S : P l a n S R U 2 2 2 - 3 3 N A D 1 9 2 7 ( N A D C O N C ON U S ) A l a s k a Z o n e 0 4 16 9 . 6 2 +N / - S +E / - W N o r t h i n g Ea s t i n g La t i t u d e L o n g i t u d e 0. 0 0 0. 0 0 24 6 4 5 8 8 . 5 0 34 5 7 1 9 . 5 0 60 ° 4 4 ' 3 5 . 5 1 3 4 N 15 0 ° 5 1 ' 4 3 . 9 8 3 5 W RE F E R E N C E I N F O R M A T I O N Co - o r d i n a t e ( N / E ) R e f e r e n c e : We l l P l a n S R U 2 2 2 - 3 3 , T r u e N o r t h Ve r t i c a l ( T V D ) R e f e r e n c e : R K B A s - S t a k e d @ 1 8 7 . 6 2 u s f t ( H E C 1 6 9 ) Me a s u r e d D e p t h R e f e r e n c e : RK B A s - S t a k e d @ 1 8 7 . 6 2 u s f t ( H E C 1 6 9 ) Ca l c u l a t i o n M e t h o d : Mi n i m u m C u r v a t u r e CA S I N G D E T A I L S TV D T V D S S M D S i z e N a m e 24 6 2 . 0 0 2 2 7 4 . 3 8 2 6 4 9 . 0 2 7 - 5 / 8 7 5 / 8 " x 9 7 / 8 " 37 5 5 . 3 0 3 5 6 7 . 6 8 3 9 7 2 . 5 6 3 - 1 / 2 3 1 / 2 " x 6 3 / 4 " SU R V E Y P R O G R A M Da t e : 2 0 2 3 - 1 0 - 1 9 T 0 0 : 0 0 : 0 0 V a l i d a t e d : Y e s V e r s i o n : De p t h F r o m D e p t h T o Su r v e y / P l a n T o o l 18 . 0 0 2 6 5 0 . 0 0 S R U 2 2 2 - 3 3 w p 0 2 a ( S R U 2 2 2 - 3 3 ) 3 _ M W D + I F R 1 + M S + S a g 26 5 0 . 0 0 3 9 7 2 . 5 6 S R U 2 2 2 - 3 3 w p 0 2 a ( S R U 2 2 2 - 3 3 ) 3 _ M W D + I F R 1 + M S + S a g 0. 0 0 40 . 0 0 80 . 0 0 12 0 . 0 0 16 0 . 0 0 20 0 . 0 0 Centre to Centre Separation (80.00 usft/in) 0 2 0 0 4 0 0 6 0 0 8 0 0 1 0 0 0 1 2 0 0 1 4 0 0 1 6 0 0 1 8 0 0 2 0 0 0 2 2 0 0 2 4 0 0 2 6 0 0 2 8 0 0 3 0 0 0 3 2 0 0 3 4 0 0 3 6 0 0 3 8 0 0 Me a s u r e d D e p t h ( 4 0 0 u s f t / i n ) SR U 3 2 - 3 3 W D SR U 3 2 - 3 3 W D GL O B A L F I L T E R A P P L I E D : A l l w e l l p a t h s w i t h i n 2 0 0 ' + 1 0 0 / 1 0 0 0 o f r e f e r e n c e 18 . 0 0 T o 3 9 7 2 . 5 6 Pr o j e c t : S w a n s o n R i v e r U n i t Si t e : S R U 3 2 - 3 3 W e l l : P l a n S R U 2 2 2 - 3 3 We l l b o r e : S R U 2 2 2 - 3 3 Pl a n : S R U 2 2 2 - 3 3 w p 0 2 a La d d e r / S . F . P l o t s 1 Christianson, Grace K (OGC) From:Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Sent:Tuesday, November 14, 2023 3:42 PM To:McLellan, Bryan J (OGC) Subject:RE: [EXTERNAL] SRU 222-33 cement calcs It looks like I was showing Ō3 instead of sacks. I get 524 sks for the surface and 220 sks for the producƟon hole. Sean 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. 2 From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Tuesday, November 14, 2023 12:24 PM To: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Subject: [EXTERNAL] SRU 222Ͳ33 cement calcs Sean, FYI, I think the number of sacks listed in your cement calcula Ɵons were a carryover from another well. Can you double check and update as needed? Thanks Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250Ͳ9193 CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. 3 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: External sender. DO NOT open links or attachments from UNKNOWN senders. 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:Sean McLaughlin To:McLellan, Bryan J (OGC) Subject:RE: [EXTERNAL] SRU 222-33 PTD application Date:Tuesday, November 14, 2023 2:21:57 PM Attachments:image001.jpg SRU 32-33WD Reservoir Pressure Analysis.pptx Bryan, A rig workover was conducted on SRU 32-33WD last year in which a reservoir pressure analysis was done. A 9.0 ppg BHP was used for the RWO and the maximum potential pressure in an offset well with no mitigation. The October 2022 observation on SRU 32-33WD was that the BHP was an 8.35 ppg gradient after 31 days of shut in. A SBHPS was conducted on SRU 32-33WD on 10/06/2022 to confirm the pressure trend and that surface pressure accurately indicates bottom hole pressure. With sufficient shut in time on 32-33WD a water gradient is expected. There is ~600’ separation between SRU 32-33WD and SRU 222-33. The surface pressure of SRU 32-33WD will be monitored to ensure a pressure fall off is occurring as expected. A SBHPS will be run if the trend is uncertain. The MW used in SRU 222-33 will be overbalance to the SRU 32-33WD BHP. Other notable observations are that both SRU 13-27 and SRU 14B-27 were drilled ~556’ from SRU 31-33WD. SRU 31-33WD was not shut in and a 10.0 ppg MW was used. This approach was considered as well. Regards, sean From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Tuesday, November 14, 2023 11:30 AM To: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Subject: [EXTERNAL] SRU 222-33 PTD application Sean, In the permit application, you mention a water injector 32-33WD that is to be shut-in 30 days before drilling begins. The spud mud starting at 8.8 ppg is not enough for the 9.0 ppg anticipated Disposal zone pressure at 2072’ TVD. Need to specify some overbalance in the procedure. How far away is the water injector from the planned SRU 222-33 at the depth of the injection zone? What is the Shut-in pressure and Equivalent Mud Weight in that zone, and what is the source of the pressure data? What is the level of uncertainty? Can run a static BHP survey in the injector if pressure is uncertain. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 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. SR U 32 Ͳ33 W D Ti m e l i n e 08 / 1 3 / 2 2 : Tx I A c o m m u n i c a t i o n ob s e r v e d du r i n g MI T ͲIA . Co n t i n u e d in j e c t i o n fo r di a g n o s t i c s . 09 / 1 1 / 2 2 : We l l sh u t Ͳin . Co n t i n u e d to in j e c t in SR U 31 Ͳ33 W D 10 / 0 6 / 2 2 : SB H P S . Se t Pl u g fo r RW O . TB G pr e s s u r e 65 ps i im m e d i a t e l y be f o r e pl u g se t . 10 / 0 9 / 2 2 : RW O to re p l a c e TB G . 10 / 1 2 / 2 2 : Pl u g pu l l e d . No TB G pr e s s u r e re p o r t e d by SL af t e r pu l l i n g pl u g . SB H P S Su m m a r y (2 5 da y s of SI ti m e ) Su r f a c e pr e s s u r e at st a r t of SB H P S : 68 . 9 ps i a Ma i n st o p at 20 7 0 RK B (2 0 7 0 TV D ) : 96 8 ps i a . To p pe r f at 21 0 0 ’ MD . Fl u i d gr a d i e n t in we l l b o r e =0. 4 3 4 ps i / f t or 8. 3 5 pp g Re s e r v o i r gr a d i e n t =0. 4 6 8 or 9. 0 pp g Su m m a r y an d Co n c l u s i o n s Ba s e d on th e pr e s s u r e pl o t [s e e ne x t sl i d e ] , 32 Ͳ33 ’ s ge n e r a l de c l i n e wa s ba c k to ano r m a l gr a d i e n t (o r ju s t sl i g h t l y ab o v e ) , bu t it re q u i r e d si g n i f i c a n t sh u t Ͳin ti m e . Th e r e ap p e a r e d to be aco r r e l a t i o n be t w e e n in j e c t i o n in 31 Ͳ33 an d TB G pr e s s u r e of 32 Ͳ33 wh e r e ach a n g e in th e pr e s s u r e / r a t e in 31 Ͳ33 re s u l t e d in aco r r e s p o n d i n g re s p o n s e in 32 Ͳ33 . Th i s ef f e c t se e m to le s s e n ov e r ti m e an d ev e n t u a l l y th e pr e s s u r e de c l i n e in 32 Ͳ33 st a b i l i z e d . SR U 32 Ͳ33 W D Re s e r v o i r Pr e s s u r e An a l y s i s 020 0 0 40 0 0 60 0 0 80 0 0 10 0 0 0 12 0 0 0 0 20 0 40 0 60 0 80 0 10 0 0 12 0 0 09 / 0 9 / 2 2 0 9 / 1 4 / 2 2 0 9 / 1 9 / 2 2 0 9 / 2 4 / 2 2 0 9 / 2 9 / 2 2 1 0 / 0 4 / 2 2 1 0 / 0 9 / 2 2 1 0 / 1 4 / 2 2 1 0 / 1 9 / 2 2 Rate [BPD] Pressure [psi] 31 - 3 3 a n d 3 2 - 3 3 P r e s s u r e C o r r e l a t i o n s 31 - 3 3 P r e s s u r e [ p s i ] 32 - 3 3 P r e s s u r e [ p s i ] 32 - 3 3 R a t e [ B P D ] 31 - 3 3 R a t e [ B P D ] 32 - 3 3 S I Sh o w s c o r r e l a t i o n be t w e e n p r e s s u r e ch a n g e s i n 3 1 - 3 3 a n d 32 - 3 3 Pr e s s u r e c o r r e l a t i o n mi n i m a l a f t e r s u f f i c i e n t SI t i m e . G e n e r a l pr e s s u r e t r e n d i s al w a y s d e c r e a s i n g Pl u g S e t We l l b l e e d s i n a n at t e m p t t o l o w e r pr e s s u r e t o a n o r m a l gr a d i e n t . Revised 7/2022 TRANSMITTAL LETTER CHECKLIST WELL NAME: ______________________________________ PTD: _____________________________________________ ___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional FIELD: __________________________ POOL: ____________________________________ Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI LATERAL (If last two digits in API number are between 60-69) The permit is for a new wellbore segment of existing well Permit Number _____________, API Number 50-______________________. Production from or injection into this wellbore must be reported under the original API Number stated above. Spacing Exception The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce or inject is contingent upon issuance of a conservation order approving a spacing exception. The Operator assumes the liability of any protest to the spacing exception that may occur. Dry Ditch Sample All dry ditch sample sets submitted to the AOGCC must be in no greater than 30-foot sample intervals from below the permafrost or from where samples are first caught and 10-foot sample intervals through target zones. Non- Conventional Well Please note the following special condition of this permit: Production or production testing of coal bed methane is not allowed for this well until after the Operator has designed and implemented a water-well testing program to provide baseline data on water quality and quantity. The Operator must contact the AOGCC to obtain advance approval of such a water-well testing program. Well Logging Requirements Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by the Operator in the attached application, the following well logs are also required for this well: Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. 223-100 SWANSON RIVER X SRU 222-33 STERLING/UPPER BELUGA GAS POOL W E L L P E R M I T C H E C K L I S T Co m p a n y Hi l c o r p A l a s k a , L L C We l l N a m e : SW A N S O N R I V U N I T 2 2 2 - 3 3 In i t i a l C l a s s / T y p e DE V / P E N D Ge o A r e a 82 0 Un i t 51 9 9 4 On / O f f S h o r e On Pr o g r a m DE V Fi e l d & P o o l We l l b o r e s e g An n u l a r D i s p o s a l PT D # : 22 3 1 0 0 0 SW A N S O N R I V E R , S T R L G / U B L U G G S - 7 7 2 5 5 NA 1 P e r m i t f e e a t t a c h e d Ye s A K A 0 2 8 3 9 9 2 L e a s e n u m b e r a p p r o p r i a t e Ye s 3 U n i q u e w e l l n a m e a n d n u m b e r Ye s S W A N S O N R I V E R , S T R L G / U B L U G G S - 7 7 2 5 5 0 - g o v e r n e d b y 7 1 6 A 4 W e l l l o c a t e d i n a d e f i n e d p o o l Ye s 5 W e l l l o c a t e d p r o p e r d i s t a n c e f r o m d r i l l i n g u n i t b o u n d a r y NA 6 W e l l l o c a t e d p r o p e r d i s t a n c e f r o m o t h e r w e l l s Ye s 7 S u f f i c i e n t a c r e a g e a v a i l a b l e i n d r i l l i n g u n i t Ye s 8 I f d e v i a t e d , i s w e l l b o r e p l a t i n c l u d e d Ye s 9 O p e r a t o r o n l y a f f e c t e d p a r t y Ye s 10 O p e r a t o r h a s a p p r o p r i a t e b o n d i n f o r c e Ye s 11 P e r m i t c a n b e i s s u e d w i t h o u t c o n s e r v a t i o n o r d e r Ye s 12 P e r m i t c a n b e i s s u e d w i t h o u t a d m i n i s t r a t i v e a p p r o v a l Ye s 13 C a n p e r m i t b e a p p r o v e d b e f o r e 1 5 - d a y w a i t NA 14 W e l l l o c a t e d w i t h i n a r e a a n d s t r a t a a u t h o r i z e d b y I n j e c t i o n O r d e r # ( p u t I O # i n c o m m e n t s ) ( F o r NA 15 A l l w e l l s w i t h i n 1 / 4 m i l e a r e a o f r e v i e w i d e n t i f i e d ( F o r s e r v i c e w e l l o n l y ) NA 16 P r e - p r o d u c e d i n j e c t o r : d u r a t i o n o f p r e - p r o d u c t i o n l e s s t h a n 3 m o n t h s ( F o r s e r v i c e w e l l o n l y ) NA 17 N o n c o n v e n . g a s c o n f o r m s t o A S 3 1 . 0 5 . 0 3 0 ( j . 1 . A ) , ( j . 2 . A - D ) Ye s 18 C o n d u c t o r s t r i n g p r o v i d e d Ye s 19 S u r f a c e c a s i n g p r o t e c t s a l l k n o w n U S D W s Ye s 20 C M T v o l a d e q u a t e t o c i r c u l a t e o n c o n d u c t o r & s u r f c s g Ye s 21 C M T v o l a d e q u a t e t o t i e - i n l o n g s t r i n g t o s u r f c s g Ye s 22 C M T w i l l c o v e r a l l k n o w n p r o d u c t i v e h o r i z o n s Ye s 23 C a s i n g d e s i g n s a d e q u a t e f o r C , T , B & p e r m a f r o s t Ye s 24 A d e q u a t e t a n k a g e o r r e s e r v e p i t NA 25 I f a r e - d r i l l , h a s a 1 0 - 4 0 3 f o r a b a n d o n m e n t b e e n a p p r o v e d Ye s 26 A d e q u a t e w e l l b o r e s e p a r a t i o n p r o p o s e d Ye s 27 I f d i v e r t e r r e q u i r e d , d o e s i t m e e t r e g u l a t i o n s Ye s 28 D r i l l i n g f l u i d p r o g r a m s c h e m a t i c & e q u i p l i s t a d e q u a t e Ye s 29 B O P E s , d o t h e y m e e t r e g u l a t i o n Ye s M P S P = 1 2 4 0 p s i , B O P r a t e d t o 5 0 0 0 p s i ( B O P t e s t t o 3 0 0 0 p s i ) 30 B O P E p r e s s r a t i n g a p p r o p r i a t e ; t e s t t o ( p u t p s i g i n c o m m e n t s ) Ye s 31 C h o k e m a n i f o l d c o m p l i e s w / A P I R P - 5 3 ( M a y 8 4 ) Ye s 32 W o r k w i l l o c c u r w i t h o u t o p e r a t i o n s h u t d o w n No 33 I s p r e s e n c e o f H 2 S g a s p r o b a b l e NA 34 M e c h a n i c a l c o n d i t i o n o f w e l l s w i t h i n A O R v e r i f i e d ( F o r s e r v i c e w e l l o n l y ) Ye s H 2 S n o t a n t i c i p a t e d 35 P e r m i t c a n b e i s s u e d w / o h y d r o g e n s u l f i d e m e a s u r e s Ye s V a r i o u s f o r m a t i o n s e x p e c t e d t o h a v e o v e r p r e s s u r e ( 9 p p g E M W ) a n d u n d e r p r e s s u r e ( 7 . 5 p p g E M W ) 36 D a t a p r e s e n t e d o n p o t e n t i a l o v e r p r e s s u r e z o n e s NA 37 S e i s m i c a n a l y s i s o f s h a l l o w g a s z o n e s NA 38 S e a b e d c o n d i t i o n s u r v e y ( i f o f f - s h o r e ) NA 39 C o n t a c t n a m e / p h o n e f o r w e e k l y p r o g r e s s r e p o r t s [ e x p l o r a t o r y o n l y ] Ap p r AD D Da t e 11 / 8 / 2 0 2 3 Ap p r BJ M Da t e 11 / 1 4 / 2 0 2 3 Ap p r AD D Da t e 11 / 9 / 2 0 2 3 Ad m i n i s t r a t i o n En g i n e e r i n g Ge o l o g y Ge o l o g i c Co m m i s s i o n e r : Da t e : En g i n e e r i n g Co m m i s s i o n e r : Da t e Pu b l i c Co m m i s s i o n e r Da t e *& : JL C 1 1 / 1 5 / 2 0 2 3