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Home My WebLink About221-0531. 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, CTCO 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: Current Pools: 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 7,012' N/A Casing Collapse Structural Conductor Surface 4,790psi Intermediate Production 7,500psi Liner Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16. Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: 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 Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? 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: Proposed Pools: AOGCC USE ONLY Tubing Grade: Tubing MD (ft): Subsequent Form Required: Noel Nocas, Operations Manager 907-564-5278 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEDA028399 221-053 50-133-20696-00-00 Hilcorp Alaska, LLC Swanson River 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 12.6# / L-80 TVD Burst 1,870' 8,430psi 1,974' 120' 2,096' MD PRESENT WELL CONDITION SUMMARY October 31, 2025 Tieback 4-1/2" 7,012' Perforation Depth MD (ft): Swanson River Unit (SRU) 241-33BCO 716A Same 6,387'4-1/2" ~1,210psi 7-5/8" Liner Top Packer ; N/A 1,866' MD / 1,766' TVD ; N/A 6,387' 4,065' 3,607' 16" See Attached Schematic 6,890psi 120' See Attached Schematic 7,012' See Schematic Length Sterling/Upper Beluga Gas 120' 2,096' Perforation Depth TVD (ft): Size m n P s 66 t N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 8:11 am, Oct 22, 2025 325-656 DSR-10/30/25A.Dewhurst 23OCT25 CT BOP test to 2500 psi (contingency) 10-404 X BJM 10/22/25 10/31/25 Well Prognosis Well: SRU 241-33B Well Name: SRU 241-33B API Number: 50-133-20696-00-00 Current Status: Gas Producer Permit to Drill Number: 221-053 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: 1566 psi @ 3557 TVD Based on 0.44 psi/ft Max. Potential Surface Pressure: 1210 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) = 1210 psi / 0.60 = 2017 TVD Top of Applicable Gas Pool: 2481 MD / 2317 TVD (Top Sterling/Upper Beluga) Well Status: Gas Producer 525 mcfd / 10 bwpd / 157 psi FTP (As of 10/14/2025) Recent Well Summary In May 2025, a CIBP was set at 4,065 isolating the UB 36-8 interval (4,070 - 4,080) and additional perforations were added in the UB 36-8 interval from (4,049 4059). The well was turned over to production and initial production was 1115 mcfd / 0 bwpd / 634 psi FTP. Since, the well production has gradually declined with an increase in water production. As of 10/14/2025 current production is 525 mcfd / 10 bwpd / 157 psi FTP. The purpose of this Sundry is to add additional perforations intervals in the Upper Beluga / Sterling Sands. Procedure: 1. MIRU E-line and pressure control equipment 2. PT lubricator to 250 psi low /2,500 psi high 3. RIH and perforate the following sands 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 Well Sand MD top MD Bottom TVD top TVD bottom Interval SRU_241-33B ST_A13 +2,889 +2,896 +2,669 +2,675 +7 SRU_241-33B ST_A14 +2,912 +2,921 +2,688 +2,696 +9 SRU_241-33B ST_A16 +2,983 +2,993 +2,746 +2,754 +10 SRU_241-33B ST_B1 +3,011 +3,025 +2,768 +2,779 +14 SRU_241-33B ST_B2 +3,118 +3,124 +2,852 +2,857 +6 SRU_241-33B ST_B5 +3,392 +3,406 +3,069 +3,078 +14 SRU_241-33B UB_FF +3,993 +4,003 +3,549 +3,557 +10 Well Prognosis Well: SRU 241-33B 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(s) 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. If possible, the CIBP will be set 50 above 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 nitrogen or high-pressure pad gas to pressure up well during perforating or to depress water prior to setting a plug above perforations 4. RDMO and turn well over to production. Contingency Procedure: Coiled Tubing Cleanout 1. If throughout the job any current or proposed zone(s) 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. Coil Tubing BOP Diagram 4. Standard Well Procedure N2 Operations Updated by DMA 06-18-25 SCHEMATIC Swanson River Unit SRU 241-33B PTD: 221-053 API: 50-133-20696-00-00 PBTD = 6,927 / TVD = 6,303 TD = 7,012 / TVD = 6,387 RKB to GL = 18 JEWELRY DETAIL No. Depth ID OD Item 1 1,5253.9584.500Chemical Injection Sub 2 1,8664.8756.540Liner Hanger / LTP Assembly 3 1,8704.7906.340Seal Assy 4 4,065NA NA CIBP (5/26/25) 5 4,148 NA NA CIBP w/ 38 cement (3/12/25) TOC 4,110 6 5,236NA NA CIBP w/ 35 cement (11/8/24) TOC 5201 7 5,307NA NA CIBP 11/7/24 8 5,446NA NA CIBP 11/5/24 9 5,576NA NA CIBP (4/2/24) 10 5,784NA NA CIBP w / 35 cement (3/6/24), TOC 5749 11 5,975NA NA CIBP w / 35 cement (3/4/24), TOC 5940 12 6,177-6,212NA NA 35 cement plug dump bailed (2/11/24) PERFORATION DETAIL Sand Top MD Btm MD Top TVD Btm TVD Ft Date Status UB 36-8 4,0494,0593,5943,601105/28/2025 Open UB 36-8 4,070 4,080 3,611 3,618 103/13/2025 Isolated UB 37-0 4,198' 4,208' 3,712' 3,720' 10' 11/27/2024 Isolated LB 50-6 5,286' 5,292' 4,678' 4,684' 6' 11/7/2024 Isolated LB 50-7 5,347' 5,352' 4,737' 4,742' 5' 11/7/2024 Isolated LB 50-9 5,503' 5,519' 4,890' 4,906'164/04/2024 Isolated LB 50-9 5,503' 5,519' 4,890' 4,906'164/12/2024 Isolated LB 50-9 5,555' 5,561' 4,942' 4,948'64/04/2024 Isolated LB 51-1 5,581' 5,587' 4,968' 4,974'63/07/2024 Isolated LB 51-2 5,674' 5,679' 5,060' 5,065'53/07/2024 Isolated LB 51-7 5,839' 5,843' 5,223' 5,228'43/05/2024 Isolated LB 52-9 5,881' 5,890' 5,266' 5,274'93/05/2024 Isolated TY 53-0 6,008 6,013 5,392 5,396 55/5/2022 Isolated TY 54-5 6,106 6,116 5,489 5,499 105/5/2022 Isolated TY 56-9 6,356 6,374 5,737 5,754 1810/1/2021 Isolated TY 62-5 6,897 6,907 6,274 6,284 109/30/2021 Isolated OPEN HOLE / CEMENT DETAIL 7-5/8"139 BBLs of cement in 9-7/8 hole Returns to surface 4-1/2 177 BBLs of cement in 6-3/4 hole Est. TOC @ 1,866 (LTP) (Returns to surface) CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16Conductor Driven to Set Depth 84 X-56 Weld 15.01Surf 120 7-5/8"Surf Csg 29.7 L-80 USS-CDC 6.875Surf 2,096 4-1/2"Prod Lnr 12.6 L-80 DWC/C HT 3.9581,8667,012 4-1/2"Prod Tieback 12.6 L-80 DWC/C HT 3.958Surf 1,870 3 16 7-5/8 9-7/8 hole 4-1/2 6-3/4 hole 2 1 TY 56-9 TY 62-5 TY 54-5 TY 53- 6,380 tag on 6/27/23 NOTE: Consistent unknown restriction @ 6,384. 12 10 11 9 LB 50-9 LB 51 5150 LB 8 RA Marker Joints #1 @ 4,239'-4,280' MD #2 @ 5,410'-5,451' MD RA #2 RA #1 LB 50-7 6 UB 37-0 7 LB 50-6 5 UB 36-84 Updated by RPL 10-17-25 SCHEMATIC Proposed Swanson River Unit SRU 241-33B PTD: 221-053 API: 50-133-20696-00-00 PBTD = 6,927 / TVD = 6,303 TD = 7,012 / TVD = 6,387 RKB to GL = 18 JEWELRY DETAIL No. Depth ID OD Item 1 1,5253.9584.500Chemical Injection Sub 2 1,8664.8756.540Liner Hanger / LTP Assembly 3 1,8704.7906.340Seal Assy 4 4,065NA NA CIBP (5/26/25) 5 4,148 NA NA CIBP w/ 38 cement (3/12/25) TOC 4,110 6 5,236NA NA CIBP w/ 35 cement (11/8/24) TOC 5201 7 5,307NA NA CIBP 11/7/24 8 5,446NA NA CIBP 11/5/24 9 5,576NA NA CIBP (4/2/24) 10 5,784NA NA CIBP w / 35 cement (3/6/24), TOC 5749 11 5,975NA NA CIBP w / 35 cement (3/4/24), TOC 5940 12 6,177-6,212NA NA 35 cement plug dump bailed (2/11/24) PERFORATION DETAIL Sand Top MD Btm MD Top TVD Btm TVD Ft Date Status ST_A13 +2,889+2,896+2,669+2,675+7TBD Proposed ST_A14 +2,912+2,921+2,688+2,696+9TBD Proposed ST_A16 +2,983+2,993+2,746+2,754+10TBD Proposed ST_B1 +3,011+3,025+2,768+2,779+14TBD Proposed ST_B2 +3,118+3,124+2,852+2,857+6TBD Proposed ST_B5 +3,392+3,406+3,069+3,078+14TBD Proposed UB_FF +3,993+4,003+3,549+3,557+10TBD Proposed UB 36-8 4,049 4,059 3,594 3,601 105/28/2025 Open UB 36-8 4,070 4,080 3,611 3,618 103/13/2025 Isolated UB 37-0 4,198' 4,208' 3,712' 3,720' 10' 11/27/2024 Isolated LB 50-6 5,286' 5,292' 4,678' 4,684' 6' 11/7/2024 Isolated LB 50-7 5,347' 5,352' 4,737' 4,742' 5' 11/7/2024 Isolated LB 50-9 5,503' 5,519' 4,890' 4,906'164/04/2024 Isolated LB 50-9 5,503' 5,519' 4,890' 4,906'164/12/2024 Isolated LB 50-9 5,555' 5,561' 4,942' 4,948'64/04/2024 Isolated LB 51-1 5,581' 5,587' 4,968' 4,974'63/07/2024 Isolated LB 51-2 5,674' 5,679' 5,060' 5,065'53/07/2024 Isolated LB 51-7 5,839' 5,843' 5,223' 5,228'43/05/2024 Isolated LB 52-9 5,881' 5,890' 5,266' 5,274'93/05/2024 Isolated TY 53-0 6,008 6,013 5,392 5,396 55/5/2022 Isolated TY 54-5 6,106 6,116 5,489 5,499 105/5/2022 Isolated TY 56-9 6,356 6,374 5,737 5,754 1810/1/2021 Isolated TY 62-5 6,897 6,907 6,274 6,284 109/30/2021 Isolated OPEN HOLE / CEMENT DETAIL 7-5/8"139 BBLs of cement in 9-7/8 hole Returns to surface 4-1/2 177 BBLs of cement in 6-3/4 hole Est. TOC @ 1,866 (LTP) (Returns to surface) CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16Conductor Driven to Set Depth 84 X-56 Weld 15.01Surf 120 7-5/8"Surf Csg 29.7 L-80 USS-CDC 6.875Surf 2,096 4-1/2"Prod Lnr 12.6 L-80 DWC/C HT 3.9581,8667,012 4-1/2"Prod Tieback 12.6 L-80 DWC/C HT 3.958Surf 1,870 3 16 7-5/8 9-7/8 hole 4-1/2 6-3/4 hole 2 1 TY 56-9 TY 62-5 TY 54-5 TY 53- 6,380 tag on 6/27/23 NOTE: Consistent unknown restriction @ 6,384. 12 10 11 9 LB 50-9 LB 51 5150 LB 8 RA Marker Joints #1 @ 4,239'-4,280' MD #2 @ 5,410'-5,451' MD RA #2 RA #1 LB 50-7 6 UB 37-0 7 LB 50-6 5 UB 36-84 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: 7/15/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20250715 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# KBU 32-06 50133206580000 216137 7/1/2025 AK E-LINE PPROF BCU 14B 50133205390200 222057 6/20/2025 AK E-LINE Perf BR 03-87 50733204370000 166052 6/15/2025 AK E-LINE Perf BRU 211-35 50283201890000 223050 6/2/2025 AK E-LINE Perf BRU 213-26 50283201920000 223069 6/23/2025 AK E-LINE Perf BRU 221-24 50283202020000 225027 6/4/2025 AK E-LINE Perf BRU 221-24 50283202020000 225027 6/22/2025 AK E-LINE Perf BRU 221-24 50283202020000 225027 6/12/2025 AK E-LINE PPROF BRU 241-23 50283201910000 223061 6/10/2025 AK E-LINE Cement/Perf BRU 241-23 50283201910000 223061 6/19/2025 AK E-LINE CIBP BRU 241-23 50283201910000 223061 6/21/2025 AK E-LINE Perf BRU 241-23 50283201910000 223061 6/4/2025 AK E-LINE PlugPerf KBU 43-07Y 50133206250000 214019 6/17/2025 AK E-LINE Perf KU 41-08 50133207170000 224005 6/24/2025 AK E-LINE Plug Perf LIS L5-26 50029220790000 190110 6/21/2025 AK E-LINE Patch MRU M-25 50733203910000 187086 6/17/2025 AK E-LINE CIBP PBU 15-14A 50029206820100 204222 6/3/2025 BAKER SPN PBU 18-15C 50029217550300 211172 6/12/2025 AK E-LINE CBL/Perf PBU F-38B 50029220930300 225029 6/12/2025 BAKER MRPM SRU 241-33B 50133206960000 221053 5/25/2025 AK E-LINE CIBP Please include current contact information if different from above. T40659 T40660 T40661 T40662 T40663 T40664 T40664 T40664 T40665 T40665 T40665 T40665 T40666 T40667 T40668 T40669 T40670 T40671 T40672 T40673SRU 241-33B 50133206960000 221053 5/25/2025 AK E-LINE CIBP Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.07.16 10:52:24 -08'00' 1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: CTCO, N2 Development Exploratory 3. Address:Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number):8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071):10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 7,012 feet See Schematic feet true vertical 6,387 feet N/A feet Effective Depth measured 4,065 feet 1,866 feet true vertical 3,607 feet 1,766 feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth)Tieback 4-1/2" 12.6# / L-80 1,870' MD 1,770' TVD Packers and SSSV (type, measured and true vertical depth)Liner Top Pkr; N/A 1,866' MD 1,766' 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: 7,500psi 6,890psi 8,430psi 2,096'1,974' Burst Collapse 4,790psi Production Liner 7,012' Casing Structural 6,387'7,012' 120'Conductor Surface Intermediate 16" 7-5/8" 120' 2,096' measured TVD 4-1/2" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 221-053 50-133-20696-00-00 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: FEDA 0028399 Swanson River - Sterling/Upper Beluga Gas Swanson River Unit (SRU) 241-33B Plugs Junk measured Length 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 90 Size 120' 0 1101115 0 3900 634 325-267 Sr Pet Eng:Sr Pet Geo:Sr Res Eng: WINJ WAG 0 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Noel Nocas, Operations Manager 907-564-5278 N/A Ryan Lemay, Operations Engineer ryan.lemay@hilcorp.com 661-487-0871 p k ft t Fra O s 6. A G L PG , Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov By Gavin Gluyas at 12:27 pm, Jun 27, 2025 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2025.06.27 11:46:15 - 08'00' Noel Nocas (4361) RBDMS JSB 070325 BJM 9/23/25 Page 1/1 Well Name: SRF SRU 241-33B Report Printed: 6/18/2025WellViewAdmin@hilcorp.com Alaska Weekly Report - Operations Wellbore API/UWI:50-133-20696-00-00 Field Name:Swanson River State/Province:ALASKA Permit to Drill (PTD) #:221-053 Sundry #:325-267 Rig Name/No: Jobs Actual Start Date:5/14/2025 End Date: Report Number 1 Report Start Date 5/14/2025 Report End Date 5/14/2025 Last 24hr Summary Complete PTW / PJSM. MIRU Pollard Slickline w/.125" wire. PT PCE to 250 psi low / 2500 psi high as per sundry. Ran 2" DD bailer w/MS flapper bottom and tagged fill @ 3618' KB. Made 10 bailer runs and bailed beluga sand from 3618' - 3948' KB. Lay down and re-pack stuffing box. SDFN. Report Number 2 Report Start Date 5/15/2025 Report End Date 5/15/2025 Last 24hr Summary Complete PTW / PJSM. MIRU Pollard Slickline w/.125" wire. PT PCE to 250 psi low / 2500 psi high as per sundry. Ran 3.5" x 5' DD bailer w/MS flapper bottom and tagged fill @ 3939' KB. Alternate bailers 3.5", 3", and 2.5". Made 9 total bailer runs and bailed hard sand from 3939' - 3944' KB. Lay down and re-pack stuffing box. Discuss plan forward w/OE. SDFN. Report Number 3 Report Start Date 5/16/2025 Report End Date 5/16/2025 Last 24hr Summary Complete PTW / PJSM. MIRU Pollard Slickline w/.125" wire. PT PCE to 250 psi low / 2500 psi high as per sundry. Ran 3.7" cent & center spear wire grab and attempt to break up fill @ 3945' KB. Made 9 total runs w/bailers and chisel. Unable to break up compressed solids. Final bail depth = 3947' KB. Discuss plan forward w/OE. RDMO Pollard Slickline. Report Number 4 Report Start Date 5/23/2025 Report End Date 5/23/2025 Last 24hr Summary Mobilize Fox CTU 10 to location. Complete PTW / PJSM. Spot CTU, crane, coil pump, supply / return tanks. Stab pipe through injector head. N/D wellhead. N/U BOPE stack. R/U 2" 1502 hardline kill/choke sides. Load supply tank w/6% KCI. Completed BOPE test 250 psi low / 2500 psi high as per sundry. AOGCC Jim Regg waived witness 5/22/25 (11:29 am). SDFN. Report Number 5 Report Start Date 5/24/2025 Report End Date 5/24/2025 Last 24hr Summary Complete PTW / PJSM. P/U injector & riser. M/U BHA = CRC, Checks, Stinger, & 2.70" JSN. Shell test 250 psi low / 2500 psi high. Test checks. RIH w/BHA and dry tagged fill 3933' ctm. PUH to 3900' and come online down coil w/KCI 1.25 bpm / N2 600 scfm. At 30 bbls away, establish 1:1 nitrified returns holding 300 psi on choke. Eq rate 1.79 bpm, Eq BHP 1523 psi, AV 150 fpm. Begin nitrified cleanout taking 1 bbl bites / 65ft followed by 100 ft wiper trip. PUW 15k. At 4000' ctm, returns 70%, open choke to 150 psi and 90% returns. Cleanout down to TOC @ 4112' ctm and jet across perfs 4070' - 4080'. Wait for BU to clean up and swap to N2 blow down at 1000 sfcm. With N2 @ Nozzle begin unloading fluid from CTBS @ 4100' ctm. Pooh w/BHA pumping N2. Pinch choke to add 36 psi for every bbl of fluid returned to maintain BHP at perfs. Recovered 33.5 bbls of fluid. On surface w/BHA. WHP 1250 psi. Bleed N2 off well and confirm LELs @ 900 psi. Swap well to production and begin flow test. SDFN. Report Number 6 Report Start Date 5/25/2025 Report End Date 5/25/2025 Last 24hr Summary Complete PTW / PJSM. MIRU AK Eline. PT PCE 250 / 2500 psi. Drifted w/junk basket w/3.52" gauge ring, tagged fill 3943'. RDMO Eline. M/U BHA = 2.70" JSN. Shell test 250 psi low / 2500 psi high. RIH w/BHA and dry tagged fill 3959' ctm. Online down coil w/KCI @ 1.75 bpm. Establish 1:1 returns w/100 psi on choke. Cleanout from 3959' - 4050'. WHP fell off. Shut in CTBS and fluff & stuff from 3900' to 4100'. PUH to 3900'. Discuss plan forward w/OE. Verify good injectivity 2 bpm @ 265 psi. Pooh w/BHA. M/U 3.70" DJN & RIH. Dry tagged 4091' (Open perfs 4070'-4080'). Repeat tag. Pooh w/BHA. SDFN. Report Number 7 Report Start Date 5/26/2025 Report End Date 5/26/2025 Last 24hr Summary Complete PTW / PJSM. MIRU Ak Eline. M/U GR / CCL and 2.75” setting tool w/3.50” CIBP. CCL to top of plug = 17.2’. PT PCE 250/2500. RIH w/3.50” CIBP. Correlate & tag @ 4074.2’ corrected. Send logs to OE & Res to confirm shift. Log CCL on depth = 4047.8’. Set top of plug 4065’. Pooh w/BHA. WHP = 750 psi. Pressure up tubing w/pad gas to 1100 psi. Plug good. RDMO Ak Eline. RDMO Fox CTU 10. Report Number 8 Report Start Date 5/28/2025 Report End Date 5/28/2025 Last 24hr Summary PJSM/PTW, MIRU YJ EL, Test lub 250-2500psi,SITP 1100psi, RIH with 2-3/4" gun loaded 10', 6spf, 15 gram charges. Tag CIBP at 4065'md. Make correlation pass and send to town. Confirmed on depth. Perf UB_36-8 (4049'-4059'md). Monitored well no positive pressure response. POOH all shot fired, plug wet no fill. Flow test well, flowing 2mm. RDMO YJ EL. g Set top of plug 4065’. Pooh Updated by DMA 06-18-25 SCHEMATIC Swanson River Unit SRU 241-33B PTD: 221-053 API: 50-133-20696-00-00 PBTD = 6,927’ / TVD = 6,303’ TD = 7,012’ / TVD = 6,387’ RKB to GL = 18’ JEWELRY DETAIL No.Depth ID OD Item 1 1,525’3.958”4.500”Chemical Injection Sub 2 1,866’4.875”6.540”Liner Hanger / LTP Assembly 3 1,870’4.790”6.340”Seal Assy 4 4,065’NA NA CIBP (5/26/25) 5 4,148’ NA NA CIBP w/ 38’ cement (3/12/25) TOC 4,110’ 6 5,236’NA NA CIBP w/ 35’ cement (11/8/24) TOC 5201’ 7 5,307’NA NA CIBP 11/7/24 8 5,446’NA NA CIBP 11/5/24 9 5,576’NA NA CIBP (4/2/24) 10 5,784’NA NA CIBP w / 35’ cement (3/6/24), TOC 5749’ 11 5,975’NA NA CIBP w / 35’ cement (3/4/24), TOC 5940’ 12 6,177’-6,212’NA NA 35’ cement plug dump bailed (2/11/24) PERFORATION DETAIL Sand Top MD Btm MD Top TVD Btm TVD Ft Date Status UB 36-8 4,049’4,059’3,594’3,601’10’5/28/2025 Open UB 36-8 4,070’4,080’3,611’3,618’10’3/13/2025 Isolated UB 37-0 4,198'4,208'3,712'3,720'10'11/27/2024 Isolated LB 50-6 5,286'5,292'4,678'4,684'6'11/7/2024 Isolated LB 50-7 5,347'5,352'4,737'4,742'5'11/7/2024 Isolated LB 50-9 5,503'5,519'4,890'4,906'16’4/04/2024 Isolated LB 50-9 5,503'5,519'4,890'4,906'16’4/12/2024 Isolated LB 50-9 5,555'5,561'4,942'4,948'6’4/04/2024 Isolated LB 51-1 5,581'5,587'4,968'4,974'6’3/07/2024 Isolated LB 51-2 5,674'5,679'5,060'5,065'5’3/07/2024 Isolated LB 51-7 5,839'5,843'5,223'5,228'4’3/05/2024 Isolated LB 52-9 5,881'5,890'5,266'5,274'9’3/05/2024 Isolated TY 53-0 6,008’6,013’5,392’5,396’5’5/5/2022 Isolated TY 54-5 6,106’6,116’5,489’5,499’10’5/5/2022 Isolated TY 56-9 6,356’6,374’5,737’5,754’18’10/1/2021 Isolated TY 62-5 6,897’6,907’6,274’6,284’10’9/30/2021 Isolated OPEN HOLE / CEMENT DETAIL 7-5/8"139 BBL’s of cement in 9-7/8” hole – Returns to surface 4-1/2”177 BBL’s of cement in 6-3/4” hole – Est. TOC @ 1,866’ (LTP) (Returns to surface) 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 USS-CDC 6.875”Surf 2,096’ 4-1/2"Prod Lnr 12.6 L-80 DWC/C HT 3.958”1,866’7,012’ 4-1/2"Prod Tieback 12.6 L-80 DWC/C HT 3.958”Surf 1,870’ 3 16” 7-5/8” 9-7/8” hole 4-1/2” 6-3/4” hole 2 1 TY 56-9 TY 62-5 TY 54-5 TY 53- 6,380’ tag on 6/27/23 NOTE: Consistent unknown restriction @ 6,384’. 12 10 11 9 LB 50-9 LB 51 5150 LB 8 RA Marker Joints #1 @ 4,239'-4,280' MD #2 @ 5,410'-5,451' MD RA #2 RA #1 LB 50-7 6 UB 37-0 7 LB 50-6 5 UB 36-84 Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 5/29/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20250529 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# BCU 19RD 50133205790100 219188 5/10/2025 AK E-LINE GPT/CIBP/Perf HVB 13A 50231200320100 224160 3/16/2025 YELLOWJACKET SCBL IRU 241-01 50283201840000 221076 5/7/2025 AK E-LINE Plug/Perf KBU 22-06Y 50133206500000 215044 5/6/2025 AK E-LINE Perf KBU 22-06Y 50133206500000 215044 5/7/2025 AK E-LINE Perf KBU 24-06RD 50133204990100 206013 4/8/2025 YELLOWJACKET GPT-PLUG MPI 1-61 50029225200000 194142 5/10/2025 AK E-LINE Perf MPU E-42 50029236350000 219082 5/3/2025 AK E-LINE Patch MPU S-55 50029238130000 225006 5/13/2025 AK E-LINE CBL OP16-03 50029234420000 211017 4/25/2025 READ LeakDetect PAXTON 13 50133207330000 225021 4/29/2025 YELLOWJACKET SCBL PBU 01-12B 50029202690200 223090 4/8/2025 HALLIBURTON RBT PBU D-08B 50029203720200 225007 3/22/2025 BAKER MRPM PBU H-17B (REVISION)50029208620100 197152 4/10/2025 HALLIBURTON RBT-COILFLAG PBU J-25B 50029217410200 224134 3/10/2025 BAKER MRPM PBU K-19C (REVISION)50029225310300 224004 3/27/2025 BAKER MRPM PBU K-19C 50029225310300 224004 3/27/2025 HALLIBURTON RBT SRU 241-33B 50133206960000 221053 3/12/2025 YELLOWJACKET PERF Revision Explanation: Both wells had wrong side stack well name and API#/PTD on previous upload H-17b was marked as H-17A and K-19C was marked as K-19B. Well name now reflets correct sidetrack and has correct SPI# and PTD. T40489 T40490 T40491 T40492 T40492 T40493 T40494 T40495 T40496 T40497 T40498 T40499 T40500 T40501 T40502 T40503 T40503 T40504SRU 241-33B 50133206960000 221053 3/12/2025 YELLOWJACKET PERF Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.05.29 14:33:01 -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, CTCO 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: Current Pools: 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 7,012'N/A Casing Collapse Structural Conductor Surface 4,790psi Intermediate Production 7,500psi Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: 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 See Attached Schematic 7,012' See Schematic Length Sterling/Upper Beluga Gas 120' 2,096' Perforation Depth TVD (ft): Size Liner Top Packer ; N/A 1,866' MD / 1,766' TVD ; N/A 6,387'4,110'3,643' 16" See Attached Schematic 6,890psi 120' Swanson River Unit (SRU) 241-33BCO 716A Same 6,387'4-1/2" ~1,231psi 7-5/8" May 7, 2025 Tieback 4-1/2" 7,012' Perforation Depth MD (ft): 120' 2,096' MD PRESENT WELL CONDITION SUMMARY 12.6# / L-80 TVD Burst 1,870' 8,430psi 1,974' STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEDA028399 221-053 50-133-20696-00-00 Hilcorp Alaska, LLC Swanson River 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 AOGCC USE ONLY Tubing Grade:Tubing MD (ft): Subsequent Form Required: Noel Nocas, Operations Manager 907-564-5278 Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? 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: Proposed Pools: m n P s 66 t N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 1:06 pm, Apr 29, 2025 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2025.04.29 12:41:07 - 08'00' Noel Nocas (4361) 325-267 DSR-4/29/25 10-404 BJM 5/2/25 A.Dewhurst 13MAY25*&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.05.13 13:59:48 -08'00'05/13/25 RBDMS JSB 051425 Well Prognosis Well: SRU 241-33B Well Name: SRU 241-33B API Number: 50-133-20696-00-00 Current Status: Gas Producer Permit to Drill Number: 221-053 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: 1592 psi @ 3618’ TVD Based on 0.44 psi/ft Max. Potential Surface Pressure: 1231 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) = 1231 psi / 0.60 = 2052‘ TVD Top of Applicable Gas Pool: 2481’ MD / 2317’ TVD (Top Sterling/Upper Beluga) Well Status: Gas Producer x 862 mcfd @ 215 psi tubing pressure (As of April 21, 2025) Recent Well Summary On March 12-13, 2025 a CIBP was set @ 4148’MD and cement dump bailed with TOC tagged at 4110’ isolating the UB 37-0 sand interval from 4198’ – 4208’ MD. UB 36-8 perforations were added from 4070’-4080’ MD. The well came online at 2.4mmcfd @ 700 psi maintaining steady production for approximately two weeks. Recent well tests are showing a significant decline in gas rate with an increase in water production (last well test ~50 bbls water per day). The well is currently producing 862 mmcfd @ 215 psi tubing pressure (As of April 21, 2025) The purpose of this Sundry is to add additional perforations intervals in the Upper Beluga / Sterling Sands. Notes Regarding Wellbore Condition: x Inclination o Max inclination = 39.1° at 3112’ MD o Max DLS of 5.26°/100’ @ 2184’ MD Procedure: 1. MIRU E-line and pressure control equipment 2. PT lubricator to 250 psi low /2,500 psi high 3. RIH and perforate the following sands from bottom up with 2-7/8” 60 deg phased perf guns: Well Prognosis Well: SRU 241-33B 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 Well Sand MD top MD Bottom TVD top TVD bottom Interval SRU_241-33B ST_A13 +2889 +2896 +2669 +2675 +7 SRU_241-33B ST_A14 +2912 +2921 +2688 +2696 +9 SRU_241-33B ST_A16 +2983 +2993 +2746 +2754 +10 SRU_241-33B ST_B1 +3011 +3025 +2768 +2779 +14 SRU_241-33B ST_B2 +3118 +3124 +2852 +2857 +6 SRU_241-33B ST_B5 +3392 +3406 +3069 +3078 +14 SRU_241-33B UB_FF +3993 +4003 +3549 +3557 +10 SRU_241-33B UB_36-8 +4049 +4059 +3594 +3601 +10 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 nitrogen or high-pressure pad gas 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. Well Prognosis Well: SRU 241-33B Attachments: 1. Current Schematic 2. Proposed Schematic 3. Coil Tubing BOP Diagram 4. Standard Well Procedure – N2 Operations Updated by RPL 03-26-25 SCHEMATIC Swanson River Unit SRU 241-33B PTD: 221-053 API: 50-133-20696-00-00 PBTD = 6,927’ / TVD = 6,303’ TD = 7,012’ / TVD = 6,387’ RKB to GL = 18’ JEWELRY DETAIL No.Depth ID OD Item 1 1,525’3.958”4.500”Chemical Injection Sub 2 1,866’4.875”6.540”Liner Hanger / LTP Assembly 3 1,870’4.790”6.340”Seal Assy 4 4,148’ NA NA CIBP w/ 38’ cement (3/12/25) TOC 4,110’ 5 5,236’NA NA CIBP w/ 35’ cement (11/8/24) TOC 5201’ 6 5,307’NA NA CIBP 11/7/24 7 5,446’NA NA CIBP 11/5/24 8 5,576’ NA NA CIBP (4/2/24) 9 5,784’NA NA CIBP w / 35’ cement (3/6/24), TOC 5749’ 10 5,975’NA NA CIBP w / 35’ cement (3/4/24), TOC 5940’ 11 6,177’-6,212’NA NA 35’ cement plug dump bailed (2/11/24) PERFORATION DETAIL Sand Top MD Btm MD Top TVD Btm TVD Ft Date Status UB 36-8 4,070’4,080’3,611’3,618’10’3/13/2025 Open UB 37-0 4,198'4,208'3,712'3,720'10'11/27/2024 Isolated LB 50-6 5,286'5,292'4,678'4,684'6'11/7/2024 Isolated LB 50-7 5,347'5,352'4,737'4,742'5'11/7/2024 Isolated LB 50-9 5,503'5,519'4,890'4,906'16’4/04/2024 Isolated LB 50-9 5,503'5,519'4,890'4,906'16’4/12/2024 Isolated LB 50-9 5,555'5,561'4,942'4,948'6’4/04/2024 Isolated LB 51-1 5,581'5,587'4,968'4,974'6’3/07/2024 Isolated LB 51-2 5,674'5,679'5,060'5,065'5’3/07/2024 Isolated LB 51-7 5,839'5,843'5,223'5,228'4’3/05/2024 Isolated LB 52-9 5,881'5,890'5,266'5,274'9’3/05/2024 Isolated TY 53-0 6,008’6,013’5,392’5,396’5’5/5/2022 Isolated TY 54-5 6,106’6,116’5,489’5,499’10’5/5/2022 Isolated TY 56-9 6,356’6,374’5,737’5,754’18’10/1/2021 Isolated TY 62-5 6,897’6,907’6,274’6,284’10’9/30/2021 Isolated OPEN HOLE / CEMENT DETAIL 7-5/8"139 BBL’s of cement in 9-7/8” hole – Returns to surface 4-1/2”177 BBL’s of cement in 6-3/4” hole – Est. TOC @ 1,866’ (LTP) (Returns to surface) 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 USS-CDC 6.875”Surf 2,096’ 4-1/2"Prod Lnr 12.6 L-80 DWC/C HT 3.958”1,866’7,012’ 4-1/2"Prod Tieback 12.6 L-80 DWC/C HT 3.958”Surf 1,870’ 3 16” 7-5/8” 9-7/8” hole 4-1/2” 6-3/4” hole 2 1 TY 56-9 TY 62-5 TY 54-5 TY 53- 6,380’ tag on 6/27/23 NOTE: Consistent unknown restriction @ 6,384’. 11 9 10 8 LB 50-9 LB 51 5150 LB 7 RA Marker Joints #1 @ 4,239'-4,280' MD #2 @ 5,410'-5,451' MD RA #2 RA #1 LB 50-7 5 UB 37-0 6 LB 50-6 4 UB 36-8 Updated by RPL 4-9-25 PROPOSED Swanson River Unit SRU 241-33B PTD: 221-053 API: 50-133-20696-00-00 PBTD = 6,927’ / TVD = 6,303’ TD = 7,012’ / TVD = 6,387’ RKB to GL = 18’ JEWELRY DETAIL No.Depth ID OD Item 1 1,525’3.958”4.500”Chemical Injection Sub 2 1,866’4.875”6.540”Liner Hanger / LTP Assembly 3 1,870’4.790”6.340”Seal Assy 4 4,148’ NA NA CIBP w/ 38’ cement (3/12/25) TOC 4,110’ 5 5,236’NA NA CIBP w/ 35’ cement (11/8/24) TOC 5201’ 6 5,307’NA NA CIBP 11/7/24 7 5,446’NA NA CIBP 11/5/24 8 5,576’ NA NA CIBP (4/2/24) 9 5,784’NA NA CIBP w / 35’ cement (3/6/24), TOC 5749’ 10 5,975’NA NA CIBP w / 35’ cement (3/4/24), TOC 5940’ 11 6,177’-6,212’NA NA 35’ cement plug dump bailed (2/11/24) PERFORATION DETAIL Sand Top MD Btm MD Top TVD Btm TVD Ft Date Status ST_A13 +2889 +2896 +2669 +2675 +7 Proposed ST_A14 +2912 +2921 +2688 +2696 +9 Proposed ST_A16 +2983 +2993 +2746 +2754 +10 Proposed ST_B1 +3011 +3025 +2768 +2779 +14 Proposed ST_B2 +3118 +3124 +2852 +2857 +6 Proposed ST_B5 +3392 +3406 +3069 +3078 +14 Proposed UB_36-FF +3993 +4003 +3549 +3557 +10 Proposed UB_36-8 +4049 +4059 +3594 +3601 +10 Proposed UB 36-8 4,070’4,080’3,611’3,618’10’3/13/2025 Open UB 37-0 4,198'4,208'3,712'3,720'10'11/27/2024 Isolated LB 50-6 5,286'5,292'4,678'4,684'6'11/7/2024 Isolated LB 50-7 5,347'5,352'4,737'4,742'5'11/7/2024 Isolated LB 50-9 5,503'5,519'4,890'4,906'16’4/04/2024 Isolated LB 50-9 5,503'5,519'4,890'4,906'16’4/12/2024 Isolated LB 50-9 5,555'5,561'4,942'4,948'6’4/04/2024 Isolated LB 51-1 5,581'5,587'4,968'4,974'6’3/07/2024 Isolated LB 51-2 5,674'5,679'5,060'5,065'5’3/07/2024 Isolated LB 51-7 5,839'5,843'5,223'5,228'4’3/05/2024 Isolated LB 52-9 5,881'5,890'5,266'5,274'9’3/05/2024 Isolated TY 53-0 6,008’6,013’5,392’5,396’5’5/5/2022 Isolated TY 54-5 6,106’6,116’5,489’5,499’10’5/5/2022 Isolated TY 56-9 6,356’6,374’5,737’5,754’18’10/1/2021 Isolated TY 62-5 6,897’6,907’6,274’6,284’10’9/30/2021 Isolated OPEN HOLE / CEMENT DETAIL 7-5/8"139 BBL’s of cement in 9-7/8” hole – Returns to surface 4-1/2”177 BBL’s of cement in 6-3/4” hole – Est. TOC @ 1,866’ (LTP) (Returns to surface) 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 USS-CDC 6.875”Surf 2,096’ 4-1/2"Prod Lnr 12.6 L-80 DWC/C HT 3.958”1,866’7,012’ 4-1/2"Prod Tieback 12.6 L-80 DWC/C HT 3.958”Surf 1,870’ 3 16” 7-5/8” 9-7/8” hole 4-1/2” 6-3/4” hole 2 1 TY 56-9 TY 62-5 TY 54-5 TY 53- 6,380’ tag on 6/27/23 NOTE: Consistent unknown restriction @ 6,384’. 11 9 10 8 LB 50-9 LB 51 5150 LB 7 RA Marker Joints #1 @ 4,239'-4,280' MD #2 @ 5,410'-5,451' MD RA #2 RA #1 LB 50-7 5 UB 37-0 6 LB 50-6 4 UB 36-8 UB_36-8 – ST_A13 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. 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 7,012 feet See Schematic feet true vertical 6,387 feet N/A feet Effective Depth measured 4,110 feet 1,866 feet true vertical 3,643 feet 1,766 feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth)Tieback 4-1/2" 12.6# / L-80 1,870' MD 1,770' TVD Packers and SSSV (type, measured and true vertical depth)Liner Top Pkr; N/A 1,866' MD 1,766' 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: 325-069 Sr Pet Eng:Sr Pet Geo:Sr Res Eng: WINJ WAG 211 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 Ryan Lemay, Operations Engineer ryan.lemay@hilcorp.com 661-487-0871 measured true vertical Packer Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf MD 0 Size 120' 0 1250 0 00 574 measured TVD 4-1/2" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 221-053 50-133-20696-00-00 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: FEDA 0028399 Swanson River - Sterling/Upper Beluga, Beluga & Tyonek Gas Swanson River Unit (SRU) 241-33B Plugs Junk measured Length Production Liner 7,012' Casing Structural 6,387'7,012' 120'Conductor Surface Intermediate 16" 7-5/8" 120' 2,096' 7,500psi 6,890psi 8,430psi 2,096'1,974' Burst Collapse 4,790psi p k ft t Fra O s 6. A G L PG , Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov By Grace Christianson at 2:02 pm, Mar 26, 2025 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2025.03.26 13:04:47 - 08'00' Noel Nocas (4361) RBDMS JSB 040325 DSR-4/2/25BJM 5/2/25 Page 1/1 Well Name: SRF SRU 241-33B Report Printed: 3/26/2025WellViewAdmin@hilcorp.com Alaska Weekly Report - Operations Wellbore API/UWI:50-133-20696-00-00 Field Name:Swanson River State/Province:Alaska Permit to Drill (PTD) #:221-053 Sundry #:325-069 Rig Name/No: Jobs Actual Start Date:3/7/2025 End Date: Report Number 1 Report Start Date 3/12/2025 Report End Date 3/12/2025 Last 24hr Summary PTW/PJSM. 528 psi SITP. MIRU YJ E-line. PT lubricator 250 psi low / 2500 psi high - good test. RIH w/ GPT/CIBP and find fluid level @ 4,151' and set CIBP @ 4,148'. Dump bail 35' cement on CIBP (2 runs w/ 3" x 35' bailer). Estimated TOC: 4,113'. SDFN. Report Number 2 Report Start Date 3/13/2025 Report End Date 3/13/2025 Last 24hr Summary PTW/PJSM. 1165 psi SITP. RU YJ E-line. RIH w/ 10' x 2 3/4" 6SPF 60deg guns. Bleed well pressure to 1100 psi. Tag TOC @ 4,110'. Perforate UB_36-8 Lower (4,070’ – 4,080’). RIH w/ GPT and find fluid level ~4,058'. Flow well starting @ 1280 psi and dropping 5-10 psi/min. Check for fluid influx w/ GPT. Identify slugging fluid, POOH and RDMO YJ Eline. Turn well over to operations and flow well. Updated by RPL 03-26-25 SCHEMATIC Swanson River Unit SRU 241-33B PTD: 221-053 API: 50-133-20696-00-00 PBTD = 6,927’ / TVD = 6,303’ TD = 7,012’ / TVD = 6,387’ RKB to GL = 18’ JEWELRY DETAIL No.Depth ID OD Item 1 1,525’3.958”4.500”Chemical Injection Sub 2 1,866’4.875”6.540”Liner Hanger / LTP Assembly 3 1,870’4.790”6.340”Seal Assy 4 4,148’ NA NA CIBP w/ 38’ cement (3/12/25) TOC 4,110’ 5 5,236’NA NA CIBP w/ 35’ cement (11/8/24) TOC 5201’ 6 5,307’NA NA CIBP 11/7/24 7 5,446’NA NA CIBP 11/5/24 8 5,576’ NA NA CIBP (4/2/24) 9 5,784’NA NA CIBP w / 35’ cement (3/6/24), TOC 5749’ 10 5,975’NA NA CIBP w / 35’ cement (3/4/24), TOC 5940’ 11 6,177’-6,212’NA NA 35’ cement plug dump bailed (2/11/24) PERFORATION DETAIL Sand Top MD Btm MD Top TVD Btm TVD Ft Date Status UB 36-8 4,070’4,080’3,611’3,618’10’3/13/2025 Open UB 37-0 4,198'4,208'3,712'3,720'10'11/27/2024 Isolated LB 50-6 5,286'5,292'4,678'4,684'6'11/7/2024 Isolated LB 50-7 5,347'5,352'4,737'4,742'5'11/7/2024 Isolated LB 50-9 5,503'5,519'4,890'4,906'16’4/04/2024 Isolated LB 50-9 5,503'5,519'4,890'4,906'16’4/12/2024 Isolated LB 50-9 5,555'5,561'4,942'4,948'6’4/04/2024 Isolated LB 51-1 5,581'5,587'4,968'4,974'6’3/07/2024 Isolated LB 51-2 5,674'5,679'5,060'5,065'5’3/07/2024 Isolated LB 51-7 5,839'5,843'5,223'5,228'4’3/05/2024 Isolated LB 52-9 5,881'5,890'5,266'5,274'9’3/05/2024 Isolated TY 53-0 6,008’6,013’5,392’5,396’5’5/5/2022 Isolated TY 54-5 6,106’6,116’5,489’5,499’10’5/5/2022 Isolated TY 56-9 6,356’6,374’5,737’5,754’18’10/1/2021 Isolated TY 62-5 6,897’6,907’6,274’6,284’10’9/30/2021 Isolated OPEN HOLE / CEMENT DETAIL 7-5/8"139 BBL’s of cement in 9-7/8” hole – Returns to surface 4-1/2”177 BBL’s of cement in 6-3/4” hole – Est. TOC @ 1,866’ (LTP) (Returns to surface) 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 USS-CDC 6.875”Surf 2,096’ 4-1/2"Prod Lnr 12.6 L-80 DWC/C HT 3.958”1,866’7,012’ 4-1/2"Prod Tieback 12.6 L-80 DWC/C HT 3.958”Surf 1,870’ 3 16” 7-5/8” 9-7/8” hole 4-1/2” 6-3/4” hole 2 1 TY 56-9 TY 62-5 TY 54-5 TY 53- 6,380’ tag on 6/27/23 NOTE: Consistent unknown restriction @ 6,384’. 11 9 10 8 LB 50-9 LB 51 5150 LB 7 RA Marker Joints #1 @ 4,239'-4,280' MD #2 @ 5,410'-5,451' MD RA #2 RA #1 LB 50-7 5 UB 37-0 6 LB 50-6 4 UB 36-8 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: Current Pools: 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 7,012'N/A Casing Collapse Structural Conductor Surface 4,790psi Intermediate Production 7,500psi Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: 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 See Attached Schematic 7,012' See Schematic Length Sterling/Upper Belulga, Beluga & Tyonek Gas 120' 2,096' Perforation Depth TVD (ft): Size Liner Top Packer ; N/A 1,866' MD / 1,766' TVD ; N/A 6,387'5,201'4,596' 16" See Attached Schematic 6,890psi 120' Swanson River Unit (SRU) 241-33BCO 716A Same 6,387'4-1/2" ~1,262psi 7-5/8" February 24, 2025 Tieback 4-1/2" 7,012' Perforation Depth MD (ft): 120' 2,096' MD PRESENT WELL CONDITION SUMMARY Proposed Pools: 12.6# / L-80 TVD Burst 1,870' 8,430psi 1,974' STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEDA028399 221-053 50-133-20696-00-00 Hilcorp Alaska, LLC Swanson River 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 AOGCC USE ONLY Tubing Grade:Tubing MD (ft): Subsequent Form Required: Noel Nocas, Operations Manager 907-564-5278 Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? 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: m n P s 66 t N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov 325-069 By Gavin Gluyas at 8:01 am, Feb 11, 2025 Noel Nocas (4361) Digitally signed by Noel Nocas (4361) Date: 2025.02.10 19:57:48 -09'00' DSR-2/18/24 Perforate SFD 2/13/2025BJM 2/25/25 10-404 *&: 2/25/2025 Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.02.25 14:01:22 -09'00' RBDMS JSB 022625 Well Prognosis Well: SRU 241-33B Well Name: SRU 241-33B API Number: 50-133-20696-00-00 Current Status: Offline Gas Producer Permit to Drill Number: 221-053 Regulatory Contact: Donna Ambruz (907) 777-8305 First Call Engineer: Ryan LeMay (661)487-0871(C) Second Call Engineer: Chad Helgeson (907) 777-8405 (O) (907) 229-4824 (C) Maximum Expected BHP: 1633 psi @ 3712’ TVD Based on 0.44 psi/ft Max. Potential Surface Pressure: 1262 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) = 1262 psi / 0.60 = 2103‘ TVD Top of Applicable Gas Pool: 2527’ MD/2359’ TVD (Top Sterling/Upper Beluga) 5200’ MD/4596’ TVD (Beluga) Well Status: Offline Gas producer Brief Well Summary SRU 241-33B was drilled in fall of 2021 and was brought online in the TY 62-5 and TY 56-9 initially at 4000+ mcfd. Since then, the rate has fallen to between 500-800mcfd and is making water intermittently. In May of 2022, additional Tyonek sands were perforated and the well held a steady decline with the rate going to zero. Slickline bailing found fill over the perfs and in June 2023, a CTU FCO returned the well to production. Rate continued to decline until Beluga 51 perforations were added in March 2024. Rate came on at 1 mmscfd but quickly died due to thick mud filling the wellbore. A CTU FCO was completed in April 2024 followed by perforations in the Beluga 50 which returned the well to production. In September 2024 rate fell off once again and slickline again found thick mud covering perforations. In November 2024 perforations were added to the Lower beluga 50-7 and 50- 6 after a fill clean out but neither produced. A plug was set over these perforations with 35’ of cement to isolate perfs and the Beluga / Sterling & Upper Beluga pools. Upper Beluga 37-0 perforations were added from 4198’- 4208’MD and put on production initially producing ~1000-1200 mcfd. Gas production began to decline and well went to zero production ~1/27/25. The well was briefly brough back online at ~250 mcfd on 1/30/25 before quickly dying again. Slickline job completed finding fluid level at ~3300’ MD. The purpose of this Sundry is to plug and isolate open UB37-0 interval and continue to perforate the Upper Beluga/Sterling sands up hole. Notes Regarding Wellbore Condition: x Inclination o Max inclination = 39.1° at 3112’ MD o Max DLS of 5.26°/100’ @ 2184’ MD Procedure: 1. MIRU E-line and pressure control equipment 2. PT lubricator to 250 psi low /2,500 psi high 3. Use nitrogen or high-pressure pad gas to pressure up well and depress fluid prior to setting CIBP. 4. Set CIBP at + 4148’ MD and dump bail 35’ cement to + 4113’ MD 5. RIH and perforate the following sands from bottom up with 2-7/8” 60 deg phased perf guns: Agree. SFD Well Prognosis Well: SRU 241-33B 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 Well Sand MD top MD Bottom TVD top TVD bottom Interval SRU_241-33B ST_A13 +2889 +2896 +2669 +2675 +7 SRU_241-33B ST_A14 +2912 +2921 +2688 +2696 +9 SRU_241-33B ST_A15 +2983 +2993 +2746 +2754 +10 SRU_241-33B ST_B1 +3011 +3025 +2768 +2779 +14 SRU_241-33B ST_B2 +3118 +3124 +2852 +2857 +6 SRU_241-33B ST_B5 +3392 +3406 +3069 +3078 +14 SRU_241-33B UB_36-0 +3993 +4003 +3549 +3557 +10 SRU_241-33B UB_36-8 +4049 +4059 +3594 +3601 +10 SRU_241-33B UB_36-8 +4070 +4080 +3611 +3618 +10 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’. Cement will be placed on top of CIBP’s if isolating in between pools. f. If necessary, use nitrogen or high-pressure pad gas to pressure up well during perforating or to depress water prior to setting a plug above perforations 6. 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 3,000 psi high / 250 psi low. i. Provide AOGCC 24hrs notice of BOP test. b. Cleanout wellbore fill and / or blowdown well with nitrogen if necessary. Well Prognosis Well: SRU 241-33B Attachments: 1. Current Schematic 2. Proposed Schematic 3. Coil Tubing BOP Diagram 4. Standard Well Procedure – N2 Operations Updated by DMA 12-11-24 SCHEMATIC Swanson River Unit SRU 241-33B PTD: 221-053 API: 50-133-20696-00-00 PBTD = 6,927’ / TVD = 6,303’ TD = 7,012’ / TVD = 6,387’ RKB to GL = 18’ JEWELRY DETAIL No.Depth ID OD Item 1 1,525’3.958”4.500”Chemical Injection Sub 2 1,866’4.875”6.540”Liner Hanger / LTP Assembly 3 1,870’4.790”6.340”Seal Assy 4 5,236’NA NA CIBP w/ 35’ cement (11/8/24), TOC 5201’ 5 5,307’NA NA CIBP 11/7/24 6 5,446’NA NA CIBP 11/5/24 7 5,576’CIBP (4/2/24) 8 5,784’NA NA CIBP w / 35’ cement (3/6/24), TOC 5749’ 9 5,975’NA NA CIBP w / 35’ cement (3/4/24), TOC 5940’ 10 6,177’-6,212’NA NA 35’ cement plug dump bailed (2/11/24) PERFORATION DETAIL Sand Top MD Btm MD Top TVD Btm TVD Ft Date Status UB 37-0 4,198'4,208'3,712'3,720'10'11/27/2024 Open LB 50-6 5,286'5,292'4,678'4,684'6'11/7/2024 Isolated LB 50-7 5,347'5,352'4,737'4,742'5'11/7/2024 Isolated LB 50-9 5,503'5,519'4,890'4,906'16’4/04/2024 Isolated LB 50-9 5,503'5,519'4,890'4,906'16’4/12/2024 Isolated LB 50-9 5,555'5,561'4,942'4,948'6’4/04/2024 Isolated LB 51-1 5,581'5,587'4,968'4,974'6’3/07/2024 Isolated LB 51-2 5,674'5,679'5,060'5,065'5’3/07/2024 Isolated LB 51-7 5,839'5,843'5,223'5,228'4’3/05/2024 Isolated LB 52-9 5,881'5,890'5,266'5,274'9’3/05/2024 Isolated TY 53-0 6,008’6,013’5,392’5,396’5’5/5/2022 Isolated TY 54-5 6,106’6,116’5,489’5,499’10’5/5/2022 Isolated TY 56-9 6,356’6,374’5,737’5,754’18’10/1/2021 Isolated TY 62-5 6,897’6,907’6,274’6,284’10’9/30/2021 Isolated OPEN HOLE / CEMENT DETAIL 7-5/8"139 BBL’s of cement in 9-7/8” hole – Returns to surface 4-1/2”177 BBL’s of cement in 6-3/4” hole – Est. TOC @ 1,866’ (LTP) (Returns to surface) 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 USS-CDC 6.875”Surf 2,096’ 4-1/2"Prod Lnr 12.6 L-80 DWC/C HT 3.958”1,866’7,012’ 4-1/2"Prod Tieback 12.6 L-80 DWC/C HT 3.958”Surf 1,870’ 3 16” 7-5/8” 9-7/8” hole 4-1/2” 6-3/4” hole 2 1 TY 56-9 TY 62-5 TY 54-5 TY 53- 6,380’ tag on 6/27/23 NOTE: Consistent unknown restriction @ 6,384’. 10 8 9 7 LB 50-9 LB 51 5150 LB 6 RA Marker Joints #1 @ 4,239'-4,280' MD #2 @ 5,410'-5,451' MD RA #2 RA #1 LB 50-7 4 UB 37-0 5 LB 50-6 Updated by DMA 12-11-24 SCHEMATIC Proposed Swanson River Unit SRU 241-33B PTD: 221-053 API: 50-133-20696-00-00 PBTD = 6,927’ / TVD = 6,303’ TD = 7,012’ / TVD = 6,387’ RKB to GL = 18’ JEWELRY DETAIL No.Depth ID OD Item 1 1,525’3.958”4.500”Chemical Injection Sub 2 1,866’4.875”6.540”Liner Hanger / LTP Assembly 3 1,870’4.790”6.340”Seal Assy 4 +4148’NA NA CIBP w/ 35’ cement TOC +4,113’ (Proposed) 5 5,236’NA NA CIBP w/ 35’ cement (11/8/24), TOC 5201’ 6 5,307’NA NA CIBP 11/7/24 7 5,446’NA NA CIBP 11/5/24 8 5,576’ NA NA CIBP (4/2/24) 9 5,784’NA NA CIBP w / 35’ cement (3/6/24), TOC 5749’ 10 5,975’NA NA CIBP w / 35’ cement (3/4/24), TOC 5940’ 11 6,177’-6,212’NA NA 35’ cement plug dump bailed (2/11/24) PERFORATION DETAIL Sand Top MD Btm MD Top TVD Btm TVD Ft Date Status ST_A13 +2889 +2896 +2669 +2675 +7 Proposed ST_A14 +2912 +2921 +2688 +2696 +9 Proposed ST_A15 +2983 +2993 +2746 +2754 +10 Proposed ST_B1 +3011 +3025 +2768 +2779 +14 Proposed ST_B2 +3118 +3124 +2852 +2857 +6 Proposed ST_B5 +3392 +3406 +3069 +3078 +14 Proposed UB_36-0 +3993 +4003 +3549 +3557 +10 Proposed UB_36-8 +4049 +4059 +3594 +3601 +10 Proposed UB_36-8 +4070 +4080 +3611 +3618 +10 Proposed UB 37-0 4,198'4,208'3,712'3,720'10'11/27/2024 Isolate LB 50-6 5,286'5,292'4,678'4,684'6'11/7/2024 Isolated LB 50-7 5,347'5,352'4,737'4,742'5'11/7/2024 Isolated LB 50-9 5,503'5,519'4,890'4,906'16’4/04/2024 Isolated LB 50-9 5,503'5,519'4,890'4,906'16’4/12/2024 Isolated LB 50-9 5,555'5,561'4,942'4,948'6’4/04/2024 Isolated LB 51-1 5,581'5,587'4,968'4,974'6’3/07/2024 Isolated LB 51-2 5,674'5,679'5,060'5,065'5’3/07/2024 Isolated LB 51-7 5,839'5,843'5,223'5,228'4’3/05/2024 Isolated LB 52-9 5,881'5,890'5,266'5,274'9’3/05/2024 Isolated TY 53-0 6,008’6,013’5,392’5,396’5’5/5/2022 Isolated TY 54-5 6,106’6,116’5,489’5,499’10’5/5/2022 Isolated TY 56-9 6,356’6,374’5,737’5,754’18’10/1/2021 Isolated TY 62-5 6,897’6,907’6,274’6,284’10’9/30/2021 Isolated OPEN HOLE / CEMENT DETAIL 7-5/8"139 BBL’s of cement in 9-7/8” hole – Returns to surface 4-1/2”177 BBL’s of cement in 6-3/4” hole – Est. TOC @ 1,866’ (LTP) (Returns to surface) 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 USS-CDC 6.875”Surf 2,096’ 4-1/2"Prod Lnr 12.6 L-80 DWC/C HT 3.958”1,866’7,012’ 4-1/2"Prod Tieback 12.6 L-80 DWC/C HT 3.958”Surf 1,870’ 3 16” 7-5/8” 9-7/8” hole 4-1/2” 6-3/4” hole 2 1 TY 56-9 TY 62-5 TY 54-5 TY 53- 6,380’ tag on 6/27/23 NOTE: Consistent unknown restriction @ 6,384’. 11 9 10 8 LB 50-9 LB 51 5150 LB 7 RA Marker Joints #1 @ 4,239'-4,280' MD #2 @ 5,410'-5,451' MD RA #2 RA #1 LB 50-7 5 UB 37-0 6 LB 50-6 4 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: 2/8/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20240208 Well API #PTD #Log Date Log Company Log Type BCU 09A 50133204450100 224113 11/13/2024 YELLOWJACKET GPT-PERF BCU 09A 50133204450100 224113 10/30/2024 YELLOWJACKET GPT BCU 11A 50133205210100 224123 11/9/2024 YELLOWJACKET SCBL BCU 25 50133206440000 214132 11/2/2024 YELLOWJACKET SCBL END 2-74 REVISED 50029237850000 224024 12/5/2024 HALLIBURTON MFC24 HVA 10 50231200280000 204186 11/13/2024 YELLOWJACKET GPT-PERF KU 23-07A 50133207300000 224126 11/23/2024 YELLOWJACKET SCBL NCIU A-21 50883201990000 224086 11/29/2024 AK E-LINE CaliperSurvey PAXTON 6 50133207070000 222054 11/7/2024 YELLOWJACKET PERF PBU 01-37 50029236330000 219073 11/23/2024 BAKER MRPM PBU 06-15A 50029204590200 224108 12/26/2024 BAKER MRPM PBU 06-19B 50029207910200 224095 12/10/2024 BAKER MRPM PBU 07-29E 50029217820500 213001 11/26/2024 BAKER SPN PBU 14-31A 50029209890100 224090 11/10/2024 BAKER MRPM PBU 14-41A 50029222900100 224076 11/9/2024 BAKER MRPM SRU 241-33B 50133206960000 221053 11/5/2024 YELLOWJACKET GPT-PERF Revision Explanation: Annotations added to processed log. Please include current contact information if different from above. T40053 T40053 T40054 T40055 T40056 T40057 T40058 T40059 T40060 T40061 T40062 T40063 T40064 T40065 T40066 T40067SRU 241-33B 50133206960000 221053 11/5/2024 YELLOWJACKET GPT-PERF Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.02.07 13:25:23 -09'00' 1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: N2 Development Exploratory 3. Address: Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number): 8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 7,012 feet See Schematic feet true vertical 6,387 feet N/A feet Effective Depth measured 5,201 feet 1,866 feet true vertical 4,596 feet 1,766 feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth)Tieback 4-1/2" 12.6# / L-80 1,870' MD 1,770' TVD Packers and SSSV (type, measured and true vertical depth)Liner Top Pkr; N/A 1,866' MD 1,766' 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: Scott Warner, Operations Engineer Contact Email:scott.warner@hilcorp.com Authorized Title: Contact Phone: 907-564-4506 7,500psi 6,890psi 8,430psi 2,096' 1,974' Burst Collapse 4,790psi Production Liner 7,012' Casing Structural 6,387'7,012' 120'Conductor Surface Intermediate 16" 7-5/8" 120' 2,096' measured TVD 4-1/2" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 221-053 50-133-20696-00-00 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: FEDA 0028399 Swanson River - Sterling/Upper Beluga, Beluga & Tyonek Gas Swanson River Unit (SRU) 241-33B Plugs Junk measured Length 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 220 Size 120' 0 3501155 0 10600 1188 324-584 & 324-648 Sr Pet Eng: Sr Pet Geo: Sr Res Eng: WINJ WAG 0 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Noel Nocas, Operations Manager 907-564-5278 N/A p k ft t Fra O s 6. A G L PG , Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov By Grace Christianson at 10:31 am, Dec 20, 2024 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2024.12.20 10:06:44 - 09'00' Noel Nocas (4361) Page 1/1 Well Name: SRF SRU 241-33B Report Printed: 12/11/2024WellViewAdmin@hilcorp.com Alaska Weekly Report - Operations Jobs Actual Start Date:10/29/2024 End Date: Report Number 1 Report Start Date 11/4/2024 Report End Date 11/5/2024 Last 24hr Summary PJSM, Crew mob to location, Spot in & rig up equipment, Nipple up BOPE, Pressure test as per SUNDRY & AOGGC 250/2500 psi, Witness waived by Jim Regg, Secure well & rig down for the night. Report Number 2 Report Start Date 11/5/2024 Report End Date 11/6/2024 Last 24hr Summary PJSM, Crew travel to location, Pick up injection head & lube, Load reel, Pressure test 250/2500-good, Make up BHA 2.13" wash nozzle, Run in hole to dry tag @ 5310', kick in pump & load hole with 35 bbls, Clean out fill from 5310-5520', Circulate bottoms up, Pull out of hole, Lay down lube & injector, Spot in & rig up YJ eline, Pick up lube & tool string (CCL/GR/GR 3.75"), Pressure test 250/2500-good, Run in the hole & tag @ 5463', Pull out of hole, Pick up run #2 (CCL/GR/GR 3.60"), Run in the hole to tag @ 5453', Pull out of the hole, Pick up run #3 (CCL/GR/PLUG) (3.71"), Run in hole & set plug @ 5446', Tag & log off, Pull out of the hole, Secure well & rig down for the night. Report Number 3 Report Start Date 11/6/2024 Report End Date 11/7/2024 Last 24hr Summary PJSM, Crew travel to location, Pick up injector head & lube, Run in hole with 2.13", Tag @ 5459', Reverse with N2 recovering 97 bbls of fluid w/ 150k scfs of N2, Pull out of hole, Rig down & release coil, Change out upper master & swab, Pressure test to 3000 psi-good, Secure well for the night. Report Number 4 Report Start Date 11/7/2024 Report End Date 11/8/2024 Last 24hr Summary PTW/PJSM, PT 250/2500. SITP 1673, Perforate LB_50-7 from 5347'-5352', Ran GPT FL@ 5316'. Depress FL to 5325' S/I Gas W/ 2500psi on tbg. RIH W/ GPT & 3.71" CIBP FL@ 5309' Unable to depress FL anymore. Set CIBP@ 5307'. Bleed tbg pressure down. SITP 1684, Perforate LB_50-6 from 5286'-5292'. Report Number 5 Report Start Date 11/8/2024 Report End Date 11/9/2024 Last 24hr Summary PTW/PJSM, Ran GPT & 3.50" CIBP, FL @ 5169', Set CIBP @ 5236'. Dumped 35' cement on CIBP. Field: Swanson River Sundry #: 324-584 & 324-648 State: Alaska Rig/Service:Permit to Drill (PTD) #:221-053Permit to Drill (PTD) #:221-053 Wellbore API/UWI:50-133-20696-00-00 Report Number 6 Report Start Date 11/27/2024 Report End Date 11/28/2024 Last 24hr Summary PTW/PJSM, PT 250/2500, Perforate UB_37-0 from 4198'-4208' (see ~140psi jump), Flow test well. RDMO Updated by DMA 12-11-24 SCHEMATIC Swanson River Unit SRU 241-33B PTD: 221-053 API: 50-133-20696-00-00 PBTD = 6,927 / TVD = 6,303 TD = 7,012 / TVD = 6,387 RKB to GL = 18 JEWELRY DETAIL No. Depth ID OD Item 1 1,5253.9584.500Chemical Injection Sub 2 1,8664.8756.540Liner Hanger / LTP Assembly 3 1,8704.7906.340Seal Assy 4 5,236NA NA CIBP w/ 35 cement (11/8/24), TOC 5201 5 5,307NA NA CIBP 11/7/24 6 5,446NA NA CIBP 11/5/24 7 5,576CIBP (4/2/24) 8 5,784NA NA CIBP w / 35 cement (3/6/24), TOC 5749 9 5,975NA NA CIBP w / 35 cement (3/4/24), TOC 5940 10 6,177-6,212NA NA 35 cement plug dump bailed (2/11/24) PERFORATION DETAIL Sand Top MD Btm MD Top TVD Btm TVD Ft Date Status UB 37-0 4,198' 4,208' 3,712' 3,720' 10' 11/27/2024 Open LB 50-6 5,286' 5,292' 4,678' 4,684' 6' 11/7/2024 Isolated LB 50-7 5,347' 5,352' 4,737' 4,742' 5' 11/7/2024 Isolated LB 50-9 5,503' 5,519' 4,890' 4,906'164/04/2024 Isolated LB 50-9 5,503' 5,519' 4,890' 4,906'164/12/2024 Isolated LB 50-9 5,555' 5,561' 4,942' 4,948'64/04/2024 Isolated LB 51-1 5,581' 5,587' 4,968' 4,974'63/07/2024 Isolated LB 51-2 5,674' 5,679' 5,060' 5,065'53/07/2024 Isolated LB 51-7 5,839' 5,843' 5,223' 5,228'43/05/2024 Isolated LB 52-9 5,881' 5,890' 5,266' 5,274'93/05/2024 Isolated TY 53-0 6,008 6,013 5,392 5,396 55/5/2022 Isolated TY 54-5 6,106 6,116 5,489 5,499 105/5/2022 Isolated TY 56-9 6,356 6,374 5,737 5,754 1810/1/2021 Isolated TY 62-5 6,897 6,907 6,274 6,284 109/30/2021 Isolated OPEN HOLE / CEMENT DETAIL 7-5/8"139 BBLs of cement in 9-7/8 hole Returns to surface 4-1/2 177 BBLs of cement in 6-3/4 hole Est. TOC @ 1,866 (LTP) (Returns to surface) CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16Conductor Driven to Set Depth 84 X-56 Weld 15.01Surf 120 7-5/8"Surf Csg 29.7 L-80 USS-CDC 6.875Surf 2,096 4-1/2"Prod Lnr 12.6 L-80 DWC/C HT 3.9581,8667,012 4-1/2"Prod Tieback 12.6 L-80 DWC/C HT 3.958Surf 1,870 3 16 7-5/8 9-7/8 hole 4-1/2 6-3/4 hole 2 1 TY 56-9 TY 62-5 TY 54-5 TY 53- 6,380 tag on 6/27/23 NOTE: Consistent unknown restriction @ 6,384. 10 8 9 7 LB 50-9 LB 51 5150 LB 6 RA Marker Joints #1 @ 4,239'-4,280' MD #2 @ 5,410'-5,451' MD RA #2 RA #1 LB 50-7 4 UB 37-0 5 LB 50-6 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: Current Pools: 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 7,012'N/A Casing Collapse Structural Conductor Surface 4,790psi Intermediate Production 7,500psi Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng See Attached Schematic 7,012' See Schematic Length Sterling/Upper Belulga, Beluga & Tyonek Gas 120' 2,096' Perforation Depth TVD (ft): Size Liner Top Packer ; N/A 1,866' MD / 1,766' TVD ; N/A 6,387'5,201'4,596' 16" See Attached Schematic 6,890psi 120' Swanson River Unit (SRU) 241-33BCO 716A Sterling/Upper Belulga 6,387'4-1/2" ~1,262psi 7-5/8" October 27, 2024 Tieback 4-1/2" 7,012' Perforation Depth MD (ft): 120' 2,096' MD PRESENT WELL CONDITION SUMMARY Proposed Pools: 12.6# / L-80 TVD Burst 1,870' 8,430psi 1,974' STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEDA028399 221-053 50-133-20696-00-00 Hilcorp Alaska, LLC Swanson River 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 AOGCC USE ONLY Tubing Grade:Tubing MD (ft): scott.warner@hilcorp.com Subsequent Form Required: 907-564-4506 Noel Nocas, Operations Manager 907-564-5278 Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? 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: Scott Warner, Operations Engineer m n P s 66 t N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov November 27, 2024 By Grace Christianson at 2:59 pm, Nov 14, 2024 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2024.11.13 17:39:14 - 09'00' Noel Nocas (4361) 324-648 X bjm SFD 11/18/2024 10-404 combined w/ sundry 324-584 BJM 11/18/24 DSR-11/21/24*&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.11.22 08:46:37 -08'00'11/22/24 RBDMS JSB 112524 Well Prognosis Well: SRU 241-33B Well Name: SRU 241-33B API Number: 50-133-20696-00-00 Current Status: Offline Gas Producer Permit to Drill Number: 221-053 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: 1633 psi @ 3712’ TVD Based on 0.44 psi/ft Max. Potential Surface Pressure: 1262 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) = 1262 psi / 0.60 = 2103‘ TVD Top of Applicable Gas Pool: 2527’ MD/2359’ TVD (Top Sterling/Upper Beluga) 5200’ MD/4596’ TVD (Beluga) Well Status: Offline Gas producer Brief Well Summary SRU 241-33B was drilled in fall of 2021, and was brought online in the TY 62-5 and TY 56-9 initially at 4000+ mcfd. Since then the rate has fallen to between 500-800mcfd and is making water intermittently. In May of 2022, additional Tyonek sands were perforated and the well held a steady decline with the rate going to zero. Slickline bailing found fill over the perfs and in June 2023, a CTU FCO returned the well to production. Rate continued to decline until Beluga 51 perforations were added in March 2024. Rate came on at 1 mmscfd but quickly died due to thick mud filling the wellbore. A CTU FCO was completed in April 2024 followed by perforations in the Beluga 50 which returned the well to production. In September 2024 rate fell off once again and slickline again found thick mud covering perforations. In November 2024 perforations were added to the Lower beluga 50-7 and 50- 6 after a fill clean out but neither produced. A plug was set over these perforations with 35’ of cement to isolate perfs and the beluga / sterling & upper beluga pools. The purpose of this sundry is to perforate the upper Beluga/Sterling sands. Notes Regarding Wellbore Condition x Inclination o Max inclination = 39.1° at 3112’ MD o Max DLS of 5.26°/100’ @ 2184’ MD Procedure: 1. MIRU E-line and pressure control equipment 2. PT lubricator to 250 psi low /2,500 psi high 3. RIH and perforate the following sands from bottom up with 2-7/8” 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_A13 ±2,889' ±2,896' ±2,669' ±2,675' ±7' ST_A14 ±2,912' ±2,921' ±2,688' ±2,696' ±9' Well Prognosis Well: SRU 241-33B ST_A15 ±2,983' ±2,993' ±2,746' ±2,754' ±10' ST_B1 ±3,011' ±3,025' ±2,768' ±2,779' ±14' ST_B2 ±3,118' ±3,124' ±2,852' ±2,857' ±6' ST_B5 ±3,392' ±3,406' ±3,069' ±3,078' ±14' UB_36-0 ±3,993' ±4,003' ±3,549' ±3,557' ±10' UB_36-8 ±4,049' ±4,058' ±3,594' ±3,601' ±9' UB_36-8 ±4,070' ±4,079' ±3,611' ±3,618' ±9' UB_37-0 ±4,198' ±4,208' ±3,712' ±3,720' ±10' 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: 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’. Cement will be placed on top of CIBP’s if isolating in between pools. g. If necessary, use nitrogen or high-pressure pad gas 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 SRW 11-13-24 CURRENT SCHEMATIC Swanson River Unit SRU 241-33B PTD: 221-053 API: 50-133-20696-00-00 PBTD = 6,927’ / TVD = 6,303’ TD = 7,012’ / TVD = 6,387’ RKB to GL = 18’ JEWELRY DETAIL No.Depth ID OD Item 1 1,525’3.958”4.500”Chemical Injection Sub 2 1,866’4.875”6.540”Liner Hanger / LTP Assembly 3 1,870’4.790”6.340”Seal Assy 3a 5,236’NA NA CIBP w/ 35’ cement (11/8/24), TOC 5201’ 3b 5,307’NA NA CIBP 3c 5,446’NA NA CIBP 4 5,576’CIBP (4/2/24) 5 5,784’NA NA CIBP w / 35’ cement (3/6/24), TOC 5749’ 6 5,975’NA NA CIBP w / 35’ cement (3/4/24), TOC 5940’ 7 6,177’-6,212’NA NA 35’ cement plug dump bailed (2/11/24) PERFORATION DETAIL Sand Top MD Btm MD Top TVD Btm TVD Ft Date Status LB_50-6 5,286'5,292'4,678'4,684'6'11/7/2024 Isolated LB_50-7 5,347'5,352'4,737'4,742'5'11/7/2024 Isolated LB 50-9 5,503'5,519'4,890'4,906'16’4/04/2024 Isolated LB 50-9 5,503'5,519'4,890'4,906'16’4/12/2024 Isolated LB 50-9 5,555'5,561'4,942'4,948'6’4/04/2024 Isolated LB 51-1 5,581'5,587'4,968'4,974'6’3/07/2024 Isolated LB 51-2 5,674'5,679'5,060'5,065'5’3/07/2024 Isolated LB 51-7 5,839'5,843'5,223'5,228'4’3/05/2024 Isolated LB 52-9 5,881'5,890'5,266'5,274'9’3/05/2024 Isolated TY 53-0 6,008’6,013’5,392’5,396’5’5/5/2022 Isolated TY 54-5 6,106’6,116’5,489’5,499’10’5/5/2022 Isolated TY 56-9 6,356’6,374’5,737’5,754’18’10/1/2021 Isolated TY 62-5 6,897’6,907’6,274’6,284’10’9/30/2021 Isolated OPEN HOLE / CEMENT DETAIL 7-5/8"139 BBL’s of cement in 9-7/8” hole – Returns to surface 4-1/2”177 BBL’s of cement in 6-3/4” hole – Est. TOC @ 1,866’ (LTP) (Returns to surface) 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 USS-CDC 6.875”Surf 2,096’ 4-1/2"Prod Lnr 12.6 L-80 DWC/C HT 3.958”1,866’7,012’ 4-1/2"Prod Tieback 12.6 L-80 DWC/C HT 3.958”Surf 1,870’ 3 16” 7-5/8” 9-7/8” hole 4-1/2” 6-3/4” hole 2 1 TY 56-9 TY 62-5 TY 54-5 TY 53- 6,380’ tag on 6/27/23 NOTE: Consistent unknown restriction @ 6,384’. 7 5 6 4 LB 50-9 LB 51 5150 LB 3c RA Marker Joints #1 @ 4,239'-4,280' MD #2 @ 5,410'-5,451' MD RA #2 RA #1 LB 50-7 3a LB 50-6 3b Updated by SRW 11-13-24 PROPOSED Swanson River Unit SRU 241-33B PTD: 221-053 API: 50-133-20696-00-00 PBTD = 6,927’ / TVD = 6,303’ TD = 7,012’ / TVD = 6,387’ RKB to GL = 18’ JEWELRY DETAIL No.Depth ID OD Item 1 1,525’3.958”4.500”Chemical Injection Sub 2 1,866’4.875”6.540”Liner Hanger / LTP Assembly 3 1,870’4.790”6.340”Seal Assy 3a 5,236’NA NA CIBP w/ 35’ cement (11/8/24), TOC 5201’ 3b 5,307’NA NA CIBP 3c 5,446’NA NA CIBP 4 5,576’CIBP (4/2/24) 5 5,784’NA NA CIBP w / 35’ cement (3/6/24), TOC 5749’ 6 5,975’NA NA CIBP w / 35’ cement (3/4/24), TOC 5940’ 7 6,177’-6,212’NA NA 35’ cement plug dump bailed (2/11/24) PERFORATION DETAIL Sand Top MD Btm MD Top TVD Btm TVD Ft Date Status ST_A13 ±2,889'±2,896'±2,669'±2,675'±7'TBD Proposed ST_A14 ±2,912'±2,921'±2,688'±2,696'±9'TBD Proposed ST_A15 ±2,983'±2,993'±2,746'±2,754'±10'TBD Proposed ST_B1 ±3,011'±3,025'±2,768'±2,779'±14'TBD Proposed ST_B2 ±3,118'±3,124'±2,852'±2,857'±6'TBD Proposed ST_B5 ±3,392'±3,406'±3,069'±3,078'±14'TBD Proposed UB_36-0 ±3,993'±4,003'±3,549'±3,557'±10'TBD Proposed UB_36-8 ±4,049'±4,058'±3,594'±3,601'±9'TBD Proposed UB_36-8 ±4,070'±4,079'±3,611'±3,618'±9'TBD Proposed UB_37-0 ±4,198'±4,208'±3,712'±3,720'±10'TBD Proposed LB_50-6 5,286'5,292'4,678'4,684'6'11/7/2024 Isolated LB_50-7 5,347'5,352'4,737'4,742'5'11/7/2024 Isolated LB 50-9 5,503'5,519'4,890'4,906'16’4/04/2024 Isolated LB 50-9 5,503'5,519'4,890'4,906'16’4/12/2024 Isolated LB 50-9 5,555'5,561'4,942'4,948'6’4/04/2024 Isolated LB 51-1 5,581'5,587'4,968'4,974'6’3/07/2024 Isolated LB 51-2 5,674'5,679'5,060'5,065'5’3/07/2024 Isolated LB 51-7 5,839'5,843'5,223'5,228'4’3/05/2024 Isolated LB 52-9 5,881'5,890'5,266'5,274'9’3/05/2024 Isolated TY 53-0 6,008’6,013’5,392’5,396’5’5/5/2022 Isolated TY 54-5 6,106’6,116’5,489’5,499’10’5/5/2022 Isolated TY 56-9 6,356’6,374’5,737’5,754’18’10/1/2021 Isolated TY 62-5 6,897’6,907’6,274’6,284’10’9/30/2021 Isolated OPEN HOLE / CEMENT DETAIL 7-5/8"139 BBL’s of cement in 9-7/8” hole – Returns to surface 4-1/2”177 BBL’s of cement in 6-3/4” hole – Est. TOC @ 1,866’ (LTP) (Returns to surface) 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 USS-CDC 6.875”Surf 2,096’ 4-1/2"Prod Lnr 12.6 L-80 DWC/C HT 3.958”1,866’7,012’ 4-1/2"Prod Tieback 12.6 L-80 DWC/C HT 3.958”Surf 1,870’ 3 16” 7-5/8” 9-7/8” hole 4-1/2” 6-3/4” hole 2 1 TY 56-9 TY 62-5 TY 54-5 TY 53- 6,380’ tag on 6/27/23 NOTE: Consistent unknown restriction @ 6,384’. 7 5 6 4 LB 50-9 LB 51 5150 LB 3c RA Marker Joints #1 @ 4,239'-4,280' MD #2 @ 5,410'-5,451' MD RA #2 RA #1 LB 50-7 3b LB 50-6 3a 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. 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: CTCO, 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: Current Pools: 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 7,012'N/A Casing Collapse Structural Conductor Surface 4,790psi Intermediate Production 7,500psi Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng 907-564-4506 Noel Nocas, Operations Manager 907-564-5278 Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? 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 writte n approval. Authorized Name and Digital Signature with Date: Tubing Size: Scott Warner, Operations Engineer AOGCC USE ONLY Tubing Grade:Tubing MD (ft): scott.warner@hilcorp.com Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEDA028399 221-053 50-133-20696-00-00 Hilcorp Alaska, LLC Swanson River 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Proposed Pools: 12.6# / L-80 TVD Burst 1,870' 8,430psi 1,974' 120' 2,096' MD PRESENT WELL CONDITION SUMMARY October 18, 2024 Tieback 4-1/2" 7,012' Perforation Depth MD (ft): Swanson River Unit (SRU) 241-33BCO 716A Same 6,387'4-1/2" ~1,680 psi 7-5/8" Liner Top Packer ; N/A 1,866' MD / 1,766' TVD ; N/A 6,387'5,576'4,963' 16" See Attached Schematic 6,890psi 120' See Attached Schematic 7,012' See Schematic Length Sterling/Upper Belulga, Beluga & Tyonek Gas 120' 2,096' Perforation Depth TVD (ft): Size m n P s 66 t N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 8:13 am, Oct 08, 2024 Noel Nocas (4361) Digitally signed by Noel Nocas (4361) Date: 2024.10.08 07:59:18 -08'00' 324-584 SFD 10/11/2024 Perforate DSR-10/10/24BJM 10/17/24 X This sundry only approves the perforations in the LB 50-6, 50-7 and 50-9. Shallower perforations will require a separate sundry because they are in a different pool. CT BOP test to 2500 psi 10-404 JLC 10/21/2024 Gregory Wilson Digitally signed by Gregory Wilson Date: 2024.10.21 09:04:20 -08'00'10/21/24 RBDMS JSB 102224 Well Prognosis Well: SRU 241-33B Well Name: SRU 241-33B API Number: 50-133-20696-00-00 Current Status: Offline Gas Producer Permit to Drill Number: 221-053 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: 2175 psi @ 4942’ TVD Based on 0.44 psi/ft Max. Potential Surface Pressure:1680 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) = 1680 psi / 0.60 = 2800‘ TVD Top of Applicable Gas Pool: 2527’ MD/2359’ TVD (Top Sterling/Upper Beluga) 5200’ MD/4596’ TVD (Beluga) Well Status: Offline Gas producer Brief Well Summary SRU 241-33B was drilled in fall of 2021, and was brought online in the TY 62-5 and TY 56-9 initially at 4000+ mcfd. Since then the rate has fallen to between 500-800mcfd and is making water intermittently. In May of 2022, additional Tyonek sands were perforated and the well held a steady decline with the rate going to zero. Slickline bailing found fill over the perfs and in June 2023, a CTU FCO returned the well to production. Rate continued to decline until Beluga 51 perforations were added in March 2024. Rate came on at 1 mmscfd but quickly died due to thick mud filling the wellbore. A CTU FCO was completed in April 2024 followed by perforations in the Beluga 50 which returned the well to production. In September 2024 rate fell off once again and slickline again found thick mud covering perforations The purpose of this sundry is to cleanout the wellbore to access the current open perforations, set a plug, and perforate Beluga/Sterling sands up hole. Notes Regarding Wellbore Condition x Inclination o Max inclination = 39.1° at 3112’ MD o Max DLS of 5.26°/100’ @ 2184’ MD x Recent Tags o 9/12/24: SL bailed fill from 116’ to 5028’ kb using various size bailers Procedure: 1. MIRU CTU 2. PT BOPE to 250 psi low / 2,500 psi high 3. RIH with coil tubing nozzle or mill and clean out as deep as possible to CIBP at 5,576’ 4. RIH and reverse out fluid with nitrogen, trap 1800 psi on the wellbore for future perforating 5. RDMO CTU 6. MIRU E-line and pressure control equipment 7. PT lubricator to 250 psi low /2,500 psi high 8. RIH and set CIBP @ ~5493’, 10’ above current open perfs , equivalent to ~3,050' MD SFD pp Shallowest Allowable Perf TVD 2800‘ TVD Well Prognosis Well: SRU 241-33B a. Requesting a variance from BLM to set the CIBP <50’ above top open perfs and to forego dump bailing cement on top of the plug due to limited spacing between current and proposed perforations 9. RIH and perforate the following sands from bottom up with 2-7/8” 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_A13 ±2,889' ±2,896' ±2,669' ±2,675' ±7' ST_A14 ±2,912' ±2,921' ±2,688' ±2,696' ±9' ST_A15 ±2,983' ±2,993' ±2,746' ±2,754' ±10' ST_B1 ±3,011' ±3,025' ±2,768' ±2,779' ±14' ST_B2 ±3,118' ±3,124' ±2,852' ±2,857' ±6' ST_B5 ±3,392' ±3,406' ±3,069' ±3,078' ±14' UB_36-0 ±3,993' ±4,003' ±3,549' ±3,557' ±10' UB_36-8 ±4,049' ±4,058' ±3,594' ±3,601' ±9' UB_36-8 ±4,070' ±4,079' ±3,611' ±3,618' ±9' UB_37-0 ±4,198' ±4,208' ±3,712' ±3,720' ±10' LB_50-6 ±5,286' ±5,292' ±4,678' ±4,684' ±6' LB_50-7 ±5,347' ±5,352' ±4,737' ±4,742' ±5' LB_50-9 ±5,456' ±5,462' ±4,844' ±4,850' ±6' 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: 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’. Cement will be placed on top of CIBP’s if isolating in between pools. g. If necessary, use nitrogen or high-pressure pad gas to pressure up well during perforating or to depress water prior to setting a plug above perforations 10. RDMO Per above calculations, shallowest allowable perforation is ~3,050' MD / 2,800' TVD. SFD Requesting a variance from BLM to set the CIBP <50’ above top open perfs and to forego dump bailing cement on top of the plug due to limited spacing between current and proposed perforations Perforations in the Upper Beluga and Sterling are not permitted. -bjm Well Prognosis Well: SRU 241-33B Attachments: 1. Current Schematic 2. Proposed Schematic 3. Coil Tubing BOP Schematic 4. Standard Well Procedure – N2 Operations Updated by DMA 05-16-24 SCHEMATIC Swanson River Unit SRU 241-33B PTD: 221-053 API: 50-133-20696-00-00 PBTD = 6,927’ / TVD = 6,303’ TD = 7,012’ / TVD = 6,387’ RKB to GL = 18’ JEWELRY DETAIL No. Depth ID OD Item 1 1,525’ 3.958” 4.500” Chemical Injection Sub 2 1,866’ 4.875” 6.540” Liner Hanger / LTP Assembly 3 1,870’ 4.790” 6.340” Seal Assy 4 5,576’ CIBP (4/2/24) 5 5,784’ NA NA CIBP w / 35’ cement (3/6/24), TOC 5749’ 6 5,975’ NA NA CIBP w / 35’ cement (3/4/24), TOC 5940’ 7 6,177’-6,212’ NA NA 35’ cement plug dump bailed (2/11/24) PERFORATION DETAIL Sand Top MD Btm MD Top TVD Btm TVD Ft Date Status LB 50-9 5,503' 5,519' 4,890' 4,906' 16’ 4/04/2024 Open LB 50-9 5,503' 5,519' 4,890' 4,906' 16’ 4/12/2024 Open LB 50-9 5,555' 5,561' 4,942' 4,948' 6’ 4/04/2024 Open LB 51-1 5,581' 5,587' 4,968' 4,974' 6’ 3/07/2024 Isolated LB 51-2 5,674' 5,679' 5,060' 5,065' 5’ 3/07/2024 Isolated LB 51-7 5,839' 5,843' 5,223' 5,228' 4’ 3/05/2024 Isolated LB 52-9 5,881' 5,890' 5,266' 5,274' 9’ 3/05/2024 Isolated TY 53-0 6,008’ 6,013’ 5,392’ 5,396’ 5’ 5/5/2022 Isolated TY 54-5 6,106’ 6,116’ 5,489’ 5,499’ 10’ 5/5/2022 Isolated TY 56-9 6,356’ 6,374’ 5,737’ 5,754’ 18’ 10/1/2021 Isolated TY 62-5 6,897’ 6,907’ 6,274’ 6,284’ 10’ 9/30/2021 Isolated OPEN HOLE / CEMENT DETAIL 7-5/8" 139 BBL’s of cement in 9-7/8” hole – Returns to surface 4-1/2” 177 BBL’s of cement in 6-3/4” hole – Est. TOC @ 1,866’ (LTP) (Returns to surface) 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 USS-CDC 6.875” Surf 2,096’ 4-1/2" Prod Lnr 12.6 L-80 DWC/C HT 3.958” 1,866’ 7,012’ 4-1/2" Prod Tieback 12.6 L-80 DWC/C HT 3.958” Surf 1,870’ 3 16” 7-5/8” 9-7/8” hole 4-1/2” 6-3/4” hole 2 1 TY 56-9 TY 62-5 TY 54-5 TY 53-0 6,380’ tag on 6/27/23 NOTE: Consistent unknown restriction @ 6,384’. 7 5 6 4 LB 50-9 LB 51 LB 52 Updated by SRW 10-03-24 PROPOSED Swanson River Unit SRU 241-33B PTD: 221-053 API: 50-133-20696-00-00 PBTD = 6,927’ / TVD = 6,303’ TD = 7,012’ / TVD = 6,387’ RKB to GL = 18’ JEWELRY DETAIL No. Depth ID OD Item 1 1,525’ 3.958” 4.500” Chemical Injection Sub 2 1,866’ 4.875” 6.540” Liner Hanger / LTP Assembly 3 1,870’ 4.790” 6.340” Seal Assy 3a 5,493’ NA NA CIBP (Proposed) 4 5,576’ CIBP (4/2/24) 5 5,784’ NA NA CIBP w / 35’ cement (3/6/24), TOC 5749’ 6 5,975’ NA NA CIBP w / 35’ cement (3/4/24), TOC 5940’ 7 6,177’-6,212’ NA NA 35’ cement plug dump bailed (2/11/24) PERFORATION DETAIL Sand Top MD Btm MD Top TVD Btm TVD Ft Date Status ST_A13 ±2,889' ±2,896' ±2,669' ±2,675' ±7' TBD Proposed ST_A14 ±2,912' ±2,921' ±2,688' ±2,696' ±9' TBD Proposed ST_A15 ±2,983' ±2,993' ±2,746' ±2,754' ±10' TBD Proposed ST_B1 ±3,011' ±3,025' ±2,768' ±2,779' ±14' TBD Proposed ST_B2 ±3,118' ±3,124' ±2,852' ±2,857' ±6' TBD Proposed ST_B5 ±3,392' ±3,406' ±3,069' ±3,078' ±14' TBD Proposed UB_36-0 ±3,993' ±4,003' ±3,549' ±3,557' ±10' TBD Proposed UB_36-8 ±4,049' ±4,058' ±3,594' ±3,601' ±9' TBD Proposed UB_36-8 ±4,070' ±4,079' ±3,611' ±3,618' ±9' TBD Proposed UB_37-0 ±4,198' ±4,208' ±3,712' ±3,720' ±10' TBD Proposed LB_50-6 ±5,286' ±5,292' ±4,678' ±4,684' ±6' TBD Proposed LB_50-7 ±5,347' ±5,352' ±4,737' ±4,742' ±5' TBD Proposed LB_50-9 ±5,456' ±5,462' ±4,844' ±4,850' ±6' TBD Proposed LB 50-9 5,503' 5,519' 4,890' 4,906' 16’ 4/04/2024 Open LB 50-9 5,503' 5,519' 4,890' 4,906' 16’ 4/12/2024 Open LB 50-9 5,555' 5,561' 4,942' 4,948' 6’ 4/04/2024 Open LB 51-1 5,581' 5,587' 4,968' 4,974' 6’ 3/07/2024 Isolated LB 51-2 5,674' 5,679' 5,060' 5,065' 5’ 3/07/2024 Isolated LB 51-7 5,839' 5,843' 5,223' 5,228' 4’ 3/05/2024 Isolated LB 52-9 5,881' 5,890' 5,266' 5,274' 9’ 3/05/2024 Isolated TY 53-0 6,008’ 6,013’ 5,392’ 5,396’ 5’ 5/5/2022 Isolated TY 54-5 6,106’ 6,116’ 5,489’ 5,499’ 10’ 5/5/2022 Isolated TY 56-9 6,356’ 6,374’ 5,737’ 5,754’ 18’ 10/1/2021 Isolated TY 62-5 6,897’ 6,907’ 6,274’ 6,284’ 10’ 9/30/2021 Isolated OPEN HOLE / CEMENT DETAIL 7-5/8" 139 BBL’s of cement in 9-7/8” hole – Returns to surface 4-1/2” 177 BBL’s of cement in 6-3/4” hole – Est. TOC @ 1,866’ (LTP) (Returns to surface) 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 USS-CDC 6.875” Surf 2,096’ 4-1/2" Prod Lnr 12.6 L-80 DWC/C HT 3.958” 1,866’ 7,012’ 4-1/2" Prod Tieback 12.6 L-80 DWC/C HT 3.958” Surf 1,870’ 3 16” 7-5/8” 9-7/8” hole 4-1/2” 6-3/4” hole 2 1 TY 56-9 TY 62-5 TY 54-5 TY 53- 6,380’ tag on 6/27/23 NOTE: Consistent unknown restriction @ 6,384’. 7 5 6 4 LB LB 51 5150 LB 3a Per above calculations, shallowest allowable perforation is ~3,050' MD / 2,800' TVD. SFD Perforations are not permitted in upper Beluga or Sterling under this sundry. -bjm 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. 1 McLellan, Bryan J (OGC) From:McLellan, Bryan J (OGC) Sent:Thursday, October 17, 2024 3:19 PM To:Scott Warner Cc:Davies, Stephen F (OGC); Roby, David S (OGC) Subject:RE: [EXTERNAL] SRU 241-33B (PTD 221-053) No worries. We’ll just cross out the shallower perfs on the sundry. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Scott Warner <Scott.Warner@hilcorp.com> Sent: Thursday, October 17, 2024 2:58 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Roby, David S (OGC) <dave.roby@alaska.gov> Subject: RE: [EXTERNAL] SRU 241-33B (PTD 221-053) Bryan, As of now we only plan to perforate the LB 50-6, 50-7 and 50-9. I should’ve either submiƩed the sundries separately or been clearer on our intenƟons knowing these are diīerent pools. Once we deplete the LB sands the new top allowable perf based on frac pressure will be 2103’ TVD. We will set a CIBP with 35’ of cement above the Beluga & Tyonek gas sands before moving uphole to the Sterling/Upper Beluga gas sands. Sorry for the confusion and lack of informaƟon. Thanks, ScoƩ Warner Kenai – OperaƟons Engineer Oĸce: (907) 564-4506 Cell: (907) 830-8863 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: Thursday, October 17, 2024 1:39 PM To: Scott Warner <Scott.Warner@hilcorp.com> Cc: Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Roby, David S (OGC) <dave.roby@alaska.gov> Subject: [EXTERNAL] SRU 241-33B (PTD 221-053) Scott, With the plan to perforate sands in both pools, you need a comingling order, or else need to plug o Ư with 25 ft of cement all Beluga & Tyo Gas sands before perforating Sterling/Upper Beluga Gas sands. Also, your calculations for top allowable perf based on frac pressure (2800’ TVD/3050’ MD) are deeper than your planned new perfs. Can’t perf above 3050 MD unless you do some plugging with cement per 20 AAC 25.112. 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. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 5/1/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20240501 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# HV B-13 50231200320000 207151 4/10/2024 YELLOW JACKET GPT-PERF KU 13-06A 50133207160000 223112 3/27/2024 YELLOW JACKET GPT-PERF KU 13-06A 50133207160000 223112 4/1/2024 YELLOW JACKET GPT-PLUG-PERF KU 13-06A 50133207160000 223112 3/22/2024 YELLOW JACKET GPT-PERF KU 33-08 50133207180000 224008 4/30/2024 YELLOW JACKET SCBL KU 41-08 50133207170000 224005 4/23/2024 YELLOW JACKET SCBL KU 41-08 50133207170000 224005 4/11/2024 AK E-LINE GPT/Perf/CIBP MPU F-30A 50029226230100 213188 4/12/2024 READ CaliperSurvey MPU S-13 50029230930000 202114 4/16/2024 READ Caliper Survey NCI A-17 50883201880000 223031 3/22/2024 AK E-LINE Perf Paxton 6 50133207070000 222054 4/14/2024 AK E-LINE GPT/Perf PBU PTM P1-13 50029223720000 193074 4/8/2024 YELLOW JACKET CBL SRU 232-15 50133207140000 223091 3/28/2024 YELLOW JACKET GPT-PLUG-PERF SRU 232-15 50133207140000 223091 4/22/2024 YELLOW JACKET PLUG-PERF SRU 241-33B 50133206960000 221053 4/12/2024 YELLOW JACKET GPT-PERF SRU 241-33B 50133206960000 221053 4/4/2024 YELLOW JACKET GPT-PERF Please include current contact information if different from above. T38745 T38746 T38746 T38746 T38747 T38748 T38748 T38749 T38750 T38751 T38752 T38753 T38754 T38754 T38755 T38755 SRU 241-33B 50133206960000 221053 4/12/2024 YELLOW JACKET GPT-PERF SRU 241-33B 50133206960000 221053 4/4/2024 YELLOW JACKET GPT-PERF Meredith Guhl Digitally signed by Meredith Guhl Date: 2024.05.13 09:32:35 -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: 4/19/2024 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 T38728SRU 241-33B 50133206960000 221053 4/2/2024 AK E-Line CIBP 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: 3/19/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20240319 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BCU 13 50133205250000 203138 12/5/2023 AK E-LINE Plug/Cement/Cutter GP ST 18742 37 (AN 37) 50733203940000 187109 11/12/2023 AK E-LINE PERF IRU 241-01 50283201840000 221076 2/25/2024 AK E-LINE Perf/GPT KU 13-06A 50133207160000 223112 2/9/2024 AK E-LINE GPT MPU CFP-02 50029212580000 184242 3/13/2024 READ CaliperSurvey NCIU A-18 50883201890000 223033 12/13/2023 AK E-LINE GPT/Plug/Perf PBU L-122 50029231470000 203051 3/2/2024 AK E-LINE LowerPatchPacker PBU L4-14 50029219730000 189098 11/22/2023 AK E-LINE PERF SRU 241-33B 50133206960000 221053 3/4/2024 AK E-LINE GPT/Cmnt/CIBP/Perf Please include current contact information if different from above. T38648 T38649 T38650 T38651 T38652 T38653 T38654 T38655 T38656SRU 241-33B 50133206960000 221053 3/4/2024 AK E-LINE GPT/Cmnt/CIBP/Perf Meredith Guhl Digitally signed by Meredith Guhl Date: 2024.03.21 11:50:20 -08'00' CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:McLellan, Bryan J (OGC) To:Jacob Flora Subject:RE: SRU 241-33B AOGCC 10-403 324-017 PTD 221-053 - Request to perform Coil Cleanout Date:Thursday, March 14, 2024 2:46:00 PM Attachments:image004.png image005.png Jake, Hilcorp has approval to perform the CT Cleanout as described below. BOP test pressure = 3000 psi. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Jacob Flora <Jake.Flora@hilcorp.com> Sent: Tuesday, March 12, 2024 2:40 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com> Subject: SRU 241-33B AOGCC 10-403 324-017 PTD 221-053 - Request to perform Coil Cleanout Hello Bryan, This well recently died while we were flow testing sands in the Lower Beluga. We put slickline on it and found muddy fill up to 1150’ so quite shallow. We would like to continue our completion efforts in this well and as such need permission to perform a coil cleanout ahead of a plug back. Hilcorp requests permission to perform the following: 1. Provide 24hrs notice of BOP test 2. MIRU coil tubing unit 3. BOP test to 3000 psi 4. Perform fill cleanout to ~ 5740’ 5. Set plug at 5576’ (5’ over the current open perfs) 6. Jet well dry with nitrogen 7. Proceed with perforation program per approved sundry 324-017 Please let me know if you need anything additional in your review. Thanks, Jake 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 thismessage 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'sphone 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 affectits 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. Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 3/15/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20240315 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BCU 13 50133205250000 203138 12/6/2023 AK E-LINE Cement-JetCut BCU 13 50133205250000 203138 2/11/2024 AK E-LINE CIBP-Perf BCU 19RD 50133205790100 219188 2/20/2024 AK E-LINE Perf-CIBP BRU 232-26 50283200770000 184138 11/26/2023 AK E-LINE GPT-PLUG-PERF BRU 244-27 50283201850000 222038 2/27/2024 AK E-LINE GPT-Perf GP ST 18742 37 (AN- 37) 50733203940000 187109 11/22/2023 AK E-LINE Perf KBU 22-06Y 50133206500000 215044 11/3/2023 AK E-LINE GPT-PERF KBU 42-6 50133205460000 204209 2/16/2024 AK E-LINE Patch PBU L-122 50029231470000 203051 12/7/2023 AK E-LINE Patch NCIU A-12B 50883200320200 223053 12/6/2023 AK E-LINE Perf-GPT NCIU A-17 50883201880000 223031 12/10/2023 AK E-LINE Perf-GPT NCIU B-02 50883200900100 197210 3/9/2024 AK E-LINE GPT-Perf SRU 241-33B 50133206960000 221053 3/6/2024 AK E-LINE GPT-Cmnt-CIBP- Perf Please include current contact information if different from above. T38630 T38630 T38631 T38632 T38633 T38634 T38635 T38636 T38637 T38638 T38639 T38640 T38641GPT-Cmnt-CIBP- SRU 241-33B 50133206960000 221053 3/6/2024 AK E-LINE Perf Meredith Guhl Digitally signed by Meredith Guhl Date: 2024.03.18 08:49:06 -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: 2/16/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20240208 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# END 1-27 50029216930000 187009 2/6/2024 YELLOW JACKET PERF KU 13-06A 50133207160000 223112 2/7/2024 YELLOW JACKET GPT MPU G-18 50029231940000 204020 2/8/2024 READ Caliper Survey MPU B-28 50029235660000 216027 1/15/2024 YELLOW JACKET PATCH PBU PAVE 1-1 50029237670000 223094 1/5/2024 YELLOW JACKET CBL SRU 241-33B 50133206960000 221053 2/8/2024 YELLOW JACKET GPT Please include current contact information if different from above. T38513 T38514 T38515 T38516 T38517 T38518 2/21/2024 YELLOW SRU 241-33B 50133206960000 221053 2/8/2024 JACKET GPT Kayla Junke Digitally signed by Kayla Junke Date: 2024.02.21 09:17:43 -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: 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: Current Pools: 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 7,012'N/A Casing Collapse Structural Conductor Surface 4,790psi Intermediate Production 7,500psi Liner Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16. Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng Sterling/Upper Belulga, Beluga & Tyonek Gas Liner Top Packer ; N/A 1,870' MD / 1,770' TVD ; N/A 6,387' 6,927' 6,302' 16" 7-5/8" See Attached Schematic 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Swanson River Unit (SRU) 241-33BCO 716A Same 6,387'4-1/2" ~2,200 psi 7,012' N/A Length January 25, 2024 Tieback 4-1/2" 7,012' Perforation Depth MD (ft): See Attached Schematic 6,890psi 120'120' 2,096' Size 120' 2,096' MD Proposed Pools: 12.6# / L-80 TVD Burst 1,870' 8,430psi 1,974' Swanson River 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 221-053 50-133-20696-00-00 Hilcorp Alaska, LLC PRESENT WELL CONDITION SUMMARY Jake Flora, Operations Engineer AOGCC USE ONLY Tubing Grade: Tubing MD (ft): 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? 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: m n P s 66 t t N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2024.01.12 15:18:53 - 09'00' Noel Nocas (4361) By Grace Christianson at 9:44 am, Jan 16, 2024 324-01 10-404 Perforate BJM 1/26/24 SFD 1/26/2024 DSR-1/26/24($8JLC 1/29/2024 1/29/24 RBDMS JSB 013024 Max. Expected BHP: ~ 2,828 psi (0.45psi/ft to deepest open perfs) Max. Potential Surface Pressure: ~ 2,200 psi (0.1psi/ft to surface) Updated by DMA 01-12-24 PROPOSED Swanson River Unit SRU 241-33B PTD: 221-053 API: 50-133-20696-00-00 PBTD = 6,927’ / TVD = 6,303’ TD = 7,012’ / TVD = 6,387’ RKB to GL = 18’ JEWELRY DETAIL No. Depth ID OD Item 1 1,525’ 3.958” 4.500” Chemical Injection Sub 2 1,866’ 4.875” 6.540” Liner Hanger / LTP Assembly 3 1,870’ 4.790” 6.340” Seal Assy 4 6,306’ CIBP w / 35’ cement OPEN HOLE / CEMENT DETAIL 7-5/8" 139 BBL’s of cement in 9-7/8” hole – Returns to surface 4-1/2” 177 BBL’s of cement in 6-3/4” hole – Est. TOC @ 1,866’ (LTP) (Returns to surface) Sand TOP MD BTM MD TOP TVD BOT TVD Total DATE Comments LB 50-7 ±5,347' ±5,352' ±4,737' ±4,742' ±5 ‘ Proposed LB 50-9 ±5,456' ±5,462' ±4,844' ±4,850' ±6‘ Proposed LB 50-9 ±5,503' ±5,519' ±4,890' ±4,906' ±16’ Proposed LB 50-9 ±5,555' ±5,561' ±4,942' ±4,948' ±6’ Proposed LB 51-1 ±5,581' ±5,587' ±4,968' ±4,974' ±6’ Proposed LB 51-1 ±5,642' ±5,646' ±5,028' ±5,032' ±4’ Proposed LB 51-1 ±5,651' ±5,656' ±5,037' ±5,043' ±4’ Proposed LB 51-2 ±5,674' ±5,679' ±5,060' ±5,065' ±5’ Proposed LB 51-7 ±5,839' ±5,843' ±5,223' ±5,228' ±4’ Proposed LB 52-9 ±5,882' ±5,890' ±5,266' ±5,274' 8’ Proposed TY 53-0 6,008’ 6,013’ 5,392’ 5,396’ 5’ 5/5/2022 2-7/8” TY 54-5 6,106’ 6,116’ 5,489’ 5,499’ 10’ 5/5/2022 2-7/8” TY 56-9 6,356’ 6,374’ 5,737’ 5,754’ 18’ 10/1/2021 2-7/8” / 6 SPF TY 62-5 6,897’ 6,907’ 6,274’ 6,284’ 10’ 9/30/2021 2-7/8” / 6 SPF 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 USS-CDC 6.875” Surf 2,096’ 4-1/2" Prod Lnr 12.6 L-80 DWC/C HT 3.958” 1,866’ 7,012’ 4-1/2" Prod Tieback 12.6 L-80 DWC/C HT 3.958” Surf 1,870’ 3 16” 7-5/8” 9-7/8” hole 4-1/2” 6-3/4” hole 2 1 TY 56-9 TY 62-5 TY 54-5 TY 53-0 6,380’ tag on 6/27/23 NOTE: Consistent unknown restriction @ 6,384’. 4 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. 1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: CTCO, N2 Development Exploratory 3. Address: Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number): 8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 7,012 feet N/A feet true vertical 6,387 feet N/A feet Effective Depth measured 6,927 feet 1,866 feet true vertical 6,303 feet 1,766 feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth)Tieback 4-1/2" 12.6# / L-80 1,870' MD 1,770' TVD Packers and SSSV (type, measured and true vertical depth)Liner Top Pkr; N/A 1,870' MD 1,770' TVD N/A; N/A 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: N/A 13a. Prior to well operation: Subsequent to operation: 13b. Pools active after work: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Authorized Name and Digital Signature with Date: Contact Name: Contact Email: Authorized Title: Contact Phone: Chad Helgeson, Operations Engineer 323-351 Sr Pet Eng: Sr Pet Geo: Sr Res Eng: WINJ WAG 0 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Noel Nocas, Operations Manager 907-564-5278 chelgeson@hilcorp.com 907-777-8405 N/A 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' 18 0773 0 1860 190 measured TVD 4-1/2" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 221-053 50-133-20696-00-00 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: FEDA 0028399 Swanson River - Sterling/Upper Beluga, Beluga & Tyonek Gas Swanson River Unit (SRU) 241-33B Plugs Junk measured Length Production Liner 7,012' Casing Structural 6,387'7,012' 120'Conductor Surface Intermediate 16" 7-5/8" 120' 2,096' 7,500psi 6,890psi 8,430psi 2,096' 1,974' Burst Collapse 4,790psi p k ft t Fra O s 6. A G L PG , Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov By Grace Christianson at 4:18 pm, Jul 07, 2023 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2023.07.07 14:58:51 - 08'00' Noel Nocas (4361) Rig Start Date End Date 6/23/23 6/25/23 06/23/2023- Friday Daily Operations: Hilcorp Alaska, LLC. Well Operations Summary API Number Well Permit NumberWell Name SRU 241-33B 50-133-20696-00-00 221-053 06/25/2023 - Sunday PTW, JSA with crew. Fire equipment. Make up BHA on 1.75" Coil. BHA OD is 2.125" CC, DFCV, MBT, Jet swirl nozzle. Stab on well. PT stack 250/4000 psi. Mix Gel sweeps in coil displacement tanks. RIH. SITP starting was 400 psi. IA 0 psi. Dry tag top of sand at 6007' CTMD. Clean pick up 21K. Fill wellbore void with 41 bbls of produced fluid. 1:1 returns to surface. start FCO from 6007' with fluid Wash down to 6368' and lost all returns. Bottom of the TY 56-9 sands when returns were lost. Cool down N2 pump. Start pumping N2 While coil tripping up hole at 800 scf/min. Increase to 10000 scf/min. Once n2 to surface start pumping gel laced produced water at .8 bbls/min and 1000 scf/min. Clean out 6384' and stacked 15k down hard. Looks like mechanical obstruction vs fill at depth. weight broke through. Continue nitrified FCO to PBTD or CTMD of 6941'. Shut down fluid pump and start lifting well. with only N2. Signs of LEL and CO2. POOH to surface. Tagged. up. Rig back for the night. More N2 ordered. Sand never cleaned up while performing FCO. Continued to produced sand from formation. Attempt to flow well overnight. PTW, JSA with crew. Pick injector head. Stab 10' lubricator. Make up BHA. 1.75x 2.125" CC, DFCV, STINGER/MBT, Jet swirl nozzle. Stab on well. PT Stack 250/4000 psi. Production shoot fluid level. 1544 and 1526'. RIH. Bleed of WHP of 400 psi. Choke open. Returns from CT displacement at surface 1515' CTMD. Back calculate and that puts fluid level at 295'. Continue in Hole for a dry tag at 6386'. 6386' is the same tag depth as previously. Thought to be mechanical obstruction and no fill/sand. Pick up clean. Trip OOH. Online with N2 down 1.75" CT to blow well dry. 1000 scf/min. While pulling up ooh n2 was to surface at 4500'. Turn around and head back down to 6386' while unloading wellbore. Well blowing dry. Shut down N2 pump and let well inflow any potential water. 68 bbls returned from well during blow down. Online at 1000 scf/min. Blow well dry. 3.5 bbls returned after shut down for 2 hours. POOH to surface. Tagged up. Rig down Fox Energy CTU 8 with 1.75" Coil. SITP 300 psi. Turn well over to production. Flowing 600 MCFD @ 550 psi at 10:30 PM. PTW, JSA with crew. MIRU FOX energy CTU 8 with 1.75" Coil. Test BOPE 250/3000 psi. AOGCC witness waived by Jim Regg. Good BOPE test. Spot in N2 pump, Fluid Pump and Nitrogen transport. Make up BHA roll on connector. 06/24/2023 - Saturday Updated by CAH 07-07-23 SCHEMATIC Swanson River Unit SRU 241-33B PTD: 221-053 API: 50-133-20696-00-00 PBTD = 6,927 / TVD = 6,303 TD = 7,012 / TVD = 6,387 RKB to GL = 18 JEWELRY DETAIL No. Depth ID OD Item 1 1,525 3.958 4.500 Chemical Injection Sub 2 1,866 4.875 6.540 Liner Hanger / LTP Assembly 3 1,870 4.790 6.340 Seal Assy OPEN HOLE / CEMENT DETAIL 7-5/8" 139 BBLs of cement in 9-7/8 hole Returns to surface 4-1/2 177 BBLs of cement in 6-3/4 hole Est. TOC @ 1,866 (LTP) (Returns to surface) PERFORATIONS Sand TOP MD BTM MD Total TOP TVD BOT TVD DATE Comments TY 53-0 6,008 6,013 5 5,392 5,396 5/5/22 2-7/8 TY 54-5 6,106 6,116 10 5,489 5,499 5/5/22 2-7/8 TY 56-9 6,356 6,374 18 5,737 5,754 10/1/21 2-7/8 / 6 SPF TY 62-5 6,897 6,907 10 6,274 6,284 9/30/21 2-7/8 / 6 SPF 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 USS-CDC 6.875 Surf 2,096 4-1/2" Prod Lnr 12.6 L-80 DWC/C HT 3.958 1,866 7,012 4-1/2" Prod Tieback 12.6 L-80 DWC/C HT 3.958 Surf 1,870 3 16 7-5/8 9-7/8 hole 4-1/2 6-3/4 hole 2 1 TY 56-9 TY 62-5 TY 54-5 TY 53-0 6,380 tag on 6/27/23 NOTE: Consistent unknown restriction @ 6,384. 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: CTCO , 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? Will planned perforations require a spacing exception?Yes No 9. Property Designation (Lease Number): 10. Field: Current Pools: 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 7,012'N/A Casing Collapse Structural Conductor Surface 4,790psi Intermediate Production 7,500psi Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng 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: AOGCC USE ONLY Chad Helgeson, Operations Engineer chelgeson@hilcorp.com 907-777-8405 Noel Nocas, Operations Manager 907-564-5278 Tubing Grade:Tubing MD (ft):Perforation Depth TVD (ft):Tubing Size: 12.6# / L-80 1,870' June 12, 2023 Liner Top Packer ; N/A 1,870' MD / 1,770' TVD ; N/A See Schematic See Schematic Tieback 4-1/2" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEDA028399 221-053 50-133-20696-00-00 Swanson River Sterling/Upper Belulga, Beluga & Tyonek Gas Same CO 716A Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Swanson River Unit (SRU) 241-33B Length Size Proposed Pools: TVD Burst PRESENT WELL CONDITION SUMMARY 6,387'6,927'6,302'~2,200 psi N/A MD 6,890psi 120' 1,974' 120' 2,096' Perforation Depth MD (ft): 7,012'4-1/2" 16" 7-5/8" 120' 2,096' 8,430psi6,387'7,012' m n P s 66 t Form 10-403 Revised 10/2022 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 1:00 pm, Jun 20, 2023 323-351 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2023.06.06 16:06:15 - 08'00' Noel Nocas (4361) MDG 6/21/2023 X BJM 6/21/23 DSR-6/21/23 CT BOP test to 3000 psi. GCW 06/22/2023 06/23/23 Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2023.06.23 09:12:56 -08'00' RBDMS JSB 062723 Well: SRU 241-33B Date: 6/2/2023 Well Name: SRU 241-33B API Number: 50-133-20696-00-00 Current Status: Offline Gas Producer Permit to Drill Number: 221-053 Regulatory Contact: Donna Ambruz (907) 777-8305 First Call Engineer: Chad Helgeson (907) 777-8405 (907) 229-4824 (C) Second Call Engineer: Jake Flora (907) 777-8442 (720) 988-5375 (C) Max. Expected BHP: ~ 2,828 psi @ 6,284’ TVD (0.45psi/ft to deepest open perfs) Max. Potential Surface Pressure: ~ 2,200 psi (0.1psi/ft to surface) Brief Well Summary SRU 241-33B was drilled in fall of 2021, and was brought online in the TY 62-5 and TY 56-9 initially at 4000+ mcfd. Since then the rate has fallen to between 500-800mcfd and is making water intermittently. In May of 2022, additional Tyonek sands were perforated and the well held a steady decline until last week, when rate went to zero. Slickline bailing found fill over the perfs. The purpose of this work is to use coil tubing to cleanout the well, unload fluid using Nitrogen, and return well to production. Notes Regarding Wellbore Condition x 6/1/23: SL bailed fill to 6,059’ with a fluid level at 3,655’. Coil Cleanout procedure (Tyonek) 1. Review all approved COAs 2. Provide 24hrs notice to AOGCC of BOP test 3. MIRU Coiled Tubing, PT BOPE to 3000 psi Hi 250 Low 4. RIH with coil tubing nozzle, clean out as deep as possible using N2 and Foam (if necessary) 5. RDMO CTU 6. Return well to operations Attachments: 1. Current Well Schematic 2. Proposed Well Schematic 3. Coil Tubing BOP Diagram 4. Standard Nitrogen Operations Updated by CAH 06-2-23 SCHEMATIC Swanson River Unit SRU 241-33B PTD: 221-053 API: 50-133-20696-00-00 PBTD = 6,927’ / TVD = 6,303’ TD = 7,012’ / TVD = 6,387’ RKB to GL = 18’ JEWELRY DETAIL No. Depth ID OD Item 1 1,525’ 3.958” 4.500” Chemical Injection Sub 2 1,866’ 4.875” 6.540” Liner Hanger / LTP Assembly 3 1,870’ 4.790” 6.340” Seal Assy OPEN HOLE / CEMENT DETAIL 7-5/8" 139 BBL’s of cement in 9-7/8” hole – Returns to surface 4-1/2” 177 BBL’s of cement in 6-3/4” hole – Est. TOC @ 1,866’ (LTP) (Returns to surface) PERFORATIONS Sand TOP MD BTM MD Total TOP TVD BOT TVD DATE Comments TY 53-0 6,008’ 6,013’ 5’ 5,392’ 5,396’ 5/5/22 2-7/8” TY 54-5 6,106’ 6,116’ 10’ 5,489’ 5,499’ 5/5/22 2-7/8” TY 56-9 6,356’ 6,374’ 18’ 5,737’ 5,754’ 10/1/21 2-7/8” / 6 SPF TY 62-5 6,897’ 6,907’ 10’ 6,274’ 6,284’ 9/30/21 2-7/8” / 6 SPF 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 USS-CDC 6.875” Surf 2,096’ 4-1/2" Prod Lnr 12.6 L-80 DWC/C HT 3.958” 1,866’ 7,012’ 4-1/2" Prod Tieback 12.6 L-80 DWC/C HT 3.958” Surf 1,870’ 3 16” 7-5/8” 9-7/8” hole 4-1/2” 6-3/4” hole 2 1 TY 56-9 TY 62-5 TY 54-5 TY 53-0 Sand fill tags @ - 6,059’ on 6/1/23 - 6,212’ on 12/30/22 - 6,345’ on 5/25/22 - 6,919’ on 3/1/22 Fluid Level @ 3,655 on 6/1/23 Updated by CAH 06-2-23 PROPOSED Swanson River Unit SRU 241-33B PTD: 221-053 API: 50-133-20696-00-00 PBTD = 6,927’ / TVD = 6,303’ TD = 7,012’ / TVD = 6,387’ RKB to GL = 18’ JEWELRY DETAIL No. Depth ID OD Item 1 1,525’ 3.958” 4.500” Chemical Injection Sub 2 1,866’ 4.875” 6.540” Liner Hanger / LTP Assembly 3 1,870’ 4.790” 6.340” Seal Assy OPEN HOLE / CEMENT DETAIL 7-5/8" 139 BBL’s of cement in 9-7/8” hole – Returns to surface 4-1/2” 177 BBL’s of cement in 6-3/4” hole – Est. TOC @ 1,866’ (LTP) (Returns to surface) PERFORATIONS Sand TOP MD BTM MD Total TOP TVD BOT TVD DATE Comments TY 53-0 6,008’ 6,013’ 5’ 5,392’ 5,396’ 5/5/22 2-7/8” TY 54-5 6,106’ 6,116’ 10’ 5,489’ 5,499’ 5/5/22 2-7/8” TY 56-9 6,356’ 6,374’ 18’ 5,737’ 5,754’ 10/1/21 2-7/8” / 6 SPF TY 62-5 6,897’ 6,907’ 10’ 6,274’ 6,284’ 9/30/21 2-7/8” / 6 SPF 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 USS-CDC 6.875” Surf 2,096’ 4-1/2" Prod Lnr 12.6 L-80 DWC/C HT 3.958” 1,866’ 7,012’ 4-1/2" Prod Tieback 12.6 L-80 DWC/C HT 3.958” Surf 1,870’ 3 16” 7-5/8” 9-7/8” hole 4-1/2” 6-3/4” hole 2 1 TY 56-9 TY 62-5 TY 54-5 TY 53-0 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. Kaitlyn Barcelona Hilcorp Alaska, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 564-4389 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 564-4422 Received By: Date: Date: 07/11/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL Well API # PTD # Log Date Log Company Log Type Notes BCU 18RD 50133205840100 222033 6/11/2022 Yellowjacket GPT-PERF + Report BCU 18RD 50133205840100 222033 6/18/2022 Yellowjacket GPT-PERF + Report BCU 18RD 50133205840100 222033 6/7/2022 Yellowjacket GPT-PLUG + Report BCU 24 50133206390000 214112 6/16/2022 Halliburton PPROF BCU 24 50133206390000 214112 5/23/2022 Yellowjacket GPT-PERF + Report BCU 24 50133206390000 214112 5/26/2022 Yellowjacket GPT-PERF + Report BCU 7A 50133202840100 214060 6/21/2022 Yellowjacket CBL BCU 7A 50133202840100 214060 6/15/2022 Yellowjacket GAMMA RAY + Report BRU 232-26 50283200770000 184138 5/25/2022 Yellowjacket CBL CLU 01RD 50133203230100 203129 5/19/2022 Yellowjacket PERF + Report CLU 01RD 50133203230100 203129 5/24/2022 Yellowjacket PERF + Report CLU 09 50133205440000 204161 5/27/2022 Yellowjacket PERF + Report CLU-1RD 50133203230100 203129 5/28/2022 Halliburton PPROF + Report END 1-17A 50029221000100 196199 5/26/2022 Halliburton LDL END 1-45 50029219910000 189124 5/23/2022 Halliburton LDL + Report END 3-17F 50029219460600 203216 6/15/2022 AK E-Line PLUG CUT FALLS CREEK 3 50133205240000 203102 6/4/2022 Yellowjacket PERF + Report HVB B-16 50231200400000 212133 6/14/2022 AK E-Line CIBP KALOTSA 1 50133206570000 216132 7/7/2022 Yellowjacket PERF + Report KBU 11-07 50133205560000 205165 6/16/2022 Yellowjacket GPT-PERF + Report KBU 11-07 50133205560000 205165 6/20/2022 Yellowjacket GPT-PERF + Report KBU 33-06X 50133205290000 203183 6/22/2022 Yellowjacket CBL MPU B-28 50029235660000 216027 5/27/2022 Halliburton LDL MPU B-28 50029235660000 216027 5/27/2022 Halliburton MFC + Report MPU B-30 50029235710000 216153 5/18/2022 Halliburton PERF MPU E-06 50029221540000 191048 5/28/2022 Halliburton MFC + Report Kaitlyn Barcelona Hilcorp Alaska, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 564-4389 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 564-4422 Received By: Date: MPU E-35 50029236150000 218152 6/15/2022 Halliburton MFC + Report MPU L-50 50029235550000 215132 6/24/2022 Read COIL FLAG PAXTON 10 50133206910000 220064 5/27/2022 Halliburton PPROF + Report PBU C-24B 50029208160200 212063 5/28/2022 Halliburton PPROF + Report PBU C-24B 50029208160200 212063 5/28/2022 Halliburton RBT PBU GNI-03 50029228200000 197189 6/25/2022 Read CALIPER PBU GNI-03 50029228200000 197189 6/25/2022 Read TEMP-PRESS PBU K-01 50029209980000 183121 6/21/2022 Halliburton PPROF + Report PBU M-13A 50029205220100 201165 5/27/2022 Halliburton TMD3D-WFL + Report PBU NGI-05 50029201960000 176014 6/7/2022 Halliburton CAST PBU W-01A 50029218660100 203176 6/8/2022 Halliburton RBT SRU 241-33 50133206630000 217047 6/13/2022 Yellowjacket PERF SRU 241-33B 50133206960000 221053 5/25/2022 Halliburton TEMP-PRESS SRU 32A-33 50133101640100 191014 6/11/2022 AK E-Line PPROF Please include current contact information if different from above. BCU 18RD PTD:222-033 T36747 BCU 24 PTD:214-112 T36748 BCU 7A PTD:214-060 T36749 BRU 232-26 PTD:184-138 T36750 CLU 01RD PTD:203-129 T36751 CLU 09 PTD: 204-161 T36752 CLU1RD PTD:203-129 T36751 END 1-17A PTD:196-199 T36753 END 1-45 PTD:189-124 T36754 END 3-17F PTD:203-216 T36755 Falls Creek 3 PTD:203-102 T36756 HVB B-16 PTD:212-133 T36757 Kalosta 1 PTD:216-132 T36758 KBU 11-7 PTD:205-165 T36759 KBU 33-06X PTD:203-183 T36760 MPU B-28 PTD:216-027 T36761 MPU B-30 PTD:216-153 T36762 MPU E-06 PTD: 191-048 T36763 MPU E-35 PTD:218-152 T36764 MPU L-50 PTD:215-132 T36765 Paxton 10 PTD:220-064 T36766 PBU C-24B PTD:212-063 T36767 PBU GNI-03 PTD:197-189 T36768 PBU K-01 PTD:183-121 T36769 PBU M-13A PTD:201-165 T36770 PBU NGI-05 PTD:176-014 T36771 PBU W-01A PTD:203-176 T36772 SRU 241-33 PTD:217-047 T36773 SRU 241-33B PTD:221-053 T36774 SRU 32A-33 PTD: 191-014 T36775 Kayla Junke Digitally signed by Kayla Junke Date: 2022.07.12 12:56:51 -08'00' Kaitlyn Barcelona Hilcorp North Slope, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 564-4389 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: DATE: 05/24/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL SRU 241-33B (PTD 221-053) PERF 05/05/2022 Please include current contact information if different from above. 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ϰͲϭͬϮΗWƌŽĚdŝĞďĂĐŬϭϮ͘ϲ>ͲϴϬtͬ,dϯ͘ϵϱϴ͟^ƵƌĨϭ͕ϴϳϬ͛ >h' ϯ ϭϲ͟ ϳͲϱͬϴ͟ ϵͲϳͬϴ͟ ŚŽůĞ ϰͲϭͬϮ͟ ϲͲϯͬϰ͟ ŚŽůĞ Ϯ ϭ dzKE< dzϱϲͲϵ dzϲϮͲϱ DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-133-20696-00-00Well Name/No. SWANSON RIV UNIT 241-33BCompletion Status1-GASCompletion Date10/1/2021Permit to Drill2210530Operator Hilcorp Alaska, LLCMD7012TVD6387Current Status1-GAS10/28/2021UICNoWell Log Information:DigitalMed/FrmtReceivedStart StopOH /CHCommentsLogMediaRunNoElectr DatasetNumberNameIntervalList of Logs Obtained:Mudlog, LWD logsNoNoYesMud Log Samples Directional SurveyREQUIRED INFORMATION(from Master Well Data/Logs)DATA INFORMATIONLog/DataTypeLogScaleDF9/27/202185 7012 Electronic Data Set, Filename: SRU 241-33B LWD FInal.las35683EDDigital DataDF9/27/2021 Electronic File: SRU 241-33B LWD Final MD.cgm35683EDDigital DataDF9/27/2021 Electronic File: SRU 241-33B LWD Final TVD.cgm35683EDDigital DataDF9/27/2021 Electronic File: SRU 241-33B surveys.xlsx35683EDDigital DataDF9/27/2021 Electronic File: SRU 241-33B_Definitive Survey Report.pdf35683EDDigital DataDF9/27/2021 Electronic File: SRU 241-33B_DSR.txt35683EDDigital DataDF9/27/2021 Electronic File: SRU 241-33B_GIS.txt35683EDDigital DataDF9/27/2021 Electronic File: SRU 241-33B_Plan.pdf35683EDDigital DataDF9/27/2021 Electronic File: SRU 241-33B_VSec.pdf35683EDDigital DataDF9/27/2021 Electronic File: SRU 241-33B LWD Final MD.emf35683EDDigital DataDF9/27/2021 Electronic File: SRU 241-33B LWD Final TVD.emf35683EDDigital DataDF9/27/2021 Electronic File: SRU 241-33B LWD Final MD.pdf35683EDDigital DataDF9/27/2021 Electronic File: SRU 241-33B LWD Final TVD.pdf35683EDDigital DataDF9/27/2021 Electronic File: SRU 241-33B LWD Final MD.tif35683EDDigital DataDF9/27/2021 Electronic File: SRU 241-33B LWD Final TVD.tif35683EDDigital Data0 0 2210530 SWANSON RIV UNIT 241-33B LOG HEADERS35683LogLog Header ScansDF9/24/202110 7100 Electronic Data Set, Filename: SRU 241-33B.las35684EDDigital DataDF9/24/202110 7100 Electronic Data Set, Filename: SRU 241-33B.las35684EDDigital DataThursday, October 28, 2021AOGCCPage 1 of 5SRU 241-33B LWD FInal.lasSRU 241-33B.lasSupplied by OPSupplied by OP DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-133-20696-00-00Well Name/No. SWANSON RIV UNIT 241-33BCompletion Status1-GASCompletion Date10/1/2021Permit to Drill2210530Operator Hilcorp Alaska, LLCMD7012TVD6387Current Status1-GAS10/28/2021UICNoDF9/24/2021 Electronic File: SRU 241-33B Daily Reports.pdf35684EDDigital DataDF9/24/2021 Electronic File: SRU 241-33B Final Well Report.pdf35684EDDigital DataDF9/24/2021 Electronic File: SRU241-33B Drilling Dynamics Log MD 2in.pdf35684EDDigital DataDF9/24/2021 Electronic File: SRU241-33B Drilling Dynamics Log MD 5in.pdf35684EDDigital DataDF9/24/2021 Electronic File: SRU241-33B Drilling Dynamics Log TVD 2in.pdf35684EDDigital DataDF9/24/2021 Electronic File: SRU241-33B Drilling Dynamics Log TVD 5in.pdf35684EDDigital DataDF9/24/2021 Electronic File: SRU241-33B Formation Log MD 2in.pdf35684EDDigital DataDF9/24/2021 Electronic File: SRU241-33B Formation Log MD 5in.pdf35684EDDigital DataDF9/24/2021 Electronic File: SRU241-33B Formation Log TVD 2in.pdf35684EDDigital DataDF9/24/2021 Electronic File: SRU241-33B Formation Log TVD 5in.pdf35684EDDigital DataDF9/24/2021 Electronic File: SRU241-33B Gas Ratio Log MD 2in.pdf35684EDDigital DataDF9/24/2021 Electronic File: SRU241-33B Gas Ratio Log MD 5in.pdf35684EDDigital DataDF9/24/2021 Electronic File: SRU241-33B Gas Ratio Log TVD 2in.pdf35684EDDigital DataDF9/24/2021 Electronic File: SRU241-33B Gas Ratio Log TVD 5in.pdf35684EDDigital DataDF9/24/2021 Electronic File: SRU241-33B LWD Combo Log MD 2in.pdf35684EDDigital DataDF9/24/2021 Electronic File: SRU241-33B LWD Combo Log MD 5in.pdf35684EDDigital DataDF9/24/2021 Electronic File: SRU241-33B LWD Combo Log TVD 2in.pdf35684EDDigital DataDF9/24/2021 Electronic File: SRU241-33B LWD Combo Log TVD 5in.pdf35684EDDigital DataThursday, October 28, 2021AOGCCPage 2 of 5 DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-133-20696-00-00Well Name/No. SWANSON RIV UNIT 241-33BCompletion Status1-GASCompletion Date10/1/2021Permit to Drill2210530Operator Hilcorp Alaska, LLCMD7012TVD6387Current Status1-GAS10/28/2021UICNoDF9/24/2021 Electronic File: SRU 241-33B Drilling Dynamics MD 2in.tif35684EDDigital DataDF9/24/2021 Electronic File: SRU 241-33B Drilling Dynamics MD 5in.tif35684EDDigital DataDF9/24/2021 Electronic File: SRU 241-33B Drilling Dynamics TVD 2in.tif35684EDDigital DataDF9/24/2021 Electronic File: SRU 241-33B Drilling Dynamics TVD 5in.tif35684EDDigital DataDF9/24/2021 Electronic File: SRU 241-33B Formation MD 2in.tif35684EDDigital DataDF9/24/2021 Electronic File: SRU 241-33B Formation MD 5in.tif35684EDDigital DataDF9/24/2021 Electronic File: SRU 241-33B Formation TVD 2in.tif35684EDDigital DataDF9/24/2021 Electronic File: SRU 241-33B Formation TVD 5in.tif35684EDDigital DataDF9/24/2021 Electronic File: SRU 241-33B Gas Ratio MD 2in.tif35684EDDigital DataDF9/24/2021 Electronic File: SRU 241-33B Gas Ratio MD 5in.tif35684EDDigital DataDF9/24/2021 Electronic File: SRU 241-33B Gas Ratio TVD 2in.tif35684EDDigital DataDF9/24/2021 Electronic File: SRU 241-33B Gas Ratio TVD 5in.tif35684EDDigital DataDF9/24/2021 Electronic File: SRU 241-33B LWD Combo MD 2in.tif35684EDDigital DataDF9/24/2021 Electronic File: SRU 241-33B LWD Combo MD 5in.tif35684EDDigital DataDF9/24/2021 Electronic File: SRU 241-33B LWD Combo TVD 2in.tif35684EDDigital DataDF9/24/2021 Electronic File: SRU 241-33B LWD Combo TVD 5in.tif35684EDDigital DataDF9/24/2021 Electronic File: SRU241-33B.dbf35684EDDigital DataDF9/24/2021 Electronic File: sru241-33b.hdr35684EDDigital DataDF9/24/2021 Electronic File: SRU241-33B.mdx35684EDDigital DataThursday, October 28, 2021AOGCCPage 3 of 5 DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-133-20696-00-00Well Name/No. SWANSON RIV UNIT 241-33BCompletion Status1-GASCompletion Date10/1/2021Permit to Drill2210530Operator Hilcorp Alaska, LLCMD7012TVD6387Current Status1-GAS10/28/2021UICNoWell Cores/Samples Information:ReceivedStart Stop CommentsTotalBoxesSample SetNumberNameIntervalDF9/24/2021 Electronic File: sru241-33br.dbf35684EDDigital DataDF9/24/2021 Electronic File: sru241-33br.mdx35684EDDigital DataDF9/24/2021 Electronic File: SRU241-33B_SCL.DBF35684EDDigital DataDF9/24/2021 Electronic File: SRU241-33B_SCL.MDX35684EDDigital DataDF9/24/2021 Electronic File: SRU241-33B_tvd.dbf35684EDDigital DataDF9/24/2021 Electronic File: SRU241-33B_tvd.mdx35684EDDigital DataDF9/24/2021 Electronic File: SRU 241-33B 2100-2612.zip35684EDDigital DataDF9/24/2021 Electronic File: SRU 241-33B 2613-2731.zip35684EDDigital DataDF9/24/2021 Electronic File: SRU 241-33B 2760-4004.zip35684EDDigital DataDF9/24/2021 Electronic File: SRU 241-33B 4020-4590.zip35684EDDigital DataDF9/24/2021 Electronic File: SRU 241-33B 4770-5130.zip35684EDDigital DataDF9/24/2021 Electronic File: SRU 241-33B 5280-6430.zip35684EDDigital DataDF9/24/2021 Electronic File: SRU 241-33B 6465-6810.zip35684EDDigital DataDF9/24/2021 Electronic File: SRU 241-33B 6822-6990.zip35684EDDigital DataDF9/24/2021 Electronic File: SRU 241-33B Show Reports.pdf35684EDDigital Data0 0 2210530 SWANSON RIV UNIT 241-33B LOG HEADERS35684LogLog Header ScansDF10/25/20216916 6675 Electronic Data Set, Filename: SRU_241-33B_CBL_27-September-2021_(3519).las35875EDDigital DataDF10/25/2021 Electronic File: SRU_241-33B_CBL_27-September-2021_(3519).pdf35875EDDigital Data0 0 2210530 SWANSON RIV UNIT 241-33B LOG HEADERS35875LogLog Header ScansDF10/26/20216911 6682 Electronic Data Set, Filename: SRU_241-33B_Perf_30-September-2021_(3522).las35876EDDigital DataDF10/26/2021 Electronic File: SRU_241-33B_Perf_30-September-2021_(3522).pdf35876EDDigital Data0 0 2210530 SWANSON RIV UNIT 241-33B LOG HEADERS35876LogLog Header ScansThursday, October 28, 2021AOGCCPage 4 of 5 DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-133-20696-00-00Well Name/No. SWANSON RIV UNIT 241-33BCompletion Status1-GASCompletion Date10/1/2021Permit to Drill2210530Operator Hilcorp Alaska, LLCMD7012TVD6387Current Status1-GAS10/28/2021UICNoINFORMATION RECEIVEDCompletion ReportProduction Test InformationGeologic Markers/TopsY Y / NAYComments:Compliance Reviewed By:Date:Mud Logs, Image Files, Digital DataComposite Logs, Image, Data Files Cuttings SamplesY / NAYY / NADirectional / Inclination DataMechanical Integrity Test InformationDaily Operations SummaryYY / NAYCore ChipsCore PhotographsLaboratory AnalysesY / NAY / NAY / NACOMPLIANCE HISTORYDate CommentsDescriptionCompletion Date:10/1/2021Release Date:8/27/202110/19/20212100 701231797CuttingsThursday, October 28, 2021AOGCCPage 5 of 5M. Guhl10/28/2021 Kaitlyn Barcelona Hilcorp North Slope, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: DATE: 10/25/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL SRU 241-33B (PTD 221-053) Perforation Record 09/30/2021 Please include current contact information if different from above. 10/26/2021 Kaitlyn Barcelona Hilcorp North Slope, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: DATE: 10/25/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL SRU 241-33B (PTD 221-053) Radial Cement Bond Log 09/27/2021 Please include current contact information if different from above. 10/26/2021 Hilw4irp Aluwka, Li , Date: 10/ 19/2021 David Douglas Hilcorp Alaska, LLC Sr. GeoTechnician 3800 CenterPoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.douglas@hilcorp.com To: Alaska Oil & Gas Conservation Commission Petroleum Geology Assistant 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMITTAL SRU 241-33B (PTD 221-053) Washed and Dried Well Samples (09/17/2021) B Set (3 Boxes): WELL BOX SAMPLE INTERVAL (FEET / MD) SRU 241-33B BOX 1 OF 3 2100 - 3750' MD SRU 241-33B BOX 2 OF 3 3750' - 5400' MD SRU 241-33B BOX 3 OF 3 5400' — 7012' MD (TD) Please include current contact information if different from above. f _�9'�_ RECEIVED, OCT 19 2021 AOGCC Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 564-4422 Date: I t/ I l 1a. Well Status:Oil SPLUG Other Abandoned Suspended 1b. Well Class: 20AAC 25.105 20AAC 25.110 Development Exploratory GINJ WINJ WDSPL No. of Completions: 1 Service Stratigraphic Test 2. Operator Name: 6. Date Comp., Susp., or 14. Permit to Drill Number / Sundry: Aband.: 3. Address: 7. Date Spudded: 15. API Number: 4a. Location of Well (Governmental Section): 8. Date TD Reached: 16. Well Name and Number: Surface: Top of Productive Interval: 9. Ref Elevations: KB: 17. Field / Pool(s): Swanson River Unit GL: 187.3' BF:187.3' Total Depth: 10. Plug Back Depth MD/TVD: 18. Property Designation: 4b. Location of Well (State Base Plane Coordinates, NAD 27): 11. Total Depth MD/TVD: 19. DNR Approval Number: Surface: x- y- Zone- 4 TPI: x- y- Zone- 4 12. SSSV Depth MD/TVD: 20. Thickness of Permafrost MD/TVD: Total Depth: x- y- Zone- 4 5. Directional or Inclination Survey: Yes (attached) No 13. Water Depth, if Offshore: 21. Re-drill/Lateral Top Window MD/TVD: Submit electronic information per 20 AAC 25.050 (ft MSL) 22. Logs Obtained: 23. BOTTOM 16" X-56 120' 7-5/8" L-80 1,972' 4-1/2" L-80 6,387' 4-1/2" L-80 1,770' 24. Open to production or injection? Yes No 25. 26. Was hydraulic fracturing used during completion? Yes No DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 27. Date First Production: Method of Operation (Flowing, gas lift, etc.): Hours Tested: Production for Gas-MCF: Test Period Casing Press: Calculated Gas-MCF: Oil Gravity - API (corr): Press. 24-Hour Rate1113 September 17, 2021 September 9, 2021 A028399 N/A N/A N/AN/A N/A 7,012' MD / 6,387' TVD Mudlog, LWD logs Sr Res EngSr Pet GeoSr Pet Eng N/A N/A Oil-Bbl: Water-Bbl: 003444 Oil-Bbl: suspension, or abandonment, whichever occurs first. Types of logs to be listed include, but are not limited to: mud log, spontaneous potential, gamma ray, caliper, resistivity, porosity, magnetic resonance, dipmeter, formation tester, temperature, cement evaluation, casing collar locator, jewelry, and perforation record. Acronyms may be used. Attach a separate page if necessary N/A3444 Flowing 6,356' - 6374' MD / 5,737' - 5,754' TVD (2-7/8" / 6 SPF / 10/1/21) 6,897' - 6,907' MD / 6,274' - 6,374' TVD (2-7/8" / 6 SPF / 9/30/21) 0 Water-Bbl: PRODUCTION TEST 10/2/2021 Date of Test: 260 10/8/2021 24 Flow Tubing 0 84# 29.7# 120' 1,866' 7,012' Gas-Oil Ratio:Choke Size: Per 20 AAC 25.283 (i)(2) attach electronic information 12.6# 1,870' 1,766' Surface DEPTH SET (MD) PACKER SET (MD/TVD) Surface CASING WT. PER FT.GRADE 12.6# 346568 346657 TOP SETTING DEPTH MD Surface SETTING DEPTH TVD 2466715 BOTTOM TOP 6-3/4" 95 bbls 29 bbls Surface 9-7/8" HOLE SIZE AMOUNT PULLED 50-133-20696-00-00 SRU 241-33B 344527 2465979 260' FSL, 1125' FEL, Sec 28, T8N, R9W, SM, AK CEMENTING RECORD 2466716 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 10/1/2021 496' FNL, 2122' FWL, Sec 33, T8N, R9W, SM, AK 260' FSL, 1036' FEL, Sec 28, T8N, R9W, SM, AK 221-053 / 321-495 Sterling/Upper Beluga, Beluga & Tyonek GP 205.3' 6,927' MD / 6,302' TVD STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG Hilcorp Alaska, LLC WAG Gas Conductor Surface 2,096' L - 255 sx / T - 170 sx Driven L - 380 sx / T - 95 sx Surface N/A SIZEIf Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number; Date Perfd): ACID, FRACTURE, CEMENT SQUEEZE, ETC. CASING, LINER AND CEMENTING RECORD List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data within 90 days of completion, Tieback AssyTieback TUBING RECORD WINJ SPLUGOther Abandoned Suspended Stratigraphic Test No No (attached) No Form 10-407 Revised 3/2020 Submit within 30 days of Completion, Suspension, or Abandonment By Samantha Carlisle at 2:29 pm, Oct 14, 2021 RBDMS HEW 10/15/2021 Completion Date 10/1/2021 HEW GDLB 10/15/2021 DSR-10/15/21BJM 10/27/21 Conventional Core(s): Yes No Sidewall Cores: 30. MD TVD N/A Top of Productive Interval TY 56-9 6,356' 5,736' 2886' 2667' 4008' 3561' 5832' 5216' 5903' 5287' 5958' 5342' 6347' 5727' 6875' 6251' Tyonek 31. List of Attachments: 32. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Name: Cody Dinger Contact Email:cdinger@hilcorp.com Authorized Contact Phone: 777-8389 General: Item 1a: Item 1b: Item 4b: Item 9: Item 15: Item 19: Item 20: Item 22: Item 23: Item 24: Item 27: Item 28: Item 30: Item 31: Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and other tests as required including, but not limited to: core analysis, paleontological report, production or well test results. Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29. Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity, permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology. The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data within 90 days of completion, suspension, or abandonment, whichever occurs first. Well Class - Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Formation at total depth: LB 52-9 Wellbore Schematic, Drilling and Completion reports, Defintive Directional Survey, Csg and Cmt Reports Signature w/Date: Report the Division of Oil & Gas / Division of Mining Land and Water: Plan of Operations (LO/Region YY-123), Land Use Permit (LAS 12345), and/or Easement (ADL 123456) number. INSTRUCTIONS Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. TPI (Top of Producing Interval). Yes No Well tested? Yes No 28. CORE DATA If yes, list intervals and formations tested, briefly summarizing test results. Attach separate pages to this form, if needed, and submit detailed test information, including reports, per 20 AAC 25.071. NAME Tyonek Upper Beluga LB 51-7 ST A13 This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed. All laboratory analytical reports regarding samples or tests from a well must be submitted to the AOGCC, no matter when the analyses are conducted. Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, core analysis, paleontological report, production or well test results, per 20 AAC 25.070. If Yes, list formations and intervals cored (MD/TVD, From/To), and summarize lithology and presence of oil, gas or water (submit separate pages with this form, if needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071. Authorized Name: Monty Myers Authorized Title: Drilling Manager TY 56-9 TY 62-5 Permafrost - Base 29. GEOLOGIC MARKERS (List all formations and markers encountered): FORMATION TESTS Permafrost - Top No NoSidewall Cores: Yes No Form 10-407 Revised 3/2020 Submit within 30 days of Completion, Suspension, or Abandonment 10.14.2021 Digitally signed by Monty M Myers DN: cn=Monty M Myers, c=US, o=Hilcorp Alaska, LLC, ou=Technical Services - AK Drilling, email=mmyers@hilcorp.com Reason: I am approving this document Date: 2021.10.14 06:37:16 -08'00' Monty M Myers Updated by CJD 10-13-2021 SCHEMATIC Swanson River Unit SRU 241-33B PTD: 221-053 API: 50-133-20696-00-00 PBTD = 6,927’ / TVD = 6,303’ TD = 7,012’ / TVD = 6,387’ RKB to GL = 18’ JEWELRY DETAIL No. Depth ID OD Item 1 1,525’ 3.958” 4.500” Chemical Injection Sub 2 1,866’ 4.875” 6.540” Liner Hanger / LTP Assembly 3 1,870’ 4.790” 6.340” Seal Assy OPEN HOLE / CEMENT DETAIL 7-5/8" 139 BBL’s of cement in 9-7/8” hole – Returns to surface 4-1/2” 177 BBL’s of cement in 6-3/4” hole – Est. TOC @ 1,866’ (LTP) (Returns to surface) PERFORATIONS Sand TOP MD BOT MD Total TOP TVD BOT TVD DATE Gun System TY 56-9 6,356’ 6,374’ 18’ 5,737’ 5,754’ 10/1/21 2-7/8” / 6 SPF TY 62-5 6,897’ 6,907’ 10’ 6,274’ 6,284’ 9/30/21 2-7/8” / 6 SPF 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 USS-CDC 6.875” Surf 2,096’ 4-1/2" Prod Lnr 12.6 L-80 DWC/C HT 3.958” 1,866’ 7,012’ 4-1/2" Prod Tieback 12.6 L-80 DWC/C HT 3.958” Surf 1,870’ 3 16” 7-5/8” 9-7/8” hole 4-1/2” 6-3/4” hole 2 1 Activity Date Ops Summary 9/2/2021 On Whiskey Gulch 1, prep for rig move to Swanson River 241-33B. trucks on location at 07:00, CCI splitting modules. R/D top drive and TD HPU, install shipping pin on iron ruff neck, R/D HPU and controls. R/D lights, spool up cords, ready shacks, bridal up,;R/D TD hyd lines on rig floor, load out centrifuge w/ crane. Scope down de rrick, remove torque tube, lower pit roofs 2 & 3, hang blocks, unspool drilling line, cut 22 wraps at 93'. CCI hauling loads and staging at SRU 34-9 pad located just beyond Swanson River gate.;Crew C/O, PTM. Craned choke house from outriggers, crane BOP into cradle and load out, R/D gen house, load out remaining pit modules, R/D- remove catwalk, Unplug and wrap up misc. electrical and service lines around rig.;Remove brake linkage, lower doghouse, remove front wind wall, prep and L/D derrick, tied up lines in derrick for craning, loaded out water tank/doghouse and hauled to Swanson river staging pad. R/D gen 1&2 skid. CCI rig mover cont. hauling off oversize rig modules to staging pad 34-9 at Swanson.;Picked IR from rig floor and installed onto shipping stand. Laid down V-door wind wall w/ crane. Changed out O- rings on TDS HPU lines in sub base. Removed rig mats from rig foot print were possible and loaded out onto trailers. CCI rig movers timed out on hrs. laid down drivers, suspended hauling;over size loads for the night. Cont. loading out misc. equip on floats and hauling to Tyler pad. Cut and disposed of liner & felt were possible. cleaned up around location. Started transferring fuel from gen skid tank into fuel trailer to lighten skid for hauling.;Crew change, held PTSM. Finished transferring fuel from gen skid tank into fuel trailer. Secured electrical cables and hoses in derrick, Cont. cleaned up around location and working on misc. projects. Held 30 min Pre-Spud meeting on SRU 241-33B with the night rig crew.;Hauled 0 bbls of solids to KGF G&I Cumulative: 0 bbls Hauled 0 bbls of fluid to KGF G&I Cumulative: 0 bbls Hauled 0 bbls of cement G&I Cumulative: 0 bbls Daily Metal: 0 lbs Cumulative: 0 lbs 9/3/2021 Ready derrick and sub for loadout, haul gen combo and pit 1 module to Swanson River, crane on location at 7am. PJSM, RU to crane derrick, trucks on location @ 09:00, crane derrick, draw works carrier, sub base and pony subs onto trailers, secure loads. Stage loaded trailers on whiskey pad.;P/U rig mat boards and old herculite, cleanup around well and pad. Continue to load and haul smaller loads staging on Tyler pad at SR,;Traveled to Swanson river SRU 241-33B w/ rig crew to lay felt, liner, and set rig mats.;Day time DSM and lead field operator did Per inspection of 21-33 pad. Rig crew laid felt, liner, and set rig mats for SRU 241-33B.;Cont. cleaning and loading out misc. equip onto floats at Whiskey Gulch pad and hauling to Tyler pad in Swanson river.;Hauled 0 bbls of solids to KGF G&I Cumulative: 0 bbls Hauled 0 bbls of fluid to KGF G&I Cumulative: 0 bbls Hauled 0 bbls of cement G&I Cumulative: 0 bbls Daily Metal: 0 lbs Cumulative: 0 lbs 9/4/2021 Continue to cleanup Whiskey Gulch pad, load equipment on float trailers, haul to Swanson river and stage on Tyler pad. Work on rig maintenance items, inventory critical spare list, replace rollers and bearings on IR, C/O valve for extend function on TD.;Night crew started at 06:00, sent to CCI yard in Nikiski to help get Rig 147 ready;Continue to load equipment on float trailers, haul to Swanson river and stage Tyler pad. Work on rig maintenance items. C/O SRL on crown section, work on crown beacon light, C/O electric choke motor with Pason spare. Spotted and set pony subs around SRU 241-33B cellar.;Cont. hauling misc. equip. on float trailers through out the night w/ CCI rig support crew. Laid rig crews hands down for the night.;Hauled 0 bbls of solids to KGF G&I Cumulative: 0 bbls Hauled 0 bbls of fluid to KGF G&I Cumulative: 0 bbls Hauled 0 bbls of cement G&I Cumulative: 0 bbls Daily Metal: 0 lbs Cumulative: 0 lbs 9/5/2021 Continue to cleanup Whiskey Gulch pad, load equipment on float trailers, haul to Swanson river and stage on Tyler pad. Work on rig maintenance items, service rig loader continue to troubleshoot IR, built containment for mud products on Tyler pad, Night crew continue to work days helping on rig 147,;Laid down rig crews for the night. CCI rig support filled horizontal water tanks at Swanson river skim pit pad, cleared area at Tyler pad, laid timbers to rack casing. Organized loads and equip on Tyler pad, and performed regular maintenance on there trucks & equip.;Currently we are 90% R/D on Whiskey pad, 80% moved to Swanson River, and 5% R/U on SRU 241-33B Contractor AFE #: AFE $: Hilcorp Rig 169 Job Name:211-00058 SRU 241-33B Drilling Spud Date: Well Name: Field: County/State: SRF SRU 241-33B Swanson River Hilcorp Energy Company Composite Report , Alaska 18 n (LAT/LONG): evation (RKB): API #: 9/6/2021 Continue to work on rig maintenance items, troubleshoot IR hydraulics- spinner operating slow, clean debris in hyd spool, operates correctly, finish organizing loads and equipment on Tyler pad. Replaced love Joy coupling on rig HPU.;Perform Whiskey Gulch #1 post pad inspection and complete handover to production. Night crew continue working days on rig 147;Laid down rig crews for the night. Current status of rig move is still 90% R/D on W hiskey pad, 80% moved to Swanson River, and 5% R/U on SRU 241-33B;Hauled 0 bbls of solids to KGF G&I Cumulative: 0 bbls Hauled 0 bbls of fluid to KGF G&I Cumulative: 0 bbls Hauled 0 bbls of cement G&I Cumulative: 0 bbls Daily Metal: 0 lbs Cumulative: 0 lbs 9/7/2021 R/D camp office trailers and camp generator, CCI trucks on location at 07:00, Move remainder of permitted loads, derrick, DWKS, sub base, and office trailers to Swanson River ( 9 total );Sub base, derrick, and DWKS arrived at SRU 241-33B @ 11:30 hrs. Spotted and R/U CCI cranes, picked and set sub base, DWKS, and derrick. Had BPV installed in well SRU 241-33. Production hands removed flow line;and installed blind flange. This was to clear path for diverter line. Set water tank/dog house w/ winch truck, scoped dog house and extended to rig floor, picked & set IR and clam shell. Raised V-door wind wall w/ crane.;Hauled in and set gen 1&2 skid and pit module #1, set pit walk way/jig. set MP modules 1&2, pit modules 2&3, TDS HPU skid, and boiler house. Raised roofs on pits, installed landings & handrails. Pick and set choke house on;outriggers, hooked up TDS HYD hoses to sub and electrical interconnect to dog house. Raised derrick.;Spotted & set auxiliary fuel tank, gas buster, service shacks, office trailers and catwalk. Lower beaver slide onto rig floor, spooled drill line onto drum, un- bridled, pinned lower section of TQ tube to top section,;Scoped derrick, R/U T-bar, tied back bridle lines, raised gas buster, R/U shock hose from MP's to sub, suction line from pits to MP's, raised degasser out of pit #4, installed cuttings chutes. R/U power to office trailers.;Spotted & set sleeper trailer, crew change shack, and mechanic shop on Tyler pad. Worked on connection interconnect between modules.;Crew change. Cont. R/U on SRU 241-33B. P/U and installed TQ bushing onto TQ tube. R/U rigging to hoist TDS to rig floor. Hoisted TDS to rig floor. Pinned TDS dog bones to blocks, Un-pinned TDS from cradle, pinned TDS to;TQ bushing, R/U HYD lines on TDS, R/U Kelley hose & service loop to TDS. R/U test pump, stand pipe manifold, installed mask cylinder covers, R/U clam shell, started bring on water in rig water tanks. worked on building mud;docks, R/U Geronimo line, spotted & set hurricane vac unit. Currently cont. to R/U on SRU-241-33B and working on rig acceptance check list.;Currently we are 100% R/D on Whiskey pad, 100% moved to Swanson River, and 65% R/U on SRU 241-33B;Hauled 0 bbls of solids to KGF G&I Cumulative: 0 bbls Hauled 0 bbls of fluid to KGF G&I Cumulative: 0 bbls Hauled 0 bbls of cement G&I Cumulative: 0 bbls Daily Metal: 0 lbs Cumulative: 0 lbs 9/8/2021 Continue to R/U on 241-33B, finish R/U TD HPU, function test HPU and TD. R/U rig floor equipment, choke lines, mud gas separator lines, test pump, water pump, boiler and lines, fill rig water tank, handy berm containment, spot comms tower. BLM rep waived witness to diverter test verbally @10:10;R/U secondary wt indicator, hurricane vac, upright water tank sensor, Hook up choke and kill lines in mezzanine, get comms up and running. R/U centrifuge, offload diverter components. Started hauling in spud mud to pits. Work on rig acceptance list. Submit 24 hr notice to AOGCC for diverter test.;PJSM. N/U DSA, spool, diverter tee, knife valve, annular, and flow nipple to well head. Installed flow line from flow nipple. Installed koomey lines to stack, energized koomey. Chained off and centered stack. Began N/U diverter vent line from knife valve.;Finished bring spud mud into pits from G&I (340 bbls of 8.8 ppg spud mud). Changed oil & filters on floor motor and transmission. Inspected shaker bed and changed out wore shaker bed seals.;Crew change, held PTSM. Cont. R/U, working through rig acceptance check list, Cont. N/U diverter vent line. Obtained RKB's, cont. prepping pits/pumps for spud. Installed 4" valves on conductor.;Cont. R/U misc. electrical/Pason cords around the rig. installed 14" wear ring, function tested diverted closure times, 34.5 sec on bag and 2 sec on knife valve. Currently prepping to commission MP's. We are currently 90% R/U on SRU 241-33B;Hauled 0 bbls of solids to KGF G&I Cumulative: 0 bbls Hauled 5 bbls of fluid to KGF G&I Cumulative: 5 bbls Hauled 0 bbls of cement G&I Cumulative: 0 bbls Daily Metal: 0 lbs Cumulative: 0 lbs 9/9/2021 Cont. R/U on 241-33B, commission mud pumps, pump thru bleederspopoff set @ 3300 psi, PT the mud line, function test TD, adjust torque to 15k, replace bladder in SPP sensor, locate 16'' flange for diverter. Peak welder in-route to rig. AOGCC rep Jim Regg waived witness for diverter test @ 08:36 am.;Adjust wrap on Kelly hose for better coverage. Place gas sensors in proper location, load pipe rack w/4 1/2'' DP, strap and tally same. Weld 16" diverter flange. Install rotary mousehole, check tong pull, IR and TD torque, test COM. Work on checklist items.;Crew change, PTM, drift P/U and rack 68 stands 4 1/2'' DP on ODS. Welder finish up welding 16'' diverter flange, install 45 deg turn and last section pipe exiting off SE side of pad. Complete rig acceptance checklist. Rig accepted @ 13:00 hrs.;Quadco on location at 17:30 to calibrate and test rig gas alarms.;Performed diverter function test and koomey draw down, annular closing time 30 sec, knife valve opening time 2 sec.;Staged bit, bit sub, motor, and MWD tools on catwalk.;M/U 9-7/8" surface directional BHA #1 as per Sperry, scribed tools on the way in to hole, plugged in and uploaded info. to MWD tools. Filled conductor w/ spud mud and circ. Checked stack for leaks (ok).;Drilled 9-7/8" surface hole F/122'-T/214'. GPM-450 SPP-920 psi Diff-60 psi RPM-40 TQ-3K WOB-5K ECD-9.9 ppg P/U-25K S/O-25K ROT-25K.;Crew change, Held PTSM, Cont. Drilling 9- 7/8" surface hole F/214'-T/395'. Ground on bolder at 212' (ratty drilling) GPM-460 SPP-1100 psi Diff-100 psi RPM-40 TQ-3.5K WOB-10/15K ECD-9.8 ppg P/U- 34K S/O-33K ROT-34K.;POOH 2 stds. racking back in derrick, had some 5K over pulls, wiped through ratty spot at 223' with no issues. P/U Yellow Jacket Jars, RIH same T/395', no fill seen on bottom.;Cont. Drilling 9-7/8" surface hole F/395' to 525' at report time.. GPM-460 SPP-1150 psi Diff-88 psi RPM-40 TQ-3.5K WOB-10/15K ECD-9.87 ppg Max gas 25 units P/U-34K S/O-33K ROT-34K Distance to well plan: 1.13' 1.12' High .16' Right.;Hauled 0 bbls of solids to KGF G&I Cumulative: 0 bbls Hauled 0 bbls of fluid to KGF G&I Cumulative: 5 bbls Hauled 0 bbls of cement G&I Cumulative: 0 bbls Daily Metal: 0 lbs Cumulative: 0 lbs @p jq AOGCC rep Jim Regg waived witness for diverter test @ 08:36 am. gpg Submit 24 hr notice to AOGCC for diverter test ppy ;Drilled 9-7/8" surface hole y F/122'-T/214'. pp g p p gp gp ;Performed diverter function test and koomey draw down, annular closing time 30 @ sec, 9/10/2021 Cont. Drilling 9-7/8" surface hole F/525' to 1080', GPM-550 SPP-1800 psi, Diff-100 psi, RPM-60 TQ-4.3K, WOB-10-15K, MW 9.2 ppg, vis 180, ECD 9.66, Max gas 30u. PU 49k, SO 46k, ROT 47k. Maintain 3 deg/100' to 1080'.;CBU x2 and cleanup the wellbore pumping 550 gpm, SPP 1700 psi, 60 rpm, flow check the well, static, Crew change, held PTM.;Pull wiper trip on elevators from 1080' to 275' seeing an occasional 10k drag, no other issues.;Service the top drive and blocks, inspect the derrick.;TIH on elevators from 275' to 1019', M/U TD, wash last stand to bottom, no fill, make connection. Pump 20 bbl hi vis sweep. Correct displacement on wiper trip.;Drill 9-7/8" surface hole F/1080' to 1637', GPM-550, SPP-1900 psi, Diff-75 psi, RPM-80 TQ-5K, WOB-13K. MW 9.25 ppg, vis 141, ECD 9.9 ppg, Max gas 23u. PU 57k, SO 53k, ROT 55k. Hold 25 deg tangent.;CBU X2 for wiper trip, survey on bottom, flow checked well-static. GPM-550 SPP- 1835 psi RPM-80 TQ-4.2K.;POOH on elevators F/1637-T/1019' w/ no issues and calculated hole fill, RIH F/1019'-T/1637', washed last std. to bottom, no fill w/ calculated pipe displacement. P/U-60K S/O-51K.;Resumed directional drilling 9-7/8" surface hole F/1637'-T/2010. PU 64K, SO 55K, ROT 60K GPM-550, SPP- 1900 psi Diff-100 psi, RPM-80 TQ-5K, WOB-15K MW 9.3 ppg, vis 89 ECD 9.9 ppg, Max gas 32 units.;Crew change, held PTSM. Cont. directional drilling 9-7/8" surface hole F/2010' to TD called by Geologist at 2103'. PU 64K, SO 55K, ROT 60K GPM-540, SPP-1800 psi Diff-100 psi, RPM-80 TQ-5K, WOB-15K MW 9.3 ppg, vis 85 ECD 9.9 ppg Max gas 43 units.;Circ. till shakers cleaned up. GPM-540 SPP-1800 psi RPM-80. Shot survey, flow checked well-static.;POOH on elevators F/2103'-T/290', seen 7K over pull at 370'. had calculated hole fill during trip.;Serviced rig-leveled sub, greased IR, DWKS, brake linkage, TDS, and checked bolts on drive shaft.;RIH F/290'-T/2103' w/ no drag during trip in the hole. Had calculated pipe displacement for the trip. GPM-540 SPP-1730 psi RPM- 80 P/U-64K S/O-59K ROT-63K.;Broke circ. Pumped BU, shakers unloaded half way through BU w/ a 50% increase in cuttings. Pumped 20 bbl Hi-Vis sweep w/ walnut & condet, sweep came back on time with no increase in cutting. Currently flow checking well and prepping to POOH.;Hauled 166 bbls of solids to KGF G&I Cumulative: 166 bbls Hauled 229 bbls of fluid to KGF G&I Cumulative: 5 bbls Hauled 0 bbls of cement G&I Cumulative: 0 bbls Daily Metal: 0 lbs Cumulative: 0 lbs 9/11/2021 Finish flow checking the well, static, POOH on elevators racking stands 4 1/2'' DP f/ 2103' to 709', rack back HWDP, L/D jars and 2 NMFCs, read MWD tools, L/D remaining BHA #1, 9 7/8'' bit grade = 2-2-WT-A-E-I-PN-TD. Correct displacement TOOH. Finished building 1st batch of new 6% KCL PHPA mud.;Clear and clean the rig floor, pull 14'' ID wear bushing, Drain and jet stack, make hanger dummy run. Submitted 24 hr BOP test notification to AOGCC @ 11:00.;RU 7 5/8'' casing tools, RU handling equipment, power tongs, ready centralizers, FOSV and cross over, RU fill up line. Make room in pits for running casing. Build black water pills, treat mud with desco and citric.;Crew C/O, held PTM, finish R/U casing equipment. Load casing onto pipe rack, PJSM for running surface casing.;Flashlight, Baker Loc , MU 7 5/8'' shoe track having pre installed centralizers with stop rings installed, check float operation, PU, RIH w/ 7 5/8'' USS- CDC, 29.7#, L-80 casing as per tally f/ 124' to 2030', wash jt #52 down to 2070', Tq to 15,500 ft/lbs, fill on the fly topping off every 10 jts.;Utilize DC clamp on 1st 10 jts, Install 1 centralizer on ea. joint to #44 @ 45 total, 2.3 BBL losses running casing.;Verify pipe count-11 joints out. M/U hanger with pup and landing joint as per WHR, MU swedge and TD, drain stack, land out hanger at 2096', PU 3', PU 74K, SO 56K.;Condition mud for cement job, CBU staging pump to 5 bpm, 0 psi, stage cmt head on rig floor, spotted cmt truck, R/U bail extensions, loaded plugs in cmt head, shut down MP. M/U cmt head and hard iron to casing stump. Broke circ. through cmt head, staged pump up to 5 bpm 349 psi. MW 9.3 VS-56.;Held PJSM w/ rig crew, HES cmts, Baroid, CCI, night DSM. HES flushed hard lines to cuttings box, loaded lines w/ 5 bbls of water, checked for leaks, HES pressure tested line at 420 psi Low and 4319 High (ok), HES pumped 39 bbls of 10.5 ppg Tuned spacer at 4 bpm-105 psi, dropped bottom plug and;pumped 107 bbls (255sx) 12 ppg Type I II lead cement at 4 bpm-80 psi, follow by 32 bbls (170sx) 15.8 ppg Type I II tail cement at 4 bpm-134 psi. HES dropped top plug, then displaced w/ 9.3 ppg Spud mud at 5 bpm. Slowed pump to 2 bpm w/ 12 bbls to go. Did bump plug at 90 bbls into displacement;(calculated 92.5 bbls). Held 1364 psi (FCP of 580 psi) for 3 min, bled off and floats held. Bled back .5 bbls to truck. Had 39 bbls of Spacer return to surface and 38 bbls of lead cement to surface. Added LCM to lead cement at 2.4 ppb (Bridge Maker). Mix water temp 45°. Pumped 50% excess on both;lead and tail. lost 0 bbls throughout the job. Did reciprocate during most of the job. CIP at 21:40 hrs. on 9-11-2021.;Bled down cmt lines and R/D cementers. B/O Laid down landing jt. M/U Johnny Wacker, flushed stack. L/D Johnny Wacker, M/U pack off and pack off running tool to landing jt. Set pack off.;Crew change, held PTSM and weekly safety meeting w/ rig crew. RILD's, tested pack off seal T/3000 psi for 10 min (ok). Started 4 bolting diverter vent line. B/O landing & running tool, L/D landing jt. and pack off running tool.;Bled down koomey, disconnected HYD control lines, removed HYD fittings from bag & plug same. Cont. N/D diverter vent line, knife valve, bell nipple, diverter bag/Tee, and DSA. Cleared off catwalk. Worked on cleaning pits 1-3 and loading water into 4-6 to build 2nd batch of 6% KCL PHPA mud.;Cleaned up and prepped cellar area to N/U B section. Currently N/U B section onto well head.;Hauled 120 bbls of solids to KGF G&I Cumulative: 286 bbls Hauled 371 bbls of fluid to KGF G&I Cumulative: 605 bbls Hauled 38 bbls of cement G&I Cumulative: 38 bbls Daily Metal: 0 lbs Cumulative: 0 lbs Cont. Drilling 9-7/8" surface hole F/525' to 1080' Cont.directional drilling 9-7/8"pp surface hole F/2010' to TD called by Geologist at 2103'. p p bled off and floats held. gp wash jt #52 down to 2070' ppg() p p ;pumped 107 bbls (255sx) 12 ppg Type I II lead cement at 4 bpm-80 psi, follow by 32 bbls ppg p p p pp (170sx) 15.8 ppg Type I II tail cement at 4 bpm-134 psi. 38 bbls of lead cement to surface. )ppgyp p p pp p Did bump plug at 90 bbls into displacement;(calculated 92.5 bbls). () g RIH w/ 7 5/8'' USS-gg CDC, 29.7#, L-80 casing as per tally f/ 124' to 2030', 9/12/2021 WHR N/U B-section, test seals to 3000 psi for 10 min, good, continue building 2nd batch 9 ppg 6%KCL polymer mud in pits.;Stage BOP skid, prep tools and equip for NU BOPE, NU spacer spool. at 07:00 CCI crane damaged power lines @ SR Skim pad intersection, secure area, Notify Swanson River lead operator, Hilcorp safety and CCI superintendent. AOGCC Rep J. Regg waived witness for BOP test verbally @ 08:30.;CCI crane arrived on location, inspect same, slip and cut 6' to remove damaged cable, inspect computer monitoring system, good, PJSM, remove BOP from cradle and stage in sub, NU BOPs.;Crew change, PTM, continue to NU BOPE, Install flow box and flowline, air boots, Install choke hose, center up and anchor stack, set test plug and fill stack with water, function test rams.;MU FOSV and dart valve, RU to test BOPE utilizing 4 1/2'' test joint, purge air from system, shell test BOP to 3500 psi, good.;Test BOPE 250 Low 3500 High 5/10 min, Annular 250 Low 2500 High 5/10 min. Had 1 F/P on test #2, upper pipe rams, re-centered stack-Passed. Had Quadco Rep on location to test audio/visual on gas alarms. BLM rep A. Schoessler on location to witness test.;R/D testing equip, drained stack, pulled test plug and installed 9" wear ring, RILD's X2, loaded 4.5" DP on pipe rack and strapped/tallied.;P/U 34 jts. of 4.5" drill pipe and racked back in derrick.;R/U testing equip. flooded lines and purged air. BLM rep A. Schoessler stayed to witness 7-5/8" surface casing test.;Crew change, held PTSM. Attempted to test 7-5/8" surface casing T/3500 psi, test bled down at 23 psi/min. Bled down test and re-purged air from system. observed air from under blind rams and C. M. Attempted to re-test still seeing psi drop at same rate. Re-inspected for leaks, found;gland nut/lock down on B section leaking. Worked gland nut/lock down and retighten same. Retested 7-5/8" surface casing T/3500 psi for 30 min on chart (ok). Pumped in 1.23 bbls and bled back 1.23 bbls. R/D testing equip and prepped rig floor for 6-3/4" BHA #2.;Loaded BHA onto catwalk, P/U 6-3/4" directional BHA #2 as per Sperry. P/U motor, M/U bit and tested float, float was not operational, attempted to remove float w/ no luck, B/O bit and L/D motor. Changed out motor w/ back up, M/U bit, checked float (ok). Currently P/U MWD tools.;Hauled 17 bbls of solids to KGF G&I Cumulative: 303 bbls Hauled 233 bbls of fluid to KGF G&I Cumulative: 838 bbls Hauled 0 bbls of cement G&I Cumulative: 38 bbls Daily Metal: 0 lbs Cumulative: 0 lbs 9/13/2021 Continue to MU 6 3/4'' BHA 2 to TM collar, upload tools, MU remaining BHA, shallow test MWD, PJSM, load source. RIH with 2 stands HWDP to 305', lost 1 slip die out of the bottom of the DP slips.;Check flow box, rig floor, cellar box and cellar for missing die , Notify town, decision made to POOH, RIH with magnet on slick line to recover same, C/O dies in backup slips. TOOH racking back HW and NMFC, PJSM, remove source. L/D bit, motor and directional tools. Drain stack, no die.;Pollard Slick line on location, spot and RU same, RIH with 4 1/2'' magnet and bow string centralizer, thru stack, no die, RIH and tag at 1970', POH, no die, remove bow spring, MU 3 1/2'' magnet, RIH tag at 1985', work to 1991', POH, recovered die, RD slick line.;MU BHA 2 to TM collar, upload tools, MU remaining BHA, shallow test MWD, PJSM, load source. RIH w/ NMFCs and 2 stands 4 1/2'' HWDP to 305' ending NPT.;Continue TIH with the remaining HWDP and jar stand to 739', single in with 4 1/2 '' DP to 1972', had calculated pipe displacement. P/U-64K S/O-50K.;Broke circ. washed down F/1972'-T/1990' started seen cement stringer, P/U and kicked in rotary to 50 RPM's, brought up pump rate to 270 GPM, washed/reamed cmt F/1990' to tag depth of plugs at 2010', drilled up plugs, shoe track, and 20' of new hole T/2123'. GPM-270 SPP-1585 psi RPM-50 TQ-5.2K WOB-9K;CBU, held PJSM on displacement. displaced well over to 9.0 ppg 6% KCL PHPA mud. Circulated an additional two BU to shear/warm mud. Shut down pump, pulled into 7-5/8" casing shoe to perform FIT test.;R/U testing equip, flooded lines & choke manifold, purged out air. Performed FIT to 13.5 ppg EMW (470 psi), R/D testing equip. Blew down choke manifold and greased same.;Resumed directional drilling 6-3/4" production hole F/2123'-T/2222'. GPM-270 SPP-1425 psi Diff-50 psi RPM-40 TQ-4.9K WOB-6K Max gas-6 units ECD-9.6 ppg P/U-66K S/O-50K ROT-57K.;Crew change, held PTSM. Cont. directional drilling 6-3/4" production hole F/2222'-T/2655'. GPM-285 SPP-1425 psi Diff-50 psi RPM-60 TQ-5.5K WOB-3/6K Max gas-31 units ECD-9.53 ppg P/U-74K S/O-55K ROT-64K Distance to well plan: 12.78' 6.93' High 10.73' Right.;Hauled 34 bbls of solids to KGF G&I Cumulative: 337 bbls Hauled 306 bbls of fluid to KGF G&I Cumulative: 1,144 bbls Hauled 0 bbls of cement G&I Cumulative: 38 bbls Daily Metal: 0.5 lbs Cumulative: 0.5 lbs 9/14/2021 Cont. directional drilling 6-3/4" production hole F/2655'-T/3149'. GPM-285 SPP-1475 psi Diff-50 psi RPM-60 TQ-6000K W OB-3-7K Max gas-93 units ECD-9.7 ppg P/U-84K S/O-59K ROT-70K.;CBU twice at 285 gpm-1440 psi, 60 rpm-6100 ft/lbs off bott torque. Obtained survey on bottom, SPR's and flow check = static.;Pulled up hole from 3149' to 3023' and had to MU topdrive, circ at idle while C/O link tilt cylinder on topdrive. Cont pull up hole from 3023' to casing shoe at 2096' with no issues.;RIH from 2096’ to 2989’, filled pipe on last stand and washed to bottom with no fill. Started sweep down DP and resumed drilling ahead once sweep left bit.;Cont drilling 6 3/4" hole from 3149' to 3434', Rot wob 6K, 285 gpm-1446 psi, 80 rpm-6826 ft/lbs on bott torque, 150-190 ft/hr ROP. Sliding wob 5K, 285 gpm-1373 psi, 37 psi diff, 98 ft/hr ROP. MW 8.9/vis 61, ECD's at 9.8 ppg, BGG 28 units, max gas 50 units.;Cont drilling 6 3/4" hole from 3434' to 4203', WOB 6-8k, 285 gpm 1750 psi 80 rpm 7500 tq on bottom 170-190 ft/hr ROP 95 diff psi MW 8.95 ECD 10.46 Distance to plan 10.94' 8.45' low 6.94' Right.;Circulate bottoms up shakers cleaned up, Flow check well static slight seepage.;Make Wiper Trip f/ 4203' to 3211' No hole issues.;Service the rig and top drive, check draw works, seepage loss rate 1 bph.;RIH f/ 3211' t/ 4203' No hole issues, no fill.;Drill Ahead 6 3/4'' hole section f/ 4203' t/ 4341', 285 gpm 1825 psi 80 rpm 8.1k tq on bottom, 100k PUW 66k SOW 80k ROT, MW 9.0 ppg ECD 10.18 ppg, Drop section 2°/100' 65 diff WOB 4-8k.;Hauled 49 bbls of solids to KGF G&I Cumulative: 386 bbls Hauled 188 bbls of fluid to KGF G&I Cumulative: 1,332 bbls Hauled 0 bbls of cement G&I Cumulative: 38 bbls Daily Metal: 0 lbs Cumulative: 0.5 lbs Cont. directional drilling 6-3/4" production hole F/2655'-T/3149' ppp Performed FIT to 13.5 ppg EMW (470 psi), p p Cont. directional drilling 6-3/4" production hole F/2222'-T/2655' AOGCC was not given opportunity to witness FIT, nor was AOGCC given opportunity to review FIT and Kick Tolerance before drilling 6.75" hole section. Both were conditions of approval. bjm BLM rep A. Schoessler on location to witness test. to tag depth of plugs at gy 2010', drilled up plugs, shoe track, and 20' of new hole T/2123'. pp ;Cont drilling 6 3/4" hole from 3149' to 3434', ;Test BOPE 250 Low 3500 High 5/10 min, Annular 250 Low 2500 High 5/10 min. g gp Retested 7-5/8" pp g surface casing T/3500 psi for 30 min on chart (ok). gp @ p AOGCC Rep J. Regg waived witness for BOP test verbally @ 08:30.;C AOGCC was not given an opportunity to witness the casing test, which was a condition of approval. bjm pp pp j BLM rep A. Schoessler stayed to witness 7-5/8" surface casing test. qg ;Cont drilling 6 3/4" hole from 3434' to 4203', pg ;Resumed directional drilling 6-3/4" production hole F/2123'-T/2222' 9/15/2021 Cont directional drilling 6 3/4" hole from 4341’ to 4727'. Rot wob 3 to 5K, 283 gpm-1964 psi, 80 rpm-8200 ft/lbs on bott torque, 140 ft/hr ROP. Sliding wob 5-7K, 283 gpm-1880 psi, 70 psi diff, 20 to 40 ft/hr ROP. MW 9.0/vis 75, ECD’s 10.5 ppg, BGG 5 units, max gas 25 units.;Cont directional drilling 6 3/4" hole from 4727' to 4888'. Sliding wob 3 to 5K, 282 gpm-2191 psi, 130 psi diff, 8 to 17 ft/hr ROP. Rot wob 9-10K, 282 gpm-1898 psi, 70 rpm-8100 ft/lbs on bott torque, 8 to 40 ft/hr ROP, MW 9.0/vis 71, ECD's at 10.1 ppg, BGG 2 units. Added 4 drums NXS lube for sliding.;Cont directional drilling 6 3/4" hole from 4888' to 4891'. NXS lube not helping, have diff psi while sliding but very little ROP. Pumped 20 bbl hi-vis nut plug sweep with condet but rotating ROP down to 6-8 ft/hr. Decision made to POOH for bit/motor change. CBU, flow check. Distance f/ Plan 12.61'.;POOH on elevators from 4891' to 740' Stand back BHA, Unload Sources, Download MWD, Break Smart tools and Lay down beaver slide, Break bit graded 5-8 RO and out of gauge (pictures in O Drive).;Service rig, clean floor.;M/U BHA as per DD/MWD Change motor and bit P/U Smart tools 2 pieces, Upload MWD and shallow test, load Sources RIH t/ 740' trip in the hole on DP t/ 2901'.;Hauled 36 bbls of solids to KGF G&I Cumulative: 422 bbls Hauled 144 bbls of fluid to KGF G&I Cumulative: 1,476 bbls Hauled 0 bbls of cement G&I Cumulative: 38 bbls Daily Downhole losses 5 bbls Cumulative Downhole losses 5 bbls Daily Metal: 0 lbs Cumulative: 0.5 lbs 9/16/2021 Cont TIH on elevators from 2901' to 4854' with no issue. MU topdrive on last stand, filled pipe, washed and reamed to bottom at 4890'.;CBU one time to warm up mud, staging up pump rate as shakers allowed. 161 gpm-834 psi, 60 rpm-7533 ft/lbs off bott torque. Had a max of 11 units gas at bottoms up.;Resumed directionally drilling 6 3/4" hole from 4890' to 5194'. Rot wob 3K, 285 gpm-1973 psi, 80 rpm-7850 ft/lbs on bott torque, 122 ft/hr ROP. Sliding wob 4K, 282 gpm- 1913 psi, 140 psi diff, 120 ft/hr ROP. MW 9.1/vis 71, ECD's at 10.6 ppg, BGG 14 units, max gas 22 units.;Cont drilling from 5194' to 5627'. Sliding wob 3-4K, 283 gpm-1873 psi, 180 psi diff, 145 ft/hr ROP. Rot wob 4-5K, 282 gpm-2099 psi, 123 ft/hr ROP. MW 9.1/vis 70, ECD's at 10.9 ppg, BGG 5 units, max gas 103 units. Received centralizers, strapped all 4 1/2" liner/pups.;Cont drilling from 5627' to 5937' 284 gpm 2127 psi, 80 rpm 9k tq on, WOB -7k, MW 9.15 ppg ECD 11.01 ppg.;Circulate bottoms up 282 gpm 1895 psi Obtain SPR's and Survey.;Make Wiper Trip f/ 5937' t/ 4857' No hole issues.;Service rig and top drive.;RIH f/ 4857' t/ 5937' No hole issues no fill.;Drilling Ahead 6 3/4'' Hole Section f/ 5937' t/ 6336' , 284 gpm 2220 psi, 80 rpm 10.5k tq on bottom, 9.15 ppg MW 11.08 ECD, 5-7k WOB, Bottoms up f/ wiper trip 1665 units of gas, Distance f/ plan 7.07' 6.85' high 1.75' right 120 ROP Avg.;Hauled 32 bbls of solids to KGF G&I Cumulative: 454 bbls Hauled 128 bbls of fluid to KGF G&I Cumulative: 1,604 bbls Hauled 0 bbls of cement G&I Cumulative: 38 bbls Daily Downhole losses 0 bbls Cumulative Downhole losses 5 bbls Daily Metal: 0 lbs Cumulative: 0.5 lbs 9/17/2021 Cont drilling 6 3/4" hole from 6336’ to 6757', rot wob 2-3K, 284 gpm-2144 psi, 65 rpm-11,700 ft/lbs on bott torque, 121 ft/hr ROP. MW 9.2/vis 61, ECD's at 10.9 ppg, BGG 15 units, max gas 222 units. Received lead cement staged on Tyler Pad.;Cont drilling 6 3/4" hole from 6757' to TD at 7012' md/6387' tvd, Rot wob 4K, 285 gpm-2144 psi, 65 rpm-11,700 ft/lbs on bott torque, 60 ft/hr ROP (slowed ROP at 6865' to allow Geo to look at logs. MW 9.2+/vis 60, ECD's at 10.8 ppg, BGG 14 units, max gas 163 units.;Obtained survey on bottom, CBU one time at 288 gpm-1989 psi, 80 rpm-12,297 ft/lbs off bott torque. Obtained SPR's, flow check = static. Distance f/ plan 8.53' 7.83' Low 3.39' Right.;Pull up hole from 7012' to 6031' on elevators with no issue.;Service rig and topdrive.;TIH from 6031' to 7012', MU topdrive on last stand and filled pipe, washed/reamed to bottom with no issues.;Pumped 20 bbl hi-vis nut plug sweep around at 288 gpm-2058 psi, 80 rpm-11,794 ft/lbs off bott torque. Had a max of 393 units gas at bottoms up which tapered down to 23 units over 15 minutes, then down to 10 units and held there.;POOH f/ 7012' t/ 4138' swab and drag seen.;Circulate bottoms up full drilling rate 285 gpm 1785 psi 80 rpm, No increase in cutting on bottoms up no gas.;POOH f/ 4138' t/ 739' No hole issues took correct fill.;Stand back and L/D BHA, Unload Sources, Download MWD, L/D BHA components drain motor and break bit graded 2-4 in gauge.;Clean and clear floor, P/U Clean out BHA components.;Hauled 34 bbls of solids to KGF G&I Cumulative: 488 bbls Hauled 136 bbls of fluid to KGF G&I Cumulative: 1,740 bbls Hauled 0 bbls of cement G&I Cumulative: 38 bbls Daily Downhole losses 0 bbls Cumulative Downhole losses 5 bbls Daily Metal: 0 lbs Cumulative: 0.5 lbs Cont drilling 6 3/4" hole from 6336’ to 6757', gy flow check. gp p y ;Drilling Ahead 6 3/4'' Hole Section f/ 5937' t/ 6336' Cont directional drilling 6 3/4" hole from 4341’ to 4727'. gp p p q ;Cont directional drilling 6 3/4" hole from 4888' to 4891'. ggpp p y drilling 6 3/4" hole from 4890' to 5194' q ;Cont drilling 6 3/4" hole from 6757' to TD at 7012' md/6387' tvd, gp p ;Cont drilling from 5627' to 5937' 9/18/2021 MU Smith 6 3/4" tri-cone jetted w/3 x 16's, bit sub, 6 5/8" IBS, XO, HWDP and jars for a BHA of 597'. TIH to 2072' and filled pipe.;Shut down pump, hung off blocks, cut and slipped 77' of drill line. Checked crown saver.;C/O grabber dies on topdrive, Cont TIH from 2072' to 3682'. Had to work pipe on elevators a couple times at 3540'.;MU topdrive, filled pipe and CBU at 285 gpm-620 psi, 20 rpm. Had a max of 18 units gas at bottoms up and shut down.;Cont TIH on elevators from 3682' to 5544'. Worked pipe on elevators at 3710', 4280', 4410'. At 4780' filled pipe and washed/reamed down to 4800'. 251 gpm-670 psi, 60 rpm- 8 to 12K torque, working through tuffaceous sandstone.;At 5544' MU topdrive, filled pipe and CBU at 255 gpm-757 psi, 30 rpm-7900 ft/lbs torque. Had a max of 476 units gas at bottoms up and shut down.;Cont TIH from 5544' to 6620' and set down hard 3 times in tuffaceous sandstone. MU topdrive, filled pipe.;Washed and Reamed down from 6620' to 6657' at 283 gpm-1090 psi, 60 rpm-10,700 to 13,000 ft/lbs torque working through tuffaceous sandstone. At bottoms up had a max of 1445 units gas, cont circ until gas dropped back to 23 units over 10 minutes. Cont wash/ream to bottom at 7012' with an occasional;short tight spot. All tight spots were in tuffaceous sandstone, no issues going through coal sections. Tagged bottom and PU stayed off bottom 6'.;Pumped 20 bbl hi-vis nut plug sweep around at 283 gpm-1085 psi, 80 rpm-11,367. Had a max of 129 units gas at bottoms up and hole unloaded 100% increase in sand and small coal chips. Sweep came back 11 bbls early with a 25% increase in cuttings. Cont to circ until clean on shakers, set up vac hoses.;Shut down and flow checked = static, broke off topdrive and dropped hollow 2.3" drift with wire.;POOH from 7012' to 5610' racking back 22 stands DP in derrick, then start LD singles of excess DP. CCI vacuuming wiper balls on pipe rack, doping box and pins prior to loading in pipe tubs, stand back 8 stands HWDP, L/D Clean Out BHA.;Service rig and top drive.;R/U Weatherford, bring centralizers and crossovers to floor, Load tubulars on racks.;M/U Shoe track and check floats, floats held, Continue RIH w/ 4.5'' Liner as per Detail @ 2086' R/U to Circulate.;Hauled 18 bbls of solids to KGF G&I Cumulative: 506 bbls Hauled 72 bbls of fluid to KGF G&I Cumulative: 1,812 bbls Hauled 0 bbls of cement G&I Cumulative: 38 bbls Daily Downhole losses 0 bbls Cumulative Downhole losses 5 bbls Daily Metal: 0 lbs Cumulative: 0.5 lbs 9/19/2021 At 2086' CBU at 214 gpm-85 psi then obtained rotating parameters at 10 rpm-2550 ft/lbs, 20 rpm-3000 ft/lbs and 30 rpm-3400 ft/lbs. Blew down topdrive.;Cont PU single in hole with 4 1/2" DWC/C-HT L-80 12.6# liner. Torqued at 6150 ft/lbs. Top filled on the fly, topped off every 10 jnts. TIH with no issue to 5105'.;PU and MU Baker HRD-E ZXP liner top packer and Flex Lock V liner hanger assembly. Up wt 77K, dwn wt 56K. Mixed and poured Pal Mix, S/O and MU XO and 1st stand HWDP, MU topdrive.;CBU at 212 gpm-340 psi. Obtained rotating parameters at 10 rpm-4700 ft/lbs, 20 rpm-5300 ft/lbs, 30 rpm-5600 ft/lbs. Up wt 75K, dwn wt 54K.;Cont TIH slowly, remainder HWDP from derrick, from 5215' to 6076', MU topdrive and filled pipe, cont TIH on 4 1/2" DP from derrick to 6945' with no issues. MU topdrive on last stand, washed down to 7006' at 154 gpm-460 psi, up wt 17K, dwn wt 75K.;CBU at 207 gpm-700 psi. Had a max of 122 units gas at bottoms up. Obtained rotating parameters at 10 rpm-7800 ft/lbs, 20 rpm-8000 ft/lbs, 30 rpm-8400 ft/lbs. Once gas dropped to 10 units shut down pump.;Broke off topdrive, PU and MU Baker cement head, 5' pup on top, 10' pup on bottom, MU topdrive and torqued assembly. With pump at idle S/O and tagged bottom at 7014' liner tally measurement. PU 2' off bottom and shut down pump. Installed low torque valve, swing and HP hose, closed valve and;resumed pumping while rigging up cementers to rig floor. Held PJSM with cementers, truck drivers, Baker Rep and rig crew.;Halliburton pumped 10 bbls water to flush lines to cuttings box, then 5 bbls to fill lines. Shut in at Baker cement head and PT lines at 1478 psi low 4550 psi high. Good tests. Lined up Baker cement head to Halliburton, pumped 29.5 bbls 10.5 ppg Tuned Prime Spacer at 4 bpm-700 psi, followed with 157;.5 bbls (380 sx) 12 ppg Type I/II Lead cement at 4 to bpm, 420 psi, followed with 19 bbls (95 sx) 15.3 ppg Type I/II Tail cement at 3 to 4.5 bpm, 316 to 470 psi. Had 2 pps of Bridge maker LCM in lead, .07 pps in tail. Baker released dart, Halliburton then displaced with 10 bbls water followed with;9.4 ppg 6% KCL mud at 5 bpm-1200 psi ICP. Did not see dart latch wiper plug 22 bbls into displacement. With 10 bbls to go, reduced rate to 2 bpm-1200 psi and stopped rotating string. Bumped wiper plug/landing collar 94 bbls into displacement (calculated at 99.5 bbls). Started overboard of spacer 84;bbls into displacement. FCP 1590 psi. Halliburton increased to and held 2480 psi (890 psi over FCP) for 1 minute. Pressured up to 2700 psi and held 1 minute to set anchor, then bled off. Slacked off on blocks from 83K to 17K, giving us a good indication hanger was set. Pressured up to 3800 psi to;release run tool collet and neutralize pusher tool, held 1 minute and bled off. CIP at 18:30 on 9-19-21. PU 7’ to clear dogs from hanger top, up wt 60K and had good indication we released liner string. S/O and set down on liner top, PU 4’, rotated at 30 rpm, 3614 ft/lbs torque, S/O and set down on;on liner top to 15K to ensure weight transfer to set packer, no indication of shear. Top of liner hanger at 1865.71’, top of landing collar at 6926.99’. No losses during cement job. Closed annular and pumped down kill line to 1200 psi and held 5 minutes to test packer seal. Good test, lined up on;topdrive to circulate. Bled off, opened annular, lined up to pump down drill string. Applied 1000 psi and start PU on drill string until pressure dropped.;Pumped BU at 284 gpm-212 psi. Had 30 bbls spacer and 29 bbls cement/contaminated mud at the shakers. Shut down pump, broke off topdrive, racked back cement head, pup joint and single joint in derrick, installed wiper ball in drill string, MU topdrive and pumped second circulation at 274 gpm-185 psi;Break down Cement Head, POOH f/ 1898' t/ surface break down running tool Dogs sheared on dog sub, flush stack with stack washer and black water.;RIH w/ polish mill as per baker rep t/ 1848' wash down and tag liner top @ 1868' work mill up and down through liner top 40 rpm 200 gpm 75 psi , verify tag, CBU.;POOH w/ polish mill f/ 1868' t/ surface L/D polish mill assembly good indication on tools.;R/U t/ run 2 7/8'' Clean out Clear floor P/U Scraper BHA, R/U Weatherford.;RIH w/ 2 7/8'' Scraper clean out assembly f/ surface t/ 3260'.;Hauled 57 bbls of solids to KGF G&I Cumulative: 563 bbls Hauled 358 bbls of fluid to KGF G&I Cumulative: 2,170 bbls Hauled 29 bbls of cement G&I pp pp With pump at idle S/O and tagged bottom atp 7014' liner tally measurement. ppppgppp Had 30 bbls spacer and 29 bbls cement/contaminated mud at the shakers. S p No losses during cement job. pp ppg Bumped wiper plug/landing collar 94 bbls into displacement g Continue RIH w/ 4.5'' Liner as per Detail @ 2086' ppg p lowed with 157;.5 bbls (380 sx) 12 ppg Type I/II Lead cement at 4 to bpm, 420 psi, p p ppg p p followed with 19 bbls (95 sx) 15.3 ppg Type I/II Tail cement at Activity Date Ops Summary 9/20/2021 Cont PU single in hole with 2 7/8" PH-6 workstring and 4 1/2" scraper assembly from 3260' to 5080', set back Weatherford tongs, C/O handling equipment, MU 7 5/8" scraper and XO's. Cont TIH with 8 stands HWDP and 21 stands DP to 6912'. MU topdrive on last stand, filled pipe, washed down and tagged wiper plugs at 6928' 3 times at 164 gpm-1966 psi.,PU 3' off bottom and CBU at 173 gpm-2153 psi.,Shut down, broke off topdrive, pulled up hole 30 stands to upper scraper at 5105'. Up wt 107K. TIH 29 stands to 6912', MU topdrive on last stand, broke circ, washed down and tagged 6928', PU and parked 3' off bottom. Changed #2 pump over to 4 1/2" liners/swabs during trip.,Filled pipe, circulated at 200 gpm-2624 psi, transfered 40 bbls clean brine into trip tank with vac truck, held PJSM.,Lined up and pumped 20 bbl hi-vis spacer with #1 pump, shut down and lined up on #2 pump for brine, displaced well to 6% KCL inhibited brine at 215 gpm-2592 psi, did not rotate string, removed shaker screens and cleaned under shakers once dirty brine to surface, ran hole fil l pump to flush any mud from pump and lines. Pumped 172 bbls and shut down.,POOH LD 48 jnts 4 1/2" DP then 16 jnts HWDP, LD 7 5/8" scraper and XO's, RU Weatherford tongs and handling equipment, cont POOH LD 167 jnts 2 7/8" PH-6. CCI vac'ing wiper balls on pipe rack, cleaning and doping threads. Received dry hole tree, tubing hanger and pups.,Pull Wear bushing R/U t/ test casing flood stack and lines.,Attempt t/ Test Casing t/ 3500 psi, sensor flat pump up and change out purge system of air, Pressure up on casing t/ 3500 psi hold f/ 30 min on chart pumped 2.02 bbls bled back 2 bbls.,R/U and RIH w/ 4.5'' Tie back assembly, M/U control line and pressure test t/ 4000 psi f/ 10 min bleed off t/ 1000 psi and continue RIH, space out on NoGo, L/D 2 jts M/U space out pups and hanger on landing jt, terminate control line through hanger.,Hauled 31 bbls of solids to KGF G&I Cumulative: 594 bbls Hauled 574 bbls of fluid to KGF G&I Cumulative: 2,744 bbls Hauled 0 bbls of cement G&I Cumulative: 67 bbls Daily Downhole losses 0 bbls Cumulative Downhole losses 5 bbls Daily Metal: 0 lbs Cumulative: 0.5 lbs 9/21/2021 Finish terminate control line through hanger. Finish banding control line to tubing, ran total 42 bands. Pulled bushings and drained BOP stack, vac'd out cellar box. Up wt 34K, dwn wt 33K, S/O and landed hanger at 19.66' with no issue, NO-GO 2.09' off seat. RILD's.,Backed out landing joint, f looded stack and choke line with water, purged air, RU chart recorder/test pump. Closed blinds, RU to test tieback and liner at 3000 psi. Pressured up to 854 psi and test pump failed.,Bled off, pulled test pump apart, found no issues with plungers, possibly some debris involved, re-assembled test pump and test ran with no issue.,Pumped 1.1 bbls to achieve 3116 psi on chart. Held 30 minutes, good test, bled back 1.1 bbls. RU on 7 5/8" x 4 1/2" annulus, pumped .58 bbls to achieve 2625 psi on chart. Held 30 minutes, good test, bled back .58 bbls. RD test equipment. PU "T" bar and installed 2 way check in hanger, released wellhead re p.,Flushed through mud pumps, mud line, topdrive, choke manifold and BOP stack with water, soap (condet) and inhibited water. Blew down all lines and vac'd out BOP stack.,Open ram doors, remove all rams , ND BOPs, NU dry hole tree, Test hanger void to 5000 psi f/ 10 min @ per WHR, test tree to 500 psi low f/ 5 min and 5000 psi hi for 10 min, Pull TWC, secure tree. Finish cleaning pits, Start RD mud pumps and pit modules, get TD ready to L/D.,Finish breaking down stack and prep f/ stack out Moly coat cavities and LPS shafts, clean and grease ring grooves and shrink wrap components f/ storage, R/D top drive and install in cradle, remove from floor, continue R/D modules, pull rotary table cover and pressure wash, clear all equip f/ floor.,clean cellar and cellar box suck out drain water tank and clean out, blow down water lines to rig, Finish prepping pit modules to move lower degasser, lower gas buster and remove vent lines, Prep derrick to scope down, remove T Bar f/ torque tube, Lower pit rooves, scope derrick, L/D Torque tube, fold beaver slide and prep t/ move, unspool drilling line coil on derrick, prep derrick t/ lay over. Release Rig @ 0600 hrs,Hauled 13 bbls of solids to KGF G&I Cumulative: 607 bbls Hauled 242 bbls of fluid to KGF G&I Cumulative: 2,986 bbls Hauled 0 bbls of cement G&I Cumulative: 67 bbls Daily Downhole losses 0 bbls Cumulative Downhole losses 5 bbls Daily Metal: 0 lbs Cumulative: 0.5 lbs 9/28/2021 Arrive on location. PTW with Ops. PJSA,Spot crane and NU BOP's,Test BOPE to 250/4000 per sundry. BOP test witness was waived by AOGCC representative Jim Regg via email on 9/27/21. Service injector and replace coil pack off.,Sim Ops with AK wireline (finishing perforating on neighboring well). SDFN n (LAT/LONG): evation (RKB): API #: Well Name: Field: County/State: SRF SRU 241-33B Swanson River Hilcorp Energy Company Composite Report , Alaska Contractor AFE #: AFE $: Job Name:211-00058 SRU 241-33B Completion Spud Date: p pp RIH w/ 4.5'' Tie back assembly, ,Test BOPE to 250/4000 per sundry. BOP test witness was waived by AOGCC pp representative Jim Regg via email on 9/27/21. p ,Pumped 1.1 bbls to pppp pg achieve 3116 psi on chart. Held 30 minutes, good test, pp RU on 7 5/8" x 4 1/2" annulus, pumped .58 bbls to achieve 2625 psi on chart. Held 30 p minutes, good test, bled back .58 bbls. R p Closed blinds, RU to test tieback and liner at 3000 psi. Liner lap test to 3500 psi. AOGCC was not notified. CBL across 4-1/2" liner was run on 9/27/21. Est TOC at 1952' MD. bjm pp g g p g Pressure up on casing t/ 3500 psi hold f/ 30 min on chart pumped 2.02 bbls bled back 2 bbls. AOGCC was notified on 9/20/21 of upcoming MIT-T and MIT-IA 9/29/2021 Crews arrive on location. Check oils and start equipment. PTW and JSA.,Spot crane, N2 pump and transport,PT on well to 250 psi. Troubleshoot N2 pump stuck valve.,Finish PT on well to 250/4000 psi. Pass,RIH with BHA #1: CTC 1.75", DCV 1.90", JSN 1.9". OAL = 2.7' -RIH @ 50 fpm -N2 pump rate = 1000scf/m Good returns noted at return tank,Tag PBTD @ 6983' ctmd. Increase N2 rate to 1500 scf/min and see increased returns. Approximately 108 bbls noted in return tank.,POOH -Pump 500 scf/min,Increase pump to 2000 scf/min and then to 2500 scf/min Leave 2634 psi on well. Secure well with Swab and Master. Install flange tree cap.,RDMO 9/30/2021 Arrive at facility obtain permit.,MIRU eline, rig up and wait on Otis spool to arrive on location. Begin to bleed down WHP from 2600 psi to 2100 psi. Pressure test lubricator to 250 psi low / 3000 psi high.,RIH with 10' 2-7/8" HSC gun and continue to bleed WHP down from 2100 psi to 1700 psi . Send correlation pass to town, spot gun and perforate TY 62-5 from 6897'-6907'. POOH, all shots fired.,RIH with 18' 2-7/8" HSC gun and send correlation pass to town. Spot gun and attempt to perforate TY 56-9_Upr from 6356'-6374'. Did not see voltage breakover. POOH, gun did not fire.,Stand back eline. Secure location and SDFN 10/1/2021 Crew arrives at facility, obtain permit.,Warm up eline equipment and rig up. WHP has increased from 1650 to 2000 psi overnight. Pressure test lubricator to 250 psi low and 3000 psi high. Bleed WHP down to 1500 psi.,RIH with 18' 2-7/8" HSC gun and send correlation pass to town. Spot gun and perforate TY 56-9_Upr from 6356'-6374'. POOH, all shots fired.,RDMO eline. Attempt to blow N2 cap off well and pressure stabilizes at 1430 psi. Blow down well until LELs are detected and route to production. perforate TY 56-9_Upr ppg from 6356'-6374'. POOH, all shots fired.,R ppg perforate TY 62-5 from 6897'-6907'. 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Yes X No Reciprocated? Yes X No % Returns during job Cement returns to surface?X Yes No Spacer returns?X Yes No Vol to Surf: Cement In Place At: Date: Estimated TOC: Method Used To Determine TOC: Type I II 255 2.4 Type I II 170 1.16 4 23.43 Hanger 13 5/8 USS-CDC 1.63 23.43 21.80 2,012.29 25.84 Pup 7 5/8 29.7 L-80 USS-CDC USS 2.41 25.84 1.28 2,013.57 2,012.29 Casing 7 5/8 29.7 L-80 USS-CDC USS 1,986.45 Float collar 8 5/8 USS_CDC Innovex Installed a total of 45 centralizers on surface casing Casing 7 5/8 29.7 L-80 USS-CDC USS 80.54 2,094.11 2,013.57 www.wellez.net WellEz Information Management LLC ver_04818br 4 Type of Shoe:Innovex Casing Crew:Weatherford 12 107 2,096.152,103.00 2,012.29 CEMENTING REPORT Csg Wt. On Slips:59,000 Spud mud 21:40 9/11/2021 0 15.8 32 Bump press Visual Bump Plug? 90/92.5 1364 95.4 HalliburtonFIRST STAGE10.5Tune spacer 39 9.3 5 100 580 Csg Wt. On Hook:74,000 Type Float Collar:Innovex No. Hrs to Run:4.5 USS-CDC Innovex 2.04 2,096.15 2,094.11 Setting Depths Component Size Wt. Grade THD Make Length Bottom Top Hilcorp Energy Company CASING & CEMENTING REPORT Lease & Well No.SRF SRU 241-33B Date Run 11-Sep-21 CASING RECORD County State Alaska Supv.D. Yessak / J. Richardson 2,012.00 Floats Held Spud Mud Rotate Csg Recip Csg Ft. Min. PPG9.3 Shoe @ 2096 FC @ Top of Liner Casing (Or Liner) Detail Shoe 8 5/8 TD Shoe Depth: PBTD: Jts. 1 1 36 1 28 1 57 X Yes No X Yes No Fluid Description: Liner hanger Info (Make/Model):Liner top Packer?:X Yes No Liner hanger test pressure:X Yes No Centralizer Placement: Preflush (Spacer) Type: Density (ppg) Volume pumped (BBLs) Lead Slurry Type:Sacks: Yield: Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Tail Slurry Type:Sacks: Yield: Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Post Flush (Spacer) Type: Density (ppg) Rate (bpm): Volume: Displacement: Type: Density (ppg) Rate (bpm): Volume (actual / calculated): FCP (psi): Pump used for disp: X Yes No Casing Rotated?X Yes No Reciprocated? Yes X No % Returns during job Cement returns to surface? Yes X No Spacer returns?X Yes No Vol to Surf: Cement In Place At: Date: Estimated TOC: Method Used To Determine TOC: Type I/II 380 2.39 Type I/II 95 1.24 4 4,239.84 4.5'' Liner jts 4 1/2 12.6 L-80 DWC 2,336.09 4,239.84 1,903.67 5,410.76 4,280.77 RA Marker Jt 4 1/2 12.6 L-80 DWC 40.93 4,280.77 40.94 5,451.70 5,410.76 4.5'' Liner Jts 4 1/2 12.6 L-80 DWC 1,129.99 RA Marker Jt 4 1/2 12.6 L-80 DWC 6,926.99 4.5'' Liner Jts 4 1/2 12.6 L-80 DWC 1,475.29 6,926.99 5,451.70 6,968.43 6,928.08 Landing Collar 5 DWC JHobbs 1.09 6,928.08 1.26 6,969.69 6,968.43 4.5'' Liner Jt 4 1/2 12.6 L-80 DWC 40.35 Float Collar 5 DWC Innovex 4.5'' liner Jt 4 1/2 12.6 L-80 DWC 40.94 7,010.63 6,969.69 HRDE ZXP Flex Lock Liner hnager Packer w/ 5.75 P www.wellez.net WellEz Information Management LLC ver_04818br 4.5 Type of Shoe:Innovex Casing Crew:Weatherford 12 157.5 7,012.007,012.00 CEMENTING REPORT Csg Wt. On Slips: 6% KCL/ Polymer 18:30 9/19/2021 1,865 15.3 19 Bump press Cement To Surface Bump Plug? 94/99.5 2480 29 CementFIRST STAGE10.5Tuned Prime 29.5 9.4 5 100 1590 Csg Wt. On Hook: Type Float Collar:Innovex No. Hrs to Run: 1,865.78 4 1/2 12.6 L-80 DWC 1,898.756 5/8 32.97 DWC Innovex 1.37 7,012.00 7,010.63 4.92 1,903.67 1,898.75 Setting Depths Component Size Wt. Grade THD Make Length Bottom Top Hilcorp Energy Company CASING & CEMENTING REPORT Lease & Well No.SRF SRU 241-33B Date Run 19-Sep-21 CASING RECORD County State Alaska Supv.R Pederson / J Riley 6,926.99 Floats Held1500 6% KCL Mud Rotate Csg Recip Csg Ft. Min. PPG9.3 Shoe @ 7012 FC @ Top of Liner 1865.78 Casing (Or Liner) Detail Float Shoe 4.5'' XO Pup jt HRDE ZXP Liner Top Packer 5 From:McLellan, Bryan J (CED) To:Todd Sidoti - (C) Subject:RE: [EXTERNAL] RE: SRU 241-33B (PTD 221-053) CBL Date:Tuesday, September 28, 2021 2:01:00 PM Todd, The CBL log looks good across the perf intervals requested in Sundry 321-495 and the MITIA passed. You have approval to proceed with perforating the intervals as described in the Sundry. Regards Bryan Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, AK 99501 Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Todd Sidoti - (C) <Todd.Sidoti@hilcorp.com> Sent: Tuesday, September 28, 2021 12:16 PM To: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov> Subject: RE: [EXTERNAL] RE: SRU 241-33B (PTD 221-053) CBL Here you go Bryan. Thanks, Todd From: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov> Sent: Tuesday, September 28, 2021 12:04 PM To: Todd Sidoti - (C) <Todd.Sidoti@hilcorp.com> Subject: [EXTERNAL] RE: SRU 241-33B (PTD 221-053) CBL Thanks Todd, Do you have the results of the MITIA? Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, AK 99501 Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Todd Sidoti - (C) <Todd.Sidoti@hilcorp.com> Sent: Tuesday, September 28, 2021 11:23 AM To: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov> Subject: SRU 241-33B (PTD 221-053) CBL Hi Bryan, Please see attached CBL for 241-33B. Good free pipe section Good tool repeatability. CBL and VDL are telling the same story with respect to cement quality. TOC found at base of swell packer (1,870’) Excellent cement quality from tool first reading at 6,900’ to 2,100’. Cement shows signs of contamination from 2,100’ to swell packer. Please let me know if you require any more information. Thanks, Todd Todd Sidoti | Kenai Ops Engineer | Hilcorp Alaska | 907-632-4113 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 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. 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, 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. Submit to: OPERATOR: FIELD / UNIT / PAD: DATE: OPERATOR REP: AOGCC REP: Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD 2210530 Type Inj N Tubing 0 3116 3107 3098 Type Test P Packer TVD BBL Pump 1.1 IA Interval I Test psi 3100 BBL Return 1.1 OA Result P Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD 2210530 Type Inj N Tubing Type Test P Packer TVD 1819 BBL Pump 0.6 IA 0 2625 2612 2600 Interval I Test psi 2600 BBL Return 0.6 OA Result P Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result 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:46 gal pumped; 46 gal returned Notes:19 gal pumped; 20 gal returned 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: Hilcorp Alaska, LLC Swanson River Field / / SRU / 21-33 Doug Yessak 09/21/21 Notes: Notes: Notes: SRU 241-33B SRU 241-33B Form 10-426 (Revised 01/2017)Hilcorp 169 MIT 09-21-21 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 or FAX to 907 564-4422 Received By: Date: Date: 09/24/2021 To: Alaska Oil & Gas Conservation Commission Natural Resources Technician 333 W. 7th Ave. Ste#100 Anchorage, AK 99501 DATA TRANSMITTAL SRU 241-33B (PTD 221-053) MUDLOGS - EOW DRILLING REPORTS (09/09/2021 to 09/19/2021) 1. DAILY DRILLING REPORTS 2. FINAL EOW REPORT 3. DIGITAL DATA 4. LWD LOG PRINTS 5. MUDLOG PRINTS 6. SAMPLE PHOTOS 7. SHOW REPORTS Folder Contents: Please include current contact information if different from above. 37' (6HW Received By: 09/27/2021 By Abby Bell at 3:39 pm, Sep 24, 2021 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 or fax to 907 564-4422. Received By: Date: Date: 9/24/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL SRU 241-33B (PTD 221-053) FINAL LWD FORMATION EVALUATION LOGS (09/09/2021 to 09/17/2021) x DGR, GM, ADR, ALD, CTN (2” & 5” MD/TVD Color Logs) x Final Definitive Directional Survey SFTP Transfer - Data Folders: Please include current contact information if different from above. 37' (6HW Received By: 09/27/2021 By Abby Bell at 3:39 pm, Sep 24, 2021 1 Guhl, Meredith D (CED) From:Davies, Stephen F (CED) Sent:Friday, September 24, 2021 8:04 AM To:AOGCC Records (CED sponsored) Subject:FW: [EXTERNAL] SRU 241-33B (PTD 221-053; Sundry 321-495) - Questions Please file. Thanks. From: Jeff Nelson ‐ (C) <Jeff.Nelson@hilcorp.com> Sent: Thursday, September 23, 2021 4:34 PM To: Davies, Stephen F (CED) <steve.davies@alaska.gov> Cc: Todd Sidoti ‐ (C) <Todd.Sidoti@hilcorp.com>; Meredyth Richards <Meredyth.Richards@hilcorp.com>; McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov>; Cody Terrell <cterrell@hilcorp.com> Subject: FW: [EXTERNAL] SRU 241‐33B (PTD 221‐053; Sundry 321‐495_ ‐ Questions Hi Steve, I am the geologist for Swanson River and for our SRU 241‐33B project. Todd forwarded me your question regarding the perforation sundry for this well. In turn, I have brought in Cody Terrell to help with providing a lease map. The below lease map and description demonstrates that all of the proposed perforations for this well will conform to the well spacing requirements of CO 716, Rule 3. Please reach out to the team with any additional questions, and as Cody mentioned, we are happy to call and discuss. Regards, Jeff Nelson Geologist Kenai Asset Team Hilcorp Alaska (w) 907‐777‐8455 (c) 307‐760‐8065 From: Cody Terrell <cterrell@hilcorp.com> Sent: Thursday, September 23, 2021 4:21 PM To: Jeff Nelson ‐ (C) <Jeff.Nelson@hilcorp.com> Cc: Meredyth Richards <Meredyth.Richards@hilcorp.com>; Todd Sidoti ‐ (C) <Todd.Sidoti@hilcorp.com> Subject: RE: [EXTERNAL] SRU 241‐33B (PTD 221‐053; Sundry 321‐495_ ‐ Questions Jeff, Rule 3 states, in part, “…no well shall be drilled or completed less than 1,500 feet from the exterior boundary of the Affected Area unless the owner and landowner are the same on both sides of the line.” 2 Looking at the well map, the well and some of our perfs are within 1,500’ of the exterior boundary of the Affected Area. However, the ownership on both sides of the line are the same. See the snip below: The teal colored area is lease A-028399 and as you can see it extends on both sides of the Affected Area boundary (pink line). CIRI and BLM both own the subsurface in this leased area, and Hilcorp owns 100% Working Interest. This is in compliance with Rule 3 of CO 716 because the owner and landowner are the same on both sides of the Affected Area boundary line. Please let me know if this answers the question and if Mr. Davies has further questions. I am happy to call him to discuss. Regards, Cody T. Terrell Landman Hilcorp Alaska, LLC Direct: 907-777-8432 3 Cell: 713-870-4532 From: Davies, Stephen F (CED) <steve.davies@alaska.gov> Sent: Thursday, September 23, 2021 3:40 PM To: Todd Sidoti ‐ (C) <Todd.Sidoti@hilcorp.com> Cc: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov> Subject: [EXTERNAL] SRU 241‐33B (PTD 221‐053; Sundry 321‐495_ ‐ Questions Todd, I’m reviewing Hilcorp’s Sundry Application to perforate this well. CO 716, Rule 3 governs well spacing for the Swanson River Field: On my workstation it appears as though some of the proposed perforations may not conform to these requirements. Hilcorp’s estimated date for commencing operations is September 27th. BLM’s online Alaska Case Retrieval Enterprise System (ACRES) has not been available this afternoon. To expedite processing of this Sundry Application, could you please provide a lease map for this area that demonstrates all of Hilcorp’s proposed perforations for this well will conform to the well spacing requirements? Thanks and stay safe, Steve Davies Alaska Oil and Gas Conservation Commission (AOGCC) 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 Steve Davies at 907‐793‐1224 or steve.davies@alaska.gov. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 1. 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 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: W hat Regulation or Conservation Order governs well spacing in this pool? W ill planned perforations require a spacing exception?Yes No 9. Property Designation (Lease Number):10. Field/Pool(s): 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 7,012'N/A Casing Collapse Structural Conductor Surface 4,790psi Intermediate Production 7,500psi Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13.Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15.W ell Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16.Verbal Approval:Date:GAS WAG GSTOR SPLUG Commission Representative: GINJ Op Shutdown Abandoned Taylor Wellman 777-8449 Contact Name: Todd Sidoti Operations Manager Contact Email: Contact Phone: 777-8443 Date: Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by:COMMISSIONER THE COMMISSION Date: Comm.Comm.Sr Pet Eng Sr Pet Geo Sr Res Eng Authorized Title: 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Signature: September 27, 2021 N/A 7,012' Perforation Depth MD (ft): See Attached Schematic 7,012' 6,387'4-1/2" 16" 7-5/8" 120' 2,096'6,890psi 120' 1,974' 120' 2,096' N/A TVD Burst N/A 8,430psi MDLength Size CO 716 & CO 716.001 Hilcorp Alaska, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage Alaska 99503 PRESENT WELL CONDITION SUMMARY STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 A028399 221-053 50-133-20696-00-00 Swanson River Unit (SRU) 241-33B Sterling/Upper Beluga, Beluga and Tyonek Gas Pools COMMISSION USE ONLY Authorized Name: Tubing Grade: Tubing MD (ft): See Attached Schematic todd.sidoti@hilcorp.com 6,387'6,927'6,303'2,208 N/A Liner Top Packer ; N/A 1,870' MD / 1,770' TVD ; N/A Perforation Depth TVD (ft): Tubing Size: Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 8:12 am, Sep 22, 2021 321-495 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143), ou=Users Date: 2021.09.21 15:59:39 -08'00' Taylor Wellman (2143) 10-407 bjm 9/23/21 SFD 9/24/2021 XCT Review CBL log with AOGCC before perforating. DSR-9/22/21 BOP test to 4000 psi. dts 9/27/2021 JLC 9/27/2021 Jeremy Price Digitally signed by Jeremy Price Date: 2021.09.27 10:12:58 -08'00' RBDMS HEW 9/27/2021 From:Monty Myers To:McLellan, Bryan J (CED); Joseph Engel Cc:Frank Roach Subject:RE: [EXTERNAL] SRU 241-33B (PTD 221-053) FIT data Date:Wednesday, September 22, 2021 4:36:32 PM Attachments:SRU 241-33B 13.5 ppg FIT 9-13-21.xls Try this one. Monty M Myers Drilling Manager 907.538.1168 (c) 907.777.8431 (o) From: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov> Sent: Wednesday, September 22, 2021 3:43 PM To: Monty Myers <mmyers@hilcorp.com>; Joseph Engel <jengel@hilcorp.com> Cc: Frank Roach <Frank.Roach@hilcorp.com> Subject: RE: [EXTERNAL] SRU 241-33B (PTD 221-053) FIT data Monty, Even if they are not on the same chart, there was no FIT pressure vs. volume data in the email Joe sent over. Just a chart recorder plot which shows pressure vs. time. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, AK 99501 Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Monty Myers <mmyers@hilcorp.com> Sent: Wednesday, September 22, 2021 1:50 PM To: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov>; Joseph Engel <jengel@hilcorp.com> Cc: Frank Roach <Frank.Roach@hilcorp.com> Subject: RE: [EXTERNAL] SRU 241-33B (PTD 221-053) FIT data Noted Bryan. We typically try and get them on the same chart. For whatever reason this one didn’t make it. We will send a note out to the field guys reminding them of this Monty M Myers Drilling Manager 907.538.1168 (c) 907.777.8431 (o) From: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov> Sent: Wednesday, September 22, 2021 1:31 PM To: Joseph Engel <jengel@hilcorp.com> Cc: Frank Roach <Frank.Roach@hilcorp.com>; Monty Myers <mmyers@hilcorp.com> Subject: RE: [EXTERNAL] SRU 241-33B (PTD 221-053) FIT data Joe, The FIT data (pressure vs. volume pumped) should be plotted on the same chart as the casing test. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, AK 99501 Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Joseph Engel <jengel@hilcorp.com> Sent: Wednesday, September 22, 2021 10:44 AM To: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov> Cc: Frank Roach <Frank.Roach@hilcorp.com>; Monty Myers <mmyers@hilcorp.com> Subject: RE: [EXTERNAL] SRU 241-33B (PTD 221-053) FIT data Bryan – Apologies for that. Attached are the casing & FIT charts and test info. Please let me know if you have any other questions. -Joe Joe Engel | Drilling Engineer | Hilcorp Alaska, LLC 3800 Centerpoint Dr., Ste. 1400 | Anchorage | AK | 99503 Office: 907.777.8395 | Cell: 805.235.6265 From: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov> Sent: Tuesday, September 21, 2021 5:07 PM To: Joseph Engel <jengel@hilcorp.com> Cc: Frank Roach <Frank.Roach@hilcorp.com> Subject: [EXTERNAL] SRU 241-33B (PTD 221-053) FIT data Joe, Frank said you would be watching Rig 169 while he is away, so sending this request to you. I was expecting to see the 7-5/8” casing FIT data before you started drilling the 6.75” hole section. Could you send it over to me? Not sure where you are in the drilling program currently, but there are other conditions of approval on the PTD. Thanks Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, AK 99501 Bryan.mclellan@alaska.gov +1 (907) 250-9193 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 the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward 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. CASING AND FIT TESTS Well Name:SRU 241-33B Date:9/13/2021 D. Yessak Csg Size/Wt/Grade:7.625'' 29.7# L-80 Supervisor:J. Richardson Csg Setting Depth:2096.15 TMD 1974 TVD Mud Weight:9.0 ppg LOT / FIT Press =470 psi LOT / FIT = Hole Depth =2123 md Fluid Pumped=9.2 Gals Volume Back =6.9 Gals Est. Test Pump Output:2.300 Gallons/Per Inch FIT DATA (test pump) CASING TEST DATA (test pump) Enter Gallons Enter Pressure Enter Gallons Enter Pressure Here Here Here Here ->0.0 0 ->0.0 0 ->1.2 52 52 ->2.3 126 ->2.3 98 46 ->4.6 299 ->3.5 172 74 ->6.9 445 ->4.6 243 71 ->9.2 617 ->5.8 298 55 ->11.5 729 ->6.9 346 48 ->13.8 882 ->8.1 414 68 ->16.1 1067 ->9.2 475 61 ->18.4 1216 ->-475 ->20.7 1388 ->0 ->23.0 1545 ->0 ->25.3 1705 ->0 ->27.6 1862 ->0 ->29.9 2035 ->0 ->32.2 2185 ->0 ->34.5 2350 ->0 ->36.8 2528 ->0 ->39.1 2683 ->0 ->41.4 2852 ->0 ->43.7 3016 ->0 ->46.0 3200 ->0 ->48.3 3388 ->0 ->50.6 3564 ->0 ->51.8 3604 ->0 -> ->0 -> ->0 -> ->0 -> ->0 -> ->0 -> ->0 -> ->0 -> ->0 -> ->0 -> ->0 -> ->0 -> ->0 -> ->0 -> ->0 -> ->0 -> ->0 -> ->0 -> ->0 -> ->0 -> ->0 -> ->0 -> ->0 -> ->0 -> ->0 -> ->0 -> ->0 -> ->0 -> ->0 -> ->0 -> ->0 -> ->0 -> ->0 -> ->0 -> ->0 -> ->0 -> ->0 -> ->0 -> ->0 -> ->0 -> ->0 -> Enter Holding Enter Holding Time Here Pressure Here ->0 475 ->0 3604 ->1 400 ->5 3598 ->2 367 ->10 3595 ->3 339 ->15 3592 ->4 300 ->20 3590 ->5 297 ->25 3588 ->6 284 ->30 3586 ->7 279 -> ->8 262 -> ->9 251 -> ->10 229 -> ->11 217 -> ->12 205 -> ->13 200 -> ->14 195 -> ->15 190 -> 1862 2035 2185 2350 2528 2683 2852 3016 3200 3388 3564 1900 2000 2100 2200 2300 2400 2500 2600 2700 2800 2900 3000 3100 3200 3300 3400 3500 3600 3700 3800 Pressure (psi)FIT DATA (test pump) CASING TEST DATA Plug Test DATA (test pump) 0 52 98 172 243 298 346 414 475 0 126 299 445 617 729 882 1067 1216 1388 1545 1705 0 100 200 300 400 500 600 700 800 900 1000 1100 1200 1300 1400 1500 1600 1700 1800 0.0 10.0 20.0 30.0 40.0 50.0 60.0 Gallons (# of) 3604 3598 3595 3592 3590 3588 3586 1900 2000 2100 2200 2300 2400 2500 2600 2700 2800 2900 3000 3100 3200 3300 3400 3500 3600 3700 3800 Pressure (psi)FIT DATA (test pump) CASING TEST DATA (test pump) Plug Test DATA (test pump) 475 400 367 339 300297284279262251229217205200195190 0 100 200 300 400 500 600 700 800 900 1000 1100 1200 1300 1400 1500 1600 1700 1800 0 5 10 15 20 25 30 35 Time (Minutes) Well Prognosis Well: SRU 241-33B Date: 09/20/2021 Well Name: SRU 241-33B API Number: 50-133-20696-00-00 Current Status: Grassroots Gas Well Leg: N/A Estimated Start Date: September 25, 2021 Rig: CTU Reg. Approval Req’d? 10-403 Date Reg. Approval Rec’vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 221-053 First Call Engineer: Todd Sidoti (907) 777-8443 (O) (907) 632-4113 (M) Second Call Engineer: Jake Flora (907) 777-8442 (O) (720) 988-5375 (M) AFE Number: 211-00058 Bottom Hole Pressure: 2,835 psi @ 6272’ TVD (Based on Normal Gradient) Max. Potential Surface Pressure: 2,208 psi (Based upon Max. Expected BHP minus 0.1 PSI/ft. gas gradient to surface Brief Well Summary: 241-33B is a grassroots gas well targeting Tyonek, Beluga and Sterling intervals. The purpose of this Sundry is to complete the well for gas production. Current Well Condition: x 4-1/2” liner ran to 7,012’ MD and cemented, liner top packer at 1,870’. x 4-1/2” tie-back ran from surface to 1,870’. x Well displaced to 6% KCL brine. E-line 1. MIRU E-line and run CBL in 4-1/2” liner from TD to 300’ above liner top packer. a. Submit CBL log to AOGCC. 2. RDMO E-line. Coiled Tubing 1. MIRU coiled tubing, PT BOPE to 250 psi low / 4000 psi high. a) Notify AOGCC 24 hrs in advance of BOP test to allow for option to witness. 2. MIRU N2 pumping unit. a) Review standard nitrogen pumping procedure with all personnel. 3. MU BHA including nozzle. 4. RIH and come online with N2 and jet well dry. a) Estimated volume of displaced 6% KCl is 107 bbls. 5. Once well is dry trap 2500 psi on the liner for perforating. 6. POOH. 7. RDMO coiled tubing. E-Line 1. MIRU E-line and pressure control equipment. PT lubricator to 250 psi low / 3000 psi high. Note that the well is pressurized with nitrogen. a) If necessary, bleed pressure down as requested by the OE. 2. PU RIH W/perf guns. Perforate each interval with 2-7/8” perf guns 6 SPF 60 degree phasing. 3. Proposed Perforated Intervals: Review CBL log with AOGCC before perforating. Well Prognosis Well: SRU 241-33B Date: 09/20/2021 Sand TOP MD BOT MD Total TOP TVD BOT TVD Pool ST A13 2889 2896 7 2670 2675 Sterling/Upper Beluga ST A14 2914 2921 7 2690 2696 Sterling/Upper Beluga ST A15 2983 2993 10 2746 2754 Sterling/Upper Beluga ST B1U 3009 3025 16 2767 2780 Sterling/Upper Beluga ST B2U 3119 3125 6 2853 2858 Sterling/Upper Beluga ST B5 3393 3405 12 3069 3078 Sterling/Upper Beluga ST B9L 3993 4001 8 3549 3556 Sterling/Upper Beluga UB 36-8U 4050 4056 6 3595 3600 Sterling/Upper Beluga UB 36-9AX_Upr 4067 4079 12 3609 3618 Sterling/Upper Beluga UB 36-9AX_Mid 4084 4090 6 3622 3627 Sterling/Upper Beluga UB 37-0 4196 4206 10 3711 3719 Sterling/Upper Beluga LB 50-9 5455 5464 9 4844 4853 Beluga LB 51-0_Upr 5502 5520 18 4890 4907 Beluga LB 51-0_Lwr 5556 5562 6 4943 4949 Beluga LB 51-1_Upr 5580 5588 8 4676 4975 Beluga LB 51-1_Lwr 5639 5656 17 5026 5042 Beluga LB 51-2 5674 5680 6 5060 5066 Beluga LB 51-4 5776 5782 6 5161 5167 Beluga LB 51-7 5879 5900 21 5263 5285 Beluga LB 52-9 5922 5935 13 5306 5319 Beluga TY 54-5 6105 6120 15 5488 5503 Tyonek TY 56-9_Upr 6355 6379 24 5736 5760 Tyonek TY 56-9_Lwr 6386 6432 46 5767 5812 Tyonek TY 57-8 6444 6461 17 5824 5841 Tyonek TY 62-5 6896 6913 17 6272 6289 Tyonek a)Proposed perforations are also shown on the proposed schematic in red font. b) Final Perforation tie-in sheet will be provided in the field for exact perforation intervals. c) Correlate using Open Hole Correlation Log provided by Geologist. Send the correlation pass to the Operations Engineer, Reservoir Engineer (Meredyth Richards), and Geologist (Jeff Nelson) for confirmation. d) Install Crystal gauges (or verify PTs are open to SCADA) before perforating. Record tubing pressures at 5, 10, and 15 minute intervals after firing gun. e) If perforating an interval results in water production: we will rig up GL and depress fluid into the perforations, set a patch or plug with 35’ cement cap. f) No co-mingling will be allowed without regulatory approval. A plug woth 35 ’ cement cap will be placed to isolate the lower pool prior to perforating a new pool. g) The listed Sands are governed by CO 716 and CO 716.001. No co-mingling will be allowed without regulatory approval. A plug woth 35 ’ cement cap will be placed to isolate the lower pool prior to perforating a new pool. Plug +25' cement required between pools. BJM Well Prognosis Well: SRU 241-33B Date: 09/20/2021 Attachments: Current Schematic Proposed Schematic Coil Tubing BOP Schematic Standard Nitrogen Procedure Updated by TCS 09-21-2021 SCHEMATIC Swanson River Unit SRU 241-33B PTD: 221-053 API: 50-133-20696-00-00 PBTD = 6,927’ / TVD = 6,303’ TD = 7,012’ / TVD = 6,387’ RKB to GL = 18’ JEWELRY DETAIL No. Depth ID OD Item 1 ~1,500’ 3.958” 4.703” Chemical Injection Sub 2 1,858’ 4.790” 6.340” Seal Stem 3 1,870’ 4.875” 6.540” Liner Hanger / LTP Assembly OPEN HOLE / CEMENT DETAIL 7-5/8" 139 BBL’s of cement in 9-7/8” hole – Returns to surface (50% excess) 4-1/2” 178 BBL’s of cement in 6-3/4” hole – Est. TOC @ 1,910’ (40% excess) PERFORATIONS Sand TOP MD BOT MD Total TOP TVD BOT TVD DATE Gun System 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 USS-CDC 6.875” Surf 2,096’ 4-1/2" Prod Lnr 12.6 L-80 DWC/C HT 3.958” 1,858’ 7,012’ 4-1/2" Prod Tieback 12.6 L-80 DWC/C HT 3.958” Surf 1,858’ 3 16” 7-5/8” 9-7/8” hole 4-1/2” 6-3/4” hole 2 1 Updated by TCS 09-21-2021 PROPOSED SCHEMATIC Swanson River Unit SRU 241-33B PTD: 221-053 API: 50-133-20696-00-00 PBTD = 6,927’ / TVD = 6,303’ TD = 7,012’ / TVD = 6,387’ RKB to GL = 18’ JEWELRY DETAIL No. Depth ID OD Item 1 ~1,500’ 3.958” 4.703” Chemical Injection Sub 2 1,858’ 4.790” 6.340” Seal Stem 3 1,870’ 4.875” 6.540” Liner Hanger / LTP Assembly OPEN HOLE / CEMENT DETAIL 7-5/8" 139 BBL’s of cement in 9-7/8” hole – Returns to surface (50% excess) 4-1/2” 178 BBL’s of cement in 6-3/4” hole – Est. TOC @ 1,910’ (40% excess) PERFORATIONS Sand TOP MD BOT MD Total TOP TVD BOT TVD DATE Gun System ST A13 2889 2896 7 2670 2675 ST A14 2914 2921 7 2690 2696 ST A15 2983 2993 10 2746 2754 ST B1U 3009 3025 16 2767 2780 ST B2U 3119 3125 6 2853 2858 ST B5 3393 3405 12 3069 3078 ST B9L 3993 4001 8 3549 3556 UB 36-8U 4050 4056 6 3595 3600 UB 36-9AX_Upr 4067 4079 12 3609 3618 UB 36-9AX_Mid 4084 4090 6 3622 3627 UB 37-0 4196 4206 10 3711 3719 LB 50-9 5455 5464 9 4844 4853 LB 51-0_Upr 5502 5520 18 4890 4907 LB 51-0_Lwr 5556 5562 6 4943 4949 LB 51-1_Upr 5580 5588 8 4676 4975 LB 51-1_Lwr 5639 5656 17 5026 5042 LB 51-2 5674 5680 6 5060 5066 LB 51-4 5776 5782 6 5161 5167 LB 51-7 5879 5900 21 5263 5285 LB 52-9 5922 5935 13 5306 5319 TY 54-5 6105 6120 15 5488 5503 TY 56-9_Upr 6355 6379 24 5736 5760 TY 56-9_Lwr 6386 6432 46 5767 5812 TY 57-8 6444 6461 17 5824 5841 TY 62-5 6896 6913 17 6272 6289 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 USS-CDC 6.875” Surf 2,096’ 4-1/2" Prod Lnr 12.6 L-80 DWC/C HT 3.958” 1,858’ 7,012’ 4-1/2" Prod Tieback 12.6 L-80 DWC/C HT 3.958” Surf 1,858’ 3 16” 7-5/8” 9-7/8” hole 4-1/2” 6-3/4” hole 2 1 Coiled Tubing Services Pressure Category 1 BOP Configuration (0-3,500 psi) Client: Hilcorp Date: April 3rd, 2017 Drawn: Chad Barrett Revision: 0 Well Category: CAT I 4-1/16" 10K Combi BOP Top Set: Blind/Shear Second Set: Pipe/Slip Wellhead 4-1/16" 10K Conventional Stripper 4-1/16" 10K x Wellhead Adapter Flange 5K CO62 x 4-1/16" 10K Flange 5K CO62 Lubricator 4-1/16" 10K Flow Cross Manual 2x2 Valve 1: 2" 1502 x 2-1/16" 10K Flange Manual 2x2 Valve 2: 2-1/16" 10K x 2-1/16" 10K Flange Manual 2x2 Valve 3: 2-1/16" 10K x 2-1/16" 10K Flange Manual 2x2 Valve 4: 2" 1502 x 2-1/16" 10K Flange 21 3 4 WH PSI 2" 1502 x 2-1/16 10K Flanged Valve (Manual) 2-1/16 10K x 2-1/16 10K Flanged Valve (Manual) Kill Port Coiled Tubing HR580 Injector Head & Gooseneck Weight = 12,850 lbs Swanson River Field SRU 241-33B 09/21/2021 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. 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, Sterlin/Upper Beluga Gas and Tyonek Gas Pool, SRU 241-33B Hilcorp Alaska, LLC Permit to Drill Number: 21-053 Surface Location: 496’ FNL, 2122’ FWL, Sec 33, T8N, R9W, SM, AK Bottomhole Location: 263’ FSL, 1039’ FEL, Sec 28, T8N, R9W, SM, AK Dear Mr. Myers: Enclosed is the approved application for the permit to drill the above referenced well. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Jeremy M. Price Chair DATED this ___ day of August, 2021. Jeremy Price Digitally signed by Jeremy Price Date: 2021.08.27 15:18:49 -08'00' 1a. Type of Work: 1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp 1c. Specify if well is proposed for: Drill Lateral Stratigraphic Test Development - Oil Service - Winj Single Zone Coalbed Gas Gas Hydrates Redrill Reentry Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal Shale Gas 2. Operator Name: 5. Bond: Blanket Single Well 11.Well Name and Number: Bond No. 3. Address: 6.Proposed Depth: 12. Field/Pool(s): MD: 6,930' TVD: 6,305' 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): 15. Distance to Nearest Well Open Surface: x-344528 y- 2465979 Zone-4 to Same Pool: 1310' to SRU 241-33 Kickoff depth: 250 feet 17.Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 38 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD Cond 16" 84# X-56 Weld 120' Surface Surface 120' 120' 9-7/8" 7-5/8" 29.7# L-80 USS-CDC 2,110' Surface Surface 2,110' 1,986' 6-3/4" 4-1/2" 12.6# L-80 DWC/C-HT 5,020' 1,910' 1,805' 6,930' 6,305' Tieback 4-1/2" 12.6# L-80 DWC/C-HT 1,910' Surface Surface 1,910' 1,805' 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 Swanson River Field Sterling/Upper Beluga Gas Pool Tyonek Gas Pool 10/6/2021 2870' to nearest unit boundary Frank Roach frank.roach@hilcorp.com 777-8413 Tieback Assy. Drilling Manager Monty Myers 21. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Surface Perforation Depth TVD (ft):Perforation Depth MD (ft): Production Liner Intermediate Conductor/Structural Authorized Title: Authorized Signature: Authorized Name: LengthCasing Cement Volume MDSize Plugs (measured): (including stage data) Driven L - 589 ft3 / T - 182 ft3 Effect. Depth MD (ft): Effect. Depth TVD (ft): 1760 Acres 18. Casing Program: Top - Setting Depth - BottomSpecifications 2837 GL / BF Elevation above MSL (ft): Total Depth MD (ft): Total Depth TVD (ft): 022224484 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 L - 894 ft3 / T - 104 ft3 2207 263’ FSL, 1043’ FEL, Sec 28, T8N, R9W, SM, AK 263’ FSL, 1039’ FEL, Sec 28, T8N, R9W, SM, AK N/A 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Hilcorp Alaska, LLC 496’ FNL, 2122’ FWL, Sec 33, T8N, R9W, SM, AK (staked) A028399 SRU 241-33B Cement Quantity, c.f. or sacks Commission Use Only See cover letter for other requirements. 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) 8.6.2021 By Meredith Guhl at 8:48 am, Aug 06, 2021 Digitally signed by Monty M Myers DN: cn=Monty M Myers, c=US, o=Hilcorp Alaska, LLC, ou=Technical Services - AK Drilling, email=mmyers@hilcorp.com Reason: I am approving this document Date: 2021.08.06 08:31:02 -08'00' Monty M Myers Provide 24 hrs notice for AOGCC witness of MITIA and MIT-T X 50-133-20696-00-00221-053 187.3' DSR-8/6/21 X Review 7-5/8" LOT data and kick tolerance with AOGCC before drilling 6.75" hole section. BOP test to 3500 psi, annular to 2500 psi Casing and liner lap test to 50% of burst - provide 24 hrs notice for AOGCC witness of Casing MIT and FIT. . 205.3' DLB BJM 8/27/21 X X X DLB 08/10/2021 X X JLC 8/27/2021 8/27/21 Jeremy Price Digitally signed by Jeremy Price Date: 2021.08.27 15:18:35 -08'00' SRU 241-33B Drilling Program Swanson River Unit Rev 1 July 2, 2021 Contents 1.0 Well Summary ................................................................................................................................. 2 2.0 Management of Change Information ............................................................................................ 3 3.0 Tubular Program: ........................................................................................................................... 4 4.0 Drill Pipe Information: ................................................................................................................... 4 5.0 Internal Reporting Requirements ................................................................................................. 5 6.0 Planned Wellbore Schematic ......................................................................................................... 6 7.0 Drilling / Completion Summary .................................................................................................... 7 8.0 Mandatory Regulatory Compliance / Notifications ..................................................................... 8 9.0 R/U and Preparatory Work ......................................................................................................... 11 10.0 N/U 21-1/4” Diverter ..................................................................................................................... 12 11.0 Drill 9-7/8” Hole Section ............................................................................................................... 14 12.0 Run 7-5/8” Surface Casing ........................................................................................................... 16 13.0 Cement 7-5/8” Surface Casing ..................................................................................................... 19 14.0 BOP N/U and Test ......................................................................................................................... 22 15.0 Drill 6-3/4” Hole Section ............................................................................................................... 23 16.0 Run 4-1/2” Production Liner ....................................................................................................... 26 17.0 Cement 4-1/2” Production Liner ................................................................................................. 29 18.0 4-1/2” Liner Tieback Polish Run and Cleanout Run ................................................................. 33 19.0 4-1/2” Tieback Run ....................................................................................................................... 34 20.0 RDMO ............................................................................................................................................ 34 21.0 BOP Schematic .............................................................................................................................. 35 22.0 Wellhead Schematic ...................................................................................................................... 36 23.0 Days Vs Depth ............................................................................................................................... 37 24.0 Geo-Prog ........................................................................................................................................ 38 25.0 Anticipated Drilling Hazards ....................................................................................................... 40 26.0 Hilcorp Rig 169 Layout ................................................................................................................ 42 27.0 FIT/LOT Procedure...................................................................................................................... 43 28.0 Choke Manifold Schematic .......................................................................................................... 44 29.0 Casing Design Information .......................................................................................................... 45 30.0 6-3/4” Hole Section MASP ........................................................................................................... 46 31.0 Spider Plot (Governmental Sections) .......................................................................................... 48 32.0 Surface Plat (As-Built NAD27) .................................................................................................... 49 Page 2 Version 1 July, 2021 SRU 241-33B Drilling Procedure Rev 1 1.0 Well Summary Well SRU 241-33B Pad & Old Well Designation 21-33 Pad / grass roots well Planned Completion Type 4-1/2” Cemented Production Liner Target Reservoir(s) Sterling/Beluga/Tyonek Gas Sands Planned Well TD, MD / TVD 6,930’ MD / 6,305’ TVD PBTD, MD / TVD 6,850’ MD / 6,226’ TVD Surface Location (Governmental) 496’ FNL, 2122’ FWL, Sec 33, T8N, R9W, SM, AK Surface Location (NAD 27) X=344528.10 Y=2465979.70 Surface Location (NAD 83) X=1484551 Y=2465741 Top of Productive Horizon (Governmental) 263’ FSL, 1043’ FEL, Sec 28, T8N, R9W, SM, AK TPH Location (NAD 27) X=346651.06, Y=2466718.64 TPH Location (NAD 83) X=1486674.06 Y=2466479.96 BHL (Governmental) 263’ FSL, 1039’ FEL, Sec 28, T8N, R9W, SM, AK BHL (NAD 27) X=346654.97, Y=2466718.64 BHL (NAD 83) X=1486677.97 Y=2466479.96 AFE Number AFE Drilling Days 4 MOB, 16 DRLG AFE Completion Days AFE Drilling Amount $3,276,818 AFE Completion Amount Maximum Anticipated Pressure (Surface) 2207 psi Maximum Anticipated Pressure (Downhole/Reservoir) 2837 psi Work String 4-1/2” 16.6# S-135 CDS-40 RKB – GL 205.3’ (187.3 + 18) Ground Elevation 187.3’ BOP Equipment 11” 5M Annular BOP 11” 5M Double Ram 11” 5M Single Ram Page 3 Version 1 July, 2021 SRU 241-33B Drilling Procedure Rev 1 2.0 Management of Change Information Page 4 Version 1 July, 2021 SRU 241-33B Drilling Procedure Rev 1 3.0 Tubular Program: Hole Section OD (in) ID (in) Drift (in) Conn OD (in) Wt (#/ft) Grade Conn Burst (psi) Collapse (psi) Tension (k-lbs) Cond 16” 15.01” 14.822” - 84 X-56 Weld 2980 1410 - 9-7/8” 7-5/8” 6.875” 6.750” 8.500” 29.7 L-80 USS-CDC 6880 4790 683 6-3/4” 4-1/2” 3.958” 3.833” 5.000” 12.6 L-80 DWC/C-HT 8430 7500 288 4.0 Drill Pipe Information: Hole Section OD (in) ID (in) TJ ID (in) TJ OD (in) Wt (#/ft) Grade Conn Burst (psi) Collapse (psi) Tension (k-lbs) All 4-1/2” 3.826 2.6875” 5.25” 16.6 S-135 CDS40 17,693 16,769 468k Cleanout 2-7/8” 2.323 2.265” 3.438” 7.9 P-110 PH-6 16,896 16,082 194k All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery to TSA in Fairbanks). Page 5 Version 1 July, 2021 SRU 241-33B Drilling Procedure Rev 1 5.0 Internal Reporting Requirements 5.1 Fill out daily drilling report and cost report on Wellez. x Report covers operations from 6am to 6am x Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left of the data entry area – this will not save the data entered, and will navigate to another data entry tab. x Ensure time entry adds up to 24 hours total. x Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. 5.2 Afternoon Updates x Submit a short operations update each work day to pmazzolini@hilcorp.com, mmyers@hilcorp.com, Frank.Roach@hilcorp.com, and cdinger@hilcorp.com 5.3 Intranet Home Page Morning Update x Submit a short operations update each morning by 7am on the company intranet homepage. On weekend and holidays, ensure to have this update in before 5am. Each rig will be assigned a username to login with. 5.4 EHS Incident Reporting x Notify EHS field coordinator. 1. This could be one of (3) individuals as they rotate around. Know who your EHS field coordinator is at all times, don’t wait until an emergency to have to call around and figure it out!!!! a. John Coston: O: (907) 777-6726 C: (907) 227-3189 b. Jacob Nordwall: O: (907) 777-8418 C: (907) 748-0753 2. Spills: Keegan Fleming: O:907-777-8477 C:907-350-9439 x Notify Drlg Manager 1. Monty M Myers: O: 907-777-8431 C: 907-538-1168 x Submit Hilcorp Incident report to contacts above within 24 hrs 5.5 Casing Tally x Send final “As-Run” Casing tally to mmyers@hilcorp.com, Frank.Roach@hilcorp.com, and cdinger@hilcorp.com 5.6 Casing and Cmt report x Send casing and cement report for each string of casing to mmyers@hilcorp.com, Frank.Roach@hilcorp.com, and cdinger@hilcorp.com Page 6 Version 1 July, 2021 SRU 241-33B Drilling Procedure Rev 1 6.0 Planned Wellbore Schematic Page 7 Version 1 July, 2021 SRU 241-33B Drilling Procedure Rev 1 7.0 Drilling / Completion Summary SRU 241-33B is a grassroots development well to be drilled off of 23-33 Pad. This well will be targeting the Sterling, Beluga, and upper Tyonek sands for initial gas production. The base plan is deviated wellbore with a kick off point at ~250’ MD. Maximum hole angle will be 38 deg before dropping to 8 deg and TD of the well will be 6,930’ TMD/ 6,305’ TVD. Drilling operations are expected to commence approximately October 6th, 2021. The Hilcorp Rig # 169 will be used to drill the wellbore then run casing and cement. Surface casing will be run to ~2,110’ MD / 1,986’ TVD and cemented to surface to ensure protection of any shallow freshwater resources. Cement returns to surface will confirm TOC at surface. If cmt returns to surface are not observed, a Temp log will be run between 6 – 18 hrs after CIP to determine TOC. Necessary remedial action will then be discussed with AOGCC authorities. All waste & mud generated during drilling and completion operations will be hauled to the Kenai Gas Field G&I facility for disposal / beneficial reuse depending on test results. General sequence of operations: 1. MOB Hilcorp Rig # 169 to well site 2. N/U diverter and test. 3. Drill 9-7/8” hole to 2,110’ MD. Run and cement 7-5/8” surface casing. 4. ND diverter, N/U & test 11” x 5M BOP. 5. Drill 6-3/4” hole section to 6,930’ MD. Perform wiper trips as needed. 6. POOH w/drill pipe. 7. Make cleanout run 8. POOH laying down drill pipe. 9. Run and cmt 4-1/2” production liner. 10. PU clean out assembly and RIH to clean out 4-1/2” to landing collar 11. Displace well to 6% KCL completion fluid. 12. POOH and LD clean out assembly. 13. RIH and land 4-1/2” tieback string in liner top. 14. N/D BOP, N/U temp abandonment cap, RDMO. Reservoir Evaluation Plan: 1. Surface hole: GR + Res 2. Production Hole: Triple Combo Surface casing will be run to ~2,110’ MD / 1,986’ TVD and cemented to surface t Drilling operations are expected to commence approximately October 6th, 2021. Hilcorp Rig # 169 w Page 8 Version 1 July, 2021 SRU 241-33B Drilling Procedure Rev 1 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 241-33B. 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 250/3500 psi & subsequent tests of the BOP equipment will be to 250/3500 psi for 10/10 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, we must test all BOP components utilized for well control prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP test. x All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid program and drilling fluid system”. x All AOGCC regulations within 20 AAC 25.035 “Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements” x Ensure AOGCC and BLM approved drilling permits are posted on the rig floor and in Co Man office. Regulation Variance Requests: x Diverter waiver requested due to the recent drilling of SRU 241-33 on the same pad and SRU 213- 15 and SRU 213B-15 on a nearby pad. No issues were experienced while drilling the surface hole. Surface casing for SRU 241-33 was set at 1,985’ TVD and SRU 213-15 was set at 2250’ TVD. Surface casing is requested to be set at 1,986’ TVD on SRU 241-33B. No shallow hydrocarbon zones will be penetrated. x BLM: Onshore Oil and Gas Order No. 1, Section III. D. 3. C. o 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 Hilcorp requests approval to utilize flexible choke and kill lines in lieu of hard piping. Concur. DLB Waiver request was withdrawn by Hilcorp 8/25/21 - bjm Page 9 Version 1 July, 2021 SRU 241-33B Drilling Procedure Rev 1 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: 250/3500 (Annular 2500 psi) Subsequent Tests: 250/3500 (Annular 2500 psi) x Primary closing unit: Control Technologies accumulator unit, 5 station, 120 gallon (12 x 11 gal bottles). x Primary closing hydraulic pressure is provided by an electrically driven triplex pump. Emergency pressure is provided by bottled nitrogen. Required AOGCC Notifications: x Well control event (BOPs utilized to shut in the well to control influx of formation fluids). x 24 hours notice prior to spud. x 24 hours notice prior to testing BOPs. x 24 hours notice prior to casing running & cement operations. x Any other notifications required in APD. Required BLM Notifications: x 48 hours before spud. Follow up with actual spud date and time within 24 hours. x 48 hours before casing running and cmt operations x 48 hours before BOPE tests x 48 hours before logging, coring, & testing x Any other notifications required in APD Additional requirements may be stipulated on APD and Sundry. Page 10 Version 1 July, 2021 SRU 241-33B Drilling Procedure Rev 1 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 1 July, 2021 SRU 241-33B Drilling Procedure Rev 1 9.0 R/U and Preparatory Work 9.1 16” not yet set on pad. Conductor will be installed and surveyed for as-built upon approval of PTD from BLM. 9.2 Dig out and set impermeable cellar. 9.3 Install slip-on 16-3/4” 3M “A” section. Ensure to orient wellhead so that tree will line up with flowline later. 9.4 Level pad and ensure enough room for layout of rig footprint and R/U. 9.5 Layout Herculite on pad to extend beyond footprint of rig. 9.6 R/U Hilcorp Rig # 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 1 July, 2021 SRU 241-33B Drilling Procedure Rev 1 10.0 N/U 21-1/4” Diverter 10.1 N/U 21-1/4” Diverter x N/U 21-1/4” diverter “T”. x Knife gate, 16” diverter line. x Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C). 10.2 Function test diverter. Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens prior to annular closure. Ensure to notify AOGCC inspector to witness function test of diverter. x NOTE: Ensure closing time on diverter annular is in line with API RP 64: o Annular element ID 20” or smaller: Less than 30 seconds o Annular element ID greater than 20”: Less than 45 seconds 10.3 Ensure to set up a clearly marked “warning zone” is established on each side and ahead of the vent line tip. “Warning Zone” must include: x A prohibition on vehicle parking x A prohibition on ignition sources or running equipment x A prohibition on staged equipment or materials x Restriction of traffic to essential foot or vehicle traffic only. 10.4 Set wear bushing in wellhead. Less than 30 seconds Page 13 Version 1 July, 2021 SRU 241-33B Drilling Procedure Rev 1 10.5 Rig 169 Orientation: Note: Actual layout may be different on location See As-built diagram attached to this PTD. bjm Page 14 Version 1 July, 2021 SRU 241-33B Drilling Procedure Rev 1 11.0 Drill 9-7/8” Hole Section 11.1 P/U 9-7/8” directional drilling assy: x Ensure BHA components have been inspected previously. x Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. x Ensure TF offset is measured accurately and entered correctly into the MWD software. x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. x Workstring will be 4.5” 16.6# S-135 CDS40 11.2 4-1/2” Workstring & HWDP will come from Hilcorp. 11.3 Begin drilling out from 20” conductor at reduced flow rates to avoid broaching the conductor. 11.4 Drill 9-7/8” hole section to 2,110’ MD/ 1,986’ TVD. Confirm this setting depth with the geologist and Drilling Engineer while drilling the well. x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Pump at 500 - 550 gpm. Ensure shaker screens are set up to handle this flowrate. x Utilize past experience to drill through coal seams efficiently. Coal seam log will be provided by Hilcorp Geo team. x Keep swab and surge pressures low when tripping. x Make wiper trips every 500’ or every couple days unless hole conditions dictate otherwise. x Ensure shale shakers are functioning properly. Check for holes in screens on connections. x Adjust MW as necessary to maintain hole stability. x TD the hole section in a good shale between 2,050’ and 2,150’MD. x Take MWD surveys every stand drilled (60’ intervals). 11.5 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 Page 15 Version 1 July, 2021 SRU 241-33B Drilling Procedure Rev 1 Properties: Depths Density Viscosity Plastic Viscosity Yield Point API FL pH 120-2110’ 8.8 – 9.5 85-150 20 - 40 25 - 45 <10 8.5-9.0 System Formulation: Aquagel + FW spud mud Product Concentration FRESH WATER SODA ASH AQUAGEL CAUSTIC SODA BARAZAN D+ BAROID 41 PAC-L /DEXTRID LT ALDACIDE G X-TEND II 0.905 bbl 0.5 ppb 12-15 ppb 0.1 ppb (9 pH) as needed as required for weight if required for <12 FL 0.1 ppb 0.02 ppb 11.6 At TD; pump sweeps, CBU, and pull a wiper trip back to the 16” conductor shoe. 11.7 TOH with the drilling assy, handle BHA as appropriate. Minimum EMW needed = 8.65 ppg. DLB Page 16 Version 1 July, 2021 SRU 241-33B Drilling Procedure Rev 1 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” USS-CDC 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 Install (1) centralizer every other joint to 300’. Do not run any centralizers above 300’ in the event a top out job is needed. x Utilize a collar clamp until weight is sufficient to keep slips set properly. 7-5/8” 29.7# CDC M/U torques Casing OD Minimum Maximum Yield Torque 7-5/8” 14,000 ft-lbs 17,000 ft-lbs 20,900 ft-lbs Page 17 Version 1 July, 2021 SRU 241-33B Drilling Procedure Rev 1 Page 18 Version 1 July, 2021 SRU 241-33B Drilling Procedure Rev 1 12.6 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 12.7 Slow in and out of slips. 12.8 P/U casing hanger joint and M/U to string. Casing hanger joint will come out to the rig with the landing joint already M/U. Position the shoe as close to TD as possible. Strap the landing joint while it is on the deck and mark the joint at (1) ft intervals to use as a reference when landing the hanger. 12.9 Lower string and land out in wellhead. Confirm measurements indicate the hanger has correctly landed out in the wellhead profile. 12.10 R/U circulating equipment and circulate the greater of 1 x casing capacity or 1 x OH volume. Elevate the hanger offseat to avoid plugging the flutes. Stage up pump slowly and monitor losses closely while circulating. 12.11 After circulating, lower string and land hanger in wellhead again. Page 19 Version 1 July, 2021 SRU 241-33B Drilling Procedure Rev 1 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 How to handle cmt returns at surface. x Which pump will be utilized for displacement, and how fluid will be fed to displacement pump. x Positions and expectations of personnel involved with the cmt operation. 13.2 Document efficiency of all possible displacement pumps prior to cement job 13.3 R/U cmt head (if not already done so). Ensure top and bottom plugs have been loaded correctly. 13.4 Pump 5 bbls 10 ppg spacer. Test surface cmt lines. 13.5 Pump remaining 10 ppg spacer. 13.6 Drop bottom plug. Mix and pump cmt per below recipe. 13.7 Cement volume based on annular volume + 50% open hole excess. Job will consist of lead & tail, TOC brought to surface. Estimated Total Cement Volume: Section: Calculation: Vol (BBLS) Vol (ft3) 12.0 ppg LEAD: 16” Conductor x 7-5/8” casing annulus: 120’ x .16239 bpf = 19.49 109.4 12.0 ppg LEAD: 9-7/8” OH x 7-5/8” Casing annulus: (1610’ – 120’) x .03825 bpf x 1.5 = 85.49 480.0 Total LEAD: 104.98 589.4 ft3 15.4 ppg TAIL: 9-7/8” OH x 7-5/8” Casing annulus: (2110’- 1610’) x .03825 bpf x 1.5 = 26.69 161.1 15.4 ppg TAIL: 7-5/8” Shoe track: 80 x .04592 bpf = 3.67 20.6 Total TAIL: 32.36 bbl 181.7 ft3 TOTAL CEMENT VOL: 137.34 bbl 771.1 ft3 Verified cement calcs - bjm Page 20 Version 1 July, 2021 SRU 241-33B Drilling Procedure Rev 1 Cement Slurry Design: 13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Keep the hanger elevated above the wellhead while working. If the hole gets “sticky”, land the hanger on seat and continue with the cement job. 13.9 After pumping cement, drop top plug and displace cement with spud mud. 13.10 Ensure cement unit is used to displace cmt so that volume tracking is more accurate. 13.11 Displacement calculation: 2110’- 80’ = 2030’ x .04592 bpf = 94 bbls 13.12 Monitor returns closely while displacing cement. Adjust pump rate if necessary. If hanger flutes become plugged, open wellhead side outlet in cellar and take returns to cellar. Be prepared to pump out fluid from cellar. Have some sx of sugar available to retard setting of cement. 13.13 Do not overdisplace by more than ½ shoe track volume. Total volume in shoe track is 3.6 bbls. x Be prepared for cement returns to surface. If cmt returns are not observed to surface, be prepared to run a temp log between 12 – 18 hours after CIP. Lead Slurry (1610’ MD to surface) Tail Slurry (2110’ to 1610’ 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 displacement 93.2 bbls. Page 21 Version 1 July, 2021 SRU 241-33B Drilling Procedure Rev 1 x Be prepared with small OD top out tubing in the event a top out job is required. The AOGCC will require us to run steel pipe through the hanger flutes. The ID of the flutes is 1.5”. 13.14 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held. 13.15 R/D cement equipment. Flush out wellhead with FW. 13.16 Back out and L/D landing joint. Flush out wellhead with FW. 13.17 M/U pack-off running tool and pack-off to bottom of Landing joint. Set casing hanger packoff. Run in lock downs and inject plastic packing element. 13.18 Lay down landing joint and pack-off running tool. Ensure to report the following on wellez: x Pre flush type, volume (bbls) & weight (ppg) x Cement slurry type, lead or tail, volume & weight x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid x Note if casing is reciprocated or rotated during the job x Calculated volume of displacement, actual displacement volume, whether plug bumped & bump pressure, do floats hold x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure x Note if pre flush or cement returns at surface & volume x Note time cement in place x Note calculated top of cement x Add any comments which would describe the success or problems during the cement job Send final “As-Run” casing tally & casing and cement report to cdinger@hilcorp.com and Frank.Roach@hilcorp.com. This will be included with the EOW documentation that goes to the AOGCC. Page 22 Version 1 July, 2021 SRU 241-33B Drilling Procedure Rev 1 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 4-1/2” BOP test assy, land out test plug (if not installed previously). x Test BOP to 250/3500 psi for 10/10 min. Test annular to 250/2500 psi for 10/10 min. x Ensure to leave “B” section side outlet valves open during BOP testing so pressure does not build up beneath the test plug. 14.5 R/D BOP test assy. 14.6 Dump and clean mud pits, send spud mud to G&I pad for injection. 14.7 Mix 9.0 ppg 6% KCL PHPA mud system. 14.8 R/U mud loggers for production hole section. 14.9 Rack back as much 4-1/2” DP in derrick as possible to be used while drilling the hole section. Page 23 Version 1 July, 2021 SRU 241-33B Drilling Procedure Rev 1 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. Hydraulics calculations and recommended TFA is attached below. 15.7 Workstring will be 4.5” 16.6# S-135 CDS40. Ensure to have enough 4-1/2” DP in derrick to drill the entire open hole section without having to pick up pipe from the pipeshed. 15.8 6-3/4” hole section mud program summary: Weighting material to be used for the hole section will be barite, salt and calcium carbonate. Additional calcium carbonate will be on location to weight up the active system (1) ppg above highest anticipated MW. Pason PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, Toolpusher office, and mud loggers office. System Type: 9.0 ppg 6% KCL PHPA fresh water based drilling fluid. Properties: MD Mud Weight Viscosity Plastic Viscosity Yield Point pH HPHT 2,110’- 6,930’ 9.0 – 10.0 40-53 15-25 15-25 8.5-9.5 11.0 Minimum EMW needed = 8.65 ppg. DLB Page 24 Version 1 July, 2021 SRU 241-33B Drilling Procedure Rev 1 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 3000 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. We are asking to test to 3000 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. Note: Offset field test data predicts frac gradient at the 7-5/8” shoe to be between 11.5 – 13.0+ ppg EMW. A 13.5 ppg FIT results in a 4.0 ppg kick margin and a >10 bbl kick tolerance volume while drilling with the planned MW of 9.5 ppg. Kick tolerance = (13.5-9.5)X(1986/6306) = 1.26 15.14 Drill 6-3/4” hole section to 6,910’ MD / 6,305’ TVD x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Pump at 400 - 500 gpm. Ensure shaker screens are set up to handle this flowrate. x Keep swab and surge pressures low when tripping. x Make wiper trips every 1000’ unless hole conditions dictate otherwise. x On the third wiper trip (around 4,500’ MD), trip back to the 7-5/8” shoe to split the hole section in half x Ensure shale shakers are functioning properly. Check for holes in screens on connections. x Adjust MW as necessary to maintain hole stability. Keep HTHP fluid loss < 10. x Take MWD surveys every 100’ drilled. Surveys can be taken more frequently if deemed necessary. x Take (3) sets of formation samples every 20’. Hilcorp verified high level of confidence in pore pressure prediction to justify 0 psi kick intensity. See attached email from Jeff Nelson. Pressure test casing to 50% of 7-5/8" burst. bjm 13.5 ppg EMW FIT yeilds 17.5 bbl kick tolerance, when accounting for hole angle and assuming 0 psi kick intensity. Page 25 Version 1 July, 2021 SRU 241-33B Drilling Procedure Rev 1 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 drill pipe. 15.17 LD BHA 15.18 RU E-Line and perform wireline logging plan. 15.19 RD E-Line. PU 6-3/4” clean out BHA, and TIH to TD. 15.20 Pump sweep, CBU and condition mud for casing run. 15.21 POOH and LD BHA 15.22 2-7/8” x 5-1/2” VBRs previously installed in BOP stack and tested with 4-1/2” test joint. Page 26 Version 1 July, 2021 SRU 241-33B Drilling Procedure Rev 1 16.0 Run 4-1/2” Production Liner 16.1. R/U Weatherford 4-1/2” casing running equipment. x Ensure 4-1/2” DWC/C-HT x CDS 40 crossover on rig floor and M/U to FOSV. x R/U fill up line to fill liner while running. x Ensure all liner has been drifted prior to running. x Be sure to count the total # of joints before running. x Keep hole covered while R/U liner tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 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 4-1/2” production liner x Fill liner while running using fill up line on rig floor. x Use “API Modified” thread compound. Dope pin end only w/ paint brush. x Install solid body centralizers on every joint across zones of interest, TBD after LWD. x Install solid body centralizers on every other joint to 7-5/8” shoe. Leave the centralizers free floating. x 2 joints with RA tags installed in the couplings will be placed in the string. Placement of the joints will be determined by asset geologist after reviewing LWD data. 16.5. Continue running 4-1/2” production liner 4-1/2” 12.6# DWC/C-HT M/U torques Casing OD Minimum Maximum Yield Torque 4-1/2” 5,800 ft-lbs 6,500 ft-lbs 9,240 ft-lbs Page 27 Version 1 July, 2021 SRU 241-33B Drilling Procedure Rev 1 Page 28 Version 1 July, 2021 SRU 241-33B Drilling Procedure Rev 1 16.6. Run in hole w/ 4-1/2” liner to the 7-5/8” casing shoe. 16.7. Fill the liner 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 liner. 16.9. Circulate 2X bottoms up at shoe, ease liner thru shoe. 16.10. Continue to RIH w/ liner no faster than 1 jt./minute. Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 16.11. Set liner slowly in and out of slips. 16.12. PU 4-1/2” X 7-5/8” Baker liner hanger/LTP assembly. RIH 1 stand and circulate one liner volume to clear string. Obtain slack off weight, PU weight, rotating weight, and torque parameters of the liner. 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. Monitor PUW & SOW. Circulate BU if needed. Highlight zones of interest before running past, ex: coals 16.15. Swedge up and wash last stand to bottom. P/U 2-5’ off bottom. Note slack-off and pick-up weights. 16.16. Stage pump rates up slowly to circulating rate. Circ and condition mud with liner on bottom. Circulate 2X bottoms up or until pressures stabilize and mud properties are correct and the shakers are clean. Reduce the low-end rheology of the drilling fluid by adding water and thinners. 16.17. Rotate and reciprocate string if hole conditions allow. Circ until hole and mud is in good condition for cementing. Page 29 Version 1 July, 2021 SRU 241-33B Drilling Procedure Rev 1 17.0 Cement 4-1/2” 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 of 12.5 ppg Mud Push spacer. 17.4. Test surface cmt lines to 4500 psi. 17.5. Pump remaining 12.5 ppg Mud Push 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. Estimated Total Cement Volume: Section: Calculation: Vol (BBLS) Vol (ft3) 12.0 ppg LEAD: 7-5/8” csg x 4-1/2” drillpipe annulus: 200’ x .02624 bpf = 5.25 29.5 12.0 ppg LEAD: 7-5/8” csg x 4-1/2” liner annulus: 200’ x .02624 bpf = 5.25 29.5 12.0 ppg LEAD: 6-3/4” OH x 4-1/2” annulus: (6430’ – 1910’) x .02459 bpf x 1.4 = 148.72 835.0 Total LEAD: 159.22 bbl 894.0 ft3 15.4 ppg TAIL: 6-3/4” OH x 4-1/2” annulus: (6930’- 6430’) x .02459 bpf x 1.4 = 17.21 96.6 15.4 ppg TAIL: 4-1/2” Shoe track: 80 x .01522 bpf = 1.22 6.8 Total TAIL: 18.43 bbl 103.5 ft3 TOTAL CEMENT VOL: 177.65 bbl 997.4 ft3 Verified cement calcs - bjm Page 30 Version 1 July, 2021 SRU 241-33B Drilling Procedure Rev 1 Cement Slurry Design: 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 ½ shoe track. Shoe track volume is 1.2 bbls. 17.13. Continue pressuring up to activate LTP pusher tool and set packer with running tool in compression. Lead Slurry (6430’ MD to 1910’ MD) Tail Slurry (6930’ to 6430’ MD) System Extended Conventional Density 12 lb/gal 15.4 lb/gal Yield 2.4 ft3/sk 1.24 ft3/sk Mixed Water 14.09 gal/sk 5.58 gal/sk Mixed Fluid 14.09 gal/sk 5.58 gal/sk Additives Code Description Code Description Type I/II Cement CLASS A Type I/II Cement CLASS A Halad-344 Fluid Loss Halad-344 Fluid Loss HR-5 Retarder HR-5 Retarder D-Air 5000 Anti Foam CFR-3 Dispersant Econolite Light-weight add. UCS Slurry Conditioner SA-1015 Suspension Agent Super CBL Anti-Gas Migration BridgeMaker II Lost Circulation Page 31 Version 1 July, 2021 SRU 241-33B Drilling Procedure Rev 1 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. 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 liner to 2500 psi and chart for 30 minutes. Page 32 Version 1 July, 2021 SRU 241-33B Drilling Procedure Rev 1 Ensure to report the following on wellez: x Pre flush type, volume (bbls) & weight (ppg) x Cement slurry type, lead or tail, volume & weight x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid x Note if liner is reciprocated or rotated during the job x Calculated volume of displacement , actual displacement volume, whether plug bumped & bump pressure, do floats hold x Percent mud returns during job. If intermittent, note timing during pumping of job. Final circulating pressure x Note if pre flush or cement returns at surface & volume x Note time cement in place x Note calculated top of cement x Add any comments which would describe the success or problems during the cement job Send final “As-Run” liner tally & liner and cement report to cdinger@hilcorp.com and Frank.Roach@hilcorp.com. This will be included with the EOW documentation that goes to the AOGCC. Page 33 Version 1 July, 2021 SRU 241-33B Drilling Procedure Rev 1 18.0 4-1/2” Liner Tieback Polish Run and Cleanout 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. POOH, and LD polish mill. 18.4. M/U casing clean out assy complete with casing scraper assys for each size casing in the hole. x 3-1/2” bit or mill x Casing scraper & brush for 4-1/2” 12.6# tubulars x +/- 5100’ 2-7/8” PH-6 workstring. x Casing scraper & brush for 7-5/8” 29.7# casing x 4-1/2” DP to surface. 18.5. TIH & clean out well to landing collar (+/- 6,250’ MD). x Circulate as needed on trip in if string begins to take weight. x Circulate hi-vis sweeps as necessary to carry debris out of wellbore. x Ensure 3-1/2” bit is worked down to the landing collar. x Space out the cleanout BHA so that the 3-1/2” bit reaches the 4-1/2” landing collar when crossover/7-5/8” casing scraper is +/- 30’ above the 4-1/2” liner top. 18.6. After wellbore has been cleaned out satisfactorily using mud, test casing to 3000 psi / 30 min. Ensure to chart record casing test. 18.7. Displace drilling fluid in wellbore with a hi-vis pill followed by 6% KCl completion fluid. 18.8. POOH, LDDP and workstring. Clean and clear rig floor in preparation for running tieback. 8.65 ppg y 6% KCl completion fluid. Pressure test liner lap to 50% of 7-5/8" burst. 6880 psi x 50% = 3440 psi. bjm Page 34 Version 1 July, 2021 SRU 241-33B Drilling Procedure Rev 1 19.0 4-1/2” Tieback Run 19.1 PU 4-1/2” tieback assembly and RIH with 4-1/2” 12.6# L-80 DWC/C-HT casing. 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 4-1/2” liner and tieback to 3,000 psi and chart for 30 minutes. 19.6 Test 7-5/8” x 4-1/2” annulus to 2,500 psi and chart for 30 minutes. 20.0 RDMO 20.1 Install BPV in wellhead 20.2 N/D BOPE 20.3 N/U temp abandonment cap 20.4 RDMO Hilcorp Rig #169 Provide 24 hrs notice for AOGCC to witness MIT-T & MIT-IA. bjm Install Tree as drawn in attached Wellhead Schmeatic. bjm Page 35 Version 1 July, 2021 SRU 241-33B Drilling Procedure Rev 1 21.0 BOP Schematic Page 36 Version 1 July, 2021 SRU 241-33B Drilling Procedure Rev 1 22.0 Wellhead Schematic Page 37 Version 1 July, 2021 SRU 241-33B Drilling Procedure Rev 1 23.0 Days Vs Depth Page 38 Version 1 July, 2021 SRU 241-33B Drilling Procedure Rev 1 24.0 Geo-Prog Page 39 Version 1 July, 2021 SRU 241-33B Drilling Procedure Rev 1 Page 40 Version 1 July, 2021 SRU 241-33B Drilling Procedure Rev 1 25.0 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. No abnormal pressures or temperatures are present in this hole section. H2S: H2S is not present in this hole section.DLB Page 41 Version 1 July, 2021 SRU 241-33B Drilling Procedure Rev 1 6-3/4” Hole Section: Lost Circulation: Ensure 1000 lbs of each of the different sizes of Calcium Carbonate are available on location to mix LCM pills at moderate product concentrations. Given the volume of losses experienced in KU 42-12 when drilling through Pool 6, ensure all LCM inventory is fully stocked before drilling out surface casing. Hole Cleaning: Maintain rheology w/ viscosifier as necessary. Sweep hole w/ 20 bbls hi-vis pills as necessary. Optimize solids control equipment to maintain density and minimize sand content. Maintain YP between 20 - 30 to optimize hole cleaning and control ECD. Wellbore stability: Maintain MW as necessary using additions of Calcium Carbonate as weighting material. A torque reduction lube may be used in this hole section in concentrations up to 3% if needed. Maintain 6% KCl in system for shale inhibition. Coal Drilling: The following lessons were learned from extensive experience drilling coal seams in Cook Inlet. The need for good planning and drilling practices is also emphasized as a key component for success. x Keep the drill pipe in tension to prevent a whipping effect which can disturb coal sections. x Use asphalt-type additives to further stabilize coal seams. x Increase fluid density as required to control running coals. x Emphasize good hole cleaning through hydraulics, ROP and system rheology. H2S: H2S is not present in this hole section. No abnormal temperatures are present in this hole section. DLB H2S: H2S is not present in this hole section. Page 42 Version 1 July, 2021 SRU 241-33B Drilling Procedure Rev 1 26.0 Hilcorp Rig 169 Layout Page 43 Version 1 July, 2021 SRU 241-33B Drilling Procedure Rev 1 27.0 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 44 Version 1 July, 2021 SRU 241-33B Drilling Procedure Rev 1 28.0 Choke Manifold Schematic Page 45 Version 1 July, 2021 SRU 241-33B Drilling Procedure Rev 1 29.0 Casing Design Information Page 46 Version 1 July, 2021 SRU 241-33B Drilling Procedure Rev 1 30.0 6-3/4” Hole Section MASP Page 47 Version 1 July, 2021 SRU 241-33B Drilling Procedure Rev 1 13.65 ppg FG - bjm @ shoe (1986' TVD) DLB Page 48 Version 1 July, 2021 SRU 241-33B Drilling Procedure Rev 1 31.0 Spider Plot (Governmental Sections) Page 49 Version 1 July, 2021 SRU 241-33B Drilling Procedure Rev 1 32.0 Surface Plat (As-Built NAD27) !!" # -950 -475 0 475 950 1425 1900 2375 2850 3325 3800 4275 4750 5225 5700 6175True Vertical Depth (950 usft/in)-475 0 475 950 1425 1900 2375 2850 3325 3800 4275 4750 5225 5700 6175 Vertical Section at 70.08° (950 usft/in) SRU 241-33B Tgt 1 SRU 241-33B Tgt 2 SRU 241-33B Tgt 3 SRU 241-33B Tgt 4 SRU 241-33B Tgt 5 16" 7 5/8" x 9 7/8" 4 1/2" x 6 3/4" 5 0 0 1 0 0 0 1 5 0 0 2 0 0 0 2 5 0 0 3 0 0 0 3 5 0 0 4 0 0 0 4 5 0 0 5 0 0 0 5 5 0 0 6 0 0 0 6 5 0 0 6 9 3 0 SRU 241-33B wp04 Start Dir 3º/100' : 250' MD, 250'TVD End Dir : 1089.33' MD, 1062.58' TVD Start Dir 3º/100' : 2059.42' MD, 1940.48'TVD End Dir : 3081.69' MD, 2827.09' TVD Start Dir 2º/100' : 3231.7' MD, 2945.3'TVD End Dir : 3367.84' MD, 3052.57' TVD Start Dir 2º/100' : 4132.72' MD, 3654.89'TVD End Dir : 5658.22' MD, 5044.69' TVD Total Depth : 6929.83' MD, 6305.3' TVD SR_ST_A SR_ST_A9 SR_ST_A12 SR_ST_B1U SR_ST_B3 SR_ST_B5 SR_ST_B8U SR_ST_B9U SR_UB_37-0 SR_UB_47-0 SR_LB_51-7 TYONEK SR_TY_56-9 SR_TY_62-5 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: SRU 241-33B 187.30 +N/-S +E/-W Northing Easting Latittude Longitude 0.00 0.00 2465979.700 344528.100 60° 44' 49.0585 N 150° 52' 8.3205 W SURVEY PROGRAM Date: 2021-06-10T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 18.00 2110.00 SRU 241-33B wp04 (SRU 241-33B) 3_MWD+IFR1+MS+Sag 2100.00 6929.83 SRU 241-33B wp04 (SRU 241-33B) 3_MWD+IFR1+MS+Sag FORMATION TOP DETAILS TVDPath TVDssPath MDPath Formation 1323.30 1118.00 1377.43 SR_ST_A 2502.30 2297.00 2689.45 SR_ST_A9 2790.30 2585.00 3035.31 SR_ST_A12 2957.30 2752.00 3246.92 SR_ST_B1U 3159.30 2954.00 3503.38 SR_ST_B3 3262.30 3057.00 3634.18 SR_ST_B5 3621.30 3416.00 4090.06 SR_ST_B8U 3695.30 3490.00 4183.68 SR_ST_B9U 3906.30 3701.00 4439.71 SR_UB_37-0 4474.30 4269.00 5070.81 SR_UB_47-0 5418.30 5213.00 6035.09 SR_LB_51-7 5552.30 5347.00 6170.26 TYONEK 5942.30 5737.00 6563.66 SR_TY_56-9 REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well SRU 241-33B, True North Vertical (TVD) Reference:RKB As-Stake @ 205.30usft Measured Depth Reference: RKB As-Stake @ 205.30usft Calculation Method:Minimum Curvature Project:Swanson River Unit Site:SRU 21-33 Well:SRU 241-33B Wellbore:SRU 241-33B Design:SRU 241-33B wp04 CASING DETAILS TVD TVDSS MD Size Name 120.00 -85.30 120.00 16 16" 1986.26 1780.96 2110.00 7-5/8 7 5/8" x 9 7/8" 6305.30 6100.00 6929.83 4-1/2 4 1/2" x 6 3/4" SECTION DETAILS Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation 1 18.00 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 3º/100' : 250' MD, 250'TVD 3 1089.33 25.18 29.14 1062.58 158.51 88.37 3.00 29.14 137.09 End Dir : 1089.33' MD, 1062.58' TVD 4 2059.42 25.18 29.14 1940.48 519.01 289.35 0.00 0.00 448.85 Start Dir 3º/100' : 2059.42' MD, 1940.48'TVD 5 3081.69 38.00 85.00 2827.09 741.72 719.04 3.00 92.54 928.71 End Dir : 3081.69' MD, 2827.09' TVD 6 3231.70 38.00 85.00 2945.30 749.77 811.05 0.00 0.00 1017.95 Start Dir 2º/100' : 3231.7' MD, 2945.3'TVD 7 3367.84 38.05 89.42 3052.57 753.85 894.77 2.00 90.69 1098.05 End Dir : 3367.84' MD, 3052.57' TVD 8 4132.72 38.05 89.42 3654.89 758.62 1366.18 0.00 0.00 1542.89 Start Dir 2º/100' : 4132.72' MD, 3654.89'TVD 9 5658.22 7.54 89.24 5044.69 764.86 1950.22 2.00 -179.95 2094.12 End Dir : 5658.22' MD, 5044.69' TVD 10 6929.83 7.54 89.24 6305.30 767.07 2117.06 0.00 0.00 2251.74 Total Depth : 6929.83' MD, 6305.3' TVD -1500150300450600750900105012001350150016501800South(-)/North(+) (300 usft/in)-300 -150 0 150 300 450 600 750 900 1050 1200 1350 1500 1650 1800 1950 2100 2250 2400West(-)/East(+) (300 usft/in)SRU 241-33B Tgt 5SRU 241-33B Tgt 4SRU 241-33B Tgt 3SRU 241-33B Tgt 2SRU 241-33B Tgt 116"7 5/8" x 9 7/8"4 1/2" x 6 3/4"2505007501000125015001750200022502 5 0 0 2 7 5 0 3 0 0 0 3250 3500 3750 4000 4250 4500 47505000525055005750600062506305SRU 241-33B wp04Start Dir 3º/100' : 250' MD, 250'TVDEnd Dir : 1089.33' MD, 1062.58' TVDStart Dir 3º/100' : 2059.42' MD, 1940.48'TVDEnd Dir : 3081.69' MD, 2827.09' TVDStart Dir 2º/100' : 3231.7' MD, 2945.3'TVDEnd Dir : 3367.84' MD, 3052.57' TVDStart Dir 2º/100' : 4132.72' MD, 3654.89'TVDEnd Dir : 5658.22' MD, 5044.69' TVDTotal Depth : 6929.83' MD, 6305.3' TVDCASING DETAILSTVDTVDSS MDSize Name120.00 -85.30 120.00 16 16"1986.26 1780.96 2110.00 7-5/8 7 5/8" x 9 7/8"6305.30 6100.00 6929.83 4-1/2 4 1/2" x 6 3/4"Project: Swanson River UnitSite: SRU 21-33Well: SRU 241-33BWellbore: SRU 241-33BPlan: SRU 241-33B wp04WELL DETAILS: SRU 241-33B187.30+N/-S +E/-WNorthingEastingLatittudeLongitude0.00 0.00 2465979.700344528.10060° 44' 49.0585 N150° 52' 8.3205 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well SRU 241-33B, True NorthVertical (TVD) Reference: RKB As-Stake @ 205.30usftMeasured Depth Reference:RKB As-Stake @ 205.30usftCalculation Method:Minimum Curvature $ " % & ! 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"! : ; 0<)& ; =&. ; ; $ &. > $#4 $) ?& 9 == & ; ;98:;:.; 0 ; :& 0.001.002.003.004.00Separation Factor550 1100 1650 2200 2750 3300 3850 4400 4950 5500 6050 6600 7150 7700 8250 8800 9350 9900 10450Measured Depth (1100 usft/in)SRU 34-28SRU 21-33WDNo-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.NOERRORSWELL DETAILS: SRU 241-33B NAD 1927 (NADCON CONUS) Alaska Zone 04187.30+N/-S+E/-W NorthingEastingLatittudeLongitude0.000.002465979.700 344528.100 60° 44' 49.0585 N 150° 52' 8.3205 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well SRU 241-33B, True NorthVertical (TVD) Reference: RKB As-Stake @ 205.30usftMeasured Depth Reference:RKB As-Stake @ 205.30usftCalculation Method:Minimum CurvatureCASING DETAILSTVD TVDSS MD Size Name120.00 -85.30 120.00 16 16"1986.26 1780.96 2110.00 7-5/8 7 5/8" x 9 7/8"6305.30 6100.00 6929.83 4-1/2 4 1/2" x 6 3/4"SURVEY PROGRAMDate: 2021-06-10T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool18.00 2110.00 SRU 241-33B wp04 (SRU 241-33B) 3_MWD+IFR1+MS+Sag2100.00 6929.83 SRU 241-33B wp04 (SRU 241-33B) 3_MWD+IFR1+MS+Sag0.0040.0080.00120.00160.00200.00Centre to Centre Separation (80.00 usft/in)550 1100 1650 2200 2750 3300 3850 4400 4950 5500 6050 6600 7150 7700 8250 8800 9350 9900 10450Measured Depth (1100 usft/in)SRU 241-33SRU 241-33SRU 211-33SRU 211-33SRU 21-33WDGLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference18.00 To 6929.83Project: Swanson River UnitSite: SRU 21-33Well: SRU 241-33BWellbore: SRU 241-33BPlan: SRU 241-33B wp04Ladder/S.F. Plots Rig 147 and 169 Diverter Stackup 16'’ Hydril V 4.30' Hydril MSP 21-¼ 2M .50' 4.00' 2.67' 1.33' 4.37' Grade Level 3.09' DSA 16 ¾ 3M X 21 ¼ 2M 21 ¼ 2M Spool 21 ¼ 2M Diverter Tee 16'’ 150 outlet 4.08' 16'’ casing cut @ 64'’ below ground level .42' 1 Carlisle, Samantha J (CED) From:McLellan, Bryan J (CED) Sent:Thursday, August 26, 2021 5:19 PM To:Jeff Nelson - (C); Meredyth Richards Cc:Frank Roach Subject:RE: [EXTERNAL] RE: Swanson River Asset Contacts ThanksJeffandMeredyth.Thatwasveryhelpful. Regards BryanMcLellan SeniorPetroleumEngineer AlaskaOil&GasConservationCommission 333W7thAve Anchorage,AK99501 Bryan.mclellan@alaska.gov +1(907)250Ͳ9193 From:JeffNelsonͲ(C)<Jeff.Nelson@hilcorp.com> Sent:Thursday,August26,202112:27PM To:McLellan,BryanJ(CED)<bryan.mclellan@alaska.gov>;MeredythRichards<Meredyth.Richards@hilcorp.com> Cc:FrankRoach<Frank.Roach@hilcorp.com> Subject:RE:[EXTERNAL]RE:SwansonRiverAssetContacts HiBryan, AsMeredythmentioned,SRU241Ͳ33BissimilarinmanywaystoSRU241Ͳ33thatwasdrilledin2017.Wearedrilling fromthesamepadandtargetingtheSterling,Beluga,andUpperTyonekgasreservoirswithasimilarwelltrajectoryand azimuth,just~1000’tothenorth. AtSwansonRiver,IhaveagoodlevelofconfidenceinvirginpressuregassandsinourSterling,Beluga,andUpper Tyonekreservoirs.Thegasreservoirsarenormallypressuredandfollowa~0.45psi/ftgradient.Thesearethe maximumpressuresthataretobeexpectedinanygivengasreservoir,andarewhathavebeenincludedintheGeoprog forplanningthemudprogram,FIT,andkicktolerancecalculations. For241Ͳ33B,wewillbedrillingdownthroughtheTyonek62Ͳ5reservoir,andstoppingshortoftheTY64Ͳ5storage reservoirwhichisactivewiththeKGSF1AandKGSF7Awells~2700’tothenorthof241Ͳ33B.Becauseofthis,the64Ͳ5I didnotbringthe64Ͳ5sandpressuresintoconsiderationforthisdrillingproject. Tosummarize: x WehavegoodconfidenceinvirginpressuregassandsatSwansonRiver,andtheyfollowa~0.45psi/ft gradient x SRU241Ͳ33wasdrilledfromthesamepadanddrilledacrossthesamegasreservoirsthatSRU241Ͳ33Bwillbe drillingthrough.Thisnearbyanaloguegivesusgoodconfidenceinourporepressurepredictionforthis project. x Wewillnotbepenetratinganystoragereservoirs. 2 Pleaseletusknowifyouhaveanyfurtherquestions. Regards, JeffNelson Geologist KenaiAssetTeam HilcorpAlaska (w)907Ͳ777Ͳ8455 (c)307Ͳ760Ͳ8065 From:McLellan,BryanJ(CED)<bryan.mclellan@alaska.gov> Sent:Thursday,August26,202110:29AM To:MeredythRichards<Meredyth.Richards@hilcorp.com>;JeffNelsonͲ(C)<Jeff.Nelson@hilcorp.com> Cc:FrankRoach<Frank.Roach@hilcorp.com> Subject:RE:[EXTERNAL]RE:SwansonRiverAssetContacts ThanksMeredyth.It’sgoodtoknowyouhavehighconfidenceinyourporepressurepredictionsbasedoncloseoffset data.I’llwaittohearfromJeffasyousuggest,toseeifhehasanythingtoadd. Regards BryanMcLellan SeniorPetroleumEngineer AlaskaOil&GasConservationCommission 333W7thAve Anchorage,AK99501 Bryan.mclellan@alaska.gov +1(907)250Ͳ9193 From:MeredythRichards<Meredyth.Richards@hilcorp.com> Sent:Thursday,August26,20216:55AM To:McLellan,BryanJ(CED)<bryan.mclellan@alaska.gov>;JeffNelsonͲ(C)<Jeff.Nelson@hilcorp.com> Cc:FrankRoach<Frank.Roach@hilcorp.com> Subject:Re:[EXTERNAL]RE:SwansonRiverAssetContacts HiBryan, Jeffcandefinitelyclarifythisforyou.He’sbackfromPTOthismorningsogivehimalittlebittogethislifetogether;) OnahigherandnonͲquantitativelevel,sincethisdrillwellislargelyacloneofSRU241Ͳ33drilledin2017,I’dsaythat wellgivesusaveryhighlevelofconfidenceabouttheexpectedporepressuresinourproposedSRU241Ͳ33B.Datafrom thatfirstwellhasbeenveryvaluableininformingourplansforthedrillwell. Anyway,Jeffcanelaborateshortly!Getintouchwithanyotherquestionsandconcerns. Best, Meredyth 3 From:McLellan,BryanJ(CED)<bryan.mclellan@alaska.gov> Sent:Wednesday,August25,20216:21:11PM To:MeredythRichards<Meredyth.Richards@hilcorp.com>;JeffNelsonͲ(C)<Jeff.Nelson@hilcorp.com> Cc:FrankRoach<Frank.Roach@hilcorp.com> Subject:[EXTERNAL]RE:SwansonRiverAssetContacts HiMeredythandJeff I’mreviewingFrank’spermittodrillapplicationandhaveaquestionaboutthelevelofcertaintyoftheporepressure acrosstheintervaltobedrilledbelowthesurfacecasingshoe.Thelevelofuncertaintyplaysintosomeofour assumptionswhenwecalculatekicktolerance. Howconfidentareyouoftheporepressurepredictioninthedrillingprogram? Thankyou BryanMcLellan SeniorPetroleumEngineer AlaskaOil&GasConservationCommission 333W7thAve Anchorage,AK99501 Bryan.mclellan@alaska.gov +1(907)250Ͳ9193 From:FrankRoach<Frank.Roach@hilcorp.com> Sent:Thursday,August12,20217:18AM To:McLellan,BryanJ(CED)<bryan.mclellan@alaska.gov> Cc:MeredythRichards<Meredyth.Richards@hilcorp.com>;JeffNelsonͲ(C)<Jeff.Nelson@hilcorp.com> Subject:SwansonRiverAssetContacts Bryan, TheSwansonRiverAssetcontactsareCc’donthisemail: MeredythRichards–ReservoirEngineer JeffNelson–Geologist Regards, FrankVRoach DrillingEngineer 907.854.2321(c) 907.777.8413(o) 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. 4 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 1 Carlisle, Samantha J (CED) From:Frank Roach <Frank.Roach@hilcorp.com> Sent:Wednesday, August 25, 2021 10:41 AM To:McLellan, Bryan J (CED) Subject:SRU 241-33B 10-401 Questions - Follow-up Attachments:217013_Hilcorp AB SRU241-33B-Rev1-Signed.pdf Bryan, IwantedtocirclebackonourFridayafternoonconversation. AttachedistheAsͲBuiltsurveyfortheconductor.Footagedistancesfromsectionlinesdidnotchange.Thedirectional planalsodidnotchange. Inregardstothedivertervariancerequest,Iamrescindingthatrequest.Wewillrigupdiverterforthiswell.Thediverter schematicwasprovidedbackon8/10toaddtotheprogramsubmittedinthe10Ͳ401.Thankyouforlettingmeknow whatyou’llbelookingforonfuturedivertervariancerequests.Wewillprovidethatdatatosupportsaidrequest. Lastly,IwantedtocheckandseeifyouhadanyoutstandingquestionsaboutSwansonRiverthatneededaconversation withtheassetgeologist/reservoirengineer? Regards, FrankVRoach DrillingEngineer 907.854.2321(c) 907.777.8413(o) 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. From:McLellan, Bryan J (CED) To:Frank Roach Subject:RE: [EXTERNAL] SRU 241-33B FIT/LOT procedure Date:Wednesday, August 11, 2021 9:20:00 AM That makes sense and works for me as long as the pressure data freaquency is reasonable on the chart, as it was on Kalotsa 7. I am confident that the rig team understands what we are asking for and that the Whiskey Gulch LOT chart will be good. Thanks for following up with them. I’m hoping we don’t have a similar issue next time there is a big changeout of the crews on 169. If you specify the ½” data collection point in your standard LOT procedure, you won’t have to worry that the next crew will do something different. Regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, AK 99501 Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Frank Roach <Frank.Roach@hilcorp.com> Sent: Tuesday, August 10, 2021 4:19 PM To: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov> Subject: RE: [EXTERNAL] SRU 241-33B FIT/LOT procedure Bryan, The importance of the LOT/FIT has been communicated, as well as the need to be consistent across the crews and rig leadership with respect to the LOT/FIT documentation detail. However, I am struggling pressure limitation for the data points. I’m used to looking for the change in pressure over a fixed volume to determine when the formation is starting to leak off. While I don’t see this being an issue with using the test pump, by requiring a pressure limitation, I’m concerned that this would result in an incorrect test that would not generate useful results. For the test pump system on rig 169, the ½” of fluid level that is used on the test pump tank equates to 1.15 gallons which should be our data frequency. Regards, Frank V Roach Drilling Engineer 907.854.2321 (c) 907.777.8413 (o) From: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov> Sent: Tuesday, August 10, 2021 13:01 To: Frank Roach <Frank.Roach@hilcorp.com> Subject: [EXTERNAL] SRU 241-33B FIT/LOT procedure Frank, Could you modify your standard FIT/LOT procedure to include our expectations for the data collection frequency. I would expect to see a data point for every 100 psi maximum of pressure increase during the FIT/LOT, and every 400 psi for the casing test. If taking a data point after every ½” of fluid level drop works out to <100 psi increments, that’s fine. But if not, they would need do something different and possibly redo the FIT. It’s important to get the LOT/FIT pressure right. It’s not only used for kick tolerance and well control, it plays into future development planning in the region. Lots of decisions are made based on that number. Please stress that with the rig team. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, AK 99501 Bryan.mclellan@alaska.gov +1 (907) 250-9193 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. Revised 2/2015 TRANSMITTAL LETTER CHECKLIST WELL NAME: ______________________________________ PTD: _____________________________________________ ___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional FIELD: ____________________________ POOL: ______________________________________ Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI LATERAL (If last two digits in API number are between 60-69) The permit is for a new wellbore segment of existing well Permit No. _____________, API No. 50-_______________________. Production should continue to be reported as a function of the original API number stated above. Pilot Hole In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well name (_______________________PH) and API number (50-_____________________) from records, data and logs acquired for well (name on permit). Spacing Exception The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce/inject is contingent upon issuance of a conservation order approving a spacing exception. (_____________________________) as Operator assumes the liability of any protest to the spacing exception that may occur. Dry Ditch Sample All dry ditch sample sets submitted to the AOGCC must be in no greater than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. Non- Conventional Well Please note the following special condition of this permit: Production or production testing of coal bed methane is not allowed for well ( ) until after ( ) has designed and implemented a water well testing program to provide baseline data on water quality and quantity. (________________________) must contact the AOGCC to obtain advance approval of such water well testing program. Well Logging Requirements Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by (_______________________________) in the attached application, the following well logs are also required for this well: Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. 221-053 X Sterling/Upper Beluga Gas & Tyonek Gas X X Swanson River SRU 241-33B :(//3(50,7&+(&./,67&RPSDQ\+LOFRUS$ODVND//&:HOO1DPH6:$16215,981,7%,QLWLDO&ODVV7\SH'(93(1'*HR$UHD8QLW2Q2II6KRUH2Q3URJUDP'(9)LHOG 3RRO:HOOERUHVHJ$QQXODU'LVSRVDO37'6:$16215,9(57<21(.*$6 6:$16215,9(5675/*8%1$ 3HUPLWIHHDWWDFKHG<HV /HDVHQXPEHUDSSURSULDWH<HV 8QLTXHZHOOQDPHDQGQXPEHU<HV :HOOORFDWHGLQDGHILQHGSRRO<HV :HOOORFDWHGSURSHUGLVWDQFHIURPGULOOLQJXQLWERXQGDU\<HV :HOOORFDWHGSURSHUGLVWDQFHIURPRWKHUZHOOV<HV 6XIILFLHQWDFUHDJHDYDLODEOHLQGULOOLQJXQLW<HV ,IGHYLDWHGLVZHOOERUHSODWLQFOXGHG<HV 2SHUDWRURQO\DIIHFWHGSDUW\<HV 2SHUDWRUKDVDSSURSULDWHERQGLQIRUFH<HV 3HUPLWFDQEHLVVXHGZLWKRXWFRQVHUYDWLRQRUGHU<HV 3HUPLWFDQEHLVVXHGZLWKRXWDGPLQLVWUDWLYHDSSURYDO<HV &DQSHUPLWEHDSSURYHGEHIRUHGD\ZDLW1$ :HOOORFDWHGZLWKLQDUHDDQGVWUDWDDXWKRUL]HGE\,QMHFWLRQ2UGHUSXW,2LQFRPPHQWV)RU1$ $OOZHOOVZLWKLQPLOHDUHDRIUHYLHZLGHQWLILHG)RUVHUYLFHZHOORQO\1$ 3UHSURGXFHGLQMHFWRUGXUDWLRQRISUHSURGXFWLRQOHVVWKDQPRQWKV)RUVHUYLFHZHOORQO\1$ 1RQFRQYHQJDVFRQIRUPVWR$6M$M$'<HV &RQGXFWRUVWULQJSURYLGHG<HV 6XUIDFHFDVLQJSURWHFWVDOONQRZQ86':V<HV &07YRODGHTXDWHWRFLUFXODWHRQFRQGXFWRU VXUIFVJ1$ 7KLVLVDOLQHUEXW OLQHUODSZLOOEHFHPHQWHGLQVLGHVXUIDFHFDVLQJ &07YRODGHTXDWHWRWLHLQORQJVWULQJWRVXUIFVJ<HV &07ZLOOFRYHUDOONQRZQSURGXFWLYHKRUL]RQV<HV &DVLQJGHVLJQVDGHTXDWHIRU&7% SHUPDIURVW<HV $GHTXDWHWDQNDJHRUUHVHUYHSLW1$ ,IDUHGULOOKDVDIRUDEDQGRQPHQWEHHQDSSURYHG<HV $GHTXDWHZHOOERUHVHSDUDWLRQSURSRVHG<HV SVLGLYHUWHUZLWKGLYHUWHUOLQH ,IGLYHUWHUUHTXLUHGGRHVLWPHHWUHJXODWLRQV<HV 'ULOOLQJIOXLGSURJUDPVFKHPDWLF HTXLSOLVWDGHTXDWH<HV %23(VGRWKH\PHHWUHJXODWLRQ<HV SVL%23VWDFN0363 SVLHVWWRSVL %23(SUHVVUDWLQJDSSURSULDWHWHVWWRSXWSVLJLQFRPPHQWV<HV &KRNHPDQLIROGFRPSOLHVZ$3,530D\<HV :RUNZLOORFFXUZLWKRXWRSHUDWLRQVKXWGRZQ1R ,VSUHVHQFHRI+6JDVSUREDEOH1$ 0HFKDQLFDOFRQGLWLRQRIZHOOVZLWKLQ$25YHULILHG)RUVHUYLFHZHOORQO\<HV +6QRWDQWLFLSDWHG²QXPHURXVRIIVHWZHOOV 3HUPLWFDQEHLVVXHGZRK\GURJHQVXOILGHPHDVXUHV<HV 'DWDSUHVHQWHGRQSRWHQWLDORYHUSUHVVXUH]RQHV1$ 6HLVPLFDQDO\VLVRIVKDOORZJDV]RQHV1$ 6HDEHGFRQGLWLRQVXUYH\LIRIIVKRUH1$ &RQWDFWQDPHSKRQHIRUZHHNO\SURJUHVVUHSRUWV>H[SORUDWRU\RQO\@$SSU'/%'DWH$SSU%-0'DWH$SSU'/%'DWH$GPLQLVWUDWLRQ(QJLQHHULQJ*HRORJ\*HRORJLF&RPPLVVLRQHU'DWH(QJLQHHULQJ&RPPLVVLRQHU'DWH3XEOLF&RPPLVVLRQHU'DWH-03JLC 8/27/2021