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Home My WebLink About222-0331. 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: 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 10,461' 6,150' (fill) Casing Collapse Structural Conductor 1,500psi Surface 1,950psi Intermediate Csg 3,090psi Intermediate Lnr 5,410psi 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 Suspension Expiration Date: Ryan Lemay, Operations Engineer See Schematic N/A; N/A N/A; N/A 12.6# / L-80 7,214' Authorized Name and Digital Signature with Date:ryan.lemay@hilcorp.com Perforation Depth MD (ft): Will perfs require a spacing exception due to property boundaries? 661-487-0871 AOGCC USE ONLY Noel Nocas, Operations Manager 907-564-5278 222-033 Current Pools: MPSP (psi): Plugs (MD): TVD Tubing Grade: 20 AAC 25.055(a) Subsequent Form Required: 2,097' 7,474' 50-133-20584-01-00 Tubing Size: PRESENT WELL CONDITION SUMMARY 2,038' 3,574' 10,432' Hilcorp Alaska, LLC Proposed Pools: Beaver Creek 9-5/8" 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Sterling Gas 108' Tubing MD (ft):Perforation Depth TVD (ft): 8,430psi 108' 6,975' 20" 13-3/8" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEDA028083 2,097' BurstMD 3,574' December 1, 2025 4-1/2" Size See Schematic 108' 4-1/2" 4,138' 5,750psi 7" 5,429' 5,102' See Schematic Length 7,240psi 3,060psi 3,450psi 9,964' ~1,522psi 4,006' 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Beaver Creek Unit (BCU) 18RDCO 237D Sterling Undefined 9,936' 3,350' m n P s t 2 N 66 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: 2025.11.19 17:29:41 - 09'00' Noel Nocas (4361) 325-711 By Grace Christianson at 9:02 am, Nov 20, 2025 DSR-11/21/25A.Dewhurst 21NOV25 X BJM 11/24/25 Provide 24 hrs notice for AOGCC to witness TOC tag and pressure test. 10-404 11/24/25 Well Prognosis Well: BCU-18RD Well Name: BCU - 18RD API Number: 50-133-20584-01-00 Current Status: Offline Gas Producer Permit to Drill Number: 222-033 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: 1983 psi @ 4611 TVD Based on 0.43 psi/ft Max. Potential Surface Pressure:1522 psi Based on 0.1 psi/ft gas gradient to surface Applicable Frac Gradient: 0.679 psi/ft using 13.05 ppg EMW FIT (4/25/2022) (Milled sidetrack window in 9-5/8 from 3574-3595) Shallowest Allowable Perf TVD: MPSP / (0.679 - 0.1) = 1522 psi / 0.579 = 2628 TVD Top of AOGCC Sterling Gas Pool: 5153 MD / 4850 TVD Top of BLM Sterling Gas PA: 2707 MD / 2583 TVD Recent Well Summary: BCU 18RD has been perforated through the Sterling B3L interval and as of late June / early July 2025 the well has been offline and unable to sustain gas production. The purpose of this sundry is to add perforations in the Sterling C6 interval. The Sterling C6 interval is within the defined BLM Sterling Gas PA. However, the proposed interval is above the currently defined top of the AOGCC Sterling Gas Pool. Regulatory: BCU 18RD is currently permitted for producing in the Sterling Gas Pool of the Beaver Creek Field defined in Rule 2(a) of CO 237D dated October 13, 2022. Proposal to perforate the subject well above the shallowest pool (Sterling Gas Pool) in CO 237D, statewide spacing rules apply pursuant to 20 AAC 25.055.(a).: (2) for a well drilling for gas, a wellbore may be open to test or regular production within 1,500 of a property line only if the owner is the same and the landowner is the same on both sides of the line. (4) Inter-well spacing was eliminated via Industry Guidance Bulletin 22-002 dated 10/05/2022, and as such, is not applicable. Attached map dated November 6, 2025, displays the 1,500 radius of the anticipated productive portion of the wellbore of BCU 18RD to not intersect with a property line with differing ownership; meaning an exception is not applicable. Effective April 1, 2020, BLM approved vertical expansion of BCU Sterling PA (891008868) to 2,570 MD to 6,370 MD, correlated in BEAVER CK UNIT 01-A (API No. 501332000600). Recompletion perforation depths are within BCU Sterling PA. However, the proposed interval is above the currently defined top of the AOGCC Sterling Gas Pool. Well Prognosis Well: BCU-18RD Procedure: 1. MIRU N2 Unit and E-line. 2. Push fluid away with N2 through existing ST B3L perforations. 3. PT lubricator to 250 psi low / 2,500 psi high 4. RIH and set 4-1/2 CIBP at + 5,368 MD 5. Dump bail a minimum of 35 of cement on top of CIBP leaving TTOC at + 5,333 MD. 6. Tag TOC w/ E-line and pressure test CIBP + cement to verify plug placement and integrity for isolation of the AOGCC Sterling Gas Pool. a. Provide a minimum of 24 hr notice to AOGCC for witness of tag and pressure test b. If fluid is used for pressure test, pressure test to 2500 psi for 30 min (chart results using a chart recorder or digital crystal gauge) c. If gas is used for pressure test to 2500 psi i. Use a chart recorder or digital crystal gauge monitor for a minimum of 72 hours ii. Criteria for a passing test being a time of 72 hours showing stabilization and less than 2% drop of the maximum test pressure over the 72 hour test period. iii. IA pressure must be monitored over the duration of the test period. iv. 72 hour test will start once pressure stabilizes. 7. RIH and perforate the following sand: Well Sand Top MD Btm MD Top TVD Btm TVD Interval BCU-18RD Sterling C6 ±4,979 ±4,985 ±4,606' ±4,611' ±6' a. Correlate using 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 perforating run at 5 min, 10 min, and 15 min intervals post perf shot. 8. RDMO and turn well over to production operations. 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 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 5. Map BCU 18RD Updated by DMA 07-16-25 SCHEMATIC BCU 18RD API: 50-133-20584-01-00 PTD: 222-033 Pad-3 PBTD = 8,583 MD / 8,115 TVD TD = 10,461 MD / 9,964 TVD RKB to GL = 18.0 8 CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 20 Conductor 154.19 X-65 Weld 19.13 Surf 108 13-3/8" Surf Csg 68.0 K-55 BTC 12.415 Surf 2,097 9-5/8 Intermediate Csg 40.0 L-80 BTC 8.835 Surf 3,574 7 Intermediate Lnr 26.0 L-80 Vam Top 6.276 3,336 7,474 4-1/2" Prod Tieback 12.6 L-80 JFEBEAR 3.958 Surf 7,214 4-1/2" Prod Lnr 12.6 L-80 JFEBEAR 3.958 7,219 10,432 TUBING DETAIL 4-1/2 Tubing 12.6 L-80 Surface 7,214 1 20 13-3/8 4-1/2 JEWELRY DETAIL No. Depth ID Item 1 3,336 6.040 9-5/8 x 7 Liner hanger / LTP Assembly 2 3,574 NA Whipstock 3 5,429 CIBP (7/3/25) 4 5,577 CIBP (4/27/25) 5 5,600 CIBP (4/26/25) 6 6,235 CIBP + 54 Cement (4/19/25) TOC @ 6181 7 6,338 CIBP (2/28/25) 8 6,445 CIBP (2/25/25) 9 6,590 3-1/2 CIBP (9/9/23) 10 6,900 NA FH Cement retainer, Eline tagged cement on top @ 6852 PBTD 11 7,150 NA 4-1/2 CIBP (refence plug tag for cement retainer) 12 7,218 5.25 7 x 4-1/2 Liner hanger / LTP Assembly with PBR 13 7,214 3.890 Seal Stem 14 8,036 N/A 4-1/2 CIBP w/ 35 cement TOC 8001 (8/25/23) 15 8,620 N/A CIBP w/ 37 cement TOC @ 8,583 (7/26/22) 16 8,865 N/A CIBP w/ 5 cement TOC @ 8,860 (7/20/22) Additional 31 cement - TOC @ 8,829 (7/21/22) OPEN HOLE / CEMENT DETAIL 13-3/8 16 Hole: TOC @ Surface (Original BCU 18) 9-5/8" 12-1/4: Hole: TOC @ 3,440 (Original BCU 18) 7 8-1/2 Hole: 125bbls 12ppg lead followed by 18bbls 15.3ppg tail pumped on 5/1/22. 38bbls lead cement back to surface. 5/14/22 CBL shows ToC at 3570 MD 4-1/2 6-1/8 Hole: Pumped 30bbl spacer followed by 54bbls 12ppg Type I/II lead followed by 25bbls 15.3ppg Type I/II tail pumped on 5/11/22. Trace spacer back to surface. 5/19/22 CBL shows ToC at 7370 MD 4-1/2 Inside 7 Casing: Pump 48 bbls of cement through tubing punch @ ~7,100. TOC @ ~4,778 13 4 9-5/8 2 BCU 18 (Abandoned) 12 7 PERFORATION DETAIL Zone Top MD Btm MD TopTVD Btm TVD Amt Date Comments ST B3L 5,418 5,428 5,092' 5,101' 10' 7/5/2025 Open ST B4 5,504 5,521 5,171' 5,186' 17' 6/27/2025 Isolated 7/3/25 ST B5 5,565 5,570 5,227' 5,231' 5' 4/27/2025 Isolated 7/3/25 ST B5 5,579 5,585 5,239' 5,245' 6' 4/26/2025 Isolated 4/27/25 ST B6 5,604 5,614 5,262' 5,272' 10' 4/24/2025 Isolated 4/26/25 BEL5 6,285' 6,305' 5,890' 5,909' 20' 2/28/2025 Isolated 4/19/25 BEL6 6,342 6,348 5,942 5,947 6 9/9/2023 Isolated 2/28/25 BEL6 6,342 6,348 5,942 5,947 6 2/26/2025 Isolated 2/28/25 BEL6 6,354 6,361 5,953 5,960 7 9/9/2023 Isolated 2/28/25 BEL6 6,356 6,362 5,955 5,961 6 2/26/2025 Isolated 2/28/25 BEL6 6,366 6,375 5,964 5,972 9 9/9/2023 Isolated 2/28/25 BEL6 6,366 6,375 5,964 5,972 9 2/26/2025 Isolated 2/28/25 BEL7 6,384' 6,404' 5,981' 5,999' 20' 2/27/2025 Isolated 2/28/25 BEL7 6,453 6,467 6,044 6,055 14 9/9/2023 Isolated 1/27/25 BEL8 6,516' 6,526' 6,103' 6,112' 10' 2/25/2025 Isolated 2/25/25 BEL8 6,533' 6,543' 6,118' 6,128' 10' 2/24/2025 Isolated 2/25/25 BEL8 6,549' 6,563' 6,133' 6,146' 14' 2/24/2025 Isolated 2/25/25 BEL8 6,601 6,620 6,181 6,196 19 9/6/2023 Isolated 9/9/23 PERFORATION DETAIL continued on following page BEL 29-32 T0 T12 16 BEL 33 FISH DETAILs: Failed WRP at 8867 ELMD (7/10/22) & Fish left from 8,785-8,829ft - 35ft 3.5"OD cement bailer, 2ft CCL, 7ft 2" weight bar (7/21/22) 15 BEL 25-28 BEL 22-23 Tubing Punch at ~7,100 TOC @ 4,778 CBL 9/4/23 14 10 9.5 ppg brine 11 9 7 Tubing Patch 6,450-6,471 1/27/25 BEL 5 BEL 6-9 ST B6 6 4 5 ST B5 3 ST B3L-B4 Updated by DMA 07-16-25 SCHEMATIC BCU 18RD API: 50-133-20584-01-00 PTD: 222-033 Pad-3 PERFORATION DETAIL continued from previous page Zone Top MD Btm MD TopTVD Btm TVD Amt Date Comments BEL9 6,660 6,668 6,235 6,242 8 9/6/2023 Isolated 9/9/23 BEL22 8,086 8,106 7,626 7,646 41 3/10/2023 Isolated 8/25/23 BEL23 8,130 8,139 7,669 7,678 9 3/10/2023 Isolated 8/25/23 BEL25 8,254' 8,264' 7,791' 7,801' 10' 7/28/2022 Isolated 8/25/23 BEL26 8,281' 8,290' 7,818' 7,827' 9' 7/28/2022 Isolated 8/25/23 BEL27 8,358' 8,372' 7,894' 7,907' 14' 7/27/2022 Isolated 8/25/23 BEL27 8,414' 8,424' 7,949' 7,959' 10' 7/27/2022 Isolated 8/25/23 BEL28 8,483' 8,491' 8,017' 8,025' 8' 7/27/2022 Isolated 8/25/23 BEL28 8,504' 8,516' 8,037' 8,049' 12' 7/27/2022 Isolated 8/25/23 BEL29 8,625 8,635 8,157 8,166 10 6/19/2022 Isolated 7/26/22 BEL29 8,625 8,635 8,157 8,166 10 6/12/2022 Isolated 7/26/22 BEL29 8,643 8,648 8,173 8,179 5 6/19/2022 Isolated 7/26/22 BEL29 8,643 8,648 8,173 8,179 5 6/12/2022 Isolated 7/26/22 BEL29 8,653 8,659 8,184 8,190 6 6/19/2022 Isolated 7/26/22 BEL29 8,653 8,659 8,184 8,190 6 6/12/2022 Isolated 7/26/22 BEL29 8,687' 8,707' 8,218' 8,237' 20' 7/16/2022 Isolated 7/26/22 BEL29 8,690' 8,692' 8,221' 8,223' 2' 7/16/2022 Isolated 7/26/22 B30 8,740' 8,745' 8,270 8,275 5 6/11/2022 Isolated 7/26/22 B30 8,775' 8,781' 8,304 8,310 6 6/11/2022 Isolated 7/26/22 B31 8,812' 8,818' 8,341 8,347 6 6/11/2022 Isolated 7/26/22 B32 8,840' 8,849' 8,369 8,377 9 7/9/2022 Isolated 7/26/22 B32 8,840' 8,849' 8,369 8,377 9 6/11/2022 Isolated 7/26/22 B33 8,995' 9,004' 8,522 8,530 9 6/11/2022 Isolated 7/10/22 T0 9,148' 9,153' 8,672' 8,677' 5 6/1/2022 Isolated 6/8/22 T2 9,230' 9,242' 8,753' 8,765' 12 6/1/2022 Isolated 6/8/22 T4 9,337' 9,347' 8,860' 8,868' 10 5/31/2022 Isolated 6/8/22 T4 9,380' 9,393' 8,901' 8,913' 13 5/31/2022 Isolated 6/8/22 T6 9,567' 9,575' 9,085' 9,093' 8 5/29/2022 Isolated 6/8/22 T7A 9,738' 9,758' 9,253' 9,273' 20 5/29/2022 Isolated 6/8/22 T7B 9,797' 9,817' 9,311' 9,328' 20 5/28/2022 Isolated 6/8/22 T11 10,116' 10,136' 9,625' 9,645' 20 5/28/2022 Isolated 6/8/22 T12 10,289' 10,308' 9,795' 9,813' 19 5/26/2022 Isolated 6/8/22 T12 10,289' 10,308' 9,795' 9,813' 19 5/27/2022 Isolated 6/8/22 Updated by RPL 11-06-2025 SCHEMATIC Proposed BCU 18RD API: 50-133-20584-01-00 PTD: 222-033 Pad-3 PBTD = 8,583 MD / 8,115 TVD TD = 10,461 MD / 9,964 TVD RKB to GL = 18.0 9 CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 20 Conductor 154.19 X-65 Weld 19.13 Surf 108 13-3/8" Surf Csg 68.0 K-55 BTC 12.415 Surf 2,097 9-5/8 Intermediate Csg 40.0 L-80 BTC 8.835 Surf 3,574 7 Intermediate Lnr 26.0 L-80 Vam Top 6.276 3,336 7,474 4-1/2" Prod Tieback 12.6 L-80 JFEBEAR 3.958 Surf 7,214 4-1/2" Prod Lnr 12.6 L-80 JFEBEAR 3.958 7,219 10,432 TUBING DETAIL 4-1/2 Tubing 12.6 L-80 Surface 7,214 1 20 13-3/8 4-1/2 JEWELRY DETAIL No. Depth ID Item 1 3,336 6.040 9-5/8 x 7 Liner hanger / LTP Assembly 2 3,574 NA Whipstock 3 +5,368 CIBP + 35 cement (Proposed) 3 5,429 CIBP (7/3/25) 4 5,577 CIBP (4/27/25) 5 5,600 CIBP (4/26/25) 6 6,235 CIBP + 54 Cement (4/19/25) TOC @ 6181 7 6,338 CIBP (2/28/25) 8 6,445 CIBP (2/25/25) 9 6,590 3-1/2 CIBP (9/9/23) 10 6,900 NA FH Cement retainer, Eline tagged cement on top @ 6852 PBTD 11 7,150 NA 4-1/2 CIBP (refence plug tag for cement retainer) 12 7,218 5.25 7 x 4-1/2 Liner hanger / LTP Assembly with PBR 13 7,214 3.890 Seal Stem 14 8,036 N/A 4-1/2 CIBP w/ 35 cement TOC 8001 (8/25/23) 15 8,620 N/A CIBP w/ 37 cement TOC @ 8,583 (7/26/22) 16 8,865 N/A CIBP w/ 5 cement TOC @ 8,860 (7/20/22) Additional 31 cement - TOC @ 8,829 (7/21/22) OPEN HOLE / CEMENT DETAIL 13-3/8 16 Hole: TOC @ Surface (Original BCU 18) 9-5/8" 12-1/4: Hole: TOC @ 3,440 (Original BCU 18) 7 8-1/2 Hole: 125bbls 12ppg lead followed by 18bbls 15.3ppg tail pumped on 5/1/22. 38bbls lead cement back to surface. 5/14/22 CBL shows ToC at 3570 MD 4-1/2 6-1/8 Hole: Pumped 30bbl spacer followed by 54bbls 12ppg Type I/II lead followed by 25bbls 15.3ppg Type I/II tail pumped on 5/11/22. Trace spacer back to surface. 5/19/22 CBL shows ToC at 7370 MD 4-1/2 Inside 7 Casing: Pump 48 bbls of cement through tubing punch @ ~7,100. TOC @ ~4,778 14 4 9-5/8 2 BCU 18 (Abandoned) 13 7 PERFORATION DETAIL Zone Top MD Btm MD TopTVD Btm TVD Amt Date Comments ST C6 +4,979 +4,985 ±4,606' ±4,611' ±6' Proposed Proposed ST B3L 5,418 5,428 5,092' 5,101' 10' 7/5/2025 Isolate ST B4 5,504 5,521 5,171' 5,186' 17' 6/27/2025 Isolated 7/3/25 ST B5 5,565 5,570 5,227' 5,231' 5' 4/27/2025 Isolated 7/3/25 ST B5 5,579 5,585 5,239' 5,245' 6' 4/26/2025 Isolated 4/27/25 ST B6 5,604 5,614 5,262' 5,272' 10' 4/24/2025 Isolated 4/26/25 BEL5 6,285' 6,305' 5,890' 5,909' 20' 2/28/2025 Isolated 4/19/25 BEL6 6,342 6,348 5,942 5,947 6 9/9/2023 Isolated 2/28/25 BEL6 6,342 6,348 5,942 5,947 6 2/26/2025 Isolated 2/28/25 BEL6 6,354 6,361 5,953 5,960 7 9/9/2023 Isolated 2/28/25 BEL6 6,356 6,362 5,955 5,961 6 2/26/2025 Isolated 2/28/25 BEL6 6,366 6,375 5,964 5,972 9 9/9/2023 Isolated 2/28/25 BEL6 6,366 6,375 5,964 5,972 9 2/26/2025 Isolated 2/28/25 BEL7 6,384' 6,404' 5,981' 5,999' 20' 2/27/2025 Isolated 2/28/25 BEL7 6,453 6,467 6,044 6,055 14 9/9/2023 Isolated 1/27/25 PERFORATION DETAIL continued on following page BEL 29-32 T0 T12 17 BEL 33 FISH DETAILs: Failed WRP at 8867 ELMD (7/10/22) & Fish left from 8,785-8,829ft - 35ft 3.5"OD cement bailer, 2ft CCL, 7ft 2" weight bar (7/21/22) 16 BEL 25-28 BEL 22-23 Tubing Punch at ~7,100 TOC @ 4,778 CBL 9/4/23 15 11 9.5 ppg brine 12 10 8 Tubing Patch 6,450-6,471 1/27/25 BEL 5 BEL 6-9 ST B6 7 5 6 ST B5 4 ST B3L-B4 ST C6 3 Updated by RPL 11-06-2025 SCHEMATIC Proposed BCU 18RD API: 50-133-20584-01-00 PTD: 222-033 Pad-3 PERFORATION DETAIL continued from previous page Zone Top MD Btm MD TopTVD Btm TVD Amt Date Comments BEL8 6,516' 6,526' 6,103' 6,112' 10' 2/25/2025 Isolated 2/25/25 BEL8 6,533' 6,543' 6,118' 6,128' 10' 2/24/2025 Isolated 2/25/25 BEL8 6,549' 6,563' 6,133' 6,146' 14' 2/24/2025 Isolated 2/25/25 BEL8 6,601 6,620 6,181 6,196 19 9/6/2023 Isolated 9/9/23 BEL9 6,660 6,668 6,235 6,242 8 9/6/2023 Isolated 9/9/23 BEL22 8,086 8,106 7,626 7,646 41 3/10/2023 Isolated 8/25/23 BEL23 8,130 8,139 7,669 7,678 9 3/10/2023 Isolated 8/25/23 BEL25 8,254' 8,264' 7,791' 7,801' 10' 7/28/2022 Isolated 8/25/23 BEL26 8,281' 8,290' 7,818' 7,827' 9' 7/28/2022 Isolated 8/25/23 BEL27 8,358' 8,372' 7,894' 7,907' 14' 7/27/2022 Isolated 8/25/23 BEL27 8,414' 8,424' 7,949' 7,959' 10' 7/27/2022 Isolated 8/25/23 BEL28 8,483' 8,491' 8,017' 8,025' 8' 7/27/2022 Isolated 8/25/23 BEL28 8,504' 8,516' 8,037' 8,049' 12' 7/27/2022 Isolated 8/25/23 BEL29 8,625 8,635 8,157 8,166 10 6/19/2022 Isolated 7/26/22 BEL29 8,625 8,635 8,157 8,166 10 6/12/2022 Isolated 7/26/22 BEL29 8,643 8,648 8,173 8,179 5 6/19/2022 Isolated 7/26/22 BEL29 8,643 8,648 8,173 8,179 5 6/12/2022 Isolated 7/26/22 BEL29 8,653 8,659 8,184 8,190 6 6/19/2022 Isolated 7/26/22 BEL29 8,653 8,659 8,184 8,190 6 6/12/2022 Isolated 7/26/22 BEL29 8,687' 8,707' 8,218' 8,237' 20' 7/16/2022 Isolated 7/26/22 BEL29 8,690' 8,692' 8,221' 8,223' 2' 7/16/2022 Isolated 7/26/22 B30 8,740' 8,745' 8,270 8,275 5 6/11/2022 Isolated 7/26/22 B30 8,775' 8,781' 8,304 8,310 6 6/11/2022 Isolated 7/26/22 B31 8,812' 8,818' 8,341 8,347 6 6/11/2022 Isolated 7/26/22 B32 8,840' 8,849' 8,369 8,377 9 7/9/2022 Isolated 7/26/22 B32 8,840' 8,849' 8,369 8,377 9 6/11/2022 Isolated 7/26/22 B33 8,995' 9,004' 8,522 8,530 9 6/11/2022 Isolated 7/10/22 T0 9,148' 9,153' 8,672' 8,677' 5 6/1/2022 Isolated 6/8/22 T2 9,230' 9,242' 8,753' 8,765' 12 6/1/2022 Isolated 6/8/22 T4 9,337' 9,347' 8,860' 8,868' 10 5/31/2022 Isolated 6/8/22 T4 9,380' 9,393' 8,901' 8,913' 13 5/31/2022 Isolated 6/8/22 T6 9,567' 9,575' 9,085' 9,093' 8 5/29/2022 Isolated 6/8/22 T7A 9,738' 9,758' 9,253' 9,273' 20 5/29/2022 Isolated 6/8/22 T7B 9,797' 9,817' 9,311' 9,328' 20 5/28/2022 Isolated 6/8/22 T11 10,116' 10,136' 9,625' 9,645' 20 5/28/2022 Isolated 6/8/22 T12 10,289' 10,308' 9,795' 9,813' 19 5/26/2022 Isolated 6/8/22 T12 10,289' 10,308' 9,795' 9,813' 19 5/27/2022 Isolated 6/8/22 STANDARD WELL PROCEDURE NITROGEN OPERATIONS 12/08/2015 FINAL v1 Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. 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 10,461 feet See Schematic feet true vertical 9,964 feet 6150 (fill) feet Effective Depth measured 5,429 feet N/A feet true vertical 5,102 feet N/A feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth) 4-1/2" 12.6# / L-80 7,214' MD 6,763' TVD Packers and SSSV (type, measured and true vertical depth) N/A N/A 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: Ryan Lemay, Operations Engineer 325-199 Sr Pet Eng: 7,500psi 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@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 108' 0 00 0 00 8 measured TVD 9-5/8" 8,430psi 7" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 222-033 50-133-20584-01-00 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: FEDA028083 Beaver Creek / Sterling Gas Beaver Creek Unit (BCU) 18RD Plugs Junk measured Length Intermediate Lnr Produciton 3,574' 4,138' 4,006' Casing Structural 3,350' 6,975' 4-1/2" 3,574' 7,474' 10,432' 9,936' 108'Conductor Surface Intermediate Csg 20" 13-3/8" 108' 2,097' 3,090psi 5,410psi 3,060psi 3,450psi 5,750psi 7,240psi 2,097' 1,038' Burst Collapse 1,500psi 1,950psi 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 8:21 am, Jul 21, 2025 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2025.07.18 17:44:49 - 08'00' Noel Nocas (4361) BJM 9/25/25 Page 1/2 Well Name: BCU-018RD Report Printed: 7/16/2025WellViewAdmin@hilcorp.com Alaska Weekly Report - Operations Wellbore API/UWI:50-133-20584-01-00 Field Name:Beaver Creek State/Province:ALASKA Permit to Drill (PTD) #:222-033 Sundry #:325-199 Rig Name/No: Jobs Actual Start Date:4/3/2025 End Date: Report Number 1 Report Start Date 4/19/2025 Report End Date 4/20/2025 Last 24hr Summary PTW/PJSM, MIRU YJOS, PT 250 / 3500 - good. Ran GPT to 6330' no tag, found FL @ 5640'. Set 3.50" CIBP @ 6235'. Dumped 25gals. cement on CIBP. Est. TOC 6196' Report Number 2 Report Start Date 4/20/2025 Report End Date 4/21/2025 Last 24hr Summary PTW/PJSM, SOS PT 250/4000. Pressure up tbg to 3144psi W/ 44.5K SCF (479 Gals.) at 11:16 hrs. Pressure stabilized at 21:00 hrs. **Start of 72 hr MIT @ 21:00 hrs 4/20/2025** Tubing pressure = 3124 psi IA pressure = 0 psi Report Number 3 Report Start Date 4/24/2025 Report End Date 4/25/2025 Last 24hr Summary PTW/PJSM. SITP 3,123 psi, IA 0 psi, OA 0 psi. MIRU Yellow Jacket E-line. P-test 250/2,500 psi. Tag TOC at 6,181.5'. Perforate ST B6 Sand (5,604' - 5,614') with well shut-in. Init SITP 1,437 psi, 15 min SITP 1,470 psi. SDFN. Turn well over to Prod Ops to flow test. **End of 72 hr MIT 08:45 hrs 4/24/25** Tubing pressure = 3123 psi IA pressure = 0 psi AOGCC representative Guy Cook witnessed cement plug tag and conclusion of 72 hr gas MIT test per approved Sundry. Report Number 4 Report Start Date 4/25/2025 Report End Date 4/26/2025 Last 24hr Summary PTW/PJSM. SITP 518 psi. Run GPT - FL at 1,870', tagged fill at 6,150.5'. SDFN. Turn well over to Prod Ops to flow test. Report Number 5 Report Start Date 4/26/2025 Report End Date 4/27/2025 Last 24hr Summary PTW/PJSM. SITP 580 psi. MIRU Fox N2 equip. PT N2 iron 250/4,000 psi. Pump 82,381 scf N2 to push fluid. SITP 1,815 psi. GIH with GPT and CIBP - fluid level at 5,608' (in perfs). Set CIBP at 5,600'. Bleed down SITP. Perforate ST B5 Sand (5,579' - 5,585') with well shut-in. Init SITP: 1,362 psi, 15 min: 1,410 psi. Turn well over to Prod Ops to flow test. SDFN. Report Number 6 Report Start Date 4/27/2025 Report End Date 4/28/2025 Last 24hr Summary PTW/PJSM. SITP 122 psi. Run GPT - FL at 990', tag fill at 5,587.5'. Pump 125,983 scf N2 to push fluid. SITP 2,420 psi. GIH with GPT and CIBP - no fluid. Set CIBP at 5,577'. SITP 1,784 psi. Bleed down SITP. Perforate ST B5 Sand (5,565' - 5,570') with well shut-in. Init SITP: 1,357 psi, 15 min: 1,669 psi. Turn well over to Prod Ops to flow test. SDFN. Report Number 7 Report Start Date 4/28/2025 Report End Date 4/29/2025 Last 24hr Summary PTW/PJSM. RDMO Yellow Jacket E-line. Release Fox N2. Report Number 8 Report Start Date 5/1/2025 Report End Date 5/1/2025 Last 24hr Summary MIRU slickline. PT lubricator 250 psi low / 2500 psi high. RIH w/ 2.5" x 4' DD bailer and tag at 5570'. RDMO slickline. Report Number 9 Report Start Date 5/31/2025 Report End Date 5/31/2025 Last 24hr Summary MIRU slickline. PT lubricator 250 psi low / 2500 high. RIH w/ 2.5" x 5' DD bailer. Tag at 5574'. POOH and bailer full of sand. RIH w/ same and bail sand 5574' - 5577.' POOH and markings on bottom of bailer confirmed bailed down to top of CIBP at 5577'. RDMO slickline. Well ready for cap string installation. Report Number 10 Report Start Date 6/10/2025 Report End Date 6/11/2025 Last 24hr Summary PTW, JSA. MIRU Hilcorp Capillary tubing unit. Load new spool of 3/8" SS capillary tubing (7000'). Stab pipe into injector head chains. Install pack off assembly. Make up foot valve with an opening pressure of 1500 psi. Stab on well. PT pack off and bowen wellhead adapter to 250/3500 psi. RIH weight at 5200' & 750 lbs. PU weight at 5560' 1400 lbs. PU to 5550' and set cap string. Close static pack off elements. Pressure up dynamic pack off elements and lock in with 2500 psi. Install 3/8" tubing hanger and anti lift bars. Strip off injector head and set on back deck. Break down injector head and remove 3/8" SS tubing. Pick and set wooden spool next to pump skid. Rig up skid and bring online with foamer/soap. Rig down cap string truck and park on edge of pad. Report Number 11 Report Start Date 6/23/2025 Report End Date 6/24/2025 Last 24hr Summary PTW, JSA. Spot in cap string truck. Rig up. Install wooden spool of 3/8" SS cap string tubing into spooler. Work 3/8" cap string tubing into injector head and reinstall plates and hydraulic cylinder. Strip tubing and stab onto pack off assembly. Remove 3/8" tubing hanger and back off manual/static lock down screws. Increase dynamic pack off pressure to 200 psi. Pick up on cap string 1700 lbs moving freely. POOH with 5550' of tubing. Close swab 23.5 turns. Foot valve recovered. All components inspected and within service limits. Set injector on stand and rig down cap string truck. Manual soap launcher installed as night cap. PTW/PJSM. SITP 3,123 psi, IA 0 psi, OA 0 psi. MIRU Yellow Jacket E-line. P-test 250/2,500 psi. Tag TOC at 6,181.5'. Perforate ST B6 Sand (5,604' - 5,614') with AOGCC representative Guy Cook witnessed cement plug tag and conclusion of 72 hr gas MIT test per approved Sundry. PTW/PJSM. SITP 580 psi. MIRU Fox N2 equip. PT N2 iron 250/4,000 psi. Pump 82,381 scf N2 to push fluid. SITP 1,815 psi. GIH with 5,608' (in perfs). Set CIBP at 5,600'. Bleed down SITP. Perforate ST B5 Sand (5,579' - 5,585') with well shut-in. Init SITP: 1, PTW/PJSM, MIRU YJOS, PT 250 / 3500 - good. Ran GPT to 6330' no tag, found FL @ 5640'. Set 3.50" CIBP @ 6235'. Dumped 25gals. cement on CIBP. Est. TOC PTW/PJSM. SITP 122 psi. Run GPT - FL at 990', tag fill at 5,587.5'. Pump 125,983 scf N2 to push fluid. SITP 2,420 psi. GIH with CIBP at 5,577'. SITP 1,784 psi. Bleed down SITP. Perforate ST B5 Sand (5,565' - 5,570') with well shut-in. Init SITP: 1,357 psi PTW/PJSM. SITP 122 psi. Run GPT - FL at 990', tag fill at 5,587.5'. Pump 125,983 scf N2 to push fluid. SITP 2,420 psi. GIH with CIBP at 5,577'. SITP 1,784 psi. Bleed down SITP. Perforate ST B5 Sand (5,565' - 5,570') with well shut-in. Init SITP: 1,357 psi PTW/PJSM. SITP 580 psi. MIRU Fox N2 equip. PT N2 iron 250/4,000 psi. Pump 82,381 scf N2 to push fluid. SITP 1,815 psi. GIH with 5,608' (in perfs). Set CIBP at 5,600'. Bleed down SITP. Perforate ST B5 Sand (5,579' - 5,585') with well shut-in. Init SITP: 1, Page 2/2 Well Name: BCU-018RD Report Printed: 7/16/2025WellViewAdmin@hilcorp.com Alaska Weekly Report - Operations Report Number 12 Report Start Date 6/27/2025 Report End Date 6/28/2025 Last 24hr Summary PTW/PJSM. MIRU Yellow Jacket E-line. PU lub and MU tools. PT 250 psi / 2,500 psi. Perforate ST B4 Sand (5,504' - 5,521') with well shut-in. Guns jumped uphole when shot. Line got stuck in the flow tubes while attempting to bump up. Bled pressure and pumped prod water until SITP 0 psi. Got off well, recovered tools, and secured well. Found line was kinked. SDFN. Report Number 13 Report Start Date 6/28/2025 Report End Date 6/29/2025 Last 24hr Summary PTW/PJSM. SITP 0 psi. Run 3.625" GR/JB - tag at 5,412'. RDMO Yellow Jacket E-line. Report Number 14 Report Start Date 6/29/2025 Report End Date 6/30/2025 Last 24hr Summary PTW/PJSM. SITP 0 psi. MIRU Pollard slickline. PT 250/2,500 psi. Bail from 5,418' KB to 5,445' KB. SDFN. Bail from 5,418' KB to 5,441'. Fill is hard packed and very sticky. Report Number 15 Report Start Date 7/1/2025 Report End Date 7/2/2025 Last 24hr Summary PTW/PJSM. SITP 477 psi. MIRU Yellowjacket E-line. PT lubricator to 250 psi low / 2,500 psi high - good test. RIH w/ CIBP and tag fill @ 5,421' (18' high). POOH and RDMO YJ. Report Number 16 Report Start Date 7/2/2025 Report End Date 7/3/2025 Last 24hr Summary PTW/PJSM. SITP 433 psi. MIRU Pollard Slickline. PT lubricator to 250 psi low / 2,500 psi high - good test. Bail fill from 5,433' to 5,445' RKB in 9 runs recovering full bailers of packed sand/clay, and mud slurry. Secure well, SDFN. Report Number 17 Report Start Date 7/3/2025 Report End Date 7/4/2025 Last 24hr Summary PTW/PJSM. SITP 208 psi. RU Pollard Slickline. Bail fill from 5,445' to 5,447' RKB SLM in 3 runs. Tag @ 5,444' SLM w/ 3.75" GR. RU YJ E-line. PT lubricator to 250 psi low - 2500 psi high, good test. RIH w/ CIBP and set @ 5,429.5' and confirm set w/ tag. RD YJ and RU Pollard. Swab fluid from 350' to 4,000'. Recovered 53 of 77 calculated bbls. Secure well, SDFN. Report Number 18 Report Start Date 7/4/2025 Report End Date 7/5/2025 Last 24hr Summary PTW/PJSM. SITP 0 psi. RU Pollard Slickline. Swab fluid from 4,000' to 5,400' tagging CIBP @ 5,429.5'. Total recovery 75 of 77 bbls calculated. RDMO Pollard, MIRU Fox N2. PT lines to 2500 psi - good test. Pump N2 and pressure up well to 1600 psi and trap on well. RDMO Fox N2. Report Number 19 Report Start Date 7/5/2025 Report End Date 7/6/2025 Last 24hr Summary PTW/PJSM. SITP 1595 psi N2. RU YJ E-line. PT lubricator to 250 psi low - 2500 psi high, good test. RIH w/ 10' x 2 3/4" 6 SPF 60 deg guns, tag CIBP @ 5,429.5' and perf ST B3L (5,418 5,428). Bleed N2 @ 5-10 psi/min from 1617 psi to 100 psi and started seeing LEL's. Shut in @ 70 psi. Secure well, RDMO YJ E-line. PTW/PJSM. MIRU Yellow Jacket E-line. PU lub and MU tools. PT 250 psi / 2,500 psi. Perforate ST B4 Sand (5,504' - 5,521') with w PTW/PJSM. SITP 208 psi. RU Pollard Slickline. Bail fill from 5,445' to 5,447' RKB SLM in 3 runs. Tag @ 5,444' SLM w/ 3.75" GR. 250 psi low - 2500 psi high, good test. RIH w/ CIBP and set @ 5,429.5' and confirm set w/ tag. RD YJ and RU Pollard. Swab fl PTW/PJSM. SITP 1595 psi N2. RU YJ E-line. PT lubricator to 250 psi low - 2500 psi high, good test. RIH w/ 10' x 2 3/4" 6 SPF and perf ST B3L (5,418 5,428). Bleed N2 @ 5-10 psi/min from 1617 psi to 100 psi and started seeing LEL's. Shut in @ 70 ps Updated by DMA 07-16-25 SCHEMATIC BCU 18RD API: 50-133-20584-01-00 PTD: 222-033 Pad-3 PBTD = 8,583 MD / 8,115 TVD TD = 10,461 MD / 9,964 TVD RKB to GL = 18.0 8 CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 20 Conductor 154.19 X-65 Weld 19.13 Surf 108 13-3/8" Surf Csg 68.0 K-55 BTC 12.415 Surf 2,097 9-5/8 Intermediate Csg 40.0 L-80 BTC 8.835 Surf 3,574 7 Intermediate Lnr 26.0 L-80 Vam Top 6.276 3,336 7,474 4-1/2" Prod Tieback 12.6 L-80 JFEBEAR 3.958 Surf 7,214 4-1/2" Prod Lnr 12.6 L-80 JFEBEAR 3.958 7,219 10,432 TUBING DETAIL 4-1/2 Tubing 12.6 L-80 Surface 7,214 1 20 13-3/8 4-1/2 JEWELRY DETAIL No. Depth ID Item 1 3,336 6.040 9-5/8 x 7 Liner hanger / LTP Assembly 2 3,574 NA Whipstock 3 5,429 CIBP (7/3/25) 4 5,577 CIBP (4/27/25) 5 5,600 CIBP (4/26/25) 6 6,235 CIBP + 54 Cement (4/19/25) TOC @ 6181 7 6,338 CIBP (2/28/25) 8 6,445 CIBP (2/25/25) 9 6,590 3-1/2 CIBP (9/9/23) 10 6,900 NA FH Cement retainer, Eline tagged cement on top @ 6852 PBTD 11 7,150 NA 4-1/2 CIBP (refence plug tag for cement retainer) 12 7,218 5.25 7 x 4-1/2 Liner hanger / LTP Assembly with PBR 13 7,214 3.890 Seal Stem 14 8,036 N/A 4-1/2 CIBP w/ 35 cement TOC 8001 (8/25/23) 15 8,620 N/A CIBP w/ 37 cement TOC @ 8,583 (7/26/22) 16 8,865 N/A CIBP w/ 5 cement TOC @ 8,860 (7/20/22) Additional 31 cement - TOC @ 8,829 (7/21/22) OPEN HOLE / CEMENT DETAIL 13-3/8 16 Hole: TOC @ Surface (Original BCU 18) 9-5/8" 12-1/4: Hole: TOC @ 3,440 (Original BCU 18) 7 8-1/2 Hole: 125bbls 12ppg lead followed by 18bbls 15.3ppg tail pumped on 5/1/22. 38bbls lead cement back to surface. 5/14/22 CBL shows ToC at 3570 MD 4-1/2 6-1/8 Hole: Pumped 30bbl spacer followed by 54bbls 12ppg Type I/II lead followed by 25bbls 15.3ppg Type I/II tail pumped on 5/11/22. Trace spacer back to surface. 5/19/22 CBL shows ToC at 7370 MD 4-1/2 Inside 7 Casing: Pump 48 bbls of cement through tubing punch @ ~7,100. TOC @ ~4,778 13 4 9-5/8 2 BCU 18 (Abandoned) 12 7 PERFORATION DETAIL Zone Top MD Btm MD TopTVD Btm TVD Amt Date Comments ST B3L 5,418 5,428 5,092' 5,101' 10' 7/5/2025 Open ST B4 5,504 5,521 5,171' 5,186' 17' 6/27/2025 Isolated 7/3/25 ST B5 5,565 5,570 5,227' 5,231' 5' 4/27/2025 Isolated 7/3/25 ST B5 5,579 5,585 5,239' 5,245' 6' 4/26/2025 Isolated 4/27/25 ST B6 5,604 5,614 5,262' 5,272' 10' 4/24/2025 Isolated 4/26/25 BEL5 6,285' 6,305' 5,890' 5,909' 20' 2/28/2025 Isolated 4/19/25 BEL6 6,342 6,348 5,942 5,947 6 9/9/2023 Isolated 2/28/25 BEL6 6,342 6,348 5,942 5,947 6 2/26/2025 Isolated 2/28/25 BEL6 6,354 6,361 5,953 5,960 7 9/9/2023 Isolated 2/28/25 BEL6 6,356 6,362 5,955 5,961 6 2/26/2025 Isolated 2/28/25 BEL6 6,366 6,375 5,964 5,972 9 9/9/2023 Isolated 2/28/25 BEL6 6,366 6,375 5,964 5,972 9 2/26/2025 Isolated 2/28/25 BEL7 6,384' 6,404' 5,981' 5,999' 20' 2/27/2025 Isolated 2/28/25 BEL7 6,453 6,467 6,044 6,055 14 9/9/2023 Isolated 1/27/25 BEL8 6,516' 6,526' 6,103' 6,112' 10' 2/25/2025 Isolated 2/25/25 BEL8 6,533' 6,543' 6,118' 6,128' 10' 2/24/2025 Isolated 2/25/25 BEL8 6,549' 6,563' 6,133' 6,146' 14' 2/24/2025 Isolated 2/25/25 BEL8 6,601 6,620 6,181 6,196 19 9/6/2023 Isolated 9/9/23 PERFORATION DETAIL continued on following page BEL 29-32 T0 T12 16 BEL 33 FISH DETAILs: Failed WRP at 8867 ELMD (7/10/22) & Fish left from 8,785-8,829ft - 35ft 3.5"OD cement bailer, 2ft CCL, 7ft 2" weight bar (7/21/22) 15 BEL 25-28 BEL 22-23 Tubing Punch at ~7,100 TOC @ 4,778 CBL 9/4/23 14 10 9.5 ppg brine 11 9 7 Tubing Patch 6,450-6,471 1/27/25 BEL 5 BEL 6-9 ST B6 6 4 5 ST B5 3 ST B3L-B4 Updated by DMA 07-16-25 SCHEMATIC BCU 18RD API: 50-133-20584-01-00 PTD: 222-033 Pad-3 PERFORATION DETAIL continued from previous page Zone Top MD Btm MD TopTVD Btm TVD Amt Date Comments BEL9 6,660 6,668 6,235 6,242 8 9/6/2023 Isolated 9/9/23 BEL22 8,086 8,106 7,626 7,646 41 3/10/2023 Isolated 8/25/23 BEL23 8,130 8,139 7,669 7,678 9 3/10/2023 Isolated 8/25/23 BEL25 8,254' 8,264' 7,791' 7,801' 10' 7/28/2022 Isolated 8/25/23 BEL26 8,281' 8,290' 7,818' 7,827' 9' 7/28/2022 Isolated 8/25/23 BEL27 8,358' 8,372' 7,894' 7,907' 14' 7/27/2022 Isolated 8/25/23 BEL27 8,414' 8,424' 7,949' 7,959' 10' 7/27/2022 Isolated 8/25/23 BEL28 8,483' 8,491' 8,017' 8,025' 8' 7/27/2022 Isolated 8/25/23 BEL28 8,504' 8,516' 8,037' 8,049' 12' 7/27/2022 Isolated 8/25/23 BEL29 8,625 8,635 8,157 8,166 10 6/19/2022 Isolated 7/26/22 BEL29 8,625 8,635 8,157 8,166 10 6/12/2022 Isolated 7/26/22 BEL29 8,643 8,648 8,173 8,179 5 6/19/2022 Isolated 7/26/22 BEL29 8,643 8,648 8,173 8,179 5 6/12/2022 Isolated 7/26/22 BEL29 8,653 8,659 8,184 8,190 6 6/19/2022 Isolated 7/26/22 BEL29 8,653 8,659 8,184 8,190 6 6/12/2022 Isolated 7/26/22 BEL29 8,687' 8,707' 8,218' 8,237' 20' 7/16/2022 Isolated 7/26/22 BEL29 8,690' 8,692' 8,221' 8,223' 2' 7/16/2022 Isolated 7/26/22 B30 8,740' 8,745' 8,270 8,275 5 6/11/2022 Isolated 7/26/22 B30 8,775' 8,781' 8,304 8,310 6 6/11/2022 Isolated 7/26/22 B31 8,812' 8,818' 8,341 8,347 6 6/11/2022 Isolated 7/26/22 B32 8,840' 8,849' 8,369 8,377 9 7/9/2022 Isolated 7/26/22 B32 8,840' 8,849' 8,369 8,377 9 6/11/2022 Isolated 7/26/22 B33 8,995' 9,004' 8,522 8,530 9 6/11/2022 Isolated 7/10/22 T0 9,148' 9,153' 8,672' 8,677' 5 6/1/2022 Isolated 6/8/22 T2 9,230' 9,242' 8,753' 8,765' 12 6/1/2022 Isolated 6/8/22 T4 9,337' 9,347' 8,860' 8,868' 10 5/31/2022 Isolated 6/8/22 T4 9,380' 9,393' 8,901' 8,913' 13 5/31/2022 Isolated 6/8/22 T6 9,567' 9,575' 9,085' 9,093' 8 5/29/2022 Isolated 6/8/22 T7A 9,738' 9,758' 9,253' 9,273' 20 5/29/2022 Isolated 6/8/22 T7B 9,797' 9,817' 9,311' 9,328' 20 5/28/2022 Isolated 6/8/22 T11 10,116' 10,136' 9,625' 9,645' 20 5/28/2022 Isolated 6/8/22 T12 10,289' 10,308' 9,795' 9,813' 19 5/26/2022 Isolated 6/8/22 T12 10,289' 10,308' 9,795' 9,813' 19 5/27/2022 Isolated 6/8/22 MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg DATE: P.I. Supervisor SUBJECT: FROM: Petroleum Inspector Section: 34 Township: 7N Range: 10W Meridian: Seward Drilling Rig: n/a Rig Elevation: n/a Total Depth: 10461 ft MD Lease No.: FEDA028083 Operator Rep: Suspend: P&A: X Conductor: 20" O.D. Shoe@ 108 Feet Csg Cut@ Feet Surface: 13 3/8" O.D. Shoe@ 2097 Feet Csg Cut@ Feet Intermediate: 9 5/8" O.D. Shoe@ 3574 Feet Csg Cut@ Feet Interm. Liner: 7" O.D. Shoe@ 7474 Feet Csg Cut@ Feet Production 4.5" O.D. Shoe@ 10432 Feet Csg Cut@ Feet Tubing: 4.5" O.D. Tail@ 7214 Feet Tbg Cut@ Feet Type Plug Founded on Depth (Btm) Depth (Top) MW Above Verified Perforation Bridge plug 6235 ft 6181 ft 15.8 ppg Wireline tag 4/20/25 1150 4/21/25 1200 4/22/25 1200 4/23/25 1200 4/24/225 0830 Initial 24 hrs 48 hrs 72 hrs 87 hrs Result Tubing 3139 3123 3123 3124 3123 IA 0 0000 OA 0 0000 Initial 15 min 30 min 45 min Result Tubing IA OA Remarks: Attachments: Upon arrival I verified the pressure for the 72 hour N2 MIT was T/IA/OA = 3123/0/0. At the time I verified the pressure they had been holding the pressure on the tubing for approximately 92 hours. They started timing the test at the pressures of 3139/0/0 at 11:50 am on 4/20/25 (pressures noted in the Test Data section except for those observed at end of test are dervied from the Crystal gauge chart). They tagged cement at 6181 ft MD and got a good sample of hard cement ( 54 ft of cement on top of the bridge plug). The tool string for the E-line unit was 21 ft closed and approximately 200 pounds including the 2.5-inch drive down bailer with mule shoe and a flapper on the bottom of the tool string. April 24, 2025 Guy Cook Well Bore Plug & Abandonment BCU 18RD Hilcorp Alaska LLC PTD 2220330; Sundry 325-199 MITT Chart Test Data: P Casing Removal: Trevor Williams Casing/Tubing Data (depths are MD): Plugging Data (depths are MD): rev. 3-24-2022 2025-0424_Plug_Verification_BCU-18RD_gc 9 9 9 9 9 9 99 9 9 9 9 9 9 9 99 9 9 9 9 9 999 9 9 9 &KDUWLVVXEVHWRI&U\VWDOUHFRUGLQJJDXJHGDWHIURP+LOFRUSFKDUWHGSURYLGHGZLWKGDWDGLGQRWPDWFKWKHUDZGDWD H[WUDFWHGSUHVVXUHVDWPLQXWHLQFUHPHQWVDQGUHSORWWHG0D[DOORZHGSUHVVXUHORVVGXULQJKRXUWHVWZDVVHWLQ DSSURYHGVXQGU\DW$GGHGWKHWRWKHFKDUWWKHWRWDOSUHVVXUHORVV-5HJJ James B. Regg Digitally signed by James B. Regg Date: 2025.05.08 14:15:57 -08'00' Beaver Creek Unit 18RD (PTD )Subset of Crystal Gauge Data (30min Increments)jbr; 5/8/20250.000%0.500%1.000%1.500%2.000%2.500%3100.03110.03120.03130.03140.03150.00.002.004.006.008.0010.0012.0014.0016.0018.0020.0022.0024.0026.0028.0030.0032.0034.0036.0038.0040.0042.0044.0046.0048.0050.0052.0054.0056.0058.0060.0062.0064.0066.0068.0070.0072.0074.0076.0078.0080.0082.0084.0086.0088.0090.0092.0094.00% Total Pressure LossTubing Pressure (psi)Test Duration (hrs)BCU 18RD MITTTubing Pressure (psi)% Total LossPD[DOORZHGSUHVVXUHORVVGXULQJKUWHVWLVMEU CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:McLellan, Bryan J (OGC) To:Ryan Lemay Cc:James Ostroot - (C); Donna Ambruz Subject:RE: Program Change Request / Hilcorp / BCU-18RD / PTD: 222-033 / Sundry Number: 325-199 Date:Tuesday, July 1, 2025 10:55:00 AM Approved. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Ryan Lemay <Ryan.Lemay@hilcorp.com> Sent: Tuesday, July 1, 2025 9:45 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: James Ostroot - (C) <James.Ostroot@hilcorp.com>; Donna Ambruz <dambruz@hilcorp.com> Subject: Program Change Request / Hilcorp / BCU-18RD / PTD: 222-033 / Sundry Number: 325-199 Good morning Bryan, Hilcorp Beaver Creek BCU-18RD PTD: 222-033 Sundry Number: 325-199 Brief Summary of Operations Performed Under Current Sundry: Steps 1-6 of the approved Sundry were successfully completed with Guy Cook witness CIBP set 6235’ with cement dump bailed to 6181’ and 72 hour gas test completed. We have perfed up to the ST_B4 interval (5504’-5521’) detailed in step 7 of the procedure. CIBP set at 5600’ per step 7.e.i after perforating ST_B6 (5604’-5614’) due to zone being wet and no sustained gas production. CIBP set at 5577’ per step 7.e.i after perforating ST_B5 (5579’-5585’) due to zone being wet and no sustained gas production. Perforated ST_B5 (5565’ – 5570’). Put on production briefly making 1 mmfcd but quickly declined to 150-200 mcfd with increased water production. Received program change approval to install capstring in efforts to optimize gas production rate with water production. The cap string was installed and did not yield an increase in gas production as hoped. The cap string was removed to add additional Sundried perforations. Perforated ST_B4 (5504’-5521’). Zone brought in water and sand / fill with no gas production. Tagged high on sand / fill after perforating at 5412’. Slickline bailed fill from 5412’ – 5445’ before progress slowed significantly and struggling to make additional footage. Program Change Request: AOGCC regulations state a CIBP must be set within 50’ of open perforations Hilcorp is requesting to set CIBP to isolate ST_B4 (5504’-5521’) at + 5438’ (66’ above perforations) due to fill in wellbore Cement is not planned to be placed on top of CIBP at + 5438’ per step 7.e.i of the approved Sundry procedure due to close proximity of planned next perforation zone Resume approved Sundry perforating ST_B3L sand (5418’-5428’) Please let me know if you have any questions or need any additional information for this request. Have a great day Ryan LeMay Operations Engineer Swanson River / Beaver Creek Cell: (661) 487-0871 E-mail: Ryan.lemay@hilcorp.com The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:McLellan, Bryan J (OGC) To:Ryan Lemay Cc:Donna Ambruz Subject:RE: Hilcorp / Beaver Creek / BCU-18RD / PTD 222-033 / Sundry Number: 325-199 / Program Change Request Date:Monday, May 19, 2025 11:55:00 AM Ryan, Hilcorp has approval to install the capillary string as part of this sundry on the condition that you pressure test the lubricator system to a least MPSP before deploying below the master valve. Thank you Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Ryan Lemay <Ryan.Lemay@hilcorp.com> Sent: Monday, May 19, 2025 10:38 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com> Subject: Hilcorp / Beaver Creek / BCU-18RD / PTD 222-033 / Sundry Number: 325-199 / Program Change Request Good morning Bryan, Perforations have been added up to the ST B5 interval (5565’ – 5570’ MD) per the approved Sundry procedure attached on BCU-18RD. The well was brought on production after this last set of perforations were added on 4/27/2025. The well briefly came on at ~1mmcfd / 700 psi FTP before quickly declining and began producing water with gas. The well is currently doing ~360 mcfd / 316 psi FTP / 22 bbls water per day as of 5/18/2025 We are having to drop soap sticks down the well every 4-6 hours to keep the well unloaded and sustain a gas rate. Program Change Request: Hilcorp is requesting a program change / addition to the approved Sundry to install a 3/8” capillary string for a more consistent soaping delivery to optimize gas production on this well. 3/8” capillary string would be set near top of perforations at + 5560’ MD Please let me know if you approve of this program change to the currently approved Sundry. Thanks and have a great day, Ryan LeMay Operations Engineer Swanson River / Beaver Creek Cell: (661) 487-0871 E-mail: Ryan.lemay@hilcorp.com The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: N2 2. Operator Name:4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number):10. Field: 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 10,461'N/A Casing Collapse Structural Conductor 1,500psi Surface 1,950psi Intermediate Csg 3,090psi Intermediate Lnr 5,410psi 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 9,964'~1,793psi 4,006' 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Beaver Creek Unit (BCU) 18RDCO 237D Sterling Gas 9,936' 3,350'5,750psi 7" 6,338'5,938'See Schematic Length April 14, 2025 4-1/2" Size See Schematic 7,240psi 3,060psi 3,450psi 108' 4-1/2" 4,138' 2,097' BurstMD 3,574' 8,430psi 108' 6,975' 20" 13-3/8" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEDA028083 10,432' Hilcorp Alaska, LLC Proposed Pools: Beaver Creek 9-5/8" 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Beluga Gas 108' Tubing MD (ft):Perforation Depth TVD (ft): Subsequent Form Required: 2,097' 7,474' 50-133-20584-01-00 Tubing Size: PRESENT WELL CONDITION SUMMARY 2,038' 3,574' 222-033 Current Pools: MPSP (psi):Plugs (MD): TVD Tubing Grade: ryan.lemay@hilcorp.com Perforation Depth MD (ft): Will perfs require a spacing exception due to property boundaries? 661-487-0871 AOGCC USE ONLY Noel Nocas, Operations Manager 907-564-5278 Suspension Expiration Date: Ryan Lemay, Operations Engineer See Schematic N/A; N/A N/A; N/A 12.6# / L-80 7,214' Authorized Name and Digital Signature with Date: m n P s t 2 N 66 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 1:32 pm, Apr 02, 2025 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2025.04.02 11:25:18 - 08'00' Noel Nocas (4361) 325-199 Perforate New Pool P Provide 24 hrs notice for AOGCC opportunity to witness cement plug tag and the some period in the final 24 hrs of the pressure test with gas. BJM 4/16/25 X 10-404 DSR-4/2/25SFD 4/16/2025*&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.04.17 10:48:25 -08'00' 04/17/25 RBDMS JSB 042125 Well Prognosis Well: BCU-18RD Well Name: BCU-18RD API Number: 50-133-20584-01-00 Current Status: Offline Gas Producer Permit to Drill Number: 222-033 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: 2320 psi @ 5272’ TVD Based on 0.44 psi/ft Max. Potential Surface Pressure: 1793 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 9-5/8” int. casing shoe Shallowest Allowable Perf TVD: MPSP/(0.70-0.1) = 1793 psi / 0.60 = 2988‘ TVD Top of Applicable Gas Pool(s): 6221’ MD / 5830’ TVD (Beluga) Top of Applicable Gas Pool(s): 5153’ MD / 4850’ TVD (Sterling) Top of Applicable PA: 2707’ MD / 2583’ TVD (Sterling Gas PA) Well Status: Offline Gas producer Brief Well Summary Well work was completed 12/30/24 - 2/28/25 to add additional Beluga perforations in the Beluga 8,7, & 5 sands. Perforations added did not yield sustained gas production. The purpose of this Sundry is to isolate current Beluga perforations and add up to 58’ of perforations in the Sterling B3L – B6 intervals. Procedure: 1. MIRU E-line unit 2. PT lubricator 250 psi low / 2500 psi high 3. Determine fluid level and push fluid away through open perforations (6285’ – 6305’ MD) with N2 as necessary. 4. RIH and set CIBP @ + 6235’ MD 5. Dump bail minimum of 35’ of cement to + 6200’ MD 6. RIH, tag TOC, and pressure test w/ N2 to 2500 psi a. Use a chart recorder or digital crystal gauge monitor for a minimum of 72 hours b. Criteria for a passing test being a time of 72 hours showing stabilization and less than 2% drop of the maximum test pressure over the 72 hour test period. c. IA pressure must be monitored over the duration of the test period. d. 72 hour test will start once pressure stabilizes e. Provide a minimum of 24 hr notice to AOGCC for witness of tag and pressure test. Well Prognosis Well: BCU-18RD 7. Perforate the following intervals with 2-7/8” 60 degree phased 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 Well Sand Top MD Btm MD Top TVD Btm TVD Interval BCU-18RD ST B3L ±5,418’ ±5,428’ ±5,092' ±5,101' ±10' BCU-18RD ST B3L ±5,441’ ±5,451’ ±5,113' ±5,122' ±10' BCU-18RD ST B4 ±5,504’ ±5,521’ ±5,171' ±5,186' ±17' BCU-18RD ST B5 ±5,565’ ±5,570’ ±5,227' ±5231' ±5' BCU-18RD ST B5 ±5,579’ ±5,585’ ±5,239' ±5,245' ±6' BCU-18RD ST B6 ±5,604’ ±5,614’ ±5,262' ±5,272' ±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 to pressure up well during perforating or to depress water prior to setting a plug above perforations. 8. 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, 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 as necessary. Attachments: 1. Current Schematic 2. Proposed Schematic 3. Coil Tubing BOP Schematic 4. Standard Well Procedure – N2 Operations Updated by RPL 03-17-25 SCHEMATIC BCU 18RD API: 50-133-20584-01-00 PTD: 222-033 Pad-3 PBTD = 8,583’ MD / 8,115’ TVD TD = 10,461’ MD / 9,964’ TVD RKB to GL = 18.0’ 4 CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 20” Conductor 154.19 X-65 Weld 19.13” Surf 108’ 13-3/8" Surf Csg 68.0 K-55 BTC 12.415” Surf 2,097’ 9-5/8” Intermediate Csg 40.0 L-80 BTC 8.835” Surf 3,574’ 7” Intermediate Lnr 26.0 L-80 Vam Top 6.276” 3,336’ 7,474’ 4-1/2" Prod Tieback 12.6 L-80 JFEBEAR 3.958” Surf 7,214’ 4-1/2" Prod Lnr 12.6 L-80 JFEBEAR 3.958” 7,219’ 10,432’ TUBING DETAIL 4-1/2” Tubing 12.6 L-80 Surface 7,214’ 1 20” 13-3/8” 4-1/2” JEWELRY DETAIL No. Depth ID Item 1 3,336’ 6.040” 9-5/8” x 7” Liner hanger / LTP Assembly 2 3,574’ NA Whipstock 3 6,338’ CIBP (2/28/25) 4 6,445’ CIBP (2/25/25) 5 6,590’ 3-1/2” CIBP (9/9/23) 6 6,900’ NA FH Cement retainer, Eline tagged cement on top @ 6852’ PBTD 7 7,150’ NA 4-1/2” CIBP (refence plug tag for cement retainer) 8 7,218’ 5.25” 7” x 4-1/2” Liner hanger / LTP Assembly with PBR 9 7,214’ 3.890” Seal Stem 10 8,036’ N/A 4-1/2” CIBP w/ 35’ cement – TOC 8001’ (8/25/23) 11 8,620’ N/A CIBP w/ 37’ cement – TOC @ 8,583 (7/26/22) 12 8,865’ N/A CIBP w/ 5’ cement – TOC @ 8,860’ (7/20/22) Additional 31’ cement - TOC @ 8,829’ (7/21/22) OPEN HOLE / CEMENT DETAIL 13-3/8” 16” Hole: TOC @ Surface (Original BCU 18) 9-5/8" 12-1/4: Hole: TOC @ 3,440’ (Original BCU 18) 7” 8-1/2” Hole: 125bbls 12ppg lead followed by 18bbls 15.3ppg tail pumped on 5/1/22. 38bbls lead cement back to surface. 5/14/22 CBL shows ToC at 3570’ MD 4-1/2” 6-1/8” Hole: Pumped 30bbl spacer followed by 54bbls 12ppg Type I/II lead followed by 25bbls 15.3ppg Type I/II tail pumped on 5/11/22. Trace spacer back to surface. 5/19/22 CBL shows ToC at 7370’ MD 4-1/2” Inside 7” Casing: Pump 48 bbls of cement through tubing punch @ ~7,100’. TOC @ ~4,778’ 9 4 9-5/8” 2 BCU 18 (Abandoned) 8 7” PERFORATION DETAIL Zone Top MD Btm MD TopTVD Btm TVD Amt Date Comments BEL5 6,285' 6,305' 5,890' 5,909' 20' 2/28/2025 Open BEL6 6,342’ 6,348’ 5,942’ 5,947’ 6’ 9/9/2023 Isolated 2/28/25 BEL6 6,342’ 6,348’ 5,942’ 5,947’ 6’ 2/26/2025 Isolated 2/28/25 BEL6 6,354’ 6,361’ 5,953’ 5,960’ 7’ 9/9/2023 Isolated 2/28/25 BEL6 6,356’ 6,362’ 5,955’ 5,961’ 6’ 2/26/2025 Isolated 2/28/25 BEL6 6,366’ 6,375’ 5,964’ 5,972’ 9’ 9/9/2023 Isolated 2/28/25 BEL6 6,366’ 6,375’ 5,964’ 5,972’ 9’ 2/26/2025 Isolated 2/28/25 BEL7 6,384' 6,404' 5,981' 5,999' 20' 2/27/2025 Isolated 2/28/25 BEL7 6,453’ 6,467’ 6,044’ 6,055’ 14’ 9/9/2023 Isolated 1/27/25 BEL8 6,516' 6,526' 6,103' 6,112' 10' 2/25/2025 Isolated 2/25/25 BEL8 6,533' 6,543' 6,118' 6,128' 10' 2/24/2025 Isolated 2/25/25 BEL8 6,549' 6,563' 6,133' 6,146' 14' 2/24/2025 Isolated 2/25/25 BEL8 6,601’ 6,620’ 6,181’ 6,196’ 19’ 9/6/2023 Isolated 9/9/23 BEL9 6,660’ 6,668’ 6,235’ 6,242’ 8’ 9/6/2023 Isolated 9/9/23 BEL22 8,086’ 8,106 7,626’ 7,646’ 41’ 3/10/2023 Isolated 8/25/23 BEL23 8,130’ 8,139’ 7,669’ 7,678’ 9’ 3/10/2023 Isolated 8/25/23 BEL25 8,254' 8,264' 7,791' 7,801' 10' 7/28/2022 Isolated 8/25/23 BEL26 8,281' 8,290' 7,818' 7,827' 9' 7/28/2022 Isolated 8/25/23 BEL27 8,358' 8,372' 7,894' 7,907' 14' 7/27/2022 Isolated 8/25/23 PERFORATION DETAIL – continued on following page BEL 29-32 T0 – T12 12 BEL 33 FISH DETAILs: Failed WRP at 8867’ ELMD (7/10/22) & Fish left from 8,785-8,829ft - 35ft 3.5"OD cement bailer, 2ft CCL, 7ft 2" weight bar (7/21/22) 11 BEL 25-28 BEL 22-23 Tubing Punch at ~7,100’ TOC @ 4,778’ CBL 9/4/23 10 6 9.5 ppg brine 7 5 3 Tubing Patch 6450-6471 1/27/25 BEL 5 BEL 6-9 Updated by RPL 03-17-25 SCHEMATIC BCU 18RD API: 50-133-20584-01-00 PTD: 222-033 Pad-3 PERFORATION DETAIL – continued from previous page Zone Top MD Btm MD TopTVD Btm TVD Amt Date Comments BEL27 8,414' 8,424' 7,949' 7,959' 10' 7/27/2022 Isolated 8/25/23 BEL28 8,483' 8,491' 8,017' 8,025' 8' 7/27/2022 Isolated 8/25/23 BEL28 8,504' 8,516' 8,037' 8,049' 12' 7/27/2022 Isolated 8/25/23 BEL29 8,625’ 8,635’ 8,157’ 8,166’ 10’ 6/19/2022 Isolated 7/26/22 BEL29 8,625’ 8,635’ 8,157’ 8,166’ 10’ 6/12/2022 Isolated 7/26/22 BEL29 8,643’ 8,648’ 8,173’ 8,179’ 5’ 6/19/2022 Isolated 7/26/22 BEL29 8,643’ 8,648’ 8,173’ 8,179’ 5’ 6/12/2022 Isolated 7/26/22 BEL29 8,653’ 8,659’ 8,184’ 8,190’ 6’ 6/19/2022 Isolated 7/26/22 BEL29 8,653’ 8,659’ 8,184’ 8,190’ 6’ 6/12/2022 Isolated 7/26/22 BEL29 8,687' 8,707' 8,218' 8,237' 20' 7/16/2022 Isolated 7/26/22 BEL29 8,690' 8,692' 8,221' 8,223' 2' 7/16/2022 Isolated 7/26/22 B30 8,740' 8,745' 8,270’ 8,275’ 5’ 6/11/2022 Isolated 7/26/22 B30 8,775' 8,781' 8,304’ 8,310’ 6’ 6/11/2022 Isolated 7/26/22 B31 8,812' 8,818' 8,341’ 8,347’ 6’ 6/11/2022 Isolated 7/26/22 B32 8,840' 8,849' 8,369’ 8,377’ 9’ 7/9/2022 Isolated 7/26/22 B32 8,840' 8,849' 8,369’ 8,377’ 9’ 6/11/2022 Isolated 7/26/22 B33 8,995' 9,004' 8,522’ 8,530’ 9’ 6/11/2022 Isolated 7/10/22 T0 9,148' 9,153' 8,672' 8,677' 5’ 6/1/2022 Isolated 6/8/22 T2 9,230' 9,242' 8,753' 8,765' 12’ 6/1/2022 Isolated 6/8/22 T4 9,337' 9,347' 8,860' 8,868' 10’ 5/31/2022 Isolated 6/8/22 T4 9,380' 9,393' 8,901' 8,913' 13’ 5/31/2022 Isolated 6/8/22 T6 9,567' 9,575' 9,085' 9,093' 8’ 5/29/2022 Isolated 6/8/22 T7A 9,738' 9,758' 9,253' 9,273' 20’ 5/29/2022 Isolated 6/8/22 T7B 9,797' 9,817' 9,311' 9,328' 20’ 5/28/2022 Isolated 6/8/22 T11 10,116' 10,136' 9,625' 9,645' 20’ 5/28/2022 Isolated 6/8/22 T12 10,289' 10,308' 9,795' 9,813' 19’ 5/26/2022 Isolated 6/8/22 T12 10,289' 10,308' 9,795' 9,813' 19’ 5/27/2022 Isolated 6/8/22 Updated by RPL 03-31-25 SCHEMATIC Proposed BCU 18RD API: 50-133-20584-01-00 PTD: 222-033 Pad-3 PBTD = 8,583’ MD / 8,115’ TVD TD = 10,461’ MD / 9,964’ TVD RKB to GL = 18.0’ 5 CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 20” Conductor 154.19 X-65 Weld 19.13” Surf 108’ 13-3/8" Surf Csg 68.0 K-55 BTC 12.415” Surf 2,097’ 9-5/8” Intermediate Csg 40.0 L-80 BTC 8.835” Surf 3,574’ 7” Intermediate Lnr 26.0 L-80 Vam Top 6.276” 3,336’ 7,474’ 4-1/2" Prod Tieback 12.6 L-80 JFEBEAR 3.958” Surf 7,214’ 4-1/2" Prod Lnr 12.6 L-80 JFEBEAR 3.958” 7,219’ 10,432’ TUBING DETAIL 4-1/2” Tubing 12.6 L-80 Surface 7,214’ 1 20” 13-3/8” 4-1/2” JEWELRY DETAIL No. Depth ID Item 1 3,336’ 6.040” 9-5/8” x 7” Liner hanger / LTP Assembly 2 3,574’ NA Whipstock 3 + 6,235’ CIBP + 35’ Cement (Proposed) 4 6,338’ CIBP (2/28/25) 5 6,445’ CIBP (2/25/25) 6 6,590’ 3-1/2” CIBP (9/9/23) 7 6,900’ NA FH Cement retainer, Eline tagged cement on top @ 6852’ PBTD 8 7,150’ NA 4-1/2” CIBP (refence plug tag for cement retainer) 9 7,218’ 5.25” 7” x 4-1/2” Liner hanger / LTP Assembly with PBR 10 7,214’ 3.890” Seal Stem 11 8,036’ N/A 4-1/2” CIBP w/ 35’ cement – TOC 8001’ (8/25/23) 12 8,620’ N/A CIBP w/ 37’ cement – TOC @ 8,583 (7/26/22) 13 8,865’ N/A CIBP w/ 5’ cement – TOC @ 8,860’ (7/20/22) Additional 31’ cement - TOC @ 8,829’ (7/21/22) OPEN HOLE / CEMENT DETAIL 13-3/8” 16” Hole: TOC @ Surface (Original BCU 18) 9-5/8" 12-1/4: Hole: TOC @ 3,440’ (Original BCU 18) 7” 8-1/2” Hole: 125bbls 12ppg lead followed by 18bbls 15.3ppg tail pumped on 5/1/22. 38bbls lead cement back to surface. 5/14/22 CBL shows ToC at 3570’ MD 4-1/2” 6-1/8” Hole: Pumped 30bbl spacer followed by 54bbls 12ppg Type I/II lead followed by 25bbls 15.3ppg Type I/II tail pumped on 5/11/22. Trace spacer back to surface. 5/19/22 CBL shows ToC at 7370’ MD 4-1/2” Inside 7” Casing: Pump 48 bbls of cement through tubing punch @ ~7,100’. TOC @ ~4,778’ 10 4 9-5/8” 2 BCU 18 (Abandoned) 9 7” PERFORATION DETAIL Zone Top MD Btm MD TopTVD Btm TVD Amt Date Comments ST B3L ±5,418’ ±5,428’ ±5,092' ±5,101' ±10' Proposed ST B3L ±5,441’ ±5,451’ ±5,113' ±5,122' ±10' Proposed ST B4 ±5,504’ ±5,521’ ±5,171' ±5,186' ±17' Proposed ST B5 ±5,565’ ±5,570’ ±5,227' ±5231' ±5' Proposed ST B5 ±5,579’ ±5,585’ ±5,239' ±5,245' ±6' Proposed ST B6 ±5,604’ ±5,614’ ±5,262' ±5,272' ±10' Proposed BEL5 6,285' 6,305' 5,890' 5,909' 20' 2/28/2025 Isolate BEL6 6,342’ 6,348’ 5,942’ 5,947’ 6’ 9/9/2023 Isolated 2/28/25 BEL6 6,342’ 6,348’ 5,942’ 5,947’ 6’ 2/26/2025 Isolated 2/28/25 BEL6 6,354’ 6,361’ 5,953’ 5,960’ 7’ 9/9/2023 Isolated 2/28/25 BEL6 6,356’ 6,362’ 5,955’ 5,961’ 6’ 2/26/2025 Isolated 2/28/25 BEL6 6,366’ 6,375’ 5,964’ 5,972’ 9’ 9/9/2023 Isolated 2/28/25 BEL6 6,366’ 6,375’ 5,964’ 5,972’ 9’ 2/26/2025 Isolated 2/28/25 BEL7 6,384' 6,404' 5,981' 5,999' 20' 2/27/2025 Isolated 2/28/25 BEL7 6,453’ 6,467’ 6,044’ 6,055’ 14’ 9/9/2023 Isolated 1/27/25 BEL8 6,516' 6,526' 6,103' 6,112' 10' 2/25/2025 Isolated 2/25/25 BEL8 6,533' 6,543' 6,118' 6,128' 10' 2/24/2025 Isolated 2/25/25 BEL8 6,549' 6,563' 6,133' 6,146' 14' 2/24/2025 Isolated 2/25/25 BEL8 6,601’ 6,620’ 6,181’ 6,196’ 19’ 9/6/2023 Isolated 9/9/23 PERFORATION DETAIL – continued on following page BEL 29-32 T0 – T12 13 BEL 33 FISH DETAILs: Failed WRP at 8867’ ELMD (7/10/22) & Fish left from 8,785-8,829ft - 35ft 3.5"OD cement bailer, 2ft CCL, 7ft 2" weight bar (7/21/22) 12 BEL 25-28 BEL 22-23 Tubing Punch at ~7,100’ TOC @ 4,778’ CBL 9/4/23 11 7 9.5 ppg brine 8 6 4 Tubing Patch 6450-6471 1/27/25 BEL 5 BEL 6-9 ST B3L – B6 3 Updated by RPL 03-31-25 SCHEMATIC Proposed BCU 18RD API: 50-133-20584-01-00 PTD: 222-033 Pad-3 PERFORATION DETAIL – continued from previous page Zone Top MD Btm MD TopTVD Btm TVD Amt Date Comments BEL9 6,660’ 6,668’ 6,235’ 6,242’ 8’ 9/6/2023 Isolated 9/9/23 BEL22 8,086’ 8,106 7,626’ 7,646’ 41’ 3/10/2023 Isolated 8/25/23 BEL23 8,130’ 8,139’ 7,669’ 7,678’ 9’ 3/10/2023 Isolated 8/25/23 BEL25 8,254' 8,264' 7,791' 7,801' 10' 7/28/2022 Isolated 8/25/23 BEL26 8,281' 8,290' 7,818' 7,827' 9' 7/28/2022 Isolated 8/25/23 BEL27 8,358' 8,372' 7,894' 7,907' 14' 7/27/2022 Isolated 8/25/23 BEL27 8,414' 8,424' 7,949' 7,959' 10' 7/27/2022 Isolated 8/25/23 BEL28 8,483' 8,491' 8,017' 8,025' 8' 7/27/2022 Isolated 8/25/23 BEL28 8,504' 8,516' 8,037' 8,049' 12' 7/27/2022 Isolated 8/25/23 BEL29 8,625’ 8,635’ 8,157’ 8,166’ 10’ 6/19/2022 Isolated 7/26/22 BEL29 8,625’ 8,635’ 8,157’ 8,166’ 10’ 6/12/2022 Isolated 7/26/22 BEL29 8,643’ 8,648’ 8,173’ 8,179’ 5’ 6/19/2022 Isolated 7/26/22 BEL29 8,643’ 8,648’ 8,173’ 8,179’ 5’ 6/12/2022 Isolated 7/26/22 BEL29 8,653’ 8,659’ 8,184’ 8,190’ 6’ 6/19/2022 Isolated 7/26/22 BEL29 8,653’ 8,659’ 8,184’ 8,190’ 6’ 6/12/2022 Isolated 7/26/22 BEL29 8,687' 8,707' 8,218' 8,237' 20' 7/16/2022 Isolated 7/26/22 BEL29 8,690' 8,692' 8,221' 8,223' 2' 7/16/2022 Isolated 7/26/22 B30 8,740' 8,745' 8,270’ 8,275’ 5’ 6/11/2022 Isolated 7/26/22 B30 8,775' 8,781' 8,304’ 8,310’ 6’ 6/11/2022 Isolated 7/26/22 B31 8,812' 8,818' 8,341’ 8,347’ 6’ 6/11/2022 Isolated 7/26/22 B32 8,840' 8,849' 8,369’ 8,377’ 9’ 7/9/2022 Isolated 7/26/22 B32 8,840' 8,849' 8,369’ 8,377’ 9’ 6/11/2022 Isolated 7/26/22 B33 8,995' 9,004' 8,522’ 8,530’ 9’ 6/11/2022 Isolated 7/10/22 T0 9,148' 9,153' 8,672' 8,677' 5’ 6/1/2022 Isolated 6/8/22 T2 9,230' 9,242' 8,753' 8,765' 12’ 6/1/2022 Isolated 6/8/22 T4 9,337' 9,347' 8,860' 8,868' 10’ 5/31/2022 Isolated 6/8/22 T4 9,380' 9,393' 8,901' 8,913' 13’ 5/31/2022 Isolated 6/8/22 T6 9,567' 9,575' 9,085' 9,093' 8’ 5/29/2022 Isolated 6/8/22 T7A 9,738' 9,758' 9,253' 9,273' 20’ 5/29/2022 Isolated 6/8/22 T7B 9,797' 9,817' 9,311' 9,328' 20’ 5/28/2022 Isolated 6/8/22 T11 10,116' 10,136' 9,625' 9,645' 20’ 5/28/2022 Isolated 6/8/22 T12 10,289' 10,308' 9,795' 9,813' 19’ 5/26/2022 Isolated 6/8/22 T12 10,289' 10,308' 9,795' 9,813' 19’ 5/27/2022 Isolated 6/8/22 STANDARD WELL PROCEDURE NITROGEN OPERATIONS 12/08/2015 FINAL v1 Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. 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: 3/18/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20250318 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# AN-51 50733204640000 195004 3/1/2025 READ CAliperSurvey AN-51 50733204640000 195004 3/1/2025 READ CaliperSurvey/SBHPS BCU 18RD 50133205840100 222033 2/25/2025 AK E-LINE Perf BCU 18RD 50133205840100 222033 2/26/2025 AK E-LINE Plug/Perf BRU 212-26 50283201820000 220058 2/28/2025 AK E-LINE PT Survey BRU 221-26 50283202010000 224098 2/27/2025 AK E-LINE PPROF BRU 241-34S 50283201980000 224077 3/1/2025 AK E-LINE PPROF IRU 11-06 50283201300000 208184 2/26/2025 AK E-LINE DepthDetermination IRU 11-06 50283201300000 208184 3/8/2025 AK E-LINE PlugSetting MPU E-42 50029236350000 219082 2/22/2025 AK E-LINE Caliper MRU A-12RD 50733200760100 171029 3/7/2025 AK E-LINE Correlation MRU A-13 (REVISED)50733200770000 168002 2/6/2025 AK E-LINE TubingPunch MRU M-32RD2 50733204620200 217091 3/4/2025 AK E-LINE Correlation PBU 13-24B 50029207390200 224087 1/4/2025 HALLIBURTON RBT PBU 16-24A 50029215360100 224158 2/23/2025 HALLIBURTON RBT-COILFLAG PBU F-21 50029219490000 189056 2/25/2025 READ CaliperSurvey SD37-DSP01 50629234510000 211089 2/28/2025 HALLIBURTON WFL-TMD3D Revision explanation: Fixed API# on log and .las files Please include current contact information if different from above. T40221 T40221 T40222 T40222 T40223 T40224 T40225 T40226 T40226 T40227 T40228 T40229 T40230 T40231 T40232 T40233 T40234 BCU 18RD 50133205840100 222033 2/25/2025 AK E-LINE Perf BCU 18RD 50133205840100 222033 2/26/2025 AK E-LINE Plug/Perf Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.03.18 15:55:41 -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: 2/20/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20250220 Well API #PTD #Log Date Log Company Log Type AOGCC ESet # BCU 18RD 50133205840100 222033 1/27/2025 AK E-LINE Patch BRU 223-24 50283201830000 221072 1/26/2025 AK E-LINE Perf CLU 10RD 50133205530100 222113 11/2/2024 YELLOWJACKET PLUG GP 03-87 50733204370000 166052 12/16/2024 AK E-LINE Plug/Cement IRU 44-36 50283200890000 193022 1/22/2025 AK E-LINE Perf KU WD-01 50133203450000 181107 10/15/2024 YELLOWJACKET PERF MPI 1-29 50029216690000 186181 1/29/2025 AK E-LINE Perf MPU C-39 50029228490000 197248 1/27/2025 AK E-LINE TubingCut MPU E-20A 50029225610100 204054 2/1/2025 READ CaliperSurvey MPU K-33 50029227290000 196202 2/8/2025 AK E-LINE TubeCut MPU S-08 50029231680000 203123 2/6/2025 AK E-LINE CmtRtr/Punch MRU A-13 50733200770000 168002 2/6/2025 AK E-LINE TubingPunch MRU M-02 50733203890000 187061 1/22/2025 AK E-LINE Perf MRU M-32RD2 50733204620200 217091 2/10/2025 AK E-LINE TubingPunch NCIU A-09 50883200290100 222024 1/31/2025 AK E-LINE Perf NCIU A-16 50883201270000 208098 1/30/2025 AK E-LINE Perf NCIU A-21 50883201990000 224086 1/15/2025 AK E-LINE Plug, Perf NK-41A 50029227780100 197158 1/6/2025 HALLIBURTON Coilflag PAVE 3-1 50029238060000 224140 1/4/2025 YELLOWJACKET CBL PBU P1-13 50029223720000 193074 12/3/2024 HALLIBURTON PPROF PTM P1-07A 50029219960100 204037 12/31/2024 YELLOWJACKET PPROF Please include current contact information if different from above. T40127 T40128 T40129 T40130 T40131 T40132 T40133 T40134 T40135 T40136 T40137 T40138 T40139 T40140 T40141 T40142 T40143 T40144 T40145 T40146 T40147 BCU 18RD 50133205840100 222033 1/27/2025 AK E-LINE Patch Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.02.20 14:09:18 -09'00' Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 09/12/2023 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20230912 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BCU 18RD 50133205840100 222033 9/6/2023 YELLOW JACKET GPT-PERF BCU 18RD 50133205840100 222033 8/24/2023 YELLOW JACKET PLUG BCU 18RD 50133205840100 222033 8/28/2023 YELLOW JACKET PLUG-PERF BCU 18RD 50133205840100 222033 9/9/2023 YELLOW JACKET PLU-GPT-PERF BCU 18RD 50133205840100 222033 9/4/2023 YELLOW JACKET SCBL BRU 211-35 50283201890000 223050 7/31/2023 AK E-LINE CBL BRU 211-35 50283201890000 223050 8/19/2023 AK E-LINE GPT/Plug/Perf BRU 211-35 50283201890000 223050 8/10/2023 AK E-LINE Perf BRU 212-26 50283201820000 220058 8/20/2023 AK E-LINE GPT IRU 11-06 50283201300000 208184 8/1/2023 AK E-LINE Perf IRU 41-01 50283200880000 192109 9/3/2023 AK E-LINE GPT/Perf KTU 43-6XRD2 50133203280200 205117 9/4/2023 YELLOW JACKET CALIPER KU 42-12 50133206890000 220045 8/31/2023 YELLOW JACKET GPT-PERF KU 42-12 50133206890000 220045 8/20/2023 YELLOW JACKET SCBL MPU E-23 50029225700000 195094 8/18/2023 YELLOW JACKET CBL-PLUG MPU E-23 50029225700000 195094 8/20/2023 YELLOW JACKET PERF Paxton 12 50133207100000 223014 8/20/2023 AK E-LINE GPT/Perf Paxton 12 50133207100000 223014 8/14/2023 AK E-LINE Patch/Perf PBU L-240 50029237030000 221086 8/30/2023 READ IPROF Please include current contact information if different from above. T37983 T37983 T37983 T37983 T37983 T37984 T37984 T37984 T37985 T37986 T37987 T37988 T37989 T37989 T37990 T37990 T37991 T37991 T37992 9/13/2023 YELLOW BCU 18RD 50133205840100 222033 9/6/2023 JACKET GPT-PERF YELLOW BCU 18RD 50133205840100 222033 8/24/2023 JACKET PLUG YELLOW BCU 18RD 50133205840100 222033 8/28/2023 JACKET PLUG-PERF YELLOW BCU 18RD 50133205840100 222033 9/9/2023 JACKET PLU-GPT-PERF YELLOW BCU 18RD 50133205840100 222033 9/4/2023 JACKET SCBL Kayla Junke Digitally signed by Kayla Junke Date: 2023.09.13 10:28:30 -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 10,461 feet See Schematic feet true vertical 9,964 feet N/A feet Effective Depth measured 6,338 feet N/A feet true vertical 5,938 feet N/A feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth)4-1/2" 12.6# / L-80 7,214' MD 6,763' TVD Packers and SSSV (type, measured and true vertical depth)N/A N/A 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: Ryan Lemay, Operations Engineer 324-523 Sr Pet Eng: 7,500psi 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@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 108' 0 00 0 18440 166 measured TVD 9-5/8" 8,430psi 7" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 222-033 50-133-20584-01-00 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: FEDA028083 Beaver Creek / Beluga Gas Pool Beaver Creek Unit (BCU) 18RD Plugs Junk measured Length Intermediate Lnr Produciton 3,574' 4,138' 4,006' Casing Structural 3,350' 6,975' 4-1/2" 3,574' 7,474' 10,432'9,936' 108'Conductor Surface Intermediate Csg 20" 13-3/8" 108' 2,097' 3,090psi 5,410psi 3,060psi 3,450psi 5,750psi 7,240psi 2,097'1,038' Burst Collapse 1,500psi 1,950psi 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 7:58 am, Mar 19, 2025 Noel Nocas (4361) Digitally signed by Noel Nocas (4361) Date: 2025.03.18 15:56:53 -08'00' RBDMS JSB 032625 BJM 5/2/25 DSR-3/27/25 Page 1/2 Well Name: BCU-018RD Report Printed: 3/17/2025WellViewAdmin@hilcorp.com Alaska Weekly Report - Operations Wellbore API/UWI:50-133-20584-01-00 Field Name:Beaver Creek State/Province:ALASKA Permit to Drill (PTD) #:222-033 Sundry #:324-523 Rig Name/No: Jobs Actual Start Date:12/30/2024 End Date: Report Number 1 Report Start Date 12/30/2024 Report End Date 12/31/2024 Last 24hr Summary MIRU slickline. PTW/PJSM. Pressure test lubricator 250 psi low / 2500 psi high - good test. Bail from 6501' - 6515' KB Report Number 2 Report Start Date 12/31/2024 Report End Date 1/1/2025 Last 24hr Summary PTW/PJSM, Wellhead hand changed out the swab valve and PT 250 psi low /3500 high - good test. Continue bailing from 6512' - 6520' KB Report Number 3 Report Start Date 1/1/2025 Report End Date 1/2/2025 Last 24hr Summary PTW/PJSM, Bail from 6518'-6526' KB, Drifted cleanly to 6518' KB W/ 3.78" cent, 15' 3 3/8" D.guns, 3.80" G-ring (17' OAL). RDMO slickline Report Number 4 Report Start Date 1/7/2025 Report End Date 1/8/2025 Last 24hr Summary Mobilize CTU package from Cannery Loop to Beaver Creek. MIRU CTU euipment. Build containment for tanks. KCL product on location. Removed well house. Install BOPE stack. Rig hardline and choke skid to reutrn tank and BOPE stack. Spot upright tank for supply fluids. Report Number 5 Report Start Date 1/8/2025 Report End Date 1/9/2025 Last 24hr Summary PTW, JSA with crew. MIRU fox energy batch mixer. Spot in KCL trailer. AOGCC waived BOPE test witness. Test BOPE 250 psi low /3500 psi high - good test. Continue mixing KCL for a total of 320 bbls. Pick injector head and make up BHA. Coil connector internal, DFCV, 3.5" tapered jet swirl nozzle. RIH with 2" coil and fill reel with 44 bbls. Initial whp 1200 psi. Fluid to surface 94 bbls away. Confirmed 1:1 returns. Shut down pump RIH for dry tag. Tag 6533' CTMD. Pick up clean at 30K . Down on NPT for 2.5 hours with batch mixer and fluid pump issues. Online 2 bbls/min 3200 psi. Start washing from 6533' to PBTD at 6605' CTMD. circulated 35 bbl high visc gel sweep. Wash across perf intervals from 6200' to 6605' 4 times. Chased bottoms up to surface. Shut in well. Pop off and stand back injector head. Cover reel with tars and install heater. Report Number 6 Report Start Date 1/9/2025 Report End Date 1/9/2025 Last 24hr Summary PTW, JSA with crew. MIRU YJOFS E-line unit. Make up DMY patch drift, RIH and tag at 6,555’ ELMD (~8’ above perf target depth). Discuss with OE and decided to proceed with patch set. Make up AK-E-line 4.5” X-span patch. RIH and correlate above perfs from 6200-5800’. Confirm Tie-in with geo and RBIH to set depth. Attempt to set patch over interval 6,450-6,471.5’ but did not get any indications of setting tool stroking. Made multiple attempts to fire setting tool with no luck. POOH with patch BHA and inspected tools. Could not find any definitive electrical issues. Lay down E-line for the night. RU FOX Coil and blow down reel with N2 for freeze protect. Report Number 7 Report Start Date 1/10/2025 Report End Date 1/10/2025 Last 24hr Summary Drop Kinley cutter - retrieve cutter crimped on line. Report Number 8 Report Start Date 1/11/2025 Report End Date 1/12/2025 Last 24hr Summary Attempt to fish E-line tool string. Report Number 9 Report Start Date 1/12/2025 Report End Date 1/13/2025 Last 24hr Summary Continue fishing eline tool and patch Report Number 10 Report Start Date 1/17/2025 Report End Date 1/18/2025 Last 24hr Summary Bail and attempt to retrieve patch part. Report Number 11 Report Start Date 1/18/2025 Report End Date 1/19/2025 Last 24hr Summary Continue to bail and attempt to retrieve patch part Report Number 12 Report Start Date 1/26/2025 Report End Date 1/27/2025 Last 24hr Summary PTW/PJSM w/ Operations. MIRU AK Eline on BCU 18RD. 5.75 hrs NPT due to crane issues. Swap out cranes. Resume rig up. Pressure Test PCE 250psi low / 2500psi high - good test. RIH w/ GR/CCL & Junk Basket w/ 3.75" G-ring Drift BHA. Tag TD at 6542.3'. Good drift below patch set depth. Pooh. Secure well & lay down for the night. Page 2/2 Well Name: BCU-018RD Report Printed: 3/17/2025WellViewAdmin@hilcorp.com Alaska Weekly Report - Operations Report Number 13 Report Start Date 1/27/2025 Report End Date 1/28/2025 Last 24hr Summary Pick up Lubricator. Make up & RIH w/ Owen's 3.60" Special Clearance X-Span Patch. See potential fluid level at ~ 820'. Stop at 6460' CCL depth to prevent tagging fill with patch. Pull Correlation Pass. Up wt= ~ 2000#. Send in correlation pass. RIH below set depth. Pick up to CCL stop depth of 6431.4'. Fire to set patch. Good indication of patch setting in ~2 mins. Wait a full 5 mins. Pick up 10' and RBIH & Tag patch. Looks good. Pull ooh weighing ~ 300# lighter. Patch is set. Pooh. Patch set from 6450' - 6471.3' isolating the BEL7 Perforations. Pull ooh. Setting tool looks good. Rig down Eline. Job Complete Patch OAL= 21.8'. Min ID= 2.992". Drift ID= 2.867". Top of Patch= 6449.75'. Bottom of Patch= 6471.5'. Report Number 14 Report Start Date 2/19/2025 Report End Date 2/20/2025 Last 24hr Summary Mobilize Fox CTU Equipment to location. Begin rig up CTU. Spot source and return tanks and fill with 170 bbls FW. Unable to complete rig up due to missing hardline and minor equipment. Gather equipment and will continue tomorrow. Report Number 15 Report Start Date 2/20/2025 Report End Date 2/21/2025 Last 24hr Summary Continue rig up of CTU. Rig up all hardline and stab pipe into injector. Complete BOP test to 250/3000 psi - good test (Witness waived by Jim Regg). Experience issues with stripper and trace hydraulic hoses to diagnose. Mix 6% KCl and stab on the well. Circulate drift ball through coil and fluid pack with 6% KCl. LDFN. Report Number 16 Report Start Date 2/21/2025 Report End Date 2/22/2025 Last 24hr Summary Make up 2.50" JSN cleanout BHA. RIH with choke open. Catch fluid at 5400' and dry drift to a tag at 6602' CTMD (6552 MD). Pump 10 bbl gel sweep and follow with 1.5 bpm of 6% KCl and 450 scf/min N2. Clean out down to 6632' CTMD (6582 MD). Chase uphole and return grey silt to the tanks at 2600'. Cut fluid at 1400' and continue to chase up with N2 until no additional fluids in returns. Shut down pumps and RIH dry, confirming clean tag at 6632' CTMD (6582 MD). Come online with N2 at 1500scf/min to unload well. Circulate until coil pressure broke over and stabilized, and begin chasing fluid up hole as BHP decrease and fluid began unloading from well. Once no additional liquid return rate at surface, and all fluid both pumped and initially in the wellbore returned, N2 Shut down and continue to POOH. As N2 from wellbore bled down, LELs were never detected and well died. Rig back CTU for the night and turn well over to operations to monitor and attempt to POP/test overnight. Report Number 17 Report Start Date 2/22/2025 Report End Date 2/23/2025 Last 24hr Summary Unable to POP well overnight, 0 psi of WHP. Re-rig hardline for reverse-out and make up 2-1/8" large hole nozzle. RIH with choke closed and never see increase in circ pressure from entering fluid. Stop at 6300' and come online down the backside with N2 at 1000 scf/min. Continue RIH and tag top of patch at 6480' CTMD (6442' MD). Work pipe through and RIH to TD tag at 6619'CTMD (6581' MD). Reverse out with N2 and return 3 bbls of liquid. Shut in choke and continue to pump N2 down the backside to pressure up well while POOH. Trap 1860 psi on the tubing. Begin Rig Down CTU. Report Number 18 Report Start Date 2/23/2025 Report End Date 2/24/2025 Last 24hr Summary Complete rig down and move off location. Job Complete. Report Number 19 Report Start Date 2/24/2025 Report End Date 2/25/2025 Last 24hr Summary PTW/PJSM,MIRU AK Eline PT 250 psi low / 3000 psi high - good test. Ran GPT, tagged @ 6588'. (no fluid observed). Pressured up well W/ N2. Pumped total of 124.8K SCF, 1340 gal. Perforate BEL 8 from (6549'-6563') & (6533'-6543') Report Number 20 Report Start Date 2/25/2025 Report End Date 2/26/2025 Last 24hr Summary PTW/PJSM. Perforate Bel 8 from 6516'-6526', Ran GPT FL @ 5760'. Bleed well down in 300psi increments W/ 10min build. Bled well to 500psi no LEL's seen, FL came up to 5100'. Push fluid away W/ N2 saw pressure break over @ 2285psi, Pumped total 210.7K SCF, 2263 Gal, Set 3.71" CIBP @ 6445'. Received approval from AOGCC Bryan McLellan and BLM Will Maercklein to set CIBP at 6445' (71' above top of Bel 8 perforation due to tubing patch set depth) and reperforate currently open Bel 6 intervals 2/25/2025 Report Number 21 Report Start Date 2/26/2025 Report End Date 2/27/2025 Last 24hr Summary PTW/PJSM. SITP 725, Reperforate shut in BEL 6 (6366'-6375'). After perforating the 1st zone SD @ 6405', 40' above CIBP, Reperforate Bel 6 (6356'-6362'), (6342'-6348'). Flow test well with operations. No LELs or sustained production observed. Report Number 22 Report Start Date 2/27/2025 Report End Date 2/28/2025 Last 24hr Summary PTW/PJSM. Ran GPT, tag @ 6407', FL @ 6392'. MIRU Fox N2, PTW/PJSM, PT 250 psi low / 3000 psi high - good test, Push fluid away & pressure up well to 1700 psi W/ 150K SCF (1601 gal). Perforate Bel 7 (6384'-6404'). Flow test well with operations. No LELs or sustained production observed. Report Number 23 Report Start Date 2/28/2025 Report End Date 3/1/2025 Last 24hr Summary PTW/PJSM. Pushed fluid away with N2 Total of 113.6KSCF (1220 gal), Saw pressure break over @ 1900psi. Set 3.71" CIBP @ 6338'. Perforated BEL 5 (6285'- 6305'). RDMO E-line. Job completed. Turn well over to operations to flow test well. RDMO. Updated by RPL 03-17-25 SCHEMATIC BCU 18RD API: 50-133-20584-01-00 PTD: 222-033 Pad-3 PBTD = 8,583’ MD / 8,115’ TVD TD = 10,461’ MD / 9,964’ TVD RKB to GL = 18.0’ 4 CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 20” Conductor 154.19 X-65 Weld 19.13” Surf 108’ 13-3/8" Surf Csg 68.0 K-55 BTC 12.415” Surf 2,097’ 9-5/8” Intermediate Csg 40.0 L-80 BTC 8.835” Surf 3,574’ 7” Intermediate Lnr 26.0 L-80 Vam Top 6.276” 3,336’ 7,474’ 4-1/2" Prod Tieback 12.6 L-80 JFEBEAR 3.958” Surf 7,214’ 4-1/2" Prod Lnr 12.6 L-80 JFEBEAR 3.958” 7,219’ 10,432’ TUBING DETAIL 4-1/2” Tubing 12.6 L-80 Surface 7,214’ 1 20” 13-3/8” 4-1/2” JEWELRY DETAIL No. Depth ID Item 1 3,336’ 6.040” 9-5/8” x 7” Liner hanger / LTP Assembly 2 3,574’ NA Whipstock 3 6,338’ CIBP (2/28/25) 4 6,445’ CIBP (2/25/25) 5 6,590’ 3-1/2” CIBP (9/9/23) 6 6,900’ NA FH Cement retainer, Eline tagged cement on top @ 6852’ PBTD 7 7,150’ NA 4-1/2” CIBP (refence plug tag for cement retainer) 8 7,218’ 5.25” 7” x 4-1/2” Liner hanger / LTP Assembly with PBR 9 7,214’ 3.890” Seal Stem 10 8,036’ N/A 4-1/2” CIBP w/ 35’ cement – TOC 8001’ (8/25/23) 11 8,620’ N/A CIBP w/ 37’ cement – TOC @ 8,583 (7/26/22) 12 8,865’ N/A CIBP w/ 5’ cement – TOC @ 8,860’ (7/20/22) Additional 31’ cement - TOC @ 8,829’ (7/21/22) OPEN HOLE / CEMENT DETAIL 13-3/8” 16” Hole: TOC @ Surface (Original BCU 18) 9-5/8" 12-1/4: Hole: TOC @ 3,440’ (Original BCU 18) 7” 8-1/2” Hole: 125bbls 12ppg lead followed by 18bbls 15.3ppg tail pumped on 5/1/22. 38bbls lead cement back to surface. 5/14/22 CBL shows ToC at 3570’ MD 4-1/2” 6-1/8” Hole: Pumped 30bbl spacer followed by 54bbls 12ppg Type I/II lead followed by 25bbls 15.3ppg Type I/II tail pumped on 5/11/22. Trace spacer back to surface. 5/19/22 CBL shows ToC at 7370’ MD 4-1/2” Inside 7” Casing: Pump 48 bbls of cement through tubing punch @ ~7,100’. TOC @ ~4,778’ 9 4 9-5/8” 2 BCU 18 (Abandoned) 8 7” PERFORATION DETAIL Zone Top MD Btm MD TopTVD Btm TVD Amt Date Comments BEL5 6,285' 6,305' 5,890' 5,909' 20' 2/28/2025 Open BEL6 6,342’ 6,348’ 5,942’ 5,947’ 6’ 9/9/2023 Isolated 2/28/25 BEL6 6,342’ 6,348’ 5,942’ 5,947’ 6’ 2/26/2025 Isolated 2/28/25 BEL6 6,354’ 6,361’ 5,953’ 5,960’ 7’ 9/9/2023 Isolated 2/28/25 BEL6 6,356’ 6,362’ 5,955’ 5,961’ 6’ 2/26/2025 Isolated 2/28/25 BEL6 6,366’ 6,375’ 5,964’ 5,972’ 9’ 9/9/2023 Isolated 2/28/25 BEL6 6,366’ 6,375’ 5,964’ 5,972’ 9’ 2/26/2025 Isolated 2/28/25 BEL7 6,384' 6,404' 5,981' 5,999' 20' 2/27/2025 Isolated 2/28/25 BEL7 6,453’ 6,467’ 6,044’ 6,055’ 14’ 9/9/2023 Isolated 1/27/25 BEL8 6,516' 6,526' 6,103' 6,112' 10' 2/25/2025 Isolated 2/25/25 BEL8 6,533' 6,543' 6,118' 6,128' 10' 2/24/2025 Isolated 2/25/25 BEL8 6,549' 6,563' 6,133' 6,146' 14' 2/24/2025 Isolated 2/25/25 BEL8 6,601’ 6,620’ 6,181’ 6,196’ 19’ 9/6/2023 Isolated 9/9/23 BEL9 6,660’ 6,668’ 6,235’ 6,242’ 8’ 9/6/2023 Isolated 9/9/23 BEL22 8,086’ 8,106 7,626’ 7,646’ 41’ 3/10/2023 Isolated 8/25/23 BEL23 8,130’ 8,139’ 7,669’ 7,678’ 9’ 3/10/2023 Isolated 8/25/23 BEL25 8,254' 8,264' 7,791' 7,801' 10' 7/28/2022 Isolated 8/25/23 BEL26 8,281' 8,290' 7,818' 7,827' 9' 7/28/2022 Isolated 8/25/23 BEL27 8,358' 8,372' 7,894' 7,907' 14' 7/27/2022 Isolated 8/25/23 PERFORATION DETAIL – continued on following page BEL 29-32 T0 – T12 12 BEL 33 FISH DETAILs: Failed WRP at 8867’ ELMD (7/10/22) & Fish left from 8,785-8,829ft - 35ft 3.5"OD cement bailer, 2ft CCL, 7ft 2" weight bar (7/21/22) 11 BEL 25-28 BEL 22-23 Tubing Punch at ~7,100’ TOC @ 4,778’ CBL 9/4/23 10 6 9.5 ppg brine 7 5 3 Tubing Patch 6450-6471 1/27/25 BEL 5 BEL 6-9 Updated by RPL 03-17-25 SCHEMATIC BCU 18RD API: 50-133-20584-01-00 PTD: 222-033 Pad-3 PERFORATION DETAIL – continued from previous page Zone Top MD Btm MD TopTVD Btm TVD Amt Date Comments BEL27 8,414' 8,424' 7,949' 7,959' 10' 7/27/2022 Isolated 8/25/23 BEL28 8,483' 8,491' 8,017' 8,025' 8' 7/27/2022 Isolated 8/25/23 BEL28 8,504' 8,516' 8,037' 8,049' 12' 7/27/2022 Isolated 8/25/23 BEL29 8,625’ 8,635’ 8,157’ 8,166’ 10’ 6/19/2022 Isolated 7/26/22 BEL29 8,625’ 8,635’ 8,157’ 8,166’ 10’ 6/12/2022 Isolated 7/26/22 BEL29 8,643’ 8,648’ 8,173’ 8,179’ 5’ 6/19/2022 Isolated 7/26/22 BEL29 8,643’ 8,648’ 8,173’ 8,179’ 5’ 6/12/2022 Isolated 7/26/22 BEL29 8,653’ 8,659’ 8,184’ 8,190’ 6’ 6/19/2022 Isolated 7/26/22 BEL29 8,653’ 8,659’ 8,184’ 8,190’ 6’ 6/12/2022 Isolated 7/26/22 BEL29 8,687' 8,707' 8,218' 8,237' 20' 7/16/2022 Isolated 7/26/22 BEL29 8,690' 8,692' 8,221' 8,223' 2' 7/16/2022 Isolated 7/26/22 B30 8,740' 8,745' 8,270’ 8,275’ 5’ 6/11/2022 Isolated 7/26/22 B30 8,775' 8,781' 8,304’ 8,310’ 6’ 6/11/2022 Isolated 7/26/22 B31 8,812' 8,818' 8,341’ 8,347’ 6’ 6/11/2022 Isolated 7/26/22 B32 8,840' 8,849' 8,369’ 8,377’ 9’ 7/9/2022 Isolated 7/26/22 B32 8,840' 8,849' 8,369’ 8,377’ 9’ 6/11/2022 Isolated 7/26/22 B33 8,995' 9,004' 8,522’ 8,530’ 9’ 6/11/2022 Isolated 7/10/22 T0 9,148' 9,153' 8,672' 8,677' 5’ 6/1/2022 Isolated 6/8/22 T2 9,230' 9,242' 8,753' 8,765' 12’ 6/1/2022 Isolated 6/8/22 T4 9,337' 9,347' 8,860' 8,868' 10’ 5/31/2022 Isolated 6/8/22 T4 9,380' 9,393' 8,901' 8,913' 13’ 5/31/2022 Isolated 6/8/22 T6 9,567' 9,575' 9,085' 9,093' 8’ 5/29/2022 Isolated 6/8/22 T7A 9,738' 9,758' 9,253' 9,273' 20’ 5/29/2022 Isolated 6/8/22 T7B 9,797' 9,817' 9,311' 9,328' 20’ 5/28/2022 Isolated 6/8/22 T11 10,116' 10,136' 9,625' 9,645' 20’ 5/28/2022 Isolated 6/8/22 T12 10,289' 10,308' 9,795' 9,813' 19’ 5/26/2022 Isolated 6/8/22 T12 10,289' 10,308' 9,795' 9,813' 19’ 5/27/2022 Isolated 6/8/22 1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: 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: 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 10,461'N/A Casing Collapse Structural Conductor 1,500psi Surface 1,950psi Intermediate Csg 3,090psi Intermediate Lnr 5,410psi 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 4-1/2" ~2,055psi 4,006' 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Beaver Creek Unit (BCU) 18RDCO 237D Same 9,936' 3,350'5,750psi 9,964'8,583'8,115'See Schematic Length September 24, 2024 4-1/2" 10,432' See Schematic 7,240psi 3,060psi 3,450psi 108' 6,975' 20" 13-3/8" Size 108' 7"4,138' 2,097' MD 3,574'9-5/8" 7,474' 12.6# / L-80 TVD Burst 7,214' 8,430psi 108' 2,097' STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEDA028083 222-033Hilcorp Alaska, LLC Proposed Pools: Beaver Creek Beluga Gas AOGCC USE ONLY Tubing MD (ft):Perforation Depth TVD (ft): Subsequent Form Required: Perforation Depth MD (ft): Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi):Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. 50-133-20584-01-00 Tubing Size: PRESENT WELL CONDITION SUMMARY 2,038' 3,574' Authorized Name and Digital Signature with Date: Tubing Grade: scott.warner@hilcorp.com 907-564-4506 Noel Nocas, Operations Manager 907-564-5278 Suspension Expiration Date: Scott Warner, Operations Engineer See Schematic N/A; N/A N/A; N/A m n P s t 2 N 66 Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 12:41 pm, Sep 11, 2024 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2024.09.10 16:17:56 - 08'00' Noel Nocas (4361) 324-523 DSR-9/13/24 CT BOP test to 2500 psi BJM 9/18/24 A.Dewhurst 13SEP24 10-404 X *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.09.19 10:36:01 -08'00'09/19/24 RBDMS JSB 092324 Well Prognosis Well: BCU-18RD Well Name: BCU-18RD API Number: 50-133-20584-01-00 Current Status: Producing Gas Well Permit to Drill Number: 222-033 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: 2659 psi @ 6044’ TVD Based on 0.44 psi/ft Max. Potential Surface Pressure: 2055 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 9-5/8” int. casing shoe Shallowest Allowable Perf TVD: MPSP/(0.70-0.1) = 2055 psi / 0.60 = 3425‘ TVD (Will not perforate above applicable gas pool) Top of Applicable Gas Pool: 6221’ MD/5830’ TVD (Beluga) Well Status: Offline Gas producer Brief Well Summary BCU 18RD was drilled in the spring of 2022 and had difficulty sustaining production until the lower beluga was plug backed and a cement annulus isolation job was performed to allow perforations in the upper beluga. Rate came on very strong and IP’d at ~8.6 mmscfd but has since declined and ultimately died in August 2024 due to dropping below unloading rate. The purpose of this sundry is to cleanout the lower wellbore to access and perforate additional Beluga sands that have been covered by fill along with adding more footage in the Beluga 7 and Beluga 5 sands. Notes Regarding Wellbore Condition x Inclination o Max inclination = 28.6 degrees at 2324’ MD x Recent Tags o 8/11/24: SL bailed fill from 6464’ to 6513’ kb using a 2.5-3” dd bailer 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 6,590’ 4. RIH and reverse out fluid with nitrogen, trap 1800 psi on the wellbore 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 perforate BEL 8, 7, and 5 sands from bottom up with 2-7/8” 60 deg phased perf guns: Well Prognosis Well: BCU-18RD 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 BEL 5 ±6,290' ±6,310' ±5,894' ±5912' ±20' Bel 7 ±6,384' ±6,404' ±5,981' ±5,999' ±20' Bel 8 ±6,516' ±6,526' ±6,103' ±6,112' ±10' Bel 8 ±6,533' ±6,543' ±6,118' ±6,128' ±10' Bel 8 ±6,549' ±6,563' ±6,133' ±6,146' ±14' 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’. g. If necessary, use nitrogen to pressure up well during perforating or to depress water prior to setting a plug above perforations 9. RDMO Attachments: 1. Current Schematic 2. Proposed Schematic 3. Coil Tubing BOP Schematic 4. Standard Well Procedure – N2 Operations Updated by DMA 09-22-23 SCHEMATIC BCU 18RD API: 50-133-20584-01-00 PTD: 222-033 Pad-3 PBTD = 8,583’ MD / 8,115’ TVD TD = 10,461’ MD / 9,964’ TVD RKB to GL = 18.0’ r CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 20” Conductor 154.19 X-65 Weld 19.13” Surf 108’ 13-3/8" Surf Csg 68.0 K-55 BTC 12.415” Surf 2,097’ 9-5/8” Intermediate Csg 40.0 L-80 BTC 8.835” Surf 3,574’ 7” Intermediate Lnr 26.0 L-80 Vam Top 6.276” 3,336’ 7,474’ 4-1/2" Prod Tieback 12.6 L-80 JFEBEAR 3.958” Surf 7,214’ 4-1/2" Prod Lnr 12.6 L-80 JFEBEAR 3.958” 7,219’ 10,432’ TUBING DETAIL 4-1/2” Tubing 12.6 L-80 Surface 7,214’ 1 20” 13-3/8” 4-1/2” JEWELRY DETAIL No. Depth ID Item 1 3,336’ 6.040” 9-5/8” x 7” Liner hanger / LTP Assembly 2 3,574’ NA Whipstock 3 6,590’ 3-1/2” CIBP (9/9/23) 4 6,900’ NA FH Cement retainer, Eline tagged cement on top @ 6852’ PBTD 5 7,150’ NA 4-1/2” CIBP (refence plug tag for cement retainer) 6 7,218’ 5.25” 7” x 4-1/2” Liner hanger / LTP Assembly with PBR 7 7,214’ 3.890” Seal Stem 8 8,036’ N/A 4-1/2” CIBP w/ 35’ cement – TOC 8001’ (8/25/23) 9 8,620’ N/A CIBP w/ 37’ cement – TOC @ 8,583 (7/26/22) 10 8,865’ N/A CIBP w/ 5’ cement – TOC @ 8,860’ (7/20/22) Additional 31’ cement - TOC @ 8,829’ (7/21/22) OPEN HOLE / CEMENT DETAIL 13-3/8” 16” Hole: TOC @ Surface (Original BCU 18) 9-5/8" 12-1/4: Hole: TOC @ 3,440’ (Original BCU 18) 7” 8-1/2” Hole: 125bbls 12ppg lead followed by 18bbls 15.3ppg tail pumped on 5/1/22. 38bbls lead cement back to surface. 5/14/22 CBL shows ToC at 3570’ MD 4-1/2” 6-1/8” Hole: Pumped 30bbl spacer followed by 54bbls 12ppg Type I/II lead followed by 25bbls 15.3ppg Type I/II tail pumped on 5/11/22. Trace spacer back to surface. 5/19/22 CBL shows ToC at 7370’ MD 4-1/2” Inside 7” Casing: Pump 48 bbls of cement through tubing punch @ ~7,100’. TOC @ ~4,778’ 7 4 9-5/8” 2 BCU 18 (Abandoned) 6 7” PERFORATION DETAIL Zone Top MD Btm MD TopTVD Btm TVD Amt Date Comments BEL6 6,342’ 6,348’ 5,942’ 5,947’ 6’ 9/9/2023 Open BEL6 6,354’ 6,361’ 5,953’ 5,960’ 7’ 9/9/2023 Open BEL6 6,366’ 6,375’ 5,964’ 5,972’ 9’ 9/9/2023 Open BEL7 6,453’ 6,467’ 6,044’ 6,055’ 14’ 9/9/2023 Open BEL8 6,601’ 6,620’ 6,181’ 6,196’ 19’ 9/6/2023 Isolated 9/9/23 BEL9 6,660’ 6,668’ 6,235’ 6,242’ 8’ 9/6/2023 Isolated 9/9/23 BEL22 8,086’ 8,106 7,626’ 7,646’ 41’ 3/10/2023 Isolated 8/25/23 BEL23 8,130’ 8,139’ 7,669’ 7,678’ 9’ 3/10/2023 Isolated 8/25/23 BEL25 8,254' 8,264' 7,791' 7,801' 10' 7/28/2022 Isolated 8/25/23 BEL26 8,281' 8,290' 7,818' 7,827' 9' 7/28/2022 Isolated 8/25/23 BEL27 8,358' 8,372' 7,894' 7,907' 14' 7/27/2022 Isolated 8/25/23 PERFORATION DETAIL – continued on following page BEL 29-32 T0 – T12 10 BEL 33 FISH DETAILs: Failed WRP at 8867’ ELMD (7/10/22) & Fish left from 8,785-8,829ft - 35ft 3.5"OD cement bailer, 2ft CCL, 7ft 2" weight bar (7/21/22) 9 BEL 25-28 BEL 22-23 Tubing Punch at ~7,100’ TOC @ 4,778’ CBL 9/4/23 8 4 9.5 ppg brine 5 3 Updated by DMA 09-22-23 SCHEMATIC BCU 18RD API: 50-133-20584-01-00 PTD: 222-033 Pad-3 PERFORATION DETAIL – continued from previous page Zone Top MD Btm MD TopTVD Btm TVD Amt Date Comments BEL27 8,414' 8,424' 7,949' 7,959' 10' 7/27/2022 Isolated 8/25/23 BEL28 8,483' 8,491' 8,017' 8,025' 8' 7/27/2022 Isolated 8/25/23 BEL28 8,504' 8,516' 8,037' 8,049' 12' 7/27/2022 Isolated 8/25/23 BEL29 8,625’ 8,635’ 8,157’ 8,166’ 10’ 6/19/2022 Isolated 7/26/22 BEL29 8,625’ 8,635’ 8,157’ 8,166’ 10’ 6/12/2022 Isolated 7/26/22 BEL29 8,643’ 8,648’ 8,173’ 8,179’ 5’ 6/19/2022 Isolated 7/26/22 BEL29 8,643’ 8,648’ 8,173’ 8,179’ 5’ 6/12/2022 Isolated 7/26/22 BEL29 8,653’ 8,659’ 8,184’ 8,190’ 6’ 6/19/2022 Isolated 7/26/22 BEL29 8,653’ 8,659’ 8,184’ 8,190’ 6’ 6/12/2022 Isolated 7/26/22 BEL29 8,687' 8,707' 8,218' 8,237' 20' 7/16/2022 Isolated 7/26/22 BEL29 8,690' 8,692' 8,221' 8,223' 2' 7/16/2022 Isolated 7/26/22 B30 8,740' 8,745' 8,270’ 8,275’ 5’ 6/11/2022 Isolated 7/26/22 B30 8,775' 8,781' 8,304’ 8,310’ 6’ 6/11/2022 Isolated 7/26/22 B31 8,812' 8,818' 8,341’ 8,347’ 6’ 6/11/2022 Isolated 7/26/22 B32 8,840' 8,849' 8,369’ 8,377’ 9’ 7/9/2022 Isolated 7/26/22 B32 8,840' 8,849' 8,369’ 8,377’ 9’ 6/11/2022 Isolated 7/26/22 B33 8,995' 9,004' 8,522’ 8,530’ 9’ 6/11/2022 Isolated 7/10/22 T0 9,148' 9,153' 8,672' 8,677' 5’ 6/1/2022 Isolated 6/8/22 T2 9,230' 9,242' 8,753' 8,765' 12’ 6/1/2022 Isolated 6/8/22 T4 9,337' 9,347' 8,860' 8,868' 10’ 5/31/2022 Isolated 6/8/22 T4 9,380' 9,393' 8,901' 8,913' 13’ 5/31/2022 Isolated 6/8/22 T6 9,567' 9,575' 9,085' 9,093' 8’ 5/29/2022 Isolated 6/8/22 T7A 9,738' 9,758' 9,253' 9,273' 20’ 5/29/2022 Isolated 6/8/22 T7B 9,797' 9,817' 9,311' 9,328' 20’ 5/28/2022 Isolated 6/8/22 T11 10,116' 10,136' 9,625' 9,645' 20’ 5/28/2022 Isolated 6/8/22 T12 10,289' 10,308' 9,795' 9,813' 19’ 5/26/2022 Isolated 6/8/22 T12 10,289' 10,308' 9,795' 9,813' 19’ 5/27/2022 Isolated 6/8/22 Updated by SRW 9-10-24 PROPOSED BCU 18RD API: 50-133-20584-01-00 PTD: 222-033 Pad-3 PBTD = 8,583’ MD / 8,115’ TVD TD = 10,461’ MD / 9,964’ TVD RKB to GL = 18.0’ r CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 20” Conductor 154.19 X-65 Weld 19.13” Surf 108’ 13-3/8" Surf Csg 68.0 K-55 BTC 12.415” Surf 2,097’ 9-5/8” Intermediate Csg 40.0 L-80 BTC 8.835” Surf 3,574’ 7” Intermediate Lnr 26.0 L-80 Vam Top 6.276” 3,336’ 7,474’ 4-1/2" Prod Tieback 12.6 L-80 JFEBEAR 3.958” Surf 7,214’ 4-1/2" Prod Lnr 12.6 L-80 JFEBEAR 3.958” 7,219’ 10,432’ TUBING DETAIL 4-1/2” Tubing 12.6 L-80 Surface 7,214’ 1 20” 13-3/8” 4-1/2” JEWELRY DETAIL No. Depth ID Item 1 3,336’ 6.040” 9-5/8” x 7” Liner hanger / LTP Assembly 2 3,574’ NA Whipstock 3 6,590’ 3-1/2” CIBP (9/9/23) 4 6,900’ NA FH Cement retainer, Eline tagged cement on top @ 6852’ PBTD 5 7,150’ NA 4-1/2” CIBP (refence plug tag for cement retainer) 6 7,218’ 5.25” 7” x 4-1/2” Liner hanger / LTP Assembly with PBR 7 7,214’ 3.890” Seal Stem 8 8,036’ N/A 4-1/2” CIBP w/ 35’ cement – TOC 8001’ (8/25/23) 9 8,620’ N/A CIBP w/ 37’ cement – TOC @ 8,583 (7/26/22) 10 8,865’ N/A CIBP w/ 5’ cement – TOC @ 8,860’ (7/20/22) Additional 31’ cement - TOC @ 8,829’ (7/21/22) OPEN HOLE / CEMENT DETAIL 13-3/8” 16” Hole: TOC @ Surface (Original BCU 18) 9-5/8" 12-1/4: Hole: TOC @ 3,440’ (Original BCU 18) 7” 8-1/2” Hole: 125bbls 12ppg lead followed by 18bbls 15.3ppg tail pumped on 5/1/22. 38bbls lead cement back to surface. 5/14/22 CBL shows ToC at 3570’ MD 4-1/2” 6-1/8” Hole: Pumped 30bbl spacer followed by 54bbls 12ppg Type I/II lead followed by 25bbls 15.3ppg Type I/II tail pumped on 5/11/22. Trace spacer back to surface. 5/19/22 CBL shows ToC at 7370’ MD 4-1/2” Inside 7” Casing: Pump 48 bbls of cement through tubing punch @ ~7,100’. TOC @ ~4,778’ 7 4 9-5/8” 2 BCU 18 (Abandoned) 6 7” PERFORATION DETAIL Zone Top MD Btm MD TopTVD Btm TVD Amt Date Comments BEL5 ±6,290' ±6,310' ±5,894' ±5912' ±20' TBD Proposed BEL6 6,342’ 6,348’ 5,942’ 5,947’ 6’ 9/9/2023 Open BEL6 6,354’ 6,361’ 5,953’ 5,960’ 7’ 9/9/2023 Open BEL6 6,366’ 6,375’ 5,964’ 5,972’ 9’ 9/9/2023 Open BEL7 ±6,384' ±6,404' ±5,981' ±5,999' ±20' TBD Proposed BEL7 6,453’ 6,467’ 6,044’ 6,055’ 14’ 9/9/2023 Open BEL8 ±6,516' ±6,526' ±6,103' ±6,112' ±10' TBD Proposed BEL8 ±6,533' ±6,543' ±6,118' ±6,128' ±10' TBD Proposed BEL8 ±6,549' ±6,563' ±6,133' ±6,146' ±14' TBD Proposed BEL8 6,601’ 6,620’ 6,181’ 6,196’ 19’ 9/6/2023 Isolated 9/9/23 BEL9 6,660’ 6,668’ 6,235’ 6,242’ 8’ 9/6/2023 Isolated 9/9/23 BEL22 8,086’ 8,106 7,626’ 7,646’ 41’ 3/10/2023 Isolated 8/25/23 BEL23 8,130’ 8,139’ 7,669’ 7,678’ 9’ 3/10/2023 Isolated 8/25/23 BEL25 8,254' 8,264' 7,791' 7,801' 10' 7/28/2022 Isolated 8/25/23 BEL26 8,281' 8,290' 7,818' 7,827' 9' 7/28/2022 Isolated 8/25/23 BEL27 8,358' 8,372' 7,894' 7,907' 14' 7/27/2022 Isolated 8/25/23 BEL 29-32 T0 – T12 10 BEL 33 FISH DETAILs: Failed WRP at 8867’ ELMD (7/10/22) & Fish left from 8,785-8,829ft - 35ft 3.5"OD cement bailer, 2ft CCL, 7ft 2" weight bar (7/21/22) 9 BEL 25-28 BEL 22-23 Tubing Punch at ~7,100’ TOC @ 4,778’ CBL 9/4/23 8 4 9.5 ppg brine 5 3 Updated by SRW 9-10-24 PROPOSED BCU 18RD API: 50-133-20584-01-00 PTD: 222-033 Pad-3 PERFORATION DETAIL – continued from previous page Zone Top MD Btm MD TopTVD Btm TVD Amt Date Comments BEL27 8,414' 8,424' 7,949' 7,959' 10' 7/27/2022 Isolated 8/25/23 BEL28 8,483' 8,491' 8,017' 8,025' 8' 7/27/2022 Isolated 8/25/23 BEL28 8,504' 8,516' 8,037' 8,049' 12' 7/27/2022 Isolated 8/25/23 BEL29 8,625’ 8,635’ 8,157’ 8,166’ 10’ 6/19/2022 Isolated 7/26/22 BEL29 8,625’ 8,635’ 8,157’ 8,166’ 10’ 6/12/2022 Isolated 7/26/22 BEL29 8,643’ 8,648’ 8,173’ 8,179’ 5’ 6/19/2022 Isolated 7/26/22 BEL29 8,643’ 8,648’ 8,173’ 8,179’ 5’ 6/12/2022 Isolated 7/26/22 BEL29 8,653’ 8,659’ 8,184’ 8,190’ 6’ 6/19/2022 Isolated 7/26/22 BEL29 8,653’ 8,659’ 8,184’ 8,190’ 6’ 6/12/2022 Isolated 7/26/22 BEL29 8,687' 8,707' 8,218' 8,237' 20' 7/16/2022 Isolated 7/26/22 BEL29 8,690' 8,692' 8,221' 8,223' 2' 7/16/2022 Isolated 7/26/22 B30 8,740' 8,745' 8,270’ 8,275’ 5’ 6/11/2022 Isolated 7/26/22 B30 8,775' 8,781' 8,304’ 8,310’ 6’ 6/11/2022 Isolated 7/26/22 B31 8,812' 8,818' 8,341’ 8,347’ 6’ 6/11/2022 Isolated 7/26/22 B32 8,840' 8,849' 8,369’ 8,377’ 9’ 7/9/2022 Isolated 7/26/22 B32 8,840' 8,849' 8,369’ 8,377’ 9’ 6/11/2022 Isolated 7/26/22 B33 8,995' 9,004' 8,522’ 8,530’ 9’ 6/11/2022 Isolated 7/10/22 T0 9,148' 9,153' 8,672' 8,677' 5’ 6/1/2022 Isolated 6/8/22 T2 9,230' 9,242' 8,753' 8,765' 12’ 6/1/2022 Isolated 6/8/22 T4 9,337' 9,347' 8,860' 8,868' 10’ 5/31/2022 Isolated 6/8/22 T4 9,380' 9,393' 8,901' 8,913' 13’ 5/31/2022 Isolated 6/8/22 T6 9,567' 9,575' 9,085' 9,093' 8’ 5/29/2022 Isolated 6/8/22 T7A 9,738' 9,758' 9,253' 9,273' 20’ 5/29/2022 Isolated 6/8/22 T7B 9,797' 9,817' 9,311' 9,328' 20’ 5/28/2022 Isolated 6/8/22 T11 10,116' 10,136' 9,625' 9,645' 20’ 5/28/2022 Isolated 6/8/22 T12 10,289' 10,308' 9,795' 9,813' 19’ 5/26/2022 Isolated 6/8/22 T12 10,289' 10,308' 9,795' 9,813' 19’ 5/27/2022 Isolated 6/8/22 STANDARD WELL PROCEDURE NITROGEN OPERATIONS 12/08/2015 FINAL v1 Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. 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: Cement Annulus, 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 10,461 feet See Schematic feet true vertical 9,964 feet N/A feet Effective Depth measured 8,583 feet N/A feet true vertical 8,115 feet N/A feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth) 4-1/2" 12.6# / L-80 7,214' MD 6,763' TVD Packers and SSSV (type, measured and true vertical depth) N/A N/A 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 323-406 & 323-467 Sr Pet Eng: 7,500psi 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 108' 11 08001 0 7040 1370 measured TVD 9-5/8" 8,430psi 7" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 222-033 50-133-20584-01-00 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: FEDA028083 Beaver Creek / Beluga Gas Pool Beaver Creek Unit (BCU) 18RD Plugs Junk measured Length Intermediate Lnr Produciton 3,574' 4,138' 4,006' Casing Structural 3,350' 6,975' 4-1/2" 3,574' 7,474' 10,432' 9,936' 108'Conductor Surface Intermediate Csg 20" 13-3/8" 108' 2,097' 3,090psi 5,410psi 3,060psi 3,450psi 5,750psi 7,240psi 2,097' 1,038' Burst Collapse 1,500psi 1,950psi 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 9:24 am, Oct 02, 2023 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2023.09.29 16:50:29 - 08'00' Noel Nocas (4361) Rig Start Date End Date 8/24/23 9/9/23 08/24/2023 - Thursday Travel to Beaver Creek office. Fox Energy pumping PJSM & permit. Drive to location. MIRU Fox Energy pumping. PT 250 / 3500 PSI. Test good. SI tubing pressure 900. Start pumping 20 BBL's of 9.5 PPG NaCL w/ corrosion inhibitor at 600 PSI and 2.6 BPM rate. Swap to produced water. 106 BBL's scheduled. Begin pumping at 350 PSI at 2 BPM rate. At 73 BBL's in of peoduced water tubing PSI climbed to over 2000 and was not taking fluid. Call town for approval to go to 3500 PSI. Town approved. SI wing & PT Fox equipment to 3500 PSI. Test good. Resumed pumping produced water. Well broke over at 3450 PSI and was able to complete produced water injection. RDMO Fox Energy pumping. MIRU Yellow Jacket E-Line. PT 250 / 2500 PSI. Test good. RIH w/ 4-1/2" CIBP. Tools fell good to 5300' then encountered new wire coming off drum that was very tight tolerance in flow tubes. Had to work wire and run slow in order to reach depth. On depth at 8036' w/ CIBP. CCL to top of plug = 12' / CCL to be at 8024' to place CIBP at 8036'. Fire setting tool. P/U 100' then go back down and tag plug at 8036'. POOH. OOH. Lay down setting tool. Secure well & equipment. SDFN. Plan forward: Dump 35' of cement in the morning. 08/25/2023- Friday Travel to Beaver Creek office. Yellow Jacket E-Line PJSM & permit. Travel to location. Rig back on to well. Prep dump bailer & cement. RIH w/ 3 dump bailer carrying 11.1 gallons cement = 17.5 fill in tubing. Tag existing CIBP at 8036. P/U 5. Fire dump bailer. Allow time to drain. Work tools up & down to clear. POOH. OOH. Reload dump bailer. RIH w/ 3 dump bailer carrying 11.1 gallons cement = 17.5 fill in tubing. Current TOC 8018. Positioned bailer at 8015. Fired dump bailer. Allow time to drain. Work tools up & down to clear. POOH. Well currently has CIBP set at 8036 with TOC at 8001. OOH. RDMO YJ E-Line. 08/28/2023 - Monday YJ E-line, Fox energy obtain PTW and PJSM. Discuss scope of work. Access work site, move in and spot E-line/crane, pump, returns tank, and vac truck. Bleed tubing from 70 psi to 0 psi. MU hard line from fluid pump to tubing wing and fill well with fresh water @ 1 bbl/min. Total - 50 bbls. MU tubing puncher: 1-9/16" x 6' (6spf/0D phased) loaded with 1/4"-3/8" WT charges. (1.5' CCL to top shot). PT 250/2500 psi. Pass RIH, locate liner packer at 7200' and tie-in. Pressure up tubing to 535 psi. position gun at 7100'. Fire gun, pressure dropped 20 psi on tubing, no change on IA. POOH. OOH. All shots fired. MU return line to tank on IA. Pressure up tubing to 2500 psi attempting to break circulation. No change. Permission given to increase to 3500 psi. No joy. MU Gun #2 - 1-9/16" x 6' (6spf/0D) loaded with 3/8"x 1/2" WT charges. (4' CCL to T.S.). RIH, tie-in to liner hanger, pressure up to 530 psi and fire gun. Tubing dropped to 30 psi. POOH. OOH. All shots fired. Roll on pump and circulate 20 bbls down tubing at 3.5 bbls/min. at 300 psi, taking returns to tank. SI IA wing and CMIT TxIA to 2500 psi. (10 min. - Pass) Secure equipment and release Fox pumping crew and vac truck. E-line MU 3.50" CIBP. (6' CCL to top of plug). RIH, tie-in at liner hanger and set plug at 7150'. POOH. Plug to be used for depth control for setting cement retainer with CT. OOH. Secure well, RDMO E-line. Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BCU-18RD 50-133-20584-01-00 222-033 Rig Start Date End Date 8/24/23 9/9/23 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BCU-18RD 50-133-20584-01-00 222-033 08/29/2023 - Tuesday Fox CT crew and Cruz crane meet at BC office, sign in, obtain PTW and hold PJSM. Move in and spot CTU and 100T crane at well site. Decommission well house and move aside. MU hard iron to choke manifold and prep BOP stack. MI and spot Rain for Rent supply tank. ND tree flange and NU BOP stack on tree. Complete MU hard lines to BOP stack. Confirm all connections are hammered up. AOGCC (JIm Regg) waived witness to BOP test on 28-Aug-23. Lubricate and bleed lines and stack with PT triplex and start BOP test 250 psi / 3500 psi. Test 1. Inner reel valve, choke valves 3,4 & 5 and blind shears. Test 2: Blind shears, choke valves 1,2 &3 Test 3: pipe slips, flow valve 1&4. Test 4: pipe slips, flow valves 2&3. Accumulator draw down: Start - 2900 psi . After function: 2250 psi - Accum. recharge: 8 sec. Closing times: Blinds - 16 sec. Pipe slips - 15 sec. Bleed down lines and secure well. Unload 90 bbls fresh water into supply tank from G&I. SDFN and leave location. 08/30/2023 - Wednesday Waiting on Cement Crew from Offshore job. Monitor well. T/I = 0/0 08/31/2023 - Thursday Waiting on Cement Crew from Offshore job. Monitor well. T/I = 0/0 09/01/2023- Friday Waiting on Cement Crew from Offshore job. Monitor well. T/I = 0/0 09/02/2023 - Saturday Waiting on Cement Crew from Offshore job. Monitor well. T/I = 0/0 09/03/2023 - Sunday Fox CT, Cruz and YJOS tool hand meet at BC office, sign in, obtain PTW and hold PJSM. Spot crane, PU injector head and lubricator. M/U 2.188" OD CTC on 1-3/4" coil. Pull test to 30K lbs. Fill coil w/ fresh water (33.4 bbls) and PT 250psi / 3500 psi. Pass M/U YJ disconnect, 3.50" OD hyd. setting tool with 3.563" OD Alpha cement retainer. Stab on well and shell test stack and pump iron 250 psi / 3500 psi. Pass. RIH, dry tag CIBP at 7166' (CTM) correct to 7150' (EL plug depth). PU to 6900'. Open IA and pump down CT, confirm circulation. Insert 5/8" ball in reel and pump 27 bbls at 1 bbl/min. then SD pump. Allow ball to settle then roll on pump until ball seats, CT pressures up to 2500 psi and sets retainer (33 bbls away). PT tubing (CT IA) to 1500psi. Hold TGM with cement crew. Start cement batch mix of 53 bbls / 15.3 ppg slurry. Start pumping operation at 1 bbl/min. Pump 1 hour (50 bbls) and follow with 32 bbls water. Offline with pump, SI IA and PU on coil to 40K lbs. (16K overpull) and release from cement retainer. PU 100' and circulate bottoms up at 1.5 bbls/min.(84 bbls). POOH holding 500 psi on tubing. Total pumped 265 bbls. OOH. Break down tools, rig back injector and nightcap well head. Rig Start Date End Date 8/24/23 9/9/23 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BCU-18RD 50-133-20584-01-00 222-033 09/04/2023 - Monday YJ E-line and Cruz crane arrive at BC office, sign in, PTW and PSM. R/U and M/U 2-3/4" radial CBL/GR/CCL logging tool. Stab on well and PT 250 psi / 2500 psi. Calibrate tools in free pipe at 600' and RIH. Tag PBTD at 6845'. Log 200' repeat section. Drop down to bottom and log main pass. Well had good bond throughout -TOC at 4780'. POOH. OOH w/ e-line (RDMO). RU Fox and perform MIT x IA 250 psi / 2500 psi. Chart for 30 minutes. Pass. PU injector head and lubricator and prepare to RIH. Open swab and RIH w/ 1-3/4" coil and 2.881" OD reverse circ nozzle. Cool down N2 pump and PT N2 lines to 3500 psi. At 4000' begin reverse circulating with N2 at 900 psi / 500 scfm. Walk up to 2300 psi / 800 scfm. Continue GIH and lightly tag bottom, PU 10' and continue reversing out recovering 137 bbls fluid (Calculated volumes - tubing 104 bbls/ CT = 33.4 bbls). Start POOH and go offline with N2 trapping 2000 psi on well. Total N2 used - 160,278 SCF. RD CT and N2 pumping equipment, secure well and move well house over well. 09/06/2023 - Wednesday YJ E-line arrive at BC office, sign in, obtain PTW and hold PJSM. MIRU. M/U 2-3/4" Gun Gamma Ray/CCL to 2-3/4" OD x 8' HSC (6spf/60D) (12' CCL T.S.) PU tools and lubricator, move to well and PT 250 psi / 2500 psi. Pass. Address swab and upper master valves leaking through stems. Call out valve service hands. SITP (N2) - 1900 psi. Open swab and RIH. Tagged PBTD at 6852'. Log correlation pass and send to GE/RE. Confirmed on depth. Draw tubing down to 1855 psi. Positioned gun and shoot the Bel 9 interval 6660'-6668' (12:00 pm). POOH. Initial: 1855 psi 5 min: 1860 psi 10 min: 1862 psi 15 min: 1863 psi OOH. All shots fired. Gun DRY. (1866 psi). SI lwr. master valve and valve hands repacked tree valves. Change out GR/CCL. M/U Gun #2 - 2-3/4" x 18' HSC (6spf/60D) (11' CCL T.S.) Open swab (1875 psi), RIH, correlate, confirm on depth, position gun and shoot the Bel 8 interval 6601'-6619' (14:50). Initial: 1915 psi 5 min: 1929 psi 10 min: 1937 psi 15 min: 1944 psi OOH. All shots fired. Gun #2 WET. Communicate w/ OE/RE/GE engineers regarding plan forward. SITP - 2005 psi, PU GPT, RIH and locate FL at 6435' (166' above perfs at 6601'-19'). POOH. Discuss next plan w/ engineers. OOH. w/ GPT. Move in flowback tank and draw well down to 1500 psi, SI, RIH w/ GPT and locate FL at 6040'. (Up approx. 400' from SI GPT.). Wait 30 min. and locate FL at 5825'. Allow well to build pressure. Orders to POOH and RD. OOH. Secure well. RDMO E- line. Final SITP 1735 psi 09/07/2023 - Thursday No activity to report. 09/08/2023- Friday No activity to report. Rig Start Date End Date 8/24/23 9/9/23 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BCU-18RD 50-133-20584-01-00 222-033 09/09/2023 - Saturday YJ E-line and SLB N2, arrive at BC office, sign in, obtain PTW and hold sim-ops PJSM. RU E-line and N2. M/U GPT, #10 setting tool with 3.50" CIBP. (CCL to plug top 19'). Move lubricator and tools to well head. N2 transport arrives, cool down N2 pump and PT lines and lubricator 500 psi / 4000 psi. SITP - 1793 psi. Open swab and RIH. Begin N2 pressure build. Locate fluid level at 5460'. Reach 2550 psi @ 1000 scf/min and pressure breaks over, continue pumping at 3100 psi. Fluid moving at 30 ft/min. Monitor FL with GPT and confirm fluid is depressed through perfs at 6660'-6668'. SD N2 pumps. Run CIBP correlation (adjust -1') and set CIBP at 6590' with 2410 psi on tubing. POOH. Bleed tubing down to 1600 psi and SI for 30 minutes performing negative test on plug. Pass. Pressure back up to 1800 psi and RD N2 equipment. Total 135,000 scfs pumped. M/U 2-3/4" switch guns (14' & 9'). (CCL to Gun #1 - 21'. Gun #2 - 10.5'). Open swab and RIH. Correlate, confirm on depth and fire Gun #1 in BEL 7 interval 6453'-6467' (14') Initial: 1818 psi 5 min: 1812 psi 10 min: 1814 psi 15 min: 1816 psi Position and fire Gun #2 in BEL 6 interval 6366' - 6375' (9') Initial: 1817 psi 5 min: 1874 psi 10 min: 1910 psi 15 min: 1940 psi. POOH. OOH. All shots fired. Guns dry. M/U Guns 3 & 4 switch guns (CCL -Gun #3 - 17'. Gun #4 - 9.5'). Open swab and RIH. (2004 psi). Correlate, confirm on depth and fire Gun #3 in BEL 6 interval 6354'-61' (7') Initial: 2028 psi 15 min: 2028 psi Position and fire Gun #4 in BEL 6 interval 6342'-48' (6'). Initial: 2027 psi 15 min: 2031 psi. POOH. OOH. All shots fired. Guns dry. Operations RU flow back tank and begin to vent off N2. Bleed down tubing to 1700 psi, SI and monitor buildup. Pressure rises to 2055 in 7 minutes. Continue venting at 1800 psi until LEL's are detected. Divert flow to sales and flow test well at 1.0 mcf / 2080psi. Continue flow test through night. Updated by DMA 09-22-23 SCHEMATIC BCU 18RD API: 50-133-20584-01-00 PTD: 222-033 Pad-3 PBTD = 8,583 MD / 8,115 TVD TD = 10,461 MD / 9,964 TVD RKB to GL = 18.0 r CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 20 Conductor 154.19 X-65 Weld 19.13 Surf 108 13-3/8" Surf Csg 68.0 K-55 BTC 12.415 Surf 2,097 9-5/8 Intermediate Csg 40.0 L-80 BTC 8.835 Surf 3,574 7 Intermediate Lnr 26.0 L-80 Vam Top 6.276 3,336 7,474 4-1/2" Prod Tieback 12.6 L-80 JFEBEAR 3.958 Surf 7,214 4-1/2" Prod Lnr 12.6 L-80 JFEBEAR 3.958 7,219 10,432 TUBING DETAIL 4-1/2 Tubing 12.6 L-80 Surface 7,214 1 20 13-3/8 4-1/2 JEWELRY DETAIL No. Depth ID Item 1 3,336 6.040 9-5/8 x 7 Liner hanger / LTP Assembly 2 3,574 NA Whipstock 3 6,590 3-1/2 CIBP (9/9/23) 4 6,900 NA FH Cement retainer, Eline tagged cement on top @ 6852 PBTD 5 7,150 NA 4-1/2 CIBP (refence plug tag for cement retainer) 6 7,218 5.25 7 x 4-1/2 Liner hanger / LTP Assembly with PBR 7 7,214 3.890 Seal Stem 8 8,036 N/A 4-1/2 CIBP w/ 35 cement TOC 8001 (8/25/23) 9 8,620 N/A CIBP w/ 37 cement TOC @ 8,583 (7/26/22) 10 8,865 N/A CIBP w/ 5 cement TOC @ 8,860 (7/20/22) Additional 31 cement - TOC @ 8,829 (7/21/22) OPEN HOLE / CEMENT DETAIL 13-3/8 16 Hole: TOC @ Surface (Original BCU 18) 9-5/8" 12-1/4: Hole: TOC @ 3,440 (Original BCU 18) 7 8-1/2 Hole: 125bbls 12ppg lead followed by 18bbls 15.3ppg tail pumped on 5/1/22. 38bbls lead cement back to surface. 5/14/22 CBL shows ToC at 3570 MD 4-1/2 6-1/8 Hole: Pumped 30bbl spacer followed by 54bbls 12ppg Type I/II lead followed by 25bbls 15.3ppg Type I/II tail pumped on 5/11/22. Trace spacer back to surface. 5/19/22 CBL shows ToC at 7370 MD 4-1/2 Inside 7 Casing: Pump 48 bbls of cement through tubing punch @ ~7,100. TOC @ ~4,778 7 4 9-5/8 2 BCU 18 (Abandoned) 6 7 PERFORATION DETAIL Zone Top MD Btm MD TopTVD Btm TVD Amt Date Comments BEL6 6,342 6,348 5,942 5,947 6 9/9/2023 Open BEL6 6,354 6,361 5,953 5,960 7 9/9/2023 Open BEL6 6,366 6,375 5,964 5,972 9 9/9/2023 Open BEL7 6,453 6,467 6,044 6,055 14 9/9/2023 Open BEL8 6,601 6,620 6,181 6,196 19 9/6/2023 Isolated 9/9/23 BEL9 6,660 6,668 6,235 6,242 8 9/6/2023 Isolated 9/9/23 BEL22 8,086 8,106 7,626 7,646 41 3/10/2023 Isolated 8/25/23 BEL23 8,130 8,139 7,669 7,678 9 3/10/2023 Isolated 8/25/23 BEL25 8,254' 8,264' 7,791' 7,801' 10' 7/28/2022 Isolated 8/25/23 BEL26 8,281' 8,290' 7,818' 7,827' 9' 7/28/2022 Isolated 8/25/23 BEL27 8,358' 8,372' 7,894' 7,907' 14' 7/27/2022 Isolated 8/25/23 PERFORATION DETAIL continued on following page BEL 29-32 T0 T12 10 BEL 33 FISH DETAILs: Failed WRP at 8867 ELMD (7/10/22) & Fish left from 8,785-8,829ft - 35ft 3.5"OD cement bailer, 2ft CCL, 7ft 2" weight bar (7/21/22) 9 BEL 25-28 BEL 22-23 Tubing Punch at ~7,100 TOC @ 4,778 CBL 9/4/23 8 4 9.5 ppg brine 5 3 Updated by DMA 09-22-23 SCHEMATIC BCU 18RD API: 50-133-20584-01-00 PTD: 222-033 Pad-3 PERFORATION DETAIL continued from previous page Zone Top MD Btm MD TopTVD Btm TVD Amt Date Comments BEL27 8,414' 8,424' 7,949' 7,959' 10' 7/27/2022 Isolated 8/25/23 BEL28 8,483' 8,491' 8,017' 8,025' 8' 7/27/2022 Isolated 8/25/23 BEL28 8,504' 8,516' 8,037' 8,049' 12' 7/27/2022 Isolated 8/25/23 BEL29 8,625 8,635 8,157 8,166 10 6/19/2022 Isolated 7/26/22 BEL29 8,625 8,635 8,157 8,166 10 6/12/2022 Isolated 7/26/22 BEL29 8,643 8,648 8,173 8,179 5 6/19/2022 Isolated 7/26/22 BEL29 8,643 8,648 8,173 8,179 5 6/12/2022 Isolated 7/26/22 BEL29 8,653 8,659 8,184 8,190 6 6/19/2022 Isolated 7/26/22 BEL29 8,653 8,659 8,184 8,190 6 6/12/2022 Isolated 7/26/22 BEL29 8,687' 8,707' 8,218' 8,237' 20' 7/16/2022 Isolated 7/26/22 BEL29 8,690' 8,692' 8,221' 8,223' 2' 7/16/2022 Isolated 7/26/22 B30 8,740' 8,745' 8,270 8,275 5 6/11/2022 Isolated 7/26/22 B30 8,775' 8,781' 8,304 8,310 6 6/11/2022 Isolated 7/26/22 B31 8,812' 8,818' 8,341 8,347 6 6/11/2022 Isolated 7/26/22 B32 8,840' 8,849' 8,369 8,377 9 7/9/2022 Isolated 7/26/22 B32 8,840' 8,849' 8,369 8,377 9 6/11/2022 Isolated 7/26/22 B33 8,995' 9,004' 8,522 8,530 9 6/11/2022 Isolated 7/10/22 T0 9,148' 9,153' 8,672' 8,677' 5 6/1/2022 Isolated 6/8/22 T2 9,230' 9,242' 8,753' 8,765' 12 6/1/2022 Isolated 6/8/22 T4 9,337' 9,347' 8,860' 8,868' 10 5/31/2022 Isolated 6/8/22 T4 9,380' 9,393' 8,901' 8,913' 13 5/31/2022 Isolated 6/8/22 T6 9,567' 9,575' 9,085' 9,093' 8 5/29/2022 Isolated 6/8/22 T7A 9,738' 9,758' 9,253' 9,273' 20 5/29/2022 Isolated 6/8/22 T7B 9,797' 9,817' 9,311' 9,328' 20 5/28/2022 Isolated 6/8/22 T11 10,116' 10,136' 9,625' 9,645' 20 5/28/2022 Isolated 6/8/22 T12 10,289' 10,308' 9,795' 9,813' 19 5/26/2022 Isolated 6/8/22 T12 10,289' 10,308' 9,795' 9,813' 19 5/27/2022 Isolated 6/8/22 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing 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): 10,461'N/A Casing Collapse Structural Conductor 1,500psi Surface 1,950psi Intermediate Csg 3,090psi Intermediate Lnr 5,410psi 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 Other: Cement Annulus, N2 See Schematic Beaver Creek Beluga Gas 4,138' 7" 7,474' 6,975' 7,240psi 8,620 & 8,865 Length N/A; N/A N/A; N/A 9,964' 8,583' 8,115' 20" 13-3/8" See Schematic Perforation Depth MD (ft): 3,574' 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Beaver Creek Unit (BCU) 18RDCO 237D and possibly Sterling Gas 9,936'4-1/2" ~2,185psi 4,006' 2,097' Size August 21, 2023 4-1/2" 10,432' 108' 9-5/8"3,574' 2,097' MD Hilcorp Alaska, LLC PRESENT WELL CONDITION SUMMARY 108' 3,350' 108' 12.6# / L-80 TVD Burst 7,274' 8,430psi 2,038' Tubing MD (ft): 3,450psi 5,750psi 3,060psi Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEDA028083 222-033 50-133-20584-01-00 Tubing Size: Proposed Pools: Beluga Gas AOGCC USE ONLY Tubing Grade: chelgeson@hilcorp.com 907-777-8405 Perforation Depth TVD (ft): 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: Chad Helgeson, Operations Engineer No Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 3:35 pm, Aug 16, 2023 323-467 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2023.08.16 15:08:51 - 08'00' Noel Nocas (4361) 10-404 August 21, 2023 Conditions on original sundry 323-406 still apply. DSR-8/18/23SFD 8/21/2023BJM 8/23/23 The 10-404 should indicate Correct location of CIBP (jewelry item #5) as indicated on the diagram. Aug 16, 2023 *&: 08/24/23 Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2023.08.24 10:09:34 -08'00' RBDMS JSB 082923 BCU-18RD Cement Annulus Rev 1 Well Name: BCU-18RD API Number: 50-133-20584-01-00 Current Status: Online Gas Well Permit to Drill Number: 222-033 First Call Engineer: Chad Helgeson (907) 777-8405 (O) (907) 299-4824 (C) Second Call Engineer: Jake Flora (907) 777-8442 (O) (720) 988-5375 (C) Maximum Expected BHP: 2,809 psi @ 6242’ TVD 0.45 psi/ft gradient at TD MASP: 2,185 psi BHP minus 0.1 psi/ft gradient Updates/changes in red font. Well History: BCU-18RD was drilled in the spring of 2022. We have been unsuccessful finding sustainable zones to produce gas. The Tyonek zone was plugged back and the well currently is produced one day a week, from the Beluga interval, but it does not sustain production. The goal of this sundry is to plugback the lower Beluga, pump a cement annulus isolation job and perforate the upper Beluga. There is a contingency to plug and perf the Sterling sands if the Upper Beluga is unsuccessful. Notes Regarding Wellbore Condition x 4-1/2” liner top @ 7,218’ with cement to 7370’ x Cement Bond Log in the 7” cement top @ 3570’ x Max Inclination = 28.6 degrees at 2324’ MD x Tested 7” liner to 4,000psi 5/2/22, tested 4-1/2” liner to 4,000 psi on 5/14/22 E-Line procedure 1. RU Pump truck and batch mixer. Mix 20 bbls of 9.5 ppg NaCl corrosion inbited brine w/ (1,300ft of KW fluid) Pump into well followed by 106 bbls of PW. To kill well and put KW fluid between plugs. 2. MIRU E-line and pressure control equipment PT lubricator 250psi low / 2,500psi high. 3. MU 4-1/2” CIBP Composite Plug (leaving option to mill out in the future if we want to combine production with lower Beluga) 4. RIH and set 4-1/2” Composite CIBP plug at ±8,036’ MD a. Tag plug b. BLM Regulations call for plug to be set 50’-100’ of perfs @ 8,086’ MD 5. RIH and dump bail 35’15’ of cement on top of plug (est ToC ±8,001’ 8,011’ MD) o <35ft of cement will be placed on plug in the event of possible drilling out plug in the future, but still function as a plug over time 6. Load tubing with source/lease water (8.5 ppg), lubricate & bleed, pump slow o ~121bbl WBV 7. MU and RIH with tubing punch o Punch tubing at ±7,100’ 7,000’ MD (±6,651’ 6,554’ TVD) o 7” x 4-1/2” Annulus is 8.6ppg inhibited brine (Ensure tubing and annulus have 0 psi on them) 8. Establish circulation from tubing to IA o Optional: Set a cement retainer @ ±6,900’ 6,990’to pump cement through full bore 9. RDMO EL and pump truck 10. Once circulation is established in both directions: o IA volume = ~250 bbls i. 4-1/2” x 9-5/8” = 0.0562 x 3,336ft = 187 bbls BCU-18RD Cement Annulus Rev 1 ii. 4-1/2” x 7” = 0.0186 bbl/ft x 3,364ft = 63 bbls o Tubing volume = 0.0152 bbl/ft x 7000ft = ~107 bbls 11. CMIT-TxIA to 2500psi (no chart required) 4-1/2” x 7” IA Cementing Procedure 12. RU cement truck, PT lines to 250psi low / 3,000psi high 13. Mix and pump ~15.3ppg cement down the tubing, taking returns up the 4-1/2” x 9-5/8” IA o Manage IA back pressure to keep the cement from running away down tubing 14. Planned TOC in IA is ±4,500’ 4,900’ MD (4,235’ 4,616’ TVD). (±48 34bbls required) a. 0.0186bbl/ft x 2600 1800ft =48 34 bbls 15. Displace per OE (use ball and cement head for dropping) displace ball down to cement retainer tubing cut, 106bbls b. 0.0152 bbl/ft x 6,900ft 7,000ft = ~105 106 bbls 16. SI master valve and IA and trap pressure on the tubing (~850 700psi) with annulus pressure at 0 psi. 17. RDMO cementers 18. Wait minimum of 24hrs on cement 19. MIRU EL and pressure control equipment 20. PT lubricator to 250psi Low / 2,500 psi High 21.RIH and tag TOC and complete CBL (submit CBL to AOGCC and obtain approval before perforating) 22. RD EL 23. MIT-IA to 2500psi for 30 charted minutes CT Procedure 24. MIRU CTU, 24hr notice for BOP test 25. Conduct BOP test to 250psi Low / 3500psi High 26. If cement tag is shallower than 6,700’ Mill out cement to 6,700’ using lease water o Confirm with engineer if the plug at 8,036’ needs to be milled up 27. If tag is deeper than 6,600’, RIH reverse out a minimum of 100 bbls of water 28. Trap N2 pressure on tubing per OE/RE recommendation for perforating, ~1700 psi (25% underbalanced) 29. RDMO CT E-Line Perf procedure 30. MIRU E-line and pressure control equipment 31. PT lubricator to 250psi low / 2500 psi High 32. RIH and perforate as directed by reservoir team Pool/PA Zone Top MD Btm MD TopTVD Btm TVD Amt Beluga BEL5 ±6,286’ ±6,311’ ±5,890’ ±5,913’ ±25’ Beluga BEL6 ±6,342’ ±6,348’ ±5,942’ ±5,947’ ±6’ Beluga BEL6 ±6,354’ ±6,361’ ±5,953’ ±5,960’ ±7’ Beluga BEL6 ±6,366’ ±6,375’ ±5,964’ ±5,972’ ±9’ Beluga BEL7 ±6,384’ ±6,398’ ±5,981’ ±5,994’ ±14’ Beluga BEL7 ±6,453’ ±6,468’ ±6,044’ ±6,056’ ±15’ (submit CBL to AOGCC and obtain approval before perforating) BCU-18RD Cement Annulus Rev 1 Beluga BEL8 ±6,478’ ±6,482’ ±6,067’ ±6,071’ ±4’ Beluga BEL8 ±6,515’ ±6,523’ ±6,101’ ±6,109’ ±8’ Beluga BEL8 ±6,534’ ±6,541’ ±6,119’ ±6,126’ ±7’ Beluga BEL8 ±6,549’ ±6,561’ ±6,133’ ±6,144’ ±12 Beluga BEL8 ±6,601’ ±6,620’ ±6,181’ ±6,196’ ±19 Beluga BEL9 ±6,660’ ±6,668’ ±6,235’ ±6,242’ ±8 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 shot and record. e. These sands are in the Beluga Gas Pool per CO 237D. 33. Turn well over to operations and flow the well. If the well is productive the rest of the perfs will not be completed on this sundry. Contingency if Beluga Gas Pool is not productive or sustained, Beluga will be isolated or commingled as allowed per CO 237D (where Rule 5 will be followed) – If commingling is the path planned – a separate submittal will be created and sent to BLM: 34. MIRU N2 Pump and E-line with pressure control equipment 35. PT lubricator and pump lines to 250psi low / 4,000 psi High 36. MU CIBP with GPT tool (for isolating Beluga and Sterling sands) 37. Pressure up with N2 and push water away, verifying depth of water with GPT (water must be deeper than 5,700’) 38. RIH and set 4-1/2” CIBP plug at ±6,236’ MD o Tag CIBP o Regulations call for plug to be set within 50’ of Beluga perfs, current @ ~6,286’ MD) 39. RIH and dump bail 35’ of cement on top of plug (est ToC ±6,201’ MD) 40. RIH and perforate Sterling Gas Pool sands Pool/PA Zone Top MD Btm MD TopTVD Btm TVD Amt Sterling Ster B3U ±5,417’ ±5,429’ ±5,092’ ±5,102’ ±12’ Sterling Ster B3L ±5,439’ ±5,465’ ±5,111’ ±5,135’ ±26’ Sterling Ster B4 ±5,503’ ±5,520’ ±5,170’ ±5,185’ ±17’ Sterling Ster B5 ±5,565’ ±5,585’ ±5,227’ ±5,244’ ±26’ Sterling Ster B6 ±5,605’ ±5,640’ ±5,263’ ±5,295’ ±35’ o Correlate using Open Hole Correlation Log provided by Geologist. Send the correlation pass to Geologist and Reservoir Engineer for confirmation. o Record tubing surface pressure before and after gun firing at 0, 5, 10, 15 min reading intervals. o The Sterling sands are governed by CO 237D. 41. Turn well over to operations and flow the well. Contingency if Beluga Gas Pool is not productive or sustained, BCU-18RD Cement Annulus Rev 1 Post-Perf MIT-IA 42. Perform MIT-IA to 2000psi once job is complete and well has been brought online within 30 days. E-line Procedure (Contingency) If any zone produces sand and/or water or needs isolated: 1. MIRU Eline 2. Pressure test equipment to 3,000 psi High/250 psi Low 3. Eline run PT to find fluid level 4. Use N2 or Gas Lift to push fluid below perfs (verify fluid depth with PT tool) 5. PU 4-1/2” CIBP, WRP, or patch a. If a CIBP is set (it must be set within 50ft of the top perf being plugged back) b. Dump bail 35ft of cement on top of CIBP (unless there isn’t enough room to the next perf) c. Any CIBP with less than 35’ of cement will need approval from BLM prior to adding next set of perfs 6. If necessary to cleanout or unload well with coiled tubing, RU same coil equipment used in initial completion a. Test BOPs, 3,000 psi High/ 250 psi Low b. Cleanout with N2 or foam c. Set 4-1/2” plug or patch Attachments: 1. Current schematic 2. Proposed Schematic dated 8-15-23 3. Standard Well procedure – N2 Operations Updated by CAH 8-15-23 PROPOSED BCU 18RD API: 50-133-20584-01-00 PTD: 222-033 Pad-3 PBTD = 8,583’ MD / 8,115’ TVD TD = 10,461’ MD / 9,964’ TVD RKB to GL = 18.0’CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 20” Conductor 154.19 X-65 Weld 19.13” Surf 108’ 13-3/8" Surf Csg 68.0 K-55 BTC 12.415” Surf 2,097’ 9-5/8” Intermediate Csg 40.0 L-80 BTC 8.835” Surf 3,574’ 7” Intermediate Lnr 26.0 L-80 Vam Top 6.276” 3,336’ 7,474’ 4-1/2" Prod Tieback 12.6 L-80 JFEBEAR 3.958” Surf 7,214’ 4-1/2" Prod Lnr 12.6 L-80 JFEBEAR 3.958” 7,219’ 10,432’ 1 20” 13-3/8” 4-1/2” JEWELRY DETAIL No. Depth ID Item 1 3,336’ 6.040” 9-5/8” x 7” Liner hanger / LTP Assembly 23,574’N/AWhipstock 2A ±6,900’ NA EZDrill squeeze cement retainer (Poppit style) 3 7,218’ 5.25” 7” x 4-1/2” Liner hanger / LTP Assembly with PBR 4 7,214’ 3.890” Seal Stem 4B ±8,036’ N/A 4-1/2” CIBP w/ 35’ cement 5 8,620’ N/A CIBP w/ 37’ cement – TOC @ 8,583 (7/26/22) 68,865’N/ACIBP w/ 5’ cement – TOC @ 8,860’ (7/20/22) Additional 31’ cement - TOC @ 8,829’ (7/21/22) OPEN HOLE / CEMENT DETAIL 13-3/8” 16” Hole: TOC @ Surface (Original BCU 18) 9-5/8" 12-1/4: Hole: TOC @ 3,440’ (Original BCU 18) 7”8-1/2” Hole: 125bbls 12ppg lead followed by 18bbls 15.3ppg tail pumped on 5/1/22. 38bbls lead cement back to surface.5/14/22 CBL shows ToC at 3570’ MD 4-1/2” 6-1/8” Hole: Pumped 30bbl spacer followed by 54bbls 12ppg Type I/II lead followed by 25bbls 15.3ppg Type I/II tail pumped on 5/11/22. Trace spacer back to surface.5/19/22 CBL shows ToC at 7370’ MD 4-1/2”Inside 7” Casing: Pump 48 bbls of cement through tubing punch @ ~7,100’. Proposed TOC @ ~4,500’ 4 4 9-5/8” 2 BCU 18 (Abandoned) 3 7” PERFORATION DETAIL Zone Top MD Btm MD TopTVD Btm TVD Amt Date Comments Ster B3U ±5,417’ ±5,429’ ±5,092’ ±5,102’ ±12’ TBD Contingency Ster B3L ±5,439’ ±5,465’ ±5,111’ ±5,135’ ±26’ TBD Contingency Ster B4 ±5,503’ ±5,520’ ±5,170’ ±5,185’ ±17’ TBD Contingency Ster B5 ±5,565’ ±5,585’ ±5,227’ ±5,244’ ±26’ TBD Contingency Ster B6 ±5,605’ ±5,640’ ±5,263’ ±5,295’ ±35’ TBD Contingency BEL5 ±6,286’ ±6,311’ ±5,890’ ±5,913’ ±25’ TBD Proposed BEL6 ±6,342’ ±6,348’ ±5,942’ ±5,947’ ±6’ TBD Proposed BEL6 ±6,354’ ±6,361’ ±5,953’ ±5,960’ ±7’ TBD Proposed BEL6 ±6,366’ ±6,375’ ±5,964’ ±5,972’ ±9’ TBD Proposed BEL7 ±6,384’ ±6,398’ ±5,981’ ±5,994’ ±14’ TBD Proposed BEL7 ±6,453’ ±6,468’ ±6,044’ ±6,056’ ±15’ TBD Proposed BEL8 ±6,478’ ±6,482’ ±6,067’ ±6,071’ ±4’ TBD Proposed BEL8 ±6,515’ ±6,523’ ±6,101’ ±6,109’ ±8’ TBD Proposed BEL8 ±6,534’ ±6,541’ ±6,119’ ±6,126’ ±7’ TBD Proposed BEL8 ±6,549’ ±6,561’ ±6,133’ ±6,144’ ±12’ TBD Proposed BEL8 ±6,601’ ±6,620’ ±6,181’ ±6,196’ ±19’ TBD Proposed BEL9 ±6,660’ ±6,668’ ±6,235’ ±6,242’ ±8’ TBD Proposed BEL22 8,086’ 8,106 7,626’ 7,646’ 41’ 3/10/2023 Isolated BEL23 8,130’ 8,139’ 7,669’ 7,678’ 9’ 3/10/2023 Isolated BEL25 8,254' 8,264' 7,791' 7,801' 10' 7/28/2022 Isolated BEL26 8,281' 8,290' 7,818' 7,827' 9' 7/28/2022 Isolated BEL27 8,358' 8,372' 7,894' 7,907' 14' 7/27/2022 IsolatedBEL 29-32 T0 – T12 6 BEL 33 FISH DETAILs: Failed WRP at 8867’ ELMD (7/10/22) & Fish left from 8,785-8,829ft - 35ft 3.5"OD cement bailer, 2ft CCL, 7ft 2" weight bar (7/21/22) 5 BEL 25-28 BEL 22-23 Tubing Punch at ~7,100’ Proposed TOC @ ~4,500’ 4B 2A 9.5 ppg brine Updated by CAH 8-15-23 SCHEMATIC BCU 18RD API: 50-133-20584-01-00 PTD: 222-033 Pad-3 PERFORATION DETAIL – continued from previous page Zone Top MD Btm MD TopTVD Btm TVD Amt Date Comments BEL27 8,414' 8,424' 7,949' 7,959' 10' 7/27/2022 Isolated BEL28 8,483' 8,491' 8,017' 8,025' 8' 7/27/2022 Isolated BEL28 8,504' 8,516' 8,037' 8,049' 12' 7/27/2022 Isolated BEL29 8,625’ 8,635’ 8,157’ 8,166’ 10’ 6/19/2022 Isolated 7/26/22 BEL29 8,625’ 8,635’ 8,157’ 8,166’ 10’ 6/12/2022 Isolated 7/26/22 BEL29 8,643’ 8,648’ 8,173’ 8,179’ 5’ 6/19/2022 Isolated 7/26/22 BEL29 8,643’ 8,648’ 8,173’ 8,179’ 5’ 6/12/2022 Isolated 7/26/22 BEL29 8,653’ 8,659’ 8,184’ 8,190’ 6’ 6/19/2022 Isolated 7/26/22 BEL29 8,653’ 8,659’ 8,184’ 8,190’ 6’ 6/12/2022 Isolated 7/26/22 BEL29 8,687' 8,707' 8,218' 8,237' 20' 7/16/2022 Isolated 7/26/22 BEL29 8,690' 8,692' 8,221' 8,223' 2' 7/16/2022 Isolated 7/26/22 B30 8,740' 8,745' 8,270’ 8,275’ 5’ 6/11/2022 Isolated 7/26/22 B30 8,775' 8,781' 8,304’ 8,310’ 6’ 6/11/2022 Isolated 7/26/22 B31 8,812' 8,818' 8,341’ 8,347’ 6’ 6/11/2022 Isolated 7/26/22 B32 8,840' 8,849' 8,369’ 8,377’ 9’ 7/9/2022 Isolated 7/26/22 B32 8,840' 8,849' 8,369’ 8,377’ 9’ 6/11/2022 Isolated 7/26/22 B33 8,995' 9,004' 8,522’ 8,530’ 9’ 6/11/2022 Isolated 7/10/22 T0 9,148' 9,153' 8,672' 8,677' 5’ 6/1/2022 Isolated 6/8/22 T2 9,230' 9,242' 8,753' 8,765' 12’ 6/1/2022 Isolated 6/8/22 T4 9,337' 9,347' 8,860' 8,868' 10’ 5/31/2022 Isolated 6/8/22 T4 9,380' 9,393' 8,901' 8,913' 13’ 5/31/2022 Isolated 6/8/22 T6 9,567' 9,575' 9,085' 9,093' 8’ 5/29/2022 Isolated 6/8/22 T7A 9,738' 9,758' 9,253' 9,273' 20’ 5/29/2022 Isolated 6/8/22 T7B 9,797' 9,817' 9,311' 9,328' 20’ 5/28/2022 Isolated 6/8/22 T11 10,116' 10,136' 9,625' 9,645' 20’ 5/28/2022 Isolated 6/8/22 T12 10,289' 10,308' 9,795' 9,813' 19’ 5/26/2022 Isolated 6/8/22 T12 10,289' 10,308' 9,795' 9,813' 19’ 5/27/2022 Isolated 6/8/22 1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: Cement Annulus, 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): 10,461'N/A Casing Collapse Structural Conductor 1,500psi Surface 1,950psi Intermediate Csg 3,090psi Intermediate Lnr 5,410psi 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 Schematic Beaver Creek Beluga Gas 4,138'7"7,474'6,975'7,240psi 8,620 & 8,865 Length N/A; N/A N/A; N/A 9,964'8,583'8,115' 20" 13-3/8" See Schematic Perforation Depth MD (ft): 3,574' 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Beaver Creek Unit (BCU) 18RDCO 237D Same 9,936'4-1/2" ~2,185psi 4,006' 2,097' Size July 31, 2023 4-1/2" 10,432' 108' 9-5/8"3,574' 2,097' MD Hilcorp Alaska, LLC PRESENT WELL CONDITION SUMMARY 108' 3,350' 108' 12.6# / L-80 TVD Burst 7,274' 8,430psi 2,038' Tubing MD (ft): 3,450psi 5,750psi 3,060psi Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEDA028083 222-033 50-133-20584-01-00 Tubing Size: Proposed Pools: AOGCC USE ONLY Tubing Grade: chelgeson@hilcorp.com 907-777-8405 Perforation Depth TVD (ft): 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: Chad Helgeson, Operations Engineer m n P s t 2 N 66 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 4:01 pm, Jul 18, 2023 323-406 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2023.07.18 14:24:32 - 08'00' Noel Nocas (4361) DSR-7/19/23BJM 7/25/23 CT BOP test to 3500 psi. Perform MITIA to 2300 psi within 30 days after perforations are complete. Perforate New Pool P X MDG 7/20/2023 Beluga Gas and possibly Sterling Gas Submit CBL to AOGCC and obtain approval before perforating. GCW 07/25/2023 07/25/23 Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2023.07.25 14:56:15 -08'00' RBDMS JSB 072823 BCU-18RD Cement Annulus Well Name: BCU-18RD API Number: 50-133-20584-01-00 Current Status: Online Gas Well Permit to Drill Number: 222-033 First Call Engineer: Chad Helgeson (907) 777-8405 (O) (907) 299-4824 (C) Second Call Engineer: Jake Flora (907) 777-8442 (O) (720) 988-5375 (C) Maximum Expected BHP: 2,809 psi @ 6242’ TVD 0.45 psi/ft gradient at TD MASP: 2,185 psi BHP minus 0.1 psi/ft gradient Well History: BCU-18RD was drilled in the spring of 2022. We have been unsuccessful finding sustainable zones to produce gas. The Tyonek zone was plugged back and the well currently is produced one day a week, from the Beluga interval, but it does not sustain production. The goal of this sundry is to plugback the lower Beluga, pump a cement annulus isolation job and perforate the upper Beluga. There is a contingency to plug and perf the Sterling sands if the Upper Beluga is unsuccessful. Notes Regarding Wellbore Condition x 4-1/2” liner top @ 7,218’ with cement to 7370’ x Cement Bond Log in the 7” cement top @ 3570’ x Max Inclination = 28.6 degrees at 2324’ MD x Tested 7” liner to 4,000psi 5/2/22, tested 4-1/2” liner to 4,000 psi on 5/14/22 E-Line procedure 1. MIRU E-line and pressure control equipment PT lubricator 250psi low / 2,500psi high. 2. MU 4-1/2” Composite Plug (leaving option to mill out in the future if we want to combine production with lower Beluga) 3. RIH and set 4-1/2” Composite plug at ±8,036’ MD a. Tag plug b. BLM Regulations call for plug to be set 50’-100’ of perfs @ 8,086’ MD 4. RIH and dump bail 15’ of cement on top of plug (est ToC ±8,011’ MD) o <35ft of cement will be placed on plug in the event of possible drilling out plug in the future, but still function as a plug over time 5. Load tubing with source/lease water (8.5 ppg), lubricate & bleed, pump slow o ~121bbl WBV 6. MU and RIH with tubing punch o Punch tubing at ±7,000’ MD (6,554’ TVD) o 7” x 4-1/2” Annulus is 8.6ppg inhibited brine (Ensure tubing and annulus have 0 psi on them) 7. Establish circulation from tubing to IA o Optional: Set a cement retainer @ ±6,990’to pump cement through full bore 8. RDMO EL and pump truck 9. Once circulation is established in both directions: o IA volume = ~250 bbls i. 4-1/2” x 9-5/8” = 0.0562 x 3,336ft = 187 bbls ii. 4-1/2” x 7” = 0.0186 bbl/ft x 3,364ft = 63 bbls o Tubing volume = 0.0152 bbl/ft x 7000ft = ~107 bbls 10. CMIT-TxIA to 2500psi (no chart required) perf the Sterling sands if the Upper Beluga is unsuccessful. o plugback the lower Beluga, perforate the upper Beluga. Dump bail 25' of cement on plug. -bjm BCU-18RD Cement Annulus 4-1/2” x 7” IA Cementing Procedure 11. RU cement truck, PT lines to 250psi low / 3,000psi high 12. Mix and pump ~15.3ppg cement down the tubing, taking returns up the 4-1/2” x 9-5/8” IA o Manage IA back pressure to keep the cement from running away down tubing 13. Planned TOC in IA is ±4,900’ MD (4,616’ TVD). (±34bbls required) a. 0.0186bbl/ft x 1800ft = 34 bbls 14. Displace per OE (use ball and cement head for dropping) displace ball down to tubing cut, 106bbls b. 0.0152 bbl/ft x 7,000ft = ~106 bbls 15. SI master valve and IA and trap pressure on the tubing (~700psi) with annulus pressure at 0 psi. 16. RDMO cementers 17. Wait minimum of 24hrs on cement 18. MIRU EL and pressure control equipment 19. PT lubricator to 250psi Low / 2,500 psi High 20. RIH and tag TOC and complete CBL 21. RD EL 22. MIT-IA to 2500psi for 30 charted minutes CT Procedure 23. MIRU CTU, 24hr notice for BOP test 24. Conduct BOP test to 250psi Low / 3500psi High 25. If cement tag is shallower than 6,700’ Mill out cement to 6,700’ using lease water o Confirm with engineer if the plug at 8,036’ needs to be milled up 26. If tag is deeper than 6,600’, RIH reverse out a minimum of 100 bbls of water 27. Trap N2 pressure on tubing per OE/RE recommendation for perforating, ~1700 psi (25% underbalanced) 28. RDMO CT E-Line Perf procedure 29. MIRU E-line and pressure control equipment 30. PT lubricator to 250psi low / 2500 psi High 31. RIH and perforate as directed by reservoir team Pool/PA Zone Top MD Btm MD TopTVD Btm TVD Amt Beluga BEL5 ±6,286’ ±6,311’ ±5,890’ ±5,913’ ±25’ Beluga BEL6 ±6,342’ ±6,348’ ±5,942’ ±5,947’ ±6’ Beluga BEL6 ±6,354’ ±6,361’ ±5,953’ ±5,960’ ±7’ Beluga BEL6 ±6,366’ ±6,375’ ±5,964’ ±5,972’ ±9’ Beluga BEL7 ±6,384’ ±6,398’ ±5,981’ ±5,994’ ±14’ Beluga BEL7 ±6,453’ ±6,468’ ±6,044’ ±6,056’ ±15’ Beluga BEL8 ±6,478’ ±6,482’ ±6,067’ ±6,071’ ±4’ Beluga BEL8 ±6,515’ ±6,523’ ±6,101’ ±6,109’ ±8’ Beluga BEL8 ±6,534’ ±6,541’ ±6,119’ ±6,126’ ±7’ Beluga BEL8 ±6,549’ ±6,561’ ±6,133’ ±6,144’ ±12 Beluga BEL8 ±6,601’ ±6,620’ ±6,181’ ±6,196’ ±19 7000' - 4900' = 2100'. Annular cement volume is 39 bbls. -bjm Tubing punch. Submit CBL to AOGCC and obtain approval before perforating. -bjm BCU-18RD Cement Annulus Beluga BEL9 ±6,660’ ±6,668’ ±6,235’ ±6,242’ ±8 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 shot and record. e. These sands are in the Beluga Gas Pool per CO 237D. 32. Turn well over to operations and flow the well. If the well is productive the rest of the perfs will not be completed on this sundry. Contingency if Beluga Gas Pool is not productive or sustained, Beluga will be isolated or commingled as allowed per CO 237D (where Rule 5 will be followed) – If commingling is the path planned – a separate submittal will be created and sent to BLM: 33. MIRU N2 Pump and E-line with pressure control equipment 34. PT lubricator and pump lines to 250psi low / 4,000 psi High 35. MU CIBP with GPT tool (for isolating Beluga and Sterling sands) 36. Pressure up with N2 and push water away, verifying depth of water with GPT (water must be deeper than 5,700’) 37. RIH and set 4-1/2” CIBP plug at ±6,236’ MD o Tag CIBP o Regulations call for plug to be set within 50’ of Beluga perfs, current @ ~6,286’ MD) 38. RIH and dump bail 35’ of cement on top of plug (est ToC ±6,201’ MD) 39. RIH and perforate Sterling Gas Pool sands Pool/PA Zone Top MD Btm MD TopTVD Btm TVD Amt Sterling Ster B3U ±5,417’ ±5,429’ ±5,092’ ±5,102’ ±12’ Sterling Ster B3L ±5,439’ ±5,465’ ±5,111’ ±5,135’ ±26’ Sterling Ster B4 ±5,503’ ±5,520’ ±5,170’ ±5,185’ ±17’ Sterling Ster B5 ±5,565’ ±5,585’ ±5,227’ ±5,244’ ±26’ Sterling Ster B6 ±5,605’ ±5,640’ ±5,263’ ±5,295’ ±35’ o Correlate using Open Hole Correlation Log provided by Geologist. Send the correlation pass to Geologist and Reservoir Engineer for confirmation. o Record tubing surface pressure before and after gun firing at 0, 5, 10, 15 min reading intervals. o The Sterling sands are governed by CO 237D. 40. Turn well over to operations and flow the well. Post-Perf MIT-IA 41. Perform MIT-IA to 2000psi once job is complete and well has been brought online within 30 days. BCU-18RD Cement Annulus E-line Procedure (Contingency) If any zone produces sand and/or water or needs isolated: 1. MIRU Eline 2. Pressure test equipment to 3,000 psi High/250 psi Low 3. Eline run PT to find fluid level 4. Use N2 or Gas Lift to push fluid below perfs (verify fluid depth with PT tool) 5. PU 4-1/2” CIBP, WRP, or patch a. If a CIBP is set (it must be set within 50ft of the top perf being plugged back) b. Dump bail 35ft of cement on top of CIBP (unless there isn’t enough room to the next perf) c. Any CIBP with less than 35’ of cement will need approval from BLM prior to adding next set of perfs 6. If necessary to cleanout or unload well with coiled tubing, RU same coil equipment used in initial completion a. Test BOPs, 3,000 psi High/ 250 psi Low b. Cleanout with N2 or foam c. Set 4-1/2” plug or patch Attachments: 1. Current schematic 2. Proposed Schematic 3. Standard Well procedure – N2 Operations Updated by DMA 04-05-23 SCHEMATIC BCU 18RD API: 50-133-20584-01-00 PTD: 222-033 Pad-3 PBTD = 8,583’ MD / 8,115’ TVD TD = 10,461’ MD / 9,964’ TVD RKB to GL = 18.0’ CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 20” Conductor 154.19 X-65 Weld 19.13” Surf 108’ 13-3/8" Surf Csg 68.0 K-55 BTC 12.415” Surf 2,097’ 9-5/8” Intermediate Csg 40.0 L-80 BTC 8.835” Surf 3,574’ 7” Intermediate Lnr 26.0 L-80 Vam Top 6.276” 3,336’ 7,474’ 4-1/2" Prod Tieback 12.6 L-80 JFEBEAR 3.958” Surf 7,214’ 4-1/2" Prod Lnr 12.6 L-80 JFEBEAR 3.958” 7,219’ 10,432’ 1 20” 13-3/8” 4-1/2” JEWELRY DETAIL No. Depth ID Item 1 3,336’ 6.040” 9-5/8” x 7” Liner hanger / LTP Assembly 2 3,574’ N/A Whipstock 3 7,218’ 5.25” 7” x 4-1/2” Liner hanger / LTP Assembly with PBR 4 7,214’ 3.890” Seal Stem 5 8,620’ CIBP w/ 37’ cement – TOC @ 8,583 (7/26/22) 6 8,865’ CIBP w/ 5’ cement – TOC @ 8,860’ (7/20/22) Additional 31’ cement - TOC @ 8,829’ (7/21/22) OPEN HOLE / CEMENT DETAIL 13-3/8” 16” Hole: TOC @ Surface (Original BCU 18) 9-5/8" 12-1/4: Hole: TOC @ 3,440’ (Original BCU 18) 7” 8-1/2” Hole: 125bbls 12ppg lead followed by 18bbls 15.3ppg tail pumped on 5/1/22. 38bbls lead cement back to surface. 5/14/22 CBL shows ToC at 3570’ MD 4-1/2” 6-1/8” Hole: Pumped 30bbl spacer followed by 54bbls 12ppg Type I/II lead followed by 25bbls 15.3ppg Type I/II tail pumped on 5/11/22. Trace spacer back to surface. 5/19/22 CBL shows ToC at 7370’ MD 4 4 9-5/8” 2 BCU 18 (Abandoned) 3 7” PERFORATION DETAIL Zone Top MD Btm MD TopTVD Btm TVD Amt Date Comments BEL22 8,086’ 8,106 7,626’ 7,646’ 41’ 3/10/2023 Open BEL23 8,130’ 8,139’ 7,669’ 7,678’ 9’ 3/10/2023 Open BEL25 8,254' 8,264' 7,791' 7,801' 10' 7/28/2022 Open BEL26 8,281' 8,290' 7,818' 7,827' 9' 7/28/2022 Open BEL27 8,358' 8,372' 7,894' 7,907' 14' 7/27/2022 Open BEL27 8,414' 8,424' 7,949' 7,959' 10' 7/27/2022 Open BEL28 8,483' 8,491' 8,017' 8,025' 8' 7/27/2022 Open BEL28 8,504' 8,516' 8,037' 8,049' 12' 7/27/2022 Open PERFORATION DETAIL – continued on following page BEL 29-32 T0 – T12 6 BEL 33 FISH DETAILs: Failed WRP at 8867’ ELMD (7/10/22) & Fish left from 8,785-8,829ft - 35ft 3.5"OD cement bailer, 2ft CCL, 7ft 2" weight bar (7/21/22) 5 BEL 25-28 BEL 22-23 Updated by DMA 04-05-23 SCHEMATIC BCU 18RD API: 50-133-20584-01-00 PTD: 222-033 Pad-3 PERFORATION DETAIL – continued from previous page Zone Top MD Btm MD TopTVD Btm TVD Amt Date Comments BEL29 8,625’ 8,635’ 8,157’ 8,166’ 10’ 6/19/2022 Isolated 7/26/22 BEL29 8,625’ 8,635’ 8,157’ 8,166’ 10’ 6/12/2022 Isolated 7/26/22 BEL29 8,643’ 8,648’ 8,173’ 8,179’ 5’ 6/19/2022 Isolated 7/26/22 BEL29 8,643’ 8,648’ 8,173’ 8,179’ 5’ 6/12/2022 Isolated 7/26/22 BEL29 8,653’ 8,659’ 8,184’ 8,190’ 6’ 6/19/2022 Isolated 7/26/22 BEL29 8,653’ 8,659’ 8,184’ 8,190’ 6’ 6/12/2022 Isolated 7/26/22 BEL29 8,687' 8,707' 8,218' 8,237' 20' 7/16/2022 Isolated 7/26/22 BEL29 8,690' 8,692' 8,221' 8,223' 2' 7/16/2022 Isolated 7/26/22 B30 8,740' 8,745' 8,270’ 8,275’ 5’ 6/11/2022 Isolated 7/26/22 B30 8,775' 8,781' 8,304’ 8,310’ 6’ 6/11/2022 Isolated 7/26/22 B31 8,812' 8,818' 8,341’ 8,347’ 6’ 6/11/2022 Isolated 7/26/22 B32 8,840' 8,849' 8,369’ 8,377’ 9’ 7/9/2022 Isolated 7/26/22 B32 8,840' 8,849' 8,369’ 8,377’ 9’ 6/11/2022 Isolated 7/26/22 B33 8,995' 9,004' 8,522’ 8,530’ 9’ 6/11/2022 Isolated 7/10/22 T0 9,148' 9,153' 8,672' 8,677' 5’ 6/1/2022 Isolated 6/8/22 T2 9,230' 9,242' 8,753' 8,765' 12’ 6/1/2022 Isolated 6/8/22 T4 9,337' 9,347' 8,860' 8,868' 10’ 5/31/2022 Isolated 6/8/22 T4 9,380' 9,393' 8,901' 8,913' 13’ 5/31/2022 Isolated 6/8/22 T6 9,567' 9,575' 9,085' 9,093' 8’ 5/29/2022 Isolated 6/8/22 T7A 9,738' 9,758' 9,253' 9,273' 20’ 5/29/2022 Isolated 6/8/22 T7B 9,797' 9,817' 9,311' 9,328' 20’ 5/28/2022 Isolated 6/8/22 T11 10,116' 10,136' 9,625' 9,645' 20’ 5/28/2022 Isolated 6/8/22 T12 10,289' 10,308' 9,795' 9,813' 19’ 5/26/2022 Isolated 6/8/22 T12 10,289' 10,308' 9,795' 9,813' 19’ 5/27/2022 Isolated 6/8/22 Updated by CAH 7-14-23 PROPOSED BCU 18RD API: 50-133-20584-01-00 PTD: 222-033 Pad-3 PBTD = 8,583’ MD / 8,115’ TVD TD = 10,461’ MD / 9,964’ TVD RKB to GL = 18.0’ CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 20” Conductor 154.19 X-65 Weld 19.13” Surf 108’ 13-3/8" Surf Csg 68.0 K-55 BTC 12.415” Surf 2,097’ 9-5/8” Intermediate Csg 40.0 L-80 BTC 8.835” Surf 3,574’ 7” Intermediate Lnr 26.0 L-80 Vam Top 6.276” 3,336’ 7,474’ 4-1/2" Prod Tieback 12.6 L-80 JFEBEAR 3.958” Surf 7,214’ 4-1/2" Prod Lnr 12.6 L-80 JFEBEAR 3.958” 7,219’ 10,432’ 1 20” 13-3/8” 4-1/2” JEWELRY DETAIL No. Depth ID Item 1 3,336’ 6.040” 9-5/8” x 7” Liner hanger / LTP Assembly 2 3,574’ N/A Whipstock 3 7,218’ 5.25” 7” x 4-1/2” Liner hanger / LTP Assembly with PBR 4 7,214’ 3.890” Seal Stem 4A ±8,036’ N/A Composite plug w/ 15’ cement 5 8,620’ N/A CIBP w/ 37’ cement – TOC @ 8,583 (7/26/22) 6 8,865’ N/A CIBP w/ 5’ cement – TOC @ 8,860’ (7/20/22) Additional 31’ cement - TOC @ 8,829’ (7/21/22) OPEN HOLE / CEMENT DETAIL 13-3/8” 16” Hole: TOC @ Surface (Original BCU 18) 9-5/8" 12-1/4: Hole: TOC @ 3,440’ (Original BCU 18) 7” 8-1/2” Hole: 125bbls 12ppg lead followed by 18bbls 15.3ppg tail pumped on 5/1/22. 38bbls lead cement back to surface. 5/14/22 CBL shows ToC at 3570’ MD 4-1/2” 6-1/8” Hole: Pumped 30bbl spacer followed by 54bbls 12ppg Type I/II lead followed by 25bbls 15.3ppg Type I/II tail pumped on 5/11/22. Trace spacer back to surface. 5/19/22 CBL shows ToC at 7370’ MD 4-1/2” Inside 7” Casing: Pump 34 bbls of cement through tubing punch @ ~7,000’. Proposed TOC @ ~4,900’ 4 4 9-5/8” 2 BCU 18 (Abandoned) 3 7” PERFORATION DETAIL Zone Top MD Btm MD TopTVD Btm TVD Amt Date Comments Ster B3U ±5,417’ ±5,429’ ±5,092’ ±5,102’ ±12’ TBD Contingency Ster B3L ±5,439’ ±5,465’ ±5,111’ ±5,135’ ±26’ TBD Contingency Ster B4 ±5,503’ ±5,520’ ±5,170’ ±5,185’ ±17’ TBD Contingency Ster B5 ±5,565’ ±5,585’ ±5,227’ ±5,244’ ±26’ TBD Contingency Ster B6 ±5,605’ ±5,640’ ±5,263’ ±5,295’ ±35’ TBD Contingency BEL5 ±6,286’ ±6,311’ ±5,890’ ±5,913’ ±25’ TBD Proposed BEL6 ±6,342’ ±6,348’ ±5,942’ ±5,947’ ±6’ TBD Proposed BEL6 ±6,354’ ±6,361’ ±5,953’ ±5,960’ ±7’ TBD Proposed BEL6 ±6,366’ ±6,375’ ±5,964’ ±5,972’ ±9’ TBD Proposed BEL7 ±6,384’ ±6,398’ ±5,981’ ±5,994’ ±14’ TBD Proposed BEL7 ±6,453’ ±6,468’ ±6,044’ ±6,056’ ±15’ TBD Proposed BEL8 ±6,478’ ±6,482’ ±6,067’ ±6,071’ ±4’ TBD Proposed BEL8 ±6,515’ ±6,523’ ±6,101’ ±6,109’ ±8’ TBD Proposed BEL8 ±6,534’ ±6,541’ ±6,119’ ±6,126’ ±7’ TBD Proposed BEL8 ±6,549’ ±6,561’ ±6,133’ ±6,144’ ±12’ TBD Proposed BEL8 ±6,601’ ±6,620’ ±6,181’ ±6,196’ ±19’ TBD Proposed BEL9 ±6,660’ ±6,668’ ±6,235’ ±6,242’ ±8’ TBD Proposed BEL22 8,086’ 8,106 7,626’ 7,646’ 41’ 3/10/2023 Isolated BEL23 8,130’ 8,139’ 7,669’ 7,678’ 9’ 3/10/2023 Isolated BEL25 8,254' 8,264' 7,791' 7,801' 10' 7/28/2022 Isolated BEL26 8,281' 8,290' 7,818' 7,827' 9' 7/28/2022 Isolated BEL27 8,358' 8,372' 7,894' 7,907' 14' 7/27/2022 Isolated BEL 29-32 T0 – T12 6 BEL 33 FISH DETAILs: Failed WRP at 8867’ ELMD (7/10/22) & Fish left from 8,785-8,829ft - 35ft 3.5"OD cement bailer, 2ft CCL, 7ft 2" weight bar (7/21/22) 5 BEL 25-28 BEL 22-23 Tubing Punch at ~7,000’ Proposed TOC @ ~4,900’ Updated by DMA 07-14-23 SCHEMATIC BCU 18RD API: 50-133-20584-01-00 PTD: 222-033 Pad-3 PERFORATION DETAIL – continued from previous page Zone Top MD Btm MD TopTVD Btm TVD Amt Date Comments BEL27 8,414' 8,424' 7,949' 7,959' 10' 7/27/2022 Isolated BEL28 8,483' 8,491' 8,017' 8,025' 8' 7/27/2022 Isolated BEL28 8,504' 8,516' 8,037' 8,049' 12' 7/27/2022 Isolated BEL29 8,625’ 8,635’ 8,157’ 8,166’ 10’ 6/19/2022 Isolated 7/26/22 BEL29 8,625’ 8,635’ 8,157’ 8,166’ 10’ 6/12/2022 Isolated 7/26/22 BEL29 8,643’ 8,648’ 8,173’ 8,179’ 5’ 6/19/2022 Isolated 7/26/22 BEL29 8,643’ 8,648’ 8,173’ 8,179’ 5’ 6/12/2022 Isolated 7/26/22 BEL29 8,653’ 8,659’ 8,184’ 8,190’ 6’ 6/19/2022 Isolated 7/26/22 BEL29 8,653’ 8,659’ 8,184’ 8,190’ 6’ 6/12/2022 Isolated 7/26/22 BEL29 8,687' 8,707' 8,218' 8,237' 20' 7/16/2022 Isolated 7/26/22 BEL29 8,690' 8,692' 8,221' 8,223' 2' 7/16/2022 Isolated 7/26/22 B30 8,740' 8,745' 8,270’ 8,275’ 5’ 6/11/2022 Isolated 7/26/22 B30 8,775' 8,781' 8,304’ 8,310’ 6’ 6/11/2022 Isolated 7/26/22 B31 8,812' 8,818' 8,341’ 8,347’ 6’ 6/11/2022 Isolated 7/26/22 B32 8,840' 8,849' 8,369’ 8,377’ 9’ 7/9/2022 Isolated 7/26/22 B32 8,840' 8,849' 8,369’ 8,377’ 9’ 6/11/2022 Isolated 7/26/22 B33 8,995' 9,004' 8,522’ 8,530’ 9’ 6/11/2022 Isolated 7/10/22 T0 9,148' 9,153' 8,672' 8,677' 5’ 6/1/2022 Isolated 6/8/22 T2 9,230' 9,242' 8,753' 8,765' 12’ 6/1/2022 Isolated 6/8/22 T4 9,337' 9,347' 8,860' 8,868' 10’ 5/31/2022 Isolated 6/8/22 T4 9,380' 9,393' 8,901' 8,913' 13’ 5/31/2022 Isolated 6/8/22 T6 9,567' 9,575' 9,085' 9,093' 8’ 5/29/2022 Isolated 6/8/22 T7A 9,738' 9,758' 9,253' 9,273' 20’ 5/29/2022 Isolated 6/8/22 T7B 9,797' 9,817' 9,311' 9,328' 20’ 5/28/2022 Isolated 6/8/22 T11 10,116' 10,136' 9,625' 9,645' 20’ 5/28/2022 Isolated 6/8/22 T12 10,289' 10,308' 9,795' 9,813' 19’ 5/26/2022 Isolated 6/8/22 T12 10,289' 10,308' 9,795' 9,813' 19’ 5/27/2022 Isolated 6/8/22 STANDARD WELL PROCEDURE NITROGEN OPERATIONS 12/08/2015 FINAL v1 Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. DATA SUBMITTAL COMPLIANCE REPORT API No. 50-133-20584-01-00Well Name/No. BEAVER CK UNIT 18RD Completion Status 1-GASCompletion Date 5/26/2022 Permit to Drill 2220330 Operator Hilcorp Alaska, LLC MD 10461 TVD 9964 Current Status 1-GAS 4/27/2023 UIC No Well Log Information: Digital Med/Frmt ReceivedStart Stop OH / CH Comments Log Media Run No Electr Dataset Number Name Interval List of Logs Obtained:Logging While Drilling Logs, Mudlog, Cement Bond Logs 5/14/22 & 5/19/22 NoNo YesMud Log Samples Directional Survey REQUIRED INFORMATION (from Master Well Data/Logs) DATA INFORMATION Log/ Data Type Log Scale DF 5/25/202210262 10021 Electronic Data Set, Filename: BCU_18RD_CBL_19-May-2022_(3783).las 36644ED Digital Data DF 5/25/2022 Electronic File: BCU_18RD_CBL_19-May- 2022_(3783).pdf 36644ED Digital Data DF 5/25/20227255 6994 Electronic Data Set, Filename: BCU_18RD_CBL_14-May-2022_(3776).las 36645ED Digital Data DF 5/25/2022 Electronic File: BCU_18RD_CBL_14-May- 2022_(3776).pdf 36645ED Digital Data DF 6/3/20223570 10462 Electronic Data Set, Filename: BCU-18RD LWD FInal.las 36678ED Digital Data DF 6/3/2022 Electronic File: BCU-18RD LWD Final MD.cgm36678EDDigital Data DF 6/3/2022 Electronic File: BCU-18RD LWD Final TVD.cgm36678EDDigital Data DF 6/3/2022 Electronic File: BCU 18RD surveys.xlsx36678EDDigital Data DF 6/3/2022 Electronic File: BCU 18RD.txt36678EDDigital Data DF 6/3/2022 Electronic File: BCU 18RD_Definitive Surveys.pdf36678EDDigital Data DF 6/3/2022 Electronic File: BCU 18RD_GIS.txt36678EDDigital Data DF 6/3/2022 Electronic File: BCU 18RD_Plan.pdf36678EDDigital Data DF 6/3/2022 Electronic File: BCU 18RD_VSec.pdf36678EDDigital Data DF 6/3/2022 Electronic File: BCU-18RD LWD Final MD.emf36678EDDigital Data DF 6/3/2022 Electronic File: BCU-18RD LWD Final TVD.emf36678EDDigital Data DF 6/3/2022 Electronic File: BCU-18RD LWD Final MD.pdf36678EDDigital Data DF 6/3/2022 Electronic File: BCU-18RD LWD Final TVD.pdf36678EDDigital Data DF 6/3/2022 Electronic File: BCU-18RD LWD Final MD.tif36678EDDigital Data Thursday, April 27, 2023AOGCCPage 1 of 7 Supplied by Op Supplied by OP BCU-18RD LWD FInal.las DATA SUBMITTAL COMPLIANCE REPORT API No. 50-133-20584-01-00Well Name/No. BEAVER CK UNIT 18RD Completion Status 1-GASCompletion Date 5/26/2022 Permit to Drill 2220330 Operator Hilcorp Alaska, LLC MD 10461 TVD 9964 Current Status 1-GAS 4/27/2023 UIC No DF 6/3/2022 Electronic File: BCU-18RD LWD Final TVD.tif36678EDDigital Data DF 6/10/20223510 10500 Electronic Data Set, Filename: BCU-18RD.las36695EDDigital Data DF 6/10/2022 Electronic File: BCU-18RD Daily Reports.pdf36695EDDigital Data DF 6/10/2022 Electronic File: BCU-18RD Final Well Report.pdf36695EDDigital Data DF 6/10/2022 Electronic File: BCU-18RD Drilling Dynamics Log MD 2in.pdf 36695ED Digital Data DF 6/10/2022 Electronic File: BCU-18RD Drilling Dynamics Log MD 5in.pdf 36695ED Digital Data DF 6/10/2022 Electronic File: BCU-18RD Drilling Dynamics Log TVD 2in.pdf 36695ED Digital Data DF 6/10/2022 Electronic File: BCU-18RD Drilling Dynamics Log TVD 5in.pdf 36695ED Digital Data DF 6/10/2022 Electronic File: BCU-18RD Formation Log MD 2in.pdf 36695ED Digital Data DF 6/10/2022 Electronic File: BCU-18RD Formation Log MD 5in.pdf 36695ED Digital Data DF 6/10/2022 Electronic File: BCU-18RD Formation Log TVD 2in.pdf 36695ED Digital Data DF 6/10/2022 Electronic File: BCU-18RD Formation Log TVD 5in.pdf 36695ED Digital Data DF 6/10/2022 Electronic File: BCU-18RD Gas Ratio Log MD 2in.pdf 36695ED Digital Data DF 6/10/2022 Electronic File: BCU-18RD Gas Ratio Log MD 5in.pdf 36695ED Digital Data DF 6/10/2022 Electronic File: BCU-18RD Gas Ratio Log TVD 2in.pdf 36695ED Digital Data DF 6/10/2022 Electronic File: BCU-18RD Gas Ratio Log TVD 5in.pdf 36695ED Digital Data DF 6/10/2022 Electronic File: BCU-18RD LWD Combo Log MD 2in.pdf 36695ED Digital Data DF 6/10/2022 Electronic File: BCU-18RD LWD Combo Log MD 5in.pdf 36695ED Digital Data DF 6/10/2022 Electronic File: BCU-18RD LWD Combo Log TVD 2in.pdf 36695ED Digital Data DF 6/10/2022 Electronic File: BCU-18RD LWD Combo Log TVD 5in.pdf 36695ED Digital Data Thursday, April 27, 2023AOGCCPage 2 of 7 BCU-18RD.las DATA SUBMITTAL COMPLIANCE REPORT API No. 50-133-20584-01-00Well Name/No. BEAVER CK UNIT 18RD Completion Status 1-GASCompletion Date 5/26/2022 Permit to Drill 2220330 Operator Hilcorp Alaska, LLC MD 10461 TVD 9964 Current Status 1-GAS 4/27/2023 UIC No DF 6/10/2022 Electronic File: BCU-18RD Drilling Dynamics Log MD 2in.tif 36695ED Digital Data DF 6/10/2022 Electronic File: BCU-18RD Drilling Dynamics Log MD 5in.tif 36695ED Digital Data DF 6/10/2022 Electronic File: BCU-18RD Drilling Dynamics Log TVD 2in.tif 36695ED Digital Data DF 6/10/2022 Electronic File: BCU-18RD Drilling Dynamics Log TVD 5in.tif 36695ED Digital Data DF 6/10/2022 Electronic File: BCU-18RD Formation Log MD 2in.tif 36695ED Digital Data DF 6/10/2022 Electronic File: BCU-18RD Formation Log MD 5in.tif 36695ED Digital Data DF 6/10/2022 Electronic File: BCU-18RD Formation Log TVD 2in.tif 36695ED Digital Data DF 6/10/2022 Electronic File: BCU-18RD Formation Log TVD 5in.tif 36695ED Digital Data DF 6/10/2022 Electronic File: BCU-18RD Gas Ratio Log MD 2in.tif 36695ED Digital Data DF 6/10/2022 Electronic File: BCU-18RD Gas Ratio Log MD 5in.tif 36695ED Digital Data DF 6/10/2022 Electronic File: BCU-18RD Gas Ratio Log TVD 2in.tif 36695ED Digital Data DF 6/10/2022 Electronic File: BCU-18RD Gas Ratio Log TVD 5in.tif 36695ED Digital Data DF 6/10/2022 Electronic File: BCU-18RD LWD Combo Log MD 2in.tif 36695ED Digital Data DF 6/10/2022 Electronic File: BCU-18RD LWD Combo Log MD 5in.tif 36695ED Digital Data DF 6/10/2022 Electronic File: BCU-18RD LWD Combo Log TVD 2in.tif 36695ED Digital Data DF 6/10/2022 Electronic File: BCU-18RD LWD Combo Log TVD 5in.tif 36695ED Digital Data DF 6/10/2022 Electronic File: BCU18RD.dbf36695EDDigital Data DF 6/10/2022 Electronic File: bcu18rd.hdr36695EDDigital Data DF 6/10/2022 Electronic File: BCU18RD.mdx36695EDDigital Data DF 6/10/2022 Electronic File: bcu18rdr.dbf36695EDDigital Data Thursday, April 27, 2023AOGCCPage 3 of 7 DATA SUBMITTAL COMPLIANCE REPORT API No. 50-133-20584-01-00Well Name/No. BEAVER CK UNIT 18RD Completion Status 1-GASCompletion Date 5/26/2022 Permit to Drill 2220330 Operator Hilcorp Alaska, LLC MD 10461 TVD 9964 Current Status 1-GAS 4/27/2023 UIC No DF 6/10/2022 Electronic File: bcu18rdr.mdx36695EDDigital Data DF 6/10/2022 Electronic File: BCU18RD_SCL.DBF36695EDDigital Data DF 6/10/2022 Electronic File: BCU18RD_SCL.MDX36695EDDigital Data DF 6/10/2022 Electronic File: BCU18RD_tvd.dbf36695EDDigital Data DF 6/10/2022 Electronic File: BCU18RD_tvd.mdx36695EDDigital Data DF 6/10/2022 Electronic File: BCU-18RD Show Reports.pdf36695EDDigital Data DF 6/29/202210324 10098 Electronic Data Set, Filename: BCU_18RD_GPT_Perf_29-May-2022_(3797).las 36731ED Digital Data DF 6/29/20229853 9730 Electronic Data Set, Filename: BCU_18RD_GPT_Perf_31-May-2022_(3798).las 36731ED Digital Data DF 6/29/20229259 8839 Electronic Data Set, Filename: BCU_18RD_Perf_GPT_3-Jun-2022_(3801).las 36731ED Digital Data DF 6/29/2022 Electronic File: BCU_18RD_GPT_Perf_29-May- 2022_(3797).pdf 36731ED Digital Data DF 6/29/2022 Electronic File: BCU_18RD_GPT_Perf_31-May- 2022_(3798).pdf 36731ED Digital Data DF 6/29/2022 Electronic File: BCU_18RD_Perf_GPT_3-Jun- 2022_(3801).pdf 36731ED Digital Data DF 7/12/20227000 8920 Electronic Data Set, Filename: BCU-18RD GPT 6-12-22.las 36747ED Digital Data DF 7/12/20229022 8732 Electronic Data Set, Filename: BCU-18RD GUN RUN #1 CORRELATION.las 36747ED Digital Data DF 7/12/20228861 8590 Electronic Data Set, Filename: BCU-18RD GUN RUN #2 CORRELATION.las 36747ED Digital Data DF 7/12/20228723 8464 Electronic Data Set, Filename: BCU-18RD GUN RUN #3 CORRELATION.las 36747ED Digital Data DF 7/12/20226800 8792 Electronic Data Set, Filename: 061822 BCU 18RD GPT.las 36747ED Digital Data DF 7/12/20228715 8428 Electronic Data Set, Filename: BCU 18RD CORRELATION GUN 1 - 2.las 36747ED Digital Data DF 7/12/20228729 8488 Electronic Data Set, Filename: BCU 18RD CORRELATION GUN 3.las 36747ED Digital Data DF 7/12/20228998 10138 Electronic Data Set, Filename: 060722 GPT DOWN PASS.las 36747ED Digital Data Thursday, April 27, 2023AOGCCPage 4 of 7 DATA SUBMITTAL COMPLIANCE REPORT API No. 50-133-20584-01-00Well Name/No. BEAVER CK UNIT 18RD Completion Status 1-GASCompletion Date 5/26/2022 Permit to Drill 2220330 Operator Hilcorp Alaska, LLC MD 10461 TVD 9964 Current Status 1-GAS 4/27/2023 UIC No DF 7/12/20227285 10140 Electronic Data Set, Filename: BCU-18RD 7200'- TD.las 36747ED Digital Data DF 7/12/20229103 8858 Electronic Data Set, Filename: BCU-18RD CORRELATION W-3.75 WRP.las 36747ED Digital Data DF 7/12/202210142 8992 Electronic Data Set, Filename: BCU-18RD GPT 6-7-22.las 36747ED Digital Data DF 7/12/2022211 8494 Electronic Data Set, Filename: GPT DOWN PASS 6-8-22.las 36747ED Digital Data DF 7/12/20227285 10140 Electronic Data Set, Filename: GPT TAG PASS 6-7-22.las 36747ED Digital Data DF 7/12/20229100 8240 Electronic Data Set, Filename: GPT UP LOD FLUID @ 8370.las 36747ED Digital Data DF 7/12/2022 Electronic File: BCU-18RD GPT 6-12-22.pdf36747EDDigital Data DF 7/12/2022 Electronic File: BCU-18RD GPT FINAL 6-11- 22.pdf 36747ED Digital Data DF 7/12/2022 Electronic File: BCU-18RD GUN RUN #1 CORRELATION.pdf 36747ED Digital Data DF 7/12/2022 Electronic File: BCU-18RD GUN RUN #2 CORRELATION.pdf 36747ED Digital Data DF 7/12/2022 Electronic File: BCU-18RD GUN RUN #3 CORRELATION.pdf 36747ED Digital Data DF 7/12/2022 Electronic File: BCU-18RD PERF FINAL 6-11- 22.pdf 36747ED Digital Data DF 7/12/2022 Electronic File: 061822 BCU 18RD GPT-PERF FINAL.pdf 36747ED Digital Data DF 7/12/2022 Electronic File: 061822 BCU 18RD GPT.pdf36747EDDigital Data DF 7/12/2022 Electronic File: BCU 18RD CORRELATION GUN 1 - 2.pdf 36747ED Digital Data DF 7/12/2022 Electronic File: BCU 18RD CORRELATION GUN 3.pdf 36747ED Digital Data DF 7/12/2022 Electronic File: 060722 GPT DOWN PASS.pdf36747EDDigital Data DF 7/12/2022 Electronic File: ACROSS LINER.pdf36747EDDigital Data DF 7/12/2022 Electronic File: BCU-18RD 7200'-TD.pdf36747EDDigital Data DF 7/12/2022 Electronic File: BCU-18RD CORRELATION W- 3.75 WRP.pdf 36747ED Digital Data Thursday, April 27, 2023AOGCCPage 5 of 7 DATA SUBMITTAL COMPLIANCE REPORT API No. 50-133-20584-01-00Well Name/No. BEAVER CK UNIT 18RD Completion Status 1-GASCompletion Date 5/26/2022 Permit to Drill 2220330 Operator Hilcorp Alaska, LLC MD 10461 TVD 9964 Current Status 1-GAS 4/27/2023 UIC No DF 7/12/2022 Electronic File: BCU-18RD GPT 6-7-22.pdf36747EDDigital Data DF 7/12/2022 Electronic File: BCU-18RD GPT FINAL.pdf36747EDDigital Data DF 7/12/2022 Electronic File: BCU-18RD WRP FINAL.pdf36747EDDigital Data DF 7/12/2022 Electronic File: GPT DOWN PASS 6-8-22.pdf36747EDDigital Data DF 7/12/2022 Electronic File: GPT TAG PASS 6-7-22.pdf36747EDDigital Data DF 7/12/2022 Electronic File: GPT UP LOD FLUID @ 8370.pdf36747EDDigital Data DF 9/30/20228605 8291 Electronic Data Set, Filename: BCU_18RD_GPT_Cement_CIBP_Perf_23-Jul- 2022_(3867).las 37069ED Digital Data DF 9/30/20228866 -23 Electronic Data Set, Filename: BCU_18RD_GPT_Perf_16-Jul-2022_(3861).las 37069ED Digital Data DF 9/30/20228870 8506 Electronic Data Set, Filename: BCU_18RD_Perf_13-Jul-2022_(3856).las 37069ED Digital Data DF 9/30/2022 Electronic File: BCU_18RD_GPT_Cement_CIBP_Perf_23-Jul- 2022_(3867).pdf 37069ED Digital Data DF 9/30/2022 Electronic File: BCU_18RD_GPT_Perf_16-Jul- 2022_(3861).pdf 37069ED Digital Data DF 9/30/2022 Electronic File: BCU_18RD_Perf_13-Jul- 2022_(3856).pdf 37069ED Digital Data DF 11/21/20228603 6993 Electronic Data Set, Filename: BCU_18RD_GPT_10-Sep-2022_(3954).las 37285ED Digital Data DF 11/21/20228583 7142 Electronic Data Set, Filename: BCU_18RD_Stim_18-Sep-2022_(3963).las 37285ED Digital Data DF 11/21/2022 Electronic File: BCU_18RD_GPT_10-Sep- 2022_(3954).pdf 37285ED Digital Data DF 11/21/2022 Electronic File: BCU_18RD_Stim_18-Sep- 2022_(3963).pdf 37285ED Digital Data DF 3/28/20238254 8026 Electronic Data Set, Filename: BCU 18 RD GUN- 1 CORRELATION.las 37567ED Digital Data DF 3/28/20238214 7954 Electronic Data Set, Filename: BCU 18 RD GUN- 2 CORRELATION.las 37567ED Digital Data DF 3/28/20238164 7963 Electronic Data Set, Filename: BCU 18 RD GUN- 3 CORRELATION.las 37567ED Digital Data Thursday, April 27, 2023AOGCCPage 6 of 7 DATA SUBMITTAL COMPLIANCE REPORT API No. 50-133-20584-01-00Well Name/No. BEAVER CK UNIT 18RD Completion Status 1-GASCompletion Date 5/26/2022 Permit to Drill 2220330 Operator Hilcorp Alaska, LLC MD 10461 TVD 9964 Current Status 1-GAS 4/27/2023 UIC No Well Cores/Samples Information: ReceivedStart Stop Comments Total Boxes Sample Set NumberName Interval INFORMATION RECEIVED Completion Report Production Test Information Geologic Markers/Tops Y Y / NA Y Comments: Compliance Reviewed By:Date: Mud Logs, Image Files, Digital Data Composite Logs, Image, Data Files Cuttings Samples Y / NA Y Y / NA Directional / Inclination Data Mechanical Integrity Test Information Daily Operations Summary Y Y / NA Y Core Chips Core Photographs Laboratory Analyses Y / NA Y / NA Y / NA COMPLIANCE HISTORY Date CommentsDescription Completion Date: 5/26/2022 Release Date: 3/29/2022 DF 3/28/2023 Electronic File: BCU 18 RD GUN-1 CORRELATION.pdf 37567ED Digital Data DF 3/28/2023 Electronic File: BCU 18 RD GUN-2 CORRELATION.pdf 37567ED Digital Data DF 3/28/2023 Electronic File: BCU 18 RD GUN-3 CORRELATION.pdf 37567ED Digital Data DF 3/28/2023 Electronic File: BCU 18 RD PERF FINAL.pdf37567EDDigital Data 7/7/20223574 10461 51806Cuttings Thursday, April 27, 2023AOGCCPage 7 of 7 M.Guhl 4/27/2023 Kyle Wiseman Hilcorp Alaska, LLC Geo Tech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: Kyle.Wiseman@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 03/28/2023 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20230328 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BCU 12A 50133205300100 214070 2/18/2023 YELLOW JACKET PLUG BCU 18RD 50133205840100 222033 3/9/2023 YELLOW JACKET PERF CLU 10RD 50133205530100 222113 3/2/2023 YELLOW JACKET PERF-GPT-PLUG KBU 11-07 50133205560000 205165 3/3/2023 YELLOW JACKET PERF KBU 11-07 50133205560000 205165 3/1/2023 YELLOW JACKET PLUG KU 14X-6 50133203420000 181092 3/3/2023 YELLOW JACKET CALIPER-SCBL NCI B-02 50883200900100 197210 3/9/2023 AK E-LINE GPT Perf SRU 224-10 50133101380100 222124 2/15/2023 YELLOW JACKET PLUG TBU D-09RD 50733201310100 181080 2/27/2023 AK E-LINE Plug Punch Please include current contact information if different from above. BCU 18RD 50133205840100 222033 3/9/2023 YELLOW JACKET PERF 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: ___________________ 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): 10,461'N/A Casing Collapse Structural Conductor 1,500psi Surface 1,950psi Intermediate Csg 3,090psi Intermediate Lnr 5,410psi 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 4,138'7" 8,430psi9,936'10,432' 7,474'6,975'7,240psi 108' 2,097' 3,574' Perforation Depth MD (ft): 4,006'4-1/2" 9-5/8"3,574' 20" 13-3/8" 108' 2,097' 5,750psi 3,060psi 3,450psi 108' 2,038' 3,350' Length Size Proposed Pools: TVD Burst PRESENT WELL CONDITION SUMMARY 9,964'8,583'8,115'~2,695 8,620 & 8,865 MD STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEDA028083 222-033 50-133-20584-01-00 Beaver Creek Beluga Gas Same CO 237D Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Beaver Creek Unit (BCU) 18RD AOGCC USE ONLY Chad Helgeson, Operations Engineer chelgeson@hilcorp.com 907-777-8405 Noel Nocas, Operations Manager 907-564-5278 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 Grade:Tubing MD (ft):Perforation Depth TVD (ft):Tubing Size: 12.6# / L-80 7,274' February 24, 2023 N/A; N/A N/A; N/A See Schematic See Schematic 4-1/2" 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 Meredith Guhl at 3:35 pm, Feb 21, 2023 323-103 BJM 2/24/23 DSR-2/22/23 10-404 SFD 2/21/2023JLC 2/27/2023 2/27/23Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2023.02.27 14:27:33 -09'00' RBDMS JSB 022823 BCU-18RD Perforating Well Name: BCU-18RD API Number: 50-133-20584-01-00 Current Status: Online Permit to Drill Number: 222-033 First Call Engineer: Chad Helgeson (907) 777-8405 (O) (907) 299-4824 (C) Second Call Engineer: Jake Flora (907) 777-8442 (O) (720) 988-5375 (C) Maximum Expected BHP: 3465 psi @ 7701’ TVD 0.45 psi/ft gradient at TD MASP: 2695 psi BHP minus 0.1 psi/ft gradient Well History: BCU-18RD was drilled in the spring of 2022. There are currently 6 open perf zones with a CIBP w/ cement @ 8583’. On 6/9/22 a WRP was set @ 9098’. On 6/13/22 Eline was hung up at the liner hanger @ 7217’ and left a perforating toolstring in the well. The Eline toolstring was fished from the well on 6/14/22. The WRP was unable to be fished. The cement bailer and 7’ of 2” weight bar was detained @ 8829’ prior to pulling out of the rope socket. The fish detailed in the schematic are below the top CIBP. Objective: Obtain FL and selectively adperfs. Procedure: 1. RU Eline. PT lubricator to 250 psi low/3000 psi high. 2. Run GPT log to find current FL. Tag TD. 3. Based on FL, contingent shoot stim guns across below 2 zones: Zone Top MD Btm MD TopTVD Btm TVD Amt Date Comments BEL25 8,254' 8,264' 7,791' 7,801' 10' 7/28/2022 Open BEL26 8,281' 8,290' 7,818' 7,827' 9' 7/28/2022 Open 4. Based on FL, contingent adperf the below zones. Zone Top MD Btm MD TopTVD Btm TVD Amt Date Comments BEL16L ±7,645’ ±7,661’ ±7,191’ ±7,207’ ±16’ TBD Proposed BEL16L ±7,667’ ±7,675’ ±7,213’ ±7,221’ ±8’ TBD Proposed BEL18 ±7,720’ ±7,733’ ±7,267’ ±7,279’ ±13’ TBD Proposed BEL18 ±7,751’ ±7,757’ ±7,297’ ±7,303’ ±6’ TBD Proposed BEL18 ±7,765’ ±7,772’ ±7,311’ ±7,318’ ±7’ TBD Proposed BEL19 ±7,784’ ±7,815’ ±7,330’ ±7,361’ ±31’ TBD Proposed BEL20 ±7,844’ ±7,866’ ±7,388’ ±7,411’ ±22’ TBD Proposed BEL20 ±7,874’ ±7,881’ ±7,418’ ±7,424’ ±7’ TBD Proposed BEL20 ±7,888’ ±7,917’ ±7,432’ ±7,460’ ±29’ TBD Proposed BEL20L ±7,963’ ±7,989’ ±7,506’ ±7,531’ ±26’ TBD Proposed BEL21 ±8,001’ ±8,011’ ±7,543’ ±7,553’ ±10’ TBD Proposed BEL22 ±8,066’ ±8,107’ ±7,607’ ±7,647’ ±41’ TBD Proposed BEL23 ±8,130’ ±8,139’ ±7,669’ ±7,678’ ±9’ TBD Proposed BEL24 ±8,155’ ±8,163’ ±7,693’ ±7,701’ ±8’ TBD Proposed 5. Contingent run GPT between perf runs to identify FL. Contingency: 1. If any zone produces sand and/or water or needs isolated: 2. RU E-line, pressure test lubricator 250 psi low/3,000 psi high. 3. RIH and set a casing patch or set a CIBP w/ 35’ of cement above the zone that needs isolated. If there is not enough room between the plug and next zone for 35’ of cement, request a waiver from BLM prior to setting cement on plug. Attachments: 1. Current Well Schematic 2. Proposed Well Schematic BCU-18RD Perforating Current Schematic BCU-18RD Perforating BCU-18RD Perforating Proposed Schematic BCU-18RD Perforating Kyle Wiseman Hilcorp Alaska, LLC Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: Kyle.Wiseman@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 11/21/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20221121 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# CLU 05RD2 50133204740200 222092 10/18/2022 AK E-Line Perf_GPT MGS S MGS Unit 11 50733201040000 168032 10/11/2022 AK E-Line LDL SRU 241-33 50133206630000 217047 8/29/2022 AK E-Line TTBP_Perf SRU 32A-33 50133101640100 191014 9/23/2022 AK E-Line GPT SCU 344-33 50133202930100 218054 9/11/2022 AK E-Line Punch BCU 18RD 50133205840100 222033 9/10/2022 AK E-Line GPT BCU 18RD 50133205840100 222033 9/18/2022 AK E-Line Stim BRU 233-23 50283201360100 222050 11/1/2022 AK E-Line Perf BRU 233-23 50283201360100 222050 9/12/2022 AK E-Line CIBP Please include current contact information if different from above. T37280 T37281 T37282 T37283 T37284 T37285 T37285 T37286 T37286 By Meredith Guhl at 2:54 pm, Nov 21, 2022 BCU 18RD 50133205840100 222033 9/10/2022 AK E-Line GPT BCU 18RD 50133205840100 222033 9/18/2022 AK E-Line Stim Meredith Guhl Digitally signed by Meredith Guhl Date: 2022.11.21 14:55:38 -09'00' David Dempsey Hilcorp Alaska, LLC Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.dempsey2@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 09/28/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20220928 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BCU 07A 501332028401 214060 7/12/2022 AK E-Line CIBP GPT BCU 18RD 501332058401 222033 7/13/2022 AK E-Line Perf BCU 18RD 501332058401 222033 7/16/2022 AK E-Line GPT Perf BCU 18RD 501332058401 222033 7/23/2022 AK E-Line GPT CIBP Perf BRU 212-24 502832003700 172015 6/27/2022 AK E-Line CBL BRU 212-24 502832003700 172015 7/5/2022 AK E-Line CIBP CBL TBG END 1-45 500292199100 189124 7/23/2022 AK E-Line Perf END 4-02 500292178900 188022 7/21/2022 AK E-Line Perf HVB B-16 502312004000 212133 6/23/2022 AK E-Line Drift, Plug, Cement IRU 241-01 502832018400 221076 8/5/2022 AK E-Line CBL IRU 241-01 502832018400 221076 8/9/2022 AK E-Line Perf Kalotsa 6 501332068500 219114 7/16/2022 AK E-Line Perf KTU 24-06H 501332049000 199073 7/15/2022 AK E-Line GPT Perf MPU S-34 500292317100 203130 7/5/2022 AK E-Line Drift PBU F-26C 500292198703 213045 8/4/2022 AK E-Line Patch/LDL SRU 213-15 501332065200 215100 8/3/2022 AK E-Line GPT Perf Please include current contact information if different from above. T37068 T37069 T37069 T37069 T37070 T37070 T37071 T37072 T37073 T37081 T37081 T37074 T37075 T37076 T37077 T37078 BCU 18RD 501332058401 222033 7/13/2022 AK E-Line Perf BCU 18RD 501332058401 222033 7/16/2022 AK E-Line GPT Perf BCU 18RD 501332058401 222033 7/23/2022 AK E-Line GPT CIBP Perf Kayla Junke Digitally signed by Kayla Junke Date: 2022.09.30 12:44:16 -08'00' 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): GL: 159.9' BF:159.9' 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 7" L-80 7,021' 4-1/2" L-80 9,936' 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 Rate101 May 9, 2022 April 23, 2022 FED A028083 N/A N/A 3,574' MD / 3,355' TVDN/A N/A 10,461' MD / 9,964' TVD Logging While Drilling Logs, Mudlog, Cement Bond Logs 5/14/22 & 5/19/22 Sr Res EngSr Pet GeoSr Pet Eng N/A N/A Oil-Bbl: Water-Bbl: 0050.2 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/A50.2 Flowing ** Please see attached schematic for perforation detail ** 0 Water-Bbl: PRODUCTION TEST 6/2/2022 Date of Test: 0 8/5/2022 24 Flow Tubing 0 26# 12.6# 7,474' Gas-Oil Ratio:Choke Size: Per 20 AAC 25.283 (i)(2) attach electronic information DEPTH SET (MD) 7,219' MD / 6,768' TVD PACKER SET (MD/TVD) 6,768' CASING WT. PER FT.GRADE 318051 318162 TOP SETTING DEPTH MD 3,336' SETTING DEPTH TVD 2434387 BOTTOM TOP 3,142' 6-1/8" HOLE SIZE AMOUNT PULLED 50-133-20584-01-00 BCU-18RD 317441 2434136 1162' FNL, 2237' FWL, Sec 34, T7N, R10W, SM, AK CEMENTING RECORD 2434019 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 5/26/2022 1055' FNL, 1628' FWL, Sec 34, T7N, R10W, SM, AK 792' FNL, 2342' FWL, Sec 34, T7N, R10W, SM, AK 222-033 / 322-269 / 322-232 Beaver Creek Unit / Beluga Gas Pool 177.9' 8,583' MD / 8,115' TVD STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG Hilcorp Alaska, LLC WAG Gas 8-1/2" 7,219' 10,432' L- 130 sx T - 115 sx L - 295 sx / T - 90 sx 7,214'4-1/2" Tieback 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, 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 James Brooks at 3:42 pm, Aug 15, 2022 Completed 5/26/2022 JSB RBDMS JSB 081622 GSFD 11/8/2022WCB 4/27/2023 BCU-18RD DSR-3/23/23 222-033 May 9, 2022 Development Beaver Creek Unit / Beluga Gas Pool G Conventional Core(s): Yes No Sidewall Cores: 30. MD TVD N/A N/A Top of Productive Interval Bel 25 8254' 7791' 5146' 4840' 6109' 5723' 6832' 6392' 8213' 7748' 8276' 7809' 8341' 7874' 8470' 8000' 8606' 8135' 9014' 8537' 9680' 9193' 10059' 9566' 10215' 9721' 10343' 9848' Ty 13 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). Ty 7A Ty 11 Ty 12 Ty 13 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. Ty 0 Formation at total depth: Bel 25 Wellbore Schematic, Drilling and Completion Reports, Definitive Directional Surveys, 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 Bel 29 Bel 26 Sterling A Mid Beluga Sterling B 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 Bel 27 Bel 28 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 8.15.2022Digitally 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: 2022.08.15 08:27:44 -08'00' Monty M Myers Updated by CJD 08-11-22 SCHEMATIC BCU 18RD API: 50-133-20584-01-00 PTD: 222-033 Pad-3 PBTD = 8,583’ MD / 8,115’ TVD TD = 10,461’ MD / 9,964’ TVD RKB to GL = 18.0’ CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 20” Conductor 154.19 X-65 Weld 19.13” Surf 108’ 13-3/8" Surf Csg 68.0 K-55 BTC 12.415” Surf 2,097’ 9-5/8” Intermediate Csg 40.0 L-80 BTC 8.835” Surf 3,574’ 7” Intermediate Lnr 26.0 L-80 Vam Top 6.276” 3,336’ 7,474’ 4-1/2" Prod Tieback 12.6 L-80 JFEBEAR 3.958” Surf 7,214’ 4-1/2" Prod Lnr 12.6 L-80 JFEBEAR 3.958” 7,219’ 10,432’ 1 20” 13-3/8” 4-1/2” JEWELRY DETAIL No. Depth ID Item 1 3,336’ 6.040” 9-5/8” x 7” Liner hanger / LTP Assembly 2 3,574’ N/A Whipstock 3 7,218’ 5.25” 7” x 4-1/2” Liner hanger / LTP Assembly with PBR 4 7,214’ 3.890” Seal Stem 5 8,620’ CIBP w/ 37’ cement – TOC @ 8,583 (7/26/22) 6 8,865’ CIBP w/ 5’ cement – TOC @ 8,860’ (7/20/22) Additional 31’ cement - TOC @ 8,829’ (7/21/22) OPEN HOLE / CEMENT DETAIL 13-3/8” 16” Hole: TOC @ Surface (Original BCU 18) 9-5/8" 12-1/4: Hole: TOC @ 3,440’ (Original BCU 18) 7” 8-1/2” Hole: 125bbls 12ppg lead followed by 18bbls 15.3ppg tail pumped on 5/1/22. 38bbls lead cement back to surface. 5/14/22 CBL shows ToC at 3570’ MD 4-1/2” 6-1/8” Hole: Pumped 30bbl spacer followed by 54bbls 12ppg Type I/II lead followed by 25bbls 15.3ppg Type I/II tail pumped on 5/11/22. Trace spacer back to surface. 5/19/22 CBL shows ToC at 7370’ MD 4 4 9-5/8” 2 BCU 18 (Abandoned) 3 7” PERFORATION DETAIL Zone Top MD Btm MD TopTVD Btm TVD Amt Date Comments BEL25 8,254' 8,264' 7,791' 7,801' 10' 7/28/2022 Open BEL26 8,281' 8,290' 7,818' 7,827' 9' 7/28/2022 Open BEL27 8,358' 8,372' 7,894' 7,907' 14' 7/27/2022 Open BEL27 8,414' 8,424' 7,949' 7,959' 10' 7/27/2022 Open BEL28 8,483' 8,491' 8,017' 8,025' 8' 7/27/2022 Open BEL28 8,504' 8,516' 8,037' 8,049' 8' 7/27/2022 Open PERFORATION DETAIL – continued on following page BEL 29-32 T0 – T12 6 BEL 33 FISH DETAILs: Failed WRP at 8867’ ELMD (7/10/22) & Fish left from 8,785-8,829ft - 35ft 3.5"OD cement bailer, 2ft CCL, 7ft 2" weight bar (7/21/22) 5 BEL 25-28 SCHEMATIC BCU 18RD API: 50-133-20584-01-00 PTD: 222-033 Pad-3 PERFORATION DETAIL – continued from previous page Zone Top MD Btm MD TopTVD Btm TVD Amt Date Comments BEL29 8,625’ 8,635’ 8,157’ 8,166’ 10’ 6/19/2022 Isolated 7/26/22 BEL29 8,625’ 8,635’ 8,157’ 8,166’ 10’ 6/12/2022 Isolated 7/26/22 BEL29 8,643’ 8,648’ 8,173’ 8,179’ 5’ 6/19/2022 Isolated 7/26/22 BEL29 8,643’ 8,648’ 8,173’ 8,179’ 5’ 6/12/2022 Isolated 7/26/22 BEL29 8,653’ 8,659’ 8,184’ 8,190’ 6’ 6/19/2022 Isolated 7/26/22 BEL29 8,653’ 8,659’ 8,184’ 8,190’ 6’ 6/12/2022 Isolated 7/26/22 BEL29 8,687' 8,707' 8,218' 8,237' 20' 7/16/2022 Isolated 7/26/22 BEL29 8,690' 8,692' 8,221' 8,223' 2' 7/16/2022 Isolated 7/26/22 B30 8,740' 8,745' 8,270’ 8,275’ 5’ 6/11/2022 Isolated 7/26/22 B30 8,775' 8,781' 8,304’ 8,310’ 6’ 6/11/2022 Isolated 7/26/22 B31 8,812' 8,818' 8,341’ 8,347’ 6’ 6/11/2022 Isolated 7/26/22 B32 8,840' 8,849' 8,369’ 8,377’ 9’ 7/9/2022 Isolated 7/26/22 B32 8,840' 8,849' 8,369’ 8,377’ 9’ 6/11/2022 Isolated 7/26/22 B33 8,995' 9,004' 8,522’ 8,530’ 9’ 6/11/2022 Isolated 7/10/22 T0 9,148' 9,153' 8,672' 8,677' 5’ 6/1/2022 Isolated 6/8/22 T2 9,230' 9,242' 8,753' 8,765' 12’ 6/1/2022 Isolated 6/8/22 T4 9,337' 9,347' 8,860' 8,868' 10’ 5/31/2022 Isolated 6/8/22 T4 9,380' 9,393' 8,901' 8,913' 13’ 5/31/2022 Isolated 6/8/22 T6 9,567' 9,575' 9,085' 9,093' 8’ 5/29/2022 Isolated 6/8/22 T7A 9,738' 9,758' 9,253' 9,273' 20’ 5/29/2022 Isolated 6/8/22 T7B 9,797' 9,817' 9,311' 9,328' 20’ 5/28/2022 Isolated 6/8/22 T11 10,116' 10,136' 9,625' 9,645' 20’ 5/28/2022 Isolated 6/8/22 T12 10,289' 10,308' 9,795' 9,813' 19’ 5/26/2022 Isolated 6/8/22 T12 10,289' 10,308' 9,795' 9,813' 19’ 5/27/2022 Isolated 6/8/22 Activity Date Ops Summary 4/12/2022 Cont. R/D Rig components, and cleaning/ organizing rig. Greased derrick pins, R/U lower pin HYD hoses to remove pins. Cont. w/ painting in boiler house. organized bolt bin. R/D air compressor room. Built steam isolation valves for hopper house #3. cont. securing derrick for move. cleaned and;organized change shack. R/D pit module roof lights. Vac'd out boiler water. Strapped down pit handrails. Removed shaker splash guards, installed keeper pins on cuttings box wind wall support rails. Completed EAM's on DWKS. Loaded out shaker screen conex. R/D alarms on pump house roofs.;Transported choke house and hurricane vac to Beaver creek staging pad. 4/13/2022 Staged felt and liner at BCU pad 3, loaded and transported upright water tank to Beaver Creek, cleaned rig water tank and cellar box on Pearl, re-staked well on Paxton pad, did line locate and started excavate with super sucker to look for well 5 electric lines, RD lights and handrails on doghouse.;Transported Sperry tools to Beaver Creek from Kalotsa, rig crew and Tool Push traveled to Beaver Creek to lay felt, liner and rig mats, shipped 4 more rig mats from Pearl to BC, loaded and shipped poorboy degasser, assorted equipment, aux fuel tank, HandyBerm and drill connex to BC from Pearl.;Finished laying rig mats at BC pad 3. Started and warmed up rig gen, powered up rig, cont. w/ general housekeeping around rig/pad. P/U sticks and felt scraps on Kalotsa, Paxton, Whiskey Gulch Pad. Broke tours w/ night crew @ 21:00 hrs. Half of the crew will return @ 06:00 hrs. to rig;and the other half will show up at the farm yard warehouse @ 06:30 hrs. Toolpushers traveled to BCU-18RD to confirm rig lay out measurements and get a visual on the area behind MP #2 (current well house).;Vac'd out remaining boiler water, cont. w/ housekeeping and organizing rig. R/U HYD lines, lowered roofs on pit modules 1-3. R/D all remaining electrical on pit modules. R/D HYD lines. Hauled trailers w/ CCI conex/timbers and water line/timbers to Beaver creek staging pad. 4/14/2022 Both crews on daylight shift, prepped and tore out boiler skid, stage same on edge of Pearl Pad, tore out, loaded and transported topdrive HPU skid and another load of 4 rig mats to Beaver Creek. Cleaned up exposed liner and felt, serviced 4 way valves on koomey unit, vac up large puddles on pad and;backdrag pad, utilize small amount of gravel on pad to fill in low spots. Checked draw works drum bearing for play. Crew at farm yard installed fuel pump on new aux fuel tank, prepped diverter vent line sections for paint, installed cabinets in rigs electrical connex. Hands at Beaver Creek cleared;more snow for office trailers, set last few rig mats in place.;Rest rig crews for the night, kept Motorman and night Push at rig for the night. CCI night rig support cont. dressing Pearl pad/road leading to pad, and removing water off pad. 4/15/2022 RD electric from gen skid to rig sub and doghouse, scoped down doghouse, RD change shacks and rig shop, loaded and transported catwalk to BCU, transported 2nd crane to Pearl pad, offloaded same, loaded up rig loader and implements, backhauled same to BCU, graded spot on BC pad 3 for office trailers;and setting rig mats now to park trailers on, sent BOP cradle to farmyard so rig’s BOP stack can be re-assembled on that to transport to BCU, rig crew plumbing and doing electrical work on new aux fuel tank and priming diverter vent line sections for paint, Expediter PU rental camp gen set and;transported to BCU, mud Engineer working with Steam on Wheels to thaw first dragon box of cuttings at G&I that came over from Beluga.;Rested rig crews for the night. Toolpusher and motorman watched over the rig during the night, and worked on EAM paper work. 4/16/2022 RD office trailers and comm tower, tore out rig shop, transported 6 trailers and shop to Beaver Creek, set 6 trailers and shop, spotted bang box and gen set, powered up office trailers-change shack and shop. Transported comm tower to Beaver Creek.;Installed HandyBerm around gen set. Assisted Well Head Rep with removal of dry hole tree and install of adaptor spool. Discussed with Lead Op on removing well house near back yard to allow bed truck to set pump module #2, cont buffing and priming diverter vent line, assemble BOP stack on cradle and;electrical on aux fuel tank at farmyard.;Rested rig crews for the night. Cont. w/ our rig night watch personal. CCI night rig support transported 3 dragon wagons from rig tenders dock to G&I and pushed back snow berms on Beaver creek pad #3. 4/17/2022 Traveled to Pearl Pad, start equipment, tore out gen skid, pits 3 and 2, jig and pump #2. Spot cranes and loaded gen skid with cranes. Tore out pit 1 and loaded with cranes. 1st non-CCI truck arrived, loaded pump #2 with cranes, wait on arrival of 4th truck which is non-CCI (arrived at 15:30).;Expediter and rig hands retrieved liner and dunnage from Beaver Creek, traveled to KGF G&I to check on building containment to park dragon boxes and trailers on. Rig crews still buffing, priming painting diverter vent line at Drilling Warehouse.;Installed lift plate on BOP stack and changed out bridle rigging on cradle, and lowered same for transport to rig, aux fuel tank electrical is complete. Moved to 4 rig mods off Pearl Pad to slow lane pull out on highway and hooked up trailer jeeps, staged for moving at 2AM.;Rested rig crews for the night, CCI and pilot cars transported 4 rig modules from Ninilchik to Beaver Creek @ 02:00 hrs. Currently off loading rig modules at Beaver creek pad #1 w/ cranes/winch truck. 4/18/2022 Traveled to Pearl Pad and tore out doghouse skid and pump #1, spotted cranes, picked and loaded derrick, carrier, sub, pit mod 3, and pump skid #1 on trailers, staged trucks for moving to Beaver Creek at 2AM. Started stacking rig mats and clean up liner/felt on Pearl pad. RU comm’s on pad 3 BCU.;Transported 1 pony wall from Pearl pad to BCU, truck returned to Pearl pad, loaded and transported 2nd pony wall to pad 3.;Rested rig crews for the night. Set pony walls over well, squared to rig mats. CCI night rig support transported two trailer w/ rig mats and another w/ IR HPU, light plant, and heater for cellar. Set IR HPU and heater inside pony walls. Permitted loads left Ninilchik at 02:00 hrs. First load;arrived at BC staging pad at 04:00 hrs. Spotted cranes and off loaded sub onto ground. Picked sub w/ winch truck. Currently waiting on 2 rig modules to arrive at staging pad for off load. n (LAT/LONG): evation (RKB): API #: Well Name: Field: County/State: BCU-018RD Beaver Creek Unit Hilcorp Energy Company Composite Report , Alaska Contractor AFE #: AFE $: Job Name:221-00038 BCU-18RD Drilling Spud Date: 4/19/2022 Offload pump #1 at staging pad, Move cranes to pad 3, Loaded one crane at Pearl pad for return, Pick and set Sub on pony walls, Pick and set carrier on sub, Pick and set derrick on carrier.;Pick and set Pit #1, Pick and set Pump #1, Pick and set Pit #2, Raise derrick to half mast, Pick and set HPU, Pick and set Pump #2, Pick and set Pit #3, Pick and set MGS. Continue connecting all modules electrical, Hydraulic and mud lines. Install wind walls with crane assistance. Pick and set;Generator #3. Lift MGS into drilling position. Lay felt and liner for catwalk and set same. Pick and set BOP cradle near cellar area. Hand off BOP stack from crane to Cellar cranes.;Installed both manual and HCR kill/choke valves on BOP stack. Cont. working on hooking up interconnects between modules, and R/U in the pits. Built mud docks, hauled in and stacked mud product . Cont. hauling misc. equip./tools from staging pad. R/U productions test pump to dry hole tree.;Performed 9-5/8" casing test down to CIBP @ 5950' WLM T/4000 psi for 30 min on chart (ok). Pumped in 7.36 bbls and Bled back 7.36 bbls. R/D and blew down productions test pump.;Finished R/D remainder of testing equip. N/D the integral wellhead cap, L/D shipping beams in sub. Tailed in BOP's on bridge cranes, bolted up BOP stack to well head. Installed flow box. Cont. w/ R/U on BOP's, pits, and interconnects through out the rig.;Laid over beaver slide onto rig floor. Transported service shacks, drilling conex, shaker screen conex and 400 bbl up right to BCU-18RD. At 04:00 hrs. CCI rig movers left staging area in Ninilchik w/ final 2 rig modules (Doghouse & boiler), and arrived at 06:00 hrs at BC Pad #1.;Currently offloading rig modules at BC pad #1 and cont. w/ R/U.;Hauled Solids to G&I 0 bbls Hauled to G&I Cumulative 0 bbls Hauled Fluid to G&I 0 bbls Hauled to G&I Cumulative 0 bbls Hauled cement to G&I 0 bbls Cumulative Cement to G&I 0 bbls Daily Down Hole Losses 0 bbls Cumulative Losses 0 bbls 4/20/2022 Continue to N/U BOP stack. Install hydraulic accumulator fittings into BOP stack. Pick and set Doghouse/ Accumulator and watertank skid. R/U hoses and scope up doghouse. R/U electrical, hydraulic and lights to doghouse. Pick and set Boiler house. R/U brake linkage and driveline from brake handle to;draworks, Pick & set third party shacks, R/U rig HPU, Take measurements for a short riser on BOP stack. R/U Pason, Lay down drill line, Kelly hose and service loop on rig floor. R/U stand pipe/ bleeder manifold. Sent 48 hour notice notification to BLM for BOPE Test at 10:29am.;Sent e-mail to AOGCC Jim Regg giving 48 hour notice for Initial BOPE test @ 10:32am.;R/U cameras. Mount upper torque tube to top section, Spool up drilling line, Install Handy Berm, Attach lower torque tube to upper torque tube and telescope derrick up. Confirm lock pins. Secure lower torque tube to derrick. Obtain RKB's, R/U Accumulator hoses to BOPE, Install new cellar grating,;Pick up and install Top Drive, Complete making up choke and kill line connections.;Changed out O-ring seals on TDS HYD lines. R/U Kelley hose & service loop to TDS. Energized koomey. Cont. R/U boiler system. Chained & centered stack. Installed flow nipple, flow line, and hole fill line. M/U saver sub to quill, and installed clamps. Cont. R/U in the pits and bring on water.;Brought handling equip to floor-Tongs, slips, bails, and elevators. R/U bails. Filled rig water tank and 400 bbl up right. Started building first batch of 6% KCL PHPA mud.;Crew change, held PTSM. Cont. R/U handling equip. Test TDS robotics. Cont. R/U air, steam, and control cables around rig. Tested BOP controls at koomey & doghouse panel (ok). Tested MP alarms and mud saver override alarms (ok). Staged subs, XO's, TIW, and dart valve on rig floor rack.;Brought over 3 pipe bunks from staging pad. Loaded ODS catwalk racks w/ 4.5" CDS 40 DP. Pulled flow riser on stack, trimmed back welded in coupler for fill up line for clearance. Installed test plug, M/U testing equip, flooded stack. Cont. building mud. Installed wall tarps on sub base.;Currently testing MP's and cont to work on rig acceptance check list.;Hauled Solids to G&I 0 bbls Hauled to G&I Cumulative 0 bbls Hauled Fluid to G&I 0 bbls Hauled to G&I Cumulative 0 bbls Hauled cement to G&I 0 bbls Cumulative Cement to G&I 0 bbls Daily Down Hole Losses 0 bbls Cumulative Losses 0 bbls 4/21/2022 Pump through open Pop-Offs and bleeders. Bump test hole fill pump. Perform weekly derrick inspection. Tighten output line on test pump. Flood remaining test equipment and perform 250 Low/ 4000 High shell test on BOPE equipment; Good Test. B/D choke. R/U and function test iron roughneck controls.;Flood and PT mudlines to 4000 psi. and B/D same, Install tarps on mast cylinders. Clean and organize Conex's. Fill and dtage up boiler. Strap CDS40 Drill Pipe on racks. Check Torque values between iron roughneck, tongs and top drive. Continue building 300 bbls 9.3ppg 6% PHPA mud.;Notified that BLM waived witness to initial BOPE test. 24 hour notification given to AOGCC from website of intent to test BOPE. Rig Accepted at 12:00pm.;Get steam going around rig and replace bad steam hoses. Set and test C.O.M. Continue building 9.3ppg KCL PHPA mud. Pressure wash and clean around rig. Install drain hoses in cellar area. Work on PM's. Check valve lash on MP #1 Engine. Re-configure liquid mud dock containment. Work with environmental;on Boiler Emissions Compliance. E-mail BLM with 48 hour notice of spud.;Cont. pressure washing & building mud. Cleaned and organized drilling conex. Changed filters on HYD unit. Gathered BHA for cleanout/Gauged run. Called AOGCC Jim Regg @ 19:15 hrs. Witness was waived on BOP test.;M/U test joint and set test plug. R/U testing equip. Filled stack , lines, and choke manifold. Purged out air.;Perform bi-weekly BOP test as per AOGCC & BLM regulations. BOP-250 Low/ 4000 High 5/10 min & Annular 250 Low/ 2500 High 5/10 min. Had no F/P. Quadco tested audio/visual on gas alarms (ok).;Pulled test pull, vac'd out stack, blew down lines and choke manifold. Greased choke manifold. Installed 9" wear ring, run in 2 lockdowns. Finished building 2nd batch of 6% KCL PHPA mud.;Serviced rig- Greased crown, blocks, TDS, IR, DWKS, brake linkage, and inspected drive shaft bolts.;Counted pipe on location. Staged drift assy. on rig floor. adjusted load collar on TDS. Strapped BHA components and obtained OD's & ID's.;M/U 8.5" drift run BHA #1- 8.5" PDC bit, bit sub/float, and XO. Started P/U and singled in the hole with 4.5" DP F/BHA #1 to current depth of 623'.;Hauled Solids to G&I 0 bbls Hauled to G&I Cumulative 0 bbls Hauled Fluid to G&I 0 bbls Hauled to G&I Cumulative 0 bbls Hauled cement to G&I 0 bbls Cumulative Cement to G&I 0 bbls Daily Down Hole Losses 0 bbls Cumulative Losses 0 bbls 4/22/2022 Continue RIH with 8-1/2" Drill Bit BHA #1 F/ 623' T/ 3624' picking up CDS40 drill pipe from catwalk.;Troubleshoot Pason EDR communications with Pason support. Had to swap antennas and re-assign configuration.;Continue RIH with 8-1/2" Drill Bit BHA #1 F/ 3624' T/ 5942' picking up CDS40 drill pipe from catwalk. Tagged CIBP at 5942'. PUW 113K SOW 99K, Calculated displacement observed for trip. E-Mail AOGCC for 24 hour notification of spud and FIT at 11:50am.;Break circulation and pump Hi-Vis sweep STS. 575 GPM with 1320psi SPP. Max gas peak at bottoms up was 1470 units.;Monitor Well, Static. POOH F/ 5942' T/ 5886' Break out Top Drive and blow down. POOH F/ 5886' T/ surface standing back drill pipe. Break out and L/D XO, bit sub and 8-1/2" cleanout bit. Calculated displacement observed for trip.;PJSM with E-Line crew, Rig up E-Line. Make up 9-5/8" CIBP and CCL to E-Line and run in hole T/3653', Logged up hole, 9-5/8" casing collar @ 3598' WLM. Logged on depth , set CIBP 6' above casing collar @ 3592' WLM. Tagged CIBP twice to confirm set depth. POOH w/ E-line, R/D and released AK-Eline.;At 18:30 hrs. the bearing on the fan hub on gen #2 came apart and contacted the radiator causing 2 gals of glycol to spill out into secondary containment. The spill was cleaned up from the secondary containment. Proper notification were made.;R/U testing equip. Tested 9-5/8" casing/CIBP T/4000 psi on chart for 30 min (ok). Lost 7 psi over 30 min. Pumped 4.55 bbls and bled back 4.5 bbls. B/D and R/D testing equip.;Held PJSM w/ Baker Rep and rig crew on M/U whipstock/milling assy BHA #2. M/U 8.5" milling assy. -Starter mill, lower mill, flex jt. upper mill, XO, and 1 jt. of HWDP. Carried scribe line from starter mill up. P/U 9-5/8" Gen 2 whipstock, inspected brass shear screw (x6) in trip anchor,;removed 1 shear screw leaving 5 screws in (3565 lbs to shear each screw). M/U starter mill to top of whipstock installing 35K shear bolt. RIH w/ whipstock/mills, M/U on top of HWDP-XO, float sub, DM & TM collar, and XO (Off set 292).;RIH out of the derrick F/103'-T/3512' at 45 fpm as per Baker Rep. Re-counted DP on location to double check count. P/U-59K S/O57K.;M/U TDS, broke circ. staged up pumps, GPM-457 SPP-782 psi P/U-75K S/O73K. Worked pipe and orientated 60° R high side as per HES DD. Cont. easing down and tagged CIBP w/ whip stock anchor @ 3596' DPM. Set down in 5K increments, sheared brass anchor screws w/ 20K set down (seen good;indication of setting). P/U 10K over S/O weight to 85K for good set verification . Set down 34K to shear whip stock lug. P/U 10' to verify released from ramp.;Held PJSM on displacing well over to 6% KCL PHPA mud. Pumped 20 bbl Hi-Vis spacer, followed by 9.3 ppg 6% KCL PHPA mud. Currently displacing well over to mud @ 3574'.;Hauled Solids to G&I 0 bbls Hauled to G&I Cumulative 0 bbls Hauled Fluid to G&I 0 bbls Hauled to G&I Cumulative 0 bbls Hauled cement to G&I 0 bbls Cumulative Cement to G&I 0 bbls Daily Down Hole Losses 0 bbls Cumulative Losses 0 bbls 4/23/2022 Mill Window F/ 3574' T/ 3595' First 2' at 1 foot per hour ROP, remaining window at 3 fph, 3K WOB 80 RPM 465 GPM 1025psi SPP 5k ft/lbs Off BTM TQ, 6.5K/ 10.5K on BTM TQ Top of Window at 3570' Bottom of Window at 3591'.;Continue milling rat hole below window with 8-1/2" milling assembly F/ 3595' T/ 3611'. 465 GPM, 1060 psi SPP, Diff 30 psi, WOB 8K, RPM 90, TQ 5.3K, Flow 36%, ROP 20 fph, PUW 75K, SOW 73K, ROT 72K. Dress window and drift with and without pumps. Pump Hi-Vis sweep. 465 GPM, 1050psi SPP, 40 RPM, 4K TQ.;Pull into window and rig up for FIT purge lines of air. Attempt to perform FIT pressure not holding. Troubleshoot and observe formation seeping fluid at a rate of 0.1285 BPH while monitoring at surf . Rig down and make up top drive. Pressure up to 430 psi. to attempt to squeeze LCM into formation.;Pressure dropped 200 psi in 15 minutes. Rig down and blow down choke and kill lines.;POOH with milling assembly F/ 3550' T/103', L/D MWD tools, XO's, and mills, 8.5" Upper window mill was a 1/16" out, lower window mill was engage, and the starter mill was 5/16" out (see photos in O -drive). Recovered 223 lbs of metal from milling. Cleaned & cleared rig floor. Calculated hole fill;P/U 4.5" CDS-40 mule shoe. RIH out of the derrick F/surface-T/3591'. Had calculated pipe displacement.;Circ. & conditioned mud while R/U HES cementers. GPM-320 SPP-260 psi P/U-77K S/O-67K.;Held PJSM w/ rig crew, HES cmt, CCI, Baroid, and night DSM. Balanced cmt plug- Pumped 2 bbls of water ahead and shutdown. Pressure tested cmt lines T/494 psi Low and T/2890 psi High (ok). Pumped 18.5 bbls of 10.5 ppg Tuned spacer@ 4 bpm (120 psi). Followed by 20 bbls of 15.8 ppg;Type I II cmt @ 4 bpm (175 psi). Pumped 5 bbls of 10.5 ppg Tuned spacer@ 3 bpm (12 psi). Displaced w/ 39 bbls of 9.3 ppg 6% KCL PHPA mud @ 6 bpm (112 psi) to balance plug. Shut down, opened bleeder on truck and checked for balance (ok). CIP @ 23:35 hrs.;R/D cementers. POOH w/ 7 stds at 30' per/min F/3591'-T/3155'. P/U- 77K S/O-67K.;Crew change, Held PTSM. Loaded 2 wiper balls into pipe, M/U TDS, CBU, GPM-400 psi SPP-335 psi. Had 5 bbls of Tune space return to surface. Shut down and lined up to squeeze cmt.;Flooded choke manifold, shut upper pipe rams. Performed cmt squeeze using MP. Pressured up T/440 psi, pressure dropped T/409 psi @ 5 min, (31 psi loss). Pressured up T/663 psi, pressure dropped T/634 psi @ 5 min, (31 psi loss). Pressed up T/802 psi, pressure dropped T/733 psi @ 5 min, (69 psi loss).;Pressured up T/1026 psi, pressure dropped T/896 psi @ 10 min, (130 psi loss). Pumped in 1.8 bbls and bled back .7 bbls;Flow checked well (static), blew down choke manifold, mudlines, and TDS. Turned elevators around.;POOH F/3155'-T/Mule shoe, L/D mule shoe. Had calculated hole fill for the trip.;M/U 8.5" cmt cleanout assy. / BHA #4- 8.5" Tricone bit, bit sub w/ out float, XO, and 1 jt. of HWDP. RIH F/36'-T/3314'.;M/U TDS, filled pipe. Washed down F/3314'-T/3410', seen 30 psi increase and 1-2K WOB. Kicked in rotary and started washing & reaming. Had indication of green cmt at surface. Current depth of 3502'. P/U-73K S/O-65K ROT-68K GPM-462 SPP-507 psi RPM-30 TQ-3.6K MW-9.3 ppg.;Hauled Solids to G&I 7 bbls Hauled to G&I Cumulative 7 bbls Hauled Fluid to G&I 312 bbls Hauled to G&I Cumulative 312 bbls Hauled cement to G&I 0 bbls Cumulative Cement to G&I 0 bbls Daily Down Hole Losses 0 bbls Cumulative Losses 0 bbls Daily metal 233 lbs. Cumulative metal 233 lbs. Continue RIH with 8-1/2" Drill Bit BHA Tagged CIBP twice to confirm set depth. gy Tested 9-5/8"y p pyp casing/CIBP T/4000 psi on chart for 30 min (ok). Lost 7 psi over 30 min. Pumped 4.55 bbls and bled back 4.5 bbls. pp Performed cmt squeeze using MP. Dress window and drift with and without pumps. Attempt to perform FITpp p pp pressure not holding. Troubleshoot and observe formation seeping fluid at a rate of 0.1285 BPH while monitoring at surf . Rig down and make up top drive. pp pg pg Pressure up to 430 psi. to attempt to squeeze LCM into formation.;Pressure dropped 200 psi in 15 minutes. M/U 8.5" milling assy. p Set CIBP for whipstock. -WCB g Shut down and lined up to squeeze cmt. gp p set CIBP 6' above casing collar @ 3592' WLM. p ;Pull into window and rig up for FIT purge lines of air. gp pg Mill Window F/ 3574' T/ 3595' First 2' at 1 foot per hour ROP, remaining window at 3 fph, p Pressured up T/440 psi, pq pppp q g pp pressure dropped T/409 psi @ 5 min, (31 psi loss). Pressured up T/663 psi, pressure dropped T/634 psi @ 5 min, (31 psi loss). Pressed up T/802 psi, pressure qgpq p pp p@(p) ppp pp p@(p dropped T/733 psi @ 5 min, (69 psi loss).;Pressured up T/1026 psi, pressure dropped T/896 psi @ 10 min, (130 psi loss). gg p POOH w/ g@ E-line, R/D and released AK-Eline. p ;Continue milling rat hole below window with 8-1/2"milling assembly F/ 3595' T/ 3611'. g y p Milled window for 7" intermediate liner. Cement squeeze after poor FIT. -WCB 4/24/2022 Drill cement F/ 3410' T/3613'. WOB 2/6K, GPM 460, SPP 480psi, RPM 30/50, TQ 3.9K/ 5.5K.;CBU, Flowcheck = Static. Discussion with engineer to drill ahead.;Drill F/ 3613' T/ 3621'. WOB 2/6K, GPM 460, SPP 480psi, RPM 30/50, TQ 3.9K/ 5.5K.;CBU, Flowcheck well and observe slight losses of .3 bbls per hour static.;Circulate and condition mud GPM 319 with 300psi.;Drill 8-1/2" Production hole F/ 3621' T/ 3631'. WOB 7.5K, GPM 465, SPP 510psi., RPM 60, DIFF 5psi., TQ 4.3K, Flow 36%, ROP 15 FPH, Max Gas 2Units, PUW 79K, SOW 69K, ROT 74K.;Circulate Bottoms up with GPM 460, SPP 490psi., RPM 60 and TQ 4.2K.;Rig up for FIT. Purge air from lines. Pressure up to 750psi and observe pressure drop to 450psi over 15 minutes. Rig down test equipment and blow down all lines.;POOH with 8-1/2" Bit cleanout assembly F/ 3570' T/ Surface. Lay down HWDP, XO, Bit sub and bit. PUW 78K, SOW 69K.;Rig service- Greased crown, blocks, TDS, wash pipe, DWKS, IR, brake linkage and drive shaft.;M/U mule shoe, RIH out of the derrick F/surface-T/3564', CBU just above window. P/U-75K S/O-66K.;Circ. & conditioned mud while R/U HES cementer. GPM-465 SPP-510 psi. Eased through the window and parked mule shoe @ 3622'.;Held PJSM w/ rig crew, HES cmt, CCI, Baroid, and night DSM. Balanced cmt plug- Pumped 2 bbls of water ahead and shutdown. Pressure tested cmt lines T/1800psi Low and T/3275 psi High (ok). Pumped 19.5 bbls of 10.5 ppg Tuned spacer@ 5 bpm (297 psi). Followed by 19 bbls of 15.8 ppg Type I II cmt @;4 bpm (200 psi). Pumped 5 bbls of 10.5 ppg Tuned spacer@ 6 bpm (130 psi). Displaced w/ 39 bbls of 9.3 ppg 6% KCL PHPA mud @ 6 bpm (110 psi) to balance plug. Shut down, opened bleeder on truck and checked for balance (ok). CIP @ 21:17 hrs. Had 8.8 ppb LCM in cmt plug.;R/D HES cmt, POOH F/3622'-T/3146' at 30' per/min. Loaded two wiper balls in DP and M/U TDS.;Circ. wiper balls around GPM-460 SPP-466 psi. Had no Tune space return to surface. Shut down and lined up to squeeze cmt.;Flooded choke manifold, shut upper pipe rams. Performed cmt squeeze using MP. Pressured up T/492 psi, pressure dropped T/479 psi @ 5 min, (13 psi loss). Pressured up T/639 psi, pressure dropped T/599 psi @ 5 min, (40 psi loss). Pressed up T/800 psi, pressure dropped T/753 psi @ 5 min, (47 psi loss).;Pressured up T/1040 psi, pressure dropped T/909 psi @ 10 min, (131 psi loss). Pumped in 1.5 bbls and bled back .75 bbls. Flow checked well (static), blew down choke manifold, mudlines, and TDS. Turned elevators around.;POOH F/3146'-T/561'. P/U-65K S/O-56K;Crew change, Held PTSM and weekly safety meeting w/ rig crew. Cont. POOH F/561'-T/ Mule shoe. L/D mule shoe. Had calculated hole fill for the trip.;M/U 8.5" cmt cleanout assy. / BHA #4- 8.5" Tricone bit, bit sub w/ out float, XO, and 1 jt. of HWDP. RIH F/36'-T/3501'.;M/U TDS, filled pipe, washed F/3501'-T/3531'. GPM-385 SPP-466 P/U-73K S/O-63K . Washed & reamed F/3531'-T/3567' GPM-394 SPP-504 RPM-27 TQ-4K MW-9.4 ppg P/U-73K S/O-63K ROT-68K.;Drilled green cmt F/3567'-T/3631'. Drilled 10' of new formation F/3631'-T/3641'. WOB-1.4K GPM-465 SPP-585 psi RPM-60 TQ-4K. P/U-73K S/O-63K ROT-68K.;CBU, shut down pumps, performed 15 min flow check. Formation sample at BU 80% sand 20% Clay stone.;Resumed drilling. Drilled last 10' of of new formation F/3641'-T/3651'. P/U-73K S/O-63K ROT- 68K GPM-465 SPP-595 psi RPM-60 TQ-4.2K WOB-7K MW-9.4 ppg;Currently CBU x2. GPM-466 SPP-623 psi TQ-4.2K RPM-60 MW-9.4 ppg;Hauled Solids to G&I 30 bbls Hauled to G&I Cumulative 37 bbls Hauled Fluid to G&I 235 bbls Hauled to G&I Cumulative 547 bbls Hauled cement to G&I 0 bbls Cumulative Cement to G&I 0 bbls Daily Down Hole Losses 0 bbls Cumulative Losses 0 bbls Daily metal 6 lbs. 4/25/2022 Complete CBU x2. GPM-466 SPP-623 psi TQ-4.2K RPM-60 MW-9.4 ppg. Flow check well, slight seepage with .25 bbl / hour static loss rate. POOH F/ 3651' T/ 3563'.;R/U Test equipment for FIT test @697 psi for a 13.5ppg EMW in 9.5ppg mud. Pressure uo to 758psi bled down to 547 psi. Pumped 36.8 gallons and bled off 29.4 gallons.;R/D test equipment, Clean and organize rig floor, B/D choke. Flush out and inspect centrifuge.;Grease and Inspect crown, blocks, top drive, iron roughneck, draworks, linkages, driveshaft and floor motor fan hub tolerance.;LOT results are a 13.05ppg EMW. Standby above Whipstock at 3563' keeping the hole full & monitoring with trip tank. Add fluid T/ Top Drive gearbox, C/O right angle gear box fluid and filter, C/O upper & lower roughneck die blocks, Clean & organize around rig while getting approval for new plan.;Re-align torque tube & T-Bar in derrick, Perform derrick inspection, perform pm on FH-80 & change filters on fh-80 and iron roughneck hpu. Pressure wash & scrub on rig floor, between pump house, pits & under drawork covers. Scrub & clean out choke house. Clean out & organize cabinet in pump house 2.;Circulate and condition mud to bring mud weight back down to 9.3ppg and treat out cmt contaminates.;Shut down the pumps, monitored well on the TT (Static). Held table top well control, and well kill methods w/ the rig crew. Pressure washed roof tops of pit modules. Worked on tong counter weights to make it easier to lower/raise the tongs. Filled lube containers in lube room. Prepped lube;room for paint. Built new steam lines and replaced bad ones around the rig. Changed out needle valve on test pump sensator. Turned cmt silo 180° for easier access to valves for cementer.;Crew change, held PTSM. Cont. w/ housekeeping and working on misc. projects. Broke circ. Staged up the pumps. CBU to turn mud over and condition mud from down hole. GPM-418 SPP-536 psi. Cleaned & organized roughneck room, choke house, and air compressor room.;Shut down MP's. Monitored well on the TT (Static). Mixed mud chemicals into active pits to treat mud from down hole. Prepping roughneck room for paint. Pressure washing outside walls of gen #3, and C-can on rig HPU skid. worked on prepping choke manifold handles for paint.;M/U TDS, broke circ. Circ. & conditioned mud down hole GPM-396 SPP-488. Cont. w/ housekeeping, organizing, and working on misc. projects.;Shut down MP's. Performed 15 min flow check (static). Cont. monitoring well on TT.;Currently gathering tools and holding PJSM for a short slip & cut of drill line (37').;Hauled Solids to G&I 33 bbls Hauled to G&I Cumulative 70 bbls Hauled Fluid to G&I 172 bbls Hauled to G&I Cumulative 719 bbls Hauled cement to G&I 0 bbls Cumulative Cement to G&I 0 bbls Daily Down Hole Losses 0 bbls Cumulative Losses 0 bbls Daily metal 0 lbs. Cumulative metal 239 lbs. ppg Had 8.8 ppb LCM in cmt plug.; pp pq Performed cmt squeeze using MP. Pressured up T/492 psi, pressure dropped T/479 psi @ 5 min, (13 psi pp p p q g p p p pp p@ loss). Pressured up T/639 psi, pressure dropped T/599 psi @ 5 min, (40 psi loss). Pressed up T/800 psi, pressure dropped T/753 psi @ 5 min, (47 psi ) p p p pp p @ ( p ) p p p pp loss).;Pressured up T/1040 psi, pressure dropped T/909 psi @ 10 min, (131 psi loss). Pumped in 1.5 bbls and bled back .75 bbls. pp 80% sand 20% Clay stone.;Resumed drilling. Drilled last 10' of of new formation F/3641'-T/3651'. gpgp p Pumped 19.5 bbls of 10.5 ppg Tuned spacer@ 5 bpm (297 psi). Followed by 19 bbls of 15.8 ppg Type I II cmt @;4 bpm (200 psi). Pumped pg() p pp 5 bbls of 10.5 ppg Tuned spacer@ 6 bpm (130 psi) pppg ;R/U Test equipment for FIT test @697 psi for a 13.5ppg EMW in 9.5ppg mud. LOT results only 13.05 ppg, far below the expected >15 ppg. AOGCC req'd 7" intermediate string, per Sundry 322-232. -WCB Drill cement F/3410' T/3613'. W Drilled 10' of new formation F/3631'-T/3641'. p ;Rig up for FIT. Purge air from lines. Pressure up to 750psi and observe pressure drop to 450psi over 15 minutes. Second cement squeeze of the 7" window. -WCB pg Clean & gp p organize around rig while getting approval for new plan. p ;Drill 8-1/2" Production hole F/ 3621' T/ 3631'. pg ;LOT results are a 13.05ppg EMW. 4/26/2022 Cut and Slip drilling line. (short cut 37') Test C.O.M. Reset ton miles on Pason.;Continue PM's around rig and general housekeeping and organization.;Continue to wait on approval from AOGCC and BLM for new well program. Monitor well on trip tank. Pressure wash BOPE stack and mezz deck. clean out and organize overhead toolbox. Buff rust off Geronimo block, prime and paint. Change out valves on rod wash for mud pumps. Calibrate hook load on Pason.;POOH F/ 3563' T/ surface and lay down 8-1/2" bit, bit sub, crossover and joint of HWDP. PUW 76K SOW 64K.;Clean and clear rig floor. Function test Blind Rams from drillers station.;PJSM Make up drilling BHA as per DD/MWD, Upload tool string and shallow pulse test MWD, Load Sources, RIH P/U remaining BHA, t/ 726', Continue RIH P/U Singles from rack t/ 3635' @ 3550' Orient tool face to slide, did see lip on bottom of window with bit.;Wash and ream to bottom Drill ahead as per DD/MWD, tools hanging up on window f/ first 60' slide drill and rotate as needed to get through tight spots Drill Ahead f/ 3651' t/ 3947' 475 gpm 1650 psi 55 rpm 6500k tq on bottom PUW 98k SOW 75k Rot 85k WOB 5k.;Distance to plan 5.45' 5.08' Low 1.98' Right;Hauled Solids to G&I 0 bbls Hauled to G&I Cumulative 70 bbls Hauled Fluid to G&I 0 bbls Hauled to G&I Cumulative 719 bbls Hauled cement to G&I 0 bbls Cumulative Cement to G&I 0 bbls Daily Down Hole Losses 0 bbls Cumulative Losses 0 bbls Daily metal 0 lbs. Cumulative metal 239 lbs. 4/27/2022 Drill Ahead F/ 3947' T/ 4381' WOB 4/8K GPM 518 SPP 2000psi RPM 80 DIFF 100psi TQ on bottom 7.8K Off bottom 7.2K Max gas 35 units PUW 114K SOW 85K ROT 98K. Madd Pass all slides. SPR's at 4072' md 3816' tvd MW 9.4ppg MP#1 at 46 stks 254psi, MP#2 at 46 stks 254psi.;Drill Ahead F/ 4381' T/ 4691' WOB 4/8K GPM 518 SPP 2016psi RPM 80 DIFF 50psi TQ on bottom 7.9K Off bottom 7.4K Max gas 20 units PUW 123K SOW 87K ROT 100K. Madd Pass slides. SPR's at 4689' md 4417' tvd MW 9.3ppg MP#1 at 46 stks 247psi, MP#2 at 46 stks 251psi.;Circulate bottoms up GPM 518 SPP 1792 RPM 80 TQ off bottom 8.2K ECD 9.64;Monitor well, slight seepage. POOH F/ 4691' T/ 4005' Hole fill Calculated 4.6 bbls. Actual 5.3 bbls. with difference of .7 bbls.;Rig Service Grease Blocks, crown, Draworks, Iron Roughneck and Clean pump suction screens.;RIH with 8-1/2" Directional assembly F/ 4005 T/ 4630' make up top drive and wash last stand T/ 4691' Actual displacement 11.3 bbls, calculated 12.2 bbls. .9 bbls difference.;Drill ahead F/ 4691' T/ 5241 WOB 4/8K GPM 518 SPP 2050psi RPM 80 DIFF 75psi TQ on bottom 9K Off bottom 7.8K Max gas 20 units PUW 123K SOW 87K ROT 100K. Madd Pass slides. SPR's at 4689' md 4417' tvd MW 9.3ppg MP#1 at 46 stks 247psi, MP#2 at 46 stks 251psi.;Drilling Ahead f/ 5241' t/ 5680' 518 GPM 2050 psi 80 rpm 9900 tq on bottom, 9.3 ppg MW 9.7 ppg ECD 147k PUW 94k SOW 100k ROT Distance to plan 1.42' .21 High 1.41 left.;Circulate bottoms up, obtain SPR's and survey, Flow check well slight seepage.;POOH on elevators f/ 5680' t/ 5350'.;Hauled Solids to G&I 84 bbls Hauled to G&I Cumulative 154 bbls Hauled Fluid to G&I 281 bbls Hauled to G&I Cumulative 1000 bbls Hauled cement to G&I 0 bbls Cumulative Cement to G&I 0 bbls Daily Down Hole Losses 0 bbls Cumulative Losses 0 bbls Daily metal 0 lbs. Cumulative metal 239 lbs. 4/28/2022 POOH on elevators F/ 5350' t/ 4625' No tight spots seen. 2BBLS over calculated Displacement.;Grease and Inspect Crown, Blocks, Top Drive, Iron Roughneck, Draworks, Linkages and Driveshaft.;RIH F/ 4625' T/ 5680' Pump 20 BBLs Hi-Vis sweep. 1 BBL under calculated displacement for the trip.;Drill F/ 5680' T/ 5954' WOB 3/8K, GPM 515, SPP 2100psi, DIFF 150psi, RPM 80, TQ on bottom 10.9K, TQ off bottom 10.7K, Max gas observed 414 units, PUW 160K, SOW 97K, ROT 118K. Sweep had an increase of 10% fine cuttings.;Circulate and reciprocate while replacing Swab and Liner in Mud Pump # 2 Mod #2. GPM 260, SPP 715, RPM 25.;Drill F/ 5954' T/ 6053' WOB 3/6K, GPM 515, SPP 2100psi, DIFF 150psi, RPM 80, TQ on bottom 11.2K, TQ off bottom 10.7K, Max gas observed 39 units, PUW 160K, SOW 97K, ROT 118K. Add 1 Drum of Drill-N-Slide.;Drill F/ 6053' T/ 6673' WOB 2/9K, GPM 515, SPP 2191psi, DIFF 169psi, RPM 80, TQ on bottom 12.4K, TQ off bottom 11.7K, Max gas observed 644 units, PUW 175K, SOW 104K, ROT 124K. SPR's at 6175'md 5777'tvd MW: 9.4ppg MP#1 @46 strokes 279psi. MP#2 @46 strokes 280psi.;Circulate bottoms up 518 gpm 2150 psi 80 rpm 11000tq off bottom, obtain SPR's and survey, Flow check well seepage loss dropped 2' in riser in 15 min;POOH on elevators f/ 6673' t/ 3568' worked through tight spots f/ 6209'- 6009' 10-20k over pulls and 5-10k drag, window was clean pulling pit through observed 15k over pull @ 3642' very quick and popped free;Service rig and top drive, draw works and crown, monitor loss rate on trip tank 1.6 bph;RIH f/ 3568' t/ 6673' work through spot @ 5273' till clean, 25k set down at 6395' wash and ream t/ 6673' 15' fill on bottom;Drill Ahead f/ 6673' t/ 6856' 518 gpm 2250 spi 80 rpm 12500 tq on bottom 9.4 ppg 25 lb/bbl Background LCM, PUW 175k SOW 104k ROT 124k, Distance to Plan 8.23' 7.55' High 3.27' Left;Hauled Solids to G&I 66 bbls Hauled to G&I Cumulative 220 bbls Hauled Fluid to G&I 189 bbls Hauled to G&I Cumulative 1189 bbls Hauled cement to G&I 0 bbls Cumulative Cement to G&I 0 bbls Daily Down Hole Losses 50 bbls Cumulative Losses 50 bbls Daily metal 0 lbs. Cumulative metal 239 lbs. Drilling 8-1/2" hole for the 7" int. liner. -WCB y ;Drill ahead F/ 4691' T/ 5241 Drill Ahead F/ 3947' T/ 4381' ;Drill Ahead f/p 6673' t/ 6856' g ;Drill F/ 5680' T/ 5954' g Pason.;POOH F/ 3563' T/ surface and lay down 8-1/2" bit p 25.;Drill F/ 5954' T/ 6053' g ;Drilling Ahead f/ 5241' t/ 5680' g ;Drill Ahead F/ 4381' T/ 4691' p ;Drill F/ 6053' T/ 6673' Drilling 8-1/2" hole for the 7" int. liner. -WCB 4/29/2022 Drill F/ 6856' T/ 7012' WOB 5/10K, GPM 515, SPP 2250psi, RPM 80, DIFF 150psi, TQ on bottom 13.7K, TQ off bottom 13.2K, PUW 195K, SOW 105K, ROT 134K, Max gas seen was 104 units. Pumped 20 BBL Hi-Vis sweep after slide. Sweep came back on time 25% increase in cuttings.;Drill F/ 7012' T/ 7137' WOB 5/10K, GPM 515, SPP 2332psi, RPM 80, DIFF 150psi, TQ on bottom 13.7K, TQ off bottom 13.2K, PUW 195K, SOW 105K, ROT 137K, Max gas seen was 15 units. MADD Pass on slides greater than 20'. SPRs at 7104'md 6648'tvd MW 9.5ppg MP#1 at 46 strokes 301psi MP#2 at 46 strokes 307psi;Drill F/ 7137' T/ 7278' WOB 5/10K, GPM 515, SPP 2240psi, RPM 80, DIFF 150psi, TQ on bottom 12.1K, TQ off bottom 11K, PUW 200K, SOW 107K, ROT 137K, Max gas seen was 12 units. MADD Pass on slides greater than 20'. MW 9.5ppg Function Upper Lower and Annular in between connections.;Drill f/ 7278' t/ 7433' 515 gpm SPP 2440 psi 80 RPM 14500 tq on bottom 13200 tq off bottom, PUW 212k SOW 110k ROT 139k, MW 9.5 ppg Distance to plan 7.49' 1.46' High 7.35' left Madd Pass every slide over 20' Max Gas seen 55 units.;Hauled Solids to G&I 47 bbls Hauled to G&I Cumulative 267 bbls Hauled Fluid to G&I 268 bbls Hauled to G&I Cumulative 1457 bbls Hauled cement to G&I 0 bbls Cumulative Cement to G&I 0 bbls Daily Down Hole Losses 24 bbls Cumulative Losses 74 bbls Daily metal 0 lbs. Cumulative metal 239 lbs. 4/30/2022 Drill F/ 7433' T/ 7476' WOB 6/12K, GPM 515, SPP 2400psi, RPM 70, DIFF 150psi, TQ on bottom 14K, TQ off bottom 14.1K, PUW 213K, SOW 108K, ROT 140K, Max gas seen was 40 units. MADD Pass on slides greater than 20'. SPRs at 7476'md 7023'tvd MW 9.5ppg MP#1 at 46 strokes 297psi MP#2 at 46 strokes 297psi;Discussion with Geologist with agreed we are at TD of 8-1/2" Intermediate section.;Circulate Bottoms Up GPM 515, SPP 2200psi, RPM 70 . Flow check well and observe seepage.;POOH F/ 7476' T/ 6605' Worked through any tight spots observed. Displacement was 2 BBLs over calculated.;Grease and Inspect Crown, Blocks, Top Drive, Iron Roughneck, Draworks, Linkages and Driveshaft. Monitor well with trip tank and observe a static loss rate of 3 BPH.;RIH F/ 6605' T/ 7476' with no tight spots observed. 5' of fill on bottom. Displacement was 1.5 BBLs under calculated displacement.;Circulate hole clean and pump 20 BBLs of Hi-Vis sweep. Sweep came back with increase of 20% in fine cuttings. Flow check with same seepage observed. Static loss rate of 3BPH. Pump 17 BBLs dry job. Notification sent to AOGCC for BOPE test at 10:22am.;POOH F/ 7476' md T/ 3551' PUW 213K, SOW 108K, work through tight spots F/ 6440' T/ 6200' with no other tight spots observed. No problems coming through window. Flow check well, still falling at a static rate of 3BPH. Continue POOH F/ 3551' T/ 726'.;Received notification at 12:19pm from AOGCC that witness for BOPE test is waived. Received notification 04/29/2022 at 07:58am that BLM waived witness of both running / cementing casing and the BOPE test.;POOH with 8-1/2" Directional BHA, stand back 5 stands of HWDP, Laying down one joint of HWDP and 6-1/2" Drilling Jars. Stand back remaining 3 stands of HWDP.;L/D Collars, Unload sources and down load MWD, L/D Remaining BHA break bit Graded a 2-3 in gauge, clean and clear floor.;Pull Wear ring and change upper rams t/ 7'' Solid body.;R/U test equipment and Make up test jt, flood stack and lines.;Test Annular and upper rams on 7'' test jt t/ 250/ 4000 psi on the rams and 250/2500 on the annular with 5 min low and 10 min high.;R/D test equipment set wear ring and blow down lines.;R/U Weatherford casing running equipment and fill up line, load racks and P/U centralizers.;RIH w/ 7'' 26# Vam casing torqueing to 8300 ft/lbs installing centralizers every jt, M/U shoe track and float equipment, check floats (good) RIH t/ 2900'.;Hauled Solids to G&I 13 bbls Hauled to G&I Cumulative 280 bbls Hauled Fluid to G&I 72 bbls Hauled to G&I Cumulative 1599 bbls Hauled cement to G&I 0 bbls Cumulative Cement to G&I 0 bbls Daily Down Hole Losses 48 bbls Cumulative Losses 122 bbls Daily metal 0 lbs. Cumulative metal 239 lbs. 5/1/2022 Continue running 7" 26# L-80 VamTop Intermediate Liner F/ 2900' T/ 4102' filling on the fly and topping off every 10 joints. PUW 113K, SOW 89K.;Pick up and Make up 7" x 9-5/8" SL ZXP Liner Top Hanger/ Packer assembly Confirm correct shear screws in assembly and RIH T/ 4147'.;Rig Down Weatherford 7" handling equipment and power tongs. Break out drive sub and crossover.;RIH with 1 stand of drill pipe F/ 4147' T/ 4213' and circulate through liner bringing pumps up to 5 BPM at 210 GPM with 267psi. Rotate Liner at 5 RPM with 7K TQ, 10 RPM with 7.4K TQ.;Continue RIH with 7" Intermediate Liner with stands of CDS40 drill pipe F/ 4213' T/ 5758' fill pipe GPM 210, SPP 425psi. Continue RIH with 7" Intermediate Liner with stands of CDS40 drill pipe F/ 5758' T/ 7423' set down with 30K on fill.;Make up Top Drive and wash down through 53' of fill T/ 7476' installing a single joint and the Baker Cement head with 10' pup on bottom. GPM 219, SPP 616psi.;PJSM with all parties on location and discuss plan forward with cement job along with roles and responsibilities. Rig up cement line to cement head.;Pump 5 BBLs of water, Pressure test lines low 380psi. High 4500psi. Pump 30 BBLs of 10.5ppg Tuned Spacer, Pump 125 BBLs of 12.0ppg Lead cement, Followed with 18 BBLs of 15.3ppg Tail cement, Release Drill Pipe wiper dart from cement head, Observed Drill Pipe wiper dart latch Liner wiper plug with;48 BBLs into displacement, Pump 10 BBLs of water and 191 BBLs of 9.5ppg mud and bumped plug with a total of 201 BBLs. CIP at 16:17pm. Pressured up to 3500psi, Then 4000psi, Then 4500psi. Set Hanger/ Packer, Lost 4.7 BBLs during entire job.;Release running tool and circulate top of liner clean with 30 BBLs of Tuned spacer and 38 BBLs of Lead cement returned to surface. GPM 470, SPP 581psi.;POOH w/ Running tool f/ 3331' t/ surface, L/D Liner running tool.;P/U Johnny wacker and flush stack and bag with black water, drain stack, break down cement head and clear floor.;Remove wear ring / Change upper rams back to 2 7/8'' X 5'' VBR's.;R/U test equipment and install test plug and 4.5'' Test jt, fill stack and lines and purge air.;Test BOP's as per state and federal guidelines, test upper lower and blind rams, CMV 1-15, Auto and Man IBOP, HCR and Man Choke and kill valves, TIW and Dart, t/ 250 low 4000 high f/ 5 min low and 10 min high Test annular t/ 250 low 2500 high, perform Draw down test, function test gas alarms, test;with 2 7/8'' and 4.5'' test Jts, test PVT alarms and flow paddle, Test man and electric choke - FP on Blind rams had to function and retest pass.;Pull test plug, R/U and test casing with test pump.;Hauled Solids to G&I 49 bbls Hauled to G&I Cumulative 329 bbls Hauled Fluid to G&I 356 bbls Hauled to G&I Cumulative 1955 bbls Hauled cement to G&I 38 bbls Cumulative Cement to G&I 38 bbls Daily Down Hole Losses 20 bbls Cumulative Losses 142 bbls Daily metal 0 lbs. Cumulative metal 239 lbs. g ;Drill F/ 7137' T/ 7278' Drill F/6856' T/ 7012' 7" liner cemented, w/38 bbls lead cement returned to surface. LTP set. -WCB ;Drill F/ 7012' T/ 7137' ;Drill f/ 7278' t/ 7433' ff jg p gp Pump 30 BBLs of 10.5ppg Tuned Spacer, Pump 125 BBLs of 12.0ppg Leadp cement, Followed with 18 BBLs of 15.3ppg Tail cement, p ;Release running tool and circulate top of liner clean with 30 BBLs of Tuned spacer and 38 BBLs of Lead cement returned to surface. pp p fill.;Make up Top Drive and wash down through 53' of fill T/ 7476' Drill F/ 7433' T/ 7476' Make up 7" x 9-5/8" SL ZXP Liner Top Hanger/ Packer assembly TD reached for the 7" liner hole. -WCB Continue RIH with 7" Intermediate Liner with stands of CDS40 drill pipe F/ 5758' T/ 7423' g Geologist with agreed we are at TD of 8-1/2" Intermediate section. Pressured up p to 3500psi, Then 4000psi, Then 4500psi. Set Hanger/ Packer, Lost 4.7 BBLs during entire job.pppg Continue running 7" 26# L-80 VamTop Intermediate Liner F/ 2900' T/ 4102' gp Observed Drill Pipe wiper dart latch Liner wiper plugr ppg p p ppg ppgpppp with;48 BBLs into displacement, Pump 10 BBLs of water and 191 BBLs of 9.5ppg mud and bumped plug with a total of 201 BBLs. ppg ppgpp ppg 5/2/2022 Test 7" Intermediate Liner against Blind Rams T/ 4000psi for 30 charted minutes. 5.6 BBLs pumped in and 5.6 BBLs bled back. Good Test.;B/D and R/D all test equipment and choke. Break out TIW and Dart valves from test joints. Install 9" ID wear ring and lock with two LDS. Clear rig floor of all unneeded equipment. Rechain BOPE stack and line up choke manifold.;Grease and Inspect Crown, Blocks, Top Drive, Iron Roughneck, Draworks, Linkages and Driveshaft. Re-Adjust link tilt arm clamp.;Pick up and Make up BHA #7 6-1/8" Directional BHA as per Halliburton MWD/ DD up to TM collar.;PJSM, Upload MWD tools, Shallow pulse test, Load sources and RIH P/U remaining BHA t/ 758', Continue RIH f/ Derrick t/ 3038' Fill pipe. Hold Kick while tripping drill.;Slip and cut 80' of drilling line, service draw works and brakes.;Continue RIH F/ 3038' T/ 7361' Wash down and tag up on landing collar @ 7391' 250 gpm 2100 psi 30 rpm 11000 tq.;Drill float equipment f/ 7391' t/ 7476' Drill 20' of new hole t/ 7496' 250 gpm 1900 psi 30 rpm 11500 tq.;Circulate bottoms up 254 gpm 1800 psi.;R/U and Perform FIT t/ 12.65 ppg EMW 1080 psi pump 1.37 bbls (57.4 gal) bleed back 1.3 bbls (56.4 gal) Blow down lines and Line up for drilling.;Drill Ahead f/ 7496' t/ 7571' , 256 gpm SPP 2020 psi, 30 rpm 11000 tq on bottom, 3-5k WOB, 9.7 ppg MW 10.74 ppg ECD, Max Gas Seen 12 units, Distance f/ plan 12.54' 9.79 high 7.83 left Issues sliding stalling motor and killing pump.;Hauled Solids to G&I 3 bbls Hauled to G&I Cumulative 332 bbls Hauled Fluid to G&I 62 bbls Hauled to G&I Cumulative 2017 bbls Hauled cement to G&I0 bbls Cumulative Cement to G&I 38 bbls Daily Down Hole Losses 0 bbls Cumulative Losses 142 bbls Daily metal 3 lbs. Cumulative metal 241 lbs. 5/3/2022 Drill Ahead F/ 7571' T/ 7705' , WOB 3-5K, GPM 278, SPP 2180psi, RPM 30, TQ on Bottom 9.7K. MW 9.6/vis 55, ECD's at 10.6 ppg, BGG 12 units, max gas 89 units.;Cont drilling 6 1/8” hole from 7705’ to 7797’. Sliding wob 1K, 278 gpm-2182 psi, 175 psi diff, 12 ft/hr ROP. Rot wob 4-6K, 278 gpm-2225 psi, 13,000 ft/lbs on bott torque, 114 ft/hr ROP, MW 9.6+/vis 54, ECD’s at 10.7 ppg, BGG 3 units, max gas 20 unit. Added 1 drum NXS lube to suction pit at 7743’.;Cont drilling 6 1/8” hole from 7797’ to 7822’. Sliding wob 1-4K, 278 gpm-2182 psi, 175 psi diff, 12 ft/hr ROP. Rot wob 4-6K, 278 gpm-2225 psi, 13,000 ft/lbs on bott torque, 114 ft/hr ROP, MW 9.55/vis 56, ECD’s at 10.7 ppg, BGG 12 units, max gas 26 unit. Added 4 drum Lube gold seal and drill n slide.;Cont drilling 6 1/8” hole from 7822’ to 7875’. Sliding wob 1-4K, 278 gpm-2150 psi, 140 psi diff, Rot wob 4-6K, 278 gpm-2225 psi, 13,000 ft/lbs on bott torque, MW 9.55/vis 56, ECD’s at 10.7 ppg, BGG 12 units, max gas 26 unit, Distance to Plan 32.77' 8.5' Low 31.65' Right.;Hauled Solids to G&I 17 bbls Hauled to G&I Cumulative 349 bbls Hauled Fluid to G&I 123 bbls Hauled to G&I Cumulative 2140 bbls Hauled cement to G&I 0 bbls Cumulative Cement to G&I 38 bbls Daily Down Hole Losses 0 bbls Cumulative Losses 142 bbls Daily metal 0 lbs. Cumulative metal 241 lbs. 5/4/2022 Cont drilling 6 1/8” hole from 7875’ to 8044’. Sliding wob 1-4K, 279 gpm-2126 psi, 140 psi diff, 15 ft/hr ROP. Rot wob 4-6K, 279 gpm-2470 psi, 60 rpm-13,300 ft/lbs on bott torque, 80 to 100 ft/hr ROP, MW 9.5+/vis 56, ECD’s at 10.8 ppg, BGG 10 units, max gas 89 units.;CBU twice at 283 gpm-2164 psi, 70 rpm-13,350 ft/lbs off bott torque. Obtained on bottom survey, SPR's, flow check was static.;Backreamed up hole through all the slide intervals, from 8044' to 7484' with no issue. 278 gpm-2006 psi, 40 rpm-13,200 ft/lbs off bott torque, up wt 150K. Pulled last stand into casing shoe on elevators, up wt 200K, then parked string at 7484'.;Serviced rig and topdrive.;RIH slow on elevators from 7484' to 7984' with no issue. MU last stand, filled pipe, washed down to bottom at 8044' with no sign of fill. Down wt 105K. Made hook.;Cont drilling 6 1/8" hole from 8044' to 8159', rot wob 6K, 283 gpm-2345 psi, 74 rpm-13,177 ft/lbs on bott torque, 11 to 98 ft/hr ROP. Rack and tally two loads 4 1/2" liner.;Cont drilling 6 1/8" hole from 8159' t/ 8340' 275 gpm 2588 psi SPP 70 RPM 13.7 k torque on bottom 14.3 k tq off bottom Max gas 25 units PUW 210k SOW 105k ROT 137k.;Cont drilling 6 1/8" hole from 8340' t/ 8504' 275 gpm 2595 psi SPP 70 RPM 14.7 k torque on bottom 15.6 k tq off bottom Max gas 50 units PUW 215k SOW 105k ROT 139k, Hydraulic fluid coming out of breather vent on gear box, Rieneer motor on top drive failing, Drain gear box lower level.;Circulate bottoms up Survey and SPR's.;POOH f/ 8504' t/ 7421' Work through tight spots @ 8340' and 8304' 30k over pulls Install TIW monitor well on trip tank.;Trouble shoot top drive work on removing Rieneer motor.;Hauled Solids to G&I 15 bbls Hauled to G&I Cumulative 364 bbls Hauled Fluid to G&I 205 bbls Hauled to G&I Cumulative 2345 bbls Hauled cement to G&I 0 bbls Cumulative Cement to G&I 38 bbls Daily Down Hole Losses 0 bbls Cumulative Losses 142 bbls Daily metal 0 lbs. Cumulative metal 241 lbs. Drilling hole for 4-1/2" liner. -WCB ;Cont drilling 6 1/8" hole from 8044' to 8159', Cont drilling 6 1/8” hole from 7875’ to 8044’. ;Cont drilling 6 q 1/8” hole from 7797’ to 7822’. p ;Drill Ahead f/ 7496' t/ 7571' q Perform FIT t/ qp 12.65 ppg EMW p ;Pick up and Make up BHA #7 6-1/8" ;Cont drilling 6 1/8” hole from 7705’ to 7797’. g Work through tight spots @ 8340' and 8304' Drill 20' of new hole t/ 7496' gp ;Cont drilling 6 1/8" hole from 8340' t/ 8504' Drilling hole for 4-1/2" liner. -WCB Drill Ahead F/ 7571' T/ 7705' ;Cont drilling 6 1/8" hole from 8159' t/ 8340' g g First portion of hole for 4-1/2" liner drilled. FIT performed to 12.65 ppg. -WCB q ;Cont drilling 6 1/8” hole from 7822’ to 7875’. 5/5/2022 Installed flow meter on hydraulic return line from topdrive to HPU, test ran topdrive, saw 1 gpm return flow (should see 3-5 gpm). Shut down, LOTO HPU and topdrive, functioned robotics to relieve any trapped hyd pressure. Removed service loop hyd hoses, removed hyd plumbing, unbolted and removed;renieer motor from topdrive. PU and installed new motor, bolted/torqued same to topdrive. Drained gear box and added fresh oil. Installed plumbing, tested sun cartridge atmospheric relief setting and installed same, installed safety wire to all bolts. Bumped HPU pump on/off to purge air from motor.;Test ran topdrive checking for leaks, checked torque values, all good. Changed oil in gear box again and filters on HPU. Monitored well on trip tank at .25 bph seepage while making repairs.;TIH from 7421' to 7542', MU topdrive, broke circ at 274 gpm-1952 psi, 60 rpm-12,198 ft/lbs off bott torque and check for leaks etc, all good. Cont TIH on elevators from 7542' to 8478', dwn wt 115K, no issues. MU topdrive on last stand and filled pipe. Started 20 bbl hi-vis sweep down drill string.;Resumed drilling 6 1/8" hole from 8504' to 8765', rot wob 6-7K, 278 gpm-2406 psi, 60 rpm-14,700 ft/lbs on bott torque, 13 to 90 ft/hr ROP, Seep back on time, maybe 10% inc in fine sand, added 6 drums Baro-Lube Gold Seal lube over 1 hour to bring lube concentration up over 3% to active system.;Cont drilling 6 1/8" hole from 8765' to 9045' 259 gpm 2580 psi SPP 70 RPM 15.7k Tq on botttom 15.3k tq off bottom, 5-7k WOB, Max Gas 45 units, PUW 230k SOW@ 107k ROT 143k Pump lube sweep seen noticeable change in torque and drag numbers.;Cont drilling 6 1/8" hole from 9045' to 9285' 282 gpm 2833 psi SPP 60RPM 15.7k Tq on botttom 16.8k tq off bottom, 5-7k WOB, Max Gas 92 units, PUW 230k SOW@ 107k ROT 143k Pump lube sweep, Distance from plan 20.46 7' Low 19.23 left.;Hauled Solids to G&I 13 bbls Hauled to G&I Cumulative 377 bbls Hauled Fluid to G&I 52 bbls Hauled to G&I Cumulative 2397 bbls Hauled cement to G&I 0 bbls Cumulative Cement to G&I 38 bbls Daily Down Hole Losses 0 bbls Cumulative Losses 142 bbls Daily metal 0 lbs. Cumulative metal 241 lbs. 5/6/2022 Cont drilling 6 1/8" hole from 9285' to 9593'. Rot wob 2-6K, 282 gpm-2685 psi, 60 rpm-16,300 ft/lbs on bott torque, 20-60 ft/hr ROP, MW 9.8/vis 56, ECD's 11.5 ppg, BGG 20 units, max gas 160 units. On bottom survey has us 8' left and 5' low of the line.;Circulated surface to surface at 282 gpm-2648 psi, working pipe with no rotation on up stroke, rotating 60 rpm on down stroke. Obtained SPR's then flow checked. Seeing very slight seepage.;Pumped up hole 18 stands from 9593' to 8472'. Pumped at 278 gpm-2400 psi. Up wt 240K. At 8993' and 8865' pulled 25K over, worked both spots one time and cleaned up. Parked string at 8532'. Up wt there 215K.;Serviced rig and topdrive. Installed new flow meter on topdrive.;PU singled in hole 32 joints CDS-40 (last of 169 DP) from 8532' to 9527'. MU topdrive on last stand, washed down to 9568' at 279 gpm, 60 rpm and ran into fill. Washed and reamed slowly to bottom at 9593'. Down wt 110K.;Cont drilling 6 1/8" hole from 9593' to 9697' 284 gpm 2809 psi SPP, 70 rpm on bottom tq 16.6k off bottom tq 17.4k, WOB 5-9k ROP 18-32 FPH, Max gas seen 447 units MW 9.9 ppg ECD 11.39, PUW 225k SOW 115k ROT 150k.;Cont drilling 6 1/8" hole from 9697' to 9836' 284 gpm 2834 psi SPP, 70 rpm on bottom tq 17.6k off bottom tq 17.k, WOB 5-9k ROP 18-32 FPH, Max gas seen 109 units MW 9.9 ppg ECD 11.38, PUW 250k SOW 112k ROT 151k Distance f/ plan 6.83' 4.73' Low 4.93' Left.;Hauled Solids to G&I 35 bbls Hauled to G&I Cumulative 412 bbls Hauled Fluid to G&I 110 bbls Hauled to G&I Cumulative 2507 bbls Hauled cement to G&I 0 bbls Cumulative Cement to G&I 38 bbls Daily Down Hole Losses 0 bbls Cumulative Losses 142 bbls Daily metal 0 lbs. Cumulative metal 241 lbs. 5/7/2022 Cont drilling 6 1/8" hole from 9836' to 9963', rot wob 2-6K, 281 gpm-2550 psi, 70 rpm-17,424 to 18,300 ft/lbs on bott torque, 15 to 40 ft/hr ROP, MW 9.9/vis 53, ECD's at 11.4 ppg, BGG 7 units, max gas 27 units. Pumped a 14 bbl NXS lube pill at 9900' (1 drum + 13 bbls mud).;Cont drilling 6 1/8" hole from 9963' to 10,087', rot wob 3-6K, 282 gpm-2695 psi, 50 rpm-17,886 to 18,900 ft/lbs on bott torque, 8 to 70 ft/hr ROP, MW 9.9+/vis 51, ECD's at 11.3 ppg, BGG 7 units, max gas 30 units. Pumped a 14 bbl NXS lube pill at 10,024' (1 drum + 13 bbls mud). Had to PU off bottom;twice due to rig blacked out (gen issues) up wt 265K with no pump or rotary. Received 4 1/2" shoe track and 6 drums BaraLube W-250. Baker liner hanger tools and our CDS-40 x JEBEAR drive sub loaded on Black Gold in Prudhoe at 15:30 hrs to head to our location.;Cont drilling 6 1/8" hole from 10,087' to 10,149' 280 gpm 2565 psi SPP 70 RPM on btm tq 18.5k off btm tq 19.5k, Max gas 15 units, MW 10ppg ECD 11.39, PUW 255k SOW117k ROT 157k, pumped lube pill tq dropped once out of bit but came right back, saver sub connection broke while making connection.;Re tighten and reinstall clamp, rack back stand of DP and adjust clamp, Drilling in Max tq, Decision made to make wiper trip to shoe.;POOH w/ pumps f/ 10149' to 9524' seen multiple over pulls of 30-40k worked through, BROOH f/ 9524' t/ 8774' working multiple tight spots and stalling top drive, continue pumping out of the hole to 8180' multiple 20-30k over pulls until able to pull clean with out over pulls, POOH on elevators.;f/ 8180' t/ 7484' no issues pulling into shoe.;Service rig and top drive, check oil on all gens, service draw works check brakes, inspect saver sub and recheck clamp for proper torque.;Pump EP Mud Lube pill f/ trucks, pump out side bit and slow circulation rate for lube casing contact time, rotate 30 rpm through out pumping pill around initial tq 11k after pill to surface 9.3k tq, shut down prep t/ RIH.;Hauled Solids to G&I 18 bbls Hauled to G&I Cumulative 430 bbls Hauled Fluid to G&I 132 bbls Hauled to G&I Cumulative 2639 bbls Hauled cement to G&I 0 bbls Cumulative Cement to G&I 38 bbls Daily Down Hole Losses 0 bbls Cumulative Losses 142 bbls Daily metal 0 lbs. Cumulative metal 241 lbs. Cont drilling 6 1/8" hole from 9285' to 9593'. p ;Cont drilling 6 1/8" hole from 9593' to 9697' Cont drilling 6 1/8" hole from 9836' to 9963', pq q ;Cont drilling 6 1/8" hole from 9697' to 9836' Drilling hole for 4-1/2" liner. -WCB q ;Cont drilling 6 1/8" hole from 9045' to 9285' Drilling hole for 4-1/2" liner. -WCB Drilling hole for 4-1/2" liner. Seeing multiple tight spots. -WCB q ;Cont drilling 6 1/8" hole from 9963' to 10,087', g g p jpgq ;POOH w/ pumps f/ 10149' to 9524' seen multiple over pulls of 30-40k worked through, BROOH f/ 9524' t/ 8774' working multiple tight spotspp pp p p g and stalling top drive, continue pumping out of the hole to 8180' multiple 20-30k over pulls until able to pull clean with out over pulls, g ;Resumed drilling 6 1/8" hole from 8504' to 8765', p y ;Cont drilling 6 1/8" hole from 8765' to 9045' g ;Cont drilling 6 1/8" hole from 10,087' to 10,149' 5/8/2022 TIH on elevators from 7484' to 8801' with no issue, dwn wt 115K. At 8801' we set down twice 15K in claystone. MU topdrive, filled pipe, washed and reamed down to 8860', worked same spot with no rotary or pump and was clean. Cont TIH and set down at 9536' twice 15K in tuffaceous sandstone.;MU topdrive, filled pipe, washed and reamed down to 9599', worked same spot with no rotary or pump and was clean. Cont TIH to 9665' and set down twice in large coal. MU topdrive, washed and reamed down to 9718'. worked through with no rotary or pump and was clean. TIH to 9750' and set down twice;15K in standstone, MU topdrive, washed and reamed to bottom at 10,149'. Washed and reamed everything at 279 gpm-30 rpm. Had a max of 270 units gas at bottoms up.;Resumed drilling 6 1/8" hole from 10,149' to 10,309'. Rot wob 2 to 6K, 278 gpm-2654 to 3000 psi, 50 rpm-17,598 to 20,170 ft/lbs on bott torque, 9 to 60 ft/hr ROP, MW 10.3/vis 50, ECD's at 11.5, BGG 7 units, max gas 79 units. Increasing MW from 10.0 to 10.4 while drilling. At 10,286' started;seeing excessive diff and pressure spikes. Added last drum of NXS lube to suction pit and worked pipe until lube exited bit. Notified Drilling Engineer, decision made to drill last 44' of stand down.;Cont drilling 6 1/8" hole from 10,309' to 10379' 278 gpm 2620 psi SPP 50 rpm 18.9k tq on bottom 19.8k tq off bottom, 10.4 ppg 11.62 ppg ECD, Max gas 20 units, PUW 245k SOW 120k ROT 164k WOB 2-4k Motor and tq holding steady with light weight ROP 5-30 FPH.;Cont drilling 6 1/8" hole from 10,379' to 10,452' 283 gpm 2665 psi SPP 50 rpm 19.3k tq on bottom 19.8k tq off bottom, 10.4 ppg 11.63 ppg ECD, Max gas 20 units, PUW 255k SOW 120k ROT 164k WOB 2-4k ROP 5-30 FPH Distance to Plan 15.13' .49' Low 15.12' Left.;Hauled Solids to G&I 27 bbls Hauled to G&I Cumulative 457 bbls Hauled Fluid to G&I 108 bbls Hauled to G&I Cumulative 2747 bbls Hauled cement to G&I 0 bbls Cumulative Cement to G&I 38 bbls Daily Down Hole Losses 0 bbls Cumulative Losses 142 bbls Daily metal 0 lbs. Cumulative metal 241 lbs. 5/9/2022 Cont drilling 6 1/8" hole from 10,452' to 10,461' md, 9964' tvd. rot wob 4-5K, 283 gpm-19,124 to 21,000 ft/lbs on bott torque, 5 to 21 ft/hr ROP, MW 10.4/vis 50, ECD's at 11.6 ppg, BGG 5 units, max gas 6 units. Called TD early due to excessive topdrive torque, diff and pump pressure spikes.;Pumped 20 bbl hi-vis nutplug sweep around at 282 gpm-2633 psi, 50 rpm-18,000 ft/lbs off bott torque on down stroke, could not rotate on upstroke. Up wt 270K pumping. No increase in cuttings at bottoms up, sweep back on time and no increase in cuttings. Obtained survey and SPR's.;Attempted to pump OOH pulling to 325K with no movement. Topdrive stalling when trying to break free. Third attempt broke loose on down stroke with topdrive torque. Had to work to break free next 5 stands. At 10,078' we were able to pump only and pull up hole with no issue. Cont pumping OOH working;tight spots at 9437' (claystone), 9048' (large coal) and 8975' (sandstone) seeing what appeared to be some packoff. Stopped at 8962' to CBU.;CBU at 282 gpm-2480 psi, 35 rpm-16,000 ft/lbs off bott torque. Slight increase in fine sand on shakers, very little coal. Shut down and flow checked, well static, dropped 2.83" hollow drift with wire.;Pulled two stands on elevators but we were swabbing. Attempted to pump OOH with no movement. Topdrive stalling, managed to work free by slack off to 70K and topdrive torque, had to fight next 6 stands getting broke free. At 8525' we were able to pump OOH with no issues. At 8403' could pull on;elevators up weight 230K. Pulled into 7" casing with no problem, stopped at 7090', just below where it starts building angle to CBU.;CBU at 282 gpm-2239 psi, 40 rpm. Had a good amount of fine sand at bottoms up, circulated until shakers cleaned up, Transferred EP Mudlube from dirty vac into dragon box, to use vac truck for cleaning layed down drill pipe.;Cont POOH from 7090' to 3308', turned elevators, LD DP t/ 738' Stand back HWDP, L/D Jars and flex collars, Break Bit 3-4 1/16 under gauge.;Slip and cut 95' of drilling line, Service rig.;Rig up to run 4.5'' Casing, R/U Weatherford casing equipment, Torque turn equipment and bring handling equipment to floor, bring cross overs and centralizers to floor.;Hauled Solids to G&I 24 bbls Hauled to G&I Cumulative 481 bbls Hauled Fluid to G&I 36 bbls Hauled to G&I Cumulative 2783 bbls Hauled cement to G&I 0 bbls Cumulative Cement to G&I 38 bbls Daily Down Hole Losses 0 bbls Cumulative Losses 142 bbls Daily metal 0 lbs. Cumulative metal 241 lbs. 5/10/2022 Cont RU Weatherford casing equipment and torque/turn system. Staged centralizers, MU TIW on CDS-40 x JFEBEAR crossover, RU fill up line. Held PJSM with rig crew and Weatherford crew.;Inspected shoe track joints internally, PU and MU shoe track, filled pipe and checked floats operationally (OK). PU singled in hole with total 76 jnts 4 1/2" L-80 12.6# JFEBEAR-HT liner to 3183’. Had to lay down 5 damaged joints due to operator error and equipment failures. Initially torqued to 9000;ft/lbs, reducing torques to 8000 ft/lbs, and finally 7000 ft/lbs to keep from damaging pipe. Applied no dope to connections. At 3183' up wt 52K, dwn wt 45K. Filled on the fly and top filled every 10 joints.;PU Baker HRD-E ZXP/Flex Lock V liner hanger assembly, MU 5” BTC x 4 1/2" JFEBEAR XO, installed LWP swivel with Type 1 Liner Wiper Plug and MU hanger assembly on stump. Mixed and poured palmix while RD Weatherford, MU 4 1/2" x 3 1/2" XO on bottom of a stand HWDP, MU stand and topdrive.;Checked crown saver, at 3269' circulated one string volume staging up to 177 gpm-156 psi, removed Weatherford tongs from rig floor.;Cont TIH slow (20 to 30 ft/min) with remaining 7 stands HWDP followed with 4 1/2" DP to float shoe depth of 6366' (liner hanger depth of 3153') MU topdrive and filling pipe every 15 stands. Top of 7" liner lap at 3336'. Set drill TQ T/7K.;MU topdrive and circulated staging pump up, CBU. GPM-206 SPP-513 psi.;Resumed RIH w/ 4.5" liner/hanger on 4.5" DP F/6366'-T/7424', keeping running speed around 20' per/min, eased through 7" liner top @ 3336' w/ 4.5" liner, no issues. Had calculated pipe displacement.;M/U TDS, filled pipe, staged up pump, CBU X2 @ 7424'. GPM-200 SPP-639 psi P/U- 136K S/O-93K. Attempted to obtain rotary parameters before exiting into open hole w/ no luck, TDS stalled out at 10 RPM.;Crew change, held PTSM. Cont. circ. second BU. Attempted to obtain rotary parameters before exiting into open hole w/ no luck, TDS stalled out at 10 RPM.;Cont. RIH w/ 4.5" liner/hanger on 4.5" DP F/7424'-T/8351', w/ no issues, keeping running speed around 20' per/min.;M/U TDS, filled pipe, staged up pump, CBU @ 8351' while reciprocating pipe +/- 10'. GPM-208 SPP-791 psi P/U-165K S/O-100K.;Cont. RIH on elevators F/8351'-T/8993', had 20K set down, attempted to work through on elevators w/ no luck, M/U TDS, washed down through large coal w/ pump at idle. Attempted to cont. RIH on elevators w/ no luck. Currently cont. to wash in hole @ 9605'. P/U-225K S/O-105K GPM-136 SPP-633 psi.;Hauled Solids to G&I 0 bbls Hauled to G&I Cumulative 481 bbls Hauled Fluid to G&I 0 bbls Hauled to G&I Cumulative 2783 bbls Hauled cement to G&I 0 bbls Cumulative Cement to G&I 38 bbls Daily Down Hole Losses 0 bbls Cumulative Losses 142 bbls Daily metal 0 lbs. Cumulative metal 241 lbs. g TIH to 9750' and set down twice;15K in standstone, MUp topdrive, washed and reamed to bottom at 10,149'. pp Topdrive stalling, managed to work free by slack off to 70K and topdrive torque, had to fight next 6 gppp p g stands getting broke free. At 8525' we were able to pump OOH with no issues. PU singled gpj in hole with total 76 jnts 4 1/2" L-80 12.6# JFEBEAR-HT liner to 3183’. ;Resumed drilling 6 1/8" hole from 10,149' to 10,309'. p g Top of 7" liner lap at 3336'. Running in 4-1/2" liner. -WCB p gpp y p ggp pp ;Resumed RIH w/ 4.5" liner/hanger on 4.5" DP F/6366'-T/7424', keeping running speed around 20' per/min, eased through 7" liner p p p top @ 3336' w/ 4.5" liner, no issues. ppg ppg ;Cont drilling 6 1/8" hole from Cont drilling 6 1/8" hole from 10,452' to 10,461' md, pp g y ppppg Topdrive stalling when trying to break free. Third attempt broke loose on down stroke with topdrive torque. Had to work to break free next 5 stands. pgyg p pq At 10,078' we were able to pump only and pull up hole with no issue. Cont pumping OOH working;tight spots at 9437' (claystone), 9048' (large coal) and 8975'pp y p p (sandstone) seeing what appeared to be some packoff. gp Called TD early due to excessive topdrive torque, Hole for 4-1/2" liner TD'd early at 10,461' MD. -WCB g 10,379' to 10,452' p ;Cont drilling 6 1/8" hole from 10,309' to 10379' Drilling hole for 4-1/2" liner. -WCB 5/11/2022 Cont TIH on stands DP with 4 1/2" liner, from 9605' to 10,430'. Washing down working through coals and fighting pack offs. At 10,430’ we set down, attempted to work back up hole with no movement, numerous times. Up wt 240K, dwn wt 115K. Working pump on and off fighting packoff. Parked string at;10,430’ having a tool joint at table allowing us to LD single joint and MU cement head. Called out cementers at 08:45.;Cont to work pump trying to establish constant circulation at 112 gpm-1100 to 1300 psi, staying below anchor set pressure of 200 psi. Parked string at 260K and worked pump, then at 160K. Eventually able to get 3.7 bpm-1230 psi with steady return flow. After crew change, shut down pump, Max gas 766.;LD single, MU cement head and plumbing, cont to circ at 132 gpm- 1204 psi while holding PJSM.;Halliburton pumped 3 bbls water to flush lines, then 5 bbls to fill lines. Shut in at Baker cement head and PT lines at 1100 psi low 4512 psi high. Lined up Baker cement head to Halliburton, pumped 30 bbls 11.5 ppg spacer at 3 bpm-1077 psi, followed with 54 bbls (130 sx) 12 ppg Type I II Lead cement;at 3 bpm, 1020 to 715 psi, followed with 25 bbls (115 sx) 15.3 ppg Type I II Tail cement at 3 bpm-550 psi. Added 2 pps LCM to lead cement. Baker released dart, Halliburton then displaced with 10.4 ppg 6% KCL mud at 3 bpm-640 ICP. 17 bbls into displacement caught pressure chasing cement. 94 bbls into;displacement saw dart latch wiper plug. With 10 bbls to go, reduced rate to 2 bpm-1470 psi and bumped plug/landing collar 141.5 bbls into displacement (calculated at 143.5 bbls). FCP 1470 psi. Halliburton increased to and held 2285 psi (815 over fcp) for 1 minute, then increased pressure to 2500 psi;for 1 minute. Slacked off on blocks from 200K to 80K, giving us a good indication hanger was set. Bled back 1 bbl to truck and floats held. CIP at 15:00 on 5-11-22. Lost 3.5 bbls throughout the job.;Applied 3737 psi and held 1 minute to shift HRD-E and release run tool. Bled off and PU to 210K three times, run tool not released. S/O to 80K and applied 4000 psi and held 5 minutes. Bled off, PU to 200K, lost weight, cont to PU at 175K, run tool released. PU 12’ to clear dogs from hanger top,;rotated at 30 rpm, 8432 ft/lbs torque, S/O and set down to 70K (55K applied) three times, to ensure weight transfer to set packer. Top of liner hanger at 7216.61’, top of landing collar at 10,342.54’. Closed upper rams, rig lined up on kill line and pressured up on annulus to 1447 psi and held for 5;minutes. Pressure holding, good indication HRDE ZXP liner top packer is set. Did not have any indication of shear at surface.;Bled off annulus pressure to 0 psi, and opened rams. LD Halliburton hardline, LD Baker cement head, MU topdrive. Pressured up to 500 psi on drill string and PU 9’ slowly. Once psi started dropping, rig started pumping and did one full circ at 430 gpm-1827 psi. Had trace of spacer to surface, no;cement. Shut down pump, racked back one stand, installed wiper ball in drill string, MU topdrive and pumped second circulation at 420 gpm-1693 psi.;POOH F/7216'-T/ surface, Inspected & B/D and L/D Baker running tool. P/U-170K S/O-106K Held kick while trip drill at 5317'. Started hauling of mud and cleaning pits.;Service rig- Greased crown, blocks, TDS, wash pipe, DWKS, brake linkage, drive shaft, and IR.;Johnny whacked the stack. Started B/O 10' & 5' off Baker cmt head and L/D.;Crew change, held PTSM. Finished B/O pups of Baker cmt head. Added oil to TDS gear box. Staged Baker polishing assy. on catwalk. Cont. hauling of mud & cleaning pits. Hauled in water and filled pits 9 & 10 to build 6% KCL brine (8.6 ppg).;M/U Baker polishing mill assy. as per Baker Rep. RIH out of the derrick F/surface-T/7191'. Eased through 7" liner top @ 3336' with out a bobble. Adjusted TDS drill TQ T/15K. Currently CBU. P/U-165K S/O-100K. GPM-216 SPP-665 psi. Changed MP #2 liner/swabs to 4.5" for displacement of brine.;Hauled Solids to G&I 35 bbls Hauled to G&I Cumulative 516 bbls Hauled Fluid to G&I 583 bbls Hauled to G&I Cumulative 3386 bbls Hauled cement to G&I 0 bbls Cumulative Cement to G&I 38 bbls Daily Down Hole Losses 0 bbls 5/12/2022 CBU at 7191’ and re-adjusted topdrive torque. Pumped at 176 gpm-560 psi.;Eased down and dressed 4 1/2" liner top and SBR as per Baker Rep three times. Liner top depth at 7218’ on this tally.;CBU at 284 gpm-960 psi then blew down topdrive, start building brine.;POOH LD and inspect polish mill. Brought in 2 7/8” workstring during trip, racked same and building inhibited brine in pits 9-10.;Clean rig floor, stage scraper BHA items, RU Weatherford, held PJSM.;MU 4 1/2" scraper assembly, 3 3/4" bit and float sub. PU single in hole with 2 7/8" PH-6 work string F/surface-T/3154'. M/U XO'S and 7" scraper back to CDS-40 DP. RIH w/ HWDP/DP F/3166' to top of 7" @ 3336', eased through TOL w/ 4.5" scraper w/ out a bobble. Cont. RIH w/ DP out of the derrick;F/3336'-T/6443', filling pipe 1500'. Finished building 50 bbl spacer and 600 bbls of corrosion inhibited 6% KCL brine w/ .5% of Baralube W 520. P/U-90K S/O-71K;Crew change, held PTSM. Cont. RIH w/ tapered scraper assy. F/6443', eased through top of 7" liner w/ the 7" scraper, seen 2-3K bobble while entering 7" liner. Resumed RIH F/6502' to just above top of 4.5" @ 7185'. P/U-100K S/O-75K;M/U TDS, filled pipe, staged up pump. CBU, GPM-272 SPP-2370 psi. P/U-117K S/O-87K;Cont. RIH F/7185', eased through liner top @ 7218', took weight at bottom of liner @ 7248', made multiple attempts to pass through staging set down weight up from 5- 12K before falling through. Cont. RIH F/7248'-T/8732', M/U TDS, broke circ. to make sure we could establish circ (ok).;Resumed RIH F/8732'-T/10183', set down 2K on cmt string, M/U TDS, broke circ. staged up pump. Washed down F/10183' to current depth of 10,216'. While running centrifuge to cut MW back before displacement. GPM-202 SPP-2593 psi P/U-183K S/O-105K MW-10.25 ppg;Hauled Solids to G&I 26 bbls Hauled to G&I Cumulative 542 bbls Hauled Fluid to G&I 289 bbls Hauled to G&I Cumulative 3675 bbls Hauled cement to G&I 0 bbls Cumulative Cement to G&I 38 bbls Daily Down Hole Losses 0 bbls Cumulative Losses 142 bbls Daily metal 0 lbs. Cumulative metal 241 lbs.;Updated/Notified BLM of up coming casing test and CBL at 12:09 pm on 5-12, and of upcoming MIT-T and MIT-IA at 20:45 pm on 5- 12. 48 hour notification to AOGCC of upcoming casing test and CBL at 20:53 pm on 5-12 p pp Had trace of spacer to surface, no;cement. pg pp g Pressure holding, good indication HRDE ZXP liner top packer is set. Parked string at;10,430’ Landed 4-1/2" liner. Cemented liner. Bumped plug @ 141.5 bbls (calc was 143.5 bbls). Set liner hanger. Set LTP. No cement seen at surface. -WCB ppg p pgp g With 10 bbls to go, reduced rate to 2 bpm-1470 psi and bumped plug/landing collar 141.5 bbls into displacement pppggppppggp (calculated at 143.5 bbls). FCP 1470 psi.Halliburton increased to and held 2285 psi (815 over fcp) for 1 minute, then increased pressure to 2500 psi;for 1()p p (p)p minute. Slacked off on blocks from 200K to 80K, giving us a good indication hanger was set. Bled back 1 bbl to truck and floats held. ;Eased down and dressed 4 1/2" liner top and SBR as per Baker Rep three times.jp Liner top depth at 7218’ on this tally. At 10,430’ we set down, attempted gggggp to work back up hole with no movement, numerous times. Up wt 240K, dwn wt 115K. Working pump on and off fighting packoff. g pp p Lined up Baker cement head to Halliburton, pumped 30 bbls 11.5 ppg spacer at 3 bpm-1077 psi, followed with 54 bbls (130 sx) 12 ppg Type I II pg p pp ppg p p p ()ppg Lead cement;at 3 bpm, 1020 to 715 psi, followed with 25 bbls (115 sx) 15.3 ppg Type I II Tail cement at 3 bpm-550 psi. Added 2 pps LCM to lead cem 5/13/2022 Cont to wash down with 3 .75" roller cone and 4.5" scraper from 10,216’ to 10,287’ seeing occasional cement stringers. At 10,287’ tagged up solid, cont to circ and work pipe making no hole. Running centrifuge while washing down, cutting MW as much as possible prior to displacement (10.2ppg). Down;weight 105K, up wt 183K. Circulating 5 bpm-2577 psi.;Held PJSM with CCI, Baroid and rig crew on displacement, Lined up pump #1 (5” liners) on 40 bbl hi-vis spacer followed with 10 bbls 8.6 ppg inhibited brine to flush pump, then switched to pump #2 (4.5” liners) at 4.7 bpm-2924 psi, increased to 5.2 bpm-2333 psi as brine rounded the corner and started;up the hole. Cleaned trip tank during circ, added brine to tank and flushed through hole fill pump and fill up line. RU mousehole and vac tri- pod on rig floor. CCI RU water weasel at pipe rack/catwalk and vac hoses. Shut down and flow checked well, static.;Held PJSM on flushing and cleaning pipe as we lay down. Racked 1st stand back, POOH from 10,224', up wt 207K, mouse holing singles, flushing with fresh water, insert wiper ball, vac ball out pin end, lay down joint, flush tube and box threads with water weasel, insert wiper ball soaked in;inhibitor, vac that through, blow dry threads and wipe with clean rags, thoroughly dope threads and install clean dry thread protectors. At 7237' at 18:00 hrs. Sent AOGCC notification for upcoming MIT-T and MIT-IA at 09:47 for 5-14 at 19:00 hrs.;Cont. POOH LD CDS-40 singles F/7237'-T/4396', cont. w/ pipe maintenance-flushing and doping pipe, hauling off fluids form pits, and cleaning tank bottom. Flushed out centrifuge/feed pump and blew down same. P/U-75K S/O-69K;Crew change, held PTSM. Cont. POOH L/D CDS-40 singles F/4396'-T/3655', cont. w/ pipe maintenance-flushing and doping pipe. RIH w/ remaining stds of 4.5" DP out of the derrick F/3655'-T/4271'. Gave WOTCO 2 hr. notice. Resumed POOH L/D CDS-40 DP singles F/4271'-T/3655'.;L/D HWDP singles F/3655'-T/3157'.;R/U WOTCO 2-7/8" handing equip. Installed shipping blocks in the centrifuge. Cont. w/ pit cleaning.;Currently performing rig service. Greasing blocks, crown, TDS, DWKS, IR, brake linkage, and drive shaft.;Hauled Solids to G&I 13 bbls Hauled to G&I Cumulative 555 bbls Hauled Fluid to G&I 737 bbls Hauled to G&I Cumulative 4412 bbls Hauled cement to G&I 0 bbls Cumulative Cement to G&I 38 bbls Daily Down Hole Losses 0 bbls Cumulative Losses 142 bbls Daily metal 0 lbs. Cumulative metal 241 lbs. 5/14/2022 Finish servicing rig and topdrive at 3149'.;Cont POOH LD 2 7/8" workstring and 4 1/2" scraper assembly, up wt 48K.;Spot Ak E-Line unit, RU same, MU 29.68' tool string for 4 1/2" CBL, max of 3" OD, start RIH. Crew cleaned up catwalk and piperack area, re-installed cellar grating, dressed air slips for 4 1/2" completion run, prepped test pump/chart recorder for upcoming casing test, loaded mud product on trailers;and staged on pad 1A, CCI loading mud dock rig mats to set on pad 1A. E-Line down to 8000' then tool lost power. Full stop tool working, any movement and tool power in/out. POOH and LD tool string.;Replaced gamma tool and tested tools, still having issues. Broke tool string down checking all connections, tools check out individually. Re-assembly tool string and working properly, PU to rig floor, still ok.;RIH with 29.86' tool string again to CBL 4 1/2" liner. Again at 8000' having telemetry issues, tool staying powered up. Cont RIH and tagged at 10,258' WLM. Pull up hole still experiencing telemetry issues. Notified Drilling Engineer, request made to POOH and swap to 7" log tool. POOH with e- line, LD;tool string. Re-configure tools for 7" liner logging.;RIH with e-line T/7250', log up hole to top of 7" liner at 3336'. (Total length of tool-24.05'). POOH L/D logging tools, R/D and release Ak E-Line.;R/U testing equip. Flooded lines and worked on purging out air. Cleaned out degasser vessel and changed oil in degasser compressor.;Crew change, held PTSM. Finished purging out air. Filled racks w/ 4.5" 12.6# JFEBEAR tubing.;Tested casing/liner T/4000 psi on chart for 30 min (ok). Pumped in 7 bbls and bled back 6.9 bbls.;R/D testing equip. P/U 4.5" testing jt. M/U test plug, pulled 9" wear ring. L/D test jt. R/U WOTCO's tubing handling equip.;Held PJSM on running tie back assy. Flash lighted and confirmed tie back seal assy. was clear. M/U 5.25" 18# locating tie back seal assembly, locator No-Go, coupling XO, and 9.75' pup jt. TQ JAM all connections to 7K.;Cont. RIH w/ 4.5" 12.6# JFEBEAR HT as per run tally F/21.40' to current depth 3332'.;Hauled Solids to G&I 6 bbls Hauled to G&I Cumulative 561 bbls Hauled Fluid to G&I 394 bbls Hauled to G&I Cumulative 4806 bbls Hauled cement to G&I 0 bbls Cumulative Cement to G&I 38 bbls Daily Down Hole Losses 0 bbls Cumulative Losses 142 bbls Daily metal 0 lbs. Cumulative metal 241 lbs. pgpyp max of 3" OD, start RIH. Crew cleaned up catwalk and piperack area, re-installed cellar grating, dressed air slips for 4 1/2" completionppp gg pp run, prepped test pump/chart recorder for upcoming casing test, loaded mud product on trailers;and staged on pad 1A, CCI loading mud dock rig mats to set on ppp p p p g g p g p gg pad 1A. E-Line down to 8000' then tool lost power. Full stop tool working, any movement and tool power in/out. POOH and LD tool string.;Replaced gamma tool pppgypgp g and tested tools, still having issues. Broke tool string down checking all connections, tools check out individually. Re-assembly tool string and working properly,g gg y yg gp PU to rig floor, still ok.;RIH with 29.86' tool string again to CBL 4 1/2" liner. Again at 8000' having telemetry issues, tool staying powered up. Cont RIH and g gg g g y ygp p tagged at 10,258' WLM. Pull up hole still experiencing telemetry issues. Notified Drilling Engineer, request made to POOH and swap to 7" log tool. POOH with e-gg line, LD;tool string. g g ;Tested casing/liner T/4000 psi on chartgp for 30 min (ok). gy pg Sent AOGCC notification for upcoming MIT-T and MIT-IA at gy p 09:47 for 5-14 at 19:00 hrs , RU same, MU 29.68' gg tool string for 4 1/2" CBL, g Re-configure tools for 7" liner logging.;RIH with e-line T/7250', log up hole to top of 7" liner at 3336'. (Total length of tool-24.05'). POOH L/D ppgy gg q pg g logging tools, R/D and release Ak E-Line. g ;Spot Ak E-Line unit,p , EL had trouble pulling CBL for 4-1/2 liner. EL pulled CBL for 7" liner (BCU-18RD_CBL_14May22_Main Pass) -WCB 5/15/2022 Cont PU single in hole with 4 1/2" tieback string from 3332' to 7172'. Down wt 85K. Ran total 171 joints.;PU MU 10' pup joint, installed bail extensions, MU CDS- 40 x JFEBEAR XO in top of single, PU and MU same. MU topdrive and broke circ at 2 bpm-40 psi. S/O 34.74' and saw psi increase to 370 psi as seals entered SBR. Shut down pump and opened bleeder. Cont S/O to 7216' and set down on no-go.;Pulled up hole and LD single. MU a second 10' pup. PU landing joint with hanger/pup and MU same. Drained BOP stack. Up wt 110K, dwn wt 90K. S/O 16.30' and landed hanger, putting seal assembly no-go 1.72' off seat. TOL at 7206'.;RD bail extensions, backed out LD landing joint, RILD's. Shut in boiler to let cool down.;RU test equipment, flood lines and purge air, with annulus open, blinds closed, pumped 2.73 bbls down kill line, through hanger and down tubing/4 1/2" liner to achieve 4190 psi. Held 30 min on chart, good test. Bled off 2.5 bbls. Opened blinds. RU on annulus and pumped 4.38 bbls to achieve 3840 psi.;Held 30 min on chart, good test. Bled off 4.38 bbls. RD test equipment. Wellhead Rep installed 2 way check in hanger. Build baraklean pill to flush through surface equipment.;Flush water and baraklean through suction lines, both mud pumps, mix pumps, gun lines, mudline, topdrive, kill and choke lines, choke manifold etc. Blow down everything. R/D and L/D WOTCO equip. bails, and subs/XO's from rig floor.;Opened doors on stack and removed rams. Pressure washed ram cavities and preserved. R/D flow line, bleeder line, and fill up line. Pulled flow riser. Removed chains & binders from stack. Removed flow box. N/D kill & choke lines, removed HCR's form stack. R/U BOP to lift cylinders on sub base,;N/D BOP's from well head. Lifted BOP's w/ lift cylinders on sub base to clear hanger neck and handed BOP's off to bridge cranes. Trolley BOP stack out of sub and positioned to be picked with crane. Cleaned, greased, and installed ring grove protectors on BOP's, HCR, and kill /choke liner flanges.;Cont. R/D in the pits, vacuumed out remaining fluid in bottom of pits, R/D plumbing to poor boy gas buster.;Brought dry hole tree into cellar area. Picked, set, and N/U tree w/ WHR onto well head. Tested hanger void T/250 psi Low -5 min and T/5000 psi -15 min (ok). B/O saver sub from TDS and pinned grabber box into the rig moving position.;Crew change, held PTSM and weekly safety meeting w/ rig crew. Pressure washed the derrick to rig floor. R/D gen #3, started R/D MP's. Power washed flow box, tongs, and subs/XO's from rig floor. R/D gas alarm lights & horns from pits and sun deck landing, removed gas alarm monitor, and cables.;R/D auxiliary fuel tank, pits 9 & 10, pit tarps, equalizer lines between pits, shakers, and Pason system. Blew down steam system. R/D pit & pump room cameras.;Hauled Solids to G&I 0 bbls Hauled to G&I Cumulative 561 bbls Hauled Fluid to G&I 170 bbls Hauled to G&I Cumulative 4976 bbls Hauled cement to G&I 0 bbls Cumulative Cement to G&I 38 bbls Daily Down Hole Losses 0 bbls Cumulative Losses 142 bbls Daily metal 0 lbs. Cumulative metal 241 lbs. 5/16/2022 Cont scrubbing and pressure washing derrick top to bottom, RD choke house, tore out cement silo and upright water tank, tore out service shacks, removed suction line from pump 1 to pits, removed jumper hose from pump 1 to sub, RD and boxed up all gas alarm equipment, stripped shakers of rubbers and;frames, changed oil and fuel filters on floor motor, RD steam line jumpers, removed stand pipe manifold, removed washpipe and checked end play on topdrive (in spec),;RD topdrive HPU skid, removed hooch over centrifuge, removed centrifuge and control panel, removed windwalls from cuttings box to allow removal of centrifuge feed pump, cleanout pipe rack sumps, cont pickle rig pumps, shipped out Sperry tools. Removed centrifuge feed pump and clam shell. Pressure;wash carrier. Install pump skid walls. Start RD topdrive.;R/U rigging to L/D TDS from rig floor. Held PJSM, L/D TDS & TQ bushing. R/D derrick board. Bridled up to scope derrick. disconnected derrick heater, and Pason depth tracker cord. Inspected derrick, un-dogged and scoped derrick to half mast. Un-pinned and L/D lower section of;TQ tube to catwalk. Removed turnbuckles from upper section of TQ tube and secured to derrick. Hung blocks, unspooled and cut 16 wraps of drill line (75'). Obtained serial numbers from brake bands and HCR's valves. Cont. changing gear oil in agitators to 220 vis and working through agitator EAM's.;Cont. prepping pits for move. Loaded out misc. equip. and hauling to staging pad. CCI rig support removed rig mats that were set in place over a section of road to prevent a washout during break up.;Final report for BCU-18RD. Released rig from BCU-18RD and moved to BRU mobe AFE @ 00:00 hrs.;Hauled Solids to G&I 0 bbls Hauled to G&I Cumulative 561 bbls Hauled Fluid to G&I 0 bbls Hauled to G&I Cumulative 4976 bbls Hauled cement to G&I 0 bbls Cumulative Cement to G&I 38 bbls Daily Down Hole Losses 0 bbls Cumulative Losses 142 bbls Daily metal 0 lbs. Cumulative metal 241 lbs. Cont PU single in hole with 4 1/2" tieback string from 3332' to 7172'. Down wt 85K. Ran total 171 joints. gj q p through hanger and down tubing/4 1/2" liner to achieve 4190 psi. Passing MIT-T and passing MIT-IA. -WCB ;Held 30 min on chart, good test. p 4-1/2" tubing installed. -WCB RU on annulus and pumped 4.38 bbls to achieve 3840 psi. gg g pg Held 30 min on chart, good test. p landed hanger, p pj S/O 34.74' and saw psi increase to 370 psi as seals entered SBR. Activity Date Ops Summary 5/19/2022 ARRIVE AT BEAVER CREEK. PJSM, INITIATE PERMIT. SPOT EQUIPMENT. RIG UP ELINE. MAKE UP TOOLS, OP CHECK. TEST RUNNING 1.69" CBL WITH THAT HAD PREVIOUS FAILURES IN THE FIELD, BUT SUCCESSFUL CHECKS PERFORMED IN SHOP. RUN 1: RIH W/ HEAD (5X2) / 5' WEIGHT / ROLLER CENT / 1.69" CBL / ROLLER CENT / GR-CCL / CENT, OAW = 160 LB, OAL = 31', MAX OD = 1.69".,LOB. TOOL BEGINNING TO HAVE ISSUES AT ~7400'. GR, CCL, AND CBL SIGNALS ERRATIC. TAG AT 10254'. LOG TO 9400'. POOH. POOH FROM 9400'. AT SURFACE. SWAB GR-CCL TOOL.,RUN 2: RIH W/ HEAD (5X2) / 5' WEIGHT / ROLLER CENT / 1.69" CBL / ROLLER CENT / GR-CCL / CENT, OAW = 160 LB, OAL = 31', MAX OD = 1.69". LOB. SAME TOOL ISSUES REPEATED. TAG 10254. LOG TO 9400'. POOH FROM 9400'. AT SURFACE. SWAB TO 2.75" CBL TOOLSTRING. RUN 3: RIH W/ HEAD (5X2) / CCL / CENT / 2.75" CBL / CENT / GR / CENT, OAW = 240 LB, OAL = 31', MAX OD = 3.125".,LOB. LOG REPEAT PASS OVER INTERVAL 10232' - 10020'. LOG MAIN PASS OVER INTERVAL 10234' - 7160'. ESTIMATED TOC AT 8570'. POOH. AT SURFACE. RIG DOWN ELINE. 5/21/2022 PTW and PJSM. MIRU Fox Energy CTU. Stage Cruz crane, open top tanks, and Fox Energy N2 unit. AOGCC waived witness of BOP test. Perform BOP test all elements except inner reel valve to 3900 psi. Place ~150 bbls of fresh water in open top tank from water well. Shut down for now. 5/22/2022 Fox Energy, Cruz, and Quadco on location. PJSM and PTW. MU MHA - 1.75" ext slip CTC, DFCV, Logan jars, Disco, Circ sub, 2-7/8" motor, pressure test MHA. MU 3.80" 5 bladed junk mill (OAL - 27.36'). Function test motor. MU lubricator to well and PT 300 psi / 3900 psi lubricator, stripper and inner reel valve. Open well and RIH taking coil displacement returns to OTT. Place an additional ~200 bbls of FW in OTT for milling.,Dry tag cement at 10,272' CTM. Come online with FW at 2 bpm at 4400 psi. Mill down to 10,377'. Made a short trip up above original tag depth. Milled at 10,377' for ~1 hour, pumping at max rate at 5500 psi. Unable to make any progress without more rate. Called and town approved stopping at current depth. Pump bottoms up and POOH. Vac truck started hauling return fluids to G&I. Total fluid pumped ~320 bbls of fresh water.,Break down MHA and mill. Mill showed some polishing around the outer rim of the mill, but nothing conclusive of what it may have been milling on at 10,377' CTM. Lay down lubricator and install night cap on BOPs. SDFN. 5/23/2022 Fox Energy and Cruz arrive on location. PTW and PJSM. MU BHA with 2-1/8" roll-on CTC, 2-1/2" DFCV, 2.5" JSN. (OAL - 6'). Stab on and RIH and tag TD 10,363' CTM. PUH to ~5000' and begin pumping nitrogen. Blowdown well to TD until no liquid returns at OTT. 171 bbls of fluid recovered. POOH. Pressured up well to 3550 psi. Rig down coiled tubing unit and nitrogen unit. Secure tree. Job Complete. 5/24/2022 AOGCC email approval to perforate after reviewing CBL logs 5/26/2022 AK E-line arrive and conduct JSA. Approve PTW. MIRU. Have high armor on cable, re-head. MU 2-7/8" x 19' gas gun, pick up lubricator/pump in sub/wireline valves. Bleed WHP from 3500 psi to 2900 psi.,PT lubricator to 250 psi low / 3900 psi high. Open well and RIH with Gun #1. Tag PBTD at 10,341' corrected depth. Send correlation data to RE/GEO. Add 3' to get on depth. No indication of guns firing at surface. POOH and NO shots fired. Thru wire was bare and shorted against gun barrel. Re-wire same gun.,RIH with 2-7/8" gas gun and send correlation data to RE/GEO. Subtract 1' to get on depth. Perforate Tyonek T12 from 10,289-10,308'. Initial pressure = 2745 psi, 5 min pressure = 2743 psi. Pressure remained unchanged. POOH. All shots fired and gun was dry.,Leave wireline valves on tree with night cap. Hand well over to production to bring online. SDFN. n (LAT/LONG): evation (RKB): API #: Well Name: Field: County/State: BCU-018RD Beaver Creek Unit Hilcorp Energy Company Composite Report , Alaska Contractor AFE #: AFE $: Job Name:221-00038 BCU-18RD Completion Spud Date: EL pulled CBL across 4-1/2" liner, seeing TOC at 8570' MD. -WCB () BEGINNING TO HAVE ISSUES AT ~7400'. GR, CCL, AND CBL SIGNALS ERRATIC. TAG AT 10254'. LOG TO 9400'. POOH. MIRU Fox Energy CTU. POOH. AT SURFACE. RIG DOWN ELINE. RIG UP ELINE. MAKE UP TOOLS, OP CHECK. TEST RUNNING 1.69" CBL WITH THAT HAD PREVIOUS FAILURES IN THE FIELD, gp Perforate Tyonek T12 from 10,289-10,308'. AOGCC email approval to perforate after reviewing CBL logs LOG MAIN PASS OVER INTERVAL 10234' - 7160'. ESTIMATED TOC AT 8570'. 5/27/2022 AK E-line and Fox N2 arrive on location. conduct JSA and approve PTW. Fox N2 MU hardline to flowline pump-in tee. AK E-line MU GPT toolstring with 4-1/2" CIBP. Stab onto well and PT to 250 psi low / 3900 psi high.,RIH and find fluid level at 9800' (correlated to perf gun pass). Monitor well for 1 hour and FL still at 9800'.,POOH with GPT/CIBP and cool down N2 pump. Pressure up tubing to 2000 psi with N2. Re-head E-line and MU 3-3/8" x 19' perf gun. GR/CCL to top shot = 9.4'.,RIH with 3-3/8" x 19' perf gun. Weight indicator change at ~ 9800' indicating possible water level. Send correlation data to RE/GEO and confirm on depth. Perforate Tyonek T12 from 10,289 - 10,308'. Initial pressure = 1976 psi, 5 min = 1973 psi.,POOH with perf gun. All shots fired gun was a little wet with small amount of sand. Secure well with night cap. SDFN. 5/28/2022 AK E-line arrive on location. conduct JSA and approve PTW. AK E-line MU GPT tool string Stab onto well and PT to 250 psi low / 3900 psi high. SITP 1925-psi.,Attempt to RIH with GPT tools. Unable to go down not enough weight bars. Lay down Tool string add two weight bars.,RIH and find fluid level at 10,020' (correlated to CBL Log). POOH with GPT Note: Issues with GPT tools, Lost tools @ 9600' shut down and had to reboot system. SITP: 1860-psi.,Lay down GPT Tools and make up 2-7/8" x 20' perf gun. Note: 6 SPF, loaded 22.7-gram REX charges GR/CCL to top shot = 8.3'.,Open Well SITP 1850-psi. RIH with 2-7/8"x 20' perf gun. Send correlation data to RE/GEO and confirm on depth. Perforate Tyonek T11 from 10,116'-10,136'. SITP 1819 psi, Initial perf pressure = 1816 psi, 5 min = 1816 psi, 10 min = 1816 psi, 15 min = 1816 psi. POOH with perf gun,Lay down T 11 guns. All shots fired; Gun was dry, small amount of wet sand in Bull plug Make up 2-7/8" x 20' perf gun. Note: 6 SPF, loaded 22.7-gram REX charges GR/CCL to top shot = 8.3'.,Open Well SITP 1795-psi. RIH with 2-7/8"x 20' perf gun. Send correlation data to RE/GEO and confirm on depth. Perforate Tyonek T 7B from 9797'-9817'. SITP 1795 psi, Initial perf pressure = 1797 psi, 5 min = 1797 psi, 10 min = 1797 psi, 15 min = 1797 psi. POOH with perf gun,Lay down T 7B guns. All shots fired; Gun was dry covered in a fine light grey sand powder, small amount of wet grey sand in Bull plug. Lay down Lubricator and crane. SDFN SITP 1785-psi. 5/29/2022 AK E-line arrive on location. conduct JSA and approve PTW. AK E-line MU GPT tool string Stab onto well and PT to 250 psi low / 3900 psi high. SITP 1768-psi.,RIH GPT and find fluid level at 10,145' (correlated to CBL Log). POOH with GPT SITP: 1756-psi.,Lay down GPT Tools and make up 2-7/8" x 20' perf gun. Note: 6 SPF, loaded 22.7-gram REX charges GR/CCL to top shot = 8.3'.,Open Well SITP 1756-psi. RIH with 2-7/8"x 20' perf gun. Send correlation data to RE/GEO and confirm on depth. Perforate Tyonek T 7A from 9738'-9758'. SITP 1756 psi, Initial perf pressure = 1758 psi, 5 min = 1759' psi, 10 min = 1759 psi, 15 min = 1759 psi. POOH with perf gun,Lay down T 7A guns. All shots fired; Gun was covered in Grease, Dry gun debris in Bull plug Make up GPT tools,RIH GPT and find fluid level at 10,090' (correlated to CBL Log). POOH with GPT SITP: 1754-psi.,Lay down GPT Tools and make up 2-7/8" x 8' perf gun. Note: 6 SPF, loaded 22.7-gram REX charges GR/CCL to top shot = 8.9'.,Open Well SITP 1744-psi. RIH with 2-7/8"x 8' perf gun. Send correlation data to RE/GEO and confirm on depth. Perforate Tyonek T 6 from 9567'-9575'. SITP 1744 psi, Initial perf pressure = 1745 psi, 5 min = 1744 psi, 10 min = 1742 psi, 15 min = 1740 psi. POOH with perf gun,Lay down T 6 guns. All shots fired; Gun was covered in Honey oil. Dry gun debris in Bull plug SITP 1695-psi. Lay down lubricator and crane SDFN 5/30/2022 SITP 1150-psi. Service E-Line equipment, Re-head for GPT run in the morning. Open Well to flowline. Perforate Tyonek T11 from 10,116'-10,136'. Perforate Tyonek T 7A from 9738'-9758'. Perforate Tyonek T12 from 10,289 - 10,308'. Perforate Tyonek T 6 from 9567'-9575'. Perforate Tyonek T 7B from 9797'-9817'. 5/31/2022 AK E-line arrive on location. conduct JSA and approve PTW. AK E-line MU GPT tool string Stab onto well and PT to 250 psi low / 3900 psi high. SITP 650-psi. Bleed tubing pressure down from 650-psi to 250-PSI and shut in,RIH GPT and find fluid level at 9530' (correlated to CBL Log). POOH with GPT SITP: 605-psi.,Lay down GPT Tools and make up 2-7/8" x 13' perf gun. Note: 6 SPF, loaded 22.7-gram REX charges GR/CCL to top shot = 9',Open Well SITP 660-psi. RIH with 2-7/8"x 13' perf gun. Send correlation data to RE/GEO and confirm on depth. Perforate Tyonek T 4 lower from 9380'-9393'. Pressure up tubing with N2 to 2190=psi and monitor. 5 min 2128-psi, 10 min 2072-psi, 15 min 2020-psi and falling Correlate and perf: SITP 1877-psi, Initial perf pressure = 1880-psi, 5 min = 1880 psi, 10 min = 1879 psi, 15 min = 1875 psi. POOH with perf gun,Lay down Lower T4 guns, all shots fired; Gun was covered in Honey oil, Dry gun debris in Bull plug make up 2-7/8" x 10' perf gun. Note: 6 SPF, loaded 22.7-gram REX charges GR/CCL to top shot = 8.3',Open Well SITP 1873-psi. RIH with 2-7/8"x 10' perf gun. Send correlation data to RE/GEO and confirm on depth. Perforate Tyonek T 4 upper from 9337'-9347'. SITP 1875 psi, Initial perf pressure = 1877 psi, 5 min = 1877 psi, 10 min = 1877 psi, 15 min = 1877 psi. POOH with perf gun,Lay down upper T4 guns, all shots fired; Gun was covered in Honey oil, Dry gun debris in Bull plug Lay down tools, lubricator and crane. SDFN turn well over to production personnel for flow back. SITP 1870-psi. 6/1/2022 AK E-line arrive on location. conduct JSA and approve PTW. AK E-line MU GPT tool string Stab onto well and PT to 250 psi low / 3900 psi high. SITP 1043-psi.,RIH GPT and find fluid level at 8994' (Correlated to CBL Log). POOH with GPT SITP:1043-psi,Lay down GPT Tools and make up 2-7/8" x 12' perf gun. Note: 6 SPF, loaded 22.7-gram REX charges GR/CCL to top shot = 10.1',Open Well SITP 1039-psi. RIH with 2-7/8"x 12' perf gun. Send correlation data to RE/GEO and confirm on depth. Perforate Tyonek T 2 from 9230'-9242'. Pressure up tubing with N2 to 2315=psi and holding Correlate and perf: SITP 2296-psi, Initial perf pressure = 2296-psi, 5 min = 2296 psi, 10 min = 2295 psi, 15 min = 2295 psi. POOH with perf gun,SITP 2280-psi. Lay down T2 guns, all shots fired; Gun was covered in Honey oil, Dry gun debris in Bull plug make up 2-7/8" x 5' perf gun. Note: 6 SPF, loaded 22.7-gram REX charges GR/CCL to top shot = 14.1',Open Well SITP 2257-psi. RIH with 2-7/8"x 5' perf gun. Send correlation data to RE/GEO and confirm on depth. Perforate Upper Tyonek T 0 from 9148'-9153'. Correlate and perf: SITP 2268 psi, Initial perf pressure = 2268 psi, 5 min = 2268 psi, 10 min = 2267 psi, 15 min = 2266 psi. POOH with perf gun,SITP 2280-psi. Lay down Upper T0 guns, all shots fired; Gun was covered in Honey oil, Dry gun debris in Bull plug Lay down lubricator and crane Secure well SDFN. 6/7/2022 Yellowjacket EL arrive at facility, PTW and PJSM. Rig up on well. MU GPT and WRP. PT to 250 psi / 3900 psi. RIH. At 2000' decided to POOH and drop WRP so that we are not running it across open perfs. Drop WRP and RIH with GPT (1-11/16" max OD, bullnose on bottom, OAL 16'). Set down at liner lap at 7285'. Worked toolstring, made it through on 10th attempt. RIH and tag at 10,134'. Log from tag to 9000'. POOH.,MU and RIH with 4-1/2" WRP (3.75" OD). FTP - 75 psi. Shut in well. Cool down N2 pump. PT to 250 psi and 4000 psi. Bring on N2 at 1500 scfm, increase to 2000 scfm. SITP 2500, 3900, 4225 psi. FL at 7450'. Bleed SITP to 2800 psi so that EL can safely POOH. Install night cap. SDFN. Fox energy N2 will return later tonight to pump up SITP to 4800 psi. 6/8/2022 YellowJacket EL arrive at facility, PTW and PJSM. MU GPT and WRP. PT to 250 psi low / 3900 psi high. RIH and pass through liner hanger without any issues. Log down and find Fluid Level = 8335'.,Log down to plug setting depth and log uphole to find fluid level. Fluid level = 8370'. Fluid level depressed downhole 35' after 2 hours. Bottomhole pressure = 5140 psi.,Send correlation data to RE/GEO and confirm on depth. Set WRP at 9098'. Set down to confirm set. POOH. RDMO YellowJacket E-line.,Bleed down tubing pressure to 500 psi. Leave shut-in for night. 6/9/2022 bled well down after WRP set. Stared at 522psi, and built to 527psi after 3 hrs. Flat for 8 hrs since then,SLB coiled tubing and Cruz arrive at facility, PJSM and PTW. Spot 1.75" coiled tubing reel, coil equipment and MU hydraulic hoses to injector and BOPs.,Function test BOP rams. Test BOPE to 250 psi low/3900 psi high. Jim Regg with AOGCC waived witness on 08:19 on 6/9/22 via email.,Pick up gooseneck and install on injector. Stab 1.75" coil into injector chains. MU BOP's on top of tree. Install night cap and SDFN. 6/10/2022 SLB coil and cruz crane arrive at facility. JSA and PTW. MU 1.75" x 6' stinger, 1.90" XO, and 2.0" big hole nozzle. PT lubricator out to choke skid to 250 psi low/3900 psi high.,RIH without check valves for reverse cleanout with N2. Online with N2 pump down backside at 8200' at 1500 scfm. RIH to 9000' and appears nozzle plugged off. POOH to 8000' and regain returns at surface. Continue to pump at 1500 scfm, WHP = 1530 psi, CTP = 400 psi. RIH and tag WRP at 9055' ctmd. POOH and recover ~ 10.5 bbls of 11.1 bbls expected.,Pressure up tubing to 3000 psi with N2. Leave well shut in.,RDMO. At 2000' decided to POOH and drop WRP j y so that we are not running it across open perfs. Perforate Upper Tyonek T 0 from 9148'-9153'. Set WRP at 9098'. Perforate Tyonek T 4 upper from 9337'-9347'. Perforate Tyonek T 4 lower from 9380'-9393'. Perforate Tyonek T 2 from 9230'-9242'. 6/11/2022 Yellow Jacket E-line arrive at facility. Hold PJSM and approve PTW. MIRU Equipment. MU two 2-7/8" x 9' guns with switch. 1st gun from CCL to top shot = 21.0'. 2nd gun from CCL to top shot = 9.5'. PT lubricator to 250 psi low/3900 psi high.,Open well and RIH. Tubing pressure = 2925 psi. Send correlation data to RE/GEO and confirm on depth. Bleed tubing pressure down to 2600 psi. Perforate Bel 33 from 8995-9004' Initial pressure = 2612 psi 5 min= 2616 psi, 10 min = 2618 psi, 15 min = 2617 psi.,Perforate Bel 32 from 8840-8849' Initial pressure = 2601 psi 5 min= 2606 psi, 10 min = 2607 psi, 15 min = 2607 psi.,POOH and laydown guns #1 and #2. All shots fired, bull plug was wet. MU & RIH with three 2-7/8" guns with switches. Gun #3 is 6' long; CCL to top shot = 24.5'. Gun #4 is 6' long; CCL to top shot = 17.0'. Gun #5 is 5' long; CCL to top shot = 10.5'. Send correlation data to RE/GEO. Add 2' to get on depth to open hole log.,Perforate Bel 31 from 8812-8818'. Initial pressure = 2593 psi; 5 min = 2592 psi; 10 min = 2592 psi Perforate Bel 30 from 8775-8781'. Initial pressure = 2592 psi; 5 min = 2592 psi; 10 min = 2592 psi Perforate Bel 30 from 8740-8745'. Initial pressure = 2592 psi; 5 min = 2592 psi; 10 min = 2592 psi,POOH and laydown guns 3,4, and 5. All shots fired. Bull Plug is dry. Install night cap on wireline valves. SDFN. 6/12/2022 YellowJacket E-line arrive at facility and hold PJSM and approve PTW. MU 1-11/16" GPT Toolstring and RIH. Tubing pressure = 39 psi. Fluid level = 8510' Tag at 8910'. POOH.,Cool down N2 unit and pressure up tubing to 1500 psi with N2.,MU & RIH with 2-7/8" switch guns for Run #1. Perforate following: Bel 29 8653-8659' Bel 29 8643-8648' Bel 29 8625-8635' Initial pressure = 1469 psi, 5, 10, and 15 min = 1477 psi.,POOH and get stuck at liner hanger. GR/CCL depth = 7217'. Liner hanger from 7200-7290'. Unable to pull out of weak point. Pull max with wire of 5k lbs. Continue to work wire, eventually pull out of weak point. POOH.,RDMO *** Left spent 2-7/8" perf gun BHA downhole at 7217'. OAL = 39.0' *** 6/13/2022 Spot in and Rig up Slickline with 50' of 4 1/2" lub to cover fish P/T Lub and WLV 2000 PSI pass RIH/w 1 3/8" JDC /w 3.5" Bell Guide to 8800' SLM Set down w/t fall to 8813' SLM w/t fall to 8819' SLM w/t can fall but no spangs POOH on Pooh massive weight swings from 500lbs to 1100 lbs to 5150' SLM OOH/w tool not sheared Order Roller Boogies,Standby for Roller boogies on Arrival Make up New Tool String Consisting of 1 3/4" RS 3" Roller, 5' Stem, KJ 5' Stem, 3" Roller, 3' Stem , KJ, 3" Roller, OJ , SJ 3" Roller RIH/w 1 3/8" JDC /w 3.5" Bell Guide to 8816' SLM w/t to deepest depth of 8823' SLM multiple attemps to latch with set downs all over the place at 8800', 8807', 8810', 8820' SLM appears unable to latch POOH OOH/w pin intact no marks on tool,RIH/w 3.5" LIB to 8800' SLM w/t fall to 8823' SLM w/t POOH OOH/w Impression of clean fishing neck RIH/w 4 1/2" GR/w Baitsub/w Series 20 Overshot (1 3/8" Grapple) to 8823' SLM w/t multiple jar licks come free with 700lbs overpull to 8750' slm weight started dropping off to 250lbs over pickup weight POOH with occasional weight swings up to 450 over looks like tools moveing freely around 6100',continue to surface OOH/w Bait sub and Grapple - contact PWL supervisor all demensions on Ropesocket and latching tools correct possible sand Obstruction around fishing neck check pin on Gr and Prep to Rerun,RIH/w Same to Same w/t Latch w/t Pooh with max overpull at 30fpm start out of hole slow until cooling fan breaks at 20:00 stop and let Cool (production brought up a frostfighter put fan on hydraulics to help cool- continue out of hole at 21:00 still pulling heavy at slow rate of 30 to 70 fpm at 4850' SLM pickup speed and lose a lot of the extra weight.,POOH To surface with 500 additional pounds vs pickup weights OOH with eline fish. rig down fish RDMO 6/16/2022 RIG UP W/L - PT LUB 150/1500 - GOOD RIH W/ 3" X 6' DD BAILER TO 8868'KB WT TO 8872'KB - SPANGS NOT VISIBLE - 1200 LBS PICK UP WEIGHT - POOH - OOH W/ SAND AND SOUPY MUD RIH W/ 3.75" BLIND BOX TO 6939'KB TAG FLUID - POOH - OOH W/ TOOLS COVERED IN MUD AND ELINE GREASE RIH W/ 3" X 6' FLUID SAMPLE BAILER TO 7000'KB - RETRIEVE FLUID SAMPLE RIG DOWN SL 6/18/2022 Yellowjacket Eline arrive at facility, PTW and PJSM. Rig up on well. PT to 250 psi / 3900 psi. MU GPT and 2" fluid sample bailer (OAL - 23.5'). RIH. Fluid level at 7420'. RIH and tag fill at 8800'. POOH. Collect fluid sample. Install night cap and SDFN. 6/19/2022 Yellowjacket EL arrive at facility. PTW and PJSM. Remove nightcap and fire up equipment. SITP at 1850 psi. MU 6' and 5' 2-7/8" guns. Arm and RIH. Correlate, send to town, on depth. Perforate the Beluga 29 from 8653'-8659'. Wait 5 min. Perforate the Beluga 29 from 8643'-8648'. POOH. All shots fired, gun was wet, muddy water in bullplug. Pressure data -initial - 1892 psi, 5 min - 1893, 10 min - 1893, 15 min - 1894 psi.,MU 10' 2-7/8" gun. Arm and RIH. Correlate, send to town, on depth. Perforate from 8625'-8635'. POOH. Lay down gun, all shots fired. Gun was wet. Install tree cap. Pressure data - initial - 1916 psi, 5 min - 1917 psi, 10 min - 1917 psi, 15 min - 1917 psi. RDMO. 7/6/2022 PJMSM, Permit, Discuss daily JSA,MIRU Fox energy 1-3/4" CTU with related equipment,Test BOP's and related equipment to 250-psi low and 3900-psi high.,Load supply tank. Troubleshoot HAK batch mixer starting system. Call out back up mix tank from rig tenders. pqp p Perforate the Beluga 29 from 8643'-8648'. pg Perforate from 8625'-8635' p Perforate Bel 30 from 8775-8781' gp Perforate Bel 33 from 8995-9004' Perforate following:g Bel 29 8653-8659' Bel 29 8643-8648' Bel 29 8625-8635' ,Perforate Bel 31 from 8812-8818' Perforate Bel 30 from 8740-8745'. ,Perforate Bel 32 from 8840-8849' y g Perforate the Beluga 29 from 8653'-8659'. 7/7/2022 Fox Coil, Cruz arrive at office. Hold PJSM and approve PTW. Fill supply tank with water. Finish RU. Wait on mixing unit to arrive from Rig Tender.,PU lubricator, MU CTC, 2.13" checks, 2.13" rotating JSN.. Mix 400 bbls of 6% KCl water.,Load coil with 6% KCl. PT lubricator to 250 psi low / 3900 psi high. Open well. Tubing pressure = 2050 psi. RIH while bleeding tubing pressure down to 400 psi through production.,Fluid pack well with 6% KCl and get returns to surface. Tag at 8856' ctmd. Hard tag. Set down 8k and jet for 20 minutes. Pump rate = 1.75 bpm. CTP = 3680 psi. WHP = 400 psi.,Coil moving downhole again. Tag at 8897' ctmd. Unable to get deeper. Set down 9.5k lbs. Pump 10 bbl gel pill. Pump rate = 1.75 bpm. CTP = 3680 psi. CTP increase to 4800 psi with gel pill. WHP = 100 to 400 psi.,POOH chasing gel pill to surface. Choke plugged several times with debris while chasing pill out of well. At surface. Close in swab. Pop off and set down injector. Secure well with night cap on BOPs. SDFN. 7/8/2022 Fox coil and Cruz crane arrive at office. Conduct JSA and approve PTW. Transfer used 6% KCl from return tank to supply tank. Haul fresh water and mix 6% KCl and add to supply tank.,MU dual checks, weight bar, and 1.75" downjet nozzle. PT lubricator and open well. Wellhead pressure = 0 psi. RIH and park coil at 8500' while continue to mix 6% KCl.,RIH and tag at 8897' ctmd. Hard tag and did not move downward. Pump rate = 2 bpm, ctp = 3300 psi, whp = 70 psi. Set down -16k. Attempt to RIH and tag at different speeds up to 75 ft/min. Overpull 7k when picking up off obstruction.,POOH pumping minimal rate to keep the hole full of 6% KCl.,Laydown BHA and set injector down. Small indention on bottom of nozzle. Install night cap on BOPs. 7/9/2022 Pollard Slickline arrive at facility. Hold PJSM and approve PTW. Spot equipment and RU 0.160" wire. MU 3.75" LIB and PT lubricator to 3500 psi.,RIH and tag at 8922' slmd. POOH. LIB indicated fishing neck of WRP.,MU & RIH with yellowjacket 4.5" WRP pulling tool. Unable to latch WRP. POOH.,Pollard modify 3" pump bailer at shop and bring to location. MU 3" bailer with 3.5" OD on bottom. Tag top of WRP and bail. POOH and recover ~ 6 small rubber pieces w/ minimal sand.,RIH with YellowJacket 4.5" WRP pulling tool. Latch WRP at 8922' slmd and shear off. WRP did not move up or down. No indication of equalizing. POOH.,MU & RIH with 4" GS fishing toolstring. Latch G profile and start jarring up. Pull up to 3600# and oil jars firing. Jar 38 times then shear down to release. POOH.,RDMO. 7/10/2022 AK E-line arrive and hold PJSM. Approve PTW. MIRU equipment. MU GR/CCL and CIBP. PT lubricator to 250 psi / 3900 psi.,RIH with 3.75" CIBP. GR/CCL to bottom of CIBP = 13.7'. Tag at 8852' + 13.7' = 8865.7' (uncorrected). Send correlation data to RE/GEO. Add 2' to get on depth. Corrected tag depth of 8867.7',Tag with plug and pick up to get weight back. Set top of plug at 8865'. POOH.,Load cement bailer with 3.2 gallons of cement to place 5' of cement on top of plug. RIH and tag CIBP. PU and dump cement. Top of cement = 8860'. POOH.,Laydown toolstring and lubricator. Remove wireline valves and secure well with coil night cap. RD. 7/12/2022 Fox coil arrive at office. Hold PJSM and approve PTW. MU coil checks, wt bar and JSN. PT lubricator to 250/3900 psi.,Open well and RIH. Tag PBTD at 8885' ctmd. Circulate around 6% KCl to ensure well is fluid packed. Pump down coil with choke closed.,No injectivity into well. Pressure increases to 3250 psi without injectivity. Linear pressure build at ~0.7bpm the whole time. Took 2mins and 20 seconds to get to 3250psi. Shut down pump and monitor pressure. 0 min = 3250 psi WHP 5 min = 2795 psi WHP 10 min = 2535 psi WHP 15 min = 2345 psi WHP,Bleed WHP down to 1000 psi and monitor pressure. 0 min = 1040 psi WHP 5 min = 1000 psi WHP 10 min = 936 psi WHP 15 min = 881 psi WHP,Open choke and circulate 18 bbls of Methanol down coiled tubing to nozzle. Lay in Methanol from PBTD to 7700'. Stop coil and close choke.,Inject 3.5 bbls of methanol into perforations. Starting WHP = 0 psi, ending WHP = 3120 psi.,After monitoring pressure for 1 hr, WHP = 1650 psi. Inject 1.2 bbls of methanol into perfs. Starting WHP = 1650 psi, ending WHP = 3223 psi.,Monitor pressure for 45 minutes, whp = 1920 psi. Inject 1 bbl of methanol into perfs. Starting WHP = 1920 psi, ending WHP = 3160 psi. Total of 5.7 bbls of Methanol pumping into perfs.,Cool down N2 and displace 6% KCl from wellbore. Trap 3000 psi on surface. Wellbore volume and coil volume minus displacement = 144 bbls. Recover 132 bbls.,RDMO 7/13/2022 AK E-line arrive at office. Hold PJSM and approve PTW. MIRU.,Re-head w/ 4-2 wire weak point. MU wt bars x 2, CCL, 3-3/8" x 10' (9' loaded) perf gun. MU lubricator to tree.,PT lubricator to 250 psi low / 3900 psi high. Open well and RIH. WHP = 3089 psi. Tag at 8842' + 13' (CCL to bottom gun) = 8855' (uncorrected). Send correlation data to RE/GEO. On depth.,Bleed pressure down from 3089 psi to 202 psi.,Perforate Bel 32 zone from 8840 - 8849' Initial press = 202 psi 5,10,15 min pressures = 202 psi. POOH. All shots fired. Bull plug a little wet.,RDMO 7/16/2022 AK EL arrive at facility. PTW and PJSM. Spot equipment and rig up on well. PT to 250 psi / 3900 psi. RIH with GPT tool (22'OAL, 2" OD). Fluid level at 7030'. Tagged at 8858'. POOH. Needed firing head sub from AKEL shop.,MU 2' 2-7/8" 6 spf 60 deg gun. Arm and RIH. Correlate, send to town, on depth. Perforate the Bel29L from 8690'-8692'. POOH. Pressure increased from 166 psi to 168 psi in 15 min. All shots fired. gun was wet.,MU 20' 3-3/8" gun. Arm and RIH. Correlate, send to town, on depth. Perforate the Bel29L from 8687'-8707'. POOH. Pressure increased from 175 to 177 in 15 min. All shots fired, gun was wet. Secure tree. RDMO. 7/21/2022 PJSM and PTW SITP 1220psi,R/U AK E-line and Fox N2 units M/U GPT tool and weight bars, place lubricator and WL valves on the well.,Pressure test lubricator to 250psi/3900psi - Test good Pressure test Fox N2 unit and lines to 250psi/3900psi - Test good,RIH w/ GPT. Fluid level at 6,510' Pressure up with N2 to 2,100psi - Fluid level at 6,590' after 30min Pressure up with N2 to 3,200psi - Fluid level at 6,650' after 30min Pressure up with N2 to 3,900psi - Fluid level at 6,730' after 30min, injecting slow ~120ft/hr POOH with GPT,M/U 3.5" Cement bailer, CCL, and weight bar. RIH to 8,860ft and tag CIBP P/U and dump 15.5ft of cement on CIBP. POOH,M/U 3.5" Cement bailer, CCL, and weight bars. Pressure dropped to 3400psi, re-pressurize well to 3,900psi RIH to 8,829ft and dump 15.5ft of cement. Calc TOC 8,829' Tools detained at 8,829ft,Work tools up in 100lb increments with no luck. Work up to 3200lbs (rope socket tied at 3321lbs) R/U open top diffuser tank and bleed well to 550psi Work tools up to 3600lbs and pull out of rope socket. POOH, All E-line recovered Fish left from 8,785-8,829ft (35ft 3.5"OD cement bailer, 2ft CCL, 7ft 2" weight bar),Lay down lubricator Secure well and SDFN 7/22/2022 PJSM and PTW SITP 590psi,R/U Fox N2 unit. Pressure test lines to 250psi/4600psi Pressure up well to 4500psi. SD for 1hr - Lost 100psi. Fluid pushing away slowly. Pressure well back up to 4500psi.,Secure well and SDFN. 7/23/2022 PJSM and PTW SITP 4090psi - Lost 410psi over 12hrs Pressure test Fox N2 to 250psi/4600psi RE-pressurize well to 4500psi Secure well RD Fox N2,SITP 4300psi @ 17:00hrs 7/24/2022 PJSM and PTW R/U AK-Eline SITP 3998psi,Pressure test lubricator to 250psi/4100psi - Test good M/U Weight bars, CCL, and GPT tool. Try to RIH but tools will not fall with 4000psi of pressure M/U 3.125" OD weight bar, CCL and GPT. RIH. Fluid level at 8,200ft and falling at 15ft/hr. POOH,M/U and RIH with weight bar, CCL and 3.75" OD junk basket gauge ring. to 8630Ft, no issues. POOH Fluid level at 8,256ft,Secure well and SDFN Final SITP 3890psi @ 1530hrs 7/26/2022 PJSM and PTW SITP 3,416psi R/U AK E-line,M/U and RIH w/ weight bar, CCL and GPT tool Fluid level below 8,650ft - POOH,M/U and RIH with weight bar, CCL, and 4.5" (3.71"OD) CIBP (CCL to CIBP 14.5ft) Gamma stopped working at 6,000, POOH, and replace Gamma. Run back in hole Pull log and send to town, on depth. Set CIBP at 8,620ft. POOH,Bleed down well from 3,266psi to 2,000psi. M/U weight bars, CCL, and 3.0"OD cement dump bailer. RIH and tag plug at 8,620ft. Pick up and dump 13.5ft of cement on CIBP. POOH RIH and dump 13.5ft of cement on CIBP. POOH RIH and dump 10 ft of cement on CIBP. POOH TOC at 8,583ft,Lay down lubricator. Secure well and SDFN 7/27/2022 PJSM and PTW SITP 2000psi R/U AK E-line and bleed well to 200psi,M/U and RIH with gun gamma and 12ft 2-7/8", 6SPF, 15g Geodynamics gun (CCL to top shot 12.3') Pull correlation pass and send to town - on depth.,Pull into position and perforate Beluga 28 @ 11:15hrs from 8,504-8,516'. POOH, gun pulled heavy off bottom gun packed with dry gray sand, no water 0min - 204psi 5min - 204psi 10min - 205psi 15min - 205psi,M/U and RIH with gun gamma and 8ft 2-7/8", 6SPF, 15g Geodynamics gun (CCL to top shot 12.3') Had to work the gun one time lightly to get it down Pull correlation pass and send to town - on depth.,Pull into position and perforate Beluga 28 @ 13:34hrs from 8,483-8,491'. POOH, gun pulled heavy off bottom gun packed with dry gray sand, no water 0min - 199psi 5min - 200psi 10min - 200psi 15min - 200psi,M/U and RIH with gun gamma and 10ft 2-7/8", 6SPF, 15g Geodynamics gun (CCL to top shot 10.5') Pull correlation pass and send to town - on depth.,Pull into position and perforate Beluga 27 @ 15:25hrs from 8,414-8,424'. POOH, gun pulled heavy off bottom gun packed with dry gray sand, no water 0min - 200psi 5min - 200psi 10min - 200psi 15min - 200psi,M/U and RIH with gun gamma and 14ft 2-7/8", 6SPF, 15g Geodynamics gun (CCL to top shot 11.3') Pull correlation pass and send to town - on depth.,Pull into position and perforate Beluga 27 @ 17:15hrs from 8,358-8,372'. POOH, water and sand in the bull plug. 0min - 195psi 5min - 196psi 10min - 198psi 15min - 199psi,Secure well and SDFN 7/28/2022 PJSM and PTW SITP 235psi R/U AK E-line,M/U and RIH with GPT tool. Tag, POOH Fluid level at 8,320 - 38ft above top perf Tag at 8,582' - Minimal to no fill on cement,M/U and RIH with gun gamma and 9ft 2-7/8", 6SPF, 15g Geodynamics gun (CCL to top shot 11.3') Pull correlation pass and send to town - on depth.,Pull into position and perforate Beluga 26 @ 11:44hrs from 8,281-8,290'. POOH, Gun dry with minimal sand 0min - 230psi No pressure change in 15min,M/U and RIH with gun gamma and 10ft 2-7/8", 6SPF, 15g Geodynamics gun (CCL to top shot 10.4') Pull correlation pass and send to town - shift down 1ft,Pull into position and perforate Beluga 25 @ 13:37hrs from 8,254-8,264'. POOH, Gun dry with minimal sand 0min - 230psi No pressure change in 15min,M/U and RIH with GPT tool. 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B0:',)5066DJ B0:',)5066DJ B0:',)5066DJ B0:',)5066DJ B0:',)5066DJ B0:',)5066DJ B0:',)5066DJ B0:',)5066DJ B0:',)5066DJ B0:',)5066DJ B0:',)5066DJ 352-(&7('WR7' $SSURYHG%\&KHFNHG%\'DWH $0 &203$66%XLOG(3DJH Chelsea Wright Digitally signed by Chelsea Wright Date: 2022.05.10 07:55:02 -08'00' Benjamin Hand Digitally signed by Benjamin Hand Date: 2022.05.10 10:06:33 -08'00' TD Shoe Depth: PBTD: Jts. 1 1 98 Yes X No X Yes No 10 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? Yes X No Reciprocated?X Yes 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: Casing (Or Liner) Detail Float Shoe 7 3/4 Rotate Csg Recip Csg Ft. Min. PPG9.6 Shoe @ 7474 FC @ Top of Liner 33367,431.00 Floats Held4000 6% KCL polymer CASING RECORD County State Alaska Supv.J Murphy / J Riley Hilcorp Energy Company CASING & CEMENTING REPORT Lease & Well No.BCU-018RD Date Run 1-May-22 Setting Depths Component Size Wt. Grade THD Make Length Bottom Top Vam Innovex 2.02 7,474.00 7,471.98 Csg Wt. On Hook: Type Float Collar:Innovex No. Hrs to Run: 9.6 6 650 FI R S T S T A G E 10.5Tune Primed 30 201/202 1200 38 Halliburton 15.3 18 Bump press CBL Bump Plug? 16:17 5/1/2022 3,570 7,474.007,476.00 CEMENTING REPORT Csg Wt. On Slips: 6% KCL Polymer 12 125 Type of Shoe:Innovex Casing Crew:Weatherford ZXP HRDE Baker Liner top packer www.wellez.net WellEz Information Management LLC ver_04818br 4 7'' Casing Jt 7 26.0 L-80 Vam 39.04 7,471.98 7,432.94 Float Collar 7 3/4 Vam Innovex 1.27 7,432.94 7,431.67 7'' Casing Jt 7 26.0 L-80 Vam 38.53 7,431.67 7,393.14 Landing Collar 7 3/4 Vam 1.77 7,393.14 7,391.37 7'' Casing Jts 7 26.0 L-80 Vam 4,021.58 7,391.37 3,369.79 7'' Casing pup jt 7 26.0 L-80 Vam 9.20 3,369.79 3,360.59 Flex lock ZXP Liner hanger Packer 8 3/4 24.45 3,360.59 3,336.14 l ll 295 1.41 l ll 90 1.24 5 TD Shoe Depth: PBTD: Jts. 1 2 79 Yes X No Yes X No 20 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? Yes X No Reciprocated? Yes X No % Returns during job Cement returns to surface? Yes X No Spacer returns? Yes X No Vol to Surf: Cement In Place At: Date: Estimated TOC: Method Used To Determine TOC: Type I II 130 2.39 Type I II 115 1.24 3 29.86 7,246.47 7,218.61Hanger 5 3/4 BTC Baker Flex lock 10,342.54 Liner 4 1/2 12.6 L-80 JFEBEAR HT JFE 3,096.07 10,342.54 7,246.47 10,385.20 10,343.60 Landing collar 5 BTC JHOBBS 1.06 10,343.60 1.54 10,386.74 10,385.20 Liner 4 1/2 12.6 L-80 JFEBEAR HT JFE 41.60 Float collar 5 BTC JHOBBS Ran centralizer on every jt. Total of 76 centralizers Liner 4 1/2 12.6 L-80 JFEBEAR HT JFE 43.26 10,428.18 10,386.74 Flex-Lock V liner hanger, HRD-E ZXP www.wellez.net WellEz Information Management LLC ver_04818br 3 Type of Shoe:JHOBBS Casing Crew:WOTCO 12 54 10,432.0010,461.00 10,342.54 CEMENTING REPORT Csg Wt. On Slips:225,000 6% KCL PHPA 15:00 5/11/2022 7,370 15.3 25 Bump press CBL Bump Plug? 141.5/143.5 2285 314.2 HES FI R S T S T A G E 11.5Tuned 30 10.4 3 96.5 1470 Csg Wt. On Hook:240,000 Type Float Collar:JHOBBS No. Hrs to Run:14.5 BTC JHOBBS 1.82 10,432.00 10,428.18 Setting Depths Component Size Wt. Grade THD Make Length Bottom Top Hilcorp Energy Company CASING & CEMENTING REPORT Lease & Well No.BCU-018RD Date Run 10-May-22 CASING RECORD County State Alaska Supv.R Pederson / J Riley 10,385.20 Floats Held4000 6% KCL PHPA Rotate Csg Recip Csg Ft. Min. PPG10.4 Shoe @ 10430 FC @ Top of Liner 7216.61 Casing (Or Liner) Detail Shoe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ll BOPE reports are due to the agency within 5 days of testing* SSu b m i t t o :jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov Owner/Contractor: Rig No.:8 DATE: 7/6/22 Rig Rep.: Rig Phone: 208-553-6699 Operator: Op. Phone:907-777-8300 Rep.: E-Mail Well Name: PTD #22220330 Sundry #322-269 Operation: Drilling: Workover: X Explor.: Test: Initial: X Weekly: Bi-Weekly: Other: Rams:250/3900 Annular:NA Valves:250/3900 MASP:3797 MISC. INSPECTIONS: TEST DATA FLOOR SAFETY VALVES: Test Result Test Result Quantity Test Result Location Gen.P Well Sign P Upper Kelly 0NA Housekeeping P Rig NA Lower Kelly 0NA PTD On Location P Hazard Sec.NA Ball Type 0NA Standing Order Posted NA Misc.NA Inside BOP 0NA FSV Misc 0NA BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm Stripper 1 1.75"P Trip Tank NA NA Annular Preventer 0 NA NA Pit Level Indicators NA NA #1 Rams 1 1.75 B/S P Flow Indicator NA NA #2 Rams 1 1.75 P/S P Meth Gas Detector NA NA #3 Rams 0 NA NA H2S Gas Detector NA NA #4 Rams 0 NA NA MS Misc 0NA #5 Rams 0 NA NA #6 Rams 0 NA NA Quantity Test Result Choke Ln. Valves 2 2"P Inside Reel valves 1P HCR Valves 0 NA NA Kill Line Valves 2 2"P Check Valve 0 NA NA ACCUMULATOR SYSTEM: BOP Misc 0 NA NA Time/Pressure Test Result System Pressure (psi)3000 P CHOKE MANIFOLD:Pressure After Closure (psi)2450 P Quantity Test Result 200 psi Attained (sec)4 P No. Valves 5P Full Pressure Attained (sec)14 P Manual Chokes 2P Blind Switch Covers: All stations Yes Hydraulic Chokes 0NA Nitgn. Bottles # & psi (Avg.): NA NA CH Misc 0NA ACC Misc 0NA Test Results Number of Failures:0 Test Time:3.0 Hours Repair or replacement of equipment will be made within NA days. Remarks: AOGCC Inspection 24 hr Notice Yes Date/Time 7/5/22 12:39 Waived By Test Start Date/Time:7/6/2022 9:00 (date) (time)Witness Test Finish Date/Time:7/6/2022 12:00 BOPE Test Report Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Jim Regg Fox Accumulator precharge pressure 1400 psi Landry Lynn Hilcorp Cole Bartlewski BCU-18RD Test Pressure (psi): cbartlewski@hilcorp.com Form 10-424 (Revised 02/2022) 2022-0706_BOP_Fox8_BCU-18RD +LOFRUS$ODVND//& 9 9 9 9999 9 9 MEU -5HJJ From:McLellan, Bryan J (OGC) To:Ryan Rupert Cc:Donna Ambruz; Dan Marlowe; Roby, David S (OGC) Subject:RE: [EXTERNAL] Re: BCU-18RD(PTD#222-033) Date:Wednesday, July 20, 2022 12:42:00 PM Ryan, Agreed that this plan satisfies the Tyonek isolation requirements. Approval granted to proceed as outlined in the below email chain. I’ll attach this to our records related to Sundry 322-269, so no need to file an additional change sundry. 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: Ryan Rupert <Ryan.Rupert@hilcorp.com> Sent: Wednesday, July 20, 2022 11:02 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com>; Dan Marlowe <dmarlowe@hilcorp.com>; Roby, David S (OGC) <dave.roby@alaska.gov>; Ryan Rupert <Ryan.Rupert@hilcorp.com> Subject: RE: [EXTERNAL] Re: BCU-18RD(PTD#222-033) Bryan- We were unable to establish production from the BEL-32 perfs, or any of the currently open perfs. Given this Hilcorp would like to plug back all existing perfs, and continue perf’ing uphole Beluga intervals, per the approved sundry. Since we’re now done with the BEL-32 sand, my plan is to dump bail an additional 30’ of cement on top of the CIBP at 8865’ (35 total) to finish the P&A of the Tyonek intervals below. ToC would be at 8830’ MD. After that we plan to set a CIBP above all open zones per the sundry and add additional zones. I believe this approach satisfies the Tyonek isolation requirement discussed prior in this email chain. Please let me know your thoughts. Thanks, Ryan Rupert Kenai Ops Engineer (#13088) 907-301-1736 (Cell) 907-777-8503 (Office) From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Monday, July 11, 2022 2:37 PM To: Ryan Rupert <Ryan.Rupert@hilcorp.com>; Brad Gathman - (C) <Brad.Gathman@hilcorp.com> Cc: Donna Ambruz <dambruz@hilcorp.com>; Dan Marlowe <dmarlowe@hilcorp.com>; Roby, David S (OGC) <dave.roby@alaska.gov> Subject: RE: [EXTERNAL] Re: BCU-18RD Ryan, How will you keep this from falling through the cracks a few years down the road? 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: Ryan Rupert <Ryan.Rupert@hilcorp.com> Sent: Monday, July 11, 2022 10:23 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Brad Gathman - (C) <Brad.Gathman@hilcorp.com> Cc: Donna Ambruz <dambruz@hilcorp.com>; Dan Marlowe <dmarlowe@hilcorp.com>; Roby, David S (OGC) <dave.roby@alaska.gov>; Ryan Rupert <Ryan.Rupert@hilcorp.com> Subject: RE: [EXTERNAL] Re: BCU-18RD Thank you Bryan. Please see below for the EL ops summary form yesterday. Given where we found top fish in corrected ELMD, we were only able to dump 5’ cement on top of the CIBP, while still maintaining access to the BEL-32 interval. Before moving uphole, and before any additional plugs are set, Hilcorp will place additional cement on top of the plug at 8865’ MD to make the cement column at least 25’. Please let us know if this is acceptable. Thank you. AK E-line arrive and hold PJSM. Approve PTW. MIRU equipment. MU GR/CCL and CIBP. 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. PT lubricator to 250 psi / 3900 psi.;RIH with 3.75" CIBP. GR/CCL to bottom of CIBP = 13.7'. Tag at 8852' + 13.7' = 8865.7' (uncorrected). Send correlation data to RE/GEO. Add 2' to get on depth. Corrected tag depth of 8867.7';Tag with plug and pick up to get weight back. Set top of plug at 8865'. POOH.;Load cement bailer with 3.2 gallons of cement to place 5' of cement on top of plug. RIH and tag CIBP. PU and dump cement. Top of cement = 8860'. POOH.;Laydown toolstring and lubricator. Remove wireline valves and secure well with coil night cap. Ryan Rupert Kenai Ops Engineer (#13088) 907-301-1736 (Cell) 907-777-8503 (Office) From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Saturday, July 9, 2022 11:43 PM To: Brad Gathman - (C) <Brad.Gathman@hilcorp.com> Cc: Ryan Rupert <Ryan.Rupert@hilcorp.com>; Donna Ambruz <dambruz@hilcorp.com>; Dan Marlowe <dmarlowe@hilcorp.com>; Roby, David S (OGC) <dave.roby@alaska.gov> Subject: [EXTERNAL] Re: BCU-18RD Brad, Approval is granted to set CIBP just above the WRP and dump bail at least 25’ of cement on top. Regards Bryan Sent from my iPhone On Jul 9, 2022, at 9:31 PM, Brad Gathman - (C) <Brad.Gathman@hilcorp.com> wrote: Slickline was eventually able to latch the WRP with the 4.5” pulling tool at 8922’ SLMD. However; after pulling 3600# and 38 jars licks, the plug only moved 3’. It is requested to proceed with setting a CIBP as deep as possible and dump cement on top. Regards, Brad Gathman From: Ryan Rupert <Ryan.Rupert@hilcorp.com> Sent: Saturday, July 9, 2022 6:09 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Donna Ambruz <dambruz@hilcorp.com>; Brad Gathman - (C) <Brad.Gathman@hilcorp.com>; Dan Marlowe <dmarlowe@hilcorp.com> Subject: BCU-18RD We have confirmed with SL impression blocks that we have a failed WRP at 8896' CTMD. We have tried to latch it with no success (even after a bailer run). CT has tried and can not push this plug downhole where its at either. Hilcorp would like approval to set a CIBP as deep as possible and dump cement on top up to 8860' or 35', whichever is lesser. This will preserve access to the vast majority of the Beluga interval, while isolating the Tyonek perfs below. The below Tyonek perfs would be permanenrly open with the Beluga 33 perfs as well in this scenario. After the WRP was set at 9098' originally, all flow attempts of the Beluga have been unsuccessful, despite FBHP's less than 1000psi. It's unlikely that Tyonek and Bel-33 would cross-flow long term, given this. Ryan Rupert 907-301-1736 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'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. 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. Updated by CRR 07-11-22 CURRENT SCHEMATIC BCU 18RD API: 50-133-20584-01-00 PTD: 222-033 Pad-3 PBTD = 8,860’ MD / 8,388’ TVD TD = 10,461’ MD / 9,964’ TVD RKB to GL = 18.0’ CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 20” Conductor 154.19 X-65 Weld 19.13” Surf 108’ 13-3/8" Surf Csg 68.0 K-55 BTC 12.415” Surf 2,097’ 9-5/8” Intermediate Csg 40.0 L-80 BTC 8.835” Surf 3,574’ 7” Intermediate Lnr 26.0 L-80 Vam Top 6.276” 3,336’ 7,474’ 4-1/2" Prod Tieback 12.6 L-80 JFEBEAR 3.958” Surf 7,214’ 4-1/2" Prod Lnr 12.6 L-80 JFEBEAR 3.958” 7,218’ 10,432’ 1 20” 13-3/8” 4-1/2” JEWELRY DETAIL No. Depth ID Item 1 3,336’ 6.040” 9-5/8” x 7” Liner hanger / LTP Assembly 2 3,574’ N/A Whipstock 3 7,218’ 5.25” 7” x 4-1/2” Liner hanger / LTP Assembly with PBR 4 7,214’ 3.890” Seal Stem 5 8,865’ CIPB w/ 5’ cement – TOC @ 8,860’ (7/20/22)** MUST be capped with 35’ cement before additional plugs are set OPEN HOLE / CEMENT DETAIL 13-3/8” 16” Hole: TOC @ Surface (Original BCU 18) 9-5/8" 12-1/4: Hole: TOC @ 2,860’ (Original BCU 18) 7” 8-1/2” Hole: 125bbls 12ppg lead followed by 18bbls 15.3ppg tail pumped on 5/1/22. 38bbls lead cement back to surface. 5/14/22 CBL shows ToC at 3570’ MD 4-1/2” 6-1/8” Hole: Pumped 30bbl spacer followed by 54bbls 12ppg Type I/II lead followed by 25bbls 15.3ppg Type I/II tail pumped on 5/11/22. Trace spacer back to surface. 5/19/22 CBL shows ToC at 7370’ MD 4 4 9-5/8” 2 BCU 18 (Abandoned) 3 7” PERFORATION DETAIL Zone Top MD Btm MD TopTVD Btm TVD Amt Date Comments BEL29 8,625’ 8,635’ 8,157’ 8,166’ 10’ 6/19/22 Open BEL29 8,625’ 8,635’ 8,157’ 8,166’ 10’ 6/12/22 Open BEL29 8,643’ 8,648’ 8,173’ 8,179’ 5’ 6/19/22 Open BEL29 8,643’ 8,648’ 8,173’ 8,179’ 5’ 6/12/22 Open BEL29 8,653’ 8,659’ 8,184’ 8,190’ 6’ 6/19/22 Open BEL29 8,653’ 8,659’ 8,184’ 8,190’ 6’ 6/12/22 Open B30 8,740' 8,745' 8,270’ 8,275’ 5’ 6/11/22 Open B30 8,775' 8,781' 8,304’ 8,310’ 6’ 6/11/22 Open B31 8,812' 8,818' 8,341’ 8,347’ 6’ 6/11/22 Open B32 8,840' 8,849' 8,369’ 8,377’ 9’ 6/11/22 Open B33 8,995' 9,004' 8,522’ 8,530’ 9’ 6/11/22 Isolated 7/10/22 T0 9,148' 9,153' 8,672' 8,677' 5’ 06/01/22 Isolated 6/8/22 T2 9,230' 9,242' 8,753' 8,765' 12’ 06/01/22 Isolated 6/8/22 T4 9,337' 9,347' 8,860' 8,868' 10’ 05/31/22 Isolated 6/8/22 T4 9,380' 9,393' 8,901' 8,913' 13’ 05/31/22 Isolated 6/8/22 T6 9,567' 9,575' 9,085' 9,093' 8’ 05/29/22 Isolated 6/8/22 T7A 9,738' 9,758' 9,253' 9,273' 20’ 05/29/22 Isolated 6/8/22 T7B 9,797' 9,817' 9,311' 9,328' 20’ 05/28/22 Isolated 6/8/22 T11 10,116' 10,136' 9,625' 9,645' 20’ 05/28/22 Isolated 6/8/22 T12 10,289' 10,308' 9,795' 9,813' 19’ 05/26/22 Isolated 6/8/22 T12 10,289' 10,308' 9,795' 9,813' 19’ 05/27/22 Isolated 6/8/22 BEL 29-32 T0 – T12 5** BEL 33 FISH DETAIL: Failed WRP at 8867’ ELMD (7/10/22) **REGULATORY: CIBP at 8865’ MD MUST be capped with at least 35’ cement before any additional plugs are set. 1 Regg, James B (OGC) From:Brad Gathman - (C) <Brad.Gathman@hilcorp.com> Sent:Saturday, June 11, 2022 8:38 PM To:Regg, James B (OGC); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (OGC) Cc:Donna Ambruz Subject:BOPE Test Report BCU-18RD 6-9-22.xlsx Attachments:BOPE Test Report BCU-18RD 6-9-22.xlsx The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. Beaver Creek Unit 18RD PTD 2220330 STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION *All BOPE reports are due to the agency within 5 days of testing* Submit to:jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov Owner/Contractor:Rig No.:1 DATE:6/9/22 Rig Rep.:Rig Phone:907-659-2434 Operator:Op. Phone:907-777-8300 Rep.:E-Mail Well Name:PTD #2220330 Sundry #322-269 Operation:Drilling:Workover:X Explor.: Test:Initial:X Weekly:Bi-Weekly:Other: Rams:250/3900 Annular:NA Valves:250/3900 MASP:3797 MISC. INSPECTIONS:TEST DATA FLOOR SAFETY VALVES: Test Result Test Result Quantity Test Result Location Gen.P Well Sign P Upper Kelly 0 NA Housekeeping P Rig NA Lower Kelly 0 NA PTD On Location P Hazard Sec.NA Ball Type 0 NA Standing Order Posted NA Misc.NA Inside BOP 0 NA FSV Misc 0 NA BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm Stripper 1 1.75" top load P Trip Tank NA NA Annular Preventer 0 NA NA Pit Level Indicators NA NA #1 Rams 1 1.75 B/S P Flow Indicator NA NA #2 Rams 1 1.75 B/S P Meth Gas Detector NA NA #3 Rams 1 1.75 Slips P H2S Gas Detector NA NA #4 Rams 1 1.75 Pipes P MS Misc 0 NA #5 Rams 0 NA NA #6 Rams 0 NA NA Quantity Test Result Choke Ln. Valves 1 2x2 FMC P Inside Reel valves 1 P HCR Valves 0 NA NA Kill Line Valves 2 2x2 FMC P Check Valve 1 2" 1502 P ACCUMULATOR SYSTEM: BOP Misc 3 EQ PORTS P Time/Pressure Test Result System Pressure (psi)3000 P CHOKE MANIFOLD:Pressure After Closure (psi)1550 P Quantity Test Result 200 psi Attained (sec)18 P No. Valves 5 P Full Pressure Attained (sec)68 P Manual Chokes 2 P Blind Switch Covers:All stations Yes Hydraulic Chokes 0 NA Nitgn. Bottles # & psi (Avg.):NA NA CH Misc 0 NA ACC Misc 0 NA Test Results Number of Failures:0 Test Time:3.0 Hours Repair or replacement of equipment will be made within NA days. Remarks: AOGCC Inspection 24 hr Notice Yes Date/Time 6/8/22 15:53 Waived By Test Start Date/Time:6/9/2022 10:30 (date)(time)Witness Test Finish Date/Time:6/9/2022 13:30 BOPE Test Report Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Jim Regg Schlumberger A push/pull test was conducted on the slip rams. Bryson Lowe Hilcorp Brad Gathman BCU-18RD Test Pressure (psi): brad.gathman@hilcorp.com Form 10-424 (Revised 02/2022)2022-0609_BOP_Schlumberger1_BCU-18RD Hilcork Alaska LLC        jbr J. Regg; 7/14/2022 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' "Ho-arg AWka, LUC: Date: 07/07/2022 David Douglas Hilcorp Alaska, LLC Sr. GeoTechnician 3800 CenterPoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.douglas@hilcorp.com To: Alaska Oil & Gas Conservation Commission Petroleum Geology Assistant 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMITTAL BCU 18RD - PTD 222-033 - API:50-133-20584-01-00 Washed and Dried Well Samples (TD: 05/09/2022) A Set (5 Boxes): WELL Bair SAMPLE IWERVAL (EEIET t MD) BCU 18RD BOX 1 OF 5 3574' - 5100' MD BCU 18RD BOX 2 OF 5 5100' - 6600' MD BCU 18RD BOX 3 OF 5 6600' - 8250' MD BCU 18RD BOX 4 OF 5 8250' - 9750' MD BCU 18RD BOX 5 OF 5 9750' - 10461' MD (TD) Please include current contact information if different from above. 2Z2-(D,3 1 �0(o RECEIVED Please acknowledge receipt by signing and returning one copy of this transmittal. JUL 01 2u« AOGCC Received Bpi/ Date: `f �7 (6 ) 2 — 11 r � I/ 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: 06/28/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL BCU 18RD (PTD 222-033) GPT/PERF 05/29/2022 Please include current contact information if different from above. PTD:222-033 T36731 Kayla Junke Digitally signed by Kayla Junke Date: 2022.07.22 12:40:51 -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: 06/28/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL BCU 18RD (PTD 222-033) GPT/PERF 05/31/2022 Please include current contact information if different from above. PTD: 222-033 T36731 Kayla Junke Digitally signed by Kayla Junke Date: 2022.06.29 10:54:36 -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: 06/28/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL BCU 18RD (PTD 222-033) GPT/PERF 06/03/2022 Please include current contact information if different from above. PTD:222-033 T36731 Kayla Junke Digitally signed by Kayla Junke Date: 2022.06.29 10:52:20 -08'00' David Douglas Hilcorp Alaska, LLC Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: DATE: 06/09/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL BCU 18RD - PTD 222-033 - API 50-133-20584-01-00 MUDLOGS - EOW DRILLING REPORTS (04/23/2022 to 05/09/2022) 1. FINAL EOW REPORT 2. DAILY REPORTS 3. SHOW REPORTS 4. DIGITAL DATA (LAS) 5. MUDLOG PRINTS (2” and 5” MD and TVD COLOR PRINTS – TIFF AND PDF FORMATS) Formation Log LWD Combo Log Gas Ratio Log Drilling Dynamics Log SFTP Transfer - Data Folders: Please include current contact information if different from above. PTD:222-033 T36695 Kayla Junke Digitally signed by Kayla Junke Date: 2022.06.10 16:14:55 -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:Ryan Rupert Cc:Donna Ambruz; Roby, David S (OGC); Boyer, David L (OGC) Subject:RE: RBP on BCU-18RD(PTD#222-033) Date:Tuesday, June 7, 2022 4:14:00 PM Ryan, Hilcorp has approval to proceed with your plan below as part of Sundry 322-269. Please include this activity on the 10-407 for the initial completion. 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: Ryan Rupert <Ryan.Rupert@hilcorp.com> Sent: Saturday, June 4, 2022 6:14 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com> Subject: RBP on BCU-18RD(PTD#222-033) Brian, per our conversation, Hilcorp plans to set a retrievable Bridge plug at 9098’ MD in BCU-18RD with NO cement. We intend to perforate the Beluga sands above while pursuing a comingling application with the intention to pull the RBP some day if/when approved. If not ultimately approved for comingling, Hilcorp will dump bail 35’ of cement on top of this WRP long term. Attached is the current schematic. Thank you Ryan Rupert Kenai Ops Engineer (#13088) 907-301-1736 (Cell) 907-777-8503 (Office) 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. David Douglas Hilcorp Alaska, LLC Sr. GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 6/01/2022 To: Alaska Oil & Gas Conservation Commission Natural Resources Technician 333 W. 7th Ave. Ste#100 Anchorage, AK 99501 DATA TRANSMITTAL BCU 18RD - PTD 222-033 - API 50-133-20584-01-00 FINAL LWD FORMATION EVALUATION LOGS (04/22/2022 to 05/10/2022) ROP, AGR, EWR-M5, PCG, ADR, ALD, CTN (2” & 5” MD/TVD Color Logs) Final Definitive Directional Survey Folder Contents: Please include current contact information if different from above. PTD:222-033 T36678 Kayla Junke Digitally signed by Kayla Junke Date: 2022.06.03 08:55:44 -08'00' 5HJJ-DPHV%2*& )URP0LFKDHO+LEEHUW&0LFKDHO+LEEHUW#KLOFRUSFRP! 6HQW0RQGD\0D\$0 7R5HJJ-DPHV%2*&%URRNV3KRHEH/2*&'2$$2*&&3UXGKRH%D\ &F-XDQLWD/RYHWW5\DQ5XSHUW 6XEMHFW%&5'%23(7HVW5HSRUW $WWDFKPHQWV%&85'%237HVW[OV[ 'ŽŽĚŵŽƌŶŝŶŐ͕ ƚƚĂĐŚĞĚŝƐƚŚĞKWƚĞƐƚƌĞƉŽƌƚƉĞƌĨŽƌŵĞĚǁŝƚŚ&ŽǆŶĞƌŐǇdhϴ͘WůĞĂƐĞůĞƚŵĞŬŶŽǁŝĨƚŚĞƌĞĂƌĞĂŶǇƋƵĞƐƚŝŽŶƐ͘ dŚĂŶŬƐ͕ DŝĐŚĂĞů,ŝďďĞƌƚ tĞůůƐŝƚĞ^ƵƉĞƌǀŝƐŽƌ ,ŝůĐŽƌƉůĂƐŬĂ ϵϬϳͲϵϬϯͲϱϵϵϬ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ll BOPE reports are due to the agency within 5 days of testing* SSu b m i t t o :jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov Owner/Contractor: Rig No.:8 DATE: 5/21/22 Rig Rep.: Rig Phone: (907)887-1766 Operator: Op. Phone:(907)632-4113 Rep.: E-Mail Well Name: PTD #2220330 Sundry #322-269 Operation: Drilling: Workover: x Explor.: Test: Initial: x Weekly: Bi-Weekly: Other: Rams:250/3900 Annular:N/A Valves:250/3900 MASP:3797 MISC. INSPECTIONS: TEST DATA FLOOR SAFETY VALVES: Test Result Test Result Quantity Test Result Location Gen.P Well Sign P Upper Kelly 0NA Housekeeping P Rig P Lower Kelly 0NA PTD On Location P Hazard Sec.P Ball Type 0NA Standing Order Posted NA Misc.NA Inside BOP 0NA FSV Misc 0NA BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm Stripper 1 1.75"P Trip Tank NA NA Annular Preventer 0 N/A NA Pit Level Indicators NA NA #1 Rams 1 1.75" BS P Flow Indicator NA NA #2 Rams 1 1.75" PS P Meth Gas Detector NA NA #3 Rams 0 N/A NA H2S Gas Detector NA NA #4 Rams 0 N/A NA MS Misc 0NA #5 Rams 0 N/A NA #6 Rams 0 N/A NA Quantity Test Result Choke Ln. Valves 2 2"P Inside Reel valves 1P HCR Valves 0 N/A NA Kill Line Valves 2 2"P Check Valve 0 N/A NA ACCUMULATOR SYSTEM: BOP Misc 0 N/A NA Time/Pressure Test Result System Pressure (psi)3000 P CHOKE MANIFOLD:Pressure After Closure (psi)2450 P Quantity Test Result 200 psi Attained (sec)4 P No. Valves 5P Full Pressure Attained (sec)14 P Manual Chokes 2P Blind Switch Covers: All stations Yes Hydraulic Chokes 0NA Nitgn. Bottles # & psi (Avg.): N/A NA CH Misc 0NA ACC Misc 0NA Test Results Number of Failures:0 Test Time:2.5 Hours Repair or replacement of equipment will be made within N/A days. Remarks: AOGCC Inspection 24 hr Notice Yes Date/Time 5/20/22 12:57PM Waived By Test Start Date/Time:5/21/2022 10:00 (date) (time)Witness Test Finish Date/Time:5/21/2022 12:30 BOPE Test Report Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Jim Regg Fox Accumulator precharge pressure 1400 psi Terence Rais Hilcorp Alaska Michael Hibbert BCU-18RD Test Pressure (psi): Michael.Hibbert@hilcorp.com Form 10-424 (Revised 02/2022) 2022-0521_BOP_Fox8_BCU_18RD 9 9 9 9 9 9 9 9 9 9 9 9 -5HJJ 5HJJ-DPHV%2*& )URP5DQFH3HGHUVRQ&USHGHUVRQ#KLOFRUSFRP! 6HQW0RQGD\0D\30 7R5HJJ-DPHV%2*& &F%URRNV3KRHEH/2*& 6XEMHFW5H>(;7(51$/@5(+LOFRUS5LJ0,77HVW5HSRUW EŽƐŝƌǁĞŚĂĚĂŶŶƵůƵƐŽƉĞŶƚŽĂƚŵŽƐƉŚĞƌĞǁŚŝůĞƚĞƐƚŝŶŐƚƵďŝŶŐĂŶĚůŝŶĞƌ͕ƚŚĞŶŚĂĚƚƵďŝŶŐĂŶĚůŝŶĞƌŽƉĞŶƚŽĂƚŵŽƐƉŚĞƌĞ ǁŚŝůĞƚĞƐƚŝŶŐĂŶŶƵůƵƐ͘/ŚĂǀĞŶŽƚďĞĞŶĨŽƌƚƵŶĂƚĞĞŶŽƵŐŚƚŽŚĂǀĞĂŶŝŶƐƉĞĐƚŽƌǁŝƚŶĞƐƐĂŶǇD/dΖƐƐŽ/ǁĂƐŶŽƚĂǁĂƌĞƚŽ ŬĞĞƉƚŚŽƐĞƐŚƵƚŝŶĂŶĚƌĞĐŽƌĚƚŚŽƐĞƉƌĞƐƐƵƌĞƐ͊ ^ĞŶƚǀŝĂƚŚĞ^ĂŵƐƵŶŐ'ĂůĂǆǇϬϭ͕ĂŶdΘdϰ'>dƐŵĂƌƚƉŚŽŶĞ 'ĞƚKƵƚůŽŽŬĨŽƌŶĚƌŽŝĚ 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%HDYHU&UHHN8QLW5' 37' ^ƵƉĞƌǀŝƐŽƌ͕/ŶƐƉĞĐƚŝŽŶƐ K' ϯϯϯt͘ϳƚŚǀĞ͕^ƵŝƚĞϭϬϬ ŶĐŚŽƌĂŐĞ͕<ϵϵϱϬϭ ϵϬϳͲϳϵϯͲϭϮϯϲ &ƌŽŵ͗ZĂŶĐĞWĞĚĞƌƐŽŶͲ;ͿфƌƉĞĚĞƌƐŽŶΛŚŝůĐŽƌƉ͘ĐŽŵх ^ĞŶƚ͗^ƵŶĚĂǇ͕DĂǇϭϱ͕ϮϬϮϮϳ͗ϭϲWD dŽ͗ZĞŐŐ͕:ĂŵĞƐ;K'Ϳфũŝŵ͘ƌĞŐŐΛĂůĂƐŬĂ͘ŐŽǀх͖KK'WƌƵĚŚŽĞĂǇфĚŽĂ͘ĂŽŐĐĐ͘ƉƌƵĚŚŽĞ͘ďĂǇΛĂůĂƐŬĂ͘ŐŽǀх͖ ƌŽŽŬƐ͕WŚŽĞďĞ>;K'ͿфƉŚŽĞďĞ͘ďƌŽŽŬƐΛĂůĂƐŬĂ͘ŐŽǀх͖tĂůůĂĐĞ͕ŚƌŝƐ;K'ͿфĐŚƌŝƐ͘ǁĂůůĂĐĞΛĂůĂƐŬĂ͘ŐŽǀх ^ƵďũĞĐƚ͗,ŝůĐŽƌƉZŝŐϭϲϵD/ddĞƐƚZĞƉŽƌƚ WůĞĂƐĞƐĞĞƚŚĞĂƚƚĂĐŚĞĚD/dĨŽƌŵĂŶĚƚĞƐƚĐŚĂƌƚĨŽƌhͲϭϴZ͘ ZĂŶĐĞWĞĚĞƌƐŽŶ ƌŝůůŝŶŐ&ŽƌĞŵĂŶ ĞĂǀĞƌƌĞĞŬhŶŝƚ ϵϬϳͲϳϳϲͲϲϳϳϲ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ubmit to: OOPERATOR: FIELDD // UNITT // PAD: DATE: OPERATORR REP: AOGCCC REP: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2220330 Type Inj N Tubing 0 4190 4165 4157 Type Test P Packer TVD BBL Pump 2.7 IA Interval I Test psi 4000 BBL Return 2.5 OA Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2220330 Type Inj N Tubing Type Test P Packer TVD BBL Pump 4.4 IA 0 3840 3838 3836 Interval I Test psi 3800 BBL Return 4.4 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 Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W = Water P = Pressure Test I = Initial Test P = Pass G = Gas O = Other (describe in Notes) 4 = Four Year Cycle F = Fail S = Slurry V = Required by Variance I = Inconclusive I = Industrial Wastewater O = Other (describe in notes) N = Not Injecting Notes: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION MMech anicall In tegri tyy Test jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov Notes:9 5/8" x 7" x 4 1/2" annulus. ZXP Liner Top Packers at 3141' tvd and 6766' tvd Notes: Notes: Hilcorp Alaska, LLC Beaver Creek / Beaver Creek Unit / Pad 3 Rance Pederson 05/15/22 Notes:4 1/2" tieback string and liner. ZXP Liner Top Packers at 3141' tvd and 6766' tvd Notes: Notes: Notes: BCU-18RD BCU-18RD Form 10-426 (Revised 01/2017)2022-0515_MITP_BCU_18RD_2tests 9 9 9 9 9 -5HJJ 05/15/22 4 1/2" tieback string and liner. 9 5/8" x 7" x 4 1/2" annulus. 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: 5/23/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL BCU 18RD (PTD 222-033) CBL 5/14/2022 CBL 5/19/2022 Please include current contact information if different from above. PTD:222-033 T36645 T36644 Kayla Junke Digitally signed by Kayla Junke Date: 2022.05.25 09:51:58 -08'00' From:McLellan, Bryan J (OGC) To:Ryan Rupert; Frank Roach; Sean McLaughlin Cc:Rixse, Melvin G (OGC); Donna Ambruz; Chad Helgeson; Sarah Frey; Meredyth Richards Subject:RE: [EXTERNAL] RE: BCU-18RD 7" CBL logs Date:Tuesday, May 24, 2022 2:15:00 PM Ryan, The CBL log indicates that there is adequate cement behind the 4-1/2” liner to isolate the Tyonek from the Beluga when Hilcorp is ready to plug back the Tyonek per Sundry 322-269. The Beluga perfs proposed in the same sundry will all be isolated from shallower formations by the cemented 7” casing shoe. Hilcorp has approval to proceed with the perforations per Sundry 322-269. 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: Ryan Rupert <Ryan.Rupert@hilcorp.com> Sent: Tuesday, May 24, 2022 1:44 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Frank Roach <Frank.Roach@hilcorp.com>; Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Cc: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Donna Ambruz <dambruz@hilcorp.com>; Chad Helgeson <chelgeson@hilcorp.com>; Ryan Rupert <Ryan.Rupert@hilcorp.com>; Sarah Frey <sarah.frey@hilcorp.com>; Meredyth Richards <Meredyth.Richards@hilcorp.com> Subject: RE: [EXTERNAL] RE: BCU-18RD 7" CBL logs Top Tyonek = 9012’ MD (8539’ TVD) Top Beluga = 6201’ MD (5811’ TVD) Ryan Rupert Kenai Ops Engineer (#13088) 907-301-1736 (Cell) 907-777-8503 (Office) From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Tuesday, May 24, 2022 12:07 PM To: Frank Roach <Frank.Roach@hilcorp.com>; Ryan Rupert <Ryan.Rupert@hilcorp.com>; Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Cc: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Donna Ambruz <dambruz@hilcorp.com>; Chad Helgeson <chelgeson@hilcorp.com> Subject: RE: [EXTERNAL] RE: BCU-18RD 7" CBL logs Ryan, Where are the tops of the Tyonek and Beluga in this well? 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: McLellan, Bryan J (OGC) Sent: Tuesday, May 24, 2022 10:45 AM To: Frank Roach <Frank.Roach@hilcorp.com>; Ryan Rupert <Ryan.Rupert@hilcorp.com>; Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Cc: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Donna Ambruz <dambruz@hilcorp.com>; Chad Helgeson <chelgeson@hilcorp.com> Subject: RE: [EXTERNAL] RE: BCU-18RD 7" CBL logs Frank, The cement report says that est TOC is 9018’ MD, but the space for “Method used to determine TOC” was left blank. How was TOC estimated in this well? 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, May 24, 2022 10:13 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Ryan Rupert <Ryan.Rupert@hilcorp.com>; Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Cc: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Donna Ambruz <dambruz@hilcorp.com>; Chad Helgeson <chelgeson@hilcorp.com> Subject: RE: [EXTERNAL] RE: BCU-18RD 7" CBL logs Bryan, No sir, I’m back in town. Please see the attached cementing summary report. I also added Sean to the email chain since he was covering when the 4-1/2” liner was ran and the cement job was performed. Regards, Frank V Roach Drilling Engineer 907.854.2321 (c) 907.777.8413 (o) From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Tuesday, May 24, 2022 09:57 To: Ryan Rupert <Ryan.Rupert@hilcorp.com> Cc: Frank Roach <Frank.Roach@hilcorp.com>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Donna Ambruz <dambruz@hilcorp.com>; Chad Helgeson <chelgeson@hilcorp.com> Subject: RE: [EXTERNAL] RE: BCU-18RD 7" CBL logs Ryan, Could you send me the cementing summary report from the drillers if Frank is out of town still? 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: Ryan Rupert <Ryan.Rupert@hilcorp.com> Sent: Tuesday, May 24, 2022 9:29 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Frank Roach <Frank.Roach@hilcorp.com>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Donna Ambruz <dambruz@hilcorp.com>; Chad Helgeson <chelgeson@hilcorp.com>; Ryan Rupert <Ryan.Rupert@hilcorp.com> Subject: RE: [EXTERNAL] RE: BCU-18RD 7" CBL logs We’re happy to keep perfs below 8650’ MD for this initial sundry/work. Here’s the cementing report, and daily log. Ended up tagging <100’ high inside the 4-1/2” liner (daily below as well) the first couple dozen feet milled very easily (likely stringers). I’m guessing about ~1bbl cement above the landing collar. We think where CT milling got difficult, and we stopped is likely the landing collar = 10,344’ MD. 5/12/22 rig report (cementing 4-1/2” liner) Cont TIH on stands DP with 4 1/2" liner, from 9605' to 10,430'. Washing down working through coals and fighting pack offs. At 10,430’ we set down, attempted to work back up hole with no movement, numerous times. Up wt 240K, dwn wt 115K. Working pump on and off fighting packoff. Parked string at 10,430’ having a tool joint at table allowing us to LD single joint and MU cement head. Called out cementers at 08:45. Cont to work pump trying to establish constant circulation at 112 gpm-1100 to 1300 psi, staying below anchor set pressure of 200 psi. Parked string at 260K and worked pump, then at 160K. Eventually able to get 3.7 bpm-1230 psi with steady return flow. After crew change, shut down pump, Max gas 766. LD single, MU cement head and plumbing, cont to circ at 132 gpm-1204 psi while holding PJSM. Halliburton pumped 3 bbls water to flush lines, then 5 bbls to fill lines. Shut in at Baker cement head and PT lines at 1100 psi low 4512 psi high. Lined up Baker cement head to Halliburton, pumped 30 bbls 11.5 ppg spacer at 3 bpm-1077 psi, followed with 54 bbls (130 sx) 12 ppg Type I II Lead cement at 3 bpm, 1020 to 715 psi, followed with 25 bbls (115 sx) 15.3 ppg Type I II Tail cement at 3 bpm-550 psi. Added 2 pps LCM to lead cement. Baker released dart, Halliburton then displaced with 10.4 ppg 6% KCL mud at 3 bpm-640 ICP. 17 bbls into displacement caught pressure chasing cement. 94 bbls into displacement saw dart latch wiper plug. With 10 bbls to go, reduced rate to 2 bpm-1470 psi and bumped plug/landing collar 141.5 bbls into displacement (calculated at 143.5 bbls). FCP 1470 psi. Halliburton increased to and held 2285 psi (815 over fcp) for 1 minute, then increased pressure to 2500 psi for 1 minute. Slacked off on blocks from 200K to 80K, giving us a good indication hanger was set. Bled back 1 bbl to truck and floats held. CIP at 15:00 on 5-11-22. Lost 3.5 bbls throughout the job. Applied 3737 psi and held 1 minute to shift HRD-E and release run tool. Bled off and PU to 210K three times, run tool not released. S/O to 80K and applied 4000 psi and held 5 minutes. Bled off, PU to 200K, lost weight, cont to PU at 175K, run tool released. PU 12’ to clear dogs from hanger top, rotated at 30 rpm, 8432 ft/lbs torque, S/O and set down to 70K (55K applied) three times, to ensure weight transfer to set packer. Top of liner hanger at 7216.61’, top of landing collar at 10,342.54’. Closed upper rams, rig lined up on kill line and pressured up on annulus to 1447 psi and held for 5 minutes. Pressure holding, good indication HRDE ZXP liner top packer is set. Did not have any indication of shear at surface. Bled off annulus pressure to 0 psi, and opened rams. LD Halliburton hardline, LD Baker cement head, MU topdrive. Pressured up to 500 psi on drill string and PU 9’ slowly. Once psi started dropping, rig started pumping and did one full circ at 430 gpm-1827 psi. Had trace of spacer to surface, no cement. Shut down pump, racked back one stand, installed wiper ball in drill string, MU topdrive and pumped second circulation at 420 gpm-1693 psi. POOH F/7216'-T/ surface, Inspected & B/D and L/D Baker running tool. P/U-170K S/O-106K Held kick while trip drill at 5317'. Started hauling of mud and cleaning pits. Service rig- Greased crown, blocks, TDS, wash pipe, DWKS, brake linkage, drive shaft, and IR. Johnny whacked the stack. Started B/O 10' & 5' off Baker cmt head and L/D. Crew change, held PTSM. Finished B/O pups of Baker cmt head. Added oil to TDS gear box. Staged Baker polishing assy. on catwalk. Cont. hauling of mud & cleaning pits. Hauled in water and filled pits 9 & 10 to build 6% KCL brine (8.6 ppg). M/U Baker polishing mill assy. as per Baker Rep. RIH out of the derrick F/surface-T/7191'. Eased through 7" liner top @ 3336' with out a bobble. Adjusted TDS drill TQ T/15K. Currently CBU. P/U-165K S/O-100K. GPM-216 SPP-665 psi. Changed MP #2 liner/swabs to 4.5" for displacement of brine. 5/22/22 CT report (tag/mill 4-1/2” liner) Fox Energy, Cruz, and Quadco on location. PJSM and PTW. MU MHA - 1.75" ext slip CTC, DFCV, Logan jars, Disco, Circ sub, 2-7/8" motor,. Pressure test MHA. MU 3.80" 5 bladed junk mill (OAL - 27.36'). Function test motor. MU lubricator to well and PT 300 psi / 3900 psi lubricator, stripper and inner reel valve. Open well and RIH taking coil displacement returns to OTT. Place an additional ~200 bbls of FW in OTT for milling. Dry tag cement at 10,272' CTM. Come online with FW at 2 bpm at 4400 psi. Mill down to 10,377'. Made a short trip up above original tag depth. Milled at 10,377' for ~1 hour, pumping at max rate at 5500 psi. Unable to make any progress without more rate. Called and town approved stopping at current depth. Pump bottoms up and POOH. Vac truck started hauling return fluids to G&I. Total fluid pumped ~320 bbls of fresh water. Break down MHA and mill. Mill showed some polishing around the outer rim of the mill, but nothing conclusive of what it may have been milling on at 10,377' CTM. Lay down lubricator and install night cap on BOPs. SDFN. Ryan Rupert Kenai Ops Engineer (#13088) 907-301-1736 (Cell) 907-777-8503 (Office) From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Tuesday, May 24, 2022 6:34 AM To: Ryan Rupert <Ryan.Rupert@hilcorp.com> Cc: Frank Roach <Frank.Roach@hilcorp.com>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Subject: [EXTERNAL] RE: BCU-18RD 7" CBL logs Ryan, This CBL is pretty washed out in the VDL and VAD tracts. It’s not a normal display for CBL across the industry, but it seems normal for Alaska E-line’s logs to look like this. It’s difficult to interpret with this display. 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. I would call top of good cement possibly around 8550’ MD, which is below your planned top perf. I’m wondering if something went wrong during the 4-1/2” cement job? Can you send me the cement summary report and daily job log? Where did you tag cement inside the 4-1/2” liner? 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: Ryan Rupert <Ryan.Rupert@hilcorp.com> Sent: Friday, May 20, 2022 9:56 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com> Subject: RE: BCU-18RD 7" CBL logs And here’s the CBL of the 4-1/2” liner. Please let us know when Hilcorp has authorization to proceed. We aim to MIRU with CT tomorrow, Saturday 5/21. Ryan Rupert Kenai Ops Engineer (#13088) 907-301-1736 (Cell) 907-777-8503 (Office) From: Ryan Rupert Sent: Tuesday, May 17, 2022 1:33 PM To: 'bryan.mclellan@alaska.gov' <bryan.mclellan@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com> Subject: FW: BCU-18RD 7" CBL logs Here’s the 7” CBL, and current schematic (this was acquired before the4-1/2” tie-back was run). Our current plans have us logging the 4-1/2” cement on Fri 5/20, and then MIRU CT on Sat 5/21 for ~100’ of cement mill out, and then blowdown. We did tag cement a bit high in our cleanout run, so I’ll be milling some of that out during my post-rig CT work. I don’t believe any sundry modification/approval is needed for that activity, but let me know if that’s incorrect. All milling will stay in the cased hole. Ryan Rupert Kenai Ops Engineer (#13088) 907-301-1736 (Cell) 907-777-8503 (Office) From: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Sent: Sunday, May 15, 2022 12:04 AM To: Ryan Rupert <Ryan.Rupert@hilcorp.com> Subject: Fwd: BCU-18RD 7" CBL logs Begin forwarded message: From: "Jesse Richardson - (C)" <jesrichardson@hilcorp.com> Date: May 14, 2022 at 11:54:24 PM AKDT To: Sean McLaughlin <sean.mclaughlin@hilcorp.com> Cc: Monty Myers <mmyers@hilcorp.com>, "Rance Pederson - (C)" <rpederson@hilcorp.com> Subject: BCU-18RD 7" CBL logs Sean, Here is an electronic copy of the 7” CBL logs. Jess Richardson Hilcorp Rig 169 DSM Contact # 776-6776 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity namedabove. 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Offset field test data predicts frac gradient at the 9-5/8” window to be between 11.0 – 13.5 ppg EMW. A 12.0 ppg FIT results in a >15 bbl kick tolerance while drilling with the planned MW of 10.5 ppg and an assumed 0.5ppg kick intensity over anticipated pore pressure. 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x3XPSUDWHZKLOHPL[LQJESPQRWHDQ\VKXWGRZQGXULQJPL[LQJRSHUDWLRQVZLWKDGXUDWLRQ x3XPSUDWHZKLOHGLVSODFLQJQRWHZKHWKHUGLVSODFHPHQWE\SXPSWUXFNRUPXGSXPSVZHLJKW W\SH RIGLVSODFLQJIOXLG x1RWHLIOLQHULVUHFLSURFDWHGRUURWDWHGGXULQJWKHMRE x&DOFXODWHGYROXPHRIGLVSODFHPHQWDFWXDOGLVSODFHPHQWYROXPHZKHWKHUSOXJEXPSHG EXPS SUHVVXUHGRIORDWVKROG x3HUFHQWPXGUHWXUQVGXULQJMRE,ILQWHUPLWWHQWQRWHWLPLQJGXULQJSXPSLQJRIMRE)LQDOFLUFXODWLQJ SUHVVXUH x1RWHLISUHIOXVKRUFHPHQWUHWXUQVDWVXUIDFH YROXPH x1RWHWLPHFHPHQWLQSODFH x1RWHFDOFXODWHGWRSRIFHPHQW x$GGDQ\FRPPHQWVZKLFKZRXOGGHVFULEHWKHVXFFHVVRUSUREOHPVGXULQJWKHFHPHQWMRE Send final “As-Run” liner tally & liner and cement report to cdinger@hilcorp.com and Frank.Roach@hilcorp.com. This will be included with the EOW documentation that goes to the AOGCC. 'ULOO´+ROH6HFWLRQ 3XOOWHVWSOXJUXQDQGVHWZHDUEXVKLQJ (QVXUH%+$FRPSRQHQWVKDYHEHHQLQVSHFWHGSUHYLRXVO\ 'ULIWDQGFDOLSHUDOOFRPSRQHQWVEHIRUH089LVXDOO\YHULI\QRGHEULVLQVLGHFRPSRQHQWVWKDW FDQQRWEHGULIWHG 7,+DQGFRQGXFWVKDOORZKROHWHVWRI0:'WRFRQILUPDOO/:'IXQFWLRQLQJSURSHUO\ (QVXUH7)RIIVHWLVPHDVXUHGDFFXUDWHO\DQGHQWHUHGFRUUHFWO\LQWRWKH0:'VRIWZDUH +DYH''UXQK\GUDXOLFVFDOFXODWLRQVRQVLWHWRHQVXUHRSWLPXPQR]]OHVL]LQJ+\GUDXOLFV FDOFXODWLRQVDQGUHFRPPHQGHG7)$LVDWWDFKHGEHORZ :RUNVWULQJZLOOEH´6&'6(QVXUHWRKDYHHQRXJK´'3LQGHUULFNWRGULOO WKHHQWLUHRSHQKROHVHFWLRQZLWKRXWKDYLQJWRSLFNXSSLSHIURPWKHSLSHVKHG ´KROHVHFWLRQPXGSURJUDPVXPPDU\ :HLJKWLQJPDWHULDOWREHXVHGIRUWKHKROHVHFWLRQZLOOEHEDULWHVDOWDQGFDOFLXPFDUERQDWH $GGLWLRQDOFDOFLXPFDUERQDWHZLOOEHRQORFDWLRQWRZHLJKWXSWKHDFWLYHV\VWHPSSJDERYH KLJKHVWDQWLFLSDWHG0: 3DVRQ397ZLOOEHXVHGWKURXJKRXWWKHGULOOLQJDQGFRPSOHWLRQSKDVH5HPRWHPRQLWRULQJ VWDWLRQVZLOOEHDYDLODEOHDWWKHGULOOHU¶VFRQVROH&R0DQRIILFH7RROSXVKHURIILFHDQGPXG ORJJHUVRIILFH System Type: SSJ.&/3+3$IUHVKZDWHUEDVHGGULOOLQJIOXLG Properties: 0'0XG :HLJKW9LVFRVLW\3ODVWLF 9LVFRVLW\<LHOG3RLQWS++3+7 ¶ ¶ ± System Formulation: .&/(=0XG'3 3URGXFW&RQFHQWUDWLRQ :DWHU .&O &DXVWLF %$5$=$1' (=08''3 '(;75,'/7 3$&/ %$5$&$5% %$52,' $/'$&,'(* %$5$&25 %$5$6&$9' EEO SSE.FKORULGHV SSES+ SSEDVUHTXLUHG<3 SSELQLWLDOO\SSE SSE SSE SSESSERIHDFK DVUHTXLUHGIRUD±SSJ SSE SSE SSEPDLQWDLQSHUGLOXWLRQUDWH 7,+Z´GLUHFWLRQDODVV\WR72&6KDOORZWHVW0:'DQG/:'RQWULSLQ1RWHGHSWK 72&WDJJHGRQ$0UHSRUW 58DQGWHVWOLQHUWRSVLPLQ(QVXUHWRUHFRUGYROXPHSUHVVXUHDQGSORWRQ),7 JUDSK´EXUVWLVSVL 'ULOORXWVKRHWUDFNDQG¶RIQHZIRUPDWLRQ &%8DQGFRQGLWLRQPXGIRU),7 &RQGXFW),7WRSSJ(0: Note: Offset field test data predicts frac gradient at the 7” shoe to be between 11 - 13 ppg EMW. A 12.6 ppg FIT results in a >15 bbl kick tolerance volume while drilling with the planned maximum MW of 11.0 ppg and an assumed 0.5ppg kick intensity over anticipated pore pressure. 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Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Regg, James B (OGC) To:Jay Murphy - (C) Cc:Brooks, Phoebe L (OGC) Subject:RE: Hilcorp 169 4-22-2022 Date:Saturday, April 23, 2022 3:24:00 PM Revised our copy to add 4 to the # N2 bottles. Jim Regg Supervisor, Inspections AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907-793-1236 From: Jay Murphy - (C) <Jay.Murphy@hilcorp.com> Sent: Friday, April 22, 2022 12:42 PM To: Regg, James B (OGC) <jim.regg@alaska.gov>; DOA AOGCC Prudhoe Bay <doa.aogcc.prudhoe.bay@alaska.gov>; Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov> Subject: Hilcorp 169 4-22-2022 Thank You and Best Regards, Jay Murphy/ DSM Hilcorp Alaska, LLC HAK Rig 169 Office: 907-776-6776 Cell: 907-715-9211 Jay.Murphy@Hilcorp.com 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. %HDYHU&UHHN8QLW5' 37' STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION *All BOPE reports are due to the agency within 5 days of testing* SSu b m i tt t o :jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov Owner/Contractor: Rig No.:169 DATE: 4/22/22 Rig Rep.: Rig Phone: 907-283-1386 Operator: Op. Phone:907-776-6776 Rep.: E-Mail Well Name: PTD #22220330 Sundry # Operation: Drilling: X Workover: Explor.: Test: Initial: X Weekly: Bi-Weekly: Other: Rams:250/4000 Annular:250/2500 Valves:250/4000 MASP:3797 MISC. INSPECTIONS: TEST DATA FLOOR SAFETY VALVES: Test Result Test Result Quantity Test Result Location Gen.P Well Sign P Upper Kelly 1P Housekeeping P Rig P Lower Kelly 1P PTD On Location P Hazard Sec.P Ball Type 1P Standing Order Posted P Misc.NA Inside BOP 1P FSV Misc 0NA BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm Stripper 0NATrip Tank PP Annular Preventer 1 11"P Pit Level Indicators PP #1 Rams 1 2-7/8" x 5"P Flow Indicator PP #2 Rams 1 Blind P Meth Gas Detector PP #3 Rams 1 2-7/8" x 5"P H2S Gas Detector PP #4 Rams 0NAMS Misc 0NA #5 Rams 0NA #6 Rams 0NA Quantity Test Result Choke Ln. Valves 1 3-1/8"P Inside Reel valves 0NA HCR Valves 2 2-1/16" & 3-1/8"P Kill Line Valves 2 2-1/16"P Check Valve 0NAACCUMULATOR SYSTEM: BOP Misc 0 NA Time/Pressure Test Result System Pressure (psi)3175 P CHOKE MANIFOLD:Pressure After Closure (psi)1650 P Quantity Test Result 200 psi Attained (sec)13 P No. Valves 15 P Full Pressure Attained (sec)86 P Manual Chokes 1P Blind Switch Covers: All stations Yes Hydraulic Chokes 1P Nitgn. Bottles # & psi (Avg.): 4@2444 P CH Misc 0NA ACC Misc 0NA Test Results Number of Failures:0 Test Time:5.0 Hours Repair or replacement of equipment will be made within 0 days. Remarks: AOGCC Inspection 24 hr Notice No Date/Time 4/21/2022 08:43 Waived By Test Start Date/Time:4/21/2022 22:30 (date) (time)Witness Test Finish Date/Time:4/22/2022 3:30 BOPE Test Report Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Jim Regg Hilcorp Tested with 4-1/2" test joint. Quadco representative tested gas alarms. Closing times recorded during Accumulator Test: Annular Preventer 24 sec. Upper Rams 4 sec. Upper Rams 4 sec. Lower Rams 4 sec. Choke HCR 2 sec. Kill HCR 2 sec. Van Evera/ Trick Hilcorp Murphy/ Richardson BCU 18RD Test Pressure (psi): Jay.Murphy@hilcorp.com Form 10-424 (Revised 02/2022) 2022-0422_BOP_Hilcorp169_BCU-18RD 9 9 9 9 9 999 9 9 - 5HJJ 9 Annular Preventer 24 sec. Upper Rams 4 sec. Upper Rams 4 sec. Lower Rams 4 sec. Choke HCR 2 sec. Kill HCR 2 sec. 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: Beaver Creek Field, Tyonek Gas Pool, BCU 18RD Hilcorp Alaska, LLC Permit to Drill Number: 222-033 Surface Location: 1055' FNL, 1628' FWL, Sec 34, T7N, R10W, SM, AK Bottomhole Location: 686' FNL, 2339' FWL, Sec 34, T7N, R10W, SM, AK Dear Mr. Myers: Enclosed is the approved application for the permit to drill the above referenced well. Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071,composite curves for well logs run must be submitted to the AOGCCwithin 90 days after completion, suspension or abandonment of this 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 March, 2022. 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3DJH9HUVLRQ0DUFK BCU-18RD Drilling Procedure Rev 0 ´+ROH6HFWLRQ0$63 3DJH9HUVLRQ0DUFK BCU-18RD Drilling Procedure Rev 0 6SLGHU3ORW1$'*RYHUQPHQWDO6HFWLRQV 3DJH9HUVLRQ0DUFK BCU-18RD Drilling Procedure Rev 0 ¶5DGLXVIRU6669 3DJH9HUVLRQ0DUFK BCU-18RD Drilling Procedure Rev 0 6XUIDFH3ODW1$' 3DJH9HUVLRQ0DUFK BCU-18RD Drilling Procedure Rev 0 6XUIDFH3ODW1$' 6WDQGDUG3URSRVDO5HSRUW 0DUFK 3ODQ%&85'ZSD +LOFRUS$ODVND//& %HDYHU&UHHN8QLW %HDYHU&UHHN8QLW3DG 3ODQ%HDYHU&.8QLW 3ODQ%&85' -250 -125 0 125 250 375 500 625 750 875 1000 1125 1250 1375 1500 1625 1750 1875 South(-)/North(+) (250 usft/in)0 125 250 375 500 625 750 875 1000 1125 1250 1375 1500 1625 1750 West(-)/East(+) (250 usft/in) BCU 18RD wp08 tgt1 BCU 18RD wp08 tgt2 2 5 0 1500 1750 2000 2 2 5 0 2 5 0 0 2 7 5 0 3 0 0 0 32503 5 0 0 3 7 5 0 4 0 0 0 4 2 5 0 4 5 0 0 4 7 5 0 5 0 0 0 5 2 5 0 5 5 0 0 5 7 5 0 6 0 0 0 6 2 5 0 6 7 5 0 750 0 8687 BCU 18 9 5/8" TOW 4 1/2" x 8 1/2"350040004 2 5 0 4500 4750 5000 5250 6500 7 0 0 0 7500 8000 8500 9000 9500 10000 10250 10548 BCU 18RD wp08a Start Dir 12.75º/100' : 3600' MD, 3378.45'TVD : 60° RT TF End Dir : 3617' MD, 3393.71' TVD Start Dir 4º/100' : 3637' MD, 3411.58'TVD End Dir : 4867.65' MD, 4585.19' TVD Start Dir 3º/100' : 6716.33' MD, 6281.13'TVD End Dir : 7830.02' MD, 7371.42' TVD Total Depth : 11055.5' MD, 10547.9' TVD CASING DETAILS TVD TVDSS MD Size Name 3379.35 3201.45 3601.00 9-5/8 9 5/8" TOW 10547.90 10370.00 11055.50 4-1/2 4 1/2" x 8 1/2" Project: Beaver Creek Unit Site: Beaver Creek Unit Pad 3 Well: Plan: Beaver CK Unit 18 Wellbore: Plan: BCU 18RD Plan: BCU 18RD wp08a WELL DETAILS: Plan: Beaver CK Unit 18 Ground Level: 159.90 +N/-S +E/-W Northing Easting Latitude Longitude 0.00 0.00 2434136.990 317441.970 60.658796°N 151.017588°W REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Plan: Beaver CK Unit 18, True North Vertical (TVD) Reference:BCU 18RD Planned RKB @ 177.90usft Measured Depth Reference:BCU 18RD Planned RKB @ 177.90usft Calculation Method:Minimum Curvature 3300 3850 4400 4950 5500 6050 6600 7150 7700 8250 8800 9350 9900 10450 11000 11550True Vertical Depth (1100 usft/in)-550 0 550 1100 1650 2200 2750 3300 3850 4400 4950 5500 6050 6600 7150 Vertical Section at 62.72° (1100 usft/in) BCU 18RD wp08 tgt2 BCU 18RD wp08 tgt1 3 5 0 0 4 0 00 4 5 0 0 5 0 0 0 5 5 0 0 6 0 0 0 6 5 0 0 7 0 0 0 7 5 0 0 8 0 0 0 8 500 90 00 9 244 BCU 18 9 5/8" TOW 4 1/2" x 8 1/2" 4 0 0 0 4500 5000 5500 6000 6500 7000 7500 8 0 0 0 8 5 0 0 9 0 0 0 9 5 0 0 1 0 0 0 0 1 0 5 0 0 1 1 0 0 0 1 1 0 5 6 BCU 18RD wp08a Start Dir 12.75º/100' : 3600' MD, 3378.45'TVD : 60° RT TF End Dir : 3617' MD, 3393.71' TVD Start Dir 4º/100' : 3637' MD, 3411.58'TVD End Dir : 4867.65' MD, 4585.19' TVD Start Dir 3º/100' : 6716.33' MD, 6281.13'TVD End Dir : 7830.02' MD, 7371.42' TVD Total Depth : 11055.5' MD, 10547.9' TVD Beluga B5 Beluga B16 Beluga B20 Beluga B23 Beluga B25 Beluga B27 Beluga B29L Beluga B33 Tyonek T1 Tyonek T6 Tyonek T8 Tyonek T12 Hilcorp Alaska, LLC Calculation Method:Minimum Curvature Error System:ISCWSA Scan Method: Closest Approach 3D Error Surface: Ellipsoid Separation Warning Method: Error Ratio WELL DETAILS: Plan: Beaver CK Unit 18 Ground Level: 159.90 +N/-S +E/-W Northing Easting Latitude Longitude 0.00 0.00 2434136.990 317441.970 60.658796°N 151.017588°W SURVEY PROGRAM Date: 2022-03-08T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 161.90 2016.90 BCU 18 MWD (1) (BCU 18) 3_MWD 2132.90 3600.00 BCU 18 MWD (2) (BCU 18) 3_MWD 3600.00 4000.00 BCU 18RD wp08a (Plan: BCU 18RD)3_MWD_Interp Azi+Sag 4000.00 11055.50 BCU 18RD wp08a (Plan: BCU 18RD)3_MWD+IFR1+MS+Sag FORMATION TOP DETAILS TVDPath TVDssPath MDPath Formation 5889.90 5712.00 6289.87 Beluga B5 7053.90 6876.00 7510.79 Beluga B16 7387.90 7210.00 7846.75 Beluga B20 7656.90 7479.00 8119.90 Beluga B23 7760.90 7583.00 8225.51 Beluga B25 7862.90 7685.00 8329.08 Beluga B27 8174.90 7997.00 8645.89 Beluga B29L 8453.90 8276.00 8929.20 Beluga B33 8710.90 8533.00 9190.16 Tyonek T1 9052.90 8875.00 9537.44 Tyonek T6 9334.90 9157.00 9823.79 Tyonek T8 9727.90 9550.00 10222.85 Tyonek T12 REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Plan: Beaver CK Unit 18, True North Vertical (TVD) Reference:BCU 18RD Planned RKB @ 177.90usft Measured Depth Reference:BCU 18RD Planned RKB @ 177.90usft Calculation Method: Minimum Curvature Project:Beaver Creek Unit Site:Beaver Creek Unit Pad 3 Well:Plan: Beaver CK Unit 18 Wellbore:Plan: BCU 18RD Design:BCU 18RD wp08a CASING DETAILS TVD TVDSS MD Size Name 3379.35 3201.45 3601.00 9-5/8 9 5/8" TOW 10547.90 10370.00 11055.50 4-1/2 4 1/2" x 8 1/2" SECTION DETAILS Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation 1 3600.00 25.57 46.18 3378.45 715.29 642.59 0.00 0.00 898.94 Start Dir 12.75º/100' : 3600' MD, 3378.45'TVD : 60° RT TF 2 3617.00 26.71 50.36 3393.71 720.27 648.18 12.75 60.00 906.19 End Dir : 3617' MD, 3393.71' TVD 3 3637.00 26.71 50.36 3411.58 726.00 655.10 0.00 0.00 914.97 Start Dir 4º/100' : 3637' MD, 3411.58'TVD 4 3787.00 24.23 63.10 3547.09 761.47 708.56 4.00 120.00 978.74 5 4867.65 23.45 194.42 4585.19 648.12 860.04 4.00 154.12 1061.43 End Dir : 4867.65' MD, 4585.19' TVD 6 6716.33 23.45 194.42 6281.13 -64.51 676.80 0.00 0.00 571.98 Start Dir 3º/100' : 6716.33' MD, 6281.13'TVD 7 7830.02 10.00 8.10 7371.42 -186.92 634.01 3.00 178.01 477.85 End Dir : 7830.02' MD, 7371.42' TVD 8 7930.02 10.00 8.10 7469.90 -169.73 636.45 0.00 0.00 487.90 BCU 18RD wp08 tgt1 9 11055.50 10.00 8.10 10547.90 367.59 712.93 0.00 0.00 802.11 BCU 18RD wp08 tgt2 Total Depth : 11055.5' MD, 10547.9' TVD 3URMHFW &RPSDQ\ /RFDO&RRUGLQDWH5HIHUHQFH 79'5HIHUHQFH 6LWH +LOFRUS$ODVND//& %HDYHU&UHHN8QLW %HDYHU&UHHN8QLW3DG 6WDQGDUG3URSRVDO5HSRUW :HOO :HOOERUH 3ODQ%HDYHU&.8QLW 3ODQ%&85' 6XUYH\&DOFXODWLRQ0HWKRG0LQLPXP&XUYDWXUH %&85'3ODQQHG5.%#XVIW 'HVLJQ%&85'ZSD 'DWDEDVH1257+86&$1$'$ 0'5HIHUHQFH%&85'3ODQQHG5.%#XVIW 1RUWK5HIHUHQFH :HOO3ODQ%HDYHU&.8QLW 7UXH 0DS6\VWHP *HR'DWXP 3URMHFW 0DS=RQH 6\VWHP'DWXP866WDWH3ODQH([DFWVROXWLRQ 1$'1$'&21&2186 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0.001.002.003.004.00Separation Factor3600 4000 4400 4800 5200 5600 6000 6400 6800 7200 7600 8000 8400 8800 9200 9600 10000 10400 10800 11200Measured Depth (800 usft/in)BCU 18BCU 5BCU 6No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.WELL DETAILS:Plan: Beaver CK Unit 18 NAD 1927 (NADCON CONUS)Alaska Zone 04Ground Level: 159.90+N/-S +E/-W Northing EastingLatitudeLongitude0.000.002434136.990317441.97060.658796°N 151.017588°WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: Beaver CK Unit 18, True NorthVertical (TVD) Reference:BCU 18RD Planned RKB @ 177.90usftMeasured Depth Reference:BCU 18RD Planned RKB @ 177.90usftCalculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2022-03-08T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool161.90 2016.90 BCU 18 MWD (1) (BCU 18) 3_MWD2132.90 3600.00 BCU 18 MWD (2) (BCU 18) 3_MWD3600.00 4000.00 BCU 18RD wp08a (Plan: BCU 18RD) 3_MWD_Interp Azi+Sag4000.00 11055.50 BCU 18RD wp08a (Plan: BCU 18RD) 3_MWD+IFR1+MS+Sag0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)3600 4000 4400 4800 5200 5600 6000 6400 6800 7200 7600 8000 8400 8800 9200 9600 10000 10400 10800 11200Measured Depth (800 usft/in)GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference3600.00 To 11055.50Project: Beaver Creek UnitSite: Beaver Creek Unit Pad 3Well: Plan: Beaver CK Unit 18Wellbore: Plan: BCU 18RDPlan: BCU 18RD wp08aCASING DETAILSTVD TVDSS MD Size Name3379.35 3201.45 3601.00 9-5/8 9 5/8" TOW10547.90 10370.00 11055.50 4-1/2 4 1/2" x 8 1/2" Page 23 Version 0 March, 2022 BCU-18RD Drilling Procedure Rev 0 15.0 Cement 4-1/2” Production Casing 15.1 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. 15.2 Attempt to rotate and reciprocate the liner during cmt operations until hole gets sticky 15.3 Pump 5 bbls spacer. 15.4 Test surface cmt lines to 4500 psi. 15.5 Pump remaining spacer. 15.6 Mix and pump lead and tail cement per below recipe. Ensure cement is pumped at designed weight. Job is designed to pump 35% OH excess. Estimated Total Cement Volume: Section:Calculation:Vol (BBLS)Vol (ft3) 12.0 ppg LEAD: 9-5/8” csg x 4-1/2” casing annulus: 500’ x .05616 bpf = 28.08 157.6 12.0 ppg LEAD: 8-1/2” OH x 4-1/2” annulus: (10556’ – 3600’) x .05051 bpf x 1.35 = 474.36 2663.4 Total LEAD: 502.44 bbl 2821.0 ft3 15.4 ppg TAIL: 8-1/2” OH x 4-1/2” annulus: (11056’- 10556’) x .05051 bpf x 1.35 = 34.10 191.4 15.4 ppg TAIL: 4-1/2” Shoe track: 80 x .01522 bpf = 1.22 6.8 Total TAIL: 35.32 bbl 198.2 ft3 TOTAL CEMENT VOL: 537.76 bbl 3019.2 ft3 9HULILHGFHPHQWFDOFVEMP Page 24 Version 0 March, 2022 BCU-18RD Drilling Procedure Rev 0 Cement Slurry Design: 15.7 Drop wiper plug and displace with drilling mud at max rate of 5bbl/min. If hole conditions allow, continue reciprocating casing throughout displacement. 15.8 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. 15.9 Bump the plug and pressure up to 500 psi over final lift pressure. Hold pressure for 3-5 minutes. 15.10 Do not overdisplace by more than ½ shoe track. Shoe track volume is 1.2 bbls. 15.11 Bleed pressure to zero to check float equipment. Watch for flow. Note amount of fluid returned after bumping plug and releasing pressure. 15.12 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. 15.13 WOC minimum of 12 hours before testing casing to 4000 psi and chart for 30 minutes. Lead Slurry (10556’ MD to 3600’ MD)Tail Slurry (11056 to 10556’ 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 25 Version 0 March, 2022 BCU-18RD Drilling Procedure Rev 0 Ensure to report the following on wellez: x Pre flush type, volume (bbls) & weight (ppg) x Cement slurry type, lead or tail, volume & weight x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid x Note if liner is reciprocated or rotated during the job x Calculated volume of displacement , actual displacement volume, whether plug bumped & bump pressure, do floats hold x Percent mud returns during job. If intermittent, note timing during pumping of job. Final circulating pressure x Note if pre flush or cement returns at surface & volume x Note time cement in place x Note calculated top of cement x Add any comments which would describe the success or problems during the cement job Send final “As-Run” liner tally & liner and cement report to cdinger@hilcorp.com and Frank.Roach@hilcorp.com. 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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 10,461 feet 8620 & 8865 feet true vertical 9,964 feet N/A feet Effective Depth measured 8,583 feet N/A feet true vertical 8,115 feet N/A feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth) 4-1/2" 12.6# / L-80 7,274' MD 6,822' TVD Packers and SSSV (type, measured and true vertical depth) N/A N/A 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 323-103 Sr Pet Eng: Sr Pet Geo: Sr Res Eng: WINJ WAG 72 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 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 108' 0 057 0 3800 353 4-1/2" 20" 13-3/8" 108' 2,097' Intermediate 9-5/8" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 222-033 50-133-20584-01-00 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: FEDA028083 Beaver Creek / Beluga Gas Pool Beaver Creek Unit (BCU) 18RD Plugs Junk measured Length measured true vertical Packer measured TVD Burst Collapse 1,500psi 1,950psi Production Liner 3,574' 4,006' Casing Structural 3,350' 9,936' 3,574' 10,432' 108'Conductor Surface Intermediate 4,138' 7" 7,474' 6,975' 7,240psi 5,410psi 3,090psi 7,500psi 3,060psi 3,450psi 5,750psi 8,430psi 2,097' 1,038' p k ft t Fra O s O 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 Kayla Junke at 8:43 am, Apr 26, 2023 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361), ou=Users Date: 2023.04.25 16:53:08 -08'00' Noel Nocas (4361) Rig Start Date End Date 3/3/23 4/4/23 Reservoir team determined additional sundried perfs will not be executed and can close out Sundry. Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BCU-18RD 50-133-20584-01-00 222-033 03/03/2023- Friday 03/10/2023- Friday Halliburton E-line arrive on location. Hold TBT and approve PTW. MU sondex pressure/temperature tool (GPT). PT lubricator to 250/3000 psi. RIH and find fluid level at 8,222' and tag at 8545' (uncorrected). Tubing pressure = 1550 psi. Bleed tubing pressure down from 1550 psi to 330 psi. Fluid level = 8080' (uncorrected) Tubing pressure = 280 psi, fluid level = 8055' (uncorrected). Send GPT log to RE/GEO to use for Tie-in log and confirm on depth. Shift 23' to get on depth. POOH with GPT toolstring. RDMO Yellow Jacket E line arrive on location. PTW JSA with crew. MIRU Yellow Jacket E-line unit. Make up Lubricator and 3 1/8" gun. Stab on well. PT stack 250/3000 psi. RIH. Pull correlation log and send to town. Shift log +4'. Production bleeding well down to 400 psi. Perforate BEL_23 sands from 8130'-8139' with 3 1/8" x 9' HSC gun loaded 5 spf. 5/10.15 minutes pressures. 423 psi, 431 psi, 434 psi. POOH. All shots fired. Gun is wet. Bull nose filled with gas entrained fluid with trace of sand. RIH Send correlation log to town. ON depth Crack well to production and attempt to maintain stable flow. Perforate 8086'-8106' with 3 1/8" x 20' HSC gun loaded 5 spf. Record 5,10,15 min 502 psi, 503 psi and 505 psi. At surface confirmed all shots fired. Gun wet. Bull nose has wellbore fluids no sand. RIH. Pull correlation log and send to town. Off 4'. Shift depth +4'. Perforate Bel sands from 8066'-8068' (20') with 3 1/8" x 20' HSC gun loaded 5 spf. 5,10,15 pressures 543, 545, 547 psi. POOH to surface. Rig down Yellow Jacket. 04/04/2023- Tuesday Updated by DMA 04-05-23 SCHEMATIC BCU 18RD API: 50-133-20584-01-00 PTD: 222-033 Pad-3 PBTD = 8,583 MD / 8,115 TVD TD = 10,461 MD / 9,964 TVD RKB to GL = 18.0 CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 20 Conductor 154.19 X-65 Weld 19.13 Surf 108 13-3/8" Surf Csg 68.0 K-55 BTC 12.415 Surf 2,097 9-5/8 Intermediate Csg 40.0 L-80 BTC 8.835 Surf 3,574 7 Intermediate Lnr 26.0 L-80 Vam Top 6.276 3,336 7,474 4-1/2" Prod Tieback 12.6 L-80 JFEBEAR 3.958 Surf 7,214 4-1/2" Prod Lnr 12.6 L-80 JFEBEAR 3.958 7,219 10,432 1 20 13-3/8 4-1/2 JEWELRY DETAIL No. Depth ID Item 1 3,336 6.040 9-5/8 x 7 Liner hanger / LTP Assembly 2 3,574 N/A Whipstock 3 7,218 5.25 7 x 4-1/2 Liner hanger / LTP Assembly with PBR 4 7,214 3.890 Seal Stem 5 8,620 CIBP w/ 37 cement TOC @ 8,583 (7/26/22) 6 8,865 CIBP w/ 5 cement TOC @ 8,860 (7/20/22) Additional 31 cement - TOC @ 8,829 (7/21/22) OPEN HOLE / CEMENT DETAIL 13-3/8 16 Hole: TOC @ Surface (Original BCU 18) 9-5/8" 12-1/4: Hole: TOC @ 3,440 (Original BCU 18) 7 8-1/2 Hole: 125bbls 12ppg lead followed by 18bbls 15.3ppg tail pumped on 5/1/22. 38bbls lead cement back to surface. 5/14/22 CBL shows ToC at 3570 MD 4-1/2 6-1/8 Hole: Pumped 30bbl spacer followed by 54bbls 12ppg Type I/II lead followed by 25bbls 15.3ppg Type I/II tail pumped on 5/11/22. Trace spacer back to surface. 5/19/22 CBL shows ToC at 7370 MD 4 4 9-5/8 2 BCU 18 (Abandoned) 3 7 PERFORATION DETAIL Zone Top MD Btm MD TopTVD Btm TVD Amt Date Comments BEL22 8,086 8,106 7,626 7,646 41 3/10/2023 Open BEL23 8,130 8,139 7,669 7,678 9 3/10/2023 Open BEL25 8,254' 8,264' 7,791' 7,801' 10' 7/28/2022 Open BEL26 8,281' 8,290' 7,818' 7,827' 9' 7/28/2022 Open BEL27 8,358' 8,372' 7,894' 7,907' 14' 7/27/2022 Open BEL27 8,414' 8,424' 7,949' 7,959' 10' 7/27/2022 Open BEL28 8,483' 8,491' 8,017' 8,025' 8' 7/27/2022 Open BEL28 8,504' 8,516' 8,037' 8,049' 12' 7/27/2022 Open PERFORATION DETAIL continued on following page BEL 29-32 T0 T12 6 BEL 33 FISH DETAILs: Failed WRP at 8867 ELMD (7/10/22) & Fish left from 8,785-8,829ft - 35ft 3.5"OD cement bailer, 2ft CCL, 7ft 2" weight bar (7/21/22) 5 BEL 25-28 BEL 22-23 Updated by DMA 04-05-23 SCHEMATIC BCU 18RD API: 50-133-20584-01-00 PTD: 222-033 Pad-3 PERFORATION DETAIL continued from previous page Zone Top MD Btm MD TopTVD Btm TVD Amt Date Comments BEL29 8,625 8,635 8,157 8,166 10 6/19/2022 Isolated 7/26/22 BEL29 8,625 8,635 8,157 8,166 10 6/12/2022 Isolated 7/26/22 BEL29 8,643 8,648 8,173 8,179 5 6/19/2022 Isolated 7/26/22 BEL29 8,643 8,648 8,173 8,179 5 6/12/2022 Isolated 7/26/22 BEL29 8,653 8,659 8,184 8,190 6 6/19/2022 Isolated 7/26/22 BEL29 8,653 8,659 8,184 8,190 6 6/12/2022 Isolated 7/26/22 BEL29 8,687' 8,707' 8,218' 8,237' 20' 7/16/2022 Isolated 7/26/22 BEL29 8,690' 8,692' 8,221' 8,223' 2' 7/16/2022 Isolated 7/26/22 B30 8,740' 8,745' 8,270 8,275 5 6/11/2022 Isolated 7/26/22 B30 8,775' 8,781' 8,304 8,310 6 6/11/2022 Isolated 7/26/22 B31 8,812' 8,818' 8,341 8,347 6 6/11/2022 Isolated 7/26/22 B32 8,840' 8,849' 8,369 8,377 9 7/9/2022 Isolated 7/26/22 B32 8,840' 8,849' 8,369 8,377 9 6/11/2022 Isolated 7/26/22 B33 8,995' 9,004' 8,522 8,530 9 6/11/2022 Isolated 7/10/22 T0 9,148' 9,153' 8,672' 8,677' 5 6/1/2022 Isolated 6/8/22 T2 9,230' 9,242' 8,753' 8,765' 12 6/1/2022 Isolated 6/8/22 T4 9,337' 9,347' 8,860' 8,868' 10 5/31/2022 Isolated 6/8/22 T4 9,380' 9,393' 8,901' 8,913' 13 5/31/2022 Isolated 6/8/22 T6 9,567' 9,575' 9,085' 9,093' 8 5/29/2022 Isolated 6/8/22 T7A 9,738' 9,758' 9,253' 9,273' 20 5/29/2022 Isolated 6/8/22 T7B 9,797' 9,817' 9,311' 9,328' 20 5/28/2022 Isolated 6/8/22 T11 10,116' 10,136' 9,625' 9,645' 20 5/28/2022 Isolated 6/8/22 T12 10,289' 10,308' 9,795' 9,813' 19 5/26/2022 Isolated 6/8/22 T12 10,289' 10,308' 9,795' 9,813' 19 5/27/2022 Isolated 6/8/22